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Home My WebLink About181-0921. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: _______________________ Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,225 feet See Attachment feet true vertical 9,863 feet 4,376' (fish) feet Effective Depth measured 3,233 feet N/A feet true vertical 3,233 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Contact Phone: 4,760psi 3,090psi 6,870psi 2,566' 2,566' Burst Collapse 1,540psi Production Liner 7,282' 131' Casing Structural 7,194' 7" 7,282' 3,762' 3,762' 85'Conductor Surface Intermediate 20" 13-3/8" 85' 2,566' measured TVD 6,340psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 181-092 50-133-20342-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEE FEDA028142 ADL0390821 Kenai Gas Field / Sterling Gas Pool 6 Kenai Unit (KU) 14X-06 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 75 Size 85' 0750 0 640 64 Casey Morse, Well Integrity Engineer N/A Sr Pet Eng: 3,830psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 casey.morse@hilcorp.com 907-777-8322 N/A Development Service GINJ SUSP SPLUG Gas Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:41 am, Apr 24, 2024 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2024.04.23 13:09:15 -08'00' RBDMS JSB 043024 DSR-4/29/24 Lease: State: Country:USA (TVD) County or Parish:Kenai Peninsula Borough Last Revison Date:Revised By:Donna Ambruz Alaska Angle @ KOP and Depth:6deg @ 5950' Perforations (MD): 5/8/2023 Completion Fluid:6% KCL Angle/Perfs:0deg Well Name & Number: Dated Completed:7/1/2003 Kenai Unit 14x-6 Kenai Gas Field Perfs (Sterling Pool 6): C1: 4,462' -4,533' DIL C2: 4,619' - 4,670' DIL (12 spf, 8/14/03) BST Coil String fish: Outer string: 2-3/8" OD, 0.125" wall, 3.007 ppf, HO- 70 coil tubing w/ plug/profile combination BST nipple @ 4,860', Nipple ID = 1.188" w/ 1.00" nogo. Standing Valve @ 4,860' 9-5/8", 47 ppf, N-80, BTC casing @ ,7282' Cmt with 1,450 sks of class G Note:Apparent casing damage at 3,550'-3,560' (6/25/2003), Tested casing to 1500 psi on 3/6/23 from 3,449' to surface Cement top ~ 3408' based on CBL from 1981 PBTD 9,296' MD 8,982' TVD Conductor: 20" @ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2,566' Cmt with 1675 sks of class G 7", 29 ppf, N-80, BTC liner 6,925' - 10,225' Cmt with 1,600 sks of class G 7" Scab Liner 3,762' - 3,893' - 7", 23 ppf, L-80, BTC casing - Baker ZXP packer on HMC liner hanger @ 3,865' - Muleshoe @ 3,893' Min ID = 6.184" at muleshoe 7" CIBP Set at 3,767' (4ft above hole based on caliper log) Perfs - Isolated Pool 3: 3,548' - 3,550' (sqz'd) 3,553' - 3,575' (A-8) 3,624' - 3,649' (A-10) 3,652' - 3,677' (A-10) 3,724' - 3,739' (A-11) 3,746' - 3,748' (sqz'd) Pool 4: 3,772' - 3,792' (B-1) 3,800' - 3,802' (sqz'd) Squeezed Perfs (isolated in 7" liner): 9,398' - 9,400' 9,411' - 9,445' 9,458' - 9,460' 9,751' - 9,781' 9,833' - 9,843' 9,953' - 9,958' Fish: Remnants of "D" packer @ 6,838' (6/22/2003) 7" cement retainers @ 9,296'; 9,707'; and 9,925' KU 14x-6 Pad 14-6 422' FSL, 1,147' FWL, Sec. 6, T4N, R11W, S.M. Permit #:181-092 API #:50-133-20342-00-00 Prop. Des:A-028142 KB Elevation:87' AGL Latitude: Longitude: Spud:9/22/1981 TD:10/27/1981 Rig Released:12/9/1981 PA #: TD 10,225' MD 9,863' TVD Parted 2-3/8" coil @ 4376' 14.5bbl cement plug tagged @ 4,092' on 3/6/23 10ft Sand & gravel on coil fish @ 4366' Hole in 7" casing @ 3,771' WLM Casing stub top @ 3,762' 3/9/23 7" CIBP set at 3767' Pool 4 isolation plug @ 3,758' Cement retainers @ 3,480' 3/26/23, 3,600' 3/24/23, 3,700' 3/23/23 TOC 3,233' 4/23/23 Picture – Well Sign Picture – IA Pressure Gauge Picture – OA Pressure Gauge Inside Cellar Plat – Quarter-mile Buffer Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 06/11/2024 InspectNo:susBDB240423034732 Well Pressures (psi): Date Inspected:4/19/2024 Inspector:Brian Bixby If Verified, How?Other (specify in comments) Suspension Date:4/24/2023 Tubing:64 IA:75 OA:86 Operator:Hilcorp Alaska, LLC Operator Rep:Zac Rohr Date AOGCC Notified:4/8/2024 Type of Inspection:Initial Well Name:KENAI UNIT 14X-06 Permit Number:1810920 Wellhead Condition Wellhead was in good condition and all the valves worked properly. There is no BPV or VR Plugs installed. Surrounding Surface Condition Clean with no issues. Condition of Cellar Clean with a couple inches of water in it. Comments Location was verified using as-built pad map. Pictures sent to Jim Regg. Supervisor Comments Photos (2) attached Suspension Approval:Completion Report Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Tuesday, June 11, 2024        2024-0419_Suspend_KU_14X-06_photos_bb Page 1 of 1 Suspended Well Inspection – KU 14X-06 (PTD 1810920) AOGCC Inspection Report # susBDB240423034732 Photos by AOGCC Inspector B. Bixby 4/19/2024 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: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: FEE FEDA028142 ADL0390821 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 20" Plain 85 13-3/8" K-55 2,566 9-5/8" N-80 7,194 7" N-80 9863 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 Sr Res EngSr Pet GeoSr Pet Eng N/A Oil-Bbl: Water-Bbl: NA Water-Bbl: PRODUCTION TEST NA Date of Test: Oil-Bbl: Flow Tubing Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 47 10,225 Surf 6879 94 61 85 Surf 7,282 SIZE DEPTH SET (MD) PACKER SET (MD/TVD) Driven N/A 17-1/2" Driven Surf 1675 sx N/A 29 Surf 6,925 2,566Surf Surf CASING WT. PER FT.GRADE 10/27/1981 CEMENTING RECORD NA N/A SETTING DEPTH TVD 2362539.60 TOP HOLE SIZE AMOUNT PULLED NA 270410.50 TOP SETTING DEPTH MD 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. N/A BOTTOM 510' FSL, 1069' FWL, Sec 6, T4N, R11W, SM, AK 554' FSL, 593' FWL, Sec 6, T4N, R11W, SM, AK N/A 9/22/1981 10,225' MD/9,863' TVD 9,296' MD/8,982' TVD 272070.70 2362465.20 N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Kenai Gas Field / Sterling Gas Pool 6 Kenai Unit (KU) 14X-06 50-133-20342-00-00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG WAG Gas 4/24/2023Hilcorp Alaska, LLC 181-092 / 323-024 & 323-077 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 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, 1600 sx8-1/2" TUBING RECORD 1450 sx N/A 12-1/4" N/A NA Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Grace Christianson at 10:38 am, May 24, 2023 Suspended 4/24/2023 JSB RBDMS JSB 052523 xGDSR-6/12/23 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval 31. List of Attachments: Well Operations Summary, Schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Chad Helgeson, Operations Engineer Digital Signature with Date:Contact Email: chelgeson.hilcorp.com Contact Phone: 907-777-8405 Authorized 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: 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. 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. 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). Authorized Name and INSTRUCTIONS Noel Nocas, Operations Manager 907-564-5278 Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. 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 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. Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.05.24 10:27:03 - 08'00' Noel Nocas (4361) Lease: State: Country:USA (TVD) County or Parish:Kenai Peninsula Borough Last Revison Date:Revised By:Donna Ambruz Alaska Angle @ KOP and Depth:6deg @ 5950' Perforations (MD): 5/8/2023 Completion Fluid:6% KCL Angle/Perfs:0deg Well Name & Number: Dated Completed:7/1/2003 Kenai Unit 14x-6 Kenai Gas Field Perfs (Sterling Pool 6): C1: 4,462' -4,533' DIL C2: 4,619' - 4,670' DIL (12 spf, 8/14/03) BST Coil String fish: Outer string: 2-3/8" OD, 0.125" wall, 3.007 ppf, HO- 70 coil tubing w/ plug/profile combination BST nipple @ 4,860', Nipple ID = 1.188" w/ 1.00" nogo. Standing Valve @ 4,860' 9-5/8", 47 ppf, N-80, BTC casing @ ,7282' Cmt with 1,450 sks of class G Note:Apparent casing damage at 3,550'-3,560' (6/25/2003), Tested casing to 1500 psi on 3/6/23 from 3,449' to surface Cement top ~ 3408' based on CBL from 1981 PBTD 9,296' MD 8,982' TVD Conductor: 20" @ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2,566' Cmt with 1675 sks of class G 7", 29 ppf, N-80, BTC liner 6,925' - 10,225' Cmt with 1,600 sks of class G 7" Scab Liner 3,762' - 3,893' - 7", 23 ppf, L-80, BTC casing - Baker ZXP packer on HMC liner hanger @ 3,865' - Muleshoe @ 3,893' Min ID = 6.184" at muleshoe 7" CIBP Set at 3,767' (4ft above hole based on caliper log) Perfs - Isolated Pool 3: 3,548' - 3,550' (sqz'd) 3,553' - 3,575' (A-8) 3,624' - 3,649' (A-10) 3,652' - 3,677' (A-10) 3,724' - 3,739' (A-11) 3,746' - 3,748' (sqz'd) Pool 4: 3,772' - 3,792' (B-1) 3,800' - 3,802' (sqz'd) Squeezed Perfs (isolated in 7" liner): 9,398' - 9,400' 9,411' - 9,445' 9,458' - 9,460' 9,751' - 9,781' 9,833' - 9,843' 9,953' - 9,958' Fish: Remnants of "D" packer @ 6,838' (6/22/2003) 7" cement retainers @ 9,296'; 9,707'; and 9,925' KU 14x-6 Pad 14-6 422' FSL, 1,147' FWL, Sec. 6, T4N, R11W, S.M. Permit #:181-092 API #:50-133-20342-00-00 Prop. Des:A-028142 KB Elevation:87' AGL Latitude: Longitude: Spud:9/22/1981 TD:10/27/1981 Rig Released:12/9/1981 PA #: TD 10,225' MD 9,863' TVD Parted 2-3/8" coil @ 4376' 14.5bbl cement plug tagged @ 4,092' on 3/6/23 10ft Sand & gravel on coil fish @ 4366' Hole in 7" casing @ 3,771' WLM Casing stub top @ 3,762' 3/9/23 7" CIBP set at 3767' Pool 4 isolation plug @ 3,758' Cement retainers @ 3,480' 3/26/23, 3,600' 3/24/23, 3,700' 3/23/23 TOC 3,233' 4/23/23 Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 01/26/2023 - Thursday PTW, JSA with Halliburton E-Line. MIRU E-Line unit and Hot oil truck. Make up 1" logging tools. Stab on well. PT stack 300/3000 psi. Good test. RIH logging down for baseline pass. Tag the end of the 1.75" CT string @ 4850'. PT pump line 3000/4500 psi. Online down 9-5/8" x 2.375" CT annulus. Pumped 450 bbls of 40° F water at 2.7 bbls/min 740 psi. Perform multiple logging runs down on pump. Pressure dropped to 0 psi. Didn't look like we caught fluid during the pump operation. Stop E-line at 4850'. Standby for 1 hr to log warming effect. Begin logging up from 4850'-2500' Stops at 2500'. RIH back to 4850' and stop for 1 hr. Log up from 4850' to 2500'. Finished logging. POOH to surface. Tagged up. Close master and swab. Pop off well. Start rigging down E-line unit. Location walk around complete. Leave location. 01/27/2023- Friday 01/28/2023 - Saturday Hot oil truck rigged up from previous day. PTW, JSA with production operators. Pump down 1.75" V-String to ensure well is full of kill weight fluid. 1 bbl/ pumped and caught fluid. Swap to 1.75" x 2.375" annulus. Pump 1.8 bbls to catch fluid. Both annuli pressured up between 1600-2000 psi. Pressure would drop to zero shortly after coming offline with pump. Monitor well conditions for 3 hrs as per AOGCC. Coil crew and crane op arrive on location. PTW, JSA. MIRU Fox CTU 8 with 1.75" V-String retrieval whip. 3 hours completed. Removed upper section of wellhead stack above hanger. Install 4" 3M x 4" 5M wellhead spool and 4" 5M gate valve. Install BOPE. 24 Hr BOPE test witness notification waived by Jim Regg. Pressure test BOPE 250/3000 psi. Good test. Break flange above hanger. Pick injector head and BOPE. RIH 15'. Manually straighten pipe from injector head. Stab double roll on coil connector. Slip chains and lower BOPE onto hanger flange and bolt up. Tie into BOPE kill port flange (above hanger). Pressure test connection break 250/3000 psi. Calculated V-String pipe weight in air 12000 lbs. Perform Pull test to 15K to verify roll on x roll on integrity. Back out top lock down hanger screws. PU on coil and confirm movement. Tagged up after pulling 16', hanger pack off/ slip assembly tagging up below stripper. RIH with hanger and coil to 3' above BOP top connection. Close pipe rams and slips. Strip up with injector and lubricator to expose hanger assembly and remove same. Slip inj down and nipple bowen connector. POOH with 4850' of 1.75" V-String and BHA, pipe in good condition. Tagged up at surface. All annuli 0 psi. Close master valve. Pop off well and rack back injector head. Install night cap on BOPE. Well secure. Perform location walkaround. Shut down and depart location. PTW, JSA with crew. Fire up equipment. Swap out 1.75" BOPE inserts and install 2.375" Inserts. Move equipment and setup metal dumpsters. Make 3ea 15' cuts and found the plugged off coil. Stab on well. Cool down N2. Blow reel dry. Cut 4850' of 1.75" V-String into metal dumpster. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 01/31/2023 - Tuesday Pollard SL & Vault WH rep on location. Open PTW & PJSM. Rig up SL & crane. Remove 4" tree w/ 2-3/8" hanger spool. Install 7" spool w/ 7" tree cap. Pick up lubricator & BHA. PT lubricator 250/2500, pass. Zero at the tubing hanger. RIH w/ SL toolstring w/ 6" LIB. Tag @ 830' SLM. POOH. LIB shows 2-3/8" coil fish sitting along side 9-5/8" casing. Lay down SL toolsting & lubricator. Remove 7" tree cap from the wellhead. Install 7" x 4" spool piece. Install 4" tree valve w/ tree cap. RDMO. 01/30/2023 - Monday PTW, JSA with crew. Hold safety meeting and discuss mitigation measures for the dangers involved with handling broken 2.375" Coiled tubing. Continue to pull V-String OOH while cutting into 20 foot sections. Had two breaks over the gooseneck of the injector head. Removed 860' of 2.375" coiled tubing from well. Performed swab checks. Closed in swab. Relaid message to town. Rig down CTU equipment. Called out Pollard slick line for a tag for the following day. 01/29/2023 - Sunday PTW, JSA with crew. Fire equipment. Check pressure on V-String and annulus. Both 0 psi. Move crane to swap reels. Swap 1.75" for 2.375" reels. Wellhead tech on location. Remove 1.75" Hanger from wellhead stack. BOPE test witness waived by Jim Regg via email. Perform full body test 250/3000 psi to test flange break. Test pipe slip rams 250/3000 psi. Good test (only required to test pipe slip rams as they are all that were changed). Operation remains within our 7 day test window for BOPE components. Swap Injector head blocks and stripper inserts to 2.375". Stab 2.375" whip into injector head. Make up Yellowjacket BHA assmebly. 2.375" external slip connector, 2.125" DFCV, 2.125" Hydraulic disconnect, 3" GS spear. BHA length 12'. (Connector pull tested 25K). Stab on well. PT stack 250/3000 psi. RIH stack 5K down on CT hanger. PU and over pull to 20K. Good latch. Slack off to half of V-String hanging weight 8K. Back out hanger lock down screws. Pick up to 15K. and up to 20K. Weight cell indicates coil stuck down hole and not at hanger. Call town to discuss acceptable max pull. 80% coil yield is 77,000 lbs. Decision made not to pull over 60K. Work string up and down increasing up weight by 5K. Pulled up to 50K when something broke loose. Weight cell dropped to 12K. Close pipe/slip rams. Ensure 0 pressure on 2.375" tubing. Slip chains and pick injector head. Cut 2.375" CT 3.5' above bop. Remove CT hanger and G spear BHA. Make up double cold roll coil connector to V-String. Slip chains and make up lubricator to BOP. Perform push pull to -5K and 15K. coil was moving at 8K up weight. Possibly pulled out of coil connector. Pop off well. Coil connector pulled out. Roll on connector was not rolled deep enough on whip end. Cut coil and roll on connector again. Strip down lubricator and make up to BOP. Pull test to 15K. Slack off to 12K. Open pipe and slip rams. Spool OOH. Pulled 320' of V-String when coil partially parted when moving over gooseneck. Stop injector. Hold safety meeting to discuss plan forward. Plan to secure well and leave night watch on location. Rig up hot oil truck to 9-5/8" casing. Secure partially parted pipe with sling and two clamps. Close in manual lock downs on pipe slip rams. Pump 105 bbls down IA to keep well killed. Location walk around completed. Well is secured. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 02/19/2023 - Sunday PTSM, PTW, Plow rig location, lay out felt & liner, spot base beam, Carrier, Accumulator, heaters, pits, pump, choke house, office trailer. Lay out grating, berm containment, run electrical lines, unload trailers, run circulating lines, winterize carrier, fill fuel bulk tank. SDFN, Rest crews. PTSM, PTW for night crews. 02/20/2023 - Monday PTSM, PTW, Fill pits w/ drill water, while warming Eq. Check well static, Pump 150 bbld down well, 3.5 BPM, 75-100 psi shut down well on vac. Monitor well, fill pits, wk LD pins, check well static. Pump Drill water down well @2BPM, while n/d adaptor & install install 11" hanger w/TWC, RILD pins, shut down pump, blow down lines, install DSA 11" 3k, x 13-5/8" 5k. N/U 13-5/8 BOPE, Mud cross, double gate, single gate & annular. Tq flanges, install kill & choke E-Lines, accumulator lines, check precharge in accumulator bottles good, pressure system, function test BOPE good, install rig floor & stairs, install cellar wind walls, cover floor, Heat cellar & rig Eq. Night watch Rig, Fuel eq. Heat cellar. 02/21/2023 - Tuesday PTSM, PTW, Function test BOPE good, Test gas alarms Good, install 2-3/8" TJ, fill stack & surface eq w./water, shell test 250/2500 till good, repair leak on TJ. Test BOPE as per Hilcorp & AOGC expectations, AOGCC witness was waived by Jim Regg, tested 250/2500, w/ 2-3/8 & 3-1/2" TJ's. Blow down surface lines, break down test eq. Check well static, pump 20 bbls down well, monitor 15 min good. Pull hanger & l/d same, secure well. R/U 3-1/2" handling tools, R/U skate, M/U BHA - 8 1/8" overshot, xo t/3-1/2" PH6 = 7.61, M/U t/jt 3-1/2" PH6 wk string. Night watch, fuel rig & keep warm. Prep Eq. for next task. 02/22/2023 - Wednesday PJSM / take on fluid to pits, check well pressure "0" load pipe skate on pipe rack. TIH with oversize guide, 5-3/4 overshot, dressed with mill control guide with a 2-3/8" plain basket grapple, top ext, top sub, x/o to work string = 7.61 picking up 3.5 12.95 P-110, ph 6 work string tagging fish 845 ft. Attempt to work over top of fish. No luck. Pooh from 845 ft. dpm lay out over shot, remove and inspect grapple take out mill control guide and make up overshot. TIH with BHA to 845 ft. Engauge and latch fish with 3k down, with 2 ft swallow work 2-3/8 coil up to 36k 3 times not free. RIG up E-line. RIH with 1-7/16 free pt. tools tagging at 831' ELM made several attempts to work thru with no joy, pooh made up 2.18 LIB RIH made impression at 831 ft. ELM pooh had impression of 1-1/4 fish top. Coil looked rolled in Makeup CCL. (2) 1-11/16 Wt bars with spangs and 1.75 swedge, RIH tagging at 831 ft. working spangs to 839, RIH with 1.82 swedge tagging at 831', work tools with hand spang down to 839 ft. had 800k over pull. free, RIH with 1.85 swedge tagging at 831 ft. hand spang made 3 ft. Pooh remove 7 ft wt. bar put on 1.82 swedge tagging at 831 ft. spang down 4 ft. to 835 pooh, had decision with ops team. Pooh to run slick line with smaller tool string. Night watch. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 02/23/2023 - Thursday PJSM check well for pressure "0" open well, spot Slick line truck and rig up slick line. RIH with 1.68 swedge on a 1.5 tool string tagging at 847' slm, attempting to work swedge inside coil. Pooh, lay out 1.5 tool string and make up 22 ft. 1" tool string. RIH, with same tagging at 4078 ft slm, pooh. Pick up on 2-3/8 coil tbg fish to 38k 8k over pull. RIH with a 1.40 swedge on a 22 ft. x 1" tool string, tagging at 4774 ft. SLM, pooh with no problems lay down tools. make up 1.25 tool string attempting to work thru top of fish 847 slm with 1.45" & 1.68" swedge with no luck. Pooh, rig down slick line. Rig up E-Line with an 18 ft. 1" free point tool. RIH. set up tool 1000 ft. continue in hole check fish for free movement at 2500 ft working pipe from 20k to 34k, 3500 ft.3750 ft. 4080 ft., 4050 ft., 3900 ft. working wt. f/ 26k to 40k, run back in hole checking fish for free movement at 4580 & 4620 ft. Had good movement at these depths. RIH with 1-3/8 RTC on 1" tools string tagging up at 827' ELM made several attempts to work same thru top of fish while holding 16k to 26k on pipe with no luck. Pooh, lay down same. Change out tools made up 1-3/8 2" coil cutter, RIH on a 1" tools string tagging up at 827' ELM made several attempts to work same thru top of fish, while working fish from 16k to 35k tools got hung up two times work same free. Pooh, lay down tools and secure well for night. 02/24/2023- Friday Check well pressure "0" psi. Break out pup joints pour 10 gallons of safe lube down work string, line up pumps and continuous fill annulus with 8.4 ppg water, make up pup joints. Rig up E-line. RIH with at 1.38 jet cutter on a 1" tools string, wt. bars CCl, RIH tagging up at 839 ft. attempt to work same into fish, with no joy, pooh lay out cutter add a 1" bull nose, RIH tagging up at 839 ft. work tools several times, work thru to 850 ft. work tools thru top of fish 4 times. Pooh, pick up 1.38 jet cutter for 2" coil tbg. RIH work thru top of fish. Continue in hole with cutter to 4630 ft ELM. Pick back up to 4620 ELM pick up on string to 40k fire cutter, had good indication of cutter firing, but no pipe movement, pooh with E-line. Work fish from 20k to 60k holding weight 5 minutes at each interval, continue to work pipe from 20 k to 65k worked pipe 16 times fish parted had 4K wt. above work string wt. Derrick inspection, lay down pup joints and single, change out bails. Pooh with work string racking back in derrick. Lay out 2 singles, change out handling equipment for pulling coil, perform shut in drill cut coil with manual cutter and install coil connector and TIW, R/u intrinsically safe coil cutter. Pooh cutting 2- 3/8 coil tbg with hyd cutter and laying out same in 59 ft pieces. Recovered total of 2929.84 ft of 2-3/8 coil secure well for night. 02/25/2023 - Saturday Lay out and strap pipe, Rig up pipe skate, change 2-3/8 handling equipment to 3-1/2 check well for pressure (psi) filling well with 8.4 water. TIH with 5-3/4 overshot with 12 stands out of derrick, continue with hole picking up pipe off pipe rack, tagging fish at 3768 ft. dpm latch dish verify latch, set same on slips with 5k. Rig up E-Line hang sheeve in derrick. RiH with 1.82 swedge to 4314' ELM pick up on fish to 5k overpull on fish. Worked up to 15k overpull on fish still tagging at 4314 ft ELM pick up to 20k overpull on fish still unable to get down below 4314 ft. Pooh and lay out same make up a 1.40 swedge with a 1-3/8 x 5" weight bar above swedge on a 1" tool string. RIH with same tagging at 4175' ELM attempt several times unable to get past this depth. Pooh lay out tools, make up 1.8 jet cutter. RIH tagging at 4300 ft. holding 20k overpull on fish slack off to 15k over pull on fish. Cut fish at 4300 ft lost 15k wt. ELM pooh rig down E-line. Secure well for night and blow down lines. Generator watch. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 02/26/2023 - Sunday Check well for pressure "0" filling well with 8.4 ppg water. POOH with fish from 3,722 ft. dpm. Change out hose on power tongs. POOH with fish f/ 2,356 ft. dpm to fish. Change out handling equipment. Lay down fish BHA, rig up to pull coil. Perform shut in drill on coil, install connector and stab valve. Lay down fish, cutting in 59 ft lengths had 8 cut pieces, and one 29 ft cut piece = 536.15 ft total fish recovered from well 3465.90. Estimated top of fish 4304 ft. Change out handling equipment. Picked up 5-3/4 over shot dressed with 4" x 2-3/8 hollow mill dress off mill and 2-3/8 grapple trip with pipe out of derrick to 3,788 ft. secure well for night. Night watch. 02/27/2023 - Monday Check well for pressure ("0") started filling continuously with 8.4 ppg water. TIH f/ 3,788' dpm to 4,302' dpm picking up 3.5 ph. 6 p-110, 12.95 lb./ft work string singles, up wt. 49k down wt. 51K, tagged top of fish at 4,302 ft. dpm. Worked over fish rotating with power tongs to 4,313' dpm. Pick up 5k over string wt. to confirm latch, lay down single of pipe and pick up 10 ft pup joint. Work fish from 50k to 116k, in 5k intervals to 66k over pull, pipe parted after 10 ft of stretch, at 116k on weight indicator had 300 lbs of weight over string wt. Perform derrick inspection. Pooh with fish f/ 4,302' to overshot racking back3.5 ph6, 12.95 P 110, work string in derrick. Change out dies in power tongs and slip dies, set slips on coil, make cut on coil, with hand cutter, lay down over shot, change out elevators, lay down power tongs, p/u coil cutter, perform and discuss coil shut in drill with crew. Lay down 2-3/8 coil tbg fish recovered total of 63.35 ft. of 2-3/8 coil tbg total of fish recovered from well 3529.77. EST top of fish 4366 ft. dpm from part in pipe od of coil 2-1/4 od for 20 ft then 2- 5/16 for 15 ft and then back to 2-3/8 od. Id at the part 1-7/8", change out 2-3/8 handling equipment to 3-1/2 handling equipment, change out weight indicator secure well for night. Night watch 02/28/2023 - Tuesday PJSM - check well for pressure "0" psi. Blow through surface line to ensure fluid paths are free and clear, build 2-3/8 & 3- 1/2 test joints, made 3-1/2 test joint to test plug. Fluid pack bop equipment with water, attempt to shell test to 250,2500 psi chasing leaks change out test plug with tubing hanger and 2-3/8 test joint run lock down screws. Test 13-5/8 5M BOPE as per sundry 250/2500 psi. Held each test 5 minutes test made with water with 2-3/8 and 3-1/2 test joints Quadco tested gas alarms, PVT alarms, tested all choke and kill valves passed, upper 2-3/8 pipe rams passed. AOGCC Jim Regg waived witness for Bop test. Install 3-1/2 test joints and tested lower3-1/2 x 5-1/2 VBRs, failed /Pass cycled and retested, 13-5/8 annular failed to test with 2-3/8 and 3-1/2 test joints. Test manual chokes A & B on choke manifold. Pull test joint joints secure well for night. Night watch. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 03/01/2023 - Wednesday Check well pressure, well static, blow through surface lines, lines clear, clear rig floor of tools and handling equipment, rig down heater to rig floor, R/d down stairs, Railings, skirting around rig floor, fold up rig floor. Nipple down annular, nipple up replacement 13-5/8 5m annular (Jim Regg - AOGCC- Approved annular change via email.) rig floor back up. make up 2- 3/8 test joint, function annular, fill stack, run 2-3/8 test joint rig up to test 13-5/8 annular. Test 13-5/8 annular and insid e choke and kill valves to 250 low and 2500 psi hi. Held each test 5 minutes test made with water. Good test, perform Accumulator drawdown. Back out hanger lock downs, lay out test joint and hanger. Rig Halliburton E-line. E-line RIH with 1- 11/16 rope socket, CCL 10 foot of stem, spang, blind box tagging at 4356' ELM had clean pick up. pooh lay down tools pick up spinner tools. RIH with Spinner tool, Found fluid level at 1210'. See Eine report for station stops and logging passes. Logged from 3400 to 4000ft at 40/60/80 FPM. Saw cooling at 3535'. no indication of flow during passes. Make station stops from 4200' to 3200' and saw no fluid movement in any stop. Started rig pump, pumping in the well at 2 bpm while logging tools stationary at 3200'. Time log for 30 min until stable flow rate. seen from pumping in well. Logged down at 40fpm to find where fluid was going. stopped at 4000' and saw no fluid movement. PU to 3775' and no fluid movement for 5 min station stop. PU to 3740' and saw fluid movement. Logged up to 3200', made station stop. Shut down rig pumps after pumping 198 bbls or water. POOH found fluid level at 1118'. RD EL. Generator watch. 03/02/2023 - Thursday Check well, well static, R/u Handling equipment to Run 3.5 work string, M/u 5-3/4 over shot dressed with 2-3/8 basket grapple with plain control. RIH with work string to, liner top rotate thru Liner top. continue in hole to 3660 ft. dpm, pick up 11 singles of 3-1/2 work string, to 4032 ft. continue with work string out of derrick to top of fish at 4367 ft, tagged with 1k down wt. on fish attempt to pick up to rotate had friction bite, set down 10k to Engauge fish lay down single make up p 10 ft. pup. Wash down over fish 1" at 2 bpm, shut down pump, pick up to 60k worked over shot to get better bite on fish. Rig up E-line RIH w/ Rope socket, 1-3/8 CCL, banded cent, two 1-3/8 x 4' weight bars, banded cent, pin to pin, 1.69 sovhock sub, jet cutter total tools string, 21.5 ft. RIH with no problems to 4760 ELM., POOH. Make up rope socket, banded cent, 1.69 CBL, banded cent, 1.69 GR-CCL, Banded cent, overall length 26', Log dwon from top of coil fish at 4,367 ft. to 4750 ELM.Pass @ log perfom free pipe cal, log up from 4750 to 4320 ft. POOH. Set E-line aside, make up 10 ft pup, with Kelly hose, wash down 5', at 2 bpm with"0" psi, increase rate to 3 bpm/ 40 psi, p/u to 50K, s/o to neutral wt. at 43k and pump 5 minutes. Rig up E-line with 1.68 jet cutter, RIH, unable to get cutter inside of fish, tried pulling up to 7k over, slack off to 30k down, pick back up to 14k over. Unable to get thru top of fish, POOH cutter was damaged. E-line finished pooh with cutter, pull up to 103k on weight indicator, 60k over, no movement, E-Ine RIH with 1-3/8 dummy run unable to get in top of fish. Rig down E-line out of derrick pull up to 114k pipe parted rack back 5 stds secure well for night. Generator watch. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 03/03/2023- Friday Check well "0" psi, well static, inspect equipment, prep to pull out of hole. Pooh with 3.5 PH 6 work string from 4,124 ft. to surface, p/u 40k. lay down single joint, with overshot Break off overshot, recovered 21.40 ft of 2-3/8 inside work string above grapple. Total pipe laid out by RIG 3551.22 ft of 2-3/8 coil tbg. EST top of 2-3/8 coil at 4396.22 ft. R/up E-line RIH with 56 arm caliper tool to 4,379 ft. Run Caliper log from 4379' to 3390 ft. make repeat pass from 4379' to 500 ft. Pooh m/u bond log tool, RIH log from scab liner to 3449' to surface R/d E-line. RIH with 3-1/2 work string from surface to 4337 ft/. Secure well for night, Blow down lines. Generator watch. 03/04/2023 - Saturday Check well ("0") psi, well static, blow through surface lines, inspect equipment. Run in hole from 4337 ft. and tag sand at 4376' DPM, lay down, top joint, PUMP 20 BBLS water to ensure pipe is clear, dump 3ea, 60 lb bags of sand, and 3ea 60 lb. bags of pea gravel, running water with water hose down work string, pump 9 bbls water started to pressure up, pick up 25 ft. pressured up to 1100 psi, work string, work string cleared, let sand and gravel settle for 30 minutes. RIH with work string tagging at 4366'. 10ft of fill on top of fish. Pick up to 4360 ft. PJSM with cmt crew and rig crew, Rig up cementers pressure test lines to 3000 psi. Mix and pump 67 sks 14.5 bbl. CL1 type II cmt with 1.243 yld mixed at 15.3 ppg. Displace same with 28 bbl. of 8.4 ppg water, shut down. POOH with 5 stands work string slow f/ 4360 ft to 4050 ft. Drop wiper ball pump 30 bbl. 8.4 ppg water at 3bpm "0" psi. Pooh racking back 3.5" PH6 work string. Clear rig floor, rig down floor, ND annular, remove single gate, NU annular. Lower rig floor. Rig up & test breaks between annular and Double BOP to 250 low and 2500 psi. Rig down test equipment. Blow lines secure well for night. Generator watch overnight. 03/05/2023 - Sunday PJSM check well "0"psi, open well, perp to RIH with test packer. Make up 7" JS3 test packer for 23-29# csg. RIH tagging at 4092 ft. with 18k pipe wt. Pooh f/ 4092 to 3800 laying down excess work string. Set test packer at 3800' fluid pack tbg and lower annulus, attempt to test cmt plug above pool 6 sand to1000 psi, bleed off 200 psi in first 6 min, trouble shoot, work air out of system, attempt several more times to test with same results, unset packer move down hole to 3831 ft. set packer, fluid pack well and pressure up to 1000 Psi and bled. Down to. 500 psi in 30 minutes, bleed off pressure, unset packer, pooh racking back in derrick f/ 3831 to 3524 set packer at 3,524'. Fluid pack annulus, close annular and test, top of liner and 9-5/8 csg to surface to 1500 psi for 30 minutes on chart (good test), unset packer. RIH f/ 3524 ft to 3800 ft set packer at 3800. Rig up E-line, pump 40 bbl.8.4 ppg water, continue to RIH w/ production log, spinner to 4,090 ft tagging at 4090 ft ELM pick up to 4070 ft pressure up to 1000 psi take 10 minute reading ( no spinner movement ) pick up 3930 ft pressure up to 500 psi take a 5 minute reading ( no spinner movement ), pick up to 3840 pressure up to 500 psi take 5 minute reading) no spinner movement, pick up to 3795 pressure up to 500 psi. had spinner movement, RIH to 3810 pressure up to 500 psi (hand no spinner movement) pick up to 3770 pressures up to 500 psi took 5-minute reading (had spinner movement) pooh with E-line. Rig down E-line blow down surface line. Secure well for night. Generator watch. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 03/06/2023 - Monday PJSM, check well for pressure "0" open well, blow through surface lines. Pooh with 3800 ft. with JS3 test packer, lay down packer. M/up spear t assembly, (ITCO spear, spear stop sub, x/over, Oil jar, bumper jar), on ground, NOTE. AOGCC Bryan McLellan gave approval VIA E-mail on March 6,20232 at 10:46 AM to complete operational steps from 44-57 in sundry # 323-077. Make up spear BHA (spear assembly, 6ea 4-3/4 drill collars, x/over = 212.43'). RIH with work string checking torque on all work string connections to 8800 ft bs max torque. Pick up power swivel and hang service loop TEST TIW TO 250 low and 2500 psi, make up valve on power swivel. Make up (2) 10" pups on the Btm on power swivel, torque connections to 8800 ft/ lbs., pick up wt., 43k s/o wt. 43k. RIH to 3445'. Tagged TOL continue slacking off to 3449 ft. set down 10k close jars, p/u and bleed jars, pick up to 47k rotate 7 turns to the left, lost pick up wt. return to neutral wt. continue to pick up without any drag. Rig down power swivel, hang in derrick, l/d pups rack back 1 std, secure well for night. Blow down surface lines. Generator watch. 03/07/2023 - Tuesday Check well for pressure "0" start filling well with 8.4 ppg water. Pooh with fish f/ 3,371' dpm to BHA. Pooh racking back Drill collars and laying out the jars and spear with 8 ft. piece of the ZXP liner top packer. Rig up to test BOPE, M/u test plug, fluid pack surface equipment. perform shell test. Test BOPE 250 low and 2500 psi high- test 3-1/2 test joint upper rams, kill manual valve K3, TIW iBOP, CMV's 3-10 PERFORM KOOMEY DRAW DOWN, KILL LINE VALVES K2 K1 FAILED LOW TEST. remove kill line valves K1 and K2 install replacement valves. unable to get a low test on valves pull hanger and install test plug with new seals, fluid pack surface equipment. Back out test plug, test Blind Rams to 250 low and 2500 psi high, install test joint and attempt to test the top rams, rams leaking call for replacement. Note Sean Sullivan with AOGCC witness test. 03/08/2023 - Wednesday Top rams failed on 250 psi low test. Pulled test joint. Shut the blind rams. C/O VBR's, C/O leaking kill line valve (K3). Insta ll test joint, shell test VBR's and K3 valve 250/2500, pass. C/O pump in sub (was leaking) & install test joint w/ TIW/Dart valve & fluid pack stack & choke. Retest BOP's to 250 low / 2500 psi high w/ 3-1/2" test joint, pass. Test each component 5 min low/high. One fail on the K2 kill line valve (greased and retested). Perform accumulator drawdown, pass. AOGCC test witnessed by inspector Sean Sullivan. Blow down BOPE, R/D test equipment, pull test plug, close blind rams & secure well for the night. Generator watch for night. 03/09/2023 - Thursday Rig up AK Eline. RIH w/ Legacy Oil Tools 5.61" OD Big Boy CIBP (LOT# 95898), CCL to top of plug = 8.9'. Pull tie in log, on depth. Set top of CIBP @ 3762'. Bottom of plug @ 3763.5'. Pick up & set down on plug. POOH. Lay down Eline. Begin hole fill. Fill wellbore w/ 177 bbls water (FL @ ~2418'). Monitor FL 15 min at surface, static. PT CIBP bringing up pressure in 100 psi increments, hold 500 psi for 5 min, pass PT. Rig down Eline and pick up Burn Shoe BHA, Flat bottom Burning shoe 8-1/8 KHT Box Crown.26 (7.0" ID with cutrite), 1 joint of 8-1/8" wash pipe, Top sub, string magnet, PxP x/over, Boot basket, Boot basket, Bit sub, 4-3/4 oil jar, Drill collars, x/over = 254.26 Trip in hole with work string, tagging at 3454 (top of liner) (d pm) Rig up swivel and haws head, space out power swivel with (2ea) 10 ft pup joints. Generator watch. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 03/10/2023- Friday PJSM - Check well for pressure "0" psi, Rig up hose to rain for rent tank, prime pump, open well. Establish Milling Parameters, 75 rpm, 900 ft/lbs. torque, pumping 3.5 bpm at 300 psi, slack off to top of liner at 3454 ft. dpm burning over liner top packer 3454 t/ 3457 'at 75 rpm/ 1800 ft/lbs. torque, pump 3.5 bpm at 350 psi, with 1 to 3k WOB, pumping 5 BBL, 140 vis sweeps as needed sweep coming out of hole at 70 vis 8.4 ppg. Finish circulating bottoms up to get sweep out. Continue burning over liner top packer f/ 3457 ft 3458 ft at 75 rpm 2200 TO 2700 FT/LBS, pumping 3.5 bpm at 300 psi, WOB 3 to 6k total hole made 4'7" getting back fine shaving on Magnets. Circulate 3 tbg volumes 80 bbls clean returns, nothing on ditch magnets. Continue burning over liner packer, at 3458 ft dpm at 75 rpm 3000 to 3500 ft/lbs. torque with 6/8k WOB pumping at 3.5 bpm/ 300 psi made no footage. Rig down power swivel, lay down pup joints, rack back 5 stds 3- 1/2 ph6 work string secure well for night. Generator watch. 03/11/2023 - Saturday PJSM - Check well "0" open well and start pump hole full. Pooh with 3.5" PH6, 12.95# work string f/ 3,165' to 254 ft to (BHA). Change out slips and bowls, swap dies in power tong, rack back 33 stds and 6ea 4-3/4 drill collars. Clean Magnets and check Boot baskets, Boot baskets were clean. Change out burn shoe. RIH with BHA, (flat bottom burning shoe, joint of wash pipe, top sub, string magnet, double pin sub, boot basket (2), Bit sub, 4-3/4 oil jars, 6ea 4-3/4 drill collars, x-over = 253.21) change out handling equipment. TIH form 235 ft. with 3.5 PH 6, 12.95# work string, to 3444 ft. Rig up Haws Head, rig up power swivel, install rubber element in haws head. Make up pup joints. Establish milling parameters, p/up wt. 40k s/off wt. 40k, pumping 3.5 bpm at 300 psi, 55 rpm at 1200 ft/lbs. off bottom. Burning over liner top packer with 4 to 6k wob, AT 55 RPM AT 3003 TO 4500 FT LBS torque, pumping at 3.5 bpm at 350 psi lost full returns. Footage made today 1.4 ft. pick up off bottom blow down surface lines secure well for night. generator watch. 03/12/2023 - Sunday PJSM check well for pressure "0", Blow air through surface lines, prime mud pump, put heater trunk on power swivel HPU, Get HPU started. Establish milling parameters. -1.5 to 2 bpm at "0" psi well still on vacuum 55-60 rpm with 2000 ft/lbs. torque off bottom, burn over liner top packer, f/ 3458.5 to 3461.5' 1.5 to 2 bpm with 50-75 psi 55-60 rpm with 2500 to 3500 ft/lb. torque, 4-6 k WOB made no footage, in last hour, total footage made today 3 ft. total footage made on both shoe runs (7' 4-1/2"). Returns were minimal to none. Lost returns for the majority of the day, Max returns 1/2 bpm when pumping 2 bpm Lay down swivel, rack back Power swivel in derrick, remove haws head l/d pup joints. Pooh with 3.5 ph. 6 work string f/ 3444 to 3166 ft. blow down surface line and secure well for night. Generator watch. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 03/13/2023 - Monday PJSM -Check pressure on well, well on vac blow through surface lines. Pooh with 3.5 PH 6 12.95# work string racking back in derrick f/ 3165 ft. to 212' adding. 5 bpm 8.4 ppg water to well Change out handling equipment, rack back 3 stds of 4-3/4 drill collars, clean magnets, l/d jars magnets, boot baskets, wash pipe and Burning shoe. Rig up shooting flange, R/up Yellowjacket E-line, pressure test to 500 psi, RIH with 6" gauge ring and junk basket. RIH tagging CIBP at 3761.5 ft. ELM run correlation log to top of scab liner, to 3454 ELM. Make up 5.8 jet cutter. RIH with same log on depth make cut on scab liner at 3760 ft ELM, had good indication of cutter firing, pooh make up second 5.8 jet cutter RIH log on depth make cut on scab liner at 3498 ft. had good indication of cutter firing, pooh. Rig down E-line and shooting flange. Rig up floor to RIH. RIH with spear assembly (ITCO spear, spear extension. Stop sub, bumper jar, oil jars and 3 std- drill collars= 244.33, continue TIH WITH 3.5 PH 6 work string f/ 224 ft to 3454 ft, Engage spear into fish. Bleed jars, Hit jars 3 time at 50k over had no movement. Secure well for night. Generator watch. 03/14/2023 - Tuesday Held PJSM, check dwell for pressure. "0" open well, rig up hose to tubing and pump 40 bbl. of 100 deg water down work string to heat up jars. Work jars from 40 to 50 k over, string wt, pull up to 60k over, worked jars several times with no luck, pumping. 5 to 1 bpm down IA. Rig up power swivel, make up to work string. Rotate work string 3 turns to the right holding 18k over string of 38k. holding 3500 ftlbs torque while working fish 60 to 100k down to 75k, grapple slipped at 75k attempted to reset grapple, grapple slipped again, unable to set grapple. Rig down power swivel and rack back in derrick, Pooh 3454 ft. to 224.33 ft. with 3.5 PH 6 work string, racking back in derrick. Pooh rack back 3 stands of drill collars and la y down BHA, no recovery of fish. Grapple had jam in bull nose. Break down wash pipe and boot baskets, Build 3-1/2 test joints. Secure well for night blow down surface lines. Generator watch. 03/15/2023 - Wednesday PJSM check well for pressure. Blow through surface lines, grease choke manifold and mud cross valves. Install 3.5 test joint and seat test plug in hanger profile, fluid pack BOPE and test equipment work air out of system. Test BOPs as per sundry to 250 /2500 psi, K-1,K-2, K-3, CMV 1 -10 2-7/8 x 5-1/2 B=VBR pipe rams, annular, dart valve, TIW, and lower Kelly. Test with 3-1/2 test joints, witness waived by AOGCC Jim Regg. Draw down test Accu, starting pressure 3000 psi, final pressure 1825 psi, pressure recovery time for 200 psi recharge 23 seconds full pressure 111 seconds. Quadco tested Gas Alarms. Rig crew check PVTS. Rig down test equipment and prep to pick up BHA. Pick up Flat Bottom burning shoe, joint of wash pipe, top sub, string magnet, double pin sub boot basket, boot basket, bit sub, 4-3/4 jar, 6 4-3/4 drill collars, x/over, =254.13 ft. Change out dies and change out slips. RIH with BHA on 3.5 PH 6 work string f/ 254 ft. to 3444 ft. Pick up power swivel, pick up single w/s, make up power swivel, install haws head torque bolts, secure well for night blow down surface line. Generator watch. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 03/16/2023 - Thursday PTSM, check well, good. Blow through surface lines, good. Establish Parameters, rot wt-40k, 70 RPM, tq off 500, tq on 2k- 5k, pump 2 bpm, new shoe slightly under gauge. Wash & ream down from top of fish @ 3454' t/ 3461', Surfaced returns after 480bbls. C/O circulating rubber. Cont. wash & ream w/ 8-1/8" burn shoe down to 3490', (end of washwipe), tq, 1500- 5k, loss rate of 30BPH. CBU Rack back power swivel, blow down lines. L/D pup jts, POOH t/3444'. Secure well. Night watch rig, fuel & monitor heat. 03/17/2023- Friday PTSM, check well, blow through surface lines, good. N/D circulating head spool. POOH w/ Burn shoe assy. f/ 3444', up wt 40k, rack back wk string, t/ BHA @ 254'. Stand back collars, clean magnets & break off jar, boot basket & magnet assy, break down washpipe/burn shoe assy. Swap out handling tools, P/U BHA - 8 1/8" burn shoe, 2-jts 8 1/8" washpipe, Top sub, string magnet, PxP xo, 2- boot baskets, bit sub, oil jar, 6-drill collars, xo t/3-1/2" PH6 =254.14'. C/O handling Eq. TIH w/ 3-1/2" PH6 wk string slow due to wind t/3447', up/dn wt 37k P/U power swivel, secure well for night. Night watch rig, fuel eq. 03/18/2023 - Saturday PTSM, check well good. P/U single, n/u circulating spool. Rih f/ 3447' t/3454' rotate over TOF @ 3454', cont. down clean except for slight bobble at 3496', tagged up @ 3501'. Wash & ream at 3501', make 2" smooth, tq. @1800, pump 2 BPM. Set back swivel, L/D single, n/d circulating spool. POOH, stand back 3-1/2" wk string t/BHA @ 287'. Stand back BHA, l/d jar, boot baskets & string magnet. Prep BHA & P/U - Spear w/6.220 grapple, xo, Ext, stop sub, bumper sub, oil jar, 6- 4.75 DC,'s, xo = 224.33'. C/o handling eq. TIH w/ 3-1/2" wk string t/3447', up /dn wt 38k. Continue in hole, engage fish w/ spear tagging stop sub on tof@ 3454'. P/u t/ 60k no movement. P/u hit jar lick @ 40k over no joy, secure well for night. Night watch, fuel & roll reserve pit. 03/19/2023 - Sunday PTSM, check well good. Jar on fish for 1.5 hrs @ 30-40k over no joy. Release grapple on spear pull out of fish, did have a 3k bobble pulling out. Cont. POOH, stand back wk string & collars, l/D grapple assy. with packer that parted at top threads - 7.35'. Cut & slip 75' drill line, service rig (DW, crown, blocks etc.). P/U Mechanical cutter BHA- Mechanical cutter w/carbide blades, 6- 4 3/4" DC, XO = 184.42 (total length to blades). TIH on 3-1/2" ph6 wk string t/3593'. P/U swivel, pull up placing cutter @ 3565'. Rotate setting cutter anchor & cut 7" casing, circulate @.75BPM. P/U closing blades. RIH past cut had bobble at cut. RIH p/u singles t/3748', p/u pup jt. rih placing cutter @ 3755'. Rotate setting cutter anchor & cut 7" casing @ 3755', pick up t/3746' w/overpull, then clean. R/D swivel, secure well f/night. Night watch rig, fuel, continue clean reserve tank. 03/20/2023 - Monday PTSM, Check well good. POOH f/ 3746'. Stand back BHA. L/D cutter, P/U Spear BHA- Spear w/6.220 grapple, xo, Ext, stop sub, bumper sub, oil jar, 6- 4.75 DC,'s, xo = 224.33'. TIH w/3-1/2" wk string t/ 3461', up wt 36k engage top of fish, pick up clean w/38k. POOH t/ BHA @ 224'. Stand back BHA. C/O handling Eq. Monitor well, good. Break & l/d fish- Recover 102.15' of 7" casing (2 full joints & 1-23' cut jt. ). C/O handling eq. P/U redressed spear BHA - Spear w/6.220 grapple, xo, Ext, stop sub, bumper sub, oil jar, 6- 4.75 DC,'s, xo = 224.33'. Cont. RIH w/ 3 stands 3-1/2" wk string t/ 410'. Secure well, night watch, fuel & work on project list. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 03/21/2023 - Tuesday PTSM, check well good. Cont. RIH f/410' t/ TOF @ 3565', up /dn wt 37k, engage spear down to stop sub. P/U @ 40k POOH stand back 3-1/2" wk string t/BHA. Stand back collars, l/d jars/bumper sub. C/O handling eq. monitor well. POOH L/D 7" casing fish, recover 190'.61'. C/O handling Eq. L /d stand of 8 1/8" wash pipe. Clear floor, shuck spear from fish. C/o handling Eq. Build 3-1/2" test joint. Secure well for night. Night watch rig, fuel & work on project list. 03/22/2023 - Wednesday PTSM, check well good, install 3-1/2" tj, fill surface eq. w/test water. Test BOPE as per Hilcorp & AOGCC expectations, test 250/2500 w/3-1/2" TJ, AOGCC witness was waived by Jim Regg, had one FP on inside choke line valve, serviced valve & re- test good. R/D test eq. l/d breakdown test jt. P/U Scraper BHA- 8 1/8 bit, 9-5/8 scraper, bit sub, pup jt, xo, bumper sub, oil jar, 6 4 3/4 DC, xo, = 219.22', cont RIH w/ 3-1/2" wk string t/tag @ 3755', p/u t/3748'. R/U break circulation @ 1.7BPM, stage up t/ 3 BPM , lost circ, attempt to catch w/ no joy, fill from surface took 56bbls to fill hole. POOH stand back 3-1/2" wk string t/1151', secure well for night. Night watch rig & fuel. 03/23/2023 - Thursday PTSM, check well, Cont. POOH standing back 3-1/2" wk string, t/BHA @ 219'. L/D BHA- 6-4 3/4 drill collars, jars, bumper sub, xo, pup jt, bit sub, 9-5/8 scraper, 8 1/8 bit. C/O handling Eq. service rig. P/U retainer w/stinger/running tool. TIH t/3750', up dn wt 36k, cont in hole t/ tag top of cut joint 3762' correlated to perf depth. P/U t/place retainer @ 3758', run through setting procedure, setting retainer @ 3758', set down 30k verify set. R/U pump lines Pump @.4bpm, 1030psi injection rate, R/D lines spot in cement unit. R/U Halliburton cmt unit, run lines. pump 1.5 bbls @.5bpm, pressured up t/1940, bled pressure off make second attempt, pressure up t/ 2000psi, monitor pressure 16 min, went t/1400psi, discuss options with Engineering. R/D Cementers, back out cmt stinger. POOH f/3758-2544'. Secure well for night, night watch, fuel. 03/24/2023- Friday PTSM, check well static, POOH f/2544' l/d cmt stinger. R/U e-line, m/u 5" bailer assy 30', RIH t/tag top of retainer @ 3758', p/u 3756' & dump, good indication bailer dumped. POOH, bailer mt, re-arm bailer, & refill, RIH t/3747' p/u 3746' dump bailer, good indication it dumped. POOH, bailer mt, re-arm bailer, & refill, RIH t/3738' p/u 3736' dump bailer, good indication it dumped. dumped total of 80gal cmt =26'. POOH, bailer mt. r/d e-line. P/U 9-5/8" retainer, RIH t/3700', up/dn wt 35k set retainer @ 3700' set 28k down verify set. R/U circ lines, check injection rate pumped 4 bbls pressured up t/1560psi held for 15 min fell to 1505, bleed off, back out stinger to release from retainer, pick up out of retainer, 5' above, RIH stab back into retainer, attempt to pump again with same results, bleed down t/600 psi un-sting from retainer, verify pressure drop, r/d circ lines & blow down secure well for night. Night watch rig, fuel, work on project list. Rig Start Date End Date 1/26/23 4/24/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 14X-06 50-133-20342-00-00 181-092 03/25/2023 - Saturday PTSM, check well good, POOH f/3700' l/d cmt stinger. P/U retainer, TIH t/ 3604' up /dn wt 31k. R/U circ lines, check circ down string good, P/U set retainer @ 3600'. R/U check injection rates below retainer, pump.5 BPM @ 1230psi, .8BPM @ 1550psi.,shut down, fill annulus 74 bbls, shut in, pump 1 bpm stage up t/ 2.5bpm catch pressure inject @ 15 psi 5 bbls, shut down, open well on vac. Mobe cementers & R/U, PJSM, pump 2 bbls water @.5bpm 900psi, pump 8bbls @ 1463psi FCP, PT lines 3k. Mix & pump 5 bbls 15.3ppg cmt, displace w/25bls water, ICP @ 1bpm 1288psi, FCP @.5BPM 1500psi, spotted 4 bbls below retainer, Pulled stinger out of retainer laid one bbl on top of retainer. POOH t/3510', r/u pumped 2.5 bpm, cleared pipe, r/d circ lines. POOH, L/D cmt stinger. secure well. Night watch rig, fuel, wk on project list. Mobe from 33-30, RU W/L - PT Lub 150L/1500H - Passed RIH w/ 2" GR to 3233' KB. Tag Cmt. POOH RDMO 04/24/2023 - Monday Ops Rig up pump trailer. Pump 250 gal of methanol to pack well Pressure tested well to 1500 psi, held for 30 min. Passed test. 03/26/2023 - Sunday Check well good, P/U 9-5/8 retainer. RIH w/3-1/2" wk string t/ 3480' pump down string clear, set retainer @ 3480', set down 24k verify good, AOGCC witness waived for tag by Jim Regg @ 8:12 am 3-26-23. Fill annulus, Pressure up t/1500psi hold f/ 30 min good. R/U circ lines, mobe out cementers, spot unit & r/u, PJSM. Fill lines Pump 225 bbls water @ 3.5bpm, 200 psi, p/t lines 780/3000 good. Mix & pump 40 bbls 15.3ppg cmt, pump 25bbls below retainer @3BPM 45 psi, un-sting from retainer & place 15 bbls on top of retainer. POOH f/3480' t/3236', pump 8bbls to clear tubing, cont POOH t/3112', pump wiper ball to clean pipe while r/d cmt unit & r/u pipe skate. POOH l/d 3-1/2" wk string. 3112' t/620', secure well. Night watch rig, prep for rig down. 03/27/2023 - Monday PTSM, check well, POOH l/d wk string f/ 610', break off cmt retainer. Clear floor, break down subs from power swivel, pack up same, R/D pump & pits. m/u landing joint, land hanger w/TWC. Rig down floor, N/D BOPE, N/U tree, load out R4R tank, load up accessory eq. mobe pump, Swaco mix tank & power swivels RTD test tree t/1500 good. Scope down mast, test lift cylinder & layover mast. SDFN. 04/23/2023 - Sunday From:Davies, Stephen F (OGC) To:Brooks, James S (OGC) Subject:RE: 181-092 state plane coordinate issue Date:Wednesday, May 31, 2023 11:03:53 AM Hi James, Yes, the difference between the operator-reported coordinates and those calculated by RBDMS is 119’ which is acceptable for a Cook Inlet Basin well. Thanks for asking, Steve From: Brooks, James S (OGC) Sent: Wednesday, May 31, 2023 10:59 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: 181-092 state plane coordinate issue Hi, Can you verify that this is OK ? thanx -$0(6%522.6 5(6($5&+$1$/<67,,E$/$6.$2,/$1'*$6&216(59$7,21&200,66,21 '(3$570(172)&200(5&(&20081,7<$1'(&2120,&'(9(/230(17 E-$0(6%522.6#$/$6.$*29 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Thursday, April 20, 2023 9:06 AM To:Harold Soule - (C) Cc:Regg, James B (OGC) Subject:RE: HAK 401 3-22-23 Attachments:Hilcorp 401 03-22-23.xlsx I made a minor revision, changing the #3 Rams control system response time test result to “NA”. Please update your copy. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Harold Soule ‐ (C) <hsoule@hilcorp.com> Sent: Wednesday, March 22, 2023 6:20 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: HAK 401 3‐22‐23 Thanks Harold Soule Cell 907‐227‐9400 401 Office 907‐283‐2580 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Kenai Unit 14X-06PTD 1810920 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:401 DATE:3/22/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #1810920 Sundry #323-077 Operation:Drilling:Workover:x Explor.: Test:Initial:Weekly:x Bi-Weekly:Other: Rams:250-2500 Annular:250-2500 Valves:250-2500 MASP:998 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.NA Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 13 5/8" 5M P Pit Level Indicators P P #1 Rams 1 2 7/8x5 1/2" VAR P Flow Indicator NA NA #2 Rams 1 Blind Ram P Meth Gas Detector NT NT #3 Rams 0 NA H2S Gas Detector NT NT #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 4 1/16" 5M FP Time/Pressure Test Result HCR Valves 1 4 1/16" 5M P System Pressure (psi)3000 P Kill Line Valves 3 4 1/16"&2 1/16"5M P Pressure After Closure (psi)1850 P Check Valve 0 NA 200 psi Attained (sec)22 P BOP Misc 0 NA Full Pressure Attained (sec)103 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 x 2025 P No. Valves 8 P ACC Misc 0 NA Manual Chokes 2 P Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 25 P #1 Rams 7 P Coiled Tubing Only:#2 Rams 7 P Inside Reel valves 0 NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:3.5 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 3-20-23 9:25 Waived By Test Start Date/Time:3/22/2023 7:00 (date)(time)Witness Test Finish Date/Time:3/22/2023 10:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested 3 1/2" TJ, had failure on inside choke line valve, service valve, re-test good, Gas system tested on 3-15-23 Kevin Reed Hilcorp Alaska LLC Harold Soule KU 14X-06 Test Pressure (psi): hsoule@hilcorp.com hsoule@hilcorp.com Form 10-424 (Revised 08/2022)2023-0322_BOP_Hilcorp401_KU_14X-06          jbr J. Regg Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 03/28/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230328 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 2/18/2023 YELLOW JACKET PLUG BCU 18RD 50133205840100 222033 3/9/2023 YELLOW JACKET PERF CLU 10RD 50133205530100 222113 3/2/2023 YELLOW JACKET PERF-GPT-PLUG KBU 11-07 50133205560000 205165 3/3/2023 YELLOW JACKET PERF KBU 11-07 50133205560000 205165 3/1/2023 YELLOW JACKET PLUG KU 14X-6 50133203420000 181092 3/3/2023 YELLOW JACKET CALIPER-SCBL NCI B-02 50883200900100 197210 3/9/2023 AK E-LINE GPT Perf SRU 224-10 50133101380100 222124 2/15/2023 YELLOW JACKET PLUG TBU D-09RD 50733201310100 181080 2/27/2023 AK E-LINE Plug Punch Please include current contact information if different from above. KU 14X-6 50133203420000 181092 3/3/2023 YELLOW JACKET CALIPER-SCBL CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Harold Soule - (C); Donna Ambruz Subject:RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Lower plug Date:Friday, March 24, 2023 8:49:00 AM Chad, Recognizing that there is only 19’ between the cement retainer and the lowest open Pool 3 perf, your plan below to place 25’ of cement on top of the retainer (with the top 6’ of cement across open perfs) is approved and a variance to 20 AAC 25.112(c)(1)(E) is granted to allow for this. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, March 24, 2023 8:31 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Harold Soule - (C) <hsoule@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Lower plug No there is only 19ft from the retainer to the bottom of open perfs. There is only 10ft to the bottom of the squeezed perfs that are in Pool 3. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, March 24, 2023 8:22 AM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Harold Soule - (C) <hsoule@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Lower plug Chad, Agree that you have a better chance of getting a good cement job with the dump bailer. And you don’t need a variance as long as you can put 25’ of cement on top of the plug. Is there enough room to place 25’ of cement on top of the cement retainer before reaching the lowest open Pool 3 perfs? CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, March 24, 2023 7:24 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Harold Soule - (C) <hsoule@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Lower plug Bryan, After we talked about the squeeze of the lower zone on KU 14X-06, we tried pumping into the zone again and we were not able to pump into Pool 4. We pressured to 2000 psi and it bled to 1400 psi in 15 min. We made the decision last night that we would get a better cement job by dump bailing cement than trying to place 2 bbls of cement on top of the retainer with pipe. We are tripping out now to RU Eline. Our plan is to place 25ft of cement on top of the cement retainer that we set at 3758’ with a dump bailer, and then run cement retainers as we planned. This follows the original plan we had in the Sundry. I guess this means we do not need a variance to regulations for setting the plug between Pools because we are within 50ft. Please let me know if you need any additional info on this change from our discussion last night. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Thursday, March 23, 2023 3:02 PM To:edhooter295@gmail.com Cc:Regg, James B (OGC) Subject:RE: HAK 401 2-28-23 test rpt Attachments:Hilcorp 401 03-01-23 Revised.xlsx Ed, Attached is a revised report correcting the formatting and changing the report date to reflect 3/1/23 based on the end date and changing the start date from 3/28/23 to 2/28/23. Please update your copy. Thanks, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 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 Phoebe Brooks at 907‐793‐ 1242 or phoebe.brooks@alaska.gov. ‐‐‐‐‐Original Message‐‐‐‐‐ From: edhooter295@gmail.com <edhooter295@gmail.com> Sent: Sunday, March 5, 2023 3:59 PM To: DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: HAK 401 2‐28‐23 test rpt CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Your message is ready to be sent with the following file or link attachments: HAK 401 2‐28‐23 Note: To protect against computer viruses, e‐mail programs may prevent sending or receiving certain types of file attachments. Check your e‐mail security settings to determine how attachments are handled. Kenai Unit 14X-06PTD 1810920 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:401 DATE:3/1/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #1810920 Sundry #323-077 Operation:Drilling:Workover:X Explor.: Test:Initial:Weekly:X Bi-Weekly:Other: Rams:250-2500 Annular:250-2500 Valves:250-2500 MASP:998 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.NA Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 13-5/85m FP Pit Level Indicators P P #1 Rams 1 2-3/8 ram P Flow Indicator NA NA #2 Rams 1 2-7/8x5-1/2 VAR P Meth Gas Detector P P #3 Rams 1 Blind ram P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 4-1/16 5M P Time/Pressure Test Result HCR Valves 1 4-1/16 5M P System Pressure (psi)3000 P Kill Line Valves 3 1/16 5M & 2-1/16 5 P Pressure After Closure (psi)1700 P Check Valve 0 NA 200 psi Attained (sec)24 P BOP Misc 0 NA Full Pressure Attained (sec)134 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 x 2075 P No. Valves 8 P ACC Misc 0 NA Manual Chokes 2 P Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 28 P #1 Rams 8 P Coiled Tubing Only:#2 Rams 8 P Inside Reel valves 0 NA #3 Rams 8 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:24.5 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 2/27/23 07:23 Waived By Test Start Date/Time:2/28/2023 12:30 (date)(time)Witness Test Finish Date/Time:3/1/2023 13:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested with 2-3/8 and 3-1/2 test joints 13-5/8 annular failed test on 2-3/8 test joint on low test, change out 13-5/8 annular, test time reflects, mobing and changing annular with replacement annular, and working 12 hr daylight schedule. Quadco tested Gas alarms,Rig crew tested PVT.s Chris Hannevold Hilcorp Howard Hooter KU 14X-06 Test Pressure (psi): howard.hooter@hilcorp.com Form 10-424 (Revised 08/2022)2023-0301_BOP_Hilcorp401_KU_14X-06 Alaska LLC jbr        jbr J. Regg; 6/13/2023 From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz; Noel Nocas; Harold Soule - (C) Subject:RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Date:Wednesday, March 22, 2023 4:10:00 PM Attachments:KU 14X-06 Cement Retainer procedure 3-22-23.docx Chad, Hilcorp has verbal approval to start the proposed work according to the attached procedure, with the following change. You are currently proposing an injectivity test in step 17 of the attached procedure, to be done after setting the cement retainer. The injectivity test must be done after step 13, to determine if there was any reason to set a cement retainer. If unable to inject, then skip the cement retainer and lay in balanced plug. Or set a CIBP no more than 50’ above the perfs and dump bail cement. The issue is, for the downsqueeze method, the retainer must be set >50’ above the perfs. For the dump bail method, the retainer or CIBP must be <50’ above the perfs. Submit an application for sundry approval within 3 days. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Wednesday, March 22, 2023 1:39 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com> Subject: RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Bryan, See below for some depth changes and response to your question. Here is some more info for you that might be beneficial. Top of each pool per correlation from pool rules with base well KU 21-06. Top Pool 3: 3550’ MD Top Pool 4: 3767’ MD CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Top Pool 6: 4463’ MD Our correlated top of 7” cut is 3,762’ based on gamma ray (relative to perf depths) We have plugged up the current perfs with debris that we can circulate across the top of the hole, losing about 300bbls/day. Attached is the procedure for the rig with the changes we have discussed and revised depths for the cement squeeze. Feel free to call and we can review any additional questions. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, March 22, 2023 8:53 AM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Chad, I’ve added a few comments/questions in red for discussion. The objective here is to have a verified isolation plug between Pools 3 & 4 and above pool 3. Just to confirm, is there a 7” CIBP set at 3762’ as shown in the diagram? (Yes we set the 7” CIBP with a hole 2ft below it, so when we were milling the packer we could get returns and circulation.) We should discuss these comments to make sure we are both on the same page. Give me a call when you’ve had time to think about it. I’m pretty booked up with meetings today, so if I don’t answer, I’ll call back at my first opportunity. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, March 21, 2023 4:58 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Bryan, We have removed the 7” casing down to 3755’. We are conducting BOP test tomorrow and then casing scraper run in the afternoon. We are requesting approval to change the procedure (steps 48 to 50 with the following steps.) Essentially changing from CIBP to cement retainers to ensure any behind pipe channels are plugged as well. This requires a variance from 20AAC25.112(c)(1)(D). The retainer will be less than 50ft above the perfs. The volumes proposed meet the requirements needed. 1. RIH and set retainer at ~3745’ 3,758’ (5’ just above casing stub – We correlated depths with casing cuts to gamma ray and the top of fish is at 3762’), pumping ~10bbls of cement below retainer (hopefully packs off) we will leave minimal amount on top of retainer. (close to perfs above that we want to squeeze cement into.) Planning to set packer 1’ above squeezed perf interval. (Adjusted down perf correlation) How do you ensure depth control? (we correlated based on caliper and PL logs we ran to the collar to cut measurement we had for the cut) Why not set it below the deepest Pool 3 squeezed perf at 3748’ MD? (We will) a. This plug will isolate the Sterling Pool 3 and Pool 4 zones. Verify plug integrity with 15klbs weight. Can be done before pumping cement. (We will set entire string 40K on retainer to ensure it is set as part of the procedure. Making notification today for a tag tomorrow.) 2. RIH and set retainer at ~3700’ and pumping 5bbls, placing 1-2 bbls on top of retainer 3. RIH and set retainer at ~3600’ and pumping 15bbls and place 1 bbl on top of retainer. a. Perform injectivity test to confirm cement can be squeezed into the last remaining open perfs. If not, then the next step should be a plug placed by displacement method per 20 AAC 25.112 (c)(1)(C). (This set of perfs we are isolating is still within Pool 3 we will do this before the last cement job is completed) 4. RIH and set Retainer at ~3540’ Set retainer >50’ above perfs, minimum 3498’ MD, per 20 AAC 25.112 (c)(1)(D). (No problem with this change) and pumping 25bbls hoping it squeezes off and placing the remaining cement on top of the retainer. If it takes all 25 bbls we will probably pump another 10-15 bbls on top of the retainer Steps 51-56 will remain the same. Shouldn’t need to dump bail any cement (step 55 of sundry) if step 4 above goes according to plan. (Agreed we will have plenty of cement on top of plug) The only plug we will be able to pressure test is the final plug, which we will notify for witness. Do we need to notify for the 1st plug we plan to set and squeeze. Notify for opportunity to witness weight test of the cement retainer. (We will notify for setting retainer weight. The process for setting retainer is the same and requires 40K set down on it.) Attached is the schematic of the proposed completion with plugs. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Please give me a call if you want to discuss anything about these plans, or shoot me an email if we are okay to proceed with retainers instead of the CIBP’s. Regards Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, March 6, 2023 10:49 AM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Chad, Integrity of the Pool 6 reservoir abandonment plug was established by tagging the cement plug with 18,000 lbs of string weight. Hilcorp has approval to complete the operational steps from Step 44 – 57 in sundry 323-077. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Monday, March 6, 2023 8:11 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Bryan, Thanks for this approval Friday night. Below is an update of events this weekend. 1. RIH and tag sand/TOF from 4337’ to 4376’ 2. Dump 10ft of sand/gravel fill on top of 2-3/8” coil fish 3. Tag at 4366’ 4. RU Cementers PT lines to 3000 psi 5. Pump 14.5 bbls of cement to isolate Pool 6 6. POOH 7. Separate annular, remove single gate, retest break 250L/2500H CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 8. RIH w/ test packer tagging cmt plug with 18k lbs. at 4092 ft 9. Jim Regg with AOGCC waived witness for tagging and testing plug. 10. TOOH laying down excess work string to 3800 ft 11. Set packer at 3800 ft and attempted to test the cement plug above the Pool 6 sand f/ 4366’ to 4092’, unsuccessful. 12. retested at 3831 ft and same result, bled from 1300 psi to 600psi in 30 min 13. PU to 3524 set packer test the 7” liner top and 9-5/8 csg to 1500 psi for 30 minutes ( good test ) 14. RIH to 3800 ft set packer at 3800 ft 15. Rig up Eline run production log from 4090 ft to 3795 ft. a. No spinner movement below test packer b. Had spinner movement at test packer c. Temp log indicated leak at 16. Rigged Down Eline 17. Unseat packer, secured well for night, blow down lines. Currently tripping out with packer and planning to PU Spear to start fishing 7” scab liner. However we need your approval to move forward with the plan. Attached is the spinner log, that shows when the test was completed yesterday on the cement plug that the fluid was not going down into pool 6, however leaking at the 7” seal assembly on the scab liner. Please let me know if you have any questions or need more information to determine if we can progress with fishing the scab liner, to isolate Pool 3 & Pool 4. Chad Helgeson From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, March 3, 2023 9:38 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Chad, Hilcorp has approval for a variance to place the cement plug on top of the parted coil at 4357’ MD, which is greater than 50’ above the Pool 6 top perf as described below, with 11 bbls of cement (150’ plug) between the Pool 6 and open Pool 4 perfs, with the following conditions: 1. Test flange break in BOP after removing the 2-3/8” pipe ram, before running back in hole. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2. Provide notice for AOGCC opportunity to witness test and tag of cement plug set above Pool 3 (step 54 & 55 in the sundry). Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, March 3, 2023 9:43 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Bryan, We have tried recovering all the 2-3/8” coil from the KU 14X-06 well (Sundry # 323-077), however have been unsuccessful getting the coil deeper than 4,367’. Hilcorp is requesting a variance from 20AAC25.112(c)(1) to set the plug at 4,357’ (which is 105’ above the top perf in Pool 6 storage sand). This will also eliminate the plug proposed to set in step 19 of the approved sundry, that isolates between the Pool6 C1 and C2 sands. Both of these sands are in the same Pool and therefore this plug is not regulatory required. On Wednesday we ran a production log to determine cross flow rates from Pool ¾ to Pool 6 and found there is not any current cross flow from Pool3/4 to Pool 6. Attached is a field print of the logging that was performed to confirm the flowrate. While pumping into the well looking for where fluid was going, it appears that there is a hole in the 7” scab liner at 3,750-3,754’, that was taking all the fluid that was being pumped in at 2 bpm. I would also like to propose changing step 22 in the program from pumping 45 bbls of cement to 11 bbls of cement, because the zone/well does not appear to be cross flowing and do not expect Pool 6 to drink the cement. We will place 10ft of gravel/sand on top of plug to prevent cement from falling down 2-3/8” coil. 11bbls of cement = 150ft of cement placed by displacement in 9-5/8”, meeting volume and depth of cement per 20AAC25.112(c)(1)(C), however will only be above the perforated interval. Then complete the following steps pending AOGCC approval. 1. Run caliper log from TD to approximately surface 2. RIH and tag top of fish with mule shoe and 3-1/2” workstring 3. Place 10ft of sand/pea gravel on top of fish & tag 4. Pump 11 bbls of cement on plug at ~ 4357. 5. Remove 2-3/8” single gate ram, while waiting on cement 6. RIH and tag cement 15K (notify AOGCC for witness) 7. Set 7” test packer below hole in 7” scab liner and test (step 28 & 29) 8. Then skip to Step 44, where we will fish the 7” scab liner from the well and set individual mechanical plugs between Pool 3 and 4. I will give you a call to discuss and walk you through the plan and answer any questions you may have as well. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. KU 14X-06 Pool 3 & 4 isolation/cementing plan (3/22/23) 7” Casing stub is at 3,762’ (relative to perfs) Record and perform injection tests prior to pumping any cement (ensure communication), record info and rate. 1. Complete casing scraper run 2. PU 9-5/8” retainer 3. RIH and set retainer at 3,758’ (4’ above casing stub) – Retainer requires 40K of down weight 4. RU cement crews, pressure test lines 5. Pump 10bbls of 15.8 quick set cement below retainer (hopefully packs off) we will leave minimal amount on top of retainer (reverse excess cement if necessary from 3740’ (22’ pipe measurement from tag). a. Notify AOGCC today (3/22) with 24hr notice for setting weight on retainer. 6. POOH 7. PU 9-5/8” Retainer 8. RIH and set retainer at ~3700’ 9. Pump 5bbls of 15.8 quick set cement, placing 1-2 bbls on top of retainer 10. POOH 11. PU 9-5/8” retainer 12. RIH and set retainer at ~3600’ 13. Pump 15bbls of 15.8ppg quick set cement and place 1 bbl on top of retainer 14. POOH LD tools 15. PU 9-5/8” retainer 16. RIH and set Retainer at ~3,480’, minimum 3498’ MD (50ft above top perf) a. Notify AOGCC with 24hr notice for setting retainer with weight on it. 17. Perform injectivity test to ensure cement will squeeze into perfs 18. Pump 25bbls of cement. If it squeezes off early, place remaining cement on top of retainer. If it takes all 25 bbls, pump another 15 bbls (205’) on top of the retainer. 19. POOH 20. Install tubing hanger 21. Install dry hole tree 22. Pressure test to 1500 psi 23. RDMO 24. After rig moves off, slickline to RIH and tag top of cement. Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 03/17/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230317 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU L-57 50029236090000 218072 3/7/2023 READ CaliperSurvey SRU 23-33 50133101630000 161019 2/16/2023 AK E-LINE Jet Cut CLU-9 50133205440000 204161 2/24/2023 HALLIBURTON PPROF CLU-15 50133206870000 220003 2/26/2023 HALLIBURTON PPROF END 1-11 50029221070000 190157 2/19/2023 HALLIBURTON MFC END 1-11 50029221070000 190157 2/25/2023 HALLIBURTON PLUG-PERF KU 14X-06 50133203420000 181092 3/1/2023 HALLIBURTON LDL Please include current contact information if different from above. KU 14X-06 50133203420000 181092 3/1/2023 HALLIBURTON LDL 1 Regg, James B (OGC) From:edhooter295@gmail.com Sent:Thursday, March 16, 2023 6:47 AM To:DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Regg, James B (OGC) Subject:Emailing: HAK 401 3-15-23 Attachments:HAK 401 3-15-23.xlsx CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Please see test report dated 3‐15/23 Thank you ED Hooter WSM HAK 401 Cell 318‐452‐8947 Your message is ready to be sent with the following file or link attachments: HAK 401 3‐15‐23 Note: To protect against computer viruses, e‐mail programs may prevent sending or receiving certain types of file attachments. Check your e‐mail security settings to determine how attachments are handled. Kenai Unit 14X-06PTD 1810920 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:401 DATE:3/15/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #1810920 Sundry #323-077 Operation:Drilling:Workover:x Explor.: Test:Initial:Weekly:x Bi-Weekly:Other: Rams:250-2500 Annular:250-2500 Valves:250-2500 MASP:998 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.NA Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 13-5/8 5m P Pit Level Indicators P P #1 Rams 1 2-7/8 x 5-1/2 vbr P Flow Indicator NA NA #2 Rams 1 Blind Ram P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 4-1/16 5m P Time/Pressure Test Result HCR Valves 1 4-1/16 5m P System Pressure (psi)3000 P Kill Line Valves 3 4-1/16 2-1/16 5m P Pressure After Closure (psi)1825 P Check Valve 0 NA 200 psi Attained (sec)23 P BOP Misc 0 NA Full Pressure Attained (sec)111 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 x 1925 P No. Valves 8 P ACC Misc 0 NA Manual Chokes 2 P Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 24 P #1 Rams 7 P Coiled Tubing Only:#2 Rams 7 P Inside Reel valves 0 NA #3 Rams NA #4 Rams NA Test Results #5 Rams NA #6 Rams NA Number of Failures:0 Test Time:4.5 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 3/14/23 9:08 Waived By Test Start Date/Time:3/15/2023 8:30 (date)(time)Witness Test Finish Date/Time:3/15/2023 13:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested 13-5/8 5m BOPE with 3.5 test joint, Quadco test GAS alarm, PVT test by rig crew Chris Hannevold Hilcorp Alaska LLC Howard Hooter KU 14X-06 Test Pressure (psi): 401@allamericanoilfield.com howard.hooter@hilcorp.com Form 10-424 (Revised 08/2022)2023-0315_BOP_Hilcorp401_KU_14X-06        jbr STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI UNIT 14X-06 JBR 04/20/2023 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:8 Test began on 3/7/23 @ 15:00. Housekeeping was lacking but resolved by the time I left. Tested with 3 1/2" test joint, lots of failures and leaking test equipment. Failures on cmv 10, 11 and 12, test chart leaking, failures on k-1,k-2, upper rams, and test plug leaked twice. Tested around failures except for MCV's. Rig only working day shift, stop test @ 22:30 after 2nd plug failure and waiting on upper rams from Anna platform. Required full test on 3/8 (from 12:30 until 16:00); 7 failures on 3/7 and 1 failure on 3/8. Test Results TEST DATA Rig Rep:Chris HannevoidOperator:Hilcorp Alaska, LLC Operator Rep:Ed Hooter Rig Owner/Rig No.:Hilcorp 401 PTD#:1810920 DATE:3/8/2023 Type Operation:WRKOV Annular: 250/2500Type Test:WKLY Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopSTS230317135521 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 11 MASP: 998 Sundry No: 323-077 Control System Response Time (sec) Time P/F Housekeeping:FP PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 0 NA Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 8 FPNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8 P #1 Rams 1 2 7/8 x 5 1/2 v FP #2 Rams 1 blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 4 1/16 P HCR Valves 1 4 1/16 P Kill Line Valves 3 4 1/16, 2 1/16 FP Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1850 200 PSI Attained P23 Full Pressure Attained P108 Blind Switch Covers:Pall stations Bottle precharge P Nitgn Btls# &psi (avg)P6@2100 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators NA NAFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P29 #1 Rams P7 #2 Rams P7 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill NA0 9 9 9 9 9 9999 9 9 9 9 9 7 failures on 3/7 and 1 failure on 3/8. Required full test on 3/8 Housekeeping was lacking Failures on cmv 10, 11 and 12,test chart leaking,failures on k-1,k-2, upper rams, FP FP FP FP From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz; Noel Nocas Subject:RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Date:Monday, March 6, 2023 10:48:00 AM Chad, Integrity of the Pool 6 reservoir abandonment plug was established by tagging the cement plug with 18,000 lbs of string weight. Hilcorp has approval to complete the operational steps from Step 44 – 57 in sundry 323-077. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Monday, March 6, 2023 8:11 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: RE: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Bryan, Thanks for this approval Friday night. Below is an update of events this weekend. 1. RIH and tag sand/TOF from 4337’ to 4376’ 2. Dump 10ft of sand/gravel fill on top of 2-3/8” coil fish 3. Tag at 4366’ 4. RU Cementers PT lines to 3000 psi 5. Pump 14.5 bbls of cement to isolate Pool 6 6. POOH 7. Separate annular, remove single gate, retest break 250L/2500H 8. RIH w/ test packer tagging cmt plug with 18k lbs. at 4092 ft 9. Jim Regg with AOGCC waived witness for tagging and testing plug. 10. TOOH laying down excess work string to 3800 ft 11. Set packer at 3800 ft and attempted to test the cement plug above the Pool 6 sand f/ 4366’ to 4092’, unsuccessful. 12. retested at 3831 ft and same result, bled from 1300 psi to 600psi in 30 min 13. PU to 3524 set packer test the 7” liner top and 9-5/8 csg to 1500 psi for 30 minutes ( good test ) 14. RIH to 3800 ft set packer at 3800 ft 15. Rig up Eline run production log from 4090 ft to 3795 ft. a. No spinner movement below test packer CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. b. Had spinner movement at test packer c. Temp log indicated leak at 16. Rigged Down Eline 17. Unseat packer, secured well for night, blow down lines. Currently tripping out with packer and planning to PU Spear to start fishing 7” scab liner. However we need your approval to move forward with the plan. Attached is the spinner log, that shows when the test was completed yesterday on the cement plug that the fluid was not going down into pool 6, however leaking at the 7” seal assembly on the scab liner. Please let me know if you have any questions or need more information to determine if we can progress with fishing the scab liner, to isolate Pool 3 & Pool 4. Chad Helgeson From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, March 3, 2023 9:38 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: [EXTERNAL] RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Chad, Hilcorp has approval for a variance to place the cement plug on top of the parted coil at 4357’ MD, which is greater than 50’ above the Pool 6 top perf as described below, with 11 bbls of cement (150’ plug) between the Pool 6 and open Pool 4 perfs, with the following conditions: 1. Test flange break in BOP after removing the 2-3/8” pipe ram, before running back in hole. 2. Provide notice for AOGCC opportunity to witness test and tag of cement plug set above Pool 3 (step 54 & 55 in the sundry). Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, March 3, 2023 9:43 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Bryan, We have tried recovering all the 2-3/8” coil from the KU 14X-06 well (Sundry # 323-077), however have been unsuccessful getting the coil deeper than 4,367’. Hilcorp is requesting a variance from 20AAC25.112(c)(1) to set the plug at 4,357’ (which is 105’ above the top perf in Pool 6 storage sand). This will also eliminate the plug proposed to set in step 19 of the approved sundry, that isolates between the Pool6 C1 and C2 sands. Both of these sands are in the same Pool and therefore this plug is not regulatory required. On Wednesday we ran a production log to determine cross flow rates from Pool ¾ to Pool 6 and found there is not any current cross flow from Pool3/4 to Pool 6. Attached is a field print of the logging that was performed to confirm the flowrate. While pumping into the well looking for where fluid was going, it appears that there is a hole in the 7” scab liner at 3,750-3,754’, that was taking all the fluid that was being pumped in at 2 bpm. I would also like to propose changing step 22 in the program from pumping 45 bbls of cement to 11 bbls of cement, because the zone/well does not appear to be cross flowing and do not expect Pool 6 to drink the cement. We will place 10ft of gravel/sand on top of plug to prevent cement from falling down 2-3/8” coil. 11bbls of cement = 150ft of cement placed by displacement in 9-5/8”, meeting volume and depth of cement per 20AAC25.112(c)(1)(C), however will only be above the perforated interval. Then complete the following steps pending AOGCC approval. 1. Run caliper log from TD to approximately surface 2. RIH and tag top of fish with mule shoe and 3-1/2” workstring 3. Place 10ft of sand/pea gravel on top of fish & tag 4. Pump 11 bbls of cement on plug at ~ 4357. 5. Remove 2-3/8” single gate ram, while waiting on cement 6. RIH and tag cement 15K (notify AOGCC for witness) 7. Set 7” test packer below hole in 7” scab liner and test (step 28 & 29) 8. Then skip to Step 44, where we will fish the 7” scab liner from the well and set individual mechanical plugs between Pool 3 and 4. I will give you a call to discuss and walk you through the plan and answer any questions you may have as well. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Lease: State:Country:USA (TVD) 6deg @ 5950' Perforations (MD): 3/6/2023 Completion Fluid:6% KCL Angle/Perfs:0deg Well Name & Number: Dated Completed:7/1/2003 Kenai Unit 14x-6 Kenai Gas Field County or Parish:Kenai Peninsula Borough Last Revison Date:Revised By:Chad Helgeson Alaska Angle @ KOP and Depth: Active Perfs (Sterling Pool 6): C1: 4,462' - 4,533' DIL C2: 4,619' - 4,670' DIL (12 spf, 8/14/03) BST Coil String fish: Outer string: 2-3/8" OD, 0.125" wall, 3.007 ppf, HO- 70 coil tubing w/ plug/profile combination BST nipple @ 4,860', Nipple ID = 1.188" w/ 1.00" nogo. Standing Valve @ 4,860' 9-5/8", 47 ppf, N-80, BTC casing @ ,7282' Cmt with 1,450 sks of class G Note: Apparent casing damage at 3,550'-3,560' (6/25/2003),Tested casing to 1500 psi on 3/6/23 from 3,449' to surface PBTD 9,296' MD 8,982' TVD Conductor: 20" @ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2,566' Cmt with 1675 sks of class G 7", 29 ppf, N-80, BTC liner 6,925' - 10,225' Cmt with 1,600 sks of class G 7" Scab Liner 3,449' - 3,893' - Baker ZXP packer @ 3,449' - 7", 23 ppf, L-80, BTC casing - Baker ZXP packer on HMC liner hanger @ 3,865' - Muleshoe @ 3,893' Min ID = 6.184" at muleshoe Isolated Perfs (behind scab liner): Pool 3: 3,548' - 3,550' (sqz'd) 3,553' - 3,575' 3,624' - 3,649' 3,652' - 3,677' 3,724' - 3,739' 3,746' - 3,748' (sqz'd) Pool 4: 3,772' - 3,792' 3,800' - 3,802' (sqz'd) Squeezed Perfs (isolated in 7" liner): 9,398' - 9,400' 9,411' - 9,445' 9,458' - 9,460' 9,751' - 9,781' 9,833' - 9,843' 9,953' - 9,958' Fish: Remnants of "D" packer @ 6,838' (6/22/2003) 7" cement retainers @ 9,296'; 9,707'; and 9,925' KU 14x-6 Pad 14-6 422' FSL, 1,147' FWL, Sec. 6, T4N, R11W, S.M. Permit #:181-092 API #:50-133-20342-00-00 Prop. Des:A-028142 KB Elevation:87' AGL Latitude: Longitude: Spud:9/22/1981 TD:10/27/1981 Rig Released:12/9/1981 PA #: TD 10,225' MD 9,863' TVD parted 2-3/8"coil @ 4376' 14.5bbl cement plug tagged @ 4,092' on 3/6/23 Sand & gravel on coil fish @ 4366' Hole in 7" casing @ 3,754' WLM Lease: State:Country:USA (TVD) County or Parish:Kenai Peninsula Borough Last Revison Date:Revised By:Chad Helgeson Alaska Angle @ KOP and Depth:6deg @ 5950' Perforations (MD): 3/6/2023 Completion Fluid:6% KCL Angle/Perfs:0deg Well Name & Number: Dated Completed:7/1/2003 Kenai Unit 14x-6 Kenai Gas Field Plugged Perfs (Sterling Pool 6): C1: 4,462' - 4,533' DIL C2: 4,619' - 4,670' DIL (12 spf, 8/14/03) BST Coil String fish: Outer string: 2-3/8" OD, 0.125" wall, 3.007 ppf, HO- 70 coil tubing w/ plug/profile combination BST nipple @ 4,860', Nipple ID = 1.188" w/ 1.00" nogo. Standing Valve @ 4,860' 9-5/8", 47 ppf, N-80, BTC casing @ ,7282' Cmt with 1,450 sks of class G Note: Apparent casing damage at 3,550'-3,560' (6/25/2003), Tested casing to 1500 psi on 3/6/23 from 3,449' to surface PBTD 9,296' MD 8,982' TVD Conductor: 20" @ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2,566' Cmt with 1675 sks of class G 7", 29 ppf, N-80, BTC liner 6,925' - 10,225' Cmt with 1,600 sks of class G 7" Scab Liner 3,750' - 3,893' - 7", 23 ppf, L-80, BTC casing - Baker ZXP packer on HMC liner hanger @ 3,865' - Muleshoe @ 3,893' Min ID = 6.184" at muleshoe Isolated Perfs (behind scab liner): Pool 3: 3,548' - 3,550' (sqz'd) 3,553' - 3,575' 3,624' - 3,649' 3,652' - 3,677' 3,724' - 3,739' 3,746' - 3,748' (sqz'd) Pool 4: 3,772' - 3,792' 3,800' - 3,802' (sqz'd) Squeezed Perfs (isolated in 7" liner): 9,398' - 9,400' 9,411' - 9,445' 9,458' - 9,460' 9,751' - 9,781' 9,833' - 9,843' 9,953' - 9,958' Fish: Remnants of "D" packer @ 6,838' (6/22/2003) 7" cement retainers @ 9,296'; 9,707'; and 9,925' KU 14x-6 Pad 14-6 422' FSL, 1,147' FWL, Sec. 6, T4N, R11W, S.M. Permit #:181-092 API #:50-133-20342-00-00 Prop. Des:A-028142 KB Elevation:87' AGL Latitude: Longitude: Spud:9/22/1981 TD:10/27/1981 Rig Released:12/9/1981 PA #: TD 10,225' MD 9,863' TVD parted 2-3/8"coil @ 4376' 14.5bbl cement plug tagged @ 4,092' on 3/6/23 Sand & gravel on coil fish @ 4366' Pool 3/Pool 4 Isolation plug @ 3765' Plugs set as necessary to isolate wet sand from depleted sands Top of Pool 4 is 3,758' PROPOSED CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz; Noel Nocas Subject:RE: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Date:Friday, March 3, 2023 9:37:00 PM Chad, Hilcorp has approval for a variance to place the cement plug on top of the parted coil at 4357’ MD, which is greater than 50’ above the Pool 6 top perf as described below, with 11 bbls of cement (150’ plug) between the Pool 6 and open Pool 4 perfs, with the following conditions: 1. Test flange break in BOP after removing the 2-3/8” pipe ram, before running back in hole. 2. Provide notice for AOGCC opportunity to witness test and tag of cement plug set above Pool 3 (step 54 & 55 in the sundry). Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, March 3, 2023 9:43 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: KU 14X-06 (PTD# 181-092) Sundry # 323-077 Bryan, We have tried recovering all the 2-3/8” coil from the KU 14X-06 well (Sundry # 323-077), however have been unsuccessful getting the coil deeper than 4,367’. Hilcorp is requesting a variance from 20AAC25.112(c)(1) to set the plug at 4,357’ (which is 105’ above the top perf in Pool 6 storage sand). This will also eliminate the plug proposed to set in step 19 of the approved sundry, that isolates between the Pool6 C1 and C2 sands. Both of these sands are in the same Pool and therefore this plug is not regulatory required. On Wednesday we ran a production log to determine cross flow rates from Pool ¾ to Pool 6 and found there is not any current cross flow from Pool3/4 to Pool 6. Attached is a field print of the logging that was performed to confirm the flowrate. While pumping into the well looking for where fluid was going, it appears that there is a hole in the 7” scab liner at 3,750-3,754’, that was taking all the fluid that was being pumped in at 2 bpm. I would also like to propose changing step 22 in the program from pumping 45 bbls of cement to 11 bbls of cement, because the zone/well does not appear to be cross flowing and do not expect Pool 6 to drink the cement. We will place 10ft of gravel/sand on top of plug to prevent cement from falling down 2-3/8” coil. 11bbls of cement = 150ft of cement placed by displacement in 9-5/8”, meeting volume and depth of cement per 20AAC25.112(c)(1)(C), however will only be above the perforated interval. Then complete the following steps pending AOGCC approval. 1. Run caliper log from TD to approximately surface 2. RIH and tag top of fish with mule shoe and 3-1/2” workstring 3. Place 10ft of sand/pea gravel on top of fish & tag 4. Pump 11 bbls of cement on plug at ~ 4357. 5. Remove 2-3/8” single gate ram, while waiting on cement 6. RIH and tag cement 15K (notify AOGCC for witness) 7. Set 7” test packer below hole in 7” scab liner and test (step 28 & 29) 8. Then skip to Step 44, where we will fish the 7” scab liner from the well and set individual mechanical plugs between Pool 3 and 4. I will give you a call to discuss and walk you through the plan and answer any questions you may have as well. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:401 DATE:2/21/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #1810920 Sundry #323-077 Operation:Drilling:Workover:x Explor.: Test:Initial:X Weekly:Bi-Weekly:Other: Rams:250-2500 Annular:250-2500 Valves:250-2500 MASP:998 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.NA Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 13 5/8" 5M P Pit Level Indicators P P #1 Rams 1 2 3/8" Ram P Flow Indicator NA NA #2 Rams 1 2 7/8x5 1/2" VAR P Meth Gas Detector P P #3 Rams 0 Blind Ram P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 4 1/16" 5M P Time/Pressure Test Result HCR Valves 1 4 1/16" 5M P System Pressure (psi)2950 P Kill Line Valves 3 4 1/16"&2 1/16"5M P Pressure After Closure (psi)1950 P Check Valve 0 NA 200 psi Attained (sec)20 P BOP Misc 0 NA Full Pressure Attained (sec)100 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:1000 P Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 x 2150 P No. Valves 8 FP ACC Misc 0 NA Manual Chokes 2 P Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 22 P #1 Rams 7 P Coiled Tubing Only:#2 Rams 7 P Inside Reel valves 0 NA #3 Rams 7 P #4 Rams NA Test Results #5 Rams NA #6 Rams NA Number of Failures:1 Test Time:5.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 2-19-23 10:00 Waived By Test Start Date/Time:2/21/2023 9:00 (date)(time)Witness Test Finish Date/Time:2/21/2023 14:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested w/2 3/8" & 3 1/2" TJ's, had failure on CMV #6, stem leak, service valve, re-test good, Kevin Reed Hilcorp Harold Soule KU 14X-06 Test Pressure (psi): hsoule@hilcorp.com hsoule@hilcorp.com Form 10-424 (Revised 08/2022)2023-0221_BOP_Hilcorp401_KU_14X-06 Alaska LLC          jbr J. Regg; 6/12/2023 Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 02/21/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230221 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 1/29/2023 HALLIBURTON PPROF END 1-69 50029220200000 190029 2/4/2023 HALLIBURTON COILFLAG END 1-69 50029220200000 190029 2/11/2023 HALLIBURTON PERF KU 14X-06 50133203420000 181092 1/27/2023 HALLIBURTON TEMP SRU 224-10 50133101380100 222124 2/3/2023 HALLIBURTON PPROF TBU D-09RD 50733201310100 181080 2/8/2023 READ LeakPointSurvey Please include current contact information if different from above. KU 14X-06 50133203420000 181092 1/27/2023 HALLIBURTON TEMP 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Fish Coil String 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,225'6,838' (fish) Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 4,760psi Liner 3,830psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 6,870psi7,194'7,282' 6,340psi3,449'3,449' 85' 2,566' Perforation Depth MD (ft): 7,282' 7"444' 9-5/8" 20" 13-3/8" 85' 2,566'3,090psi 85' 2,566' Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 9,863'9,296'8,982'~998psi 9296, 9707, 9925 MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE FEDA028142 181-092 50-133-20342-00-00 Kenai Gas Field Sterling Gas Pool 6 Same SIO 7A.002 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 14X-06 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 3.004# / HO-70 4,860' February 17, 2023 N/A; N/A N/A; N/A See Schematic See Schematic 2-3/8" 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 Chad Helgeson, Operations Engineer chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 m n P s 66 t g Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Meredith Guhl at 8:13 am, Feb 08, 2023 323-077 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.02.07 14:56:31 -09'00' Noel Nocas (4361) 10-407 X -bjm Sterling Gas Pool 6 X , ADL0390821 SFD Do not proceed beyond step 27 in the procedure without written AOGCC approval, based on results of diagnostics. Install tubing head adapter, tubing hanger for BPV/TWC installation and dry hole tree before demobilizing from location. DSR-2/8/23 For steps 1-6 Bryan McLellan 2/17/23 BJM 2/17/23 SFD 2/8/2023 BOP test to 2500 psi. GCW 02/22/23 JLC 2/22/2023 2/23/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.23 09:52:48 -09'00' RBDMS JSB 022323 Well Prognosis – Change of Program Well: KU 14X-06 Date: 2/6/2023 Well Name: KU 14X-06 API Number: 50-133-20342-00-00 Current Status: Pool 6 Storage Well Permit to Drill Number: 181-092 Estimated Start Date: February 14, 2023 Rig: HAK 401 Regulatory Contact: Donna Ambruz 777-8305 First Call Engineer: Chad Helgeson (907) 777-8405 (O)(907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Current BHP: ~1,444 psi @ 4,462’ TVD (Based on current fluid level in well) Max. Expected BHP: ~1,444 psi @ 4,462’ TVD (Based on current fluid level in well) Max. Potential Surface Pressure: ~ 998 psi (Based on current fluid level less gas gradient to surface (0.10psi/ft) Well Status: KU 14X-06 is a Pool 6 Gas storage well that is currently shut-in. The 1.75” coil tubing velocity string was removed from the well. While pulling the 2-3/8” coil string, the coil parted at 830’. The well does not build any pressure and temp log completed prior to pulling the 1.75” coil string indicates there is cross flow of fluid from approx. 3650’ towards the Pool 6 reservoir. Summary: KU 14X-06 has been a very stable storage producer since 2004. December 10th 2022, the well unloaded a slug of water and stopped flowing 2 days later. The purpose of this work/sundry is to use the HAK Rig 401 workover rig to fish the 2-3/8” coil, isolate the Pool 6 reservoir and isolate Sterling Pool 3 and Pool 4 gas sands. Notes Regarding Wellbore Condition: x Jan 11, 2023, an MIT was completed on the 9-5/8” x 13-3/8” annulus to 1,000 psi x SL tagged top of coil at 830’. With LIB on 1/31/23 x Static fluid level on 9-5/8” annulus was ~1150ft with multiple echometer shots. BOP Usage during job: The rig will likely be operated with 1 shift per day. The nightly shutdown of the unit will be manned to maintain heat and equipment for efficient operations the following day. The BOP equipment will be used to shut the well in overnight, with blind rams or pipe in the pipe rams. The coil BOP components will also be used when circulating fluids, pressure testing plugs, pumping cement, etc. The BOP components will not be retested after use unless they are; x Purposely used to prevent the uncontrolled flow of fluids from the well, x Specifically mentioned in the procedure to test at certain steps to test x They appear to be damaged from the work completed or use of them (eg, stripping pipe through them or closing on tool strings) Procedure: 1. MIRU Rig 401 2.Pump 150bbls of 8.4 ppg water down well (volume is ~100bbls to static fluid level, but well will not sustain a full column of fluid.) a. Monitor well pressure for an hour after pumping 3. Continuously pump water in 2” side outlet valve at least 2 bpm while performing steps 4&5. a.The well has been shut in for more than 50days without building pressure, 0 psi when not pumping on well. Pool 6 Gas storage well that is currently shut-in. there is cross flow of fluid from approx. 3650’ towards the Pool 6 reservoir. Well Prognosis – Change of Program Well: KU 14X-06 Date: 2/6/2023 b. During coil work there was not any pressure or gas seen at surface for 4 continuous days of well work. c. The risk of setting an expandable plug in the well to ND the 7” valve poses additional risk to completing the successful workover of the Pool 6 storage well. d. The estimated length of time the well will be without mechanical barriers is estimated at 15-30 min to perform this task. e. No ignition sources will be within 50’ during steps 4&5. 4. ND 7” Master valve 5. Install 11” 3M tubing head test plug with 3” BPV 6. NU 13-5/8” BOPs and test (Notify AOGCC 24hrs in advance for witness) a. PT to 250psi low / 2500psi high / 2500psi annular b. Test to handle 2-3/8” coil in single ram c. Test to handle 3-1/2” workstring 7. Pull BPV 8. Pump 8.4 ppg water to ensure well is dead 9. PU fishing/overshot assembly for 2-3/8” coil with 3-1/2” work string 10. RIH and latch fish, PU 5K weight and set pipe in slips 11. MIRU Eline 12. RIH with logging tools to find stuck pipe (CBL, USIT, SCMT, etc) 13. Cut pipe @ approx. 4620’. 14. RD Eline 15. Pull coil tubing fish out of well, (use intrinsically safe cutting tools for coil on the rig floor) Do not pull more than 50K on fish (weight at which coil parted) 16. RU Eline 17. Run spinner and caliper logs to identify condition of pipe, attempt to find where the cross flow is occurring and entering the 9-5/8” wellbore 18. Ensure well is clear to 4,550’ (cleanout as needed/possible with rig workstring) 19. Plug and isolate C2 sand (4619-4670’) from C1 Sand at 4,462-4,533’, maybe set cement plug on sand or use an umbrella basket plug. This is for reservoir management purposes and not a pool abandonment. 20. RIH with 3-1/2” work string and open nozzle for cementing and tag up on plug set over C2 Sand (~4550’) 21. PU and MIRU cementers. PT Cement equipment 22. Pump ~45 bbls of 15.8ppg cement. (614ft of cement in 9-5/8” casing) Puts max top of cement ~3,919’ (Below 7” scab liner bottom) It is expected the Pool 6 will drink some of this cement. Work string volume approx. 37 bbls. 23. RD cementers and pull work string above TOC, into liner to 3650’ 24. Wait on cement 25. RIH and tag TOC with work string, set 15K weight on plug. (Notify AOGCC for witness of tagging and pressure testing plug) 26. RU Eline RIH with spinner tools and confirm Pool 6 is not taking any fluid. 27. Repeat cement operations 22-27 until there is no cross flow into Pool 6. Pending results of where the 7” scab liner is leaking – Review the leak info with AOGCC and provide notice of which option will be executed If caliper indicates hole in 7” scab liner above liner top packer the following steps will be performed: Hold point. Do not proceed without AOGCC approval. -bjm Well Prognosis – Change of Program Well: KU 14X-06 Date: 2/6/2023 28. RIH with 7” test packer and set at the bottom of the scab liner ~3800’ or below hole indicated in pipe. (this will test the pool 6 plug and the lower 7” packer at 3,865’.) Pressure test plug to 1000 psi. a. If the test does not pass, Lay in cement to the bottom of the liner top packer b. Ensure Pool 6 is isolated from cross flow 29. PU Test packer and set at the top of the scab liner ~ 3450’, Pressure test the top of the scab liner and the 9-5/8” casing to surface to 1500 psi 30. Establish injection rate into the scab liner, for squeeze purposes to confirm squeeze design 31. POOH 32. PU Cement retainer and RIH to set above hole in scab liner and below 3450’ 33. RU Cementers, PT Lines 34. Pump ~40 bbls of cement, squeezing into liner i. work string volume ~28 bbls ii. Scab liner volume ~ 16 bbls b. If zone continues to take cement, mix additional cement and pump again (attempt 2 more times.) c. If unable to squeeze zones, PU milling assembly for cement retainer, and mill up retainer. Then mill/fish the 7” scab liner as deep as possible. (steps 42-49) 35. If squeeze holds, unsting from retainer and lay excess cement on retainer 36. PU to 3400’ and circ out any excess cement 37. Wait on cement to set and tag TOC. (Notify AOGCC 24hrs prior to tag and pressure testing plug) 38. Pressure test well to 1500 psi 39. Set tubing hanger in well for future BPV installation 40. RDMO off well If caliper completed in step 17 does not indicate a hole in the scab liner the following steps will be performed 41.RU Eline 42. RIH with 7” casing cutter and cut 7” casing at ~3825’ 43. RD Eline 44. PU 7” milling assembly for milling Baker ZXP liner top packer 45. Mill packer and fish 7” casing string from well a. The BOPs will not have 7” rams for the 375’ of 7” fish b. Well will be monitored for static conditions for 10 min, prior to 7” casing reaching the rig floor, will attempt to have hole full c. A crossover to the workstring will be on the rig floor to be able to stab the on the 7” as standard for BHA’s 46. Once 7” casing is removed PU 9-5/8” casing scraper and RIH to top of fish. 47. POOH and LD casing scraper 48. PU 9-5/8” CIBP and set at 3765’. Place cement on top of CIBP per 20AAC25.112 (c). This plug will isolate between Pool3 and Pool4 zones. Tag with 15K of weight on plug. 49. Plug back additional perfs as necessary for reservoir management with cement or additional CIBP’s. 50. Set final 9-5/8” CIBP at 3525’ 51. Pressure test well 52. Set tubing hanger in well for future BPV installation 53. RDMO 54. RU Eline 55. RIH and dump 25ft of cement on CIBP, tag TOC 56. Pressure test well to 1500 psi. PU to 3370' to put 75' of cement on top of scab liner. -bjm Install tubing head adapter with tubing hanger for BPV/TWC installation and dry hole tree. -bjm Well Prognosis – Change of Program Well: KU 14X-06 Date: 2/6/2023 57. Place well on Temp Suspended Status. KU 14X-06 is a good candidate for a sidetrack in Kenai Gas Field. It is close to the top of structure and has 9-5/8” casing. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Current Wellhead Schematic 4. Nipple Down Wellhead schematic 5. BOP Schematic Lease: State: Country:USA (TVD) 6deg @ 5950' Perforations (MD): 2/2/2023 Completion Fluid:6% KCL Angle/Perfs:0deg Well Name & Number: Dated Completed:7/1/2003 Kenai Unit 14x-6 Kenai Gas Field County or Parish:Kenai Peninsula Borough Last Revison Date:Revised By:Chad Helgeson Alaska Angle @ KOP and Depth: Active Perfs (Sterling Pool 6): C1: 4,462' -4,533' DIL C2: 4,619' - 4,670' DIL (12 spf, 8/14/03) BST Coil String fish: Outer string: 2-3/8" OD, 0.125" wall, 3.007 ppf, HO- 70 coil tubing w/ plug/profile combination BST nipple @ 4,860', Nipple ID = 1.188" w/ 1.00" nogo. Standing Valve @ 4,860' 9-5/8", 47 ppf, N-80, BTC casing @ ,7282' Cmt with 1,450 sks of class G Note:Apparent casing damage at 3,550'-3,560' (6/25/2003) PBTD 9,296' MD 8,982' TVD Conductor: 20" @ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2,566' Cmt with 1675 sks of class G 7", 29 ppf, N-80, BTC liner 6,925' - 10,225' Cmt with 1,600 sks of class G 7" Scab Liner 3,449' - 3,893' - Baker ZXP packer @ 3,449' - 7", 23 ppf, L-80, BTC casing - Baker ZXP packer on HMC liner hanger @ 3,865' - Muleshoe @ 3,893' Min ID = 6.184" at muleshoe Isolated Perfs (behind scab liner): Pool 3: 3,548' - 3,550' (sqz'd) 3,553' - 3,575' 3,624' - 3,649' 3,652' - 3,677' 3,724' - 3,739' 3,746' - 3,748' (sqz'd) Pool 4: 3,772' - 3,792' 3,800' - 3,802' (sqz'd) Squeezed Perfs (isolated in 7" liner): 9,398' - 9,400' 9,411' - 9,445' 9,458' - 9,460' 9,751' - 9,781' 9,833' - 9,843' 9,953' - 9,958' Fish: Remnants of "D" packer @ 6,838' (6/22/2003) 7" cement retainers @ 9,296'; 9,707'; and 9,925' KU 14x-6 Pad 14-6 422' FSL, 1,147' FWL, Sec. 6, T4N, R11W, S.M. Permit #:181-092 API #:50-133-20342-00-00 Prop. Des:A-028142 KB Elevation:87' AGL Latitude: Longitude: Spud:9/22/1981 TD:10/27/1981 Rig Released:12/9/1981 PA #: TD 10,225' MD 9,863' TVD LIB Tagged @ Well is currently cross flowing water from ~3650 down to Pool 6 based on Temp log Lease: State: Country:USA (TVD) County or Parish:Kenai Peninsula Borough Last Revison Date:Revised By:Chad Helgeson Alaska Angle @ KOP and Depth:6deg @ 5950' Perforations (MD): 2/3/2023 Completion Fluid:6% KCL Angle/Perfs:0deg Well Name & Number: Dated Completed:7/1/2003 Kenai Unit 14x-6 Kenai Gas Field Active Perfs (Sterling Pool 6): C1: 4,462' -4,533' DIL C2: 4,619' - 4,670' DIL (12 spf, 8/14/03) Plugs set at ~4,550' ~3919-4362' (will be tested plug) ~3450' Cmt retainer, Squeezed scab liner below 9-5/8", 47 ppf, N-80, BTC casing @ ,7282' Cmt with 1,450 sks of class G Note:Apparent casing damage at 3,550'-3,560' (6/25/2003) PBTD 9,296' MD 8,982' TVD Conductor: 20" @ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2,566' Cmt with 1675 sks of class G 7", 29 ppf, N-80, BTC liner 6,925' - 10,225' Cmt with 1,600 sks of class G 7" Scab Liner 3,449' - 3,893' - Baker ZXP packer @ 3,449' - 7", 23 ppf, L-80, BTC casing - Baker ZXP packer on HMC liner hanger @ 3,865' - Muleshoe @ 3,893' Min ID = 6.184" at muleshoe Isolated Perfs (behind scab liner): Pool 3: 3,548' - 3,550' (sqz'd) 3,553' - 3,575' 3,624' - 3,649' 3,652' - 3,677' 3,724' - 3,739' 3,746' - 3,748' (sqz'd) Pool 4: 3,772' - 3,792' 3,800' - 3,802' (sqz'd) Squeezed Perfs (isolated in 7" liner): 9,398' - 9,400' 9,411' - 9,445' 9,458' - 9,460' 9,751' - 9,781' 9,833' - 9,843' 9,953' - 9,958' Fish: Remnants of "D" packer @ 6,838' (6/22/2003) 7" cement retainers @ 9,296'; 9,707'; and 9,925' KU 14x-6 Pad 14-6 422' FSL, 1,147' FWL, Sec. 6, T4N, R11W, S.M. Permit #:181-092 API #:50-133-20342-00-00 Prop. Des:A-028142 KB Elevation:87' AGL Latitude: Longitude: Spud:9/22/1981 TD:10/27/1981 Rig Released:12/9/1981 PA #: TD 10,225' MD 9,863' TVD PROPOSED Kenai Gas Field KU 14X-06 Current 01/29/2023 Starting head, Cameron WF, 20 1/4 2M x 20'’ SOW, w/ 2- 2 1/16 2M EFO Casing spool, Cameron WF, 21 ¼ 2M x 13 5/8 5M, w/ 2- 2 1/16 5M SSO PP bottom 20'’ 9 5/8'’ 13 3/8'’ Kenai Gas Field KU 14X-06 20 X 13 3/8 x 9 5/8 Current Valve, Master, VG-D, 7 1/16 3M FE, HWO, EE trim Tree cap, Otis, 7 1/16 3M FE X 9.5’’ Otis Quick Union Tubing head, Vetco Gray, 11 3M x 11 3M w/DSA seal adapter back to 13 5/8 5M prepped for 9 5/8 pipe Valve, VG-D, 7 1/16 3M FE, HWO, EE trim Valve, WKM-M, SSV 7 1/16 3M FE EE trim 13 3/8 x 9 5/8 annulus Kenai Gas Field KU 14X-06 Proposed 401 02/01/2023 Starting head, Cameron WF, 20 1/4 2M x 20'’ SOW, w/ 2- 2 1/16 2M EFO Casing spool, Cameron WF, 21 ¼ 2M x 13 5/8 5M, w/ 2- 2 1/16 5M SSO PP bottom 20'’ 9 5/8'’ 13 3/8'’ Kenai Gas Field KU 14X-06 20 X 13 3/8 x 9 5/8 Nipple down Tubing head, Vetco Gray, 11 3M x 11 3M w/DSA seal adapter back to 13 5/8 5M prepped for 9 5/8 pipe Valve, VG-D, 7 1/16 3M FE, HWO, EE trim 13 3/8 x 9 5/8 annulus Test plug 4 ½ IF top and bottom w/ 3'’ BPV Locks in wellhead Kenai Gas Field KU 14X-06 BOP Rig 401 02/04/2023 CIW-U Choke and Kill valves 2 1/16 5M Mud Cross 3 1/8 5M EFO 4.30' Hydril GK 13 5/8-5000 DSA 3 X 2Shaffer SL 2 3/8'’ rams 2 7/8-5 ½’’ variables Blind Superseded From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Rixse, Melvin G (OGC); Regg, James B (OGC); Harold Soule - (C); Donna Ambruz; Noel Nocas; Regg, James B (OGC) Subject:RE: [EXTERNAL] KU 14X-06 (PTD 189-092) Suspension sundry Date:Friday, February 17, 2023 4:30:00 PM Attachments:image001.png Chad, Hilcorp has verbal approval to perform steps 1-6 in the sundry application submitted on Feb 8, 2023. Sundry number is 323-077. Conditions of approval for these steps are: BOP test to 2500 psi. BOP configuration with pipe rams below annular as submitted in your email below. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, February 17, 2023 4:14 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Harold Soule - (C) <hsoule@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: RE: [EXTERNAL] KU 14X-06 (PTD 189-092) Suspension sundry Bryan, As we discussed on the phone, attached is a revised BOP schematic with the single gate below the Annular Preventer to ensure the project can keep its schedule. Please provide the verbal approval to start the job this project on Sunday/Monday and provide any stipulations we need to be aware of for the rig up operations. Please let me know if you need any additional information on this over the weekend, please give me a call or text if you need anything else for this project. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Chad Helgeson From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, February 16, 2023 8:22 AM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] KU 14X-06 (PTD 189-092) Suspension sundry Chad, Why do you have the single gate above the annular preventer? That is very unconventional. Bryan McLellan CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, February 14, 2023 11:14 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] KU 14X-06 (PTD 189-092) Suspension sundry Bryan See Below for responses to these questions. I will give you a call to discuss the last one. I will be sending another email to answer the question on disposal zones. Let me know if you need anything else. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, February 13, 2023 8:53 AM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: [EXTERNAL] KU 14X-06 (PTD 189-092) Suspension sundry Chad, A few questions regarding the sundry application: 1. The BOP stack doesn’t show a 2-3/8” pipe ram. Are you planning to add a single gate for pulling the CT? (Yes the single gate is for the 2-3/8” coil) 2. We need to have some means of measuring success for the first option of squeezing cement behind the scab liner. The goal is to isolate Pool 3 from Pool 4. If the leak in the 7” is deep, it might be possible to set the cement retainer deep enough to run a CBL across the 7” between the pools from 3478 – 3772’ MD. Or maybe there is a minimum volume of cement that must be squeezed below the retainer, enough to fill the annular space between 7” and 9-5/8”, and then establish some squeeze pressure. Since we don’t know the situation now, we can make a hold point after you’ve completed the diagnostics and then establish some criteria for success at that point. How would you like to handle it? (I prefer to make a hold point, based on diagnostics. I put this in for some flexibility, If the hole in the 7” casing is from where the warming is coming from, we will probably have to go down the path for Milling the packer and pulling it.) 3. Need to install tubing head adaptor and dry hole tree per 20 AAC 25.110 and ideally a tubing hanger and short kill string when you leave the well so you have a way to test your BOP’s upon return. (Yes, we are installing and will have the tubing head adapter in the well to install a BPV when ND/NU in the future. The hanger we are planning due to availability is 4-1/2”. We do not plan on installing a short kill string, just some methanol for the surface freeze protect. The well will be plugged tested and full of fluid.) 4. You probably already know this, but I’d feel bad if I don’t mention it and someone gets hurt. Cutting the CT on the rig floor can be a hazardous operation due to residual bend in the CT. Serious injuries have occurred when the stored energy in the coil is suddenly released when it is cut. Maybe you already have experience in handling the CT on a workover rig and are set up for it, but if not, I am happy to discuss what I’ve seen in the past. Yes definitely worth mentioning, we have some experience in the past and we have been working with our rig crews, and safety team to ensure we conduct the coil cutting safely. I am open to any additional thoughts you want to share with us. I can give you call and discuss this with you. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. 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Kenai Gas Field KU 14X-06 BOP Rig 401 02/17/2023 CIW-U Choke and Kill valves 2 1/16 5M Mud Cross 3 1/8 5M EFO 4.30' Hydril GK 13 5/8-5000 DSA 3 X 2Shaffer SL 2 3/8'’ rams 2 7/8-5 ½’’ variables Blind 1 Regg, James B (OGC) From:Cole Bartlewski <cbartlewski@hilcorp.com> Sent:Wednesday, February 1, 2023 9:56 PM To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Subject:BOPE test report for Fox CTU 8 on KU 14X-06 Attachments:Fox CTU 8 BOPE TEST REPORT 1_28_23.xlsx Good evening, Attached is the BOPE test report for Fox CTU on KU 14X‐06. Cole Bartlewski Hilcorp Alaska, LLC Sr. Wellsite Supervisor Email: cbartlewski@hilcorp.com Office 907-283-1301 Cell 907-690-2854 Hilcorp Alaska, LLC A Company built on Energy The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Kenai Unit 14X-06PTD 1810920 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:8 DATE:1/28/23 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #1810920 Sundry #323-024 Operation:Drilling:Workover:X Explor.: Test:Initial:X Weekly:Bi-Weekly:Other: Rams:250/3000 Annular:NA Valves:250/3000 MASP:998 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.P Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 0 NA Test Fluid Other Inside BOP 0 NA FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0 NA NA Pit Level Indicators NA NA #1 Rams 1 1.75" B/S P Flow Indicator NA NA #2 Rams 1 1.75" P/S FP Meth Gas Detector NA NA #3 Rams 0 NA NA H2S Gas Detector NA NA #4 Rams 0 NA NA MS Misc 0 NA #5 Rams 0 NA NA #6 Rams 0 NA NA ACCUMULATOR SYSTEM: Choke Ln. Valves 2 2"P Time/Pressure Test Result HCR Valves 0 NA NA System Pressure (psi)3000 P Kill Line Valves 2 2"P Pressure After Closure (psi)2500 P Check Valve 0 NA NA 200 psi Attained (sec)3 P BOP Misc 0 NA NA Full Pressure Attained (sec)9 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):0 NA No. Valves 5 P ACC Misc 0 NA Manual Chokes 2 P Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 0 NA #1 Rams 22 P Coiled Tubing Only:#2 Rams 26 P Inside Reel valves 1 P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:3.0 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/27/23 0921 Waived By Test Start Date/Time:1/28/2023 10:00 (date)(time)Witness Test Finish Date/Time:1/28/2023 13:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Test Fluid: Methanol. Bottle Precharge: 1400 psi. Landry Lynn Hilcorp Cole Bartlewski KU 14X-06 Test Pressure (psi): trais@foxenergyak.com Cbartlewski@hilcorp.com Form 10-424 (Revised 08/2022)2023-0128_BOP_Fox8_KU_14X-06         jbr J. Regg; 5/31/2023 ==1 Hilcorp Alaska LLCjbr 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Pull Coil V String 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,225'6,838' (fish) Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 4,760psi Liner 3,830psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 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 Chad Helgeson, Operations Engineer chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 3.004# / HO-70 4,860' January 24, 2023 N/A; N/A N/A; N/A See Schematic See Schematic 2-3/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE FEDA028142 181-092 50-133-20342-00-00 Kenai Gas Field Sterling Gas Pool 6 Same SIO 7A.002 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 14X-06 Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 9,863'9,296'8,982'~183psi 9296, 9707, 9925 MD 3,090psi 85' 2,566' 85' 2,566' Perforation Depth MD (ft): 7,282' 7"444' 9-5/8" 20" 13-3/8" 85' 2,566' 6,870psi7,194'7,282' 6,340psi3,449'3,449' m n P s 66 t g Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Samantha Carlisle at 8:02 am, Jan 17, 2023 323-024 Digitally signed by Aras Worthington (4643) DN: cn=Aras Worthington (4643), ou=Users Date: 2023.01.13 15:40:14 -09'00' Aras Worthington (4643) BJM 1/24/23 998 psi -bjm Production is not allowed without production tubing and packer. Separate sundry required for installing production packer and tubing prior to returnto production, except short term flow testing may be performed for well integrity diagnostic purposes as part of this sundry. See additional notes and conditions written into the attached procedure. DSR-1/17/23 CT BOP test to 3000 psi. 10-404 X X DLB 01/17/2023 x-bjm GCW 01/25/23JLC 1/25/2023 forupto14days. 1/25/23Brett W. Huber. Sr.Digitally signed by Brett W. Huber. Sr. Date: 2023.01.25 16:25:01 -09'00' Well Prognosis Rev 1 Well: KU 14X-06 Date: 1/12/2023 Well Name: KU 14X-06 API Number: 50-133-20342-00-00 Current Status: Pool 6 Storage Well Permit to Drill Number: 181-092 Estimated Start Date: January 24, 2023 Rig: CTU Regulatory Contact: Donna Ambruz 777-8305 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Current BHP: ~1,444 psi @ 4,462’ TVD (Based on current fluid level in well) Max. Expected BHP: ~1,444 psi @ 4,462’ TVD (Based on current fluid level in well) Max. Potential Surface Pressure: ~ 998 psi (Based on current fluid level less gas gradient to surface (0.10psi/ft) Well Status: KU 14X-06 is a Pool 6 Gas storage well that is currently shut-in. Summary: KU 14X-06 was originally drilled and named KDU-08 in 1981 where it was tested in the Tyonek and plugged back and completed as a dual string Sterling producer and the name changed to KU 14X-06. In 2003 the well was decompleted from Sterling Pool 3 and 4 sands, which produced ~40 BCF combined and were flowing with a shut in pressure of almost 200 psi when shut in. The Sterling Pool 3 and 4 sands were isolated with a 7” scab liner and the well converted to a Pool 6 Gas Storage producing well with a dual coil concentric string for dewatering the 9- 5/8” casing. This well has been a very stable storage producer since 2004. December 10 th the well unloaded a slug of water and stopped flowing 2 days later. The purpose of this work/sundry is to pull the 1-3/4” velocity string, pull the 2-3/8” coil string and plug back zone that is making water, try to return well to production. Notes Regarding Wellbore Condition: x Jan 11, 2023, an MIT was completed on the 9-5/8” x 13-3/8” annulus to 1,000 psi o 9-5/8” will be considered as the tubing with the annulus shoe (tested with MIT) as the packer x SL fish @ 4,865’ inside 2-3/8” coil string (below the 1.75” coil string) - ½ of a standing valve x Dual Coil Tubing Hangers installed above 7” Master Valve x The Pool 6 reservoir pressure is limited to 400 psi per SIO 7A.002. (Very low likelihood of overpressuring tubing or annulus) x The typical flowing tubing pressure on the storage wells when flowing at Kenai Gas Field is 70-100psi x KU 14X-06 is 2700’ from the closest public building/highway x Caliper will be run to determine if there is any damage is present in the 9-5/8” and will be submitted to AOGCC prior to returning the well to production Prework Diagnostic Results: x Static fluid level on 9-5/8” annulus was ~1150ft with multiple echometer shots. The pump did not catch pressure when filled. Pumped 80 bbls @ 2.5 bpm at minimal pressure build and well died to 0 psi when pumping stopped. x 2 bbls to catch fluid on 2-3/8” x 1-3/4” annulus (~2,222ft to fluid) – Established injection down tubing at 0.4 bpm @ 450 psi. x 3.1 bbls to catch fluid on 1-3/4” string (~1,347ft to fluid)- pressured up to 1,300 psi and very slow drop, no communication observed on 2-3/8” or 9-5/8” gauges. Pressure bled off to monitor other strings when pumping. Tubing and packer to be installed before returning the well to production. 9-5/8" casing is not considered tubing. -bjm Well Prognosis Rev 1 Well: KU 14X-06 Date: 1/12/2023 BOP Usage during job: Several steps in this procedure require the coil BOP components to be used when circulating fluid; isolating the coil during connections to the coil string at surface, breaks in work activity, etc. The BOP components will not be retested after use unless they are; x Purposely used to prevent the uncontrolled flow of fluids from the well, x Specifically mentioned in the procedure to test at certain steps x They appear to be damaged from the work or use of them (eg, stripping pipe through them or closing on tool strings) Procedure: 1. MIRU Coiled Tubing. 2. Circ/pump KW fluid (8.4 ppg water) to ensure well is dead. 3. ND 2-9/16” Tree to double studded adapter (DSA), install new DSA (4” 3M x 4” 5M) and 4-1/16” gate valve on well. During the work on this step there are not any mechanical barriers from the reservoir. Confirm well is dead before breaking apart barriers. 4. NU BOP equipment on 4-1/16” 5M valve, PT BOPE to 3,000 psi Hi 250 Low. (3000 psi wellhead components). a. Provide AOGCC 24hrs notice of BOP test. 5. Ensure well is full of fluid, test 1-3/4” coil for communication at hanger with 2-3/8” string (500 psi differential). 6. Make up double roll on connector with slick 1.75” OD, run through Lubricator. a. If during the inspection of the coil stub during step 3, it is determined there is not enough room for a dimple cold coil connector to be installed on stub, measure for overshot and/or spear to latch string. 7. Separate 4-1/16” valve from CT hanger (below tested BOPE). And connect 1-3/4” coil connector with the 1-3/4” stub above the tubing hanger. During the work on this step there are not any mechanical barriers from the reservoir. Confirm well is dead before breaking apart barriers. 8. Reconnect stack and test broken connection. 9. Pull test connector to calculated v string weight off bottom (~10,000lbs). Slack off to neutral weight and back out top lockdowns. 10. Attempt to pull V string into lubricator. a. If overshot or spear are used to pull coil, pull equipment above the BOPs, close pipe rams, remove and install double cold roll when equipment is above BOP stack. b. Retest connection and open pipe rams. Pull coil out of well. 11. Spool CT v string. Tag up at surface. Break down BHA. 12. Close 4-1/16” master valve. 13. Nipple Down BOP Equipment, swap to 2-3/8” equipment for pulling 2-3/8” coil. PT BOPE to 3,000 psi Hi 250 Low. (3000 psi wellhead components). a. Provide AOGCC 24hrs notice of BOP test 14. Connect 2-3/8” coil to a 1-3/4” service coil reel. Monitor all annuli for 3 hours after pumping KW fluid to ensure no pressure build before ND tree. -bjm Well Prognosis Rev 1 Well: KU 14X-06 Date: 1/12/2023 15. MU MHA with disconnect and GS spear. Stab on well PT lubricator to 250/3,000 psi. RIH to latch hanger profile. Pick up to confirm latch. Slack off to neutral weight. Back off top lock down screws. Attempt to pull V string into lubricator. 16. Close pipe rams and slips & test they are holding. Perform a push/pull test to confirm engagement. 17. Slack off to neutral weight. Unscrew lubricator and drop chain tension to start stripping off lubricator to expose CT hanger and GS profile. 18. Cut off CT Connectors from both V string and CT retrieval whip. Make up double roll on connector with slick 2-3/8” OD. 19. Slips chains and stab lubricator back on BOPE. Pressure test break to 250/3000 psi on back side of CT. 20. Pull test double cold roll connector to the weight indicated when pulling CT hanger. Slack back down to hanging weight. Open pipe rams then pipe slips. Spool CT v string OOH onto reel. Tag up at surface. Break down BHA. Contingency 1: a. If any issues with pulling 2-3/8” coil, use Eline and cut and fish coil as necessary with jet cutter until can be pulled free (preferably below the C1 Sands @ 4,550.) b. If 2-3/8” Coil cannot be pulled or fished with coil, the Rig 401 workover unit may be used to fish coil. If this happens an update to this procedure will be provided, BOP schematics will be submitted to AOGCC for review. 21. RIH with 1-3/4” service coil, tag bottom, clean out to 4700ft if necessary (fluff & stuff as needed). 22. Stand back coil equipment. 23. MIRU Eline, PT equipment 250/2500. 24. Run eline caliper from bottom of well to surface. 25. PU Neoplug and try to set between 4,565’-4,600’. Dump 25ft of cement on plug to isolate C2 Sand. (C2 sand is suspected wet sand). 26. WOC and tag top of cement. 27. RIH with CT and jet well with N2 (attempt to flow any fluid out of well and or push fluid away to C1 zone.) Note: A pressure test of the 9-5/8” pipe is not needed or planned if the water production is isolated from this work. If there is a leak of fluid in the 9-5/8” or scab liner, the well will load up and die. At which point to recover the well, a casing test will be necessary to verify repairs are made or to find the leak. 28. Monitor returns back into wellbore with echometer (determine if same fluid level returns). a. Option will be to run a spinner log if there is inflow. Contingency 2: if there is inflow with pressure above 400 psi BHP, a retrievable plug will be set to test casing, looking for the leak in casing. If a leak in the casing is found, plan will be to plug back pool 6 and isolate the scab liner depending on where the leak is found. i. Neo plug will be set ~4,450’ with 25ft of cement on top of plug. Well will be filled with fluid. ii. Neo plug will be set above leak in casing wherever it is found, with 25ft of cement placed on plug. The well will be pressure tested to 1500 psi and suspended. Note: A pressure test of the 9-5/8” pipe is not needed or planned if the water production is isolated from this work. If there is a leak of fluid in the 9-5/8” or scab liner, the well will load up and die. At which point to recover the well, a casing test will be necessary to verify repairs are made or to find the leak. A suspension sundry will be required if Contingency step 2.i is completed. -bjm Swap to 1-3/4" equipment and BOP pipe/slip ram. Test BOP to 250/3000 psi. -bjm Another sundry will be required before Rig is used. -bjm Obtain approval from AOGCC if CT fishing operation in contingency 1.a. requires removal or defeat of BOPE. -bjm Contingency 2.ii. will require another sundry. -bjm Well Prognosis Rev 1 Well: KU 14X-06 Date: 1/12/2023 29. RIH and jet well with N2 and unload any fluid left on well to return the well to production. Repeat unloading or push away fluid with N2 as necessary until recover gas flow from well. 30. Try to flow well to tank, if necessary. Contingency 3: if cannot reestablish flow from pool 6, but there is no inflow of fluid in wellbore. i. RU Eline, PT 250/2500. ii. RIH and reperforate well from 4,462-4,533. 31. RDMO coil tubing. 32. Turn well over to production. 33. Flow well without velocity strings in well. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Current Wellhead Schematic 4. Proposed Wellhead schematic (during coil work) 5. Proposed Wellhead schematic for testing 6. Coil BOPE Schematic 7. Standard Well Procedure- Nitrogen 8. MIT-IA of 9-5/8” x 13-3/8” (1/11/23) return the well to production. Will need to install a tubing string and packer before return to production. A separate sundry is required. -bjm Short term production is allowed for well integrity diagnostic purposes only. -bjm Production allowed for up to 14 days for diagnostics. -bjm Lease: State: Country:USA (TVD) 6deg @ 5950' Perforations (MD): 12/21/2022 Completion Fluid:6% KCL Angle/Perfs:0deg Well Name & Number: Dated Completed:7/1/2003 Kenai Unit 14x-6 Kenai Gas Field County or Parish:Kenai Peninsula Borough Last Revison Date:Revised By:Chad Helgeson Alaska Angle @ KOP and Depth: Active Perfs (Sterling Pool 6): C1: 4,462' -4,533' DIL C2: 4,619' - 4,670' DIL (12 spf, 8/14/03) BST Concentric String: Outer string: 2-3/8" OD, 0.125" wall, 3.007 ppf, HO - 70 coil tubing w/ plug/profile combination BST nipple @ 4,860', Nipple ID = 1.188" w/ 1.00" nogo. Standing Valve @ 4,860' Inner string: 1-3/4" 0.109" wall CT w/ BST seating nipple @ 4,852', Nipple ID = 1.375" 9-5/8", 47 ppf, N-80, BTC casing @ ,7282' Cmt with 1,450 sks of class G Note:Apparent casing damage at 3,550'-3,560' (6/25/2003) PBTD 9,296' MD 8,982' TVD Conductor: 20" @ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2,566' Cmt with 1675 sks of class G 7", 29 ppf, N-80, BTC liner 6,925' - 10,225' Cmt with 1,600 sks of class G 7" Scab Liner 3,449' - 3,893' - Baker ZXP packer @ 3,449' - 7", 23 ppf, L-80, BTC casing - Baker ZXP packer on HMC liner hanger @ 3,865' - Muleshoe @ 3,893' Min ID = 6.184" at muleshoe Isolated Perfs (behind scab liner): Pool 3: 3,548' - 3,550' (sqz'd) 3,553' - 3,575' 3,624' - 3,649' 3,652' - 3,677' 3,724' - 3,739' 3,746' - 3,748' (sqz'd) Pool 4: 3,772' - 3,792' 3,800' - 3,802' (sqz'd) Squeezed Perfs (isolated in 7" liner): 9,398' - 9,400' 9,411' - 9,445' 9,458' - 9,460' 9,751' - 9,781' 9,833' - 9,843' 9,953' - 9,958' Fish: Remnants of "D" packer @ 6,838' (6/22/2003) 7" cement retainers @ 9,296'; 9,707'; and 9,925' KU 14x-6 Pad 14-6 422' FSL, 1,147' FWL, Sec. 6, T4N, R11W, S.M. Tree cxn: 4-3/4" Otis Permit #:181-092 API #:50-133-20342-00-00 Prop. Des:A-028142 KB Elevation:87' AGL Latitude: Longitude: Spud:9/22/1981 TD:10/27/1981 Rig Released:12/9/1981 PA #: TD 10,225' MD 9,863' TVD Lease: State: Country:USA (TVD) 6deg @ 5950' Perforations (MD): 1/13/2023 Completion Fluid:6% KCL Angle/Perfs:0deg 4,462'-4,533' Well Name & Number: Dated Completed:7/1/2003 Kenai Unit 14x-6 Kenai Gas Field County or Parish:Kenai Peninsula Borough Last Revison Date:Revised By:Chad Helgeson 4,462'-4,533' Alaska Angle @ KOP and Depth: Active Perfs (Sterling Pool 6): C1: 4,462' - 4,533' DIL 9-5/8", 47 ppf, N-80, BTC casing @ ,7282' Cmt with 1,450 sks of class G Note: Apparent casing damage at 3,550'-3,560' (6/25/2003) PBTD 9,296' MD 8,982' TVD Conductor: 20" @ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2,566' Cmt with 1675 sks of class G 7", 29 ppf, N-80, BTC liner 6,925' - 10,225' Cmt with 1,600 sks of class G 7" Scab Liner 3,449' - 3,893' - Baker ZXP packer @ 3,449' - 7", 23 ppf, L-80, BTC casing - Baker ZXP packer on HMC liner hanger @ 3,865' - Muleshoe @ 3,893' Min ID = 6.184" at muleshoe Isolated Perfs (behind scab liner): Pool 3: 3,548' - 3,550' (sqz'd) 3,553' - 3,575' 3,624' - 3,649' 3,652' - 3,677' 3,724' - 3,739' 3,746' - 3,748' (sqz'd) Pool 4: 3,772' - 3,792' 3,800' - 3,802' (sqz'd) Isolated Perfs (below NEO PLug w/ 25' of cement) Squeezed Perfs (isolated in 7" liner): 9,398' - 9,400' 9,411' - 9,445' 9,458' - 9,460' 9,751' - 9,781' 9,833' - 9,843' 9,953' - 9,958' Fish: Remnants of "D" packer @ 6,838' (6/22/2003) 7" cement retainers @ 9,296'; 9,707'; and 9,925' KU 14x-6 Pad 14-6 422' FSL, 1,147' FWL, Sec. 6, T4N, R11W, S.M. Tree cxn: 4-3/4" Otis Permit #:181-092 API #:50-133-20342-00-00 Prop. Des:A-028142 KB Elevation:87' AGL Latitude: Longitude: Spud:9/22/1981 TD:10/27/1981 Rig Released:12/9/1981 PA #: TD 10,225' MD 9,863' TVD PROPOSED Kenai Gas Field KU 14X-06 Current 12/29/2022 Starting head, Cameron WF, 20 1/4 2M x 20'’ SOW, w/ 2- 2 1/16 2M EFO Casing spool, Cameron WF, 21 ¼ 2M x 13 5/8 5M, w/ 2- 2 1/16 5M SSO PP bottom 20'’ 9 5/8'’ 13 3/8'’ Kenai Gas Field KU 14X-06 20 X 13 3/8 x 9 5/8 x 2 3/8 x 1 ¾ Valve, Master, VG-D, 7 1/16 3M FE, HWO, EE trim Tree cap, Otis, 2 9/16M FE X 6.5’’ Otis Quick Union Valve, Swab, CIW-F, 2 9/16 5M FE, HWO, EE trim Coiled tubing hanger, VG- CTM, 4'’ nominal x 1 ¾ slips Coil is cut 8 1/8'’ above the top flange 2 3/8'’ 1.750'’ Coiled tubing hanger, VG- CTM 4 X 3'’ GS Baker fish neck and 2 3/8 susp, w/ 2'’ Type H BPV and grapple for 2 3/8'’ coil Valve, Masters, CIW-F, 2 9/16 5M FE, HWO, EE trim Valve, Wing, 2 1/16 5M FE, HWO and SSV, EE trim 2 1/16 5M Gas lift Tubing head, Vetco Gray, 11 3M x 11 3M w/DSA seal adapter back to 13 5/8 5M prepped for 9 5/8 pipe Valve, VG-D, 7 1/16 3M FE, HWO, EE trim Valve, WKM-M, SSV 7 1/16 3M FE EE trim 1 ¾ tubing 2 3/8 x 1 ¾ annulus 9 5/8 x 2 3/8 annulus 13 3/8 x 9 5/8 annulus Kenai Gas Field KU 14X-06 Coiled tubing removal 01/11/2023 Starting head, Cameron WF, 20 1/4 2M x 20'’ SOW, w/ 2- 2 1/16 2M EFO Casing spool, Cameron WF, 21 ¼ 2M x 13 5/8 5M, w/ 2- 2 1/16 5M SSO PP bottom 20'’ 9 5/8'’ 13 3/8'’ Valve, Master, VG-D, 7 1/16 3M FE, HWO, EE trim Coiled tubing hanger, VG- CTM, 4'’ nominal x 1 ¾ slips Coil is cut 8 1/8'’ above the top flange 4 1/16 3M head 3000psi rated 2 3/8'’ 1.750'’ Coiled tubing hanger, VG- CTM 4 X 3'’ GS Baker fish neck and 2 3/8 susp, w/ 2'’ Type H BPV and grapple for 2 3/8'’ coil 4 1/16 3M head 3000psi rated Tubing head, Vetco Gray, 11 3M x 11 3M w/DSA seal adapter back to 13 5/8 5M prepped for 9 5/8 pipe Valve, VG-D, 7 1/16 3M FE, HWO, EE trim Valve, WKM-M, SSV 7 1/16 3M FE EE trim Lubricator to injection head 4 1/16 10MBlind Shear Blind Shear Pipe Slip Pipe Slip Manual 2 1/16 10M Manual 2 1/16 10M Manual 2 1/16 10M Manual 2 1/16 10MManual2 1/16 10MManual2 1/16 10MKill port4 1/16 5M x 4 1/16 3M spool 4 1/16 5M Gate valve 4 1/16 5M x 4 1/16 10M spool Kenai Gas Field KU 14X-06 Proposed 12/29/2022 Starting head, Cameron WF, 20 1/4 2M x 20'’ SOW, w/ 2- 2 1/16 2M EFO Casing spool, Cameron WF, 21 ¼ 2M x 13 5/8 5M, w/ 2- 2 1/16 5M SSO PP bottom 20'’ 9 5/8'’ 13 3/8'’ Kenai Gas Field KU 14X-06 20 X 13 3/8 x 9 5/8 Temporary testing Valve, Master, VG-D, 7 1/16 3M FE, HWO, EE trim Tree cap, Otis, 7 1/16 3M FE X 9.5’’ Otis Quick Union Tubing head, Vetco Gray, 11 3M x 11 3M w/DSA seal adapter back to 13 5/8 5M prepped for 9 5/8 pipe Valve, VG-D, 7 1/16 3M FE, HWO, EE trim Valve, WKM-M, SSV 7 1/16 3M FE EE trim 13 3/8 x 9 5/8 annulus Production testing outlet Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Coil Tubing BOP STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. -200.00.0200.0400.0600.0800.01000.01200.001-11-23 12:50:24 01-11-23 12:57:36 01-11-23 13:04:48 01-11-23 13:12:00 01-11-23 13:19:12 01-11-23 13:26:24 01-11-23 13:33:36 01-11-23 13:40:48 01-11-23 13:48:0014X-6 MIT TEST 9-5/8" x 13-3/8"JAN 11-2023PSIG CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Chad Helgeson To:McLellan, Bryan J (OGC) Cc:Josh Allely - (C) Subject:RE: [EXTERNAL] KU 14X-06 (PTD 181-092) Fishing 1.75" CT Date:Tuesday, January 24, 2023 12:15:10 PM The road is private, maintained by Hilcorp, with no other access to properties off the road and there is a gate at the pad. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, January 24, 2023 12:03 PM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: RE: [EXTERNAL] KU 14X-06 (PTD 181-092) Fishing 1.75" CT Chad, is the road leading to the pad accessible to the public? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, January 24, 2023 10:14 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] KU 14X-06 (PTD 181-092) Fishing 1.75" CT Bryan, That is a great question. The primary reason is that we must remove the tree to install a 4” valve for the coil and hangers to fit, as the equipment does not currently fit through the master valve. While we could only do it one time to install the new valve for installation of the BOP stack, we believe removing the BOPs and Master valve to install the roll-on connector to coil, gives us the project a higher chance of success without increasing the risk much more. The way the well was completed is not very friendly for removing the 1.75” coil string. From a safety risk perspective the following conditions were considered: The 1.75” coil is plugged enough that bleed rates do not fall to zero within a 24hr period CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. The estimated time the BOPs will be off the well to install the roll-on connector is approximately 30 min to 90min. The well is full of kill weight fluid, (8.4 ppg fresh water) No communication between the 2-3/8” x 1.75” tubing hanger Well has been shut-in for 40+ days and no pressure increase on the any annulus A overshot will not fit over the coil inside the hanger A spear is one time option, if we use it and its unable to pull free, it leaves the well in even worse decomplete options we currently have. Also attached is a 660’ map for the whole pad that KU 14X-06 is attached. The 14X-06 well is located directly in the center of the pad, and as I put in the procedure, the closest building/residence is 2700’ away. Please let me know if you have additional questions regarding the procedure. Feel free to email or give me a call with them. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, January 23, 2023 3:10 PM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: [EXTERNAL] KU 14X-06 (PTD 181-092) Fishing 1.75" CT Chad, For step 7 in the proposed procedure, why can’t you fish the 1.75” CT through the BOP’s with an overshot or spear? That way you don’t have to break containment without any mechanical downhole barriers. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility ! !!!!! ! !!! !! !! ! ! ! !!! ! ! ! SEC. 6 SEC. 1 SEC. 7SEC. 12 4N12W 4N11W KENAI UNIT LACEY DENNIS ALASKA STATE D N R SALAMATOF NATIVE ASSN INC SALAMATOF NATIVE ASSN INC Kenai Gas Field Pad No. 14-06 KGF 14-06 Source: Esri, Maxar, GeoEye, Earthstar Geographics, CNES/Airbus DS, USDA, USGS, AeroGRID, IGN, and the GIS User Community 151°15'30"W151°15'40"W151°15'50"W151°16'0"W151°16'10"W151°16'20"W 60°27'55"N60°27'55"N60°27'50"N60°27'50"N60°27'45"N60°27'45"N60°27'40"N60°27'40"N60°27'35"N60°27'35"N60°27'30"N60°27'30"N60°27'25"N60°27'25"N60°27'20"N60°27'20"N60°27'15"N60°27'15"N± 0 150 300 450 600 Feet 1 inch = 300 feet @ 11x17 Page Size Map Date: 3/2/2021 Document Path: O:\Alaska\GIS\cook_inlet\fields\All_Fields\All_Fields_Pad_SHL_660ftBuffer_11x17_TWellman_v01.mxdKenai Unit KGF 14-06 660 ft Radius Legend !Surface Well Location Existing Gas Pipelines MHW Line (NOAA) KPB Parcels Cook Inlet Oil and Gas Units Imag~t~roject Well History File Cover I~e XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. j <~ [- _~_~_~ Well History File Identifier RESCAN DIGITAL DATA OVERSIZED (Scannable) [] Color items: [] Diskettes, No. [] Maps: [] Grayscale items: [] Other, No/Type [] Other items scannable by large scanner [] Poor Quality Originals: [] Other: ,ov~IZED (N°n'Scannable) NOTES: jJ;a~ Logs of various kinds [] Other Scanning Preparation ,1 5-L) + .I 3 Stage I PAGE COUNT F.Oa SCA..ED ~,~E: ] ~. PAGE COUNT MATCHES NUMBERIN SCANNING PREPARATION: YES ~ NO BY: BEVE~INOENT SHERYL MARIA WINDY DATE; ~-~~ ~ Stage 2 IF NO ~N STA~E 1, PA~E(S) mSC~EPANC~ES WErE FOUND: __ YES __ NO RESCANNED BY; BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: /S/ General Notes or Comments about this file: Quality Checked (do.e) 12110102Rev3NOTScanned.wpd UNSCANNED, OVERSIZED MATERI.ALS AVAILABLE: /q( {)9'~ FILE # / /)/Nr;/;^OI1r: (Sètru-ey /J1ltfJ To request any/all of the above information, please contact: Alaska Oil & Gas Conservation Commission 1333 W. 7th Ave., Ste. 100 ' Anchorage, Alaska 99501 Voice (907) 279-1433 tFax (907) 276-7542 . . MEMO WELLS PRODUCING IN KENAI, STERLING POOL 6 AS NATIVE & STORAGE GAS WELLS Reference letter in file dated October 25, 2006 about wells producing from the Kenai, Sterling 6 Pool (pool code 448568) and the Kenai Pool 6 Gas Storage (pool code 448809). Storage Injection Order 7 A has a report, 2007 Annual Gas Storage Performance Evaluation dated March 2, 2007 which has a statement with an official start date of May 8, 2006 where storage started in the pool. There was no formal paperwork submitted about this change so this letter is for the official well status date change for the well status or date it was accomplished by AOGCC. The following is a list of wells that is reported with both pool codes 448568 and 448809: APD No. 201-097 201-231 159-013 165-007 178-055 168-071 181-092 181-154 182-015 182-085 184-109 185-181 200-148 Well No. 21-6RD 43-6RD 34-31 33-32L 44-30L DU5-L 14X-6AN 34-32L 14-32L 13-6L 23X-6SAN 33-7S 3 1- 7X I 0 ?yJl ,.O~ þ- /.- ~ \ ";) <0 SCANNED JUL 2 7 2007 ~ . Alaska .eam Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 October 25,2006 Alaska Oil and Gas Conservation Commission Attn: Steve McMains 333 W. 7th Street, Suite 100 Anchorage, AK 99501 RE: Weils Completed in Pool Codes 568 and 448809 Dear Steve, Per your request, this letter is being provided to the AOGCC to identify wells completed in the Kenai Sterling Pool 6 (Pool Code 568) and the Kenai Pool 6 Gas Storage (Pool Code 448809). As you are aware, the above pool codes refer to the same geologic reservoir, a partially depleted gas reservoir which is being used for gas storage operations. Subsequent to the initiation of storage operations in May 2006, all future production from this reservoir is allocated between the remaining native gas and the injected/stored volumes, per written agreements between Marathon Oil Company and both the ADNR and the BLM. Therefore, any production from the wells completed in Pool 6 will be reported monthly on Form 10-405 under both pool codes. The wells appearing on Form 10-405 will appear the same for both pool codes. Per your request, the following is a list of wells which will be reported on Form 10-405, for both Pool Code 568 and 448809: Well No. 2l-6RD 43-6RD 34-31 33-32L 44-30L DU5-L l4X-6AN 34-32L l4-32L 13 -6L 23X-6SAN 33-7S 3 1- 7X API No. 5011331009001 5011331009101 5011331009700 5011331009800 5011332013900 5011332031900 5011332034200 5011332034800 5011332035100 5011332035600 5011332037100 5011332038000 5011332049500 APD No. 201097 201231 159013 165007 178055 168071 181092 181154 182015 182085 184104 185181 200148 .. " . . Please advise if you have any questions or need any additional information. I can be reached at 907.565.3041 or lcibele@marathonoil.com. yndon Ibele, PE Production Coordinator Cc Randy Jindra, IBM, Tulsa Ken Walsh, MOC, Kenai Marathon Houston Central Files Brian Havelock, ADNR, Anchorage Greg Noble, BLM, Anchorage ( i '( Alaska Business Unit Domestic Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 December 3,2003 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: KU 14x-6 Dear Mr. Aubert: Enclosed is the 10-407 WELL COMPLETION OR RECOMPLETION REPORT AND LOG for Marathon Kenai Gas Field well KU 14x-6. After pulling existing tubulars, the well was recompleted from Pool 3 and Pool 4 zones into the Pool 6 zone. After patching existing perfs, the well was reperforated and a concentric gas lift string was installed. A 10-404 subsequent notice, a daily summary of operations, and an updated wellbore diagram were previously submitted. If you need any additional information, I can be reached at 907-283-1333 or bye-mail at dmtitus@marathonoiLcom. Sincerely, ~ ._'~" .! \\ A A ¡ , , . ~'" rWv~ Denise M. Titus Production Engineer Enclosure RECEIVED DEC - 8 2003 Alaska Oil & Gas Cons. Commission Anchorage , ,," ,,", "" ,--- ~D'. EC" /J.'\¡¡I, ~1. ^..OOJ ' .' . ." ," " ~' ,I,J,U . ~-";':;' :"-',:.~ "'°1 ~~- ~ ' 11 oJ "p ..!... L .. ...... .-" ,,- " ,,~-.. . :( '~, STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OILD GASŒ] SUSPENDEDD ABANDONEDD SERVICED Development 2. Name of Operator 7, Permit Number MARATHON OIL COMPANY 81-92 3. Address 8, API Number P. O. Box 196168, Anchorage, AK 99519-6168 50-133-20342 4. Location of Well at Surface 9. Unit or Lease Name 422' FSL & 1147' FWL, Section 6, T4N, R11W, SM Kenai Unit At top of Producing Interval 10. Well Number 407' FSL & 1160' FWL, Section 6, T4N, R11W, SM @ 4462' OIL KU 14x-6 (KDU-8) At Total Depth 11. Field and Pool 455' FSL & 513' FEL, Section 1, T4N, R12W, SM Kenai Gas Field 5, Elevation in feet (indicate KB, OF, etc.) 6, Lease Designation and Serial No. Pool 6 25,06' KB A-028142 12. Date Spudded 13. Date TD. Reached 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 16. No. of Completions 9/22/1981 10/27/1981 10/6/2003 N/A feet MSL 1 17. Total Depth (MD+ TVD) 18. Plug Back Depth (MD+TVD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost 10,225'/9,862' 9296'/8,991' YesDNo ~ N/A feet MD N/A 22. Type Electric or Other Logs Run NIA 23 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT, GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 94 Plain 0 85 Driven Driven NIA 13-318" 61 K-55 0 2566 17-1/2 1675 sx NIA 9-518" 47 N-80 0 7282 12-1/4 1450 sx N/A 7" 29 N-80 6925 10225 8-1/2 1600 sx N/A 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) MD TVD 2-3/8" CT 4860 N/A C-1: 4462'.4533' 4462'-4533' 1-3/4" CT 4852 N/A 2-7/8" HSD, PJ 2906, 6 spf (x2 runs, 12spf total) 26, ACID, FRACTURE, CEMENT SQUEEZE, ETC. C-2: 4619'.4670' 4619'-4670' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 4.72" 4621 PF, RDX, 12spf N/A 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc,) 11-Sep-03 flowing wi concentric lift Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF W A TER-BBL CHOKE SIZE GAS-OIL RATIO 10/10/2003 24 TEST PERIOD ~ 0 7,847 36 N/A Flow Tubing Pres. Casing Pressure CALCULATED 01 L-BBL GAS-MCF WATER-BBL OIL GRAVITY-API (corr) 150 psig 0 24-HOUR RATE~ 0 7,487 36 N/A 28. Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Interbedded gas bearing sandstone, shale and coal. Core chips not available Form 10-407 Rev. 7-1-80 Submit in Triplicate CONTINUED ON REVERSE SIDE _lafL ,00; .. {,f N:\drlg\kgflwells\KBU33-6\AOGCC compl sundry.xls ( \ { 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME MEAS.DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase, Sterling Gas Sand 3542' 3542' Interbedded sandstone, silt shale and thin coals RECEIVED DEC - 8 '2003 Alaska Oil & Gas Cons. Commission Anchorage 31, LIST OF ATTACHMENTS Daily operations summary, wellbore schematic, directional survey 32. I hereby certify th~t the foregoing ~ tife and correct to the best of my knowledge "'./ tï V '""1 1<;1 If ll?""- Signed '.~ I VI it Denise Titus Title Production Engineer ,.. Date i>/?)o?L. I I INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska, Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. . Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.) Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain, Item 28: If no cores taken, indicate "none". Form 10-407 N:\drlg\sterling\su32-9\AOGCC compl sundry.xls Marathon Oil Company Alaska Business Unit Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 9071561-5311 Fax 907~564-6489 July 16, 2003 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference' KU 14x-6 Dear Mr. Aubert: Enclosed is the 10-403 Application for Sundry Approvals. The proposed work is to install a concentric lift string to unload water from the casing. For this operation, compressed gas will be metered and used to reverse water out of a CT chamber to surface. The high pressure lift gas will be metered independently.,'~A time cycle controller will be used to optimize the compressed gas used to keep the Iow pressure gas well unloaded. ~'" This work is expected to begin 7/23/03. A detailed procedure, wellbore diagram, and gas flow diagram are included for your review. If you need any additional information, I can be reached at 907-283-1333 or by e-mail at dmtitus@marathonoil.com. Sincerely, Denise M. Titus Production Engineer Enclosu res CANNE JUL 2 2{)03 G:\CMN\DRLG\KGF\WELLS\KU13-6L\Concentric AOGCC Sundry APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend__ Operation Shutdown __ Re-enter Susp_,en/ded Well__ Alter Casing __ Repair WellM Plugging Time Extension__ .j~pl,/.~Stimulate Change Approved Program __ Pull Tubing__ Variance Perforate 2. Name of Operator 5. Type of Well: 6. Datum Elev/~tion (DF or KB) MARATHON OIL COMPANY Development X 25.06 KB feet 3. Address Exploratory 7. Unit or Property Name P. O. Box 196168, Anchorage, AK 99519-6168 Stratigraphic KENAI UNIT 4. Location of Well at Surface Service 8. Well Number 422' FSL & 1147' FWL, Section 6, T4N, R11W, SM KU 14x-6 (also called KDU-8) At top of Productive Interval 9. Permit N,.gmber 407' FSL & 1160' FWL, Section 6, T4N, RllW, SM @ 4462' DIL 81-92" At Effective Depth Ilnstall Concentric String to Lift Water//i 10. APl Number 50- 133-20342 I / At Total Depth ~ 4. Field/Pool 455' FSL & 513' FI:L, Section 1, T4N, R12W, SM KENAI GAS FIELD/Pools 3 & 4 12. Present Well Condition Summary Total Depth: measured 10225 feet Plugs (measured) cement retainers @ 9296', @707', & 9925' true vertical 9862 feet Effective Depth: measured 9296 feet Junk (measured) N/A true vertical 8991 feet Casing Length Size Cemented Measured Depth True Vertical Depth Structural 85 20" driven 85 same Conductor Surface 2566 13 3/8" 1675 sacks 2566 same Intermediate Production 7282 9-5/8" 1450 sacks 7282 7194' Liner 3300 7" 1600 sacks 6925'-10,225' 6879'-9862' measured C-1' 4462'-4533'; C-2: 4619'-4670' true vertical C-1' 4462'-4533'; C-2: 4619'-4670' JUL ~. 13 ~003 Tubing (size, grade, and measured depth) Outer String: 2-3/8" HO-70, 0.125" wall thickness, Coiled Tubing .. .............. .. ..... ~, ..... Inner String: 1-3/4" QT-700, 0.109 wa th~ckness,.~ail;~l~¢a~i~g Packers and SSSV (type and measured depth) 13. Attachments Description Summary of Proposal__ Detailed Operations Program X BOP Sketch 14. Estimated Date for Commencing Operation 15. Status of Well Classification as: 23-Jul-03 16. If Proposal was Verbally Approved Oil Gas X Suspended Name of Approver, Date Approved Service 17. I hereby certr~y that the foregoing is~rue and correct to the best of my knowledge. ~/~/~ Denise Titus Title Production Engineer Date 7/16/2003 Signed FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness'~ Plug Integrity ~ BOP Test ~ Location Clearance Mechanical Integrity Test Subsequent Form Required 10- O"7 *,,roved Order of the o ,ss,on Form 10-403 Rev. 06/15/88 ORIGINAL Submit in Triplicate KU 14x-6 Concentric String Gas Flow Diagram Portion of gas stream downstream of compression Lift Gas Meter I ITo low pressure production header [ KU 14x-6 Annulus Production Meter KU 14x-6 Velocity String Production Meter Water and lift gas out Time cycle control valve Annular Production Lift gas in: down velocity string x concentric strin~ annulus Standing Valve Well 1. 4x-6 Orig. KB-GL: 25.06 DF-GL: 21.00' (Glacier Rig #1) APl: 50-133-20342 AOGCC: 81-92 422' FSL, 1147' FWL Sec. 6, T4N, R11W, S.M. Tree cxn: 4-3/4" Otis Baker ZXP w/7" 23 ppf casing Min ID = 6.184" at muleshoe 3440'-3893' Isolated Perfs (behind casin.q patch): Pool 3: 3548'-3550' (sqz'd) 3553'-3575' 3624'-3649' 3652'-3677' 3724'-3739' 3746'-3748' (sqz'd) Pool 4: 3772'-3792' 3800'-3802' (sqz'd) .Proposed Perfs (Sterlin.q Pool 6): C1,4462' - 4533' DIL C2, 4619' - 4670' DIL Squeezed Perfs(isolatedin 7"liner): 9398-9400 9411-9445 9458-9460 9751-9781 9833-9843 9953-9958 KU 14X-6 - PROPOSED ,ii IPBTD-9296' TD-10,225' IConductor: 20"@ 85' (driven) Surface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2566' Cmt with 1675 sks of class G Tubing: 2-3/8" coil tubing, 0.125" wall, 3.007 ppf, HO-70 grade, flash present Drft = 2.000" BST Concentric String: Outer string: 2-3/8" 0.125" wall CT w/ plug/profile combination nipple @ 4900' ID=1.188" Inner string: 1-3/4" 0.109" wall CT w/ seating nipple @ 4890' ID=1.438" IFish: Remnants of"D" I ,16--'~1' packer on top of 7" liner @ +I- 9-5/8", 47 ppf, N~80, BTC casing @ 7282' Cmt wth 1450 sks of cass G 7" cement retainers @ 9296', 9707', and 9925' 7", 29 ppf, N-80, BT, C liner 6925' - 10,225' Cmt with 1600 sks of class G Well Name & Number: KU 14x-6 I Lease I Kenai Gas Field, Pad 14-6 Perforations: (MD) I (TVD) I Angle/Perfs Ivertical /~',gle @KOP and DePth [ KOP I ...... Date Completed: I . RKB: .I .. Prepare.d...By: Gary Eller .... I Last Revision Date: _05/08/031 Marathon Oil Company Alaska Region KU 14x-6 Kenai Gas Field, Pad 14-6 Concentric String Installation Procedure History: KU 14x-6 is a Pool 6 tubingless completion. Following a rig workover, the wellbore will consist of 9-5/8" casing with a 7-3/4" Owen casing patch over the old Pool 3 and Pool 4 perforations. Objective: Install a 2-3/8" x 1-3/4" concentric unloading string in the wellbore bel.ow the perforations to lift static water from the wellbore. ?roeedure: . Complete NU of 6" side outlet gate valve and SSV. NU and test 7-1/16" master valve and blind flange. Complete necessary surface steps to flow via annular valves and flowline. , MIRU coiled tubing with nitrogen pump and MOC flowback equipment. Pressure test lines, BOP, and flowback to 250/2500ps~. Hold prejob safety meeting. RIH, c~rculate out completion fluid (3% KCI?) with N2 to at least 5000'. Estimated recovery is 366 bbl. Bleed off nitrogen pressure. POOH, RDMO CT. . MIRU electric line unit. ConduCt prejob safety meeting and test lubricator with MOC test skid using methanol to 1000psi. RIH w/4-1/2", 12spfperforating guns. Tie in to CBL log dated ~ Perforate the C-2 sand 4619'-4670' DIL. POOH, RDMO e-line. (safe system??) 4. Produce the C-2 perfs to sales for 1-2 weeks through annulus flowlines. Conduct static, flowing, and/or pressure buildup surveys as needed. o MIRU electric line unit. Conduct prejob safety meeting and test lubricator and BOPs with MOC test skid using methanol to 1000psi. RIH w/4-1/2", 12 spfperforatix~g guns. Tie in to CBL log dated ~., perforate the C-1 sand 4462'-4553' DIL. POOH, RDMO e-line. , NU tree including CT hanger spools on top of the 7" master valve. Have facilitSes take field, measurements of tree installation to begin fabrication of surface tie-in lines. Include BST time cycle control choke assembly in measurements. ND 2" portion of tree leaving CT spools in place. . . . MIRU CT unit to begin work to lengthen new 2-3/8", 0.125" WT coil using Marathon owned 2-3/8", 0.134" WT FF CT. Butt weld per procedure. Final 2-3/8" string should be at least 5050' in length. Spool up lengthened pipe. Build and drift BHA assembly for 2-3/8" CT. Maximum OD=3.770", min ID=2.1'' (excluding BST no-go nipple): Have PWS install plug in BST nipple. Also ensure plug pulling tool and plug will drift sample section of 1-3/4" CT. RU 2-3/8" CT unit with work window and BOPs'to top of 4-1/16" 3M flanged CT hanger spool. Stab pipe and weld threaded connector to end of CT per procedure. MU BST Lift BHA including Weight bars, nipple sub, and centralizer. Conduct prejob safety meeting and test BOPs to 250/2500psi. 10. RIH with 2-3/8" tubing to 4900'. PUH measured distance from top of 2-3/8" hamger to window opening. Close slip/tubing rams. Slack off pipe weight to verify slips are holding. Bleed WHP to flow.back tmtk. Block valve closed once pressure reacl~es zero and monitor WHP to verify tubing rams are holding. 11. Open 7" window. Install slip bowl and 2-3/8" spider slips with 2-3/8" dog collar backup. Cut weephole in CT to ensure no gas ~present. Complete cut and swing the injector head to the ground. 12. Install CT connector and GS profile tool string on injector CT stub end. Pull test CT connector to 27,000 lbs. Install ABB mandrel hanger on stub end inside work window. 13. NU injector to WHA. Roll pipe forward to latch up GS profile in mandrel. Pull test to 27,000 lbs. Inspect mandrel grapple connector for slippage. Once man&el inStallation is verified, remove dog collar, slips, and slip bowl from 7" window. Close windoxv. Equalize pressure across slip/tubing rams. Open rams. 14. Slowly lower pipe to hangoff depth (measured distance from top of the hanger in the window to the top of the tubing head--mark pipe as needed to ensure accurate measurements). Once the top of the hanger is 5-6 inches above the top of the head, the locating shoulder will be 2-3" from its profile. From this point, lower the 'hanger very slowly until the Weight starts to drop on the weight indicator. This must be done . carefully as the locating shoulder will not support the entire string weight. No more than 10,000 lbs should be applied to the locating Shoulder. 15. Once the hanger is properly set in. the top of bowl of the head, run in the lower bank 'of lock screws. Torque to approximately 20 ft-lbs (6" wrench and only one hand). Over- torque will deform the hanger. Verify that all gland nuts are tight. Pull test the hanger to 10,000 lbs over string weight. If any motion of the hanger is detected, repeat setting procedure. 16. Verify seal integrity by pressure testing through the test ports in the tubing head. If this test fails, continue to torque lock screws and repeat pressure test. As a contingency, plastic injection ports can be used to pump plastic between the compression seal. 17. Once a pressure test is obtained, line up to pump KC1 water. Determine volume of remaining CT on reel. Pump down CT at 1.5 to 2 bpm with flowback open to tank. Pump to reel volume x 1.5 or until nmning tool releases. PU released tool and RD WHA. 18. Swap CT injector head to 1-3/4". Prepare 1-3/4" BHA including BST profile. Prep WHA as needed. 19. RU 1-3/4" CT unit w/BOPs and 7" work window to top of 4-1/16" 3M flanged CT hanger. Stab pipe and weld threaded connector to end of CT per procedure. Pull test connector. MU BST Lift BHA including nipple sub and centralizer. Conduct prejob safety meeting and test BOPs to 250/2500psi. 20. RIH w/1-3/4" pipe to 4890'. Use caution when nearing depth to avoid running in to 2- 3/8" BHA. Watch weight indicator closely and stop immediately if pipe weight begins to drop. 21. PUH measured distance from top of 1-3/4" hanger to window opening. Close slip/tubing rams. Slack off. pipe weight to verify slips are holding. Bleed WHP to flow back tank. Block valve closed once pressure reaChes zero and monitor WHP t° verify tubing rams are holding. 22. Open work window and install Vetco clamp style hanger on 1-3/4" CT per procedure inside window. Close window and equalize pressure across slip/tubing rams. Open rams. 23. Screw in lower bank of lock screws on tubing head. 3 TURNS ONLY. 24. Slowly lower pipe to hangOff depth mark pipe as needed to ensure accurate measurements. Watch weight closely to detect hanger landing on lock pins. 25. Screw in upper bank of lock screws to secure hanger. Pull test +/- 5000. 26. Bleed off pressure from BOPs above hanger. Watch gauges to be certain there is no pressure communication from below. 27. Once hanger is installed and. pressure tested, cut pipe with BOP shears. RD WHA. RDMO CT unit. 28. Dress cut 1.-3/4" CT leaving as much stub as possible without interfering with operation of 2" valve (probably about 6"). Install wireline entry guide if deemed necessary. 29. NU 2" tree on CT hangers. Begin instalhng surface tie-in lines and instrumenta_tion. 30. MIRU slickline unit. Pressure test to 250/1000psi. a. RIH to 4890' (nipple landing depth of 1-3/4" CT) and pull blanking plug in 1-3/4" string. POOH. b. MU string to run out the .end of the 1-3/4" CT and pull blanking plug in 2-3/8" CT at 4900' (nipple landing depth of 2-3/8" CT). RIH and pull plug. POOH. c. MU string for standing valve and setting tool for nipple in 2-3/8" CT. RIH to 4900' and set standing valve. POOH. d. MU tool string with setting tool and check valve for 1-3/4" CT nipple. RIH and place check valve at 4890'. POOH. e. RDMO slickline. 31. Open annular production to the system and observe production for 1 week. If loading is detected, open gas to lift line and Open velocity string for wing flow lined up to the test separator. Record 24 hr water production. 32. Observe and optimize lift using test gas and water production rates and time controller valve. Re: KU 14x-6 Workover Subject: Date: From: Organization: To: CC: Re: KU 14x-6 Wo¥ 'er Mon, 12 May 2003'~. 13:49 -0800 Winton Aubert <Winton_Aubert~admin.state.ak.us> AOGCC "Eller, John G." <JGEller@MarathonOil.com> Sarah H Palin <sarah_palin@admin.state.ak.us>, Randolph A Ruedrich <randy_ruedfich~admin.state.ak.us>, Daniel Seamount <dan_seamount~admin.state.ak.us> Gary, AOGCC hereby approves proposed changes to your KU 14x-6 workover (App. No. 302-386) as detailed below. All other permit stipulations apply. Winton Aubert AOGCC 793-1231 "Eller, John G." wrote: Winton/Greg - I wanted to get the OK from both of you regarding a couple of minor changes to the proposed workover of well KU 14x-6 in the Kenai Gas Field. This workover is now anticipated to begin in mid-June. The workover sundry (AOGCC #302-386) was approved 1/6/03 by the AOGCC and 12/20/02 by the USBLM. A new proposed wellbore schematic is attached. Them are three proposed changes. The first is in the method of isolating the Pool 3/4 perfs at 3548'-3802'. Instead of running a 7" scab liner with packers I am now wanting to run a 7.75" ID casing patch. The larger ID is expected to reduce production problems, particularly problems with unloading water from these highly depleted completions. The casing testing procedure will be the same following setting of the patch. The second proposed change is that 2-3/8" coil tubing will be run for a lift string instead of 2-3/8" jointed tubing. The coil tubing will be run after the rig is gone. Third, the Pool 6 perfs will be shot with wireline guns instead of tubing conveyed guns. The perforation interval is unchanged. Please confirm that these changes are acceptable to you, and call if you have any questions. <<KU14x-6.ZIP>> J. Gary Elle:r Operations Engineer Alaska Region, Marathon Oil Company 907-5(-;4:.-631.5 Orig. KB-GL: 25.06 DF-GL: 21.00' (Glacier Rig #1) APl: 50-133-20342 AOGCC: 81-92 422' FSL, 1147' FWL Sec. 6, T4N, R1 lW, S.M. Tree cxn: 4-3/4" Otis Owen casinq patch ID = 7.75", J-55 material Burst = 3565 psi, collapse = 3765 psi 3540'- 3820' Isolated Peris (behind casing patch): Pool 3: 3548'-3550' (sqz'd) 3553'-3575' 3624'-3649' 3652'-3677' 3724'-3739' 3746'-3748' (sqz'd) Pool 4: 3772'-3792' 3800'-3802' (sqz'd) IProposed Perfs (Sterling Pool 6): C1,4462' - 4533' DIL C2, 4619'-4670' DIL Squeezed Peris(isolatedin 7"liner): 9398-940O 9411-9445 9458-946O 9751-9781 9833-9843 '9953-9958 KU 14x-6 - PROPOSED IConductor: 20"@ 85' (driven) ISurface Casin.q: 13-3/8", 61 ppf, K-55, BTC casing @ 2566' Cmt with 1675 sks of class G Tubing: 2-3/8" coil tubing, 0.125" wall, 3.007 ppf, HO-70 grade, flash present Drift = 2.000" BST Nipple @ 4610' Wireline re-entry guide at 4620' Remnants of "D" packer on top of 7" liner 9-5/8", 47 ppf, N-80, BTC casing @ 7282' Cmt with 1450 sks of class G 7" cement retainers @ 9296', 9707', and 9925'. 7", 29 ppf, N-80, BTC liner 6925'- 10,225' Cmt with 1600 sks of class G PBTD-9296' TD - 10,225' Well Name & Number: KU 14x-6 Lease I Kenai Gas Field, Pad 14-6 Perforations: (MD) (7'VD) I Angle/Peris Ivertical Angle @KOP and Depth J KOP TVD I Date Completed: I RKB: I Prepared By: Gary Eller I Last Revision Date: 05/08/031 [Fwd: Etc, etc] Subject: [Fwd: Etc, etc] Date: Tue, 24 Dec 2002 14:08:54-0900 From: Tom Maunder <tom_maunder~admin.state.ak.us> To: Mike Bill <mike_bill~admin. state, ak.us> Mike, I sent you a copy of this note with regard to Marathon's proposal on no 7" rams and why they don't need them. I have put the sundry and the back up PTD in your box so you can get them if you need them. The sundry will need to be approved prior to the new year. I suspect that they plan to start the rig as soon as practical after the 1st. I have asked the Inspectors to send their thoughts to both of us. Not having ram coverage is a touchy issue. My original note has the out of state phone number for me if you need it. I will be in state until Saturday morning. Happy Holidays. Tom Subject: Etc, etc Date: Tue, 24 Dec 2002 14:05:45 -0900 From: Tom Maunder <tom_maunder~admin. state.ak.us> To: AOGCC North Slope Office <aogcc__prudhoe_bay@admin. state, ak.us> CC: Mike Bill <mike_bill~admin. state.ak.us> Hello All, Merry Christmas. I will be in California 12/28 thru 1/4. If you need to call, the number is 760-340-6057. There are little "bricks" of fudge in your mail boxes from Linda Lassch. There is one issue out there that may come up in the early new year. Marathon is proposing a workover on a Kenai gas field well. It is a low pressure situation, ~160 psi on surface, and they propose to isolate to depleted sets of perfs using a 7" scab liner. No real problem with that, but they can only get 1 set of pipe rams under the rig and are proposing running the 320' (8 joints) of 7" liner with no ram coverage. They have provided an "application" requesting approval of this. I have faxed the documents to Jeff and the NS office. John Spaulding has a hard copy and I have put hard copies in JC's and Chuck's boxes. Please have a look at these and let me and Mike know your thoughts. One thought I have is, would it be appropriate to have 7" rams rather than blind rams?? That would give us the pipe ram coverage. Tom Tom Maunder <tom maunder~admin, state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 2 12/26/2002 8:35 AM Alaska c~usiness Unit Marathon OilCompany P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 December 20, 2002 Mr. Tom Maunder Alaska Oil and Gas Commission 333 West 7th Ave Suite 100 Anchorage, AK 99501 RECEIVED Dear Mr. Maunder: DEC 20 2002 SubjeCt: Naska 0il & Gas Cons. Comrmssion Well KU 14x-6 Anchorage Kenai Gas Field, Pad 14-6 . Well Control During Workover While Running a 7" Scab Liner The purpose of this letter is to address concerns related to well control while running a 7" scab liner during a recompletion of well KU 14x-6 inthe Kenai Gas Field. Well KU 14x-6 will be completed in the Sterling Pool 6 as an annular producer up the 9%" casing and 2%" tubing strings. Existing Pool 3 and Pool 4 perforations will be isolated using a 7" scab liner with packers. The total length of this 7" liner is approximately 320'. The concern is that Marathon will be unable to install a set of pipe rams for the 7" liner as required by 20 AAC 25.285(c)(2)(A)(i). The height of the tubing head on well KU 14x-6 will not allow a separate set of pipe rams to be installed specifically for the 7" liner, although pipe rams will' be in place for the 4" work string. Neither are variable-bore rams available that will span the range from 4" and 7" diameter pipe. Therefore, Marathon requests that the commission review the following information to authorize a variance in accordance with 20 AAC 25.285(h), which reads: "Upon request of the operator, the commission will in its discretion, approve a variance from the requirements of this section if the variance provides at least an equally effective means of ensuring well control." Anticipated Formation Pressure Well KU 14x-6 is currently completed in the Sterling Pool 3 and Pool 4 reservoirs. The maximum formation pressure in these two interVals is about 200 psi. This formation pressure estimate is highly reliable and verifiable given the large number of completions currently producing from both of these pools and an extensive production history. This pressure .equates to a gradient of 1.3 ppg EMW With a maximum possible surface pressure of 160 psi. Environmentally aware for the long run. Primary_ Well Control While Running 7" Liner The primary well control measure that will be used while running this 7" liner will be maintaining a hole full of kill weight fluid. The only open perforations in well KU 14x-6 are those that will be isolated by the 7" scab liner. Therefore, Marathon will employ lost circulation material (LCM) as needed to control losses to these perforations prior to running the 7" liner. Experience has shown that we can successfully control fluid losses in these zones, and Marathon will not run the 7" liner without being able to keep the hole full. Until the 7" liner is suspended on the work string and below the BOPE, a continuous fill trip tank will be used to ensure that the hole remains full. Secondary Well Control While Running 7" Liner Marathon will have available on the drill floor a valve capable of making up onto any pipe that is run, which includes the 7" liner, 6¼" drill collars, and 4" work string. In the event of a kick, this floor valve will be stabbed onto the pipe that is being run, then the valve would be closed. The annular preventer would be closed on the 7" liner or the 6¼" drill collars. A surface pressure of 160 psi acting on the area of the 7" liner (i.e. 38.5 in2) will produce a lifting force of 6,160 lbs. This would be opposed by the weight of the 7" liner and packers being run, which is approximately 7,400 lbs for the full 320' of liner. Therefore the weight of 7" liner itSelf is adequate to balance the piston force on the liner during a kick. The weight of the top drive and traveling block could also be used to assist in holding the liner in place during a kick. Summary Marathon believes that the low bott°mhole pressure of well KU 14x-6 combined with the short length of proposed 7" liner, the ability to maintain a ful1 column of kill weight fluid, and the ability to shut-in the well with an annular preventer constitutes an equally effective method of well control as that outlined in 20 AAC 25.285(c)(2)(A)(i). Accordingly, Marathon reqUests that a variance be granted for well KU 14x-6 allowing the 7" liner to be run without 7" pipe rams. If further information is needed, I can be reached at 907-564-6315 or jgeller~marathonoil.com. Skncerely, , Senior Production Engineer bjv Re: KU 14x-6 Proposal Subject: Re: KU 14x-6 Proposal Date: Wed, 18 Dec 2002 10:53:09 -0900 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: "Eller, John G." <JGEIler@MarathonOil.com> Gary, Thanks for your quick reply. Numbers 1 and 3 will answer my questions. #2 is a different animal. You correctly point out that the liner is short, but I believe the regs specify 1 set of pipe rams for each tubing, casing and DP [20 AAC 25.285 (c) (2) (A) (i)]. Liner is defined as casing [(20 AAC 25.990 (37)]. 20 AAC 25.285 (h) provides, "Upon request of the operator, the commission will, in its discretion, approve a variance from the requirements of this section if the variance provides at least an equally effective means of ensuring well control." I suggest you get with the drilling folk to prepare a request with regard to meeting the requirements or describing what mitigating steps/prodecures you will have in place to allow us to find that you have "provided at least an equally effective means of ensuring well control." Please call with any questions. Tom Maunder, PE AOGCC "Eller, John G." wrote: > Tom - Thanks for looking over my proposal so quickly. I hope this answers your questions. > > 1) The static BHP for Pool 6 is about 375 psi, and shut-in pressure is something like 240 psi. Slightly higher than the Pool 3/4 perfs we are isolating. > 2) The height of the tubing head will not allow installation of the single gate ram in the substructure. We've looked at an 11" stack and a 13-5/8" stack, and since the 11" stack really didn't buy us any extra room we elected to use our standard 13-5/8" stack. Our variable bore rams only cover 2.875"to 5.5". It is such a short length of 7" (about 320') that I didn't view it as a significant well control risk. Of course we can shut the annular preventer on any of our tubulars including the 7" liner. > 3) I meant to generate the erosion/corrosion letter and forgot about it. I'll do that today or tomorrow. ..... Original Message ..... From: Tom Maunder [mailto:tom maunder~admin, state, ak. us/ Sent: Wednesday, December 18, 2002 7:14 AM To: Eller, John G. Subject: KU 14x-6 Proposal Gary, I have looked over your proposal and have a couple of questions. 1. What is the anticipated SI pressure for Pool 6?? I know I have looked at a number of these annular flow proposals, but I am not certain if that pool is one of the Iow pressure ones. 2. You will be running a short 7" liner to effect the straddle/scab. You initially NU with only 2 sets of rams and a hydril. I don't see that you are installing the 3rd ram. How is it proposed to have rams that cover your DP (4'') and the 7" liner?? 3. With this being proposed as annular flow, the erosion/corrosion "statement/determination" that you have provided with other applications should be submitted as well. Thanks. Please call with any questions. ~¢~~.~., ,,1~ ~ /~ ~.0~ Tom Maunder 1 of 2 12/18/2002 10:53 AM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend m Operation Shutdown m Re-enter Suspended Well Alter Casing Repair Well Plugging X Time Extension Stimulate Change Approved Program Pull Tubing__ Variance m Perforate ~ Other~ 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 422' FSL & 1147' FWL, Section 6, T4N, R11W, SM At top of Productive Interval v-' 407' FSL & 1160' FWL, Section 6, T4N, R11W, SM @ 4462' DIL At Effective Depth IRecomplete to Sterling Pool 6 At Total Depth 455' FSL & 513' FEL, Section 1, T4N, R12W, SM 5. Type of Well: Development X Exploratory Stratigraphic Service Datum Elevation (DF or KB) 25.06 KB feet 7. Unit or Property Name KENAI UNIT 8. Well Number KU 14x-6 (also called KDU-8) 9. Permit Number 81-92 lO. APl Number 50~ 133-20342 11. Field/Pool KENAI GAS FIELD/Pools 3 & 4 12. Present Well Condition Summary Total Depth: measured true vertical 10225 feet Plugs (measured) 9862 feet cement retainers @ 9296', 9707', & 9925' Effective Depth: measured true vertical Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured true vertical 'Length 85 2566 7282 3300 9296 feet Junk (measured) 8991 feet N/A Size Cemented Measured Depth True Vertical Depth 20" driven 85 same 13 3/8" 1675 sacks 2566 same 9-5/8" 1450 sacks 7282 7194' 7" 1600 sacks 6925'-10,225' 6879'-9862' RECEIVED Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) DEC 1 7 2002 Alaska 0il & Gas Cons. C0mmisaior~ .Anchorage 13. Attachments Description Summary of Proposal X Detailed Operations Program X BOP Sketch X 14. Estimated Date for Commencing Operation 115. Status of Well Classification as: 8-Jan-03 16. If Proposal was Verbally Approved Oil__ Gas ~/''' Date Approved Service Nam~k~f Appr°ver 17. I here%that the ~_.~~ng is true and correct to the best of my knowledge. Signed ~.~j~,~,~. k~.¢,~. Gary Eller Title Production Engineer · '~ - ' FOR COMMISSION USE ONLY Conditions of Approval.-~"'Nq~ Commission so representative may witness Plug Integrity BOP Test..~ Location Clearance Suspended__ Date 12/17/2002 J Approval No. Mechanical Integrity Test Subsecjuent Form, Required 10- ~¢--j1:)'7 .... ' '' ~ ' ' ~ "' Commissioner Date Approved by Order of the Comm~smon ,o,m ~0-403 R~v. od/is/88 ORIGINAL SIGNED BY ~GANNED JAN ~ A ~t r. Tri~jicate RBDMS BFL 9 2003 Marathon Oil Well KU i4x-6 BOP Stack IFIow Nipple 13 5/8" 5M Annular Preventer 13 5/8" 5M Double Ram Preventer Flow Line [~- IPip~R~m I ~-- IBlind Ram I ]2 1/16" 5M Manually J Operated Valves ~> 3 1/8" 5M Hydraulically Operated Valve < ~C;ANNED JAN ~ A 2OD3 3 1/8" 5M Manually Operated Valve . LONG STRLNG: !. 3 1/2" ~':.ll sleeve- 3456' 3, 3 112" blast j=s f/ 3546-3582' 3613-3~92' 3706-3745' 4. 3 1/2" C~is "'~1",, sleeve- 3745' '---- 12 "31"8" C. 2566~ ~a:or Sub -3754' 2 5f8" ~e~. model "D" P¥-~- 3756' I/2" Sea! .~s~y- f/ 3755-3766' !/2" G~de $~- ~766' ~' ~ re~ - ~296" 7" ~ ret - 9707' 7:" ~ ret- 99'25' , A. 3. 1/2" ~is "XA" sleeve ~ 13462' B. 3 ~'/2" ~::s: "~" nipple- 3512', ,9: ~ , iI 9/22181 7" C. I022S' JAN 4 20 D3 Cc~mplet:~: 1219/8t Orig. KB-GL: 25.06 DF-GL: 21.00' (Glacier Rig #1) APl: 50-133-20342 ~AOGCC: 81-92 422' FSL, 1147' FWL Sec. 6, T4N, R1 lW, S.M. Tree cxn: 4-3/4" Otis Lift threads: 2-3/8" EUE 8rd ITubin.q: 2-3/8", 4.7 ppf, J-55, EUE 8rd I Isolated Perfs(behind 7"scabliner): Poo13:3548'-3550'(sqz'd) 3553'-3575' 3624'-3649' 3652'-3677' 3724'-3739' 3746'-3748'(sqz'd) Pool4:3772'-3792' 3800'-3802'(sqz'd) IProposed Perfs (Sterling Pool 6): Cl, 4462' - 4533' DIL C2, 4619' - 4670' DIL ISqueezed Perfs(isolatedin 7"liner): 9398-9400 9411-9445 9458-9460 9751-9781 9833-9843 9953-9958 KU 14x-6 - PROPOSED PBTD-9296' TD - 10,225' IConductor: 20" @ 85' (driven) ISurface Casing: 13-3/8", 61 ppf, K-55, BTC casing @ 2566' Cmt with 1675 sks of class G 7" scab liner (isolating Pool 3/4 perfs): f 7", 23 ppf, L-80, BTC scab liner 3516' - 3836'. Drift = 6.241" Weatherford SLP Packers -upper@3516' - middle@3756' -lower@3836' X-nipple at 4413' (ID = 1.875") Ported nipple at 4452' Wireline re-entry guide at 4460' Fish: ' 208' of 4-5/8" OD guns @ +/- 6713' ' remnants of model D packer on top of 7" liner 16 +/- 6921' 9-5/8", 47 ppf, N-80, BTC casing @ 7282' Cmt with 1450 sks of class G /" 7" cement retainers @ 9296', 9707', and 9925' 7", 29 ppf, N-80, BTC liner 6925' - 10,225' Cmt with 1600 sks of class G 8CANNED JAN 4 2003 Well Name & Number: KU 14x-6 Lease I Kenai Gas Field, Pad 14-6 Perforations: (MD) (TVD) I Angle/Perfs Ivertical Angle @KOP andDepth ] KOP TVD J Date Completed: I RKB: Prepared By: Gary Eller I Last Revision Date: 12/17/021 Well KU 14x-6 Kenai Gas Field WBS WO.03.07934.EXP Recompletion to Sterling Pool 6 Objective: Recomplete well KU 14x-6 as a single annular producer in the Sterling Pool 6. Procedure: Mark on the tubing head with permanent marker the location of the short and long strings so they can be readily identified when the tree is removed. Remove wellhouse and ND flowlines sufficiently to move in rig substructure. Mark the cellar at the desired orientation of the new tubing head outlet. o Blend LCM pill as per M-I recommendation. MIRU pump truck onto KU 14x,6. Bullhead down the LS and SS tubing to kill well. LCM Pills with field water. Also, make sure annulus is full Leave +200 Psion annulus when done. . MIRU slickline on LS, lubricatOr. RIH with a 2.70" tag fill, POOH. (Note: Last fill at 6822' on 4/30/99.) plug and setin the XA sleeve (D = 2.75") at 3745'. POOH. plug setting with a check-set tool. POOH, RD from LS. POOH, · slickline. ;e ring to an XX proper , Blow down trapped pressure on KU 14x-6 tubing string. MIRU APRS pipe recovery, unit on the longstring. RIH with jet cutter for 3½", 9.2 ppf tubing (OD = 2.625"). Tie'in with CCL to the top of the .