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Home My WebLink About197-1288 By Grace Christianson at 8:30 am, Jun 27, 2023 Abandoned 6/8/2023 JSB RBDMS JSB 062923 xG MGR08AUG2023 DSR-7/19/23 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2023.06.26 16:29:02 -08'00' Monty M Myers Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.06.26 21:31:21 - 08'00' Taylor Wellman (2143) _____________________________________________________________________________________ Revised By: JNL 6/26/2023 SCHEMATIC Milne Point Unit Well: MPU L-39 Last Completed: 5/15/2023 PTD: 197-128 GENERAL WELL INFO API: 50-029-22786-00-00 Drilled and Cased by Nabors 27E - 6/29/1997 3.5” Injection Completion by Nabors 27E – 7/1/1998 Conversion to Jet Pump – 10/16/2014 Convert to Producer – 4/23/2015 Install Kill String by ASR#1 – 11/24/2016 Run ESP Doyon 14 – 2/7/2017 Completed by ASR – 5/15/2023 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. A2 &A3 12,362’ 12,402’ 7,062’ 7,098’ 40 6/27/1998 Closed CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 114' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’ 7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’ TUBING DETAIL 4-1/2” Tubing 12.6/L-80/TXP 3.958 Surface 12,154’ 3-1/2” Tubing 9.3 / L-80 / EUE 2.992 12,286’ 12,332’ JEWELRY DETAIL No Depth Item 1 11,858’ 3.813” X Sliding Sleeve 2 11,919’ 4-1/2” D&L Perm Hyd Packer COE 7.8’ from PIN “Threads off” 3 12,020’ 3.813” X Nipple 4 12,113’ Wireline entry guide – Btm @ 12,154’ 5 12,255’ A Whipstock 6 12,296’ 3-1/2” Baker SB-3 Packer 7 12,320’ 3-1/2” HES XN Nipple (No Go 2.750” ID) 8 12,332’ 3-1/2” Otis WLEG OPEN HOLE / CEMENT DETAIL 24" 250 sx of Arcticset I (Approx) 12-1/4" 2,199 sx PF “E”, 550 sx Class “G” 8-1/2” 275 sks Class “G” WELL INCLINATION DETAIL KOP @ 300’ to 4,500’ Max Hole Angle = 78 deg. Max Hole Angle through perforations = 27 deg. TREE & WELLHEAD Tree 5M Cameron 2-9/16” Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile STIMULATION SUMMARY Kuparuk “A” Sand: 59,000# of 20/40 Carbo Bond frac proppant behind pipe. TD = 12,740’ (MD) / TD = 7,401’(TVD) 20” KB Elev.: 51.42’, GL Elev.: 17.1’ 7” 2 4 9-5/8” 1 5 3 3-1/2” Tubing w/ Packer & Tail (12,286’ – 12,332’) 8 A Whipstock set @ 12,555’ PBTD = 12,255’(MD)/ PBTD = 6,956’(TVD) 67 12,255' ACTIVITYDATE SUMMARY 5/19/2023 T/I/O=180/15/0 Assist Slickline ( Circ 11.3 brine to tank) Unable to slide sleeve open.Did not pump any fluids. Final Whp's=180/20/0 5/19/2023 *** WELL SHUT-IN ON ARRIVAL.*** ATTEMPT TO SHIFT XD-SS AT 11,839' MD (See log). *** CONTINUE WSR ON 5-20-23.*** 5/20/2023 *** CONTINUE WSR FROM 5-19-23.*** ATTEMPT TO SHIFT SLEEVE. PULLED OFF JOB DUE TO HOT JOB ON I-PAD. *** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.*** 5/20/2023 T/I/O=180/20/0 (Circ Out Brine to tank) Job Postponed. Did not pump any fluids. Final Whp's=180/20/0 5/22/2023 *** WELL SHUT-IN ON ARRIVAL.*** PULL BALL&ROD, 4-1/2" RHC FROM X-NIPPLE AT 12,001' MD. *** CONTINUE WSR ON 5/23/23.*** 5/23/2023 *** CONTINUE WSR FROM 5-22-23.*** SHIFT XD-SS W/ 4-1/2" 42BO(open) AT 11,839' MD. LRS ASSIST W/ 94bbls SOURCE WATER. SHIFT XD-SS W/ 4-1/2" 42BO(closed) AT 11,839' MD. LRS ASSIST W/ 52bbls SOURCE WATER. LRS PRESSURE TESTED IA TO 1700psi (Holding). LRS FREEZE PROTECTED W/ DIESEL TBG - 42bbls, IA - 48bbls. *** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.*** 5/23/2023 T/I/O=10/0/0 Assist Slickline/Freeze protect. Pumped a total of 146 bbls source water down TBG to assist slickline down hole. Pumped 48 bbls diesel down IA and 42 bbls diesel down TBG to freeze protect. Pressured up IA to 1700 psi with .3 bbls diesel after SL shut sleeve. IA lost 28 psi in 10 min. Bled IA to 0 psi and recovered1.7 bbls Final Whps=1700/0/0 Daily Report of Well Operations PBU MPL-39 Activity Date Ops Summary 6/6/2023 Pull mud module off. Pull sub off. Prepare cellar. Pull over and set down with rig. Rig accepted at 14:00. RU checklists. LTT tree to 3500#. Install extra wing valve for MPD line. N/U BOPE. Grease and service all choke and kill valves. Take on KWF and rig water. Install new pack offs and clean stripper brass. R/U and PT return line to tiger tank to 4200 psi. Hold Pre-Spud with Kaleos crew. Displace coil to fresh water. Start initial BOPE test. Test witness was waived by AOGCC representative Guy Cook. Test 1: IRV, Stripper, C7, C9, C10, C11. Replace leaking whitey valve on test pump. Test again and Pass. Test 2: Blind/Shears, R2, B2, C15. Pass. Test 3: Annular (2 3/8"), TIW #1, Bravo #1, Bravo #4. 6/7/2023 Test 3: Annular (2 3/8"), TIW #1, Bravo #1, Bravo #4. Bravo #1 fail/pass. Test 4: Upper 2 3/8" Pipe/Slips, TIW#2, Bravo #2, Bravo #3. Test 5: Lower 2 3/8" Pipe/Slips, C5, C6, C8, TV2. Test 6: Choke A, Choke C. - Test 7: Charlie 1, Charlie 4, TV1.F23 Test 8: Pipe/Slips, Charlie 2, Charlie 3. Draw Down Test on Accumulator. Test Rig Gas Alarms. R/D BOP test joint and equipment. Swap test risers to drilling risers. R/U and test PDL's to 3500 psi. Not able to see pump pressure to test PDL's. RU to read pressure at the lubricator while troubleshooting Pump Transducer. PDL's tested to 3500psi. Install BHI Floats and Test. Good test, MU nozzle BHA on coil to RIH and displace well to source water then perform FIT Test to see if the parent Perfs will support the 11.8 ECD required to drill the D- Shale. Open up to well, WHP = 770psi. RIH with nozzle BHA holding 900psi WHP. 2000' online with pump. 2600' getting a lot of gas back, maintain <150psi downstream of the choke. Tag tubing stump at 12,280'. Circulate source water to surface. In Rate = 1.95 bpm, Out Rate = 1.91 bpm. In Mud Weight = 8.36 ppg, Out Mud Weight = 8.83 ppg. IA = 662, OA = 0. Shut in tubing pressure (WHP) fell to 735 psi after bumping up twice. EMW ~ 10.4 ppg. Pump down coil with closed choke and establish loss rate at 1300 psi. LLR = 20 bph at 1300 psi. Swap well over to used mud system from 12,269'. Continue displacing source water from well with used mud from 12,269'. In Rate = 2 bpm, Out Rate = 1.94 bpm. In Mud Weight = 8.70 ppg, Out Mud Weight = 8.41 ppg. IA = 881, OA = 0. Mud back to surface. POOH from 12,269'. In Rate = 1.51 bpm, Out Rate = .98 bpm. In Mud Weight = 8.70 ppg, Out Mud Weight = 8.77 ppg. IA = 1014, OA = 0. OOH - Secure well and L/D nozzle BHA. M/U and pressure deploy BHI DGS and HOT with Baker whipstock drift. RIH with BHA #2 - 3.70" Baker Whipstock Drift. In Rate = .76 bpm, Out Rate = 1.21 bpm. In Mud Weight = 8.72 ppg, Out Mud Weight = 8.79 ppg. IA = 773, OA = 79. WHP = 837 psi. 6/8/2023 Continue RIH with WS Drift BHA. Log tie in, correct depth -5' and RIH. Clean drift to tag at 12276', PU and retag to confirm. Tag at same depth. POOH for WS BHA. OOH, PUD the drift BHA, maintain 11.8 ECD. RIH with WS BHA. Log Tie in, correct depth -6'. RIH and lightly tag 3.5" stub at 12274'. PUH to 122655', PUW = 51k. RIH to 12266' (BOWS), PU to 48k (12264') close EDC and set WS at 0deg ROHS. WS set and sheared at 5338psi, set down 7k WOB with no movement. Open EDC and POOH maintaining 11.8 ECD at the window. OOH - PJSM. PUD NSAK WS setting tool. Pressure Deploy NSAK window milling BHA #3. NSAK 2 7/8 straight motor w/3.80" string reamer and window mill. RIH with window milling BHA. In Rate = .80 bpm, Out Rate = 1.25 bpm. In Mud Weight = 8.73 ppg, Out Mud Weight = 8.81 ppg. IA = 641 psi, OA = 23 psi. WHP = 1027 psi. Log Tie In from 11,780' @ 5 fpm. Correct -8'. Close EDC RIH and dry tag whipstock pinch point @ 12,257'. PUH and establish milling paramaters. Begin milling window from 12,256'. In Rate = 2.50 bpm, Out Rate = 2.50 bpm. In Mud Weight = 8.73 ppg, Out Mud Weight = 8.81 ppg. IA = 825 psi, OA = 98 psi. WHP = 550 psi. Milling estimated mid-point of window at 12,260'. In Rate = 2.58 bpm, Out Rate = 2.52 bpm. In Mud Weight = 8.72 ppg, Out Mud Weight = 8.78 ppg. IA = 1289 psi, OA = 431 psi. WHP = 519 psi 6/9/2023 Milling window at 12,262.7'. In Rate = 2.54 bpm, Out Rate = 2.52 bpm. In Mud Weight = 8.72 ppg, Out Mud Weight = 8.85 ppg. IA = 1363 psi, OA = 483 psi WHP = 478 psi, ECD = 11.81. Exit the bottom of the window at 12263.7' continue milling at 1 fph for 1' to dress bottom of window with string mill. 12265' start milling 10' of Rat Hole and increase rate to 2.85 bpm. Very slow milling Rat Hole and high vibration on the tool. Reduce rate to 2.65 bpm to reduce vibration. Milled 10' of Rat hole to 122675' start ream passes. Ream passes completed, dry drift window. Seeing WOB at the TOW, continue dressing TOW until clean BOW sample 2% formation. 12274' sample 40% formation. Made 2 slow ream passes through window, dry drift is clean, POOH for the build BHA. OOH PUD the milling BHA. String Reamer and window mill both gauged 3.80" GO 3.79" NO GO. M/U and RIH with swizzle stick to jet stack and surface lines. Pressure deploy build BHA with 2.1 deg motor bend and re-run HCC 4.25" bi-center bit. RIH with build BHA #5. In Rate = .95 bpm, Out Rate = 1.52 bpm. In Mud Weight = 8.75 ppg, Out Mud Weight = 8.81 ppg. IA = 22 psi, OA = 157 psi. WHP = 528 psi, ECD = 11.73. Log tie in from 11170' @ 5 fpm. Correct - 7'. Close EDC and RIH through window clean. Bring pump up to rate and establish parameters. Drill 4.25" lateral from 12274'. In Rate = 2.79 bpm, Out Rate = 2.80 bpm. In Mud Weight = 8.75 ppg, Out Mud Weight = 8.81 ppg. IA = 753 psi, OA = 244 psi. WHP = 420 psi, ECD = 11.76. Drill 4.25" lateral from 12331' to 12,351'. In Rate = 2.80 bpm, Out Rate = 2.77 bpm. In Mud Weight = 8.76 ppg, Out Mud Weight = 8.83 ppg. IA = 748 psi, OA = 436 psi. WHP = 413 psi, ECD = 11.70. ROP = 10 - 30. 50-029-22786-01-00API #: Well Name: Field: County/State: MP L-39A Milne Point Hilcorp Energy Company Composite Report , Alaska 6/9/2023Spud Date: PU to 48k (12264') close EDC and set WS at 0deg ROHS. Clean drift to tag at 12276', 12266' (BOWS), 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Complete 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 12,740 feet N/A feet true vertical 7,401 feet N/A feet Effective Depth measured 12,634 feet 11,901 & 12,271 feet true vertical 7,305 feet 6,646 & 6,970 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 4-1/2" 12.6# / L-80 / Multi 12,136' 6,852' Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 / EUE Mod 8rd 12,312' 7,007' 7" x $-1/2" D&L Perm. ISO Packers and SSSV (type, measured and true vertical depth)3.5" Baker SB-3 N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: 5,750psi 7,240psi12,717' 7,380' Burst N/A Collapse N/A 3,090psi 5,410psi Casing Conductor 12,684' 8,649'Surface Intermediate 20" 9-5/8" 7" 80' 8,613' measured TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 197-128 50-029-22786-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025509, ADL0025514 & ADL0025515 MILNE POINT / KUPARUK RIVER OIL MILNE PT UNIT L-39 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 114' 1450 Size 114' 4,165' 0 14500 0 00 0 323-198 & 323-249 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Scott Pessetto scott.pessetto@hilcorp.com 907-564-4373 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:17 am, Jun 05, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.06.02 14:25:13 - 08'00' Taylor Wellman (2143) RBDMS JSB 071723 WCB 2-1-2024 DSR-6/12/23 _____________________________________________________________________________________ Revised By: TDF 5/16/2023 SCHEMATIC Milne Point Unit Well: MPU L-39 Last Completed: 5/15/2023 PTD: 197-128 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 114' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’ 7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’ TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / TXP 3.958 Surface 733’ 4-1/2” Tubing 12.6 / L-80 / EZGO HT 3.958 733’ 8,500’ 4-1/2” Tubing 12.6 / L-80 / DWC 3.958 8,500 12,136’ 3.5" Tubing 9.3/L-80/EUE Mod 8rd 2.992 12,264’ 12,312’ JEWELRY DETAIL No Depth Item 1 11,839’ Sliding Sleeve 2 11,901’ 7" x 4½" D&L PERM. HYD. ISO Packer COE 7.8' from PIN "threads off" 3 12,001 X Nipple Min ID - 3.813'' w/ RHC Installed 4 12,094’ Wireline Entry – Mule Shoe –Bottom @ 12,136’ 5 12,271’ 3.5” Baker SB-3 Packer 6 12,295’ 3.5” HES XN Nipple (No Go 2.750” ID) 7 12,307 3.5” Otis WLEG PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. A2 &A3 12,362’ 12,402’ 7,062’ 7,098’ 40 6/27/1998 Open OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24” Hole 9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole 7” 275 sks Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 300’ to 4,500’ Max Hole Angle = 78 deg. Max Hole Angle through perforations = 27 deg. TREE & WELLHEAD Tree 5M Cameron 2-9/16” Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile GENERAL WELL INFO API: 50-029-22786-00-00 Drilled and Cased by Nabors 27E - 6/29/1997 3.5” Injection Completion by Nabors 27E – 7/1/1998 Conversion to Jet Pump – 10/16/2014 Convert to Producer – 4/23/2015 Install Kill String by ASR#1 – 11/24/2016 Run ESP Doyon 14 – 2/7/2017 Completed by ASR - 5/15/2023 STIMULATION SUMMARY Kuparuk “A” Sand: 59,000# of 20/40 Carbo Bond frac proppant behind pipe. TD =12,740’ (MD) / TD = 7,401’(TVD) 20” Orig. KB Elev.: 34.3’ 7” 2 4 9-5/8” 1 5 3 Top of Tubing Cut @ 12,264’ PBTD = 12,634’ (MD) / PBTD = 7,305’(TVD) 6 7 NOTE: ALL TUBING AND JEWELRY DEPTHS ADJUSTED TO ASR RKB. Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR 50-029-22786 197-128 4/25/2023 5/16/2023 4/21/2022 - Friday No operations to report. 4/19/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 4/20/2022 - Thursday No operations to report. Rig accepted at 20:30 hrs. Fill stack and work air out of system, Test Annular to 250 low/ 3500 high psi for 5 min each with 2 7/8" test jt. LPR's failed test - leaking out of weep hole. Drain stack and replace seals on pipe rams ( double gate). No operations to report. 4/22/2022 - Saturday No operations to report. 4/25/2023 - Tuesday 4/23/2023 - Sunday No operations to report. 4/24/2023 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR 50-029-22786 197-128 4/25/2023 5/16/2023 Cont. milling at 12,126' ROT 30 RPM, free rot TQ = 4.5K ft-lbs . Changed RPM and pump rate. No torque response, no depth change. 24 BPH loss rate while milling pumping at 4 BPM w/ 1550 psi. Decision was made with OE to POOH & run, outside mechanical cutter. Break swivel. L/D JT. Disconnect kelly hose and blow down. POOH with 3-1/2" workstring and milling BHA from 12,126' to 9,525' Pump single displacement for hole fill. Service Rig. POOH with 3-1/2" workstring and milling BHA F/ 9,525' T/ 354'. Pump single displacement for hole fill. L/D PKR Milling BHA. Intensifier, 6x drill collars, hyd oil jars, bumper sub, 2x boot baskets, drive sub, 4x joints of wash pipe, PKR mill shoe. Drive sub shows internal indication of contact with tubing stub. Service rig. Clean & clear floor. P/U & M/U outside mechanical cutter BHA as per fishing rep. BHA includes. outside cutter assy. , 6x joints of wash pipe, drive sub, bumper sub, hyd. oil jars, 6x drill collars, intensifier. RIH w/ outside mechanical cutter BHA on 3-1/2 workstring F/ 406' T/ 2,205' P/U wt = 25K S/O wt = 20K. 4/29/2023 - Saturday 4/28/2023 - Friday Swap over handling equipment for 3-1/2 workstring. rack and tally BHA and workstring in pipe shed. P/U M/U packer milling BHA as per yellowjacket rep. BHA includes dress off shoe, 4 joints of wash pipe, boot baskets, bumper sub, jars, 6 drill collars. RIH w/ milling BHA on 3-1/2 workstring F/ 343' T/ 1,954' P/U wt = 23K S/O wt = 19k. Service Rig. RIH w/ milling BHA on 3-1/2 workstring F/ 1,954' T/ 11,645' P/U wt = 105K S/O wt = 35k. Service rig. Clear rig floor of rust debris from pipe picked up. RIH w/ milling BHA on 3-1/2 workstring F/ 11,645' T/ 11,995' P/U wt = 110K S/O wt = 37k. Tag up early @ 11,995' w/ 10K dw. Obtain milling parameters. 30 RPM w/ 4.5K ft-lbs TQ, P/U wt = 115K, ROT wt = 65K , S/O wt w/ ROT= 56K. S/O work past obstruction. Cont. RIH w/ milling BHA on 3-1/2 workstring F/ 11,995' T/ 12,126' P/U wt = 110K S/O wt = 37k. Tagged w/ 10K DW. Kelly up & line up to pump for milling ops. At 12,126' ROT 30 RPM, free rot TQ = 4.5K ft-lbs . Work new pump up to 4.5 BPM. Ensure operation of new equipment. Fill pits. 4/26/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Yellowjacket rep replace seals on kill side lower ram. Pick up test joint and Test BOPE to 250 low 3500 high as per approved sundry. witness waive by AOGCC rep Brian Bixby. Tested with 2-7/8",3-1/2" and 4-1/2" test joints. 1 F/P on the rams. Blow down fluid lines. Rig down test equipment. Ship fresh water to kill tank. take on 11.2 brine in the pits. Hang sheave and elephant trunk. run ropes to the spooler. Pick up T bar, Pull CTS, Pull BPV. M/U landing joint. BOLDS. Work hanger up to 112K. Hanger up to 115K. Hold 115K pump down tubing 1 BPM 75psi. packer released. Wait & allow packer elements relax, rig up to pump down tubing. P/U wt = 75K S/O wt= 55K. Pump 75 bbls down tubing to clear any gas from backside of packer. Pump at 2 BPM W/ 400 psi. Shut down. Monitor well, static. POOH w/ ESP completion F/ 11,222' T/ 10,674' pumping single displacement for hole fill. P/U wt = 60k S/O wt = 30k. Service rig. Cont. POOH w/ ESP completion F/ 10,674' T/ 8,757' pumping single displacement for hole fill. P/U wt =44 k S/O wt = 16 k. L/D ESP packer, Bleed cap line & remove cap line f/ derrick sheave. Inspect packer. "Intact" Spliced ESP together to cont. spooling line. 4/27/2023 - Thursday Continue POOH w/ 2-7/8 EUE and ESP completion from F/ 8,725' T/ 6,113' Crew preformed Kick while tripping drill. Continue POOH w/ 2-7/8 EUE and ESP completion F/ 6,113' T/ 2,970'. Service Rig. Continue POOH w/ 2-7/8 EUE and ESP completion F/ 2,970' T/ 82 '. L/D ESP completion, DH, 2x Pump, Upper & lower seals, Motor, DHG, Cent. Discharged head packed off w/ scale. Remove ESP equipment F/ rig floor. Change handling equip. Clean & clear floor. Inspect floor equipment. Prep to P/U BHA. Continue POOH w/ 2-7/8 EUE and ESP completion from F/ 8,725' T/ 6,113' Continue POOH w/ 2-7/8 EUE and ESP completion F/ 2,970' T/ 82 '. L/D ESP completion, DH, 2x Pump, Upper & lower seals, Motor, DHG, Cent. Continue POOH w/ 2-7/8 EUE and ESP completion F/ 6,113' T/ 2,970'. Drive sub shows internal indication of contact with tubing stub Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR 50-029-22786 197-128 4/25/2023 5/16/2023 Hilcorp Alaska, LLC Weekly Operations Summary Continue M/U PKR mill Assy. as follows. 5-3/4" PKR mill, 6X washpipe, drive sub, double pin, 2X boot basket, bit sub, bumper sub, oil jar, DC. RIH w 3-1/2" workstring and PKR milling BHA F/ 417' T/ 10,946'. RIH w 3-1/2" workstring and PKR milling BHA F/ 10,946' T/ 12,107'. Kelly up & obtain parameters prior to milling & washover. Pump at 3.5 BPM w/ 650 psi, ROT 65 RPM 3.5K TQ. P/U wt =93K S/O wt = 47K. Free ROT wt= 64K. Adjust kelly clamp. Wash & ream over tubing stub, F/ 12,107' T/ 12,271' w/ 3.5 BPM w/ 680psi. ROT @ 60 RPM, 4k ft/lbs TQ. Set 8k on PKR. P/U WT = 93K, S/O wt = 61K. Begin milling. Mill PKR F/ 12,271' mill PKR w/ varying pump rates F/ 6.5 BPM 890 PSI. T/ 1 BPM w/ 200 PSI. Milling w/ 5K T/ 10K dw on PKR. Current depth T/ 12,272'. Trouble shoot with I-rig electrician and mechanic. Found a relay in the rig PLC that had intermittent failure. Changed out relay. and rig was working properly. Rig service. Clean up areas and prep to POOH. POOH from 12,160' to 9,800'. bolts on top of elevators sheared. Swap elevators to slip type. Cont. POOH W/ 3-1/2" workstring and mechanical outside cutter F/ 9,800' T/ 6,812'. Cont. POOH W/ 3-1/2" workstring and mechanical outside cutter F/ 6,812' T/ 406'. L/D mechanical outside cutter BHA, Intensifier, 6x DC, oil jar, bumper sub, drive sub. FISH ON. L/D wash pipe & internal 3-1/2" tubing fish. 176' of tubing recovered. L/D. 6x washpipe & outside cutter. M/U PKR mill Assy. as follows. 5-3/4" PKR mill, 6X washpipe, drive sub, double pin, 2X boot basket, bit sub, bumper sub, oil jar, DC. 5/2/2023 - Tuesday 4/30/2023 - Sunday Cont. RIH w/ mechanical outside cutter on 3-1/2" workstring F/ 2,205' to 9,414' P/U wt = 55K S/O wt = 29K. Service Rig. Cont. RIH w/ mechanical outside cutter on 3-1/2" workstring F/ 9,414' to 11,976' P/U wt = 93K S/O wt = 43K. Kelly up & line up to pump for milling ops. At 11,896' ROT 60 RPM, free ROT TQ = 4K ft-lbs ROT wt = 67K. Pump at 2 BPM w/ 450 PSI. Wash down to tag out on drive sub at 1 BPM w/ 160 psi. Tag at 12,180'. P/U to catch collar in mechanical cutter. P/U wt = 67K. P/U t/ 12,160' Pull in tension 5K over 2x to confirm catch. Begin tubing cutting ops. ROT at 60 RPM w/ initial 4 K TQ. w/ 72K P/U WT total, = 5K over, pump at 1 BPM w/ 160 psi. After 3 mins observed string wt decrease to 65K & 3.5K TQ. P/U 2" increments. P/U wt never returning to 73K. New P/U wt = 65K while ROT. After 1.5' stop ROT & P/U string. New Non-ROT P/U wt = 95K. 2K over initial. Rig down kelly hose, B/D pump lines & L/D 1 JT. Change tong back up ram. Trouble shoot carriage issue, possible encoder / electrical failure. Service Rig. Trouble shoot carriage issue, possible encoder / electrical issue. 5/1/2023 - Monday Begin tubing cutting ops 176' of tubing recovered Cont. RIH w/ mechanical outside cutter on 3-1/2" workstring M/U PKR mill Assy. as Begin milling. Mill PKR F/ 12,271' mill PKR w/ varying pump rates F/ 6.5 BPM 890 PSI. T/ 1 BPM w/ 200 PSI. Milling w/ 5K T/ 10K dw on PKR. Current depth T/ 12,272'. Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR 50-029-22786 197-128 4/25/2023 5/16/2023 5/5/2023 - Friday RIH w 3-1/2" workstring & PKR milling BHA F/ 11,813' T/ 12,133'. Obtain milling parameters. 60 RPM w/ 3.5K ft-lbs TQ, P/U wt = 93K, ROT wt = 60K , S/O wt w/ ROT= 57K. Ream over tubing stub & past collars to PKR at 12,272'. Mill PKR F/ 12,272' mill PKR w/ varying pump rates F/ 5.3 BPM 890 PSI. T/ 1 BPM w/ 200 PSI. Milling w/ 5K T/ 40K dw on PKR. AT 60 & 80 RPM, TQ F/ 5.5K ft-lbs T/ 2.5 ft-lbs. Current depth T/ 12,272'. Mill PKR F/ 12,272' mill PKR w/ varying pump rates F/ 2 BPM 280 PSI. Milling w/ 40K dw on PKR. AT 60 RPM, TQ F/ 5K ft-lbs T/ 3.5 ft-lbs. Current depth T/ 12,272'. Pump sweep, sweep on time, no increase in metal cuttings. Pull working JT & B/D lines & prep to POOH. POOH with 3-1/2" workstring and milling BHA F/ 12,254' T/ 7,849' Pump single displacement for hole fill. Rig service. POOH with 3-1/2" workstring and milling BHA F/ 7,849' T/ 2,565' Pump single displacement for hole fill. 5/3/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Mill PKR F/ 12,271' mill PKR w/ varying pump rates F/ 5.25 BPM 890 PSI. T/ 1 BPM w/ 200 PSI. Milling w/ 5K T/ 10K dw on PKR. Current depth T/ 12,271.5'. POOH with 3-1/2" workstring and PKR milling BHA F/ 12,273' T/ 2,219' Pump single displacement for hole fill. POOH with 3-1/2" workstring and PKR milling BHA F/ 2,219' T/ 417' Pump single displacement for hole fill. L/D BHA PKR milling BHA, 6X DC, oil jar, bumper sub, bit sub, 2X boot basket, drive sub, 6X wash pipe, 5-3/4" PKR mill. No excess wear on mill. Mill shows minimal "work". Test BOPE as per approved sundry, AOGCC waived witness. All test performed to 250 psi low & 3500 psi high F/ 5/5 charted mins. Found K6 leaking & K2. Changed valves. Simops. Clear & clear floor from fishing & mill job. Currently on test # 4. 5/4/2023 - Thursday Test BOPE as per approved sundry, AOGCC waived witness. All test performed to 250 psi low & 3500 psi high F/ 5/5 charted mins. Perform accumulator drawdown test. B/D test lines. Changed out wash pipe packing & pressure test swivel. Good test. Perform function test. Rig service. Rig down testing equipment f/ floor. Clean & clear floor. P/U BHA handling Equip. Hold PJSM. M/U PKR mill Assy. as follows. 6.125" PKR mill, 4X washpipe, drive sub, double pin, 2X boot basket, bit sub, bumper sub, oil jar. RIH w 3-1/2" workstring & PKR milling BHA F/ 163' T/ 1,364'. RIH w 3-1/2" workstring & PKR milling BHA F/ 1,634' T/ 7,569'. Rig service. Check all equipment oil levels. RIH w 3-1/2" workstring & PKR milling BHA F/ 7,569' T/ 9,489'. Repair shear tong make break pin. RIH w 3-1/2" workstring & PKR milling BHA F/ 9489' T/ 11,813'. POOH with 3-1/2" workstring and milling BHA F/ 2,565' T/ 146' Pump single displacement for hole fill. L/D BHA PKR milling BHA. oil jar, bumper sub, bit sub, 2X boot basket, drive sub, 4X wash pipe, 6.125" PKR burn shoe. Mill shows minimal wear. Boot baskets contain a small amount of shards of metal. Rack & tally new BHA in shed replace damaged wash pipe. simops. perform maintenance on rig, grease rack, change swab & liner. Serivce rig, preform equip. oil checks. Clean & clear floor. P/U & M/U outside mechanical cutter BHA as per fishing rep. BHA includes. outside cutter assy. , 5x joints of wash pipe, drive sub, bumper sub, hyd. oil jars, 3x drill collars. RIH w/ outside mechanical cutter BHA on 3-1/2 workstring F/ 270' T/ 5,473' P/U wt = 35K S/O wt = 23K. Monitor displacement via return tank. Serivce rig, preform equip. oil checks. RIH w/ outside mechanical cutter BHA on 3-1/2 workstring F/ 5,473' T/ 10,477' P/U wt = 63 K S/O wt = 33 K. Monitor displacement via return tank. 5/6/2023 - Saturday Mill PKR F/ 12,272' mill PKR w/ varying pump rates RIH w 3-1/2" workstring & PKR milling BHA F/ 163' T/ 1,364'. RIH w 3-1/2" workstring & PKR milling BHA F/ 1,634' T/ 7,569'. Rig service. Check all equipment oil levels. RIH w 3-1/2" workstring & PKR milling BHA F/ 7,569' T/ 9,489'. Repair shear tong make break pin. RIH w 3-1/2" workstring & PKR milling BHA F/ 9489' T/ 11,813'. Mill PKR F/ 12,271' mill PKR w/ varying pump rates F/ 5.25 BPM 890 PSI. T/ 1 BPM w/ 200 PSI. Milling w/ 5K T/ 10K dw on PKR. Current depth T/ 12,271.5'. POOH Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR 50-029-22786 197-128 4/25/2023 5/16/2023 Hilcorp Alaska, LLC Weekly Operations Summary Mill PKR F/ 12,276' mill PKR w/ varying pump rates F/ 3 BPM 645 PSI T/ 1 BPM w/ 200 PSI. Milling w/ 5 - 20K dw on PKR W/ 3- 5k TQ. Milling depth remains 12,276'. L/D 2x JTs. F/ 12,276' T/ 12,200' B/D kelly hose. Service Rig, Fluid checks & replace tong hose. POOH with 3-1/2" workstring and PKR milling BHA F/ 12,200' T/ 7,636' Pump single displacement for hole fill. POOH with 3-1/2" workstring and PKR milling BHA F/ 7,636' T/ 428' Pump single displacement for hole fill. Service rig, perform equip. oil checks. L/D 12x DC & milling BHA as per fishing rep. Mill showing slight wear on face & broken inserts on ID. Clean & clear floor. M/U RBP & running tool as per fishing rep. Clean & clear floor. Remove BHA components f/ rig floor. Perform Derrick inspection after jarring ops. NO issues found. While awaiting milling tools to arrive, Perform oil change on 300k gen set. M/U PKR mill Assy. as follows. 6.125" burn shoe, 1 washpipe extension, drive sub, double pin, 2X boot basket, bit sub, bumper sub, oil jar, 12x DC, intensifier. Replace worn hoses on tongs & wearable items. i.e. brake bands & tensioner. RIH w/ PKR mill assy. on 3-1/2" workstring F/ 470' T/ 9,477' P/U wt =61 K S/O wt = 35 K. Monitor displacement via return tank. Service rig, perform equip. oil checks. RIH w/ PKR mill assy. on 3-1/2" workstring F/ 9,477' T/ 12,241' P/U wt = 95K S/O wt = 52K. Monitor displacement via return tank. Lost 32 bbls total for the trip. Kelly up to JT. Trip in F/ 12,241' & tag at 12,276'. Set 8k dw on PKR. Did not see any S/O wt change swallowing over tubing. P/U off PKR & Begin milling. Mill PKR F/ 12,276' mill PKR w/ varying pump rates F/ 3 BPM 645 PSI T/ 1 BPM w/ 200 PSI. Milling w/ 5K dw on PKR. 5/9/2023 - Tuesday 5/7/2023 - Sunday RIH w/ outside mechanical cutter BHA on 3-1/2" workstring F/ 10,477' T/ 12,239' P/U wt = 66 K S/O wt = 45 K. Monitor displacement via return tank. Wash down w/ 1 BPM w/ 120 psi. S/O to 12,268'. P/U to catch collar in mechanical cutter. P/U wt = 86 K. P/U t/ 12,257' Pull in tension 5K over 2x to confirm collar catch. Begin tubing cutting ops. ROT at 65 RPM w/ initial 2.5 K TQ. w/ 62K ROT wt, 64. P/U 1/10th ft increments. P/U wt = 65K ROT TQ = 4k. After 8' stop ROT & P/U string. ROT P/U wt = 95K. Pull into collar, 120K, for 35 k over, pull allow jars to hit in slips. Con't. to jar 6x. Pipe becoming free. Cont. POOH W/ 3- 1/2" workstring and mechanical outside cutter F/ 12,257' T/ 270'. L/D mechanical outside cutter BHA. 3x DC, oil jar, bumper sub, drive sub. at wash pipe observed, FISH ON. L/D wash pipe & internal 3-1/2" tubing fish. 95.44' of tubing recovered. L/D. 5x washpipe & outside cutter. Clean & clear floor. 5/8/2023 - Monday Mill PKR F/ 12,276' mill PKR w/ varying pump rates Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR 50-029-22786 197-128 4/25/2023 5/16/2023 5/12/2023 - Friday Attempt to pull 11 x 7" tubing spool pulling up to 50K with no success;Continue to cut remaining tubing spool studs;Work stack and tubing spool up to 60K and drive wedges in-between flange, until tubing spool free;hammer out cut studs from 11" flange, clean ring grove and replace neck seals. Install 11 x 11" tubing spool. Test pack-off to 5000 psi for 10 min.;N/U BOP's, Riser, flow line, bird bath, replaced outer kill line valve. and install choke and kill lines;Function test BOP rams;Set test plug and R/U test equipment, fill stack and preform shell test.;Test BOP's to 250 low/ 3500 high for 5 min each. 3 1/2" and 4 1/2" test jts. used. Perform Koomey draw down test;R/D test equipment, pull test plug and center stack;M/U storm packer retrieval tool on single jt. Engage/ release storm packer and L/D same. 5/10/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary M/U 7" RBP and RIH to 4,102'. Service rig and check fluids. Continue to RIH f/ 4,102' to 12,070'. R/U power swivel and attempt to set RPB with out success. P/U single and set RBP @ 12,117', Release from RBP and test 7" casing to 3,600 psi for 30min. (good test). L/D 3 jts and 10' pup jt., M/U storm packer, RIH with 1 jt. and set storm packer below wellhead. test to 1500psi for 10 min. Remove bails from swivel, N/D bird bath, riser, flowline, disconnect koomey lines and N/D BOP's. 5/11/2023 - Thursday Cont. to N/D BOP's and break nuts from 7 x 11" tubing spool;Made several attempts to pull tubing spool with no success, R/U bottle jacks and hammer in wedges while pulling 10-15K over BOP wt. with no success;Cut Tubing spool studs with Sawzall. WELLHEAD: BOP stack pulled, clean tbg hgr void, install SBMS metal neck seal and RX54 gasket. Land 4 1/16" tree/adapter, torque to spec and test 500/5000 (PASS). Pull bpv, instal tree cap w/ manifold, dunp SSV valves closed except MV. P/U 3 jts. and engage RBP. release same and monitor well fo 30 min.;POOH from 12,095' to 9,011';Service rig and check fluid levels;POOH from 9,011' to surface;L/D RBP assembly;Clean and clear rig floor;Change out handling equipment, rack and tally 4 1/2" completion tubing, prep jewelry to run completion;Service and check fluid levels;P/U 4 1/2" completion assembly and RIH hole. 5/13/2023 - Saturday WELLHEAD: MU tbg hgr to 4 1/2" TC11 LJ, five ft into profile RKB 18.80' RILDS. RIG pump and drop ball/rod and test. Set 4" bpv 5/16/2023 - Tuesday 5/14/2023 - Sunday RIH with 4 1/2" l-80 completion to 5,895';Service rig and check fluid levels;Cont. to RIH with 4 1/2" l-80 completion f/ 5,895' to 12,118';M/U tubing hanger and land out completion. up wt 100k, dw wt 53K, EOT @ 12,135.65' RILDS;Pump 25 bbls of 11.1 inhibited brine followed by 180 bbls of 11.1 brine. 3.5 BPM/525 psi;Drop ball and rod, R/U to and set packer, test tubing to 3800 psi for 30 min. Bleed of tubing to 1000 psi and test IA to 3600 psi for 30 min.;L/D landing jt, Set back pressure valve and secure well. Rig released at 06:00 hrs. 5/15/2023 - Monday RIH with 4 1/2" l-80 completion to 5,895';Service rig and check fluid levels;Cont. to RIH with 4 1/2" l-80 completion f/ 5,895' to 12,118';M/U tubing hanger and land out completion. Drop ball and rod, R/U to and set packer, test tubing to 3800 psi for 30 min. Bleed of tubing to 1000 psi and test IA to 3600 psi for 30 min.;L/D landing jt, Set back pressure valve and secure well. Rig released at 06:00 hrs. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:Tom Fouts Cc:AOGCC Records (CED sponsored) Subject:20230531 1635 APPROVAL PTD197-128 combined 10-404 MP L-39 10-404 Filing Request Date:Wednesday, May 31, 2023 4:36:54 PM Tom, Hilcorp is approved to submit a single 10-404 for sundry # 323-198 and sundry # 323-249. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Tom Fouts <tfouts@hilcorp.com> Sent: Wednesday, May 31, 2023 3:28 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Scott Pessetto <Scott.Pessetto@hilcorp.com> Subject: MP L-39 10-404 Filing Request Mel, I would like to request your approval to file a single 10-404 for MP L-39 sundry #’s 323-198 original submittal & 323-249 change of approved program submittal. Please let me know if you have any questions. Regards, Tom Fouts | Senior Ops/ Reg Tech Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907) 777-8398 Mobile: (907) 351-5749 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:FW: PTD197-128 MPU L-39, Sundry 323-198 - BOPE test to 3500 psi and add additional ram Date:Monday, April 24, 2023 10:41:34 AM From: Rixse, Melvin G (OGC) Sent: Monday, April 24, 2023 10:33 AM To: Scott Pessetto <scott.pessetto@hilcorp.com> Cc: DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Subject: PTD197-128 MPU L-39, Sundry 323-198 - BOPE test to 3500 psi and add additional ram Scott, AOGCC approves Hilcorp changes to Sundry 323-198 work plan as describe below. Hilcorp is now required to add a 3rd ram to the BOPE stack and test to 3500 psi. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. AOGCC Inspec From: Scott Pessetto <scott.pessetto@hilcorp.com> Sent: Monday, April 24, 2023 9:59 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] PTD197-129 Hi Mel, Regarding MPL-39 - PTD #197-128 - Sundry# 323-198. On Friday April 21 an updated SBHP was obtained. Reservoir pressure at the perforations was calculated to be 3,672 psi (10ppge) at 7,062’ TVD 10.2 kill weight brine was used to kill the well CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. After circulating the kill 220 psi remained on the annulus and tubing. 220 psi over 7,062’ TVD gives a 0.6 ppg deficit. Hilcorp plans to: Circulate ~11ppg fluid to ensure the well is dead Use 3,892 psi as the new reservoir pressure giving a MPSP of 3,185 psi. Due to the MPSP over 3,000 psi, a third ram will be added to the stack, and we plan to test all rams to 3,500 psi. I tried listening to your voicemail but the message was mostly garbled. Please let me know if you need any other information. Scott Scott Pessetto | Milne Point | Operations Engineer | Hilcorp Alaska Office: 907-564-4373 | Cell: 801-822-2203 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, April 24, 2023 9:28 AM To: Scott Pessetto <scott.pessetto@hilcorp.com> Subject: [EXTERNAL] PTD197-129 Scott, Send me an email so I can approve what you described on the phone. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. 