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198-002
1. 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 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 16,720 feet See schematic feet true vertical 12,943 feet N/A feet Effective Depth measured 3,450 feet See schematic feet true vertical 3,266 feet See schematic feet Perforation depth Measured depth See schematic feet True Vertical depth See schematic feet Tubing (size, grade, measured and true vertical depth) N/A Packers and SSSV (type, measured and true vertical depth) See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:N/A 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: 8,850psi 3,060psi 5,380psi 10,900psi 3,760 3,515 Burst Collapse 1,500psi 2,670psi measured TVD Production Liner 10,377 6,576 Casing Structural 8,841 5" 10,377 16,650 12,896 2,579 3,760 2,579Conductor Surface Intermediate 30" 20" 13-3/8" 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 198-002 50-883-20093-01-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0017589 North Cook Inlet / Tertiary System Gas & Undefined WSDP N Cook Inlet Unit B-01A Plugs Junk measured Length 407 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 407 N/A 18 Size 407 2,511 0170 0 00 0 N/A Sr Pet Eng: 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. Casey Morse Casey.Morse@hilcorp.com 907 777-8322Operations Manager 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 7:42 am, Apr 24, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.04.23 12:26:01 - 08'00' Dan Marlowe (1267) DSR-4/29/24 RBDMS JSB 043024 Suspended Well Inspection Data Well: NCIU B-01A Surface Location: NWNW, Sec 6, T11N, R9W, SM, AK Permit to Drill: 198-002 API: 50-883-20093-01-00 AOGCC Inspection Date: 04/19/2024 AOGCC Inspector: Sean Sullivan Size Pressure (psi) Tubing A 2-3/8 0 Tubing B 2-3/8 0 Casing 9-5/8 17 OA 13-3/8 42 OOA 20 0 *Note: Wellhead pressures to be recorded monthly at minimum. Other Notes: x Condition of Wellhead: Good x Condition of Surrounding Surface Location: Good x Follow Up Actions needed: N/A x Currently, all perforations are isolated with cement and the tubing strings are cement to surface in the “A” string and to 255’ (~80’ below the mudline) in the “B” string. Both tubing strings are run inside the 13-3/8” x 20” annulus. This well is currently being evaluated as a future sidetrack candidate. Attachments: x Current Well Schematic x Picture(s) x Plat - 1/4mile radius of wellbore Picture – Well Sign Picture – IA Pressure Gauge Picture – OA Pressure Gauge Wellhead Looking North Wellhead Looking East Wellhead Looking South Wellhead Looking West Inside Cellar N/A Plat – Quarter-mile Buffer Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ InspectNo:susSTS240421083805 Well Pressures (psi): Date Inspected:4/16/2024 Inspector:Sully Sullivan If Verified, How?LAT / LONG Suspension Date:4/24/2023 Tubing:0 IA:43 OA:17 Operator:Hilcorp Alaska, LLC Operator Rep:Ben Quesnel Date AOGCC Notified:4/12/2024 Type of Inspection:Initial Well Name:N COOK INLET UNIT B-01A Permit Number:1980020 Wellhead Condition B-01A is located within Leg Room #1. Dry hole tree is very clean, marked appropriately and had no signs of corrosion or leakage. Surrounding Surface Condition Very well kept with no signs of leaks. Condition of Cellar Clean with no signs of leakage Comments Two 2-3/8" cuttings disposal strings in 20" x 13-3/8" annulus clamped to 13-3/8" casing. Both perfed with 13-3/8" and 9- 5/8" (3440 to 3500 ft MD) and cemented when 20" x 13-3/8" annulus cemented. Tubing "A" cement to surface; Tubing "B" cement top at 255 ft (80 ft below the mudline). Dryhole tree installed and tested at the end of RWO. Well intended for future sidetrack. Supervisor Comments Attachments - Photo; Well schematic Suspension Approval:Completion Report Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Monday, June 10, 2024 JBR; 6/10/2024 NCIU B-01A (PTD 1980020) – Suspended Inspection 4/16/2024 Page 1 of 2 Suspended Well – NCIU B-01A (PTD 2980020) Photos by AOGCC Inspector S. Sullivan 4/16/2024 NCIU B-01A (PTD 1980020) – Suspended Inspection 4/16/2024 Page 2 of 2 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: _0 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: N/A BF: N/A Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 130 (ft MSL) 22.Logs Obtained: CBL (4/24/23) 23. BOTTOM 30" H-40 407 20" K-55 2,511 13-3/8" N-80 3,515 9-5/8" P-110 8,841 5" S-135 12,896 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 North Cook Inlet / Tert. Sys Gas & Undef WDSP N/A Oil-Bbl: Water-Bbl: Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing N/A N/A Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 72 10,377 Surf Surf 133 407 Surf 3,760 SIZE DEPTH SET (MD) N/A PACKER SET (MD/TVD) 10,07419.5 Surf 53.5 Surf Surf 2,579Surf Surf CASING WT. PER FT.GRADE 4/2/1998 CEMENTING RECORD N/A N/A SETTING DEPTH TVD 2580008.4843 TOP HOLE SIZE AMOUNT PULLED N/A 329895.2607 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 50-883-20093-01-00 N Cook Inlet Unit B-01A ADL0017589 1249' FNL, 981' FWL, Sec 6, T11N, R9W, SM, AK N/A 2/12/1998 16,720 / 12,943 3,450 / 3,266 132 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 332000.5215 2586731.2783 N/A 2558' FSL, 1026' FEL, Sec 12, T11N, R10W, SM, AK STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 4/24/2023 198-002 / 323-164 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, TUBING RECORD 16,650 8,598 N/AN/A Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Grace Christianson at 11:58 am, Jun 29, 2023 Suspended 4/24/2023 JSB RBDMS JSB 062923 xGDSR-7/19/23BJM 8/14/24 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A N/A N/A Top of Productive Interval N/A N/A N/A N/A 31. List of Attachments: Wellbore schematic, Well operations summary 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Ryan Rupert Digital Signature with Date:Contact Email:Ryan.Rupert@hilcorp.com Contact Phone: (907) 777-8503 Operations Manager 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: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. INSTRUCTIONS Formation Name at TD: 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. Authorized Title: Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Authorized Name and 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 Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2023.06.29 11:25:35 - 08'00' Dan Marlowe (1267) _____________________________________________________________________________________ Updated By: JLL 06/23/23 SCHEMATIC North Cook Inlet Unit Well: NCI B-01A PTD: 198-002 API: 50-883-20093-01 OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 1690sxs of 12ppg lead followed by 700sxs of 15.8ppg tail cement.Saw cement to surface. 13-3/8"18-1/2” hole: 115bbls of 12ppg lead cement returned to surface.9/4/97 cement log acquired 9-5/8" 12-1/4" hole: Pumped 822bbls 12.5ppg lead cement followed by 144bbls of 15.8ppg tail cement. Lost circulation after 500bbls lead pumped, never did regain. Circ’d 50bbls cement/mud mix from top of 9-5/8” liner. 9/7/97. 11/25/03 USIT log shows ToC at 3775’ MDPBTD: 9,610’ TD: 16,720’ 4 30” RKB: 53.6’, RKB to MSL: 132’, RKB to Mudline: 232’ 5” 5 6a/b 7 8 9 10 11 12 13 13-3/8” 9-5/8” 1 ToC at 2230’ (CBL 4/24/23) 14 15 16 17 20” 2-3/8”8” 18 20 21 Tag TOC in tubing @ 9,610’ Calc. TOC in tubing x 9-5/8” @9,837’ XN X X X 19 CASING DETAIL Size Wt Grade Conn ID Top Btm 30” H-40 Weld 27.000 Surf 407’ 20” 133# K-55 BTC 18.730” Surf 2,579’ 13-3/8” 72# N-80 12.347” Surf 3,760’ 9-5/8” Tie-Back 53.5 P-110 BTC 8.535” Surf 3,588’ 9-5/8” 53.5 P-110 BTC 8.535’ 3,588’ 10,377’ 5” 19.5 S-135 4.5” IF 4.408“/3.25” 10,074’ 16,650’ TUBING DETAIL 5-1/2” 15.5 L-80 BTC-Mod 4.950” 3,504’ 3,764’ 5-1/2” Combo Screens & Blanks 15.5 SLHT 4.950” 3,797 5,547’ 4-1/2” 12.6 IBT 3.958” 5,547 5,647’ 4” Combo Screens & Blanks 9.5 SLHT 3.548” 5,647 6,805’ 3-1/2” 9.3 L-80 IBT 2.992” 6,805 6,867’ 2” Coil Inner String ~2.51 HS-90-C BHISG 1.750” 3,567’ 6,817’ 4-1/2” 12.75 P-110 3.958” 8,052’ ±10,074’ Cuttings Disposal Tubing (2 strings) Dual 2-3/8” clamped to outside 13-3/8” A String:Cement to Surface B String:Cement to 255’ (~80’ below mudline). Will need cement top off for final P&A 4.7 N-80 CS Hydril 1.995” Surf 3,663’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 3,475’ 3,309’ 9-5/8” CIBP with 25’ cement dump bailed on top (Est. ToC = 3,450’) 4 3,591’ 3,411’ >8.535” 9-5/8” x 13-3/8” Liner Top Packer 5 3,602’ 3,389’ 4.653” 7.962” GLM #3 – Camco MMG w/ 5/16” orifice valve 6a 3,700’ 3,467’ 4.562” X-Nipple 6b 3,764’ 3,518’ 6.000” 8.313” Baker SC-1R Packer, PBR, seals, MOE, seal bore & gravel pack sleeve 7 3,797’ 3,544’ 5.000” 7.650” Model C KOIV (Knock Out Isolation Valve) 3,800’ 3,547’ 4.950” 6.110” 5-1/2” 15.5# SLHT blanks & Screens (140 x 0.012ga.) 8 4,368’ 4,010’ 4.940” 8.125” Baker SC-1L Packer, seal bore & gravel pack sleeve 4,421’ 4,053’ 4.940” 8.125” 5-1/2” 15.5# SLHT blanks & Screens (140 x 0.012ga.) 9 4,969’ 4,495’ 6.000” 8.281” Baker SC-1R Sump Packer & MOE 4,985’ 4,508’ 4.892” 6.050” 5-1/2” 15.5# L-80 SLHT Blank 10 5,547’ 4,962’ 3.958” 6.060” Crossover 5-1/2” SLHT x 4-1/2” IBT 11 5,579’ 4,988’ 3.813” 5.230” X-Nipple 12 5,613’ 5,015’ 4.750” 8.329” Baker SC-2 Packer, S-22 Snap Latch, seal bore, & gravel pack sleeve 13 5,647’ 5,042’ 3.500” 5.650” Model C KOIV (Knock Out Isolation Valve) 5,650’ 5,044’ 3.548” 4.590” 4” SLHT Screen & Blanks (12 ga.) 14 6,787’ 5,960’ 6.000” 8.280” Baker SC-1R Sump Packer, S-22 Snap Latch, MOE 15 6,805’ 5,975’ 2.992” 6.050” Crossover 5-1/2” x 3-1/2” 16 6,836’ 6,000’ 2.813” 4.250” X-Nipple 17 6,867’ 6,026’ 2.992” 4.250” WLEG 18 8,052’ 6,984’ Fish – Cut top of 4-1/2” tubing 19 10,032’ 8,564’ Sliding Sleeve – PXN Plug @ 10,042 20 10,074’ 8,598’ Packer 21 10,376’ 8,840’ XN Nipple w/ PXN Plug in Nipple _____________________________________________________________________________________ Updated By: JLL 06/23/23 SCHEMATIC North Cook Inlet Unit Well: NCI B-01A PTD: 198-002 API: 50-883-20093-01 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Disposal 3,500' 3,540' 3,307' 3,339' 40' 9/9/1997 Isolated 4/23/23 3,850' 3,869' 3,587' 3,602' 19' 12/8/2003 Isolated 4/23/23 3,886' 3,893' 3,616' 3,621'7'12/8/2003 Isolated 4/23/23 CI 1 4,185' 4,268' 3,859' 3,928'83'12/8/2003 Isolated 4/23/23 CI 2 4,275' 4,365' 3,933' 4,007'90'12/8/2003 Isolated 4/23/23 CI 4 4,429' 4,480' 4,060' 4,101'51'12/8/2003 Isolated 4/23/23 CI 8 4,751' 4,761' 4,319' 4,327'10'12/8/2003 Isolated 4/23/23 CI 8 4,792' 4,803' 4,352' 4,361'11'12/8/2003 Isolated 4/23/23 CI 11 4,922' 4,955' 4,457' 4,484'33'12/8/2003 Isolated 4/23/23 BELG-F 5,718' 5,742' 5,098' 5,118'24'12/1/2003 Isolated 4/23/23 BELG-G 5,885' 5,892' 5,234' 5,239'7'12/1/2003 Isolated 4/23/23 BELG-H 5,929' 5,939' 5,269' 5,278'10'12/1/2003 Isolated 4/23/23 BELG-H 5,948' 5,969' 5,285' 5,302'21'12/1/2003 Isolated 4/23/23 BELG-H 5,995' 6,032' 5,323' 5,353'37'12/1/2003 Isolated 4/23/23 BELG-I 6,078' 6,091' 5,390' 5,400'13'12/1/2003 Isolated 4/23/23 6,097' 6,107' 5,405' 5,413'10'12/1/2003 Isolated 4/23/23 BELG-I 6,118' 6,124' 5,422' 5,427'6'12/1/2003 Isolated 4/23/23 BELG-I 6,148' 6,158' 5,446' 5,454'10'12/1/2003 Isolated 4/23/23 BELG-I 6,169' 6,182' 5,463' 5,473'13'12/1/2003 Isolated 4/23/23 BELG-J 6,283' 6,290' 5,553' 5,559'7'12/1/2003 Isolated 4/23/23 BELG-L 6,375' 6,390' 5,627' 5,639'15'12/1/2003 Isolated 4/23/23 BELG-M 6,610' 6,622' 5,815' 5,825'12'12/1/2003 Isolated 4/23/23 BELG-O 6,762' 6,767' 5,939' 5,943'5'12/1/2003 Isolated 4/23/23 9,970' 9,972' 8,514' 8,515'2'Isolated Oil Exploration 16,080' 16,118' 12,525' 12,548'38'Isolated INNER STRING JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item Fish: 04/20/21 - UDGL Widepack Upper Packer pulled & fell to 3,588’ RKB 3,575’ 3,367’ 3.000” 4.500” Weatherford 450 Widepack Upper Packer 3,581’ 3,372’ 2.992” 3-1/2” Pup Joint 3,586’ 3,376’ 3.000” 3-7/8” Pup Joints 3,606’ 3,392’ N/A 4.420” Centralift AVE Sub w/ Dual Flapper Check Valve 3,606’ 3,392’ 2.875” 4.470” WP Anchor Seal Latch 3,609’ 3,394’ 0.875” 1.750” Stinger Rod w/ seal stack (6.90’) stung into PBR Seal Bore 3,610’ 3,395’ 3.000” 4.500” Weatherford 450 Widepack Lower Packer 3,616’ 3,400’ 3.476” 4.420” Slotted Sub 3,617’ 3,401’ 1.750” 4.420” PBR Seal Bore 3,619’ 3,402’ 1.375” 4.420” Torq-Thru Quick Connect - Upper 3,620’ 3,403’ 1.375” 2.875” Torq-Thru Quick Connect - Lower 3,620’ 3,403’ 3.000” 4.313” Tryton Max Frac Plug 6,049’ 5,367’ 1.375” 2.875” External Grapple Coil Connector 6,050’ 5,367’ 2.000” 2.600” PM-1 Gas Lift Mandrel 6,052’ 5,369’ 1.375” 2.875” Torq-Thru Quick Connect 6,817’ 5,984’ 1.750” 2.000” CT Dimple Connector 6,817’ 5,984’ 0.930” 2.375” injection sub 6,819’ 5,986’ bottom of injection string Rig Start Date End Date N/A 4/9/23 6/7/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/09/23 - Sunday Arrive platform. Orientation. Open PTW & PJSM w/ ops. Rig up to disposal string A w/ produced water pump w/ 1/2" hose (Disposal A - 0 psi, Disposal B - 0 psi, OA - 0 psi), pump 4 bbls produced water, pop off on pump @ 900 psi WHP. Move to disposal string B, pump pop off @ 1700 psi. Rig up to disposal string A w/ 1 1/2" hose, (Disposal A - 0 psi, Disposal B - 0 psi, OA 0 psi), pump 10 bbls of produced water (14 bbls total) @ ~1 bpm. Ending pressures, Disposal A = 1450 psi, Disposal B = 0 psi, OA = 1450 psi). Disposal string A and OA tracked, no communication to disposal B. Rig up to disposal string B w/ triplex pump (1/2" hose). Starting pressures, Disposal A = 50 psi, Disposal B = 0 psi, OA = 50 psi. Pump 14 bbls of produced water in 1 bbl increments (shut down to fill up tank). 1st bbl injected @ 1100 psi WHP in 5 minutes. 14th bbl injected @ 950 psi WHP in 8 minutes (.13 bbl/min). Final pressures, disposal string A = 0 psi, disposal string B = 950 psi, OA = 0 psi. Rig up to OA w/ produced water pump & 1 1/2" hose. Starting pressures, Disposal A = 0, Disposal B = 0, OA = 0. Establish injection, pressures stabilize @ 1580 psi on OA & Disposal A, 0 psi on Disposal B. Pump at ~1 bpm. Pump 210 bbls of produced water. Ending pressures, OA = 1573 psi, Disposal A = 1580 psi, Disposal B = 0 psi (no communication to disposal B). Rig Start Date End Date N/A 4/9/23 6/7/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/17/2023 - Monday Read gauge on 2 3/8 Injection string A = 0, pulled gauge found cmt to up into surface lines. Read gauge on 2 3/8 Injection string B = On Vac, open & let equalize to atmosphere, shut in for 4 hours, re-check static. RIH on 2 3/8 injection line B w/ nut on string to tag @ 257' from wellhead. (~80' below mudline). Read gauge on 9 5/8 x 13 3/8" annulus = On Vac, open & let equalize to atmosphere, shut in for 4 hours, re-check static. 04/12/2023 - Wednesday B string cement job: OA closed in for duration of B string cement job. Slowly pumped fresh water down A-string to keep communication with formation during duration of B-string cement job. 8.5bbls fresh water pumped over 1 hr down A-string. Injection pressure stabalized at 600psi. OAP was always ~25psi less. Pumped 11.1bbls of 12ppg cement down B-disposal string. No change in A nor OA pressure behaviour throughout job. Lead in with 3bbls neat, and followed with 8.1bbls with Bridgemaker LCM in cement at ~5lb/bbl. Pumped at ~0.3bpm with WHP's of 1120psi. Until 10bbls away when pressure rose, and tripped cementers. Came back on, but never got any steady rate before tripping out. Tried a 2min SD and pressured right back up after that. 11.1bbls cement pumped down B-string total. A string cement job: OA open to return tank for duration of A-string cement job. B-string SI at surface and stayed at 0psi for duration of A-string cement job. Started cement down A-string at 0psi injection pressure at 2bpm. Neat 12ppg. Slowed down at 0.6bpm for a few bbls when cement was calculated to hit perfs / holes to 13-3/8" x 9-5/8" OA. Didn't see any change in pump parameters when cement turned the corner. Returns from OA with partial losses after cement turned the corner. Returned a total of 64bbls water from OA after cement turned the corner. 24bbls lost to formation after cement turned corner. Pumped a total of 101bbls 12ppg down A-string. Final 17bbls had 5lb / bbl bridgemaker LCM material in cement. Injection pressures down A-string were <5psi at 2bpm throughout job until very end. Last 1 bbl pressure spiked up to 1200psi and stayed there. OA SI with 2bbls to go, and saw same pressure trend that A-string did. Final pressures 10 minutes after SD were A- string = 800psi, B-string = 0psi, and OA = 1100psi. Pressures after 3 hrs SI were A-string = 250psi, B-string = 0psi, and OA = 600psi. Calculated 64bbls 12ppg cement circ'd into OA (Calc'd ToC = 2865' MD) Pumped a total of 101bbls 12ppg down A-string TOC logged at +/-2115' MD. -bjm Pumped 11.1bbls of 12ppg cement down B-disposal string. No change in A nor OA pressure behaviour throughout job Calc'd ToC = 2865' MD) Started cement down A-string Rig Start Date End Date N/A 4/9/23 6/7/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/22/2023 - Saturday Continue R/u e-Line, install landing joint, build cutter. RIH w/Jet cutter, set cutter @ 3504' CCL @ 3501.1', distance from ccl to cutter 2.9'. Fire cutter, good indication at surface cutter fired. POOH had over pulls coming out, found bow spring sub damaged likely culprit for drag, cutter fired. BOLD pins, pull staging up t/90k, work 2x & park, string popped free, pickup wt 70k, land hanger back. Rev circulate hole volume, 240 bbls @ 3.5BPM, 120psi, clean. R/U handling tools. Cont. R/U handling tools, POOH l/d hanger & landing joint. Cont, POOH. L/D 15.5# 5 1/2" BTC tubulars, up wt 70k from 3504 ft. to 3018 ft. Waiting on weather due to hi winds gusting 45 to 52 mph. R/U & bullhead 256 bbls down tubing @ 2.5BPM 600 psi. Pump, bullhead 194 bbls down IA @ 2.9BPM, 700 psi, shut down & monitor one hour. Prep rig to skid. R/U jacks, remove stairs & doghouse landing. Rig up pancakes. Skid rig south to B-01A center. Check well on vac, install BPV. Pull hatch cover & N/D tree. Rig up cylinders and feet on single and double beam. Skid rig 3' North. Change out 4 Nitrogen Bottles on Accumulator. Make up 11" 5m x 13-5/8 5m spool onto riser, Fill pits with 80 bbl. water. Stack and nipple up BOPE, install choke, kill & accumulator lines. Torque BOP bolt to specs, move racking mat. PJSM, raise derrick to 1/2 mast. Run in lower dawgs, scope Derrick up, hook up guy wires. Install rig floor, install legs, level rig over hole. 04/20/2023 - Thursday Change out upper rams from 4 1/2" t/5 1/2" rams. M/U 5 1/2" TJ. Fill surface eq. w/test water, r/u test Eq. Shell test BOPE w/5 1/2" TJ 250/2500, had leak on low test w/pipe rams. Troubleshoot & narrow down too pipe rams. Pull test dart & inspect, had some bubbling from BPV, bullhead tubing volume @ 2bpm took 93bbls to catch pressure. Source more rams on slope & put in motion, ETA tomorrow midday. Close blinds, pull 5 1/2" rams inspect & turn rams over, re-install same, install test joint w/ dart sub, re-test pipe rams w/same results. Pull test joint & close blinds, test blinds 250/2500 to verify test dart holding. R/U & gravity feed IA with drill water for hole fill. Losses 35-40 BPH. Re- configure test joint after hawkjaw arrived on boat. Rig up and test 13-5/8 5m BOPE (Annular and Blind rams, TIW and IBOP choke and kill line valves choke manifold) to 250 low and 2500 high with 5-1/2 test joint. Held on chart 5 minutes. Rig maint & housekeeping while waiting on ram arrival. 04/21/2023- Friday Waiting on replacement 5-1/2" pipe rams. Performing rig maintenance, house keeping. Rams arrived at location, change out top 5-1/2 pipe rams with replacement rams. Fluid pack 5-1/2 test joint w/water test top 5-1/2 rams to 250 low and 2500 psi high (good test). Rig down test joint blanking sub, pull back pressure valve, break down test joint. M/U landing Joint. Rig up Pollard E-line. 04/19/2023 - Wednesday Rig Start Date End Date N/A 4/9/23 6/7/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 Disposal String MIT's: A-string not tested due to cement to surface (can see in valve) B-string: Pressured up to 1685psi. Lost 56psi in first 15 mins and 25psi in next 15 mins. PASS 05/06/2023 - Saturday R/D tools from floor while waiting on AOGCC review of CBL log before proceeding. Receive AOGCC approval. No OA remedial cement required. R/U E-line. M/U 30' of 5" bailer, Mix 17PPG cmt for each bailer run. RIH Dump 1st bailer w/25+galcmt @ 3475', 2nd bailer w/25+gal. Dumped @ 3466'. 3rd bailer run 25+gal cmt dump @ 3458.2', ETC= 3449.8'. Move E-line to A-12A for Tag. Backload 5 1/2" tubing, handling eq, xo's & Misc. Eq. to go to the beach. Start breaking down lines, emptying pits & prepping to remove rig floor. Remove on drillers side, rig floor stairs, remove rig floor, break and remove BOPE bolts from flanges, leave 4 bolted, nipple down choke and kill lines, nipple down control lines and plug BOPE hyd ports. Rig down pvt sensors, heater, prep derrick to scope down, scope down derrick, unspool tuggers, man riders and draw works, organize decks, rig down pits. Lay over derrick, nipple down 13- 5/8 bops and riser, set out same cleaning decks, install dry hole tree, rig up test pump and test dry hole tree to 250 low and 1500 psi HI, rig down test pump. Prep to skid rig. 04/23/2023 - Sunday Waiting on weather due to high winds gusting 45 to 47 mph. Winds slowed, Cont/ POOH l/D 5 1/2" 15.5# BTC tubing, f/3018', full recovery from cut. R/D 5 1/2" Handling tools. R/U e-line. RIH w/ 8.25 GR/JB t/3504 tag cut, POOH. RIH w/ CBL tools. Log up from stump @ 3504 t/surface ETC 2230'~ send logs to town. RIH w/CIBP Set @ 3475'. P/U & run back in to tag on depth, good, POOH & l/d tools. R/U test CIBP t/1500psi. Pressured up t/ 1640psi 3BBLS, first 15 min 1640PSI, 30 min 1640psi, bleed back 3 bbls. Witness was waived for this test by AOGCC inspector Jim Regg. R/U & test 13-3/8" x 9-5/8" OA. Took 3.5 bbls pressure up start pressure 1622psi, first 15 min 1556psi, final 30 min pressure 1526psi. PASS. Bleed back 2.8. AOGCC Witness Waived By Jim Regg. 04/24/2023 - Monday Rig Start Date End Date N/A 4/9/23 6/7/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 06/07/2023 - Wednesday Travel to OSK. Fly to Dolly Varden and pick up state Rep. Fly to Tyonek Platform. Hold safety meeting with Production operators and State Rep. Haskel pump and crystal gauge recorder hooked up to B string. Pressure up on B string for MIT. Required 1500 psi. Start test as per state Rep Kam St. John at 1635 psi. After 15 min 1615 psi. 30 minute end pressure 1602 psi. Good MIT. Break off flange on B string and A string. State Rep visually and physically check cement quality at surface on A string. A string complete. No need to MIT as per State Rep. Stinger assembly (5' long x 18lbs. 1.3" OD x 0.5" ID) and rope rigged up and lowered into B string. Rope is marked every 10'. Tagged cement top on B string at 255' below wellhead. State Rep confirms depth.;A string and B string requirements met. Pull weight bar and rope. Production to secure A string and B string with cap. Depart Tyonek platform. Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 06/20/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230419 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 04RD 50133202390100 219011 5/10/2023 AK E-LINE PERF BRU 212-26 50283201820000 220058 5/31/2023 AK E-LINE PPROF NCI B-01A 50883200930100 198002 4/24/2023 AK E-LINE Cut CBL CIBP Paxton 12 50133207100000 223014 5/24/2023 AK E-LINE Perf Record Paxton 12 50133207100000 223014 4/27/2023 AK E-LINE GPT/PERF SRU 213B-15 50133206540000 215130 5/1/2023 AK E-LINE CIBP Perf TBU M-29A 50733204280100 212050 5/7/2023 AK E-LINE Drift Punch Please include current contact information if different from above. T37759 T37760 T37761 T37762 T37762 T37763 T37764 NCI B-01A 50883200930100 198002 4/24/2023 AK E-LINE Cut CBL CIBP Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.20 11:55:19 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:6 Township:11N Range:9W Meridian:Seward Drilling Rig:n/a Rig Elevation:n/a Total Depth:16720 ft MD Lease No.:ADL017589 Operator Rep:Suspend:P&A:X Conductor:20"O.D. Shoe@ 2579 Feet Csg Cut@ Feet Surface:13-3/8"O.D. Shoe@ 3760 Feet Csg Cut@ Feet Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet Production:9-5/8"O.D. Shoe@ 10377 Feet Csg Cut@ Feet Liner:5"O.D. Shoe@ 16650 Feet Csg Cut@ Feet Tubing:5-1/2"O.D. Tail@ 3764 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified "A" String Tubing Bottom 3663 Surface n/a N/A "B" String Tubing Bottom 3663 255 ft 8.6 ppg N/A Initial 15 min 30 min 45 min Result "B" String Tubing 1635 1615 1602 IA OA Remarks: Attachments: Plug back for redrill. The well has 2, 2-3/8 inch disposal strings clamped to the 13-3/8 inch surface casing. Both disposal strings are 3663 ft in length and are perforated at 3500 ft MD. Hilcorp pumped cement from surface down both strings taking returns up the OA and holding pressure. The "A" Disposal string had good cement at surface; confirmed by removing the piping at the flange to verify good cement. They had no way of tying in to do the MIT. The "B" Disposal string cement fell back to 255 ft below surface, determined by disconnecting pipe at the tree flange and running in with an 18 lb weight bar and rope. MIT on the B-string passed. June 7, 2023 Kam StJohn Well Bore Plug & Abandonment North Cook Inlet Unit B-01A Hilcorp Alaska LLC PTD 1980020; Sundry 323-164 Photos (3) Test Data: P Casing Removal: Cole Bartelowski Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 11-28-18 2023-0607_Plug_Verification_annular_strings_NCIU_B-01A_ksj See remarks for "B" string depth verification jbr 2023-0607_Plug_Verification_annular_strings_NCIU_B-01A_photos_ksj Page 1 of 2 Plug Verification – North Cook Inlet Unit B-01A (PTD 1980020) Photos by AOGCC Inspector K. StJohn 6/7/2023 2023-0607_Plug_Verification_annular_strings_NCIU_B-01A_photos_ksj Page 2 of 2 “A” Disposal String – cement to surface 414 Kw -.n Wit' Tyonek Platform B-01 Proposed 03/17/2023 Starting head, Vetco AL-II, 30 x 20 x 13 3/8 x 2 3/8 dual tubing string surface hanger set-up 30'’ 20'’ 13 3/8'’ 9 5/8'’ Completion spool, Vetco CWC-T, 13 5/8 10M NT-2 bottom x 11 5M FE top BHTA, Otis, 5 1/8 5M FE x 9 1/2 Otis quick union top Valve, Master, VG-300, 5 1/8 5M FE, HWO, DD trim 2 3/8 tubing strings X 2 Cemented off Vetco Gray, MB-189 unitized wellhead, 3 string, 13 5/8 10M NT-2 top x 21 ¼ 2M SPECIAL bottom, w/ 2- 2 1/16 5M SSO, 4- 2 1/16 10M SSO Tyonek Platform B-01 30 x 20 x 13 3/8 x 9 5/8 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Ryan Rupert To:McLellan, Bryan J (OGC) Cc:Josh Allely - (C); Dan Marlowe; Juanita Lovett Subject:RE: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) Date:Tuesday, May 2, 2023 8:53:19 AM End of field life Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, May 1, 2023 2:02 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) When are you planning to do that? Before the sidetrack, or end of field life? 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, May 1, 2023 1:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) We would likely use 1” pipe (like that of a surface casing top job) and circulate in cement once the mainbore is P&A’d and tree/wellhead removed to allow better access. 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. Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, May 1, 2023 1:25 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) Ryan, How does Hilcorp intend to complete the surface P&A of the B-string? Cement is required within 30’ of mudline. 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Friday, April 28, 2023 9:51 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: NCIU B-01A (PTD#198-002) Bryan- The decomplete rig is now free and clear of Tyonek, so I’m planning for the final remaining witnessed tags / MIT’s from those sundries. We did in house tags of each of the A and B disposal strings on NCIU B-01A. A-string was right at surface (could see it). B-string found ToC at 257’ below the wellhead (80’ below mudline). Given these results, and how the job pumped, Hilcorp is asking to forgo the MIT requirements on both disposal strings. We will still provide a state witnessed tag. B-string volume to ToC is only ~1bbl, and A-string is zero volume. I think there’s a high likelihood these may not pass the traditional MIT criteria given the small volumes. Thoughts? Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) 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 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, please immediately 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, pleaseimmediately 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. From:McLellan, Bryan J (OGC) To:Ryan Rupert Cc:Josh Allely - (C); Dan Marlowe; Juanita Lovett; Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) Date:Tuesday, May 2, 2023 9:25:00 AM Ryan, The witnessed tag for both tubing strings needs to be with a drive down bailer and weight bar, or something similar, that is run until no further progress is made, indicating solid cement. A nut on a string is not sufficient to verify the presence of solid cement. If solid cement is verified, then we would consider a variance for not pressure testing. Pressure gauges must remain installed and functional on the tubing strings and pressures must be recorded at the same frequency of annular pressure reads on the wells at Tyonek platform. The OA still needs a witnessed PT to 1500 psi. If AOGCC inspectors are not available when you provide notice for witness, Hilcorp will need to wait until one is available because this well is a priority for inspection. 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Tuesday, May 2, 2023 8:53 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) End of field life Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Sent: Monday, May 1, 2023 2:02 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) When are you planning to do that? Before the sidetrack, or end of field life? 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, May 1, 2023 1:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) We would likely use 1” pipe (like that of a surface casing top job) and circulate in cement once the mainbore is P&A’d and tree/wellhead removed to allow better access. Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, May 1, 2023 1:25 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: [EXTERNAL] RE: NCIU B-01A (PTD#198-002) 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. Ryan, How does Hilcorp intend to complete the surface P&A of the B-string? Cement is required within 30’ of mudline. 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Friday, April 28, 2023 9:51 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: NCIU B-01A (PTD#198-002) Bryan- The decomplete rig is now free and clear of Tyonek, so I’m planning for the final remaining witnessed tags / MIT’s from those sundries. We did in house tags of each of the A and B disposal strings on NCIU B-01A. A-string was right at surface (could see it). B-string found ToC at 257’ below the wellhead (80’ below mudline). Given these results, and how the job pumped, Hilcorp is asking to forgo the MIT requirements on both disposal strings. We will still provide a state witnessed tag. B-string volume to ToC is only ~1bbl, and A-string is zero volume. I think there’s a high likelihood these may not pass the traditional MIT criteria given the small volumes. Thoughts? Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) 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 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 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. Rig Start Date End Date N/A 4/9/23 Future Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 No operations to report 04/15/2023 - Saturday 04/16/2023 - Sunday No operations to report 04/12/2023 - Wednesday B string cement job: OA closed in for duration of B string cement job. Slowly pumped fresh water down A-string to keep communication with formation during duration of B-string cement job. 8.5bbls fresh water pumped over 1 hr down A-string. Injection pressure stabalized at 600psi. OAP was always ~25psi less. Pumped 11.1bbls of 12ppg cement down B-disposal string. No change in A nor OA pressure behaviour throughout job. Lead in with 3bbls neat, and followed with 8.1bbls with Bridgemaker LCM in cement at ~5lb/bbl. Pumped at ~0.3bpm with WHP's of 1120psi. Until 10bbls away when pressure rose, and tripped cementers. Came back on, but never got any steady rate before tripping out. Tried a 2min SD and pressured right back up after that. 11.1bbls cement pumped down B-string total. A string cement job: OA open to return tank for duration of A-string cement job. B-string SI at surface and stayed at 0psi for duration of A-string cement job. Started cement down A-string at 0psi injection pressure at 2bpm. Neat 12ppg. Slowed down at 0.6bpm for a few bbls when cement was calculated to hit perfs / holes to 13-3/8" x 9-5/8" OA. Didn't see any change in pump parameters when cement turned the corner. Returns from OA with partial losses after cement turned the corner. Returned a total of 64bbls water from OA after cement turned the corner. 24bbls lost to formation after cement turned corner. Pumped a total of 101bbls 12ppg down A-string. Final 17bbls had 5lb / bbl bridgemaker LCM material in cement. Injection pressures down A-string were <5psi at 2bpm throughout job until very end. Last 1 bbl pressure spiked up to 1200psi and stayed there. OA SI with 2bbls to go, and saw same pressure trend that A-string did. Final pressures 10 minutes after SD were A- string = 800psi, B-string = 0psi, and OA = 1100psi. Pressures after 3 hrs SI were A-string = 250psi, B-string = 0psi, and OA = 600psi. Calculated 64bbls 12ppg cement circ'd into OA (Calc'd ToC = 2865' MD) No operations to report 04/14/2023- Friday No operations to report 04/13/2023 - Thursday Rig Start Date End Date N/A 4/9/23 Future Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 No operations to report Read gauge on 2 3/8 Injection string A = 0, pulled gauge found cmt to up into surface lines. Read gauge on 2 3/8 Injection string B = On Vac, open & let equalize to atmosphere, shut in for 4 hours, re-check static. RIH on 2 3/8 injection line B w/ nut on string to tag @ 257' from wellhead. (~80' below mudline). Read gauge on 9 5/8 x 13 3/8" annulus = On Vac, open & let equalize to atmosphere, shut in for 4 hours, re-check static. 04/18/2023 - Tuesday 04/17/2023 - Monday _____________________________________________________________________________________ Updated By: JLL 04/27/23 SCHEMATIC North Cook Inlet Unit Well: NCI B-01A Last Completed: 12/16/2003 PTD: 198-002 API: 50-883-20093-01 OPEN HOLE / CEMENT DETAIL 20" 24” Hole: Pumped 1690sxs of 12ppg lead followed by 700sxs of 15.8ppg tail cement. Saw cement to surface. 13-3/8" 18-1/2” hole: 115bbls of 12ppg lead cement returned to surface. 9/4/97 cement log acquired 9-5/8" 12-1/4" hole: Pumped 822bbls 12.5ppg lead cement followed by 144bbls of 15.8ppg tail cement. Lost circulation after 500bbls lead pumped, never did regain. Circ’d 50bbls cement/mud mix from top of 9-5/8” liner. 9/7/97. 11/25/03 USIT log shows ToC at 3775’ MD CASING DETAIL Size Wt Grade Conn ID Top Btm 30” H-40 Weld 27.000 Surf 407’ 20” 133# K-55 BTC 18.730” Surf 2,579’ 13-3/8” 72# N-80 12.347” Surf 3,760’ 9-5/8” Tie-Back 53.5 P-110 BTC 8.535” Surf 3,588’ 9-5/8” 53.5 P-110 BTC 8.535’ 3,588’ 10,377’ 5” 19.5 S-135 4.5” IF 4.408“/3.25” 10,074’ 16,650’ TUBING DETAIL 5-1/2” 15.5 L-80 BTC-Mod 4.950” 3,504’ 3,764’ 5-1/2” Combo Screens & Blanks 15.5 SLHT 4.950” 3,797 5,547’ 4-1/2” 12.6 IBT 3.958” 5,547 5,647’ 4” Combo Screens & Blanks 9.5 SLHT 3.548” 5,647 6,805’ 3-1/2” 9.3 L-80 IBT 2.992” 6,805 6,867’ 2” Coil Inner String ~2.51 HS-90-C BHISG 1.750” 3,567’ 6,817’ 4-1/2” 12.75 P-110 3.958” 8,052’ ±10,074’ Cuttings Disposal Tubing (2 strings) Dual 2-3/8” clamped to outside 13-3/8” A String: Cement to Surface B String: Cement to 257’ (~80’ below mudline) 4.7 N-80 CS Hydril 1.995” Surf 3,663’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 1 3,475’ 3,309’ 9-5/8” CIBP with 25’ cement dump bailed on top (Est. ToC = 3,450’) 4 3,591’ 3,411’ >8.535” 9-5/8” x 13-3/8” Liner Top Packer 5 3,602’ 3,389’ 4.653” 7.962” GLM #3 – Camco MMG w/ 5/16” orifice valve 6a 3,700’ 3,467’ 4.562” X-Nipple 6b 3,764’ 3,518’ 6.000” 8.313” Baker SC-1R Packer, PBR, seals, MOE, seal bore & gravel pack sleeve 7 3,797’ 3,544’ 5.000” 7.650” Model C KOIV (Knock Out Isolation Valve) 3,800’ 3,547’ 4.950” 6.110” 5-1/2” 15.5# SLHT blanks & Screens (140 x 0.012ga.) 8 4,368’ 4,010’ 4.940” 8.125” Baker SC-1L Packer, seal bore & gravel pack sleeve 4,421’ 4,053’ 4.940” 8.125” 5-1/2” 15.5# SLHT blanks & Screens (140 x 0.012ga.) 9 4,969’ 4,495’ 6.000” 8.281” Baker SC-1R Sump Packer & MOE 4,985’ 4,508’ 4.892” 6.050” 5-1/2” 15.5# L-80 SLHT Blank 10 5,547’ 4,962’ 3.958” 6.060” Crossover 5-1/2” SLHT x 4-1/2” IBT 11 5,579’ 4,988’ 3.813” 5.230” X-Nipple 12 5,613’ 5,015’ 4.750” 8.329” Baker SC-2 Packer, S-22 Snap Latch, seal bore, & gravel pack sleeve 13 5,647’ 5,042’ 3.500” 5.650” Model C KOIV (Knock Out Isolation Valve) 5,650’ 5,044’ 3.548” 4.590” 4” SLHT Screen & Blanks (12 ga.) 14 6,787’ 5,960’ 6.000” 8.280” Baker SC-1R Sump Packer, S-22 Snap Latch, MOE 15 6,805’ 5,975’ 2.992” 6.050” Crossover 5-1/2” x 3-1/2” 16 6,836’ 6,000’ 2.813” 4.250” X-Nipple 17 6,867’ 6,026’ 2.992” 4.250” WLEG 18 8,052’ 6,984’ Fish – Cut top of 4-1/2” tubing 19 10,032’ 8,564’ Sliding Sleeve – PXN Plug @ 10,042 20 10,074’ 8,598’ Packer 21 10,376’ 8,840’ XN Nipple w/ PXN Plug in Nipple _____________________________________________________________________________________ Updated By: JLL 04/27/23 SCHEMATIC North Cook Inlet Unit Well: NCI B-01A Last Completed: 12/16/2003 PTD: 198-002 API: 50-883-20093-01 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Disposal 3,500' 3,540' 3,307' 3,339' 40' 9/9/1997 Isolated 4/23/23 3,850' 3,869' 3,587' 3,602' 19' 12/8/2003 Isolated 4/23/23 3,886' 3,893' 3,616' 3,621' 7' 12/8/2003 Isolated 4/23/23 CI 1 4,185' 4,268' 3,859' 3,928' 83' 12/8/2003 Isolated 4/23/23 CI 2 4,275' 4,365' 3,933' 4,007' 90' 12/8/2003 Isolated 4/23/23 CI 4 4,429' 4,480' 4,060' 4,101' 51' 12/8/2003 Isolated 4/23/23 CI 8 4,751' 4,761' 4,319' 4,327' 10' 12/8/2003 Isolated 4/23/23 CI 8 4,792' 4,803' 4,352' 4,361' 11' 12/8/2003 Isolated 4/23/23 CI 11 4,922' 4,955' 4,457' 4,484' 33' 12/8/2003 Isolated 4/23/23 BELG-F 5,718' 5,742' 5,098' 5,118' 24' 12/1/2003 Isolated 4/23/23 BELG-G 5,885' 5,892' 5,234' 5,239' 7' 12/1/2003 Isolated 4/23/23 BELG-H 5,929' 5,939' 5,269' 5,278' 10' 12/1/2003 Isolated 4/23/23 BELG-H 5,948' 5,969' 5,285' 5,302' 21' 12/1/2003 Isolated 4/23/23 BELG-H 5,995' 6,032' 5,323' 5,353' 37' 12/1/2003 Isolated 4/23/23 BELG-I 6,078' 6,091' 5,390' 5,400' 13' 12/1/2003 Isolated 4/23/23 6,097' 6,107' 5,405' 5,413' 10' 12/1/2003 Isolated 4/23/23 BELG-I 6,118' 6,124' 5,422' 5,427' 6' 12/1/2003 Isolated 4/23/23 BELG-I 6,148' 6,158' 5,446' 5,454' 10' 12/1/2003 Isolated 4/23/23 BELG-I 6,169' 6,182' 5,463' 5,473' 13' 12/1/2003 Isolated 4/23/23 BELG-J 6,283' 6,290' 5,553' 5,559' 7' 12/1/2003 Isolated 4/23/23 BELG-L 6,375' 6,390' 5,627' 5,639' 15' 12/1/2003 Isolated 4/23/23 BELG-M 6,610' 6,622' 5,815' 5,825' 12' 12/1/2003 Isolated 4/23/23 BELG-O 6,762' 6,767' 5,939' 5,943' 5' 12/1/2003 Isolated 4/23/23 9,970' 9,972' 8,514' 8,515' 2' Isolated Oil Exploration 16,080' 16,118' 12,525' 12,548' 38' Isolated INNER STRING JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item Fish: 04/20/21 - UDGL Widepack Upper Packer pulled & fell to 3,588’ RKB 3,575’ 3,367’ 3.000” 4.500” Weatherford 450 Widepack Upper Packer 3,581’ 3,372’ 2.992” 3-1/2” Pup Joint 3,586’ 3,376’ 3.000” 3-7/8” Pup Joints 3,606’ 3,392’ N/A 4.420” Centralift AVE Sub w/ Dual Flapper Check Valve 3,606’ 3,392’ 2.875” 4.470” WP Anchor Seal Latch 3,609’ 3,394’ 0.875” 1.750” Stinger Rod w/ seal stack (6.90’) stung into PBR Seal Bore 3,610’ 3,395’ 3.000” 4.500” Weatherford 450 Widepack Lower Packer 3,616’ 3,400’ 3.476” 4.420” Slotted Sub 3,617’ 3,401’ 1.750” 4.420” PBR Seal Bore 3,619’ 3,402’ 1.375” 4.420” Torq-Thru Quick Connect - Upper 3,620’ 3,403’ 1.375” 2.875” Torq-Thru Quick Connect - Lower 3,620’ 3,403’ 3.000” 4.313” Tryton Max Frac Plug 6,049’ 5,367’ 1.375” 2.875” External Grapple Coil Connector 6,050’ 5,367’ 2.000” 2.600” PM-1 Gas Lift Mandrel 6,052’ 5,369’ 1.375” 2.875” Torq-Thru Quick Connect 6,817’ 5,984’ 1.750” 2.000” CT Dimple Connector 6,817’ 5,984’ 0.930” 2.375” injection sub 6,819’ 5,986’ bottom of injection string From:McLellan, Bryan J (OGC) To:Ryan Rupert Subject:RE: [EXTERNAL] Re: NCIU B-01A RWO (PTD#198-002) Date:Monday, April 24, 2023 6:50:00 AM Ryan, The CBL indicates good cement well above the 3400’ minimum. Hilcorp has approval to proceed with the sundry 323-164. 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, April 24, 2023 5:46 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: FW: [EXTERNAL] Re: NCIU B-01A RWO (PTD#198-002) Attached Ryan Rupert 907-301-1736 -------- Original message -------- From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Date: 4/24/23 1:41 AM (GMT-09:00) To: "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>, "Harold Soule - (C)" <hsoule@hilcorp.com>, "Howard Hooter - (C)" <Howard.Hooter@hilcorp.com>, Dan Marlowe <dmarlowe@hilcorp.com>, "Loepp, Victoria T (OGC)" <victoria.loepp@alaska.gov>, Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: [EXTERNAL] Re: NCIU B-01A RWO (PTD#198-002) Looks like ~2230’ ToC from what I see. Hilcorp requests permission to continue with sundry steps 25-27 as written (no contingency remedial OA cement necessary). Please advise Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Ryan Rupert Sent: Sunday, April 23, 2023 9:36 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Harold Soule - (C) <hsoule@hilcorp.com>; Howard Hooter - (C) <Howard.Hooter@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL] Re: NCIU B-01A RWO (PTD#198-002) Just an update: we expect to have the CBL around 02:00 this morning. I'll email over when we get it. Ryan Rupert 907-301-1736 -------- Original message -------- From: "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov> Date: 4/20/23 2:52 PM (GMT-09:00) To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com>, "Harold Soule - (C)" <hsoule@hilcorp.com>, "Howard Hooter - (C)" <Howard.Hooter@hilcorp.com>, Dan Marlowe <dmarlowe@hilcorp.com>, "Loepp, Victoria T (OGC)" <victoria.loepp@alaska.gov> Subject: [EXTERNAL] Re: NCIU B-01A RWO (PTD#198-002) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Ryan. Hilcorp has approval to go up to and including Step 24 without log review and approval from AOGCC. I’ll review the log, but will not necessarily get you an immediate response, depending when it comes. Bryan Sent from my iPhone > On Apr 20, 2023, at 4:22 PM, Ryan Rupert <Ryan.Rupert@hilcorp.com> wrote: > > 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- > > > Just an update on our in progress RWO for NCIU B-01A (sundry #323-164). AOGCC has requested a hold point in the sundry to review the CBL log we plan to acquire before proceeding. It’s a bit of a moving target, but we could have that CBL for the agency to review as soon as Friday evening 4/21. Most likely will be Saturday 4/22. Will you be the person this weekend to review it? > > Also, I wanted to clarify exactly what work must be held until approval granted. I think it makes sense that we continue with the sundry as written through step #24. We would then wait to execute step’s 25 and beyond for approval. Is that interpretation correct? > > > > > Decomplete Rig Procedure: > > > 1. MIRU HAK rig 404. > 2. Bullhead kill well down IA and tubing to flush all hydrocarbons and ensure same fluid everywhere > > * Work over fluid will be produced water or fresh water > * Take returns to formation > * Tubing volume to bottom perf = 160bbls > * IA volume = 150bbls (should be able to inject down IA through orifice GLV at 3,602’ MD) > > 1. Set BPV, ND tree, NU BOP > * Notify AOGCC 48 hours in advance for witness > * Test to 250psi Low /2,500psi High / 2,500psi Annular > * Test to accommodate 5-1/2” tubing, and any workstring pipe required > * BOP’s will be closed as needed to circulate the well > 2. Pull BPV > 3. RU EL cut 5-1/2” tubing at ±3,500’ MD > * Fish at 3575’ MD > * Avoid collars > 4. Stand back EL > 5. Circulate well down IA taking returns up tubing (Surface to surface volume = 235bbls) > 6. Monitor well to ensure it is dead and static > 7. Unseat hanger and POOH laying down 5-1/2” tubing > 8. RU EL and perform CBL on 9-5/8” x 13-3/8” annulus > * Confirm ToC is above 3400’ MD (at least 100’ above top disposal perf at 3500’ MD) > * If ToC is below target depth, see contingent steps at end of procedure for remedial OA cementing > 9. MU 9-5/8” CIBP and set at ±3,475’ MD > * Within 25’ of cut tubing stub > * No more than 50’ above top disposal perf at 3500’ > 10. Tag CIBP and perform MIT to 1500psi (give 48hr notice for AOGCC witness) > > Hold point here to review CBL results between these steps, correct? > > > 1. Dump bail 25’ cement on top of plug > * 1.8bbls / 75 gal required > * Skip this step if remedial OA cementing is necessary > 2. ND BOP’s, Install dryhole tree and test > 3. RDMO HAK rig 404 > > > > > > Ryan Rupert > CIO Ops Engineer (#13088) > 907-301-1736 (Cell) > 907-777-8503 (Office) > > > ________________________________ > 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. 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. 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:Wallace, Chris D (OGC) To:Brooks, Phoebe L (OGC); AOGCC Records (CED sponsored) Subject:FW: NCIU B-01A (PTD# 198-002) Pump-in Differential Temperature Log - March 2023 Date:Thursday, April 6, 2023 8:44:03 AM Attachments:NCI B-01A Schematic 2023-02-21.pdf NCIU B-01A Temp Survey 3-2-23.pdf From: Josh Allely - (C) <Josh.Allely@hilcorp.com> Sent: Wednesday, April 5, 2023 4:51 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: NCIU B-01A (PTD# 198-002) Pump-in Differential Temperature Log - March 2023 Mr Wallace, Per DIO 33, Rule 4, North Cook Inlet Unit B-01A (PTD 198-002) requires a biennial pump-in temperature survey. The 2023 survey was completed on 3/3/2023. As in previous years, water was pumped down one of the 2-3/8” injection strings into the disposal zone and temperature passes were logged though the 5-1/2” production tubing looking for any shallow anomalies. The attached survey data, which consists of 3 warm back passes after injecting 150 bbls of water, does not show any temperature anomalies that would indicate out of zone injection is occurring. Let me know if you have any questions or require additional information/data. Thanks Josh Allely Well Integrity Engineer Kenai – Hilcorp Alaska 907-777-8505 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. _____________________________________________________________________________________ Updated By: JLL 02/21/2023 SCHEMATIC North Cook Inlet Unit Well: NCI B-01A Last Completed: 12/16/2003 PTD: 198-002 API:50-883-20093-01 OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 1690sxs of 12ppg lead followed by 700sxs of 15.8ppg tail cement.Saw cement to surface. 13-3/8"18-1/2” hole: 115bbls of 12ppg lead cement returned to surface.9/4/97 cement log acquired 9-5/8" 12-1/4" hole: Pumped 822bbls 12.5ppg lead cement followed by 144bbls of 15.8ppg tail cement. Lost circulation after 500bbls lead pumped, never did regain. Circ’d 50bbls cement/mud mix from top of 9-5/8” liner. 9/7/97. 11/25/03 USIT log shows ToC at 3775’ MDPBTD:9,610’TD:16,720’ 4 30” RKB: 53.6’, RKB to MSL: 132’, RKB to Mudline: 232’ 5” 3 5 6a/b 7 8 9 10 11 12 13 13-3/8” 9-5/8” 1 2 14 15 16 17 20” 2-3/8” 18 20 21 Tag TOC in tubing @ 9,610’ Calc. TOC in tubing x 9-5/8” @9,837’ XN X X X 19 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”H-40 Weld 27.000 Surf 407’ 20”133#K-55 BTC 18.730”Surf 2,579’ 13-3/8”72#N-80 12.347”Surf 3,760’ 9-5/8” Tie-Back 53.5 P-110 BTC 8.535”Surf 3,588’ 9-5/8”53.5 P-110 BTC 8.535’3,588’10,377’ 5”19.5 S-135 4.5” IF 4.408“/3.25” 10,074’ 16,650’ TUBING DETAIL 5-1/2”15.5 L-80 BTC-Mod 4.950”Surf 3,764’ 5-1/2” Combo Screens & Blanks 15.5 SLHT 4.950”3,797 5,547’ 4-1/2”12.6 IBT 3.958”5,547 5,647’ 4” Combo Screens & Blanks 9.5 SLHT 3.548”5,647 6,805’ 3-1/2”9.3 L-80 IBT 2.992”6,805 6,867’ 2” Coil Inner String ~2.51 HS-90-C BHISG 1.750”3,567’6,817’ 4-1/2”12.75 P-110 3.958”8,052’ ±10,074’ Cuttings Disposal Tubing (2 strings) Dual 2-3/8”4.7 N-80 CS Hydril 1.995”Surf 3,663’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 53.6’53’5.500” 10.750” Hanger – 10-3/4” x 5-1/2” VETCO 1 410’410’ 4.562” 7.500” SSSV – CAMCO TRM-4E w/ OTIS WLRSV (X Profile) 2 1,559’ 1,553’ 4.653” 7.962” GLM #1 – Camco MMG w/ dummy valve 3 2,675’ 3,598’ 4.653” 7.962” GLM #2 – Camco MMG w/ dummy valve 4 3,591 >8.535”9-5/8” x 13-3/8” Liner Top Packer 5 3,602’ 3,389’ 4.653” 7.962” GLM #3 – Camco MMG w/ 5/16” orifice valve 6a 3,700’ 3,467’ 4.562”X-Nipple 6b 3,764’ 3,518’ 6.000” 8.313” Baker SC-1R Packer, PBR, seals, MOE, seal bore & gravel pack sleeve 7 3,797’ 3,544’ 5.000” 7.650” Model C KOIV (Knock Out Isolation Valve) 3,800’ 3,547’ 4.950” 6.110” 5-1/2” 15.5# SLHT blanks & Screens (140 x 0.012ga.) 8 4,368’ 4,010’ 4.940” 8.125” Baker SC-1L Packer, seal bore & gravel pack sleeve 4,421’ 4,053’ 4.940” 8.125” 5-1/2” 15.5# SLHT blanks & Screens (140 x 0.012ga.) 9 4,969’ 4,495’ 6.000” 8.281” Baker SC-1R Sump Packer & MOE 4,985’ 4,508’ 4.892” 6.050” 5-1/2” 15.5# L-80 SLHT Blank 10 5,547’ 4,962’ 3.958” 6.060” Crossover 5-1/2” SLHT x 4-1/2” IBT 11 5,579’ 4,988’ 3.813” 5.230” X-Nipple 12 5,613’ 5,015’ 4.750” 8.329” Baker SC-2 Packer, S-22 Snap Latch, seal bore, & gravel pack sleeve 13 5,647’ 5,042’ 3.500” 5.650” Model C KOIV (Knock Out Isolation Valve) 5,650’ 5,044’ 3.548” 4.590” 4” SLHT Screen & Blanks (12 ga.) 14 6,787’ 5,960’ 6.000” 8.280” Baker SC-1R Sump Packer, S-22 Snap Latch, MOE 15 6,805’ 5,975’ 2.992” 6.050” Crossover 5-1/2” x 3-1/2” 16 6,836’ 6,000’ 2.813” 4.250” X-Nipple 17 6,867’ 6,026’ 2.992” 4.250” WLEG 18 8,052’ 6,984’Fish – Cut top of 4-1/2” tubing 19 10,032’ 8,564’Sliding Sleeve –PXN Plug @ 10,042 20 10,074’ 8,598’Packer 21 10,376’ 8,840’XN Nipple w/ PXN Plug in Nipple _____________________________________________________________________________________ Updated By: JLL 02/21/2023 SCHEMATIC North Cook Inlet Unit Well: NCI B-01A Last Completed: 12/16/2003 PTD: 198-002 API:50-883-20093-01 PERFORATION DETAIL Zone Top (MD)Btm (MD) Top (TVD) Btm (TVD)FT Date Status Disposal 3,500'3,540'3,307'3,339'40'9/9/1997 Open 3,850'3,869'3,587'3,602'19'12/8/2003 Open 3,886'3,893'3,616'3,621'7'12/8/2003 Open CI 1 4,185'4,268'3,859'3,928'83'12/8/2003 Open CI 2 4,275'4,365'3,933'4,007'90'12/8/2003 Open CI 4 4,429'4,480'4,060'4,101'51'12/8/2003 Open CI 8 4,751'4,761'4,319'4,327'10'12/8/2003 Open CI 8 4,792'4,803'4,352'4,361'11'12/8/2003 Open CI 11 4,922'4,955'4,457'4,484'33'12/8/2003 Open BELG-F 5,718'5,742'5,098'5,118'24'12/1/2003 Open BELG-G 5,885'5,892'5,234'5,239'7'12/1/2003 Open BELG-H 5,929'5,939'5,269'5,278'10'12/1/2003 Open BELG-H 5,948'5,969'5,285'5,302'21'12/1/2003 Open BELG-H 5,995'6,032'5,323'5,353'37'12/1/2003 Open BELG-I 6,078'6,091'5,390'5,400'13'12/1/2003 6,097'6,107'5,405'5,413'10'12/1/2003 Open BELG-I 6,118'6,124'5,422'5,427'6'12/1/2003 Open BELG-I 6,148'6,158'5,446'5,454'10'12/1/2003 Open BELG-I 6,169'6,182'5,463'5,473'13'12/1/2003 Open BELG-J 6,283'6,290'5,553'5,559'7'12/1/2003 Open BELG-L 6,375'6,390'5,627'5,639'15'12/1/2003 Open BELG-M 6,610'6,622'5,815'5,825'12'12/1/2003 Open BELG-O 6,762'6,767'5,939'5,943'5'12/1/2003 Open 9,970'9,972'8,514'8,515'2'Isolated 16,080'16,118'12,525'12,548'38'Isolated INNER STRING JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item Fish: 04/20/21 - UDGL Widepack Upper Packer pulled & fell to 3,588’ RKB 3,575’3,367’3.000”4.500”Weatherford 450 Widepack Upper Packer 3,581’3,372’2.992”3-1/2” Pup Joint 3,586’3,376’3.000”3-7/8” Pup Joints 3,606’3,392’N/A 4.420”Centralift AVE Sub w/ Dual Flapper Check Valve 3,606’3,392’2.875”4.470”WP Anchor Seal Latch 3,609’3,394’0.875”1.750”Stinger Rod w/ seal stack (6.90’)stung into PBR Seal Bore 3,610’3,395’3.000”4.500”Weatherford 450 Widepack Lower Packer 3,616’3,400’3.476”4.420”Slotted Sub 3,617’3,401’1.750”4.420”PBR Seal Bore 3,619’3,402’1.375”4.420”Torq-Thru Quick Connect - Upper 3,620’3,403’1.375”2.875”Torq-Thru Quick Connect - Lower 3,620’3,403’3.000”4.313”Tryton Max Frac Plug 6,049’5,367’1.375”2.875”External Grapple Coil Connector 6,050’5,367’2.000”2.600”PM-1 Gas Lift Mandrel 6,052’5,369’1.375”2.875”Torq-Thru Quick Connect 6,817’5,984’1.750”2.000”CT Dimple Connector 6,817’5,984’0.930”2.375”injection sub 6,819’5,986’bottom of injection string Well:Field:03/02/2023HilcorpB-01A Tyonek 69 70 71 72 73 74 75 3000 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 Temperature (Deg. F)Depth-MD, (feet)Perfs Valve 30"20" 13 3/8"9 5/8"TBG "Packer Temperature Up 1 Temp U2 Temp U3 Pressure-Temperature Profile 1. Up Passes 3000' -3550' Up 1 -directly after injection Up 2 -2hrs after injection Up 3 -4hrs after injection Report date: 4/5/2023 03/31/2023 RBDMS JSB 040423 From:McLellan, Bryan J (OGC) To:Ryan Rupert Subject:NCIU A-08 (PTD 198-002) Injection test sundry Date:Friday, February 24, 2023 11:29:00 AM Ryan, Hilcorp has verbal approval to set a CIBP and cap it with cement per Sundry application submitted 2/21/23 steps 1-4, with the condition that 25’ of cement are placed on top of the CIBP. FYI, this has been assigned sundry number 323-110. 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 Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8300 Fax: 907-777-8580 June 6, 2022 Mr. Chris Wallace, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Subject: 2021 Annual Disposal Report for North Cook Inlet B-01A (DIO 33) Dear Mr. Wallace: In accordance with DIO 33 (rule 6), Hilcorp Alaska, LLC hereby submits the annual disposal report for well North Cook Inlet B-01A (PTD # 198-002) for the year 2021. Surveillance Summary B-01A was used for disposal operations for 4 days and a total of 5753 bbls was injected for 2021. Injection performance was consistent with previous injection performance and injection parameters (pressure and rate) were maintained within the limits set forth in DIO 33. A pump-in differential temperature survey was performed on the 5-1/2” production tubing in the NCIU B-01A on 3/16/2021 and the log confirmed well integrity and confinement. The next temperature survey will be conducted in March of 2023. Should you have questions, please contact Chris Kanyer at 777-8377 or Josh Allely at 777-8505. Sincerely, Chris Kanyer Reservoir Engineer 0 500 1000 1500 2000 2500 3000 3500 4000 0 500 1000 1500 2000 2500 01/2021 02/2021 03/2021 04/2021 05/2021 06/2021 07/2021 08/2021 09/2021 10/2021 11/2021 12/2021 NCIU B-001A TBG TBG 2 (2-3/8")IA OA OOA Water Injection Date Tubing Tubing 2 IA OA OOA Water Injection 12/31/2021 101 0 446 30 0 0 12/30/2021 101 0 446 25 0 0 12/29/2021 102 0 446 23 0 0 12/28/2021 101 0 445 20 0 0 12/27/2021 102 0 446 15 0 0 12/26/2021 103 0 446 10 0 0 12/25/2021 103 0 447 0 0 0 12/24/2021 102 0 456 0 0 0 12/23/2021 104 0 447 0 0 0 12/22/2021 104 0 445 0 0 0 12/21/2021 102 0 444 0 0 0 12/20/2021 104 0 444 0 0 0 12/19/2021 104 0 444 0 0 0 12/18/2021 104 0 444 0 0 0 12/17/2021 105 0 444 0 0 0 12/16/2021 104 0 445 0 0 0 12/15/2021 104 0 445 0 0 0 12/14/2021 104 0 445 0 0 0 12/13/2021 103 0 448 0 0 0 12/12/2021 103 0 444 0 0 0 12/11/2021 104 0 444 0 0 0 12/10/2021 107 0 445 0 0 0 12/9/2021 107 0 445 0 0 0 12/8/2021 108 0 444 0 0 0 12/7/2021 111 0 445 0 0 0 12/6/2021 111 0 445 0 0 0 12/5/2021 111 0 445 0 0 0 12/4/2021 111 0 445 0 0 0 Date Range: 01/01/2021 - 12/31/2021 Well: B-01A S Desc: Shut-In Permit to drill: 1980020 Admin Approval: N/A API: 50-883-20093-01-00 12/3/2021 111 0 445 0 0 0 12/2/2021 111 0 445 0 0 0 12/1/2021 113 0 445 0 0 0 11/30/2021 114 0 445 0 0 0 11/29/2021 113 0 445 0 0 0 11/28/2021 112 0 445 0 0 0 11/27/2021 114 0 445 0 0 0 11/26/2021 115 0 445 0 0 0 11/25/2021 116 0 445 0 0 0 11/24/2021 118 0 445 0 0 0 11/23/2021 118 0 444 0 0 0 11/22/2021 118 0 445 0 0 0 11/21/2021 121 0 444 0 0 0 11/20/2021 121 0 444 0 0 0 11/19/2021 123 0 444 0 0 0 11/18/2021 123 0 444 0 0 0 11/17/2021 125 0 444 0 0 0 11/16/2021 130 0 446 0 0 0 11/15/2021 140 0 444 0 0 0 11/14/2021 139 0 444 0 0 0 11/13/2021 137 0 444 0 0 0 11/12/2021 140 0 444 0 0 0 11/11/2021 150 0 444 0 0 0 11/10/2021 148 0 444 0 0 0 11/9/2021 148 0 444 0 0 0 11/8/2021 154 0 444 0 0 0 11/7/2021 159 0 444 0 0 0 11/6/2021 168 0 444 0 0 0 11/5/2021 178 0 444 0 0 0 11/4/2021 145 0 444 0 0 0 11/3/2021 445 0 444 0 0 0 11/2/2021 445 0 444 0 0 0 11/1/2021 445 0 444 0 0 0 10/31/2021 445 0 444 0 0 0 10/30/2021 445 0 444 0 0 0 10/29/2021 445 0 445 0 0 0 10/28/2021 445 0 444 0 0 0 10/27/2021 444 0 444 0 0 0 10/26/2021 443 0 444 0 0 0 10/25/2021 447 0 447 0 0 0 10/24/2021 443 0 443 0 0 0 10/23/2021 443 0 444 0 0 0 10/22/2021 443 0 444 0 0 0 10/21/2021 443 0 444 0 0 0 10/20/2021 443 0 444 0 0 0 10/19/2021 443 0 444 0 0 0 10/18/2021 443 0 443 0 0 0 10/17/2021 443 0 444 0 0 0 10/16/2021 443 0 444 0 0 0 10/15/2021 443 0 444 0 0 0 10/14/2021 443 0 444 0 0 0 10/13/2021 443 0 444 0 0 0 10/12/2021 445 0 445 0 0 0 10/11/2021 445 0 444 0 0 0 10/10/2021 445 0 445 0 0 0 10/9/2021 445 0 444 0 0 0 10/8/2021 445 0 445 0 0 0 10/7/2021 445 0 445 0 0 0 10/6/2021 445 0 445 0 0 0 10/5/2021 444 0 444 0 0 0 10/4/2021 446 0 445 0 0 0 10/3/2021 444 0 444 0 0 0 10/2/2021 444 0 445 0 0 0 10/1/2021 442 0 444 0 0 0 9/30/2021 443 0 445 0 0 0 9/29/2021 443 0 445 0 0 0 9/28/2021 445 0 445 0 0 0 9/27/2021 445 0 445 0 0 0 9/26/2021 445 0 445 0 0 0 9/25/2021 445 0 445 0 0 0 9/24/2021 445 0 445 0 0 0 9/23/2021 445 0 445 0 0 0 9/22/2021 445 0 445 0 0 0 9/21/2021 445 0 445 0 0 0 9/20/2021 445 0 445 0 0 0 9/19/2021 445 0 446 0 0 0 9/18/2021 440 0 446 0 0 0 9/17/2021 445 0 446 0 0 0 9/16/2021 450 0 450 0 0 0 9/15/2021 450 0 448 0 0 0 9/14/2021 450 0 450 0 0 0 9/13/2021 451 0 450 0 0 0 9/12/2021 452 0 451 0 0 0 9/11/2021 452 0 451 0 0 0 9/10/2021 362 0 361 0 0 0 9/9/2021 444 0 444 0 0 0 9/8/2021 444 0 444 0 0 0 9/7/2021 444 0 444 0 0 0 9/6/2021 444 0 444 0 0 0 9/5/2021 444 0 444 0 0 0 9/4/2021 444 0 444 0 0 0 9/3/2021 444 0 444 0 0 0 9/2/2021 444 0 443 0 0 0 9/1/2021 444 0 444 0 0 0 8/31/2021 443 0 443 0 0 0 8/30/2021 442 0 443 0 0 0 8/29/2021 442 0 442 0 0 0 8/28/2021 443 0 443 0 0 0 8/27/2021 442 0 443 0 0 0 8/26/2021 443 0 443 0 0 0 8/25/2021 442 0 443 0 0 0 8/24/2021 443 0 443 0 0 0 8/23/2021 442 0 442 0 0 0 8/22/2021 442 0 442 0 0 0 8/21/2021 442 0 442 0 0 0 8/20/2021 442 0 442 0 0 0 8/19/2021 442 0 442 0 0 0 8/18/2021 442 0 442 0 0 0 8/17/2021 443 0 443 0 0 0 8/16/2021 443 0 443 0 0 0 8/15/2021 443 0 443 0 0 0 8/14/2021 443 0 443 0 0 0 8/13/2021 443 0 443 0 0 0 8/12/2021 443 0 443 0 0 0 8/11/2021 443 0 443 0 0 0 8/10/2021 443 0 442 0 0 0 8/9/2021 443 0 443 0 0 0 8/8/2021 443 0 443 0 0 0 8/7/2021 443 0 443 0 0 0 8/6/2021 443 0 443 0 0 0 8/5/2021 442 0 442 0 0 0 8/4/2021 440 0 439 0 0 0 8/3/2021 430 0 440 0 0 0 8/2/2021 430 0 440 0 0 0 8/1/2021 430 0 440 0 0 0 7/31/2021 430 0 440 0 0 0 7/30/2021 430 0 440 0 0 0 7/29/2021 430 0 440 0 0 0 7/28/2021 430 0 440 0 0 0 7/27/2021 415 0 440 0 0 0 7/26/2021 415 0 440 0 0 0 7/25/2021 415 0 440 0 0 0 7/24/2021 415 0 440 0 0 0 7/23/2021 420 0 440 0 0 0 7/22/2021 420 0 440 0 0 0 7/21/2021 420 2100 440 1650 0 167 7/20/2021 435 2150 440 1650 0 3337 7/19/2021 434 2200 441 1650 0 1915 7/18/2021 435 55 440 278 0 0 7/17/2021 438 55 440 284 0 0 7/16/2021 426 55 440 284 0 0 7/15/2021 438 55 441 284 0 0 7/14/2021 436 55 436 275 0 0 7/13/2021 436 55 436 284 0 0 7/12/2021 436 55 436 284 0 0 7/11/2021 436 55 435 280 0 0 7/10/2021 436 54 435 277 0 0 7/9/2021 438 55 437 276 0 0 7/8/2021 437 55 437 275 0 0 7/7/2021 437 55 437 275 0 0 7/6/2021 420 55 437 270 0 0 7/5/2021 420 55 437 280 0 0 7/4/2021 420 55 437 270 0 0 7/3/2021 425 55 437 270 0 0 7/2/2021 440 55 437 265 0 0 7/1/2021 437 55 437 262 0 0 6/30/2021 420 55 437 260 0 0 6/29/2021 420 55 438 260 0 0 6/28/2021 420 55 438 225 0 0 6/27/2021 420 55 438 255 0 0 6/26/2021 420 55 439 250 0 0 6/25/2021 420 55 438 250 0 0 6/24/2021 420 55 437 250 0 0 6/23/2021 420 55 437 245 0 0 6/22/2021 438 55 438 246 0 0 6/21/2021 438 55 438 244 0 0 6/20/2021 438 55 438 242 0 0 6/19/2021 437 56 437 240 0 0 6/18/2021 438 56 438 240 0 0 6/17/2021 437 56 437 238 0 0 6/16/2021 437 56 437 236 0 0 6/15/2021 437 60 437 235 0 0 6/14/2021 436 60 436 230 0 0 6/13/2021 436 60 436 227 0 0 6/12/2021 436 60 436 225 0 0 6/11/2021 435 60 435 225 0 0 6/10/2021 435 60 435 220 0 0 6/9/2021 435 60 435 210 0 0 6/8/2021 434 60 436 210 0 0 6/7/2021 434 60 434 215 0 0 6/6/2021 434 55 434 210 0 0 6/5/2021 434 50 434 210 0 0 6/4/2021 434 50 434 210 0 0 6/3/2021 434 50 434 205 0 0 6/2/2021 433 50 434 200 0 0 6/1/2021 434 55 434 200 0 0 5/31/2021 434 75 434 205 0 0 5/30/2021 434 100 433 225 0 0 5/29/2021 434 95 434 210 0 0 5/28/2021 434 100 434 210 0 0 5/27/2021 434 100 434 210 0 0 5/26/2021 434 95 434 205 0 0 5/25/2021 435 95 434 210 0 0 5/24/2021 435 95 434 210 0 0 5/23/2021 435 90 434 210 0 0 5/22/2021 435 95 435 200 0 0 5/21/2021 436 95 435 200 0 0 5/20/2021 435 90 435 190 0 0 5/19/2021 433 85 433 190 0 0 5/18/2021 420 75 433 185 0 0 5/17/2021 430 75 433 175 0 0 5/16/2021 425 80 433 175 0 0 5/15/2021 425 80 433 170 0 0 5/14/2021 425 75 433 175 0 0 5/13/2021 425 110 433 175 0 0 5/12/2021 425 105 433 175 0 0 5/11/2021 430 130 433 175 0 0 5/10/2021 430 130 433 460 0 0 5/9/2021 430 433 450 0 0 5/8/2021 430 437 440 0 0 5/7/2021 430 437 420 0 0 5/6/2021 422 438 395 0 0 5/5/2021 420 432 317 0 0 5/4/2021 410 412 317 0 0 5/3/2021 390 386 317 0 0 5/2/2021 358 353 317 0 0 5/1/2021 320 316 315 0 0 4/30/2021 244 239 315 0 0 4/29/2021 244 239 315 0 0 4/28/2021 215 210 315 0 0 4/27/2021 185 180 315 0 0 4/26/2021 154 149 315 0 0 4/25/2021 118 114 315 0 0 4/24/2021 70 65 315 0 0 4/23/2021 0 20 315 0 0 4/22/2021 0 20 315 0 0 4/21/2021 0 20 315 0 0 4/20/2021 0 20 315 0 0 4/19/2021 0 20 315 0 0 4/18/2021 0 20 315 0 0 4/17/2021 0 20 315 0 0 4/16/2021 0 20 315 0 0 4/15/2021 0 9 313 0 0 4/14/2021 200 56 313 0 0 4/13/2021 200 56 310 0 0 4/12/2021 200 4 310 0 0 4/11/2021 200 4 310 0 0 4/10/2021 207 4 310 0 0 4/9/2021 99 66 310 0 0 4/8/2021 75 61 310 0 0 4/7/2021 60 84 310 0 0 4/6/2021 409 409 310 0 0 4/5/2021 408 409 310 0 0 4/4/2021 408 409 310 0 0 4/3/2021 408 408 310 0 0 4/2/2021 408 408 320 0 0 4/1/2021 408 408 310 0 0 3/31/2021 408 408 320 0 0 3/30/2021 410 409 310 0 0 3/29/2021 410 409 310 0 0 3/28/2021 409 408 310 0 0 3/27/2021 409 408 310 0 0 3/26/2021 409 408 310 0 0 3/25/2021 408 408 310 0 0 3/24/2021 408 407 310 0 0 3/23/2021 408 408 310 0 0 3/22/2021 408 407 311 0 0 3/21/2021 407 406 312 0 0 3/20/2021 406 406 315 0 0 3/19/2021 407 406 316 0 0 3/18/2021 406 405 320 0 0 3/17/2021 406 406 330 0 0 3/16/2021 406 406 365 0 334 3/15/2021 236 409 170 0 0 3/14/2021 405 405 170 0 0 3/13/2021 405 405 170 0 0 3/12/2021 405 405 170 0 0 3/11/2021 405 405 170 0 0 3/10/2021 405 404 170 0 0 3/9/2021 405 404 170 0 0 3/8/2021 405 404 170 0 0 3/7/2021 405 404 170 0 0 3/6/2021 405 404 170 0 0 3/5/2021 405 404 170 0 0 3/4/2021 404 404 175 0 0 3/3/2021 404 404 175 0 0 3/2/2021 404 404 170 0 0 3/1/2021 404 404 170 0 0 2/28/2021 404 404 170 0 0 2/27/2021 404 404 170 0 0 2/26/2021 404 404 170 0 0 2/25/2021 404 404 170 0 0 2/24/2021 404 404 170 0 0 2/23/2021 404 404 170 0 0 2/22/2021 404 404 170 0 0 2/21/2021 404 404 170 0 0 2/20/2021 404 404 170 0 0 2/19/2021 404 404 175 0 0 2/18/2021 404 404 175 0 0 2/17/2021 403 403 175 0 0 2/16/2021 402 402 175 0 0 2/15/2021 402 403 170 0 0 2/14/2021 403 403 170 0 0 2/13/2021 403 403 170 0 0 2/12/2021 402 402 170 0 0 2/11/2021 402 402 175 0 0 2/10/2021 402 402 170 0 0 2/9/2021 402 402 170 0 0 2/8/2021 402 402 165 0 0 2/7/2021 400 401 165 0 0 2/6/2021 400 401 155 0 0 2/5/2021 400 401 155 0 0 2/4/2021 401 401 150 0 0 2/3/2021 401 401 145 0 0 2/2/2021 402 402 140 0 0 2/1/2021 402 401 130 0 0 1/31/2021 402 401 125 0 0 1/30/2021 403 402 98 0 0 1/29/2021 403 402 100 0 0 1/28/2021 403 402 101 0 0 1/27/2021 402 402 95 0 0 1/26/2021 402 401 82 0 0 1/25/2021 402 401 70 0 0 1/24/2021 401 401 70 0 0 1/23/2021 402 401 70 0 0 1/22/2021 401 401 70 0 0 1/21/2021 401 400 70 0 0 1/20/2021 401 401 65 0 0 1/19/2021 401 400 64 0 0 1/18/2021 401 400 62 0 0 1/17/2021 401 400 58 0 0 1/16/2021 401 401 88 0 0 1/15/2021 401 401 82 0 0 1/14/2021 401 401 85 0 0 1/13/2021 401 401 85 0 0 1/12/2021 401 401 82 0 0 1/11/2021 402 402 80 0 0 1/10/2021 402 402 75 0 0 1/9/2021 402 402 70 0 0 1/8/2021 403 402 65 0 0 1/7/2021 403 402 150 0 0 1/6/2021 403 401 150 0 0 1/5/2021 403 402 160 0 0 1/4/2021 402 402 175 0 0 1/3/2021 402 403 190 0 0 1/2/2021 402 401 84 0 0 1/1/2021 402 401 56 0 0 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Development Exploratory 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 16,720 feet 10,042 & 10,376 feet true vertical 12,941 feet N/A feet Effective Depth measured 3,588 feet See Schematic feet true vertical 3,378 feet See Schematic feet Perforation depth Measured depth 3,500 - 6,767 feet True Vertical depth 3,307 - 5,943 feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3 / L-80 6,867 MD 6,026 TVD Packers and SSSV (type, measured and true vertical depth)See Schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 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: Contact Name: Authorized Title: Contact Email: Contact Phone: TVD 407 measured true vertical Packer Other: Attempted to pull DGL 9-5/8" 5" 30" 10,377 MD 407 2,579 3,760 16,650 measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 1700 Casing Pressure STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 198-002 50-883-20093-01-00 Plugs ADL0017589 N Cook Inlet Unit B-01A 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-443 427 Authorized Signature with date: Authorized Name: 0 WINJ WAG 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 125 N/A Oil-Bbl 0 Water-Bbl Intermediate N/A Junk 5. Permit to Drill Number: 0 North Cook Inlet / Tertiary Gas & Undefined WSDPN/A measured 10,377 Size 438 Production Casing Structural Liner 6,576 Length 407 2,579 3,760 Conductor Surface 8,850psi 20" 13-3/8" 907 777-8376 10,900psi 2,511 3,515 8,841 12,896 Collapse 1,500psi Katherine O'Connor Katherine.oconnor@hilcorp.com Tubing Pressure 2,670psi 3,060psi 5,380psi Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Daniel E. Marlowe Operations Manager Burst PL G Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:59 am, Jul 06, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.07.06 08:34:31 -08'00' Dan Marlowe (1267) SFD 7/7/2021BJM 10/12/21 DSR-7/6/21 RBDMS HEW 7/8/2021 _____________________________________________________________________________________ Updated By: JLL 06/30/21 SCHEMATIC North Cook Inlet Unit Well: NCI B-01A Last Completed: 12/16/2003 PTD: 198-002 API: 50-883-20093-01 PBTD: 16,590’ TD: 16,720’ 30” RKB: 53.6’, RKB to MSL: 132’, RKB to Mudline: 232’ 5” 3 4 5 6 7 8 9 10 11 12 13 RA Collar 4,016’ 13-3/8” 9-5/8” 1 2 14 15 16 17Top of Tbg 8,052’ 20” 2-3/8”8” RA Collar 4,609’ RA Collar 4,881’ 18 20 21 Tag TOC in tubing @ 9,610’Calc. TOC in tubing x 9-5/8” @9,837’ XN X X X 19 CASING DETAIL Size Wt Grade Conn ID Top Btm 30” H-40 Weld 27.000 Surf 407’ 20” 133# K-55 BTC 18.730” Surf 2,579’ 13-3/8” 72# N-80 N-80 12.347” Surf 3,760’ 9-5/8” Tie-Back 53.5 P-110 BTC 8.535” Surf 3,588’ 9-5/8” 53.5 P-110 BTC 8.535’ 3,588’ 10,377’ 5” 19.5 S-135 4.5” IF 4.408“/3.25” 10,074’ 16,650’ TUBING DETAIL 5-1/2” 15.5 L-80 BTC-Mod 4.950” Surf 3,764’ 5-1/2” Combo Screens & Blanks 15.5 SLHT 4.950” 3,797 5,547’ 4-1/2” 12.6 IBT 3.958” 5,547 5,647’ 4” Combo Screens & Blanks 9.5 SLHT 3.548” 5,647 6,805’ 3-1/2” 9.3 L-80 IBT 2.992” 6,805 6,867’ 2” Coil Inner String ~2.51 HS-90-C BHISG 1.750” 3,567’ 6,817’ 4-1/2” 12.75 P-110 3.958” 8,052’ ±10,074’ Cuttings Disposal Tubing (2 strings) Dual 2-3/8” 4.7 N-80 CS Hydril 1.995” Surf 3,663’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 53.6’ 53’ 5.500” 10.750” Hanger – 10-3/4” x 5-1/2” VETCO 1 410’ 410’ 4.562” 7.500” SSSV – CAMCO TRM-4E w/ OTIS WLRSV (X Profile) 2 1,559’ 1,553’ 4.653” 7.962” GLM #1 – Camco MMG w/ dummy valve 3 2,675’ 3,598’ 4.653” 7.962” GLM #2 – Camco MMG w/ dummy valve 4 3,602’ 3,389’ 4.653” 7.962” GLM #3 – Camco MMG w/ 5/16” orifice valve 5 3,700’ 3,467’ 4.562” X-Nipple 6 3,764’ 3,518’ 6.000” 8.313” Baker SC-1R Packer, PBR, seals, MOE, seal bore & gravel pack sleeve 7 3,797’ 3,544’ 5.000” 7.650” Model C KOIV (Knock Out Isolation Valve) 3,800’ 3,547’ 4.950” 6.110” 5-1/2” 15.5# SLHT blanks & Screens (140 x 0.012ga.) 8 4,368’ 4,010’ 4.940” 8.125” Baker SC-1L Packer, seal bore & gravel pack sleeve 4,421’ 4,053’ 4.940” 8.125” 5-1/2” 15.5# SLHT blanks & Screens (140 x 0.012ga.) 9 4,969’ 4,495’ 6.000” 8.281” Baker SC-1R Sump Packer & MOE 4,985’ 4,508’ 4.892” 6.050” 5-1/2” 15.5# L-80 SLHT Blank 10 5,547’ 4,962’ 3.958” 6.060” Crossover 5-1/2” SLHT x 4-1/2” IBT 11 5,579’ 4,988’ 3.813” 5.230” X-Nipple 12 5,613’ 5,015’ 4.750” 8.329” Baker SC-2 Packer, S-22 Snap Latch, seal bore, & gravel pack sleeve 13 5,647’ 5,042’ 3.500” 5.650” Model C KOIV (Knock Out Isolation Valve) 5,650’ 5,044’ 3.548” 4.590” 4” SLHT Screen & Blanks (12 ga.) 14 6,787’ 5,960’ 6.000” 8.280” Baker SC-1R Sump Packer, S-22 Snap Latch, MOE 15 6,805’ 5,975’ 2.992” 6.050” Crossover 5-1/2” x 3-1/2” 16 6,836’ 6,000’ 2.813” 4.250” X-Nipple 17 6,867’ 6,026’ 2.992” 4.250” WLEG 18 8,052’ 6,984’ Fish – Cut top of 4-1/2” tubing 19 10,032’ 8,564’ Sliding Sleeve –PXN Plug @ 10,042 20 10,074’ 8,598’ Packer 21 10,376’ 8,840’ XN Nipple w/ PXN Plug in Nipple INNER STRING JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item Fish: 04/20/21 - UDGL Widepack Upper Packer pulled & fell to 3,588’ RKB 3,575’ 3,367’ 3.000” 4.500” Weatherford 450 Widepack Upper Packer 3,581’ 3,372’ 2.992” 3-1/2” Pup Joint 3,586’ 3,376’ 3.000” 3-7/8” Pup Joints 3,606’ 3,392’ N/A 4.420” Centralift AVE Sub w/ Dual Flapper Check Valve 3,606’ 3,392’ 2.875” 4.470” WP Anchor Seal Latch 3,609’ 3,394’ 0.875” 1.750” Stinger Rod w/ seal stack (6.90’) stung into PBR Seal Bore 3,610’ 3,395’ 3.000” 4.500” Weatherford 450 Widepack Lower Packer 3,616’ 3,400’ 3.476” 4.420” Slotted Sub 3,617’ 3,401’ 1.750” 4.420” PBR Seal Bore 3,619’ 3,402’ 1.375” 4.420” Torq-Thru Quick Connect - Upper 3,620’ 3,403’ 1.375” 2.875” Torq-Thru Quick Connect - Lower 3,620’ 3,403’ 3.000” 4.313” Tryton Max Frac Plug 6,049’ 5,367’ 1.375” 2.875” External Grapple Coil Connector 6,050’ 5,367’ 2.000” 2.600” PM-1 Gas Lift Mandrel 6,052’ 5,369’ 1.375” 2.875” Torq-Thru Quick Connect 6,817’ 5,984’ 1.750” 2.000” CT Dimple Connector 6,817’ 5,984’ 0.930” 2.375” injection sub 6,819’ 5,986’ bottom of injection string _____________________________________________________________________________________ Updated By: JLL 06/30/21 SCHEMATIC North Cook Inlet Unit Well: NCI B-01A Last Completed: 12/16/2003 PTD: 198-002 API: 50-883-20093-01 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status 3,500' 3,540' 3,307' 3,339' 40' 9/9/1997 Open 3,631' 3,632' 3,412' 3,413' 1' 3,850' 3,869' 3,587' 3,602'19'12/8/2003 Open 3,886' 3,893' 3,616' 3,621'7'12/8/2003 Open CI 1 4,185' 4,268' 3,859' 3,928'83'12/8/2003 Open CI 2 4,275' 4,365' 3,933' 4,007'90'12/8/2003 Open CI 4 4,429' 4,480' 4,060' 4,101'51'12/8/2003 Open CI 8 4,751' 4,761' 4,319' 4,327'10'12/8/2003 Open CI 8 4,792' 4,803' 4,352' 4,361'11'12/8/2003 Open CI 11 4,922' 4,955' 4,457' 4,484'33'12/8/2003 Open BELG-F 5,718' 5,742' 5,098' 5,118'24'12/1/2003 Open BELG-G 5,885' 5,892' 5,234' 5,239'7'12/1/2003 Open BELG-H 5,929' 5,939' 5,269' 5,278'10'12/1/2003 Open BELG-H 5,948' 5,969' 5,285' 5,302'21'12/1/2003 Open BELG-H 5,995' 6,032' 5,323' 5,353'37'12/1/2003 Open BELG-I 6,078' 6,091' 5,390' 5,400'13'12/1/2003 6,097' 6,107' 5,405' 5,413'10'12/1/2003 Open BELG-I 6,118' 6,124' 5,422' 5,427'6'12/1/2003 Open BELG-I 6,148' 6,158' 5,446' 5,454'10'12/1/2003 Open BELG-I 6,169' 6,182' 5,463' 5,473'13'12/1/2003 Open BELG-J 6,283' 6,290' 5,553' 5,559'7'12/1/2003 Open BELG-L 6,375' 6,390' 5,627' 5,639'15'12/1/2003 Open BELG-M 6,610' 6,622' 5,815' 5,825'12'12/1/2003 Open BELG-O 6,762' 6,767' 5,939' 5,943'5'12/1/2003 Open 9,970' 9,972' 8,514' 8,515'2'Isolated 16,080' 16,118' 12,525' 12,548'38'Isolated Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 No operations to report. Simops mtg w/ production. PJSM & permits. Waiting on boat to arrive. M/V Titan arrives at platform. Wait on helicopter green deck for SLU crew transfer to Granite Point. Offloading M/V Titan. Offload 500 bbl tank, 2 heaters & 6 pallets KCl spotting all on pipe deck. Offload return tank & gas buster & spot on drill deck. Offload BLU & ELU packages, perf guns, Quadco toolbox, metal dumpster, hose basket & scaffolding package. M/V Titan offloaded & away from platform. Lay down liner & plywood spotting N2 pump & tanks w/in liner, crib in liner for containment. Run hyd. lines to injector & BOP. Run hoses to batch mixer & 500 bbl tank. SDFN. Fly to beach. Job Suspended until 4/7/21. 04/03/21 - Saturday No operations to report. 04/06/21 - Tuesday 04/04/21 - Sunday No operations to report. 04/05/21 - Monday 04/02/21 - Friday Arrive OSK & fly to platform. Arrive platform. Platform orientation, pre-job safety meeting & permits. Waiting on boat. M/V Titan arrives @ platform. Offload M/V Titan. Spot CTU & 2" reel, fluid & N2 pump, 2 N2 tanks, C-pump, dog house, lubricator box, choke & reverese skid, iron rack, generator, gooseneck basket & injector on drill deck. Spot batch mixer on pipe deck. M/V Titan offloaded & away from platform. Start rigging up CTU. Run hyd. line from power pack to console & reel. Run electric line from generator to CT console. Run all data acquisiton lines. Run pump line from fluid pump to rev. skid & reel. Run kill line from choke manifold to well hatch. SDFN. Job in Progress. 04/07/21 - Wednesday Arrive OSK heliport. Fly to platform. Simops kick-off mtg w/ production. Platform orientation for 2 SLB. Pre-job safety meeting & permits. Return to CTU rig up. Spot heaters on drill & pipe deck. Fire up heater & start warming batch mixer & fluid pump. T/IA/OA/OOA = 400/400/20/0. 2-3/8" Injection Tubing Strings = 0. Production bleeding down IA lift gas pressure. MU gas buster to flowback tank & run flowback line. Thaw iced up fluid pump valve w/ heater unit. Stab 2" pipe in injector. Start BOP test. CTU data acquisition system crash & fail, lost all recorded test data. Trouble shoot data acquisition system. Test BOPE to Hilcorp & AOGCC standards & requirements. Witness waived (Jim Regg). Test 250/3500 body, blind/shear ram, stripper & valves. Fail Pipe/Slip ram 250 test. SDFN. Will continue in morning to troubleshoot & retest pipe/slip ram. Job in Progress. T/IA/OA/OOA = 61/85/320/0 Fail Pipe/Slip ram. Witness waived (Jim Regg). Test 250/3500 body, Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/08/21 - Thursday Simops mtg w/ production. PJSM & permits. Inspect combination pipe/slip ram. Fines & debris from prior job found in ram cavity & on ram body & rubber elements. Clean & removed all debris from pipe/slip ram assemblies & ram cavity. Complete BOPE test to Hilcorp & AOGCC standards & requirements. Pass retest of combination pipe/slip ram. Witness waived (Jim Regg). Test 250/3500. Submit BOPE Test report to AOGCC & save copy to O drive projects file. Mericka crew build scaffold work platform on drill deck around BOP WHA. Run heater trunk to 500 bbl tank & start warming tank. Shut down crane operations due to high wind speeds. Secure drill deck and pipe deck. Batch mixer internal temp = 80*F, continue w/ heat on batch mixer while bringing on 50 bbl of drill water. Roll drill water in batch mixer w/ paddles while continuing to heat to raise water temp prepping to blend 6% KCL KWF. Roll & heat batch mixer thru the night. SDFN. Job in progress. T/IA/OA/OOA = 150/120/320/0 04/09/21 - Friday Simops meeting w/ production. PJSM & permits. Weather standby waiting for wind speed decrease & return to crane operations. Blend 50 bbl 6% KCl. Continue to heat batch mixer & fluid while rolling the tank w/ paddle system. Wind speed decreases to allow crane operations to resume. PU injector & 3 sections of lubricator when strong wind gusts return. Lay down lubricator & return injector to drill floor securing injector. Weather standby, crane operations suspended for high winds. Continue to keep heat on batch mixer & 500 bbl tank. Roll 50 bbl of 6% KCL w/ batch mixer paddles. Wind speed still in excess of resuming crane operations. SDFN. Job in Progress. Pass retest of combination pipe/slip ram. Witness waived (Jim Regg). Test 250/3500. S Fines & debris from prior job found in ram cavity & on ram body & rubber elements. Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/10/21 - Saturday Simops mtg w/ production. PJSM & permits. Fire up CTU. PU injector & lubricator. MU Quadco/WFT BHA1: 2"CTC(2.88"x1.67'), DFCV(2.88"x1.41'), Intensifier(2.88"x4.37'), WB(2.88"x5.60'), WB(2.88"x5.60'), X- over(3.12"x1.00'), BI-DI Jar(3.13"x3.91'), X-over(3.12"x1.00"), Disco(2.88"x1.29'), X-over(3.10x1.00'), 5-1/2" WFT Spear(4.50"x2.50') OAL = 29.35'. Pull Test CTC = 25K. Press Test BHA1 = 4400. Disco Ball = 7/8",T/IA/OA/OOA = 140/66/320/0. Move to well. PT Lub, BOP & WHA = 545/4000. Open swab valve(35T). SSV fusible installed. RIH pumping min rate 6% KCl water. 2500' stop pump & continue TIH.3500' RIW = -1.2K, WT CHK = 1K. TIH to 3575' RKB tag & latch of WFT Upper DGL 450 Widepak packer assy. Straight pull to 20K, packer releases. PUH to 3540', PUW = 8K, FISH ON. RBIH to 3574", RIW = -4K. 6% KCL Lost to Formation = 29 bbl. Stack down on packer assy, RIW = -8K. Bring online fluid pump w/ 6% KCl @ 0.50 BPM (130 psi), work up to 2.30 BPM(744 psi) to shift spear & release Upper DGL 450 Widepak packer assy. PUH clean leaving Upper DGL packer assy in place for BLU to retrieve. Stop fluid pump & continue to POOH. Call out BLU crew. 6% KCL Lost to Formation = 17 bbl, OOH, close swab(35T). Freeze protect CT & surface lines. RD laying down BHA1, lubricator & injector. Secure injector & BOP/WHA. Stand back CTU Production bleeding IA pressure to flair. BLU crew arrives platform. T/IA/OA/OOA = 145/62/320/0. Total 6% KCl Lost to Formation = 46 bbl. BLU PJSM & permit. Spot BLU & grease skid on drill deck. Build lubricator stand. Mount bottom shieve. Mericka Techs modify scaffold work platform to raise work platform 1 level. Lay out 70' of 7" & 3- 1/2" BLU lubricator. MU grease skid hoses to grease head. Lay out & MU fishing tools in prep for 450 Widepak packer fish & retrieval run. Replace all bowen O-rings. MU WLV to BOP/WHA & nite cap WLV. Stop BLU rig up to work boat. Fly BLU crew to Granite Point to support Rig 404. Will fly 2nd BLU crew out in morning. SDFN. Job in Progress. 04/11/21 - Sunday Simops mtg w/ production. Waiting on BLU crew. BLU crew arrives platform. Platform orientation. PJSM & permits. Resume BLU RU. PU 35' of 3-1/2" lubricator + 47' of 7" lubricator. MU 1-3/4" TS: RS, 15' Stem, KJ, OJ, LSSJ, 4-1/2" GS spear, Bait Sub, 5-1/2" WFT Widepak spear. Move to well. PT WLV & Lub = 250/1500 - Fail. Plug all needle valves, Repeat PT @ same - Pass, Initial T/IA/OA/OOA = 200/3/320/0. RIH to 3500, WT CHK = 1450#. TIH to 3551' SLM & latch upper DGL packer. Work TS w/ 6 jar licks, 3400# - 4600'. 4-1/2" GS brass pin shears w/ 4600# jar lick. POOH. Leave baited 5-1/2" WFT Widepak spear latched in upper DGL packer. OOH, lay down sheared 4-1/2" GS & MU 4- 1/2" GS pinned w/ steel. RIH w/ 2nd 4-1/2" GS pinned w/ steel to 3548' SLM. Worked tools, unable to latch back into bait sub. POOH. 4-1/2" GS spear steel pin is not sheared. Redress & pin 1st run 4-1/2" GS w/ steel. RBIH to 3548' SLM. Work tools, unable to latch baited 5-1/2" WFT Widepak spear/upper DGL packer. POOH. Steel pinned 4-1/2" GS is not sheared. Add 4.50" centralizer to toolstring. RIH w/ 1-3/4" TS + 4.50" centralizer & 4-1/2" GS dressed w/ steel pin to 3548' SLM. Work tools w/ same. Unable to latch back into baited 5-1/2" WFT Widepak spear. POOH. Lay down 7" & 3-1/2" lubricator. Secure well & drill deck. Call PWL shop for tools, fly tools to platform in AM. SDFN. Job in Progress. Final T/IA/OA/OOA = 200/3/320/0 Unable to latch back into baited 5-1/2" WFT Widepak spear. Straight pull to 20K, packer releases. Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/12/21 - Monday Simops mtg w/ production. PJSM & permits. RU BL. MU 35' of 3-1/2" lub + 47' of 7" lub. PT = 250/1500, leak @ 7" O- ring connection on 7" lub. Replace O-ring. Retest - GOOD. RIH w/ 1-3/4" TS + 4.5" Cent & 4-1/2" PRGS w/ 1.75" swedge to 3545' SLM. Work tools, getting 100# friction bites but will not latch. POOH. Remove 1.75" swedge. Add 1.30" swedge. RBIH to 3545' SLM. Work tools, w/ same. Getting slight friction bites but unable to latch. POOH. Remove 1.30" swedge & modify swedge. RBIH w/ 1-3/4" TS + knuckle joint & 4-1/2" PRGS w/ modified 1.30" swedge to 3545' SLM. Work tools, would not latch & no friction bites. POOH. RBIH w/ 4-1/2" Cent + 4" LIB to 3545' SLM. Hit 1 time, POOH. OOH 2/ impression of sand. RBIH w/ 3" x 4' DD Bailer to 3545' SLM. Work tools. OOH w/ full bailer of sand & scale. RBIH to 3546' SLM. Work tools, OOH w/ full bailer of sand & scale. RD 85' of lubricator. Secure drill deck & well room. SDFN. Job in progress. 04/13/21 - Tuesday Simops mtg w/ production. PJSM & permits,T/IA/OA/OOA = 165/3/320/0 - Production flows & bleeds tubing down, T = 60. Clear drill deck of BLU lubricator & tools. Pull WLV off BOP. M/V Titan arrives. Work boat offloading 6 pallets of KCl. RU CTU. PU injector & lubricator. MU BHA2: 2"CTC(2.88" x 1.67'), DFCV(2.88" x 1.41'), WB(2.88"x5.60'), WB(2.88"x5.60'), X-over(2.88"x0.50'), X-over(2.12"x0.25'), Jet Swirl Nozzle (2.51""x0.83') OAL = 15.86'. PT BHA = 3500. Move to well. PT LUB & WHA = 3500. Initial T/IA/OA/OOA = 60/3/320/0. RIH @ 50 FPM w/ JSN BHA. 500' start pumping 6% KCl @ 1.5 BPM washing tubing while TIH. WHP = 30, 1:1 returns. Continue in hole to 1000' & lose returns, WHP = 0. 1500' WT CHK = -6K, inc PR = 1.70 BPM, PP =247, WHP = 0 w/ no returns. TIH 50 FPM washing tubing, RIW = -8K. 2470' WT CHK = -3.5K. Inc PR = 2.30 BPM, PP = 471, WHP = 0 w/ no returns. TIH 50 FPM washing tubing. 3000' Inc PR = 3.1 BPM, PP = 1462, WHP = 32, 1:3 returns to surface. IA = 140 , T X IA communication. 3350' PR = 3.10 BPM, PP = 1462, WHP = 32, IA = 140 w/ 1:1 returns. 