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Home My WebLink About195-1801. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ESP Change-out w/ Packer 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 15,655 feet N/A feet true vertical 7,628 feet N/A feet Effective Depth measured 15,551 feet ±4,531 feet true vertical 7,547 feet ±3,261 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 / EUE 8rd ±15,551' ±7,547 Packers and SSSV (type, measured and true vertical depth)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 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Contact Phone: Viking Hyd. Set ESP Pkr 5,750psi 7,240psi Burst N/A Collapse N/A 3,090psi 5,410psi 4,711' 7,614' measuredPlugs Junk measured N/A Length 80' 8,988' 15,608' Size Surface Production 20" 9-5/8" 7" Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 195-180 50-029-22621-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025509 & ADL0355017 MILNE POINT / KUPARUK RIVER OIL Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: MILNE PT UNIT L-25 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0 1,0400 103 221 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 112' 9,019' 15,636' 1,950 Conductor TVD 112' 321-060 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 22 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 534 0 Taylor Wellman twellman@hilcorp.com 777-8449Authorized Title: Operations Manager Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Grace Christianson at 11:11 am, Aug 09, 2023 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2022.03.18 11:43:43 -08'00' David Haakinson (3533) DSR-8/14/23 RBDMS JSB 081523 _____________________________________________________________________________________ Revised By TDF: 7/27/2022 SCHEMATIC Milne Point Unit Well: MPU L-25 Last Completed: 7/13/2020 PTD: 195-180 ± TD =15,655’ (MD) / TD = 7,628’(TVD) 20” RA Tag @ 15,020’ Orig. KB Elev.:46’/ Orig. GL Elev.: 16.5’ Nabors 22E / RT to 7”Hanger= 28.5’ 7” 10 11 & 12 13 14 ±9-5/8” 1 5 Min ID = 2.205”@ ±15,625’ PBTD =15,551’(MD) / PBTD = 7,547’(TVD) 8 & 9 KUP B6 Sands 6 & 7 KUP A3/A2/A1/A1B Sands 2 3 4 KUP C1 Sands Tubing Punch ±14,959’ – ±14,962’’ MD (12 holes) 3/12/20 Tight Spot @ ±3,034’MD Able to get 2.25” Through Tubing Leaks found at ~±13,787’, ±13,805’, ±13,816’ MD. Top of tubing separation @ ±696’ Bottom of Mule Shoe @ 666’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 112' 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 9,019’ 7" Production 26 / L-80 / BTC/BTC-MOD 6.276 Surface 15,636’ TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 666’ 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 ±696 ±15,551’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C1, B6 15,135’ 15,173’ 7,228’ 7,257’ 38 1/20/2020 Open Kuparuk B6 15,174’ 15,180’ 7,258’ 7,262’ 6 4/20/1996 Open Kuparuk A3/A2/A1 15,230’ 15,250’ 7,300’ 7,315’ 20 6/23/2005 Open 15,250’ 15,282’ 7,315’ 7,340’ 32 N/A Open 15,278’ 15,308’ 7,337’ 7,360’ 30 6/23/2005 Open Kuparuk A1B 15,309’ 15,336’ 7,360’ 7,381’ 27 1/19/2020 Open Ref Log: 4/10/1996 – GR / CCL : Mid Perf TVD = 7,308’ : Mid Perf MD = 15,241’ OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24” Hole 9-5/8" 1,750 sx PF ‘E’, 250 sx Class ‘G’, 150 sx PF ‘E’ in 12-1/4” Hole 7” 240 sx Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 69 to 74 deg. f/ 3,600’ to 13,150’ Max Hole Angle through perforations = 40 deg. TREE & WELLHEAD Tree 2-9/16” x 11” – 5M FMC Wellhead 11” 5M FMC Gen 5, w/ 11” Gen 5 ESP w/ 2-7/8” FMC Tbg. Hngr., EUE Lift Threads, 2-7/8” CIW “H” BPV profile GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E - 12/6/1995 Perf, Frac & Run ESP Completion by Polar #1 – 5/25/1996 ESP Change-out by Nabors 4ES – 12/9/1998, 10/2/1999 & 3/23/2002 Pull ESP Service and Re-run by Nabors 4ES – 11/29/2003 Perforate & ESP Change-out by Nabors 4ES – 6/25/2005 ESP Change-out by Doyon 16 – 12/18/2013 ESP Change-out and Perforate by ASR 1 – 1/23/2020 ESP Change-out by ASR 1 – 7/13/2020 Kill String Installed by Doyon 14 – 2/22/2021 STIMULATION DETAIL Frac’d w/ 110,500# of 16/20 Carbolite behind pipe NOTE: All Depths associated with Tubing/ Jewelry have been shifted ±696’ deeper to reflect the shift of tubing down to PB depth JEWELRY DETAIL No Depth Item GLM Detail: KBMG GLM 2-7/8” x 1” BK Latch 1 ±4,475’GLM #2: KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 2 ±4,531’Packer: Viking Hyd Set ESP Packer W/Dual vent valve (49k Pull Release) 3 ±4,581’2-7/8” X-Nipple (2.313 ID) 4 ±15,554’GLM #1: KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 5 ±15,612’2-7/8” XN-Nipple (Min ID = 2.205 No-go) 6 ±15,663’Discharge Head: 400 FPDIS 7 ±15,664’Discharge Head: HEAD S/A B/O PRESS PORT 400P 8 ±15,665’Pump 2: PMSXD 134 FLEX ER M FER 9 ±15,668’Pump 1: PMSXD 134 FLEX ER M FER 10 ±15,712’Gas Separator: 513 GSHV FER 11 ±15,715’Upper Tandem Seal: GSB3DB H6 SB/AB PFSA 12 ±15,722’Lower Tandem Seal: GSB3DB H6 SB/AB PFSA 13 ±15,729’Motor: 562XP – 150HP/ 2420V / 38A 14 ±15,739’Gauge & Centralizer: Zenith E7 175C – Bottom @ 15,049’ _____________________________________________________________________________________ Revised By TDF: 3/14/2022 SCHEMATIC Milne Point Unit Well: MPU L-25 Last Completed: 7/13/2020 PTD: 195-180 ± TD =15,655 (MD) / TD = 7,628(TVD) 20 RA Tag @ 15,020 Orig. KB Elev.:46/ Orig. GL Elev.: 16.5 Nabors 22E / RT to 7Hanger= 28.5 7 10 11& 12 13 14 ±9-5/8 1 5 Min ID = 2.205@ ±15,625 PBTD =15,551(MD) / PBTD = 7,547(TVD) 8 & 9 KUP B6Sands 6 & 7 KUP A3/A2/A1/A1B Sands 2 3 4 KUP C1 Sands Tubing Punch ±14,959 ±14,962 MD (12 holes) 3/12/20 Tight Spot @ ±3,034MD Able to get 2.25 Through Tubing Leaks found at ~±13,787, ±13,805, ±13,816 MD. Top of tubing separation @ ±696 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 112' 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 9,019 7" Production 26 / L-80 / BTC/BTC-MOD 6.276 Surface 15,636 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 ±696 ±15,551 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C1, B6 15,135 15,173 7,228 7,257 38 1/20/2020 Open Kuparuk B6 15,174 15,180 7,258 7,262 6 4/20/1996 Open Kuparuk A3/A2/A1 15,230 15,250 7,300 7,315 20 6/23/2005 Open 15,250 15,282 7,315 7,340 32 N/A Open 15,278 15,308 7,337 7,360 30 6/23/2005 Open Kuparuk A1B 15,309 15,336 7,360 7,381 27 1/19/2020 Open Ref Log: 4/10/1996 GR / CCL : Mid Perf TVD = 7,308 : Mid Perf MD = 15,241 OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24 Hole 9-5/8" 1,750 sx PF E, 250 sx Class G, 150 sx PF E in 12-1/4 Hole 7 240 sx Class G in 8-1/2 Hole WELL INCLINATION DETAIL KOP @ 500 Max Hole Angle = 69 to 74 deg. f/ 3,600 to 13,150 Max Hole Angle through perforations = 40 deg. TREE & WELLHEAD Tree 2-9/16 x 11 5M FMC Wellhead 11 5M FMC Gen 5, w/ 11 Gen 5 ESP w/ 2-7/8 FMC Tbg. Hngr., EUE Lift Threads, 2-7/8 CIW H BPV profile GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E - 12/6/1995 Perf, Frac & Run ESP Completion by Polar #1 5/25/1996 ESP Change-out by Nabors 4ES 12/9/1998, 10/2/1999 & 3/23/2002 Pull ESP Service and Re-run by Nabors 4ES 11/29/2003 Perforate & ESP Change-out by Nabors 4ES 6/25/2005 ESP Change-out by Doyon 16 12/18/2013 ESP Change-out and Perforate by ASR 1 1/23/2020 ESP Change-out by ASR 1 7/13/2020 STIMULATION DETAIL Fracd w/ 110,500# of 16/20 Carbolite behind pipe NOTE: All Depths associated with Tubing/ Jewelry have been shifted ±696 deeper to reflect the shift of tubing down to PB depth JEWELRY DETAIL No Depth Item GLM Detail: KBMG GLM 2-7/8 x 1 BK Latch 1 ±4,475GLM #2: KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 2 ±4,531Packer: Viking Hyd Set ESP Packer W/Dual vent valve (49k Pull Release) 3 ±4,5812-7/8 X-Nipple (2.313 ID) 4 ±15,554GLM #1: KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 5 ±15,6122-7/8 XN-Nipple (Min ID = 2.205 No-go) 6 ±15,663Discharge Head: 400 FPDIS 7 ±15,664Discharge Head: HEAD S/A B/O PRESS PORT 400P 8 ±15,665Pump 2: PMSXD 134 FLEX ER M FER 9 ±15,668Pump 1: PMSXD 134 FLEX ER M FER 10 ±15,712Gas Separator: 513 GSHV FER 11 ±15,715Upper Tandem Seal: GSB3DB H6 SB/AB PFSA 12 ±15,722Lower Tandem Seal: GSB3DB H6 SB/AB PFSA 13 ±15,729Motor: 562XP 150HP/ 2420V / 38A 14 ±15,739Gauge & Centralizer: Zenith E7 175C Bottom @ 15,049 Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 Doyon 14 50-029-22621-00-00 195-180 2/20/2021 2/22/2021 2/19/2021 - Friday No operations to report. 2/17/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 2/18/2021 - Thursday No operations to report. Accept rig @ 09:00. PJSM, ensure suction line on FB tank clear. Bleed off gas from IA and tubing, pump down the 2-7/8" tubing, stage pump to 1.5 bpm, 570 psi, pump 30 bbl hi vis spacer, followed with 9.8 ppg KW brine thru tubing punch holes at 14,959', take returns out IA holding 300 psi back pressure on choke at FB tank, at 210 bbls away increase to 2.5 bpm, 960 psi, gradually reduce choke to 100 psi, then fully open. 70 bbls away 9.8 brine at returns, 200 bbls away sea water at returns. 450 bbls 8.3 water, pump total 753 bbls with 9.6 brine at returns. 19 bbl losses. Shut down, let the tbg and I/A bleed to 0 psi, shut in and monitor, in 5 min building to 100 on the tbg, 110 psi on the IA and leveling out, perform several times with final building to 10 psi and leveling out. Pump additional 50 bbls 9.8 ppg NaCl brine down the tbg 1.5 BPM, 410 PSI. 29 bbls total losses for both circulations. Out of fluid on the rig, vac truck en route from Deadhorse with 4th load of brine. Monitor pressure build, 38 PSI initial pressure. Bleed off 3x over 15 min built to 17 PSI. Continue to bleed off monitor for 2 hrs total, final 2 PSI with 8.5 bbls bled back. Flow check for 30 min. static. Sim-ops: Load 2-7/8" tubing in the pipe shed. R/D circulating lines & squeeze manifold. Install BPV, bleed off packer vent control pressure closing vents and torque tubing hanger lock down screws. Remove ESP & control line penetrations from tree adapter flange. N/D tree & set in cellar. Measure RKB elevations. Install test dart then pressure test to 500 PSI low / 4,000 PSI high - good. N/U BOP stack, kill line, riser and install turnbuckles. Move production tree to driller's side of the cellar to clear kill line. Install 2-7/8" test joint and R/U test equipment. Fill stack with water. Perform shell test: 250 PSI good, kill line Oteco connection leaking on high. Tighten Oteco clamp 2x, still leaking. Remove kill line, install new Oteco gasket and re-install kill line. Perform shell test - good 3,500 PSI high test. Test BOPs as per AOGCC, PTC & Hilcorp requirements. AOGCC notified of testing at 18:23 on 18 Feb 2021. AOGCC representative Adam Earl waived the right to witness test at 18:34 on 18 Feb 2021. All tests performed with fresh water against a test dart installed in the tubing hanger. Tests held for 5 minutes at 250 PSI low / 3,500 PSI high. 1) Annular with 2-7/8" test joint, choke valves 1, 12, 13, 14, kill line Demco & 3.5" FOSV. 2) Upper 2-7/8" x 5" VBR on 2-7/8" test joint, choke valves 9, 11, kill line HCR & 3.5" dart valve. Test continues into the next report period. 2/20/2021 - Saturday Accept rig @ 09:00. Test BOPs as per AOGCC, PTC & Hilcorp requirements. AOGCC notified of testing at 18:23 on 18 Feb 2021. AOGCC representative Adam Earl waived the right to witness test at 18:34 on 18 Feb 2021. Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 Doyon 14 50-029-22621-00-00 195-180 2/20/2021 2/22/2021 Hilcorp Alaska, LLC Weekly Operations Summary 2/21/2021 - Sunday Continue BOP testing to 250 psi low/ 3,500 psi hi, 5 min ea. charted. 3) Choke valves 5, 8, 10, manual kill & upper IBOP. 4) Choke valves 4, 6, 7 & lower IBOP. 5) Choke valve 2. 6) HCR choke. 7) Manual choke. 8) Lower 2-7/8" x 5" VBR on 2-7/8" test joint. 9) Blind rams & choke valve 3. 10) Manual choke B. 11) Super choke A. Perform accumulator test, 3,100 psi system pressure, 1,650 psi after closure, 200 psi attained in 43 sec, full pressure in 198 sec. 6 N2 bottle avg = 2,120 psi. Rig electrician test rig gas alarms, verify PVT system. Note: 1- F/P on HCR choke, service and re-test, good. Blow down lines, R/D test equipment. Vac out BOP stack, R/U tee bar. Load tools to the rig floor. Pull BPV dart, check for pressure under BPV, none, finish loading tools to floor, M/U FOSV and XOs with 2-7/8" pup on landing joint. Pull BPV, M/U landing joint. BOLDS. P/U unseating hanger at 73k, work up to 175k observing packer shear work several times, PU to 190k seeing packer movement, S/O to 75k, PU to 190k 3 times confirming movement releasing 7'' viking packer at 3,835'. SO to neutral wt, fill the hole with the trip tank 11 bbls to fill, wait 30 minutes to let packer element relax. Monitor well with trip tank. Loss rate 2.5 bph. load tools to rig floor. Attempt to pull hanger to floor, PU to 175k pulling packer up hole 20', S/O 20' working packer 3 times staging up to 190k pulling packer up hole, pipe parted, Notify town team, notify Baker fishing to bring out overshot and tools. POOH L/D tbg hanger and pup, 4 joints 2-7/8" EUE tubing, pup joint, GLM, pup joint, and parted joint tubing. Parted joint= 5.35', total length POOH= 167.25' ( old ESP tally shows 161.40') ( ESP cable length recovered= 199.5'.) Monitor well, 2 bph loss rate. R/D 2-7/8" handling equipment, mobilize 4'' handling equipment , test plug and wear bushing to rig floor. Install test plug with 4" test joint. R/U test equipment. Fill stack & flood lines. Test BOPs with 4" test joint to 250 PSI low / 3,500 PSI high for 5 min each with fresh water and charted. 1) Upper 2-7/8" x 5" VBR on 4" test joint and 4" dart valve. Test plug began leaking on 2nd test. Remove test plug, inspect & re-install. 2) Lower 2-7/8" x 5" VBR on 4" test joint and 4" FOSV. Drain stack, blow down lines, R/D test equipment, pull test joint and test plug. Install 9-1/8" I.D. wear bushing and run in 2 lock down screws. Mobilize Baker BHA components and XOs to the rig floor and verify O.D., I.D. & lengths. PJSM. M/U fishing BHA #1 - 5.75" OD overshot w/ 2-7/8" grapple and 2-3/8" stop ring, bumper sub and XO sub to 15.33'. Losing 2 BPH, 13.6 bbls lost at midnight. Single in the hole w/ 4" XT-39 drill pipe. Top of fish should have been at ±196' but was not seen indicating the tubing string fell downhole after parting. Began to see 2-3K drag at 576', suspect control line. Deepest tubing should be is 685' (PBTD of 7" is 15,551'.) Stop at 658' & consult completions engineer. Decision made to make a rope spear run prior to engaging with overshot. POOH racking back 7 stands & L/D grapple. M/U fishing BHA #2 Baker rope spear w/ 10 barbs, bumper sub, oil jar and XO to 36.24'. TIH to 605' then M/U top drive. 53K SO / 47K PU. TIH to 664K and took 2K weight. Rotate 3 turns, S/O and rotate in intervals to 675' for a total of 11 rotations. Saw 4K weight max. P/U with 2K overpull/drag. POOH from 675' to 36'. Inspect rope spear, found control wire wrapped in spear. Cut off control wire, 16.75# recovered, est. 83' based upon weight. Suspect 84' of control line remaining above top of fish. RIH with fishing BHA #3 same rope spear assembly. TIH to 605' then M/U top drive. 53K SO / 47K PU. TIH to 675' & took 5K weight, rotate 2 turns. S/O & rotate in intervals to 688' for a total of 13 rotations. Saw 5K weight max. P/U with 5K overpull/drag. POOH from 688' to 36'. Inspect rope spear, recovered 8.25# (41' based upon weight) on spear (not continuous) with 250' of control line tail. 374' total between both run RIH with fishing BHA #4 same rope spear assembly. TIH to 605' then M/U top drive. 53K SO / 47K PU. TIH to 701' and set 5K down twice. P/U to 691' to verify free. S/O to 695', rotate 1 rev, S/O to 697', rotate 1 rev, S/O to 698', rotate 1 rev - 3 revolutions total. S/O & tag 701' with 5 K again. P/U with no drag. POOH from 701' to 510'. M/U fishing BHA #1 - 5.75" OD overshot w/ 2-7/8" grapple and 2-3/8" stop ring, bumper sub and XO sub to 15.33'. Top of fish should have been at ±196' but was not seen indicating the tubing string fell downhole after parting. Attempt to pull hanger to floor, PU to 175k pulling packer up hole 20', S/O 20' working packer 3 times staging up to 190k pulling packer up hole, pipe parted, Suspect 84' of control line remaining above top of fish Notify town team, notify Baker fishing to bring out overshot and tools. POOH L/D tbg hanger and pup, 4 joints 2-7/8" EUE tubing, pup joint, GLM, pup joint, and parted joint tubing. Parted joint= 5.35', total length POOH= 167.25' ( old ESP tally shows 161.40') P/U unseating hanger at 73k, work up to 175k observing packer shear work several times, PU to 190k seeing packer movement, S/O to 75k, PU to 190k 3 times confirming movement releasing 7'' viking packer at 3,835'. SO to neutral wt recovered 8.25# (41' based upon weight) on spear (not continuous) with 250' of control line tail. Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 Doyon 14 50-029-22621-00-00 195-180 2/20/2021 2/22/2021 Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. POOH with fishing BHA #4 - Baker rope spear from 510' to 36'. Inspect rope spear, no control line recovered and no damage or missing barbs on spear. L/D rope spear. M/U fishing BHA #5 - 5.75" O.D overshot with 2-7/8" grapple & 2-3/8" stop ring, bumper sub, oil fishing jar and XO sub to 28'. RIH to 691', M/U TD, PU 47k, SO 52k, tag at 696' 2 times, work over fish w/ RH rotation. swallowed 697' set grapple w/ 15k down, stage overpulls in 25k increments, at 140k seen wt drop to 125k, continue pulling to 175k, work pipe without setting down 75k to 175k w/ 6' free travel both up and down. While working free travel several times loosing our free travel. pull max pull @ 185k, S/O to 85k with no movement, decision made to set jars, jar 5 times at 100k over with no movement, took stretch calcs, from 50k over to 100k over= 43'' stretch. indicating packer set. Park with 180k,. Notify engineer to review options, continue jarring while town team reviewing options, jarring up with 100k over pulling up to 185k, Perform post jar derrick inspection after every 20 hits. Loss rate 2 bph. Decision made to POOH run kill string, RDMO L-25, set down to 40k, sloA20:F21wly turning to the right and P/U off fish, Break out top drive, POOH from 696' L/D 4'' DP to 28', LD XO, oil jar, bumper sub and overshot. Load out tools, Pull wear bushing, M/U stack flush tool, jet stack, Load, strap and tally 2-7/8" kill string, Sim-ops: R/D Doyon camp and start move to M-pad @ 15:00. PJSM, Drift P/U and RIH with 2-7/8" EUE 6.5# L-80 mule shoe jt, and 19 jts 2-7/8" EUE 6.5# L-80 tubing to 634', torque to 2,200 ft/lbs. M/U tubing hanger with pup, M/U landing joint, Drain stack, land out at 666.17' with 5k on hanger, RILDS, L/D landing joint. Install BPV @ per WHR. Sim-ops: offload pits, L/D mouse hole. N/D BOPs. Sim-ops: Remove 2-7/8" tubing from the pipe shed for rig move. N/U tree. Test hanger void to 500 PSI for 5 min & 5000 PSI for 10 min - good. Pressure test tree to 5,000 PSI for 5 min - good. Pull BPV. Sim-ops: Remove 2-7/8" tubing from the pipe shed for rig move. R/U to freeze protect well in the cellar. Injection line to IA and tubing to cuttings tank. Mini vac truck w/ diesel having problems with pump. Attempt to apply pressure from 2nd vac truck unsuccessful. Suspect broken of frozen valve. Apply heat to valve. No vac trucks available from Milne Point or Innovation Rig. Dispatch replacement vac truck from Deadhorse. Continue to troubleshoot vac truck on location. Truck arrived on location at 03:00. Sim-ops: Blow down rig floor and disconnect lines. Roads & pads preparing L-01A location - 6" low in areas. Transfer diesel from disabled vac truck to new vac truck. Line up truck to mud pump. Flood lines w/ water & PT to 1,500 PSI. Pump 27 bbls diesel freeze protection down the IA taking returns up the tubing to the cuttings tank, 3 BPM, 30 PSI ICP, 140 PSI FCP. 3 bbls pumped before wellbore was full. 24 bbls returned to tank, straight diesel last 3 bbls. Sim-ops: Empty rock washer & mud pits. Flush mud pumps and lines with fresh water to the cuttings tank. Blow down and rig down lines. Secure well: 20 PSI on IA and tubing, 0 PSI on OA. Sim-ops: Set matting boards on L-01A. PJSM and pre-skid rig floor checklist. Begin skidding rig floor into drilling position. Move rock 2/23/2021 - Tuesday 2/22/2021 - Monday washer and fuel tank trailer. Rig released from L-25 at 06:00 Drift P/U and RIH with 2-7/8" EUE 6.5# L-80 mule shoe jt, and 19 jts 2-7/8" EUE 6.5# L-80 tubing to 634', torque to 2,200 ft/lbs. M/U tubing hanger with pup, M/U landing joint, M/U TD, PU 47k, SO 52k, tag at 696' 2 times, work over fish w/ RH rotation. swallowed 697' set grapple w/ 15k down, stage overpulls in 25k increments, at 140k seen wt drop to 125k, continue pulling to 175k, work pipe without setting down 75k to 175k w/ 6' free travel both up and down. While working free travel several times loosing our free travel. pull max pull @ 185k, S/O to 85k with no movement, decision made to set jars, jar 5 times at 100k over with no movement, took stretch calcs, from 50k over to 100k over= 43'' stretch. indicating packer set. POOH with fishing BHA #4 - Baker rope spear from 510' to 36'. Inspect rope spear, no control line recovered and no damage or missing barbs on spear Decision made to POOH run kill string From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220318 1422 MPU L-25_ PTD_ 195-180_ 10-404 Follow Up Date:Friday, March 18, 2022 2:23:51 PM Mel, Today I submitted the 10-404 for MPU L-25, sundry #: 321-060 which was approved on 2/1/2021. The initial work per formed on this well started on 2/20/2021 and ended 2/23/2021 after the tubing parted and the ESP assembly moved downhole ±696’. Hilcorp’s intention was to return and complete the sundried work, unfortunately this did not happen. It is our plan to return and recomplete this well when we can fit it into this year’s schedule. With the changed/increased complexity of the scope due to the now required fishing operation we want to use a new procedure and sundry to install a new completion. If you have any questions please let me know. 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. JLC 3/30/2023 3/30/2023 RBDMS JSB 033123 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ESP Change-out w/ Packer Hilcorp Alaska 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 15,655 feet N/A feet true vertical 7,628 feet N/A feet Effective Depth measured 15,551 feet 3,813 feet true vertical 7,547 feet 3,036 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 / EUE 8rd 15,062' 7,173' Packers and SSSV (type, measured and true vertical depth)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 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG 0 Water-Bbl MD 112' 9,019' 15,636' TVD 112' Viking Hyd. Set ESP Pkr Oil-Bbl measured true vertical Packer Size N/A Casing Conductor Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 195-180 50-029-22621-00-00 Plugs ADL025509 & ADL0355017 5. Permit to Drill Number: MILNE POINT / KUPARUK RIVER OIL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-095 0 Authorized Signature with date: Authorized Name: Ian Toomey itoomey@hilcorp.com 500 MILNE PT UNIT L-25 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 140 Casing Pressure Tubing Pressure 0 N/A measured Length 80' 8,988' 15,608' Surface Production 777-8434 20" 9-5/8" 7" 4,711' 7,614' 5,410psi 0 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 3,090psi Burst N/A 5,750psi 7,240psi Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:22 am, Mar 02, 2021 Chad Helgeson (1517) 2021.03.02 09:16:40 - 09'00' MGR03MAR2021 SFD 3/2/2021 RBDMS HEW 3/2/2021 DSR-3/2/21 _____________________________________________________________________________________ Revised By TDF: 2/23/2021 SCHEMATIC Milne Point Unit Well: MPU L-25 Last Completed: 7/13/2020 PTD: 195-180 TD =15,655’ (MD) / TD = 7,628’(TVD) 20” RA Tag @ 15,020’ Orig. KB Elev.:46’ / Orig. GL Elev.: 16.5’ Nabors 22E / RT to 7”Hanger= 28.5’ 7” 6 11 12 & 13 14 9 15 9-5/8” 1 5 Patch pulled 2-3-21 Min ID = 2.205”@ 14,929’ PBTD = 15,551’(MD) / PBTD = 7,547’(TVD) 9& 10 KUP B6 Sands 7 & 8 KUP A3/A2/A1/A1B Sands 2 3 4 KUP C1 Sands Tubing Punch 14,959’ – 14,962’’ MD (12 holes) 3/12/20 Tight Spot @ 2,338’MD Able to get 2.25” Through Tubing Leaks found at ~13787’, 13805’, 13816’ MD. Patch pulled 2-3-21 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1 / H-40 / N/A N/A Surface 112' 9-5/8" Surface 40 / L-80 / BTC 8.835 Surface 9,019’ 7" Production 26 / L-80 / BTC/BTC-MOD 6.276 Surface 15,636’ TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 15,062’ JEWELRY DETAIL No Depth Item GLM Detail: KBMG GLM 2-7/8” x 1” BK Latch 1168’GLM #3: KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 23,779’GLM #2: KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 3 3,835’ Packer: Viking Hyd Set ESP Packer W/Dual vent valve (49k Pull Release) 4 3,885’ 2-7/8” X-Nipple (2.313 ID) 5 14,858’GLM #1: KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 6 14,916’ 2-7/8” XN-Nipple (Min ID = 2.205 No-go) 7 14,967’ Discharge Head: 400 FPDIS 8 14,968’ Discharge Head: HEAD S/A B/O PRESS PORT 400P 9 14,969’ Pump 2: PMSXD 134 FLEX ER M FER 10 14,992’ Pump 1: PMSXD 134 FLEX ER M FER 11 15,016’ Gas Separator: 513 GSHV FER 12 15,019’ Upper Tandem Seal: GSB3DB H6 SB/AB PFSA 13 15,026’ Lower Tandem Seal: GSB3DB H6 SB/AB PFSA 14 15,033’ Motor: 562XP – 150HP/ 2420V / 38A 15 15,043’ Gauge & Centralizer: Zenith E7 175C – Bottom @ 15,049’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C1, B6 15,135’ 15,173’ 7,228’ 7,257’ 38 1/20/2020 Open Kuparuk B6 15,174’ 15,180’ 7,258’ 7,262’ 6 4/20/1996 Open Kuparuk A3/A2/A1 15,230’ 15,250’ 7,300’ 7,315’ 20 6/23/2005 Open 15,250’ 15,282’ 7,315’ 7,340’ 32 N/A Open 15,278’ 15,308’ 7,337’ 7,360’ 30 6/23/2005 Open Kuparuk A1B 15,309’ 15,336’ 7,360’ 7,381’ 27 1/19/2020 Open Ref Log: 4/10/1996 – GR / CCL : Mid Perf TVD = 7,308’ : Mid Perf MD = 15,241’ OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24” Hole 9-5/8" 1,750 sx PF ‘E’, 250 sx Class ‘G’, 150 sx PF ‘E’ in 12-1/4” Hole 7” 240 sx Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 69 to 74 deg. f/ 3,600’ to 13,150’ Max Hole Angle through perforations = 40 deg. TREE & WELLHEAD Tree 2-9/16” x 11” – 5M FMC Wellhead 11” 5M FMC Gen 5, w/ 11” Gen 5 ESP w/ 2-7/8” FMC Tbg. Hngr., EUE Lift Threads, 2-7/8” CIW “H” BPV profile GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E - 12/6/1995 Perf, Frac & Run ESP Completion by Polar #1 – 5/25/1996 ESP Change-out by Nabors 4ES – 12/9/1998, 10/2/1999 & 3/23/2002 Pull ESP Service and Re-run by Nabors 4ES – 11/29/2003 Perforate & ESP Change-out by Nabors 4ES – 6/25/2005 ESP Change-out by Doyon 16 – 12/18/2013 ESP Change-out and Perforate by ASR 1 – 1/23/2020 ESP Change-out by ASR 1 – 7/13/2020 STIMULATION DETAIL Frac’d w/ 110,500# of 16/20 Carbolite behind pipe 1-16-2021 Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 LRS/ Slickline 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 3/13/2020 - Friday No operations to report. 3/11/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 3/12/2020 - Thursday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. ATTEMPT TO PULL STA #1, TOOLS S/D @ 13,759' SLM, UNABLE TO WORK PAST TIGHT SPOT, LRS PUMP 5.87BBLs OF 60/40. DOWN TBG, UNABLE TO WORK DOWN, HAVE TO SPANG OUT TO WORK FREE, MINIMAL MARKS ON TOP CENT OF KOT. PULL 1" BKP-SOGLV & SET 1" BK-DGLV IN STA #3 @ 142' SLM / 167' MD. RUN HES MEMORY MAXFIRE TUBING PUNCH (17' x 1.69", 12 holes), DRIFT TBG & STOP @ 14,920' SLM / 14,956' MD, TOOLS FIRES. JOB COMPLETE, LEAVE WELL S/I & TURN WELL OVER TO PAD-OP UPON DEPARTURE. No operations to report. No operations to report. 3/14/2020 - Saturday No operations to report. 3/17/2020 - Tuesday 3/15/2020 - Sunday No operations to report. 3/16/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 7/3/2020 - Friday No operations to report. 7/1/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 7/2/2020 - Thursday No operations to report. No operations to report. WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. RUN SBHPS WITH DUAL SPARTEK GAUGES PER PROGRAM (good data.) START TIME 07:31, 30' KB CORRECTION, GAUGE #'s TOP-7,868' / BOTTOM-7,8058'. RDMO, CLOSE PERMIT W/PAD-OP. 7/4/2020 - Saturday No operations to report. 7/7/2020 - Tuesday 7/5/2020 - Sunday No operations to report. 7/6/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 7/10/2020 - Friday Crew Change service and inspect rig and equipment. Finish Prep for shell test and rig inspection. conduct shell test as per sundry 250/low 3,500/high . Found leak at 2 1/16" flange to Cushion-T, also had leak at the pump in-T swap out. 3rd test good. waiting on state rep. Matt Herrera for rig inspection and BOPE test. Rig inspection with AOGCC Inspector was a pass. BOPE Test as per sundry 250/low 2,500/high on the Annular, 250/low 3,500/high all rams and valves. failure on test #3 at Grey lock fitting replace both. Performed Gas Dection and Koomey Draw-down. Completed BOPE per sundry with AOGCC Inspector Matt Herrera Witnessing test. Repositioned target tee on the kill line pre AOGCC Inspector. Tested line to 250- 3,500psi. Good Test. L/D BOP testing equipment and blew lines dry. Prep rig floor to pull ESP completion and serviced rig. Pulled plug off tool and well went on a vac. Pulled the BPV. BOLDS. PU/MU 2-7/8" Landing Jt. Open IA static. RU slips and could not get slips to open from the drillers console. Trouble shooting problem with slips not opening at the drillers console. Cleaned all electrical connection and double checked hydraulic connection. Found electrical actuator to remotely opened the hydraulic valve on the power pack was only going to the neutral position. Decided to operate slips from the power pack until we can troubleshot the issue with VMS and pro star. PU on hanger to 116k and packer sheared PU weight dropped to 107k. Had issues pulling hanger thru the BOP cavities. Pulled stack over to center the well and pulled hanger to rig floor. Meg check failed on penetrator, cable test was good below the penetrator. De-completed and LD tbg hanger and 6' pup jt. Baker will inspect penetrator and send out failure report. Filled hole with 7bbls of 9.9ppg kill fluid. Treaded cable and cap string thru sheaves. PU 15' on jt #1 started pulling heavy. PU to 135k started working pipe up/dn. Was able to work pipe dn 2'. PU 1 jt and started working pipe. Thinking the packer elements are the issue continued trying to work free. pipe. 7/8/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Little red rigged up, Well kill (Pressure test equipment 281/2,647psi). Tbg and IA pressure @ 480psi try bleeding tbg off but got fluid right away. Begin circulation down the tbg up the IA caught pressure on tbg at 20 bbls away brought the rate up to 1,000psi pump pressure holding back pressure on the choke after pumping tbg volume began checking returns every 20 bbls. 290 bbls away total established a loss rate +-33% we think vent PKR restricting returns. decided to Bull head IA at this point. started bull head 3BPM@ 1,500psi, then slowly the well tighten up to and end rate of 1.3BPM@ 1,650psi. 455BBLS total down the IA. Monitor well pressure until tbg went on a vac. install BPV. RDMO LRS. Blow down Kill lines and Manifold. RU Crane, ND Production Tree and inspected lifting threads on hanger. NU the 11" 5M BOP Stack as following Mud Cross, Dbl Ram (Blind and 2-7/8"-5" VBR's), Single Ram (2-7/8" solid body) and Annular. 7/9/2020 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 Hilcorp Alaska, LLC Weekly Operations Summary Freeze Protect (Post Rig) (Pressure test equipment 250/2500psi) Pump 81 bbls Dsl down IA. Pump 16 bbls Dsl down Tbg crew change, service and inspect rig. trouble shoot Tbg slips. found bad relay in PLC replaced. working string again from 40K- 130K. not making any ground. Decided to get 2x 10' pups to work string a bit deeper. make 0ne pup and work down to SO wt of 17K. work back and forth from 17k to 130K. no luck, sent baker to get cap tube extension to be able to control vent valve while sliding down with tbg. MU 2nd pup, clamp ESP cable to the tbg. at first we were able to slide down at 15k SO wt. and work up to original stuck point. then started to loose ground. After discussion with town decided to check for injection past pkr. filled IA 7 Bbls and quickly pressured up to 800psi with slow leak off. bleed off and turned around to pump down the tbg. broke circulation 1BPM @ 250psi worked up to 2.5BPM @ 800psi. started working the tbg while pumping. after several motions. noticed tbg was not sliding but stacking and pressure began to climb loosing circulation. 35 Bbls circulated. worked PKR while pumping without circulation 2.5 BPM@ 1800psi for 15 more BBLS , Bleed down and work PKR same parameters. worked through lower tight spot. RD Kelly, lay down pup and cont. to work pkr. with no suscess. RU Kelly and circulate while working PKR again. circulating down tbg up the IA for 40 Bbls at 2.5 BPM this time no success and never lost circulation. Picked up landing jnt and began to slide down to 3,825' working back up to original stuck point at 3,790'. PU 1 Jt and 10' pup. Worked back down to 3,825'md PU 20' with drag. Continue working pipe up and down 20' until drag was minimal. POH and LD 1jt. Working packer thru tight spot @ 3,790'md. Filled hole w/7 bbls of 9.9 Brine. POH LD 10' pup, JT # 1 and 2. Having to work packer thru csg collars. Continues POOH w/ ESP Completion, Jt #3, 1 hour to work packer thru csg collar. LD jt4 and top GLM. Continued POOH working packer thru the next 4 csg collars, minimal drag across collars thereafter. L/D 17jts. Displacing every 15 jts with 9.9 Brine. SD due to losing the 100k gen that powering the spooler's . Battery problems but was able to restart. Continued POOH with ESP completion. Displacing every 15 jts with 9.9 Brine. 7/11/2020 - Saturday Cont. in the hole with 2-7/8" EUE 8rnd 6.5# tbg /w ESP and control line. testing every 1,000'. a total of 483 jnts. PU and MU TBG hanger FMC 11" x 2-7/8", Make Cable splice set up control line to land tbg. 18K SO. ESP cable test after landing was good. Drop ball and rod, RU to set Viking vent PKR, Pressure up to 3,100psi saw PKR set @ 2850PSI hold for 15min, bleed off and pressure back up to 3,100psi for 5min all good. turn around and test IA pressure up slowly to 1,600PSI chart 30 min bleed off slowly test good. LD landing JNT, Set BPV, END OF WELL WORK, Begin RDMO to L-36. Empty pits and tiger tank. Broke down circulating lines. Lowered Mast move rig out, Pulled rig floor and well hut. ND 11" BOP's/NU Production Tree test void to 5,000psi. Pulled BPV. Continued RDMO 7/14/2020 - Tuesday 7/12/2020 - Sunday Crew change, service and inspect rig and equipment. LD 2-7/8" EUE 6.5# L-80 tubing from joint #49-119 with minimal drag. Pulled the packer up to the floor. inspected had minimal wear(Pics in well file). After discussion with town decided to PU new PKR to go back in the hole. Change out equipment and Reel swap. LD 1 jnt to move Packer assembly down hole. to +- 3,835'md. PU MU X-nipple(ID 2.313") w/RHC installed, Jt # 361 and new vent packer. Splice on the ESP and Control line to Viking vent Packer Verify that Packer is loaded with 4 setting shear pins and 18 release shear pins. test ESP cable, test control line to 5,000psi-good test. Function vent valve and opened at 3,600psi. Filled hole with 7bbls of 9.9ppg Brine will servicing the packer.Resumed ops. PU jt#362, 2nd GLV w/DV Installed @ 3,779'MD. Cont TIH with 2-7/8" ESP Completion clamping every other joint and testing cable ever 1,000' maintaining 500psi on control line. f/11,269'md t/1,700'md. 7/13/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 LRS/ Slick Line 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 8/21/2020 - Friday No operations to report. 8/19/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 8/20/2020 - Thursday No operations to report. No operations to report. No operations to report. 8/22/2020 - Saturday No operations to report. 8/25/2020 - Tuesday 8/23/2020 - Sunday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/3,500H. RAN HES LDL TOOL DOWN TO DISCHARGE HEAD @ 14,988' SLM (14,967' MD) & MADE ONE BASELINE & 2 LEAK DETECT PASSES UP TO 14,800' SLM (14,771' MD) AS PER PROGRAM (good data) REFER TO JOB LOG FOR RUN DETAILS. WELL S/I ON DEPARTURE, DSO NOTIFIED. 8/24/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 LRS/ Slickline 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 No operations to report. WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. RAN 5' x 2-1/8" STEM, 2.24" SWEDGE, S/D @ 13,770' SLM, UNABLE TO WORK PAST, TOOK 1,800lb OJ LICK TO COME FREE, FAINT METAL MARKS ON SWEDGE. RAN 5' x 2-1/8" STEM, 2.21" SWEDGE,S/D @ 13,770' SLM, UNABLE TO WORK PAST, TOOK 1500lb OJ LICK TO COME FREE, METAL MARKS 180deg FROM EACH OTHER ON SWEDGE.RAN 5' x 1-1/2" STEM, 2.07" SWEDGE, S/D @ 13,770', UNABLE TO WORK PAST, TOOK 15min HITTING UP W/ OJ'S & SPANGS TO COME FREE, NO DIFINITIVE MARKS ON SWEDGE. RAN 5' x 1-1/2" STEM, 2" CENT, TOOLS BOBBLED PAST RESTRICTION @ 13,770' SLM & PASS BACK THROUGH W/ SLIGHT OVER PULL, NO MARKS ON CENT. WELL S/I ON DEPARTURE, DSO NOTIFIED. 8/29/2020 - Saturday No operations to report. 9/1/2020 - Tuesday 8/30/2020 - Sunday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500. RAN 5 'x 1-1/2" STEM, 2" BROACH, TOOLS BOBBLE PAST RESTRICTION @ 13,770' SLM & PASS BACK THROUGH W/ SLIGHT OVER PULL. RAN 5 'x 1-1/2" STEM, 2.125" BROACH 2 TIMES S/D @ 13,770' SLM, WORK TOOLS FOR TOTAL OF 2.5hrs, VERY STICKY, ABLE TO COME FREE W/ 1 - 2 SPANG LICKS, FIRST RUN BROACH HAD METAL MARKS ON 2.05" SECTION & 2ND RUN HAD METAL MARKS UP TO THE 2.1" SECTION. WELL S/I ON DEPARTURE, DSO NOTIFIED. 8/31/2020 - Monday 8/28/2020 - Friday No operations to report. 8/26/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 8/27/2020 - Thursday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/3500H. RAN KJ, 3'x1-1/2" STEM, 2-7/8" BLB, 2.105" GAUGE RING, S/D @ 13,772' SLM, UNABLE TO WORK PAST, TOOK 3 1,500lb OJ LICKS TO COME FREE. RAN KJ, 3' x 1-1/2" STEM, 2" CENT, SAMPLE BAILER, TOOLS BOBBLE PAST TIGHT SPOT @ 13,772' SLM & PASSED BACK THROUGH W/ SLIGHT OVER PULL, TAGGED ESP DISCHARGE HEAD @ 14,957' SLM (14,981' MD). WELL S/I ON DEPARTURE, DSO NOTIFIED. Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 Slick Line 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 No operations to report. No operations to report. 9/5/2020 - Saturday WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. MAKE ONE RUN WITH 2.10" SWEDGE TO 13,756' SLM, UNABLE TO PASS AFTER WORKING TOOLS FOR 1 HOUR. (2 marks similar to LIB impression, swedge comes free with 1 or 2 jar licks). 