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: Complete well 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,740'N/A Casing Collapse Conductor N/A Surface 3,090psi Intermediate 5,410psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Operations Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 9-5/8" 7" 8,613' 12,684' Perforation Depth MD (ft): MD N/A 5,750psi 7,240psi 4,165' 7,380' 8,649' 12,717' Length Size Proposed Pools: 114' 114' TVD Burst PRESENT WELL CONDITION SUMMARY 7,401' 12,634' 7,305' 2,903 N/A 80' 20" MILNE POINT STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025514 197-128 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22786-00-00 Hilcorp Alaska LLC KUPARUK RIVER OIL N/A C.O. 432E MILNE PT UNIT L-39 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 6.5 / L-80 / EUE Mod 8rd 11,261 4/21/2023 TriPoint ESP Pkr, 3.5" Permapac & 3.5" Baker SB-3 and N/A 2,503 MD/ 2,338 TVD, 12,227 MD/ 6,943 TVD & 12,296 MD/ 7,004 TVD and N/A See Schematic See Schematic 2-7/8" 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY scott.pessetto@hilcorp.com 907-564-4373 Scott Pessetto Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 323-249 By Kayla Junke at 2:54 pm, Apr 21, 2023 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2023.04.21 14:01:06 -08'00' David Haakinson (3533) MGR22MAY23 ADL0025509, ADL0025515, BOPE pressure test to 3000 psi. Annular to 2500 psi. Apr 21, 2023 4/21/2023 10-404 7390' SFD 4/24/2023 DSR-4/26/23 2,903 SFD GCW 05/23/23JLC 5/23/2023 05/23/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.23 22:14:54 -05'00' RBDMS JSB 052523 Well: MPL-39 PTD: 197-128 API: 50-029-22786-00-00 Well Name:MPL-39 API Number:50-029-22786-00-00 Current Status:Shut-in Producer Rig:ASR Estimated Start Date:4/21/2023 Estimated Duration:9 days Regulatory Contact:Tom Fouts Permit to Drill Number:197-128 First Call Engineer:Scott Pessetto (907) 564-4373 (O) (801) 822-2203 (M) Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Current Bottom Hole Pressure: 3,577 psi @ 6,735’ TVD SBHP 10/26/16 |10.2 PPGE Maximum Expected BHP:3,577 psi Max Potential Surface Pressure: 2,903 psi Gas Column Gradient (0.1 psi/ft) Max Angle:79° @ 5,850’ MD Brief Well Summary: Well MPL-39 is slant producer completed in the Kuparuk A-sand. Well MPL-39 has gone through several completion iterations (injector, jet pump, ESP) over the years. Currently MPL-39 is shut-in due to a grounded ESP (2017). A CTD sidetrack out of MPL-39 is planned to improve the economic viability of MPL-39. Objectives: 1. Pull failed ESP completion. 2. Mill and push packer to bottom 3. Run tubing and a production packer setting up the well for a CTD sidetrack. Notes Regarding Wellbore Condition: x Tripoint ESP packer at 2,503’ MD. Packer expected to release at ~92,000 lbf. x IA tested to ESP packer at 2,000 psi on 2/17/17 Pre-Rig Procedure (Non-Sundried Work) Slickline 1. MIRU SL, PT PCE to 250 psi low / 2,500 psi high 2. RIH to 11,076' MD (5,926' TVD) or deep as possible for 30 minute station stop 3. Pull up hole 200' TVD (10,843' MD) for 15 minute gradient stop. 4. Confirm good data. 5. Run memory caliper as deep as possible. 6. RDMO. Pumping & Well Support 1. Bleed OA to 0 psi prior to ASR moving onto well. 2. Clear and level pad area in front of well. Spot rig mats and containment. 3. RD well house and flowlines. Clear and level area around well. 4. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 5. Pressure test lines to 3,000 psi. 6. Circulate at least one wellbore volume with 10.4 ppg brine down tubing, taking returns up casing to 500 barrel returns tank. 7. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 8. RD Little Red Services and reverse out skid. 10.2 PPGE Well: MPL-39 PTD: 197-128 API: 50-029-22786-00-00 9. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Approved Sundry Required) 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 bbl returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with 10.4 ppg brine prior to setting CTS. 3. Test BOPE to 250 psi low/ 3,000 psi high. Test annular to 250 psi low/ 2,500 psi high (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on 2-7/8”, 3-1/2”, and 4-1/2” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with produced water as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Centrilift for ESP pull. 6. RU spooler(s) to handle ESP cable and packer control line. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. ESP packer set at 2,503’ MD. Packer pinned to release at 27,000 lbf. b. String weight noted as 65,000 lbf prior to landing hanger. SO recorded as 28,000 lbf. c. Expected PU to release packer ~92,000 lbf. 8. Confirm hanger free, lay down tubing hanger. a. Wait 30 minutes after releasing packer to allow packer elements to relax. 9. POOH and lay down the 2-7/8” tubing. Number all joints. a. Pre-rig caliper to inform on whether to keep 2-7/8” tubing. b. Keep ported discharge head and centralizer for future use. c. Note any sand or scale inside or on the outside of the ESP on the morning report. d. Continue to monitor hole fill while pulling ESP. e. Clamp placement. i. Cross collar clamps: 741 ii. Pump Clamps: 8 iii. Protectolizers: 5 iv. Flat Guards: 2 10. Lay Down ESP. 11. PU burn over shoe and sufficient wash pipe to swallow the 90’ tubing stub to mill and push the SB- 3 packer located at 12,296’ MD to bottom. a. Milling BHA to be finalized with fishing company and OE. b. Target depth to push top of fish down to is 12,450’ MD. Well: MPL-39 PTD: 197-128 API: 50-029-22786-00-00 c. If the top of fish cannot be pushed below 12,400’ to allow for whipstock setting, proceed to outside cut of the tubing stub. 12. RIH with burn over shoe on 3-1/2” workstring. 13. Before swallowing tubing stub, establish milling parameters. a. Build high viscosity fluid to carry cuttings out of the well. b. Maintain sufficient pump rate to prevent depositing debris on top of wash pipe. 14. Mill Baker SB-3 and push top of fish to 12,450’ MD. 15. POOH with fishing assembly while filling hole with 2x pipe displacement. 16. RIH with 7” RBP to 12,070’ MD. Set RBP. 17. Test casing to 3,600 psi. 18. POOH 3 joints and pick up RTTS storm packer. 19. RIH one joint and set RTTS storm packer. 20. Test storm packer to 3,000 psi. 21. Confirm casing packoffs have been tested and OA pressure bled off. 22. Remove 7 x 11 spool and install 11 x 11 spool. 23. Test packoff (this will test casing spool by new tubing spool break) 24. Test BOPs with upper test plug 25. Release RTTS storm packer and pull storm packer out of hole. 26. RIH and engage RBP. 27. POOH with RBP, while filling hole with 2x pipe displacement. 28. RIH with new 4-1/2”, 12.6# L-80 completion to +/- 12,170’ and obtain string weights. a. Note PU and SO weights on tally. b. Photograph packer prior to running. Colors indicate assemblies to be bucked up prior to RWO. Nom. Size ~Length Item Lb/ft Material Notes 4-1/2” WLEG L-80 Place at ±12,170’ md. CTD planned TOWS ~12,295’ MD. 4.5''2 Joints 12.6 L-80 4.5''10'Pup Joint 12.6 L-80 4.5''X Nipple 12.6 L-80 RHC Profile Installed 4.5''10'Pup Joint 12.6 L-80 4.5'' 1 joint 12.6 L-80 4.5''10'Pup Joint 12.6 L-80 7'' 7” x 4-1/2” Packer 12.6 L-80 Packer set ±12,050' MD 4.5''10'Pup Joint 12.6 L-80 4.5'' 1 joint 12.6 L-80 Well: MPL-39 PTD: 197-128 API: 50-029-22786-00-00 4.5''10'Pup Joint 12.6 L-80 4.5''3.813” X Sliding Sleeve 12.6 L-80 4.5''10'Pup Joint 12.6 L-80 4.5''Joints 12.6 L-80 4.5''Space out PUPS 12.6 L-80 4.5'' 1 joint 12.6 L-80 4.5''Tubing Hanger 12.6 L-80 29. Space out and land hanger. RILDS. 30. Spot Corrosion inhibited brine in the sump between the packer and the sliding sleeve. a. Surface to sliding sleeve Annulus Volume: 221 bbls b. Sliding Sleeve to Packer Annulus Volume: 1.2 bbls c. Surface to 2,100’ for Freeze Protect Annulus Volume: 39 bbls 31. Drop ball and rod. Complete loading FP and hydraulically set the packer per the manufacturer's setting procedure. 32. Pressure up and test the tubing to 3,000 psi for MIT-T with positive pressure on the IA. Bleed off the tubing to 1,000psi. Test the IA to 3,600 psi for MIT-IA. Record all pressure tests (30 minutes) on chart. 33. Lay down landing joint. 34. Set BPV. 35. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. 4. RD crane. Move 500 bbl returns tank and rig mats to next well location. 5. RU well house and flowlines. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic 4. Pre-Workover Wellhead Diagram 5. Post Workover Wellhead Diagram _____________________________________________________________________________________ Revised By: TDF 12/8/2021 SCHEMATIC Milne Point Unit Well: MPU L-39 Last Completed: 2/7/2017 PTD: 197-128 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 114' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’ 7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’ TUBING DETAIL 2-7/8” Tubing 6.4/L-80/EUE 8rd 2.441 Surface 11,261’ JEWELRY DETAIL No Depth Item 1141’GLM STA# 4:2-7/8” x 1” GLM w/ SO 3-5-17 22,441’GLM STA# 3: 2-7/8” x 1” GLM w/ DGLV 32,503’TriPoint ESP Packer w/ WFD Annular Vent Valve 4 2,524’ 2-7/8” X profile (2.313” Packing Bore) 52,576’GLM STA# 2: 2-7/8” x 1” GLM w/ DGLV 6 11,027’GLM STA# 1: 2-7/8” x 1” GLM w/EMPTY POCKET 10-23-17 7 11,137’ 2-7/8” XN-Nipple (2.205” No-Go) 8 11,178.5 Discharge Head 9 11,179.0’ Pump 134 Flex 17.5 Model SXD-H6 10 11,203’ Pump 134 Flex 17.5 Model SXD-H6 11 11,226’ Gas Separator GRS FER N AR 12 11,229’ Upper Tandem Seal GSB3DBUT SB/SB PFSA 13 11,236’ Lower Tandem Seal GSB3DBUT SB/SB PFSA 14 11,243’ Motor CL5 XP-200 3635V/34A 15 11,257’ Phoenix XT-150 Sensor w/ Centralizer Bottom: 11,261’ 16 12,205’ 3-1/2” Cut Joint 17 12,227’ 3.5” Permapac Packer 18 12,250’ 3.5” HES X Nipple (2.813” ID) 19 12,296’ 3.5” Baker SB-3 Packer 20 12,320’ 3.5” HES XN Nipple (No Go 2.750” ID) 21 12,332’ 3.5” Otis WLEG PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. A2 &A3 12,362’ 12,402’ 7,062’ 7,098’ 40 6/27/1998 Open OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24” Hole 9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole 7” 275 sks Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 300’ to 4,500’ Max Hole Angle = 78 deg. Max Hole Angle through perforations = 27 deg. TREE & WELLHEAD Tree 5M Cameron 2-9/16” Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile GENERAL WELL INFO API: 50-029-22786-00-00 Drilled and Cased by Nabors 27E - 6/29/1997 3.5” Injection Completion by Nabors 27E – 7/1/1998 Conversion to Jet Pump – 10/16/2014 Convert to Producer – 4/23/2015 Install Kill String by ASR#1 – 11/24/2016 Run ESP Doyon 14 – 2/7/2017 STIMULATION SUMMARY Kuparuk “A” Sand: 59,000# of 20/40 Carbo Bond frac proppant behind pipe. TD = 12,740’ (MD) / TD = 7,401’(TVD) 20” Orig. KB Elev.: 34.3’ 7” 5 15 19 2 16 18 4 20 17 9-5/8” 1 7 8-14 21 3 6 PBTD = 12,634’ (MD) / PBTD = 7,305’(TVD) Holes Shot 9/28/08 12,246.5’ to 12,248.5’ ELM. Set Owen Oil Tools X-Span 2.715” x 24” Patch @ 12,233.5’ to 12,256.1’, Min ID = 2.25” – 9/12/2014 _____________________________________________________________________________________ Revised By: TDF 4/2/2023 PROPOSED Milne Point Unit Well: MPU L-39 Last Completed: 2/7/2017 PTD: 197-128 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 114' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’ 7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’ TUBING DETAIL 4-1/2” Tubing 12.6/L-80/TXP 3.958 Surface ±12,170’ JEWELRY DETAIL No Depth Item 1 ±12,000’ 3.813” X Sliding Sleeve 2 ±12,050’ 7” x 4-1/2” Packer 3 ±12,160’ 3.813” X Nipple 4 ±12,168’ Wireline entry guide – Btm @ ±12,170’ 5 ±12,450’3.5” Baker SB-3 Packer 6 ±12,474’3.5” HES NX Nipple 7 ±12.486’3.5” Otis WLEG PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. A2 &A3 12,362’ 12,402’ 7,062’ 7,098’ 40 6/27/1998 Open OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24” Hole 9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole 7” 275 sks Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 300’ to 4,500’ Max Hole Angle = 78 deg. Max Hole Angle through perforations = 27 deg. TREE & WELLHEAD Tree 5M Cameron 2-9/16” Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile GENERAL WELL INFO API: 50-029-22786-00-00 Drilled and Cased by Nabors 27E - 6/29/1997 3.5” Injection Completion by Nabors 27E – 7/1/1998 Conversion to Jet Pump – 10/16/2014 Convert to Producer – 4/23/2015 Install Kill String by ASR#1 – 11/24/2016 Run ESP Doyon 14 – 2/7/2017 STIMULATION SUMMARY Kuparuk “A” Sand: 59,000# of 20/40 Carbo Bond frac proppant behind pipe. TD =12,740’ (MD) / TD = 7,401’(TVD) 20” Orig. KB Elev.: 34.3’ 7” 2 4 9-5/8” 1 5 3 PBTD = 12,634’ (MD) / PBTD = 7,305’(TVD) 6 7 Updated 8/11/2020 Milne Point ASR Rig 1 BOPE 2023 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30'Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR 4.17.2023 323-229 By Kayla Junke at 4:17 pm, Apr 17, 2023 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2023.04.17 12:44:56 -08'00' Monty M Myers 10-407 24 hour notice for AOGCC to witness BOPE test to 3500 psi. MDG 4/28/2023 DSR-4/17/23 Variance to 20 AAC 25.112(i) Alternate plug placement approved for liner cement to provide isolation to parent wellbore abandonment. MGR22MAY23GCW 05/23/23JLC 5/23/2023 05/23/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.23 16:46:47 -05'00' RBDMS JSB 052423 To: Alaska Oil & Gas Conservation Commission From: Trevor Hyatt Drilling Engineer Date: April 17, 2023 Re: MPU L-39 Sundry Request Sundry approval is requested to set a whipstock and mill a window in MPU L-39, as part of the pre-rig for drilling and completing of the proposed MPU L-39A CTD lateral. Proposed plan for MPU L-39A Producer: Prior to drilling activities, a RWO will be conducted to swap to 4-1/2" tubing and mill the lower completion packer and push to bottom. Screening will be conducted to MIT and drift for whipstock. E-line will then set a 4-1/2"x7" flow through whipstock (rig will set if needed). Service Coil will mill the window (rig will mill if needed). See MPU L-39A PTD request for complete drilling details - A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the well. If unable to set or mill pre-rig, the rig will set a 4-1/2"x7" flow through whipstock and mill a single string 3.80" window + 10' of formation. The well will kick off drilling and land in the Kuparuk. The lateral will continue in the Kuparuk to TD. The proposed sidetrack will be completed with a 3-1/2"x3-1/4"x2-7/8” L-80 solid liner and cemented. This completion WILL abandon the parent Kuparuk perfs. The well will be perforated post rig (see future perf sundry). This Sundry covers plugging the existing Kuparuk perforations via the liner cement job or liner top packer, if the liner lap pressure test fails (alternate plug placement per 20 AAC 25.112(i)). Pre-Rig Work - (Estimated to start end of May 2023): 1. RWO: Tubing Swap and MIT-T 3,500 psi (see preceding RWO sundry) 2. Slickline: Dummy WS drift a. Drift past whipstock setting location 3. E-line: Set 4-1/2”x7” whipstock a. Top of whipstock set at 12,295’ MD b. Oriented at 0° ROHS c. Top of window (whipstock pinch point 2’ down from top) at 12,297’ MD 4. Service Coil: Mill Window a. Mill Window I. MIRU Service Coil Window Milling Surface Kit II. Give AOGCC 24hr notice prior to BOPE test III. Test BOPE to 3500 psi. MASP with gas (0.10 psi/ft) to surface is 3,100 psi IV. Mill 3.80” window plus 10’ of rat hole V. Single string window exit out of 7” liner 5. Valve Shop: Pre-CTD Tree Work as necessary Rig Work: x Reference MPU L-39A PTD submitted in concert with this request for full details. x General work scope of Rig work: 1. MIRU and Test BOPE - MASP with gas (0.10 psi/ft) to surface is 3,100 psi a. Give AOGCC 24hr notice prior to BOPE test 2. Set Whipstock (only if not done pre-rig) 3. Mill Window (only if not done pre-rig) 4. Drill Build and Lateral 5. Run and Cement Liner* 6. Perforate (only if not done post-rig) 7. Freeze Protect and RDMO 8. Perforate post rig and set LTP* (if needed) * Approved alternate plug placement per 20 AAC 25.112(i) PTD Sundry 323-229 The sundry and permit to drill will be posted in the Operations Cabin of the unit during the window milling operation. Window Milling Fluids Program: x A min EMW of 8.4 ppg KCL. KCl will be used as the primary working fluid and viscous gel sweeps will be used as necessary to keep the hole clean. x The well will be freeze protected with a non-freezable fluid (typically a 60/40 methanol/water mixture) prior to service coil’s departure. x Additionally, all BHA’s will be lubricated and there is no plan to “open hole” a BHA. Disposal: x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4. x Fluids >1% hydrocarbons or flammables must go to GNI. x Fluids >15% solids by volume must go to GNI. Hole Size: x The window and 10’ of formation will be milled/drilled with a 3.80” OD mill. Well Control: x BOP diagram is attached. x AOGCC will be given at least 24-hour notice prior to performing a BOPE function pressure test so that a representative of the commission can witness the test. x Pipe rams, blind rams, CT pack off, and choke manifold will be pressure tested to 250 psi and at least 3,500 psi. x BOPE test results will be recorded in our daily reporting system (Alaska Wells Group Reporting System) and will provide the results to the commission in an approved format within five days of test completion. x BOPE tests will be performed upon arrival (prior to first entry into the well) and at 7 days intervals thereafter. x 10 AAC 25.036 c.4.C requires that a BOPE assembly must include “a firewall to shield accumulators and primary controls”. A variance is requested based on the result of the joint hazop with the AOGCC. For our operation, the primary controls for the BOPE are located in the Operations Cabin of the Coiled Tubing Unit, and the accumulators are located on the backside of the Operations Cabin (opposite side from the well). These are approximately 70' from the well. Hazards: x MPU L-pad is an H2S pad. o The highest recorded H2S well on the pad was from L-32 (410 ppm) in 2009. o No recorded H2S on L-39. Reservoir Pressure: x The estimated reservoir pressure is expected to be 3,800 psi at 7,000’ TVD (10.5 ppg equivalent). x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 3,100 psi (from estimated reservoir pressure). x Reservoir pressure will be controlled with a closed circulating system and choke for backpressure to maintain overbalance to the formation. Trevor Hyatt CC: Well File Drilling Engineer Joseph Lastufka 907-223-3087 Coiled Tubing BOPs Well Date Quick Test Sub to Otis -1.1 ft Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular 2.75 ft C L Annular 3.40 ft Bottom Annular 4.75 ft CL Blind/Shears 6.09 ft CL 2.0" Pipe / Slips 6.95 ft B3 B4 B1 B2 Kill Line Choke Line CL 2-3/8" Pipe / Slip 9.54 ft CL 2.0" Pipe / Slips 10.40 ft TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level 3" LP hose open ended to Flowline CDR2-AC BOP Schematic CDR2 Rig's Drip Pan Fill Line from HF2 Normally Disconnected 3" HP hose to Micromotion Hydril 7 1/16" Annular Blind/Shear 2-3/8" Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross 2-3/8" Pipe/Slips 3.0" Pipe / Slip HF nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee _____________________________________________________________________________________ Revised By: TDF 12/8/2021 SCHEMATIC Milne Point Unit Well: MPU L-39 Last Completed: 2/7/2017 PTD: 197-128 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 114' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’ 7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’ TUBING DETAIL 2-7/8” Tubing 6.4/L-80/EUE 8rd 2.441 Surface 11,261’ JEWELRY DETAIL No Depth Item 1 141’ GLM STA# 4: 2-7/8” x 1” GLM w/ SO 3-5-17 2 2,441’ GLM STA# 3: 2-7/8” x 1” GLM w/ DGLV 3 2,503’ TriPoint ESP Packer w/ WFD Annular Vent Valve 4 2,524’ 2-7/8” X profile (2.313” Packing Bore) 5 2,576’ GLM STA# 2: 2-7/8” x 1” GLM w/ DGLV 6 11,027’ GLM STA# 1: 2-7/8” x 1” GLM w/ EMPTY POCKET 10-23-17 7 11,137’ 2-7/8” XN-Nipple (2.205” No-Go) 8 11,178.5 Discharge Head 9 11,179.0’ Pump 134 Flex 17.5 Model SXD-H6 10 11,203’ Pump 134 Flex 17.5 Model SXD-H6 11 11,226’ Gas Separator GRS FER N AR 12 11,229’ Upper Tandem Seal GSB3DBUT SB/SB PFSA 13 11,236’ Lower Tandem Seal GSB3DBUT SB/SB PFSA 14 11,243’ Motor CL5 XP-200 3635V/34A 15 11,257’ Phoenix XT-150 Sensor w/ Centralizer Bottom: 11,261’ 16 12,205’ 3-1/2” Cut Joint 17 12,227’ 3.5” Permapac Packer 18 12,250’ 3.5” HES X Nipple (2.813” ID) 19 12,296’ 3.5” Baker SB-3 Packer 20 12,320’ 3.5” HES XN Nipple (No Go 2.750” ID) 21 12,332’ 3.5” Otis WLEG PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. A2 &A3 12,362’ 12,402’ 7,051’ 7,087’ 40 6/27/1998 Open OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24” Hole 9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole 7” 275 sks Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 300’ to 4,500’ Max Hole Angle = 78 deg. Max Hole Angle through perforations = 27 deg. TREE & WELLHEAD Tree 5M Cameron 2-9/16” Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile GENERAL WELL INFO API: 50-029-22786-00-00 Drilled and Cased by Nabors 27E - 6/29/1997 3.5” Injection Completion by Nabors 27E – 7/1/1998 Conversion to Jet Pump – 10/16/2014 Convert to Producer – 4/23/2015 Install Kill String by ASR#1 – 11/24/2016 Run ESP Doyon 14 – 2/7/2017 STIMULATION SUMMARY Kuparuk “A” Sand: 59,000# of 20/40 Carbo Bond frac proppant behind pipe. TD = 12,740’ (MD) / TD = 7,401’(TVD) 20” Orig. KB Elev.: 34.3’ 7” 5 15 19 2 16 18 4 20 17 9-5/8” 1 7 8-14 21 3 6 PBTD = 12,634’ (MD) / PBTD = 7,305’(TVD) Holes Shot 9/28/08 12,246.5’ to 12,248.5’ ELM. Set Owen Oil Tools X-Span 2.715” x 24” Patch @ 12,233.5’ to 12,256.1’, Min ID = 2.25” – 9/12/2014 _____________________________________________________________________________________ Revised By: JNL 4/10/2023 PROPOSED Milne Point Unit Well: MPU L-39 Last Completed: 2/7/2017 PTD: 197-128 GENERAL WELL INFO API: 50-029-22786-00-00 Drilled and Cased by Nabors 27E - 6/29/1997 3.5” Injection Completion by Nabors 27E – 7/1/1998 Conversion to Jet Pump – 10/16/2014 Convert to Producer – 4/23/2015 Install Kill String by ASR#1 – 11/24/2016 Run ESP Doyon 14 – 2/7/2017 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. A2 &A3 12,362’ 12,402’ 7,051’ 7,087’ 40 6/27/1998 Open CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 114' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’ 7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’ TUBING DETAIL 4-1/2” Tubing 12.6/L-80/TXP 3.958 Surface ±12,170’ JEWELRY DETAIL No Depth Item 1 ±12,000’ 3.813” X Sliding Sleeve 2 ±12,050’ 7” x 4-1/2” Packer 3 ±12,160’ 3.813” X Nipple 4 ±12,168’ Wireline entry guide – Btm @ ±12,170’ 5 12,295’ Whipstock OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24” Hole 9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole 7” 275 sks Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 300’ to 4,500’ Max Hole Angle = 78 deg. Max Hole Angle through perforations = 27 deg. TREE & WELLHEAD Tree 5M Cameron 2-9/16” Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile STIMULATION SUMMARY Kuparuk “A” Sand: 59,000# of 20/40 Carbo Bond frac proppant behind pipe. TD = 12,740’ (MD) / TD = 7,401’(TVD) 20” KB Elev.: 51.42’, GL Elev.: 17.1’ 7” 2 4 9-5/8” 1 Whipstock set @ 12,295’5 3 Fish: 3-1/2” Tubing Tail w/ Packer (Depth Unknown) PBTD = 12,297’ (MD)/ PBTD = 6,993’(TVD) _____________________________________________________________________________________ Revised By: JNL 4/10/2023 PROPOSED Milne Point Unit Well: MPU L-39A Last Completed: TBD PTD: TBD GENERAL WELL INFO API: 50-029-22786-01-00 Drilled and Cased by Nabors 27E - 6/29/1997 A Sidetrack: PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. A CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 114' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’ 7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’ 3-1/2” Liner 9.3 / 13Cr85 / STL 2.992 12,175’ 12,290’ 3-1/4” Liner 6.6 / 13Cr85 / TCII 2.805 12,290’ 12,600’ 2-7/8” Liner 6.5 / 13Cr85 / Hyd 511 2.441 12,600’ 14,105’ TUBING DETAIL 4-1/2” Tubing 12.6/L-80/TXP 3.958 Surface ±12,170’ JEWELRY DETAIL No Depth Item 1 ±12,000’ 3.813” X Sliding Sleeve 2 ±12,050’ 7” x 4-1/2” Packer 3 ±12,160’ 3.813” X Nipple 4 ±12,168’ Wireline entry guide – Btm @ ±12,170’ 5 12,295’ Whipstock (pinch point = 12,297’) 6 12,290’ 3-1/2” xo 3-1/4” 7 12,600’ 3-1/4” xo 2-7/8” OPEN HOLE / CEMENT DETAIL 42" 250 sx of Arcticset I (Approx) 12-1/4" 2,199 sx PF E, 550 sx Class G 8-1/2” 275 sx Class G 4-1/4” 127 sx Class G WELL INCLINATION DETAIL KOP @ 12,297’ 90 deg Hole Angle = 13,052’ TREE & WELLHEAD Tree 5M Cameron 2-9/16” Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile TD = 14,105’ (MD) / TD = 7,002’(TVD) 20” KB Elev.: 51.42’, GL Elev.: 17.1’ 7” 2 4 9-5/8” 1 2-7/8” 3-1/4” xo 2-7/8” 12,600’ 5 3 Top of Cement / Liner @ 12,145’ Whipstock set @ 12,295’, Top of Window @ 12,297’ 3-1/2” xo 3-1/4” 12,290’ PB1: TBD PBTD = 14,085’ (MD)/ PBTD = 7,002’(TVD) 6 7 _____________________________________________________________________________________ Revised By: JNL 4/10/2023 PROPOSED Milne Point Unit Well: MPU L-39B Last Completed: TBD PTD: TBD GENERAL WELL INFO API: 50-029-22786-02-00 Drilled and Cased by Nabors 27E - 6/29/1997 B Sidetrack: PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kup. A CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 114' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’ 7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’ 3-1/2” Liner 9.3 / 13Cr85 / STL 2.992 12,175’ 12,290’ 3-1/4” Liner 6.6 / 13Cr85 / TCII 2.805 12,290’ 12,600’ 2-7/8” Liner 6.5 / 13Cr85 / Hyd 511 2.441 12,600’ 14,944’ TUBING DETAIL 4-1/2” Tubing 12.6/L-80/TXP 3.958 Surface ±12,170’ JEWELRY DETAIL No Depth Item 1 ±12,000’ 3.813” X Sliding Sleeve 2 ±12,050’ 7” x 4-1/2” Packer 3 ±12,160’ 3.813” X Nipple 4 ±12,168’ Wireline entry guide – Btm @ ±12,170’ 5 12,295’ Whipstock (pinch point = 12,297’) 6 12,290’ 3-1/2” xo 3-1/4” 7 12,600’ 3-1/4” xo 2-7/8” OPEN HOLE / CEMENT DETAIL 42" 250 sx of Arcticset I (Approx) 12-1/4" 2,199 sx PF E, 550 sx Class G 8-1/2” 275 sx Class G 4-1/4” 172 sx Class G WELL INCLINATION DETAIL KOP @ 12,297’ 90 deg Hole Angle = 12,540’ TREE & WELLHEAD Tree 5M Cameron 2-9/16” Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile TD = 14,944’ (MD) / TD = 7,125’(TVD) 20” KB Elev.: 51.42’, GL Elev.: 17.1’ 7” 2 4 9-5/8” 1 2-7/8” 3-1/4” xo 2-7/8” 12,600’ 5 3 Top of Cement / Liner @ 12,145’ Whipstock set @ 12,295’, Top of Window @ 12,297’ 3-1/2” xo 3-1/4” 12,290’ PB1: TBD PBTD = 14,924’ (MD) / PBTD = 7,125’(TVD) 6 7 JLC 4/14/2023 RBDMS JSB 041823 David Douglas Hilcorp North Slope, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: Hilcorp Alaska, LLC Date: 03/23/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-39 -PTD 197-128 -API 50-029-22786-00-00 Definitive Directional Survey (Gyro + MWD Composited) Gyrodata Gyro Survey 10/22/2017 Anadrill MWD 07/15/1997 Main Folder Contents: Please include current contact information if different from above. STATE OF ALASKA ALA OIL AND GAS CONSERVATION COMMON REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull TubingU U Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 8rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: Run ESP ❑✓ 2. Name: 4.Well Class Before Work: 5.Permit to Drill Number: Hilcorp Alaska LLC Development 0 Exploratory ❑ 197-128 3.Address: Stratigraphic❑ Service ❑ 6.API Number: 3800 Centerpoint Dr,Suite 1400 Anchorage,AK 99503 50-029-22786-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0025514 MILNE PT UNIT L-39 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): IVED N/A MILNE POINT/KUPARUK RIVER OIL RECE 11.Present Well Condition Summary: MAR 1 0 2017 Total Depth measured 12,740 feet Plugs measured N/A fee��,p$$� G CC true vertical 7,401 feet Junk measured N/A fee 2,503, 12,227& Effective Depth measured 12,634 feet Packer measured 12,296 feet 2,338,6,943& true vertical 7,305 feet true vertical 7,004 feet Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 114' 114' N/A N/A Surface 8,613' 9-5/8" 8,649' 4,165' 5,750psi 3,090psi Production 12,684' 7" 12,717' 7,380' 7,240psi 5,410psi Perforation depth Measured depth See Attached Schematic � �� P ,i 17 ;��. Jt. .�,LU I. True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.4/L-80/EUE 8rd 11,261' 6,096' TriPoint ESP Packer 3.5"Permapac Packers and SSSV(type,measured and true vertical depth) 3.5"Baker SB-3 N/A See Above 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: 0 0 0 560 0 Subsequent to operation: 190 44 456 250 212 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 ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ 0 WAG ❑ GINJ❑ SUSP❑ SPLUG 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-647 Contact Paul Chan Email • pchan(p7hilcorp.com Printed Name Bo York - Title • Operations Manager Signature de' 90 1,-A . .Phone• 777-8345 Date 3/8/2017 3.—'21 V6DrAS V`/ MAR 2 2 2017 Form 10 404 Revised 5/2015 in-* Submit Original Only • • Milne Point Unit Well: MPU L-39 II SCHEMATIC Last Completed: 2/7/2017 Hilcorp Alaska,LLC PTD: 197-128 TREE&WELLHEAD Tree 5M Cameron 2-9/16" Orig.KB Elev.:34.3' Wellhead FMC 11"x 11"5M Gen 5 w/11"x 2-7/8"FMC Tbg.Hngr.w/3"LH Acme top and 2-7/8"EUE-8rd bottom and 2.5"CIW H BPV Profile e OPEN HOLE/CEMENT DETAIL 20 20" 250 sx of Arcticset I(Approx)in 24"Hole LI 1 9-5/8' 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole t, 7" 275 sks Class"G"in 8-1/2"Hole t _ CASING DETAIL .4 Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 114' 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface _ 8,649' 14;) 2 "; 7" Production 26/L-80/NSCC 6.276 Surface 12,717' P TUBING DETAIL a 3 Tubing 6.4/L-80/EUE 8rd 2.441 Surface 11,261' t 1 i4 JEWELRY DETAIL it No Depth Item Itzi 5 it 44 1 141' GLM STA#4:2-7/8"x 1"GLM w/SO 3-5-17 d 2 2,441' GLM STA#3:2-7/8"x 1"GLM w/DGLV 3 2,503' TriPoint ESP Packer w/WFD Annular Vent Valve 4 2,524' 2-7/8"X profile(2.313"Packing Bore) " 5 2,576' GLM STA#2:2-7/8"x 1"GLM w/DGLV 9-5/8"iA 6 11,027' GLM STA#1:2-7/8"x 1"GLM w/DGLV 6 7 11,137' 2-7/8"XN-Nipple(2.205"No-Go) 8 11,178.5 Discharge Head { 9 11,179.0' Pump 134 Flex 17.5 Model SXD-H6 7 10 11,203' Pump 134 Flex 17.5 Model SXD-H6 11 11,226' Gas Separator GRS FER N AR 12 11,229' Upper Tandem Seal GSB3DBUT SB/SB PFSA wit 8-14 13 11,236' Lower Tandem Seal GSB3DBUT SB/SB PFSA 14 11,243' Motor CL5 XP-200 3635V/34A _ 15 11,257' Phoenix XT-150 Sensor w/Centralizer Bottom:11,261' 16 12,205' 3-1/2"Cut Joint III 17 12,227' 3.5"Permapac Packer Affit 18 12,250' 3.5"HES X Nipple(2.813"ID) pi VI— Cj 19 12,296' 3.5"Baker SB-3 Packer r 20 12,320' 3.5"HES XN Nipple(No Go 2.750"ID) kt. 21 12,332' 3.5"Otis WLEG il IV PERFORATION DETAIL 10 • Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status 15 Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open 16 . 17 ,:Holes Shot9/28/08 WELL INCLINATION DETAIL 12,246.5 to KOP @ 300'to 4,500' . 18 12,248.5'ELM. ?I Max Hole Angle=78 deg. t AO' 19 Max Hole Angle through perforations=27 deg. Set Owen Oil Tools ''"r • 3 H 20 X-Span2.715"x24' t; STIMULATION SUMMARY Patch @ 12,233 5 toA 12,256.1',Min ID= 21 Kuparuk"A"Sand:59,000#of 20/40 2.25"-9/12/2014 1 4iiti Carbo Bond frac proppant behind pipe. �" GENERAL WELL INFO tL ' API:50-029-22786-00-00 Drilled and Cased by Nabors 27E -6/29/1997 3.5"Injection Completion by Nabors 27E-7/1/1998 Conversion to Jet Pump -10/16/2014 Convert to Producer-4/23/2015 7 I a. Install Kill String by ASR#1-11/24/2016 Run ESP Doyon 14-2/7/2017 TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Revised By:BK 3/5/2017 • • Hilcorp Alaska, LLC HiihorpAlaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPL-39 Doyon 14 50-029-22786-00-00 197-128 2/3/2017 2/7/2017 7z-4 2/ / 7-1 ' M de ;,1411V4 Weesdayr `—�� 9 , � =_ � ' =� pV 3eV ,1 No Operations to Report. urs a �; ��_ ii� �� Vii{ 9 �I� �I' �i 24' No Operations to Report. ;;10," �li 1114 i= A it I IIIP"rilip ill III � „46r7„,„ r (P Crews arrive at location,clean and organize rig,inspect and verify piping installed in the mud pits,install hydraulic hoses on BOP stack,layout rig mats around well,skid conveyor#2 into drilling position.Rig Accepted at 12:00pm 02/03/17,Company Rep perform well handover w/Pad Op, spot and shim rig over well L-39.,Skid rig floor into drilling position.,R/U high pressure mud lines,airlines,steam lines,and water lines,to rig floor,spot cuttings tank and conveyor chute into position.,Pack exterior of cellar w/snow for insulation,dig out wellhead so annuls valves are exposed,verify no pressure is seen on the IA,N/D production tree and adapter. ,J�77 . trdp t_ae ...; t ic .v r2t` , � 1, , , € Iii it: d . 41' 7 _ Wellhead I r Rep.pulled BPV.Installed TWC,NU BOPE.Install Kill Line.Obtain RKB's.Install Riser.RU Test Equipment.,Fill lines and stack.Check for leaks. Tighten leaking connections.,Test BOPE per PTD and Doyon 14 procedure.AOGCC Rep Bob Noble waived witness to testing @ 08:OOam 02/04/17,BIow down top drive/kill/choke lines,R/D test equipment,drain BOP stack.,Wellhead Rep Greg Ruge on location to pull TWC,difficulty engaging TWC retrieving head into TWC thread profile.Attempt to clean and clear any obstructions from TWC thread profile.Still unable to engage TWC.,M/U landing joint and 'r thread into tubing hanger profile.Wellhead Rep BOLDS.P/U on landing joint,unseating hanger(hanger PUW=42klbs),pull hanger to the floor,L/D landing joint and hanger,M/U hardline to flowback tank,steam line to ensure it is clear,fill w/fluid and pressure test to 500psi(good test/no leaks),R/U and circ out freeze protect from wellbore pumping 25bbls down the annulus @ 2BPM=730psi,followed by 140bbls @ 4.5BPM=1300psi, down the TBG to clear out the IA of Diesel.Verify both fluid returns are 10.4ppg when pumping is complete.Blow down and R/D lines.,RIH w/4 jnts of 2-2/8”tubing tagging the top of fish 6'into the 4th jnt @ 11915'md.Mark the tubing to indicate top of fish.P/U and screw into TD.Gain fishing parameters,(1k ft-lbs TO,68klbs down weight,85klbs up weight)and ease the string back into the fish,while rotating.Once engaged,P/U on PKR to ensure tubing has made r back up. Release RBP as per Halliburton rep,GBR on location to pull and run tubing.,POOH w/2-7/8"6.5#EU_E L-80 tubing,standing back stands in ) �\ derrick.Drop 100'rabbit drift pipe while POOH. blil,jill ` 'i�� iI ( - ii li i. Ii��lli Il�gl�ie-2 Ilei` (lih� li1i��ili��- `Iloi i irk tHi i y,. Ii"j,, l ; 44, #_ t i a iii z: POOH w/Halliburton RBP on_27/8' kill string/TBG7s r f/11872'md to 43'md,racking back stands in derrick.Recoverd 2.32"drift w/100'tail in the last stand from surface(std#128).,L/D single joint and crossover pups back to Halliburton RBP.Break out Halliburton RBP/retrival tool and send off the floor.,Mobilize ESP tools and equipment to rig floor for upcoming completion run.,R/U ESP sheaves and running equipment on rig floor.,M/U ESP motor, pump assembly,and test ESP cable to verify connectivity,pressure and temperature.(Good Test),RIH w/ESP completion on 2-7/8"6.5#EUE L-80 TBG out of the derrick f/92'md to 3100'md.Test cable every 500'md until 2000'md and then every 1000'md there after.Utilize cross collar clamps every collar,as well as heat trace clamps in the middle of every joint for the ESP cable.Verify the torque of each connection to 2250ft-lbs while RIH,several connections found under torqued.,Trouble shoot power outage w/the spooling unit.Rig power outlet found to be shorting out.Electrician change out power outlet. Still)having �issues with spooler power system.Retrieve back up generator from A pad and attempt to bypass possible shorted out wires from power cable. . a ..71 1 i( Continue to RIH w/ESP completion on 2 7/8"6.5#L-80 EUE tubing stands f/3132'to 8237'.Install Cross Collar clamps,mid joint clamps on every joint. Check each connection for proper torque(±2250 ft./lbs.).Test for cable conductivity every 1000'.,Perform ESP cable splice,clean and prep rig floor.,Continue to RIH w/ESP completion on 2 7/8"6.5#L-80 EUE tubing stands f/8237'to 8757'.Install Cross Collar clamps,mid joint clamps on every joint.Check each connection for proper torque(±2250 ft./lbs.).Test for cable conductivity every 1000'.,M/U annulus packer w/vent valve,splice ESP cable through annulus packer.SIMOPS:R/U control line spooler and sheave,M/U control line to vent valve and function vent valve.Valve actuated at 3000psi, bleed pressure off control line and vent valve closed.Place 500psi on control line and monitor 5 mins while checking for leaks.No leaks or lost pressure.,Continue to RIH w/ESP completion on 2 7/8"6.5#L-80 EUE tubing stands f/8757'to 11222'.Install Cross Collar clamps,mid joint clamps on every joint.Check each connection for proper torque(±2250 ft./lbs.).Test for cable conductivity every 1000'.Pressure on control line reducing as line is RIH,monitor for pressure loss while Centrilift performs conductivity test,no pressure loss seen.,P/U tubing hanger and begin to perform ESP cable splice into penetrator. • Hilcorp Alaska, LLC Hik•or1Alaska,LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPL-39 Doyon 14 50-029-22786-00-00 197-128 2/3/2017 2/7/2017 Continue to splice ESP cable into penetrator on hanger;Obtain parameters.Land hanger and RILDS.PUW 105k-SOW 68k-Blocks 40k.;RU LRS to IA.Hold PJSM.Test lines to 4500 psi.Pump 80 bbls diesel down IA taking returns out tubing to pits w/2 bpm,380 psi.Shut in IA and RD&release LRS.;Close valve on tubing.RD lines to pits.Open valve to tubing to drop ball&rod.Observing flow out of tubing.Close valve and RU to pump down tubing.;Bullhead down tubing w/55 bbls of 10.4 ppg brine w/1 bpm,2350 psi.Stop pumps and observe for flow.Got 10 bbls back.Still flowing.Continue to bullhead down tubing w/25 bbls of 10.4 ppg brine.1 bpm,2330 psi.Allow to flow back 5 bbls.Total of 65 bbls bullheaded into formation(same as tubing volume).;Drop Ball&Rod.Allow to fall f/10 min.Pressure up to 3900 psi to set Tri-point Packer.Chart pressure for 45 minutes.Lost 200 psi in 45 minutes.Suspect 1.