¢mifp~cker at 3492'. Cut the longstring tubing below the dual packer q[t/35'l 8~'~,- "which is within 3' of the top of a full tubing joint. POOH, RD from longs~ o RU APRS on'shortstring. RIH with tubing punches for 3 ½", 9.2 ppf, L-80 tubing. Tie in with CC1 to the dual packer. Punch 12 circulating holes +3' above the dual packer. Monitor pressure on annulus during firing. POOH, RDMO APRS. o Call out Vetco wellhead rep. Bleed off any remaining tubing and annulus pressure. Set 3" BPVs in the LS and SS tubing strings. Prep the tubing hangers by working the lock-down pins. Pressure test tubing hanger seals. MIRU drilling rig. Prior to ND tree confirm that no trapped pressure exists below the BPVs. ND tree. Inspect lift threads on tubing hangers. (Note: Records are scarce, but apparently both strings have 3 ½" buttress lift threads. Inform Company Man immediately if different lift threads are different than expected.) NU DSA (11", 5M x 13~/8'', 5M), 24" spacer spool, and 13%", 5M BOPs. Lower single gate rams will not be installed. Upper pipe rams should be e_quip, pe~d~g~h SCANNED .lAN ~ ~ Zuu~ Well KU 14x-6, Recompletion Procedure WBS - WO.03.07934.EXP Page 2 dual '~ ~/'' ~/2 , 5M pipe rams. Install dual mousehole. Pull LS and SS BPVs, set 2- way checks. PU dual joints of 3½" tubing and screw into dual test bushing for testing dual pipe rams. Test BOPE to 250/3000 psi.'~LD test joints, pull 2-way checks. . RU dual elevators, dual spiders, dog collars, and integral tongs for pulling both strings of 3½", 9.2 ppf, L-80, buttress tubing. MU dual 3½" IBT lift joints into tubing hanger. Load hole with field water and establish circulation down the shortstring tubing (through the sliding sleeve). Apply LCM pills as needed. , PU on LS tubing to release A-5 dual packer at 3492'. All tubing is 3½", 9.2 ppf, -/ L-80, special-clearance, non-upset IBT, which is rated to 159 mlbs ofjoint strength (100%). Coupling OD is 3.865". (Note: The OD of the XA sliding sleeves is apparently 4.28", which is probably too large to pass each other in the 9%", 47 ppf casing. Well records are unclear.) If unable to release packer, RIH in ppf tubing. Cut SS at 3441' (+25 Verify that the SS tubing is free, ~d free dual packer. 1/" /2 , 9.2 .g sleeve). POOH. again to attempt to stillwont' cOme free, RIH in LS with chemical cutter for ~/" D/2 , 9 . Cut the LS at 3341' (± 100' above the cut in the SS tubing, near.the top of a full tubing joint). down all used 3½" tubing. (Note: :N:O need touse thread protectors as strings will be junked.). Take occasional measurements for NORM while TOH. :: Note: The remaining recompletion procedure assumes that the A-5 dual packer came out as designed. Modify the procedure as needed for recovering the dual packer - see separate fishing procedure from Baker Oil Tool. If the dual packer cannot be pulled>~ there is a high likelihood that the well will be sidetracked from a proposed kickoff :: Pbint of 2700'. A separate drilling permit and procedure is being prepared. RD d~i :tubing handling equipment. RU single elevators, slips, and tongs for running 4", 14.0 ppf, S-135, HT-38 workstring. Lay out, tally, and rabbit 5500' of 4v ~orkstring. :: :: i~i:P~i:l dual mousehole. Close the blind rams. Replace the dual 3½", 5M rams in the upper pipe rams with variable-bore (2.875" to 5.5") 5M pipe rams. Install single mousehole. Open blinds, install test plug, and test BOPE as needed. Pull test plug. $C/4~h!1~ JA~ ~, 4- 2[~03 {' Well KU 14x-6, Recompletion Procedure WBS - WO.03.07934.EXP Page 3 13. PU 300' of 8¼" wash pipe. TIH with wash pipe on 4" drill pipe. Wash over remaining 3½" tubing and blast joint to the top of the model "D" packer at 3756'. Circulate clean. POOH, laying down wash pipe. 14. PU overshot for 3½" tubing and fishing jars. TIH, latch fish. Jar loose to release packer seal assembly. POOH, LD overshot and fish. 15. PU packer milling assembly and TIH. Mill up model "D" packer at 3756' and push remnants to bottom of hole (at least below 5000'). 16. MU 8 ½" bit and casing scraper. TIH with bit and scraper on 4" workstring to +5000'. Circulate bottoms up. TOH standing back drill pipe. 17. PU Weatherford SLP scab liner packer assembly as follows. Rabbit all 7" casing joints on location. RIH with liner assembly on 4" drill pipe. Do not RII-I faster than fpm to prevent packer from prematurely setting. a. SLPL lower packer b. two joints (i.e. 80') of 7", 23 ppf, L-80, BTC Casing c. SLP middle packer d. (i.e. 240') ofT' Casing: ., if, ii runmng tool o-ring test sub g. six stands of 6¼" drill collars (Note: '9%" SLP packers require minimum of 25,000 lbs weight to set. Confirm with the Weatherford hand about specific pinning for this three-packer configuration.) (Note:.The middle packer in the scab liner BHA will isolate the Pool 3 and Pool 4 perfs behind the scab liner.) the.middle packer of the scab liner at +3756' between the Pool 3 perfs / -3739') and Pool 4. perfs (3772'-3792'). The lower packer should be at 836' and .the upper packer at 4-3516'. Rotate ¼ tums to the right and slack off : : to setthe lower packer. Do not pull the packer assembly in tension once the setting process has begun. Once the lower packer is set, can apply pressure down the drill pipe to test the lower SLP packer. · : 19. Continue slacking off weight to set the middle and upper packers. Verify that the observed setting stroke indicates that both the middle and upper packers set. Release from the packer by pulling to neutral weight, and turn to the left ¼-turn to un-jay the running tool. Stand back two or three stands of drill pipe, close the pipe rams and pressure test the scab liner to 2000 psi. Bleed off pressure, open the pipe rams. Note: After setting the scab liner, the drift through the 7" liner will be 6.241". Well KU 14x-6, Recompletion Procedure WBS - WO.03.07934.EXP Page 4 20. PU storm packer for 9%", 47 ppf casing. RIH with storm packer on 4" work string just below the existing tubing. Set packer by ¼-rotation to the right and setting down weight. Release from storm packer by continuing to rotate to the right. LD running joint. 21. ND BOPE and 24" spacer spool. ND DSA and old 11", 5M tubing head. NU new 11", 3M tubing head. (Note: The 6" outlet on the new tubing head should point east. Look for a paint mark on the cellar wall.) NU BOPE. Upper and lower pipe rams are still equipped with single variable-bore pipe rams. Close blinds and test tubing head flanged connections to 250/2000 psi against storm // packer. Set test plug in new tubing head, test BOPE as needed to 250/3000 psi.' Pull test plug. 22. PU joint of drill pipe, engage and pull storm packer. LD storm packer. TOH f laying down drill pipe. LD packer running tool and: 6¼" drill collars. 23. Close blind rams. Install 2%", 5M pipe rams in upper pipe rams. Open blind rams, PU and set test plug in new tubing hanger. Retest BOPE as needed. 24. RU single elevators, slips, and tongs for running 2%", 4.7 ppf, J-55, EUE 8rd tubing. 25. Prepare to PU Halliburton TCP guns, conduct prejob safety meeting. RIH with completion string on 2%", 4.7 ppf, J-55; EUE 8rd tubing. Completion string is as : · follows: a. Bull plug b. 51' of 4%", 6 spf, 60° phase guns (C~2:Sand, 4,619' -4,670' DIL) c. 86' of 4%" blank d. 71" of 4%", 6 spf, 60° phase guns (C-1 Sand, 4,462'-4,533 DIL) e. ' of blank guns f. auto-release feature for 4%" guns g.:: re-entry guide h. drop-bar firing head with 1.56" no-go i. 2%" pup joint (6') j. 2%" ported pup joint (3') 2%" pup joint (6') ') 2%" tubing joint (31 X-nipple (1.875" profile) 2%" pup joint (6') 2%" tubing joint (31 ') with RA tag 2%" tubing to surface 2%" pup joint (pin by pin) tubing hanger with BPV profile ..lAN Well KU 14x-6, Recompletion Procedure WBS - WO.03.07934.EXP Page 5 Note: The ~s/,, -,/8 , 6 spf TCP guns are equipped with a drop-bar firing head and auto-release head. After firing, total length of guns dropped to bottom is approximately 208'. The guns are loaded with __. grn DP charges with an expected entrance hole size of " 26. MIRU electric line unit to tie-in TCP guns. Conduct prejob safety meeting. Tool string needs to be larger than the 1.56" no-go on the drop-bar firing head. RIH with gamma ray correlation log. Tie in with CBL log of / /. Determine pipe movement required to put guns on depth. POOH, RDMO electric line. 27. Install space out pups and tubing hanger. Land 2%" tubing. 28. Install BPV in tubing hanger. ND BOPE, NU tree..(Note: The wing valVe on the tree should point west, opposite of the 6" outlet on the tubing head:) :Pull BPV, install 2-way check in tubing hanger. Test tree to 3000 :psi using methanol. Pull 2-way check, reinstall BPV. RDMO workover rig, 29. Remove 7-1/16", 3M ' " ' ' ' bhnd flange. Pull 6 BPV ~n tubing head s~de outlet. Pull st '" ~ : : BPV from tubing nng. NU 7-1/16 3M valve and remmnder oftree valves. NU 30. MIRU nitrogen pump onto the 9%" casing and flowback tank onto the 2%" wing valve'. Pressure test lines and lubricator to 3000 psi. Hold prejob safety meeting. Reverse out completion fluid using nitrogen through the ported pup. Do not exceed 2000 psi casing, pressure. Total estimated .recovery = 308 bbl. After unloading completion fluid, shut in returnS and continue to pressure up with nitrogen to 1500 psi on the tubing and 9%" casing. RDMO nitrogen pump. 31. MIRU slickline lubricator and load with 10' x 1¼" drop bar. Hold prejob safety meeting and pressure test. Open the swab valve to drop the 1¼" bar. (Note: Need minimum of 1500 psi casing pressure when bar is dropped in order for gun release system to activate.) Listen for confirmation of detonation of the 4%" guns. When confirmed, produce the Pool 6 perfs up the tubing until satisfied that they are cleaned up: RD flowback lines and tank. Produce well to sales. JGE - December 17, 2002 SCANNED J A N ~ z~ 20 03 Re: Isolation of Existing Perfs During Recompl,efion Subject: Re: Isolation of Existing Perfs During Recompletion Date: Thu, 12 Dec 2002 14:03:00-0900 From: Winton Aubert <Winton_Aubert@admin.state.ak.us> Organization: AOGCC To: "Eller, John G." <JGEIler@MarathonOil.com> CC: Thomas E Maunder <tom_maunder@admin.state.ak.us> Gary, AOGCC believes your KU 14x-6 production isolation proposal described below is acceptable. either me or Tom Maunder if further discussion is desired. Please contact Winton Aubert AOGCC 793-1231 "Eller, John G." wrote: Winton/Tom - I want to run something by you to see if it would be acceptible for a workover sundry I shall soon submit. The well is KU 14x-6, a dual producer in the Sterling Pool 3 and Pool 4 in the Kenai Gas Field. Both Pools have static BHP of 250 to 300 psi. The recompletion would be to the Sterling Pool 6, which has about 400 psi of pressure and is deeper than the Pool 3/4. I was going to isolate the old Pool 3/4 perfs with a scab liner, but then I realized that I have two seperate pools and they would be communicated behind the scab liner. The Pool 3/4 perfs are seperated by only 33' (perfs are 3553'-3739' and 3772'-3792' for Pool 3 and 4, respectively). What I propose to do is to still use a scab liner, but include an isolation packer in the middle of the scab liner that would isolate the Pools 3 and 4. However, with the way that I want to run this, I won't have any means to pressure test that middle isolation packer. I will be able to test the upper and lower scab liner packers. I will be able to confirm that the middle packer properly set (it's a weight-set packer in a vertical hole), but I couldn't pressure test it. I believe knowing the packer is set without a specific pressure test would be adequate and will meet the intent of the rquirements, especially since there is minimal pressure differential between these two highly depleted Pools. There is a way to construct the scab liner so that I could pressure test the middle isolation packer, but it will add significantly to the cost and rig time. I have also looked into squeezing these Pool 3/4 perfs, but I think that the likely cost of squeezing them would make the workover uneconomic. This scab liner would obviously not suffice for permanent plugging of either Pool 3 or Pool 4 perfs in KU 14x-6. That is not it's intent. The scab liner is strictly there to allow me to cost effectively produce the Pool 6. Marathon plans to begin this workover in January. Please let me know right away if you think that this is not an acceptable means of isolation in this instance. J. Gary Eller Operations Engineer Alaska Region, Marathon Oil Company 907-564-6315 JAN 4 200,,,' 1 of 1 12/20/2002 9:11 AM Unocal Oil & Gas Division' Unocal Corporation ~, P.O. Box 190247 ~' Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Alaska District DOCUMENT TRANSMITTAL April 15, 1987 HAND DELIVERED TO: Fran Jones FROM: R.C. Warthen K. D. Kiloh LOCATION: Anchorage LOCATION: Alaska DiStrict ALASKA OIL & GAS CONSERVATION COMMISSION Transmitting: REGARDING: Kenai Gas Field One magnetic tape and LIS verification listing PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY OF THIS DOCUMENT TRANSMITTAL. THANK YOU. RECEIVED BY: D A T E D: RECEIVED ,,..;?R 1 6 1987 Alaska Oil & Oas Cons, CommiSsion Anchorage January 13, 1983 ~{r. R. J. Peterman, Manager Regulatory Co~Ipliance Marathon Oil Company 539 South Main Street Findlay, Ohio 45840 Dear }~r. 'Peter~an: Januazy I1, 1983 we received applications for cataMory d. eter~in- ations under the '~ ~.,atural Gas Policy Act for 13 wells within the Kenai Gas Field, all dated January 6, 1983. Obviously these submittals crossed in the m. aiI with our Ja~n.~ary 5, 1983 response to your Decca.bet 31, 1982 application for KDU ~'.~o. 8 (14~-6). Accordingly, please request Union Oil Company of California as vzelt operator to resubmit your applications in conformance witb~ our Deter~ination Procedures. Regarding the appropriate j~.~risdi.ctional agency ~,gith ~,~hicb~ to file, ~e are of. the opinion that Subpart E § 274.501(c) may provide the clarificat~ion that you are seeking ~.~hich in part fo ! 1 ows: "(c) Federal Lands. For purposes of this section, 'Federal lands' r~eans (I) alt lands leased "under: (i) the l,?~inerals Lands Leasing Act, as amended by 30 U.S.C. ~ ~ 181 et seq.~ and (ii.) the .~lr~.er.al~ Lands L~asip~ Act for Acquired Lands, as a~ended, 30 L~.S.C. ~ § 351 et seq.~ and '~ ~'~ sugge~ts that the determination of the appropriate diction a~ency is a function of the original lessor Accordingly, ~,~e interpret the above to indicate t'bat the A].a~ka Oil and Ga,~, 6onserv~tion ~-~' Com~.~.~ssion is the jurisdictional agency only for ~ells [~r[t 11 17 and KU 13-8: both on ~.~,ta.t,e of Mr. R. J. Peterm~.. Page 2 January 14, 1983 Alaska lease ADL 22330. However, should your interpretation be otherwise, we will be pleased to act upon your applications once they are submitted by the operator. Sincerely, (~,..~.~ ..... ,, I / /,?' t t .,,,/'/ :': (>/'.,',;, ./5"..'.,:./.:..'2'.. '/'"''.,, .... ~../,4,.:t..?¥'":..": '~' ~ .... C, V, Chatter'ton Ch. airr,~an cc: R. T. Anderson Union Oil Company of. California b~ ~anuary §, 1~83 ~.!r. R. J. Peterman, ~anager Regulatory Compliance ~,{arathon Oi I Company 539 South ~{ain Street Findlay, Ohio 45840 Dear ~'~.~r. Peterman: Thank you for your December 31, 1982 application f.or catagory determination for Kenai Deep Unit ~;~ell No. $ (KU No. 14X-6). Our Natural Gas Policy Act ':Determination Procedures as filed with the Federal Energy Regulatory Commission (FERC) provide for eatagory determination applications to be filed only by the operator of the t~ell. ~/e have solicited comments fr~laska operators regarding ibis limiting feature, but as yet have no conclusive response to our request. ~egardless, suspect the time required to file and Obtain FE~,C approval of an amended determination p~oeedure ~ould be too lengthy to ~erve your purpose, Accordingly, p.lea~e request U'nion ()il Co~pa.ny of California, the operator of well. gDU No. 8 (KU No, 14X-6)to re-submit your application. cc: Fi. T. Anderson, Union Oil Company of CaIifornia be STATE OF ALASKA' i ' ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well - OIL [] GAS ~L-~ SUSPENDED [] ABANDONED [] SERVICE [] - 2". Name of Operator 7. Permit Number UNION 0IL CONPANY OF CALIFORNIA 81-92 3. Address 8. APl Number PO BOX 6247 ANCHORAGE AK 99502 50- 133-20342 --, 4. Location ~ well at surface 9. Unit or Lease Name 422'N & 1147'E of SW corner, Sec. 6, T4N, RllW, SM. KENAI DEEP UNIT , At Top Producing Interval 10. Well Number ~ (KD #14X-6) At Total Depth 11. Field and Pool 455'N & 513'W of SE corner, Sec. 1, T4N, R12W, SM. 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. KB +90' MSL A-028142 KENAI GAS FIELD -- , 12. DateSpudded 13. DateT.D. Reached 14. DateComp.,Susp. orAband. 115. WaterDepth, ifoffshore 116. N°.ofCompletions 9/22/81 10/27/81 12/6/81I ]--- feet MSL 2 17. Total Depth (MD+TV'D)10225' & 9880' 18. Plug Back Depth (MD+TVD)___ YES19' Directional Survey,~ NO [] I20' Depth where SSSV setfeet MD I21' Thickness Of PermafrOst ,, 22. Type Electric or Other Logs Run DIL-SONIC-GR, FDC-CNL-GR, HRD-O~pmeter,. CBL-VDL-GR 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM ~.HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 94 Plain Surf. 85 Driven ...... 13 3/8" 61 K-55 Surf. 2566 17 1/2 1675 sxs --- , 9 5/8" 47 N-80 Surf. 7282 ~. 12 1/4 1450 sxs --- 7,, 29 N-80 6925 10225 8 1/2 1600 sxs -.-- , ,, 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 (M'i~) ..... 8 HPF Perforations 3 1/2" 3766 ' 3756i 3553 tO 3575' TVD 3 1/2" 3512 3506, 3624 to 3649 3724 to 3739 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 3652 to 3677 3772 to 3792 DEPTH INTERVAL (MD) AMOUNT & KIND OF I~/IATERIAL USED See attached 9Z~] ]-9445 6000 o~]]nn.~ m~d ~nid . 27. PRODUCT'ION TEST . Date First Production' I Method of Operation (Flowing, gas lift, etc.) 12/10/81I Flowing ..... Date of:l'est Hours Tested 'PRODUCTION FOR !OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO 12/13/81 24 TEST PERIOD ~ r'-- 24900 ...... ,, FI°w Tubing Casing Pressure CALCULATED OIL-BBL', ' GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 980 ---- 24.HOUR RATE ~1~ __ 24900 -- 28. CORE DATA , NONE OCT :t982 /!,, ..~.:.~.,, .., ,,, .,,,, . Form 10-407 Submit in duplicate ,~i~ Rev. 7-1-80 CONTINUED ON REVERSE SIDE L'"' , , 29. 30. 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. T/Sterling Fm. 3542' 3542' D-4 sd. Perfed 9953-58' DIL. Rate 0.55 Gas Sands MMCFPD ~ 300 psi tbg press thru 3" choke. Shut-in surface pressure 1135 psi. T/Beluga Fm. 4698' 4698' T/Tyonek Fm. 7412' 7313' D-3 sd. Perfed 9833-43' DIL & 9751-81' DIL ,,. Rate 1.6 MMCFPD ~ 175 psi T/Tyonek "D" 9210' 8924' w/ 28.8 BWPD. Four hour buildup resulted Zone in a surf pressure of 3255 psi. D-2 sd. Perfed 9411-45' DIL(. Stabilized rate of 3.7 MMCFPD ~ 387 psi w/ 4.8 BWPD. Pressure buildup resulted in a reservoir pressure of~ 1329 psi. Acldized w/ 600 g'als mud acid. Max rate achieved was 4.59 MMCFPD ~ 800 psi. 31. LIST OF ATTACHMENTS , , , ' 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ... Title / , - -- .... INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24' If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only 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 cement- ing and the location of the cementing tool. Item 27' Method of Operation' Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Well Completion Report KDU #8 (14X-6) 1/6/82 #26. 3548-3550' 3746-3748' 3800-3802' 9398-9400' 9411-9445' 9458-9460' 9Y51-gY81' 9833-9843' 9953-9958' 750 SXS CL "g" 250 " " " 250 " " " 170 " " " 167 " " " 170 " " " 50 " " " 50 " " " 170 " " " OCT1 1,982 Alaska Oi~ & Gas Cons~ Ocm,mi~:,,:~m~ Anchorag~ November 11, 1981 Mr. Gary Bush Union Oil Company P. O. Box 6247 Anchorage, Alaska 99502 Re: Our Boss Gyroscopic Survey Well No.--K~"~(SEC6 1 Kenai Gas Field Kenai Peninsula Date of Survey: November 3, 1981 Operator: Chris Willoughby Dear Mr. Bush: Please find enclosed the "Origi.~a'l" and seven (7) copies of our Boss Gyroscopic Multishot DirectionaI Survey on the above well. Thank you for giving us this opportunity to be of service. Yours very truly, NL SPERRY-SUN, INC. Ken Broussard District Manager KB/pr Enclosures SPERRY -SUN 0.00 5CRLE :- 1 INCH TO 2000.00 / 2000.0 / UNION OIL COMPRNY NOVEMBER 5, i981 B055--1691S 5 89 56 N S 89 56 N 2000.00 4000.00 6000.00 8000.00 ~0000.00~ VERTICAL SECTZON -9500 20~10. O0 VERTICAL PROJECTION OCT z, 1982, SPEBBY -SUN SCRLE :- ! INCH TO 200.00 / 200.0 / /~ / NaVEMSER 5, 1981 8aS$-16919 s 89 s~ ~ s 8~ s~ ~ 9500 -looo. oo -800. oo -60[. aO -40~. O0 -20o. O0 HOBIZONTFtL PfiOJECTION TRUE NORTH oo.00 SPERRY-SUN INCORPORATED OPERATOR-CHR I:3 WILLOUGHBY PAGE ........................ -~---~-~[~N--~ i. i-~. COMPANY K-OU-ee l,~Iy Y¥./ TOTAL DIRECTION ANGLE DEPTH DEO MIN DEO MIN · 7100 S 87 36 W 29 8 7200 $ 87 24 W 29 45 7300 S 88 30 W 28 36 7400 $ 89 30 W 28 43 BOSS-1691 NOVEMBER 3, 196 VERTICAL DEPTH ~AT~TUDE .... ']3£P~RTu~'~ .... V~i~-~r-I CAL DC FEET FE£T SE¢I'ION L~ 7035.02 42.91 7122.11 45.06 7209.41 46.81 7297.16 47.65 8 sse. 73 w 401.22 0.~ 447.44 14 449.76 1.2 F~:'~-~"~-' 497.44 O. 4 7600' N 89 12 W 27 58 7473.41 7700 N 89 30 W 27 27 7561.94 7800 N 88 0 W 27 1 7650.85 :.i!~:~'~'': ' ":7900 ~ :~': N: 87 7739.72 48'10 542.94 W 544.67 0.6 47.49 S 636.40. W 637.31 O. 5 46.50 S 682.15 W 682.58 0.8 44.49 727.96 W. 727.77:0-7 ;::' ,.:/.:8000 :.:N 85 .42i~;:,W.: :27,:23 .7828.43- 41.56 S 774.00 W 773..08 0-6 8100 N 86 18 W 27 10 7917.32 8160 N 86 12 W 27 3 8200 N 87 48 W 26 46 7970.73 8006.39 8300. S 87: 42:'W 26. 37 8095.74 :~:::;'84,0:0: :s 88 23 :8:185.23 8500 N 88 12 W 25 58 8274.98 36.57 S 846.98 W 844.86 0.2 35.63 S 865.06 W 862.67 1,9 ......... ~;"~""~ ~;-~'~'""~ ...... 907.22 2.0, 37.03 $ 954.56 w 951.~4 o.",5 · · ........... ~-~-:§b"'"~ ~'~,'"~'~"""~ .............. ~-2~ ........ 8600 N 88 0 W 25 49 8667 N 88 30 W 25 53 8364.94 8425.23 :: ;:8700 N 87 IS::W ::':25' 49 ,84~4,93 8900 N 86 42 W 26 14 9000 N 85 36 W 26 8 9100 N 84 30 W 26 23 8634.51 8724.24 8813.92 9200; 'N:84 12:14 ;2~: 9 8903.97 9300 N 82 25 3 8~94,52 35.36 S 1042.30 W 1038.47 0.1 34.46 S 1071.50 W 1067.33 0.3 33.94 S 1085.87 W 31.83:!.Si: 1129.67 W 11'24 29.48 S 1173.79 W 1168.19 0.2: 26.52 S 1217.82 W 1211.49 0.4' 22.70 S 1261.90 W 1254.75 0.5~ 18.42 S ~-~':"~'W 1297.13 1,21 , 13.55 S 1347.30 W 1338.32 .................... 9400 N 81 30 W 24 17 9085.39 .... 7.78"$ 1388.64 W' 1378.61 0.8' 9500 N 82 0 W 23 13 9176.92 2.00 ~ 1428.50 W 1417.43 1.0' 9600 N 82 0 W 21 43 9269.32 3.33 N 1466.35 W 1454.30 1.5, , .... ~ .:::9700' N 82 0 W '20 13 9362.70 8.31N 1501.7~'"W 1488.83 1.~ =' · 9800 N 82 0 W I8 43 9456.98 12.95 N 1534.78 W 1520.99 1.5~ 9900 N 8! .... ¢i-"N ....... 1"~'"'"'~8 ....... '~'~ J":"96 ..... ~7' = .................................................................................................. ~.,9 N 1565.90 14 1~;:.'-== I. 28 ................. O. ~.~" 10000 N 80 0 W 17 13 9647.22 22.58 N 1595.71 W 1580.22 0.8. ........ THE DOGLEG SEVERITY IS IN DEGREES PER ONE HUNDRED FE~ THE VERTICAL SECTION W~S COMPUTED ~LONO ~: 82 47 .......................................................................................... OCT 4 B~SED LIPON MINIMUM CURVATURE TYPE CALCLIL~TIONS. THE ,BOTTOM HOLE ' DISPLACEMENT IS 15'~5.8& FEET, IN THE DIRECTION :~l~ka'Oji~s~rr.'. B~TOM HOLE DI'.PLACEMENT IS RELATIVE TO WELLHE~[. VERTICAL SECTION IS RELATIVE TO WELLHEAD. INTERPOLATED VALUES BELOW 9500 FEET PAGE OPERATOR-CHRIS WILLOUGHBY · . UNION OIL COMPANY B05S-1691~ ~ /~ /~-~ NOVEMBER 3, 1981 TOTAL DIRECTION ANGLE VERTICAL · DEPTH DEO MIN DEC MI'N DEPTH 0 N 0 0 E 0 0 0.00 100 $ 16 24 E 0 14 100.00 400 N 58 48 W 0 12 400.00 LATITUDE DERARTURE VERTI GAL DOG . 0.00 N 0.00 E 0.00 0.00 0.21 $ ' 0.06 E -0.03 0.24 .0.54 $ 0.22. W 0.28 0.14 i3oo 'S 65' i8'E '6 "~ 'i'2~9.'99 1600 S 55 30 E 0 53 1599.96 1900 S 1 54 E 0 33 1899.94 3.66 $ 0.05 W 0.50 0.16 6.42 S 1.93 E -I.11 0.24 $ 5i :4.e:E 0 32 2499.90 2800 $.68 36 E 0 29 2799.89 S400 S 32 24 E 0 14 3399.88 9.57 s · ... :3.19. E' 12.13 S 5.4<2 E -1,96. 0.15 -3.92 O. 11 13.45 14.00 14.61 7.75 E ....... i-~ ;'"66 ....... -~J- ~"6~ 8.83 E -7.00. O. 17 9.06 E --7. 15 0.07 :!!::'~-i: "'/i!3:700 S 55 48 E 0 14 3699.88 15.45 S .~2.88 E -7.86 O. 03 78 42 E 0 13... 3999.88 15.69 S 10.~2 E -8.86 0:06 .................................... ~-~6'6 .......... ~""'~ ...... i"6'""~ ............ '6'"'"i'~ ............... ~'~'~-~";"-6~ .......................... i'~':':~'-~ ....................... i~'T~'-~ .......... :i"6':-6~ ..... 6-26~ 4600 N 6~ 36 E 0 18 45~.87 14.65 S 13.~4 E -11.50 0.02 4~00 N 22 18 E 0 l& 48~.87 1~.74 S 14.44 E -12.60 0.08 5:200 ::S:::1:4 0 E 0 7 51<29,86 13'39.6 14.77E -'12.'<27 0.'12 0 E 0 20 5499.86 13.72' S :15.73. E -13.88 0,11 5600 N 32 24 E 0 32 5599.86 13.34 $ 16.27 E -14.47 0.47 5700 S 79 18 E 0 18 5699.85 13.00 S 1~.77 E -15.01 0.50 5800 S 38 30 W I 31 579~.84 14.08 S 1&.21 E -14.32 1.&7 5850 S 63 12 'W' 3 :'7 5849.S0 15'21'::S 14,'59'E: -12.57 ..;.~.70 5900 $ 68 30 W 4 55 5899,/~'7 . : :-:9:"':2:1:'2,:67 5950 S 76' 30 W 6 2 5<249.44 18. O0 S ~. 84 E -4.53 2.70 6000 S 77 30 W 7 49 5999.07 19.35 S 0.97 E 1.46 3.57 ....................... ~i9_9 ...... S_.~.....~.__H... zo i 4 6o~7.83 22.64._.~ ................. d4,.3~_ ......... ~Z.~P=~_ ...... ;~..~..~.~. ~200 S 80 30 W 12 14 ~1~5.~0 '2&':21~ S :33,:53 W 36-55 2.05 ~300 S 82 24 W 14 29 ~2.93.19 29'&1.;:~S: : :5~.:~9. :W.. 2.29 ,_,,. ~3~1 S 85 24 W 15 49 ~381.02 32.11 S 80.03 W 83.42 1.~? 6400 S 86 6 W 15 52 6389.~8 32.29 S 82.48 W 85.87 ~'.~'-q . .. ~.5~0.S .87.4.~...N ..... .~.7....!~ 6~.85,._~0 .......... >>,_.~.~._...S. ................. U_!,_.3.~___N ........ !..~.4,721 ~5 6761 'See 12 w' 225'8' 6729.74 2.7,15 ...................................................... s OCT2~2,j~gw ........... z05.u!; ....... ~''.531 6800 S 87 42 W 23 19 6765.60 37.69 S ziS.~ W zzl.07 1~01 ........... ~ ......... ~....e~. ~e....~ ......... 2~ ..... ~..~ ......... ~.~i.~, ~.~: ............... ~.,...~,~!.~:~ :)~! ~, (~'~,~:'~W":'~:,:,:?,~43- 56 ...... !,.~.6 6949 S 87 48 W 25 55 6901.08 40.09 $ F~,~.~2 W 282.83 1.80 7000 S 87 42 W 26 54 6946.75 40.98 S 302.:68 W 305.42 1.94 12/9/81 Kenai Unit VTE]_,I, ~IO14x6 (KDU8) SpU]) DATE 9/22/81 · COMi. DATE 1S_; · Kenai Gas Field CO]'.j'['I[f~C'['Ol'[ Brinkerhoff __ 1[I(] NO.-59 ~OCATION., _~' N & 1147' E of SW TYPE UNIT Oilwell 96 Corner Sec. 6, T4N, RllW, SM DI{II..,LPiPED];;SCIIIf'TION ELEVATIONS: \V;VI'Ei[ DEIYJ'iI : IL T. TO OCI';AN FLOOR U~iiMIT NO 81-92 SERIAL NO. ~-028142 P.D. 10225 (~) T.V.D. 9880~ iI.T. TO ~,ILI.,W 9W ,. B. 31 TO ~ ~ pti ' 1596' ~ ~CSG., ~ // CASING ~e TUi)ING J3~D.. __~:. ..... - -- size ~ VJEICHT ~3, 3/8" 619 Butt K-55 2566' ~'d w~ 1675 sxs c[-"~" 9 5/8"I 47# 7" 29# 3 1/2" [ 9.2# 20" .k 9,.4~_~,-~-= Butt Butt Butt Butt Plain End N-80 N-80 J-55 J-55 7282' .0225' 3766' 85' Cmt'd' with 1450 sxs C1 "G" ~~d with. 1600 sxs C1 "G"' (T6P @ 69~5) L.S. pkr ~': 3755' S.S. dual pkr @ 3496' D__riven' P EBF O R A T.I3_.I_G EECOIID .1-5-81-D'AIE 9458-9460tlLTKEJ~/YL I 10225 iso±a~zon ..j~q z' with 170 sxs c~ .1--5281 9398--9~00 943b-- (Ret) i~blation "i~q---~*~ with 1'70 sks ci ::G:; ~ , ~i-10-8~ 9953-99'58 10050 production Sq z'd with 170 sxs cl ~.~" '(D_4 sand) .._ ~1-12-8~ 9833_9843 .... 9925 produ~{ion Sq'z'd with 100 sxs cl "G" (D-3 's'~hd) iiL12~8] 9751-9781 -- 99~-5' '"- ~roduction Sq-~?d with 10]J-SXS cl "G" (D-3 sand) i1-14-8] 9435-9445 9707 .(ret) product~0n Sq z'd with 167 sxs cl "G" (D-2 sand) ~1-15-8] 9425-9435 9707 (ret) . production Sq z'd with 167 Sxs cl "G" '(D-2 sand) 1i'16-8] 9411-944'[ '.~ .9707'"(retS-- Production Sq 'z'd with 167 s~s cl "G' '(D-2 sand),. .... .. 11-17-8] 3800-3802 .... 9-~6 isolation .' S~. Z'a With..250 sxs cl "G"',, [1-20-8] 3746-3748 9296 - - isolation Sq z'd with 250 sxs cl G" [1-21-81 3548=3'~50 9296 isolation !Sq z'd·with 250 sxs cl ~'~" !1-29-'8] 3553-3558 6915 (TOL) production ~Open for production (A-8 sd.) !1-30-8] 3558-357'5 6915 (TOL) production Open for produc, tion (A-8 sd.) ., [2-1-81 3624-3649 .... Open for production (A-10 sd.) [2-1-81 3652-3-677 ,, " Open for production (A-10 sd.) [2-1-81. 3724-3739 .... Open f~r production (A-il sd.) · [2-2-81 3772-.3792 .... IOpen for production '(B-1 sd.) INITIAL TYPE:} ~ ~ CASING HEAD: 5_0" 224 PSI SOW CASING HANGER:--B°ll-wccvS! Flow-thru ty~ 20" CASING SPOOL:_ 2M X 13 5/8" ~5M w/ double "P" Seals TUBING HEAD:_ 13 5/8" 5M X 10'; 5MDCB s~l TUBING ItANGER:_ TUBING tlEAD .TOP' MA ST EI{. VALVES:_ CItR!STMAS TRI,;E TOP CONN.: ..... LEASE Kenai Deep Unit U['IIOIi OIL CCI?/ Y OF CALIFOPJ.iIA WELL RECORD iELL NO, FIELD S EET' D PAGE ih, -" I Kenai Gas Field DATE A 9/17/8] DAILY COST- ACC COST- AFE AMT- B 9/18/81 DAILY COST' ACC COST' AFE AMT' C 9/19/81 DAILY COST' ACC COST' AFE AMT' D ¢/20/8l DAILY COST- ACC COST- AFE AMT- ~ . 9/21/81 DAILY COST- ACC COST: AFE AMT- ETD $ 240,165 $ 240,165 $2,450,000 $ 22,563 $ 262,728 $2,450,000 $ 22,121 $ 284,849 $2,450,0O0 $ 19,899 $ 304,748 $2,450,000 2~" D. 8-5' 64 PCF 180 SEC $ 34 ,'268 $ 339,016 -- $2,450,000 OF Began oPerations @ KDU //8 @ 06:00 hrs 9/17/81. Set in rig mats and sub-base. I'nstalled drawworks & //1 and //2 motors. Installed FPS unit - rigging up same. NOW- Continue rigging up. · Set in all major rig components except derrick. Continued general rig up. NOW' Rigging up. Pinned derrick to subbase. Strung blocks. Isolated pill pit and moved hopper location away from pump suction. Worked on water lines & blooey lines. Swaco rigged up completely. Began to rig up BJ cement unit. N~N" Continue general rig up. ~Raised derrick & installed wind walls. 'Water well motor burned out. Rigged up blooey line. N0'W: Continued general rig up. ! Continued general rig up. Drove 20".94// drive pipe to refusal at 85' w/ 250 BPF (53' of soil pene- tration). 'Cut 20" pipe off 4.5' below GL. Welded on 20" 2M psi 50W starting head w/ top face of flange 39" below GL. NOW: Installing diverter system & pitcher nipple.- UillOI-I OIL Ca:PAth' CF CALIFORHIA WELL RECORD -. $ :EET D PAGE ~b. ---2 Kenai Deep Unit WELL NO, KDU #8 FIELD Kenai Gas Field DATE 1 9/22/8i- DAILY COST' ACC COST: AFE AMT' 2 9/23,/81 DAILY COST' ACC COST' AFE AMT' 3 9/24/81 DAILY COST' ACC COST' AFE AMT' 4 9/25'/8 DAILY COST' CUM COST' AFE AMT: ETD 405'/405' 20" D. 85' 67 PCF 186 SEC $ 56,307 $ -395,323 $2,450,000 2397'~1992' 20" D. 85' 69 PCF 54 SEC $ 31 ,.232 $ '~26,5~- $2,450,000 2579'/182' 20" D. 85' 13 3/8" C. 2566' 67 PCF 48 SEC $ 152,336 $ 578,891. $2,450,000 -. 20" D. 85' 13 3/8" C. 2566' 69 PCF 48 SEC $ 61,640 $ 643,283 $2,450,000 .,.. DETAILS OF OPERATIOIiS, DE..SCRIPTIOt!S .& RESULTS Completed general rig up. Instal. led and checked diverter assembly for operation. Installed ~itcher nipple. Measured tools and attempted to spud @ 15:00 hrs. Mud line plugged with gravel from rig up. Cleaned out mud line. Spud well @ 16:30 hrs. 9/22/81. Cleaned out drive pipe to 85'. Took drift survey @ shoe of drive pipe @85' - 1/2°. Drilled.~-$7 1/2" hole f/ 85' to 405'. NOW: Drilling @ 405'. SURVEY. 395' -.i/2~ Drill6d 17 1/2" straight hole f/ 405' to 2397'. NOW' Drilling @ 2397'. sURVEYS· 709' - 1/8° 1013' - 1/2° 1317' - 1/2° 1615' - 3/4° 2016' - 1/2° Continued to drill 17 1/2" hole' f/ 2397" to 2579'. Circ. and pulled 11 stds. out of hole. Picked up 34 jts. of "E" d.p. and RIH - had 2' of-fill..Circ, well clean. POOH and laid down 17 1/2" BHA. Rigged up and ran 64 jts (and 1 pup) of 13 3/8" 61# K-55 Buttress casing. Set shoe @ 2566', float collar @ 2520'. Landed boll- weevil hanger 29.5' below R.T. Cut off 13 3/8":' csg. below rotary table. RIH w/ stab-in tool on 5" d.p. NOW' RIH w/ stabLin tool on 5" d. Dt : Stabbed into F.C. @ 2520'. Broke circ. and circ. hole clean. Lead w/ 50 bbls. caustic water ahead of 1425 sx. cl. "G" w/ 2 1/2% pre-hyd. gel and 2% CaC12 until had cmt returns to surface. Followed ~/ 250 sx. cl. "G" w/ 2% CaC~2 Disp. w/ 34 bbls of mud. CIP ~4'20 hrs 9/25/81. POOH w/ d.p. Removed landing joint and installed 20" 2M x 13 5/8" 5M csg. spool - spool would not land properly. Removed spool and -- inspected same. Found spool to be ~.:~,...~,~.~.~ incorrect - sealing surface not under- ~,. ~_~i1~\! i~-/~) cut back far enough. Cut off 1" of ~- neck of-hanger. Installed and tested ...~ ~. ,.-,c,spool to 2000 psi - ok ...... r,.o~.~:~ ........ ::-~N(DW~ Installing BOPE. i'..9.C:~ ..... Kenai Deep Unit Ur'IIOr-I OIL CC ?A N OF CALIFOR .iIA WELL RECORD ELL NO, FIELD S EE-[ D PAGE rb, --3 Kenai Gas Field DATE 5 9/26/81 DAILY COST' CUM COST- AFE AMT- 6 9/27/81 DAILY COST- CUM COST- AFE AMT- 7 9/28/8-i DAILY COST' ACC COST' AFE AMT' ETD - -2B89-'/lO' 20" D. 85' 13 3/8" C. 2566' 67 PCF 41 SEC / $ 34,601 $ 677,884 $2,450,000 2908'/319' 20" D. 85' 13 3/8" C. 2566' 68 PCF 54 SEC $-- -4S~2 $. 722,986 $2,450,000 3826'/918' 20" D. 85' 13 3/8" C.-2566' 70 PCF 51 SEC $ 30,685 $ 753,671 $2,450,000 OF OPERATIOI-!S, DESCRIPTIOI!S &,R~SULTS Installed and tested 13 5/8" 5M BOPE. Testing witnessed and approved by Joe Russell of USGS. 'Changed out Kelly Spinner. RIH w/ bit #2. C.O. cmt. stringers @ 1862' and tagged firm cmt. @ 2515'. Tested csg. to 2500 psi. ok. Cleaned out cmt. to 2555' and retested csg. to 2500 psi - ok. Cleaned' out cmt. and shoe @ 2566', rathole to 2579', and drilled 10' of new hole to 2589'. Circ. and cond. cmt. contaminated mud. Performed leak off test - shoe held 500 psi (95 PCF equivalent) w~th no leak off. NOW' POOH w/ d.p. POOH w/ d.p. Ran Sperry Sun gyro on Schlumberger W. L. f/ 2555' to surface R.D. Sperry Sun. Laid down S-135 d.p. RIH w/ bit #2 on C.O. assembly and circ. @ 2522' - had low circ. pressure. Checked- surface equipment. POOH .looking for wash- out - did not find. RIH - staged in hole. Did not find washout. Circ. and cond. mud @ 2560' - pwessure is good. Drilled 12 1/4" hole f/ 2589' to 2908'. NOW' Drilling @ 2908'. SURVEYS' 2726' 3/4° S-56-E 2878' 3/4° S-41-E Drilled 12 1/4" hole f/ 2908' to 3312'. Ran survey. Had 20' of fill after survey. Drilled 12 1/4" hole f/ 3312' to 3683'. Circ. and surveyed. POOH - laid down S-135 D.P. (had a tight spot at 2961' - pulled up to 170M #). RIH w/ bit #4 on BHA #2 (60' pendulum) while picking up "E" d.p. R~amed f/ 3326' to 3681' (Previous bit had lcome out 1/8" undergage). Drilled 12 1/4" hole f/ 3683' to 3826'. NOW' Drilling @'3826'. SURVEYS' 3281' 1/2° S-26-E 3645' 1 / 4° S- 38-W UiIIOl.l OIL CCI PA h' [DF CALIFORHIA £LL RECORD Sl-: q' PAGE -4 " LEASE Kenai Deep Unit DATE '8 972~/81 DAILY COST' ACC COST' AFE AMT 9 9/30/81 DAILY COST: ACC COST' AFE AMT' lO 10/1/81 DAILY COST' ACC COST' AFE AMT' DAILY COST' ACC COST' AFE AMT' ETD ~809'/983 '- 20" D. 85' 13 3/8" C. 2566' 69 PCF 58 SEC $ 38,636 $ 792,307 $2,450,000 5209'/400' ~20'_' ~5' 13 3/8" C. 2566' 78 PCF 59 SEC $ 51,85O $ 844,157 $2,450,000 ~56/3'/464' 20" D. 85' 13 3/8" C. 2566' 78 PCF 62 SEC $ 39,568 . $ 883,725 $2,450,000 5'~9~'/124' 2O" D. 85' 13 3/8" C. 2566' 78 PCF 60 SEC $ 43,727 $ 927,452 $2,450,000 NELL NO, KDU FIELD Kenai Gas Field OF OPERATIOIIS, DESCRIpTI_03!S & RESULTS Drilled 12 1/4" hole f/. 3826' to 4072' Circ. and surveyed. Drilled 12 1/~l' hole f/ 4072' to 4409'. Circ. and surveyed. POOH for bit change. Had some slight tight spots at 3909', 3817', 3770', and 3726'. Remainder of trip smooth. RIH w/ bit #5 on BHA #2. Had slight tight spot @ 3700'. Cleaned out 8' of fill and drilled 12 1/4" hole f/ 4409' to 4809'. Circ. clean. NOW- Prep. to Survey and short trip. SURVEYS' 4045' '1/4° S-30-E 4383' 1/4° S-50-E 4783' 1/4° N . Ran survey. Pulled 5 stds. for short trip - had to pull up to 20OM# for all 5 stds. Reamed down f/ 4359' to 4809' while raising mud weight. Circ. and raised mud wt. to 76 PCF. Drilled 12 1/4" hole f/ 4809' to 5209' Circ. and surveyed. Trip for bit change. Had tight spots @ 4858', 4486', 4441', 4244', 4176', and 3816'. NOW- Repairing torque gauge. SURVEY- 4845' 0°' RIH w/ bit #6 on BHA #2. Filled dip. @ 2500' RIH and reamed f/ 3726' to 3827' (~lays). RIH to bottom. Drilled 12 1/4" hole f/ 5209' to 5518'. Circ. btms. up and made short trip to shoe of 13 3/8" csg. Hole was tight f/ 5456' to 5240' (clay). Worked thru tight sec~i6~n w/ Kelly. Hole was smooth remainder of trip. RIH and drilled 12 1/4" hole f/ 5518' to 5673'. Made short trip to 4600' - had slight drag for 1st 5 stands. NOW' RIH after s~ort tr'ip. Finished l0 stand short trip. Drilled 12 1/4" hole f/ 5673' to 5797. Circ. Repair #1 mud pump. Ran survey. Made l0 std. short trip - had only slight drag. Circ. and POOH for dyna-drill. NOW: RIH w/ dyna-drill. SURVEY' 5770 1/4° S-50-E urlIOr.l OIL CCI-?AI'IY CF CALIFOP qIA RECORD J. SI-: T- D PAGE ih', '" 5 LEASE Kenai Deep Unit DATE i2 10/3/81 DAILY COST' ACC COST' AFE AMT' 13 10/4/81 DAILY COST' ACC COST' AFE AMT' 14 10/5/81 DAILY COST' ACC COST' 15 10/6/81 DAILY COST' ACC COST' AFE AMT' ETD 6019'/222' 20" D.'85' 13 3/8" C. 2566' 78 PCF 62 SEC $ 84,635 $1,012,087 $2,450,000 6143'/124' 20" D. 85' 13 3/8" C. 2566' 78 PCF 64 SEC $ 32,891 $1,044,978 $2,450,000 6516'/373' 20" D. 85' 13 3/8" C. 2566' 78 PCF 64 SEC $ 38,997 $1,083,975 6930'/~]4' 20" D. 85' 13 3/8" C. 2566' 78 PCF 62 SEC $ - 37,073 $1,1 21 ,O48 $2,450,000 % ELL H0, FIED Kenai Gas Field DETAIL, S OF OPERATIOHS, DESCRIP_TIO~!S._& RESULTS RIH w/ dyna-drill - washed 20' to bottom. R.U. Schlumberger w/ Sperry Sun and side- entry sub. Tool would not work. POOH w/ W.L. Reheaded line and changed out probe. RIH w/ steering tool and oriented dyna-d~ill. Directionally drilled 12 1/4" hole f/ 5797' to 601 9'. Ran survey. . NOW' POOH w/ dyna-drill. SURVEYS' 5904' 4°15' S-59-W 5975' 6° S-70-W POOH w/ dyna-dr~ll. RIH w/ bit #2 RR #1 on BHA'#4 (90' belly follow assembly). Filled drill pipe @ 2500' and 4600'. Reamed dyna-drill run f/ 5852' to 601 9' Directionally drilled 12 1/4" hole f/ 601 9' to 6081'. Ran survey. Wireline parted while running survey. Pulled 15 stds. to catch W.L. Pulled 10 more stds. to remove d.p. rubbers. RIH and direc- tionally drilled 12 1/4" hole f/ 6081' to 6143'. Lost 1000 psi pump pressure. POOH looking for washout. Found split box at top of jars. Laid down jars and 1 jr. of HWDP. NOW: RI~t w/ BHA #5 (90' belly-). RIH w/ bit ,8 on BHA #5 Reamed-f/ 6110 to 6143'. Directiona!ly drilled 12 1/4" hole f/ 6143' to 6516 . Pumped dry job and POOH - had slight drag on 1st 2 stands. NOW' RIH w/ bit #9 on BHA #6. SURVEYS' 6029' 7°3(3, 6082' 8°45' 62O7' 11°45'-- 6298' .13°30'- 6391' 15° 30' ~ 6485 17°15' S-70-W S-70-W S-76-W S-78-W S-80-W S-82-W RIH w/ bit #9 on BHA #5. Reamed f/ 6282' to 6516'. Directionally drilled 12 1/4" hole f/ 6516' to 6930'. Circ. and trip for bit change. NOW.: POOH for bit change. SURVEYS' 657.8' 19° , S-83 1/2-W 20045 6668' ~o30' S-83 1/2-W 6761' S-83 l/2-W 6856' 23°4-_~5' S-83 1/2-W SEP 2 1 · ,.~-,<~ Oil & Ga,'-]-Cons. Commission $ :EET D U[lIOit OIL OF CALIFOP .iIA PAGE ih, --6 LEASE Kenai Deep Unit DATE ETD 16 10/7/81 DAILY COST- ACC COST- AFE AMT' 17 10/8/81 DAILY COST- ACC COST: AFE AMT' -- _ ]8 ]0/9/81 DAILY COST- ACC COST- AFE AMT' 19 lO/lO/S] DAILY COST- ACC COST. AFE AMT' 20" D. 85' 13 3/8" C. 2566' 79 PCF 58 SEC '$ 37,183~ $1 ,l 58,231 $2,450,000 7301 '/135' 20" D. 85' 13 3/8" C. 2566' 79 PCF 61 SEC $ 105,743 $1,263,974 $2,'450,000 __ 7301 '/0' 20" D. 85' 13 3/8" C. 2566' 79 PCF 65 SEC $ 31,309 $1,293,283 . $'2 ,Q50,O00 730] '/0' 20" D. 85' 13 3/8" C. 2566' 78 PCF 45 SEC, $ 36,425 $1,331,708 $2,45'0,000 WELL RECORD I,lO, #s FIELD Kenai Gas Field RIH w/ bit #10 on BHA #6 (90' belly). Directio'nally drilled 12 1/4" hole f/ 6930' to 7166'. Circ. and POOH for · BHA change. RIH w/ bit #11 on BHA #7 (locked up assembly) - strapped in hole. NOW- RIH w/ BHA #7. SURVEYS' 6949' 25°1--5' 7042' 26°30'_ 7136' 29° S-83 1/2°-W S-83 1/2°-W S-82-W~. Continued to RIH w/ bit #11 on BHA #7 (locked up assembly). Directionally drilled 12 1/4" hole f/ 7166' to 7301'. Circ. and work on mud pumps. Made 15 stand-short trip - OK. Circ. and dropped survey. POOH. R.U. Schlumberger. Ran Dil/Sonic/GR and FDC/CNL/GR logs f/ 7301' to 2566'. R. D. Schlumberger. RIH w/ bit #11 RR #1 on BHA #7 for clean--' out run. NOW' RIH.w/ BHA #7' SURVEY. '7270' 290 S-84-W - ! .. RIH w/ bit #11 RR #1 on BHA #7 to 7301'. Had no fill. Circ. hole clean and POOH. Laid down BHA. Changed pipe rams to 9 5/8". Rigged up and RIH w/ 9 5/8" csg. to 5400' - lost returns. Lost approx. 4 Bbls. of mud while running each jt. of csg. Mixed mud. NOW'-- Mixing mud. Mixed mud while working~casing. Pulled 2 jts. of csg. and attempted to Circ. - had no returns. Pulled 10 more jts. of csg. and Qttempted to circ. - had small amount oflreturns. Pulled and laid down 9 5/8" csg. RIH w/ BHA #8 (bit, stab, D.C., stab, D.C., stab, XO). NOW-. RIH Zo cleah tip hole. Gas Cons. commission II I ' ~AS[ Kenai Deep Unit U?IIOIt OIL Ca?A h' CALIFOR .iIA RECORD 'ELL [,I0, KDU FIELD S ;EET D PAGE ih, ---7 Kenai Gas Field DATE ETD 20 ]0/1]/8] 7,'30]'70-'~ ' '! 20" D. 85' , 13 3/8" C. 2566' 78 PCF 52 SEC DAILY COST' $ 36,188 ACC COST- $1,367,896 AFE AMY-- $2,450,000 21 10/12/81 7301'/0' 13 3/8" C. 2566 9' 5/8" C. 7282' 78 PCF 44 SEC DAILY COST' ACC COST- $ 431,149 $1,799,045 AFE AMT- _. $2,450,000 22 lO/l 3/81 7310'/10' 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 72 SEC DAILY COST' ACC COST' AFE AMT' I 23 10/14/81 DAILY COST' ACC COST- AFE AMT- ~4 10/15/8] DAILY COST- ACC COST' AFE AMT' $ 36,145 $1,799,915 $2,450,000 75"12'/~02' 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 55 SEC $ - 46,54O $1,846,455 $2,450,000 7-701 '/189' 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 56 SEC $ 43,624 $1,890,079 $2,450,000 DETAILS OF OPEFLATIO[tS, DESCRIPTIOJ!S & RE_SU[.TS , RIH w/ BHA #8 slowly. Broke circ. every 1000' on trip in. Had no fill. Circ. hole clean - had full returns. POOH - laid down BHA. R.U. to run 9 5/8" casing. R~n 9 5/8" csg. - had to change out slips - after 1st joint run. RIH to shoe of surface csg. - had partial returns. Built 120 Bbls. of mud volume. RIH - broke circ. every 1200'. NOW- Running 9 5/8" csg. Ran 9'5/8" csg to 7282~ Rigged up cmt. head and broke circ. t. w/ 500 sxs lead slurry w/ 2% KCL .2% D6 2.5% pre-hydrated . gel and-a 950 sx tail slurry w/ 5% KCL, 1.7% D-29, .5% D-19, .5% D-31, .2% D-6, .1% A-2. Displaced w/ 534 Bbl of mud. Picked up BOP's and set slips. Nippled down. Install and tested to 2400 psi CIW 13 5/8" 5000 psi xlO" 5000 psi DCB spool. Nipple up BOP'.s and change to 5" pump liner. . NOW' Nippling up BOP's. Nippled up BOPE and tested to 5000 psi. · Tested hydril to 2500 psi. RIH w/ BHA #8 & Bit #12. Strap in hole. Tagged cmt @ 7027' Clean out cmt to 7194' & tested to 5000 psi -..OK. Drilled FC & cmt to .7265'. Tested to 5000' psi -' OK. Drilled shoe and 10' of new hole to 7310' Pulled into csg. Tested shoe to iO0 PCF equiv, w/ no leak off. NOW: Circ & cond mud. Circ. and con. mud. POOH. RIH ~/ bit #13 on BHA #9 '(lokked up assembly). Directiohally drilled 8 1/2" hole f/ 7310' to 7512'. Dropped survey and POOH. -, Now: POOH for .bit change. SURVEYS- 7379' 28° 3--0' S-87-W 7469' · 28°30'. S-87-W POOH for bit change. RIH w/ bit #14 on BHA #9. Directionally drilled 8 1/2" hole f/ 7512' to 770]'. Circ. and dropped survey. POOH for bit change. RIH w/ bit #15 on BHA #9. NOW' RIH w/ new bit. SURVEY' 7659' 27° S-89-W S EP 2 i t982 Oil & Gas Cons. Commission ,'k~.chura,q~ $t-:EET D UNIOIt OIL C[IPAIN OF CALIFORt-iIA P^~E ih, -.~' ~ELL RECORD LEASE Kenai Deep Unit SELL NO, KDU ~8 FIELD Kenai Gas Field DATE ETD ~-5- 10/]6/8-1- DAILY COST- ACC COST- AFE AMT- 26 10/17/81' DAILY COST- ACC COST- AFE AMT- 27 10/18/81 DAILY COST- ACC COST- ~FE AMT- 8.023'/322' _. 13 3'/8" C. 2566' 9 5/8" C. 7282' 78 PCF.57 SEC- $ 41,074 - $1,931,153 $2,450,000 82'35'/212' 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 55 SEC $ 52,922 $1,984,075 $2',450,000 8375'/140' 13 3/8" C. 2566' 9 5/8"_ ~~82' 78 PCF 51 SEC $ 33,916 $2,017,991 $2,45O,OOO RIH w/ bit #15 on BHA #9. DD 8 1/2" hole f/ 7701' to 8023'. Circ & dropped survey. POOH. RIH w/ bit #16 on BHA #9. NOW' RIH w/ bit #16. Surveys' 7811' 27° S89 1/2°W o 7981' 27° N89 1/2°W RIH w/ bit #16 on BHA #9. DD 8 1/2" hole f/ 8023' to 8218' Circ hole clean & POOH. RIH w/ bit #17 on-~HA #10 (dyna-dril-1 assembly). DD 8 1/2" hole f/ 8218' to 8235' w/ tool face 60-65© left of HS. NOW' Dyna-drilling @ 8235'. Survey' 8160' 26° 45' N87W Continued to dyna-drill 8 1/2" hole f/ 8235' to 8278' Total D/D run f/ 8218' to 8278'. POOH. RIH w} bit #18 on BHA #11 (30' belly). Reamed D/D run f/ 8218' to 8278'. DD 8 1/2" hole f/ 8278' to '8375'. Dropped survey & POOH. NOW- Trip for BHA change. Surveys' 8253' 26° 30~' S89W 8350' 26° 45' S86 1/2W LEASE Kenai Deep Unit UNION OIL Ca'?A Y CALIFORI.iIA WELL RECORD t ELL NO, KDU FIELD SHEET D PAGE ih, -.9 Kenai Gas Field DATE 28 10/19/81 DAILY COST: ACC COST: AFE AMI: 29 10/20/81 DAILY COST: ACC COST: AFE AMI: 30 10/21/81. DAILY COST' ACC COST' AFE AMT' ., 31 i0/22/81 DAILY COST' ACC COST: AFE AMT: ETD 8700'/325' 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 45 SEC $ 37,245 $2,055,236 $2,450,000 8928'/228' 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 44 SEC $ 31,513 $2,086,749 $2,450,000 9J_ 62 ' '/?~! 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 47 SEC $ 29,560 $2,116,309 $2,450,00O 9396'/234~'' 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 47 SEC $ 51,291 $2,167,600 $2,450,000 __..DETAIL~ OF OPEP~iT_IOI.IS, DESCRIpT!OI!S ..