9/8/2020 - Tuesday 9/6/2020 - Sunday No operations to report. 9/7/2020 - Monday 9/4/2020 - Friday No operations to report. 9/2/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. MAKE ATTEMPTS TO PASS THROUGH TIGHT SPOT AT 13,770' SLM WITH A 2.11" BROACH AND A 2.15" SWEDGE (unsuccessful). (marks seen at ~2.09" OD on braoch), (see 2 marks ~180 degrees from each other). RUN 2.21" LIB TO TIGHT SPOT AT 13,770' SLM (2 marks similar as the marks on the swedge). L/D FOR THE NIGHT, NOTIFY PAD-OP. 9/3/2020 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 CTU 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/3,500H. RAN 2.1" CENT, 10'x1-1/2" STEM, 2.19" CENT, 1.875" X- MAGNET, S/D IN XN @ 14,933' SLM (14,929' MD), UNABLE TO WORK PAST, RECOVERED 1/8lb OF COIL SHAVINGS. RAN 2.1" CENT, 10'x1-1/2" STEM, 2.19" CENT, SAMPLE BAILER, S/D IN XN @ 14,933' SLM (14,929' MD), UNABLE TO WORK PAST, METAL MARKS ON 2.19" CENT, BAILER EMPTY. RAN 2.1" CENT, 10'x1-1/2" STEM, 2.15" SWEDGE, 1.875" X-MAGNET, TOOLS BOBBLE PAST XN, TAGGED ESP @ 14,984' SLM (14,980' MD), RECOVERED 1/4 CUP OF COIL SHAVINGS ON MAGNET. SET SPECIAL CLEARANCE TS SLIP STOP (oal: 24") @ 14,977' SLM (14,973' MD). SET SPECIAL CLEARANCE 2-7/8" D&D PACK OFF (oal: 24") @ 14,977' SLM (14,973' MD). SET 10' PATCH SECTION (oal: 127") @ 14,975' SLM (14,971' MD). SET SPECIAL CLEARANCE 2-7/8" D&D PACK OFF W/ 10' PATCH SECTION (oal: 144") @ 14,962' SLM (14,958' MD). SET SPECIAL CLEARANCE TS SLIP STOP (oal: 17") @ 14,949' SLM (14,945' MD). JOB COMPLETE, WELL LEFT S/I. Travel to location with CTU #9. PU and perform BOPE test while waiting on conductor crew to finish on MPL-63. Perform weekly BOPE test 4-1/16" B/S, B/S, 1.75" Slip ram, 1.75" Pipe Ram 300 psi low/ 4,000 psi high. Completed BOPE test. All pass. Begin equipment rig down. 9/19/2020 - Saturday CTU#9 1.75" Coil: Rih w/CTC (1.75" x 0.32'), DBPV (1.81" x 1.50'), G-Force Jar (1.69" x 5.58'), TJ Disconnect (1.69" x 1.33'), DCV (1.81" x 0.92'), X-Treme Motor (1.69" x 7.64'), X-Over (2.0" x 0.34), String Reamer (2.30" x 0.66'), Tapered Mill (2.25" x 0.96') TL= 19.25'. Rih while displacing coil to 1% SL KCL w/ safelube. Dry tag at 13,776' ctmd. Few stalls initiating milling. Time mill at 13,773.4' ctmd. At 13,774.8' ctmd through restiction. Rih to 14,881.9'. Start pumping gel sweeps. Chase up to restriction. Multiple back reaming passes through without issue. Dry drifted clean. Open circ sub and start chasing gel pills to surface. Freeze Protect well with 15 bbls diesel. 9/22/2020 - Tuesday 9/20/2020 - Sunday CTU#9 1.75" Coil: RU CTU. Make up CTC (1.75" x 0.32'), DBPV (1.81" x 1.50'), G-Force Jar (1.69" x 5.58'), TJ Disconnect (1.69" x 1.33'), DCV (1.81" x 0.92'), Tempress Screen sub (1.69" x 1.52'), Tempress HydroPull (1.69" x 1.52'), X-Treme Motor (1.69" x 7.64'), X-Over (2.0" x 0.34), String Reamer (2.30" x 0.66'), Parabolic Mill (2.30" x 0.52') TL= 21.85'. Rih while displacing coil to 1% SL w/ safelube. Rih and dry tag at 13,763'. Come online and attempt multiple times to initiate milling at 13,758.5' Motor stalling immediately. Approach at different speeds and different rates. Stall motor every time. Discuss scenarios with OE. Pumped 10 bbls of gel. Pooh to inspect mill. Freeze Protect Coil / Well with diesel. 9/21/2020 - Monday 9/18/2020 - Friday No operations to report. 9/16/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 9/17/2020 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 CTU 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 9/25/2020 - Friday No operations to report. 9/23/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 9/24/2020 - Thursday No operations to report. No operations to report. AOGCC witnessed (Brian Bixby) SVS test - Passed. 9/26/2020 - Saturday No operations to report. 9/29/2020 - Tuesday 9/27/2020 - Sunday No operations to report. 9/28/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 LRS 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 10/16/2020 - Friday No operations to report. 10/14/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Freeze Protect (Leaking packer) (Pressure test surface lines 250/2,500psi) Pump 3 bbls 60/40 down Test Lateral. Bleed to zero. Pump 3 bbls 60/40 down Prod Lateral and 15 bbls Dsl down Tbg. Bleed Prod Latural to zero. 10/15/2020 - Thursday No operations to report. No operations to report. No operations to report. 10/17/2020 - Saturday No operations to report. 10/20/2020 - Tuesday 10/18/2020 - Sunday No operations to report. 10/19/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 LRS / Slickline 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 11/13/2020 - Friday No operations to report. 11/11/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 11/12/2020 - Thursday No operations to report. WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. RAN 2.2" CENT, 3' x 1-7/8" STEM, 2.28" GAUGE RING & S/D @ 2,316' SLM, ABLE TO BEAT THROUGH AFTER 5min, HANG UP COMING BACK THROUGH TIGHT SPOT, MADE MULTIPLE PASSES W/ SAME RESULTS. RAN 2.2" CENT, 3' x 1-7/8" STEM, 2.35" SWEDGE, S/D IN ST# 3 @ 145' SLM (167' MD), UNABLE TO WORK PAST. RAN 2.2" CENT, 3' x 1-7/8" STEM, 2.23" SWEDGE, PASS RIGHT THROUGH TIGHT SPOT @ 2,316' SLM. RAN 2- 7/8" D&D HOLE FINDER (oal: 43), UNABLE TO GET TUBING TO PRESSURE UP @ 14,898' SLM (14,894' MD) & 14,848' SLM (14,844' MD), PUH 100' ABOVE TIGHT SPOT @ 13,770' MD TO 13,666' SLM (13,662' MD), PRESSURED UP TUBING TO 1,500psi, TUBING HELD SOLID, REFER TO JOB LOG FOR RUN DETAILS. WELL S/I ON DEPARTURE, DSO NOTIFIED. No operations to report. 11/14/2020 - Saturday No operations to report. 11/17/2020 - Tuesday 11/15/2020 - Sunday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. RAN 2-7/8" CAT STANDING VALVE & S/D @ 2,312' SLM, UNABLE TO WORK PAST, TOOK 300 - 400lb OVER PULLS TO COME FREE, NO MARKS ON VALVE. RAN VARIOUS TOOL CONFIGUREATIONS ATTEMPTING TO FISH POSSIBLE DEBREES FROM 2,316' SLM DOWN TO 2,450' SLM W/ OUT SUCCESS, LAST 2 ATTEPTS S/D & HANG UP IN SAME SPOT @ 2,318' SLM, REFER TO JOB LOG FOR RUN DETAILS. RAN RAN 2-7/8" CAT STANDING VALVE & S/D @ 2,318' SLM, UNABLE TO WORK PAST, TOOK 6 600lb OJ LICKS TO COME FREE, NO MARKS ON VALVE. MADE 2 ATEMPS RUNNING 2.31" XO, 3 'x 1-1/2" STEM, 2.36" CENT, 2.35" LIB / 2.33" LIB, UNABLE TO MAKE IT PAST ST# 3 @ 145' SLM (167' MD). RAN 5' x 1-1/2" STEM, 2.33" LIB, ABLE TO SKIP PAST ST# 3, S/D @ 2,316' SLM, HAVE SMALL IMPRESSION OF POSSIBLE DEBREES ON EDGE ON LIB. RAN 3'x1-1/2" STEM, 2.1" CENT, 2" LIB & TAGGED PATCH SLIPSTOP @ 14,949' SLM (14,945' MD), HAVE IMPRESS ON OF G FISH NECK. WELL S/I ON DEPARTURE, DSO NOTIFIED. 11/16/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 LRS / Slickline 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 AOGCC SVS test - Failed (Bob Noble) Pilot passed and SSV failed to hold DP. Serviced and scheduled for re-test on 11/25/20. No operations to report. 11/21/2020 - Saturday No operations to report. 11/24/2020 - Tuesday 11/22/2020 - Sunday No operations to report. 11/23/2020 - Monday 11/20/2020 - Friday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. SET 20' PATCH SECTION (oal: 259") @ 13,824' SLM (13,820' MD). SET 2-7/8" D&D PACK OFF, 20' PATCH SECTION (oal: 276") @ 13,803' SLM (13,799' MD). SET 2-7/8" SLIP STOP (oal: 18") @ 13,780' SLM (13,776' MD). WELL S/I ON DEPARTURE, DSO NOTIFIED. 11/18/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. RAN 2-7/8" D&D HOLE FINDER (oal: 43) & S/D @ 6,368' SLM, TOOK 400lb OVERPULL TO COME FREE, UNABLE TO GO BACK DOWN HOLE, HUNG UP @ 4,117' SLM, BEAT UP FOR 10min, HUNG UP MULTIPLE TIMES FROM 120' SLM TO SURFACE. RAN 2-7/8" D&D HOLE FINDER (oal: 43) DOWN TO 14,013' SLM (14,009' MD) & ATTEMPTED TO PT W/ LRS, LEAK RATE IS 1/2bbl @ 820psi, LEFT D&D @ 13,903' SLM (13,899' MD), REFER TO JOB LOG FOR RUN DETAILS.RAN 3'x1-1/2" STEM, 2.1" CENT, SAMPLE BAILER W/ 12" FRAYED ROPE DOWN TO 13,850' SLM (13,846' MD), FOUND 3 HOLES W/ LRS ASSIST @ 13,820' SLM (13,816' MD), 13,809' SLM (13,805' MD) & 13,791' SLM (13,787' MD), REFER TO JOB LOG FOR RUN DETAILS. WELL S/I ON DEPARTURE, DSO NOTIFIED. 11/19/2020 - Thursday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. PULLED D&D HOLE FINDER FROM 13,903' SLM (13,899' MD), ELEMENTS ARE INTACT. RAN KJ, 2.1" CENT, 2-7/8" BLB, 1.75" X-MAGNET & BRUSHED TUBING FROM SURFACE DOWN TO 14,900' SLM, RECOVERED 3 PIECES OF A ROLL PIN & 1 SMALL SET SCREW ON MAGNET. SET 2-7/8" SLIP STOP (oal: 25") @ 13,827' SLM (13,823' MD), SLIP STOP HAS 1.75" FN USE 2.5" R TOOL TO PULL. SET 2-7/8" D&D PACK OFF (oal: 25") @ 13,826' SLM (13,822' MD). WELL S/I ON DEPARTURE, DSO NOTIFIED. Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 LRS / Slickline 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 11/27/2020 - Friday No operations to report. 11/25/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary AOGCC SVS test - Passed post service SSV (waived - B. Bixby) 11/26/2020 - Thursday No operations to report. No operations to report. No operations to report. 11/28/2020 - Saturday No operations to report. 12/1/2020 - Tuesday 11/29/2020 - Sunday No operations to report. 11/30/2020 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 LRS 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 No operations to report. No operations to report. 12/12/2020 - Saturday No operations to report. 12/15/2020 - Tuesday 12/13/2020 - Sunday No operations to report. 12/14/2020 - Monday 12/11/2020 - Friday No operations to report. 12/9/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 12/10/2020 - Thursday Freeze Protect (ESP Problems) (Pressure test surface lines 250/2,500psi) Pump 15 bbls Dsl down Tbg. Pump 3 bbls 60/40 down Prod Lateral and 3 bbls 60/40 down test lateral. Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 Slickline 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 1/15/2021 - Friday No operations to report. 1/13/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/14/2021 - Thursday No operations to report. No operations to report. WELL S/I ON ARRIVAL, NOTIFY PAD-OP (PULL PATCHES / PRWO). PULLED 2-7/8" SLIP STOP FROM 13,778' SLM (13,772' MD), RECOVERED SMALL PIECE OF ROLL PIN & 1/4" SET SCREW IN SLIP STOP, HUNG UP COMING OOH @ 10,218' SLM & 6,285' SLM. PULLED 2-7/8" D&D PACK OFF W/ 20" STINGER FROM 13,780' SLM (13,776' MD), ELEMENT GONE, MISSING 1 O-RING. PULLED 2-7/8" 20" PATCH SECTION FROM 13,801' SLM (13,797' MD), ALL O-RINGS RECOVERED & 1/4 OF THE UPPER PACKOFF ELEMENT. WELL S/I ON DEPARTURE, DSO NOTIFIED 1/16/2021 - Saturday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H (PULL PATCHES / PRWO). RAN 10'x2" PUMP BAILER W/ MULE SHOE FLAPPER DOWN TO 13,824' SLM (13,820' MD), RECOVERED 2-1/2" PIECES OF PACK OFF ELEMENT. RAN 2-7/8" GR (steel), S/D @ 13,824' SLM (13,820' MD), ATTEMPTED TO LATCH SLIP STOP FOR 45min, UNABLE TO LATCH, GR NOT SHEARED. RAN 10'x2.25" PUMP BAILER W/ MULE SHOE FLAPPER DOWN TO 13,824' SLM (13,820' MD), RECOVERED 3/4s OF 1 ELEMENT & 2 SMALL 1/2" PIECES IN BAILER. RAN 2-7/8" GR, S/D @ 13,824' SLM (13,820' MD), UNABLE TO LATCH AFTER 20min, GR NOT SHEARED. WELL S/I ON DEPARTURE, DSO NOTIFIED. 1/19/2021 - Tuesday 1/17/2021 - Sunday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H (PULL PATCHES / PRWO). PULLED 2-7/8" D&D PACK OFF FROM 13,822' SLM (13,818' MD), ELEMENT GONE. RAN 2-7/8" GR (steel), S/D @ 13,824' SLM (13,820' MD), UNABLE TO LATCH AFTER 20min, GR NOT SHEARED. RAN 10'x2" PUMP BAILER W/ MULE SHOE FLAPPER, S/D @ 13,824' SLM (13,820' MD), WORK BAILER FOR 15min, RECOVERED HALF OF 1 PACK OFF ELEMENT IN BAILER. WELL S/I ON DEPARTURE, DSO NOTIFIED. 1/18/2021 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 Slickline 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 1/29/2021 - Friday No operations to report. 1/27/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/28/2020 - Thursday No operations to report. WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2,500H. LRS PRESSURE TBG TO 4,000psi FOR 10min (good, see LRS log). PULL P-PRONG FROM PX-PLUG BODY IN X-NIP AT 3,865' SLM. PULL 2-7/8 PX-PLUG BODY FROM X-NIP AT 3,871' SLM/3,885' MD (recovered all packing). PULL 2-7/8 D&D SLIP STOP FROM 13,824' SLM. No operations to report. 1/30/2021 - Saturday WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. RUN 1.75" HYDROSTATIC BAILER TO 13824' SLM TO CLEAR ELEMENT PIECES (bailer empty). MAKE 2 ATTEMPTS TO PULL D&D SLIP STOP AT 13,824' SLM (unsuccessful, sheared off with 2.5" JUS). SET XP-PLUG (4" x 3/16" ports, OAL=23") IN X-NIP AT 3,871' SLM/3,885' MD. SET P-PRONG IN PLUG BODY IN X-NIP @ 3,865' SLM (test plug to 1,500psi, good). L/D FOR THE NIGHT, NOTIFY PAD-OP. 2/2/2021 - Tuesday 1/31/2021 - Sunday No operations to report. 2/1/2021 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 Slickline 50-029-22621-00-00 195-180 3/12/2020 2/3/2021 No operations to report. No operations to report. 2/6/2021 - Saturday No operations to report. 2/9/2021 - Tuesday 2/7/2021 - Sunday No operations to report. 2/8/2021 - Monday 2/5/2021 - Friday No operations to report. 2/3/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. PULL D&D SLIP STOP FROM 14,945' SLM PULL D&D PACKOFF 10' STINGER FROM 14,946' SLM (missing element) ATTEMPT TO FISH (unsuccessful). PULL D&D STINGER FROM 14,959' SLM. PULL D&D PACKOFF FROM 14,970' SLM. PULL D&D SLIP STOP FROM 14,972' SLM. RDMO, CLOSE PERMIT W/PAD-OP. 2/4/2021 - Thursday No operations to report. 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Change-out w/ Packer 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 15,655'N/A Casing Collapse Conductor N/A Surface 3,090psi Production 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 Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name:Ian Toomey Operations Manager Contact Email:itoomey@hilcorp.com Contact Phone: 777-8520 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng MILNE POINT / KUPARUK RIVER OIL COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0355017 195-180 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22621-00-00 Hilcorp Alaska LLC Length Size 7,628' 15,551' 7,547' 2,847 N/A MILNE PT UNIT L-25 112'112' 6.5#/ L-80 / EUE8rd TVD Burst 15,049' MD N/A 5,750psi 7,240psi 4,711' 7,614' 9,019' 15,636' 80'20" 9-5/8" 7" 8,988' 15,608' Authorized Signature: 3/18/2021 2-7/8" Perforation Depth MD (ft): See Schematic See Schematic C.O. 432D Viking Hydraulic Set ESP Packer and N/A 3,835'MD/3,026'TVD and N/A Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:43 am, Jan 29, 2021 321-060 Chad A Helgeson 2021.01.28 18:50:37 -06'00' SFD 1/29/2021 2,847 BOPE Test to 3500 psi. 29JAN2021 10-404 DSR-2/1/21Comm. 2/1/21 dts 2/1/2021 JLC 2/1/2021 RBDMS HEW 2/2/2021 ESP Changeout Well: MPU L-25 Date: 1/27/21 Well Name: MPU L-25 API Number: 50-029-22621-00-00 Current Status: SI Oil Well [tubing holes] Pad: L-Pad Estimated Start Date: February 13th, 2021 Rig: Doyon 14 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 195-180 First Call Engineer: Ian Toomey (907) 777-8434 (O) (907) 903-3987 (M) Second Call Engineer: David Gorm (907) 777-8333 (O) (505) 215-2819 (M) AFE Number: TBD Job Type: ESP Swap Current BHP (1/21/21): 3,539 psi @ 7,159’ TVD Downhole Gauge | 9.5 ppg Maximum Expected BHP: 3,562 psi @ 7,159’ TVD 30 day PBU Extrapolation | 9.6 ppg; KWF = 9.8 ppg MPSP: 2,847 psi Gas Column Gradient = 0.1 psi/ft Max Inclination 74° @ 4,876’ MD Max Dogleg: 4.5°/100ft @ 2,037’ MD Tree: Cameron 2-9/16” 5M Wellhead: FMC Gen 5, 11” x 11” 5M Tubing Hanger Lift threads: 2-7/8” EUE 8rd top & bottom BPV Profile: 2-1/2” CIW Type H Brief Well Summary: Well L-25 was drilled by Nabors 22E in December 1995 and completed by Polar #1 in May 1996 in the Kuparuk B and C sands. There have been 7 previous ESP swaps on this well with an average run life of 994.5 days (2.73 years). The current ESP failed on 2/8/19 due to a downhole short after a run life of about 5 years (8 year run life on the previous ESP installed). The ESP was replaced in January 2020 but failed after 5 hours of run time. A RWO was done in July 2020 and found the packer penetrator had failed. The packer was replaced the ESP was run back in the well (ESP was not pulled to surface). Post RWO it was discovered there were holes in the tubing and after multiple unsuccessful attempts to patch the holes a RWO is necessary to replace the tubing. Notes Regarding the Well & Design x 7” Casing MIT to 2,650 psi passed on 1/17/2020 down to 14,955’ MD. x Offset Injector Support o F-49: Online – 1900 BWPD at 845 psi. o F-89: SI on 6/28/19. Objective: x Pull 2-7/8” ESP completion x Install ESP packer per CO 390A w/ 2-7/8” ESP completion with packer and dual vent valves. Pre-Rig Procedure: 1. RD well house and flowlines. Clear and level area around the well. 2. Set 2-1/2” BPV. ESP Changeout Well: MPU L-25 Date: 1/27/21 RWO Procedure: 3. MIRU Doyon 14, ancillary equipment and lines to returns tank. 4. Pull the BPV. Bleed gas to 0 psi on the tubing and IA (if needed). a. Verify that the vent valves are open. 5. Circulate a minimum 550 bbls of 9.8 ppg NaCl down the tubing taking returns up the IA to the kill tank until clean 9.8 ppg brine is seen at surface. a. Tubing holes at 13,787’, 13,805’, 13,816’ & 14,959’-14,962’ 6. Monitor to confirm the well is dead for 30 minutes. If not, contact Operations Engineer and record SITP/SICP. 7. Set 2-1/2” HP BPV. 8. ND Tree. Inspect the lift threads on the tubing hanger. Install the plug off tool into the BPV. 9. NU 13-5/8” BOP stack with 2-7/8” x 5” VBR’s in the upper and lower ram cavities. 10. Test BOPE to 250/3,500 psi and annular to 250/3,500 psi. a. Notify the AOGCC 24 hours in advance of BOP test. b. Perform test per ASR #1 BOPE test procedure dated 11/3/15. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR’s and annular with 2-7/8” and 3-1/2” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (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 if test witness was waived. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) 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. 11. RU to pull 2-7/8” ESP completion. 12. Pull plug off tool, check for pressure under the BPV, if needed kill the well with KWF and pull the BPV. 13. MU the landing joint to the tubing hanger, BOLDS, unseat the tubing hanger and PU to release the packer. Wait 30 minutes for the packer element to relax. a. String PU = 81K and SO = 18K when landed by ASR #1 (block weight = 0K) in 9.9 ppg brine. b. Viking ESP Packer is pinned for 49K straight pull to release. 14. Pull the hanger to the rig floor. Lay down the landing joint and tubing hanger. RU to pull ESP over sheaves to spooling units. a. Inspect the tubing hanger and note any corrosion or damage. ESP Changeout Well: MPU L-25 Date: 1/27/21 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 and sundry. 15. POOH laying down the 2-7/8” tubing spooling ESP cable and removing all jewelry as it presents itself. Lay down ESP components. a. Note any corrosion, sand, scale, damage or over torqued connections on the tubing with associated depths and ESP components on the morning report. Equipment Disposition Tubing hanger Visually inspect on site then reuse, restock or junk Tubing & Pup joints Visually inspect on site then reuse Gaslift Mandrels/Nipple Visually inspect on site then reuse ESP equipment/Power Cable Centrilift to take possession for inspection and teardown Capillary Tubing Junk Protectorlizer (3) Visually inspect on site then reuse, restock Cannon clamps (240) Visually inspect on site then reuse, restock Pump Clamps (8) Visually inspect on site then reuse, restock Half Clamp (2) Visually inspect on site then reuse, restock 16. RD ESP pulling equipment. 17. RU to run ESP completion. 18. PU and MU new Baker ESP assembly. Set base of ESP assembly at ±15,075’ MD. Check electrical integrity test every 1,000’. Install clamps on the first 15 joints then every other joint to surface. a. Motor centralizer b. Motor gauge unit c. ESP motor d. Lower tandem seal e. Upper tandem seal f. Gas separator g. Pump #1 h. Pump #2 i. Ported discharge head j. Bolt on discharge head with pup joint, 2-7/8”, 6.5#, L-80, EUE 8rd box up k. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing l. Nipple, HES 2.313” XN (2.205” no-go) with 10’ handling pups above and below m. XXX joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing n. Nipple, HES 2.313” X with 10’ handling pups above and below, RHC plug body installed o. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing p. Packer, Viking ESP retrievable with dual vent valves (setting depth = ±3,800’ MD) 19. PU and MU the Viking packer. Verify that there are 4 setting shear pins and 18 shear to release pins. 20. Terminate the ESP cable and MU the ESP penetrator to the ESP cable. Ensure the 3/8” NPT control line feed thru port is dummied off. ESP Changeout Well: MPU L-25 Date: 1/27/21 21. MU the control line to the dual vent valves. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in WellEZ). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while RIH. 22. Continue to RIH with ESP completion. Check electrical integrity test every 1,000’. q. 1 joint, 2-7/8”, 6.5#, L-80, EUE 8rd tubing r. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below (setting depth ±3,750’ MD) s. XXX joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing t. GLM, 2-7/8” x 1”, DV installed with 10’ handling pups above and below (setting depth ±175’ MD) u. XX joints, 2-7/8”, 6.5#, L-80, EUE 8rd tubing 23. PU and MU the 2-7/8” tubing hanger. Make final splice of the ESP cable to the penetrator, MU the control line to the tubing hanger and dummy off any additional control line ports if present. 24. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in WellEZ). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while landing the hanger. 25. Land tubing hanger with extreme caution to avoid damaging the ESP cable, penetrator or control line. RILDS. Record PU and SO weights on tally and WellEZ. 26. Drop the ball & rod and allow time for it to gravitate to the ball seat. 27. Pressure up on the tubing to 4,000 psi and hold for 15 minutes to set the packer. Bleed the tubing pressure to 0 psi. Pressure back up to 4,000 psi and hold for 5 minutes then bleed to 0 psi. 28. Bleed the control line pressure to 0 psi to close the vent valves. 29. Slowly pressure up at 50 psi/min on the IA to 1,500 psi and hold for 30 minutes on chart recorder. a. Test of ESP packer @ ±3,800’ MD. 30. Slowly bleed the IA pressure at 25 psi/min to 0 psi. 31. Set 2-1/2” HP BPV. 32. ND the BOP stack. Install the plug off tool. 33. NU the tubing head adapter and 2-9/16”, 5M tree. 34. PT tubing hanger void to 500/5000 psi. PT the tree to 250/5000 psi. 35. Pull plug off tool and BPV. 36. Replace gauge(s) if removed. Secure the tree and cellar. 37. RDMO Post-Rig Procedure: 38. Turn well over to production via handover form. 39. RU well house and flowlines. 40. RU HES slickline. 41. Pull the ball and rod. 42. Pull DV from GLM #2 and install OV. 43. Pull RHC plug body. 44. RD HES slickline. Note: Freeze protect is up to the discretion of the Wells Supervisor/Foreman depending on timing for the well to be POP. True crystallization temperature (TCT) of 9.8 ppg NaCl = -6°F ESP Changeout Well: MPU L-25 Date: 1/27/21 Attachments: 1. Current schematic 2. Proposed schematic 3. BOP Schematic 4. Blank RWO MOC Form _____________________________________________________________________________________ Revised By TDF: 11/20/2020 SCHEMATIC Milne Point Unit Well: MPU L-25 Last Completed: 7/13/2020 PTD: 195-180 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 91.1 / H-40 / N/A N/A Surface 112' 9-5/8"Surface 40 / L-80 / BTC 8.835 Surface 9,019’ 7"Production 26 / L-80 / BTC/BTC-MOD 6.276 Surface 15,636’ TUBING DETAIL 2-7/8"Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 15,062’ JEWELRY DETAIL No Depth Item GLM Detail: KBMG GLM 2-7/8” x 1” BK Latch 1 168’GLM #3:KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 2 3,779’GLM #2:KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 3 3,835’Packer: Viking Hyd Set ESP Packer W/Dual vent valve (49k Pull Release) 4 3,885’2-7/8” X-Nipple (2.313 ID) 5 14,858’GLM #1:KBMG 2 7/8 X 1'' Side pocket, w/ Dummy & BK Latch 6 14,916’2-7/8” XN-Nipple (Min ID = 2.205 No-go) 7 14,967’Discharge Head: 400 FPDIS 8 14,968’Discharge Head: HEAD S/A B/O PRESS PORT 400P 9 14,969’Pump 2: PMSXD 134 FLEX ER M FER 10 14,992’Pump 1: PMSXD 134 FLEX ER M FER 11 15,016’Gas Separator: 513 GSHV FER 12 15,019’Upper Tandem Seal: GSB3DB H6 SB/AB PFSA 13 15,026’Lower Tandem Seal: GSB3DB H6 SB/AB PFSA 14 15,033’Motor: 562XP – 150HP/ 2420V / 38A 15 15,043’Gauge & Centralizer: Zenith E7 175C – Bottom @ 15,049’ PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status Kuparuk C1, B6 15,135’15,173’7,228’7,257’38 1/20/2020 Open Kuparuk B6 15,174’15,180’7,258’7,262’6 4/20/1996 Open Kuparuk A3/A2/A1 15,230’15,250’7,300’7,315’20 6/23/2005 Open 15,250’15,282’7,315’7,340’32 N/A Open 15,278’15,308’7,337’7,360’30 6/23/2005 Open Kuparuk A1B 15,309’15,336’7,360’7,381’27 1/19/2020 Open Ref Log: 4/10/1996 – GR / CCL : Mid Perf TVD = 7,308’ : Mid Perf MD = 15,241’ OPEN HOLE / CEMENT DETAIL 20"250 sx of Arcticset I (Approx) in 24” Hole 9-5/8"1,750 sx PF ‘E’, 250 sx Class ‘G’, 150 sx PF ‘E’ in 12-1/4” Hole 7”240 sx Class “G” in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 69 to 74 deg. f/ 3,600’ to 13,150’ Max Hole Angle through perforations = 40 deg. TREE & WELLHEAD Tree 2-9/16” x 11” – 5M FMC Wellhead 11” 5M FMC Gen 5, w/ 11” Gen 5 ESP w/ 2-7/8” FMC Tbg. Hngr., EUE Lift Threads, 2-7/8” CIW “H” BPV profile GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E - 12/6/1995 Perf, Frac & Run ESP Completion by Polar #1 – 5/25/1996 ESP Change-out by Nabors 4ES – 12/9/1998, 10/2/1999 & 3/23/2002 Pull ESP Service and Re-run by Nabors 4ES – 11/29/2003 Perforate & ESP Change-out by Nabors 4ES – 6/25/2005 ESP Change-out by Doyon 16 – 12/18/2013 ESP Change-out and Perforate by ASR 1 – 1/23/2020 ESP Change-out by ASR 1 – 7/13/2020 STIMULATION DETAIL Frac’d w/ 110,500# of 16/20 Carbolite behind pipe _____________________________________________________________________________________ Revised By IAT: 1/25/2021 PROPOSED Milne Point Unit Well: MPU L-25 Last Completed: 12/18/2013 PTD: 195-180 TD = 15,655’ (MD) / TD = 7,628’(TVD) 20”00 RA Tag @ 15,020’ Orig. KB Elev.: 46’66 / Orig. GL Elev.: 16.5’ Nabors 22E / RT to 7”Hanger= 28.5’ 7” 6 9 10 & 11 129 13 14 9-5/8”88 1 5 Min ID = 2.205”@ ±15,007’ PBTD = 15,551’(MD) / PBTD = 7,547’(TVD) 8 KUP B Sands 7 KUP A Sands 2 3 4 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 91.1 / H-40 / N/A N/A Surface 112' 9-5/8"Surface 40 / L-80 / Btc.8.835 Surface 9,019’ 7"Production 26 / L-80 /BTC & MBTC 6.276 Surface 15,636’ TUBING DETAIL 2-7/8"Tubing 6.5 / L-80 / EUE 8rd 2.347 Surface ±15,077’ JEWELRY DETAIL No Depth Item 1 ±200’GLM #3: 2 ±3,775’GLM #2: 3 ±3,800’Packer: 4 ±3,820’2-7/8” X-Nipple (2.313 ID) 5 ±14,960’GLM #1: 6 ±15,007’2-7/8” XN-Nipple (2.205 No-go ID) 7 ±15,008’Discharge Head 8 ±15,025’Pump: 9 ±15,032’ Gas Separator: 10 ±15,037’ Upper Tandem Seal: 11 ±15,044’Lower Tandem Seal: 12 ±15,051’Motor 13 ±15,073’Pumpmate 14 ±15,075’ Centralizer: Bottom @ ±15,077’ PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C1, B6 ±15,135’ ±15,173’ ±7,228’±7,257’38 1/20/2020 Open Kuparuk B 15,174’15,180’ 7,258’ 7,262’6 4/20/1996 Open Kuparuk A 15,230’15,250’ 7,300’ 7,315’20 6/23/2005 Open 15,250’15,282’ 7,315’ 7,340’32 N/A Open 15,278’15,308’ 7,337’ 7,360’30 6/23/2005 Open Kuparuk A1B ±15,309’±15,336’±7,360’ ±7,381’27 1/19/2020 Open Ref Log: 4/10/1996 –GR / CCL : Mid Perf TVD = 7,308’ : Mid Perf MD = 15,241’ OPEN HOLE / CEMENT DETAIL 20"250 sx of Arcticset I (Approx) in 24” Hole 9-5/8"1,750 sx PF ‘E’,250 sx Class ‘G’, 150 sx PF ‘E’in 12-1/4” Hole 7”240 sx Class “G”in 8-1/2” Hole WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 69 to 74 deg. f/ 3,600’ to 13,150’ Max Hole Angle through perforations = 40 deg. TREE & WELLHEAD Tree 2-9/16” x 11” –5M FMC Wellhead 11”5M FMC Gen 4, w/11” Gen 5 ESP w/ 2-7/8” FMC Tbg. Hngr., EUE Lift Threads, 2-7/8” CIW “H” BPV profile GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E -12/6/1995 Perf, Frac & Run ESP Completion by Polar #1 –5/25/1996 ESP Changeout by Nabors 4ES –12/9/1998, 10/2/1999 & 3/23/2002 Pull ESP Service and Re-run by Nabors 4ES –11/29/2003 Perforate & ESP Changeout by Nabors 4ES –6/25/2005 ESP Changeout by Doyon 16 – 12/18/2013 ESP Changeout & Perforate by ARS 1 – 1/23/2020 ESP Changeout by ARS 1 –7/13/2020 STIMULATION DETAIL Frac’d w/ 110,500# of 16/20 Carbolite behind pipe ] Milne Point Doyon 14 13-5/8” BOP Stack Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: January 25, 2021 Subject: Changes to Approved Sundry Procedure for Well MPU L-25 Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Operations Manager Date Prepared: Operations Engineer Date Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 11/12/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-25 (PTD 195-180) Leak Detection Log 08/23/2020 Please include current contact information if different from above. Received by the AOGCC 11/13/2020 PTD: 1951800 E-Set: 34251 Abby Bell 11/13/2020 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: P.I. Supry % Zrj 4,7,c:, BOPE Test Report for: MILNE PT UNIT L-25 Comm Contractor/Rig No.: Hilcom ASR 1 - Operator: Hilcom Alaska, LLC Type Operation: WRKOV Sundry No: Type Test: INCL 320-095 PTD#: 1951800 - DATE: 7/10/2020 ' Operator Rep: Carl Linaman Test Pressures: Rams: Annular: Valves: MASP: 250/3500' 250/2500' 250/3500 - 3073 TEST DATA Inspector Matt Herrera Rig Rep: Matt Beshea Insp Source Inspector Inspection No: bopMFH2O0711131452 Related Insp No: MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: Upper Kelly 0 WE Lower Kelly Visual Alarm Time/Pressure P/F Location Gen.: P " Trip Tank NA_ NA System Pressure 3000 P Housekeeping: P - Pit Level Indicators P _ P ; Pressure After Closure 1650 - P PTD On Location P _" Flow Indicator P P 200 PSI Attained 11 P Standing Order Posted P Meth Gas Detector P P _ _' _ Full Pressure Attained 56 P Well Sign P 112S Gas Detector P - P Blind Switch Covers: YES P ' Drl. Rig P MS Misc _NA NA Nitgn. Bottles (avg): X2395 "_ P Hazard Sec. P ' ACC Misc —0 Misc NA —NA FLOOR SAFTY VALVES: BOP STACK: Quantity Size Quantity PIF Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 1 _ P Inside BOP 1 P FSV Misc 0_ NA BOP STACK: Quantity Size WE Stripper 0 NA Annular Preventer 1- 11" P- -#1 #1 Rams 1 - 2 7/8" Fixed, P, _ #2 Rams 1 -Blinds P #3 Rams 1 '27/8x5" P #4 Rams 0 NA_ #5 Rams 0 NA_ #6 Rams 0 NA _ Choke Ln. Valves 1 3 1/8" P HCR Valves 1' 31/811 P - Kill Line Valves 2 - 3 1/8" " P Check Valve _ 0 _ NA BOP Misc 0 NA Number of Failures: 0 ✓ Test Results Remarks: Rig Inspection completed all PVT and Fire and Gas alarms tested. i CHOKE MANIFOLD: Quantity P/F No. Valves 16 _ P_ Manual Chokes 1 _ _ P ' Hydraulic Chokes 1 P CH Misc 0 NA INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity WE Inside Reel Valves _ 0 NA Test Time 6 ALASKA OIL AND GAS CONSERVATION COMMISSION RIG INSPECTION REPORT INSPECT DATE 1 7/10/2020 P Supv x!71-7/Z4j-1ZrW AOGCC INSPECTOR L Matt Herrera - . comm: RigASR1 - Coil Tubing Unit? No Rig Contractor Hilcorp Rig Representative Matt Beshea Operator I Hilcorp Alaska Contractor Representative Carl Linaman /Wade Hudgens Well IMPU L-25 Permit to Drill #1951800 Sundry # 320-095 ' Operation Workover Inspection Location MPU L -Pad BOP STACK MUD SYSTEM CLOSING UNIT Working Pressure, W/H Flange P Pit Fluid Measurement P - Working Pressure P Working Pressure, BOP Stack P Flow Rate Sensor P Operating Pressure P Annular Preventer P Mud Gas Separator P - Fluid Level/Condition P Pipe Rams P Degasser P - Pressure Gauges P Blind Rams P Separator Bypass P Sufficient Valves P Locking Devices, Rams P Gas Detectors P Regulator Bypass P - Stack Anchored FP Alarms Separate/Distinct P - Actuators (4 -way valves) P Choke Line P Choke/Kill Line Connections P - Blind Ram Handle Cover P Kill Line P Reserve Pits P Control Panel, Driller P - Targeted Turns FP Trip Tank NA Control Panel, Remote P HCR Valve(s) P Firewall P Manual Valves P RIG FLOOR 2 or More Pumps P Flange/Hub Connections P Kelly or TD Valves P - Independent Power Supply P Drilling Spool Outlets P Floor Safety Valves P N2 Backup P - Flow Nipple - P Drillers Console P Condition of Equipment P Control Lines P Flow Monitor P Flow Rate Indicator P CHOKE MANIFOLD MISCELLANEOUS Pit Level Indicators P , Valves P - PPE P Gauges P Remote Hydraulic Choke P Well Control Trained P Gas Detection Monitor P FOV Upstream of Chokes P Housekeeping P Hydraulic Control Panel P Targeted Turns P Well Control Plan P Kill Sheet Current P Bypass Line P FAILURES: 2 CORRECT BY: JUH StacK obtained from Doyon 1 Fox Rig. Certifications onsite for Rams and Annular. Confirmed compatable with ASR1 Accumulator Unit. Stack was pressure tested to 3500 psi at Doyon Yard on 6/27/20 prior to set up on ASR1 sub (test chart attached). COMMENTS 2 action items identified to correct: BOP Stack was not anchored; targeted cushion tee on choke line was in wrong orientation. Both items were corrected same day verified by State Inspector and Co Rep. Rig clean and everything in good operating condition. New ProStar Fire and Gas screen on drillers console (monitor being installed and commissioned) will enable Driller to monitor all gas sensor % and PPM from console in the event of an incident. All PVT and Gas alarms tested. 2020-0710_Ri9_Hi wrp_ASR1_MP1J_L-25_mh rev. 5-16-16 c�'l dfilcc.�,� A-S�1 6 r 27'2 { p� 1 � J r 1 11ft .1 . iY 1�L �• 1 Y`.r '•�'�l+l'4 �..lyli�rl�. e • i y i ' Y Y • y l `:4 i AA .+ � F 6 _1 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU L-25 Permit to Drill Number: 195-180 Sundry Number: 320-095 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax 907.276.7542 www. a ogcc. a I aska. gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, p Tom' m . Price Chair DATED this day of March, 2020. RBDMS /MA0 0 41010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED FEB 2 8 202 /JTS 3 ( 3 pZo AOGCC 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 ❑ Aller Casing ❑ Other: ESP Change -out w/ Packer0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 195-180 - 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-22621-00-00 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 ❑� MILNE PT UNIT L-25 9. Properly Designation (Lease Number): 10. Field/Pool(s): ADL002550e& ADI -03550' MILNE POINT / KUPARUK RIVER OIL ' it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 15,655' 7,628' 15,551' 7,547' 3,073 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 112' 112' N/A WA Surface 81988' 9-5/8" 9,019' 4,711' 5,750psi 3,090psi Production 15,608' 7" 15,636' 7,614' 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 / EUE8rd 15,062' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Viking Hydraulic Set ESP Packer and WA 3,813'MD/3,019'TVD and N/A 12. Attachments: Proposal Summary a 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: 3/18/2020 OIL ❑� WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. c Authorized Name: Chad Helgeson Contact Name: Stan Porhola S Authorized Title: Operations Manager Contact Email: S orhola hilcor ,com Contact Phone: 777-8412 Authorized Signature: Date: 2/28/2020 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Sit i� Z - 5 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: ,F 3500 Ps �/njvP eSfi 2SQU PSv J`fr�h MAR Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS(� 0 4 2020 Spacing Exception Required? Yes ❑ No Subsequent Form Required: / L..J G N APPROVED BY 3� 3 Approved by: COMMISSIONER THE COMMISSION Date: v ORIGINAL J10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Submit Form and Adachryents in Duplicate pie 31�atiD H Hilcorp Alaska, LU ESP Changeout Well: MPU L-25 Date:2/28/20 Well Name: MPU L-25 API Number: 50-029-22621-00-00 Current Status: SI Oil Well [Failed ESP] Pad: L -Pad Estimated Start Date: March 18th, 2020 Rig: ASR #1 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 195-180 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Ian Toomey (907) 777-8434 (0) (907) 903-3987 (M) AFE Number: TBD Job Type: ESP Swap Most recent SBHP (11/04/19): Maximum Expected BHP: MPSP: Max Inclination Max Dogleg: Tree: Wellhead: Tubing Hanger Lift threads: 8PV Profile: Brief Well Summary: 3,785 psi @ 7,124' TVD 3,785 psi @ 7,124' TVD 3,073 psi 74° @ 4,876' MD 4.5'/100ft @ 2,037' MD Cameron 2-9/16" 5M FMC Gen 5, 11"x11"5M 2-7/8" EUE 8rd top & bottom 2-1/2" CIW Type H E M W =10.22 ppg; KW F =10.5 ppg E M W = 10.22 ppg Gas Column Gradient = 0.1 psi/ft Well L-25 was drilled by Nabors 22E in December 1995 and completed by Polar #1 in May 1996 in the Kuparuk B and C sands. There have been 7 previous ESP swaps on this well with an average run life of 994.5 days (2.73 years). The current ESP failed on 2/8/19 due to a downhole short after a run life of about 5 years (8 year run life on the previous ESP installed). The ESP was replaced in January 2020 but failed after 5 hours of run time. Notes Regarding the Well & Design • 7" Casing MIT to 2,650 psi passed on 1/17/2020 down to 14,955' MD. • Offset Injector Support o F-49: SI on 6/27/19. o F-89: SI on 6/28/19. Objective: • ' Pull 2-7/8" ESP completion • Install ESP packer per CO 390A w/ 2-7/8" ESP completion with packer and dual vent valves. Pre -Rig Procedure: P(�fC ' �,y 1. RU slickline. 2. Pull DV from GLM at 14,872' MD. Leave pocket open. 3. RD Slickline Unit 4. RU LRS and PT lines to 3,000 psi. 5. Bleed gas to 0 psi on the tubing and IA (if needed). 0 Hilcorp Alaska, LU ESP Changeout Well: MPU L-25 Date; 2/28/20 6. Circulate a minimum 550 bbls of 10.5 ppg NaCl/Naar down the tubing taking returns up the IA to the kill tank until clean 10.5 ppg brine is seen at surface Cls 0---6y— oFg-., , 7. Monitor to confirm the well is dead. If not, contact Operations Engineer and record SITP/SICP. Note: Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. True crystallization temperature (TCT) of 10.5 ppg NaCl/NaBr = -4.4°F. 8. RD Little Red Services. 9. RD well house and flowlines. Clear and level pad area around the well. Spot rig mats and containment. 10. RU crane. Set 2-1/2" HPC ND Tree. Inspect the lift threads on the tubing hanger. Install plug off tool into the BPV. 11. NU 11", SM BOPE with two sets 2-7/8" x 5" VBR's. RD Crane. 12. RU BOPE house. Spot the mud boat. RWO Procedure: 13. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank. 14. Test BOPE to 250/3,500 psi and annular to 250/3,500 psi. a. Notify the AOGCC 24 hours in advance of BOP test. p')pE b. Perform test per ASR #1 BOPE test procedure dated 11/3/15. �I c. Confirm test pressures per the Sundry Conditions of approval. 