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Home My WebLink About199-111Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 10/27/2025 InspectNo:susGDC250903195720 Well Pressures (psi): Date Inspected:9/2/2025 Inspector:Guy Cook If Verified, How?Other (specify in comments) Suspension Date:6/26/2020 #320-250 Tubing:20 IA:80 OA:20 Operator:Hilcorp Alaska, LLC Operator Rep:Steve Soroka Date AOGCC Notified:8/31/2025 Type of Inspection:Subsequent Well Name:MILNE PT UNIT J-01A Permit Number:1991110 Wellhead Condition The wellhead was in good condition. It has a double swab tree only. No wellhouse protecting the well from the elements. Well guard in place. Surrounding Surface Condition Good clean gravel pad with no signs of hydrocarbons. Condition of Cellar Filled with water. No sheen to be seen. No trash or debris noted. Comments Well location verified by well-site pad map. Supervisor Comments Photos (8) attached Suspension Approval:Sundry Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Monday, October 27, 2025            2025-0902_Suspend_MPU_J-01A_photos_gc Page 1 of 4 Suspended Well Inspection – MPU J-01A PTD 1991110 AOGCC Inspection Rpt # susGDC250903195720 Photos by AOGCC Inspector G. Cook 9/2/2025 2025-0902_Suspend_MPU_J-01A_photos_gc Page 2 of 4 Tree Cap Pressure Gauge (Tbg Pressure) 2025-0902_Suspend_MPU_J-01A_photos_gc Page 3 of 4 IA Pressure Gauge OA Pressure Gauge 2025-0902_Suspend_MPU_J-01A_photos_gc Page 4 of 4 Well Cellar 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Ran Kill String Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Inspect 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 7,950 feet N/A feet true vertical 4,165 feet N/A feet Effective Depth measured 2,932 feet N/A feet true vertical 2,844 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 / EUE 8rd 3,536' 3,405' Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 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: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG Water-Bbl MD 105' 2,409' 3,640' TVD 105' Oil-Bbl measured true vertical Packer 2-3/8" 7,135' 7,709' Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: Representative Daily Average Production or Injection Data STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 199-111 50-029-22070-01-00 Plugs ADL0025906 / ADL0315848 5. Permit to Drill Number: Milne Point Field / Schrader Bluff Oil Pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Authorized Signature with date: Authorized Name: Abhijeet Tambe abhijeet.tambe@hilcorp.com Size MILNE PT UNIT J-01A 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.28 Gas-Mcf Casing Pressure Tubing Pressure N/A measured 3,623' 3,142' N/A Slotted Liner Slotted Liner Casing Conductor Length 105' 2,409' 3,640' Surface Production 13-5/8" 9-5/8" 7" 4-1/2" N/A 2,346' 3,502' 4,154' 4,161' 5,410psi N/A Burst N/A 7,240psi N/A 3,520psi N/A 777-8485 Hilcorp Alaska LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 2,020psi Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 12:12 pm, Jun 30, 2021 Chad Helgeson (1517) 2021.06.30 09:15:59 - 08'00' MGR30JUL2021 DSR-6/30/21 SFD 6/30/2021 4,141 RBDMS HEW 6/30/2021 SFD 6/30/2021 8,034 24 23 1 4 10 3 8 2 11 22 21 20 19 18 17 16 15 7 27 5 13 9 12 6 25 26 28 MILNE P OI N T J P A D Sec. 28 ADL25906 U013N010E MILNE POINT UNIT F B CL S EJ I KH A MINE CFP D G M MINE N S&K MOOSE PAD TEXACO MILNE POINT UNIT MPU J PAD LOCATION MAP Date: December 2020 Map Author: HAK - MRA Map 12 of 23 Map Center Coordinates: LAT: 70.451015 LON: -149.577931 NAD 1983 Decimal Degrees Map Imagery Date: 8/2020 (QSI) 1 inch = 125 feet 1500 FeetMap Scale 1: Well J-01A Suspended WellInspection Review Report !nspectNo: susGDC210627061154 Date Inspected: 6/27/2021 ' Inspector: Guy Cook ^ Type ofInspection: Initial ' VVeUName: k4|LNEPTUNIT ]-OlA ' Date AOG[ZNotified: 6/26/2021 ' Permit Number: 1991110' Operator: Hi|corpAlaska, LLC Suspension Approval: Sundry # 320'250 ' Operator Rep: Josh McNeal Suspension Date: 6/26/2020 Wellbore Diagram Avail? Location Verified? W ` Photos Taken? |fVerified, How? Other (specify incomments) Offshore? Ll Well Pressures (psi): Tubing: ` |A: OA: Wellhead Conditions A bit rusty and dirty, overall In good condition. Condition uJCellar Standing water with no signs of hydrocarbons. ,Surrounding Surface Condition Good dry gravel pad with no signs of hydrocarbons. 0 _ Fluid in Cellar? 40 - 8PV|nstaUed? [] 80 - VRP|ug(s)Installed? LJ Comments ` The well is protected only by a guard rail as the wellhouse has been removed and used for another well. Suggested at least wrapping the well toprotect itfrom the elements. The location was verified with apad map. Supervisor Comments Photos (5)attached ^ ��J Monday, August 2'Z0Z1 IA pressure gauge 2021-0627_Suspend_MPU_J-01 A_photos.docx Page 2 of 3 OA pressure gauge . It -V tL-- 13 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: _2 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: 2,622' SNL. 3,378' WEL, Sec. 28, T13N, R10E, UM Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): 1,127' SNL, 3,692' WEL, Sec. 28, T13N, R10E, UM GL: 35.2 BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 13-5/8"K-55 105' 9-5/8"K-55 2,364' 7"L-80 3,502' 4-1/2"L-80 4,108' 2-3/8"L-80 4,118' 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 Pet Eng N/A Oil-Bbl: Water-Bbl: Gas-Oil Ratio:Choke Size: Sr Res EngSr Pet Geo Flow Tubing Water-Bbl: PRODUCTION TEST Date of Test: Oil-Bbl: 54.5 36 105' Surface 3,640' Per 20 AAC 25.283 (i)(2) attach electronic information 26 7,135' Surface 3,383 Uncemented Liner7,709' 4,011' 12.6 551612.7621 552206.2342 TOP SETTING DEPTH MD Surface Surface GRADE suspension, or abandonment, 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 if necessary CASING WT. PER FT. 65.65' 393 sx Class 'G' 2,409' TOP Surface N/A CEMENTING RECORD 6016547.15 1,800 Approx SETTING DEPTH TVD 6019724.85 N/A 551939.4789 6015054.121 MILNE PT UNIT SB J-01A ADL0025906 / ADL0315848 Milne Point Field / Schrader Bluff Oil Pool 1,145 sx Permafrost 'E'12-1/4" 500 sx Permafrost 'C' Surface 8,034 / 4,141' 11/23/1999 8-1/2" BOTTOM HOLE SIZE AMOUNT PULLED 2,932' / 2,844' (SLM) 11/27/1999 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska LLC WAG Gas 6/26/2020 199-111 / 320-250 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): DEPTH SET (MD) 2,046' NSL, 3,075' WEL, Sec. 21, T13N, R10E, UM 4.7 50-029-22070-01-003800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PACKER SET (MD/TVD) 4,567' 4,837 MD / 4,035 TVD 30" 2-7/8" SIZE 3-3/4" 3,496' N/A 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, 97 sx Class 'G'6-1/8" TUBING RECORD 3,512' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Meredith Guhl at 11:26 am, Jul 14, 2020 RBDMS HEW 7/14/2020 Suspension Date 6/26/2020 HEW xG SFD 7/15/2020 DLB 07/14/2020 DSR-7/14/2020MGR16OCT2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 2,622' SNL. 3,378' WEL, Sec. 28, T13N, R10E, UM Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): 1,127' SNL, 3,692' WEL, Sec. 28, T13N, R10E, UM GL: 35.2 BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 13-5/8"K-55 105' 9-5/8"K-55 2,364' 7"L-80 3,502' 4-1/2"L-80 4,108' 2-3/8"L-80 4,118' 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 Pet Eng N/A Oil-Bbl: Water-Bbl: Gas-Oil Ratio:Choke Size: Sr Res EngSr Pet Geo Flow Tubing Water-Bbl: PRODUCTION TEST Date of Test: Oil-Bbl: 54.5 36 105' Surface 3,640' Per 20 AAC 25.283 (i)(2) attach electronic information 26 7,135' Surface 3,383 Uncemented Liner7,709' 4,011' 12.6 551612.7621 552206.2342 TOP SETTING DEPTH MD Surface Surface GRADE suspension, or abandonment, 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 if necessary CASING WT. PER FT. 393 sx Class 'G' 2,409' TOP Surface N/A 11/27/1999 CEMENTING RECORD 6016547.15 1,800 Approx SETTING DEPTH TVD 6019724.85 N/A 551939.4789 6015054.121 MILNE PT UNIT SB J-01A ADL0025906 / ADL0315848 Milne Point Field / Schrader Bluff Oil Pool 1,145 sx Permafrost 'E'12-1/4" 500 sx Permafrost 'C' Surface 7,950' / 4,165' 65.65' 11/23/1999 8-1/2" BOTTOM HOLE SIZE AMOUNT PULLED 2,932' / 2,844' (SLM) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska LLC WAG Gas 6/26/2020 199-111 / 320-250 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): DEPTH SET (MD) 2,046' NSL, 3,075' WEL, Sec. 21, T13N, R10E, UM 4.7 50-029-22070-01-003800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PACKER SET (MD/TVD) 4,567' 4,837 MD / 4,035 TVD 30" 2-7/8" SIZE 3-3/4" 3,496' N/A 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, 97 sx Class 'G'6-1/8" TUBING RECORD 3,512' Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Jody Colombie at 3:52 pm, Jul 13, 2020 Suspension Date 6/26/2020 HEW RBDMS HEW 7/14/2020 Superseded- TD incorrect Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 0' 0' 1,819' 1,815' Top of Productive Interval 4,692' 4,030' 3,742' 3,595' SBF2 - NA 4,090' 3,851' SBF1 - NB 4,141' 3,881' SBE4 - NC 4,202' 3,913' SBE2 - NE 4,263' 3,937' 4,461' 3,995' TSBD - OA 4,692' 4,030' OA OA 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Chad Helgesen Contact Name: Tom Fouts Operations manager Contact Email:tfouts@hilcorp.com Authorized Contact Phone:777-8393 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: 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). 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. 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. 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. TPI (Top of Producing Interval). INSTRUCTIONS Authorized Name: Authorized Title: Signature w/Date: Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS 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, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Asbuillt schematic & daily operations reports. Top Ugnu SBE1 - NF If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Permafrost - Top Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Chad A Helgeson 2020.07.13 14:58:41 -08'00' _____________________________________________________________________________________ Revised By: TDF 7/13/2020 SCHEMATIC Milne Point Unit Well: MPJ-01A Last Completed: 8/11/2015 PTD: 199-111 TD= 7,905’ TD= 8,034’ 4-1/2”Slotted Liner 2-3/8”Slotted Liner TD =7,950’ (MD) / TD = 4,165’(TVD) Window: 4,837’ to 4,843’ RKB Elev = 65.65’ AMSL (Nordic #3) RKB-THF: 35’ (Original RKB) 7” 2 3 & 4 9-5/8” “OA” Lateral PBTD =7,950’(MD) / PBTD = 4,165’(TVD) TIW Whipstock @ 4,835’ “OB” Lateral 13-3/8 ” 6 TOC @ 2,810’ 7 Fill Cleanout to 4,409’ on 8/10/15 Obstruction In 4-1/2” liner @ 3,648’ MD 5 1 TOC at 2,932 SLM Tagged 6/26/2020 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / K-55 / Welded 12.615” Surface 105' 9-5/8” Surface 36 / K-55 / BTC 8.921” Surface 2,409’ 7" Intermediate 26 / L-80 / BTC 6.276” Surface 3,640' 4-1/2” Slotted Liner A 12.6 / L-80 / IBT 3.958” 3,512’ 7,135’ 2-3/8” Slotted Liner B N/A / L-80 / N/A 1.995” 4,567’ 7,709’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992” Surface 3,536’ JEWELRY DETAIL No Depth Item 1 2,544’ 3-1/2” x 1.5” GLM – DGLV set 4/14/2020 2 3,505’ 3-1/2” EUE Tubing w/ Mule Shoe – Btm @ 3,536’ 3 3,496’ Baker 5” x 7” ZXP Packer (5.25” ID x 6’ tieback) 4 3,512’ Baker 5” x 7” HMC Liner Hanger (4.375” ID) 5 4,567’ 2-3/8” Slotted Liner Top w/ 3.70” Deploy Sleeve 6 4,682’ Baker HMCV Cementing Valve 7 4,704’ Baker CTC 20’ PZP ECP OPEN HOLE / CEMENT DETAIL 13-3/8”" Cmt w/ 500 sx Permafrost ‘C’ in 30” hole 9-5/8" Cmt w/ 1,145 sx Permafrost ‘E’ in 12-1/4” Hole 7” Cmt w/ 293 sx Class “G” in 8-1/2” Hole 4-1/2” Cmt w/ 97 sx Class ‘G’ in 6-1/8” Hole 2-3/8” Uncemented in 3-3/4” Hole WELL INCLINATION DETAIL KOP @ 1,500’ MD Max Hole Angle = 21.5 deg @ 3,250’ MD Hole Angle Slotted = 90 deg @ 4,810’ MD TREE & WELLHEAD INFO Tree WKM 3-1/8” 5M Wellhead 11” x 11” 5M Tubing Spool, 11” x 3-1/2” 8rd (Top & Bottom) w/ 3.0” ‘H’ BPV Profile GENERAL WELL INFO API: 50-029-22070-01-00 Drilled and Cased by Nabors 27E – 12/15/1990 RWO/ Multiple Frac Packs – 4/4/1995 ESP Replacement by Nabors 4ES – 2/21/1997 S/T & Comp. Nabors 4ES &Completion – 10/05/99 2nd Lateral 3S, Nabors $-ES & Nordic #3 – 5/27/2001 Replace ESP – Nabors 4ES – 8/20/2003 Replace ESP – Doyon 16 – 8/20/2003 Replace ESP – Doyon 16 – 4/24/2011 Replace ESP – Nordic 3 – 3/21/2015 Replace ESP – ASR 1 – 8/12/2015 Pull ESP/Run Kill String – ASR 1 – 4/05/2020 Suspend and Plug Back Production Interval – 6/26/2020 Well Name Rig API Number Well Permit Number Start Date End Date MPU J-01A Fullbore 50-029-22070-01-00 199-111 6/22/2020 6/26/2020 6/19/2020 - Friday No operations to report. 6/17/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 6/18/2020 - Thursday No operations to report. No operations to report. No operations to report. 6/20/2020 - Saturday Well shut in. MIRU Halliburton cement unit + LRS pump. Cement unit pressure test to 3,000psi high. Circulate preflush and diesel around down the tubing and up the IA to tanks. Squeeze 92 bbls 12 ppg cement into formation. Pump balanced plug with 10 bbls 15.8 ppg "G" cement (with foam wiper ball behind the cement) across tubing tail and IA with diesel in tubing above the cement. Estimated TOC at 3308' MD. Diesel from surface to 3308' in the tubing and the IA (pumped by LRS). Final T/I/O pressures were 365/5/0 psi. RDMO. 6/23/2020 - Tuesday 6/21/2020 - Sunday No operations to report. 6/22/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MPU J-01A Fullbore 50-029-22070-01-00 199-111 6/22/2020 6/26/2020 No operations to report. No operations to report. 6/27/2020 - Saturday No operations to report. 6/30/2020 - Tuesday 6/28/2020 - Sunday No operations to report. 6/29/2020 - Monday 6/26/2020 - Friday WELL S/I ON ARRIVAL, NOTIFY PAD OP & FILL OUT PERMIT, PT PCE 250L/2500H. DRIFT TBG W/ 2.33" CENT, 1.75" SAMPLE BAILER & TAG TOP OF CEMENT @ 2932' SLM, WITNESSED BY AOGCC REP, RECOVER SAMPLE OF CEMENT. LRS COMPLETE MIT-T TO 1500psi, Tbg PASSED & IA PASSED),Witnessed by Austin McCloud. JOB COMPLETE. 6/24/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 6/25/2020 - Thursday No operations to report. MEMORANDUM TO: Jim Regg (� ZffLl7 P.I. Supervisor FROM: Austin McLeod Petroleum Inspector Section: 28 Township: Drilling Rig: NA Rig Elevation: Operator Rep: Jeff Jones Casing/Tubing Data Conductor: 13 5/8" 0. D. Shoe@ Surface: 95/8" O. D. Shoe@ Intermediate: NA 0. D. Shoe@ Production: 7" 0. D. Shoe@ Slotted Liner 1: 4 1/2" 0. D. Shoe@ Slotted Liner 2: 2 3/8" 0. D. Shoe@ Tubing: 31/2" 0. D. Tail@ Plugging Data: Test Data: State of Alaska Alaska Oil and Gas Conservation Commission DATE: June 26, 2020 SUBJECT: Well Bore Plug & Abandonment Milne Point Unit J -01A Hilcorp Alaska LLC PTD 1991110; Sundry 320-250 13N Range: 10E Meridian: Umiat ' NA Total Depth: 8034 ft MD ' Lease No.: ADL025906 - 105 Feet 2409 Feet NA Feet 3640 Feet 7135 Feet 7709 Feet 3536 Feet Suspend: X 2932ftMD'I 6.8 ppg IP&A: 7905 ft MD - 160 IA Casing Removal: Csg Cut@ NA Feet Csg Cut@ NA Feet Csg Cut@ NA Feet Csg Cut@ NA Feet Csg Cut@ NA Feet Csg Cut@ NA Feet Tbg Cut@ NA Feet Tvpe Pluq Founded on Depth (Btm) Deoth (Too) MW Above Verified Fullbore I Bottom I 8034 ft MD • 2932ftMD'I 6.8 ppg I Wireline tag 7905 ft MD - 160 IA Initial 15 min 30 min 45 min Result Tubing 1746 1624 1598 - 160 IA 0 0 0 P ✓ OA 0 1 0 0 OA Initial 15 min 30 min 45 min 60 min Reciilt Tubing 173 - 175 - 168 160 151 , 1663 - IA 1659 1587. 1549 1521 1497 - F OA 0 0 0 0 0 Initial 15 min 30 min 45 min Result Tubing 122 - 146 - 139 IA 1663 - 1532 - 1509 P ✓ OA 0 0 0 Remarks: Cement plug for suspension was pumped on 6/22/2020. Proposed top of cement was 3,300 ft WLM (236 ft above the tail). With the — 225 pound, 1-3/4" sample bailer slickline string, they tagged top of the plug at 2,932 ft WLM (inclination 20 degrees & 3.2 barrels high). Multiple tags were made. A passing tubing pressure test was done 1500 psi. The tool string was rigged down and cement was found in the bailer. Inner Annulus (IA) pressure test #1 FAILED at —10 min interval, falling below 1500 psi. Pressure was bumped up for retest - ran 60 minutes with sub par stabilization (FAIL). I requested bleed to zero and start over. PASS on the third attempt, but it appeared to me on probably all three tests they were compressing or slightly moving the top of the cement in the IA. Pressure tests were close to the allowable 10% decline. Bottom depth of the plug in above plugging data ✓ refers to each lateral. Other Lease No. ADL 0315848. Attachments: none x/ rev. 11-28-18 2020-0626_Plug_Verification_MPU_J-01 A_am.docx 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Cement Plugback 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,034'3,648' Casing Collapse Conductor 1,130psi Surface 2,020psi Production 5,410psi Slotted Liner N/A Slotted Liner N/A Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: Wyatt Rivard Operations Manager Contact Email: Contact Phone: 777-8547 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 2,409'2,364'3,520psi wrivard@hilcorp.com COMMISSION USE ONLY Authorized Name: Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025906 / ADL0315848 Tubing Grade:Tubing MD (ft): 3,623'4-1/2"7,135' C.O. 477.05 MILNE PT UNIT J-01A N/A Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY 4,154' N/A 2,409' 9-5/8" 3,502' 4,161' 3,640' 199-111 Anchorage Alaska 99503 50-029-22070-01-00 Hilcorp Alaska LLC Length Size 3800 Centerpoint Dr, Suite 1400 105'13-5/8" 7" 2-3/8" 9.3 / L-80 / EUE 8rd TVD Burst 3,536' MD 2,730psi MILNE POINT / SCHRADER BLUFF OIL 4,141'7,135'4,108'1,560psi 7,709' 105'105' Perforation Depth MD (ft): 3,640' 3,142' 7,240psi 6/24/2020 3-1/2" N/A and N/A See SchematicSee Schematic N/A and N/A N/A Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Chad A Helgeson 2020.06.11 10:18:05 -08'00' By Samantha Carlisle at 12:44 pm, Jun 11, 2020 320-250 Suspended DSR-6/11/2020 MIT-IA and MIT-T to 1500 psi Tag TOC in tubing X * Wellsite inspection requried within 1 yr of suspension per 20 AAC 25,110(e) SFD 6/11/2020 10-407 Suspend gls 6/12/20 Comm. 6/16/2020 dts 6/15/2020 JLC 6/15/2020 RBDMS HEW 6/18/2020 Reservoir P&A Well: MPU J-01A Date: 02/14/2020 Well Name:MPU J-01A API Number:50-029-22070-01-00 Current Status:SI Pad:Milne Point J-Pad Estimated Start Date:June 24 th, 2020 Rig:SL & Cement Reg. Approval Req’d?No Date Reg. Approval Rec’vd:N/A Regulatory Contact:Tom Fouts Permit to Drill Number:199-111 First Call Engineer:Wyatt Rivard (907) 777-8547 (O) (509) 670-8001 (M) Second Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) AFE Number:2051015 WellEZ Entry Required:Yes Current Bottom Hole Pressure: 1,960 psi @ 4,000’ TVD (Gauge Reading 1/28/20 EMW = 9.42 ppg) Maximum Expected BHP: 1,960 psi @ 4,000’ TVD (Gauge Reading 1/28/20 EMW = 9.42 ppg) MPSP: 1,560 psi (0.1 psi/ft gas gradient) Max Deviation:21 deg in motherbore, laterals 88-93 deg below 4800’ MD. Max Sand face Treatment Pressure:2700 psi Brief Well Summary The Milne Point J-01A well was sidetracked in December 1999 as a Schrader Bluff OA producer with a slotted 4- 1/2” liner in open hole. In 2001, an additional Schrader Bluff OB lateral was CTU sidetracked with a 2-3/8”, uncemented, slotted liner. In spring 2020 the ESP completion was pulled in preparation for reservoir abandonment but communication with the reservoir could not be established. The well was left with a 3-1/2” packer less tubing string down to 3536’ MD to facilitate cleanout. In May 2020 a Coil cleanout was performed from 3652’ MD to 4538’ MD, reestablishing reservoir communication with 2.5 BPM injectivity at 640 psi. Notes Regarding Wellbore Condition x Casing was last tested to 1,500 psi for 30 min down to 3,577’ on 3/20/2015. Casing also held 1600 psi with no pressure drop during 4/6/2020 RWO indicating 7” casing currently has integrity. x Uppermost “open” slots in liners are at 4623’ MD (2-3/8” OB) and 4810’ MD (4-1/2” OA lateral) Liner Volumes: x 4-1/2” OA Liner & 6-1/8”OH= 3623’*.0152bpf + 900’*.038bpf = 55 bbls (liner)+30 bbls (OH) = 85 bbls x 2-3/8” OB Liner & 3-3/4”OH = 3142’*.0039bpf +200’*.014bpf = 12.5 bbls (liner) +3 bbls (OH) = 15.5 bbls x Previous Schrader Bluff FIT/LOTs in this area of the field ranged from 12-14 ppg. Objective: Pump fullbore cement job of OA and OB laterals using existing 3-1/2” packerless tubing string. Sundry Procedure (Approval Required to Proceed: Cement Reservoir Abandonment 1. Rig up cement unit to the tubing and PT to 2000 psi 2. Circulate at least 130 bbls source water and 1 drum of baraklean at max rate down the tubing while taking returns off the IA to a tank to ensure system is fluid packed and tubulars clean. a. Tubing Volume = 3536’*.0087bpf=31bbls b. Annular Volume = 3536’*.0264bpf = 93bbls n May 2020 a Coil cleanout was performed from 3652’ MD to 4538’ MD, reestablishing reservoir communicationyp with 2.5 BPM injectivity at 640 psi. The well was left with a 3-1/2” packer less tubing string down to 3536’ MD to facilitate cleanout. Brief We Reservoir P&A Well: MPU J-01A Date: 02/14/2020 c. Record Circulating Pressure (CP) for use during downsqueeze. 3. Close in the IA ahead of downsqueeze to ensure cement confined to formation. 4. Pump the following down the tubing at an initial maximum of 1000 psi over CP dropping to 300 psi over CP as a full hydrostatic column (at least ~40 bbls) of cement is established. ***Note: Cement volumes based on casing and liner volume estimates only. Actual volumes pumped may vary. Aggregate may be added to cement based on injectivity response.*** i. 30 bbls of surfactant preflush ii. 100 bbls of 12 ppg cement. iii. 10 bbls of 15.8 ppg class G cement 5. With 15.8 ppg class G cement away, pump a foam wiper ball and begin to displace tubing with 29 bbls of diesel. 6. Once 23 bbls diesel away, open up and take returns off the IA for final 6 bbls of displacement. a. Resulting final cement top should be ~3300’ MD in tubing and IA 7. RD cementers ***Contingency*** If cement injectivity is lost prior to full displacement: 8. Increase injection pressure up to max of 1000 psi over CP to account for higher than expected friction pressure. 9. If still no injectivity, discontinue pumping cement and proceed to displace tubing with ~20 bbls of diesel while taking returns to IA. a. Resulting TOC should be ~ 2500’ in Tubing and IA Slickline And Hot Oil Plug Verification 10. Notify AOGCC at least 24 hrs prior to plug pressure testing and depth verification. 11. MIRU SL unit and Hot Oil 12. Pressure test to 300 psi low and 1500 psi high 13. RIH with drift and tag cement plug, estimated at 3,300’ MD 14. MIT-T tubing to 1500 psi and chart for 30 minutes 15. Swap over and MIT-IA to 1500 psi and chart for 30 minutes 16. RDMO Attachments: 1. As-built Schematic 2. Proposed Schematic MIT-T tubing to 1500 psi and chart for 30 minutes . Swap over and MIT-IA to 1500 psi and chart for 30 minutes TAG TOC MIT-IA and T Notify AOGCC at least 24 TOC planned at 3300 ft RIH with drift and tag cement plug, estimated at 3,300’ MD _____________________________________________________________________________________ Revised By: STP 4/07/2020 SCHEMATIC Milne Point Unit Well: MPJ-01A Last Completed: 8/11/2015 PTD: 199-111 TD= 7,905’ TD= 8,034’ 4-1/2”Slotted Liner 2-3/8”Slotted Liner TD =7,950’ (MD) / TD = 4,165’(TVD) Window: 4,837’ to 4,843’ RKBElev =65.65’ AMSL (Nordic #3) RKB-THF: 35’ (Original RKB) 7” 2 3 & 4 9-5/8” “OA” Lateral PBTD =7,950’(MD) / PBTD = 4,165’(TVD) TIW Whipstock @ 4,835’ “OB” Lateral 13-3/8” 6 TOC @ 2,810’ 7 Fill Cleanout to 4,409’ on 8/10/15 Obstruction In 4-1/2” liner @ 3,648’ MD 5 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / K-55 / Welded 12.615” Surface 105' 9-5/8” Surface 36 / K-55 / BTC 8.921” Surface 2,409’ 7" Intermediate 26 / L-80 / BTC 6.276” Surface 3,640' 4-1/2” Slotted Liner A 12.6 / L-80 / IBT 3.958” 3,512’ 7,135’ 2-3/8” Slotted Liner B N/A / L-80 / N/A 1.995” 4,567’ 7,709’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992” Surface 3,536’ JEWELRY DETAIL No Depth Item 1 2,544’ 3-1/2” x 1.5” GLM – DGLV set 4/14/2020 2 3,505’ 3-1/2” EUE Tubing w/ Mule Shoe – Btm @ 3,536’ 3 3,496’ Baker 5” x 7” ZXP Packer (5.25” ID x 6’ tieback) 4 3,512’ Baker 5” x 7” HMC Liner Hanger (4.375” ID) 5 4,567’ 2-3/8” Slotted Liner Top w/ 3.70” Deploy Sleeve 6 4,682’ Baker HMCV Cementing Valve 7 4,704’ Baker CTC 20’ PZP ECP OPEN HOLE / CEMENT DETAIL 13-3/8”" Cmt w/ 500 sx Permafrost ‘C’ in 30” hole 9-5/8" Cmt w/ 1,145 sx Permafrost ‘E’ in 12-1/4” Hole 7” Cmt w/ 293 sx Class “G” in 8-1/2” Hole 4-1/2” Cmt w/ 97 sx Class ‘G’ in 6-1/8” Hole WELL INCLINATION DETAIL KOP @ 1,500’ MD Max Hole Angle = 21.5 deg @ 3,250’ MD Hole Angle Slotted = 90 deg @ 4,810’ MD TREE & WELLHEAD INFO Tree WKM 3-1/8” 5M Wellhead 11” x 11” 5M Tubing Spool, 11” x 3-1/2” 8rd (Top & Bottom) w/ 3.0” ‘H’ BPV Profile GENERAL WELL INFO API: 50-029-22070-01-00 Drilled and Cased by Nabors 27E – 12/15/1990 RWO/ Multiple Frac Packs – 4/4/1995 ESP Replacement by Nabors 4ES – 2/21/1997 S/T & Comp. Nabors 4ES &Completion – 10/05/99 2nd Lateral 3S, Nabors $-ES & Nordic #3 – 5/27/2001 Replace ESP – Nabors 4ES – 8/20/2003 Replace ESP – Doyon 16 – 8/20/2003 Replace ESP – Doyon 16 – 4/24/2011 Replace ESP – Nordic 3 – 3/21/2015 Replace ESP – ASR 1 – 8/12/2015 Pull ESP/Run Kill String – ASR 1 – 4/05/2020 _____________________________________________________________________________________ Revised By: STP 4/07/2020 PROPOSED Milne Point Unit Well: MPJ-01A Last Completed: 8/11/2015 PTD: 199-111 TD= 7,905’ TD= 8,034’ 4-1/2”Slotted Liner 2-3/8”Slotted Liner TD =7,950’ (MD) / TD = 4,165’(TVD) Window: 4,837’ to 4,843’ RKB Elev = 65.65’ AMSL (Nordic #3) RKB-THF: 35’ (Original RKB) 7” 2 3 & 4 9-5/8” “OA” Lateral PBTD =7,950’(MD) / PBTD = 4,165’(TVD) TIW Whipstock @ 4,835’ “OB” Lateral 13-3/8” 6 TOC @ 2,810’ 7 Fill Cleanout to 4,409’ on 8/10/15 Obstruction In 4-1/2” liner @ 3,648’ MD 5 1 Est. TOC at 3300’ MD CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / K-55 / Welded 12.615” Surface 105' 9-5/8” Surface 36 / K-55 / BTC 8.921” Surface 2,409’ 7" Intermediate 26 / L-80 / BTC 6.276” Surface 3,640' 4-1/2” Slotted Liner A 12.6 / L-80 / IBT 3.958” 3,512’ 7,135’ 2-3/8” Slotted Liner B N/A / L-80 / N/A 1.995” 4,567’ 7,709’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992” Surface 3,536’ JEWELRY DETAIL No Depth Item 1 2,544’ 3-1/2” x 1.5” GLM – DGLV set 4/14/2020 2 3,505’ 3-1/2” EUE Tubing w/ Mule Shoe – Btm @ 3,536’ 3 3,496’ Baker 5” x 7” ZXP Packer (5.25” ID x 6’ tieback) 4 3,512’ Baker 5” x 7” HMC Liner