& RESULTS RIH w/ bit ~;i9 on BHA #12 (locked-up assy). Filled DP ~ 3500' & 7100'. DD 6 1/2" hole f/ 8375' to 8700'. Circ & dropped survey. ROOH. NOW: Trip for bit change. Survey: 8667' 240 45' S89W RIH w/ bit #20 on 5HA #12. Directionally drilled 8 1/2" hole f/ 8700' to 8924'. Circ and dropped survey. POOH. Changed wear bushing. RIH w/ bit #21 on 8HA #12. Filled DR ~ 3500' & 7100!. Reamed f/ 8598' to 8722' (various spots) and 8900' to 8924'. Direc- tionally drilled 8 1/2" hole f/ 8924' to 8928'. NOW: Orlg ~ 8928'. Survey: 8891' 250 15' N89W Directiona'lly drilled 8 1/2" hole f/ 8928i to 9137'. Circ & dropped survey. POOH. RIH w/ bit #22 on BHA #13 (10' pendulum). Washed 40' to ' btm. DD 8 1/2" hole f/ 91 37' to 91 62'. NOW' Drlg @ 9162'. Survey' 9104' 25° 15' N87W Directionally drilled 8 1/2" hole f/ 9162' to 9321'. Circ. and dropped survey. Trip for bit change. RIH w/ bit #23 on BHA #13. Washed 20' to bottom. Directionally drilled 8 1/2" hole f/ 9321' to 9396'. NOW' Drlg. @ 9396'. SURVEY' 9290' 24°45' N-86-W UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. lO LEASE Kenai Deep Unit WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 32 10/23/81 9467'/71' 13 3/8" C. 2566' 9 5/8" C. 7282' 78 PCF 55 SEC DAILY COST: $ 39,766 ACC COST: $2,207,366 AFE AMT: $2,450,000 33 10/24/81 9746'/279' .... 13 9/~* C. 2566' 9 518" C. 7282' 78 PCF 54 SEC DAILY COST: $ 28,894 ACC COST: $2,236,260 AFE AMT: $2,450,000 34 10/25/81 to 9844'/98' 13 3/8" C. 2566' 9 5/8" C. 7282' 82 PCF 58 SEC DAILY COST: ACC COST: $ 39,628 $2,275,888 AFE AMT: $2,450,000 35 10/26/81 DAILY COST: ACC COST: AFE AMT: 36 10/27/81 good. strapped DAILY COST: ACC COST: AFE AMT: 10084 '/240 ' 13 3/8" C. 2566' 9 5/8" C. 7282' 82 PCF 53 SEC $ 31,166 $2,307,054 $2,450,000 10225'/141' 13 3/8" C. 2566' 9 5/8" C. 7282' 82 PCF 54 SEC $ 31,792 $2,338,846 $2,450,000 Directionally drilled 8 1/2" hole f/ 9396' to 9422'. Dropped survey & POOH. RIH w/ bit #24 on BHA #13. Washed 18' to bottom and directionally drilled 8 1/2" hole f/ 9422' to 9434' Pressure increased to 3000 psi then dropped to 1500 psi. POOH looking for washout. Did not find washout. RIH w/ bit #25 on BHA #13. Broke circ ~ 3500' & 7200'. Washed 8' to bottom. Directionally drilled 8 1/2" hole f/ 9434' to 9467'. NOW: Drlg ~ 9467'. Survey: 9391' 230 45' N87W Directionally drilled 8 1/2" hole f/ 9467'-" to 9746'. Had 1 tight connection ~ 9535'. NOW: Drlg ~ 9746'. Directionally drilled 8 1/2" hole f/ 9746' 9807'. Circ gas cut mud (cut to 74 PCF). Raised mud wt to 82 PCF. Dropped survey & trip for bit change. First 4 stds off btm pulled 3OM# over normal pickup. RIH w/ bit #26 on BHA #14. Washed 35' to btm. Direc- tionally drilled 8 1/2" hole f/ 9807' to 9844'. Lost power to solids control unit. Circ & pulled to csg shoe. Worked on genez- ator. NOW: prep to RIH. Repaired generator. RIH - washed 10' to bottom. Directionally drilled 8 1/2" hole fi 9944' to 10084'. NOW: Drlg 8 10084'. Directionally drilled 8 1/2" hole f/ 10084' to 10225'. C&C hole. Pulled up to shoe - had a max of 5Om# excess drag. Wait I hr. RIH & washed 5' to bottom, Trip in was C&C hole for logs. Dropped survey & out of hole. NOW: POOH for logs., Survey: 10194' 14 3/4°'N82W UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. 11 LEASE Kenai Deep Unit WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 37 10/28/81 10225' TD 13 3/8" C. 2566' 9 5/8" C. 7282' 82 PCF 59 SEC DAILY COST: ACC COST: $ 128,764 $2,467,610 AFE AMT: $2,450,000 38 10/29/81 10225' TD 10088' ETD (EST.) 9 5/8" C. 7282' 7" L. 10217' 82 PCF 56 SEC DAILY COST: - --$- =~673 ACC COST: $2,490,283 AFE AMT: $2,450,000 39 10/30/81 10225' TD 5365' ETD (Cmt) 9 5/8" C. 7282' 7" L. 10217' 81PCF 56 SEC DAILY COST: ACC COST: $ 233,933 $2,724,216 AFE AMT: $2,450,000 40 10/31/81 DAILY COST: ACC COST: AFE AMT: 41 11/1/81 DAILY COST: ACC COST: 10225' TD 6512' ETD (cmt) 9 5/8" C. 7282' 7" L. 10217' 80 PCF 50 SEC $ 32,170 $2,756,386 $2,450,000 10225' TD 6915' ETD (TOL) 9 5/8" C. 7282' 7" L. 10225', top ~ 6915' 81PCF 55 SEC $ 32,416 $2,788,802 POOH w/ DP. RU Schlumberger & ran DIL-Sonic, FDC-CNL-GR, and HRD-Dipmeter logs f/ 10225' to_]7282'. RD Schlumberger. RIH w/ bit #24 RB~J~& washed 4' to bottom. C&C mud for NOW: C&C mud. Made short trip to csg shoe. C&C mud. POOH w/ DP. RU & ran 3300' (79 jts) of 7" 29# N-80 buttress liner w/ DOT liner hanger on 5" DP. Tagged bottom ~ 10225'. C&C mud --whi-te-~working pipe 20'. Mixed & pumped 1600 -'~x~i~'"G'' w/ 5% kcl, 1.7% D-29, .5% D-19,-" ~5%.D-31, .2% R-5, and .2% D-6. -N~W]-~'~D isp 1 ac ing cmt. Dropped plug & displaced cmt w/ 234 bbls of mud. Bumped plug w/ 3800 psi - floats held ok. CIP ~ 00:30 hrs. Rotated off of liner (est. top_.~ 6909'). Pulled 650' of DP & attempted to rev out cmt - press rose indicating still in cmt. POOH w/ DP - LD setting tools. RIH to +3250' &circ cmt contaminateo muo. POOH & LD 75 jts of DP & 30 jts of h~CDP: RIH w/ 8 1/2" bit w/ 5-6 1/4" Dg~s, 8 jts.HWDP, & jars. Tagged firm cmt ~ 4515'. Drld cmt f/ 4515' to 5365'. NOW: Drlg cmt ~ 5365'. Drld firm cmt f/ 5365' to 5637'. LD 15 jts of DP. Drld cmt f/ '5637' to 6031'. Trip for bit change - LD 27 jts of DP. RIH w/ bit ¢28 & drld cmt f/ 6 ¢~:V 6512'. ~, t . Drld cmt f/ 6512' to 6533'. Trip for bit change & add 9 jts of HWDP to string. RIH w/ bit 029 on BHA #16. Drld cmt f/ 6533' to 6915' (top of liner). Circ btms up. Pressuze tested liner lap to 3000 psi - ok. POOH w/ DP. NOW: Trip for bit change. AFE AMT: $2,450,000 J' UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. 12 LEASE Kenai Deep Unit WELL: 1'~0. ..... KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 42 11/2/81 DAILY COST: ACC COST: AFE AMT: 10225' TD POOH for bit change. RIH w/ bit 10065' ETD (CMT) on BHA ~I17'(4-4 3/4" DC's, 125 jts 9 5/8" C 7282' __3~1/ DP, . . '~: 2" XO) Drld cmt f/ 6915' 7" L. 10225' , top ~ 6915' ~~ .... RIM to 8500' & circ 30 81 PCF 50 SEC . H & tagged cmt ~ 9924'. . Drld cmt f/ 9924' to 10065'. Circ $ 26,441 ~2~hrs,-& FOOH. RU Schlumberger & $2,815,243 ~~' log. $2,450,000 NOW: Running CBL log. 43 DAILY COST: ACC COST: 11/3/81 10225' TD Ran CBL-VDL-GR log f/ 10030' to 10065' ETD (CMT) 2566'. RU Sperry Sun on Schlum & 9 5/8" C. 7282' ran gyro-gyro stopped ~ 7500'. 7" L. 10225' , top ~ 6915'-~~~-.-found cmt chunk-s in belly 81 PCF 50 SEC ~~~. RIH w/ gyro. $69,034 _~..~_~_Running gyro. $2,884,277 AFE AMT: $2,450,000 11/4/81 DAILY COST: ACC COST: AFE AMT: $ 27,731 $2,912,-008 $2,450,000 10225' TD Completed running gyro survey to 10050' ETD (CMT) (Corr.) -~00', POOH w/ WL. RIH w/ 8 1/2" 9 5/8" C. 7282' -~l~r~.t &'9 5/8" csg scraper to TOL ~ 7" L. 10225', Top ~ 6915' ~._~/~5.1.~. Circ clean & POOH. RIH w/ 81PCF 53 SEC RTTS pkr & hydrosp~ing test valve on dry DP. Set pkr ~ 6865' DPM. Opened hydrospring tester ~ 14:25 hrs. Had slight blow for 15 min, then dead. Held test 1 hr. Closed ..... ~Osp~ing & released pkr. POOH - me~ 215' of mud. 'LD tools. RIH w/ 6" bit & 7" csg scraper to 10036' (corr). Cleaned out cmt to 10050' &circ clean. NOW: Circ hole clean. UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. ],3 LEASE Kenai Deep Unit WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 45 11/5/81 DAILY COST: ACC COST: AFE AMT: 46 11/6/81 DAILY COST: ACC COST: AFE AMT: 47 11/7/81 DALLY COST: ACC COST: AFE AMT: 10225' TD 9435' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', Top ~ 6915' 81 PCF 47 SEC $ 27,832 $2,939,840 $2,450,000 Completed circ hole clean ~ 10050' POOH. RU Schlum & RIH w/ 2' of 4" csg gun. Attempted to perf for Tyonek "D-2" isolation f/ 9458' - 9460' DIL - gun misfired. Reheaded WL &'RIH w/ 2' of 4" csg gun. Rerfed 4-1/2" HRF f/ 9458' to 9460' DIL. POOH & RD Schlum. RIH w/ Howco E-Z Drill cmt ret on 3 1/2" DP & set ret ~ ~435' DPM. Tested surf equip to 6000 psi. Tested csg to 5000 psi. Broke down perfs f/ 9458' to 9460' DIL w/ 3700 psi. Pumped in w/ 1.5 BPM ~ 3500 psi. Form held 3050 psi w/ pumps off 5 min. Mixed & sqz'd BS #1 parrs w/ 170 sxs el "G" w/ 40 gal/lO0 sxs D-45L, 4 gal/lO0". sxs R-12L, and 1 gal/lO0 sxs D-GL. Displaced 160 sxs below ret w/ a final rate of 1.5 BPM 8 3400 psi. Sqz held 2200 psi w/ pumps off 5 min. CIP ~ 17:35 hrs. Rev out 10 sxs cmt. POOH w/ DP. RU Schlum & perfed 4-1/2" HPF for Tyonek "D-2" isolation f/ 9398' to 9400' DIL. POOH w/ WL. NOW: POOH w/ WL. 10225' TD 9357' ETD (Ret) 9 5/8" C. 7282' 7" L. 10225', top ~ 6915' 82 PCF 58 SEC $ 44,206 $2,984,046 $2,450,000 POOH w/ WL. RD Schlum. RIH w/ 7" EZ drill cmt ret on DP & set ret ~ 9357'. Tested surf lines to 6000 psi & csg to 5000 psi. Broke down isolation perfs above D-2 sand f/ 9398' to 9400' w/ 3700 psi. Pumped in w/ 1.5 BPM ~ 3750 psi. Form held 2200 psi w/ pumps off 2 min. Mixed & sqz'd for BS #2 w/ 170 sxs cl "G" w/ 40 gal/lO0 sxs D-45L, 4 gal/lO0 sxs R-12L, & 1 gal/lO0 sxs D-6L to lla'pcf. Displaced 146 sxs below ret w/ a final rate of 1 3/4 BPM ~ 4000 psi. Sqz held 3200 psi w/ pumps off 5 min. CIP ~ 08:10 hrs. Rev out 24 sxs cmt. POOH w/ DP. RIH w/ 6" bit, 2 junk subs, on 12-4 3/4" DC's to 8000'. WOC. RIH & tagged cmt ~ 9352'. C0 cmt to ret ~ 9357'. NOW: Drlg on ret 8 9357'. 10225' TD 10050' ETD (LC) 9 5/8" C. 7282' 7" L. 10225', top ~ 6915' 80 PCF 50 SEC $ 24,726 $3,008,772 Drld ret ~ 9357', cmt to 9435', & ret ~ 9435'. CO cmt stringers to 9585' & RIH to 10050'. Circ& tested csg & sqzs to 3000 psi - ok. POOH. LD 4000' of 5" DP & stood back the remainder. RIH w/ 7" csg scraper & 6" bit while pick- ing up 3 1/2" DP test string. $2,4.50,000 SEP 2 I_ '~;~"~'~_..,;~. NOW: PU 3 1/2" DP. ?:.1¢~ 0i~ & Ga'-~ Oons. Commission UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. 14 LEASE Kenai Deep Unit WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 48 11/8/81 DAILY COST: ACC COST: AFE AMT: 49 11/9/81 DAILY COST: ACC COST: AFE AMT: 50 11/10/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 10050' ETD (LC) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' $ 27,770 $3,036,542 $2,450,000 10225' TD 10050' ETD (LC) --- 9 ~-C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 Fluid $ 23,250 $3,059,792 $2,450,000 10225' TD 10050' ETD (LC) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 82,202 $3,141,944 $2,450,000 Continued to RIH w/ 6" bit & 7" csg scraper while PU 3 1/2" DP test string. Circ ~ 10050' & POOH. RIh w/ test tools (60' tbg tail, RTTS, bundle carrier, aux valve) w/ 2000' water-cushion. Set pkr ~ 9262', tail ~ 9327'. Opened aux valve to dry test isola- tion perfs f/ 9398' to 9400', & 9458' to 9460'. Tested for 1 hr - test was dry. NOW: Prep to release pkr. Rev out water cushion f/ dry test. RIH to 10050' & picked up to 10045'. Dumped & cleaned mud pits. Pumped 100 bbls of fresh water spacer town annulus. Mixed 72 PCF CaCL2 fluid & changed hole over to CaCL2 fluid. NOW: Changing over to CaCL2 fluid. Completed change over to CaCL2 fluid. Pulled up so tbg tail ~ 9891', pkr ~ 9823'. Tested surf equip to 6000 psi. Displaced DP w/ nitrogen. Set pkr ~ 9823' & bled off nitrogen to 2760 psi (3650 psi BHP). RU Schlum & tested lub to 5000 psi. RIH w/ 5' of 2 1/8" chef- jet gun. Parred D-4 sd w/ 4-1/2" HPF f/ 9953' to 9958' DIL - had no press increase. POOH w/ WL - guns had fired. Ble~d off nitro cushion to 1014 psi. Press builC to 1034 psi in 9 min. RIH w/ 2nd 5' perf gun. Press built to 1084 psi in 70 min. Bled press to 1017 psi & reperfed the D-4 sd for DST #1 f/ 9953' to 9~58' DIL. Had gradual press increase. POOH w/ WL. Press had built to 1151 psi. Opened well to flare. Had an initial rate of' .13 MMCFD ~ 350 psi. Well iced up. Press built to 1135 psi while de-icing lines. Reopened well to flare. Had an initial rate of .55 MMCFD ~ 300 psi thru a 3" choke. Rate gradually decreased to .085 MMCFD ~ 50 psi after 45 min. Shut well in ~ 22:00 hfs w/ 3.5 psi on DP. Press built to 365 psi after 70 min. NOW: Prep to kill well. UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. 15 LEASE DATE Kenai Deep Unit ETD WELL NO. KDU 8 FIELD Kenai Gas Field DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 51 11/11/81 DAILY COST: ACC COST: AFE AMT: 52 11/12/81 DAILY COST: ACC COST: AFE AMT: 10225' TD' 9925' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 33,983 $3,175,927 $2,450,000 10225' TD 9925' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 50,876 $3,226,803 $2,450,000 Filled DP w/ CaCL2 fluid & rev out. Released pkr & RIH 90' - rev out. ROOH - LD test tools. RIH w/ cmt ret on DR & set ret ~ 9925' DRM. Tested surf lines to 6500 psi, csg to 3000 psi. Rev capacity of DR. Stabbed into ret & broke down the D-4 sand f/ 9953' to 9958' DIL w/ 4400 psi. Pumped in w/ 2 BPM ~ 4200 psi. Formation held 1500 psi w/ pumps off 5 min. Mixed & pumped 170 sxs cl "G" w/ 10 gal/lO0 sxs R-12L & i gal/lO0 sxs D-eL to a weight of ll8 RCF. Displaced 130 sxs below tool ~ a final rate of 2 BRM ~ 6000 psi. Rev out 40 sxs of cmt. CIR ~ 18:15 hrs. ROOH w/ DR. NOW: Making up test tools. RIH w/ test tools. Set pkr ~ 9635', tail ~ 9700'. RU Schlum & tested surf equip to 5000 psi. RIH w/ 10' enerjet gun. Tagged ret ~ 9925'. Charged DP to 1500 psi w/ nitrogen. Perforated lower portion of D-3 sd f/ 9833' to 9843' DIL. Press built to 1700 psi in 30 min. POOH w/ perf gun. Bled press down to 800 psi. Pressure stabilized ~ 800 psi while shut-in 2 hrs. RIH w/ 30' perf gun. Bled well down to 500 psi & parred the upper portion of D-3 sd f/ 9751' to 9781' DIL. Press built to 800 psi while POOH w/ perf gun. Opened well to flare to clean up. Put well into separator - had stabilized rate of 1.6 MMCFD ~ 175 psi w/ 28.8 BWPD. Shut well Sn 6 21:00 hrs for buildup. : NOW: Well shut-in for buildup. UNION OIL COMPANY OF CALIFORNIA WELL RECORD LEASE Kenai Deep Unit WELL NO. KDU 8 SHEET D PAGE NO. 16 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 53 11/13/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 9707' ETD (RET) 9 5/8" C. 7282' 7" L, 10225', TOP ¢~ 6.915' CaCL2 FLUID $ 54,710 $3,281,513 $2,450,000 54 11/14/81 DAILY COST: ACC COST: AFE AMT: 10225' TD .9707' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6.915' CaCL2 FLUID $ 32,094 $3,313,607 $2,450,000 Shut well in for buildup. Pressure built to 3266 psi after 4 hrs. Opened well to flow - had stabilized rate of 1.54 MMCFD ~ 168 psi w/ 28.8 BWPD. Pumped CaCL2 fluid down DP to kill well. Released pkr & RIH - circ& killed well ~ 9888'. POOH & LD test tools. RIH w/ cmt ret on DP & set ret ~ .9707'. Broke down parrs f/ .9833' to 9843' & 9751' to 9781' DIL w/ 3200 psi ~ 2 BPM. Formation held 1000 psi w/ pumps off 5 min. Mixed & sqz'd w/ 100 sxs cl "G" w/ 10 gal/lO0 sxs R-12L & 1 gal/lO0 sxs D-6L. Displaced .90 sxs below ret w/ a final rate of 2 BPM ~ 4500 psi. CIP ~ 17:40 hfs 11/13/81. Rev out 10 sxs of cmt & POOH w/ DP. NOW: POOH w/ DP. POOH w/ DP. RIH w/ test tools on 3 1/2" DP (RTTS pkr, hydrospring test tool, pump-out sub). Set RTTS pkr ~ .9291', tail ~ 9358', pump-out sub ~ 9212'. RU Schlum & RIH w/ 10' of 2 1/8" enerjet perf guns. Could not get thru tools - appears to be stopping in pump-out sub. POOH - left 10' gun in hole. Released pkr & DP filled w/ fluid - hydrospring test tool had not closed. POOH w/ test tools - did not find gun. Hydrospring valve was partially open. RIH w/ 10' of 4" csg guns & perfed lower portion of D-2 sd f/ 9435' to 9~45' DIL w/ 4-1/2" HPF. RD Schlum. !RIH w/ test tools (RTTS pkr, aux valve, bundle carrier) on 3 1/2" DP. NOW~ RIH w/ test tools. LEASE SHEET D PAGE NO. 17 UNION OIL COMPANY OF CALIFORNIA WELL RECORD WELL NO. KDD 8 Kenai Deep Unit FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 55 11/15/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 9707' ETD (RET) 9 5/8" C, 7282' 7" L. 10225', TOP ~ 6915' $ 44,744 $3,358,351 $2,450,000 56 11/16/81 DAILY COST: ACC COST: AFE ANT: 10225' TD 9707' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', top ~ 6915' CaCL2 FLUID $ 22,524 $3,380,875 $2,450,000 57 11/17/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 9707' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 53,215 $3,434,090 $2,450,000 Finished RIH w/ test tools (rabbited DP). Set pkr ~ 9295', tail ~ 9360'. Tested surf equip to 5000 psi. Charged DP to 2700 psi (3500 psi BHP) w/ N2. Opened aux valve - had no indication of entry. Bled off nitro press to 0 psi - had no build- up. RU Schlum & RIH w/ 2 1/8" sinkerbars to 9675' - tool was open. RIH w/ 10' of 2 1/8" enerjet guns. Charged DP w/ 1850 psi (2500 psi BHP) w/nitrogen. Perfed middle portion of D-2 sd f/ 9425' to 9435' DIL. Had no press increase. Bled surf press to 500 psi - had no buildup. NOW: RIH w/ 30' perf gun. RIH w/ 30' of 2 1/8" enerjet perf gun. Perfed D-2 sd for DST ~3 f/ 9411' to 9441' DIL. Opened well to flare. Had stabilized rate after 5 hrs of 3.70 MMCFD ~ 387 psi w/ 4.8 BWRD. Shut well in ~ ll:lO hrs. RIH w/ HR pressure recorder to 9390'. Opened well to flare until stabilized. Shut well in ~ 15:00 hrs. Pressure built to 1323 psi BHR after 1 hr & stabilized. POOH w/ WL. NOW: Prep to acidize. RU Dowell. Pumped 9900 gal of 7 1/2% HCL w/ MSR 100, .2~ W-52, .2% L-53, .~% A-200, & 3900 gal of 7 1/2 - I 5/2 mud acid w/ MSR 123, .2% W-52, .2% L-53, .3% A-200, & 9900 gal of 7 1/2% HCL w/ MSR 100, .2% W-52, .2% L-53, .3% A-200. Dis- placed acid w/ nitrogen. Opened well to clean up. Had rate of 1.2 MMCFD ~ 100 psi. Shut well in ~ 11:15 hrs. Opened well ~ 12:15 . hrs. Rate increased to 1.98 MMCFD ~ 173 psi w/ 38.4 BWPD. Shut well in ~ 14:00 hrs. Opened well ~ 14:40 hrs. Rate increased up to 5.66 MMCFD ~ 422 psi w/ 19.2 BWPD ~ 22:00 hrs. Pinched well down to increase pzessure. Had rate of 4.2 MMCFD ~ 800 psi. NOW: Flowing well. SHEET D UNION OIL COMPANY OF CALIFORNIA WELL RECORD PAGE NO. 18 LEASE Kenai Deep Unit' WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS DF OPERATIONS, DESCRIPTIONS & RESULTS 58 11/18/81 10225' TD 9707' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' 70 PCF Brine DAILY COST: $ 28,840 ACC COST: $3,462,930 AFE AMT: $2,450,000 59 11/19/81 DAILY COST: ACC COST: AFE AMI: 10225' TD 3775' ETD (RET) 9 5/8" C. 7282' 7'" L. 10225', TOP ~ 6915' CaCC~FLUID $ 33,303 $3,496,233 $2,450,000 Tested D-2 perfs f/ 9411' to 9441'. Rate stabilized ~ 4.59 MMCFPD w/ 800 psi tbg press. Killed well. Spotted Dril-S & safe-seal pill across perfs to stop lost circ. NOW: POOH. POOH & LD test tools. RIH w/ 7" cmt ret on DP & set ret ~ 9296' DPM. Tested csg - ok. Pumped into D-2 perfs f/ 9411' to 9445' DIL w/ 3 BPM ~ 1000 psi. Form held 250 psi w/ pumps off 5 min. Mixed & sqz'o w/ 167 sxs cl "G" w/ 10 gal/lO0 sxs R-12L & 1 gal/lO0 sxs D-6L to 119 pcf. Displaced 103 sxs below ret w/ a final rate of .75 BPM ~ 4000 psi. Sqz held 3500 psi w/ pumps off 5 min. CIP ~ 05:40 hfs 11/19/81. Rev out 64 sxs of cmt. POOH. Tested csg to 3000 psi - ok. RU Schlum & perfed below base of B-1 sd f/ 3800' to 3802' DIL. POOH w/ perf gun. Ran GR & OB to 4000'. RIH w/ 9 5/8" omt ret on WL & set ret ~ 3775' DIL. POOH w/ WL. RD Schlum. RIH w/ stab-in tool on 5" DP. NOW: RIH w/ 5" DP. .-- Oil & Gas Cons. UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. 19 LEASE Kenai Deep Unit WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 60 11/20/81 DAILY COST: ACC COST: AFE ANT: 10225' TD 3705' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 42,158 $3,538,391 $2,450,000 Completed RIH w/ 5" DP & stab-in tool. Testeo surf equip to 4500 psi, csg to 3000 psi. Broke down perfs f/ 3800' to 3802' DIL w/ 1100 psi. Pumped in w/ 5 BPM ~ 1750 psi. Form'held 750 psi w/ pumps off 5 min. Mixed & sqz'd w/ 250 sxs cl "G" w/ 2% CaCL2, 35 gal/lO0 sxs D-45L, 10 gal/lO0 sxs R-12L, & 1 gal/lO0 sxs D-6L to 118 pcf. Dis- placed 235 sxs below ret w/ a final rate of 2.5 BPM ~ 1750 psi. Sqz held 1250 psi w/ pumps off 5 min. CIP ~ 07:30 hfs 11/20/81. Rev out 15 sxs cmt. POOH w/ DP. WOC 12 hrs. RU Schlum & perfed base of A-11 sd f/ 3746' to 3748' DIL w/ 4-1/2" HPF. POOH w/ WL. RD Schlum. RIH w/ 9 5/8" EZ drill cmt ret on 5" DP & set ret ~ 3705' DPM. Tested surf equip to 4000 psi, csg to 3000 psi. NOW: Prep to sqz for isolation. UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. 20 LEASE Kenai Deep Unit WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 61 11/21/81 DAILY COST: ACC COST: AFE AMT: 10225' ID 3494' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 31,623 $3,570,014 $2,450,000 Bzoke down perfs f/ 3746' to 3748' DIL w/ 1400 psi. Pumped in w/ 7 BPM ~ 1800 psi. Form held 1100 psi w/ pumps off 5 min. Mixed & sqz'd w/ 250 sxs cl "G" w/ 30 gal/lO0 sxs D-45L, 3 gal/lO0 sxs R-12L, & 1 gal/lO0 sxs D-6L to 118 pcf. Dis- placed 236 sxs below ret w/ a final rate of 2 BPM ~ 2250 psi. Sqz held 1500 psi w/ PO 5 min. CIP ~ 00:50 hfs 11/21/81. Rev out 14 sxs cmt. POOH w/ DP. RU Schlum & perfed above top of A-8 sd f/ 3548' to 3550' DIL w/ 4-1/2" HPF. RD Schlum. RIH & set EZ dr1 cmt ret ~ 3494' gPM. Tested surf equip to 4000 psi, csg to 3000 psi. Pumped into perfs, w/ 6 BPM ~ 1500 psi. Form held 250 psi w/ pumps off 5 min. Mixed & sqz'd w/ 250 sxs cl "G" w/ 1% CaCL2, 30 gal/lO0 sxs D-45L, 2 gal/lO0 sxs R-12L, & 1 gal/lO0 sxs D-6L to 118 pcf. Displaced 235 sxs below ret w/ a final rate of 3 BPM ~ 1500 psi. Sqz held 1200 psi w/ pumps off 5 min. CIR ~ 10:15 hrs ll/21/81. Rev out 15 sxs cmt. ROOH w/ DR. LD 3000' of 3 1/2" DR. RIH w/ 8 1/2" bit w/ 2 junk subs on 5" DR. DrlO on ret ~ 3494'. NOW: Drlg on ret ~ 3494'. 62 11/22/81 DALLY COST: ACC COST: AFE AMI: 10225' TD 9296' ETD (RET) 9 5/8" C 7282' · ; 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 26,198 $3,596,212 $2,450,000 Drld ret e 3494', cmt f/ 3496' to 3705', & ret ~ 3705'. Had void f/ 3705' to 3744'. Drld cmt f/ 3744' to 3766'. Trip for bit change. RIH w/ bit ~33 & drld ret ~ 3775', cmt f/ 3777' to 3814'. RIH to 4703' to check for stringers. POOH - LD junk subs. RIH w/ 8 1/2" bit on 9 5/8" csg scraper. NOW: RIH w/ csg scraper. UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. 21 LEASE Kenai Deep Unit WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 63 11/23/81 DALLY COST: ACC COST: AFE AMT: 64 11/24/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 9296' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 22,278 $3,618,490 $2,450,000 10225' TD 3500' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 53,418 $3,671,908 $2,450,000 RIH w/ bit & csg scrpr to liner top ~ 6915'. Circ& POOH. RIH w/ test tools (tail, RTTS, bundle carrier, aux'valve). Set pkr ~ 3425', tail ~ 3495'. Opened aux valve to dry test sqz perfs - had strong blow. Shut well in - pressure built to 536 psi in 45 min. Killed well & POOH. RIH w/ RTTS on 5" DP. Set RTTS ~ 3780' to dry test BS perfs f/ 3800' to 3802' DIL. Displaced DP w/ nitrogen & dry tested perfs - ok. Reset pkr ~ 3691' to dry test BS perfs f/ 3746' to 3748' DIL. Displaced DP w/ nitrogen & dry tested perfs - ok. N6w:~-Reset pkr to dry test perfs f/ 3548' to 3550' DIL. .. Reset RTTS ~ 3500' & displaced DP w/ nitrogen. Opened up to blow dwn nitrogen - pkr failed allowing annu- lus fluid to enter DP. Filled DP & csg & POOH - changed pkrs. RIH & set RTTS ~ 3500'. Displaced DP w/ nitrogen. Blew down nitrogen to dry test perfs f/ 3548' to 3550' DIL - had +3.0 NNCFD gas flow. Killeo well & reset pkr ~ 3685' - dry tested lower BS perfs - ok. Pkr began~to leak toward end of test. Filled DP & csg. POOH. Ran & set cmt ret ~ 3590'. Ran & set ret ~ 3500'. NOW: Prep to resqueeze perfs f/ 3548' to 3550' DIL. UNION OIL COMPANY OF CALIFORNIA WELL RECORD LEASE Kenai Deep Unit WELL NO. KDU 8 SHEET D PAGE NO. 22 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS : 65 11/25/81 DAILY COST: ACC COST: AFE AMT: 66 11/26/81 DAILY COST: ACC COST: AFE AMT: 67 11/27/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 3590' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID $ 23,054 $3,694,962 $2,450,000 RU & tested surf equip to 4000 psi, csg to 3000 psi. Broke down perfs f/ 3548' to 3550' DIL w/ 1750 psi. Pumped in w/ 5 BPM ~ 1750 psi. Form held 250 psi w/ pumps off 1 min. Mixed & sqz'd w/ 300 Sxs cl "G" w/ 30 gal/lO0 sxs D-45L, 3 gal/lO0 sxs R-12L, & 1 gal/lO0 sxs D-6L to 118 pcf. Displaced 231 sxs below ret w/ a final rate of 3.5 BPM ~ 1800 psi. Sqz held 1300 psi w/ pumps off 2 min. CIP ~ 02:00 hrs. Rev out 69 sxs cmt. POOH. RIH w/ bit #34 w/ 2 junk subs to 3000'. Circ & WOC. RIH & tagged cmt ret ~ 3500'. Drld ret ~ 3500', cmt f/ 3502' to 3570'. Drlg on ret ~ 3590'. NOW: Drlg on ret ~ 3590'. 10225' TD Drld ret ~ 3590' & RIH to 6915'. 3600' ETD (RET) Circ & POOH. RIH w/ bit & csg 9 5/8" C. 7282' scraper to 6915'. Circ & POOH. 7" L. 10225', TOP ~ 6915' RIH w/ RTTS pkr & aux valve on CaCL2 FLUID Ory DP. Set pkr ~ 3519'. Opened tool to test perfs - had slight $ 35,129 blow. Blow increased steaoily over $3,730,091 45 min. Killed well & POOH. RIH & set cmt ret on DP ~ 3600' DPM. $2,450,000 POOH. RIH w/ RTTS sqz tool. 10225' TD 3590' ETD (CMT) 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' CaCL2 FLUID ' $ 33,993 $3,764,084 $2,450,000 NOW: RIH w/ sqz tool. RIH & set RTTS pkr ~ 3504'. Tested surf lines to 4000 psi. Broke dwn perfs f/ 3548' to 3550' DIL w/ 2200 psi. Pumped in w/ 2.5 BPM ~ 2000 psi.' ReseW RTTS ~ 3408' Sqz'd perfs w/ 200 sxs cl "G" ~/ 4 gal/- lO0 sxs D-45L, 3 gal/lO0 sxs R-12L, 1 gal/lO0 sxs D-6L to 118 per. Dis- placed cmt 100' below tool w/ a final rate of 1.5 BPM ~ 1900 psi. CIP ~ 03:48 hrs 11/27/81. WOC 4 hrs - press bled to 0 psi. POOH w/ DR. RIH w/ 8 1/2" bit to 3000' & WOC. RIH & tagged cmt ~ 3521' (13' iow). Drld cmt f/ 3521' to 3568'. RIH to 3590'. Circ & POOH. RIH w/ bit & csg scraper to 3590'. Circ & POOH. NOW: POOH w/ bit & csg scraper. SEP 2 f ',;, SHEET D UNION OIL COMPANY OF CALIFORNIA WELL RECORD PAGE NO. 23 LEASE Kenai Deep Unit WELL NO. KDU 8 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 68 11/28/81 DAILY COST: ACC COST: AFE AMT: 69 11/29/81 DAILY COST: ACC COST: AFE AMT: 70 11/30/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 6915' ETD (RET) 9 5/8" C. 7282' 7" L. 10225', T0P ~ 6915' CaCL2 FLUID $ 21,239 $3,785,323 $2,450,000 10225' TD 6915' ETD (TOL) 9 5/8" C. 7282' 7"'L. 10225', T0P ~ 6915' CaCr...~"~LU I D $ 37,556 $3,822,879 $2,450,000 10225' TD 6915' ETD (TOL) 9 5/8" C. 7282' 7" L. 10225' TOP ~ 6915' CaCL2 BRINE $ 21,298 $3,844,177 $2,450,000 POOH w/ bit & csg scraper. RIH w/ RTTS pkr & set ~ 3482'. Opened tool to dry test perfs f/ 3548' to 3550' DIL - ok. Filled DR & POOH. RIH w/ 8 1/2" bit & drld ret ~ 3600'. RIH to 6915' & circ btms up. POOH. RIH w/ bit & csg scraper to 6S05'. Circ& cleaned mud pits. NOW: Dumped & cleaning mud pits. Dumped & cleaned mud pits. Filled pits w/ water & mixed clean CaCL2 fluid. Displaced hole w/ clean CaCL2 fluid. LD excess 5" DR, 5" HWDR, 4 3/4" DC's, & 3 1/2" HWDR. RIH w/ RTTS pkr & set ~ 3483'. Tested surf equip to 3500 psi Displaced DR w/ nitrogen. RU Schlumberger & tested lubricator to 3500 psi. RIH w/ 5' of 2 1/8" ener- jet perf guns. Bled nitro cushion to 1000 psi. Rerfed top of A-8 sd f/ 3553' to 3558' DIL - had no press increase. Bled nitro cushion to 500 psi. Press built to 600 psi in 3 min. Bled off nitrogen cushion & flowed well to clean up. NOW: Flowing well to clean up - well making 6.78 MMCFD w/ 768 psi DP pressure. Flowed A-8 perfs f/ 3553' to 3558' DI1 thru pkr ~ 3479' until clean. Rate'stabilized ~ 6.78 MMCFPD w/ no water. ~Perfed remain0er of A-8 sd f/ 3558' to 3575' DIL. Initial rate 6.78 MMCFPD w/ 36.6 BWPD & tr of sd. NOW: Flowing A-8 sd. UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. 24 LEASE DATE Kenai Deep Unit ETD WELL NO. KDU 8 FIELD Kenai Gas Field DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 71 12/1/81 DAILY COST: ACC COST: AFE AMT: 72 12/2/81 __ _ DAILY COST: ACC COST: AFE ANT: 73 12/3/81 DAILY COST: ACC COST: AFE AMT: 74 12/4/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 6915' ETD (TOL) 9 5/8" C. 7282' 7" L. 6915' to 10225' CaCL2 BRINE $ 24,159 $3,868,331 $2,450,000 10225' TD 69!~TD (TOL) 13 3/8" C. 2566' 9 5/8" C. 7282' 68 PCF BRINE $ 96,983 $3,965,314 $2,450,000 10225' TD 6915' ETD (TOL) 13 3/8" C. 2566' 9 5/8" C. 7282' 68 PCF BRINE $ 36,095 $4,001,409 $2,450,000 10225' TD 6915' ETD (TOL) 13 3/8" C. 2566' 9 5/8" C. 7282' 68 PCF BRINE $ 152,342 $4,153,751 $2,450,000 Tested A-8 perfs f/ 3553' to 3575'. Stabilized rate 6.4 MMCFPD, 4.8 BWPD, & 825 psi tbg press. Inflow perfed 4 HPF A-10 sd f/ 3624'.... to 3649' & f/ 3652' to 3677' the A-il sd f/ 3724' to 3739' & the B-1 sd f/ 3772' to 3792'. Tested A-8, A-10, A-ii & B-1 perfs. Stabilized rate 8.15 MMCFPD, no water & 955 psi tbg press. Inflow perfed A-8 f/ 3553' to 3575' w/ 4 HPF (8 HPF total now). NOW: Reperfing A-10, A-il & B-1. Continued reperfing the A-lO.f/ 3624' to 3649' & 3652' to 3677', A-il f/ 3724' to 3739', B-1 f/ 3772' to 3792'. Killed Well. Spotted 60 bbl Dril-S & safe-seal pill on btm to stop loss circ. POOH LD 3 1/2" DP. RIH w/ 9 5/8" scrpr & 8 1/2" bit to 4000'. POOH LD 3 1/2" DP. Set Baker model "D" perm pkr on WL ~ 3756' RIH w/ seal assy on 5" DP. Teste~ pkr ~ 3756' - ok. P00H LD 5" DP. LD Kelly. Installed dual 3 1/2" rams in BOP. NOW: Prep to run tbg. Ran dual 3~1/2'' comp assy. Landed tbg w/ LS MS ~ 3766', SS MS ~ 3512' & dual g-5 pkr ~ 3506'. NOW: Landing tbg. LEASE Kenai Deep Unit UNION OIL COMPANY OF CALIFORNIA WELL RECORD WELL NO. KDU 8 SHEET D PAGE NO. 25 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 75 12/5/81 10225' TD 6915' ETD.(TOL) 13 3/8" C. 2566' 5/8" C. 7282' PKR FLUID DAILY COST: ACC COST: AFE AMT: DAILY COST: $ 36,342 ACC COST: $4,190,093 AFE AMT: $2,450,000 76 12/6/81 10225' TD 6915' ETD (TOL) 13 3/8" C. 2566' 9 5/8" C. 7282' RKR FLUID $ 44,737 $4,234,830 $2,450,000 77 12/7/81 DAILY COST: ACC COST: AFE ANT: 78 12/8/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 6915' ETD (TOL) 13 3/8" C. 2566' 9 5/8" C. 7282' 7" L. 1_0225', TOR ~ 6915' PKR FLUID $ 18,398 $4,253,228 $4,270,000 10225' TD 6915' ETD (TOL) 13 3/8" C. 2566' 9 5/8" C. 7282' 7" L. 10225', TOR ~ 6915' RKR FLUID $ 18,837 $4,272,065 $4,270,000 Completed landing tbg. Set plug in "XN" in SS ~ 3510' on Otis WL. Set Baker "A-5" hydro-pkr w/ BO. Pulled plug f/ XN & tested A-5 pkr - ok. Opened sleeve in SS ~ 3462'. Dis- placed annulus w/ pkrfluid. In- stalled BPV's. Removed BOPE. In- stalled & tested CIW X-mas tree. Installed & tested tree. Removed BPV's. RU Otis on LS. RIH - opened "XA" sleeve in LS ~ 3745'. Closed "XA" in LS ~ 3455'. Closed "XA" in SS ~ 3462'. RU BO on LS & displaced down LS & up SS w/ nitro. Opened well to flow & flowed 10 min. Shut well in & closed "XA" in LS ~ 3745'. Flowed both strings individually to clean up. Installed BPV's. Began to rig down. NOW: Rigging down. Rigging down to move to KBU #31-7. Disconnected pumps and Swaco unit. Laid derrick down. NOW: Rigging down. Continued ~o rig down to move to KBU #31-7. Moved Swaco unit to new lo- cation. NOW: Rigging down. Oil & Gm'; Cons. UNION OIL COMPANY OF CALIFORNIA WELL RECORD LEASE Kenai Deep Unit WELL NO. KDU 8 SHEET D PAGE NO. 26 FIELD Kenai Gas Field DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 12/9/81 DAILY COST: ACC COST: AFE AMT: 10225' TD 6915' ETD (TOL) 13 3/8" C. 2566' 9 5/8" C. 7282' 7" L. 10225', TOP ~ 6915' PKR FLUID $ 18,837 $4,290,902 $4,270,000 Removed derrick f/ subbase. Com- pleted general rig down. Moved sub- bases over KBU #31-7. Released rig ~ 19:00 hfs 12/9/81. ~SE Kenai Deep Unit UHIOH OIL CaiP~'h' ~ CALIFOP¢iIA hELL RECORD WELL NO, ~x-6 FIELD KGF SI-~EET-D PAGE ih, -'- DATE From 2565.61 A563.78 2527.50 2525.34 135.00 103.30 29.25 28.00 From 7282.36 7280.68 7198.76 7197.14 28.00 ETD To 2563.78 2527.50 2525.34 135.00 103.30 29.25 28.00 -0- To 7280.68 7198.76 7197.14 28.00 -0- OF OPERATIOItS, DESCRIPTIO]tS &RESULTS. Length 1.83 36.28 2.16 2390.34 .31.70 74.05 1.25 13 3/8" csg. Detail Jts. Description B&W 13 3/8" Float Shoe 1 13 3/8" 61# K-55 Butt B&W 13 3/8" Float Collar 61 13 3/8" 61# K-55 Butt 1 13 3/8" 61# K-5$.Butt pup 2 13 3/8" 61# K-55 Butt CIW ~3 3/8" x 20" Flow through Hanger Landed Below R.T. Length 1.68 81.92 1.62 9 5/8" Csg. Detail Jts. Description B&W 9 5/8" Float Shoe 2 9 5/8" 47# N-80 Butt Baker 9 5/8" Float Collar 173 9 5/8" 47# N-80 Butt 7169.14 Landed below RT. ~SE DATE From 10225.00 10223.15 10179.97 10179.02 10135.18 10134.14 10093.13 10092.23 10051.30 10050.35 9929.39 9907.94- 9668.02 9647.48 9276.34 9255.94 8546.84 8525.54 6927.55 U['lIOl,l OIL CO~'?A~'h' OF CALIFORNIA ~ELL RECORD S~EE-I'~D PAGE ih, A-028142 ETD TO ~ 10223.15 10179.97 10179.02 10135.18 10134.14 10093.13 10092.23 10051.30 10050.35 9929.39 9907.94 9668.02 9647.48 9276.34 9255.94 8546.84 8525.54 6927.55 6915.19 ~ELL NO, 14X-6 (KDU8) FIELD KGF DETAIL, S OF OPERATIOHS, DESCRIPTIO~'.!S &.RESUL,TS Length 1.85 7" Liner Detail Jts Description B.O.T. Float Shoe 43.18 1 .95 43.19 1 1.69 41.01 .... 1 .90 40.93 1 .95- 120.96 ..... 3 21.45 239.92 6 20.54 371.14 ~ 9 20.40 709.10 21.30 18 1597.99 --- 39 12.36 7-" 29~ N-80 Butt B.O.T. Float Collar 7" 29# N-80 Butt Howco Float Collar 7" 29# N-80 Butt B.O.T. Catcher Sub 7" 29# N-80 Butt B.O.T. Landing Collar 7" 29# N-80 Butt 7" pup 29# N-80 Butt 71! 7" pup " 11 Ii 7" pup " 11 ii 7" pup ,, 11 ii B.O.T. Liner Hanger N ION OIL CO. OF CALIFORNIA REPAIR RECORD SHEET B PAGE NO. J' -. LEASE KENAI DEEP UNIT COMPLETION DATE WELL NO. 14X-6 (KDU #8) FIELD KENAI GAS FIELD APPROVED DATE E.T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS Jts 9 9 3 10 5 4 5 14 3 3 5 7 4 9 7 3 2 2 Description Length Btm Top 3 1/2" Guide Shoe .90' 3 1/2" Seal Assembly 10.50' Baker model "D" pkr w/ 4 3/4" bore set @ 3756' Locator Sub 3 1/2" 9.3# N-80 Pup 3 1/2" Otis "XA" Sleeve 3 1/2" Blast its 3 1/2" 9.2# N-80 Pups (3) 3 1/2" Blast Jts 3 1/2" 9.3# N-80 tbg 3 1/2" Blast its 3 1/2" 9.2# N-80 tbg 3 1/2" 9.2# N-80 Pups (2) 9 5/8" X 3 1/2" X 3 1/2" "A-5 pkr 3 1/2" 9.2# N-80 tbg 3 1/-~" 9.2# N-80 Pup 3 1/2" Otis "XA" Sleeve 3 1/2" 9.2# N-80 Butt tbg 3 1/2" 9.2# N-80 Pup -3- 112''~ 9.~FN-80 Butt tbg 3 1/2" 9.2# N-80 Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" 9.2# N-80 Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" 9.2# N-80 Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" 9.2# N-80 Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" 9.2# N-80 Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" 9.2# N-80 Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt!tbg 3 1/2" Pup ~ 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tb.~ 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pup 3 1/2" 9.2# N-80 Butt tbg 3 1/2" Pups (4) CIW tbg hanger Landed below KB 3766.40' 3765.50' 3765.50' 3755.00' .90' 3755.00' 3754.10' 5.10' 3754.10' 3749.00' 4.00' 3749.00' 3745.00' 38.90' 3745.00' 3706.10 14.14' 3706.10' 3691.96 78.73' 3691.96' 3613.23 31.05' 3613.23' 3582.18 36.27' 3582.18' 3545.91 30.58' 3545.91 ' 351 5.33 10. 26' 3515.33' 3505.07 12.87' 30.22 2.09 4.00 270.68 4.08 270.44 3.42 90.25 5.10 303.84 3.08 147.88 4.08' 119.94' 5.06' 149.21 ' 5.13 41 9.23 5.08 88.11 5.10 89.53 5.12 150.52 5.25 21 O. 60 4.10 121.46 5.15 267.45 5.10 209.62 5.10 5.10 59.11 4.07 60.15 4.00 211.16 19.03 .83 24.03 3505.07' 3492.20' 3461.98' 3459.89' 3455.89' 3185.21 ' 3181.1 3 291 O. 69 2907.27 281 7.02 2811.92 2508.08 2505. O0 2357.1 2 2353.04 2233.10 2228.04' 2078.83' 2073.70' 1654.47' 1649.39' 1561.28' 1556.18' 1466.65' 1 461.53' 1311. O1 ' 1 305.76' 1095.16' 1 091.06' 969.60' 964.45' 697.00 691.90 48 2.28 a77.1~ 387.68 382.58 323.47 31 9.40 259.25 255.25 44.09 25.06 24.03 All tubing is 3 1/2" buttress w/ special clearance collars 3492.20 34.61.98 3459.89 3455.89 3185.21 3181.13 2910.69 2907.27 281 7.02 2811.92 2508.08 2505.00 2357.12 2353.04 2233.10 2228.04 2078.83 2073.70 1654.47 1649.39 1561.28 1556.18 1466.65 1461.53 1311.01 1305.76 1095.16 1091.06 969.60 964.45 697.00 691.90 482.28' 477.18 ?P 7. ~P 382.58 323.47 319.40 259.25 255.25 44.09 25.06 24.23 0 UNION OIL COMPANY OF CALIFORNIA WELL RECORD SHEET D PAGE NO. LEASE Kenai Deep Unit WELL NO. KU #14X-6 (KDU #8) FIELD Kenai Gas Field DATE ETD. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS Ots 2 12 97 SHORT STRING TUBING DETAIL DeScription Length 3 1/2" Otis XN nipple 3 1/2" 9.2# N'80 butt pup 9 5/8" X 3 1/2" X 3 1/2" A-5 pkr 3 1/2" 9.2# N-80 butt 3 1/2" Otis XA sleeve 3 1/2" 9.2# N-80 butt tbg 3 1/2" 9.2# N-80 butt pup 3 1/2" 9.2# N-80 butt tbg 3 1/2" butt pup 3 1/2" 9.2# N-80 butt tbg 3 1/2" butt pup 3 1/2" butt pup 3 1/2" butt pup CIW tbg hanger Landed. below RKB Top B.tm 1.55 3510.53 3512.08 4.08 3506.45 3510.53 10.75 3495.70 3506.45 29.38 3466.32 3495.70 4.00 3462.32 3466.32 62.83 3399.49 3462.32 4.02 3395.47 3399.49 366.57 3028.90 3395.47 4.13 3024.77 3028.90 2982.34 42.43 3024.77 10.00 32.43 42.43 4.03 .28.40 32.43 3.34 25.06 28.40 .83 24.23 25.06 24.23 0 24.23 Mr. John Underhill Union Oil Company P. O. Box 6247 Anchorage, Alaska 99502 September 28, 1981 Re: Our Boss Gyroscopic Survey Well No. k~.'(SEC~4N ~1'1~)~ Kenai Gas Field Kenai Peninsula, Alaska Date of Survey: September 27, 1981 Operator: Chris Willoughby Dear Mr. Underhill: Please find enclosed the "Original" and seven (7) cOpies of our Boss Gyroscopic Multishot Directional Survey on the above well. Thank you for giving us this opportdnity to be of service. Yours very truly, NL SPERRY-SUN, INC. Ken Broussard District Manager KB/pr Enclosures SPERRY-SUN WELL SURVEYING COMPANY PAGE ! ANCHORAOE ALASKA UNION ,_niL COMPANY DATE OF SURVEY SEPTEMBER 27, KENAI riEEP LINIT-NO;--8 ...... :--: ....................... COMPUTATIO~ DATE"- :'i~::::: ; · BOS~GYROSCOP,I_,C SURV~ KENAI GAS FIELD .' : · ; · SEPTEMBER ~8, ,JO, B NUMBER B0~S-1689~ ALASKA : :i ~ ::':::.. , KELLY BUSHING ELEV-=. 26.25 FT. TRUE SUB-SEA COURSE COURSE DOG-LEG TOTAL MEASURED .... VERTICAl- ........VERTICAL - INCLINATION -- DIRECTION~SEVERITYT:RECTANGULAR ---COORDI-NATES----VERTICAL DEPTH DEPTH DEPTH DEG MIN DEGREES.>?~iii:~ DEO/lO0:ii' NORTH/SOUTH EAST/WEST o ........ o oo :' ......... ........... o ....... o .-- o:-o o oO 100 100.00 73.75 0 7 S 69.80 E 0.13 0.04 S 0.11 E 200 200,00 173.75 0 22 S 62.50 E 0.24 0.23 S 0.50 E 300 .... 300~-00 ...... 273~ 75 ' 0 ' ~21 ......... N,'8~O~W 0~2t .. 0~"34-'-8 ........... l'~-09'-E~ 400 400. O0 373.75 0 7 :N 21':;::8~'~: 31 O- 21 S 1.43 E /:~ 22 ~ 80 :~ W ~:::~ ::~:~::~:.?O- 1'4 . 500 500. O0 · .473.75 0 11 700 699.99 673.74 0 23 S 2.69 W 0.04 0.74 S 1.29 E 800 799.~9 773.74 0 34 S 11.39 W 0.19 1.57 S 1.17 E 900 ..... 899, 98 ....... ~- 873~ 73 --- 0- 22 ..... ?S--42~'60-W 05-32 ............. 2~"~0-S ........... 0~85-E . .: 1000 999.98 973.73 0 37 S'42-19 W.. :::..~:~::::~:0-24.... . 2.95 S 0.26 E 1100 1099.98 . '1073.73 0 36 S'22.39 E>:~'~;:~::?~:~-~?:O.~5 3.83 S' 0.10 E ..... . .... 1200 - 1199.97 ....... 1173~-72 ........ 0 ..... 41 1300 1299.96 1273.71 0 45 S 81.80 E 0.43 5.23 S 1.83 E 1400 1399.95 1~7~.70 i 16 S ~5.69 E 0.52 5.40 S 3.58 E 1500 1499.93 ...... 1473.68 ........... 1 0 .... N-~81.'80--W-? 1600 1599.91 :1573.66 1 0 S 81;50 E :~:"~ ':::~::::0~:29 ' 5.37;-S ,': ':::?:7'29 E 1700 16~9 90 1673.65 ' : 0 49 S ~ : : ::::::: .... : ' ~ -1~00 17~. 8~ t773: ~ 1~00 18~.88 1873.~3' 0 40 S 53.~ E 0.11 7.21 S 11.04 E 2000 1~.87 1~73,~2 0 33 S 42,~0 E 0.1~ 7.~2 S 11,84 E .... 2100 20~, 87 ..... 2073~ ~2 .................. 2200 21~,~ 217~.~1 :' ::: :: 0 52 S ~1~0 E : '::::::: :0, ~3 : ~ ~ S - 1~ 20 E 2300 22~,8~ 2273.~0 :": :::-:.0: 4~ ~ ~1:~:~0 E ::-::-::0.:10 : ~,~3 ~ ': 14,47 E ::: · . . ::: ::.:::-' ~ . . SECTION~. 2400 2500 2550 2399, 84.-: 2499,84 2549.83 0;00 0.11 0.55 ............. t;11 1.34 1.18 1;-19 1.49 1.81 1.73 2.04 3~05 .... 4.24 5.84 7~~, 10.55 1-1~3--- 13.18 14.23 14~'92 ..... 15.~1 17.3~ ...... 0-'45 ..... S--77~60---E" : : 0:22~:::' . m : ....... :' i' ' ~10 ~-'09-S "15',-72--E ......... 18~ 67 .... 2473.5.9 0 46 S 77.60 E 0.02 10.38 S 17.03 E 19.~4 252~.58 0 40 S 86. I0 E 0.30 10.48 S 17.66 E 20.53 HORIZONTAL DISPLACEMENT = 20.53:-:: FEET:AT-SOUTH: 59 DEG':::.: :ig::MIN' EAST AT MD --- 2550 , THE CALCULATION PROCEDURES ARE-BASED ON--THE-usE-OF----THREE-D-IMENSIONAI:--RADIUS--OF-CURVATURE-METHOD, - UNION OIL COMPANY - -KENAI DEEP-UNIT---NO.---8 ..... KENAI GAS FIELD ALASKA SPERRY-SUN WELL SURVEYING COMPANY PAGE 2 ANCHORAGE ALASKA DATE OF SURVEY SEPTEMBER 27, 1~1 ............... COMPUTATION-DATE ~ :SEPTEMBER i~28,~ ~1~81<!ii~i/i~!~iili~:~. :'~i:-,/,'i'i.il;:'dOB ~ NUMBER BOSS-16893 ~. ~!:ii .i'i?~!i?!!;~ ~ ~.~::/i?~i!!:~ili!?!il;~i~:~i~:ii'!?i:(-'. KELLY BUSHING~ ELEV. = 26.25 FT. . .. : .i : ....... INTERPOLATED VALUE8 FOR EVEN 1000 FEET OF MEASURED DEPTH MEASURED VERTICAL '.. VERTICAL RECTANGULAR}~:~icOORDINATES .MD'TVD :::.i:i:::~i::'~:: VERTICAL DEPTH - - - DEPTH.-----i-~C~ .... DEPTH ..... 2-NORTH/SoLITH":-;'--:--~'EAST-/WEST---~DIFFERENCE '~ ~' --~ORREGT-IQN 0 0. O0 -26.25 O. O0 O. O0 O. O0 ........ 1000 .- 999.-98 ........ 973.-73 .................. :..2..-95-4~. .. -0.-26- E------ 0-.-02. 0.-0-2 2000 1999.87 i : 1973.62 :' 7, 92 :;~i$:1-':::.ii::~i:::?! ?:i:~ ::::i ! !. 84 E. ' :ii:'~: ,i?..~:'::0'-::.13:::i :.: ::: i:~:: : O. 11 :-.:' 2550 254':.:2.83 ': i'7'..2523"58 :::10~:48 i::Si:~ ?'-!:!'~.ii:!i'ii'. :;7:I:I!: 17' 6~.'-"' E :' :": :ii,?;i 0i17::!i.,'i!:i i' :::7.' O. 04 .'.i.:. · . ' THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE DIMENSIONAL RADIUS OF CURVATURE METHOD. ,_ SPERRY-SUN WELL SURVEYING COMPANY PAGE 3 ANCHORAGE ALASKA UNION OIL COMPANY DATE OF SURVEY SEPTEMBER 27, 1.9~i KENA I-- DEEP -LIN I T---NOi-8 COMPUTAT I ON--DATE KENAI ~3AS FIELD ~'~..~ .~.. ~ ~ ~ ' ~'~ ~"'-~ SEPTEMBER-~ 28,~. 1.981 . i ,.~ ~?~.ii?.ilJoBi~iNUMBER BOSS-16893= ALASKA __.~_ ~ iii :: -: ' -~ ~:''' :.' ': ': : ~''': ' ' ~ ::':i~ i'!~"?i:ili~KELLY BusHING'ELEV- : 26.25 FT. ................. · .. · ~ :::::.:-i~:~,-;:i,i~::?.,. OPERATOR_ _OHRt.s~W:.~_L_OUGHB¥ INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH : .. ~ .... ~- ~--- : . . '- .~. '~ ~ . :':~i ........ ii ii:~i: ~.~i~!!~::~i ~:!i :i:::i i ~' ~ ' -~: .~ ' TRUE ~ UB~EA. :?< ~:-~i!~. ~: ? ?i. :¥ ~:~r~:: TOTAL ~' . MEASURED VERTICAL vERTICAL i :'~ :~'i~ ::' R~TANGO~AR ':~: COORDINATES -DEPTH .......... DEPTH ........ :-:'DEP-T-H'-~--~- NOR-TH/SOUTH~:~ ~:-:: ~ EAST-¥WEST--L D I FFERENC-t~ 0 0.00 ............ 26 -26.25--- 126 126.25 226 226.25 ............ 326 ....... 326.25 -.. 426 426.25 526 526.25 ........ 626 .......... 626.25- 726. 726.25 ~ 826 ~ 826.25 ........... 926---: ..... ~26.25 ..... 1026 1026.25 1126 1126.25 400.00 500.00 .-600.00 700.00 800.00 -900.00 1000.00 I100.00 0.16 S 1.45 E 0.00 0.13 N 1.37 E 0.00 0 r26--$ . . -~ 1 .-~ 1-- EI~~~0 :0' .gz~' S,~i: :!.:' :.ii:!i;!' ~. 1.28 E 0- 3.16 S 0.07 E 0.02 4.0.9 S 0.20 E 0.03 0.00 O. O0 O. O0 0.00 ' . :. O. O0 0~00 ': ' 0.01 0.01 .......... 1226 .........1226.25 ........ 1200.00 ............ 4-.-.9~S :: 0.97--E .:0-~0~ . .. .-0~00 1326 1326.~5 . :: 1300.00 : : 1426 1426. ~5;.:i::': ii:'i': 1400. O0 .......... 1526 ..... 1526.--25-~;i .'.-1500,00 1626 1626.25 1600. O0 5.44 S 7.75 E O. 10 O. 02 1726 1726.25 1700.00 6.01 S 9.14 E 0.11 0.01 UNION OIL COMPANY KENAI--DEE~ UNIT-NO.-8 KENAI GAS FIELD ALASKA SPERRY-SUN WELL SURVEYING COMPANY PAGE ..4 ANCHORAGE ALASKA ' DATE OF SURVEY SEPTEMBER 27, 19~1 · :~: ::-'~:-::r-?:i<i~ SEPTEMBER28, 1981 ' :: ~ :~::~ ;"i.iq3!? :::~iii:i:dOB NUMBER ! BOSS- 16893 · ~. '~!'~i!i~ i!! i~.i:~i ~.i. i ~ i~i"i~iiiii!:i!i:iii~iii~ii~:ii:i!:ii?-i:KELLY BusHING ELEV. = 26.25 FT. ·: :~ :.: i' ~i?i:~!Z:'~i!~!i~ii! ! !!::~IOPERATOR_~HRI~S_W_I~_~OUGHB¥ INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH MEASURED · VERTICAL ' 'VERTICAL RECTANGULAR~!'cOORDINATEs--: ::~ VERTICAL ~'.~.~,.; ~'~- . . : '.:. :: .: : :::: .-.::.': ........... DEP.TH ~ DEPTH '~ · DEPTH _.. NoRTH~-$OUT-H :~ EAST~-WES-T, i~:~DIFF-ERENCE c:¥.,r:?:'CORRECT_iON ::' ~':::: ;' ~ : 1826 1826.25 1800.00 6.70 S 10.31 E 0.12 0.00 ..........202621261926 ..... 2026,252126,1-926' 2525: ...... ::i'2000'211900'-0000, 0000 .7._,..39_~ li_,_29_E._. ......... 0-._. 12 :~ . 0,-00. ? ~. ~ ~ ~:{:~::~ '8't1.~ ::: :;..'. :': ~.~ ~:~: 0.01 .............. 2226_. ~:~2226;_25/_ :~ ' :2200' O0 -::~::~::.~::?~:~:~::? :~-%13___S ::~ :::: :~: :::13:~ 55~E~i;?~L~f-;~F~::~?/~:~.~::~:::~:.~.~!:~:~::0~..:! 4 '..::" : · 2326 2326, 25 2300, O0 ~, 80 S 14, 7~ E O, 15 O, 01 2426 2426, 25 2400, O0 10, 17 S 16, 06 E O, 16 O, O0 ............ 2526 .... 2526,_25 .......... 2500, O0 ........... ~ 0,_~5_S. .1Z,S7--E .0~7- 0,-00 . .:: . - ::::::::::::::::::::: ::?~:~::::: . :;: :. ).:~?..~:.?~?:?~Z?? ?.:.:'~?-:?::~::~?:~::C:.~L: ::~j; ?