1"5 d. Test VBR's and annular with 2-7/8" and 3-1/2" test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test if test witness was waived. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) 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. 15. RU to pull 2-7/8" ESP completion. 16. Pull plug off tool, check for pressure under the BPV, if needed kill the well with KWF and pull the BPV. 17. MU the landing joint to the tubing hanger, BOLDS, unseat the tubing hanger and pull to the rig floor. a. String PU = 81K and SO= 15.5K when landed by ASR #1 (block weight =01K) in 10.5 ppg brine. ^iL b. Viking ESP Packer is pinned for 49k straight pull to release. 18. Lay down the landing joint and tubing hanger. RU to pull ESP over sheaves to spooling units. a. Inspect the tubing hanger and note any corrosion or damage. ESP Changeout Well: MPU L-25 ❑ikon, Alaska, LU Date: 2/28/20 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 and sundry. 19. POOH laying down the 2-7/8" tubing spooling ESP cable and removing all jewelry as it presents itself. Lay down ESP components. a. Note any corrosion, sand, scale, or damage on the tubing with associated depths and ESP components on the morning report. Equipment Disposition Tubing hanger Visually inspect on site then reuse, restock orjunk Tubing & Pup joints Visually inspect on site then reuse Gaslift Mandrels/Nipple Visually inspect on site then reuse ESP equipment/Power Cable Centrilift to take possession for inspection and teardown Capillary Tubing Junk Protectorlizer (3) Cannon clamps (240) Pump Clamps (8) Half Clamp (2) Visually inspect on site then reuse, restock Visually inspect on site then reuse, restock Visually inspect on site then reuse, restock Visually inspect on site then reuse, restock 20. RD ESP pulling equipment. 21. RU to run ESP completion. 22. PU and MU new Baker ESP assembly. Set base of ESP assembly at±15,075' MD. Check electrical ��S P integrity test every 1,000'. Install clamps on the first 15 joints then every other joint to surface. a. Motor centralizer b. Motor gauge unit, Zenith c. ESP motor, 562, 150 HP, 2420 V, 38 A d. Lower tandem seal, GSB3DB H6 e. Upper tandem seal, GSB3DB H6 f. Gas separator, 538 GSHVV g. Pump, 134 Flex ER h. Ported discharge head, Zenith i. Bolt on discharge head, 2-7/8", 6.5#, L-80, EUE 8rd box up j. 1 joint, 2-7/8", 6.5#, L-80, EUE 8rd tubing k. Nipple, HES 2.313" XN (2.205" no-go) with 10' handling pups above and below 2 joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing m. GLM, 2-7/8" x 1", DV installed with 10' handling pups above and below n. ±260 joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing o. 1 pup joint, 2-7/8", 6.5#, L-80, EUE 8rd 10' Long Pup (For Splice Placement) p. ±100 joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing q. Nipple, HES 2.313" X with 10' handling pups above and below, RHC plus body installed r. 1 joint, 2-7/8", 6.5#, L-80, EUE 8rd tubing s. Packer, Viking ESP retrievable with dual vent valves (setting depth = ±3,800' MD) H lliluorn ANkn. LI: ESP Changeout Well: MPU L-25 Date: 2/28/20 23. PU and MU the Viking packer. Verify that there are 4 setting shear pins and 18 shear to release pin. 24. Terminate the ESP cable and MU the ESP penetrator to the ESP cable. Ensure the 3/8" NPT control line feed thru port is dummied off. 25. MU the control line to the dual vent valves. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in WeIIEZ). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while RIH. 26. Continue to RIH with ESP completion. Check electrical integrity test every 1,000'. t. 1 joint, 2-7/8", 6.5#, L-80, EUE 8rd tubing u. GLM, 2-7/8" x 1", DV installed with 10' handling pups above and below (setting depth ±3,750' MD) v. ±116 joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing w. GLM, 2-7/8" x 1", DV installed with 10' handling pups above and below (setting depth ±175' MD) x. ±4 joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing 27. PU and MU the new 2-7/8" tubing hanger. Make final splice of the ESP cable to the penetrator, MU the control line to the tubing hanger and dummy off any additional control line ports if present. 28. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in WeIIEZ). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while landing the hanger. 29. Land tubing hanger with extreme caution to avoid damaging the ESP cable, penetrator or control line. RILDS. Record PU and SO weights on tally and WeIIEZ. 30. Drop the ball & rod and allow time for it to gravitate to the ball seat. 31. Pressure up on the tubing to 3,000 psi and hold for 15 minutes to set the packer. Bleed the tubing 5� pressure to 0 psi. Pressure back up to 3,000 psi and hold for 5 minutes then bleed to 0 psi. P32. Bleed the control line pressure to 0 psi to cllooW the vent valves. �T tik 33. Slowly pressure up at 50 psi/min on the IA to -1,500 psi and hold for 30 minutes on chart recorder. a. Test of ESP packer @ ±3,800' MD. 34. Slowly bleed the IA pressure at 25 psi/min to 0 psi. 35. Set 2-1/2" HP BPV. Post -Rig Procedure: 36. RD mud boat. RD BOPE house. Move to next well location. 37. RU crane. ND BOPE. Install plug off tool. 38. NU the tubing head adapter and 2-9/16", 5M tree. PT tubing hanger void to 500/5000 psi. PT the tree to 250/5000 psi. 39. Pull plug off tool and BPV. 40. RD crane. Move returns tank and rig mats to next well location. 41. Replace gauge(s) if removed. 42. Turn well over to production via handover form. RU well house and flowlines. 43. RU HES slickline. 44. Pull the ball and rod. 45. Pull DV from GLM #3 and install OV. 46. Pull RHC plug body. 47. RD HES slickline. H fli],.p Alaska, LLQ ESP Changeout Well: MPU L-25 Date: 2/28/20 Note: Freeze protect is up to the discretion of the Wells Supervisor/Foreman depending on timing for the well to be POP. True crystallization temperature (TCT) of 10.5 ppg NaCl/NaBr=-4.4°F Attachments: 1. Current schematic 2. Proposed schematic 3. BOP Schematic 4. Blank RWO MOC Form K nilcorp Alaska. LLC Ong. KB Elev.: 46 / Orig. GL Elev.: 16.5' TD= 15,655'(MD) / TD = 7,62B(TVD) PBTD=15,551'(MD) / PBTD = 7,547(TVD) SCHEMATIC Milne Point Unit Well: MPU L-25 Last Completed: 1/23/2020 PTD: 195-180 TREE & WELLHEAD Tree 2-9/16" x 11" -SM FMC Wellhead 11" SM FMC Gen 5, w/ 11" Gen 5 ESP w/ 2-7/8" FMC Tbg. Top Hngr., EUE Lift Threads, 2-7/8" CIW "H" BPV profile OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24" Hole 9-5/8" 1,750 sx PF'E', 250 sx Class'G', 150 sx PF'E' in 12-1/4" Hole 7" 240 sx Class "G" in 8-1/2" Hole WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle = 69 to 74 deg. f/ 3,600' to 13,150' Max Hole Angle through perforations = 40 deg. CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 112' 9-5/8" Surface 40/L-80/BTC 8.835 Surface 9,019' 7" Production 26/L-80/BTC/BTC-MOD 6.276 Surface 15,636' TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE 8rd 1 2.441 1 Surface 15,062' JEWELRY DETAIL No Depth I Item GLM Detail: KBMG GLM 2-7/8" X 1" BK Latch 1 167' GLM #3: Side pocket, w/ Dummy & BK Latch 2 3,750' GLM #2: Side pocket, w/ Dummy & BK Latch 3 3,813' Packer: Viking Hyd Set ESP Packer W/Dual vent valve (49k Pull Release 4 3,863' 2-7/8" X -Nipple (2.313 ID) 5 14,872' GLM #1: Side pocket, w/ Dummy & BK Latch 6 14,929' 2-7/8" XN-Nipple (Min ID = 2.205 No-go) 7 14,980.9' Discharge Head: Bolt On FPDIS 8 14,981.5' Discharge Head: Ported 9 14,982' Pump 2: 134 FLEX ER/40OPMSXD 10 15,006' Pump 1: 134 FLEX ER/ 40OPMSXD 11 15,029' Gas Separator: 513 GSHV FER 12 15,032' Upper Tandem Seal: GSB3DB H6 SB/AB PFSA-513 SEAL 13 15,039' Lower Tandem Seal: GSB3DB 1-16 SB/AB PFSA-513 SEAL 14 15,046' Motor: 562XP- 150HP/ 2420V/ 38A 15 15,057' Gauge & Centralizer: Zenith E7 175C- Bottom @ 15,062' STIMULATION DETAIL Frac'd w/ 110,500# of 16/20 Carbolite behind pipe PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk Cl, B6 15,135' 15,173' 7,228' 7,257' 38 1/20/2020 Open Kuparuk B6 15,174' 15,180' 7,258' 7,262' 6 4/20/1996 Open 15,230' 15,250' 7,300' 7,315' 20 6/23/2005 Open Kuparuk A3/A2/AS 15,250' 15,282' 7,315' 7,340' 32 N/A Open 15,278' 15,308' 7,337' 7,360' 30 6/23/2005 Open Kuparuk AlB 15,309' 15,336' 7,360' 7,381' 27 1/19/2020 Open Ref Log: 4/10/1996 - GR / CCL: Mid Perf TVD = 7,308': Mid Perf MD = 15,241' GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E - 12/6/1995 Perf, Frac & Run ESP Completion by Polar #1-5/25/1996 ESP Change -out by Nabors 4E5-12/9/1998, 10/2/1999 & 3/23/2002 Pull ESP Service and Rerun by Nabors 4ES-11/29/2003 Perforate & ESP Change -out by Nabors 4ES -6/25/2005 ESP Change -out by Doyon 16 - 12/18/2013 ESP Change -out and Perforate by ASR 1 - 1/23/2020 Revised By STP: 2/19/2020 K lliic ru Alasku, LLC Orig. KB Elev.: 46 / Orig. GL Elev.: 16.5 TO=15,655 (MD)/TD=7,6W(TVD) FETID =15,551'(MD) / PBTD= 7,547(TVD) PROPOSED Milne Point Unit Well: MPU L-25 Last Completed: 1/23/2020 PTD: 195-180 TREE & WELLHEAD Tree 2-9/16" x 11" -SM FMC Wellhead 31" SM FMC Gen 5, w/ 11" Gen 5 ESP w/ 2-7/8" FMC Tbg. Top Hngr., EUE Lift Threads, 2-7/8" CIW "H" BPV profile OPEN HOLE/ CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24" Hole 9-5/8" 1,750 sa PF 'E', 250 sx Class 'G', 150 sx PF E' in 12-1/4" Hole 7" 240 sx Class "G" in 8-1/2" Hole WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle = 69 to 74 deg. f/ 3,600' to 13,150' Max Hole Angle through perforations = 40 deg. CASING DETAIL Size Type I Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 112' 9-5/8" Surface 40/L-80/BTC 8.835 Surface 9,019' 7" Production 26/L-80/BTC/BTC-MOD 6.276 Surface 15,636' TUBING DETAIL 2-7/8" Tubing 6.5 / L-80/ EUE 8rd 1 2.441 1 Surface ±15,075' JEWELRY DETAIL No Depth Item GLM Detail: KBMG GLM 2-7/8" X 1" BK Latch 1 ±175' GLM #3: Side pocket, w/ Dummy & BK Latch 2 ±3,750' GLM #2: Side pocket, w/ Dummy & 8K Latch 3 ±3,800' Packer: Viking Hyd Set ESP Packer W/Dual vent valve (49k Pull Release) 4 ±3,850' 2-7/8" X -Nipple (2.313 ID) w/ RHC Plug Body 5 ±14,885' GLM #1: Side pocket, w/ Dummy & BK Latch 6 ±14,940' 2-7/8" XN-Nipple (Min ID = 2.205 No-go) 7 ±14,993' Discharge Head: Bolt On FPDIS 8 ±14,994' Discharge Head: Ported 9 ±14,995' Pump 2:134 FLEX ER/40OPMSXD 10 ±15,019' Pump 1: 134 FLEX ER/ 40OPMSXD 11 ±15,042' Gas Separator; 513 GSHV FER 12 ±15,045' Upper Tandem Seal: GSB3D8 H6 SB/AB PFSA-513 SEAL 13 ±15,052' Lower Tandem Seal: GS93DB H6 SB/AB PFSA-513 SEAL 14 ±15,059' Motor: 562XP- 150HP/ 2420V/ 38A 15 ±15,070' Gauge & Centralizer: Zenith E7 175C - Bottom @±15,075' STIMULATION DETAIL Frac d w/ 110,500# of 16/20 Carbolite behind pipe PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk Cl, 86 15,135' 15,173' 7,228' 7,257' 38 1/20/2020 Open Kuparuk 86 15,174' 15,180' 7,258' 7,262' 6 4/20/1996 Open 15,230' 15,250' 7,300' 7,315' 20 6/23/2005 Open Kuparuk A3/A2/Al 15,250' 15,282' 7,315' 7,340' 32 N/A Open 15,278' 15,308' 7,337' 7,360' 30 6/23/2005 Open Kuparuk AlB 15,309' 15,336' 7,360' 7,381' 27 1/19/2020 Open Ref Log: 4/10/1996 - GR / CCL: Mid Pert TVD = 7,308': Mid Perf MD =15,241' GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E -12/6/1995 Perf, Frac & Run ESP Completion by Polar #1- 5/25/1996 ESP Change -out by Nabors 4ES -12/9/1998, 10/2/1999 & 3/23/2002 Pull ESP Service and Re -run by Nabors 4ES-11/29/2003 Perforate & ESP Change -out by Nabors 4ES - 6/25/2005 ESP Change -out by Doyon 16 -12/18/2013 ESP Change -out and Perforate by ASR 1- 1/23/2020 Revised By STP: 2/28/2020 Milne Point ASR 11" BOP (Triple) 2/19/2020 Ililn.rp ALo-f.n. 1.1.1: 11" BOPE Stripping Head 2-7/8" x 5" VBR 2 1/16 5M Choke Line Valves Updated 2/19/2020 ff Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: February 28, 2020 Subject: Changes to Approved Sundry Procedure for Well MPU L-25 Sundry M TBD Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. HAK Step Page Date Procedure Change Prepared B Initials HAK Approved B initials AOGCC Written Approval Received Person and Date Approval: Prepared: uperations manager Date uperations cngmeer Date STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RECEIVED REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon LJ Plug Perforations L1 Fracture StimulWteLj Pull Tubing LVI Operations s utdown Performed: Suspend ❑ Perforate Q Other Stimulate❑ Alter Casing ❑ Cha g 0 ram Plug for Redrill ❑ srforate New Pool ❑ Repair Wel❑ Re-enter Susp Well ❑ (1 �ut Q 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska LL(i Development Q Exploratory ❑ 195-180 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6. API Number: AK 99503 50-029-22621-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL025509 & ADL0355017 MILNE PT UNIT L-25 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 15,655 feet Plugs measured N/A feet true vertical 7,628 feet Junk measured N/A feet Effective Depth measured 15,551 feet Packer measured 3,813 feet true vertical 7,547 feet true vertical 3,036 feet Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 112' 112' N/A N/A Surface 8,988' 9-5/8" 9,019' 4,711' 5,750psi 3,090psi Production 15,608' 7" 15,636' 7,614' 7,240psi 5,410psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / L-80 / EUE 8rd 15,062' 7,173' Packers and SSSV (type, measured and true vertical depth) Viking w/ Dual Vent 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 C J P Prior to we}I operation: 0 0 0 0 .7 Subsequent to operation: 0 J14 0 0 0 0 14. Attachments (required per 20 AAC 25.070, 25.071, &-25-29T) 15. Well Class after work: Daily Report of Well Operations 0 E ploratory❑ Development 21 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Q Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ElGSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and C the b st f my knowledge. Sundry Number or N/A if C.O. Exempt: 7 319-572 & 320-006 Authorized Name: Chad Helgeson �vrb� Contact Name: Ian Toomey Authorized Title: Operations Manager Contact Email: Itoomey(Whllcoro.com d Authorized Signature: Date: �'A Contact Phone: 777-8434 / J-.2i•11� � �/27�-d-7J RBDMSLJ FEB 19 1010 Form 10-404 Revised 4/2017 Submit Original Only n HilcurP Alaska, LLC Ong. KB Bev: 46' / On& GL Elea.: 16.5' TD=15,655' (lV%))/TD=7,628'(ND) PBTD=15,551'(MD) / FETID = 7,547(TVD) SCHEMATIC Milne Point Unit Well: MPU L-25 Last Completed: 1/23/2020 PTD: 195-180 TREE & WELLHEAD Tree 2 -9/16"x11" -5M FMC Wellhead 31"5M FMC Gen 4,W/11"Gen 5 ESP W/2-7/8"FMC Tbg. Hngr., ELIE Lift Threads, 2-7/8" CIW "H" BPV profile OPEN HOLE /CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24" Hole 9-5/8" 1,750 sx PF 'E', 250 sx Class V, 150 sx PF'E' in 12-1/4" Hole 7" 240sx Class"G"in8-1/2"Hole WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle = 69 to 74 deg. f/ 3,600' to 13,150' Max Hole Angle through perforations = 40 deg. CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Stm 20" Conductor 91.1/H-40/N/A N/A Surface 112' 9-5/8" Surface 40/L-80/Btc. 8.835 Surface 9,019' 7" Production 26/L-80/BTC&MBTC 6.276 Surface 15,636' TUBING DETAIL 2-7/8" Tubing 6.5/L-80 /EUE 8rd 2.347 Surface 15,062' JEWELRY DETAIL STIMULATION DETAIL Fred w/ 110,500#,f 16/20 Carbolite behind pipe PERFORATION DETAIL SandsU15,250' th Item Top (TVD) KBMG GLM 2-7/8" X 1"7' FT!MD=15241' GLM #3: Side ocket w/ Dumm& BK Latch Kuparuk C 0' GLM #2: Side pocket, w/Dummy & BK Latch ±7,228' 3' Packer: Viking Hyd Set ESP Packer W/Dual vent valve3' U Open 2-7/8" X -Nipple 12.313 ID) w/RHC Installed 72' GLM #1: Side pocket, w/Dumm& BKLatch 7,262' 29' 2-7/8" %N -Nipple (2.205 No -o ID) Open 0.9' Discharge Head: B01t On FPDIS 15,250' 81' Discharge Head: Ported 205 Pump 2: 134 FLEX ER/ 40OPMSXD Kuparuk 15,006' Pump 1: 134 FLEX ER/ 40OPMSXD 7,315' 15,029' Gas Separator: 513 GSHV FER k 15,032' Upper Tandem Seal: GSB3D6 H6 SB/AB PFSA - 513 SEAL 15,039' Lower Tandem Seal: GSB3DB H6 SB/AB PFSA-513 SEAL 7360' 15,046' Motor: 562%P-150Hp/2420V/3&A OpenKu 15,057' Gauge& Centralizer: Zenith E7175C-Bottom@15,062' STIMULATION DETAIL Fred w/ 110,500#,f 16/20 Carbolite behind pipe PERFORATION DETAIL SandsU15,250' Btm (MD) Top (TVD) Btm (TVD) FT!MD=15241' Status Kuparuk C ±151173' ±7,228' ±7,257' 3820 Open Kuparuk 15,180' 7,258' 7,262' 66 Open 15,250' 71300' 7,315' 205 Open Kuparuk 15,282' 7,315' 7340' 32 Open 15,308' 7,337' 7360' 305 OpenKu aruk A 15,336' 7,360' 7,381' 270 O enRef Lo : 4/10/1996-GR/CCL : Mid PerfTVD =7,308' : Mid Perf' GENERAL WELL INFO pDririled jtj 1-00-00 by Nabors 22E -12/6/1995 SP Completion by Polar #1-5/25/1996 ny Nabors 4ES-12/9/1998,10/2/1999 & 3/23/2002 nd Re -run by Nabors 4ES -11/29/2003 hange-out b Nabors 4ES-6/25/2005 ny Doyon 16 -12/18/2013 Change -out by Revised By TDF: 2/14/2020 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number I Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 1 195-180 1/3/2020 1/23/2020 1/1/2020 - Wednesday No operations to report. 1/2/2020 - Thursday No operations to report. 1/3/2020 - Friday IWS crew arrived. Preparing the ASR and associated equipment to Mobe from A -pad to L-25.;LRS was only able to establish a pump rate @ 1.3bpm/3,300psi. Decision was made to have SL punch holes in tbg to establish enough rate for the well kill. ASR on stand-by at A -Pad waiting for SL ops and well kill to completed. Continued continued preparing and servicing ASR and auxiliary equipment. 1/4/2020 -Saturday Serviced and cleaned rig. Replaced sensor light for the PTO. Put together the 13-5/8" BOP Stack inside the ASR Tent.;Well Kill (PT surface lines 250/2,500psi) Pump 635 bbls 10.5 Brine down Tbg @ 4.7bpm/2,300psi taking returns up IA to Tank. Returned 584bbls. Monitored well static. Pumped Freeze Protect do Tbg w/ 5 bbls 60/40. Pumped Freeze Protect do IA w/ 1 bbl 60/40. Freeze Protect surface lines w/ 4 bbls 60/40. Pull power swivel from Carriage and replace Seal Package on thrust box/quill. Need to pull schematics of power swivel/thrust box/quill/wash pipe/gooseneck. Prep to Mobilize Rig and equipment. 1/5/2020 -Sunday On hold due to cold weather. 1/6/2020 - Monday On hold due to cold weather.. 1/7/2020 -Tuesday On hold due to cold weather. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 195-180 1/3/2020 1/23/2020 1/8/2020 - Wednesday Held PJSM and discussed daily operations. Continued moving euipment in with assistants from Roads&Pads. Spot in Mud Boat and Well Hut. N/D the Production Tree and inspected lifting Treads. NU 13-5/8" BOP Stack as following. 13-5/8" 5M MudCross w/ 2-1/16"5M Manual Kill Line Valves and. 2-1/16" 5M Manual/HCR Choke Line Valves, 13-5/8" DBL Gate Ram dressed w/Blinds on bottom and 2-7/8"-5" VBR's on top, 13-5/8" Single Gate dressed w/2-7/8"-5" VBR's, 13-5/8" Annular. With assiance from Crane Fly in and set Floor. Spotted ASR and raised Mast. Secured Rack Pins Spot in Catwalk, Spot in the Mud Pits, Load all hose in the warm up skid. RD Range land TBG tongs and RU Macoy TBG tongs on Floor. Spot Mud Pump with the crane. Load Pipe Shed and Road form A -Pad to L-25, Spot in and RU. Spot in Accumulator and camps. Run power to camps. Begin RU for Bope test, BOPE hydraulic lines, kill and choke, pump lines, flow spool and flow line, winterize. 1/9/2020 - Thursday Held P1SM and discussed daily ops. Spotted Company Shack and Crew Change Shack. Ran Kill/ Choke and pump lines. Wrap lines for winterization. NU Flow Spool and 6" Flow Line. While function the pipe handler observed a hydraulic leak coming from the pump shaft. Could not repair leak so plan is. to RD Pipe shed and Pipe handler and use the old one. Continued preparing for BOPE Test. Loaded Pit with 40bbls of FW. Hooked up Accumulator Hook Lines and Function Tested the Koomey Unit. PJSM, Service and inspect rig and equipment. Added Hydraulic oil to the accumulator. Continue to winterize rig and pump lines still getting lots of cold spots had to hooch in the jumpers form rig manifold to the pits as well as from the pits to the mud pump with assistance from the carpenters, had to round up more heaters from the field added heater to the back of the derrick, one to the Kill and choke lines and one for the test mandrills, one under the rig hydraulics. Grease mud cross and choke manifold. Move the Pipe shed and remove the HPH RD Tong rack, Replace with Spare HPH. Cont, to Wrap BOPE test lines and heat All lines and Equipment Finally at working temp. Fill the hole and work air out of the system. Roll it while picking up test mandrill and connect the test line to mandrill. Notify the State Rep. Austin Mcleod . When Closing the 2-7/8" x 5-1/2" VBR"s on Shaffer Double Gate noticed that the mandrill was loose when shut. Blow down the stack and begin trouble shoot the issue. Trouble shoot issue with the 2-7/8" x 5-1/2" VBR"s on Shaffer Double Gate. 1/10/2020 - Friday Held PJSM and discussed daily activities. Continued Trouble shooting issue with the 2-7/8" x 5-1/2" VBR"s on Shaffer Double Gate not fully functioning. Due to the cold temps we doubled wrapped. Accumulator lined and heated. Continued cycling to circulate warm fluid around system. After getting the Fluid warm the Shaffer stack. we got full closing Pressure and Tested good on 2-7/8" mandril. move on to the upper cameron U -Type single gate rams. Could not get the Rams to test on 2-7/8" Mandril. swap out mandril with the 3.5". mandril and test test was good. opened up the rams to inspect. Found that there were 4.5"-7" VBR's loaded. Started hunting down Replacement Rams for Cameron U -type but were unsuccessful. Ended up having to Rent Single Gate Hydril from Doyon Casing. Moved the Pipe shed out of way for the crane. ND Flow spool, Pulled the Rack Pins and layed over the derrick. Singe gate arrived unloaded and wrapped with heat. Start crane operations. Fly the floor off, ND Annular, ND Single Gate Cameron U -Type. Prep the New Hydril Single Gate with verified 2-7/8" x5" VBR's. Install hydraulic fittings. NU Hydril and Annular, set the work floor. RU ASR while torqueing up the stack. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 .95-180 1/3/2020 1/23/2020 1/11/2020 -Saturday PJSM and discussed daily activities. Coni torqueing up the stack and preparing to test BOP'S , Spotted pipe handler and Pipe shed. MU 2-7/8" Test Mandrel Flood BOPE and circulated stack. Preformed shell test, on the high test observed leak coming from the 13-5/8" spacer spool between the DBL and single Gate. Tried torqueing up connect and retesting with no luck. Broke out the 13-5/8" Spacer Spool and found a gouge in the face of the flange. Replaced the Spacer Spool and torqued up the connection. Get stack torqued back up, NU Flow spool, hunted for cold spots and mitigated. prep for BOPE Shell test work air out of the system. Conduct Bope Shell test 250/low 3500/high test good. Conduct BOPE Test as per sundry 250/low 3500/high on all rams and valves Blinds, 2 sets of 2-7/8" x 5" VBR's. and the Annular chart 5 Min.. All tests good. Aogcc witness waived by Austin McLeod. Blow Down, Pull Test Plug and check for pressure under BPV and bleed off. Pull BPV. Transfer Fresh water out of the pits. Pull over the the stack. Make up 2-7/8" Landing jnt. BOLDS 1/12/2020 -Sunday Held PJSM, Checked Fluids and Services Equipment. Cont BOLDS, Hung Cable Sheave and PU handling tools for 2-7/8" Tbg. Well static opened IA and pulled Hanger off seat. PU is 81k. Pulled Hanger to Rig Floor. De -completed Hanger, L/d Hanger and Landing Joint. MU the TIW in the closed position, lined up to pump down the IA. Filled IA with 9bbls of 10.5 Brine. Monitor well -static. L/D one joint and pulled cable thru Sheave to spooler. POH L/D 7 jts of 2-7/8" 6.5# L-80 EUE 8rd tbg. SD and secured well due to problems with the Rigs Hydraulics. Briefly lost Hydraulic pressure on Aux pump #2. Pressure did come back up but could not maintain a constant pressure. Troubleshoot issue found the McCoy tong that were being operated with the Rig Hydraulics leaking by. Installed a valve on the Hydraulic line going to the Tongs so it can deadhead when not being operated to keep the systems hydraulics fluctuating. Continue POH with 2-7/8" ESP Completion. L/d total of 250 jts. Displacing every 15 its with 10.5 Brine. 1/13/2020 - Monday Held PJSM, Checked fluid and serviced rig. Continue POH with 2-7/8" ESP Completion. Displacing every 15 jts with 10.5 Brine. After joint # 276 tbg showing some dusting possible light salt build-up. No issued with drag or over pulls while tripping. De -Completed and Lay down ESP Equipment. No sign of scale or corrosion on the ESP assembly. RD Elephant Trunk and remove Baker equipment from the Work floor, Change over to BHA Handling Equipment. Unload the Completion 2-7/8 EUE tbg. Load 120 jnts on the Pipe racks and tally top row. Prep and Tally Clean Out BHA (5-7/8" Tri -come bit,Bit Sub,Bumper Sub, Oil Jars ,4- 4-3/4 DC,+ -400' 2-7/8" Ph6 TBG, 7" CSG Scraper) M/U BHA 5-7/8" Tri -come bit, Bit Sub ,Bumper Sub, Oil Jars ,4 x. 4-3/4 DC,14 Joints 2-7/8" Ph6 7.9# P110 TBG, 7" CSG Scraper. All Cross overs in Clean out TBG Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 195-180 1/3/2020 1/23/2020 1/14/2020 -Tuesday Held PJSM, Checked Fluids and serviced equipment. TIH with Cleanout BHA on 2-7/8" 7.9# P110 PH6 Work -string. SD and Secured well. Had to replace a busted hydraulic hose from the Rig to the Tongs. Continued TIH with Cleanout BHA on 2-7/8" 7.9# P110 PH6 Work -string. At 4,880'md started taking weight. SO 21k/ PU 29k turn pipe a quarter turn set down 10k and pushed through tight spot. Cont TIH. Continue in the hole with Cleanout BHA on 2-7/8" 7.9# Pilo PH6 Work -string. 190 jnts EOT @ 6,009'. PJSM, Service and inspect rig and Equipment. Cont. in the hole with Cleanout BHA on 2-7/8" 7.9# Pilo PH6 Work -string. Total of 203jnt EOT @. 6,483'. M/U XO Sub 2-7/8" x 3-1/2 NC31, X -over to 3.5" WS handling equipment. Cont. RIH With Joint 3-1/2" NC31 10.37# WS to 9,407'. Conduct well control drill while tripping in the hole. Group discussion on where improvements can be made. Cont. RIH With Joint 3-1/2" NC31 10.37# WS Tight Spot at 10,382' Jnt 98 -12' in. work through continue down to jnt 106, Service loop wrap came apart and the lines were. catching on the Back of the rack on the way up. Tighten up wrap and keep RIH. Hit another Tight Spot Jnt 117-20' in @ 11,150' work through and cont. RIH. EOT @ 12,812' Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 195-180 1/3/2020 1 1/23/2020 1/15/2020 - Wednesday Held PJSM, check fluids and serviced equipment. Continued TIH with Cleanout BHA from f/12,812't/15,100'. Established parameters PU 121k/SO 26k. Cont TIH No issues running through perfs or to tag depth @ 15,552'md. Confirmed tag putting 10k dn. L/D 1 joint and set pipe in slips. RU the circulating lines and lined up valves to pump down tbg taking returns up the IA. Rolled pump over at 5 bpm took 14 bbls to catch returns. Continued circulating @ 5bpm/1,900psi while monitoring returns at the shaker. After bottoms up return were clean with fluid weight @ 10.5ppg. SD pump and found no solids at across the Shaker. Pumped a total of 460bbls. Lost 36bbls to formation. RD the Kelly hose. Blow lines and dry and prepared to TOH with Cleanout BHA. POH L/D workstring and displacing every 15 jts with 10.5ppg Brine. PJSM, Crew Change, Service and inspect Rig and Equipment. POOH L/D 3-1/2" NC31 10.37# WS, did not see any overpull when going through the tight areas. Change over to 2-7/8" Handling equipment, conduct a kick while tripping out of the hole well control drill. Pooh L/D2- 7/8" 7.9# Ph6 did not see any overpull when going through the tight areas Fluid lose was 61 bbls. 1/16/2020 - Thursday Held PJSM and discussed plan forward. Checked and serviced equipment. Continued POOH L/D 2-7/8" 7.9# Ph6 to the Cleanout BHA. L/D BHA, Cgs Scraper, 14 joints of 2-7/8" PH6, (4) 4-3/4" DC, Oil Jars Bumper Sub and BIT. Filled hole with 16.5 bbls of 10.5# Brine. Troubleshot carriage motor delays With the assisted of Pro Star, adjusted Carriage Motors Pressure. Prepared Rlg Floor to make the Test Packer Run, . PU/MU and Strapped the 7" AS1-X Test Packer. Performed Pre - run inspection on packer. MU XO to our 2-7/8" PH6 Work -string. TIH with Test Packer on 2-7/8" 7.9# PH6 work string 42 jnts in the hole at crew change. PJSM, Crew Change, Service and inspect rig and equipment. TIH with Test Packer on 2-7/8" 7.9# PH6 work string 162 total 5,053'MD. Held Well Control drill while crossing over to 3.5" handling equipment. Finish crossing over. rack and tally 61 jnts of 3.5" 10.3# NC31 WS. P/U M/U 2-7/8" Ph6 Pin X 2-7/8" NC31 Box. Change tong dies on TBG tongs. Cont TIH With 3.5" 10.3# NC31 WS. 75'nts in the hole. 1/17/2020 - Friday PJSM, Crew Change, Service and inspect Rig and Equipment. RIH/w PKR on 3.5" 10.3# 2-7/8" NC31 WS to Jnt 247. Get PU 105K, SO 25K. Try to set the PKR with Wobble Couldn't get the turns worked down enough to set. Swivel up to top drive and work pipe torque down to PKR. After Setting PKR @ 14.994' Fill the IA 12 BBIs Work air out of the system Brine test pressure to 2,650PSI Loosing Pressure right away double check all surface equipment for any leaks or cold spots that might contribute to leak off Watch for a flat line but could not get one. Bleed off pressure and continue to work air out of the well and system. Bring Back up to 2,700P51 this time a much slower leak off of about 10psi/min continuous trend. Bleed off and Release PKR Lay down 1 jnt moving the PKR to 14,955' COE. Set PKR & fill IA 8 Bbls work air out of system again and retest Initial Pressure-2,780PSI. 15Min- 2,685PS1. 30min- 2,650PSI. Good Test Bleed off and Release the PKR. Blow Dry and Let PKR Elements relax. POOH with PKR on 3.5" 10.3#2-7/8" NC31 WS LD 8 jnts. Oil Leak on the Rig engine VMS here to look at rig. could not lock down where leak was coming from. POOH with PKR on 3.5" 10.3#2-7/8" NC31 WS LD Pumping Single Displacement. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 195-180 1/3/2020 1/23/2020 1/18/2020 -Saturday Held PJSM and discussed daily activities. Checked fluids and serviced rig. Cont POOH with the Test Packer and 3-1/2" Work - string. Displacing every 15 jts with 10.5ppg Brine. SD and secured well to troubleshot issues with the rig air system not keeping the PTO engaging. With help from VMS troubleshot issues. Found a seal leak on the air control valve. Cap the lines coming from the Namco and supplied a direct air feed to the PTO. Cont POOH with the Test Packer and L/D 3-1/2" Work - string to XO sub @ 5,054'md. Displacing every 15 jts with 10.5ppg Brine. Swapped over Handling equipment to pull the 2- 7/8" workstring. Cont POOH with the Test Packer and 2-7/8" Work -string f/5,054' t/surface. Displacing every 15 jts with 10.Sppg Brine. PJSM, Crew Change Service and inspect rig and equipment. 300K gen set went down fault in coolent sensor inspect and restart gen set. cleared fault. Cont POOH with the Test Packer and 2-7/8" Work -string f/5,054't/surface. Displacing every 15 jts with 10.5ppg Brine. B/0 L/D 7" Test PKR. M/U X -overs for the Test Plug, Make up 2-7/8" Test mandrill. PU/MU Test Plug and land in well. Make sure Plug is seated and work all the air out of the system. Bump test repaired test pump. bump test Good. Conduct BOPE test as per Sundry. 250/low 3,500/high on all equipment. During test 2 Had a slow leak on valve K5 had to bleed off blow down and swap out. Give E -line a call out. 1/19/2020 -Sunday Held PJSM and discussed daily activities. Checked fluids and serviced rig. Cont. Test BOPE as following. Rams 250-3500psi,� Valves 250-3,500psi, Annular 250-3,500psi. Charted Test for 5 mins on the low and high test. Tested with 2-7/8" Test Mandrel. Tested Gas Detection and Preformed Accumulator Draw -down. No failures were recorded. AOGCC witness waived by Jeff Jones. L/D Testing equipment and blow lines dry. NU 11'x 7-1/16" Spool and 7-1/16" Shooting Flange. MIRU Pollard EL Unit. RD elevators and tie off sheave to the tool carrier. PU/MU GR/CC, 27'3-3/8" 6spf 60 deg phase 23 gram charges and Roller Bogies on top and bottom of tool string. RIH w/tool string to 15,370'. Send correlation logs to town. CCL depth @ 15'301.3' Fire off guns from 15,309'-15,336'. all indication pointed to guns going off yet we did not see a change in the well bore. POOH. After getting the guns to surface found that the guns had not went off. Called to have new gun sent to Rig. When new 273-3/8" 6spf 60 deg phase 23 gram charges arrived prep gun to RIH. RIH/ GR/CC, 27'3-3/8" 6spf 60 deg phase 23 gram charges and Roller Bogies on top and bottom of tool string. CCL depth @ 15'301.3' Fire off guns from 15,309' 15,336' great indication that guns went off. felt it in the truck. well is static after firing guns. POOH. 91 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#1 50-029-22621-00-00 195-180 1/3/2020 1 1/23/2020- 1/20/2020 - Monday Held PJSM, checked fluids and serviced rig. POOH and LD Perf Gun. Confirmed all shots fired. PU/MU CCL/GR and 18' 3-3/8" 6spf 60 degree carrier. RIH at 15,150 started having issues with the CCL/GR signal cut in and out. PU to 14,500' and regained signal. Logged back down and lost signal again @ 15,250'. Checked connection and rebooted system and still having same issues. POOH. With tools at surface changeout the CCL/GR. RIH with tool string to 6,700' and the same issues with CCL/GR losing signal. Continued troubleshooting found cable from the collector slips to the shooting panel with nick wire. Same issues after replacing the cable and shooting panel. POOH. POOH, L/D tool string and re -head WL thinking that it might be a tension issue. MU tool string with new roller boggy on top and RIH with tool string to 15,300' logged correlation stripe up to 14,700'. Tied -in and sent to town for approval. With CCL @ 15,144' pref from 15,155-73'. Good indication gun fired. Monitored well on slight vac. SIMOP: While waiting on WL to re -head filled IA with 18.5bbls of 10.5# Brine. POOH L/D Gun Confirmed all shots fired. LD Fired Gun, PU/MU CCL/GR and 20'3-3/8" 6spf 60 degree carrier, RIH to 15,300' Log up to 14,700' Tied -in and sent to town for approval. With CCL @ 15,125.9' pref from 15,135'-55'. Good indication gun fired. Monitored well on slight vac. POOH L/D Gun Confirmed all shots fired. LD Guns. RDMO E -line Fill the hole 17 BELS 10.5# Brine. ND 11" -7" DSA, NU Flow Spool. RU to pick up Baker ESP equipment. Spot in the Spooling Unit, Load Prep and Tally ESP Completion onto the catwalk and Pipe racks. PU/MU and service ESP Equipment. 1/21/2020 -Tuesday Held PJSM, Checked fluids and serviced rig. TIH with ESP Assembly on 2-7/8" 6.5# L-80 EUE 8rd production tbg as following: 1 jts of 2-7/8" tbg, XN Nipple (2.205 no/go), 1 jts of 2-7/8" tbg, Lower GLM w DV Installed, continued TIH cross clamping the first 15 jt then every other thereafter. Test cable first 1000' then 2000' after that. Total of 190jts in the hole at crew change. Crew change, service and inspect rig and equipment. Tally TBG. TIH with ESP Assembly on 2-7/8" 6.5# L-80 EUE 8rd production tbg testing every 2,000' 254 total jnts in the hole. Test cable and do Reel to Reel splice. RIH/ to splice on the Cable @ 8,121'MD -Splice landed right on a collar had go get a 10.19' pupjnt from D -Pad to add under jnt #261 to space out the splice. Also had VMS work on the Coolant system at the same time. TIH with ESP Assembly on 2-7/8" 6.5# L-80 EUE 8rd production tbg testing every 2,000'. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP L-25 ASR#150-029-22621-00-00 1 195-180 1/3/2020 1 1/23/2020 1/22/2020 - Wednesday Held PJSM, Checked fluids and serviced rig. TIH with ESP Assembly on 2-7/8" 6.5# L-80 EUE 8rd production tbg PU #361, X - nipple w/RHC Body Installed, PU jt #362. PU/MU and inspected the Viking Packer verified 4 set shear pins and 15 shear release pin (49k straight over pull release), made the vertical cable splice and tested, swapped out cable spool, Made the top cable splice and MU 3/8" cap line to the vent valve. Pressured up to 5,000psi no leaks and vent valve opened at 3,600psi. Bled Cap string to 500psi and held. PU jt#363, 2nd GLV w/DV Installed @ 3,757'MD. Cont TIH with ESP Completion testing cable ever 1,000', PU Jt#479, 3rd GLM/w DV Installed @ 173.91'.Make Penetrator Splice and terminate cap tube. Do final checks. Land TBG, 50 wt. 15.5K. RILDS, Total Jnts 483, Hanger+ KB, EOT @ 15,062.02'. Drop Ball and Rod, Fill tbg and pressure up to 2,500psi and hold for 5Min to set the PKR. Bleed off. 1/23/2020 - Thursday Held PJSM, Checked fluids and serviced rig. Filled and pressure on the IA up to 1,500PSI chart 30 MI -Good Test Bleed off slow. Installed BPV. End of well work for L-25. Start RDMO operations. Continue with RDMO operations, break off and secure hoses. Crew change out day, both crews swap out. Conduct Pre -Tour meeting with incoming crew. All personnel muster at Milne Point main camp for post review and Lessons Learned of L-25 operations and crew Safety Meeting with IWS Safety Rep. Continue with RDMO operations off of L-25. ND BOP, stage on truck and move off location. Begin to change out upper variable rams in Double Stack. Pits module moved off location. Changing out upper variable rams, stage tree over well and NU. Test tree to 500 psi low / 5,000 psi high for 5 minutes. port.ayport.yport. =report. r 1/27/2020 - Monday No operations to report. 1/28/2020 -Tuesday No operations to report. Explanation of production data for sundry 319-572 & 320-006. There is no production data for L-25 because the ESP only ran for about 5 hours before a downhole electrical short occurred. L-25 is on the ASR schedule to pull & replace the failed ESP. Regg, James B (CED) From: Ian Toomey - (C) <itoomey@hilcorp.com> Sent: Monday, February 10, 2020 10:26 AM To: Regg, James B (CED) Cc: Brooks, Phoebe L (CED); Wallace, Chris D (CED) Subject: RE: [EXTERNAL] RE: MIT Test Report MPU L-25 Attachments: Revised MIT form L-25.xlsx Jim, Here is the revised MIT form. Regards, Ian Toomey I Operations Engineer Hilcorp Alaska, LLC I Milne Point Cell: 907-903-3987 From: Regg, James B (CED) [mailto:jim.regg@alaska.gov] Sent: Monday, February 10, 2020 10:20 AM To: Ian Toomey - (C) <itoomey@hilcorp.com> Subject: RE: [EXTERNAL] RE: MIT Test Report MPU L-25 Thank you for the quick reply. Please send a revised MIT report. Jim Regg Supervisor, Inspections AOGCC 333 W.7`h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 Rkk L-z5- PrIN ig5lt�00 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 Jim Regg at 907- 793-1236 or iim.reg¢@alaska.