�-t leaking by Ball&Rod.Bleed off pressure.Line up and test IA_LPacker to 2000 psi f/30 min.,Good test.Bleed pressure.;Back out landing joint.Install rV\ BPV.;Clean/clear Rig floor.;ND BOPE,pull riser,N/D kill and choke lines,stand back BOPE on stump;Remove 13-5/8"spacer spool and double stud adapter.Baker centrilift on location to verify final ESP checks.;Wellhead hand Greg Ruge on location to N/U tree and adapter flange as well as orient. (Trouble Shoot)Issue getting control line tree port seals to hold pressure.Change out seals on port(holding pressure).Test tree void(pass),fill tree w/ diesel,secure tree.SIMOPS:R/D floor air/steam/mud lines,skid beaverslide into travel position.;Skid floor into moving position,secure derrick.;R/D move off well onto edge of L-pad.Release rig from well L-39 @ 23:59 2/7/17;Lay rig mats around well L-03,stage wellhead equipment behind well.Spot rig in positon to begin backing over L-03.SIMOPS: Doyon welder remove and fix landing in front of pipe shed door entrance. • y'OF Ty • `,1&%\II/7: THE STATE Alaska Oil and Gas Of LAS KA Conservation COlI[llllissi®n s ' 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 e„ Main: 907.279.1433 A 9� Fax: 907.276.7542 www.aogcc.alaska.gov Bo York ��N�� M '. Operation Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU KR L-39 Permit to Drill Number: 197-128 Sundry Number: 316-647 Dear Mr. York: 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, 0 Cathy P Foer ter Chair DATED this day of January, 2017. RBDMS LL-- JAN Z 6 2017 • 0 STATE OF ALASKA RECEIVED 0 ALASKA OIL AND GAS CONSERVATION COMMISSIONDEC 32016 APPLICATION FOR SUNDRY APPROVALS S 20 AAC 25.280 b� ((��` 1:Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ dnaiUtdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Q Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Run ESP Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q 197-128 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ElService ❑ 6.API Number: Anchorage Alaska 99503 50-029-22786-00-00 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D Will planned perforations require a spacing exception? Yes ❑ No 0 MILNE PT UNIT KR L-39 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0025514 MILNE POINT/KUPARUK RIVER OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): 'Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,740' 7,401' 12,634' 7,305' 2,912 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 114' 114' N/A N/A Surface 8,613' 9-5/8" 8,649' 4,165' 5,750psi 3,090psi Intermediate 12,684' 7" 12,717' 7,380' 7,240psi 5,410psi 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 Mod 8rd 10,020 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 3.5"Permapac Packer&3.5"Baker S-3 and N/A 12,227 MD/6,943'TVD&12,296'MD/7,004'TVD and N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch El Exploratory ❑ Stratigraphic❑ Development Q Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 1/15/2017 Commencing Operations: OIL 2 WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Paul Chan Email pchan(a,hilcorp.com L . � ctr11e� Printed Name �� Bo York Title Operations Manager / Signature hone 777-8345 Date /2) O I Z(7 I v COMMISSION USE ONLY Conditions of ap oval: Notify Commission so that a representative may witness Sundry Number: / . ° 27/`'7 Plug Integrity ❑ BOP Test Mechanical Integrity Test Location Clearance ❑ Other: 44 35G—) r5:, 13 0!icJes i 45C. i Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Elf Subsequent Form Required: /v y D RBDMS l/I L.JAN 1 6 2017 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date:1— 4 _77 /3/ie NI I13/Ii— ///�� y__ /_ 3-/ 7 Submit Form and Form 10-403 Revised 11/2015 Approved application is v f r 2R ' '+hl N Ai, of approval. Attachmentss in Duplicate S • llWell Prognosis Well: MPU L-39 Hilcorp Alaska,LLD Date:12/29/2016 Well Name: MPU L-39 API Number: 50-029-22786-00 Current Status: SI Oil Well Pad: L-Pad Estimated Start Date: January 10th, 2017 Rig: Doyon 14 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 197-128 First Call Engineer: Paul Chan (907)777-8333 (0) (907)444-2881 (M) Second Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228 (M) 710* ,111%ligitlE -481* '14 ititIA;t4 Current Bottom Hole Pressure: 3,612 psi @ 7,000' TVD (SBHPS 10/26/2016/9.94 ppg EMW) Maximum Expected BHP: 3,612 psi @ 7,000' TVD (No new perfs being added) MPSP: 2,912 psi (0.1 psi/ft gas gradient) Brief Well Summary: i 3 1 MPU L-39 was originally completed as an injector in an isolated fault block with no off-take points. The well had a short injection life,from mid-1998 to 1999. Cumulative injection is 58 Mbw and 20 MMscfd. The current estimated reserves are 1.01 MMbo with 0.66 MMbo within the A2/A3 sands. A previous attempt at free- flowing the well to tanks was conducted in October 2002 as part of a tracer/low salinity pilot, only managing to produce a rate of 190 BFPD. A"poor boy"jet pump design was attempted in 2008, but failed to produce after the packing was blown during the first attempt to lift the well. Following attempts were cancelled after not being able to get a good jet pump set. In 2014, BP decided to try another attempt at'poor boy'jet pump lift and include an A-sand fracture as part of the project. In September 2014,the original tubing punches from 2008 were patched and the frac job pumped away 59,000Ibs of 20/40 Carbo Bond frac proppant behind pipe before screening out(design was for 150-200 M lbs). The well was put on production 11/28/14 with the new poor boy jet pump design, but the packing failed after—5.5 hrs of production. At the time of failure,the well was at"'90%WC and declining. In 2015, a thru-tubing jet pump was installed by punching the tubing and straddling the holes with packers and a small diameter jet pump. The well came on with a high water cut(>95%)and was losing power fluid (water) the well was shut-in. In November 2016,the through tubing jet pump completion was removed and an ESP ran to 2025' MD. The ESP tested bad at that point and damaged cable was observed in several location while POOH. The ESP motor lead was replaced and the ESP assembly was RBIH with the addition of cross-collar clamps on every joint (instead of every other joint). The ESP tested bad again at 520' MD. Upon POOH, ESP power cable damage was observed again. Dual full gauge string mills were then RIH to±2600' MD, 100' below the ESP packer set depth. No obstructions were noted on the trip in the hole. The well was back reamed from 2600'to 2150' (15 joints)while POOH. Started back reaming again from 450' and encountered a tight spot at 48' below the rig floor. Back reamed the tight spot clean and LD the string mills. A dummy ESP run was made to 500'without incident. The casing was pressure tested down to 156'to 2000 psi. Two more ESP runs were made without success before deciding to suspend operations. Prior to shutting down operations, a caliper log was run from^'12,000' MD to surface. The caliper log showed obvious casing restrictions or damage. Note: All four ESP runs were made with the same motor. The ESP power cable and MLE were changed out. • • Well Prognosis Well: MPU 1-39 IIileorp Alaska,LI) Date:12/29/2016 Notes Regarding Wellbore Condition • The 7" production casing was tested to 4,200 psi on 9/12/2014 down to 12,296' MD. • Per CO 390A, an ESP packer will be run Objective: Screw back into kill string, retrieve RBP and full kill string, M/U ESP and RIH to setting depth. Brief RWO Procedure: 1. MIRU Doyon 14 and 500 bbl returns tank. 2. 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/±10.4 ppg brine. ,,// i-- 3. Set BPV. ND tree/NU BOPE. Set TWC. 4. Test BOPE to 250 psi Low/3,500 s_i High, annular to 250 psi Low/2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. .2 t)e a. Perform Test per Doyon 14 BOP Test Procedure. 1 ,i;.ii b. Notify AOGCC 24 hours in advance of BOP test. 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. 5. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV 77- profile is eroded and/or corroded and BPV cannot be set with tree on.) 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 t,'Ili c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor Sthe 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.) f. 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. 6. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/±10.4 ppg brine as needed. 7. MU landing joint or spear and PU on the tubing hanger. 8. LD the tubing hanger. 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. • 0 Well Prognosis • Well: MPU 1-39 Hi corp Alaska,LI) Date:12/29/2016 9. Obtain down hole parameters. RIH and screw back into tubing string. Consult w/Halliburton rep about proper release procedure prior to torqueing up string. Note: Indicators of kill string make up will be an increased string weight followed by a gradual increase in torque. Note: If we cannot screw back into the fish then the remaining tubing string and RBP will be fished with an overshot on a workstring. 10. Release the RBP and circulate bottoms up to check for gas below the RBP. 11. POOH and stand back the 2-7/8"tubing. LD Halliburton RBP. Number all joints.Tubing will be re- used for the ESP completion run. a. Mark all bad joints of tubing for disposal. 12. PU new ESP and RIH on 2-7/8" tubing. Set base of ESP at± 11,260' MD. a. GLM#4 @ ± 140' MD w/DGLV b. GLM#3 @ ±2440' MD w/DGLV c. E$P Packer w/annular vept valve @ ±2,500' MD d. X profile @ ±2,550' MD w/RHC ball catcher e. GLM#2 @ ±2,600' MD w/SO f. GLM #1 @ ±11,150' MD w/DGLV Y— g. 2-7/8"XN Nipple @ ±11,200'MD ,(211k:Uctc h. Base of ESP @ ± 11,260' MD 4/ 13. Terminate ESP power cable. Land tubing hanger. RILDS. Freeze protect IA and tubing. 14. Drop ball/rod and set ESP packer. la)) 6 7 15. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off)weights on tally. 16. Set BPV. ND BOPE. NU 2-9/16" 5,000#tree/adapter flange and test to 500 psi low/5,000 psi high. 17. RDMO Doyon 14 18. Replace gauge(s) if removed. 19. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Existing Tree/Wellhead 4. BOPE Schematic 5. Blank RWO MOC Form • • Milne Point Unit Well: MPU L-39 SCHEMATIC Last Completed: 11/24/2016 Mean)Alaska,LLC PTD: 197-128 TREE&WELLHEAD Tree 5M Cameron 3-1/8" Orig.KB Elev.:34.3' Wellhead FMC 11"x 11"5M Gen 5 w/11"x 3.5"FMC Tbg.Hngr.w/NSCT Lthreads top and bottom and 3"CIW H BPV Profile i 20„ h OPEN HOLE/CEMENT DETAIL 20" 250 sx of Arcticset I(Approx)in 24"Hole t 9-5/8" 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole 7" 275 sks Class"G"in 8-1/2"Hole `" CASING DETAIL ' ' Size Type Wt/Grade/Conn ID Top Btm ;,;t 1 20" Conductor 91.1/H-40/N/A N/A Surface 114' ; 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface 8,649' ,4 7" Production 26/L-80/NSCC 6.276 Surface 12,717' TUBING DETAIL y � 2-7/8" Tubing 6.5/L-80/EUE Mod 8rd 2.441 Surface 10,020' r' JEWELRY DETAIL 5' r' No Depth Item 1 ±9,981' Tubing Tail 2 ±10,020' Top of 2-7/8"fish(estimated from string weight) l 3 11,865' Cross Over 3-1/2"IF Pin x 2-7/8"EUE Box '41 Ltl 4 11,870' 7"3L RBP—Bottom @ 11,878' t' 5 12,205' Top of 3-1/2"Cut Joint 9-5/8"tA ik 6 12,227' 3.5"Permapac Packer 7 12,250' 3.5"HES X Nipple(2.813"ID) 8 12,296' 3.5"Baker SB-3 Packer 9 12,320' 3.5"HES XN Nipple(No Go 2.750"ID) 10 12,332' 3.5"Otis WLEG PERFORATION DETAIL 1 Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status 2 Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open t.; WELL INCLINATION DETAIL KOP @ 300'to 4,500' 3d di Max Hole Angle=78 deg. e� Max Hole Angle through perforations=27 deg. sb4 174 STIMULATION SUMMARY w Kuparuk"A"Sand:59,000#of 20/40 5 r Carbo Bond frac proppant behind pipe. 6 Holes Shot 9/28/08„;i7,',..1 AA iE, 7 12,246 5 ELM. GENERAL WELL INFO API:50-029-22786-00-00 8 Drilled and Cased by Nabors 27E -6/29/1997 Set Owen Oil Toolsitt; 9 i 3.5"Injection Completion by Nabors 27E—7/1/1998 X-Span 2.715 x 24" M Conversion to Jet Pump —10/16/2014 Patch @ 12,233 5 to 1010 Convert to Producer—4/23/2015 12,256.1',Min ID= 4. 2.25"-9/12/2014 ° Install Kill String by ASR#1—11/24/2016 i it it o TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Revised By:PC 12/28/2016 • • Milne Point Unit Well: MPU L-39 II - PROPOSED Last Completed: 11/24/2016 lllilcorp Alaska,LLC PTD: 197-128 TREE&WELLHEAD Tree 5M Cameron 3-1/8" Orig.KB Elev.:34.3' Wellhead FMC 11"x 11"5M Gen 5 w/11"x 3.5"FMC Tbg.Hngr.w/NSCT threads top and bottom and 3"CIW H BPV Profile 4 'i.:' t 20 OPEN HOLE/CEMENT DETAIL 20" 250 sx of Arcticset I(Approx)in 24"Hole l 1 9-5/8" 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole 4s° 4t 7" 275 sks Class"G"in 8-1/2"Hole CASING DETAIL ' 2� Size Type Wt/Grade/Conn ID Top Btm Z��V 20" Conductor 91.1/H-40/N/A N/A Surface 114' ts7 V1/4 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface 8,649' 2 7" Production 26/L-80/NSCC 6.276 Surface 12,717' _ T ,i/v* TUBING DETAIL �r4' �—! 3 (3/4,1•' 2-7/8" Tubing 6.4/L-80/EUE Mod 8rd 2.441 Surface ±11,260' JEWELRY DETAIL f. ` No Depth Item )'f 5 ;' §. 1 ±140' GLM STA#4:2-7/8"x 1"GLM w/DGLV l , 2 ±2,440' GLM STA#3:2-7/8"x 1"GLM w/DGLV 'p °' 3 ±2,500' ESP Packer w/Annular Vent Valve 4 ±2,550' X profile w/RHC ball catcher 5 ±2,600' GLM STA#2:2-7/8"x 1"GLM w/SO 9-5/8"till 6 ±11,150' GLM STA#1:2-7/8"x 1"GLM w/DGLV 6 7 ±11,200' 2-7/8"XN-Nipple(2.205"No-Go) 8 ±11,260' Base of ESP d: w 9 12,205' 3-1/2"Cut Joint j 7 10 12,227' 3.5"Permapac Packer PI 11 12,250' 3.5"HES X Nipple(2.813"ID) 12 12,296' 3.5"Baker SB-3 Packer 13 12,320' 3.5"HES XN Nipple(No Go 2.750"ID) 14 12,332' 3.5"Otis WLEG aa:Na PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status 0 Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open s° WELL INCLINATION DETAIL KOP @ 300'to 4,500' li Max Hole Angle=78 deg. 8 + Max Hole Angle through perforations=27 deg. t Z i;t io ' Holes Shot 9/28/08 STIMULATION SUMMARY 12,246.5'to Kuparuk"A"Sand:59,000#of 20 40 ' 12,248.5'ELM. P / y ,. ' 12 Carbo Bond frac proppant behind pipe. , Set Owen Oil Tools 13 GENERAL WELL INFO X-Span 2.715"x24" , Patch @ 12 233 5 to API:50-029-22786-00-00 12,256.1',Min ID= ,i,q 14 Drilled and Cased by Nabors 27E -6/29/1997 2.25"-9/12/2014 z3.5"Injection Completion by Nabors 27E-7/1/1998 1'1 i° Conversion to Jet Pump -10/16/2014 r Convert to Producer-4/23/2015 Install Kill String by ASR#1-11/24/2016 7" TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Revised By:PC 12/28/2016 --p---- MP L-39 0 11.11,'Mill 1St IMIIIIIIIIIIMI • Tubing hanger,FMC 7 X 2 7/8&2 t.,-.';"type H BPV PR profile 3" LH acme thread 2 9/16 SM HWO Valve,Swab,CIW, Top/2 7/8 EUE 8rd thread ..:.:-) 7.:„°' it,,.;-.1 i• "'-',) Bottom i a 1.11.11 It21 ATo 1; '- All ; . .*41231.4CIAM ! • . llwillan ,.,.) --", Valve,SW,cm * ) ,› 1- ,9 (a i;;" 2 9/16 5M FE,Baker oper, It- I o". 47 til, _a alliIllMlg. 0 .' Malliniffn. til............1St Valve,Master,OW, i,::: 1;'L'.,;----.' 2 9/16 SM HWO,DO :,..‘,.., limit II,• /la -"MEINEDF; II Adapter,FMC A-5-EC, - 7'51VI rot fig btm X ._ 2 9/16 5M stdd top, . .- , tit miihltgi 1111.‘-'- mint 11"X 7"Tubing head,FMC -- • • K- I • In sommillia, --_;_•'± III Astrine_ Gen 5 Or ME WA . KAI MI Am 1 — 1 IV • II t11 1 I iI 1 .. - ip-- ii il•I trlo t 1-1.--'; alOM Casing head,FMC ir FIg 1.11111i :,), . All casing valves2 1/15 5M Top NI ME111110,1 gal MN ' III 11 -I` i III _- ... _ ...... .., .-,- - .,....---- -dillijoTal....; • , ; •?.-* 0 i,:••=•ii-;,(4.;or •., ,m, „ , . • Ltsiro. 1 vi".- si011 . ", ? i II , .''' , ill.• 'i 111111-' , . ,• ..,- ...• ai. 44 ' iii . • n 11 IIII All casing casing valves2 1/16 5M , 1--- 1/04/16 ® DOYON 14 BOP'S • DRILLING 13-5/8 5000 PSI RIG FLOOR �n n n n nj ,rir4 HYDRH. 13-5/8" ANNULAR \ \t is) / CNI 'GTUD x00FLANGEI I ' I • M i •HYDRIC® . \ / in \ / Iiiauir ii urau:nii HYDRIL MPL DOUBLE GATE 1 �I!_ o � � is 13-5/8" 5000 PSI °'��•..:� o t ,1 - iTUD z STUD BX-160 •� �� 10" OPERATORS °'�;,► � - M PIPE RAMS .t[■ � M Ili I iii. 6 KTI?i ZZ7- "{ 10" OPERATORS '1,� IN �,� BLIND RAMS \ u - �. it CK II*M ,:. :. ii 3-1/8" 5000 PSI MANUAL VALVE :,-: ^ ia_i �,_ 3-1/8" 5000 PSI HCR VALVE )— -___=--- ____T elaiiiitur uN mar ——.I-2 -- I I 0 — it --� ---/i:uuuuan unnuun -- _ -- — cv IIUD CROSS / +I 13-5/8" 5000 PSI FLANGE x FLANGE BX-160 nIn.unnn,.cine c WITH lEA. 3-1/8" & 4-1/16"OUTLETS - o•,I�. w.f..o• HYDRIL MPL SINGLE GATE e 1 ■I■■ _ ■■ 13-5/8" 5000 PSI o;_�►�.� o �� 10 FLANGE x FLANGE BX-160 CE i�� G 3) N 10" OPERATORS °. unit c0 PIPE RAMS . ;.1m... ..,„,,0.= M Iii.Guircn onioiui c i PUBING SPOOL -I 1- I 1 1 \./ . GROUND LEVEL t I • • A rm0 0 � WI ® ° > 8\ 0./ f/ a§ < E c o _ � � 0 % > $ = \ f k� \ a o. ± m .E« C / / 22 om \ = e < o. ED _ w \ / � C % .q ■ ■ 2 \ k k (o c \ asf c o / $ % B / 5 CD - § o 9 > c & m % c k» 2 % o \ C.) f / 2 \ 0 o \ � / CD E § k / k i _ � a S \ 0 »y Cl)\ . / � c 0 4.1o. k � SI i.4 c7F L a « mo # E w C) § \ k k 2 E & \ .2 co co k 0 S § % a) C) � c c 0 / >, a O O 0 .. « t .. . . a q E0 / k -a 0 a 0 o $ k k 9 < / STATE OF ALASKA - ALRSKA OIL AND GAS CONSERVATION COMI�RSSION RECEIVED- REPORT OF SUNDRY WELL OPERATIONS DEC 29 ZO cd 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing U p f .°wn U Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Chanrblele N am ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: Run Kill String 0 2. Name: 4.Well Class Before Work: 5.Permit to Drill Number: Hilcorp Alaska LLC Development Q Exploratory ❑ 197-128 3.Address: Stratigraphic❑ Service ❑ 6.API Number: 3800 Centerpoint Dr,Suite 1400 Anchorage,AK 99503 50-029-22786-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0025514 MILNE PT UNIT KR L-39 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A MILNE POINT/KUPARUK RIVER OIL 11.Present Well Condition Summary: Total Depth measured 12,740 feet Plugs measured 11,870 feet true vertical 7,401 feet Junk measured N/A feet Effective Depth measured 12,634 feet Packer measured 12,227&12,296 feet true vertical 7,305 feet true vertical 6,943&7,004 feet Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 114' 114' N/A N/A Surface 8,613' 9-5/8" 8,649' 4,165' 5,750psi 3,090psi Intermediate 12,684' 7" 12,717' y'7,380' 7,240psi 5,410psi Perforation depth Measured depth See Attached Schematic SCANNED ;ti"1? ,t .'"i 20 17, True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.5/L-80/EUE Mod 8rd 10,020' 5,024' 3.5"Permapac Packer Packers and SSSV(type,measured and true vertical depth) 3.5"Baker SB-3 Packer N/A See Above 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: 0 0 0 800 0 Subsequent to operation: 0 0 0 560 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 2 Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑✓ Gas ❑ WDSPL Li Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-557 Contact Paul Chan Email pchan@hilcorp.com Printed Name Bo York Title Operations Manager Signature Phone 777-8345 Date 12/15/2016 �� f� ORIGINAL Aso/ Form 10-404 Revised 5/2015 RBDMS 1i 1 A\ 2 2617 Submit Original Only H . ill Milne Point Unit Well: MPU L-39 SCHEMATIC Last Completed: 11/24/2016 uili•ore,)��I:�ak.�.LIC. 197-128 TREE&WELLHEAD Tree 5M Cameron 3-1/8" Orig.KB Elev.:34.3' Wellhead FMC 11"x 11"5M Gen 5 w/11"x 3.5"FMC Tbg.Hngr.w/NSCT threads top and bottom and 3"CIW H BPV Profile ,j OPEN HOLE/CEMENT DETAIL 20 i+ 20" 250 sx of Arcticset I(Approx)in 24"Hole 9-5/8" 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole 7" 275 sks Class"G"in 8-1/2"Hole CASING DETAIL "J Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 114' jr 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface 8,649' 7" Production 26/L-80/NSCC 6.276 Surface 12,717' o TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE Mod 8rd 2.441 Surface 10,020' JEWELRY DETAIL No Depth Item f 1 ±9,981' Tubing Tail 1 ±10,020' Top of 2-7/8"fish(estimated from string weight) it 3 11,865' Cross Over 3-1/2"IF Pin x 2-7/8"EUE Box , 4 11,870' 7"3L RBP-Bottom @ 11,878' 10 5 12,205' Top of 3-1/2"Cut Joint 9-5/8" a ► 6 12,227' 3.5"Permapac Packer 7 12,250' 3.5"HES X Nipple(2.813"ID) 8 12,296' 3.5"Baker SB-3 Packer 9 12,320' 3.5"HES XN Nipple(No Go 2.750"ID) 10 12,332' 3.5"Otis WLEG PERFORATION DETAIL 1 Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status 2 Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open WELL INCLINATION DETAIL KOP @ 300'to 4,500' Max Hole Angle=78 deg. s Max Hole Angle through perforations=27 -_ 4 g g p deg. STIMULATION SUMMARY Kuparuk"A"Sand:59,000#of 20/40 5 Carbo Bond frac proppant behind pipe. • 6 Holes Shot 9/28/08 GENERAL WELL INFO ,, I 0 12,246.5'to 12,248.5 ELM. API:50-029-22786-00-00 t , � 8 Drilled and Cased by Nabors 27E -6/29/1997 3.5"Injection Completion by Nabors 27E-7/1/1998 Set Owen Oil Tools ' . 9 X-Span 2.715"x 24 Conversion to Jet Pump -10/16/2014 Patch 12,233.5'to Convert to Producer-4/23/2015 1n210 = Install Kill String by ASR#1—11/24/2016 2.25"-9/12/2014 .4, 7"A TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Revised By:PC 12/28/2016 • . Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR#1 50-029-22786-00-00 197-128 11/13/16 11/24/16 Daily Operations: 11 11/9/26/2016-Wednesday No activity to report. 11/10/2016-Thursday No activity to report. 11/11/2016- Friday No activity to report. 11/12/2016-Saturday No activity to report. 11/13/2016-Sunday Rig up Little Red Pumping Services,Test Lines, Bleed gas from tubing and back side, Start pumping with 10.2 ppg brine water staging up to 4 BPM @ 630psi, pumped a total of 525 bbls returning to flow back tank. (SIMOPS, Moving Rig& Equipment from E pad to L-39) Monitor well, on slight vac. Install BPV with Tee bar. (AOGCC was notified of right to witness BOP Test on 11-12-16 @ 22:40 Hrs.) (BOP Test witness was waived by AOGCC Bob Noble on 11-13-16 @ 0:154 AM). Continue to Rig up on MP L-39, Spot mud boat, install VR plug in wellhead, remove annulus valve. Remove well supports choke skid from behind the well row, prep wellhead and BOPE studs for spotting BOPE in place. Alaska crane spot BOPE on wellhead, NES trucking spot dog house and well site manager trailers in place. Roads and Pads on location w/vac truck removing fluids from flow back tank. Back pit trailer into place along side mud boat, set on blocks, and put up hand rails. Line cellar w/herculite.Alaska Crane pick wellhouse and set over well. Back carrier onto mud boat, extend outriggers into position to raise mast, and connect electrical from generator to wellhouse. Raise mast into working position, secure guy wires onto outriggers. Pin mast supports into place and spot tool storage seacan into place. Perform Sundry meeting w/ crew. Lay out herculite containment. Spot catwalk into place, hook up accumulator lines from TP trailer into BOP.Torque all bolts on BOP stack.Spot cuttings tank into place behind pit trailer. Wellhead hand Greg Ruge on location. Open blind rams, remove BPV (no pressure seen below BPV or on the annulus) and set TWC. Rig up kill and choke lines from pit trailer to mud cross. Repair worn hydraulic hose on power tongs. Peak truck on location to offload 250bbls of 10.2ppg brine into pits. Crew continues to R/U fluid lines, heating trailers and prepare to R/U to test BOPE. Wrap fluid lines w/glycol lines from Certek,fill stack w/fresh water and prepare to test BOPE. 11/14/2016- Monday Continue to wrap lines with heat trace and insulation. Held Sundry meeting with Rig crew. Rig up for BOP Test, make up test joints, Shell Test on BOP, Changed out seals on choke manifold valve# 12, chasing leaks on BOP, tighten all lock down screws, pulled TWC and rebuilt and reset.Test to 250/3,500psi.Tested Annular to 250/2,500psi.Tested with 2-7/8" & 3- 1/2"Test joints. Gas Alarms all tested good, Perform Accumulator test.Test witness waived by AOGCC rep Bob Nobel 11/13/16 1:54am. P/U landing joint, M/U crossovers from 3-1/2" RTS-8 to left handed ACME, engage landing joint and crossovers to TBG hanger. M/U w/9.5 rotations. Wellhead hand Greg Ruge on location to back out lock down screws. LDS very tight, issue getting 1 lockdown to back out of gland nut. Remove gland nut and LDS and find replacement. Slowly pull TBG hanger out of spool and watch for weight indicator to break over, indicating the TBG is free. Weight indicator broke over at 77klbs and TBG pulled out consistently at 73klbs. POOH w/3.5" L-80 EUE tubing from jet cut @ 12,015'md to ^' 3,000'md. Inspect and number all joints, mark and remove any bad joints. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR#1 50-029-22786-00-00 197-128 11/13/16 11/24/16 Daily Operations: 11/15/2016-Tuesday Continue to TOOH laying down 3.5" EUE Tubing F/3,000'T/Surface. Recovered total of 383 joints & 1 Cut joint. Load &Tally 3.5" work string on racks &Tally, Make up 7" Casing scraper assembly, scrape through Packer setting depth @ 2,500'4 times. TIH with 7" Casing Scraper assembly on 3.5" Work string from surface to TBG stub. Lightly tag TBG stump w/ mule shoe 15' in on jnt 403 (12,012'md). L/D jnt 403 and circulate 1 Bottoms Up (105bbls). Fluids clean throughout bottoms up. Allow well to U-tube, then blow down lines. POOH w/7" Casing Scraper assembly on 3.5" work string f/ 12,012'md to 9,500'md. 1111 Hilcorp Alaska, LLC Weekly ifilvorpAlaska.LLC: Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPU L-39 ASR 1 50-029-22786-00-00 197-128 11/13/2016 11/24/2016 11/16/16 .Wednesday TOOH to 9,265',Service Rig, Check fluids in all equipment, Flow check well.CBU,3 BPM @ 520psi, monitor wellbore,wellbore still flowing, discussed options with Work over Engineer,TIH F/9,265'T/9,830',(NPT),VMS Mechanic clear codes on Rig Engine. EGR&Anti Freeze low coolant.Continue to TIH F/9,830'T/11,230',(NPT),VMS Mechanic clear codes on Rig Engine. EGR&Anti Freeze low coolant. Run update on Engine with Computer. Line up and circulate a wellbore bottoms up(320bbls)weighing fluid every 20bbls. Fluid weights range from 10.2ppg to 10.0ppg w/the majority of the well at 10.1ppg.Shut in well and record tubing and IA pressure.TBG= 120psi, IA=110psi.Wait on weight up fluid from Bariod. 165bbls of 11ppg fluid on location to be used to weigh up the 10.1ppg fluid.Work the circulation plan with the crew, blending fluids in pits 2,3,and 4. Utilize pit 1 at a mixing pit to ensure fluid gets up to 10.4ppg before entering the well. Blend 45bbls of 11ppg brine with 113bbls of 10.1ppg brine in pits 2,3,and 4 to take the fluid to 10.4ppg. Begin pumping circulation with the 158bbls of 10.4ppg fluid.SIMOPS: blend 10.1ppg fluid with 11ppg fluid in pit 1 until reaching 10.4ppg. Roll 10.4ppg fluid into active system and repeat process using 10.1ppg returns from wellbore to blend with 11ppg fluid off of peak truck.Take wellbore returns out to cuttings tank when not utilizing fluid for weighing up. 11/17/16'L Thursdayi; 434.. � , Continue to Circulate, Increase brine weight from 10.2 ppg.to 10.4 ppg. Monitor well after circulation, no flow on annulus or tubing. 23bbls lost during 435bb1 circulation. (AOGCC was notified of use of BOP equipment during increase of working brine weight @ 09:00 HRs. on 11-17- 16)(AOGCC was notified of upcoming BOP Test for testing equipment used while increasing working brine fluid weight @ 09:50 11-17- 16,(NPT) Reset Rig Engine codes with VMS mechanic. POH w/3-1/2"WS to 7,565'. (NPT) Reset Rig Engine codes with VMS mechanic. Re-Gen Rig Engine. Continue to POOH w/7"cleanout BHA#1 f/7,565'and to surface. L/D scraper and mule shoe. (Well on slight losses,taking proper fill while pulling out of hole),Swap out rig floor equipment from 3.5"to 2-7/8"for running completion. R/U to test BOPE that was utilized to shut in the well.Set test plug,fill stack, P/U 2-7/8"test joint.AOGCC rep Matthew Herrera waived witness to testing @ 21:40 11- 17-16.Test BOPE equipment that was used to shut in well.Choke valves#12, 14, 16, and the TIW to 250psi low, 3,500psi high f/5 charted mins each.Annular element w/2-7/8" pipe to 250psi low, 2,500psi high,f/5 charted mins each.SIMOPS: Load and strap 360jnts of 2-7/8" completion tubing in prep t/RIH w/ESP completion. 1a/18T16 Friday r ogV r ,- Pull test plug.Clear Rig floor. RU to run 2-78" ESP completion. PU centralizer,Sensor,CL5 motor, lower&upper seals,separator, 2 pumps& discharge head w/pup to 92'. Perform conductivity test.Good. RIH w/ESP on 2-78"6.5#L-80 EUE tubing per tally to 2,025' (62 joints).While doing first conductivity test,observed that the cable was grounded. POH LD 2-78"tubing looking for damaged cable.Cable damage seen on jnts 19, 20,and 22. Damage was mostly compressing of the ESP cable armor with a small amount peeling off and exposing the rubber insulation. ESP cable continues to ground out 500'from surface, again 100'from surface,and again after the cable splice from the MLE. L/D ESP beginning with the Discharge head, Pump#1, Pump#2, and the Gas Separator w/upper and lower seal assemblies.Testing MLE for conductivity(continuing to fail). ESP motor tested and passed once MLE was removed.While rolling pump#1 from catwalk onto pipe racks, pump#1 fell between the two and ended up on the ground. Decision was made to proactively replace pump with new pump. Lower cut portion of ESP cable from sheave.Test Centerlift ESP cable on cable spool to ensure proper conductivity prior to making new splice. Centerlift replace MLE and splice new MLE onto tested ESP cable.Verify splice conductivity(good test),P/U ESP Gas Separator w/Upper and Lower Seal assembly and M/U to ESP motor section. • • Hilcorp Alaska, LLC Weekly Imem'pAhaaku. <.0 Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPU L-39 ASR 1 50-029-22786-00-00 197-128 11/13/2016 11/24/2016 11j1 /16Sturtay�,, I. '' y ., ,4 Continue to PU ESP pump/motor assembly to 92'. PU 1st full joint and submerge pump assembly. Perform conductivity test. Good test. RIH w/ESP on 2-78"tubing to 520'. Perform conductivity test.Again showing grounded. POH 3 joints and observed cable armor had been rubbing on something just below surface.Observed another spot where armor had kinked and parted.Continue to POH LD tubing and ESP assembly.Again the MLE failed &the motor passed after MLE was removed. Look down hole for any obstructions protruding in the wellhead. Nothing observed.Secure well &stand by during Code Red All Call on Milne radio.All clear called.Change over handling equipment to 3-1/2".Wait on 6-1/8"string mills to arrive from Baker Fishing shop. Offload tools.Strap same. MU 4-3/4"OD bullnose, 6-1/8" OD string mill, 3-1/2" IF pup joint, 6-1/8"OD string mill&XO to 3-1/2"CS Hyd/,Secure well.Travel crews to MPOC for safety meeting. Day WSM remained on location to man the rig.Check all equipment fluids and top off well prior to RIH.Well took 5bbls to fill. RIH w/string mill BHA#2 on 3.5"work string watching for signs of drag or interference from surface to^'500'md.5 joints into hole, a gradual reduction in weight is seen on weight indicator changing from 2.2klbs to 1.6klbs over the last 16' and of joint#5.Similar results are seen while running joints#7-15.The trend is a gradual weight reduction 12-15'into each joint reducing the hookload by 600-800Ibs. Continue to RIH w/string mill BHA#2 on 3.5"work string f/^'500'md to packer setting depth at^'2,600'md watching for any indicators that could explain our ESP cable damage. No hangups or major changes seen. Drag pattern continued fairly consistently down to packer stetting depth of 2,600'md. Kelly up to joint#89 w/power swivel and rotate through the entire joint watching for signs of torque. Initial torque @ 60RPM =220ft-lbs.Once rotating joint down to floor level, P/U joint 30'md and RIH watching weight indicator.Same drag is noted 12-15'into joint,and 600-800Ibs reduction in weight.Continue to rotate joints 89-84 and check for changes in drag. Drag is still noted in similar location. POH LD 3-1/2"WS to ±450' (15 jts left in hole),Begin back reaming out of hole& reaming each joint back down. n 11/2Q/16340rday; .a, Continue to back ream w/6-1/8"string mill assembly f/450'.At 48', encountered torque while back reaming. Ream&back ream through that area several times.Cleaned up nicely.Continue to back ream to surface. Inspect string mills.Obvious indications on both string mills of working through obstruction(s). LD string mills.Change handling equipment to 2-78". PU 2-78" Muleshoe. RIH w/2-78"tubing while clamping damaged ESP to string for"dummy run"to±500'. POH LD 2-78"tubing watching carefully for additional damage on ESP cable. None observed.Change over handling equipment to 3-1/2",PU 3-1/2" Muleshoe. RIH w/3-1/2"CS Hyd.to±2,230'(75 jts). MU storm packer per HES Rep. RIH 5 joints to spotting mid element at 156'.Set Storm Packer w/1/2 RH turn per HES Rep. Fill hole. Pressure up and test casing f/156'to surface w/2,000psi f/5 min. Good test. Release packer. Blow down lines. POH LD 5 jts. LD Storm Packer. Continue to POOH w/3- 1/2"CS Hyd work string to surface. P/U ESP completion and RIH to ESP motor. M/U MLE cable and begin clamping to seal assembly's,gas separator, pumps 1 and 2 and the discharge head. Fill seal assembly's with hydraulic fluid as per Centerlift rep. Perform insulation test on motor(9.5 G Ohms and climbing)good test.Test MLE plugged into motor(9 G Ohms and climbing)good test. RIH w/ESP completion on 2- 7/8"6.5ppg EUE tubing down to joint#4(-200'md)and test ESP cable. (Good Test). Continue to RIH down to joint#13 (' 500'md)and test ESP cable. (Bad Test).Try secondary insulation tester and test still failing(1.1 G Ohms and dropping),POOH w/ESP completion on 2-7/8" 6.5ppg EUE tubing from^'500'md to ESP motor. No damage found on ESP cable. ESP cable on splice was loose all over the splice and rolled back slightly in two areas.Test ESP cable above splice(Failed Test)and then below splice on MLE cable(Failed Test).Test ESP motor at the MLE connection (Passing Test). Remove MLE cable and test(Failing Test). No damage to completion components found,Order new MLE cable from Centerlift shop in Deadhorse. Rig crew clean and organize rig. 11/21/ 6 M,ondy ill`` Continue to wait on MLE from Deadhorse. Rig crews performing maintenance/cleaning on rig. Prepping XO subs and other equipment for inspection during shut down period. NOTE: MLE arrived on location.Wrong MLE for our type of motor.Centrilift Rep returned to Deadhorse and retrieved the correct MLE.Splicing MLE to ESP cable. LD top section of ESP pumps. Leave Motor hanging. Rig up to test BOPE. Install test plug. Perform 250psi low,3,500psi high Shell Test on BOPE to insure no leaks prior to AOGCC Rep.arriving(Good Test).AOGCC was notified of upcoming test and elected to witness.Test BOPE per PTD and ASR 1 procedure.Test w/2-78"test joint. 