3450' WT CHK = -3.5K,3555' Top of Fish. PR = 3.10 BPM, PP =1552, WHP =90, IA = 165 w/ 1:1 returns. Circulate on top of fish. Wash to 3556'. Start shipping returned fluid in FB tank to production. Dec PR = 2.5 BPM, PP = 1060, WHP = 44, IA = 165 w/ 1:1 returns. 1/2 BU pumped circulating on top of fish, POOH @ 80% pumping 2.5 BPM KCl. 1624' PR = 2.5 BPM, PP 885, WHP = 24, IA = 145 w/ 1:1 returns. Chase returns to surface @ 80%. Return to surface. SD pump. T/IA/OA/OOA = 30/70/320/0. Close swab. Freeze protect CT. Ship all returned fluid in FB tank to production. Freeze protect surface lines. RD & stand back CTU. Total pumped KCl = 372 bbl. 6% KCl Lost to Hole = 147 bbl,PJSM & permit. RU BLU. MU WLV to BOP/WHA. PU lubricator & 1-3/4" TS w/ 4.5" Cent & 4-1/2" GR. Move to well. PT WLV & LUB = 250/1500. RIH to 3500' WT CHK = 1100#. Continue in hole to 3545' SLM, work tools w/ friction bites up to 1600#. Unable to latch fish. POOH. Sand packed inside of GR spear. RBIH w/ 4.50" Cent + 4" LIB to 3545' SLM. 1 HIT. OOH w/ clear impression of sand. RBIH to 3545' SLM w/ 3" x 4' DD Bailer. Work tool. OOH w/ bailer full of sand. RBIH to 3546' SLM. OOH w/ bailer full of sand. RBIH to 3547' SM. OOH w/ bailer full of sand. RBIH to 3548' SLM. OOH w/ bailer full of sand. RD SLU. Secure well & drill deck. SDFN. Job in Progress. OOH w/ full bailer of sand & scale. OOH w/ clear impression of sand. Wash to 3556' Seems like sand is flowing into the well from above, possible crossflow from somewhere? RU CTU. OOH w/ bailer full of sand. RU BLU. POOH. Sand packed inside of GR spear. Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/14/21 - Wednesday Simops mtg w/ production. PJSM & permits. RU BLU. Top sheave spun & twisted wire. LD lub, cut wire & re-head rope socket. Move to well. PT = 250/1500,T/IA/OA/OOA = 0/60/320/0. RIH w/ 1-3/4" TS + 4.50" Cent w/ 3" x 10' DD bailer, fluid top @ 705'. Production bleeding off IA. Continue TIH to 3545' SLM' (3589' RKB). Work tool, POOH full of sand. RBIH w/ 3" x 10' pump bailer to 3546' SLM. Work tool, POOH w/ 2' of sand. RBIH w/ 3" x 4' DD bailer to 3547' SLM. Work tool, POOH full of sand. RBIH w/ 3" x 4' DD bailer to 3548' SLM. Work tool, POOH full of sand. T/IA = 0/4. RBIH w/ 3" x 4' DD bailer, fluid top @ 790'. Contiue TIH to 3548' SLM. POOH, OOH w/ bailer flapper stuck open, bailer empty. RBIH w/ 2.61" Hydrostatic bailer to 3548' SLM (3592' RKB). Work tool, PUW = 2000#, pull free. POOH, OOH w/ bailer flapper broke & empty bailer. RBIH w/ 2.61" hydrostatic bailer to 3544' SLM (3588' SLM). Appear to have lost hole after previous run. Work tool, no overpull on PU. POOH, OOH w/ broken flapper & empty bailer. RBIH w/ 4.50" Cent + 4-1/2" GR spear to 3544' SLM (3588' RKB). Work tool, unable to latch fish (bait sub & WFT Widepak packer spear). POOH. LD & stand back BLU. secure well & drll deck. SDFN. Job in progress. T/IA/AO/OOA = 0/4/320/0 04/15/21 - Thursday Simops mtg. w/ production. PJSM & permits. BOPE Test to Hilcorp & AOGCC standards & requirements. Witness waived (Jim Regg). Test 250/3500. Submit BOPE Test report to AOGCC & save copy to O drive projects file. RU CTU. PU injector & lubricator. MU BHA3 to disconnect. PT BHA = 3500. Waiting on Itco spear fishing tool to arrive. Initial T/IA/OA/OOA = VAC/5/340. MU BHA3: 2" CTC(2.88"x1.67'), DFCV(2.88"x1.41'), X-over(3.12"x1.00'), Bi-Di Jar(3.13" x 3.91'), X-over(3.12"x1.00"), Disco(2.88"x1.29'), XRV(2.88"x1.29'), 4" JPP spear(3.49" x 1.90'), 4" bait Sub(3.700"x0.64'), Cent(3.75"x1.79'), X-over(2.89"x0.42'), X-over(2.00x0.67'), X-over(1.75"x0.79'), Itco spear(1.70"x1.69' w/ 1.929" grapple) OAL = 19.81'. Disco ball = 7/8". Move to well. PT LUB & BOP = 3500. RIH w/BHA3 to 3500 WT CHK = 0K. RIW = -4.5K. TIH to tag @ 3555' CTM (3590' RKB). Stack down -6K. Bring F. pump on @ 1.90 BPM, work XRV tool stack down -5K. Stop pump. PUH, PUW = 2K. RBIH stack down -8K. Work XRV tool @ 2 BPM, stack down -14K. Stop pump. PUH to 2.7K wt break, hanging wt = 1K. RBIH work XRV tool to -18K. PUH, PUW = 1K pulling free. POOH. OOH, MISSED RUN. Metal mark 6" up spear. 39 bbl 6% KCl pumed & lost,T/IA = 0/50. RBIH w/ BHA3 to 3500' WT CHK = -2K. TIH to tag @ 3554' CTM. Stack down -5K. Work XRV tool 1.90 BPM. Stop pump, PUH w/ no overpull. Continue working XRV to 3559' CTM (3594' RKB). Catch 1:1 returns @ surface w/ 10 bbl away. PUH w/ no overpull. POOH. OOH, MISSED RUN. 44.7 bbl 6%KCl pumped. RD & standback CTU. Freeze protect coil & surface lines. SDFN. Job in Progress. 6% KCl lost to hole = 49 bbl. Final T/IA/OA/OOA = 0 /55/340/0 RU CTU. RD & standback CTU. Work tool, unable to latch fish Appear to have lost hole after previous run. W RU BLU. Top sheave spun & twisted wire. Work tool, POOH full of sand. T Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/16/21 - Friday Simops mtg w/ production. PJSM & permit. Initial T/IA/OA/OOA = 0/0/340/0. Fire up & RU CTU package. PU inj. & lubricator. MU BHA4: 2" CTC(2.88"x167'), DFCV(2.88"x1.41'), Intensifier(2.88"x4.37'), WB(2.88'x5.60'), WB(2.88'x5.60'), X-over(3.12"x1.00'), BI-DI Jar(3.13"x3.91'), X-over(3.12"x1.00'), Disco(2.88"x1.29'), Screen (2.88"x2.69'), Tempress(2.88"x2.69'), X-over(2.88"x0.58'), X-over(2.12"x0.50'), PRGS(3.65" 1.62', 3/4" SR pin) OAL = 33.93'. PT =3500 Disco Ball = 7/8". Move to well. PT Lub & BOP/WHA = 3500. Open Swab. RIH BHA4 to 3554' CTM (3589' RKB) tag depth. Pump online w/ 6% KCL @ 2.0 BPM. Work toolstring attempting to dig. Stacking weight, unable to dig forward. Continue to work tool string, no overpulls on pickup, no indication of latch to fish. No returns, well on vac. Stop pump. POOH. OOH, FISH ON, retrieved WFT WP spear & PWL bait sub. Pumped & Lost 91 bbl 6% KCl to hole. MU BHA5: 2" CTC(2.88"x167'), DFCV(2.88"x1.41'), Intensifier (2.88"x4.37'), WB(2.88'x5.60'), WB(2.88'x5.60'), X-over(3.12"x1.00'), BI-DI Jar(3.13"x3.91'), X-over (3.12"x1.00'), Disco(2.88"x1.29'), Screen(2.88"x2.69'), Tempress(2.88"x2.69'), 4" JPP spear(3.49"x1.90'), Bait sub(3.70"x0.64'), 5-1/2" WFT WP spear(4.50" x2.50') OAL = 37.27'. RBIH BHA5, baited WFT WP retrieval spear to 3554' CTM. Pump 6% KCl @ 2.1 BPM, work Tempress tool to latch WFT spear in 4.50 Widepak packer profile. Stop pump, PU w/ no overpull. Repeat same, no overpull, unable to latch. Multiple attempts to stack & Tempress hammer into profile @ 3554'. Unable to latch. OOH. LEFT IN HOLE: BAIT SUB & WFT WP SPEAR. 98 bbl 6% pumped. 10 bbl returned & shipped to production. BHA6: 2" CTC(2.88"x167'), DFCV(2.88"x1.41'), Intensifier(2.88"x4.37'), WB(2.88'x5.60'), WB(2.88'x5.60'), X- over(3.12"x1.00'), BI-DI Jar(3.13"x3.91'), X-over(3.12"x1.00'), Disco(2.88"x1.29'), Screen(2.88"x2.69'), Tempress(2.88"x2.69'), 4" JPP spear (3.49"x1.90') OAL = 33.13'. RBIH w/ BHA6 to 3553' CTM dry tag. Stack down & PU. Repeat 4 times . POOH. OOH, NO FISH, missed run. RBIH w/ BHA6 to 3547'CTM. Pump online w/ 6% KCL, Stack down & Tempress hammer. PR = 2.1 BPM, PP = 2200. Pump 10 bbl & catch 1:1 returns @ surface. WHP = 37, IA = 40 & increasing. Continue to pump while stacking down weight & hammering, PP inc = 3200. Stop pump. POOH. OOH w/ FISH ON. 32 bbl 6% KCl pumped w/ 22 returned to surface & shipped to production. RD standback. secure CTU, well & deck. SDFN. Call for tools, motor & mills for tubing scrape & clean run. Job in progress. Total 6% KCl pumped = 231 bbl. 198 bbl lost to hole. Final T/IA/OA/OOA = 0/20/315/0. OOH, FISH ON, retrieved WFT WP spear & PWL bait sub. POOH. OOH w/ FISH ON. Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/17/21 - Saturday Simops mtg w/ production. PJSM & permit. Waiting on boat for KCl & tools & helicopter for tool hand. PU injector & lubricator. MU BHA 7 to disconnect. Move to well & secure while waiting for tools & toolhand. Tool hand arrives. Waiting on boat. M/V Endeavor arrives. Offload KCl & tools & 12 pallets KCl. MU Quadco / Yellowjacket BHA7: 2" CTC(2.88"x1.67'), DFCV(2.88x1.41'), Disco(2.88x1.29'), Circ Sub(2.88"x2.14'), Motor (2.88"x12.00'), 5 blade mill(4.52"x0.87') OAL = 19.38. PT BHA = 3500. Disco Ball = 7/8". Circ Sub Ball + 5/8" Move to Well. PT Lub & BOP/WHA = 3500,T/IA/OA/OOA = 0/0/320/0. RIH w/ motor & 4.52" 5-blade mill to 500'. Pump @ 2.90 BPM, TIH @ 65 FPM filling hole w/ 6% KCl. Stop pump & motor , all passes, 30' above & below 1559' & 2675' GLVs. TIH tbng scraping filling hole. 2800', 150 bbl KCl away returns to surface. WHP = 49, IA = 148. Mill/Scrape @ 60 FPM & 2.90 BPM to 3520'. Pump 5 bbl gel sweep, dec PR = 0.75 bpm, soft tag/stall @ 3555' CTM (3590' RKB) top of pkr, PU 3554' CTM, circ 5 bbl gel out & above CT. PUH chasing gel sweep @ 70 FPM to 1000', PR = 2.90 BPM, WHP = 34, IA = 125. RBIH PR = 2.90 BPM, TIH 60 FPM, PP = 1804, WHP = 44, IA = 140, 1:1 returns. Pump 5 bbl gel @ 2200', continue TIH same to 3552'. M/V Endeavor arrives. Offload 2 totes Oilsafe AR & platform takes on 40,000 gal. drill water. Pump 10 bbl gel + 5 bbl 6% KCl . Drop 5/8" ball & circ on seat to circ sub @ 2.0 BPM. Ball on seat, 300 psi inc, shift circ sub. POOH 60 FPM chasing gel to surface. Identifiable solids in returns as CT approaches surface. Pull into lub, SD pump. Close Swab. LD BHA, recover ball from sub. Secure CTU, drill deck & well. SDFN. Job in Progress. T/IA/OA/OOA = 5/84/315/0. 560 bbl 6% KCL pumped w/ 150 bbl to hole. 15 bbl gel pumped. RIH w/ motor & 4.52" 5-blade mill to 500'. shift circ sub. POOH 60 FPM chasing gel to surface. Identifiable solids in returns as CT approaches surface. Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 04/18/21 - Sunday Simops mtg w/ production. PJSM & permits. RU CTU. MU BHA8: 2" CTC(2.88"x167'), DFCV(2.88"x1.41'), Intensifier (2.88"x4.37'), WB(2.88'x5.60'), X-over(3.12"x1.00'), BI-DI Jar(3.13"x3.91'), X-over(3.12"x1.00'), Disco(2.88"x1.29'), Screen(2.88"x2.69'), Tempress(2.88"x2.69'), X-over(3.10"x1.00'), 5-1/2" WFT WP PT(4.50"x2.50') OAL = 29.13'. PT BHA = 3500. Disco Ball = 7/8". Move to well. PT Lub & BHA = 3500, Initial T/IA/OA/OOA = 0/0/320/0 tubing on vacuum. Open swab & RIH w/ 5-1/2" WFT WP PT to 3513' WT CHK = 10K pumping min rate 6% KCL. RIW = 5K. TIH to 3556' CTM top of Widepak packer. PUH & bring on pump @ 2.6 BPM. RBIH to top packer, stack wt. Stop pump. PU, w/ 1-2K over pull. Continue to hammer @ 2.6 BPM trying to latch. NO overpulls on PU. PUH 40', RBIH @ 80FPM stack weight down. No Love. Repeat w/ same. POOH. No Fish. Call out Yellowjacket toolhand. RBIH w/ venture tool BHA (BHA9) to 3556' CTM (3591' RKB). Lay in 1 bbl of Oilsafe AR. Allow to soak for 30 minutes. Venturi to 3560' RKB. PUH 15', SD pump. RBIH to 3557' dry tag. Bring up pump, unable to dig. SD pump. POOH. OOH w/ full venture of scale. Empty & clean venture for next run. WFT Tech redress WFT WP PT. Waiting on crane to offload M/V Endeavor. Take on 475 bbl water from M/V Endeavor. RBIH w/ venture BHA. 3500' WT CHK = 10K. RIW = 3K Dry tag @ 3557' CTM. Venturi to 3560' CTM. SD pump. PUH 10'. RBIH to 3560' dry tag. POOH. OOH. Wait on crane to backload M/V Titan. Break off well, venture full of scale. Empty & clean venture. RBIH to dry tag @ 6549' CTM. Start pump, venturi wash past 6549' easily. Continue venturi washing to 6560' CTM. SD pump, PUH 10'. RBIH to 3560' CTM dry tag POOH. OOH w/ full venturi. LD venturi. MU WFT WP PT BHA. RIH w/ WFT WP PT BHA to 3500 WT CHK = 10K, RIW = 5K. Continue TIH to 3547' CTM (3582' RKB) dry tag depth. Stack down to 0K string weight. PU free. RBIH pumping 2.0 BPM, stack down to -5K string weight. PUH, PUW = 25K. RBIH to -5K to set pulling tool. PUH to 42K & pull free. PUH @ 13 K. Appear to have Upper DGL 4.50 Widepak packer assy. Trip out to 374' CTM (409' RKB), pull 6K over string weight. Stop, RBIH 20',394' CTM, PUH & overpull @ 374' CTM (409' RKB). Unable to pull thru TRSSSV (410' RKB). Pump 6% KCL @ 4.5 BPM attempting to pump open TRSSSV safety valve while attempting to work tools & fish thru TRSSSV. Unable to pass. RBIH to 1450' & trip out tagging @ same. Multiple repeats, unable to pass. Correlate tools & packer depth to schematic RKB depths. Appears that packer is not passing TRSSSV 4.562" ID profile. Depth correlation appears that BHA & pulling tool are above TRSSSV 4.562" profile. RBIH to 430' RKB. Set pipe/slip rams & manually lock rams. Set reel & injector brake. SDFN & night watch CTU. Job in Progress. T/IA/OA/OOA = 0/4/320/0. 211 bbls 6% KCl pumped & lost to formation. Appear to have Upper DGL 4.50 Widepak packer assy. Unable to pull thru TRSSSV (410' RKB) RBIH to 3560' CTM dry tag POOH. OOH w/ full venturi. OOH w/ full venture of scale. E . No Fish. Appears that packer is not passing TRSSSV 4.562" ID profile. Break off well, venture full of scale. Rig Start Date End Date CTU 4/2/21 4/20/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-01A 50-883-20093-01-00 198-002 PJSM & permit. 430' RKB Open pipe/slip rams. PUH, PUW = 6k. Hang up @ 410' RKB @ 12K. Unable to pass. RBIH to 3300' & POOH. Pull solid 410' RKB TRSSSV @ 15 K. Unable to pass. RBIH to 430' RKB'. Pump 53 bbl 6% KCl to wash packer. PUH to 410' RKB @ 25K, 20K overpull, unable to pass. Make 3 passes 3300' & back to 410' RKB pull solid into TRSSSV @ 20K, unable pass. Not sticky when RBIH on any PUH into the TRSSV. Call for friction reducer. Waiting on friction reducer. Friction reducer arrives. Blend 10 bbl friction reduce 6% KCL. 450' RKB RIW = -1.2K, PUW = 2K,420' RKB pump 50 bbl 6% KCl @ 4.80 BPM to CT x TBG annulus. PUH to 410' RKB, 56 bbl ^% KCl away pump 10 bbl (9.5 BBL 6% KCL + 1/2 BBL NXS-Lube). Stop pump & let fluid fall while pulling into 4.50 Widepak packer into TRSSV. Work up to 35K, no pass & -11K to RBIH. PUH working up to 40K, no pass & -15K to RBIH. PUH to 45K, no pass & 25K unable to RBIH. PUH to 42K & pull free. PUW = 2K. POOH. Swab check from 100'. Close swab 35T, no fish. Stand back from well, OOH w/ all tools & WFT PT sheared. WFT toolhand redress PT. MU BHA w/ 3.56" Cent & 1.75" DJ nozzle. Move back to well, PT =3500. RBIH to tag top of Widepak pkr. 430' RKB TIH, pkr fell. Continue RBIH to dry tag @ top of pkr @ 3591' RKB. POOH. OOH. Secure well, drill deck & CTU. SDFN. Job in Progress. T/IA/OA/OOA = 0/0/320/0. 127.5 bbl KCL pumped & lost to hole. 0.5 bbl NSX-Lube pumped & lost to hole. 04/20/21 - Tuesday Simops mtg w/ production. PJSM & permit. RU CTU. MU BHA w/ WFT WP PT. Move to well, PT =3500. Open swab & RIH to 3500' WT CHK = 11K, RIW = 8K. TIH to 3584' RKB dry tag. Stack down to 0K to latch 450 widepak packer, PU free. RBIH to same, stack down to -5K. PU, PUW =13K, appear to have latched packer. POOH Tripping out, PUW = 12 - 13K. Hang up @ 410' RKB. Fish on. 410' RKB Pull up to 20K, start F. pump & ramp up to 2.50 BPM 6% KCl. Hammering up w/ Tempress, PR = 2.5 BPM. PP = 2800, WHP = 0, no returns. Maintain 20K PUW to keep WFT PT pulled into packer FN & prevent pump off & release. Pump & hammer for 30 minutes. Stop pump & SD for 10 minutes to minimize potential of harmonic resonance frequency damage to CT @ injector gooseneck. 410K RKB PU to 30K. Start F. pump @ 2.5 BPM & resume hammering up w/ Tempress. PP inc = 3600. Hammer for 15 minutes & pull free. POOH checking for tools. Swab check from 100' to surface. Close swab 35T, NO FISH. Rig off WHA, WFT PT collets damaged & wiped off face of spear. Remove WFT PT & MU 3.56" Cent & 1-3/4" DJ nozzle. RBIH w/ 3.56" Cent & DJ nozzle. 430' TIH free, packer fell from TRSSSV @ 410' RKB. Continue TIH to dry tag @ top of UDGL widepak packer @ 3588' RKB. POOH. 101 bbl 6% pumped & lost to hole. JOB SUSPENDED. RD CTU & prep for backload of 2" reel to boat. 04/19/21 - Monday Close swab 35T, resume hammering up w/ Tempress. Hang up @ 410' RKB. Fish on. 4 packer fell from TRSSSV @ 410' RKB. no fish. S B pull solid into TRSSSV @ 20K, unable pass Hammer for 15 minutes & pull free. POOH checking for tools. Swab check from 100' to surface. Close swab 35T, NO FISH. 1 Juanita Lovett From:McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent:Monday, June 7, 2021 11:52 AM To:Katherine O'connor Cc:Juanita Lovett Subject:[EXTERNAL] RE: NCI B-01A PTD 198-002 Coil Sundry Thanks Katherine. Don’t worry that you are past 30 days from your last work on this well because you were still planning to complete the approved work until now. Please submit the 10-404 for the work that you’ve done so far within 30 days from today. You can attach this email to the 10-404. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Katherine O'connor <Katherine.Oconnor@hilcorp.com> Sent: Monday, June 7, 2021 11:08 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: NCI B-01A PTD 198-002 Coil Sundry Hi Bryan Hilcorp has decided to forego intervening on B-01A anymore this year and will move forward with submitting a sundry closeout. This is outside of the 30 day window. We suspended operations on step 5, after we were unable to get the weatherford upper packer assembly out of the well. Previous thoughts were that we would be submitting a sundry revision, and then continue on with the original scope of the sundry, but those plans will not happen within the year. Thank you Katherine O’Connor CIO Operations Engineer Katherine.oconnor@hilcorp.com W: (907) 777-8376 C: (214) 684-7400 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. Wallace, Chris D (CED) From: Julie Wellman - (C) <Julie.Wellman@hilcorp.com> Sent: Thursday, April 22, 2021 10:43 AM To: Wallace, Chris D (CED) Subject: NCIU B -01A (PTD# 198-002) Pump -in Differential Temperature Log - March 2021 Attachments: NCI B -01A Schematic 2020-10-13.pdf; B -01A Temp survey 3-15-2021.xls Hello Chris, On 3-16-2021, a pump -in survey was performed on producer/disposal injector B -01A (PTD #198002) per Rule 4 of DID 33. The injection survey was performed ahead of schedule to take advantage of the well being shut-in until April wellwork is complete. This will eliminate the need to shut in production in August when the previous temp survey would have expired. As in previous years, the logging tools were run through the 5-1/2" tubing string while water was injected down the 2- 3/8" disposal strings. A baseline pass was made with the well shut in, then a flowing survey performed after 150 bbl of injection. The survey was run to a depth of 3605' to ensure the log captured injection into the perforations at 3500'- 3540' MD. Like the 2019 survey, cooling is shown only at the desired perf interval, indicating that all injection is confined to the approved disposal strata. Please see the attached wellbore schematic and survey. Please contact me if you have questions. Thank you, Julie Wellman Regulatory Tech — Hilcorp Alaska, LLC o: 777-8505 1 c: 360-265-4397 Julie. Wellman(a,hilcorp.com 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. 0 250 500 750 1000 1250 1500 1750 2 t 2000 Q. d 2250 2500 2750 3000 3250 3500 3750 30 410 Pressure (psia) 420 430 440 450 460 470 40 50 60 70 80 Temperature (Deg. F) — Perfs o Valve 30" 20" 13 3/8" 9 5/8" —TBG " x Packer Press Inj 21 —2019 Temp Temp Inj 21 Report date: 4/26/2021 l 9g 00 z0 u :l ....... %A/..II. 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ŶŐŝŶĞĞƌ͗<ĂƚŚĞƌŝŶĞK͛ŽŶŶŽƌ ;ϵϬϳͿϳϳϲͲϴϯϳϲ;KͿ ;ϮϭϰͿϲϴϰͲϳϰϬϬ ;DͿ ^ĞĐŽŶĚĂůů ŶŐŝŶĞĞƌ͗<ĂƌƐŽŶ<ŽnjƵď ;ϵϬϳͿϳϳϳͲϴϰϯϰ ;KͿ ;ϵϬϳͿ ϱϳϬͲϭϴϬϭ ;DͿ Current Bottom Hole Pressure: 763 psi @ 4641’ TVD 0.164 lbs/ft Maximum Expected BHP:1085 psi @ 4720’ TVD 0.23 lbs/ft Maximum Potential Surface Pressure: 977 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ƌŝĞĨtĞůů^ƵŵŵĂƌLJ ͲϬϭŝƐĂŐĂƐƉƌŽĚƵĐĞƌƚŚĂƚŝƐƉƌŽĚƵĐŝŶŐĨƌŽŵƚŚĞŵĂũŽƌŝƚLJŽĨƚŚĞ^ƚĞƌůŝŶŐƐĞĐƚŝŽŶĂŶĚ>ŽǁĞƌĞůƵŐĂƐĂŶĚƐ͘/ƚƐƌĂƚĞ ŚĂƐďĞĞŶƐĞǀĞƌĞůLJĚĞĐƌĞĂƐŝŶŐŽǀĞƌƚŚĞůĂƐƚLJĞĂƌ͘dŚŝƐǁĞůůŝƐĐŽŵƉůĞƚĞĚǁŝƚŚĂĚĞĞƉŐĂƐůŝĨƚĚĞƐŝŐŶƚŽůŽǁĞƌƚŚĞůŝĨƚ ƉŽŝŶƚ͕ǁŚŝĐŚƚƌĂŶƐĨĞƌƐůŝĨƚŐĂƐĨƌŽŵƚŚĞůŽǁĞƌŵĂŶĚƌĞů͕ĚŽǁŶĂŶĚŽƵƚĂĐŽŝůĞĚƚƵďŝŶŐƐƚƌŝŶŐĚĞĞƉĞƌŝŶƚŚĞǁĞůů͘dŚĞ ŽďũĞĐƚŝǀĞŽĨƚŚŝƐƉƌŽŐƌĂŵŝƐƚŽĂĚĚƉĞƌĨŽƌĂƚŝŽŶƐŝŶƚŽƚŚĞĞůƵŐĂĂŶĚƐĂŶĚƐ͕ǁŚŝĐŚǁŝůůƌĞƋƵŝƌĞƉƵůůŝŶŐĂŶĚƌĞƐĞƚƚŝŶŐ ƚŚĂƚĚĞĞƉŐĂƐůŝĨƚĚĞƐŝŐŶ͘ WƌŽĐĞĚƵƌĞ͗ ϭ͘ D/ZhdhĂŶĚǁŽƌŬƉůĂƚĨŽƌŵ x dĞƐƚKW^ƚŽϮϱϬϬƉƐŝͬϮϱϬƉƐŝ;EŽƚĞ͗EŽƚŝĨLJK'ϰϴŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨƚĞƐƚƚŽĂůůŽǁ ƚŚĞŵƚŽǁŝƚŶĞƐƐƚĞƐƚͿ͘ Ϯ͘ hŶƐƚŝŶŐƵƉƉĞƌƉĂĐŬĞƌĂƐƐĞŵďůLJ ϯ͘ ZdhǁͬŽďƌĞĂŬŝŶŐŽĨĨKWƐŝĨƉŽƐƐŝďůĞ ϰ͘ ZhƌĂŝĚĞĚůŝŶĞ͕WdůƵďƌŝĐĂƚŽƌƚŽϭϱϬϬƉƐŝͬϮϱϬƉƐŝ ϱ͘ WƵůůƵƉƉĞƌƉĂĐŬĞƌΘũĞǁĞůƌLJĂƐƐĞŵďůLJĚŽǁŶƚŽƚŚĞůŽǁĞƌƉĂĐŬĞƌ ϲ͘ ZďƌĂŝĚĞĚůŝŶĞ ϳ͘ Zhdh x /ĨKWƐǁĞƌĞďƌŽŬĞŶŽĨĨ͕ƌĞƚĞƐƚΘŶŽƚŝĨLJK';ϰϴŚŽƵƌƐĨŽƌǁŝƚŶĞƐƐͿ ϴ͘ <ŝůůǁĞůůǁͬǁĞŝŐŚƚĞĚĨůƵŝĚ ϵ͘ WƵůůĚĞĞƉŐĂƐůŝĨƚĐŽŝůƐƚƌŝŶŐĨƌŽŵůŽǁĞƌƉĂĐŬĞƌŽŶ ϭϬ͘ Zdh ϭϭ͘ D/Zh ͬ>͕WdůƵďƌŝĐĂƚŽƌƚŽϭ͕ϱϬϬƉƐŝͬϮϱϬƉƐŝ͘ ϭϮ͘ WĞƌĨŽƌĂƚĞƉĞƌƉƌŽŐƌĂŵ ϭϯ͘ Z > ϭϰ͘ Zhdh x /ĨKWƐǁĞƌĞďƌŽŬĞŶŽĨĨĨŽƌ >Žƌŝƚ͛ƐďĞĞŶхϳĚĂLJƐƐŝŶĐĞůĂƐƚKWƚĞƐƚ͕ƚĞƐƚKWƐƚŽϮϱϬϬ ƉƐŝͬϮϱϬƉƐŝ;EŽƚŝĨLJK'ϰϴŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨƚĞƐƚƚŽĂůůŽǁƚŚĞŵƚŽǁŝƚŶĞƐƐƚĞƐƚͿ͘ ϭϱ͘ ZĞƐĞƚĚĞĞƉŐĂƐůŝĨƚĐŽŝůƐƚƌŝŶŐ ϭϲ͘ ŽŶƚŝŶŐĞŶƚEϮůŝĨƚŝĨŶĞĐĞƐƐĂƌLJƚŽƵŶůŽĂĚǁĞůů ϭϳ͘ dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ tĞůů^ĐŚĞŵĂƚŝĐͲƵƌƌĞŶƚ Ϯ͘ tĞůů^ĐŚĞŵĂƚŝĐʹWƌŽƉŽƐĞĚ ϯ͘ tĞůůŚĞĂĚŝĂŐƌĂŵͲƵƌƌĞŶƚ ϰ͘ ^ƚĂŶĚĂƌĚtĞůůWƌŽĐĞĚƵƌĞʹEŝƚƌŽŐĞŶKƉĞƌĂƚŝŽŶƐ ϱ͘ ŽŝůdƵďŝŶŐKWƌĂǁŝŶŐ ϲ͘ &ůŽǁŝĂŐƌĂŵƐ ϳ͘ ^ƵŶĚƌLJZĞǀŝƐŝŽŶŚĂŶŐĞ&Žƌŵ Pull DGL string (perf through tubing) (verify well is dead before pulling DGL system)NOTE: dual flappers CV in bottom of DGL string. 3500 psi pull upper packer assembly BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚLJ͗:>>ϭϬͬϭϯͬϮϬ ^, Dd/ EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚ tĞůů͗E/ͲϬϭ >ĂƐƚŽŵƉůĞƚĞĚ͗ϭϮͬϭϲͬϮϬϬϯ Wd͗ϭϵϴͲϬϬϮ W/͗ ϱϬͲϴϴϯͲϮϬϬϵϯͲϬϭ Wd͗ ϭϲ͕ϱϵϬ͛ d͗ ϭϲ͕ϳϮϬ͛ ´ RKB: 53.6’, RKB to MSL: 132’, RKB to Mudline: 232’ ϱ͟ 5$&ROODU ¶ ϭϯͲϯͬϴ͟ ϵͲϱͬϴ͟ dŽƉŽĨdďŐ ϴ͕ϬϱϮ͛ ´ ϮͲϯͬϴ͟ϴ͟ 5$&ROODU ¶ 5$&ROODU ¶ 7DJ72&LQ WXELQJ# ¶&DOF72&LQ WXELQJ[ ´ # ¶ ;1 ; ; ; ^/E' d/> ^ŝnjĞ tƚ 'ƌĂĚĞ ŽŶŶ / dŽƉ ƚŵ ϯϬ͟ ,ͲϰϬ tĞůĚ Ϯϳ͘ϬϬϬ ^ƵƌĨ ϰϬϳ͛ ϮϬ͟ ϭϯϯη <Ͳϱϱ d ϭϴ͘ϳϯϬ͟ ^ƵƌĨ Ϯ͕ϱϳϵ͛ ϭϯͲϯͬϴ͟ ϳϮη EͲϴϬ EͲϴϬ ϭϮ͘ϯϰϳ͟ ^ƵƌĨ ϯ͕ϳϲϬ͛ ϵͲϱͬϴ͟dŝĞͲĂĐŬ ϱϯ͘ϱ WͲϭϭϬ d ϴ͘ϱϯϱ͟ ^ƵƌĨ ϯ͕ϱϴϴ͛ ϵͲϱͬϴ͟ ϱϯ͘ϱ WͲϭϭϬ d ϴ͘ϱϯϱ͛ ϯ͕ϱϴϴ͛ ϭϬ͕ϯϳϳ͛ ϱ͟ ϭϵ͘ϱ ^Ͳϭϯϱ ϰ͘ϱ͟/& ϰ͘ϰϬϴͬ͞ϯ͘Ϯϱ͟ ϭϬ͕Ϭϳϰ͛ ϭϲ͕ϲϱϬ͛ dh/E' d/> ϱͲϭͬϮ͟ ϭϱ͘ϱ >ͲϴϬ dͲDŽĚ ϰ͘ϵϱϬ͟ ^ƵƌĨ ϯ͕ϳϲϰ͛ ϱͲϭͬϮ͟ŽŵďŽ^ĐƌĞĞŶƐΘůĂŶŬƐ ϭϱ͘ϱ ^>,d ϰ͘ϵϱϬ͟ ϯ͕ϳϵϳ ϱ͕ϱϰϳ͛ ϰͲϭͬϮ͟ ϭϮ͘ϲ /d ϯ͘ϵϱϴ͟ ϱ͕ϱϰϳ ϱ͕ϲϰϳ͛ ϰ͟ŽŵďŽ^ĐƌĞĞŶƐΘůĂŶŬƐ ϵ͘ϱ ^>,d ϯ͘ϱϰϴ͟ ϱ͕ϲϰϳ ϲ͕ϴϬϱ͛ ϯͲϭͬϮ͟ ϵ͘ϯ >ͲϴϬ /d Ϯ͘ϵϵϮ͟ ϲ͕ϴϬϱ ϲ͕ϴϲϳ͛ Ϯ͟Žŝů/ŶŶĞƌ^ƚƌŝŶŐ ΕϮ͘ϱϭ ,^ͲϵϬͲ,/^' ϭ͘ϳϱϬ͟ ϯ͕ϱϲϳ͛ ϲ͕ϴϭϳ͛ ϰͲϭͬϮ͟ ϭϮ͘ϳϱ WͲϭϭϬ ϯ͘ϵϱϴ͟ ϴ͕ϬϱϮ͛ цϭϬ͕Ϭϳϰ͛ ƵƚƚŝŶŐƐŝƐƉŽƐĂůdƵďŝŶŐ;ϮƐƚƌŝŶŐƐͿ ƵĂůϮͲϯͬϴ͟ ϰ͘ϳ EͲϴϬ ^,LJĚƌŝů ϭ͘ϵϵϱ͟ ^ƵƌĨ ϯ͕ϲϲϯ͛ : t >Zz d/> EŽ ĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ / K /ƚĞŵ ϱϯ͘ϲ͛ ϱϯ͛ ϱ͘ϱϬϬ͟ ϭϬ͘ϳϱϬ͟ ,ĂŶŐĞƌʹϭϬͲϯͬϰ͟džϱͲϭͬϮ͟s dK ϭ ϰϭϬ͛ ϰϭϬ͛ ϰ͘ϱϲϮ͟ ϳ͘ϱϬϬ͟ ^^^sʹDKdZDͲϰ ǁͬKd/^t>Z^s;yWƌŽĨŝůĞͿ Ϯ ϭ͕ϱϱϵ͛ ϭ͕ϱϱϯ͛ ϰ͘ϲϱϯ͟ ϳ͘ϵϲϮ͟ '>DηϭʹĂŵĐŽDD'ǁͬĚƵŵŵLJǀĂůǀĞ ϯ Ϯ͕ϲϳϱ͛ ϯ͕ϱϵϴ͛ ϰ͘ϲϱϯ͟ ϳ͘ϵϲϮ͟ '>DηϮʹĂŵĐŽDD'ǁͬĚƵŵŵLJǀĂůǀĞ ϰ ϯ͕ϲϬϮ͛ ϯ͕ϯϴϵ͛ ϰ͘ϲϱϯ͟ ϳ͘ϵϲϮ͟ '>DηϯʹĂŵĐŽDD'ǁͬϱͬϭϲ͟ŽƌŝĨŝĐĞǀĂůǀĞ ϱ ϯ͕ϳϬϬ͛ ϯ͕ϰϲϳ͛ ϰ͘ϱϲϮ͟ yͲEŝƉƉůĞ ϲ ϯ͕ϳϲϰ͛ ϯ͕ϱϭϴ͛ ϲ͘ϬϬϬ͟ ϴ͘ϯϭϯ͟ ĂŬĞƌ^ͲϭZWĂĐŬĞƌ͕WZ͕ƐĞĂůƐ͕DK ͕ƐĞĂůďŽƌĞΘŐƌĂǀĞůƉĂĐŬƐůĞĞǀĞ ϳ ϯ͕ϳϵϳ͛ ϯ͕ϱϰϰ͛ ϱ͘ϬϬϬ͟ ϳ͘ϲϱϬ͟ DŽĚĞů<K/s;<ŶŽĐŬKƵƚ/ƐŽůĂƚŝŽŶsĂůǀĞͿ ϯ͕ϴϬϬ͛ ϯ͕ϱϰϳ͛ ϰ͘ϵϱϬ͟ ϲ͘ϭϭϬ͟ ϱͲϭͬϮ͟ϭϱ͘ϱη^>,dďůĂŶŬƐΘ^ĐƌĞĞŶƐ;ϭϰϬdžϬ͘ϬϭϮŐĂ͘Ϳ ϴ ϰ͕ϯϲϴ͛ ϰ͕ϬϭϬ͛ ϰ͘ϵϰϬ͟ ϴ͘ϭϮϱ͟ ĂŬĞƌ^Ͳϭ>WĂĐŬĞƌ͕ƐĞĂůďŽƌĞΘŐƌĂǀĞůƉĂĐŬƐůĞĞǀĞ ϰ͕ϰϮϭ͛ ϰ͕Ϭϱϯ͛ ϰ͘ϵϰϬ͟ ϴ͘ϭϮϱ͟ ϱͲϭͬϮ͟ϭϱ͘ϱη^>,dďůĂŶŬƐΘ^ĐƌĞĞŶƐ;ϭϰϬdžϬ͘ϬϭϮŐĂ͘Ϳ ϵ ϰ͕ϵϲϵ͛ ϰ͕ϰϵϱ͛ ϲ͘ϬϬϬ͟ ϴ͘Ϯϴϭ͟ ĂŬĞƌ^ͲϭZ^ƵŵƉWĂĐŬĞƌΘDK ϰ͕ϵϴϱ͛ ϰ͕ϱϬϴ͛ ϰ͘ϴϵϮ͟ ϲ͘ϬϱϬ͟ ϱͲϭͬϮ͟ϭϱ͘ϱη>ͲϴϬ^>,důĂŶŬ ϭϬ ϱ͕ϱϰϳ͛ ϰ͕ϵϲϮ͛ ϯ͘ϵϱϴ͟ ϲ͘ϬϲϬ͟ ƌŽƐƐŽǀĞƌϱͲϭͬϮ͟^>,ddžϰͲϭͬϮ͟/d ϭϭ ϱ͕ϱϳϵ͛ ϰ͕ϵϴϴ͛ ϯ͘ϴϭϯ͟ ϱ͘ϮϯϬ͟ yͲEŝƉƉůĞ ϭϮ ϱ͕ϲϭϯ͛ ϱ͕Ϭϭϱ͛ ϰ͘ϳϱϬ͟ ϴ͘ϯϮϵ͟ ĂŬĞƌ^ͲϮWĂĐŬĞƌ͕^ͲϮϮ^ŶĂƉ>ĂƚĐŚ͕ƐĞĂůďŽƌĞ͕ΘŐƌĂǀĞůƉĂĐŬƐůĞĞǀĞ ϭϯ ϱ͕ϲϰϳ͛ ϱ͕ϬϰϮ͛ ϯ͘ϱϬϬ͟ ϱ͘ϲϱϬ͟ DŽĚĞů<K/s;<ŶŽĐŬKƵƚ/ƐŽůĂƚŝŽŶsĂůǀĞͿ ϱ͕ϲϱϬ͛ ϱ͕Ϭϰϰ͛ ϯ͘ϱϰϴ͟ ϰ͘ϱϵϬ͟ ϰ͟^>,d^ĐƌĞĞŶΘůĂŶŬƐ;ϭϮŐĂ͘Ϳ ϭϰ ϲ͕ϳϴϳ͛ ϱ͕ϵϲϬ͛ ϲ͘ϬϬϬ͟ ϴ͘ϮϴϬ͟ ĂŬĞƌ^ͲϭZ^ƵŵƉWĂĐŬĞƌ͕^ͲϮϮ^ŶĂƉ>ĂƚĐŚ͕DK ϭϱ ϲ͕ϴϬϱ͛ ϱ͕ϵϳϱ͛ Ϯ͘ϵϵϮ͟ ϲ͘ϬϱϬ͟ ƌŽƐƐŽǀĞƌϱͲϭͬϮ͟džϯͲϭͬϮ͟ ϭϲ ϲ͕ϴϯϲ͛ ϲ͕ϬϬϬ͛ Ϯ͘ϴϭϯ͟ ϰ͘ϮϱϬ͟ yͲEŝƉƉůĞ ϭϳ ϲ͕ϴϲϳ͛ ϲ͕ϬϮϲ͛ Ϯ͘ϵϵϮ͟ ϰ͘ϮϱϬ͟ t> ' ϭϴ ϴ͕ϬϱϮ͛ ϲ͕ϵϴϰ͛ &ŝƐŚʹƵƚƚŽƉŽĨϰͲϭͬϮ͟ƚƵďŝŶŐ ϭϵ ϭϬ͕ϬϯϮ͛ ϴ͕ϱϲϰ͛ ^ůŝĚŝŶŐ^ůĞĞǀĞʹ WyEWůƵŐΛϭϬ͕ϬϰϮ ϮϬ ϭϬ͕Ϭϳϰ͛ ϴ͕ϱϵϴ͛ WĂĐŬĞƌ Ϯϭ ϭϬ͕ϯϳϲ͛ ϴ͕ϴϰϬ͛ yEEŝƉƉůĞǁͬWyEWůƵŐŝŶEŝƉƉůĞ /EE Z^dZ/E': t >Zz d/> EŽ ĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ / K /ƚĞŵ ϯ͕ϱϳϱ͛ ϯ͕ϯϲϳ͛ ϯ͘ϬϬϬ͟ ϰ͘ϱϬϬ͟ tĞĂƚŚĞƌĨŽƌĚϰϱϬtŝĚĞƉĂĐŬhƉƉĞƌWĂĐŬĞƌ ϯ͕ϱϴϭ͛ ϯ͕ϯϳϮ͛ Ϯ͘ϵϵϮ͟ ϯͲϭͬϮ͟WƵƉ:ŽŝŶƚ ϯ͕ϱϴϲ͛ ϯ͕ϯϳϲ͛ ϯ͘ϬϬϬ͟ ϯͲϳͬϴ͟WƵƉ:ŽŝŶƚƐ ϯ͕ϲϬϲ͛ ϯ͕ϯϵϮ͛ Eͬ ϰ͘ϰϮϬ͟ ĞŶƚƌĂůŝĨƚs ^ƵďǁͬƵĂů&ůĂƉƉĞƌŚĞĐŬsĂůǀĞ ϯ͕ϲϬϲ͛ ϯ͕ϯϵϮ͛ Ϯ͘ϴϳϱ͟ ϰ͘ϰϳϬ͟ tWŶĐŚŽƌ^ĞĂů>ĂƚĐŚ ϯ͕ϲϬϵ͛ ϯ͕ϯϵϰ͛ Ϭ͘ϴϳϱ͟ ϭ͘ϳϱϬ͟ ^ƚŝŶŐĞƌZŽĚǁͬƐĞĂůƐƚĂĐŬ;ϲ͘ϵϬ͛ͿƐƚƵŶŐŝŶƚŽWZ^ĞĂůŽƌĞ ϯ͕ϲϭϬ͛ ϯ͕ϯϵϱ͛ ϯ͘ϬϬϬ͟ ϰ͘ϱϬϬ͟ tĞĂƚŚĞƌĨŽƌĚϰϱϬtŝĚĞƉĂĐŬ>ŽǁĞƌWĂĐŬĞƌ ϯ͕ϲϭϲ͛ ϯ͕ϰϬϬ͛ ϯ͘ϰϳϲ͟ ϰ͘ϰϮϬ͟ ^ůŽƚƚĞĚ^Ƶď ϯ͕ϲϭϳ͛ ϯ͕ϰϬϭ͛ ϭ͘ϳϱϬ͟ ϰ͘ϰϮϬ͟ WZ^ĞĂůŽƌĞ ϯ͕ϲϭϵ͛ ϯ͕ϰϬϮ͛ ϭ͘ϯϳϱ͟ ϰ͘ϰϮϬ͟ dŽƌƋͲdŚƌƵYƵŝĐŬŽŶŶĞĐƚͲhƉƉĞƌ ϯ͕ϲϮϬ͛ ϯ͕ϰϬϯ͛ ϭ͘ϯϳϱ͟ Ϯ͘ϴϳϱ͟ dŽƌƋͲdŚƌƵYƵŝĐŬŽŶŶĞĐƚͲ>ŽǁĞƌ ϯ͕ϲϮϬ͛ ϯ͕ϰϬϯ͛ ϯ͘ϬϬϬ͟ ϰ͘ϯϭϯ͟ dƌLJƚŽŶDĂdž&ƌĂĐWůƵŐ ϲ͕Ϭϰϵ͛ ϱ͕ϯϲϳ͛ ϭ͘ϯϳϱ͟ Ϯ͘ϴϳϱ͟ džƚĞƌŶĂů'ƌĂƉƉůĞŽŝůŽŶŶĞĐƚŽƌ ϲ͕ϬϱϬ͛ ϱ͕ϯϲϳ͛ Ϯ͘ϬϬϬ͟ Ϯ͘ϲϬϬ͟ WDͲϭ'ĂƐ>ŝĨƚDĂŶĚƌĞů ϲ͕ϬϱϮ͛ ϱ͕ϯϲϵ͛ ϭ͘ϯϳϱ͟ Ϯ͘ϴϳϱ͟ dŽƌƋͲdŚƌƵYƵŝĐŬŽŶŶĞĐƚ ϲ͕ϴϭϳ͛ ϱ͕ϵϴϰ͛ ϭ͘ϳϱϬ͟ Ϯ͘ϬϬϬ͟ dŝŵƉůĞŽŶŶĞĐƚŽƌ ϲ͕ϴϭϳ͛ ϱ͕ϵϴϰ͛ Ϭ͘ϵϯϬ͟ Ϯ͘ϯϳϱ͟ ŝŶũĞĐƚŝŽŶƐƵď ϲ͕ϴϭϵ͛ ϱ͕ϵϴϲ͛ ďŽƚƚŽŵŽĨŝŶũĞĐƚŝŽŶƐƚƌŝŶŐ string gas lift DGL Ϭ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚLJ͗:>>ϭϬͬϭϯͬϮϬ ^, Dd/ EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚ tĞůů͗E/ͲϬϭ >ĂƐƚŽŵƉůĞƚĞĚ͗ϭϮͬϭϲͬϮϬϬϯ Wd͗ϭϵϴͲϬϬϮ W/͗ ϱϬͲϴϴϯͲϮϬϬϵϯͲϬϭ W Z&KZd/KE d/> ŽŶĞ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ĂƚĞ ^ƚĂƚƵƐ ϯ͕ϱϬϬΖ ϯ͕ϱϰϬΖ ϯ͕ϯϬϳΖ ϯ͕ϯϯϵΖ ϰϬΖ ϵͬϵͬϭϵϵϳ KƉĞŶ ϯ͕ϲϯϭΖ ϯ͕ϲϯϮΖ ϯ͕ϰϭϮΖ ϯ͕ϰϭϯΖ ϭΖ ϯ͕ϴϱϬΖ ϯ͕ϴϲϵΖ ϯ͕ϱϴϳΖ ϯ͕ϲϬϮΖ ϭϵΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ ϯ͕ϴϴϲΖ ϯ͕ϴϵϯΖ ϯ͕ϲϭϲΖ ϯ͕ϲϮϭΖ ϳΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϭ ϰ͕ϭϴϱΖ ϰ͕ϮϲϴΖ ϯ͕ϴϱϵΖ ϯ͕ϵϮϴΖ ϴϯΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /Ϯ ϰ͕ϮϳϱΖ ϰ͕ϯϲϱΖ ϯ͕ϵϯϯΖ ϰ͕ϬϬϳΖ ϵϬΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϰ ϰ͕ϰϮϵΖ ϰ͕ϰϴϬΖ ϰ͕ϬϲϬΖ ϰ͕ϭϬϭΖ ϱϭΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϴ ϰ͕ϳϱϭΖ ϰ͕ϳϲϭΖ ϰ͕ϯϭϵΖ ϰ͕ϯϮϳΖ ϭϬΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϴ ϰ͕ϳϵϮΖ ϰ͕ϴϬϯΖ ϰ͕ϯϱϮΖ ϰ͕ϯϲϭΖ ϭϭΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϭϭ ϰ͕ϵϮϮΖ ϰ͕ϵϱϱΖ ϰ͕ϰϱϳΖ ϰ͕ϰϴϰΖ ϯϯΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ >'Ͳ& ϱ͕ϳϭϴΖ ϱ͕ϳϰϮΖ ϱ͕ϬϵϴΖ ϱ͕ϭϭϴΖ ϮϰΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ' ϱ͕ϴϴϱΖ ϱ͕ϴϵϮΖ ϱ͕ϮϯϰΖ ϱ͕ϮϯϵΖ ϳΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ, ϱ͕ϵϮϵΖ ϱ͕ϵϯϵΖ ϱ͕ϮϲϵΖ ϱ͕ϮϳϴΖ ϭϬΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ, ϱ͕ϵϰϴΖ ϱ͕ϵϲϵΖ ϱ͕ϮϴϱΖ ϱ͕ϯϬϮΖ ϮϭΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ, ϱ͕ϵϵϱΖ ϲ͕ϬϯϮΖ ϱ͕ϯϮϯΖ ϱ͕ϯϱϯΖ ϯϳΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ/ ϲ͕ϬϳϴΖ ϲ͕ϬϵϭΖ ϱ͕ϯϵϬΖ ϱ͕ϰϬϬΖ ϭϯΖ ϭϮͬϭͬϮϬϬϯ ϲ͕ϬϵϳΖ ϲ͕ϭϬϳΖ ϱ͕ϰϬϱΖ ϱ͕ϰϭϯΖ ϭϬΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ/ ϲ͕ϭϭϴΖ ϲ͕ϭϮϰΖ ϱ͕ϰϮϮΖ ϱ͕ϰϮϳΖ ϲΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ/ ϲ͕ϭϰϴΖ ϲ͕ϭϱϴΖ ϱ͕ϰϰϲΖ ϱ͕ϰϱϰΖ ϭϬΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ/ ϲ͕ϭϲϵΖ ϲ͕ϭϴϮΖ ϱ͕ϰϲϯΖ ϱ͕ϰϳϯΖ ϭϯΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ: ϲ͕ϮϴϯΖ ϲ͕ϮϵϬΖ ϱ͕ϱϱϯΖ ϱ͕ϱϱϵΖ ϳΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ> ϲ͕ϯϳϱΖ ϲ͕ϯϵϬΖ ϱ͕ϲϮϳΖ ϱ͕ϲϯϵΖ ϭϱΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'ͲD ϲ͕ϲϭϬΖ ϲ͕ϲϮϮΖ ϱ͕ϴϭϱΖ ϱ͕ϴϮϱΖ ϭϮΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'ͲK ϲ͕ϳϲϮΖ ϲ͕ϳϲϳΖ ϱ͕ϵϯϵΖ ϱ͕ϵϰϯΖ ϱΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ ϵ͕ϵϳϬΖ ϵ͕ϵϳϮΖ ϴ͕ϱϭϰΖ ϴ͕ϱϭϱΖ ϮΖ /ƐŽůĂƚĞĚ ϭϲ͕ϬϴϬΖ ϭϲ͕ϭϭϴΖ ϭϮ͕ϱϮϱΖ ϭϮ͕ϱϰϴΖ ϯϴΖ /ƐŽůĂƚĞĚ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚLJ͗:>>ϭϬͬϭϯͬϮϬ ^, Dd/ EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚ tĞůů͗E/ͲϬϭ >ĂƐƚŽŵƉůĞƚĞĚ͗ϭϮͬϭϲͬϮϬϬϯ Wd͗ϭϵϴͲϬϬϮ W/͗ ϱϬͲϴϴϯͲϮϬϬϵϯͲϬϭ Wd͗ ϭϲ͕ϱϵϬ͛ d͗ ϭϲ͕ϳϮϬ͛ ´ RKB: 53.6’, RKB to MSL: 132’, RKB to Mudline: 232’ ϱ͟ 5$&ROODU ¶ ϭϯͲϯͬϴ͟ ϵͲϱͬϴ͟ dŽƉŽĨdďŐ ϴ͕ϬϱϮ͛ ´ ϮͲϯͬϴ͟ϴ͟ 5$&ROODU ¶ 5$&ROODU ¶ 7DJ72&LQ WXELQJ# ¶&DOF72&LQ WXELQJ[ ´ # ¶ %HOXJD$ %HOXJD% ;1 ; ; ; ^/E' d/> ^ŝnjĞ tƚ 'ƌĂĚĞ ŽŶŶ / dŽƉ ƚŵ ϯϬ͟ ,ͲϰϬ tĞůĚ Ϯϳ͘ϬϬϬ ^ƵƌĨ ϰϬϳ͛ ϮϬ͟ ϭϯϯη <Ͳϱϱ d ϭϴ͘ϳϯϬ͟ ^ƵƌĨ Ϯ͕ϱϳϵ͛ ϭϯͲϯͬϴ͟ ϳϮη EͲϴϬ EͲϴϬ ϭϮ͘ϯϰϳ͟ ^ƵƌĨ ϯ͕ϳϲϬ͛ ϵͲϱͬϴ͟dŝĞͲĂĐŬ ϱϯ͘ϱ WͲϭϭϬ d ϴ͘ϱϯϱ͟ ^ƵƌĨ ϯ͕ϱϴϴ͛ ϵͲϱͬϴ͟ ϱϯ͘ϱ WͲϭϭϬ d ϴ͘ϱϯϱ͛ ϯ͕ϱϴϴ͛ ϭϬ͕ϯϳϳ͛ ϱ͟ ϭϵ͘ϱ ^Ͳϭϯϱ ϰ͘ϱ͟/& ϰ͘ϰϬϴͬ͞ϯ͘Ϯϱ͟ ϭϬ͕Ϭϳϰ͛ ϭϲ͕ϲϱϬ͛ dh/E' d/> ϱͲϭͬϮ͟ ϭϱ͘ϱ >ͲϴϬ dͲDŽĚ ϰ͘ϵϱϬ͟ ^ƵƌĨ ϯ͕ϳϲϰ͛ ϱͲϭͬϮ͟ŽŵďŽ^ĐƌĞĞŶƐΘůĂŶŬƐ ϭϱ͘ϱ ^>,d ϰ͘ϵϱϬ͟ ϯ͕ϳϵϳ ϱ͕ϱϰϳ͛ ϰͲϭͬϮ͟ ϭϮ͘ϲ /d ϯ͘ϵϱϴ͟ ϱ͕ϱϰϳ ϱ͕ϲϰϳ͛ ϰ͟ŽŵďŽ^ĐƌĞĞŶƐΘůĂŶŬƐ ϵ͘ϱ ^>,d ϯ͘ϱϰϴ͟ ϱ͕ϲϰϳ ϲ͕ϴϬϱ͛ ϯͲϭͬϮ͟ ϵ͘ϯ >ͲϴϬ /d Ϯ͘ϵϵϮ͟ ϲ͕ϴϬϱ ϲ͕ϴϲϳ͛ Ϯ͟Žŝů/ŶŶĞƌ^ƚƌŝŶŐ ΕϮ͘ϱϭ ,^ͲϵϬͲ,/^' ϭ͘ϳϱϬ͟ ϯ͕ϱϲϳ͛ ϲ͕ϴϭϳ͛ ϰͲϭͬϮ͟ ϭϮ͘ϳϱ WͲϭϭϬ ϯ͘ϵϱϴ͟ ϴ͕ϬϱϮ͛ цϭϬ͕Ϭϳϰ͛ ƵƚƚŝŶŐƐŝƐƉŽƐĂůdƵďŝŶŐ;ϮƐƚƌŝŶŐƐͿ ƵĂůϮͲϯͬϴ͟ ϰ͘ϳ EͲϴϬ ^,LJĚƌŝů ϭ͘ϵϵϱ͟ ^ƵƌĨ ϯ͕ϲϲϯ͛ : t >Zz d/> EŽ ĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ / K /ƚĞŵ ϱϯ͘ϲ͛ ϱϯ͛ ϱ͘ϱϬϬ͟ ϭϬ͘ϳϱϬ͟ ,ĂŶŐĞƌʹϭϬͲϯͬϰ͟džϱͲϭͬϮ͟s dK ϭ ϰϭϬ͛ ϰϭϬ͛ ϰ͘ϱϲϮ͟ ϳ͘ϱϬϬ͟ ^^^sʹDKdZDͲϰ ǁͬKd/^t>Z^s;yWƌŽĨŝůĞͿ Ϯ ϭ͕ϱϱϵ͛ ϭ͕ϱϱϯ͛ ϰ͘ϲϱϯ͟ ϳ͘ϵϲϮ͟ '>DηϭʹĂŵĐŽDD'ǁͬĚƵŵŵLJǀĂůǀĞ ϯ Ϯ͕ϲϳϱ͛ ϯ͕ϱϵϴ͛ ϰ͘ϲϱϯ͟ ϳ͘ϵϲϮ͟ '>DηϮʹĂŵĐŽDD'ǁͬĚƵŵŵLJǀĂůǀĞ ϰ ϯ͕ϲϬϮ͛ ϯ͕ϯϴϵ͛ ϰ͘ϲϱϯ͟ ϳ͘ϵϲϮ͟ '>DηϯʹĂŵĐŽDD'ǁͬϱͬϭϲ͟ŽƌŝĨŝĐĞǀĂůǀĞ ϱ ϯ͕ϳϬϬ͛ ϯ͕ϰϲϳ͛ ϰ͘ϱϲϮ͟ yͲEŝƉƉůĞ ϲ ϯ͕ϳϲϰ͛ ϯ͕ϱϭϴ͛ ϲ͘ϬϬϬ͟ ϴ͘ϯϭϯ͟ ĂŬĞƌ^ͲϭZWĂĐŬĞƌ͕WZ͕ƐĞĂůƐ͕DK ͕ƐĞĂůďŽƌĞΘŐƌĂǀĞůƉĂĐŬƐůĞĞǀĞ ϳ ϯ͕ϳϵϳ͛ ϯ͕ϱϰϰ͛ ϱ͘ϬϬϬ͟ ϳ͘ϲϱϬ͟ DŽĚĞů<K/s;<ŶŽĐŬKƵƚ/ƐŽůĂƚŝŽŶsĂůǀĞͿ ϯ͕ϴϬϬ͛ ϯ͕ϱϰϳ͛ ϰ͘ϵϱϬ͟ ϲ͘ϭϭϬ͟ ϱͲϭͬϮ͟ϭϱ͘ϱη^>,dďůĂŶŬƐΘ^ĐƌĞĞŶƐ;ϭϰϬdžϬ͘ϬϭϮŐĂ͘Ϳ ϴ ϰ͕ϯϲϴ͛ ϰ͕ϬϭϬ͛ ϰ͘ϵϰϬ͟ ϴ͘ϭϮϱ͟ ĂŬĞƌ^Ͳϭ>WĂĐŬĞƌ͕ƐĞĂůďŽƌĞΘŐƌĂǀĞůƉĂĐŬƐůĞĞǀĞ ϰ͕ϰϮϭ͛ ϰ͕Ϭϱϯ͛ ϰ͘ϵϰϬ͟ ϴ͘ϭϮϱ͟ ϱͲϭͬϮ͟ϭϱ͘ϱη^>,dďůĂŶŬƐΘ^ĐƌĞĞŶƐ;ϭϰϬdžϬ͘ϬϭϮŐĂ͘Ϳ ϵ ϰ͕ϵϲϵ͛ ϰ͕ϰϵϱ͛ ϲ͘ϬϬϬ͟ ϴ͘Ϯϴϭ͟ ĂŬĞƌ^ͲϭZ^ƵŵƉWĂĐŬĞƌΘDK ϰ͕ϵϴϱ͛ ϰ͕ϱϬϴ͛ ϰ͘ϴϵϮ͟ ϲ͘ϬϱϬ͟ ϱͲϭͬϮ͟ϭϱ͘ϱη>ͲϴϬ^>,důĂŶŬ ϭϬ ϱ͕ϱϰϳ͛ ϰ͕ϵϲϮ͛ ϯ͘ϵϱϴ͟ ϲ͘ϬϲϬ͟ ƌŽƐƐŽǀĞƌϱͲϭͬϮ͟^>,ddžϰͲϭͬϮ͟/d ϭϭ ϱ͕ϱϳϵ͛ ϰ͕ϵϴϴ͛ ϯ͘ϴϭϯ͟ ϱ͘ϮϯϬ͟ yͲEŝƉƉůĞ ϭϮ ϱ͕ϲϭϯ͛ ϱ͕Ϭϭϱ͛ ϰ͘ϳϱϬ͟ ϴ͘ϯϮϵ͟ ĂŬĞƌ^ͲϮWĂĐŬĞƌ͕^ͲϮϮ^ŶĂƉ>ĂƚĐŚ͕ƐĞĂůďŽƌĞ͕ΘŐƌĂǀĞůƉĂĐŬƐůĞĞǀĞ ϭϯ ϱ͕ϲϰϳ͛ ϱ͕ϬϰϮ͛ ϯ͘ϱϬϬ͟ ϱ͘ϲϱϬ͟ DŽĚĞů<K/s;<ŶŽĐŬKƵƚ/ƐŽůĂƚŝŽŶsĂůǀĞͿ ϱ͕ϲϱϬ͛ ϱ͕Ϭϰϰ͛ ϯ͘ϱϰϴ͟ ϰ͘ϱϵϬ͟ ϰ͟^>,d^ĐƌĞĞŶΘůĂŶŬƐ;ϭϮŐĂ͘Ϳ ϭϰ ϲ͕ϳϴϳ͛ ϱ͕ϵϲϬ͛ ϲ͘ϬϬϬ͟ ϴ͘ϮϴϬ͟ ĂŬĞƌ^ͲϭZ^ƵŵƉWĂĐŬĞƌ͕^ͲϮϮ^ŶĂƉ>ĂƚĐŚ͕DK ϭϱ ϲ͕ϴϬϱ͛ ϱ͕ϵϳϱ͛ Ϯ͘ϵϵϮ͟ ϲ͘ϬϱϬ͟ ƌŽƐƐŽǀĞƌϱͲϭͬϮ͟džϯͲϭͬϮ͟ ϭϲ ϲ͕ϴϯϲ͛ ϲ͕ϬϬϬ͛ Ϯ͘ϴϭϯ͟ ϰ͘ϮϱϬ͟ yͲEŝƉƉůĞ ϭϳ ϲ͕ϴϲϳ͛ ϲ͕ϬϮϲ͛ Ϯ͘ϵϵϮ͟ ϰ͘ϮϱϬ͟ t> ' ϭϴ ϴ͕ϬϱϮ͛ ϲ͕ϵϴϰ͛ &ŝƐŚʹƵƚƚŽƉŽĨϰͲϭͬϮ͟ƚƵďŝŶŐ ϭϵ ϭϬ͕ϬϯϮ͛ ϴ͕ϱϲϰ͛ ^ůŝĚŝŶŐ^ůĞĞǀĞʹ WyEWůƵŐΛϭϬ͕ϬϰϮ ϮϬ ϭϬ͕Ϭϳϰ͛ ϴ͕ϱϵϴ͛ WĂĐŬĞƌ Ϯϭ ϭϬ͕ϯϳϲ͛ ϴ͕ϴϰϬ͛ yEEŝƉƉůĞǁͬWyEWůƵŐŝŶEŝƉƉůĞ /EE Z^dZ/E': t >Zz d/> EŽ ĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ / K /ƚĞŵ ϯ͕ϱϳϱ͛ ϯ͕ϯϲϳ͛ ϯ͘ϬϬϬ͟ ϰ͘ϱϬϬ͟ tĞĂƚŚĞƌĨŽƌĚϰϱϬtŝĚĞƉĂĐŬhƉƉĞƌWĂĐŬĞƌ ϯ͕ϱϴϭ͛ ϯ͕ϯϳϮ͛ Ϯ͘ϵϵϮ͟ ϯͲϭͬϮ͟WƵƉ:ŽŝŶƚ ϯ͕ϱϴϲ͛ ϯ͕ϯϳϲ͛ ϯ͘ϬϬϬ͟ ϯͲϳͬϴ͟WƵƉ:ŽŝŶƚƐ ϯ͕ϲϬϲ͛ ϯ͕ϯϵϮ͛ Eͬ ϰ͘ϰϮϬ͟ ĞŶƚƌĂůŝĨƚs ^ƵďǁͬƵĂů&ůĂƉƉĞƌŚĞĐŬsĂůǀĞ ϯ͕ϲϬϲ͛ ϯ͕ϯϵϮ͛ Ϯ͘ϴϳϱ͟ ϰ͘ϰϳϬ͟ tWŶĐŚŽƌ^ĞĂů>ĂƚĐŚ ϯ͕ϲϬϵ͛ ϯ͕ϯϵϰ͛ Ϭ͘ϴϳϱ͟ ϭ͘ϳϱϬ͟ ^ƚŝŶŐĞƌZŽĚǁͬƐĞĂůƐƚĂĐŬ;ϲ͘ϵϬ͛ͿƐƚƵŶŐŝŶƚŽWZ^ĞĂůŽƌĞ ϯ͕ϲϭϬ͛ ϯ͕ϯϵϱ͛ ϯ͘ϬϬϬ͟ ϰ͘ϱϬϬ͟ tĞĂƚŚĞƌĨŽƌĚϰϱϬtŝĚĞƉĂĐŬ>ŽǁĞƌWĂĐŬĞƌ ϯ͕ϲϭϲ͛ ϯ͕ϰϬϬ͛ ϯ͘ϰϳϲ͟ ϰ͘ϰϮϬ͟ ^ůŽƚƚĞĚ^Ƶď ϯ͕ϲϭϳ͛ ϯ͕ϰϬϭ͛ ϭ͘ϳϱϬ͟ ϰ͘ϰϮϬ͟ WZ^ĞĂůŽƌĞ ϯ͕ϲϭϵ͛ ϯ͕ϰϬϮ͛ ϭ͘ϯϳϱ͟ ϰ͘ϰϮϬ͟ dŽƌƋͲdŚƌƵYƵŝĐŬŽŶŶĞĐƚͲhƉƉĞƌ ϯ͕ϲϮϬ͛ ϯ͕ϰϬϯ͛ ϭ͘ϯϳϱ͟ Ϯ͘ϴϳϱ͟ dŽƌƋͲdŚƌƵYƵŝĐŬŽŶŶĞĐƚͲ>ŽǁĞƌ ϯ͕ϲϮϬ͛ ϯ͕ϰϬϯ͛ ϯ͘ϬϬϬ͟ ϰ͘ϯϭϯ͟ dƌLJƚŽŶDĂdž&ƌĂĐWůƵŐ ϲ͕Ϭϰϵ͛ ϱ͕ϯϲϳ͛ ϭ͘ϯϳϱ͟ Ϯ͘ϴϳϱ͟ džƚĞƌŶĂů'ƌĂƉƉůĞŽŝůŽŶŶĞĐƚŽƌ ϲ͕ϬϱϬ͛ ϱ͕ϯϲϳ͛ Ϯ͘ϬϬϬ͟ Ϯ͘ϲϬϬ͟ WDͲϭ'ĂƐ>ŝĨƚDĂŶĚƌĞů ϲ͕ϬϱϮ͛ ϱ͕ϯϲϵ͛ ϭ͘ϯϳϱ͟ Ϯ͘ϴϳϱ͟ dŽƌƋͲdŚƌƵYƵŝĐŬŽŶŶĞĐƚ ϲ͕ϴϭϳ͛ ϱ͕ϵϴϰ͛ ϭ͘ϳϱϬ͟ Ϯ͘ϬϬϬ͟ dŝŵƉůĞŽŶŶĞĐƚŽƌ ϲ͕ϴϭϳ͛ ϱ͕ϵϴϰ͛ Ϭ͘ϵϯϬ͟ Ϯ͘ϯϳϱ͟ ŝŶũĞĐƚŝŽŶƐƵď ϲ͕ϴϭϵ͛ ϱ͕ϵϴϲ͛ ďŽƚƚŽŵŽĨŝŶũĞĐƚŝŽŶƐƚƌŝŶŐ $ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚLJ͗:>>ϭϬͬϭϯͬϮϬ ^, Dd/ EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚ tĞůů͗E/ͲϬϭ >ĂƐƚŽŵƉůĞƚĞĚ͗ϭϮͬϭϲͬϮϬϬϯ Wd͗ϭϵϴͲϬϬϮ W/͗ ϱϬͲϴϴϯͲϮϬϬϵϯͲϬϭ W Z&KZd/KE d/> ŽŶĞ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ĂƚĞ ^ƚĂƚƵƐ ϯ͕ϱϬϬΖ ϯ͕ϱϰϬΖ ϯ͕ϯϬϳΖ ϯ͕ϯϯϵΖ ϰϬΖ ϵͬϵͬϭϵϵϳ KƉĞŶ ϯ͕ϲϯϭΖ ϯ͕ϲϯϮΖ ϯ͕ϰϭϮΖ ϯ͕ϰϭϯΖ ϭΖ ϯ͕ϴϱϬΖ ϯ͕ϴϲϵΖ ϯ͕ϱϴϳΖ ϯ͕ϲϬϮΖ ϭϵΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ ϯ͕ϴϴϲΖ ϯ͕ϴϵϯΖ ϯ͕ϲϭϲΖ ϯ͕ϲϮϭΖ ϳΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϭ ϰ͕ϭϴϱΖ ϰ͕ϮϲϴΖ ϯ͕ϴϱϵΖ ϯ͕ϵϮϴΖ ϴϯΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /Ϯ ϰ͕ϮϳϱΖ ϰ͕ϯϲϱΖ ϯ͕ϵϯϯΖ ϰ͕ϬϬϳΖ ϵϬΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϰ ϰ͕ϰϮϵΖ ϰ͕ϰϴϬΖ ϰ͕ϬϲϬΖ ϰ͕ϭϬϭΖ ϱϭΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϴ ϰ͕ϳϱϭΖ ϰ͕ϳϲϭΖ ϰ͕ϯϭϵΖ ϰ͕ϯϮϳΖ ϭϬΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϴ ϰ͕ϳϵϮΖ ϰ͕ϴϬϯΖ ϰ͕ϯϱϮΖ ϰ͕ϯϲϭΖ ϭϭΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ /ϭϭ ϰ͕ϵϮϮΖ ϰ͕ϵϱϱΖ ϰ͕ϰϱϳΖ ϰ͕ϰϴϰΖ ϯϯΖ ϭϮͬϴͬϮϬϬϯ KƉĞŶ ĞůƵŐĂ цϰ͕ϵϵϳ͛ цϱ͕ϬϬϵ͛ цϰ͕ϱϭϴ͛ цϰ͕ϱϮϳ͛ цϭϮ͛ &hdhZ WZKWK^ ĞůƵŐĂ цϱ͕ϭϬϰ͛ цϱ͕ϭϭϮ͛ цϰ͕ϲϬϱ͛ цϰ͕ϲϭϭ͛ цϴ͛ &hdhZ WZKWK^ ĞůƵŐĂ цϱ͕ϭϮϰ͛ цϱ͕ϭϯϱ͛ цϰ͕ϲϮϭ͛ цϰ͕ϲϯϬ͛ цϭϭ͛ &hdhZ WZKWK^ >'Ͳ& ϱ͕ϳϭϴΖ ϱ͕ϳϰϮΖ ϱ͕ϬϵϴΖ ϱ͕ϭϭϴΖ ϮϰΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ' ϱ͕ϴϴϱΖ ϱ͕ϴϵϮΖ ϱ͕ϮϯϰΖ ϱ͕ϮϯϵΖ ϳΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ, ϱ͕ϵϮϵΖ ϱ͕ϵϯϵΖ ϱ͕ϮϲϵΖ ϱ͕ϮϳϴΖ ϭϬΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ, ϱ͕ϵϰϴΖ ϱ͕ϵϲϵΖ ϱ͕ϮϴϱΖ ϱ͕ϯϬϮΖ ϮϭΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ, ϱ͕ϵϵϱΖ ϲ͕ϬϯϮΖ ϱ͕ϯϮϯΖ ϱ͕ϯϱϯΖ ϯϳΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ/ ϲ͕ϬϳϴΖ ϲ͕ϬϵϭΖ ϱ͕ϯϵϬΖ ϱ͕ϰϬϬΖ ϭϯΖ ϭϮͬϭͬϮϬϬϯ ϲ͕ϬϵϳΖ ϲ͕ϭϬϳΖ ϱ͕ϰϬϱΖ ϱ͕ϰϭϯΖ ϭϬΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ/ ϲ͕ϭϭϴΖ ϲ͕ϭϮϰΖ ϱ͕ϰϮϮΖ ϱ͕ϰϮϳΖ ϲΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ/ ϲ͕ϭϰϴΖ ϲ͕ϭϱϴΖ ϱ͕ϰϰϲΖ ϱ͕ϰϱϰΖ ϭϬΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ/ ϲ͕ϭϲϵΖ ϲ͕ϭϴϮΖ ϱ͕ϰϲϯΖ ϱ͕ϰϳϯΖ ϭϯΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ: ϲ͕ϮϴϯΖ ϲ͕ϮϵϬΖ ϱ͕ϱϱϯΖ ϱ͕ϱϱϵΖ ϳΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'Ͳ> ϲ͕ϯϳϱΖ ϲ͕ϯϵϬΖ ϱ͕ϲϮϳΖ ϱ͕ϲϯϵΖ ϭϱΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'ͲD ϲ͕ϲϭϬΖ ϲ͕ϲϮϮΖ ϱ͕ϴϭϱΖ ϱ͕ϴϮϱΖ ϭϮΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ >'ͲK ϲ͕ϳϲϮΖ ϲ͕ϳϲϳΖ ϱ͕ϵϯϵΖ ϱ͕ϵϰϯΖ ϱΖ ϭϮͬϭͬϮϬϬϯ KƉĞŶ ϵ͕ϵϳϬΖ ϵ͕ϵϳϮΖ ϴ͕ϱϭϰΖ ϴ͕ϱϭϱΖ ϮΖ /ƐŽůĂƚĞĚ ϭϲ͕ϬϴϬΖ ϭϲ͕ϭϭϴΖ ϭϮ͕ϱϮϱΖ ϭϮ͕ϱϰϴΖ ϯϴΖ /ƐŽůĂƚĞĚ ĞůƵŐĂцϰ͕ϵϵϳ͛цϱ͕ϬϬϵ͛цϰ͕ϱϭϴ͛цϰ͕ϱϮϳ͛цϭϮ͛&hdhZ WZKWK^ ĞůƵŐĂцϱ͕ϭϬϰ͛цϱ͕ϭϭϮ͛цϰ͕ϲϬϱ͛цϰ͕ϲϭϭ͛цϴ͛&hdhZ WZKWK^ ĞůƵŐĂцϱ͕ϭϮϰ͛цϱ͕ϭϯϱ͛цϰ͕ϲϮϭ͛цϰ͕ϲϯϬ͛цϭϭ͛&hdhZ WZKWK^ ^dEZt >>WZK hZ E/dZK' EKW Zd/KE^ ϬϵͬϮϯͬϮϬϭϲ &/E>ǀͲŽĨĨƐŚŽƌĞ WĂŐĞϭŽĨϭ ϭ͘Ϳ D/ZhEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘ Ϯ͘Ϳ EŽƚŝĨLJ&ĂĐŝůŝƚLJKƉĞƌĂƚŽƌŽĨƵƉĐŽŵŝŶŐEŝƚƌŽŐĞŶŽƉĞƌĂƚŝŽŶƐ͘ ϯ͘Ϳ WĞƌĨŽƌŵ WƌĞͲ:Žď ^ĂĨĞƚLJ DĞĞƚŝŶŐ͘ ZĞǀŝĞǁ ŽƉĞƌĂƚŝŶŐ ƉƌŽĐĞĚƵƌĞƐĂŶĚ ĂƉƉƌŽƉƌŝĂƚĞ ^ĂĨĞƚLJ ĂƚĂ ^ŚĞĞƚƐ;ĨŽƌŵĞƌůLJD^^Ϳ͘ ϰ͘Ϳ ŽĐƵŵĞŶƚ ŚĂnjĂƌĚƐ ĂŶĚ ŵŝƚŝŐĂƚŝŽŶ ŵĞĂƐƵƌĞƐ ĂŶĚ ĐŽŶĨŝƌŵ ĨůŽǁ ƉĂƚŚƐ͘ /ŶĐůƵĚĞ ƌĞǀŝĞǁ ŽŶ ĂƐƉŚLJdžŝĂƚŝŽŶ ĐĂƵƐĞĚ ďLJ ŶŝƚƌŽŐĞŶ ĚŝƐƉůĂĐŝŶŐŽdžLJŐĞŶ͘ DŝƚŝŐĂƚŝŽŶ ŵĞĂƐƵƌĞƐ ŝŶĐůƵĚĞĂƉƉƌŽƉƌŝĂƚĞ 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C13 C15 C14 C16 A B C4 C5 C6 C7 C2 C10 C9 C11 C8 C3 P C1 C +LOFRUS$ODVND//&+LOFRUS$ODVND//&Changes to Approved Rig Work Over Sundry Procedure6XEMHFW &KDQJHVWR$SSURYHG6XQGU\3URFHGXUHIRU:HOO 1&RRN,QOHW8QLW%$ 37' 6XQGU\ ;;;;;;$Q\PRGLILFDWLRQVWRDQDSSURYHGVXQGU\ZLOOEHGRFXPHQWHGDQGDSSURYHGEHORZ&KDQJHVWRDQDSSURYHGVXQGU\ZLOOEHFRPPXQLFDWHGWRWKH$2*&&E\WKHULJZRUNRYHU 5:2 ³ILUVWFDOO´HQJLQHHU$2*&&ZULWWHQDSSURYDORIWKHFKDQJHLVUHTXLUHGEHIRUHLPSOHPHQWLQJWKHFKDQJH6HF 3DJH 'DWH 3URFHGXUH&KDQJH 1HZ5HTXLUHG"<1+$.3UHSDUHG%\ ,QLWLDOV +$.$SSURYHG%\ ,QLWLDOV $2*&&:ULWWHQ$SSURYDO5HFHLYHG 3HUVRQDQG'DWH $SSURYDO $VVHW7HDP2SHUDWLRQV0DQDJHU 'DWH3UHSDUHG )LUVW&DOO2SHUDWLRQV(QJLQHHU 'DWH Customer Conoco Phillips Contact Marcus Barbee, Thure Johnson Contact Details Jake Bramwell / Jason Moseley W/ford Location Alaska - Cook Inlet Field/ Well No.NCI A-06 Toolstring Desc.Lower Packer BHA for 374 WidePak RGL System BHA Seq Description Asset Number OD (Inches)ID (Inches)Weight (Lbs) Length (Feet)Total Depth 1 Top Of Packer 3864.89 2 Center Packing Element 3869.99 3 374 Widepak Packer WFT 3.740''2.375" 95.2 Lbs 6.21 3871.10 8 x Setting pins (9600lbs) 5 x Release Pins (6000lbs) 3.5" VAM FJL Pin 2.875" Sealbore ID 3880.2 4 Tubing Punch 3885.7 5 2-Each 9.2# Pup Joints WFT 3.530''2.930'' 92.0 Lbs 19.66 3890.76 3.5" VAM FJL Box x Pin 6 Centralift AVE Sub PCS 3.515''N/A 14.5# 0.44 3891.20 3.5" Vam FJL Box X Pin 7 WP Anchor Seal Latch WFT 3.700''2.240'' 39.8 Lbs 3.67 3893.00 3.5" VAM FJL Box c/w Seal Stack 5 x Release Pins (6000lbs) Dual Flapper Check Valve WFT 1.688"0.790" 3.1 Lbs 0.00 1.0" CS pin X Stub Acme Box 8 Top Of Packer 3893.00 9 Bottom Of Seal Assembly 3894.87 10 Center Packing Element 3898.00 11 374 Widepak Packer WFT 3.740''2.375'' 95.2 Lbs 6.21 3899.21 8 x Setting pins (9600 lbs) 5 x Release Pins (6000lbs) 2.875" WTS-8 Pin 2.875" Sealbore ID 12 Slotted Sub WFT 3.215''2.375'' 10.3 Lbs 1.34 3900.55 2.875" WTS-8 Box x Stub Acme Box Stinger Rod w/ DFCV WFT 1.750"0.875" 41.6 Lbs 6.56 3901.43 1" CS Pin X Guide Nose c/w Seal Stack 13 PBR - Seal Bore WFT 2.875''1.750'' 26.3 Lbs 0.96 3901.53 Stub Acme Pin x 2.375" WTS-8 Pin 14 Torq-Thru Quick Connect WFT 2.875''1.375'' 25.0 Lbs 1.66 3903.21 2.375" WTS-8 Box x 1.900 NU 10rd Pin 15 23-JTS" Of Jointed Pipe CoP 2.115''1.560'' 746.46 4649.67 1.90" NU 10RD, 2.75lb/ft 16 2.375" Dual Flapper Assembly WFT 2.375''0.375" 10.0 Lbs 0.78 4650.45 1.900" NU 10RD Box x Bullnose w/ 3/8" Restriction for Flow control PREPARED BY: Joe Bob Maddox & Howard Bolton Weight : 438 Lbs Date 9/29/12 TRADE SECRET AND CONFIDENTIAL Copyright © Weatherford Inc. 2012 Wallace, Chris D (CED) From: Holly Tipton <hotipton@hilcorp.com> Sent: Monday, August 26, 2019 12:19 PM To: Wallace, Chris D (CED) Subject: NCIU B -01A (PTD# 198-002) Pump -in Differential Temperature Log Attachments: NCIU B -01A (PTD 198-002) Temp Survey -August 2019 .pdf.xlsx; NCI B -01A Schematic 2019-08-21.pdf Hi Chris, On 8-24-19, a pump -in differential temp survey was performed on the 5-1/2" production tubing in the NCIU B -01A (PTD# 198-002) per Rule 4 of DID 33 to evaluate injected fluid isolation. A baseline temperature pass was logged in the 5-1/2" production tubing from surface to 3,619' MD while the well was shut-in and static for over 24 hours. The well was then placed on injection for several hours for a total of 158 bbls of produced water at 60 degrees F. While pumping down the disposal string, a pass was made over the same interval in the 5-1/2" production tubing. There were no indications of out of zone injection, channels, or other anomalies in the temperature profile. By all indications injection is solely into the perforated interval and is confined without upward or downward movement near the wellbore. All annulus pressures were monitored before injection, during injection, and after injection and no signs of annular communication are present. Please see attached for log performed and the wellbore schematic. Up until this email, production on the Tyonek platform has been curtailed due to lack of produced water disposal options with the NCIU A-13 Class I well out of service. With the successful pump -in differential temp survey on the NCIU B -01A Class II well and this email notification, we will now be returning the high water producing wells to production. If you see any problems with this interpretation, please let me know at your earliest convenience. Thank you, Holly Tipton Regulatory Tech - CIO Asset Team Hilcorp Alaska, LLC o: (907) 777-8330 1 m: (281) 543-8964 e: hotiotonPhilcorp.com W1 The information contained in this a -mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication maybe legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. PiD ! i % `00.20 ®v 'vim ®ee ii ��G������• is ��C CCCQC �1j :: e Sm 12L �_p : .00 0.0 7 :: iC • • ` G 2 Hilcorp Alaska, LLC -e 3800 Centerpoint Drive Suite 1400 M1\R a ?c,)7 Anchorage,AK 99503 Phone: 907-777-8321 Fax:907-777-8580 March 27, 2017 Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission SCANNED APR 1 0 2f:.,17, 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: NCIU Class II injection surveillance summary (DIO 17 and 33) Dear Ms. Foerster: Hilcorp Alaska, LLC ("Hilcorp"), as Operator of North Cook Inlet Field (effective November 2016) hereby submits the report required by DIO 17 (rule 4) and DIO 33(rule 6) establishing the DIO for the Class II Water Disposal wells at NCIU A-12 and B-01A respectively for the calendar year of 2016. Surveillance Summary No fluid was injected into NCIU A-12 and minimal volumes were injected into NCIU B- O 1 A within the year 2016. A passing mechanical integrity test was performed on the well on 5/10/2015 and is required bi-annually to retain disposal approval status. Sincerely, v Reis Edwards Reservoir Engineer • S Wallace, Chris D (DOA) From: Kautz, Rachel <Rachel.Kautz@conocophillips.com> Sent: Wednesday, April 27, 2016 8:16 AM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler Subject: NCIU B-01A (PTD# 198-002) Pump-in Differential Temperature Log Attachments: NCI B-01A.pdf; NCI B-01A (PTD# 198-002) Temp Survey_April 2016.xlsx Chris, To satisfy Rule 4 of DIO 33 for NCIU's B-01A(PTD# 198-002), ConocoPhillips has completed a pump-in differential temperature log in the 5-1/2" production tubing to evaluate injected fluid isolation. Attached is the log performed on B- 01A and a well schematic. Pump-in Differential Temperature Log Interpretation: On April 16, 2016, a Pump-In Differential Temperature Log was performed on NCI B-01A to verify injected fluid isolation to the perforated interval. A baseline temperature pass was logged in the 5-1/2" production tubing from surface to 3624' MD (3407'TVD) while the well was shut-in and static for over 24 hours. The well was then placed on injection for several hours with a total of 168 bbls of produced water at 60 °F injected down the 2-3/8" disposal string for the log. While pumping down the disposal string, a pass was made over the same interval in the 5-1/2" production tubing. There were no indications of out of zone injection, channels or other anomalies in the temperature profiles.All annulus pressures were monitored before, during, and after injection and no signs of annular communication are present. Please let me know if there is any other information you will need at this time or would like to discuss any of this information further. Regards, Rachel Kautz Well Integrity Engineer EQ MAY 0 9 ?Q16 ConocoPhillips Alaska, Inc. SCON Temp.Slope Phone:907-659-7126 1 • • IConocoPhillips Well: NCI B-01A I Field: North Cook Inlet 4/16/2016 I Pressure(psia) 400 410 420 430 440 0 250 - >� ------ -- 1 Pressure-TemperatureRIH Profile 500 Overlay 750 1000 1250 _ _ 1500 -. d te- W : .4,, 1750 2000 CL m = 0 - 2250 2500 ,-- -- 2750 Is3000 3250 Disposal Perforations 3500 — 3500'-3540'MD —milk \ 3750 , I I I I I 45 50 55 60 65 70 Temperature(Deg. F) -Pressure Inj - Perfs ,_ Valve —30" -20" 13 3/8" 9 5/8" TBG " Packer —Baseline Press Temperature Inj —Baseline Temp SAK PROD • NCI B-01A ConocoPhillips FAWell Attributes Max Angle&MD TD t 18$k8.IfiC i Wahiawa APII(IWI Field Name Wellbore Statue not C) MD MIK(4) Act BM,(ROB) t,.,,A REr, 508832009301 COOK INLET PROD 38.53 7,939.01 16.720.0 - Comment 1125(ppm) Date Annotation End Date 08Lrd(ft) `Rig Release Date NCI B0IA6/4201525936 PM SSSV:LOCKED OUT Last WO: 12/1812003 10/21/1997 Vertical schematic(actual) Annotation Depth(ttKB) End Date Annotation Last Mod By End Date HANGER:53.6 1 -...illi Last Tag:RK6 8,8070 7/31/2011 Rev Reason'SSSV LOCK OUT,INSTALL SSSV smsmith 5/19/2015 &GLV Itt rings asinnn St W[ .J L, Caaing Description OD(In) ID(In) Top(MOB) Set Depth(NKB) Set Depth(TVD)...WNLen(I...Grade Top Thread f f CONDUCTOR 30 27.000 54.0 407.0 407.0 120.00 H-40 WELDED Casing Description OD(In) ID(In) Top(ttKB) Bet Depth(ttKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread SURFACE 20 18.730 57.0 2,579.0 2,510.9 133.00 K-55 BUTT Casing Deecrlptlon OD(In) ID(In) Top(ttKB) 5e1 Depth(RKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread INTERMEDIATE 133/8 12.347 56.8 3.760.0 3,514.4 72.00 N-80 N-80 Casing Description OD(In) ID(In) Top(ItKB) Set Depth(tt613) Set Depth(TVD)...Wt/Len(I...Grade Top Thread CONDUCTOR:54.0-4070 A WINDOW 10 8.000 9.590.0 9,600.0 8,2120 55.50 SAFETY 1/1-V;409.9 in--1671 III' Casing Description OD(inl ID(In) Top(1tK61 Set Depth(ftKB) Set Depth(TVD)...WULen II...Grade Top Thread PRODUCTION 95/8 8535 55.5 10.376.5 53.50 P-110 BUTT GAS LIFT:1.558.6 Casing Deattlptlon OD(In) ID(In) Top(ttKB) Sel Depth(MOB) Set Depth(TVD)...WflLen(I...Grade Top Thread DRILL PIPE LINER 5 4.408 10.074.0 16.650.0 16.25 6135 4.51E DISPOSAL;54.0 Tubing Strings SURFACE;57.0-2,579.0 Tubing Description String Ma...ID(In) Top(RKB) Set Depth(ft..f Set Depth(TVD)(...Wt(lb/ft) Grade Top Connection TUBING Upper 5 1/2 4.950 53.6 3,687.81 3,457.0 15.50 L-80 BTCMOD GAS LIFT,2,675.4 - Completion Details Nominal ID (PERF;3,5000-1.540.0-- I - ( Top(COB) Top(TVD)(RKB) Top Inel(•) Item Dee Com (In) 53.6 53.6 0.05 HANGER FMC TUBING HANGER 5.500 PACKER:3,592.0 _ 409.9 409.9 0.27 SAFETYVLV CAMCO TRM-4E TR SSSV.LOCKED OUT 12/5/2014 4.562 SUB;3.59204 TUBING;3,599.1 3,667.1 3,4-40.6 37.73 SEAL ASSY -BAKER 6-22 PBR Anchor Seal Assembly w/15'seals 4.750 SUB:3,603.8 ` - ' GAS LIFT;3,601.8 �'e'I Tubing Description String Ma...ID(In) Top(RK8) -Set Depth(ft..fset Depth(TVD)(...Wt(lb/ft) Grade Top Connection EXTENSION;3.604.4 -St TUBING Lower 51/2 4.950 3.670.5 3.76361 3.517.3 15.50 L-80 BTCM STOP;3.5670 Ma•- SUB;3613.4 '-e°- ` `r Completion Details EXTENSION;3.614 4 ' II M!..1.„ SUB. `� I Nominal ID SUB,3.623.4 l TopftK8 To TVD RKB To LATCH'.33,235.50 .623 8 1 ) P(TVD)( 1 P Intl(°) Item Dee Com (in) FL4PPER VALVE;3,825.0 3,670.5 3,443.3 37.70 PBR 190-60 PBR w/15'SEAL TRAVEL 4.750- PATINGER:3,625.0 1111' 3,700.4 3.467.0 3747 NIPPLE 'X'LANDING NIPPLE 4.562 STINGER;3,6250 PERFP.3,631.1-3032.6 1�.'.. SUB: 3632.1 I 3,762.4 3,516.3 37.01 SEAL ASSY 190-60 S-22 ANCHOR LATCH SEAL ASSEMBLY 4.750 PBR:3.632.8 ■u�l! (ABOVE SC-1R PACKER) CONNECT;3,833.8 111°E Tubing Description String Ma...ID(In) Top 0003) Set Depth(R...Set Depth(TVD)(...WI(lb/ft) Grade Top Connection GRAVEL PACK 4 3.500 3.763.7 6.868.0 6,026.7 15.50 SLHT Completion Details .1 Nominal ID SEAL ASSY;3,667 Top MKS) Top(TVD)(RKB) Top Incl(°) Item Des Com (In) PBR;3,670.5 IC 3,763.7 3,517.3 37.00 PACKER BAKER SC-1R PACKER 6.000 L' j 3,796.7 3,543.7 36.75 KOIV BAKER KOIV MODEL C 5.000 NIPPLE;3,7005 4,015.7 3,720.7 35.48 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892 I = 4,0245 3,7279 3543 SCREEN 3.600 ■ _ 4,367.7 4,009.5 35.01 PACKER BAKER SC-(R PACKER 4.940 INTERMEDIATE;56.4-3,7600 I 4,370.7 4,012.0 35.03 SCREEN 3.600 SEAL AWN 3,762.4 $ 4,608.7 4,204.8 36.91 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892 PACKER:3.763.6 RON;3,796,6 14.617.5 4,211.9 3690 SCREEN 3.600 KOH;3,768.8 1 4,880.7 4,423.4 35.98 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892' BLOTS 3 850.0-3,869.0- 4.968 7 4,494.7 35.77 SUMP BAKER SC-2 SUMP PACKER 4.940 BLOTS;3406.00,893.0 _ PACKER SCREEN;4,021.5 I 5,578.7 4,987.5 37.58 NIPPLE BAKER'X'NIPPLE 3.813 SLOTS 4,185.0-4,206.0 1 SLOTS. 775.04,365.0 = 5,613.2 5,014937.52 PACKER BAKER SC-1R PACKER 4.750 PACKER.4,367.6 I 5,646.9 5,041.6 37.35 KOIV 3.500 RPERF:3 8500-4,955.0, - SLOTS,4429.0-4.480.0` , c 5,648.8 5,043.2 37.33 SCREEN 3.500 SCREEN:4,3707 3 - (- 6,786.8 5,959.5 34.30 SUMP BAKER SC-2 SUMP PACKER 6.000 SCREEN;4,617.5 PACKER SLOTS;4.751.04.761.0 SLOTS,4.792.0-4.803.0 6,836.4 6,000,5 34.16 NIPPLE BAKER')C NIPPLE 2.813 6.867.2 6,026.0 34.23 WLEG BAKER WIRELINE ENTRY GUIDE 3.000 SLOTS.4 922.0-4.955.0, SUMP PACKER.4,988.7 Other In Hole(Wlreilne retrievable plugs,valves,pumps,fish,etc.) TUBING;3536.5, SUB.3.017.1-3Top(TVD) TapIMel NIPPLE;5,578 7 Top(RKB( (RKB) (°) Den Com Run Data ID(In) PACKER.5,013.2 6 54.0 54.0 0.05 DISPOSAL 23!8'DISPOSAL STRING TO3663' 7!31/1997 KON',5,6469 IN 417.0 417.0 0.31 SSSV OTISX STYLE WIRELINE RETRIEVABLE SSSV 12/19/2104 SLOTS.5.718.0-5,742.0 3,567.0 3.361.0 36.52 STOP TRYTON MAX FRAC PLUG,TUBING STOP 3/28/2015 3.000 SLOTS'3.88505.682 aI - 3.599.1 3.386.7 37.06 TUBING PUP JOINT,3-1/2".9.2 ppf VAM FJL BOX X PIN 4/3/2015 2.992 SLOTS 5.92805.939.0 - 3.604.4 3,390.9 37.14'EXTENSION PUP JOINT,3.875"STUB ACME G2 PIN X PIN 4/3/2015 3.000 SLOTS;3.948.05.988.0 3.614.4 3,398.8 37.31 EXTENSION PUP JOINT,3.875"STUB ACME G2 PIN X PIN 4/32015 3.000 SLOTS;5.985.08.032.0 I 3,623.9 3.406.4 37.47 LATCH WP ANCHOR SEAL LATCH 4,3/2015 2.875 SLOTS;8.076.08,081.0 I I 3,625.0 3.407.3 37.49 PACKER 450 WEATHERFORD WIDEPACK LOWER 4/1/2015 3.000 SLOTS;6.1 18.08.124.0 1 PACKER SLOTS.6140.0-6,159.0, = Blois.8.te9.O6,te2.o 3,625.0' 3.407.3 37.49 FLAPPER DUAL FLAPPER CHECK VALVE 4/3/2015 0.790 SCREEN;5.646.8-1 - I c' VALVE RPERF:5718.0-8,767.0 _ c SLOTS,6,2630-6290.4 3,625.0 3,407.3 37.49 STINGER STINGER ROD 4/3/2015 0.875 SLOTS.6.375.0-8,390.0 3,632.6 1413.3 37.61 PBR PBR-SEAL BORE/3.48'NoGo 4/12015 1.750 SLLOTS.8.610.046224 3,633.8 3.414.3 37.63 CONNECT TORQ-THRU QUICK CONNECT 4/1:2015 1.375 SLOTS'6,762.0.6.1670 i I - SUMP PACKER:8.766.6 3.636.5 3,416.4 37.68 TUBING HS-90 COIL TUBING.2.00'OD 0.125'WALL 4/1/2015 1.750 i'' THICKNESS CONNECTOR;6,816.5 6.816.5 5.984.1 34.11 CONNECTO COIL TUBING INTERNAL DIMPLE CONNECTOR 4/1/2015 1.420 I_T. R NIPPLE;4836 3 Perforations&Slots WLEO:8.067.2 IS - SLOTS 8097.0-9,107.0 -- Shot Dene - Top(TVD) atm(TVD) (shotNlf WINDOW A;9.590.00.600.0 I. Top(ttKB) Btm MKS) (1108) )RKB) Zone Date II Type Com 3.500.0 3.540.0 3,306.9 3,339.2 9/9/1997 4.0 [PERF 3 WL runs w/4.5"casing :-: guns)4 SPF PRODU C TION;55.513,074.5 GRILL PIPE LINER',11 0?ll) 18.6500 ti -ill SAK PROD • NCI B-01A ConocoPhillips - Alaska,Inc. I mn[MHBIps - -• Comment NCI13-015,6/0120152'5939 PM OTIS X STYLE WIRELINE RET._ Vertical schematic(actual) HANGER.516 L,I^ F Perforations&Slots 6 Shot I / Denn I Top(TVD) Blm(TVD) (shotsif Top(ftKB) Blot(ItKB) (SKIS) 106131 Zone Date 1) Type Com 3.631.1 3,632.7 3,412.1 3,413.4 4/1/2015 PERFP Slotted Sub 3,850.0 4.955.0 3.586.6 4,483.6 12/8/2003 18.0 RPERF 2003 workover Perfs w/TCP guns CONDUCTOR;54.0.407.0 SAFETY vLv;Iw93,850.0 3.869.0 3,586.6 3,601.9 2!511998 32.0 SLOTS 3.886.0 3.893.0 3,615.6 3,621.3 2/5/1998 32.0 SLOTS GAS LIFT;1,558.8 I 4,185.0 4.268.0 3,859.3 3,927.6 C.I.1,NCI B- 2/511998 32.0 SLOTS DISPOSAL;54.0 01 4.275.0 4.365.0 3.933.3 4,007.3 C.I.2,NCI B- 2/5/1998 32.0 SLOTS SURFACE:57.0-2,579.001 GAS LIFT;2,875.4 4,429.0 4,480.0 4,059.6 4,101.0 C.I.4,NCI B- 2/5/1998 32.0 SLOTS 01 'Pew 3500.0-3.540.0t. ( 4,751.0 4.761.0 4.318.8 4,326.9 C.I.8,NCI B- 2/5/1998 32.0 SLOTS 01 PACKER:3,552.0 - 4,792.0 4,803.0 4,351.8 4,360.7 C.I.8,NCI B- 2/5/1998 32.0 SLOTS SUB:3.582.0 �' TUBING;3,599.1 1�I 01 SUB:3.603.6. P 1 4,922.0 4.955.0 4,456.9 4,483.6 C.I.11,NCI B 2/5/1998 32.0 SLOTS - GAS LIFT:3.801.8 EXTENSION:3.604.4 !r _1- -01 STOP 8.3:567.0 �• (F SUB:3.8131 5,718.0 6.767.0 5,098.4 5.943,2 12/1/2003 18.0 RPERF 2003 workover Perts EXTENSION:3.61/-1 ' I w/TCP guns SUB.3.823. . ', LATCH:3.623.9 �� . 5,718.0 5.742.0 5.098.4 5,117.7 BELG-F,NCI 2/5/1998 32.0 SLOTS FLAPPER VALVE,3825.0 6-01 PACKER:3.620.0 STINGER:3.625.0 * 5,885.0 5,892.0 5.233.4 5,239.2 BELG-G,NCI 2/5/1998 32.0 SLOTS PER FP.3,631.1.3.632.8 �i:71 B-01 SUB:3.631 1I I PER.3. 832.8 111. 5,929.0 5.939.0 5,269.5 5,277.7 BELCH.NCI 2/5/7998 32.0 SLOTS CONNECT,3,833.8 t 6-01 II 5,948.0 5,969.0 5,285.0 5,302.2 BELG-H,NCI 2!511998 32.0 SLOTS B-01 SEAL.59/;36671 5,995.0 6.032.0 5,323.2 5,353.0 BELG-H.NCI 2/5/1998 32.0 SLOTS PBR:3.670.5 B-01 6,078.0 6.091.0 5,389.9 5,400.3 BELG-I,NCI 2/5/1998 32.0 SLOTS B-01 NIPPLE;3,700 5 3 6,097.0 9.107.0 5,405.1 7,817.3 2/5/1998 32.0 SLOTS 6,118.0 6.124.0 5,421.9 5,426.7 BELG-I,NCI 2/5/1998 32.0 SLOTS B-01 INTERMEDIATE:568-37600- 6,148.0 6,158.0 5,445.8 5,453.8 BELG-I.NCI 2/5/1998 32.0 SLOTS SEAL ASSY;3.762 4 * B-01 PACKER.3.763.6 . II 6,169.0 6,182.0 5,462.6 5,472.9 BELG-I,NCI 2/5/1998 32.0 SLOTS KOIV;3,796.8 n l B-01 - 6,283.0 6,290.0 5,553.3 5,558.8 BELG-d NCI 2/5/1998 32.0 SLOTS SLOTS'.3 8500-3,869.0 - 8-01 SLOTS,3886.0-3,863.0 - 6,375.0 6,390.0 5,626.6 5,638.6 BELG-L,NCI 2/5/1998 32.0 SLOTS - 8-01 SCREEN;4,024 5, SLOTS.4,1RS.0-1.208.0 " 6,610.0 6.622.0 5,815.4 5,825.0 BELG-M,NCI 2/5/1998 32.0 SLOTS SLOTS 4.275.0-4,3650 - - 0-01 PACKER:4.367.8 R PERF'3.850.0.4.955.0-56,762.0 6,767.0 5,939.0 5,943.2 BELG-O,NCI 2/5/1998 32.0 SLOTS SLOTS;1.129.0.1.180.01 - 8-01 SCREEN;1.3707 SCREEN.4,817.51 - I I- Mandrel Inserts SLOTS 4.751.0-4.761.0 - - SI SLOTS;4,792.0-4.803.0 Ili all Top(TVD) Valve Latch Pon Size TRO Run ( N Top(1168) (KIM Make Model 00110) Sery Type Type (I0) (pal) Run Date Com SLOTSa 922.0./,955.0__ !- -1 1,558.6 1,552.1 CAMCO MMG 11/2 GAS LIFT OMY RK 0.000 0.0 4/30(2015 SUMP PACK2:11:955.7 TUBING;3,63651 4E 2 2,675.4 2,598.0 CAMCO MMG 11/2 GAS LIFT DMY RK 0.000 0.0 4/30/2015 SUE.5,578 a 3 3,601.6 3,388.7 CAMCO MMG 1/2 GAS LIFT -OV RK 0.000 0.0 7/7/2012 NIPPLE;3,376 7 PACKER,5.813.2 Notes:General&Safety KOIV;5,646 8 End Date Annotation 61.078.5.718.25,712.0 7/30/1997 NOTE:Two 2-318 tubing strings were run w/the 13-3/8 surface casing. SLOTS:5.885.0-5.892.0 2/511998 NOTE:SIDETRACK'A' SLOTS 5.0260.5,639.0 _ 2/7/2011 NOTE:View Scheamtic w.l Alaska Schemabc9.OREV SLOTS;5.948.0-5.969.0 8/7/2011 NOTE:Establish Int rate#8 bpm#1000 psi down 13-3/8" SLOTS,5.995.0-6.032.0 ._ - 8/7/2011 -NOTE:1.5 bpm down 2-3/8"kb 1400 psi.down the 13.3/8"casing from 3500-3540' SLOTS;6,078.0.6.091.0 SLOTS;6.118.0-6.124.0 - - SLOTS:0148.0.8.158.0, - SLOTS.8.189.0.8,182.0 _ SCREEN.5.646.0 - E. - RPERF:5 718.06.767.0 SLOTS.6,283.0-8.290.0 - F BLOTS.8.375.0.8.3911.0 _ SLOTS.8.610.0-8.622.0 SLOTS 6 762.0-6.767.0 SUMP PACKER,6.786.8 CONNECTOR;6,8165 NIPPLE;6.8363 - WLEG;6.667.2, _. SLOTS:6 067.0-9.1070 1 WINDOW A;9.590.0-9.600.0 I • 1 PRODUCTION;55.5-10.376.5, DRILL PIPE LINER;10.0710- . 16.850.0 WELL HISTORY FILE COVER PAGE XHVZS This page identifies oversize material and digital information available for this individual Well History file and weather or not it is available in the LaserFiche file. Please insure that it remains as the first page in this file. / 9 If ~~ ell History File # Digital Data 0 CD's - # 0 DVD's - # 0 Diskettes - # Added to LaserFiche File 0 Yes 0 No 0 Yes 0 No 0 Yes 0 No Oversized Material Added to LaserFiche File 0 Maps # 0 Yes 0 No 0 Yes 0 No 0 Yes 0 No 0 Mud Logs # - 0 Other # General Notes or Comments about this file. If any of the information listed above is not available in the LaserFiche file you may contact the Alaska Oil & Gas Conservation Commission to request copies. Please call Robin Deason at (907) 793-1225 if you have any questions or information requests regarding this file. • STATE OF ALASKA • i( '. ''ED ALA. OIL AND GAS CONSERVATION COMMISSION It - .. Z REPORT OF SUNDRY WELL OPERATIONS (�'�`(�; 1. Operations Performed: Abandon j'-- Repair w ell r Plug Perforations r Perforate r . 0 5 �° °�' Alter Casing r Pull Tubing r Stimulate - Frac r Waiver r Time Extension fl Change Approved Program I- Operat. Shutdow n r Stimulate - Other r Re -enter Suspended WeII r 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory E 198 -002 3. Address: 6. API Number: ^ ,rye P. O. Box 100360, Anchorage, Alaska 99510 Stratigraphic r Service 50- 883 - 20093 -01 —OD 7. Property Designation (Lease Number): SH\ 8. Well Name and Number: North Cook Inlet — rte' 1 1,s 8 it 1 t t -, NCI B -01A 9. Logs (List logs and submit electronic and printed data pe 20AAC25.07 10. Field /Pool(s): Cook Inlet p 1 ARIi GA51 funk w.6-f 11. Present Well Condition Summary: " girl / 1 ( f f - Total Depth measured 16720 feet Plugs (measured) None true vertical 12943 feet Junk (measured) None Effective Depth measured 0 feet Packer (measured) 3764, 4368, 5613 true vertical 0 feet (true vertucal) 3517, 4009, 5015 Casing Length Size MD TVD Burst Collapse CONDUCTOR 353 30 407 407 SURFACE 2522 20 2579 2511 INTERMEDIATE 3703 13.375 3760 3515 PRODUCTION 10321 13.375 10376 Perforation depth: Measured depth: injection perfs 3500 -3540 True Vertical Depth: injection perfs 3307 - 3339 11 L. Tubing (size, grade, MD, and TVD) 3.5, L -80, 6867 MD, 6026 TVD Packers & SSSV (type, MD, and TVD) PACKER - BAKER SC - R PACKER @ 3764 MD and 3517 TVD PACKER - BAKER SC -1 R PACKER @ 4368 MD and 4009 TVD PACKER - BAKER SC-1R PACKER @ 5613 MD and 5015 TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil - Bbl Gas - Mcf Water - Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 14. Attachments 15. Well Class after work: Copies of Logs and Surveys run Exploratory r Development 17 • Service Pi Stratigraphic r / 16. Well Status after work: Oil r Gas Pr WDSPL P Daily Report of Well Operations x GSTOR WA G GIN J SU C` WI r r r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 312 -116 Contact Printed Name Dethlefs Title Well Integrity Director Signature L ac . j (, (--- 75. 907- 265 -1464 Date jj�y>�� vi- Form 10-404 Revised 11/2011 NOV 14 2012 Submit Original Only 1, /j4/J ,4 ` i • • ConocoPhillips Alaska, Inc. Well Service Report Summary NCI B -01A Class II Disposal Well PTD 198 -002 4/24/12 - Gaslift RU SL, BRUSH #3 GLM, PULL #3 GLV, SET DV IN #3 GLM, PT IA W /LIFT GAS, STOPPED AT 680 PSI, IA/OA TRACKING, SPOKE TO WELL INTEGRITY, WILL PUT ON DHD SCHEDULE, TURN OVER TO PRODUCTION, JOB COMPLETE (Note: The results of the suspected communication was reported via 10 -404 dated 10/17/12) 4/23/12 — Temperature Log RIH W /PT GAUGES, BASELINE LOG WITH WELL SHUT -IN, RU PUMP TO ANNULAR INJECTOR, 2ND LOG WHILE ON INJECTION, CHECK DATA, DATA GOOD, SEND TO BRIAN BUCK. PUMPED 300 BBLS WATER FOR TEMPERATURE LOG 4/22/12 — Gaslift for Logging SUNDAY OPS SAFETY MEETING, GET PERMIT, PJSM, MU TOOLS, HAD TROUBLE LOCATING AND LATCHING #3 GLV, MAKE SEVERAL ATTEMPTS, SET DV IN #2 GLM, PULL CATCHER, PREP FOR INJECTION LOGGING, SHUT DOWN FOR NIGHT, IN PROGRESS 4/21/12 — Gaslift for Logging TRAVEL TO PLATFORM, GET PERMIT, PJSM, RU SL, FUNCTION PT WIRELINE VALVE 250/2500, SET CATCHER, MU 5.5" OM -1, BEGIN GLV CHANGE OUT, SHUTDOWN FOR NIGHT, IN PROGRESS 4/6/12 — Tag Run Ran in Hole with 2.5" DD bailer and tagged at 8678' SLMD, unit rigged back and shut down for the night. Well handed back to production. Job Complete HLUEIVELI STATE OF ALASKA `�C 1 9 2012 ALA OIL AND GAS CONSERVATION COM ION REPORT OF SUNDRY WELL OPERATIONS AOGCC 1. Operations Performed: Abandon r Repair well f Rug Perforations (m Perforate [ Other P Alter Casing r Pull Tubing r stimulate- Frac fl Waiver (— Time Extension r Change Approved Program r Operat. Shutdow n (° Stimulate - Other r Re -enter Suspended Well -- 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory r — 198 -002 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 Stratigraphic r Service (� 50- 883 - 20093 -01 7. Property Designation (Lease Number): &'" 8. Well Name and Number: ,, � North Cook Inlet — :�JL I ig 'g L � o ! J 9 NCI B -01 A ern 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): tat 1q Cook Inlet %� LAP l IA/ PS1 t 11. Present Well Condition Summary: ' Total Depth measured 16720 feet Plugs (measured) None true vertical 12943 feet Junk (measured) None Effective Depth measured 0 feet Packer (measured) 3764, 4368, 5613 true vertical 0 feet (true vertucal) 3517, 4009, 5015 Casing Length Size MD TVD Burst Collapse CONDUCTOR 353 30 407 407 SURFACE 2522 20 2579 2511 INTERMEDIATE 3703 13.375 3760 3515 PRODUCTION 10321 13.375 10376 Perforation depth: Measured depth: injection perfs 3500 -3540 SCANNED JAN 2013 True Vertical Depth: injection perfs 3307 -3339 Tubing (size, grade, MD, and TVD) 3.5, L - 80, 6867 MD, 6026 TVD Packers & SSSV (type, MD, and TVD) PACKER -BAKER SC-1R PACKER @ 37 MD and 3517 TVD PACKER - BAKER SC -1 R PACKER @ 4368 MD and 4009 TVD PACKER - BAKER SC-1R PACKER @ 5613 MD and 5015 TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil - Bbl Gas - Mcf Water - Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 14. Attachments 15. Well Class after work: — Copies of Logs and Surveys run Exploratory r Development J7 Service P' Stratigraphic E 16. Well Status after work: Oil r Gas J WDSPL P Daily Report of Well Operations GSTOR r WIND r WAG r GINJ r SUSP r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N/A Contact Printed Name Jerry Dethlefs Title Well Integrity Director Signature ,f c , e 907 - 265 -1464 Date �,/, � OF b Form 10-404 Revised 11/2011 FRO MS OCT 1 9 7012, ) ( 4)f - '.. ■ Atli Submit Or jnal Only • • ConocoPh i l l i ps Alaska RECEIVED P.O. BOX 100360 0 1: i 1 7 ANCHORAGE, ALASKA 99510 -0360 �y A C.: October 17 2012 Mr. Jim Regg Alaska Oil & Gas Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Regg: Enclosed please find a Sundry 10 -404 report of Well Operations regarding Tyonek well NCIU B -01A (PTD 198 -002) Class II disposal well. Please call me @ 265 -1464 if you have any questions. Sincerely, Jerry Dethlefs Well Integrity Director Attachments • • ConocoPhillips Alaska, Inc. Well Service Report Summary NCI B -01A Class II Disposal Well PTD 198 -002 On June 25, 2012, ConocoPhillips Alaska (CPAI) reported to the AOGCC of a potential failed MIT on NCI B -01A, a Class II disposal well located on the Tyonek platform. The well is a combination producer and disposal well; Class II disposal is approved into the 'B' annulus of the well, which is perforated and intended for disposal reinjection. The wellhead packoff assembly provides isolation between the producer tubulars and the annular injection flowpath. If the packoffs leak then the isolation is lost between the injection zone and the production casing of the well. Leaking packoffs were the reason for the report on June 25, 2012 to the AOGCC. The packoffs were successfully energized by the wellhead vendor on 07/02/12, which re- established the seal between the injection interval and producer tubulars of the well. J As specified by the AOGCC on 07/11/12, a 10 -404 and 90 -day annular trend plots are being submitted to demonstrate that the annular communication issue has been reso The enclosed trend plot illustrates the communication in early July, and no problems are evident since the packoffs were repaired. CPAI / intends to keep the packoff assembly on a service program to maintain the assembly in good condition. v The following events detail the work performed on the well regarding the annular communication and repair of the packoff assembly. 6/23/2012 Monitor WHPs T /I /O= 85/220/210, IA FL @ 315' (600 fps), OA FL @ NS 6/24/2012 IC -POT (Failed), IC -PPPOT (Failed), MITIA (Failed) Initial T /I /O= 85/220/220/10 (10 psi on side string) Stung into IC -PO with 200 psi, would not bleed to 0 psi. Rigged up to IA to pressure IA up to 1000 psi with gas. Injected gas for over an hour (1:15) with the IA building to 420 psi with the OA slowly tracking it. The OA is perforated so the OA is bleeding down through the perfs. Stung into the IC PO during the test which showed the pressure tracking the IA. Shut down the gas injecting into the IA. IC- POT -- (Failed) Could not get the PO to bleed to 0 psi, would build back immediately. IC -PPPOT (Failed) Attempted to pressure up the PO with Hyd. Fluid, pumped right through with immediate fall off to 400 psi. Final T /I /0= 85/420/315/10 (side string had 120 psi) 6/25/2012 Report to AOGCC regarding failed MIT. Jim: I am reporting a failed MIT on NCIU B -01A (PTD 198 -002). During a diagnostic checkout of the well on 6/24/12 the wellhead packoffs were tested and failed to hold pressure between the IA and OA. The OA is perforated on this well and is the flowpath for Class II injection. Since the packoff leak is substantial, a pressure differential with gas could not be established between the IA and OA and therefore we are classifying as a failed MIT. The next course of action will be to evaluate options for regaining packoff integrity. NCIU B -01A will not be used for injection until approved by the AOGCC. 7/2/2012 TEST /REENERGIZE 9 5/8 PACK OFF, TEST 13 3/8 PACKOFF, TEST GOOD, JOB COMPLETE. FMC rep performed POT and energized 10K wellhead with packing compound. 7/5/2012 PRESSURE TEST IA W /GAS TO 800 PSI, 12 HRS W /NO CHANGE IN IA OR OA PRESSURE • • 717/2012 • INSTALL GASLIFT DESIGN, BLEED DOWN IA, ALL VALVES HOLDING, JOB COMPLETE 7/11/2012 AOGCC requested 10-404 after 90 days with verification that IA x OA communication is not present and q Y P there are no problems with the wellhead. 8/30/2012 Monitor WHPS T /I /O /OO= 85/700/180/0 ■ , NCU B -01A Class II Injection Well T /I /O 90 Day Pressure Data 800 700 600 • 500 y 0 _ —t- Flowing Tubing Pressure • 400 i --m— Inner Annulus Pressure d Outer Annulus Pressure o_ 300 — 200 — t 100 —N• 0 1 ' \q \ gyp 1, \ ` 9 \gy \ ` , \ `L9 \p - 1, \ `1p 1, \ \7 1, c , • Date K CI B -01A Conoc©Phillips Well Attribut UW Max Angle TD 'a( inn I , Wellborn API/I Feld Name Well Status Intl ( °) MD (ft ) Act Btm (ftKB) CAM - ull -_ , 508832009301 COOK INLET PROD 38.53 7,939.01 16,720.0 Comment H2S (ppm) Date Annotation End Date KB-Grd (ft) Rig Release Date •- SSSV: TRDP Last WO: 12/18/2003 10/21/1997 Well ConfiA: -NCI I3-01A, 9/5/20129: 20: 55 AM Schepetic - Actual Annotation Depth (ftKB) End Date Annotation Last Mod ... End Date --- - - - - -- ` - - - -- ----- - - - - -- Last Tag: RKB 8,807.0 7/31/2011 Rev Reason: GLV C/O ninam 9/5/2012 HANGER, E °„ M - '- Casing Strings Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD)... String Wt.. String ... String Top Thrd IlM i P CONDUCTOR 30 27.000 54.0 407.0 407.0 120.00 H - 40 WELDED ' - Casing Description String 0... String ID ... Top (ftKB) Set Depth (1... Set Depth (TVD)... String Wt.. String ... String Top Thrd SURFACE 20 18.730 57.0 2,579.0 2,510.9 133.00 K - 55 BUTT Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND) ... String Wt.. String ... String Top Thrd INTERMEDIATE 13 3/8 12.347 56.8 3,760.0 3,514.8 72.00 N - 80 N - 80 Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND) ... String Wt.. String ... String Top Thrd or WINDOW A 10 8.000 9,590.0 9,600.0 8,212.0 55.50 CONDUCTOR, ge. Casing Description String 0... String ID ... Top (ftKB) Set Depth (f -.- Set Depth (ND) ..- String Wt... String ... String Top Thrd 54 PRODUCTION 9 5/8 8.535 55.5 10,376.5 53.50 P - 110 BUTT SAFETY VLV, Casing Description String 0... String ID ... Top (ftKB) Set Depth (t.. Set Depth (ND) ... String Wt.. String ... String Top Thrd 410 DRILL PIPE LINER 5 4.408 10,074.0 16,650.0 16.25 S135 4.5 IF GAS LIFT - „.. Tubing Strings 1,558 ' • Tubing Description String 0... String ID ... Top )ftKB) Set Depth (f... Set Depth )TVD) ... String Wt... String ... String Top Thrd DISPOSAL, 54 TUBING Upper 51/2 4.950 53. 3,687.8 3,457.1 15.50 L -80 BTCMOD Completion Details SURFACE, • 1 I. Top Depth 57 -2,579 (TVD) Top Inc/ Nomi... GAS LIFT, ' „ Top (11KB) (ftKB/ ( °) Item Description Comment ID (in) 2,675 53.6 53.6 0.35 HANGER FMC TUBING HANGER 5.500 IPERF, 3,5003540 409.9 409.9 0.27 SAFETY VLV CAMCO TRM-4E TR SSSV 4.562 f ' f III 3,667.1 3,440.6 37.73 SEAL ASSY BAKER S-22 PBR Anchor Seal Assembly w/15' seals 4.750 I' T Description String 0... String ID -.- Top (ftKB) Set Depth (f. -. Set Depth (ND) ... String Wt.. String ... String Top Thrd GAS FT, T UBING Lower 5 1/2 4.950 3,670.5 3,763.6 3,517.6 15.50 L -80 BTCM 3 LI,602 ■■ Completion Details , , ■ Top Depth Depth :. (ND) Top Intl Nomi... Top (ftKB) (ftKB) ( °) Item Description Comment ID (in) SEAL ASSY, 3,670.5 3,443.3 37.70 PBR 190-60 PBR w /15' SEAL TRAVEL 4.750 3067 - - "" 3,700.5 3,467.1 37.47 NIPPLE 'X' LANDING NIPPLE 4.562 PBR, 3,671 - - an 3,762.4 3,516.7 37.01 SEAL ASSY 190-60 S -22 ANCHOR LATCH SEAL ASSEMBLY (ABOVE SC-1R 4.750 PACKER) 11�a NIPPLE, 3,700 gm Tubing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND) ... String Wt.. String ... String Top Thrd I Ti GRAVEL PACK 4 3.500 3,763.7 6,868.0 6,026.8 15.50 SLHT a Completion Details .,. Mk Top Depth NTERMEDIATE, (TVD) Top Intl Nomi... 573,760 Top (ftKB) (ftKB) ( Item Description Comment ID (in) SEAL 3 762 2 7 3, 3,763.7 3,517.7 37.00 PACKER BAKER SC -1R PACKER 6.000 PACKER, 3,764 - 3,796.7 3,543.9 36.75 KOIV BAKER KOIV MODEL C 5.000 KOIV, 3,797 ' 4,015.7 3,720.7 35.48 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892 SLOTS, 3,6503,869 4,024.5 1727.9 35.43 SCREEN 3.600 SLOTS, 3,886 - 4,367.7 4,009.4 35.01 PACKER BAKER SC-1R PACKER 4.940 SCREEN 4,02TS, 4N 4,370.7 4,011.9 35.03 SCREEN 3.600 4,105 t�I SLOTS, 4,608.7 4,205.3 37.31 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892 1♦� -_ 4 PACKER, R, 4,368 Mid 4,617.5 4,212.3 37.27 SCREEN 3.600 OTT, 4,429 4 - P 4,880.7 4,423.4 35.97 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892 SCREEN, 4,371 �.. - 4,968.7 4,494.7 35.77 SUMP BAKER SC-2 SUMP PACKER 4.940 SCREEN, 4,618 I ° I PACKER SLOTS, 4,751 -4,761 I 4 SLOTS, I 4 5,578.7 4,987.8 38.00 NIPPLE BAKER 'X' NIPPLE 1813 3,792 <,803 - M 5,613.2 5,014.9 37.67 PACKER BAKER SC -1R PACKER 4.750 SLOTS, _ 5,646.9 5,041.7 37.35 KOIV 3.500 4,922 - 4,955 _ - SUMP _ _ 5,648.8 5,043.2 37.33 SCREEN 3.500 PACKER, 4,889 NIPPLE, 5,579 rIC 6,786.8 5,959.5 34.30 SUMPER BAKER SC - 2 SUMP PACKER 6.000 PACKER, 5,613 KOIV, 5,647 6,836.4 6,000.8 34.66 NIPPLE BAKER'X' NIPPLE 2.813 SLOTS, is 41 5.7186742 - �'I - 6,867.2 6,026.1 34.52 WLEG BAKER WIRELINE ENTRY GUIDE 3.000 SLOTS, 5,885 ohs Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) 5,929-5,939 _ Top Depth SLOTS, - -- )TVD) Top Intl 5,9465,969 SLOTS, 1fIJ I Top )ftKB) )ftKB) (°) Description Comment Run Date ID (in) 5,995 tS . -- 54 54.0 0.35 DISPOSAL 2 3/8" DISPOSAL STRING TO 3663' 7/31/1997 SLOTS, 6,0786,091 SLOTS, Perforations & Slots 8,118$124 Shot SLOTS, Top (ND) Btm (ND) Dens 6,1486,158 SLOTS, Top (ftKB) Btm (ftKB) (ftKB) (ftKB) Zone Date PO- Type Comment s, 5,649 3,500 3,540 3,306.8 3,339.2 9/9/1997 4.0 IPERF 3 WL runs w /4.5" casing guns @ 4 SCREEN, SPF 6,283 -6,290 SLOTS, - - 3,850 3,869 3,586.6 3,602.2 2/5/1998 32.0 SLOTS 6,375 -6,390 SLOTS, - I - 3,886 3,893 3,615.8 3,621.4 2/5/1998 32.0 SLOTS 6,6106,622 SLOTS, - -- 6,762 S11MP Mandrel Details PACKER, 6,787 ■ Top Depth Top Port `T (TVD) Intl 00 Valve Latch Size TRO Run NIPPLE, 8,836 ! _ Stn Top (ftKB) (ftKB) ( °) Make Model (in) Sery Type Type (in) (Mil Run Date Com... WLEG, 6,867 ill 1 1,558.6 1,552.1 12.23 CAMCO MMG 1 1/2 GAS LIFT GLV RK 0.000 0.0 7/7/2012 SLOTS, 6,097 - 9,107 2 2,675.4 2,598.0 26.02 CAMCO MMG 1 1/2 GAS LIFT GLV RK 0.000 0.0 7/7/2012 WINDOW A, 3 3,601.6 3,389.0 38.22 CAMCO MMG 1/2 GAS LIFT OV RK 0.000 0.0 7/7/2012 9,59 -9,600 APERF, 9,9709,972 PRODUCTION, 55- 10,376 DRILL PIPE LINER, 10,074-16,650 TD (NCI B -01A), 16,720 • • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510 -0360 July 7, 2012 JUL l 2 2012 Ms. Cathy Foerster Alaska Oil & Gas Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Dear Ms. Foerster: Enclosed please find a Sundry 10 -403 request to verify integrity for Tyonek well NCIU B -01 A (PTD 198 -002) Class II disposal well. Please call me @ 265 -1464 if you have any questions. Sincerely, Jerry Dethlefs Well Integrity Director Attachments RECEIVED ,UL 01 2012 AOGCC STATE OF ALASKA Alt OIL AND GAS CONSERVATION COMMIRAN APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon J"` Rug for Redrill r Perforate New Pool E Repair w ell r Change Approv - . Program r Suspend r Rug Perforations r Perforate r Pull Tubing r ' - Extension E Operational Shutdown r Re -enter Susp. Well 1- Stimulate E Alter casing r Other: p 2. Operator Name: 4. Current Well Class: 5. Per - to Drill Number: ConocoPhillips Alaska, Inc. Development IV . Exploratory f • 8 -002 • 3. Address: Stratigraphic r Service r API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-883-20093-01 • 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name a . Nu where ownership or landownership changes: Spacing Exception Required? Yes F No I NCI B -• A • 9. Property Designation (Lease Number): 10. Field /Pool(s): it / - t'_g4' -� - 4---/-, � O 2 ,; k41/- -IT 4 - 17S �� Nom' � e— N Cook Inlet / /l � � .1- t'�-�r -� � ` a• , 11. ii c, '' 7 PRESENT WELL CONDITION *, � MMARY G C Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): P gs (measured): Junk (measured): 16720 • 12943 ' Casing Length Size MD TVD Burst Collapse CONDUCTOR 353 30 Nikk407' 7 SURFACE 2522 20 • 79' INTERMEDIATE 3703 13.375 , d' PRODUCTION 10321 13.375 ' ` �' / ,,��6 Perforation Depth MD (ft): Perforati -pt ! Tubing Size: Tubing Grade: Tubing MD (ft): injection perfs 3500 -3540 , ".ction - 3 .1 39 3.5 L -80 6867 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft) PACKER - BAKER SC-1R PACKER / MD= 3764 TVD= 3517 ■ PACKER - BAKER SC-1R PACKER MD= 4368 TVD= 4009 PACKER - BAKER SC-1R PACKER MD= 5613 TVD= 5015 12. Attachments: Description Summary of Proposal 13. Well Class after proposed work: Detailed Operations Program r BO' Sketch Exploratory r Development jw Se rvice 14. Estimated Date for Commencing Operations: 15. Well Status after proposed work: -v Immediately Oil r Gas - WD SPL j /) ( . Suspended r' 16. Verbal Approval: Date: WINJ ig' y rz' GINJ r' WAG �" i Abandoned r"' Commission Representative: 't GSTOR r SPLUG r 17. I hereby certify that the foregoing true and correct to the best of my knowledge. Contact: Amanda Longbrake Printed Name erry Det• efs Well Integrity Director Title: Engineering Aide Signature (_.- ' ' Phone: 907- 263 -4146 Date: July 6, 2012 Commission Use Only Sundry Number: 91 Conditions of app .val: Notify Commission so that a representative may witness I Plug Integri BOP Test r Mechanical Integrity Test fl Location Clearance r Other: Sullisequent Form Required: APPROVED BY Approved by: "' COMMISSIONER THE COMMISSION Date: (-1--)i,\ ,v Form 10 -403 Revised 1/2010 OR1GINAL I/2_ bmit in Duplicate /A" • • ConocoPhillips Alaska, Inc. Application for Sundry Approvals 10 -403 NCIU B -01A Class II Injection Well ConocoPhillips Tyonek platform well NCIU B -01A (PTD 198 -002) is a gas producing well that / also is configured as a Class II disposal well down the OOA (C annulus). The well is subject to the regulatory conditions in Area Disposal Order 33. The well is not routinely used for injection except when drilling operations are taking place on the platform. On 6/25/12 CPAI reported to the AOGCC, as per Rule 5, of pressure observances that may indicate integrity problems with the wellhead packoff assembly on the production casing. Due to the configuration of the well, the production casing packoff assembly provides isolation between the injection string and production tubulars in the well. On 7/2/12 the wellhead vendor provided routine maintenance on the packoff assembly and was able to "energize" it and cause it to stop leaking. Also by Rule 5, this Sundry has been prepared for a plan to monitor the repair and verify integrity has been re- etablished. Traditional MIT testing is not an option for this well since there is not a packer as in a normal arrangement; the injection string is down the OOA (C annulus). The tubing is configured for gaslift service which prohibits a standard MIT of the IA (A annulus). Proving integrity is best accomplished via the conditions in Rule 4, which calls for monitoring surface pressure conditions in the annulus injection tubing and annulus wellhead pressures. Proposed plan: CPAI proposes to verify the integrity of the packoff maintenance repair by monitoring and I trending wellhead pressures over 90 days and submit them to the AOGCC. In addition, annulus fluid level surveys will be obtained at least monthly to check for an influx of gas and will be presented in the 90 -day report. This plan has the following benefits: 1. If the packoff assembly "energizing" was successful there will not be an increase in OA (B) or OOA (C) annulus pressure due to gas from the IA (B) annulus. 2. If gas pressure is observed on the outer tubulars then additional maintenance can be provided to the packoff assembly to stop the leak and monitor success over time. 3. Fluid level surveys that show fluid near the surface will support the determination that the packoff assembly has been repaired, or be an indicator that more work is required if a gas column is building. 4. The results of this monitoring will be provided to the AOGCC at the end of the 90 -day period. 5. Should communication problems become apparent during the 90 -day period and cannot be repaired, the AOGCC will be contacted to discuss a plan forward for the well. CPAI Well Integrity Director 7/6/2012 • K , ci B -01A ConocoPhillips ; Well Attribut Max Angle TD Wellborn API /UW I Field Name Well Status Inc! ( °) MD (ftKB) Act Btm (ftKB) 508832009301 COOK INLET PROD 38.53 7,939.01 16,720.0 Conorifttillps "` Comment H2S (ppn) Date Annotation End Date KB-Grd (ft) Rig Release Date "' SSSV: TRDP Last WO: 12/18/2003 10/21/1997 Wet Contq: - NCI B -01 A, 6/272012 11:14:10 AM Schematic - Actual Annotation Depth (ftKB) End Date Annotation Last Mod By End Date Last Tag: RKB 8,807.0 7/31/2011 Rev Reason: WELL REVIEW osborl 6/27/2012 HANGER, 54 '"' 1=i °" Casing Strings Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd \ i _ CONDUCTOR 30 27.000 54.0 407.0 407.0 120.00 H WELDED - Casing Description String 0... 'String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... ' String Top Thrd SURFACE 20 18.730 57.0 2,579.0 2,510.9 133.00 K - 55 BUTT Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD)... String Wt.. String ... String Top Thrd INTERMEDIATE 133/8 12.347 56.8 3,760.0 3,514.8 72.00 N - 80 N - 80 8 § Casing Description String 0... String ID ... Top (ftKB) Set Depth (f.,. Set Depth (TVD) ... String Wt.. String ... String Top Thrd IIIIIE = WINDOW A 10 8.000 9,590.0 9,600.0 8,212.0 55.50 I It CONDUCTOR, Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd 54 PRODUCTION 9 5/8 8.535 55.5 10,376.5 53.50 P - 110 BUTT SAFETY VLV, _ ) Casing Description String 0... String ID ... Top (ftKB) Set Depth (f...' Set Depth (TVD) ... String Wt... String ... String Top Thrd 410 DRILL PIPE LINER 5 4.408 10,074.0 16,650.0 16.25 S135 4.5 IF GAS LIFT, IMP Tubing Strings 1,559 J :'. Tubing Description String 0... String 10 ... Top (ft6B) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd DISPOSAL, 54 TUBING Upper 51/2 4.950 53.6 3,687.8 3,457.1 15.50 L -80 BTCMOD Completion Details SURFACE, L Top Depth 57 -2,579 (TVD) Top Intl Nom)... GAS LIFT, Top (ftKB) (MB) ( °) Item Description Comment ID (in) 2'675 53.6 53.6 0.35 HANGER FMC TUBING HANGER 5.500 IPERF, • 3,502 409.9 409.9 0.27 SAFETY VLV CAMCO TRM-4E TR SSSV 4.562 - -- 3,667.1 3,440.6 37.73 SEAL ASSY BAKER S -22 PBR Anchor Seal Assembly w/15' seals 4.750 Tubing Description String 0... String ID ... Top (ttKB) Set Depth (f... Set Depth (TVD) ... String Wt.. String ... String Top Thrd . - � «- TUBING Lower 5 1/2 4.950 3,670.5 3,763.6 3,517.6 15.50 L - 80 BTCM GAS LIFT, 3,602 Completion Details Top Depth I i i (TVD) Top Incl Nomi... Top (NM (ro( ( °) Item Description Comment ID (in) 3,670.5 3,443.3 37.70 PBR 190 - 60 PBR w /15' SEAL TRAVEL 4.750 SEAL ASSY, 3,887 3,700.5 3,467.1 37.47 NIPPLE 'X' LANDING NIPPLE 4.562 PBR, 3,671 - 3,762.4 3,516.7 37.01 SEAL ASSY 190-60 S-22 ANCHOR LATCH SEAL ASSEMBLY (ABOVE SC -1 R 4.750 PACKER) 7 R NIPPLE, 3,700 € r Tubing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd GRAVEL PACK 4 3.500 3,763.7 6,868.0 6,026.8 15.50 SLHT i 1 Completion Details i- Top Depth NTERMEDIATE, (TVD) Top Inc! Nomi... 57- 3.760 Top (ttKB) (B) (°I Item Description Comment !D (In) ASSY, 3,762 Y, SEAL Ass 3,763.7 3,517.7 37.00 PACKER BAKER SC-1R PACKER 6.000 PACKER, 3,784 3,796.7 3,543.9 36.75 KOIV BAKER KOIV MODEL C 5.000 KOIV, 3,797 ammo 4,015.7 3,720.7 35.48 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892 SLOTS, 3,850 -- 4,024.5 3,727.9 35.43 SCREEN 3.600 SLOTS, 3,886 - - - - 4,367.7 4,009.4 35.01 PACKER BAKER SC -1 R PACKER 4.940 SCREEN, 4,025 4,370.7 4,011.9 35.03 SCREEN 3.600 O 4,185 � ( SLOTS, . _ � `) 4,608.7 4,205.3 37.31 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892 4,2751,365 - - PACKER, 4,388 '4I - -- 4,617.5 4,212.3 37.27 SCREEN 3.600 4,429A� % 4,880.7 4,423.4 35.97 RA BLANK RADIOACTIVE MARKER IN COLLAR 4.892 SCREEN, 4,371 - - -- ■!� - 4,968.7 4,494.7 35.77 SUMP BAKER SC -2 SUMP PACKER 4.940 SCREEN, g618 -� 1 1 PACKER 4,7511,7 1 ' SLOTS, �� ,, 5,578.7 4,987.8 38.00 NIPPLE BAKER 'X' NIPPLE 3.813 4,7921,803 '►. - - -- 5,613.2 5,014.9 37.67 PACKER BAKER SC-1R PACKER 4.750 I SLOTS, . ,- 5,646.9 5,041.7 37.35 KOIV 3.500 4,9221,955 - - -- SUMP _ _ PACKER 5,648.8 5,043.2 37.33 SCREEN 3.500 PACKER, 4,969 NIPPLE, 5,579 ` aat 6,786.8 5,959.5 34.30 PA BAKER SC - 2 SUMP PACKER 6.000 PACKER, 5,613 i KOIV, 5,647 1 6,836.4 6,000.8 34.66 NIPPLE BAKER 'X' NIPPLE 2.813 SLOTS, 5,718 - 5,742 6,867.2 6,026.1 34.52 WLEG BAKER WI RELINE ENTRY GUIDE 3.000 SLOTS, S,eeSLO 892 TS, O ther In Hole ireline retrievable P 9 pump lugs, valves, um s, fish, etc.) 9-5 - 5,929-5,939 Top Depth SLOTS, (TVD) Top Intl 5,9485,9691 Si SLOTS, Top (ftKB) (tt(MO) ( °) Description Comment Run Date ID (in) 9,8958,032 54.0 54.0 0.35 DISPOSAL 2 3/8" DISPOSAL STRING TO 3663' 7/31/1997 SLOTS, 6,0788,091 - SLOTS, Perforations & Slots 6,1188,124 - - Shot SLOTS, 6,14 Top (TVD) Btm (TVD) Dens 88,158 SLOTS, Top (ftKB) Btm Ifn(8) MB) Ifti(BI Zone Date ( Type Comment 8,169-6,182 SCREEN, 5,8849 49 3,500.0 3,540.0 3,306.8 3,339.2 9/9/1997 4.0 IPERF 3 WL runs w/4.5" casing guns @ 4 SLOTS, _ SPF 6,2835,280 s- 3,850.0 3,869.0 3,586.6 3,602.2 2/5/1998 32.0 SLOTS 6,3758,390 ,390 SLOTS, - -- 3,886.0 3,893.0 3,615.8 3,621.4 2/5/1998 32.0 SLOTS 6,610 SLOTS, '� - 4,185.0 4,268.0 3,859.3 3,927.3 C.I. 1, NCI 8 2/5/1998 32.0 SLOTS 8,762 SUMP - - 4,275.0 4,365.0 3,933.1 4,007.2 C.I. 2, NCI B 2/5/1998 32.0 SLOTS PACKER,6,787 - 4,429.0 4,480.0 4,058.8 4,100.9 C.I. 4, NCI B-01 2/5/1998 32.0 SLOTS NIPPLE, 8,836 �� _ 4,751.0 4,761.0 4,318.8 4,326.9 C.I. 8, NCI B-01 2/5/1998 32.0 SLOTS WLEG, LOTS 4,792.0 4,803.0 4,351.8 4,360.7 C.I. 8, NCI 8 -01 2/5/1998 32.0 SLOTS 8,097 - 9,107 4,922.0 4,955.0 4,456.9 4,483.6 C.I. 11, NCI B -01 2/5/1998 32.0 SLOTS /MNDOW A, 5,718.0 5,742.0 5,098.4 5,118.5 BELG -F, NCI 2/5/1998 32.0 SLOTS 9,5905,600 B APERF, 9,970 -9,972 Mandrel Details Top Depth Top Port (TVD) Inc! OD Valve Latch Sire TRO Run PRODUCTION, Stn Top (ftKB) (ftKB) ( °) Make Model (!N Sery Type Type ON (psi) Run Date Com... 55 1 1,558.6 1,552.1 12.23 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 12/18/2003 DRILL N ER. LINER, ° • 10,074 - 16.650 . 1 2 2,675.4 2,598.0 26.02 CAMCO MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 4/24/2012 TD (NCI 3 3,601.6 3,389.0 38.22 CAMCO MMG 1/2 GAS LIFT DMY RK 0.000 0.0 4/24/2012 B -01A), 18,720 • • Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, July 10, 2012 3:46 PM To: Dethlefs, Jerry C Cc: Regg, James B (DOA) Subject: NCIU B -01A (PTD 198 -002) Jerry, Jim Regg and I discussed this well's situation... A sundry is not required to do the monitoring you are proposing. If repair to the well is needed then a sundry is required as per DIO -033 Rule 5. . The best course would be to keep us posted and submit a report of findings after your monitoring period on a 10- 404 or by email. The sundry you submitted will be returned to you as "Not Required" . ,,,r,., 1'13 c-:, c-:, f /z g Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) 7/10/2012 • • Regg, James B (DOA) From: Dethlefs, Jerry C [ Jerry.C.Dethlefs @conocophillips.com] Sent: Monday, July 09, 2012 11:20 AM To: Regg, James B (DOA) Cc: Buck, Brian R; Dethlefs, Jerry C Subject: RE: CPAI Tyonek NCIU B -01A Class II Disposal Well (PTD 198 -002) Jim: Regarding Tyonek NCIU B -01A Class II injection well, on July 2 the wellhead vendor was able to successfully energizeAhe 9 -5/8" packoff assembly. In addition, the 13 -3/8" packoff was successfully tested. At this point we have reason to believe the annular communication previously reported on 6/25/12 has been repaired. Since gaslift valves are installed in the production tubing it will be difficult to prove the integrity with an MITIA. However, the well will soon be put on gaslift and annular pressures can be monitored for signs of leaking. I have submitted a 10 -403 as per requirements in DIO 33 to monitor and report the wells' behavior over the next 90 days. Let me know what you think after you get the 10 -403. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska Office: 907- 265 -1464 Cell: 907 - 268 -9188 From: Dethlefs, Jerry C Sent: Monday, June 25, 2012 12:42 PM To: 'jim.regg @alaska.gov' Cc: NSK Problem Well Supv; Dethlefs, Jerry C; Buck, Brian R Subject: CPAI Tyonek NCIU B -01A Class II Disposal Well (PTD 198 -002) Jim: I am reporting a failed MIT on NCIU B -01 A (PTD 198 -002). During a diagnostic checkout of the well on 6/24/12 the wellhead packoffs were tested and failed to hold pressure between the IA and OA. The OA is perforated on this well and is the flowpath for Class II injection. Since the packoff leak is substantial, a pressure differential with gas could not be established between the IA and OA and therefore we are classifying as a failed MIT. The next course of action will be to evaluate options for regaining packoff integrity. NCIU B -01 A will not be used for injection until approved by the AGOCC. I will respond to the questions from the previous email separately. Please let me know if you have any questions. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska Office: 907 - 265 -1464 Cell: 907 - 268 -9188 From: Dethlefs, Jerry C Sent: Friday, June 22, 2012 1:27 PM To: 'jim.regg @alaska.gov' 1 • • Cc: Dethlefs, Jerry C Subject: Re: [EXTERNAL]RE: CPAI Tyonek NCIU B -01A Class II Disposal Well Thanks Jim; I am currently out of the office but will work your questions next week. Have a good weekend. Jerry Dethlefs From: Regg, James B (DOA) [mailto:jim.reqg @alaska.gov] Sent: Friday, June 22, 2012 01:52 PM To: Dethlefs, Jerry C Subject: [EXTERNAL]RE: CPAI Tyonek NCIU B -01A Class II Disposal Well I am also not comfortable with the informal direction you have been provided since you are required by rule to run temp survey. Couple questions: 1) A -12 appears to be primary disposal well , operating avg of 15 -20 days per month; what is future utility of A -12 disposal strings? 2) A -13 was permitted as Class I well but is not reporting any injection. What are you doing with the treated sanitary effluent? (overboard under NPDES permit ?) 3) What volume /duration of injection does CPAI consider to be significant enough to warrant a temp survey to evaluate injected fluid isolation? I see no value in redoing what would be a baseline temp survey, so admin approval waiving the requirement for temp survey seems right approach. If you agree, please confirm with email requesting AA and we will prepare for Commissioners' consideration. Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Dethlefs, Jerry C [mailto:Jerry.C.Dethlefs @conocophillips.com] Sent: Thursday, June 21, 2012 4:47 PM To: Regg, James B (DOA) Cc: Dethlefs, Jerry C Subject: CPAI Tyonek NCIU B -01A Class II Disposal Well Jim: Tyonek well NCIU B -01A (PTD 198 -002) is a Class II disposal well down a 2 -3/8" string located between the 13 -3/8" intermediate string and 9 -5/8" production casing. The injection zone is 3000 - 3540'. The well is also a producer up the 5- 1/2" tubing string. The well was permitted for Class II injection 11/5/08 but has seen very little injection during that time. According to DIO 33, an annual report is due on July 1 of each year. Every two years a temperature log is supposed to be ran across the injection interval to verify injection is into the approved zone. Up until now this temperature log has not been performed by direction from Tom Maunder since the well has not been used to the extent that a zone of influence can be established and indentified. Although the annual reports have been filed, I am not comfortable with this informal direction not to perform the temperature profile. In my opinion we need to either perform the temperature survey to comply with the permit conditions or get a formal variance until such time injection is routinely underway. I have attached a number of documents, including a well diagram, well history, injection plot showing no injection and a copy of the permit. Please let me know your thoughts on this well so CPAI can remain in compliance with the permit conditions. Thanks for your time. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska Office: 907 - 265 -1464 2 Page 1 of 1 • • Schwartz, Guy L (DOA) From: Barbee, Marcus G (Swift Technical Services LLC) [Marcus.G. Barbee @contractor.conocophillips.com] Sent: Wednesday, April 04, 2012 10:19 AM To: Schwartz, Guy L (DOA) Cc: Merritt, Cameron (SolstenXP); Johnson, Thure R ( SolstenXP); Buck, Brian R; Allsup- Drake, Sharon K Subject: FW: 10-403 sundry application for Tyonek B -01a (PTD 198 -002) Thank you Mr. Schwartz! From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Wednesday, April 04, 2012 10:15 AM To: Barbee, Marcus G (Swift Technical Services LLC) Subject: [EXTERNAL]RE: 10 -403 sundry application for Tyonek B -01a (PTD 198 -002) Yes.. got the email clarification and approved the sundry. Your proposal to add additional temperature logs is fine. Good luck. Guy Schwartz Abi R) APR j 20 i*/ Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Barbee, Marcus G (Swift Technical Services LLC) [mailto: Marcus.G. Barbee @contractor.conocophillips.com] Sent: Wednesday, April 04, 2012 9:29 AM To: Schwartz, Guy L (DOA) Subject: 10 -403 sundry application for Tyonek B -01a Mr. Schwartz, I trust I have sufficiently answered your questions pertaining to B -01a perforations inside the 9 -5/8" casing (non existent); if not please let me know. I would like to add one run in the hole to the operation if it will be acceptable to you. I believe we will get better overall survey results if we perform our baseline survey first, the injection profile next, followed by a warm up logging run to see the injection zone come back up to nominal ambient reservoir temperature. I will add the subsequent run to a bulleted procedure for field distribution. Thank you, ai'vu ' 8arbe Wells Engineer ConocoPhillips Alaska, Inc. 1- 907 - 265 -6932 O. 1- 907 - 250 -1163 C. This transmission may contain information that is privileged, confidential and / or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, or use of the information contained herein (including any reliance therein) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether in electronic or hard copy format. Thank You. 4/4/2012 • • ALAsE,A (11 9 7 ip 7 n O ,, � , , a SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Marcus Barbee Wells Engineer (� 68 ConocoPhillips Alaska, Inc. �� , 17 i s t P.O. Box 100360 Anchorage, AK 99510 Re: Sterling Field, Undefined Waste Disposal Pool, NCIU B-0 1A Sundry Number: 312 -116 Dear Mr. Barbee: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, , r A ( 9 04,,v)74,......... Cathy ,•. Foerster Chair rd. DATED this 3 day of April, 2012. Encl. • • STATE OF ALASKA • R CE VED ALASKA OIL AND GAS CONSERVATION COMMISSION O 7-- 3//2 MAR APPLICATION FOR SUNDRY APPROVALS 2 8 2012 20 AAC 25.280 ! 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ ask Oil h. Gas Conk C�mu slo Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑" ' ime n ion] Anchorage Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing] infectivity test survey 0 • 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development Exploratory ❑ 198 -002 . 3. Address: Stratigraphic ❑ S ervice ❑ 6. API Number: P.O. Box 100360, Anchorage, Alaska 99510 50- 883 - 20093 -01 -00 . 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No El NCIU B -01A • 9. Property Designation (Lease Number): 10. Field /Pool(s): • ADL 17589 * Sterling / Undefined Waste Disposal Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): • Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 16720 12943 Casing Length Size MD TVD Burst Collapse Structural 368' 30" 407' 407' Conductor 2579 20 2579' 2571' Surface 3760 13-3/8" 3760' 3514' Intermediate 10376' 9 -5/8" 10376' 8840' Liner 5" 16650 12896' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): (3280' - 3314', 3500' - 3540', 3099' - 3131', 3307' - 3339', 2 -3/8" / 5 -1/2" N -80 / L -80 3663' / 6867' 3850' - 4365', 4429' - 4955', 3587' - 4007', 4060' - 4484', 5718' - 6767') 5098' - 5943' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker / Camco 6787', 5613', 4969', 4368', 3764', 410' 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch El Exploratory ❑ Development 0 Service 0 • 14. Estimated Date for April 3rd, 2012 15. Well Status after proposed work: Commencing Operations: Oil ❑ Gas Ei WDSPL ig . Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Marcus Barbee *4-6932 Printed Name Marcus Barbee 265 -6932 Title Wells Engineer 03 -26 -2012 atl/' Signature T / Phone Date 4 (7 .'. ' , geP 3 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ) 12..' I l L Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: / V / / APPROVED BY Approved by: , - /X COMMISSIONER THE COMMISSION Date: it_ -3— /Z 4 gotti: -. 3 -: 20PR 04 2012 7,1,_ ,?- Z � Submit in Duplicate � • • ConocoPhil ips oedaska Tyonek B 01a Procedure • Drift production tubing and tag bottom • Set a catcher sub r ` l • CO Gas lift valves to dummies and PT casing w/ header pressure C • CO dummies to live valves • Pull catcher sub • Run pressure temperature baseline survey • Run pressure temperature injection survey @ 1 BPM 03 -26 -12 Tyonek B -01A f - PPHILLIPS Aia &, Inc. • A Subsidiary of PHILLIPS PETROLEUM COMPANY As Run 12/16/03 B -1 A 3 Well Name: North Cook Inlet Unit -B -1A 30" @ 40T MD (430" TVD) Spud Date: 7/31 /97 ® amco 5-1/2" SSSV @ 410' Sidetrack Date: 2/5/98 Schematic Update: Billingsley 12/18/03 '' 5 -1/2" GLM at 1559' with dummy, RK latch Casinq Depth Grade Weight 30" 407' 5 -1 /2 "GLM @ 2675' w/5/16" orifice /RK latch 20 ' 2579' K -55 133# 13 -3/8" 3760' N -80 72# 20" @ 2579' MD (2571' TVD) 9 -5/8" 10376' P -110 53.5# 2 -3/8" Injection Strings for 5" DP 16650' S -135 19.5# top= 10074' e (terling Disposal zone 13 - 3/8" @ 3760' MD Tbci Depth Grade Weight (5 -1/2" 3764' L -80 15.5 #, csg buttress I 5 -1/2" GLM at 3602' w /dummy and RK latch Top Length Item 53.6' 1' 10 -3/4" x 5 -1/2" Vetco tbg hgr, 15' PBR on top of pkr 5 -1 /2" BTC btm and top 5 -1/2" "X" nipple, 4.562' ID @ 3700 5 -1/2" tbg, L -80, 15.5# R2, BTC mod Baker SC -1 R Pkr @ 3764 (6.00" ID) 410' Camco 5 -1 /2" SSSV TRM -4E w/4.562" X 5" x 7" KOIV @ 3797 1559' dummy Camco 5- 1/2 "x1 -1/2" MMG GLM 1 i 4 zones: 3850'- 3869', 3886'- 3893 2675' 5/16' orifice Camco 5- 1/2 "x1 -1/2" MMG GLM 1 4185 4268',4275' -4365' 3602' dummy Camco5- 1/2 "x1 -1/2" MMG GLM 1 one jt 5 -1 /2" tbg, L -80, 15.5# R2, BTC mod 9 5/8" SC -1L @ 4368 3671' Baker PBR /seals, 7.0" OD x 4.875" ID 1 1 — 4 zones: 4429'- 4480 4751' -4761' 3700' 5 -1/2" "X" nipple 4792'- 4803', 4922' -4955 one jt 5 -1/2" tbg, L -80, 15.5# R2, BTC mod s s /8" SC -1 R Sump Pkr @ 4969 (6.00" ID) 3764' Baker 5 -1 /2" x 9 -5/8" SC -1 R pkr assy 51/2" SLHT blank 3797' 7" x 5" KOIV Tag fill @ 54 8' a -1/2" X nipple profile, 3.813 @ 5576' 5 -1/2" 15.5# SLHT blank & screens* on 12/19/03 � 9 -5/8" SC -2 @ 5613' (4.75 ID) 4368' Baker SC -1 L pkr assy `,� 5" x 3 -1/2" KOIV at 5647 5 -1/2" 15.5# SLHT blank & screens ** 4" screens and blanks 4969' Baker SC -1 R Sump pkr #2 assy --- 14 zones perfed: 5718 5742', 5885' -5892' 5 -1 /2" 15.5# L -80 SLHT blank tbg 5929'- 5939', 5948'- 5969', 5995 - 6032', 5547' Xover, 5 -1/2" SLHT x 4 -1/2" IBT 1 1 — 6078'- 6091', 6097'- 6107', 6118'- 6124', one jt of 4 -1 /2" IBT 1 1 = 6148'- 6158', 6169'- 6182', 6283 - 6290', 5579' 4 -1/2" X nipple, 3.813" profile 6375' - 6390 6610' - 6622', 6762' -6767' 1 jt of 4 -1/2" IBT w /S -22 4.75" snap latch S -22 Snap Latch 5613' Baker 4" x 9 -5/8" SC -2 pkr assy, 4.75" ID 9 -5/8" SC -1 R Sump Packer @ 6787' 5647' 5" x 3 -1 /2" KOIV 5 -1/2" x 3 -1/2" crossover 4" SLHT screen and blank 3 -1/2" X nipple at 6836 6786' Baker S -22 Snap Latch 3-1/2" WLEG at 6867 6787' Baker SC -1 R sump packer Actual 4 -1/2" tbg cut @ 8052' on 11/22/03 6805' 3 -1/2" x 5 -1/2 xover 9/29/02 Tag TOC at 9610' in tbg 6836' 3 -1/2" tbg, 3 -1/2" X nipple, 2.813" profile 4.5 ", 12.75 ppf, P -110 Tubing 6867' 3 -1/2" WLEG tbg tail , ' / Calc TOC in tbg x 9 -5/8" @ 9837' A / PERFS @ 9970' -9972' 4 SPF * and ** 9' long x 5 -1/2" Braden blanks w /RA collars ' ► PKR 10,074 MD (8846' TVD) @ 4016', 4609' and 4881' r e Sliding Sleeve@ 10032' MD (8598'T/D) WELL HISTORY: Feb. 5, 1998 - Sidetrack ©� ► PXN Pl "gin Nipple, 9 -5/8' @ 10376' MD (8846' wD) Nov. 26, 2001 - Set 3.813" PXN Plug in XN Nipple. et j/ .4 3.125 Fishneck. XN Nipple is 3.725" NoGo w /3.813" g 4 -s. packing bore. Sept. 25, 2002 - PERF from 9970' 9972' RKB, 4 spf w /2' PERF gun in prep for P&A '5 ", 19.5 ppf, S -135 Drill Pipe with G' Tool Joints (min. ID: 3.25 ") Sept 27, 2002 - Cement tubing & casing, cement in annulus @ 9937' (est.); PXN Plug in Nipple @ 10,073' N. Forlands PERFs @ 16080 - 16118' MD Junk & fill on top of PXN plug top @ 10,010' Sept 29, 2002 - Tag TOC @ 9610' CMT in DP @ 16590 MD 12/18/2003 Unable to pull dummy @ 3602', set orif @ 2675' �'��� � � s" DP @ 16654 MD 12/19/2003 Tag top of CaCO3 w /wt bar @ 5478' =169' above KOIV I I • • Page 1 of 3 Schwartz, Guy L (DOA) From: Barbee, Marcus G (Swift Technical Services LLC) [Marcus.G. Barbee @contractor.conocophillips.com] Sent: Monday, April 02, 2012 9:46 AM To: Schwartz, Guy L (DOA) Cc: Merritt, Cameron (SolstenXP); Johnson, Thure R ( SolstenXP) Subject: RE: Tyonek B -01a (PTD 198 -002) Guy, Sorry for the late reply; I leave the office at 2:00 on Fridays; missed your mail by 37 minutes... Agreed that would not work too well. it is somewhat confusing as to the geometry of this well. 8/8/1997 0:00 FINISHED RUNNING 13 3/8" CASING W /ATTATCHED DUAL 2 3/8" INJECTION STRINGS. CIRC BU & STARTED CEMENTING SAME. LEAD PUMPED, STARTING ON TAIL. was the summary written when the 13 -3/8" & 2 -3/8" strings were run. (behind the 13 -3/8 ") cemented to surface. Then we were unable to get down either string of 2- 3/8 "... 8/10/1997 0:00 FINISHED TESTING WELLHEAD SEALS & VOID AREA. ATTEMPTED TO GET DOWN THROUGH 2 3/8" INJECTION STRINGS WITH BOTH ELECTRIC LINE & SLICK LINE WITH NO SUCCESS. CONTINUING WITH RU OF 10,000# CHOKE MANIFOLD. 8/11/1997 0:00 ATTEMPTED 1 3/8" DUMMY RUNS WITH SCHLUMBERGER ON INJECTION STRINGS WITH NO SUCCESS GETTING DOWN Then we drilled ahead and TD`d the original B1 bottom hole location —10,378' and notified Blair Wandzell of intentions to run liner @ 09:30 hrs on 09 -03 -97 and then ran +- 6900' of 9 -5/8" liner to + -358 and cemented with 300 Bbls 12.5 pg lead and 144 Bbls of 15.8 ppg tail. On equent run saw packer set with 65K, after which we tested our 13 -3/8" x 9 -5/8" lap to 3,000 psi good. Then on 09 -07 -97 the rig notified Blair Wandzell or our intention of perforating and establishing injection through the 13 -3/8" casing above the liner lap 09 -09 -97 we RIH w/ 4.5" csg guns w/ 4 spf from 3540' - 3530' (run 1), 3530' - 3520' (run 2), misfire run 3, 3520' - 3500' (run 4) with initial injection into the Sterling formation at 1 BPM / 900 psi; 2 BPM / 970 psi; 3 BPM 1 985 psi; 4 BPM / 965 psi; 5 BPM / 975; 6 BPM / 990 psi; 7 BPM / 1000 psi; 8 BPM / 1000 psi with a total of 45 Bbls pumped. We then attempted to run 77 joints of 53.5# p -110 9 -5/8" casing tie back but could not get a test, so we pulled the seal assembly and repaired the seals and got a successful test of the tie back. I will attach a power point slide of what the well looks like to day. Please let me know if you have any more questions. best regards, Marcus 4/2/2012 . Page 2 of 3 • • Re- completion in 2003 North Cook Inlet Unit A OL 17589 Well. S ?a f Leg 1 Slot 4 API: 50- 883 - 20093 -01 PTO: 198 -002 RKB =132' MSL PIM ... 6. t 30" @ 407' / 40 -_I dv ,T �n � 5/16' o. v. a.- 111M0 41 A, 20" @ 2579' / 2571 1690 sx' t..j dv :...t 15-- ,.., I " 500' - 3540) Al: 1 ` _� 13 -318" @ 3760' 13521' 1234 sx 1' 1 1 f . 1 1 ,•IrSr'� [ i .._.. � _ f 5" DP cmtd @ 10,115' 9 -518" @ 10376' / 8840' . i 1 /7-6 • 04 -15 -98 9 -518" csg tested good 5,000 psi A ■ TD 16590' 4/2/2012 . Page 3 of 3 • • From: Schwartz, Guy L (DOA) [ mailto:guy.schwartz @alaska.gov] Sent: Friday, March 30, 2012 2:37 PM To: Barbee, Marcus G (Swift Technical Services LLC) Subject: [EXTERNAL]RE: Tyonek B -01a (PTD 198 -002) Thanks... I reviewed the well file a bit myself. I have a question. How can the 5 %" X 9 5/8" annulus (IA) pressure test if it was perforated at 3280 — 3314' ? Am I missing something? Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Barbee, Marcus G (Swift Technical Services LLC) [mailto:Marcus.G. Barbee ©contractor.conocophiilips.com] Sent: Friday, March 30, 2012 1:46 PM To: Schwartz, Guy L (DOA) Subject: Tyonek B -01a Mr. Schwartz, As per our phone conversation pertaining to Tyonek Platform Well B -01a; CPAI would like to drift the production tubing to refusal, collect a sample of material from there; change out the orifice SPM valve with a dummy and pressure test the 9 -5/8" casing, change out SPM dummy valves with a live valve design, perform a static bottom hole pressure survey and perform an injection survey to determine where injection fluids from DIO - 33 are actually going. With any luck we should be able to have this work completed within 2 -3 days of the start of the project and will be able to bring the well back on line. Please let me know if you require any additional information from me to proceed. Thank you, Ala-rc 8a-rbee/ Wells Engineer ConocoPhillips Alaska, Inc. 1- 907 - 265 -6932 0. 1- 907 - 250 -1163 C. This transmission may contain information that is privileged, confidential and / or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, or use of the information contained herein (including any reliance therein) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether in electronic or hard copy format. Thank You. 4/2/2012 1 ' ( ( ' V . ' , ' , / ti) ct-afr I 11 _ I I Jo ,,. „ ) , ) 4. ---7I losk 1015\ V 141°-9 - ---•,-) j • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Disposal Injection Order No. 33 ConocoPhillips Alaska Inc. for ) disposal of Class II oil field wastes ) Sterling Formation by underground injection in the ) North Cook Inlet Unit Well B -01A Sterling Formation in the North ) Cook Inlet Unit Well B -01A, ) November 5, 2008 Section 6, T11N, R9W, S.M. ) IT APPEARING THAT: 1. By correspondence received by the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) July 14, 2008, ConocoPhillips Alaska Inc. (CPAI) requested that the Commission issue an order authorizing underground disposal of Class II oil field waste fluids into the Sterling Formation through the North Cook Inlet Unit (NCIU) B -01A wellbore. The NCIU B -01A well is located on the Tyonek Platform offshore Cook Inlet, Alaska. 2. The Commission requested additional information on July 15, 2008. CPAI clarified several points by electronic mail on July 15, 2008 and met with the Commission on July 21, 2008 to give an overview of the project and discuss specifics relating to the well. 3. Notice of opportunity for a public hearing was published in the ANCHORAGE DAILY NEWS on July 17, 2008, in the PENINSULA CLARION on July 20, 2008, on the State of Alaska Online Notices on July 17, 2008, and on the AOGCC website on July 17, 2008 in accordance with 20 AAC 25.540. 4. The Commission did not receive any public comments, protests or a request for a public hearing. 5. A public hearing was held August 26, 2008 and recessed until September 17, 2008. The record was left open at CPAI's request to allow additional time to provide Commission - requested information. . . Disposal Injection Order 33 Page 2 of 9 NCIU B -OIA November 5, 2008 6. Additional clarification and information in support of the application was received from CPAI on September 11, 2008. The Commission closed the hearing record on September 17, 2008, without reconvening the hearing based on a review of the information provided by CPAI. 7. Information submitted by CPAI and public well history records are the basis for this order. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) NCIU B -01A is an existing gas development well located 1249 feet from the north line and 980 feet from the west line of Section 6, Township 11N, Range 9W, Seward Meridian. The surface location is on the CPAI - operated Tyonek Platform in 110 feet of water approximately 5 miles due east of Tyonek, Alaska and 40 miles west - southwest of Anchorage, Alaska. Five wells penetrate the disposal zone within a' /4 -mile radius of NCIU B -01A. 2. Notification of Operators /Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) CPAI is the only operator within a 1 /4 -mile radius of the proposed disposal well. The sole surface owner within a 1 /4 -mile radius of NCIU B -01A is the State of Alaska. 3. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) The proposed disposal injection interval in NCIU B -01A lies within the Sterling Formation, and it consists of a series of coarse - grained sand beds interspersed with relatively thin layers of carbonaceous mudstone. This interval, which lies between 3295 feet true vertical depth (TVD) and 3387 feet TVD, was previously perforated and used in NCIU B -01A to dispose approximately 135,000 barrels of slurried Class II drilling waste during 1997 -98. This same interval is also currently used for disposal injection in offset well NCIU A -12. Upper confinement is provided by a stacked sequence of siltstones, mudstones, and coals interbedded with scattered sands. This sequence extends from approximately 3110 feet TVD to 3295 feet TVD, and it contains an aggregate thickness of about 125 true vertical feet of mudstone. Lower confinement is provided by a sequence of interlaminated mudstone, claystone, coal and siltstone interbedded with occasional sand intervals. This sequence extends from 3387 feet TVD to 3549 feet TVD, and it contains an aggregate thickness of at least 55 true vertical feet of mudstone. 4. Evaluation of Confining Zones (20 AAC 25.252(c)(9)) CPAI states the effectiveness of the confining and arresting intervals — both upper and lower — is demonstrated by the past injection in the proposed disposal zone in NCIU A -12 and B- OIA. Structure maps and cross sections provided with the application indicate the confining zones are laterally continuous. • • Disposal Injection Order 33 Page 3 of 9 NCIU B -01 A November 5, 2008 5. Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)); Aquifer Exemption (20 AAC 25.252(c)(11)) Aquifer Exemption Order (AEO) 4 dated September 29, 1998, exempts those portions of aquifers within the NCIU that are common to and correlate with the interval below 2900 feet TVD in NCIU A -12. Wireline analytical techniques compliant with EPA recommended methods coupled with laboratory analysis of water samples in wells offsetting NCIU B -01A were used to characterize formation water salinities. The Commission concluded in AEO 4 that freshwater aquifers underlying NCIU do not serve as a source of drinking water. Further, the Commission concluded that freshwater exists at a depth and location that makes its recovery for drinking purposes economically impractical. The closest drinking water well to the NCIU is onshore approximately 8 miles to the northwest, in the Beluga River Unit. 6. Well Logs (20 AAC 25.252(c)(5)) Log data from NCIU B -01A and offsetting wells are on file with the Commission. CPAI provided a type log section of NCIU B -01A and a cross section through NCIU wells A -11, A -12, B -OIA and 13-02 identifying the confining and disposal zones. 7. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) NCIU B -01A is an existing gas development well directionally drilled south to a depth of 12988 feet TVD. The well was drilled originally as an oil exploration well and subsequently plugged back and sidetracked to a Sterling - Beluga Formation gas producing objective. The well is constructed with 30 -inch structural pipe set at 407 feet TVD, 20 -inch conductor casing set at 2571 feet TVD, 13 -3/8 -inch surface casing set at 3514 feet TVD, 9 -5/8 -inch intermediate casing set at 8840 feet TVD, and 5 -inch production liner set from 8598 feet to 12896 feet TVD. Well B -01A is completed with a single 5 -1/2 -inch production tubing string and produces gas through Sterling and Beluga perforations between 3307 feet and 5943 feet. The annulus space between surface casing and conductor casing is cemented from shoe depth to the surface; well records indicate cement was circulated to surface and a passing positive pressure test was performed. Well construction for NCIU B-OIA incorporates a cuttings injection system consisting of two 2 -3/8 -inch injection strings (i.e., annulus injection tubings) strapped to the surface casing and ) cemented to surfacg. These annulus injection tubings were installed to a depth of 3437 feet TVD. The cuttings injection system was designed to inject oil -based muds and cuttings within a confined interval in the upper Sterling Formation. Inability to run perforating equipment into the annulus injection tubings resulted in installing the intermediate casing in states — the lower section run as a liner and cem-n - • • the 1' • • • ? . feet_ 's / TVD. , Prior to running the remainder of the intermediate casing kupper sectionl_the intermediate casing and annulus injection tubings were perforated from 3280 feet to 3314 1 2900 feet TVD is 2900 feet MD as referenced in AEO 4. • • Disposal Injection Order 33 Page 4 of 9 NCIU B -01A November 5, 2008 feet TVD, providing access to the Sterling disposal zone. The upper section of the intermediate casing was run into the well, connected to the lower section and tested. The remainder of the well was constructed as planned. A Cement Bond Log run during well construction over the surface casing interval provides inconclusive results regarding the quality of the cement in the surface casing annulus. CPAI states this is due to the existence of the two annulus injection tubings. Interpreted results from CPAI indicate a cement top in the surface casing annulus at 2530 feet TVD. The Commission authorized the injection of approximately 135,000 barrels of drilling waste down the annulus injection tubings during 1997 -98 in conjunction with development drilling activities on the Tyonek Platform. Injection occurred without incident. 8. Disposal Fluid Type, Composition, Source, Volume and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) NCIU B -01A will be the second waste disposal well for non- hazardous Class II oil field wastes generated on the Tyonek Platform. Waste disposal injection will consist of the same fluids currently being injected into A -12, including drilling mud, drill cuttings, reserve pit fluids, rig wash fluids, formation material, completion fluids, produced water, stimulation fluids and other fluids eligible for injection into a Class II disposal well. The total estimated volume of Class II wastes to be injected into B -01A for disposal over the life of the project is 1,200,000 barrels. Disposal injection is expected to be made in small batches and at rates similar to NCIU A -12 (i.e., approximately 1000 barrels every other day). CPAI states that performance data and extensive operational experience involving similar waste materials, the same formation and depths, and similar volumes and rates in NCIU A -12 provide an adequate analogy for the proposed NCIU B -OlA disposal injection. Fracture modeling submitted with the application for DIO 17 (NCIU A -12) used well B -01 A as the basis for simulating fracture propagation. A third party fracture model was used to update the DIO 17 results by simulating 3 cases: - 150,000 barrels of 7,4 pounds of solids to each gallon of slurry at 3000 barrels per day (i.e., a volume representing the approved, historical cutting - slurry disposal injection that occurred during 1997 -98); - 1,000,000 barrels of produced water at rates of 1 barrel per minute (i.e., modeling the maximum water handling rate capability on the Tyonek Platform); - 60,000 barrels of 7.4 pounds of solids to each gallon of slurry at 2.4 barrels per minute (i.e., modeling the proposed cuttings disposal injection). All fracture model simulations were run with performance assumptions (i.e., rates, volumes, pressures, and continuous injection) that CPAI states exceed the planned injection. Rock properties and wellbore hydraulic data replicate actual conditions. Modeling indicates single wing fracture lengths up to nearly 400 feet horizontally. The total vertical fracture growth (true vertical thickness) is predicted to be 125 feet. . • Disposal Injection Order 33 Page 5 of 9 NCIU B -01A November 5, 2008 9. Estimated Injection Pressures (20 AAC 25.252(c)(8)) CPAI estimates that the maximum surface injection pressure will be 2500 prig. CPAI modeling indicates the average surface injection pressure will be approximately 1030 psi. A step -rate injectivity test was performed in July 2008 with injection rates up to 2 barrels per minute and injection pressures up to 2116 psi. 10. Mechanical Condition of Wells Penetrating the Disposal Zone Within 1/4-Mile of NICU B- 01A (20 AAC 25.252(c)(12)) Five wells penetrate the Sterling within a 1/4-mile radius of NCIU B -01 A. Within this area of review, the lateral distance from B -01 A to the offsetting penetrations ranges from 440 feet to approximately 1000 feet. Construction information for each well, including cement tops for casing set across the Sterling is summarized in the injection order application. Detailed well construction information is in Commission well files; this information includes cementing records that indicate cement has been circulated to surface in the surface casing annulus for each of the five wells. In addition, CPAI has summarized the results of Cement Bond Logs run for four of the five wells (no bond log was run in NCIU B -03). Recent wellhead pressures (L tubing, inner annulus, and outer annulus pressures) have also been summarized for the five wells penetrating the 1/4-mile area of review. 11. Operating Intent CPAI intends to simultaneously operate NCIU B -01A as a waste disposal injection well and a gas production well. NCIU A -12 is similarly operated. CONCLUSIONS: 1. The application requirements and conditions for approval of an underground disposal application in 20 AAC 25.252 have been met. 2. Aquifers below 2900 feet TVD are exempt under 20 AAC 25.440 by AEO 4. 3. Proposed injection sands and confining layers are laterally continuous over the field. Stacked confining zones totaling approximately 185 feet true vertical thickness above and approximately 160 feet true vertical thickness below the injection zone will provide confinement of injected wastes. 4. Injection in NCIU A -12 (which is the same sand interval as proposed for B -01A) and results from historical injection in B -O 1 A (1997 -98) confirm that injected fluids will remain confined to the intended interval. 2 The five wells are NCIU A -04, A -06, A -07, A -12, and B -03. • • Disposal Injection Order 33 Page 6 of 9 NCIU B -OlA November 5, 2008 5. Based on the modeled injection rates, volumes, fluid densities, and pressures, which exceed expected operating conditions, and the historical injection in the proposed disposal zone common to NCIU B -01A and NCIU A -12, reasonable grounds exist to conclude that waste fluids should be contained within the receiving intervals by the confining lithologies within the Sterling. Cement isolation of the injection zone in the well bore and operating conditions further support the Commission's conclusion about confinement. Modeling worst case conditions (i. continuous injection) predicts a zone of influence (waste plume area) for injected materials to occupy a fracture domain extending approximately 400 feet laterally from the well and vertically 125 feet, all within the identified geologic confinement. Batch injection will likely result in a radial -type disposal domain, reducing the predicted lateral and vertical propagation of the fractures that result from the slurry injection. 6. A 1/4-mile area of review is appropriate given the fracture modeling results. 7. Disposal injection operations in NCIU B -01A will be conducted at rates and pressures below those estimated to fracture through the confining zones. Therefore, oil field wastes injected into B -01A will be confined to the isolated Sterling disposal injection zone. Successful disposal of 135,000 barrels of slurried Class II drilling waste during 1997 -98 in the identified zone confirms injected fluids will be confined. Also, a step -rate injectivity test performed in July 2008 confirms injection is into a confined system. 8. Fluid compatibility in the Sterling disposal zone is not an issue. Operating experience and data from disposal injection —(i) involving similar materials and performance parameters (i.e., pressures, rates, and volumes), (ii) including the historical injection of 135,000 barrels of Class II drilling waste, and (iii) involving the same injection zone in nearby NCIU A -12— provide a suitable analogy for underground disposal using annulus injection tubings in NCIU B -01A. 9. The mechanical integrity of the five offset wells within the 1/4-mile area of review has been demonstrated by cementing records, bond logs (where available) and annuli pressures. 10. Unique well construction involving two small diameter annulus injection tubings and casing perforations mandate procedures other than pressure testing for demonstrating ongoing mechanical integrity of NCIU B -01A. 11. Supplemental mechanical integrity demonstrations and the surveillance of injection operations — including temperature surveys, monitoring of injection performance (i.e., pressures and rates), and analysis of the data for indications of anomalous events —are appropriate to ensure that waste fluids remain within the disposal interval. 12. NCIU B -01A may simultaneously operate as a completed gas production well (producing up the 5 -1/2 -inch tubing) and a Class II disposal well (injecting down the two 2 -3/8 -inch annulus injection tubings installed in the surface casing by conductor casing annulus). • • Disposal Injection Order 33 Page 7 of 9 NCIU B -01A November 5, 2008 NOW, THEREFORE, IT IS ORDERED THAT disposal injection is authorized into the Sterling Formation within North Cook Inlet Unit B -01 A subject to each of the following requirements: RULE I: Infection Strata for Disposal The underground disposal of Class II oil field waste fluids is permitted into the Sterling within NCIU B -01A in the interval between 3295 feet and 3387 feet TVD. The Commission may immediately suspend, revoke, or modify this authorization if injected fluids fail to be confined. Injection shall only occur down the 2-3/8-inch tubings ipst lied in the L3 -3/S- h_sinface_casing _ by_ 20- inch conductor .casing. lus— RULE 2: Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production and workover operations. Included are drilling mud, drill cuttings, reserve pit fluids, rig wash fluids, formation material, completion fluids, produced water, stimulation fluids and other fluids eligible for injection into a Class II disposal well. RULE 3: Infection Rate and Pressure Disposal injection is authorized at (a) rates that do not exceed 2.4 barrels per minute and (b) surface pressures that do not exceed 2500 psig. RULE 4: Demonstration of Mechanical Integrity The mechanical integrity of NCIU B -01A must be demonstrated before injection begins and before returning the well to service following a workover affecting mechanical integrity. A pump -in differential temperature log shall be run in the 5 -1/2 -inch production tubing every 2 years to evaluate injected fluid isolation. The anniversary date for the temperature log is the effective date of this order. after the date of entry of this order Ongoing mechanical integrity of the well shall be demonstrated by injection performance monitoring of the surface pressure at static conditions in the 2 -3/8 -inch annulus injection tubings and open 13 -3/8 -inch by 9 -5/8 -inch casing annulus with a known fluid. The results of all mechanical integrity demonstrations and CPAI's interpretation of those results shall be provided to the Commission and be readily available on the Tyonek Platform for Commission inspection. RULE 5: Well Integrity Failure and Confinement Whenever any pressure communication between the production tubing and the casing - tubing annulus is identified, or lack of injection zone isolation is indicated by the injection rate, an operating pressure observation, a test, a survey, a log, or any other evidence, the operator shall notify the Commission by the next business day and submit a plan of corrective action on Form 10 -403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates • • Disposal Injection Order 33 Page 8 of 9 NCIU B -01 A November 5, 2008 must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. RULE 6: Surveillance The operator shall run a baseline differential temperature log in the 5 -1/2 -inch tubing prior to initial injection. A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids. Surface pressures and rates must be monitored continuously during injection. Results of daily wellhead pressure observations in NCIU B -01 A must be documented and available to the Commission upon request. Subsequent temperature surveys or other surveillance logging (e.g., water flow; acoustic) will be based on the results of the initial and follow -up temperature surveys and injection performance monitoring data. A report evaluating the performance of the disposal operation must be submitted to the Commission by July 1 of each year. The report shall include data sufficient to characterize the disposal operation, including, among other information, the following: surface pressures (daily average, maximum and minimum); fluid volumes injected (including disposal and clean fluid sweeps); injection rates; an assessment of fracture geometry; a description of any anomalous injection results; and a calculated zone of influence for the injection fluids. RULE 7: Notification of Improper Class II Injection The operator must immediately notify the Commission if it learns of any improper Class II injection. Notification requirements of any other state or federal agency remain the operator's responsibility. RULE 8: Administrative Action Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. • • Disposal Injection Order 33 Page 9 of 9 NCIU B -01A November 5, 2008 RULE 9: Compliance Operations must be conducted in accordance with the requirements of this order, AS 31.05, and (unless specifically superseded by Commission order) 20 AAC 25. Noncompliance may result in the suspension, revocation, or modification of this authorization. DONE at Anchorage, Alaska, and dated N •- mbeerr 5, 2008 la „,wtc ` ° 1 L. l, lG Daniel T. Seamount, Jr., Chair A / t io , . i .1.,, • _ , .., , ,,,..„ Adl . yy ` - oerste Commissioner / A b A., ../ 4 ly " 1‘4f. .2 ON t :00 ' rman, CovT ' RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. lithe notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it I within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "(t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Page 1 of 1 • Maunder, Thomas E (DOA) From: NSK Well Integrity Proj [N1878 @conocophillips.com] Sent: Thursday, June 30, 2011 6:15 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: Dethlefs, Jerry C; NSK Problem Well Supv; NSK Well Integrity Proj Subject: NCI B -01A Annual Surveillance Report (9& -Q02) DIO 33 Rule 6 Attachments: NCI B- 01AD.pdf Tom, The following surveillance information is provided as required in DIO 33 Rule 6. NCI B- 01A(198 -002) was permitted under DIO 33 November 5, 2008 as a Class II disposal well. It has remained primarily unused, however has had an approximate total of 3000 bbls of Class II fluid injected sporadically over the last 15 months. The well was not used more than two consecutive days during any of the injection periods. See the attached Surveillance Plot showing injection tubing pressure, injected volumes and inner annulus pressures. During each injection periods the injection pressure always less than 2000 psi, injection rates varied between .25 BPM and 1.5 BPM, and no anomalous injection results were noted. When not under injection the well head pressure was zero psi. The IA pressure averages -400 psi with a high of 670 psi and a low of zero psi. Due to the very low injected volumes a zone of influence has not yet been delineated or calculated for this well. This will be completed as soon as there is sufficient injection volume to detect on a temperature trend. Please let me know if you require any additional information. MJ Loveland Well Integrity Project Supervisor ConocoPhillips Alaska, Inc. Office (907) 659 -7043 CeII (907) 943 -1687 *`' it ._Rig:.. s_ 213 7/1/2011 String Name B -01AD Start Date 7/1/2010 Days 365 End Date 7/1/2011 IA Cook Inlet Production & Pressure Data OA WHP WHT 2500 - 200 180 2000 • - 160 • – 140 • N • 1500 • - 120 LL y –100' a 0 m 1000 - 80 – 60 500 ___ ____ - 40 – 20 0 l— 0 Jul -10 Aug -10 Sep -10 Oct -10 Nov -10 Dec -10 Jan -11 Feb -11 Mar -11 Apr -11 May -11 Jun -11 Gas Vol Water Vol -- In) Vol • 700 ._ 1.2 600 — —_ — __. _ ___ ___ 1 'CI . 500 -- - 0.8 .0 400 - • • - - • - 0.6 V 300- - —. -- -0.4 j_ 200 - _ __. -_. • 100 • Olt • 1- - 0 Jul -10 Aug -10 Sep -10 Oct -10 Nov -10 Dec -10 Jan -11 Feb -11 Mar -11 Apr -11 May -11 Jun -11 Date B-OlA (PTD 198-002) Baseline Temp Survey DIO 33 Rule 6 Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, May 08, 2009 4:08 PM To: 'Braden, John C' Cc: Regg, James B (DOA) Subject: RE: B-01A (PTD 198-002) Baseline Temp Survey DIO 33 Rule 6 John, Thanks for your clarification about the static log. As far as the fluid you will pump, either water is acceptable. Tom Maunder, PE AOGCC From: Braden, John C [mailto:John.C.Braden@conocophillips.com] Sent: Friday, May 08, 2009 10:54 AM To: Regg, James B (DOA) Cc: Maunder, Thomas E (DOA) Subject: B-01A (PTD 198-002) Baseline Temp Survey DIO 33 Rule 6 Jim- The Kuukpik rig is finally leaving the platform, so ConocoPhillips can do the baseline temp log for DIO 33 Rule 6. We used fresh water to establish infectivity. I plan to use produced water (Class II) for the baseline temp log. Please let me know if you have a different recommendation. Thanks, John Braden ;~ ~.~,~~b~~h.~ l~si~~~ .. ~~~~'' .~ 5/8/2009 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS' 1. Operations Pertormed: Abandon ^ Repair Well ^ Plug Pertorations ^ Stimulate ^ Other Q Infectivity Test Alter Casing ^ Pull Tubing ^ Pertorate New Pool ^ Waiver ^ Time Extension ^ Change Approved Program ^ Operat. Shutdown^ Pertorate ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: ConocoPhillipsAlaska, InC. Development ~ Exploratory ^ 198-002! 3. Address: Stratigraphic ^ Service ^ 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-883-20093-01 7. KB Elevation (ft): 9. Well Name and Number: RKB 132' NCI B-01A 8. Property Designation: 10. Field/Pool(s): ADL 17589. North Cook Inlet Field /Undefined Waste Disposal Pool 11. Present Well Condition Summary: Total Depth measured 16720' feet true vertical 12943' feet Plugs (measured) Effective Depth measured feet Junk (measured) true vertical feet Casing Length Size MD TVD Burst Collapse Structural Structural 368' 30" 407' 407' Conductor 2579' 20" 2579' 2571' Surface 3760' 13.375" 3760' 3514' ' Intermediate 10376' 9.625" 10376' 8840' Liner 5" 16650' 12896' Perforation depth: Measured depth: 3500'-3540' , 3850'-4365', 4429'-4955', 5718'-6767' true vertical depth: 3307-3339, 3587-4007, 4060'-4484', 5098'-5943' ~~( s~ ~ i'r:~ ~t~~.~ ~ ~ ~~~ Tubing (size, grade, and measured depth) 2.375" / 5.5", N-80 ! L-80, 3663' / 6867' MD. Packers &SSSV (type & measured depth) Baker pkrs @ 37sa', a3s s', asss', 5613', 6787' Camco SSSV @ 410' 12. Stimulation or cement squeeze summary: Intervals treated (measured) not applicable Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casin Pressure Tubin Pressure Prior to well operation na S `} ^)ti -- Subsequent to operation na s . ~} • j h -- 14. Attachments 15. Well Class after work: Copies of Logs and Surveys run _ Exploratory ^ Development ~ Service ^ Daily Report of Well Operations _X 16. Well Status after work: a ~` Oil^ Gas^~ WAG^ GINJ^ WINJ ^ VtlDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 308-228 contact John Braden @ 263-4536 tt~~3~ • Printed Name ,~ Jo r~ Signature 1% Title Phone: 263-4536 Staff Engineer ~ ( /~ ~? Date ~~ (~y°~-/' (.1 L.~V ,. Pre ared 6 Sharon Allsu Drake 263-4612 / r Form 10-404 Revised 04/2006 ..~ . ~ ~ R;~ ~~~,, (~~~ +~ ~ j~~E ~}- 10.2-0• a+b Submit Original Only r An infectivity test was performed on B-01 a 2-3/8" string on 7/26/08: 12:09 Rig up BJ pumps to B-01A 2-3/8" injection string 14:02 Begin pumping fresh water at 0.5 bpm, final WHP 1722 psis 14:31 Increase rate to 1 bpm, final WHP 1828 psia 14:36 Increase rate to 1.5 bpm, final WHP 1951 psia 14:39 Increase rate to 2.0 bpm, final WHP 2116 psia 14:43 Divert to tank 14:44 SD pumps 14:50 Begin recording shut-in pressures 14:58 Rig down BJ 20:41 Finish recording shut-in pressures (see table below): • Time Time,min 2-3/8" inj t #2 -2-3/8" IA OA Elapsed Time 2-3/8" Injection Point 2-3/8" Alt Strin Inner Annulus Outer Annulus 2:50 SI 1440 50 340 1550 0.1074 1440 50 340 1550 2:51 0:01 1400 50 340 1440 0.1081 1400 50 340 1440 2:56 0:06 1300 50 340 1340 0.1116 1300 50 340 1340 3:06 0:16 1250 50 340 1330 0.1185 1250 50 340 1330 3:26 0:36 1230 50 340 1290 0.1324 1230 50 340 1290 3:56 1:06 1230 50 340 1240 0.1533 1230 50 340 1240 4:41 1:51 1230 50 340 1200 0.1845 1230 50 340 1200 5:41 2:51 1140 50 340 1170 0.2262 1140 50 340 1170 6:41 3:51 1140 50 340 1160 0.2678 1140 50 340 1160 8:41 5:51 1120 50 340 1150 0.3512 1120 50 340 1150 B-01a Infectivity Test 7125/08 4500 4000 3500 3000 ~a 'a 2500 ~' 3 ~ 2000 a 1500 1000 500 2-3/8" Injection Point 2-3/8" Alt. String Inner Annulus BJ pump --- Outer Annulus 2.0 bpm 1.5 bpm 1.0 bpm 0.5 bpm -~~ 0 0:00:00 1:12:00 2:24:00 3:36:00 4:48:00 6:00:00 7:12:00 8:24:00 9:36:00 Elapsed time, HH:MM:ss • 2500 2000 c. 1500 m L d L a a ~ 1000 a 500 0 B-01a Infectivity Test 7/25/08 0 0.5 1 1.5 2 2.5 3 3.5 4 Pump Rate, bpm • • ' ~---, a ~.~ ~- w~ , ~~ ~--~ a : -, ~ ~-~ ,~-~ ~~: ~: f1,' ~~~, ~~~ e a..R -i4LL,.,~' ~.. ~..,r~ ~ ~. ~";s ~'' ~ ~..5 [ z '~~ ~ 1 }... 1.~ (,~:'1 ~.;~l~ ~~1 -t SARAH PALIN, GOVERNOR [~ilta-78A OIL Ai`17 ~iAS A~ 333 W. 7th AVENUE, SUITE100 COI~SERQATIOi~T COMMI5SIOI~T 1 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 John Braden Staff Engineer ConocoPhillips Alaska Inc. ~~• ~ JUL ~ ~ 2DG8 PO Box 100360 Anchorage, AK 99510 Re: North Cook Inlet Field, Undefined Waste Disposal Pool, NCI B-OlA Sundry Number: 308-228 i ~ ~ ~ ~ 1 n, ~, Dear Mr. Braden: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Corrunission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, ~~~ Daniel T. Seamount, Jr. ~~ Chair DATED this 1 S day of July, 2008 Encl. ~, .o~'~~ R r qo STATE OF ALASKA ~ .t ~ ~t ~ I ALASKA OIL AND GAS CONSERVATION COMMISSION ~ ~`~ ~ ~ ~ ~ ~~~ i APPLICATION FOR SUNDRY APPROV,~~~ ~;~ (~.~, .~;~;~-;. ~~I7;l,i~n 20 AAC 25.280 - a 1, Type of Request: Abandon ^ Suspend ^ Operational Shutdown ^ Perforate ^ Waiver ^ Other ^ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Infectivity Test Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development Q , Exploratory ^ 198-002 3. Address: Stratigraphic ^ Service ^ 6. API Number: Q P. O. Box 100360, Anchora e, Alaska 99510 50-883-20093-01 ~o 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name and Number: where ownership or landownership changes: Spacing Exception Requires? YeS ^ NO ~ NCI B-01A 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): Vt~ '~ K~`1.SC~S~€~.~, ADL 17589 ~ RKB 132' ' North Cook Inlet Field / Bol 12. PRESENT WELL CONDITION SUMMARY Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ff): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 16720' ~ 12943' Casing Length Size MD TVD Burst Collapse Structural 368' 30" 407' 407' Conductor 2579' 20" 2579' 2571' Surface 3760' 13.375" 3760' 3514' Intermediate 10376' 9.625" 10376' 8840' Liner 5" 16650' 12896' Perforation Depth MD (3500'-3540' Perforation Depth TVD (ft): 3307-3339' Tubing Size: Tubing Grade: Tubing MD (ft): 3850'-4365', 4429'-4955', 5718'-6767' 3587'-4007', 4060'-4484', 5098'-5943' 2.375" / 5.5" N-80 / L-80 3663' / 6867' Packers and SSSV Type: Packers and SSSV MD (ft) Baker pkrs @ 3764', 4368', 4969', 5613', 6787' Camco SSSV @ 410' 13. Attachments: Description Summary of Proposal ~ 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^~ Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operat July 7, 2008 Oil ^ Gas ~ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL Commission Representative: Dual Pur Ose Well 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: John Braden @ 263-4536 Printed Name hn Braden Title: Staff Engineer Signature Phone 263-4536 Date ~~~- ®~ Commission Use Onl Sundry Number: Conditions of approval: Notify Commission so that a representative may witness ~O~ Plug integrity ^ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ^ ,~.:~~~C.} ~~C.tC,.~I~,'~'~~ 'W~~`fc CLi` ~~CC~~~~~'C\1~~~~ ~5 Other: ()~'I.SSvt;'~'`,e ~ . Subsequent Form Required: "1V~ ~~ .~r-L~i`~,~:i~-~ ~ r~~; y-~,~G:~'~5..;~-~ FL. ~~~. ~ ~~~~ APPROVED BY / < ~ Approved by. COMMISSIONER THE COMMISSION Date: / "+ Form 10-a>~ FYeGsed 06!2006 O R I G I N A L ubmit in Duplicate .~~/~~~-~ ~ /S.oB ~ • NCI B-O1A Procedure Objective: Fresh water infectivity test into disposal zone at a maximum rate of 2.0 bpm and 2500 Asia. • Rig upon one 2-3/8" tubing string with pipe or hose and pressure gauge to measure tubing pressure after injection is shut-in.. • Pump 15 bbl of fresh water down the 2-3/8" string at 0.5 bpm do not exceed 2500 psis. Record injection pressure on both 2-3/8" strings and 9.625" x 13.375" and 13.375" x 20" annuli. • Pump 5 bbl of fresh water down the 2-3/8" string at 1.0 bpm do not exceed 2500 psia. Record injection pressure on both 2-3/8" strings and 9.625" x 13.375" and 13.375" x 20" annuli. • Pump 5 bbl of fresh water down the 2-3/8" string at 1.5 bpm do not exceed 2500 psia. Record injection pressure on both 2-3/8" strings and 9.625" x 13.375" and 13.375" x 20" annuli. • Pump 10 bbl of fresh water down the 2-3/8" string at 2.0 bpm do not exceed 2500 psia. Record injection pressure on both 2-3/8" strings and 9.625" x 13.375" and 13.375" x 20" annuli. • Shut-in injection. • Record pressure at shut-in, 1 min, 5 min, 10 min, 20 min, 30 min, 45 min, 1 hour, 2 hours, 4 hours on all strings and annuli. • Report results to reservoir engineer. • • Questions/Comments on CPAI Application for Class II Injection in Well NCI B-OlA 1. Class II annular injection? Is this even allowed? 2. I believe the DNR would be considered the surface owner and therefore would be required to be notified in accordance with 25.252(c)(3). As they were for DIO 17. 3. Description of proposed disposal interval is insufficient. 25.252(c)(4) requires name, description, depth, and thickness of the formation. The draft application provides the formation name and a minimal description of the formation but does not provide the depth of this formation in the subject well or the thickness of the formation, Also, there is no discussion on the confining intervals. 4. Estimated average and maximum injection pressures are required in an application, but only maximum values are given. 5. 25.252(d) requires mechanical integrity 6e demonstrated in accordance with 25.412. 25.412(b) requires the well to be completed with tubing and a packer, or other equipment to isolate pressure to the injection interval. The annular tubing that will be used for injection was cemented in place and perforated. The perforations penetrated the 13-3/8" casing which is an open annulus to the surface. How would this meet the intent of our regulations? ~(f~~ m. l ,.. ., ,r~;: ~L .~ ~, -~c>r "' t~t~„ 1,~.~ /?Y'om'"~ ~ j ,;. ~' u ~` ,~ - ;~~ ~ ' ~ r 4 l C+"Y" ,~(yj Gam' s...~.k. w. C7'" ~ /~ t h~ G-~ ~'~~ -~v~. ~S ~'La(~l U~ ~~~ `~ ~C C~~~~vz~ ~v c'~vi~ - U ..., ~~ ei~~1~~.~i~ Uv~..-~lC.~ ~~~ ~~ ~`~ ~-f~1l~L~GLti ~.C,(1l L(~'11.~ p0 ~~5~ C.Y. >. Well Name Pre 2008 Survey Location NAD27 ASP 4 Northing Easting Post 2008 Survey Location NAD27 ASP4 Northing Easting Distance Moved NCI A-01 2,586,726.69 332,100.19 2,586,726.40 332,102.26 2.09 - --- NCI A-02 2,586,722.85 332,108.29 2,586,721.16 332,111.27 3.43 NCIA-03 __ 2,586,728.60 332,106.22 _ 2,586,728.31 _ 332,109.43 3.22 ____ _ NCI A-04 2,586,719.62 332,105.09 2,586,718.58 332,108.09 __ 3.18 NCI A-05 _____ 2,586,725.55 332,110.17 2,586,725.14 332,111.79 1.67 NCI A-06 2,586,719.66 332,102.09 2,586,719.22 332,104.19 2.15 NCI A-07 2,586,727.79 332,103.73 2,586,728.78 . 332,105.40 1.94 NCI A-08 2,586,720.56 332,098.31 2,586,722.44 332,101.65 3.83 NCI A-09 2,586,666.58 332,039.08 2,586,667.35 332,040.44 1.56 NCI A-10 2,586,670.21 332,040.91 2,586,673.71 332,044.17 4.78 ---- NCI A-10A 2,586,670.21 332,040.91 2,586,673.71 332,044.17 4.78 NCI A-11 2,586,670.23 332,039.14 _ 2,586,677.01 332,041.75 ___ 7.27 _ NCI A-12 _ 2,586,722.73 331,947.80 2,586,723.59 331,994.15 _ 46.36 ____ ___ NCI A-13 2,586,734.88 331,993.50 2,586,733.15 _ 331,995.48 2.63 NCI B-01 2,586,730.03 331,999.80 ' 2,586,723.04 331,998.16 7.18 NCI B-01A 2,586,730.03 331,999.80 2,586,723.04 331,998.16 7.18 NCI B-02 2,586,731.14 331,999.29 2,586,729.60 332,001.86 3.00 NCI B-03 2,586,731.69 331,986.37 _ 2,586,726.81 331,991.70 7.23 NCI B-03PB1 _ 2,586,731.69 331,986.37 2,586,726.81 331,991.70 7.23 ~~~~oa i • • REV DATE BY CK APP SCRIPTION REV DATE BY C P DESCRIPTION I 2/29/08 SAS 1{ yyA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 y9~ ~ ~ 36 31 T 12 lU 31 32 qPx. ¢ ~£' yea ~°`~ ' 6 ~ T ll N s 5 ..~ a9 N S, 19Y5' Sft. 6 1206' SCALE: I"=1320' --6- -- ~ ~ i o ~ I ~ ~ 1 6 I 6 5 12 7 7 8 GENERAL NOTES: ~~~~ ~~./~~ ~~~/ ~~•~~.~ • I. SEE SHEET 3 FOR COORDINATE TABLE ~~'''•9`S~-~1 i '~P •'~~~ ~ °~~ ` ~ 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND .: : Y 1 ' ~ ~ ' VERTICAL SURVEY DATA 49th : ~~ i : / : .... SECTION LINES AND TIES ARE BASED ON PROTRACTED ~ """""""""""""""""""""" 3 . VALUES. ..... .................................. i . : ~ ~ ~ • ~, ~; KENNETH W. AYERS ~~ ~~A ~ ~•:J`~ '•., LS-8535 ~,~ • ~,~i SURVEYOR'S CERTIFICATE 1~~'FpA••..,,,~~.~~,,,..••''~o`~~i ~ I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED ~1t;i ~=~~~~~~ AND LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY DONE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL LOUNSBURY DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF & nssoclnTES, INC. FEBRUARY 28, 2008. SORVEYGRS ENGINEERS PLANNERS ~ PHONE: 1907/ 272-5451 yi AREA: MODULE: UNIT: ConocoPhilli s NORTH C°OK INLET p TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 ~80~5 /~S BU~~T 1 of 3 1 REV DATE BY CK APP SCRIPTION REV DATE BY CK P DESCRIPTION 1 2/29/08 SAS KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 ,g ° ~ t' ~ ~9; R 1f' 9 Z~~. s° AA0 iWI A0 ~~ S. 9'U' stS sc a ~~ ~j ~~ so ~~ SCALE: 1"-30' 99 aQ. 0 ESD 600 50 - ESD 600-51 e •10 7 I p ~BZ 83 Al A7 AB ~ ~ • : •p5 A3~ 46 A12 BI : •A5 ' A4 • A2 WELL HOUSE 2 Ip O ~ zp A1Oa LEGEND: 3~~ ~ WELL p WELL CONDUCTOR 0 ESD (EMERGENCY SHUT OFF VALVE) GENERAL NOTES: 1. SEE SHEET 3 FOR COORDINATE TABLE 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND VERTICAL SURVEY DATA LOUNSBURY 3. NO WELLS EXIST IN WELL HOUSE N0. 4, AND IT WAS NOT & ASSOCIATES, Irrc. A S B UIL T SURVEYORS ENGINEERS PLANNERS 7 7 ~ PH / 2 ONE: (90 2-5451 AREA: MODULE: UNIT: ConocoPhilli s NORTH COOK INLET p TYONEK PLATFORM Alaska, Inc. W EAL CONDUCTOR AS BUNT CADD FILE N0. 08-005 AS BUILT 02/27/08 DRAWING N0: 08-005 AS BUILT PART: 2 of 3 REV: 1 1 12/29/08 ( $A$ KWA I ADDI MUD LINE EO EV., SHTE3 ATIC, SHT.2I T I) ASP ZONE 4, NAD83, FEET NAD83 GEOGRAPHIC MLLW DESCRIPTION (POINT NO.) NORTHING FASTING LATITUDE LONGITUDE ELEVATION NCIU W ELL TAG NO. WELL HOUSE NO. 1 1001 2586492 1472018 61 04 34.38 150 57 03.71 72.0 Conductor 1 1002 2586489 1472017 61 04 34.34 150 57 03.72 73.9 63 1003 2586485 1472019 61 04 34.31 150 57 03.67 74.1 A12 1004 2586485 1472023 61 04 34.31 150 57 03.59 73.8 B1 1005 2586487 1472027 61 04 34.33 150 57 03.52 72.0 Conductor 5 1006 2586491 1472027 61 04 34.37 150 57 03.52 73.7 B2 1007 2586495 1472025 61 04 34.41 150 57 03.57 72.1 Conductor 7 1008 2586495 1472021 61 04 34.41 150 57 03.65 73.7 A13 WELL HOUSE N0.2 2001 2586437 1472060 61 04 33.84 150 57 02.83 71.9 Conductor 1 2002 2586433 1472059 61 04 03.38 150 57 02.84 71.9 Conductor 2 2003 2586430 1472062 61 04 33.77 150 57 02.79 71.8 Conductor 3 2004 2586429 1472066 61 04 33.77 150 57 02.71 73.4 A9 2005 2586431 1472069 61 04 33.79 150 57 02.65 71.9 Conductor 5 2006 2586435 1472069 61 04 33.83 150 57 02.64 73.3 A10 2007 2586439 1472067 61 04 33.86 150 57 02.69 73.3 A11 2008 2586439 1472063 61 04 33.87 150 57 02.77 71.9 Conductor 8 WELL HOUSE N0.3 3001 2586488 1472128 61 04 34.36 150 57 01.47 73.0 Al 3002 2586484 1472127 61 04 34.32 150 57 01.48 73.1 AS 3003 2586481 1472130 61 04 34.29 150 57 01.43 73.1 A6 3004 2586480 1472133 61 04 34.28 150 57 01.35 73.0 A4 3005 2586483 1472137 61 04 34.31 150 57 01.29 73.0 A2 3006 2586487 1472137 61 04 34.34 150 57 01.28 73.0 A5 3007 2586490 1472135 61 04 34.38 150 57 01.33 73.0 A3 3008 2586490 1472131 61 04 34.38 150 57 01.41 73.3 A7 50 2586540 1472069 61 04 34.86 150 57 02.69 72.7 ESD Valve 600-50 51 2586501 1472011 61 04 34.46 150 57 03.86 72.6 ESD Valve 600-51 100 2586572 1472123 61 04 35.18 150 57 01.58 115.3 Top center helipad -101' MUD LINE SURVEY NOTES: I. ALL COORDINATES ARE ASP ZONE 4, NAD83, US SURVEY FEET. GEOGRAPHIC COORDINATES ARE NAD83. 2. ELEVATIONS ARE IN FEET, BASED ON MLLW, REFERENCED TO DRAWING ND. MPD- TY04-2021, SHEET 1 OF 1, REV. 2 3. ALL AS BUILTS ARE TO THE CENTER OF EXISTING STRUCTURE. 4. WELL CONDUCTOR ARE VERTICALLY AS BUILT TO THE TOP OF A I/4" STEEL LID, TACK WELDED TO THE TOP OF THE CONDUCTOR. 5. WELLS ARE VERTICALLY AS BUILT TO THE TOP OF THE LOUNSBURY LOWEST HORIZONTAL FLANGE ON THE WELL. & nssoclATES, INC. SURVEYORS ENGINEERS PLANNERS O ~ PHONE: (90 TI 272-5451 `.~ AREA: MODULE: UNIT: ConocoPhillips NORTH C°OK INSET TYONEK PLATFORM Alaska, Inc. WELD CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 08-0~5 AS BU~~T 3 of 3 1 e e MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _ Inserts\Microfilm _ Marker. doc ",....-.., ~-... ¡¡; ~ -- ,""::"\,..........., f ÎÙ 'l r ^\' ¡ ¡ ¡ r ¡f n I ¡ r~ , \' !! " ¡ ! I ' ¡ . "'\ì " fIl\ I ì L-. " ,k-, "'-. l' (w. ., It i, Ir QL¿ U Lru U Lb \J¿) lJ I~~ fl r~ rr:~ r /7 r\ / ^ \ ¡ ¡ ! II \ l \U ¡ ~ I ¡ f\ \ ¡ U \ II ¡ ¡ \ ì ",'\ I ~ \ ¡ U \ Lr--J ¡ L, LF~ cQ) L1 \~j uìJ A.IfA.~1iA OIL AND GAS CONSERVATION COMMISSION October 20, 2004 Wade Gilpin Alaska Dept. of Environmental Conservation 555 Cordova St., 2nd Floor Anchorage, AK 99501 Re: North Cook Inlet Platform ConocoPhillips Alaska, Inc. Tyonek Deep Well Abandonments Dear Mr. Gilpen: /11% - P a;r FRANK H. MURKOWSKI. GOVERNOR 333 W. ]'TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 This letter is in response to your inquiry regarding the plugging of the "deep" oil wells drilled from ConocoPhillips' North Cook Inlet or Tyonek Platform in Cook Inlet. Your message asked if the abandonments were in accord with 20 AAC 25.105. 25.105 is applicable when all operations on a property are completed which is not the case here. Specific well plugging operations must be in accord with 20 AAC 25.112. During the 1990s a total of 4 exploration wells were drilled from the platform to determine if developable oil reserves were present. Oil was encountered in the deep formations below 12,000', however it was determined to be non-commercial. The deep intervals of these wells were subsequently plugged and abandoned and shallower gas intervals completed and placed into production. I have reviewed the information contained in the files for the respective wells. The deep intervals of NCIU A-13 (formerly Sunfish #2) were abandoned in late 1993 as part of the original work program. An AOGCC Inspector did not witness the plugging operations. Based on my review of the file, the work performed conforms to the requirements of 20 AAC 25.112. The deep intervals in the remaining wells, B-OIA, B-02 and B-03, were plugged and abandoned in late 2002. An AOGCC Inspector did witness weight "tags" and pressures tests to verify the competence of the plugs on each well subsequent to the cementing operations. These verifications were in accord with 20 AAC 25.112 (g)(l) and (2) and the Inspector reported that the plugs were satisfactorily verified. SCANNED OCT 2 7 2004 Wade Gilpin October 20, 2004 Page 2 of2 Based on my review of the infonnation contained in the AOGCC's wells files, I confirm that any potential oil intervals penetrated by the 4 "deep" exploration wells were satisfactorily plugged and abandoned in compliance with AOGCC regulation 20 AAC 25.112. Please feel free to contact me with any questions. Sincerely, ft~ ~ '- Thomas E. Maunder, PE ~ Sr. Petroleum Engineer cc: Well file: NCIU A-13 PTD 192-106 NCIU B-01A PTD 198-002 NCIU B-02 PTD 197-210 NCIU B-03 PTD 198-059 Field file: North Cook Inlet Unit OCT 2 7 2004 ~: Tyonek Platform ?'s Subject: RE: Tyonek Platform ?'s From: "Gilpin, Wade" <Wade - Gilpin@dec.state.ak.us> Date: Fri, 08 Oct 2004 08 :28 :29 -0800 To: 'Thomas Maunder' <tom - maunder@admin.state.ak.us> Thanks Tom - Here is my snail mail address: Alaska Dept. of Environmental Conservation Attn: Wade Gilpin 555 Cordova 81., 2nd Floor Anchorage, AK 99501 tks wg -----Original Message----- From: Thomas Maunder (mailto:tom_maunder@admin.state.ak.us] Sent: Friday, October 08, 2004 7:30 AM To: Gilpin, Wade Subject: Re: Tyonek Platform ?'S Hi Wade, Sorry not to get back to you sooner. so we can send the letter. Thanks, Tom Maunder, PE Could you please provide me with your snail mail address Gilpin, Wade wrote: HI Tom - I have been working this issue with our FR (Financial Responsibility) folks here. For them to lift the FR requirement for Tyonek (and for us to rescind the C-plan), they need confirmation in writing that all wells were plugged/abandoned iaw 20 MC 25.105. Can you possibly provide us letter related to this? Thanks Wade -----Original Message----- From: Thomas Maunder rmailto:tommaunder@admin.state.ak.us] Sent: Thursday, September 16, 2004 7:54 AM To: Gilpin, Wade Cc: John D Hartz Subject: Re: Tyonek Platform ?'S Wade, Based on your reply, you are indeed concerned about the "B" or deep wells that were drilled in 1997 - 1998. I have checked our records with regard to the 3 wells. The deeper intervals are plugged in accord with our SCANNED OCT 2 '1 2004 10f3 10/8/2004 10:18 AM ItE: Tyonek Platform ?'s 2of3 regulations. I do not have any concern about potential oil leakage. Tom Maunder, PE AOGCC Gilpin, Wade wrote: Thanks Tom - Sounds like I got this all wrong I'm quite the novice. Honestly, I don't know the difference between the B and Deep wells. We are concerned in any of the wells that had perforations into potential oil bearing zones. What I meant was concerns about the mechanical integrity of the well bore (after P&A), and the lack of oil leakage from the plugged perforations. Mostly, I need to confirm that you guys don't have any concerns about potential oil leakage. Thanks Wade -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.usl Sent: Tuesday, September 14, 2004 12:51 PM To: Gilpin, Wade Cc: John D Hartz Subject: Re: Tyonek Platform ?'s Wade, Are you talking of the "B or deep" wells. As I remember, we did have an Inspector witness the verifications of the plugging activities. CP AI's intent was to convert or re-equip the wells as gas wells from the shallower formations. What do you mean by "structural concerns"?? Tom Maunder, PE AOGCC Gilpin, Wade wrote: Hi Tom - I talked with Jack Hartz about this at the end of last week and he mentioned that you are who I should be talking to about Tyonek. I have been talking with Steve Geddes of CPA lately and CPA is interested in deactivating thier C-plan since they are only involved gas production. My questions to you are: Did you guys witness the P&A for the well(s)? If so, was everything done satisfactorily? Do you have any structural integrity concerns? I am just looking to make sure they have covered everything to your satisfaction as well as follow our regs/guideliens for deactivation. SCANNED OCT 2 7 2004 10/8/2004 10:18 AM I<:.E: Tyonek Platfonn ?'s .. t. ... Thanks for you help! Wade Gilpin Environmental Specialist Industry Preparedness Program Alaska Dept of Environmental Conservation 555 Cordova St. Anchorage AK 99516 (907) 269-3060 wade Qilpin(â2dec.state.ak.us 30f3 SCANNED OCT 2 7 2004 10/8/2004 10:18 AM RE: Tyonek Platform ?'5 Subject: RE: Tyonek Platform ?'s From: "Gilpin, Wade" <Wade_Gilpin@dec.state.ak.us> Date: Thu, 16 Sep 2004 08:15:16 -0800 To: 'Thomas Maunder' <tom_maunder@admin.state.ak.us> Thanks Tom. -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Thursday, September 16, 2004 7:54 AM To: Gilpin, Wade Cc: John D Hartz Subject: Re: Tyonek Platform ?'s ~C\ U ß- \ k \~~-DaJ Wade Wade, Based on your reply, you are indeed concerned about the "B" or deep wells that were drilled in 1997 - 1998. I have checked our records with regard to the 3 wells. The deeper intervals are plugged in accord with our regulations. I do not have any concern about potential oil leakage. Tom Maunder, PE AOGCC Gilpin, Wade wrote: Thanks Tom- Sounds like I got this all wrong I'm quite the novice. Honestly, I don't know the difference between the B and Deep wells. We are concerned in any of the wells that had perforations into potential oil bearing zones. What I meant was concerns about the mechanical integrity of the well bore (after P&A), and the lack of oil leakage from the plugged perforations. Mostly, I need to confirm that you guys don't have any concerns about potential oil leakage. Thanks Wade -----Original Message----- From: Thomas Maunder rmailto:tom maunder@admin.state.ak.us] Sent: Tuesday, September 14, 2004 12:51 PM To: Gilpin, Wade Cc: John D Hartz Subject: Re: Tyonek Platform ?'s Wade, Are you talking of the "B or deep" wells. As I remember, we did have an Inspector witness the verifications of the plugging activities. CP AI's intent was to convert or re-equip the wells as gas wells from the shallower formations. What do you mean by "structural concerns"?? lof2 9/16/20048:18 AM RE: Tyonek Platform ?'5 2 of2 Tom Maunder, PE AOGCC Gilpin, Wade wrote: Hi Tom -I talked with Jack Hartz about this at the end of last week and he mentioned that you are who I should be talking to about Tyonek. I have been talking with Steve Geddes of CPA lately and CPA is interested in deactivating thier C-plan since they are only involved gas production. My questions to you are: Did you guys witness the P&A for the well(s)? If so, was everything done satisfactorily? Do you have any structural integrity concerns? I am just looking to make sure they have covered everything to your satisfaction as well as follow our regs/guideliens for deactivation. Thanks for you help! Wade Gilpin Environmental Specialist Industry Preparedness Program Alaska Dept of Environmental Conservation 555 Cordova St. Anchorage AK 99516 (907) 269-3060 wade Qilpin@dec.state.ak.us 9/16/20048:18 AM ~ ~ Mike Mooney Wells Group Team Leader Drilling and Wells ConocÓPh ill i ps P. o. Box 100360 Anchorage, AK 99510-0360 Phone: 907-263-4574 May 10, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ¡th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations for NCI 8-01 A (APD # 198-002/304-072) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the North Cook Inlet well 8-01 A. If you have any questions regarding this matter, please contact me at 263-4372. Sincerely, )/¡J J1~ M. Mooney Wells Group Team Leader CPAI Drilling and Wells MM/DV/skad RECEIVED MAY 12 2004 Alaska Oil & Gas Cons. Commission Anchorage ORIG\NAL 1. Operations Performed: STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS D Repair well D Plug Perforations 0 Stimulate D D Pull Tubing D Perforate New Pool D Waiver D D Opera!. Shutdown D Perforate D 4. Current Well Class: ~ Abandon Alter casing Change approved program 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: Development 0 Stratigraphic D P. O. Box 100360, Anchorage, Alaska 99510-0360 7. KB Elevation (ft): 132' RKB 8. Property Designation: ADL 17589 11. Present Well Condition Summary: Total Depth Effective Depth Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: measured 16720' feet true vertical 12942' feet measured 9610' feet true vertical 8220' feet Length Size MD 368' 30" 407' 2579' 20" 2579' 3760' 13.375" 3760' 10376' 9.625" 10376' 5" 16650' Measured depth: 3850'-4365',4429'-4955',5718'-6767' True Vertical depth: 3587'-4007',4060'-4484',5098'-5943' Tubing: (size, grade, and measured depth) Packers and SSSV (type and measured depth) 5.5", L-80, @ 6867" Baker pkr's @ 3764',4368',4969',5613',6787' and Camco SSSV@ 410' 12. Stimulation or cement squeeze summary: 3850'-3869', 3886'-3893' Intervals treated (measured): 24 bbls silgel, 6 bbls silgel Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure 3.6 mmscfld 438 nla 9 mmscfld 175 nla 15. Well Class after proposed work: Exploratory D Development 0 Treatment descriptions including volumes used and final pressure: 13. Oil-Bbl n/a n/a Prior to well operation: Subsequent to operation: estimated 14. Attachments: Copies of Logs and Surveys Run ~ Other D Time Extension D Re-enter Suspended Well D Exploratory D Service D 5. Permit to Drill Number: 198-02/304-072 6. API Number: 50-883-20093-01 9. Well Name and Number: NCIU B-1 A 10. Field/Pool(s): North Cook Inlet Field / Beluga Pool Plugs (measured) Junk (measured) 4020' TVD 407' 2571' 3514' 8840' Burst Collapse 12896' RECEIVED MAY 1 2 2004 Alaska Oil & Gas Cons. Commission Anchorage Tubing Pressure 280 280 Service D Daily Report of Well Operations X 16. Well Status after proposed work: Oil D Gas 0 WAG D WINJD 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Signature Dan Venhaus @ 263-4372 Mike Mooney JJrJ.M.~ Title GINJD WDspD Sundry Number or N/A if C.O. Exempt: Phone 263-4574 Wells Group Team Leader Form 10-404 Revised 2/2003 OR\G\NAL Date t7JII~ RØ)MS ~~IT IN DUPLlC~ES 200\ .PHILLIPS AlaS}, Inc. . A Subsidiary of PHILLIPS PETROLEUM COMPANY SSSv - SO' @ 407' MD (430' TVD) amco 5-1/2' SSSV @ 410' ~, As Run 12/16/03 B-1 A Well Name: North Cook Inlet Unit-B-1A Spud Date: 7/31/97 Sidetrack Date: 2/5/98 Schematic Update: Billingsley 12/18/03 J 5-1/2' GLM at 1559' with dummy, RK latch Casino Deoth Grade Weicht 30" 407' .J 5-1/2' GLM @ 2675' w/5I16' orfficelRK latch 20" 2579' K-55 133# 13-3/8' 3760' N-80 72# 20' @ 2579' MD (2571' TVD) 9-5/8" 10376' P-110 53.5# 2-318' Injection Strings for 5" DP 16650' S-135 19.5# top=10074' Sterling Disposal zone 13-318' @ 3760' MD ITbO Deoth Grade Weicht 5-1/2" 3764' L-80 15.5#, csg buttress J 5-1/2' GLM at 3602' w/dummy and RK latch LJ 15' PBR on top ofpkr 5-1/2" 'X' nipple, 4.562' ID @ 3700' Baker SC-1R Pkr @ 3764' (6.00'ID) 5' x 7' KOIV @ 3797' 4 zones: 3850'-3869', 3886'-3893'. 4185'-4268',4275'-4365' Tag fill @ 54 8' on 12/19/03 9-5/8' SC-1L@ 4368' 4 zones: 4429'-4480', 4751'-4761' 4792'-4803',4922'-4955' 9-518' SC-1R Sump Pkr @ 4969' (6.oo'ID) 5-1/2' SLHT blank 4-1/2' X nipple profile, 3.813' @ 5579' 9-5/8' SC-2 @ 5613' (4.75' ID) 5' x 3-1/2" KOIV at 5647' 4' screens and blanks 14 zones perfed: 5718'-5742', 5885'-5892' 5929'-5939',5948'-5969',5995'-6032', 6078'-6091',6097'-6107',6118'-6124', 6148'-6158',6169'-6182',6283'-6290', 6375'-6390',6610'-6622',6762'-6767' S-22 Snap Latch 9-5/8' SC-1R Sump Packer @ 6787' -1/2' x 3-1/2' crossover 3-1/2" X nipple at 6836' 3-1/2" WLEG at 6867' Actual 4-1/2' tbg cut @ 8052' on 11/22/03 9/29/02 Tag TOC at 9610' in tbg 4.5', 12.75 ppf, P-110 Tubing Calc TOC in tbg x 9-518' @ 9837' PERFS @ 9970'-9972' 4 SPF PKR @10,074MD (8846' TVD) Sliding Sleeve @ 10032' MD (8598'TVD) PXN Plug '" Nipple, 9-518' @ 10376' MD (884S' TVD) 5',19.5 ppf, S-135 Drill Pipe with G' Tool Joints (min. ID: 3.25') N. Forlands PERFs @ 16080'-16118' MD CMT in DP @ 16590' MD 5' DP @ 16650' MD !QQ 53.6' 410' 1559' 2675' 3602' 3671' 3700' 3764' 3797' 4368' 4969' 5547' 5579' 5613' 5647' 6786' 6787' 6805' 6836' 6867' 'and" Lenoth Item l' 10.3/4" x 5-1/2" Vetco tbg hgr, 5-1/2" BTC btm and top 5-1/2" tbg, L-80, 15.5# R2, BTC mod Cameo 5-1/2' SSSV TRM-4E w/4.562" X dummy Cameo 5-1/2"x1-1/2" MMG GLM 5/16' orificeCamco 5-1/2"x1-1/2' MMG GLM dummy Cameo 5-1/2'x1-1/2" MMG GLM one jt 5.1/2" tbg, L-80, 15.5# R2, BTC mod Baker PBR/seals, 7.0' OD X 4.875' ID 5-1/2" "X" nipple one jt 5-1/2" tbg, L-80, 15.5# R2, BTC mod Baker 5-1/2" x 9.5/8" SC-1 R pkr assy 7" x 5" KOIV 5-1/2" 15.5# SLHT blank & screens' Baker SC-1 L pkr assy 5-1/2" 15.5# SLHT blank & screens" Baker SC-1 R Sump pkr #2 assy 5-1/2" 15.5# L-80 SLHT blank tbg Xover, 5-1/2" SLHT X 4-1/2" IBT one jt of 4-1/2" IBT 4-1/2" X nipple, 3.813" profile 1 jt of 4-1/2" IBT w/S-22 4.75" snap latch Baker 4" X 9-5/8' SC-2 pkr assy, 4.75" ID 5" X 3-1/2" KOIV 4" SLHT screen and blank Baker S-22 Snap Latch Baker SC-1 R sump packer 3-1/2" x 5-1/2" xover 3-1/2" tbg, 3.1/2" X nipple, 2.813" profile 3-1/2" WLEG tbg tail 9' long x 5-1/2" Braden blanks w/RA collars @ 4016', 4609' and 4881' WELL HISTORY: Feb. 5, 1998 - Sidetrack Nov. 26, 2001 - Set 3.813" PXN Plug in XN Nipple. 3.125 Fishneck. XN Nipple is 3.725" NoGo w/3.813" packing bore. Sept. 25, 2002 - PERF from 9970' 9972' RKB, 4 spf w/2' PERF gun in prep for P&A Sept 27, 2002 - Cement tubing & casing, cement in annulus @ 9937' (est): PXN Plug in Nipple @ 10,073' Junk & fill on top of PXN plug top @ 10,010' Sept 29, 2002 - Tag TOC @ 9610' 12/18/2003 Unable to pull dummy @ 3602', set orif @ 2675' 12/19/2003 Tag top of CaCO3 wlwt bar @ 5478'=169' above KOIV r"\ r'"\ NCI B-01 A WELL EVENTS SUMMARY Date Summary 01/16/04 TAGGED FILL @ 5370' RKB CORRECTED, RAN CATCHER SUB ON TOP OF SAND- ATTEMPTED TO PULL OV AT STATION #2. UNABLE TO LATCH OR PULL - TOOLS COVERED AND PACKED WITH MUD AND SAND - DISCUSSED WITH ENG. 02/12/04 OFF-LOAD BOATS - MIRU BJ SERVICES AND PTSo [Standby] 02/13/04 PDS MEMORY SPINNER SURVEY FROM 3800' TO 5200' AT 40/80/120 FTIMIN WITH MULTIPLE STOP COUNTS TO LOCATE WATER PRODUCTION ZONES FOR NEAR FUTURE WATER SHUTOFF PROCEDURES - TAGGED FILL @ 5347' WLMo [Prod-Inj Profile] 02/15/04 TUBING COATED WITH MUD - LATCHED AND PULLED BOTTOM DV @ 3,617' RKB AND REPLACED WITH A 1/2" ORFACE VALVE - LATCHED AND PULLED MIDDLE OV @ 2,689' RKB AND REPLACED WITH A LIVE OPERATING VALVE. 0 [GLV] 02/16/04 CONTINUED TO MOVE EQUIP FROM A-10 TO B-01. PERFORMED A BOP TEST WITH A 500# TEST TO THE PTS SEPARATOR. INITIATED A MEM LOG TO FLAG PIPE AT 4500' CTM - MEMORY COUNTER PROBLEMS. INSTALLED BAKER BHA AND J-20 SETTING TOOL W/4.5" WRP - SET WRP @ 4130' CTM. 02/20104 TAGGED CAC03 PLUG WI 2.5" BAILER AT 4127' WLM.o [Tag] 02/21/04 RIGGED UP TEMP GAS LIFT. OPENED UP WELL TO FLOW, TAKING RTNS THROUGH PTS SEPARATOR. APPROX 80 BBLS FLOWED BACK; SHUT IN WELL, DISCUSS OPTIONS IN A.M. 02/24/04 TAGGED FILL I TOP OF PLUG 4127' WLM W / SLICK LINE. MOVED COIL ON AND PREPPED FOR SAND PLACEMENT. TAGGED TOP OF PLUG WI COIL AT 4125' CTM. ONGOING.O [Tag, Cement-Poly Squeeze] 02/25/04 TAGGED TOP OF PLUGIFILL AT 4125' CTM; LAYED IN 1250#'S OF 20/40 SILICA SAND FROM TAG TO 3850' CTM. ATTEMPTED TAG WI COIL AFTER 1.5 HOURS-- DIDN'T SEE ANY SAND. RIGGED SIL AND TAGGED WI 1.75" DD BAILER @ 4127' WLM, 4167' COR RKB. CONFIRMED TOP OF PLUG CLEAN. START TO DUMP BAIL. 250 SAFECARB ON TOP OF PLUG. APPROX 6 GALS SLURRY DUMPED, TAGGED APPROX 3' ABOVE PLUG AT 4123', RAN 3.5" LIB, FISHNECK COVERED. 02/26/04 RIGGED UP COILED TBG TO PULL WRP - WAIT ON CIRC SUB AND DISCONNECT BALLS - LATCH WRP AND JARRED LOOSE - LOST PLUG AT X NIPPLE (3720' CTM)- POOH TO CHECK TOOLS - RETRIEVING HEAD OKAY - RIH AGAIN AND KNOCKED WRP DOWNHOLE FROM 3720' CTM TO 4125' CTM AND RELATCHED. POOH W/WRP. 02/27/04 TAGGED TOP OF FILL @ 5097' WLM (5140' RKB) WI 1.75" DD BAILER. FILL 20/40 MESH SAND PUMPED ON 2125. RIGGED UP COIL AND RAN MEMORY LOG FROM 5100' CTM TO 3800' - FLAGGED PIPE @ 4500' AND MADE PDS TIE-IN LOG AND SET 5-1/2" WRP AT 4020' RKB. RIGGED UP SIL TAGGED TOP OF WRP AT 3985' WLM, DUMPED BAILED 6' OF SAFECARB 250 ON TOP OF PLUG (TOP OF FILL 3979' WLM, 4014' COR RKB). r-'\ r-'\ NCI B-01A WELL EVENTS SUMMARY 02/28/04 BULLHEADED APPROX 1200# OF 20/40 SAND IN 5 BBL HEC SLURRY W/ BREAKER FOLLOWED BY 71 BBLS DIESEL. RIGGED S/L AND TAGGED TOP OF SAND PLUG AT 3930' WLM, 3965' COR RKB. TAGGED NUMEROUS TIMES AS SAND WAS FALLING OUT. PUMPED 20 BBLS AND FINAL SAND TOP WITHIN WINDOW @ 3947' RKB - PDS MEMORY SPINNER LOG ON SLlCKLINE W/40/80/120/160 FT/MIN PASSES AND STOP COUNTS - PREPARE COIL DUMP BAIL OF POISON PILL SQUEEZE W/2 BBL SODIUM SILICATE AND ACID. 02/29/04 ATTEMPTED TO PUMP SODIUM SILICATE POISON PILL - UNABLE TO GET PAST 3863' RKB - RIG UP SLlCKLINE AND MADE 4 BAILER RUNS WITH SOLID FORMATION SAND - DUMP SILICATE TO OPEN TOP AND RIG UP FCO WITH N2 - PIN HOLED PIPE WHILE POOH DURING CLEANOUT @ 2740' CTM. 03/01/04 STANDBY FOR WEATHER - UNABLE TO GET TOOLS TO PLATFORMO [Tag] 03/02/04 TAG OBSTRUCTION W/ 1.75" LIB AT 3878' WLM. LIB SHOWS TAPERED TUBING RESTRICTION ON TWO SIDES.O [Tag] 03/03/04 STANDBY FOR MEMORY CAMERA TOOLS. CHOPPER GROUNDED FOR BAD WEATHER AND MECHANICAL PROBLEMS 03/04/04 STANDBY FOR CAMERA AND OPERATOR, CHOPPERS GROUNDED DUE TO WEATHER 03/05/04 ATTEMPTED MEMORY CAMERA LOG. MADE THREE ATTEMPTS, NO PICTURES OF OBSTRUCTION. ATTEMPTED TO DISPLACE WELLBORE WITH N2 AFTER SECOND RUN, UNABLE TO DISPLACE WELLBORE TO OBSTRUCTION DUE TO OPEN PERFS ABOVE. 03/06/04 RAN MEMORY CAMERA, SAW SAND ON OBSTRUCTION AT 3878' WLM. BAILED -1- 1/2 CUPS OF FORMATION SAND, SCALE AND BEACH SAND FROM SAME DEPTH. RAN 1.35" LIB, SAW SIMILAR TAPERED RESTRICTION AS PREVIOUS LIB'S. SD TO ALLOW FLUIDS TO SETTLE AND CLEAR. 03/07/04 MADE 3 MEMORY CAMERA RUNS, PICTURE CLARITY IMPROVING WITH WATER CLARITY. LAST SET OF PICTURES SHOW OVALLING OF WELLBORE AT OBSTRUCTION DEPTH (3878' WLM), CAUSE NOT DETERMINED DUE TO PICTURE CLARITY ISSUES. PUMPED TOTAL OF 315 BBLS OF DRILL WATER. 03/08/04 MADE MEMORY CAMERA RUN, FLUIDS STILL NOT CLEAR. STANDBY TO ALLOW WELLBORE TO SETTLE OUT. 03/09/04 MEMORY CAMERA, SAW HEAVY SCALE ON BOTTOM, UNABLE TO GET PICTURE OF OTHER OBSTRRUCTION. 03/10/04 PERFORMED MULTIPLE SAMPLE RUNS, ALONG WITH SHIFTING THE SLIDING SLEEVE AT 3,786' RKB CLOSED.O [Tag] 03/11/04 THIS COVERS ALL STBY CHARGES FOR PTS AND PDS UP TO 3/11/20040 [Standby] 03/11/04 DEMOB DAY FOR POLLARD. 03/13/04 PERFORMED A FCO TO A DEPTH OF 3,925' MD - 3,960' RKB WITH THE 13/4" BJ TORNADO NZL. WASHED TUBING FROM 3,800' TO 3,960' RKB IN RESPECT TO A POSSIBLE OBSTRUCTION AT 3,921' RKB FOUND ON 3/10/04 WITH WIRELINE DDB. NOTE: «(UTILIZED 3# XCD MIXED WITH 3% KCL FOR CLEAN OUT STAGE AND SAND STAYED SUSPENDED IN GEL))) SECOND RIH WAS A 3.82" JUNK MILL FOR A SEMI DRIFT. TAGGED UP ON CMD AT 3800'. ROLLED PUMPS TO BYPASS CMD. DRY TAG AT 3960' RKB. ~ ,-..., NCI B-01 A WELL EVENTS SUMMARY 03/14/04 PERFORMED A MEMORY INJECTION PROFILE FOR FLUID PATH IDENTIFICATION. NOTED THAT 50% OF FLOW INJECTING INTO CMD THAT COIL TAGGED LIGHTLY THE DAY BEFORE AT 3,780' RKB. RAN A CMD SHIFTING TOOL TO A DEPTH OF 3,950' RKB FOR A DRIFT OF 4.5". PULLED SHIFTING TOOL INTO POSITION ON CMD AND SHIFTED SLEEVE CLOSED. RIH WITH COILED TUBING TO SPOT A POISON PILL OF 30 GAL SILGEL, LA YED IN 7 BBLS OF 15% HCL AND DISPLACED ON WAY TO SURFACE. 03/15/04 PERFORMED A SILGEL SQUEEZE FROM 3,950' TO 3,750' RKB. INJECTED A 20 BBLS DIESEL PILL FOLLOWED UP WITH 24 BBLS OF SILGEL. WILL STBY FOR PT ON SILGEL UNTIL 3-16-2004.0 [Cement-Poly Squeeze] 03/16/04 TAG TOP OF GEL AT 3,694' RKB. HELD WIEGHT OF TOOL STRING AT 3,709' RKB. POOH FOR COIL TO RIG UP.O [Cement-Poly Squeeze] 03/16/04 CLEANED OUT SILGEL TO 3950' CTM W/ FRESH WATER. ATTEMPTED TO UNLOAD TBG TO PTS W/ GAS LIFT, TOO MUCH HYDROSTATIC. PERFORMED N2 LIFT; RECOVERED APPROX. 100 BBLS. SHUT DOWN FOR THE NIGHT. 0 [FCO] 03/17/04 UNLOADED REMAINING FLUID FROM TBG TO PTS SEP / FLARE W/ LIFT GAS (APPROX MORE 25 BBLS). PUT WELL IN TEST; AS OF 17:00, WELL HADN'T PRODUCED ANY FLUID FOR ROUGHLY 8 HOURS. SILGEL SQUEEZE APPEARS TO BE GOOD. ONGOING.O [Cement-Poly Squeeze] 03/18/04 ATTEMPTED TO FIND FLUID LVL W/ SL; INCONCLUSIVE RESULTS. TAGGED FILL AT 3940' RKB. SHOT FLUID LVL WI ECHOMETER, FOUND FLUID AT 2912' WI 1000 PSI WHTP. BEGAN CIRCULATING WELL W/ LIFT GAS; RECOV 13 BBLS WATER, APPROX 4 BBLS/HR. PROCEEDED TO LOAD IA FOR UPCOMING SQUEEZE W/225 FW, CIRC TO PTS. AT 175 BBLS AWAY, BEGAN GETTING WATER AT SURFACE, 34 BBLS WHEN DONE INDICATING TBG ALREADY FLUID PACKED. SWAPPED OVER AND BEGAN PUMPING DOWN TBG, 0.42 BPM AT 800 PSI. SHUT DOWN AT 14 BBLS AWAY. 03/19/04 LOADED COIL W/ DIESEL. ATTEMPTED TO RIH, CTU OPERATOR FORGOT TO DISENGAGE REEL BRAKE, BENT GOOSENECK ASSEMBLY. FLEW IN PARTS, REPAIRED GOOSENECK. TAGGED FILL AT 3947' RKB, PICKED UP TO 3930' AND PERFORMED INJ TEST: 0.07 BPM @ 800 PSI, 0.18 @ 1100 PSI MAX 03/20104 UNLOADED WELL WI N2 IN ATTEMPT TO FLUSH GRAVEL PACK SCREENS IF PLUGGED. RELOADED WELL AND PERFORMED INJECTIVITY TEST, 0.18 AT 800 PSI, 0.3 BPM @ 1100 PSI. LA YED IN 6 BBL SILGEL PILL (12.4 HCL I 39% SODIUM SILICATE) FROM 3930' TO 3720' RKB. PULLED UP HOLE 200' AND SQUEEZED SILGEL IN. 03/21/04 CLEANED SAND/CAC03 PLUG FROM TOP OF WRP USING 2.70 JS NZL AND N2/FW/10% HCL. PULLED 4.5" BAKER WRP FROM 4020'; 1ST RUN IN, COULDNT GET DOWN THRU SLEEVE AT 3782'- POOH AND CUT MULESHOE ON RETRIEVING HEADfTWEAKED PIPE. 03/22/04 PERFORMED CLEANOUT WI 2.70 JET SWIRL NOZZLE/BJ TORNADO TO HARD TAG AT 5539' RKB USING N2 & 3% KCL. ATTEMPTED TO JET THU CAC03 PLUG WI NITRIFIED 10% HCL ACID, PUMPED 75 BBLS AND MADE HOLE TO 5577' RKB. RBIH WI BAKER 2-1/8" BAKER MOTOR AND 3.25" OD 3-BLADE JUNK MILL.; MILLED HARD TAG AT 5641' RKB. UNABLE TO MILUBREAKTHRU KOIV IF ON IT. RIGGED UP S/L AND TAGGED 5549'. r"- ~, NCI B-01 A WELL EVENTS SUMMARY 03/23/04 CLEANED FILL TO 5641' COR RKB W/2.70" JS NZL USING 3% KCL. RIGGED SIlo RIH W/2.25 DD BAILER, RECOVERED 20/40 SAND & PIECES OF METAL- TWO TYPES MESHED (APPEARED BRASS/STEEL), LGST 0.5" LONG. CHECKED SOLIDS TRAP AND RECOVERED PIECES OF PLASTIC/RUBBER W/ THREAD GROOVES. 