¢ov. From: Ian Toomey - (C) <itoomey@hilcorp.com> Sent: Monday, February 10, 2020 10:18 AM To: Regg, James B (CED) <iim.rese@alaska.gov>; Alaska Well Integrity <AlaskaWellinteerity@hilcorp.com> Cc: Brooks, Phoebe L (CED) <phoebe. brooks@alaska.gov>; Wallace, Chris D (CED) <chris.wallace@alaska.gov>; Carl Linaman - (C) <clinaman@hilcorp.com> Subject: RE: [EXTERNAL] RE: MIT Test Report MPU L-25 Jim, The 2,000 psi tubing pressure was an input error. The MIT of the 7" casing to 2,500 psi for 30 minutes per sundry 319- 572 was done with a test packer which was not plugged therefore could not have held pressure. L-25 is an ESP producer. Regards, Ian Toomey I Operations Engineer Hilcorp Alaska, LLC I Milne Point Cell: 907-903-3987 From: Regg, James B (CED) [mailto:iim.rega alaska.gov] Sent: Monday, February 10, 2020 10:07 AM To: Alaska Well Integrity<AlaskaWelllnteRrity@hilcorp.com> Cc: Brooks, Phoebe L (CED) <phoebe.brooks@alaska.gov>; Wallace, Chris D (CED) <chris.wallace@alaska.eov>; Carl Linaman - (C) <clinaman@hilcorp.com> Subject: [EXTERNAL] RE: MIT Test Report MPU L-25 AOGCC has not yet received the requested clarification regarding the MIT on MPU L-25. [MIT attached for your convenience]. Response is due not later than 2/14/2020. Jim Regg Supervisor, Inspections AOGCC 333 W.Th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Regg, James B (CED) Sent: Thursday, January 23, 2020 1:45 PM To: Carl Linaman - (C) <clinaman@hilcorp.com> Cc: Brooks, Phoebe L (CED) <phoebe. brooks @alaska.aov>; Wallace, Chris D (CED) <chris.wallace@alaska.gov> Subject: RE: MIT Test Report MPU L-25 Did you do separate tubing and IA tests? I'm a bit confused by the 2000psi tubing pressure. Jim Regg Supervisor, Inspections AOGCC 333 W.Th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Carl Linaman - (C) <clinaman@hilcorp.com> Sent: Tuesday, January 21, 2020 8:52 PM To: Regg, James B (CED) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (CED) <phhoebe.brooks@alaska.gov>; Wallace, Chris D (CED) <chris.waIlace @alaska.gov> Subject: MITTest Report MPU L-25 Thanks! Carl Linaman Company Rep, ASR #1 Hilcorp, Alaska Cell: 307-277-0813 Office: 907-685-1266 clinaman@hilcorp.com The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: "m mogigalaska.aoyAOOCC t I k Phoebe brookuitud.ska.gov OPERATOR: H'Icorp FIELD / UNIT / PAD: MPU L-25 (ESP producer) DATE: 01/17/20 OPERATOR REP: AOGCC REP: Chris wallace�eleska aov ` efI Z{I1� &rw Well MPU L-26 Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 0= offer (descnce in Notes) 4•Four Year Cyde PTD 195.180 Type lnl Tubing 1=lncondusne 0 00 0 =other (us... in notes) NIA NIA Type Test P Peder ND 7075. BBL Pump 4.0 IA 2780 2685 -F2 650 ' NIA N/A Interval O Test psi 2500 BBLRalum 4.0 OA 0 0 D 1 0 0 Result P P Notes: T' using test b 2.500 psi for 30 minutes per sundry%319572 s/ Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Int TubingType Test Paler NO BBLPump IA Interval Test psi BBL Retum OA Result NNS: Well Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Pip Inj Tubing Tubing Type Test PackerND Be IA interna( Interval Test psi BBL Retum OA Result Neter: yyeg Pressures: Pretest Initial 15 Min. W Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Paler TVD BBL IA Interval Test psi 8131 Retum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test PackerND BBLPump IA Interval Test psi BBL Relum OA Result Notes: Wall Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD Type lint Tubing Type Test Paler TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: y,/eg Pressures: Pretest Insist 15 Min. 30 Min, 45 Min. 60 Min. PTD Type lnl Tubing Type Test PackerND BBL Pump IA Interval Test psi BBL Return OA Result Nom: weIP Pressures: Pretest Initial 15 Min. W Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test PackerND BBLPump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Cotler TYPE TEST Cod. INTERVAL Codes Result Catlae W=Water P=Pressure Ted I=Initial Test P=Pass G=Gas 0= offer (descnce in Notes) 4•Four Year Cyde F=Fail s=Sloth' V=Rept dEy Variance 1=lncondusne I = IMuattial Wademner 0 =other (us... in notes) N = Not mustang Forth 10-026 (Revised 01/2017) 20ID-0t]) MIT hi THE STATE °1 LASKA .L IL GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU L-25 Permit to Drill Number: 195-180 Sundry Number: 320-006 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaskc.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, \ 1 J e y rice C ai DATED this A day of January, 2020. RBDMSL✓JAN 10 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 280 JAN C 7 2020 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate 0 . Other Stimulate ❑ Pull Tubing ❑ Change Approved Program Q Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ESP Change -out ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q - Stratigraphic ❑ Service ❑ 195-180 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-22621-00-00 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 [Y]' �) MILNE PT UNIT L-25 9. Property Designation (Lease Number): 10. Field/Pool(s): t" .4Dz- 0 ADL0355017 MILNE POINT/ KUPARUK RIVER OIL - 11. 1- Z,9 PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 15,655' 7,628' 15,551' 7,547' 3,073 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 112' 112' N/A N/A Surface 8,988' 9-5/8" 9,019' 4,711' 5,750psi 3,090psi Production 15,608' 7" 15,636' 7,614' 7,240psi 5,410psi Perforation Depth MD ft) : Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing See Attached Schematic See Attached Schematic 2-7/8" 6.5#/ L-80 / EUE8rd 15,077' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A and N/A NA/ and N/A 12. Attachments: Proposal Summary r 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: 1/7/2020 OIL ❑✓ WIND ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Ian Toomey Authorized Title: Ope ations Xanager Contact Email: itoome hilCor .Goth /�µ.•/ Contact Phone: 777-8434 .7 Authorized Signature: Ir.( +/ ur11+ Date: d V COM SSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Numbb r, U 20_ O� Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS'' JAN 1 0 2020 Post Initial Injection MIT Req'd? Yes ❑ No ❑ j Spacing Exception Required? Yes ❑ No [� Subsequent Form Required: 1 Q "--� D y APPROVED BY n Approved by: COMMISSIONER THE COMMISSION van -2 Date: UHIGINAL I 1 I Submit Form and onn 10-403 Revised 412017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate K Hil.mp Alaska, LL Add Perfs During RWO Well: MPU L-25 Date: 01-07-2020 Well Name: MPU L-25 API Number: 50-029-22621-00-00 Current Status: SI - ESP Producer Pad: L -Pad Estimated Start Date: January 7`^, 2020 Rig: ASR Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 195-180 First Call Engineer: Ian Toomey (907) 777-8434 (0) (907) 903-3987 (M) Second Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) AFE Number: Job Type: Add Perfs during RWO Most recent SBHP (11/04/19): Maximum Expected BHP: MPSP: Max Inclination Max Dogleg: Tree: Wellhead: Tubing Hanger Lift threads: BPV Profile: Brief Well Summary: 3,785 psi @ 7,124' TVD 3,785 psi @ 7,124' TVD 3,073 psi 74" @ 4,876' MD 4.5"/100ft @ 2,037' MD Cameron 2-9/16" 5M FMC Gen 5, 11"x11"5M 2-7/8" EUE 8rd top & bottom 2-1/2" CIW Type H EMW = 10.22 ppg; KWF = 10.5 ppg EMW = 10.22 ppg Gas Column Gradient =0.1 psi/ft Well L-25 was drilled by Nabors 22E in December 1995 and completed by Polar #1 in May 1996 in the Kuparuk B and C sands. There have been 7 previous ESP swaps on this well with an average run life of 994.5 days (2.73 years). The current ESP failed on 2/8/19 due to a downhole short after a run life of about 5 years (8 year run life on the previous ESP installed). Notes Regarding the Well & Design • 7" Casing MIT to 2,500 psi passed on 9/30/1999 • Offset Injector Support o F-49: SI on 6/27/19. o F-89:SIon 6/28/19. Objective: • Add perforations in the C, B and A sands during the RWO (refer to approved sundry(# 319-572). Pre -Rig Procedure: 1. Completed under sundry #319-572 2. ASR is currently waiting on weather prior to RU on well L-25. H Llacara Alaska, LG Add Perfs During RWO Well: MPU L-25 Date: 01-07-2020 RWO Procedure: 3. Refer to sundry #319-572 for previous steps. Note: The cleanout depth in sundry #319-572 will be changed from ±15,400' MD to ±15,551' MD (PBTD). 4. After the test packer assembly is laid down (step #28 in approved sundry #319-572). 5. RU E -line. 6. RIH with GR/CCL with 25' dummy gun for drift and tag to ensure we can get to the target depth of 15,370' MD with E -line. a. Short joint (-21') with RA tag installed at 15,020' MD 7. Log up from 15,370' to 14,700' MD for correlation and tie into GR/CCL log dated 4/10/96. POOH. 8. PU and MU 3-1/8" or 3-3/8", 6 SPF, 60° phasing with GR/CCL. a. Send gun worksheet to engineer for review. 9. RIH with perforating guns to 15,370' MD. Log up to 14,700' MD for correlation confirmation. a. Contact Geologist Radu Girbacea (907-230-9490) and Engineer Ian Toomey (907-903-3987) for review prior to perforating. 10. RIH to 15,370' MD and PU to perforating depth. 11. Perforate the following interval: Zone Sand I Top (MD) I Bottom (MD) Length Kuparuk AIB 15,309' 15,336' 27' ut l., 12. POOH and lay down perforating guns. ✓✓ a. Document condition of fired guns including damage or unfired charges. 13. PU and MU 3-1/8" or 3-3/8", 6 SPF, 600 phasing with GR/CCL. a. Send gun worksheet to engineer for review. T 14. RIH with perforating guns to 15,300' MD. Log up to 14,700' MD for correlation confirmation. a. Contact Geologist Radu Girbacea (907-230-9490) and Engineer Ian Toomey (907-903-3987) for review prior to perforating. 15. RIH to 15,300' MD and PU to perforating depth. 16. Perforate the following interval: Zone Sand Top (MD) Bottom (MD) Length Kuparuk C & B 15,135' 15,173' 38' 17. POOH and lay down perforating guns a. Document condition of fired guns including damage or unfired charges 19. Continue to RWO under approved sundry #319-572 at step #28. Attachments: 1. Current schematic 2. Proposed schematic Ong. KB Elev.: 46 (Nabors 22E) TD=15,655' (MD)/TD=7,628'(TW) PBTD = 15,55V(MD) / PBTD = 7,547'(TVD) SCHEMATIC Milne Point Unit Well: MPU L-25 Last Completed: 12/18/2013 PTD: 195-180 TREE & WELLHEAD Tree 2 -9/16"x11" -5M FMC Wellhead 11" 5M FMC Gen 4, w/11" Gen 5 ESP w/2-7/8" FMC Tbg. Hngr., EUE Lift Threads, 2-7/8" CIW "H" BEV profile OPEN HOLE/ CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24" Hole 9-5/8" 1,750 sx PF'E', 250 sx Class'G', 150 sx PF'E' in 12-1/4" Hole 7" 240 sx Class "G" in 8-1/2" Hole WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle= 69 to 74 deg. f/ 3,600' to 13,150' Max Hole Angle through perforations =40 deg. CASING DETAIL Size Type Wt/Grade/Conn ID Top Bt, 20" Conductor 91.1/H-40/N/A N/A Surface 112' 9-5/8" Surface 40/L -80J Btc. 8.835 Surface 9,019' 7" Production 26 / L-80 / BTC & MBTC 6.276 Surface 15,636' TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUEBrd 2.347 Surface 15,077' JEWELRY DETAIL No Depth Item 1 143' GLM #2: Camco 2-7/8" x 1" Dummy Valve 10-8-17 2 14,820' GLM #1: Carrico 2-7/8" x 1" Side Pocket KBMM GLM 3 14,964' 2-7/8" XN-Nipple (2.205 No-go ID) 4 15,007' Discharge Head 5 15,008' Upper Tandem Pump: Type- 119P23, Model- PMSXD 6 15,025' Lower Tandem Pump: Type- 18P75, Model- PMSXD 7 15,032' Gas Separator: GRSFTXARH6 8 15,037' Upper Tandem Seal: GSB3DBUT SB/SB PFSA 9 15,044' Lower Tandem Seal: GSB3DBUTSB/SBPFSA 10 15,051' Motor: CL -5 MSP1250, 294hp/ 2,315V/ 77A 11 15,073' Pumpmate 12 15,075' Centralizer: Bottom @ 15,077' STIMULATION DETAIL Frac'd w/ 110,500# of 16/20 Carbolite behind pipe PERFORATION DETAIL Sands Top(MD) Btm(MD) Top (TVD) Btm(TVD)d20 Date Status Kuparuk B 15,174' 15,180' 7,258' 7,262' 4/20/1996 Open 15,230' 15,250' 7,300' 7,315' 6/23/2005 Open KuparukA 15,250' 15,282' 7,315' 7,340' N/A Open 15,278' 15,308' 7,337' 7,360' 6/23/2005 Open Ref Log: 4/10/1996 - GR / CCL: Mid Perf TVD = 7,308' : Mid Perf MD = 15,241' GENERAL WELL INFO APE 50-029-22621-00-00 Drilled and Cased by Nabors 22E -12/6/1995 Pert, Frac & Run ESP Completion by Polar #1-5/25/1996 ESP Changeout by Nabors 4ES -12/9/1998 ESP Changeout by Nabors 4ES -10/2/1999 ESP Changeout by Nabors 4ES-3/23/2002 Pull ESP Service and Re -run by Nabors 4ES-11/29/2003 Perforate & ESP Changeout by Nabors 4ES-6/25/2005 ESP Changeout by Doyon 16 -12/18/2013 Revised By TDF: 12/17/2019 K klilcom Alaska, LLC. Orifi. KB Elev.: 46 / Odg. GL Elev.:16.5' TO=15,655(MD) /TD=7,628(TVD) PBTD=15,551'(MD) / PBTD= 7,547(TVD) PROPOSED Milne Point Unit Well: MPU L-25 Last Completed: 12/18/2013 PTD: 195-180 TREE & WELLHEAD Tree 2-9/16"x11"-SMFMC Wellhead 11" SM FMC Gen 4,w/11"Gen 5 ESP w/2-7/8"FMCTbg. Top Hngr., EUE Lift Threads, 2-7/8" CIW "H" BPV profile OPEN HOLE / CEMENT DETAIL 20" 250 sx of Arcticset I (Approx) in 24" Hole 9-5/8" 1,750 sx PF'E', 250 sx Class V, 150 sx PFT in 12-1/4" Hole 7" 240 sx Class "G"in 8-1/2" Hole WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle = 69 to 74 deg. f/ 3,600' to 13,150' Max Hole Angle through perforations = 40 deg. CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 112' 9-5/8" Surface 40 / L-80 / Btc. 8.835 Surface 9,019' 7" Production 26/L-80/BTC&MBTC 6.276 Surface 15,636' TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUEBrd 1 2.347 1 Surface 1 ±15,077' JEWELRY DETAIL No Depth Item 1 ±200' GLM #3: 2 13,775' GLM #2: 3 ±3,800' Packer: 4 ±3,820' 2 -7/8"X -Ni le 2.313 ID 5 ±14,960' GLM #1: 6 ±15,007' 2-71W XN-Nipple (2.205 No-go ID) 7 ±15,008' Discharge Head 8 115,025' Pump: 9 ±15,032' Gas Separator: 10 ±15,037' Upper Tandem Seal: 11±15,044' 15,282' Lower Tandem Seal: 12 ±15,051' Motor 13 ±15,073' Pum mate 14 ±15,075' Centralizer: Bottom @±15,077' STIMULATION DETAIL Frac d w/ 110,500# of 16/20 Carbolite behind pipe PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk C,B ±15,135' ±15,173' ±7,228' ±7,257' 38 Future Future KuparukB 15,174' 15,180' 7,258' 7,262' 6 4/20/1996 Open 15,230' 15,250' 7,300' 7,315' 20 6/23/2005 Open KuparukA 15,250' 15,282' 7,315' 7,340' 32 N/A Open 15,278' 15,308' 7,337' 7,360' 30 6/23/2005 Open Kuparuk AlB ±15,309' ±15,336' ±7,360' ±7,381' 27 Future Future Ref Log: 4/10/1996 -GR / CCL: Mid Perf TVD = 7,308' : Mid Perf MD =15,241' GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E - 12/6/1995 Perf, Frac & Run ESP Completion by Polar #1-5/25/1996 ESP Changeout by Nabors 4ES - 12/9/1998 ESP Changeout by Nabors 4ES - 10/2/1999 ESP Changeout by Nabors 4ES-3/23/2002 Pull ESP Service and Re -run by Nabors 4ES -11/29/2003 Perforate &. ESP Changeout by Nabors 4ES - 6/25/2005 ESP Changeout by Doyon 16 -12/18/2013 Revised By TDF: 1/7/2020 THE STATE °f11. GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU L-25 Permit to Drill Number: 195-180 Sundry Number: 319-572 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. a o g c c, a l a s ka. g o v Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, essi ielowski Commissioner DATED this 2-b day of December, 2019. RBDMS '*.IAM 0 2 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 90 DDC 95 280 DEC 17 2919 Z-1 Zo 111 i' O G °+ C 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 Snap Well ❑ Alter Casing ❑ Other: ESP Change -out ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: C)o , z Hilcorp Alaska LLC Exploratory ❑ Development Stratigraphic ❑ Service ❑ 195-180 ' 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-22621-00-00 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 ❑ Nft MILNE PT UNIT L-25 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0355017 �japLo0ZS50 � g 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): 15,655' 7,628' 15,551' 7,547' 3,073 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 112' 112' N/A N/A Surface 8,988, 9-5/8" 9,019' 4,711' 5,750psi 3,090psi Production 15,608' 7" 15,636' 7,614' 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 / EUE8rd 15,077' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A and N/A NA/ and N/A 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: 1/3/2020 Commencing Operations: OIL WINJ ❑ EJWDSPL F] Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without priorwritten approval. Authorized Name: Chad Helgeson Contact Name: Ian Toomey Authorized Title: Operations Manager Contact Email: It00me hllCof .Corn Contact Phone: 777-8434 Authorized Signature: Date:) Z 1 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ / u Other: y-3S©D /05i. &-11Q.x,/1 C�" (�T y+ J /3BDMS tri`' 0 2 2020 Post Initial Injection MIT Req'd? Yes ❑ No ❑ .)AN Spacing Exception Required? Yes ❑ No �/ Subsequent Form Required: /0 APPROVED BY Approved by: i ✓liCOMMISSIONER THE COMMISSION Date: 'Zy\ 1z1g111 ORIGINAL m 10-aoa Revised 4/2017 Approved application is valid for 12 months from the date of approval. '/ 4 SubmR Form and Attachments in Duplicate vTJ A`I;12J1 S'�l4 U Ililam , Alk., LU ESP Changeout Well: MPU L-25 Date: 12-17-19 Well Name: MPU L-25 API Number: 50-029-22621-00-00 Current Status: SI - ESP Producer Pad: L -Pad Estimated Start Date: January 3`^, 2020 Rig: ASR Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 195-180 First Call Engineer: Ian Toomey (907) 777-8434 (0) (907) 903-3987 (M) Second Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) AFE Number: Job Type: ESP Swap Most recent SBHP (11/04/19): 3,785 psi @ 7,124' TVD EMW = 10.22 ppg; KWF = 10.5 ppg Maximum Expected BHP: 3,785 psi @ 7,124' TVD EMW = 10.22 ppg MPSP: 3,073 psi Gas Column Gradient = 0.1 psi/ft Max Inclination 74° @ 4,876' MD p p` co Max Dogleg: 4.5'/100ft @ 2,037' MD K �SI t Tree: Cameron 2-9/16"5M Wellhead: FMC Gen 5, 11" x 11" 51A Tubing Hanger Lift threads: 2-7/8" EUE 8rd top & bottom BPV Profile: 2-1/2" CIVV Type H Brief Well Summary: Well L-25 was drilled by Nabors 22E in December 1995 and completed by Polar #1 in May 1996 in the Kuparuk B and C sands. There have been 7 previous ESP swaps on this well with an average run life of 994.5 days (2.73 years). The current ESP failed on 2/8/19 due to a downhole short after a run life of about 5 years (8 year run c life on the previous ESP installed). Notes Regarding the Well & Design • 7" Casing MIT to 2,500 psi passed on 9/30/1999 • Offset Injector Support o F-49: SI on 6/27/19. o F-89: SI on 6/28/19. Objective: • Pull 2-7/8" ESP completion • Pressure test the 7" casing. • Install new 2-7/8" ESP completion with packer and dual vent valves. ESP Changeout I[ilcoru Alaska, LL Well: MPU L-25 Date: 12-17-19 Pre -Rig Procedure: 1. RU slickline. 2. Pull DV from GLM at 14,820' MD. Leave pocket open. 3. RD Slickline Unit 4. RU LRS and PT lines to 3,000 psi. 5. Bleed gas to 0 psi on the tubing and IA (if needed). �4 6. Circulate a minimum 550 bbls oLIQ.5 on¢ NaCl/Naar down the tubing taking returns up the IA to the kill tank until clean 10.5 ppg brine is seen at surface 7. Monitor to confirm the well is dead. If not, contact Operations Engineer and record SITP/SICP. Note: Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. True crystallization temperature (TCT) of 10.5 ppg NaCl/NaBr = AWF. 8. RD Little Red Services. 9. RD well house and flowlines. Clear and level pad area around the well. Spot rig mats and containment. 10. RU crane. Set 2-1/2" HP BPV. NO Tree. Inspect the lift threads on the tubing hanger. Install plug off tool into the BPV. 11. NU 11", 5M BOPE with two sets 2-7/8" x 5" VBR's. RD Crane. 12. RU BOPE house. Spot the mud boat. RWO Procedure: Ask *i- 13. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank. 14. Test BOPE to 250/3,500 psi and annular to 250/3,500 psi. a. Notify the AOGCC 24 hours in advance of BOP test. b. Perform test per ASR #1 BOPE test procedure dated 11/3/15. C. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR's and annular with 2-7/8" and 3-1/2" test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. Contingency: If BOPE test fails a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test if test witness was waived. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) 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. 15. RU to pull 2-7/8" ESP completion. 0 Iiilcuru Alaska, LL ESP Changeout Well: MPU L-25 Date: 12-17-19 16. Pull plug off tool, check for pressure under the BPV, if needed kill the well with KWF and pull the BPV. 17. MU the landing joint to the tubing hanger, BOLDS, unseat the tubing hanger and pull to the rig floor. a. Strip PU = 124K and SO = 65K when landed by Doyon 16 (block weight = 40K) in 10.8 ppg brine. 18. Lay down the landing joint and tubing hanger. RU to pull ESP over sheaves to spooling units. a. Inspect the tubing hanger and note any corrosion or damage. 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 and sundry. 19. POOH laying down the 2-7/8" tubing spooling ESP cable and removing all jewelry as it presents itself. Lay down ESP components. a. Note any corrosion, sand, or scale on the tubing with associated depths and ESP components on the morning report. Equipment Disposition Tubing hanger Tubing & Pup joints Gaslift Mandrels/Nipple ESP equipment/Power Cable Visually inspect on site then reuse, restock orjunk Junk Junk Centrilift to take possession for inspection and teardown Capillary Tubing Junk Protectorlizer (6) Visually inspect on site then reuse, restock orjunk Cannon clamps (244) Visually inspect on site then reuse, restock orjunk Flat cable guard (3) Visually inspect on site then reuse, restock orjunk 20. RD ESP pulling equipment. 21. PU and MU cleanout assembly. a. Junk mill or tri -cone bit b. 7" casing scraper c. Bumper sub d. Oil jars 22. RIH with cleanout assembly on 3-1/2" work string to the top of the perforations at 15,174' MD. 23. Cleanout down to 15,400' MD (PBTD is 15,551' MD). 24. Circulate the well clean at max rate. 25. POOH laying down work string and cleanout assembly. 26. PU, MU and RIH with 7" test packer on 3-1/2" work string to ±13,200' MD. 27. Set the test packer with center of element at ±15,100' MD. Ensure the IA is fluid packed and PT the IA — to 2.500 psi for 30 minutes charted Zt7 a. If the test fails, notify the operations Engineer. Begin moving up hole, testing in intervals to identify the leak point. 28. POOH laying down work string and 7" test packer/cleanout assembly. 29. RU to run ESP completion. 30. PU and MU new Baker ESP assembly. Set base of ESP assembly at ±15,077' MD. Check electrical integrity test every 1,000'. Install clamps on the first 15 joints then every otherjoint to surface. a. Motor centralizer H IIiI..0 Akskx, LU b. Motor gauge unit, Zenith c. ESP motor, 562, 150 HP, 2420 V, 38 A d. Lower tandem seal, GSB3DB H6 e. Upper tandem seal, GSB3DB H6 f. Gas separator, 538 GSHVV g. Pump, 134 Flex h. Ported discharge head, Zenith i. Bolt on discharge head, 2-7/8", 6.5#, L-80, EUE 8rd box up j. 1 joint, 2-7/8", 6.5#, L-80, EUE 8rd tubing k. Nipple, HES 2.313" XN (2.205" no-go) with 10' handling pups above and below 2 joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing ESP Changeout Well: MPU L-25 Date: 12-17-19 m. GLM, 2-7/8" x 1", DV installed with 10' handling pups above and below n. XXX joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing o. Nipple, HES 2.313" X with 10' handling pups above and below, RHC plug body installed p. 1 joint, 2-7/8", 6.5#, L-80, EUE 8rd tubing / q. Packer, Viking ESP retrievable with dual vent valves (setting depth = ±3,800' MD) " 31. PU and MU the Viking packer. Verify that there are 4 setting shear pins and 18 shear to release pin. 32. Terminate the ESP cable and MU the ESP penetrator to the ESP cable. Ensure the 3/8" NPT control line feed thru port is dummied off. 33. MU the control line to the dual vent valves. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in WelIEZ). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while RIH. 34. Continue to RIH with ESP completion. Check electrical integrity test every 1,000'. r. 1 joint, 2-7/8", 6.5#, L-80, EUE 8rd tubing s. GLM, 2-7/8" x 1", DV installed with 10' handling pups above and below t. XXX joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing u. GLM, 2-7/8" x 1", DV installed with 10' handling pups above and below (setting depth = ±200' MD) v. X joints, 2-7/8", 6.5#, L-80, EUE 8rd tubing 35. PU and MU the new 2-7/8" tubing hanger. Make final splice of the ESP cable to the penetrator, MU the control line to the tubing hanger and dummy off any additional control line ports if present. 36. Pressure up on the control line to 5,000 psi and hold for 5 minutes checking for leaks (note the opening pressure in WeIIEZ). Bleed the pressure to 500 psi and lock it in to maintain 500 psi while landing the hanger. 37. Land tubing hanger with extreme caution to avoid damaging the ESP cable, penetrator or control line. RILDS. Record PU and SO weights on tally and WeIIEZ. 38. Drop the ball & rod and allow time for it to gravitate to the ball seat. l A_39. Pressure up on the tubing to 2,500 psi and hold for 5 minutes to set the packer. Bleed the tubing pressure to 0 psi. 40. Bleed the control line pressure to 0 psi to close the vent valves. 41. Pressure test the IA to 1,500 psi for 30 minutes on chart recorder._ 42. Slowly bleed the IA pressure to 0 psi. ESP Changeout Well: MPU L-25 Illk.p Alaska, LL Date: 12-17-19 43. Set 2-1/2" HP BPV. Post -Rig Procedure: 44. RD mud boat. RD BOPE house. Move to next well location. 45. RU crane. ND BOPE. Install plug off tool 46. NU the tubing head adapter and 2-9/16", 5M tree. PT tubing hanger void to 500/5000 psi. PT the tree to 250/5000 psi. 47. Pull plug off tool and BPV. 48. RD crane. Move returns tank and rig mats to next well location. 49. Replace gauge(s) if removed. 50. Turn well over to production via handover form. RU well house and flowlines. 51. RU HES slickline. 52. Pull the ball and rod. r P� c��(. f/ic✓� �'—� 53. Pull DV from GLM #3 and install OV. 2 uo 54. Pull RHC plug body. 55. RD HES slickline. Note: Freeze protect is up to the discretion of the Wells Supervisor/Foreman depending on timing for the well to be POP. True crystallization temperature (TCT) of 10.5 ppg NaCl/Naar = -4.4°F Attachments: 1. Current schematic 2. Proposed schematic 3. BOP Schematic 4. Blank RWO MOC Form K Hileoru Alaska, LLC Orig. KB Elev.: 46' (Nabors 22E) TD=15,655' (MD) / TD = 7,628'(TVD) PBTD=15,551'(MD) / PBTD = 7,547'(f VD) SCHEMATIC Milne Point Unit Well: MPU L-25 Last Completed: 12/18/2013 PTD: 195-180 TREE & WELLHEAD Tree 2-9/16" x 11" - SM FMC Wellhead 11" SM FMC Gen 4,w/11"Gen 5 ESP w/2-7/8"FMC Tbg. H ngr., EUE Lift Threads, 2-7/8" CIW "H" BPV profile OPEN HOLE/ CEMENT DETAIL 20" 250 as of Arcticset I (Approx) in 24" Hole 9-5/8" 1,750 sx PF 'E', 250 sx Class V, 150 sx PF'E' in 12-1/4" Hole 7" 240 sx Class "G" in 8-1/2" Hole WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle= 69 to 74 deg. f/ 3,600't. 13,150' Max Hole Angle through Perforations= 40 deg. CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 1 112' 9-5/8" Surface 40/L-80/Btc. 8.835 Surface 9,019' 7" Production 26/L-80/BTC&MBTC 6.276 1 Surface 15,636' TUBING DETAIL 2-7/S" Tubing 6.5/L-80/EUE 8rd 2.347 Surface 15,077' JEWELRY DETAIL No Depth Item 1 143' amco 2-7/8" x 1" DummAModel-PMSXD 2 14,820' amco 2-7/8" x 1" Side P3 7,258'1 14,964' -Nipple(2.205 No-go ID)4 4/20/1996 15,007' M#1: Head5 15,250' 15,008' dem Pump:Type-119P26 20 15,025' dem Pump:Type-18P757 KuparukA 15,250' 15,032' tor: GRSFTXARH6 8 15,037' Upper Tandem Seal: GSB3DBUTSB 9 15,044' Lower Tandem Seal: GSB3DBUTSB/SB PFSA 10 15,051' Motor: CL5 MSP1250, 294hp/2,315V/77A 11 15,073' Pumpmate 12 1 15,075' 1 Centralizer: Bottom @ 15,077' STIMULATION DETAIL Frac'd w/ 110,500# of 16/20 Carbolite behind pipe PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Kuparuk B 15,174' 15,180' 7,258'1 7,262' 6 4/20/1996 Open 15,230' 15,250' 7,300' 7,315' 20 6/23/2005 Open KuparukA 15,250' 15,282' 7,315' 7,340' 32 N/A Open 15,278' 15,308' 7,337' 7,360' 30 6/23/2005 Open Ref Log: 4/10/1996-GR/CCL: Mid PerfTVD=7,308': Mid PerfMD=15,241' GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E - 12/6/1995 Perf, Frac & Run ESP Completion by Polar #1- 5/25/1996 ESP Changeout by Nabors 4ES -12/9/1998 ESP Changeout by Nabors 4ES -10/2/1999 ESP Changeout by Nabors 4ES-3/23/2002 Pull ESP Service and Re -run by Nabors 4ES -11/29/2003 Perforate & ESP Changeout by Nabors 4ES-6/25/2005 ESP Changeout by Doyon 16 -12/18/2013 Revised By TDF: 12/17/2019 n IIileom Aleeha, LLC Orig. KB Elev.: 46 / Orig. GL Elev.: 16.5 PROPOSED Milne Point Unit Well: MPU L-25 Last Completed: 12/18/2013 PTD: 195-180 TREE & WELLHEAD Size Tree 2 -9/16"x11" -5M FMC Wellhead 11" 5M FMC Gen 4, w/ 11" Gen 5 ESP W/ 2-7/8" FMC Tbg. Hngr., EUE Lift Threads, 2-7/8" CIW "H" BPV profile Size OPEN HOLE/ CEMENT DETAIL Wt/ Grade/ Conn 20" 250 sx of Arcticset I (Approx) in 24" Hole Top 9-5/8" 1,750,xPF'E', 250 sx Class'G', 150 sx PF'E' in 12-1/4" Hole F/ 7" 240 sx Class "G" in 8-1/2" Hole 91.1/H-40/N/A N/A Surface WELL INCLINATION DETAIL OIY KOP @ 500' 40/L-80/Btc. Max Hole Angle =69 to 74 deg. f/ 3,600'to 13,150' Surface Max Hole Angle through perforations = 40 deg. 7" CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 91.1/H-40/N/A N/A Surface 112' 9-5/8" Surface 40/L-80/Btc. 8.835 Surface 9,019' 7" Pr.d.cton 2L/L-80/BTC&MBTC 6.276 Surface 15,636' TD= 15,655' (MD) /TD=7,628'(TVD) PBTD=15,551'(MD) / PBTD= 7,547(TVD) TUBING DETAIL 2-7/8" Tubing 6.5/L-SO/EUE Brd 2.347 Surface ±15,077' JEWELRY DETAIL No Depth Item 1 ±200' GLM #3: d 2 ±3,775' GLM#2: 3 1:3,800' Packer: 4 ±3,820' 2-7/8" X -Nipple (2.313 ID) 5 ±14,964 GLM#1: 6 ±15,007' 2-7/8" XN-Nipple (2.205 No-go ID) 7 ±15,008' Discharge Head 8 ±15,025' 15,282' 9 ±15,032' or:10 N/A ±15,037' m Seal:11 15,278' ±15,044' m Seal:12 Mp 7,360' ±15,051' 6/23/2005 13 ±15,073' CCL: Mid Perf 14 ±15,075' Bottom @ ±15,077' STIMULATION DETAIL Fmed w/ 110,500# of 16/20 Carbolite behind pipe PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status KuparukB 15,174' 15,180' 7,258' 7,262' 6 4/20/1996 Open 15,230' 15,250' 7,300' 7,315' 20 6/23/2005 Open KuparukA 15,250' 15,282' 7,315' 7,340' 32 N/A Open 15,278' 15,308' 7,337' 7,360' 30 6/23/2005 Open Ref Log: 4/10/1996 - GR / CCL: Mid Perf TVD = 7,308': Mid Perf MD =15,241' GENERAL WELL INFO API: 50-029-22621-00-00 Drilled and Cased by Nabors 22E -12/6/1995 Perf, Frac & Run ESP Completion by Polar#1 - 5/25/1996 ESP Changeout by Nabors 4E5 -12/9/1998 ESP Changeout by Nabors 4E5 -10/2/1999 ESP Changeout by Nabors 4ES - 3/23/2002 Pull ESP Service and Re -run by Nabors 4ES-11/29/2003 Perforate & ESP Changeout by Nabors 4ES - 6/25/2005 ESP Changeout by Doyon 16-12/18/2013 Revised By TDF: 12/17/2019 a a I-� E i a w R W) N J D a o Y.. 3 a N V 0 IL a C N a 0 G C a 0 N d L7) e m _ A i Q to L 0 n CL Em IP R O =dam d > R =�o U m c C9 0 0 ¢ Qa a w d R Y c x a" CL am a w Y omM cc C x y = v am CD LSI c R U i a m U O a` d b D d LSI m CL CL y 0 n CL Em IP R O H Milne Point ASR 11" BOP (Triple) 2019 11" BOPE Updated 6/21/18 )r Pipe Rams 3R or Pipe Rams nd Rams • STATE OF ALASKA '. AU,--.SKA OIL AND GAS CONSERVATION COiwiIIISSION REPORT OF SUNDRY WELL OPERATIONS AOGCC 1. Operations Performed: ❑Abandon 0 Repair Well 0 Plug Perforations 0 Perforate 0 Re-Enter Suspended Well 0 Alter Casing ® Pull Tubing 0 Stimulate-Frac 0 Waiver 0 Other ❑Change Approved Program 0 Operation Shutdown 0 Stimulate-Other 0 Time Extension Change Out ESP 2. Operator Name: 4. Well Class Before Work: 5. Permit To Drill Number: BP Exploration(Alaska) Inc. 0Exploratory 0Stratigraphic • 195-180 3. Address: IN Development 0 Service 6. API Numbe P.O. Box 196612,Anchorage,Alaska 99519-6612 . 50-029-22621-00-00 7. Property Designation(Lease Number): 8. Well Name and Number: ADL 025509&3550174 MPL-25 9. Logs(list logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): • Milne Point Unit/Kuparuk River Oil 11. Present well condition summary: Total depth: measured 1 15655' feet Plugs:(measured) None feet true vertical 7628' feet Junk:(measured) None feet Effective depth: measured % 15551' feet Packer: (measured) None feet true vertical 7547' feet Packer: (true vertical) None feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 32'- 112' 32'- 112' 1490 470 Surface 8988' 9-5/8" 31'-9019' 31'-4711' 5750 3090 Intermediate Production 15608' 7" 28'- 15636' 28'-7614' 7240 5410 Liner JUL1 6 2014 SCANNED Perforation Depth: Measured Depth: 15174'- 15308' feet True Vertical Depth: 7258'-7360' feet Tubing(size,grade,measured and true vertical depth): 2-7/8",6.5# L-80 15077' 7185' Packers and SSSV(type,measured and true vertical depth): None None None 12.Stimulation or cement squeeze summary: Intervals treated(measured): Treatment description 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: 276 106 705 300 244 Subsequent to operation: 272 73 935 320 358 14.Attachments: ❑Copies of Logs and Surveys run 15.Well Class after work: 0 Exploratory 0 Stratigraphic ®Development 0 Service ®Daily Report of Well Operations 16. Well Status after work: 9 ®Oil 0 Gas 0 WDSPL ®Well Schematic Diagram 0 GSTOR 0 WINJ 0 WAG 0 GINJ 0 SUSP 0 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: Contact: J.E.B.Bolen,564-5110 Email: J.E.B.Bolen@bp.com N/A Printed Name: Joe Lastu aTitle: Drilling Technologist Signature: / 564-4091 Date: 1 /13j/4-- Form 13II4'Form 10-404 Revised 10/2012 Submit Original Only North America-ALASKA-BP Page 1 of 7 Operation Summary Report Common Well Name:MPL-25 AFE No Event Type:WORKOVER(WO) Start Date:12/13/2013 End Date:12/18/2013 X4-00XXC-E:(2,100,001.00) Project:Milne Point Site:M Pt L Pad Rig Name/No.:DOYON 16 Spud Date/Time:11/1/1995 12:00.00AM Rig Release:12/18/2013 Rig Contractor DOYON DRILLING INC. UWI:500292262100 Active datum:ORIG KELLY BUSHING @36.00usft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (usft) 12/13/2013 09:00 - 10:00 1.00 MOB P PRE SECURE CELLAR AND RIG FLOOR FOR TRAVEL. 10:00 - 11:30 1.50 MOB P PRE PJSM WITH ALL CREWS FOR MOVING OFF WELL. JACK UP RIG,MOVE RIG OFF WELLAND SET DOWN ON OTHER SIDE OF PAD. MOVING OFF WELL IS WITNESSED BY TOOLPUSHER,DDI SUPT AND WSL. 11:30 - 20:00 8.50 MOB P PRE PJSM TO CHANGE OUT ANNULAR MOVE BOP OFF STUMP ONTO RIG MATS BREAK DOWN BOP STACK CHANGE OUT ANNULAR PREVENTER. MAKE STACK BACK UP MOVE MADE UP BOP BACK TO STUMP IN CELLAR 20:00 - 20:30 0.50 MOB P PRE PREPARE TO MOVE OVER WELL MOVE RIG FORWARD LAY MATS AROUND WELL 20:30 - 22:00 1.50 MOB P PRE PJSM BACK RIG OVER MPL-25 -NOTIFY PAD OPERATOR. -SPOT RIG OVER MPL-25 -WSL&NIGHT TOOLPUSHER PRESENT 22:00 - 00:00 2.00 MOB P PRE RIG UP ON MPL-25 -SHIM UP AROUND RIG AND LEVEL SAME -SPOT CUTTINGS TANK AND CREW CHANGE TRAILER ACCEPT RIG AT 00:00 HRS 12-14-2013 ON MPL-25 12/14/2013 00:00 - 06:00 6.00 MOB P PRE SPCC CHECKS AND PRE-TOUR MEETING ACCEPT DOYON 16 ON MPL-25 AT 00:00 12-14-13 -LOAD PITS WITH 10.8#BRINE(TEMP:100 F) PJSM,RU CIRCULATING EQUIPMENT. -RU HARD LINE TO FLOW BACK TANK -R/U KILL MANIFOLD IN CELLAR. -WARM LINE AND FILL TO TEST WITH DIESEL. -PRESSURE TEST KILL MANIFOLD AND HARD LINE. -250/3500 PSI FOR 5 CHARTED MIN. OA:0 PSI,IA:1250 PSI 06:00 - 06:30 0.50 MOB P PRE RIG EVAC DRILL FOR H2S. CONDUCT AAR WITH TOURPUSHER,RIG CREW AND WSL. 06:30 - 09:00 2.50 BOPSUR P PRE RIG UP WELLS SUPPORT LUBRICATOR,PT TO 250/3500 PSI,GOOD. PULL BPV,RIG DOWN WELLS SUPPORT LUBRICATOR. TUBING IS 1050 PSI,IA=1250 PSI,OA=0 PSI. 09:00 - 09:30 0.50 BOPSUR P PRE PJSM FOR WELL KILL WITH ALL CREWS. • Printed 12/30/2013 11:27:55AM • • North America-ALASKA-BP Page 2 of 7 Operation Summary Report Common Well Name:MPL-25 AFE No Event Type:WORKOVER(WO) Start Date:12/13/2013 End Date:12/18/2013 X4-00XXC-E:(2,100,001.00) Project:Milne Point Site:M Pt L Pad Rig Name/No.:DOYON 16 Spud Date/Time:11/1/1995 12:00:00AM Rig Release:12/18/2013 Rig Contractor:DOYON DRILLING INC. UWI:500292262100 Active datum:ORIG KELLY BUSHING @36.00usft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (usft) 09:30 - 14:00 4.50 BOPSUR P PRE MAKE NOTIFICATIONS THEN START BLEEDING GAS OFF IA. BLEED IA FROM 1300 PSI TO 950 PSI, GETTING MOSTLY FLUID BACK AT THAT POINT. PUMP 3 BPM DOWN TUBING,TAKE RETURNS FROM IA. ICP=2000 PSI,FCP=1350 PSI AT 3 BPM. AFTER 1 TUBING VOLUME SHUT IN WELL, BULLHEAD 2X VOLUME BELOW TUBING HOLE TO PERFS AT 3 BPM. FCP AFTER BULLHEADING IS 2250 PSI,2650 PSI ON IA,0 PSI CN OA. SHUT DOWN PUMP AND ALLOW PRESSURES TO BLEED OFF FOR 5 MIN. OPEN WELLAND START CIRCULATION KILL, HOLD 1400 PSI TUBING PRESSURE AT 3 BPM. START EASING RATE UP TO FINAL CIRC RATE OF 3.8 BPM AT 2200 PSI TUBING PRESSURE. GET 10.8 PPG WATER BACK AFTER TOTAL OF 719 BBLS PUMPED. CONTINUE CIRCULATING 1.5XANNULUS VOLUME,EASE RATE UP TO 4.2 BPM AFTER GETTING WATER BACK. 14:00 - 15:30 1.50 BOPSUR P PRE SHUT DOWN AND MONITOR PRESSURES. AFTER 1.5 HRS TUBING PRESSURE FALLS STEADILY FROM 56 PSI TO 2 PSI. IA PRESSURE FALLS FROM 63 PSI TO 11 PSI. 15:30 - 17:30 2.00 BOPSUR P PRE OPEN BOTH TUBING AND IA TO A BUCKET TO CHECK FOR FLOW. BOTH CONFIRMED STATIC. START RIGGING DOWN CIRC SKID. ESTABLISH LOSS RATE=3 BPH,10.8 PPG BRINE 17:30 - 19:30 2.00 BOPSUR P PRE PJSM ON R/U LUBRICATOR AND SETTING TWC -R/U LUBRICATOR,CHART TEST 250 PSI LOW,3500 PSI HIGH -PERFORM ROLLING TEST FROM BELOW TWC -PUMP BBLS @ 3 BPM=500 PSI.CHART FOR 5 MINUTES -TEST TWC FROM ABOVE 250 PSI LOW AND 3500 PSI HIGH,CHARTED 19:30 - 21:00 1.50 BOPSUR P PRE PJSM TO DRAIN AND NIPPLE DOWN TREE AND N/U BOPE -BLOW DOWN LINES,SUCK OUT TREE, -FMC REP BLEED HANGER VOID AND CHECK LOCK DOWN SCREWS -NIPPLE DOWN TREE -FMC REP CLEAN AND INSPECT EUE 8RD HANGER THREADS -CONFIRM 10 TURNS BY HAND Printed 12/30/2013 11:27:55AM • North America-ALASKA-BP Page 3 of 7 Operation Summary Report Common Well Name:MPL-25 AFE No Event Type:WORKOVER(WO) Start Date:12/13/2013 End Date:12/18/2013 X4-00XXC-E:(2,100,001.00) Project:Milne Point Site:M Pt L Pad Rig Name/No.:DOYON 16 Spud Date/Time:11/1/1995 12:00:00AM Rig Release:12/18/2013 Rig Contractor:DOYON DRILLING INC. UWI:500292262100 Active datum:ORIG KELLY BUSHING©36.00usft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (usft) 21:00 - 00:00 3.00 BOPSUR P PRE PJSM,NIPPLE UP BOP -N/U 13-5/8"5M BOP STACK. -INSTALL TURNBUCKLES AND FLOW NIPPLE. -RE-ENERGIZE ACCUMULATOR SYSTEM. -R/U TEST EQUIPMENT MANITAIN CONTINUAL HOLE FILL AT 5 BPH OF 10.8 PPG BRINE 24 HR LOSSES=218 BBLS KWF 12/15/2013 00:00 - 06:00 6.00 BOPSUR P PRE SPCC CHECKS AND PRE-TOUR MEETING FINALIZE NIPPLE UP OF BOP STACK AND RIG UP OF TEST EQUIPMENT PJSM,TEST FOUR PREVENTER BOP AND RELATED EQUIPMENT -TEST ANNULAR WITH 2 7/8"TEST JOINT TO 250 PSI LOW,3500 PSI HIGH,5 MINUTES EACH,CHARTED -TEST 2 7/8"X 5"VARIABLE RAMS WITH 2 7/8" &4"TEST JOINTS,250 PSI,3500 PSI,5 MIN, CHARTED -TEST BLIND RAMS,FLOOR VALVES,AND CHOKE MANIFOLD TO 250 PSI,3500 PSI,5 MIN,CHARTED -TEST WITH FRESH WATER. -NO FAILURES. -RIG DOWN TEST EQUIPMENT -AOGCC,JEFF JONES WAIVED STATES RIGHT OF WITNESS BOP TEST 06:00 - 07:00 1.00 BOPSUR P PRE RIG DOWN TEST EQUIPMENT. DRAIN STACK. RIG UP DSM LUBRICATOR. 07:00 - 09:00 2.00 BOPSUR P DECOMP PRESSURE TEST DSM LUBRICATOR 250/ 3500 PSI,GOOD. PULL TWC. RIG DOWN AND OFFLOAD WELLS SUPPORT EQUIPMENT. 09:00 - 10:00 1.00 PULL P DECOMP VAC OUT STACK. MAKE UP LANDING JOINT. PREP FOR PULLING COMPLETION. RIG UP CENTERLIFT EQUIPMENT ON RIG FLOOR. 