1st test Blinds,Choke valves# 12,14&16(Good test).Test 2: Pipe rams, IBOP, Cl& K1(test failed). Begin isolating and looking for small leaks. Pull test plug. Change seals &wrap with Teflon. Install test plug. Rebuild Valves#C2&#4 manual. Grease all choke& BOP valves. Re pack Gland nuts on wellhead. • • Hilcorp Alaska, LLC Weekly Uncoil;Alaska.LIC Operations SUrnmary Well Name Rig API Number Well Permit Number Start Date End Date MPU L-39 ASR 1 50-029-22786-00-00 197-128 11/13/2016 11/24/2016 1.1/22J16-70escfay �� To To �„ �p e: 6' ' ' �` ,4,': Continue chasing small leaks during BOP test. Determined that the test plug was still leaking after installing new seals.Seals were WKM and not FMC(a little different). Pull test plug. Re-install original FMC seals.Cover seals with graphite and Teflon tape. Install plug and dump bentonite on top.Test BOPE per Sundry and ASR 1 procedure.Test all components to 250psi low,3,500psi.Test annular to 250psi low, 2,500psi high. Use 2-78"test joint.All tests held for 5 min each.All tests charted. Perform Choke bleed down test. Perform Accumulator draw down test.AOGCC Rep.Guy Cook was present to witness all tests. Pull test plug. LD test joint. RD test equipment. RU to run 2-78" ESP completion. PU centralizer,Sensor,CL5 motor, lower& upper seals,separator, 2 pumps&discharge head w/pup to 92'.Test conductivity. Good test. Install "Gator Splice Clamp"across splice(Measured 5 1/2"OD overall). PU first 2 joints of 2-78"tubing and submerge splice.Test Conductivity.Good test. RIH w/ESP on 2-78"tubing. Place 1 Heat Trace/Cable Clamp on every mid joint and 1 cross-collar clamp every joint.Test ESP cable for conductivity after'500'md (joint#13).Test failed to carry proper voltage through ESP cable.Centerlift lead hand arrive on location and re-test.Same failing results.Call Ops engineer and discuss plan forward. Decision to POOH w/ESP completion on 2- 7/8"tubing f/joint#13 to surface and investigate ESP failure. Cut ESP cable above splice and test cable back to motor(failed test).Test ESP cable on the reel in the spooler to the cut end of ESP on the floor(passing test).Cut ESP below the splice and test(failed test).Continue to POOH with ESP and L/D completion. R/D ESP equipment and support tools. Roads and Pads on location to move spooler to A pad. Back Halliburton slickline into position and prepare to R/U for caliper run. Perform PJSM w/Halliburton crew, M/U caliper log BHA and prepare to RIH. Caliper log set to open prematurely, remove from BHA and reset. RIH w/PDS caliper BHA on Halliburton slickline f/surface to ' 12,000'md. RIH @ 150fpm, POOH w/caliper at 50fpm as per PDS rep. • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-39 ASR#1 50-029-22786-00-00 197-128 11/13/16 11/24/16 Daily Operations: 11/23/26/2016-Wednesday Continue to log up w/40 arm caliper log at 50 fpm to surface. RD Slickline. Perform rig maintenance while waiting on Halliburton Rep & RBP. Off load RBP. Verify lengths. PU to rig Floor. MU RBP to first joint of 2-7/8" EUE per HES Rep. RIH w/ RBP on 2-7/8" 6.5#EUE tubing from surface to 11,970'md. Set RBP at 11,970'md. L/D 4 joints of 2-7/8" 6.5# EUE TBG. 11/24/2016-Thursday Continue attempting to set RBP. Initially was a partial set. Dragging up hole but able to set weight down. Install 11 turns right to engage packer& release same. PUW 52k-SOW 22k. LD 3 joints to 11,780'. Work LH torque downhole. Set down to confirm packer set. PU to 60k (8k overpull)to confirm not dragging up hole. Install left hand turn to release running tool f/ packer. Work pipe to up wt. & back down several times setting all weight on packer. Pipe pulled free but lost 12k up wt. Appears to have backed off tubing. Calculations indicate tubing backed off @ ±1,850' above packer. LD 1 joint. Fill hole. Close rams.Test casing f/ 11,874' (C.O.E.)to surface w/ 1,000 psi f/ 10 min. Good test. Confirmed RBP is set& holding. Estimated depth of backed off pipe is: 10,020'. Bottom of RBP at 11,878'.Top of total packer assembly(including running tool &XO) @ 11,865'. LD 2 joints leaving a total of 384 in the hole. PU hanger. Install BPV. Land hanger RILDS.Test hanger from below to 1,000psi f/ 10 charted min. Good test. Pull BPV. Line up Little Red to pump down IA. Test lines to 3,000psi. Pump 90bbls diesel down IA taking returns out tubing to pits. RD Little Red. Line up & U-tube diesel. Allow to U-tube while continuing to RD & prep for move to F-38. Vac fluids out of pits &cuttings tank. Set BPV. Set Boat. (Release Rig at 1600 hrs. Disconnect gas alarms, Rig down Certek Heater Equipment. Blow down and Disconnect all Service Lines, Nipple down bop stack to Four Bolts, unpin Top Section Lower Derrick onto Carrier, Move ASR Rig to VMS Shop,Alaska Crane on Location Remove Rig Floor, Well House, Load on NES Trailer, Hauled Company man and Change house Trailers,Tool Pusher Shack, to F-Pad Finish Nipple Down Bop Stack Load Equipment on Trailer, Nipple up Tree,Test Hanger Void 5,000psi, (Good Test) Pull BPV, NES Hauled Pit module and Drilling Equipment F/L-39 to F-38 Clear and Clean Location. 11/25/2016- Friday No activity to report. 11/26/2016-Saturday No activity to report. 11/27/2016-Sunday No activity to report. 11/28/2016- Monday No activity to report. 11/29/2016-Tuesday No activity to report. • • M PLic t97 rzeo Regg, James B (DOA) From: Cody Rymut - (C) <crymut@hilcorp.com> Sent: Tuesday, November 22, 2016 10:51 PM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Subject: BOPE Re-Test Report for MPL-39 Attachments: Hilcorp ASR1 11-18-16.xlsx Attached is the test report for when we re-tested our Annular element, choke valves#12,14,16, and the Floor valve. These components were used to shut in the well when flow was observed while tripping out of hole on MPL-39. Please let me know if you have any further questions. Thanks, Cody Rymut WSM, ASR#1 Hilcorp, Alaska C: 907-230-3594 crymut@hilcorp.com cmitiED ATV, 2 02.017 • • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: jim.regqaalaska.gov AOGCC.Inspectors a(�.alaska.gov phoebe.brooks a(�.alaska.gov Contractor: Hilcorp - Rig No.: ASR 1 DATE: 11/18/16 Rig Rep.: Darrell Bledsoe Rig Phone: 907-310-0887 Operator: Hilcorp Alaska Op. Phone: 907-310-0243 Rep.: Cody Rymut E-Mail crymut@hilcorp.com Well Name: MPU L-39 - PTD# 197-128 . Sundry# 316-557 Operation: Drilling: Workover: X Explor.: Test: Initial: Weekly: Bi-Weekly: Test Pressure(psi): Rams: 250/3,500 Annular: 250/2500 Valves: 250/3,500 MASP: 2912 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen. NT Well Sign NT Upper Kelly 0 NA Housekeeping NT Rig NT Lower Kelly 0 NA PTD On Location NT Hazard Sec. NT Ball Type 1 . P Standing Order Posted NT Misc. NA Inside BOP 1 NT FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 - 11 P - Pit Level Indicators P - NT #1 Rams 1 2 7/8"X 5" NT Flow Indicator NA NA #2 Rams 1 Blinds NT Meth Gas Detector P NT #3 Rams 0 NA H2S Gas Detector P NT #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln.Valves 1 2 1/16" NT Inside Reel valves 0 NA HCR Valves 1 2 1/16" NT Kill Line Valves 2 2 1/16" NT Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure(psi) 0 NT CHOKE MANIFOLD: Pressure After Closure(psi) 0 NT Quantity Test Result 200 psi Attained(sec) 0 NT No.Valves 3 - P - Full Pressure Attained(sec) 0 NT Manual Chokes 1 NT Blind Switch Covers: All stations NA Hydraulic Chokes 1 NT Nitgn. Bottles#&psi(Avg.): 0 NT CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 0 Test Time: 4.0 Hours Repair or replacement of equipment will be made within days. Notify the AOGCC of repairs with written confirmation to:AOGCC.Inspectors@alaska.gov Remarks: This was a re-test of equipment that was used to shut in well MPL-39 when we observed flow while tripping out of the hole.We re-tested the Annular element w/a 2-7/8"test joint to 250psi low, 2500psi high for 5 charted minutes each, and also tested the choke valves that were used to shut in the well, chokes#12,#14, and#16 and the Floor Valve to 250psi low 3500psi high,for 5 charted minutes each. AOGCC Inspection 24 hr Notice Yes Date/Time 9:47 11/17/16 Waived By Matt Herrera Test Start Date/Time: 11/18/2016 2:00 (date) (time) Witness Test Finish Date/Time: 11/18/2016 6:00 Form 10-424(Revised 11/2015) Hilcorp ASR1 11-18-16.xlsx Prn tc ►21;0 Regg, James B (DOA) From: Cody Rymut - (C) <crymut@hilcorp.com> . `�(;4 (( ( I 514, Sent: Thursday, November 17, 2016 9:10 AM �� ` To: Schwartz, Guy L (DOA); Regg, James B (DOA); DOA AOGCC Prudhoe Bay Cc: Rob Handy; Paul Chan; Bo York Subject: Notice of BOPE Usage MP L-39 Attachments: Notice of BOP Usage ASR#1 Well L-39.docx Attached is a detailed description of operations leading up to utilization of the ASR#1 BOPE on well MPL-39 and the action taken to increase the working fluid brine weight. Please contact me for any further details. Cody Rymut WSM, ASR#1 Hilcorp, Alaska C: 907-230-3594 Rig: 907-310-0243 crymut@hilcorp.com MED " JUN 0 82,017 • S Notice of BOP Usage Date/Time of usage: 11/16/16 18:30 Well/Location/ PTD: Milne Pt Unit KR L-39 Milne Point L pad, 197-128 V Rig Name:ASR#1 Operational Contact: Cody Rymut/Don Haberthur Operational Summary: On 11/13/2016 the ASR#1 moved onto well L-39 to perform workover operations.The well was killed earlier that day by performing a surface to surface circulation (525bb1s) with 10.2ppg kill weight fluid which resulted in the well going on a vacuum. A back pressure valve was then installed in the tubing hanger prior to the rig arriving on location. The ASR# 1 began rigging up on 11/13 and continued to rig up over the well until the morning of 11/14. The rig crew monitored the IA pressure while rigging up to ensure the well was still under control hydrostatically. Once rigged up over the well, there was no pressure seen on the IA and when the BPV was pressed open, there was no pressure seen on the tubing.The well was no longer on a vacuum but remained stagnant.The BPV was then removed and replaced with a TWC in order to test the BOPE. Once BOPE tests were complete the annulus pressure was verified to be Opsi and the TWC was pressed open to verify there was no pressure beneath it on the tubing.The well still remained stagnant so,the TWC was then removed and the ASR# 1 began the process of removing the 3.5" TBG from the jet cut made by E-line at 12,015'md. Tubing was pulled from 11/14 until the morning of 11/15. While pulling out of hole with the 3.5" tubing the well was able to take proper hole fill (1.5bbls/15jnts of tubing) and remained dead once out of the hole. Later on 11/15 the ASR#1 picked up cleanout BHA#1 consisting of a mule shoe and 7" scraper assembly and began to run in the hole on their 3.5" wark string. BHA#1 was ran in the hole from 11/15 until early in the morning on 11/16. While running in hole, very limited returns were seen at surface compared to the metal displacement that was being run in the hole (Only 5 bbls returned to surface compared to 40bbls of metal displacement placed in the hole). Overall the well lost 35bbls of fluid as the cleanout BHA was ran down to 12,015'md. Once on bottom in the morning of 11/16 the ASR#1 reverse circulated 1 bottoms up (110bbls) at 3bpm and 800psi watching for dirty returns.All returns were clean, so the rig crew shut down their pumps and monitored the wellbore.The well appeared to be out of balance or slightly ballooned due to the pressure from reverse circulating because when the pumps were turned off, the wellbore continued to flow slightly.The flow was observed and quickly began to reduce to a trickle over a time frame of 5min. Total flow back is estimated to be less than 1bbl. After the well was determined to be stable the rig crew began to trip out of hole with BHA#1. After 30jnts were pulled out of the hole,the assistant driller noted that we were only able to fill the hole with lbbl instead of the 3bbls of calculated metal displacement. When looking down the tubing the fluid level had dropped from site, so it was assumed the wellbore was still slightly out of balance and U-tubing into the annulus from the tubing.After • another 30jnts were pulled the wellbore annulus needed less than lbbl to fill. Driller notified the Co Rep that there was a discrepancy in the hole fill.The pit system was strapped to verify sensors were working correctly and a manual strap was then used to verify all pit sensors were correct.The well was not flowing at this time, but the trip displacement was off. Crew change occurred as this was being investigated. Day crew came on and the decision was made to pull a few more joints and watch the hole level as they were being pulled. The well appeared to have a slight gain as pipe was pulled, but not enough to run over into the pit system.The decision was then made to circulate a bottoms up through the mud gas separator(250bbls) and observe the well. Once the circulation was complete, the pumps were turned off and the well was monitored.The fluid volume in the wellbore was very slowly rising and continued to slowly rise at a consistent rate.The decision was then made to run back in hole to bottom and weight up our fluid system to a 10.4ppg brine. BOPE Used: Once on bottom (12,015'md)the annular element was closed and a bottoms up circulation was performed with 320bbls of 10.2ppg mud from the pits. All pits were weighed prior to circulation and verified to be 10.2ppg The rig crew weighed the returns every 20bbls for the duration of the bottoms up and noted a range of fluid densities. 75%of the weighed returns were 10.1ppg, 12.5%were 10.0ppg 12.5%were 10.2ppg. Once circulation was complete the pumps were shut down and the well was shut in as per standing orders. Choke valves#12, # 14 and #16 were closed to shut in the annulus side, and pump valve# l shut in to close in the tubing, and both IA and tubing pressures were recorded. Initial tubing pressure was 120psi and initial annulus pressure was 110psi but slowly bled down to 75psi and 55psi over the duration of 3hrs while waiting for our 10.4ppg fluid to arrive on location. Actions taken: Rig crew performed a wait and weight method well kill with 10.4ppg kill weight fluid circulating a surface to surface volume of 10.4ppg fluid. Once kill weight fluid was circulated around the wellbore, the well was shut in as per standing orders and pressures were recorded.The well was dead upon completion of circulation. Rig crew monitored the well for 30mins before opening the well and beginning to trip out of the hole. Once out of the hole with BHA#1 we will test all BOPE components used during the operation. • \�1 1/y7,7 N THE STATE Alaska Oil and Gas of Conservation Commission 333 West Seventh Avenue lir►.- GOVERNOR BILL WALKER Anchorage, Alask907. 299501-3572 79-3433 � 3 L, S� Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager � � �� Hilcorp Alaska, LLC SCANNED 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU KR L-39 Permit to Drill Number: 197-128 Sundry Number: 316-557 Dear Mr. York: 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 Foerster Chair DATED this Z day of November, 2016. RBDIVIS NOV - 2 2016 • 0 RECEIVED STATE OF ALASKA 0 . 2 20 6 ' 7 ALASKA OIL AND GAS CONSERVATION COMMISSION ' 1t(4/1‘ APPLICATION FOR SUNDRY APPROVALS AUL L L 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑✓ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Q Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Convert to ESP ❑✓ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑s 197-128 3.Address: 3800 Centerpoint Dr,Suite 1400Stratigraphic ❑ Service ii 6.API Number: Anchorage Alaska 99503 50-029-22786-00-00 - 7. If perforating: Ai,6 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432( Will planned perforations require a spacing exception? Yes ❑ No ❑ ( MILNE PT UNIT KR L-39 - 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0025514 MILNE POINT/KUPARUK RIVER OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): . 12,740' • 7,401' • 12,634' • 7,305° N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 114' 114' N/A N/A Surface 8,613' 9-5/8" 8,649' 4,165' 5,750psi 3,090psi Intermediate 12,684' 7" 12,717' 7,380' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic I See Attached Schematic 3-1/2" 9.3#/L-80 f EUE 12,332 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 4-1/2"Baker S-3 Perm Packer and N/A ' 12,296'MD I 7,006'TVD and N/A 12.Attachments: Proposal Summary Q Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development❑., Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 11/11/2016 WDSPL ❑ ❑ ❑ Suspended ❑ Commencing Operations: OIL WINJ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved ,.----2--;;:„. herein will not be deviated from without prior written approval. Contact Paul Chan \ Email pchanCa7,hllcorp.com Printed Na e Bo York Title Operations Manager 11 / 40,04W3 /10/1c.. Phone 777-8345 Date /O! 4Z Signatu 0 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: _ ^7 Plug Integrity ❑ BOP Test Mechanical ®Integrity Test Location Clearance ❑ Other: .t 3 Sw 10..i... 40I f•e 1--- x r t5 P Pie'-- eR-3 -i;re-9 yc.. L ce 314A Post Initial Injection MIT Req'd? Yes ❑ No ❑ --- Spacing Exception Required? Yes ❑ No rei Subsequent Form Required: ia..11041 RBDMS 1,1-- A'n,/ _ 2016 $6.7 / APPROVED BY NOV Approved by: �./ ��G//_ COMMISSIONER THE COMMISSION Date: /l Z_ -/14.6 1ci3j/IS- ( //j. /( ),L,„ t(-1-1c, n e Submit Form and Form 10-403 Revised 11/2015 A®pReI iiafJ iAI1 for 12 months from the date of approval. Attachments in Duplicate • • Well Prognosis Well: MPU L-39 Hiknrn Alaska. a. Date: 10/28/2016 Well Name: MPU L-39 API Number: 50-029-23040-00 Current Status: SI Oil Well [Failed JP] Pad: L-Pad Estimated Start Date: November 11th, 2016 Rig: ASR 1 Reg.Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 197-128 First Call Engineer: Paul Chan (907) 777-8333 (0) (907)444-2881 (M) Second Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228 (M) AFE=Number: = 1653114 Job Type: Convert to ESP Current Bottom Hole Pressure: 3,612 psi @ 7,000' TVD (SBHPS 10/26/2016/9.94 ppg EMW) Maximum Expected BHP: 3,612 psi @ 7,000' TVD (No new perfs being added) MPSP: 2,912 psi (0.1 psi/ft gas gradient) Brief Well Summary: MPU L-39 was originally completed as an injector in an isolated fault block with no off-take points. The well had a short injection life, from mid-1998 to 1999. Cumulative injection is 58 Mbw and 20 MMscfd. The current estimated reserves are 1.01 MMbo with 0.66 MMbo within the A2/A3 sands. A previous attempt at free- flowing the well to tanks was conducted in October 2002 as part of a tracer/low salinity pilot,only managing to produce a rate of 190 bfpd. A"poor boy"jet pump design was attempted in 2008, but failed to produce after the packing was blown during f the first attempt to lift the well. Following attempts were cancelled after not being able to get a good jet pump set. In 2014, BP decided to try another attempt at'poor boy'jet pump lift and include an A-sand fracture as part of the project. In September 2014,the original tubing punches from 2008 were patched and the frac job pumped away 59,000lbs of 20/40 Carbo Bond frac proppant behind pipe before screening out(design was for 150-200 M lbs). The well was put on production 11/28/14 with the new poor boy jet pump design, but the packing failed after—5.5 hrs of production. At the time of failure,the well was at—90%WC and declining. In 2015, a thru-tubing jet pump was installed by punching the tubing and straddling the holes with packers and a small diameter jet pump. The well came on with a high water cut (>95%) and was losing power fluid (water) and the well was shut-in. Notes Regarding Wellbore Condition • The 7" production casing was tested to 4,200 psi on 9/12/2014 down to 12,296' MD. • Per CO 39 A, an ESP packer will be run v Objective: Convert well from jet pump to ESP. Pre-Rig Procedure: 1. RU wireline. PT PCE to 1500 psi (SITP=^'700 psi on 10/26/2016) 2. RIH and cut tubing at 12,205' MD (in the middle of the second joint above the 3-1/2" X profile at 12,250' MD). Do not cut the joint at a connection. to"';"1 . 11 0 • Well Prognosis Well: MPU L-39 Hilcorp aiv5ka.IA: Date: 10/28/2016 3. POOH and RD wireline. 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. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 7. Pressure test lines to 3,000 psi. 8. Circulate at least one wellbore volume with 10.2 ppg NaCI/KCI down tubing, taking returns up casing to 500 bbl returns tank. 9. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 10. RD Little Red Services and reverse out skid. 11. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 12. NU BOPE house.Spot mud boat. Brief RWO Procedure: 13. MIRU Hilcorp ASR#1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 14. 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/±10.2 ppg NaCI/KCI prior to pulling BPV. Set TWC. 15. Test BOPE to 250 psi Low/3,500 psi High, annular to 250 psi Low 2L500.psiHJg: h„(hold each -_,I,4` ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. AG' a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. b. Notify AOGCC 24 hours in advance of BOP test. 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. 16. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) 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 " 1( c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor ,,fr 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.) �f. 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. 17. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/±10.2 ppg NaCI/KCI as needed. 18. MU landing joint or spear and PU on the tubing hanger. - • • Well Prognosis Well: MPU L-39 Hilcorp Alaska.LI) Date: 10/28/2016 a. The PU weight during the 1998 completion was 115K lbs. (block weight not noted) b. If needed, circulate (long or reverse) pill with lubricant prior to laying down the tubing hanger. c. Contingency,CasingJackProcedure If the tubing hanger will not come off seat after circulating lubricant, RU casing jacks as follows: i. PU Casing Jacks via the beaver slide and Tugger winches to rig floor ii. Set casing jacks on top of the BOP Annular with Tuggers. Connect Hydraulics and function test same. iii. RU Casing jack Hydraulics to the ASR#1 control Panel. Set pressure relief high point iv. 100%Yield strength of 3-1/2",9.2#, L-80=207K lbs v. Cycle jacks up and down to ensure proper function (dry run without being connected to hanger). 19. Recover the tubing hanger. 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. 20. POOH and lay down the 3-1/2"tubing. Number all joints. Tubing may be inspected and re-used. a. Mark all bad joints of tubing for disposal. 21. PU & RIH with 7" 26#scraper assembly to—12,150' MD on 3-1/2" workstring. Reciprocate scraper across packer setting depth of 2500' MD. Circulate the well clean. 22. POOH. L/D scraper assembly and 3-1/2" workstring. 23. PU new ESP and RIH on new 2-7/8" tubing. Set base of ESP at± 11,260' MD. a. GLM #3 @ ± 140' MD w/SO b. ESP Packer w/annular vent valve @ ±2,500' MD c. X profile @ ±2,550' MD w/RHC ball catcher d. GLM #2 @ ±2,600' MD e. GLM #1 @ ±11,150' MD f. 2-7/8" XN Nipple @ ±11,200'MD g. Base of ESP @ ± 11,260' MD 24. Land tubing hanger. RILDS. Drop ball/rod and set ESP packer. 25. Freeze protect IA. Note: This step may be done as part of the post-rig procedure. 26. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off)weights on tally. 27. Set BPV. Post-Rig Procedure: 28. RD mud boat. RD BOPE house. Move to next well location. 29. RU crane. ND BOPE. 30. NU 2-9/16" 5,000#tree/adapter flange and test to 500 psi low/5,000 psi high. Pull BPV. 31. RD crane. Move 500 bbl returns tank and rig mats to next well location. 32. Replace gauge(s) if removed. 33. Turn well over to production. RU well house and flowlines. • Well Prognosis Well: MPU 1-39 Hilcora Alaska.LI.i Date: 10/28/2016 Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Existing Tree/Wellhead 4. BOPE Schematic 5. FWD Circ to Kill Tank Flow Diagram 6. REV Circ to Kill Tank Flow Diagram 7. Bleed to Pits Flow Diagram 8. Blank RWO MOC Form • • Milnll:e PoiMPtin nt Unit We SCHEMATIC Last Completed: 4/23/2015 flacon„Alaska,LLC PTD: 197-128 TREE&WELLHEAD Tree 5M Cameron 3-1/8" Orig.KB Elev.:34.3' Wellhead FMC 11"x 11"5M Gen 5 w/11"x 3.5"FMC Tbg.Hngr.w/NSCT threads top and bottom and 3"CIW H BPV Profile OPEN HOLE/CEMENT DETAIL 20 20" 250 sx of Arcticset I(Approx)in 24"Hole 9-5/8" 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole • 7" 275 sks Class"G"in 8-1/2"Hole 1 CASING DETAIL • R Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 114' 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface 8,649' 7" Production 26/L-80/NSCC 6.276 Surface 12,717' TUBING DETAIL 3.5" Tubing 9.3/L-80/EUE Mod 8rd 2.992 Surf 12,332' JEWELRY DETAIL • No Depth Item 1 2,006' 3.5"HES X Nipple(2.8131D': 2 12,201' 3.5"ER Packer(Fished 10/26/16) 3 12,220' Jet Pump(Fished 10/26/16) 4 12,227' 3.5"Permapac Packer 5 12,250' 3.5"HES X-Nipple(2.813 ID) 9-5/8" 6 12,296' 3.5"Baker SB-3 Packer 7 12,320' 3.5"HES XN Nipple(No Go 2.750 ID) 8 12,332' 3.5"Otis WLEG PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open WELL INCLINATION DETAIL KOP @ 300'to 4,500' Max Hole Angle=78 deg. 2 Max Hole Angle through perforations=27 deg. 10/14/Punch STIMULATION SUMMARY 3 :'4 *' 10/14/14:1Z212'to 12,214' Kuparuk"A"Sand:59,0008 of 20/40 4 Carbo Bond frac proppant behind pipe. . w Holes Shot 9/28/08 GENERAL WELL INFO . 12,246.5'to API:50-029-22786-00-00 5 12,248.5'ELM. Drilled and Cased by Nabors 27E -6/29/1997 3.5"Injection Completion by Nabors 27E—7/1/1998 Set Owen Oil Tools ' Conversion to Jet Pump —10/16/2014 X-Span 2.715"x 24" Irt Convert to Producer-4/23/2015 Patch©12,233.5'to Ira 6 12,256.1',Min ID 2.25"—9/12/2014 7 3, 8 7"% &8&9 TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Revised By:TDF 10/4/2016 and PC 10/27/2016 • Milnll:e PoiMPUnt Unit We • PROPOSED Last Completed:4/23/2015 Hilcorp Alaska,LLC PTD: 197-128 TREE&WELLHEAD Tree 5M Cameron 3-1/8" Orig.KB Elev.:34.3' Wellhead FMC 11"x 11"5M Gen S w/11"x 3.5"FMC Tbg.Hngr.w/NSCT ,, kthreads top and bottom and 3"CIW H BPV Profile 1 y� OPEN HOLE/CEMENT DETAIL 2011 V it 20" 250 sx of Arcticset I(Approx)in 24"Hole LI 1 9-5/8" 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole A 7" 275 sks Class"G"in 8-1/2"Hole 4a r+e CASING DETAIL 10 Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 114' ,[ ,r 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface 8,649' V 7" Production 26/L-80/NSCC 6.276 Surface 12,717' � � TUBING DETAIL li 2 2-7/8" Tubing 6.4/L-80/EUE Mod 8rd 2.441 Surface ±11,260' ' 3 JEWELRY DETAIL ak ;f: No Depth Item o 4 l' 1 ±140' GLM STA#3:2-7/8"x 1"GLM & 2 ±2,500' ESP Packer w/Annular Vent Valve =t t 3 ±2,550' X profile w/RHC ball catcher 4 ±2,600' GLM STA#2:2-7/8"x 1"GLM 5 ±11,150' GLM STA#1:2-7/8"x 1"GLM O." 1 9 5/8" 6 ±11,200' 2-7/8"XN-Nipple(2.205"No-Go) 5 7 ±11,260' Base of ESP Left in Hole Detail 8 12,205' 3-1/2"Cut Joint 6 9 12,227' 3.5"Permapac Packer 10 12,250' 3.5"HES X Nipple(2.813"ID) 11 12,296' 3.5"Baker SB-3 Packer 7 12 12,320' 3.5"HES XN Nipple(No Go 2.750"ID) 13 12,332' 3.5"Otis WLEG PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open WELL INCLINATION DETAIL V 8 KOP @ 300'to 4,500' 9 Max Hole Angle=78 deg. Holes Shot 9/28/06 Max Hole Angle through perforations=27 deg. 12,246.5'to t 4 1112,248.5 ELM. STIMULATION SUMMARY to , 11 Kuparuk"A"Sand:59,000#of 20/40 � Carbo Bond frac proppant behind pipe. Set Owen Oil Tools ; 12 p pp p p Patch@ 12,2335't :[ GENERAL WELL INFO Patch�12,233.5'to 12,256.1',Min ID= 4 3 4,4 API:50-029-22786-00-00 2.25"-9/12/2014 1! Fi Drilled and Cased by Nabors 27E -6/29/1997 4 % ,..)13.5"3.5"Injection Completion by Nabors 27E-7/1/1998 I ) Conversion to Jet Pump -10/16/2014 tl 10. Convert to Producer-4/23/2015 u 7"4 . . TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Revised By:Dinger 10/28/2016 Current Tree/Wellhead • • BHTA,Otis,3"5M ubing hanger,FMC 7 X 3 1/2&3"type H BPV f <" profile 4"LH acme thread Top/2 7/8 EUE 8rd thread rn I Icr-rt Bottom Iii 0 0 Valve,Swab,CIW, 0_ . 3 1/8 5IVI HWO --- - '- 1., 1 r _ 711 IV 1711 N . 1 MO . ,... , . 1,.,...,-, I .... ,,,.. 87.7;-..._,-____„......„ 1- q>, 01 1-6, Valve,SSV,CIW, ?-•-• "iz- 3 1/8 SM FE,Baker oper, ( ) Ns..,_ -1'0 ..... „.4 III Valve,Master,CIW, z 31/8 SM HWO,DD '...-...-..... 6"i-13"0' Adapter,FMC A-5-EC, . 7"51v1 rot flg btm X 2 9/16 SM stdd top, imi .,..1.. WIif .11_11 ll 11-X 7"Tubing head,FMC Gen SA :IV- MI Mill =IM I Ill 'II All casing valves 2 1/16 5M ..--------- , (''''.-c:, (—""'..--• i I) ,i 0ii-i.ii Li& • ® :4; :i: 0 . i Casing head,FMC 11"Flg MINN 4 :i= — TopMir i -MT: i. III k 1,- ,rui II ,,,,,,-01 • , „---„:„.,_:„ ,.„; 1 : -'7' I'44* -!•',.eiNi 0..) 1,1114rio.'w i; - ... illU fill) NI .... , ..,, - , - All casing valves 2 1/16 5M _ _ 4 0 Proposed • BHTA,Otis,2 9/16 5M f ' i • MP L-39 Tubing hanger,FMC 7 X 2 iti I 7/8&2Y"'type l4BPV Q profile 3"LH acme thread Valve,Swab,CIW, Top/2 7/8 EUE 3rd thread 2 9/16 5M HWO a n; Bottom co Q v I*I hod ctt II v (Ai La Valve,SSV,CIW, + `�0 2 9/16 5M FE,Baker aper, I 9•co, �'q se`s��7^v l Yl' is, r li Valve,Master,OW, "-'�2 2 9/16 5M HWO,DD '— :ais, 0 III:.:_ Ill _ LI Adapter,FMC A-5-EC, 7"5M rot fig btm X 2 9/16 SM stdd top, '4. " , 1�I , 11"X 7"Tubing head,FMC , l Gen 5 _r;i MI ....... _ r >t s_ Iii IV I!, w _ 4 I r;�;'., -. . M' AL, f NIl_ i 4 .l Casing head,FMC 11"Fig - All casing valves2 1/16 SM Top � MEMI III - I M : IF ,w--- 4.1 , ia. .i- 111I� . � �! I r • I I ` I' I.1°'1 All casing valves2 1/16 5M • M•Point . 2015 ASR Rig 1 .t �. 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N Z « '" 4 a F LI yR Y '`A " 6 u u , C m i; J m En 1 H 7Y o m a H In X Y� Y Q O 0 Z 2 Y 98 Y • R �—J •«4 .«4 —H M Y • I § 1 EH { } a I^ w F zn Q d ' F- Fjl��--�j(`{�`M }1x{ y}1((c u c 0 t • S c d r a) .> ns E ca OOV ca = O CQ a a) = � Qa E E. E cr' Oma. 'a N Uc d O a) Y > ADE < 2 E = O 20.- T E Q A a) c L n 0 a) Y m rr Q Mo_.5 = d v N CS°LL2 I.V M cor o aa co0 co c O R Cr)-C C U RI N ..0 _c U CD L o 0 75 L Q V 0) -0 Q Q M > f0 a) L J O c C as t§ U a _ m m ccU c s L .,0 N Q O L O i EN d O U O O d 'm ia)2 a) S 0 U CX '0 w cu o f C� LQ. N Q ai o s E 2 as W Ci) CV d O 3 O O ta 0 .Q cl C CO cc i cc y.r O a) a) d d v • 0 U > Q) x a) Ev ° Cu t °' CO _ _ 5, �i0 o vn v Q °Q n • • Schwartz. Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Tuesday,June 07, 2016 1:56 PM To: 'Tom Fouts' Cc: Stan Porhola;samantha.carlisle@alaska.gov Subject: RE: Request to Withdraw Sundry#315-466/PTD 197-128 Tom, AOGCC will withdraw approved sundry 315-466 as requested. Regards, Guy Schwartz � � JAN 0 9 2057. Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Tom Fouts [mailto:tfoutsPhilcorp.com] Sent:Tuesday, June 07, 2016 1:44 PM To: Schwartz, Guy L(DOA) Cc: Stan Porhola Subject: Request to Withdraw Sundry # 315-466/ PTD 197-128 Guy, Hilcorp Alaska LLC requests to withdraw sundry number 315-466 for MP L-39. Thanks, Tom Fouts l Senior Ops/Reg Tech Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907) 777-8398 Mobile: (907) 351-5749 RBDMS 4 2016 .OF TAri Alaska Oil and Gas THE STATE �'� 115 0 Conservation Commission 333 West Seventh Avenue 'sem GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 \Th- "' Main: 907.279 1433 OF ALAS�� Fax 907 276 7542 iCANt° www aogcc.alaska.gov Stan Porhola Operations Engineer ai, 19.„q Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU KR L-39 Sundry Number: 315-466 Dear Mr. Porhola: 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 414-day / Chair DATED this ` 1 y of August, 2015 Encl. . R CEWED llil_ 3 G ?01') STATE OF ALASKA n 1 0 4l 1S ALASKA OIL AND GAS CONSERVATION COMMISSION AOG CC APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon❑ Plug Perforations ❑ Fracture Stimulate D Pull Tubing D Operations shutdown ❑ Suspend❑ Perforate ❑ Other Stimulate ❑ After Casing ❑ Change Approved Program ❑ Plug for Redrill❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other. Convert to ESRD 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC - Exploratory ❑ Development ch 197-128 - 3.Address: Stratigraphic ❑ Service ❑ 6.API Number. 3800 Centerpoint Drive,Suite 1400,Anchorage AK,99503 50-029-22786-00-00 . 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O.432C Will planned perforations require a spacing exception? Yes ❑ No D MILNE PT UNIT KR 1-39 • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0025514 • MILNE POINT/KUPARUK RIVER OIL' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 12,740. 7,401 - 12,634 • 7,305 • N/A N/A Casing Length Size MD ND Burst Collapse Conductor 80' 20" 114' 114' Surface 8,613' 9-5/8" 8,649' 4,165' 5,750psi 3,090psi Intermediate 12,684' 7" 12,717' 7,380' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80/EUE 12,332' Packers and SSSV Type: 4-1/2"Baker S-3 Perm Packer Packers and SSSV MD(ft)and ND(ft): •12,296'MD/7,006'ND No SSSV No SSSV 12.Attachments: Description Summary of Proposal D 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch D Exploratory ❑ Stratigraphic❑ Development D• Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 8/20/2015 Commencing Operations: OIL ❑ ' WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: N/A GAS 0 WAG ❑ GSTOR ❑ SPLUG 0 Commission Representative: N/A GINJ ❑ Op Shutdown 0 Abandoned ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email sporhola@hilcorp.com Printed Nametan Porhola Title Operations Engineer Signature ! Phone 777-8412 Date 7/30/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 315—y142L Plug Integrity ❑ BOP Test [ Mechanical Integrity Test 0 Location Clearance ❑ Other: 4- 3 061) /OSi /� . ,a 7-sf ( MATS e 2 ` os--6 p s`) Spacing Exception Required? Yes El No Ei Subsequent Form Required: / [ d I / APPROVED BY Approved by: /0r)„,._4,7,/,, COMMISSIONER THE COMMISSION RBDMDate: e-- .?-7.5----- 04 � 7� 1•3•t.( � 7-/-Nbs SU' AUG 1 4 1 015e. /' c Submit Form and Form 10-403 Revised 5/2015 caleaLuAini for 12 months from the date of approval. Attachments in Duplicate Well Prognosis Well: MPU L-39 Hilcory Alaska,LL, Date:7/28/2015 Well Name: MPU L-39 API Number: 50-029-22786-00 Current Status: SI Oil Well [Jet Pump] Pad: L-Pad Estimated Start Date: August 20th,2015 Rig: ASR#1 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 197-128 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: 3,696 psi @ 7,000'TVD (Last BHP measured 11/14/2012) Maximum Expected BHP: 3,696 psi @ 7,000'TVD (No new perfs being added) Max.Allowable Surf Pressure: 1,056 psi (Based on SBHP taken 3/18/2014 and water cut of 50% (0.385psi/ft)with an added safety factor of 1,000' TVD of oil cap) Brief Well Summary: MPU L-39 was originally an injector in an isolated fault block with no off-take points. The well had a short injection life, from mid-1998 to 1999. Cumulative injection is 58 Mbw and 20 MMscfd. The current estimated reserves are 1.01 MMbo with 0.66 MMbo within the A2/A3 sands(A previous attempt at free- flowing the well to tanks was conducted in October 2002 as part of a tracer/low salinity pilot, only managing to produce a rate of 190 bfpd. A "poor boy" jet pump design was attempted in 2008, but failed to produce after the packing was blown during the first attempt to lift the well. Following attempts were cancelled after not being able to get a good jet pump set. In 2014, BP decided to try another attempt at 'poor boy'jet pump lift and include an A-sand fracture as part of the project. In September 2014, the original tubing punches from 2008 were patched and the frac job pumped away 59,000Ibs of 20/40 Carbo Bond frac proppant behind pipe before screening out (design was for 150-200 M lbs). The well was put on production 11/28/14 with the new poor boy jet pump design the packing was blown away after"'5.5 hrs on production.At the time of failure,the well was at'90%o WC and declining. In 2015, a thru-tubing jet pump was installed by punching the tubing and straddling those punch holes with packers and a small diameter jet pump. The well came on with a high water cut (>95%) and was losing power fluid (water)and the well was shut-in. Notes Regarding Wellbore Condition • Slickline to pull the upper packer(12,201') and jet pump (12,220') before moving rig on well. • Slickline to drift tubing thru the lower packer(12,227', 1.75" Min ID)and tag PBTD. Objective: The purpose of this work/sundry is to pull the existing completion and convert the well to an ESP. Brief Procedure: Wireline Procedure Well Prognosis • Well: MPU L-39 Hilcorp Alaska,LL Date:7/28/2015 1. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. 2. RU 1-11/16"Tubing Punch. 3. RIH and punch tubing at+/- 12,285' MD. POOH. 4. RU 1-11/16" Radial Torch. 5. RIH and torch cut tubing at+/- 12,285' MD. POOH. a. Have backup cutters on location if tubing does not part. 6. RD E-line. WO Rig Procedure: 7. MIRU Hilcorp ASR#1 WO Rig. 8. Circulate well with 8.4 ppg lease water down tubing and fill casing. 9. Set BPV. ND Tree. 10. NU 7-1/16" 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 and 3-1/2"test joint. 11. Bleed any pressure off tubing and casing. Pull BPV. 12. MU landing joint and pull 10k tension over string weight on tubing hanger to confirm tubing cut. a. ***Contingency*** If landing joint won't make up to tubing hanger(bad threads). b. MU spear and pull 10k tension over string weight on tubing hanger to confirm tubing cut. i. ***Contingency*** If tubing is not fully cut. ii. LD landing joint/spear. iii. MIRU E-line. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. iv. BOPE connection is 7-1/16"studded top for lubricator on top of annular. v. MU 1-11/16" radial torch. vi. RIH and cut tubing at+/- 12,280'. vii. POOH. RD E-line. viii. MU landing joint or spear. Pull tension to confirm tubing cut. 13. POOH. Lay 3-1/2"tubing on the pipe rack(utilize as workstring). a. ***Contingency*** If unable to cut tubing below XSPAN patch. b. MIRU E-line. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. c. BOPE connection is 7-1/16"studded top for lubricator on top of annular. d. MU 1-11/16" radial torch. e. RIH and cut tubing at+/- 12,225'above 3.5" Permapac Packer f. POOH. RD E-line. g. MU landing joint or spear. Pull tension to confirm tubing cut. h. POOH. Lay down 3-1/2"tubing. i. MU 3.5"OD Cutter BHA. j. RIH w/3-1/2"tubing and make cut at+/- 12,260'. k. POOH. Lay down 35'of fish(3-1/2"tubing w/Permapac and XSPAN patch). I. MU 3.5"OD Cutter BHA. m. RIH w/3-1/2"tubing and make cut at+/- 12,285'. n. POOH. Lay down 25'of fish(partial 3-1/2"tubing joint and partial pup joint). 14. MU 6-1/8" burn shoe,jars, collars and RIH w/3-1/2"tubing. 15. Burn over packer at 12,296'. Push packer to bottom at 12,634' (302'to tag up on WLEG). 16. POOH. Lay down burn shoe,jars, collars. 17. PU 5-3/4"overshot and jars and RIH w/3-1/2"tubing. 18. Tag packer at+/-12,598'.Attempt to jar packer free. If packer won't move, leave on bottom. • II Well Prognosis • Well: MPU L-39 Hilcorp Alaska,LL Date:7/28/2015 19. POOH. Lay down fish if recovered. 20. MU 6.0" mill and 7" casing scraper and RIH to+/- 12,325' (do not go past perfs). 21. Circulate bottoms up x 2 with 8.4 ppg lease water. 22. SOOH. Lay down mill and scraper. Lay down 3-1/2"tubing. 23. PU new 475 series ESP and RIH with new 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). 24. Set base of ESP at+/-12,300' (Pump intake around+/-12,220'). Land tubing hanger. 25. Lay down landing joint.Set BPV. ND BOPE. NU new 2-7/8" 5,000#tree. Pull BPV. 26. Set TWC.Test tubing hanger to 250/5,000 psi.Test tree to 250/5,000 psi. Pull TWC. 27. RD Hilcorp ASR#1 WO Rig. 28. Replace IA x OA pressure gauge if removed (7"x 9-5/8"). 29. Turn well over to production. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic Milne Point Unit Well: MPU L-39 SCHEMATIC Last Completed: 4/23/2015 Ililrorp Alaska,JAC PTD: 197-128 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm Orig.KB Elev.:34.3' 20" Conductor 91.1/H-40/N/A N/A Surface 112' 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface 8,649' 7" Production 26/L-80/NSCC 6.276 Surface 12,717' 20" TUBING DETAIL 3.5" Tubing 9.3/L-80/EUE Mod 8rd 2.992 Surf 12,332' JEWELRY DETAIL , No Depth Item 1 2,006' 3.5"HES X Nipple(2.8131D) 2 12,201' 3.5"ER Packer 3 12,220' Jet Pump • 4 12,227' 3.5"Permapac Packer 5_ 12,296' 3.5"Baker SB-3 Packer 6 12,320' 3.5"HES XN Nipple(No Go 2.750 ID) 7 12,332' 3.5"Otis WLEG PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open WELL INCLINATION DETAIL KOP @ 300'to 4,500' • Max Hole Angle=78 deg. 9-5/8"'a ► Max Hole Angle through perforations=27 deg. STIMULATION SUMMARY Kuparuk"A"Sand:59,000#of 20/40 Carbo Bond frac proppant behind pipe. OPEN HOLE/CEMENT DETAIL 20" 250 sx of Arcticset I(Approx)in 24"Hole 9-5/8" 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole 7" 275 sks Class"G"in 8-1/2"Hole TREE&WELLHEAD 2 Tree 5M Cameron 3-1/8" Tubing Wellhead Punch- FMC 11"x 11"5M Gen 5 w/11"x 3.5"FMC Tbg.Hngr.w/NSCT 3 4 10/14/14:12,212'to threads top and bottom and 3"CIW H BPV Profile ,41•1412,214' • dl 4 GENERAL WELL INFO API:50-029-22786-00-00 s, Hdes Shot 9/28/08 Drilled and Cased by Nabors 27E -6/29/1997 12,248.5'to 3.5"Injection Completion by Nabors 27E-7/1/1998 2.248.5'ELM. Conversion to Jet Pump -10/16/2014 • — 4 Convert to Producer 4/23/2015 Set Owen Oil Tods % AMP (�Ty a X-Span 2.715"x 24" Patch @ 12,233.5'to •, 5 12,258.1',Min ID= 2.25"-9/12/2014 6 [=1 7 7" II\8&9 TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Created By:TDF 5/22/2015 Milne Point Unit Well: MPU L-39 • PROPOSED SCHEMATIC Last Completed: 4/23/2015 Hilcorp Alaska,LLC PTD: 197-128 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm Orig.KB Elev.:34.3' 20" Conductor 91.1/H-40/N/A N/A Surface 112' 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface 8,649' 20"J 7" Production 26/L-80/NSCC 6.276 Surface 12,717' TUBING DETAIL ' 2.875" Tubin 6.5/L-80/EUE Mod 8rd 2.441 Surf 12,100' JEWELRY DETAIL 1. No Depth Item 1 ±200' GLM I 2 ±11,875' GLM ,F 3 ±12,025' 2-7/8"XN Nipple, 2.250 ID O. 4 ±12,036' Discharge Head—FPHVDIS F. 5 ±12,037' Dual Tandem Pump Section—71 Flex 10 SXD(2) . 6 ±12,066' Gas Separator—GRSFTXAR H6 • 7 ±12,071' Tandem Seal Section-GSBDBUT SB/SB PFSA:GSBDBIT SB/SB PFSA 8 ±12,085' Motor—MSP1-250 126HP/2,445 V/31A . 9 ±12,096' 3/8"Stainless Steel External Capstring 1. 10 ±12,096' Sensor/Centralizer—Bottom@±12,100' N'4' 1 .j• d�"h $, 9-5/8".• ► PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open WELL INCLINATION DETAIL KOP @ 300'to 4,500' Max Hole Angle=78 deg. I2 Max Hole Angle through perforations=27 deg. STIMULATION SUMMARY Kuparuk"A"Sand:59,0004 of 20/40 Carbo Bond frac 1 3 proppant behind pipe. OPEN HOLE/CEMENT DETAIL 20" 250 sx of Arcticset I(Approx)in 24"Hole �� 9-5/8" 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole 4 7" 275 sks Class"G"in 8-1/2"Hole 5 TREE&WELLHEAD Tree 5M Cameron 3-1/8" 6 FMC 11"x 11"5M Gen 5 w/11"x 3.5"FMC Tbg.Hngr.w/NSCT Wellhead threads top and bottom and 3"CIW H BPV Profile . 7 GENERAL WELL INFO API:50-029-22786-00-00 • 8 Drilled and Cased by Nabors 27E -6/29/1997 3.5"Injection Completion by Nabors 27E—7/1/1998 10' Conversion to Jet Pump —10/16/2014 Convert to Producer—4/23/2015 .=KUP A2/A3 Sands • 7"• IC TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Created By:STP 7/28/2015 Milne Point 2015 ASR Rig 1 Meng, ��•kM �. Knight Oil Tools BOP 11" BOPE Stripping in Head 4 3.98' Hydril lin G I< 11"-5000,ad my lil iiiIi iYiii di i [1 ITV 4.54' M� CI ® IIiiii - 2 7/8 -5 variables 11 - 5000 • "41111 11 mp - Blind 11.!.: lillaall* JIM 11111 2 1/16 5M Kill Line Valves Aim ill 2 1/16 5M Choke Line Valves 1 ,Z ,j I- - - - - �.illlllillillil '�2.00' � . � , . ; , _ ,; . ,. 11 ,, { (° 1101 ii.iiiiii 1.1 ril Manual Manual MOP Manual HCR Updated 7/23/15 • STATE OF ALASKA RECEIVED AL .CA OIL AND GAS CONSERVATION COI'. iSIOI4 REPORT OF SUNDRY WELL OPERATIONS MAY 2 2 2015 1.Operations Abandon U Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing❑ Gown U Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Convert to Producers 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number: Hilcorp Alaska,LLC Development Q Exploratory❑ 197-128 3.Address Stratigraphic❑ Service ❑ 6.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage AK,99503 50-029-22786-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0025514 MILNE PT UNIT KR L-39 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s). N/A MILNE POINT/KUPARUK RIVER OIL 11.Present Well Condition Summary Total Depth measured 114 feet Plugs measured N/A feet true vertical 114 feet Junk measured N/A feet 12,201, 12,227& Effective Depth measured 12,634 feet Packer measured 12,296 feet 6,920,6,943& true vertical 7,305 feet true vertical 7,004 feet Casing Length Size MD TVD Burst Collapse Structural Conductor Surface Production SCANNED JUN 1 7 2015 Perforation depth Measured depth See Attached Schematic feet True Vertical depth See Attached Schematic feet Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3#/L-80/EUE 8rd 12,332' 7,036' 3-1/2"ER Pckr, 3- 1/2"Permapac& Packers and SSSV(type,measured and true vertical depth) 3-1/2"SB-3 N/A Please See Above 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. 198 40 485 800 210 Subsequent to operation: 197 17 84 3,418 218 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑✓ Exploratory Developments Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil Li Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17 I hereby certify that the foregoing is true and correct to the best of my knowledge Sundry Number or N/A if C.O.Exempt 314-234 Contact Tom Fouts Email tfoutsna hiIcorp.com Printed Name Tom Fouts Title Operations/Regulatory Tech Signature / n•—• Phone 777-8377 Date 5/22/2015 Form 10-404 Revised 5/2015 _'Z D. 1764, Submit Original Only 0;/.,5-- RBDMS MAY 2 9 2015 Milne Point Unit . ii • Well: MPU L-39 SCHEMATIC Last Completed: 4/23/2015 Mean)Alaska,LLC PTD: 197-128 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm Orig.KB Elev.:34.3' 20" Conductor 91.1/H-40/N/A N/A Surface 112' I 9-5/8" Surface 40/L-80/Btrc. 8.835 Surface 8,649' ! + U 7" Production 26/L-80/NSCC 6.276 Surface 12,717' TUBING DETAIL r 3.5" Tubing 9.3/L-80/EUE Mod 8rd 2.992 Surf 12,332' i JEWELRY DETAIL t.. . r No Depth Item 4 1 2,006' 3.5"HES X Nipple(2.8131D) 2 12,201' 3.5"ER Packer i' 3 12,220' Jet Pump 4 12,227' 3.5"Permapac Packer 5 12,296' 3.5"Baker SB-3 Packer 6 12,320' 3.5"HES XN Nipple(No Go 2.750 ID) 7 12,332' 3.5"Otis WLEG PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Kup.A2&A3 12,362' 12,402' 7,062' 7,098' 40 6/27/1998 Open WELL INCLINATION DETAIL KOP @ 300'to 4,500' i:, Max Hole Angle=78 deg. 9 5/8 A 1, Max Hole Angle through perforations=27 deg. STIMULATION SUMMARY Kuparuk"A"Sand:59,000#of 20/40 Carbo Bond frac proppant behind pipe. OPEN HOLE/CEMENT DETAIL 20" 250 sx of Arcticset I(Approx)in 24"Hole 9-5/8" 2,199 sx PF"E",550 sx Class"G"in 12-1/4"Hole 7" 275 sks Class"G"in 8-1/2"Hole TREE&WELLHEAD 2 Tree 5M Cameron 3-1/8" ' Tubing Punch- Wellhead FMC 11"x 11"5M Gen 5 w/11"x 3.5"FMC Tbg.Hngr.w/NSCT 3r:; :. 10/14/14:12,212'to threads top and bottom and 3"CIW H BPV Profile 12,214' I' ' 4 a GENERAL WELL INFO API:50-029-22786-00-00 '_':Holes Shot9/28/08 Drilled and Cased by Nabors 27E -6/29/1997 • 12,246.5'to 3.5"Injection Completion by Nabors 27E—7/1/1998 j 12,248.5'ELM. Conversion to Jet Pump —10/16/2014 4 Convert to Producer—4/23/2015 Set Owen 0il Tools : X-Span 2.715"x 24" i., a Patch @ 12,233.5'to , ' 5 12,256.1',Min ID= ' Lj 2.25"—9/12/2014 ' it 1 6 X E8, i X 1 14 7" 8&9 TD=12,740'(MD)/TD=7,401'(TVD) PBTD=12,634'(MD)/PBTD=7,305'(TVD) Created By:TDF 5/22/2015 Hilcorp Alaska, LLC Ili or,,AIa ka.,.0 Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date MP L-39 50-029-22786-00-00 197-128 4/19/2015 4/23/2015 Daily Operations: 4/15/15-Wednesday MIRU.Pressure test lubricator to 300psi low/2,000psi high.;RIH hole and tag tubing packer @ 12,232. Pull correlation strip up to 11,780'with gamma ray. Contact Geologist and correlate depth using CCL/GR log dated 10/11/2014. RIH and tag tubing packer @ 12,232 and lift packer assembly to 12,227.5' ELM. Adjusted correction puts the packer @ +/- 12,226.5. RIH and tag tubing packer @ 12,232 and lift packer assembly to 12,227.5' ELM. Adjusted correction puts the packer @ +/-12,226.5. Set plug. Set down on plug to verify good set. POOH. RDMO. 4/23/15-Thursday MIRU wireline stack riser next to wheelhouse, M/U tools.Jet pump and packer Rep. on location. M/U tool and put jet pump/upper packer assembly in riser. Pick up lubricator&stack PCE. LRS R/U and PT hose. PT PCE to 500psi,good test. Start HES DPU timer at 11:34(240 minutes). RIH w/QC, 3-1/2" GR, HES 2.50" DPU, Weatherford jet jump latch assembly (OAL=31'). Get P/U weight @ 12,100'SLM,SD @ 12,181'SLM,tap down and overpull to —800lbs,set brake and P/U 9601bs,standby for DPU to stroke.;Observe DPU stroke and weight loss of 1501bs. POOH.;OOH w/tools, begin RID,tree cap on and tested. Down stack PCE& lay down riser. RDMO. Schwartz, Guy L (DOA) From: Tom Fouts <tfouts@hilcorp.com> Sent: Tuesday, March 10, 2015 11:15 AM To: Schwartz, Guy L (DOA) Subject: RE: Status of Sundry 314-234 for MPL-39 Attachments: MPL-39I SCHEMATIC10-16-14.pdf ?TP -/2$ Guy, Please see the attached BP schematic. Our plan forward is to set a permanent lower packer with a greater differential pressure rating and then reinstall the Jet pump and upper packer assembly. The frac procedure was executed prior to Hilcorp becoming the operator.We will have to contact BP to obtain the results from the frac procedure and will include them with the 10-404 sundry. Please feel free to contact me if you have any other questions. Thanks, Tom Fouts I Senior Ops/Reg Tech S(ANEO MAR 1 7 201 Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907)777-8398 Mobile: (907)351-5749 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Tuesday, March 10, 2015 11:00 AM To: Tom Fouts Cc: Chris Kanyer; Loepp, Victoria T(DOA) Subject: RE: Status of Sundry 314-234 for MPL-39 The sundry is still valid (written by BP) ... but I noticed there is some mention of frac'ing the well in the sundry before running jet pump. Can you also elaborate on exactly what you will be doing to set jet pump? Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaska.gov). From: Tom Fouts [mailto:tfouts@hilcorp.com] Sent: Tuesday, March 10, 2015 9:00 AM To: Schwartz, Guy L (DOA) Cc: Chris Kanyer Subject: Status of Sundry 314-234 for MPL-39 1 Guy, I am wanting to check the status of sundry 314-234 for MPL-39 to see if it is still open. If so, our plan is to run a jet pump in the well on the 19th. Please advise. Thanks, Tom Fouts Senior Ops/Reg Tech Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907) 777-8398 Mobile: (907) 351-5749 2 Tree: Cameron 3 1/8", 5M Orig. KB Elev. = 51.4 ' (N 27E) Wellhead: FMC 11" x 11" 5M, MPU L-39 i Orig. GL Elev. = 17.1' Gen. 5 w/ 11" x 3.5" FMC Tbg. RT To Tbg. Spool = 34.3 ' (N 27E) Hnr. w/ NSCT threads top and bottom.and 3" CIW H BPV profile 117- // 6C)20" 91.1 ppf, H-40 112' KOP @ 300' to 4,500' Max. hole angle = 78 deg. 3.5" HES X-Nipple (2.813 id) 2,006' Hole angle thru' perfs = 27 deg. 9 5/8", 40#/ft, L-80 Btrc. 8,649' "Reverse Circulation'Jet Pump Configuration ha id Mid "Lial l1 1 7" 26 ppf, L-80, NSCC production casing al I ( drift ID = 6.151", cap. = 0.0383 bpf) i v. 3.5 9.3 ppf, L-80 dr Mod 8rd tbg. (cap. = 00087 bpf, drift = 2.867") • E7 a Upper Packer/Jet Pump-Top is @ 12,204' Reservoir Fluid Tbg. Punch 10-11-14 12,2212'- 12,214' WFD Lower ER Patch Set @ 12,224' MD 2.74"OD / 1.812 ID / 2.70'OAL Holes shot 9-28-08© 12,246.5 to 12,248.5 E-Line measurement. Set Owen Oil Tools X-Span 2.715"X 24'Patch I pp 12 250' 12,233.5'to 12,256.1'Min ID 2.25" 9/12/2014 3.5" HES X-Ni Ie (2.813 id) Stimulation Summary 3.5"x 7" Baker SB-3 pkr. 12,296' 3.5" HES XN-Nipple 12,320' (No-Go 2.75 id) Perforation Summary Ref log: 07/24/96 Anadrill LWD 13.5" Otis WLEG 12,332' Size SPF Interval (TVD) ELMD 4.5" 5 12,362'-12,402' 7062'-7097' XHVZE Pages NOT Scanned in this Well History File 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. File Number of Well History File PAGES TO DELETE RESCAN [] Color items - Pages: [] Grayscale, halftones, pictures, graphs, charts Pages: [] Poor Quality Original- Pages: [] Other - Pages: DIGITAL DATA [] Diskettes, No. n Other, No/Type 'OVERSIZED [] .Logs of vadous kinds o Other Complete COMMENTS: Scanned by: ~e,,~,r~ Mildred-Daretha ~owell TO RE-SCAN Notes: Re-Scanned by: Beverly Mildred Daretha Natl3an Lowell Date: /s/ • /40, `s'��\\1%%"-s,7. THEl!STATE (( Lai_p C i1 e TT Cf U \ I • 333 West Seventh Avenue i -..:J✓ I' �' S , . Anchorage. Alaska 99501 3572 CYO��LL.�t.t: Ei�N I aR�'Et_.I. liin 907.2'9 t!33 ALAS G.A ,r'?.2ic, 7 Alex Youngmun Production Engineer iqii- ta BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Milne Point Field, Kuparuk River Oil Pool, MPL-39 Sundry Number: 314-234 Dear Mr. Youngmun: il nn Enclosed is the approved application for sundr NW Min b tt 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, , - ..- vI Daniel T. Seamount, Jr. pr-t- � Commissioner DATED this/0 day of April, 2014. Encl. Qa STATE OF ALASKA �\. ,,4 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS (°)(74 ' , 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pool❑ Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations E] Perforate❑ Pull Tubing❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate❑ Alter Casing❑ Other _Convert to Producer 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. BP Exploration(Alaska),Inc.- Exploratory ❑ Development ❑ \ 197-128-0 • 3.Address: Stratigraphic ❑ Service 0 , 6.API Number. P.O.Box 196612,Anchorage,AK 99519-6612 ' 50-029-22786-00-00 7.If perforating: 8.Well Name and Number: 043 What Regulation or Conservation Order governs well spacing in this pool? \ *3P M PL-39 Will planned perforations require a spacing exception? Yes ❑ No ❑ 9.Property Designation(Lease Number): 10.Field/Pool(s): \ ADL0025514- MILNE POINT, KUPARUK RIVER OIL • 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): 12740 s 7401 ,. 12634• 7305 None None Casing Length Size MD ND Burst Collapse Structural Conductor 80 20"91.1#H-40 34-114 34-114 Surface 8613 9-5/8"40#L-80 36-8649 36-4165.42 5750 3090 Intermediate 12684 7"26#L-80 33-12717 33-7380.11 7240 5410 Production None None None None None None Liner None None None None None None Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 12362-12402 - 7062.25-7097.83 3-1/2"9.2#L-80 L-80 32-12332 Packers and SSSV Type: 4-1/2"Baker S-3 Perm Packer Packers and SSSV MD(ft)and ND(ft): 12296,ND Top No SSSV Installed No SSSV Installed 12.Attachments: Description Summary of Proposal El • 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑Q - Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: Oil Q- Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Alex Youngmun Email \,a,,dexk0 bp,t..„(x. Printed Name Alex Youngmun Title Production Engineer Signature p p Phone 564-4864 Date p 1 t f I 1 ' 19 Prepared by Garry Catron 564-4424 ��i COMMISSION USE ONLY ` Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 3k. " 2231—( Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 116 = l 1::*7 MAY d ? J) Spacing Exception Required? Yes ❑ No Z Subsequent Form Required: /p - 4-7 IF —`%�/ ',,/-- -,-.. ''/ APPROVED BY / J Approved by: �� /'j/ COMMISSIONER THE COMMISSION Date: Of, / J- -( & Li/iigty ,0 y/,� Form 10-403 Revised 10/2012 epRiaecitNAtoir 12 months from the date of approval. Submit Form and Attachments in Duplicate v'i-r 4/i 5/lam by BP Exploration(Alaska)Inc 900 East Benson Blvd. Anchorage,Alaska 99508 1.907.564 5111 March 11th, 2014 Ms. Victoria Ferguson Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage,Alaska 99501 Subject: MPL-39 Reclassification from Injector to Producer Dear Ms. Ferguson, BP Exploration(Alaska) Inc. requests approval for reclassifying MPL-39 from a injector to producer. MPL-39 is currently classified as an injector. The well is located in an isolated fault block with no ' (0460"' other off-take or intake points. MPL-39 had a short Injection Tife, ending in 1999 when it was founcflii X not be in communication with offset producer MPL-40. New seismic data interpretations do not iriy present any worrisome faults that could further compartmentalize the block, which has been carried as a major risk in past economic evaluations. Recent static pressures have ensured stable BHP's over time and that no leakage has occurred to nearby producing fault compartments. There have been several attempts to produce this well over the years. MPL-39 had an attempted free flow back to tanks performed in 2002 as part of tracer study/low salinity pilot. In 2008, a "poor boy" jet pump conversion was attempted by punching holes is the tubing resulting in two unsuccessful POP attempts. A high pressure rated patch will be set over the holes punched in the tubing prior to a frac taking place. The proposed plan is to perform a two stage hydraulic fracture stimulation in the Kuparuk A2/A3 and C sands. After the frac, holes will be punch in the tubing above the high rated patch and a packer assembly will be set to allow the well to flow via jet pump. The proposed packer assembly has been successfully used in Prudhoe Bay jet pumped wells. Performing this operation and converting MPL- 39 to a producer would allow the reserves to be accessed on primary depletion that would otherwise be untouched./ In summary, BPXA requests reclassification of MPL-39 from injector to producer status. If you require any additional information, please contact me at 564-4864. Sincerely, Alex Youngmun Milne Point Unit F&L Pad Petroleum Engineer Cameron 3 1/8", b... Orig. h .sv. = 51.4 ' (N 27E) Wellhead: FMC 11" x 11" 5M, MPU L-39i Orig. GL Elev. = 17.1' Gen. 5 w/ 11"x 3.5" FMC Tbg. 7 RT To Tbg. Spool = 34.3' (N 27E) Hnr. w/ NSCT threads top and bottom.and 3" CIW H BPV profile 20" 91.1 ppf, H-40 112' KOP @ 300' to 4,500' Max. hole angle= 78 deg. 3.5" HES X-Nipple (2.813 id) 2,006' Hole angle thru' perfs =27 deg. 9 5/8", 40#/ft, L-80 Btrc. 8,649' 7"26 ppf, L-80, NSCC production casing (drift ID=6.151", cap. =0.0383 bpf) 3.5"9.3 ppf, L-80 EUE Mod 8rd tbg. (cap. = 0.0087 bpf, drift= 2.867") 3.5" HES X-Nipple (2.813 id) 12,250' Stimulation Summary 3.5"x 7" Baker SB-3 pkr. 12,296' 3.5" HES XN-Nipple 12,320' Perforation Summary (No Go 2.75 id) _Ref log: 07/24/96 Anadrill LWD 3.5" Otis WLEG 12,332' Size. SPF Interval (TVD) • ELMD 4.5" 5 12,362'-12,402' 7062'-7097' 7"float collar(PBTD) 12,634' 7"float shoe 12,717' DATE REV. BY COMMENTS MILNE POINT UNIT 7-28-97 MDO 7" Cased Hole Completion WELL No : L-39i 7-01-98 MDO 3.5" Injection completion API : 50-029-22786 BP EXPLORATION (AK) • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 December 30, 2011 Sra...ANNEC; r 11 5. z, ZO;? 1,91 - ( � � Mr. Tom Maunder Alaska Oil and Gas Conservation Commission Ig-- I._ 3g 333 West 7 Avenue 1 Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of MPL -Pad Dear Mr. Maunder, Enclosed please find multiple copies of a spreadsheet with a list of wells from MPL -Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10 -404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Gerald Murphy, at 659 -5102. Sincerely, ________() . L— / 7 1 7 \ ----- Mehreen Vazir BPXA, Well Integrity Coordinator 0 0 BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10 -404) MPL -Pad Date: 10/08/11 Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # cement pumped cement date inhibitor sealant date ft bbls ft gal MPL -01A 2030640 50029210680100 Sealed conductor N/A N/A N/A N/A NA MPL -02A 2091470 50029219980100 Sealed conductor N/A N/A N/A N/A NA MPL -03 1900070 50029219990000 Tanko conductor N/A N/A N/A N/A NA MPL-04 1900380 50029220290000 Sealed conductor N/A N/A N/A WA NA MPL -05 1900390 50029220300000 Sealed conductor N/A N/A N/A N/A NA MPL -06 1900100 50029220030000 Sealed conductor N/A N/A N/A N/A NA MPL -07 1900370 50029220280000 Sealed conductor N/A N/A N/A N/A NA MPL -08 1901000 50029220740000 Sealed conductor N/A N/A N/A N/A NA MPL -09 1901010 50029220750000 Sealed conductor N/A N/A N/A N/A NA MPL -10 1901020 50029220760000 Sealed conductor N/A N/A N/A N/A NA MPL -11 1930130 50029223360000 Sealed conductor N/A N/A N/A N/A NA MPL -12 1930110 50029223340000 Sealed conductor N/A N/A N/A N/A NA MPL -13 1930120 50029223350000 Sealed conductor N/A N/A N/A N/A NA MPL -14 1940680 50029224790000 Sealed conductor WA N/A N/A N/A NA MPL -15 1940620 50029224730000 3.3 N/A 3.3 N/A 15.3 8/9/2011 MPL -16A 1990900 50029225660100 23 Needs top job MPL -17 1941690 50029225390000 0.2 N/A 0.2 N/A 5.1 9/1/2011 MPL -20 1971360 50029227900000 0.4 N/A 0.4 N/A 3.4 8/10/2011 MPL -21 1951910 50029226290000 1.7 N/A 1.7 N/A 8.5 8/10/2011 MPL -24 1950700 50029225600000 0.2 N/A 0.2 N/A 8.5 10/8/2011 MPL -25 1951800 50029226210000 1.7 N/A 1.7 N/A 15.3 8/10/2011 MPL -28A 1982470 50029228590100 0.3 WA 0.3 N/A 8.5 10/8/2011 MPL -29 1950090 50029225430000 0.5 WA 0.5 N/A 3.4 8/7/2011 MPL -32 1970650 50029227580000 0.5 WA 0.5 N/A 5.1 8/10/2011 MPL -33 1971050 50029227740000 0.2 WA 0.2 WA 8.5 10/8/2011 MPL -34 1970800 50029227660000 1.7 N/A 1.7 WA 8.5 8/9/2011 MPL -35A 2011090 50029227680100 0.2 N/A 0.2 N/A 8.5 10/8/2011 MPL -36 1971480 50029227940000 0.1 N/A 0.1 N/A 7.6 9/1/2011 MPL -37A 1980560 50029228640100 6 N/A 6 N/A 47.6 8/13/2011 * MPL -39 1971280 50029227860000 1.7 N/A 1.7 WA 6.8 8/8/2011 MPL -40 1980100 50029228550000 1 N/A 1 WA 6.8 8/8/2011 MPL-42 1980180 50029228620000 5.3 N/A 5.3 WA 30.6 8/14/2011 MPL-43 2032240 50029231900000 17.5 Needs top job MPL-45 1981690 50029229130000 10 N/A 10 WA 8.5 8/10/2011 STATE OF ALASKA ALA OIL AND GAS CONSERVATION COMt~ION ~ ~ T ~ ~ ZQQB REPORT OF SUNDRY WELL OPERATIO~V~S~,„ n;, ~ ,~..., , ,___ 1. Operations Abandon ~ Repair Well ~ Plug Perforations ~ Stimulate ~ t er ~ 'p ~b QQ Performed: Alter Casing ~ Pull Tubing ~ Perforate New Pool ~ Waiver ~ Time Extensidr3 _ Change Approved Program ~ Operat. Shutdown Perforate ~ Re-enter Suspended Well ~ instal iet pump 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development ~ Exploratory 197-12so 3. Address: P.O. Box 196612 Stratigraphic Service .~ 6. API Number: Anchorage, AK 99519-6612 50-029-22786-00-00~ 7. KB Elevation (ft): 9. Well Name and Number: 51.42 KB MPL-39 8. Property Designation: 10. Field/Pool(s): ADLO-025514 MILNE POINT Field/ KUPARUK RIVER OIL Pool ' 11. Present Well Condition Summary: Total Depth measured 12740 ~ feet Plugs (measured) None true vertical 7400.8 feet Junk (measured) None Effective Depth measured 12634 feet true vertical 7305.48 feet Casing Length Size MD TVD Burst Collapse CONDUCTOR 80 20" 91.1# H-40 32 - 112 32 - 112 1490 470 SURFACE 8618 9-5/8" 40# L-80 31 - 8649 31 - 4165 5750 3090 PRODUCTION 12687 7" 26# L-80 30 - 12717 30 - 7380 7240 5410 nnnQQ ~~~~~~ ''`,Ivy'/ ~ ~ ~Cl~C~ sY~ , Perforation depth: Measured depth: 12362 - 12402 = _ _ _ True Vertical depth: 7062.25 - 7097.83 = _ _ _ Tubing: (size, grade, and measured depth) 3-1/2" 9.3# L-80 30' - 12332' 0 0 - Packers and SSSV (type and measured depth) 3-1/2" BAKER SB-3 12296' 0 0 0 0 0 0 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing pressure Prior to well operation: SI Subsequent to operation: SI ' 14. Attachments: 15. Well Class after proposed work: Copies of Logs and Surveys Run Exploratory ~ Development ~`°°' Service ~' • Daily Report of Well Operations X 16. Well Status after proposed work: Oil Gas ~ WAG ' ' GINJ ~'' WINJ WDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N/A Contact Kristin Krom Printed Name Kristin Krom Title PE Signature Phone 564-5850 Date 10/22/2008 / . /3 _~ Form 10-404 Revised 04/2006 ,, ~ ~ ~ ~,~ I ~ ~J~~'a~ ~ ); h~(),i ~S~b~ ri final Only ~~ ~, c.. rl/i~~6 ~ ~ i~ • • MPL-39 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 9/27/2008!WELL SHUT-IN ON ARRIVAL. INITIAL PRESSURES 1200/700/150 DISCREPANCY IN THE TUBING TALLEY HAD AN INCORRECT ORDER IN JOINTS. THIS WAS DISCUSSED WITH THE PE, AND IS MOST LIKELY A CLERICAL ERROR. JOB PROCEEDED, SHOT THE BOTTOM SHOT 1.3 FT ABOVE THE TOP OF THE NIPPLE AT BOTTOM SHOT DEPTH: 12248.7' CCL TO BOTTOM SHOT: 10.7' CCL STOP DEPTH: 12338' WELL SHUT-IN ON DEPARTURE 9/28/2008T/I/0=650/600/140 Assist E-line Injectivity test Pumped 7 bbls 60/40 methanol `down IA for injectivity test. Pressured up to 2500 psi. in 4 bbls. Bleed pressure ":;,down to 350 psi. FWHP=650/600/120 Well left with E-line still on. 9/28/2008'T/I/0=1200/600/140 IA Injectivity test Pumped 20 bbls Dead Crude into IA. Could not maintain rate Pressured~.~ t~ ~ Ano r~si after 8 bhJs. Tag well, IA/OA, ?ssv & master open. Swab & wing closed. Notify operator. Final W HP's=1350/850/150 9/29/2008T/I/0= 650/600/140 Tubing injectivity test Pumped 30 bbls 60/40 methanol down tubing. Pumped first 5 bbls C«~ .6 bpm and 1500 psi. next 5 bbls @ .8 and 1900 ;psi. Bleed IA down to 500 psi after first 10 bbls and maintain open bleed while ;pumping remaining 20 bbls. FWHP= 1200/1000/140 Master, IA, OA open. Swab, SSV, and Wing closed. 10/7/2008T/I/0=1150/650/140 IA Injectivity Test Inject down IA taking returns up tbg to 'choke skid/flow back tank (tbg open to formation also). Pumped IA w/total of 10 3 bbls crude & 6 bbls diesel taking returns up tbg to tank. Establish infection rate of 0.5 bpm @ 3000 osi. _ IA/OA & master open. Swab, ssv & wing closed. Notify ;operator. Final WHP's=550/500/80 10/8/2008;*"*WELL S/I ON ARRIVAL"'*" (set PXN) r 1 ;RUNNING IN HOLE W/ 2.805 GAUGE RING, DRIFT TO XN-NIPPLE C~ 12320' 3MD ? I"""CONY ON WSR 10-09-08""` • • 10/9/2008~(Brush and Flush) T/I/0= 600/680/140 Pump 89 bbls 180* diesel down TBG to kassist slickline with brush and flush. IA/OA open, s-line on well, operator notified. FW H P=1500/1100/280 10/9/2008***CONT FROM WSR 10-08-08*** ;RUN W/ OC, KJ, XO, 2.75 CENT, XO, 3' OF 1 7/8, XO, 3.5 LOOSE BLB, XO, 2.805 GAUGE RING. S/D @ 12219' SLM '***WELL S/1 ON DEPARTURE*** i 10/10/2008 '**WELL S/I ON ARRIVAL*** (set pxn) SET 2.813 PXN BODY (4 - 3/16" EO PORTS). C«3 12320' MD (T/I/O- ;1040/760/140) ~ ?SET PX PRONG (OAL 39 1/2", 1 3/8" FN) C«~ 12311' SLM FWH PRESSURE ( ± T/I 0-725 4 10 ) I ***WELL S/I ON DEPARTURE*** OPERATOR NOTIFIED 10/10/2008 (CMIT Tx IA /Circ-Out) T/I/0= 800/460/100 Pressure up Tx IA to 3000 Psi. €Awgers Continued on 10-11-08. s 10/11/2008;CMIT Tx IA /Circ-Out ~T/I/0= 800/460/100. OMIT Tx IA to 4200 psi PASSED. Initial press= ;4150/4200/500) 15 Min press=4100/4000/520. 30 Min press= 4100/3920/520. i 'i Retests Intial Press= 4200/4200/520. 15 Min press=4200/4040/520. 30 Min press= 4200/4000/520 CMIT Tx IA is a pass. Pre-Heat diesel to 120*. ;Circ-Out -Circulate down IA taking retums through tbg perferations up tbg to flow ;back tank. Pumped IA with a total of 14 bbls 110*F diesel, 13 bbls 60/40 ;methanol, 80 bbls 180*F diesel, 8 bbls 60/40 methanol, 180 bbls 180*F produced =water, 7 bbls 60/40 methanol & 85 bbls diesel. U-tube TxIA to freeze protect. ;Encountered suspected ice bridges in IA during 1st 107 bbls pumped (See log). Awgers Continued on 10-12-08) _ _ _ __ __ __ 10/12/2008: (Circ-Out/Ice Plug) T/I/0= 800/460/100 Awgers continued from 10-11-08. Pump TBG with 14 bbls neet meth, pressured up to 3500 psi, pump & bleed to rock ice ;plug. Ice plug clear, pump IA w/75 bbls 180*F diesel (total of 102 bbls w/yesterdays) taking returns up tbg to flow back tank. U-tube TxIA to freeze protect. IA/OA & master open. Swab, ssv & wing closed. Tag well & notify ;operator. Final WHP's=0/0/160 ~. . ~__._ __._ w. u._ _ _,_.~~ _______ _ _ ~.~_ ~ .__._ ~~ 10/14/2008~PULLED 2.81" PXN PLUG BODY FROM 12320' MD ***REPLACEMENT WSR *** 10/15/2008:***CONTINUE FROM 10/14/08 ***PULL PLUG SET GAUGES SET 2.813 LOCK AND SOFT_SET W/ SPARTEK GAUGES_C«~ 12310 SLM OAL ***JOB CANCEL *** 4 10/15/2008;***ARRIV ON LOC WELL S/I "** JET PUMP :RAN 3.5 X-LINE W/ 2.813 LOCK W/ POLISH BORE @ 12246 SLM ***CONTINUE ON 10/16/08*** • ( • 10/16/2008"""CONTINUE FROM 10/15/08""' JET PUMP """ SET 3 5" D&D PACKOFF JET PUMP (BP-1039 9Al OAL=121"1 ~ ~?~S~MD ~ RAN PACK-OFF TEST TOOL TO PUMP. TESTED PACK-OFF. GOOD TEST. SET 3.5" D&D AA SLIP-STOP @ TOP OF PUMP (max O.D. 2.72") OAL=20" WELL S/I ON DEP. TURN WELL OVER TO DSO "*'JOB COMPLETE'"'* COMPLETE DRAWING OF ASSEMBLY IN WELL FILE'"'"" FLUIDS PUMPED BBLS 109 diesel 30 Dead crude 44 60/40 meth 183 Total • ~.~ ~~ ~~"~ ~ ~ ..~ ~ ~,:^_,~ ~ ~`, f "`~ ~, ~ ~'~"~~ Ct~'1~ ~~ SARAH PAL/N, GOVERNOR OII/ ~ t7[v-7 333 W 7th AVENUE, SUITE 100 CO1~T5i' RQA~IOr1T COAII-iI55I0IQ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Emeka Emembolu Light Oil Team Leader BP Exploration Alaska Inc. PO Box 196612 f~~e~~~~ AUu~ ~ 20~~ Anchorage, AK 99519-6612 Re: Milne Point Field, Kuparuk River Oil Pool, MPL-39 Sundry Number: 308-288 ~ ~ ~ ~ ~ ~"' Dear Mr. Emembolu: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Cathy . Foerster Commissioner DATED this ~i day of August, 2008 Encl. • STATE OF ALASKA O i ALASKA OIL AND GAS CONSERVATION COMMISSIO ~ G , ~ ~ ;a ~ N APPLICATION FOR SUNDRY APPROVAL:.. o0 20 AAC 25.280 1. Type of Request: Abandon Suspend Operational shutdown Perforate Waiver Oth ~ Alter casing ^ Repair well ^ Plug Perforations[] StimulateTime Extension ^ Convt to producer Change approved program ^ Pull Tubing ~ Perforate New Pool^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: BP Exploration (Alaska), Inc. Developmenl^ Exploratory ^ 197-1280 3. Address: P.O. Box 196612 Stratigraphic^ Service Q ~ 6. API Number: Anchorage, AK 99519-6612 50-029-22786-00-00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: MPL-39 , Spacing Exception Required? Yes ^ No ^ 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pools(s): , ADLO-025514 ~ 51.42 KB - Milne Point Field / Kuparuk River Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12740 ~ 7400.8 / 12634 7305.48 NONE NONE Casing Length Size MD TVD Burst Collapse Conductor 80 20" 91.1# H-40 32 112 32 112 1490 470 Surface 8618 9-5/8" 40# L-80 31 8649 31 4165 5750 3090 Production 12687 7" 26# L-80 30 12717 30 7380 7240 5410 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 12362 - 12402 7062.25 - 7097.83 3-1/2" 9.3# L-80 30 - 12332 Packers and SSSV Type: 3-1/2" baker SB-3 Packers and SSSV MD (ft): 12296' 12. Attachments: Descriptive Summary Proposal ~ 13. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development Q Service ^ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/26/2008 OIL Q ~ GAS ^ PLUGGED ^ ABANDONED ^ 16. Verbal Approval Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: Prepared by Gary Preble 564-4944 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Emeka Emembolu Printed Nam Emeka Emembolu Title Light Oil Team Leader Signature Phone 907-564-4560 Date 8/12/2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~" w~,~~ ~o~-~~S~cco1o42 Plug Integrity ^ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ^ ~~~~ P tl ~1 ` S~ `~ Other: ~~~ ~ ~ ~ vo'~ ~5~ Subsequent Form Required: ~~~ APPROVED BY ISSION D t 8 - Z ~~ a e: Approved by: COMMISSIONER THE COMM Form 10-403 ~evise~0~/6~ ~ ! ~ n ( M Cam' ~~'~ pU~ ~ ~ ~oo@ ~ ~ _ Submit in Duplicate • • Maunder, Thomas E (DOA) From: Preble, Gary B (SAIC) [Gary.Preble@bp.com] Sent: Friday, August 22, 2008 11:25 AM To: Maunder, Thomas E (DOA) Subject: FW: L-39i full work scope. Tom, Hamid Is the PE for MPL-39 and has updated the work scope. Have a nice weekend. From: Hassanali, Hamid Sent: Fri 8/22/2008 11:16 AM To: Preble, Gary B (SAIC) Subject: L-39i full work scope. Gary, I am sending a brief on L-39i and overall work scope. Let me know if more is required. Thanks Hamid L-39i was initially planned and drilled in July 1997 as a Kuparuk producer to encounter A1,2,3 and possibly B and C sands. However, the oil column was less than expected with an OWC in the A2 sand package. Only after drilling L-40, where a full oil column was obtained, was L-39 completed as an injector - June 1998. Perforations @ 5 SPF using 4.5" guns from 12,362' to 12,402' MD extended below the OWC in the A2 sand. Water injection was poor with rates averaging between 300 to 650 bwpd and >3500 psi WHP in the first 4 months. The well was then converted to gas injection but was quickly discontinued as communication between the tubing and the OA was observed. After only a few months on injection and unable to inject gas safely, all injection stopped after 06/ 1999. Cumulative injection is 58 Mbw and 20 mmscf. An economic feasibility analysis was conducted in June 2001, of converting L-39 to a producer by Stuart Shaw, the then Pad engineer. Using Darcy's equation for semi-steady state production; a skin value of +2, a reservoir pressure of 4,766psi and other typical Kuparuk parameters an IP of 220 bopd was proposed. To predict a production profile for the economic model an MBAL simulation was used assuming 3 MMRB OOIP and an aquifer size of 2MMRB. An estimated IP of 235 bopd with a decline rate of 45% per annum was derived, based solely on aquifer support. The investigation concluded this prospect to be marginal, having metrics of 4.94 $/bbl, IRR>100%, NPV(SMM) 0.273 and a payback of 0.69 years based on an overall cost of $657K and $16/bbl oil price. The projection was not sanctioned and L-39i remained a LTSI well and a potential wellbore donor. Operationally, ice plugs have been observed on several occasions during attempts to capture reservoir surveillance data. The last CT ice plug removal - 12/02/05, SBG was pumped and the perfs washed. In preparation for a flow back a HOT diesel/ DAD acid wash was implemented 10/06/02. A 10 day flow back test was implemented one day later but the well flowed for only a few hours at an average rate of 190 bopd. The current reservoir pressure, obtained 04/27/08, is 3541 psi. The current oil price now makes this opportunity very attractive, with an expected 12 month average oil rate of 200 bopd. However, a major risk is access to the entire OOIP or that L-39i is isolated in a very small block. Additionally, to ensure maximum contribution, the C sand will be perforated and A3 hydraulically fractured. The frac will be designed and implemented to avoid the OWC in A2. Work Scope 1) MIRU 2) Kill Well. Try not to pump excess fluid in formation 3) Unsting from pkr. and ~rieve injection string • 4) Recover/mill out pkr 5) Sand-off upto ti 12366' MD 6) Frac using ~25K # 20-40 carbolite 7) FCO to TD ~ 12634' MD 8) Perforate C sand ( 12284' - 12290'; 12292' - 12296' MD RKB) using 4.5" DP guns @ 5 SPF 9) Run new ESP completion on 2-7/8" 26#/ft L-80 tbg, setting pump @ ~ 12200' MD 10) RD and move off Tree: Cameron 3 1/8", ~ Wellhead: FMC 11" x 11" 5M, Gen. 5 w/ 11" x 3.5" FMC Tbg. Hnr. w/ NSCT threads top and bottom.and 3" CIW H BPV profile 20" 91.1 ppf, H-40 112' KOP @ 300' to 4,500' Max. hole angle = 78 deg. Hole angle thru' perfs = 27 deg. 19 5/8", 40#/ft, L-80 Btrc. 8,649' 7" 26 ppf, L-80, NSCC production ca ( drift ID = 6.151 ", cap. = 0.0383 bpf 3.5" 9.3 ppf, L-80 EUE Mod 8rd tbg (cap. = 0.0087 bpf, drift = 2.867") Stimulation Summary Perforation Summary Ref log: 07/24196 Anadrill LWI Size SPF Interval (TVD) 4.5" 5 12,362'-12,402' 7062'-70~ DATE REV. BY COMMENTS 7-28-97 MDO 7" Cased Hole Completio 7-01-98 MDO 3.5" Injection completion Orig. elev. = 51.4 ' (N 27E) Orig. GL Elev. = 17.1' RT To Tbg. Spool = 34.3 ' (N 27E) .5" HES X-Nipple (2.813 id)~ 2.006' HES X-Nipple (2.813 id) 12,250' ! "x 7" Baker SB-3 pkr. 12,296' I 3.5" HES XN-Nipple 12,320' (No-Go 2.75 id) 3.5" Otis WLEG 12,332' ELMD " float collar (PBTD) 12,634' "' float shoe 12,717' M1LNE POINT UNIT WELL No : L-39i API : 50-029-22786 MPU L-39i ~. by ~ August 13, 2008 Recipient's name Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, AK 99501 ,''~,~~ %~ i~~'~1`~ BP Exploration (Alaska) Inc 900 East Benson Boulevard P.O.Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 Dear Sir/ Madam Sundry Notice for MPL-39 Conversion from Injector to a Producer BP Exploration Alaska, inc. proposes to convert well MPL-39 from ashut-in injection well to an active producing well. MPL-39 was originally drilled and completed as a water injection well in the Milne Point Kuparuk hydraulic unit 305. This well was intended to support MPL-40 in hydraulic unit 310. Seismic and interference data have since demonstrated that MPL-39 is not in hydraulic or pressure communication with MPL-40. Records indicate that oniy 60,000 bbls of water have been injected into the A sands from this well. The current plan is to complete this well as an ESP producer from the A and C sands If you have any questions, please contact me on 564-5536. Sincerely, Emeka Emembolu Milne Point Unit Light Oil Team Lead MPL-39 Current Status: • Well is shut in and freeze protected Order of Operations: • Frac A3 Sands • Perforate C Sands • Clean all sand/ fill out of well • Install ESP Completion Registered company information Registered company address Address line 2 Address line 3 Address line 4 10-403 MPL-39 • • Maunder, Thomas E (DOA) Page 1 of 1 From: Maunder, Thomas E (DOA) Sent: Tuesday, August 19, 2008 3:23 PM To: Emembolu, Emeka Cc: 'Preble, Gary 8 (SAlC)' Subject: RE: 10-403 MPL-39 Thanks Gary, In general I can see what will be done, however will the frac/pert/cleanout be done with the existing completion and then the rig work occur or what? As 1 explained in the message left with Gary, it is appropriate to include the whole scope of work. Email is fine. Call or message with any questions. Tam Maunder, PE AOGCC From: Preble, Gary B (SAIC) [mailto:Gary.Preble@bp.com] Sent: Tuesday, August 19, 2008 3:05 PM To: Emembolu, Emeka Cc: Maunder, Thomas E (DOA) Subject: 10-403 MPL-39 Emeka, Your Sundry support needs more information pertaining to the order of operations. The whole scope of work needs to be listed in order for the AOGCC to approve this work. Thanks. • Frac A3 Sands • Perforate C Sands • Clean all sand/ fill out of well • Install ESP Completion Gary Preble Information Technology and Services Petrotechnicai Data Team Coordinator SAIC 907-5644944 907-350-6879 8/19/2008 • Note to File Milne Point Unit L-39 (PTD 197-128) Sundry Application 308-288 Request: BP Exploration (Alaska), Inc. (BPXA) requests permission to convert the subject well from WAG service to production. Recommendation: I recommend approving this request Discussion: The subject well was initially permitted to be a producer and was drilled in July 1997. The well encountered less oil column than anticipated, due to an OWC in the A2 sand, and completion operations were postponed. The MPU L-40 well was later drilled into what was believed to be the same fault block and completed as a producer and the MPU L-39 well was completed as an injector to provide support to the MPU L-40 well. Later testing indicated that the MPU L-39 and L-40 wells were not in hydraulic or pressure communication and injection into the MPU L-39 well ceased. Water injection began in the MPU L-39 well in August 1998 and continued until December 1998. Beginning in April 1999 BPXA attempted to inject gas into the subject well, but abandoned this operation the following month. There have been a couple of intermittent attempts at injection since that time but nothing of any consequence in terms of duration or volume. Cumulative water injection in the subject well was almost 58 MBW and cumulative gas injection was a little more the 20 MMCF. Conclusions: The well is currently providing no benefit to recovery from the MPU and appears to be located in a portion of the field that is not currently contributing to production. Therefore, converting this well from ashut-in injector to an active producer should benefit ultimate recovery from the field. ~ ~ ,, Dave Roby.: -~~~ Sr. Reservoir Engineer August 19, 2008 Kt:.~,t:.1 V tU DEC 2 2 2005 n ') STATE OF ALASKA ) AlA~, ,Á Oil AND GAS CONSERVATION COMrvhvSION REPORT OF SUNDRY WELL OPERATIONSA\aska Oi\ &Gas Cons.l;Ommission 1. Operations Abandon 0 Repair Well 0 Plug Perforations 0 Stimulate 0 Other EjAIISBPNWFt to WAG Performed: Alter Casing 0 Pull Tubing 0 Perforate New Pool 0 Waiver 0 Time Extension 0 8/22/1998 Change Approved Program 0 Operat. Shutdown 0 Perforate 0 Re-enter Suspended Well 0 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development 'C,' Exploratory C 197-1280 3. Address: P.O. Box 196612 Stratigraphic D Service r;?1 6. API Number: Anchorage, AK 99519-6612 50-029-22786-00-00 7. KB Elevation (ft): 9. Well Name and Number: 51.42 KB 8. Property Designation: ADL-025514 11. Present Well Condition Summary: Total Depth measured 12740 true vertical 7400.8 Effective Depth measured 12634 true vertical 7305.48 Casing Conductor Surface Production Length 80 8618 12687 Size 20" 91,1# H-40 9-5/8" 40# L-80 7" 26# L-80 Perforation depth: Measured depth: 12362 - 12402 True Vertical depth: 7062.25 - 7097.83 Tubing: (size, grade, and measured depth) Packers and SSSV (type and measured depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations Oil-Bbl o o MPL-39 10. Field/Pool(s): Milne Point Fieldl Kuparuk River Oil Pool feet feet Plugs (measured) Junk (measured) None None feet feet MD 32 - 112 31 - 8649 30 - 12717 TVD 32 - 112 31 - 4165.42 30 -7380.11 Burst 1490 5750 7240 Collapse 470 3090 5410 ~Ç^NNED DEC 2: 820D5 3-1/2" 9.3# L-80 30 - 12332 3-1/3" Baker SB-3 Packer 12296 RBDMS BFl DEC 2 2 2005 Representative Daily Average Production or Injection Data Gas-Met Water-Bbl Casing Pressure o 0 0 o 327 0 15. Well Class after croposed work: Exploratory L, Development r 16. Well Status after proposed work: Oil r Gas r WAG P' Tubing pressure o 2862 Service R GINJ r WDSPL r WINJ r 17. I hereby certify that the foregoing is true and COITcct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 398-138 Contact Sharmaine Vestal Printed Name Sharmaine Vestal ~ !. Title Data Mgmt Engr Signat~ :j~/l . Phone 564-4424 -(~~ I,,! iI, L Form 10-404 Revised 04/2004 t,~,): ¡-\ ~ l:} ~ ~ \j j"-'\ Date 12/19/2005 Submit Original Only C~'"Milne Point 2001 Shut In Wells Date Reason for Future Utility Plans & Sw Name Shut-In Well Shut-In ~ Current Mechanical Condition of Well2 Possibilities; Comments MPB-07 Jul-97 ' A No known problems I High 'GOR' Well, Faciliti"es 'can not handle gas. Possible production after gas .... expansion pr.o. ject. MPB-08 May-94 '.. E No known Pr°b!e. ms 3 . Futher use as. an injector not required MPB-13 Jan-86 B GL well that was shut in due to high 3 We#house and flowlines removed water cut. Possible channel into water zone. ~MPB-17 Jan-96 E No mechanical problems. Quick 3 Wellhouse and flowlines removed communication with producer . MPB-19 Jul-91 B GL welJ. High water cut producer. 3 ~ellhouse and flowlines removed' ' Possible frac into water zone Feb-96 E No known problems 3 F~rther use aS an Injector not required while associated producer shut-in MPC-12 / Jan-oo E Fish in hole, dr#'ling pro~lems 3 SusPended due to drilling p~ol~iems, 12a MPC-16 Aug-93 A" High GOR well, perfs and completion 3 ' Wellhouse and fiowlines'removed abandoned MPC-17 May-O0 D Leak in 9 5/8" ca'sing to surface I Evaluatin'g possible plans for soluti'o'n to . problem. Mpc-20 Apr-O0 B High water cut well, no mechanical I Evaluating possible plans for solution to iproblems problem, MPC-21 Feb-02 D Problems with Jet Pump Completion I Evaluating possJble plans 'for solution pr..oblem. MPD-01 Dec-90 C Dead ESP completion, n° support to '1 Evaluating poss'ible plans for solutio'n to block problem. Possible alternative uses for wellbore MPD-02./ Aug-99 B Dead ESP completion, very high water I Evaluating possible pJans. ' 02a cut well MPE.02 Jun-OS C No known problems.' 2 .. Recomiolete to ~'i~per Kup zo. ne "... MPE-19 Aug-99 C Failed ESP on t.ubing string 2 . Well brought on line iq 2002 MPL-01 Feb-O0 B High water cut well, no mechanical I Evaluating possible plans problems dead ESP in hole MPL-IO Feb-99 E N° proof that is .supports other wefts I J' ,EvalUating side track possi~ilittes MPL-17 Apr-O0 B No menchanical problems, dead ESP I Evaluating side track possibilities ~MPL-21 0ct,98 E High-pressure-block ~'"5000 psi, no I :Possible-uSe-for injection *when pressure support needed for producers . .. Iowa. rs MPL-37a Nov-99 C Dead ESP, no-other.mechanical I Evaluating p~Ssibl'e side track plans or issuses recompletions MPL-39 Jan-99 E Could not inject gas into well, no use I Evaluating possible side track plans or for it. . . recomplet, ions , , , ,, , *Note - Wells were shut in 100% during 2001 Mitne Pt Shut In Wells 2001.xls THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ! ON OR BEFORE JANUARY 03, 2 001 M PL ATE E W IA L UNDER TH IS M AR K E R C:LORBMFILM.DOC Well Compliance Report File on Left side of folder 197-128-0 MILNE POINT UNIT L-39 50- 029-22786-00 BP EXPLORATION MD 12740/ TVD 07401 ~ Completion Date: ~/98 Completed Status: 1WINJ Current: Name Interval Sent Received T/C/D D 8111 ~ sPERRY GR/RLL/CNP OH 9/26/97 9/26/97 L ADN-MD q~A~ 5884-12740 q/ sh o. 4,27'98 4,30,98 L ADN-TVD q~/~L 3400-7400 / OH 4/27/98 4/30/98 L CDR-MD ~ 5884-12740 ~ OH 4/27/98 4/30/98 L CDR-TVD ~ 3400-7400 OH 4/27/98 4/30/98 L DG~CNP-MD ~ 5885-8670 ~tiq/q~ OH 10/8/97 10/8/97 . L DG~CNP-TVD ~ 3399-4173 ~ OH 10/8/97 10/0/97 L PERF "F~AL 12362-12402 "~"Lv]/q'~ CH 5 8'17/98 8'20/98 L USIT ~,F~P~L BL(C, 11550-12620 (4' ['7..~/'~'~ CH t'6'99 1'15/99 R SRVY RPT SCHLUM 0-12740. OH 10/5/98 10/5/98 T 8396 ~ SCHLUM CDR/ADNO OH 4/27/98 4/30/98 Daily Well Ops 7//}/]2--~/"?~/~(f Are Dry Ditch Samples Required? yes (~_~. And Received? yes-nm------~ Was the well cored? yes ~- Analysis Description Re~-~-ytm'-n~ Sample~-q~~ _ _ Comments: Tuesday, May 30, 2000 Page I of I 1/7/99 GeoQuest 3940 Arctic Blvd Anchorage, AK 99503 ATTN: Sherrie NO. 12211 Company Alaska Oil & Gas Cons Comm Attn: Lori Taylor 3001 Porcupine Drive Anchorage, AK 99501 Field: Milne Point (Cased Hole) Color Well Job # Log Description Date BL Sepia Print LIS Tape MpL-39 L,~.t C.., 99003 USIT 980627 i MPF-80 ~ ~"1 99005 DDL (PDC) 981207 1 MPB-05A l~l ~-- INJECTION PROFILE 981227 I 1 'MpB-18 J RST-INJECTION WFL 981223 1 "1 MPJ-17~ INJECTION PROFILE 981220 1 1 ,, , PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska)Inc. Petrotectnical Data Center MB3-3 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 Date Delivered: RECEIVED 1999 Alaska Oil & Gas Cons. Commi~on Anc,,hora.cte Schlumberger GeoQuest 3940 Arctic Blvd Anchorage, AK 99503 AT[N: Sh~/ .~ ~/~~ RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION LoGOCT 05 ~)98 WELL COMPLETION OR RECOMPLETION REPORT AND 1. Status of Well Classification of~e ~'"~lTl~ll~-f~ - [] Oil [] Gas [] Suspended [--lAbandoned [] Service Water & Gas Injector 2. Name of Operator 7. Permit Number BP Exploration (Alaska)Inc. 97-128 398-138 3. Address 8. APl Number P.O. Box 196612, Anchorage, Alaska 99519-6612_ .................... 50-029-22786 4. Location of well at surface ~ ~:~'~"'"~":-'~ ~"~'; ~ 9. Unit or Lease Name 3334' NSL, 5137' WEL, SEC. 8, T13N, R10E, UM'~i(~/~;~¢~'~"'~'" ~ ~_ ..,,.r__~ Milne Point Unit At top of productive interval .............. 10. Well Number 1707'SNL, 1800'WEL, SEC. 13, T13N, ReE, UM ii ~i~;!!~ ! 18.~ MPL-39i At total depth ~.L':;'~-. ~ .r: .... .~:~_:;..~-' 11. Field and Pool 1805' SNL, 1937' WEL, SEC. 13, T13N, R9E, UM . '-' Milne Point Unit / Kuparuk River 5. Elevation in feet (indicate KB, DF, etc.) [6. Lease Designation and Serial No. Sands KBE = 51.42'I ADL 025514 12. Date Spudded 113. Date T.D. Reached I 14. Date Comp., Susp., or Aband.115. Water depth, if offshore 16. No. of Completions 7/14/97I 7/24/97I 6/29/98I N/A MSL One i17. Total Depth (MD+TVD) 118. Plug Back Depth (MD+TVD)119. Directional Survey 120. Depth where SSSV set 121. Thickness of Permafrost 12740' 7401' FTI 12634' 7305' FTI [~Yes []NoI N/AMDI 180o' (Approx.) 22. Type Electric or Other Logs Run MWD, LWD, USlT, CBL, CNP, GR/JB 23. CASING~ LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE TOP BOTTOM SIZE CEMENTING RECORD AMOUNT PULLED 20" 91.1# H-40 38' 112' 24" 250 sx Arcticset I (Approx.) 9-5/8" 40# L-80 36' 8649' 12-1/4" 2199 sx PF 'E', 550 sx Class 'G' 7" 26# L-80 33' 12717' 8-1/2" 275 sx Class 'G' 24. Perforations open to Production (MD+TVD of Top and 25. TUBING RECORD Bottom and interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 4-1/2" Gun Diameter, 5 spf 3-1/2", 9.2#, L-80 12332' 12300' MD TVD MD TVD 12362'-12402' 7062'-7098' 26. AC~D, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze protect with 70 bbls diesel 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) August 22, 1998 I On Injection Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE IGAs-OIL RATIO TEST PERIOD I Flow Tubing Casing Pressure OALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAWTY-API (CORR) Press. 24-HOUR RATE 28. 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 __ 29. Geologic Markers 30. Formation Tests Measured True Vertical Include interval tested, pressure data, all fluids Marker Name Depth Depth recovered and gravity, GOR, and time of each phase. Top Kuparuk 'B' 12277' 6987' Top Kuparuk 'A' 12353' 7054' Top Kuparuk A3 12362' 7062' Top Kuparuk A2 12383' 7081' 31. List of Attachments Summary of Daily Drilling Reports, Surveys 32. I hereby certifv~rregoing i~t'~ue~d correct to-t~e best of my knowledge Signed T~~~~~f'~~~. ~~Title Drillincj Engineerin~ Supervisor Date,/'/Et -- cMPI'L39i 97-128 398-138 Prepared By Name/Number: Kathy Campoamor, 564-5122 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 Performance Enquiry Report Operator BP Exploration Date 23:36, 05 Oct 98 Page 1 The analysis is from - 15:00, 21 Jul 97 - to - 15:00, 21 Jul 97 Programs in Result Table: MPL-39 completion Well Type Time From Time To Duration Description E.M.W.(equivalent mud weight) MPL-39 Event 15:00, 21 Jul 97 15:00, 21 Jul 97 0 hr 0 min Obtained leak off 14.2 Hole Size MDR 8-1/2 Progress Report Facility M Pt L Pad Well MPL-39 Rig Page 1 Date 05 October 98 Date/Time 13 Jul 97 18:00-22:00 22:00-01:00 14 Jul 97 01:00-03:00 03:00-06:00 06:00-09:00 09:00-15:00 15:00-15:30 15:30-18:00 18:00-18:30 18:30-19:30 19:30-06:00 15 Jul 97 06:00-06:30 06:30-08:30 08:30-09:30 09:30-10:30 10:30-11:30 11:30-12:30 12:30-19:00 19:00-20:00 20:00-20:30 20:30-21:00 21:00-05:00 16 Jul 97 05:00-06:00 06:00-06:30 06:30-07:00 07:00-07:30 07:30-08:00 08:00-16:00 16:00-17:00 17:00-17:30 17:30-18:30 18:30-02:30 17 Jul 97 02:30-04:00 04:00-06:00 06:00-08:00 08:00-08:30 08:30-10:00 10:00-12:30 12:30-13:00 13:00-13:30 13:30-00:30 18 Jul 97 00:30-02:30 02:30-03:30 03:30-04:00 04:00-06:00 06:00-19:30 19:30-21:30 21:30-00:30 19 Jul 97 00:30-01:00 01:00-03:00 03:00-05:30 05:30-06:00 06:00-08:30 08:30-10:30 Duration 4hr 3hr 2hr 3hr 3hr 6hr 1/2 hr 2-1/2 hr 1/2 hr lhr 10-1/2 hr 1/2 hr 2hr lhr lhr lhr lhr 6-1/2 hr lhr 1/2 hr 1/2 hr 8hr lhr 1/2 hr 1/2hr 1/2 hr 1/2hr 8hr lhr 1/2hr lhr 8hr 1-1/2 hr 2hr 2hr 1/2 hr 1-1/2 hr 2-1/2 hr 1/2 hr 1/2 hr llhr 2hr lhr 1/2 hr 2hr 13-1/2 hr 2hr 3hr 1/2 hr 2hr 2-1/2 hr 1/2 hr 2-1/2 hr 2hr Activity Rigged down High pressure lines Rig moved 40.00 % Rig moved 60.00 % Rig moved 80.00 % Rig moved 100.00 % Rigged up Divertor Functioned Divertor Made up BHA no. 1 Held safety meeting Tested Fluid system Drilled to 1175.0 ft Held safety meeting Drilled to 1368.0 ft Circulated at 1368.0 ft Pulled out of hole to 0.0 ft Serviced Top drive R.I.H. to 1368.0 ft Drilled to 2400.0 ft Circulated at 2400.0 ft Pulled out of hole to 1185.0 ft R.I.H. to 2400.0 ft Drilled to 3438.0 ft Circulated at 3438.0 ft Circulated at 3438.0 ft Pulled out of hole to 2260.0 fl Serviced Top drive R.I.H. to 3438.0 ft Drilled to 4662.0 ft Circulated at 4662.0 ft Pulled out of hole to 3238.0 ft R.I.H. to 4662.0 ft Drilled to 5884.0 ft Circulated at 5884.0 ft Pulled out of hole to 219.0 ft Pulled BHA Serviced Drillfloor / Derrick Made up BHA no. 3 R.I.H. to 4210.0 ft R.I.H. to 5808.0 ft Reamed to 5884.0 ft Drilled to 7505.0 ft Circulated at 7505.0 ft Pulled out of hole to 8430.0 ft R.I.H. to 7505.0 ft Drilled to 7787.0 ft Drilled to 8670.0 ft Circulated at 8670.0 ft Pulled out of hole to 1017.0 ft Serviced Top drive R.I.H. to 8670.0 ft Circulated at 8670.0 ft Pulled out of hole to 7735.0 ft Pulled out of hole to 1017.0 ft Pulled BHA Progress Report Facility M Pt L Pad Well MPL-39 Rig (~a~-l)/V/- o~ 7,C-~ Page 2 Date 05 October 98 Date/Time 10:30-13:00 13:00-22:30 22:30-00:30 20 Jul 97 00:30-03:30 03:30-06:00 06:00-08:00 08:00-09:00 09:00-11:00 11:00-14:30 14:30-15:00 15:00-21:00 21:00-21:30 21:30-01:00 21 Jul 97 01:00-03:00 03:00-04:00 04:00-05:30 05:30-06:00 06:00-06:30 06:30-09:30 09:30-11:00 11:00-12:00 12:00-14:00 14:00-14:30 14:30-15:00 15:00-01:00 22 Jul 97 01:00-02:30 02:30-04:00 04:00-05:00 05:00-06:00 06:00-18:30 18:30-20:00 20:00-21:30 21:30-22:30 22:30-06:00 23 Jul 97 06:00-06:30 06:30-08:00 08:00-09:00 09:00-13:00 13:00-15:30 15:30-18:00 18:00-18:30 18:30-20:00 20:00-00:00 24 Jul 97 00:00-06:00 06:00-06:30 06:30-07:00 07:00-09:30 09:30-11:00 11:00-13:30 13:30-17:00 17:00-18:00 18:00-18:30 18:30-21:00 21:00-05:00 Duration 2-1/2 hr 9-1/2 hr 2hr 3hr 2-1/2 hr 2hr lhr 2hr 3-1/2 hr 1/2 hr 6hr 1/2 hr 3-1/2 hr 2hr lhr 1-1/2 hr 1/2 hr 1/2 hr 3hr 1-1/2 hr lhr 2hr 1/2 hr 1/2 hr 10hr 1-1/2 hr 1-1/2 hr lhr lhr 12-1/2 hr 1-1/2 hr 1-1/2 hr lhr 7-1/2 hr 1/2hr 1-1/2 hr lhr 4hr 2-1/2 hr 2-1/2 hr 1/2hr 1-1/2 hr 4hr 6hr 1/2hr 1/2 hr 2-1/2 hr 1-1/2 hr 2-1/2 hr 3-1/2 hr lhr 1/2 hr 2-1/2 hr 8hr Activity Serviced Casing handling equipment Ran Casing to 8648.0 ft (9-5/8in OD) Circulated at 8648.0 ft Mixed and pumped slurry - 490.000 bbl Circulated at 2081.0 ft Mixed and pumped slurry - 473.000 bbl Rigged down Casing handling equipment Rigged down Divertor Rigged up BOP stack Installed BOP test plug assembly Tested BOP stack Removed BOP test plug assembly Made up BHA no. 4 Repaired Top drive Serviced Top drive R.I.H. to 2081.0 ft Drilled installed equipment - DV collar Drilled installed equipment - DV collar R.I.H. to 8000.0 ft Held drill (Stripping) Tested Casing Drilled installed equipment - Float collar Circulated at 8690.0 ft Performed formation integrity test Drilled to 9930.0 ft Circulated at 9930.0 ft Pulled out of hole to 8648.0 ft Serviced Top drive R.I.H. to 9930.0 ft Drilled to 11534.0 ft Circulated at 11534.0 ft Pulled out of hole to 9267.0 ft R.I.H. to 11534.0 ft Drilled to 12150.0 ft Held safety meeting Drilled to 12323.0 ft Circulated at 12323.0 ft Pulled out of hole to 250.0 ft Pulled BHA Made up BHA no. 5 Held safety meeting Serviced Drillfloor / Derrick R.I.H. to 12323.0 ft Drilled to 12740.0 ft Held safety meeting Circulated at 12740.0 ft Pulled out of hole to 8648.0 ft R.I.H. to 12740.0 ft Circulated at 12740.0 ft Pulled out of hole to 8648.0 ft R.I.H. to 12740.0 ft Held safety meeting Circulated at 12740.0 ft Pulled out of hole to 1000.0 ft Progress Report Facility M Pt L Pad Well MPL-39 Rig (a,mt~/~/~ ,9, ~Z5 Page 3 Date 05 October 98 Date/Time 25 Jul 97 26 Jul 97 05:00-06:00 06:00-06:30 06:30-08:00 08:00-08:30 08:30-10:30 10:30-23:00 23:00-01:30 01:30-03:30 03:30-04:30 04:30-06:00 06:00-06:30 06:30-07:30 07:30-08:30 08:30-11:30 11:30-13:30 13:30-15:00 15:00-15:30 15:30-06:00 Duration lhr 1/2 hr 1-1/2 hr 1/2 hr 2hr 12-1/2 hr 2-1/2 hr 2hr lhr 1-1/2 hr 1/2 hr lhr lhr 3hr 2hr 1-1/2 hr 1/2 hr 14-1/2 hr Activity Rigged up Top ram Held safety meeting Pulled BHA Removed Wear bushing Serviced Casing handling equipment Ran Casing to 12717.0 ft (7in OD) Circulated at 12717.0 ft Mixed and pumped slurry - 56.000 bbl Tested Casing Serviced Casing handling equipment Serviced Drillfloor / Derrick Installed Wellhead integral components Serviced Top ram Rigged down BOP stack Installed Wellhead primary components Freeze protect well - 70.000 bbl of Diesel Held safety meeting Rig moved 75.00 % Progress Report Facility M Pt L Pad Well MPL-39 Rig (ma~l),/t/& ~ ~/~- Page 1 Date 05 October 98 Date/Time 25 Jun 98 15:00-18:00 18:00-18:30 18:30-06:00 26 Jun 98 06:00-06:30 06:30-08:00 08:00-09:00 09:00-12:00 12:00-12:30 12:30-15:30 15:30-16:00 16:00-18:00 18:00-18:30 18:30-19:00 19:00-00:00 27 Jun 98 00:00-02:00 02:00-02:30 02:30-06:00 06:00-06:30 06:30-07:30 07:30-14:00 14:00-15:30 15:30-17:30 17:30-20:30 20:30-00:00 28 Jun 98 00:00-03:00 03:00-06:00 06:00-06:30 06:30-07:00 07:00-08:00 08:00-09:00 09:00-10:00 10:00-22:00 22:00-00:30 29 Jun 98 00:30-02:00 02:00-02:30 02:30-04:30 04:30-06:00 06:00-06:30 06:30-07:30 07:30-08:30 08:30-09:00 09:00-10:00 10:00-21:00 Duration 3hr 1/2 hr 11-1/2 hr 1/2 hr 1-1/2 hr lhr 3hr 1/2 hr 3hr 1/2 hr 2hr 1/2 hr 1/2 hr 5hr 2hr 1/2 hr 3-1/2 hr 1/2 hr lhr 6-1/2 hr 1-1/2 hr 2hr 3hr 3-1/2 hr 3hr 3hr 1/2 hr 1/2 hr lhr lhr lhr 12hr 2-1/2 hr 1-1/2 hr 1/2 hr 2hr 1-1/2 hr 1/2hr lhr lhr 1/2 hr lhr llhr Activity Rigged down High pressure lines Held safety meeting Rig moved 100.00 % Held safety meeting Rigged up High pressure lines Removed Xmas tree Rigged up BOP stack Installed BOP test plug assembly Tested BOP stack Removed BOP test plug assembly Made up BHA no. 1 Held safety meeting Circulated at 2400.0 ft R.I.H. to 12630.0 ft Circulated at 12630.0 ft Tested Casing Pulled out of hole to 2500.0 ft Held safety meeting Pulled out of hole to 0.0 ft Conducted electric cable operations Rigged up Additional services Test Lubricator unit Perforated from 12382.0 ft to 12402.0 ft Perforated from 12382.0 ft to 12402.0 ft Perforated from 12362.0 ft to 12382.0 ft Conducted electric cable operations Held safety meeting Pulled out of hole to 0.0 ft Rigged down Lubricator Rigged up Bell nipple Rigged down sub-surface equipment - Hydraulic packer Ran Tubing to 12332.0 ft (3-1/2in OD) Rigged down BOP stack Installed Xmas tree Removed Accessories Reverse circulated at 12332.0 ft Freeze protect well - 70.000 bbl of Diesel Held safety meeting Tested Tubing Tested Casing Installed Accessories Serviced Block line Laid down 12630.0 ft of 4in OD drill pipe Schlumberger ANADRILL Survey Report Client: BP Exploration (Alaska), Inc. Field: Milne Point Well Name: MPL-39 Permanent datum MSL Depth measured from MSL Elevation of kelly bushing Elevation of drill floor Elevation of ground level Magnetic Declination 28.00 DEG Grid Convergence 0.00 DEG Total Correction 28.00 DEG Survey.ASCII FILE 24-JUL-97 06:01:37 51.42 FT 51.42 FT 17.10 FT Page 001 TIE IN POINT Measured depth True vertical depth N/S disp (-ye for S) E/W disp (-ye for W) 0.00 FT 0.00 FT 0.00 FT 0.00 FT Inclination 0.00 DEG Azimuth 0.00 DEG Azimuth from rotary table to the target 234.80 DEG Minimum Curvature Method MEASURED INTERVAL VERTICAL TARGET DEPTH DEPTH SECTION FT FT FT FT 0.0 0.00 0.00 0.00 204.2 204.20 204.20 1.07 296.5 92.30 296.48 2.73 387.6 91.10 387.52 5.95 478.0 90.40 477.78 10.65 567.3 89.30 566.88 16.50 656.2 88.90 655.44 24.18 745.9 89.70 744.59 34.01 835.0 89.10 833.00 44.99 924.8 89.80 921.87 57.87 1014.0 89.20 1009.74 73.15 1103.3 89.30 1097.21 91.13 1198.0 94.70 1189.28 113.23 1289.0 91.00 1277.08 137.10 1382.2 93.20 1365.99 165.02 1476.8 94.60 1454.83 197.49 1572.1 95.30 1543.69 231.89 1666.1 94.00 1631.18 266.24 1760.0 93.90 1717.56 303.02 1855.4 95.40 1803.98 343.39 1949.9 94.50 1888.44 385.72 2045.1 95.20 1971.72 431.79 2139.7 94.60 2052.09 481.67 2233.8 94.10 2129.63 534.97 2329.1 95.30 2206.49 591.28 STATION AZIMUTH LATITUDE DEPARTURE DISPLA- at AZIMUTH DLS INCLN. N/-S E/-W CEMENT DEG DEG FT FT FT DEG D/HF 0.00 0.0 0.00 0.00 0.00 0.00 0.00 0.63 217.2 -0.89 -0.68 1.12 217.20 0.31 1.49 247.2 -1.76 -2.09 2.74 229.87 1.08 2.68 248.7 -3.00 -5.17 5.97 239.90 1.31 3.52 252.0 -4.62 -9.78 10.81 244.70 0.95 4.18 242.4 -6.98 -15.27 16.79 245.44 1.03 5.86 244.5 -10.43 -22.24 24.56 244.87 1.90 6.84 240.9 -15.00 -31.04 34.47 244.20 1.18 7.38 238.6 -20.56 -40.56 45.47 243.11 0.69 9.14 238.6 -27.28 -51.57 58.34 242.12 1.96 10.62 237.7 -35.37 -64.56 73.62 241.29 1.67 12.64 236.3 -45.19 -79.65 91.57 240.43 2.28 14.37 237.4 -57.27 -98.17 113.65 239.74 1.85 16.09 238.5 -69.94 -118.44 137.55 239.44 1.92 18.82 235.7 -85.16 -141.87 165.47 239.02 3.06 21.35 232.7 -104.20 -168.18 197.85 238.22 2.89 21.00 232.4 -125.13 -195.51 232.13 237.38 0.38 21.89 233.1 -145.93 -222.87 266.40 236.78 0.99 24.27 232.8 -168.11 -252.24 303.13 236.32 2.54 25.85 231.8 -192.83 -284.21 343.45 235.84 1.71 27.44 232.2 -218.92 -317.60 385.74 235.42 1.69 30.49 233.4 -246.77 -354.33 431.79 235.15 3.26 33.17 234.5 -276.11 -394.68 481.67 235.02 2.90 35.85 236.3 -306.35 -438.57 534.97 235.06 3.05 36.63 236.7 -337.45 -485.55 591.29 235.20 0.86 2425.0 95.90 2280.96 651.64 2518.5 93.50 2349.16 715.58 2613.4 94.90 2414.67 784.22 2707.4 94.00 2476.21 855.25 2801.4 94.00 2533.60 929.67 2896.4 95.00 2587.63 1007.79 41.45 236.1 -370.88 -535.84 651.67 235.31 5.04 44.86 234.9 -407.11 -588.52 715.61 235.33 3.75 47.81 234.8 -446.63 -644.64 784.25 235.28 3.11 50.39 233.2 -488.40 -702.10 855.27 235.18 3.03 54.35 234.1 -532.51 -762.06 929.68 235.06 4.28 56.31 234.8 -577.93 -825.63 1007.80 235.01 2.15 Page 1 ORIGINAL Schlumberger ANADRILL Survey Report Survey.ASCII FILE 24-JUL-97 06:01:~7 Page 002 Minimum Curvature Method MEASURED INTERVAL VERTICAL TARGET STATION AZIMUTH LATITUDE DEPARTURE DISPLA- at AZIMUTH DLS DEPTH DEPTH SECTION INCLN. N/-S E/-W CEMENT FT FT FT FT DEG DEG FT FT FT DEG D/HF 2991.7 95.30 2637.17 1089.18 61.04 234.5 -625.02 -892.00 1089.18 234.98 4.97 3085.2 93.50 2680.39 1172.08 63.89 235.4 -672.62 -959.87 1172.08 234.98 -3.17 3178.5 93.30 2720.27 1256.42 65.50 235.2 -720.64 -1029.22 1256.42 235.00 1.74 3273.1 94.60 2759.12 1342.67 66.00 234.6 -770.23 -1099.78 1342.68 234.99 0.78 3365.3 92.20 2794.14 1427.92 69.35 237.3 -817.95 -1170.44 1427.93 235.05 4.53 3462.0 96.70 2826.48 1518.97 71.58 236.9 -867.45 -1246.96 1519.00 235.18 2.34 3554.7 92.70 2855.48 1606.95 71.95 237.1 -915.41 -1320.80 1607.01 235.28 0.45 3650.0 95.30 2883.28 1698.03 74.13 237.1 -964.92 -1397.33 1698.11 235.37 2.29 3744.8 94.80 2909.02 1789.15 74.36 238.2 -1013.74 -1474.40 1789.28 235.49 1.14 3838.2 93.40 2933.08 1879.27 75.78 237.5 -1061.76 -1550.81 1879.45 235.60 1.68 3931.3 93.10 2955.84 1969.46 75.93 237.1 -1110.53 -1626.78 1969.69 235.68 0.45 4025.4 94.10 2978.95 2060.59 75.63 237.6 -1159.74 -1703.58 2060.87 235.75 0.61 4119.8 94.40 3001.65 2152.13 76.55 237.0 -1209.25 -1780.69 2152.47 235.82 1.15 4214.8 95.00 3024.12 2244.35 76.08 237.3 -1259.31 -1858.23 2244.75 235.87 0.58 4308.0 93.20 3046.11 2334.88 76.63 235.8 -1309.24 -1933.80 2335.31 235.90 1.67 4402.6 94.60 3067.99 2426.90 76.62 235.3 -1361.30 -2009.69 2427.34 235.89 0.51 4497.5 94.90 3089.40 2519.35 77.30 235.9 -1413.53 -2085.97 2519.79 235.88 0.94 4589.6 92.10 3109.72 2609.17 77.21 235.5 -1464.15 -2160.18 2609.62 235.87 0.43 4682.5 92.90 3130.79 2699.62 76.57 236.7 -1514.62 -2235.28 2700.10 235.88 1.43 4780.3 97.80 3154.56 2794.44 75.30 236.3 -1566.98 -2314.38 2794.96 235.90 1.36 4874.0 93.70 3177.44 2885.29 76.43 235.3 -1618.05 -2389.53 2885.82 235.90 1.59 4968.0 94.00 3199.66 2976.62 76.23 235.2 -1670.11 -2464.58 2977.15 235.88 0.24 5063.2 95.20 3222.09 3069.14 76.51 235.5 -1722.71 -2540.69 3069.66 235.86 0.42 5156.4 93.20 3243.99 3159.72 76.31 235.3 -1774.15 -2615.26 3160.25 235.85 0.30 5250.4 94.00 3265.96 3251.12 76.66 235.1 -1826.32 -2690.31 3251.64 235.83 0.43 5343.7 93.30 3287.14 3341.98 77.10 235.3 -1878.17 -2764.92 3342.50 235.81 0.52 5438.5 94.80 3307.95 3434.47 77,54 235.2 -1930.89 -2840.91 3434.99 235.80 0.48 5533.1 94.60 3327.95 3526.92 78.04 235.1 -1983.72 -2916.79 3527.44 235.78 0.54 5627.0 93.90 3347.50 3618.76 77.93 235.5 -2036.01 -2992.30 3619.28 235.77 0.43 5721.7 94.70 3366.84 3711.46 78.50 235.2 -2088.72 -3068.56 3711.98 235.76 0.68 5813.3 91.60 3385.08 3801.23 78.53 234.9 -2140.14 -3142.14 3801.74 235.74 0.32 5903.4 90.10 3403.22 3889.48 78.24 234.0 -2191.45 -3213.94 3889.97 235.71 1.03 5998.4 95.00 3422.37 3982.52 78.50 234.6 -2245.75 -3289.50 3982.99 235.68 0.68 6091.4 93.00 3440.92 4073.65 78.49 234.0 -2298.93 -3363.51 4074.10 235.65 0.63 6183.7 92.30 3459.29 4164.10 78.55 234.1 -2352.03 -3436.73 4164.52 235.61 0.12 6279.9 96.20 3478.52 4258.34 78.39 233.6 -2407.63 -3512.85 4258.73 235.57 0.54 6374.1 94.20 3497.46 4350.61 78.41 234.2 -2462.00 -3587.40 4350.97 235.54 0.62 6469.3 95.20 3516.78 4443.82 78.18 233.9 -2516.73 -3662.87 4444.16 235.51 0.39 6560.6 91.30 3535.60 4533.15 78.03 234.0 -2569.31 -3735.10 4533.46 235.48 0.20 6657.4 96.80 3555.96 4627.78 77.68 234.7 -2624.46 -3812.00 4628.08 235.45 0.79 6753.0 95.60 3577.67 4720.88 76.07 234.4 -2678.46 -3887.84 4721.17 235.44 1.71 6846.4 93.40 3600.24 4811.50 75.96 234.0 -2731.47 -3961.35 4811.78 235.41 0.43 6940.0 93.60 3623.28 4902.21 75.54 233.9 -2784.86 -4034.69 4902.47 235.39 0.46 7033.0 93,00 3646.37 4992.29 75.71 234.4 -2837.62 -4107.71 4992.54 235.36 0.55 7127.2 94.20 3669.52 5083.60 75.84 234.0 -2891.04 -4181.77 5083.83 235.34 0.43 Page 2 Schlumberger ANADRILL Survey Report Survey.ASCII FILE 24-JUL-97 06:01:37 Page 003 Minimum Curvature Method MEASURED INTERVAL VERTICAL TARGET STATION AZIMUTH LATITUDE DEPARTURE DISPLA- at AZIMUTH DLS DEPTH DEPTH SECTION INCLN. N/-S E/-W CEMENT FT FT FT FT DEG DEG FT FT FT DEG D/HF 7223.4 96.20 3693.18 5176.83 75.68 233.6 -2946.11 -4257.02 5177.04 235.31 0.44 7316.6 93.20 3716.83 5266,97 74.92 234.9 -2998.78 -4330.18 5267.17 235.30 1.58 7409.7 93.10 3741.43 5356.76 74.44 235.3 -3050.15 -4403.82 5356.96 235.29 0.66 7506.5 96.80 3767.79 5449.90 73.96 235.5 -3103.04 -4480.49 5450.10 235.29 0.53 7599.0 92.50 3794.05 5538.59 73.05 235.0 -3153.59 -4553.36 5538.80 235.29 1.11 7694.1 95.10 3822.05 5629.47 72.71 235.6 -3205.33 -4628.08 5629.68 235.29 0.70 7788.0 93.90 3849.58 5719.22 73.19 236.5 -3255.47 -4702.55 5719.44 235.31 1.05 7881.2 93.20 3877.35 5808.14 72.14 236.7 -3304.44 -4776.82 5808.39 235.33 1.15 7974.2 93.00 3907.35 5896.11 70.22 237.0 -3352.58 -4850.52 5896.38 235.35 2.09 8068.2 94.00 3939.91 5984.23 69.24 236.8 -3400.73 -4924.39 5984.53 235.37 1.06 8162.2 94.00 3973.27 6072.08 69.19 235.7 -3449.55 -4997.46 6072.40 235.38 1.10 8257.7 95.50 4007.56 6161.20 68.73 235.8 -3499.72 -5071.13 6161.53 235.39 0.49 8349.7 92.00 4041.80 6246.56 67.57 236.7 -3547.16 -5142.13 6246.91 235.40 1.55 8444.8 95.10 4078.48 6334.28 67.05 235.6 -3596.03 -5215.00 6334.64 235.41 1.20 8540.0 95.20 4117.44 6421.12 64.63 235.4 -3645.22 -5286.58 6421.49 235.41 2.55 8573.7 33.70 4131.94 6451.54 64.40 235.0 -3662.58 -5311.56 6451.91 235.41 1.27 8719.2 145.50 4198.29 6581.02 61.34 234.7 -3737.12 -5417.43 6581.38 235.40 2.11 8813.5 94.30 4244.95 6662.96 59.34 234.8 -3784.41 -5484.34 6663.32 235.39 2.12 8908.3 94.80 4293.63 6744.30 58.86 234.0 -3831.77 -5550.48 6744.65 235.38 0.88 9001.7 93.40 4343.53 6823.24 56.55 233.7 -3878.33 -5614.23 6823.57 235.36 2.49 9093.9 92.20 4395.92 6899.09 54.20 234.1 -3923.04 -5675.53 6899.41 235.35 2.57 9188.1 94.20 4452.50 6974.39 51.95 234.7 -3966.87 -5736.75 6974.70 235.34 2.44 9282.8 94.70 4512.42 7047.71 49.54 234.3 -4009.45 -5796.45 7048.01 235.33 2.57 9377.3 94.50 4574.87 7118.63 47.73 234.2 -4050.89 -5854.01 7118.92 235.32 1.92 9469.9 92.60 4638.31 7186.08 45.78 234.6 -4090.15 -5908.85 7186.36 235.31 2.13 9563.8 93.90 4705.01 7252.17 43.70 233.9 -4128.76 -5962.49 7252.44 235.30 2.28 9660.3 96.50 4775.90 7317.62 41.74 234.1 -4167.24 -6015.45 7317.89 235.29 2.04 9755.4 95.10 4848.04 7379.57 39.57 233.4 -4203.87 -6065.42 7379.82 235.27 2.33 9849.8 94.40 4921.13 7439.28 38.96 232.5 -4239.86 -6113.10 7439.52 235.26 0.88 9943.8 94.00 4994.57 7497.89 38.28 232.0 -4275.78 -6159.49 7498.11 235.23 0.80 10038.4 94.60 5069.06 7556.12 37.83 231.5 -4311.88 -6205.29 7556.31 235.21 0.58 10132.6 94.20 5143.66 7613.53 37.45 230.6 -4348.04 -6250.02 7613.69 235.17 0.71 10228.6 96.00 5220.59 7670.81 36.01 231.5 -4384.14 -6294.67 7670.95 235.14 1.60 10322.6 94.00 5297.31 7725.07 34.59 233.1 -4417.36 -6337.63 7725.20 235.12 1.80 10416.7 94.10 5375.65 7777.18 32.68 234.0 -4448.33 -6379.55 7777.30 235.11 2.10 10512.0 95.30 5455.98 7828.46 32.44 233.7 -4478.59 -6420.96 7828.57 235.10 0.30 10606.2 94.20 5535.65 7878.71 32.05 233.5 -4508.41 -6461.42 7878.81 235.09 0.43 10701.1 94.90 5616.15 7928.95 31.90 233.2 -4538.41 -6501.74 7929.04 235.08 0.23 10794.6 93.50 5695.63 7978.17 31.67 232.7 -4568.08 -6541.04 7978.26 235.07 0.37 10888.1 93.50 5775.39 8026.91 31.24 231.9 -4597.92 -6579.65 8026.99 235.05 0.64 10982.7 94.60 5856.36 8075.75 31.02 231.4 -4628.26 -6618.00 8075.81 235.03 0.36 11076.4 93.70 5936.80 8123.70 30.69 230.6 -4658.50 -6655.35 8123.75 235.01 0.56 11170.8 94.40 6018.10 8171.54 30.41 230.3 -4689.06 -6692.35 8171.58 234.98 0.34 11266.6 95.80 6100.87 8219.61 30.06 229.7 -4720.06 -6729.30 8219.64 234.95 0.48 11360.1 93.50 6181.97 8265.93 29.62 229.1 -4750.34 -6764.63 8265.95 234.92 0.57 Page 3 Schlumberger ANADRILL Survey Report Survey.ASCII FILE 24-JUL-97 06:01:37 Page 004 Minimum Curvature Method MEASURED INTERVAL VERTICAL TARGET STATION AZIMUTH LATITUDE DEPARTURE DISPLA- at AZIMUTH DLS DEPTH DEPTH SECTION INCLN. N/-S E/-W CEMENT FT FT FT FT DEG DEG FT FT FT DEG D/HF 11455.1 95.00 6264.72 8312.31 29.21 228.1 -4781.19 -6799.62 8312.32 234.89 0.67 11548.7 93.60 6346.45 8357.74 29.15 231.1 -4810.76 -6834.37 8357.75 234.86 1.56 11642.4 93.70 6428.48 8402.91 28.65 230.3 -4839,44 -6869.41 8402.91 234.84 -0.67 11736.1 93,70 6511.12 8446.92 27.59 229.8 -4867,79 -6903.27 8446.92 234.81 1.16 11828.2 92.10 6592.68 8489.61 27.77 232.4 -4894.65 -6936.56 8489.61 234.79 1.33 11924.2 96.00 6677.31 8534.92 28.59 12019.2 95.00 6760.48 8580.81 29.19 12111.8 92.60 6841.54 8625.57 28.63 12206.3 94.50 6924.60 8670.65 28.36 12304.3 98.00 7011.08 8716.73 27.74 234.5 -4921.64 -6972.98 8534.92 234.79 1.34 236.2 -4947.72 -7010.73 8580.81 234.79 1.07 235.7 -4972.79 -7047.83 8625.57 234.79 0.66 234.8 -4998.48 -7084.87 8670.65 234.80 0.54 233.9 -5025.34 -7122.32 8716.73 234.79 0.77 12396.1 91.80 7092.57 8759.00 12491.6 95.50 7177.80 8802.08 12585.3 93.70 7261.75 8843.70 12662.7 77.40 7331.28 8877.71 PROJECTED TO TD 12740.0 77.30 7400.80 8911.51 27.10 26.53 26.21 25.93 25.93 234.9 -5049.95 -7156.69 8759.00 234.79 0.86 233.7 -5075.08 -7191.67 8802.08 234.79 0.82 234.8 -5099.40 -7225.45 8843.70 234.79 0.62 234.7 -5119.03 -7253.23 8877.71 234.79 0.37 234.7 -5138.56 -7280.81 8911.51 234.79 0.00 Page 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL · Type of Request: ~. Abandon [] Alter Casing [] Change Approved Program 2. Name of Operator BP Exploration (Alaska) Inc. ~ Suspend [] Plugging I--[Time Extension [] Perforate [] Repair Well 1-~ Pull Tubing [] Variance [] Other [] Operation Shutdown ~ Re-Enter Suspended Well [] Stimulate Complete & Change to Injector 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 3334' NSL, 5137' WEL, SEC. 8, T13N, R10E, UM At top of productive interval N/A At effective depth 1778' SNL, 1820' WEL, SEC. 13, T13N, R9E, UM At total depth 1805' SNL, 1858' WEL, SEC, 13, T13N, R9E, UM Type of well: [] Development [] Exploratory [] Stratigraphic F3Service 6. Datum Elevation (DF or KB) RTE = 51.42' 7. Unit or Property Name Mitne Point Unit 8. Well Number MPL-39 9. Permit Number 97-128 10. APl Number 50-029-22786 11. Field and Pool Milne Point Unit / Kuparuk River Sands 12. Present well condition summary Total depth: measured 12740' feet true vertical 7401' feet Effective depth: measured 12634' feet true vertical 7305' feet Casing Length Size Structural Conductor Surface Intermediate Production Liner 80' 20" 8617' 9-5/8" 12687' 7" Plugs (measured) Junk (measured) Cemented MD TVD 250 sx Arcticset I (Approx.) 112' 112' 2199 sx PF 'E', 550 sx Class 'G' 8648' 4166' 275 sx Class 'G' 12717' 7380' Perforation depth: measured N/A true vertical Tubing (size, grade, and measured depth) N/A Packers and SSSV (type and measured depth) N/A 1998 Alaska 0il & 6~ ~s. ~i~ 13. Attachments [] Description summary of proposal ~ Detailed operations program '.~ BOP sketch ~,~. Estimated date for commencing operation 115. Status of well classifications as: May 29, 1998 16. If proposal was verbally approved [] Oil [] Gas [] Suspended Service Name of approver Date appro..v, ed Contact Engineer Name/Number: Omar Nur, 564-5627 ~ Prepared By Name/Number: 17. I hereby (:edifY that thug is true,nd c_,elCreC~ to the best of my knowledge' ' Sig ned T. Brent Reav'~es~~~/~~tle Senior Dri,ling Engineer // -~-- .... ..- ........ Commission Use Only iConditions of Approval: Notify Commission so representative may witness Kathy Campoamor, 564-5122. Plug integrity ~ BOP Test ~ Location clearance__ Mechanical Integrity Test ~ Subsequent form required 10~~/-~0 "~ Original Signed By Approved by order of the Commission Form 10-403 Rev. 06/15/88 David vv. JO~lilS[UII Commissioner Submit In Triplicate OBJECTIVE' Install initial iniection completion in L-391 with the ddlling rig N-27E to prepare the well for IWAG service. SCOPE: Rig: · MIRU N27E · Eline convey GR/CCL and USIT logs · Eline perforate reservoir intervals · Cleanout well with casing scraper and reversing junk basket · RIH with 3-1/2" IBT-Mod. · Freeze protect well to 2000'MD. RE) 27E. BACKGROUND: L-39 was initially planned as a producer and was ddlled and cased by N27E dudng July 1997. The oil column encountered was less than expected due to an oil/water contact in the "A2" sand. Completion operations were therefore postponed until after L-40 was drilled into the same fault block. L-40 was successfully drilled and encountered a full oil column, The decision was then made to complete L-40 as a producer and L-39 as an IWAG injector to maximize recovery. It is intended to complete the well with the drilling rig N-27E. · 't A¥ 19911 hIAY 22 i ! I MPU L 39 Wellhead: 11" x 7 1/1~" 5M FMC -- Orig. GL Elev. = 17.1' ~en SA, w/2 7/8" FMC tbg. hng., 3" I~ RT To lbg. Spool = 34.3' (N 27E) LH acme on top and 27/8" EUE 8 rd on bottom, 2.5" CIW BPV pro,lc ~ ' :M~. hole a~fe = 78 ~g. ~Hole angle thru' peals = 27 deg, 7" 26 ppf, L-80, NSCC production casing ( drift ID = 6.151", cap. = 0.0383 bpf ) Stimplation Summa~ Peroration Summa~ , , Size SPF Inte~al (~O) , XXXXX Jet charges ~ 60 deg. nhm~inn ~ ~ : ~ ~ Ji~;~:~:~ k 7" float shoe [ '12,7i7,I DA~ REV. BY COMMENTS ' ' MILNE POINT UNIT 7-2B-97 .MDg 7" Cased Hole Completion .... WELL No: L-39 ........... BP EXPLORATION (AK)._. I ~ I III I1~ - i i ii n i Ires: Cameron 2 9/16" 5M Orig. KB Elev. = 5i .4 ' (N 27E) LH acme on top and 27/@" EUE 8 rd on bottoro, 2.5" CIW BPV profile ~ !l 20" 91.1 pp~. H-40 I [] [] 3-1/2" x Nipple KbP ~ 200. ~'o 4,soo, Max. hole angle --_ 78 deg, Hole angle thru' perfs = 27 deg. ,, · i' I 7" 2B ppf, L-B0, NSCC production casingi ( drift ID = 6.151", cap. = 0.03B3 bp( ) , , 1 1 I [] E 3-112" x Nipple I S,t,[m_ulation Summa~ i a-~/2" XN Nipple {2.75", , 2.65" NO) Pedorafion sum_ .mary , Ref IoQ: 7124197 Annadrill LWO Size SpF Inlerval (7'VD} i~ 4-1/2"5 12362'-12402' ~ j 7" (lear collar (PBTD) al ~."_---;~.~----%5--~ ~. 7" float shoe DATE REV. BY COMMEI~TS ' MILNE POINT U~IT i i m 7-28-97 MDO 7" Cased Hole .C.oropletion WELL No: L-39 5-6-98 SXN Proposed initial completion ... gPI: 50-029-22786 BP EXPLORATION III I m II .7. [ ! Schlumberger - GeoQuest A Division o.? ScniumDerger 1-echnolog~es Corporation 500 W. internat~onai Airport Road Anchorage, .alasKa 99518 - 1199 (907) 562-7669 CBus.) (907) 563-3309 fFax) April 27, 1998 TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center MB3-3 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 The following data of the Depth Corrected CDR/ADN, CDR/ADN TVD'S for well MPL-39, Job # 97417 was sent to: BP Exploration (Alaska) Inc. Petrotechnical Data Center, MB3-3 900 E. Benson Blvd. Anchorage, AK 99519-6612 E-TRANS 4~27/98 3 Bluelines each 1 Film each State of Alaska Alaska Oil & Gas Conservation Attn: Lori Taylor 3001 Porcupine Drive Anchorage, AK 99501 I OH LIS Tape 1 Blueline each 1 RF Sepia each OXY USA. Inc. Attn: Darlene Fairly P.O. Box 50250 Midland, TX 79710 1 OH LIS Tape 1 Blueline each 1 RF Sepia each Sent Certified Mail: P 067 695 454 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center MB3-3 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 Date Delivered: Schlumberger GeoQuest 500 W. International Airport Road Anchorage, Alaska 99618-1199 Received by.~O~/~/~, CI Fi I I_1-- I fM CS WELL LOG TRANSMITTAL To: State of Alaska October 8, 1997 Alaska Oil and Gas Conservation Comm. Attn.: Loft Taylor 3001 Porcupine Dr. Anchorage, Alaska 99501 ~I f I MWD Formation Evaluation Logs - MPL-39, RE: AK-RB-70205 The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of.' Jun Galvin, Sperry-Sun Drilling Services, 5631 Silverado Way, #G, Anchorage, AK 99518 MPL-39: 2" x 5" MD Gamma Ray & Neutron Porosity Logs: 50-029-22786-00 2" x 5" TVD Gamma Ray & Neutron Porosity Logs: 50-029-22786-00 1 Blueline 1 Rev. Folded Sepia 1 Blueline 1 Rev. Folded Sepia ©CT 08 -isa7 5631 Silverado Way, Suite G · Anchorage, Alaska 99518 · (907) 563-3256 · Fax (907) 563-7252 A Dresser Industries, Inc. Company 0 I~! I L_I_ I I~ (~S SEI::IL~I C E S WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Loft Taylor 3001 Porcupine Dr. Anchorage, Alaska 99501 MWD Formation Evaluation Logs - MPL-39, September 26, 1997 The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of.' fan Galvin, Sperry-Sun Drilling Services, 5631 Silverado Way, #G, Anchorage, AK 99518 1 LDWG formatted Disc with verification listing. API#: 50-029-22786-00 5631 Silverado Way, Suite G · Anchorage, Alaska 99518 · (9.07) 563-3256 · Fax (907) 563-7252 A Dresser Industries, Inc. Company TONY KNOWLE$, GOVERNOR ~kLASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 July 2, 1997 Tim Schoficld SeniorDrlg Enginccr BP Exploration (Alaska), lnc P O Box 196612 Anchorage, Ak 99519-6612 Ro: Milne Point Unit MPL-39 BP Exploration (Alaska) Inc. Pcrmit No. 97-128 Sur. Loc. 3334'NSL. 5137'WEL. Scc. 8. TI3N. RIOE. UM Btmholc Loc. 3438'NSL. 2004'WEL. Scc. 13. TI3N. R9E. UM Dcar Mr. Schoficld: Enclosed is thc approvcd application for pcrmit to drill thc abovc rcfcrcnccd wcll. Thc pcrmit to drill docs not cxempt you from obtaining additional pcrmits rcquired by law from othcr govcmmcntal agcncics, and docs not authorizc conducting drilling opcrations until all othcr rcquircd pcnnitting dctcnninations arc madc. Thc blowout prcvcntion cquipmcnt (BOPE) must bc tcstcd in accordancc with 20 AAC 25.035: and thc mcchanical integrity (MI) of thc injcction wells must bc dcmonstratcd undcr 20 AAC 25.412 and 20 25.030(g)(3). Sufficicnt noticc (approximatcly 24 hours) of thc MI tcst bcforc opcration, and of thc BOPE tcst pcrformcd bcforc drilling bclow thc surfacc casing shoe. must be givcn so that a rcprcscntativc of thc Commission ma,,' v,'itncss thc tcsts. Notice ma,,' bc givcn by contacting thc Commission at 279-1433. ._ Chainna'~ BY ORDER OF THE COMMISSION dlf/Enclosurc CC; Dcpartmcnt of Fish & Game. Habitat Scction v,'/o cncl. Dcpartmcnt of Environmcntal Conscrvation v,'/o cncl. STATE OF ALASKA ~- ALASKA OiL AND GAS CONSERVATION COMIv,,SSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work [] Drill [] Redrill Ilb. Type of well [] Exploratory [] Stratigraphic Test J~[,Development Oil [] Re-Entry [] DeepenI [~ Service [] Development Gas [] Sin~lle Zone [] Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc. Plan RTE = 49.5' Milne Point Unit / Kuparuk River 3. Address 6. Property Designation Sands P.O. Box 196612, Anchorage, Alaska 99519-6612 ADL 025514 4. Location of well at surface 7. Unit or Property Name 11. Type Bond (See 20 AAC; 25.025) 3334' NSL, 5137' WEL, SEC. 8, T13N, R10E, UM Milne Point Unit At top of productive interval 8. Well Number Number 2S100302630-277 3559' NSL, 1842' WEL, SEC. 13, T13N, R9E, UM MPL-39 At total depth 9. Approximate spud date Amount $200,000.00 3438' NSL, 2004' WEL, SEC. 13, T13N, R9E, UM 07/04/97 12. Distance to nearest property line113. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) ADL 388235, 1842'I No Close Approach 2560 12764' MD / 7425' TVD 16. To be completed for deviated wells 17. Anticipated pressure {see 2o AAC 25.035 (e) (2)} Kick Off Depth 300' Maximum Hole Angle 110° Maximum surface 2865 psig. At total depth (TVD) 7165' / 3582 psig 18. Casing Program Setting Depth Size Specifications Top Bottom Quantity of Cement Hole Casing Weight Grade Coupling Length MD 'I-VD MD TVD (include stage data) 24" 20" 91.1# H-40 Weld 80' 32' 32' 112' 112' 250 sxArcticsetl(Approx.) 12-1/4" 9-5/8" 40# L-80 Btrc 8669' 31' 31' 8700' 4192' 1952 sx PF 'E', 541 sx Class 'G' 8-1/2" 7" 26# L-80 Btm 12734' 30' 30' 12764' 7425' 245 sx Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary '- I.J ~.J'l L.. I ~., I t I L. Total depth: true measured vertical feet feet Plugs(measured) ORIGINAL Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented MD TVD Structural Conductor Sa,ace ~..,-~ ~ ~ ;~ '"'~ ~' Intermediate ~ !. "h~ Production Liner \.1'.'; - Perforation depth: measured true vertical 20. Attachments [] Filing Fee [] Property Plat [] BOP Sketch [] Diverter Sketch [] Drilling Program [] Drilling Fluid Program [] Time vs Depth PIct [] Refraction Analysis [] Seabed Report [] 20 AAC 25.050 Requirements Contact Engineer Name/Number: Lance Spencer, 564-5042 Prepared By Name/Number: Kathy Carnpoamor, 564-5122 21. I herebYsigned certify that the foregoing i~tru~7 and.~coIrgct-~"'~ t"" ' ~ - *-' to the best of my knowledge/~/T/~---- Tim Schofield ' ' '" 6 '7' ///,fi'/ ~ C.',¢'~)~..{.6Jr Title Senior Drilling En~lineer Date // Commission Use Only Permit Number J APl Numberi/- .._ ~.- J Approval Qate J See cover letter -.J for other requirements Conditions of Approval: Samples Required []Yes ~ No Mud Log Required []Yes J~JNo Hydrogen Sulfide Measures []Yes ]~ No Directional Survey Required []Yes []No Required Working Pressure for BOPE [-I 2M; [-I 3M; li~ 5M; I--I 10M; I--I 15M Other: Original Signed By by order of "7/'~IA Approved By David W. Johnston Commissioner the commission DateI/~//,~ Form 10-401 Rev. 12-01-85 Subm'~ Triplicate Shared Services Drilling Contact: I Well Name: J Type of Well (producer or injector): Lance Spencer I MPL-39[ Well Plan Summary I Kuparuk Injector 564-5042 ISurface Location: Schrader Bluff Target Kuparuk Target Bottom Hole Location: 3334' NSL, 5137' WEL, Sec. 08, T13N ,R10E, UM., AK 82' NSL, 4547' WEL, Sec. 07, T13N ,R10E, UM., AK 3559' NSL, 1842' WEL, Sec. 13, T13N, R09E, UM., AK 3438' NSL, 2004' WEL, Sec. 13, T13N, R09E, UM., AK I AFE Number: I I I Rig: I Nabors27-E I I Estimated Start Date: 14 July 97 I I Operating days to complete: I 13 IuD= 112,764' I I mvo= 17,425'au, I IEEE= 149.5 Well Design: Ultra Slim Hole Long String I 9-5/8", 40# Surface X 7", 26# Longstring Formation Markers: Formation Tops MD TVD (bkb) EMW Formation Pressure Base Permafrost 1859 1800 8.4 ppg 786 psi NNSchrader Bluff 7726 3840 8.4 ppg 1677 psi Target OA 8286 4010 8.4 ppg 1751 psi OB 8499 4098 8.4 ppg 1790 psi Base Schrader 8566 4128 8.4 ppg 1803psi Top HRZ 11779 6570 8.8 ppg 3006 psi Base HRZ 11877 6655 8.8 ppg 3045 psi TKLB(MK-19) 11975 6740 9.2 ppg 3224psi TKUD 12159 6900 9.2 ppg 3301 psi TKUC 12286 7010 9.6 ppg 3505 psi TKUB 12291 7015 9.6 ppg 3507 psi TKA3FFARGET1 12355 7070 9.6 ppg 3535 psi TEA2 12372 7085 9.6 ppg 3542 psi TEA1 12407 7115 9.6 ppg 3557 psi TMLV 12464 7165 9.6 ppg 3582 psi Total Depth 12764 7425_+ 9.6 ppg 3712 psi · *These are estimated maximum pressures. Casing/Tubing Pro.clram: Hole Size C~sg/ T Wt/Ft Grade Conn Length Top Btm Tbg O.D. MD/TVD MDrFVD 24" 20" 91.1 # H-40 Weld 80 32/32 11 2/112 12 1/4" 9-5/8" 40# L-80 btm 8669 31/31 8700/4192 8-1/2" 7" 26# L-80 btrc 12734 30/30 12764/7425 The internal yield pressure of the 7" 26# casing is 7240 psi. The deepest anticipated gas should occur no deeper than the oil water contact which is expected below the TEA1 at __. 7,165 TVDbkb In this instance, this worst case surface pressure would occur with a full column of gas from the reservoir from a depth of -,-7,165 TVDbkb. The maximbm anticipated surface pressure in this case assuming a reservoir pressure of 3,582 psi is 2,865 psi using a 0.1 psi/ft gas gradient, well below the internal yield pressure rating of the 7" casing. MP L-39 (L-97a) Drilling Permit 1 6/20/97 Cementing Program: Halliburton Cementing Services Hole Casing Interval Volume~ Spacer Type of Cement Properties2 Category S!ze.~Depth Surface Lead .Lead" Lead Lead Lead First 9-5/8" @ 2059-7256' 975 sx 70 bbls Fresh Permafrost "E" Den 12.0 ppg Stage 8,700' 377 bbls water Yield 2.17 ft 3/sx Water 11.63 gps 'IT 4.0 hrs Tai__[I 7256-8700' Tails Tai__l Tai__l 541 sx Premium Class "G" w/ Den 15.8 ppg 111 bbls 0.2 % CaCI, 0.15 #/sk Celoflakes Yield 1.15 ft 3/sx Water 4.9 gps TT 4.0 hrs ....... '§~'¢,'~i ...................... ~{~;~' ..................................... G'~. .............. r;~;~' .................... i¥~i ....................................... i';~'~.'~i ......................................................... Stage collar° @ 0-1859' 977 sx 75 bbls Fresh Permafrost "E' Same as above 2,059' 1859-2059 378 bbls water Wellhead If Lead/ Lead Lead Stability Cmt necessary. 150 sx Permafrost "E" Same as above Production Lead" Lead Lead Den 15.8 ppg First 7" @ 11159- 245 sx 20 bbls. Premium Class "G" w/ Yield 1.15 ft 3/sx Stage 10,498' 12764' 51 bbls Fresh water 0.2 % CFR-3 Water 5.0 gps 70 bbls NSCl 0.1% HR-5 TT 3.5-4.5 h rs @ 140° F 0.45% Halad 344 FL 50cc/30 min @140° F 1. Volumes are rounded u ~ to the nearest 10 sacks. 2. Ensure thickening times are adequate relative to pumping job requirement. Actual times should be based on job requirements and lab tests. Perform lab tests on mixed cements, spacers and muds to ensure compatibility prior to pumping job. 3. A Type H ES Cementer will be installed in the 9-5/8" csg. which is 200' md below the base of the Permafrost at 2059'MD-~-_ 4. The surface hole First Stage LEAD Cement Volume. Interval from 2,059-7256' md. The estimated first stage lead cement volume from 2,059-7256' md is equivalent to the annular volume calculated from the 9-5/8" ES Cementer at 2,059' md which is 200 ft md below Base of the Permafrost at 1,859' md (1,800 TVD bkb) to 7,256' md which is 500' above the NA top plus 30% Excess. 5. The surface hole First Stage TAIL Cement Volume covers the interval from 7,256-8700' md. The estimated first stage tail cement volume is equivalent to the annular volume calculated from the 7,256' (500' md above the NA top) to surface TD at 8,700' md (4,192' TVD bkb) plus 30% open hole excess and the shoe joint volume. The estimated shoe joint volume is equivalent to the capacity of 80'md of 9-5/8", 40# casing. 6. The surface hole Second Stage Lead Cement Volume covers the interval from 0-2,059' md The estimated second stage lead cement volume is equivalent to the annular volume calculated from the ES cementer located at 2,059' MD (1,973' TVDbkb) to surface. From 1859' to surface include 250% open hole excess and from 1,859-2,059' use 30% open hole excess. 7. The estimated Well head stability Cement Volume is 150 sacks. It will be pumped if necessary to provide support to the well head. 8. Install one(l) Bow Spring Centralizers per joint on the bottom 10 joints of 9-5/8" casing (required). 9. If the Schrader is productive, install one(l) Bow Spring Centralizers per joint from 7400-8700' on the 9-5/8" casing to cover the top of the NA to Base OB. 10. The production hole LEAD Cement Volume covers the interval from 11,159-12,764' md The estimated cement volume is equivalent to the annular volume calculated from 11,159 to TD at 12,764' plus 30% open hole excess and the shoe joint volume. The estimated shoe joint volume is equivalent to the capacity of 80'md of 7", 26# casing. 11. Use 7' × 8-1/4" Straight Blade Rigid Centralizers and install TWO per joint from 120' below to 120' above any potential hydrocarbon bearing sands. 12. Run two (2) 7" x 8-1/4" Straight Blade Rigid Centralizers on the second full joint inside the 9-5/8" casing. 13. Install two 7' marker joints and position three joints above the Kuparuk C sand. 14. Place all centralizers in middle of joints using stop collars. 15. Mix all cement slurdes in the surface and production holes on the fly - batch mixing is not necessary. MP L-39 (L-97a) Drilling Permit 2 6/19/97 Logging/FOrmation Evaluation Proqram: Anadrill Schlumberger Op;n'r Ho~e Logs: None Surface-12-1/4" 1. M10 Power Plus MWD Directional from top to bottom of surface hole.. 2. LWD (CDR/GR/ROP) from TOP Schrader Bluff to TD of surfa~ hole. 4. DWOB/DTOQ from top to bosom of sudace hole. Intermediate N/A Final Production 1. M10 Power Plus MWD Directional 8-1/2" 2. LWD (CD~AND/G~ROP) (Real Tim~) 3. DWOB/DTOQ Cased Hole Lo~s: N/A Mud Logging Schlumberger IDEAL System in the sudace and production holes. SPIN Log: Record: GR, Depth, Sudace Torque and DWOB/DTOQ, ROP, Hook Load, RPM, Pump Pressure, GPM (in and out) during all operations. 12-1/4" and 8-1/2" Hole M10 PowerPlus IWOB: GR: CDR: ADN: ROP: Directional Inclination and Azimuth DWOBB/DTOQ Gamma Ray Compensated Dual Resitivity Azimuthal Density Neutron (Density, Porosity, and Sonic Caliper) Rate of penetration Mud Program: Baroid Drilling Fluids Inc. Surface Mud Properties: LSND Freshwater Mud Density Marsh Yield 10 sec 10 min pH Fluid Solids (PPG) Viscosity Point gel gel Loss % 8.6-9.6 50-150 15-35 8-25 20-35 9-10 8-15 <9 Production Mud Properties LSND Freshwater Mud Density Marsh Yield 10 sec 10 min pH APl HTHP Solids (PPG) Viscosity Point gel gel Filtrate %LGS 8.6-10.2 35-45 6-20 3-10 7-20 8.5-9.5 6-12 8-10 for <6 <4 Miluveac h Well Control: Well control equipment consisting of 5000 psi working pressure pipe rams, blind rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. The diverter, BOPE and drilling fluid system schematics are on file with AOGCC. Directional: KOP1 300' Start Variable @ 1.0°- 3.0 °/100 and Az 305.13°. EOB 3479' Tangent Hole Angle 75.59° from 3,479-7,826' KOP 3 12242' Start Curve @ 3.5 °/100 to 110° incl. and 310 Az o EOB 11408' Maximum Hole Angle Close Approach Wells Survey Program 110° from 12801-12854' All wells may remain flowing while drilling ~9~ and no shut-ins are required. 1. Surface to 8,700' MWD surveys. MP L-39 (L-97a) Drilling Permit 3 6/19/97 Disposal: No "Drilling Wastes" will be injected or disposed into L-35 while drilling this well. Cuttinqs Handlinq: Cuttings should be hauled to the ball mill at CC-2A. The Milne Point reserve pit can be opened in emergencies by notifying Karen Thomas (564-4305) with request. Fluids Handlinq: All drilling wastes will be hauled off and disposed of in accordance with pertinent rules and regulations. GENERAL DISCUSSION Well Obiective: MPL-39 planned to the northeast corner of tract 22 is planned as a 12,764' md', 8,969' departure, S-Shaped Kuparuk River A Sand Producer. With this S-shaped design the well bore will intersect targets in the Schrader Bluff and Kuparuk. This profile will facilitate optimum fracture stimulation. The surface casing will be deep set below the Schrader Bluff at 8,700' measured depth to isolate the Ugnu and Schrader Bluff from the Kuparuk interval. The Kuparuk may be partially pressure depleted but is expected to be normally pressured with an estimated pore pressure of 9.62 ppg EMW. The target location is directly offset by Kuparuk Unit injection and production from 3R and 30 pads. Communication across the fualts is not anticipated. To date, no wells have penetrated the L-39 fault block. Excessive pressure depletion from area production or high pressure from injection are not anticipated. GeolocIv - L-39 (MPL-97a) will target the Kupauuk A3, A2 and A1 sands with some potential in the Kuparuk B and C sands. The Kuparuk target was selected to prove up reserves in the Tract 22 accumulation. L-39 could prove up an estimated 11.1 MSTBO in place, and 3.9 MSTBO in reserves (1.7 MSTBO primary and 2.2 MSTBO secondary). The closest faults from the target center are: 350' northeast, 700' east and 540' south west. The shallowest OWC could be at 6,718' TVDss and with oil up to 6666' TVDss. The nearest well to the target location is 6,100'. DRILLING HAZARDS AND RISKS SUMMARY: Formation pressures are expected to be normal (9.6 ppg EMW) or partially depleted and not be affected by Kuparuk injection. The deep set surface casing design is recommended to alleviate potential problems of differential sticking and lost circulation in the Ugnu and Schrader Bluff while drilling the Kuparuk. The well profile has been designed to avoid close approaches and no wells will be shut in while drilling this well. Lost circulation and stuck pipe have occurred but not recently and are not expected. · Close Approaches There are no close approaches associated with the drilling of MP L-39, however, tolerance lines should be carefully monitored and deviations from the proposed well path minimized. Water, Gas and WAG Iniection Formation pressures are expected to be partially depleted at a maximum of 9.6 ppg EMW pore pressure in the Kuparuk while drilling L-39. Kuparuk injection wells 3R-20, 30-05 and 30-07 are to the west of MPL-39 and Milne Point injection wells L-15i and L-081 are to the north. The Kuparuk and Milne injection wells are not expected to be in communication with the proposed well I_-39 and should not abnormally pressure the reservoir. Annular Iniection Currently annular injection is not permitted on L-Pad. Lost Circulation: Lost circulation has been most prevalent while running casing and cementing in the surface as well as production hole. Losses are extremely probable while cementing the long string in wells with shallow set surface casing. Losses have been experienced while drilling the 12-1/4" surface and while circulating to condition mud before, while and after running surface casing. Major losses have also occurred while cementing the production casing. In many instances, the losses were minimized by reducing swab and surge pressures, minimizing mud weight and conditioning the mud before cementing. MP L-39 (L-97a) Drilling Permit 4 6/1'9/97 Stuck Pipe Potential: Running gravel's, sticky clays, tight coal sections, packing off, bridging, and stuck pipe have occurred while drilling the 12 1-4" surface holes on L-Pad. Excessive amounts of reaming have been required to condition the hole to run surface casing after drilling the surface hole. While running 9-5/8" casing the following problems were experienced: hole packing off; tight hole and bridging, and the 9-5/8" casing has been stuck. While drilling the surface hole additional time has been spent reaming and conditioning the hole prior to cementing because of tight hole. Caution is advised while drilling the Ugnu and Schrader Bluff formations to reduce the chances of differential sticking in these formations While drilling the production section increased torque and drag have been experienced after drilling into Kuparuk. This is common occurrence, has often caused difficulties, so care should be taken to avoid the stuck pipe while drilling the 8 1/2" production interval. Attention should be given to avoid excessive mud's weights to keep the HRZ and Kalubik shales stabilized and risk breaking down the Kuparuk formations.. Differential sticking and lost circulation is most likely to occur while running and cementing the production string. Formation Pressure: KUPARUK C SAND 7010' TVDss 3505 PSI 9.6 PPG EMW The deepest anticipated gas should occur no deeper than the oil water contact which is expected below the TKA1 at _ 7,165' TVDbkb. In this instance, this worst case surface pressure would occur with a full column of gas from the reservoir from a depth of ,7,165' TVDbkb. The maximum anticipated surface pressure in this case assuming a reservoir pressure of 3,582 psi is 2,865 psi. The maximum expected pore pressure for this well is 10.5 ppg EMW (3,582 psi @ 2,865' TVDbkb). There has been injection in this region, however the reservoir pressure is not expected to exceed this estimate. See the updated Milne Point L-Pad Data Sheet prepared by Pete Van Dusen for information on L pad and review recent wells drilled on L Pad. MP L-39 (L-97a) Drilling Permit 5 6/19/97 MP L-39 Kuparuk Producer Proposed Summary of Operations 1. Drill and Set 20" Conductor. Weld an FMC landing ring for an FMC Gen 5A Well head on conductor as well as a nipple to aid in performing potential well head stability cement job. 2. Prepare location for rig move. 3. MIRU Nabors 27E drilling rig. 4. NU and test 20" Diverter system. Ensure the diverter is as per AOGCC specifications and is approved by an AOGCC supervisor. Build Spud Mud. 5. Drill a 12-1/4" surface hole as per directional plan. Run Directional MWD/LWD (GR/DIR/CDR/DWOB/DTOQ) from surface to 12-1/4" TD. 6. Run 9-5/8" casing. Space out ES Type H Cementer to 2059' md. 7. Perform Two Stage Cement Job. Complete the surface casing cementing check list. 8. ND 20" Diverter, NU and Test 13-5/8" BOP 9. MU a PDC bit on an extended power section medium speed motor, with Directional MWD and LWD (GR/DIR/CDR/DWOB/DTOQ/ADN). RIH, Drill out Float Equipment and 20' of new formation. Perform Leak Off Test as per Revised Recommended Practices Manual. Record pressure versus cumulative volume for LOT test for the well file. 10. Drill 8.5" hole to TD as per directional plan. Make sure sufficient footage is drilled to provide 250' of production rat hole between the base of the Kuparuk A sand and PBTD before running the 7' casing. 11. Perform Single Stage Cement Job. Complete the surface casing cementing check list. 12. Displace cement with 8.4 ppg filtered sea water and enough diesel to cover from the base of permafrost to surface (+-2100' MD). 13. Test casing to 3500 psig. 14. ND BOPE and 11' drilling spool NU tubing spool and dry hole tree and Test Tree. RDMO Nabors 27E. 15. RDMO Nabors 27E. THE WORKOVER PROGRAM WITH A DETAILED COMPLETION PROCEDURE SHALL BE SUBMIT-i'ED ONCE THE PERFORATION INTERVALS ARE SELECTED. MP L-39 (L-97a) Drilling Permit 6 6/19/97 Anadrill Schlumberger .. Alaska District 1111 ~ast ~Oth Avanue 349-4511 PaX 344-2160 '. ~e~ ......... ~i }4~-K L-97A e01 Pield ........ , ~Lne 'Po~mt, ~-Pad Com~u=a~£on,.'~ H£ntmumC~rva~u~e. · · . · .. ~tts ......... = ~. . Surface ~nS..= ~9:6~%~38~ ~ -. : , , . ,, ~ '.' mmmm~m~mmmmmmmm m,~'mm mm m~mmmmm STATION .i DIP~CTIO~U~WH~J PLAN [or SHARBD SE[~ICHS DRILL~N~ .. ..... : .' ~ega£,Descrl~tlon~___ ..... Y-Coord . . Surface ...... I 3334 ~ch=ader ~,~ ' 82 PSh'4547 F~h' S07 T13N ~3OE~ . 540085,00.'602824~;00 :... 3 '... , '. · ~p~k T~C.., 3559 .~Sh ,i812 FH~ '*%3 T13N.R~B~ 53~6'10',00 6'.0~6430.00 B~ .......... r 3438.'~S~ 2004 FHb. 8i3 T13~ ROgH'~ 537448J'T~..'6026~07.43' .... .. . .. . .. ... ~. *', ... ~ ~ . . '. '.-~ .:" : · . . ... '. ~ . . .... . , ~ .... ~ ~=--,=,,=~ ..' ~. ~- .." . . ...'"...: .. IN~' :DI.~/ON .,.~I~;DEPT~,' ,. . .. . '.'.. , . .: ,.... · . IDH~IPI~ON".' Oa~ · '~ .....~H "' ~ ' :S~,S~ DEPOT . * . ', , . · . , . .... . , . , . . . . .... · ,. . ........ ...., .... . ... .. .. .... :~,.. ' ~o~ / ~ux~o.l'.2s/loo '30o..oo .... 400.00 .. aU~ 1,7.&/100 1.25 '2,50 · .3,13 *'... 4.00 SOO,O0 550.0'0' ,. "60o..oo .vo0.oo. · 800.00' ?",50 900.00 .9..5o ,~0oo.oo ~.3:5o," · , . o:oo ,.,o..oo ..o :,oo '. '.:235;~1 · - .235 ~'~ ~ 235~.23 235.2~ '235.21 2as.2s .235.2£ '.2~.~s 235,2~ o.oo -4~.5o ,oo.oo So.so .. 399.99 350.49 .499.9~ 450~44 549.88 500~'38 599.?8 55o.28 ~S.~ a~7'.64 '848.~4 BUILD 2/10o .Prepared ..... : 0% Oun ~997 Vert sect az.t 234.82 KB elevation.t 49,50 ft Magnetic Dcln: +28.005 · Scale Factor.: 0,9999022~ Convergence,,~ ~0.3~489356 mmm Slam tm m tmm mms mmm f ti m ~mm lu,~.amm COORDID~TF.~- PROM -' WHhL.~EAD mmm~mmmmmm isudfmmm.wre~ mmmwmr-~mml 0,00' 0.OD N 0.00 P- -0,00 O.'O0 E 0.00 B 1.09 1.3// 6:82 · ALASKA Zone 4 TOO~, D6/ '.. X Y PACH LOG ~4{7&3','49 603~5~3,36 125L ~.00 54%T43.49 '603~523.36 12~L ~.00 O,62 S 0.90 R 544742,60 .~033522.~3 L25~ ~,25 '2.49 S 3.58 W 544839;92' 6031520.85 £251 'L~25 3.99 S S.60 W 544?37.92 60315~9.44 1'251 L.25 18.42 20.51 29.96 1V,09 44.?4 25.53 62~96 35,92 8.15'W 544735.38'6031517.65 '3251 3.~$ 15.13 W 544728.43 603L5/2.76 HS 1.75 2~.60 ~ ;44~18,99 6031506.~2 HS 1.75 36.74 ~, 5~4706,91 603~497.62 ~S 2.00 51.91 W 54469,2.01 6031487.13 HS ~,00 1100.00. 13.50 · . .. " . - . . . · . .. . . · · 235,21 1093.58 L044;08 · .. 84,60 69.48 W S44674.3l 60314?4.6? RS 2.00 M~b-K b-gTA Jun ~97 Pa~e .3 OB BAS]~ $CD[RADBR' ~NCL~ ~.30 72.ss 70.80 .. 82D0,00 '8285.$6 .. 83oo~ oo s~oo.Oo 9499,32 .. ~. , 85oo~°o es65:93 8'600.00 ~eoo.oo · .. . , . 8900~0D .56.e3 sooo..b° ,ss.o6 ',~oo.oo "~3.3~ '2oo.bo....sl,86 2300.0·0· 49.8·Z 69.05 67.5 6~o~ 65;5S '~3.82 '9400,00 sso0.oo , . 2700,00 ,gaOa.oo ., mml~m~m O z~,~c~ IoN ,, . · . ~ m' ' mmNme m Nm mmm mmmm~m~m 235.08 3943..55 3894.05 .. 235.03 3977.87 ,, . . 234.98 4015.04 234.93 4055~03 . ,. : . ~' · mi m mm mmf ., .. 5696.84 .5793',70 5865.08 6055.8~ ., . mlmmmmmma~awmmm·mmmam . C00RDI~L~T~S-PROH ~HbL~AD' mm/mmluLmmmm mmmmmwmmmm 3250.S$ S 46~8,60 N 3305,84 $ 4758.L4-N 3346.52 S 4816.;5·~ 340L.35 ~ 4895.41.~ 3455,66 S ~973.26 ~ 3928°37 6349.V6 3508.45 $, 5050.25 . 3260,00. 622~.'26 ...35'55.04 ~ 5118.3O'~. 3965.54.. 6242'.S~." 35~2.69 8 5%26.30 W' , 4005.53 6334.25 3615.31 ~ 520L.34 ~ 4048.00 ' ,6424.02 3666.93 S 5274.79 ~ · 63.a0 "2~4.88 .... 40~9.'80 '4o48,3o 62.65 ,234',84 '4L2~.50 4078'00 ' 62.05 ,.,' 234.8; 4L43;3l ·4093.81 60,3'0" 234.77 '4X93,52' 4142~02 · . . ,, · .....', "S8.,56' ',.,'234'.?t.' '.4242,3~ 'it'~2.87 .. 46'~3L 42.81 4~o6 9900~00 39.32 · toooo.oo. .'XOL00,00' .35.82 (Xnadrll. 1 to) 97. K~1.KPQ2 3JOC 3,36 PM P) ·, ; .. mmm' mm m mm' . m mmm m m mmmmgm · : ... A:LA,.qKA Zone 4 · '.. . . . mm ] ' mmmmmu mul 840005;00 '6'0282i5.00 . 94ooo~;.80:.:~02~L.59.'26 ..... .' :..' , ... .,: .... . · 5329~7.44. 6028348.17 . . 539862.82 6028092.94 -. · ... -.::..}: 5397X~.95 6027903:92" u mi mi m ~cooh W./ L~ACB ' 'lO0 mm mum m. m 0 ..00 179L L~.75 279L 1.75 .5396'5~:10'60279~?',~S' 53.963~.23 6o29530..3.3 %.?eL -. S39564.5~ 602707~.t6 ~78L ~.?S 53949~,38 6027825,££ 370.L '2.75 .,: . ,.. , ... ., ., · · , . ....~.. '. , ,.... 6424.;3 3669.28 s 5275'.3d W 532496.88. 602?B24~;' ,S78~ '3'..75 .'%. ,- ., · . ,... . .., 6483,.42 3703~16 S 5323.43 W 539442','86.'602~720.59 Z78~..1..?$ :, , ..:..:,~..,. .'23d.45 23~-88 · . :'234 234.23 . 234.05 ~33;96 ,. 23~ 233,74 233,62 '. '&S34.7'o .:" 46'~0.39 46Fn..38 473B,SL 48'2o,'82 .. 4885,20 ,. ..., ,. ., . '4,96[.59 · 5039.91 , 5110.10 234.65""42~S.,4' 4246,'3~ ,6~7~.00" 234,52 '4351:e'5 4302;35 '..~8&4',72 ' 234.52 . 44'~0':'3~ '4360,87 6935,80 ,4~8'5.20..~0~2,'4'2 ,, , ,'' ., . · , , ,. '~$$o.e~. ,. 46t8,85 72i1'.16 i6~9,01 ~312,.4o '4761,32 ' 738t.47' .: . , 4835,70. , ., 4932,09 4990;4L 7574.97 5070,60 3867.:60 $ 5558.9~ w 539208=4? 602'7622,75 .... . , . - - .: ;: . .... . . ..' . , 3962,58 ~' 5692,54. w 53:9075..'4~:.602~526~97 ... ,. .., .. ' 4008,62 S 5759,.05 ~ 5390L~.23' 602V480.,55 .,.. . . ,, . ..,, . · . . ..' · 4053,64 .. - . . ... . ~o9~.58 s 5888.23. w '.53d8'07,eo ~02'?agO.85 .... . , , ,.. .4140/42 8 59~0,78 .W 53882,8.,32 t~a~.ts s S99~.85 W, · 8387~o.8~ .6o~305.63 .. t222,6~ & gOS4,50'w 5'38'9~5:~'3 6029264.80 . . · . .4229,9i ~ 6L60,72 . 433~.63 ~ 62~o.~. ,. 4372.0Z S e2S~.03" .$~oss~.,3 eo2~14e.ee 178L :.'1.15 .' . :1~8X~ ', ,1 .'75 1'/8I. 1.75 £-/ar, !. :75. 3786. .. 3~8L "1'.75 'lTBb 178b 178b ",:L :,.75 1.'Z86' l.. 75 , 1761. L.q5 MPb-K L-97A P0~ ~ [.75/100 DRDP --TOP HiRg-- £0200,00 £0300.00 tO400.O0 L0452,33 'L277~.38' PROP0$~D WELL P~OpIL]I .. - · . . m D[RSCTIOM . VERT~ICA~-DH/~TH$ SHCTIO~ . . - AZZMUT~ TVD AU~-3~IA - . .DEPART- . UE~ ~. .'X ' "' ' Y ' ~Acs m ~ mmmmmmmum s~tMsm m m m,mm~mmmm 34.0'/ 32.32 30.5'/ 29,66 29.66 29,66 29,66 29.66 29.66 29.66 29,66 29 29.66 29.66 · . 29 .'66 UD 12764.09 29.66 233.49 ~3~..~5 233.19 233.10 :233.~0 2~3..~o '233'.~0 233.1o 233,1o 233.1o 233',10 233.~0 · . 233,~0' 23'3.20 · . · . 233.30 .. 52o2.o~ . .52S5,74 5371.O5 532L.55 5416.3&-536g.8~ eseg.$o es2o..o6 ~OO . · . . . . · 5152';'56 '769L~~q .'4406.03 $ 6305.10 U '5384~5,54 G027079.89 .1~7b t.?S 5236,2~ 7746,70'..'4438.66 $' 6349.07. N .53842L..87.60270¢?..OL 1~7~ 1.,~5 · .. · . ... · 7798.85 4469.86 '$. 6390.88'~ 538380,25 6027035,$6 1'/7L 3'.'/5 ~825-10 4485.60 3 .64LL.'89' W 53'83S9,$4 6026999;69 HS 1~75 848~.~8 o.o~ ees4.S·o G;os.oo e?3~..so 6~0o.oo · ~9~'.'$0 6850.'00 ..... 7009;50 6960.00 70~4.50 6965;00 .. 8529 .B6 as?.8.~4 8669.33 8731.', 92 · . . .8734 ., , .48.79,'88 ~ 6937.03 U 537836.:64 60266.02.30 .ElS 4908.94 6 6975.74 U 539~98,11 6026573.01 US 4938.00 8 '7014'745 ~ $3'/759.58 6026543.'