03/24/04 RIH W/2-1/8" BAKER FISHING BHA W/1.75 " TAPERED CHISEL-BIT NOZZLE; WASHED RIGHT THROUGH KOIV W/3% KCL (ASSUME IT WAS BROKEN BY S/L YESTERDAY) TO 5750' RKB. RIGGED S/L AND DRIFTED OUT OF TTL W/2.25" DD BAILER. ENCOUNTERED SOME TRASH / DEBRIS JUST UNDER KOIV PROFILE. 03/25/04 WAITING ON PDS CALIPER / DHV CAMERA EQUIPMENT TO ARRIVE; DEMOB PERSONNEL TO THE SHORE FOR THE NIGHT. D [Standby] 03/26/04 RE-MOB CREWS BACK TO THE PLATFORM. PDS CALIPER TOOLS ON LOC. AS WELL AS DHV CAMERA EQUIPT. POLLARD E-LINE UNIT TO ARRIVE BY BOAT THIS EVENING. ONGOING. ATTEMPTED LOGGING RUN W/2.75" PDS CALIPER LOGGING STRING; SAT DOWN IN SLEEVE OF INTEREST AT 5623' AND IN KOIV PROFILE. 03/27/04 RAN DRIFT 3.25" DRIFT THROUGH SLEEVES/KOIV PROFILE AT 5647'; NO PROBLEMS. SAT DOWN SLIGHTLY IN KOIV. SMALLER CALIPER TS HAS ARRIVED; RIGGED UP PW W/ 1-11/16" 20 FINGER PDS CALIPER; SURFACE TESTED IT, FINGERS FAILED TO EXTEND-ATTEMPTED TO TROUBLESHOOT, NO GOOD. 03/28/04 RAN 1-11/16" DHV CAMERA TAKING VIDEO OF POINTS OF INTEREST; TWO UPPER- MOST GP SLEEVES IN OPEN POSITION. DIDN'T SEE ANY FLUID INFLUX OR DAMAGE IN AREA OF SILGEL SQUEEZE. FOUND FLUID LEVEL AT 4710' VISIBILITY POOR FROM THAT POINT DOWN. 04/01/04 PERFORMED A MEMORY CALIPER LOG FROM 5,750' RKB TO SURFACE. ALL DATA WAS RETRIEVED AND DOWNLOADED TO PDS COMPUTER. WILL HAVE LOG AND FEED BACK IN THE AM. RELEASED POLLARD AND PDS. (PHILLIPS 15% CHARGES CAUGHT UP FROM 3-25-2004 TO PRESENT!!)D [Leak Dete 04/03/04 PERFORMED A MEMORY LOG ACROSS GRAVEL PACKS FOR CONFIRMATION. SHIFTED CMD'S CLOSED AT 4,380' & 3,786' RKB. PREP WELL FOR FLOW BACK.D [Other Stirn] 04/05/04 AWAITED FINAL CONFIRMATION ON TOP OF GRAVEL PACK PRIOR TO INITIATING FLOW BACK PROCEEDURES. AT 18:00 HOURS BEGAN FLOW BACK. ISIWHP = 800# IA = 800#. SLOWLY BLED OFF 50 PSI EVERY 30 MIN TO 450# FHWP. 04/07/04 PRODUCTION RATE = 9.2 MIL GAS, 120 BWPD, AT 400# FWHP( THIS TEST DATA PROVES THAT THE SIL GEL TREATMENT HAS SUCCESSFULLY SHUT OFF> 80% OF THE WATER INFLUX ). 04/10/04 CHARGES FOR DEMOBE OFF THE TYONEK PLATFORM. THESE CHARGES INCLUDE BOAT, CRANE, AND TANK CLEANING. Dan Venhaus Drilling and Wells Senior Engineer ConocJP'hillips P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-263-4372 March 5, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 ,./ Subject: Application for Sundry Approval for NCI 8-01 A (APD # 198-002) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Application for Sundry Approval for the North Cook Inlet well 8-01 A. This request is for upcoming water shut-off work on this well. If you have any questions regarding this matter, please contact me at 263-4372. SinC~..IY, ¿Lie""."" /:-¿, / / ~/l !/~~~ D. Venhaus Wells Senior Engineer CPAI Drilling and Wells DV/skad RE(~E"V1=,¡:,=) }liAR 0 5 200~ C So r. nt\"'lrl¡I'\;¡¡~On M~~~Œ Oi\ !?~. Gas JO.~.~, .. ,,,' {,\nr,~ijf"Ç:', ~CÞ~¡NJ~ED MAR 122004 \' ! :, \ \ , STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 J% 1. Type of Request: Abandon 0 Suspend 0 Operational shutdown 0 Perforate D Variance 0 Annular Dispos. D Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate D Time Extension 0 Other 0 Change approved program D Pull Tubing D Periorate New Pool 0 Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number/ ConocoPhillips Alaska, Inc. Development 0 Exploratory 0 198-02 3. Address: Stratigraphic 0 Service D 6. API Number: V P. O. Box 100360, Anchorage, AK 99510 50-883-20093-01 7. KB Elevation (ft): 9. Well Name and Number: 132' RKB NCIU B-1 A 8. Property Designation: 10. Field/Pools(s): ADL 17589 Cook Inlet Field / Beluga Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured) Junk (measured): 16720' 12942' 9610' 8220' 4020' Casing Length Size MD TVD Burst Collapse Structural 368' 30" 407' 407' Conductor 2579' 20" 2579' 2571' Surface 3760' 13.375" 3760' 3514' Intermediate 1 0376' 9.625" 10376' 8840' Production Liner 5" 16650' 12896' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 3850'-4365',4429'-4955',5718'-6767 3587'-4007', 4060'-4484', 5098'-5943' 5.5" L-80 6867' Packers and SSSV Type: Packers and SSSV MD (ft): packer, Camco SSSV pkr @ 3764',4368',4969',5613' and 6787', SSSV @ 410' 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program D BOP Sketch [J Exploratory 0 Development 0 Service 0 14. Estimated Date for 15. Well Status after proposed wo~ Commencing Operations: 3/9/2004 Oil [!j. Gas Plugged 0 Abandoned 0 16. Verbal Approval: Date: WAG 0 GINJD WINJ D WDSPL 0 Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Venhaus 263-4372 Printed Name an VÜa,JJS Title Signature :::7'/Ý1^- Ud~ Phone 263-4362 Date 3 .-S "bl COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: BOP Test'~ ~Llt?1¿ Plug IntegrityD Mechanical Integrity Test 0 Location Clearance D Other: dSDD rS\ \¡.'--~\^', v'--'~ \~. '\SÛ ?-\-e-~'-\-- SUbs~?7ßd.L\ _BFl M.'\ \) 9 1.ßMì Approve bY:/. j A BY ORDER OF Date:(j Iii It! COMMISSIONER THE COMMISSION ~~ \. ~ \.: / { , - Form 10-403 Revised 2/2003 l\ I SUBMIT IN DUPLICATE ~PHILLIPS Ala!. ..8, Inc. ~ A Subsidiary of PHILLIPS PETROLEUM COMPANY 30" @ 407' MD (430" TVD) amco 5.1/2" SSSV @ 410' 5-1/2" GLM at 1559' with dummy, RK latch 5-112" GLM @ 2675' w/5l16" orifice/RK latch 20" @ 2579' MD (2571' TVD) 2-3/8" Injection Strings for Sterling Disposal zone 13-3/6" @ 3760' MD 5-1/2" GLM at 3602' w/dummy and RK latch 15' PBR on top of pkr 5-1/2" "X" nipple, 4.562' ID @ 3700' Baker SC-1R Pkr @ 3764' (6.00"ID) 5" x 7" KOIV @ 3797' 4 zones: 3850'-3869', 3686'-3693',' 4185'-4266',4275'-4365' 9-5/6" SC-1 L @ 4368' 4 zones: 4429'-4480', 4751'.4761' 4792'-4803',4922'-4955' 9-5/6" SC-1R Sump Pkr @ 4969' (6.00" ID) 5-1/2" SLHT blank 4-1/2" X nipple profile, 3.613" @ 5579' 9-5/8" SC-2 @ 5613' (4.75" ID) 5" x 3-1/2" KOIV at 5647' 4" screens and blanks 14 zones perted: 5718'-5742', 5885'-5892' 5929'-5939',5946'-5969', 5995'-6032', 6076'-6091',6097'-6107',6118'-6124', 6148'-6158',6169'-6182',6283'-6290', 6375'-6390',6610'-6622',6762'-6767' S-22 Snap Latch' 9.518" SC-1R Sump Packer @ 6787' 5-1/2" x 3-1/2" crossover 3-1/2" X nipple at 6836' 3-1/2" WLEG at 6867' Actual 4-1/2" tbg cut @ 8052' on 11/22/03 9/29/02 Tag roc at 9610' In tbg 4.5", 12.75 ppf, P-110 Tubing Calc TOC in tbg x 9-5/6" @ 9837' PERFS @ 9970'.9972' 4 SPF PKR @10,074 MD (8846' TVD) Sliding Sleeve @ 10032' MD (8598' TVD) PXN Plug In Nipple, 9-5/8' @ 10376' MD (8846' TVD) 5", 19.5 ppf, S-135 Drill Pipe with G' Tool Joints (min. ID: 3.25") N. Forlands PERFs @ 16080'-16118' MD CMT in DP @ 16590' MD 5" DP @ 16650' MD :\ \ , As Run 12/16/03 ' B-1 A Well Name: North Cook Inlet Unit-ß..1A Spud Date: 7/31/97 Sidetrack Date: 2/5/98 Schematic Update: Billingsley 12/18/03 Casina Decth Grade W eiaht 30" 407' 20" 2579' K-55 133# 13-3/8" 3760' N-80 72# 9-5/8" 10376' P-110 53.5# 5" DP 1 ß650' S-135 19.5# top=10074' Tba Decth Grade W eiaht 5-1/2" 3764' L-80 15.5#, csg buttress JQg 53.6' Lenath Item l' 10-3/4" X 5-1/2" Vetco tbg hgr, 5-1/2" BTC btm and top 5-1/2" tbg, L-80, 15.5# R2, BTC mod Camco 5-1/2" SSSV TRM-4E w/4.562" X dummy Camco 5-1/2"x1-1/2" MMG GLM 5/16' orifice Camco 5-1/2"x1-1/2" MMG GLM dummy Camco 5-1/2"x1-1/2" MMG GLM one jt 5-1/2" tbg, L-80, 15.5# R2, BTC mod Baker PBRlseals, '7.0" aD X 4.875" ID 5-1/2" "X" nipple one jt 5-1/2" tbg, L-80, 15.5# R2, BTC mod Baker 5-1/2" X 9-5/8" SC-1 R pkr assy 7" x 5" KOIV 5-1/2" 15.5# SLHT blank & screens'" Baker SC-1 L pkr assy 5-1/2" 15.5# SLHT blank & screens"" Baker SC-1 R Sump pkr #2 assy 5-1/2" 15.5# L-80 SLHT blank tbg Xover, 5-1/2" SLHT x 4-1/2" 1ST one jt of 4-1/2" IBT 4-1/2" X nipple, 3.813" profile 1 jt of 4-1/2" 1ST w/S-22 4.75" snap latch Baker 4" x 9-5/8" SC-2 pkr assy, 4.75" ID 5" x 3-1/2" KOIV 4" SLHT screen and blank Baker S-22 Snap Latch Baker SC-1 R sump packer 3-1/2" x 5-1/2" xover 3-1/2" tbg, 3-1/2" X nipple, 2.813" profile 3-1/2" WLEG tbg tail 9' lon~ x ?1/2" Braden blanks w/RA collars @ 4016',.4609' and 4881' 410' 1559' 2675' 3602' 3671' 3700' 3764' 3797' 4368' 4969' 5547' 5579' 5613' 5647' 6786' 6787' 6805' 6836' 6867' '* ana'"'" WELL HISTORY: Feb. 5, 1998 - Sidetrack Nov. 26,2001 - Set 3.813" PXN Plug in XN Nipple. 3.125 Fishneck. XN Nipple is 3.725" NoGo w/3.813" packing bore. Sept. 25, 2002 - PERF from 9970' 9972' RKB, 4 spf w/2' PERF gun in prep for P&A Sept 27, 2002 - Cement tubing & casing, cement in annulus @ 9937' (est.); PXN Plug in Nipple @ 10,073' Junk & fill on top of PXN plug top @ 10,010' Sept 29,2002 - Tag TOC @ 9610' 12/18/2003 Unable to pull dummy @ 3602', set orif @ 2675' 12/19/2003 Tag top of CaC03 w/wt bar @ 5478'=169' above KOIV ~ ConocoPhillips NCIU B-Ol Proposed Squeeze March 4, 2004 SUMMARY: Well B-01A is a NCI gas producer that was re-completed and gravel-packed this past December, 2003. The new completion consists of 5-1/2" tubing, an upper 5-1/2" screen interval, and a lower 4" screen interval. Significant losses occurred during perforating requiring 6 - 50 bbl HEC pills to slow losses. In addition, a 1500# batch of CaC03 was pumped to isolate the lower straddle due to a leaking KOIV. After completing, slickline broke through upper KOIV with a 3.22" weight bar but tagged 170' above the lower KOIV @ 5478'. The obstruction is mostly likely CaC03 (no sample taken). With only the upper straddles flowing, current gas production is only 2 mmscfd. Water production was initially 200 bpd and has since increased to 500 bwpd. The objectives of this well work are: . Production log to determine water source (Completed) . Set WRP below water zone. Cover with CaC03 (Completed) . Spinner to verify squeeze perfs are open . CTU pump "donut" poison pill followed by sodium silicate squeeze . CTU FCO/pull WRP . CTU FCO carbonate in lower section and break KOIV . N2 lift PROCEDURE: Completed 1. RU slickline. Run memory spinner across open screens to identify water entry. Move orifice to lowest station. (Upper 2 sets of perfs 3850'-3869' producing water) 2. RU CTU/slickline and set retrievable plug below proposed squeeze interval at 4020' rkb. Spot or dump bail calcium carbonate on plug followed by 20-40 sand. Target sand top 3930' -3950'. Proposed Saueeze Steps 3. RU CTU. Spot concentrated 1 bbl sodium silicate pill on sand plug using CT dump bailer. Bullhead 7 bbls 15% HCL to contact silicate and set up. 4. Log w/ spinner/temp tools to determine effectiveness of sodium silicate pill. 5. Rill with treating nozzle and sit above squeeze interval. Pump 24 bbl BJ SilJel squeeze. RD CTU. Allow 24 hrs for silicate to set. 6. RU slickline. Bail to CaC03 cap or hard tag. Flow well to PTS separator to test squeeze. 7. Rill w/ CT , clean out to plug and pull plug. Perform nitrified FCO to KOIV @ 5647'. Knock out KOIV. Drift to PBTD to determine how much CaC03 is in screens. N2 lift to assist flow if necessary. 8. RU slickline. Run memory spinner across screens while flowing. D. Venhaus 3/3/04 Paul Mazzolini It' " Exploration/Cook Inlet Drilling , ~ T earn Leader Drilling & Wells ~ P.O. Box 100360 GonocoPh811 181 pS Anchorage,AK 99510-0360 Phone: 907-263-4603 January 21, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Report for NCI 8-01 A (APD # 198-002 / 303-138) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Well Completion Report,for the North Cook Inlet well 8-01 A. This report is for the recent workover operations on this well. If you have any questions regarding this matter, please contact me at 263-4603. Sincerely, ?~Y1~ P. Mazzolini Exploration/Cook Inlet Drilling Team Leader CPAI Drilling PM/skad RECEIVED JAN 2 2 2004 Alaska Oil & Gas Cons. Commission Anchorage ~(;ANB~EC Jt~N 2 ~ 2,OO(~. ( STATE OF ALASKA J". ALASKA OIL AND GAS CONSERVATION COM 1......:iION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil D Gas ~ Plugged [J Abandoned D Suspended D WAG D 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development 0 Exploratory D GINJ D WINJ 0 WDSPL 0 No. of Completions - Other - Service 0 Stratigraphic Test D 2. Operator Name: 5. Date Comp., Susp., 12. Permit to Drill Number: ConocoPhillips Alaska, Inc. or Aband.: 12/16/03 198-02/303-138 3. Address: 6. Date Spudded: 13. API Number: P. O. Box 100360, Anchorage, AK 99510-0360 February 12,1998 50-883-20093-01 4a. Location of Well (Govemmental Section): 7. Date TO Reached: 14. Well Name and Number: Surface: 1249' FNL, 980' FWL, Sec. 6, T11N, R9W, SM . April 2, 1998 NCIU B-1A At Top Productive 8. KB Elevation (ft): 15. Field/Pool(s): Horizon: 2321' FNL, 1235' FWL, Sec. 6, T11N, R9W, SM 132' North Cook Inlet Field Total Depth: 9. Plug Back Depth (MD + TVD): Beluga Pool 2558' FSL, 1032' FEL, Sec. 12, T11N, R10W, SM 9610' MD / 8220' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 332000 y- 2586730 Zone- 4 16720' MD /12942' TVD ADL 17589, North Cook Inlet Unit TPI: x- 331990 y- 2585659 Zone- 4 11. Depth where SSSV set: 17. Land Use Permit: Total Depth: x- 329890 y- 2580009 Zone- 4 410' N/A 18. Directional Survey: Yes D No~ 19. Water Depth, if Offshore: 20. Thickness of 130' feet MSL Permafrost: N/A 21. Logs Run: RST, USIT, CHMDT 22. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 30" Surface 407' Driven 20" 133# K-55 Surface 2579' 24" 1690 sx Class G, 700 sx tail 13-3/8" 72# N-80 Surface 3760' 18-1/2" 1234 sx Class G, 672 sx tail 9-5/8" 53.5# P-110 Surface 10376' 12-1/4" 2400 sx lead, 704 sx tail 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) 5.5" /4.5" / 3.5" 6867' 3764',4368',4969',5613', and 6787' 3850' - 6767' MD, 3586' - 5943' TVD, 18 spf 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED N/A 26. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) December 24, 2003 Flowing Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO 12/25/2003 24 hours Test Period --> 6830 320 Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF W A TER-BBL OIL GRAVITY - API (corr) press. 120 ps 500 psig (used gas lift to kick off) 24-Hour Rate -> 6830 320 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary)R E C E I V E Submit core chips; if none, state "none". ,.. .. . .. , . D ,\ " ::., ,;. -- JAN 0 2 2004 I ¿ -It .D' ...J J:¡ NONE'.'.~H::-:"'~ . .' , -Â~'- i Alaska Oil & :::h;;::~ Commission Fonn 10-407 Revised 2/2003 CONTINUã'RrG \~ f\ L (g ¡:;; Submk in duplicate 28. GEOLOGIC MARKERS ( 29. ( FORMATION TESTS NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". Top Cook Inlet Sands 3846' 3583' Top Beluga 4968' 4494' N/A RECEIVED JAN 2 2 2004 Alaska Oil & Gas Cons. Commission Anchorage 30. LIST OF ATTACHMENTS Summary of Daily Operations, Schematic 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Tim Billingsley 265-6531 Printed Na"'"") n ¡ff{'~~ . nle: Cook Inlet Drillina T earn Leader 0 'I , Signature ïa-.x.... ~ ~ Phone 263-4603 Date Z. I zð04 Prepared by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1a: Classification of Service wells: Gas injection, water injection, Water-Alternating-Gas Injection, salt water disposal, water supply for injection, observation, or Other. 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. Item 4b: TPI (Top of Producing Interval). Item 8: the Kelly Bushing elevation in feet abour mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: 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). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Fonn 1 ~O7 Revised 212003 0 R \ G \ t\\ A. \ . (' I~ North Cook Inlet Unit No. B-IA Daily Summary Rig W orkover for Shallow Gas Recompletion 11/21/03 Release rig from B-3 at 23:59 on 11/20/03. Skid rig from B-03 to B-Ol, Accept rig on B-IA at 06:00 11/21/03. ND tree, NU riser & BOPs. Unable to test BOPs due to leaking tubing head. 11/22/03 Pull BPV, RU Lnd joint & Vetco tool to de-energize LD on hanger, "J" onto hngr, PU 135 k, de-energize, PU to 135 k, RU APRS to log collars & drift tubing to 3.625", RIH w/chem cutter, cut 4 1/2" tbg @ 8052' WLM, POOH- and RID WL, Rev circ, Circ. 11/23/03 POOH laying down 4-1/2" tubing-some kind of coating on OD of tbg. Monitor well-stable, break BOP connection to PU stack, raise stack, remove spools, install tubing head & x-o spool, test BOPE. 11/24/03 Finish testing BOPE, RIH with dual scraper BHA, RIH slow due to taking weight (pushing debris/coating in front of scraper?), tag tubing cut @ 8047' dpm, Circ 2-1/2 hole volumes until returns clean, POOH with scraper. 11/25/03 Rigged up Schlumberger and ran RST and USIT logs from 8000' to 3750'. Tested casing to 3000 psi. Picked up CHMDT tools. 11/26/03 Schlumberger ran CHMDT at 4948' (bit broke-trip out), 4937' (bit broke-trip out), 3864' (good gas sample), 4473' (good gas sample), 6122' (good gas sample), 6286' (bit quit-trip out), 4755' (good gas sample), 4797' (good gas sample),4937' (bit quit), 5462' (bit would not drill-trip out), 4937' (good gas sample finally), 5462' (good penetration-no sample due to tite formation), 6286' (good gas sample), 4110' (mud sample), 3972' (water sample) 11/27/03 Schlumberger finished CHMDT. Total of 5 trips in the hole, attempted 15 samples, obtained 10 samples- 7 gas, 2 wet, 1 tite. Ran 8.375" GR/JB to 8020'. Made up Sump packer and tail pipe. RIH. RU Schlumberger. 11/28/03 Schlumberger ran correlation log. PU 37' and put packer on depth at 6787' elm. Ran confirmation log. Set packer at 6787' and tested, small leak from MDT holes. POOH, Made up Sump packer plug. RIH and set plug at 6787' elm, pump sand on top of plug. Mixed and pumped caustic wash. 11/29/03 Circulated caustic wash to surface and injected fluid. Pumped 500 gallons HCl acid pickle down drill pipe and reversed out. Circulated and filtered brine with 64 NTU returns. RIH and tag top of sand at 6765' dpm=6785' elm. POOH and tested BOP. B-1 daily summary 12-19-03.doc 1 { ~ 11/30/03 Finished testing BOPE. Cut DL. Rigged up and ran 7" 18 spf TCP guns. Tagged sand at 6765' dpm. Spaced out guns and set packer. 12/01/03 Perforated casing from 5718' to 6767' elm, reversed out until brine cleaned - up. Monitored well and POOH. Laid down guns. Picked up scrapers and Rill tagged fill @ 6763' dpm (6783' elm). POOH to 5896'. 12/2/03 Circulated well clean and POOH with scrapers. PU Cavins bailer and overshot. RIH to 6763', bailed to 6765', engaged plug and pulled 2101 before pulling free, POOH, no plug. Cleaned out pipe and redressed bailer BHA. Rill again with bailer/overshot. 12/3/03 Rill and attempted to recover plug. POOH no plug. Cleaned out pipe and redressed bailer BHA. Rill. Bailed on plug and worked pipe, came free. POOH. Recovered plug. 12/4/03 MU OP packer. PU and Rill OP assembly with 4" screen and 2-7/8" inner string. Located sump packer at 6787' and set OP packer at 5613'. Reversed out setting ball. 12/5/03 Pump single gravel pack, ran low on brine. Built volume and finished gravel pack with a total of 40,500# sand. Killed well. POOH to KOIV flapper, losses still at 110 bph. Pump 15 bbl HEC/CaC03 pill. Losses declined to o. 12/6/03 POOH and laid down 2-7/8" inner string. PU sump packer #2 and tail pipe. Rill on drill pipe and located packer at 5613'. Set sump packer #2 at 4969' elm and tested packer. POOH with setting tool. 12/7/03 Picked up packer plug and RIH set in packer at 4969' elm. Put sand on packer. POOH with setting tool. Tested BOP. RIH with 7" TCP guns. 12/8/03 Tag sand on top of packer, PU to place guns on depth, perfed well from 3850' -~ to 4955' elm. Losses at 40 bph, pump 40 bbl HEC pill ro reduce losses to 14 bph. POOH and laid down guns. RIH with casing scraper BHA. 12/9/03 Tag fill with scraper assy at 4942'. POH above perfs to 3744'. Circ above perfs with clean returns. POH. Rill wi Cavins bailer assembly to top of fill @ 4941' dpm, bail to 4954' dpm, pull pkr plug with 105k overpull, POOH to 3841', drop bar, circ hole clean with some dirty fluid, Con't POOH wi bailing assy. 12/10103 POOH w/Cavins bailing assy, noticed dirty brine in drill pipe between circ sub and bailer. RIH wlopen ended dp to 1230', circ dp clean with 100 bbls, (dumped 25 bbls of dirty returns), decide to RIH to bottom to circ out any dirty fluid prior to gravel pack. Rill to 4954' dpm with open ended drill pipe, reverse circ 140 bbls, (dump 64 bbls dirty fluid) POOH, trouble shoot & replace service loop fl top drive. Losses at 14 bph. B-1 daily summary 12-19-03.doc 2 ,f , ( (' 12/11/03 PUIRllI wI 5 1/2" GP screens, 4" inner string & 2 7/8" inner string, MU Baker SC-IR packer, test string to 300 psi, Rill slow on 4 1/2" dp, attempt to stab into packer at 4969', had to rotate muleshoe to stab into packer. 12/12/03 Stab mule shoe into packer @ 4954' dpm, RU & space out, Snap into SC -IR packer, Set SC-IR packer @ 3745' dpm, RU BJ lines, Pump lower Gravel Pack stage- 24,640 lbs sand, screened out, reverse out sand, POH to 2nd stage of gravel pack with 80 bph losses, pump GP #2 with 30,900# sand, screened out, reverse out 150 bbls when pressured up to 4000 psi for no known reason. Bleed pressure, resumed reversing and pressured up again after 30 bbls pumped. This amount of reversing had cleared the 47 bbl drill pipe capacity and returns were clean of sand, no known reason for why pressure up occurred twice. POOH LID working joint, LID 15' pup. Pulled tight, pipe stuck after pulling a total of 27'. Able to circulate. 12/13/03 Continue to try & free stuck string with 160 klbs overpull, 90 bph losses, spot 15 bbls HEC around annulus to slow losses to 11 bph, con't to work string, let ann fluid drop 33 bbls in case differentially stuck, still stuck. Fill annulus back up, rotate to the right with minimal torque, pull 250k to attempt to part 4" inner string, no luck. Uncontrolled back-off by rotate to left while pulling 20k over & pipe pulled free (26k less wt), POH to 3700', spot 17 bbl HEC pill, losses at 11 bph, POOH, UD some fish- recovered packer setting tool and 3 out of 8 seal sections in 4" inner string and recovered all of 2-7/8" inner string, top of fish at 3136' . 12/14/03 MV fishing BHA # 1 overshot of 4.75" seal assy. RllI check torque on connx's, work over fish at 3136', attempt to tighten connections with rt hand torque, pulled free with 46k overpull. POOH slow w/6K extra wt, Remove fish flgrapple, LID 624.3' fish which was remaining 5 seals from upper seal section, 13 jts of 4" inner string, 41' of mini-beta assy including ball sub restriction, bottom of recovered fish was a 2-7/8" EVE collar in good shape. 2-7/8" EUE pin looking up on fish remaining in hole. PV/MU BHA #2 with 2-7/8" EVE cut lip collar on bottom to screw on to fish and jars. RIH to TOF @ 3761', engage fish with 10 right hand turns then 5 more rt hand turns. Start pumping with 500 psi then pressure broke back. Jar free, POOH, pulled tite at 3630' TOF/4214' bottom of fish, pull tite again at 3308' TOF/bottom of fish at 3890' . 12/15/03 POOH wI fish while eirc, jar seals through SB area at 3758', pull fish above packer to 3709', monitor hole losses at 13 bph, eirc, POOH w/entire fish. Test BOPE, losses at 13 bph. Run snap latch, one jt 5-1/2" tbg, 5-1/2" X nipple with PX plug in place, and PBR on drill pipe. Snap into packer at 3764', pressure test annulus to 2000 psi and plug to 1500 psi, OK. B-1 daily summary 12-19-03.doc 3 I ~. ,( 12/16/03 PU to shear pins from seals to PBR, POOH LD DP, Pull Wear bushing, strap tubing & jewelery, PU & RIH wI 5-1/2" tubing, three 5-1/2" GLMs with dummies, 5-1/2" TRSSSV. 12/17/03 Space out tubing, circ, land tbg, test ann to 2000 psi, test tbg to 1000 psi, install two way check, Pull rotary table, N/D BOPE, NU Vetco gray tree, test void to 5000 psi, test tree to 5000 psi, RU Pollard WL, RIH wI GS & catcher sub. 12/18/03 Set basket on top of plug at 3658'. POOH wI slickline, attempt to pull dummy valve in GLM #3 @ 3601' three trys- no good, Run Lffi, valve in pocket, try 4th time-no good. Try to pull dummy in station # 2, retrieved after second run, install 5/16" orifice in # 2 GLM. 12/19/03 Slickline pulled basket, pulled prong fl PX plug, pulled plug from 5-1/2' X nipple at 3700'. RIH wI 3.22" centralizer & wt bar to pass KOIV @ 3796'- nothing seen, con't to lower KOIV- tagged @ 5427' Pollard WLM (5478' elm)- 169' high of 2nd KOIV at 5647' elm, POOH, RID WL. Release rig from Well B-01a at 10:00 on 12/19/03. Move rig to A-13. B-1 daily summary 12-19-03.doc 4 8PHILLlPS Alasl " Inc., .~ ASUbsidiaryofPHILLIPSPETRO\ ,v1COMPANY As Run 12/16/03 ( B-1 A Well Name: North Cook Inlet Unit-B-1A 30" @ 407' MD (430" TVD) Spud Date: 7/31/97 amco 5-1/2" SSSV @ 410' Sidetrack Date: 2/5/98 Schematic Update: Billingsley 12/18/03 5-1/2" GLM at 1559' with dummy, RK latch Casina DeDth Grade Weiaht 30" 407' 5-1/2" GLM @ 2675' w/5/16" orifice/RK latch 20" 2579' K-55 133# 13-3/8" 3760' N-80 72# 20" @ 2579' MD (2571' TVD) 9-5/8" 10376' P-110 53.5# 2-3/8" Injection Strings for 5"DP 16650' S-135 19.5# top=10074' Sterling Disposal zone 13-3/8" @ 3760' MD Tba DeDth Grade Weiaht 5-1/2" 3764' L-80 15.5#, cs buttress 5-1/2" GLM at 3602' w/dummy and RK latch IQQ Lenath Item 53.6' l' 10-3/4" x 5-1/2" Vetco tbg hgr, 15' PBR on top of pkr 5-1/2" BTC btm and top 5-1/2" "X" nipple, 4.562' ID @ 3700' 5-1/2" tbg, L-80, 15.5# R2, BTC mod Baker SC-1 R Pkr @ 3764' (6.00" ID) 410' Cameo 5-1/2" SSSV TRM-4E w/4.562. X 5"x7"KOIV@3797' 1559' dummy Camc05-1/2.x1-1/2" MMGGLM 4 zones: 3850'-3869', 3886'-3893'. 2675' 5/16' orifice Camco 5-1/2"x1-1/2" MMG GLM 4185'-4268', 4275'-4365' 3602' dummy Cameo 5-1 /2.x 1-1/2" MMG G LM one jt 5-1/2" tbg, L-80, 15.5# R2, BTC mod 9-5/8" SC-1L @ 4368' 3671' Baker PBR/seals, 7.0" OD x 4.875. ID 4 zones: 4429'-4480', 4751'-4761' 3700' 5-1/2. "X" nipple 4792'-4803',4922'-4955' one jt 5-1/2. tbg, L-80, 15.5# R2, BTC mod 9-5/8" SC-1R Sump Pkr @ 4969' (6,00" ID) 3764' Baker 5-1/2" x 9-5/8. SC-1 R pkr assy 5-1/2" SLHT blank 3797' 7" x 5" KOIV 4-1/2" X nipple profile, 3.813" @ 5579' 5-1/2" 15.5# SLHT blank & screens. 9-5/8" SC-2 @ 5613' (4.75" ID) 4368' Baker SC-1 L pkr assy 5" x 3-1/2" KOIV at 5647' 5-1/2" 15.5# SLHT blank & screens.. 4" screens and blanks 4969' Baker SC-1 R Sump pkr #2 assy 14 zones perted: 5718'-5742', 5885'-5892' 5-1/2" 15.5# L-80 SLHT blank tbg 5929'-5939',5948'-5969',5995'-6032', 5547' Xover, 5-1/2" SLHT x 4-1/2. IBT 6078'-6091',6097'-6107',6118'-6124', one jt of 4-1/2. IBT 6148'-6158',6169'-6182',6283'-6290', 5579' 4-1/2" X nipple, 3.813. profile 6375'-6390',6610'-6622',6762'-6767' 1 jt of 4-1/2. IBT w/S-22 4.75. snap latch S-22 Snap Latch 5613' Baker 4. x 9-5/8" SC-2 pkr assy, 4.75" ID 9-5/8" SC-1R Sump Packer @ 6787' 5647' 5" x 3-1/2" KOIV 5-1/2" x 3-1/2" crossover 4. SLHT screen and blank 3-1/2" X nipple at 6836' 6786' Baker S-22 Snap Latch 3-1/2" WLEG at 6867' 6787' Baker SC-1 R sump packer Actual 4-1/2" tbg cut @ 8052' on 11/22/03 6805' 3-1/2" x 5-1/2" xover 9/29/02 Tag TOC at 9610' in tbg 6836' 3-1/2" tbg, 3-1/2" X nipple, 2.813. profile 4,5",12.75 ppf, P-110 Tubing 6867' 3-1/2" WLEG tbg tail Calc TOC in tbg x 9-5/8" @ 9837' PERFS @ 9970'-9972' 4 SPF . and .. 9' long x 5-1/2. Braden blanks w/RA collars PKR @10,074 MD (8846' TVD) @ 4016', 4609' and 4881' Sliding Sleeve @ 10032'MD(8598'TVD) WELL HISTORY: Feb. 5, 1998 - Sidetrack PXN Plug in Nipple, 9-5/8' @ 10376' MD (8846' TVD) Nov. 26, 2001 - Set 3.813. PXN Plug in XN Nipple. 3.125 Fishneck. XN Nipple is 3.725. NoGo w/3.813. packing bore. Sept. 25, 2002 - PERF from 9970' 9972' RKB, 4 spf w/2' PERF gun in prep for P&A 5",19.5 ppf, S-135 Drill Pipe with G' Tool Joints (min. ID: 3.25") Sept 27, 2002 - Cement tubing & casing, cement in annulus @ 9937' (est.); PXN Plug in Nipple @ 10,073' N. Forlands PERFs @ 16080'-16118' MD Junk & fill on top of PXN plug top @ 10,010' Sept 29,2002 - Tag TOC @ 9610' CMT in DP @ 16590' MD 12/18/2003 Unable to pull dummy @ 3602', set orif @ 2675' 5" DP @ 16650' MD 12/19/2003 Tag top of CaC03 w/wt bar @ 5478'=169' above KOIV I I ConocoPhillips Post Office Box 100360 Anchorage, Alaska 99510-0360 Paul Mazzolini Phone (907) 263-4603 Fax: (907) 265-1535 Emaih pmazzol@conocophillips.com May 2,2003 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 279-1433 Re: Sundry Application to Recomplete, NCIU Well #B-lA, Tyonek Platform, Cook Inlet Dear Commissioner: ConocoPhillips Alaska, Inc. hereby applies to r~-enter a suspended_,.well, NCIU B-lA, and recomplete as a gas well in the Cook Inlet and Beluga Sands. Attached for your review is Sundry Application. Estimated start date is August 1, 2003. Well B-lA was drilled in 1998 as a Tyonek deep exploration well. The B-lA wellbore was suspended on 9/27/02 with a cement plug laid in the 4-1/2" tubing and the 4-1/2" x 9-5/8" annulus via coil tubing. The top of cement was tagged in the 4-1/2" tubing at 9610' on 9/29/02 and the tubing plug was pressure tested to 2500 psi on 9/30/02. A 10-407 completion report was filed with AOGCC on 10/24/02 to suspend B-lA. The proposed recompletion will cut the tubing at 6400' and install a multi-zone gravel pack completion in the Beluga and Cook Inlet sands-from 3~54' to~--C2'8-~--f~e Propose u ~ng a~ w~ tubing stub to connect the well to the existing deep casing strings in case the Tyonek deep zones are deemed economically viable in the future. If you have any questions or require any further information, please contact Tim Billingsley at 265-6531 or myself at 263-4603. Sincerely, Paul Mazzolini Cook Inlet Drilling Team Leader RECEIVED MAY 0 6 200.3 Alaska Oil & Gas Cons. Commission Anchorage ;ANNE~ ~AY 1 ~ 2003 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 1. Type of Request: Abandon Alter casing Change approved program Suspend El Operational shutdown El Perforate Repair well E] Plug Perforations E~ Stimulate Pull Tubing [-~ Perforate New Pool ]-~ Variance E~ Annular Dispos. El Time Extension El Other [] Re-enter Suspended Well r~ 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: P. O. Box 100360, Anchorage, AK 99510 4. Current Well Class: Development [-~ Exploratory El Stratigraphic El Service r--] 5. Permit to Drill/Number: V 98-02/302-310 6. APl Number: 50-883-20093-01 ~' 7. KB Elevation (ft): 132' RKB 8. Property Designation: ADL 17589, North Cook Inlet Unit 9. Well Name and Number: NCIU B-lA lO. Field/Pools(s): North Cook Inlet Field/Tyonek Deep Pool 11. Total Depth MD (ft),,;,,,- 16720' Casing PRESENT WELL CONDITION SUMMARY Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): N/A Total Depth TVD(~ 12942' Length 368' 2579' 3760' 10376' 6576' Effective Depth MD (ft): 16590' Size 30" 20" 13.375" 9.625" 5" drill pipe Effective Depth TVD (ft): 12854' MD 407' 2579' 3760' 10376' 16650' Perforation Depth TVD (ft): N/A Plugs (measured) 9610' TVD 407' 2511' 3514' 8840' 12887' Tubing Size: N/A Junk (measured): Burst Tubing Grade: N/A Collapse Tubing MD (ft): N/A Packers and SSSV Type: HES TRSSV, Liner top packer 12. Attachments: Description Summary of Proposal ['~ Detailed Operations Program [~ BOP Sketch 14. Estimated Date for Commencing Operations: 8/1/2003 16. Verbal Approval: Commission Representative: Date: Packers and SSSV MD (ft): pkr @ 10074', TRSV @ 430' 13. Well Class after proposed work: Exploratory r-1 Development r'~ 15. Well Status after proposed work: Oil El Gas ~-~ Plugged WAG El GINJ r--] WINJ r-"] Service Abandoned r-] WDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Signature Paul Mazzolini Title Cook Inlet Drilling Team Leader Phone 263-4603 COMMISSION USE ONLY Tim Billinqsley 265-6531 Date Conditions of approval: Notify Commission so that a representative may witness Plug Integrity r-] BOP Test ~ Mechanical Integrity Test El Subsequent Form Required: ~% Approved by: Location Clearance [--] Sundry Number: RECEIVED MAY 0 6 200,3 .~,~a~ :~;Alaska 0il & Gas Cons. Commission ,~,,~, ...... .....- J~ichorage BY ORDER OF THE COMMISSION Date: · Form 10-403 Revised 2/2003 ' " NNED' [~Y t ~ 2003 SUBMIT IN DUPLICATE B-01A Proposed Gravel Pack Workover Operation I Move Rig from B-3 2 ND tree, NU and test BOPE to 3000 psi 3 Run e-line chemical cutter, cut 4-1/2" 12.75# tbg @ 6400' 4 Pull & lay down 6400' of 4-1/2" tubing 5 RU E-line for Cased Hole Dynamics Tester 6 RIH w/E-line and tag tbg stub at 6400', (correlate depth of stub) 7 Run CHDT pressure/sample stops and POOH, 2 runs with 5 drillholes each 8 ND BOPE. Repalce damaged tbg head with new tb-g-h~.'~' ........ 9 NU and test BOPE 10 RIH with tbg stub overshot/sump pkr on drill pipe 11 Stab over stub and set lowest sump packer at 6300' 12 POOH with drill pipe and packer setting tool 13 MU and RIH w/TCP guns 14 Tag packer at 6300' with btm of guns, set plug in packer, PU to place guns on depth 15 Apply tbg pressure to fire guns at~ 16 Pump LCM pill if necessary, POOH & LD spent guns 17 RIH with Cavins bailer on drill pipe. 18 Bail perf debris from top of plug at 6300', engage and pull plug from packer 19 POOH and lay down Cavin bailer and plug 20 Run Gravel Pack assembly incl inner string 21 Pump two Gravel Packs 22 POOH with DP and inner String 23 Run 3800' of 5-1/2" completion tbg and SSSV 24 Stab into t~p packer at 3800 ,--"0~and pump packer fluid 25 Space out and Land hanger :26 ND BOP / NU Tree 27 Pressure up tbg to knock out KOIV 28 Demob rig from Tyonek platform. Tim Billingsley B-1 Sundry procedure.xls PHILLIPS Al{ .ska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY 30" @ 407' MD (430" TVD) @ 430' MD (430' TVD) Current B-lA IWell Name: North Cook Inlet Unit-B 00001 Spud Date: 7/31/97 Sidetrack Date: 2/5/98 Schematic Update: Osborn 10/26/2002 20" @ 2579' MD (2571' TVD) 2-3/8" Injection Strings for Sterling Disposal zone 13-3/8" @ 3760' MD (3521' TVD) ~TOC at 9610' in tbg 4.5", 12.75 ppf, P-110 Tubing Calc TOC in tbg x 9-5/8" @ 9937' PERFS @ 9970'-9972' 4 SPF @10,074 MD (8846' TVD) Sliding Sleeve @ 10032' MD (8598' TVD) PXN Plug in Nipple, 9-5/8" @ 10376' MD (8846' TVD) 19.5 ppf, S-135 Drill Pipe with G' Tool Joints (min. ID: 3.25") IWELL HISTORY: Feb. 5, 1998 - Sidetrack Nov. 26, 2001 - Set 3.813" PXN Plug in XN Nipple. 3.125 Fishneck. XN Nipple is 3.725" NoGo w/3.813" packing bore. Sept. 25, 2002 - PERF from 9970' 9972' RKB, 4 spf w/2' PERF gun in prep for P&A Sept 27, 2002 - Cement tubing & casing, cement in annulus @ 9937' (est.); PXN Plug in Nipple @ 10,073' Junk & fill on top of PXN plug top @ 10,010' Sept 29, 2002 - Tag TOC @ 9610' N. Forlands PERFs @ 16080'-16118' MD CMT in DP @ 16590' MD 5" DP @ 16650' MD PHILLIPS Ala i .a, Inc. Subsidiary ol= PHILLIPS PETROLEUM COMPANY 30' @ 407' MD (430' TVD) @ 430' Proposed IWell Name: North Cook Inlet Unit-B-IA Spud Date: 7/31/97 Sidetrack Date: 2/5/98 Schematic Update: Billingsley 5/2/03 B-lA I I I I I I I I I I I I I I I I I I 5-1/2' GLM at 1700' 5-1/2" GLM at 2700' 20" @ 2579' MD (2571' TVD) 2-3/8" Injection Strings for Sterling Disposal zone 13-3/8" @ 3760' MD (3521' TVD) 5-1/2" GLM at 3700' 5-1/2" sliding sleeve @ 3750' 15' PBR on top of pkr Baker SC-IR Pkr @ 3774' with 5" x 7" KOIV 3854'-3867' 3968'-4118' 4190'-4260' 4278'-4356' 4434'-4474' 9-5/8" SC-1L @ 4484' 9-5/8" SC-1L 65673' 5732'-5738' 5886'-5889' 5934'-5937' 5956'-5966' 6010'-6015' 6285'-6288' S-22 Snap Latch 9-5/8" SC-1R Sump Packer @ 6293' 4-1/2" Baker poor boy overshot @ 6400' Tag TOC in 4-1/2" @ 9610' 9/29/02 12.75 ppf, P-110 Tubing in tbg x 9-5/8" @ 9937' PERFS @ 9970'-9972' 4 SPF @10,074 MD (8846' TVD) Sliding Sleeve @ 10032' MD (8598' TVD) g In Nipple, 9-5/8' @ 10376' MD (8846' TVD) Casin.q Depth Grade Weight 30" 407' 20" 2579' K-55 133# 13-3/8" 3760' N-80 72# 9-5/8" 10376' P-110 53.5# 5" DP 16650' S-135 19.5# top=10074' I Tba ~ProD) Depth Grade 5-1/2', 3774' L-SO Weiqht 15.5#, cs~ buttress Top Len.qth 39' 1' 40' 429' 430' 5' 435' 1265' 1700' 6' 1706' 994' 2700' 6' 2706' 994' 3700' 6' 3706' 44' 3750' 5' 3755' 15' 3774' 4484' 5673' 6293' 6400' 46' 629' 1163' 30' 564' Item 10-3/4" x 5-1/2" Vetco tbg hgr, 5-1/2" BTC btm and top 5-1/2" tbg, L-80, 15.5# R2, BTC mod Camco 5-1/2" SSSV TRM-4E 4.562" 5-1/2" tbg, L-80, 15.5# R2, BTC mod Camco 5-1/2"x1-1/2" MMG GLM 5-1/2" tbg, L-80, 15.5# R2, BTC mod Camco 5-1/2"x1-1/2" MMG GLM 5-1/2" tbg, L-80, 15.5# R2, BTC mod Camco 5-1/2"x1-1/2" MMG GLM 5-1/2" tbg, L-80, 15.5# R2, BTC mod Baker 5-1/2" CMU sliding sleeve Baker PBR/S22 Anchor Baker 5-1/2" x 9-5/8" SC-1R pkr assy 7" x 5" KOIV 5-1/2" 15.5# L-80 SLHT blank tbg 5-1/2" Bakerweld screen, .012" gauge Baker SC-1L pkr assy 5-1/2" 15.5# L-80 SLHT blank tbg Baker SC-1 L pkr assy 5-1/2" 15.5# L-80 SLHT blank tbg 5-1/2" Bakerweld screen, .012" gauge Baker S-22 Snap Latch Baker SC-1 R sump packer 5-1/2" tbg, L-80, 15.5# R2, BTC mod Baker poor boy overshot, 4-1/2" tb~l stub 19.5 ppf, S-135 Drill Pipe with G' Tool Joints (min. ID: 3.25") N. Forlands PERFs @ 16080'-16118' MD CMTin DP @ 16590' MD 5" DP @ 16650' MD WELL Feb. 5, 1998 - Sidetrack Sept. 25, 2002 - PERF from 9970' 9972' RKB, 4 spf w/2' PERF gun in prep for P&A Sept 27, 2002 - Cement tubing & casing, cement in annulus @ 9937' (est.); P. XN_Plu. g in Nipple @ 10,073' $CANNED:~ ~AY .TL ~ 2003 13.400 Kill Line Inlet 3" 5,000 PS! 1 I 5/8" Annular 45" I I I I 13 5/8" Double Gate 34" 9.800 Choke Line Outlet 1 3" 5,000 PSI Mud Cross 20" 3 5/8" Single Gate18" 13 5/8" 5,000 PSI Shaffer BOP Stack Kuukpik Drilling Rig 5 To Shaker 3" Panic To Gasbuster I I Manual Choke AutomatiC Choke Inlet 3" 5,000 PSI Choke Manifold Kuu,kpik Drilling Rig 5 P LLIPS Alaska ol n ; A Subsidiary of PHILLIPS PETROLEUM Post Office Box 100360 Anchorage, Alaska 99510-0360 A. Worthington Phone (907) 265-6802 Fax: (907) 265-6224 October 23, 2002 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Report for NCIU B-01A (198-02 / 302-310) Dear Commissioner: Phillips Alaska, Inc. submits the attached Well Completion Report for the recent P&A operations on the Tyonek well NCIU B-01A. If there are any questions, please contact me at 907-265-6802. Sincerely, A. Worthington Wells Engineer Phillips Alaska Inc. AW/skad RECEIVED OCT 2 9 2002 ,~aslm 01t & Gas Cons. Commission Anchorage i STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of well Classification of Service Well Oil E~] Gas ~] Suspended [-~ Abandoned [~ Service [~ 2. Name of Operator 7. Permit Number ConocoPhillips Alaska, Inc. 198-02 / 302-310 3. Address 8. APl Number P. O. Box 100360, Anchorage, AK 99510-0360 50-883-20093-01 4. Location of well at surface ....................... ,,., 9. Unit or Lease Name 1249' FNL, 980' FWL, Sec. 6, T11N, R9W, SM '. '.:'~ ..';~.. ~'i .~."..;. ~ ~ '~ North Cook Inlet Unit ,r: 10. Well Number ~ ~ ................. ~ ~ B-lA .~, ~"~ ~: ~ ~ 11. Field and Pool ~~ Depth i ~ ~ ............ ~ ~ FSL, ~FEL, Sec. 12, T11 N, ~SM ~. ............ .,~. Cook Inlet Field 5. Elevation in feet (in,cate KB, DF, etc.) ~ ~6. Lease Designation and Serial No. Beluga Pool RKB 132' feet~ ADL 17589 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. Or Aband. ~15. Water Depth, if offshore 16. No. of Completions Februa~ 12, 1998 April 2, 1998 December 1, 1998~ N/A feet MSL 1 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Su~ey ~20. Depth where SSSV set 21. Thickness of Permafrost 16720' MD / 12942' TVD 10042' MD YES ~ No ~'ITRSV ~ '430' N/A 22. Type Electric or Other Logs Run 23. CASING, LINER AND CEMENTING RECORD SE~ING DEPTH MD CASING SIZE WT. PER ~. GRADE TOP BO~OM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 30" Su~ace 407' Driven 20" 133~ K-55 Su~ace 2579' 24" 1690 sx Class G, 700 sx Tail 13-3/8" 72~ N-80 Su~ace 3760" 18.5" 1234 sx Class G, 672 sx tail 9-5/8" 53.5~ P-110 Surface 10376' 12.25" 2400 sx lead, 704 sx tail 5" 19.5~ S-135 Su~ace 16650' 8.5" 700 sx Class G PXN plug ~ 10042' 24. Perorations open to Production (MD + TVD of Top and Bottom and 25. TUBING RECORD inte~al, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 4.5" 10074' 10074' all pe~s P&A'd 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 9610'- 9970' 13.8 bbls Class G 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) not applicable P&A Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE IGAS-OIL RATIO I N/A Test Period > Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY - APl (cor0 press, psi 24-Hour Rate > 28. CORE DATA Brief description of lithology, porosi~, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. N/A ~~ 0U 2 9:2002 ~ ~~'5 ~' ~ ~ ~ N~ 0it & AnchomgeG~ ~ns. Commi~ion Form 10-407 Rev. 7-1-80 ,SCANNED NOV 0 5 2002 CONTINUED ON REVERSE SIDE Submit in duplicate / GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity. MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. N/A ' REEEIVE, I) OCT 2 9:2002 31. LIST OF ATTACHMENTS Summary of Daily Operations 32. I hereby certify that the following is true and correct to the best of my knowledge. Questions? Call Aras Worthington 265-6802 Signed ~ Title Wells E nqineer Date ,~1~_~ ~~ INSTRUCTIONS Prepared by Sharon Al~sup-Drake General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 CANNEID NOV 0,5 2002 Date Comment Event History 09/12/O2 09/25/02 09/26/02 09/27/02 09/29/02 09/30/02 SERVICE TREE VALVES FOR P&A WORK RIH WITH GAUGE RING TO 9977' SLM (10010' RKB). UNABLE TO GET TO PRONG ON PXN PLUG, ESTIMATE 61' ABOVE PRONG. PERFORATE FROM 9970' RKB - 9971' RKB, 4 SPF 60 DEGREE PHASED. RIH AND CIRCULATE BOTTOMS UP VOLUME OF 850 BBLS FRESHWATER. CIRCULATED 840 BBLS WATER DOWN TBG AND UP CASING TO REMOVE GAS - PUMPED 13.8 BBLS CLASS G CEMENT W/7 BBLS IN CASING (137') AND 6.8 BBLS (447') IN TUBING FROM 9970' - CLEANED OUT TBG FROM 8800' AND FREEZE PROTECTED WELL WITH 500' DIESEL CAP ON TBG AND CASING - READY FOR DRAWDOWN AND PRESSURE TEST AFTER CEMENT CURES TAGGED CEMENT IN TUBING @ 9610' WLM W/2.625" GAUGE RING - CEMENT TOP AT CORRECT DEPTH - READY FOR PRESSURE TEST/DRAWDOWN & AOGCC WITNESS. PRESSURE TESTED TUBING TO 2500 PSI - PRESSURE TESTED CASING TO 2500 PSI - DRAWDOWN TUBING AND CASING TO ZERO PSI - CEMENT JOB ON B-1 PASSED PRE-AOGCC WITNESSED TEST CANNEU NOV 0 5 2002 Page 1 of I 10/22/2002 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 A. Worthington Phone (907) 265-6802 Fax: (907) 265-6224 October 16, 2002 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations NCIU B-01A (198-02 / 302-310) Dear Commissioner: Phillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent operations on the Tyonek well NCIU B-01A. If there are any questions, please contact me at 907-265-6802. Sincerely, A. Worthington Wells Engineer Phillips Alaska Inc. AW/skad RECEIVED OCT 1 7 2002 ~aska OiL& Gas I~n9. ~lltlltls~ior, Anchorage STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate_ Plugging _ Perforate_ Pull tubing _ Alter casing _ Repair well _ Other _XX P&A 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchora~le, AK 99510-0360 4. Location of well at surface 1249' FNL, 980' FWL Sec. 6 T11 N, R9W At top of productive interval At effective depth At total depth 2513' FSL, 1520' FEL, Sec 12, T11 N, R9W 5. Type of Well: Development _X Exploratory __ Stratigraphic _ Service__ 6. Datum elevation (DF or KB feet) RKB 132 feet 7. Unit or Property name North Cook Inlet 8. Well number NCIU B-lA 9. Permit number / approval number 198-02 / 302-310 10. APl number 50-883-20093-01 11. Field / Pool North Cook Inlet Field Development 12. Present well condition summary Total depth: measured true vertical 16720 12942 9610 8220 Size 30" 20" 13-3/8" 9-5/8" 5" Effective depth: measured true vertical Casing Length Structural 368' Conductor 2579' Surface 3760' Intermediate 10376' Liner 6576' Perforation depth: measured 16080' - 16118' true vertical 12524' - 12547' Tubing (size, grade, and measured depth) 4-1/2" P-110 @ 10074' Packers & SSSV (type & measured depth) Pkr @ 10074' MD HES TRSV @ 430' MD. feet Plugs (measured) feet feet Junk (measured) feet Cemented Driven 1690 sx lead, 700 sx tail 1234 sx lead, 672 sx tail 2400 sx lead, 704 sx tail 700 sx G 13. Stimulation or cement squeeze summary Intervals treated (measured) N/A Treatment description including volumes used and final pressure Cement plug 9610' - 10042' PXN plug @ 10042' Measured Depth True vertical Depth 407' 407' 2579' 2511' 3760' 3514' 10376' 8840' 16650' 12887' RECEIVEO OCT 17 2002 Anchorage 14. Prior to well operation Subsequent to operation OiI-Bbl Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl N/A Casing Pressure Tubing Pressure 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations Oil m Gas _ Suspended Service _Water Injector 17. I hereby certify that the foregojJ;~g, is tqj,e and correct to the best of my knowledge. Signed ~ '~"~~-~~~ Title: Wells Team Leader Mike Mooned, ~. ~ //~/~'?'i/// /';',~; ~"~') Questions? Call Aras Worthington (907) 265-6802 Date / ('~! "/~ ~ Prepared b~/ Sharon AIIsup. Drake 263-4612 Form 10-404 Rev 06/15/88 · SUBMIT IN DUPLICATE Date Comment NCI B-1 Event History 09/12/O2 09/25/02 09/26/02 O9/27/02 09/29/02 09/30/02 SERVICE TREE VALVES FOR P&A WORK RIH WITH GAUGE RING TO 9977' SLM (10010' RKB). UNABLE TO GET TO PRONG ON PXN PLUG, ESTIMATE 61' ABOVE PRONG. PERFORATE FROM 9970' RKB - 9971' RKB, 4 SPF 60 DEGREE PHASED. RIH AND CIRCULATE BOTTOMS UP VOLUME OF 850 BBLS FRESHWATER. CIRCULATED 840 BBLS WATER DOWN TBG AND UP CASING TO REMOVE GAS - PUMPED 13.8 BBLS CLASS G CEMENT W/7 BBLS IN CASING (137') AND 6.8 BBLS (447') IN TUBING FROM 9970'- CLEANED OUT TBG FROM 8800' AND FREEZE PROTECTED WELL WITH 500' DIESEL CAP ON TBG AND CASING - READY FOR DRAWDOWN AND PRESSURE TEST AFTER CEMENT CURES TAGGED CEMENT IN TUBING @ 9610' WLM W/2.625" GAUGE RING - CEMENT TOP AT CORRECT DEPTH - READY FOR PRESSURE TEST/DRAWDOWN & AOGCC WITNESS. PRESSURE TESTED TUBING TO 2500 PSI - PRESSURE TESTED CASING TO 2500 PSI - DRAWDOWN TUBING AND CASING TO ZERO PSI - CEMENT JOB ON B-1 PASSED PRE-AOGCC WITNESSED TEST Page I of I 10/16/2002 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Camille Taylor, ~ ~ DATE: Commissioner Tom Maunder, /~.~_~~~ P. I. Supervisor t~ - THRU: October 11, 2002 FROM: John Spaulding, SUBJECT: Petroleum Inspector Plug 'and Abandonments PAl Tyonek Platform Wells .No.n Confidential October ..1!,. 2002: i traveled to PAl's Tyonek platform to witness the plug and abandonments of the bottom hole locations in preparation for eventual sidetracking and workoVers of the following wells. In previous conversations PAl's rep. Jack Kralik asked how much preSsure I wanted to see on the well upon my arrival, I requested that 500psi or at a mina positive pressure be displayed. All well were in the near area of 500psi. A-lO was pressured from 500 psi to 1150 psi and held for 30 min. with no bleed down. The well was then de pressured to 0 psi and observed for 15 min. with no build up. A,'~ ]'~was pressured up from 500 psi to 1100 psi and held for 30 min with no bleed down. The well was then de pressured to 0 psi and observed for 15 min. with no build up. ' ~was pressured up from 420 psi to 2200 psi and held for 30 min. with no bleed ~down. The well was then de pressured to 0 psi and observed for 15 min. with no build up. ;B~2: was pressured up from 500 psi to 2400 psi and held for 30 min. with no bleed down. The well was then de pressured to o psi and observed for 15 min, with no build up. SUMMARY: I. Witnessed:4, successful plug and abandonment. Pressure tests. Attachments: None P&A's Tyonek Plat 10-tl-02js.doc PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 A. Worthington Phone (907) 265-6802 Fax: (907) 265-6224 September 25, 2002 Ms. Cammy Oechsli Taylor Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501 Subject: NCIU B-01A Application for Sundry Approval Dear Commissioner: Phillips Alaska, Inc. hereby files this Application for Sundry Approval for a change of plans in the P&A operations of the Cook Inlet NCIU B-01A well. If you have any questions regarding this matter, please contact me at 265-6802. Sincerely, Wells Engineer AW/skad SCANNED OCT 0~ 2002 RECEIVED SEP 2 5' 2002 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon_XX Suspend_ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program _XX Pull tubing _ Variance _ Perforate _ 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 5. Type of Well: Development Exploratory __ Stratigraphic __ Other _ 6. Datum elevation (DF or KB feet) RKB 132 feet 7. Unit or Property name Anchorage, AK 99510-0360 4. Location of well at surface 1249' FNL, 980' FWL Sec. 6 T11N, RDW At top of productive interval Service__ At effective depth At total depth 2513' FSL, 1520' FEL, Sec 12, T11 N, RDW North Cook Inlet 8. Well number NCIU B-lA 9. Permit number / approval number 198-02 10. APl number 50-883-20093-01 11. Field / Pool North Cook Inlet Field Development 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Structural 368' Conductor 2579' Surface 3760' Intermediate 10376' Liner 6576' Size 30" 20" 13-3/8" 9-5/8" 5" 16720 12942 16590 12854 feet Plugs (measured) PXN plug to 10042' feet feet Junk (measured) feet Cemented Measured Depth Driven 407' 1690 sx lead, 700 sx tail 2579' 1234 sx lead, 672 sx tail 3760' 2400 sx lead, 704 sx tail 10376' 700 sx G 16650' True vertical Depth 407' 2511' 3514' 8840' 12887' Perforation depth: measured 16080' - 16118' true vertical 12524' - 12547' Tubing (size, grade, and measured depth Packers & SSSV (type & measured depth) 4-1/2" P-110 @ 10074' Pkr @ 10074' MD HES TRSV @ 430 ' MD. 13. Attachments Description summary of proposal _X Detailed operations program _ BOP sketch _ 14. Estimated date for commencing operation I 15. Status of well classification as: September 25, 2002 I: 16. If pr,op,osal,was v~rbally approved / / 0il Name of approver Date approved Service 17. I hereby certify that the foregoing is true .a~d corr,~ ct to the best of my knowledge. Signed ~.~~.~~~ Title: Wells Team Leader Mike Moone)~ ~v~~ FOR COMMISSION USE ONLY Gas __ Suspended _XX Questions? Call Aras Worthington (907) 265-6802 Date ~"' ~"~" "'~ ~" Prepared by Sharon AIIsup-D~ake 263.4612 Conditions of approval: Notify Commission so represent~a~ive may witness I Plug integrity __ BQP Test _~, Location clearance __ Mechanical Integrity Test_ Subsequent form required 10- ~77 j~,~ ~.- I Approved by order of the Commission ORIGINAL SIGNED BY D 'Taylor Seamount Commissioner Approval Date SCANNED OCT 0 & 200Z Form 10-403 Rev 06/15/88 · SUBMIT IN TRIPLICATE NCIU B-lA Intended P&A for Completion as a Gas Well Objective: Plug and abandon all perforated zones in the well for re-completion as a gas well. Intended Procedure: o ° o , Pressure test & drawdown test the Tbg-Tail Plug (TTP) set in 4 1/2" tail-pipe. Rig up SL & Test BOPE to 3000 psi. Shift Sliding Sleeve immediately above the packer to open position or shoot holes in the tbg immediately above the packer. Rig up CTU & Test BOPE to 3000 psi. RIH w/CT & circulate 100' of cement into the 4 IA" x 9 5/8" annulus. Lay 100' of cement in the tbg on top of the tbg-tail plug. Pressure-test & drawdown test the cement plug. MIRU Drilling rig. Pull tbg. Perforate well & run gas completion. Note: This P&A procedure represents a deviation from the original P&A procedure; which proposed laying a cement plug in the drillpipe liner. The original plan has become impractical due to extreme difficulties in pulling the tbg-tail plug in the 4 IA" tbg. ,SCANNED OCT 04 2002 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon_XX Suspend_ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program _ Pull tubing _ Variance _ Perforate _ Other _ 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 ~,' 4. Location of well at surface v/' ~/ ''/' 1249' FNL, 980' FWL Sec. 6 T11 N, R9W At top of productive interval At effective depth At total depth 2513' FSL, 1520' FEL, Sec 12, T11 N, R9W 5. Type of Well: Development Exploratory _ Stratigraphic __ Service_ 6. Datum elevation (DF or KB feet) RKB 132 feet 7. Unit or Property name North Cook Inlet 8. Well number NCIU B-lA 9. Permit number/~ppproval number 198-02 ~/ 10. APl number ~ 50-883-20093-01 11. Field / Pool North Cook Inlet Field Development 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing. Length Structural 368' Conductor 2579' Surface 3760' Intermediate 10376' Liner 6576' Size 30" 20" 13-3/8" 9-5/8" 5" 16720 12942 16590 12854 feet Plugs (measured) PXN plug to 10042' feet ''/ feet Junk (measured) feet Cemented Measured Depth Driven 407' ' 1690 sx lead, 700 sx tail 2579' 1234 sx lead, 672 sx tail 3760' 2400 sx lead, 704 sx tail 10376' 700 sx G 16650' True vertical Depth 407' 2511' 3514' 8840' 12887' Perforation depth: measured true vertical Tubing (size, grade, and measured depth Packers & SSSV (type & measured depth) 16080' - 16118' 12524' - 12547' 4-1/2" P-110 @ 10074' Pkr @ 10074' MD HES TRSV @ 430 ' MD. JUL 2 5 2002 Alaska 0il & Gas 00ns. C0rmmss~ol Anchora0e 13. Attachments Description summary of proposal _X Detailed operations program __ BOP sketch _ 14. Estimated date for commencing operation 15. Status of well classification as: August 1, 2002 16. If proposal was verbally approved Oil __ Name of approver Date approved Service 17. I hereby certify that the foregoes tru~a, an~,~ best of my knowledge. Signed ~ ~~" Title: '~-ffs'-T'eawr~a~der FOR COMMISSION USE ONLY Gas _ Suspended _XX Questions? Call Aras Worthington (907) 265-6802 Date Prepared b,v Sharon AIIsup-Drake 263-4612 Conditions of approval: Notify Commission so represen.tat~ve may witness 'S(~(.~.~ ~ ~, ~-2>C3~ ~-.+~I~ Approval-~n°~o Plug integri~ BOP Test ~ Location clearance __ Mechanical Integri~ Test_ ~ubsequent form required 10- ~ ~gmal S~gn~ By Commissioner Date ~[~ Approved by order of the Commission ~ ............ ~"'"'", ~,~,, ,ay,o,' SCANNED AUG ! 2002 Form 10-403 Rev 06/15/88 · SUBMIT IN TRIPLICATE NCIU B-1 P&A Intended Procedure Subject: NCIU B-1 P&A Intended Procedure Date: Fri, 2 Aug 2002 14:47:23 -0800 From: "Aras Worthington" <ajworth@ppco.com> To: tom_maunder@admin.state.ak.us Tom, Sorry it has taken all week to get back with you. We've been discussing our plans on B-2 a bit more as they pertain to the gas well completion - will let you know as soon as we've settled on a plan that will stick; we've decided to re-evaluate a few options on the gas well completion. As for B-l, I've edited the Intended procedure that you have currently as follows. Please let me know if you require anything more on this. Thanks, Aras (See attached file: NCIU B1 Intended P&A.doc) ~NCIU B1 Intended P&A.doc Name: NCIU B1 Intended P&A.doc 1 Type: WINWORD File (application/msword) Encoding: base64 SCANNED AUG 1 of 1 8/5/2002 7:05 AM NCIU ~ Intended P&A for Completion as a Gas Well Objective: Plug and abandon all perforated zones in the well for re-completion as a gas well. Intended Procedure: . 4~ Pressure test & drawdown test the Tbg-Tail Plug (TTP) set in 4 ½" tail-pipe. Rig up CTU & Test BOPE to 5000 psi. RIH w/CT; Lay 17+ ppg drilling mud in the 4 ½" tbg from the plug to surface. Pull the TTP with Slickline or CTU. Lay 200' cement plug in the 5 ½" Drillpipe liner w/CT ~ 13,000', or as deep as attainable. Pressure-test & drawdown test the cement plug. MIRU Drilling rig. Pull tbg. Set a bridge plug in the 9 5/8" casing above the packer. Perforate well & run gas completion. A Subsidiary of PHILLIPS PETR 30" @ 407' MD ;SSV @ 430' It 20" @ 2579' Mr 2-3/8" Injection Sterling Dispos~ 13-3/8" @ 3760 4.5", 12.75 ppf, CIU B',,I Intended P&A for Completion as a Gas W~ff Objective: ~' Plug and abandon all perforated zones in the we~ re-completion as a gas well. Intended Procedure: / ,, ,, 1. Pressure test & drawdown test th~us (9 5/8' x 4 1/2" annulus). 2. Pressure test & drawdown test t/be'~bg-Tail Plug (TTP) se,~ in 4 V2" tail-pipe. 3. tRoigsuUrPfacCeT. U & RIH; Lay ,!~,,~lSpg drilling mud in the 4 V2 tUg from the plug 4. Pull the TTP with Slickli~e or CTU. 5. Lay 200' cement p.. 14~ in the 5 V2" Drillpipe liner from as deep as attainable. 6. Pressure-test &,drawdown test the cement plug. ... ~ ~ 7. MIRU D~i~rig. ~ ''''~- '~:~' ~:~ 8. Pull tbg.,/' 9. Set a ~dge plug in the 9 5/8" casing above the pac , : a/bCidge plu ~I~;Ahll~I~D/I, UG g 1 2002_ 10. Ruja/gas well completion into well. PKR @ 10,074 M Sliding Sleeve @ 1007 Nipple, 9-5/8" @ 1( ',, 19.5 ppf~ 8-1 ~ G' Tool Joinls (m N. Forlands PER CMTinDP@ 16. 5" DP @ 16650'1 30" @ 407' MD (430" TVD) @ 430' MD (430' TVD) BIA SIDETRACK IWell Name: North Cook Inlet Unit-B 00001 Spud Date: 7/31/97 Sidetrack Date: 2/5/98 20" @ 2579' MD (2571' TVD) 2-3/8" Injection Strings for Sterling Disposal zone 13-3/8" @ 3760' MD (3521' TVD) 4.5", 12.75 ppf, P-110 Tubing @ 10,074 MD (8846' TVD) Sliding Sleeve @ 10074' MD (8598' TVD) Nipple, 9-5/8" @ 10376' MD (8846' TVD) 19.5 ppf~ S-135 Drill Pipe with G' Tool Join~ls (min. ID: 3.25") ! WELL HISTORY: Feb. 5, 1998 - Sidetrack Nov. 26, 2001 - Set 3.813" PXN Plug in XN Nipple. 3.125 Fishneck. XN Nipple is 3.725" NoGo w/3.813" packing Dore. N. Forlands PERFs @ 16080'-16118' MD CMT in DP @ 16590' MD 5" DP @ 16650' MD Subject: Date: Wed, 25 Sep 2002 13:56:00 -0800 From: "Aras Worthington" <ajworth@ppco.com> To: winton_aubert@admin.state.ak.us Winton, Regarding the Revised P&A Procedure w/form 403 sent today: An option for P&A of the well is to do the P&A with a Drilling Rig. This could be a high-risk option, however, because the tubing and inner annulus would need to be displaced with heavy-weight (-18.5ppg) lead-based drilling mud with it's own associated environmental risks. Pulling the tubing would allow gas-laden oil to swap to surface and a lubricate & bleed operation' would commence in an effort to kill the well. It may be possible to run a small work-string into the liner at that point and lay a plug into the drillpipe liner if other problems did not ensue. Whereas, a P&A via Coil Tubing as described in the Form 403 submitted today would be a relatively low-risk operation and provide a solid cement plug to isolate the drillpipe liner and hence, the perforations. Aras Worthington Non-Rig Workover Engineer Phillips Alaska Inc. 265-6802 (See attached file: NCIU Bi Intended P&A.doc) .................................................. Name: NCIU B 1 Intended P&A.doc ] ~NCIU B 1. Intended e&A.doc Type: WINWORD File (application/msword)t E~S.°.,.~!~.!~.,,b...,a.~.s.,~,~ S.,C~' NNED OCT 04:2002 PERMIT 98-002 98-002 98-002 98-002 98-002 98-002 98-002 98-002 98-002 98-002 98-002 DATA T DATA PLUS AOGCC Individual Well Geological Materials Inventory RUN L LGR 14500-16590 L LGR 14500-16590 L BL 8860-12942 L BL 8860-12942 L BL 10400-16720 L BL 10400-16720 L BL 10400-16720 L BL 12800-16732 L 8860-12942 L 15301-17864 CN/LDT/GR-TVD CN/LDT/GR-MD FET-TVD MWD FET-TVD FET-MD MWD FET-MD DRILG DATA-MD CDR~TVD PDL-TVD ADN-4 Page: 1 Date: 03/03/99 RECVD 1 04/20/98 1 04/20/98 FINAL 05/18/98 FINAL 05/18/98 FINAL 05/18/98 FINAL 05/18/98 FINAL 05/18/98 FINAL 02/02/99 FINAL 02/02/99 1 02/09/99 1 02/09/99 $CANNF-..O SEP ! g 2002 PHALLI Alaska, Inc. A Subsidiary of IPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 B. Seitz Phone (907) 265-6961 Fax: (907) 265-6224 June 19,2002 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations NCIU B-lA (198-02 / 301-320) RECEIVED JU _ o. 2002 Alaska 0il & Gas Cons. Commission Anchorage Dear Commissioner: Phillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent operations on the Tyonek well NCIU B-lA. If there are any questions, please contact me or Len Janson at 907-776-2046. Sincerely, B. Seitz Sr. Operations/Reservoir Engineer Phillips Alaska Inc. BS/skad STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate_ Plugging_ Perforate_ Pull tubing _ Alter casing _ Repair well _ Other_XX Set Plug 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface 1249' FNL, 980' FWL Sec. 6 T11 N, R9W At top of productive interval At effective depth At total depth 2513' FSL, 1520' FEL, Sec 12, T11 N, R9W 5. Type of Well: Development _X Exploratory __ Stratigraphic __ Service_ 6. Datum elevation (DF or KB feet) RKB 132 feet 7. Unit or Property name North Cook Inlet 8. Well number NCIU B-lA 9. Permit number / approval number 198-02 / 301-320 10. APl number 50-883-20093-01 11. Field / Pool North Cook Inlet Field Development 12. Present well condition summary Total depth: measured true vertical 16720 feet Plugs (measured) PXN plug to 10042' 12942 feet 16590 feet Junk (measured) 12854 feet Size Cemented Measured Depth 30" Driven 407' 20" 1690 sx lead, 700 sx tail 2579' 13-3/8" 1234 sx lead, 672 sx tail 3760' 9-5/8" 2400 sx lead, 704 sx tail 10376' 5" 7oo sx G 16650' Effective depth: measured true vertical Casing Length Structural 368' Conductor 2579' Surface 3760' Intermediate 10376' Liner 6576' Perforation depth: measured 16080' - 16118' true vertical 12524' - 12547' Tubing (size, grade, and measured depth) 4-1/2" P-110 @ 10074' Packers & SSSV (type & measured depth) Pkr @ 10074' MD HES TRSV @ 430 ' MD. True vertical Depth 407' 2511' 3514' 8840' 12887' RECEIVED JUL 2 2002 Alaska 0i~ & Gas C,o~l~, Commmmo~, Anchorage 13. Stimulation or cement squeeze summary Intervals treated (measured) N/A Treatment description including volumes used and final pressure 14. Prior to well operation Subsequent to operation Oil-Bbl Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl N/A Casing Pressure Tubing Pressure 15. Attachments Copies of Logs and Surveys run _ Daily Report of Well Operations __X Oil 2¢_ Gas I Suspended __ Service _ 17. I hereby certify that the foregoing is true and corl, e'ct to the best of my knowledge. Questions? Call Len Janson (907) 776-2046 Signed 7~./~~ ///~/ Title: Sr. Operations/Reservoir Engineer Date '/¢,~P'"/~,~ Brian Seitz Prepared b)/ Sharon AIIsup-Drake 263-4612 & Brian Seitz (265-6961) Form 10-404 Rev 06/15/88 · SUBMIT IN DUPLICATE Date Comment NCI B-01A Event History 11/15/01 11/16/01 11/17/01 11/22/01 11/23/01 11/24/01 11/26/01 Pump 5 bbl 3% KCI, linear pressure increase to pressure out at 8200 psi. Suspect hydrate plug formed. Re-rig and bleed WHP back to 5800 psi, returning approx. 5 bbl fluid. Pump 7.5 bbl fluid incl 3.5 bbl methanol, pressure out again at 8500 psi. Now suspect deep plug, not hydrates. Attempt to drift well to find obstruction. Tag SSSV at 365' SLM. Attempt to open by pressuring well several times to up to 8800 psi and SSSV control line to up to 9300 psi. Apparently open SSSV briefly but tool will not pass. Some evidence of very limited communication with formation. Exercised TRSV, appears to stroke open @ 9200 psi. Confirmed TRSV open @ 430' RKB. Tagged hydrate plug @ 481' SLM, worked plug top to 1007' SLM utilizing pump. In progress. Worked thru hydrate bridges 973' to 1833' SLM utilizing pump. In progress. Broke through ice w/2.25" bailer - cleared to 10100' WLM, moved up to a 2.85" gauge ring and braided line brush assb and also broke through many hydrate stringer to 10100' WLM, RDFN. Ran 3.813" gauge ring/brush assb. To 10042' WLM to assure tubing was clear - ran PXN plug body and PXN prong to 10042' WLM - bled tubing off from 6200 psi to 3000 psi - shut SSSV and bled tubing to 300 psi - plug is set - will repressurize tubing for monitoring purposes and bleed off casing to within well operating guidelines. Page I of I 2/8/'2002 PHILLIP, ' Alaska, Inc. ,A Subs d ar~,' of PHILLIPS PETROLEUFvl COMPANY 30" @ 407' MD (430" TVD) @ 430' MD (430' TVD) 20" @ 2579' MD (2571' TVD) 2-3/8" Injection Strings for Sterling Disposal zone 13-3/8" @ 3760' MD (3521' TVD) B1 A SIDETRACK IWell Name: North Cook Inlet Unit-B 00001 Spud Date: 7/31/97 Sidetrack Date: 2/5/98 4.5", 12.75 ppf, P-110 Tubing PKR @ 10,074 MD (8846' TVD) Sliding Sleeve @ 10074' MD (8598' TVD) Nipple, 9-5/8" @ 10376' MD (8846' TVD) 19.5 ppf, S-135 Drill Pipe with G' Tool Joints (min. ID: 3.25") WELL HISTORY: Feb. 5, 1998 - Sidetrack Nov. 26, 2001 - Set 3.813" PXN Plug in XN Nipple. 3.125 Fishneck. XN Nipple is 3.725" NoGo w/3.813" pacmng bore. N. Forlands PERFs @ 16080'-16118' MD CMT in DP @ 16590' MD 5" DP @ 16650' MD PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 B. Seitz Phone (907) 265-6961 Fax: (907) 265-1441 November 16, 2001 Ms. Cammy Oechsli Taylor Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 W. 7'" Avenue, Suite 100 Anchorage, Alaska 99501 RECEIVED "200! Alaska Oil & ua~,":,,,~-o. Commission Anchorage Subject: NCIU B-01A Application for Sundry Approval Dear Commissioner Taylor: Phillips Alaska, Inc. hereby files this Application for Sundry Approval for suspension of the Cool< Inlet NCIU B-01A well. This well is not producing fi'om the perforated intervals and will be recompleted as a gas-producing well at a later date. In addition, the cement plug will provide an additional barrier to flow from the well. If you have any questions regarding this matter, please contact Len Janson at (907) 776-2046. Sincerely, Brian Seitz Sr. Operations/Reservoir Engineer Cook Inlet Asset BS/skad STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon_. Suspend_X Operational shutdown _ Re-enter suspended well _. Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Other _ Change approved program _ Pull tubing _ Variance _ Perforate _ 2. Name of Operator 5. Type of Well' 6. Datum elevation (DF or KB feet) Phillips Alaska, Inc. Development__ RKB 132 feet 3. Address Exploratory __ 7. Unit or Property name P. O. Box 100360 Stratigraphic_ Anchorage, AK 99510-0360 Service__X Nodh Cook Inlet 4. Location of well at surface 8. Well number 1249' FNL, 980' FWL Sec. 6 T11N, R9W NCIU B-lA At top of productive interval 9. Permit number / approval number 98 -02 At effective depth 10. APl number : :: :: 50-883-20093-01 At total depth 11. Field / Pool 2513' FSL, 1520' FEL, Sec 12, T11N, R9W North Cook Inlet Field Development 12. Present well condition summary Total depth: measured 16720 feet Plugs (measured) true vertical feet Effective depth: measured i;: ;ii;ii:il ii';i;:ii/i:ii:ii:~ii::.i: 1ii6590ii feet Junk (measured) true verticali:i:i:::.:i{:i:::::i:::::i:: i::.:i:{i::::i:1i2854: feet CaSing Length Size Cemented Measured Depth True vertical Depth Structural 368' 30" :B fi~en'i:i:: !::: ::.{::{:i: :!':: :i: {:i:i::: :i:i::: ::: :i:i::: :i: 407' 407' Conductor 2579' 20" :;i:~°i~i~il~dii:i~]S!xi:;{aiii.ii:i;i:!:i:ii:i:iii: 2579' :i;!'.. ;. ';;'i ;25i!!.'.!: ;; :;; .i .:.!i Surface 3760' 13-3/8" ;i!~i:~:~ ;{~:,ii ~.P i;~ii:2 i;:ii :i i:i ?;]:!i;:;i;: 3760' Intermediate 10376' 9-5/8" ~ ~b~ ~:~'~i~;~ ~:~2~&ii:~:: ] ~ ~ :~:~]:~ :~: 10376' ~8~:~ ~ ~ ~ ~:.: Liner 6576' 5" 16650' Perforation depth: measu red ~ ~: 6080.:~:~' j,~ ~,,,~ , ~ /' Tubing (size, grade, and measured depth 4-1/2" P-110 ~ 10074' ;',,,,,,~"?¢ (} Packers & SSSV (~pe & measured depth) Pkr ~ 10,074' md ,¢~S~(~ 0~ & ~aS 'P'q,.,,.. Anchorage HES TRSV ~ 430' md 14. Estimated date for commencing operation 15. Status of well classification as: ::....16. IfPr0Pb~al was Verbally.apProved .. ~~; .' ;1'3:No~:0.i; '::~. :. Oil ~ Gas __ Suspended .... ':':.:.:'~'~ :: .~ :.": :'::':...;:. .':. {.:" :..'~l~.f;'.:...:: .':. :. ~';: ~.: '~: -- :.' Na.me.~f:.appr0ver: ~o:m :Maund'er :; '... :Date approved. Se~ice .... ':.. ......... . .. ..~ :~':::.:.;.. ~..;.~:~..';.. :..;.;..::::'.. 17. I hereby certi~ that the foregoing is true and~orrect~ the best of my knowledge. Questions? Call Len Janson (907) 776-2046 Signed ~~~ Title: Sr. Operations/Rese~oir Engineer Date: 11/16/01 Brian Seit2 Prepared b7 Sharon AIIsup-Drake (263-4612) & Brian Seitz FOR COMMISSION USE ONLY Conditions of approval: Noti~ Commission so representative may witness Approval no.~l Plug integri~__ BOP Test__ Location clearance_ Mechanical Integri~ Test__ Subsequent form required 10- ~~~--I~. - - . ___~pproved by order of the Commission .,~, ~. HeU~se,F . Commissioner Dat~ Form 10-403 Rev 06/15/88 · (' , 3. 4. 5. 6. 7. NCIU B-1 Sidetrack Well Suspension Pump fullbore cement plug (approximately 35 bbls) chased with a foam plug & 178 bbls of 3% KCI & con-osion inhibitor w/diesel cap. Displace cement down to the perforations & SD pump. WOC for 3 days. Perform drawdown test on well to 0 psi for 30 minutes. Pressure test plug to 3000 psi for 30 minutes. RU Slickline and tag cement top. Close SSSV, Master, SSV, & Swab valve. '" '"',',~ ~i 6 ~.00! .A!as!<a Oil & Gas Cons. Cornmissior, Anchorage Re: NCIU B-1 & B-2 Well Suspensions Subject: Re: NCIU B-1 & B-2 Well Suspensions Date: Tue, 13 Nov 2001 14:42:06 -0900 From: Tom Maunder <tom_maunder@admin.state.ak. us> To: Tyonek Supervisor <tyksupv@ppco.com> CC: Aras Worthington <ajworth@ppco.com>, AOGCC North Slope Office <aogcc_prudhoe_bay@admin.state.ak.us> Aras and Len, Chuck Scheve and I reviewed the original plans you submitted by email this morning. You have made edits and provided further information as requested. Based on the information you have provided and our discussions, you have approval to proceed with your planned operations. Please note that sundry notices for the activities will need to be submitted as soon as practical. I would like the see the appropriate forms before weeks end if possible. I am copying the inspectors with this approval. As far as witnessing any operations goes, I imagine that the pressure testing planned on each string is likely the operation we will witness. Please keep the North Slope office informed. Tom Maunder, PE Sr. Petroleum Engineer AOGCC Tyonek Supervisor wrote: Yes, we are planning to pump a 3% KCI flush down the tubing on B-lA prior to pumping cement. We are also planning to pump a 3% KCl flush down the Iongstring on B-2 prior to setting the ClBP. Thanks, Aras Tom Maunder <torn_maunder(~admin. state, ak. us> 11/13/2001 12:42 PM To: Tyonek Supervisor/PPCO@Phillips CC: Subject: Re: NCIU B. 1 & B-2 Well Suspensions Aras, I have looked at the procedures. They are essentially as we discussed, however I have noted one item. It is specifically stated to kill the short string in B-2. You did mention that you will be pumping quite a volume of fluid into B-lA, but it is not mentioned in the procedure. Will you also be killing the long string in B-277 Given that you do not have any oil handling or separation equipment, it would seem like a good practice to employ. Look 1 of 3 2/21/02 5:26 PM Re: NCIU B-1 & B-2 Well Suspensions ;> :> ~> ;> :> :> :> :> > > > :> :> > :> forward to your reply. Tom Tyonek Supervisor wrote: > Tom, > As per our conversation earlier today, the following work scopes for B-1 & > B-2 are attached with editions including a 20' cement cap on top of the > CIBP in the Iongstring of B-2. > Please call back if there are any questions/concerns @ 776-2073. > Thanks, > Aras > (See attached file: NCIU Bl.doc)(See attached file: NCIU B2. doc) > .... Forwarded by Tyonek Supervisor/PPCO on 11/13/2001 12:19 PM ..... > Leonard G Janson Jr > > 11/13/2001 08:11 AM > To: torn_maunder@admin.state, ak. us > cc: Aras Worthington/PPCO@Phillips, C Lindsey Clark/PPCO@Phillips, Scott B > Rennie/PPOO@Phillips, Michael J Nelson/PPCO@Phillips, Tyonek Supervisor/PPCO@Phillips, Ryan P Deines/PPCO@Phillips bec: Subject: NCIU B-1 & B-2 Well Suspensions > Attached are the expected work scopes for B-t and B-2. In addition to this > work, we will repeat the MIT on A-12's disposal string. If you or an AOGCC > rep would like to witness any of this work, call the platform at 776-2073 for helicopter connections. If you have any comments, contact me on the platform. Thanks... l_en danson Office- ~07-776-2046 /:ax- ~07-776-6246 ¢oll. ~07-2~2-6748 2 of 3 2/21/02 5:26 PM Re: NClU B-1 & B-2 Well Suspensions > > (Embedded image moved to file: pic10291.pcx) ~> :> :> Name: NCIU Bl.doc NCIU Bl.doc Type: WINWORD File (application/msword) Encoding: base64 Name: NCIU B2. doc NCIU B2. doc Type: WINWORD File (application/msword) Encoding: base64 > Name: piclO2gl.pcx > pic10291.pcx Type: PCX Image (application/x.unknown-content-type.pcxfile) > Encoding: base64 (See attached file: torn_maunder, vcf) Tom Maunder <tom maunderL'~.admin.state.ak, us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 3 of 3 2/21/02 5:26 PM l, e 3. 4. 5. 6. 7. NCIU B-1 Well Suspension Pump fullbore cemem plug (approximately 35 bbls) chased with a foam plug & 178 bbls of 3% KC1 & corrosion inhibitor w/diesel cap. Displace cement down to the perforations & SD pump. WOC for 3 days. Perform drawdown test on well to 0 psi for 30 minutes. Pressure test plug to 3000 psi for 30 minutes. RU Slickline and tag cemem top. Close SSSV, Master, SSV, & Swab valve. NCIU wells B1 and B2 Subject: NCIU wells B1 and B2 Date: Fri, 12 Oct 2001 13:33:16 -0800 From: "Leonard G Janson Jr" <lgjanso@ppco.com> To: tom_maunder@admin.state.ak.us Len Janson Office - 907-776-2046 Fax- 907-776-6246 Cell - 907-252-6748 ..... Forwarded by Leonard G Janson Jr/PPCO on 10/12/2001 01:34 PM ..... Delivery Failure Report Your NCIU wells B1 and B2 document: was not delivered to: tom-maunder@admin.state.ak, us because: 551 User unknown What should you do? You can resend the undeliverable document to the recipients listed above by choosing the Resend button or the Resend command on the Actions menu. Once you have resent the document you may delete this Delivery Failure Report. If resending the document is not successful you will receive a new failure report. Unless you receive other Delivery Failure Reports, the document was successfully delivered to all other recipients. BVLNOTES 10/CIT/Phillips Petroleum/us, NSATOH02/AAI/ARCO To: C Lindsey Clark/PPCO@Phillips 1 of 3 2/21/02 5:01 ALASKA OIL AND GAS CONSERVATION COMMISSION TONY KNOWLES, GOVERNOR 333 W. 7~ AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 October 4, 2001 Mr. Robert Watkins Environmental Specialist Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, Alaska 99501 Re' Tyonek Deep Wells B-01A, B-02 and B-03 PPCo Petroleum Company (PPCo) North Cook Inlet Platform (Tyonek) Cook Inlet Alaska Dear Mr. Watkins: In early September, a meeting was held with PPCo representatives, yourself and myself to discuss the status of the subject wells. PPCo is seeking relief from DEC requirements with regard to maintaining spill response plans and equipment since there is no oil production from their platform. In support of their request, PPCo has submitted information regarding the physical condition of the wells and represents that the wells are well secured and that the chance of any release to the environment is remote. I have reviewed the submitted information. My analysis follows. All wells are "on board" Tyonek Platform in Northern Cook Inlet. Tyonek is a continuously manned production platform with 13 producing gas wells and the 3 "Tyonek Deep" wells. As described below, the Tyonek Deep wells are physically well secured. The present condition of the wells is beyond simply being shut in and the Deep wells have been physically isolated from any platform production system. B-01A and B-02 are equipped with tubing, packers, SSSVs and wellhead equipment with all appropriate valving including a SSV. Both wells do not have flowlines installed with such attachment locations covered with blind flanges. The SSSV and SSV control lines are not connected to any '~'13ntrol ~em,and valves with plugs have been affixed to the terminations. The SSSV in each'.,:':. Tyonek Deep Wells B-01A, B-02 and B-03 October 4, 2001 Page 2 of 2 tubing string is closed. The tubing above the SSSV in each string has been bled down to provide a differential pressure across the valves. The SSV is not closed so the tubing space above the SSSV can be monitored for any leakage across the SSSV. Since the wells were secured, PPCo has not reported that the wells have exhibited any pressure increase that would indicate a leaking SSSV. B-03 has cemented, tested and unperforated casing set to total depth. The well has never been completed and a deep retrievable bridge plug was set in the well during final operations. Based on my knowledge of no oil production equipment existing on board Tyonek Platform, the documentation submitted by PPCo relating to how the wells have been physically secured and isolated, I concur that the subject wells are well secured and that an oil discharge is not likely. I endorse PPCo's request for the relief requested. Please contact me at 793-1250 if you require further information. Sincerely, Thomas E. Maunder, PE Senior Petroleum Engineer jjc CC: Well Files B-01A-198-002 B-02-197-210 B-03-198-059 Phillips Tyonek Exemption Subject: Phillips Tyonek Exemption Date: Thu, 20 Sep 2001 15:41:50 -0800 From: "Watkins, Robert" <Robe~_Watkins@envircon.state.ak.us> To: "'tom_maunder@admin.state.ak.us'" <tom_maunder@admin.state.ak.us> CC: "Harvey, Susan" <Susan_Harvey@envircon.state.ak.us> Tom-- Phillip Alaska is requesting DEC's approval to exempt their Tyonek Platfrom facility from oil discharge prevention and contingency plan requirements. Three well were drilled at this platform. In order to deregulate this facility, we are requiring Phillips to obtain a certification from AOGCC that the wells are in suspended classification under you regulations. If AOGCC concurs that the well are in secure, suspended state, incapable of flow to the surface, and do not present any environmental risk. Upon receipt of your certification, we issue a letter exempting the facility from the State's contingency pla approval requirements. We will advise them that a contingency plan will be required to re-enter the wells in order to perform the modifications converting them to gas production. Thanks, Robert Robert Watkins EPR Section Manager Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, AK 99501 Ph: (907) 269-7680 Fax: (907) 269-7687 Mailto:Robert Watkins~..envircon.state.ak. us <mailto: Robert Watkins~envircon.state.ak.us> [~Clear Day Bkgrd.JPG: Name: Clear Day Bkgrd.JPG 'Type: JPEG Image (imageljpeg) Encoding: base64 1 of 1 9/21/01 10:10 AM Note to File North Cook Inlet Unit Wells B-01A (198-002), B-02 (197-210) and B-03 (198-059) Phillips Petroleum Company (PPCo) is the operator of North Cook Inlet Platform (NCIUP) in upper Cook Inlet. The platform produces gas from 13 producing wells, ships it to shore where it is liquefied for shipment to Japan. In late 1997 and continuing into 1998, PPCo drilled 3 wells and a sidetrack in a second attempt to further delineate the Sunfish prospect that had been identified with 2 ARCO wells drilled in 1991/1992 and a platform well drille~finished in 1993. In the most recent drilling program PPCo completed and tested B-01A and B-02. The wells are equipped with tubing, packers, sub-surface safety valves, surface safety valves and other tree valves. B-03 was drilled to total depth, cased and cemented. An operations shutdown was granted in late 1998 and the well has never been completed. In order to drill and potentially produce oil wells, PPCo is required by DEC regulations to have an Oil Spill Discharge Prevention Plan (Spill Plan) in place. PPCo is required to maintain certain equipment and contractor relationships in order to assure available response resources in case of a spill. The current Spill Plan will expire in early October and PPCo is seeking to be released from the need for a plan since the wells have been secured and PPCo does not have oil production equipment available on board NCIUP. A meeting was held September 10 at DEC offices with Robert Watkins representing DEC, myself representing AOGCC and 4 PPCo representatives. The currently carried status of the wells according to AOGCC records is 2 oil wells and 1 well in operations shutdown. From the DEC perspective, the 2 oil wells (B-01A and B-02) are the concern. According to Mr. Watkins, based on the information provided by PPCo, he is ready to release PPCo from the Spill Plan requirements provided AOGCC concurs that the wells are secure and not at risk to flow. Please see his attached email regarding this subject. In conjunction with this determination, it may be appropriate to change the wells' status to Suspended. PPCo was able to flow test the 2 wells. Following the flow tests, the wells were shut in to await further development. With the drastic decline in crude prices, the potential for an offshore development on a platform that could not produce oil without significant capital investment was erased. Although crude prices have increased, so has the investment cost and a development scenario has not been put forward. At the present time, the physical condition of the wells is as follows: All wells are "on board" NClUP in Northern Cook Inlet. NClUP is a continuously manned production platform with 13 producing gas wells and the 3 "Sunfish" wells. B-01A and B-02--Wells are equipped with tubing, packers, SSSVs and wellhead equipment with all appropriate valving including a SSV. Both wells do not have flowlines installed with such attachment locations covered with blind flanges. The SSSV and SSV control lines are not connected to any control system and valves with plugs have been affixed to the terminations. The SSSV in each tubing string is closed. The tubing above the $SSV in each string has been bled down to provide a differential pressure across the valves. The SSV is not closed so the tubing space above the SSSV can be monitored for any leakage across the SSSV. Since the wells were secured, PPCo has not reported that the wells have leaked. B-03 has cemented, tested and unperforated casing set to total depth. The well has never been completed and a deep retrievable bridge was set in the well during final operations. Through the discussions with PPCo, they have indicated that they do not intend for the wells to remain in their current configuration indefinitely. They have indicated that in their 2003 budget year, they plan to mobilize a rig to NCIUP. They intend to recomplete the wells as gas wells in the shallower Cook Inlet and Beluga sands. The lower oil intervals will be isolated with cement plugs and retainers to preserve the oil production opportunity should such production equipment and a pipeline be available. I recommend that the status of B-01A and B-02 be changed to suspended. The wells are mechanically secure on a continuously manned platform. PPCo does not have the necessary production or transportation equipment available to allow the wells to be produced. The wells are equipped with the necessary equipment (tubing, packers, S$SVs and wellheads) to prevent flow. The wells are not equipped with flow lines and their hydraulic control systems have been isolated from the active platform system. PPCo has indicated that within about 2 years, they plan to mobilize a rig to the platform to perform well work. At that time they have indicated that they intend to workover these wells, abandon the lower oil zones and recomplete the wells in the shallower gas intervals. In support of this recommendation, the following regulations apply. Suspended Wells 20 AAC 25.110 (a) If allowed under 20 AAC 25.105... 