10:00 - 11:00 1.00 PULL P DECOMP MAKE UP LANDING JOINT TO HANGER. FMC BACK OUT LDS. PULL HANGER TO FLOOR AND 1 FULL JOINT. CUT CABLE THEN RUN FULL JT BACK IN ACROSS BOP STACK 11:00 - 12:00 1.00 PULL P DECOMP CLOSE ANNULAR,CIRC 1 TUBING VOLUME THROUGH MGS. SHUT DOWN AND MONITOR WELL,WELL IS STATIC. 12:00 - 13:30 1.50 PULL P DECOMP OPEN ANNULAR,LAY DOWN HANGER AND LANDING JT. RUN ESP CABLE OUT TO SPOOLING UNIT, ATTACH TO EMPTY DRUM THERE. START PULLING COMPLETION OUT IN STANDS. 13:30 - 14:00 0.50 PULL N RREP DECOMP LOSS OF RIG POWER. RESTART GEN 2 AND TROUBLESHOOT ESD SYSTEM. Printed 12/30/2013 11:27:55AM • • North America-ALASKA-BP Page 4 of 7 Operation Summary Report Common Well Name:MPL-25 AFE No Event Type:WORKOVER(WO) Start Date:12/13/2013 End Date: 12/18/2013 X4-00XXC-E:(2,100,001.00) Project:Milne Point Site:M Pt L Pad Rig Name/No.:DOYON 16 Spud DateTme:11/1/1995 12:00:00AM Rig Release:12/18/2013 Rig Contractor:DOYON DRILLING INC. UWI:500292262100 Active datum:ORIG KELLY BUSHING©36.0ousft(above Mean Sea Level) Date From-To 1 Hrs 1 Task Code NPT NPT Depth Phase Description of Operations (hr) (usft) '14:00 - 18:00 1 4.00 PULL P DECOMP POOH WITH 2-7/8"EUE 8RD TUBING AND ESP 'ASSEMBLY POH WITH TUBING&ESP CABLE -STAND 2-7/8"BACK IN DERRICK 18:00 - 18:30 0.50 PULL P DECOMP KICK WHILE TRIPPING DRILL AAR -QUICK TO ARRIVE TO ASSIGNED LOCATIONS AND COMMUNICATE STATUS -SAFETY VALVE-JOINT WAS EASILY ACCESABLE 18:30 - 22:00 3.50 PULL P DECOMP POOH WITH 2-7/8"EUE 8RD TUBING AND ESP ASSEMBLY POH WITH TUBING&ESP CABLE -STAND 2-7/8"BACK IN DERRICK -POOH TO-7600 FT 22:00 - 23:00 1.00 PULLP CED OMP CHANGE OUT REELS -CENTRALIFT CHANGE REELS IN SPOOLING 1 UNIT 23:00 - 00:00 1.00 PULL P DECOMP POOH WITH 2-7/8"EUE 8RD TUBING AND ESP ASSEMBLY -POH WITH TUBING&ESP CABLE -STAND 2-7/8"BACK IN DERRICK i I -POOH FROM-7600 FT TO-6400 FT MAINTAIN-6 BPH HOLE FILL W/10.8 PPG BRINE 24 HR LOSSES=161 BBLS KWF 12/16/2013 00:00 - 05:00 5.00 PULL P DECOMP SPCC CHECKS AND PRE-TOUR MEETING POOH WITH 2-7/8"EUE 8RD TUBING AND ESP ASSEMBLY -POH WITH TUBING&ESP CABLE -STAND 2-7/8"BACK IN DERRICK -POOH FROM -6400 FT TO-150 FT LAY DOWN JTS#408&456 DUE TO EGGING 05:00 - 05:30 0.50 PULL P DECOMP KICK WHILE TRIPPING DRILL AAR -SAFETY VALVE-JOINT AND ESP CUTTERS WERE ACCESSED EASILY -GOOD COMMUNICATION WITH SPOOLER 05:30 - 06:00 0.50 PULL P DECOMP PJSM WITH CENTRALIFT LAYING DOWN ESP -PULL ESP TO RIG FLOOR -BREAK DOWN PUMP AS PER CENTRALIFT REP 06:00 - 08:00 2.00 PULL P DECOMP LAY DOWN ESP PUMP AND SEAL ASSEMBLY. CLAMPS RECOVERED ILASALLE:236 FLAT GAURDS:3 PROTECTOLIZERS:6 108:00 - 11:30 3.50 RUNCOM P RUNCMP CLEAN AND CLEAR RIG FLOOR. PULL CABLE TAIL OUT TO SPOOLER. RIG DOWN TRUNK. LOAD NEW CLAMPS ONTO RIG FLOOR. CHANGE OUT REELS IN SPOOLING UNIT. ATTACH CABLE SNAKE TO NEW CABLE IN SPOOLER. PULL NEW ESP CABLE UP TO RIG FLOOR. 11 30 - 1800 6.50 RUNCOM P RUNCMP CENTERLIFT TECH BEGIN SPLICE FLAT TO ROUND CABLE ON RIG FLOOR. Printed 12/30/2013 11:27:55AM • North America-ALASKA-BP Page 5 of 7 Operation Summary Report Common Well Name:MPL-25 AFE No Event Type:WORKOVER(WO) Start Date:12/13/2013 End Date:12/18/2013 X4-00XXC-E:(2,100,001.00) Project:Milne Point Site:M Pt L Pad Rig Name/No.:DOYON 16 Spud Date/Time:11/1/1995 12:00:00AM Rig Release:12/18/2013 Rig Contractor:DOYON DRILLING INC. UWI:500292262100 Active datum:ORIG KELLY BUSHING @36.00usft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (usft) 18:00 - 21:00 3.00 RUNCOM P RUNCMP PJSM,MAKE UP ESP MOTOR -P/U SECTIONS OF ESP -SERVICE&ASSEMBLE AS PER CENTRALIFT REP. 21:00 - 22:30 1.50 RUNCOM P RUNCMP PJSM RUN IN HOLE WITH COMPLETION -INSTALL FLAT GAURDS ON PUMP AND MOTOR -INSTALL POTHEAD ON PUMP -CHECK CONDUCTIVITY PRIOR TO RIH. -MAKE UP 1ST JOINT OF TUBING 22:30 - 23:00 0.50 RUNCOM N RREP RUNCMP H2S GAS MONITORING SYSTEM ISSUES -POH AND LAY DOWN 1ST JOINT -PICK UP MOTOR TO RIG FLOOR 23:00 - 00:00 1.00 RUNCOM N RREP RUNCMP ESTABLISH PLAN FORWARD TROUBLE SHOOT SIERRA GAS ALARM SYSTEM MAINTAIN-6 BPH HOLE FILL W/10.8 PPG BRINE 24 HR LOSSES=133 BBLS KWF 12/17/2013 00:00 - 01:00 1.00 RUNCOM N RREP RUNCMP SPCC CHECKS AND PRE-TOUR MEETING. CHECK CROWN-O-MATIC. TROUBLE SHOOT SIERRA GAS ALARM SYSTEM. -CHANGE OUT SENSOR IN PITS. -MONITOR FOR 1 HOUR. • 01:00 - 01:30 0.50 RUNCOM P RUNCMP PJSM,RUN IN HOLE WITH COMPLETION -RE-INSTALL FLAT GAURDS ON PUMP AND MOTOR -MAKE UP 1ST JOINT OF TUBING 01:30 - 09:00 7.50 RUNCOM P RUNCMP RIH WITH 2 7/8"6.5#EUE 8 RD TUBING ESP COMPLETION FROM DERRICK -TUBING TORQUE=2300 FT/LBS. -USE BEST-O-LIFE 2000 PIPE DOPE ON EVERY CONNECTION. -INSTALL CANNON CLAMPS ON EVERY COLLAR ON THE FIRST 9 JOINTS,THEN EVERY OTHER JOINT THEREAFTER. -CHECK ESP CABLE CONDUCTIVITY EVERY 2000'. -PUMP 5 BBLS TO FLUSH THRU PUMP AT 1 BPM 600 PSI.AT 2182'. 580 PSI AT 4066'. 580 PSI AT 5950'. 580 PSI AT 7834'. RIH TO-7800 FT 09:00 - 12:30 3.50 RUNCOM P RUNCMP CENTRALIFT MAKE ESP CABLE SPLICE. -CHANGE OUT CABLE REELS. -CENTRALIFT TECH PERFORM CABLE SPLICE. Printed 12/30/2013 11:27:55AM North America-ALASKA-BP Page 6 of 7 Operation Summary Report Common Well Name:MPL-25 AFE No Event Type:WORKOVER(WO) Start Date:12/13/2013 End Date:12/18/2013 'X4-00XXC-E:(2100,001.00) Project:Milne Point Site:M Pt L Pad Rig Name/No.:DOYON 16 Spud Date/Time:11/1/1995 12:00:00AM Rig Release:12/18/2013 Rig Contractor:DOYON DRILLING INC. I UWI:500292262100 Active datum:ORIG KELLY BUSHING t 36.00usft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth ! Phase Description of Operations (hr) (usft) 12:30 - 19:30 7.00 RUNCOM P RUNCMP 'RIH WITH 2 7/8"6.5#EUE 8 RD TUBING ESP COMPLETION FROM DERRICK. j-RIH FROM-7800 FT TO 15077 FT. -TUBING TORQUE=2300 FT/LBS. -USE BEST-O-LIFE 2000 PIPE DOPE ON 'EVERY CONNECTION. -CHECK ESP CABLE CONDUCTIVITY EVERY 2000'. -PUMP 5 BBLS TO FLUSH THRU PUMP AT 1 BPM&560 PSI EVERY 2000 FT. 19:30 - 22:00 2.50 RUNCOM P RUNCMP PJSM,LANDING TBG HANGER.REP,WSL, FMC,CENTRILIFT REP IN ATTENDANCE. j-LAND HANGER PER FMC REP. '-PU WT=124K,SOW=65K.INCLUDING 40K TOP DRIVE WT. -HANGER SET,ESP CENTRALIZER AT 15077' MD. -RUN IN LOCK DOWN SCREWS PER FMC REP.LD LANDING JOINT. -RAN 224 CANNON CLAMPS,3 FLAT GUARDS, 6 PROTECTORS. 22:00 - 00:00 2.00 RUNCOM P RUNCMP FMC REP T-BAR SET TWC. -ATTEMPT ROLLING TEST FROM BELOW TWC. -1 BPM=500 PSI FOR 5 CHARTED MINUTES. -TEST FROM ABOVE TWC TO 250 PSI LOW AND 3500 PSI HIGH FOR 5 CHARTED MINUTES. -FLUSH LINES,CHOKE MUD PUMP AND POP-OFF. -DRAIN STACK AND FLUSH WITH FRESH WATER. 12/18/2013 00:00 - 01:00 1.00 RUNCOM P RUNCMP SPCC CHECKS AND PRE-TOUR MEETING. CHECK CROWN-O-MATIC. -DRAIN STACK AND FLUSH WITH FRESH WATER. 01:00 - 02:00 1.00 RUNCOM P RUNCMP PJSM,N/D BOPE. 02:00 - 02:30 0.50 RUNCOM P RUNCMP FMC CLEAN AND INSPECT HANGER. -TURN ROTATING HEAD. 02:30 - 03:00 0.50 RUNCOM T P RUNCMP N/U TREE AND ADAPTER. -CENTRALIFT TO CHECK ESP:BOTTOM HOLE PRESSURE=4105 PSI,BOTTOM HOLE TEMPERATURE=174 DEGREES F. 03:00 - 05:00 2.00 RUNCOM P RUNCMP FMC PRESSURE TEST TUBING HEAD ADAPTER TO 5000 PSI FOR 30 CHARTED MINUTES. -CENTRILIFT MAKE FINAL CK ON ESP 05:00 - 06:30 1.50 RUNCOM P RUNCMP R/U&P/T TREE W/DIESEL,5K F/5MIN CHARTED -R/D TEST EQUIP 06:30 - 08:30 2.00 RUNCOM P RUNCMP R/U DSM LUBRICATOR,PIT 250 LOW,3500 HIGH F/5MIN CHARTED. -PULL TWC -R/D LUBRICATOR 08:30 - 13:00 4.50 RUNCOM P ( RUNCMP R/U LRS,P/TLINE TO 250 LOW,3500 HIGH, PUMP 72 BBLS DN I/A TAKEN RETURNS OFF 1 TUBING TO SLOP TANK -PUMP RATE 1.6 BPM @ 500 PSI. -SHUT/DN AND U-TUBE FOR 1 HOUR Printed 12/30/2013 11:27:55AM • North America-ALASKA-BP Page 7 of 7 Operation Summary Report Common Well Name:MPL-25 AFE No Event Type:WORKOVER(WO) Start Date:12/13/2013 End Date: 12/18/2013 X400XXC-E:(2,100,001.00) Project:Milne Point Site:M Pt L Pad Rig Name/No.:DOYON 16 Spud Date/Time:11/1/1995 12:00:00AM Rig Release:12/18/2013 Rig Contractor:DOYON DRILLING INC. UWI:500292262100 Active datum:ORIG KELLY BUSHING t 36.00usft(above Mean Sea Level) Date From-To Hrs ( Task Code NPT NPT Depth Phase Description of Operations (hr) (usft) 13:00 - 15:00 2.00 RUNCOM P RUNCMP P/U LUBRICATOR AND TEST 250 LOW F/5 MIN 3500 HIGH F 5 MIN,CHART -SET BPV• -L/D LUBRICATOR 15:00 - 15 30 0.50 RUNCOM P RUNCMP TEST BPV W/LRS F/5 MIN,CHARTED -PUMP 1BPM @ 590 PSI -FINAL 1 BPM 560 PSI 15:30 - 16:00 0.50 RUNCOM P RUNCMP BLOW DOWN LINES&R/D,SECURE TREE& CELLAR. 16 HR LOSSES=55 BBLS KWF 1 TOTAL LOSSES FOR WELL=696 BBLS 10.8 PPG BRINE RELEASE RIG AT 16:00 HOURS FROM MPL-25 FOR RIG MOVE TO MPL-43 Printed 12/30/2013 11.27:55AM Tree:2-9/16"x 11"-5M FMC L-25 Orig. KB Elev.= 46.'(N 22E) Wellhead:11" 5M FMC Gen. 5 ESP MPU Orig.GL Elev.= 16.5' w/ 2-7/8"FMC Tbg. Hng , EUE RT To 7" hng.=28.5'(N 22E) lift threads,2-7/8" CIW H BPV profile fkr 20" 91.1 ppf, H-40 casing 115' Camco 2-7/8"x 1" 143' KOP @ 500' sidepocket KBMM GLM Max. hole angle=69 to 74 deg. f/3600'to 13,150' Hole angle across perforations =40 deg. 9 5/8", 40#/ft.,L-80 Btrc. 9019'and / 2-7/8"6.5#ppf,L-80,EUE 8rd tbg (drift ID=2.347",cap,=.0058 bpf 7"26 ppf, L-80,BTR casing (drift ID=6.151",cap.=.0383 bpf Camco 2-7/8"x 1" 14820' sidepocket KBMM GLM Intake TVD =7152' 2-7/8"XN nipple 14964' Mid-pert TVD=7308' (No-GO ID 2.205") Mid-pert MD =15241' PBTD TVD =7451 PBTD MD =15561 4, Tandem Pumps,PMsxD 119 P23/18 P75 15008' Stimulation Summary IN Gas Separator 15032' 110.5 M#16/20 Carbolite behind pipe, )'- GRSFTXAR H6 Intake 7152'TVD job went through flush,no ISO indicatio Tandem Seal Section Model GSB3 DB UT/LT 15037' Perforation Summary Ref log: 04/10/96-GR/CCL Motor,250/294 HP,2315 volt, 15050' 77 amp,Model MSP1 Kup.'B'Sand Pumpmate XT-150 15075' w/6 fin Centralizer Size SPF Interval (TVD) Sensor 7183'TVD 3 3/8" 6 15,174'-15,180' (7264'-7269') X 7"x 21'short joint w/RA Tag at top 32 gm.Alpha Jet charges(0.44"EHD 32"TTP) 15,024'-15,045' Kup.'A'Sand Size SPF Interval (TVD) 3 3/8" 6 15,230'-15,250' (7300'-7315') j 3 3/8" 6 15,250'-15,282' (7315'-7340') 3 3/8" 6 15,278'-15,308' (7337'-7360') 7 22 gm.Jumbo Jet charges(6.4"TTP, 0.76"EHD @ 60 deg.random orientation 7"float collar(PBTD) 15,561' Initial SBHP=3195 psia @ 15,266'and -- - 7"csg.shoe 15,636' (7325' TVDss). DATE REV.BY COMMENTS 12/07/95 JBF Drilled and Cased by Nabors_22E MILNE POINT UNIT 4/20198 MDO/M L ESP Completion-Polar RWNabors 4-ES WELL MPL-25 12/10/98 MDO Casins desander/ ESP RWO Nabors 4ES 10/01/99 MDO ESP RWO 4es/Capillary tube installed API NO: 50-029-22621 3/23/02 BMH ESP RWO Nabors 4ES 11/29/03 Lee Hulme ESP RWO Nabors 4ES 6/23/05 Lee Hulme Elective Pull/Add perfs Nabors 4ES BP EXPLORATION (AK) 12/19/13 B. Bixby ESP RWO Doyon 16 0 • bp BP Exploration (Alaska) Inc. 0 Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 I December 30, 2011 P _, FED ` 4 ` z Mr. Tom Maunder I 5- + Alaska Oil and Gas Conservation Commission 1 5 333 West 7 Avenue Anchorage, Alaska 99501 r41 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, a 7 h- ----- --,---. Mehreen Vazir BPXA, Well Integrity Coordinator • 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 N/A 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 WA N/A NA MPL -14 1940680 50029224790000 Sealed conductor N/A N/A N/A N/A NA MPL -15 1940620 50029224730000 3.3 N/A 3.3 WA 15.3 8/9/2011 MPL -16A 1990900 50029225660100 23 Needs top job MPL -17 1941690 50029225390000 0.2 N/A 0.2 WA 5.1 9/1/2011 MPL -20 1971360 50029227900000 0.4 N/A 0.4 WA 3.4 8/10/2011 MPL -21 1951910 50029226290000 1.7 N/A 1.7 WA 8.5 8/10/2011 MPL -24 1950700 50029225600000 0.2 N/A 0.2 N/A 8.5 10/8/2011 - '7ti MPL -25 1951800 50029226210000 1.7 N/A 1.7 N/A 15.3 8/10/2011 MPL -28A 1982470 50029228590100 0.3 N/A 0.3 N/A 8.5 10/8/2011 MPL -29 1950090 50029225430000 0.5 N/A 0.5 N/A 3.4 8/7/2011 MPL -32 1970650 50029227580000 0.5 N/A 0.5 N/A 5.1 8/10/2011 MPL -33 1971050 50029227740000 0.2 N/A 0.2 N/A 8.5 10/8/2011 MPL -34 1970800 50029227660000 1.7 N/A 1.7 N/A 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 N/A 6.8 8/8/2011 MPL -40 1980100 50029228550000 1 N/A 1 N/A 6.8 8/8/2011 MPL-42 1980180 50029228620000 5.3 N/A 5.3 N/A 30.6 8/14/2011 MPL-43 2032240 50029231900000 17.5 Needs top job MPL-45 1981690 50029229130000 10 N/A 10 N/A 8.5 8/10/2011 STATE OF ALASKA ) ALASKA )L AND GAS CONSERVATION COlv,MISSION REPORT OF SUNDRY WELL OPERATIOfi:~,;", 1. Operations Performed: o Abandon o Alter Casing o Change Approved Program o Suspend 0 Operation Shutdown II Perforate 0 Other II Repair Well 0 Plug Perforations 0 Stimulate 0 Re-Enter Suspended Well II Pull Tubing D Perforate New Pool D Waiver 0 Time Extension 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 7. KB Elevation (ft): KBE = 46' 8. Property Designation: ADL 355017 11. Present well condition summary Total depth: measured 15655 true vertical 7628 Effective depth: measured 15551 true vertical 7547 Casing Length Structural Conductor 80' Surface 8988' I nterm ediate Production 15608' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 4. Current Well Class: 1m Development D Exploratory o Stratigraphic 0 Service 5. Permit To Drill Number: 195-180 6. API Number: 50-029-22621-00-00 99519-6612 9. Well Name and Number: MPL-25 10. Field 1 Pool(s): Milne Point Unit 1 Kuparuk River Sands feet feet Plugs (measured) N/A feet Junk (measured) N/A feet Size MD TVD Burst Collapse 20" 112' 112' 1490 470 9-5/8" 9019' 4711' 5750 3090 7" 15636' 7614' 7240 5410 SÇi~NNED ,JUL ü"1 2Dn5 15174' - 15308' 7258' - 7360' Tubing Size (size, grade, and measured depth): Packers and SSSV (type and measured depth): 12. Stimulation or cement squeeze summary: Intervals treated (measured): 2-7/8",6.5# L-80 15079' None None Treatment description including volumes used and final pressure: RBDMS BFl .J U L 0 7 2005 13. Oil-Bbl Prior to well operation: 335 Subsequent to operation: 319 14. Attachments: 0 Copies of Logs and Surveys run 1m Daily Report of Well Operations o Well Schematic Diagram Representative Daily Average Production or Injection Data Gas-Met Water-Bbl CasinQ Pressure ~ 4~ MO 36 489 360 TubinQ Pressure 303 311 15. Well Class after proposed work: D Exploratory 1m Development D Service 16. Well Status after proposed work: II Oil 0 Gas 0 WAG 0 GINJ 0 WINJ D 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: Contact David Reem, 564-5743 Printed Name Sondra Stewman Sign~~~~ Form 10-404 Revised 04/2004 Title Technical Assistant PÕ"R I Gm5j\ L -I . "~Prepared By Name/Number: DatO -C~.D'-"O~Ondra Stewman, 564-4750 Submit Original Only ) ~: 2-9/16"x 11" - 5M FMC Wellhead: 11" 5M FMC Gen. 5 ESP wi 2-7/8" FMC Tbg. Hng , EUE lift threads, 2-7/8" CIW H BPV profile 20" 91.1 ppf, H-40 casing I 115' I' KOP @ 500' Max. hole angle = 69 to 74 deg. fl 3600' to 13,150' Hole angle across perforations = 40 deg. 95/8",40#/ft.,L-80 Btrc·19019' mdl ... 2-7/8" 6.5# ppf, L-80, EUE 8rd tbg (drift ID = 2.347", cap. = .0058 bpf 7" 26 ppf, L-SO, BTR casing (drift ID = 6.151 ", cap. = .0383 bpf Intake TVD = 7152' Mid-perf TVD = 730S' Mid-perf MD = 15241' PBTD TVD = 7451 PBTD MD = 15561 Stimulation Summary 110.5 M # 16/20 Carbo lite behind pipe, job went through flush, no TSO indicatio Perforation Summary Ref log: 04/10/96· GR / CCl Kup. 'B' Sand Size SPF Interval (TVD) 33/8" 6 15,174'-15,1S0' (7264'-7269') 32 gm. Alpha Jet charges (OA4" EHD 32" TTP) Kup. 'A' Sand Size SPF Interval (TVD) 33/8" 6 15,230' -15,250' (7300'-7315') ~ 3 3/8" 6 15,250' -15,2S2' (7315'-7340') t1 33/8" 6 15,278' -15,308' (7337'-7360') ~ 22 gm. Jumbo Jet charges (6A" TIP, ~ 0.76" EHD @ 60 deg. random orientation Initial SBHP = 3195 psia @ 15,266' md (7325' TVDss)" MPU L-25 ~~ ) Orig. KB Elev. = 46.' (N ,??p)" Orig. GL Elev. = 16.5' /'.1"« :;'M,,') RT To 7" hng. = 28.5' (N' 22E)'" Camco 2-7/8" X 1" I I sidepocket KBMM GLM 140' , Cameo 2-7/S" x 1" sidepocket KBMM GLM 2-7/8" XN nipple (No-GO ID 2.205") Tandem Pumps, 122GC2200 & 19GCNPSH GPMTAR 1:1 \14848' I 114991' I. 115005' i 115034' I Gas Separator GRSFTXAR H6 (400 Internals) Intake 7152' TVD Tandem Seal Section I ' Model GSB3 DB UT/L T IL H6 PFS AB HSN 15039 Motor, 195 HP, 2177 volt, 53 amp, Model KMH I 115053' I Phoenix MS-1 w/6 fin Centralizer 115075' I Sensor 7183' TVD .x. 7" x 21' short joint wi RA Tag at top 15,024' - 15,045' DATE 12 / 07 / 95 4120198 12/10198 10/01/99 3/23/02 11/29/03 REV. BY COMMENTS Mdgr M L ~~~<b~~p~ri~~~ ~~I~~~o~cf~~bors 4-ES MDO Cavins desander / ESP RWO Nabors 4ES MDO ESP RWO 4es / Capillary tube installed BMH ESP RWO Nabors 4ES Lee Hulme ESP RWO Nabors 4ES ~ ~ 7" float collar (PBTD) 7" csg. shoe 15,561' 15,636' MILNE POINT UNIT WELL MPL-25 API NO: 50-029-22621 6/23/05 Lee Hulme Elective Pull 1 Add perfs Nabors 4ES BP EXPLORATION (AK) ) ) BPEXPLORATION Oiperatiol1S Summary RepQrt Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPL-25 MPL-25 WORKOVER NABORS ALASKA DRILLING I NABORS 4ES Start: 6/20/2005 Rig Release: 6/25/2005 Rig Number: Spud Date: 11 /1 /1995 End: 6/25/2005 Date From ~ To Hours Task Code NPT Phase Dé$Criþtion Of Operations 6/21 12005 03:00 - 06:30 3.50 MOB P PRE RID. Scope down & lower derrick. Move from MPL-28a to MPL-25. Layout herculite & matting boards. Spot Rig over well. Spot in pipe shed & pits. 06:30 - 08:00 1.50 RIGU P PRE Raise & scope up derrick. R/U rig & equip. 08:00 - 09:00 1.00 RIGU P PRE R/U lines to tiger tank & tree. P/U lubricator & pull BPV. UD lubricator. ACCEPTED RIG @ 0800 hrs. 09:00 - 10:00 1.00 RIGU P DECOMP Take on 120 degree seawater & rig up equip. 10:00 - 14:00 4.00 KILL P DECOMP Open well. SITP 1010 psi, SICP 1110 psi. Circulate well wi hot 8.5 ppg seawater. Pumped 3 BPM @ 1400 psi. Pumped total of 750 bbls. SID & observe well. SITP 520 psi, SICP 520 psi. 14:00 - 20:30 6.50 KILL P DECOMP Monitor well. SITP decreased to 370 psi, SICP decreased to 380 psi. Ordered 10.1 ppg brine. Wait on fluid & maintain rig. 20:30 - 00:00 3.50 KILL P DECOMP Wait on trucks wi 10.1 ppg brine. Take on 10.1 ppg brine. 6/22/2005 00:00 - 03:00 3.00 KILL P DECOMP Open well. SITP 370 psi. SICP 380 psi. Kill well wi 10.1 ppg fluid. Pumped 3 BM @ 880 psi. Increased rate to 4 BPM, 1330 psi. Pumped total of 570 bbls. SID & monitor well. Well dead, on slight vacuum. 03:00 - 03:30 0.50 WHSUR P DECOMP Blow down & N/D kill lines. Set TWC & test to 1000 psi, Ok. 03:30 - 04:30 1.00 WHSUR P DECOMP Bleed off tubing void. N/D X-mas tree. 04:30 - 07:00 2.50 BOPSUP P DECOMP N/U BOPE. 07:00 - 10:30 3.50 BOPSUP P DECOMP PJSM. Conduct full test on BOPE. No Failures. Test witnessed by Nabors Tool Pusher & BP Company Man. Witnessing of test waived by AOGCC rep John Crisp. 10:30 - 11 :00 0.50 PULL P DECaMP PJSM. Pull two way check valve, back out lock down screws. 11 :00 - 12:00 1.00 PULL P DECaMP PJSM. Pull hanger to floor. Hanger free @ 57K, max up wt = 100K. Up wt stabalized @ 72K. Well stable. LID hanger. 12:00 - 16:00 4.00 PULL P DECOMP POOH wi 2 7/8" ESP completion, double displacing. Pulled 78 stands, 7552'. 16:00 - 17:30 1.50 PULL P DECOMP Change out reels in spooling unit. 17:30 - 21 :00 3.50 PULL P DECOMP Con't to POOH & stand back 2 7/8" tubing. 21 :00 - 23:30 2.50 PULL P DECOMP Break out & UD ESP. 23:30 - 00:00 0.50 PULL P DECOMP Clear & clean rig floor. RID tubing tools. 6/23/2005 00:00 - 01 :00 1.00 PRFADD P DECOMP N/D flow nipple. Install shooting nipple on annular. 01 :00 - 05:30 4.50 PRFADD N WAIT DECOMP Wait on perforators. Maintain & service rig. 05:30 - 07:30 2.00 PRFADD P DECOMP R/U perforators. 07:30 - 08:00 0.50 PRFADD P DECOMP Safety meeting wi regard to handling & running perf guns. Emphasis on keeping unnecessary personel off rig floor & out of pipeshed when handling guns. 08:00 - 12:00 4.00 PRFADD P DECOMP Pick up (20') of 3 3/8" Power Jet, 6 spf gun assembly wi gamma ray I CCL. RIH & tag @ 15,297' ELM. Tie in & perfortate fl 15,230' - 15,250'. Monitor well, well stable. POOH, ASF, UD gun assembly. (32) bbls to fill hole. 12:00 - 13:30 1.50 PRFADD P DECOMP PJSM. RID Schlumberger. 13:30 - 18:30 5.00 CLEAN P DECOMP PJSM. Make up mule shoe & RIH on 2 71* EUE 8 rnd tubing out of derrick. 18:30 - 19:00 0.50 CLEAN P DECOMP P/U & single in hole wi tubing to tag up @ 15,294'. 19:00 - 00:00 5.00 CLEAN P DECOMP M/U head pin close in annular & reverse circulate. Wash & reverse thru fill to 15,530' Recovered black heavy oil, frac sand, formation sand & cobble sized gravel. Several times tubing tried to plug off. P/U wt = 75K, S/O wt = 25K. Pumped 3 BPM @ 600 psi, pressure increased to SOO psi. losses averaged 3/4 BPM. Printed: 6/27/2005 11: 14:58 AM ) ) SP EXPLQRA TION OþèratlonsSurn rt1aryReport Page 2 of 2 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: MPL-25 MPL-25 WORKOVER NABORS ALASKA DRILLING I NABORS 4ES Start: 6/20/2005 Rig Release: 6/25/2005 Rig Number: Spud Date: 11/1/1995 End: 6/25/2005 Date From - To Hbu rs Task Code NPT Phase Description of Operations 6/24/2005 00:00 - 00:30 0.50 CLEAN P DECOMP Con't to reverse circulate & wash to hard bottom @ 15,555' DPM. 295 jts in hole. 00:30 - 01 :30 1.00 CLEAN P DECOMP Reverse circulate 2 bottoms up until hole clean. 4 1/2 BPM @ 1100 psi. SD monitor well. Hole staying full. UD head pin, recovered large piece of rubber in connection. 01 :30 - 02:30 1.00 CLEAN P DECOMP POOH & UD 21 singles. Monitor well. Annulus very slight flow. Monitor well, well flowed 2 bbls. Well appeared to breathing, then FL slowly dropped in annulus. 02:30 - 08:00 5.50 CLEAN P DECOMP POOH & stand back 2 7/8" tubing. Pulled 12 stands, tubing wet. Pump tubing volume. FL dropping slowly. Seem to have some plugging. Con't to POOH. UD mule shoe. 08:00 - 09:30 1.50 PRFADD P DECOMP PJSM. N/D flow nipple, N/U shooting flange. 09:30 - 11 :00 1.50 PRFADD P DECOMP PJSM. Rig up Schlumberger E Line. Pressure test lubricator & Eline BOPE connections @ 500 psi, OK. 11 :00 - 15:30 4.50 PRFADD P DECOMP Safety meeting wI all personel regarding perforating gun safety. P/U & RIH wI (10') 3 3/8" Power Jet, 6 spf perforating assembly, including gamma ray I CCL & rollers. RIH. Some trouble, (hanging up), at the 5000' area. Work thru OK. Run on down, tie in wi correlation log. Shoot perfs from 15,298' - 15,308'. Monitor well, well on slight vacuum. POOH & UD perf gun, ASF. 15:30 - 16:00 0.50 PRFADD P DECOMP Pick up (20') 3 3/8" Power Jet, 6 spf perforaitng assembly wi gamma ray I CCL. 16:00 - 19:00 3.00 PRFADD P DECOMP RIH wi perforating assembly. Tie in & correlate on depth. Perforate 15,278 - 15,298'. Monitor well. POOH & UD perf. guns, all shots fired. 19:00 - 20:00 1.00 PRFADD P DECOMP RID perforating equip. 20:00 - 20:30 0.50 PRFADD P DECOMP N/D shooting flange. NU flow nipple. 20:30 - 21 :00 0.50 RUNCOMP RUNCMP Spot in spooling unit. Install new cable reel. R/U to run tubing. 21 :00 - 23:30 2.50 RUNCOMP RUNCMP P/U, M/U & service new ESP. Connect cable. Test same. 23:30 - 00:00 0.50 RUNCOMP RUNCMP RIH wI ESP & 2 7/8" tubing. 6/25/2005 00:00 - 05:00 5.00 RUNCOM RUNCMP Con't to RIH wi 27/8" ESP completion. Pump thru ESP & test every 2000'. 05:00 - 09:00 4.00 RUNCOM RUNCMP Change out reels in spooling unit. Make reel to reel splice @ 81 stands in @ 7819'. 09:00 - 14:00 5.00 RUNCOM RUNCMP Continue in hole wi 2 7/8" ESP completion string, testing cable & pumping @ 1 bpm I 1000 psi every 2000'. 14:00 - 16:00 2.00 RUNCOM RUNCMP P/U landing jt & attach field connection. 87K up wt, 37K down wt. Ran (3) flast guards, (6) protetralizers, & (245) La Salle clamps. 16:00 - 16:30 0.50 RUNCOM RUNCMP Land hanger. RILDS. UD landing jt. 16:30 - 18:00 1.50 BOPSUP RUNCMP N/D BOPE. 18:00 - 19:00 1.00 WHSUR RUNCMP N/U X-mas tree. Test tubing void & tree to 5000 psi, OK. 19:00 - 20:00 1.00 WHSUR RUNCMP Make final ESP check, Ok. P/U lubricator pull TWC. Install BPV. UD lubricator. 20:00 - 21 :00 1.00 RUNCOM RUNCMP Clear & clean cellar. Secure well. RELEASE RIG @ 2100 hrs, 6/25/2005 Printed: 6/27/2005 11: 14:58 AM ( II STATE OF ALASKA l ALASKA t..L. AND GAS CONSERVATION CO~..tldSSION REPORT OF SUNDRY WELL OPERATIONS 1. Type of Request: 0 Abandon 0 Suspend 0 Operation Shutdown 0 Perforate 0 Variance 0 Othel 0 Alter Casing ~ Repair Well 0 Plug Perforations 0 Stimulate 0 Time Extension 0 Change Approved Program ~ Pull Tubing 0 Perforate New Pool 0 Re-Enter Suspended Well 0 Annular Disposal 2. Operator Name: 4. Current Well Class: 5. Permit To Drill Number BP Exploration (Alaska) Inc. IBI Development 0 Exploratory 195-180 3. Address: 0 Stratigraphic 0 Service 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-22621-00-00 7. KB Elevation (ft): KBE = 46' 9. Well Name and Number: M PL-25 8. Property Designation: 10. Field 1 Pool(s): ADL 355017 Milne Point Unit 1 Kuparuk River Sands 11. Present well condition summary Total depth: measured 15655 feet true vertical 7628 feet Plugs (measured) N/A Effective depth: measured 15551 feet Junk (measured) N/A true vertical 7547 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 112' 112' Surface 8988' 9-5/8" 9019' 4711' 5750 3090 Intermediate Production 15608' 7" 15636' 7614' 7240 5410 Liner Perforation Depth MD (ft): 15174' - 15282' Perforation Depth TVD (ft): 7258' - 7340' R~ÇEIVED Tubing Size (size, grade, and measured depth): 2-7/8",6.5# 15066' Packers and SSSV (type and measured depth): None arC 1 7 20Õ3 None .11 nil P. I"'-"'L' f'nn", r . 12. Stimulation or cement squeeze summary: Anchorage Intervals treated (measured): Treatment description including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casino Pressure Tubina Pressure Prior to well operation: Subsequent to operation: 14. Attachments: 15. Well Class after proposed work: 0 Copies of Logs and Surveys run 0 Exploratory IBI Development 0 Service IBI Daily Report of Well Operations 16. Well Status after proposed work: IBI Oil 0 Gas 0 WAG DGINJ DWINJ 0 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: Contact David Reem, 564-5743 Printed Name Sondra Stewman Title Technical Assistant -..."....- ~ l;;2 \ 10 ~ Prepared By Name/Number: ." ~~..L "\ ~ ¡ Phone Slgrfiatyre Jr y Q r"Ji '\..~ 564-4750 Date - - l:$ondra Stewman, 564-4750 Form 10-404 Revis~n.'((212QOßh\I!I;;;'.tt i;lf."."f\¡ ~ì\.~Y 1 ,?no:') ~v{rlI~'ì;.je~~l1.... tJ L. ~ d .1 {,)J J nD1h1~,J¡,~,L- IBfL DEC 17-3 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 11/26/2003 11/27/2003 11/28/2003 ~I' ( ( BP EXPLORATION Operations Summary Report MPL-25 MPL-25 WORKOVER NABORS ALASKA DRILLING I NABORS 4ES 00:00 - 05:00 From - To Hours PRE 05:00 - 06:00 06:00 - 09:00 09:00 - 13:30 13:30 -18:00 18:00 - 20:45 20:45 - 23:30 23:30 - 00:00 00:00 - 01 :00 01 :00 - 02:00 02:00 - 03:30 03:30 - 06:30 06:30 - 07:00 07:00 - 07:30 07:30 - 09:30 09:30 - 10:30 10:30 - 16:00 16:00 - 18:00 18:00 - 22:30 22:30 - 00:00 00:00 - 02:30 02:30 - 07:30 07:30 - 12:00 12:00 -15:30 15:30 - 20:30 20:30 - 22:00 Task Code NPT Phase 5.00 RIGU P 1.00 KILL 3.00 KILL P P DECOMP DECOMP 4.50 KILL P DECOMP 4.50 KILL P DECOMP 2.75 KILL P DECOMP 2.75 KILL P DECOMP 0.50 KILL P 1.00 KILL P 1.00 WHSUR P 1.50 BOPSUF P 3.00 BOPSUF P 0.50 BOPSUF P 0.50 BOPSUF P DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP 2.00 PULL P DECOMP 1.00 PULL P DECOMP 5.50 PULL P DECOMP 2.00 PULL 4.50 PULL 1.50 PULL 2.50 PULL P P P P DECOMP DECOMP DECOMP DECOMP 5.00 RUNCO~~ 4.50 RUNCO~~ CaMP CaMP 3.50 RUNCO~~ 5.00 RUNCO~~ 1.50 RUNCor~ CaMP CaMP CaMP Page 1 of 2 Start: 11/26/2003 Rig Release: 11/29/2003 Rig Number: Spud Date: 11/1/1995 End: 11/29/2003 Description of Operations Move Rig from MPL-36 to MPL-25. Rig up, prepare for circulation of seawater and well kill operations, Rig accepted at 05:00. Rig up lines to Tiger Tank. Rig up lines to Tree. RU wellhead and test manifold to circulate; take on 140 F seawater. PU/RU lubricator Pull BPV and RD/LD lubricator. SITP = 1050 psi; SICP = 1050 psi. RU cement line and test lines to 3500 psi. PJSM wI all hands. Bleed gas, pump 106 Bbls down tubing @ 550-900 psi, and bullhead 18 Bbls for 3 BPM @ 900-1700 psi. Continue pump 3-4 BPM @ 800-1500 psi. Take returns to pit 'til clean--11 , 193 strokes or 658 Bbls. Bleed down surface lines; monitor well--SITP 220 psi. Order 9.7 ppg brine at 17:00 hours. At 18:00 hours SITP 320 psi, SICP 300 psi. Prepare for well kill circulation and wait on 775 Bbls 9.7 ppg fluids. Begin circulation of 9.7 ppg well kill fluids; SITP 240 psi, SICP 230 psi. Start at 2 BPM and work up to 4 BPM; TP increased from SITP to 1550 psi and CP was held to 80 - 90 psi for a total of 10,122 strokes = 595 Bbls. Monitor well. Monitor Well. TP = 0, CP = O. Set and test TWC to 2500 psi. Nipple down Production Tree. Nipple up BOP Stack. Test BOPE as per BP I AOGCC requirements at 250 / 3,500 psi. State's right to witness test waived by J. Chrisp. Rig down test equipment. Blow down lines. Pick up Lubricator. Pull TWC. (Well on slight vac) Lay down same. Make up Landing Joint. BOLDS. Pull Hanger to Floor. Un-seat Hanger at 80K. Pulled string up to 105K. Broke back to 94K. Fill hole with 7 bbls (Static FL at 230-ft), Pump 100 down Tbg to clean remaining oil from top hole section. Start POOH with 2 7/8" Tbg and ESP Assy. Stop with 76 Stands pulled to change Cable Reels and to circulate top hole section. Change Cable Spools. TOH wI 474 joints 2-7/8" tubing and ESP cable and equipment. Disassemble and inspect ESP and lay down sections. Disassemble and inspect ESP Assy and lay down sections. Clear and clean drill floor. Remove elephant trunk. M/U and service ESP Assembly. Start to RIH with ESP Assy as follows: ESP Assy, 27/8" Pup Jt,1 Jt 27/8" Tbg, XN Nipple, 4 Jts 27/8" Tbg, 2 7/8" x 1" GLM Assy w/Dummie installed, 234 Jts 2 7/8" Tbg. Note: Check Cable and pump down Tbg every -2,000-ft. Stop to make Cable Reel change. Change out Cable Reels. Make mid-cable splice. Test Cable Resume RIH with ESP Assy and 2 7/8" Tbg. Total Jts = 474. MU hanger and landing jt. Install penetrator and lower connector. Make cable connection and test cable. Printed: 12/1/2003 9:55:38 AM ( ( BP EXPLORATION Page 2 of 2 Operations Summary Report Legal Well Name: MPL-25 Common Well Name: MPL-25 Spud Date: 11/1/1995 Event Name: WORKOVER Start: 11/26/2003 End: 11/29/2003 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 11/29/2003 Rig Name: NABORS 4ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 11/28/2003 22:00 - 22:30 0.50 RUNCO~ If> CaMP Land hanger. PU = 85,000# ; SO = 32,000#. RILDS; Set and test TWC. 22:30 - 00:00 1.50 BOPSUF P CaMP Drain BOPE; BD hard lines; ND BOPE. 11/29/2003 00:00 - 00:30 0.50 BOPSUF P CaMP ND BOPE. 00:30 - 01 :30 1.00 WHSUR P CaMP NU TREE AND ADAPTOR FLANGE. 01 :30 - 02:00 0.50 WHSUR P CaMP Test adaptor flange and tree to 5000 psi. 02:00 - 03:00 1.00 WHSUR P CaMP PU lubricator; Pull TWC; Set BPV; Lay down same. 03:00 - 04:00 1.00 WHSUR P CaMP Secure tree and cellar. 11/30/2003 00:00 - 0.00 WHSUR CaMP Printed: 12/112003 9:55:38 AM ~ STATE OF ALASKA "O~ ALAS ,-, OIL AND GAS CONSERVATION C ,.MISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abanonr-] SuspendE} Operation Shutdownr-~ PerforateE] varianceE] Annuar Disposal['-~ After Casin.qE] RepairWellE] Plu.q Perforations[~] Stimulate[] Time Extensionr"] Other[--] Change Approved ProgramE] Pull Tubingr-] Perforate New PoolE] Re-enter Suspended Well[-] AOIDIZI= FORMATION 2. Operator 4. Current Well Class: 5. Permit to Drill Number: Name: BP Exploration (Alaska), Inc. Development [ ExploratoryE~ 195-180 3. Address: P.O. Box 196612 6. APl Number Anchorage, Ak 99519-6612 StratigraphicF1 ServiceF~ 50-029-22621-00-00 7. KB Elevation (ft): 9. Well Name and Number: 46.00 MPL-25 8. Property Designation: 10. Field/Pool(s): ADL 355017 Milne point Unit ! Kuparuk River Sands 11. Present Well Condition Summary: Total Depth measured 15655 feet true vertical 7628 feet Plugs (measured) Effective Depth measured 15551 feet Junk (measured) true vertical 7547 feet Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 112' 112' 40K 540 Surface 8988' 9-5/8" 9019' 4711' 80K 4760 Production 15608' 7" 15636' 7614' 80K 7020 ~' *'~' Perforation depth: Measured depth: Open Rerfs 15174'-15180', 15250'-15282' True vertical depth: Open Perfs 7264'-7269', 7315'-7340' Tubing: ( size, grade, and measured depth) 2-7/8" 6.5¢ L-80 TBG @ 15003'; ESR @ 15070' Packers & SSSV (type & measured depth) No Packer (ESR pump), Camco 2-7/8" x 1" sidepocket KBM GLM @ 140'. 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: ' 13 Representative Daily Avera,qe Production or Injection Data Oil~Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 373 37 695 343 Subsequent to operation: 392 40 776 366 14. Attachments: 15. Well Class after proposed work: Exploratory E] Development~ Servicer"] Copies of Logs and Surveys run __ 16. Well Status after proposed work: Oil[] GasE] WAGF~ GINJE] WINJE] WDSPLE] Daily Report of Well Operations _X 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ISundry Number or N/A if C.C. Exempt: Contact DeWayne R. Schnorr I N/A Printed Name DeWayne R. Schnorr Title Techical Assistant Signature" ~ '.~-'~~._.. ~..~~ Phone 907/564-5174 Date Sept 18, 2003 Form 10-404 Revi*.~~E~-" OCT 1_. & 0RIG"INAL MPL-25 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS 09/13/2003 FORMATION ACID JOB EVENT SUMMARY 09/13/O3 OBJECTIVE: PICKLE TUBING, FILL IA, PUMP ACID AND MONITOR FLOWBACK TO TANK. OPERATION: RIGGED UP FESCO AND DOWELL ACID TRANSPORT TO PICKLE TUBING. PRESSURE TESTED LINES TO 4500 PSI. PUMPED 12 BBLS OF 10% HCL ACID FOLLOWED BY 74 BBLS OF 2% KCL WATER. PUMPED AT 1.5 BPM FROM 750 TO 1000 PSI PUMPING PRESSURE. RIGGED UP AND FLOW ACID OUT OF THE WELL TO A TANK. FLOWED A TOTAL OF 90 BBLS BACK TO A TANK. RIGGED UP FESCO TO THE IA AND PUMPED 233 BBLS DEAD CRUDE TO FILL THE ANNULUS FOR THE FORMATION ACID JOB. PUMPED AT 2 BPM FROM 550 TO 2000 PSI. RIGGED UP DOWELL PUMP UNIT AND ACID TRANSPORT TO THE TUBING. PRESSURE TESTED LINES TO 4000 PSI. PUMPED 95 BBLS OF 10% MSR 100 ACID, PUMPED FROM 1.5 BPM TO 1.1 BPM FROM 900-4000 PSI. SWITCHED TO 2% KCL FOR OVER FLUSH, PUMPED 206 BBLS, PUMPED AT 1.1 BPM AT 3000 PSI. THE IA STARTED OUT AT 1600 PSI AND WENT TO 2100 PSI. CONCLUSION: JOB WAS COMPLETED WITH NO PROBLEMS AND WELL WAS FLOWED BACK TO A TANK UNTIL THE PH WAS 6 AND THEN SWITCHED TO THE PRODUCTION LINE. FLUIDS PUMPED BBLS 280 2% KCL WATER 233 DEAD CRUDE 12 10% HCL ACID 95 10% MSR 100 ACID 620 TOTAL Page 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: [] Operation Shutdown [] Stimulate [] Plugging [] Perforate [] Pull Tubing [] Alter Casing [] Repair Well [] Other Change Out ESP 2. Name of Operator 5. Type of well: 6. Datum Elevation (DF or KB) BP Exploration (Alaska) Inc. [] Development KBE = 46' [] Exploratory 7. Unit or Property Name 3. Address [] Stratigraphic Milne Point Unit P.O. Box 196612, Anchorage, Alaska 99519-6612 [] Service 4. Location of well at surface 8. Well Number 3712' NSL, 5086' WEL, SEC. 8, T13N, R10E MPL-25 At top of productive interval 9. Permit Number / Approval No. 195-180 5217' NSL, 3432' WEL, SEC. 32, T14N, R10E 10. APl Number At effective depth 50-029-22621-00 143' NSL, 3376' WEL, SEC. 29, T14N, R10E 11. Field and Pool At total depth Milne Point Unit / Kuparuk River 208' NSL, 3373' WEL, SEC. 29, T14N, R10E Sands 12. Present well condition summary Total depth: measured 15655 feet Plugs (measured) true vertical 7628 feet Effective depth: measured 15551 feet Junk (measured) true vertical 7547 feet Casing Length Size Cemented M D TVD Structural Conductor 80' 20" 250 sx Arcticset I (Approx.) 112' 112' Surface 8988' 9-5/8" 1750 sx PF 'E', 250 sx 'G', 150 sx PF 9019' 4711' Intermediate Production 15608' 7" 240 sx Class 'G' 15636' 7614' Liner Perforation depth: measured 15174'-15180', 15250' - 15282'RECEIVED true vertical 7257' - 7261', 7315'- 7339' Tubing (size, grade, and measured depth) 2-7/8", 6.5~, L-80 to 15091' Packers and SSSV (type and measured depth) None 1'3. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 14. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Attachments 16. Status of well classifications as: [] Copies of Logs and Surveys run [] Oil [] Gas I-'1 Suspended Service [] Daily Report of Well Operations 17. I hereby certify that th~e_f, oregoing is true and correct to the best of my knowledge Signed ~'~'L~, ~'~~ C-~ ~,-,.,v: ~.~Title Technical Assistant Date ,:t~-,.~ ~.-~ ! !:-~ : L. i :;-"~ i Prepared ByName/Number: Sondra Stewrnan, 564-475~_ Form 10-404 Rev. 06/15/88 Submit In Duplicat~~ · nS:Summary Report Legal Well Name: MPL-25 Common Well Name: MPL-25 Spud Date: 11/1/1995 Event Name: WORKOVER Start: 3/21/2002 End: 3~23~2002 Contractor Name: NABORS Rig Release: 3~23~2002 Rig Name: NABORS 4ES Rig Number: ~Date::~ i ~rom-~l!H:6urs Activity iC°dei~ NP~ ': Phase i Description of Operations 3/21/2002 00:00 - 02:00 2.00 RIGU P DECOMP MOVE RIG AND EQUIPMENT FROM E-PAD TO MPL-25. 02:00 - 03:00 1.00 RIGU P DECOMP BERM AND SPOT SUB, PITS, AND PIPE SHED. 03:00 - 05:00 2.00 RIGU P DECOMP RAISE AND SCOPE DERRICK. ACCEPT RIG AT 05:00 HRS. 05:00 - 05:30 0.50 WHSUR P DECOMP INSTALL HCR VALVE. 05:30 - 06:00 0.50 WHSUR :P DECOMP PICK-UP LUBRICATOR AND PULL BPV. LAY DOWN SAME. CREW CHANGE. 06:00 - 07:30 1.50 KILL P DECOMP RIG UP HARD LINES. TAKE ON 10.7 LB/GAL BRINE IN RIG PITS. 07:30 - 08:00 0.50 KILL 3 DECOMP PRESSURE TEST LINES TO 3,500 PSI. GOOD. 08:00- 12:00 4.00 KILL 3 DECOMP KILL WELL WlTH 10.7 LB/GAL BRINE. 12:00 - 13:30 1.50 KILL 3 DECOMP RETURNS STILL CONTAIN SOME OIL/GAS. CONTINUE TO CIRCULATE CLEAN. 13:30 - 14:00 0.50 WHSUR ~ DECOMP SET AND PRESSURE TEST-FVVC. 14:00 - 15:00 1.00! WHSUR ~ DECOMP iREMOVE PRODUCTION TREE. 15:00 - 17:00 2.00 BOPSUF; :~ DECOMP I INSTALL BOPE. 17:00 - 18:00 1.00 BOPSUIq P DECOMP BEGIN BOPE TEST. CREW CHANGE. 18:00 - 20:00 2.00 BOPSUR P DECOMP COMPLETED BOPE TEST PER BP AND AOGCC REQUIREMENTS. STATE'S RIGHT TO WITNESS TEST WAIVED BY C. SHEVE. 20i00 - 20:30 0.50 WHSUR P DECOMP PICK-UP LUBRICATOR AND PULL TWC. LAY DOWN SAME. 20:30 - 21:30 1.00 PULL :P DECOMP SPOT ESP SPOOLING UNIT. RIG UP CAMCO SPOOLING UNIT TO SPOOL 1/4" INJECTION LINE. 21:30 - 22:00 0.50 PULL P DECOMP BOLDS. MAKE-UP LANDING JT. PULL HANGER TO FLOOR. 95K. 22:00 - 00:00 2.00 PULL 3 DECOMP BEGIN TOH WITH 2 7/8" TBG ESP ASSY. ADDITIONAL TASK...SPOOL 1/4" CAMCO INJECTION LINE. 3/22/2002 00:00 - 10:00 10.00 PULL = DECOMP CONTINUE TO POOH WITH ESP COMPLETION & LAY DN PUMP & CLEAR & CLEAN RIG FLOOR. 10:00 - 14:00 4.00 RUNCOI~ COMP MAKE UP ESP PUMP & MOTOR 14:00 - 00:00 10.00 RUNCOI~ COMP RIH WITH ESP COMPLETION & STOP AS WELL BORE I REQUlRES & CIRC. GAS & OIL MIGRATION OFF OF WELL BORE REPLACING 10.5 PPG. FLUID WITH 10.8 PPG. (WEIGH LOSS OF FLUID DUE TO BRINE HEATING UP DN WELL BORE AND WELL BORE BEGAN MIGRATING GAS AND OIL WHILE WE WERE CHANGING OUT PUMP. 3~23~2002 00:00 - 02:30 2.50 RUNCO~ P COMP CONTINUE TO RIH TO ESP SETTING DEPTH. 02:30 - 05:00 2,50 RUNCOI~ COMP MU HANGER & MAKE ESP CONNECTOR & LAND HANGER & RILDS. & SET TWC. & TEST TWC. 05:00 - 08:00 3,00 BOPSUF,P COMP NIPPLE DN BOP 08:00 - 10:00 2.00 WHSUR P COMP NIPPLE UP TREE & TEST SAME TO 5000 PSI. & PULL TWC & SET BPV. & SECURE TREE & RELEASE RIG @ 1000 HRS. 03/23/2002 Printed: 3/25/2002 8:10:15 AM TOO MEMORANDUM TO: THRU: Julie Heusser, Commissioner Tom Maunder, ,~..flrv~~ P. I Supervisor FROM: John Crisp, SUBJECT: Petroleum InSpector State of Alaska Alaska Oil and Gas Conservation Commission DATE: December 22, 2000 Safety Valve Tests Milne Point Field L Pad DeCember 22, 2000[ I traveled to BPX's Milne Point Field L Pad to witness Safety Valve System tests. I conducted wellhouse inspections during SVS tests. Larry Niles was BP rep. in charge of SVS testing. As usual, Larry was ready to begin testing as soon as I arrived on location. Wellhouses on L Pad are heated & have lights, this makes for safe working conditions & minimal SVS failures. Wellhouses are clean:& in good condition. The ^OGCC test report is attached for SVS failure reference. SUMMARY: I traveled to BPX MPU L Pad for SVS tests. 20 wells, 40 components tested. 1 Failure witnessed, 2.5% failure rate. 20 wellhouses inspected. No failures to report. AttaChments' SVS MPU L pad 12-22-00jc cc; NON-CONFIDENTIAL SVS MPU L Pad 12-22-OOjc.doc Alaska Oil and Gas Conservation CommiSsion Safety Valve System Test Report Operator: BPX Operator Rep: Larry Niles AOGCC Rep: John Crisp Submitted By: John Crisp Field/Unit/Pad: PBU MPU L Pad Separator psi: LPS 140 Date: 12/22/00 HPS Well Permit Separ Set L/P Test Test Test Date Oil, WAG, GIN J, Number Number PSI PSI Trip Code Code Code Passed GAS or CYCLE L-01 1840050 L-02 1900060 140 100 90 P P .OIL £-03 1900070 L-04 1900380 140 100 105 P P OIL L-05 1900390 140 100 100 P P OIL L-06 1900100 140 100 100 P P OIL L-07 1900370 140 100 100 P P OIL / L-08 1901000 4000 2000 1950 P ' P WAG] L-09 1901010 L-Il 1930130 140 100 115 P P OIL L-12 1930110 140 100 100 P P OIL L-13 1930120 140 100 100 e e OIL L, 14 1940680 140 100 95 e P OIL L-15' 1940620 L-16A 1990900 ~-17 1941690 I L-20 1971360 140 100 100 P P OIL L-25 1951800 140 100 105 P P OIL L-28A 1982470 140 100' 110 P P OIL L-29 1950090 140 100 95 P P OIL ~-32 1970650 140 100 100 e e OIL L-33 1971050 L-35 1970920 140 100' 105 e P OIL L-36 1971480' 140 100 105 e e OIL L-37A 1980560 L-40 1980100 140 100 100 P P g-~\~:~o~\"~ OIL L-45 1981690 140 100 105 P P ~' OIL L-34 1970800 4000 2000 1900 P 4 WAG Wells: 20 Components: 40 Failures: 1 Failure Rate: 2.5% Elg0 Day Remarks: 12/26/00 Page 1 of 2 SVS MPU L Pad 12-22-00jc.xls Well Permit Separ Set L/P Test Test Test Date Oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed {;ns or CYCLE 12/26/00 Page 2 of 2 SVS MPU L Pad 12-22-OOjc.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: []Operation Shutdown ~-IStimulate I~ Pull Tubing i-]Alter Casing 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 3712' NSL, 5086' WEL, SEC. 8, T13N, R10E At top of productive interval 5217' NSL, 3432' WEL, SEC. 32, T14N, R10E At effective depth 143' NSL, 3376' WEL, SEC. 29, T14N, R10E At total depth 207' NSL, 3417' WEL, SEC. 29, T14N, R10E [] Plugging [] Perforate I~ Repair Well [~ Other Change Out ESP Type of well: [] Development I--I Exploratory i--I Stratigraphic E] Service 6. Datum Elevation (DF or KB) KBE: 47.7' 7. Unit or Property Name Milne Point Unit 8. Well Number MPL-25 9. Permit Number / Approval No. 95-180 10. APl Number 50-029-22621 11. Field and Pool Milne Point Unit / Kuparuk River Sands 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor Surface Intermediate Production Liner 15655 feet 7628 feet 15551 feet 7546 feet Length Size 80' 20" 8988' 9-5/8" Plugs (measured) Junk (measured) Cemented 250 sx Arcticset I (Approx.) 1750 sx PF 'E', 250 sx 'G', 150 sx PF 'E' 15608' 7" 240 sx Class 'G' MD TVD 112' 112' 9019' 4711' 15636' 7614' Perforation depth: measured 15174' - 15180', 15250' - 15282' true vertical 7257' - 7261 ', 7315' - 7339' Tubing (size, grade, and measured depth) 2-7/8", 6.5#, L-80 to 15091' Packers and SSSV (type and measured depth) None 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure ORIGINAL 14. Prior to well operation: Subsequent to operation: Representative Daily Average Production or Iniection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 15. Attachments [--I Copies of Logs and Surveys run [~ Daily Report of Well Operations 16. Status of well classifications as: [~ Oil E~ Gas I~ Suspended Service 7. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Terrie Hubble /~_~,~¢ ~ Title Technical Assistant III Prepared By Name/Number: Date /0'~'¢(~ ~ Terrie Hubble, 564-4628 ~ Submit In Duplic~ Form 10-404 Rev. 06/15/88 Facility M Pt L Pad Progress Report Well MPL-25 Page 1 Rig Nabors 4ES Date 06 October 99 Date/Time 26 Scp 99 16:00-06:00 16:00-06:00 27 Sep 99 06:00 06:00-07:00 07:00 07:00-09:30 07:00-09:30 09:30 09:30-03:30 09:30-13:00 13:00 13:00-15:00 15:00 15:00-17:00 17:00 17:00-20:30 20:30 20:30-22:00 22:00 22:00-03:30 28 Sep 99 03:30 03:30-05:00 03:30-04:00 04:00 04:00-05:00 05:00 05:00-06:00 05:00-06:00 06:00 06:00-12:00 06:00-07:00 07:00 07:00-09:30 09:30 Duration 14hr 14hr lhr 2-1/2 hr 2-1/2 hr 18hr 3-1/2 hr 2hr 2hr 3-1/2 hr 1-1/2 hr 5-1/2 hr 1-1/2 hr 1/2 hr lhr lhr lhr 6hr lhr 2-1/2 hr Activity Move rig Rig moved 100.00 % MOVE RIG FROM F-PAD TO L-PAD. & SET IN & RAISE DERRICK. HAD TO REMOVE MATTING FROM ROAD IN ORDER TO GET SUBSTRUCTURE OVER IT. At well location - Slot Removed Hanger plug Equipment work completed Derrick management Installed High pressure lines set tiger tanks & rig hard lines to tree & test to 2500 psi. & offioad brine. (hold well kill meeting. SICP=1300 Ann= 1090 psi. Equipment work completed Well control Circulated closed in well at 14680.0 ft circ. through choke with 10.0 ppg. brine & replace well bore influx sitp--250 sicp=400. Hole displaced with Brine - 115.00 % displaced Monitor wellbore pressures Raise brine wt. in pits. to 10.2 ppg. Stopped: To circulate Circulated closed in well at 1460.0 ft circ. well through choke @ 4-BPM & raise brine wt. to 10.2 ppg. sicp =130 sitp=100 psi. Hole displaced with Brine - 100.00 % displaced Circulated at 0.0 ft raise wt. in pits. to 10.5 ppg. Obtained req. fluid properties - 100.00 %, hole vol. Circulated closed in well at 14640.0 ft circ. well through choke with 10.5 ppg. brine. @ 4-bpm. sitp=30 psi. sicp--60 psi. Hole displaced with Brine- 105.00 % displaced Circulated closed in well at 14640.0 ft circ. well bore @ 4-bpm & raise brine st. to 10.6 ppg. + & shut dn & monitor well static (No Loss no gain. Hole displaced with Brine - 100.00 % displaced Wellhead work Installed Hanger plug set twc & test to 2500 psi. Equipment work completed Removed Xmas tree Equipment work completed Nipple up BOP stack Installed BOP stack Stopped: To hold safety meeting Nipple up BOP stack (cont...) Installed BOP stack Equipment work completed Tested BOP stack TEST WAIVED BY JOHN SPAULDING WITH AOGC Pressure test completed successfully - 3500.000 psi Facility M Pt L Pad Progress Report Well MPL-25 Page 2 Rig Nabors 4ES Date 06 October 99 Date/Time 09:30-10:30 10:30 10:30-12:00 12:00 12:00-15:00 12:00-15:00 29 Sep 99 15:00 15:00-06:00 15:00-16:45 16:45 16:45-18:45 18:45 18:45-03:00 03:00 03:00-06:00 06:00 06:00-06:30 06:00-06:30 06:30 06:30-10:00 06:30-10:00 10:00 10:00-13:30 10:00-13:30 13:30 13:30-19:00 13:30-19:00 19:00 19:00-05:30 19:00-04:30 30 Sep 99 04:30 04:30-05:30 05:30 05:30-06:00 05:30-06:00 06:00 Duration lhr 1-1/2 hr 3hr 3hr 15hr 1-3/4 hr 2hr 8-1/4 hr 3hr 1/2 hr 1/2 hr 3-1/2 hr 3-1/2 hr 3-1/2 hr 3-1/2 hr 5-1/2 hr 5-1/2 hr 10-1/2 hr 9-1/2 hr lhr 1/2 hr 1/2 hr Activity Removed Hanger plug Equipment work completed Removed Tubing hanger Equipment work completed Fluid system Circulated at 14680.0 ft CLEAN WELL BORE OF INFLUX & INCREASE BRINE WT. 10.7 FOR 75 PSI. TRIP MARGIN. Hole displaced with Brine - 125.00 % displaced Pull Single completion, 2-7/8in O.D. Pulled Tubing in stands to 14300.0 ft Completion string handling equipment failed - Change operation Serviced Completion string handling equipment REPAIR CENTRILIFT SPOOLING UNIT HYDRAULICS. Equipment work completed Pulled Tubing in stands to 300.0 ft Stopped: To pick up/lay out tubulars Laid down 300.0 ft of Tubing LAY DN ESP & CAVINS DESANDER & TAILPIPE ETC. Tailpipe assembly laid out Pull Single completion, 2-7/8in O.D. (cont...) Rigged down sub-surface equipment - Debris barrier laid dn 7-jts. 3.5" tbg tail & desander & recovered 19' sand. Equipment work completed Slickline wireline work Conducted slickline operations on Slickline equipment - Tool run Ran 6" od GR/JB to 15530' & pooh & rig dn same. rec 1-piece rubber. Completed run with Junk basket/gauge ring from 0.0 ft to 15530.0 ft Run Single completion, 2-7/8in O.D. Rigged up sub-surface equipment - ESP Make up esp assy & camco 1/4" capillary line Stopped: To flowcheck well Well control Monitor wellbore pressures Observed well percolating oil & gas & flowing while making up esp assy. & closed well in & begin monitoring, pressure to 10 psi in 10 min & duringduration of rig waiting for SWS & baker packer pressure rose to 210 psi. Began precautionary measures Electric wireline work Conducted electric cable operations ran in hole with rbp & set with baker 20 setting tool 22' below collar. Completed run with Retrievable packer from 0.0 ft to 15139.0 ft Tested Retrievable packer - Via annulus Pressure test completed successfully - 2500.000 psi Well control Worked on BOP - Lubricator rig dn lubricator & nipple up flow line. Stopped: To hold safety meeting crew change. FO Facility M Pt L Pad Progress Report Well MPL-25 Page 3 Rig Nabors 4ES Date 06 October 99 Date/Time 01 Oct 99 06:00-07:00 06:00-06:15 06:15 06:15-07:00 07:00 07:00-23:00 07:00-10:00 10:00 10:00-10:30 10:30 10:30-15:15 15:15 15:15-16:30 16:30 16:30~17:00 17:00 17:00-19:00 19:00 19:00-23:00 23:00 23:00-05:00 23:00-05:00 05:00 05:00-06:00 05:00-06:00 06:00 06:00-22:00 06:00-07:30 07:30 07:30-13:30 13:30 13:30-16:00 16:00 16:00-20:30 20:30 20:30-22:00 22:00 Duration lhr 1/4 hr 3/4 hr 16hr 3hr 4-3/4 hr 1-1/4 hr 1/2 hr 2hr 4hr 6hr 6hr lhr lhr 16hr 1-1/2 hr 6hr 2-1/2 hr 4-1/2 hr 1-1/2 hr Activity Well control (cont...) Held safety meeting Completed operations Worked on BOP - Bell nipple Completed operations BHA run no. 1 R.I.H. to 4200.0 ft Mu Baker Ret. tool & inside preventer valve & rih. Stopped: To circulate Circulated at 4200.0 ft circ. oil off well to thrash tank. Hole displaced with Brine - 100.00 % displaced R.I.H. to 15100.0 ft Rih & circ. @ 8000' & 12400' Stopped: To circulate Circulated at 15100.0 ft Circ. well bore clean of influx above pkr. @ 5-bpm 2350 psi. Hole displaced with Brine - 125.00 % displaced Functioned downhole tools at 15139.0 ft set dn & equalize pressure beneath plug & release same .& verify released, ran dn to 15162' Equipment work completed Circulated at 15162.0 ft Circ. bottoms up and had lots of oil & gas. (circ. through choke until bottoms up past & shut dn & check pressure SiTP=50 50 psi. sicp= 100 psi. Observed change in Gas levels Circulated at 15162.0 ft circ. well bore through choke & bring wt. to 11.1 ppg. & shud dn & monitor well (STATIC) Hole displaced with Brine - 125.00 % displaced Pull Tubing, 2-7/8in O.D. Pulled Tubing in stands to 0.0 ft POOH & lay dn plug & ret. tool Completed operations Run Single completion, 2-7/8in O.D. Serviced ESP s Stopped: To hold safety meeting crew change. Run Single completion, 2-7/8in O.D. (cont...) Serviced ESP Equipment work completed Ran Tubing in stands to 8600.0 ft Stopped: To splice cable Serviced ESP make mid-line spice in esp cable. Equipment work completed Ran Tubing in stands to 15090.0 ft Completed run with ESP to 15090.0 ft Serviced ESP install esp EFT connector at hanger. Equipment work completed ; , .- . £)it :.'.5 Facility M Pt L Pad Progress Report Well MPL-25 Page 4 Rig Nabors 4ES Date 06 October 99 Date/Time 02 Oct 99 22:00-23:00 22:00-23:00 23:00 23:00-01:30 23:00-01:30 01:30 01:30-02:30 01:30-02:30 02:30 02:30-03:30 02:30-03:30 03:30 03:30-06:00 03:30-06:00 06:00 Duration lhr lhr 2-1/2 hr 2-1/2 hr lhr lhr lhr lhr 2-1/2 hr 2-1/2 hr Activity Wellhead work Installed Tubing hanger iLand hanger & set twc. & test same to 2500 psi. Tie-down bolts energised Nipple down BOP stack Removed BOP stack Equipment work completed Wellhead work Installed Xmas tree Test hanger & tree to 5000 Psi. Equipment work completed Wellhead work Removed Hanger plug Remove twc & set BPV & secure tree & cellar. Equipment work completed Derrick management Rigged down Fluid system Clean pits. Equipment work completed Rig Released @ 0600 Hrs. 10/2/99 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COM~wlSSION REPORT OF SUNDRY WELL OPERATIONS Operations performed: [-'1 Operation Shutdown I'-I Stimulate I--1 Plugging I--I Perforate E] Pull Tubing I--}Alter Casing r-I Repair Well [] Other ESP Changeout 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 3712' NSL, 5086' WEL, SEC. 8, T13N, R10E At top of productive interval 5195' NSL, 3503' WEL, SEC. 32, T14N, R10E At effective depth 157' NSL, 3490' WEL, SEC. 29, T14N, R10E At total depth 220' NSL, 3487' WEL, SEC. 29, T14N, R10E 5. Type of well: [] Development I--I Exploratory I-'-] Stratigraphic I--I Service 6. Datum Elevation (DF or KB) KBE = 46' 7. Unit or Property Name Milne Point Unit 8. Well Number MPL-25 9. Permit Number / Approval No. 95-180 10. APl Number 50-029-22621 11. Field and Pool Milne Point Unit / Kuparuk River Sands 12. Present well condition summary Totaldepth: measured 15655 feet true vertical 7628 feet Effective depth: measured 15551 feet true vertical 7546 feet Casing Length Size Structural Conductor 80' 20" Surface 8983' 9-5/8" Intermediate 15582' 7" Production Liner Plugs (measured) Junk (measured) Cemented 250 sx Arcticset I (Approx.) 1750 sx PF 'E', 250 sx 'G', 150 sx PF 'E' 240 SX Class 'G' MD TVD 112' 112' 9019' 471 O' 15636' 7613' Perforation depth: measured true vertical 15174' - 15180', 15250' - 15282' (Subsea) 7212' - 7216', 7269' - 7294' Tubing (size, grade, and measured depth) 2-7/8" 6.5# ppf, L-80 to 15147' Packers and SSSV (type and measured depth) ORIGINAL RECEIVED 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure JAN 08 1999 Naska 0il & (~as Cons. Commission Anchorage 14. Prior to well operation: Subsequent to operation: Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure 15. Attachments 16. Status of well classifications as: F-'I Copies of Logs and Surveys run Report of Well Operations ~Oaily [~ Oil ['--} Gas [--1 Suspended correci to best of my knowledge 17. I hereby certify that the foregoing is true anc~ the J ' Title Staff Technical Assistant Service Prepared By Name/Number: Date ~/~' ~" Jeanne L. Haas, 56~1-5225 Facility M PtL Pad Progress Report Well MPL-25 Page 1 Rig Nabors 4ES Date 05 January 99 Date/Time 05 Dec 98 06 Dec 98 07 Dec 98 08 Dec 98 09 Dec 98 00:02-05:00 05:00-06:00 06:00-15:30 15:30-02:00 02:00-03:00 03:00-04:30 04:30-06:00 06:00-07:00 07:00-08:00 08:00-09:30 09:30-16:00 16:00-18:30 18:30-21:00 21:00-01:30 01:30-06:00 06:00-06:15 06:15-06:30 06:30-07:30 07:30-11:00 11:00-12:30 12:30-13:15 13:15-13:30 13:30-18:00 18:00-18:15 18:15-19:00 19:00-19:30 19:30-00:00 00:00-00:30 00:30-06:00 06:00-11:30 11:30-12:00 12:00-12:30 12:30-18:00 18:00-18:15 18:15-18:45 18:45-19:00 19:00-19:15 19:15-20:00 20:00-20:30 20:30-21:00 21:00-23:00 23:00-04:30 04:30-06:00 06:00-07:00 07:00-12:30 12:30-13:00 13:00-15:00 15:00-15:30 15:30-16:30 16:30-17:30 17:30-18:00 18:00-18:30 18:30-19:00 19:00-20:00 Duration 4-3/4 hr lhr 9-1/2 hr 10-1/2 hr lhr 1-1/2 hr 1-1/2 hr lhr lhr 1-1/2 hr 6-1/2 hr 2-1/2 hr 2-1/2 hr 4-1/2 hr 4-1/2 hr 1/4 hr 1/4 hr lhr 3-1/2 hr 1-1/2 hr 3/4 hr 1/4 hr 4-1/2 hr 1/4 hr 3/4 hr 1/2 hr 4-1/2 hr 1/2 hr 5-1/2 hr 5-1/2 hr 1/2 hr 1/2 hr 5-1/2 hr 1/4 hr 1/2 hr 1/4 hr 1/4 hr 3/4 hr 1/2 hr 1/2 hr 2hr 5-1/2 hr 1-1/2 hr lhr 5-1/2 hr 1/2 hr 2hr 1/2 hr lhr lhr 1/2 hr 1/2 hr 1/2 hr lhr Activity Rig moved 100.00 % Fill pits with Brine Conducted slickline operations on Slickline equipment - Retrival run Circulated closed in well at 15282.0 ft Removed Xmas tree Rigged up BOP stack Tested BOP stack Tested BOP stack Worked on BOP - Lubricator Retrieved Tubing hanger Pulled Tubing in stands to 7440.0 ft Circulated at 7440.0 ft Ran Tubing in stands to 15282.0 ft Circulated at 15282.0 ft Pulled Tubing in stands to 6912.0 ft Held safety meeting Serviced Drillfloor / Derrick Repaired Completion string handling equipment Pulled Tubing in stands to 55.0 ft Rigged down sub-surface equipment - Electrical submersible pumps Rigged up Tubing handling equipment Made up BHA no. 1 R.I.H. to 14800.0 ft Held safety meeting Singled in drill pipe to 15530.0 ft Washed to 15530.0 ft Reverse circulated at 15520.0 ft Laid down 425.0 ft of 3-1/2in OD drill pipe Circulated at 15105.0 ft Circulated at 15105.0 ft (cont...) Flow check Laid down 281.0 ft of 3-1/2in OD drill pipe Pulled out of hole to 1000.0 ft '9£C£1 Held safety meeting Pulled out of hole to 219.0 ft t1[88]r~" CO ~,90 Laid down 218.0 ft of 2-7/8in OD drill pipe Pulled BHA Rigged up Completion string handling equipment '~tllClloro.qO-'°' Cofl/l~l,- Rigged up sub-surface equipment - Completion string sub-assemblies Rigged up sub-surface equipment - Completion string sub-assemblies Rigged up sub-surface equipment - Electrical submersible pumps Ran Tubing in stands to 7750.0 ft Serviced Electric cable Serviced Electric cable (cont...) Ran Tubing in stands to 15127.0 ft Rigged up Tubing hanger Serviced Electric cable Ran Tubing on landing string to 15147.0 ft Removed BOP stack Installed Xmas tree Tested Xmas tree Retrieved Hanger plug Installed High pressure lines Freeze protect well - 14.000 bbl of Diesel Facility M Pt L Pad Progress Report Well MPL-25 Rig Nabors 4ES Page Date 2 05 January 99 Date/Time 20:00-21:00 21:00-23:00 Duration lhr 2hr Activity Rigged down High pressure lines Rigged down Fluid system PERM I T DATA 95-180 7220 95 - 180 GR/CCL/PERF 95-180 GR/CCL/MARK 95-180 GR/CC/PERF 95-180 PLS (STAT) 95-180 CDR -MD 95-180 CDR -TVD 95-180 CDN - MD 95-180 7363 95-180 CDN AOGCC Individual Well Geological Materials Inventory Page: 1 Date: 05/13/98 DATA PLUS GR 05/21/96 SEPIA :l,~ ~¥~I/ q~> )o/'?'3~/~'3/, 1 05/03/96 SEPIA /~70~ ;~ ~ 1 05/03/96 SEPIA ]~-{o~ - /P3~ 0 1 05/03/96 RUN DATE RECVD -- ~00-15600 FINAL 08/08/96 J~/4700-7600 ~000-15550 ~CDR/CDN - MWD /~'4700-7550 FINAL 08/08/96 FINAL 08/08/96 1 08/08/96 FINAL 08/08/96 10-407 ~COMPLETION DATE JyA~/q~/ /// '/' 1"_4~ / DAILY WELL OPS R /~1~0/~-I TO 3~ ~//~[ / ~/ ~/ Are dry aitch samples re~ired? yes ~~d received? ye~' Was the well cored? yes ~~alysis.: . & desCription received? Are well tests required?l\ yes ~~Rece Well is in compliance Initial COMMENTS %1, ~ ~,~,.,, ived? yes ...... h'6 ALASK,-, OIL AND GAS CONSERVATION CO,,~iMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. 'Status of Well Classification of Service Well [] Oil [] Gas [] Suspended [] Abandoned [] Service 2. Name of Operator 7. Permit Number BP Exploration (Alaska)Inc. 95-180 96-093 3. Address 8. APl Number P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-22621 4. Location of well at surface :~:~:'~:%~;~'F 9. Unit or Lease Name 3712' NSL, 5086' WEL, SEC. 8, T13N, R10E ?' %:;:: -;"F';-' -~:"'-, ~ '-*- ;.'; ;'-~::. ' i Milne Point Unit At top of productive interval ¢ ,-~,..?,:: ,._~*~ _..:~,[,~~. 10. Well Number 5217' NSL, 3432' WEL, SEC. 32, T14N, R10E i~/,~__~ i¢'; MPL-25 At total depth ... , ~.~ .l~-i~ . ~~ '~ 11 Field and Pool ' 207' NSL, 3417' WEL, SEC. 29, T14N, R10E i .... ~~. ! Milne Point Unit/Kuparuk River 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation an~t, Serial No. Sands KBE = 47.7'I ADL 355017 12. Date Spudded11/21/95 I13' Date T'D' Reached I 14' Date C°mp" Susp" °r Aband'[15' Water depth' if OffshOre 16' NO' Of COmpletiOnsl 2/03/95 05/25/96 N/A MSL One 17. Tota['"Depth (MD+TVD)118. Plug Back Depth (MD+TVD)I19. Directional Survey 20. Depth where SSSV set~21. Thickness of Permafrost 15655 7628 F~ 15551 7546 FTI E~Yes [] No N/A MD! 1800' (Approx.) 22. Type Electric or Other Logs Run MWD, EMSS, GR/CCL i23. CASING, LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE TOP BO'FrOM SIZE CEMENTING RECORD AMOUNT PULLED 20" 91.1# H-40 32' 112' 24" 250 sx Arcticset I (Approx.) 9-5/8" 40# L-80 31' 9019' 12-1/4" 1750 sx PF 'E', 250 sx 'G', 150 sx PF 'E' 7" 26# L-80 28' 15636' 8-1/2" 240 sx Class 'G' 24. Perforations open to Production (MD+TVD of Top and Bottom 25. TUBING RECORD and interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 3-3/8" Gun Diameter, 6 spf 4-1/2" Gun Diameter, 5 spf 2-7/8", L-80 14974' N/A MD TVD MD TVD 15250'-15282' 7315'-7339' 15174'-15180' 7257'-7261' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. ..... DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED ...... Freeze protect 15250'-15282' Frac'd w/110500# 16/20 Carbolite behind pipe 27. PRODUCTION TEST Date First Production IMethod of Operation (Flowing, gas lift, etc.) June 5, 1996 I Electric Submersible Pump .. Date of Test Hours Tested PRODUCTION FOR OIL-EEL GAS-MCF WATER-EEL CHOKE SIZE I GAS-OIL RATIO TEST PERIOD · I Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (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. RECEIVED Form 10-407 Rev. 07-01-80 Submit In Duplicate Geologic Marke._ 30. Formation Tests Measured True Vertical Include interval tested, pressure data, all fluids recovered Marker Name Depth Depth and gravity, GOR, and time of each phase. Top Kuparuk A 15207' 7282' Top Kuparuk A3 15218' 7290' Top Kuparuk A2 15228' 7298' Top Kuparuk A1 15264' 7325' 31. List of Attachments Summary of Daily Drilling Reports, Surveys, Annular Pumping Repod 32. I hereby certify that the foregoing is true and corr¢cl to the best of my knowledge Signed ~-/ %~f.q¢' .,~-d/ C~/~ /~ · ~ ' n. / Title Senior Drilling Engineer Date I ! ~ Tim Schofield /f.,,CY') .,~ ~. , ~ Prepared By Name/Number: Kathy Campoamor, 564-5122 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 BP/AAI SHARED SERVICE DAILY OPERATIONS PAGE: 1 WELL: MPL-25 BOROUGH: NORTH SLOPE UNIT: UNKNOWN FIELD: UNKNOWN LEASE: API: 50- PERMIT: APPROVAL: ACCEPT: 11/20/95 02:00 SPUD: 11/21/95 10:30 RELEASE: OPERATION: DRLG RIG: NABORS 22E WO/C RIG: NABORS 22E 11/20/95 (1) TD: 112'( 0) RIGGING UP ON MPL-25 MOVE FROM MPJ-16 TO MPL-25. MIRU. MW: 0.0 VIS: 0 11/21/95 ( 2) TD: 112'( 0) 11/22/95 (3) TD: 1758' (1646) 11/23/95 (4) TD: 4348' (2590) 11/24/95 ( 5) TD: 5257' ( 909) 11/25/95 ( 6) TD: 7817' (2560) PU HWDP MW: 0.0 VIS: 0 FINISH MIRU. RIG ACCEPTED 11/20/95, @ 1400 HRS. HOOK UP ALL WATER, STEAM & ELECTRICAL LINES. NU DIVERTER, RISER & FLOWLINE. TAKE ON WATER IN PITS. CLEAN RIG. PU DP & STAND BACK IN DERRICK. FUNCTION TEST DIVERTER SYSTEM WITH LOU GRIMALDI WITH AOGCC. LOU WOULDN'T APPROVE DIVERTER WITHOUT EXTENDING DIVERTER LINE PAST RIG 4ES. PU DP WHILE MODIFYING DIVERTER LINE. TOTAL LENGTH FROM CELLAR DOOR=182' PU HWDP & LOAD FLOOR WITH BHA. DRILLING 12-1/4" HOLE MW: 0.0 VIS: 0 PU BHA & STAND BACK IN DERRICK. REPAIR LEAKING DIVERTER. FINISH MU BHA, ORIENT & TEST MWD. DRILL ICE INSIDE CONDUCTOR. SPUD & DRILL 12-1/4" HOLE F/l12' T/332'. MWD FAILED, POOH & CHANGE OUT SAME & TEST. TIH. DRILL & SURVEY F/332' T/1758'. DRILLING 12-1/4" HOLE MW: 0.0 VIS: 0 DRILL & SURVEY 12-1/4" HOLE F/1758' T/2587'. FINISH CIRC SWEEP AROUND. MONITOR WELL & PUMP PILL. POOH. TIH, HIT BRIDGE. WASH & REAM F/1700' T/1919'. FINISH TIH. CBU. REPAIR ROLLER ON BLOCK GUIDE IN DERRICK. DRILL & SURVEY 12-1/4" HOLE F/2587' T/4348' DRILLING MW: 0.0 VIS: 0 DRILL & SURVEY 12-1/4" HOLE F/4348' T/5043' PUMP HI-LO SWEEPS & CIRC HOLE CLEAN. MONITOR WELL. PUMP PILL. POOH. SWABBING, PUMP OUT F/2490' T/1700' LD MWD & BIT. MU NEW BIT & MWD. SLIP & CUT DRLG LINE. SERVICE CROWN & DRAWWORKS. MU BHA #3. ORIENT & TEST MWD. TIH, PU DP, WASH & REAM THRU TIGHT SPOTS. NO FILL. DRILL & SURVEY 12-1/4" HOLE F/5043' T/5257' DRILLING 12-1/4" HOLE MW: 0.0 VIS: 0 DRILL & SURVEY 12-1/4" HOLE F/5257' T/6306'. CBU. MONITOR WELL. SHORT TRIP. OK. DRILL & SURVEY 12-1/4" HOLE F/6306' T/7535'. CIRC HOLE CLEAN. MONITOR WELL, PUMP PILL. SHORT TRIP. OK. DRILL & SURVEY 12-1/4" HOLE F/7535' T/7817' WELL : MPL-25 OPERATION: RIG : NABORS 22E PAGE: 2 11/26/95 ( 7) TD: 9043' (1226) 11/27/95 ( 8) TD: 9043' ( 0) 11/28/95 (9) TD: 9043' ( 0) 11/29/95 (10) TD: 9414' ( 371) 11/30/95 (11) TD:11968' (2554) 12/01/95 (12) TD:13288' (1320) 12/02/95 (13) TD:13288' ( 0) CIRC & COND MUD MW: 0.0 VIS: 0 DRILL & SURVEY 12-1/4" HOLE F/7817' T/9043'. CIRC HOLE CLEAN WITH SWEEPS. MONITOR WELL. PUMP PILL. SHORT TRIP, SWABBING F/3400' T/1700'. WORK EACH STAND THROUGH TIGHT SPOT TO TAKE MUD. TIH. OK. NO FILL. CIRC & COND MUD TO RUN CASING. CIRC & COND MUD FOR CMT MW: 0.0 VIS: 0 FINISH CIRC & COND MUD, DROP ESS, PUMP PILL, MONITOR WELL. POOH, LD BHA. CHANGE BAILS, RU CASING EQUIP. RUN 9-5/8" L-80. SHOE @ 9019'. MU CEMENT HEAD & BREAK CIRC SLOWLY. BRING RATE UP SLOW. CIRC @ 10 BPM, NO LOSSES. NU 13-5/8" BOPE MW: 0.0 VIS: 0 TEST LINES. MIX & PUMP CEMENT, DISPLACE WITH RIG & BUMP PLUG. CIP @ 0915 HRS. FLOATS HELD. RU TO RUN TOP JOB. DRAIN STACK. FLUSH ANNULUS. MIX & PUMP TOP JOB CEMENT, RD. LD CASING EQUIP, CEMENT HEAD & LANDING JT. REMOVE FLOWLINE, ND DIVERTER. REMOVE DIVERTER FROM CELLAR & INSTALL SPEED HEAD & TUBING SPOOL. SET 13-5/8" BOPE ON SPOOL & TEST SEALS. OK. ND ANNULAR PREVENTER & TOP SET OF RAMS. REMOVE FROM CELLAR & BRING NEW PREVENTER & RAMS INSIDE. NU STACK. DRILLING 8-1/2" HOLE MW: 0.0 VIS: 0 FINISH NU BOPE. INSTALL TEST PLUG, TEST BOPE. DOUG AMOS WITH AOGCC WAIVED WITNESSING TEST. PULL TEST PLUG & INSTALL WEAR RING. RU RISER & FLOWLINE. PU BHA #4, ORIENT, LOAD SOURCE, TEST MWD. TIH TO FLOAT COLLAR. PU DP. TEST CASING. DRILL FLOAT COLLAR, CEMENT, FLOAT SHOE & 10' NEW FORMATION T/9053'. RUN FIT. DRILL 8-1/2" HOLE F/9053' T/9414' DRILLING 8-1/2" HOLE MW: 0.0 VIS: 0 DRILL & SURVEY 8-1/2" HOLE F/9414' T/Il021'. CBU. MONITOR WELL. PUMP PILL. SHORT TRIP TO CASING SHOE. OK. DRILL & SURVEY 8-1/2" HOLE F/l1021' T/11968' RIH PU DP MW: 0.0 VIS: 0 DRILLED T/11968' T/13003'_ PUMP HIGH VIS SWEEP, CBU, MONITOR WELL. DRILL F/13003' T/13288. CBU. MONITOR WELL. PUMP PILL. POOH TO SHOE SLOWLY, CALC DISPLACE, MONITOR. OK. SERVICE TOP DRIVE & CROWN. TIH, PU DP. DRILLING PU DP & RIH. DRILL F/13288' T/14799' MW: 0.0 VIS: 0 12/03/95 (14) TD:15406' (2118) DRILLING MW: 0.0 VIS: 0 FINISH DRILLING T/14799'. FINISH CIRC SWEEPS OUT. MONITOR WELL, PUMP PILL. SHORT TRIP. OK. RIH. CIRC & WEIGHT UP. DRILL F/14799' T/15060'. MONITOR WELL. CBU. DRILL F/15060' T/15185'. CONTROL DRILL F/15185' T/15406' WELL : MPL-25 OPERATION: RIG : NABORS 22E PAGE: 3 12/04/95 (15) TD:15655' ( 249) 12/05/95 (16) TD: 0 PB: 0 12/06/95 (17) TD: 0 PB: 0 12/07/95 (18) TD: 0 PB: 0 POOH TO RUN CASING MW: 0.0 VIS: 0 DRILLED F/15406' T/15649'. CIRC OH VOLUME. MONITOR WELL. DRILL T/15655', PUMP LOW-HI VIS SWEEP. MONITOR. CIRC SWEEPS OUT. MONITOR WELL & CIRC SWEEPS. POOH. MONITOR, NO FLOW, PUMP SECOND PILL. POOH TO SHOE, OK. RIH W/30 STDS. CIRC PILLS OUT OF HOLE. RIH TO TD. CBU, PUMP LOW-HI VIS PILL. FINISH HIGH TEMP MUD TREATMENT, MONITOR. DROP EMS, PUMP TO BOTTOM, PUMP PILL. BLOWDOWN TOP DRIVE. POOH, STANDING BACK & LD DP. RUNNING CSG, PREPARE CIRC MW: 0.0 POOH, LD DP & STAND SOME IN DERRICK. LD BHA, REMOVE SOURCE & LD REMAINDER OF BHA. CHANGE UPPER PIPE RAMS TO 7", PULL WEAR RING, TEST DOOR SEALS. JOHN SPAULDING WITH AOGCC GAVE EXTENSION TO FINISH WELL WITHOUT FULL TEST. CHANGE ELEVATOR LINKS & RU CASING EQUIP. PU & RIH WITH 7" CASING. FULL RETURNS. RU TO CIRC @ SHOE. CLEANING PITS & NU TREE MW: 0.0 CIRC CASING @ 9-5/8" SHOE. RIH WITH 7" CASING. SHOE @ 15635'. FLOAT COLLAR @ 15551', RA TAG @ 15020'. CIRC CASING, LOAD PITS WITH SEAWATER. TEST LINES, PUMPED WATER & CEMENT, DISPLACE WITH DIESEL & SEAWATER. WELL TRYING TO PACK OFF BUT ABLE TO BACKDOWN. OK. INCREASED RATE WITH CEMENT AROUND TO SHOE, DISPLACED FINAL BBLS. BUMP PLUG, CHECK FLOATS, PRESSURE UP. OK. RD HALLIBURTON EQUIP, RD CASING EQUIP, CHANGE ELEVATORS. LD LANDING JT, SET 7" PACKOFF & TEST. RIH WITH TUBING HANGER & SET. CHANGE RAMS, ND FLOWLINE, SET BOP'S BACK, CLEAN PITS. NU ADAPTER FLANGE FOR TREE. RIG RELEASED MW: 0.0 NU ADAPTER FLANGE & TREE & TEST. CLEAN PITS, PULL BACK PRESSURE VALVE, INSTALL TWO WAY CHECK & BULL PLUGS. WAIT ON SUPERSUCKER & WEATHER, FINISHED CLEANING PITS. RIG RELEASED @ 1700 HRS, 12/06/95. SIGNATURE: (drilling superintendent) DATE: SUMMARY OF DAILY OPERATIONS SHARED SERVICES DRILLING - BPX / ARCO Well Name: M PL-25 Rig Name: Polar Rig #1 AFE: 33021 5 Accept Date: 05/1 9/96 Spud Date: Release Date: 05/25/96 May 17 1996 Cont moving Polar equipment to location. Finish w/Herculite liner on pad. Start to spot equipment. Notify State for BOP test on 5/18/96. Cont with RU. Unload 450 bbls brine. Cont with RU, 75% complete. May 18 1996 Cont with RU. Wellhead pressure 250 psi. Bleed gas. Hook up line to gas buster. Update State for BOP test. Pressure test Baker bridge plug with rig pump to 1500 psi/10 min. Good test. Bleed pressure to 0. Close in well. Cont with RU. Wellhead pressure 0. Monitor for flow-none. ND frac tree. Pull false bowl. Install BOP. Well secure. Choke line flange will not lineup with HCR valve flange again. Notify State of delay. Cont with RU. Receive & unload 2-7/8" tubing. Finish welding mods to choke line. Call out State and HB&R. HB&R rigged up. AOGCC rep.,D.Amos on location. Start BOP test. Cont with BOP pressure test. May 19 1996 Cont BOP test. BOP test complete. Pull test plug. Rig accepted @ 0645 hrs. Generator down. Swap over to rig generator. PU Baker retrieving head & start to tally, drift & PU 2-7/8" L-80 tubing. Generator repaired. Now Tioga heater is acting up. Tioga repaired. Have 180 jts tubing ran, +/- 5675'. Tally next row & cont running tubing. Have 274 jts ran, +/- 8615'. Run 338 jts & stop retrieving head at 10657'. (Bridge plug at 10687'). RU return line to dirty fluids tank. Start brine down tubing to displace produced fluids with kill weight brine. Return diesel and produced fluids to dirty fluids tank. SD pump hole swapped over to brine to bridge plug. Drain lines to dirty fluids tank. Tag Baker bridge plug at 10701' with 340 jts in hole. Release BP & monitor well. Off load additional brine. Start to bullhead kill weight fluid from BP to top perf. May 20 1996 Cont to pump kill weight fluid to top perf. Finish with bullhead. Unable to POOH. Well out of balance. Load tubing with brine. RU to "U"-tube. Well balanced. Start POOH with tubing & bridge plug. Finish POOH. LD BP. Start in hole with BHA #2. Space out casing scraper above top perf and tubing from derrick. Run 120 jts back in hole. Finish in hole with tubing in derrick. Load pipe rack. Start to tally, drift and PU tubing. Have 450 jts in hole, +/- 14050'. Cont in hole. Start MI extra tanks for clean-out. Page May 21 1996 Looking f/top of sand. Tag top of sand at 15350' w/488 jts in hole. PUH and WO load of brine. Cont to RU tank and lines to circulate out sand. Break circulations (35 bbls to fill hole) and reverse circulate a tubing volumn (89 bbls). (Loosing 1/2 bpm to formation). Pump had two swabs leaking. Have to SD for repairs. Order out lighter brine. Repairs complete. Break circulations. Tag TOS and start washing thru. Stop at 15404' and clean up tubing. Getting Iow on fluids on location, without trucks. Resume operations. Clean out sand down to hard bottom at 15561' with good carbolite returns. Still losing some fluid. Clean up well. Three loads of brine made it before Kuparuk bridge was closed. Put 2 loads in tanks on A pad and put one load in clean tank on location. Unable to get pre-mixed Xanvis across river before road was closed. At present time the Polar rig is unable to mix any sweeps or pills with equip it has. Only option to mix gel sweeps on this side of river is to use Dowell. Dowell is preparing for frac in morning on C pad & will not have equip available until frac is done. Pull 10 stds of tubing. Secure well. Put Polar on maintenance day. Total down time 2 hrs repair pump & 3 hrs maint. (down time due to lack of proper equipment). Rig service & maintenance cont. May 22 1996 Rig remains on a maintenance day while waiting for equip to become available to mix gel sweeps. Take rig back off maintenance day. Run back in hole with 10 stds of tbg. Tag TD at same place, 15561'. No sand fill. Dowell on location and RU. Bring rig pump on line and fill hole with 26 bbls brine. Break circulations. Start gel sweep followed by a brine spacer. Pumped the second sweep the same. Third & final sweep pumped was 60 bbls of gel. Chase gel sweeps to surface w/brine. Gel spacers to surface. Grab samples. Trace of carbolite. Returns starting to cleanup. Ran out of tank room in dirty tank. Cont to clean up well. Ran out of brine in clean tank. SD pump. Cont to clean-up well. SD pump. RU to POOH. Start POOH with tubing & BHA #2. Cont POOH. May 23 1996 Cont POOH w/BHA #2. Call out centrilift. Finish POOH. LD BHA #2. Start to RU handle & run ESP equip. Centrilift service people had to leave location due to problem with the start up on two other wells. Put ESP RU on hold. Resume RU operations. Cont RU operations. PU & service ESP assy. RU sheave & string flat cable. Start in hole with 2- 7/8" tubing. Have 90 stands run. May 24 1996 Cont to RIH with ESP completion. Have 130 stds run. Make first splice. Cable checked good. Cont to RIH with ESP completion. Have 195 stds run. Make second splice. Cable checked good. Cont RIH with ESP completion. PU GLM w/dummy installed. Run 3 jts. MU tubing hanger, install 2-way check valve. Measure pig-tail & splice. Cable checked good. Land tubing hanger & tighten lock down screws. Land completion. Start to ND BOPE. NU tubing head adapter & tree. Test tubing hanger & tree. Good test. Pull 2-way check. Freeze protect tubing & annulus with diesel to 2000'. Rig released @ 0600 hrs, 05/25/96. Page 2 C~PAt{T BF' WELL NAME MPL-25 LOC~TI£~ 1 MILNE PT ~AGlq~I~ DECLINATION GRID COb~ERGENCE ANGLE DA~: 21-NOV-95 WELL NUMBER 0 APi~ WELL HEAD LOE~TI£~4: LAT(N/-S) 0,00 OOB t-L~BER 37411 AZIMUTH ~:OM ROTARY TABLE TO TA~ET IS TIE IN F~iNT(TIP) MEASURED DEPTH 1!2.6~ TE~E VER% DE'TH 112,00 INCLINATION AZIMLITd 0,00 LATITUDE(N/-S) 0,00 DEF'ARTURE(E/-W) 0,00 DEP(E/-W) 0,00 7 ANADRILL ~JRVEY CALCU~TI~S CIRCULAR AB£ MEASURED INTERVAL V~TICAL DEFT,, D~F~H ft ft ft 112,00 0,0 112,00 174,00 6£,0 174,~Ou 260,76 ~6,~ ~" "~ . £00,1 ~ 441,82 89,8 441,~1 533~19 £~4 806,08 898.0t ,~.,. I!~,~' 9~,$ 805,73 91,9 897,3~ ~ARGE; STA?ION AZimUTH gATtTUDZ SECTION INCLN. N/-S ft dea ~ea ft 0.(~ 0,00 0,00 0.00 0,06 0.32 297,7! 0,08 0,23 0,37 296,4! 0,32 0,57 0,64 ~ 307~13 0,75 ~,03. 0,5~ 305,47 1 ,o~ 0,00 0,00 0,00 -0,15 0,i7 297,71 -g,~Z v.o? ~7/~19 -1,26 .1,49 300;42 ~ ~ '" :2;44 302,74 -Z,oS. ;,' .,'. .. !OOft 0 j.- 0,04 "'..,, 31 ,. 4:32 2,dC.~ opv,09 4/73 -r.~l~, ._. ,_~.~4 .:,_~..-- .~'.;.'1 ~,52 3:23 352,7'~ ". ":'~ -4,7':,' '"" i.' ~ 7,/=." . · - Lf~'~/: - · i°,8,~ ~' ~ 347,i3 14,80 -5,79 ._, ,-., a, u.., ... 21,28 6,02 '.::47 ..A4 ..... 22,~n.,... -7 .j,=' ;:.q, 7Z__. 54i,54 2,38 938,19 !tV_,4,6& i179,08 1D5.46.. 1371 90,2 986,92 ?6,5 ~n~4~ 94,4 1175,61 96,4 1270,39 96.3 1364.4! 3i,02 7,01 351,91 32,57 43,6/ 8,~4 348.i5 45,66 58,44 ?.y~"= 354,70 A0,87. 75,59 1!,03 356.!3 78,37 95,M 13,7! 357,49 98,96 -'?,30 .:.~ ,w 344,07 1 · ?'.-" -il ,65 47, r2 345,69 i ,97 -13,85' ,.,~c',44 347.. .:40 - 16,40 !00,3! 350,59 1466,61 1750,49 1846,05 94,9 1456,11 93,A 15~6,03 94,7 1726,97 117,87 16,00 0,23 123,25 145.82 !6,34 4,!7 149,32 !73,~8 17,&3 6u?O 177,07 204,47 20,34 9,08 ~" == 23'?,~5 22,39 10,~ 24!,84 -t6,84 124,42 352,22 2,53 -13,!2 177,56 355,76 ~,56 ~ on 207,74 %7,57 . ,- .... -2,80 ~41,86 359,34 194t ~= D36 2133,39 2226,63 2oZo,oo 95,2 t903,07 '9~.4 1787,84 96.7 ~A~A-~? 93,2 2146,69 97,2 2223.44 DT/,SX~ 25.18 10,19 279,60 ~,~z ,43 371,66 ..... ~ ~0,34 ~/Z.~ 425,15 36,72 !0.~0 424,94 .~4,73 38.93 i0,18 483,64 4,14 279 11,87 322,89 2,i! · '= . ?'= ZO,-:,s "-"'-' ~ ,20 30,c.c;'"~' ~2,~, . ,02 4,,.,~'," _~ r;.,;.'~ 485,:,, "''-'' 4,S4. 4,45 4 3,58 2418,95 270~,29 2800.40 95,1 2295,67 ,~,/ 2362,yz 96,9 2430,15 93,7 2492,02 98,1 2~3,54 660.i3 47.42 7¢n ~ 49,95 7,an 746,64 ~26,96 52,35 7,21 822,42 50,97 947 r,t 5 60,23 ~lr,.v~ 7fi ~e A~fl.~ 5,91 °°,46 827,Z7 A,Z! '3,54 2,7? 2,44 2990,54 30~3,19 3178,~ 94,9 2609,74 95.2 2&S2,&! 55,4 276i.&S 94,7 2808,38 903,44 55,03 7 = _ ,,4: 89R,27 982,~0.. s7,22 1060,79 58,1~ ~,57 ~ "~ !142,48 59 .,.~ '~zd 1134,72 t924 o~ 6i,24 ~,31 99' ':''~ 903,72 _110.70 o~,75, ~,~ ,.,',44 . 121 ~'' 1061,01 '~ ~"' ,-_,£ . ,.,, .:'7 134,47 1142,66 6,.76 147,7'~ · , / 2,48 !,04 1,60 1,73 3247.18 3462,47 3652,97 3746,48 2893.8! 95,4 2965,17 93,5 2'3%.84 1307,74 ~",,~ !0,03 1297,A0 1393,42 65,20 9,47 1382,29 1480,69 68.17 9,!0 i4~4,45 1569,93 70.4i 8,57 !556,64 1A97,90 .... 69,99 8 .7o~'~ 1643,60 ..~ ~. ! ' 1~?0,% 7,26 176.iY ~,'-, 'o ,~s 1480,72 7 c~ D3,98 !569,95 7,47 ~7 !657,9Z 7.5d 2,05 2,31 3,15 2,4! 0,58 PAGE r,-,..-25 $U~EY £~IZ1JLATiON$ CIRCULAR ARC ME?~D*.~.**~* ~NT~R¥~ VERTICAL DEPTH DEPTH 3639,40 ?2,9 3027,?0 3926,70 87,3 3056.18 4027,58 100,9 %~ % 4123,25 ?5,7 31~''' ~ 4~j.~ 92,0 3148.06 TARGET $TAT!£~ AZI~JTH k4TITUDE SECTION INCLN, N/-S ft ~eo ~eo !745,47 70,76 6.62 1730,35 1828 ~ 71 ~ g,g~ 18127~ 1923,46 70,92 6,38 P707,i4 2014,10 71,9~ ~ ~v 1997,36 2101,4! 7! ~ = ~= ~084.21 DEPARTURE DISPLACEMD;T ar AZIMUTH ft ft Oeo 229,36 1745,48 7,55 239,18 1~28,07 7,52 250.16 1923,48 7.47 259,45 2014,i4 7,40 267,?'? 2101,47 7,33 DLS de~/ iOOf, 2,38 0,30 0,52 1,49 0,63 4402,: '~ 4496,56 4592,17 46~6,14 ~2,~ 3177.80 o~ 1 3208.16 94,0 °294,°s ~1~,~2 70 ~ ~ ,~ J,u, 217i 2278,87 7!,92 7 =~ . .,a,., 224~,93 2368,i6 72,i0 7,34 ~47,46 ~'~ ~ .... 7~38 2439,74 2548,90 73,23 S,12 ~28,64 L%,31 2t88,90 7 . . .... =¢ 2278,98 277,51 2 ..... ~ ,~,., 309,47 2459,29 7,23 ~1,57 2549,00 7,25 !,16 2,73 0,30 0,14 1,31 4774,45 4875,85 4967,67 4993.77 5085.~ ~.,3 33!9.69 t0!,4 ~ 43 26.1 33~3.33 92,1 3412.67 ~,0~o,,9 73,42 ¢,06 26!2,39 ~30,73 7~,g5 8,22 2708 ~ ~ 72,;s 8,8~ 27~5,46 £010 ~4 Z~4o,oJ 72,!6 9,77 ~g0,5~ 70,67 a ~ 2906,17 c6~3,¢y 7,27 333,48 ~ ~ =~ 347,25 27~,82 7,31 360,24 2818,58 7,34 364 ~ 2843,42 7,36 377,90 ~930,63 7,41 0,22 0,28 1,64 3,56 2.27 5!~I,76 5372,!I 5467.72 JJ~o,12 94,9 3509,95 ';s.^ 3542,67 ._ %~ ~ 70 "~ 9,06 2995,75 ,Oi . 3ii0.77 69.94 7,80 3084,38 319~,80 69 '~ ,33 3i72,64 ~"'~"'" 70,35 '" ~' ,56 3379,$~ 69,97 5, (~, 3350,31 371 =" ~:021 .... 7,45 ~M,65 3110,h:i 7,47 416.37 3?¢¢,84 7,48 429,12 ..... ' o~oV,6/ 7,50 442,37 337?,3? / 0,'?0 0,57 1,79 1,05 5659, 5, _-~, 49 5849. .... '~,,24 96,1 3608.15 95,2 3641.20 94.8 3674,6! 92,? 3706.90 96,2 3739,40 3'.46.?,6! 69,76 7,83 3439,71 3558,94 69,64 g.22 3528,t5 3647.69 69.10 8,67 3615.95 3734,60 70.24 7,58 3702,19 ~_ J,3B 70,30 9,51 3771,.77 454,8.0 ~o ~ 7,53 · _~,.,l, ~..~ . ¢57 ~ os~.~ 7 agO/W) ~A47 ~' 7 ~? ,... ~ _ . . ,/ ~ 492,6! 3734,52 7,58 506,06 3825,39 7,60 0,28 0,4f~ 0,73 1.65 ! 6!33,39 6230.00 6324,12 64!7,25 6512,82 . . Ozz 96.6 3~03,53 94,t o~ 40 %,1 38h5,36 5~14,61 70 a~ ' -' ~79 ge _.. ,va Y,ZO , 4(~74,67 70,31 5.04 4057,76 ~1~?,49 70.87 9.01 4144 ~ , .