~::: ~. THE NEAREST 20 FOOT 'MD (FROM RADIU~ OF CURVATURE) POINTS D U N C A N , 0 K L A H 0 M A KENAI DEEP UNIT Lease Name 564704.1 Ticket Number ~ 1 Well No. Test No. KENAI Camp 9333' -10050' Tested Interval 11-8-81 Date UNION OIL COMPANY OF CALIFORNIA Lease Owner/Company Name H-311 H-310 HI-196 Gauge Number(s) _ TICKET NO i LEASE OWNER LEASE NAME 564704.1 DATE 11-8-81 HALLIBURTON CAMP UNION 0IL COMPANY OF CALIFORNIA KENAI DEEP UNIT WELL NO, TEST NO KENAI bc/vf 1 ALASKA LEGAL LOCATION S6-T4-R11 FORMATION TESTED FIELD AREA KDU COUNTY KENAI BOgOUGH STATE TYPE OF D.S.T WATER SHUT OFF TESTER(S). D. E. MC MAHAN DICK PIKE WITNESS GARY BUSH DRILLING CONTRACTOR BRINKERHOFF #59 DEPTHS MEASURED FROM KELLY BUSHING CASING PERES (FT.) 9398'-9400' TYPE AND SIZE OF GAS MEASURING DEVICE CUSHION DATA TYPE Water AMOUNT 591 GAL WEIGHT (lb./gal.), 8.33 AMOUNT WEIGHT (lb./gal.), TYPE, RECOVERY (ft. or bbl.): FLUID PROPERTIES CHLORIDES CHLORID ES SOURCE RESISTIVITY (PPM) SOURCE RESISTIVITY (PPM) @ °F @ °F @ °F @ OF @ °F @ °F REMARKS: -SEE PRODUCTION TEST DATA SHEET- III FORM NO. 325--LIyTL£'C 1146'76 31/I 7/81 FORMATION TEST DATA (SHEET 1) 564704.1 11-8-81 TICKET NO. DATE.. 9333 ELEVATION (FT) .BOTTOM OF TESTED INTERVAL (ft.) TOP OF TESTED INTERVAL (ft.) NET PAY (ft.). 2 HOLE OR CASING SIZE (in.) 7 SURFACE CHOKE (in.) .125 TOTAL DEPTH (ft.) MUD WEIGHT (lb./gal.) BOTTOM CHOKE (in.) 10050 10050 10.4 VISCOSITY (sec.) 2.25 OIL GRAVITY @ OF GAS GRAVITY--ESTIMATED ACTUAL PRESSURE (P.S.I.) C.C.'s OF OI! C:C.'s OF MUD SAMPLER DATA · CUBIC FT. OF GAS, C.C.'s OF WATER .TOTAL LIQUID C.C.'s. GAS/OIL RATIO (cu. ft. per bbl.) FROM SAMPLER OTHER~ SERIAL NO. HT-196 ~ . RECORDER AND PRESSURE DATA · . CHARTS READ BY. D. E. MC MAHAN DATA APPROVED BY. TEMPERATURE (OF) ESTIMATF ACTUAL 138.9 DEPTH (ft.) H.T.-500 FI; T.E. OR R.T.-7 F-I; THERMOMETER F-I; OTHER [] ~^u~ ~u~,~ ~-~ z ~-~zo TIM ES R (00:00-24:00 HRS.) GAUGE TYPE 3 3 2258 TOOL OPENED O R GAUGE DEPTH (ft.) 9326 9326 DATF 11-8-81 D i~ CLOCK N,UMBER 22455 22929 0008 BYPASS OPENED S CLOCK RANGE (HR.) 48 72 DATF 11-9-81 INITIAL HYDROSTATIC 5257.7 5266.6 PERIOD MINUTES INITIAL FLOW 571.4 566.6 XXX XXX · . P 1st. FINAL FLOW 574.5 566.6 1st. FLOW 70 R 1st. C.I.P. CLOSED-IN E S INITIAL FLOW XXX XXX S 2nd. FINAL FLOW 2nd. FLOW U 2nd. C.I.P. CLOSED-IN R E INITIAL FLOW XXX XXX S 3rd. FINAL FLOW 3rd. FLOW · CLOSED-IN 3rd. C.I.P. FINAL HYDROSTAT,C 5257.7 5266.6 XXX XXX :ORI,{ I~lO. 327--tlTTLE'$ 114675 31,4 7/81 FORMATION TEST DATA (SHEET 2) ,, 564704.1 Casing perfs. Bottom choke Surf. temp °F Ticket No, C~s gravity Oil gravity GOR Spec. gravity Chlorides .,ppm Res., ~ °F INDICATE TYPE AND SIZE OF GAS MEASURING DE¥1CE USED Date Choke Surface Gas Liquid Time a.m. Size Pressure Rate Rate Remarks m.m. psi MCF BPD 11-8-81 1710 Clocks inserted. 1845 Made up tools. 1925 Went in hole. ,. 2045 Put in water cushion. 2100 'Went in hole. 2235 Rigged up surface equipment. 2250 Set packer. 2258 .125 0 Opened auxiliary valve-very weak blow. 2315 Well died. 11-9-81 0008 Opened by-pass and filled hole and circulated water cushion out. 0045 Unseated packer. 0050 Broke out surface equipment. , , 0115 Ran tools on to bottom for next test. Tools hanging free while rig does surface work. 0700 Released-on will call. . , · ~OR~ 1B2-RI~PRINTE:D IN U.S.A. PRODUCTION TEST DATA TICKET NO. 564704.1 Tool Description O.D. I.Do Length Depth DRILL PIPE AUXILIARY VALVE BUNDLE CARRIER X/O CIRCULATING VALVE PACKER X/O TAIL PIPE 4.63" 5.375" 3.5" 4.87" 5.75" 3.5" 3.5" 2.764" 2.44" 2.25" 2.764" 2.44" 2.36" 2. 764" 2.922" 9312' 7.28' 7.90' .79' 3.51' 4.36' .88' 62.32' 9318' 9326' 9328' 9333' EQUIPMENT DATA SHEET TIME Horizontal Line El a c h E q u a I '! 0~0 0 p.s.i. DUNCAN, OKLAHOMA KENAI DEEP UNIT Lease Name 564704.2 Ticket Number --8-- 2 Wel'l No. Test No. KENAI Camp 9826'-10050' Tested Interval 11-10-81 Date UNION OIL COMPANY OF CALIFORNIA Lease Owner/Company Name H-311 H-310 HT-196 Ga uge Number (s) TICKET NO. LEASE OWNER 564704.2 DATE 11-10-81 UNION OIL COMPANY OF CALIFORNIA KENAI bc/vf LEASE NAME LEGAL LOCATION S6-T4-R11 FIELD AREA KDU TYPE OF D.S.T CASED HOLE KENAI DEEP UNIT WELL NO ~ TEST NO FORMATION TESTED COUNTY ., KENAI STATE ALASKA TESTER(S). D. E. MC MANAN DICK PIKE WITNESS. GARY BUSH DRILLING CONTRACTOR BRINKERHOFF #59 DEPTHS MEASURED FROM.. KELLY BUSHING CASING PERFS (FT.) 9948'-9953' TYPE AND SIZE OF GAS MEASURING. DEVICE .... I TYPF 'TYPE CUSHION DATA NITROGEN AMOUNT 2750 PSI WEIGHT (lb./gal.) RECOVERY (ff. or bbl.): AMOUNT WEIGHT (Ib./gol.) FLUID PROPERTIES CHLORIDES CHLORIDES SOURCE RESISTIVITY (PPM) SOURCE RESISTIVITY (PPM) ,, @ °F @ OF @ °F @ °F · @ °F @ OF REMARKS. -SEE PRODUCTION TEST DATA SHEET- I I I I FORM NO, '~26--LITTLE'$'114676 :SM '7/81 FORMATION TEST DATA (SHEET 1) TICKET NO LEASE OWNER LEASE NAME 564704. Z DATE 11-10-81 UNION OIL COMPANY OF CALIFORNIA I HALLIBURTON CAMP i i i KENAI DEEP UNIT WELL NO ~ TEST NO KENAI bc/vf LEGAL LOCATION S6-T4-R11 FIELD AREA KDU , TYPE OF D.S.T. CASED HOLE FORMATION TESTED, COUNTY ,KENAI STATE ALASKA TESTER(S) D. E. MC MANAN DICK PIKE WITNESS, GARY BUSH DRILLING CONTRACTOR BRINKERHOFF #59 DEPTHS MEASURED FROM KELLY BUSHING CASING PERFS (FT.) 9948'-9953' TYPE AND SIZE OF GAS MEASURING. DEVICF i TYPE NITROGEN CUSHION DATA AMOUNT 2750 PSI WEIGHT (Ib./gol.) TYPE ~ , AMOUNT RECOVERY (ft. or bbl.)' WEIGHT (lb./gal.) ! i i i FLUID PROPERTIES CHLORIDES CHLORIDES SOURCE RESISTIVITY (PPM) SOURCE RESISTIVITY (PPM) @ OF @ °F @ OF @ °F @ °F @ °F i i REMARKS: -SEE PRODUCTION TEST DATA SHEET- I II I III FORM NO, 326--LITTLr'$ 114676 FORMATION TEST DATA (SHEET 1) TICKET NO 564704.2 DATE. TOP OF TESTED INTERVAL (ft.) 9826 NET PAY (ft.) 5 HOLE OR CASING SIZE (in.) 7 SURFACE CHOKE (in.) .375 and ,75 11-10-81 ELEVA~ ION (FT) BOTTOM OF TESTED INTERVAL (ft.) TOTAL DEPTH (ft.) MUD WEIGHT (lb./gal.) BOTTOM CHOKE (in.) 10050 1005'0 9.6 VISCOSITY (sec.). 2.25 OIL GRAVITY @ OF GAS GRAVITY--ESTIMATED ACTUAl SAMPLER DATA PRESSURE (P.S.I.) C.C.'s OF Oit C.C.'s OF MUD CUBIC FT. OF GAS C.C.'s OF WATER TOTAL LIQUID C.C.'s GAS/OIL RATIO (cu. ft. per bbl.) FROM SAMPLER OTHER TEMPERATURE (°F) ESTIMATE 154.6 ACTUAl DEPTH (ft.). 9819 H.T.-500 [-]; THERMOMETER I-1; T.E. OR R.T.-7 ;El; OTHER [] SERIAL NO. HT-196 RECORDER AND PRESSURE DATA · . . CHARTS READ BY DATA APPROVED BY. ~^u~ ,u~,~ ~- ~ 11' ~- ~ ~ o TIM ES R (00:00-24:00 HRS.) GAUGE TYPE 3 3 1650 TOOL OPENED O R GAUGE DEPTH (ft.) 9819 9819 DATE 11-10-81 D RE CLOCK N,UMBER 22455 22929 BYPASS OPENED 2320 S CLOCK RANGE (HR.) 48 72 DATF 11-10-81 INITIAL HYDROSTATIC A. 4765.6 A. 4768.0 PERIOD MINUTES ,~,~,^, ~ow ~. ~.~ ~. ~0.~ XXX XXX P ]st. FINAL FLOW C. 3593.1-( C. 3484.7-.Q ]st. FLOW 390 R CLOSED-IN D, 3403,7 D, 3405.4 1st. C.I.P. E E. 1444.1 E. 1442.0 XXX XXX INITIAL FLOW S S 2nd. FINAL FLOW F. 1 729.8 F. 1739.3 2nd. FLOW U CLOSED-IN G. 673.9 G. 669.6 2nd. C.l.P. R H. gTE H. 1872.7 XXX XXX INITIAL FLOW E S 3rd. fINAL FLOW 1'. CTE ]'. 945.4 3rd. FLOW CLOSED-IN J, CTE J, 1796.9 3rd. C.I.P. K. CTE K. 4749.9 XXX XXX FINAL HYDROSTATIC CTE = Chart time expired ..... 0 : 0uestionable ,o,,,o.,,,-,,,,L,.s,,,,,,,,,/,, FORMATION TEST' DATA (SHEET 2) ,, 564704.2 Casing perfs Bottom choke Surf. temp . 'F Ticket No... Gas gravity. Oil gravity GaR Spec. gravity. Chlorides ppm Res @ 'F INDICATE TYPE AND SIZE OF GAS MEASURING DEVICE USED , Date Choke Surface Gas Liquid Time a.m. Size Pressure Rate Rate Remarks p.m. psi MCF BPD 1430 Pumped 100 BBLS of water down annulus. -- 2000 Displaced hole with 9.6# calcium. ,, chloride water. 11-10-81 0130 Rigged up and tested surface equipment. 0520 2750 Displaced Drill Pipe with Nitrogen. 0610 set packer. 1130 Perforated. 1650 .75 1175 Started to flow well. 1705 .3125 125 F1 owed thru seperator. 1810 Seperator line frozen. , 1920 .375 1135 Started flowing well. 1930 .375 .75 Flowing gas. 2200 .375 4 ,,, .75 · , 2320 Pumped down Drill Pipe and killed well. 2400 Unseated packer and reversed out. 11-11-81 0140 Broke out surface equipment. 0240 Pulled out of hole. 0530 ~. Broke down tools. PRODUCTION TEST DATA Tool Description DRILL PIPE AUXILIARY VALVE BUNDLE CARRIER X/O CIRCULATING VALVE PACKER X/O TAIL PIPE O,D. 4.63" 5.375" 3.5" 4.87" 5.75" 3.5" 3.5" TICKET NO. 564704.2 I.D. Length Depth 2.764" 2.44" 2.25" 2. 764" 2.44" 2.36" 2.764" 2.922" 9804' 7.28' 7.90' .79' 3.51' 4.36' .88' 63.32' 9811' 9819' 9821' 9826' EQUIPMENT DATA SHEET ~.?:.~`~`:~:.u:!.`.?x:~`.~:~::!:.~:.~:..?:`~.?``~.?:.~::?.::.::i.~.:!?~:d.x ~?!:d:'.l;~O~..~i...;~KeD'O~FT:~,i.~I'5,:i:ibi:DUT.IO~'.'.. :.~..,..';. :~'...;~:'. ~.... ..,: :: .f':"':.':; : '. :'.':.':-'~ '.; :~::.':~:':~':':~:~ ".::'. '[~ ':'~ - '" ' ':. :::. ':" · ::'.;'.":" :'" :'" . :.?' -," -' :"' '~'F ~:~ · ~~'~' '~'-''- '. ..... ~: .-"' '-? ''-' ' ".-': .""'::'~?':'-':'~:~?~-': .. ~'~'... :'h.. :..L.:: f.:'~'~;~;:-,,-/. :'.:... ~~, -:: ..,.,; ...... ::,' ..... '~. :.:E~ : .- .~.::... v, . · . :: :.. ~::....:~ ~ ~ ~ ~ ,...~ .... -.:...~ d./. .& d' l, : ,...':-. · , .., '.R~uested Distribution of Completed.D,S,T~ Report F~lder ..: . . ....~ ,-.forT~=~,~'No. ~ ~"?~- ~...~ · ': .... (Thi~ Orde~ Must ~e FiIIed Out and Si~ned By Com~ny~epree'entative)' ' . ~ ',~ Company Orig. C~art " .. ' ATT. "& Reports Company P,O: sox STREET 8~ NO. , BUILDING Reports ciTY' STATE ZIP CODE NUMBER · . Company O. ATT, P,O, BOX · STREET & NO, BUILDING Reports c~TY STATE . ZIP CODE NUMBER I'~_ mn v_o...~an. , , .... AT T.p.O. BOX STREET & NO, .BUILDING Reports CITY STATE ZIP CODE NUMBER Company, ATT. P.O. BOX STREET 8~. NO. BUILDING CITY STATE ZIP CODE NUMBER Reports ~- ' Owner.,-..Operato, r: or His Agent S IGN,~EO~-/' ///' / (i. "'~i,..',~,7~__.~ Agent Send 1st, 2nd and 3rd Copy with Charts (Use Additional Sheets When Necessary), DUNCAN, OKLAHOMA KENAI DEEP UNIT Lease Name -8.- //eX/-, 3 Well No.. ][est No. 9291' -9707' Tested Interval UNION OIL COMPANY OF CALIFORNIA Lease Owner/Company Name 576832 Ticket Number KENAI Camp 11-14-81 Date H-311-H196 Gauge Number(s) 0 KENAI DEEP UNIT Lease Name 675832 . Ticket Number ~r/~x~ 3 Well No. Test No. 9291' -9707' Tested Interval KENAI Camp 11-14-81 Date UNION OIL COMPANY OF CALIFORNIA Lease Owner/Company Name H-311-H196 Gauge Number (-s") 0 TICKET NO. 575832 DATF 11-14-81 HALLIBURTON CAMP KENAI i_ UNION OIL COMPANY OF CALIFORNIA LEASE OWNER LEASE NAME KENAI DEEP UNIT WELL NO~'- .TEST NO 3 BC LEGAL LOCATIONS-6-T-4-R- 11 FORMATION TESTED FIELD AREA KENAI GAS FIELD COUNTY. KENAI gTATF ALASKA TYPE OF D.S.T CASED HOLE TESTER(S) D. E. MC MAHAN WITNESS , DR ILLI NG CONTRACTOR BRI N KE RHOFF DEPTHS MEASURED FROM KE,LLY BUSHING CASING PERFS (FT.) DID NOT SHOOT TYPE AND SIZE OF GAS MEASURING DEVIC~ CUSHION DATA TYPE NITROGEN , .AMOUNT 1500 TYPE AMOUNT WEIGHT (IE~)PSI WEIGHT (lb./gui.). RECOVERY (ft. or bbl.): FLUID PROPERTIES CHLORIDES CHLORIDES SOURCE RESISTIVITY (PPM) SOURCE ' RESISTIVITY (PPM) @ °F @ OF , @ °F : @ °F @ °F @ °F REMARKS' FORMATION TEST DATA (SHEET 1) ~ TICKET NO. 575832 . DATF TOP OF TESTED INTERVAL (ft.) 9291' NET PAY (ft.) HOLE OR CASING SIZE (in.) 7" SURFACE CHOKE (in.) OIL GRAVITY__@ 11-14-81 ELEVATION (FT) ]00' BOTTOM OF TESTED INTERVAL (ft.) 9707' .TOTAL DEPTH (ft.) 9707' VISCOSITY (sec.), 2.250" PRESSURE (P.S.I.) C.C.'s OF OIL C.C.'s OF MUD , TOTAL LIQUID C.C.'s , GAS/OIL RATIO (cu. ft. per bbl.) FROM SAMPLER OTHER MUD WEIGHT (lb./gal.) 9.6 BO-i-l-OM CHOKE (in.) °F GAS GRAVITY--ESTIMATED SAMPLER DATA CUBIC FT. OF GAS C.C.'s OF WATER ACTUAl TEMPERATURE (OF) ESTIMATF ACTUAL 1 47.2 DEPTH (ft.) 9284' H.T.-500 I-1; THERMOMETER F-l; T.E. OR R.T.-7 :~: OTHER [] CHARTS READ BY SERIAL NO. RECORDER AND PRESSURE DATA D. E. MC MAHAN DATA APPROVED BY, HT-196 ~^.~. u~.~, ,- ~ ~. z TIM'-"',- :::, R (00:00-24:00 HRS.) ~ RPG-3 TOOL OPENED. GAUGE TYPE 0546 O R GAUGE DEPTH (ft.) q?R4 ' DATF 11- 14; D ' I~ 'CLOCK NUMBER 224.~R BYPASS OPENED 1200 S CLOCK RANGE (HR.) 48 DATE 11-].4- INITIAL HYDROSTATIC 4500.0 .... PERIOD MINUTES, ,~,~,^, ~ow. ~. ~ XXX XXX P ]_~t. FINAL FLOW 105,5 ],t. FLOW 374 R 1st. c.I.P. CLOSED-I N E XXX XXX S INITIAL FLOW S 2nd. FINAL FLOW 2nd. FLOW U 2nd. C.I.P. CLOSED-IN · R XXX XXX EINITIAL FLOW S 3rd. FINAL FLOW 3rd. FLOW CLOSED-IN 3rd. C.I.P. ~,.^~ .~o~^~,c ~s~.~ XXX XXX =ORNI NO. '~27--LITTL£'$ 114675 3M 7/81 FORMATION TEST DATA (SHEET 2) 575832 Casing perfs. Bottom choke Surf. temp 'F Ticket No Gas gravity Oil gravity .., GaR Spec. gravity, .Chloride~ ppm Res. @ °F INDICATE TYPE AND SIZE OF GAS MEASURING DEVICE USED , Date Choke Surface Gas Liquid Time a.m. Size Pressure Rate Rate Remarks p.m. psi MCF BPD , , 11-14-81 0045 Started clocks 0150 Went in hole 0546 Set packer, open F.O. hydrospring, unable to get through tools with guns. 1000 Pulled packer loose, rotated pipe. 1005 Reset packer, oepn hydrospring, guns still could not go through tools 1015 Pulled guns out of hole. 1100 Out of hole, guns came off wire line 1200 Pulled packer loose, reverse out. Hydrospring did not close. 1400 Started out of hole. 1700 Out of hole, guns not stuck in tools or drill pipe ,, ,,, "°""""'-"'-""'"'"""'""'"*. PRODUCTION TEST DATA '-,,'"',-,', Tool Description O.D. I.D. TICKET Length NO. 575832 Depth DRILL PIPE REVERSE VALVE DRILL PIPE FUL FLOW HYDROS SLIP JOINT BUNDLE CARRIER CROSSOVER BYPASS PACKER Crossover Tubing 5.0" 3.5" 5.03" 5.0" 5.375" 5.0" 4.87" 5.75" 3.5" 3.5" 2.764" 2.25" 2.764" 2.25" 2.25" 2.25" 2.25" 2.44" ,. 2.36" 2.36" .88" 9185' 1.0' 62.54' 13.480, 13.170' 7.9' 1.0' 4.3' 1.70' 2.660' .88' 6'1.48' 9185.46' 9248' 9284' 9289.3' 9291' EQUIPMENT DATA SHEET Each Horizontal Line Equal ,) 1000 p.s.i. t982 DUNCAN, 0K.'L A H 0 /~A A KENAI DEEP UNIT Lease Name 575833 Ticket Number 4 Well No. Test No. ANCHORAGE Camp 9296' -9707' Tesl~'ed Interval 11-15-81 Date UNION OIL COMPANY OF CALIFORNIA Lease Owner/Company Name H-311-H-310.-HT-196 Gauge Number(s) TICKET NO iii I LEASE OWNER LEASE NAME ,. 575833 DATE ' 21-15-81HALLI BURTON CAMP ANCHORAGE i UNION OIL COMPANY OF CALIFORNIA BC- DR KENAI DEEP UNIT , WELL NO '--8-' .TEST NO. 4 LEGAL LOCATION S-6-T-4-R-11 FORMATION TESTED TYONEK FIELD AREA KENAI GAS FIELD COUNTY KENAI BOROUGH STATE ALASKA TYPE C~ D.S.T CASED HOLE TESTER(S), D.E. MC MAHAN AND DI'CK PI'KE WITNESS DRILLING CONTRACTOR.,. BRINKERHOFF DEPTHS MEASURED FROM, KELLY. BUSHING CASING PERFS (FT..), 9445:9,91Z' TYPE AND SIZE OF GAS MEASURING DEVICE I ii i I i i i i i CUSHION DATA Nitrogen AMOUNT 3500 PSIwEiGHT (Ib./§ol.) TYPE RECOVERY (ft. or bbl.): AMOUNT ., WEIGHT (Ib./gol.). FL J ID PROPERTIES CHLORIDES CHLORIDES SOURCE RESISTIVITY (PPM) SOURCE, RESISTIVITY (PPM) ........ @ °F @ OF ,, @ OF ,,, @ OF m mm @ °F @ °F ,,, I I i i i i i II ii iii i i I iii REMARKS: SEE PRODUCTION TEST DATA SHEETS. FORMATION TEST DATA (SHEET 1) · TICKET'NO, 575833 DATF 11.-~--81 I ELEVA'I ~ON (FT) 100' TOP OF TESTED INTERVAL (ft.) NET PAY (ft.) 34' 9296' BOTTOM OF TESTED INTERVAL (ft.). 9707' TOTAL DEPTH (ft.) 9707' HOLE OR CASING SIZE (in.) 7" SURFACE CHOKE (in.) 3/4-1/2" MUD WEIGHT (lb./gal.),, 9.6 VISCOSITY (sec.) BOTTOM CHOKE (in.), 2 1/4" OIL GRAVITY @ OF GAS GRAVITYmESTIMATED ACTUAL PRESSURE (P.S.I.) C.C.'s OF OIL C.C.'s ~1: MUD SAMPLER DATA CUBIC FT. OF GAS C.C.'s OF WATER TOTAL LIQUID C.C.'s. ii GAS/OIL RATIO (cu. ft. per bbl.) FROM SAMPLER.,, OTHER I i I TEMPERATURE (OF) ESTIMATE ACTUAL DEPTH (ft.), H.T.-500 I-1; 148.8 9288' THERMOMETER F'I; T.E. OR R.T.-7 l-1; OTHER I'-I SERIAL NO, HT-196 RECORDER AND PRESSURE DATA CHARTS READ BY R.B. PIKE DATA APPROVED BY, GAUGE NUM. ER H-.311 H-310 ' TIMES (00:00-24:00 HRS.) GAl}GE TYPE 3 3 O705 TOOL OPENED,, , GAUGE DEPTH (ft.) 9288 9288 DAT~ 11-15-I CLOCK N,UMBER 22466 2119'3 BYPASS OPENED_1630 CLOCK RANGE (HR.) 48 ,24 DATI: 11-18-I 4526,3 4530.4 INITIA,L HYDROSTATIC .......... PERIOD MINUTES _ ,.m^..ow XXX XXX ~ , , 1st? FINAL FLOW 1st. FLOW. , , SEE ATTACHED SPECIAL 1st. C.I.P. , , CLOSED-IN , , ", , READTNG SHEETS. XXX XXX INITIAL FLOW .... 2nd. FINAL FLOW 2nd. FLOW CLOSED-IN 2nd. C.I.P. INITIAL FLOW XXX XXX 3rd. FINAL FLOW 3rd. FLOW CLOSED-IN 3rd. C.I.P. FINAL HYDROSTATIC 4580.6 CHART TTME EXPIRED... XXX XXX ,, FORMATION TEST DATA (SHEET 2) s 575833 Casing perfs. ,. Bottom choke Surf. temp , 'F Ticket No Gas gravity Oil gm. vity ... , , GaR ,., Spec. gravity. Chloride~ ppm Res @ °F INDICATE TYPE AND SIZE OF GAS MEASURING DEVICE USED .... Date Choke Surface Gas Liquid Time a.m. Size Pressure Rate Rate Remarks D.m. psi MCF SPD PAGE 1 ~ , , , , , 11-14-81 2145 Made up tools ,, , 2230 Went in hole 11-15-81 0300 ... Rig up surface equipment 0358 ..... Set,., packer 0600 . . . Waitin...9.~on Nitrogen. PSis/Nitrogen ..... OYO0 2700 0705 ..... 2700 Opened Auxiliary valve, no increase . . .0210 1520. . .... .B. led Nitrogen oy o.. .1520,. ,, OY.40 100.0 .B1 ed Nitrogen .... ; 0830 Bled Nitrogen, no gas flow, rig. up Sch ??? and run in with bar to I ...... , , ........ .. check Auxiliary valve. Valve open... 16.30:. .............. Rig up...to reperforate ..... 1830. 1500 .. Charge.. dri 11 pipe wi th,.Nitrogen .1855 1100 Perforated 9425.9435' ........... 20.15 Bled off Nitrogen .11-16-81 ........ 02.18 ..150..0 Perforated 9411-9441' 0315 3/8" 950 .. Opened to flow .. 03:24 Gas to surface .............. 3/8 0345 .1/2 400. r'.') .... Flowing gas 0.415 ,, 28y ,, ........ , ,,, 0445 ,, 380 ,, ........ _..0545 " . 356 Flowi.n.9 gas through scrubber device 0630 ,, 360 27 ,, ,, PRODUCTION TEST DATA Casing perfs. ,Bottom choke Surf. temp .... °F Ticket No, 575833 -C~s gravity -Oil gravity,, GOR Spec. gravity ,Chloride~ ppm Res, (~ *F I~mCAT£ TYPE AND S~Z£ OF CAS ,! , Date Choke Surface Gas Liquid Time a.m. Size Pressure Rate Rate Remarks ~).m.., psi MCF BPD 3/8 0930 1/2" 400. 3.7 Flowilng gas .through scrubber device ,.. ". "i 412 ..'i Shut iln at surface Run in hole with. wireline, pressure recorder 1300 " 1076 Opened to flow ,., 1515 395 '3.7 Shut well in on surface ,, 1830 " 600 Opened to flow 2145 " 620 Clocks ran out, flowing gas 11-17-81' ' ......... 0343. Pump Acid ....... 04_45 Displace with nitrogen ,, 0523 " 3000 Opened to flow ..... 0555 1/2 200 Gas to surface ................ 1115 97 Shut in at .surface ....... 1215 .1046.0 Opened to flow ,, , 1400 1420 Shut in at surface ..... 1455 1051 Flowed well 1930 406 5.48 ,, 11_18,81 0800 800 4.26 F1 owed wel 1 .... 1200 800 !4.68 ,, ........ 1600 800, ,4.68 " 1605 Shut in, killed well ...... 1630 Pulled packer loose, revers'e out, mix .... lost circulation pill. ............... 210.0. Pulled out of hole. , ..... .,, _ I PRODUCTION TEST DATA UNION OIL COMPANY OF CALIFORNIA Lease Owner/Company Name 575833 Ticket Number H-311 H-310 B.T. B.T. B.T. 9288' 9288' Depth Depth Depth INITIAL FLOW Time t + 6) PSIG Time t + (~ PSIG Time t + 6) PSIG (minutes) Log Temp. Log Temp. Log Temp. (--) Corr. (minutes) {-) Corr. (minutes) O Corr. 0 3555.6 0 3545.2 10.7 OAS 3555.0 10.2 OAS 3559.7 1 9.0 CAS 2068.4 1 7.9 CAS 2066.0 33.5 OAS 2068.4 33.1 OAS 2066.0 39.5 CAS 1 399.1 38.7 CAS' 1402.1 52.5 OAS 1398.4 52.4 OAS 1402.1 60 504.7 60 '469.8 80.2 MFP 37.6 80.1 MFP 32.1 120 37.6 120 32.1 180 41.6 180 32.1 240 46.6 240 42.6 300 56.8 300 50.0 360 65.8 360 58.3 420 74.8 420 66.0 480 93.5 480 85.8 540 100.9 540 93.8 ,,, 600 111 · 5 600 104.3 660 127.6 660 122.8 , , 685.0 BPN 123,6 685.0 BPN 117,6 , , APN 2520.8 APN 2514.2 SECOND FLOW 0 251 5 ~ 5 CLOCK STOPPED ..... 60 2458.4 . 66..8 OAs 2454.5 75 0 CAS 1386.6' , 92.0 OAS 1 386.6II 97.1 MFP 717.3 II 120 71 7.3 1'80 739.4 203.6 757.0 i. CHART lIME EXPIRED... : .... SECOND CLOSED IN PRESSU~' 0 2520.8 65.7 2462.2 CLOCK STARTED ~UNNING. -- ONLY 65~..7_MI[I~lE$ ~.~.01; ~:~P_ . _.._ __ i m .... , PAGE 1 Re~ks: OAS : Opened at surface CAS : at su : Before pumping nitrogen APN : After pumping n~trogen MFP = Minimum flow pressure 80-2860 ,~. UNION OIL COMPANY OF CALIFORNIA 575833 Lease Owner/Company Name Ticket Number H-311 H-310 B.T. B.T. B.T. 9288' 9288' Depth Depth Depth THIRD FLOW PSIG ~ ~ I PSIG Time PSIG Time Log t + (-~ Temp. I I Time Log ! '" ~ Temp. Log t + (-) Temp. (minutes) O Corr. ~ ~ (minutes) ~I Corr. (minutes) e) Corr. 0 OAS 734.5 II 60 268.0 II 120 860.2 I]CHART T~ME EXPIRED .... 180 665.8 240 647.2 °300 656.5 360 ' 664.9 420 674.5 480 703.4 '540 703.4 557.9 702~.,3 T~IRD C'OSED IN PRESSURIEI '' 704.3 ~ 1204.0 /I 4 1309.9/I 28 1325.8 /I 35 ' 1328.9 H 42 1328.9 || ' ' 49 1 328.9 56 1 328.9 63 1 328.9 70 1 328.9 77 1 328.9 84 1 328.9 ' ' 91 1,333.2 98 1 333.2 105.4 1333.9 ,, FOURTH FLOW 0 1 2O8.7 5 814.9 10 693.2 1 5 'MFP 660.6 20 660.6 25 660.6 30 660.6 35 667.7 40 669.9 45 672.0 49.1 CS 672.0 PAGE 2 Remarks: OAS = Opened at surface nlmum ow pressure CS = Clock stopped... $0.2860 , UNION OIL COMPANY OF CALIFORNIA Lease Owner/Company Name ., 575833 Ticket Number H-311 H-310 B.T. B.T. B.T. 9288' 9288' Depth Depth Depth FOURTH CLOSED IN PRESSURE PSIG Time t -~ (~) PSIG Time t * ~-) PSIG Time Log t + (-) Temp. Log Temp. Log Temp. (minutes) 0 Corr. (minutes) ~ ) Corr. (minutes) o Corr. i i 0 672.0 54.0 1332.3 CHART 'rIME EXPIIRED... FIFTH FLOW 0 1267.1 5 1100.6 10 743.5 15 653.4 .... 25 631.7 II 30 631.7 ~1 ,, 35 637'311 37.3 CS, 637.3 ,,, , , .... II " II II II II ,, , , I Ill I PAGE 3 Remarks: MFP : Minimum ow pressure CS = Clo'ck stopped .... 80.2860 Tool Description DRILL PIPE AUXILIARY VALVE BUNDLE CARRIER CROSSOVER CIRCULATING VALVE PACKER CROSSOVER TAIL PIPE TICKET O.D. 3.5" 4,630" 5. 375" 3,50" .4,87.0" .. 5,7 50." · 3,5" I .D, 2,764" 2,440" 2,250" 2,25" 2,440" 2.360" 2,25" 2,922" Length 9274' 7.31' 7.90' .72' 3,65' 4..35' ,88" 61,48' NO, 575833 Depth 9288' 9290' .9.296' EQUIPMENT DATA SHEET Each Horizontal Suggested form to be inserted in each "Active" well folder to check for timely compliance with 6ur regulations. - 0p~ra~0r', Well'N~une 'and 'Number -- Reports and Materials to be received by: I -- ~'-~.~ .Date Required Date Received Remarks Comp l etion Report Yes / ~re ~ips ~ ~C, ~'~ , . Core ~scription Inclination Su~oy ~s R~. Yes Digitiz~ ~ta y Document Transmittal Union Oil Company of Califor( DATE SUBMITTED ACCOUNTING MONTH HAND DELIVERY 3-23-82 TO FROM AT .......... "~"' ' ~'"'' '"'' AT ''' "° .... State 011 and Gas CC P0 Box 6247 Anchorage, Alaska ~"~"~age, Alaska 99502 TRANSMITTING THE FOLLOWING: i ea. uirec~ionai survey, radiu~ of cumature D-9~; 1 ea. Directional survey, radiu~ of cumature tangential average a ~gle, ta) gentl(1 1 ea. Blueline and sep~ of the foll~i~g: _ 2" and 5" D I-SFL 2" and 5" Borehole c)mpensat(d son~ c log compensated neutron Formatim density ~compensated formatto~ densitj , gama-ga~ PLE S A R R ' '~CE~FE~F --' ~~ECE VED DATE: MAR©~ ~,, ]982 Ai~s~'z Oil & Gas C )ns. Corn nission i FORM 1-2M02 (REV. 11-72) PRINTED IN U.S.A. \ Document Transmittal.. Union Oil Company of .,, union DATE SUBMITTED ACCOUNTING MONTH 2-~-82 TO FROM AT AT Stat~ Oil ~h Gas Cons. Coram. UOC-PO Box 6247 3001 Porcupine Drive *~"°"~Aflchorage, AK 995~0 TRANSMITTING THE FOLLOWING: 1 ea. DST C}'~orLs i'.lus. 1,2,3 4 ~PLEASE SIGN AND RETURH ONE COPY ,, RECEIVED: ~ D~FIVF~ ~LD lU ~chorage , : . FORM 1-2M02 (REV. 11-72) PRINTED IN U.S.A. ~,~ STATE OF ALASKA ALASKA d,, AND GAS CONSERVATION COl( IISSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS · Drilling well [] Workover operation [] 2. Name of operator 7. Permit No. UNION 0TL COMPANY OF CALTFORNTA 81-5;2 3. Address 8. APl Number PO BOX 6247 ANCHORAGE AK 99502 50- 133-20342 4. Location of Well 9. Unit or Lease Name at surface KENAI DEEP UNIT 442'N & 1147'E of SW corner, Sec. 6, T4N, RllW, SN. 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. KB +90' MSL A-028142 10. Well No. KU ~14X-6 (KDU ~8) 11. Field and Pool KENAI GAS FIELD For the Month of. DECEMBER , 19. 81 12. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks Rigged down 12/6/81 & released rig [ 19:00 hrs 12/9/81, 13. Casing or liner run and quantities of cement, results of pressur9 tests None 14. Coring resume and brief description None 15. Logs run and depth where run None 1 6. DST data, perforating data, shows of H2S, miscellaneous data Perfed: 3558-3575' 3772-3792 3624-3649' 3553-3575 3652-3677' 3724-3739' 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. (?~.~,,~'~ DIST DRLG SUPT 1/15/82 SIGNED---,,--, .,. TITLE. DATE ~ - ~ o/r NOTE--Report on this form is required f each calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10-404 Submit in duplicate Rev. 7-1-80 O! STATE OF ALASKA ALASKA AND GAS CONSERVATION COI~:,,,~ISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL [] OTHER [] 2. Name of Operator 7. Permit No. UNION 0IL COMPANY OF CALIFORNIA 81-92 3. Address 8. APl Number PO BOX 6247 ANCHORAGE AK 99502 50- 133-20342 9. Unit or Lease Name KENAI DEEP UNIT 4. Location of Well 442'N & 1147'E of SW corner, Sec. 6, T4N, RllW, Section 29, TgN, R13W, SM. 5. Elevation in feet (indicate KB, DF, etc.) KB +90' MSL 6. Lease Designation and Serial No. A-028142 10. Well Number KU #14x-6 (~) 11. Field and Pool KENAI GAS FIELD Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] , Perforations [] Altering Casing [] Stimulate [] Abandon [] Stimulation [] Abandonment [] Repair Well [] Change Plans [] Repairs Made [] Other [] Pull Tubing [] Other ,[~' Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). , KDU #8 should be renamed KU #14x-6. The weil'was completed in the Kenai Unit instead of the Kenai Deep Unit. 14. I her rtify thatr~n~going is true and correct to the best of my knowledge. Signed ~.~.,~ Title DIST DRLG SUPT The/Je;o"w for ~m__m issio_ n use Con(~Li,l~ons of Approval, if any: Date 12/18/81 Approved by COMMISSIONER By Order of the Commission Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate '~' STATE OF ALASKA ~I ~ ALASKA ~,,- AND GAS CONSERVATION COt~,..¢IlSSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS Drilling well [] Workover operation [] !. Name of operator UNION 0IL CONPANY OF CALIFORNIA 3. Address PO BOX 6247 ANCHORAGE AK 99502 4. Location of Well at surface 1442'N & 1147'E of SW corner, Sec. 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. KB +90' MSL A-028142 7. Permit No. 81-92 8. APl Number 5o- 133-20342 9. Unit or Lease Name KENAI DEEP UNIT 10. Well No. ~ ~¢. ,,:" ~'/" ,--141;~8 (KU #14-CA 11. Field and Pool KENAI GAS FIELD For the Month of. NOVEMBER , 19 81 · 12. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks 10225' TMD 11/30/81. 13. Casing .or liner run and quantities of cement, results of pressure tests Tested liner lap to 3000 psi - ok. Tested csg to 5000 psi - ok. 14. Coring resume and brief description None 15. Logs run and depth where run CBL-VDL-GR logs f/ 10030' to 2566' 1 6. DST data, perforating data, shows of H2S, miscellaneous data Perfed & sqz'd: 9458-9460' 9398-9400' 9953-9958' 9833-9843' 9751-9781' 9411-9441' 3800-3802' 3746-3748' 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. NOTE--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10-404 Submit ir~ duplicate Document Transmitta Union Oil Company of Cal~ unlen HAND DELIVERY o^TE SUBMITTED AcCoUNTING MONTH 11-23-81 TO FROM Mr. William Van Allen R.C. Warthen Pouch 6247 ^T State 0il and Gas Con. ^T Anchorage, AK 99502 3001 Porcupine Drive Anchorage, Alaska T~-E,.o,E ~ o .I TRANSMITTING THE FOLLOWING: KDU-8: 1 magnetic tape # 10707 162266 and listing II PLEASE I~I'~N.~ ^N~ ....,~.,. 10~.~ ~)~ ~:~ .... DATE' ' ...... '~ ......... Ap. chorage ....... ....... ,,. ,,, iii i ii i ~1 ii FORM 1-2M02 (REV, 11-72) PRINTED IN U.S.A. STATE OF ALASKA ¢,"T,~ ., ALASKA(' _AND GAS CONSERVATION C(~' MISSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS · Drilling well I-~ Workover operation [] J 2. Name of operator UNION 0IL COMPANY OF CALIFORNIA 7. Permit No. 81-92 3. Address 8. APl Number PO BOX 6247 ANCHORAGE AK 99502 so- 133-20342 4. Location of Well at surface +850'E & +370'N of SW corner, Sec. 6, T4N, RllW, SM. -- __ 6. Lease Designation and Serial No. A-n28142 5. Elevation in feet (indicate KB, DF, etc.) KB +90' MSI 9. Unit or Lease Name KENA! DEEP UNIT 10. Well No. KDU #8 11. Field and Pool For the Month of OCTOBER , 19, , 8l KFNAT GAS FTFID 12. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks Directionally drilled 12 1/4" hole and 8 1/2" hole to 10225'. 13. C.asing or liner run and quantities of cement, results of pressure tests Ran 9 5/8" csg to 7282' w/ ]450 sxs cmt & tested to 5000 psi - ok. Tested 13 5/8" & 10" DCB' spools to 2400 psi - ok. Tested BOPE 1:o 5000 psi - ok. Tested h~vdril to 2500 psi - ok. Ran 7" liner to 10225' w/ 1600 sxs cmt. 14. Coring resume and brief description None 15. Logs run and depth where run DIL-Sonic-GR & FDC-CNL-GR 7301-2566'. DIL-Sonic, FDC-CNL-GR, & HRD-Dipmeter 10225' to 7282'. 1 6. DST data, perforating data, shows of H2S, miscellaneous data None NOV2 u 1581 Ojj & GaS OOrl$. Coitjti~j,~,~O, 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. SlGNE ,TITLE DATE 11/15/81 NOTE--~ep~)rt on this formi, req~i~ed f~;each calend~r month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10-404 Submit in duplicate Rev. 7-1-80 Document Transmittal ,, Union Oil Company of California unlen [:)ATE 'S'UBMI.TTED AC (~OLINTING MONTH' HAND DELIVERY ll-17-81 ,,,, TO .......... ~'ROM Mr. Bill Van Allen R.C. Warthen ~T~laska 0ii and Gas gens ~T ~ouch 62~?" ' 3001 Porcupine Drive Anchorage, Alaska 99502 .......... D~ ......... ~v , TELEPHONE NO, TRANSMITTING THE FOLLOWING: ..... KDU f7 and 'KDU,f8 ....... 1 .ea Blueline and ..... 1 , ea Sepia nf th~ fnllnwing' .. - .-2" & 5" D!L-SFL ... .. . 2" & H" Comp_ Formatior. Density Log .. .2,, & 5".Boreho!e Comp. Sonic Lo~ ..- ............ v ...... ~, U ~, ~t ~, ~ ..... ,., ..........~ ,11 ,, r,,h~rleek (K~II=R- s~t If two/ , l. ,, Cyberd i p ........ T~I~ , . ~ ........ b, <')"I ] ? i:, ..... j ~ i , .......... iiii i i i i iiii i i le iiiii i FORM 1-2M02 (REV. 11-72) PRINTED IN U.S.A. L Robert T. Anderson District Land Manager Union Oil and Gas' ..... ,ison:Western Region ,~. Union Oil CompanyJ.. California P.O. Box 6247, Anchorage, Alaska 99502 Telephone: (907) 276-7600 union October 16, 1981 · Dear Mr. Hamilgon~ Mr. 'Hoyle Hamilton Alaska Oil & Gas Conservation 'Commission 3001 Porcupine Drive Anchorage, Alaska 99504 STATE OF ALASKA 1981 Permits to Drill Correction of BOnding Information , It has been brought to my attention that we have been carrying incorrect bonding information on all Union operated Permits to Drill submitted to the Alaska Oil & Gas Conservation Commission since January 1, 1981. 'For each of the below listed wells, Item No. 12 on the Permit to Drill (Form 10-401) should be changed frOm United Pacific Insurance Company (B-55372) in the amount of ~100,000.00 to National Fire Insurance Company of Hartford (B-5534278) in the amount of ~200,000.00. WELLS PERMITED TBS A-9 Rd. CLU #3 TBS A-17 Rd. KDU #7 K~u #8 WD ¢1 KBU #31-7 KU #34-32 Tungak Creek #1 DATED PERMITED 3/17/81 4/20/81 5/12/81 6/26/81 6/26/81 7/14/81 lO/8/81 lO18/81 10/14/81 API NUMBER 50-733'20062-01 50-133-20340 50-733-20135-01 50-133-20341' 50-133-20342 Pending Pending Pending Pending DATED APPROVED 3/24/81 4/28/81 5/15/81 7/27/81 9/17181 Pending Pending Pending RE[~V~OPending' 0il & C~::~s Cons. 6oinmjssi0n Anchorage 1981 Permits to Drill Correction of Bonding Information -2- October 16, 1981 We would appreciate your reflecting these corrections on your copies of the subject Permits and we will do the same on ours. We apologize for the oversite and any inconvenience this has caused. All future Permits submitted for your approval will have the current bonding information on them. sk cc: Ann Lannin-LA Office Jim Callender Very Truly yours, Robert T. Anderson 0 195! Alaska Oil & Gas Cor~s. Commission , Anchora,qe STATE OF ALASKA ALASKA(" _AND GAS CONSERVATION C~ MISSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS · Drilling well E~ Workover operation [] 2. Name of operator 7. Permit No. UNION OIL COMPANY OF CALIFORNIA 81-92 3. Address P. O. BOX 6247, ANCHORAGE, AK 4. Location of Well at surface +850' 99502 E & +370' N of S.W. Cor Sec 6, T4N, RllW, S.M. 5. Elevation in feet (indicate KB, DF, etc.) KB +90' MSL 6. Lease Designation and Serial No. A-028142 8. APl Number 5o- 133-20342 9. Unit or Lease Name Kenai Deep Unit 10. Well No. KDU #8 11. Field and Pool Kenai Gas Field For the Month of September ,19 81 Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks Began ,operations 6'00 hrs 9/17/81 Spud @ 16'30 hrs 9/22/81 9/30/81 5209' 13. Casing or liner run and quantities of cement, results of pressure tests Set 20" casing to 85' Set 13 5/8" casing to 2566' - 1675 sxs C1 iiGii 14. Coring resume and brief description None 15. Logs run and depth where run None 1 6. DST data, perforating data, shows of H2S, miscellaneous data None 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. eac~ U NOTE--Repor~)n this form is required for calendar month, regardless of the status of operations, and must be filed in duplicate with the AlaSka. Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10-404 Submit in duplicate Rev. 7-1-80 LONG STRING: 1. 3 1/2" XA sleeve - 3456' 2. 9 5/8" "A-5" pkr- 3492' 3. 3 1/2" blast jts f/ 3546-3582" 3613-3692 ' 3706-3745' 4. 3 1/2" Otis "XA" sleeve - 3745' 5. Locator Sub - 3754' 6. 9 5/8" Baker model "D" pkr- 3756' 7. 3 1/2" Seal Assy- f/ 3755-3766' 8. 3 1/2" Guide Shoe - 3766' 9. 7" cmt ret- 9296'" 10. 7" cmt ret- 9707' 11. 7" cmt ret- 9925' 13 3/8" C. 2566' SHORT STRING PERFS: 3553-3578' (A-8 Sand) 3624-3649' (A-10 Sand) 3652-3677' (A-10 Sand) 3724-3739' (A-11 Sand) LONG STRING PERFS: 3772-3792' (B-1 Sand) SHORT STRING A. 3 1/2" Otis "XA" sleeve- 3462' B. 3 1/2" Otis "XN" nipple - 3512' TOL @ 6915' 10 x 9 5/8" C. 7282' 7" C. 10225' KU #14X-6 (KDU #8) CX~D. APP'D. o^~ 8/3/82 :9/22/81 Completed: 12/9/81 UNION OIL COMPANY OF CALIFORNIA SHEETS I SHEEI' F'ORM 247 (NEW 5/66l September 17, 1981 Mr. Robert T. Anderson District Land 5~anager Union Oil Company of California P. O. Box 6247 Anchorage, Alaska 99502 Kenai Deep Unit KDU ~o. 8 Union Oil. Company of California Permit }~o.. 81.-92 Sur. Loc.~ 850'E, 370"N of SW cr Sec 6, T4N, Rllg?, SM. Bottomhole Loc.: 180'N, 300'W of SE cr Sec 1, T4N, R12W, SM. Dear Mr. Anderson: Enclosed is the approved application for permit to drill the above referenced well. Well samples and a mud log are not required. A directional survey is required. If available, a tape containing the digitized log information shall be submitte(t on all logs for copying3 except experimental logs, velocity surveys and dipmeter survey s. ~mny rivers in Alaska and. their drainage systems have been classified as important for the spawning or migration of anadromous fish. Operations in these areas are subject to AS 16.50.870 an~1 the regulations promulgated thereunder (Title 5, Alaska Administrative Code). Prior to. commencing operations you may be contacted by the Habitat Coordinator's office, Department of Fish and C~me. Pollution of any waters of the State' is prohibited by AS 46, Chapter 3, Article 7 and the regulations promulgated thereunder (Title 18, Alaska Administrative Code., Chapter 70).and~. 'by the Federal Water Pollution Control Act, as amended. Prior to Mr. Robert T. Anderson Kenai Deep Unit KDU No. 8 -2- September 17, 1981 commencing, operations you may be contacted by a representative of the Department of Environmental Conservation. To aid us in scheduling field work, we would appreciate your notifying this office at lease 48 hours before the well is spudded~ We would like to be notified so that a representative of the Commission may be present to inspect the diverter system ~fore the conductor shoe is drilled and also to witness testing of blowout preventer equipment before surface casing shoe is drilled. In the event of ,suspension or abandonment,, please give this office adequate advance 'notification so that we may have a wi tness present. Very truly yours, Hoyl~ H. l{ami lton Chairman of BY ORDER OF THE COMii/IISSION Alaska Oil & Gas Conservation Commission Enclosure ccz Department of Fish & Game, Habitat Section w/o encI. Department of Environmental Conservation w/o/encl. Union Oil and Gas D~;'qon: Western Reg Union Oil Company of ,Jalifornia P.O. Box 6247, Anchorage, Alaska 99502 Telephone: (907) 276-7600 union .September 8, 1981 Mr. Jim Trimble O&G Cons. Commiss.ion 3001 Porcupine Drive Anchorage AK 99501 Dear Mr. Trimble: On KDU #8, for our diverter valve, we are planning on using a 6" Fabri- valve. This valve is a full port gate valve with series 150 ANSI flanges with a Fabrivalve 3000 psi hydraulic operator. The valve will be con- nected to a 6" line off of the 20" drive pipe. The operator will be tied into the diverter line and will be open when the diverter is closed. Two 6" butterfly valves will be placed downstream of the diverter tee to direct flow. These valves will be linked together such that only one valve may be open at a time. ¢ ~-,.,,...,...~ ,~,~......~:: ......... ~,, ,.~ ........ ~,....L..¢ ..... ~.c, ,.:'~,,.~, .... ,,,=::~': ~...~t .:,(:,~,,, ...... ~,,.~..~ ...... Please contact me for any further question~. Sincerely, Lawrence O. Cutting LOC/drm Union Oil Company of California P.O. Box 6247, An,(' rage, Alaska 99502 Telephone: (907) 2, ._-7600 Robert T. Anderson District Land Manager June 26, 1981 Anchorage Branch Matanuska Valley Bank Anchorage, Alaska Pay to the order of Mr. Hoyle Hamilton Division of Oil & Gas 3001 Porcupine Drive Anchorage, Alaska 99504 KENAI SOLDOTNA AREA State of Alaska Kenai Gas Field Kenai Deep Unit #7 A-028056 (8-86-71-5390-600979) Kenai Deep Unit #8 A-028142 (8-86-71-5390-600972) Dear Mr. Hamilton: Enclosed for your approval are three (3) copies of the Permits to Drill for the above captioned wells. Also enclosed is our check number 19141 in the amount of $200.00 to cover the required filing fee of $100.00 ~per permit. Upon approval, we would appreciate a copy so that we may complete our files. JUN 2 6 A~aska 0il & Gas Corm. Very trUly yours, Robert T. Anderson Union Oil Compa. ny of California Anchorage, Alaska' i ,, Date June 26, 1981 $200.00 'i252 STATE OF ALASKA DEPARTMENT OF REVENUE Url~on Oil Company of Cal!forr~la Land Account ALASK ,L AND GAS CONSERVATION C~. ,.~MISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work. DRILL [~ lb. Type of well EXPLORATORY~] SERVICE [] STRATIGRAPHIC [] REDRILL [] DEVELOPMENT OIL [] SINGLE ZONE [] DEEPEN [] DEVELOPMENT GAS [] MULTIPLE ZONE ~] 2. Name of operator Union Oil Company of California 3. Address PO Box 6247, Anchorage Alaska 99502 4. Location of well at surface+ 850'E'"'AfE[-+ 370'N of S.W. cur. , 9. Unit or lease name sec. 6, T4N, RllW, S.M. Kenai Deep Unit At top of proposed producing interval-{- 200'W and 20'0'N of the S.E. cur., 10. Well number section 1, T4N, R12W, S.M. KDU #8 At total depth+_lS0 'N & +__ 300~W of S.E. curl, sec. 1, T4N, R12W, S.~.'..ll. Field and poo~ Ke~ai Gas Field -- 5. Elevation in feet (indicate KB, DF etc.) 6. Lease designation and serial no. KDB + 90' Above MSL A-028] ~2 12. Bond information (see-20 AAC 25.025) United Pacific Ins. Type S'tatewide Surety and/or number Com..DanY 3-55372 Amount ~](')0. 000. or) 13. Distance and direction from nearest town 14. Distance to nearest property or lease line 15. Distance to nearest d~illing °r completed 6.5 T~'~I,~.~, .~S/~__O~iles 25(')' to nearest lease linefeet KDU-AWell 2200' feet 16. Proposed depth (MD & TV D) 17. Number of acres in lease 18. Approximate spud date 10,520 ' TMD-10,395' TVD feet 2,560.00 9/1/81 19. If deviated (see 20 AAC 25.050) 120. Anticipated pressures ** 3900 psig@__ Surface KICK OFF POINT 1000' feet. MAXIMUM HOLE ANGLE l0 oI (see 20 AAC 25.035 (c) (2) * 4900 psig@ 9~00 ft. TD (TVD) 21*Based On KBU 41-7 **Maximum Possible Surface pressure using weight of gas column Proposed Casing, Liner and Cementing Program SIZE CASING AND LINER SETTING DEPTH QUANTITY OF CEMENT Hole Casing Weight Grade Coupling Length MD TOP TVD MD BOTTOM TVD (include stage data) - 20" ' _~.~,,~ 94# Plain End +100 Surfac~ +100 ~ Driven 1~-±-z 13 3/8 61# K-55 +--2500' Surfac~ ~2500'~2450' 1400SX '~'~ ~'~ ~/;. ~2 ,, Butt _ _ ~ a 1/4 9 5/8 47# N-80 Butt +_8000' Surface +--8000'1 7900' 1800SX 8 1/2' 7" 29#. N-80 Butt +--2420 +_7600' +_7500 +--10,020' 9900' 700SX i I 22. Describe proposed program: .. 1. Move in and rig up. 2.' Drive 20" conductor to + 100'. 3. Drill 17 1/2" directional hole to + 2500'. R E'C E 4. Run & cement' 13 3/8" casing @ + 25~0'. 5. Drill 12 1/4" directional hole--to + 8000'. 6. Run logs. -- ,3 U N 6 .] 7. Run & c~t 9 5/8" casln9 @ + 8000'. 8. Drill 8 1/2 directional hole to + 10,020' MD, TD. ~..A~.k~0il & Gas C01]s. 9. Run logs & evaluate. -- 10. R]ml. and cement.'. 7." liner at 10,020' as justified. 23.1 h~lb'y certif~<~~~~~ to the best of my knowledge The space below for Commissior~ use Robert T. An)~rso~ v~ Mgr CONDITIONS~ '"~'O~: APPROVAL Samples required Mud log required Directional Survey required I APl number []YES ~NO []YES [~]NO /~YES F-INOI 50-- /~/~.- Permit number Approval date ~/- ?'2__ SEE COVER LETTER FOR OTHER REQUIREMENTS (]q/17/R1 -- ~,~, .- ~,~;~ by order of the Commission ~"~ ""' ' Form 10-401 Submit in triplicate Rev. 7-1-80 CA3ING STRING CASING SIZE HOLE SIZE CASING AND ~13BING DESIGN · COUNTY STATE ~,~^_%~ DATE ~- z%-~ DESIGN BY ~ ~ . k~/D ~. I ~q~g. ~DGR. i 5~qps~/ft~%~. IISsc~ ~ ~D. GR. II .g%oppi/ft. M.S.P. .1:si. INTERVAL LENGTH.. - ' ~9ottom Top Wt. DESC.~iPTION '~IGHT TENSION ~-~ kq .Mb~4 TDF COLLAPSE COLLAPSE CDF BUP~T Ii',TERi'U~L W/ BF -top of STRENGg~[ PRESS. ~ PF. SIST. 'PRESSURE Grade Thread W/O BP><- section TEI~SION bott°m tension YIELD lbs lbs 1000 lbs psi psi ~si psi BDF pP_VCE PER PT. , COSi · , >.2 ! -.. Formulae: Collapse resistance in tension = X (Collapse pressure ratify) Burst Pressure = ~P + Depth ( Hyd. Gr. II --.~) BF (BouyanCy Fac%or) = ~.oo- (o.0~ x ~u~ wt. z) Calculations: Total Co&t · · ,680 ' TMD 10,502 6 KTU-4$-6X TMD 570C o ~ooo ,~! - I , J FEET Alaska District I": I000' KENAI GAS FIELD ' PROPOSED WELL 'LOCATION K D U-8 (44. X -I ) OCT. 17, 8( Zooo 'eS% I .. JUN ~ 6 1~381[ ' ' I Oil & Gas Cons. -- : UNION OIL COMPANY OF CALtFORIqI^ Usc & "co '~e,'tu~ ~ ~'/~ " vto'L.e. "fro '~. ~ooo ' · , .o o . £HECK ~: ,. ] · ) o . ,. HY~94UL/£ OP£PW T~D VALVE · ".' ' ]./,SATE O.q " / . ,, , . . . : · ., · ~c,41-f C~ l..O-TO, q$ff J ' . G4 7E V, q L V£ ,. _.p, g.,l, ~ g.RTG j · f PIPE RA/.t~ ( s ',) . .: · ~ HYDR~/JLI£ OPEP~TfD ., .o ZO-I--OR~U~ · . . ' ' ' ?/?E t~A/.tS · · , . . ,, . ' ........;-,D-..'; L~ ) gOTE ' APP~CVAL BY THE DISTRICT DRILLING SUPERIrlTENDENT j sc~t[_,, .... ~-- VI/' · , JUN o ' 09 CHECK LIST FOR NEW WELL PERMITS Company ~-~- Lease & Well No. ~OM~ ~ ITEM APPROVE DATE (1) Fee (2) Loc (2 thru 8) (3) Admin (~ thru 11) (4) Casg 1~2 ;t hru 20) <5) BOPE ~ (~2'1 thru 24) (6) Add: 12. 13. 14. 15. 16. 17. '18. 19. 20. YES NO REMARKS 1. Is the permit fee attached ............................ ' .............. ' ~_~_.... 2. Is well to be located in a defined pool ............................ 3. Is well located proper distance from property line ................. 4. Is well located proper distance from other wells .................... 5. Is sufficient undedicated acreage available in this pool ............ 6. Is well to be deviated and is well bore plat included ............... __ 7. Is operator the only affected party ...... ...... ...................... 8. Can permit be approved before ten-day wait .......................... 9. Does operator have a bond in force ................................. f~ ~~--~'~ 10. Is a conservation order needed ..................................... _~' 11. Is administrative approval needed ................................... ,/ Is conductor string provided Is enough cement used to circulate on conductor and surface ......... Will cement tie in surface and intermediate or production strings ...~_~ Will cement cover all known productive horizons .................... Will surface casing protect fresh water zones ............... Will all casing give adequate safety in collapse, tension and'burst..~ Is this well to be kicked off from an existing wellbore ............. --.~ Is old wellbore abandonment procedure included on 10-403 ............ Is adequate well bore separation proposed ........................... ~'__ 21. Is a diverter system required ....................................... 22. Are necessary diagrams of diverter and BOP equipment attached ....... 23. Does BOPE have sufficient pressure rating - Test to ~--~o o psig .. ~ 24. Does the choke manifold comply w/API RP-53 (Feb.78) .................. 25. Additional requirements ............................................. Additional Remarks: ~~'~ ¢7~ INITIAL GEO. UNIT ON/OFF POOL CLASS STATUS AREA NO, SHOKE Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file, To improve the readability of the Well History file and to simplify finding information, information, of this nature is accumulated at the end of the file under APPENDIXi No'special'effort has been made to chronologically organize this category of information. vv VV vv VV VV V V VV41~ VV VV VV Vv YV vv YV V¥ vv vv VV vv vv vv 000000 000000 11 000000 000000 11 O0 O0 O0 O0 llll O0 -~'-'00-~ O0 O0 11{1 O0 0000 oo oo00 O0 0oo0 O0 00o0 Il O0 oo oo oo O0 Oo 11 O0 oo O0 O0 O0 O0 11 0000 oo o0oo O0 11 0000 O0 0000 O0 Il O0 oo oo oo 11 O0 :~- ;00 .-00 '- ~' O0 11 000000 000000 111111 000000 000000 111111 *S/ART* =USER" PCCC [1070b,5563b]' dOB SHIP Sk(~. 7~.34 DATE 24-dUb-79 10:49:41 MONIT[]_~ SWS KL{0E34 JiJ[,-79. *START* ' ' FI[,E: DSKH:VERIFY.O01¢057>[10706,55636! C}~EATE[): 24-JUla-79 10 46:57 ' PRINTED:''24-JUL-79 ~10:50:10 OUEUE SWITCHES: /FILE:~U~T /CDPIES:I /SPACING:I /LIMIX:125 /Ft)PMS:Ht~RMAL RECEIVED -.lAN 1 5 =~ · Alas~ 0i1 & Gas cons. 6oramissie~ An¢lorage R£C£1v£ NOV- 4 1983 ~las~a o~1 & Gas Co~s. Cor~m~ . . AnChora S$ior~ l.,.I,g VERSION 15,HOI 79/03/26 PAC .[l~ lC CLIA~T COf.~PUTING CENTRR 10706, fifi6J6 , RE:EL HEADF.:R DAT.~,: 'Tq/ 1/23 TAPE HEADER bENGTH: 1,32 TAPF, NAiV~I=:: 5563~ DATE,: '19/ 7t23 5E.:RVICE: NANE: EDIT rAPE CfJNTiNUATZUN NlJMB~:R: PRF;VlUUS TAPE NAHE: TAPE CSG=I 3.3?5~a2bO~/~TSg= 12 F'I,=7.6/RM=5.1 5~65/R~viF=~. 42[abO/RMC=3. ~ l{~b I/BHT=~ ~ 1 F"I .[,E; HE, ADE;R F: N ,,. ! tt: l.. [~ [~: NAME: AXIMUN P Ek: v .I UUS ANY D SHIP 1 lin T ¥ E; I1"¥ IJ P C 0 M P I"iEI, i,~ A N G ,SE(.'. 1' C [) U t',1 S'tA r DENS 62 B.Y ']'g8 : [, D 1 T . () 01 H~ISICAL RECORD F I[.,k~ NANk;: : UNlt'.IN [1I[, C : ~'I' [J 43-~X : KtLNA I GAS : llw 7 KENA I. ALAMKA 80O. L, E; N G T H: UE' C Ah 1024 .BYTES DATA ~"£1Ri'.'tA'I' SPECII:'ICAI'I[.IN 0 DATHt4 5PF.:CI[-'ICAI'.lt.)N B[,OCI<,S: NA!qE T{JU.I_, UNII' APl ~,PI APl APl. 1-'11.,1,. SIZE SA~vi lak,~' PROCESS INDiCA'I'OR$ I L) t', P q' [.,' '.[' r) o 0 o 0 4 ) ~ ~ 3 CII,D bl.b ~,.~y~tit) ? Il. 46 t) 0 4 1 ~8 4 C I. l, ~! D 11., N [~'! d LI 7 11. 44 () 0 4 .l 68 5 C,51; I, DI£, t.I~.~HU 7 2 I 1 0 0 4 I. 68 6 GR BHC GAPi 7 31 32 o 0 4 1 68 7 GP, CNb (.;APl 4,2 ~l. 32 O 0 ~ I 6el 8 C:Al,l Cr..~k, 1,~ 42 .28 1 0 t) 4 !. 68 9 DRHO ifDC G/C3 42 :;4 O 0 0 4 1 68 :I0 NPH!. CNL Pti 12 68 3 0 0 4 I 68 11 R~l(~B k'DC G/C~ 42 35 1 0 0 4 I 68 12 bP, AT Cal, C/C 42 a. 2 1 0 0 a 1. 68 i 3 N C ~,t I, C 6', L C P 5 42 13 .-~ 92 0 O 4 1 68 14 F C N I~ C i'..I L C [-~ S 42 3 '.~, 93 0 0 4 .l O 8 15 G F. t4 rt C G A. P 1 o O 3 I, 32 a 0 4 ! b 8 :] 6 ['~ T ~ H C [) 8 / F 60 52 3 Z' 0 0 4 I b ~ (.)U'I'PtJT ,SP A"[' 2 [)IJTPIIT C IL, D AT 3 [)[j I.'PtJT C [ [.,M A'.[' 4 ()UTP[I~' C..S~ 1'., A'I" [.)tJTPtl'r' G~ Aq' O LI I' IP I I T G ~ A '11 ? t)ilTPIIT CALl A'.r 8 (.) {J 'T P t ~ '1' I ) P H t.~ A 'l:' q (.) Ij T P l.] 'j.' N P i! 1A ] 10 (,)[}'[[:'I,)T RHIJB Al' .1, 1 [j[}TPIIT NRAT A'] ,1.2 {JLIT['~IIT NCNI~ A'l" 13 I3 U T P (I T F C' ~'t 1..~ a "1.' I 4, U t.} 1' [." t.I T fi ~ fl T 1 5 Ut,IT[>I~T D'[ ,~q' I 6 8{50.000 t00. 000 8200. ()00 a 1 oo. 000 8000,000 7900,000 7 gO 0,0OO 77O0. 000 7 (~()0, U('.) 0 '7500 . 000 7 ~ 0 0.00 0 H 11 k PI [] N I C GR r't p ti 1 VC Nb SP 1t P H J. FC NB SP N P H l I:'C N L SP NF:HI. 8P SP NPH i 8P GR FC NL tX! [:.' H .1 t' C N I., GR F CNL SP N P H I 1' C 1~ 1., G R t,t P H 1. F C N b VA -2 3 10 -2 2 -1 5 3 9 -1 .3 9 -1 4 3 11 -i 5 4 8 -2 5 -2 5 3 9 -2 5 -2 5 1_, U E 2.25(.) 8.90O 3.640 I. 2 ~,.-i: 5. 750 4.000 9.820 3.89:1 8. '750 4. b. (} :1. (} 6.525 '150 40 (') 9e~O 809 '7.000 8.100 0.08 (') 8. ,404 ~,. 250 9. 'l 00 1.94. 0 O. 223 5.750 3. 600 1.920 1.96q 4.0 00 (). b (,) 0 4,. 00 0 6.096 5 U 0 gOO 640 9,12 3.000 0.1 O0 5.420 4.084 5. 000 6. 't 00 5. I .081. M N k ih t.I N .l C C ILl) GR GR C I GR C lt,i) C litD P, Itt.}B C1 bD GR C it.,D GR C I L D GR Gl-;: ' C I L O (./R C 1. l., O C I I, [) GR MHIIB C ILl) GR V A L, l.I E 1 3/t.0'!5 98.800 2.33J 9 ~ .057 a7.424 5b.lO0 1.7 ,':~ 7 '1 i}. B 00 1 30.61 7 71.. 50 () 2,462 72.284 131.826 t~9. 200 2.455 65.195 I O1. ~59 65. 000 2..429 10.553 190.546 81.2 O 0 2.48! 92. 809 100. 925 {~ 5. 'l 00 2.418 72. 449 92.0.45 '? 2..~ 00 ?.434 61,351 ~ '7. o 0 2 6 q,/400 2.40 ,,~ 16.5 70 119.1,24 81..400 2.454. 82.6 lO 7:2.800 2. 436 77.2 ] 0 MNEMONIC VAbUE, NNI'.NUN IC CII, M 129.420 CSFb CALl 13. 800 DHHO NRA'£ 3. 172 NCNb DT 91. 750 C CALl aRA'I' D 1' C 1. I,g CAbl N R A '£ 10T C 1. b M C AL1 i'~RAT C I b a CALl t'~ R,A T D T C A b ,1 N R A D T 1~ R A T t) T C I I,, CAhl NHAT D'.I' C Ih ~ C AL 1 i~RAT VT 37.670 CSF'b 15.400 U~HLJ 5.480 NCNb 99.800 127.057 CSFL 13./00 DHHO 3.362 NCNb 89.5O0 128,233 CSFL ] 3. 550 L)RHL) .~, 600 NCNb 9O. 55O 102.802 CSF'b I 3 , 050 DRHO 2.958 NCNb 100. 300 1 '7 '?. 011 C 8 F L, 13.800 D R H 3.614 NC NO 96.700 89.536 13.55O 3.082 9 ]. 30O 84. 3. 88. 8(') . ~9. 723 050 268 5O0 100 '718 600 DR t-lO Iq C lq b CSFb D }{ It LI N C i,1 b D R H O N C iq L C [[,M C A i..~1 £) T C 1 L ?4 D"I.' 119. 1.5. 3. 92. 84. la,. 95. 124 3OO 500 ; 2.3 400 270 25O CSFI., D l-< H U . N C N b C SFb I.)RHU VAbUE 104.715 0.021 313.599 38.726 -0.002 1 '13.316 135.51~ -0.005 301.158 131.826 O. 080 2'14.989 114.815 0.053 322.179 197.697 0.010 270.699 86.298 0.034 338.481 63.096 -0.002 315.744 9 'l. 2 '15 0.026 291.720 11~.0~2 293.805 53.951 0.026 28~.143 D ~ P T I.] ? .~; O id. 000 2o0. 000 71 O0 '. 0()0 7000.000 6900. 000 6800.000 6 '700 . 000 6600.000 6500 o 0 () 0 6400.00 () 63 O 0 . () 0 ,') L.~ t~iq lC $ P i,~ P H 1 FC SI-" SF GR NF'H ] F C ~',J L 81> GF: NPH I. GR N F' H .1 F C N 1, SP SP NPh 1 [~'C N L SP N P H ,I G R N F' H I P'C N I..~ F'C N b VAb -3 I 5L 110 -]3 54 31 111 43 -43 55 33 102 - .30 54 U E: .5OO .300 .480 .253 50O ~ 0 0 .480 540 .000 .400 .360 .~70 .750 . _gO() .14 O .5~1 .5 00 .900 4.4.250 40.90*3 25.20¢ 42.75O 52.600 30.360 95.60'1 '] 3.750 44 · 0 O 0 .43.3 ~ 0 69. 498 49. '150 48.2OO 3,0.680 .1, ,~, (,~ '72 32. 750 4.0. 300 27.840 ~ 0.750 4 ?. 700 39.90 ('~ 81,. 51 () Pi t~1 ~,Pll ) N .[C C ill) Gl( CILD G P, C: 1 I~ D GR Ri.~tltJ GR C 1 I,,t.) C .1. lad GP ~ l-J () B G R C 1 L D AH[IB G R C I JjL) Gl.,.. C I ,I,~ D C 1, I~D GR C I i.., D R H (.I B C I' [., j) G F! V A [., U E 77.983 '70.700 2.428 71.3'77 94.723 69. 800 81.764 gb.298 70. tO0 2.291 73. 83.946 15.400 2.4 ] 4 77.801 9b.49a 73.100 2..464 48.306 60. ~ 00 2.598 6 '7. g 20 t', g. 400 2.4.31 67.255 80.9:10 6 l. 200 2.25'1 6'2. '192 32. ?.', 09 61.. 700 2 · ,,i. 01 62.474 5'7 58. ,50 2.57 11. 1.. 68 6 C). O 00 2.4 33 67.~32 M N E M U N 1 C CILM C AI..,I I",1RA i' DT C I b H C Al..,1 NRAT D T CALl D T C 1 ¢: A L ,t NR UT C 1 I, M L: A I, ,[ NP.A J' D I' C Ab 1. 1'4 R A T D ',1:,' CALl 1,~ RA I' [) C I !, H CA,U 1 F~RAT D T C A NRA'.I D T C J l,,iq CALl i,i R A 1 l) CAL, I f,,t R/~, '1" D 'I' VAI.,UE '73.114 1, 4. 550 3.1 '72 93.800 80.910 14.600 3.100 91.600 81.658 15.000 3.'784 102.900 76.560 14.350 3.164 88.500 94.024 14.200 3.416 90.350 39.084 1 3. 100 2.982 72. 450 74.473 13.300 3.378 92.50O 83.946 13.700 3.722 99.250 33.420 12.600 2.872 95.550 52.481 I ,1.000 70.800 105.082 I 4. 850 3.594 9'7. 950 MNLHUN lC C&FL, D~HU NCNb CSFL D R H U NCNb CSk'b DRHO N C i,,I la CSFL CSFb DRtlO N C iq b CSFb D R H tO NCNb CS[.,'[., DRHO CSFL b R H U N C N L, CSFL D R H [] N C IX] b C SF' b L:, R fi tJ N C 1'4 L t) RtiU a C N VAhO~ 91.201 0.00b 310.173 86.298 0.004 321.750 ~0.168 0.024 290.433 04.269 0.018 329.4'12 12 '1.057 0.03 '7 273. 702 53.450 0.035 339.768 ~37.090 0.0.39 303.132 'l 6.56 0 0.02t) 293.43~ 25.35i O.O20 .31. b 1 'l 58.076 O.05e 397.6~3 104.71 ,J 0.017 302.445 6200. 000 .610C). 000 5400.0()0 5 R 00.000 570 O . (.) 00 5,600. (! 0 540O. 000 5300.000 52 (; 0 . 000 M N k, M 0 N I C $ P GR P SP i',l P H ] N P H ] 5P GR [ CNI., 5P {3 }.: N P H l [~' C N I., SI:" Ge N P Fi i [, C H L, GP, N l.' H I, F C N b N P t'I I. F' C N L SP FC N b VAbll ' .~ 7 51 3 94 - 27 ~3 35 82 . .~, 1 101 i? () ',.40 60 46 64 ' '25 41 51 41. t.', 5 -38 -41. 39 6. 8 - a 7 '.'I 7 39 81 ' 40 33 .000 .2O0 .240 .80.9 75O OOf) '7 .~ 0 797 .500 .5 t) :) . {' 2 o , ~ '7 4 . gO0 .7 (.) 0 .5OO .300 .520 · '779 .000 .4OO .2 00 .0 ~ .] .5 i) 0 . h 0 0 .6 3 '7 .00 () .80O .540 .302 .250 . '0 (') 0 .8O9 .211 .500 . tl 00 .760 .081 .2.5O .5OO . q 0 [) . '747 M N k.M(}N lC C lbo RI-il'lB C ]. b D F',H()B GR CibD C 11,1:, G~,. CI. LD GR RI.tIJB GR C i l:., 0 R lq t) B C .I I, [; G F< C i l.., D Gl...: Gl-;' CII,D (:, t~ Ix f.t I. ,i ~, (; t{ C .I (.;t~ ~ H l,ll5 G[e C .1 b t; (J t..~ V Abtl[< 10~.7 61.q 2.~ 64-9 131.8 56.5 2.3 55.~ 76.5 5'.2.2 2.3 52.6 53 O0 ~7 26 OO 95 b2 60 0 t) 4. q ~5 2.~.595 71. i-, I) {) 2. ~ 10 72...531 1 .~$ 5. 75. 2. 7 5. 1 33. 57. 2. 61. 97. 70. 2. 66, 120. 6~,. 2. 86. !5 b. 2. 6 (). 80 o b t). 68. 56. 51. 2:. 51o 8 O0 334 045 I 00 376 4o .~ 275 2 0() ~ 26 184 226 ~ 00 "l 12 .~99 298 000 ~ 5 'l !68 100 g32 '~ 2 'l 49,1 .~ O0 g22 MNkMI]NIC VAbUE C.IbR ~7.902 CALl I 4. 000 NRAr 3. 260 l)'r 9.t. 750 C.lbf,,~ 135.519 C ALI 14. 800 ~ P A "f 3.2.32 UT 94.700 C]I,M b/.920 CAL,L 12. 700 UT gO. 450 ClbM ~ 27.057 CALl. I ~.400 I'1 ~ A'I' .3.914 D'[' :11 3. 350 C t L i',l 1. 36.773 CALl 1. 4. 300 i'~ R A T .3.92 b D(},' 110.650 C ILM '1 54. 276 CAbl 13,~00 NRAT . 942 D"[' 99. 100 C,[LM 1.00. 925 CAL, i : 13 · NRA1' 3. 864 I)']' 99.650 C ll.,M 109. 648 C A .b I I 4 ,.700 N R ~ T ], 468 D '!.' 105,450 C I 1..~ ~4 83. t 16 C A L l I 3.300 id a A T 3. 'l 28 L,~ 1" 102, q 50 C 1 L ~ 75. ~ 58 CAI,1 1. 3. ~00 NRAT 3. 480 0'1' ~ 01. 000 C I I..~ M 56. ~ 94 CAbi 12. 750 .{q R.A T ~ , ] 68 MIiEMON lC DRHO NCNb CSFL NCNb CSPL DR[tU NC !qb CSFb D~HU NCNb CS~.'L D ~ It U N C N b D R t-t u I',1C Iq b CSl~'b l.)a HU l,~ C I.'~1 L CSFh DRHu CS? b D R t:t [t NC NL C SF'b L) RHO N C N b C,SI~ b D t.<. HU N C iii L · , VAbUE 0.046 29~.010 148.594 O.U1'7 278.42'1 b4.863 0.016 319.b05 148.594 0.015 229.515 101 0.042 244.959 17 '7.0 1 l 0.112 246.246 95.499 0.068 202.119 109.648 0.045 261 .261 103.753 O.O,qO 246.246 73.790 0.037 28 'l. 430 35.645 0.032 ,301.158 D I:.. P T H ..5 1 ('° 0.0 0 0 5ilO0. OOO 4qO0'.O00 4~00.000 47 (,' 0 . C} ¢) 0 4600.000 q % 00 . () 00 44, 00 . 000 4: !I 00.000 2.. 00.000 4 1 (0. u 00 NPH £ F- C~ L, SP i'~' 1" Id .I. F CNI.,, (.-; .P, NP[t I F C {4 L, GH NPH1 F C N b SP GR N t:" H ] [ C N L SP N [' H i ["(:Nb SP N P H 1. IF C Nil,. SP l,J P it 1 t C i~ b · F" C N L, V Al., 56 - 50 34 42 25 41 36 1 O0 -43 .3 7 -42 39 33 1 -15 53 52 54 -22 15 -39 40 40 8:] -19 -46 3~ 25 135 UE .750 .500 .4.00 .199 .500 .20 o .820 .525 .500 .b(~O .340 , ?t~O .000 .400 .780 .815 .000 .6(:)0 .440 .084 .000 .30 () .200 .534 .50(') .700 .160 .054 .500 .100 . , .00 () .5O0 . .i4.0 .226 .50O .90 t) .260 ,35 3 .50 U . '200 . 'l 60 MN ~;M('I N lC C 1 L [) 1-( PI t.115 GR C IbD C i GR CII.,D (JR Gl:-'., CI.I,D (.; P, C I L D R Ii U B C .L i., D GP, GR C 1 I., D GI~ (JR ~ t,ttJb (;14 C I b D G I4 RH[~B C I 1,, D t:,: }t tJ B G R VAb 111 55 2 64 76 50 2 53 4b 53 2 55 1.07 69 2 bl I 45 55 2 59 1.29 5~ 2 57 346 2 73 2,18 b5 2 2 7'7 ~7 2 ~ 0 26 54 2 55 .68b .gOO .292 .288 .560 .200 .118 . 't 3e,., .132 · 30O .105 .'715 .647 .800 .~1 . qO0 .118 .754 .42 0 .7 ()0 .1,52 .440 . '137 . q ()0 .07 .~ .850 . '17 b .900 .224. .8e, 5 .600 .07,4 . ~'78 ,()11 . () 0 () , .1B (~. .400 . MNEMUNIC C l CALl N iq A :1' DT C ILM CALl N R A T DI' CiLM CALl N K A 'P DT CIUM C AI..,I I:~ R A T t) 'r C I, ,t., M CALl 1"~ t< A T C 1 C A I,, 1 NRAT C i LM CAI, [ D C ILNi C A,L 1 L' T C [I.,M C A L 1 .N R A T DT C I. i., M C A i., 1. ;',t R A T D'[' C 1 I.,, M C A 1., i VA.L, UE 111.686 13.200 4.078 109.500 79.433 12.4O0 2.998 135.150 q6.989 12.300 2.004 142.250 95.499 3.338 99.500 1.30.773 12.850 10 .450 118.032 12.750 3.130 121.500 319.154 15.300 4.372 131.700 21.2.81~ 13.150 ~.652 l15.b00 11.8.032 12.500 3.52b 126.750 183.654 I 4. 200 ]. 986 I 1 1. b 00 28.8,~0 12.550 2.05~ 187.300 MNEM[JN lC C,S Fi., DRHU N C r,J L C St;' b NCNL CSFL DRHO N C IN b CSFL DRHU CSt;'[., D R .H 0 N C N L CSFI., I)RHU NCNb CSF'E DRHU N C N b L)RHO NCNb CSFL N C N u CSF'L bi ~ H tJ NCNb CSFb ORflU NCNb 131.82~ 0.112 230.802 89.536 O.OOb 297.726 53.456 0.002 355.212 98.175 0.018 321.32.1. 147.231. 0.005 29o,8e2 .127.057 0.020 339.768 217.971 0.012 226.941 231.206 O.022 215.418 138.038 0.0O8 284.421 210.86~ 0.021 250.1u7 2 '9.376 338. ~B 1 t)l:, P i"h 4000.O00 38 t.~ 0.000 ~ 700.000 3600. O 00 ~ 500. O 00 3400. 0 () 0 3 ~00 . 000 ,:~ 200 . 000 .~ 100.000 3()t~(i. 000 M N ?':MIj H 1C S P 5P G F. t.t [: H I ? C i'J 1., G 14 I',l F' ii .1 ~[,~ ~,~ F H i t. (; N H P H i t" C N 1,,, (~t F> l-.~ I f.,, P H } S [':~ l: C N .L, i,.! P H I I~C N L F' C N 1., N F' ti 1 1~ C,NL V A L L] F' 3'7.25o 51. 120 62.205 I 8. 000 38.8uo 56.700 55.341 -lb.250 32.800 6 '1. ()00 36.0 3 b - 16.500 ,1 '2.6 t)0 57.4';O 51 - 1. 7.75O 3 §. 500 46 .ogO ~ 4.7 79 - 23.000 21. 500 b'7.02,,0 36.894 . ~o. 250 60.30 () 6 2. '720 57.91, 5 000 90 t) 440 3 '7 I 4:2.500 4 l. 56O 57.915 -39. 750 34.20() 41.5,20 - 2 !). 'l 50 'l 0. 185 ;,1U N 1 C C i l., O Gl), IR It I.) b CIbD C i L, I: C I 1., L) C i b D G I.( C I ,b 0 C I b D GR GR C IbD GR C I I,, 0 GR C I b D GR C I i., O G V A I.~lll": 131 .~. 54.2 205.1 5H.9 2.0 6,8.4 I 02. ~ I 64.4 56°4 1.9 e, 1 .5 2.51 .1 58.4 2.1 60. ~ "1.6 47 .~, 77. ~ 104.2 1..'1 89.3 64.9 55.6 2.0 51.6 9~.h 69.4 l I. 5 67.9 52.2 2.1. 5a. 8 1, 3b.'7 5 e,. '7 ?. f') O :~. 2 (') () 2~ 91 16 O0 75 09 02 O0 O1 46 ~7 0 0 98 O0 74 51 O0 6a 01, 83 00 47 t) 0 '11 76 24 00 9O :1.2 20 00 17 0 o Ih M N ['.Mfj N [C V AL, liE CII.,M 134.27 CALl 1 3. 300 NRA'[ ¢ . 156 UT 122.600 C IbM 20;. 014 CALl 15.20() h~,AT 4. 592 O'.t' 127. 250 C I [.,t,'~ ! 02. C~L,i IO.050 r~ ~ A'I' 5. ~66 P:f 131. 750 C] I,F~ 175.388 CAI.,.[ l;~ RA 1' 4.840 UT 129. ,J0() CILM 248. ~86 CALl 15. 300 N ~ A 'i' 4.0 t) 2 D~[' 117.550 C I .t., ~4 70.469 CAb]. 1,~.550 f'J R,a 'i' 5.070 D r 13'1.100 c ~ l., ~.i 77.268 c A b I 14.100 it P A 'l' 4.080 0'.[' ,120.750 CILM ' 61.376 CAI~I J J.lO0 i'~ R A T 3.6 30 iJ't' 1. 29. 200 ~: I I,M 9 t. '156 CAbl I 3. 350 I 24. 600 C] I~M 66.681 CAI,[ 12.700 NRAI 3. 780 ~., I' 1. 26.900 C'AI., I 12. 550 L~ f I 27. 500 MNf~MON lC CSKL DH HO NC Nb L)H HIJ NC i,l b CSi"b DRH(J CSF'b D R ~.t U NCNb C S Fb U H H (] N C N L, CSFL NCNb C S['"'L, t)RHU N C N b CSF'b D ~ H L} NC NL CSFb [)R HO NCNb I.)RHU CSFL D.B H U N C N b VAbUE 158.4d9 0.020 24~.~20 229.087 0.02(3 23~.~06 61.944 0.013 1~3.612 190.546 0.014 215.787 2'15. q2.J 0.016 252.25~ 66.069 -0.00b 193.908 '19.43 ] 0.002 235.521 59.1.55 -0.002 290.00~ 112.720 0.014 24b .b'15 73.790 0.020 274.989 159.956 O. O ,:lb 2'16.276 2 ?(,,0. 000 2600· 000 25O0. 000 2 :~ 00.000 2. 4 O0. 000 GR NPHi FC NL 8 P t~ CNL VAL(~ -26. -4?. 3 43. bO. -2'4. ~. 52. 4~.. '-48. 32. 44. ,,,40 ,. 25. 6 0. '-48. 0 o 0 l O0 24(3 000 90 {) 9l a 250 900 ~ 4O 477 250 70 0 32('} 92 / t) 0 () P, O0 060 000 000 (,) 00 000 000 000 () 0 O 000 C i L D C .12 L O t~ H 0 tS C ]..LD R I.i U ~3 GR 127· 60. 2. 52. ~7. 51. 2. 129. 55. b(}. 7?. 2. 49. O. ,10. 2. 36. 009. O. 0. 40. I (~09. 0. 0. ,40. O57 100 995 90 o O05 12'I 420 7 O0 26,8 075 bib {) 00 300 1.17 '/55 253 () 00 0 O0 465 253 000 (~ 00 465 M N I.'.MfJ N lC C[LM CALl N~AI' C ILM CALl N R A 'I' DT C AL 1, 1,I R A i' CALl N R ,~ T D T 'C I b ~ C~bI DT CILM CALl NRAT OT C I L P~ i.) T VAL 12:t 12 4 129 63 12 4 141 133 13 4 128 73 145 0 12 4 175 1000 0 · 0 100(} 0 0 56 U E .595 .650 .022 .450 .680 .350 .048 .65O .045 . qO0 .43u .950 . '190 .550 .908 .000 .006 .900 .91,1 .100 .000 · ()00 · 000 .850 .000 .000 · 000 .850 MN Et4(JN lC CSF'b DRHU N C N b CSFb D R It u NCNI, I) R H (J NCNb CSFL DRHU .NC Nb CSFb DRHO NC Nb CSFL D R it U N C N b D R H NC Nb VALUE 144.544 (}.003 212.784 72. 444 0.005 252 .~81 105.959 0.002 209.352 80.1 68 0,0~2 262.9 7 5 'l 5q. 398 -0.251 lbO.44U ] 000.000 - 0. Z 50 0.000 1000.000 -0.250 O.OO0 bY'['ES 390 Fll,g 'I"RA ] i,i-.P, I,P:NG] Fl: ~'2 6¥ [" 1. I., ~, hi A t,ll-,: t,.. 1.) l t' ,,001 r',IAXI.,',}U~ Ph¥S,[CAI~ P, kCUHI.} 10 2 4 T h P ~, ':1'1~ A 1 L, I,.; Ft 0.1. D A'I.' Ii;: '? 9/ '112~ ~mmmmmmmmmmmmmmmwmmmm~ · V£RIFICATION bISTING DVP O09.HU5 V~RIFICATiON ~£~TING ** REEL HEADE~ SERVICE NAME :S~RVIC DATE ORIGIN : REE~ NAM~ :REEL ID CONTINOATION # ~01 PRE~IOdS REEL : COMiqENT$ :REEL COMMENTS ** TAPE HEAuER ~* SERVICE NA~E :SCRVIC DATE :~1/11/15 ORIGIN :1070 TAPE i~AI~E ;622~6 CONTINUATION ~ PREVIOUS TAPE : CUMME~,TS :TAPE COMMENTS ** FILE HEADER SERVICi~ NAME : VERSION # DAT~ : MAXIMOi~ LENGTH : ~024 FILE TYPE INFORMATION RECORDS MNEM CONTENT8 CN : UNION OIL COMPANY FN : KENAI GAS RANG; TOWN; 4N SECT: 6 COUN: KENAI STAI; ALASKA CTRY: USA NNEM CONTENT~ RECORD TYPE 047 ** PAGE 000 000 018 065 '000 000 014 065 000 000 010 065 000 000 003 065 000 000 002 065 000 000 OOl 065 000 000 00~ 065 000 000 006 065 000 000 004 065 UNIT TYPE CATE SiZE CODE OOu 000 uO7 06~ LYP 009.H05 ¥£RIFICATiON LISTING RECORD TYPE 047 ~ ~ RE:CORD TYPE 047 ~ ~ COI~MENTS ~ JOB ~ 10707,62266 Lib RUN #2, LOGGED 27-OCT-S1 BOTTOM LOG INTERVAL TOP &OG INTERVAL CA~ING-5OGGER BIT SIZE TYPE HOLE FLUID DENSI'rY VISCOSITY PH RMF ~ i~CAS, TEMP, R~ ~ ~T 10216.0 FT. 7282 FT. 9.62 ~N . ~ 7282 F~. 8.5 I~, X-C PObUMER 82,0 54.0 9.4 5.0 C~ 2 220 1:720 1'153 OH~a ~ 145 F MATRIX bIMESTONg PAG5 JU~ ~ lU707,62265 LOGGED 10-OCT-8! BOTIO~ bOG INTEKVAb TOP LOG INTERVAL CASING-LOGGER BIT SIZE TYPE MOUE FLUID DENSITY VISCOSI'~Y PH FLUID bOSS RM ~ MEAS, TEMP, R~F ~ ~i~A$. TE~F. RMC @ ~EAS. T~MF. RM @ JHT = 7300 FT. = 2562 FT. = 13318 114. {~ 2565 FT. -- 12 1/4 iN. : XC 9,6 : 6 0 ~v~b = 3~21 ~ 64 F = 3,24 ~ 52 F = 5.24 = 1,73 ~ 119 F MATRIX SAhDSTON£ *~ DATA FORMAT RECORD ~ ENTRY BLOCKS TYPE SIZ£ REPR CODE 4 1 66 8 4 73 ENTRY PAGE DVP 009.H05 VERIFICATION DATUM SPECIFICATION BLOCKS MNEM SERVICE SERVICE UNIT iD ORDER DEPT " FT GR OIL GAPI SP DIL IbD 003 SFbU 003 OHMM DT 003 CAbI FDN RHOB 004 G/C3 NPHI 004 PU DRHO 004 G/C3 GR PON GAPI NRAT 0O4 NC~b 004 FCNb FON 0 DEPT IbM RHOB NRAT DEPT IbM RHOB NRAT DEPT RH08 NRAT DEPT IbM RHOB NRAT DEPT NRAT DEPT IbM NRAT ATA ~* 1~238,000 GR ' 999.250 SFLU 1'737 NPHI 4,520 NCNb 10200.000 GR 11.039 SFLU 2.i6Z NPHI 3,Bll NCNb 10100,000 GR " ' 8.148 SFbU 2 2 NPH! 10000.000 GR 4,758 SFLO 2,484 NPHI 2,~0~ NCNb 9~00,000 GR 9,~12 SFLU 2.~53 NPHI 2,~4b NCNb 9800,000 ' GR " 6.781 SFLU 2'549 NPHI 2,973 NCNb API API APl bOG TYPE CLASS 0 0 0 7 31 32 7 1 0 0 12 46 7 0 0 0 0 0 0 52 32 42 28 3 0 35 0 68 2 0 44 0 42 31 32 0 42 1 0 4 92 42 ~4 93 65 66 .lin '999,250 SP -999,250 DT 65,576 O~HO 1355.000 FCNb '23',938 48.193 DRHO 22 ..ooo 906 22 607 3494 000 FCNU 63.312 SP 602 DT 62,906 SP 9,688 DT 276 393 DRHO 336:000 FCNb 70,I'88 SP 5.461 DT 31.836 ORHO 2692,000 FCNb API FILE SIZE PROCESS MOD NO. LCVEb 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 0 0 4 0 '999,250 -999,250 -0.100 291,750 10,914 80,188 '0.023 566,000 3¸ 0 7~: 50 750 0,000 1477,000 23.016 81 75 957,000 1,969 72,375 O,P12 1128.000 '0,031 76,000 0,037 ~8~,500 CALI GR CALl OR CALl GR IbP CAbI GR' CAbI CAb i GR SAMPbE 1 1 1 ! 1 1 1 PAGE 4 REPR CODE 68 68 68 68 68 68 b8 68 68 68 68 68 68 68 '999,250 8,500 85.250 10,844 88 8 , 953 9,094 ,48.844, 4.828 9 180 60:625 8.211 9.469 55',844 7.188 9.~59 53.688 LVP 0139.H05 V~R1FiCAIION LISTING PAG~ 5 DEPT 9700.000 Ib~ 9.925 SKbU RHOD 2.54~ NPHI N~AT 2,918 ~'~C~b ., DLPT 9bO0.O00 GR Ib~4 ~.~61 SFLU RHO~ 2.54'1 NP~I NRAT 2,78'7 NCNL DEP'f 9500,000 GR I~,q 10,O39 RHUB 2,~82 NPNI NRA'I 2,342 NC~ DEP~ 9qO0,000 GR ISM 10,938 SFbU R~OB 2,49~ NRAT 2,551 NCnb DEPT 9~00,000 GR IbM 6,992 SFLU RHOB 2.377 NPHI NRAT 2,39~ NCNb DEPT 9200,000 G~ I~4 18,84~ SFUU RHOB 1.520 NP~I NRAT 4.72~ NCNb DEPT 9100.000 GR IL~ 6.207 SFbU RHOB 2,494 NRA'£ 3,082 NCnb DgPT 9000,~00 GR IbM 11.742 SFLU RHOB 2,~35 NP~I NRAT 2,~88 NC~L DEPT ~900,000 GR ILH 7,930 SFLU RHOB 2,477 NP~I NRAT 2,56~ NCNb DEPT 8800.000 G~ IbM 7,477 SFbU RHO5 2,620 NPMI NRAT 2.852 NCNb .DEPT 2700.000 GR 'ILpl 6,16~ SFbU RHO~ 2,~67 NPHI NRAT 3,2~ NCnb 69.250 14.906 31.836 2802.000 63.094 6.375 29.004 2672.000 53.125 ~,281 21.973 330b.000 77,b86 12.148 25,679 2758,000 29,781 ~.5~0 22,119 3614.000 39,3~4 71,438 60,205 1784.000 $6,281 ~.992 32.080 25~4.000 5~.188 16,141 23.096 2708,000 49,938 6,629 24.121 33~.000 47.594 6.133 2b.320 2772.000 65,000 5.273 34.~63 2532.000 SP DT SP DT SP DRHO SP DT FCNb DRHO DT DHHO FCNL SP DHHO D~ DRHO FCNb DRHO DY FCNL 8P DRHO lg,O00 77,188 0.013 931.500 1~.q69 77.18~ 0.01~ 953.500 -9,531 ~7,188 0,0@6 1292,000 3,967 78,188 0.016 1077,000 -2i,03i $2,750 0.008 1461,000 '12,023 116,375 -0.042 369,000 '3,531 84.375 0,000 U20.500 15.016 65,188 0,08~ 1084.000 3.467 83,000 0.045 1311,000 -6,039 89.563 0.07~ 949.000 -12.531 89.37b 0.026 735,000 ILD GR CALl G~ IbD CALl GR CALI CALl CALl GR I~D CALl GR CALI G~ CAL~ CALl GR ILO CALl 9.398 9.180 56.40~ 8,2~0 9.89U 57.00u 10.469 10.172 45.750 12.391 9 539 75:~25 6,789 10.828 29.q8~ 22 703 15:039 39.938 6,137 11.570 58.15b 10,992 11,867 50.031 7.996 12 219 41:438 7.002 12.305 39,375 6.180 12.500 60.594 LVP DEPT NRAT DEPT RHDB NRAT DEPT InN RHOb NRAT DEPT NRAT DEPT DEPT NRAT DEPT IbM RH05 NRAT DEPT RHUB NEAT NRAT DEPT RHOB NRAT D~PT IbM 009,H05 VERiFICATiON 8bO0.O00 GR 3.e18 SFLU 2.432 NPHi 3.268 NCNb 8500.000 GR 5.691 SFbU 2.473 NPH[ 3.32~ NCNb 8400.000 GR 32.750 SFbU 1,462 NPHI 5.461 NCNU 8300.000 GR 2.51b NPHI 3.143 NCNB G200.O00 GR '19.266 SFDU 1.'108 NPHI 4.92b NCNB 8100.000 GR 8,531 SFLU 2.471 NPHI 2.~67 NCNL 8000,000 GR 8.75~ SFbO 2.367 NPMI 3.223 NCNL 7900.000 GR 9,977 SFbO 2,479 NPHI 3.021 NCNB 7BO0,O00 GR 10.320 SFLU 2,314 NPHI 3.18b NCNL 7700,000 GR '10,008 1.419 NPHI 4,914 NCNb 7000.000 GR 12.~84 SFLU 1.480 NPHI 57 3 3~ 2474 5 36 2420 22 569 73 1456 57 32 2654 27 18 65 1480 59 7 29 2570 62 6 33 2330 54 3O 2714 49 10 33 2956 37 63 1440 47 129 73 .625 .426 .766 .000 .500 ,520 .572 ,000 .188 ,500 ,877 ,000 .250 .395 .$61 ,000 .938 .438 .674 .000 .469 .777 .639 ,000 .750 .508 .936 .000 .531 ,383 .420 .000 .781 .047 .203 .000 .969 .344 .379 .000 .688 .625 .730 SP DT DR~O SP DT DRHO FCNb SP DT DRHU FCNL SP DT DRHO DT DEHO FCNB SP DT DHHO SP DRHO FCNL SP DRHO FCNn DT FCNL DRHO SP DT DNHO 3,969 91,~88 0,013 ~08,000 0.468 89.18~ 0.068 728,000 -37,531 130,000 '0,041 269.750 -lb.039 89.750 0.070 862.500 -34,531 115,563 0,002 306,000 -9.500 ~o.188 0.031 ~79.500 -17,000 84.563 0,033 754.000 -21,531 88,18B 0.017 ~73,500 -14,53I 101,000 0.005 W83,000 -22,000 104.750 -0.042 '35,063 108,750 '0,058 CALl GR CALl CALl G~ CALl GR CALl GR lbo CALl GR CALl GR ILD CAL~ GR CALI GR GR CAb I PAGE 3.932 13.44b 59.000 5.727 11.~8J 59.969 33.188 1~,297 22.14I 6.922 11,961 54.969 12,641 11,203 33,156 8 727 54.000 8.570 13.500 50,281 10,117 13.~0~ 54.250 12.250 12,617 47.000 14.109 15.664 15.172 15 523 5:781 40.531 NRAT DEPT RHOB NRAT DEPT IbM NRA'£ DEPT DgPT NRAT DEPT RHOB NKA'£ DEPT NRAT DgPT RHOB NRAT DEPT IUM NRAT DEPT NRAT DEPT IbM RH06 NRAT DEPT 009.HO5 VERIFICATION 5.992 NCNb 750 0.o00 GA 2,402 NPHI 2,877 '140 O,uOO GR 9.492 6F~U 2.q6'; NPHI 2.B67 NCNb 7300.000 G~ 16.219 SFbU 2.523 NPHI 2.B13 NCNb 7200,000 G~ 22,109 SFLU 2,502 NPHI 2,77~ NCNb 7100.000 GA 14,617 SFbU 2.301 NPHI 3.92~ NCNU 7000.000 GH 22,203 SFbU 2,~49 NPHI 2.B52 NCNb 6900,000 GR 13 Bg~ &FLU 2:537 NPHI 3.094 NCNb 6800,~00 GR '22,922 2,57~ NPHI 1.903 NCNb 6700,000 GR '15.023 6FLU 1,792 NPHI 4,922 NCNb 6~00.000 GA 16,828 SFbU 2,42~ NPHi 3,355 NCNb 6500.000 GR 13.367 blSTImG 1~73.000 48.375 8.000 28.223 2852.000 62.906 9,633 2 49O ss :ooo 6a,ooo 24.312 25.977 2298,ooo 67 188 30:766 27,051 248~.000 80,188 14.~77 47.070 2276,000 65,750 26,828 2~,076 2626,000 68.500 12.344 31,641 2328.000 54,344 105.000 13,916 3356.000 61,688 16.375 64.502 2043.000 59.625 16,734 36.279 2356.000 68,625 9.563 FCNL SP DRHO P'CNL DT FCNb SP D~ DRHO FCNL SP DT FCNb SP DT FC~b SP DT DRHO FCNb SP DRHO FCNb SP DT DRHO $P DT ORHO FCNb SP DT DRHO FCNb SP 286.750 -30.531 69.750 0.021 959.500 -40.531 90,000 0.020 925.000 -18,531 76.188 0,067 855.500 -24.641 8b.750 0,039 862,000 -17,203 91,375 0.022 550.500 -40,906 90.188 0,037 ~75.500 -24.625 85,i88 0,038 750,000 -3b,281 56,781 0,064 1733,000 -35.219 95.188 -0.021 376.500 '61,000 87.750 0.016 b2b.500 '51,750 91,750 ILO CALl Gk CALf G~ CAnZ GR lbo CAbI GR ILO CAbI CALl G~ CAbI GH CAbI GR CAbI CALI GR ILD CALl PaGE 9.320 13.539 46.813 10.188 15.039 59,~44 15.750 55'56~ 21.516 12.492 72.~2~ 14,859 12 500 78:438 18.578 12 961 7o: so 12,789 13 148 22 328 12!~44 58 031 16.906 13.563 52,719 . 15.~48 13.609 70.~7~ 13.b80 13,~90 r LVP 0o9.Ho5 2.461 NPHI 3.blO NCNb 0400.000 GR 15.984 SFbO 2.~2W NPHI 2.996 NCnb b300.O00 GR 14.289 SFbU 2.467 NPHi 3.004 NCNb 6200.000 GE 32.844 SFLU 2.490 NPHI 3.088 NCNb -- 6100.000 GR 9,906 SFbU 2.514 NPHI 3.J38 NCNb 6000,000 GR 13.10~ SFLU 2. 9 NCNb 5900.000 GR 13,961 SFbu 2.375 NPHI 3.477 NCi~b 5000.000 "'36.62~ SFbU 2.650 NPH~ 3,09~ NCNb ,, 5700,00O GR '11,21~ $FLU 2.330 NPH! ~,510 NCNb Lb00.000 b.242 SFbo 2.375 NPHI 3.59B NCNb ., 5500.000 GR 8.12~ SFLU 2,420 NPHI 3.217 NCNb 5~00.000 GR bi~TImG 38.916 2222.000 59.250 12.547 2 932 70.063 14.617 30.127 2108.000 53.312 27.859 31.836 2b16,000 48.094 8,281 35.742 187b,000 59.594 26.2~4 28 076 1821~000 5b.bg4 17.281 38.428 1790.000 57.563 56.0o0 3i,396 1721'000 54.406 I0.547 39.795 2000.000 50.281 6.063 41.260 1733.000 52.500 7,504 34,27.7 !975.000 60.656 DRHO DT FCNL SP DT ORHO FCNL SP DT DRMO FCNb SP DT DRHO P"CNU SP DT DRHO PC~b SP DT ORHO F'C~b SP DT DRHO FCNb SP DT ORHO FCN~ SP DT ORHO fCNb OT DRHO FCNb SP 0.013 581.500 -55.813 86,000 0.034 77b.000 -43.281 8S.375 0.027 -69.750 77.563 0,023 795.500 -26.45~ 92.750 0.065 567,500 -25.547 83.563 U.030 648.000 -41.688 93,750 0.005 472.500 -39.094 64.188 0,251 557.000 -37.938 97.000 0,011 55U,000 -19.750 103,188 0,056 445.750 '26.531 95,000 '0.004 597,500 '38,031 GR lbo CALl G~ IbP CALI GR CAbI G~ CALI CALl GR IbD CAb~ CALl G~ CALi GR CALI CALl GR 66.125 15.039 13.83b 67,063 13,B44 13.633 b8.688 26.875 12.477 53.719 10,883 14'078 57.938 11,578 14,070 57.312 12.172 13.63j 65,312 13 984 10.789 12.O6j 58.56J 6.35~ 12,281 61,~5~ 7.914 50.594 12.57~ bVP 009.H05 VER~?'~CA~UN IbM 13.461 RHOD 2.344 NRAT 3.752 D£PT 5500.000 IbM 11.891 RHOS 2.365 NRAT 3,533 DEPT 5200.000 Ib~ 9.~20 RHO~ 2.307 NRAT 3.377 DEPT 5100.000 Ib~ 26.375 RHO~ 2,375 NRAT 3.11W ~ DEPT 5000,000 IbM 10,328 RHO~ 2.070 NRAT 4,344 DEPT 4900.000 IbM 11.242 RHO~ 2.350 NRAT 3,541 D.EPT 4~00.000 IbM 9,609 RHO~ 2,342 NRAT 3,689 DEPT 4700,000 IbM 9,922 RHOS 2,377 NRAT · .. ' 7,96! RHOB 2,~76 NRAT 3.277 DEPT 4500,000 Ib~ 20,~I1 RHO~ 2, NRAT DEP~ 4400,000 IbM 18.250 aaO~ 2.~75 NRAT 3,16~ .. SFbU NPHI NCNb SFLU NPHI NC~b GH 8FbU NCNb GR SFLU NPHI NCNb ~R SFbU NPHI NCNb SFbO NPHI NCNb GR SFbU NPH£ NCNb SFbU NPHI NCNb SFbU NPH[ NCN~ GR SFbU NPHI NCNb $FLU' NPHi NCNb b~$TING 11.516 ~4.141 1904,000 56.063 12.938 40.137 !8'/2,000 ~0.656 12'719 37,354 1723.000 61.813 27,719 32,471 2082,000 48,063 12,117 54 688 1573:000 55.500 16,063 40,283 1734,000 62.375 10,766 42,969 1857.000 62 469 10i820 36 230 1940.000 54,03~ 9,508 35,596 2017.000 50.938 17,969 29.346 2062.000 49,344 21,766 33,203 2066,000 DT DRHO FCND SP D~ ORHO FCNb SP DT DRHO FCNb OT DRHO FCNb SP DT O~HO FCNb. $P D~ DRHO FCNb SP DT DRHO ~CNb OT DRHO FCNb SP DT DRHO FCNb 'DRHO FCNb SP DT DRHO FCNb 97.188 '0,006 477.750 -37.688 98.750 0,009 ~79.750 =55,406 103.000 0,023 501.250 '61,094 100.000 0 032 644:000 -27,688 114.000 0,069 332,000 -41.188 101,000 0,014 506.750 =44,125 99,000 0,019 468.250 -40.656 99,375 , 0.039 556,500 -36 781 122~563 0,017 566.000 -45,063 131.000 0.006 64~,000 ._ '38,84~ 91.563 0,020 618,500 CAbI GR lbo CALI GR CAbI GR ILl) CAbI G~ CALI IbD CALI GR CAbI GR CALI CAbI CALI CAbl GR PAG~ 12.086 bg,56j 11,148 12.258 58.156 10,15~ 12.063 67.93~ 23 813 1:992 51.375 10.227 12 305 51:563 ~ 10,836 1~.227 5 ,469 9,898 12,094 62.813 9,141 6 781 8,242 12.06~ 49,15~ 21 391 ~1i969 47 719 14,b4~ 12.039 43.406 . DEPT RHOD NRAT DEPT NRAT DEPT RHOb NRAT DEPT IbM NRAT DEPT NRAT D~PI' NRAT D~PT NRA~' DEPT NRAT DEPT RHOB NRAT DEPT RHO $ NRAT RHOb N ~ 1' 009,H05 V~RIFICATION 4300.000 GR 11.703 2.170 NPHI 4200.000 ' G~ 11,750 SFLU 2,094 NPHI 3,250 NCNb 4100,000 2,229 NPHI 3,'193 NCNb 4000.000 5,387 SFLU 1.970 NPHI 3.74~ NCNb 3900,000 GR 7,891 2,12~ NPHI ~,~57 NCNb 3~00,000 GR ' ~,172 SFbU 2,18~ NPHI 3,b13 NCNb 3700,000 4,~12 2,140 NPHI 3,920 NCNb 3600.000 GM 9,031 SFbU 2,276 NPHI 4,020 NCNb 3500,000 GR 14,047 SFLU 2,115 NPEi 3.~3~ NC~L ... 3400,000 GR '24.~44 SFbO 1.997 NPHI 3,105 NCNb 3300.000 5,070 SFLU 1.gb~ NPHI q,~41 NCi~b b I $ T I N G 54. 10. 36. 2000, 52. lO. 35, 1961, 53. 4, 4~. 1791. 55, 5. 54. 40, 1868, 344 078 133 000 312 547 156 000 281 492 824 000 344 3O5 092 000 938 bO9 625 000 52.781 5,879 ~1,553 1727.000 3 4~ 1697 60 8 4~ 1753 .031 .479 .191 .0o0 ,500 .859 .926 .000 54.281 14.016 36,719 1947.000 53 2O 32 1926 47 6 56 1543 ,906 .125 .227 ,000 .375 ,484 .250 ,000 SP D'£ DRHO FCNb SP ORHO FCNb SP DT DRHO FCNb SP DT DRHO FCNb SP DRHO fC~b DT DR~O FCNb SP DT DRHO FC~b Se OT DRHO FC~D SP DT DRMO FCNb SP DT FCNb SP ORHO -41.938 122.375 0.002 ~91,000 -45,719 132.125 -0.002 572.500 -20.531 114,750 0,049 42q,500 -14,688 111,375 0,026 ~62.750 -29,719 121,563 0.005 447,750 -21,312 116,375 0,005 ~41.250 'b,402 i20,750 0.046 41~.500 -2~,312 130.750 0,014 390,250 -25.984 163.000 0,042 556.500 -40.281 193.]75 -0.006 568.50O -17.969 128,125 0,008 32!,250 IUD CALl GR IUD IUD CALl GR CALI GR CAUl GR GR CALl GR" OR CAn~ CALI GR IUD CAbI GR PAGE 10 10.828 ll.UgB 57.~3~ 11.148 11.969 56.18~ .. 5.211 12.133 59.~44 5.473 11.969 52,18~ 8 078 51,~69 6 727 59.813 4.652 14.102 58.500 9 266 12:094 53,405 13,63J 12.008 48.029 23 797 12~094 56.625 5.477 12.664 51.969 LVP uOg,H05 VERiFiCATION DEPT 3200.0G0 GR IbM 7.U3W SFLU RHO~ 2,102 NFH1 NRAT 4,043 NCNb DEPT 3100,000 GR IbM 8.b52 SFbU RHOS 1.~83 NPHI NRAT 4,090 NCNb DEPY 3000,uOV Ga IbM 9.719 Sf'bO RHO~ 2.02'1 NPHI NRAT 4.16B NCNb DEPT 290U.OOU GR R~OD 2,061 NPHI NRAT 3,66q NCNb 50,563 5.551 DF 49.365 1677.000 FC~L 58.594 SP 6,683 57 50.244 DRHO 1~12,000 FC~b 44,656 $P 10,398 UT 51.416 D~{~iO 1459,000 FCNL 55.~38 13,000 42,578 DRHO 1811.000 fChb DEPT 2~O0,UO0 GR 57. IbM ~' 7,047 SFLU 6, RhOb 2,10q NPHI 49. NRAT 4,051 NCNb 1698. DEPY 2'700,000 GR ILS 7,297 Sf'bU RHOm 2.111 NPHI NRA~~ 3.90~ NCNb 2b00,O00 GR ~EFT 14 391 F O bN , $ b RHO~ 2,12! NPHI NRAT 3,857 NCNb DEPT 2518,500 GR IbR -999,250 RHOD 1,793 NPHI NRAT 4,523 NCNb ,, 688 SP 164 DT 414 DRHO 000 FChb 48,156 SP 8,164 DT 46,82~ DRHO 1677,000 FCNb 49,469 8F 13,000 DT 45,947 DMMO 1687.000 FCNb *~ FILE TRAILER FILE NAME ;SERVIC.001 SERVICE NAME VERSION ~ DAT~ ; MAXIMUM L~NGTH : 1024 FILE TYPE : NEXT FILE NAME : -999,250 SP -999,250 OT 67,920 DRHO 1320.000 FCNb -i~.039 129.500 0.000 413,500 -10.523 124,188 -o.000 ~1'7.500 -14.086 126,750 0,055 342,750 -35.188 129,12b '-0,002 452,750 -14,07U 12~,500 0,026 414,750 -15,844 130,750 0.011' 389,500 -2s,~72 136,750 0.012 411'750 -999,250 -999,250 '-0.757 280.000 CALl IbP CADI I LD CAbI GR CALl I CAb~ GR I bD CALl GR ' CAbI GR PAG~ 11 7.09~ 12.133 52,875 9.203 12.V55 60.56~ 10,359 12,453 46.59~ 16.453 11.992 52,813 7.43~ 12.281 55.43~ 7,745 12,~80 54,625 15,500 12,20~ 48.18~ -999.250 3.211 35,719 LVP O09.HOb VERIFiCATIO~ Li~%ING ** TAPE TRAILER *~ 6ERVICE NA~:E :SERVIC DATE :81/12/15 O~IGIi'~ :1070 TAPE ~iAME ;62266 CONII~UA~IO[~ # :01 NEXT TAPE NAME : COMME~TS :~APE COMMENTS ** RE~b TRAILER *~ SERVICE NA~ :8ERVIC DATE :81/11/15 ORIGi~ : REEL NAME :REEL ID NEXT KErb NAME : COi~M~TS :REEL COMMENTS him TAPE VERiF'ICATI[,)N LISTING '[~-~6[ ~ 8 AON LVP ()09.H05 VERiFiCATiOI.,i LiSTiNG PAGE SERV1CF. NAM£ :8ER'VIC DATE; :0i/11/15 ORIGi~ :1070 TAPE ~i%i~'~E :62266 CONTI,N[]ATION ~ PREVIO[;$ YAFE : FILE NANE :SERVIC.O0! SERlV~CE NAM~ VERSION ~ DATE : MAXI{~UM LENGTH : 1024 FILE TYPE : PREVI[]U6 FILE MN'E,M CONIENT$ CN : UNION OIL COMPANY ~N : KDU 8 (44X-~) FN : KENAI GAS ' HANG; TOWN: 4N $~CT: 6 COUN; KENAI STAT: ALASKA CTRY: USA MNEM CONTENTS PRES: N~DIT4F UNIT TYPE CAT~ SIZ~ CODE 000 000 ()lB 065 000 000 014 065 000 000 010 065 000 000 003 06~ 000 000 002 065 000 000 001 065 000 000 006 065 000 000 006 065 000 000 004 065 TYPE CATE SiZE CODE 000 000 007 065 LVP 00~.~05 VhEIFiCATiOi',~ bISTING PAGE 2 RECORD TYP~ 047 ** jOB ~ 10707,62266 DIL RU,'; #2, LOGGED 27-OCT-81 BOTTUi~i LOG iNTERVAl, TOP LOG Ii~TERVAL CAS lNG BIT SIZE: TYPE ~{]LE FLUID DENSITY VI$COj!%Y FSUiD R~ ~ ~EA$, TEMF. RMF @ iq£A6. TEMP. RMC ~ i'~EASo TEMP. ' 10216 0 FT = 7282 FT. -- 9.62 IN . (~ 7282 FT. : 8.5 IN. : X'C POLL, M, ER = 82,0 : 9.4 : 5.0 C3 : 2 22o720 : I 720 O}iM~,~ La 65~0 D : 2 890 OH~/{P~ ~ 65,0 DF MATRIX ~Iiq'E6TONE LV? OOq. H05 V£RIFICATiON 6I$II~G PAGE JO~ ~' [0707,62265 DIL RU~ ~1, LUGGED 10-OCT-Si BOT'i'On bUG ~NTERVAL TOP LUG INTERVA~ CA$iNG-bOGG6R BIT SiZE TYPE ~C~E FLUID DENS£Y¥ PH FLUII') LLiSS RM ~ i<~AS. IEMP. RMF @ dEAS. TEMP. RMC (~ i~iEAS. TEMP. R~ ~ ~,~T 7300 FT. 2562 FT. 133184~h,, 12 ~, XC 79 6.0 5.2~ ~.73 (a ~19 F MATRIX SANDSTONE DATA FORN, AT AECORD ~ ENTE% BLOCKS TYPE SiZe: REPR CODE 8 4 73 E N'~ '~' 60 LVP 009.H05 VERiFiCATION ~LiSTi~.G PAGg ~ 9 4 65 0 i 66 DATO~q SPECIFICATION BLOCKS MNEa 2E~VIC~ SERVICE UNi~ API AP I0 ORDER ~ LOG TYP DEPT FY 0 GR 0I~ GAPi 7 3 SP OIL ~V 7 ILO 003 OH~M 0 Ib~ OIL O~Mi~ 7 SFLO 003 C!H~M 0 DT 003 dS/F 0 5 CALL FON IN 42 2 RMO~ 004 G/C3 0 NPHi 004 Pd 0 6 DRHU 004 G/C3 0 GR F'I')N GAPI 42 NRA~ OOt 0 NCNb 00~ 0 FCNL FDN 42 3 APl APl FiLE CLASS MOD 0 0 0 32 0 0 0 0 0 46 0 0 0 0 0 0 o 0 32 0 0 3 0 0 1 0 0 2 0 0 0 0 0 32 0 O 1 0 0 92 0 0 93 0 0 DEPT 10238,000 GA -999 IbFt ''999.250 SFLU -999 RHO~ 1,737 NPHY 65 NRAT 4,520 NCNb 1358 DEPT 10200,000 GR 83 IbM 11,039 8FbU 23 RHCtB 2.162 NRAT 3,~11 NCNL 2254 DEPT 10100.000 GR 51 ILM 8.14~ SFLU 6 RHO~ 2.~I2 NPHi 22 NRAT 2'295 NCNb $49~ DEPT 10000.000 GR 63 RHOB 2,484 NPHI 3i NRAI~ 2,904 NCNL 2940 DEPT 9~00,000 GA 62 I5~ 9,312 SFLU 9 RH[}~ 2,553 NFHI 27 NRAT 2,645 NCNb 3366 DEP~ 9~00,000 GR 70 ILM 6.781 SFLO 5 RHOb 2.54:9 NPHi 31 NRAT 2.973 NCN'b 2692 .250 .250 DT ,576 DRHO ,000 FCN'L .I88 SP .938 DT .193 DRHO .000 FCNb ,781 SP ~906 DT .607 DRHO ,000 FCNb .312 SP .602 ,641 DRMO ,000 FC~b .905 SP '688 DT ,393 DRHO ,000 PCNi'~ ..461 ,836 DRHO ,000 FCi~b .lin SiZ~ PROCESS SAMPLE LEVEL 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 4 0 '999,250 '999.250 -0,100 291,750 10,914 -0.023 566,000 30.500 78,750 0.000 1477.000 23,016 81,750 0,02~ ~57,000 1,969 72,375 0.012 1128,000 '0.031 76,000 0.037 ~8~,500 EPR ODE 68 68 68 68 68 68 68 68 68 CALI GR I bD CALl G~ CALI G~ CAbI CALl G~ ILD CALl G~ -999,250 8,500 85.250 10,844 .9,09~ 94,688 · 8.953 9,094 48.844 4.828 9.180 60,625 8.211 9,469 55,S4~ 7.~8S 9,859 53,688 LVP 009.HO5 VERIFICATION LISTING PAGE 5 DEPT 9'700.000 GR 69, IL~ 9.023 SFLO lg, R,OB 2.549 NPHI 31. NRAT 2,918 NCi~u 2802, DEFT 9600.000 GR 63, ILM 8.461 SFI, U RHOf~ 2.D47 NPHi 29. NRAT 2.787 NCNL 2572. DEPT 9500.000 Ga 53. Iblq 10.039 SFLU RHO~ 2.482 NPSI 21. NRA~ 2.342 NCNb 3306. D£PY 9400,000 G~ 77. ILM 10,93~ SFLU 12, RHOB 2,496 NP~ii 25, NRAT 2.55~ NCNi~ 2755~ DEPT 9300.000 GR 29. ILB 6.992 SFLU ~. RHO3 2.377 NPH~ 22. NRA'~ 2,39~ NCNb 361~. DEFT 9200,000 GR 39. IbM 18.~44 SFLU 7i' RHG~ 1,520 NP~'{I 60. NRAT 4,723 NCNb 1784. DEPT 9100,000 GR 5~. IbM 6,207 SF,[,~O RHO~i 2,49~ NP~I 32' NRAY 3.082 ~CNh 2544, DEFT 9000,OOU G~ 56. Ib}~ 11.742 8FLU' I6. R~OD 2,635 N'P,fll 23. NRAT 2.48~ NCNL 2708. DEPT 8900,000 Ga 49, IbM 1.930 RHO~ 2,47'1 NPHi. 24, NRAT 2.566 NCNi~ 3348. DgFT 8~00,~00 GR 47, IbM 7.47'7 SFLO RMU~, 2,'~2U NP~{i 2~, NRAI' 2,852 NCtq~.,,, 2772. DEFi' 8?00,000 GS 65, Ibi.:~ 6.i6~ SFLU 5, RHOB 2'467 NPHi 34. NRA~ 3,248 NCN£, 2532. 250 906 ~3~ 000 094 375 00 a 000 125 281 973 000 688 148 879 000 781 590 119 0 O0 344 438 205 000 281 992 08O 000 188 096 000 938 629 121 000 594 133 320 000 000 273 863 000 Sp ORHO SP DT DRHG FCNb DT SP DT DRHO FCN~ SP DT DRHO FCN,b 8P DT FCNL DRHO FCNL 8P DT SF SP FCN~ SP DT FCNL 19.000 77.1~8 0.013 931.500 14.469 77.188 0.018 953,500 -9.531 0,086 1292.000 3,967 78.i88 0,01~ 1077,000 -21.031 82,75O 0,008 1461.000 -12.023 116.375 '-0. 042 369,000 -3,531 84,375 0,000 ~20.500 65,188 0,088 1084.000 3.467 83,000 0,045 131!.000 -6.039 89,563 949.000 -12.531 89.375 0.026 735.000 GR CALI CAL~ G~ CALI CALI GR CAhl CA L I G~ CAb I G~ CAbI 9.398 9.180 8,266 9.898 57.OOO 10.~69 10.172 45.750 12.391 9.539 75.025 6.789 10.828 29.484 ,70~ 39.938 6.137 11.570 58..1;56 I,992 '867 50.03i 7,996 12"219 41.438 7.602 12'305 39,375 6.180 12.500 60.594 LVP 009.HO5 VERIFiCATiOI~ PAGE DEPT 8600.000 GR NRAT 3.268 NCNi~ DEPi 8500,000 Ibi.~ 5,~91 D[PT ~400,000 GR IbM 32.750 SFGU RHOB 1, ~i62 NPHI NRAT 5,461 NCNb DEPT 8300,000 GR I L ~'~'~ ~, 809 RHOB 2,510 NPHI NRAY 3,143 NCNb DEP~f 8200.000 GR ILH 19. 266 RHO~:~ 1. 708 NPHI NRAT ~,92~ NCN~ DEPT 8100,000 Ih~ 8,511 SFLU RHD,6 2.471 NPHi DEPT 8000,000 GR Ibi'4 8,75~ SFLU RMO~ 2.~7 NPH~ ,NRA T ~. 3 DEPT 7800,000 I L M ~ 0.320 RHO:~ 2.3!4 NPH, i NRAT 3. 186 DEPT 7'700,000 GR NRAT 4,914 NCNb OgPT 7~00.000 GR I 6/'4 12.48 ~ $ R M O,~:~ I. ~80 57.625 3.426 3~.766 247~.000 63,500 5,520 30.572 2420,000 22.188 569.500 73.B77 145b.000 57.250 6.395 32.861 2654,000 27,938 18.438 65,~74 1480.000 59,469 7,777 2~,639 257 '000 62,750 6.508 33'936 2330,000 5g.531 $,383 30,420 271~,000 49,781 10'047 33,203 2956.000 37,~69 38.344 63,379 1440,000 47,688 129,625 73,730 SP DT DRHO FCNL DRHO FC~D SP DT DRHO FC~b DY DRHO FCNb DT DRHO FCN~ ORMO FCmb SP DT DRHO FCN/, SP DRHO SP DT DRHO DT DRHO 3.969 91,188 0.013 0.468 ~9,188 0,068 728.000 -37,531 130.000 -0.041 269,750 -15.039 S9,750 0.070 ~62,500 -34,531 115,563 0,002 306.000 '9,500 86,188 0.031 879,~00 -17.000 84,563 0,033 754.000 '21,531 88.188 0.017 ~73,500 -14,531 101,000 0.005 983.000 -22.000 10~,750 -0.042 26~,000 -35,063 10~.'750 -0.05~ CALI GR IbP CALI I LD CAL£ I L 0 CALl G~ I LD CALI I CALl GR CALI GR I GR CAbI GR CALI GR CALI GR 3.932 13.445 59.000 5,727 11,~85 59,969 33,18~ 14.297 22,141 6,922 12.~41 11.203 33,156 ~,727 ~3.367 54'000 8,570 13,500 50,281 13,508 54,250 ~2,250 47,000 14,109 15,66~ 15.I72 15.523 15.78i 40.531 DEP'i' 7500, OOO GR I D~'.l 8,984 RRt3~ 2.402 NP,~I NRAT 2.b77 D~Py 7~O0.OOO GR IDM 9.492 SFLU RHO~ 2, ~67 NPHI NRA'f 2 . ~67 DEPT 7300,000 GR IL~q ' 16,219 8FLU RHUE~ 2.523 NPHi NRAT 2.613 DEP~' 7200.000 IbM 22, i09 8FLU RHOB 2,502 NRAT 2,771 NC,Nh DEPT 7100,000 GR IbM 14,617 8FL RHOS 2,301 NPHI NRA'I' 3,92~ DEPT 7000.OOO GR IbM 22. 203 SFLU NRAT 2,85~ NCNG DEPT 6900.000 ILM 13'898 SFLO RHOB 2,537 NPHI NRAT 3.09~ N'CN& .... DEPT 6~00,00O GR I~.M .... 22,922 SFL0' RHOb 2,57e NPHi NRAT I ' 903 NCNL. DEP'~7 6700,000 GR IbM ~'15,023 RHO,~ I, 792 NPHi NRAT 4,922 NCNL DEPT ~00,000 GR ILM '16,828 SFLU RHO~ 2, ~2q NRA'I' 3,355 NCNb DEPT 6500. 000 GR IL~v~ 13,367 i873.000 48.375 8.600 28.223 2852.000 62,900 9.633 2'7.490 2852.000 64.000 24.312 25,977 2299.000 67,188 30.766 27,05i 2484,000 80.188 14,477 7,070 22 6,000 65.750 26,828 28.076 262b.000 68.500 12.344 I 641 54,344 105,000 335 ,000 61.688 16,375 64'502 2043.000 59,625 15,734 36 279 2356~000 68,625 9:.563 285.750 -30.531 8~.750 0.u21 95~.500 -40.531 90.000 0.020 925.000 -1~.531 7~.188 0.067 856,500 -24.641 86.750 0,039 862,000 '17,203 91,375 0.022 555.500 -40.906 90,188 0,037 875.500 '24,625 85 188 0~038 '150,000 '35.281 56.781 0.064 1733.000 '35.219 95.188 '0,021 37~.500 -61,000 ~7,750 0.0~6 026.50{) -51.750 91,750 PAGE 9.320 13,539 46.813 15.039 59.844 15.750 16.844 55,563 21.51~ 12.492 72,525 14.859 12,500 78.438 18.578 12,96~ 70,750 12.789 1~,I48 7 .81~ . 2,328 ~2.844 58,031 16,906 13,563 52,719 15,648 13.609 70,875 13.680 13.898 RHOt% 2.461 NPHi NaAT 3.510 NCNB DEPT ~%00.000 GR IbM '15.9~4 SFbO R~U6 2.529 NRAT 2.996 NCNb DEPT 6300.00U GR Ib~ 14.Z8~ SFLU RHOb 2,467 NR&'£ 3.004 NCNB DEPT 6200.000 GR IbM 32.844 RhOb 2,490 NP~i NRAT 3,088 NCNb DEPT 6100.000 Ib~ 9.90~ SFLU RHO~ 2.514 NPHI NRAT 3.338 NCNb DEPT OOOO.O00 GR Ib~ 13,109 SFLU RaGS 2,531 NPH~ NRAT 2,879 NCNb DEPY 5900,000 GR Ibi~1 "13.961 RHO~ 2,375 NPHI NRAT 3.477 NCN4 D~P'T 5800.000 GR IbM "36.625 RHO5 2.65~ NPHI NRA.~ 3.098 NCN~ DEPT' 5700,000 GR Iba '11.219 RHO~ 2.330 NPHI NRAT ~.510 NCN~ DEPT 5600,000 G~ IL~l 6.242 RHO~ 2,375 NRAT 3.598 DEPT 5500.000 GR Ib~ 8,125 R~tO~ 2.420 NPHi NRAT 3.217 NCi~ib DEPT 5QO0.o00 GR 38.916 2222.000 69.250 12.547 29.932 2352.000 70.063 14.o1'7 30.127 2108.000 53.312 27.~59 31.836 2616.000 48.094 0,2~1 35.742 1876.000 59.594 26.234 28.076 182~,000 56.594 1'7,28i 38,428 1790.000 57.563 56,000 31.396 1721,000 54.406 10,547 39.795 2000.0O0 6.063 41,260 1733.000 52,500 7.504 34.27'7 1975.000 60.656 DRHU SP DRHO SP DT DRHO FCNh SP DT DRMO f'CNL SP DRBO CCN.h DRRO FCN4 DT DRHO FCNb DRH'O FC~5 OT DRHO FCNL OT FCN& S~ DT FCNh SP o.013 581.500 -55.813 86.000 0.034 776.000 '43.281 88,375 0.027 ~64.500 -69,750 77,563 0,023 795.500 -26,453 92.750 0.065 567,500 -25,547 83,563 0,030 646.000 -41.688 93,750 0,008 472,500 '39.094 64,188 0,251 557,000 -37.938 97,000 0.011 556,000 -19.750 103.188 0,056 445'750 -26.531 95,000 -0.004 597.500 -38.031 GR CALl CALI GR ILD CAL~ GR CALl I bD CALI ILD CALI GR GR Ca h I C A L i PAGg 66.125 15,039 13.S36 67.063 13.844 13.~33 68.688 26,875 12.477 53.7~ 10.883 14.078 57,938 I1,57~ 14,070 57.312 12,172 13.b3~ 65'312 23.484 13.984 54,156 10.789 12.063 58,563 6.355 12,281 61'656 7.914 12.523 50.594 12,578 LVP OOg,Hu5 VERIFICATIO:~ LIS~'ING ILFi ! 3.,61 SP'bU RHO~ 2.34q NPHi NRAi' ~. 75~ NCNI. DEPT 5300.0o0 GR ILM 11.~91 SFBU RHOB 2.36~ m~PHI NRAT 3. 533 NCi~L DEPT 5200.000 Gfl RHO~ 2.307 NPHI NRAT 3. 577 NC~h D~PY 5100.000 G~ I L~',l 26.375 SFLU RH06 2,375 NPHI NRAT 3.119 NCNL DEPT 5000,000 GR Iblq i0.328 SFLU RHOS 2,070 NPH~ DEP? 4900. 000 GR ILM "11,242 SFLU RHOa 2.350 NPHi NRAT 3,541 NCNi~ DEP'T 4800,000 GR IL~ 9,609 SFGU RHO~ 2. 342 NPHi NRAT 3.~89 NCNn DEPT 4700.000 GR RHO,S 2. ~77 NPH~ NRAT 3,3I~ ~q C N',h DEPT 4600,000 GR ILM 7.961 SFLU R H[3.S. 2' i76 NPHI NRAT 3,27'1 NCNb D~PT '4500.000 G,R Ihb'~ 20,891 SF'bJ RHOS 2' I41 NPHi N~AT 2. ~ 10 NCNL DEPT 4400. OOu GR ILM ~ 18,250 SFLU RH.O~> 2' 3'75 NPHI NRAT 3.16B NCNL~ 11.516 19ui.o0o 56.063 12.938 40.i37 ~0.65~ 12.719 37.354 1723.000 6i.813 27.719 32,471 2082,000 q~.063 12.117 54.688 1573.000 55,500 16,063 40.283 1734.0()0 62.375 10,766 42.969 1857'000 62.469 10.820 36'230 19~0,000 54.031 ~.50~ 35.59~ 2017.000 50.938 i'7.969 29.346 2062,000 49.3q% 21.766 33,203 206~.000 DT FCmb DRHO FCm~ D k H O FCNL SP OT DRHO DT DRHO FCmb SP OT DRHO FCNL SP DRMO FCNb DT DRHO ORHO FCNb D~ FCNb 87.188 -u.006 477,750 -37.68~ 98.750 0.009 479.';50 -55.~06 i03.000 0.023 501.250 -61.094 100.000 0.032 644,000 -27,688 114.000 0.069 332,000 '41,188 101,000 0.014 506,750 '44.125 99.000 0,019 468,250 -40.656 99,375 0,039 556.500 '36,781 122~563 0.01.7 566,000 -45,063 131.000 0,006 648.000 -38.~44 91.563 0,020 618,500 C~ ~ I GH I CALl GR CAGI Gl,{ I hD CALl GR I b, 9 CALl GR I bO GR CALI GR CAI, I G~ CAbI CAbI GR 9 ,,, ~ , C~,~,,,, i PAGE 12,085 69.56,J 11.148 12.258 58.15~ 10,~56 12.063 67.93~ 23.8i3 11.992 54.375 10,227 i2.305 51.563 10,836 12,227 55,469 12,094 62.813 9.141 12,055 62.78I 8,242 12,063 49.156 21,391 11.969 47,719 14,648 12,039 43.406 DEFT 4300. 000 GR IL~i "11.'703 RHOL~ 2.17b NPH1 NRA'i' 3. 303 DEFT 4200.000 GR ILa li.750 SF50 NRAT 3.~50 NCNb DEFY 4100.000 GR ILM 4.96~ SFLO RHOS 2.229 NPHi NRAT 9.793 NCNb DEFY 4000.000 GR RHO~ 1.970 NFMi NRA? 3.74~ ~CNb DEFT 3900.000 GR ILM 7.891 SFGU RHO~ 2.123 NPHI N~A? 3.557 NC~h DEFY 3~00.000 GR R~ 2,186 aPal NRAT 3,613 NCNb DEPT 3700.000 GR ~LM q.312 SFbO NR~T 3,920 NC~ D£PT 3500.U00 G~ Ib~ 14.047 SFb{J RMOB 2,115 NPHi NRAT 3,338 NCnb DEFT 3300.000 GR Ib)~i 5.070 SFLO RH05 1,96~ NPHI N~AT 4,441 NCnb 5~ iO 36 2000 .34 .07 .13 .00 52.31 10.54 35.15 1961.00 53. 4. 44. 1791. 55. 5. O,~. 1967. 54. 6. 40. 1868. 52, 5. 41. 1727, 58, 3. 4~, 1697, 60, 8. 175~. 36. 1947. 32. 1926.. 47. 28 49 O0 34, 30 09 O0 93 6O 62 O0 55 00 03 47 19 O0 50 85 92 00 28 01 '? 1 O0 90 12 22 O0 37 48 25 00 SP DT ORHO FC~b SP D~' DRHO SP OT DRHO SP DT FCNL SP DRHO DT F C iq .[~ SP DT FCNL SP DT DR~O FCN'h DT DT F C i~ ,h DT DRHO f' C a~ g -41.938 122.375 0,002 591.000 -45.719 132.125 -0.002 572.500 -20,531 114.750 0.049 42~,500 -14,688 111.~75 0.026 462.750 121,563 0.005 447.750 -21,312 116.375 6.005 4ql.250 -6.402 120.750 0.046 q16.500 -2~.312 13(),750 0,014 390.250 -25.984 163,000 0.042 ~56.500 -40,281 193,375 '0,006 568.500 -17,969 128,125 0,008 321,250 ILO CALl GR ILD CALl GR i bD CAhI GR CALl G~ CALi G~ I bD CALl GR CALl GB I LD CALl i h D GR I L, D I gl3 GR PAGE 10.828 11.898 5'7,438 11.148 11.969 56.188 5.211 12.133 59.84R 5 473 111969 52.188 ,. 8,078 51.469 ~.727 i2,234 59.813 4.652 14,i02 58,500 9.265 12,094 53.400 13.633 12.00~ 48.625 23.797 12,09~ 56.625 5.47'7 12.664 51,969 10 DgPT 3200,000 GA I5~ 7.039 RH06 2.102 NPH~ NRA'I ~.043 NC.~L DEP'I 3~00.000 GK IbM 8.~52 SFbU RHOS 1.983 NPHi NRAT 4.090 ~C~ DEPT 3000,000 IbM 9,719 SFLU RHO~ 2.027 NRAT ~,168 NCNL DEPT 2900.000 GR I&i4 '16.125 RB08 2.06i NPHI NRAT 3,66~ ~CNL DEP? 2~00,000 ILM 7'047 RHI]S 2,10~ NP~I NRAT 4.051 NCNL DEPT 2700,000 I~a 7,297 RHOB 2.1~I NPHI NRAT 3,904 NCNL DEPT 2600.000 ILM 14,391 RHO~ 2,121 N'PHi NRAT 3.857 NCNL D~P'ii~ 2518,500 GR I~M "99~,250 SF.b'O' RMO~ 1.793 NPMt NRAT 4.523 NCNb ** FI]bE' TRAILER FILE SERVICE NA~E : DATE : M,AXJ~F;U~v, LENGT~ : 1024 FILE N~XT 5.551 DT 49.365 ORHO le77,000 FCNL 56.59& SP ~,883 DT 50.24~ DRMO 1812.000 FCNb 44.656 10.396 DT 1459.000 FCNb 55.438 BP 13.000 DY 42.578 DRHO 1811,000 ~CNL 57.68~ BP 6.16~ DT 49,41~ DRHO 1698,000 FCNL 48.156 SP 6.164 46,.826 DR, HO 1577,000' FCNL ~9.~69 13,000 45.947 DRHO 1687.000 FCML -999.250 SP -999,250 PT 67,920 DRi~[} 1320,000 FC~b EOF ********~* -14.039 ISD i29,500 CA)~I 0.000 Gk q13,500 -10.523 124,18~ CALl -0.000 417,500 -14.u86 12~.750 CALl 0.055 Ga 342.750 -35.188 129,125 CALl -0.002 ~52.750 -14.078 128,500 CALI 0.026 GM ~1~.'750 -15.844 130,750 CALl 0.011 GR. 389,500 -28,172 138,'/50 CALl 0,012 G~ 411,'750 '999.250, ILl") -999,250 CAbI '-0,757 Ga 280.000 7.098 12,133 52.~75 9,203 12.055 ~0.563 10,359 12.~53 4b,b9% 16.453 11.992 52.813 7.438 12.28I 7.74b 12.~80 5~,625 15,500 12,203 -999.250 35.719 ORiGi:'., :1070 TAPE ~ A ~ ~ :62266 NEXi ~i'APE NAM~ ; COM~cEhT6 :~APE C[]MMEN~'S ** kEEL. TF~,AiLER ** SER V IC~3 N A!,~£ :SERVIC DAT~] :61/i1/15 REEL ~%~.~E :REEl., ~D CO[,~'J~i'i~DATiON ~ :01 PAGE 12