20 AAC 25.105 (b) A well drilled...from a fixed offshore platform must be abandoned before removal of the ddll rig unless the well is completed as an oil...well or is suspended, or unless well operations are shut down in accordance with 20 AAC 25.072. Each well drilled for a fixed offshore platform must be abandoned before the platform is removed or dismantled. ...the commission will, upon application by the operator under (b) of this section, approve the suspension of a well if (1) the well (A) encounters hydrocarbons...to indicate the well is capable of producing in paying quanities or (D) is located on a...platform with active producing...wells and (2) the operator justifies...why the well should not be abandoned...or why the well should not be completed; sufficient reasons include (B) unavailability of surface production or transportation facilities (C) need for pool delineation and evaluation to determine the prudence of pool development (d) A well approved for suspension must be plugged in accordance with the requirements of 20 AAC 25.112, except that the requirements of 20 AAC 25.112(d) do not apply if (1) a wellhead is installed...and (2) a bridge plug capped with 50 feet of cement...; the commission will waive the requirement of this paragraph for a development welt drilled from a pad or platform, if the commission determines that the level of activity on the pad or platform assures adequate surveillance of that development well. 20 AAC 25.112(i) provides that The commission will, in its discretion, approve a variance from the requirements of the section if the variance provides for at least equally effective plugging of the well and prevention of fluid movement into sources of hydrocarbons or freshwater. PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY COOK INLET AREA BOX 66 KENAI, ALASKA 99611 Phone: (907) 776-8166 Fax: (907) 776-6240 August 30, 2001 Ms. Cammy Taylor, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, #100 Anchorage, AK 99501-3539 Re:RE: Tyonek Deep wells ~ and B-2 Dear Ms. Taylor This letter is a follow-up to our July 19, 2001 correspondence to Mr. Maunder in which we requested the classification of Tyonek Deep wells B-lA and B-2 be changed to 'shut-in'. We would like to advise the AOGCC of our future plans for these two wells. Tyonek Deep wells B 1-A and B-2 are scheduled to have the oil zones suspended and be completed as shallow gas wells in the Beluga and Sterling formations in 2003. The wells current mechanical condition will be maintained until a rig is mobilized to perform this remedial work in 2003. Should we change the mechanical condition of the wellbore by the addition of a wireline retrievable plugging device we will advise AOGCC of the change. Additionally, we will implement a monthly annulus monitoring program. The current physical condition of these two wells is outlined in our letter of July 19, 2001. please contact me with any questions at 776-2021. Lindsey Clark Cook Inlet Operations Manager RECEIVED AUG 3 0 200 Alaska Oil & Gas Cons. Commissior~ Anchorage NCIU wells B1 and B2 cc: Michael J Nelson/PPCO@Phillips, NSK Problem Well Supv/PPCO@Phillips, Brian Seitz/PPCO@Phillips, Aras Worthington/PPCO@Phillips, tom-maunder@admin.state.ak.us, J Scott Jepsen/PPCO@Phillips, Michael G Knight/PPCO@Phillips, Scoff R Fahrney/PPCO@Phillips, F Steve Townsend/PPCO@Phillips Date: 01:24:45 PM PST Today Subject: NCIU wells B1 and B2 Lindsey, As a follow up to our conversation, I contacted Tom Maunder of the AOGCC to discuss NClU B-1 and B-2 in reference to our "C" plan. The follow is an out line of our conversation. I asked Tom what is going to be required for AOGCC to consider the two wells as suspended. Tom replied that bottomhole plugs of "whatever" type (meaning cement or wireline set) would be required for AOGCC to consider the wells suspended. I asked Tom if AOGCC planned to issue a letter to DEC stating what the requirements for "suspended" status would be. Tom replied that he was not sure. He stated that he and Cammy will discuss if a letter would be sent. I expressed our desire for a letter so that we could request an extension to our "C" plan based on meeting AOGCC's requirements. Tom replied that he and Cammy will discuss the need for a letter to DEC. He additionally stated that he and Cammy will be contacting Susan with DEC on Monday to discuss both the need for a letter from AOGCC as well as our extension of the "C" plan. Tom did state that he had received a verbal statement from Susan at DEC that she saw "no problem in extending the "C" plan" beyond the 22nd of October. Our conversation centered around a 4 to 6 week extension. I explained to Tom that we are working on equipment availability as well as a work timeline to accomplish AOGCC's requirements. Obviously, whatever the extension, we must have all work complete before that date. 2of3 2/21/02 5:01 PM NCIU wells B1 and B2 I explained that we are currently taking the following steps to address the wells: Brian Seitz is searching well records. Aras Worthington is searching for equipment and developing a timeline for availability. NSK Problem Well group is assisting in locating equipment and developing a timeline for availability. I told Tom that I would keep him abreast of our progress on a continual basis and inform him of any changes, If you have any questions, please let me know. Len Janson Office - 907-776-2046 Fax- 907-776-6246 Cell- 907-252-6748 3 of 3 APR ;3 0 2/2t/02 5:01 PM 198,002~0 N COOK INLET UNIT Roll gl: Start: Stop Roll #2: MD 16720 TVD 12941 Completion Date: B-01 A 50- 883-20093-01 PHILLIPS PETROLEUM CO Start Stop 12/1/98 Completed Status: 1-OIL Current: T Name Interval q~ L ADN-4 1 15301-17864 ~'L CDR-TVD FINAL BL 12800-16732 L CDR/LDT/GR-TVD FINAL BL 14500-16590 ~,q,. L CN/LDT/GR-MD 1 LGR 14500-16590 4~,L CN/LDT/GR-TVD 1 LGR 14500-16590 ~/L DRILGDATA-MD FINAL BL 10400-16720 ~ L FET-MD FINAL BL 10400-16720 ,~L FET-TVD FINAL BL 8860-12942 L MWD FET-MD FINAL BL 10400-16720 L MWDFET-TVD FINAL BL 8860-12942 It/ L PDL-TYD 1 8860-12942 ~ R RES FLUID STUDY CORELAB 16080-16118 Sent Received OH I 2/3/99 2/9/99 OH 2/2/99 2/2/99 OH 2/2/99 2/2/99 OH 4/17/98 4/20/98 OH 4/17/98 4/20/98 OH 2 5/18/98 5/18/98 OH 2 5/18/98 5/18/98 OH 2 5/18/98 5/18/98 OH 2 5/18/98 5/18/98 OH 2 5/18/98 5/18/98 OH I 2/3/99 2/9/99 CH 3/12/99 3/16/99 T/C/D Wednesday, January 24, 2001 Page 1 of 1 Tyonek C-Plan ADEC Comments Subject: Tyonek C-Plan ADEC Comments Date: Wed, 1 Aug 2001 11:10:06 -0800 From: "Don P Turner" <dpturne@ppco.com> To: tom_maunder@admin.state.ak.us Per our conversation of this morning. Let me know (265-6056) or Gordon Caughman know (265-6711) of any news. Thank you. ..... Forwarded by' Don P Turner/PPCO on 08/01/01 11:13 AM ..... Gordon R Caughman 08101101 10:09 AM To: Steve FindlaylPPCO~Phillips, David W HansonlPPCO@Phillips, Michael J NelsonlPPCO~Phillips, Don'P Turner/PPCO~Phillips, Ryan P Deines/PPCO@Phillips, C Lindsey CladdPPCO~Phillips, Steven F ArbeiovskylPhillips Petroleum/us~Phillips, Bob D HalelPPCO~!Phillips, Leonard G Janson Jr/PPCO@Phillips, J Scott JepsenlPPCO~Phillips, Randal Buckendorf/PPCO~PhilliPs cc: Subject: Tyonek C-Plan ADEC Comments As you recall, we have been attempting to drop the Tyonek C-plan because the platform is a gas production facttity and does not produce oil. ADEC has not concurred that the C-plan can be dropped becauSe the Tyonek Deep wells B-~IA and B-2 are perforated and completed in an oil bearing formation. Originally, we understood ADEC's concern to be that B-lA and B-2 are classified as "oil wells" on the AOGCC completion reports. We talked to AOGCC and sent a letter requesting reclassification of the wells from "oil" to "shut-in" since the wells have a) surface and subsurface safety valves closed, b) no flowlines connected to the wellheads and are c) incapable of being produced. Tom Maunder of AOGCC has transmitted our letter to Robert Watkins of ADEC. Robert called and indicated ADEC's current primary concern is the "capability of the oil wells to flow to surface." Evidently, even though the wells are mechanically secured, ADEC is concerned that the wells do not have cement plugs, or kill weight fluid in the well bores / tubing strings. Robert indicated that he will review the Subject with Susan Harvey and will respond back to me with their recommendations. However, it does appear that we will either have to install cement plugs or kill weight fluid to satisfy ADEC that Tyonek is incapable of flowing oil to surface. I will advise you of ADEC's official response when received. Gordon R. Caughman Phillips Alaska, Inc. 700 G St, Anchorage, AK 99510 - 0360 Phone: 907.265-6711 SCANNED DEC ]1 9 2002 1 of 1 8/1/01 11:46 AM PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P. ©, BOX 10036;0 ANCHORAGE, ALASKA 99510-0360 July 19, 2001 Mr. Thomas Maunder, Petroleum Engineer State of Alaska, Oil and Gas Conservation Commission 333 W. 7th Avenue, #100 Anchorage, Alaska 99501-3539 Subject: Tyonek Deep Wells B-lA and B-2 Dear Mr. Maunder: This letter is to follow up on the recent telephone conversations that we have had with you and other AOGCC staff, regarding the status and classifications for the Tyonek Deep wells B-lA and B-2. Phillips Alaska requested that the classifications of these wells be changed from "l-oil" to "suspended", in a letter to the AOGCC on May 15, 2001. AOGCC's most recent input to Phillips is that the well classifications could be changed to "shut-in" in their present physical condition. This letter is to request that the classification of the Tyonek Deep Wells B-lA and B-2 be changed to "shut-in". The physical condition and status of the Tyonek Deep wells B-lA and B-2 are as follows: Well B-lA (sidetrack) Physical Condition: The well was perforated and tested. A completion report was filed 1/28/99. The well is shut in. No flow line is installed. The wing valve is closed with a blind flange installed. A SSSV is installed at 430'MD. The SSSV is closed and the control line is not connected to a control panel. Therefore, the valve cannot be opened without hooking up a hydraulic pump and manually pumping the valve open. Attachment 1 shows the wing valve with no flow line attached. Attachment 2 shows that the control line is not connected. Attachment 3 is a completion diagram. July 19, 2001 Mr. T. Maunder, AOGCC Re: Tyonek Deep Wells B-lA and B-2 Page 2 Current Status: The current AOGCC status is "l-oil". Phillips Alaska requests that the status be modified to "shut-in". Well B-2 Physical Condition: The well was completed as a dual well. The well was perforated and tested. A completion report was filed 4/1/98. The well is shut in. No flow lines are installed. The wing valves are closed with blind flanges installed. SSSVs are installed in both tubing strings. The SSSVs are closed and neither control line is connected to a control panel. Therefore, the valves cannot be opened without hooking up a hydraulic pump and manually pumping the valves open. Attachment 4 shows the long string wing valve with no flow line attached. Attachment 5 shows the short string wing valve with no flow line attached. Attachment 6 shows that the short string control line is not connected. Attachment 7 shows that the long string control line is not connected. Attachment 8 is a completion diagram. Current Status: The current AOGCC status is "l-oil". Phillips Alaska requests that the status be modified to "shut-in". The Tyonek Platform is not equipped to produce and process oil. The platform lacks flow lines to the wells, three-phase separation equipment, heater treaters, and oil pumps. Phillips Alaska has no plans to install oil-producing equipment for any of the Tyonek Deep wells. Please contact me with any questions at 265-6711. Sincerely, 6'ordon ~aug'hman Safety Engineer gc/dt/djn ATTACHMENT 1 B-lA Wing Valve No Flow Line Attached ATTACHMENT 2 B-lA Control Line Control Line Is Not Connected NCIU B-1 SIDETRACK COMPLETION DIAGRAM 430:. MO (,430' 'I'VD} 12o' @ 2579' MD ('2571' TVD) I 2-3/8" injection strings for !13-3/8' @ :3760' MD ~521' 'TVD) ' ! .4.-1/2". 12.75 10,074' MD (8598' TVD,) [9-5/8' ~ 10,376' MD ~8846' TVD) I 5', 19.5 ppf, S-135 Drill Pipe with I 'G' Tool Joints (Min ID: 3.25'~ I IN. FORE~'NDS PERFS Q 16,080' - 16,11~' MD ICMT IN DP ~ 16,590' MD IS' DP e ~s,sso',,Mp SCANNED DEC ~ ~ 2{]D2 ATTACHMENT 4 B-2 Long String Wing Valve No Flow Line Attached A TTP, cHr ~ ~ ~1'~ ~ ATTACHMENT 5 B-2 Short String Wing Valve No Flow Line Attached ATTACHMENT 6 B-2 Short String Control Line Control Line Is Not Connected ATTACHMENT 7 B-2 Long String Control Line Control Line Is Not Connected Lmer Top Packer , Sunfish 13110.13170' N. FomJamls 13652.13M~ 13718-13736' 13818-13856' 13901.13920' 13944.13966' PRESENT COMPLETION )lo! ADplk~ble ,M Not AppliGJbM , R.K.~-BH F: I R.Y~LMSL: Pmm~m Llmer: X-~ N.10'.P. 110 P. II0 4'730 1920 8160 149eo ! UK~oer Beuga Lower SamOa TOC ~ 10.0B8' 11086 PBTD · 14.37T 31F2 · O 14,457' TD · 14537 Uixmled 03/26/98 20" Ceaducter 13 ~1" Ist Sale 12/11/93 2nd Dv mci ~ 738~ ' 3rd Sale '/'A3 I/2' CEMENTING SUMMARY Cmm~d ~ I010n 12.1 R~pl m~'G'~0.2~ ~sx D-TT. 0.0~ ~ C~ C~ m S~. C~ 0.0~ l~m 0.1 ~ 0.1 l~m ~7, 0.1% ~13~, 1.0 ~ ~, ~ 0.3% ~1. T~ m IO.~ 0.13 ~ SHORT STRING TUBING 0.00 53.Se Emvat~ 53.$1o.g3 Tu~ Hanger ~.51 213.36 27~ 6.S~L~~IT~ ~1.17 39~.~ 2 7~ 6.5 ~ L~ ~ ~ T~ 4326.11 6.48 2 7~ ~M~ ~ ~ ~1 4JJ3.29 I~S.51 2 5911.lO 6.43 2 ?~239 6,45 2 ?~I.P 1135J5 2 liP. t96.48 SIH.6? 1112.45 27~ 930342 6.~ 2 7~ ~ ~ ~ ~1 93~,~ ~O. SS 2 7~ 102~,t~6.~ 1~.59 2~.75 2 7~ 10S93.34 7.13 ~ R~ ~l ~er 1~.47 12.05 2 7~ ~.5 ~ L~ ~ ~l Tubing 1~12.321.14 HES I~1~.~ 10.12 2 7~ 1~.78 1.43 HES ~ ~e 1~.21 0.74 LONG ~ING ~BING ~3.S80.93 ~.~1 36~.~ 3 1~ 12.95 ~ L~ ~ Tubing 420.41 B.10 3 421.~1 ]~., 3 1~ 12.95 ~ L~ P~ T~ing ~14.9~ 3 1~ 12.95 ~ L~ ~ Tubng ~ 3 ~.01 a.~ 3 ~7.87 6.51 3 92~.38~ I~.M 3 1~ 12.~ M L~ ~ Tu~ 103~2.02 6.49 3 103Sl.~l ~3.93 3 I~ 12.~ML~P~T~O 1o~2.~I. lO ~ ~H ~l ~ i~.~ 2~.47 3 1~ 12.~ ~ L~ ~ Tung 13~.011~ W 13524.~ 3.~ 3 Well: PBTD: ,4.~77 Is,~,: IT~ w,: TyoMk Plillom. C~ iibl. Ab~ Field: Neflh CNk Ial~ .. SCANNED BEC 1 2002 NSH PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 15, 2001 RECE'IVF ' Mr. Thomas Maunder, Petroleum Engineer State of Alaska, Oil and Gas Conversation Commission 333 W. 7th Avenue, #100 Anchorage, Alaska 99501-3539 Subject: Tyonek Deep Wells'B-IA and B-2 MAY 17 '°'. ,'~;iaska 0il & Ga~ !", AtlC': : .. Dear Mr. Maunder: This letter is to follow up on the recent telephone conversations that you have had with Len JansOn, the Tyonek Platform Engineer, regarding the status and classifications for the Tyonek Deep wells B-lA and B-2. The physical condition and status of the Tyonek Deep wells B-lA and B-2 are as follows: Well B-lA (sidetrack) Physical Condition: The well was perforated and tested. A completion report was filed 1/28/99. The well is shut in. No flow line is installed. The wing valve is closed with a blind flange installed. A SSSV is installed at 430'MD. The SSSV is closed and the control line is not connected to a control panel. Therefore, the valve cannot be opened without hooking up a hydraulic pump and manually pumping the valve open. Attachment 1 shows the wing valve with no flow line attached. Attachment 2 shows that the control line is not connected. Attachment 3 is a completion diagram. Current Status: The current AOGCC status is "l-oil". Phillips Alaska requests that the status be modified to "suspended''. Well B-2 Physical Condition' The well was completed as a dual well. The well was perforated and tested. A completion report was filed 4/1/98. The well is shut in. No flow lines are CANNED [ 0V 2002 , · .. May 15, 2001 Mr. T. Maunder, AOGCC Re: Tyonek Deep Wells B-lA and B-2 Page 2 installed. The wing valves are closed with blind flanges installed. SSSVs are installed in both tubing strings. The SSSVs are closed and neither control line is connected to a control panel. Therefore, the valves cannot be opened without hooking up a hydraulic pump and manually pumping the valves open. Attachment 4 shows the long string wing valve with no flow line attached. Attachment 5 shows the short string wing valve with no flow line attached. Attachment 6 shows that the short string control line is not connected. Attachment 7 shows that the long string control line is not connected. Attachment 8 is a completion diagram. Current Status: The current AOGCC status is "l-oil". Phillips Alaska requests that the status be modified to "suspended". The Tyonek Platform is not equipped to produce and process oil. The platform lacks flow lines to the wells, three-phase separation equipment, heater treaters, and oil pumps. Phillips Alaska has no plans to install oil-producing equipment for any of the Tyonek Deep wells. Please contact me with any questions at 265-6711. Sincerely, r /' .... G/ordon C~ghma~ Safety Engineer ' gc/dt/djn SCANNED NOV I ~, 2002 t , TT CHiY F_ T · ~.. CEMENTING SUmmARY TOC ~ 10,088' 0.13 i~ HGM ~L, 0,2~ % HR-5 · , , , ,, bHOR~ STRIhG TUBIN~ 53.~8 0.93 Tubing HBnger ~.5l 283.36 2 7~ 6.5 I~ L~O CS H~fll Tubing 341,87 39B4.~ 2 7~ 6.5 ~ L~ CS H~I Tubing 4326.81 6.48 2 7~' ~MCO 4333.29 1578.51 2 7~ 6.5 I~ L~ ~ H~I Tubing ~911.B0 ~.43 2 7~ ~MCO ~s ~ Mandrel 7~2.39 6.45 2 7~ CAMCO ~s ~ Mafldml Liner Top ~ ~ Io~r 8184.19 6.48 2 7~ CAMCO ~s Lift ~ndml 9303.12 6.4B 2 7~ ~MCO ~s L~ ~nd~l ~ 11086 102~,15 6.~ 2 7~' ~MCO ~s Uti Mandrel 102~.~9 2~.75 2 7~ 6,5 Ib~ L~ ~ H~I Tubing ~: 10~93,34 7.13 ~llibu~ RDH ~al Pa~er 1~.47 12.05 2 7~' 6.5 Ib~ L~ CS H~I Tubing 1~23.7~ %43 HES XN Nipple 1~2~.21 0,74 W~line En~ Guide LONG STRING TUBING Sunfish 53.~8 0.93 Tubing Hanger 420.41 8.10 3 1~ Hallibu~ ~SV 428.51 ~.~. 3 1~ 12.95 I~ L~ PH~ Tubing 4~88.95 6.~ 3 1~ ~MCO ~s Lift ~ndml ~[ 7' ~ 13~2~ 4395.45 ~14.95 3 1~ 12.95 Ib~ L~0 PH~ Tubing ~10.40 6.52 3 1~' ~MCO ~s ~ ~ndrel N. Forelands ~ ~16.92 1350.~ 3 1~' 12.95 Ib~ L~0 PH~ Tubing ?~7.01 6.~ 3 13652-13686' ~ 7973.51 12~.35 3 1~ 12.95 Ib~ L~O PH~ Tubing ~ , 13718-13736' ~ 9237.87 6.51 3 1~' ~MCO ~s ~ Mandrel 13818-13856' ~ 92~.~8 1107.~ 3 1~' 12.95 Ib~ L~ PH~ Tubing 13~1.13920' ~ 10~52.02 6.49 3 1~ ~CO ~s ~ ~ndrel ~ PB~ = 14.377' 13523.01 1.~ ~k~ N~ 13524.34 5.50 3 1~ ~al ~ly TD = 14537' Welh Nomh C~k In~l Unll U~aI~ 0~8 ~i~: Tyonek Plll~om. C~k Inlet. Alaska Field: No~h C~k inlel NSH ,,, , ,, CANNED NOV ] 20[ 2 PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 NORTH AMERICA EXPLORATION AND PRODUCTION COMPANY BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING May 25, 1999 North Cook Inlet Unit "B" No. 1 PPCo. Tyonek Platform North Cook Inlet Unit, Alaska Cuttings Injection System Alaska Oil and Gas Conservation Commission 300i Porcupine Drive Anchorage, Alaska 99501 Attn: Mr. Blair Wondzell Gentlemen: In response to your letter dated April 21, 1999, enclosed is a Schematic of the Cuttings Injection System with the following summary of the Phillips Petroleum Company operations for clarification as to what was happening. The 13 3/8" casing with the two strings of 2 3/8" tubing attached had been set and cemented to surface, providing zonal isolation to the Sterling Sand Interval. As the reports state, there was difficulty getting down the tubings to perforate, in fact the deepest we could get was 2600'. The decision was made to run the next string of casing (9 5/8") in two steps, rather than as a single intermediate casing string. With the approval of the AOGCC, the 9 5/8" casing was set as a liner, with the top of the liner set at 3588 and cemented. A liner top packer was also installed and set to further insure the integrity of the casing. The 13 3/8" casing and 9 5/8" liner were then tested to 3000 psi. At this point, the well was perforated in three separate wireline runs from 3500' - 3540' with the intent of penetrating both the Sterling Sand interval and the 2 3/8" tubing strings at the Sterling Sand level. The injection tests were ran and confirmed that we could pump int° the Sterling Sands at acceptable rates via the 13 3/8" casing or the 2 3/8" tubings. With the tubings being perforated and in communication with the Sterling Sands, they were then used as the injection system rather than using the 9 5/8" x 13 3/8" annulus as this would provide more control over the system in the event the perforations or tubings became plugged with cuttings. We would be able to "rock" the system by pumping either down the tubings or the annulus and hopefully remedy any plugging problem. The 9 5/8" tie back string was then installed with a 10' seal assembly and landed at the surface. The 9 5/8" casing was pressure tested for integrity to 5000 psi. Operations continued with very few problems pertaining to the injection and disposal of the cuttings. Should you require any additional information, please contact P. R. Dean at (713) 669-3502. NPO/prd~ cc' Well File Regards, ~7--~~ .... ~ ~ ~ N. ~. Omsberg E&P America's Drilling ,.l~r~,~lVE~D ~ Oil & Gas Cons. · ' ' ~chomge, SCHEMATI~ OF CUTTINGS INJE ~i,ON SYSTEM Slurry Injection WellHead 20" x 13 318" Annulus to Surface 20" Conductor 2600' Tubing Clamps Cement .... · Inject Into -" 3500' on : 3540' ~--.-~~2 ~8" Tubings 518" Tie-Back Casing Tubings Perforated When Casing Perforated · Baker Liner Top Packer 3663' (~ 3588' 13 318" Surfac;'Casing ' 1¥ I ~ '~Top of Cement PRD~ April 21, 1999 N.P.Omsberg North America Drag. Mgr. Phillips Petroleum Co. Box 1967 Houston, Texas 77251-1967 Re~ Annular Disposal Conduit, North Cook Inlet Unit Well B-1 Dear Mr. Omsberg: Your February 19,1998 letter to me states that "The cuttings are disposed of through the 2-3/8" tubing string attached to the 13-3/8" surface casing." From the Operation Summary describing attempts to get down the two 2-3/8" tubing strings run to 3663', strapped to the 13 3/8" casing: 8/10/97 UNABLE TO GET PAST 1076' ON ONE STRING & 1930' ON THE OTHER STRING. TRIED DIFFERENT HOOK-UPS W/NO SUCCESS ...... SLICK LINE PROGRESS = 1768' & 1538'. UNABLE TO GET ANY DEEPER. 8/11/97 ATTEMPT 1 3/8" DUMMY RUNS ON BOTH 2 3/8" INJECTION STRINGS W/N SUCCESS. 2550 & 2600' MAX PROG. An APPLICATION FOR SUNDRY APPROVALS No. 397-176 Dated 8/21/97 states: Approval is requested to alter the approved casing program. The request is made due to the inability to successfully perforate the .2 3/8" tubing strings designed for the cuttings injection service. The alteration consists of setting The 9 5/8" casing string shallower (above the MGS formation), and setting it as a liner, with subsequent tie-back being made after perforating and completing the annulus as a disposal horizon for the oil base cuttings. From Operation Summary: 9/9/97 RIH W/4.5" CSG GUNS & PERF AT 4 SPF STERLING SANDS FOR DISPOSAL. ON RUN #1 F/3530 TO 3540', RUN #2 F/3520~3530' . ..... RIH WITH GUN RUN RR #3 & PERFORATE F/3500' TO 3520'. ALL SHOTS FIRED ....... CLOSED BLINDS & ESTABLISHED INJ RATE THROUGH STERLING PERFS AS FOLLOWS; ...... 1000 PSI AT 8.0 BPM. TOTAL OF 45 BBLS INJECTED. 9/13/97 PERFORMED INJECTION TEST WITH APOLLO THRU INJECTION TBG; ½ BPM @ 1150 PSI, h BPM ~ 1250 PSI, 1-1/2 BPM @ 1400 PSI. N. P. Omsberg 2 April 21, 1999 On the completion report (10-407) signed by Paul Dean on Nov 12, 1997 under section 24. Perforations open to Production (MD+TVD of Top and Bottom and interval, size, and number) "13 3/8" casing perforated from 3500-3540 (For purpose of cuttings disposal)" Please review this well and explain how the mud, water, and cuttings were pumped into the Sterling Formation. If the 2-3/8" tubing strings were used, please provide the information as to how they were drifted, cleaned out, and perforated for injection. If you have questions, please call me at 907-279-1433. Ext 226 or E-mail blair wondzell~admin.state.ak.us. Thank you for your efforts, Blair E. Wondzell, P.E. Senior Petroleum Engineer File:nciu-b-1 .doc PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-~- BOX '~ 967 AMERICAS DIVISION COMPANY BELLAIR E. TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING March 12, 1999 Mr. Robert Crandall Alaska Oil & Gas commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Dear Mr. Crandall: q 3.o Enclosed is a copy of the Reservoir Fluid Study for the NCIU B- 1 ST by CoreLab. If you need anything else, feel free to give me a call on 713-669-3731. Yours truly, Jim Lachenmaier IWL:co Enclosure CORE LABORATORIES Reservoir Fluid Study for Phillips Petroleum Company NCIU Well B1-ST (North Forelands Fm.) Offshore, Alaska North Cook Inlet Unit RFL 980061 3-Mar-99 A product of Core Laboratories, Inc. . The an~y~s, opinions or inte~ions ~nt~n~ in this Bpo~ are bas~ upon ob~ims ~nd ~edal suppli~ by the ~ient ~r ex~usi~ and ~n~dential use this Bpo~ has b~n m~e. The integrations or opini~s e~ Bp~nt the be~ judgement ~ La~. O~ Labo~odes assum~ ~o r~nsibil~y and makes no ~nty or ~p~nt~ions, e~s or i~pli~, ~ to the p~u~Mty, p~per oper~ions or p~tablen~, b~r, ~ any ~1, g~, ~1 or ~ber min~, prope~y, ~1 ~ sand in ~n~ion ~ioh su~ Bpo~ is u~ or ~i~ upon for any ~n ~~r. PETROLEUM SERVICES March 3, 1999 Phillips Petroleum Company 6330 West Loop South, Rm 1142 Bellaire, TX 77401-2901 ATTENTION: Mr. David P. Tobola Subject: Reservoir Fluid Study NCIU Well BI-ST (North Forelands Fm.) North Cook Inlet Unit (NCIU) Offshore, Alaska File: RFL 980061 Dear Mr. Tobola, Multiple samples of separator gas and separator liquid were collected from the subject well by a representative of Halliburton Energy Services. The samples were shipped to our Carrollton, Texas laboratory for use in a reservoir fluid study. Results of the study are presented in the following report. It has been a pleasure to perform this fluid stUdy for Phillips Petroleum COmpany. ShOUld any questions arise or if we may be of further service in any way, please do not hesitate to contact us. Sincerely, Lee Williams Staff Engineer Reservoir Fluid Studies 8 cc: Addressee encl: diskette Core Laboratories, Inc. 1875 Monetary Lane, Carrollton, Texas 75006-7012, (972) 466-2673, Fax (972) 323-3930, E-mail @corelabusa.com LABORATORY PROCEDURES Phillips Petroleum Company NClU Well BI-ST (North Forelands Fm.) Offshore, Alaska RFL 980061 PRELIMINARY CHECKS OF SAMPLE QUALITY Multiple samples of separator gas and separator liquid were received in our laboratory for use in a reservoir fluid study. As a quality check, the opening pressures of the separator gas cylinders were determined. In addition, the bubblepoint pressures of the separator liquids were measured at room temperature. Results of the preliminary quality checks are summarized on page four of the report. RECOMBINATION OF WELLSTREAM FL UID The composition of the separator gas sample was determined using temperature-programmed extended gas chromatography. The composition, together with the calculated properties of the separator gas, is reported on page five. The composition of the separator liquid sample was measured to a triacontanes plus residual fraction using a flash/chromatographic technique. The separator liquid composition is presented on page six. During the compositional analysis, a sample of atmospheric liquid was collected for chromatographic ('fingerprint) analysis. The whole oil chromatogram by temperature-programmed, capillary gas chromatography is presented in graphical form in the appendix. Using the compositions of the separator products in conjunction with the reported gas/oil ratio, the composition of the wellstream fluid was calculated. The recombination parameters and calculated recombined wellstream composition may be found on pages seven and eight. The separator gas and separator liquid were physically reeombined to the reported gas/oil ratio and the resulting fluid used for the remainder of the laboratory testing program. PRESSURE- VOL UME RELATIONSHIP A portion of the recombined fluid was charged to a high-pressure windowed cell and heated to the reported reservoir temperature of 210° F. After establishing thermodynamic equilibrium, the fluid sample was subjected to a constant composition expansion. During the constant composition expansion, a bubblepoint was observed to occur at 2454 psig. Complete data derived from the pressure-volume relations measurement including average single-phase compressibilities, relative volumes and calculated single-phase densities may be found on pages 9 and 10. DIFFERENTIAL VAPORIZATION ' At the completion of the constant composition expansion, the sample of reservoir fluid was pressurized and brought to equilibrium at single-phase conditions. A differential vaporization procedure was then conducted for the purpose of measuring two-phase properties as a function of differential pressure depletion. Results of the differential vaporization are presented on page 11. MUL TI-PRESSURE VISCOSITY The viscosity of the reservoir fluid was measured over a range of pressures at the reported reservoir temperature in a rolling-ball viscometer. Both single-phase and two-phase viscosities of the reservoir fluid can be found on page 12. SINGLE-STA GE SEPARATOR TEST A small portion of the reservoir fluid was subjected to a separator test at the prescribed conditions. The resulting gas/oil ratio, stock tank oil gravity and formation volume factor are presented on page 13. During the separator test, a sample of gas was collected from the primary stage and analyzed by extended gas chromatography. The composition of the separator gas sample and calculated total gas properties are presented on page 14. Using the separator test results, the differential vaporization data were adjusted for surface separation. The adjusted differential vaporization data may be found on page 15. GRAPHICAL REPRESENTATIONS This report includes graphical representations and analytical expressions. The statistical summaries represent an objective estimate of non-systematic error using a preset level of confidence. Confidence intervals are calculated using the Student "t" density distribution tables. An appendix is also included which contains equations and nomenclature which extend and define the analytical expressions and data relationships presented in the report. i TABLE OF CONTENTS Laboratory Procedures i Summary of PVT Data General Well Information Preliminary Quality Checks Wellstream Recombination Pressure-Volume Relations Differential Vaporization Viscosity of Reservoir Fluid Single-Stage Separator Test Adjusted Differential Data Nomenclature & Equations Whole Oil Chromatogram 1 4 5-8 9,10 11 12 13,14 15 Appendix-A Appendix-B LIST OF FIGURES Pressure-Volume Relations Relative Volume .................... A-1 Y-Function .................... ~1-2 Differential Vapor~n Relative Oil Volume .................... B-I Solution Gas~Oil Ratio .................... B-2 Oil Density .................... B-3 Incremental Gas Gravity .................... B-4 Deviation Factor, Z .................... B-5 Viscosity Analysis Two-Phase Fluid Viscosities .................... C-1 Single-Phase Oil Viscosity .................... C-2 Differential Vaporization Adjusted to Separator Conditions Solution Gas~Oil Ratio .................... Formation Volume Factor .................... D-I D-2 Phillips Petroleum Company NCIU Well Bi-ST (North Forelands Fm.) RFL 98O061 SUMMARY OF PVT DATA Reported Reservoir Conditions Average Reservoir Pressure ................... Average Reservoir Temperature ............. 9300 psig 210 °F Pressure-Volume Relations Saturation Pressure ............................... Avg Single-Phase Compressibility .......... Thermal Exp @ 5000 psig. ' ................ 2454 13.03 1.09299 psig E-6 v/v/psi ( 10000 to 2454 psig ) V at 210 °F / V at 60 °F Differential Vaporization Data ( at 2454 psig and 210 °F ) Solution Gas/Oil Ratio ........................... Relative Oil Volume ............................... Density of Reservoir Fluid ...................... 1,184 1.813 0.6078 scf / bbl of residual oil at 60 °F bbl / bbl of residual oil at 60 °F grn~cc Reservoir Fluid Viscosity 0.225 cp at 2454 psig and 210 °F Se )arator Test Results Separator Conditions Formation Total Solution Tank Oil Gravity Volume Factor Gas/Oil Ratio ( °APl at 60 °F ) psig °F (A) (B) 100 70 1.661 1,078 44.9 (A) Barrels of saturated oil per barrel of stock tank oil at 60 °F. (B) Total standard cubic feet of gas per barrel of stock tank oil at 60 °F. Page I CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 General Well Information Company ......................................................... Phillips Petroleum Company Well Name ....................................................... NClU Well B1-ST APl Well Number .............................................. File Number ..................................................... RFL 980061 Date Sample Collected ..................................... 30-Nov-98 Sample Type .................................................... Separator Geographical Location ...................................... North Cook Inlet Unit Field ................................................................. Offshore, Alaska Well Description Formation ......................................................... Pool (or Zone) .................................................. Date Completed ............................................... Elevation .......................................................... Producing Interval ............................................ Total Depth ...................................................... Tubing Size ...................................................... Tubing Depth .................................................... Casing Size ...................................................... Casing Depth ................................................... Pressure Survey Data North Forelands * * ft 16080-16118 md ft 16650 md ft 4.5 in 10074 md ft 9.625 in 10376 md ft Data from Original Discovery Well Date ................................................................ Reservoir Pressure .......................................... Data at Sample Collection Date ................................................................. Reservoir Pressure ........................................... Reservoir Temperature ..................................... Pressure Tool ................................................... Flowing Bottom-Hole Pressure ......................... Flowing Tubing Pressure .................................. Sampled by ...................................................... 30-Nov-98 9300 210 * Halliburton psig psig oF psig psig * Data not forwarded to Core Laboratories. Page 2 CORE LABORATORIES Production Data Phillips Petroleum Company NClU Well BI-ST (North Forelands Fm.) RFL 980061 Data from Original Discovery Well Location ........................................................... Date ................................................................. Oil Gravity @ STP ............................................ Separator Pressure ........................................... Separator Temperature ..................................... Production Rates Gas ......................................................... Liquid ...................................................... Gas/Liquid Ratio ...................................... Separator Conditions Primary Separator Pressure ............................. Primary Separator Temperature ....................... Secondary Separator Pressure ......................... Secondary Separator Temperature ................... Primary Separator Gas Production Rate ........... 75 87 na na 1948.6 °APl psig oF Mscf/D STbbI/D scf/bbl psig oF psig oF Mscf/D Gas Factors - Field Values: Pressure Base ..................................... Temperature Base ............................... Compressibility Factor (Fpv) ................ Gas Gravity Factor (Fg) ....................... Laboratory Values: Pressure Base ......................................... Temperature Base ................................... Compressibility Factor (Fpv) .................... Gas Gravity Factor (Fg) ........................... 14.65 60 * 14.65 60 1.0113 1.0669 psia oF psia oF Primary Separator Liquid Rate .......................... Stock Tank Liquid Rate ..................................... Separator Gas / Separator Liquid Ratio ............ Separator Gas / Stock Tank Liquid Ratio .......... Separator Liquid / Stock Tank Liquid Ratio ....... 2123.9 2014.1 917.5 967.5 1.0545 bbl/D at 87 °F bbl/D at 60 °F scf/bbl scf/bbl bbl/bbl at 60 °F * Data not forwarded to Core Laboratories. Page 3 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 SUMMARY OF SAMPLES RECEIVED and Preliminary Checks of Sample Quality , Separator Gas Samples 'Cylinder Number K18228 l K335303' , K335302 K335308 Cylinder Size, liters 38 38 38 38 38 Sampling Conditions Pressure, psig 75 78 76 75 71 Temperature, °F 88 87 86 89 89 Opening Conditions Pressure, psig 81 83 76 78 74 Temperature, °F 70 70 70 70 70 Liquid Content, cc 0 0 0 0 0 Air Content, mol% 0.28 0.158 0.39 0.841 0.292 Separator Liquid Sa~nples ~ Cylinder Number DEN004 CAL31* CLH529 2040 2014 __I Cylinder Size, cc 500 500 500 500 500 Sampling Conditions Pressure, psig 78 78 78 78 78 Temperature, °F 87 87 87 87 87 Bubblepoint Check Pressure, psig 58 61 60 49 59 Temperature, °F 68 68 68 68 68 Water Content, cc 1 0 0 0 0 Sample Volume, cc 455 455 450 450 455 * These samples selected for recombination and further analysis. lOO lO o.1 0.01 ~' .,Cl. · ~ :3 · . ' '. ' ' ' : :~',.'C4nc4 " ' · · Theoretical Fquilibrium Raflo~~ ........ calculated at 78 psig and 87 °F . (dashed line) -350 -300 -250 Source: GPSA Engineering Data Book. -200 -150 -100 -50 0 50 100 150 Boiling Point, °F 200 Page 4 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fro.) RFL 980061 COMPOSITION OF PRIMARY STAGE SEPARATOR GAS (by Programmed-Temperature, Capillary Chromatography) Plant Liquid Component Mol % Products Density MW (GPM) (gm/cc) Hydrogen Sulfide 0.00 Carbon Dioxide 0.40 0.8172 44.010 Nitrogen 1.40 0.8086 28.013 Methane 62.30 0.2997 16.043 Ethane 17.29 4.594 0.3562 30.070 Propane 11.45 3.135 0.5070 44.097 iso-Butane 1.84 0.598 0.5629 58.123 n-Butane 3.21 1.006 0.5840 58.123 iso-Pentane 0.65 0.236 0.6244 72.150 n-Pentane 0.64 0.230 0,6311 72.150 Hexanes 0.37 0.143 0.6850 84.0 Heptanes 0.30 0.126 0.7220 96.0 Octanes 0.11 0.050 0.7450 107 Nonanes 0.03 0.015 0.7640 121 Decanes 0.01 0.005 0.7780 134 Undecanes 0.00 Dodecanes 0.00 ........... I 00.001 10.138 I Properties of Plus Fractions Liquid Liquid Component Mol % Density APl MW (gm/cc) Gravity Heptanes plus 0.45 0.7326 61.5 101.2 SAMPLING CONDITIONS 78 psig 87 °F Gas Cylinder K335303 Average Sample Properties Critical Pressure, psia ................................ 656.3 Critical Temperature, °R .............................. 446.4 Average Molecular Weight ...........................25.44 Calculated Gas Gravity ( air = 1.000 ) ......... 0.878 at t4.65 psia and 60 °F Heating Value, Btu/scf dry gas* Gross ........................................................ 1481 Note: Component properties assigned from literature. * ref: Gas Producers & Suppliers Association (GPSA) Engineering Data Book Page 5 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 98~X)61 COMPOSITION OF PRIMARY STAGE SEPARATOR LIQUID (by Low Temperature Distillation, Capillary Chromatog~hy) Component Hydrogen Sulfide Carbon Dioxide Nitrogen Methane Ethane Propane iso-Butane n-Butane iso-Pentane n-Pentane Hexanes Heptanes Octanes Nonanes Decanes Undecanes Dodecanes Tridecanes Tetradecanes Pentadecanes Hexadecanes Heptadecanes Octadecanes Nonadecanes Eicosanes Heneicosanes Docosanes Tricosanes Tetracosanes Pentacosanes Hexacosanes Heptacosanes Octacosanes Nonacosanes Triacontanes plus Totals ........... Mol % Wt % I Density I ~w I o.oo o.oo I (gm/cc) I I 0.04 0.01 0.8172 44.0101 0.00 0.00 1.91 0.23 0.2997 16.043 3.10 0.70 0.3562 30.070 6.66 2.21 0.5070 44.097 2.31 1.01 0.5629 58.123 5.04 2.20 0.5840 58.123 3.18 1.73 0.6244 72.150 4.53 2.46 0.6311 72.150 8.48 5.36 0.6850 84.0 8.24 5.95 0.7220 96.0 13.32 10.71 0.7450 107 6.65 6.06 0.7640 121 5.47 5.52 0.7780 134 4.17 4.61 0.7890 147 3.45 4.18 0.8000 161 3.27 4.31 0.8110 175 2.71 3.88 0.8220 190 2.34 3.63 0.8320 206 1.83 3.06 0.8390 222 1.63 2.91 0.8470 237 1.56 2.95 0.8520 251 1.25 2.47 0.8570 263 1.14 2.36 0.8620 275 0.91 1.99 0.8670 291 0.83 1.91 0.8720 305 0.73 1.75 0.8770 318 0.63 1.57 0.8810 33t 0.63 1.64 0.8850 345 0.46 1.24 0.8890 359 0.45 1.27 0.8930 374 0.40 1.17 0.8960 388 0.38 1.09 0.8990 402 2.32 7.86 0.9100 450 I ~°°.°°1 ~oo.ool SAMPLING CONDITIONS 78 psig 87 °F Liquid Cylinder CAL31 Average Sample Properties Average Molecular Weight ........................... Calculated Density at 0 psig and 60 °F ........ 132.86 0.7661 Plus Fraction Properties of Plus Fractions I I I Liquid I Liquid I I Mol% I wt% IDensityI APlI MW I I I (gm/cc) I Gravity I Heptanes plus 64.75 84.09 0.8135 42.3 173 Undecanes plus 31.07 55.85 0.6498 34.8 239 Pentadecanes plus 17.47 38.87 0.8712 30.8 295 Eicosanes plus 8.86 23.85 0.8890 27.5 357 Pentacosanes plus 4.62 14.27 0.9017 25.3 410 Triacontanes plus 2.32 7.86 0.9100 23.8 450 Page 6 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 WELLSTREAM RECOMBINATION CALCULATION (based on f~d production data) Conditions for Recombination Calculations Pdmary Stage at 75 psig and 87 °F Field Gas Rate Correction Factors- Gas Gravity (air=l.000) ................................................. ** Gas Gravity Factor, Fg .................................................. ** Gas Deviation Factor, Z ................................................ ** Super Compressibility Factor, Fpv ................................ ** Pressure Base, psia ..................................................... 14.650 Laboratory Gas Rate Correction Factors - Gas Gravity (air=l.000) ................................................. 0.878 Gas Gravity Factor, Fg (not applied) .............................. 1.0669 Gas Deviation Factor*, Z ............................................... 0.978 Supercompressibility Factor, Fpv (not applied) .............. 1.0113 Pressure Base, psia ..................................................... 14.650 Laboratory Liquid Rate Correction Factors. Liquid Volume Factor, S~bbl/STbbl @ 60 °F ................. 1.0545 Bitumen, Sediment & Water (BS&W) Factor ................ 1.000 Field Measured Rates and Ratios. Primary Stage Gas Flow Rate, Mscf/D ....................... 1948.6 Stock Tank Liquid Flow Rate, bbl/D ............................ 2014 Field Gas / Oil Ratio, scf/STbbl .................................. 987.48 Recombination Rates and Ratios - Pdmary Stage Gas Flow Rate, Mscf/D ....................... 1948.6 Primary Stage Liquid Flow Rate, bbl/D ........................2124 Pdmary Stage Gas / Oil Ratio, scf/S~bbl ..................... 917.48 Stock Tank Liquid Flow Rate, bbl/D ............................ 2014 Corrected Gas / Oil Ratio, scf/STbbl .......................... 967.48 Wellstream Recombination Ratio mol~mol .......................... 1.2110 * From: Standing, M.B., '¥olumetric and Phase Behavior of Oil Field Hydrocarbon Systems'.', SPE (Dallas),1977, 8th Edition, Appendix II. Data not supplied to Core Laboratories Page 7 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 COMPOSITION OF RECOMBINED WELLSTREAM (from calculated recombination of separator products) Liquid Component Mol % Wt% Density MW (gm/cc) Hydrogen Sulfide 0.00 0.00 Carbon Dioxide' 0.24 0.14 0.8172 44.010 Nitrogen 0.77 0.29 0.8086 28.013 Methane 34.98 7.58 0.2997 16.043 Ethane 10.87 4.41 0.3562 30.070 Propane 9.28 5.53 0.5070 44.097 iso-Butane 2.05 1.61 0.5829 58.123 n-B utane 4.04 3.17 0.5840 58.123 iso-Pentane 1.79 1.74 0.6244 72.150 n-Pentane 2.40 2.34 0.6311 72.150 Hexanes 4.04 4.58 0.6850 84.0 Heptanes 3.89 5.04 0.7220 96.0 Octanes 6.08 8.80 0.7450 107 Nonanes 3.02 4.94 0.7640 121 Decanes 2.48 4.49 0.7780 1 34 U ndecanes 1.89 3.75 0.7890 147 Dodecanes 1.56 3.39 0.8000 161 Tridecanes 1.48 3.50 0.8110 175 Tetradecanes 1.23 3.16 0.8220 190 Pentadecanes 1.06 2.95 0.8320 206 Hexadecanes 0.83 2.49 0.8390 222 Heptadecanes 0.74 2.37 0.6470 237 Octadecanes 0.71 2.41 0.8520 251 Nonadecanes 0.57 2.02 0.8570 263 Eicosanes 0.52 1.93 0.8620 275 Heneicosanes 0.41 1.61 0.8670 291 Docosanes 0.38 1.57 0.8720 305 Tdcosanes 0.33 1.42 0.8770 318 Tetracosanes 0.28 1.25 0.8810 331 Pentacosanes 0.28 1.30 0.8850 345 Hexacosanes 0.21 1.02 0.8890 359 Heptacosanes 0,20 1.01 0.8930 374 Octacosanes 0.18 0.94 0.8960 388 Nonacosanes 0.16 0.87 0.8990 402 Triacontanes plus 1.05 6.38 0.9100 450 To a,= ........... I 100'001 00.001 RECOMBINATION CONDITIONS 75 psig 87 °F Recombination Parametem Primary Stage Gas / Oil Ratio, scf/S~bbl at recombination conditions .......................917.48 Wellstream Recombination Ratio moles gas / mole liquid .............................. 1.2110 Average Wellstream Properties Average Molecular Weight ........................... Calculated Density at 0 psig and 60 °F ........ 74.0 0.6453 Properties of Plus Fractions Liquid Liquid Plus Fraction Mol% Wt% Density APl MW (gm/cc) Gravity Heptanes plus 29.54 68.61 0.8131 42.4 172 Undecanes plus 14.07 45.34 0.8498 34.8 239 Pentadecanes plus 7.91 31.54 0.8712 30.8 295 Eicosanes plus 4.00 19.30 0.8890 27.5 357 Pentacosanes plus 2.08 11.52 0.9017 25.3 410 Triacontanes plus 1.05 6.38 0.9100 23.8 450 Page 8 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fro.) RFL 980061 VOLUMETRIC DATA (at 210 °F) Saturation Pressure (Psat) .............................. 2454 psig Density at Psat ............................................... 0.6078 gm/cc Thermal Exp @ 5000 psig ............................... 1.09299 V at 210 °F / V at 60 °F AVERAGE SINGLE-PHASE COMPRESSIBILITIES Pressure Range psig Single-Phase Compressibility v/v/psi 10000 8500 7000 5500 40O0 to to to to to 85OO 7000 5500 400O 2454 9.27 E-6 10.70 E -6 12.53 E -6 15.23 E -6 21.38 E-6 Page 9 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 PRESSURE-VOLUME RELATIONS (at 210 °F) Pressure psig Relative Volume (A) Y-Function (B) Density gm/cc 10000 0.9017 9500 0.9057 9000 0.9099 8500 0.9142 8000 0.9189 7500 0.9238 7000 0.9289 6500 0.9344 6000 0.9402 5500 0.9464 5000 0.9530 4500 0.9602 4000 0.9680 3500 0.9767 3000 0.9865 2900 0.9887 2800 0.9909 2700 0.9933 2600 0.9958 2500 0.9985 b~2454 1.0000 2446 1.0013 2434 1.0034 2428 1.0044 2420 1.0058 2389 1.0112 2334 1.0215 2240 1.0407 2115 1.0702 1978 1.1086 1809 1.1673 1632 1.2466 1435 1.3652 1207 1.5641 941 1.9452 710 2.5445 512 3.5288 2.268 2.199 2.114 2.024 1.925 1.809 1.675 1.558 1.458 0.6741 0.6711 0.6681 0.6649 0.6615 0.6580 0.6544 0.6505 0.6465 0.6423 0.6378 0.6330 0.6279 0.6224 0.6162 0.6148 0.6134 0.6120 0.6104 0.6087 0.6078 (A) Relative Volume: VNsat or volume at indicated pressure per volume at saturation pressure. (B) Where: Y-Function = (Psat - P) (Pabs) * (VNsat - 1) Page 10 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fro.) RFL 980061 1.0000 RELATIVE VOLUME ( at 210 °F ) 0.9~XI 0.9800 0.9700 0.9600 0.9500 0.9400 0.9300 0.9200 0.9100 0.9000 2000 3000 4000 5000 6000 7000 8000 9000 Pressure, psig 10000 Relative Volume Expression: y= a + b (Xd)^i + c (Xd)^j + d Iog(Xd)^k where: a= 1.02521e+ O0 i= 0.910 b= -2.66609e- 02 j= 1.909 c= 1.44636e- 03 k= 0.880 d= -7.55347e- 02 Note: Xd (dimensionless 'X') = Pi / Psat, psig Confidence level: 99 % Confidence interval: +/- 0.00004 'r squared': .999997 LEGEND o Laboratory Data ........ Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Current Reservoir Pressure: 9300 psig Pressure-Volume Relations Figure CORE LABORATORIES 5.00 Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) 990014 Y-FUNCTION ( at 210 °F ) 4.50 4.00 3.50 o 3.00 ~-, >.- 2.50 2.00 1.50 1.00 50O 750 1000 1250 1500 1750 2000 2250 Pressure, psig 2500 Y-function Expression: y= a + b (Xd)^i a= 1.19946e+00 i= 1.000 b= 1.24008e+ 00 Note: Xd (dimensionless 'X') = Pi/Psat, psig Confidence level: 99 % Confidence interval: +/- 0.01242 'r squared': .999111 LEGEND o Laboratory Data Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Current Reservoir Pressure: 9300 psig Pressure-Volume Relations ~_ Figure A-2 CORE LABORATORIES Phillips Petroleum Company NCIU Well B1-ST (North Forelands Fm.) RFL 980061 DIFFERENTIAL VAPORIZATION (at 210 °F) Pressure psig Solution Gas/Oil Ratio Rsd (A) Relative Oil Volume Bod (B) Relative Total Volume Btd (C) Oil Density gm/cc Deviation Factor Z Gas Formation Volume Factor (D) Incremental Gas Gravity (Air=1.000) b))2454 1,184 1.813 1.813 0.6078 2200 1,049 1.740 1.902 0.6189 0.792 1950 928 1.675 2.027 0.6294 0.803 1700 816 1.616 2.204 0.6396 0.815 1450 712 1.562 2.458 0.6496 0.827 1200 616 1.512 2.835 0.6593 0.841 950 524 1.465 3.436 0.6689 0.857 700 434 1.417 4.506 0.6787 0.875 450 339 1.365 6.853 0.6894 0.898 235 242 1.308 13.015 0.7010 0.923 138 186 1.272 21.920 0.7083 0.940 0 0 1.082 0.7663 @60°F =1.000 O.OO675 0.00772 0.00897 O.O1O67 0.01308 0.01677 0.02312 O.O3647 0.06982 0.11618 0.859 0.851 0.844 0.841 0.847 0.867 0.914 1 .OO7 1.165 1.289 1.783 Gravity of Residual Oil = 39.0 °APl at 60 °F Density of Residual Oil = 0.8292 gm/cc at 60 °F (A) Cubic Feet of gas at 14.65 psia and 60 °F per Barrel of residual oil at 60 °F. (B) Barrel of oil at indicated pressure and temperature per Barrel of residual oil at 60 °F. (C) Barrels of oil plus liberated gas at indicated pressure and temperature per Barrel of residual oil at 60 °F. (D) Cubic Feet of gas at indicated pressure and temperature per Cubic Feet at 14.65 psia and 60 °F. , Page 11 CORE LABORATORIES 2.00 1.80 .70 1.60 1.50 1.40' 1.30 1.20 1.10 1.00 Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 RELATIVE OIL VOLUME ( at 210 °F ) . ,, .. .. ................................. 7 ......... 1.90 , ./ .... Single-Phase ...... -~ ...... ~ '~.8o--% ........................................................... - ........................................................ ..................... 2000 4000 ~000 8~0 ~00~ ~r~sum, psi~ .............. '~ I , ~ ~ ~ 0 250 500 750 1000 1250 1500 1750 2000 2250 Pressure, psig 2500 Relative Oil Volume Expression: y= a + b (Xi)"i + c (Xi)^j a= 1.08188e+ 00 b= 3.76209e- 02 c= 2.67885e- 09 Note: Xi (incremental 'X') = pressure, psig Confidence level: Confidence interval: 'r squared': i: 0.328 j= 2.348 99 % +/- 0.00042 .999995 LEGEND o Laboratory Data ......... Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Differential Vaporization .. Figure B-1 CORE LABORATORIES o 1200 1100 1000 900 800 700 Phillips Petroleum Company NClU Well BI-ST (North Forelands Fm.) RFL 980061 SOLUTION GAS/OIL RATIO ( scf/bbl at 210 OF ) o 600 5OO 400 300 200 100 250 500 750 1000 1250 1500 1750 2000 2250 Pressure, psig 2500 Solution Gas/Oil Ratio Expression: y= a + b (XJ)^i + c (Xi)^j where: a= -5.56406e- 01 b= 1.67730e+ 01 c= 6.98984e- 06 i= 0.488 j= 2.297 Note: Xi (incremental 'X') = pressure, psig Confidence level: Confidence interval: 'r squared': 99 % +/- 0.82 scf/bbl .999994 LEGEND o Laboratory Data ............ Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Differential Vaporization Figure B-2 CORE LABORATORIES 0.800 0.780 0.760 0.740 0.720 0.700 0.680 0.660 Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 0.640 0.620 0.600 OIL DENSITY ( gm/cc at 210 °F ) ........................................................ .~, 0.680 I - ~' 0.660 ............ -- I ................................................ ~ 0.640~ , J -. ~ 0.620 ..................................................... o~ I Single-Phase ]- 0.600I ~, 2000 4000 6000 8000 10000 \ Pressure, psig ........................................................ ..... , , ,, , ,, , 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 Pressure, psig Oil Phase Density Expression: y= a + b (Xd)^i + c (Xd)^j where: a= 7.66305e- 01 b= -1.03869e- 01 c= -5.45955e- 02 Note: Xd (dimensionless 'X') = Pi / Psat, psig i= 0.206 j= 1.598 Confidence level: Confidence interval: 'r squared': 99 % +/- 0.00015 gm/cc .999986 LEGEND o Laboratory Data ........ Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Differential Vaporization Figure B-3 CORE LABORATORIES 1.80 1.70 1.60 1.50 1.4O 1.30 1.20 1.10 1.00 0.90 0.80 Phillips Petroleum Company NClU Well B1-ST (North Forelands Fm.) RFL 980061 GAS GRAVITY ( at 210 °F ) 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 Pressure, psig Gas Gravity Expression: y= a + b (Xd)^i + c (Xd)^j + d (Xd)^k where: a= 1.78272e+ 00 i= 0.657 b= -6.94099e+ 00 j= 0.846 c= 6.32596e+00 k= 2.479 d= -3.02764e- 01 Note: Xd (dimensionless 'X') = Pi / Psat, psig Confidence level: 99 % Confidence interval: +/- 0.0054 'r squared': .999683 LEGEND o Laboratory Data ......... Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Differential Vaporization Figure B-4 CORE LABORATORIES 0.980 0.940 0.920 0.900 0.880 0.860 0.820 0.800 0.780 Phillips Petroleum Company NClU Well BI-ST (North Forelands Fm.) RFL 980061 DEVIATION FACTOR, Z ( at 210 °F ) 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 Pressure, psig Deviation Factor Expression: y= a + b (Xd)^i where: a= 1.00020e+ 00 b= -2.18376e- 01 Note: Xd (dimensionless 'X') = Pi / Psat, psig Confidence level: Confidence interval: 'r squared': i= 0.446 99 % +/- 0.0038 .997239 LEGEND o Laboratory Data ........... Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Differential Vaporization Figure B-5 CORE LABORATORIES Pressure psig Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fro.) RFL 980061 RESERVOIR FLUID VISCOSITY (at 210 °F) Oil Viscosity cp 10000 0.328 900O 0.315 8000 0.301 7500 0.294 6500 0.281 55O0 0.267 4500 0.254 3300 0.237 3000 0.233 2500 0.226 b~2454 0.225 2200 0.236 1950 0.249 1700 0.263 1450 0.279 1200 0.298 950 0.320 700 0.348 450 0.386 235 0.436 138 0.473 0 0.802 Gas Viscosity * Oil/Gas Viscosity Ratio 0.0198 11.9 0.0184 13.6 0.0171 15.4 0.0161 17.4 0.0152 19.6 0.0144 22.3 0.0136 25.7 0.0127 30.5 0.0117 37.4 0.0111 42.7 * Gas Viscosity data calculated from correlation of Lee A.L., Gonzalez M.H., and Eakin B.E., "The Viscosity of Natural Gases", Journal of Petroleum Technology, August, 1966, pp. 997-1000. Page 12 CORE LABORATORIES 0.85 0.75 0.70 0.65 0.60 0.55 0.50 Phillips Petroleum Company NCIU Well BJ-ST (North Forelands Fro.) RFL 980061 0.45 0.40 0.35 0.30 0.25 0.20 RESERVOIR FLUID VISCOSITY ( cp at 210 °F ) 0.0200 -- ~- 0.0180 -- 8 ...................... i .~.~ > 0.0160 ..... ~-~ ~'~ ....................... .,= 0.0140 _ c~ 0.0120 ~ -~ Calculat~Gas~scosi~ ~ 0.0100 0 500 1000 15~ 2000 2~ ......................... Pr~sure, ps~ ~ ......................................................... , , , , , , , , ~ -1 Calculated Gas Viscosity ~ 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 Pressure, psig Oil Viscosity Expression: y= a + b (×d)^i + c (Xd)^j where: a= 8.02188e- 01 b= 8.94216e- 03 c= -5.86284e- 01 Note: Xd (dimensionless 'X') = Pi / Psat, psig i= 1.171 j= 0.200 Confidence level: Confidence interval: 'r squared': 99 % +/- 0.0034 cp .999784 LEGEND o Laboratory Data ........ Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Rolling-Ball Viscosity Figure C-1 CORE LABORATORIES 0.400 Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fro.) RFL 980061 SINGLE-PHASE FLUID VISCOSITY ( cp at 210 °F ) I ........................... ............................................. 0.380 0.360 0.320 0.300 0.280 0.260 0.240 0.220 O.200 2000 3000 4000 5000 6000 7000 8000 9000 Pressure, psig 10000 Single-Phase Viscosity Expression: y= a + b (dX)^i where: a= 2.24847e- 01 b= 1.72270e- 05 Note: dX (delta 'X') = I Psat - Pi I, psig Confidence level: Confidence interval: 'r squared': i= O.974 99 % +/- 0.0005 cp .999868 LEGEND o Laboratory Data Confidence Limits Analytical Expression Saturation Pressure: 2454 psig Rolling-Ball Viscosity Figure C-2 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 SEPARATOR FLASH ANALYSIS Flash Gas/Oil Gas/Oil Stock Tank Formation Separator Specific Oil Phase Conditions Ratio Ratio Oil Gravity Volume Volume Gravity of Density ( scf/bbl ) ( scf/STbbl ) at 60 °F Factor Factor Flashed Gas ( gm/cc ) psig I °F (A) (B) ( °APl ) Bofb (C) (D) ( AJr=l.000 ) 2454 210 0.6078 100 70 885 951 1.075 0.820 * 0.7816 0 70 126 127 44.9 1.661 1.005 1.417 0.7970 Rsfb= 1,078 * Collected and analyzed in the laboratoq/by gas chromatography. (A) Cubic Feet of gas at 14.65 psia and 60 °F per Barrel of oil at indicated pressure and temperature. (B) Cubic Feet of gas at 14.65 psia and 60 °F per Barrel of Stock Tank Oil at 60 °F. (C) Barrels of saturated oil at 2454 psig and 210 °F per Barrel of Stock Tank Oil at 60 °F. (D) Barrels of oil at indicated pressure and temperature per Barrel of Stock Tank Oil at 60 °F. Page 13 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 o 1200 1100 1000 90O 800 700 600 500 400 3OO 200 100 SOLUTION GAS/OIL RATIO ( scf/STbbl ) ,, ...... Saturation Pressure [-- ........................ ~ .......................... ~7 .............................................. ........... , , ,. . ..... , , ,, 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 Pressure, psig LEGEND Differential Vaporization 100 psig at 70 °F DV Adjusted to Separator Figure D-1 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fro.) RFL 980061 FORMATION VOLUME FACTOR 1,80 1.70 1.60 1.50 1.40 1.30 1.20 1.10 1.00 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 Pressure, psig 10000 LEGEND Differential Vaporization 100 psig at 70 °F DV Adjusted to Separator Figure D-2 CORE LABORATORIES Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fro.) RFL 980061 Composition of Primary Stage Separator Gas ( From Chromatographic Technique ) Liq Component Mol % GPM MW Dens (gm/cc) Hydrogen Sulfide 0.00 Carbon Dioxide 0.43 44.010 .8172 Nitrogen 1.54 28.013 .8086 Methane 66.42 16.043 .2997 Ethane 16.97 4.509 30.070 .3562 Propane 9.80 2.683 44.097 .5070 iso-Butane 1.38 .449 58.123 .5629 n-Butane 2.28 .714 58.123 .5840 iso-Pentane 0.41 .149 72.150 .6244 n-Pentane 0.39 .140 72.150 .6311 Hexanes 0.21 .081 84.000 .6850 Heptanes 0.14 .059 96.000 .7220 Octanes 0.03 .014 107.00 .7450 Nonanes Trace Decanes Trace Undecanes Trace Dodecanes Trace To~a,s ........... I 100.00 1 8.798 I I Properties of Plus Fractions Liq Component Mol % MW Dens APl (gm/cc) Gravity Heptanes plus 0.17 97.9 0.729 62.4 Sampling Conditions 100 psig 70 OF Sample Characteristics This is Core Lab sample number 306 Cdtical Pressure (psia) .............................. 660.4 Critical Temperature (°R) ........................... 429.6 Average Molecular Weight ......................... 23.75 Calculated Gas Gravity (air = 1.000) ......... 0.820 Gas Gravity Factor, Fg ................................................ 1.1043 Super Compressibility Factor, Fpv at sampling conditions ............................. 1.0143 Gas Z-Factor at sampling conditions *. .......................... 0.972 at 14.65 psia and 60 °F Heating Value, Btu/scf dry gas Gross ...................................................... 1383 * From: Standing, M.B., '¥olumetdc and Phase Behavior of Oil Field Hydrocarbon Systems", SPE (Dallas), 1977, 8th Edition, Appendix I1. Page 14 CORE LABORATORIES b)) Pressure psig 10000 9500 9000 8500 8000 7500 7OOO 6500 6000 5500 5000 4500 4000 3500 3000 2900 2800 2700 2600 2500 2454 2200 1950 1700 1450 1200 950 700 450 235 Phillips Petroleum Company NCIU Well BI-ST (North Forelands Fm.) RFL 980061 DIFFERENTIAL VAPORIZATION ADJUSTED TO SEPARATOR CONDITIONS* Solution Gas/Oil Ratio Rs (A) Formation Volume Factor Bo (B) Gas Formation Volume Factor (C) Oil Density gm/cc 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 1078 955 741 646 558 474 391 304 215 1.498 0.6741 1.504 0.6711 1.511 0.6681 1.519 0.6649 1.526 0.6615 1.534 0.6580 1.543 0.6544 1.552 0.6505 1.562 0.6465 1.572 0.6423 1.583 0.6378 1.595 0.6330 1.608 0.6279 1.622 0.6224 1.639 0.6162 1.642 0.6148 1.646 0.6134 1.650 0.6120 1.654 0.6104 1.658 0.6087 1.661 0.6078 1.595 ' 0.00675 0.6189 1.535 0.00772 0.6294 1.481 0.00897 0.6396 1.432 0.01067 0.6496 1.386 0.01308 0.6593 1.342 0.01677 0.6689 1.299 0.02312 0.6787 1.251 0.03647 0.6894 1.199 0.06982 0.7010 Oil/Gas Viscosity Ratio 11.9 13.6 15.4 17.4 19.6 22.3 25.7 30.5 37.4 *Separator Conditions First Stage 100 psig at 70 °F Stock Tank 0 psig at 70 °F (A) Cubic Feet of gas at 14.65 psia and 60 °F per Barrel of Stock Tank Oil at 60 °F. (B) Barrel of oil at indicated pressure and temperature per Barrel of Stock Tank Oil at 60 °F. (C) Cubic Feet of gas at indicated pressure and temperature per Cubic Feet at 14.65 psia and 60 °F. Page 15 CORE LABORATORIES NOMENCLATURE AND EQ UA TIONS APPENDIX A RFL 980061 EXTENSIONS TO ANALYTICAL EQUATIONS Appendix A Sin~lle-Phase Relations: Average Compressibility - '1 ~v I rv~-rv~4 v ~P rv~ P~ - P~.~ forP~ <~,_, (al.l) Two-Phase Relations: Constant Mass Expansion Relative Volume - fyi=vi- =14 for 0 < P~ <P~ Differential Relative Total Volume - (R~,., -R,~).~g for 0 < P/<P~ Differential Gas Formation Volume Factor - for 0< P/<g Formation Volume Factor (adjusted for surface separation) - for 0< P~ < P~ Solution Gas/Oil Ratio (adjusted for surface separation) - R~ = R,z~ - ( R,,t~ - R~,~ ).fl°'~ for 0<P~ < P, (al 2) (al 3) (al .4) (al.5) (al.6) Page A'I B/a~ (2/1 ,~t~ EXTENSIONS TO ANALYTICAL EQUATIONS Appendix A DEFINITION OF TERMS Definition of Variables - C~ L P T Z Formation Volume Factor Coe~cient of Isothermal Compressibility Conversion Constant for gas to liquid volmnc (c.g., $.61459 cf/bbl) Limits of Confidcnce,± Relative Volume (from constant mass expansion) Solution Gas/Oil Ratio Temperature Volume Y-function (from constant mass expansion) Gas Deviation Factor Definition of Subscripts - in absolute units at bubble point pressure from differential vaporization analysis from flash separation test (separator test) gas phase any discreet point oil phase at reservoir conditions in solution total at working conditions at base conditions Page A-2 B laa~ O~l 5ystera~ WHOLE-OIL GAS CHROMA TOGRAM OF FLASH RESIDUE (.fingerprinO APPENDIX B RFL 980061 80000 , I Intermediates J I 60000 - 20000 - i I !i ii 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10 Elution '~me, minutes 20000 I ,sopren,ods J > 15000 - I 5000 - :,~' ' ,,, !~,'~ ~!-~ 'i''t '~'L: '~,,'!~"~'....v,',.~..,! ..,.,':.. ~, .:Vt.!!'~__...~..,...~:~',._.~'.,..-.?-...~.....~' .... .-.,:. ~ n i ,~""~;?~"2'~''-'' ~' "' I "" "'' "1 z_., I '~" .... I '~' I ' I I I ! ~' " 20 i " 10 ~2 ~4 ! Elution Time minutes : Phillips Petroleum Company WHOLE OIL CHROMATOGRAM Well B'I-ST (North Forelands Fm,) Separator Liquid Flash Residue RFL 980061 Appendix B I ,I J I I I I I I I I I I I I I 40000 36000 32000 28000 24000 20000 16000 12000 8000 4000 0 .4000 0 4 8 12 16 20 24 28 Elution Time, minutes 32 36 40 CORE LABORATORIES Geologic Tops Rock Unit: Sunfish SS. N.Forelands SS. for NCIU B-lst 15,016' 16,037' Oil Shows: Weak show in the excellent shows 16,118' (tested Sunfish interval at 15,020' in the Nort.h Forelands interval 2,150 BOPD). 15,050' and from 16,080 Zones of Abnormal Pressure: North Forelands SS. SCAN WELL TEST Phillips Petroleum Well: NCIU BI-ST Tyonek Platform Cook Inlet Production Test # 1 Nov. 29m to Dec. 1st 1998 ~'~l '"i]gu RTON Oi'N'~, L L I B U RTON ENERGY SERVICES TABLE OF CONTENTS PHILLIPS PETROLEUM NCIU BI-ST SECTION I ...................................................... Sequence of Operations SECTION II ..................................................... Nomenclature SECTION III .................................................... SECTION IV ................................................... SECTION V .................................................... Method of Gas Rate Measurement and Calibration including Flow Meter Calibration Method Used for Calculation Oil Rates Flow Test Results SECTION VI ................................................... Plots SECTION VII .......................................... Sample Report SECTION VIII .......................................... ASCII Disks Oi'IZJALLI B U RTO N ENERGY SERVICES DISCLAIMER These calculations are based on certain data, assumptions and applied mathematical methods. Inaccurate well data, changing well conditions, tolerance variations of mechanical components, mechanical malfunctions and other factors may affect these calculations. Halliburton Energy Services, Alaska makes no warranty, express or implied, as to the accuracy of the data, calculations or opinions expressed herein, or of merchantability or fitness for a particular purpose. User agrees by its purpose thereof that user will release, indemnify and costs related there to arising out of or in conjunction with such use and incurred by user or third parties, whether due to negligence or otherwise. I I Il II I I I SEQUENCE OF OPERATIONS III I I II I I I COMPANY: Phillips Petroleum FIELD: Cook Inlet LEASE: Tyone~ WELL/t: NCtU 3 BJ~T TICKETS: 397997 ~ 93 I r I~ ~ I I I 2~-Nov-98 8:I5 Bray, Z~d~es D~a~ An~ra~e ~or Kenai. David Bray, Kris K~dies .., , ~:45 , ~rN~, Kenai, Travel to Kenai Air , , , , 9:~ , , ~rNed K~ai~r, ch~k in for 10:00am flight t0:00 ........ ~~ K~ai ~r, Traveled to Phillips Tyonek Plaffo~ ,,, 10:30 ........... ~rrN~ Phjlli~ Tyq~ Plaffq~, Check in ~th Phillips Company Man ' ' 13:00 [' Saf~ M~tin~ Held~th Phillips Personnel, Hallibu~on Personnel, ...... Po~ Perso~el con~rnin~ Boom Installation. , 16:~ Welder Finish~ Pad-e~e Installation. , , t6:30, , ' ~, " Order~ ~ T~iler~ of e~uipmen{ ~om Anchorage for 7:00am arrival at O~K " , , ' ' 17:~0 , ~ {b m~ ~uipm,ent from the areas n~ded for Testin~ Equipment. , , '26:00 , , ~,r~ s~nds d~n f~ night. 24-Nov-~B 6~" Confer~ Call ~ Phillips Houston O~ce concernin~ the Test on B-1 ST ' ' 8:~ :~ay, z~d~es, ~uniphin, LX~ Tommy Duniph~, Bill ~yon Arriv~ Kenai Air. , , 9:00 .... ~pa~ed Keoai Air, Tmvel~ to Phillips Tyonek pl~ffo~ 9:30 ~ Phillips ~o~k Platform. ' 9:30 ' , ' Saf~ M~ing Held with Phillips Personnel, ~llibu~on Personnel, ,, 10:~ S~ B~m ln~lJation. = , , ,, ~ 1t:30 Finish~ Boom tn~allation. ' ' ~2:30 ' ' ' Wo~ B~ Arrived Rig with ~ bbl Tanks, Surge Tank, Piping, Hoses, ,, ,, , V~i~l ~s ~r~b~. ", 13:oo r ", , ' , ~ta~ea unt~adigg Work Boat, , 15:00 ,, , Fin~s~,~ HES Equ~ment ~oad, Wa~ing on Crane, Availability. , 16:00 ,, Order~ 3 Trailem of ~uipment from Anchorage for 8:00am arrNal at OSK ,, , 15:00 Finish~ Sp~ffing E~u,~pment ,, lb:OO ' sti~ ~aitip¢ on Crane Availability. , 25-Nov-98 0:0d' ' ~ray, ,Z~i~s,, ~u~phi~, LYon ,, ~a~ to Spot E~uipment. , , , , .... 4:00 Sql, Tyb~,rski, Tucks, ,, Finish~ ~o~ng Equipment , , ' , 6:~0 H~ton , , Conf~ Call with Phillips Houston b~ce con~nin~ the Test on B-1 ST , , , , phillips HO~ton ve~ up~t because Hallibu~on Well Test Equipment was , ~t on board rigg~ up as the ~11 would be ready for t~t on 26th a.m. A~s~ Phillips Company Man of our notifi,~tion date of Nov. l~h. , ..... This will ~ addr~s~ in CPI. ' 6:45 ..... , DePa~ed Ancho[~e for Kenai. Doug Sco~, L0nny Tucker, Steve T~bumki,, Marc H~ton. '2~Nov-98 , 7:15 ,' ' ~rJv~ ~en'~, Tmv~ to Kenai Air , ,, , , 10:00 ~epa~ed Kenai ~r, Traveled to Phillips, Tyonek Plaffo~ , ,. , , , 10:30 , , , ~ri~, ~illips Tyog~ Platform. , , , , 1~:~0 .... S~e~ M~ting ~1¢ ~h Hailibu~on Personnel on Ri~ up Safety. Page 1 ............. SEQUENC~ bF OPERATIONS ' I I I I II I I I I COMPANY: FIELD: Cook Phillips inlet Petroleum LEASE: Tyonek N WELL#: NClU 3 B1-ST TICKET#: 397997,92,93 I I I I I I I I 13:30 .... Work Boat Arrive~, Rig with remaining Halliburton Equipm~t. , ..... 14:00 started unto~,dJng Work Boat. . , '" 1~:00 , , Finished HES Equipment offload. Started Rig-up. ,, , 23:00 Crew stands down for night. , , 26-Nov-98' '1:30 ' ' Welt NClU B-'I ST is ready for Tes, ting. , , ' ' 6:00 ....... Safety Meeting Held with Halliburton PersonneJ on Rig t~p Safety. ~ , , ',", ' '6:30 .... COntinue R~ up. ;~3:00 C,r, ,e~v, stands dow, n ,for night. , 27-Nc~v,'98 6:00 Bra~/,S~'c~tt, kiewston,,Tyt~UrSl< '~8 Hold safety meeting and go over the days events Zeddies,,Tucker, Lyon,Tomm 18 Rig up ,t,o the flare , ,, 1 ~':(~0 ,, , Run air to scrubbe, r a'nd p-tank, add high level to p-tank 11:25 FunctiOn test all controls on gas scrubber and p-tank ' , 14:26 .,,' ' ' ,,' , , Rig up, pr,essUre P°!~;[s on the data header ,for chemical iniection, pressure recorder and scan 22:00 Run air to the Wilden pump ..... 28'-NoV-98 0:00 Bray,'.S,c(~t~-e~, ~on,Tyburski Prepare for pr, ess, ur,e test .... , , 1:00 Zeddies, ,Tucker.,,Lyon,Tomm, ,y , Function'test, safety, system, plug in ,heat trace panel, wrong panel ,unplugged waiting on electrician ..... 2:00 Brown, Knight Heater Honeywell controller burned out, waiting on new one 3:00 , Safety Meeting "' 4:00' Start hi,gh pressure test on the flow line fr~)m the ,well to the choke manifold , , , 4:23 High pressure test COmplete, test safety valve , 5:00' , , Break down line, ,s, to,,pull safety Valve , , , 6:00 ' , ...... Continue to work on safety valve .... ,. 7:00 .... safe/va't~e ,re,,m, oved, inside pin sheared when tested prepare to retest surface ,, , flow lines to the choke manifold , , 7:22 ' , . , Pressur~ test co~np'l~te prepare to do the gas scrubber ..... 8:05 .... Gas scrubber test comp,lete prepare to do the main ,sep~'rator, all fluid drair~ed back ........ t~rough ~,Pol'to , , 8i~5 ', , Main separator ready to pressure test , 9:20 Begin to test main s, eparator , 9:30 , Main separator test ,complete, bleed down to tank farm to purge lines with fluid , , 10:15 ' , , , Pressure test complete blow down the system with air , ' 28-Nov-98 11:00 , , System bl°V~,n down ,prepare to insulate , ,, 12:00 ,, To, p deck insu!at!on ,complete .... , , 13:00 Separa, t, or deck insulation complete 14:06 Tank deck insulation complete , , ' 14:30 : lndustri';I I~iler ;3n the platform to fix heater ' ' 1'5:00 " ' F'ire heater ........ .... 17:30 ....... H,eater, temp~at~re ,bath holdi,n,g, and set temperature ' , ,, , , ,, n :18:23 , , Saf~y sy, ste, ,m full function and in proper workin~ order P~e2 ...... SEQUENCE OF OPERATIONS ' ' I I I II I I I I LEASE: Tyonek WELL~: NCIU 3 B1-ST TICKETS: 397997,92,93 I I I I I 19:00 R~rder,~ ~, conn~ti,ng up and testing chem~al inje~ion 19:15 Safe~ m~g, ~h Pool Ar~ic, Phillips Petr~leum,A~ollo, Phillips Productio~ personnel 2~:1~ " , ' ~a~d I~g~q~ to disk, for oil ~lculations usin~ 30 APl oil ~ravit~ at 60 d~. as a de~u~ ~:~ ~ master ~ive to closed choke manifold .... ~:~ ' ,,' ,, ' oP~,~ ~ a lO/64" adjustable choke 22:t0 tncr~s~ choke to ~/64'{ adjustable .... ' ,,, 22:13 " ,, Inc~eas~,c~e to ~/64" adjustable. Flui~ at choke manifold ~: 15 Fluid at s~p~ator , , , ,, ,~ ,, ~:19 incre~ choke to ~0~4" adjustable ' ' 22:~0 ....... Ta~ 1 2P' 45 bbls Tank 3 =6" 10.02 bbls , ~:39 In~ed sepamt~ pr~sure to 200 psi , ,, ~:41 ' ~om~ ~emi~l inj~tion , , 22:45 {a~k 1 = ~ ~ b~ Tank 3 = 6" 10.02 bbls "' ~:5~ , ' ' ' , ....... ~r~s~ ~arat~[ pr~ure to 100 psi ', , ~:55 Incr~ choke to ~64" ad, usable , "23:~ ...... T~nk ~ ~ ~0" ~.6 bbls Tank 3 = 6" 10.02 bbls ~:15 ' Tank 1 ~ 44" 73.3 bbls Tank 3 = 6" 10.02 bbls, s~'arator bypasse~ do to mud 23:23 ...... Instatl~ 0.7~ or~ pIMe , 23:~ Tank t = 44'; 73.3 bbls Tank 3 = 7" 11.66 bbls , , ,, " 23:38 ' " ln~e~'c~ to ~/64" adjustable , ' ~:~ ' T~k I =' 44" 7~.'3 bbls Tank 3 = 6" 11.~ bbls ~Nov-~ ' "0:~ Tucker, H,~ton,T~urski , Flu~~= '10~ ~as c~ mud. Tank 1 = ~.25" 73.7 bbls Tank 3 = 20" 33.~ bbls, o~ ba'~k t9 separal ' d:15 Z~,Scoff,Lyon,~ommy Flu~s = 'lb~ gas c~t mud. Tank 1 = 48.00,, 80 bbls Tank 3 = 29,, 48.3 bbls , ' ' b:30 Bmr, Knight, Bray Estimated ~ate = 2,5~ bbls total fluid. Tank 1 = 57.5" 95.8 bbls Tank 3 = 39.5" 65.8 bbls , , , ~ ,, ,, , ,, 0?5 ,, lns~ l.~',~rifice plate ,, 0:~ Decr~s~ choke, to 48/64" ~djustable to maintain flowr~te parameters 1:00 , " , , ,, Fluids = 10~% ~s cut m~d Tank 1 = 78.5" 135,9 bb~ Tank 3 = 44.5" 7~35 ~bls 29-Nov-98 1:19 Took final strap on ~ank I = 90.0" 1~ bbls Tank 3 = 44.5" 73.35 bbls 1:20 ........ ~ to Tank 2 and commen~d pumping out Tan~ 1 , , 1:21 T~k 2 = 12.~ 20.0 bbls Tank 3 = 44.5" 73.35 bbls 1:45 ' BS&W = 22% mud solids Tank 2 = 16.5" 27.5 bbls Tank 3 = ~.5" 73.35 b61s ' : 2:00 ' , Tank 2 ' 19.0, 31.0 bbls Tank 3 ~.5" 73.35 bbls ' , 2~15 .... T~nk 2 = 19:~ 31.6 bbls Tank 3 ~.5" 73.35 bbls 2:30' ' ' T~k 2 = ~9.~ 31.~ bbls Tank 3 44.5" 73.35 bbls, 1 '1/2" liquid meter plu~i~ off, s~itch to 2" liqui .... 2:45 ' ' Tank 2 "19~0" ~1.6 bbls Tank 3 44.5" 73.35 bbls, liquid m~er back in se~ce .... 3:~ ' ' ~ank 2 = 19.~' 31.6 bbls Tank 3 47.5" 79.1 bbls ,, ' ~:~5' ~ank2 '~9.0" 31.6bbls'Tank3 50.5" ~.1 bbls ' ~:30 Tank 2 = 26.~' 43.3 bbls Tank 3 = 57.0" 95.0 bbls 4:~ Tank2 = ~.~ 43.3 bbls Tank 3 = 69.0" 115.0 bbls , , , , , · , ~ Page 3 .......... SEQUENCE'OF oPERATIONS ' ' ' I I I I I I I COMPANY: FIELD: Cook Phillips inlet PetroleumlJl LEASE: Tyonek N WELL#: NClU 3 BI-ST TICKET#: 397997,92,93 I I . I I I I !,, , , ! , , r - , , ' II r il ", , , ir L , ! I' L , I ,L [il ' i ~_ ,Ill , ~ L . - . L£ ~ , . ~,l. r F .. '3 .:J_ : .J .i !' . . '' ' ,'., .' i.'.. I ' '. q, ', : · ........ EO~ ~:~?~./..:~:-,. :-: ~'~i:'' ;:,:- 4:15 Went into 2 phase flow BS&W = 25% mud solids .... , , , ! , , "4:18 Default ,gas gravity = 0.750 oil apl = 47.5 (~ 100 f, corrected APl 44 ~ 60 f 4:30 ' ' ' Tank 2 = 26.0" 43.3 bbls Tank 3 = 81.0" 135.4 bbis H2S = 0 CO2 = 0.25% '" 4:55' , ' , , ,,,' Gas grav~ actuai r,,e, adin~t = 0.8~9 ' , 5:00 Tank2 = 26.0" 43.3 bbls Tank 3 = 81.25" 135.4 bbls BS&W = 30% mud solids , , [ i' ~:30 Tank 2 = 26.0" 43.3 bbts Tank 3 = 87.5" 146.2 bbls , ,, 6:00 ...... Tank 2 = 26J7' 43.3 bbis Tank 3 = 122.0" 203.3 bbls BS&W =50% mud ~;31ids ,, , , , ...... 6:30 Tank 2 = 26.0" 43.3 bbls Tank 3 = 122.0" 203.3 bbls " 7:00 ........ BSS~V = 30% mud solids t, , 7:14' ' Shut in well at ~h~)k;~ manifold. Line to purple tank leaking. Repair line, mud plu~l~li~l off Halliburton tes~ 8:00 ' ' Total fl~ids flowed to tanks = 370 bbls ' , , , 9:00 .... Still working on pump and tank to transfer fluids to Apollo 10:00 , , Still,p, umpir~ on the ,tanks, Dou~l, Scott departed from the ri~ , , 11:00 Still pumpin, g on the tanks , ,, "' 1,2:07' , .... ' Valve clOsed On the girder, thou~th was pump not working, pulled hose and,'s'pilted mud on the deck 12:20 ...... Mud cleaned up , , , ' 12:30 . , , commence Pum,,ping of the tank , , 13:33 Rig installed second pump to assist first pump ' ' 13:45 .... Ri~t pump hose iea,ked at the camlock, stopped p~mping and repaired hoes, cleanu, p mes,s, 13:50 , r , C, on,tinu ,e,,to pump , , i 14:t0 . , Tanks pu, m ,l~d, down ..... .... 14:14.'. .... ' '.. ,'" ' Ope,n we!l, shut in p,ressure at, 553,6 psi, op,en adiustable c,hoke to 12/64 "14:15 ,, 'rpn,k,# 1.at,13" =, 21.67 bbls, ,Tank # 2 at 2,6" = 43.,34 bbls, Tank # 3 at 6" = 10 bbl~ ' , i , 29-N0v-9~, 1~,:15 " .. , P,umping complete Rumped 197 bbls, total fluid pumped 5,67 bbls 14i25 Increase choke to 18/64 adjustable, oil meter skid on bypass .... , 14:3,2 ' R(~cked~noke a,,nd !ncreased to 20/64, ~as turbine meter skid on bypas,s , , , 14:38 Increase choke to 22/64 adiustabte , , , "14:45 ' 'l:ank #1 at 1'~" =,21.67bbls, Tank # 2 at 26" =, 43.34 bbis, T, ank # 3 at 46" =, "7'6.7 bbls '14:48 ' ln~reas~.d choke to 26/64 adjustable 14:55 .... Orifice plate in service 15:00 ......... Tank # 1 at 13" ~ 21.67 bbls, Tank # 2 at 26" = 43.34 bbls, Tank # 3 at 48" = I~0 bbls ' 15:07 increaSe~! c~'°ke to 32/64 adjustable, gas meter skid in service, gas turbine rate 113 scf/d cumm. 41 s{ 15:15 ..... Tanl~# '~'at 13" = 21.67 bbls, Tank # 2 at 26" = 43.34 bbls, Tank # 3 at 62", 1.03:354 bbls , ' '15:24 ' Ali fl~!d going through 2" oil meter , , ! , 15,:,~0 Incr,,eased choke to 40/64 adjustable, cas gravity 0.790, Gas turbine rate 1416 scf/d, Cumm 70.5, ,rna. in ....... gas to su, rge ,tanj< caused high readin{~ at surge t, ank, surge, tank pressure went to 35 psi Tank# 1 at 13" = 21.67,bbls, Tank # 2 at 26" = 43.34 bbls, Tank # 3 at 78"= 130 bbls ,, ....... G~s"turbine ra{e 195 scf/d cumm 70.5 scl Page 4 SEQUENCE OF OPERATIONS I I I I I I I COMPANY: Phillips Petroleum FIELD: Cook Inlet LEASE: Tyonek WELL#: NClU 3 B1-ST , ,, TICKET#:, , ,:397, ,9~J, 7,92.93' , , ........... 15:45 Tank# 1 at t3" = 21.67 bbls, Tank#2 at 26" = 43.34 bbls, Tank# 3 at 93"= 155 bbls ..... iGas turbine rate 132 scf/d cum. 83.8 scf ' , , 15:5b Start pumping tank 3 oil to the girder t,ank , 16:00 ,,, Increased choke to 48/64 adiustable, no tank strap while pumping down tank , , 16:15 :Decrease separator pressure to 100 pti! ' ' 1~:24 ' ' ' BS&W 1% mud solids ' 16:3{) , ' , No tank rea,di'n~ (Jo ko pumpin,~ down o,f the tank ,, ' ' 16:45 Gas turbine rate 91.68 scf/'d cum. 122 scf 16:56 O,dfice plate out of service ' ;17:00' ' ' B$&W 30% mud s~lids ,,, , , , , , ,, , ,,, , 17:11 Stop pumpinf/, to the girder tank, tank 3 at 30 inches = 50 bbls 17:15. . Valve shut in, Halliburton room on the hose to the gi,rder tank ,, , , ,~ , , . ,, , , , ,, , , , ,, ,, , , 17:15 Tank # ~ at 13" = 21.67 bbls, Tank # 2 at 26" = 43.34 bbls, Tank # 3 at 30"= 48.5 bbls .... 17:30 ' Tank'# 1 at 13" = 21.67 bbls, Tank# 2'at 26" = 43.34 bbls, Tank # 3 it' 30"'- 48.5 bbls , , , , , , ,, 17:35 Gas turbine ,meter acting up, switch to other side of meter run 17:41 ] ' ' ®bs trubine rate 480 scf/d cumin.- 20 scl ..... , , , , , , 18:00 , , Change orifice p ,late to 2.000" 18:30 Tank # 1 at 13" = 21.67 bbls, Tank # 2 at 26" = 43.34 bbls, Tank # 3 at 73"= 122 bbls , , ,,,, Gas turbine rate 650 scfld cumin.- 42 scf ,,, ,, , , , , , 18:38 B in to pump down tank # 3 1~. , , , 29-Nov-~ 19:00 Tank# 1 at 13" = 21.67 bbls, Tank#2 at 26" = 43.34 bbls, Tank # 3 at 103'"= 17i bbls' , , , , , Chloride at 1,2,000 very muddy, Water, meter factor of 1.004 .... No tank stm. p while pumping down tank ,, , ,, 19:30 Baroid d!d chloride and got 3800 ~PM, gas tt~rbine cum. 11.8 scf ~No tank strap while p,,umping down tank "' 14:56 ' ,, ~rinter q,uit WOrking shut down ti~e entire system and rebooted ' ,, , 19:5~ , ' System back up,and, collectin~l data 20:00 :BS&W 1% mud solid, s, gas turbine rate 1491.~ scf/d. Cumin.- 147 scf " ' ' ' ~0:.30 ' ' ' . , BS&W 3% mud solids, gas turbine rate 1582.4 scf/cJ. ~umm.- 181 scl , ,, ' ', '" 21:00 ,, !BS&W 2% mud sol~l, s gas turbine rate 1588.0 scfld. Cumm.- 211 scf , , , 21:30 .... 'BS&W 4% mud, solids, gas turbine rate 1343.2 scf/d. Cumin.- 237 scl 22:00 , , , BS&W 1% mud solids, gas turbine rate 1610.0 scf/d. Cumin.- 272 scf, stop Pu~ping shut'in gli,rder val' 22:30 BS&W 1% mud solids, gas turbine rate 1260.4 scf/d. Cumin.- 301 scf, Tank # 3 at 37" = 61 bbls 23~;00 .... BS&W 2% mud solids, gas turbine rate 1426.0 scl. Cum. 329 scf, Tank # 3 at 64" = 106.7 bblb' ' 23:30' ' ' Bs&w 2% mud sol!ds, gas turbine rate 1481.0 scfld. Cumm.- 368 scf, Tan,k # 3 at 92' = 153.~ b'bls '3(~-Nov-98.,'," 0:00 !TUcker, Hewston,,Tyburski I~s&W 3% mud solids, gas turbine rate 1499.0 scf/d. Cumin.7 392 scl, Pumping out Tank # 3 , 0,:30,,, [Zeddies, Lyon,To, mmy @S&W 3% Mhd Solids gas turbine rate 1628.0 'scf/d. Cumin.- 428 scf , , 1:00 Brow?, Knight, B, ray, BS&W 3% Mud Solids gas turbine rate 1536.0 scf/d. Cumin.- 462 scl ....... 1:30 Gas turbihe rate 1545.0. Scf/d. Cumin.- 491 scf Tank 3 = 39" ,, , ,, P~e5 I i ........ $~QUENCE OF OPERATIONS [I I IIII I I I I I COMPANY: FIELD: Cook Phillips inlet Petroleum II :': RTON LEASE: Tyonek WELL#: NClU 3 B1-ST TICKET#: 39,,7997,92,93 I .I II I I II I ,,~~iL..-i~:::'.:.!i ;?~ !.~:?'2i~ ~.~i~i. i.:.i.' .~ ~..:..' ii ~ , , 2:00 BS&W 1% Mud 8oil,ds gas turlpine rate 1141.0 scf/d Cumm.- 547 ,scl , , , 2:31~' ' I~S&W I% l~lud Solids ~ias turbine rate 7t7.0 scf/d Cumin.- 570 scf 3:C~) ' ' BS&W t% Mud 8olids ga, s turbine rate 838.0 scf/d Oum. 595 scf Tank ,8 pumped out ~o 6" 3:~0 ' " BS&W 1% Mud Solids gas turbine rate 690.0 scf/d Cumm.- 609 scf Tank #,3 a,t 24" = 40.0 bbls ;' ' ' 4:00 ' ' BS&W 1% Mud Solids ~las turbine rate 690.0 scf/d Cumm.- 616.2 scf Tank # 3 at z~2', = 70 bbls .... ,~:30' ' BS&W '~% Mud ,~olids gas turbine rate 901.0 scf/d cumm.- 632.2 scf Tank # 3 at 72" = 120 bbls '5:00 ' BS&w 1% Mud Solids gas turbine rate 1021.0 scf/d Cumm.- 653.2 scf TaNk # 3 at 83" = 138 bbls '5i30 ........... BS&W 1% Mud' Solids gas turbine rate 1060 scf/d Cumm.- 678.2 scf Tank#3 at 108" = 180 bbls ,, ' 6i00 ' , ', ' ' ' , BS&W 1% Mud solids, Pumping out Tank # 3 gas turbine rate 1021.0 scf/~l' 'Cumm.L 696.2 Scl 6:30 Bs&W'1% m~ud solidsl Pumping out Tank # 3 gas tUrbine rate 1030.0 scf/d Cumm.- 718.2 scf ,, 7:00 ' ,, BS&~/3% mud solids Gas SG=0.892 gas turbine rate 1076.0 scf/d Cumm.- 740.2 scf _ , , , 7:3b BS&W 3% mu,d'so ,~ds, pumping out Tank # 3 gas turbine rate 938.0 scf/d Cumm.- ~'~1.2 scl ~, ..... 8:00 ,, BS&W ,3,%, mud solids, Pumping out Tank # 3 gas turbine rate 1142.0 scf/d, ~umm.- 783.2 scl 8:30 BS&W 3% mud solids, Tank # 3 20" 33.3 bbls gas turbine rate 1306.0 scf/d Cumin.- 811.2 scf 9:01~ ' " BS&W 3% mud Solids, Tank # 3 48" 80.0 bbls gas turbine ra~e 1264.0 scfJd cU~nm.-837.2 sCf 9:30 ' ' ' BS&W 3% mud solids, Tank # 3 75" t~5.0 bbls gas turbine rate 1370.0 s~;/d Cumm.- '872.2 scf ...... 30-Nov'-98 ld:O0 " BS&W :~% mud Soil,ds, ,Tank # 3 78" 130.0 bbls gas turbine rate 1527.0 scf/d Cumm.- 899.2 ~cf' " ,, t0:30 ' ' ', Bs&W 3% ,mud solids, Tank # 3 130" 216.71 bbls gas turbine rate 1462.0 sCf,/d Cum, m.- 919.2's;:f" 11:00 ....... New meter factor 0.978 turbine rate 1~72.0 scl;Id cumm.- 949.2 scf start tg,pump tank # 3 11:30 Tan,k # 3 pumpi ,n~l out turbine rate 1398.0 scf/,d, cumm.- 971.2 scl , 12i00 .... ' "', ' , ,, IT,ank# 3,pumping o,ut turbine r, ate 1205.0 scf/d, cumm,- 1000.2 scf BS~W ;I% mud solids , , ' ' 12:3(~ , iTank,# 3 ,pu,m, pin~t out tur,bine rate 1141.0 scftd, cumin.- 1025.2 scf BS&W,,4% ,mud solids 12:37 ISfill have 51" to pump away, in tank # 3 ' 13:00 .... [Ta,nk # 3 pur~p!n~l ,~t turbine rate 1453.6 scl, cumin.- 1051.2 scl BS&W 4% mud'solids .... ~, ' 13:~,5 ' ' ' , Start sampling as p,er Phillips sample procedure ," 13:30 iTank, # ,3 pu, mping out turbine rate 1242.0 scf/d, cumm.- 1076.2 scf BS&W 4% mud solids ..... 14:00 ' . ~Tank # 3,pu, mpir~ 0ut turbine rate 1509.0 scf/d, cumm.;- 1106.2 scf Bs&W 4%'mud solids' l, 14:30 ' ,, ' ' IT~n,k ,~ ,3 pumping out turbine rate 1206.0 scf/d, cumm.- 1134.2 scf BS&W 1% mud solids 15:00 [Tank # 3 pumping out turbine rate 1509.0 scf/d, cumin.- 1160.2 scf BS&W 2% mud solids 15:02 Valve to girder tank closed, sampling complete 15:30 ' B,?~W 3% mud solids, tank # 3 at 31"= 51.677 bbls, turbine rate 1330 scf/d cumin.- 1190.'2 s(~f ..... 16:00 ' ' ' Bs&W 2% mud solids, tank # 3 at 56" = 93.352 b,blsl turbine rate 1398.0 scf/(J cu'mm.- 1217.2 scf ' 16i06 .... Oil AP! indicated gravity of 49.5 at 140 degrees, corrected APl at 42.4 ~ 60 ~; ,, t~:30,' ,, , BS&W ~6~'~ud solids tank # 3 at 82" = 134 bbls, tUrbine rate 1407.0 scf/d ,c, um'm.'- 1247.2 scf 16:33 Sta~ pumping tank # 3 ' ' 16:57 IsWitch logger to.build-up' mode recording well head and csg only, separator off '17:00 ' , S'hut in well at cl~,,oke manifold, record pressure for 2 hours, then move sens~)r ~o v~ell b;a¥ ,, ,, , Gas turbine cum. final 1369.2 scf; Total gas produced during test = 3.6782, mm, scl 18:48 fPumping complete pf oil to the girder tank, tank # 3 and surge tank done , P~e6 SEQUEi~t(~E OPERATIONSI OOMPANY: FIELD: Oook Phillips inlet Petroleum O:?