~ ..... ~ , ,..~ 4~o,69 4272 ~ 70,00 7.91 "~ 535,19 4005,77 7.66 548.55 4094.67 7.70 561.57 i1~9.47 7.72 ~v~ ~ 4272,54 7 ~ 0,43 1,44 1,69 1,16 1,41 6606.44 6703,42 6798.0! 6891.35 6985.93 55,6 3~i9,65 97,0 39.~.23 94,6 93,4 4026,01 94,6 4056,05 4360.41 69,65 9,10 43~,60 445i,38 69,83 5.49 4410.52 4540,32 70,44 8,55 4498,49 '~" = . 4585 4o~.ol 71,~5 ~,4E 4718,17 71.69 7,26 %74,54 ~'~ ~":' 4o_.0.41 7,7s did/ ,l_.& . ~ 601.73 ~451.37 7,77 614,90 4540,32 7,78 627,9~ 4628,51 7,80 68~, 14 4718,17 7 ar 1,24 0,62 0,64 0,89 1,25 7080,36 7177.7E 7273,40 7~.6,37 7460.24 94.4 4085,81 97.4 41!6,97 95.7 4147.53 93.0 4!s/.7~ .... ~307,78 71,57 7,39 47~,4~ 4900,02 7!.10 7,80 4854,86 49?0,69 71,64 7,86 4944,68 5078,61 70,45 6,37 5031.9~ 5167 ~ 71,A2 6,!1 5120.17 ,~ __ 651,56 4807.78 7,7? .%3,75 4900,02 7,79 676.1i 4990,6? 7,79 687,01 5078,6i 7,77 ~'>~ &~ 5167 ~ 7.75 0.18 0,63 0,57 1,99 1,28 ntb-25 ANHDRIhL ************** ~************ CIRCUI.3¢~ A~: METHOD******** DEPTH DEPTH ft ft ft 755t,67 91,4 4236.89 7648,27 96,6 4268,17 7741.!9 92,9 4298,22 7831,92 90,7 4326,62 7926,66 94,7 4357,82 ~=~ STATIOM AZIMUTH LATITUDE SECTION tNCD~, N/-S ft ~e.~ ~eq ft ~=.~,~ ,o~ 6,68 5206,44 5345,51 70 ~ 5.62 5433.41 71.35 5,0? 5384,57 55_,19 ~ 7i,37 7,~3 .... .46,,8~ 509~,03 70.43 6,91 5558,70 uEARI~]RE !)ISPLACEMENT at AZII~JTH ft ft 706,47 5254,15 7.73 716.42 5345,51 7,70 726,92 -' 7qB.K4 ~r r 74g,72 5609,04 DLS dec/ lOOft 0,83 !,94 2,99 1,1Z 8019.98 6116,57 ~2i2,35 ~'.07,9! 93,3 4389,62 96,6 4422,44 95,8 4454,08 95,6 4484,74 94,7 ~,~ · . ~ 5696,77 69,73 7,14 · 5787.60 ~ ~ 5876,01 70,91 7.32 5825,49 5968,51 71,66 7,50 5915.24 An~ 13 ~ ~ ~,19 760,46 5%96,77 7,67 772.20 5787,61 7,67 784,r02 5878,02 7,67 ..795,70 5968 ,~ =~ 7,66 807.93 6058.!4 7,66 0.78 0.9'? 0.55 ! ,',!'7 94.4 4546,20 ~5,3 4576.~. 95.4 4606.93 96.0 4637,67 92.9 4667.!7 6i47.~? 71.i6 3,03 6092.29 6237,60 "TM ' ' ,~... ~,Zl 6!81,70 ~7,96 70,99 5,60 6271,09 6416,94 7!.68 7.74 6361.15 6~)6.9'? 71,25 7.06 6448,47 820.52 6147.30 7.67 ~ c~ 6237,61 7,68 846.49 6327.97 7.69 859,42 64!8.95 7.69 870.76 6506,99 7,69 0,56 0,66 0.90 1.11 0.82 8972,04 .u ..... I1 9~45,~ 9~7,24 9326,39 55.6 4696,92 !14.i 47~2.10 :¢ .... 4751,05 91,5 ,"o~ 89.2 48!0,24 A~97.79 72.44 6.30 :~'::" '''~ '.J-: . .,/u,.,, z,_, 7i ,64 9,g& A64A,~! .... : . .. 676'7-' "'" 7~ """ . ,o~ ,o; 7,26 ~.&4~ ,c5 70,60 4,¢:, 6788,07 6933,3:5 70,98 6:8.1 687 i. 85 88I .t.' "¢"" -'" ...,Y/ 896,37 6706~ 904,69 :-~ :'~ ~.s - ,., ...... ,,...,.. /. 69 913.42 .r~,,,', .... ,~:.,-o 7,66 '92!,=''j.? 6933,38 -/, 64 1,43 2,8? 3,86 3,12 ~417,nA 9508,03 9599.64 9694.71 9759,75 90,6 4639,80 91,0 4669,82 9!,6 4900.i6 95,1 4930,83 95,0 4960,9! 7018.% 70,93 5,97 6956.97 7104,87 70.57/ 5,43 7042.48 7i91 ~= 70,75 s z~ ,~' ~ .... = 7128,52 7281.18 7!.60 5,69 72!8,05 7371,31 71.49 7,9i 7307,54 93t.!2 70!'?.00 7.62 920,66 7104.89 7,60 946,03 7191.29 7.58 957.10 728!,23 7,55 · -. - ~/ ~ .~'.: e ~ 0 0,68 0,33 2,03 10074,54 10169,t5 10263.95 94.t 4'}90,94 95.1 502i o~ '35.6 94,6 5084,86 94,8 5116.94 7460,47 ~' 7_5500.42 70,83 6,82 74B5,14 7640,6~ 70,67 7,77 ~74,67 7729.91 ?n.4i · . t ~ .. 7819,07 7o,0! '779,70 7460 ¢= ~ ~¢ .991.i3 7550.48 7,54 !002,58 7640,73 7,54 ~ l 96 101~.5... 7729. 7.55 1029,08 7819.11 7,56 .46 0.64 O. 95 1.22 0,63 10o~... !045.4! 10741,91 ~,0 5149,14 96.5 5181.40 96,7 52i3,77 '~.6 ~' ~ ' '94.2 5276,36 7908.41 70,36 9..~o~' 7839,39 7999.31 70.5'7 8,87 7929.17 8¢r?0,45 70,34 ~, .., ~= 8019 ~ ~180.56 70.70 8.17 8108.64 8269,.9a 7!,~4 9,24 8196,66 1042.86 79~..45 7,5g 1057,19 7999,34 7.59 1070 ~ 8o90.4g .~O ..... 1082.57 8!80.59 1096,05 8269.62 7,62 0,85 0,43 1 0.70 1,22 10838,78 10934.41 11036,2"? i1!27J7 11~18.76_.. 96~? 5306,90 95,6 ~o~t ~ 10!.9 55~7.78 91,5 5396,16 91.0 5424.73 E~.$1,49 72.01 9.23 82B7,40 8452,45 72,12 8.70 8377,26 _ =. _ ' Q 7~ _. A549,~A 71,94 ~,2z ~4,~,1~ 8.536,32 71.9i 6,77 8559,34 87~2.70 7!,4'? 7~04 8645,11 1!10,81 8361,51 7,63 1124,98 8452,46 7.65 1139,24 8549,37 7,66 , ~ ~ . 1!50,58 66o6,o~ !!60,96 8722,71 7.65 0,79 0.54 0,48 1,50 0,54 F'AFj~ NO, 5 ************* A~DRI~ ~**'********** SURVEY CALCULA?iOHS ~************ CiRCULAE ARC M~T~D******** MEASURED iNTERVAL VF~'2!CAL DEPTH t~ ~ 96,0 11407,73 '.;5.0 5485,60 1~....7 92,9 ~..~ 1!598,10 95.4 5547.00 . !16~3.06 '~_,,0 ~8.32 TARGET STATION AZI~]TH LATITUDE S~CTION !HCUq. NI-S ft ~eg Oeo 8813,73 71,43 8,60 8735,29 ~o~, w 71,29 7,61 88~4,37 ~991,62 70,90 6,45 8911,63 ~081,77 70,63 7.93 9171,4! 70,66 7,40 9069,9~ DEPARTURE DiSF'LACEMB4T at AZ!MIJ?H ft ft Oeo 1!73,35 ~.13,74 ~ ~ . / , 1186,03 8903.71 7,65 1196,79 8991,63 ? ,65 1~08.07 '7081,79 7 I~O,OS 9~71,43 7,64 DLS deo/ DOit 1,00 !.25 !,47 0.5A !17~6,62 11975.69 ~vy 93,6 5609,71 ~5,6 5~1.93 93,4 5673.~5 94,6 5705,06 95.4 ~,~7.39~. 925-9.~ 70,14 7,40 9177,33 9349.58 70,48. 7,82 ~66,57 9437.66 70,4~ 7.85 9353.62 ~J4~,/J 70,11 7,49 9442,11 ~ L ' ~", ?.4~,~? 70,26 7.15 9531,12 1231, ~ ~ 9259,57 .7,A4 .. 12-43,31 9349,60 7,64 1~5 "" 94.R7,AA 7,64 .0£ ...... 1267,~i '7526,77 7 1~6,'5... %16,5i 7,64. 0,55 0,55 0,53 0,37 !2~9,24 12446,80 12540.74 12633,~g 9~,t 5800.!4 ~5,5 5832,58 93,9 5864,!6 9~,9 5895,60 9704,54 70,~I 8,40 9618,37 9791,~ 70,02 7,43 9704,20 9880.96 70.24 8.65 9793.08 9?69,43 70,47 ~,01 9&~0,62 10056,61 69,94 7.59 9767,19 1290,56 9704,56 7,64 1302,47 9791,21 7.64 1315,04 9880.98 7,65 1327,85 99A9.44 7,~ 1339,7! 10056,212 7,66 1,27 1.06 1.22 0,69 0.70 12822,37 12915,22 !3012.21 92,9 ~927,TM '~5,9 5960,70 92,9 5992.07 97,0 6024,76 Q~,.~ ~: 6056 10143.96 69,63 ~,55 1(Q53,50 10233.97 70,11 9.22 10142,43 lOll.S6 70,41 7,99 10~8.84 10412,66 70,19 7,78 10319,28 I05CK).37 69,92 7.14 104C~,25 1351,96 10144.00 7,66 1365.86 n~"" . _ l~J.?8 7.A7 1378.92. 10321,37 7.68 13~1,45 1041~,67 7.66 1+32.~5 10500,36 7,6~ !.03 0,82 !.29 0,29 0.71 13202.01 13297,67 13394 o~ 13%6,07 1357~ ~ 96,5 6091,04 95,7 6128,03 97~2 6168,94 91,2 6209,69 9~,3 6252,29 10590.50 68.25 8,25 10495.57 10678.71 66,26 7.04 10583.00 10766,85 63,94 6,69 10670,51 10848.45 62,99 6,86 10751.55 ~ ..~ 10931,40 62.68. ,.4/ 10834.06 1414,91 10590,51 7,68 1426,65 10678,73 7,66 ! 437,19 10766,8.6 7.67 14,~,~,2 10848,46 7.66 !455,73 lOyJl, 42 7, ,b. '~ 2.03 2,39 2,40 1 1,36 13767,65 t3~.,/,~ 13955,49 14048,22 92,8 6295.96 95.5 6343.31 93,6 6392,48 94,2 6444,01 92.7 6495.42 11013,24 61,17 6,45 10915,49 11096,14 59,~ 6.19 10997,92 11175,80 57,26 7.56 1!077.01 11254,65 56,42 6,56 11155_.,2~ 1!S~1,82 56.26 7,24 11231.90 1464,23 11013,26 7,64 1473,C6 11096.17 7,6S A~ 14_~,86 11175,~3 7,62 1492.56 11254.69 7,62 1501,85 11331.86 7,62 1 2,59 0 14144.51 1423~,51 14332,45 14428,80 14521.40 96.3 6549,~ 94,0 6605,02 93.9 96,4 6723,19 9~,6 6784,63 11411,:0 54,76 7,51 11310,62 11487,35 53.44 7,69 11~6,10 llJ..1,Y/ 51,75_ 8,51 11459,98 116~5,% 49,53 7,~? 11533,78 11705,7! 47,o~2 6,15 11602,56 1512,03 11411,23 7,61 1522,!0 11467,~? 7.6i 1532,61 !~JTc,ui 7,62 1542,73 11636.49 7.62 t~0,73 11705,75 7,6! 1,55 1,43 1.93 2.57 2,50 !~517,62 14711,22 14805,75 14899,!2 14994.46 96,2 6851,09 93.6 6917,96 94.5 6987.51 '-15.,47057,40 95.3 11775,24 45.3! = ~ o,~ 11671,80 11640.62 43,~$ 4,13 11737,05 1!904.5~ 41,84 3,34 11800,55 11966.25 41,23 3,91 11862,74 1~29.02 4!.41 3,05 11925,57 1557.69 117.75,29 7,60 1563,09 11840,67 7,59 1567,Z7 11904,57 7.57 1571,18 11966.33 7,54 1575.0! 12029,13 7,52 2,16 t,!7 1,80 0,77 0,62 --PAGE NO, ~A~L~Eu iNTERWAL VERTICAL D~'TH DEPTH f~ f~ ft 150~9.57 95.! 72¢0.42 15184 ~ 94,7 7271.95 ~, c.4, 9~,6 7416 ls~.~ ~s,2 7489.55 TA6~ET S%ATiON AZIMUTH LATITUDE SECTION INCLN, N/-S it deq aeq ft 12091,68 4!,26 4,16 ~'"'~ '-' 12153.5S 40,63 2,9% ~2050.21 !~21;.~Y 4fi.~ 2,93 .... ~ 1~o~ ~ 39.95 ~.29 12172,44 12336,11 39.32 2,67 t2233,i0 DEPARTURE DISPLACEMENT at AZIMUTH it ft deq !~6,98 12091,50 7.50 1582,83 12153,72 7,4~ 1566,03 1~2!5,56 7.4'5 !569.3! 12275.75 7,44 1572,57 12336.33 7,42 uLo 6eo/ lt.;Oft 0 0,3i 0,48 0,7! 15655.00 756!.47 94,1 7636.26 12397..53 3~,0~ 3,02 i~r' ~= **ww F$:COECTiON TO TD ~2450,50 36,70 3,20 12347,73 1595,53 12393,76 7,40 1598,63 12450,78 7,36 i S~ ~RRY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE SHARED SERVICES DRILING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 11/30/95 DATE OF SURVEY: 112695 ELECTRONIC MULTI-SHOT SURVEY JOB NUMBER: AK-EI-50117 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION TRUE SUB-SEA COURS MEASD VERTICAL VERTICAL INCLN DEPTH DEPTH DEPTH DG MN COURSE DLS TOTAL DIRECTION RECTANGULAR COORDINATES DEGREES DG/100 NORTH/SOUTH EAST/WEST VERT. SECT. 0 .00 -46.00 225 225.24 179.24 316 315.99 269.99 406 406.92 360.92 498 498.39 452.39 0 0 0 27 0 35 0 40 1 9 N .00 E .00 .00N .00E N 6.25 E .21 .91N .10E N 5.89 W .19 1.74N .09E N 8.85 W .10 2.74N .04W N 19.54 W .56 4.14N .43W .00 .91 1.74 2.71 4.05 589 589.70 543.70 2 680 680.09 634.09 ~2 771 771.22 725.22 3 862 862.06 816.06 4 953 952.15 906.15 7 1 57 40 48 9 N 5.67 W 1.04 6.62N .90W N .60 E 1.07 10.55N 1.03W N 13.32 W 1.17 15.75N 1.68W N 10.09 W 1.27 22.35N 3.02W N 8.21 W 2.60 31.68N 4.50W 6.44 10.31 15.38 21.74 30.78 1048 1046.80 1000.80 1144 1140.92 1094.92 1239 1234.71 1188.71 1334 1328.57 1282.57 1430 1421.53 1375.53 8 9 10 11 15 10 39 28 51 6 N 9.62 W 1.09 44.26N 6.48W N 6.87 W 1.61 58.88N 8.57W N 3.41 W 1.07 75.46N 10.04W N 2.24 W 1.47 93.98N 10.94W N .79 W 3.40 116.26N 11.50W 42.98 57.18 73.41 91.64 113.64 1526 1513.53 1467.53 1621 1605.31 1559.31 1716 1695.42 1649.42 1812 1785.19 1739.19 1907 1873.63 1827.63 15 58 16 34 19 11 21 33 23 10 N 3.35 E 1.48 141.82N 10.90W N 6.42 E 1.10 168.53N 8.60W N 8.46 E 2.83 197.35N 4.80W N 9.72 E 2.52 230.27N .48E N 11.49 E 1.83 266.04N 7.20E 139.05 165.82 194.90 228.23 264.57 2003 1960.14 1914.14 27 13 2098 2042.81 1996.81 31 14 2194 2123.19 2077.19 34 47 2289 2200.57 2154.57 36 58 2384 2274.32 2228.32 40 24 N 11.47 E 4.24 305.93N 15.30E N 11.43 E 4.24 351.28N 24.48E N 11.26 E 3.70 402.48N 34.75E N 11.54 E 2.30 457.35N 45.81E N 10.49 E 3.70 515.33N 57.08E 305.20 351.37 403.49 459.35 518.32 2479 2345.62 2299.62 42 59 2575 2413.91 2367.91 45 50 2670 2478.89 2432.89 48 30 2765 2540.67 2494.67 50 31 2861 2599.58 2553.58 53 19 N 9.01 E 2.90 577.93N 67.82E N 8.59 E 3.00 644.05N 78.05E N 8.67 E 2.79 713.37N 88.57E N 8.50 E 2.13 784.93N 99.37E N 8.23 E 2.93 859.34N l10.31E 581.79 648.69 718.79 791.16 866.37 2957 2654.98 2608.98 55 48 3052 2707.17 2661.17 57 43 3147 2757.62 2711.62 58 22 3243 2806.52 2760.52 60 7 3337 2852.63 2806.63 61 34 N 8 . 74 E 2 . 64 936 . 35N 121 · 81E N 9.23 E 2.05 1015.02N 134.25E N 9.91 E .92 1094.78N 147.70E N 10.22 E 1.85 1175.71N 162.06E N 10.46 E 1.56 1257.04N 176.90E 944.22 1023.85 1104.70 1186.83 1269.42 RRY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE SHARED SERVICES DRILING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 11/30/9 DATE OF SURVEY: 112695 ELECTRONIC MULTI-SHOT SURVEY JOB NUMBER: AK-EI-50117 KELLY BUSHING ELEV. = 46.00 OPERATOR: BP EXPLORATION FT. TRUE SUB-SEA COURS MEASD VERTICAL VERTICAL INCLN DEPTH DEPTH DEPTH DG MN COURSE DLS TOTAL DIRECTION RECTANGULAR COORD DEGREES DG/100 NORTH/SOUTH EAST I NAT E S /WEST VERT. SECT. 3433 2896.28 2850.28 3526 2935.67 2889.67 3622 2971.47 2925.47 3717 3004.04 2958.04 3813 3035.89 2989.89 63 53 N 10.88 E 2.45 66 22 N 10.34 E 2.71 69 23 N 9.90 E 3.19 70 45 N 10.31 E 1.49 70 20 N 9.29 E 1.10 1340.28N 192.58E 1423.82N 208.23E 1510.56N 223.70E 1599.02N 239.47E 1687.87N 254.82E 1354.01 1438.90 1526.93 1616.71 1706.82 3908 3067.02 3021.02 4004 3097.24 3051.24 4099 3127.13 3081.13 4194 3156.63 3110.63 4289 3186.48 3140.48 71 37 N 7.78 E 2.01 7-1 28 N 7.81 E .17 71 44 N 7.13 E .74 72 13 N 6.80 E .61 71 20 N 5.59 E 1.51 1777.23N 268.22E 1866.96N 280.51E 1956.10N 292.19E 2046.13N 303.18E 2136.31N 312.97E 1797.17 1887.74 1977.64 2068.33 2159.01 4385 3216.79 3170.79 4481 3245.97 3199.97 4576 3274.45 3228.45 4671 3302.22 3256.22 4767 3329.16 3283.16 71 45 N 7.31 E 1.75 72 35 N 8.42 E 1.41 72 41 N 8.16 E .28 73 27 N 8.64 E .94 73 50 N 8.79 E .43 2226.60N 323.18E 2316.50N 335.60E 2406.64N 348.73E 2496.89N 362.06E 2587.64N 375.97E 2249.85 2340.60 2431.68 2522.91 2614.71 4863 3355.66 3309.66 4958 3382.61 3336.61 5052 3411.04 3365.04 5147 3441.78 3395.78 5243 3473.40 3427.40 74 4 N 9.02 E .34 73 0 N 9.06 E 1.13 71 37 N 9.07 E 1.47 70 53 N 8.74 E .84 70 34 N 8.64 E .35 2678.66N 390.23E 2768.76N 404.56E 2856.78N 418.61E 2946.27N 432.63E 3035.66N 446.29E 2706.82 2798.03 2887.14 2977.70 3068.12 5338 3505.65 3459.65 5434 3538.50 3492.50 5529 3570.85 3524.85 5625 3602.98 3556.98 5720 3635.05 3589.05 69 41 N 6.68 E 2.14 70 6 N 8.52 E 1.86 70 22 N 8.97 E .51 70 24 N 8.90 E .08 70 11 N 8.73 E .28 3124.08N 458.19E 3213.06N 470.07E 3302.10N 483.77E 3391.20N 497.77E 3479.71N 511.49E 3157.33 3247.10 3337.18 3427.35 3516.91 5815 3667.60 3621.60 5911 3700.65 3654.65 6006 3732.92 3686.92 6101 3764.34 3718.34 6197 3796.36 3750.36 69 48 N 8.32 E .57 69 40 N .54 E 7.67 70 47 N 9.13 E 8.58 70 35 N 8.85 E .35 70 25 N 9.21 E .40 3568.13N 524.75E 3657.17N 531.65E 3746.38N 539.22E 3834.95N 553.23E 3924.32N 567.44E 3606.31 3695.47 3784.88 3874.53 3965.00 6292 3827.45 3781.45 6387 3858.54 3812.54 6482 3890.34 3844.34 6575 3922.03 3876.03 6670 3955.12 3909.12 71 18 N 8.64 E 1.08 70 37 N 8.70 E .71 70 14 N 9.10 E .56 69 45 N 8.81 E .61 69 41 N 8.90 E .10 4012.82N 4101.90N 4190.32N 4276.32N 4364.83N 581.34E 594.92E 608.77E 622.32E 63,6.11E 4054.57 4144.67 4234.14 4321.19 4410.75 ~RRY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE SHARED SERVICES DRILING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 11/30/95 DATE OF SURVEY: 112695 ELECTRONIC MULTI-SHOT SURVEY JOB NUMBER: AK-EI-50117 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION TRUE SI/B-SEA COURS COURSE DLS MEASD VERTICAL VERTICAL INCLN DIRECTION DEPTH DEPTH DEPTH DG MN DEGREES DG/100 TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST VERT. SECT. 6765 3988.01 3942.01 69 44 N 8.90 E .04 6859 4019.71 3973.71 70 40 N 9.11 E 1.03 6954 4050.18 4004.18 71 53 N 8.13 E 1.61 7049 4079.60 4033.60 72 0 N 8.32 E .22 7144 4109.42 4063.42 71 44 N 8.12 E .34 4452.76N 649.88E 4499.73 4539.74N 663.67E 4587.78 4628.67N 677.14E 4677.71 4718.00N 690.05E 4767.97 4808.14N 703.07E 4859.04 7239 4139.31 4093.31 71 17 N 7.93 E .52 7332 4169.15 4123.15 7-1 27 N 7.63 E .35 7425 4199.21 4153.21 70 46 N 7.43 E .76 7520 4229.62 4183.62 71 52 N 7.35 E 1.16 7614 4259.09 4213.09 71 38 N 7.41 E .25 4896.69N 715.55E 4948.46 4984.38N 727.53E 5036.97 5071.52N 739.06E 5124.87 5160.72N 750.63E 5214.81 5249.39N 762.11E 5304.22 7707 4288.59 4242.59 71 19 N 7.57 E .39 7800 4317.78 4271.78 72 4 N 8.49 E 1.24 7895 4347.53 4301.53 71 26 N 8.30 E .68 7989 4378.00 4332.00 70 35 N 7.70 E 1.10 8084 4410.27 4364.27 69 58 N 7.96 E .70 5336.73N 773.60E 5392.32 5424.11N 785.93E 5480.56 5513.38N 799.11E 5570.79 5601.11N 811.44E 5659.38 5690.29N 823.70E 5749.39 8180 4442.45 4396.45 70 44 N 8.02 E .81 8212 4453.05 4407.05 71 3 N 8.60 E 1.95 8275 4473.46 4427.46 71 7 N 8.19 E .61 8370 4503.81 4457.81 71 26 N 8.59 E .52 8464 4534.23 4488.23 70 54 N 8.54 E .58 5779.56N 836.23E 5839.54 5809.83N 840.66E 5870.14 5868.79N 849.36E 5929.73 5957.45N 862.44E 6019.35 6045.69N 875.73E 6108.57 8496 4544.63 4498.63 71 19 N 9.04 E 1.95 8559 4564.68 4518.68 71 34 N 9.19 E .45 8655 4594.73 4548.73 71 43 N 8.32 E .87 8750 4625.11 4579.11 71 13 N 8.17 E .54 8844 4654.79 4608.79 71 55 N 7.89 E .79 6075.74N 880.37E 6138.97 6134.71N 889.83E 6198.68 6224.22N 903.62E 6289.24 6313.93N 916.62E 6379.88 6402.14N 929.06E 6468.96 8938 4684.38 4638.38 71 2 N 6.76 E 1.48 6489.74N 9043 4718.48 4672.48 71 2 N 6.76 E .00 6588.36N 940.32E 6557.28 952.01E 6656.57 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. HORIZONTAL DISPLACEMENT = 6656.79 FEET AT NORTH 8 DEG. 13 MIN. EAST AT MD = 9043 VERTICAL SECTION RELATIVE TO WELL HEAD VERTICAL SECTION COMPUTED ALONG 7.76 DEG. ~RRY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE SHARED SERVICES DRILING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 11/30/95 DATE OF SURVEY: 112695 JOB NUMBER: AK-EI-50117 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 1000 FEET OF MEASURED DEPTH TRUE SUB-SEA TOTAL MEASD VERTICAL VERTICAL RECTANGULAR COORDINATES MD-TVD DEPTH DEPTH DEPTH NORTH/SOUTH EAST/WEST DIFFERENCE VERTICAL CORRECTION 0 .00 -46.00 .00 N .00 E .00 1000 998.56 952.56 37.45 N 5.33 W 1.44 2000 1957.10 1911.10 304.40 N 14.99 E 42.90 3000 2679.10 2633.10 971.44 N 127.21 E 320.90 4000 3095.85 3049.85 1862.86 N 279.94 E 904.15 1.44 41.47 278.00 583.25 5000 3394.72 3348.72 2807.85 N 410.80 E 1605.28 6000 3730.81 3684.81 3740.40 N 538.29 E 2269.19 7000 4064.43 4018.43 4671.81 N 683.30 E 2935.57 8000 4381.61 4335.61 5611.24 N 812.81 E 3618.39 9000 4704.51 4658.51 6547.97 N 947.22 E 4295.49 701.13 663.91 666.38 682.82 677.09 9043 4718.48 4672.48 6588.36 N 952.01 E 4324.52 29.04 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. ~RRY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE 5 SHARED SERVICES DRILING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 11/30/95 DATE OF SURVEY: 112695 JOB NUMBER: AK-EI-50117 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE SUB-SEA TOTAL MEASD VERTICAL VERTICAL RECTANGULAR COORDINATES MD-TVD DEPTH DEPTH DEPTH NORTH/SOUTH EAST/WEST DIFFERENCE VERTICAL CORRECTION 0 .00 -46.00 .00 N .00 E .00 46 46.00 .00 .00 N .00 E .00 146 146.00 100.00 .27 N .03 E .00 246 246.00 200.00 1.08 N .12 E .00 346 346.00 300.00 2.05 N .06 E .01 .00 .00 .00 .01 446 446.00 400.00 3.21 N .12 W .02 546 546.00 500.00 5.12 N .74 W .04 646 646.00 600.00 8.78 N 1.05 W .11 746 746.00 700.00 14.18 N 1.31 W .26 846 846.00 800.00 21.02 N 2.79 W .50 .01 .02 .07 .15 .25 947 946.00 900.00 30.92 N 4.39 W 1.03 1047 1046.00 1000.00 44.15 N 6.46 W 1.92 1149 1146.00 1100.00 59.74 N 8.67 W 3.16 1250 1246.00 1200.00 77.55 N 10.16 W 4.75 1352 1346.00 1300.00 97.76 N 11.07 W 6.79 .52 .90 1.24 1.59 2.04 1455 1446.00 1400.00 122.86 N 11.59 W 9.90 1559 1546.00 1500.00 151.11 N 10.35 W 13.83 1664 1646.00 1600.00 181.02 N 7.08 W 18.26 1770 1746.00 1700.00 215.10 N 2.10 W 24.04 1877 1846.00 1800.00 254.44 N 4.84 E 31.74 3.12 3.92 4.43 5.78 7.69 1987 1946.00 1900.00 298.94 N 13.88 E 41.58 2101 2046.00 2000.00 353.19 N 24.87 E 55.92 2221 2146.00 2100.00 418.02 N 37.84 E 75.82 2347 2246.00 2200.00 492.23 N 52.71 E 101.26 2480 2346.00 2300.00 578.28 N 67.87 E 134.08 9.85 14.33 19.90 25.44 32.82 2621 2446.00 2400.00 677.49 N 83.11 E 175.80 2774 2546.00 2500.00 791.39 N 100.34 E 228.38 2941 2646.00 2600.00 923.28 N 119.80 E 295.09 3125 2746.00 2700.00 1076.20 N 144.45 E 379.49 3324 2846.00 2800.00 1245.00 N 174.67 E 478.05 41.72 52.58 66.71 84.40 98.56 3553 2946.00 2900.00 1447.61 N 212.54 E 607.27 3843 3046.00 3000.00 1715.82 N 259.39 E 797.38 4159 3146.00 3100.00 2013.21 N 299.26 E 1013.67 4481 3246.00 3200.00 2316.59 N 335.61 E 1235.22 4828 3346.00 3300.00 2645.24 N 384.93 E 1482.29 129.22 190.11 216.30 221.54 247.07 ZRRY-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE SHARED SERVICES DRILING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 11/30/95 DATE OF SURVEY: 112695 JOB NUMBER: AK-EI-50117 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE SUB-SEA TOTAL MEASD VERTICAL VERTICAL RECTANGULAR COORDINATES MD-TVD DEPTH DEPTH DEPTH NORTH/SOUTH EAST/WEST DIFFERENCE VERTICAL CORRECTION 5160 3446.00 3400.100 2958.30 N 434.48 E 1714.71 5456 3546.00 3500.00 3233.58 N 473.14 E 1910.17 5753 3646.00 3600.00 3509.75 N 516.11 E 2107.02 6046 3746.00 3700.00 3783.42 N 545.16 E 2300.14 6349 3846.00 3800.00 4066.65 N 589.53 E 2503.77 232.42 195.46 196.85 193.12 203.63 6644 3946.00 3900.00 4340.47 N 632.30 E 2698.40 6940 4046.00 4000.00 4616.02 N 675.34 E 2894.71 7260 4146.00 4100.00 4916.24 N 718.27 E 3114.05 7573 4246.00 4200.00 5210.24 N 757.02 E 3327.01 7890 4346.00 4300.00 5508.88 N 798.45 E 3544.67 194.63 196.31 219.34 212.96 217.66 8191 4446.00 4400.00 5789.64 N 837.67 E 3745.29 8501 4546.00 4500.00 6079.74 N 881.01 E 3955.20 8816 4646.00 4600.00 6375.46 N 925.36 E 4170.52 9043 4718.48 4672.48 6588.36 N 952.01 E 4324.52 200.62 209.90 215.32 154.01 THE CALCULATION PROCEDURES USE A LINEAR INTERPOLATION BETWEEN THE NEAREST 20 FOOT MD (FROM MINIMUM CURVATURE) POINTS SPE -SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE SHARED SERVICES DRILLING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 12/11/95 DATE OF SURVEY: 120495 ELECTRONIC MULTI-SHOT SURVEY JOB NUMBER: AK-EI-50119 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH COURS INCLN DG MN COURSE DLS TOTAL DIRECTION RECTANG~ COORDINATES DEGREES DG/100 NORTH/SOUTH EAST/WEST VERT. SECT. 8938.00 4684.38 4638.38 9160.00 4755.58 4709.58 9255.63 4786.82 4740.82 9350.63 4818.01 4772.01 9445.63 4848.94 4802.94 71 19 71 15 70 36 71 3 70 56 N 6.76 E .00 6489.74N 940.32E N 6.16 E .26 6698.67N 963.98E N 5.35 E 1.05 6788.60N 973.05E N 6.76 E 1.48 6877.82N 982.51E N 6.47 E .31 6967.05N 992.86E 6557.27 6767.49 6857.81 6947.50 7037.31 9540.63 4880.26 4834.26 70 33 9635.63 4911.33 4865.33 71 16 9730.63 4941.65 4895.65 71 29 9856.63 4981.62 4935.62 71 30 9951.63 5012.16 4966.16 70 59 N 5.31 E 1.23 7056.26N 1002.07E N 6.59 E 1.48 7145.54N 1011.38E N 7.38 E .82 7234.90N 1022.33E N 7.37 E .00 7353.41N 1037.66E N 7.65 E .62 7442.59N 1049.42E 7126.94 7216.67 7306.69 7426.18 7516.13 10046.63 5043.23 4997.23 70 49 10173.03 5085.38 5039.38 70 12 10268.03 5117.72 5071.72 69 59 10363.03 5149.78 5103.78 70 33 10458.20 5181.55 5135.55 70 25 N 9.06 E 1.41 7531.41N 1062.46E N 8.65 E .57 7649.15N 1080.79E N 8.13 E .57 7737.52N 1093.82E N 9.03 E 1.08 7825.94N 1107.17E N 8.53 E .52 7914.60N 1120.87E 7605.89 7725.04 7814.36 7903.77 7993.46 10554.00 5213.37 5167.37 10649.58 5244.36 5198.36 10744.55 5274.21 5228.21 10840.32 5303.59 5257.59 10935.51 5332.75 5286.75 70 46 71 22 72 0 72 15 72 4 N 9.12 E .68 8003.89N 1134.73E N 9.30 E .65 8093.14N 1149.20E N 9.59 E .72 8182.07N 1164.00E N 9.22 E .46 8272.00N 1178.90E N 8.51 E .75 8361.53N 1192.87E 8083.81 8174.19 8264.31 8355.42 8446.02 11030.58 5362.03 5316.03 11125.96 5391.84 5345.84 11218.00 5420.92 5374.92 11313.55 5451.14 5405.14 11409.05 5481.79 5435.79 72 3 71 31 71 38 71 28 71 5 N 8.00 E .51 8451.04N 1205.85E N 7.63 E .66 8540.80N 1218.16E N 7.97 E .38 8627.31N 1230.01E N 7.49 E .51 8717.13N 1242.21E N 7.10 E .57 8806.85N 1253.69E 8536.46 8627.06 8714.39 8805.03 8895.48 11503.95 5512.63 5466.63 70 59 11597.55 5543.28 5497.28 70 46 11692.51 5574.98 5528.98 70 13 11787.22 5606.95 5560.95 70 18 11882.43 5638.86 5592.86 70 31 N 7.57 E .49 N 7.86 E .36 N 7.60 E .64 N 7.31 E .30 N 7.68 E .42 8895 . 86N 1265 . 15E 8983 . 50N 1277.03E 9072 . 20N 1289 . 06E 9160.59N 1300.63E 8985.22 9073.66 9163.17 9252.32 9342.02 SPF '.-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE SHARED SERVICES DRILLING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 12/11/95 DATE OF SURVEY: 120495 ELECTRONIC MULTI-SHOT SURVEY JOB NUMBER: AK-EI-50119 KELLY BUSHING ELEV, = 46.00 OPERATOR: BP EXPLORATION FT. TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH COURS INCLN DG MN COURSE DLS TOTAL DIRECTION RECTANGULAR COORDINATES DEGREES DG/100 NORTH/SOUTH EAST/WEST VERT, SECT, 11977,32 5670,76 5624,76 70 11 12070,71 5702,36 5656,36 70 14 12164,10 5733,85 5687,85 70 20 12256,64 5764,92 5718,92 70 25 12349,55 5796,09 5750,09 70 22 N 7,33 E ,49 9338,13N 1324,00E N 7,98 E ,66 9425,23N 1335,70E N 8,21 E ,25 9512,27N 1348,08E N 8,21 E ,10 9598,55N 1360,53E N 8,17 E ,08 9685,18N 1373,00E 9431,39 9519,27 9607,18 9694,35 9781,87 12444,81 5827,94 5781,94 12540,20 5860.02 5814,02 12635,78 5892,81 5846,81 12730,69 5925,26 5879,26 12825,80 5957,19 5911.19 70 34 70 7 69 44 70 15 70 30 N 8,88 E ,73 9773,96N N 8,59 E .54 9862,76N N 8,23 E ,53 9951,57N N 8,92 E ,88 10039,76N N 8.55 E ,45 10128,31N 1386,31E 9871,64 1399,95E 9961,46 1413.08E 10051,24 1426,38E 10140,42 1439,99E 10229,99 12921,01 5989,02 5943.02 13014,05 6020,48 5974,48 13108,80 6053,77 6007,77 13201,69 6088,55 6042,55 13296,55 6125,29 6079,29 70 25 70 2 68 49 67 11 67 13 N 8,62 E ,11 10217,04N N 8,23 E ,56 10303,65N N 7,49 E 1,49 10391,52N N 7,59 E 1,75 10476,90N N 7,50 E .10 10563,59N 1453,39E 10319,71 1466,21E 10407,27 1478,35E 10495,97 1489,65E 10582,09 1501,14E 10669,54 13391.55 6164.09 6118.09 13486,55 6206,03 6160,03 13579.55 6248,38 6202.38 13671.55 6291.96 6245.96 13764,55 6338.88 6292,88 64 33 63 2 62 46 60 39 58 43 N 6,40 E 3.00 10649,66N N 5,95 E 1,65 10734,40N N 6.16 E .35 10816,74N N 6.77 E 2.38 10897.23N N 6,81 E 2.08 10976.94N 1511.63E 107~6,24 1520,80E 10841.44 1529.54E 10924.20 1538.65E 11005.19 1548,14E 11085,45 13857,55 6388.31 6342,31 13953,00 6440.60 6394,60 14047,55 6492,93 6446.93 14205,55 6582,14 6536.14 14298.84 6637.05 6591.05 57 3 56 29 56 17 54 57 52 54 N 6,95 E 1.79 11055.14N N 6.86 E .60 11134.41N N 6,70 E .25 11212,61N N 6,01 E .92 11342,20N N 7.77 E 2,66 11417.04N 1557,57E 11164,21 1567,17E 11244,05 1576,47E 11322.79 1590.92E 11453.14 1599,95E 11528.52 14394.43 6695.90 6649.90 14489.00 6756.94 6710,94 14583.70 6821.08 6775.08 14679.02 6887.79 6841.79 14774.66 6957.23 6911.23 51 4 48 31 46 10 44 58 41 53 N 7.59 E 1.93 11491.68N N 6,66 E 2.79 11563.34N N 5.45 E 2.65 11632.59N N 4.27 E 1.54 11700.42N N 3.14 E 3.33 11766.03N 1610.01E 11603.83 1618.98E 11676.05 1626,33E 11745,66 1632.10E 11813.65 1636.36E 11879,23 SP5 '-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE 3 SHARED SERVICES DRILLING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 12/11/95 DATE OF SURVEY: 120495 ELECTRONIC MULTI-SHOT SURVEY JOB NUMBER: AK-EI-50119 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION TRUE SUB-SEA COURS COURSE DLS TOTAL MEASD VERTICAL VERTICAL INCLN DIRECTION RECTANGULAR COORDINATES VERT. DEPTH DEPTH DEPTH DG MN DEGREES DG/100 NORTH/SOUTH EAST/WEST SECT. 14867.89 7026.89 6980.89 41 25 N 3.37 E .53 11827.90N 1639.88E 11941.01 14963.23 7098.40 7052.40 41 22 N 3.56 E .14 11890.83N 1643.69E 12003.88 15057.88 7169.44 7123.44 41 21 N 3.50 E .04 11953.27N 1647.54E 12066.26 15152.04 7240.30 7194.30 41 0 N 3.50 E .38 12015.15N 1651.32E 12128.09 15247.22 7312.42 7266.42 40 28 N 3.23 E .57 12077.16N 1654.97E 12190.02 15279.56 7337.04 7291.04 40 21 N 3.33 E .43 12098.10N 1656.17E 12210.93 15340.39 7383.52 7337.52 39 58 N 3.47 E .64 12137.27N 1658.50E 12250.05 15436.08 7456.97 7410.97 39 44 N 3.55 E .26 12198.48N 1662.25E 12311.21 15530.00 7529.82 7483.82 38 32 N 2.68 E 1.40 12257.66N 1665.47E 12370.29 15655.00 7627.60 7581.60 38 32 N 2.68 E .00 12335.46N 1669.11E 12447.86 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. HORIZONTAL DISPLACEMENT = 12447.87 FEET AT NORTH 7 DEG. 42 MIN. EAST AT MD = 15655 VERTICAL SECTION RELATIVE TO WELL HEAD VERTICAL SECTION COMPUTED ALONG 7.76 DEG. TIED INTO AK-EI-50117 MPL-25 AT 8938' KICK OFF POINT AT 9160' INTERPOLATED DEPTH 15655' SPE ~-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE SHARED SERVICES DRILLING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 12/11/95 DATE OF SURVEY: 120495 JOB NUMBER: AK-EI-50119 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 1000 FEET OF MEASURED DEPTH TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST MD-TVD VERTICAL DIFFERENCE CORRECTION 8938.00 4684.38 4638.38 6489.74 N 940.32 E 4253.62 9938.00 5007.72 4961.72 7429.82 N 1047.70 E 4930.28 676.66 10938.00 5333.51 5287.51 8363.87 N 1193.22 E 5604.49 674.21 11938.00 5657.44 5611.44 9301.44 N 1319.28 E 6280.56 676.08 12938.00 5994.71 5948.71 10232.86 N 1455.78 E 6943.29 662.72 13938.00 6432.32 6386.32 11121.99 N 1565.68 E 7505.68 562.39 14938.00 7079.47 7033.47 11874.19 N 1642.65 E 7858.53 352.85 15655.00 7627.60 7581.60 12335.46 N 1669.11 E 8027.40 168.88 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE-DIMENSION MINIMUM CURVATURE METHOD. SP! f-SUN DRILLING SERVICES ANCHORAGE ALASKA PAGE 5 SHARED SERVICES DRILLING MILNE PT/MPL-25 500292262100 NORTH SLOPE BOROUGH COMPUTATION DATE: 12/11/95 DATE OF SURVEY: 120495 JOB NUMBER: AK-EI-50119 KELLY BUSHING ELEV. = 46.00 FT. OPERATOR: BP EXPLORATION INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE SUB-SEA MEASD VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATES NORTH/SOUTH EAST/WEST MD-TVD VERTICAL DIFFERENCE CORRECTION 8938.00 4684.38 4638.38 6489.74 N 940.32 E 4253.62 9130.19 4746.00 4700.00 6670.61 N 960.95 E 4384.19 130.57 9436.63 4846..00 4800.00 6958.60 N 991.90 E 4590.63 206.44 9744.35 4946.00 4900.00 7247.80 N 1024.00 E 4798.35 207.71 10055.05 5046.00 5000.00 7539.26 N 1063.71 E 5009.05 210.71 10351.67 5146.00 5100.00 7815.36 N 1105.49 E 5205.67 196.61 10654.70 5246.00 5200.00 8097.93 N 1149.99 E 5408.70 203.03 10978.56 5346.00 5300.00 8402.03 N 1198.92 E 5632.56 223.86 11297.36 5446.00 5400.00 8701.92 N 1240.21 E 5851.36 218.81 11605.81 5546.00 5500.00 8991.23 N 1278.09 E 6059.81 208.45 11903.83 5646.00 5600.00 9269.53 N 1315.03 E 6257.83 198.02 12200.19 5746.00 5700.00 9545.91 N 1352.93 E 6454.19 196.36 12498.96 5846.00 5800.00 9824.40 N 1394.16 E 6652.96 198.76 12792.28 5946.00 5900.00 10097.06 N 1435.29 E 6846.28 193.32 13087.30 6046.00 6000.00 10371.64 N 1475.74 E 7041.30 195.03 13348.42 6146.00 6100.00 10610.77 N 1507.09 E 7202.42 161.12 13574.36 6246.00 6200.00 10812.15 N 1529.04 E 7328.36 125.94 13778.26 6346.00 6300.00 10988.57 N 1549.53 E 7432.26 103.91 13962.78 6446.00 6400.00 11142.51 N 1568.14 E 7516.78 84.52 14142.62 6546.00 6500.00 11290.96 N 1585.52 E 7596.62 79.84 14313.68 6646.00 6600.00 11428.78 N 1601.55 E 7667.68 71.06 14472.38 6746.00 6700.00 11550.92 N 1617.50 E 7726.38 58.70 14619.67 6846.00 6800.00 11658.42 N 1628.78 E 7773.67 47.29 14759.51 6946.00 6900.00 11755.88 N 1635.79 E 7813.51 39.83 14893.38 7046.00 7000.00 11844.74 N 1640.87 E 7847.38 33.87 15026.65 7146.00 7100.00 11932.67 N 1646.28 E 7880.65 33.28 15159.59 7246.00 7200.00 12020.09 N 1651.62 E 7913.59 32.93 15291.32 7346.00 7300.00 12105.70 N 1656.61 E 7945.32 31.73 15421.81 7446.00 7400.00 12189.37 N 1661.69 E 7975.81 30.49 15550.69 7546.00 7500.00 12270.54 N 1666.08 E 8004.69 28.88 15655.00 7627.60 7581.60 12335.46 N 1669.11 E 8027.40 22.72 THE CALCULATION PROCEDURES USE A LINEAR INTERPOLATION BETWEEN THE NEAREST 20 FOOT MD (FROM MINIMUM CURVATURE) POINTS Schlumberger - GeoQuest A Division of Schlumberger Technologies Corporation 500 W. International Airport Road Anchorage, Alaska 99518 - 1199 (907) 562-7669 (Bus.) (907) 563-3309 (Fax) August 8, 1996 p,C_OEIVEB TO: BP Exploration (Alaska) Inc. Petrotechnical Data Center, MB3-3 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 AUG 08 ~996 Alasl(a 0ii & Gas Cons. Commissio~ Anchorage The following data of the Depth shifted CDR/CDN, CDR/CDN TVD'S for well MPL-25g'"-/._.%--/"~O Job # 95409 was sent to: BP Exploration (Alaska) Inc. Petrotechnical Data Center, MB3-3 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 . . 1 OH LIS Tape 3 Bluelines each 1 Film each 1 Depth.shift display · State of AlasKa Alaska.Oil & Gas Conservation Comm. Attn' ¢'Larry Grant 3001 Porcupine Drive Anchorage,_&l_a ~ska 99501 1 OH LIS Tape ,. 1 Blueline each 1 RF Sepia each // .. _ · OXY USA, Inc Attn: Darlene Fairly P.O. Box 50250 Midland, Texas 79710 1 OH LIS Tape 1 Blueline each 1 RF Sepia each Sent Certified Mail Z 777 937 429 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP EXPLORATION (ALASKA)INC. PETROTECHNICAL DATA CENTER, MB3-3 900 EAST BENSON BLVD. ANCHORAGE, ALASKA 99519-6612 SCHLUMBERGER GEOQUEST 500 WEST INTERNATIONAL AIRPORT ROAD ANCHORAGE, ALASKA 99518-1199 Schlumberger Courier: Date Delivered: Received By: LARRY GRANT Attn. ALASKA OIL + GAS CONSERVATION 3001 PORCUPINE DRIVE ANCHORAGE AK, 99501. Date: 9 May 1996 RE: Transmittal of Data Sent by: HAND CARRY Dear Sir/Madam, Enclosed, please find the data as described below: WELL # DESCRIPTION ~ 7 ~ ~ MPL-25 ~7~;~ ~PO-25A 1 LDWG TAPE+LIS 1 LDWG TAPE+LIS 1 LDWG TAPE+LIS ECC No. Run # 1 6644.00 Run # 1 6657.00 Run # 1 6658.00 Please sign and return to: Attn. Rodney D. Paulson Western Atlas Logging Services 5600 B Street Suite 201 Anchorage, AK 99518 Received by: /~/~r/~AX/.~/~~~to (907) 563-7803 Date: tv]AY 2 ] 1996 Alaska Oil & Gas CODS. CommissioD. A.~chomge MEMORANDUM State of Alaska A~as~a~. and Gas Conservation Commission TO: David J oh~n,' Chairman FROM: Doug Amos, '- -: Petroleum Inspector DATE: May 19, 1996 FH~E NO: a,~.~hetdd, doc BOPE Test Polar 1 BPX MPU L-25 Kuparuk Rv. Field PTD No. 95-180 Saturday, May 18. 1996: ! traveled to BPX MPU L-25 well to witness the BOPE test at Polar Energy Rig No. 1. Due to choke line alignment problems the test was delayed. Sunday, May 19, 1996: As the attached AOGCC BOPE Test Report indicates the choke line flange at the stacked leaked. The flange was repaired and retested good. The gas detection system was on location and installed but not operational, the main panel seemed to be operational but would not recognize the remote sensors. i informed BPX representative Lee Hinkel that he had seven days to correct this non compliance item or have the rig shut down. The rig has had ample time to install this system but has not made the installation a priority, i noted this non (' compliance in my change out notes so that a follow-up inspection would be conducted by the other inspectors. SUMMARY: ! witnessed the BOPE Test at BPX MPU L-25 well on Polar Energy Rig No. 1. A'~,,achment' AW9HESDD.XLS STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: Workover: Drlg Contractor: Polar Engery Inc. Rig No. Operator: BP Exploration Well Name: ~PU L-25 Casing Size: 7" Set @ 15,552 Test: Initial X Weekly Other 5/19/96 DATE: I PTD # g5-180 Rig Ph.# 65g-2782 Rep.: Lee Hinkel Rig Rep.: Cliff Ehret Location: Sec. 8 T. 13 N. R. 10 E. Meridian Umiat Test Well Sign Yes Drl. Rig OK MISC. INSPECTIONS: Location Gen.: OK Housekeeping: OK (Gen) PTD On Location Yes Standing Order Posted Yes Hazard Sec. Yes FLOOR SAFETY VALVES: Quan. Pressure P/F Upper Kelly / IBOP N/A 500/5,000 I Lower Kelly / IBOP N/A 500/5, 000 ! Ball Type f 500/5, 000 P Inside BOP '1 500/5, 000 P BOP STACK: Quan. Annular Preventer 1 Pipe Rams Lower Pipe Rams Blind Rams 1 Choke Ln. Valves 2 HCR Valves 1 Kill Line Valves 2 Check Valve N/A 500/5,000 Test Press. P/F 300/3,000 P P 500/5,000 500/5,000 P 500/5,000 500/5,000 500/5,000 P P P MUD SYSTEM: Visual Alarm Trip Tank OK OK Pit Level Indicators OK OK Flow Indicator OK OK Meth Gas Detector See Remarks H2S Gas Detector CHOKE MANIFOLD: No. Valves 7 No. Flanges Manual Chokes 2 Hydraulic Chokes 0 Test Pressure P/F 500/5,000 P t6 500/5,000 P P Functioned Functioned N/A ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure System Pressure Attained Blind Switch Covers: Master: Nitgn. Btl's: N/A 3,250 I P 2,150 P minutes 13 sec. f minutes 25 sec. Yes Remote: No Psig. Number of Failures: I ,Test Time: 7.0 Hours. Number of valves tested '/3 Repair or Replacement of Failed Equipment will be made within 7 days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-361)7 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 II REMARKS: The choke line flange leaked, the flange was repaired and retested good. The gas detection system is still not operational I gave Lee Hinkel 7 days to have it up and tested. I informed him that in the future failure to have the gas detection system operational would result in the shut down of the rig. Distribution: orig-Weil File c - Oper./Rig c - Database c - Trip Rpt File c - Inspector STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Wrtnessed By: Doug Amos FI--021L (Rev. 12/94) AW9H ESDD.XLS LARRY GRANT Attn. ALASKA OIL + GAS CONSERVAT!©N 3001 PORCUPINE DRIVE ANCHORAGE AK, 99501. Date: 17 April 1996 RE: Transmittal of Data Sent by: HAND CARRY Dear Sir/Madam, Enclosed, please find the data as described below: WELL = DESCRTOm~ON ~ SBT FINAL BL~RF /1 PFC/PERF FINAL BL+RF ~r PLS FINAL BL+RF ~ PFC/PERF FINAL BL+RF ~'1 PLS FINAL BL+RF ~1 GR/CCL FINAL BL+RF ~ PFC/PERF FINAL BL+RF Run Run # 1 Run # 1 Run # 1 Run # 1 Run # 1 Run # 1 ECC ~' 6500.01 6512.03 6644.00 Please sign and return to: Attn. Rodney D. ?aulson Western Atlas Logging Services 5600 B Street Suite 201 AK 99518 Anchorage, FAX I 07> Received by: "'--'"-P~--~//.//'~', ~'~- "~. Date: · · LARRY GRANT Attn. ALASKA OIL + GAS CONSERVATION 3001 PORCUPINE DRIVE ANCHORAGE AK, 99501. Date: 26 April 1996 RE: Transmittal of Data Sent by: HAND DELIVERY Dear Sir/Madam, Enclosed, please find the data as described below: WELL # DESCRIPTION 1 PFC/PERF FINAL BL+RF 1 GR/CCL FINAL BL+RF ~SBT FINAL BL+RF ~/ PLS FINAL BL+RF ~I'PFC/PERF FINAL BL+RF MPL-21 ~ GR/CCL FINAL BL+RF ECC No. Run # 1 6644.01 Run # 1 6658.01 Run # 1 Run # 1 Run # 1 Run # 1 6661.00 6661.01 Please sign and return to: Attn. Rodney D. Paulson Western Atlas Logging Services 5600 B Street Suite 201 Anchorage, AK 99518 Or FAX to 563-7803 (907) Date To: April 23, 1996 Alaska Oil & Gas Conservation Commission .eared rvices rilling BP Exploration / Arco Alaska Subject: MPL-25, Permit #95-180 I am submitting the attached Form 10-403 requesting a change in status of MPL-25 from a service well to a development oil well. MPL-25 is now planned to be a producer due to structural re-interpretation of the bottom hole location. Thank you for your assistance, Kathy Campoamor Technical Assistant 564-5122 STATE OF ALASKA ALASKA OiL AND GAS CONSERVATION COMrv~'SION APPLICATION FOR SUNDRY APPROVAL Type of Request: [] Abandon ~ Suspend [] Plugging [] Time Extension [] Perforate [] Alter Casing ~ Repair Well [] Pull Tubing [] Variance [] Other [] Change Approved Program iX Operation Shutdown [] Re-Enter Suspended Well [] Stimulate Change Status .. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 3712' NSL, 5086' WEL, SEC. 8, T13N, R10E At top of productive interval N/A At effective depth 143' NSL, 3420' WEL, SEC. 29, T14N, R10E At total depth 207' NSL, 3417' WEL, SEC. 29, T14N, R10E 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Structural Conductor Surface Intermediate Production Liner Casing Perforation depth: measured true vertical Type of well: ~ Development [] Exploratory [] Stratigraphic [] Service ORIGINAL 6. Datum Elevation (DF or KB) KBE = 46' 7. Unit or Property Name Milne Point Unit 15655 feet Plugs (measured) N/A 7628 feet 15551 feet Junk (measured) N/A 8. Well Number MPL-25 9. Permit Number 95-180 10. APl Number 50-029-22621 11. Field and Pool Milne Point Unit / Kuparuk River Sands 7546 feet Length Size Cemented 80' 20" 250 sx Arcticset I (Approx.) 112' 8983' 9-5/8" 175o sx PF 'E', 250 sx 'G', 150 sx PF 'E' 9019' 1 5582' 7" 240 sx Class 'G' 15636' MD TVD 15250'-15258', 15258'-15280' 7315'-7321', 7321'-7337' Tubing (size, grade, and measured depth) N/A Packers and SSSV (type and measured depth) N/A 112' 4710' 7613' 17. I hereby certify that the foregoing is tru9 and corr~ect to the best of my knowledge Signed ~ d'"-" ] ~ ,/ T,rnSchofie,d~ /~",3 .~ C__;~~--) Title Senior Drilling Engineer Date ~/2_7 · // Commission Use Only / Conditions of Approval: Notify Commission so representative may witness IApproval No.¢~- (~JG"~ Plug integrity BOP Test Location clearance L¢O_¢' - --' ~ ~I ~opy Mechanical Integrity Test__ Subsequent form required 10- I~ , . Davidu,',g,na, W.S'gnee Johnston tdy ~//~o/~_ .... Approved by order of the Commission Commissibn~r Date Form 10-403 Rev. 06/15/88 Submi{ l'n Tdplic~tte Name of approver Date approved Contact Engineer Name/Number: Bill Hill, 564-4924 Prepared By Name/Number Kathy Campoamor, 564-5122 15. Status of well classifications as: [] Oil [] Gas [] Suspended Service 16. If proposal was verbally approved 4. Estimated date for commencing operation 05/25/96 13. Attachments [] Description summary of proposal ~ Detailed operations program [] BOP sketch MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: David Johnsto~ Chairman November 20, 1995 THRU: Blair Wondzell, P. i. Supervisor FILE NO: EWOJKTCD.doc FROM: Lou Grimaldi, t.~.,. SUBJECT: Petroleum lnsp. Monday, November 20, 1995: Diver[er Insp. Nabors 22E BPX MPU well MPL-25 Kuparuk River Field PTD # 95-180 witnessed the Diver[er Function Test on Nabors rig 22E preparing to drill BPX' Milne Point Unit, well MPL-25. The AOGCC Diver[er Function Test Report and a location sketch is attached for reference. . ! found the Vent line araingement Of the Vent lines to be too close and aimed directly at the opposite well. Rig 4-ES was also in close proximity which only compounded the problem. I had concerns with the possible ignition of gas in case of a surface kick which could involve the other rig. After confering with the Drilling foremans and tooiPushers from both rigs, and PE superviser Blair Wondzell I required a small redirection and lengthening of the existing vent line. The end of the vent line was extended alongside the target wellhouse and beyond rig #.4-ES.. This is not a isolated incident. The' pads at Milne Point are small and haven become quite congested with the 'increased activity. I believe some extra x/.~,~,.'~ preplanning for rig positioning and layout of. vent lines would be appropriate. found some gakets missing in the existing vent line rigup and the vent line knife/ valve appeared to have sustained some damage with the actuator support arm~ being bent. The gaskets and a new Knife valve were installed. The Diver[er functioned properly with a closure time of 1:40 minutes. The accumulator recharged in a acceptable 2:50 minutes. Summary: I witnessed the successful diver[er function test on Nabors 22E. Layout of vent lines presented problems. Attachments: EWOJKTCD.XLS Pad sketches (2) cc; Scott Sigurdsen/Tom Horten Nabors 22-E Diverter Layouts MPU L-25 !House~ Rig 4E S~~k Pipe Rack Work Shop As Found Well iHouse I 182' LWell House Pipe Rack Camp Work Shop As LeR J~- STATE OF ALASKA ALASKA O~,. AND GAS CONSERVATION COMMIb~ION Diverter Systems InsPection Report Drlg Contractor: Nabors Operator: BPX Well Name: MPL-25 LoCation: Sec. 8 T. 13N Operation: Development X Rig No. 22-E PTD # 95-180 R, Oper. Rep.: Rig Rep.: 10E Date: 11/20/95 Exploratory: Rig Ph. # 659-4454 Jimmy Pyron Larry Wardeman Merdian Umiat TEST: DATA MISC. INSPECTIONS: Location Gen.: OK Well Sign: Housekeeping: OK (Gen.) Drlg. Rig: Reserve Pit: N/A Flare Pit: DIVERTER SYSTEM INSPECTION: Diverter Size: 20 Divert Valve(s) Full Opening: P Valve(s) Auto & Simultaneous: P Vent Line(s) Size: 10 Vent Line(s) Length: 28 Line(s) Bifurcated: P Line(s) Down Wind: NO Line(s) Anchored: OK Turns Targeted / Long Radius: P OK OK N/A in. in. ACCUMULATOR SYSTEM: Systems Pressure: Pressure After Closure: 200 psi Attained After Closure: Systems Pressure Attained: Nitrogen Bottles: 320O 1700 min. 30 2 min. 50 8 bottles psig psig sec, sec. MUD SYSTEM INSPECTION: Trip Tank: Mud Pits: Flow Monitor: 21 O0 average psig Light Alarm P GAS DETECTORS: Methane Hydrogen Sulfide: Alarm P P P P Light P P DIVERTER SCHEMATIC SEE EWOJKTCD.DOC FOR DIAGRAM Non Compliance Items 3 Repair Items Within IMMEDIATE Day (s) And contact the Inspector @ 659-3607 Remarks: Vent line pointed at and to close to adjacent well, Gaskets missing from vent line and divert valve. Divert valve actuator arms bent. Better preparation would eliminate these problems in future. Distribution orig. - Well File c - Oper/Rep c- Database c - Trip Rpt File c - Inspector FI-022 (Rev. 7/93 AOGCC REP.: OPERATOR REP.: EWOJKTCD.XLC Louis R Grimaldi TONY KNOWLE$, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 November 16, 1995 .: Tim Schofield, Senior Drilling Engineer BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Milne Point Unit MPL-25 BP Exploration (Alaska), Inc. Permit No 95-180 ' Surf Loc 3712'NSL, 5086'WEL, Sec. 08, T13N, R10E, UM Btmhole Loc 139'NSL, 3371'WEL, Sec. 29, T14N, R10E, UM Dear Mr. Schofield: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. The blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035; and the mechanical integrity (MI) of injection wells must be demonstrated under 20 AAC 25.412 and 25.030(g)(3). Sufficient notice (approximately 24 hours) of the MI test before operation, and of the BOPE test performed before drilling below the surface casing shoe, must be given so that a representative of the Commission may witness the tests. Notice may be given by contacting the Commission's on the North Slope pager at 659-3607. David W. Johnston % ~ ~ Chairman ~ BY ORDER OF THE COMMISSION c: Dept of Fish & Game, Habitat Sect - w/o encl Dept of Environmental Conservation - w/o encl STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 2O AAC 25.005 la. Type of work Drill [] Redrill I-Illb. Type of well. Exploratoryl-'l Stratigraphic Test [] Development Oil [] Re-Entry [] Deepen []1 Service [] Development Gas [] Single Zone [] Multiple Zone [] 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc. Plan RTE = 46 feet Milne Point / Kuparuk River 3. Address 6. Property Designation P. O. Box 196612, Anchorage, Alaska 99519-6612 ADL 355017 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025) 3712' NSL, 5086' WEL, SEC. 08, T13N, RIOE Milne Point Unit At top of productive interval 8. Well number Number 5161' NSL, 3407' WEL, SEC. 32, T14N, RIOE MPL-25 2S100302630-277 At total depth 9. Approximate spud date Amount 139' NSL, 3371' WEL, SEC. 29, T14N, RIOE 11/18/95 $200,000.00 12. Distance to nearest 13. Distance to nearest well 4. Number of acres in property15. Proposed depth (MD andTVD) property line AD.L 355018 1909 feet No Close Approach feet 4480 15549'MD/7556' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 2S.035 Kickoff depth 500 feet Maximum hole anglezl. O3 o Maximum surface 3301 psig At total depth (TVD) 7000'/3998 psig 18. Casing program Specifications Setting Depth s~ze Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 24" 20" 91.1# H-40 Weld 80' 32' 32' 112' 112' 250 sx Arcticset I (Approx.) 12-1/4" 9-5/8" 40# L-80 Btrc 8968' 31' 31' 9000' 4708' 1724 sx PF'E', 250 sx 'G', 150 sx PF'E' 8-1/2" 7" 26# L-80 Btrc 15519' 30' 30' 15549' 7556' 229 sx Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet ..... Casing Length Size Cemented Measured depth True Vertical depth Structural ii.. :.-., ~ .... Conductor ' '~ ~ ' Surface ,r,, ~' .~ '~ .r ', .. ~. r... -., Intermediate Production · ,,-. Liner i'~ta'~':;~'~ Perforation depth' measured true vertical 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program [] Drilling fluid program [] Time vs depth pict [] Refraction analysis [] Seabed report[] 20 AAC 25.050 requirements[] 21.1 hereby certify that_..the foregoipg is_ trp~ and correct to the best of my knowledge Signed '~~:¢Y~ .~¢~ Title Senior O#llingEn~lineer Date 1~/$//~5" a~m Commission Use Only Permit Number IAPI n ber Approvg. I date See cover letter ,~',~'",,'/r~'~:~ ]50-,~..--~- :.2.. 2. ~'.~.. / ] ///./'~"~/?~-~ for other requirements Condition~ of approval Samples required [] Yes ~ No Mud Icg ~'e'quired []Yes ~ No Hydrogen sulfide measures [] Yes j~ No Directional survey require~ [] Yes [] No Required working pressur~i'fgrRl~P~"r¥-'~'~l;U l§ld/o,~j t;u c~y []3M; J~5M; []1OM; []15M; Other: by order of~/////~/~,'/~ Approved by r)avid W. Johnston Commissioner tne commission Date Form 10-401 Rev. 12-1-85 Submit cate I Well Name: IMPL-25i Well Plan Summary ITypeinjector)'°f Well (producer or I Kuparuk Injector I Surface Location: 3712 NSL 5086 WEL Sec 08 T13N R10E UM., AK Target Location: 5161 NSL 3407 WEL Sec 32 T14N R10E UM., AK Bottom Hole 139 NSL 3371 WEL Sec 29 T14N R10E UM., AK Location: I AFE Number: 1330215 I I Rig: I Nabors 22-E I IEstimated Start 118NOV95 I IOperating days t°Date: complete' 115 I IWell Design (conventional, slimhole, Milne Point Ultra Slimhole:9-5/8" SURFACE e t c.)' CASING X 7" LONGSTRING Formation Markers: Formation Tops MD TVD (bkb) base permafrost 1 7 7 7 1 70 0 NA 7270 4146 Top of Schrader Bluff Sands (8.3 ppg) Seabee Shale 8808 4646 Base of Schrader Bluff Sands (8.3 ppg) HRZ 14467 6736 High Resistivity Zone Top Kuparuk 14890 7051 Kuparuk Cap Rock Target Sand -Target 15145 7246 Target Sand (9.6 ppg) Total Depth 15549 7556 Casinq/Tubing Pro ram: Hole (~sg/ Wt/Ft Grade Conn Length Top Btm Size Tbg O.D. MD/TVD MD/TVD 24" 20" 91.1# H-40 Weld 80 32/32 1 12/1 12 12 1/4" 9 5/8" 40# L-80 btrc 8968 31/31 9000/4708 8 1/2" 7" 26# L-80 btrc 15519 30/30 15549/7556 Internal yield prgssure of the 7" 26# casing is 7240 psi. Worst case surface pressure would occur with a full column of gas to the reservoir at 7000 TVDSS. Maximum anticipated surface pressure in this case assuming a reservoir pressure of 3998 psi is 3301 psi, well below the internal yield pressure rating of the 7" casing. Logging Program: Open Hole Logs: Surface MWD Directional DSS Intermediate N/A Final Cased Hole Logs: MWD Dir and LWD (GR/CDR/CDN). Mudloggers are NOT required for this well. Mud Program: ISpecial design INone- SPUDMUD considerations Surface Mud Properties: I Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.6 1 00 1 5 8 1 0 9 8 to to to to to to to 9.0 50 35 1 5 30 1 0 1 5 Intermediate Mud Pro3erties- N/A I Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss Production Mud Properties' I LSND freshwater mud Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 9.0 4 0 1 0 3 7 8.5 6 - 8 to to to to to to to 10.4 50 1 5 1 0 20 9.5 4-6 Well Control: Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Diverter, BOPE and drilling fluid system schematics on file with AOGCC. Directional' I KOP' 15oo' IMaximum Hole Angle: Close Approach Well' I71'°3° (No Shut Ins) Disposal' Cuttings Handling: 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. Request to AOGCC for Annular Pumping Approval for MPL-25i: 1. Approval is requested for Annular Pumping into the MPL-25i, 9-5/8" x 7" casing annulus. 2. Aquifers in the Milne Point Unit have been exempted from Class II injection activities by the AOGCC by Aquifer Exemption Order #2 as referenced in Area Injection Order #10. There are no domestic or industrial use water wells located within one mile of the project area. 3. The 9-5/8" casing shoe will be set at 9000' md (4708' tvd) which is a minimum of 500' tvd below the Permafrost and into the Prince Creek formation which has a long established history of annular pumping at Milne Point. 4. The burst rating (80%) for the 9-5/8" 40# LB0 casing is 4600 psig while the collapse rating (80%) of the 7" 26# LB0 casing is 4325 psig. The break down pressure of the Prince Creek formation is 13.5 ppg equivalent mud weight. The Maximum Allowable Surface Pressure while annular pumping is calculated according to the following equation and is 3100 psi for a 10.4 ppg fluid in this well (Assumes worst case in which 7" casing is filled with gas). MASP = 4325 psig - ((fluid density ppg - 1.9) X 0.052 X 9-5/8" Casing Shoe TVD 5. A determination has been made that the pumping operation will not endanger the integrity of the well being drilled by the submission of data to AOGCC on 7/24/95 which demonstrates the confining layers, porosity, and permeability of the injection zone. 6. The cement design for this well ensures that annular pumping into hydrocarbon zones will not occur. ANNULAR INJECTION: THE FOLLOWING WELLS HAVE BEEN PERMITTED FOR ANNULAR INJECTION FOR 1995 AREA WELL PREV VOL PERMITTED PERMITTED INJECTED VOL DATES (BEES) (aBES) Milne Point MPJ-13 4070 0 1JAN95-31DEC95 Milne Point MP L-14 0 35000 1JAN95-31DEC95 Milne Point MP L-15 0 35000 1JAN95-31DEC95 Milne Point MP L-16i 0 35000 1JAN95-31DEC95 Milne Point MP L-17 16026 35000 1JAN95-31DEC95 Milne Point MP L-24i 225 35000 1JAN95-31DEC95 Milne Point MP L-29i 0 35000 1JAN95-31DEC95 DO NOT EXCEED 35,000 BBLS IN ANY ANNULUS. MAXIMUM EXPECTED FLUID DENSITY IS 17.0 PPG BURTST PRESSURE 9-5/8" 40# L-80 CASING: COLLAPSE 7", 26#, L-80 CASING: 5750 PSI 5410 PSI 9-5/8" SURFACE CASING SHOE DEPTH: 9000' MD/4708' TVD HYDROSTATIC PRESSURE @ 4708' TVD WITH VARIOUS DENSITY FLUIDS: (0.052) X (4708) X (FLUID DENSITY) = HYDROSTATIC PRESSURE 80% OF 7' COLLAPSE PRESSURE = (5410 PSI) X (0.8) = 4328 PSI MAXIMUM ALLOWABLE INJECTION PRESSURE 2000 PSI AT ANY PPG MAXIMUM ALLOWABLE HYDROSTATIC 7" COLLAPSE ANNULAR INJECTION _ FLUID DENSITY PRESSURE AT 4708' TVD PRESSURE (80%) PRESSURE (PPG) (PSI) (PSI) (PSI) 8 1958.53 4328 2000 9 2203.34 4328 2000 1 0 2448.16 4328 !880 1 1 2692.98 4328 1635 1 2 2937.79 4328 1390 1 3 3182.61 4328 1145 1 4 3427.42 4328 901 1 5 3672.24 4328 656 1 6 3917.06 4328 41 1 1 7 41 61.87 4328 1 66 MAX ALLOWABLE INJECTION PRESSURE = 4328 PSI- HYDROSTATIC PRESSURE MPL-25i Proposed Summary of Operations . , , , , . . . . 10. 11. 12. 13. 14. Drill and Set 20" Conductor. Weld a starting head and top job nipple on conductor. Prepare location for rig move. MIRU Nabors 22E drilling rig. NU and test 20" Diverter system.. Build Spud Mud. Drill a 12-1/4" surface hole as per directional plan and run and cement 9-5/8" casing. Run only Dir MWD. ND 20" Diverter, NU and Test 13-5/8" BOPE. MU a PDC bit on a motor, with Directional MWD and LWD CDR/CDN (GR/RES/Dens/Neu). RIH, Drill out Float Equipment and 10' of new formation. Perform FIT to 12.5 ppg. Drill 8.5" hole to TD as per directional plan. Run and Cement 7" Casing. Displace cement with seawater and enough diesel to cover from the base of permafrost to surface. Test casing to 3500 psig. ND BOPE, NU and Test Tree. RDMO Nabors 22E drilling rig to drill next well. Perforate and Stimulate in absence of rig. Displace well with 10.2 ppg brine and set a wireline retrievable bridge plug. MIRU Nabors 4ES or Polar 1 Rig. NU & Test BOPE to 5000 psig. Complete well with 3-1/2" tubing and packer hookup. Install Surface Lines and Wellhouse and put the well on production. Drilling Hazards and Risks: 1. The Kuparuk reservoir sands are expected to be a maximum of 3500 psig or 9.6 ppg. 2. See the Milne Point L-Pad Data Sheet prepared by Pete Van Dusen for a general recap of the original13 wells drilled by Conoco on L-Pad plus the L- 14 and L-15 wells recently drilled by BPX. L-16i recently drilled by Nabors Rig# 27E is a very similar profile although drilled to the southeast of the L-25i location. MP L-16i was drilled without incident. Nabors rig# 27E should have the DRILLING WORKFILE in the Co. Rep's office. It is suggested/requested that the Directional Driller consult with the Directional Driller (Larry Mc Guire/Bob Lent)on Rig# 27E about MP L-16i. 3. There will be no close approaches while drilling MP L-25i. 4. Surface casing will be deep set across the Scrader Bluff this well due to the high~' step out (+12,381' Departure). It is important that we drill the hole with minimum doglegs, concentrating on maintaining a Iow solids mud, and practicing good hole cleaning procedures. 5. Nabors Rig# 4ES may still be on Milne Pt. L-pad when Rig 22E moves ofer L-25i. Also construction offices are still located on Milne Pt. L-Pad. Construction is still onging between L pad and F pad. Ensure personnel and vehicles use caution while approaching and while on L-pad. 6. An in-hole reference MAY be run in this well. LOST CIRCULATION: Lost circulation while drilling the production interval has been a problem in on 4 different L-pad wells. The Kuparuk sands and a number of shallower intervals are highly fractured. Wells L-07, L-08, L-09 and L-11 lost varying amounts of mud (from 70 to 220 bbls) drilling through or near the top of the Kuparuk sands. Be prepared to treat these losses with LCM treatments. Have the LCM materials outlined in the Drilling Fluid Program on location and recommended pills ready to address the Lost Circulation Problem when drilling into the Kuparuk Sand. Stuck Pipe Potential: Stuck pipe has occurred on 3 wells on this pad at the interface between the Kalubik and D-shale (called the Kuparuk cap rock). These wells and the corresponding depths at which they were stuck were: L-06 @ 6871' ss, L- 07 @ 6859' ss, L-11 @ 6835' ss. While running 7" casing on MPL-29 the last two joints (TD was 14025'MD/7208'TVD) that were run acted sticky and repeatedly packed off for a period of time. Landing the casing hanger required working the casing string and circulating in order to get casing in place. Gas hydrates: Although hydrates were encountered on E, H, and Pads, no hydrates are expected on L pad. No hydrates were encountered during the recent drilling of MP L-29 and MP L-16i. 4. No other drilling hazzards or risks have been identified for this well. CASING SIZE: 9-5/8" MPL-25i 9-5/8" SURFACE CASING CEMENT PROGRAM - HALLIBURTON CIRC. TEMP 50 deg F at 2500' TVDSS. SPACER: 75 bbls fresh water. LEAD CEMENT TYPE: ADDITIVES: Retarder WEIGHT: 12.0 ppg APPROX #SACKS: 1724 Type E Permafrost YIELD:2.17 ft3/sx MIX WATER: 11.63 gal/sk THICKENING TIME: Greater than 4 hrs at 50° F. TAIL CEMENT TYPE: Premium G ADDITIVES: 2.0% CaCI2 WEIGHT: 15.8 ppg YIELD:1.15 ft3/sx MIX WATER: 5.0 gal/sk APPROX #SACKS: 250 THICKENING TIME: Greater than 4 hrs at 50° F. FLUID LOSS: 100-150 cc TOP JOB CEMENT TYPE: Permafrost E ADDITIVES: Retarder WEIGHT: 12.0 ppg YIELD'2.17 ft3/sx MIX WATER: 11.63 gal/sk APPROX NO SACKS: 150 CENTRALIZER PLACEMENT: 1. 1 Bowspring centralizer per joint of 9-5/8" casing on bottom 15 joints of casing (15 required). 2. Place all centralizers in middle of joints using stop collars. OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 12 - 15 bpm. Mix slurry on the fly -- batch mixing is not necessary. CEMENT VOLUME: 1. The Tail Slurry volume is calculated to cover 618' md above the 9-5/8" Casing Shoe with 30% excess. 2. The Lead Slurry volume is calculated to cover from the top of the Tail Slurry to 1500' md with 30% excess and from 1500' md to surface with 100% excess. 3. 80'md 9-5/8", 40# capacity for float joints. 4. Top Job Cement Volume is 150 sacks. MPL-2$i Well 7" PRODUCTION CASING CEMENT PROGRAM- HALLIBURTON STAGE I CEMENT JOB ACROSS THE KUPARUK INTERVAL: CIRC. TEMP: 140° F SPACER: 20 bbls fresh water BHST 170° F at 7040' TVDSS. 70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0 ppg above current mud weight. CEMENT TYPE' Premium G ADDITIVES: 0.2% CFR-3, 0.1% HR-5, 0.4% Halad 344 WEIGHT: 15.8ppg YIELD: 1.15 cu ft/sk MIX WATER: 5.0 gal/sk APPROX # SACKS: 229 THICKENING TIME' 3 1/2 - 4 1/2 hrs @ 140° F FLUID LOSS: < 50cc/30 min @ 140° F FREE WATER: 0cc @ 45 degree angle. CENTRALIZER PLACEMENT: o . 7" x 8-1/4" Straight Blade Rigid Centralizers. Two per joint on the bottom 19 joints of 7" Casing (38 total). This will cover 300' above the KUPARUK C1 Sand. Run two 7" x 8-1/4" Straight Blade Rigid Centralizers on the second full joint inside the 9- 5/8" casing shoe. OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 8-10 bpm. Batch mixing is not necessary. CEMENT VOLUME' . Stage 1 cement volume is calculated to cover 1000' md above the Kuparuk Target Sand with 30% excess. ----' ..... '" SHARED S'ERVTiCES ORiLLTNG .... ---- i i llll · i i i · ii i ii Harl<er ~dentitication HD N/S E/H MPL--25 (P6) A) KB 0 0 o ~, ~o~o ~,oo ~oo o o ~ PLAN VIEW :1 ,,~o ,.~oo ~oo ~ o D) 8UILO 2/~00 ~000 25 3 ...... E) BUILO 2.5/J00 ~300 75 JO CLOSURE ' ~238J feet at Azimuth 7.76 F) END 2.5/100 BUILD 364~ ~553 212 G) 9-5/8" CASING POINT 8600 6200 845 DECLINATION.' +0.000 (E) H) DROP 2/~00 ~3~94 ~050~ ~43~ SCALE ' 1 inch : 2000 feet I) END 2/~00 DROP 14745 ~1755 1~03 J) TARGET 15J45 12o~o ~s38 DRAWN · ~J/~4/95 K) 7' CASING POINT ~5549 J2268 t673 L) TD 15549 J2268 ~673 mmm m m m m 1 12ooo pnn FT T~nGFT n~nTIlfi I ~ . ; 1000 ............. - ........ 10000 ~ ' ..... ~000 ....... ' ............ ........ 8000 ANACRmLL AKA-D~( ~] AI~PROVED ~ooo- ' .................... ~ooo " )'LAb ''J 5000- m ...... I [ : 4000 .... ~ ......... 3000 ................ I , ~000 ........ I 1000 ...... 7000 6000 5000 4000 3000 2000 1000 0 1000 2000 3000 4000 5000 8000 7000 <- WEST ' EAST -> _ m m m mm m m ,.= mm Pmadnil} (c)g5 NI:~25P6 2.50.04 ~: 18 Pl~ P} ______SHARED SERV T CE S,.. DR l LL l NG MPL-25 (PG) VERTZOAL SECTION VZEH Section at: 7.76 TVD Sca]e' I inch = ~BO0 feet Dep Scale' I inch = ~600 feet Drawn ' ~]/]4/95 u-- 'A I I MaPker Identification MD BKB SECTN INCLN , ' A) KB 0 O 0 0.00 B '- ' ' B) KDP/BUILD J/~O0 500 500 0 0.00 D -~ ' ---- i C) BUILD 1.5/~00 700 700 3 2.00 · D) BUILD 2/200 lO00 999 26 6.50 E' ' i FI'END 2.5/100 BUILD 3641 2966x~566 71.0~ O--- . ........ ' m m ' m m ' G) 9-5/8' CASING POINT ~~ ~ ~ 71 03 . ~ ..... ~~ ~K-~ H) DROP ~/~00 ~v I3194 507~ ~OBO1 7~.03 j ) I) END 2/100 DROP 14745 6940 ~tBB4 40.00 O~ ..... ~ ' J TARGET J5145 7~46 l~i~l 40.00 K) 7" CASING POINT 15549 7556 ~238~ 4D,O0 L) TD ~5549 7556 ~238~ 40.00 ~~' I ' ' I ~,~'NADRLL : 'I AP ~RO~ ,ED -,;--;, ; .... 'DNL'f . , ...... , - ,t, [ , nnn t~nn pann ~nn annn wonn 5600 6400 7200 8000 8800 9600 10400 t 1200 Sect ion DepaPture - WELL PERMIT CHECKLIST COMPANY INIT CLASS UNIT# PROGRAM: exp [] dev [] redrll [] serv~ ADMINISTRATION 1. 2. 3. 4. 5. 10. 11. 12. 13. Permit fee attached ................... Y Lease number appropriate ................ Y ¥ Unique well name and number ............... Well located in a defined pool ............. Well located proper distance from drlg unit boundary. Well located proper distance from other wells ..... Sufficient acreage available in drilling unit ..... If deviated, is wellbcre plat included ........ Operator only affected party .............. ~ .Y Operator has appropriate bond in force .......... i~Y Permit can be issued without conservation order ..... Y Permit can be issued without administrative approval. Can permit be approved before 15-day wait ....... ENGINEERING I N N N N N N N N N N N N N 14. Conductor string provided ............... ~ N 15. Surface casing protects all known USDWs'. ....... ~ N 16. CMT vol adequate to circulate on conductor & surf cst.. Y~ N 17. CM~ vol adequate to tie-in long string to surf cst . . . Y ~ 18. CM~will cover all known productive horizons ...... ~ N 19. Casing designs adequate for C, T, B & permafrost .... ~ N 20. Adequate tankage or reserve pit... ~ .......... ~ N 21. If a re-drill, has a 10-403 for abndnmnt been approved. ~ 22. Adequate wellbore separation proposed .......... ~ N 23. If diverter required, is it adequate ........... Y N ~P 24. Drilling fluid program schematic & equip list adequate .~ N 25. BOPEs adequate ............ ~._ ........ ~ N 26. BOPE press rating adequate; test to ~~ psig.~ N 27. Choke manifold complies w/API RP-53 (May 84) ...... ~ M /~/h' 28. Work will occur without operation shutdown ....... ~ N 29. 'Is presence of H2S gas probable . . ~,. ..... ....~ N GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures .... Y 31. Data presented on potential overpressure zones ..... 32. Seismic analysis 9f shallow gas zones .......... 33. Seabed condition survey (if off-shore) ....... /Y N ' 34. Contact name/phone for weekly progress reports . . .//.. Y N [exploratory only] GEOLOGY: ENGINEERING: COMMISSION: C~mments/Instructions: ,1 Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding infOrmatiOn, information, of this nature is accumulated at the end of the file under APPENDIXi .. No 'special'effort has been made to chronologically,'., ,. organize this category of information. F P CEiVED AUG 08 1996 AJaska Oil & Gas Co~s. Commi~ * ALASKA COMPUTING CENTER * ....... SCHLUMBERGER COMPANY NAME : B.P. EXPLORATION WELL NAME : MPL-25 FIELD NAME : MILNE POINT BOROUGH · NORTH SLOPE STATE · ALASKA API NUMBER : 50-029-22621-00 REFERENCE NO : 95409 LI'S Tape Verification Listing Schlumberger Alaska Computing Center 8-AUG-1996 09:53 PAGE: **** REEL HEADER **** SERVICE NAME : EDIT DATE : 96/08/ 8 ORIGIN : FLIC REEL NAME : 95409 CONTINUATION # : PREVIOUS REEL CO~94ENT : B.P. EXPLORATION, MILNE POINT MPL-25, API #50-029-22621-00 **** TAPE HEADER **** SERVICE NAME : EDIT DATE · 96/08/ 8 ORIGIN · FLIC TAPE NAME : 95409 CONTINUATION # : 1 PREVIOUS TAPE : COIZk4ENT · B.P. ~PLORATION, MILNE POINT MPL-25, API #50-029-22621-00 TAPE HEADER MILNE POINT MWD 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: ~L: ELEVATION(FT FROM MSL O) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: BIT RUN1 95409 ST. AMOUR PYRON WELL CASING RECORD 1ST STRING 2ND STRING MPL-25 500292262100 B.P. EXPLORATION SCHLUMBERGER WELL SERVICES 8-AUG-96 BIT RUN 2 BIT RUN 3 8 13N iOE 3712 5087 46.00 46.00 16.50 OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 8.500 9.625 9019.0 LI'S Tape Verification Listing Schlumberger Alaska Computing Center 8-AUG-1996 09:53 3RD STRING PRODUCTION STRING REMARKS: Well drilled 28-NOV through 04-DEC-95 with CDR/CDN. Ail data was collected in a single bit run. $ $ PAGE: **** FILE HEADER **** FILE NAME : EDIT .001 SERVICE ' FLIC VERSION · O01CO1 DATE : 96/08/ 8 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE FILE HEADER FILENTJ~4BER: 1 EDITED~4ERGEDMWD Depth shifted and clipped curves; all bit runs merged. DEPTH INCREMENT: 0.5000 FILE SOTmlARY LDWG TOOL CODE START DEPTH STOP DEPTH ~fWD 8906.0 15668.5 $ BASELINE CURVE FOR SHIFTS: GR CURVE SHIFT DATA (MEASURED DEPTH) .......... EQUIVALENT UNSHIFTED DEPTH .......... BASELINE DEPTH MWD 88888.0 88901 5 15294.5 15308 0 15277.5 15291 0 15273.0 15286 0 15270.0 15283 5 15265.5 15278 5 15256.0 15269 5 15251.0 15265.0 15242.5 15255.0 15232.5 15246.0 15228.5 15242.0 15227.5 15240.5 15197.0 15210.5 15178.0 15192.0 15163.5 15177.0 15133.5 15148.0 15124.5 15138.0 15105.0 15119.0 15092.5 15107.0 LI'S Tape Verification Listing Schlumberger Alaska Computing Center 8-AUG-1996 09:53 PAGE: 15066.5 15052.0 15038.5 15007.5 14997.0 14988.0 14978.0 14960.0 14941.5 14920.5 14876.0 14827.0 14787.5 14754.0 14736.5 14707.0 9020.0 $ MERGED DATA SOURCE LDWG TOOL CODE $ REMARKS: 15082.0 15066.0 15053.0 15020.5 15010.0 15002.5 14991 0 14973 5 14954 5 14934 5 14889 0 14839 5 14800 0 14766.5 14749.0 14720.5 9020.0 BIT RUN NO. MERGE TOP MERGE BASE The depth adjustments shown above reflect the M~'~D GR to the WA CHGR logged by Atlas. Ail other MWD curves were carried with the GR. This file also contains the Very Enhanced QRO resisitivity with 2' average that was reprocessed at GeoQuest. LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 60 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 17 12 68 13 66 0 14 65 FT Lib Tape Verification Listing Schlumberger Alaska Computing Center 8-AUG-1996 09:53 PAGE: TYPE REPR CODE VALUE 15 66 68 16 66 1 0 66 0 ** SET TYPE - CHAN ** NAME SERVUNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 630376 O0 000 O0 0 1 1 1 4 68 0000000000 RA MWD OH~R~ 630376 O0 000 O0 0 1 1 1 4 68 0000000000 RP MWD OH?4~ 630376 O0 000 O0 0 1 1 1 4 68 0000000000 VRA MWD 0~ 630376 O0 000 O0 0 1 1 1 4 68 0000000000 VRP MWD 0~4 630376 O0 000 O0 0 1 1 1 4 68 0000000000 DER MP~ OI~Rff630376 O0 000 O0 0 1 1 1 4 68 0000000000 ROP ~D FPHR 630376 O0 000 O0 0 1 1 1 4 68 0000000000 FET MP~ HR 630376 O0 000 O0 0 1 1 1 4 68 0000000000 GR MWD GAPI 630376 O0 000 O0 0 1 1 1 4 68 0000000000 RHOBMWD G/C3 630376 O0 000 O0 0 1 1 1 4 68 0000000000 DP=HO MWD G/C3 630376 O0 000 O0 0 1 1 1 4 68 0000000000 PEF M~ BN/E 630376 O0 000 O0 0 1 1 1 4 68 0000000000 CALNMWD IN 630376 O0 000 O0 0 1 1 1 4 68 0000000000 NPHI MP~ PU-S 630376 O0 000 O0 0 1 1 1 4 68 0000000000 GRCH TIE GAPI 630376 O0 000 O0 0 1 1 1 4 68 0000000000 ** DATA ** DEPT. 15668.500 RA.MWD -999.250 RP.MWD -999.250 VRA.MWD VRP.NflWD -999.250 DER.MWD -999.250 ROP.MWD 194.816 FET.~D GR.MWD -999.250 RHOB.MWD -999.250 DRHO.MWD -999.250 PEF.MWD CAI~N.~WD -999.250 NPHI.MWD -999.250 GRCH. TIE -999.250 DEPT. 15000.000 RA.MWD 2.289 RP.MWD 2.245 VRA.~D VRP.MWD 2.220 DER.J~D 2.261 ROP.MWD 88.729 FET.~D GR.MWD 117.028 RHOB.~D 2.424 DRHO.MWD 0.113 PEF.~D CALN. MWD 9.305 NPHI.~D 31.500 GRCH. TIE 46.518 DEPT. 12000.000 RA.MWD 3.155 RP.MWD 3.457 VRA.~gD VRP.MP~ 3.464 DER.MWD 3.339 ROP.MWD 252.020 FET.MWD GR.MWD 87.254 RHOB.MWD 2.426 DRHO.MWD 0.029 PEF.MWD CALN.MWD 8.895 NPHI.MWD 31.600 GRCH. TIE -999.250 DEPT. 9000.000 RA.MWD -999.250 RP.MWD -999.250 VRA.~VD VRP.~ -999.250 DER.~4~D -999.250 ROP.MWD -999.250 FET.MWD GR.F~z~ 40.975 RHOB.MWD 2.078 DRHO.MWD -0.532 PEF.~D CALN. MWD 9.509 NPHI.MWD 51.200 GRCH. TIE -999.250 -999.250 -999.250 -999.250 2.243 O. 845 3. 361 3.223 0.258 3.051 -999.250 -999.250 21.992 LIk Tape Verification Listing Schlumberger Alaska Computing Center DEPT. 8906.000 RA.~D VRP.MWD -999.250 DER.MWD GR.MWD -999.250 RHOB.~D CALN.MWD -999.250 NPHI.~WD 8-AUG-1996 09:53 -999.250 RP.MWD -999.250 ROP.MWD -999.250 DRHO.MWD 51.700 GRCH. TIE -999.250 -999.250 -999.250 -999.250 VRA . ~D FET. PS~D PEF. ~gD PAGE: -999.250 -999.250 -999.250 ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .001 SERVICE : FLIC VERSION : O01CO1 DATE : 96/08/ 8 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .002 SERVICE : FLIC VERSION : O01CO1 DATE : 96/08/ 8 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NU~BER 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: O. 5000 FILE S~Y VENDOR TOOL CODE START DEPTH MWD 8905.5 $ LOG HEADER DATA DATE LOGGED: SOFTWARE: SURFACE SOF~'/ARE VERSION: DOWNHOLE SOFT~gARE VERSION: DATA TYPE (MEMORY or REAL-TIME): TD DRILLER (FT) : TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : STOP DEPTH 15655.0 04 -DEC- 95 FAST2.5 4.0 MEMORY 15655.0 8906.0 15655.0 7O LI~ Tape Verification Listing Schlumberger Alaska Computing Center 8-AUG-1996 09:53 PAGE: HOLE INCLINATION (DEG) MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE CDR RESIST./GR CDN NEUT./DENS. $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH (FT) : 36.7 72.4 TOOL NUMBER ........... RGS022 NDS022 8. 500 9019.0 BOREHOLE CONDITIONS t4IID TYPE: LSND MUD DENSITY (LB/G): 9.70 MUD VISCOSITY (S) : 42.0 MUD PH: MUD CHLORIDES (PPM) : 800 FLUID LOSS (C3): 4.2 RESISTIVITY (OH~bl) AT TEMPERATURE (DEGF) : MUD AT MEASURED TEblPERATURE (MT): 2. 270 MUD AT MAX CIRCULATIONG TEMPERATURE : MUD FILTRATE AT (MT): 2. 090 MLrD CAKE AT (MT): NEUTRON TOOL MATRIX: SANDSTONE MATRIX DENSITY: 2.65 HOLE CORRECTION (IN) : TOOL STANDOFF (IN): 1.0 EP~ FREQUENCY (HZ): 20000 REMARKS: ************ RUN1 ************* DRILLED INTERVAL 9043' - 15655' HOLE ANGLE AT TD = 36.7 DEG @ 15655' RES TO BIT: 52.73'; GR TO BIT: 63.12' NEUT TO BIT: 115.55'; DENS TO BIT: 108.57' TD WELL @ 07:45 03-DEC-95 MAX DEVIATION 72.12 AT 10934 $ LIS FORMAT DATA 66.0 64.0 LIS Tape Verification Listing Schlumberger Alaska Computing Center 8-AUG-1996 09:53 PAGE: ** DATA FORe,AT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 60 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 17 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) FT 630376 O0 000 O0 0 2 1 1 4 68 0000000000 DEPT ATR LW1 OH~4~I630376 O0 000 O0 0 2 1 1 4 68 0000000000 PSR LW1 OH~4~ 630376 O0 000 O0 0 2 1 1 4 68 0000000000 DER LW1 OH~4 630376 O0 000 O0 0 2 1 1 4 68 0000000000 ROPE LW1 F/HR 630376 O0 000 O0 0 2 1 1 4 68 0000000000 TABR LW1 HR 630376 O0 000 O0 0 2 1 1 4 68 0000000000 GR LW1 GAPI 630376 O0 000 O0 0 2 1 1 4 68 0000000000 RHOB LW1 G/C3 630376 O0 000 O0 0 2 1 1 4 68 0000000000 DRHO LW1 G/C3 630376 O0 000 O0 0 2 1 1 4 68 0000000000 PEF LW1 BN/E 630376 O0 000 O0 0 2 1 1 4 68 0000000000 CALN LWl IN 630376 O0 000 O0 0 2 1 1 4 68 0000000000 TNPH LW1 PU 630376 O0 000 O0 0 2 1 1 4 68 0000000000 TABD LW1 630376 O0 000 O0 0 2 1 1 4 68 0000000000 DPHI LW1 PU 630376 O0 000 O0 0 2 1 1 4 68 0000000000 DCAL LW1 IN 630376 O0 000 O0 0 2 1 1 4 68 0000000000 DATA ** DEPT. 15655.000 ATR.LW1 -999.250 PSR.LW1 -999.250 DER.LW1 ROPE.LW1 194.816 TABR.LW1 -999.250 GR.LW1 -999.250 RHOB.LW1 DRHO.LW1 -999.250 PEF.LW1 -999.250 CALN. LW1 -999.250 TNPH. LW1 TABD.LWt -999.250 DPHI.LW1 -999.250 DCAL.LW1 -999.250 -999.250 -999.250 -999.250 LI~ Tape Verification Listing Schlumberger Alaska Computing Center 8-AUG-1996 09:53 PAGE: DEPT. 15000. 000 ATR. LW1 ROPE. LW1 67. 098 TABR. LW1 DRHO . LW1 O . 056 PEF. LW1 TABD. LW1 3.260 DPHI . LW1 DEPT. 12000. 000 ATR. LW1 ROPE. LW1 249. 353 TABR. LW1 DRHO. LW1 O . 020 PEF. LW1 TABD. LW1 1.040 DPHI . LW1 DEPT. 9000. 000 ATR. LW1 ROPE. LW1 -999. 250 TABR. LW1 DRHO.LW1 -0. 532 PEF.LW1 TABD.LW1 -999.250 DPHI.LW1 DEPT. 8905. 500 ATR. LW1 ROPE. LW1 -999. 250 TABR. LW! DRHO . LW1 - 999.250 PEF . LW1 TABD.LW1 -999.250 DPHI.LW1 2. 641 PSR. LW1 O . 642 GR. LW1 3. 508 CALN. LW1 22. 200 DCAL. LW1 3. 196 PSR. LW1 O. 267 GR. LW1 3.209 CALN. LW1 17. 400 DCAI~. LW1 0. 078 PSR . LW1 -999. 250 GR. LW1 21 . 992 CALN. LW1 40.400 DCAL. LW1 - 999.250 PSR. LW1 -999. 250 GR. LW1 -999. 250 CALN. LW1 -999. 250 DCAL. LW1 2. 434 DER. LW1 109.567 RHOB. LW1 9.388 TNPH.LW1 0.888 3. 542 DER. LW1 79. 059 RHOB. LW1 8. 899 TNPH. LW1 O. 399 31. 031 DER. LW1 40. 975 RHOB. LW1 9. 509 TNPH. LW1 1 . 009 -999.250 DER.LW1 -999.250 RHOB.LW1 -999.250 TNPH.LW1 -999.250 2.503 2.426 30.80O 3.406 2.427 27.500 0.078 2.078 51.200 -999.250 -999.250 49.700 ** END OF DATA ** * * * * FILE TRAILER * * * * FILE NAME : EDIT .002 SERVICE : FLIC VERSION ' 0 O1 CO1 DATE · 96/08/ 8 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** TAPE TRAILER **** SERVICE NA2~E : EDIT DATE : 96/08/ 8 ORIGIN · FLIC TAPE NAME : 95409 CONTINUATION # : 1 PREVIOUS TAPE : COICk~ENT · B.P. EXPLORATION MILNE POINT MPL-25, API #50~029-22621~00 **** REEL TRAILER **** SERVICE NAME : EDIT DATE · 96/08/ 8 ORIGIN : FLIC REEL NAME : 95409 CONTINUATION # : PREVIOUS REEL : CON~4ENT : B.P. EXPLORATION, MILNE POINT MPL-25, API #50-029-22621-00 Tape Subfile 2 is type: TAPE HEADER MILNE POINT UNIT CASED HOLE WIRELINE LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: 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: WELL CASING RECORD MPL - 25 500292262100 BP EXPLORATION (ALASKA) INC. WESTERN ATLAS LOGGING SERVICES 08-MAY-96 6644.00 W.R. BARKER D. ROBERTSON 8 13N 10E 3712 5086 .00 46.00 16.50 OPEN HOLE CASING DRILLERS CASING BIT SIZE (IN) SIZE (IN) DEPTH (FT) WEIGHT (LB/FT) 1ST STRING 2ND STRING 20.000 115.0 3RD STRING 9.625 9019.0 PRODUCTION STRING 7.000 15636.0 CURVE SHIFT DATA - ALL PASSES TO STANDARD (MEASURED DEPTH) BASELINE CURVE FOR SHIFTS PBU TObL CODE: PBU CURVE CODE: RUN NUMBER: PASS NI3MBER: DATE LOGGED: LOGGING COMPANY: BASELINE DEPTH $ GR GRCH 1 1 10-APR-96 WESTERN ATLAS LOGGING SERVICES EQUIVALENT UNSHIFTED DEPTH REMARKS: Marked Line GR/CCL. 91.10 40.00 26.00 *** THIS IS THE DEPTH REFERENCE FOR THIS WELL *** NO DEPTH SHIFTING WAS DONE SINCE THERE IS ONLY 1 PASS (MAIN PASS), & IT IS THE DEPTH REFERENCE FOR THIS WELL. LOG WAS RUN WITH MAGNETIC MARKS FOR DEPTH CONTROL. FILE HEADER FILE NUMBER: 1 EDITED CURVES Depth shifted and clipped curves for each pass in separate files. PASS NUMBER: 1 DEPTH INCREMENT: .5000 FILE SUMMARY PBU TOOL CODE START DEPTH STOP DEPTH GRCH 14700.0 15309.0 $ CURVE SHIFT DATA - PASS TO PASS (MEASURED DEPTH) BASELINE CURVE FOR SHIFTS PBU CURVE CODE GRCH PASS NUMBER: 1 BASELINE DEPTH $ REMARKS: EQUIVALENT UNSHIFTED DEPTH PASS 1 (MAIN PASS). THE GAMMA RAY FROM THIS PASS IS THE DEPTH REFERENCE FOR THIS WELL. CN WN FN COUN STAT : BP EXPLORATION (ALASKA) : MPL - 25 : MILNE POINT/KUPARUK : NORTH SLOPE : ALASKA * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 2 Curves: Name Tool Code Samples Units 1 GRCH GR 68 1 GAPI 4 2 TENS GR 68 1 LB 4 API API API API Log Crv Crv Size Length Typ Typ Cls Mod 4 30 310 01 1 4 30 635 99 1 * DATA RECORD (TYPE# 0) 1014 BYTES * Total Data Records: 16 Tape File Start Depth = 15321.000000 Tape File End Depth = 14689.000000 Tape File Level Spacing = 0.500000 Tape File Depth Uni = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 3796 datums Tape Subfile: 2 107 records... Minimum record length: 62 bytes Maximum record length: 1014 bytes Tape Subfile 3 is type: LIS FILE HEADER FILE NUMBER: 2 RAW CURVES Curves and log header data for each pass in separate files; raw background pass in last file. PASS NUMBER: 1 DEPTH INCREMENT: .2500 FILE SUMMARY VENDOR TOOL CODE START DEPTH GR 14700.0 $ LOG HEADER DATA DATE LOGGED: SOFTWARE VERSION: TIME LOGGER ON BOTTOM: TD DRILLER (FT) : TD LOGGER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : LOGGING SPEED (FPHR) : DEPTH CONTROL USED (YES/NO): STOP DEPTH 15316.0 10-APR-96 FSYS REV. J001 VER. 1.1 1218 10-APR-96 15551.0 15347.0 14700.0 15311.0 1500.0 YES TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE PFC PERFORATE GAMMA RAY $ TOOL NUMBER 0722XA BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE(IN): DRILLER' S CASING DEPTH (FT) : LOGGER'S CASING DEPTH (FT) : .000 15636.0 .0 BOREHOLE CONDITIONS FLUID TYPE: FLUID DENSITY (LB/G): SURFACE TEMPERATURE (DEGF): BOTTOM HOLE TEMPERATURE (DEGF) : FLUID SALINITY (PPM) : FLUID LEVEL (FT) : FLUID RATE AT WELLHEAD (BPM) : WATER CUTS (PCT) : GAS/OIL RATIO: CHOKE (DEG) : SEAWATER .00 .0 .0 0 .0 .000 .000 .000 .0 NEUTRON TOOL TOOL TYPE (EPITHERMAL OR THERMAL): MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): .00 .000 BLUELINE COUNT RATE NORMALIZATION IN OIL ZONE TOP NORMALIZING WINDOW (FT) : BASE NORMALIZING WINDOW (FT) : .0 .0 BLUELINE COUNT RATE SCALES SET BY FIELD ENGINEER FAR COUNT RATE · I SCALE (CPS) : FAR COUNT RATE HIGH SCALE (CPS): NEAR COUNT RATE LOW SCALE (CPS): NEAR COUNT RATE HIGH SCALE (CPS): TOOL STANDOFF (IN) : REMARKS: PASS 1 (MAIN PASS). $ CN WN FN COUN STAT : BP EXPLORATION (ALASKA) : MPL - 25 : MILNE POINT/KUPARUK : NORTH SLOPE : ALASKA .0 * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 5 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod GR GR 68 CCL GR 68 SPD GR 68 TEN GR 68 TTEN GR 68 1 GAP I 4 1 4 1 F/MN 4 1 LB 4 1 LB 4 4 30 310 01 1 4 30 150 01 1 4 30 636 99 1 4 30 635 99 1 4 30 635 99 1 20 * DATA RECORD (TYPE# 0) 1014 BYTES * Total Data Records: 61 Tape File Start Depth = 15321.000000 Tape File End Depth = 14689.000000 Tape File Level Spacing = 0.250000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 15175 datums Tape Subfile: 3 132 records... Minimum record length: 62 bytes Maximum record length: 1014 bytes Tape Subfile 4 is type: LIS 96/05/08 O1 **** REEL TRAILER **** 96/ 5/ 9 O1 Tape Subfile: 4 2 records... Minimum record length: 132 bytes Maximum record length: 132 bytes End of execution: Thu 9 MAY 96 1:39a Elapsed execution time = 0.83 seconds. SYSTEM RETURN CODE = 0