/2 t. lS .. '4992.70'8 ?087.33 # .53768%,06 6026488.58 HS 5030.31 $ .7137.40 H 537637,20 6026450.68 H$ 5032.02 S 7139.68 ~ 53~634,93 60.26448.95 HE aooo o:o0 O .00 0.00 0.00 7069;50 9020';00 '8766.07 · . ?069:S0 ~020.'00 '8'766,07 '/Oa4.~O ?035,00 · ?LL~.so'?065.0'0 879~;69 . ... .. :: '?.' · :.. 7425,20. 7375';?0 · 5050.82 3 9164.72 ~ '5376LO.00.60264'30.O0 .Hs 505'0;82 ~ 7164,72 ~ 53~610,00 602643Q.'O0 HS 5055.9S S ?~'/~.$;, ~ 53'/603.20.602~424.83 ..~$ 5066-2.1 8 7185,2~ ~ 537589,E0 6'026415,49 Hs 5083,31 ;. 7207.98' .#.' 53756~'.,~ :602639;.26 HS · . .... ..'..,. .. .5172.44' S 7326.70 ~ .537~48,77'6026307.4'3 · .... 0o00 0,00 0.00 0 · 0.O 0,00 0,00 (An~dz:LL1 (c)97 KPIGKP03 3.DC 3 ~36 PM D) lm T SHARED SERVTCES "'O'P,¢L"i' 't'Nn m I i i i i ii i _ MPL'-K 'L '"97A 'P01 VERTICAL SECTION VIEW Sect ion 'at:..~4' e~ ~ 'i'VD 'Scale.' .'.,l..'inch' .=.'"t400-feel: '. .:. "DeP .Scale'" 'i'::"i.n~:!~ ',, i40.0 faa't: '"' ' Drawn :" 04' Jun.;]997 : ' · .. ... Nanken Identi!acatton ~ ,'BKB'.:'SECTN .INgt · O. '" ,0 0 0.[ .. .. A) KB' "" "30(~ -0 · " "'" B) KOP/':BUXLD.'J',25/~O0".,'. ".3'00 .. . ' . ,."C)"BUiLOd.751~O0' '" '.. ,~0" . " .' '-'- '" ' '0) BUZLO"2/tO0"'." '.;'.'" 800'~ 799 ..'30' '7.f ' " E) END. 2/~00' "' '.," "'. 1~5 . .'1769 ..341 27..~ ..... · ' ~ ~":s~ , F) BOZLD.3/IOO .: ...:.' ..... 'S893"'1829 '.:'.,'373 27.~ ' .,, ' ..' '" ,' '' '6) E~D','3/JO0 BUi~: :'34~9.'"'.2783.' "'J584' ', 75,~ ' " .,..., '", . H) .SH~AOER. .m '. " " "]) DR~ ~757t00 .:' .".' .'...78~6 ".3864'' 5794" '75.{ · ' : ' " ' ' ... "" "' '.: ~) E~"J';75/tOO.'.D~P' ." ~0452 '5~6.. 7825 '29.~ ....... · ~ , ,'" "' "' K) K~UK, TARGE1~*:~,~: lE355'. 7069 8766 ' ~9.( . · .,', , , "," .." , L) 3D.~... . ~-~=~---' ~-~ ..~. .~.. . _ .. '~- . . . , ,., .,.',',,,,, .,..,'. '.' ,;':. , .,. 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'[; ,.,,,. . .... ,,,. ~ ,, .,.,,' ,..... ;, :~: .'., .,. ::::: :='~:'::,~:::::::,:~ ::=~:' ~:':~':,:~':,:'.~ ::~::~ :~':~: ....,, .,, , ' ........ ~- ',"~':' ' --'~ -': ~"'," ~ff-~ ........................ j ' .... ~i~..... ................, ....,',.~... ~.i...~i~..... ..........., ....., ,, . 0 700 1400 . 2100 2800 ' 3500 ~00 4900 5600. . 6300 "' 7000 7700 ' 8400 .9.800 10500 ~lt200 ' , 13900 section Deparl:ure ' " i i I i ii iii ', ' i 'i i ii .i ! ii ! i , , [ .SF~AR_,_,~ED- SERVICE'S--DRZLLZ'N6 ! . - . :~o -., ._ ,'--.--MPL"'K .L-g7A :.PO. 1. . -_-,~'~_-,--'.,~- , . . .,-~,,n~.. _-.-,'.,.,---.-,~.--, .... .--.-.. ,;- .,,-.-',: ~-.-,,.-.~;, .... .. ... 7200 .. .... - · ' - - ' .-. . . 7400- '. . 7filXl ..... : 71100 8000 8t00 8~00 8300 8400 8500 8600 '8700 8800 8900 9000 9200 9200 9300 9400 Section Departure,, , ,. =!L ....... ~aort3:l Cc}g7 ~PL.I,¢O! 3.GC 3r. 37 Pti Pi tL ' U~UU .reel: al: A/]ilIULil ~',3~,!0 '. ". ...... · ,, ' .. . -- OECLZNAT[ON ' +28,005 (E} '" ... . i' ':' " ?' '" :'" ' .... $C~E ....... :t "inch.; 1000 feet '" " ". '" ',-. " . ' .... "':":' ::"".'::':"~,':' '"' . '.. DRAWN ....... :04 Jun 1997" ..' '". "".':.....'--..'- . ' '.."",.. :'-'""'..... ... .." . "...,. .. ... .."~-i ./'~'.. !" ~,r Identification RD ~,. .,~ 0 0 It ' 0 E .... :.. . ".... ......':..~ ' ' . . .'.... Eli KOP /BUILD 1.25/t00 300 0 I~ 0 E " ..... ": '"' :' '":' ' " .." ': C] BI/ILD 1.75/$00 550 I E~, t.75/~00 D~OP ~0452 4485 $ .64~2 ~ ' .,, · .,,, " . .. :. .,": , , " E~PARUK TARGE1~a~ ~235~ 505t -q .' 7~65 Il, ., : .: . '. ,. ' '" " , · :'" ~KI-) lO ~2764 "5t72 S 7327 N . ' .. .. ~ ,.... . , . .... . .... '. · . . . . , . ...... . .. .. :""' :"':' ' .... ""'" ' · , ' ~Jl~ ~ ' " ' ,":', ' ' ' ' '1 , ~"'"" ~'":, .- ::T':.," ""' ' '' ':.' :'. :'..i..,. ',,:,: " .. ' ..' .'. .. . ..' Kupa~'u dlus'20[ feel ) ., . ,' ' 8500 eooo 7500 ?000 -. r~oo 6000 zoo 5000' ,~500 4000 3500 3000 [50o. ~000 .1500 · tooo 500 .0 500 ,, ' ' ' ' ' '¢: WES1'.- EASI -> ' . . , i i' i i i iii i i i i i i iii i iiii _ , , , . (~'lli (~1~7 IO~LKRII 3.0C 3:39 R4 P) 06¢04/199~ t5'5B ANAUNILL un~ ~ ~ 907-344-21 b~- ~---~ ') WELL PERMIT CHECKLISToo Y. ADMINISTRATION N N N .Y N · N N N N ..Y N ENGINEERING 1. Permit fee attached ................... 2. Lease number appropriate ................ 3. Unique well name and number .............. 4. Well located in a defined pool ............. 5. Well located proper distance from drlg unit boundary. 6. Well located proper distance from other wells ..... 7. Sufficient acreage available in drilling unit ..... 8. If deviated, is wellbore plat included ........ 9. Operator only affected party .............. 10. Operator has appropriate bond in force ......... 11. Permit can be issued without conservation order .... 12. Permit can be issued without administrative approval. 13. Can permit be approved before 15-day wait ....... PROGRAM: exp[] dev [] redrl[] ser~wellbore seg[] ann dtsp para req[] - oN,oFF REMARKS APPR D~TE; 14. Conductor string provided ............... ~ N 15. Surface casing protects all known USDWs ........ ~ N 16. CMT vol adequate to circulate on conductor & surf csg. .~ N 17. CMT vol adequate to tie-in long string to surf csg . . . Y ~ 18. CMT will cover all known productive horizons ...... ~ N 19. Casing designs adequate for C, T, B & permafrost .... ~ 20. Adequate tankage or reserve pit ............. 21. If a re-drill, has a 10-403 for abndnmnt been approved. ~Y 22. Adequate wellbore separation proposed ......... .~ 23. If diverter required, is it adequate .......... 24. Drilling fluid program schematic & equip list adequate .~) N 25. BOPEs adequate .................... i~ N 26. BOPE press rating adequate; test to ~'~(~fS~_~ psig~ N 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 ............ ~ N N GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures .... Y N///. 31. Data presented on ,potential overpressure zones ..... Y/N 32. Seismic analysis of shallow gas zones .......... 33. Seabed condition survey (if off-shore) ........ / Y N 34. Contact name/phone for weekly progress reports . . ./6 . Y N [explorato~-y only] GEOLOGY: ENGINEERING: CO~~ ' Comments/Instructions: HOW/dlf- A:\FORMS\cheklist rev 01/97 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 Thu Sep 25 08:27:59 1997 Reel Header Service name ............. LISTPE Date ..................... 97/09/25 Origin ................... STS Reel Name ................ UNKNOWN Continuation Number ...... 01 Previous Reel Name ....... UNKNOWN Comments ................. STS LIS Writing Library. Technical Services Scientific Tape Header Service name ............. LISTPE Date ..................... 97/09/25 Origin ................... STS Tape Name ................ UNKNOWN Continuation Number ...... 01 Previous Tape Name ....... UNKNOWN Comments ................. STS LIS Writing Library. Technical Services Scientific Physical EOF Comment Record TAPE HEADER MILNE POINT MWD/MAD LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: MPL-39 500292278600 BP EXPLORATION (ALASKA), INC. SPERRY-SUN DRILLING SERVICES 25-SEP-97 MWD RUN 1 AK-RB- 70205 M. HANIK P. WILSON 8 13N 10E 3334 5137 .00 51.40 17.10 WELL CASING RECORD OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT 1ST STRING 2ND STRING 3RD STRING 20.000 112.0 PRODUCTION STRING 12.250 8670.0 REMARKS: 1. ALL DEPTHS ARE MEASURED DEPTHS (MD) UNLESS OTHERWISE NOTED. 2. MWD RUN 1 IS DUAL GAMMA RAY (DGR) ~%ND COMPENSATED NEUTRON POROSITY (CNP). 3. DEPTH SHIFTING/CORRECTION OF MWD DATA IS WAIVED AS PER THE PHONE CONVERSATION BETWEEN ERIC DIXSON OF BP EXPLORATION (ALASKA), INC. AND ALI TURKER OF SPERRY-SUN DRILLING SERVICES ON 09/24/97. 4. MWD RUN 1 REPRESENTS WELL MPL-39 WITH API# 50-029-22786. THIS WELL REACHED A TOTAL DEPTH (TD) OF 8669'MD, 4173'TVD. SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING SGRC = SMOOTHED GAMMA RAY COMBINED. SPSF = SMOOTHED COMPENSATED NEUTRON POROSITY (SANDSTONE MATRIX-FIXED HOLE SIZE). SNNA = SMOOTHED AVERAGE OF NEAR DETECTORS' COUNT RATES. SNFA = SMOOTHED AVERAGE OF FAR DETECTORS' COUNT RATES. ENVIRONMENTAL PARAMETERS USED IN PROCESSING THE NEUTRON LOG DATA: HOLE SIZE: 12.25" MUD FILTRATE SALINITY: 600 - 750 PPM CL MUD WEIGHT: 8.9 - 9.3 PPG FORMATION WATER SALINITY: 14545 PPM CL LITHOLOGY: SANDSTONE $ File Header Service name ............. STSLIB.001 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/25 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; all bit runs merged. DEPTH INCREMENT: .5000 FILE SUMMARY PBU TOOL CODE START DEPTH FCNT 5848.0 NCNT 5848.0 NPHI 5848.0 GR 5857.0 ROP 5886.5 STOP DEPTH 8628.5 8628.5 8628.5 8638.0 8670.0 $ 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 1 5885.0 8670.0 $ 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 .liN Max frames per record ............. Undefined Absent value ...................... -999.25 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 GR MWD AAPI 4 1 68 4 2 NPHI MWD P.U. 4 1 68 8 3 ROP MWD FT/H 4 1 68 12 4 FCNT MWD CNTS 4 1 68 16 5 NCNT MWD CNTS 4 1 68 20 6 First Name Min Max Mean Nsam Reading DEPT 5848 8670 7259 5645 5848 GR 18.1131 108.251 56.2236 5563 5857 NPHI 10.1891 96.9319 55.6974 5562 5848 ROP 15.1172 991.126 269.733 5568 5886.5 FCNT 404 767.954 518.762 5562 5848 NCNT 2104 3091.38 2472.66 5562 5848 Last Reading 8670 8638 8628.5 8670 8628.5 8628.5 First Reading For Entire File .......... 5848 Last Reading For Entire File ........... 8670 File Trailer Service name ............. STSLIB.001 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/25 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.002 Physical EOF File Header Service name ............. STSLIB.002 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/25 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.001 Comment Record FILE HEADER FILE NUMBER: 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH FCNT 5848.0 8628.5 NCNT 5848.0 8628.5 NPHI 5848.0 8628.5 GR 5857.0 8638.0 ROP 5886.5 8670.0 $ LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT) : BOTTOM LOG iNTERVAL (FT) : BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE DGR DUAL GAMMA RAY CNP COMPENSATED NEUTRON $ 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: 18-JUL-97 ISC VERSION 5.06 5.46 MEMORY 8670.0 5885.0 8670.0 64.4 78.6 TOOL NUMBER P0774NCG8 P0774NCG8 12.250 12.3 LSND 9.30 58.0 9.7 MUD CHLORIDES (PPM): FLUID LOSS (C3) : RESISTIVITY (OPH~M) AT TEMPERATURE (DEGF) I~UD AT M~ASURED TEMPERATURE (MT): I~UD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL ICuXT RI X: 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 .liN Max frames per record ............. Undefined Absent value ...................... -999.25 Depth Units ....................... Datum Specification Block sub-type...0 600 6.8 .000 .000 .000 .000 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 GR MWD 1 AAPI 4 1 68 4 2 NPHI MWD 1 P.U. 4 1 68 8 3 ROP MWD 1 FT/H 4 1 68 12 4 FCNT MWD 1 CNTS 4 1 68 16 5 NCNT MWD 1 CNTS 4 1 68 20 6 -17.7 First Name Min Max Mean Nsam Reading DEPT 5848 8670 7259 5645 5848 GR 18.1131 108.251 56.2236 5563 5857 NPHI 10.1891 96.9319 55.6974 5562 5848 ROP 15.1172 991.126 269.733 5568 5886.5 FCNT 404 767.954 518.762 5562 5848 NCNT 2104 3091.38 2472.66 5562 5848 Last Reading 8670 8638 8628.5 8670 8628.5 8628.5 First Reading For Entire File .......... 5848 Last Reading For Entire File ........... 8670 File Trailer Service name ............. STSLIB.002 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 97/09/25 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.003 Physical EOF Tape Trailer Service name ............. LISTPE Date ..................... 97/09/25 Origin ................... STS Tape Name ................ UNKNOWN Continuation Number ...... 01 Next Tape Name ........... UNKNOWN Comments ................. STS LIS Writing Technical Services Reel Trailer Service name ............. LISTPE Date ..................... 97/09/25 Origin ................... STS Reel Name ................ UNKNOWN Continuation Number ...... 01 Next Reel Name ........... UNKNOWN Comments ................. STS LIS Writing Technical Services Library. Library. Scientific Scientific Physical EOF Physical EOF End Of LIS File * ALASKA COMPUTING CENTER . ****************************** . ............................ * ....... SCHLUMBERGER ....... . ****************************** COMPANY NAME : B.P. EXPLORATION WELL NAME : MPL-39 FIELD NAME : MILNE POINT BOROUGH : NORTH SLOPE STATE : ALASKA API NUMBER : 50-029-22786-00 REFERENCE NO : 97417 Oate_OI- 0'5 - ol _ * ALASKA COMPUTING CENTER * . * ****************************** . ............................ * * ....... SCHLUMBERGER ....... * . ............................ * ****************************** COMPAlCYNAME : B.P. EXPLORATION WELL NAME : MPL-39 FIELD NAME : MILNE POINT BOROUGH : NORTH SLOPE STATE : ALASKA API NUMBER : 50-029-22786-00 REFERENCE NO : 97417 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: **** REEL HEADER **** SERVICE NAME : EDIT DATE : 98/04/23 ORIGIN : FLIC REEL NAME : 97417 CONTINUATION # PREVIOUS REEL COI~4ENT : B.P. EXPLORATION, MILNE POINT MPL-39, API #50-029-22786-00 **** TAPE HEADER **** SERVICE NAME : EDIT DATE : 98/04/23 ORIGIN : FLIC TAPE NA~E : 97417 CONTINUATION # : 1 PREVIOUS TAPE : COI~ENT : B.P. EXPLORATION, MILNE POINT MPL-39, API #50-029-22786-00 TAPE HEADER MILNE POINT MWD/MAD LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM MSL O) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: WELL CASING RECORD 1ST STRING 2ND STRING MPL- 39 500292278600 B. P. EXPLORATION SCHLUMBERGER WELL SERVICES 23-APR-98 BIT RUN 1 97417 DENNETT PYRON BIT RUN 2 BIT RUN 3 8 13N 10E 51.40 51.40 17.10 OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 8. 500 9. 625 8648.0 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 3RD STRING PRODUCTION STRING Well drilled 17-JUL through 25-JUL-97 with CDR and ADN. All data was collected in three bit runs. $ $ PAGE: **** FILE HEADER **** FILE NA~E : EDIT .001 SERVICE : FLIC VERSION : O01CO1 DATE : 98/04/23 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUMBER: 1 EDITED MERGEDMWD Depth shifted and clipped curves; all bit runs merged. DEPTH INCREME2~T: 0.5000 FILE SOY4~L~RY LDWG TOOL CODE .............. $ BASELINE CURVE FOR SHIFTS: GR CURVE SHIFT DATA (MEASURED DEPTH) START DEPTH STOP DEPTH 5815.0 12740.5 BASELINE DEPTH .............. 88888 0 8612 0 8589 0 8568 5 8567 0 8553 5 8538.5 8528.5 8510.5 8478.0 8452.0 8441.5 8436.5 8426.0 8423.5 8401.0 8373.5 8339.0 8325.5 .......... EQUIVALENT UNSHIFTED DEPTH .......... ....... 88888.5 8612.5 8589.0 8567.5 8566.0 8552.5 8538.5 8527.5 8510.0 8478.5 8451.5 8440.0 8435.5 8426.0 8420.5 8399.5 8372.0 8340.0 8325.0 LIS Tape Verification Listing Schlumberger Alaska Computing Center 8312.0 8304.5 8290.0 8255.0 8204.0 8176.5 8136.5 8124.0 8118.5 8105.0 8101.0 8093.0 8075.5 8065.5 8034.5 8032.5 8021.5 8017.0 8012.5 7989.5 7971.0 7967.5 7954.0 7924.0 7902.5 7869.5 7858.0 7832.5 7809.0 7791.0 7784.5 7771.0 7722.5 7712.0 7698.5 7694.5 7669.5 7659.0 7650.0 7644.5 7623.5 7590.5 7577.0 7563.5 7559.5 7535.0 7503.0 7482.0 7464.0 7423.0 7401.5 7370.5 7353.0 7339.5 7336.0 8311.5 8304.0 8291.0 8255.0 8205.5 8177 5 8137 0 8124 5 8118 5 8105 5 8100 5 8093.0 8075.5 8065.5 8034.5 8032.0 8021.0 8018.0 8014.5 7992.0 7973.0 7969.0 7954.0 7925.0 7903.0 7870.0 7858.0 7834.0 7809.5 7791.5 7785.5 7771.5 7722.0 7713 0 7701 0 7695 5 7671 0 7659 0 7649 5 7645 5 7624 5 7591 5 7576.5 7563 5 7557 0 7532 0 7502 5 7481 5 7465 5 7423 0 7402 0 7371 0 7354 0 7341 0 7336 5 23-APR-1998 10:25 PAGE: LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 7325.0 7287.0 7266.5 7256.0 7245.5 7229.0 7211.0 7190.0 7158.0 7109.5 7104.0 7097.5 7057.0 7016.0 7009.0 6994.5 6982.5 6976.0 6952.5 6944.0 6919.0 6884.0 6874.5 6869.5 6856.0 6838.0 6806.5 6792.5 6783.0 6767.5 6751 5 6723 0 6714 5 6682 5 6652 5 6630 5 6612 5 6597 5 6591 5 6582 5 6578 0 6569 5 6526 0 6505.0 6495.0 6480.0 6454.0 6449.5 6424.0 6395.0 6368.0 6339. 0 6314.5 6308.5 6294.5 7325.5 7287.5 7267.5 7256.5 7244.0 7228.5 7211.0 7188 5 7157 5 7109 0 7101 0 7095 0 7052 5 7015 5 7011 5 6995 5 6984 5 6977 0 6950 0 6945 5 6920 5 6884 5 6875 0 6870 5 6857 0 6840 0 6807 5 6792 5 6781 5 6766 5 6750 5 6722 0 6713 5 6680.5 6650.5 6629.0 6611.0 6597.5 6590.0 6582.0 6577.5 6568.0 6525.0 6504. 0 6495.0 6479. 0 6453.0 6449.0 6424.0 6395.5 6368.5 6339.5 6313.5 6306.0 6291.0 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 6286.5 6265.0 6243.0 6229.5 6225.5 6212.5 6191.5 6180.0 6161.5 6149.0 6134.0 6124.0 6104.0 6096.0 6078.5 6065.0 6061.5 6043.5 6024.5 601 O. 0 5996.5 5988.0 5955.5 5941.5 5916.5 5907.5 5887.5 5881.5 100.0 $ MERGED DATA SOURCE LDWG TOOL CODE .............. $ RE~ARKS: 6282 0 6261 5 6240 0 6226 0 6221 5 6208 0 6187 5 6179 5 6161 0 6148 0 6132 0 6122 5 6102 5 6094.5 6077.0 6065.0 6061.5 6044.5 6027.5 6011.5 5997.5 5989.5 5958.5 5944.0 5920.5 5909.5 5891.0 5883.5 102.0 BIT RUN NO. MERGE TOP MERGE BASE 1 5813.0 8670.0 2 8537.0 12323.0 3 12197.0 12740.0 The depth adjustments shown above reflect the MWD GR to the PDC GR logged by SPERRY. Ail other MWD curves were carried with the GR. This file also contains the Very Enhanced QRO resisitivitywith 2' average that was reprocessed at GeoQuest. The ADN quadrant outputs are as follows: ROBB/ROBU/ROBL/ROBR are bottom, upper, left, and right quadrant density; and are also listed as RHO1, RH02, RH03, RH04 in the LDWG listing. The other outputs (Delta Rho, PEF) are listed with their quadrants as DRHB/DRHU/DRHL/DRHR, PEB/PEU/PEL/PER. The LDWG outputs of CALA and CALS are HDIA and VDIA respectively. $ LIS FORMAT DATA LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 76 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 13 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 0 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID O~OER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 FET MWD HR 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 RA MWD OHP4M4000096 O0 000 O0 0 1 1 1 4 68 0000000000 RP ITWD OPiMM4000096 O0 000 O0 0 1 1 1 4 68 0000000000 VRA MWD oIqMM4000096 O0 000 O0 0 1 1 1 4 68 0000000000 VRP MWD OHlVk~4000096 O0 000 O0 0 1 1 1 4 68 0000000000 ROP MWD FPHR 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 GR MWD GAPI 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 RHO1 MWD G/C3 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 RH02 MWD G/C3 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 RH03 MWD G/C3 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 RH04 MWD G/C3 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 DRHOMWD G/C3 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 PEF MWD BN/E 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 DCALMWD IN 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 CALSMWD IN 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 CALAMWD IN 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 NPHIMWD PU-S 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 NRAT~ 4000096 O0 000 O0 0 1 1 1 4 68 0000000000 ** DATA ** LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PA GE: DEPT. 12740. 500 FET. MWD VRA . MWD -999. 250 VR P . MWD RHO1.MWD -999.250 RHO2.MWD DRHO . MWD - 999.250 PEF. MWD CALA. MWD - 999.250 NPHI. MWD DEPT. 12000. 000 FET.MWD VRA . MWD 1. 382 VRP. MWD RHO1 . MWD 2.419 RH02. MWD DRHO . MWD O . 025 PEF . MWD CALA.MWD 9. 870 NPHI.MWD DEPT. 11000.000 FET. MWD VRA.MWD 2.741 VRP.MWD RHO1.MWD 2.393 RHO2.MWD DRHO.MWD -0.004 PEF. MWD CALA.MWD 9.002 NPHI.MWD DEPT. 10000.000 FET. MWD VRA.MWD 2.134 VRP.MWD RHO1.MWD 2.363 RHO2.MWD DRHO.MWD 0.021 PEF.MWD CALA.MWD 11.363 NPHI.MWD DEPT. 9000. 000 FET. MWD VRA . MWD 2. 541 VR P . MWD RHO1. MWD 2.274 RH02. MWD DRHO . MWD O . 024 PEF . MWD CALA.MWD 10.202 NPHI.MWD DEPT. 8000.000 FET.MWD VRA.MWD 20.216 VRP.MWD RHO1.MWD -999.250 RHO2.MWD DRHO.MWD -999.250 PEF.MWD CALA.MWD -999.250 NPHI.MWD DEPT. 7000.000 FET.MWD VRA.MWD 111.799 VRP.MWD RHO1.MWD -999.250 RHO2.MWD DRHO.MWD -999.250 PEF.MWD CALA.MWD -999.250 NPHI.MWD DEPT. 6000.000 FET.MWD VRA.MWD 3.951 VRP.MWD RHO1.MWD -999.250 RHO2.MWD DRHO.MWD -999.250 PEF.MWD CALA.MWD -999.250 NPHI.MWD DEPT. 5816.000 FET.MWD VRA.MWD -999.250 VRP.MWD RHO1.MWD -999.250 RHO2.MWD DRHO.MWD -999.250 PEF. MWD CALA.MWD -999.250 NPHI.MWD -999.250 RA.MWD -999.250 ROP.MWD -999.250 RHO3.MWD -999.250 DCAL.MWD -999.250 ArRAT.MWD 1.119 RA . MWD 1.291 ROP.MWD 2. 464 RH03 .MWD 3. 800 DCAL.MWD 50. 304 NRAT.MWD 0.270 RA.MWD 2.681 ROP.MWD 2.385 RHO3.MWD 3.254 DCAL.MWD 35.775 NRAT.MWD 0.474 RA.MWD 2.234 ROP.MWD 2.321 RHO3.MWD 3.394 DCAL.MWD 43.637 NRAT.MWD O . 166 RA . MWD 2. 409 ROP.MWD 2. 274 RH03 .MWD 3. 079 DCAL.MWD 42. 387 NRAT.MWD 1.435 RA.MWD 24.285 ROP.MWD -999.250 RHO3.MWD -999.250 DCAL.MWD -999.250 NRAT.MWD 0.362 RA.MWD 38.484 ROP.MWD -999.250 RHO3.MWD -999.250 DCAL.MWD -999.250 NRAT.MWD -999.250 214.291 -999.250 -999.250 -999.250 1.317 49.855 2.430 0.466 26.666 2.760 233.980 2.471 0.155 22.024 1. 915 85. 727 2.356 0.127 24. 673 2.614 514.803 2.236 0.166 24.279 12.466 100.543 -999.250 -999.250 -999.250 8.762 -999.250 -999.250 -999.250 -999.250 0.256 RA.MWD 3.218 4.007 ROP.MWD 240.000 -999.250 RHO3.MWD -999.250 -999.250 DCAL.MWD -999.250 -999.250 NRAT.MWD -999.250 0.003 RA.MWD -999.250 -999.250 ROP.MWD -999.250 -999.250 RHO3.f4WD -999.250 -999.250 DCAL.MWD -999.250 -999.250 NRAT. MWD -999.250 RP.MWD GR. MWD RH 0 4 . MWD CAL S . MWD RP.MWD GR. MWD RH04. MWD CAL S . MWD RP.MWD GR. MWD RH04. MWD CAL S . MWD RP.MWD GR. MWD RH 0 4 . MWD CAL S . MWD RP.MWD GR.MWD RHO4.MWD CALS.MWD RP.MWD GR. MWD RH04. MWD CALS . MWD RP.MWD GR. MWD RH04 . MWD CAL S . MWD RP.MWD GR. MWD RH04. MWD CAL S . MWD RP.MWD GR. MWD RH04. MWD CAL S . MWD -999.250 -999.250 -999.250 -999.250 1.280 113.114 2.417 10.137 2. 710 91. 308 2. 385 9.171 2.080 92.689 2.329 10.780 2. 414 84.108 2. 261 10. 403 20.408 60.068 -999.250 -999.250 13.872 52.983 -999.250 -999.250 3.729 70.751 -999.250 -999.250 -999.250 81.034 -999.250 -999.250 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: END OF DATA ** **** FILE TRAILER **** FILE NAM~ : EDIT .001 SERVICE : FLIC VERSION · O01CO1 DATE : 98/04/23 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .002 SERVICE : FLIC VERSION . O01CO1 DATE : 98/04/23 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUMBER 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: 0.5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH ..................................... 5813 . 0 8670.0 LOG HEADER DATA DATE LOGGED: 25-JUL-97 SOFTWARE: SURFACE SOFTWARE VERSION: IDEAL DOWN-HOLE SOFTWARE VERSION: 4. OC DATA TYPE (MEMORY or ~-TIME) : MEMORY TD DRILLER (?T) : 12740.0 TOP LOG INTERVAL (FT): 5814.0 BOTTOM LOG INTERVAL (FT) : 12740.0 BIT ROTATING SPEED (RPM) : 64 HOLE INCLINATION (DEG) MINIMUM ANGLE: 61.9 MAXIMUM ANGLE: 78.5 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE CDR RESIST./GR $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH (FT) : BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3): RESISTIVITY (OH~M) AT TEMPERATURE (DEGF) : MUD AT FIEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATIONG TEMPERATURE : MUD FILTRATE AT (MT): MUD CAKE AT (MT): NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN) : TOOL STANDOFF (IN) EWR FREQUENCY (HZ) TOOL NUMBER CDR752 8.500 8648.0 LSND 10.30 1.900 105.0 1.600 105.0 20000 REMARKS: *** RUN 1 DRILLED INT. 5884'-8670'**** *** RUN 2 DRILLED INT. 8670'-12323'**** *** RUN 3 DRILLED INT. 12323'-12740'**** RUN 1 - CDR, RUNS 2/3 - CDR/ADN GR/TNPH CORRECTED FOR ENVIRONMENTAL FACTORS 9. 625 CSG SET AT 8670' AFTER RUN 1 DATA FROM DOWNHOLE MEMORY, V4. OC SOFTWARE ***THIS IS THE DATA FROM RUN #1 (CDR) *** $ LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 24 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 10 TYPE REPR CODE VALUE 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 42 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 4000096 O0 000 O0 0 2 1 1 4 68 0000000000 ATR LW1 0H~4000096 O0 000 O0 0 2 1 1 4 68 0000000000 PSR LW1 OHMM4000096 O0 000 O0 0 2 1 1 4 68 0000000000 ROPE LW1 F/HR 4000096 O0 000 O0 0 2 1 1 4 68 0000000000 GR LW1 GAPI 4000096 O0 000 O0 0 2 1 1 4 68 0000000000 TABR LW1 4000096 O0 000 O0 0 2 1 1 4 68 0000000000 ** DATA ** DEPT. GR.LW1 DEPT. GR.LW1 DEPT. GR.LW1 8669. 500 ATR. LW1 3. 838 PSR. LW1 113. 718 TABR. LW1 3421 . 406 8000. 000 ATR. LW1 11 . 079 PSR. LW1 62.368 TABR.LW1 4697. 000 7000. 000 ATR. LW1 8. 263 PSR. LW1 55. 081 TABR. LW1 1231. 000 DEPT. 6000. 000 ATR. LW1 3 . 194 PSR. LW1 GR.LW1 69. 482 TABR.LW1 840. 000 DEPT. 5813.500 ATR . LW1 3. 718 PSR. LW1 GR.LW1 80. 834 TABR.LW1 O . 000 3. 609 ROPE. LW1 17. 602 ROPE. LW1 11. 426 ROPE. LW1 3. 592 ROPE. LW1 3 . 357 ROPE. LW1 115.437 81. 070 214.326 243.236 -999.250 ** END OF DATA ** LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 11 **** FILE TRAILER **** FILE NAME : EDIT .002 SERVICE . FLIC VERSION · O01CO1 DATE · 98/04/23 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .003 SERVICE : FLIC VERSION ' O01CO1 DATE ' 98/04/23 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUMBER 3 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 2 DEPTH INCREMENT: O. 5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH 8537.0 12323.0 LOG HEADER DATA DATE LOGGED: 25 - JUL - 97 SOFTWARE: SURFACE SOFTWARE VERSION: IDEAL DOWNHOLE SOFTWARE VERSION: 4. OC DATA TYPE (MEMORY or REAL-TIME): MEMORY TD DRILLER (FT) : 12740.0 TOP LOG INTERVAL (FT): 5814.0 BOTTOM LOG INTERVAL (FT) : 12740.0 BIT ROTATING SPEED (RPM) : 81 HOLE INCLINATION (DEG) MINIMUM ANGLE: 28.3 MAXIMUM ANGLE: 61.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE CDR RESIST./GR ADN AZ. DENS./NEUT. $ TOOL NUMBER CDR752 ADN059 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 12 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN) DRILLERS CASING DEPTH (FT) 8.500 8648.0 BOREHOLE CONDITIONS MUD TYPE: LSND MUD DENSITY (LB/G): 10. 30 MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : 700 FLUID LOSS (C3): RESISTIVITY (OH~4M) AT TE~IPERATURE (DEGF) : MUD AT MEASURED TEMPERATURE (MT): 1.900 MUD AT MAX CIRCULATIONG TEMPERATURE : MUD FILTRATE AT (MT): 1. 600 MUD CAKE AT (MT): 105.0 105.0 NEUTRON TOOL MATRIX: SANDSTONE MATRIX DENSITY: 2.65 HOLE CORRECTION (IN): TOOL STANDOFF (IN): 1.0 EWR FREQUENCY (HZ): 20000 REMARKS: *** RUN 1 DRILLED INT. 5884'-8670'**** *** RUN 2 DRILLED INT. 8670'-12323'**** *** RUN 3 DRILLED INT. 12323'-12740'**** RUN 1 - CDR, RUNS 2/3 - CDR/ADN GR/TNPH CORRECTED FOR ENVIRONMENTAL FACTORS 9. 625 CSG SET AT 8670' AFTER RUN 1 DATA FROM DOWNHOLE MEMORY, V4. OC SOFTWARE ***THIS IS THE DATA FROM RUN #2 (CDR/ADN) *** $ LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** .............................. TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 100 4 66 1 5 66 6 73 7 65 8 68 0.5 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 13 TYPE REPR CODE VALUE 9 65 FT 11 66 10 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 ATR LW2 OBlVk44000096 O0 000 O0 0 3 1 1 4 68 0000000000 PSR LW2 OH~M4000096 O0 000 O0 0 3 1 1 4 68 0000000000 ROPE LW2 F/HR 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 GR LW2 GAPI 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 TABR LW2 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 TABD LW2 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 ROBB LW2 G/C3 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 ROBU LW2 G/C3 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 ROBL LW2 C/C3 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 ROBR LW2 G/C3 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 DRHB LW2 G/C3 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 DRHU LW2 C/C3 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 DRHL LW2 G/C3 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 DRHR LW2 G/C3 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 PEB LW2 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 PEU LW2 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 PEL LW2 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 PER LW2 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 TNRALW2 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 TNPH LW2 PU 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 DCALLW2 IN 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 HDIA LW2 IN 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 VDIA LW2 IN 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 RPM LW2 RPM 4000096 O0 000 O0 0 3 1 1 4 68 0000000000 ** DATA ** DEPT. 12323.000 ATR. LW2 2 GR. LW2 107. 752 TABR. LW2 4263 ROBU. LW2 2. 499 ROBL. LW2 2 DRHU. LW2 O . 106 DRHL . LW2 0 PEU. LW2 4. 381 PEL . LW2 4 TNPH. LW2 33. 061 DCAL.LW2 0 RPM. LW2 O. 000 210 PSR. LW2 2. 185 ROPE. LW2 625 TABD. LW2 6272.438 ROBB. LW2 499 ROBR. LW2 2. 499 DRHB. LW2 106 DRHR.LW2 0.106 PEB.LW2 381 PER. LW2 4 . 381 TNNA. LW2 224 HDIA. LW2 7. 868 VDIA. LW2 58. 263 2. 499 0.106 4. 381 21. 008 9. 135 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 14 DEPT. GR. LW2 ROBU. LW2 DRHU. LW2 PEU. LW2 TNPH. LW2 RPM. LW2 DEPT. GR. LW2 ROBU. LW2 DRHU. LW2 PEU. LW2 TNPH. LW2 RPM. LW2 DEPT. GR. LW2 ROBU. LW2 DRHU. LW2 PEU. LW2 TNPH. LW2 RPM. LW2 DEPT. GR. LW2 ROBU. LW2 DRHU. LW2 PEU. LW2 TNPH . L W2 RPM. LW2 DEPT. GR. LW2 ROBU. LW2 DRHU. LW2 PEU. LW2 TNPH. LW2 RPM. LW2 12000. 000 ATR.LW2 1 . 339 PSR.LW2 1 . 198 ROPE.LW2 114.509 TABR.LW2 2899.594 TABD.LW2 6437.094 ROBB.LW2 2. 405 ROBL.LW2 2.394 ROBR.LW2 2,398 DRHB.LW2 0.127 DRHL.LW2 0.090 DRHR.LW2 0.033 PEB.LW2 5.073 PEL.LW2 4.476 PER.LW2 3.563 TNRA.LW2 50.982 DCAL.LW2 0.440 HDIA.LW2 10.182 VDIA.LW2 77. 882 11000. 000 ATR. LW2 89. 758 TABR. LW2 2. 385 ROBL. LW2 O . 039 DRHL . LW2 3.515 PEL . LW2 36. 795 DCAL. LW2 71. 000 2 790 PSR.LW2 2. 731 ROPE.LW2 774 750 TABD.LW2 2468. 094 ROBB.LW2 2 463 ROBR.LW2 2.399 DRHB.LW2 0 029 DRHR.LW2 O. 029 PEB.LW2 3 001 PER.LW2 3.396 TNRA.LW2 0 171 HDIA.LW2 9. 002 VDIA.LW2 10000. 000 ATR. LW2 1 . 809 PSR. LW2 2. 055 ROPE. LW2 92. 478 TABR. LW2 1498. 906 TABD. LW2 2506. 781 ROBB. LW2 2.334 ROBL.LW2 2.365 ROBR.LW2 2.335 DRHB.LW2 O. 062 DRHL.LW2 O. 047 DRHR,LW2 O. 022 PEB.LW2 3 . 511 PEL. LW2 3 . 055 PER. LW2 3 . 395 TNRA. LW2 41.565 DCAL.LW2 0.150 HDIA.LW2 11.033 VDIA.LW2 75. 000 9000. 000 ATR. LW2 80. 657 TABR. LW2 2. 278 ROBL. LW2 O. 043 DRHL.LW2 2. 852 PEL. LW2 40. 055 DCAL. LW2 69. 000 2. 634 PSR. LW2 2. 432 ROPE. LW2 440.438 TABD.LW2 3074.203 ROBB.LW2 2.234 ROBR.LW2 2.257 DRHB.LW2 O . 035 DRHR . LW2 O . 037 PEB . LW2 3.2 O1 PER. LW2 3.123 TNRA . LW2 O. 091 HDIA. LW2 10. 202 VDIA. LW2 8537. 000 ATR. LW2 43.102 TABR. LW2 2. 257 ROBL. LW2 -0. 315 DRHL. LW2 19. 315 PEL. LW2 67. 755 DCAL. LW2 O. 000 O . 139 PSR . LW2 O . 000 TABD. LW2 2.156 ROBR. LW2 -0.297 DRHR.LW2 19. 734 PER.LW2 O . 541 HDIA. LW2 0. 855 ROPE. LW2 O. 000 ROBB. LW2 2.282 DRHB. LW2 - 0.348 PEB. LW2 18. 709 TArRA . LW2 8. 868 VDIA. LW2 51. 572 2. 391 O. 018 3. 621 26. 969 8. 834 233 980 2 388 -0 005 3 316 22 392 9 327 90. 468 2. 339 O. 006 3. 223 24. 015 10. 591 504. 547 2. 266 O. 027 3.120 23. 518 10. 401 67. 421 2.108 -0.374 20. 647 32. 619 8. 802 ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .003 SERVICE : FLIC VERSION : O01CO1 DATE : 98/04/23 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 15 **** FILE HEADER **** FILE NAME : EDIT .004 SERVICE : FLIC VERSION . O01CO1 DATE : 98/04/23 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE AUJM~ER 4 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 3 DEPTH INCREMENT: 0.5000 FILE S~Y VENDOR TOOL CODE START DEPTH STOP DEPTH 12197.0 12740.0 LOG HEADER DATA DATE LOGGED: 25 - JUL- 97 SOFTWARE: SURFACE SOFTWARE VERSION: IDEAL DO~VHOLE SOFTWARE VERSION: 4. OC DATA TYPE (MEMORY or REAL-TIME): MEMORY TD DRILLER (FT) : 12740.0 TOP LOG INTERVAL (FT): 5814.0 BOTTOM LOG INTERVAL (FT) : 12740.0 BIT ROTATING SPEED (RPM) : 81 HOLE INCLINATION (DEG) MINIMUM ANGLE: 28.3 MAXIMUM ANGLE: 61.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE ......................... CDR RESIST./GR ADN AZ. DENS./NEUT. $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH (FT) : BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: TOOL NUMBER CDR752 ADN059 8.500 8648.0 LSND 10.30 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 16 MUD CHLORIDES (PPM) : 700 FLUID LOSS (C3): RESISTIVITY (OH~M) AT TEMPERATURE (DEGF) : MUD AT MEASURED TEMPERATURE (MT): 1. 900 MUD AT MAX CIRCULATIONG TEMPERATURE : MUD FILTRATE AT (MT): 1. 600 MUD ~ AT (MT): 105.0 105.0 NEUTRON TOOL MA TRIX: SANDSTONE MATRIX DENSITY: 2.65 HOLE CORRECTION (IN): TOOL STANDOFF (IN): 1.0 EWR FREQUENCY (HZ): 20000 REMARKS: *** RUN 1 DRILLED INT. 5884'-8670'**** *** RUN 2 DRILLED INT. 8670'-12323'**** *** RUN 3 DRILLED INT. 12323'-12740'**** RUN 1 - CDR, RUNS 2/3 - CDR/ADN GR/TNPH CORRECTED FOR ENVIRONMENTAL FACTORS 9. 625 CSG SET AT 8670' AFTER RUN 1 DATA FROM DOWNHOLE MEMORY, V4. OC SOFTWARE ***THIS IS THE DATA FROM RUN #3 (CDR/ADN) *** $ LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE- 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 100 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 10 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 17 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) O0 000 O0 0 4 1 1 4 68 0000000000 DEPT FT 4000096 ATR LW3 0H~44000096 O0 000 O0 0 4 1 1 4 68 0000000000 PSR LW3 0H~44000096 O0 000 O0 0 4 1 1 4 68 0000000000 ROPE LW3 F/HR 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 GR LW3 GAPI 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 TABR LW3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 TABD LW3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 ROBB LW3 G/C3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 ROBU LW3 G/C3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 ROBL LW3 G/C3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 ROBR LW3 G/C3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 DRHB LW3 G/C3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 DRHU LW3 G/C3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 DRILL LW3 G/C3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 DRHRLW3 G/C3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 PEB LW3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 PEU LW3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 PEL LW3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 PER LW3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 TNRALW3 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 TNPH LW3 PU 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 DCALLW3 IN 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 HDIA LW3 IN 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 VDIA LW3 IN 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 RPM LW3 RPM 4000096 O0 000 O0 0 4 1 1 4 68 0000000000 ** DATA ** DEPT. 12740. 000 GR. LW3 97.518 ROBU. LW3 2.638 DRHU. LW3 O . 073 PEU. LW3 5.047 TNPH. LW3 35. 582 RPM. LW3 75. 000 DEPT. 12197. 000 GR. LW3 100. 108 ROBU. LW3 2.170 DRHU. LW3 O . 203 PEU. LW3 7. 568 TNPH. LW3 43. 902 RPM. LW3 64. 000 ATR.LW3 2. 316 PSR. LW3 2.130 ROPE. LW3 TABR. LW3 903. 000 TABD. LW3 2707. 000 ROBB. LW3 ROBL. LW3 2. 652 ROBR. LW3 2.648 DRHB. LW3 DRHL.LW3 O. 048 DRHR . LW3 O . 040 PEB. LW3 PEL.LW3 4.873 PER.LW3 5.137 TNRA.LW3 DCAL. LW3 O . 501 HDIA. LW3 9. 002 VDIA . LW3 ATR.LW3 2.724 PSR.LW3 2.365 ROPE. LW3 TABR.LW3 727.000 TABD.LW3 4994.000 ROBB.LW3 ROBL.LW3 2. 320 ROBR.LW3 2. 794 DRHB. LW3 DRHL.LW3 0.230 DRHR.LW3 O. 479 PEB.LW3 PEL . LW3 6.392 PER . LW3 6.236 TNRA . LW3 DCAL.LW3 O. 720 HDIA. LW3 10. 936 VDIA. LW3 214. 291 2. 650 O. 001 5. 044 21. 954 9. 069 211. 769 3. 064 0.544 5. 803 24. 755 10. 923 ** END OF DATA ** LIS Tape Verification Listing Schlumberger Alaska Computing Center 23-APR-1998 10:25 PAGE: 18 **** FILE TRAILER **** FILE NAME : EDIT .004 SERVICE : FLIC VERSION : O01CO1 DATE : 98/04/23 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** TAPE TRAILER **** SERVICE NAME : EDIT DATE : 98/04/23 ORIGIN : FLIC TAPE NAME : 97417 CONTINUATION # : 1 PREVIOUS TAPE : COf~4ENT : B.P. EXPLORATION, MILNE POINT MPL-39, API #50-029-22786-00 **** REEL TRAILER **** SERVICE NAME : EDIT DATE : 98/04/23 ORIGIN : FLIC REEL NAME : 97417 CONTINUATION # : PREVIOUS REEL : COf4~ENT : B.P. EXPLORATION, MILNE POINT MPL-39, API #50-029-22786-00