- RTO LEASE: TyonekN WELL#: NCIU 3 BI-ST TICKET#: 397997,92,93 I I I I II I ! 19;02 Dis¢onne~ woil he~d .eh.or .o ri~or e~n b~ mmovod , , ,, i , ,, 2~:05 ~in~ta~ son.or on ~e~ and b~in to roeord ~ and 2~:~5 ~ ' ' ' , " B~in to d~ d~ ~mn sy~tom ~il~ tho tiC is flush}n~ our ~quipment with Water ~-~8 ~:~ E~ of Ft~s[ 8tocpod Io~in~ data to disk ~:0~ ........ 8~d to ~ da~ and ~rk on mpo~ ' " , , , .2:~5, , ,. , , B~in to ri~ d~ ~u~ac~ t~.t ~uipm~nt ~:06 , 1~. qm~ am ~u~ with ~h~ r~ moy~, wo are mit!~~ on emn~ to a~t in'moWnfl pipo ' ' ~5:30 .... H~t~n,Ty~,~i~ht,Z~ddi~,Br~n, and lu~or doCad fro~ ~h, ri~ , , ~:00 ~v. at K.n,ai ~r, Knight ~t~y in K~nal to cloan ~uipm.nt , ' ', .......... ~ra~ ~ d~.d ffo~ tho fl~ whon all ~qui~moht ~ off. , ~7:~ , When ~mtor I~, it w~ 6000 pound, h~avi~ th~n when it arrivod, mud in ~o~a, rator . , ' 2-~ee-~ ~:00 ~Mflht ' ~'a ~tmn~n~'~6ipm~nt in K~na~ and ~tiflun , ' ~:00 . ,,' ,, S,~ ~ ~r~ niCht , ' , ~-~-~ ~:00 ~l¢'ht, , ~3 9t~n~n~'~p~nt in Kon~ an~ ~ti~un ' , ~0:~ .... 8hut down for th..n~ht . , , , , , , ,, , ,, , ,, , , ,, , , , ,, , , , , , , , , , , , ,,, ,,, ,, . , ,, , , ,,, , , ,, [ , ,, , , , , , ~ , ~ , ,, , .,, ,, , ,, , , , , , , ,,, , , , ,,, , ~ , , , , ~ , , , , , , , ., , . , , , , , , Page 7 TIME PRESSURES TEMPS CHOKE FLOWRATES RATIOS CUM VOLS, CO2/H2S GRAVITY'S SEPARATOR DATE TIME DTIME RTO N NOMENCLATURE The following is a guide to the various headings used in the SCAN test results. · Date, reported in days, months, years. · Time, reported in hours, minutes, seconds. · Delta Time, reported in hours. DSP WHP CSG · Downstream choke pressure, reported in psia · Upstream choke pressure, reported in psia. · Casing / annulus pressure, reported in psia. WHT : Upstream choke temperature, reported in degrees Fahrenheit· DSHTR : Downstream heater temperature, reported in degrees Fahrenheit UPSHTR : Upstream heater temperature, reported in degrees Fahrenheit MFLD : Manifold Choke size, reported in 64ths of an inch. GAS OIL H20 GOR GLR WOR GAS OIL H20 : Gas Rate, calculated from acquired data, reported in standard cubic feet per day : Oil Rate, calculated from acquired data, reported in standard barrels per day. : Water Rate, calculated from acquired data, reported in standard barrels per day. : Gas Oil Ratio, calculated from acquired data, reported in standard cubic feet per standard barrel. : Gas Liquid Ratio, calculated from acquired data, reported in standard cubic feet per standard barrel. : Water Oil Ratio, calculated from acquired data, reported in standard barrel per standard barrel. : Accumulative gas volume, reported in million standard cubic feet. : Accumulative oil volume, reported in standard barrels. : Accumulative water volume, reported in standard barrels. CO2 H2S · Carbon Dioxide, reported in percentage. - Hydrogen Sulfide, reported in parts per million. GAS ' Gas gravity, Air = 1.000. OIL - Oil gravity, reported in APl units (@ 60 deg.f) SALINITY · Water salinity, reported in parts per million. PRESS. DIFF TEMP. · Separator pressure, reported in units of psiG. · Separator gas meter differential pressure, reported in inches of water · Gas temperature, reported in degrees Fahrenheit. RTO N Method of Gas Rate Measurement and Calibration including Flow Meter Calibration. Measurement by Odfice Plate :- where :- C Qg C Hw Pf Fpv Fb Fg Fff Ftb Fpb Fr Y2 Fm Unit Conversion Factor Qg = C * Sqr ( Hw * Pf ) = Fpb * Fb * Fg * Fff *Ftb * Fr* Y2 * Fm * Unit Conversion Factor = Corrected Gas Flow Rate. = Odfice flow constant. = Differential pressure across orifice plate in inches water gauge at 60 deg.f = Absolute static pressure. = Supercompressibility factor ( corrected for N2, H2S and CO2 effects ). = Basic odfice factor. = Specific gravity factor. = Flowing temperature factor, = Temperature base factor. = Pressure base factor. = Reynolds number factor = 1. = Expansion factor for downstream pressure tap. = Manometer factor = 1. = Factor changing flow rate units. We can unite Fu = Ftb * Fpb * Unit Conversion Factor, ( Fu factors are given in the table for different standard conditions and flow rate units ). Cl = Fu * Fg ( theoretically constant dudng the test ). C2 = Fpv * Fb * Fff * Y2 Then C = Cl * C2 Table of Fu Factors i~te 0¥ Fl'0~v uniis ........................................................ Stan, d,a,rd~,,Cp ,nditiop,s .............. Cu ,Ft / hours Cu Ft / day M3/hour U3/day 14.73.psi ~/60.deg F,,~ ............ 1,0,0 24.00 0,03 0.68 ,76,0, mm Hg !,0. deg c. . ...... 0,95 ..... 22.76 ~0.03 0.64 r760, mm, ,Hg / 15 deg,,C., .......... !.00,' ,, ', .... 24:0!, , ', 0.03 0.68 ?,50,m'mhg/15 deg. C. i 1.01 24..33 0.03 I ' 0169 Gas Flow Meter Calibration :- Prior to the test, the orifice meter and differential cell are cleaned, serviced and calibrated using a reference manometer at the HALLIBURTON base. During the test, the odfice meter and differential cell are field checked using a calibrated Poddy meter or manometer / dial gauge for any shift during transportation. This test is conducted at vadous intervals throughout the testing programme. Gas gravity measurements are made using a Ranarex Graviometer. Gas gravity measurements are made using a Ranarex Graviometer. This unit is also serviced and calibrated at our base pdor to load out using commercial gas and recorded for our records. Dudng the test there is also a field check made using Propane and air. RTO N Method Used For Calculating Oil Rates 1. Measurement by METER where :- Vo Vm Mf BS&W QO Vo = Vm * Cf * k ( 1 - BS&W I 100 ) Volume of oil at atmospheric pressure and ambient temperature. ( 14.73 psi and 60 deg F. ) Volume of oil registered by meter(s) since last reading at separator pressure and temperature. Combined measured correction factor obtained by calibrating the meter with the tank during the test and includes both the meter factor, Mf and the weathering factor (shrinkage), Wf. Therefore Cf = Mf * Wf. Meter factor. It is to be corrected for any meter non linearities, due to mechanical error. Weathering factor = Volume of oil at atmospheric pressure and 60 deg F. / Volume of oil at separator conditions. Note :- Wf = ( I - Sh ), where Sh = Oil shrinkage from separator to stock tank conditions. Temperature correction factor from ASTM table ( k = 1 for an oil temperature of 60 deg Fahrenheit ). Basic sediment and water measured using APl field centrifuge method, Percentage of basic sediment and water volume to total volume of oil and BS&W. Corrected Oil flow rate = Vo / Time to produce the volume. 2. Measurement by TANK. where:- Vo = Vt k ( 1 - BS&W 1100 ) Vo, k, BS&W and Qo are as above. = Volume of oil measured in tank at tank temperature since last reading. ~/'~RTO N o~o~ ~sT~. l~,o~v,E~,oD ou~ToM~,~S~,f*T~ " Phillips Petroleum One J Flow Test One Shonna Boyer 5.761 2" Turbine NCIU BI-ST Cook I ,nlet . Forelands ,, Unocal 428 ,. , 'I:IME PRESSURES TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H28 GRAVITYS SEPARATOR ' COMMEN'TS , DAY:MO:YR DSP (psia) USHTR GAS(mmscf/d) GOR (scf/bbl) Mud/Sotid~ GAS (mmscf) CO2 GAS (Air=l.0) PRESS (psig) * Gas measurements are of separator gas only. :~i~i~i~'-6 :~:~i:i !: !~: :: :i~::: :~i~:: :!::: '.i~ :~i¢!: :i~'.~i~/i:i:i:i~:i:i:!: ~ii?!:!:i:!~,~ :i:i:i~f:i:!t :i~!:i:i:!:i:i~:i:i:~i~:!:ii~a:i ** ~OR = ~r~rator C~ ~ Co~ O, Rate. DTIME CSG (psia) DSHTR Mud/8olids WOR (bbl/bbl) Water Mud/8olids H2S SALINITY (ppm) TEMP. (°f} *** Gas from surge tank measurements are from turbine meter (*f) (64tbs) (bbb) (%) (bbls) (ppm) 28111198 100% At 22:06 OPen ~ell on 10164 adj chok~' Fluid at separator, APl Default for calculations of 30 28111/98 90.3 100% 1.000 173,6 Tank 1 equals 27" = 45 bbls, Tank 3 equals 6" = 10 bbls i:i: :~ ~ ~: :i:i i:!:}:i:~::.Ei:i:}:i i:!:'~.~:: i:i:i~!~i:i:i:!:i:i:i:!~i;~:i:!:i:!: ::::::::::::::::::::::::::::::: i:i:i:i:!:!:!:!:i i: :i:!:i:i~62i;~:i i i:ii :ii! iii i i i ii il i i i ! ~i!! i ii i! i i i i~.j¢ i ii! ! i!i At 22:39 Increased separator pressure to 200 psi 0.2500 52.3 2387.6 24.9 67.0 At 22:41 Commence chemical injection, Gas Gravity default 1.000 28111/98 52.0 100% 1.000 156.9 Tank 1 equals 36" = 60 'bbls, Tank 3 equals 6" = 10 bbls i ~i~i~ii ii i i i }.~-~ ii i i i~i:i: :i:i:~:i~!ii:i:!:i:i:!:i:i:i:i:!:i:!:i:i:i:i:i:i i:i:i:i:!:!:i:i:i:i:i:i:i:i:!:! :!:i:i:i:i:ii! i ! ::!:!:i:~ ~:i:i ! ! i:i ! !i! iii ii iiiiiiiiii!~ii!!i}i!iii ! i ii!i!!!i!!i !}!i At 22:54 Decreased separator pressure to 100 psi ,.,......-...-.-.....,........-.-.-.....-.....-.........: .......-.:;...: .... .... -....... .............. ; .......................... ....,... -;.....-..<;., : ..... , .......... . ........ -.....-.-_..-.-.-....,....-.-.., 0.5000 108.5 2111.8 46.9 79.6 At 22:55 Increased to 42/64 adj.choke 28/11/98 53.4 100% 1.000 100.6 Tank 1 equal 40" = 66 bbls :3 ~ O~iOOi:::: :i:: ~ 3:: :}:i~.~:::::: :~2:~i~.f-'.' ::: :?::::::i:::: ::: :: 3::}: 3::::}: :i::: :::i: :!:i:i :i:: :~ ~i:i:i:i:~ i:i:i:i:i:i:!:i:i: i:i:i:i:i:i:~.~!:i:i:i:i:!:i:!:i:i:i:i:i:i:i:i:i:i:!:i:i: 0.7500 120.4 770.1 54.9 91.6 28111198 54.1 100% 1.000 54.6 Tank 1 equals 44" = 73.3 bbls 1.0000 135.4 895.2 64.2 98.5 Separator bypassed do to mud 28111/98 53.0 100% 1.000 20.5 Tank I equals 44" = 73,3 bbls iii::!::i~!!}!:: :::::::::::::::::::::::::::::: ::ii:~.~:i:?i:i:!~i:~::-:i:i~ :i:iii:i:!:i:i:i:i:i:i:i:i:i:!: ii!iiiii:iiiii;:!iii!ii;iii!!i iii!ii!iiiii:ii!~!ii !iiiii:.~.~i!:!:i:i i:!:i:!:i:i:i:i:i: !:!:!:i:!:i~-.~i:!:i:i:i:i:i:i:!:!:i:i~i3:i:i:i:i:!: Tank 3 equals 7"= 11.66 bus i ;1'i'~ '~':~'" '""'"'"'"'"'"'"'""'"'"'""""""""'" .... ' .... ' ..................... 6~.2 .................................... 9'7;.~' ..... At 23:38 Increased choke to 64164 adj. 28/11/98 57.0 100% 1.000 36.7 Flow well as directed 1.5000 3.0 108.5 64.2 92.9 29/11/98 62.2 0.088 61.1 0.001 1.000 45.1 j Fluids = 100% gas cut mud, open back to separator ~??:.?<.....?.-.:,;.:.;: ;.:.:.:.:.?..<.-.:.;.;. - ] .............................. b..-.x-.-.-.-.-...-. ~.-...-.-.-.-.-.,.-.-.-.-...-.-.'.'.-.-.-.-.- .'.'.-.'.-,-.'.'.'-'.'.'.'.'.-.-:.'.'.'-'.'.'.'.'.'.'.'.'.-,1 f:i:i:!:p.:!..~.<!..~....:i:i:i: :i:i:i:ii!~.'..O.i:iS; :i:i~!:!i :i:i:~i.~;i:!:! i:!:i:;:'.li434i.i:i:i:i:!:! !:}:i:i:;:!~li;~.i:i:iii:i:i ::: ::::: ::: :::: ::: ::H:Z;.4:::::: ::::::::::: ::::: :::::::::::::::::::::::::::::::::::::.1:::::::::::::: Tank 1 equals 44.25" = 73.7 bbls / 1.7500 9.0 ""'~;'~'"':"'"'""'"'" '"'"' '"'-'"'"'""'"'"'"'"'" "-'"'""'"'"' '"" '"" "'-""'"'"'"'" '"'""~;~'-"'-"' '"'"'"'""" .... '""'"'"":'"'"'"'"" '""'"' ~;~,'"'"""~ Tank 3 equals 20''= 33.34 bbls .. 29111198 63.7 0.157 127.0 ............. .0:..0~3 .................. !;..07. .......... . .~.'8. .... Fluids= 100% gas cut mud i:i:i:i0i.~.~!:i:i:i i:i:i:i:}li7.'t¢~d:i:i:i: i:i:~.~:!:ii !:!:i~i:'.~.j~:i:ii ::i:i:i:i:'~:2~;~l!:!:i:i:i: :i:!i!:!:!:i86~9 !i!ii !: ?'-'."'.'."'-'-"' "--"-'130-2.-'-:-" '-:-:':':':-:'":- :-:':-:-:-:-.~9:':-:-:':-:' +:':':-:52:9:':':':': Tank 1 equals 48" = 80 bbls ~ .'.'-'.'-'-'.'-'-'-'.'.'-'-'- .'.'.'.-.'.'.-.-.,...-.-.- ................................. -~-:-'-:.;.:-:-:.:.: i:-:-:-:-; .~..,. ~,:-.-:- :-.-.-.-_,.-.-:-.- .-.-...-.-_-...~..-.-.-.-.-..-...-_,.-...: .-.-.-.-... 2.0000 15.0 "'"~'.'~""!'- .... '" ........... '~'~2;5 .................... ' ............... ~.~ ................................... 8~.~4' .... Tank 3 equals 29.5"= 48.3 bbls 29111198 66.1 0.124 57,7 0.004 1.000 138.0 Flow well as directed :::::::::::::::::::::::::::::::::::::::::::::::::::: i::!::~::i::' i::i.i~!~i::i.i.:::i::i::i::i~'.{.~::?!::!.i::i.i, :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::: ii::i::i::i::i::i~::i::i::i::i::i::! iii::i::iiii!~i~::i::ii!::i::, Tank 1 equal 57.5" = 95.8 bbls 2.25OO 27.O 92.5 2OO7.6 91.1 89.8 Tank 3 equals 39.5" = 65.85 bbls 29/11/98 60.9 o.660 0,011 1,000 139.6 Installed 1.000 orifice plate iiii~i}~i::i:: At 00:55 Decreased choke to 48~64 adj. 2.5000 33.0 101.5 2210.2 114.1 94.2 TO maintain flowrate parameters Page l I B U RTO N Phillips Petroleum One I Flow Test One Shonna Boy. e. r 5.761 I 2" Turbine NCIU BI-ST Cook Inlet . Forelands, Unocal 428 , TIME pREssu'RE8 TEMPS I CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H25 GRAVITYS SEPARATOR . COMME.NTS' DAY:MO:YR DSP (psia) USHTR GAS(mmscf/d) GOR (scf/bbl) Mud/Solid~c GAS (mmsc¢, CO2 GAS (Air=l.0) PRESS (psig) * Gas measurements are of separator gas only, DTIME CSG (psia) DS~ Mud/Solids WOR (bbl/bbl) Water Mud/Solids H2S SALINITY (ppm) TEMP, (°f) *** Gas from surge tank measurements are from turbine meter (°f) (64ths) (bbls) (%) (bbls) (ppm) ,, 29111/98 59.7 0.718 0.018 1.000 150.7 Fluids: 100% gas cut r~ud i:i:i:i:.~:'~:!:i:i: :i:i:i:i~E~i:i:i:i :i:i~.~iO!:!: """' '"'"' '"'" '"'"""'""'"'"'"""'" "'"'"'"' ...... '"" .......... : .... ' '-'"-' ..... :' ': .......... :'- ' '" ' ':':':' ':':':':': '" :"':':':':': -:--~8.:a.~i .:- ::::::::::::::::::::::::::::::: :.:-:-:-:-:425:7:-.-.-.-: r.'.'.'.'.'.'.'-'.'..-.-.-.-~52.:a..-.-...-.:.: .... : ........ .' .,30-~ ........... 26..~ ..... Tank 1 equals 78.5" - 130.9 bbls 2.7500 38.0 ' '931~' ' 1686.1 131.7 91.1 Tank 3 equals 44.5" = 65,8 bbls -- 29/11/98 58.7 0.800 0.027 1.000 168.0 Flow well as directed .... ~i000~ .......... 4510 ...... i~)3'.6 .................. 20:7'~.6' ................................... 1'5~313 .............................. 96.9 !At 01:20 switch to Tank 2 and begin to pump__out Tank 1 29/11/98 57.7 0.814 0.035 1.000 170.8 At 01:21 Tank 2 equals 12" = 20 bbls 3.2500 53.0 108.6 1992.9 174.1 98.1 29/11/98 57.1 O.778 0,O43 1.000 163.1 BS&W 22% mud solids i:i:!:!:~l!::4~:~:!:!:i:i :!:i:i:!.~.~!~i:i:i:i :!:i~.~!:i::: :'-~:~i :i:! i:i:: :i :iii:i: ::::: :i: !::: :i:~2:~::~i:i:i:i:! ki:i:i:i:i:i:i:i:i:i ;::i:i:!:{~;~: :i: :- Si:: :i: :i:i: i:!:i:i:i:i:~:~.'~i: :i:i:i:i: :i:i:i:i:i~ :~:i:!:!:i:i Tank 2 equals 16.5" = 27,5 bbls 3.5000 53.O 111.8 1490.6 189.6 98.1 Tank 3 equals 44.5" = 73.35 bbls 29/11/98 57.4 0.705 476.9 10% 0.O5O 1.000 148.6 Tank 2 equals 19" = 31.6 bbls ::::::::::::::::::::: ::::::::..3~.~:.~.::::::: ::::~...8.:::: :::::.4..8.:..a¢.::::: :::::::::::::::::::::::: :::: ::.3:t.7:;.3.':::: I::::::: :::: !::: :~...~.,,...0.:::: ::::::::: .:.:.:.:.: .3.....:0..: :.:.:.:.; :.:.:.:.:...~.,.3..:.:.:.:. Tank 3 equals 44.5" = 73.35 bbls 3.7500 66.0 110.4 743.7 197.4 101.7 -- 29111/98 57.8 0.733 1900.0 10% 0.058 1.000 134.3 Tank 2 equals 19" = 31.6 bbls : ::: 2-':~5:00 :::: ::::33:1:.0:::: : :.6~..0:: :: ~18 ~dJ-'::: ::::::: :.385:8:::::::::: :::::::::::::::::::::: ::::::::::::::::5:: ::::::::::::::::::::: :::::::::::::::::: :::::::::::20,0:::: :-:::: ::::: .~..~ . :: :: Tank 3 equals 44.5" = 73.35 bbls 4.0000 87.0 107.3 19.8 197.6 104.1 29/11/98 57.1 0.778 0,086 1.000 100.2 Tank 2 equals 19" = 31.6 bbls ..... 4.~5(~) ......... iO~',O ' '1'05,'6 ..... 1 - - i97.~ 102.8 I l/2" plugged off switch to 2 " liquid meter 29/11/98 57.0 0.764 0.074 1 .o(3O 97.2 Flow well as directed ,......-...-.-.-.-...-.-.-.-..-.-...-.-.-.-.......-_-... ................... · .... ~ ........... Z-; ........ Z-/-Z.Z-;-; ;'.'.';':'.'.':'.':'; -'.'.'.'.'.'.'.'_'/--'-'.' .'.'.'-'.'.'.'.'.' -'.'.'-'.'.'.'.~.'.'.'-'.'-'-'.~ '-'-'-'-':.','-' '.'-'- .'- 4.5(X:)0 124.0 105.9 197.6 100.5 Meters in service, and working properly 29/11/98 56.6 / 0.764 420.8 100% 0.082 1.000 98.6 Tank 2 equals 19" = 31.6 bbls ::: 3i0~-00i:: :i {::: :~i~(0:!::: ]i:!:~.~:!:! {:{:)i~i}~j:{:i! :!:i:{:{:~t~;~:{:!:{:i: :{:i:!:!:i~;8~:i:{:{:{: !:{:{:{:!:!:{:i:i:{: i{:i:!:i{~i~i:!:{:{ :{:{:! !:i {:{ !:{ {i! i { { ~ {! !i{{! !i{{{ ;{~ 9.'. {{{ i {: Tank 3 equals 44.5" = 73.35 bbls 4.7500 141.0 104.6 197.6 99.1 29/11/98 57.1 0.813 1011.4 30% 0.091 1.000 102.9 Tank 2 equals 19" = 31.6 bbls 5.0000 158.0 99.4 200.9 199.5 98.2 29111198 56.8 0.822 945.3 30% 0.099 1.000 102.9 Tank 2 equals 26" = 43.3 bbls "-""'"""'""-'""'"'"'"'"'-"'"'-'"'"'" :: 5.2500 173.0 98.2 366.4 203.3 97.4 Page 2 Phillips Petroleum One I Flow Test One Shonna Boyer GAS METER I.D. lOlL METER WELL NAME & No. FIELD IlNTERVAL TESTED RIG NAME I I 5.761 2" Turbine NClU B1-ST Cook Inlet I N. Forelands Unocal 428 TIME PRESSURES TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H2~ GRAVITYS SEPARATOR ' ' cOMMENTS , DAY:MO:YR DSP (psia) USHTR GAS(mmscf/d) GOR (scf/bbl) Mud/Solicb GAS(mmscf) CO2 GAS (Air=l.0) PRESS(psig) * Gas rneasurements are of separator gasonly. DTIME CSG (psia) DSHTR Mud/Solids WOR (bbl/bbl) Water Mud/Solids H2S SALINITY (ppm) TEMP. (of) *** Gas from surge ~nk measurements are from turbine meter (of) (64tbs) (bbb) (%) (bbls) (ppm) 29111198 57.0 0.827 961.4 25% 0.108 1.000 103.0 Flow well as directed :i:i:i:'.~".45.'f~:i:i:i: :i:i:i:i;~Si~)!:i:i:i: :!:iS~¢.Oi:i: :!:i:~:-~.~i:i:i:! :i:i:i:i:i~;5~:i:i:i:i:! i:!:i:i:!:~i6i:i:i:i:i :i:i:i:i:i:i:i:i:i:i ::i:i:i:2~li¢.i~:i:i:i:! i:i:i:i:i:i:i:i:i: i:i:i:i:i:i:~:;/iOi:i:i:i:i:i: !:i:i:!:i:!60i3i:i:i:i:i: Tank 3 equals 69" = 115 bbls 5.5000 149.0 99.2 420.1 208.9 98.4 29111/98 55.9 0.822 762.5 t00% 0.116 1.000 103.2 Tank 2 equals 26" = 43.3 bbls i:!:i:}~ibi~i{:J~i:!:i:i i:}:i:i:~:i0:i:i:i:" !:i:~.~:i:ii i:i:!;~i~i:i:!: ::i:!:i:i:'i~.:!:i:i:!: :i:i:!:!:i:~i$!:!:!:!:!: i:i:i:i:i:i:i:i:i:i: i:i:i:~i~i:i:i:! :i:i:i:i:!:i:i:i:i i:i:! !:i ~O:i}i i i i i i:i i i i ~i~ i ii ! ' At 04:18 Default gas gravity, 750 5.7500 167.0 101,4 208.9 98.7 Indicated oil APl = 47.5 at 100 degrees f 29/11/98 55.2 0.646 952.3 25% 0.123 o.25% 1.0(30 89.1 Flow well as directed 'ii~i~iCi~i~ii~i i~iii~i~:diiii~i ................~i~O~ii: '"'""""""'""'"!iiii~.:~i ~!i~:.e.~.2.i~i!iii~'-""-'"'"-'-'""'""'"' "'""""'"'"'"'"'"'"" ~'"'-""'"'""'" :::::::::::::::::::::::: i::iiiiii::ii::iiiiii iiii::i::::::i::i~i~iiiiiii::::::i! i::::ii::::!!i~i~::!::!ii?::: Tank 3 equals 81"= ~35.4 bbls, H25=0%,CO2=.25% 6.0300 161,0 103.0 229.5 211.3 97.8 At 04:55 Gas Gravity .899 29/11/98 55.9 0.844 1598.7 25% 0.132 0.25% 0.750 98.5 Tank 2 equals 26" = 43.3 bbls 6.2500 176.0 105.6 179.2 213.2 102.5 29111198 56.3 0.921 1207.4 25% 0.141 0.25% 0.750 101.2 Flow well as directed 6.5000 190.0 103.0 258.6 215.8 99.1 29/11/98 56.4 0.835 1047.0 30% 0.150 0.25% 0.899 100.6 Tank 2 equals 26" = 43.3 bbls 6.7500 203.0 104.5 270.3 218,7 99.8 di~'ected 29/11/98 55.8 0.843 904.5 30% 0.159 [ 0.2.5% 0.899 99.5 Flow well as 7.0000 211.0 103.1 237.0 221.1 97.8 29/11/98 55.5 0.878 956.7 30% 0.168 0.25% 0.899 102.7 Tank 2 equals 26" = 43.3 bbls 7.2500 225.0 97.2 233.3 223.6 96.2 29111/98 55.3 0.910 1457.7 50% 0.178 0.25% 0.899 104.9 Flow well as directed :i:i:i:i~!~i~i:i:!:i i:i:i:i:~.i~q:i:i:i:i li:i:~:q:i:i i:i:i~i:.a-~-.':i:i :i:i:i:i:~.'.4-~ii:i:i:i:i: :i:i:i:i:i.'.7.'..m.-.~.e.-:i:i:i:i:! :::::::::::::::::::::: :i:i:i:~ii!:i:i:i:i: !:i:i:i:i:i:i:i:i:i: i:i:i:i:i:!:i~-..°.:i:i:i:i:i: 7.5000 219.0 98.2 634,7 230.2 96.6 29111198 55.1 0.851 1578.1 50% 0.186 0.25% 0.899 101.0 Tank 2 equals 26" = 43.3 bbls 7.7500 210.0 104.7 548.6 235.9 99.8 29111/98 55.8 0.814 114t.6 30% 0.195 0.25% 0.899 95.8 !Flow well as directed ':':'X-'-:'"'-:'"'-:-;-:'; X':':-'-'-'-'-?':':-:'; :.;-?.'-:.'.?i;-:-?-'.;-X.X-;-~ .:-:,:-:-'-'-'-'-:-'-:-:-:-x--;,:,:-:.:-'-'-'-'-'E-:-:.;.:-;,:-;.:-;-;.:-:-:-:.;,-:-X-;.'-'-'-?-;,:.:.:.',-:-:-X-:.:.;-;.:.;.: ;.: :.::;-'-',:.' :.:: ;,~. X : : :X: x ; ~: ~-i:!:~:~:~-~-!:i: :~:?~:~..'.o.!:~:~:!. :~:;~..'.o.~.i-:~:~:~:~.~:~-~: i:!:~:?~.-.2-:.7.!:~:~:!:~:~ ~:!:i:~:!:!.7:~:~:~:~:i:!;;:~:;:!:~:!:?!:~:!:~ ~:~:~:!:~:.2._:!:~:!:~:~:~:~:~:~:~:?~:!:::::::::::::::::::::::::: :::::::::::::::::::::::: 8.0000 207.0 104.9 310.6 239.1 100.0 __ Page 3 t HALLI B 0'-RTON OU,TO,R iF,ow PE.,c ...... Phillips Petroleum One I Flow Test One ., Shonna B,oyer 5.761 I 2" Turbine NCIU Bt-ST Cook InletIN. Forelands Unocal 428 , ,, , , TIME PRESSURES TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H2E GRAVITYS SEPARATOR i .... COMMENTS .. ...... , . DAY:MO:YR DSP (paia) USh'T~ GAS(mmscf/d) GOR (scf/bbl) Mud/Solid~ GAS (mrnscf: CO2 GAS (Air='~.0) PRESS (psig) * Gas measurements are of separator gas only. i}~i~..'J~.'i'.S.'~i:: ::i~ii~ii:: ii::i,~.'~::i:: !i::i::i~iil}:: ~i~j~.i::i::i::!::i::!::ii~'i~i::!::!~."~ ::iii?i~i::i?::i ~i~ii::i::iii::~ il}iii~ii::i! ii~::i::i::!::iiii~i~!:: !::i.~.i~ii!iJ~ii ** GOR = Separator Gas I Corrected Oil Rate. DTIME CSG (psia) DSHTR Mud/Solids WOR (bbl/bbt) Water Mud/Solids H2S SALINITY (ppm) TEMP. (of) *** Gas from surge tank measurements are from turbine meter (°f) (64tbs) (bbb) (%) (bbls) (pPm) . 29/11/98 54.0 0.774 1309.2 30% 0.203 0.25% 0.8.99 96.'4 Tank 2 equals 26" = 43.3 bbls -.- -.... ...... .-.-.-.i,- ..-.- -.- - ..- ..-.-....- .... -.. -.-_ .-.-.. - -.-.-.- -...-...-.,.-.-... .... .. -.,.....-. -.-.-...-.- -_-.-.. · -.-.-.-.- .-.-.-,..,.-.-.-..., .-... ..... .- -.-.-...~ -.-...-,-.-.- ,... -.-.-.-.-.-.- · ..- -.-...-.-.-..-.-.-.-.-.-.- -~..-.-,'.-.- !:i:i:i:~:.~:.~:i:i:i: :i:!:i:i~.5.!~!:[:!:i: :i:i~-~!:!: :!:i:~:i~ii:i:ii!:i:!:i:!:.~[.:~i:!:i:i:!:, !:!:!:i:!:.9.~:!:!~i:i:!:i:i :i:i:i:i:!:i:i:!:i:i :i:!:i~-;~:i:i:i:! i:i:!:i:!:i:i:i:i: i:i:i:i:i:i~:O.i:i:i:i:i:i: :i:i:i:[:i~2.i-::i:i: :i:i Tank 3 equals 122" = 203.3 bbls 8.2500 205.0 111.9 257.7 241.8 102.4 29/11/98 55.6 0.944 t421.2 30% 0.213 0.25% 0.899 108.9 Flow well as directed ..,.,.....,.....-.-.....-....r..-.-.....- -.....-....,..- -.-....,-...-........,.-.......-...-...- ,.-.-..,-..,..-.-.-..,............-.....-...-_-.....-.-...-... ,...............-,.. -..,-...._....-....,..-.-..,.........,.............-...,...-..,....-......., -...-.,.,.,,..-...-..,......, ::!::::~!~::i:!:i ::::i:::~$~:!:i:::! !:::~'~:i:: i::::~i~;::::::::::::::::::::::::::::: :::::::::::::::::::::: i:i:i:i:::::::::::i: ::::::~:~::i:i:i :::::i:i:!:i: :i:i 3 :i:i:i:~:i.°.:::: :i: 8.5000 261.0 102.9 290.0 244.8 101.3 29/11/98 59.6 '1.34 I001.8 30% o.227 0.25% o. 899 140.5 Tank 2 equals 26" = 43.3 bbls ======================================================== ::::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::: ========================================================= :::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: Tank 3 equals = qqS 8.7500 3o2.0 86.3 583.8 250.9 88.7 29/11/98 0.227 At 07:14 shut in at choke manifold. i.iiii:?i&.":~ii:?i: i!iii?iT~.?i:?i: :?i~.~i:? :i:iii}i::::??:::?i:i"i:}:i:iii}i:i:i:??i:?i:i:?i i:i:?i!i}?i:i:??i!?i:i:i }i}i:.:!il}i!i}?i!!!:i}?i:~i~i?!!i! i:ii?i}i!}:i:iiii i:i:::ii:i}i:i:i!i:::iii!i?i:?ii :i}i:iiiii!i}!}i i i:!iii}!i To repair leak at the tank farm 9.0000 323.0 250.9 Mud plugging off equipment 29/11/98 O.227 Record shut in pressure while making repairs 9.2500 467.0 250.9 -- 29/11/98 o.227 Record shut in pressure while making repairs i:i:i:f.t-i,~i00!:i:i:! i:i:i:i~0i:i:i:i i:i:i~.-.~:i:" i:i:i:i:i:i:i:i:i:i:i:i: ::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::: ii:i:!:!:!:i:}:i:i:i: : :::::3~:~::::::: ::::::::::::::::: :: ::::::::::::::::: :-:::::::: ::::: :::::.:-:-:-:.:::: 9.5000 524.0 250.9 -- 29/11/98 0.227 Record shut in pressure while making repairs ::::::::::::::::::::::::: i::i::i::i~?!i::i:: :::ii~.9.'i~!:::: :::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::: ':::i::::ii~;~iii!!i! ::iiii!iiiii!i!iiii ! !iiiiiiii!i !{ :: i!i i i !i i!iiiiiiiiii iii! At this time total fluids flowed to tank = 370 bbls 9.75OO 489.o 250.9 29/11/98 0.227 Record shut in pressure while making repairs · ;-:-;-'C"~.i-'"-:';';'~ ;-:';C-'-'"'""";-:';' :'?-'-'-'-":-: :-:-:-X-:C.:-;-:q.? -:.:-:-;,:.;-:.:.Z-:C-Z.Z-:.:'i-:-:-:.:-:-:':.:-;';-:.:.:.;';- C-;.~';-;-Z-:-:':':. -;-;-;-:-'-'-'-:-":';':': -;-;-:-:';':';'X .;-:-;-:-:-;-:-;-:-X-;.:-:-;-: ~-:-:.:..8.:.~..,0~..:.:.;-, .:-:-5~:80.:0-:.:.: .:. -7--~,0:.: -:-:,:.:..x-:-:-:-;-: :,:-:.;-:-:-:,:-:.:.:-:-:-:-:-: :-:.:-:-:-;.z-:,:.:.:-:-:-:.:-: ;-;.:-;-:-;.;.;.:-:-: :-:.:-::~2~,2;-:-:-:- :.;.:-:.:.:.:.:-:- :-:.:-:-:.:-:.:.:-:.:-;.:-:-:.:.-:.:-:-:-;-..,-...-..:.:-:-. 10.0000 455.0 250.9 29/11/98 _t 0.227 Record shut in pressure willie making repairs ::::::::~:;30.I~:::::: Z::::::~,~?~:.'O:.:;:::: :::::~:.-.J~:::: :::: :::::;:::::::::::: ::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::: rZ:::::::3~;'2"::::::: :::::::::::::::::: :::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::: 10.2500 424.0 250.9 29/11198 0.227 Record shut in pressure while making repairs ::::::::::::::::::::::: ::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::: :::::::::::::::::::::::::: 10.5000 398,0 250.9 29/11/98 0.227 Record shut in pressure while making repairs 10.7500 374.0 250.9 Page 4 RTON I ,ow ,oo ' Phillips Petroleum One I Flow Test One Shonna Boyer GAS METER I.D. lOlL METER WELL NAME & No, FIELD ]INTERVAL TESTED RIG NAME 5.761il 2" Turbine NCIU B1-ST Cook InletI N. Forelands Unq,ca1428 . TIME pRESSURES TEMPS cHOKE FLOW RATES: RATIOS BS&W CUM VOL8 CO2/H2S GRAVlTYS SEPARATOR COMMENTS .--, DAy:Mo:YR DSP (psia) USHT~ Cw~.8(mmscf/d) GOR (scf/bbf) Mud/8°licb GAS (rnrnscf;, 002 GA8 (Air=l.0) PRESS (psig) * Gas measurernentsareofseparater gasonl~. .....-............,,..........~..........-.......-.:......,-.-....,..._-,..- -...-.......*.-.....-.....*...-...*...............-....*.....*,*.....-...-.-.-.-..... *,..*.-.-..,-.-..... -.-...-...-.-.-.-.....-..~ ...-...-.-.-,:.:...-.......:.?.-.-...-...¥.-. :::::. :~ :. , :::H.RL~...N;_.S_E¢:: ::¥¢HP-:.(~).:: ::i~.H.~::: J::i:::..MF~D.-::::: ,:~.-II;.:i:i:::i:!:i:(~ :~B:i:::.(~) i:i: :i~.H-.:i:!:i: .O.l.L!:i:!:i:i(.'~! :i:i:i .-(~.-) ::i :i-0.~ ::::: :.(~ :.0.::: :.D.I..~::::(~2...0~.: ** GOR = Separator Gas / Corrected O[I Rate. DTIME CSG (psia) DSHTR Mud/Solids WOR (bbt/bbl) Water Mud/Solids H2S SALINITY (ppm) TEMP. (°f) *** Gas from surge tank measurements are from turbine meter (of) (64tbs) (bbb) (%) (bbb) (ppm) 29111/98 0.227 Record sl~'ut in pre~ure while making rePairs 11.0000 354,0 250.9 29/11/98 O,227 Record shut in pressure while making repairs 11.2500 334.0 250.9 29/11/98 o.227 Record shut in pressure while making repairs 11.5000 316.0 250.9 29/11/98 O.227 Record shut in pressure while making repairs 11.7500 300.0 250.9 29/11/98 O.227 Record shut in pressure while making repairs 12.0000 284.0 250.9 29/11198 0.227 Record shut in pressure while making repairs 12.2500 269.0 250.9 29/11/98 o.227 Record shut in pressure while making repairs :i:!:i.~i~i00i:i:i: :i:i:i:~:2j~i:i:!: :i:i:~..~{~i:i :!:i:i:!:i:i:i:!:!:i:i:i i:!:i:i:!:!:i:i:!:i:!:i:i:i:i:i !:i:i:i:i:i:i:i:i:!:!:i:i:i:i:! [:!:!:!:i:i:i:i:i:!:! i:i:i:i:~;)-':i:!i!: i:!:iiii!ii i ! i !iiii ! ! i i!iiiiiii i i i i 12.5o00 256.0 250.9 29/11/98 0.227 Record shut in pressure while making repairs ~'-'.'.'.','.'.'-'.'.','-'.'.': '.'.'.'.'-'-'.'.'-'-'.'.'-'i '-:-:.'.'-'-'.'.' :.:.:.:.:-'.','-'.'.'.'i .'.'.'.'.'.'.'-:-'.:.'.','-'.'..'-'-'-'-'.'-'-'-;-:-Z-:-:-'-:- iZ-:-:.:-:-;,:.'-','- -:-:-:.:.'-'.'.:.'-:-:.:- -:-: ..... Z.: ..................... Z-:- -: .... :. -7 ::::::;:l:'J:;O0;O0:: ::: :::::':,~'q,~,O::::::; ::- :t~;:0: .: .... :::;::::: : : ::::::::::::::. : .::':::::::; :::: ::::::::: ..... ::. ~ ...... :- ::: ::;. . -:3;~;;~.~-:.:-;- :. -:-:': ..... :- -: .... : ...... :- -:':- ':-:':':':':':':-:-:':-:-:': 12.7500 244.0 250.9 29/11/98 O.227 Record shut in pressure while making repairs : ;;:.1.1: .1-~-1i0!0: :::.' :: : ~,d~.'O.: ::: :;::.t~.~0; :: :::::::¥ : : ::;:::::i::: ::::::::::::::;: ;:; :::i::::::::: ::::: ::::::::::; ":: ::::::::::::::::::::: ;::::::"~]~:~;::::;: ::::;:;:::::::::;: :::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::: 13.0OD0 233.0 250.9 29111/98 0.227 Record sh'ut in pressure while making repairs 13.2500 222.0 250.9 29/11/98 0.227 Record shut in pressure while making repairs · - - -Z- -:-;-'-'-'-'-'- -:. i .... '-'-'-"'-'-: ...... "'-:-'-: ...... :': ...... :-:- - -; ...... :-:.:-: ...... :.:-:-;.:. -:- -;-:-;-:. C ........ : .... ;.;. -'-'-'.:.'- - .:-: · -:.:-:-:-:-:-;': .;-:-:-;-7:. -:-:-:-:-:':-:-:': :-:-;':-:':':-;':-:-;':-:':- f:i:;:?:!~!~?!:;:,:i:!:!:5::-4.~!,O.:!:;:J: :!:;~?-!;O.i:? ::::::::::::::::::::::: ;:J:i:i:;:i:i:;:J:i:;:i:i:i:i:i i:i:;:;:;:i:i:;:i:i:i:i:i:i:i:i ;:i:;:i:i:i:i:i:f:;:i i:i:i:i:~!.2.:i:i:i:: i:i:;:i:i:i:i:i:i: f:i:;:i:i:i:i:i:i:i:i:i:i:i:i:i; 13.5000 212.0 250.9 Page 5 ; ' ALLIB '-RTON CUSTOMER TEST~O. '" Phillips Petroleum One [ Flow Test One Sh,0nna B,oyer GAS METER I.D. lOlL METER WELL NAME & No. FIELD I INTE~'VAL TESTED RIG NAME 5.761~] 2" Turbine NCIU Bt-ST Cook InletI N. Forelands Unocal 428 TiME PRESSURES TEMps CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H2S GRAVITYS SEPARATOR COMMENTS" , , , DAY:MO:YR DSP (psia) USHTR GAS(mmscf/d) GOR (scf/bbl) Mud/Solids GAS (mmsct] CO2 GAS (Air=l.0) PRESS (psig) * Gas measurements are of separator gas only. DTIME CSG (psia) DSHTE Mud/Solids WOR (bbt/bbl) Water Mud/Solids H2S SALINITY (ppml TEMP. (°f) *** Gas from surge tank measurements are from turbine meter (of) (64bbs) (bbls) (%) (bbls) (ppm) 29/11/98 0.227 !Record shut in pre~ure while r~aking repairs ::!::~i~::i~i~i~i::::i :i:i:!:~i0'i::::i: ::::?:0i:i: :::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::~!~!:i:i:i:i:?i:::~i ::ii:i:::~.~i~i~i!::~i i~i!il ?::~i!i~i i~:?;i ::! i :: i:: i i ii i :: :::::::::::::::::::::::::: 13.7500 202.0 250.9 29/11/98 0,227 Record shut in pressure while making repairs :::::::~2i-~$i(~::::: :::::::~::0::::::: :::i~.0:::: ::::::::::::::::::::::: ::i:::!:i:i:i:i: :i::: :i:i:i: i::: ::: ::::::::: ::::::::: ::::::::::::::: ::: :3'_~.;'.2.::::: ::::::::::::::::::::::::: ::::::::::::::: 14.0000 193.0 250.9 29/11/98 0.227 Record shut in pressure while making repairs 14.2500 184.0 250.9 29Ill/98 0.227 Record shut in pressure while making repairs 14.5000 176.0 250.9 29/11/98 o.227 :~ecord shut in pressure while making repairs 15.0000 160.0 250.9 29/11/98 0.227 Record shut in pressure while making repairs :!iiii!.~ii~i~iii!!! ii!!ii!~-~0:iiii:! iii!.~:~!ii! _-.......-...-...-.-..-...._.............-.-...-.-.-..-...-.~.-.-..:.-.......-.-.-i ........-.-...-.-.-~..-.-.-.-.-.-..-.-.: .... -...- ...... : ............................. ~::: Z:::::::: Z:.':::::::::::::: ::::::::::::::: ::: ::::: :::! : :3-2~:~ .... :: - - :: ...... .:- .:-:':-:-:':':':-:':':-:':' !:-:-:':-:-:':':-:':':':':-:' 15.2500 153.0 250.9 29/11/98 o.227 Record shut in pressure while making repairs 15.5000 146.0 250.9 29/11/98 0.227 Record shut in pressure while making repairs 15.7500 140.0 250.9 29/11/98 42.7 0.049 2.5 15% 0.227 0.25% 0.899 45.9 At 1 4:14 reopen well, continue on with flow test :i:!:i:)ti4i.;I;~i~:!:i:i !:!:i:i6$:~3~!:i:i:i i:i:~:i:! i:!:i~li:~.'-:!:i: :!:!:i:~l~!$i:i:!:i: :i:!:!:i:!:!:~_:~!:!:!:!:!:i: !:!:!:!:!:!:i:!:!:!: :i:!:i:i.~2:S!2i:!:!:i:::i:!:!:!:!:!:i:i:!; :i:i:!:!:!:izi;~:0:i:!:!:!:i:!:!:!:i:i:!:!0~i:i:i:i:!:i High rate do to one minute of flow 16.0000 135,0 52.7 3418.2 286.5 56.6 -- 29/11/98 50.7 0.097 26.6 15% 0.228 0.25% 0.899 192.2 At 14:25 increased choke to 18164 adj, ii::i::!?~i~::i::i::i !iiiiii~i'.o.':iiiii! !::ii~::i::i !::iiii~i~!ii::i i!i::iiiii~i~::iiiiii! iiii::i::!ii::!~:~::!:?:!iiiii !ii!iii::i::iiiiili::i:: ii::i::iii~i~!ii::~i!:: ii:?i::!ii::iii::!!ii iiii::i::i::i!i~:.0.iiiiiiiii!::~::iiiii::iii::~i?:i::iiiiii! o, meter on o, skid on bypass t6.2500 75.0 114.7 660.3 293.4 91.4 At 14:32 increased choke to 20164 adj.gas turbine on bypass 29/11198 47.7 0.810 188.7 15% 0.237 0.25% ', 0.899 188.2 Flow well as directed 16.5000 42.0 107.1 773.3 301,5 93,6 Pago 6 Phillips Petroleum One [ Flow Test One Shonna B0¥er (3AS METER I.D. IOILIMETER WELL NAME & No_ FIELD I~NTERVAL TESTED RIG NAME 5.7611 2"Turbine NCIU B1-ST Cook Inlet! N. Forelands Unocal 428 TIME PRESSURES TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H2S GRAVITYS SEPARATOR coMMENTS ,,, , DAY:MO:YR DSP (psia) USHTR GAS(mmscfld) GOR (scf/bbl) Mud/Solicb GAS (mmsc~ CO2 GAS (Air=-1.0) PRESS (psig) * Gas measurements are'of separator gas only. ~ ~{~i~ ~ ~i i i~ i ~. i~i~ ! i)~ ~.~i~ i ~ ::: ~: :i: :"~ ~:.:i:!:i:!~: :i:i:!~i:}:i :i~i:i:i:!:i:~: i:~[~.':i:ii'~-2.~~ ** GOR = Separator Gas I Corrected Oil Rate. DTIME CSG (psia) DSHTR Mud/Solids WOR (bbt/bbl) Water Mud/Solids H2S SALINITY (ppm', TEMP. (°f) *** Gas from surge tank measurements are from turbine meter (°f) (64tbs) (bbls) (%) (bbls) (ppm) 29111/98 46.7 1.247 697.7 15% 0.250 0.25% 0.899 190.6 At 14:55 odfme plate in service, tank 3 equals 46"=76.77 bbls i i:~6iO000 .~:~i0} :i ~:~.0} : ~'~'~i: :i:::'.1i7.'8~i8:::i: :::::~i~:i~.::::::::: ::::::::::::::::5::::::::::::::::::: :::::::::::::: :::::~i~):::i:: ::::i:67-i-~:i:i:i::: Gasturbine back inservice, rate 113scf/d cumm.-41 scf 16.7500 37.0 94.5 320.1 304.8 88.3 At 15:07 increased choke to 32/64 adj. ._ 29/11198 49.4 1,234 798.9 15% 0.263 0.25% 0.899 190.6 Tank 1 and 2 no change 17.0000 48.0 86.1 276.5 307.7 85.1 At 15:24 all fluid going through 2" turbine oil meter 29111/98 53.6 1.591 1000.1 15% 0.279 0.25% 0.790 196.7 Flow well as directed 17.2500 87.0 81.8 284.5 310.6 87.6 Main separator blew gas to surge tank, high gas rate 29/tl/98 54.7 1.364 642.5 15% O.293 O.25% 0,790 192.5 Tank 3 equals 93" = 155 bbls 17.5000 77.0 82.9 378.8 314.6 82.3 At 15:50 start pumping tank 3 to girder tank 29111198 55.1 1.428 794.1 2% 0.308 0.25% 0.790 127.5 Increased choke to 48164 adj. 17.7500 89.O 85.4 37.1 315.0 63.4 At 16:06 new APl at 42.4 corrected at 60 f 29111/98 57.1 1,302 755.8 2% 0.322 0.25% 0.790 98.9 Flow well as directed ~ i~ i~ii~ ~ii ~ii i ~ i ~::~::i::~::i !::~::~:Oii!! i?::i~i~;:ii~::!::~::i!~::ii~i~;::;:iii::i ?iiiiii::~i~i::iii::i::i:: i::i::i::~i~!iii::~i~?i :i::~::i::~i~;:~i;:i! ::~iii~:;::ii!i~::i::i :::::::::::::::::::::::::::::::::::::::: .... i8.'0000 ......... 8910 ....... '86.'9 .................... :~5',5 .................................. 3i5,3 ' 81.1 29/11/98 57,9 1,041 1106.3 1% 0.333 0.25% 0.790 93.5 NO tank reading while pumping down tank 18.2500 123.0 103.2 9.7 315.4 90.4 29/11/98 59.9 1.519 933.9 1% O.348 0.25% O.79O 136.1 Gas turbine meter rate 91,68 scf/d cumin.-122 scf i ! !~..8.!~!~i ! i !il i i~.5.! i ! i ii i~,'..0.! ii !iiii~i~-i! iii!iiii!iii.-t.~!:!iiiiiiiii iiiii!ii!i~.2..-4.;~!iiiiiii: i:i:i:!:i:i:i:!:i:!: :!:i:i::7.-~ig..i:!:i:i: :i:i:!:i:!:!:!:!:! i !i!ii ~;Z..'.-4 ! ! !: i:i! :i:i:!:.-t.:0...2:.-:5-:i:i:i:i At 16:56 orifice plate out of service 18.5000 174.0 89.4 16.7 315.6 86.9 29111198 60.6 0.622 341.7 1% 0.355 0.25% 0.790 118.6 Tank 3 equals 30" = 50 bbls ::i: 3~i~i~::: ::: :~.~:~3:: :i: !: :~:~O:: :: ~ :~id~J::: :i: :i: :~.~/;~:::: :!:::: ;~3i~;~: :!::: ::::i: ::::: ::: :7.e~i~ :::::::::::::::::::::: 18.7500 219.0 89.7 18.6 315.8 87.7 29/11/98 59.8 0.053 47.5 30% 0.355 0.25% 0.790 72.5 Flow well as directed ~.!;.i~.i~i~.!.~.i,~.ii~.~.~i::~..~.~i!:; i::~::~:0:i~::~ ~i~i~i~!~:: !i~i~i;:~::~.o.'.'ti~::~i~!~::~ !~::i::;!~::~!!~:i:;::~i!ii::ii :i~::~!~?:;:: !:i i::::i:! ~ ~:i::: i i ::;: :: ! :: :: i~i :: :: :: :: ! :: i i ::::::::::::::::::::::: .'.o.'~ 19.0000 255.0 85.2 479.8 320.8 83.6 29/11/98 60.1 0.729 117.5 30% 0.363 0.25% 0.790 76.5 Tank 3 equals 48.5" = 81 bbls iii -;{~i~J~ i i i i iii ~.'~.~ i i i i i i ~jii i; i i~i~'.8:.~i;i;iiiiiiii; i~j{iiiiiiii iiiiiiiiiii~-~iiiiiiiiiii ii;iiiiiiiiiiiii;;il iiiiiii~;~iiiiiiii; iiiiiiiiiiiiiiiii!i iiiii iil i~ii i ii; i i ii i i~i~ i; i::i il At 17:35 Switch gas turbine meter to other meter 19.2500 309.0 82.6 2683,2 348,7 79.7 At 17:41 Gas turbine rate 480 scf/d cumm- 20 scl Page 7 RTON cusTo TEST O. JFLOWPE OD Phillips Petroleum One Flow Test One ,. Shonna B0yer GAS METER I.D. IOtL METER WELL NAME & No. FIELD IlNTERVAL TESTED RIG NAME 5.761II 2" Turbine NClU B1-ST Cook Inlett N. Forelands Unocal 428 ., TIME PRESSURE~ TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H2S GRAVITYS SEPARATOR COMMENTS , .... , ,, DAY:MO:YR DSP (psia) USHTR GAS(mmscf/d) GOR (scflbbl) Mud/SolidsGAS (mmscf) CO2 GAS (Air=l.0) PRESS (psig) * Gas measurements are of separator gas oniy. DTtME CSG (psia) DSHTRi Mud/Solids WOR (bbl/bbl) Water Mud/Solids H2S :SALINITY (ppm) TEMP. (of) *** Gas from surge tank measurements are from turbine meter . (of) (64tbs) (bbb) (%) (bbls) (ppm) 29/11/o~ 60.9 2,196 1466.1 30% O.386 O.25% O.79O 78.O Flow well as directed :: ~-7. ~l;5:00 ::::::: 5~0_:3::: ::: ~3.0:::: :¢1~:~'.~i :: ~:::: :.J~7:~ :::: :::: :1:029 .'1:::: ~:::::. :--:. :: ::-85,~J:~.:- :. :-.:.:-:-:-:-:.:- !:-:-:-:.:.:'.42.'.4:.:-:-:.:-: .:.:-:,:-,~8: -:-:-:-: 19.5000 347.0 84.1 648.6 355.5 81.5 29/11/98 60.1 2.040 1270.1 30% 0.407 0.25% 0.790 71.3 Increased orifice plate to 2.000" 19.7500 373.0 85.6 695.4 362.7 81.0 29111/98 60.2 1.953 977.2 3% 0.427 0.25% 0,790 67.6 Flow well as directed 29.0000 385,0 87.8 62.5 363.4 82.7 29/11/98 60.1 1.8,94 1011.9 1% 0,447 0.25% 0.790 65.2 Tank 3 equals 73" = 122 bbts ::i: ~;~i~i00 :::::: :i:46~!:$::: ::: ~"~,~):::: ::::::::::::::::::::::: :::: ::: :!:~8;J:i2: :::: ::::i:::::: !:i:: :~:~ -~:i:i:!: i:i:i:i:i:i:i:i:i: !:i:i:i:i:i~,~'.4i:i:i:i:i:i :!:!:i:i:i~3i6i:!:!:!:i Gas turbine meter rate 650 scf/d cumm.- 42 scl 20.2r-----------------~ 400.0 84.2 58.5 364.0 3800 82.7 At 18:38 Begin to pump down tank 3 29/11/98 60.1 1,965 1132.2 1% O.468 O.25% 0.790 67.9 Flow well as directed 20,5000 415,8 84.2 17,4 29/11/98 60.1 2,122 1181.8 3% O.490 O.25% 0.790 75.7 Tank 3 equals 103" = 171 bbls, pumping down 20.7500 473.0 87.4 53.9 364.0 38oo 84.1 Meter factor 1,004 29/11/98 60.1 2.220 993.1 3% 0.513 0.25% 0.790 90.9 Flow well as directed :::::::::::::::::::::::::::: f iii i :: :?::: i:: ii:: 21.0000 533.3 88.0 67.1 364.0 3800 83.6 29/11/98 60.1 2.273 1008.9 1% O.537 O.25% O.79O 91.9 BaroJd extracted all mud from sample ::.!::::.i~::~::~ii::i::f ::i::iii::i~.~iiii::iii !ii::~i-~iiii iii::i~i~iiii!ii::!ii::!::i~i~iii!::!iil ::i::!::iii::i!i~i~!i!::i::ii i::iii::iii::ii i ii:: :: i:: ::~ ".2.' f :: :: i :: :: :: :: ! ii::!ii ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: New chloride of 3800 ppm 21.2500 584.4 87.4 22.3 364.0 38OO 83.1 No strap while pumping down tank 29/11/98 60.1 2.277 880.2 1% 0.560 0.25% 0.790 92.0 Flow well as directed 21.5000 630.3 87.1 25,9 364,0 3800 82.9 29/11198 60.1 2,215 880.2 1% 0,583 0.25% 0,790 89.4 Gas Turbine rate 1461.60 scf/d 21.7500 672.6 86.8 25,9 364.0 3800 82.6 29/11/98 60.1 2.220 877.4 1% 0,606 0.25% 0.790 89.1 Flow well as directed 22,0000 711.6 86.8 25,8 364,3 3800 79.9 Page 8 L i B U RTO N I Phillips Petroleum One _L._ Flow Test One Shonna Bo~/er 5,761 , ! 2" Turbine NCtU B1-ST Cooklnlet ! N. Forelands , Unocal428 , , ,, TIME PRESSURE8 TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H2S GRAVITYS SEPARATOR COMMENTS DAY:MO:YR DSP (psia) USHTE GAS(mmscf/d) GOR (scf/bbl) Mud/Solids GAS (mmsct3 CO2 GAS (Air=l,0) PRESS (psig) * Gas measurements are of separator gas o'nly. :: HRLMIN:$EC:-,:W.I~ .P. (1:~,~): .::..~4.U:T:.:.-:.:.:MF~D..:.:-: :~i¢i ::i: :i:i: :~:~:i:!: :!: : .~i~:i: I ** GOR = Separator Gas I Corrected Oil Rate. DTIME CSG (psia) DSHTE Mud/Solids WOR (bbl/bbl) Water Mud/Solids H2S iSALINITY (ppm) TEMP. (°f) *** Gas from surge tank measurements are from turbine meter (of) (64tbs) (bbis) (%) (bbls) (ppm) 29111198 60.1 2.192 884.2 1% 0,629 0.25% 0,790 87.9 Gas Turbine rate 1582.40 scf/d i:i:i:i~i3~i00i:i:!: :i:i:!:i~-2}2i:i:i:i' :i:i~¢,i;3i:i ':: :.~:~,:' ::i i::: :~;4~,~i2: :i::: : :!:: :~i3:::: :i:i: :i::: :i: :i i:: :~.~0~i3: :i: : :i:i:i:i:i:!:i: 'i:i:i:i:i:i'.4~,~i:!:i:i:i:i :i:i:!:i:i98il~!:i:i:!:: [Gas turbine cumm.- 181 scf 22.2500 746.9 83.2 25.3 384.5 3800 79.9 29/11/98 60.1 2.176 929.8 3% 0.652 0.25% 0,790 87.3 Flow well as directed ........-.......-............................-.......-........-.,.......-...-...................-.....-.-...-.-.......-.-.-.-..-.-.-.-.-...._-.:...,:.:.:.:. :.:.:.:.:.:.:.:.:.:...:.:.:.-.-.....--..-.:-:.: .:.:-:.:-:.:.:.:.: .:.:.:.:.:.:.'.'-:-'-:-:.:-:-:-x<->>~-' ii !:~ ~ ~iiiiii !:~:i:i:!:! i:!:~:'~:i:! iS!~:~i:::i:::!:!:!:!:.2.~':.-e-:i:i:!:;: :!:!:!:i: ~::: :: :F :::::::: ::: ::: :?:~.::7::::::: :::::::::::::::::: ::::::::::::::::::::::::: :::::::::::::::::::::::::: 22.5000 780.5 83.2 73.2 365.3 3800 82.4 29111198 60.1 1.861 802.3 3% 0.671 0.25% 0.790 73.5 Gas Turbine rate 1588.0 scf/d 22.7500 812.5 87.0 72.5 366.1 3800 80.8 29/11/98 60.1 1.865 941.8 2% 0.691 0.25% 0.795 72.5 Flow well as directed k:: :.~:1:7.~.:~: ::: :::::::::::: :: ::::::::::::::::::::::::: :.:.:.:.:-~.~.:-:.:-:- ::!:-5:'i: ~;iO~i:!:i: :i:!:i:i~/'-'~!:2i:!:i:i: :i:!i~,!:~i:!: :i:!:.'~:'~l~.ii:i:!:!:i:i:i:~.~.-7.9.'i~i i ! i i i!ii i i ~!~i!i ! i !i !i!i!i!ii!!i!iiii '""'" ...... "'" '"'"'"'"'"'" '"'" ....... "': .... :'" '"" .... 23.0000 849.0 82.2 40.7 368.5 3800 76.4 29/11/98 60.1 2,342 1082,5 2% 0,715 O.25% O.795 94.9 Gas Turbine rate 1343.20 scf/d i:: ii~J!i~i~ ::iii:: i i i :: ~.~! :: i ::ii ~!.~ ::i! ii:: ::~::~iii i i i i i !~'.~i~iiii!:: } iii::iiii!::~i.e'_'iii!i!ii iiii!iiiiii::!i!::!i! iiiii~i'0.'i!iiii i!!iiii!i! i i iii::i i~'2."i~i ! i i i i ::i iiiii::i~iiii::iii Gas turbine cumm.- 237 scf 23.2500 880.5 82.2 44,5 367.0 3800 77.9 29/11198 60.1 2.181 810.5 4% 0.738 0.25% 0.795 87.8 Flow well as directed 23.5000 903.1 80.8 113.2 368.1 3800 78.3 29111198 60.1 1.906 851.7 1% 0.758 0.25% 0.795 75.3 Gas Turbine rate 1610 scf/d ::: '-~ibi~i0~:::::: :i~:~i:!::: 3 ~:~: 3 :i:i:~:'~ii:! i ! !:!:! ~ ;4:i:! ! i} ii ii!i ~i~ iiii! ! ! ii iii ii iii i!i } ! i ~.".~.i~i i ! ~i ! !i iii i i i !iiiiii!i!ii4~!iiiiiiii!ii iiiiiiii!i~i~iii!i!iii Gas turbine cumm.- 272 scf, shut down pumping 23.7500 901.1 83.2 22,9 368.4 3800 81.3 29111/98 60.1 1,964 1042.6 1% 0.778 0.25% 0.795 78.1 Flow well as directed · .-.-.-.'.'.-.'.'.-,-.-.-,'.' '.-.-.-.'.-.-.-.-.-.-.-.-.-'.-.'-'-'.'--.--- -.'.-,'.'.'.'.'.'.','-' 7.'-'.'-'-'.'.'-'-'-',--'-'-'-:.1-'.'.'.'-:.:.'-'-'-;.'.:-:-:-:- :':'X';':':':':';' ;':-:'-"-""'"-"7;':~ ':':':':':';':':': ':':':':';':'""?':':':".'>; ::: ~:15 80 ::: :::: 62:1.'.4: ::: :: 65;:~- :::: :~:.a~.:::::: ::::::::::::::::::::: ::::::::::::::::::::::: -:.:-:.:.:.:-:.:-:.: :::::::::::::::::::::::: ::::::;.4.'.2,.'.4.::: ::::::::::::::::::::::::::::::::: 24.0000 890.7 87,0 19.3 368.6 3800 83.3 29/11/98 60.1 2.07O 1061.4 1% O.8OO O,25% O,795 83.O Gas Turbine rate 1260.40 scl/d, cumin.- 301 scl '::: :22i38i0~: :: ::: :ff~.-7.:::: : :~¢8:: :: ~::~d}::::: ::: :1:958 .4:: ::::::: :::::::::::::::::::::: :::::::::::::::::::: :::::: ¢ .2~5.: ~3 ::: :! :::::::: :::: ::::: :~2i:~:::::: ::: ::: ::.9!.:..- ..:::::::::: Tank 3 equals 37~' = 61 bbls 24.2500 926.1 85.1 19,9 368.8 3800 82.4 29111198 60,1 2.118 951.5 1% 0.822 0,25% 0.795 85.3 Flow well as directed 24.5000 954.6 86.8 22.8 369.0 3800 83.4 29111/98 60.1 2,138 950.5 1% 0.844 0.25% 0.795 86.2 Flow well as directed !!iii!i~:~i~i~!i!::i ?iiiiii~{5?iiiiiii ::iii~ii~ii!:: i!iii~i~ii::!i i::i::iiii~."~i:;ii!iiiiiiii !::!iiii!;!~:~iii!!!!!i :i!!i!i!i!ii!!i!!!ii!ii!i!i!~..~..'.?:~ii::!::!i ::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: Gas Turbine rate 1426.0 scf/d, cumin.- 329 ,cf 24.7500 979.0 88.0 23.0 369.3 3800 82.0 Tank 3 equals 64" = 106.7 bbls Page 9 Phillips Petroleum One ! Flow Test One ,Sh, onna Boyer GAS METER I.D. lOlL METER WELL NAME & No. FIELD ]INTERVAL TESTED RIG NAME 5.761Il 2" Turbine NClU B1-ST Cook InletI N. Forelands Unocal 428 .... , , , TIME PRESSURES TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H28 GRAVITYS SEPARATOR COMMENTS , DAY:MO:YR DSP (psia) USHTR GAS(mmscf/d) GOR (scf/bbl) Mud/Solid~ GAS (mmscf:, CO2 GAS (AJr=l.0) PRESS (psig) * Gas measurements are of separator gas only. DTIME CSG (psia) DSHTE Mud/Solids WOR (bbt/bbl) Water Mud/Solids H2S SALINITY (ppm) TEMP. (°f) *** Gas from surge tank measurements are from turbine meter (of) (64ths) (bhls) (%) (bbls) (ppm) 29/11/98 60.1 2.176 960.3 1% 0.867 0.25% 0.795 87.7 Flow well as directed :: :-2~ -~iO0::::: :!:iZ~i~:~ :!:i:i:: :i~.~i:i: :!:!:.~:!~i~:i:!:i~i:!:i:i:~i~i:i:!:i:i !:i:i:i:!:~i6i:!:!:i:i :i:i:i:i:i:}:i:i:i:i i:i:i:!~¢::~i~!:i:i: i:i:ii !! ! i i; i i i !i i.'.4.~i i i i ii! 25.0000 1001.0 83.1 23.1 369.5 3800 81.4 29/11/98 60.1 2.170 945.5 1% 0.889 0.25% 0.795 87.6 Flow well as directed ::!ii::i~i~i~!iiiii ::iii::i::!~i~.'ili::i::!i i!::!~.~iiil ::iii!~i~iii!iiii::!i!::ii~i.'2.'iii::!ii::i iiii!!iii::~i~iiiiii!ii iii}?:!!i i! iii iii i'~i ! ii i i::!i!!iii ! i ! iii i~i~!?iiiiii ii !iii::!::ii!~i~ii!::i::iii Gas Turbine rate 1481.0 scl/d, cumm.- 368 scf 25.2500 1021.0 85.5 23.4 369.7 3800 82.2 Tank 3 equals 92" = 153.3 bbis 29111198 60.1 2.244 969.9 1% 0.913 0.25% 0.795 9O.9 Flow well as directed 25.5000 1041.0 86.4 23.7 370.0 3800 83.2 30/11/98 60.1 2.278 970.2 1% 0.937 0.25% 0.795 92.5 Flow well as directed :i:?:i~'-'~.'..'i~.~.' .':i:ii::: !iiii::!i~??i:::!::i !::ii~.'.Sii? :::::::::::::::::::::::::::::::::::::::::::::: i!:: i!ii::!~i~!i!iiiii!i !::!iiii::i::!i i :: :: i i i ~i'-0'-i i i i :: :: :: i i ::!i!::! iii ::!i!i!::.':.4..'-Z_~::iiiiiii::!i! ii!i!i!iii~-~i~!i!iiii:: Gas Turbine rate 1499.0 scf/d, cumm.- 392 scf 25.7500 1062.0 87.6 24.0 370.2 38oo 83.4 Start pumping tank 3 .. 30/11/98 60.1 2.264 944.0 3% 0.96o 0.25% 0.795 91.6 Flow well as directed 26.0000 1082.0 87.5 74.9 371.0 3800 81.3 30111/98 60.1 2.194 910.8 3% 0.983 0.25% 0.795 88.3 Flow well as directed !::i i~!~!~:: :: :: i :: ::i:: ii~!7", i i i :: i } ~:.3.'iii:: :: :: i~i~i?:::::i :::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::: !::::ii?:i::i!i::iii::ii iii::ii~.~i~::iiiii ::::::::::::::::::::::::: ::i::i::i::i}ili~.~ii~iiii:: i :: :: i ili ::~i.5.1:: :: :: ii! Gas Turbine rate 1628.0 =f/d, cumin.-428 scf 26.2500 1103.0 84.9 75.3 371.8 3800 81.1 30/11/98 60.1 2.212 966.2 3% 1.006 O.25% O.795 89.3 Flow well as directed 26.5000 1110.0 87.3 71.6 372.5 3800 82.7 30111198 60.1 2.214 976.7 3% 1 .O29 O.25% O.795 89.5 Flow well as directed ::i i ii{~i~ i :: i ::ii:: ::~¢ii:: :/:: :/i~¢i.'.8.':: ii :::::::::::::::::::::::: ::i::ii::iii~i~i::i!i::ii'. ii::::i::::::ii~?:'iiii::i!i::!::i ::iiiii::i::!iiii::!::iii iii!i!.~5.'i~i::iii:: !i!::ii!iii!i!iiiii iii::iii::i!i~.~ :: i i i :: :::: :::::: :: ~ ~::i iii Gas Turbine rate 1536.0 scf/d, cumm.- 462 scf 26.7500 1132.0 88.0 70.9 373.3 3800 83.7 30/11/98 60.1 2.183 987.8 3% 1.052 0.25% 0.795 88.2 Flow well as directed 27.0000 1151.0 86.3 70.6 374.0 3800 84.0 30/11/98 60.1 2.190 982.5 3% 1.075 0.25% 0.795 88.4 Gas turbine meter rate 1545.0 scf/d, cumin.- 490 scf 27.2500 1166.0 86.2 69.7 374.7 3800 82.0 30/11198 60.1 2.020 890.4 3% 1.096 0.25% 0.795 80.8 Flow well as directed 27.5000 1178.0 88.0 71.0 375.5 3800 83,2 Page 10 RTON ~u~To~R ~s?~o. IFLOW.~OU~TOM~R Phillips Petroleum, One I Flow Test One Shonn~ Boyer, GAS M~ER I.D. i~L M~ER ~LL ~E& ~. ~D IIN~ TES~D R~ ~E 5.761~! 2" Turbine NCIU BI-ST Cook InletI N. Forelands Unocal 428 , TIME PRESSURES: TEM~S~ CHO~ FLOW ~TES ~TIOS BS&W CUMVOLS CO~H2S G~S SEP~ATOR ~OMMENTS , , , DAY:MO:YR DSP (~) UNiI!'R GAS(m~ld) GOR (~f~) Mu~lids:GAS(mm~ 002 GAS (~1.0) PRESS(~ig) * G~ur~areof~r~ gasonly. DTIME CSG (~) Dh' i'I'R Mu~Sol~ WOR (b~l) Wa~r Mu~Soli~ H2S SALINI~ (~m] TEMP. (~ ~* Gas ~ sur~ ~k ~~en~ are ~om ~ine meter ('f;, (64~) (bb~) (%) (bbb) (~) ~11~ C~.I 1.9~ 9~.3 3% 1.116 0.~% 0.7~ ~.1 Flow well ~ dire~ :~:~:~:~::~:~:~:~: :~:~:~:~;97~:~:~: :~: 67.9 :~:~:~::.~:~:~:~:~:~:~:~:~:~:~:~ [:~:~:~:~:~j~:~:~:~:~ ~: :~:: ::: :~:? :: :~6~[3 ::: ~:~:~:~:~:~:~:~:~: [:~:~:~:~:~:~:~:~:~:~ :[:~:~:~:~:~:~:~:~ Gas Turbine rate 1141.0 scf/d, cumm.- ~7 scf -...,.-...-.-.-.-.-,,...,,.,- ..-.-...-.,......,,.-.-.-.--.- . -...-.-.-.-,..-....-.,...'...-.-.-.-.-.-.'.'.-.-.-.-.'. ,',-.-.-.-,-,-.-.-.'.-.-.'.-.'. ......,...-.......-.:.-.....-...-.,...,...,,-., ...-...........,,, ...............-.-. ,.- .................. 27.7~ 11~.0 89.3 61.7 376.1 ~ ~.6 ~/11~ 60 1 1.979 1~7.2 1% 1.1~ 0.25% 0.7~ 78.7 Flow well as directed ~::~::~:: ::~::~::~::~ ?~ ~.o ??~??~: :?:::?:::~::~? ~::~f:~:~f: :: ~ ~ ::::~:: ::~ ::~ ~:: ~~ f:~::f:~f:~f:f: ~:~ ~~ ~ ~ ~ 28.~ J J~.O 8gA ~.J 376.3 ~ ~.0 ~/J J/~ 60.~ J .~J ~O.J J% J A57 0.~% 0.7~ 7g.2 Flow well ~s directed "'"""'"'"'"'"'"'""28.2~ '"'"'""'"'"'"'"'"'J~.O "' ~.2 '"' '"'"'"'" ...... ' .... ~.j'"'"""'"'"'" ...... ' .................. t .... 3~ .................................... ~ ~.2 T~nk 3 pureed out, 6" in equals JO bbls ~/j j/~ ~.¢ J .8~ g~o.6 J~ J .J76 0.~ 0.7~ 72.5 Flow well ~s dire~ed ........................................................................ .- -.-, ..-...-,.....- -, ........................ ...-......,........~ ...-.-.........~....-,-., :::::::~:~:~::::::: ::::::::~:::::::: ::: 68.3 :::::~:~::::: ::::: :::~:~::::::::: :::::::::::::::::::::::: -:::-:::::.:-:-:.:-: :-::.:~7~:~: :: :::::::::: ::::::~:::::: ::::::~J:_.:::::::::: ...........~...,,,....,,.,.., ........,.........,........... ..-.,.-.-.....-.....-.,....-,. ............. ..,.-.-...-..-.-.-.-.-,..-. -.-.-.-.-.-.-.-.,,-, r......- ................................... - ........... 28.~ J J 67.0 88.~ ~.6 376.8 ~ ~.0 ~/J J/~ 60. J J .~7 J~J .4 J~ J .J~ 0.25~ 0.~ 73.2 Flow well ~s directed 28.7~ ~J~.o g4.2 J8.2 3~.0 ~ ~.5 T~nk 3 equals 24": 40 ~J J/g8 60.~ J .~ J~J .5 J~ J .2J5 0.~ 0.795 73.g Flow well ~ dir~ted ...............-......,..-...,-.-,-.-.-...-,....,,-...-.... .-.-...-.-,-...,.-.-.,..,-.-.-.....-,-...,...*.-.-.-.-_ -.-...-.-...-.,....-.-..-_-,- .... - .................... '..' .... ..., -.-.-..- .......................... ~.~ JJ~.O 88.5 JS.0 3~.J ~ ~.7 ~JJ/~ 60.~ ~.~7 ~7.7 J% J.~2 0.25~ 0.7~ ~.2 Flow well ~s directed ............................................. · ...... -.- .... -..,...,-,..-.-...-.- ......................................... ~.2~ JJ32.0 8~.6 Jg.3 3~.3 ~ ~.8 T~nk 3 equals 42" = 70 bbls ~/~ j/~ ~ j J.~J ~2.0 J~ J.2~ 0.25~ 0.795 6~.J Flow well ~s directed :-:-:-:.'.:.'-',:-'-'-:.:.:-: :-:-:-:-~-'-'.:-'-:-:-:.: :-::::::::::::::::::::::~:~:~:~:~.:.~.~:~:~:~: :~: ~., ::.::.::~::~.~.~.:: ~.::.~.::.~.~.::~.::_:: ~::~::::::~ ~::::~?:~::~.~::~::~::~ f::~::~S~::::~::~::~::~::~::~::~ :::::::::::::::::::::::::::::::::::::::::::::::::: ~.~ J~2.0 93 3 J5.4 3~.5 ~ 87.8 ~/J J~ 63. J J .~ ~ J~.7 ~% J .~ 0.~% 0.7~ ~.8 Flow well ~s dire~ed ,...-.-..,-,-...,.-.-.-..,-.-.i.,.-...-.'.-.-,-.-,-.-.'.-..'. ,'.'.'.'-'.',-,'-'.'-'.'~'.','-'.'.'..'.' ......... '- ---'.'.'.'-'-'-'-'-',',' ·, -'.'-','-'-'-' ..................................................... ~.~ J~7.0 g3.g J4.g 3~.7 ~ ~.g T~nk 3 equals 42" ~ 70 bbls ~/J J/g8 60.~ ~.752 J J J5. J J% J.2~ 0.25~ 0.7~ ~.7 Flow well es directed .-.-.......-.-.-.-......,-.-....-.-...-...-.-..,..-.-...~-.. .......,..........,...,~.-.,.........,..-...,.-.-.....*...-,..,....-...........-_,......,........-.... ..... . ................................................. ~.~ JJ~.O g3 2 J6. J 3~.8 ~ ~.5 ~/J~ 60 J J.7~ JO70.g J~ J.~ 0.25~ 0.7~ 70.3 Flow well ~s dire~ed :-:-;-:-:-F,-.-~-...-:-:-;-:' -:-:-;-:-,..-:-.-.-:-:C-:. ? ~.2~ JJ~g.o 87.7 J7A 378.0 ~ ~.7 T~nk 3 equals 72": J20 bbls __ Page 11 Phillips Petroleum One [ Flow Test One Shonna Boyer ....... G,~,S METER I.D. JOIL METER WELL NAME & No. FIELD IINTERVAL TESTED RIG NAME 5.761Ij 2" Turbine NClU B1-ST Cook InletJ N. Forelands Unocal 428 ..... TIME PRESSURES TEMPS CHOKE FLOW RATES RATIOS BS&W ~UM VOLS CO2JH2S GRAVITYS SEPARATOR COMMENTS - , DAY:MO:YR DSp (psia) USI-iTR GAS(mmscfld)!GOR (scf/bbl) Mud/Solids GAS (mmscf) CO2 GAS (Air=l.0) PRESS (psig) I* Gas measurements are of separator gas only. DTIME CSG (psia) DSHT~ Mud/Solids WOR (bbl/bbl) Water Mud/Solids H2S SALINITY (ppm] TEMP. (°f) i*** Gas from surge tank measurements am from turbine meter (°f) (64ths) (bbls) (%) (bt)Is) (ppm) 30/11/98 60.1 1.816 1003.5 1% 1.322 0.25% 0.795 71.5 iFIow well as directed 30.5000 1132.0 85.2 18.5 378.2 3800 84.5 30/11/98 60.1 1.863 987.4 1% 1.341 0.25% 0.795 73.7 Flow well as directed !:!:i:!:5'.':'.0~; ~:0~.' ~:!:i:i:l :i:i:i:i$~.3i:i:i:i: :i:! .6~.' !.,Si:i: :i:i:~ .4~.:~'.8ji;!:}:I :::::::::::::.6::::::::: :::::::::::.77.-:::::::::::: ::::::::::::::::::::: :i:i:i:.l:~;~:!:i:i: :i:!:i:!:!:!:!:i:i: i:!:!:i:!:i:~:2:~:!:i:i:!:!: !:i:!:{:i:~.9..:i:i:i:!: Gas Turbine rate 1021.0 scf/d, cumm.- 6{53.2 scl 30.7500 1141.0 91.5 19.3 378.4 3800 85.9 [Tank 3 equals 83" = 138 bbls 30/11t98 65,0 1.914 1008.5 1% 1.361 0.25% 0.795 76.1 iFIow well as directed i::: ${{5~;X~ :: :i::: :~{6J~:::: : :.~.~:: :: ~1~ti~d~:::; ::: :::::189~;3:::::: ::: :::::::::::::3:::::::::::::::::::::::::::::::: :::::::1:~..;~. ::::::: :::::::::::::::::::::::::::::::::2.::::::::: ::::: .1~:i. ::::: 31.0(xx) 1149.0 9t.5 19.4 378.6 3800 87.1 30111/98 65.1 1.908 992.4 1% 1.381 0.25% 0.795 76.1 Flow well as directed :::::::~':2b::~::: :::::6~;~2::::: :::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::~8~:6i::: ::i::::::: ;i:::i:i:i~,~'4i:i:i::: ::i::: 8~i-~: :i:i:i:! Gas Turbine rate 1060 scf/d cumm.- 678.2 scl ·..-.- -. - - -. .... . _ . . '.'.-.- .'.' ..... '.' .'.'.' ...... ".'.'.! '.'.'.'.'.'....'..'.'.'.'-' '.'.','-'- .... ., .-.-..,-.* r.-...-.-.-...-.-.-.- -.-.-... .... ;"'"'"" '""'""'-'"' ' *- .... ' ............. "" '" '"'"'"""'" II .... 3;1'.~Z5~ ...... '1'1'55~0 ..... 9i'.~ .................... 1'9.'~ ..................................... 3:7'8.8 3800 88.6 ITank 3 equals 108 = 180 bbls 30/11/98 65.2 1.911 994.5 1% 1.401 0.25% 0.795 76.1 Flow well as directed :.- -.-.-.-...-...-.-.'.-.-.'.' '.','.'.'.','.'.'.'.-.','. '.'.'-'.'.'.'.'.'] '.'.'.'.' · '.'.'-' '.' , ............ -'.- ', .' '-'.'-'-'-'-'.'-'-'-'-'.','--'-'.'-'.','.'---'.'. -'-'-'-'-'-',','-'-'-'-'-'. -'-'.'-'-','-'-'-','-'-'-'.'-'-Z-'-'-Z-'.;-X-Z-Z- :.;-Z-:-Z-'.'::,'-X'X-= ';i!i:i:!-.5-!~! .~.-i:i i i i i!i .-s.~.0-i0. i i i ii ~:.:6. i i ! i i~i-:a.'.d'.-~i ! i~- :!:5 :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::?:8~.-:.~::::::: ::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::~;.2.::::: 31.5000 1161.0 92.2 19.7 379.0 3800 87.2 30/11/98 65.4 1.891 1008.4 1% 1.421 O.25% O.795 75.3 Flow well as directed i:iii!i!i~i~!!i!iii ii!iiiii~j~!i!ii!! !ii!~.~iiii ":'"'" ':"~" '~ ' ..... ""-':" ..... I--':----. .... -------.'.-.---'-'-':-.--'-'---'.--.----- .... .----.------------'--:-:':-,~:-:':':'.-:':'"'"-:'::::::::: :::::::::::::::::::::::::::: -.:~ ac~: ...... :1~75- ~ ........ :.- L~98,2 ..... ...:.-.:-:.:.:-:..:-:.:.'~9:1:7.:~-:-:.:.-:-:.:-:-:.:-:-:-:-:-:.:.:.:.:42.:4-:..-.-,-.- ....:.....84~3~..-...-.- Gas Turbine rate 1021,0 scf/d, cumm 696.2 scf i 31.7500 1168.0 91.9 ............ 19.2 ' 379.2 38OO 88.4 j Start pumping tank 3 30/11/98 65.5 1.895 1017.1 1% 1.440 o.25% 0.795 75.4 Flow well as directed I: ::: :~::¢;,~::0~::::::: ::::::::507,:2::::::: ::::~r,~:::: :::::~8:~dj::::::! :::::::::::::::::::::::::::::::::::: :::: :: ::::::::::::::::::::::::: :i: ::: :::::: :::i: 4.2,~::::::::::: ::::::::::~..:: :::::::::: 32.0000 1175.0 90.0 19.1 379,4 3800 88.6 30/11/98 65.6 1.857 998.9 1% 1,46o o.25% o.795 73.7 Flow well as directed ::::::::::::::(3.~::::::::::: i::i::!i!::~'::~i::::i::ii" ii!i~}~iii! !::iii~i~i::ii ! ::::i iiii!i~i~iii i!:: :: } } i i :: ~i~i :: i i!i !i:: ii! ::i!::i :: :: i i :: i::i iii~::~::i}::il ::i::::iii!!ii!ii:::::::: ,::::iiii}::i::::~:2.'."~iii::!iiiii! ii::!ii!i::i~i~ii!i!::iii Gas Turbine rate 10:30.0 scl'Id, cumin- 718,2 scl' 32.2500 1182.0 93.4 19.1 379.6 38OO 89.3 i Pumping out tank 3 30/11/98 65.4 1.918 1046.0 1% 1,480- 0.25% 0.795 76.5 Flow well as directed 32.5000 1194.0 90.8 18.8 379.8 3800 89.1 Flow 30/11/98 65.4 t .794 959.5 3% 1,498 0.25% 0.795 70.7 well as directed 32.7500 1190.0 92.9 58.6 380.4 3800 88.8 Gas Gravity .892 30/11/98 65.6 1,825 1053.1 3% 1.517 0.25% 0.795 72.3 Flow well as directed :!:: :~i.;i~!~::::: ::: ~}i:.:8 :!:!:::: ~J:: :i: :~:~.~: :i: ::: :h~::~i~:: :: :::: :;1~ ~:::: :5:: :i: :i:i:i:i i:i: :~?2i~i:i:i:i i:i:i:i:i:;:i:i:i:;ii:i:i:i:i:i:~:~i:i:i:i:i:i 33.0000 1171.0 90.8 54.4 381.0 3800 90.5 Page 12 RTON ousTo ER TEST.O. JFLowP o ousToMER Phillips PetroleumOne I FIowTest One ,,Shonna Bo~er 5.761 2" Tu~ine NCtU BI-ST Cook Inlet . Forelands Unocal 428 TIME ~PRESSURES ~MPS CHOKE FLOW RATE~ ~TIOS BS&W CUMVOLS CO~H2~ G~VI~S SEPA~TOR COMMENT~ DAY:MO:YR DSP (~) OS~ GAS(mmV/d) GOR (~bl) M~S~i~ GAS (mm~ CO2 GAS (Ai~l.0) PRESS (~ig) * Gas ~a~re~ are of ~r~r gas only. DTIME CSG (~) ~ M~ids WOR (bb~l) W~r Mu~S~Ms H2S SALINI~ (p~) TEMP. ('~ ~ Gas ~om s~ge ~k ~emen~ are ~om tu~i~ me~r (°0 (~s) (bbls) (%) (bbls) (ppm) , i ~/11~8 ~.7 1.~ 11~.3 3% 1.~7 o.25% 0.7~ 74.8 Flow well as directed :::: ~ ::: ::: :~2:1~: ::~: : :~4:: :: ~ ~1::::: :~:~:~;~:~:~: :~ :~:~:~:?~b~:~:~:~: ~:~:~:~:~:~:~:~:?~: :~:~:~;~:~:~:~ :~:~:~:~:~:~:~:?~ :?~:~:~:~:~42:i4:~:~:~:~:~:~:~:?~:~:~:~;~:~:~:~:~: Gas tu~ine rate 938.0 scl/d, cumm 761.2 scf 33.2~ 11~.0 ~.1 53.5 ~1.5 ~ ~.4 Pumping out tank 3 ~/11~ ~.5 1.879 1~.2 3% 1 .~7 0.~% 0.~2 78.2 Flow well as direct~ ::: :y~:~: :~:: :~::: ~.~: :!:::: ~.~:: :~: :~:~:~:5:~:~:5:~:5:5: 5:~:~:~:~;~:~:~:~:~ :5:5:5:~:~:~:i :5:~:5:~ ~:~:~:~:E:5:? ~:;:~:~:~:~:~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~; ,, ~.~ 1~5.0 9~ .6 ~.4 ~2.1 ~ ~.3 ~/11198 ~.4 1.~2 ~.4 3% 1.~6 0.25% 0.~2 79.7 Flow well as dire~ :::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::~:~:::~:::~]~:::~;~:::~:::~:~ :::::::::::::::::::::::::::: ?::5:::: :::?::::::? ::: (?~;~ ~ ~ ~ :: ::~::~ ~ ~ ~ :: :: ~ :: :: ~ :: :?: :: ~ ~:: ::~:~?~ ~::~ Gas Tu*ine rate 1142.0 scf/d, cumin.- 783.2 sof ~.7~ 12~.0 93.3 61.0 ~2.7 ~ 87.1 Pumping out tank 3 ~11/~ ~.6 1 .~ 931.4 3% 1.5~ 0.~% 0.~ ~.7 Flow well ~ dir~ted ~'.~' J' ~fO;o .... ~;S .................... ~.'~ .... ~,~ ~ 87.8 ~t11~ ~.9 1.873 879.0 3% 1.616 0.25% 0.~2 79.2 Flow well as directed ............................................................................................. I ..... .-.-...- .-.-.,.-.-...-.-.--...-.-.-. ..... , ~.25~ 12~.0 92.1 ~.7 ~.1 ~ ~.3 Tank 3 ~is 20" = 33.3 bbls ~/11/98 , ~.3 1.978 ~.4 3% 1 .~ 0.~% 0.~2 82.3 Flow well as directed .............. : ............................................................. :, ................................... ~.~ 1~7.0 ~.0 64.0 ~.8 ~ 87.6 ~/11/98 ~.5 2.~ 974.6 3% 1.6~ 0.25% 0.~2 ~.1 Flow well as dire~ed ~.7~ 1~7.0 91.9 ~.5 ~.4 ~ 87.2 Tank 3 equals 48": 80 bbls ~/11~8 ~.0 2.~ 876.1 3% 1.678 0.~% 0.~ 82.8 Flow well ~ dire~ed ~.~ 1317.0 ~.6 71.6 ~.2 ~ ~.8 ~1111~ 67.3 1.~7 ~.5 3% 1.~ 0.25% 0.~ ~.2 Flow well as dJre~ed 35.2~ 1~8.0 ~.7 ~.5 3~.9 ~ 87.8 Tank 3 equals 75": 125 bbls ~/11/98 67.2 1.973 ~.2 3% t .719 0.~% 0.~2 81.4 Flow well as dire~ - .......... ' .... h*- - -' ...... ' .................... '-'-..'-,'-'"-'.'"-'-'-'-'-'-'-'-'-'-'-'-'-'-'"- -' ........ ' .............................................. ; ............. ~.~ 1~2.0 . 92.2 65.9 ~7.6 ~0 ~.6 ~tl 1t~ 87.0 1.9~ g~.o 3% 1.7~ 0.~% 0.~2 79.7 Flow well ~ dire~ed "'""~'~"""'"'"'"~'~.'~'"'"' ""'~'~"'" '"'""'"'"" '"'"'"'"'"'"'~'.'~'""'"'" '"""'"'""'"'"'""'"" '""'"'"'"'"'"~'"'""~]~ "'"" .............. ~ ..... J ..... 8~2 ..... Tank 3 ~ua~ 78"= 130 bbls ~/11/98 ~.8 1 .g~ 9~.8 3% 1.7~ 0.25% 0.~ ~.1 Flow well as dire~ed ~.~ 1~7.0 91.5 ~.4 ~.9 ~ ~.5 ~1t1/98 ~.3 1 .~ ~4.5 3% 1.7~ 0.~% 0.~2 81.2 Flow well as dire~ed """"~'""""'"'"~'~':~"'"" ""'~'~"" '""'"'""'" '"'"'"'""'""~'.'~"'"'""' "'"'"'""'"'""" ""-"" .... "'"" .... ~.~ .................. ~ .......... 8~[2 ..... Tank 3 equals 130": 216.71 bbls Page 13 TON CUSTOMER TEST NO. IFLOW PERIOD CUSTOM ER REPRESENTATIVE i Phillips Petroleum One I Flow Test One Shonna Boyer ... 5.761 2" Turbine NCIU BI-ST Cook Inlet . Forelands Unocal 428 , TIME [PRESSURES TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H28 GRAV1TYS SEPARATOR cOMMENTS , , DAY:MO:YR DSP (psia) USh'-T~ GAS(mrnscf/d) GOR (scf/bbl) Mud/Solid.~GAS (mmscf~, CO2 GAS (Air=l,0) PRESS (psig) * Gas measurements are of separator gas only. DTIME CSG (psia) DSHTP~ Mud/Solids WOR (bbl/bbl) Water Mud/Solids H2S SALINITY (ppm) TEMP. (°f) *** Gas from surge tank measurements are from turbine meter (°f) (64ths) (bbls) (%) (bbls) (ppm) ,. 30/11/98 66.8 1.958 939.3 3% 1.8OO O.25% O.892 8O.7 Flow well as directed 36.5000 1384.0 91,5 65.3 390.2 3800 85.1 30/11/98 67.1 1.986 940.7 3% 1.821 0.25% 0.892 81.1 New meter factor .978 ::: ~:~:i00 00 ::: :i: :: 68.;lis :i:i:: :i:i~i:~i:!: :i:i:.~:~ii:i:i i:i:i:i:~i~:i:i:i:i:: i:i:i:i:i:.~-~i-~:i:i:i:!:i :i:i:i:!:!:i:!:i:!:i :i:i:~329i8i:i:i:t i:!:i:i:i:i:i:i:i: i:!:i:i:i:i~i:i:i:! i !: ! i i:i i~i.3.'i iii ii Gas Turbine rate 1972.0 scf/d, cumin.- 949.2 scl 36.7500 1392.0 88.3 65.5 39O.9 38OO 86.9 Start pumping tank 3 30/11/98 67.2 1,948 951.8 3% 1.841 0.25% 0.892 79.9 Flow well as directed ::: :.~.~ ~.~b~:i:i:i !:i:i:i:~.~j0:i:i:i:i i:i:iT.'~:.~2:!:i i:i:i~i:~i:i:!:i:i:i:!:i~;~:!:i:i:i: :i:i:i:i:!:~2~;~:i:i:i:i: i:i:!:i:i:i:i:i:!:i: :i:i:i:~{3i:i:i:! :i:i:i:i:i:i:i:i:i ii !:! i!iii.4~iJ~ i i i i i i :i } i i i 9.'.4i~.i i ! iii 37.0000 1400.0 91.2 64.1 391.6 3800 86.4 30111198 67.6 1.945 935.1 3% 1.861 0.25% 0.8,92 79.7 Flow well as directed :::::::::::::::::::::::::::::::::::::::::::::::: :i:!?!i:.~!:i: ::::i:~i~.i::i::i::i?i:~iii::i!i::ii! i :: !i::!:: ~i~i:: :: :: :: :: i :: i :: i :::i ii:: i: :: i ~i~i :: i i i :: i ::! :: i! :: :: :: i!::i::~i~.! iiii::ii!::! i::iiii:ii::~i~i::iii::iiii Gas Turbine rate 1398.0 scf/d, cumin.- 971.2 scf 37.2500 1406.0 87.2 65.2 392.3 ,,-3800 86.6 Pumping out tank 3 30/11/98 67.4 1.914 947.7 3% 1.881 0.25% 0.892 78.5 Flow well as directed 37.5000 1411.0 91.0 63.3 392.9 3800 88.1 30/11198 67.5 1.967 992.4 4% 1.9O2 0.25% 0.892 77.1 Flow well as directed 37.7500 1419.0 91.3 62.8 393.6 3800 86.4 Pumping out tank 3 30/11/98 67.6 1.956 982.1 4% 1.922 0.25% 0.892 76.1 Flow well as directed 38.0000 1430.0 90.8 63.1 394.2 3800 87.6 30111/98 67.7 1.988 986.4 4% 1.943 0.25% O.892 77.3 Flow well as directed iii! i~".2!~!~i ! i iiiii i'-_~.'3.;.5i ! ii! i !!.¢.~;.'6i ii iiiii.~.i~i:i:i:!:iii:!:i_'~.~;~.:i:!:i:!: :i:ii!:i:i~;.~i:i:i:iii: !:i:;:i:i:ii!iii}iii iiiii:2.~i'.2!i!iii !iiiii!ii!:iiiiiii :;:!iii! !i!42.i4:i:i:i:i i i i !; ! i:~.0.~.i~i i i i Gas Turbine rate 1141.0 scf/d, cumm.- 1025.2 scf 38.2500 1440.0 92.7 63.8 394.9 38OO 85.4 Pumping out tank 3 30/11198 67.9 1.931 934.6 4% 1.963 0.25% 0.892 74.8 Flow well as directed i ii¢~ ~i~!i;; i i i ~-.'.4. ! i i i i ii~;..¢:i;!; iii;i~i:.~!iii;i;iiii !;i~i~i;i:i:!!i i:i:i:i:i::<~:9.'i:i:i:i:i :i:i:i:!:;:i:i:?i:i :i:i:~i¢i:i:!: i:i:i:i:;:i:i:i:i: i:!:i:!:i:;~'.4i:;:?i:i i :iii 38.5000 I449.0 89.3 65.4 395.6 3800 86.9 30/11/98 68.1 1.893 955.6 4% 1.983 0.25% 0.892 73.0 Flow well as directed 38.750o 1436.0 91.8 62.7 396.2 38OO 85.9 At 13:25 start sampling, as per Phillips procedure 30111198 67.8 1.932 1033.3 3% 2.003 0.25% 0.892 74.9 Flow well as directed 39.0000 1447.0 89.3 58.6 396.8 3800 87.6 30/11/98 68.0 2.003 1011.1 4% 2.024 0.25% 0.892 77.6 Flow well as directed :i:i:!3~i~ib~:i:!:i i:i:i:i:~7.'~i~:i:i:i:i ;:i:i¢.5;i~.:i:i !:!:i~;:~.;:!:i:!:!:!:i:!:~:~;~:i:!:i:i: :i:;:!:i:i:{)~8;~:i:!:!:!: !:i:i:i:! !:i:i !:{ i! !i~;~:; !ii !! !;! !i!i! ! i ! i ! ! i!~i~ii¢!! ! ! iii ii!{ !¢~;~! ! !i!i Gas Turbine rate 1242.0 scf/d, cumin.- 1076.2 scf ,.,..-.,..., ................................... '..-.- ...... ...,....,..'.,.,.-,-.-.,...,. -,',-,-,'.',',-.'.'.".",-.',-.- ,-.-.-.-, .-.-. ,- .................................................... 39.2500 1464.0 92.5 83.6 397.7 38OO 86.O Pumping out tank 3 30/11198 68.3 2.027 96I .7 4% 2.045 0.25% 0.892 i 78.4 Flow well as directed ............... ' .............................................................................. ~4~.e' .................. ~ ........... 8e;e 39.5000 1478.0 88.6 89.0 P~¢ 14 ~~~J'~~'"~-RTO N ou~ToM~ TEST~O. I~_OWPER,OD OUSTOMER,~.*^T~ Phillips Petroleum One J Flow Test One Shonna 8oyer 5.761 2" Turbine NCIU B1-ST Cook Inlet N. Forelands Unocal 4,,28 .... TIME PRESSURES TEMPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H2S GRAVITY'S SEPARATOR COMMEI~TS DAY:MO:YR DSP (psia) USHTR GAS(mmscf/d) GOR (scf/bbl) Mud/Sotid~ GAS (mmscf;, CO2 GAS (AJr=l.0) PRESS (psig) * Gas measurements are of separator gas only. ii~i~i~i~¢~ii ::!~¢.:ii~ii:: ::!i~::ii ::i!!::!~::!::ii!i!~j~ii!::!::!iiiiiii~ i~.~!::i::i.~ iiii::!::~i::i::iii ~i~i::!::iiiii~ i::!!i::i~f:i::i:: i::~::!::iii!iiii~0.'~.i:: ii~i~i!iii~ii -- ~OR = so~r~ c~ Co~ O, ~ts. DTIME CSG (psia) DSHTR Mud/8olids WOR (bbt/bbl) Water Mud/8olids H28 SALINITY (ppm) TEMP. (°f) '~' Gas from surge tank measurements are from turbine meter (of) (64th$) (bbls) (%) (bbls) (ppm) , , 30111198 69.0 1.973 922.5 4% 2,065 0.25% 0.892 76.1 Flow well as directed 39.7500 1486.0 91.3 90.3 399.6 3800 87.6 Pumping out tank 3 30111/98 68.8 1.918 943.0 4% 2.085 0.25% 0.892 73.3 Flow well as directed 40.0000 1487.0 90.3 85.8 400.5 3800 86.4 30/11/98 68.4 1.940 983.2 1% 2.106 0.25% O.892 74.4 Flow well as directed 40.2500 1494.0 91.4 20.2 4OO.7 38OO 88.6 Pumping out tank 3 30111/98 68.6 1.901 935.3 1% 2.125 0.25% 0.892 72.9 Flow well as directed ~::~i~::i~i~::~i~i~i~ ~i~::~::~i~,'~.i~i~::~i~ ~?.~:;i~ ~::~i~i~::~:::.i~::i?::~ii~::~::~::~i~::i i~ii::~i~i~i~i~?i ::::::::::::::::::::::::::: i~:?:i~i:.0:i~::~::~:: i~?i~i~i~::~i~i~:; i!::~i~::~i~::~iii~!~?::~i~ ~i~::~i~::~::~ii!ii::~ii:?:! 40.5000 1499.0 93.5 20.8 400.9 3800 90.1 30/1t/98 68.6 1.943 986.6 I% 2.146 0.25% O.892 74.6 Flow well as directed 40,7500 1499.0 95.0 2o.2 401.1 380o 87.3 Pumping out tank 3. At 15:02 pumping complete 30/11/98 68.6 1.984 1004.8 2% 2.166 0,25% 0.892 76.3 Flow well as directed ...................................... -- ' ' .'.-,-.'. l'.'.'-'--.'----.'-'----.----'-' '.-. ....... · .... - ...... -' --'.'--.' .'-'.'-'-'-'-'-'.-.','---- '-'.'-'-'- -'.--'-~ '-'--.'-'.'.'.'-'-'--.'-'. "--' -'-'-'-'"'"'"';'";'Z'Z': !~i'-'l.;5.'!~iii!i! !!iii!ii~..'.6ii!ii!iii!i!i:..7.:.2:..'.6i!!i !iiii.".¢.!~d..f:.:!:i: i:i:!:i:il.:8.:'(:.3.i~i:!:i:!:i i:i:i:!:i:~{.4.:i:i:!:!:! :!:i:!:i:i:i:i:i:i:! i:i:}:~-.6~.-i:.7-!:!:i:i i:i:!:!:!:i:i:i:i:! {:!:i:i:i:i:.4.2.'-:.q'i:!:!:i:i:i::::::::::::l::::::::::::: 41.00(30 1501.0 9t .4 40.9 401.5 3800 88.5 30111/98 68,9 1.987 992.7 3% 2. t87 0.25% 0.892 76.6 Flow well as directed 41.2500 t510.0 93.7 62.8 402.2 38O0 89.2 At 15:02 sampling complete 30/11/98 69.2 2,020 1000.1 3% 2.208 0.25% 0.892 77.8 Flow well as directed 30111/98 69.4 2,034 979,5 3% 2.229 0.25% 0.892 78.3 Flow well as directed 41.75OO t532.0 90.5 65.1 4O3,5 3800 87.2 At 16:06 APl Oil gravity corrected 42,4 30111/98 69.7 2.032 966.9 2% 2.250 0.25% 0.892 78.3 Flow well as directed 42.0000 1541.0 92.4 43.5 404.0 3800 87.3 30111/98 69.7 2.087 992.6 2% 2.272 0.25% 0.892 80.4 Flow welt as directed i!i!::!ii~i~i~::i::!i i::ii!ii::~i'.3.::i::iiiii i::i::~::iii i::}ii~.'8.'i~d)}i::ii} ::ili::i?~O.'.'.2.'i~::iiiiiii:: ::i::iii::iii~i~ii}i::iiiil i!iiiii::ii!iiiiii::i::'.::i}ili.'.2.'.7.'-.~}-O.-'::i::!::!:: !::i?::i::iiiiiiiii::i:: i::!ii::i::i::i::~::iliiiii::i::iii::i::!ii::!i~i~iiiiiii::: Gas Turbine rate 1407.0 scFd, camm.- 124'7.2 scl 42.2500 1557.0 90.3 43,5 404,4 3800 85.4 At 16:33 start pumping tank 3, at 134 bbls 30/11/98 69.9 1.522 684.2 2% 2.268 0.25% 0.8,92 57.0 Flow well as directed i::ii!::~!~i~i~!::ii!.. ::!::!::!ii~!i!::!::! ::ii!~.~!i!! i!i!i~::~i!::i:: ::::::::::::::::::::::::::: i!!i!!!ii:::,.'?~i?:!!~?:!::~!!::iii::i::!::!ii::i::!::i:i::i::iii~¢~i!!:?:i :::::::::::::::::::::::::::ii::~::~i!::~?::~i~i::i!~::~i~i! !!~::i::i::!!!~i~!i!i!:?:! ,',t 16:56 stop ~ogger on ,eparator. 42.5000 1575.0 90.3 46.0 404.9 38OO 86.6 Switch to fast rate for buildup 30111198 70,1 1.993 880.0 2% 2.309 0.25% 0.892 61.9 Shut in well at choke manifold iiiiii::~i~i~i~iiiiii i!!!i!!!~ii~.!!::!i!! i::iii~:,.'::i!i i::iii~!~iii::~ ::!!i::!!i'..2.'f.~i.o;'ii!i::~ii:: ::i!i::i::~ii~i~::i::i!i::!::!::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: Record ,hut ~n pre~ure 42.7500 1581.0 92.1 45.3 405.4 3800 86.4 Page 15 RTON Phillips Petroleum One ,Flow Test One Shonna Boy. er, 5.76t J 2" Turbine NCIU B1-ST Cook Inlet . Forelands Uno,cai 428 ., TIME PRESSURES: TEMPS cHOKE FLOW RATES RATIOS BS&W CUM VOLS cO2/H2S GRAVITYS SEPARATOR COMMENTS DAY:MO:YR DSP (psia) USHTR GAS(mrnscf/d) GOR (scf/bbl) Mud/Solids GAS (mmscf) CO2 GAS (Air=l.0) PRESS (psig) * Gas measurements are of separator gas only. .... ~-i:iM~ ..... ~$'G' (~i ':' ~SH~R' Mud/Solids 'WOR (bbl/bbl) Water Mud/Solids H2S SALINITY (ppm TEMP. (of) *** Gas from surge tank measurements are from turbine meter (°0 (64th$) (bbls) (%) (bbls) (ppm) 30111198 Total gas prodUced from gas tu'rbine = 1369.2 scf :::: .1:7.i.'1~1[0~: ::: ::::: 90~ .0::: :~:: :7.~2: ::::::::: :::::: ~::: :::: :::::::::::::::: ::::: :::::: :-:-:: :.:.:-:-:-:. -:-:.:-:.:-:: :.:.:.:-:-:- -:-:.:-:-:-:-:-:-:..:.:-:.:-:- .:-:-:, .:-:.:- · -: .............. Total gas produced from test = 3.6782 mmscf 42.9200 1607.0 Record shut in pressure _ 30/11/98 Record shut in pressure ::: -~i~ O0::: :i:i:i:~iO:i:i:i: :i:iSSi:~.i:i: ::::::::::::::::::::::: i:i:i:i:i:i:i:i:!:i:i:i:!:i:i:! i:i:i:i:i:i:i:i:i:i:i:i:i:i:i:il :i:i:i:i i:i:i:i:i:i i:!:!:} iii:i !:i:i i i i i i ii i 43.080O 1699.0 30/11/98 Record shut in pressure ,'.'..' ' '.' · ',* · '*','.' '.'.'.'.'-' ' ' -' ;. - -' - ,' ' '- '.'- ......... ' ................................ .'. - ~ .......... ' .... ;. ,Z.:- .Z'Z.Z.:,Z' -:-:-;-Z' -:-;-:-;~ · :':-:'.t:'~:'3~ioo':';'; :-:*:':;4~2~:0,'.'.': H.' .~. ~.7.;:'..'.'.'.',',:.:.'-:;'.'. '-'.:-:.:.:,:-:.:.:.:.:.:.:.:-: :.:.:-:.:.:.:.:.:-:-:-:-:-:.:.:~ ;,;.:.:-:.:.:-:.:.:.:! :-:-:.:-;-:-:-:-:-:-:-:-:-: :.:-:.:.:.:-:-:-:-: :.:.;-;-:.:.:.:.:-:-:.:-:-:-:-: 43. 2500 1768.0 30/11/98 Record shut in pressure :-:-:-:-1"~';40 00:':-:' ':':-;-~6~;O:-:-:' -:-::~6,~;-:- ':':':-:-:-:-:-;':':-;- :-;';-:':-;':';':-:-;':-:':':-~:: :':':;:: :::: :;:::: ::::::: :::::::::::;;:::::: ;:;::::;:: ::: ::::: :::::::::::::::::::::::::::::::::::::::::::::::: 43.42OO 1733.O 30111/98 Record shut in pressure :!:i:i:.~i~ ~:i:!:i i:i:!:i~;b!:!:i:i !:!:~.~:i:i i:i:i:i:!:!:i ! i:i:i ! :i:i i i i i i:i: '-'---'-':'-'-'-'.'.~-'" '. ......... --' ...... -'.'~-'-'.'.'-'-'-'.'.'.'.'.'.'.'-'.'.'-'-'-'.'-'.'.'.'-'-'-'-'.'.' ,. ......... ....,-.-......-.-.....-.-.-.,...-,.. ~...-.-......,..-..-...,.-..........,. ...... -.- ...... -.-. ~ ............... ,:-;.:-:.:.Z-:-:-:-:..;-:-:-:-:-:.:-:.:-:-:-:-:~ -:-:-;-:-:.:.:-:-:i .:-:.:-:.;-:.;.:-:-:-:-:-Z-;-:-~ :-:.:-:.:-;-:-:-:.:-:-:-:.:-; 43.5800 1686.0 30/11/98 Record shut in pressure -,....-.-.-.,.-.-.-. :-.'.;.;-;.;.;-;-:-:.:,;.:. ;,:-;.:-:-;.;-:-;. 43.75OO 1641.0 30/11/98 , Record shut in pressure ii i:..1~ :1.0..~..:i:! i i:i:i:i~:Y3;Oi:i:i:i!i:i: .~.,.3.:!:: ::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: 43.92o0 1599.0 30/11/98 Record shut in pressure ::Z~1~-~{~:.::::.:*:-:-51:5~.:0:.:-:.':.:.~..,~;': ::::--'::-h::-: :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::: 44.0800 1561.0 30111198 Record shut in pressure 44.2500 1526.0 30111198 Record shut in pressure ;:: :.1~ ~ o0:Z:: :::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::: :;:.:::,:.:-:-:-:-:: .;-;-:-:-:-:-:.:-:d-:-:-:~-:.:-:-:-:-:.:-:-; -: ;-;: :-:-:::: '.; ::::; :: ::: :::; ::::: 44.4200 1493.0 30/11/98 Record shut in pressure 44.5800 1461.0 30/11/98 Disconnect wellhead sensor, so rig can move 44.75o0 1431.0 30111198 Record shut in pressure ............................ ,'-','-'.-.','.'.'.'.'. '.'.'-'.'-'-'-'.'.'.'.'.'.'-','~'.'.'-'-'.'.'.'.'.'-'.'-'-'.'-' .'-'-'-;-;-:-'-:-'-: ,: .... : ........ ~ ........................ ?-Z. -:-:-:-:-:-Z-:-:.:-;.:.: i~!iii!~.'.o.'!~:0.'!~!~ii!~ iii!~iiii!i!i!ii;i!ii!iii!i i?!.~!ii~::::::::::::::::::::::: ~:i:!:i:!:!:i:i:!:!: :!:!:i:!:~ i::: :~:: :!::::: ::: ::: ::::::: ::: :: ::::::::::::::::::::::::::: ::::::::~::::::::: :::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::: 44.9200 1404.0 Pago 16 ~iii~ALLI BU RTON ou~o~ ~sT.o_ i~ow~.,o~ ou~o~.~.~**~ Phillips Petroleum One I Flow Test One , Shonna Boyer 5.761 I 2" Turbine NCIU B1-ST Cook Inlet . Forelands, Unocal 428 .... TIME PRESSURE8 TEMPS CHOKE FLOw RATES RATIOS BS&W CUM VOLS CO2/H2S GRAVITYS S'EPARATOR COMMENTS DAY:MO:YR DSP (psia) USHT~ GAS(mmscf/d) GOR (scf/bbt) Mud/Solid., GAS (mmsct~ CO2 GAS iAir=l.0) PRESS (psig) * Gas measur~Cm are of separator gas only. DTIME CSG (psia) DSHTR Mud/Solids WOR (bbl/bbl) Water Mud/Solids H2S SALINITY (ppm] TEMP. (of) *** Gas from surge tank measurements are from turbine meter (of) (64tbs) (bb]s) (%) (bbls) (ppm) ,,, 30111/98 Record shut in pressure :.:.:.:$9. ~ .2o..: .~. .... : .............. ..~. i-,e ...... :' ': ......... : ............... : ................ :' ':': ...................... :'" r-' '-'.'.'-'-'-'.'.'.' '-'.'.'. '.'.'-'.'-'-'-'.--'-'-'-'-'- 45.0800 1376.0 30/11/98 Record shut in pressure !:!:i:i2:~:i02i00i:i:!: :i:i:i:i:i:i:i:!:i:i:!:i:! :i:i:!:i:i:i:i:i: ::::::::::::::::::::::: i:!:i:i:i:!:i:!:i:i:i:i:i:i:i:iji:i:i:i:i:i:!:!:i:i:i:i:i:i:i:i:i:i:i:i:!:i:i:i:i:i:i i:i:i:i:i:i:i:i:i:i:i:i:!:i i:i:i:i i iii ii:i i i iS?iii:iii i:i !i:i !i iii ii!i iii}ii 46.7800 1152.0 3O/11198 'Record shut in pressure .... ;~:~'~ ....... ~-~'i~ ................................................... ' ........................... ~ ...................................... 30111198 Record shut in pressure :->.':~ :-~;b~::: ::: ~'~-:~:: :: :::::: ::: :: ::: ::: ::: ::::::: :: ::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::: Reconnect whp sensor, in well bay room :-:-:.:-.-.-'- -.-:-.-..:-:-: -:.:-:-.-...-.-.-:-.-:-:.: .:-:.:.:-:-:-:.:..:-:-:-:-:-:-:-:-:-:-:- :-:.:-:-:-:-:-:-:. - -:. -:-:- :- · .: ........ :-- .: ........... :-: :- ':-:-:':':':-:-:-:':-:':i:-:-:-:-:':-:':-:':':-:-:':':':':':-:-:-:-:':-:-:-: f-:-:.:.:-:.:-:.:-:-:-:->x 47.0800 1120.0 30/11/98 Record shut in pressure ::::::::::::::::::::: ::::::}::~iiii!i ::iiii~}!i::i:?:ii !i!i??!~!~!iii::?:f: ~?ii!i::~:/:ii~ii!iii:: ii!ii !i i:: ii::i?:: :::::::::::::::::::::::::::::::::::::::::::::::::::::: !~i i i i :: i :: :: :: i i :: i i ! ! }:: :: :: i i ?i i ,i i :: :: :: i :: :: :: ii:: i ! i 47.2500 1105.0 30111/98 Record shut in pressure i~? !~!-°9-. i::::: :::i:::5¢2.;0.:::::: :i:::::i::::::::: ::::::::::::::::::::::: i:!:i:iSi:!:i:i:!:i:i:!:!:!:i !:!:i:!:i:i:i:i:i:i:!:i:i:i:i:i:i:i:i:i:i:i:i:i:!:!:i~!:!:i:!:!:!:i:}:i:i:i:!:i:i:i:::!:i:i:::!:i:!::::::::::::::::::::::: :::::::::! ::::::::::::::::::::::::::::: 47.4200 1087.0 30/11/98 Record shut in pressure 47.5800 1070. o 30/t1/98 Record shut in pressure i:i:i:!'22. ! .~. i .~. i:i:i: :!:i:!:~{O.-i:i:i: Fi:i:i:!:i:!:i:i: ::::::::::::::::::::::: ::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::: ::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: 47.7500 1053.0 30/1 t/98 Record shut in pressure 47.9200 1039.0 30/tl/98 Record shut in pressure 48.0800 1023.0 30/11198 Record shut in pressure :::::::~:~:~:::::: :::::::~:~::::::!:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::: :::::::::::::::::::: ::::::::::::::::::::::::::: ::::::::::::::::::; ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: 48.2500 1009.0 ~ -- 30/11/98 Record shut in pressure ::::::12~j~4~i(~ :1: '.::: :~2.:0::::;:;::::;::: ::: :::: :;::: :::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::: :::::::::;:::::::::: ::::::::::::::::::::::::::: :;:::::::::::::;::t :::::::::::::::::::::::::::: ::: ::::::: :::::: :::::;::::: 48.5000 987.7 30/11198 Record shut in pressure i:i:i:i-~i~ii~i:i:i:[:i:i:i:~fi~iO:i:i:i. :i:i:i:i:i:i:i:i: ::::::::::::::::::::::: '.i:i:i:i:i:i:i:i:i:i:i:i:i:i:i: :.:-:-:-:-:..:-:.:.:.:.:.:.:-: .:-:-:,:.:-:-:-:-:-: -:-:-:-:-:.:.:-:-:.:.:-:-~ :.:.:-:.:.:-:-:.:- :-:-:-:-:-:-:-:-:-:-:.:-:.:.:-:,-:.:.:-:.:-:-:.:.:.:+x< ...-...-.-.-,.,-.-.-.-.-.-.-.- ..-.-,,.-..,.,-.-...-.-.-.--.-....,....-.-.- -.-.-...-.....-...-.... :.-.......-...-.....-.-.-....,- ::::::::::::::::::::::::::::::: ZZ;:ZZyZZ:;:;:;Z:: :;¥:::'-:¥:Z::Z'-:::¥i ZyZ:::Z::Z:::ZZ; :::::::::::::::::::::::::::::::: ¥;¥~:~:::¥; ::~¥~:; 46.7500 967.9 Page 17 RTON 2.50 2.00 ' 1,50 1,00 0.50 Gas Rate vs Oil Rate Phillips Petroleum Well NClU B1 - ST T¥onek Platform 0.00 10000,00 19:12 00:00 04:48 09:36 28-Nov 22:15 [ , , , ~ , , 0.00 14:24 19:12 00:00 04:48 09:36 14:24 19:12 9000.00 8O00.00 7OOO.OO 6000.00~ 5000.08, 4000.00 3000,00 2000.00 1000.00 Gas , ,.Oil{ [3(~'Nov '~7:oo] Page 1 Well Pressure vs Casing Pressure Phillips Petroleum Well NClU B1 - ST Tyonek Platform 6000 5O0O 4000 '" 3000 2000 1000 12:00 00:00 12:00 00:00 12:00 00:00 12:00 128-Nov 22:15 ! I -WHP ' CSG i [ 02-Dec 01:26 ! 2OOO 1800 1600 1400 1200 60O 400 200 0 12:00 Page 1 "ALL!B U RTO N ou~-~o,~ TEsT.o. IF.~.~,oD OU*~'O,,E. k'~E.~^.~ ........ Phillips Petroleum One I Flow Test One Shonna Boyer WELL NAME & No. FIELD INTERVAL TESTED RIG NAME 5.761 i. 2" Turbine NCIU Bt-ST Cook Inlet N. Forelands Unocal 428 ,,. ,, TIME PRESSURE8 T'~MPS CHOKE FLOW RATES RATIOS BS&W CUM VOLS CO2/H28 GRAVlTYS SEPARATOR COMMENTS , DAY:MO:YR DSP (psia) USHTR GAS(mmscf/d) GOR (scf/bbl) Mud/Solids GAS (mmscfJ CO2 GAS (Air=l.0) PRESS (psig) * Gas measurements are of separator gas only. DTIME CSG (psia) DSH'TR Mud/Solids WOR (bbl/bbl) Water Mud/Solids H2S SALINITY (ppm', TEMP. (°f) *** Gas from surge tank measurements are from turbine meter (°f) (64~hs) (bbb) (%) (bbb) (ppm) 30/11/98 Record shUt in pressure ~:: :g~1'.5 i~:i:: :i: :,¢~:0~::: ::::::i::' :: ::::::::::::::::::::::: :i:i: :i: :!:i: ::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::: :i:i:i:i:i:i:i:i:i ::i:i:i:i:i:i:i:i:i:i:i:i:i:i:i: ................................................................................................ 49.0000 947.7 30/11/98 Record shut in pressure ;.i.i.~i~i~_i.i.~ ~.i.~.~i~.i.i. ~.!.i.~;; ~.~; ~.~.~.~.i.~.i.~.~.:.i.~l ======================================================================!i?~:~?;i~ii~i~:~!i~: ii::ii~:;!~!~:?~ii::::;i ::::::::::::::::::::::::::::::::::::::::::::::::::::::::: :::::::::::::::::::::::::::::::: 49.2500 928.9 30/11/98 Record shut in pressure '"'~':~ ........ ~i'~','~ ....................... ~ .... '"'" ..... ""' "'"'"'"'"'"'""'""'""'- ...... ' ...................................................... 01/12J98 Record shut in pressure i:: :i3 ::~::~::::::: :~if :: ::: :i: :: :: 3:: :!:i::: :i:: :: :i: :i:i:i: :i:i:i: :i:i: :::: : :::::::::::::::::::::::::!:i:i:i:E:i:i:i:!:i !:!:i:i:i:!:i:!:i:!:!:!:i:i i:i:!:i:i:i:i:i:!:i;i:i:!:!:i:!:i:i:!:i:i:!:i:i:i:! ..,,...-.....-,...,-.-.......~ ......-.- ........ · ...... ....- .... ...., ...,...,..,...-.......-.,.....,...-......-.....,.-...,...-...,.,... ,-.-.-.-.-.-.-.-.-.., ...............-.....-.,.-......-...-.-.-...-,.,,........_ ...- ..... -... ............... 50.7500 828.1 01/12/98 Record shut in pressure 51.0000 812.9 02/12/98 Stop logging, flow test complete 51.1900 800.0 .................. J .... :- -5-:.:.; - -:.:-:-:-:.:-: .:-:-:-:,:.;-?;-:-:-;- ;-:,;':-:':-:':-:-:-Z-:-Z-:-:': :.Z.:-?Z.:.:-Z'i.:.Z'Z':':':-:':':-:'Z':'Z':':':';-: :-Z.:.Z-:-:':-;-:':':-:-:-~[:':-;-;';':-:';':';':':':';':';':':':':';':':'::: :; :'::: :;: :; : : -;,;.:-:-;-:.:-:-:.:-:-:-:-:. :,Z-:-:-;-;-:.;-;-;-; ...... ; ...... : ...... :--:-.: .Z-Z.i.Z.Z.:.:-;.:..:-:-:.;.Z- -:- -:-:-:':-:-;,:-:':-:-:-:':':':':':':-:-;':':':':' ':';':-:':':';':':':':':';'[':';';':':';';';';';';':':':':':':':':';':':':'-'.' Page 18 Date: Nov. 30,1998 Phillips Petroleum Tyonek Platform Well: NClU BI-ST Halliburton Samplers: S. Tyburski. D. Bray Sample Report Date/Time Sa, mple No. Type Container Number '~1/3b/9813:2~ .... :1 ............. o'iJ" ' DENO04 "' I Gas K18228 [ .. . [ Ill I .I ! I Ill I I Il I I I I I HALLIBURTON Sepa,,r, ator Separator Pressure Temperature (psi.q) f de~. F ) II I I I Iii IIII 75 88 75 88 II II I I I I 11/30/98 13:49 2 Oil CAL31 2 Gas K335303 II II . IIIII I I . II I I II IIIII IIII II I I I 78 87 78 87 I II I I I I fll . I I 11/30/98 14:10 3 Oil CL4529 3 Gas K335302 III III I II I iiiiii IIII!1 I IIIll IIIIII I IIIll IIIJll I I IIII I IIII 76 86 76 86 II II I I /30/98 14:32 4 Oil 2040 75 89 4 Gas K335308 75 89 r - .. . ' ' II I I I I II III u _ IIIII I I I IIIIIIIII IJ I I I IIII I I [I II I 11/30/98 14:59 5 Oil 2014 71 89 5 Gas K335297 71 89 I I I III1[ I I III II II I[. II II II ,11 II I I I I I I I III I I II I I II IIIII I I I I I PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 NORTH AMERICA EXPLORATION AND PRODUCTION COMPANY February 3, 1999 BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Attn: Mr. Robert Crandall Re: Well Information Tyonek Deep Project Cook Inlet, Alaska Gentlemen: Phillips Petroleum hereby delivers two boxes containing the well information as described on the attached schedule. This information covers the four wells (North Cook Inlet Unit wells B-1, B-2, B-1 ST and B-3/B-3 ST1/B-3 BP1) which have been drilled to date as part of the captioned project. Some of the material included in this package may be redundant with information that was provided to you earlier. Please contact the undersigned at 713-669-2942 if you have any questions. Sincerely, Robert N. Welch~CAh~h~ED SEP IL g 2002 Landman cc: J. W. Lachenmaier TYONEK DEEP WELL INI~,,. ,2/3/99) General: Folder B-1: Folder B-I ST: Folder B-2: Folder B-3: Core Sample Report (B-l, B-1ST, B-2, B-3, B-3BP1, B-3ST) Geologic Tops (B-l, B-1ST, B-2, B-3) Operations Summary Report Well Completion/Re-completion Report and Log Schlumberger LIS Tape Verification Listing Blueline Logs: Fluid Comp. Cement Bond Phasor Induction w/GR Repeat Formation Tester- 32 Pressure Stations Comp. Neutron Litho-Density & Microlog w/GR/Calipers Comp. Neutron Litho-Density (TVD) Comp. Neutron Litho-Density (MD) CDR (TVD) CDR (MD) Repeat Formation Tester 14-Oct-1997 Array Induction (TVD) Array Induction (MD) Dipole Shear Sonic (MD) Dipole Shear Sonic (TVD) Gamma Ray CCL Formation Evaluation 2" MD Drilling Data Log 2" MD MWD 2" TVD MWD 2"MD Operations Summary Report Well Completion Report Directional Survey Permit to Drill Scan Well Test (Prod. Test #1) Logs: CDR (TVD) Comp. Neutron Litho-Density w/GR (TVD) and (MD) Pressure Data Log Film: ADNR (TVD) Vellum: Pressure Data Log 1":250' Sepia: Pressure Data Log 1":250' Operations Summary Report Well Completion or Recompletion Report Well Test Results = Short & Long String Diskette: Surveys Diskette: Scan Data NF. ASC and SUN. AS Logs: Array Induction 2" MD Array Induction 5" = 100' MD Comp. Neutron Litho - Density W/GR Digital Sonic Tool - Long Array Dipole Sonic Relabelled Delta Ts Formation Evaluation 2" TVD Drilling Data Log 2" MD Formation Evaluation 2" MD MWD Integrated Formation Evaluation 2" TVD MWD Integrated Formation Evaluation 2" MD Blueline Logs: G/R Collar Log Perf. Record 6-Feb-1998 G/R Collar Log Perf. Record 23-Jan-1998 Mechanical Sidewall Coring Tool $~[~E~' S~]~ 1 ~ ~00~? Completion Reports 99-021.doe / Folder B-3 ST: Folder B-3 BP1: ( .rations Summary Report { P~rmit to Drill; Sundry Approvals Blueline Logs: Platform Express Three-Detector Litho-Density Comp. Neutron/GR Caliper/GR MWD Integrated Formation Evaluation 2" TVD MWD Integrated Formation Evaluation 2" MD Formation Evaluation 2" MD Formation Evaluation 2" TVD Drilling Data 2" MD Film: Caliper Log/GR Sepias: Formation Evaluation 2" TVD Drilling Data Log 2" MD MWD 2'" TVD Formation Evaluation 2" MD Pressure Data MWD 2"MD Vellums: Formation Evaluation 2" MD Pressure Data Log MWD 2" TVD Formation Evaluation 2" TVD Drilling Data Log 2" MD MWD 2"MI) Blue Line Logs: Diskette: 4MM Tape: Film: Vellums: Direction Survey 0-17864' Formation Evaluation 2" TVD Formation Evaluation 2" MD MWD 2" MD MWD 2" TVD Pressure Data Log 8918' TVD-12332' TVD Pressure Dta Log 9134' TVD-13368' TVD Drilling Data Log 2" MD Impulse TVD Impulse MD ADI',I4 MD ADN4 TVD Resistivity TVD 1:600 & 1:240 Resistivity MD 1:600 & 1:240 B3-STI .LAS and Survey. TXT-Dir. Survey MD & TVD LAS Files (final data) Survey Files Resistivity 1:600 & 1:240 MD ADN4 MD Resistivity 1:600 & 1:240 TVD Formation Evaluation 2" MD Formation Evaluation 2" TVD Drilling Data 2" MD MWD Integ. Formation Evaluation 2" MD MWD Integ. Formation Evaluation 2" TVD Pressure Data Log Blueline Logs: Sepias: Formation Evaluation 2" TVD MWD 2" TVD Pressure Data Log Formation Evaluation 2" MD MWD 2"MD Drilling Data 2" MD MWD 2" MD Pressure Data Log Drilling Data Log 2" MD Formation Evaluation 2" TVD MWD 2" TVD Formation Evaluation 2" MD SGANNEJgl SEP ! % 2.002 99-021.doc TYONEK DEEP WELL I( _~ (2/3/99) General: Folder B-1: Folder B-1 ST: Folder B-2: Folder B-3: Core Sample Report (B-l, B-IST, B-2, B-3, B-3BP1, B-3ST) Geologic Tops (B-I, B-1 ST, B-2, B-3) /Operations Summary Report Well Completion/Re-completion Report and Log Schlumberger LIS Tape Verification Listing Blueline Logs: Fluid Comp. Cement Bond Phasor Induction w/GR Repeat Formation Tester-321~essure Stations Comp. Neutron Litho-Density & Microlog w/GR/Calipers Comp. Neutron Litho-Density (TVD)- Comp. Neutron Litho-Density (MD)' CDR (TVD). CDR (MD) ,' Repeat Formation Tester 14-Oct-1997 Array Induction (TVD) Army Induction (MD)' Dipole Shear Sonic (MD) Dipole Shear Sonic (TVD)" Gamma Ray CCL, /';-49 ~t ,t/49~-- Formation Evaluation 2" MD Drilling Data Log 2" MD htBVD 2" TVD ' Diskette: Diskette: Logs: Operations Summary Report Well Completion Report Directional Survey Permit to Drill Scan Well Test (Prod. Test #1) f Logs: CDR (TVD)" Comp. Neutron Litho-Density w/GR ' (TVD) and (MD), Pressure Data LOg Film: ADNR (TVD) Vellum: Pressure Data Log 1":250'" Sepia: Pressure Data Log 1":250'~ Operations Summary Report Well Completion or Recompletion Report Well Test Results -- Short & Long String Surveys Scan Data NF. ASC and SUN. AS Army Induction 2" MD" Array Induction 5" -- 100' MD ~' Comp. Neutron Litho - Density W/GR / Digital Sonic Tool - Long Array r' Dipole Sonic Relabelled Delta T's ' Formation Evaluation 2" TVD .