Hanger (4.375” ID) 5 4,567’ 2-3/8” Slotted Liner Top w/ 3.70” Deploy Sleeve 6 4,682’ Baker HMCV Cementing Valve 7 4,704’ Baker CTC 20’ PZP ECP OPEN HOLE / CEMENT DETAIL 13-3/8”" Cmt w/ 500 sx Permafrost ‘C’ in 30” hole 9-5/8" Cmt w/ 1,145 sx Permafrost ‘E’ in 12-1/4” Hole 7” Cmt w/ 293 sx Class “G” in 8-1/2” Hole 4-1/2” Cmt w/ 97 sx Class ‘G’ in 6-1/8” Hole 2-3/8” Uncemented in 3-3/4” Hole WELL INCLINATION DETAIL KOP @ 1,500’ MD Max Hole Angle = 21.5 deg @ 3,250’ MD Hole Angle Slotted = 90 deg @ 4,810’ MD TREE & WELLHEAD INFO Tree WKM 3-1/8” 5M Wellhead 11” x 11” 5M Tubing Spool, 11” x 3-1/2” 8rd (Top & Bottom) w/ 3.0” ‘H’ BPV Profile GENERAL WELL INFO API: 50-029-22070-01-00 Drilled and Cased by Nabors 27E – 12/15/1990 RWO/ Multiple Frac Packs – 4/4/1995 ESP Replacement by Nabors 4ES – 2/21/1997 S/T & Comp. Nabors 4ES &Completion – 10/05/99 2nd Lateral 3S, Nabors $-ES & Nordic #3 – 5/27/2001 Replace ESP – Nabors 4ES – 8/20/2003 Replace ESP – Doyon 16 – 8/20/2003 Replace ESP – Doyon 16 – 4/24/2011 Replace ESP – Nordic 3 – 3/21/2015 Replace ESP – ASR 1 – 8/12/2015 Pull ESP/Run Kill String – ASR 1 – 4/05/2020 8,034' 4,141' 8,034' 4,141' MDG 7/14/2020 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Ran Kill String Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ESP Pull 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 7,950 feet N/A feet true vertical 4,165 feet N/A feet Effective Depth measured 7,950 feet N/A feet true vertical 4,165 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 / EUE 8rd 3,536' 3,405' Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 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: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG 0 Water-Bbl MD 105' 2,409' 3,640' TVD 105' 0 Oil-Bbl measured true vertical Packer 2-3/8" 7,135' 7,709' Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 3000 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 199-111 50-029-22070-01-00 Plugs ADL0025906 / ADL0315848 5. Permit to Drill Number: Milne Point Field / Schrader Bluff Oil Pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-080 0 Authorized Signature with date: Authorized Name: Stan Porhola sporhola@hilcorp.com Size 0 MILNE PT UNIT SB J-01A 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 300 Casing Pressure Tubing Pressure 0 N/A measured 3,623' 3,142' N/A Slotted Liner Slotted Liner Casing Conductor Length 105' 2,409' 3,640' Surface Production 13-5/8" 9-5/8" 7" 4-1/2" N/A 2,346' 3,502' 4,154' 4,161' 5,410psi N/A Burst N/A 7,240psi N/A N/A 777-8412 Hilcorp Alaska LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 2,020psi3,520psi Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Chad A Helgeson 2020.05.04 18:20:51 -05'00' By Samantha Carlisle at 3:32 pm, May 04, 2020 DSR-5/4/2020gls 5/4/20 gls RBDMS HEW 5/5/2020 Note: Attempted to suspend well. Not successful (obstruction) _____________________________________________________________________________________ Revised By: STP 4/07/2020 SCHEMATIC Milne Point Unit Well: MPJ-01A Last Completed: 8/11/2015 PTD: 199-111 TD= 7,905’ TD= 8,034’ 4-1/2”Slotted Liner 2-3/8”Slotted Liner TD =7,950’ (MD) / TD = 4,165’(TVD) Window: 4,837’ to 4,843’ RKB Elev =65.65’ AMSL (Nordic #3) RKB-THF: 35’ (Original RKB) 7” 2 3 & 4 9-5/8” “OA” Lateral PBTD = 7,950’(MD ) / PBTD = 4,165’(TVD) TIW Whipstock @ 4,835’ “OB” Lateral 13-3/8” 6 TOC @ 2,810’ 7 Fill Cleanout to 4,409’ on 8/10/15 Obstruction In 4-1/2” liner @ 3,648’ MD 5 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / K-55 / Welded 12.615” Surface 105' 9-5/8” Surface 36 / K-55 / BTC 8.921” Surface 2,409’ 7" Intermediate 26 / L-80 / BTC 6.276” Surface 3,640' 4-1/2” Slotted Liner A 12.6 / L-80 / IBT 3.958” 3,512’ 7,135’ 2-3/8” Slotted Liner B N/A / L-80 / N/A 1.995” 4,567’ 7,709’ TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8rd 2.992” Surface 3,536’ JEWELRY DETAIL No Depth Item 1 2,544’ 3-1/2” x 1.5” GLM [Open Pocket] 2 3,505’ 3-1/2” EUE Tubing w/ Mule Shoe – Btm @ 3,536’ 3 3,496’ Baker 5” x 7” ZXP Packer (5.25” ID x 6’ tieback) 4 3,512’ Baker 5” x 7” HMC Liner Hanger (4.375” ID) 5 4,567’ 2-3/8” Slotted Liner Top w/ 3.70” Deploy Sleeve 6 4,682’ Baker HMCV Cementing Valve 7 4,704’ Baker CTC 20’ PZP ECP OPEN HOLE / CEMENT DETAIL 13-3/8”" Cmt w/ 500 sx Permafrost ‘C’ in 30” hole 9-5/8" Cmt w/ 1,145 sx Permafrost ‘E’ in 12-1/4” Hole 7” Cmt w/ 293 sx Class “G” in 8-1/2” Hole 4-1/2” Cmt w/ 97 sx Class ‘G’ in 6-1/8” Hole WELL INCLINATION DETAIL KOP @ 1,500’ MD Max Hole Angle = 21.5 deg @ 3,250’ MD Hole Angle Slotted = 90 deg @ 4,810’ MD TREE & WELLHEAD INFO Tree WKM 3-1/8” 5M Wellhead 11” x 11” 5M Tubing Spool, 11” x 3-1/2” 8rd (Top & Bottom) w/ 3.0” ‘H’ BPV Profile GENERAL WELL INFO API: 50-029-22070-01-00 Drilled and Cased by Nabors 27E – 12/15/1990 RWO/ Multiple Frac Packs – 4/4/1995 ESP Replacement by Nabors 4ES – 2/21/1997 S/T & Comp. Nabors 4ES &Completion – 10/05/99 2nd Lateral 3S, Nabors $-ES & Nordic #3 – 5/27/2001 Replace ESP – Nabors 4ES – 8/20/2003 Replace ESP – Doyon 16 – 8/20/2003 Replace ESP – Doyon 16 – 4/24/2011 Replace ESP – Nordic 3 – 3/21/2015 Replace ESP – ASR 1 – 8/12/2015 Pull ESP/Run Kill String – ASR 1 – 4/05/2020 Well Name Rig API Number Well Permit Number Start Date End Date MP J-01A ASR#1 50-029-22070-01-00 199-111 3/31/2020 4/5/2020 Blow down Kill Manifold trailer. ND Tree, NU BOP. Move in and rig up Well House and Rig Floor. Conduct Safety Meeting with Night Crew. Review Sundry for upcoming well J-01. Conduct Fluid checks. Prep for BOP test. Crew moving in test joints, work string to be used for cleanout run and kill string. Move in and secure stairs. Spotting equipment and heaters, RU and winterize lines. Torque Flow-T and spacer spools on Annular. Move in primary mud pump and rig up hoses. Torque Flow-T and spacer spools on Annular. Move in primary mud pump and rig up hoses. Troubleshoot and make repairs to test pump - plastic liner was in several pieces. Pressure up on Accumulator lines in preparation to function test BOP. Leak at HCR. Inspect, leaking hydraulic fluid. Retrieve backup HCR from tent at A-pad, swap out valve. Reinspect all flanges for proper torque. Apply pressure, all good. Function test BOP components, all good. Conduct BOP Body test to 250psi low / 2,500psi high. Continue with BOP test. Test with 2-7/8" and 3-1/2" test joints to 250psi low / 2,500psi high. BOP Configuration: Blind / Shear Rams, 2-7/8" x 5" Variable Bore Rams, 11" Annular. No operations to report. 3/28/2020 - Saturday No operations to report. 3/31/2020 - Tuesday 3/29/2020 - Sunday No operations to report. 3/30/2020 - Monday 3/27/2020 - Friday No operations to report. 3/25/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 3/26/2020 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP J-01A ASR#1 50-029-22070-01-00 199-111 3/31/2020 4/5/2020 4/1/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Morning Safety Meeting, Daily Plan Forward. Discussed hazards of pressure testing and performed Sundry Review. Begin Shell test and found gland nuts leaking on well head. Tightened and re-attempted shell test. High test leaking off. Trouble shoot and attempt to find leak path. Continue to troubleshoot and annular failing to open. Troubleshoot and find water in hydraulic "close" or return line for opening annular. Remove hydraulic fitting from annular and relieve hydraulic pressure and annular opened immediately. Suspected failed wellbore fluid seal on annular and called Yellow Jacket who confirmed failed seal. Prep to replace 11" annular with 13-5/8" annular. Start breaking down hydraulic lines and blowing them out with air. Inspect Accumulator - tank appears ok and not water flooded. Heated hydraulic hoses and blow out with air, pull floor panel on rig floor, start breaking bolts on 11" annular. Discussion from town and decision made to attempt to clean out 1100' of slotted liner w/ 2-3/8" PH-6 tubing . Will require addition of a single gate BOP to stack w/ 2-3/8" rams . Continue to Rig down ASR floor to add single gate BOP and 13-5/8" annular. Will also BOP test w/ a 2-3/8" test mandrel. Conduct Safety Meeting with night crew to discuss change to current BOP configuration and change in plan to well cleanout. Prepare to Derrick Down, remove pins, lower Derrick. ND 11" Annular, having difficulty with bolts. Remove floor, crane out Annular. Crane in 2.-3/8" Single Door ram body and 13-5/8" Annular. NU and torque components. Swap out Pressure / Return hydraulic hose for Annular. RU remainder of hydraulic hoses. Re-install rig floor, raise and secure Derrick. Fluid pack lines, prepare for BOP test. 4/2/2020 - Thursday Morning Safety Meeting and daily plan forward. Discussed hazards of changes in scope as in this well. Not to get frustrated with having to swap out equipment and rig down and re-rig back up. Continue w/ N/U of BOPE and torqueing all flanges. Install 13-5/8 x 11" DSA and install flow spool and flow-line. Re- purge BOP lines to the annular. Start to test BOP's. attempt shell test and losing pressure- begin troubleshooting leak-off. Pressure up to 2,500psi and inspect all connections - no visual leak. Isolate kill side of at well head and pressure to 2,500psi and no leak off. Isolate choke side of wellhead and pressure up and no leak off. Shut blinds and pressure up and pressure fall off. Re-tighten lock down screws and pressure to 2,500psi no loss. Continue with BOP testing . Test with 2-3/8", 2-7/8"" and 3-1/2" test mandrels. Test Blinds, pipe rams, annular, all choke /kill valves, TIW and IBOP for 250 low test and 2,500psi high test. Holding all tests for 5 minutes. Tested all LEL, and Gas Detectors, Pit level alarms. Found Leaking Gland Nut on Wellhead test 2 tightened -good test. Found HCR not holding on Test 3. Cycled valve and greased - Held Good. Safety Meeting with night crew. Emphasis on pressure testing, opening up to well. Change out crews, conduct fluid checks. Continuing with the BOP test joint with test #4, #5, and #6 with 2-3/8" test joint to 250psi low / 2,500psi high. All good tests. Line up for test #7 of Annular with 2-3/8" test joint, no go. Double check all lines, inspect tree, ensure everything lined up properly. Observe bubbling and flow above Annular at flow line to pits. After several unsuccessful tests with 100+psi pressure bleed in ~1 to 1-1/2 minutes, prepare to attempt test with 2-7/8"" test joint. Reinspect all lines again, look for leaks. Swap out test joints. 5 successive fails but taking more time with ~100psi pressure loss over 2 minutes or more. Again observe bubbling and slight flow of fluid above Annular. Have team swap out to 3-1/2" test joint to give it a last test chance while calling to find an Annular. Found two elements in Milne. Call Yellow Jacket, only replacement is in Kenai. Coordinate to get Shaffer element picked up and taken to A-pad tent to begin warming up. Well Name Rig API Number Well Permit Number Start Date End Date MP J-01A ASR#1 50-029-22070-01-00 199-111 3/31/2020 4/5/2020 Hilcorp Alaska, LLC Weekly Operations Summary 4/3/2020 - Friday Morning Safety meeting, Daily Plan Forward. Discussed hazards of pressure testing, not getting frustrated and taking chances to trying to get a good test. P/U 2-7/8" test mandrel, attempt pressure test on 13-5/8" annular with 2-7/8" test mandrel to 2,500psi. Increased hydraulic pressure on annular to 1,500psi (max). Annular leaked off 400psi in 10 minutes. Closed pipe rams on 2-7/8" test mandrel and opened annular. NO other valves manipulated. Pressure tested pipe rams on 2- 7/8" mandrel to 2,500psi with no leak off indicating annular not holding pressure. Locate back-up 11" annular in DeadHorse. Start to N/D 13-5/8 " annular and arrange trucking for 11" annular. N/D flow spool and flowline, remove spacer spool and pull 13-5/8" annular, New 11" annular on location. N/U new 11" annular, spacer spool and flow spool and flowline. Purge hydraulic lines and hydraulic chamber on new annular. Test new Annular to 250psi low / 3500psi high per AOGCC requirement for new equipment. RD from testing BOP equipment. Load rig tongs onto rig floor. Safety meeting with night crew. Discuss current operations, plan for the evening. Emphasis on working with pressure, opening to well, initial actions after releasing hanger. Conduct fluid checks. RU tongs, function test. Complete loading equipment onto rig floor. Offload fresh water from pits, take on 9.8 ppg Brine into pits. RU sheave for spooling ESP. Fluid pack all lines, circulate through MGS. Load 290 bbls brine from storage upright tank to truck and line up to pits. Dress out slips, check hydraulics, function test. Conduct walk through Well Control drill. Check for pressure, pull BPV from hanger. No pressure. Break circulation down tubing, immediate returns. Pull hanger up and space out in Annular, pick up weight of 27k. Slight vacuum as hanger is pulled. Break circulation across top, immediate returns, well static. Pull and lay down hanger and landing joint. POH and lay down 2-7/8"" tubing and GLM #1. Continue to POH with tubing. Well Name Rig API Number Well Permit Number Start Date End Date MP J-01A ASR#1 50-029-22070-01-00 199-111 3/31/2020 4/5/2020 Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. Morning Safety Meeting, Daily plan forward. Discussed hazards of pulling pipe, handling clamps on floor, and keeping thick oil cleaned form pipe as pulling . Fluid checks on all equipment. Rig beginning to fill new coolant reservoir installed last week indicating possible head gasket leak. Continue to POOH w/ 2-7/8" EUE tubing unclamping control line and cap string. and wiping off heavy oil. ESP at surface, inspect and find small amounts of corrosion. Lay Down ESP wiping off thick heavy oil. Clean floor from heavy thick oil, lay down ESP control line sheave, elephant trunk. Move out pulled 2-7/8" EUE tubing and put in pipe tub. Move in 2-3/8" PH6 tubing for clean out run, swap out pipe handling equipment from 2-7/8" to 2-3/8". Rig crew had to rig up to pull BOP stack over ~6-8 inches in order to align stack up with carriage for pipe make-up. Start make up BHA consisting of 3.750" roller cone bit with hole drill out to make a full throat bit and jets removed. 2-3/8" reg x 2-3/8" reg bit sub, and 2-3/8" reg x 2-3/8" PH-6 X-over. 35 joints 2-3/8" PH-6 tubing. BHA length 1127.99'. Begin swapover of make-up and handling equipment from 2-3/8" to 3-1/2". Safety meeting with night crew. Discuss current running operation and plan forward, emphasis on wind picking up, proper torque on drill pipe, contingencies for cleanout run. Change out crews, check equipment and fluids. Continue to RIH with 3.75" rollercone bit BHA on 2-3/8" PH6 x 3-1/2" drill pipe workstring. Hydraulic hose on tongs has pinhole leak. Cannot make proper torque on drill pipe with pinhole leak in hydraulic hose on tongs. Change out hose with one on location. Attempt to make up torque, this hose also leaks. Send Floorhand back to A-pad to make a replacement hose. Swap out hoses, function test. Continue with making up 3-1/2" drill pipe and RIH with 3.75" rollercone bit BHA on 2-3/8" PH6 x 3-1/2" drill pipe workstring. Hold pre-job with crew on getting cleanout parameters (circ pressures, free rotating torque, PUW, SOW). RU hoses to swivel, blow air through to ensure all clear. SOW above liner top 23k, PUW 27k, Torque of 650-700 at 60 rpm, Circ pressure 375psi at 2 bpm, 580psi at 3 bpm. Move down with work string into 4-1/2" liner top at 3,496' md (joint 60 of 3-1/2" tally). Beginning PVT 248 bbls. Break circulation, Power Swivel leaking. Slowly RIH with workstring. Nothing noted on jt 60. Bury jt 60, grease Washpipe. Make connection, move down with jt 61, no tag. Make up jt 62 and begin cleanout at 36' in on jt 62, 3608' md (3,624' adjusted RKB). SOW dropping to as low as 9k, Rot Torque up to .8-1.0k, Circ pressure remaining consistent at 300psi at ~3 bpm. Bury jt 62, PU and circ bottoms up before next jt. MU jt 63, move back down. Engage at 60 RPM, 3 bpm. Washpipe still leaking. Consistent pump pressures at 300-350psi, torque ranging .7-1.1k. Take more significant weight and applied torque at 3,648' md, 3,664' adjusted RKB depth. SOW dropping to 10k, torque up to 1.3-1.7k, circ pressure remaining consistent at 320-370psi. Stacking out at 3,648' with no progress. Total sand recovered - 1 pint. Fine sand pic on o-drive. Pick up work string clean, circulate bottoms up with full returns of 9.8+ ppg Brine, no losses to formation. Washpipe leaking quite a bit more. Continue with ill h h l k ff l lli Cl d i d d B llh d @ 1 600 i 4/4/2020 - Saturday No operations to report. 4/7/2020 - Tuesday 4/5/2020 - Sunday Morning Safety Meeting, Daily Plan Forward, - Discussed hazards of laying down pipe, complacency in work place. Fluid checks on all equipment. Continue to POOH w/ 3.5" x 2-3/8" tapered string and 3.750" tri- cone bit. Filling hole w/ single displacement of 9.9 brine. Hole full and well static. Swap out handling equipment from 3.5" to 2-3/8" an start laying down 2- 3/8" PH-6 tubing. Filling hole w/ single displacement of 9.9 brine. Hole full and well static - 2-3/8" PH-6 connections breaking out very hard. Connections very tight. Crew having to warm up every connection to break out. Inspect bit and no unusual marking. Recovered small amount of fine sand from jet ports on bit. Move out 2-3/8" PH-6 Workstring and move in 3.5" 9.3# EUE L-80 tubing. Tally pipe and swap tubing handling gear. P/U and start RIH w/ 3.5" muleshoe / WLEG assembly on 3.5" EUE L-80 tubing. Installed GLM at ~2,550' w/ no valve to allow for freeze protect circulation. Well Static. Continue to RIH w/ 3.5" EUE tubing. Conduct trial run for spaceout - tag up and measure for spaceout. Conduct Safety Meeting with evening crew, discuss landing and RDMO operations. Swap out crews. Check fluids and equipment. Swap out handling equipment for landing joint and crossovers for hanger, torque connections. Drain stack. Pick up and land hanger, PUW 30k, SOW 23k. Run in lockdown screws, lay down landing joint and install BPV. Well Secure. 4/6/2020 - Monday Run Kill string. obstruction at 3648' THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU SB J -01A Permit to Drill Number: 199-111 Sundry Number: 320-080 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.oIoska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, er .Price Chair DATED thiso2 oday of February, 2020. 'jBDMSjAj FEB 241010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED FEB ' Z/027 (ZO A®GCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑✓ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑✓ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ESP Pull Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 199-111 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-22070-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No D MILNE PT UNIT SB J -01A 9. Property Designation (Lease Number): $a rfiiic0 110. Field/Pool(s): ADL0315848 ' AkL 0627106 Milne Point Field / Schrader Bluff Oil Pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,034 4,141 7,135 4,108 1,348' .- N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 105' 13-5/8" 105' 105' 2,730psi 1,130psi Surface 2,409' 9-5/8" 2,409' 2,364' 3,520psi 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psi 5,410psi Slotted Liner 3,623' 4-1/2" 7,135' 4,154' N/A N/A Slotted Liner 3,142' 2-3/8" 7,709' 4,161' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5# / L-80 / EUE 8rd 3,469' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A and WA N/A and N/A 12. Attachments: Proposal Summary ✓ Wellbore schematic ✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 3/2/2020 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑✓ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. S�p Authorized Name: Chad Helgeson Contact Name: Stan Porhola Authorized Tide: Operations Manager Contact Email: S orhola hilcor .com Contact Phone: 777-8412 Authorized Signature: Date: 2/12/2020 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity �] BOP Test/Mechanical I.Test El Location Clearance ❑ Gnnt-e'grity p n Other: ?SOD OSS :J�1 /Qs! � 1<. T"r /I.T I , � c�„t-r� t,a: f� �ti 1 '� �j �'>• �� se�L Z6 A -4L 2Cil r Post Initial Injection MIT Req'd? Yes ❑ No ❑ �' �'�'FEB 2 4 2020 Spacing Exception Required? Yes No Q% Subsequent Form Required:r3BDM5 {❑] APPROVED BY Approved by: ll��ttV✓.. COMMISSIONER THE COMMISSION Date: 9O 4�W6dll A -� 1 ed p r � �Mhsl M IIEV % ( Submit Form and F 10A0 (/ Approved application i94alid dfa, I1lh5�Ffbrdt111/ELate of approval. Attachments in Duplicate � $fta%ao n enru Alueku, LILC RKB Elev= 35' Milne Point Unit Well: MPJ -01A SCHEMATIC Last Completed: 8/11/2015 PTD: 199-111 TD= 7,950' (MD) / TD= 4,165(TVD) PBTD= 7,950' (MD) / PBTD = 4,165'(TVD) TREE & WELLHEAD INFO Tree WKM2-9/16"5M Wellhead 11"x 11" 5M Tubing Spool, 11" x 2-7/8" 8rd (Top & 7" Bottom) WKM tbg. w/ 2.5"'H' BPV Profile OPEN HOLE/ CEMENT DETAIL CASING DETAIL Type Cmt w/ 500 sx Permafrost 'C' in 30" hole 9-5 /8" Cmt w/ 1,145 sx Permafrost'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class'G' in 6-1/8" Hole CASING DETAIL Type Wt/Grade/Conn ID Top Btm B" Conductor 54.5/K-55/Welded 12.615" Surface 105' Surface 36/K-55/BTC 8.921" Surface 2,409' Intermediate 26/L-80/BTC 6.276" Surface 3,640' Slotted Liner 12.6 / L-80 / IBT 3.958" 3,512' 7,135' Slotted Liner B N/A / L-80 / N/A 1.995" 4,567' 7,709' TUBING DETAIL Tubing 6.5/L-80/EUE 8rd 1 2.441" 1 Surface 1 3,496' WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 21.5 deg @ 3,250' MD Hole Angle Slotted= 90 deg @ 4,810' MD JEWELRY DETAIL Depth Item 205' 2-7/8" Gas Lift mandrel W/ 1" SK latch Pulled S/O Valve 12-09.19 3,252' 2-7/8" Gas Lift mandrel W/ 1" BK latch 3,428' 2-7/8" XN Nipple, Min ID=2.205" ID 3,440' Discharge Head - FPHVDIS 3,441' Pump Section -119 -Flex 10 SXD 3,464' Gas Separator-GRSFTXAR H6 3,469' Tandem Seal Section - GSBDBUT SB/SB PFSA: GSBDBITSB/SB PFSA 3,483' Motor -MSP3-250 84HP/ 2,210 V/ 23A 3,491' 3/8" Stainless Steel External Capstring 3,491' Sensor XT -150 / Centralizer - Bottom@ 3,496' 3,496' Baker 5" x 7" ZXP Packer (5.75" ID x B tieback) 3,512' Baker 5" x 7" HMC Liner Hanger (4.375" ID) 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,682' Baker HMCV Cementing Valve 4,704' Baker CTC 20' PZP ECP )= 8,034' D= 7,905' GENERAL WELL INFO API: 50-029-22070-03-00 Drilled and Cased by Nabors 27E -12/15/1990 RWO/ Multiple Frac Packs -4/4/1995 ESP Replacement by Nabors 4ES-2/21/1997 S/T & Camp. Nabors 4ES &Completion -10/05/99 2"d Lateral 3S, Nabors $-ES & Nordic R3-5/27/2001 Replace ESP - Nabors 4ES - 8/20/2003 Replace ESP- Doyon 16 - 8/20/2003 Replace ESP - Doyon 16 - 4/24/2011 Replace ESP - Nordic 3 - 3/21/2015 Replace ESP - ASR 1- 8/12/2015 Revised By: STP 2/03/2020 K corp Alaska, LLC RKB Elev= 35' 133/8' 45/8' M Milne Point Unit Well: MPJ -01A PROPOSED Last Completed: 8/11/2015 PTD: 199-111 TREE & WELLHEAD INFO Gs�./ W ' A FII Gea w 5 4 2&3 4,403'an a'lats 6 64-1/2"Slotted Liner 7" - nw w6lpsl= @4.BN "OB"Lateial 2-3/8"Slotted Liner wrxlw✓ ' � '- 4.837to4,e93' TD= 7,950' (MD) / TD= 4,165(TVD) PBTD= 7,95(Y (MD) / PBTD = 4,165'OW) Tree WKM 3-1/8" SM Wellhead 11" x 11" SM Tubing Spool, 21"X 3-1/2" 8rd (Top 7" & Bottom) WKM tbg. w/ 3.0"'H' BPV Profile OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost 'C' in 30" hale 9-5/8" Cmt w/ 1,145 sx Permafrost 'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class'G' in 6-1/8" Hole CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 13-3/8" Conductor 54.5/K-55/Welded 12.615" Surface 105' 9-5/8" Surface 36/K-55/BTC 8.921" Surface 2,409' 7" Intermediate 26/L-80/BTC 6.276" Surface 3,640' 4-1/2" Slotted Liner 12.6 / L-80 / IBT 3.958" 3,512' 7,135' 2-3/8" Slotted Liner B N/A / L-80 / N/A 1.995" 4,567' 7,709' TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / ELIE 8rd 1 2.992" 1 Surface 3,250' WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 21.5 deg @ 3,250' MD Hole Angle Slotted = 90 deg @ 4,810' MD JEWELRY DETAIL No Depth Item 1 3,485' 7" 26N Cement Retainer(100'Cement on top) TOC 3,385' 2 3,496' Baker 5" x 7" ZXP Packer (5.75" ID x 6' tieback) 3 3,512' Baker 5" x 7" HMC Liner Hanger (4.375" ID) 4 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 5 4,682' Baker HMCV Cementing Valve 6 4,704' Baker CTC 20' PZP ECP TD= 8,034' TD= 7,905' GENERAL WELL INFO API: 50-029-22070-01-00 Drilled and Cased by Nabors 27E-12/15/1990 RWO/ Multiple Frac Packs -4/4/1995 ESP Replacement by Nabors 4ES – 2/21/1997 S/T & Comp. Nabors 4ES &Completion –10/05/99 2n0 Lateral 3S, Nabors $-ES & Nordic #3 – 5/27/2001 Replace ESP – Nabors 4ES – 8/20/2003 Replace ESP – Doyon 16 – 8/20/2003 Replace ESP – Doyon 16 –4/24/2011 Replace ESP– Nordic 3-3/21/2015 Replace ESP –ASR 1– 8/12/2015 Revised By: STP 2/03/2020 Milne Point ASR Rig 1 BOPE 2020 11" BOPE Updated 1/09/2020 !-7/8" x 5" VBR ind es UHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: February 12, 2020 Subject: Changes to Approved Sundry Procedure for Well MP J -01A Sundry #: xxx-xxx Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approved B Initials AOGCC Written Approval Received Person and Date Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date H 11H.P Alaska, LD Well Prognosis Well: MPU J -01A Date:02/12/2020 Well Name: MPU J -01A API Number: 50-029-22070-01-00 Current Status: SI Oil Well [Failed ESP] Pad: Milne Point J -Pad Estimated Start Date: March 02nd, 2020 Rig: ASR Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 199-111 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Wyatt Rivard (907) 777-8547 (0) (509) 670-8001 (M) AFE Number: TBD Job Type: Pull ESP/Plug Laterals Current Bottom Hole Pressure: 1,685 psi @ 3,366' TVD (SBHP 1/28/20/ EMW = 9.62 ppg) Maximum Expected BHP: 1,685 psi @ 3,366' TVD (EMW = 9.62 ppg) MPSP: 1,348 psi (0.1 psi/ft gas gradient) Brief Well Summary The Milne Point J -01A well was sidetracked as a Schrader Bluff development well that TD'd at a depth of 8,034' and ran a slotted 4-1/2" liner in open hole in December 1999. The well was initially completed with an ESP. This ESP was pulled in 2001, a lateral (J-01ALI) was drilled & lined with a 2-3/8" pre-drilled/slotted liner, and a new ESP installed. Subsequent ESPs failed and were replaced in 2003, 2011, and 2015. Due to observed scale issues, a downhole chemical injection line was run as part of the new completion in 2015. Solids production was the cause of the ESP failure in July 2015. The ESP again failed and was replaced in August 2015. The ESP recently shutdown on high motor temp in October 2019 and has failed to surface fluids since this date. Notes Regarding Wellbore Condition L� • Casing last tested to 1,500 psi for 30 min down to 3,577' on 3/20/2015. • Hole angle at GLM @ 3,252' MD is 21.5°. • Hole angle at Top of Liner @ 3,497' MD is 23.0 • Hole angle at Top of Slotted Liner in Upper Lateral @ 4,810' MD is 90.0 Objective: The purpose of this work is to pull the ESP with the ASR rig and abandon/isolate both laterals with cement. The Schrader OA/OB laterals needs to be abandoned prior to drilling future wells on Milne Point I -pad due to close approach risks and to help prevent potential MBE's. T_ (on6✓), 2-1,1 20 Future Wellbore Utility Ootions to he RR viewer/: 1.) Rotary sidetrack into the Ugnu or Schrader Bluff sands. 