~ Drilling Data Log 2" MD / Formation Evaluation 2" MD / MWD Integrated Formation Evaluation 2" TVD MWD Integrated Formation Evaluation 2" MD Blueline Logs: G/R Collar Log Perf. Record 6-Feb-1998 G/R Collar Log Perf. Record 23-Jan-1998 Mechanical Sidewall Coring Tool .'"~~..~ SED 1 ~ 2002, Completion Reports 99-021.doc Folder B-3ST: Folder B-3 BP1: ~erations Summary Report ~ · -emit to Drill; Sundry Approvals Blueline Logs: Platform Express Tlu'ee-Detector Litho-Density Comp. Neutron/GR Caliper/GR MWD Integrated Formation Evaluation 2'' TVD MWD Integrated Formation Evaluation 2" MD Formation Evaluation 2" MD Formation Evaluation 2" TVD Drilling Data 2.. MD Film: Caliper Log/GR Sepias: Formation Evaluation 2" TVD Drilling Data Log 2" MD MWD 2" TVD Formation Evaluation 2" MD Pressure Data MWD 2.. MD Vellums: Formation Evaluation 2.. MD Pressure Data Log Formation Evaluation 2" TVD Drilling Data Log 2.. MD MWD 2.. MD Blue Line Logs: Diskette: 4MM Tape: Film: Vellums: Direction Survey 0-17864' Formation Evaluation 2" TVD Formation Evaluation 2" MD MWD2" MD MWD 2" TVD Pressure Data Log 8918' TVD-12332' TVD Pressure Dta Log 9134' TVD-13368' TVD Drilling Data Log 2' MD Impulse TVD Impulse MD ADN4 MD ADN4 TVD Resistivity TVD 1:600 & 1:240 Resistivity MD 1:600 & 1:240 B3-ST1.LAS and Survey. TXT-Dir. Survey MD & Tv'I) LAS Files (final data) Survey Files Resistivity 1:600 & 1:240 MD ADN4 MD ,/ Resistivity 1:600 & 1:240 TVD ,,/ Formation Evaluation 2" MD Formation Evaluation 2" TVD Drilling Data 2" MD / MWD Integ. Formation Evaluation MWD lnteg. Formation Evaluation Pressure Data Log Blueline Logs: Sepias: Drilling Data Log 2" MD Formation Evaluation 2' TVD MWD 2' TVD Formation Evaluation 2" MD Formation Evaluation 2" TVD MWD 2" TVD Pressure Data Log Formation Evaluation 2" MD MWD 2" MD Drilling Data 2" MD MWD 2" MD Pressure Data Log 99-021.doc PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 NORTH AMERICA EXPLORATION AND PRODUCTION COMPANY January 28, 1999 BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Wondzell: Phillips Petroleum Company is submitting the Form 407 Well Completion Report on the North Cook Inlet Unit B No. 1 Sidetrack. I have attached the Form 407, directional survey, wellbore schematic and well logs. If you have any questions regarding this, please contact Shonna Boyer at (713) 669- 7980. Sincerely, N. P. Omsberg ~' Drilling Manager Phillips Petroleum Company NPO/smb CC: P. R. Dean L. L. Lyon S. M. Boyer J. D. Admire A. J. Lasche' 'IVIVI$1 O STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL [~ GAS r'-"] SUSPENDED[~I ABANDONED I"--I SERVIC,,E,,~.._~ ...... Producing Gas Well 2. Name of Operator ~,~.~.~~ 7. Permit Number Phillips Petroleum Co. 3. Address ~.;.!~ 8. APl Number 6330 W. Loop South, Bellaire, TX 77401 i 50-883-20093-01 4 Location of well at surface~.~?'.;i.~'.:i:I ;i'i?'? !.. :'. ?'~.~7.~.~ 9. Unit Name i ~,.'~'~ '~ 1249' FNL & 980' FWL SEC 6:T~"I~R~'9*~V~' North Cook Inlet At Top Producing Interval , ,~lO~ ~ NCIU B-1 ST ~.-.-3 ~ ,. .... ~/2_~ ; V'~ ~..~ : At Total Depth i ~/~ ii I0'~' ~W 11. Field and Pool i..;;';¢-;~'~:~,.~.,'-%-~..~ ~:i 2513' FSL & 1,,~,~' EEL SEC 12-T 11N-R 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. No~h Cook Inlet Field Development RKB 132 E.I NCIU 12. Date Spudded 13. Date T.D. Reached 14. Date Suspended 15. Water Depth 16. No. of Completions 02/12/1998 04/02/1998 12/01/1998 130 1 17. Total Depth 18. Plug Back Depth (MD+~D) 19. Dir~tional Su~ey 20. SSSV Depth 21. ~ickness of Permafrost 16720' MD 16590(MD) 12854 (TVD) YES ~ NO ~ 430' MD~D N/A ,, 22. Type Electric Logs Run Drillpipe conveyed Io~s were run: CDR, compensated ne~on, litho-densi~, GR 23. CASING, LINER AND CEMENTING RECORD Casi,ng She ~. per ~. Grade Seffing Depth (MD) Hole Size Cementing Record Amount Pulled 30" 407 Driven ,,,=,, , 20" 133 K-55 2,579 24" Existing 13 3/8" 72 N-80 3,760 18.5" Exisdn~ 9-5/8" 53.5 P-110 10,376 12-1/4" Existing 5" 19.5 S-135 16,650 8-1/2" 700 sxs G 24, Pe¢orations open to Pr~uction(MD+~D of Top and 25. Tubing Record ,, BoSom and inte~al, she, and number) She Depth Set (MD) ~Packer Set (MD) ........ 16080' MD- 16118' MD 4-1/2" 10074' N/A 12524' ~D - 12547' ~D 6 spf, 38 E, 219 shots, 60 deg phasing .... 26, Acid, Fracture, Cement Sqeeze, ETC. ,, I I I 27. PRODUCTION TEST Date First Production Method of Operation (flowing, gas li~, etc.) 11/29/1998 Flowing Date of TestHoum Test~ Prod. for Oil Gas Water-BBL Choke GOR 11/29/1998 36 Test Period FTP Casin~ Pressure Calculated Oil Gas Water-BBL Choke GOR 591 24 hr Rate 2186 1.99 43 48/64 910 28. CORE DATA _ Brief description of lithology, porosi~, fractures, apparent dips and presence of oil, gas or ~ter. Subm~ core chips. none Form 10-407 Rev 7-1-80 29 30 GEOLOGICAL MARKERS FORMATION TESTS Include interval tested, pressure data, all NAME MEAS. DEPTH TRUE VERT. DEPTH fluids recovered and gravity, GOR, and time of each phase. North Forelands interval see test data above ,, 31. LIST OF A'ICI'ACHMENTS Directional survey, weilbore schematic, well Io~lS 32 I hereby certify that the foregoing is true and correct to the best of my knowledge ,,,.. ~- .? ,, Title .,~ ,., Date From 10-407 Rev 7-1-80 ~.~,. ,... ~ ~-,~; PHILLIPS PETROLEUM CO A asvons Operations Summary Repo · ; ~2~ e ..... ~... ~'.,..' ..'~?~ Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: No~h Cook Inlet Unit B-1 Spud Date Event Name: Sidetrack Sta~: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date ~ From - To Hours Sub Co Phase Code Description of Operation 02/10/98 ~12:00 - 18:00 6.00 MV [v 00MMIR ~FINISHED PREPARING RIGTO SKID, LOADING C TESTING EQUIP. SKIDDED RIG SOUTH AND EAS 18:00 - 20:00 2.00 MV 6 00MMIR INSTALL RIG C~MPS, 4" MUD LINE, FLOWLINE, ~ SECURE HAND RAILING. ~20:00 - 22:00 2.00 MV 6 00MMIR REMOVE ADAPTER AND SPACER SPOOL OFF OI I ~ LAYED OVER HES HOLDING TANKS TO LOAD eL ~ 10M FLANGE W/1/2" NEEDLE VALVE ON WING V 22:00 - 00:00 2.00 DR 6 95RNTR RIGGED DOWN APOLLO INJECTION LINES. PRE~ AND INSTALL RISER AND BOPE. 02/11/98 ~00:00 06:00 6.00 DR 6 95RNTR PRE-JOB SAFE~ MEETING. 0~ PRESSURE ON V [ [ FLANGE. RU VETCO-GRAY NT-2 CONNECTOR. ~06:00 - 10:00 4.00 DR 6 95RNTR NU RISER & BOP STACK. CHG TOP & BTM RAMS I VARIABLES. 10:00 - 12:00 ' 2.00 DR 6 95RNTR LAYED DOWN PIPE HANDLER AND PICK UP POT ~ TOP OF HYDRIL. ~12:00 - 13:00 . 1.00 DR 6 95RNTR INSTALL SCAFFOLDING AND TURN BUCKLES Oh 13:00 - 17:00 4.00 RM m 95RNTR CHANGE OUT HYDRIL RUBBER. 17:00 - 20:00 3.00 DR 6 95RNTR INSTALL BELL NIPPLE, STRIP-O-MATIC TRACK (, HOLE), RIG UP IRON ROUGHNECK, BREAK DOW START TRANSFERING OBM TO PITS. ~20:00 - 20:30 0.50 WC 8 95RNTR PICKED UP TEST JOINTS AND TEST PLUG. [20:30 - 00:00 3.50 WC 8 95RNTR TESTING BOPE. TESTED HYDRIL TO 250/3500, R CHOKES/CHOKE LINE, CHOKE LINE VALVES, KII [ LINE VALVES, AND TOP DRIVE TO 250/8000 PSI, PREP. TO INSTALL WEAR BUSHING, BREAK OUT LOGGING TOOL, TEST SACING TO 5000 PSI. 02/12/98 00:00 - 00:30 0.50 WC 8 50PRDR SET WEAR BUSHING & LD RUNNING TOOL. 00:30 - 01:00 0.50 DR 2 50PRDR BREAK OUT XO SUB FR/CDR TOOL & BACK-LO~ 01:00 - 02:00 1.00 DR 9 50PRDR RU TO TEST 9 5/8" CSG. 02:00 - 02:30 0.50 DR 9 50PRDR TEST 9 5/8" CSG TO 5000 PSI/30 MIN - OK. 02:30 - 07:00 4.50 DR 2 50PRDR =U DIRECTIONAL BHA. 07:00 - 13:30 6.50 DR 4 50PRDR TIH (RABBITING DP) TO 9745'. TAGGED CMT BRII 13:30 - 15:30 2.00 DR d 50PRDR WASH & REAM FR/9745 TO 10029'. TAGGED HAF COND THICK OBM FR/BO~OMS UP. 15:30 - 21:30 6.00 CE .s 50PRDR DRILLING CMT PLUG FR/10029 TO 10386' (10' BI j i SHOE). ~21:30 - 00:00 2.50 DR 5 50PRDR CIRC. & COND. MUD, BALANCING OUT MUD ~. 02/13/98 00:00 - 02:30 2.50 DR 5 50PRDR CIRC. AND COND MUD, BALANCE OUT MUD ~. 02:30 03:00 0.50 DR y 50PRDR TEST FORMATION TO 16.0 PPG EMW W/850 PSi ~ 8849' TVD. TESTED OK. , 03:00 - 03:30 0.50 DR ~1 50PRDR DRILL FROM 10386' TO KOP ~ 10430'. 03:30 - 05:30 2.00 DR q 50PRDR WORK PIPE AND CUT GROOVE FOR SIDETRACK 05:30 - 00:00 18.50 DR = q 50PRDR TIME DRILLING TO SIDETRACK HOLE. DRILLED.~ 2.5 MIN/IN; 10' ~ 1.5 MIN/IN; 18' ~ 1 MIN/IN; DRILl ~ MUD LOGGERS SEE 90% FORMATION IN CU~Ih i ~ 80% FORMATION. 02/14/98 00:00 - 01:30 ~ 1.50 DR q 50PRDR TIME DRILL FR/10465 TO 10477' ( 1"/MIN; 80%+ F T ~ SAMPLES). SLIPPED BACK INTO OLD HOLE. VOl[ CMT AGAIN ~ 10502' W/20K ~. 01':30- 05:00 3.50 DR 5 50PRDR CIRCU~TE & WORK PIPE. I Page 1 of 22 07/31/97 OUT HES FLOW TO WELL # B-1. SERVICE AND 13-5/8" RISER. SAME, PUT 3-1/16" LVE ON B-2 WELL. =PARING TO N/D TREE ELL. RD DRYHOLE TO3 1/2" -5" D MASHER FOR BOP. CENTER OVER POTATO MASHER, RAMS HCR VALVES, LINE AND KILL ALL TESTED OK. X-O SUB ON SAME ON BOAT. CMT. CIRC & BELOW CASING TO PERFORM FIT. FOR FIT. + 14.2 PPG MUD @ @ 5 MIN/IN; 4' @ AT .5 MIN/IN UNTIL IGS. AT 10465' HAD FORMATION IN IN CIV1T. 'FAGGED Printed: 10/2'7/98 3:02:3B PM ..... - ....... , PHILLIPS PETROLEUM CO Page 2 of 22 i' .,. :' Operations Summary Report Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 ' Phase Date i From - To Hours Sub Co Code Description of Operations 02/14/98 i05:00 - 12:00 7.00 DR 4 50PRDR PUMP SLUG & POOH. '12:00 - 13:00 1.00 DR 2 50PRDR BROKE OUT BIT & MOTOR SLEEVE STABILIZER. (NOTE 1 BLADE ~, BROKEN OFF BIT). MU NEW MILL TOOTH BIT. 113:00 - 18:00 5.00 DR z 50PRDR A'I-FEMPTED TO RUN NEW BIT/BHA IN HOLE. WlH W/NEW BIT TO 54' ! & SAT DOWN. WORK BIT, UNABLE TO WORK BIT BELOW 54'. PULLED ~ & INSPECTED WEAR BUSHING-OK. ATTEMPTED TO RIH W/NEW BIT i AGAIN W/NO SUCCESS. MU USED 8 1/2" BIT & RIH 60'-OK. UPON. I CLOSE INSPEC:FION OF NEW HUGHES BIT, NOTICED VERY THICK ! WELD OF HARDFACING ON SHIRT TAIL AREA. GROUND SHIRT TAIL ! PROTECTION DOWN TO 8 1/2". i RIH W/NEW BIT TO 60' - OK. RERAN WEAR BUSHING. 18:00 - 23:00 5.00 DR 4 50PRDR TIH W/NEW HUGHES GTMPG1 BIT ON XL MOTOR W/1.5 DEG BEND ! & NO BEARING HOUSING STABILIZER. i23:00 - 00:00 1.00 DR d 50PRDR FILL PIPE AND BREAK CIRC. WASH AND REAM FROM 10437' TO ! 10502'. TAGGED PLUG, BIT DRILLED THRU PLUG IN 6". CONTINUED WASHING DOWN HOLE TO 1052.2', TAGGED HARD CEMENT. HOLE TRYING TO PACK OFF. CONT CIRC. AND WORKING TO CLEAN UP ' HOLE BEFORE ATTEMPTING TO SIDETRACK. 02/15/98 00:00 - 02:00 2.00 DR d 50P'RDR CIRC & COND MUD @ 10522' (HOLE PACKING OFF). 02:00 - 07:00 5.00 DR d 50PRDR ORIENT TO LOW SIDE & REAM TO CUT TROUGH. FELL THROUGH CMT PLUG. CONTINUE WASHING TO 10860'. CONTAMINATED CMT AT SHAKERS. 107:00 - 08:00 1.00 DR 5 50PRDR SPOT 15.5 PPG HI-VIS PILL FR/10860 TO 10760'. i 08:00 - 09:00 1.00 DR d 50PRDR PU ABOVE PILL & BACKREAM TO ] 9 5/8" SHOE. 109:00 - 10:30 1.50 DR 5 50PRDR CIRC BOTTOMS UP & PUMP SLUG. ! 10:30 - 16:30 6.00 DR 4 50PRDR POOH. 116:30 - 19:00 2.50 DR 2 50PRDR PU DIVERTER SUB & 500'2 7/8" PAC DP. 119:00 - 00:00 5.00 DR 4 50PRDR TIH TO 9 5/8" SHOE. 02/16/98 00:00 01:30 1.50 DR z 50PRDR SLIP & CUT 116' DRLG LINE 01:30 - 02:00 0.50 DR 2 50PRDR PICK UP AND MAKE UP BAKER CIRC. SWIVEL ON SINGLE JT. OF DRILL PIPE AND LAY BACK IN V-DOOR. 02:00 - 02:30 0.50 DR 4 50PRDR TIH TO 9-5/8" CASING SHOE @ 10376'. 02:30 - 05:30 3.00 DR d 50PRDR WASH, REAM, WORK PIPE, AND CIRC. EA. STAND OF DRILL PIPE TO 10730'. 05:30 - 06:00 0.50 DR 2 50PRDR PICKED UP CIRC. SWIVEL, AT-I'EMPT TO CIRC. & ROTATE. SWIVEL LEAKING, LAYED DOWN SWIVEL. 06:00 - 06:30 0.50 DR d 50PRDR WASH, REAM, AND WORK PIPE TO 10760'. 06:30 - 09:30 3.00 DR 2 50PRDR CIRC & COND HOLE FOR CEMENTING WHILE ROTATING & I RECIPROCATING @ 10BPM 109:30 - 11:00 1.50 CE 5 50PRDR RU HALLIBURTON LINES & CIRCULATING HEAD. CONTINUE TO CIRC ~ & COND, HOLD PRE JOB SAFETY MEETING 111:00 - 13:00 2.00 CE v 50PRDR RIG PUMPED 30 BBL DIESEL SPACER. SWITCH TO HALLIBURTON, I PRES TEST LINES 3000#. HALLIBURTON PUMP 40 BBLS FLOZAN i SPACER MIXED @14.5# 150 + VIS. START MIXING CMT @1140 HRS. i , MIX & PUMP 900 SXS PREMIUM CMT +0.80% CFR-3 MIXED @ 16.8#. DISPLACED 3/BBLS FLOZAN SPACER + 143.5 BBLS 14.2# MUD FOR BALANCED PLUG. 1300 HRS FINISHED DISPLACEMENT. 13:00 - 13:30 0.50 CE 4 50PRDR LD 2 JTS & POOH 8 STDS. SCREW INTO STD #9 WITH TOP DRIVE. 13:30 - 14:30 1.00 CE 5 50PRDR WHILEBREAKRoTATINGCIRCULATION& RECIPROCATING.@10009' 10 BPM, WORKING ENTIRE STAND 14:30 - 17:30 3.00 CE z !50PRDR FLOZAN SPACER @SURFACE W/4000 STKS. BYPASS SHAKERS & GIVING FLUID TO APOLLO. CEMENT RETURNS @SURFACE, Printed: 10/27/98 3:02:3~ PM . ' '.' ' ...... PHILLIPS PETROLEUM CO Page 3 of 22 ". Operations Summa Repod Legalwe,~ame: NORTH COOK INLET UNIT-B 000001 Common Well Name: NoKh Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Stat 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 ' Co Phase . Date ' From - To Hours Sub Code Description of Operations -- 02/16/98 14:30 - 17:30 I 3.00 CE z 50PRDR PLUGGED SHALE SHAKER BYPASS , RAN OVER AUGER TO APOLLO, PLUGGED FLOWLINE, & POLLUTION PANS UNDER ROTARY. RU'2" LINE ON FLOWLINE TO CLEAR SAME. UNABLE TO CLEAR FLOWLINE ~ FROM BELL NIPPLE TO J~ ON FLOWLINE. RU LINE FROM OUTLET ~ ~ ON CHOKE MANIFOLD TO FLOWLINE. CLOSE HYDRIL& CIRC THRU I CHOKE LINE, OK. RECIPROCATE PIPE THRU HYDRIL. CON'T CIRC I UNTIL CMT CLEANUP ON SHAKERS. OPEN HYDRIL & WORK PIPE FULL STD. 17:30 - 18:30 1.00 CE 4 50PRDR POOH 10 STDS. NO DRAG, PIPE COATED ON OD W/LAYER OF CEMENT. FILL HOLE THRU KILL LINE. I ~ FUNCTION HYDRIL, TOP & BTM RAMS. 18:30 - 00:00 5.50 CE 4 50PRDR POOH W/5" DRILL PIPE. 02/17/98 100:00 - 02:00 2.00 CE 4 50PRDR FINSIHED POOH W/5' DP. NOTE: 1ST 18 STDS 5" DP PULLED COATED ON OD W/1/16" - 1/2" THICK CEMENT SHEATH. 02:00 - 03:00 1.00 CE 2 50PRDR POOH LD 2 7/8" TBG. RD HANDLING TOOLS, ETC. 03:00 - 00:00 21.00 CE z 50PRDR CHIPPING & CLEANING OUT CMT FROM UNDER ROTARY TABLE, IN STIP-O-MATIC, IN FLOWLINE & IN POLLUTION PAN UNDER RIG FLOOR. NOTE: FOUND WEAR BUSHING CMTD UP INSIDE STRIP-O-MATIC. 02/18/98 00:00 - 00:00 24.00 CE z 50PRDR CHIPPING AND CLEANING CEMENT FROM UNDER RIG FLOOR, CLEANED OUT AROUND WEAR BUSHING AND RETRIEVED SAME, CLEANED OUT AROUND STRIP-O-MATIC AND REMOVED SAME, CHIP AND CLEAN CEMENT OUT OF POLLUTION PAN AND 30" RISER. HAVE BLIND RAMS CLOSED AND TOP PIPE RAM DOORS OPEN, REMOVING ~ CHIPPED CEMENT THRU OPEN DOOR. 02/19/98 00:00 - 00:00 24.00 CE :z 50PRDR CHIPPING & CLEANING CMT FR/BELL NIPPLE, RISER, FLOWLINE, TRIP TANK LINES & GAS BUSTER RETURN LINE. FUNCTION HYDRIL. ~ OPEN DOORS & CLEAN CMT OFF RAMS. i PLAN TO: RIH & TAG WELL HEAD W/12 1/4" BIT. RUN WASH TOOLS & WASH INSIDE STACK & WELL HEAD. PUMP THROUGH CHOKE MANIFOLD & KILL LINES. A~EMPT TO SET TEST PLUG & TEST BOP'S. TIH W/8 1/2" BIT & SCRAPER. , 02/20/98 00:00 - 07:00 7.00 CE z 50PRDR Open doors on all rams. Clean & chip cement (rams did not have much cement around them). Changed rubber elements on blind rams (had trouble closing doors on blinds - hinges seem worn. Bolt holes not alighed - had to pick up on ram door to sta~ bolts.) 07:00 - 08:00 1.00 CE z 50PRDR Made up 12-1/4" bit & RIH slowly to 53.5fl. Broke circ. with OBM & checked for leaks in sudace lines - all OK. Wash out wellhead and rams. 08:00 - 09:00 1.00 CE z 50PRDR ~D 12.1/4" bit and PU 8-1/8" OD Kvaemer washing tool. Washed out wellhead, rams & Hydril. Function all BOP rams and wash out again. 09:00 - 10:00 1.00 CE z 50PRDR With washing tool at w/h, pumped 30bbl diesel while working and rotating pipe and washing tool. 10:00 - 11:00 1.00 CE :z 50PRDR Washed out BOP stack with 30bbl soapy water, followed with 60bbl drill I water. 11:00 - 16:00 5.00: CE z 50PRDR ~D washing tool and P/U test plug. A~empt to set test plug in w~ - would not go. Pull test plug to rig floor and inspect same - found scrape mark on plug from taper to 'o' ring seal area. Made several a~empts to set test plug - no go. Still getting scrape marks from w/h. 16:00 - 20:30 4.50 CE z 50PRDR ~D test plug. Clear rig floor. Pull master bushings, remove 30" riser, unbolt BOP stack at w/h. 20:30 - 21:00 0.50 CE z 50PRDR Raise BOP and inspect w/h. Wellhead full of cement. 21:00 - 00:00 3.00 CE z 50PRDR Clean cement from w/h. .... Printed: 10/27/98 3:02:38 PM PHILLIPS PETROLEUM CO Page 4 of 22 Operations Summary Report !Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 i From- To [ Hours Sub ColPhase Code Description of Operations Date 21:oo - oo:oo 3.00 CE z i50PRDR O2/2O/98 I , CEMENT IN WELL HEAD FROM TEST PLUG SEALING AREA DOWN I I BELOW LENGTH OF WEAR BUSHING AND BEYOND. CEMENT SET UP !t AROUND WALL OF CASING W/HOLE IN CENTER ABOUT 6.625 AND ~ CLOSED UP SMALLER DOWNHOLE AS FAR AS WE CAN SEE. =02/21/98 00:00 - 01:00 1.00 CE z !50PRDR Chip & clean cmt from tbg spool. ~01:00 04:00 ' 3.00 CE z ~50PRDR NU BOP stack 04:00 - 08:00 ! 4.00 WC 8 ' 50PRDR Run test plug. Fill stack. Test BOP:- i Annular - 250/3000psi Top VBR, Blinds, Lower VBRs, choke & kill line HCRs, TIW and Gray ~nside valves - 250/8000psi Choke manifold - 250/8000psi. Upper IBOP failed to test. 08:00 - 09:30 1.50 WC 8 50PRDR Blowdown choke & kill manifolds. Retrieve test plug. Run wear bushing. L/D test jr. 09:30 - 12:00 2.50 RM .m 50PRDR Change out saver sub. Change dies in back-up grabber. 12:00 - 19:30 7.50 RM !m 50PRDR Attempt to test I-BOP to 250/8000 psi, would not test. Changed out upper and lower I-BOP. ,19:30 - 20:00 0.50 WC 8 50PRDR Tested I-BOP to 250/8000 psi, ok. i20:00 - 20:30 0.50 WC 12 50PRDR Rigged down bop test equip. ,20:30 - 22:00 1.50 CE 4 50PRDR Picked up 8.5" bit, 1 stand of HWDP, and 1 stand of 5" drillpipe, rih and washed and reamed out cement from wellhead to 189' to get bha in hole from bit to casing scraper. 22:00 - 22:30 0.50 CE 4 50PRDR Circ. hole clean, pooh w/2 stands of pipe. layed down bit and bit sub. 22:30 - 23:30 1.00 DR 2 50PRDR Picking up new BHA. 23:30 - 00:00 0.50 DR 6 50PRDR Install strip-o-matic. 02/22/98 00:00 - 01:30 I 1.50 DR 2 50PRDR PU BHA. INSTALL STRIP-O-MATIC AND REMOVE (NOT i FUNCTIONING). 01:30 - 07:00 , 5.50 DR p 50PRDR REAM CMT FROM 189FT TO 1808FT. 07:00 - 07:30 0.50 DR 4 50PRDR CIRC BOTTOMS UP 07:30 - 08:30 1.00 DR 4 50PRDR TIH TO 2180FT. CIRC HOLE CLEAN. CLEAN RIG FLOOR. 08:30 - 12:00 3.50 DR 4 50PRDR TIH FROM 2180FT TO 6477FT 12:00 - 14:00 2.00 DR p .50PRDR RIH. FILL @ 8810FT. TAG CMT @ 9528FT. 14:00 - 18:00 4.00 DR p 150PRDR ~REAM & WASH, DRILL OUT CEMENT STRINGERS FROM 9528FT' TO 110,041FT. .18:00 o 00:00 6.00 DR w i 50PRDR DRILLING OUT CEMENT PLUG IN CASING FROM 10041' TO 10232', i 191' @ 31.83 FPH. 02/23/98 00:00 - 03:00 3.00 DR w 50PRDR DRILLING GOOD HARD CEMENT FROM 10232' TO 10400', 168' @ 56.0 FPH. CEMENT DRILLING @ 58 FPH TO CASING SHOE @ 10376', ROP INCREASED TO 72 FPH F/10376' TO 10386', SLOWED TO 20 FPH F/ I ~ 10386' TO 10391', INCREASED TO 52 FPH F/10391' TO 10400'. HAD i 14-16000 WOB W/110 RPM ON MOTOR AND 50 RPM ON ROTARY @ ~ 420 GPM, DIFF. pRESSURE @ 250 PSI. 03:00 - 09:00 6.00 DR q 50PRDR TRIMsiDETRAcK.HOLE FROM 10378 TO 10398, PREPARING HOLE FOR 09:00- 14:30 . 5.50 DR 4 50PRDR PUMP SLUG AND POOH 14:30 21:30 7.00 DR 4 50PRDR L/DDEGLOWBEND)SPEEDAND MOTORMwD. RIHANDToCASING10390'. SCRAPER. P/U XP MOTOR (1.5 21:30 - 22:00 0.50 DR Iq 150PRDR CIRC, ORIENT TOOL FACE TO LOW SIDE, WORK TORQUE OUT OF It DRILL STRING. 22:00 - 23:00 1.00 DR q i 50PRDRSET BIT @ 10390' W/TOOL FACE TO LOW SIDE OF HOLE, ROTATING ...... Printed: 10/27/98 3:02:38 PM .,.... , :, PHILLIPS PETROLEUM CO Page 5 of 22 Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date , From - To I Hours Sub Co'Phase Code Description of Operations I I 02/23/98 122:00 - 23:00 1.00 DR lq 50PRDR BIT W/MOTOR ONLY @ 180 RPM W/400 GPM. STARTING LEDGE 23:00 I FOR SIDE TRACK. - 00:00 1.00 DR q 50PRDR TIME DRILLING @ .5 FPH ( 10 MIN. PER INCH), ATTEMPTING TO SIDE TRACK HOLE. i PLANNED SIDETRACK: t 10 MIN./INCH .5 FPH 3.0' 6 HRS 5 MIN./INCH 1.0 FPH 10.0' 10 HRS 2.5 MIN./INCH 2.0 FPH 10.0' 5 HRS 1.5 MIN./INCH 3.3 FPH 26.0' 8 HRS 00:00 TOTAL 49.0' 29 HRS 02/24/98 - 00:00 24.00 DR q 50PRDR TIME DRILL 1/2FT/HR TO 10,393FT (3FT IN 6HRS) 1FT/HR TO 10,403FT (10FT IN 10 HRS) 2FT/HR TO 10,413FT (10FT IN 5 HRS) 3.3FT/HR TO 10,423FT (10FT IN 3HRS) I FURTHER 16FTTO DRILL @ 3.3FT/HR 02/25/98 00:00 - 06:00 6.00 DR q 50PRDR TIME DRILLING @ 3 FPH TO 10440'. HAD 100% FORMATION IN SAMPLES. 06:00 - 00:00 18.00 DR q 50PRDR DIRECTIONAL DRILLING, ROTATE & SLIDE. SLIDE 10440-10450; ROT 10450-10527 SLIDE 10527-10541; ROT 10541-10546 SLIDE 10546-10564; ROT 10564-10621 SLI DE 10621-10653; ROT 10653-10715 I SLIDE 10715-10719; ROT 10719-10725 : SLIDE 10725-10732 02/26/98 00:00 - 01:00 1.00 DR q 50PRDR Directional drilling (sliding) 10,732' to 10,736'. 01:00 - 02:00 1.00 DR !q 50PRDR Drilling (rotating) 10,736'- 10,747' 02:00 - 03:30 1.50 DR q 50PRDR Sliding 10,747'- 10,751' 03:30 - 07:00 3.50 DR q 50PRDR Rotated 10,751'- 10,832'. 07:00- 10:00 3.00 DR q 50PRDR Sliding 10,832'- 10,850'. 10:00 - 12:00 2.00 DR q 50PRDR Rotated 10,850'- 10,865'. 12:00 - 00:00 12.00 DR q 50PRDR Rotate 10,865'- 10,906'. Slide 10,906'- 10,912'. Rotate 10,912'- 10,917'. Slide 10,917'- 10,921'. I . Rotate 10,921' - 10,926'. Slide 10,926'- 10,931'. I Rotate 10,931'- 10,936'. I Slide 10,936' - 10,941'. I ~ Rotate 10,941' - 10,972'. Now at 10~972' MD (9,314' TVD) 02/27/98 100:00- 15:30 15.50 DR q 50PRDR DIRECTIONAL DRILLING- I : ROTATE 11,966' - 11,001 (35FT) ' I SLIDE 11,001' - 11,007' (6FT) ! ROTATE 11,007' - 11,012' (5FT) I SLIDE 11,012' - 11,017' (5FT) ROTATE 11,017'- 11,022' (5FT) [ SLIDE 11,022' - 11,028' (6FT) ROTATE 11,028' - 11,033' (SFT) SLIDE 11,033' - 11,038' (5FT) ROTATE 11,038' - 11,052' (14FT) ...... Printed: 10/27/98 3:02::38 PM .... '"' '"'- ':" -' .. PHILLIPS PETROLEUM CO Page'6 of 22 · Operations Summary Report Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 ~ I Co Phase ' i Date i From - To Hours Sub Code Description of Operations I ' 02/27/98 1.15:30 - 17:00 1.50 DR 4 50PRDR BACKREAM TO SHOE @ 10,3961:'1'. POOH. CI'ESTED CHOKE i MANIFOLD 250/5000PSI WHILE POOH). 17:00 - 18:00 1.00 DR 5 50PRDR iCIRC. BOTTOMS UP. 18:00 - 21:30 3.50 DR 4 50PRDR FINISHED POOH TO BHA. 21:30 - 22:30 1.00 DR 2 50PRDR L/D BHA 22:30 00:00 ' 1.50 WC 8 50PRDR TEST BOPs. ALL RAMS, CHOKE LINE VALVES, KILL LINE VALVES, FLOOR VALVES TO 250/5000 PSI. TESTED HYDRIL TO 250/2500 PSI. 02/28/98 00:00 - 01:30 1.50 WC 8 50PRDR FINISHED TESTING BOPE, WEEKLY TEST. TESTED BOPE TO 250/5000 PSI. TESTED HYDRIL TO 250/2500 PSI. (AOGC DID NOT 01:30 WISH TO WITNESS THIS TEST.) - 02:00 0.50 WC 6 50PRDR RIGGED DOWN BOP TEST EQUIP. 02:00 - 03:30 1.50 RM m 50PRDR REPAIRING AIR BOOT ON BELL NIPPLE, REPLACED AIR HOSE. 03:30 04:30 1.00 DR 2 50PRDR MOToRMU BHA:(w/CHANGEDNo STABILIZER).TO NEW PDC BIT & CHANGED TO NEW MUD 104:30 - 09:00 4.50 DR 4 .50PRDR WIH TO CASING SHOE. 09:00 - 10:00 1.00 :{M c ,50PRDR CUT DRILLING LINE. 10:00 11:00 1.00 DR 4 50PRDR WlH TOTD11,093'MD. 11:00 00:00 13.00 DR q 50PRDR DIRECTIONAL DRILLING, ROTATE AND SLIDE. ROTATE F/11092 TO I 11103- 10'. I i SLIDE F/11103 TO 11128 - 25'. I ROTATE F/11128 TO 11188 - 60°. I SLIDE F/11188 TO 11218 - 30'. ROTATE F/11218 TO 11281 - 63'. SLIDE F/11281 TO 11283- 2'. I 03/01/98 I00:00 - 02:30 2.50 DR q 50PRDR DIRECTIONAL DRILLING, ROTATE AND SLIDE. SLIDE F/11283 TO 11311 - 28'. 02:30 - 05:30 3.00 DR q 50PRDR ROTATE F/11311 TO 11377 - 66'. 05:30 - 09:30 4.00 DR q 50PRDR SLIDE F/11377 TO 11407 - 30'. 09:30 - 12:00 2.50 DR q 50PRDR ROTAYE F/11407 TO 11470 - 63'. 12:00 - 15:00 : 3.00 DR q 50PRDR SLIDE F/11470 TO 11500 - 30'. 15:00 - 22:00 7.00 DR q 50PRDR ROTATE F/11500 TO 11564 - 64'. 22:00 - 00:00 2.00 DR q 50PRDR SLIDE F/11564 TO 11578 - 14'. 03/02/98 00:00 - 01:30 1.50 DR q 50PRDR Drilling directionally. Slide 8' 11,578' - 11,586'. 01:30 - 02:00 0.50 DR q 50PRDR Rotated 6' to 11,592'. 02:00 - 03:00 1.00 DR q 50PRDR Slide 10' to 11,602'. 03:00 - 06:00 3.00 DR q 50PRDR Rotated 56' to 11,658'. 06:00 - 07:30 1.05 DR q 50PRDR Slide 8' to 11,666'. 07:30- 10:00 2.50 DR q 50PRDR Rotated 15'to 11,681' 10:00 - 12:30 2.50 DR q 50PRDR Slide 22' to 11,703'. 12:30 - 15:00 2.50 DR q 50PRDR Rotated 49' to 11,752'. starting to get behind on direction. 15:00 - 00:00 9.00 DR q 50PRDR Slide 26' to 11,778'. I :[UNNING 250-275 PSI DIFF. ON MOTOR W/10 - 12,000# WOB. , · 03/03/98 i00:00 - 04:00 4.00 DR q 50PRDR DIR. DRLG. ROTATE AND SLIDE, I SLIDE 11'TO 11789'. 04:00- 09:00 5.00 DR q i50PRDR ROTATE 56' TO 11845'. 09:00-12:30 3.50 DR q 50PRDR SLIDE 20' TO11865'. 12:30 - 13:00 0.50 DR q 50PRDR ROTATE 8' TO 11873'. 13:00- 15:00 2.00 DR q 50PRDR SLIDE 17'TO 11890'. 15:00- 19:00 I 4.00 DR q 50PRDR ROTATE 47' TO 11937'. 19:00.00:00i 5.00 DR q 50PRDR SLIDE 20' TO 11957'. / ,, Printed: 10/27/98 3:02:38 PM ~','.,.~::.:. PHILLIPS PETROLEUM CO Page 7 of 22 Operations Summary Report · . . .... Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date [From-,To Hours SubColPhase C°de/ Description of Operations 03/04/98 t00:00 - 01:00 1.00 DR q 50PRDR Drilled directionally from 11,957' MD: ~ ' i Slide 10' to 11,967'. 101:00 - 05:30 4.50 DR tq 50PRDR Rotated 63' to 12,030'. 105:30 - 09:30 4.00 DR Iq 50PRDR Slide 40'to 12,070'. 109:30 - 12:00 2.50 DR q 50PRDR Rotate 53'to 12,123'. 112:00 - 12:30 0.50 DR 7 50PRDR Anadrill computer down. 12:30 - 18:00 5.50 DR q 50PRDR Slide 42' to 12,165'. 18:00 - 22:30 4.50 DR q 50PRDR Rotate 52' to 12,217'. 22:30 - 23:15 0.75 DR q 50PRDR Slide 9' to 12,226' MD (10,296' TVD) 23:15 - 00:00 0.75 DR b 50PRDR Take survey (computer down 15 rain). Orient tool. Last survey at 12149.5' = 36.58 deg, azm 221.18 deg. 03/05/98 00:00 - 00:30 0.50 DR iq 50PRDR Slide from 12,226' to 12,228'. 00:30 - 01:00 0.50 DR iq 50PRDR Rotate 3' to 12,231'. 01:00 - 07:30 6.50 DR q 50PRDR Slide 35' to 12,266'. 07:30- 12:00 4.50 DR q 50PRDR Rotate 44' to 12,310'. 112:00 - 17:00 5.00 DR q !50PRDR !Slide 40' to 12,350'. 17:00- 22:30 5.50 DR q 50PRDR Rotate 51' to 12,401' 22:30 - 23:00 0.50 DR b 50PRDR Survey. 23:00 - 00:00 1.00 DR q 50PRDR Slide 8' to present depth of 12,409' MD (10,441' TVD). 03/06/98 00:00 - 04:30 4.50 DR q 50PRDR Slide from 12,408' - 12,442' MD (34ft) 04:30 - 08:00 3.50 DR !q 50PRDR Rotate form 12,442' - 12,506' MD (64ft) 08:00 - 12:00 4.00 DR q 50PRDR Slide from 12,506' - 12,534' MD (28ft) '12:00 - 14:00 2.00 DR q 50PRDR Slide from 12,534'- 12,555' MD (21ft) 114:00 - 18:00 4.00 DR q 50PRDR Rotate from 12,555'- 12,601' MD (46ft) 18:00 - 21:00 3.00 DR q !50PRDR Slide from 12,601'- 12,620' MD (18ft) 21:00 - 22:00 1.00 DR z 50PRDR MWD quit working. Tried several procedures to get working - would not work. 22:00 - 22:30 0.501 DR 5 50PRDR Pumped sweep (previously mixed) down tbg & above BHA. 22:30 - 00:00 1.50 DR 14 50PRDR 3ackreaming out of hole - OK so far. 03/07/98 00:00 - 02:30 2.50 DR 4 50PRDR Finish back reaming from 12409' MD to casing shoe at 10,376' MD. !02:30 - 04:00 1.50 DR 5 50PRDR Circulate bottoms up at casing shoe. Clean rig floor up. Pumped dry job. Filled trip tank. Blew down kelly hose. 04:00 - 08:00 4.00 DR 4 50PRDR Finished POOH. Testing choke manifold (250psi / 5000psi) while POOH. Good test. 08:00 - 09:00 "i.00 DR 2 50PRDR Lay down bit / mud motor / MWD / jars / 2 LC. 09:00 - 11:00 2.00i DR .z 50PRDR Clean rig floor. Pull wear bushing and make up test joint. Set test plug in 8 7" bowl. ;11:00 - 12:00 1.00 DR 50PRDR Tested BOP's. GoodTest. 12:00 - 13:30 1.50 DR 8 50PRDR Tested annular (250psi / 2500psi). Tested top pipe, HCR choke, HCR kill, manual choke, manual kill, lower pipe rams, and blinds (250psi / 5000pst). I ) Tested BOP kelly cock, dart valve, and TIW (250psi / 5000psi). All tested I Good. [ 13:30 - 14:00 0.501 DR z 50PRDR Pulled test plug, set wear bushing, and layed down test pipe joint. [ 14:00 - 15:30 1.50 DR 2 50PRDR ! PU BHA, orient mud motor, test MWD and motor. [15:30 - 19:00 3.50 DR 4 50PRDR TI H to casing shoe at 10376' MD. 19:00 - 20:00 1.00 RM lc 50PRDR Cut ddll line. 20:00 - 21:00 1.00 RM .3 50PRDR Service top drive. 21:00 - 00:00 3.00 DR 14 50PRDR Going in open hole slowly, having to rotate & ream. 03/08/98 ~ 00:00 - 12:00 12.00 DR 14 50PRDR Ream and was'h from 10,815' MD t'o 12,282' MD (Ream 1467', Act. Rmg. i 9.7 Hrs). i t !Torque --- (550 - 610 amps) I Rotary spd --- (45 - 50 RPMs) .... ~ , .............. ¢, Printed: 10/27/98 3:02:38 .... : .... ',..'.:" PHILLIPS PETROLEUM CO Page 8 of 22 . ,. _*..::: ..'.. .,.'.. Operations Summary Report Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B*I Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: ~Rig Name: Rig Number: 428 ' Date i From - To Hours Sub Co Phase Code Description of Operations 03/08/98 i oo:oo - 12:00 12.00 DR 4 50PRDR Wt on Bit -o- (0 - 2K) Pmp Press --* (2500#) '~12:00 - 16:00 4.00 DR 4 50PRDR Ream and wash from 12,282' MD to 12,619' MD (Ream 337', Act. Rmg. i 3.25 Hrs). ~ Torque --- (550 - 610 amps) I Rotary spd --- (45 - 50 RPMs) ~ WtonBit --- (0-2K) i Pmp Press ---(2~;00#) 116:00 - 16:30 0.50 DR q 50PRDR Drilling: rotate from 12,619' - 12,634' MD (15 ft) 116:30 - 21:00 4.50 DR q 50PRDR Slid 23' to 12,657'. [21:00 - 00:00 3.00 DR q 50PRDR Rotated 72' to 12,729' MD (10,684' TVD). Last survey 12621.69' = 41.477, ; azm 233.07. 03/09/98 00:00 - 03:00 3.00 DR q 50PRDR Slide from 12,729' - 12,749' (24 ft) 03:00 06:00 3.00 DR q 50PRDR Rotate from 12,749' - 12,812' (63 ft) !06:00 - 07:30 1.50 DR q 50PRDR Slide from 12,812' - 12,817' (5 ft) 107:30 - 08:00 0.50 DR q 50PRDR Rotate from 12,817' - 12,822' (5 ft). !08:00 - 10:00 2.00 DR q 50PRDR Slide from 12,822'- 12,833' (11 ft) 110:00 - 11:00 1.00 DR q 50PRDR Rotate from 12,833' - 12,844' (11 ft) i11:00-12:30 1.50 DR q 50PRDR Slide from12,841' -12,845' (4 ft) 112:30 - 13:00 0.50 DR q 50PRDR Rotate from 12,845' - 12,852' (7 ft) I. 13:00 - 16:30 3.50 DR q 50PRDR Slide from 12,852' - 12,867' (15 ft) 116:30 - 19:00 2.50 DR q 50PRDR Rotate from 12,867' - 12,937' (70 ft) i 19:00 - 22:30 3.50 DR q 50PRDR Slide 12,937' - 12,961' (24'). i22:30 - 00:00 1.50 DR :q 50PRDR Rotate 12,961' -' 12974' (13'). Now at 12,974' MD (10,865' TVD). Last . survey at 12,898.03'= 42.157 angle, 240.7? azm. 03/10/98 i00:00 - 01:30 1.50 DR q 50PRDR Rotate from 12,974' MD - 12,999' MD (25 ft) i01:30 - 03:00 1.50 DR q 50PRDR Slide from 12,999' MD - 13,003' MD (4 ft) i03:00 - 04:00 1.00! DR q 50PRDR Rotate from 13,003' MD - 13,011' MD (8 ft) 104:00 - 05:30 1.50 DR q 50PRDR Slide from 13,011' MD - 13,020' MD (9 fl) 105:30 - 07:00 1.50 DR q 50PRDR Rotate from 13,020' MD - 13,035' MD (15 ft) 07:00 - 12:00 5.00 DR q 50PRDR Slide from 13,035' MD - 13,052' MD (17 ft) . i12:00 - 12:30 0.50 DR q . 50PRDR Rotate from 13,052' MD - 13,061' MD (9 ft). TVD is 10,932'. i12:30 - 13:00 0.50 DR q 50PRDR Conduct directional survey @ 12,992' MD shows 0.87? drop in angle. ! Last survey at 12992.35' MD = 41.287 angle, 241.37 azm. Prepare to I ~OOH to change BHA to get better angle-building capability. !13:00 - 18:00 5.00 DR 4 50PRDR Back reaming from 13,061' MD - 10,376' MD (9 5/8" csg shoe) i 18:00 - 19:30 1.50 DR 5 50PRDR Circulate bottoms up at casing shoe. Cleaned rig floor. Pump dry slug. ! Filled trip tank. Blew down kelly hose. 19:30 - 23:30 4.00 DR 4 50PRDR POOH. ',23:30 - 00:00 0.50 DR 2 50PRDR LD PDC bit & XP motor. Prep to PU mill-tooth bit & regular motor (7/8 lobes). 03/11/98 '~ 00:00 - 01:30 1.50 DR 2 50PRDR Lay down bit and motor. Pickup Bit #7 (MFDSSHL) and new 1.5 Adj. ~ motor. Orient and test mud motor. i01:30 - 06:30 5.00 DR 4 50PRDR GIH to casing shoe. i06:30 - 12:00 5.50 DR 4 50PRDR Wash from 11,466' MD- 13,061' MD. ~ Surveyed going in @ I 12870' MD, Incl. = 42.68 Deg Azm. = 240.4 Deg DLS = 1.33 Deg/100ft I TVD. = 10788' I 12898' MD, Incl. = 42.15 Deg ' I i Azm. = 240.7 Deg. [ DLS = 2.04 Deg/100ft .. --.. Printed: 10/27/98 3:02:38 PM - .. PHILLIPS PETROLEUM CO Page 9 of 22 · ... - ...... Operations Summary Report ,, , . Legal Well Name: NQRTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date From-To Hours Sub ColPhase Code Description of Operations _ 03/11/98 i06:30-12:00 5.50t DR 50PRDR TVD = 10809' , I 12940' MD, Incl. = 42.17 Deg ~ Azm. = 240.7 Deg ,, [ DLS = 0.05 Deg/100ft ~, TVD = 10840' , 12960' MD, Incl. = 42.35 Deg i Azm. = 240.9 Deg DLS = 1.12 Deg/100ft I TVD = 10855' I 12992' MD, Incl. = 41.28 Deg ) i Azm. = 241.3 Deg ~ DLS = 3.40 Deg/100ft I TVD = 10879' I '*No trouble tih. [ 12:00 - 13:30 1.50 DR iq 50PRDR Rotate from 13,061' MD - 13,082' MD 13:30 - 15:30 2.00 DR q 50PRDR Slide from 13,082' MD- 13,100' MD !15:30 - 16:30 1.00 DR q 50PRDR Rotate from 13,100' MD - 13,104' MD. Oriented tools. 16:30 - 18:00 1.50 DR q 50PRDR Slide from 13,104' MD- 13,114' MD. 18:00 00:00 6.00 DR q '50PRDR Rotate from 13,114' MD- 13,162' MD. 03/12/98 ! 00:00 - 04:00 4.00 DR q 150PRDR Slide from 13,160' MD - 13,190' MD (30 ft). 04:00 - 05:30 1.50 DR q 50PRDR Rotate from 13,190' MD - 13,210' MD (20 ft). 05:30 - 09:00 3.50 DR q 50PRDR Slide from 13,210' MD - 13,224' MD (14 ft). 09:00 - 13:30 4.50 DR q 50PRDR Rotate from 13,224' MD - 13,244' MD (20 ft). Prepare to POOH to change BHA to get better ROP. 13:30 - 18:30 5.00' DR 4 50PRDR Back reaming from 13,244' MD - 10,376' MD (9 5/8" csg shoe) t 18:30 - 19:30 1.00 DR 4 50PRDR i Circulate bottoms up at casing shoe. Clean rig floor. Pump dry slug. Filled i ~ trip tank. Blew down kelly hose. 19:30 - 00:00 4.50 DR 4 50PRDR 'TOOH. Broke out bit. 03/13/98 00:00 - 01:30 1.50 DR 4 50PRDR i Layed down mill tooth bit, motor, MWD, changed STB blades. Picked up MWD, motor, and Hycalog steering wheel PDC bit. Tested MWD. 01 :.30 - 06:00 4.50 DR !4 50PRDR TIH to 9 5/8" csg shoe - retested MWD @ 721', filled pipe at 3889', 7160', i and 10340'. '06:00 - 07:30 1.50 DR 7 50PRDR Cut 101' of drill line. Service rig and top drive. 107:30 - 09:00 1.50 DR 4 50PRDR Continue to TIH to 12,967' MD. 09:00 - 10:00 1.00 DR 4 50PRDR Ream from 12,967' MD - 13,244' MD (last 3 stands) for safety. 10:00 12:30 2.50 DR q 50PRDR Check survey at TD. Rotate from 13,244' MD - 13,274' MD. 12:30-13:00 0.50 DR 7 50PRDR No. 2 mud pump down. Pump liner swab out. 13:00 - 15:30 2.50 DR q 50PRDR Rotate from 13,274' MD - 13,311' MD. Survey. 15:30 - 18:00 2.50 DR q 50PRDR Slide from 13,311' MD - 13,335' MD. Survey. S.P.R. check. ,18:00 20:30 2.50 DR q 150PRDR Rotate from 13,335' MD - 13,375' MD. 120:30 - 22:00 1.50 DR q 50PRDR Slide from 13,375' MD - 13,400' MD. Survey. [22:00 - 00:00 2.00 DR q '50PRDR Rotate from 13,400' MD - 13,432' MD 03/14/98 100:00 - 02:00 2.00 DR q '50PRDR Rotate from 13,432' MD - 13,465' MD. 102:00 - 05:00 3.00 DR q '50PRDR Slide from 13,465' MD - 13,486' MD. 05:00 - 09:30 4.50' DR q 50PRDR Rotate from 13,486' MD - 13,580' MD. 09:30 10:30 1.00[ DR q 150PRDR Slide from 13,580' MD - 13,583' MD. 10:30 - 11:00 0.50 t DR q 50PRDR Rotate from 13,583' MD - 13,541' MD. 11:00- 13:00 2.00 DR q 50PRDR Slide from 13,591' MD - 13,597' MD. 13:00 - 13:30 0.50 DR q 50PRDR Rotate from 13,597' MD - 13,602' MD 13:30 - 16:00 2.50 DR q 50PRDR Slide fro m 13,602' MD - 13,613' MD 16:00 - 17:00 1.00 DR 'q 50PRDR Rotate from 13613' MD - 13620' MD. 17~:00 - 21:30 4.50 DRq 50PRDR ISlide from 13620' MD - 13642' MD. 21:30 - 23:00 , 1.50 DR q 50PRDR ;Rotate from 13642' MD - 13657' MD. , , Printed: 10/27/98 3:02:38 PM 'i.''.,. ". PHILLIPS PETROLEUM CO Page 10 of 22 .', .,.~ .,... ,,',¥..,~', :.~:i~';~, Operations Summary Report ~ .',:,"~,.: :' ?:' ,., Legal Well Name: NQRTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 : Sub ,Phase Date From - To Hours Co, Code Description of Operations 03/14/98 23:00 - 00:00 1.00 DR q 50PRDR Slide from 13657' MD - 13661' MD. 03/15/98 00:00 02:30 2.50 DR q 50PRDR Slide from 13,661' MD - 1:J,676' MD (15 ft). t02:30 - 03:00 0.50 DR q 50PRDR Rotate from 13,676' MD - 13,681' MD (5 ft). 103:00 - 07:30 4.50 DR q 50PRDR Slide from 13,681' MD - 13,704' MD (23 ft). 07:30 - 09:00 1.50 DR q 50PRDR connection.R°tate from 13,704' MD - 13,719' MD (15 ft). Took survey and made a 09:00 - 15:00 6.00 DR q 50PRDR Slide from 13,719' MD - 13,737' MD (18 ft). 15:00 16:00 1.00 DR q 50PRDR Rotate from 13737' MD- 13,745' MD (8 ft). 16:00 19:00 3.00 DR q 50PRDR Slide from13,745' MD -13,764' MD (19 ft). Survey@ 13,681'MD. t 19:00 - 20:00 1.00 DR q 50PRDR Rotate from 13,764' MD - 13,776' MD (12 ft). Survey @ 13,713' MD. 20:00 - 21:30 1.50 DR q 50PRDR Slide from 13,776' MD - 13,786' MD (10 ft). 21:30 - 00:00 2.50 DR q 50PRDR Rotate from 13786'MD - 13806' MD. 03/16/98 00:00 - 01:00 1.00 DR q 50PRDR Rotate from 13,806' MD - 13,817' MD (15 ft). 01:00 - 03:30 2.50 DR q 50PRDR Slide from 13,817' MD - 13,828' MD (11 ft). Noticed rubber pieces [ (possiblly from the mud motor) over the shakers. 03:30 - 04:30 1.00' DR Iq 50PRDR Rotate from 13,828' MD - 13,832' MD (4 ft). 04:30 - 12:00 7.50 DR q 50PRDR Slide from 13,832' MD - 13,864' MD (32 fi). 12:00 - 13:30 1.50 DR q 50PRDR Rotate from 13,864' MD - 13,877' MD (13 ft). 13:30 - 16:30 3.00 DR q 50PRDR Slide from 13,877' MD - 13,886° MD (9 ft). Survey @ 13,820' MD. Prepare to TOOH due to lost performance in mud motor. 16:30 - 21:30 5.00 DR 4 50PRDR Back reaming from 13,886' MD - 10,376' MD (9 5/8" csg shoe). 21:30 - 23:00 1.50 DR 4 50PRDR downCirculatekellyb°tt°mShose, up at casing shoe. Clean rig floor. Filled tdp tank. Blew ; 123:00 - 00:00 1.00 RM c 50PRDR Slip & cut drill line, mix dry job. 03/17/98 00:00- 00:30 0.50 DR 4 ,50PRDR Finish up pumping dry job. 00:30 - 05:00 4.50 DR 4 50PRDR I POOH, break bit, and stab blade protector. 05:00 - 11:00 6.00 DR 8 50PRDR :RU test joint. Pull wear bushing / install test plug. Test BOP's - Hydrill 250# / 3500#, Rams (pipe & blinds), Choke & Kill Valves (manual & HCR), Top Drive (2)IBOP, Floor Valves (IBOP & Dart), Choke Manifold 250# / 5000# (No. 5 valve on choke manifold leaked - changed out, retested 250# / 5000#). 11:00 - 13:00 2.00 DR 4 50PRDR L/D mud motor - P/U mud motor - Break off stand sleeve. Make up bit, adjust motor, test MWD. P/U HWDP. 13:00 - 19:00 6.001 DR 4 50PRDR Trip in hole to 13,808' MD.. 19:00 - 19:30 0.50 DR p 50PRDR Ream from 13,808' MD - 13,886' MD. 19:30 - 21:00 1.50 DR q 50PRDR Rotate from 13,886' MD - 13,911' MD (25 ft). 21:00 - 23:00 2.00i DR g 50PRDR Slide from 13,911' MD - 13,950' MD (39 ft). 23:00 - 00:00 1.00 DR q 50PRDR Rotate from 13950'MD - 13960'MD. 03/18/98 00:00 - 03:00 3.00 DR q 50PRDR Slide from 13,960' MD - 13,964' MD (4 ft). I Rotate from 13,964' MD - 13,966' MD (2 ft). F Slide from 13,966' MD - 13,984' MD (18 ft). !03:00 - 04:00 1.00 DR q 50PRDR Rotate from 13,984' MD - 14,003' MD (19 ft). Made connection. 04:00 - 06:30 2.50 DR q 50PRDR Slide from 14,003'.MD - 14,026' MD (23 ft). 06:30 - 00:00 17.50 DR Iq 50PRDR Rotate from 14,026' MD - 14,358' MD. (332'). 03/19/98 00:00 - 07:30 7.50 DR q 50PRDR ROTATE F/14,358'-T/14,490', 132' @17.6 FPHR. 07:30 - 09:00 , 1.50 DR q 50PRDR SLIDE DOWN F/14,490' - T/14,505, 15' @ 10 FPHR. 09:00 - 00:00 I 15.00i DR tq 50PRDR ROTATE F/14,505' - T/14833, 328' @ 21.9 FPHR. 03/20/98 00:00 - 07:00 7.00 DR q 50PRDR ROTARY DRILLING FROM 14,833' TO 14,982' MD - 11,933' TVD. 149 FT I I @ 21.3 FT/HR. .... Printed: 10/27/98 3:02:38 PM : -':;' PHILLIPS PETROLEUM CO Page 11 of 22 .. :?_ .... Operations Summary Report 'Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 ! From - To Hours Sub Co Phase Code Description of Operations Date I 03/20/98 07:00- 13:00 6.00 DR p 50PRDR BACKREAMING FROM 14,982' TO 10,376' ! MAX DRAG UP 320K AND DRAG DOWN 200K. 13:00- 15:00 2.00 DR 5 50PRDR 'ClRC BO'I-rOMS UP, CLEAN RIG FLOOR, FILL TRIP TANK, MIX AND ]PUMP SLUG. 15:00 - 16:00 1.00 DR 4 50PRDR PULL OUT OF HOLE TO 8,281' '16:00 - 16:30 0.50 RM m 50PRDR LOST POWER TO RIG - TROUBLE SHOOT AND REPAIR SAME. 16:30 - 19:00 2.50 RM rn 50PRDR REPAIR BROKEN AIR LINE ON DRUM CLUTCHES. 19:00 - 23:00 4.00 DR 4 50PRDR PULL OUT OF HOLE. 23:00 - 00:00 1.00 DR 2 50PRDR BREAK OFF BIT AND LAY DOWN MWD. INNER CUTTERS CHIPPED AND WORN, OUTER CUTTERS APPEAR OK, BIT IN GAGE, 3 INNER JETS PLUGGED. 03/21/98 00:00 - 00:30 0.50 DR 2 50PRDR I./D MWD & MOTOR - CLEAN RIG FLOOR 00:30 - 04:00 3.50~ DR 2 50PRDR P/U NEW BHA W/LWD LOGGING TOOLS 04:00 - 07:30 3.50 DR 4 50PRDR PU 69 JTS DRILL PIPE AND TI TO 3306.43' ~ 07:30 - 10:00 2.50 DR 4 50PRDR RIH TO 10,310', FILL PIPE AT 6762' & 10,310' ! 10:00 - 11:00 1.00 RM c 50PRDR SLIP AND CUT 126' DRILLING LINE. .~ 11:00 - 12:00 1.00 RM' 3 50PRDR SERVICE TOP DRIVE, CHECK SAVER SUB & CHNG PIPE HANDLER I DIES. 12:00 - 14:30 2.50 DR 4 50PRDR RIH F/10,310' TO 12,366'. LOST ALL ELECTRIC POWER ON PLATFORM. 14:30 - 17:30 3.00 DR p 50PRDR 'STARTED RIG GENERATORS AND BACKREAMED FROM 12,366' UP ITO CASING SHOE AT 10,376'. 17:30 - 19:30 2.00 WO 7 50PRDR MONITOR WELL WHILE PRODUCTION TROUBLESHOOTS ELECTRICAL SYSTEM. DISCONNECTED BACKUP SYSTEM (UPS) AND RESTABLISHED ELECTRICAL POWER. 19:30 - 00:00 4.50 DR ! p 50PRDR RIH F/10,376' TO T/10,564' STARTED REAMING IN HOLE T/11,617'. 03/22/98 00:00 - 08;00 8.00 DR , p 50PRDR REAM IN HOLE T/11,617'. .08:00 - 13:00 5.00 DR :z 50PRDR LOG W/LWD WHILE REAMING HOLE F/12,886'- 13,214'. '13:00 - 14:30 1.50 DR p 50PRDR REAM IN HOLE F/13,214'- T/13,424 i 14:30 - 15:30 1.00 DR p 50PRDR REAM THRU TIGHT SPOT F/13,424' - T/13,470' 2 TIMES. 15:30 ~ 19:00 3.50 DR p 50PRDR REAM F/13,470' o T/13,648'. 19:00 - 19:30 0.50 DR a 50PRDR WHILE REAMING IN HOLE TIGHT SPOT @ 13,648' PIPE STUCK. WORK PIPE FREE MOVING PIPE DOWNHOLE. UNABLE TO COME UP. 19:30 - 21:00 1.50 DR a 50PRDR ATTEMPT TO BACKREAM AND PULL F/13,677' - T/13,604'. BAOKREAM UNTIL TORQUE INCREASED AND STALLED TOP DRIVE. PULL TO 'MAX 400,000 LB (150,000 OVER STRING WT). PIPE COMES FREE EASY MOVING DOWNHOLE, BUT WILL NOT COME UP. ELECTED TO i CONTINUE REAMING / LOGGING DOWNHOLE DUE TO BATTERY LIFE OF LOGGING TOOL. 21:00 - 00:00 3.00 DR p 50PRDR REAM DOWN F/13,604' - T/13,721'. ! = TIGHT SPOTS: F/13,426' - T13,470', F/13,527' - T/13,532', F13,579' - I [ 13,581', F/13,648' - T13,604'. 03/23/98 100:00 - 07:30 7.50 DR D 50PRDR REAM F/13,721' - T/14,600'. i07:30 - 12:30 5.00 DR~ 50PRDR LOGGING WHILE REAMING IN HOLE F/14,600'- T/14,982'. 12:30 - 00:00 11.50 DR q '50PRDR ROTARY DRILL F/14,982' T/15,065' (83'). LOGGING WITH LWD. 03/24/98 00:00 - 22:30 22.50 DR q 50PRDR ROTARY DRILLING F/15,065' - T/15,255'. 22:30-23:00 0.50 DR q 50PRDR ANGLE DROPPING 3.9? /100'. UNSUCESSFULLY ATTEMPT TO SLIDE I i AT 15,255'. 23:00 - 00:00 1.00 DR q 50PRDR ;ROTARY DRILLING F/15,255' - T/15,258'. 03/25/98 00:00 - 00:30 0.50 DR iq 50PRDR !ROTARY DRILLING F/15258' TO 15271'. 13' @ 26.0 FPH. 00:30 - 01:00 0.50 RM13 50PRDR SERVICED RIG WHILE TAKING SURVEY. 01:00 - 08:30 7.50 DR q 50PRDR ROTARY DRILLING F/15271' TO 15400'. 129' @ 17.2 FPH. ,, Printed: 10/27/98 3:02:38 PM ..... PHILLIPS PETROLEUM CO Page-12 of 22 · ..... ...... Operations Summary Report Legal Well Name: NORTH CC)OK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date From - To Hours Sub Co Phase . Code. Description of Operations I · 08:30 10:00 1.50 3R 5 50PRDR WORK PIPE AND CIRC. BO'I-1'OMS UP. 03/25/98 10:00 ' 15:30 5.50 DR 4 50pRDR BACK-REAMING WHILE POOH F/15400' UP TO 13603'. MAX. DRAG I UP TO 13603' - 5 TO 10,000 W/TORQUE RUNNING @ 800 AMPS. 15:30 - 18:00 2.50 DR a 50PRDR PULLED INTO TIGHT SPOT @ 13603'. WORKED PIPE AND :CONTINUED TO BACK-REAM UP THRU TIGHT SPOT F/13603' UP TO 13406'. PULLED ON PIPR TO MAX. 400,000 # ( 150000# OVER ST. WT. I i), BACK-REAMING AND STALLING OUT TOP DRIVE W/1000-1100 I AMPS. PULLED THRU TIGHT SPOT @ 13406'. 18:00 - 21:30 3.50 DR 4 50PRDR CONTINUED BACK-REAMING AND POOH TO CASING SHOE @ 10376'. HAD NO EXCESS DRAG ABOVE 13406'. 21:30 - 23:30 2.00 DR 5 50PRDR CIRC. BO'I-['OMS UP @ 10376', FILLED TRIP TANK, AND PUMPED DRY JOB. 23:30 - 00:00 0.50 DR .4 50PRDR POOH TO CHANGE BHA. 03/26/98 00:00 - 04:00 4.00 DR i4 50PRDR TOOH F/SHOE 04:00- 05:00 1.00 DR 2 50PRDR REMOVE RADIOACTIVE SOURCE 05:00 - 06:00 1.00 DR 4 50PRDR LAY DOWN BHA 06:00 - 08:30 2.50 DR 8 50PRDR PULL WEAR BUSHING. SET TEST PLUG. TEST HYDRILL@250-3500 PSI. TEST TOP PIPE RAMS, HCR CHOKE, HCR KILL @250-5000 PSI. ~ TEST CHOKE MANUEL / KILL MANUAL @250-5000 PSI. TEST BOTTOM PIPE & BLINDS @250-5000 PSI. TEST TOP BOP & UPPER KELLY COCK @250-5000 PSI. 08:30 - 09:30 1.00 DR 8 50PRDR SET WEAR BUSHING LAY DOWN BOP TEST PLUG. 09:30 - 10:30 1.00 RM 3 50PRDR SERVICE TOP DRIVE. 10:30 - 12:00 1.50 FI 4 50PRDR PICK UP BHA. 112:00 - 14:00 2.00 FI 4 50PRDR ' PU BHA - CONCAVE MILL AND RIH WITH W/DC AND HWDP. 14:00 15:30 1.50 RM m 50PRDR REPAIR STOP BAR ON LINK TILT. 15:30 19:30 4.00 FI 4 50PRDR RIH T/10,301'. 19:30 - 20:30 1.00 RM c 50PRDR CUT DRILL LINE 92'. INSPECT DRAWWORKS BRAKES. : 20:30 - 23:00 2.50 FI 4 50PRDR RIH F/10,301' T/13,560'. 23:00 - 00:00 1.00 FI !4 50PRDR TIGHT SPOT AT 13,560'. WORK PIPE / MILL T/13,570'. 03/27/98 00:00 - 06:30 6.50 FI 4 50PRDR WASH F/13,570'T/15,400'. 06:30 - 12:00 5.50 DR h 50PRDR ROTATE MILL ON BOTTOM F/15,400' T/15,404'. ! 12:00 - 18:30 6.50 DR ~ p 50PRDR BACKREAM OUT OF HOLE F/15,404' T/10,376'. 18:30 - 19:30 1.00 DR 5 50PRDR CIRC BOTTOMS UP. PUMP DRY JOB. CLEAN RIG FLOOR. 119:30 - 00:00 4.50 DR 4 50PRDR POOH. L/D MILL & BIT SUB. 03/28/98 00:00 - 01:30 1.50 DR 2 50PRDR PICKING UP NEW BHA. 01:30 - 02:30 1.00 DR . 2 50PRDR PICKED UP MWD AND ORIENT DIRECTIONAL TOOLS. 02:30 - 03:00 0.50 RM 3 50PRDR SERVICED RIG AND REPLACE GAUGE ON TOP DRIVE. 03:00 - 08:30 5.50 DR 4 50PRDR TIH W/DIRECTIONAL ASSEMBLY TO 13400'. 08:30 - 10:00 1.50 DR 4 50PRDR ORIENT TOOL FACE TO HIGH SIDE AND TIH TO 13900'.' HAD NO EXCESS DRAG BETWEEN 13400' AND 13600'. DRAG ACTUALLY DECREASED 25M W/TOOL FACE TO HIGH SIDE. I10:00 - 00:00 14.00 DR d 50PRDR ROTATE & LOG F/14,110' T/15,404' - REAM OFF BOTTOM A COUPLE OF TIMES. 03/29/98 t00:00 - 00:30 0.50 DR q 50PRDR DIR DRLG UNDER ROTATION F/15,404' T/15,417'. 100:30 - 01:00 0.50 DR q 50PRDR DIR DRLG UNDER SLIDE F/15,417' T/15,434'. !01:00 - 01:30 0.051 DR ;q 50PRDR SURVEY ORIENT TOOLS, GREASE SWIVEL @CONN 15,434'. 01:30 - 12:00 10.50 DR q 50PRDR DIR DRLG UNDER ROTATION F/15,434' T/15,640'. SURVEY @ F/15,525' , ~ T/15619'. 12:00 - 00:00 12.00 DR q 50PRDR DIR DRLG UNDER ROTATION F/15,640' T/15,845' 03/30/98 00:00 - 00:00 24.00 DR q 50PRDR DIRECTIONAL DRILL BY ROTATION F/15,845' T/16,177' (332'). 03/31/98 00:00 - 00:00 24.00 DR q 50PRDR DIRECTIONALLY DRILL BY ROTATION F/16,171' T16,383' (212'). 04/01/98 . 00:00 - 00:00 24.00 DR q 50PRDR Drilling f/16383't/16602' = 219' (9fph) I i , Printed: 10/27/98 3:02:38 PM , PHILLIPS PETROLEUM CO Page 13 of 22 . . ..., . ..... .... Operations Summary Report Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date From - To Hours Sub Co Phase Code Description of Operations , . 04/02/98 !00:00 - 17:00 17.00 DR q 50PRDR Drilling f/16602' t/16720'= 118' ( 6.9 fph). ~ TD 8.5" hole @ 05:00pm AST @ 16720' t 17:00 - 00:00 7.00 DR p 50PRDR Backream out of the hole f/16720' t/13945'. Did not encounter tight spots while backreaming f/16720' t/13945'. 04/03/98 00:00 - 05:30 5.50 DR p 50PRDR BACKREAM FROM 13,945FTTO SHOE @ 10,376FT. 05:30 - 07:00 1.50 DR p 50PRDR CIRCULATE BU. PUMP PILL. RABBIT DRILLPIPE (2.625" DRIFT). 07:00 - 08:00 1.00 RM !m 50PRDR RIG REPAIR, REPLACE HI-LO CLUTCH CONTROL. ,08:00 - 14:00 6.00 DR 14 50PRDR TOH. L/D BHA. CLEAN RIG FLOOR. ~14:00 - 18:00 4.00 WC 8 50PRDR TEST BOPs, CHOKE, FLOOR VALVES, HCRs & IBOP 250/5000psi. TEST I ANNULAR PREVENTER 250/3500psi. 18:00 - 20:00 2.00 LG 8 !50PRDR HOLD PRE-JOB SAFETY MTG. PICK UP LOGGING TOOLS AND I I FUNCTION TEST WET CONNECT. LOAD RADIOACTIVE SOURCES. 20:00 ~ 00:00 4.00 LG x 50PRDR RIH PIPE-CONVEYED LOGS TO 6760'. 04/04/98 00:00 02:00 2.00 LG x 50PREV RIH WITH PIPE-CONVEYED LOGS. FILL PIPE @ 10,368FT. 02:00 - 03:30 1.50 LG x 50PREV RIG UP SIDE-ENTRY SUB @ SHOE 10,376FT. HOLD PRE-JOB SAFETY MTG. 03:30 - 05:30 2.00 LG x 50PREV RUN ELECTRIC LINE & WET CONNECT. 05:30 - 06:30 1.00 LG !x 50PREV STAB IN WET CONNECT. SET WIRE TENSION. 06:30 - 08:00 1.50 LG I x 50PREV RIH WITH LOGGING TOOLS TO 11,218FT. '08:00 - 09:00 1.00 LG z 50PREV TOOL FAILURE. A'I-FEMPT TO LOCATE PROBLEM. 09:00 - 10:00 1.00 LG z 50PREV ITOH TO SHOE. .,.,~.- 10:00 - 10:30 0.50 LG z 50PREV PULL WET SOCKET. RE-SET & RE-TEST INSTRUMENTS. CONFIRM TOOL FA LURE. 10:30 - 13:00 2.50 LG z 50PREV PULL WET CONNECT & ELECTRIC LINE. REMOVE SIDE-ENTRY SUB. CIRCULATE. 13:00 - 14:00 1.00 RM 3 50PREV SLIP & CUT 128FT DRILLING LINE. CIRCULATE & PUMP DRY JOB. 14:00 - 18:00 4.00 LG z 50PREV POQH. DOWNLOAD RADIOACTIVE SOURCES. 18:00 - 22:30 4.50: LG 7 50PREV INSPECT SCHLUMBERGER TOOLS, REMOVED : KNUCKLE JTS ON WET CONNECT SYSTEM. I CONNECT SCHLUMBERGER LOGGING UNIT TO RIG POWER SUPPLY , (SCHLUMBERGER UNABLE TO RESTART GENERATOR), 22:30 - 00:00 1.50 LG 2 50PREV ASSEMBLy.REASSEMBLYTEsTSCHLUMBERGERwET PIPE CONVEYED LOGGING CONNECT. GIH W/PIPE CONVEYED LOGGING ASSEMBLY TO 3265'. 04/05/98 00:00 - 01:30 1.50 LG x 50PREV !CONTINUE TIH W/LOGGING TOOLS 3265' - 6200' FILL DP @6200' 01:30 - 02:00 0.50 LG x 50PREV MOVE HWDP TO DRILLERS SIDE. 02:00 - 04:00 2.00 LG x 50PREV TIH TO CSG SHOE @10376' FILLED DP @9795' 104:00 - 06:30 2.50 LG x 50PREV PRE JOB SAFETY MEETING. RU SIDE ENTRY SIDE & TIH W/WET 06:30 ' CONNECT. -07:00 0.50 LG Ix 50PREV PUMP DOWN WET CONNECT & FUNCTION TEST TOOLS, OK. CLAMP , & PULL TEST WL. 107:00 - 13:30 6.50 LG ix 50PREV TIH LOGGING ON WAY IN HOLE. SCHLUMBERGER WL LOST LINE ! CONTINUNITY @ 16649' STOP TIH. CHECK LINE AT SURFACE. i 13:30 - 14:30 1.00 LG x 50PREV PU DP TO STRING WT @320 W/BLKS. NO MOVEMENT. SLACK OFF ' NO DOWN MOVEMENT. CON'T WORK PIPE SEVERAL TIMES t i ToWITHOUT MOVEMENT UP OR DOWN. EST CIRC & CON'T WORK PIPEMAx PULL 525K. 14:30 - 17:30 3.00 LG !z 50PREV CIRCULATING & WORKING PIPE, BG GAS INC FROM 85 UNITS TO i MAX 1200 UNITS. 17:30 - 18:30 1.00 LG tz 50PREV TRANSFER 30 BBL OF 8.6 PPG OIL BASE MUD FROM HOLDING TANK t TO SUCTION PIT. t18:30 - 19:30 1.00 LG t5 50PREV PUMP 30 BBL OF 8.6 PPG OIL BASE MUD DOWN DRILL STRING, / ! ., Printed: 10/27/98 3:02:3Ei PM PHILLIPS PETROLEUM CO Operations Summary Report Page 14 of 22 Legal W~il Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 04/05/98 O4/O6/98 04/07/98 NORTH COOK INLET UNIT-B North Cook Inlet Unit B-1 Sidetrack Unocal/Pool Rig From- To Hours Sub Co[Phase 18:30 - 19:30 1.00 LG 19:30 - 00:00 4.50 LG 00:00 - 07:30 07:30 - 21:00 21:00 - 22:00 22:00 - 00:00 00:00 - 05:00 1.50 LG /i 4.00 / LG 05:00 - 05:30 05:30 - 06:30 06:30 - 13:00 3:00 - 16:00 16:00 - 16:30 16:30 - 18:00 18:00 - 22:00 Code 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREY 50PREV 50PREV 000001 Start: 02/05/98 Rig Release: 10/21/97 Rig Number: 428 Spud Date: 07/31/97 End: Group: Description of Operations DISPLACE W/258 BBL OF 14.5 PPG MUD. LEFT 15 BBL OF 8.6 OIL BASE INSIDE DRILL STRING & 15 BBL 8.6 PPG OIL BASE MUD IN 5"x8.5" ANNULUS. WORK STUCK DRILL PIPE F/-50k T/450k IN A"FrEMPT TO FREE PIPE. PUMPING 0.5 BBL OF 14.6 PPG MUD IN 3'0 MIN. INTERVALS TO DISPLACE THE 8.6 PPG OIL BASE MUD INTO THE 5"x8.5" ANNULUS. ~.T REPORT TIME THERE IS 10.5 BBL OF 8.6 PPG OIL BASE MUD LEFT INSIDE THE DRILL STRING. LEAVING 19.5 BBL OF 8.6 PPG OIL BASE MUD IN THE 5"x8.5" ANNULUS. NO MOVEMENT OF THE DRILL STRING, UP OR DOWN. 'CONTINUE TO PUMP 0.5 BBL STAGES OF 14.6 PPG OBM IN 30 MIN INTERVALS UNTIL ALL 30 BBL OF 8.6 PPG OIL BASE MUD WAS i PUMPED INTO THE 5" x 8.5" ANNULUS. WORKED THE STUCK DRILL PIPE STRING F/ -50k T/450k IN ATTEMPT TO WORK STUCK DRILL PIPE FREE. NO FREE MOVEMENT UP OR DOWN. (UNABLE TO ROTATE DUE TO WlRELINE IN ANNULUS F/SURF'ACE TO SIDE ENTRY SUB @ 6278') ClRC & COND MUD. PUMP 33 BBL OF 6.9 PPG DIESEL, DISPLACED DIESEL W/371 BBL OF 14.6 PPG OBM. SPOTTED 6.9 PPG DIESEL ACROSS SUNFISH FORMATION 14850'MD, 11879' TVD. (ASSUMING 8.5" GAUGEB HOLE) WORK STUCK DRILL PIPE F/-50K T/450k. NO FREE MOVEMENT UP OR DOWN. DRILL STRING W/LOGGING TOOLS AS FOLLOWS TOP TO BTM: 5358.90' - 171 JTS 5" D.P. 919.45'- 30 JTS 5" HWDP. 6.15'- 7" OD SIDE ENTRY SUB W/2" ID. 10308.92' - 330 JTS 5" D.P. 3.00' - X-OVER W/ClRC PORTS 53.50'- SCH. PIPE CONVEYED LOGS. 16649.92' WORK STUCK PIPE AT 10 MINUTE INTERVALS - FROM 150K UP TO 450K DOWN, 175K UP/300K DOWN, 175K UP/325K DOWN, 175K UP/350K DOWN, 175K UP/375K DOWN, 175K UP/400K DOWN, 175K UP/425K DOWN, 175K UP/450K DOWN. PRE-JOB SAFETY MTG. PULLED 11 K+ WITH SCHLUM. UNIT BUT UNABLE TO PULL CABLE FREE FROM SIDE-ENTRY SUB PACK-OFF. R/U T-BAR TO WlRELINE. PULL W/LINE FROM 16,345FT TO 16,240FT WITH 12K OVERPULL. HELD PRE-JOB SAFETY MTG. CHECK SHEAVES. PULL W/LINE FROM 16,240FT TO 6,202FT WITH SOHLUM. UNIT R/U T-BAR TO W/LINE. PULL 12K WITH BLOCKS AND PULL W/LINE FREE FROM WET CONNECT ROPE SOCKET. POOH W/LINE TO SURFACE WITH SCHLUM. UNIT. RIG DOWN SCHLUM. BREAK CIRCULATION. UNABLE TO ROTATE PIPE. HOLD TORQUE IN STRING. RETURN MUD WT. 13.9PPG. SHUT DOWN, WEIGHT UP MUD TO 14.6PPG. CONTINUE CIRCULATING. (RECOVERED 130 BBL OF Printed: 10/27/98 3:02:3~ PM , PHILLIPS PETROLEUM CO Page 15 of 22 .... .. Operations Summary Report Legal Well Name: NORTH COOK INLET UNIT-B 000001 ~Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date From - To I Hours Sub Co Phase Code . Description of Operations II ' 04/07/98 18:00 - 22:00 4.00 LG z 50PREV 13.9 PPG OBM) 22:00 - 00:00 2.00 LG 'z 50PREV RU ALASKA PIPE RECOVERY SERVICE, HELD SAFETY MEETING. GIH z W/SINKER BARS & CCL ON 0.3125" OD WlRELINE. 04/08/98 00:00 - 00:30 0.50 LG 50PREV RIH WITH APRS - 1.80" STAR BIT, JARS, SINKER BAR. TOOL STRING SET DOWN @ 6261FT. 00:30 - 01:30 1.00 LG I z 50PREV POOH WITH APRS. L./D SIDE ENTRY SUB. 01:30 - 03:00 1.50 LG z 50PREV CIRCULATE - 85 SPM/1850 PSI, 106 SPM/2500 PSI, 117 SPM/3000 PSI. 03:00 - 05:00 2.00 LG z 50PREV R/U SIDE ENTRY SUB. RIH WITH APRS - 0.5" - 1.56" TAPERED TORPEDO PUNCH. TOOLSET DOWN @ 6,261FT (WLM). POOH. L/D SIDE-ENTRY SUB. TOOL HAD FLARED ON END OF TAPER. 05:00 - 16:00 11.00 LG z 50PREV CIRCULATE & CONDITION MUD WHILE WAITING ON SLICKLINE . EQUIPMENT/CREW. ' 16:00 - 20:00 4.00 LG z 50PREV ]OFFLOAD WORKBOAT. RIG UP HALLIBURTON SLICKLINE. TEST 20:00 LUBRICATOR 1000#, OK. - 22:00 2.00 LG z 50PREV RIH WITH SLICKLINE - 1.74" LIB, SPANG JARS, OIL JARS & SINKER BARS. TOOL STRING SET DOWN @ 6327FT (SLM). JAR DOWN WITH IMPRESSION BLOCK, POOH. NO DEFINITIVE MARKS ON IMPRESSION I BLOCK. 22:00 - 00:00 2.00 LG z 50PREV MU 1.50" OD TAPERED TORPEDO PUNCH ON SLICK LINE TOOL STRING. RIH & SET DOWN @ 6327 FT (SLM). 04/09/98 00:00 - 01:30 1.50 LG z 50PREV POOH WITH HALLIBURTON SLICKLINE 1.5" GAUGE BAR; ' 01:30 - 04:00 2.50 LG I z 50PREV RIH WITH SLICKLINE 1.0" O.D. GAUGE BAR, UNABLE TO PASS z SIDE-ENTRY SUB. POOH. 04:00 - 05:00 1.00 LG 50PREV R/D SLICKLINE. 05:00 - 07:00 2.00 LG i5 50PREV CIRC & CONDITION MUD. 07:00 - 12:30 5.50 FI q 50PREV R/U ALASKA PIPE RECOVERY SERVICES. RIH WITH STRING SHOT. BACK OFF @ 6,261FT (WLM). POOH. RIG DOWN APRS SIDE-ENTRY SUB. 12:30 - 15:00 2.50 FI y 50PREV POOH FROM 6,278FT AND L/D 1 HWDP (SHOT JT). 15:00 - 19:00 4.00 FI 2 50PREV P/U BAKER OVERSHOT TOOLS - 8.3/8" SHOE, 8.1/8" EXTENSION, ! 8.1/8" O/SHOT BUSHING, 8.1/8" O/SHOT BOWL, 8.1/8" TOP EXT., 4.1/2" I.F. TOP SUB, 4.1/2 I.F. BUMPER SUB, OIL JARS, 4.1/2" I.F. x 4.1/2" H90 ; X-OVER, 6.1/4" DCs, 4.1/2" H90 X 4.1/2" I.F. X-OVER, HWDP. WAIT ON X-OVERS. 19:00 - 19:30 0.50 RM m 50PREV ~INSTALL LINK TILT ON TOP DRIVE. 19:30 - 00:00 4.50 FI 4 50PREV MU XO EXTENSION & TOP SUB. TIH SLOW MUD RUNNING OVER. SPOT WEIGHTED PILL INSIDE DRILL STRING & FINISH TIH TO 6267'. I BREAK CIRC ON TOP OF FISH. 04/10/98 00:00 - 06:00 6.00 FI d 50PREV TAG FISH @ 6285FT. MILL OVER FISH TO 6,292FT (CUT OD OF SIDE ENTRY SUB, XO SUB & DP TOOL JT DOWN TO 5 1/2") 06:00 - 07:00 1.00 FI 5 50PREV CIRC. BOTTOMS UP. 07:00 - 07:30 0.50 FI x 50PREV LATCH FISH AND BACK OFF. 07:30 - 08:00 0.50 FI 5 50PREV PUMP DRY JOB. FILL TRIP TANK. 108:00-12:00 4.00 FI y 50PREV POOH. RECOVEREDO.65FTOFFISH-1X4.1/2"IFBOXxPINISUB&2 I ! PIECES ( 4"x 2"+ 3" X 1.1/2" ) BROKEN OFF FACE OF WASHOVER I i SHOE. 12:00- 15:00 3.00 WC 8 50PREV TESTED BOPE- RAMS, HCRs, CHOKE, FLOOR VALVES & IBOP , 250/5000PSI. TESTED HYDRIL 250/3500PSI. 15:00 - 18:30 3.50 FI 14 50PREV. TIH W/OVERSHOT ASSY (SLOW-PIPE RUNNING OVER). 18:30 19:30 1.00 FI x 50PREV LATCH ONTO FISH & BACKED OFF. 19:30 - 22:00 2.50 FI 14 50PREV POOHW/DP, 29JTSHWT&41/21FBX41/2 ! H-90 P XO SUB. LEFT DC'S & OVER SHOT FISHING ASSY IN HOLE I (120.2'). Printed: 10/27/98 3:02:3~ PM PHILLIPS PETROLEUM CO Page 16 of 22 · . Operations Summary Report ,,, Legal Well Name: NORTH COOK INLET UNIT-B 00000'[ Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date ! From - To I Hours Sub Co Phase Code Description of Operations 04/10/98 22:00 - 23:00 1.001 FI 7 50PREV CLEAN RIG FLOOR. RE-DRESS PIN END THREADS ON XO SUB. t23:00 - 00:00 1.00 FI 4 50PREV TIH W/XO SUB BELOW 5" HWDP. PLAN TO SCREW INTO FISH, · ={ELEASE OVERSHOT & POOH W/O/SHOT ASSY THEN TIH W/ OUT-SIDE CUTTER & CUT DP TUBE IN JT BELOW SIDE ENTRY SUB. 04/11/98 00:00 - 01:00 1.00 FI 4 50PREV TIH W/XO SUB ON HWDP TO 6166'. 01:00 - 01:30 0.50 FI y 50PREV SCREW INTO FISH. WORK & RELEASE OVERSHOT FR/FISH. ; 01:30 - 02:00 0.50 FI 5 50PREV MIX & PUMP DRY JOB. FILL TRIP TANK. 02:00 - 05:00 3.00 FI 4 50PREV POOH (RECOVERED O/SHOT ASSY). 05:00 - 06:00 1.00 FI 2 50PREV LD CUT LIP GUIDE & OVERSHOT. PU OUTSIDE CUTTER & WP EXTENSIONS. 06:00 - 11:00 5.00 FI 4 50PREV TIH W/OUTSIDE CUTTER ASSY (TRIP SLOWLY PIPE RUNNING OVER). 11:00 - 12:00 1.00 FI x 50PREV BROKE ClRC &WORKED OVER FISH @ 6286'. 12:00- 15:30 3.50 FI 4 50PREV 3CCH W/CUTOFF ASSY& FISH. 15:30- 17:00 1.50 FI 2 50PREV LD SIDE ENTRY SUB, CUTOFF, & OUTSIDE CUTTER (8' OFFISH ) TOF 6294'. PU OVERSHOT ASSY. 17:00 - 21:00 4.00 FI 4 50PREV TIH W/OVERSHOT. 21:00 - 21:30 0.50 FI 2 50PREV PU 16JTS 578 ft 5" DP. 21:30 - 22:00 0.50 FI z 50PREV LATCH ONTO FISH W/OVERSHOT. 22:00 - 00:00 2.00 FI 5 50PREV CIRCULATE & CONDITION MUD. 04/12/98 00:00 - 13:00 13.00 WO t 50PREV CIRCULATE & CONDITION MUD WHILE WAITING ON PROCEDURE. 13:00 - 14:00 1.00 LG 6 50PREV R/U APRS W/LINE & SIDE-ENTRY SUB. 14:00 - 16:30 2.50 LG 1 50PREV RIH WITH 2.94" GAUGE RING, 1.7/16" CCL, JARS, 20FT x 1.11/16" WEIGHT BAR TO 16,530FT (WLM) NOTE: PUMPED IN HOLE FROM 14,300FT TO 16,530FT. ' 16:30 - 18:30 2.00 LG 1 50PREV POOH WITH W/LINE. '18:30 - . 50PREV CIRCULATE & CONDITION MUD WHILE WAITING ON PROCEDURE. 04/13/98 00:00 - 12:00 12.00 WO t 50PREV CIRC. AND COND. MUD, WAITING ON LINER HANGER AND TOOLS FROM BAKER. 12:00 - 18:30 6.50 CE 5 50PRRC CONTINUE CIRC. AND COND. MUD. MIXED PRE-FLUSH AND PREP. TO CMT. 5" DP. 18:30 - 20:00 1.50 CE 6 50PRRC RIGGED UP CONTROL HEAD AND LOADED WIPER PLUGS. RIGGED ! UP LINES TO CONTROL HEAD. 20:00 - 23:00 3.00 CE 1 50PRRC TESTED PUMP AND LINES TO 2500 PSI, OK. CEMENTED 5" DRILL PIPE AS FOLLOWS: PUMPED 10 BBLS OF DIESEL SPACER, PUMPED 10 BBLS OF 15.0 PPG FLOZAN SPACER. MIXED AND PUMPED 700 SX OF HALLIBURTON CLASS G CEMENT W/.13 GPS 344-L ( WATER LOSS ADDITIVE) + .3% CFR-3 (FRICTION REDUCER) + .27% HR-5 I ~ (RETARDER). MIXED CEMENT @ 15.6 PPG W/YIELD 1.18 CU. FT./SK. :MIXED AND PUMPED CEMENT @ 3.5 BPM AVG. RATE W/1000 PSI MAX. PRESS. RELEASED WIPER PLUG, PUMPED 1 BBL OF CEMENT, ~ AND RELEASED 2nd WIPER PLUG. DISPLACED CEMENT W/290 BBLS ! OF 14.6 PPG OBM @ 5.0 BPM W/1650 PSI MAX. PRESS. (CALC. 282 I, BBLS) DID NOT BUMP PLUG. OVERDISPLACED CEMENT 8 BBLS. I SHUT DOWN PUMP W/350 PSI LEFT ON DP. SET CEMENT PLUG I I FROM 16,593' UP TO 14,000' (1000' ABOVE SUNFISH FORM.). 23:00 - 00:00 1.001WO j 50PRRC WAITING ON CEMENT TO CURE. WILL WAIT ON CMT F/12 HRS. 04/14/98 00:00 - 11:00 11.00 WO I j 50PRRC WAITING ON CEMENT 11:00 12:00 1.00 CE16 50PRRC BLEED OFF PRESSURE. R/D CEMENT HEAD 12:00 - 13:00 1.001 FI t6 50PRRC R/U APRS W/LINE. HELD PRE-JOB SAFETY MTG 13:00 - 14:00 1.00! FI iq 50PRRC RIH W/LINE CCL & STRING SHOT TO 10,115FT. APPLY DOWNHOLE TORQUE. FIRE BACK-OFF CHARGE. , Printed: 10/27/98 3:02:3B PM .,. PHILLIPS PETROLEUM CO Page 17 of 22 Operations Summa Report · ~..'? .., '. ,' i , ~ .'.,. Legal Well Name: NORTH COOK INLET UNIT-B 00000-1 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 ~ I Phase Date From - To Hours Sub Co Code Description of Operations t 50PRRC '04/14/98 i 14:00 - 14:30 0.50 FI x BACK OFF DRILL PIPE. ' I 114:30 - 16:00 I 1.50 FI 6 50PRRC POOH W/LINE AND RIG DOWN APRS. i16:00 - 20:30I 4.50 FI y 50PRRC PUMP DRY JOB. POOH WITH DRILL PIPE TO 3,~00FT (OVERSHOT I PACK-OFF IN GOOD SHAPE. OBSERVED TRACE OF CEMENT IN I 'UPPER EXTENSION). RELEASE O/SHOT. L/D FISHING TOOLS. 20:30 - 22:00 1.50 =~M c 50PRRC SLIP & CUT DRILLING LINE (FI'). 22:00 - 00:00 2.00 FI y 50PRRC POOH WITH DRILL PIPE. TOP OF REMAINING DP @ 10,115FT (WLM). 04/15/98 00:00 - 00:30 I 0.50 FI 4 50PRRC FINISHED POOH W/REMAINDER OF 5" DRILL PIPE AFTER LAYING ii DOWN OVERSHOT ASSEMBLY AND CUTTING DRILL LINE. 00:30 - 01:00 0.50 FI 2 50PRRC LAYED DOWN BOTTOM JT. OF DRILL PIPE (SHOT JOINT). CLEANED UP RIG FLOOR. 101:00 - 01:30 0.50 CS :9 50PRRC PICKED UP HALLIBURTON RTTS TOOL AND BY-PASS SUB FOR 9-5/8" 01 CASING. :30 - 07:00 5.50 CS 9 50PRRC TIH W/RTTS TOOL TO 10013'. 107:00 - 09:30 2.50 CS 9 50PRRC FILLED PIPE AND BROKE CIRC. PICKED UP TO 10000.02' AND SET i R'I-r's TOOL. PRESSURED UP W/HALLIBURTON TO 5000 PSI AND I 'TESTED 9-5/8" CASING FOR 30 MIN., OK. BLED OFF PRESSURE AND ! PUMPED DRY JOB. !09:30 o 13:30 4.00 CS 9 5.0PRRC POOH W/HALLIBURTON RTTS TOOL. 13:30 - 14:00 0.50 CS 9 50PRRC LAYED DOWN R'IFS TOOL AND BY-PASS SUB. 14:00 15:00 I 1.00 RM 3 50PRRC SERVICED RIG. 15:00 16:00i 1.00 CS 1 50PRRC PICKED UP SKIRTED SCREW IN SUB W/ 4-1/2" IF PIN & O-RING SEAL- 3.75'; PICKED UP BAKER LINER HANGER ASSEMBLY W/80-40 SEAL BORE EXTENSION- 18.85'; XO SUB- 7" TKC BUTT. PIN X 4-3/4" STUB ACME BOX- 1.85; FLEX LOCK LINER HANGER- 7" TKC BUTT. PIN X PIN W/TKC COUPLING DOWN- 18.13'; ZXP LINER TOP PACKER W/HOLD DOWN SLIPS- 19.51' TOTAL LENGTH OF LINER HANGER ASSEMBLY TO O-RING SEAL- 60.44'. 16:00 - 00:00 8.00 CS 1 50PRRC TIH W/BAKER LINER HANGER AND LINER TOP PACKER ASSEMBLY ON 5" S-135 DRILL PIPE. 04/16/98 00:00 - 04:00 4.00 CS 1 50PRRC TIH w/packer assy. to 10,069 ft. 04:00- 10:30 6.50 CS 1 50PRRC Wait on orders from PPCo. 10:30 - 12:00 1.50 CS 1 50PRRC Tag fish at 10,134' w/5000# DN WT. Screw into fish w/10 turns into pipe (15,000 fi-lbs torq.). (NOTE: UP WT = 225K & DN WT = 190K) .(1) Pull 50,000# over UP WT. ~ (2) Set DN to 205K, press, up to 500psi, bleed off press. ~ (3) Pull up to 275K, press, up to 2000psi, set DN to 150K, bleed off press. (4) Pull up to 230K, set DN to 150K, press, up to 2000psi, bleed off same. (5) Pull up 240K, set DN to 100K, press, up to 2100psi, bleed off same. [ Top of linedpacker @ 10,074' MD. i Attempt to release HR running tool, press, up to 1500# - bleed off same, I press, up to 2000# - bleed off same~ press, up to 2100#, bleed off same, i press, up to 2200#, bleed off same. HR running tool did not release. 112:00 - 13:30 1.50 CS 1 50PRRC Drop ball. Wait on ball to fall. i 13:30 - 14:00 0.50 CS 1 50PRRC Work pipe 190K - 240K / Press. from 2100# - 2500# / 3 wraps to the left ! ~ (8000 fi-lbs torq.) work pipe to 220K. Pull loose from liner/packer. 14:00 - 15:00 1.00 CS 1 50PRRC Set 150K DN on packer. Tested screw-in sub to 2200#. Pulled dog sub above liner packer. Set down 175K and set liner packer. 15:00 - 18:30 3.50 CS I 50PRRC Pulled seals out of liner hanger, pumped 2 drill pipe capacities. Stung back . into liner hanger with seals, press, up on annulus to 2200# and held of 30 I min. Tested good. 18:30 - 22:00 3.50 CS,1 50PRRC , Pumped dry job. TOOH w/drill pipe and running tool. Printed: 10/27/98 3:02:3B PM PHILLIPS PETROLEUM CO Page t8 of 22 Operations Summary Report :Legal Well Name: NORTH COOK INLET UNIT-B 0000131 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 " Co Phase Date ! From - To Hours Sub Code' Description of Operations I , 04/16/98 i. 22:00 - 22:30 0.50 CS 11 50PRRC Laydown Hgr. ~nning tools. ~22:30 00:00 1.50 CS ~ 1 50PRRC Pick up B.O.P. Test Jts. AND R/U TO TEST BOPE. I ' TOP OF 5" FISH & SCREW IN SUB @ 10132.32'. DRILL PIPE LEFT IN , HOLE; 206 JTS @ 6449.01' PLUS LOGGING TOOLS. : 04/17/98 i00:00 - 04:00 4.00 CM 8 80CMPL Test BOP's RAMs, HCR's / Manuals, choke manifold floor valves, top drive , to 250 psi Iow / 5000 psi high. Tested hydril to 250 psi Iow / 3500 psi high. 'I i Accum test, install wear bushing R/D test its. 104:00 - 05:30 1.50 RM 3 80CMPL !Service top drive. Clean dg floor. 05:30 - 07:30 2.00 CM 4 80CMPL P/U BHA, R/U tongs, slips, elevators, for 1 1/4" D.P.. Held pre-job safety ~ meeting. 07:30 - 12:00 4.50 CM 4 80CMPL P/U (1774') 1 1/4", 3.02 ppf, N-80 CS Hydril D.P.. TIH. Flushing D.P., as ~ required, prior to TIH in an attempt to reduce rust build-up in motor / BHA. i Break circulation @ 1.6 BPM / 2900#. ~ 12:00 - 18:30 6.50 CM 4 80CMPL P/U (4768') 2 1/16", 3.25 ppf, N-80 CS Hydril D.P.. TIH. Flushing D.P., as required, prior to TIH in an attempt to reduce rust build-up in motor / BHA. r Break circulation @ 1.2 BPM / 3800#. BHA @ 6542' MD. P/U PBL bypass system and 2 1/16" CS Hydril X 5" DP X-over sub. ,18:30 - 22:00 3.50 CM 80CMPL Kelly-up. Circulate and test / actuate PBL bypass sub. Dropped & pumped i 4 vinyl ball at 3000# @ 1.0 BPM to open side sleeve. Dropped & pumped i steel ball at 4200# 3.5 BPM to close side sleeve and shear vinyl ball into I ball catcher. Pull 1 stand DP and brake lower PBL ball catcher sub. Retdeve both balls. Make-up connection.. 22:00 - 00:00 I 2.00 CM 4 80CMPL GIH with 5" DP. 04/18/98 !00:00-01:00I 1.00 CM 4 80CMPL TIH W/1-1/4" & 2-1/16" TUBING ON 5"19.5# DRILL PIPE TO10002'. !01:00 - 02:00 ~ 1.00 CM d 80CMPL STARTED PUMPING @ 1 BPM W/3100 PSI AND WASHED DOWN 71' ~ TO TOP OF LINER @ 10074', MILL WENT INTO TOP OF LINER W/NO i PROBLEM. 02:00 - 12:30 10.50 CM d 80CMPL WASHING THRU 5" DRILL PIPE W/3-1/4" MILL ON BAKER 2-1/16" MOTOR TO 12,253'. TAG HIT OBSTRUCTION CAUSING INCREASE IN DIFFERENTIAL PRESSURE. 12:30 - 17:00 4.50 CM 4 80CMPL !TOOH PULLING WET 5" DRILLPIPE. !17:00 00:00 7.00 CM 4 80CMPL RU 2 1/16" TOOLS. POOH LD 120 JTS 2 1/16". 04/19/98 00:00 - 04:30 4.50 CM 4 80CMPL TOOH, L/D 2 1/16" TBG, 1 1/4" TBG, MOTOR, AND.MILL. NOTE: MILL CORED OUT BY WHAT APPEARS TO BE JUNK. 04:30 - 11:00 6.50 CM 7 80CMPL CLEAN RIG FLOOR & BEAVER SLIDE WALK WAYS. WAIT O1'4 BAKER METAL MUNCHER MILL / X-OVERS. 11:00 - 12:00 1.00 CM 4 80CMPL M/U BHA AND 3 JTS OF 1 1/4" DP. 12:00,14:00 I 2.00 CM 4 80CMPL TEST 2 7/8" MOTOR; 2000PSI @ 14 SPM (1.20 BPM). P/U 1 1/4" DP, , TIH FILLING PIPE. 114:00- 14:30 I 0.50 OM 14 80CMPL TEST MOTOR WITH 55 JTS OF 1 1/4" DP IN THE HOLE; 2050PSI @ 14 ! 4 SPM (1.20 BPM). !14:30 - 19:30 5.00 OM 80CMPL PU 2 1/16" DP, TIH FILLING PIPE. :~19:30-21:00 1.50 OM 14 80CMPL PUMP TESTED MOTOR W/ 55 JTS OF 1 1/4"& 153JTSOF2 1/16" @ r 6548' MD (14 SPM / 50 GPM / 3350#, 17 SPM / 60 GPM / 3800#). 21:00 - 00:00 3.00 CM 4 80CMPL TIH W/1-1/4" & 2-1/1'6" TUBING ON 5" DRILL PIPE TO TOP OF LINER , I @ 10074'. 04/20/98 00:00 - 02:00 2.00. CM 4 80CMPL RIH, BREAK CIRCULATION @ 10,040'/12,165'. 02:00 - 08:00 I 6.00 CM 14 80CMPL REAM W/MOTOR FROM 12,169' - 13,546'. MILL SPOT @ 12,252'. TAG ! AND WORK PIPE THRU @ 13,221'/13,484' / 13,546'. I 08:00- 09:30 I 1.50 OM I4 WORK THROUGH 13,546' - 13,570' TIGHT SPOT TO MAKE WORKING THROUGH SMOOTHLY. TIGHT SPOT VARIED IN POSITION i I Printed: 10/27/98 3:02:38 PM ': PHILLIPS PETROLEUM CO Page 19 of 22 :.,.: .... Operations Summary Report , Legal Well Name: NORTH COOK INLET UNIT-B 00000.1 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 Date From - To Hours Sub Co Phase Code Description of Operations 04/20/98 108:00 - 09:30 1.50 CM 4 80CMPL ON EACH PiPE MOVEMENT SEQUENCE -- +4', +5', -2', +3', ETC. FROM ~ 1ST TAG POINT. THERE WAS NO NOTICEABLE DRAG ON UPWARD I MOTION BUT UNTIL SMOOTH OUT THERE WAS CONSIDERABLE I ~ INCREASE IN DIFFERENTIAL PRESS. (400-500#) AND SET DOWN I WEIGHT FOR SLIM HOLE DP +/- 10,000 LBS). 109:30 - 16:30 7.00 CM 4 180CMPL REAM W/MOTOR FROM 13,546'- 13,899' TAG UP ON JUNK @ 13,899'. WORK JUNK DOWNHOLE AND CONTINUE REAMING W/MOTOR TO 14427', TAGGED JUNK. 16:30 o 20:00 ! 3.50 CM h 80CMPL MILLING ON JUNK IN HOLE @ 14427'. MOTOR ACTING OK, BUT MILL I IS NOT DRILLING W/200-300 PSI DIFFERENTIAL. MILL SEEMS WORN. 20:00 - 22:00 2.00 CM 5 80CMPL CIRC. B/U FROM JUNK MILL UP TO PBL SUB. 22:00 - 00:00 2.00 CM 5 80CMPL SHUT DOWN PUMP AND BLEED OFF PRESSURE, DROPPED PLASTIC I OPENING BALL TO OPEN PORTS ON PBL SUB. PUMP BALL TO PBL i I SUB @ 1.7 BPM W/3900 PSI. PUMPED 2200 STROKES, PBL SUB DID , NOT OPEN. PREPARE TO DROP STEEL EMERGENCY BALL TO OPEN I PBL TOOL. 04/21/98 00:00 - 00:30 0,50 OM 4 80CMPL Dropped red emergency ball and pumped 359 stks and PBL tool opened. 00:30 02:00 1.50 CM 5 i80CMPL Circulated bttm's up w/4400 stks @ 83 spm (7 bpm) / 3000 psi. 02:00 - 02:30 0.50 CM 4 80CMPL Pumped dry job and started to POOH. 02:30 - 05:30 3.00 FI z 80CMPL Pulled to 14,088' and worked thru tight spot w/max, pull 15-20,000#. I Continue to POOH to 14,057'. Pulled into tight spot @ 14,057'. Max. pull : so far 35,000#. Have tried pumping but circ. is thru PBL (NOTE: Once the red ball is dropped - PBL cannot be closed). Have tried 1-2 rounds torque & working pipe. Still will not come past 14,057'. Seems like a piece junk of I ~s above mill. Pipe goes down hole O.K. (+/- 60 ft). Pulled 40,000#, ; ~ncrease P/U wt to 45,000#. Pulled pipe 2 times at 45,000#. Third time pipe parted. Lost +/- 10,000# on wt. indicator. t05:30 - 09:30 4.00 FI 4 80CMPL POOH to PBL sub. 109:30 - 10:30 1.00 Ft 4 80CMPL Recover 2 balls (vinyl & steel) from top of PBL sub. 10:30 - 11:00 0.50 FI 4 80CMPL R/U to L/D 2 1/16" DP equipment. 11:00 - 13:00 : 2.00 FI 4 80CMPL LJD 2 1/16" DP, total recovered 763.90' - fish remaining as follows: i 2 1/16" DP ---4004.36' X-over --- 0.69' I 1 1/4" DP --o 1757.35' I BHA --- 16.29' TOTAL FISH --- 5,778.69' Estimated top of fish at 8,278.31' if fish did not fall to Mill drilling TD of 14,427' (370' diff.). Fish top was the parted body of 2 1/16" DP (20.19'). I' Appeared to be a clean brake with some pinch down at and near parting i' ipoint' 113:00 - 17:00 4.00 we u 80CMPL Waiting on fishing tools for slimhole pipe inside large O.D. pipe (Sling lifted i to rig). 17:00 - 17:30 0.50 Fi 2 80CMPL M/U over shot. 117:30 - 18:30 1.00 WO u 80CMPL Waiting on shock-sub / bumper (Sling lifted to rig). 18:30 - 00:00 5.50 FI 4 80CMPL TIH w/over shot fishing assembly. d 80CMPL Wash to top of fish @ 8648' -- fish has dropped to bottom. ,04/22/98 00:00- 01:00 I 1.00 FI 01:00 - 04:00 t 3.00 FI id 80CMPL Engage overshot w/fish. Pump press, increase inc. from 500psi to I !1500psi. POOH to 14,021' Pulled into tight spot. Max. pull 25,000# work I pipe, attemptin~ to circulate thru fish. Pumping @ 12 SPM (1.02 BPM) w/ I 2500psi. Pack-off in overshot holding @ 2500 psi. Continue working pipe i w/max, pull @ 35,000# over string wt. Mill does not move higher than ! 14,021'. Continued working pipe & pulling to max. 35,000#, grapple Printed: 10/27/98 3:02:38 PM PHILLIPS PETROLEUM CO Page 20 of 22 Operations Surnrna Report · , Legal Well Name: NORTH COOK INLET UNIT-B 000001 Common Well Name: North Cook Inlet Unit B-1 Spud Date: 07/31/97 Event Name: Sidetrack . Start: 02/05/98 End: Contractor Name: Unocal/Pool Rig Rig Release: 10/21/97 Group: Rig Name: Rig Number: 428 To I Hours Sub Co Phase Code Description of Date From Operations I i , 04/22/98 i01:00 - 04:00 3.00 FI d '80CMPL slipped off of fish. Went down & caught fish @ 8242'. Fish did not fall I , down hole. Worked pipe - pulling to 30-35,000#, grapple slipped off again. Caught fish again @ 8242'. Pulled on fish w/20,000#. Grapple slipped off i again & will not hold. ; 80CMPL !04:00 - 04:30 0.50 FI 4 L/D 1 jr. D.P.,- prepare to POOH. 04:30 - 08:00 3.50 FI y 180CMPL POOH w/fishing tools. !08:00 09:00 1.00 RM 3 !80CMPL Clean rig floor/service top drive. t09:00 - 10:00 1.00 RM c 80CMPL ~Cut 140' ofdrill line. 10:00 - 13:30 3.50 FI 2 80CMPL M/U over shot P/U top extension sub and jars. TIH to 8242'. Up Wt = 80CMPL ~ 185,000#/Dn Wt -- 165,000# 13:30 16:001 2.50 FI 4 Work over fish. Work tight spot - pulted 35,000# over up wt and jar up. I Saw pressure loss and pulled free. No noticeable extra weight on total ~string weight. Pump dry job - fill trip tank. 16:00 - 19:00 3.00 FI 4 80CMPL POOH. Recovered 9.65' of 2 1/16" fish. Total fish = 5,769' T.O.F. @ 8,262' I B.O.F. @ 14,021' 119:00 - 20:30 1.50 FI 2 80CMPL L/D BHA clean rig floor. 20:30 - 22:00 1.50 we s 80CMPL Waiting on fishing tools. 22:00 - FI 2 80CMpL P/U BHA. 04/23/98 00:00 - 02:30 2.50 FI 4 80CMPL TIH w/outside cutter to 8262'. 02:30 - 05:00 2.50i FI z 80CMPL Swallow 2 1/16" DP w/5" DP from 8262' to 9595'. 05:00 - 07:30 2.501 FI x 80CMPL Start at 9595' to make outside cut on 2 1/16" - rotate & pull slow looking for ~ i a 2 1/16" collar to engage cutters. 07:30 - 11:00 3.50 FI y 80CMPL Pump dry job and POOH to 1222'. 11:00 - 14:30 3.50 FI i Y 80CMPL L/D 2 1/16" DP out of 5" DP. 1307.87' of 2 1/16" DP recovered. 14:30 - 15:00 0.50 FI 2 80CMPL P.O.O.H. L/D BHA outside cutter. 15:00 - 16:00 1.00 FI 2 80CMPL P/U over-shot / grapple fishing BHA. 16:00 - 16:30 0.50 we u 80CMPL Waiting on fishing tools. 16:30 - 17:00 0.50 FI 2 80CMPL M/U top sub, top ext., O/S bowl, and guide. 17:00 - 20:00 3.00 FI 4 80CMPL T.I.H. w/BHA on 5" DP to T.O.F. at 9565'. ~20:00 - 00:00 4.00 FI z 80CMPL Swallow 2 1/16" D.P. to 9596'. Break circulation @ 3800# & 13 SPM (50 GPM). Work pipe, jarring 45k above sting wt of 210k. circ pressure dropped f/3800# t/600# w/13 ' spm (50 gpm) i while jarring stuck pipe, indicating the pack off rubber in the overshot ~ became ineffective. 04/24/98 00:00 - 01:00 1.00 FI a 80CMPL Jar on fish - pulled 75K over up weight. Parted string. Pumped dry job. 01:00 - 04:30 3.50 FI !2 80CMPL POOH w/fish. 04:30 - 07:00 2.50 FI 2 80CMPL L/D BHA & 2 1/16" DP fish. Recovered 538.96'- fish remaining as follows: I ~ 2 1/16" DP~ 3.25ppf -- 783.71' ~ 2 1/16" DP, 4.50ppf -- 1364.00' ~ X-over -- 0.69' ,, i I 1/4" DP, 3.02ppf -- 1757.35' i BNA -- 16.29' i TOTAL FISH -- 3922.04' ' I i ! I Estimated top of fish at 10,104' which is 31' below the top of the I , f liner/packer hanger. Fish top was the parted body of 2 1/16" DP (7.10'). ! Appeared to be a clean brake with some pinch down at or near parting ' I point. 07:00 - 08:30 1.50 FI 2 80CMPL P/U iars / bumper. Attempt to remove 2 1/16" DP out of bumper sub (2 Printed: 10/27/98 3:02:3~, PM PHILLIPS PETROLEUM CO Operations Summary Report Page 21 of 22 Legal Well Name: Common Well Name: North Cook Inlet Unit B-1 Event Name: Sidetrack Contractor Name: Unocal/Pool Rig Rig Name: Date From - To Hours Sub Co Phase 04/24/98 07:00 - 08:30 ! 1.! O4/25/98 04/26/98 08:30 - 12:00 12:00 - 13:00 13:00 - 16:00 16:00 - 20:00 20:00 - 00:00 00:00 - 03:30 03:30 - 06:30 06:30 - 07:00 07:00 - 07:30 07:30 - 11:00 11:00 - 14:00 14:00 - 15:00 15:00- 19:00 19:00 - 20:00 20:00 - 23:00 23:00 - 00:00 00:00 - 02:30 02:30 - 04:30 04:30 - 12:00 NORTH COOK INLET UNIT-B Code 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 000001 Start: 02/05/98 Rig Release: 10/21/97 Rig Number: 428 Spud Date: 07/31/97 End: Group: Description of Operations 1/16" jammed in sub). Separate & L/D - P/U break down O/S bowl. Remove grapple & 2 1/16" DP (NOTE: Pack-Off washed out). Clean rig floor, waiting on fishing tools. Rig up test its pull wear bushing. Install Test Plug, Test BOPE to 250 psi Iow & 5000 psi high pressure test. Test Hydril annular preventor to 250 psi Iow & 3500 psi high pressure test. held ok. Retrieve test plug. Install wear bushing. M/U 3.125" OD Overshot w/2.0625" spiral grapple, x-over, 2 jts of 2.0625" work stdng, & x-over on 5" d.p.. (tack weld 3.125" od overshot bowl & top sub, tack weld & strap the 2 jts of 2.0625" above the overshot to insure the 2.0625" tbg will be backed off below the overshot.) Gih w/3.125" OD Overshot & fishing assembly on 5" d.p. to 9992'. Circulate and condition mud @ 9992'. P/U pup & single, R/U pump in sub (APR's). RIH to 10,104' - no fish. Continue to 10,123'. P/U another joint DP, RIH to 10,073' (liner top).- no fish at 10,142'. NOTE: Believe that force created in pulling pipe in two, jarred bttm of fish (@ 14,021') loose and sent it to bt'tm (mill TD @ 14,427'). R/D pump in sub & d.p. pup its Pump slug POOH. Remove straps f/x-over on BHA. Weld each connection on 2 1/16" D.P. as RIH. Cut drill line - 92 ft. RIH with 3 1/8" fishing assembly and 472' of vertical beed welded conn. on 2 1/16" DP and tie back to surface w/5" DP (X-over 44 ft above liner top). Assembly as follows: (1)Guide OD=3 1/8" ID=2 7/16" Lgth=0.09' (2)Bowl OD=3 1/8" ID=2 1/16" Lgth=l.00' (3)Top-sub OD=3 1/8" ID=I 7/8" Lgth=l/01' (4)X-over OD=2 13/14" ID=I 3/4" Lgth=0.68' (5)2 1/16" OD=2.33" ID=1.700" Lgth=472.19' Total BHA=476.19' Latch onto fish at 10,505 ft w/3 1/8" over shot grapple BHA. Saw press. incr., PU wt. is 10K over DP. Fish appears to be free. TOOH, worked fish thru tight spot at 14,021 ft. DP drag appeared to have stopped after tight spot but no indication of loss of fish weight. TOOH to liner top @ 10073' Clean rig floor. Mix & Pump dry job Continue to POOH w/5" DP slowly. Ground off tack welds on 2 1/16" DP connections. L/D 15 jts. and overshot grapple. Clean rig floor. I. JD 2 1/16" DP fish and 1 1/4" DP fish. Fished BHA complete. BHA OD's measurements out of the hole (O.O.H), compared to Baker original measurements as follows: O.O.H. Baker Length Mill 3 1/8 "----3 3/16"- .... 0.80' X-over 3 1/16"----3 1/8 "- .... 0.84' Motor 2 7/8 "----2 7/8 "- .... 11.48' Printed: 10/27/98 3:02:38 PM PHILLIPS PETROLEUM CO Operations Summary Report Page 22 of 22 Legal Well Name: :Common Well Name: Event Name: Contractor Name: Rig Name: Date From - To 04/26/98 04:30 - 12:00 2:00 - 15:00 5:00 - 15:30 15:30 - 21:00 21:00 - 23:00 23:00 - 00:00 04/27/98 ~ 00:00 - 03:30 03:30 - 04:00 04:00 - 06:00 06:00 - 12:00 04/28/98 : 00:00 - 06:00 '06:00- 16:00 16:00 - 00:00 04/29/98 00:00 - 00:00 00:00 - 00:00 04/30/98 05/01/98 00:00- 12:00 NORTH COOK INLET UNIT-B North Cook Inlet Unit B-1 Sidetrack Unocal/Pool Rig Hours Sub Co Phase 7.50 Ft l y PA e PA PA PA PA 12.00 ./MV v Code 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 60ABNT 60ABNT 60ABNT 60ABNT 60ABNT 60ABNT 60ABNT 60ABNT 60ABNT 00MMIR 000001 Start: 02/05/98 Rig Release: 10/21/97 Rig Number: 428 Spud Date: 07/31/97 End: Group: Description of Operations Fish wear description as fbllows: (1) Mill "Mill cutting edge worn flat (1/3 of outside of each of the 3 cutter blades). "Gash cuts +/- 1" long horizontally and upward on 2 of 3 blades. "Deep angled cut 1/4" wide on the side of the upper most part of one blade. **Mill skirt tail had spiral cut over the entire skirt length and circumference. (2) X-over '*Deep gash cuts horizontally and upward over the entire length. **Spiral cut over entire length. (3)Motor **Gashes and spiral cut over entire length. Steam clean out 1 1/4" DP and BHA, tools, and rig floor. M/U 9 5/8" model 3 packer type RBP (RTTS packer element / J-lock set RBP) w/overshot setting tool. RIH w/9 5/8", 53.5ppf, model 3 packer type RBP on 5" DP. Set same at 10,036.51' (Top of tool). P/U DP 1 jr. Test RBP / CSG to 2500# for 5 min.. Tested good. Circulate bottoms up. TOOH w/5" DP. POOH. L/D running tool also make breaks on Howco by-pass. Clean rig floor & equipment L/D HWDP & DC Displace oil base mud to platform tanks (365 bbls total volume in platform tanks / 826 bbls total volume B-1 S.T. cased hole). Flush lines. Clean out rig pits of oil based mud residue. Load equipment onto work boat. Prepare rig to nipple down BOPE. Clean, inspect, change elements in blind rams. Install & close up rams. Continue to clean pits and mud solids control equipment. Nipple down BOPE, raiser, clean well head, & lower TA tree into well bay. Inspect well head, clean / polish gasket area. Install tree. R/D Howco flare boom. Continue to clean pits. Clean and prepare rig and equipment for move. Continue to clean rig pits, solids control equipment, and area of oil based mud residue. Continue to prepare rig, equipment, and platform for move. Continue to clean rig pits, solids control equipment, flowline, drain lines, and rig area of oil based mud residue. Unload equipment and materials forthe NCIU B-3 off of workboat and onto platform decks. NOTE: Estimated spud date 5-3-98, due to excessive OBM residue in flowline and pit tanks. CONTINUE TO PREPARE RIG, EQUIPMENT, & PLATFORM TO MOVE RIG INTO POSITION OVER B-3 WELL SITE. CONTINUE TO CLEAN PITS OF OBM RESIDUE & DRILL SOLIDS. PREP TO INSTALL 30" ABB VETCO GRAY MULTI BOWL WELL HEAD ASSEMBLY ON THE 28" DRIVE PIPE ON B-3 WELL SITE. NOTE: ESTIMATED SPUD DATE 5-3-98'. FINISH CLEANING MUD PITS & EQUIPMENT. T&A COMPLETE. SKID UNOCAL RIG #428 F/SLOT #4 OF LEG #1 T/SLOT #2 OF LEG #1. Printed: 10/27/98 3:02:38 PM S~09 9££ Anadri l 1 Schlumberger Alaska District 1111 East 80th Avenue Anchorage, AK 99518 (gq7) 349-4511 Fax 344-2160 O1 Apr 1998 Client .... : Phillips Petroleum Field ..... : Cook Inlet Well ...... · NCIU-B1ST (PO~) Vert sect.' 261.57'deg az DD engnr..: Units ..... : FEET Position calc.: Minimum Curvature DLS calc meth.: Lubinski Survey Date...: 01 Apr 1998 KB Elevation..: 132.00 ft Reference ..... : Magnetic. Jcln.: +22.I82 (E} WELLHEAD coordinates...: 0,0 RECORD OF SURVEY Pg: 1 (Calculated from a tie-in station at 10354 MD) ~EASUR£O IN~LN DIRECTION V£RTI~AL-DEPTH$ $£¢TION ¢OOR~INAT~$-FRO~ DEPTH ANGLE AZIMUTH TVD .SUB-SEA' DEPART WELLHEAD 100 10354.00 37.68 159.60 8822.47 869~.