2.) Coil tubing sidetrack into the Ugnu or Schrader Bluff sands. 3.) Conversion to a water source well in either the Prince Creek or Ugnu sands. Pre -Rig Procedure: 1. RU LRS and PT lines to 3,000 psi. 2. Circulate at least one wellbore volume down to the bottom GLM at 3,252 MD (120 bbl) with 9.9 ppg Brine and 1 drum of Baraklean (for tubing cleaning) down tubing, taking returns up the casing to the 500 bbl returns tank. True crystallization temperature (TCT) of 9.9 ppg NaCl = +5.0°F. U Hilcorp Alaska. Lb Well Prognosis Well: MPU J -01A Date:02/12/2020 3. Bullhead an additional 1.5 volumes down to the top of the slotted liner at 4,810' MD in the upper lateral (45 bbls) with 9.9 ppg Brine down the IA to confirm the lateral is open. 4. Clear and level pad area in front of well. Spot rig mats and containment. 5. RD well house and flowlines. Clear and level area around well. 6. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH. 7. RD Little Red Services. 8. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 9. NU BOPE house. Spot mud boat. Brief RWO Procedure: Ask JsI 10. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank. 11. Check for pressure and if 0 psi, pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 9.9 ppg Brine prior to pulling BPV. 12. Set BPV Plug (converting BPV to TWC). 13. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,5�si High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per ASR #1 BOP Test Procedure dated 11/03/2015. sh C. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" and 3-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 14. Contingency: If BOPE test fails �a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 15. Bleed any pressure off casing to returns tank. Pull BPV plug and BPV. Kill well w/ 9.9 ppg Brine as needed. 16. Rig up spoolers for ESP #1 round cable (3,380') and 3/8" capillary string. a. Baker Hughes representative should be onsite for ESP pull. 17. RU spoolers and MU landing joint or spear and PU on the tubing hanger. a. The PU/SO weights during the 2015 ASR ESP RWO were 29k/22k. 18. Recover the tubing hanger. H flilcoro Alaska. LU Well Prognosis Well: MPU J -01A Date: 02/12/2020 Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. a. Evaluate pulled tubing hanger for possible thread damage. If any damage is found, contact well head specialist for possible replacement. Plan to re -use this hanger on a different well. 19. POOH and lay down the 2-7/8" tubing. Lay down ESP. Note any sand or scale inside or on the outside of the ESP on the morning report. b. Look for over -torqued connections from previous tubing runs. c. The well completion currently has: i. 3,380' of ESP cable ii. 3,439' of 3/8" SS Cap String iii. 59 Cannon Clamps iv. 4 Protectorlizers V. 0 Flat Guards vi. 5 Pump Clamps 20. PU 7" 26# Cement Retainer and setting tool. 21. RIH w/ 3-1/2" EUE workstring. a. MU XOs and pups from workstring to setting tool. b. Have 3-1/2" EUE space out pups on location for retainer space out. 22. Space out and set cement retainer above liner top at +/- 3,480' MD. a. Variance Request: Requesting variance to 20 AAC25.112 (c)(1)(D) requiring a cement retainer be no more than 500' MD above the perfs. The top of the slotted liner section is at 4,810' MD, and the cement retainer will be at 3,480' MD (1,330' MD) just above the 4-1/2" liner top. Requesting this depth since setting the retainer within 500' MD would require setting the retainer in the 4-1/2" lateral section, and a cement retainer of this size would limit the cement pumping rates to 1.5 bpm, as opposed to the cement retainer being set in the 7" casing allowing cement pumping rates of 3.0 bpm. 23. Stab -into retainer and set down 10k to confirm retainer set. 24. Perform injectivity test into the retainer and into the lateral at up to 6.0 bpm or 1,200 psi, whichever occurs first. 25. RU Cementers. 26. Mix and pump 200 bbl of 15.8 ppg cement and pump below the retainer, displace w/+/- 26 bbl of 9.9 ppg Brine (leaving +/-4 bbl short of full displacement). a. Contingency: If unable to pump the full volume of cement below the retainer due to bridging or packing off, attempt to adjust pump rate to continue pumping below the retainer. If the well packs off, unsting from the cement retainer and reverse circulate out excess cement. 27. Unsting from cement retainer. Spot +/- 4 bbl of cement (+/- 100' MD) of cement on top of the cement retainer). 28. PU to 30' above estimated cement top (+/- 3,350' MD) and line up to reverse circulate. Reverse circulate at least 2 BU or until no cement returns are seen. 29. POOH to surface. 30. LD running tool. 31. RIH w/ 3-1/2" tubing to +/- 3,250' MD as kill string. �Sr.f 32. Land the 3-1/2" tubing hanger. RILDS. Note PU (Pick Up) and SO (Slack Off) weights on tally. -1 H IlileorV Alaska, LU 33. Pressure test casing to 1,500 psi for 30 min and chart. 1A ..r,c- a. Notify AOGCC 24 hours in advance to witness pressure test. 34. Freeze protect tubing (Tbg ±20bbls) and the annulus (IA±100bbis). 35. Lay down landing joint. Set BPV. Post -Rig Procedure: Well Prognosis Well: MPU J -01A Date:02/12/2020 36. Begin RD of ASR. RD BOPE house. 37. RU crane. ND BOPE. 38. NU used 3-1/8" 5,000# dry hole tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 39. RD crane. Move to next well location. Move 500 bbl returns tank and rig mats to next well location. 40. Pull BPV. 41. RD crane. Move returns tank and rig mats to next well location. 42. Replace casing gauge(s) if removed. 43. Turn well over to production. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Blank RWO Sundry Change Form STATE OF ALASKA ASKA OIL AND GAS CONSERVATION COASION REPORT OF SUNDRY WELL OPERATIONS OCT 3 0 2015 1. Operations Abandon Plug Perforations Ej Fracture Stimulate Pull Tubing ✓ pera ions shutdown LJ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well Q Re-enter Susp Well ❑ Other: ESP Change -out ❑✓ 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska, LLC Development ❑✓ Stratigraphic ❑ Exploratory ❑ Service ❑ 199-111 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22070-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0315848 MILNE PT UNIT SB J -01A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Field / Schrader Bluff Oil Pool 11. Present Well Condition Summary: Total Depth measured 8,034 feet Plugs measured N/A feet true vertical 4,141 feet Junk measured N/A feet Effective Depth measured 7,135 feet Packer measured N/A feet true vertical 4,108 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Conductor 105' 13-5/8" 105' 105' 2,730psi 1,130psi Surface 2,409' 9-5/8" 2,409' 2,346' 3,520psi 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psi 5,410psi Slotted Liner 3,623' 4-1/2" 7,135' 4,154' N/A N/A Slotted Liner 3,142' 2-3/8" 7,709' 4,161' N/A N/A Perforation depth Measured depth See Attached Schematic feet FEB 0�� True Vertical depth See Attached Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5#/ L-80/ EUE 8rd 3,496' 3,368' Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 19 54 54 300 223 Subsequent to operation: 59 0 103 340 226 14. Attachments (required per 20 AAC 25.070; 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑✓ Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ IGSTOR 16. Well Status after work: Oil ✓ . Gas 0 WDSPL Printed and Electronic Fracture Stimulation Data ❑ ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 315-459 Contact Stan Porhola Email sporholaahilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature A v— Phone 777-8412 Date 10/30/2015 Ic Form 10-404 Revised 5/2015 ` _/ RBDMS)q,,NOV 0 4 2015 Submit Original Only • • Milne Point Unit Well: MPJ-01AL1 ACTUAL SCHEMATIC Last Completed: 8/ 11/2015 Hilcorp Alaska, l l c PTD: 201-021 CASING DETAIL RKB Elev = 35' Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26/ L-80/ BTC 6.276 Surface 3,640' 4-1/2" Sltd Liner A 12.6 / L-80 / IBT 1 3.958 1 3,512' 7,135' 2-3/8" Sltd Liner B N/A / L-80 / N/A I N/A 1 4,567 7,709' TD = 7,950' (MD) / TD = 4,165'(TVD) PBTD = 7,950' (MD) / PBTD = 4,165'(TVD) TUBING DETAIL 8" Tubing 6.5 / L-80 / EUE 8rd 1 2.867 1 Surface 3,496' JEWELRY DETAIL 0 Depth Item 205' GLM 3,252' GLM 3,428' 2-7/8" XN Nipple, 2.250 ID 3,440' Discharge Head — FPHVDIS 3,441' Pump Section —119 -Flex 10 SXD 3,464' Gas Separator —GRSFTXARH6 3,469' Tandem Seal Section - GSBDBUT SB/SB PFSA : GSBDBIT SB/SB PFSA 3,483' Motor— MSP3-250 84HP/ 2,210 V/ 23A 3,491' 3/8" Stainless Steel External Capstring 3,491' Sensor XT -150 / Centralizer— Bottom@ 3,496' L 3,512' Baker 5" x 7" HMC Liner Hanger 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 3 4,682' Baker HMCV Cementing Valve t 4,704' Baker CTC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 26 deg @ 2,50(Y MD Hole Angle through Perf= 20 deg OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost 'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost 'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class 'G' in 6-1/8" Hole TREE & WELLHEAD INFO Tree I WKM 2-9/16" 5M Wellhead 11" x 11" 5M Tubing Spool, 11" x 2-7/8" 8rd (Top & Bottom) WKM tbg. w/ 2.5" 'H' BPV Profile )= 8,034' )= 7,905' GENERAL WELL INFO API: 50-029-22070-60-00 Drilled and Cased by Nabors 27E —12/15/1990 RWO/ Multiple Frac Packs -4/4/1995 ESP Replacement by Nabors 4ES — 2/21/1997 SIT & Comp. Nabors 4ES &Completion —10/05/99 2" Lateral 3S, Nabors $-ES & Nordic #3 — 5/27/2001 Replace ESP - Nabors 4ES — 8/20/2003 Replace ESP — Doyon 16 — 8/20/2003 Replace ESP - Doyon 16 — 4/24/2011 Created By: STP 10/29/2015 1J � �W Vj Hilcorp Alaska, LLC',. Hilcorp Alaska, LLC Weekly p Y Operations ra t i o n s Summar c= Well Name API Number Well Permit Number Start Date End Date MPJ -01A 50-029-22070-01-00 199-111 7/16/2015 8/12/2015 Daily Operations: 8/5/15 - Wednesday MIRU ASR #1. 8/6/15 - Thursday PJSM Continue moving ASR and kill tank. PJSM Blow down well SICP 250 psi SITP 600 psi. RU LRS PT lines line up to reverse circ. Pump 150° Seawater 8.5 ppg 30 bbls down annuluus to catch fluid. 51 bbls gone. Caught circulation 1st tbg volume — 20 bbls all water, turned to oil. Continue pumping 80 bbls until oil returns clean@ 4BPM with 50-60% losses. Pump additional 20 bbls to clean pipe and cable. Annulus on vacuum. Light blow on tubing. Pump 5 BBIs down tubing. New gas system arrived, begin installation and continue RU of ASR. Total pumped 175 bbls total recovery 65 bbls, est oil recovery 50%. RD LRS install BPV. ND Tree NU BOPE . Spot Mud boat, Rig and Tank. Raise Derrick. Run all pump lines and hydraulic hoses. Lower floor to slip height, install containment. AOGCC rep Johnnie Hill on location. Arrival of Total Safety hands. MPU electricians on sight to plan Gas Monitor System installation. Continuing BOPE test, Function test BOPS. Install stairs. RU LRS. PT all lines. Prepare to BOP Test. Test BOPE 250/3,000 psi. Continue alarm system install and calibration. Test all Alarms Low and Hi limits. All audio and visual good. AOGCC concurs. Release Total safety technicians. Techs to Train Electricians before return to ANC. 8/7/15 - Friday PJSM complete BOPE Test. RD LRS test unit. OK on test by Johnnie Hill AOGCC. PJSM intoduction to ESP recovery, assign duties, goals, discuss hazards. Remove TWC well on Vac. RU floor for ESP and Cap recovery, Hang sheave w/snorkel for containment PJSM pre pull. BOLDS. PU to 30 K and pull completion to rig floor. Pump 20 bbls down annulus, decomplete Hanger. Thread spooler snakes for CAP and ESP. Crew change. PJSM and handover individual positions and teams and training. POOH w 2-7/8" ESP Cap completion. 16 jts /base line 6.5 jph. Also recovered 1st GLM. BOLD top pup and XN Top of pump shows no sand or solids. Continue POOH to top of pump 90 jts and 1 GLM recovered average speed — 15 jph. BOLD pump assy. 2 bad jts LD from thread damage. Pump failure identifies snap rig off of spacer bushings (Pics to S. porhola) to drive assembly. Motor spins free was not being engaged. Off Load ESP gear ready floor for running cleanout. MU 2-7/8" Mule shoe jt 22.10'. RIH w 2-7/8" L-80 to clean out to TOL. 8/8/15 - Saturday PJSM continue RIH w 2-7/8" muleshoe and 110 jts 2-7/8" L-80. Tag up 24' in on jt 110 at 3,507'. Halliburton N2 on location 1000 hrs.,Order swivel sub for top drive and Mill and bootbasket. Wait on same, rig service. Work/rock pipe and muleshoe rig cannot spud or rotate in this position. Rig up to reverse circulate 8.5 ppg SW. Pump 24 bbls caught returns at 33 bbls pump failure. MU x -overs. Swivel still at factory settings reset recalibrate. Hook up to top drive , reset torque values. PU 22K SW rotating 27 RPM pass through liner top. (Completion depth 3,512') Rig measured depth 3,507'. Tagged up again 3,529'. Hook up to swivel again. Continue in hole liner top an issue with most all tool jts. Tag fill @ 3,970'. 6K over to pull free. PU is 22K. Wait on LRS Pump Truck. Begin pumping 2 bpm @ 340 psi gained circulation. Increase to 3 bpm 500-800 psi returns fluctuating solids heavy gravel and some sand. 88 bbl in/ 78 bbls out 9% losses 10% oil. Depth is 3983'. Let well equalize. U tubing oil. Pump 1 tubing volume 20 bbls. Make connection wash down to 4015' again heavy particle trash and O/W 58 in /50 out. Work to — 4,018' will not wash off and muleshoe light rotation no progress. Pump 20 bbls down annulus, 20 bbls down tbg. Hole is standing full. Open annular. Check flow. Break Swivel. POOH LD 2- 7/8". � �W Vj 0 0 ItHilcorp Alaska, LLC IfillinrpAlaska. Weekly Operations Summary Well Name API Number Well Permit Number Start DateEnd Date MPJ -01A 50-029-22070-01-00 199-111 7/16/2015 8/12/2015 8/9/15 - Sunday PJSM and resume TOOK LD muleshoe. No liner top evidence on shoe but there is evidence and scarring on the downhole side of the tubing collars. Clean up rig floor, repair tong hose, prepare for conventional circ, spot cuttings tank, send 290 bbls O/W mix to B-50. MU BHA with 4-1/8" mill. Repair leak on Hydraulic system. PJSM crew change, detailed plans on fluid/N2/ losses. RIH with singles off rack to 3490'. POOH LD singles. Mill looks OK light groove on OD. LD jt 112 bad pin. MU JT 111 to swivel, work down to TOL. Walked in with light rotation after tag . Work/clean up liner to bottom of extension @ 3,521'. Circ 1.5 x hole volume. B/0 swivel. Pull Stripping rubber. PU new 3.6" BN and 3.5" bootbasket. TOAL 4.65' RIH to 3,490'. Install Stripping head rubber. 8/10/15 - Monday PJSM continue fill DEF and resume RIH through TOL @ 3,507'. Top of liner in good shape. Continue in hole. Swivel up on jt 127. Tag sand @— 4,000'. Rig up to circ, change stripping rubber. PJSM Ref: Ann 106 bbls Tbg 25 bbl Halliburton N2 is preheated. LRS is tied in for pump. Broke fitting on slips trying to B/O single repair same. Losses steadily increasing. Pump rate reduced to 2 bpm @ —200 psi w spikes to 600psi through bridges on sand plugs. Continue Mill and circ ops. Begin washing down 2 BPM 200 psi 3 bpm @ 500psi connection times start @ 23 minutes. Saver Sub MU is difficult. 4,059' broke thru bridge total loss for short period, slow down rate circ regain. Returns averaging 25 bbls losses per connection. Depth is 4,123'. Circ 30 minutes. Attempt to run a joint without swivel no go. PJSM Crew Change. Resume operations @ 4,281'- 4,409' getting sticky fluctate rate 1-3 BPM and work pipe. Broke through total losses C could not regain circulation. BOLD single. Total losses for clean out — 350 bbls SW. RU N2. PJSM PT all lines to 3,500psi. PUMP 100,000 CF @=L 00 scfm and 1 25 bpm ^'1 600psi Good returns after 16,000 SCF. Plentiful fine sand mix w oil/water. Clean returns for 20 minutes. FCP 1,400psi. Fluid Pumped 125 bbl SW. Recovered 227 bbls. BOLD milling assy. Sort Floor to Assemble ESP. RD N2 and release. Blow down annulus. Pump 130 bbl SW, started losses after 110 bbls. Rig down pump lines and pump in sub. POOH with cleanout assembly and LD 2-7/8" L-80. 8/11/15 - Tuesday PJSM Crew Change. Rig up for ESP RIH w 2-7/8" L-80 EUE production. Final depth and BHA are centralizer bottom @ 3,496'. Sensor sub 3,491', Motor 3,460, Tandem seals 3,469', Gas separator 3,463', Pump 3,440', XN 2.251D @ 3,428', 5 jts tbg GLM (blank) 3,252', 95 jts tbg , GLM (orificed) 205'. 5 jts tbg. PJSM Install hanger and 4' pup. All depths are 35' Original KB adjusted. Build ESP spice install and check same. Issue Hot work Permit and Meg Check ESP cable. Land Hanger. PU weight 29K. SO 22.3 K. RILD LD landing jt. Install BPV. Rig Down ASR 1. 8/12/15 - Wednesday ND BOPE NU Tree and test 250/5,000 psi RDMO turn well to production. THE STATE °'ALASKA GOVERNOR BILL WALKER Alaska ail and Gas Conservation Commission Stan Porhola I I Operations Engineer Hilcorp Alaska, LLC 1 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Pool, MPU SB J -01A Sundry Number: 315-459 Dear Mr. Porhola: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.go,/ Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy V. Foerster Chair DATED this 3 day of July, 2015 Encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 E E -WED 11 -JI- 2 8 2015 713-0AI- AOGGG 1. Type of Request- Abandon ❑ Plug for Redrd' ❑ Perforate New Pool ❑ Repair Well Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing 0 Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Wel ❑ Stimulate ❑ Alter Casing ❑ Other: ESP Change -out ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 199-111 , 3 Address- 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22070-01-00 - 7. If perforating. 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 ?{ib Will planned perforations require a spacing exception? Yes ❑ No MILNE PT UNIT SB J -01A, 9. Property Designation (Lease Number) 10. Field/Pool(s) ADL0315848 Milne Point Field / Schrader Bluff Oil Pool - 11 PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft). Effective Depth TVD (ft): Plugs (measured). Junk (measured). 8,034. 4,141 7,135 4,108 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 105' 13-5/8" 105' 105' 2,730psi 1,130psi Surface 2,409' 9-5/8" 2,409' 2,364' 3,520psi 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psi 5,410psi Slotted Liner 3,623' 4-1/2" 7,135' 4,154' 1N/A N/A Slotted Liner 3,142' 2-3/8" 7,709' 4,161' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade. Tubing MD (ft). See Attached Schematic See Attached Schematic 2-7/8" 6.5# / L-80 / EUE 8rd 3,469' Packers and SSSV Type. Packers and SSSV MD (ft) and TVD (ft): N/A and N/A N/A and N/A 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work, Detailed Operations Program ❑ BOP Sketch R1 Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/11/2015 Oil Q • Gas ❑ WDSPL ❑ Suspended ❑ WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval Date: Commission Representative- GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email ckan er hilcor .com Printed Name Stan Por ola Title Operations Engineer Signature Phone 777-8412 Date 7/28/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 315-`15� Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location ClearanceEl / ar Other C c3 /5 C Lae"c / A,��/ Spacing Exception Required? Yes ❑ No d Subsequent Form Required to --YC) V APPROVED BY Approved by COMMISSIONER THE COMMISSION Date: j- 72y -Is �2 Submit Form and Form 10-403 (Revised 10/2012) GR164444L 12 months ffom the date of approval. Attachmen i uplicate 2m �i.� RBDMS- AUG 2 2015 . K Hilcoru Alaska, LL Well Prognosis Well: MPU J -01A Date: 7/28/2015 Well Name: MPU J -01A API Number: 50-029-22070-001 Current Status: SI Oil Well [ESP] Pad: J -Pad Estimated Start Date: August 11th, 2015 Rig: ASR #1 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 199-111 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Paul Chan (907) 777-8333 (0) (907) 444-2881 (M) AFE Number: Current Bottom Hole Pressure: 1,378 psi @ 4,000' TVD (Last BHP measured 2/02/2015) Maximum Expected BHP: 1,378 psi @ 4,000' TVD (No new perfs being added) Max. Allowable Surf Pressure: 0 psi (Based on SBHP taken 2/02/2015 and water cut of 54% (0.389psi/ft) with an added safety factor of 1,000' TVD of oil cap) Brief Well Summary: The Milne Point J -01A well was sidetracked as a Schrader Bluff development well that TD'd at a depth of 8,034' and ran a slotted 4-1/2" liner in open hole in December 1999. The well was initially completed with an ESP. This ESP was pulled in 2001, a lateral was drilled & lined with a 2-3/8" pre-drilled/slotted liner, and a new ESP installed. Subsequent ESPs failed and were replaced in 2003, 2011, and 2015. Due to observed scale issues, a downhole chemical injection line was run as part of the new completion in 2015. Solids production is assumed to be the cause of the most recent ESP failure in July 2015. Notes Regarding Wellbore Condition • Casing last tested to 1,500 psi for 30 min down to 3,577' on 3/20/2015. V Objective: The purpose of this work/sundry is to pull the existing failed ESP and run a new ESP. Brief Procedure: WO Rig Procedure: 1. MIRU Hilcorp ASR #1 WO Rig. 2. Circulate well with 8.4 ppg lease water down tubing and fill casing. 3. Set BPV. ND Tree. 4. NU 11" BOPE. Test to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 1,500 psi High (hold each valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Test VBR rams on 2-7/8" test joint. 5. Bleed any pressure off tubing and casing. Pull BPV. 6. MU landing joint and pullover string weight (65k) on tubing hanger to confirm free. 7. POOH. Lay 2-7/8" tubing on the pipe rack (utilize as workstring). 8. MU 6-1/8" bit and junk baskets and RIH to +/- 3,500'. 9. Circulate bottoms up x 2 with 8.4 ppg lease water. 10. MU 3-3/4" bit and junk baskets and RIH to +/- 3,500' w/ 1-1/2" tubing. Hilcory Alaska, LLQ Well Prognosis Well: MPU J -01A Date: 7/28/2015 11. MU XO from 1-1/2" tubing to 2-7/8" tubing. 12. Cleanout fill to +/- 7,000' in A lateral. 13. Circulate bottoms up x 2 with 8.4 ppg lease water. 14. POOH. Lay down bit and junk baskets. Lay down 1-1/2" tubing and 2-7/8" tubing. 15. PU new 475 series ESP and RIH with existing 2-7/8" 8RD EUE L-80 tubing. a. Test 3/8" control line to 2,500 psi. b. RU to use clamps to secure control line to tubing (ensure adequate clamps) 16. Set base of ESP at +/-3,475' (Pump intake around +/- 3,395'). Land tubing hanger. 17. Lay down landing joint. Set BPV. ND BOPE. NU existing 2-7/8" 5,000# tree. Pull BPV. 18. Set TWC. Test tubing hanger to 250/5,000 psi. Test tree to 250/5,000 psi. Pull TWC. 19. RD Hilcorp ASR #1 WO Rig. 20. Replace IA x OA pressure gauge if removed (7" x 9-5/8"). 21. Turn well over to production. Attnrhmantc- 1. As -built Schematic 2. Proposed Schematic 3. BOPE Schematic Milne Point Unit I� /I /�A I T Well: MPJ-01AL1 SCHEMATIC Last Completed: 4/24/2014 Ailcorp Alaska, f f c PTD: 201-021 CASING DETAIL RKB Elev = 35' Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26 / L-80 / BTC 6.276 Surface 3,640' 4-1/2" Sltd Liner A 12.6 / L-80 / IBT 3.958 1 3,512' 7,135' 2-3/8" Sltd Liner B N/A / L-80 / N/A N/A 1 4,567 7,709' TD = 7,950' (MD) / TD = 4,165'(TVD) PBTD = 7,950' (MD) / PBTD = 4,165'(TVD) TUBING DETAIL 3" Tubing 9.3 / L-80 / EUE 8rd 2.867 Surface 3,469' Capstring Stainless Steel N/A Surface 3,469' JEWELRY DETAIL > Depth Item 171' GLM 3,253' GLM 3,394' 2-7/8" XN Nipple, 2.250 ID 3,405' Discharge Head — FPHVDIS 3,406' Dual Tandem Pump Section — 71 Flex 10 SXD (2) 3,435' Gas Separator —GRSFTXARH6 3,440' Tandem Seal Section - GSBDBUT SB/SB PFSA : GSBDBIT SB/SB PFSA 3,454' Motor — MSPl-250 126HP/ 2,445 V/ 31A 3,465' Sensor / Centralizer —±Bottom@3,469' i 3,512' Baker 5" x 7" HMC Liner Hanger 4,567 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,682' Baker HMCV Cementing Valve 4,704' Baker CTC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 26 deg @ 2,500' MD Hole Angle through Perf= 20 deg OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost 'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost 'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class 'G' in 6-1/8" Hole TREE & WELLHEAD INFO Tree WKM 2-9/16" 5M Wellhead 11" x 11" 5M Tubing Spool, 11" x 2-7/8" 8rd (Top & Bottom) WKM tbg. w/ 2.5" 'H' BPV Profile GENERAL WELL INFO API: 50-029-22070-60-00 Drilled and Cased by Nabors 27E —12/15/1990 RWO/ Multiple Frac Packs -4/4/1995 ESP Replacement by Nabors 4ES — 2/21/1997 S/T & Comp. Nabors 4ES &Completion — 10/05/99 2"' Lateral 3S, Nabors $-ES & Nordic #3 — 5/27/2001 Replace ESP -Nabors 4ES — 8/20/2003 Replace ESP — Doyon 16 — 8/20/2003 Replace ESP - Doyon 16 — 4/24/2011 )= 8,034' �= 7,905' Created By: TDF 4/29/2015 RKB Elev = 35' Milne Point Unit Well: MPJ-01AL1 PROPOSED Last Completed: Proposed PTD: 201-021 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26 / L-80 / BTC 6.276 Surface 3,640' 4-1/2" Sltd Liner A 12.6 / L-80 / IBT 1 3.958 3,512' 1 7,135' 2-3/8" Sltd Liner B N/A / L-80 / N/A I N/A 4,567 1 7,709' TI) =7,950' (MD)/TD=4,165'(TVD) PBTD = 7,950' (MD) / PBTD = 4,165'(TVD) TUBING DETAIL Tubing 6.5 / L-80 / EUE 8rd 1 2.867 1 Surface I ±3,475' JEWELRY DETAIL Depth Item ±200' GLM ±3,250' GLM ±3,400' 2-7/8" XN Nipple, 2.250 ID ±3,411' Discharge Head — FPHVDIS ±3,412' Dual Tandem Pump Section — 71 Flex 10 SXD (2) ±3,441' Gas Separator —GRSFTXARH6 ±3,446' Tandem Seal Section - GSBDBUT SB/SB PFSA : GSBDBIT SB/SB PFSA ±3,460' Motor—MSP1-250 126HP/2,445V/31A ±3,471' 3/8" Stainless Steel External Capstring ±3,471' Sensor / Centralizer —±Bottom@3,475' 3,512' Baker 5" x 7" HMC Liner Hanger 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,682' Baker HMCV Cementing Valve 4,704' Baker CTC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 26 deg @ 2,500' MD Hole Angle through Perf = 20 deg OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost 'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost 'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class 'G' in 6-1/8" Hole TREE & WELLHEAD INFO Tree WKM 2-9/16"5M 11" x 11" 5M Tubing Spool, 11" x 2-7/8" 8rd (Top & Wellhead Bottom) WKM tbg. w/ 2.5"'H' BPV Profile )= 8,034' )= 7,905' GENERAL WELL INFO API: 50-029-22070-60-00 Drilled and Cased by Nabors 27E — 12/15/1990 RWO/ Multiple Frac Packs -4/4/1995 ESP Replacement by Nabors 4ES — 2/21/1997 S/T & Comp. Nabors 4ES &Completion —10/05/99 2" Lateral 3S, Nabors $-ES & Nordic #3 — 5/27/2001 Replace ESP - Nabors 4ES — 8/20/2003 Replace ESP — Doyon 16 — 8/20/2003 Replace ESP - Doyon 16 — 4/24/2011 Created By: STP 7/27/2015 . R 4.54' 2 1/16 5M Kill Line Valves � 2.00 NIP' IIl_ Manual Manual 11" BOPE 06U 11"- 5000 Updated 7/23/15 Mime Point 2015 ASR Rig 1 Knight Oil Tools BOP Stripping Head 2 7/8 -5 variables Me 2 1/16 5M Choke Line Valves InG STATE OF ALASKA AL _(A OIL AND GAS CONSERVATION COW- _MON REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Repair Well L/j Plug Perforations Ll Perforate Lj Other I ESP Change -out Performed: Alter Casing ❑ Pull Tubing Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re-enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑ Stratigraphic Exploratory ❑ Service ❑ 199-111 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-029-22070-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0315848 MILNE PT UNIT SB J-01AL1 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Field / Schrader Bluff Oil Pool 11. Present Well Condition Summary: REr '"" Total Depth measured 8,034 feet Plugs measured N/A feet true vertical 4,141 feet Junk measured N/A feet AFf; 2.9 201S Effective Depth measured 7,135 feet Packer measured N/A feet,.,.,� A0CC true vertical 4,108 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Conductor 105' 13-5/8" 105' 105' 2,730psi 1,130psi Surface 2,409' 9-5/8" 2,409' 2,346' 3,520psi 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psi 5,410psi Slotted Liner 3,623' 4-1/2" 7,135' 4,154' N/A N/A Slotted Liner 3,142' 2-3/8" 7,709' 4,161' N/A N/A Perforation depth Measured depth See Attached Schematic SCANNED i'J.ay 2" 0 2 0 � True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5#/ L-80/ EUE 8rd 3,469' 3,349' Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 176 84 202 220 228 Subsequent to operation: 265 11 320 320 223 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ❑ Development ❑ Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil Gas ❑ WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 315-116 Contact Chris Kanyer Email ckanyer(p7hilcorp.com Printed Name Kanyer Title Operations Engineer 1Chris Signature ��._ �p G Phone 907-777-8377 Date 4/29/2015 Form 10-404 Revised 10/2012 RBDMS �-V APR 19 1015 Submit Original Only Milne Point Unit Well: MPJ-01AL1 SCHEMATIC Last Completed: 4/24/2014/ Hilcorp Alaska, LLC P ' CASING DETAIL RKB Elev = 35' Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26 / L-80 / BTC 6.276 Surface 3,640' 4-1/2" Sltd Liner A 12.6 / L-80 / IBT 3.958 1 3,512' 1 7,135' 2-3/8" Sltd Liner B N/A / L-80 / N/A N/A 1 4,567 1 7,709' TD = 7,95(Y (IVU) / TD = 4,165'(TVD) PBTD= 7,950' (MD) / PBTD=4,16T(TVD) TUBING DETAIL Tubing 9.3 / L-80 / ELIE 8rd 2.867 Surface 3,469' Capstring Stainless Steel N/A Surface 3,469' JEWELRY DETAIL Depth Item 171' GLM 3,253' GLM 3,394' 2-7/8" XN Nipple, 2.250 ID 3,405' Discharge Head — FPHVDIS 3,406' Dual Tandem Pump Section — 71 Flex 30 SXD (2) 3,435' Gas Separator —GRSFTXARH6 3,440' Tandem Seal Section - GSBDBUT SB/SB PFSA : GSBDBIT SB/SB PFSA 3,454' Motor— MSPl-250 126HP/ 2,445 V/ 31A 3,465' Sensor / Centralizer —±Bottom@3,469' 3,512' Baker 5" x 7" HMC Liner Hanger 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,682' Baker HMCV Cementing Valve 4,704' Baker CTC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 26 deg @ 2,500' MD Hole Angle through Perf = 20 deg OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost 'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost 'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class 'G' in 6-1/8" Hole TREE & WELLHEAD INFO Tree WKM 2-9/16" 5M Wellhead 11" x 11" 5M Tubing Spool, 11" x 2-7/8" 8rd (Top & Bottom) WKM tbg. w/ 2.5" 'H' BPV Profile )= 8,034' )= 7,905' GENERAL WELL INFO API: 50-029-22070-60-00 Drilled and Cased by Nabors 27E —12/15/1990 RWO/ Multiple Frac Packs -4/4/1195 ESP Replacement by Nabors 4ES — 2/21/1997 S/T & Comp. Nabors 4ES &Completion —10/05/99 2" Lateral 3S, Nabors $-ES & Nordic #3 —5/27/2001 Replace ESP - Nabors 4ES — 8/20/2003 Replace ESP — Doyon 16 — 8/20/2003 Replace ESP - Doyon 16-4/24/2011 Created By: TDF 4/29/2015 Hilcorp Alaska, LLC IIiIf.,,,.,,,,.1'ka.LLC Weekly Operations Summary Well Name JAPI Number lWell Permit Number IStart Date End Date MPJ-01AL1 50-029-22070-01-00 199-111 3/18/2015 3/20/2015 Daily Operations: 3/18/15 - Wednesday Mobilize rig / camp and ancillary equip., spot and accept rig. RU, spot and berm tanks and cellar, run hardline, offload 3% 160° KCL, pressure test lines 250psi low/3,000psi high. SITP 30 psi SICP 40 psi. Line up and pump 47 bbls down tbg, caught circulation in 37 bbls, oil returns. Flop over and reverse circ 150bbls mostly oil. Set BPV, ND tree, pack hanger grooves and voids with graphite grease, NU BOP. Pull BPV Set TWC and fill stack. Shell test 250psi low/3,000psi high. 3/19/15 - Thursday PJSM tighten well head bolts. Shell Test. Can not get shell test, hanger is leaking. Pressure up on hanger and overtighten lock down pins. no go. Jeff Jones on location, get approval from AOGCC for rolling test and organize test plu& for second test. Hanger packed off, eliminate rolling test. Complete choke manifold test as per procedure. # 2 valve leaking. Proceed with BOP test, BOP'S and all surface & floor valves while rebuilding # 2 valve on choke manifold. Retest choke maniold against #2 valve and blind rams 250psi low/3,000psi high. State witness did not like chart for proof of flow restriction with chokes. Discuss with Jeff Jones. Function test with rig pumps good test. Blew pop off closing manual choke. Check chokes charting and function tests. AOGCC still not chart satisfied. Tear down chokes and clean no damge noted or repairs needed. Check with larger flow from kill line . Chokes reduce flow as required. AOGCC agrees on choke functionality and passes test. Back out lock down pins, remove TWC, install landing jt . Unland hanger at 65K pull to service decomplete and terminate ESP cable. POOH and string cable to spooler. POOH LD all tubing and the entire ESP completion from 3,840'. PU MU muleshoe, 7" casing scraper, PU, drift, and run new tubing plus 11jts RIH w/ scraper to 3,515'. No Tags No Drags.' POOH with scraper 3/20/15 - Friday PJSM resume POOH w/ scraper, LD same. PU MU 7" 26# champ test packer RIH and set @ 3,577' element depth. Chart test casing 1,500psi 30 minutes. ISIP 1,590psi FSIP 1,530psi. POOH LD champ packer. Rig up floor to run ESP completion assemble and service ESP assy. Install lower ESP connection and 3/8" cap tube with 2,500psi check valve. Cycle test OK cable check OK. RIH with ESP completion on new 2-7/8" 6.5# L-80 tbg check cable and cap check @ 2,000' RIH with total 106 jts new tubing, PU hanger and landing joint, install penetrator. Space out/ cut ESP cable and cap string. Build connector splice on ESP cable, connect same and meg check. Land hanger 65K up/dn. Pull landing jt install BPV. EOT/ESP 3,469', motor 3,454', tandem seals 3,440', dual pumps 3,406', discharge head 3,405' ,1- 10' PJ , XN nipple 2.25" ID 3,394',4 jts tbg, 10' PJ, GLM ( Blank) 3,523',10' PJ , 97 jts tbg, 10' PJ, GLM 171', 10'PJ, 2' pup. Hardware used 61 Cannon clamps, 5 protectolizers, 2 flatbars. Insure alignment, run in lockdown pins. ND BOP NU tree. Test Void and Tree 250psi low/5,000psi high. Freshly serviced SSV in warm cellar expanion burst rupture disc during test, replace same retest. All good. Remove BPV. RDMO release rig 02:30. 3/21/15 - Saturday No operations to report. 3/22/15 - Sunday No operations to report. 3/23/15 - Monday No operations to report. 3/24/15 -Tuesday No operations to report. THE STATE °fALASKA GOVERNOR BILL WALKER Chris KanY er ��ANNED Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 f Re: Milne Point Field, Schrader Bluff Oil Pool, MPU SB J-OIA Sundry Number: 315-116 Dear Mr. Kanyer: Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax 907 276.7542 www.aogcc.alaska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair, Commissioner DATED this c3 day of March, 2015 Encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25280 RECEIVED FEB 2 7 2015 f3 7:� -S/ 3,//j A0GCG 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pod ❑ Repair Wella Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing E] • Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: ESP Change -out ❑� 2. Operator Name: 4. Current Well Gass: 5. Permit to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 199-111 3. Address: 6. API Number. 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22070-01-00 ' 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O. 477 Will planned perforations require a spacing exception? Yes ❑ No MILNE PT UNIT SB J -01A 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0315848 Milne Point Field / Schrader Bluff Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 8,034 4,141 7,135. 4,108 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 105' 13-5/8" 105' 105' 2,730psi 1,130psi Surface 2,409' 9-5/8" 2,409' 2,364' 3,520psi 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psi 5,410psi Slotted Liner 3,623' 4-1/2" 17,135' 14,154' 1N/A N/A Slotted Liner 3,142' 2-3/8" 7,709' 4,161' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5* / L-80 / EUE 8rd 3,476' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A and N/A N/A and N/A 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 3/15/2015 Oil ❑✓ Gas ❑ WINJ ❑ GINJ ❑ WDSPL ❑ Suspended ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chris Kan er Email ckan er hilcor .corn Printed Name Chris Kanyer Title Operations Engineer Signature i , Phone 777-8377 Date 2/27/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3/ICo Plug Integrity ❑ BOP Test 2Mechanical Integrity Test ❑ Location Clearance ❑ Other: ,= 3(ba \ Spacing Exception Required? Yes ❑ No Eg/ Subsequent Form Required: C7 — ! y�y APPROVED BY COMMISSIONER THE COMMISSION Approved by:ayA,:, Dater Form 10-403 (Revised 10/20120'a.LaIN i a dfor 12 months from the dat of approval. TITII &_ RBDMS �\q MAR - 5 2015 /X113- -L-/S Submit Form and Attachments in Duplicate Hilcorp Alaska, LLQ Well Prognosis Well: MPJ -01A Date: 2/27/2015 Well Name: MPJ -01A API Number: 50-029-22070-01-00 Current Status: SI Producer Pad: J Pad Estimated Start Date: March 15, 2015 Rig: Nordic 3 Reg. Approval Req'd? March 13, 2015 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 199-111 First Call Engineer: Chris Kanyer (907) 777-8377 (0) (907) 250-0374 (M) Second Call Engineer: Bo York (907) 777-8345 (0) (907) 727-9247 (M) AFE Number: 1550618 Current Bottom Hole Pressure: — 1,378 psi @ 4,000' TVD Maximum Expected BHP: — 1,378 psi @ 4,000' TVD Max. Allowable Surface Pressure: 0 psi Brief Well Summary: (Last BHP measured 2/2/2015) (No new perfs being added) ✓ (Based on actual reservoir conditions and water cut of 54% (0.389psi/ft) with an added safety factor of 1000' TVD of oil cap) The Milne Point J -01A well was sidetracked as a Schrader Bluff development well that TD'd at a depth of 8,034' and ran a slotted 4-1/2" liner in open hole in December 1999. The well was initially completed with an ESP. This ESP was pulled in 2001, a lateral was drilled & lined with a 2-3/8" pre-drilled/slotted liner, and a new ESP installed. Subsequent ESPs failed and were replaced in 2003 and 2011. The recent pump failed in December 2014. The ESP has recently been restarted on February 5, 2015 and well has produced intermittently through the tubing to a tank while the well pad is continuously manned. The well is currently unable to produce fluids on its own or with the ESP into the production header with—200psi tubing pressure. This is likely due to the pump deterioration, probably caused by erosion from solids. There is no recent casing pressure test performed and one will be completed during this workover. Due to observed scale issues, a downhole chemical injection line will be run as part of the new completion. No subsidence issues are expected in this well. Notes Regarding Wellbore Condition Current well status is shut in oil producer. No subsidence issue suspected. RWO Obiective: Pull ESP, run casing scraper, pressure teasing, & run 2-7/8" ESP completion with downhole chemical injection. Brief Procedure: 1. MIRU Nordic #3 Rig. 2. Circulate well with 8.5ppg seawater and monitor well. 3. ND tree, NU 13-3/8" BOPE with 11" spool adapter and test to 250psi low/3,000psi igh, annular to 250psi low/2,500psi high. a. Notify AOGCC 24hrs in advance to witness test. 4. Unseat hanger and pull 2-7/8" ESP completion from 3,476' to surface and lay down same. 5. 111H with 7" cleanout BHA to +/-3,500'. POOH with same. llilvorp Alaska. I.L; Well Prognosis Well: MPJ -01A Date: 2/27/2015 6. RIH and set test packer at +/-3,480' (Note: above liner, to test of 7" casing only). 7. Perform a charted casing pressure test to 1,500psi for 30min. Bleed off pressure and POOH with same. 8. MU and RIH with ESP with gas separator and 3/8" chemical injection line on 2-7/8" 8RD EUE L-80 tubing [to be replaced if necessary]. Set ESP at +/-3,476'. Land tubing hanger. 9. ND BOP, NU and tree. 10. RDMO workover rig and equipment. 11. Turn well over to production. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOP Schematic Milne Point Unit Well: MPJ-01AL1 SCHEMATIC Last Completed: 4/24/2014 Hilcorp Alaska, l l c PTD: 201-021 CASING DETAIL RKB Elev = 35' Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26 / L-80 / BTC 6.276 Surface 3,640' 4-1/2" Sltd Liner A 12.6 / L-80 / IBT 3.958 3,512' 7,135' 2-3/8" Sltd Liner B N/A / L-80 / N/A N/A 4,567 7,709' TD = 7,950' (MD) / TD = 4,165'(TVD) PBTD = 7,950' (MD) / PBTD = 4,165'(TVD) TUBING DETAIL 3" Tubing 9.3 / L-80 / EUE 8rd 1 2.867 1 Surface 3,476' JEWELRY DETAIL Depth Item 171' GLM - Camco 2-7/8'x 1" KBMG w/ DPSOV 3,259' GLM - Camco 2-7/8'x 1" KBMG w/ DGLV 3,404' 2-7/8" XN Nipple, 2.2501D 3,426' GPDIS Discharge Head 3,426.4' Dual Tandem Pump Section —SXD 90-P17 & SXD 18-P75 MVP 3,446' Gas Separator 3,451' Tandem Seal Section 3,465' KMH Motor: 114HP/ 2,330 V/ 30 Amp 3,476' Sensor Pumpmate XTO w/ Centralizer — Bottom@ 3,480' 1 3,512' Baker 5" x 7" HMC Liner Hanger 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,682' Baker HMCV Cementing Valve 4,704' Baker CTC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 26 deg @ 2,500' MD Hole Angle through Perf = 20 deg OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost 'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost 'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class 'G' in 6-1/8" Hole TREE & WELLHEAD INFO Tree WKM 2-9/16" 5M Wellhead 11" x 11" 5M Tubing Spool, 11" x 2-7/8" 8rd (Top & Bottom) WKM tbg. w/ 2.5" 'H' BPV Profile GENERAL WELL INFO API: 50-029-22070-60-00 Drilled and Cased by Nabors 27E —12/15/1990 RWO/ Multiple Frac Packs -4/4/1195 ESP Replacement by Nabors 4ES — 2/21/1997 S/T & Comp. Nabors 4ES &Completion —10/05/99 2 Lateral 3S, Nabors $-ES & Nordic #3 —5/27/2001 Replace ESP - Nabors 4ES — 8/20/2003 Replace ESP — Doyon 16 — 8/20/2003 Replace ESP - Doyon 16-4/24/2011 >= 8,034' i /" t )= 7,905' 'A/_1_ Created By: TDF 2/25/2015 I n Ililcorp Alaska, LLC RKB Elev = 35' Milne Point Unit Well: MPJ-01AL1 PROPOSED Last Completed: 4/24/2014 PTD: 201-021 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26 / L-80 / BTC 6.276 Surface 3,640' 4-1/2" Sltd Liner A 12.6 / L-80 / IBT 3.958 3,512' 7,135' 2-3/8" Sltd Liner B N/A / L-80 / N/A N/A 4,567 7,709' TD = 7,950' (MD) / TD = 4,165'(TVD) PBTD = 7,950' (MD) / PBTD = 4,165'(TVD) TUBING DETAIL Tubing 9.3 / L-80 / ELIE 8rd 2.867 Surface ±3,476' Capstring Stainless Steel N/A Surface ±3,476' JEWELRY DETAIL Depth Item ±171' GLM ±3,259' GLM ±3,404' 2-7/8" XN Nipple, 2.250 ID ±3,426' Discharge Head ±3,426.4' Dual Tandem Pump Section ±3,446' Gas Separator ±3,451' Tandem Seal Section ±3,465' Motor ±3,476' Sensor / Centralizer —±Bottom@3,480' 3,512' Baker S" x 7" HMC Liner Hanger 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,682' Baker HMCV Cementing Valve 4,704' Baker CTC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 26 deg @ 2,500' MD Hole Angle through Perf = 20 deg OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost 'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost 'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class 'G' in 6-1/8" Hole TREE & WELLHEAD INFO Tree WKM 2-9/16" 5M Wellhead 11" x 11" 5M Tubing Spool, 11" x 2-7/8" 8rd (Top & Bottom) WKM tbg. w/ 2.5" 'H' BPV Profile GENERAL WELL INFO API: 50-029-22070-60-00 Drilled and Cased by Nabors 27E — 12/15/1990 RWO/ Multiple Frac Packs -4/4/1195 ESP Replacement by Nabors 4ES — 2/21/1997 S/T & Comp. Nabors 4ES &Completion —10/05/99 2°d Lateral 3S, Nabors $-ES & Nordic #3 — 5/27/2001 Replace ESP - Nabors 4ES — 8/20/2003 Replace ESP — Doyon 16 — 8/20/2003 Replace ESP - Doyon 16 — 4/24/2011 )= 8,034' )= 7,905' /► i -y Created By: TDF 2/27/2015 MPU BOP Stack -%2" variables Pages NOT Scanned in this Well History File xHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. 1 qq.-- I il File Number of Well History File PAGES TO DELETE Complete RESCAN ❑ Color items - Pages: ❑ Grayscale, halftones, pictures, graphs, charts Pages: ❑ Poor Quality Original - Pages: ❑ Other - Pages: DIGITAL DATA Diskettes, No. ❑ Other, No/Type OVERSIZED ❑ Logs -of various kinds ❑ Other COMMENTS: � Scanned by: Beverly Dianna Vincent Nathan Lowell Date: 5Fa d O') Isl ❑ TO RE-SCAN Notes: Re -Scanned by: Beverly Dianna Vincent Nathan Lowell Date: /s/ STATE OF ALASKA ALASKAL AND GAS CONSERVATION COMMISMN REPOR OF SUNDRY WELL OPERANS 1. Operations Performed: ❑ Abandon ® Repair Well ❑ Plug Perforations ❑ Stimulate ❑ Re -Enter Suspended Well ❑ Alter Casing ® Pull Tubing ❑ Perforate New Pool ❑ Waiver ® Other ❑ Change Approved Program ❑ Operation Shutdown ❑ Perforate ❑ Time Extension Change Out ESP 2. Operator Name: 4. Well Class Before Work: 5. Permit To Drill Number: BP Exploration (Alaska) Inc. ® Development ❑ Exploratory ❑ Service ❑ Stratigraphic - 199-111 3. Address: 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 - 50-029-22070-01-00 7. Property Designation: — 8. Well Name and Number: ADL 025906 & 315848 MPJ -01A 9. Field / Pool(s): I Milne Point Unit / Schrader Bluff 10. Present well condition summary Total depth: measured 8034 feet Plugs (measured) None feet true vertical 4141 feet Junk (measured) None feet Effective depth: measured 8034 feet Packer. (measured) None feet true vertical 4141 feet Packer. (true vertical) None feet Casing Length Size MD TVD Burst Collapse Structural Conductor 70' 13-3/8" 105' 105' 2730 1130 Surface 2374' 9-5/8" 2409' 2364' 3520 2020 Intermediate Production 3605' 7" 3640' 3502' 7240 5410 Liner 3623' 4-1/2" 3512'- 7135' 3383'- 4108' 8430 7500 ,�A,AAWMAY 2 0 2011 Perforation Depth: Measured Depth: Slotted Liner: 4810'- 7091' True Vertical Depth: Slotted Liner: 4035'- 4106' Tubing (size, grade, measured and true vertical depth): 2-7/8", 6.5# L-80 3480' 3354' Packers and SSSV (type, measured and true vertical depth): None None 11. Stimulation or cement squeeze summary: Intervals treated (measured): REO',f IV L - Treatment description including volumes used and final pressure: ctin Da 12. Representative Daily Average Production or In ta Oil-Bbl Gas-Mcf Water -Bbl Cas a Tubing Pressure Prior to well operation: 178 52 427 Not Available Not Available Subsequent to operation: 164 64 508 260 230 13. Attachments: ❑ Copies of Logs and Surveys run 14. Well Class after work: ❑ Exploratory ® Development ❑ Service [IStratigraphic ® Daily Report of Well Operations 15. Well Status after work: ❑ GINJ d ® Oil ❑ SUSP ❑ WDSPL ® Well Schematic Diagram ❑ Gas ❑ GSTOR ❑ SPLUG ❑ WAG ❑ WINJ 16. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry NuT or if'C.O. Exempt: Contact Charles Reynolds, 564-5480 N/A Printed Name Terrie Hubble Title Drilling Technologist Prepared By Name/Number. Signature Phone 564-4628 Date717111 Terrie Hubble, 564-4628 Form 10-404 Revised 10/2010Submit Original Only RBDMS MAY 19101 �. �►� S•�' !l ,�� 7� • Printed 5/11/2011 10:21:14AM North America - ALASKA - BP Page 1 of 4 Operation Summary Report Common Well Name: MPJ -01 AFE No Event Type: WORKOVER (WO) Start Date: 4/15/2011 � 1 End Date: I X4-OORVH-E (450,000.00 ) ' Project: Milne Point Site: M Pt J Pad Rig Name/No.: DOYON 16 Spud Date/Time: 12/1/1999 12:00:OOAM Rig Release: 4/25/2011 Rig Contractor: DOYON DRILLING INC. UWI: 500292207000 Active Datum: 4: 01 11/11/1999 15:00 @65.65ft (above Mean Sea Level) Date From - To Hrs Task Code j NPT NPT Depth Phase Description of Operations (hr) (ft) _ 4/22/2011 - 07:00 7.00 MOB P PRE SECURE BOPE STACK ON STORAGE RACK. 100:00 R/U BOOSTER WHEELS. -REMOVE RIG MATS FROM AROUND WELL. P -PREP FOR RIG MOVE. 07:00 - 09:00 2.00 MOB PRE MOBILIZE RIG WITH DERRICK UP. '- MOBOIZE FROM MPH PAD TO MPJ PAD HAD TO WAIT FOR MPU ROADS AND PADS j TO DEAL WITH A PROBLEMATIC_ ROAD RAIL 09:00 - 10:30 1.50 RIGU P PRE RIG ON LOCATION - REMOVED REAR BOOSTER WHEELS. - INSTALL BOP STACK IN CELLAR 10:30 - 11:30 1.00 RIGU P PRE PJSM FOR SPOTTING THE RIG OVER THE WELL. �- SPOTTED THE RIG OVER THE WELL. I NOTIFIED THE PAD OPERATOR PRIOR - SPOTTED THE SLOP TRAILER. j ;- SPOTTED FUEL TRAILER & CHANGE OUT -- — -- --- _12-:00 -- -- SHACK 11:30 - 0.50 RIGU P PRE HOLD RIG EVAC DRILL AND COMPLY WITH RIG ACCEPT CHECK LIST AAR: WAS DISCUSSED THAT THE CREW HAD TWO NEW HANDS AND THEY MUST BE BROUGHT UP TO SPEED ON WHERE THINGS TARE ON THE RIG. RIG ACCEPTED AT 12:00 TO MPJ -01 OPPS 12:00 - 15:30 3.50 RIGU N WAIT ! PRE WAIT ON DSM AND SEAWATER TRUCKS THAT ARE STUCK BEHIND NABORS 9 ES RIG 15:30 - 18:30 !i 3.00 RIGU P PRE MOVE ON SPINE RD RU FLOW BACK TANK AND HARD LINE RU CELLAR - ON FLUIDS TO PITS - -- - --- 18:30 - 19:00 _TAKE 0.50 l RIGU P PRE PERFORM RIG EVAC DRILL AND ASSOCIATED AAR WITH SECOND RIG CREW -AAR: WENT WELL EVERYBODY WAS ACCOUNTED FOR AND SIGN IN ROSTER WAS UP TO DATE. ONE FINDING WAS THAT THERE WAS SOME CONFUSION AROUND WHAT THE RESPPONSIBILITIES FOR THE FORKLIFT OPERATOR. WSL ASKED THE TOOL PUSHER TO PULL THE DDI PROCEDURE AND MAKE SURE ' EVERYBODY KNOWS THEIR ROLES AND RESPONSIBILITIES & THEY ARE CLEARLY WRITTEN IN THE PROCEDURE. I 19:00 21:00 2.00 WHSUR P WHDTRE PRESSURE TEST SURFACE LINES TO 3500, PSI ON UP STREAM SIDE AND TO 500 PSI DOWN STREAM OF THE CHOKE. RU DSM LUBRICATOR AND TEST TO 250/3500 PSI !CHARTED -PULL BPV WITH 400 PSI WHP - DSM LUBRICATOR 21:00 - 22:30 1.50 WHSUR P WHDTRE BLEED DOWN TUBING AND IA TO 0 PSI LE -SHUT IN FOR 5 MIN AND REOPEN STILL 0 PSI . WHP -PJSM WITH CH2 TRUCK DRIVERS FOR --- - - --- - - - -- lCIRCULATINGOUTWELL Printed 5/11/2011 10:21:14AM Orth America - ALASKA - BP Page 2 of 4' Operation Summary Report Common Well Name: MPJ-01 AFE No X4-OORVH-E (450,000.00) Event Type: WORKOVER (WO) Start Date: 4/15/2011 End Date: Project: Milne Point Site: M Pt J Pad Rig Name/No.: DOYON 16 Spud Date/Time: 12/1/1999 12:00:OOAM Rig Release: 4/25/2011 Rig Contractor: DOYON DRILLING INC. UWI: 500292207000 Active Datum: 4: 01 11/11/1999 15:00 @65.65ft (above Mean Sea Level) Date From - To HrsTask Code NPT NPT Depth Phase Description of Operations --- 22:30 - 00:00 1.50 WHSUR P WHDTRE PUMP 25 BBLS DOWN TUBING TAKING RETURNSOUT IA TO TIGER TANK AT 5 BPM & 680 PSI -GOT MINIMAL RETURNS BACK TO TT -BULL HEAD IN 500 BBLS DOWN TBG AND IA @ 7 BPM & 1240 PSI -SD AND SECURE WELL WITH 200 PSI WHP, ALLOW PRESSURE/FORMATION TO RELAX - RELAXED TO 0 PSI 4/23/2011 00:00 - 01:00 -— j 1.00 WHSUR P WHDTRE COMPLETE BULL HEAD OPS AND MONITOR I WELL. -BLOW DOWN AND R/D CIRCULATING LINES. 01:00 - 03:00 2.00 WHSUR P i WHDTRE R/U DSM LUBRICATOR AND TEST. j -SET TWC AND TEST FROM BELOW AT 500 PSI @ 4 BPM. -TEST FROM ABOVE AT 250/3500 PSI HIGH PRESSURE. 03:00 - 06:30 3.50 WHSUR P WHDTRE ND 2-9/16" TREE CAMERON REP TO FUNCTION THE LDS. ;- CHECK LANDING JT HANGER THREAD MAKE UP; 10-1/2 TURNS. 06:30 - 09:00 7 2.50 f _ ---�-- — BOPSUR P WHDTRE 1 N/U 13-5/8" 5M HYDRIL BOPE AND 13-3/8" X 11" ADAPTER SPOOL. i- WITH A FOUR PREVENTER MAKE UP. -ANNULAR. - 2-7/8" X 5" VBR. - BLIND SHEAR. j - MUD CROSS. 09:00 - 09:30 1 0.50 SOPSUR - 2-7/8" PIPE RAM. P WHDTRE RIG UP PRESSURE TESTING EQUIPMENT. 09:30 - 16:00 6.50 BOPSUR P WHDTRE PRESSURE TEST 13-5/8" HYDRILL BOPE - PRESSURE TEST TO 250 LOW / 3500 PSI HIGH FOR 5 CHARTED MIN. - JEFF JONES WITH AOGCC WAIVED RIGHT ITO WITNESS TESTING. -ALL TEST WITNESSED BY BP WSL & DDI TP. - ALL TEST FOLLOW TESTING CRITERIA DOCUMENTED IN CRT-AK-10-45 MAINTAINING 20 BPH CONTINUOUS HOLE FILL IN THE IA DURING TESTING. KOOMEY DRAW DOWN TEST: -2850 PSI DRAWN DOWN TO 1675 PSI. -200 PSI INCREASE IN 20 SECONDS. -FULL PRESSURE IN 90 SECONDS. _ -5 N2 BOTTLES @1975 _PSI. - 16:00 - 16:30 li 0.50 BOPSUR P WHDTRE '', DERRICK INSPECTION. REMOVE DERRICK PER TP. -.LIGHT 17:30 1.00 PULL P DECOMP R/U: OPSO-LOPSO, HANG ESP SHEAVE & TRUNK. SPOOLING UNIT. - _-SPOT -- I DECOMP R/U XO, PUMP IN SUB & LUBRICATOR. 17:30 - 23:00 5.50 PULL I P I -TEST TO 250 PSI LOW & 1500 PSI HIGH PRESSURE. -ATTEMPT TO PULL TWC... NO-GO. -R/D LUBRICATOR, FLUSH & VACUUM ON TOP OF TWC. -R/U & TEST LUBRICATOR. PULL TWC. R/D LUBRICATOR. J-MR ON PULLING TWC. Printed 5/11/2011 10:21:14AM 8c, orth America - ALASKA - BP Page 3 of 4 Operation Summary Report Common Well Name: MPJ -01 AFE No X4-OORVH-E (450,000.00) Event Type: WORKOVER (WO) Start Date: 4/15/2011 End Date: Project: Milne Point Site: M Pt J Pad Rig Name/No.: DOYON 16 Spud Datefrime: 12/1/1999 12:00:OOAM Rig Release: 4/25/2011 Rig Contractor: DOYON DRILLING INC. UWI: 500292207000 _ Active Datum: 4: 01 11/11/1999 15:00 @65.65ft (above Mean Sea Level) Date From - To Hrs Task Code NPT NPT Depth 1 Phase Description of Operations (ft 23:00 - 00:00 0 1 PULL P �) 1 DECOMP M/U LANDING JT TO HANGER. BOLDS. -PULL HANGER FREE W/ 75K, PUW= 70K. STAGE UP PUMPS TO 5 BPM / 800 PSI AND CBU. - -- -- ---.._�- - — 4/24/2011 00:00 - 01:00 1.00 PULL P DECOMP CONTINUE TO CBU AT 5 BPM @ 800 PSI -OBTAINED STATIC LOSS RATE OF 109 BPH 1101:00 01:30 0.50 PULL p --=- DECOMP (TERMINATE ESP CABLE -LD HANGER AND LD JOINT -BD CIRCULATING LINES ---i01:30 - 06:30 5.00 PULL P DECOMP tPOOH WITH 2-7/8" ESP COMPLETION LAYING TUBING FROM 3,471 DOWN -CONTINUOUS HOLE FILL @ 30BPH DURING OPERATIONS 06:30 - 10:00 3.50 PULL P DECOMP BREAK AND LAYDOWN ESP PUMP & MOTOR ASSEMBLY. j - CENTRILIFT REPS DIRECTING ESP DECOMPLETE CONTINUOUS HOLE FILL @ 30BPH 10:00 - 11:00 1.00 PULL P DECOMP CLEAN AND.CLEAR RIG FLOOR - PREP FOR RUNNING COMPLETION - RD ELEPHANT TRUNK, - SWAP SPOOLS, --- --- - -- - _----- _ - LAYING DOWN CLAMPS RING 11:00 15:00 4.00 RUNCOM P RUNCMP NEW ESP CABLE UP THRU SHEIVE - START PICKING UP ESP PUMP & MOTOR j ASSEMBLY. MAKING UP ESP ASSEMBLY AS DIRECTED BY CENTRILIFT REP. 15:00 - 22:00 7.00 RUNCOM T P - CAMERON REP VERIFIED THE CORRECT ALIGNMENT FOR PIN ORIENTATION. RUNCMP RIH WITH ESP COMPLETION ON 106 JTS OF �2-7/8" 6.5# EUE TUBING IH ON SINGLES FROM PIPE SHED - USED 61 LESALLE CLAMPS ON EVERY OTHER COLLAR - MU TO 2300 FT/LBS USING BEST 0 LIFE PIPE DOPE CHECKING CONDUCTIVITY AT THE START AND EVERY 2000' - REDRESS HANGER, MU LANDING JOINT 22:00 - 00:00 2.00 WHSUR P RUNCMP TERMINATE ESP CABLE AT TUBING HANGER -FILL TBG AND CIRCULATE 10 BBLS AT 1 BPM @ 660 PSI. -CONTINUE TO MAINTAIN CONTINUOUS HOLE FILL AT 20 BPH THROUGH IA -- - - 4/25/2011 00:00 - 01:30 1.50 WHSUR P - RUNCMP CONTINUE TO INSTALL ESP CABLE TO WELL HEAD PENATRATOR AND TEST. 01:30 02:30 li 1.00 WHSUR P RUNCMP !LAND TUBING HANGER AND RILDS. -PUW= 65K. SOW= 65K. - 61 LASALLE CLAMPS RAN. 02:30 - 03:30 1.00 WHSUR P _ RUNCMP INSTALL TWC. -TEST FROM ABOVE AT 250 PSI LOW & 5000 PSI HIGH - 10 MIN CHARTED. -TEST FROM BELOW WITH ROLLING TEST OF 500 PSI @ 5 BPM - 10 MIN CHARTED. - -_ -- - - 03:30 - 05:00 1.50 BOPSUR P RUNCMP N/D BOP'S. N/U TREE & ADAPTOR._ - CENTRILIFT MAKING FINAL CHECKS WITH ESD MOTOR AND PUMPS, ALL CHECKS - - - - - - --- -- - GOOD. Printed 5/11/2011 10:21:14AM Orth America - ALASKA - BP Page 4 of 4 Operation Summary Report Common Well Name: MPJ -01 AFE No Event Type: WORKOVER (WO) Start Date: 4/15/2011 End Date: X4-OORVH-E (450,000.00) Proiject Milne Point Site: M Pt J Pad Rig Name/No.: DOYON 16 Spud Date/Time: 12/1/1999 12:00:OOAM Rig Release: 4/25/2011 Rig Contractor: DOYON DRILLING INC. UWI: 5.00292207000 Active Datum: 4: 01 11/11/1999 15:00 @65.65ft (above Mean Sea Level) Date From - To Hrs 1 Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 05:00 - 08:30 3.50 WHSUR P RUNCMP TEST ADAPTOR & TREE. - HAD A PROBLEM WITH THE CONTINUOUS CONTROL LINE PLUG NOT HOLDING PRESSURE. -INSTALLED NEW 11"X 2-9/16" ADAPTER FLANGE. '- R/D TREE AND ADAPTER - PREPARE FOR RIG MOVE TO MPE-15. 08:30 - 12:00 3.50 WHSUR P _ RUNCMP N/U NEW ADAPTER FLANGE AND TREE. PRESSURE TESTED HANGER VOID TO 250 PSI LOW & 5000 PSI HIGH FOR 30 CHARTED MIN. - PRESSURE TEST TREE TO 5000 PSI FOR 30 CHARTED MIN. ALL TESTS GOOD. 12:00 - 15:00 3.00 WHSUR P _ RUNCMP R/U LUBRICATOR & PRESSURE TEST/ - PT TO 250 LOW AND 1500 HIGH FOR 5 CHARTED MIN, -OK. - PULL TWC AND INSTALL BPV. - PERFORMED ROLLING TEST. - PUMPED 60 BBLS @ 4 BPM @ 290 PSI FOR '10 MIN. i -RIG RELEASED @ 15:00 LRS TO PERFORM FREEZE PROTECT POST RIG MOVE —'� ***RDMO... Printed 5/11/2011 10:21:14AM Tree: WKM 2 9/16" 5M Wellhead: 11" x 11" 5M tbg. s 11"x27/8"8 rdELIE(top &bo WKM tbg. hng. w/ 2.5" 'H' BPV profile. 13 3/8", 54.5 ppf, K-55 Butt 9 5/8", 36 ppf, K-55, Btrc. 2409' KOP @ 1500' Max Hole Angle: 26' @ 2500' MD Hole angle through perfs = 20 deg. 2 7/8" 6.5 ppf, L-80, 8 rd EUE tbg (drift ID = 2.347", cap. = 0.00592 bpf) 7" 26 ppf, L-80, BTC production casing (drift ID = 6.151", cap. = 0.0383 bpf) (cap. w/ tbg inside = 0.02758 bpf) Baker 5" x 7" HMC Liner hgr 3,512' Baker HMCV Cementing valve 4,682' Baker CTC 20' PZP ESP 4,704' MP J -01A 2-3/8" liner top w/ 3.70" deploy sleeve @ 4567' 4-1/2" SLOTTED INTERVALS 4810' - 4852' Open 4892'-5301' Open 5340'-5743' Open 5784'-6195' Open 6236'-6644' Open 6682' - 7091' Open 2-3/8" SLOTTED INTERVALS 4623'-4816' Open 4848'-5167' Open 5199'- 5520' Open 5552'-5868' Open 5900'-6222' Open 6254'-6575' Open 6607'- 6928' Open 6978'-7676' Open Old bottom hole location PERFORATION SUMMARY Size SPF Interval Open/ Sqzd 3426` 90-Pl7 & 18-P75 MVP "N'Sands Both Model - SXD 4.5" 24 4010'4036' Sqzd 4.5" 24 4042'-4082' Sqzd 4.5" 24 4098'4128' "O" Sands Sqzd 4.5" 12 4192'4222' Sqzd 4.5" 12 4258'-4282' Sqzd 4044-4065 Open 4.5" 12 4069-4089 Open 4.5' 12 41884218 Open 45' 12 42604280 Open TIW Whipstock @ 4835' Window 4,837'- 4843' KB elev. = 70.2' ev. = 68.7' ev. = 35.2' Camco 2 7/8"x 1" sidepocket KBMM GLM 171' Camco 2 7/8" x 1" sidepocket KBMM GLM 3259' 2 7/8" XN Nipple (2.205 min ID) 3404` Dual Tandem Pumps, 3426` 90-Pl7 & 18-P75 MVP 04/04/95 02/21/97 Both Model - SXD RWO/ MULTIPLE FRAC PACKS ESP Replacement by Nabors 4ES Gas Separator 3446' GRSFTX AR H6 5/27/01 8/20/03 Tandem Seal Section 3451' GSB3 DB UT/LT SB/SB PFSA/FSA CL5 Lee Hulme Motor, 114 HP, 2330 vo11, 30 amp, Model KMH 3465 PumpMate w/6 fin Centr TVD =3350' 3476` 899' I Open 6-1/8" hole TD @ 8034' J -01a L-1 lateral 2-3/8" L-80 pre -drilled slotted liner Guide shoe 7709' TD 7950' DATE REV. BY COMMENTS 04/04/95 02/21/97 DBR JBF RWO/ MULTIPLE FRAC PACKS ESP Replacement by Nabors 4ES 12/05/99 MDO S/T & Comp. Nabors 4 -ES & Nordic #3 5/27/01 8/20/03 BMH Lee Hulme 2nd Lateral 3S, Nabors 4ES completion Replace ESP - Nabors 4ES 8/20/03 Lee Hulme Replace ESP - Doyon 16 " HES cement retainer at 3669' ES Versatrieve packer @ 3923' MD 1.880- ID) 2'- 20 ga screen ES X nipple 2.75" ID @ 4148' MD ES Vematneve packer @ 4138' MO 2'-20 Ga screen IES VersaMeve packer @ 4223' MD 1.88"10) 4'- 20 ga screen IES BWD Sump packer @ 4290' MO 1.00" ID) 7" Moat collar (PBTD) g45q 7" casing shoe MILNE POINT UNIT WELL J -01A API NO: 50-029-22070 BP EXPLORATION �A PT -0 l i L_ k STATE OF ALASKA ALASK4aiL AND GAS CONSERVATION CO(.AISSION REPORT OF SUNDRY WELL OPERATIONS 1. Type of Request: ❑ Abandon ❑ Suspend ❑ Operation Shutdown ❑ Perforate ❑ Variance ® Othe! ❑ Alter Casing ® Repair Well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension Change Out ESP ❑ Change Approved Program ® Pull Tubing ❑ Perforate New Pool ❑ Re -Enter Suspended Well ❑ Annular Disposal 2. Operator Name: 4. Current Well Class: 5. Permit To Drill Number BP Exploration (Alaska) Inc. ® Development ❑ Exploratory ❑ Stratigraphic ❑ Service 199-111 3. Address: 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-22070-01-00 7. KB Elevation (ft): KBE = 65.66' 9. Well Name and Number: MPJ -01A 8. Property Designation: 10. Field / Pool(s): ADL 315848 Milne Point Unit / Schrader Bluff 11. Present well condition summary Total depth: measured 8034 feet true vertical 4141 feet Plugs (measured) N/A Effective depth: measured 8034 feet Junk (measured) N/A true vertical 4141 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 70' 13-3/8" 105' 105' 2730 1130 Surface 2374' 9-5/8" 2409' 2364' 3520 2020 Intermediate Production 3605' 7" 3640' 3502' 7240 5410 Liner 3623' 4-1/2" 3512'- 7135' 3383'- 4108' Perforation Depth MD (ft): Slotted Liner: 4810'- 7091' Perforation Depth TVD (ft): Slotted Liner: 4035'- 4106' Tubing Size (size, grade, and measured depth): 2-7/8", 6.5# L-80 3476' Packers and SSSV (type and measured depth): N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): 3Ep, 23 0` Treatment description including volumes used and final pressure: W; U:. f_�L•;A 4` ".r"fir6}1 r.1 .. 1,6 '4.9 uA�II :I IIY, n". }�1 A'' 13. Representative D ily Average Production or In'ectio&,. 9 Oil -Bbl Gas-Mcf Water -Bbl Casina Pressure Tubinq Pressure Prior to well operation: 489 543 158 Subsequent to operation: 382 98 292 14. Attachments: 15. Well Class after proposed work: ❑ Copies of Logs and Surveys run ❑ Exploratory ® Development ❑ Service 16. Well Status after proposed work: ® Daily Report of Well Operations ® Oil ❑ Gas ❑ WAG ❑ GINJ ❑ WINJ ❑ WDSPL 17. 1 hereby certify that the foregoing is true and correct tot the best of my knowledge. Sundry Number or N/A if C.O. Exempt: Contact Robert Odenthal, 564-4387 Printed Name Sondra Stewman Title Technical Assistant Sig ature ��rr Prepared By Name/Number: Phone 564-4750 Date �.`��E' " �. "(� Sondra Stewman, 564-4750 Form 10 -404 -Revised 2/2003 RWMS 8� LSES 2 3 2003 BP EXPLORATION Operations Summary Report Legal Well Name: MPJ -01 Common Well Name: MPJ -01A Event Name: WORKOVER Contractor Name: NABORS ALASKA DRILLING I Rig Name: NABORS 4ES Date I From - To Hours Task Code NPT 8/19/2003 00:00 - 02:30 2.50 MOB P 1.00 02:30 - 03:30 1.00 RIGU P PULL P 03:30 - 04:30 1.00 RIGU P 07:00 - 08:00 04:30 - 06:00 1.50 RIGU P 06:00 - 06:30 1 0.501 WHSUR I P 06:30 - 09:00 1 2.501 KILL I P 09:00 - 09:30 0.50 WHSUR I P 09:30 - 10:00 0.50 WHSURIP 10:00 - 12:00 2.00 BOPSU P 12:00 - 13:00 1.00 BOPSU P 13:00 - 14:00 1.00 WHSUR P 14:00 - 14:30 0.50 PULL P 14:30 - 17:30 3.00 PULL P 17:30 - 20:00 1 2.501 PULL IP 20:00 - 21:00 1 1.001 PULL I P 21:00 - 23:00 2.00 RUNCO 23:00 - 00:00 1.00 RUNCO 18/20/2003 00:00 - 02:00 2.00 RUNCO 02:00 - 04:00 2.00 RUNCOMP 04:00 - 04:30 0.50 BOPSU P 04:30 - 06:00 1.50 BOPSU P 06:00 - 07:00 1.00 WHSUR P 07:00 - 08:00 1.00 WHSUR P Start: 8/19/2003 Rig Release: 8/20/2003 Rig Number: 4ES Page 1 of 1 Spud Date: 12/1/1999 End: 8/20/2003 Phase I Description of Operations PRE Move from F-58 to J -01A. PRE Spot Sub, Pipe Shed, Pits, and Camp. PRE Raise and Scope Dreeick. PRE Take 140 deg F. 2% KCL Water in Rig Pits. Lay lines to Tiger Tank and Production Tree. Crew change. DECOMP PJSM. Pick-up Lubricator. Pull BPV. Lay down same. Pressure test lines to 3500 psi. Good. DECOMP Open Well. Tbg pressure 70 psi. Annulus presure 790 psi. Bleed gas from Annulus. Attempted to circulate well, however unable to get returns. Bullhead Kill well with 2% KCL Water at 4 -5 bpm/100 psi. Monitor Well. Well on vacuum. DECOMP Set TWC and test. DECOMP Nipple down Production Tree. DECOMP N/U BOPE. C/O pipe rams, install 2 7/8" x 5" pipe rams. Function test pipe rams. DECOMP Body test on BOPE, 250 / 3500 psi, OK. DECOMP Pick up lubricator, pull two way check valve. DECOMP BOLDs. Pull hanger to floor, 42K up wt. L/D hanger. DECOMP POOH w/ 2 7/8" ESP completion string, double displacing hole, well stable. Spool up old cable. Recovered 7 protectrolizers, 3 flat guards & 61 LaSalle clamps. DECOMP Break out & L/D ESP. Bolts were frozen & much scale on pump. R/D tiger tank. DECOMP Clear & clean rig floor. R/D elephant trunk. Change out old cable spool. COMP M/U & service new ESP. COMP RIH w/ new ESP & new cable. Ran 15 stands 2 7/8" tbg. COMP Con't to RIH w/ 2 7/8" ESP completion. Space out & M/U hanger. Ran 106 jts 2 7/8" Tbg. COMP Splice ESP cable to hanger penetrator. Check & test same. COMP Set two way check valve. COMP Nipple down BOPE. COMP Nipple up tree. Test void & tree to 5000 psi, OK. COMP Pick up lubricator. Pull two way check, set BPV. Secure well. Rig released @ 08:00 hrs, 8/20/2003. Printed: 8/25/2003 9:06:29 AM DATA SUBMITTAL COMPLIANCE REPORT 2/5/2002 Permit to Drill No. 1991110 Well Name/No. MILNE PT UNIT SB J -01A Operator BP EXPLORATION (ALASKA) INC API No. 50-029-22070-01-00 MD 8034 TVD 4141 Completion Date 12/3/1999 `� Completion Status 1 -OIL Current Status 1 -OIL UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey No DATA INFORMATION Types Electric or Other Logs Run: (data taken from Logs Portion of Master Well Data Maint) Well Log Information: 7l Log/ Data Digital Digital Log Log Run Interval OH / Dataset Type Media Format Scale Media No Start Stop CH Received Number Comments ((Name DGR/EWR4-MD 25 FINAL 3643 8034 OH 1/11/2000 DGR/EWR4-TVD 25 FINAL 3505 4041 OH 1/11/2000 13l SRVY RPT 45 8034 OH 1/19/2000 SPERRY 3595.. y 3630-7984 O 1/4/2000C0968 5 Well Cores/Samples Information: Interval Dataset Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y / N Daily History Received? N Chips Received? Y / N Formation Tops Receuived?N Analysis Received? Y / N Comments: Compliance Reviewed By: _._ _ _ Date: _ . , MEMORANDUM TO: THRU: FROM: Len State of Alaska Alaska Oil and Gas Conservation Commission Julie Heusser, ,- .�= DATE. Commissioner Tom Maunder, P. 1. Supervisor Chuck Scheve; Petroleum Inspector April 22, 2001 SUBJECT: Safety Valve Tests Milne Point Unit J & I Pads Sunday April 22.2001: 1 traveled to BPXs MPU J & I Pads and witnessed the semi annual safety valve system testing. As the attached AOGCC Safety Valve System Test Report indicates I witnessed the testing of 17 wells and 34 components with no failures. Lee Hulme performed the testing today; he demonstrated good test procedures and was a pleasure to work with. I also inspected the well houses on these pads during the SVS testing. All the wellhouses were very clean and the equipment appeared to be in excellent condition. Summary: I witnessed SVS testing at BPXs MPU J & 1 Pads. MPU J Pad, 11 wells 22 components 0 failures MPU I Pad .fi wells 12 components 0 failures 23 wellhouse inspections Attachment: SVS MPU J Pad 4-22-01 CS SVS MPU I Pad 4-22-01 CS X Unclassified Confidential (Unclassified if doc. removed ) v Alaska Oil and Gas Conservation Commission Safety Valve System Test Report RJF 1/16/01 Page 1 of 1 SVS MPU I Pad 4-22-01 CS Operator: BPX Operator Rep: Lee Hulme AOGCC Rep: Chuck Scheve Submitted By: Chuck Scheve Date: Field/Unit/Pad: Milne Point / MPU / I Pad Separator psi: LPS 140 HPS 4/22/01 ,SSV Retest Well Type Well Number Permit Number Separ PSI Set PSI UP Trip Test Code Test Code Test Code Date Passed OH, WAG, GINJ, GAS or CYCLE I-01 1900900 I-02 1900910 140 100 95 P P OIL I-03 1900920 140 100 95 P P OIL 1-04 1900930 140 100 95 P P OIL I-06 1971950 140 1001 95 P P OIL I-07 1951510 140 100 95 P P OIL 1-08 1971920 140 100 95 P P OIL Wells: 6 Remarks: Components: 12 Failures: 0 Failure Rate: 0.00% ❑ 90 Day RJF 1/16/01 Page 1 of 1 SVS MPU I Pad 4-22-01 CS 3 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPX Submitted By: Chuck Scheve Date: 4/22/01 Operator Rep: Lee Hulme Field/Unit/Pad: Milne Point / MPU / J Pad AOGCC Rep: Chuck Scheve Separator psi: LPS 1 140 HPS Wells: 11 Components: 22 Failures: 0 Failure Rate: 0.00% Cl 90 Day Remarks; RJF 1/16/01 Page 1 of 1 SVS MPU J Pad 4-22-01 CS SSS V Retest hype Yell Number Permit Separ Number PSI Set PSI UP Tri Test Code Test Code Test Date G, GMJ, FCA Code Passed r CYCLE J-01 A 1991110 140 100 95 P P OIL J-03 1900970 140 100 95 P P OIL J-04 1900980 140 100 95 P P OIL J-05 1910950 140 100 95 P P OIL J-06 1940950 140 100 125 P P OIL J-07 1910970 140 100 95 P P OIL J -08A 1991170 140 100 95 P P OIL J -09A 1991140 140 100 110 P P OIL J-10 1941100 140 100 95 P P OIL J-11 1941140 J-12 1941180 J-18 1972200 J -19A 1951700 J-20 1972150 J-21 1972000 140 100 95 P P OIL J-22 1981240 140 100 95 P P OIL IJ -23 1 2001200 Wells: 11 Components: 22 Failures: 0 Failure Rate: 0.00% Cl 90 Day Remarks; RJF 1/16/01 Page 1 of 1 SVS MPU J Pad 4-22-01 CS .. f( 'f 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 ❑ Suspended ❑ Abandoned ❑ Service 2. Name of Operator BP Exploration (Alaska) Inc. 7. Permit Number 199-111 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 - 8. API Number 50-029-22070-01 4. Location of well at surface 2622' SNL, 3378' WEL, Sec. 28, T13N, R10E, UM At top of productive interval `� 1127' SNL, 3692' WEL, Sec. 28, T13N, R10E, UMC At total depth y- 2046' NSL, 3075' WEL, Sec. 21, T13N, R10E, UM - 9. Unit or Lease Name Milne Point Unit 10. Well Number MPJ -01A 11. Field and Pool Milne Point Unit /Schrader Bluff 5. Elevation in feet (indicate KB, DF, etc.) 6. KBE = 65.65' Lease Designation and Serial No. ADL 315848 12. Date Spudded 11/23/99 13. Date T.D. Reached 11/27/99 14. Date Comp., Susp., or Aband. 12/3/99 15. Water depth, if offshore N/A MSL 16. No. of Completions One 17. Total Depth (MD+TVD) 8034 4141 FT 18. Plug Back Depth (MD+TVD) 8034 4141 FT 19. Directional Survey0. M Yes ElNo r Depth where SSSV set N/A MD 21. Thickness of Permafrost 1800' (Approx.) 22. Type Electric or Other Logs Run MWD, GR, PWD 23• CASING LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE TOP BOTTOM SIZE CEMENTING RECORD AMOUNT PULLED 13-3/8" 54.5# K-55 35' 105' 30" 500 sx Permafrost 'C' 9-5/8" 36# K-55 35' 2409' 12-1/4" 1145 sx Permafrost 'E' 7" 26# L-80 35' 3640' 8-1/2" 393 sx Class 'G' 4-1/2" 12.6# L-80 3512' 7135' 6-1/8" 97 sx Class'G' 24. Perforations open to Production (MD+TVD of Top and Bottom and interval, size and number) 4-1/2" Slotted Intervals MD TVD MD TVD 4810' - 4852' 4035'- 4035' 4892'- 5301' 4035'-4049' 5340'-5743' 4048'-4065' 5784'- 6195' 4068'- 4095' 6236'-6644' 4096'- 4093' 6682'- 7091' 4093'- 4106' 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD) 2-7/8", 6.5#, L-80 3399' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 2200' Freeze Protect with 20 Bbls of Diesel 27. PRODUCTION TEST 4 Date First Production December 22, 1999 Method of Operation (Flowing, gas lift, etc.) �ti�,,ra<<1 ijii �� ,, (i;;��Ifti(8 Electric Submersible Pump , . �. ,. Date of Test Hours Tested PRODUCTION FOR TEST PERIOD OIL -BBL GAS -MCF WATER -BBL CHOKE SIZE GAS -OIL -kA T-16' Flow Tubing Press. Casing Pressure ID CALCULATE 24-HOUR OIL -BBL GAS -MCF WATER -BBL OIL GRAVITY -API (CORR) 28, RATE CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Form 10-407 Rev. 07-01-80 Submit In Duplicate Eorlk 29. Geologic Markers 30. Formation Tests Marker Name Measured True Vertical Include interval tested, pressure data, all fluids recovered and Depth Depth gravity, GOR, and time of each phase. Top Ugnu 3742' 3595' SBF2 - NA 4090' 3851' SBF1 - NB 4141' 3881' SBE4 - NC 4202' 3913' SBE2 - NE 4263' 3937' SBE1 - NF 4461' 3995' TSBD - OA 4692' 4030' RECEIVED JAN 19 2000 A1NM 0B & Gas Cons. Arfw 31. List of Attachments Summary of Daily Drilling Reports, Surveys 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge Signed , Terrie4"HubbleHubble Title Technical Assistant III Date MPJ -01A 199-111 Prepared By Name/Number.- Terrie Hubble, 564-4628 Well Number Permit No. / Approval No. INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage 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 Rev. 07-01-80 Facility M Pt J Pad Progress Report Well MPJ-OIA Rig Nordic3 Page 1 Date 06 December 99 Date/Time Duration Activity 20 Nov 99 18:01-01:00 6-3/4 hr Move rig 18:01-20:00 1-3/4 hr Rig moved 100.00 % Move & spot camp. Pull rig off MP J-151. Spot mats & herculite. Spot rig on MP J-OIA. Clean up around J- 15i and set well guard. Rig accepted @ 2000 hrs on 11/20/99. 20:00 At well location - Cellar 20:00-01:00 5 hr Rigged up Drillfloor / Derrick Spot misc equipment and berm everything. 21 Nov 99 01:00 Equipment work completed 01:00-02:45 1-3/4 hr Wellhead work 01:00-02:30 1-1/2 hr Removed Xmas tree ND tree & adapter. Pull BPV and hanger. 02:30 Equipment work completed 02:30-02:45 1/4 hr Rigged up BOP test plug assembly Set BOP test plug. RECEIVED 02:45 Equipment work completed 02:45-05:30 2-3/4 hr Nipple up BOP stack 02:45-05:30 2-3/4 hr Rigged up BOP stack JAN 19 2000 05:30 Equipment work completed 05:30-06:00 1/2 hr Test well control equipment AMA Oil & Ga Cons. Q mmim 05:30-06:00 1/2 hr Tested BOP stack Ard10 e Start testing BOPE. -' 05:30-06:00 1/2 hr Tested BOP stack Finish testing BOPE to 250 / 3500 psi; annular ro 250 / 2500 psi. Witnessing waived by Chuck Scheave. 06:00-10:30 4-1/2 hr Test well control equipment (cont...) 06:00-10:00 4 hr Tested BOP stack (cont...) Finish testing BOPE to 250 / 3500 psi; annular ro 250 / 2500 psi. Witnessing waived by Chuck Scheave. 10:00 Pressure test completed successfully - 3500.000 psi 10:00-10:15 1/4 hr Retrieved BOP test plug assembly 10:15 Equipment work completed 10:15-10:30 1/4 hr Installed Wear bushing 10:30 Eqpt. work completed, running tool retrieved 10:30-21:00 10-1/2 hr 3-1/2in. Drillpipe workstring run 10:30-12:00 1-1/2 hr Rigged up Drillstring handling equipment RU pipe spinner & XO Kelly cocks. 12:00 Equipment work completed 12:00-12:30 1/2 hr Tested Top drive Test upper & lower kelly cocks. 12:30 Pressure test completed successfully - 3500.000 psi 12:30-16:00 3-1/2 hr Singled in drill pipe to 2200.6 ft RIH w/ mule shoe, 9-4.75" DC, 33-3.5" HWDP, & 27-3.5" DP. D1 Drill; OS :46 secs. 16:00 69 joints picked up 16:00-17:00 1 hr Circulated at 2200.6 ft Displace diesel out of well. 17:00 Hole displaced with Seawater - 120.00 % displaced 17:00-19:00 2 hr Held drill (Stripping) Held stripping drill w/ both crews. 19:00 Drill abandoned 19:00-21:00 2 hr Pulled out of hole to 0.6 ft LD TIW & Dart valve. Cont out. LD mule shoe. Progress Report Facility M Pt J Pad Well MPJ -01A Page 2 Rig Nordic3 Date 06 December 99 Date/Time Duration Activity 20:00 At BHA 21:00 At Surface : 0.6 ft 21:00-06:00 9 hr BHA run no. 1 21:00-21:15 1/4 hr Made up BHA no. 1 Prep to pick up whipstock. 21:15 Stopped : To hold safety meeting 21:15-22:00 3/4 hr Held safety meeting Held prespud meeting with all personnel. Discussed well plan. (horizontal section, bonzai/innerstring liner job, mud system, close approach issues, & whipstock). Stressed the good performance from the team on previous 3 wells. 22:00 Completed operations 22:00-01:30 3-1/2 hr Made up BHA no. 1 MU BHA. Test & orient MWD. PU whipstock. MU remainder of BHA. Blow down. 22 Nov 99 01:30 BHA no. 1 made up 01:30-04:00 2-1/2 hr R.I.H. to 3653.6 ft RIH slow. Tag retainer. IJEWD 04:00 On bottom RECE\ 04:00-04:30 1/2 hr Serviced Mud pump fluid end Check out pump #2. Hammer up flange. JAN 19 200 04:30 Equipment work completed 04:30-05:30 1 hr Set tool face C011S, " 00 8L GN b Break circ and orient whipstock 30L. pNhOMP 05:30 Completed operations 05:30-05:45 1/4 hr Functioned Setting tools Set whipstock. Oriented 30L of high side. Top of ramp @ 3643'. 05:45 Equipment work completed 05:45-06:00 1/4 hr Circulated at 3643.6 ft Displace well to milling fluid. 05:45-06:00 1/4 hr Circulated at 3643.6 ft Finish change over to milling fluid. 06:00-18:00 12 hr BHA run no. 1 (cont...) 06:00-07:00 1 hr Circulated at 3643.6 ft (cont...) Finish change over to milling fluid. 07:00 Hole displaced with Water based mud - 100.00 % displaced 07:00-13:30 6-1/2 hr Milled Casing at 3640.0 ft Mill window off whipstock set 30L from high side. Milled to 3668'. Window appears in good shape. TOW @ 3640'; BOW @ 3656'. 13:30 Completed operations 13:30-14:30 1 hr Circulated at 3668.0 ft Pumped weighted fiber sweep followed w/ Hi -Vis fiber sweep, while reaming window. Metal cuttings cleaned up good. —10 gals metal. 14:30 Hole swept with slug - 150.00 % hole volume 14:30-16:00 1-1/2 hr Pulled out of hole to 1392.0 ft D1 Drill; OS: 38 sec. 16:00 At BHA 16:00-18:00 2 hr Pulled BHA LD mills & bumper sub. Mills in guage. Clear floor. 18:00 BHA Stood back Progress Report Facility M Pt J Pad Well MPJ -01A Page 3 Rig Nordic3 Date 06 December 99 Date/Time Duration Activity 18:00-06:00 12 hr BHA run no. 2 18:00-18:30 1/2 hr Held safety meeting Safety meeting with new crew. Discussed recent LCIR's. 18:30 Completed operations 18:30-23:00 4-1/2 hr Made up BHA no. 2 MU BHA. Load & orient Sperry tools. Test MWD & motor. 23:00 BHA no. 2 made up 23:00-00:00 1 hr Serviced Block line Slip & cut 49' drlg line. 23 Nov 99 00:00 Line slipped and cut 00:00-01:15 1-1/4 hr R.I.H. to 3640.0 ft RECEIVEEI 01:15 At Window: 3640.0 ft 01:15-02:00 3/4 hr Took MWD survey at 3640.0 ft JAN 19 2000 Orient & slide out window to 3668'. 02:00 Acceptable survey obtained at 3640.0 ft al & CGas Cons' Ifrl 02:00-06:00 4 hr Drilled to 3784.0 ft a Sliding out window. kdvmp 06:00-06:00 24 hr BHA run no. 2 06:00-06:00 24 hr Drilled to 4800.0 ft Continue Drictional drilling 6 1/8" hole F/ 3784' to 4800' @ 88 deg. Slide & rotate Geo steer. 24 Nov 99 06:00-08:30 2-1/2 hr BHA run no. 2 06:00-08:30 2-1/2 hr Drilled to 4888.0 ft Continue drictiional drilling 6.125" Hole f/ 4800' to 4888'MD 4034' TVD. (Top of 'OA' sand @ 4690'MD 4030' TVD) 08:30 Reached planned end of run - Directional objective met 08:30-09:30 1 hr BHA run no. 2 08:30-09:30 1 hr Circulated at 4888.0 ft Servey and pump Weighted sweep. 09:30 Hole swept with slug - 200.00 % hole volume 09:30-13:00 3-1/2 hr BHA run no. 2 09:30-12:30 3 hr Pulled out of hole to 1340.0 ft Trip out to shoe slick, Hole takiing right fluff displacement. 12:30 At BHA 12:30-13:00 1/2 hr Pulled BHA L/D BIT & Motor 13:00 BHA Laid out 13:00-06:00 17 hr BHA run no. 3 13:00-14:00 1 hr Downloaded MWD tool Change out MWD -PWD For directional contort. M/U RR Smith 6.125" PDC bit. 14:00 Completed operations 14:00-15:00 1 hr Made up BHA no. 3 Run BHA & 1 stand Test MWD & Motor. 15:00 BHA no. 3 made up 15:00-17:00 2 hr Serviced Crown block Slip and cut drilling line. Service top drive & swivel. Check crown-o-matic. 17:00 Line slipped and cut 17:00-19:00 2 hr R.I.H. to 3675.0 ft RIH to „ window. Orient Sperry -Sun Facility M Pt J Pad Progress Report Well MPJ -01A Rig Nordica Page 4 Date 06 December 99 Date/Time Duration Activity check shot @ 3675' 19:00 At lin casing shoe 19:00-22:00 3 hr Set tool face Orient tool face to slide out of window. Set Sperry -sun counter & computors. Trouble getting computors to line up and track each other. POOH two std's. RIH to 4515' Check shot survey O.K. 22:00 Completed operations 22:00-22:30 1/2 hr R.I.H. to 4888.0 ft RIH to 4800' Wash to bottom @ 4888' No fill. Hole in good condition. 22:30 On bottom 22:30-23:30 1 hr Circulated at 4888.0 ft Circulate & pump sweeps of 30 bbl's each Low vis followed by Hi vis. Followed by New 9%n KCL BaradrilN mud system. Change over soomth. 23:30 Obtained req. fluid properties - 100.00 %, hole vol. 23:30-06:00 6-1/2 hr Drilled to 5220.0 ft Continue drilling Horizonal F/ 4888' to 5220' @ 88 to 89 Degs 25 Nov 99 06:00-06:00 24 hr BHA run no. 3 (cont...) 06:00-20:30 14-1/2 hr Drilled to 5820.0 ft Continue directional drill 6-1/8" hole f/ 5220' to 5820'. Drill & slide making direction turn. Slide RECEI 15' intervals. Add lube to slick up hole for sliding. 20:30 Stopped : To service drilling equipment JAN 19 20:30-21:00 1/2 hr Serviced Top drive Service top drive & swevil. A laft 00 & Gas 21:00 Equipment work completed Ar#M, 21:00-06:00 9 hr Drilled to 6192.0 ft Continue drilling Horizonal 6-1/8" hole F/ 5820' to 6192' Pumping sweeps @ 5000', 5800', 6000' & 6100' First two sweeps brought back quite a good load of cuttiing. The last two pretty clean. ECD 10.8 to 11.1 ppg hole apears to be clean. 26 Nov 99 06:00-06:00 24 hr BHA run no. 3 (cont...) 06:00-13:30 7-1/2 hr Drilled to 6579.0 ft Continue drilling 6-1/8" Horizonal Geodrill f/ 6192' to 6579'. Delute mud system w/ 300 bbl's new 9.6 ppg BaradrillN on the fly. Pump sweeps. ECD 10.9 to 11.2 ppg. 13:30 Started scheduled wiper trip: due to Time elapsed 13:30-14:30 1 hr Circulated at 6579.0 ft Pump Sweeps. Take torque & drag readings. 14:30 Obtained clean returns - 100.00 % hole volume 14:30-16:00 1-1/2 hr Pulled out of hole to 3642.0 ft Short trip to 7" casing shoe. Move HWDP up. Hole in good conditon. 16:00 At 3642.000 in casing shoe 16:00-16:30 1/2 hr Serviced Top drive Service top drive. Take torque & drag readings @ 3690' ED bmmisto Progress Report Facility M Pt J Pad Well MPJ -01A Page 5 Rig Nordic3 Date 06 December 99 Date/Time Duration Activity 16:30 Equipment work completed 16:30-19:30 3 hr R.I.H. to 6579.0 ft RIH and wash last stand to bottom. Hole slick on trip in. 19:30 On bottom 19:30-06:00 10-1/2 hr Drilled to 7162.0 ft Continue drilling from 6579' to 7162' MD. Drilling ahead at report time. 27 Nov 99 06:00-06:00 24 hr BHA run no. 3 (cont...) 06:00-00:00 18 hr Drilled to 8034.0 ft Drilled horizontal hole from 7162' to 8034' MD @ TD, 4140 TVD. Hard streaks from 7800', ECD increasing to 11.5/11.6 at TD. Pump hi -vis weighted sweeps, brought out cuttings. Last 200' of hole were ratty. 28 Nov 99 00:00 Reached planned end of run - Section / well T.D. 00:00-03:00 3 hr Circulated at 8034.0 ft Circulate and condition hole for 2 bottoms -up. ECD came down to 11.29. Pumped two sweeps, one hi -vis, weighted (one ppg over), followed by one hi -vis sweep. Sweeps brought up a load of cuttings and brought ECD down to 11.1. 03:00 Obtained clean returns - 400.00 % hole volume 03:00-04:30 1-1/2 hr Pulled out of hole to 6510.0 ft Short trip past last short trip @ 6579' (15 stands). First 200' from bottom had 5-8klb overpull. Hole good from there to 6510. No losses or gains. Obtained torque and drag readings at TD and 6579' MD. Torque and drag readings repeated. 04:30 At Top of new hole section : 6579.0 ft 04:30-06:00 1-1/2 hr R.I.H. to 8034.0 ft RECEIV RIH to TD, circulate the last stand to bottom. Hole looked good going in. 06:00 On bottom JAN 19 20 0 06:00-14:00 8 hr BHA run no. 3 (cont...) Qf� $c GaS11S. mt�! 06:00-08:00 2 hr Circulated at 8034.0 ft �,j Circulate two bottoms -up followed by 2 hi -vis, All1L�10� to -wt sweeps. Condition hole to run casing. Laid in 100 bbl pill of Baradril-n fluid with slightly higher YP and 5% lubetex. 08:00 Hi -Vis mud spotted downhole 08:00-12:00 4 hr Pulled out of hole to 340.0 ft Drop 1.75" drift for HWDP, drip 2.312" drift for DP. Pump dry job and blow down top drive. 12:00 At BHA 12:00-14:00 2 hr Pulled BHA Retrieve corrosion ring, L/D jars, motor, bit. Down load MWD & L/D same. 14:00 BHA Laid out 14:00-16:00 2 hr BOP/riser operations - Top ram 14:00-16:00 2 hr Installed BOP stack Change top rams to 4-1/2" and test to 250/3500 psi. Install wear ring. 16:00 Equipment work completed Facility M Pt J Pad Progress Report Well MPJ-OIA Rig Nordica Page 6 Date 06 December 99 Date/Time Duration Activity 16:00-06:00 14 hr Run Liner, 4-1/2in O.D. 16:00-17:00 1 hr Held safety meeting Held PJSM on running liner with inner string. Rig up for same. 17:00 Completed operations 17:00-22:00 5 hr Ran Liner to 3600.0 ft (4-1/21n OD) Run 4-1/2" slotted bonzai liner --Shoe jt, slotted liner, one solid jt. every 10 slotted its, 51 slotted total, 36 solid. Ran straight blade turbolators and stop rings on 5 joints above ECP. 22:00 At lin casing shoe 22:00-23:00 1 hr Rigged up Drillstring handling equipment Rig up 2-7/8" handling equipment and false rotary table. Held PJSM on running inner string. 23:00 Equipment work completed 23:00-05:30 6-1/2 hr Ran Drillpipe to 3585.0 ft (2-7/81n OD) Run inner string and m/u hanger and liner top packer. Up wt = 85klb, do wt = 80 klb. 29 Nov 99 05:30 At lin casing shoe 05:30-06:00 1/2 hr Circulated at 3640.0 ft Circulate at 2.4 bbl/min = 440 psi. 06:00-15:30 9-1/2 hr Run Liner, 4-1/2in O.D. (cont...) 06:00-06:30 1/2 hr Circulated at 3600.0 ft Circulate @ 7" shoe w/ 4-1/2" liner. 52 spm, 440 psi. 06:30 Obtained clean returns - 100.00 % hole volume 06:30-11:30 5 hr Ran Drillpipe in stands to 7135.0 ft RIH w/ 4.5" liner in open hole. Landed 5' deep. Experiencing differential sticking after making ��1 connections. 11:30 On bottom 11:30-14:30 3 hr Circulated at 7135.0 ft JAN 19 135klb up wt., 65 do wt. 14:30 Obtained clean returns - 200.00 % hole volume All" ()H & Cx% Con 14:30-15:00 1/2 hr Functioned Sliding sleeve door assembly Drop 29/32" ball. Pump w/ 40 bbls. @ 42 spm, 440 psi. Ball in place @ 677 stks. Pressure up to 1600 psi. Set hgr, stack 40k, pressure up to 2450 @ 14:50 hrs, bleed off pressure, p/u hanger w/ 100k. 15:00 Began precautionary measures 15:00-15:30 1/2 hr Held safety meeting Held PJSM for Dowell cement job. 15:30 Completed operations 15:30-05:00 13-1/2 hr Cement: Liner cement 15:30-17:30 2 hr Functioned Sliding sleeve door assembly Test inner string to 1000 psi. p/u and locate E.C.P., test lines to 5000 psi, inflate ECP pkr @ 750 psi. Shear out ball @ 3400 psi.Pump dart to reverse catcher. 17:30 Equipment work completed 17:30-18:00 1/2 hr Batch mixed slurry - 21.000 bbl Drop plug, displace w/ 28.85 bbls from dowell, bumb plug, Pull up to HMCV-open w/ 2150 psi, switch to ED ommr Facility M Pt J Pad Date/Time Duration 18:00 18:00-21:00 3 hr 21:00 21:00-22:00 1 hr 22:00 22:00-22:45 3/4 hr 22:45 22:45-05:00 6-1/4 hr 30 Nov 99 05:00 05:00-06:00 1 hr 05:00-06:00 1 hr 06:00-16:00 10 hr 06:00-08:00 2 hr 08:00 08:00-15:00 7 hr 15:00 15:00-16:00 1 hr 16:00 16:00-06:00 14 hr 16:00-19:30 3-1/2 hr 19:30 19:30-22:00 2-1/2 hr 22:00 22:00-22:30 1/2 hr 22:30 22:30-02:00 3-1/2 hr 01 Dec 99 02:00 Progress Report Well MPJ -01A Rig Nordic3 Activity Page 7 Date 06 December 99 Batch slurry mixed Mixed and pumped slurry - 21.000 bbl Pump spacer and cement. Close cement port, move down hole and reverse 3 bbls. Shear out @ 4 bpm, 1100 psi. Began precautionary measures Circulated at 7130.0 ft Circulate out excess cement. High pH sand coming over shakers. Obtained clean returns - 200.00 % hole volume Functioned Permanent packer Set liner top packer, test to 1000 psi in annulus. R/U and circulate. Condition mud 125 spm, 1440 psi, pump dry job. Began precautionary measures Functioned Sliding sleeve door assembly POOH Began precautionary measures BOP/riser operations - All functions Rigged up Top ram Change top rams to 2-7/8". BOP/riser operations - All functions (cont...) Rigged up Top ram Finish change top rams to 2 7/8". Equipment work completed Tested BOP stack Test BOP'S and choke manifold to 250/3500 psi, and annular to 250/3000 psi. Test all floor safety valves and upper & an lowerr kelly valves to 250/3500 psi. 3-1/2" pipe rams wouldn't test. Noticed leak on bottom flange and csg spool. Began precautionary measures Retighten flange nuts and test 3-1/2" p -rams and blinds to 250/3500 psi. Test good. BOP test witnessed by John Crisp of AOGCC. RECEI Rigged down High pressure lines Rig down test equipment set wear ring. If Equipment work completed ' ,SAN 19 2000 Run Tubing, 2-7/81n O.D. Ran Tubing to 3640.0 ft (2-7/8in OD) Al OR & GN Cw S. (commis Make up slick stinger and RIH to to 7" window. 9 At lin casing shoe Ran Drillpipe to 7081.0 ft (3-1/2in OD) R!U and RIHwith 3-1/2" DP to 7081' MD. Up wt. _ 73k, do wt. = 60. Began precautionary measures Held safety meeting Held PJSM on diplace well and enzyme spotting. Completed operations Circulated at 7081.0 ft Circulate and displace well to 8.6 ppg. Reciprocate pipe while displacing. Spot Enzyme pill. Obtained req. fluid properties - 400.00 %, hole vol. Progress Report Facility M Pt J Pad Well MPJ -01A Page 8 Rig Nordic3 Date 06 December 99 Date/Time Duration Activity 02:00-03:00 1 hr Pulled Drillpipe in stands to 4698.0 ft 03:00 Began precautionary measures 03:00-06:00 3 hr Circulated at 4698.0 ft Circulate and displace well with clean seawater. 06:00 Hole displaced with Seawater - 100.00 % displaced 06:00-11:30 5-1/2 hr Run Tubing, 2-7/81n O.D. (cont...) 06:00-07:00 1 hr Pulled Drillpipe in stands to 3720.0 ft Continue to POOH with 3-1/2" DP in stands. 07:00 Completed operations 07:00-07:30 1/2 hr Rigged up Winch P/U e -line spooler with crane, set inside rig. 07:30 Equipment work completed 07:30-11:30 4 hr Laid down 3720.0 ft of Tubing Lay down 2-7/8" workstring to 0.0 feet. 11:30 120 joints laid out 11:30-06:00 18-1/2 hr Run Other completion type completion, 2-7/81n O.D. 11:30-12:30 1 hr Functioned Completion equipment Load production equipment in pipeshed: centrilift pumps. R/U completion equipment, p/u clamps. 12:30 Equipment work completed 12:30-18:00 5-1/2 hr Ran Tubing to 3348.0 ft (2-7/8in OD) Run singles into hole, POOH and stand 2-7/8" tubing back in derrick. 18:00 Began precautionary measures 18:00-18:30 1/2 hr Held safety meeting Held PJSM on r/u for ESP completion and sheave. 18:30 Completed operations 18:30-20:30 2 hr Rigged up Winch R/U ESP sheave, I -wire spool & sheave, and heat trace spool. RECEIV 20:30 Equipment work completed 20:30-21:00 1/2 hr Retrieved Wear bushing 21:00 Equipment work completed JAN 19 20 21:00-00:00 3 hr Rigged up sub -surface equipment - ESP Hold PJSM, p/u and service ESP. Aloft 00 & Ga C011s• C 02 Dec 99 00:00 Equipment work completed A�1C�10f8 00:00-06:00 6 hr Ran Tubing in stands to 2000.0 ft Running in hole with ESP completion at report time. 06:00-18:00 12 hr Run Other completion type completion, 2-7/81n O.D. (cont...) 06:00-10:30 4-1/2 hr Ran Tubing in stands to 2697.0 ft Continue to RIH with completion string to stand #29. 10:30 Control lines failed - Abort operation Ouside centrilift spooling unit generator went down. 10:30-11:00 1/2 hr Serviced Control lines Restore power to outside spooling unit. 11:00 Equipment work completed 11:00-14:00 3 hr Ran Tubing in stands to 3399.0 ft Continue to run 2-7/8" ESP completion with ESP cable, heat trace, and I -wire. 14:00 At Setting depth : 3399.0 ft Make up space out pups and tubing hanger. 14:00-16:00 2 hr Installed Control lines Is] Progress Report Facility M Pt J Pad Well MPJ-OIA Rig Nordic3 Page 9 Date 06 December 99 Date/Time Duration Activity connect ESP cable to penatrator. 16:00 Equipment work completed 16:00-18:00 2 hr Installed Tubing hanger Land tubing hanger and RILDS. Lay down landing joint and set BPV. 18:00 Equipment work completed 18:00-19:30 1-1/2 hr Nipple down All functions 18:00-19:30 1-1/2 hr Removed BOP stack N/D BOPE 19:30 Equipment work completed 19:30-01:00 5-1/2 hr Wellhead work 19:30-23:30 4 hr Installed All tree valves NIU tree and test tubing hanger packoff to 5000 psi. Test good. Perform final conductivity test of Baker, Raychem, and Centrilift cables. 23:30 Equipment work completed 23:30-00:00 1/2 hr Tested Xmas tree integral components Test tree to 500 and 5000 psi. All tests good. 03 Dec 99 00:00 Pressure test completed successfully - 5000.000 psi 00:00-01:00 1 hr Installed Lubricator R/U lubricator and pull TWC. 01:00 Equipment work completed 01:00-02:00 1 hr Fluid system 01:00-02:00 1 hr Freeze protect well - 20.000 bbl of Diesel Freeze protect tbg to 2200'. Annulus @ surface w/ 5 bbls. 02:00 Completed operations 02:00-03:30 1-1/2 hr Wellhead work 02:00-03:30 1-1/2 hr Installed Hanger plug Set BPV w/ lubricator. RD lubricator. 03:30 Eqpt. work completed, running tool retrieved 03:30-06:00 2-1/2 hr Move rig 03:30-06:00 2-1/2 hr Rig moved 10.00 % Move rig off MPJ -01A. Clean up cellar & secure. PU herculite. 06:00 Rig off station Rig released @ 0600 hrs on 12/3/99. RECEIVED JAN 1 q 2000 ::�,�.... „Jfnmi North Slope Alaska Alaska State Plane 4 Milne Point MPJ MPJ -01A Surveyed. 14 November, 1999 SURVEY REPORT 14 December, 1999 199= 11 t ORIGINAL Your Ref: API -500292026202 Surface Coordinates: 6015054.63 N, 551939.14 E (700 27'06.7370" N, 1490 34'34.3658" W) Kelly Bushing: 65.65ft above Mean Sea Level RECEIVED JAN 19 2000 Naska OU & Gas Cans. Com Amhorep spenry-sun DRILLING SERVICES Survey Ref.svy8918 A IW.I.IBURTON COMPANY North Slope Alaska Measured Depth Incl. Azim. (ft) Sperrym,Sun DServices Survey Report for MPJ -01A Your Ref: API -500292026202 Surveyed: 14 November, 1999 Alaska State Plane 4 Milne Point MPJ Sub -Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Depth Northings Eastings Northings Eastings Rate Section (ft) (ft) (ft) (ft) (ft) (ft) pi 00ft) (ft) 3595.45 21.070 6.580 3394.88 3460.53 696.74 N 48.97 W 6015751.01 N 551885.31 E 692.10 3643.00 20.730 6.520 3439.30 3504.95 713.59 N 47.04 W 6015767.87 N 551887.13 E 0.716 709.04 3674.01 23.080 4.320 3468.07 3533.72 725.10 N 45.96 W 6015779.40 N 551888.13 E 8.026 720.60 3706.07 26.920 2.470 3497.12 3562.77 738.63 N 45.17 W 6015792.92 N 551888.82 E 12.222 734.15 3742.06 28.900 0.830 3528.92 3594.57 755.46 N 44.69 W 6015809.76 N 551889.18 E 5.900 750.98 3772.86 30.480 359.530 3555.68 3621.33 770.72 N 44.65 W 6015825.02 N 551889.12 E 5.539 766.21 3804.89 33.800 358.450 3582.79 3648.44 787.75 N 44.96 W 6015842.05 N 551888.69 E 10.519 783.18 3836.62 36.120 358.650 3608.80 3674.45 805.93 N 45.42 W 6015860.22 N 551888.11 E 7.321 801.29 3870.82 38.550 358.160 3635.99 3701.64 826.66 N 46.00 W 6015880.95 N 551887.38 E 7.158 821.94 3900.32 42.190 356.500 3658.46 3724.11 845.74 N 46.90 W 6015900.02 N 551886.35 E 12.865 840.92 3932.30 43.660 355.560 3681.88 3747.53 867.47 N 48.41 W 6015921.74 N 551884.69 E 5.013 862.51 3965.69 46.360 352.920 3705.48 3771.13 890.95 N 50.79 W 6015945.21 N 551882.14 E 9.830 885.79 3998.81 48.280 351.970 3727.93 3793.58 915.09 N 53.99 W 6015969.32 N 551878.77 E 6.169 909.67 4031.35 49.840 348.390 3749.26 3814.91 939.30 N 58.19 W 6015993.50 N 551874.40 E 9.593. 933.56 4063.43 51.680 345.580 3769.55 3835.20 963.50 N 63.79 W 6016017.66 N 551868.63 E 8.883 957.34 4096.72 53.050 343.090 3789.88 3855.53 988.88 N 70.92 W 6016042.99 N 551861.33 E 7.212 982.21 4127.35 55.070 340.500 3807.86 3873.51 1012.43 N 78.67 W 6016066.48 N 551853.42 E 9.505 1005.21 4155.45 57.360 339.620 3823.49 3889.14 1034.38 N 86.64 W. 6016088.38 N 551845.30 E 8.555 1026.60 4193.97 61.050 337.880 3843.21 3908.86 1065.21 N 98.63 W 6016119.12 N 551833.08 E 10.335 1056.58 4220.17 64.670 336.090 3855.16 3920.81 1086.66 N 107.75 W 6016140.51 N 551823.82 E 15.095 1077.40 4254.96 68.810 335.030 3868.89 3934.54 1115.75 N 120.98 W 6016169.51 N 551810.39 E 12.225 1105.57 4280.59 71.980 332.890 3877.49 3943.14 1137.44 N 131.58 W 6016191.12 N 551799.64 E 14.657 1126.53 4315.51 74.180 332.740 3887.65 3953.30 1167.15 N 146.84 W 6016220.73 N 551784.17 E 6.314 1155.19 4346.85 74.640 332.340 3896.08 3961.73 1193.94 N 160.76 W 6016247.42 N 551770.06 E 1.915 1181.02 4386.59 76.360 332.410 3906.03 3971.68 1228.03 N 178.60 W 6016281.38 N 551751.98 E 4.331 1213.88 RECEIVED Comment Tie -on Surrey Window Point (whipstock) MWD Magnetid Continued... JAN 19 no0 -- - 14 December, 1999 - 14:18 - 2 - DrlllQuest Alas#ca ()i1 & Gas Cons. CrOrrtrnlesi0n AnCh North Slope Alaska Measured Depth Incl. Azim (ft) SperrymSun DServices Survey Report for MPJ -01A Your Ref: API -500292026202 Surveyed: 14 November, 1999 Sub -Sea Vertical Local Coordinates Global Coordinates Depth Depth Northings Eastings Northings Eastings (ft) (ft) , (ft) (ft) (ft) (ft) 4420.73 76.440 333.090 3914.05 3979.70 1257.53 N 4453.16 76.210 333.100 3921.72 3987.37 1285.63 N 4483.54 77.730 333.450 3928.57 3994.22 1312.06 N 4518.72 78.240 334.150 3935.89 4001.54 1342.93 N 4549.39 78.010 334.380 3942.21 4007.86 1369.97 N 4576.93 78.320 332.810 3947.85 4013.50 1394.11 N 4615.36 80.350 332.740 3954.97 4020.62 1427.69 N 4647.70 82.560 332.570 3959.77 4025.42 1456.10 N 4675.79 84.360 332.200 3962.97 4028.62 1480.83 N 4712.63 86.170 333.450 3966.01 4031.66 1513.49 N 4743.06 86.830 334.250 3967.87 4033.52 1540.75 N 4772.97 88.710 333.690 3969.03 4034.68 1567.60 N 4807.86 89.850 335.290 3969.47 4035.12 1599.09 N 4837.23 89.880 337.300 3969.54 4035.19 1625.98 N 4863.58 89.910 339.830 3969.59 4035.24 1650.50 N 4902.13 89.780 341.910 3969.69 4035.34 1686.92 N 4936.09 88.020 344.020 3970.34 4035.99 1719.38 N 4967.77 86.240 343.880 3971.93 4037.58 1749.79 N 4999.84 85.550 342.960 3974.23 4039.88 1780.45 N 5033.56 86.080 345.080 3976.69 4042.34 1812.78 N 5064.37 86.490 346.740 3978.68 4044.33 1842.60 N 5097.39 85.900 346.490 3980.88 4046.53 1874.65 N 5130.84 86.580 349.260 3983.07 4048.72 1907.28 N 5161.23 86.710 349.130 3984.85 4050.50 1937.08 N 5192.64 88.550 349.310 3986.15 4051.80 1967.91 N Alaska State Plane 4 Milne Point MPJ Dogleg Vertical Rate Section Comment (°/100ft) (ft) 193.79 W 6016310.77 N 551736.58 E 1.950 1242.33 208.05 W 6016338.77 N 551722.13 E 0.710 1269.45 221.36 W 6016365.12 N 551708.64 E 5.128 1294.97 236.55 W 6016395.88 N 551693.23 E 2.427 1324.79 249.59 W 6016422.83 N 551680.01 E 1.049 1350.93 261.57 W 6016446.89 N 551667.86 E 5.692 1374.24 278.85 W 6016480.35 N 551650.34 E 5.285 1406.63 293.54 W 6016508.65 N 551635.46 E 6.853 1434.03 306.48 W 6016533.28 N 551622.35 E 6.540 1457.86 323.24 W 6016565.83 N 551605.36 E 5.964 1489.37 336.63 W 6016593.00 N 551591.78 E 3.404 1515.71 349.74 W 6016619.76 N 551578.48 E 6.558 1541.66 364.77 W 6016651.14 N 551563.24 E 5.630 1572.10 376.57 W 6016677.94 N 551551.24 E 6.844 1598.17 386.20 W 6016702.40 N 551541.44 E 9.602 1622.02 398.84 W 6016738.73 N 551528.56 E 5.406 1657.55 408.78 W 6016771.12 N 551518.38 E 8.090 1689.29 417.53 W 6016801.47 N 551509.43 E 5.636 1719.07 426.66 W 6016832.06 N 551500.08 E 3.580 1749.07 435.91 W 6016864.32 N 551490.60 E 6.464 1780.73 443.40 W 6016894.09 N 551482.91 E 5.539 1810.00 451.03 W 6016926.09 N 551475.06 E 1.940 1841.49 458.04 W 6016958.67 N 551467.82 E 8.510 1873.60 463.72 W 6016988.43 N 551461.93 E 0.604 1902.97 469.59 W 6017019.21 N 551455.84 E 5.886 1933.35 RECEIVED JAN 19 2000 14 December, 1999 - 14:18 .3- Ard amp Continued... DrillQuest Sperry,Sun DServices Survey Report for MPJ -01A Your Ref: API -500292026202 Surveyed: 14 November, 1999 Alaska State Plane 4 North Slope Alaska Milne Point MPJ Measured Sub -Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) pi 00ft) (ft) 5225.51 90.660 350.360 3986.37 4052.02 2000.26 N 475.39 W 6017051.52 N 551449.82 E 7.170 1965.26 5256.08 92.770 353.550 3985.46 4051.11 2030.51 N 479.67 W 6017081.74 N 551445.33 E 12.507 1995.17 5291.70 92.330 356.180 3983.87 4049.52 2065.94 N 482.85 W 6017117.16 N 551441.90 E 7.479 2030.33 5323.18 91.600 357.110 3982.79 4048.44 2097.35 N 484.69 W 6017148.55 N 551439.84 E 3.754 2061.55 5355.77 89.820 358.210 3982.39 4048.04 2129.91 N 486.02 W 6017181.10 N 551438.28 E 6.420 2093.95 5389.18 89.110 357.480 3982.70 4048.35 2163.29 N 487.28 W 6017214.48 N 551436.79 E 3.048 2127.19 5421.97 88.770 359.100 3983.31 4048.96 2196.06 N 488.26 W 6017247.24 N 551435.59 E 5.047 2159.82 5452.45 88.520 0.210 3984.03 4049.68 2226.53 N 488.44 W 6017277.71 N 551435.19 E 3.732 2190.22 5483.42 87.840 0.410 3985.01 4050.66 2257.49 N 488.28 W 6017308.66 N 551435.14 E 2.289 2221.12 5516.29 87.670 1.290 3986.30 4051.95 2290.33 N 487.79 W 6017341.50 N 551435.40 E 2.725 2253.92 5548.88 87.450 3.950 3987.69 4053.34 2322.85 N 486.30 W 6017374.04 N 551436.66 E 8.182 2286.47 5582.05 87.130 5.920 3989.26 4054.91 2355.86 N 483.45 W 6017407.06 N 551439.28 E 6.010 2319.60 5614.08 86.780 6.050 3990.96 4056.61 2387.67 N 480.11 W 6017438.90 N 551442.39 E 1.165 2351.56 5643.75 86.430 8.730 3992.72 4058.37 2417.04 N 476.31 W 6017468.29 N 551446.00 E 9.094 2381.11 5673.30 86.340 9.220 3994.58 4060.23 2446.17 N 471.71 W 6017497.45 N 551450.40 E 1.683 2410.48 5711.90 86.260 11.330 3997.07 4062.72 2484.07 N 464.83 W 6017535.40 N 551457.00 E 5.459 2448.74 5743.08 86.000 12.930 3999.17 4064.82 2514.48 N 458.30 W 6017565.86 N 551463.33 E 5.187 2479.52 5776.98 86.080 13.980 4001.52 4067.17 2547.37 N 450.43 W 6017598.80 N 551470.97 E 3.099 2512.85 5807.58 86.520 16.620 4003.49 4069.14 2576.82 N 442.37 W' 6017628.31 N 551478.82 E 8.729 2542.76 5838.71 86.670 17.430 4005.34 4070.99 2606.54 N 433.27 W 6017658.08 N 551487.71 E 2.642 2573.00 5871.82 86.170 18.030 4007.41 4073.06 2638.01 N 423.21 W 6017689.63 N 551497.55 E 2.356 2605.06 5903.94 85.370 16.800 4009.78 4075.43 2668.58 N 413.62 W 6017720.26 N 551506.93 E 4.559 2636.18 5936.68 84.020 16.790' 4012.80 4078.45 2699.78 N 404.20 W 6017751.53 N 551516.13 E 4.124 2667.93 5969.87 83.790 18.380 4016.33 4081.98 2731.24 N 394.23 W 6017783.06 N 551525.88 E 4.814 2699.97 6001.92 84.850 18.730 4019.50 4085.15 2761.48 N 384.09 W 6017813.36 N 551535.82 E 3.481 2730.80 RECEIVED' Continued... JAN 14 2000 14 December, 1999 - 14:18 _ 4 _ AJmka Od & Ges Cms. Cmwj@jM DrlllQuest A,R(hQ B SperrywSun DServices Survey Report for MPJ -01A Your Ref: API -500292026202 Surveyed: 14 November, 1999 Alaska State Plane 4 North Slope Alaska Milne Point MPJ Measured Sub -Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (°/100ft) (ft) 6032.04 87.410 17.380 4021.53 4087.18 2790.05 N 374.77 W 6017842.00 N 551544.93 E 9.604 2759.91 6062.31 88.460 18.560 4022.62 4088.27 2818.82 N 365.44 W 6017870.84 N 551554.06 E 5.216 2789.23 6099.29 87.490 21.030 4023.93 4089.58 2853.59 N 352.93 W 6017905.69 N 551566.33 E 7.172 2824.74 6129.79 86.640 20.700 4025.49 4091.14 2882.05 N 342.08 W 6017934.23 N 551576.98 E 2.989 2853.84 6158.92 86.260 20.670 4027.30 4092.95 2909.25 N 331.81 W 6017961.50 N 551587.06 E 1.309 2881.65 6196.72 87.670 20.670 4029.30 4094.95 2944.57 N 318.48 W 6017996.91 N 551600.14 E 3.730 2917.75 6227.01 89.380 24.070 4030.08 4095.73 2972.57 N 306.96 W 6018024.98 N 551611.47 E 12.561 2946.44 6260.90 88.550 23.840 4030.69 4096.34 3003.53 N 293.20 W 6018056.04 N 551625.01 E 2.541 2978.23 6293.65 88.370 25.250 4031.57 4097.22 3033.31 N 279.60 W 6018085.92 N 551638.40 E 4.339 3008.83 6323.77 89.540 24.620 4032.12 4097.77 3060.62 N 266.91 W 6018113.31 N 551650.91 E 4.412 3036.90 6356.11 88.990 24.550 4032.53 4098.18 3090.02 N 253.45 W 6018142.81 N 551664.15 E 1.714 3067.12 6385.94 90.930 24.550 4032.55 4098.20 3117.15 N 241.06 W 6018170.03 N 551676.36 E 6.504 3094.99 6419.79 94.070 23.640 4031.08 4096.73 3148.02 N 227.26 W 6018200.99 N 551689.95 E 9.657 3126.69 6453.41 92.860 23.140 4029.05 4094.70 3178.82 N 213.93 W 6018231.88 N 551703.05 E 3.893 3158.29 6485.44 91.720 21.910 4027.77 4093.42 3208.38 N 201.67 W 6018261.53 N 551715.11 E 5.234 3188.58 6516.17 90.830 21.480 4027.08 4092.73 3236.93 N 190.32 W 6018290.15 N 551726.26 E 3.216 3217.80 p 6546.03 89.450 21.400 4027.01 4092.66 3264.72 N 179.40 W 6018318.02 N 551736.99 E 4.629 3246.24 ' 6581.86 88.720 22.610 4027.58 4093.23 3297.94 N 165.98 W 6018351.33 N 551750.18 E 3.944 3280.26 6611.61 89.880 22.240 4027.94 4093.59 3325.44 N 154.63 W- 6018378.91 N 551761.33 E 4.093 3308.43 6645.51 90.750 20.850 4027.76 4093.41 3356.96 N 142.18 W 6018410.52 N 551773.56 E 4.837 3340.70 6678.88 90.040 22.260 4027.53 4093.18 3388.00 N 129.93 W 6018441.64 N 551785.60 E 4.731 3372.47 6712.24 89.260 21.740 4027.73 4093.38 3418.93 N 117.43 W 6018472.66 N 551797.88 E 2.810 3404.14 6744.39 88.020 23.140 4028.49 4094.14 3448.64 N 105.16 W 6018502.45 N 551809.94 E 5.816 3434.58 6776.91 87.310 22.610 4029.82 4095.47 3478.57 N 92.53 W 6018532.47 N 551822.37 E 2.724 3465.27 6807.50 88.030 21.730 4031.06 4096.71 3506.88 N 81.00 W 6018560.86 N 551833.70 E 3.715 3494.27 RECEIVED JAN 19 2000 Continued... 14 December, 1999 - 14:18 - flauka (N & Ga cm. cullmiollim DrlllQuest Sperry,Sun. DServices Survey Report for MPJ -01A Your Ref: API -500292026202 Surveyed: 14 November, 1999 North Slope Alaska Alaska State Plane 4 Milne Point MPJ Measured Sub -Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) pi 00ft) (ft) 6841.79 88.370 21.200 4032.14 4097.79 3538.77 N 68.45 W 6018592.84 N 551846.02 E 1.836 3526.91 6874.26 87.840 22.790 4033.21 4098.86 3568.86 N 56.30 W 6018623.01 N 551857.96 E 5.159 3557.72 6904.90 87.750 20.970 4034.39 4100.04 3597.27 N 44.89 W 6018651.50 N 551869.18 E 5.943 3586.81 6938.80 87.670 19.970 4035.75 4101.40 3629.01 N 33.05 W 6018683.32 N 551880.80 E 2.957 3619.24 6971.14 88.990 21.730 4036.69 4102.34 3659.21 N 21.54 W 6018713.60 N 551892.09 E 6.801 3650.13 7002.16 88.610 19.890 4037.34 4102.99 3688.20 N 10.52 W 6018742.67 N 551902.91 E 6.056 3679.78 7033.13 88.000 20.560 4038.26 4103.91 3717.25 N 0.18 E 6018771.79 N 551913.41 E 2.925 3709.45 7060.34 87.670 19.620 4039.28 4104.93 3742.79 N 9.52 E 6018797.39 N 551922.57 E 3.659 3735.54 7099.15 87.040 20.180 4041.08 4106.73 3779.24 N 22.71 E 6018833.94 N 551935.51 E 2.171 3772.77 7133.32 88.110 20.500 4042.52 4108.17 3811.25 N 34.58 E 6018866.03 N 551947.16 E 3.268 3805.49 7165.00 88.550 19.790 4043.44 4109.09 3840.98 N 45.49 E 6018895.83 N 551957.85 E 2.636 3835.86 7196.48 87.720 19.540 4044.47 4110.12 3870.61 N 56.07 E 6018925.53 N 551968.23 E 2.753 3866.11 7230.70 88.110 20.670 4045.71 4111.36 3902.72 N 67.83 E 6018957.73 N 551979.77 E 3.491 3898.92 7263.24 90.660 19.970 4046.06 4111.71 3933.23 N 79.13 E 6018988.32 N 551990.85 E 8.126 3930.09 7292.82 90.430 19.330 4045.78 4111.43 3961.09 N 89.07 E 6019016.24 N 552000.60 E 2.299 3958.54 7326.46 89.690 20.850 4045.75 4111.40 3992.68 N 100.63 E 6019047.91 N 552011.94 E 5.025 3990.81 7358.84 89.070 20.670 4046.10 4111.75 4022.95 N 112.11 E 6019078.27 N 552023.20 E 1.994 4021.77 7389.30 88.650 19.750 4046.70 4112.35 4051.53 N 122.63 E 6019106.92 N 552033.52 E 3.320 4050.97 7422.27 87.580 20.500 4047.79 4113.44 4082.47 N 133.96 E 6019137.94 N 552044.64 E 3.962 4082.58 7455.27 87.220 19.790 4049.28 4114.93 4113.42 N 145.32 E 6019168.96 N 552055.78 E 2.410 4114.19 7485.20 88.310 19.480 4050.45 4116.10 4141.59 N 155.37 E 6019197.20 N 552065.64 E 3.786 4142.95 7521.48 89.340 18.210 4051.20 4116.85 4175.92 N 167.08 E 6019231.61 N 552077.11 E 4.506 4177.97 7554.39 89.160 17.150 4051.63 4117.28 4207.27 N 177.08 E 6019263.03 N 552086.89 E 3.267 4209.90 7585.27 88.890 17.750 4052.15 4117.80 4236.72 N 186.33 E 6019292.55 N 552095.94 E 2.130 4239.89 7618.84 90.040 17.500 4052.47 4118.12 4268.71 N 196.50 E 6019324.61 N 552105.88 E 3.506 4272.48 RECEIVED Continued... JAN 19 2000 14 December, 1999 - 14:18 - 6Alas(a Oil & Gas Cons. ODITIMMiM Andmip DrlllQuest North Slope Alaska Measured Depth Incl. Azim. (ft) SperrymSun DServices Survey Report for MPJ -01A Your Ref: API -500292026202 Surveyed: 14 November, 1999 Sub -Sea Vertical Local Coordinates Global Coordinates Depth Depth Northings Eastings Northings Eastings (ft) (ft) (ft) (ft) (ft) (ft) 7651.46 90.040 17.150 4052.44 4118.09 4299.85 N 206.21 E 6019355.82 N 7681.54 89.660 17.270 4052.52 4118.17 4328.59 N 215.11 E 6019384.61 N 7715.68 90.130 18.210 4052.58 4118.23 4361.10 N 225.51 E 6019417.20 N 7748.47 89.520 17.680 4052.68 4118.33 4392.30 N 235.62 E 6019448.46 N 7778.66 88.800 16.860 4053.13 4118.78 4421.12 N 244.58 E 6019477.35 N 7812.06 88.190 14.330 4054.00 4119.65 4453.28 N 253.55 E 6019509.57 N 7844.52 86.430 12.920 4055.53 4121.18 4484.79 N 261.19 E 6019541.13 N 7875.43 85.620 13.530 4057.67 4123.32 4514.81 N 268.25 E 6019571.20 N 7909.28 84.850 13.350 4060.48 4126.13 4547.62 N 276.09 E 6019604.06 N 7941.72 84.170 13.850 4063.59 4129.24 4579.00 N 283.68 E 6019635.50 N 7971.85 82.750 11.970 4067.02 4132.67 4608.18 N 290.37 E 6019664.72 N 8034.00 82.750 11.970 4074.86 4140.51 4668.49 N 303.15 E 6019725.12 N All data is in feet unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to Well Reference. Northings and Eastings are relative to Well Reference . The Dogleg Severity is in Degrees per 100ft. Vertical Section is from Well Reference and calculated along an Azimuth of 3.714° (True). Based upon Minimum Curvature type calculations, at a Measured Depth of 8034.00ft., The Bottom Hole Displacement is 4678.32ft., in the Direction of 3.715° (True). Alaska State Plane 4 Milne Point MPJ Dogleg Vertical Rate Section Comment (0/100ft) (ft) 552115.38 E 1.073 4304.18 552124.08 E 1.325 4333.43 552134.25 E 3.078 4366.55 552144.14 E 2.464 4398.34 552152.90 E 3.614 4427.68 552161.65 E 7.789 4460.35 552169.07 E 6.944 4492.29 552175.91 E 3.278 4522.70 552183.52 E 2.336 4555.95 552190.90 E 2.598 4587.76 552197.38 E 7.787 4617.31 552209.75 E 0.000 4678.32 Projected Survey RECEIVED JAN 19 2000 Ala*a Oil & Gas Cons. QWMi Ancholw Continued... 14 December, 1999 - 14:18 - 7 - DrillQuest Sperry,Sun DServices Survey Report for MPJ -01A Your Ref: API -500292026202 Surveyed: 14 November, 1999 North Slope Alaska W.111/I-1 7 Measured Station Coordinates Depth TVD Northings Eastings (ft) (ft) (ft) (ft) 3595.45 3460.53 696.74 N 48.97 W 3643.00 3504.95 713.59 N 47.04 W 8034.00 4140.51 4668.49 N 303.15 E Survey tool program Comment Tie -on Survey Window Point (whipstock) Projected Survey From To Measured Vertical Measured Vertical Depth Depth Depth Depth Survey Tool Description (ft) (ft) (ft) (ft) 0.00 0.00 3643.00 3504.95 Good Gyro 3643.00 3504.95 8034.00 4140.51 MWD Magnetic RECEIVED JAN 19 2000 Ala*a Oil & Ga cons. COMMOSIM kdww Alaska State Plane 4 Milne Point MPJ 14 December, 1999 - 14:18 - 8 - DrillQuest Sperry -sun DRILLING SERVICES WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Ann.: Lori Taylor 3001 Porcupine Dr. t Anchorage, Alaska 99501 t RE: MWD Formation Evaluation Logs - MPJ -01A, AK -MM -90191 MPJ-OIA: 2" x 5" MD Resistivity and Gamma Ray Logs: 50-0-29=22070=01 2" x 5" TVD Resistivity and Gamma Ray Logs: 50-029-22070-01 1 Blueline 1 Folded Sepia 1 Blueline 1 Folded Sepia January 11, 2000 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING THE ATTACHED COPIES OF THE TRANSNIITTAL LETTER TO THE ATTENTION OF: Sperry -Sun Drilling Services Attn: Ali Turker 5631 Silverado Way, Suite G Anchorage, Alaska 99518 RECEDVED Date: AMM 00&Gas Cwm*Xjgn w BP Exploration (Alaska) Inc. __Petro-ledmi.cal Data.C=u,1M3-3 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 Signed: 5631 Silverado Way, Suite G - Anchorage. AK 99518 • 907-273-3500 - Fax: 907-273-3535 A Halliburton Company sperry-sun DRILLING SERVICES WELL LOG TRANSMITTAL To: State of Alaska December 237 1999 Alaska OR and Gas Conservation Comm. Attn.: Lori Taylor 3001 Porcupine Dr. Anchorage, Alaska 99501 e';" , , RE: MWD Formation Evaluation Logs MPJ -01A, AK -MM -90191 1 LDWG formatted Disc with verification listing. API#: 50-029-22070-01 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING THE ATTACHED COPIES OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry -Sun Drilling Services Attn: Jim Galvin 5631 Silverado Way, Suite G. Anchorage, Alaska 99518 row !DIN Date: 4 200 Mmv* Signed: J BP Exploration (Alaska) Inc. Petro -technical Data Center, MB3-3 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 5631 Silverado Way. Suite G - Anchorage, AK 99518 - 907-273-3500 - Fax: 907-273-3535 A Halliburton Company MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Robert Christenson DATE: November 30, 1999 Chairman THRU: Blair Wondzell, ,04L, FILE NO: BOP Nordic 3jc.DOC P. 1. Supervisor 1216(i 9 FROM: John Crisp, SUBJECT: BOPE Test Petroleum I Spector Nordic 3 BPX MPU J -01A PTD 199-111 November 30,1999: 1 traveled to Milne Point to witness weekly BOP test on Nordic 3 drilling BPX MPJ -01A. The BOP test went fairly well. The Driller was new to crew & crew had just arrived for first tour on 2 week hitch. One failure was observed. The API ring gasket started leaking on BTM. Set of pipe rams during lower pipe ram test. The drill crew modified hammer wrench to tighten flange on lower pipe rams. The ring gasket passed retest. SUMMARY: I witnessed weekly BOP test on Nordic 3 BPX MPJ -01A. Test time was 7 hours. One failure witnessed. Failure passed retest. Attachments: BOP Nordic 3 11-30-99jc CC" NON -CONFIDENTIAL STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: x Workover: _ Drlg Contractor: Nordic Operator: BPX Well Name: MPJ -01A DATE: 11/30/99 Rig No. 3 PTD # 199-111 Rig Ph* 659-4165 Rep.: Don Wester/ Tom Anglen Rig Rep.: Lance Johnson Casing Size: 4 1/2 S.L. Set @ 7,635 Location: Sec. 28 T. 13N R. 10E Meridian Test: Initial Weekly x Other UM REMARKS: Ring gasket for lower pipe rams leaked during lower pipe ram test Tightened flange & retested rams & ring gasket. Retest successful. Rig & location was neat & clean & in good shape. Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: c - Inspept%1L (Rev. 12/94) 1 "ff^t'ic 3 11-30-99jc John Crisp TEST DATA Test MISC. INSPECTIONS: FLOOR SAFETY VALVES: Quan. Pressure P/F Location Gen.: OK Well Sign YES Upper Kelly/ IBOP 1 250/3,500 P Housekeeping: OK (Gen) Drl. Rig OK Lower Kelly/ IBOP 1 250/3,500 P PTD On Location YES Hazard Sec. YES Ball Type 1 250/3,500 P Standing Order Posted YES Inside BOP 1 250/3,500 P BOP STACK: Quan. Test Press. P/F Test Annular Preventer 1 250/3,000 P CHOKE MANIFOLD: Pressure P/F Pipe Rams 1 250/3,500 P No. Valves 12 250/3,500 P Lower Pipe Rams 1 250/3,500 P No. Flanges 36 250/3,500 P Blind Rams 1 250/3,500 P Manual Chokes 1 Functioned P Choke Ln. Valves 1 250/3,500 P Hydraulic Chokes 1 1 Functioned P HCR Valves 1 250/3,500 P Kill Line Valves 2 250/3,500 P ACCUMULATOR SYSTEM: Check Valve N/A System Pressure 3,000 Pressure After Closure 2,150 MUD SYSTEM: Visual Alarm 200 psi Attained After Closure minutes 18 sec. Trip Tank P P System Pressure Attained 1 minutes 7 sec. Pit Level Indicators P P Blind Switch Covers: Master: YES Remote: YES Flow Indicator P P Nitgn. Btl's: 4 Bt/s. @ 2150 Ave. Meth Gas Detector P P Psig. H2S Gas Detector P P TEST RESULTS Number of Failures: 1 ,Test Time: 7.0 Hours. Number of valves tested 19 Repair or Replacement of Failed Equipment will be made within 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 REMARKS: Ring gasket for lower pipe rams leaked during lower pipe ram test Tightened flange & retested rams & ring gasket. Retest successful. Rig & location was neat & clean & in good shape. Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: c - Inspept%1L (Rev. 12/94) 1 "ff^t'ic 3 11-30-99jc John Crisp ALASKA OII, AND GAS CONSERVATION COMMISSION Charles Mallan- Senior Drilling Engineer BP Exploration (Alaska). Inc. P O Box 19661.2 Anchorage, AK 99519-6612 Re: Milne Point Unit MPJ -01 A BP Exploration (Alaska). Inc. Permit No: 199-111 Sur. Loc. 2622'SNL. 3378'WEL, SEC, 28. TON. R10E, UM Btmhole Loc. 2069'NSL. 3061'WEL. SEC. 21.T1 --,ti- R10E. UM Dear Mr. Mallan-: TONY KNOWLES, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 Enclosed is the approved application for permit to redrill the above referenced well. The permit to redrill does not exempt you from obtaining additional permits required by lacy from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. The blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035: and the mechanical integrity (MI) of the injection «-ells must be demonstrated under 20 AAC 25.412 and 20 AAC 25.030(g)(3). Sufficient notice (approximately 24 hours) of the MI test before operation. and of the BOPE test prior to drilling new hole must be given so that a representative of the Commission may witness the tests. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Smel-,,-. Robert N. Christenson. P. E. Chairman BY ORDER OF THEE COMMISSION DATED this � day of November. 1999. dlf Enclosure cc: Department of Fish & Game. Habitat Section %v o encl. Department of Environmental Conservation w: o encl. STATE OF ALASKA ALASK JIL AND GAS CONSERVATION COh, SSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of work ❑ Drill ® Redrill 1 1 b. Type of well ❑ Exploratory ❑ Stratigraphic Test ® Development Oil ❑ Re -Entry ❑ Deepen ❑ Service ❑ Development Gas ❑ Single Zone ❑ Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc. Plan KBE =65.5' Milne Point Unit / Schrader Bluff 3. Address 6. Property Designation and P.O. Box 196612, Anchorage, Alaska 99519-6612 ADL 315848 OZ5906o 4. Location of well at surface 7. Unit or Property Name 11. Type Bond (See 20 AAC 25.025) 2622' SNL, 3378' WEL, Sec. 28, T13N, R10E, UM Milne Point Unit 8. Well Number At top of productive interval Number 2S100302630-277 1035' SNL, 3749' WEL, Sec. 28, T13N, R10E, UM MPJ -01A 9. Approximate spud date At total depth Amount $200,000.00 2069' NSL, 3061' WEL, Sec. 21, T13N, R10E, UM 11/20/99 12. Distance to nearest property line 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) ADL D No Close Approach 1280 8039' MD / 4116' TVD 6. To be completed for deviated wells 13Q)' C (od_-sw 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)) Kick Off Depth 3655' MD Maximum Hole Angle 890 Maximum surface 1200 psig, At total depth (ND) 4000'/ 1650 psig 18. Casing Program Setting Depth Specifications Size Top Bottom Quantity of Cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 6-1/8" 4-1/2" 12.6# L-80 IBT-M 4529' 3510' 3381' 8038' 4116' 92 sx Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured 4535 feet Plugs (measured) true vertical 4342 feet ORIGINAL Effective depth: measured 4325 feet Junk (measured) true vertical 4144 feet Casing Length Size Cemented MD TVD Structural Conductor 70' 13 3/8" 500 sx PF 'C' 105' 105' Surface 2374' 9 5/8" 945 sx PF 'E' , 200 sx E 2409' 2364' Intermediate Production 4500' 7" 393 sx Class 'G' 4535' 4342' Liner Perforation depth: measured Open: 4044'- 4280' (four intervals) Squeezed: 4010'-4282' (five intervals) true vertical Open: 3880'-4101' -' Squeezed: 3849'- 4103' 20. Attachments ® Filing Fee ❑ Property Plat ❑ BOP Sketch ❑ Diverter Sketch ® Drilling Program ® Drilling Fluid Program ❑ Time vs Depth Plot ❑ Refraction Analysis ❑ Seabed Report ❑ 20 AAC 25.050 Requirements Contact Engineer Name/Number. Mik Triolo, 564-5774 Fred Johnson, 564-5427 Prepared By Name/Number: Michael Williams, 564-4657 21. 1 hereby certify khat t foregoin i rue and correct to the best of my knowledge � Si ned _ rMal g Charles lary Title Senior Drilling Engineer Date Commission Use Only Permit Number �y / API Num Approval Date See cover letter ��/' �! 50-029-22070-01 ` l — for other requirements Conditions of Approval: Samples Required ❑ Yes boo Mud Log Required El Yes No Hydrogen Sulfide Measures ❑ Yes �Oo Directional Survey Required fg:yes ❑ No Required Working Pressure for BOPE 17712K; ❑ 3K; 04K; ❑ 5K; ❑ 10K; ❑ 15K Other: 350 ps C�o�s�- ORIGINAL SIGNED -BY by order of (HS -T Approved By PnhortrhriqtpnqnnCommissioner the commission Date Form 10-401 Rev. 12-01-85 Submit In Triplicate Well Name: I MPJ -01 A Well Plan Summary Type of Well (producer or injector): I Producer Surface Location: 2622' SNL, 3378' WEL, Sec. 28, T13N, R10E X = 551,939.14 Y = 6,015,054.63 Target Start: 1035' SNL, 3749' WEL, Sec. 28, T13N, R10E X = 551,552.00 Y = 6,016,638.00 Z = 3,965' TVDss Intermediate Target End: 2069' NSL, 3061' WEL, Sec. 21, T13N, R10E X = 552,211.00 Y = 6,019,748.00 Z = 4,050' TVDss AFE Number: 1337169 1 Rig: Nordic 3 Estimated Start Date: Nov 20, 1 Operating days to complete: 115.5 MD 8,039' TVDrkb: 4,116' KBE: 65.50' Well Design (conventional, slim hole, Extended Horizontal Sidetrack etc. Objective: Sidetrack out of existing 26#, 7" csg into the Ugnu Formation, directionally drill 6 1/8" hole thru the Ugnu ,formation, land horizontally in the Schrader Bluff 'OA' sands. Geosteer horizontally through the OA target sands to TD at 8,039' MD. Run, cmt and test a 4 1/2" Banzai (slotted/solid) liner, complete with an ESP pump, 2 7/8", L-80, EUE tubing. Well Name: API Number: Well Type: Current Status: Last H2S Sample: Cement: TD / PBTD: BHP: BHT: Is this well frac'd? Mechanical Condition: MPJ -01 Wellhead: Nordic 3: Tubing: Liner: Casing: Casing Head: Casing Hanger: 7" Packoff: Tubing Spool: Tbg. Hanger: Tree: Open Perlis: Tubing Fluids: Annulus Fluids: Target Estimates: Estimated Reserves: Expected Initial Rate: Expected 6 month avg: Materials Needed: L-80 Intermediate: Current Well Information MPJ -01 50-029-22070 Shrader Bluff Producer All open perf's P & A'd 0 ppm TOC planned to be at top of 7" window at 3660'. Liner top at 3,510'. 8,039'/ 7,997' 1,634 psi Schader Bluff 'OA' sand. Estimated from shut-in pressure & offset wells 80°F@ 4,020' ss Estimated No Cellar Box MSL = 35.5' KB/MSL =65.5' 2 7/8", 6.5#, L-80, EUE 8rd above an ESP pump None Conductor: 105', 13 3/8", 54.5#, K-55, BTC Welded Surface: 2,409', 9-5/8", 36#, K-55, BTC Production: 4,535', 7", 26#, L-80, BTC WKM 103/4" BTC x 11", 5M 7" WKM Mandrel WKM Mandrel type WKM 11" x 11", 5M WKM 11" x 2 7/8" EUE top and btm. ESP and heat trace penetrator prep. 2 1/2", 'H' type BPV profile WKM 5M, 2 9/16", 2 9/16" w/ 2 7/8" EUE lift threads treetop connection P&A'd on pre -rig SW with diesel cap down to 2000' Note: No kill string planned. SW with diesel cap down to 2000' Expected reserves 1.4 mmbbl Production rate: 1,000 b/d Production rate: 1,000 b/d L-80 Production: 3,244' 4.5", 12.6#, L-80, IBT-Mod Slotted Liner 1,325' 4.5", 12.6#, L-80, IBT-Mod Solid Liner 7" x 4-1/2" Baker liner top hanger / packer 4-1/2" Halliburton Guide Shoe 40 - 4-5/8" x 5 7/8" x 8" Rigid Straight Blade Centralizers L-80 Completion: 3,400' 2 7/8", 6.5#, L-80, 8rd EUE tubing ESP Centrilift 2 - 2 7/8" Sidepocket GLM's 3,460' Centrilift #2 cable 2,265' Raychem heat trace 3600' Baker TEC Wire BHP Gauge Baker Sentry Gauge Drilling Hazards and Contingencies 1) Well Control MANDATORY WELL CONTROL DRILLS: Drill Type Frequency Comments D1 Tripping 1per week, per crew Conducted only inside casing. D2 Drilling 1per week, per crew Either in cased oro en hole. DO NOT shut-in well in open hole. D3 Diverter Prior to spud, per crew Once per week per crew while drilling with diverter in place. D4 Accumulator Prior to spud or RWO Approx. every 30 days, thereafter at convenient times. D5 Well Kill Prior to drill out, per crew Prior to drill out the intermediate and production strings. Never carry out this drill when o enhole sections are exposed. • IN ALL CASES, ENSURE THAT THE DRILLS ARE CAREFULLY CARRIED OUT AND DO NOT EXPOSE EQUIPMENT, CASING OR FORMATION TO EXCESSIVE PRESSURES AND LOADS. • See BP Well Control Manual for all details of these drills. 2) Hydrogen Sulfide • MP J Pad is not designated as an H2S Pad. 3) Kick tolerance • The kick tolerance for the 6 1/8" open hole section would be 28.3 bbls assuming an influx at the 8045' TD in the Schrader OA formation. This is a worst case scenario based on a 8.5 ppg pore pressure gradient in the top of the production section and a minimum fracture gradient of 13.5 ppg below the 9 5/8" surface casing shoe with a 9.4 ppg mud in the hole. • LOT at the 9 5/8" shoe after the original drill out: 14.8 ppg EMW 4) Breathing • No breathing problems are expected drilling the Ugnu or the Schrader Bluff formations. 5) Lost Circulation • There is a `low' probability for lost circulation drilling to the start target. A fault should be encountered just prior to drilling to the T1 target. Expect to drill the fault at 4,259' MD. • Follow the LOST CIRCULATION DECISION MATRIX if fluid losses occur while drilling. Break circulation slowly in all instances and get up to recommended circulating rate slowly prior to cementing. 6) Faults • One fault is expected just prior to drilling into the start target at 4,259' MD, 3865' TVDss. 7) Hydrocarbons • Will be kicking off in the Ugnu interval, therefore the first possible hydrocarbon zone will be the Schrader Bluff `NA' sand at @ 4,061' MD, 3,773' TVDss. 8) Geosteering • (2) rig site geologists are required onsite for accurate geosteering through the thin OA sands 9) Pad Data Sheet 0 Please Read the J -Pad Data Sheet thoroughly. Drillinq Program Overview Surface and Anti -Collision Issues Surface Shut-in Wells: No wells need to be shut-in for the rig move on and off MPJ -01 A. Close Approach Wells: MP J-01 Well Name Current Status Production Priority Precautions MP J-11 1'� `�, Water Injection Well Control: Expected Formation Pressures & BOPE Test Pressures �\� �o`- �� • Expected BHP Max Exp Surface Pressure BOPE Rating Planned BOPE Test Pres. 1,650 psi, 4,000' TVDss estimated 1,200 psi .115psi/ft gasgradient) 5,000 psi WP entire stack & valves 3,500/250 psi Rams and Valves 2,500/250 psi Annular Mud Program Production Mud Properties: 9% KCL BaraDriln 16 1/8" hole section Density Funnel vis YP HTHP pH API Filtrate LG Solids 9.6 1 40-55 1 20-27 10-15 8.0-8.5 4-6 <15pob NOTE: See attached Baroid mud recommendation LCM Restrictions: No Organic LCM products in the Schrader Bluff formation Waste Disposal: NO ANNULAR INJECTION. Drill Cuttings taken to DS -4 disposal site. Call the Pad 4 waste disposal site prior to truck leaving location so the site can be ready to unload waste. Exempt liquid wastes can be taken to DS -4 or ARCO KRU 1R. Formation Markers Formation Tops MD TVDss Pore Psi EMW Comments TUZC 3492 3296 1483 8.65 Top U nu KOP 3655 3451 Planned Kick Off Point BUZB 3737 3525 1586 8.65 NA 4060 3773 1559 7.95 NB 4117 3805 1572 7.95 NC 4177 3834 1584 7.95 NE 4242 3860 1594 7.94 NF 4513 3920 1618 7.94 TOA 4794 3960 1634 7.94 Top OA sand. Set ECP in the sand TD 8038 4050 Casing/Tubing Program Hole Size Csg/ Tbg O.D. Wt/Ft Grade Conn Length Top MD/TVD Btm MD/TVD PDC 15-15-15: 250+ gpm 61/8" 41/2" Banzai 12.6# L-80 IBT-Mod 4,529' 3,51073,381' 8,03874116' Tubing 2 7/8" w/ ESP 6.5# L-80 EUE 8rd 3,400' 30730' 343073,390' Cement Calculations Liner Size 14Y2" Banzai IBT-Mod Basis 0% excess in open hole (6 1/8" hole), No cement in liner lap 7" casing) or above liner to 3 1/z" d ECP 4,794' MD 4,031 TVDrkb , Window at 3,660' (3,520'), Liner top at 3,510' 3,381' Total Cement Spacer None if well displaced to completion fluid. Contingency 15 bbls of B45 Volume: Viscosified Spacer Weighted to 10.2 ppg if cementing in mud Tail 92 sxs, Class 'G'+ .30%D65 + .5%S001 +.4% D167 +.2% D046 Temp I BHST --80° F from SOR. BHCT 85° F estimated by Dowell Centralizer Placement: 1. Run (2) rigid straight centralizer per joint first 500' above the ECP 2. Run (1) rigid straight centralizer per joint to the window. 2. Run each single centralizer in the middle of each joint of casing. Other Cement Considerations: 1. Batch mix this single slurry. Survey and Logging Program 6 1/8" Section: Open Hole: MWD / GR / PWD - Over production interval. Sample Catchers - None! Cased Hole: None Perforating: None Bit Recommendations BHA Hole Size Number and Section Depths (MD) Bit Type Nozzle / Flow Rate K -Rev's Hours 1 6 1/8" 3,660' - 8,038 PDC 15-15-15: 250+ gpm Motors and Required Doglegs BHA Number Motor Size and Motor Required Flow Rate RPM's Required Doglegs 1 (PDC) 43/4" Sperrydrill 4/5, 6.3 stg Slow Seed, 1.150 ad' w/5.9" sleeve 250 - 300 gpm 75 mtr, 60 rotate Build out of window at 9°/100 to horizontal. Drill to TD. MPJ -01A Operations Summary Pre -Rig Operations 1. MIRU Nabors 4ES 2. Circ well. ND Tree, NU Stack and Test_. 3. POOH w/ 2-7/8 ESP completion" tbg. Note: Plan to rerun 2-7/8" tbg, Raychem HT, Tree 4. RU E -line. Set EZSV on EL .@ +/-3670'. Note: EZSV to be used as base for setting whipstock. EZSV must be set so that window is not milled thru 7" casing coupling 5. RIH with stinger. Cmt sqz existing perfs. Circ hole clean on top of EZSV. 6. POOH. Freeze protect well at 2200' tvd. 7. Land hanger. Install BPV. 8. ND BOPS, NU Tree & Test Move off. Snapshot of Well Program 1. MIRU Nordic 3. NU and test BOP 2. Run and set whipstock on EZSV. Mill window. 3. MU 6 1/8" BHA. RIH. 4. Drill 6-1/8" hole. Build angle and steer to land horizontal in OA sand. 5. Displace hole to new BARADRILn mud. Drill horizontal section. 6. Run 4-1/2" Bonzai liner and inner string. 7. Displace hole to 9.0 KCL completion fluid thru inner string 8. Spot Starch Enzyme in 4-1/2" x 6-1/8" open hole annulus 9. PU and displace liner to completion fluid and spot enzyme in liner if required. 10. Inflate ECP and cement top liner interval above slotted liner. Circ. POOH. 11. Run 2-7/8" ESP completion with Raychem heat trace and Baker Sentry gauge with TEC wire, 12. ND BOPE, NU tree. Release rig. Rig Operations 1. Complete a pre -rig inspection with the Drill Site Operator prior to the rig moving on the well. 2. MIRU Nordic 3. Note: Tubing Hanger: WKM 11" x 2 7/8", EUE 8rd top & bottom, WKM 2 1/2" `H' type BPV profile. 3. Install a BPV and test from below to 1000 psi. N/D the production tree. NORM all well head and retrieved completion. Send the tree to the APC Valve shop for repair and send the adapter flange to Tool Service for FMC inspection. 4. N/U 11" BOP stack. Test BOP rams and valves to 250/3500 psi against the test dart. Test annular preventer to 250 /2500 psi. Pull BPV. Pull tubing hanger. Reference RP: Whipstock Sidetracks 5. Make up Baker Whipstock/Mill assy. Mill the 7" window as per RP with Baroid recommended mud. 6. Make up 6 1/8" directional assembly (see attached BHA and Bit recommendations). Kick-off drilling the 6 1/8" production section according to the directional plan to TD @ ± 8,039' and (4,116' TVDrkb). NOTE: Critical to Geosteer staving in the OA sands. Reference in the Wellplan: Drilling Hazards Section • Moderate potential for Lost Circulation drilling to T1 target. Use Lost Circulation Decision Matrix Good Drilling Practices: • Hole Cleaning: follow 'Stuck Pipe Prevention' attachment and Baroid recommendations • Sweeps: Sweep hole after PWD evaluations as per Baroid recommendations • ECD: follow attached 'PWD Drilling Practices' • Wiper Trips: as needed by hole conditions • Stuck Pipe: Go immediately to SURE manual, determine stuck pipe mechanism, follow recommendations in the SURE manual. DO NOT JAR UP if packed -off! Reference RP: Combination Solid - Slotted Production Liners Reference RP: Baker Inner String Banzai Liner Cementing 7. Run and cement a 4'/2", 12.6#, L-80, IBT-Mod Banzai liner with a minimum of 150' liner lap in the 7" window. Follow the Baker Inner String Banzai Liner Cementing Recommended Procedure. • Contingency if the liner does not get to bottom: If the liner stops prior to reaching the minimum setting depth, POOH with liner and make a clean-out trip. If the liner will not POOH, notify the ODE to discuss options. • Contingency if the plug does not bump: See the RP. • Contingency if the packer does not set: See the RP. • Contingency if the casing does not test: See the RP. • Run 2 rigid straight blade centralizers per joint bottom 500', then (1) centralizer per joint to window. • Displace cement and set hanger/packer with cementing unit pumps. Switch to rig pumps before rotating out of liner top and circulating the inhibited completion fluid. • Circulate and leave corrosion inhibited seawater or source water as the completion fluid. 41/2 ", 12.6#, IBT-Mod ID drift 100% 3.833" Collapse 7,500 psi Burst 8,440 psi Tensile 208,730 lbs 80% 6,000 psi 6,752 psi 166.984 lbs 8. Note: no casing test is planned with the slotted liner completion. Reference RP: Running an ESP Completion 9. Run 2 7/8", 6.5#, L-80, EUE 8rd completion, land the bottom of the ESP 50' above the 4-1/2" liner top extention. Completion Tailpipe Assembly: See Completion Drawing. Can use Grade 'B', inspected 2 7/8" tubing. NOTE: ESP completions witt,jut packer do not test tubing or annulus. 10. Nipple down the BOPE. Nipple up and test the tree to 5000 psi. 11. Move the rig off the well, pick up the matting boards and herculite. Clean the well area and release the rig. 12. Complete a post -rig inspection with the Drill Site Operator. Tree: WKM 2 9/16" 5M Open sand o 421 MP J-01 4.5" 12 4069-4089 KB elev. = 70.2' Wellhead: 11 " x 11 " 5M tbg. Cement Retainer 3,660' Oen Note: 2/21/97 Suspected voids behind the bottom Open screen so it was isolated w/ 100 mesh sand plum DATE DF elev. = 68.7' Cement MILNE POINT UNIT spool, 11" x 2 7/8" 8 rd EUE (top PERFORATION SUMMARY GL elev. = 35.2' & bottom) WKM tbg. hng. w/ 2.5" REF LOG: DIL - SFL 12/13/90 WELL J-01 (3.880" ID) 'H' BPV profile. 02/21/97 JBF ESP Replacement by Nabors 4ES 92'- 20 ga screen Size SIPF PROPOSED P&A 13 3/8", 54.5 ppf, 105 STATUS K-55 Butt Weld "N" Sands KO P @ 1500' Max Hole Angle: 26° @ 2500' MD 4.5" 24 4010'-4036' Hole angle through perfs = 20 deg. HES Versatrieve packer @ 4138' MD 4.5" 9 5/8", 36 ppf, K-55, Btrc. 12409- MD 7" 26 ppf, L-80, Btrc. production casing ( drift ID = 6.151 ", cap. = 0.0383 bpf ) 4.5" 12 4044-4065 Open sand o 421 7" float collar (PBTD) 4454' and 4.5" 12 4069-4089 Open 7" casing shoe 4535' and Cement Retainer 3,660' Oen Note: 2/21/97 Suspected voids behind the bottom Open screen so it was isolated w/ 100 mesh sand plum DATE REV. BY Cement MILNE POINT UNIT PERFORATION SUMMARY 04/04/95 HES Versatrieve packer @ 3923' MD REF LOG: DIL - SFL 12/13/90 WELL J-01 (3.880" ID) 02/21/97 JBF ESP Replacement by Nabors 4ES 92'- 20 ga screen Size SIPF Interval Open/Sqzd Proposed decompletion 4ES HES X nipple 2.75" ID @ 4148' MD "N" Sands 4.5" 24 4010'-4036' Sqzd HES Versatrieve packer @ 4138' MD 4.5" 24 4042'-4082' Sqzd 42'-20 Ga screen 4.5" 24 4098'-4128' Sqzd HES Versatrieve packer @ 4223' MD "O" Sands (3.88" ID) 4.5" 12 4192'-4222' Sqzd 34'- 20 ga screen 4.5" 12 4258'-4282' Sqzd HES BWD Sump packer @ 4290' MD (4.00" ID) 100 mesh 4.5" 12 4044-4065 Open sand o 421 7" float collar (PBTD) 4454' and 4.5" 12 4069-4089 Open 7" casing shoe 4535' and " 4.5" 12 4260-4280 Oen Note: 2/21/97 Suspected voids behind the bottom Open screen so it was isolated w/ 100 mesh sand plum DATE REV. BY COMMENTS MILNE POINT UNIT 04/04/95 DBR RWO/ MULTIPLE FRAC PACKS WELL J-01 02/21/97 JBF ESP Replacement by Nabors 4ES API NO: 50-029-22070 9/27/99 MTT Proposed decompletion 4ES BP EXPLORATION (AK) TREE: WKM 2 9/16", 5M WELLHEAD: WKM 11 " x 11 ", 5M tbg. spool 11" x 2 7/8", 8rd EUE (top & btm) ESP, HT WKM tbg. hanger, 'H' BPV profile 105• 13-3/8", 54.5 #/ft, L-80, Welded 2 7/8", 6.5#, L-80, 8rd EUE * ( Run Used Tbg. From Decompletion) Drift. I.D.: 2.347" Capacity: .00592 bbl/ft Centralift #2 cable 7", 26#, L-80, BTC Drift. I.D.: 6.151 " Capacity: .0383 bbl/ft Window in 7" casing @ 3,660' A11 Perforations P & A'd PBTD 4.45T-7 TD 4,535' DATE REV. BY COMMENTS 20 CR 20 ME 20 M - = KB. ELEV = 65.50' Cellar Box ELEV = 35.50' 2 7/8" x 1 " sidepocket GLM I 124' Raychem Heat Trace Baker TEC Wire 2 7/8" x 1" sidepocket GLM 1 3,390' Centrilift FC 925 ESP 1 3,420' Baker Sentry Gauge + TEC 3,460' 7" x 4 1/2" liner/hgr pkr. 3,510' Baker ECP (top of 'OA' sand) 4y800' 4 1/2" liner TD L 8,000' ------------------------ ------------------------ 4-1/2", 12.6# L-80, Banzai Liner 1 9/29/96 1 RMK 1 Horizontal Sidetrack 1 Milne Point Unit WELL:.1-01A API NQ: 50-029- 22070-01 SEC,32-;-TN -i 2N - $ti.F-A- E F , sperry-sun C7r�14.L INS_ 15RRVICq15 DrillQuest- A anLLIRUR M con+r.wv Alaska State Plane Zone 4 Milne Point MPJ MPJ -01A Current Well Properties Wall: MPJ -01A Horizontal Coordinates: Rel. Global Coordinates: 6015054.63 N. 551939.14 E Rol. Structure Reference ; 1635.64 N, 515.45 E Ref. Geographical Coordlnatas : 70' 27'06.7370- N, 149.34' 34.3659- W RKB Elevation : 65.50f1 above Mean Sea Level Horizontal Origin :Well 65,501t above Structure Reference North Reloronce : True North Units : Feet MD 3535°'9 � ft� 5.p00�j1�� ft6369 3 ftMb, s��Dir @@9.p00 t1e-on,te %net() 3500 D`t s 55.55ft Ap13Z8ft�M 403t).50ft�0 LSC') a00. �� 435. 61ftMD,39 4654.61ftiMp ft 419426ft .-Vq ft Apg05��D �: y52 gOft MD NA - 3838.50 TVD f0 it ::::.---: �d.D�r :............... .6pg°I't.... < 8,......... 4055 45a ASS.....:.....::.................................:... -- NB -3 70.50 VD 5 ................ 7,.. ... .. r•L crease .............. .... ....:. 1.l,Ci...................................... 5 • US��IUDitRate6b .................... D":545�51ft .....:. D,x62:?1A.'.........................................................::NN�-� �%'3�� (T Er1d............ .............................. ee5 C QOOO �e NF-398b.50TVD r......... ............................ 00.................. .000.00 ................. .................................................................................OA - 4030.50 TVD 00 cN � MPJ -01A Wp9-2 U b Total Dept : 8037.78ft MD, 4115.50ft TVD U) 4 2" In 37.78ft MD, 4115.50ft TVD 1000 1500 2000 2500 3000 3500 4000 4500 Scale: 1 inch = 500ft Vertical Section Section Azimuth: 3.714° (True North) Proposal Data for MPJ -01A Wp9-2 Vertical Origin: Well Horizontal Origin :Well Measurement Units: fl North Reference : True North Dogleg severity: Degrees per 1001t Vertical Section Azimuth : 3.714' Vertical Section Description: Vertical Section Origin: Well ;r:':'.0.00 N,0.00 E Measured Incl. ,;;; Azlm. Vortical Northings Eastings Vertical Dogleg Depth Depth Section Rate 3645.30 20 .63116,503 3516.44 717.96 N 46.54 W 713.43 $890.30 22,4$7 3.642 3549.00 730.76 N 45.42 W 726.28 6.000 4351.87 ::;. 78.917 9.35.026 3955.55 1193.70N 187.12W 1179.07 9.000 4654 U ';, 4794.26 78 917 ;8,7306 33088:: 330.0$5 :; 4013.78 4030.50 1463.33 N 1586.03 N 312.35 W 376.09 W 1440.02 1558.34 0.000 7.000 , :5452.51 68,375 15.890 'i 4055.50 2221.60 N 454,67 W 2187.48 6.952 64$8,46 8039,78 „ 88,577 88,885:' 13.827 19.843' 4080.50 4115.50 3189.11 N 4691.36 N 180.37 W 304.57 E 3170.73 4701.24 0.000 0.262 MD 3535°'9 � ft� 5.p00�j1�� ft6369 3 ftMb, s��Dir @@9.p00 t1e-on,te %net() 3500 D`t s 55.55ft Ap13Z8ft�M 403t).50ft�0 LSC') a00. �� 435. 61ftMD,39 4654.61ftiMp ft 419426ft .-Vq ft Apg05��D �: y52 gOft MD NA - 3838.50 TVD f0 it ::::.---: �d.D�r :............... .6pg°I't.... < 8,......... 4055 45a ASS.....:.....::.................................:... -- NB -3 70.50 VD 5 ................ 7,.. ... .. r•L crease .............. .... ....:. 1.l,Ci...................................... 5 • US��IUDitRate6b .................... D":545�51ft .....:. D,x62:?1A.'.........................................................::NN�-� �%'3�� (T Er1d............ .............................. ee5 C QOOO �e NF-398b.50TVD r......... ............................ 00.................. .000.00 ................. .................................................................................OA - 4030.50 TVD 00 cN � MPJ -01A Wp9-2 U b Total Dept : 8037.78ft MD, 4115.50ft TVD U) 4 2" In 37.78ft MD, 4115.50ft TVD 1000 1500 2000 2500 3000 3500 4000 4500 Scale: 1 inch = 500ft Vertical Section Section Azimuth: 3.714° (True North) sperm -sun DLD�'irlQest¢ RILING SERVICES A RV]36VRSp`i CYN.pA:Y Current Well Propertles Wed: MPJ -01A Alaska State Plane Zone 4 "°.'�°°'° Ref. Global (bOrdnatM : 6015054.63 N, 551939.14 E 5 E Milne Point MPJ Rel. SbuctixeGeowaO cal C*" : 1635.64 K 0B. -MI N, Rel. Geo�4pltical CoorWiafes : 70' 2T 08.737fY N, 149' 34' 34.3669' W eva MPJ 01A Scale: 1inch = 500ft Eastings 'S OB �00f- 0. "abw SVUd." `of - fiS ton above se�,c4,s Roraenm -1000 -500 0 500 Ncd R : Tr ; N"°' MPJ-0lA T4 (June2) - Point 4115.50 TVD 4691.36 N, 304,57E Total Depth: 8037.78ftMC 4115.50ft TVD 7,v 4500 4500 4 4000 3500 3000 Cn m c 0 z 2500 1500 4= O O Irl 1000 U MPJ -DIA 73 (July 11) - 4080.50 TVD 3189.11 N,180.37 W / MPJ (OA) Polygon --ETd Dir: 5452.51ft MD, 4055.50ft TVD MPJ-OIA 72 (June2) - Point 4055.50 TVD 2221.60 N, 454.67 W 4000 3500 3000 2500 2000 MPJ -VIA TI (June2) -Point it Rate Decrease @ 6.952°/100ft : 4794.26ft MD, 4030.50ft TV 4030.50 TVD 1500 1586.03 N, 376:09 W tart Dir @ 7.000°/100ft : 4654.81ft MD, 4013.78ft TVD 4000. nd Dir: 4351.87ft MD, 3955.55ft TVD 0 3900. -1000 -500 Scale: 1 inch = 500ft U) 0) C :.c 0 z 1000 - Dir Rate Increase @ 9.000°/100ft: 3690.308 D, 3549,00ft TVD Tie -on, Start Dir @ 6.000*11 00ft: 3655.30ft M P, 3516.44ft TVD 0 500 S Reference is True North 4 Sperry -Sun Drilling Services Proposal Report for MPJ -0 IA Wp9-2 Revised. 11 October, 1999 Measured Sub -Sea Depth Incl. Azim. Depth (ft) (ft) 3655.30 20.638 6.503 3450.94 3690.30 22.457 3.642 3483.50 3700.00 23.194 2.436 3492.44 3800.00 31.182 353.259 3581.36 3900.00 39.573 347.602 3662.84 4000.00 48.154 343.673 3734.89 4060.28 53.380 341.789 3773.00 4100.00 56.838 340.684 3795.72 4117.32 58.349 340.229 3805.00 4177.08 63.573 338.764 3834.00 4200.00 65.580 338.239 3843.84 4242.11 69.273 337.314 3860.00 4300.00 74.357 336.113 3878.06 4351.87 78.917 335.088 3890.05 4400.00 78.917 335.088 3899.30 4500.00 78.917 335.088 3918.52 4512.89 78.917 335.088 3921.00 4600.00 78.917 335.088 3937.75 4654.81 78.917 335.088 3948.28 4700.00 81.629 333.436 3955.92 4794.26 87.306 330.055 3965.00 Vertical Local Coordinates Global:C Depth Northings Eastings Northings ` (ft) (ft) (ft) (ft) 3516.44 717.96 N 46.54 W 6015772.24 !N. 3549.00 730.76 N 45.42 W 60 15785.05 N 3557.94 734.51 N 45.22:W 601.6788.81 N 3646.86 779.99 N 47.43 W 601583.4.27 N 3728.34 836.93 N 57.33 W 6015891.13 N 3800.39 903.92 N 14.67 W 6015958.00 N 3838.50 948.48 N 88.55 W 6016002.46 N 3861.22 979.32 N 99.04 W 6016033.23 N 3870.50 993.10 N 103.93 W 6016046.98 N 3899.50 1042;01 N 122.24 W 6016095.76 N 3909.34 1061.27IN 129.82 W 6016114.97 N 3925.50 1097.26 N 144.53 W 6016150.85 N 3943.56 1147.76 N 166.28 W 6016201.20 N 3955.55 1193.70 N 187.12 W 6016246.99 N 3964.80 1236.54 N 207.02 W 6016289.69 N 3984.02 1325.54 N 248.35 W 6016378.41 N 3986.50 1337.01 N 253.68 W 6016389.84 N 4003.25 1414.54 N 289.69 W 6016467.12 N 4013.78 1463.33 N 312.35 W 6016515.74 N 4021.42 1503.44 N 331.69 W 6016555.72 N 4030.50 1586.03 N 376.09 W 6016638.00 N Alaska State Plane Zone 4 Milne Point MPJ Mates Dogleg Vertical 3965.27 :Ea stings Rate Section Comment (ft) (./10 oft) (ft) 4900.00 551887.59E 337.413 713.43 60000/100ft Dir 1680.69 N 422.80 W 6016732.33 N MD, 3516.44ft TVD 551888.63 E 6.000 726.28 ((�� 91000 to In 344.370 3974.29 4039.79 to 690'30ft MD, 455.49 W 6016826.44 N 551471.29 E 3549.00ft TVD 551888.80 E 9.000 730.04 351.326 551886.28 E 9.000 775.28 476.51 W 551875.98 E 9.000 831.45 1837.84 551858.17 E 9.000 897.18 551843.98 E 9.000 940.75 NA 551833.28 E 9.000 970.85 551828.29 E 9.000 984.28 NB 551809.64 E 9.000 1031.90 NC 551801.92 E 9.000 1050.63 551786.96 E 9.000 1085.59 NE 551764.87 E 9.000 1134.57 551743.70 E 9.000 1179.07 End Dir: 4351.87ft MD, 3955.55ft TVD 551723.51 E 0.000 1220.53 551681.55 E 0.000 1306.67 551676.15 E 0.000 1317.77 NF 551639.59 E 0.000 1392.81 551616.60 E 0.000 1440.02 Start Dir �7.0000/100ft 4654.81ft D, 4013.78ft TVD 551596.98 E 7.000 1478.80 551552.00E 7.000 1558.34 6i952a�100ft Decrease MD, 40 0.50ft TVD OA Target - MPJ -01A T1 (June2) 4800.00 87.310 330.454 3965.27 4030.77 1591.01 N 378.94 W 6016642.96 N 551549.12 E 6.952 1563.12 4900.00 87.409 337.413 3969.88 4035.38 1680.69 N 422.80 W 6016732.33 N 551504.63 E 6.952 1649.77 5000.00 87.546 344.370 3974.29 4039.79 1775.03 N 455.49 W 6016826.44 N 551471.29 E 6.952 1741.79 5100.00 87.719 351.326 3978.43 4043.93 1872.65 N 476.51 W 6016923.91 N 551449.59 E 6.952 1837.84 Continued... 11 October, 1999 - 9:03 - 1- DrlllQuest Sperry -Sun Drilling Services Proposal Report for MPJ -0 IA Wp9-2 Revised: 11 October, 1999 Continued... 9 9 October, 1999 - 9:03 .2- DrillQuest i Measured Dogleg Vertical Sub -Sea Vertical Local Coordinates Global C Depth Incl. Azim. Depth Depth Northings Eastings Northings (ft) 552068.64 E 0.262 (ft) (ft) (ft) (ft) (ft) 7500.00 88.779 18.548 4039.04 4104.54 4183.77 N 127.30 E 6019239.19N. 7600.00 88.799 18.810 4041.15 4106.65 4278.49 N 159.32 E 6019334.12::N 7700.00 88.818 19.071 4043.23 4108.73 4373.05 N 191.77 E 661!9428.91 N 7800.00 88.838 19.332 4045.27 4110.77 4467.47 N 224.66 E 601.0523.55 N 7900.00 88.857 19.593 4047.29 4112.79 4561.73 N 257.97 E 601961.8.05 N 8000.00 88.877 19.855 4049.26 4114.76 4655.85 N 291.71 E 6019712.40 N 8037.78 88.885 19.953 4050.00 4115.50 4691.36 N 30457E 6019748.00 N All data is in feet unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to Well. Northings and Eastings are relative to Well. The Dogleg Severity is in Degrees per 100ft. Vertical Section is from Well and calculated along an Azimuth of 3.714° (True). Based upon Minimum Curvature type calculations, at a Measured Depth of 8037.78ft., The Bottom Hole Displacement is 4701.24ft., in the Direction of 3.714° (True). inates Dogleg Vertical Eastings Rate Section Comment (ft) (°/100ft) (ft) 552037.28 E 0.262 4183.23 552068.64 E 0.262 4279.82 552100.43 E 0.262 4376.29 552132.65 E 0.262 4472.64 552165.30 E 0.262 4568.86 552198.39 E 0.262 4664.97 552211.00 E 0.262 4701.24 Total D tt p h : 8037.78ft MD, 4 1/2" Liner Target - MPJ -01A T4 (June2) Continued... 11 October, 1999 - 9:03 .3. Drll/Quest H 158189 DATE CHECK NO. 10/28 FOO 158199 VFNnOR All AQU AQ—r 1 A r) fl DATE INVOICE / CREDIT MEMO DESCRIPTION GROSS DISCOUNT NET 102749 CK102799B 100.00 100.00 HANDLING INST: S/H TERRIE HUBBLF X4628 THE ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. 100,001 100-001 8P EXPLORATION (ALASKA) ING. �I�iS f NATIQF�l11. FlANI� OF ASHLAND N o. H 15 818 9 PAS : BbX :19 512 AK:APAL1ATE op r�At Ai L, ciTY BANK CONSOLIDATED COMMEACIAC ACCOUNT:': ANGHOFiAGE ALAI: 99519-6612 CCEVE LAND OW6 41200158189:: II' 158 1891" 1:04 1 20 389 51: 0084419,11 H WELL PERMIT CHECKLIST COMPANY WELL NAME&AZ PROGRAM: exp dev redrIl V1 sery wellbore seg _ann. disposal para req FIELD & POOL INIT CLASS r - GEOL AREA UNIT# ON/OFF SHORE _0AJ ADM1N1STRAT!_0N_T._ 2. 3. Permit fee attached. . . . . . . . . . . . . . . . . . . . . . . / 't , Jq Lease number appropriate'! . . . . . . . . . . . . . . . . . N A i r_V-) , Unique well name and number ... . . . . . . . . . . . . . . . N I -C4 Vla-1 bli_ -7 4. Well located in a defined pool. .N a�:1-7 v 11 a- -e- &x? ?41'_ /_Z>� j %akI r 0 5. Well located proper distance from drilling unit boundary.' Y N 6. Well located proper distance from other wells.. . . . . . . . . N 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . N ......... 8. If deviated, is wellbore plat included .. . . . . . . . . . . . . . Y, N 9. 10. Operator only affected party .. . . . . . . . . . . . . . . . . . Operator has appropriate bond in force . . . . . . . . . . . . . N Y N 11. Permit can be issued without conservation order. . . . . . . . N ..... ..... AIDPR DATE oe-. 12. 13. Permit can be issued without administrative approval.. . . . . Can be before 15 N Y N _77 permit approved -day wait.. . . . . . . . . . ENGINEERING 14. Conductor string provided . . . . . . . . . . . . . . . . . . . Y N 15. 16. Surface casing protects all known USDWs . . . . . . . . . . . CMT vol adequate to circulate on conductor & surf csg Y N Y N C) . . . . . 17. 18. CMT vol adequate to tie-in long string to surf csg . . . . . . . . CMT will cover all known productive horizons. . . . . . . . . . Y N Y 19. Casing designs adequate for C, T, B & permafrost. . . . . . . 20. Adequate tankage or reserve pit .. . . . . . . . . . . . . . . . If for N Y 21. a re -drill, has a 10-403 abandonment been approved. . . N jQ 22. Adequate wellbore separation proposed .. . . . . . . . . . . . Y N 23. 24. If diverter required, does it meet regulations . . . . . . . . . . Drilling fluid program schematic & equip list adequate . . . . . _*_N_ N 25. BOPEs, do they meet regulation . . . . . . . . . . . . . . * , Y N DATE 26. BOPE press rating appropriate; test to psig. Y N iY n f J 27. Choke manifold complies w/API RP -53 (May 84) . . . . . . . . N 28. Work will occur without operation shutdown. . . . . . . . . . . N 29. Is presence of H2S gas probable .. . . . . . . . . . . . . . . . Y GEOLOGY—- -80. Permit can be issued w/o hydrogen sulfide mea -sure -s-.-- CY)N 31. Data presented on potential overpressure zones . . . . . . . Y N 32. Seismic analysis of shallow gas zones . . . . . . . . . . . . . Y N 41171 APPIR33. �Xq 34. Seabed condition survey (if off -shore) . . . . . . . . . . . . Contact for 6 N -,V4 Y N 1 name/phone weekly progress reports [exploratory only ANNULAR DISPOSAL 35. With proper cementing records, this plan � �j I'll, In 1, � ;j I F! 15:! 1 111 contain c a waste 0 w 'e In (A) will contain waste in a 1. 9 Y N Y__ APPR DATE ea 0 c 0 n ta freshwater; (B) will not conta e freshwater; or cause drilling waste Y N to surface - I (C) will no i pair mechanical integrity of the well used for disposal; Y (D) will of damage producing formation or impair recovery from a Y P ol; and (E) i 11 not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N GEOI OGY' ENGINEERING: UIC/AmmInj COMMISSION: Comments/Instructions: S1 F PAEI� I- BE VV DWJNC -4�X� D��JDH R T E M ;6�kLO-4 1C) t CO cc.[J;I 1s1h1 c:\msoffice\wordiati\diaiia\ctiecklist (rev. 09/27/99) 0 0 Z Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. Sperry -Sun Drilling Services LIS Scan Utility $Revision: 3 $ LisLib $Revision: 4 $ Thu Dec 16 21:34:08 1999 Reel Header Service name.............LISTPE Date .....................99/12/16 Origin...................STS Reel Name................UNKNOWN Continuation Number ...... 01 Previous Reel Name....... UNKNOWN Comments.................STS LIS Writing Library. Tape Header Service name.............LISTPE Date .....................99/12/16 Origin...................STS Tape Name................UNKNOWN Continuation Number ...... 01 Previous Tape Name....... UNKNOWN Comments.................STS LIS Writing Library. Physical EOF Comment Record TAPE HEADER Milne Point Unit MWD/MAD LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: Scientific Technical Services Scientific Technical Services MPJ- 01A 500292207001 BP Exploration (Alaska), Inc. Sperry Sun 16 -DEC -99 MWD RUN 2 MWD RUN 3 AK -MM -90191 AK -MM -90191 G. GRIFFIN G. GRIFFIN �CEIV T. ANGLEN D. WESTER SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL : ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: WELL CASING RECORD 0 4 2000 10 E COtIS. C0�1rI1#�IOn AnftraP 2622 3378 65.65 65.65 35.50 OPEN HOLE BIT SIZE (IN) 1ST STRING 5.630 2ND STRING 6.125 3RD STRING 6.125 PRODUCTION STRING REMARKS CASING DRILLERS SIZE (IN) DEPTH (FT) 13.375 105.0 7.000 3643.0 .0 1. ALL DEPTHS ARE MEASURED DEPTHS (MD) UNLESS OTHERWISE NOTED. 2. MWD RUN 1 IS DIRECTIONAL ONLY AND NOT PRESENTED. 3. MWD RUNS 2-3 ARE DIRECTIONAL WITH DUAL GAMMA RAY (DGR) UTILIZING GEIGER - MUELLER TUBE DETECTORS AND ELECTROMAGNETIC WAVE RESISTIVITY PHASE -4 (EWR4). 4. DEPTH SHIFTING/CORRECTION OF MWD DATA IS WAIVED AS PER THE E MAIL MESSAGE FROM D DOUGLAS FOR M VANDERGON OF BP EXPLORATION (ALASKA), INC. ON 12/15/99 MWD DATA IS CONSIDERED PDC. KICKOFF POINT FROM PARENT WELLBORE FOR THIS WE IS 3642'MD, 3505'TVD. 5. MWD RUNS 1-3 REPRESENT WELL MPJ -01A WITH API#: 50-029-22070-01. THIS WELL REACHED A TOTAL DEPTH (TD) OF 8034'MD, 4140'TVD. SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING. SGRC = SMOOTHED GAMMA RAY COMBINED. SEXP = SMOOTHED PHASE SHIFT -DERIVED RESISTIVITY (EXTRA -SHALLOW SPACING). SESP = SMOOTHED PHASE SHIFT -DERIVED RESISTIVITY (SHALLOW SPACING). SEMP = SMOOTHED PHASE SHIFT -DERIVED RESISTIVITY (MEDIUM SPACING). SEDP = SMOOTHED PHASE SHIFT -DERIVED RESISTIVITY (DEEP SPACING). SFXE = SMOOTHED FORMATION EXPOSURE TIME. File Header Service name.............STSLIB.001 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 99/12/16 Maximum Physical Record..65535 File Type................LO Previous File Name ....... STSLIB.000 Comment Record FILE HEADER FILE NUMBER: 1 EDITED MERGED MWD Depth shifted and clipped curves; DEPTH INCREMENT: .5000 FILE SUMMARY all bit runs merged. PBU TOOL CODE START DEPTH STOP DEPTH GR 3630.0 7984.5 RPD 3637.0 7991.0 RPM 3637.0 7991.0 RPS 3637.0 7991.0 RPX 3637.0 7991.0 FET 3668.5 7991.0 ROP 3670.0 8034.5 4 1 68 8 BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH MERGED DATA SOURCE PBU TOOL CODE BIT RUN NO MERGE TOP MERGE BASE MWD 200 3630.0 4888.0 MWD 300 4888.0 8034.0 REMARKS: MERGED MAIN PASS. Data Format Specification Record Data Record Type..................0 Data Specification Block Type ..... 0 Logging Direction.................Down Optical log depth units ........... Feet Data Reference Point..............Undefined Frame Spacing.....................60 .1IN Max frames per record.............Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub -type ... 0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD FT/H 4 1 68 4 2 GR MWD API 4 1 68 8 3 RPX MWD OHMM 4 1 68 12 4 RPS MWD OHMM 4 1 68 16 5 RPM MWD OHMM 4 1 68 20 6 RPD MWD OHMM 4 1 68 24 7 FET MWD HOUR 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3630 8034.5 5832.25 8810 3630 8034.5 ROP MWD FT/H 0 897.53 105.577 8730 3670 8034.5 GR MWD API 22.71 128.23 80.9043 8710 3630 7984.5 RPX MWD OHMM 0.24 1533.12 11.1252 8708 3637 7991 RPS MWD OHMM 0.37 2000 17.2774 8708 3637 7991 RPM MWD OHMM 0.73 2000 20.6949 8708 3637 7991 RPD MWD OHMM 2.04 2000 19.7582 8708 3637 7991 FET MWD HOUR 0.2422 16.0621 1.04388 8645 3668.5 7991 First Reading For Entire File.......... 3630 Last Reading For Entire File ........... 8034.5 File Trailer Service name.............STSLIB.001 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 99/12/16 Maximum Physical Record..65535 File Type................LO Next File Name ........... STSLIB.002 Physical EOF File Header Service name.............STSLIB.002 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 99/12/16 Maximum Physical Record..65535 File Type................LO Previous File Name ....... STSLIB.001 Comment Record FILE HEADER FILE NUMBER: 2 SOFTWARE RAW MWD SURFACE SOFTWARE VERSION: Insite Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 2 4888.0 DEPTH INCREMENT: .5000 BOTTOM LOG INTERVAL (FT): 4884.0 BIT ROTATING SPEED (RPM): FILE SUMMARY MINIMUM ANGLE: VENDOR TOOL CODE START DEPTH STOP DEPTH GR 3630.0 4849.0 RPX 3637.0 4856.0 RPD 3637.0 4856.0 RPS 3637.0 4856.0 RPM 3637.0 4856.0 FET 3668.5 4856.0 ROP 3670.0 4888.0 LOG HEADER DATA DATE LOGGED: 24-NOV-99 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 0.41 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 4888.0 TOP LOG INTERVAL (FT): 3630.0 BOTTOM LOG INTERVAL (FT): 4884.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 20.7 MAXIMUM ANGLE: 89.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER # # DGR DUAL GAMMA RAY P135GRV4 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: # Data Format Specification Record Data Record Type..................0 Data Specification Block Type ..... 0 Logging Direction.................Down Optical log depth units ........... Feet Data Reference Point..............Undefined Frame Spacing.....................60 .1IN Max frames per record.............Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub -type ... 0 6.125 Water Based 9.70 45.0 9.1 27000 3.5 .170 67.0 .114 103.0 .140 67.0 .320 67.0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD 2 FT/H 4 1 68 4 2 GR MWD 2 API 4 1 68 8 3 RPX MWD 2 OHMM 4 1 68 12 4 RPS MWD 2 OHMM 4 1 68 16 5 RPM MWD 2 OHMM 4 1 68 20 6 RPD MWD 2 OHMM 4 1 68 24 7 FET MWD 2 HOUR 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3630 4888 4259 2517 3630 4888 ROP MWD 2 FT/H 14.62 384.98 91.5696 2437 3670 4888 GR MWD 2 API 22.71 128.23 79.9813 2439 3630 4849 RPX MWD 2 OHMM 0.24 1533.12 9.23222 2439 3637 4856 RPS M'A7D 2 OHMM 0.37 2000 21.0643 2439 3637 4856 RPM MIWD 2 OHMM 0.73 2000 31.2907 2439 3637 4856 RPD MWD 2 OHMM 2.04 2000 26.3692 2439 3637 4856 FET MWD 2 HOUR 0.2441 1.7072 0.766968 2376 3668.5 4856 First Reading For Entire File.......... 3630 Last Reading For Entire File ........... 4888 File Trailer Service name.............STSLIB.002 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 99/12/16 Maximum Physical Record..65535 File Type................LO Next File Name ........... STSLIB.003 Physical EOF File Header Service name.............STSLIB.003 Service Sub Level Name... Version Number.. ........1.0.0 Date of Generation ....... 99/12/16 Maximum Physical Record..65535 File Type................LO Previous File Name ....... STSLIB.002 Comment Record FILE HEADER FILE NUMBER: 3 SOFTWARE RAW MWD SURFACE SOFTWARE VERSION: Insite Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 3 8034.0 DEPTH INCREMENT: .5000 BOTTOM LOG INTERVAL (FT): 8034.5 BIT ROTATING SPEED (RPM): FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 4849.5 7984.5 RPD 4856.5 7991.0 RPM 4856.5 7991.0 RPS 4856.5 7991.0 RPX 4856.5 7991.0 FET 4856.5 7991.0 ROP 4889.5 8034.5 LOG HEADER DATA DATE LOGGED: 27-NOV-99 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 0.41 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 8034.0 TOP LOG INTERVAL (FT): 4849.5 BOTTOM LOG INTERVAL (FT): 8034.5 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 82.8 MAXIMUM ANGLE: 92.8 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY P1335GRV4 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 6.125 DRILLER'S CASING DEPTH (FT): BOREHOLE CONDITIONS MUD TYPE: Water Based MUD DENSITY (LB/G): 9.70 MUD VISCOSITY (S): 46.0 MUD PH: 8.5 MUD CHLORIDES (PPM): FLUID LOSS (C3): 3.2 RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): .100 79.0 MUD AT MAX CIRCULATING TERMPERATURE: .080 100.0 MUD FILTRATE AT MT: .080 79.0 MUD CAKE AT MT: .180 79.0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format Specification Record Data Record Type..................0 Data Specification Block Type ..... 0 Logging Direction.................Down Optical log depth units ........... Feet Data Reference Point..............Undefined Frame Spacing.....................60 .1IN Max frames per record.............Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub -type ... 0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD 3 FT/H 4 1 68 4 2 GR MWD 3 API 4 1 68 8 3 RPX MWD 3 OHMM 4 1 68 12 4 RPS MWD 3 OHMM 4 1 68 16 5 RPM MWD 3 OHMM 4 1 68 20 6 RPD MWD 3 OHMM 4 1 68 24 7 FET MWD 3 HOUR 4 1 68 28 8 First Reading For Entire File.......... 4849.5 Last Reading For Entire File ........... 8034.5 File Trailer Service name.............STSLIB.003 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 99/12/16 Maximum Physical Record..65535 File Type................LO Next File Name ........... STSLIB.004 Physical EOF Tape Trailer Service name.............LISTPE Date.....................99/12/16 Origin...................STS Tape Name................UNKNOWN Continuation Number ...... 01 Next Tape Name ........... UNKNOWN Comments.................STS LIS Writing Library. Reel Trailer Service name.............LISTPE Date.....................99/12/16 Origin...................STS Reel Name................UNKNOWN Continuation Number ...... 01 Next Reel Name ........... UNKNOWN Comments.................STS LIS Writing Library Physical EOF Physical EOF End Of LIS File Scientific Technical Services Scientific Technical Services First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 4849.5 8034.5 6442 6371 4849.5 8034.5 ROP 1\61'WD 3 FT/H 0 897.53 110.975 6291 4889.5 8034.5 GR MWD 3 APi 46.68 124.03 81.2633 6271 4849.5 7984.5 RPX MWD 3 OHMM 3.71 84.7 11.862 6270 4856.5 7991 RPS M`WD 3 OHMM 4.3 212.73 15.8044 6270 4856.5 7991 RPM MWD 3 OHMM 4.55 72.68 16.5731 6270 4856.5 7991 RPD MWD 3 OHMM 5.1 61.88 17.1868 6270 4856.5 7991 FET MWD 3 HOUR 0.2422 16.0621 1.14872 6270 4856.5 7991 First Reading For Entire File.......... 4849.5 Last Reading For Entire File ........... 8034.5 File Trailer Service name.............STSLIB.003 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 99/12/16 Maximum Physical Record..65535 File Type................LO Next File Name ........... STSLIB.004 Physical EOF Tape Trailer Service name.............LISTPE Date.....................99/12/16 Origin...................STS Tape Name................UNKNOWN Continuation Number ...... 01 Next Tape Name ........... UNKNOWN Comments.................STS LIS Writing Library. Reel Trailer Service name.............LISTPE Date.....................99/12/16 Origin...................STS Reel Name................UNKNOWN Continuation Number ...... 01 Next Reel Name ........... UNKNOWN Comments.................STS LIS Writing Library Physical EOF Physical EOF End Of LIS File Scientific Technical Services Scientific Technical Services