~7 ~"~805.,16 4715.87 S 1512.81 E-. <TIE 3 10390.00 37.70 3 10466.78 32.66 3 10552.28 34.65 3 10648.98 37.82 3 10741.10 39.27 3 10839.97 39.15 3 10932.63 39.60 3 11027.38 40.40 3 11120. I8 40.73 159.60 8850.96 8718.96 160.96 8913.69 8781.69 164.22. 8984.87 8852.87 167.99 9062.86 8930.86 -809.72 4736.20 S' 1520.48 E 0.06 -818,41 .4777.82 S 1535.43 E 6.64 -825.77 ':~823.02 S 1549.57 E 3.14 -831,14 4878,49 S 1563,22 £ 4,01 169.26 i71.11 174.00 175.27 178.04 9134.91 9002.91 -834.08 92]1.5Z 9079.52 -835.59 928~.16 9151.16 ? -834.57 · , 9355.74 9223.74 -831.31 9426.~4 9294.24 -825.96 4934.77 S 1574.53 E 1.79 4996.35 S 1585.19 E 1.19 5054.62 S 1592.80 E 2.04 5115.26 S 1598.48 E 1.21 5175.49 S 1602.00 E 1.97 3 11214.84 40.77 3 11306.48 39.68 3 11404.09 39.18 3 11497.64 39.72 3 11589.36 39.20 3 11688.83 38.22 3 11778.27 37.38 3 11869.50 36.47 3 11962.48 35.71 3 12055.28 35.71 I81.72 185.56 190.21 195.05 198.53 9497.96 9365.96 -817.03 9567.94 9435.94. -804.68 9643.35 9511.35 -787.29 9715.61 9583.61 -765.93 9786.43 9654.43 -741.11 200.99 9864.05 9732.05 205.07 9934.73 9802.73 209.18 10007.68 9875.68 213.93 10082.83 9950.83 217.52 10158.19 10026.19 -711.74 -683.16 -651.33 -616.17 -578.45 5237.26 S 1602.13 E 2.54 5~'96.30 $ 1598.40 E 2.96 5357.67 S 1589.91 E 3.07 5415:63 S 1576.91 E 3.34 5471,42 5 1560,08 E 2,48 5529.96 S 1539.0~' E 1.83 5580.39 S 1517.65 E 2.95 5629.16 S 1492.69 E 2.88 5675.81 S 1464.07 E 3.12 5719.77 S 1432.45 E 2.26 3 12149.45 36.58 3 12240.35 36.45 3 12335.00 37.30 3 12425.99 38.98 3 12523.08 39.87 3 12621.69 41.47 3 12711.75 42.38 221.18 10234.24 10102.24 223.97 10307.30 10175.30 228.47 10383.03 10251.03 229.62 10454.59 10322.59 231.08 10529.59 10397.59 233.03 10604.38 10472.38 234.92 10671.39 10539.39 -537.32 -495.29 -448.98 -401.60 -348.87 -292.95 -239.62 5762.69 S 1397,23'E 2.47 5802.51 $ 1360.65 E 1.83 5841.77 S 1319.65 E 2.99 5878.59 S 1277.21 E 2.00 5917.93 S 1229.73 E 1.32 5957.43 S 1179.05 E 2.07 5992.81 S 1130.38 E 1.73 'Station Types:, 3/MWD 8/TIE-IN (knadrill (c)98 BlSTD8 3.2C 6:34 PX D) IO'd 9'1~,1 NOJ. StqOH Oi CI09 9££ NCIU-B1ST (P08) RECORD OF SURVEY 01 Apr 1998 Page 2 (Calculated from a tie-in station at 10354 MD) S MEASURED INCLN DIRECTION VERTICAL-DEPTHS SECTION COORDINATES-FROM DC/ T DEPTH ANGLE AZIMUTH TVD SUB-SEA DEPART WELLHE~U] 100 3 12803.56 42.33 239.16 10739.25 10607.25 -183.37 6026.44 S 1078.51 E 3.11 3 12898.03 42.15 240.65 10809.19 10677.19 -124.36 6058.29 S 1023.57 E 1.08 3 12992.35 41.28 241.28 10879.60 10747.60 ,-65.61 6088.75 S 968.70 E 1.02 3 13086.39 42.20 243.64 10949.77 10817.77 -6.¢6 6117.68 S 913.19 E 1.94 3 13178.10 44.I8 245.73 11016.64 10884.64 53.60 6144.50 S 856.45 E 2.66 3 13271.13 46.33 3 13364.57 47.09 3 13459,63 47,13 3 13546.98 48.14 3 13643.45 50.19 3 13735.56 53.18 3 13824.91 55.37 3 13922.85 58.88 3 14013.84 64.08 3 14104.30 65.67 248.88 11082.13 10950.13 249.74 11146.20 11014.20 251.93 11210.91 11078.91 252.74 11269.77 11137.77 253.58 11332.84 11200.84 255,41 11389.95 11257,95 256.94 11442,12 11310.12 257.49 11495.27 11363.27 259.90 I1538.71 11406.7I 260.72 11577.11 11445.11 117.62 6169.95 S 795.49 E 3.33 184.08 6193.98 S 731.87 E 1.05 252.50 6216,84 S 666.09. E 1.69 316,21 6236.42 S 604.59 E 1.34 388.41 6257.56 S 534.73 E 2.22 460.12 6276.85 S 465.10 E 3.60 532.33 6294.17 S 394.67 E 2.82 614.33 6312.36 S 314.46 E 3.61 694.14 6327.98 S 236.09 E 6.17 776.02 6341.77 S 155.37 E 1.94 3 14195,85 66.09 3 14291.04 66.55 3 14384.52 67.02 3 14476,50 67.57 3 14565.00 65.43 261.03 11614.53 11482.53 859.57 6355.02 S 72.87 E 0.55 261.11 11652.76 11520.76 946.74 6368.55 S 13.25 W 0.49 261.60 11689.60 11557.60 1032.65 6381.46 S 98.19 W 0.70 260.86 11725.11 11593.11 1117.50 6394.40 S 182.05 W 0.95 261.86 11760,40 11628.40 1198.66 6406.60 S 262.28 W 2,63 3 14661.20 65,27 3 14754,81 65,46 3 14850,92 65,88 3 14914.16 65,97 3 15007,49 65.09 262.27 11800.52 11668.52 1286.09 6418.67 $ 348,87 W 0.42 262.30 11839.54 11707.54 1271.17 6430.09 S 433.19 W 0,21 262.20 11879.14 11747.14 1458.74 6441.90 S 519.97 W 0.45 262.56 11904.93 11772,93 1516.47 6449.56 S 577.20 W 0.54 263.5¢ 11943.59 11811.59 I601.39 6459.84 S 661.52 W 1.34 3 15099.33 62.83 3 I5194.92 60.19 3 15287.39 58.17 3 15365.94 57.1!2 3 15457.70 57.27 262.90 11983.91 11851.91 1683.86 6469.57 S 743.45 W 2.54 262;79 12029.50 11897.50 I767.85 6480.04 S 826.80 W 2.76 261.46 12076.88 11944.88 1847.25 6490.91 S 905.46 W 2.51 259.40 12118.86 11986.86 19!3.62 6501.94 S 970.92 W 2.53 260,20 12168.50 12036,50 1990,75 6515.60 S 1046.87 W 0.74 3 15549.56 56,43 3 15645.91 56.32 3 15738.20 55.83 3 15829.78 55.44 3 15923.52 54,30 260.40 12218.74 12086.74 2067.64 6528.56 S 1122.68 W 0.93 259.53 12272.09 12140.09 2147.84 6542.54 S 1201,68 W 0.76 259.20 12323,60 12191.60 2224,36 6556,67 S 1276.94 W 0.61 258,60 12375.~'9 12243.29 2299,88 6571.22 S 1351,13 W 0.69 257.83 12429.23 12297,23 2376.41 6586.88 S 1426.17 W 1.39 3 16017.44 52.5¢ 3 16108,20 51.71 3 16200,36 50,67 3 16291.40 49.77 257.85 12485,20 12353.20 2451.66 6602.76 S 1499.g0 W 1.87 256.40 12540,93 12408.93 2523,09 6618.72 S 1569.74 W 1,56 255.55 12598.68 12466.68 2594.56 6536.12 S ]639.41 W 1.34 254.10 12656.93 12524,93 2664.04 6654.43 S 1706.93 W 1.58 'Station Types: 3/MWD (tnadrill (c)98 BIST~8 3.2C 6:34 Plt D) aO'd r'J"l:'::t,l NOi'_=,l-lOH O.L tI09 9£L £86 U>iSU-'IU IUN~>I ~5 9t~:I0 85, EO ~dU ~:S0 866~-20-~d NCIU-B1ST {PO8) 01 Apr 1998 Page 3 RECORD OF SURVEY. (Calculated from a tie-in station at 10354 MD) S MEASURED INCLN DIRECTION VERTICAL-DEPTHS SECTION COORDINATES-FROM DL/ T DEPTH ANGLE AZIMUTH' TVD SUB-SEA DEPART WELLHEAD 100 m 3 16385,44 ¢8.95 254.00 ]2718.18 12586.18 2734.78 6674,04 S 1775.54 W 0.88 3 16479.19 48.16 252.70 12780.24 12648,24 2804.33 6694.17 S 1842.87 W 1.34 3 16570.64 47.89 251.50 12841,40 12709.40 2871,39 6715.06 S lg07,56 W. 1,02 3 16645.96 47.80 250.30 12891,95 12759.95 2926.26 6733.33 S 1960,33 W 1.19 j 16720,00 47.60 249.00 12941.78 12809.78 2979.84 6752.37 S 2011,67 W 1.33 ~Station Types:. 3/MWD J/PROJECTED Final closure from wellhead: 7045,7 FEET at 196,59 (~nadrii1 f¢)98 BlJSTP08 3.2C 6:34 PI(D) £0'd 9-1:-~,'l NOL'_~IgOH 0£ GIE)9 9AY. LID6 t-j>iSbt-lU Ibl,13>( ~d £t~:I0 86, EiD ~dt-3 NClU B-1 SIDETRACK COMPLETION DIAGRAM ISSSV (~ 430' MD (430' TVD) I 120" (~ 2579' MD (2571' TVD) I 2-3/8" injection strings for 113-3/8" (~ 3760' MD (3521' TVD) ] 4-1/2", 12.75 ppf, P-110 tubing I IPKR {~ 10,074' MD (8598' TVD) I 19-5/8" ~ 10,376' MD (8846' TVD) I · I ~5", 19.5 ppf, S-135 Drill Pipe with i '~l"o" Tool Joints (Min ID: 3.25") ~,,, IN. FORELANDS PERFS @ ..... 116,080'- 16,118' MD ICMT ~. DP ~. 16,590' MD I "15" DP (~ 16,650' MD I DATE: July 8, 1998 OPERATOR: PHILLIPS PETROLEUM COMPANY FIELD: North Cook Inlet WELL NAME: NCIU B-1 and B-1ST COUNTY: Kenai STATE: Alaska SECTION: 6 TWNSP: 11N RANGE: 9W APl NUMBER: 50-883-20093 ARCO Alaska, Inc. Alaska Dept of Natural Resources l~l~ska O&G Conservation Commission DISTRIBUTION LIST LOGGING DEPTH # OF # OF # OF ROLLED TYPE LOG DATE SCALE LOGGED ORIG. PRINTS FILMS VELLUM MUD LOGS: i?t'l !" I V I' OTHER MATERIALS: Well Summary Report (drilling report) D j jI, ! ,'5 1998 .~.~.~ nil & G~t8 Cons. commission Anchorage Should you have any questions, please contact: Donna Hole Phillips Petroleum Company P.O. Box 1967, Houston, TX 77251-1967 713-669-3722 SCHLUMBERGER WELL SERVICES A DIVISION OF SCHLUMBERGER TECNOLOGY CORPORATION HOUSTON, TEXAS 77251-2175 APR 1 ? 1998 Phillips Petroleum Company 6330 West Loop S., Texas Commerce Bank Buildin~l, P.O. Box 1647 Houston, TX 77401 ATTENTION: PLEASE REPLY TO: Schlumberger Well Services HC01, Box 337 Kenai, AK 99611 Attn: Shelley Ramsey Enclosed are 8 BL/2 films Company Phillips Petroleum Company Well North Cook Inlet Unit "B" No. 1ST Field North Cook Inlet Additional prints are being sent to: 2 BL prints Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchora~le, AK 99501 Attn: Blair E. Wondzell of the CNL/LDT, CNL/LDT TVD, Run 1,4/2/98 on: County Kenai State Alaska prints prints prints prints prints prints PLEASE SIGN AND RETURN ONE COPY OF THIS TRANSMITTAL TO THE ADDRESS INDICATED ABOVE. THANK YOU. prints The film is returned to Phillips Petroleum ? We apprec~e the privilege of se~ing you. Received by: Date: Very truly yours, Schlumberger Well Services Rachel Walsh Engineer in Charge MEMORANDUM TO: THRU: Blair Wondzell, P. !. Supervisor State of Alaska Alaska Oil and Gas Conservation Commission DATE: March 17, 1998 FILE NO: AX9JCPFE.DOC FROM: Lou Grimaldi, vi ~- ~- SUBJECT: Petroleum Inspector BOP test Phillips NCIU B-1ST North Cook Inlet Unit PTD #98-02 Mond..ay, Mar. ch 16,. 1998; I witnessed the weekly BOP test on the Tyonek platform rig #429 drilling Phillips well NCIU B-lST in the North Cook Inlet Unit. ! arrived to find the rig still tripping out of the hole. ! made a tour of the rig and found all to be in good shape. The test, once started, went well, All BOPE were tested with one failure observed. The isolation valve for the #2 hydraulic choke failed and was replaced and retested "OK". The Accumulator test time of 1 minutes and 40 seconds is quick but normal for this dg. The Gas detectors were tested and were working properly. I made a tour of the well rooms and found all to be normal. SUMMARY: The weekly BOPE test I witnessed on the Tyonek platform revealed the following; Test time 3 hours, One failures. Attachments: A6TJCNFE.XLS . CC; NON-CONFIDENTIAL STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: Drlg Contractor: Operator: Well Name: Casing Size: Test: Initial X Workover: Pool Rig No. Phillips Petroleum NCiU B-I ST Set @ Weekly X Other 428 PTD # g8-02 Rep.: Rig Rep.: Location: Sec. 6 T. DATE: 3/16/98 Rig Ph# 776-6013 Danny Simin~on Frank Pluid 11N R. OgW Meddian Seward , i i _ TEST DATA MISC. INSPECTIONS: Location Gen.: P Housekeeping: P PTD On Location /5 Standing Order Posted (Gen) Well Sign Drl. Rig Hazard Sec. FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly / IBOP Bali Type Inside BOP Quan. 1 ,,, ,, ,,, Test Pressure 250/5,0OO 25O/5, OOO 250/5,000 250/5,000 PIF BOP STACK: Annular Preventer Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve Quan. Test Press. 1 25O/2500 , , 1 250/5,000 1 25O/5, OO0 1 25O/5,000 ,,, 2. 0/ ,000 2 2. 0/ ,000 I 250/5,000 N/A P/F P CHOKE MANIFOLD: ,, P No. Valves .14 P No. Flanges 1'32 .P Manual Chokes -1.., P Hydraulic Chokes 2 Test Pressure 250/5,000 250/5,000 N/A Functioned Functioned PIF ACCUMULATOR SYSTEM: System Pressure 3,050 !, P Pressure After Closure 1,800 I P, , MUD SYSTEM: Visual Alarm 200 Psi Attained After Closure 0 . minutes 21 sec. Trip Tank ..... P P System Pressure Attained I minutes 40 sec. Pit Level Indicators P' P Blind Switch Covers: Maste~: P Remote: 'P Flow Indicator _ P .. P Nitgn. Bt's: Twelve Bottles Meth Gas Detector P .. P 2050 avera~le Psig. H2S Gas Detector P P TEST RESULTS NumberDf Failures: '.",l.., ,m~st'Time: '~.0 'Hour~. N~l~ber"of'~al~s't~sted .... ~0 R~pair or Replacementof .Equipment will be made within N/A days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 III I . II II I I III I I III I ~ I II II I REMARKS: IsolaUon valve for #2 hydraulic choke leaked, replaced vane and retested "oK".. waived By: Witnessed By: Louis R. Grimaldi Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File c - Inspector FI.O21L (Rev. 12/94) "~'~ATE WITNESS REQUIRED?" YES X NO , , , 24 HOUR NOTICE GIVEN YES X NO STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF PHILLIPS ) PETROLEUM COMPANY ) (PHILLIPS) for an order granting ) an exception to spacing requirements ) of Title 20 AAC 25.055 to provide ) for the drilling of the North Cook Inlet ) Unit B No. 1 ST delineation oil well. ) Conservation Order No. 409 Phillips Petroleum Company North Cook Inlet Unit B No. 1 ST January 29, 1998 IT APPEARING THAT: o Phillips submitted an application dated January 6, 1998, requesting exception to 20 AAC 25.055(a)(3) to allow drilling the North Cook Inlet Unit B No. 1 ST delineation oil well to a location in an undefined pool that is closer than 500 feet to a quarter section line. o Notice of opportunity for public hearing was published in the Anchorage Daily News on January 13, 1998, pursuant to 20 AAC 25.540. 3. No protests to the application were received. FINDINGS: o The North Cook Inlet Unit B No. 1 well as proposed will be a deviated hole drilled from a surface location 1249' from the north line (FNL) and 980' from the west line (FWL) of Section 6, T11N, R09W, Seward Meridian (SM) to a proposed producing location 2830' from the south line (FSL) and 5044' from the east line (FEL) of Section 7, T11N, R09W, SM. 2. Affected owner ARCO Alaska, Inc. has been duly notified. 3. An exception to 20 AAC 25.055(a)(3) is necessary to allow drilling of this well. CONCLUSION: Granting a spacing exception to allow drilling of the Phillips North Cook Inlet Unit B No. 1 ST well as proposed will not result in waste nor jeopardize correlative rights. Conservation Order No. 4(J ~ January 29. 1998 Page 2 NOW, THEREFORE, IT IS ORDERED: Phillips Petroleum Company's application for exception to 20 AAC 25.055 for the purpose of drilling the North Cook Inlet Unit B No. 1 ST well is approved as proposed. DONE at Anchorage, Alaska and dated January 29, 1998. ~, ,~!~.,/~ "%,~ ',.,~, ~ ~- . ------- ----__._.." /'~! . ~4 ~ ~~'..~7.X~ ~~ati°n Comm.ission ~:,...~ . ~, . ~,~.,-~ ,~ :~ Alaska Oil an : ~, · :,, ..,.. .-. :' . }f .,..'.. ~' ~.~' '~: . ,~. '. ~,~ , ' . ",,,.. .... :' ': ' Cm~ ~echs~Commissioner Alaska Oil and ~as Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written nOtice of the entry of an Order, a person affected by it may file with the Commission an application for rehearing. A request tbr rehearing must be received by 4:30 PM on the 23rd day tbllowing the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or rethse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission. to appeal the decision to Superior Court. Wherea request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th dav after the application for rehearing was filed). TONY KNOWLE$, GOVERNOR 5L&SKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 Januarv 29, 1998 Paul R. Dean Sr. Drilling Engr. Spec. Phillips Petroleum Company 6330 W. Loop South Bellaire. Texas 77401 Re' North Cook Inlet Unit "B" No. I ST Phillips Petroleum Company Permit No. 98-02 Sur. Loc. 1249'FNL & 98()'FWL, Sec. 06, TI IN. R09W, SM Btmnholc Loc. 2513'FSL & 1520'FEL, Sec. 12. T1 IN, RI0W. SM Dear Mr. Dean: Enclosed is thc approved application for permit to rcdrill thc above referenced ,,,.'ell. Thc permit to redrill docs not exempt you from obtaining additional permits required by law from other governmental agencies, and docs not authorize conducting drilling operations until all other required permitting determinations are made. Blov,'out prevention equipment (BOPE) must bc tested in accordance ,,vith 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to alloy,' a representative of thc Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given inspector on thc North Slope pager at 659-3607. David W. Johnston Chairman 'oF T~HE) BY ORDER OMMISSION dlffEnclosures CC: Department of Fish & Game, Habitat Section w/o cncl. Department of Environmental Conservation w/o cncl. jAN-25-1998 14:01 FROM PHI LL I PS PETROLEUM CO. PHILLIPS PETROLEUM CO1~I HOUSTON, TEXAS ~'725~-1H87 ~OX ~ ~6.," ~ORI H AMERICA ~UCT:ON O~V~ON TO =ANY 890?2?6?542 P.001 DATE; ~.~ [ ATTN: ~ELECOFY #: FROM: Oebor-h A. Riehard~0n ~ GRO~H TEAM ' ~ TELECOPY #: ~ Tdel31'mne.' (713) 669-3622 Telecapy: (713) 669-378~ Houston. Texaa 7'7251-1967 NO, OF PAGES (INCLUDING COVER SHEET)= PLEASE CALL SUSIE DEASON AT (713) ~ O~l ' ~ ~ ~ F T~ ~" A" ~ ~ N Y PR O"~l , ~S ' ~ :~,~.~ ~' = ::~,,: ~2 "" ~ ,...,~ ,,,-_'-'-_. ".,E_." ,,...,/- ...~ ' r' ._ _ ._.'- ;, '" ,,,~ _.- JAN-23-1998 14:02 FROM t, PHILLIPS PETROLEUM CO. TO 89872767542 P. 001~ PHILLIPS PETROLEUM COM HO;.JSTON, TEY, A,~ ~'7'~51-1967 Box 1907 i', :D Rl'e,t AMI=HI~A t-'l i~DUCTIOH ~lVl~'Of,I $~0 WC$? LOOP ,..w, OUTH PHILLIP.$ F~UI L O;l~J~ Janua~7 7, 199B UESTED ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99,510,0360 Attention: Mr JirTI Ruud DearMr. Ruud: Notifi ion of Affected Owners Spaci Exception Philli, Well No. I ST C~ Phillips Petroleum Company proposes re-at, try and sidel of the NOIU-B No. t (NCIU-B No. 1 ST), as an intentionally deviated hole pursuant to th Alaska Administrative Code Title 20. Phillips has requested a Spacing Exception pure,ant to 2~ 25.05,5 regarding this operation, since the Sunfish Sand and the North Forelands rs will be penetrated within 500' of a section line and a governmerltal quarter 9ection lir~e res ~. Additionaffy, the bottomhole location is projected to bc within 500' of a governmental after section line. Phillips NCtU-B Wail No. I ST will be drillsd {rDm a su FWL of ~ec. 6-TllN-RgW, on the Phillips Tyanek A location i~ 2513' FSL & 1520' FEI... of Sec, 12-TllN..R11 Alaska. A plat showing the surface and bottomhole path is at~acl~ed hereto. locatiOn of 1,250' FNL and 980' 'lafform. The proposed bottomhole North Cook Inlet, Kena~ Borough, :ions in addition to the proposed well Phillips Petroleum Comparty requests [hat you your receipt of this notification, and ~.hat you state your non-objectior3 la the pending applicat by signing and returning one (1) odginal copy of this letter to the undersigned. Due to time constraints, we would appreciate it if you would also send an approved Copy of this letter via tel( (713) 669,.3769, If you have any questions ar concern~ regarding this matt, ,r, please contact the undersigned at (713) 669-3622. Very truly yours; RECEIVED Nask~ 0it & Gas Co~s. Commtss[0~ Anchorage JAN-23-1998 14:02 FROM PHILLIPS PETROLEUM CO. NotificationS. ,ffect~u Owners Phillips NCIU-B No, 1 ST Spacing Exception Cook Inlet, Alaska Janua~ 7, ~998 Page 2 of 2 TO 89072767542 P, 00:5 THE UNDERSIGNED DOES HEREBY AOKNOWL~ CONCERNING THE PHILLIPS NCIU-B WELL NO. 1 HEREBY STATE THAT 'I'HERE IS NO OBJECTION DRILL, AND NO OBJECTION TO THE GRANTING WELL, RECEIPT Of THIS NOTIFICATION AND THE UNDERSIGNED DOES THE GI~Z~N"i-ING OF A PERMIT TO A SPACING EXCEPTION FOR THIS 1998. RE,CEIVED JAN 2_ ,5 ]998 Alaska 0il & Gas Cons. Commission Anchorage jRN-23-1998 14:02 FROM PHILLIPS PETROLEUM CO.]"~"TO , 890'72767542~. ,., P. O, PHILLIPS ~ ~ )ADL-278~l 3 31 98 ~ ' ~--- ~-__L~ _~ __~ ~ A~CO ~ ~ ~1 ' 374856 . I / / - , ~~ ~ I ~ ' HBP ~ .... '%7 2830' FSL & 5044' FgL I I N, Fareland~ . i 2642' FgL & gO3' FEL 1 ~ PHILLIPS PETROLEUM r'-OMPANY COOK INLET B~kSIN [ otl m H lo at' n' ~ ..... , "-':-. - ..... - ---,.. . ...... . ' '...- ..,'"'. .... ... ~.'.::": ':,:::.:.:C-": _.,-'.,: ...... : .... : TOTRL P. 004 .... ~': ~-. _ ._~. PHILLIPS PETROLEUM COM'PANY P. O. Box 1967 Houston, Texas 77251-1967 6330 West Loop South Bellaire, Texas 77401 January 06, 1998 North Cook Inlet Unit "B" No. 1 PPCo. Tyonek Platform North Cook Inlet Unit, Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn' Mr. Blair Wondzell Gentlemen: Enclosed for your consideration and approval are three copies of Form 10-401 (Application for Permit to Drill). The referenced well will be re-entered and sidetracked from the existing intermediate casing shoe to a development location penetrating the Sunfish and North Forelands reservoirs discovered by the ARCO-Phillips Sunfish No. 1, the PPCo. NCIU "B" No. 1 and NCIU "B" No. 2 ST. Phillips plans to continue the use of the Unocal owned Rig No. 428, which will be operated by the crews of Pool Artic Alaska. This Application requests a location exception ruling for the Sunfish Sand Reservoir, which will be penetrated within 500' of the Section Line dividing Section 7-T11N-R09W and Section 12- T11N-R10W. The N. Forelands Reservoir will be penetrated within 500' of the southern 1/4 Section Line of the'N'~,, 1/4 Section 12-T11N-R10W. The proposed BHL will be within 500' of the same quarter section line. ARCO and Phillips are the only Owners/ Operators of the offsetting quarter sections. ARCO has been sent notice of this request under a separate letter. In addition to this Application for the Permit to Drill is a request to continue the use of the Cuttings Injection System that is set up for this Drilling Program. The cuttings injection is required to continue use of the oil base mud system that was so successful in the drilling of the previous wells last year. Enclosed with the application are the following support documents: 1) Check for $ 100.00 to the State of Alaska, Department of Revenue. 2) A plat showing the referenced property, leaseholds, surface and proposed target and bottom hole locations. 3) The proposed casing and cementing program. RECEIVED JAN - 8 ' 998 Naska 011 & Gas Cons. Commission Anchorage 4) 5) 6) 7) 8) 9) 10) 11) Schematic diagrams of the existing wellhead and proposed BOP equipment. Proposed drilling fluid program with supplementary documentation as follows: a) b) c) d) Anticipated Mud Weight / Casing Point Plot Anticipated Surface Pressure Calculations Solids Control Program Schematic Diagrams of Rig 428 and Tyonek Platform Mud Systems. Predicted geo-pressured strata are described in detail in the drilling fluid program and supporting documentation. A copy of the proposed drilling program. The well will be sidetracked from a depth of approximately 10,378' MD (8,846' TVD) and intentionally deviated to reach from the Tyonek Platform to the bottom hole location Southwest of the platform as illustrated on the proposed directional plan. Projected Time versus Depth Plot. Hydrogen Sulfide gas has not been encountered in any of the referenced offset wells drilled from or near the Tyonek Platform, nor is it anticipated in the North Cook Inlet Unit 'B" No. 1 ST. It is PPCo's. intent to monitor for the presence of hydrogen sulfide while drilling the entire well. Should H2S be detected, the AOGCC will be notified and contingency equipment installed immediately. The referenced well is scheduled to be spud approximately January 20, 1998, or as close thereafter as possible. AOGCC is requested to keep this application and the attachments confidential. Should you have any questions or require any additional information, please contact Paul R. Dean at (713) 669-3502. Regards, N. P. Omsberg North America Drilling Manager enc: J. W. Konst (w/o enc) W. L. Carrico , J. R. Soybel " D. A. Richardson ' P. R. Dean (w/enc) A.J. Lasche " PERMIT TO DRILL 20 AAC 25.005 la. TyPe of Work Drill~ Redrill_X Ilb. Type of well Exploratory ~ Stratigraphic Test ~ Development Oil X Re-Entr)/ Deepen__ IService _ Development Gas _ Sin~lle Zone _ Multiple Zone__ , 2. Name of Operator: 5. Datum Elevation (DF or KB) 10. Field and Pool Phillips Petroleum Co. 132 feet North Cook Inlet Unit Field 3. Address: 6. Property Designation Development 6330 W. Loop South~ Bellair% TX 77401 ADL-17589 4. Location of well at surface: Tyonek Platform Leg 1 Slot 6 7. Unit or Property Name 11. Type Bond (SEE 20 AAC 25,025) 1249' FNL & 980' FWL SEC 6-T 11N-R09W North Cook Inlet Unit "B" Statewide At top of productive interval: !8. Well Number Number 2830' FSL & 5044' FEL SEC 07-T 11N-R09W No. 1 ST 41-0-524 At total depth: 9. Approximate spud date Amount 2513' FSL & 1520' FEL SEC 12-T 11,N-R10W 01/20/98 $200t000 _ , 12.Distance to nearest 13. Distance to nearest well 14. No. of acres in property 15. Proposed depth (MD and -I-VD) property line Surface: 4' 9920 , approx. 512 feet NCIU A-12,, 18200 MD 13000 TVD fee.[, 16. TO be completed for deviated wells 17. Anticipated pressure (S~E 20 AAC 25.035 (e)(2)) Kickoffdepth: 10~378 ft Maximum hole.angle 69 degrees ,,, Maximum surface 7707 , psig , Attotal depth ('I'VDt 9650 _psig Casing program, , Setting Depth ,, size , Specifications ToP Bottom Quantity of cement ,_ Casing Weight ,,Gra, d,e coUpling Length MD , ,'I-VD MD TVD , (include sta~]e data) Driven 30" Drive 368' 57 57 407' 407' EXISTING 24" 20" 133 K-55 B'I'&C 2522' 57 57 2579' 2571' EXISTING , , , 18-1/2" 13-3/8" 72 L-80 ST/L 3703' 57 57 3760' 3521' EXISTING , , , 12-1/4" 9-5/8" 53.5 P-110 BT&C 10323' 53 53 10376 8846' EXISTING 8-1/2" ,i 7", 32 P-110 BT&c 6900' 10100' 8750' 17000' 12932' 1200 sx Class "G" + Additives 3r ,(Alternative) ....... , 8-1/2" I 3 1/2" "i2.,95 ,P-110 PH-6 6900' 10100' 8750' 17000' 12932' 1400 sx Class"G" + Additives Note: Well to be sidetracked from 9 5/8" casing @ 10,376' after drilling out cement plug. 19. To be completed for Redrill, Re-entry, and Deepen Operations. 1) 261 sx 14,850-15500' Present well condition summary 2) 282 sx 14,150-14,560'. Tagged Plug 3) 535 sx 10,270' - 10,800'. Tagged Plug. Total depth: measured 15500' feet Plugs (measured) true vertical 12878' feet Effective depth: true measured vertical feet feet Junk(measured)ORIGINAL Casing Length Size Cemented Measured depth True Vertical depth Structural 368' 30" Driven 407' 407' Conductor 2579' 20" Yes 2579' 2571' Surface 3760' 13-3/8" Yes 3760' 2521' Intermediat 10376' 9-5/8" Yes 10376' 8846' Prod. Liner Perforation depth: measured None .... 7998 true vertical Naska 0il & 0as Cons. Coramissi0~ Anchorage 20. Attachments Filing fee X Property plat_X_ BOP sketch_X_ Diverter Sketch Drilling program_X_ Drilling fluid program X Time vs depth ,pl0t.X~ ,, Refraction anal~,,s,!s ...... Seabed report 20 AAC 25.050 requirements (Directional Progra ,, XX, 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed~{~, ~ Title 51~. ~ ~{~p?, ,,~0~..(~ Date ~'"~ Comr~ission I~se Only, ~ ' 'l~ermitNum'ber ...... iAp, N,mber "' IApprovaiDate t[;~911~j Iseec°ver'etter ' (::~--O ~--. I 50- ¢~,,~ ' .2..O~ ~ "Of ~, Ifor other requirements Conditions of Approval: Samples required ~ Yes _~No Mud log required ~ Yes ~ No Hydrogen sulfide measures ~ Yes ~ No Directional survey required ~ Yes ~ No Required working pressure for BOPE ~ 2M ~3M 5M ~ 10M ~ 15M Oavid W, Johnston by order of ,,Approved by' Commissioner the commission Date Form 10-401 Rev. 12-1-85 Submit in triplicate c.~ to 36 6 LEG NE. 4' LAT. 61° 04' 3,6.89" LONG. 150° 56' 54.25" Y=- 2~86,781 X:' 332~63 FROM N.W. 1,198' SOUTH · 1,045' EAST. ' LEG Ng. I LAT. 61° 04' 36.3,8" LONG.150° 56' 55.63" Y= 2:,586,731 X: 331,995 FROM N.W. CO.R.' 1,2:50' SOUTH 8, 975'EAST. CERTIFICATE OF SURVEYOR TI2N _ , TIIN ORIGI"N:AL .. f ,31 _ .. SCALE ~" I'"' ;' 1,000" LEG N-9-. ?. LEG N° $ LAT. 61° 04' 35.85" LAT. 61~ 04' 36.34".' LONG. ~50° 56' 54.77" LONG.~50' 56"53.39" .. Y= 2:,586,674 Y-' 2,5 86,7:> 4 .. · X= 332,036 X: 332,105 FROM .N.W. COR. .FROM N.W. COR. 1~305: SOUTH 8s 1,254' SOUTH 5 : 1,018- EAST. 1,085' EA.ST.. I hereby certify that I am properly registered and licensed to practice land surveyihg in the State of A laska'ond 'that this plat represents a location survey made by me or under my supervision and that all dimensions and other details ore correct. '~ '/ D AtE SJI:~YOR .o · . . ;.'. NOTE: Plat emended 7AUG.68' to show · revised leg numbering. .. · , , ,, · , · · · · , es_. ."..:.'...,... :... 7 8 ' ".' · . o.. . · · ,-;· .~". · · · · - · · . ,.' , .. · · NOTE NORTH COOK I ,TUNIT The location of the platform legs was accomplished by usi~ECE,~ PLATF'OR , triangulation stations BELUGA,TERRACE,end TYONEK w'h]'c~ ' ~' ~ HILLIPS PETROLEUM CO _ are all U.S.C.E~ G.S. stations· ~]~ '-<<ii [3~'~,[E' I"' I000' .J Land & Hydrographic AIl coordinates are Alaska StatePiane~ Zone 4 ~ ~-T~'-~5'j Surveyors · ~$OZ ~. NO~TI.I[~LN3HI'3 ,Anchora! 3-31 -98 ADL- 369101 I HBP ADL-374081 f ' I ~ ARCO I ADL-.'. 759(3 / , ----- --f-' ..... -~-'- "' ~ T" ! ABE-374083 ~ - - ~ .... ,_1 ........ ! ,~ PHILLIP~ I I ~; AOL-37831\l~li !../'1 1~ ,-~-~ ' t 1 ' /V ~~ o ' )L ----¢ f ¢---'i PHiLLiPS / I N. Forelands-~ ."-" ~ I ' '~ .......... ~ ~ ~ I i PHILLIPS ADL-18741 + ,. O. · , ,~, II ~ I I II I i I R 10'W ! - I ~ Sunfish ,,, 2830' FSL & 5044' FEL · I N. Forelands ,.~ RSW PHILLIPS PETROLEUM COMPANY ' North Cook Inlet Unit "B" No. 1 ST ........ ' ..... Surface Location: ~2~o' .,L & ~o' .w. BASIN Sec. 6- T11N- R09W Bottom Hole Location' 2513' FSL & 1520' FEL Sec. 12 - T11N - R10W _ - . COOK' INLET OIL & GAS LEASE OWNERSHIP MAP . sc.L~ !.,~! .... North Cook Inlet Unit A-$.~~ N.~,I. Un, A-~~ PHI.L. LIPS PETROLEUM COMPANY ,, ~1~ ? ~T~[~I' .... NORTH COOK INLET TYONEK PLATFORM COOK INL_ET ~ NQTI[~; Ueln~ PLATFORM NORTH, Slol Noi! will be furthest platform North slot In platform North- welt quadrant of any legi Slots are numbered I thru 8 In a counfer-clocX-wise direction. Pt.&TFO~iLOCATtQM:iee.&'ilN-SW l~'X?[: i-IQ-iS , ~,w.. ,. ~...C'"'" .... l ~T,,,TO, ~C)~L{ .... ,, North Cook Inlet Unit" B" No.1 TELEPHONE NUMBERS Drilling Superintendent W.L Carrico Home Mobile Pager (713) 669-2173 (281) 343-7279 "542-9988 (800) 626-6182 Drilling Engineer Paul Dean (713) 669-3502 Home (281) 980-1557 N. P. Omsberg Drilling Manager Dave Beardmore Mud Specialist Panafax - Houston Office Logs Larry Airington Materials Coordinator Jim Magee Materials Coordinator (713) 669-7550 (281) 565-3140 (713) 669-21 98 (281) 261-5554 (713) 669-3754 669-3755 669-2975 Alaska Oil & Gas Conservation Commission Anchorage Office Fax Len Janson Kenai Office Jim Konst (907) 776-6027 (907) 776-6035 (907) 283-4057 (907) 776-6046 (907) 279-1433 (907) 276-7542 (713) 669-7020 (281)980-0336 PHILLIPS PETROLEUM COMPANY NORTH AMERICAN REGION VENDOR'S CHECK LIST Prepared By: P.R. Dean Date: January 06, 1998 Well: North Cook Inlet Unit B No. 1 ST AFE: P-V139 ITEM Company Telephone Casing Crews Weatherford 907--776-5531 Cement & Services Halliburton 907-344-2929 Cement Personnel Halliburton 907-344-2929 , Drilling Contractor Pool Artic Alaska 907-561-7447 ,, Electric Logs Schlumberger 907-336-2291 , Float Equipment & Centralizers Petro. Equipment 907-248-0066 (Weatherford) ,,, Mud & Chemicals Baroid 907-248-3511 Mud Engineer W. LeJuene / 318-856-7840 Ray Glenn / 601-649-5706 Jack Quinn 504-839-2074 Mud Logger Baker Hughes Inteq 907- 267-6600 .... , ,,, Wellhead Equipment & Service ABB Vetco-Gray 907-522-3940 Directional & MWD Service Anadrill 907-349-4511 Rental Tools (Drill String) Weatherford 907-776-5531 Adapter Spools DSR Rentals 907-522-3234 ....... ,,, Oil Base Cuttings Disposal Apollo Services 318-837-6961 Cuttings Hauling,Tank,etc. ...... Liner Hanger and Equipment Baker - Kenai - Turbulators Petro. Equipment 907--248-0066 (Weatherford) RECE]VED -8 998 Naska Oil & Gss Co~s. Commissio~ Anchorage PHILLIPS PETROLEUM COMPANY WELL PROGNOSIS DATE' May 14, 1997 AFE No. P-X047 PHILLIPS PETROLEUM COMPANY LEASE' NCIU-B Well No. I SURFACE LOCATION' Tyonek Platform Leg 1, Slot4: 1250' FNL and 979' FWL of Section 6-11, N-gw BOTTOM HOLE LOCATION: 1310' FSL and 1 860' FEL of Section 7-11N-gW FIELD NAME OR WILDCAT: North Cook Inlet Unit (NCIU) - Deep Appraisal Wiidca~ PROJECTED TD:- 15,840' MD and 13,262' TVD ELEVATION' RKB = 132 ft., Water depth: 100' @ MLLW) CONTRIBUTORS OR WORKING INTEREST OWNERS' Phillips Petroleum Company (Operator) 100% NEAREST AND SIGNIFICANT WELL CONTROL: Arco/Phillips'Sunfish #1 Section 12-11N-10W Pan Am'17589 State #1 Section 6-11N,gW Arco/Phillips N. Foreland #1 Section 13-11N-10W ANTICIPATED TOPS': Top ....., MD (ft.) TVD (ftc), TVDs'S (ft.) Cook Inlet ,"Stray" sand ,, 4000 3579 -3447 Upper BelUga 5103 4482 ,. -4350 -Tyonek ~Po,.~u. ch.~,.. ~.....d w~,h~. 250 91 20 7772 -7640 vertical feet below top of T¥onek) MGS 11,098 9392 -9260 "10,700' CoaI'' 12,673 10,682 -10,550 ,, _ "C" Sand 13,1 31 11,057 -10,925 Sunfish Sand 14,380 12,082 ~ I~¢~-11,950 N. Foreland Sand 15,11 6 1 2,682 -1 2,550. MUD LOGGING PROGRAM: - A computerized mudlogging unit will be on the well from base surface casing (+2500') TD. Mudlogs n~ed to be transmitted daily to PPCo offices in Kenai and Houston. SAMPLE PROGRAM: Cuttings: Samples will be collected every 30' from base of surface casing to top Tyonek. Samples will then be collected every 10' from this depth to TD. Sampling frequency may be adjusted at the wellsite geologist's discretion, or as permitted by well conditions. PPCO will require: 1. Two sets of washed and dried cuttings in 3"x5" envelopes. -- One set for the State of Alaska - -- One set for Phillips Petroleum Company 2. One set of washed, damp cuttings in viewing trays for the wellsite geologist. ARCO will require: 1. One set of washed and dried cuttings in 3"x5" envelopes. SPECIAL PRODUCTION PRACTICES: (Core, DST, Mud Logging Unit, Anticipated Pressure Breaks) Core Sunfish and N. Foreland 'sands as directed by wellsite geologist. Three to four 60' cores will be required. RECOMMENDED ELECTRICAL SURVEYS: MWD: MWD directional services will be in place from spud to TD. Resistivity and Gamma-Ray MWD will be required from 2500' to 4000' and from 9,000' to TD (hole conditions permitting).' LWD Resistivity and gamma-ray will be required from 9 5/8" casing shoe (est. 14,200' MD) to TD. WlRELINE: 0-4000': No openhole logs (unless more cost-effective than MWD) Run No. 1: 4,140' MD to 14,200' MD in 12 1/4" hole (oil-based mud) Array Induction and GR Compensated Neutron Litho-Density with GR and Caliper Long-spaced Sonic with GR and Caliper RFT (_+35 pressure points, no samples-'C-Sand, Beluga, C! Sands) Run No. 2: 14,200' MD to TD in 8 1/2" hole (oil-based mud) Array Induction and GR Compensated Neutron Litho-Density with GR and Caliper Dipole/Array Sonic with GR and Caliper MDT (Pressures in N. Foreland Sand and Sunfish Sands) OBDT (Dipmeter) '3 POTENTIAL COMP_LETION HORIZONS AND INTERVALS: Sunfish Sand N. Foreland Sand Tyonek 'C'-Sand (Primary Objective) (Primary Objective) (Secondary Objective) 14,380'-14,480' MD 15,116'-15,200' MD 13,130'-13,160' MD RECOMMENDED CASING PROGRAM: 20" Surface Casing 2500' MD 1 3 3/8" Intermediate Casing 4,140' MD 9 5/8" Intermediate Casing Est. 14,200' MD 7" Liner 15,800' MD PHILLIPS .NOTIFICATION: Geologist: Office Phone FAX Number · : Home Phone: Operations Supervisor: Office Phone Home Phone Pager Number Mobile Phone W. F. (Bill) Koerschner (713) 669-3521 (713)'669-3725 (281 ) 879-4863 Exploration Manager: Office Phone Home Phone Mobile Phone Page N~Jmber Erich Ramp (713) 669-7088 (713) 565-5110 (281) 906-6935 1-800-242-7217 Drilling Engineer: Office Phone Home Phone Paul Dean (713) 669-3502 Landman: Office Phone Home Phone D. A. (Deborah) Richardson (713) 669-3622 Prol~osed Logging Program NCIU B#1 (Tyonek Deep W.e!!) INTERVAL Sterling Disposal Sands (WATER BASE MUD) Cook Inlet Pay Sands, Beluga Sands & U Tyonek sands (PROBABLY OIL BASE MUD) Sunfish and North Foreland Sand (OIL BASE MUD) LOG JUSTIFICATION - GR/Induction -Used to correlate with offset wells to determine interval to perf for cuttings injection. Will use MWD or openhole wireline, whichever is least expensive. If 13 3/8" csg i~s~t deeper (below the Cook Inlet pay sands) the disposal zone wilJ liole, with the Cook Inlet Day sands Quad Combo: GR, Induction, Neutron, Density° long spaced sonic. RFT's (- 30 points) -Standard log suite for evaluation ofshallow pay interval. - Sonic will be used in conjunction with the deeper sonic run to generate a synthetic. -This log suite will also be adequate to evaluate the Tyonek "C'-Sand if Ihe 9 5/8" csg'is set this deep. - Most RFT's in Cook Inlet/Beluga; however, if "C" sand is included in this interval, we will need a few points in this zone to determine continuity with other wells and/or determine water contact. L WD - GR/Inductlon Quad Combo: GR, Induction, Neutron, Density, array sonic. Dipmeter MDT's (three zones -10 points) Cores in U. Sunfish, L. Sunfish and N. Foreland sands (est. three 60' cores ~} 90% recovery.) DST's In U, and L. Sunfish and in N. Forhland sands (2 tests) -Comparison of LWD resistivity with open-holo resistivity will indicate invasion (permeability). Also, near real-time stratigraphic data will allow for picking core points and accurate identification of coals ..... an important issue if the coals are washing out. -Standard log suite to correlate zones to offset ,,veils and provide a basis for rudimentary log evaluation. -Array sonic MAY provide information on permeability (if the Stoneley wave is recorded). Also, knowing thc stress orientations and rock properties ,,viii be beneficial when sidetracking and testing. -Dipmeter is necessary to insure that the sidetrack well targets the N Foreland sand. if there is significatat dip in the section and we do not have the dipmeter, we may find it difficult to intercept the sand in the sidetrack hole at the correct angle. -MDT's will provide accurate pressure data for reserves determination, reservoir continuitym and fluid gradient analysis. -Cores will help us determine how much ofthe reservoir la produetlvo. Tho eoro will also help in our continuing efforts to establish a relationship betwee.n 10g response and rock properties. Calibration ofthe logs to the core is critical to determining reserves and the optimal development plan. -DST's are Ihe only positive indication ofproducibility, as well as providing information about the continuity and extent of the reservoir. by: W F Koerschner, D N Tolman-Exploration: M L Kingsley, S M Hurst-Expioitation: G Z Schell, Reservoir Evaluation. 14.5 lb/gal Mud DIAGRAM XISTING CASING & CEM(' W'V(Make,Type,OD) ABB Vetco-Gray RKB-THF: ABB Vetco-Oray RKB-BHF: Annulus Fluid: 14.5 lb/gal mud RKB-MSL: 132.00 TOC: Tagged TOC (,,_~ 10,270' in 9 5/8" Casing Water Depth 130.00 Coil Structural Casing: Drive Pipe Conductor Casing: PPCo. Allowable Ratings 1410 Surface Casing: 2520 Intermediate Liner: 7500 Intermediate Tie-Back String 7500 Production Liner: Not Set i0-i 5-6- Tubinl (2 strings) 10240 CEMENTING PROGRAM 20"~2579' 2 Strings 2 3/8 "~3663' 13 318 "@3760' Cook Inlet 20" Conductor Cemented with 1690 sx H'burton Prenfium Cement with 3% gel + 0.50 % CFR-3 8/04/97 plus 1.0 % CaCI2 followed with 700 sx H'burton Premium + 2.0 % CaCI2 + 0.2 % CFR-3. Cement circulated to surface. 13 3/8 "Surface Cemented with 1234 sx H'burton Premium Cement wifl) 3% gel + 0.25 % CFR-3 8/09/97 pltLs 1.0 % CaCI2 followed with 672 sx H'bullon Premium + 2.0 % CaCI2 + 0.1% CFR-3. Cement circulated to surface. 9 5/8" Intem~ediate Liner Upper Beluga Lead Cemented with 2400 sx llalliburton Prcmiun~ Cement with 3% gel + 0.5% CFR-3 pi + 0.2 % HR-5. TOC (~ 3,588'. Tail Cement with 704 sx FI'burton Prenfium Cement with 0.20 % CF'R-3 Lower Beluga 9/06/97 '0.13 gal/sx Halad 344L + 0.13 % HR-5. TOC (~,~ 9,400'. 14.51b/gal Mud TOC @ 10029' 530' Comet;t 14.5 lb/gal Mud tTOC ~ TOC @ 14850' T, @ 15500 15,,500' Tyonek 9 5/8" @ MGS "c" Sand Sunfish Sand 14273-14453 No~h Forelands Sane 14972-15056 Plug No. I Plug No, 2 Plug No. 3 650' cement plug fi'om 15,500' to 14,850'. Not required to Tag. 261 sx Class "G" plus 0.2% CFR+0.08% Il R-5 (~ 15.8 lb/gal. 410' cement plug fi'om 14560'to 14,150'. Tagging Required. 282 sx Class "G" plus 0.2% CFR+0.08% IIR-5 ¢_}~) 15.8 Ib/o~al. Tagged Plug @ 13,564'. 530' cement plug fi'om 10800' to 10,270'. Tagging Plug Required. 535 sx Class "G" plus 0.2% CFR+0.08% IIR-5 (q') 17.0 lb/gal. Tagged Plug @ 10,029'. (Sidetrack Plug). The wellhead is capped with a Vetco-Gray 10M blanking flange with 10M valve. PBTD: 10,270 ]Supv: S'm'ton; Bab'n'eu]q'bg ~ .................................................................................... Well: North Cook Inlet Unit "B" No. 1 ~.~i.'iiii.i,i..'iii'.'.i~i .~.!ii!.~)~ii{~i?[.,i')??~i.'" ~iiiiii~ 71, Location: Tyonek I. I:~t form, Cook Inlet, Alaska Field: North Cook Inlet PRI:) , ~,:~I PROPOSED CASIN & CEMENT DIAGR , ,. i'! ':::':iii! 30"1~407' BPV,Make,TYpe,OD) ABB~' "~-~a'~ .......... ........................ ' - ':-?'. ~ OD [ Top ~ Bottom ~" ~ ~ -- Grad~ ....... [ .... (':;;~-~ .... ; ...... i,~'~;~'--~ Coil ~:~i~ ' ' Condu~or Casing: .... : ..... I;l'Co. Al~wable Ratings ...... :~:~ 20" ] 571 2.5791 133.0 lb/It [ K-55 _~_)3T&&2._.[ ......... _~6~.)} 5h'ii;; ......... Surfi~ce Casing~ _ 2~ Strings InternxMiate Liner: Disposal Peffs ~[ 2~'~3663' 95/8' ] 35881 10~3761 53.51b/R I P-II0 ] BT&C _._~_. 8710[ 9]qoi~-[ .... 3500-3540' ~j~ Intern~dia~ TieBack S~ing ~ ~:::. 95/8'I 531 3.588] 53.51b/tiI PdlO 1 Br&c.. 75I 87~[ ' ~}~}: Vrodut~on Liner: ~:~:~:~:~: ~ 13 3~ ' ~ 3760' , ~}~' ~ CEMENTING PROGRAM ~ Cook Inlet Sands ......... i .... , + 0.2 % C~-3. C~m~mt circulated to sudhcc. 8/09/97 plus 1.0 % CaCI2 follow~ ~ 672 sx H'bunon Premium + 2.0 % CaCI2 ~ Upper Beluga + 0. 1% CFR-3. Count circulated to sudhcc. " 9 5/8" ~t~iate Lin~ ................... L~ad C~nt~+ 0.2 % ~-5.~th 2400 SX~c ~llib~°n~ 3,588'. Pren~um ('chant ~ith 3% gel + O.5% CFR.3 pl;~ ............ .. ~{::~ Ta Taild ~th 7~ sx ~b~on ~um C~nt ~th 0.20 % CFR-3 ........... ................ ....................................................................... Tyonek Propose to: Set ?" Production Liner Ii-om I 1,100' to I?,000'. ~ ~ 9 5/8" ~ 10376' Will Cen~nt ~O~ 1200 ax ~0 %execs over gauge hole volume) Halliburton Class "C" Prenfium ~, ~ .~': ~fl~ 0.20 %CFR4 + 0,13 gal/sx [~lad 3~L + 0.25 %I111-5 nfixed ((~! 15.8 Ih/gal. ,"~ ~'.¢ MGS TOC to be at 11,100' ~op or Liner). 14.5 L~GAL ./ /, :1 ! ~ Toc ~ ~ ~ ~:~Plug~{~{~;~:{~ 14273- 14453 : 14972 - 15056 O 15500 Total Depth P9~: 16,¢00' ~Sup'~ .... ~W{: ....................................... Alaska 0il ,& Gas Cons. Coramissior Anchorage PHILLIPS PETROLEUM COMPANY NORTH AMERICA E & P DRILLING OPERATIONS WELL: APl NO. FIELD: North Cook Inlet Unit "B" No. 1 ST (Sidetrack of NCIU "B" No. 1) Permit No. North Cook Inlet Field LOCATION: Surface: BHL : WORKING INTEREST: AFE: BUDGET ITEM: GROSS AUTHORIZATION: OBJECTIVE: 1,249' FNL & 980' FWL Leg No. 1; Slot No. 6 2,513' FSL & 1,520' FEL Phillips Petroleum Co: P-V139 2A $ 8,398,000 COUNTY, STATE: NCIU Alaska AREA: Kenai, Alaska Sec. 6-T11N-R09W Sec. 12-T 11 N-R 1 OW 100.000000 % Re-Enter and Sidetrack the former North Cook Inlet Unit "B" No. 1 to a 17,000' MD (12,932' TVD) Development Location and Complete Same as a Producing Oil Well. DRILLING ENGINEER DRILLING ENGR. DIRECTOR DRILLING SUPERINTENDENT DRILLING MANAGER DATE DATE DATE DATE DISTRIBUTION: J. W. KONST N. P. OMSBERG (R) CENTRAL FILES W. L. CARRICO DEVELOPMENT SUPERVISOR (2) J. R. JACKSON (R) L.D. AIRINGTON L.G. JANSON W. B. VIA M. P. GATES POOL ARTIC ALASKA J. W. SPENCER P. R. DEAN (ORIGINAL) ORIGINAL(X) REVISION(I ) TIGHT HOLE: YES(X) NO ( ) Well Name: AFE No. AFE P-V1 39 Drill & Test Costs: Surface Location: 1,249' FNL & 980' FWL Sec. 6-T 11N-RO9W Bottom Hole Loc. 2,513' FSL & 1,520' FEL Sec. 12-T11N-R10W Depth: 17,000' MD 12,932' TVD AFE Days: 75 Rig: Unocal Rig 428 with Pool Artic Alaska manpower DRILLING PROGRAM suMM~,~.,V North Cook Inlet Unit B No. 1 ST Field: North Cook Inlet Unit Ty p e: 2B $ 8,398,000 Leg 1; Slot6 OBJECTIVE- Plug Back and Sidetrack the former Sunfish No. 3 to Test a 16,600' MD (1 3,732' TVD) Appraisal Structure 2000' West of the Original Exploration Well. CASING PROGRAM: Size]Depth MD (TVD) Wtlb/ft]GradelC°nnlBurstlC°llapselTensi°n]PSItest 30" 407' Drive Pipe 20" 2579' (2571') 133 K-55 BT&C 2860 1410 1700 13 3/8" 3760' (3521 ') 72 L-80 SL/X 4730 2520 761 NA 9 5/8" 10376' 53.50 P-110 BT&C 8710 7500 1159 5000 (8846') 7" Liner 17000' 32 P-110 BT&C 9960 10170 688 5000 (12932') 3.5" (Alt) 17000' 12.95 P-110 PH-6 14240 17470 232 8000 ..... Sec. I PROCEDURE SUMMARY 1. MIRU Unocal Rig No. 428 over Leg No. 1, Slot No. 6. ~ ¢,// 2. Install riser and 13 5/8" 10M BOP and Choke Manifold. Test BOP to 8000 psi. Install PVT equip. 3. TIH and wash cement to 10,200'. Pressure test casing to 5000 psi. 4. Drill out cement plug and drill to 10,386'. 5. Take FIT test to 16. Ppg EMW. Sec. II , , 9. 10. Drill an 8 1/2" hole with directional assembly to 17000' MD. Circulate and condition hole for logs. Log well with DIL/GR/Den/Neutron. as per Geological Prognosis. Run and cement 7" production liner (or 3 1/2" production casing ( 3 1/2" monobore tubing )). Clean out production liner to PBTD. Completion testing program will be planned based upon log evaluation. . , , o , 7, . ° DRILLING PROSPECTUS Location Phillips Petroleum Company's Tyonek Platform located in the North Cook Inlet of Alaska. Drilling will be from Leg No. 1, slot No. 6 ( See attached survey and schematics). Drilling Contract The drilling contract is a bare boat charter directly from Unocal for the use of the Rig No. 428. Pool Artic Alaska will provide the manpower and rig crews to install and operate the rig. Well Control Well control procedures will be in accordance with Phillips Petroleum Company's Well Control Manual and State of Alaska Oil and Gas Conservation Commission. Govermental Reporting Notify AOGCC (Blair Wondzell) @ (907) 279-1433 prior to moving rig and prior to spud. Special Considerations This section is intended to clarify and discuss special drilling situations that may occur. Be alert for these potential problems and ready to implement the appropriate contingent actions. Oil Base Mud will be used for the entire sidetrack operation and drilling the new hole interval from 10,376' to total depth of 17,000' (12932' TVD). (Refer to Oil Based Mud Handling Procedures - attached in mud program). All precautions will be taken to insure that no runoff is allowed. Proximity to Other Wells The referenced well will be kicking off from the existing wellbore at a depth of 10,376'. There are no other wellbores within 3,600' of this point, nor are any prognosed to be crossed at the planned trajectory. Shallow Gas There is no reason to expect a shallow gas hazard at the North Cook Inlet "B" No. 2, since the well has been drilled and cased. All BOP equipment will be installed and tested prior to drilling any cement plugs. COAL SEAMS Stuck pipe due to coal beds has been a frequent occurrence in this and other fields in the Cook Inlet, mainly when using WBM. Coal generally swells with WBM. These coals will be drilled throughout the well. The use of OBM with the use of the top drive has shown a reduction in the problems associated with coal. The coals may be fractured and have a tendency to cave into the well. A large chunk could result in mechanically sticking the drillstring. Mud weight and soltex have been used with some success to stabilize the coals. Raise mud weight as needed to control the coal seams. For OBM, gelsonite and/or Soltex should be used to lower HP/HT to 4 cc or less. 11. The penetration rate in the coals will be high. This can result in an attempt to drill a lot of fast hole. Experience in the Inlet shows that this fast hole may result in stuck pipe. The experience of the driller is important in avoiding this. The geologist and mud loggers can be helpful in predicting where coal seams may occur so the driller can be especially alert in areas where coal seams are about to be drilled. Control drilling rate through coal and determine if reaming is necessary. Make sure there is a backreaming cutter on bit if available. In the event the pipe does become stuck, spotting fluids have been successful in some cases in freeing the pipe where the mud was water based. The use of oil based mud should help in this regard. DIFFERENTIAL STICKING There are several sands in the 8 1/2" hole section that are expected to be normally pressured and permeable. If mud weight has been raised to stabilize the coal seams then these sands will present a risk for differential sticking. To minimize this keep the pipe moving as much as possible and minimize stabilized spiral HWDP and spiral DC's in OBM. During a fishing job on the Sunfish No. 2, even spiraI-wate drillpipe became differentially stuck. Efforts should be made to avoid directional corrections by sliding with a mud motor. Use lost circulation additives such as Barafiber or Steel Seal to reduce seepage losses and to minimize the risk of differential sticking. 12. HIGH BACKGROUND GAS The formations that will be drilled are gas saturated coal, sand, and silt. This will result in unusually high background gas readings. Mud weight should not be increased to suppress the high background gas. SECTION I: DRILLING PROCEDURE ( 9 5/8" CASING) - DEPTH 11,100' MD-RKB. A. GENERAL REMARKS - PREPARE WELL FOR SIDETRACK OPERATIONS 1. Intent- Clean out 9 5/8" intermediate casing and cement plug to 10,200'. Pressure test casing to 5000 psi. Drill ahead following directional program to new sidetrack location. 2. Wellhead Proaram- An ABB Vetco-Gray MB-189 Multi-Bowl wellhead is installed. Install 13 5/8" 10M BOP and riser system with adapter spool as necessary. 3. BOPE Reo. uirement$ ~nd Test Pressures 13 5/8" 10M BOPE is required. Test pressures are as follows: Initial Installation Rams: 7900 psi Annular: 3500 psi Weekly 5000 psi 2500 psi 4. Casing Pressure Test & Leak-off Test Pressure test 9 5/8" casing to 5000 psi prior to drilling out cement plug at intermediate show. After 1 O' of new formation is drilled, perform an Formation Integrity Test as per the PPCo. Well Control Manual to 16.0 lb/gal equivalent. Contact Drilling Superintendent if leak-off occurs before 15.0 ppg EMW. 5. Special Drilling Instructions A. Insure the following equipment is in place and fully operable prior to beginning drilling operations: a. b. C, d. e. Pit level monitor with audio and visual warning system. Mud return indicator. Gas detector with audio and visual warning system. Mud volume measuring device (trip tank, etc). Both mud systems are tied together and shut down detectors are fully functional and operating. B. Install a wear bushing before drilling to prevent wear in the casing head. .~ectiqn Ih 8 1/2" H01e (7" Casing) to 13,262'TVD 15,800' MD-RKB A, GENERAL REMARKS 1. Intent . . Drill an 8 1/2" hole from 9 5/8" intermediate casing through the Sunfish and North Forelands Sands to 12,932' TVD (17,000' MD). Log well as per the Geological Prognosis, with revision from Drilling Manager. If productive intervals are indicated, set and cement a 7" production liner. Lithologv and Anticipated Problems Continuation of the sand and shale with interbedded coal seams is prognosed. There is a pressure transition that occurs slightly above the Sunfish Sands at__+ 12,000' TVD,_,+ 15,200' MD,. Pore pressures may increase from 9.8 ppg to about 13.2 ppg during this transition. This abnormal pressure trend is expected to continue to TD. Actual mud weights could be as high as 14.5 ppg. Wellhead Proaram , The ABB Vetco-Gray MB-189 Multi-Bowl Wellhead is installed. with adapter spool as necessary. BOPE Reauirements and Test Pressures Install 13 5/8" 10M BOP and riser system . 13 5/8" 10 M BOPE is required. Test pressures are continued frome previous section as follows: Initial Installation Rams: 7900 psi Annular: 3500 psi Casin_~ Pressure Test & Leak-off Test Weekly 5000 psi 2500 psi Perform a Formation Integrity Test as per well control manual to an EMW of 16.0 ppg. (anticipated L/O -- 16.5 ppg EMW). Maximum anticipated mud weight in this hole section will be 14.5 ppg. Consider squeezing the shoe if the leakoff is less than 15.0 ppg EMW. Contact Drilling Superintendent if FIT leak- off occurs before 15.5 ppg EMW. 6. Directional Drillin..g In~tructi0n$- Follow directional drilling program. RIH w/8 1/2" PDC bit, steerable motor and BHA, including MWD. Drill the 8 1/2" hole, following directional plan, from kick off point at 10,400' RKB. With the steerable motor, slide and rotate to attain the 2.5 deg/100' azimuth change to the west. NOTE: BHA adjustments must be discussed with the Houston Office personnel. At kickoff point, begin sliding to kick well off per directional plan. Drill ahead, rotating and sliding as required to attain the proposed wellbore trajectory. This directional plan is based on a maximum azimuth change of 2.0°/100 ft. Dog leg severity in excess of 5°/100 ft could cause both drillpipe fatigue and excessive torque and drag. To minimize the potential for these problems THE DOG LEG SEVERITY CAN NOT BE PERMITTED TO EXCEED 3°/100 FT. Take MWD surveys every 30' throughout Build (azimuth angle change). RECEIVED 7. Special Drilling Instructions A, C. Install a wear bushing before drilling to prevent wear in the casing head. Drill ahead with motor and steerable assembly, maintaining angle and direction to the targets. To prevent differential sticking, keep pipe moving as much as possible, especially while making connections. Drilling Jars should be used in this section of the hole. Coring is not anticipated. It has not been requested by geological and reservoir personnel and has not been revised by Drilling Manager. At TD, circulate hole clean, C&CM for logging. B. PRILLING DETAILS ( 8 1/2" HOLE TO 16,600 MD-RKB) 1. Bottom Hole Assembly (Steerable Drilling Assembly) 8 1/2" PDC bit, Anadrill 6 3/4" 6 stage extended length performance motor, float sub, MWD/LWD equip., 2- 6 3/4" NMDC, 25 jts. 5" HWDP, Drlg. Jars, 5 jts. HWDP, Drill Pipe. BHA to be discussed and agreed with Houston office. 2. Bits. WOB. RPM IADC Bit Code: PDC Type WOB: 10 - 20 M RPM: 60 -150 Jets: 20-20-20-20 HycalogDS71 to begin, thenDS66orDS75. (or similar). As required for smooth drilling (drill on motor differential) 3. Hydraulics Maintain flowrate at 450 - 500 GPM. Maintain stable pump pressure.- 3600 - 4000 psi (with motor). Maintain good mud properties. Yield point should be as Iow as possible to keep the ECD as Iow as possible. 4. Mud Proaram Depth TVD 8846' - 12,932' (10376-17000' MD) i Weight PPG I Oil/Wtr PV I Ratio 12.5 -15.0 80120 I 35-40 85115 YP 15-20 IHPHT Fluid Loss 3-6 Mud Type Oil Base Invermul Continue program from previous section. Mud weight will need to be brought up to 14.0 right below the Sunfish Sands to determine if Sand can maintain integrity. Non progressive gels important. THESE ARE APPROX RHEOLOGICAL VALUES, and WILL VARY DEPENDING ON OWR & TYPE OF SUSP AGENTS. Survey Requirements and Deviation Restrictions A. Continue with directional plan, using MWD surveys for directional control. Samoling, Mud Logging. and Electric Logs A. Mud logging to be from 10,386'MD to 17,000' MD. B. Fax reports every morning to (713) 669-3754 by 5:30 (PDT) and follow with phone report at 06:00 a.m. Openhole logs from 10,400'-TVD (11,500' MD)to 13,700' TVD (16,600' MD): Array Induction / GR; Compensated Neutron / Litho-Density with GR and Caliper; Dipole Array / Sonic with GR and Caliper; MDT Tools, Dipmeter. Circulate and condition hole for logs. NOTE: See Attached Geological Prognosis 7. Coring A. No Cores Anticipated. Environmental A. Do not spill any Oil Mud. Insure that no mud escapes from platform area. If any accidents occur advise Houston Office Immediately. B. An SPCC plan is required on rig at all times. CASING AND CEMENTING DETAILS (7 " CASING) AT 12,932 TVD (17,000 MD-RKB) 1. Casing Specifications: (Top to Bottom) TVD PPCo Pw Torque Depth Description Burst Coll Ten Opt ft- Drift 10,100 - 7 "32 lb/ft 10270 10150 688 6.0" 17,000' MD P-110 BT&C Note: Air weight for this casing (liner) string is 221,000 lbs. . Float Shoe : Float Collar : Landing Collar & Loc : Centralizers : Connection Lock : Cementing Plugs : Circ, Mix, Displace Rate : W'ford Model 323 (PDC drillable). W'ford Model 402 Sure Seal - 1 joint above shoe. Baker Type II - 1 joint above float collar. W'ford 1-7' above shoe; next 2 joints w/collar stops; every second collar to 15,000'.; Every third joint to 10,400'. Use turbulator type (2 per joint) across N. Forelands and Sunfish pay intervals. Do Not Thread Lock Float Equipment, in the event liner does not reach bottom and has to be retrieved. Drill pipe and Liner Wiper Plugs only Maximum practical . Spacer : 10 bbls of Diesel/ 10 bbls HiVis FW (FIozan and barite) FV = 150. Mix at 14.5 ppg (actual mud weight). Actual volume TBA . First Stage Cmt Slurry Slurry Weight : Slurry Yield : Mix Water - Type : Pumping Time : Desired TOC : Compressive Strength : Calc 1200 sx Halliburton Premium + 0.20 % CFR-3 + 0.13 gal/sx Halad 344L + 0.13 % HR-5 15.8 PPG 1.15 Ft3/Sx 4.87 gal/sk. Fresh 3-4 hours 10,100' (use 20% excess in open hole interval) 24 Hours - 2140 psi. NOTE: ACTUAL CEMENT TO BE USED MUST BE LAB TESTED PRIOR TO SENDING SAME TO THE LOCATION. SPECIAL LINER CEMENTING INSTRUCTIONS Check to verify that all equipment required is in place and inspected for operation. Drill pipe must be rabbitted to 3" ID on last trip out of the hole. Have the following equipment made up and ready prior to the liner leaving the cased hole: A) 10' 15' drill pipe Pup joints. B) TD (Top Drive) Swivel with Totco baffle plate installed in box and Halliburton valve / chicksan swivel made up on circulating port in closed position. C) TD plug dropping head with drill pipe dart installed. D) Flag sub E) Run liner on drill pipe only. Use DP for required set down weight to set packer. Make up above assembly with TD unit to 20-22 K torque, then lay on pipe rack for quick access. B. Notify the AOGCC a minimum of 24 hours prior to the casing job. Co D° Go H, K. L. N, O, Do Not Baker Lock theW'ford Float Shoe and Float Collar on the first joint of casing. Install the Baker Landing Collar / ball catcher sub on the top of the 2nd joint. Do Not Baker Lock the Landing Collar. Make up third joint, then fill the casing with mud and pick up 40 - 60' to operate the float valves. The fluid should fall, but not refill as pipe is lowered back to the floor. Record torque values required to make up the Buttress threads to the diamond. This torque value will be used when calculating final liner rotational torque allowed. It is important that hole is not surged while running casing. Continue to pick up and run casing, filling as required with the fill-up tool. Use the collar clamp until sufficient weight is reached. The casing running speed should be 1 minute per joint, or less. Once the last joint is made up, change to DP elevators and pick up liner hanger assembly. Make up to proper torque and lower through the BOP stack. Make up three stands of drill pipe, then circulate one volume of the liner. Observe liner weight and continue in the hole, filling drill pipe every 5 stands. With liner shoe still inside casing at the 9 5/8" window, record torque readings to initiate rotation at 10, 20 and 30 rpm. This torque value will be used when calculating final liner rotational torque allowed. Continue running in the hole, filling drill pipe as above. Keep liner moving as much as possible in the open hole to minimize the chances for differential sticking. If necessary, the liner can be reamed into the hole. When liner is close to bottom, make up surface equipment and break circulation. Obtain good returns at 2-3 BPM, then slowly tag bottom. Pick up liner to setting depth (2-3' off bottom). Drop setting ball and let it free-fall (or pump slowly to ball seat on landing collar. Once ball is on seat, pressure up drill pipe per Baker representative to set hanger (+/- 15-1800 psi). Maintain pressure and slack off liner weight plus 15-20,000 lbs. Increase pressure on work string until HR Running Tool is released ( +/- 2100 psi). Pick up liner 4' and note loss of liner weight. If required, the HR running tool can be released manually by working left hand torque into the running tool. NOTE: Do not pick up more than Feet as the DOG sub .will exit the PBR. Continue to pressure up to shear out ball seat ( =/- 2900 psi). Set down 20-30,000 lbs on liner, then slowly initiate rotation (Maximum Torque = Casing Make-Up Torque + Torque of DP at shoe from Steps "D" and "E" above). Establish circulation. Bring circulation rates on up to 5-6 BPM (cementing rates, per Baker representative). Continue circulating and conditioning mud to PV required for cementing. When hole is conditioned, pump spacer and cement lineras per program. Release drill pipe pump down plug and displace with rig pumps at maximum rate until plug catches cement. Slow rates and watch for latch-up of drill pipe dart and liner wiper plug. A slight pressure increase should be noted as wiper plug leaves setting tool. Check displacement calculations from this point. Stop rotation when plug is 10 bbls from the shoe. Do not overdisplace. If plug bumps, pressure up to 1200 psi above circulation pressure. Hold for 5 minutes, then release pressure and test float equipment. If full circulation was maintained during the job, or cement is at least 1000' above the Sunfish Sand, pick up drill pipe to expose setting dog sub, then set back down with 60,000 lbs. Observe liner top packer shear. Hold weight for 5-10 minutes. Circulate out excess cement at maximum rate conventionally. POOH and lay down setting tools. NOTE: A Top Job may be performed on the liner if lost circulation was experienced during cementing and cement calculations indicate the top of cement is not adequately above the Sunfish Sands. In this case, Do Not Set Packer. If cement losses were experienced, pick up and circulate until the hole is clean. POOH, then RIH with setting tool (Or RTTS tool). Perform liner top squeeze and set packer. RECE]VE¢ Complete PPCO Gasing and Cementing Report and send to the Houston Office. JAN .... 8 1998 DRILLING FLUID PROGRAM Depth TVD 300'-2400' (2600' MD) Weight PPG Use pre-hydrated bentonite and extender flocculated in inlet water. Use all solids control equipment, keeping LGS below 6 % if possible. Sweep hole as needed with 50 bbl pills made up of 25 ppb gel and 1/2 ppb caustic in fresh water. Treat system with Drispac if seepage problems occur. Maximize pump rates to provide increased annular velocity. * NOTE Have funnel viscosity 50 - 70 sec/qt while drilling through gravel and when running casing. Depth TVD 2400 '-4000' (4500' MD) Weight PPG 8.8 - 9.2 40-5O Visc. I PH I PV I8.5-9.5' J 10-15 YP 15-25 Type J.6-10 J Water Base Continue use of conductor mud system. Use fresh water for make-up mud. Continue use of all solids control equipment, sweeping hole as needed with 50 bbl pills. Continue the PAC treatments. Use Kwik- Seal and BaroFibre for any losses or excess seepage. Maximize pump rates to provide increased annular velocity. Depth TVD J Weight PPG J Oil/WtrRatio PV ]YP J HPHT Fluid J Mud Type Loss 4000'-9300 9.5-10.0 70/30 10-30 < 20-25 3-5 Oil Base (11000' MD) 75/25 Invermul 9300-11900 10.0-12.0 80/20 25-35 15-20 3 - 5 Oil-Base (14200' MD) Invermul Drill out with 9.0 ppg mud. Use soltex for HTHP fluid loss control. Keep Iow gravity solids below 8 %. Increase mud weight as required below 9000', keeping a supply of Barofibre and Steelseal for potential seepage problems. It is very important to have flat gels, 10 for running pipe. Depth TVD JWeight PPG I 11,900' - 13,300' J 12.5 - (14200-15800' MD) J 15.0 I HPHT IMud Type Fluid Loss I 3-6 JOil Base Invermul Continue program from previous section. Mud weight will need to be brought up to 13.0 - 14.0 after coring the Sunfish Sands. Non progressive gels important. THESE ARE APPROX RHEOLOGICAL VALUES, and WILL VARY DEPENDING ON OWR & TYPE OF SUSP AGENTS. DRILLING FLUID PROGRAM Depth TVD 8,846' - 12,932' (10376-17000' MD) IWeightPPG Oil/Wtr IPV IYP IHPHT Ratio Fluid Loss IMud Type Oil Base Invermul Continue mud program from previous section. Mud weight will need to be brought up to 14.0 after cutting the Sunfish Sands. Non progressive gels important. THESE ARE APPROX RHEOLOGICAL VALUES, and WILL VARY DEPENDING ON OWR & TYPE OF SUSP AGENTS. SOLIDS CONTROL PROGRAM Refer to Intermediate and Production Hole Sections Rig Eauioment: Linear shakers - 3 Derrick Model 58 FIo-Line Cleaners Desander Pioneer Model T-86 with 8-6" cones Mud Cleaner Derrick with 16-4" cones Degasser Drilco See-Flow OBM Cuttings Handlin(~: Apollo Services will vacuum the drill cuttings to their catch tank. From there, the cuttings will be ground and disposed into the non-productive sands at a TVD of approximately 3300' TVD. Disposal will be down one of the two 2 3/8" tubing strings in the North Cook Inlet Unit "B" No. 1. Additional Eauipment Needed: 1) A dedicated steam cleaner is needed at the shakers to allow for screen cleaning at any time. 2) Coarse (e.g., expanded metal) cages will be installed over the pump intakes in the pits to prevent trash from fouling the valves. A dedicated pump capable of pumping liquids out of the cuttings catch tank back over the shakers will be furnished by Apollo Services. Use Pyramid Plus screens as the first 2 screens on the Derricks. The Plus feature is merely taller corrugations, which allows for more separation in the deep pool section of the shakers. NOTE: Ensure all equipment is fully operational before drilling ahead with oil base fluids. Install an operational pressure gauge on the hydroclone headers. Pressure should be 4 x MW in psi. Upgrade feed pump impeller if necessary. Be sure cones are clean and in spray discharge. Conductor and Sgrfoce HoI~: Use all rig solids control equipment. Run 210 mesh pyramids on the Derricks. Run desander and desilter on surface hole. Intermediate H01e: The goals during the OBM sections are to produce dry cuttings (to reduce cuttings slurry volumes), and yet keep Iow gravity solids (Igs) less than 8 vol% with existing rig equipment. In past wells, <8% Igs has been achieved using 210's on the Derricks. Again, the goal is to produce dry cuttings, even during upsets and startups with cold mud. During switch out to OBM, put coarse flat screens on Derricks (e.g. 80 mesh). After several circulations, start the Derricks with 140 mesh screens. Use Pyramid Plus screens on the first 2 screens, and a regular Pyramid on the last screen. Screen down to 210's in the same arrangement consistent with dry cuttings as soon as possible. A major goal is to produce dry cuttings. To prevent whole mud going over the shakers, it may be necessary to bypass the Derricks for the first half circulation after a trip into the hole. When the mud warms up, immediately switch back over the Derricks. Pump liquids that collect in the catch tanks back over the shakers. Lost circulation is possible at any time. It may be necessary to bypass the Derricks for a short time to allow bridging size LCM (e.g., sized calcium carbonate and Steel Seal) to build up in the mud to plug the problem zone. Return flow to the Derricks as soon as possible to prevent buildup of Igs. It is better to have to keep adding LCM than to let the Igs build up over 8 vol%. Production Hole: Continue with previous program. Lower pump rates may allow 250's on the Derricks. PRESSURE ANALYSIS Pore pressure predictions have been made based on the offset well information from other wells drilled in the area and the seismic data. The most important offset wells used in this analysis are the production wells on the platform for the shallow horizons, and the Shell North Cook Inlet State No. 1, Arco Sunfish No. 1, Arco-Phillips North Forelands State No. 1, and the Phillips-Arco Sunfish No's. 2 and 3 wells recently drilled. The interval above 7,800' TVD, 4- 9,300 MD will be the Cook Inlet and Beluga sands that are produced at the platform. The pressures in these sands have declined to a 5 - 6 ppg equivalent mud weight. Based on the results from the Arco Sunfish No. 1, the Arco-Phillips North Forelands State No. 1, the Phillips-Arco Sunfish No's. 2 and 3 and the workovers on the North Cook Inlet Unit Wells A-1 thru the A-13, lost circulation is not expected to be a problem despite the Iow reservoir pressures. Due to the lenticular nature of the Beluga formation, there is the possibility of encountering a Beluga sand at virgin conditions. Virgin pressure in the Beluga interval was 8.5 - 9.5 ppg. The geologic interpretation for the interval below 7800' TVD is that the formations and pressures should be similar to those encountered in the Arco Sunfish No. 1 and the PPCo. NCIU No. A-12 (formerly Cherryville A-15). The interval between 7800' TVD and the proposed 9 5/8" casing point at 11900' TVD, 14,200' MD is essentially normally pressured. This is the Middle Ground Shoal section with the 10,700' Sand and the Tyonek C Sand. Mud weights of 10.5 to 11.5 ppg are anticipated and will be dictated by the coal seams throughout this interval. There is a pressure transition that occurs slightly above the Sunfish Sands at 4- 12,000' TVD, 4- 14,300' MD,. Pore pressure will increase from 9.8 ppg to about 13.2 ppg during this transition. This abnormal pressure trend is expected to continue to TD. Actual mud weights could be as high as 14.5 ppg. I II II 1 D / / Depth (TV D) 0 OO'@' 1 -, - - - -,- - ,- - 2 - - - - @ 2511 , 3 - - - - - -- . - - - ~ 13 3¡6 /j!) - - 3520 4 , - 5 - - - - 6 - - - - -, . . . . . - . , . - . . . . . . . . Top of 9 . '. - - - ., .LI!J'i!f_@. 10016 95ffj"@, 10,100' 0046, 10 , . - - . ", - 11 : - - -. -. SUNFISH 12 - .,. - ,,' - NORTH 12932 13 fO.F!~Q$ .. 17000 14 - - - - . - - - . - . " - . - " " - " 15 -, " -, - - -. -,- " - " . - -, 16 - . . . - - - - - . . .. .... 17 - - - - . - .. ... , .. HI - - . - . - . . . . , . 19 . - .. ""'. - . . . . . -. .. - . 20 8 18 Mud Weigh!(ppg) - PROPOSED ~NCIU B1 - -Series 5 TEST - - - - S'Fish 2 -S'Fish 3 Flowline I Kill Line HCR Valve GateValve , 10M Blind Flange 10M Blind Flange 20" Mandrel Hanger 28" x 30" Swage 28" Structural Pipe 13 $/8" 5M BOP and Riser System Use while Drilling below 9 $/8" casing prd / January 05~, 1998 .......... Fill-up Line 13 5/8" 5M Annular Preventer 13 5/8" 10M Pipe or Variable Bore Pipe Rams 13 5/8" 10M Blind Rams Gate Valve HCR Valve I 13 5/8" 10M Rams Pipe Choke Line 13 5/8" 10M Riser 13 5/8" 10M Flange I V etco NT-2 10M Connector · Vetco JV1B-189 Multi-Bowl 10M Wellhead 2" Gate Valve 21 1/4" 2M Offset Adapter Flange (13 3/8" x 2 3/8" x 2 3/8") 21 1/4" 2M Adapter Flange 20" Casing PHILLIPS PETROLEUM COMPANY North Cook Inlet Unit "B" No. I PROCEDURE FOR DETERMINING PLAXI~ DOWNHOLE PRESSURE AND lw~AXI~ POTENTIAL SURFACE PRESSURE Maximum Downhole Pressure is determined from the pore pressure predictions of the interval to be drilled below the subject casing. The pore pressure predictions were made from offset well data and the seismic data. The maximum potential surface pressure is determined to be the lesser of the fracture pressure of the formation at the subject casing shoe less a fluid gradient to surface or the bottomhole pressure of the intervals to be drilled less the gradient of the fluid produced from the formation. Drilling Below 9 5/8" Intermediate: Frac Pressure = 16.4 lb/gal from MW / Casing Point Chart @ 10,400 kick-off (8,846 TVD) Max MW to Drill with = 14.5 lb/gal. BHP = MW * 0.052 * Depth Frac PSI @ Shoe = 16.0 lb/gal * 0.052 * 8846 = 7360 psi BHP from Mud Weight 14.5 lb/gal * 0.052 *8846 = 6670 psi Max Surface PSI before Formation breaks down is 690 psi Gas Gradiant Alternative BHP = 9700 psi from DST of N. Forelands No. 1 Max MW = PP / 0.052 / D~ 9700 / 0.052 / 12932 Max MW = 14.4 lb/gal Maximum Potential Surface Pressure is determined based on the pressure that would result from BHP less a gas gradient back to surface. The mud weight will be at least 0.5 ppg higher than the pore pressure gradient. MPSP = BHP - (gas gradient)(TVD) MPSP = 9700 - (0.15 psi/ft)(12932') = 7760 psi Anmdrf]! Schlumberger Ala6ka District Anchorage, AK 99538 {907} 349-{5LL Fax 344-2160 D3ilOJ~C~PIONA/~ Hm. LI, PLJkN for Piilbb[P.q ~'S~I'ROL, EU1W COMPANY Well ......... : NCIU-nlA (R02) F/eld ........ : Cook rnlet Computation..: t4inirmjm Curvature Units ........ : FBET Surface Lat..: 61.07675999 N S%Lrface LON9.: 150.9487794] ~ Legal Description ~lrface ...... : 4025 FSL 4049 PBD ~06 TiLN R09;; ~M Tie-in su~: 4632 PSh 2565 FEb S07 TI~ R09W SM LOCATIONS - ALASKA Zone; 4 X-Coord Y - Coord 331995.77 2586725.70 333424.58 2582032.36 3.30924.98 2580265.70 330019.57 2580090.6] 329401.0L 2579970.99 ANADp, ILL FEASIBILITY PLAN NOT APPROVED FOR EXECUTION PLAN Prepared ..... : 05 Jan 1998 Vert ae=t az.: 263.73 KB elevation.: 132.00 ft Hagne:ic Dcln: +22.126 (E) ~c~Le Factor.: 0.99993212 Convergence..: -~-83045450 PROPOSBD ~E~L PROFILE __ $~AT ~ON M~ASURED INCLR DI RECT£ON VERT [~- D~PT~ TIE-IN ~ 10278.00 36.80 L59.60 8761.97 8629.97 KO~/C~ 2.00/1~0 ~8300.~0 ~7.06 159.6~ 8779.55 8647.55 [0400.00 36.27 162.68 10500.OO 8HCTION DEPART COORDINA~iE~-~OM AI~SKA Zone 4 TOOL Db/ WELLH]/AD X Y FACE 100 -977.61 4672.46 ~ 1496.78 E 333424.58 2582032.]6 -980.8~ 4684.85 S 1501.39 H 333429.~0 2582~]9.90 1142 [.]7 474£.~4 ~ [520.70 E 333447.49 2581963.~5 ll2H 2.00 4797.78 ~ 153~.61 ~ 333462.58 258]906.49 ]~gR 2.00 4~54.11 $ ~549.09 ~ 333474.25 25~i849.98 10TH 2.00 30600.00 35.56 265.87 34.94 169.36 8859.77 8727.77 8940.77 8808.77 9022.44 8890.44 -993.87 -L003.52 -1009.78 10700.00 34.41 172.55 9104.68 10800.00 33.9g L76.03 9187.40 ~0900.00 33-65 179.57 9270.50 £LO00.O0 33.42 183.~7 9353.86 11100.00 33.29 186.80 9437.40 L3200.00 33.27 190.4~ 8972.68 -LOL2.64 4910.26 8 1558.L4 B 333482.48 2581793.71 3043~ 2.00 9055.40 -1012.10 4966.16 $ 1563.74 E 333487.27 2581737.74 [0IR 2.00 9138.50 -1008.16 5021.75 S 1565.88 E 333488.60 258L682.13 98R 2.00 9221.86 -1000.82 5076.95 S L564.56 g 333486.49 2581626.95 952 2.00 9305.40 ~990~10 513L.7l S 3-559.79 ~ 333480.92 2581572.28 922 2.00 9521.00 9389.00 -976.00 5185.94 8 155L.57 g 33347L.92 25815L$.L7 89R 2.00 m PRO[:OBED WELt. PROFiI[,W- STATION IDB~ITIFICAT D rRECiqON AZ EI/UTH 05 Jan 1998 Page 2 194.O8 197.69 201.26 204.76 208.18 11800.00 35.33 11900.00 36.00 12000.00 36.76 /2100.00 37.60 12200.00 38.51 VERTIC~-OBpT~ SECTION COORDINAT~$-FRfX,{ TVD SUB-SHA DEPART NELLHBAD 9604.58 9472.50 -958.55 5239.59 $ 1539.90 9688.02 9556.02 -937.76 5292.60 S 1524-81 9771.22 9639.22 -913.66 ~344..88 ~ L506.31 9854.08 9722.08 -886.28 5396.39 ~ 1484.43 9936.51 9804.51 -855.66 12300.00 39.49 12400.00 40.54 12500.00 4L.64 12600.00 42.79 12700.00 44-00 12800.00 45.25 12900_00 46.54 13000.00 47.86 13100.00 49.23 13200.00 50.62 ALASKA Zone 4 Y 333459.48 2581464.70 332443.62 2501411.92 333424.36 2581359.91 333~01.74 258L108.T'J 5447.06 8 145).18 E 3333~5.76 2581258.43 211.51 ~0018.40 9886.40 -821.&2 5496.83 S 1430.61 214-74 L0099.65 9967.65 -704.82 5545.64 ~ 139~.74 217.86 1OL80.16 i0048.16 -744.69 5593.42 ~' 1363.62 220.87 ]0259.84 £0~27.84 -70~-48 5640.13 B ~325.29 223-75 10338.58 10206.58 -6~5-26 5685.69 S ]283.79 L3300-00 52.04 13400.00 53.49 13500.00 54.97 13600.00 5~.46 13700.00 57.98 333346.47 2581209.09 333313.90 2581160.75 333278.L0 2581113.48 333239.09 25a1067.)4 333196.9% 2582022.39 TOOL DL/ PACE LO0 -- 86R 2 . 00 83R 2. O0 80R 2.00 77R 2.00 74R 2.00 226.53 10416.29 10284.29 -606.06 5730.07 8 1239.17 E 333151.69 2500978.67 229.18 10492.89 L0360.89 -553.96 5773.19 S 1191.50 B 333/03.40 2500936.24 231.72 L0568.26 10436.26 -499.02 58]5.02 S LL40-82 ~ 333052.13 2580095.15 234.15 L0642.33 105L0.33 -441.3L 5~55.50 S LO87.21 E 332997.93 2~80855.46 236.48 10714.99 ]0582.99 -380.89 5894.57 S 1030.7[ E 332940.88 2580817.2] 72R 2.00 69R 2.00 66R 2-00 64R 2. O0 62R 2.00 6OR 2.00 58R 2.00 S6'R 2.00 S~R 2.00 52R 2.00 23B.70 10986.18 10654.18 -317.83 5932.21 S 971.42 R 332881.0~ 2580780.44 $LR 2.00 240.83 L0855.78 10723.78 -252.23 5968.34 $ 909.38 H 332818.5~ 2580745.21 49R 2.00 2~2.87 10923.73 10T91.73 -104.14 6002.94 $ 844.69 E 322753.32 2580711.55 4ER 2.00 2~4.82 ]0989.94 L0857.94 -LL3.67 6035.96 S 777.42 g 332685.59 2580679.52 46R 2.00 246.70 11054.32 10922.]2 -40.89 6067.37 S 707.65 H 332615.37 2580649.13 45R 2.00 248.50 11L16.80 10984.80 34.1/ 6097.11 8 635.47 E 332542.77 2580620.44 44R 2.00 250.23 11177.31 /i046.31 L13.23 6125.~6 ~ 560.96 B 332467.88 2580593.47 43R 2.00 253.09 11235.76 11L03o76 190.39 6i51.~8 S 484.22 8 ~32390.77 2~580568.27 42R 2.00 2-53.50 11292.[0 11160_L0 271.4~ 6176.04 $ 405.34 E 332311.54 2580~44.05 43R 2-00 2~5.O5 11346.24 1121~.24 354.41 61_9~.$1 $ 324.~2 E 332230.30 2500523.26 40R 2.00 ~J',,ID 2.00/100 33800°00 59.51 1390Oo00 61.06 13915.06 63.30 (Anadrill (c)98 BIA~02 3-2b.5 1:35 PM P) 256.56 £3398.13 I1266.13 439.07 6239.77 ~ 241.55 E 332147.L4 2580503.51 4OR 2.00 258.01 1/447.70 11-315.70 525.37 6238.88 g 156.83 E 332062.16 2580485.63 39R 2.00 258.22 11454.96 11322.96 538.50 6241.60 $ 143-92 E 332049.21 2580483.L0 ~S 2.00 rDEiNT2 F1 CAT EOII .==~- TD L6272.10 6i.30 16990.42 61.30 PROPOSED ~gI.~ PROPII.~ DIRECT[ON VE RTI CAL-DEL>TRS AZ~/MUTH TVD 8U~-$EA ====; --- 258.22 [2882.00 11950.00 258.22 12082.00 11950.00 258.22 12082.00 11950.00 258.2~ 12587.00 12455.00 258.22 [2587.00 12455.00 258.22 12587.00 52455.00 258.22 12932.00 i2800.00 SgCTrOll ]678.35 [678.35 1678.1~ 2S96.34 2S96.35 2596.35 05 Jan [998 Page COORDINATES-PROM ALASKA Zone 4 TOOL Db/ WSbLi4EAD X Y FACZ 100 6475.28 S 977.12 W ])0924.98 2580265.?0 ~$ 0.00 6475.28 ~ 977.t2 W 330924.98 ~580~65.70 H8 0.OO 6475.28 S 977.T2 W 33092~.98 2580265.70 ~8 0.00 666~.48 S ~879.96 W 3300L9.57 2S80090.61 HS 0.00 6663.49 ~ 1879.97 W 33~019.57 2580090.61 ~ 0.0~ 6663-49 $ 1879.97 W 3300~9-57 2580090.6L H~ 0.00 6792-06 S 2496.76 ~ 329401-01 2579970.99 0.00 ANADR[LL AKA-DPC; FEASIBI!_!TY PLAN NOT APPROVED FOR EXECUTION PLAN ¢¢ ~ ~l {Anadr~.:~] (e)98 B/AP02 3.2b.5 L:35 PM ~') Z 01/0S/1B98 14'36 B07-344-2160 ANADRILL DPO PAGE 05 PHILLIPS PETROLEUM ! COMPANY - INL, IU-~ lA II-'U,dJ ,I I I VERTICAL SECTION VIEW - ' 'Section at: 263.73 TVD Scale,: J inch = J600 feet __ , Dep Scale.: ~ inch = j600 feet '. Drawn ..... · 05 Jan ~99B : -._ ~nadr~]] Schlumberger __ , Narker Identification MD BKB SECTN INCLN Al TIE-IN SURVEY ~0278 876E -978 36.8~ , 8) KOP/CURVE 2.00/100 10300 8780 -98~ 37.06 C) END 2.00/JO0 CURVE 13915 ~t~55 538 -- .- , ..... D) CURVE 2.00/100 ~5~21 1208~ 1678 81.30. E) SUNFISH TARGET 15~25 J2082 1678 F) END ~,O0/JO0 CURVE J6272 ~587 2596 61,30' _ G) N FORLAND TARGET 16272 ~2587 2596 G1.30~ " ' H) TD 36990 1293~ 3223 61,30:. , FEASIBILIT'f PLAN I .,_o ,! L , ,, , ,, ~ ~~ ..... , ,, ,,, ,, ,, , -3200 -2400 -i600 -800 0 800 :~600 2400 3200 4000 4800 5600 6400 7200 15:00 Sect ion Departure 90? :344 2160 98X P. 05 JRN-05-1998 16:45 ~07-344-21~0 ANADRI/L I)PO PA~E 0S I ' PHI"LLiPS' PET,R, OL,EUI ,, COMPANY .... i i i i i i i r ~ ,> ~oP/cu~v~.oo/~oo ~o~oo ,,,o -~,~ ~7.o~ VERTICAL SECTION VIEW · , O) CUAVE ~.00/100 ~5~2~ ~2082 ~678 6~.30 E) SUNFISH TARGET 15221 ~2082 ~678 6~.30 Section at: 263.73 F) END 2.00/t00 CURVE ~272 12587 2596 61.3O TVD Scale.' t inch ~ 800 feet G) N KO~A~ TARGET ~627e ~2~87 ~596 6~.~0 Dep Scale.' ~ inch : 800 feet H) TD ~990 I2932 3223 61,30 Drawn ..... · 05 Jan lggB 8400 , ' ~ '- ~nadr~ 11 Schlumberger _ i i .. i ,~ ~ , · . ~ ...... . ~ . ._ [ I xlOT APF'RO~ED F:OR tO800 .............. ' i''' ~0400 , --~ ' ' ~ ~ ,,, lOgO0 ...... ~ a~O0 ~ .......... "~ ~ 1600 ' ~ "' ; ~a~oo .... , . ~3800 " [ ............. ~000-,. ~ " . , , -1600 -~EO0 -800 -400 0 400 800 JgO0 1600 2000 2400 ~800 3~00 3600 , ,I P. 06 3RN-05-i998 16:45 909 344 2160 98Z 01/05/1BBB 14' 36 907-344-2160 ANADRILL DPC PHILLIPS PETROLEUM COMPANY Marker IdentifiCation Al TIE-IN SURVEY B) KDP/¢URVE 2.00/100 C) END 2.00/100 CURVE DJ CURVE 2.00/100 E) SUNFISH TARGET F) END 2.00/~00 CURVE G]N FORLAND TARGET H) TO MD N/S ]0278 4672 1497[ ~ t0300 4685~ ~§0] ~3915 6242 144 ,522, 6475~ 977 ~ ~522! 6~75 S 977 W ]6272 6663 S 1880 I6272 6663 S 1880 16990 6792 $ 2497 PAGE 87 NCIU-B A (PO2) PLAN VIEW CLOSURE ..... : 7236 feet at AZimuth 200.'~8 DECLINATION.: +22.]26 SCALE ....... : ] inch = ~200 feet DRAWN ....... : 05 Jan ]998 /nadr il], $chlu, mbsrger ; ..... ...... :'"" "'" ...... ' ....... :'" " ' .... :"; JAN-OS-1998 16:46 4200 3600 3000 2400 ]800 t200 600 0 600 1200 ~.800 2400 3000 3600 ,4 '00 <- WEST' EAST -> 907 344 2160 98X P.O? i i i ii iiii ii ii i /lnadri I] Sch]umber#er i i i i ii i i · i NCIU-BIA (PO2) PLAN VIE i ii i i i ii CLOSURE .... ' 7236 feet at Azimuth 200.t8 DECLINATION ' +22.126 (El SCALE. · I inch = 700 feet DRAWN. · 05 Jan 1998 i i i Marker Identi f ica[ tod A) liE-iN SURVEY ~0878 4672 S 1497 E B] KI]P/£tlRVE 8.00/100 10300 4685 S I59~ E C) END 2.00/100 ~R~E t39~5 6242 S 144 E D) CURVE 2.00/100 1522~ 6475 S 977 E) S~FISH TARGET ]522~ 6475 S 977 FI END 2.00/100 C~VE ~6272 6~3 S G} N F~L~NO TAROT 16272 H) TD ~6990 6792 i PHILLIPS i · ii i · ii ii i i PETROLEU' 4' ii i i i ii i · · · i~ ~11~ ~§i~ 900 l~50 i600 <- ~IESf · EAST -> i i iiii i i ii ii OMPANY ! ii 4900 C. fi I V i i i i I I ATTEN' i, c..~ K e--- 55 BS~ O£5AI~OER PIT 80 88L O~C~$SF.R PIT 105 BBL CEI, IT£IFUCE POWER UNITS CHARGE PU~P HOPPER /'ox CE. NTRIFUG .C PUMP~ ,?.A/VD TRAP UNOCAL RIG 428 MUD SYSTEM LAYOUT FUTURE CUTTINGS CONVEYOR 255 BBL ~255 BBL 90 BBL' VOL UME/'COMPLETION VOLUME PIT SUCTION PIT -:, PIT I , .t PHILLIPS' TYONEK PLATFORM 'MUD SYSTEM LAYOUT · WELL PERMIT CHECKLIST COMPANY FIELD & POOL /'~/: '~ INIT CLASS NAME / ~.~. -- . _ PROG, RAM: exp [] dev~ redrllll~ serv r-1 wellbore seg E: arm. disposal para req FI WELL GEOL AREA _~;~.~ ~:~ UNIT# /z/~--'~'~--,l ON/OFF SHORE C~/~J ADMINISTRATION APPR DATE 1. Permit fee attached ....................... ('Y_.¥,~N 2. Lease number appropriate ................... 3. Unique well name and number .................. 4. Well located in a defined pool ................. ~ 5. Well located proper distance from drilling unit boundary .... Y 6. Well located proper distance from other wells .......... 7. Sufficient acreage available in drilling unit ........... (~ N 8. If deviated, is wellbore plat included ............ N 9. Operator only affected party ................. (~ N 10. Operator has appropriate bond in force ............. (_3~) N 11. Permit can be issued without conservation order ........ Y (~ 12 Permit can be issued without administrative approval ...... (~-N~ 13. Can permit be approved before 15-day wait ........... REMARKS ENGINEERING GEOLOGY 14. Conductor string provided ................... Y N 15. Surface casing protects all known USDWs ........... Y N) 16. CMT vol adequate to circulate on conductor & sud csg ..... Y N 17. CMT vol adequate to tie-in long string to surf csg ........ Y N 18. CMT will cover all known productive horizons .......... (~N 19. Casing designs adequate for C, T, B & permafrost ....... C.Y~N 20. Adequate tankage or reserve pit ................. ~..,t 21. I! a re-drill, has a 10-403 for abandonment been approved .... ~N 22. Adequate wellbore separation proposed ............. 23. If diverter required, does it meet regulations .......... 24. Drilling fluid program schematic & equip list adequate ..... (~(~1~ 25. BOPEs, do they meet regulation ..... NN 26. BOPE press rating appropriate; test to ~ .... Psig 27. Choke manifold complies w/APl RP-53 (May 84) ........ 28. Work will occur without operation shutdown ........... 29. Is presence of H~S gas probable ................. Y DA~TE~ 30. Permit can be issued w/o hydrogen sulfide measures ..... Y 31. Data presented on potential overpressure zones ....... Y 32. Seismic analysis of shallow gas zones ............. ,,Y/"N 33. Seabed condition survey (if off-shore) ............. ,/Y N 34. Contact name/phone for we,ekly,progress repqrts ..... ~/. Y N lexp~oratory omyj GEOLOGY: RPC ENGINEERING: COMMISSION' JDt~" RNC~ CO Comments/Instructions:
