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Home My WebLink About218-1521. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Convert to JP 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 15,000 feet 14,740 feet true vertical 4,362 feet N/A feet Effective Depth measured 14,740 feet 4,682 & 6,095 feet true vertical 4,377 feet 4,122 & 4431 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2# / L-80 / EUE 8rd 4,812' 4,191' Tri-Point Hyd. Packers and SSSV (type, measured and true vertical depth)BOT SLZP Ltp N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Contact Phone: 4,790psi 107' N/A 5,750psi 6,890psi N/A measured Burst N/A Collapse N/A 3,090psi 4,647' Casing Conductor 4,377'14,745' 6,095' 6,277'Surface Production Drilled Liner 20" 9-5/8" 7-5/8" 107' 6,277' TVD N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025518 / ADL047437 Milne Point Field / Schrader Bluff Oil Pool MPU E-35 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-152 50-029-23615-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC Plugs Junk measured Length measured true vertical Packer MDSize 107' 4,438' 540 184406150 Water-BblOil-Bbl Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf 6-5/8" 6,095' 4,421' Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. scott.pessetto@hilcorp.com 907-564-4373 N/A Scott Pessetto 322-601 200 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 601 601 255858 217 PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Anne Prysunka at 9:09 am, Dec 13, 2022 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2022.12.12 12:31:59 -09'00' David Haakinson (3533) RBDMS JSB 121223 WCB 12-2-2024 _____________________________________________________________________________________ Revised By: TDF 12/12/2022 Milne Point Unit Well: MPUE-35 Last Completed: 11/22/2022 PTD: 218-152 SCHEMATIC TD =15,000’ (MD) / TD =4,362’(TVD) 20” Orig. KB Elev.: 26.5’(Innovation) 7-5/8” 6 9-5/8” 1 2 PBTD =14,740’(MD) / PBTD =4,377’(TVD) ES Cementer @ 2,427’ MD Min ID= 2.75” @ ±4,750’ 7 9&10 8 4 3 5 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor - / X-52 / Welded N/A Surface 107' 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 6,277’ 7-5/8" Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 6,095’ 6-5/8” PreDrilled Liner 20 / L-80 / Hyd 563 6.049 6,092’ 14,745’ TUBING DETAIL 3-1/2” Tubing 9.2 / L-80 / EUE 8rd 2.992 Surface 4,812’ JEWELRY DETAIL No Depth Item 1 4,577’ 3-1/2” Sliding Sleeve with X- Profile of 2.81” 2 4,629’ 3-1/2” Baker Zenith Guage Carrier 3 4,682' 7-5/8” x 3-1/2” Tri-Point Hydraulic Set Packer 4 4,738’ XN Nipple – Min ID- 2.750 No Go 5 4,781’ WLEG - Bottom @ 4,812’ 6 6,095’ BOT SLZXP Liner Top Pkr w/BD Slips, 7" x 9 5/8" 7 6,114’ Crossover Sub, 7" H563 x 6.625" Hyd 563 8 14,709’ 4-1/2” Drillable Packoff Sub 9 14,740’ WIV Valve with 1” Ball on Seat 10 14,743’ Round Nose Float Shoe: Bottom @ 14,745 WELL INCLINATION DETAIL KOP @ 43’ Max Hole Angle = 94.5 deg. @ 7,954’ GENERAL WELL INFO API: 50-029-23615-00-00 Drilled, Cased and Completed by Innovation - 12/29/18 ESP SWAP by ASR#1 – 3/6/2019 ESP SWAP by ASR#1 – 7/1/2022 Convert to Jet Pump by ASR#1 – 11/22/2022 TREE & WELLHEAD Tree 5K Cameron 2-9/16” Wellhead FMC Gen 5 CEMENT DETAIL 20” ~270 ft3 dumped down backside 9-5/8”Stg 1 L - 425 sx / T – 397 sx Stg 2 L – 550 sx / T – 270 sx (271 bbls to surface) 6-5/8” PREDRILLED LINER DETAIL 6-5/8” Predrilled Liner, 78 holes/foot, 3/8” holes, 1x 6.625”x7.75” free floating cent/jnt Well Name Rig API Number Well Permit Number Start Date End Date MP E-35 ASR#1 50-029-23615-00-00 218-152 11/20/2022 11/22/2022 Rack and Tally Jet Pump Completion. Spot in Tech Wire Spooler. Prepare rig floor to run Completion.;M/U Jet Pump Completion WLEG Mule Shoe, XN Nipple, Tri Point Packer, Zenith Gauge, Sliding Sleeve.;RIH with Jet Pump Completion on 3.5", 9.2#, EUE, L-80 Tubing;M/U Tubing Hanger, Terminate I-Wire Cap String to Hanger. Land Hanger. RILDS. PUW=40K, SOW 29K. Ran a total of 81 Cross Collar Cannon Clamps.;Drop Ball & Rod. R/U Circulating Lines. Pressure to 3800psi to set Tri Point Packer. Hold for 30 charted minutes for tubing test. Pressure test IA to 3650 psi for 30 Charted minutes.;Install BPV. Blow down all circulating lines and equipment. Total Fluid Loss to the Formation for the Work Over = 400 bbls.;Suck Out The Pits. Start Rigging Down. No operations to report. 11/19/2022 - Saturday Continue to POOH Laying down 3.5" EUE Tubing and ESP Cable to ESP Assembly.;Lay Down ESP Assembly. Found the ESP Intake Plugged off with a piece of absorb.;R/D ESP Handling equipment. L/D Elephant Trunk and Sheave. Clear Rig Floor of all non essential tools and equipment.;Rack and Tally Drill Collars, 3.5' Work String and Yellow Jacket Test Packer.;M/U Test Packer and 6 each 4-1/4" Drill Collars. RIH on 3.5" Work String to 4920' MD. Obtain Parameters, PUW = 53K, SOW= 32K. Set Test Packer at 4915' MD as per Yellow Jacket rep. Pump 30 BBL. Down the backside to fill the hole. PT 7-5/8"casing to 3650 psi. for 30 charted minutes. Good Test. Release packer.;POOH with Test Packer to surface. Pump 2X Pipe Displacement for hole fill.;Change Rig Floor Pipe Handling Equipment. Hang Sheave in the Mast for the Tech Wire. R/U Baker Spooler. Rack and Tally 3.5" Jet Pump Completion. 11/22/2022 - Tuesday 11/20/2022 - Sunday M/U TIW and IBOP on 3-1/2" test mandrel. Hook up testing equipment.;Test BOPE as per AOGCC approved Sundry. 250 psi low / 2500 psi high. All tests charted for 5 minutes each. Witness of the test was waived by AOGCC rep. Adam Earl. Rig Accepted on E-35 at 15:00 Hours on 11-20-2022;Blow down Testing equipment. R/U ESP Spooler Sheave.;M/U Tee Bar and pull CTS Plug. Bleed pressure off. Pull BPV;M/U Landing Joint. BOLDS. Pull Hanger to the floor. Pull off seat at 58K, PUW = 59 K. Pump 20 bbls 8.4 ppg. Source Water with no returns.;POOH Laying down 3.5" EUE completion F/5780' T/2200' at report time. Pump 2X Displacement for hole fill. 11/21/2022 - Monday 11/18/2022 - Friday No operations to report. 11/16/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 11/17/2022 - Thursday No operations to report. MIT-IA or combo to 3650 psi is a COA in Sundry 322-601. -WCB 250 psi low / 2500 psi high. All tests charted for 5 minutes each. Witness of the test was waived by AOGCC rep. Adam Earl. Pull BPV;M/U Landing Joint. BOLDS. Pull Hanger to the floor. Pull off seat at 58K, PUW = 59 K. Pump 20 bbls 8.4 ppg. Source Water with no returns.;POOH Laying down 3.5" EUE completion F/5780' T/2200' M/U Jet Pump Completion WLEG Mule Shoe, XN Nipple, Tri Point Packer, Zenith Gauge, Sliding Sleeve.;RIH with Jet Pump Completion on 3.5", 9.2#, EUE, L-80 Tubing;M/U Tubing Hanger, Terminate I-Wire Cap String to Hanger. Land Hanger. RILDS Continue to POOH Laying down 3.5" EUE Tubing and ESP Cable to ESP Assembly.;Lay Down ESP Assembly. Found the ESP Intake Plugged off with a piece of absorb Test BOPE as per AOGCC approved Sundry Pressure to 3800psi to set Tri Point Packer. Hold for 30 charted minutes for tubing test. Pressure test IA to 3650 psi for 30 Charted minutes Set Test Packer at 4915' MD as per Yellow Jacket rep. Pump 30 BBL. Down the backside to fill the hole. PT 7-5/8"casing to 3650 psi. for 30 charted minutes. Good Test 1 Regg, James B (OGC) From:Charles Huntington - (C) <Charles.Huntington@hilcorp.com> Sent:Sunday, November 20, 2022 8:10 PM To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Cc:Alaska NS - ASR - Well Site Managers Subject:BOPE Test, MPU E-35, 11-20-2022 Attachments:E-35 BOPE test report 11-20-22.xlsx Categories:Blue Category Please find attached BOPE Test on 11‐20‐2022 Regards, ASR DSM’s Hilcorp DSM: 907‐685‐1266 Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Some people who received this message don't often get email from charles.huntington@hilcorp.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Milne Point Unit E-35PTD 2181520 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:ASR 1 DATE:11/20/22 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2181520 Sundry #322-601 Operation:Drilling:Workover:x Explor.: Test:Initial:X Weekly:Bi-Weekly:Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:1366 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators P P #1 Rams 1 2 7/8" x 5"P Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 2 1/16"P Time/Pressure Test Result HCR Valves 1 2 1/16"P System Pressure (psi)3000 P Kill Line Valves 2 2 1/16"P Pressure After Closure (psi)1800 P Check Valve 0 NA 200 psi Attained (sec)8 P BOP Misc 0 NA Full Pressure Attained (sec)49 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4 / 2225 PSI P No. Valves 16 FP ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 23 P #1 Rams 7 P Coiled Tubing Only:#2 Rams 7 P Inside Reel valves 0 NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:5.0 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 11/19/2022 13:20 Waived By Test Start Date/Time:11/20/2022 15:00 (date)(time)Witness Test Finish Date/Time:11/20/2022 20:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Adam Earl Hilcorp F/P test #6, Manifold Valve # K5. Changed out valve and retested good. Test preformed w/ 3-1/2"" test joint. Bottle precharge pressure 1000 psi. C.Pace / J. Werlinger Hilcorp Alaska LLC A.Hiem / C. Huntington PBU E-35 Test Pressure (psi): askans-asr-toolpushers@hilcorp.co ans-asrwellsitemanagers@hilcorp Form 10-424 (Revised 08/2022)2022-1120_BOP_Hilcorp_ASR1_MPU_E-35           J. Regg; 12/27/2022  From:Brooks, James S (OGC) on behalf of AOGCC Reporting (CED sponsored) To:AOGCC Records (CED sponsored) Subject:FW: BOP - Hilcorp ASR 1 Date:Wednesday, December 28, 2022 9:31:00 AM Attachments:2022-1120_BOP_Hilcorp_ASR1_MPU_E-35.pdf James Brooks research analyst II | alaska oIl and Gas conservatIon commIssIon department of commerce, communIty and economIc development 907-793-1241|James.Brooks@alaska.Gov From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Tuesday, December 27, 2022 3:36 PM To: AOGCC Reporting (CED sponsored) <aogcc.reporting@alaska.gov> Subject: BOP - Hilcorp ASR 1 Milne Point Unit E-35 (PTD 2181520) Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage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aylor wellman for David Haakinson By Anne Prysunka at 11:09 am, Oct 12, 2022 'LJLWDOO\VLJQHGE\7D\ORU :HOOPDQ '1FQ 7D\ORU:HOOPDQ RX 8VHUV 'DWH 7D\ORU:HOOPDQ '65 ; %23(WHVWWRSVL $SSURYHGIRUDUHYHUVHFLUFXODWLQJMHWSXPS 7KH,$ZLOOKDYHD;9DFWXDWHGYDOYHWRSURWHFWWKH '/% ,$IURPSRZHUIOXLGSUHVVXUHDQRPDOLHV669RQ,$SRZHUIOXLGKLJKSUHVVXUHWULSQRWWRH[FHHGSVL0,7,$RU&0,7,$WRSVL &KDUWHGDQG5HFRUGHG ,$ORZSUHVVXUHWULSWREHSVLRUOHVV 669RQSURGXFWLRQWXELQJORZSUHVVXUHWULSVHWDWaSVLRUOHVV 669RQWXELQJFORVXUHZLWKLQPLQXWHVRQ669RQ,$DQGYLVDYHUVD 0*52&7*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.10.19 15:28:35 -04'00' RBDMS JSB 102422 ZtK tĞůů͗DWhͲϯϱ ĂƚĞ͗ϬϯKĐƚϮϬϮϮ tĞůůEĂŵĞ͗DWhͲϯϱW/EƵŵďĞƌ͗ϱϬͲϬϮϵͲϮϯϲϭϱͲϬϬͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗KŶůŝŶĞWƌŽĚƵĐĞƌWĂĚ͗ͲWĂĚ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗EŽǀĞŵďĞƌϭ͕ϮϬϮϮZŝŐ͗^Zϭ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍zĞƐĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗dŽŵ&ŽƵƚƐWĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϮϭϴͲϭϱϮ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗dŽĚĚ^ŝĚŽƚŝ;ϵϬϳͿϳϳϳͲϴϰϮϬ;KͿ;ϵϬϳͿϲϯϮͲϰϭϭϯ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗dĂǇůŽƌtĞůůŵĂŶ;ϵϬϳͿϳϳϳͲϴϰϰϵ;KͿ;ϵϬϳͿϵϰϳͲϵϱϯϯ;DͿ ƵƌƌĞŶƚŽƚƚŽŵ,ŽůĞWƌĞƐƐƵƌĞ͗ ϭϳϮϲƉƐŝΛϯϲϬϬ͛ds ϳͬϯϭͬϮϬϭϴ^,W^ͮϵ͘ϮϮWW' DW^W͗ ϭϯϲϲƉƐŝ 'ĂƐŽůƵŵŶ'ƌĂĚŝĞŶƚ;Ϭ͘ϭƉƐŝͬĨƚͿ DĂǆ/ŶĐůŝŶĂƚŝŽŶϳϯ͘ϱΣΛϱϯϬϲ͛D ƌŝĞĨtĞůů^ƵŵŵĂƌǇ͗ DWhͲϯϱǁĂƐĚƌŝůůĞĚĂŶĚĐŽŵƉůĞƚĞĚĂƐĂ^ĐŚƌĂĚĞƌůƵĨĨKƉƌŽĚƵĐĞƌŝŶĞĐĞŵďĞƌϮϬϭϴ͘dŚĞǁĞůůŚĂƐĂ Εϴ͕ϳϬϬ͛ŵĚŚŽƌŝǌŽŶƚĂůƐĞĐƚŝŽŶŝŶƚŚĞKƐĂŶĚƐ͘dŚĞǁĞůůĞŶĐŽƵŶƚĞƌĞĚŚŝŐŚĞƌƚŚĂŶĞǆƉĞĐƚĞĚ'KZ͛ƐŝŶƚŚĞƚŽĞŽĨ ƚŚĞǁĞůů͘tŚĞŶƚŚĞǁĞůůǁĂƐďƌŽƵŐŚƚŽŶůŝŶĞƚŚĞ'KZ͛ƐƌĂŶŐĞĚĨƌŽŵϭϬϬϬͲϮϬϬϬƐĐĨͬďďůĂŶĚƚŽƚĂůŐĂƐƵƉƚŽ ϭ͘ϱŵŵƐĐĨƉĚ͘tĞǁĞƌĞĂďůĞƚŽĚƌĂǁƚŚĞǁĞůůĚŽǁŶƚŽϭϭϬϬƉƐŝǁŝƚŚƚŚĞ^WƐŽĂŚŝŐŚĞƌŚŽƌƐĞƉŽǁĞƌĚĞƐŝŐŶǁĂƐ ŝŶƐƚĂůůĞĚŝŶ:ƵŶĞϮϬϮϮ͘dŚŝƐ^WŝƐŽŶůǇĂďůĞƚŽďĞƌĂŶŝŶ/Ͳůŝ ŵŝƚŵŽĚĞĂŶĚǁĞĂƌĞŽŶůǇĂďůĞƚŽĚƌĂǁƚŚĞǁĞůů ĚŽǁŶƚŽϭϱϬϬƉƐŝ͘ EŽƚĞƐZĞŐĂƌĚŝŶŐtĞůůďŽƌĞŽŶĚŝƚŝŽŶ xdŚĞϳͲϱͬϴ͟ĐĂƐŝŶŐƉĂƐƐĞĚĂŶD/dͲ/ƚŽϭ͕ϴϬϬƉƐŝŽŶϭϮͬϮϴͬϮϬϭϴ;ĚƵƌŝŶŐƚŚĞŽƌŝŐŝŶĂůĐŽŵƉůĞƚŝŽŶͿ͘ xdŚĞĐƵƌƌĞŶƚƉƵŵƉŝƐŽƉĞƌĂƚŝŽŶĂůĂŶĚĚŽǁŶŚŽůĞƉƌĞƐƐƵƌĞƌĞĂĚŝŶŐƐĂƌĞĂǀĂŝůĂďůĞ͘ KďũĞĐƚŝǀĞ͗ ZĞƉůĂĐĞ^WǁŝƚŚŶĞǁũĞƚƉƵŵƉĐŽŵƉůĞƚŝŽŶĂŶĚƌĞƚƵƌŶǁĞůůƚŽƉƌŽĚƵĐƚŝŽŶ͘ WƌĞͲZŝŐWƌŽĐĞĚƵƌĞ;EŽƐƵŶĚƌǇƌĞƋƵŝƌĞĚͿ͗ WƵŵƉŝŶŐΘtĞůů^ƵƉƉŽƌƚ ϭ͘ůĞĂƌĂŶĚůĞǀĞůƉĂĚĂƌĞĂŝŶĨƌŽŶƚŽĨǁĞůů͘^ƉŽƚƌŝŐŵĂƚƐĂŶĚĐŽŶƚĂŝŶŵĞŶƚ͘ Ϯ͘ZǁĞůůŚŽƵƐĞĂŶĚĨůŽǁůŝŶĞƐ͘ůĞĂƌĂŶĚůĞǀĞůĂƌĞĂĂƌŽƵŶĚǁĞůů͘ ϯ͘Zh>ŝƚƚůĞZĞĚ^ĞƌǀŝĐĞƐ͘ZhƌĞǀĞƌƐĞŽƵƚƐŬŝĚĂŶĚϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬ͘ ϰ͘ŝƌĐƵůĂƚĞĂƚůĞĂƐƚŽŶĞǁĞůůďŽƌĞǀŽůƵŵĞǁŝƚŚƉƌŽĚƵĐĞĚǁĂƚĞƌĚŽǁŶƚƵďŝŶŐ͕ƚĂŬŝŶŐƌĞƚƵƌŶƐƵƉĐĂƐŝŶŐ ƚŽϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬ͘ ϱ͘ŽŶĨŝƌŵǁĞůůŝƐĚĞĂĚ͘&ƌĞĞǌĞƉƌŽƚĞĐƚƚƵďŝŶŐͬĐĂƐŝŶŐĂƐŶĞĞĚĞĚǁŝƚŚϲϬͬϰϬDĞK,ŽƌĚŝĞƐĞů͘ Ă͘&ƌĞĞǌĞƉƌŽƚĞĐƚŝƐƵƉƚŽƚŚĞĚŝƐĐƌĞƚŝŽŶŽĨƚŚĞtĞůůƐŝƚĞ^ƵƉĞƌǀŝƐŽƌĚĞƉĞŶĚŝŶŐŽŶƚŝŵŝŶŐĨŽƌ ĂƌƌŝǀĂůŽĨƚŚĞ^Z͘ ϲ͘Z>ŝƚƚůĞZĞĚ^ĞƌǀŝĐĞƐĂŶĚƌĞǀĞƌƐĞŽƵƚƐŬŝĚ͘ ϳ͘ZhĐƌĂŶĞ͘^ĞƚWs͘EƚƌĞĞĂŶĚEhKW͘ZƌĂŶĞ͘ ϴ͘EhKWŚŽƵƐĞ͘^ƉŽƚŵƵĚďŽĂƚ͘ ƌŝĞĨZtKWƌŽĐĞĚƵƌĞ͗ ZtK tĞůů͗DWhͲϯϱ ĂƚĞ͗ϬϯKĐƚϮϬϮϮ ϭ͘D/Zh,ŝůĐŽƌƉ^ZηϭtKZŝŐ͕ĂŶĐŝůůĂƌǇĞƋƵŝƉŵĞŶƚĂŶĚůŝŶĞƐƚŽϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬ͘ 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ŚĂŶŐĞĚ,ZŚŽŬĞĂ ŚŽŬĞDĂŶŝĨŽůĚƚŽ&W STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:ASR 1 DATE: 6/29/22 Rig Rep.: Rig Phone: 685-1266 Operator: Op. Phone:685-1266 Rep.: E-Mail Well Name: PTD #22181520 Sundry #322-312 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:1007 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 11"P Pit Level Indicators PP #1 Rams 1 2 7/8" x 5"P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 2 1/16"P Inside Reel valves 0NA HCR Valves 1 2 1/16"FP Kill Line Valves 2 2 1/16"P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi)3050 P CHOKE MANIFOLD:Pressure After Closure (psi)1850 P Quantity Test Result 200 psi Attained (sec)16 P No. Valves 16 FP Full Pressure Attained (sec)54 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4x2262 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:2 Test Time:9.0 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/27/22 18:46 Waived By Test Start Date/Time:6/29/2022 6:00 (date) (time)Witness Test Finish Date/Time:6/29/2022 15:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Lou Laubenstein Hilcorp Test #6 bled off. Greased HCR choke. Retested good. Test #7 bled off. Greased C1 valve. Retested good. Tested w/ both 2.875" & 3.5" test joints. Annular closing time = 28 sec C. Pace/ C. Greub Hilcorp Alaska S. Hiem/ A. Haberthur MPU E-35 Test Pressure (psi): skaNS-ASR-Well Site Managers@hilcorp.c Form 10-424 (Revised 02/2022) 2022-0629_BOP_Hilcorp_ASR1_MPU_E-35 9 9 9 9 9 9 9 9 99 9 9 9 9 9 -5HJJ FP FP 2 Test #6 bled off. Greased HCR choke.Test #7 bled off. Greased C1 valve. Annular closing time = 28 sec By Samantha Carlisle at 9:48 am, Aug 05, 2022 Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Date: 07/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes BCU 18RD 50133205840100 222033 6/11/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/18/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/7/2022 Yellowjacket GPT-PLUG + Report BCU 24 50133206390000 214112 6/16/2022 Halliburton PPROF BCU 24 50133206390000 214112 5/23/2022 Yellowjacket GPT-PERF + Report BCU 24 50133206390000 214112 5/26/2022 Yellowjacket GPT-PERF + Report BCU 7A 50133202840100 214060 6/21/2022 Yellowjacket CBL BCU 7A 50133202840100 214060 6/15/2022 Yellowjacket GAMMA RAY + Report BRU 232-26 50283200770000 184138 5/25/2022 Yellowjacket CBL CLU 01RD 50133203230100 203129 5/19/2022 Yellowjacket PERF + Report CLU 01RD 50133203230100 203129 5/24/2022 Yellowjacket PERF + Report CLU 09 50133205440000 204161 5/27/2022 Yellowjacket PERF + Report CLU-1RD 50133203230100 203129 5/28/2022 Halliburton PPROF + Report END 1-17A 50029221000100 196199 5/26/2022 Halliburton LDL END 1-45 50029219910000 189124 5/23/2022 Halliburton LDL + Report END 3-17F 50029219460600 203216 6/15/2022 AK E-Line PLUG CUT FALLS CREEK 3 50133205240000 203102 6/4/2022 Yellowjacket PERF + Report HVB B-16 50231200400000 212133 6/14/2022 AK E-Line CIBP KALOTSA 1 50133206570000 216132 7/7/2022 Yellowjacket PERF + Report KBU 11-07 50133205560000 205165 6/16/2022 Yellowjacket GPT-PERF + Report KBU 11-07 50133205560000 205165 6/20/2022 Yellowjacket GPT-PERF + Report KBU 33-06X 50133205290000 203183 6/22/2022 Yellowjacket CBL MPU B-28 50029235660000 216027 5/27/2022 Halliburton LDL MPU B-28 50029235660000 216027 5/27/2022 Halliburton MFC + Report MPU B-30 50029235710000 216153 5/18/2022 Halliburton PERF MPU E-06 50029221540000 191048 5/28/2022 Halliburton MFC + Report Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: MPU E-35 50029236150000 218152 6/15/2022 Halliburton MFC + Report MPU L-50 50029235550000 215132 6/24/2022 Read COIL FLAG PAXTON 10 50133206910000 220064 5/27/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton RBT PBU GNI-03 50029228200000 197189 6/25/2022 Read CALIPER PBU GNI-03 50029228200000 197189 6/25/2022 Read TEMP-PRESS PBU K-01 50029209980000 183121 6/21/2022 Halliburton PPROF + Report PBU M-13A 50029205220100 201165 5/27/2022 Halliburton TMD3D-WFL + Report PBU NGI-05 50029201960000 176014 6/7/2022 Halliburton CAST PBU W-01A 50029218660100 203176 6/8/2022 Halliburton RBT SRU 241-33 50133206630000 217047 6/13/2022 Yellowjacket PERF SRU 241-33B 50133206960000 221053 5/25/2022 Halliburton TEMP-PRESS SRU 32A-33 50133101640100 191014 6/11/2022 AK E-Line PPROF Please include current contact information if different from above. BCU 18RD PTD:222-033 T36747 BCU 24 PTD:214-112 T36748 BCU 7A PTD:214-060 T36749 BRU 232-26 PTD:184-138 T36750 CLU 01RD PTD:203-129 T36751 CLU 09 PTD: 204-161 T36752 CLU1RD PTD:203-129 T36751 END 1-17A PTD:196-199 T36753 END 1-45 PTD:189-124 T36754 END 3-17F PTD:203-216 T36755 Falls Creek 3 PTD:203-102 T36756 HVB B-16 PTD:212-133 T36757 Kalosta 1 PTD:216-132 T36758 KBU 11-7 PTD:205-165 T36759 KBU 33-06X PTD:203-183 T36760 MPU B-28 PTD:216-027 T36761 MPU B-30 PTD:216-153 T36762 MPU E-06 PTD: 191-048 T36763 MPU E-35 PTD:218-152 T36764 MPU L-50 PTD:215-132 T36765 Paxton 10 PTD:220-064 T36766 PBU C-24B PTD:212-063 T36767 PBU GNI-03 PTD:197-189 T36768 PBU K-01 PTD:183-121 T36769 PBU M-13A PTD:201-165 T36770 PBU NGI-05 PTD:176-014 T36771 PBU W-01A PTD:203-176 T36772 SRU 241-33 PTD:217-047 T36773 SRU 241-33B PTD:221-053 T36774 SRU 32A-33 PTD: 191-014 T36775 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.12 12:56:51 -08'00' Surface Casing by Conductor Annulus Fill Coat Corrosion Inhibitor (CI) Applications Well Field API -Corrosion PTD Top of Cement (ft.) Inhibitor: Fill Volume (gal) Final Cl Top (ft.) Corrosion Inhibitor Treatment Date E-35 Milne Point 50029236150000 2181520 Surface 22.5 Top of Cond 10/24/2019 E-36 Milne Point 50029236200000 2190050 Surface 15 Top of Cond 10/24/2019 E-38 Milne Point 50029236260000 2190440 Surface 20 Top of Cond 10/24/2019 E-39 Milne Point 50029236400000/60-00 2190960 Surface 20 Top of Cond 10/24/2019 E-40 Milne Point 50029236260000 2190440 Surface 25 Top of Cond 10/25/2019 E-41 Milne Point 50029236220000 2190310 Surface 15 Topof Cond 10/24/2019 E-42 Milne Point 50029236350000/60-00 2190820 Surface 17 Top of Cond 10/25/2019 M-18 Milne Point 50029236320000 2190700 3 50 Top of Cond 10/26/2019 M-06 Milne Point 50029236460000 2191130 3 30 Top of Cond 10/26/2019 Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat Notes: #7 Initial top of Cement footage measurement was taken from the 4" outlet down to the TOC The 4" conductor outlets are anywhere from Ito 3' down from the top of the conductor RECEIVE® DEC 0 6 2019 A®GCC DATA SUBMITTAL COMPLIANCE REPORT 4/15/2019 Permit to Drill 2181520 Well Name/No. MILNE PT UNIT E35 MD 15000 TVD 4362 Completion Date 12/28/2018 REQUIRED INFORMATION Mud Log No l V-� Operator HILCORP ALASKA LLC Completion Status 1 -OIL Current Status 1-0I1 Samples Nov/ DATA INFORMATION List of Logs Obtained: ROP/ABG/DGR/EWR/ADR MD Main and P131, ABG/DGR/EWR/ADR TVD Main and PBI Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received ED C 30260 Digital Data 100 15000 ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data ED C 30260 Digital Data Log C 30260 Log Header Scans AOGCC Page I of 3 6250 14950 0 0 API No. 50.029.23615-00-00 UIC No Directional Survey Yes `� (from Master Well Data/Logs) 1/17/2019 Electronic Data Set, Filename: MPU E-35 DGR ABG EWR ADR.Ias 1/17/2019 Electronic Data Set, Filename: MPU E-35 ADR Quadrants All Curves.las 1/17/2019 Electronic File: MPU E-35 LWD Final MD.cgm 1/17/2019 Electronic File: MPU E-35 LWD Final TVD.cgm 1/17/2019 Electronic File: MPU E-35 Definitive survey Report.pdf 1/17/2019 Electronic File: MPU E-35—Definitive Survey Report.txt 1/17/2019 Electronic File: MPU E-35_GIS.txt 1/17/2019 Electronic File: MPU E-35 LWD Final MD.emf 1/17/2019 Electronic File: MPU E-35 LWD Final TVD.emf 1/17/2019 Electronic File: MPU E-35 Geosteering.dlis 1/17/2019 Electronic File: MPU E-35 Geosteering.ver 1117/2019 Electronic File: MPU E-35 LWD Final MD.pdf 1 /1 712 01 9 Electronic File: MPU E35 LWD Final TVD.pdf 1/17/2019 Electronic File: MPU E-35 LWD Final MD.tif 1/17/2019 Electronic File: MPU E-35 LWD Final TVD.tif 1 /1 712 01 9 Electronic File: EMFView3_l.zip 1/17/2019 Electronic File: Readme.txt 2181520 MILNE PT UN T E 3 OG I - 5 L HEADERS i Monday, April 15, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/15/2019 Permit to Drill 2181520 Well Name/No. MILNE PT UNIT E-35 MD 15000 Log C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C Well Cor Operator HILCORP ALASKA LLC API No. 50-029-23615-00-00 TVD 4362 Completion Date 12/28/2018 Completion Status 1 -OIL Current Status 1 -OIL UIC No 30261 Log Header Scans 0 0 2181520 MILNE PT UNIT E-35 P61 LOG HEADERS 30261 Digital Data 100 6954 1/17/2019 Electronic Data Set, Filename: MPU E-35 P131 DGR ABG EW R ADR.Ias 30261 Digital Data 6250 6904 1/17/2019 Electronic Data Set, Filename: MPU E-351`131 ADR Quadrants All Curves.las 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 PB1 LWD Final MD.cgm 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 PB1 LWD Final TVD.cgm 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 P131 Definitive survey Report.pdf 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 P131—Definitive Survey Report.txl 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 PB1_GIS.txt 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 PB1 LWD Final MD.emf 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 PB1 LWD Final TVD.emf 30261 Digital Data 1/17/2019 Electronic File: MPU E35PB1 Geosteering.dlis 30261 Digital Data 1/17/2019 Electronic File: MPU E-35PB1 Geosteering.ver 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 P131 LWD Final MD.pdf 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 P131 LWD Final TVD.pdf 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 PB1 LWD Final MD.tif 30261 Digital Data 1/17/2019 Electronic File: MPU E-35 P81 LWD Final TVD.tif 30261 Digital Data 1/17/2019 Electronic File: EMFView3_1.zip 30261 Digital Data 1/17/2019 Electronic File: Readme.txt /Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments AOGCC Pugc 2 of 3 Monday, April 15, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/15/2019 Permit to Drill 2181520 Well Name/No. MILNE PT UNIT E-35 Operator HILCORP ALASKA LLC MD 15000 TVD 4362 INFORMATION RECEIVED Completion Report Y Production Test Informati Y NA Geologic Markers/Tops Y COMPLIANCE HISTORY Completion Date: 12/28/2018 Release Date: 11/15/2018 Description Comments: Compliance API No. 50-029-23615-00-00 Completion Date 12/28/2018 Completion Status 1 -OIL Current Status 1 -OIL UIC No / Directional / Inclination Data /�Y ) Mud Logs, Image Files, Digital Data Y N�A Core Chips Y Mechanical Integrity Test Information Y //NA Composite Logs, Image, Data Files Sy Core Photographs Y / Daily Operations Summary YO Cuttings Samples Y CiFA Laboratory Analyses Y / A Date Comments Date: AOGCC Page 3 of 3 Monday, April 15, 2019 r ✓ STATE OF ALASKA ALA-- _ .OIL AND GAS CONSERVATION COMMIT. )N MAR 1 /t ^ n REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon LJ Plug Perforations LJ Fracture StimulatELJ Pull Tubing LJ Operations shutdown Ll Performed: Suspend ❑ Perforate ❑ Other Stimulat Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑-rforate New Pool ❑ Repair Well] Re-enter Susp Well ❑ Other: ESP Change -out ❑� 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska LLC Development ❑� Stratigraphic❑ Exploratory ❑ Service ❑ 218-152 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-23615-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL025518 / ADL047437 MPU E-35 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Field / Schrader Bluff Oil Pool 11. Present Well Condition Summary: Total Depth measured 15,000 feet Plugs measured 14,740 feet true vertical 4,362 feet Junk measured N/A feet Effective Depth measured 14,740 feet Packer measured 6,095 feet true vertical 4,377 feet true vertical 4,431 feet Casing Length Size MD TVD Burst Collapse Conductor 107' 20" 107' 107' N/A N/A Surface 6,277' 9-5/8" 6,277' 4,438' 5,750psi 3,090psi Production 6,095' 7-5/8" 6,095' 4,421' 6,890psi 4,790psi Drilled Liner 4,647' 6-5/8" 14,745' 4,377' N/A N/A 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-801 EUE 8rd 5,787' 4,395' Packers and SSSV (type, measured and true vertical depth) BOT SLZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 1 0 0 0 320 1 0 Subsequent to operation: 1 612 659 182 1 200 1 200 14. Attachments (required per 20AAc 25.070, 25.071, 8 25.283) 15. Well Class after work: Daily Report of Well Operations F±1 Exploratory❑ Development El Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Q Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-074 Authorized Name: Chad Helgeson Contact Name: Taylor Wellman^/ Authorized Title: Operations Manager Contact Email: twellman(cDhilcorp.com Authorized Signature: Dale: 3112/2019 Contact Phone: 777-8449 Form 10-0RBDMS I'�MAR 14 201904 Revised 4/2017 ##,q - Submit Original Only [ / n Hili Alaaka, LLC Orig. KB Bev.: 26.5'(1) M=15,00(r (MD) / TD=4,362'(1VD) PBTD=14,740'(NU) / PBTD=4,377'M) SCHEMATIC Milne Point Unit Well: MPUE-35 Last Completed: 3/6/2019 PTD: 218-152 TREE & WELLHEAD Tree 5K Cameron 2-9/16" Wellhead ii FMCGen5 CEMENT DETAIL 20" —270ft3 dumped down backside 9-5/8" Stg1L-425sx/T-397sx —550 sx / T —270 sz (271 bbls to surface) Stg 2 L_556 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor -/X-52/Welded N/A Surface 107' 9-5/8" Surface 40/L-80/TXP 8.835 Surface 6,277' 7-5/8" Tieback 29.7/ L-80 / Hyd 521 6.875 Surface 6,095' 6-5/8" PreDrilled Liner 20 / L-80 / Hyd 563 6.049 6,092' 14,745' TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.441 Surface 5,787' 3/8" Capstring Stainless Steel N/A li Surface 5,787' WELL INCLINATION DETAIL KOP @ 43' Max Hole Angle =94.5 deg. @ 7,954' JEWELRY DETAIL No Depth Item 1 159' Sta #3: GLM- 1" DPSOV BK Latch 2 219' Sta #2: GLM- 1" DPSOV BK Latch 3 4,898' Sta #1: GLM- 1" w/ Dummy 4 4,955' 2-7/8" XN-Nipple (2.205 No-go ID) 5 5,688' Discharge Head: CPDI527/8"EUE 6 5,688.5' Ported Discharge Head 7 5,689' Upper Pump: 134 STG FLEX 17.5 8 5,713' Middle Pump: 118 stage G12 9 5,733' Lower Pump: 24 stage Ginpshl 10 5,743' 1 538 Gas Separator: Dual 11 5,746' 1 512 Gas Avoider 12 5,751' Upper Tandem Seal: GSB3DBUT 58/SB PFSA 13 5,758' Lower Tandem Seal: GS83DBUT SB/SB PFSA 14 5,765' Motor: CL5 XP-200hp/ 3635V/ 34A 15 5,782' Sensor, Zenith S/S TB12629 16 5,785' Centralizer: Bottom @ 5,787' 17 6,095' BOT SLZXP Liner Top Pkrw/BD Slips, 7"x95/8" 18 6,114' Crossover Sub, 7"H563 x6.625"Hyd 563 19 14,709' 4-1/2" Drillable Packoff Sub 20 14,740' WIV Valve with 1" Ball on Seat 21 14,743' Round Nose Float Shoe: Bottom @ 14,745 6-5/8" PREDRILLED LINER DETAIL 6-5/8" Predrilled Liner, 78 holes/foot, 3/8" holes, 1x 6.625"x7.75" free floating cent/jnt GENERAL WELL INFO API: 50-029-23615-00-00 Drilled, Cased and Completed by Innovation -12/29/18 ESP SWAP by ASR#1 — 3/6/2019 Revised By: TDF 3/12/2019 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP E-35 ASR#1 50-029-23615-00-00 218-152 3/5/19 3/7/19 Daily Operations. 2/27/2019- Wednesday No activity to report. 2/28/2019 - Thursday No activity to report. 3/1/2019 - Friday No activity to report. 3/2/2019 -Saturday No activity to report. 3/3/2019 -Sunday No activity to report. 3/4/2019 - Monday No activity to report. 3/5/2019 -Tuesday MIRU ASR, electricians test and calibrate all fire and gas detectors. Prep to perform shell test and proceed with BOP test.. Start BOP Test - initial shell test test 250 low and 2,500psi high for good test. Notify State and Remainder of BOP Test to be witnessed by Adam Earle.. Continue BOP Testing and Testing of Fire and Gas alarms. Test 2-3/8" X 3-1/2" VBRs for 250psi low test and 2,500psi high for good Test. Continue Testing BOP'S and Choke / Kill Manifold as per Sundry. All tests preformed at 250psi low and 2,500psi high. Blow down, Pull BPV, BOLDS, Unland TBG 40K up wt. Lay down tbg hanger run ESP cable and single 3/8" Cap. line to Spooler. POOH w/2 7/8" 6.5# EUE 8round tbg with ESP. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP E-35 ASR#1 50-029-23615-00-00 218-152 3/5/19 3/7/19 Daily Operations. 3/6/2019 - Wednesday Continue POOH w/ 2-7/8" tubing and ESP assembly, found burnt motor lead on ESP. All ESP pump components checked out good. All motor oil was clear and seals all good. ESP pump layed down and S/I well at blinds pumping 15bbls 8.3 ppg lake water every 30 mins to well stagnant. Prep for new ESP gas separator to arrive. threw out total of 60 joints of 2-7/8" L-80 EUE tubing due to galled threads. Swap out spools on spooler unit w/ new control line cable and cap string. Decision made to swap out old tubing string for new. Swapped out tubulars on pipe rack with NEW tubing to RIH. Prep to P/U new ESP, tally tubulars, p/u new ESP motors and serviced/swapped fluids, new gas avoider part arrived. prep to RIH. Start assembling new ESP and RIH w/ ESP assembly on NEW 2-7/8" L-80 6.5# EUE tubing. RIH with 2-7/8" EUE L-80 6.5# w/ESP as per sundry. 3/7/2019 - Thursday Continue RIH w/ new ESP assembly on 2-7/8" L-80 6.5# EUE tubing, make hanger splice and test for good test. Land Hanger, Tighten Lock Down Screws, Install BPV, ESP Centralizer @ 5,786', XN Nipple @ 4,956', Lower GLM @ 4,905', Upper GLM #2 w/ DPSOV @ 216' and Upper GLM #1 @ 166'. Last down weight landing hanger 26K. No up weight due to RIH ESP. 3/8/2019 - Friday No activity to report. 3/9/2019 -Saturday No activity to report. 3/10/2019 -Sunday No activity to report. 3/11/2019 - Monday No activity to report. 3/12/2019 -Tuesday No activity to report. THE STATE ALASKA Chad Helgeson GOVERNOR MIKE DUNLEAVY Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU E-35 Permit to Drill Number: 218-152 Sundry Number: 319-074 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.claska.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, Daniel T. Seamount, Jr. Commissioner DATED this aday of February, 2019. ,,,, 3BDMS"U 05 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 2n AAC 95 9R0 rr....g...a C k; n V r".. FEB 15 2019 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Q Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Atter Casing ❑ Other: ESP Change -out Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 218-152 - 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23615-00-00 " 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No MPU E-35 9. Property Designation (Lease Number): r 10. Field/Pool(s): • ADL025518 / ADLO4743 I Milne Point Field / Schrader Bluff Oil Pool 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): • 15,000' 4,362' 14,740' 4,377' 1,006 14,740' N/A Casing Length Size MD TVD Burst Collapse Conductor 107' 20" 107' 107' N/A N/A Surface 6,277' 9-518" 6,277' 4,438' 5,750psi 3,090psi Production 6,095' 7-5/8" 6,095 4,421' 6,890psi 4,790psi Drilled Liner 4,647' 6-5/6' 114,745' 4,377' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 2-7/8" 6.5 ! L-80 ! EUE 3rd 5,790' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): BOT SLZXP LTP and N/A 6,095 MD/ 4,431 TVD 12. Attachments: Proposal Summary ❑✓ Wellbore schematic Q 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: 2/28/2019 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. Authorized Name: Chad Helgeson Contact Name: Taylor Wellman r Authorized Title: O erations Manager Contact Email: twellmaD hilcor .Com Contact Phone: 777-8449 Authorized Signature: Date: 2/1 512 01 9 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: /1 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No F31 Subsequent Form Required: I APPROVED BY f.�� Approved by: COMMISSIONER THE COMMIS te: /--fi" l /r'S-6oror\10403 Revised 4/2/ ORIGINAL ,— rmn u J (V)`J A Submit Form and Approved application is valid for 12 months from the date of approval. f9p achments t Duplicate liee✓ K Hileoep Alaska. LU ESP Change -Out Well: MPU E-35 Date:02/14/2019 Well Name: MPU E-35 API Number: 50-029-23615-00 Current Status: Shut in — ESP Down Pad: E -Pad Estimated Start Date: February 28, 2019 Rig: ASR Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218-152 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) AFE Number: Job Type: ESP Swap Current Bottom Hole Pressure: Maximum Expected BHP: MPSP: 1,446 psi @ 4,395' TVDss FL shot 2 days after SI — Feb '18/ 6.4 ppg EMW 1,446 psi @ 4,395' TVDss FL shot 2 days after SI — Feb'18 / 6.4 ppg EMW 1,006 psi (0.1psVft gradient back to surface) Brief Well Summary: MPU E-35 was drilled and completed as a Schrader Bluff OA producer in December 2018. The well has a —8,700' and horizontal section in the OA sands. The well encountered higher than expected GOR's in the toe of the well. When the well was brought online the GOR's ranged from 1000-2000 scf/bbl and total gas up to 1.Smmscfpd. The well ESP design in the well was not designed to handle this volume of gas. On 02/11/19 the downhole gauge lost signal and indications were the ESP cable was damaged. Over the course of the next 24 hrs the well ESP lost all lines and ability to function. Indications are there is a blown spot in the cable. Notes Regarding Wellbore Condition • The 7-5/8" casing passed an MIT -IA to 1,800psi on 12/28/2019 (during the original completion). • Indications from the failure are there is cable damage(began as phase to ground and progressed to lose all 3 lines to the ESP). Objective: Pull the failed ESP and run a new ESP completion. Pre -Rig Procedure: 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 8.5 ppg sea water down tubing, taking returns up casing to 500 bbl returns tank. 6. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. a. Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of the ASR. 7. RD Little Red Services and reverse out skid. 8. RU crane. Set BPV. ND Tree. NU BOPS. RD Crane. 9. NU BOPE house. Spot mud boat. Brief RWO Procedure: U Hilrnry Alaska, LG ESP Change -Out Well: MPU E-35 Date: 02/14/2019 10. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 11. Check for pressure and if 0 psi pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 8.5 ppg sea water prior to pulling BPV. Set TWC. 12. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 13. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure 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. 14. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ 8.5 ppg sea water as needed. 15. MU landing joint or spear and PU on the tubing hanger. a. The PU weight during the 2018 ESP running was 70K lbs / SOF = 54K lbs (Block weight= 35K r/ lbs). b. If needed, circulate (long or reverse) pill with lubricant and/or baraclean pill prior to laying down the tubing hanger. 16. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 17. POOH and lay down the 2-7/8" tubing. Inspect tubing and replace any joints that have thread damage. Lay down ESP. — a. Plan is to reuse the tubing that is pulled from the well. b. Note any sand or scale inside or on the outside of the ESP on the morning report. c. Look for over -torqued connections from previous tubing runs. d. The completion has the following amount of clamps/guards: i. 192 Cross Collar (Cannon) Clamps H ffil r A6akn, w ii. 3 Motor Clamps iii. 2 Pump Clamps ESP Change -Out Well: MPU E-35 Date: 02/14/2019 18. PU new ESP with single cap string and RIH on 2-7/8" tubing. Set base of ESP assembly at ± 5,780' MD. a. Upper GLM #3 @ ± 140' MD w/SO b. 1 joint of 2-7/8" tubing c. GLM #2 w/ DGLV d. 2-7/8" tubing e. Lower GLM #1 w/ DGLV f. 2 joints of 2-7/8" tubing g. 2-7/8" XN (2.205" No -Go) above ±4,975' md. a. This keeps the XN nipple wireline accessible. h. 2-7/8" tubing Downhole gauge for discharge temperature and pressure (connected with a jumper from the lower sensor. Does not require a separate tech wire). Base of ESP centralizer @ ± 5,780' MD a. Setting window for the ESP is between 5,650'— 5,775' md. This is to keep DLS for the setting of the ESP under 2°. b. ESP to have the following included into the design: i. 134 stage Flex 17.5 ii. 118 stage G-12 iii. 24 stage Ginpshl iv. 538 Gas Separator (dual gas se arators) v. 512 as avoider vi. Tandem seals vii. Motor c. Contact Ops Engineer or Baker Centrilift Engineer Jay Thompson 907-231-7395 for further discussion if needed. 19. Land tubing hanger. RILDS. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off) weights on tally. 20. Set BPV. Post -Rig Procedure: 21. RD mud boat. RD BOPE house. Move to next well location. 22. RU crane. NO BOPE. 23. NU existing 2-9/16" 5,000# tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 24. RD crane. Move 500 bbl returns tank and rig mats to next well location. 25. Replace gauge(s) if removed. 26. Turn well over to production. RU well house and flowlines. H Ililcura Alaska, LU Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Blank RWO MOC Form ESP Change -Out Well: MPU E-35 Date: 02/14/2019 n n.Hr LLC orifi KBElm-26 ewwwabon) To=15AW M /TD =4,36271%) PBTD=14,740'(MD) / PBFD=4,377TW SCHEMATIC Milne Point Unit Well: MPUE-35 Last Completed: 12-29-18 PTD: 218-152 TREE & WELLHEAD Tree 51(Cameron2-9/16" Wellhead FMCGenS CEMENT DETAIL 20" -270 ft3 dumped down backside Wt/Grade/Conn Stg1L-4255x/T-397sx Top Stg 2 L —550 sx / T— 270 sx (271 bbls to surface) CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor -/X-52/Welded N/A Surface 107' 9-5/8" Surface 40/L-NL2 8.835 Surface 6,277' 7-5/8" Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 6,095' 6-5/8" PreDrilled Liner 20/L-80/Hyd 563 6.049 6,092' 14,745' TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE8rd 2.441 Surface 5,790' 3/8" li Dual Capstring I SS N/A I Surface 5,790' WELL INCLINATION DETAIL KOP @ 43' Max Hole Angle = 94.5 JEWELRY DETAIL No Depth Item 1 159' Sta N2: GLM- 1" Side Pocket KBMM w/ Orifice 2 4,898' Sta p1: GLM- 1" w/ Dummy 3 4,975' 2-7/8"XN-Ni le(2.205 No-go ID) 4 5,701' Discharge Head: FPDIS 5 5,702' Upper Tandem Pump: 625TG FLEX 17.5 6 5,725' Lower Tandem Pump: 134 STG FLEX 17.5 7 5,749' Gas Separator: GRS FER N AR 8 5,754' Upper Tandem Seal: GSB3DBUT 58/SB PFSA 9 5,761' Lower Tandem Seal: GSB3DBUT SB/SB PFSA 30 5,768' Motor: CL5 XP— 200hp/ 3635V/ 34A 11 5,785' Sensor, Zenith S/S TB12629 12 5,788' Centralizer: Bottom @ 5,790' 13 6,095' BOT SLZXP Liner Top Pkr w/BD Slips, 7"x95/8" 14 6,114' Crossover Sub, T' H563 x 6.625" Hyd 563 15 14,709' 4-1/2" Drillable Packoff Sub 16 14,740' WIV Valve with 1" Ball on Seat 17 14,743' Round Nose Float Shoe: Bottom @ 14,745 6-5/8" PREDRILLED LINER DETAIL 6-5/8" Predrilled Liner, 78 holes/foot, 3/8" holes, Ix 6.625"x7.75" freefloating cent/int GENERAL WELL INFO API: 50-029-23615-00-00 Drilled, Cased and Completed by Innovation -12/29/18 Revised By: TDF 2/13/2019 0 cora Alaeka, LLC Orig, KB Elev.: 26.5'(Innovation) PROPOSED SCHEMATIC TD =15,000' (ND) / TD = 4,36Y(TVD) PBTD=14,74U'(MD) / PBT) =4,377(M) Milne Point Unit Well: MPUE-35 Last Completed: 12-29-18 PTD: 218-152 TREE & WELLHEAD Tree 5K Cameron 2-9/16" Wellhead FMC Gen 5 CEMENT DETAIL 20" -270 ft3 dumped down backside Wt/Grade/Conn Stg1L-425 sx/T-397 sx 95/8„ Stg 2 L - 550 sz / T- 270 sx (271 bbls to surface) CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor -/X-52/Welded N/A Surface 107' 9-5/8" Surface 40/L-80/TXP 8.835 Surface 6,277' 7-5/8" Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 6,095' 6-5/8" PreDrilled Liner 20 / L-80 / Hyd 563 6.049 6,092' 14,745' TUBING DETAIL 2-7/8" Tubing 6.5 / L-80/ EUE 8rd 2.441 Surface 5,790' 3/8" li Dual Capstring I SS N/A Surface 5,790' WELL INCLINATION DETAIL KOP @ 43' Max Hole Angle = 94.5 deg. @ 7,954' JEWELRY DETAIL No Depth Item 1 ±150' Sta 113: GLM -1" Side Pocket KBMM w/ Orifice 2 ±190' Sta q2: GLM- 1" Side Pocket KBMM w/ Orifice 3 ±4,898' Sta #1: GLM- 1" w/ Dummy 4 ±4,975' 2-7/8" XN-Nipple (2.205 No-go ID) 5 ± Discharge Head: FPDIS 6 ± Upper Pump: 134 STG FLEX 17.5 7 ± Middle Pump: 118 stage G12 8 ± Lower Pump: 24 stage Ginpshl 9 ± 538 Gas Separator: Dual 30 ± 512 Gas Avoider 11 ± Upper Tandem Seal: GSB3DBUTSB/SB PFSA 12 ± Lower Tandem Seal: GSB3DBUTS8/S8 PFSA 13 ± Motor: CL5 XP- 200hp/ 3635V/ 34A 14 ± Sensor, Zenith 5/S TB12629 15 ±5,780' Centralizer: Bottom @ 5,790' 16 6,095' BOT SLZXP Liner Top Pkr w/BD Slips, 7" x 9 5/8" 17 6,114' Crossover Sub, 7" H563 x 6.625" Hyd 563 18 14,709' 4-1/2" Drillable Packoff Sub 19 14,740' WIV Valve with 1" Ball on Seat 20 14,743' Round Nose Float Shoe: Bottom @ 14,745 6-5/8" PREDRILLED LINER DETAIL 6-5/8" Predrilled Liner, 78 holes/foot, 3/8" holes, 1x 6.625"x7.75" free Boating cent/jn[ GENERAL WELL INFO API: 50-029-23615-00-00 Drilled, Cased and Completed by Innovation -12/29/18 Revised By: TTW 2/15/2019 H namrr .AIxAa. LII: 11" BOVE Milne Point ASR Rig 1 BOPE 2019 Updated 1/05/2018 311 or Pipe Rams ind es HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: February 151h, 2019 Subject: Changes to Approved Sundry Procedure for Well MPU E-35 Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first calf' engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date HAK Procedure Change Prepared B Initials HAK Approved B Initials AOGCC Written Approval Received (Person and Date Approval: Prepared: Operations Manager Date Operations Engineer Date STATE OF ALASKA JAN Z 2019 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AN 1a. Well Status: Oil ❑✓ Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended LJ tb. Well Class: 20MC 25.i05 20aac 25110 Development Exploratory ❑ GINJ ❑ WINJ ❑ WAG[—] WDSPL ❑ No. of Completions: _ 1 Service ❑ Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 12/28/2018 218-152 ` 3. Address: 7. Date Spudded: 15. API Number: , 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 November 19, 2018 50-029-23615-00-00 4a. Location of Well (Governmental Section): Surface: 3594' FSL, 1720' FEL, Sec 25, T1 3N, R1 OE, UM, AK 8. Date TD Reached: December 4, 2018 16. Well Name and Number: ©A MPU E-35 P11114- 111""Top Topof Productive Interval: 9. Ref Elevations: KB: 48.7 ' 17. Field / Pool(s): Milne Point Field 593' FSL, 2537' FEL, Sec 24, T13N, R10E, UM, AK GL:21.7' BF:21.7' Schrader Bluff Oil Pool , Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 776' FNL, 40' FWL, Sec 23, T1 3N, R1 OE, UM, AK 14,740' MD / 4,377' TVD - ADL025518 / ADLO47437 ' 41b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 569426 y- 6016133 Zone- 4 15,000' MD / 4,362' TVD LONS 94-017 TPI: x- 568586 y- 6018404 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 560567 y- 6022244 Zone- 4 N/A 1,884' MD / 1,798' TVD ' 5. Directional or Inclination Survey: Yes ✓ (attached) No ❑ 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP/ABG/DGR/EWR/ADR 2"/5" MD / PBI ABG/DGR/EWR/ADR 2"/5" TVD / PB1 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH TVD SETTING DEPTH MD HOLE SIZE AMOUNT CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM 20" - X-52 Surface 107' Surface 107' 42" —270 ft3 Stg 1 L - 425 sx / T - 397 sx 9-5/8" 40# L-80 Surface 6,277' Surface 4,438' 12-1/4" Stg 2 L - 550 sx / T - 270 sx 271 bbls 7-5/8" 29.7# L-80 Surface 6,095' Surface 4,431' Tieback 6-5/8" 20# L-80 6,092' 14,745' 4,431' 4,377' 8-1/2" PreDrilled Liner 24. Open to production or injection? Yes ❑✓ No ❑ 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD/TVD) Size and Number; Date Perfd): 2-7/8" 5,790' 6,092' / 4,431' (LTPacker) 6-5/8" PreDrilled Liner, 78 holes/foot, 3/8" holes, run on 12/23/18 6,119'- 14,704' MD / 4,433' - 4,377' TVD 0 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. COMPLETION DATE Z12-�a VERIFIED Was hydraulic fracturing used during completion? Yes LJ No ✓ Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED �(2 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 1/8/2019 ESP Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 1/25/2019 24 Test Period 247 621 57 N/A 2514 Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 226 540 24 -Hour Rate __► 247 621 57 17.6 Form 10-407 Revised 5/201 c,0 L' -G1 - �Q CONTINUED ON PAGE 2 RBDMS ��JAN 'J) 0j 2619 Submit ORIGINIAL on] f r ok I 0.4%9. W10//4 6 28. CORE DATA Conventional Corals): Yes ❑ No Q Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑v If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 1,884' 1,798' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB OA 6,119' 4,433' information, including reports, per 20 AAC 25.071. SV5 1,792' 1,713' Sv1 2,683' -I-7, Z1j 1'(7 6, Ugnu LA3 4,241' 3,839' SB NA 5,160' 4,320' SB OA 6,078' 4,429' Formation at total depth: Scky4At v 864 O 4 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Survey, Csg and Cmt Report. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdin of hilcof .com Authorized Contact Phone: 777-8389 Signature:— Date: �. ZJr INSTRUCTIONS General: This form and the required attac nits provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only K Hfleorp Alaska, LI.0 Ong. KB Elev.: 26.5'()nnovation) TD=15,000 (MD) / TD = 4,36Y(TVD) PBTD=14,740'(MD) / PBTD= 4,377'WM) SCHEMATIC Milne Point Unit Well: MPUE-35 Last Completed: 12-29-18 PTD: 218-152 TREE & WELLHEAD Tree 5K Cameron 2-9/16" Wellhead FMC Gen5 CEMENT DETAIL 20" —270 113 dumped down backside Wt/Grade/Conn Stgi L-425 Ix /T —397 sx 95/8„ Stg 2 L — 550 sx / T— 270 sx (271 bbls to surface) CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor -/X-52/Welded N/A Surface 107' 9-5/8" Surface 40/L-80/TXP 8.835 Surface 6,277' 7-5/8" Tieback 29.7/L-80/Hyd 521 6.875 Surface 6,095' 6-5/8" PreDrilled Liner 20 / L-80 / Hyd 563 6.049 6,092' 14,745' TUBING DETAIL 2-7/8" Tubing 6.5 / L-80/ EUE 8rd 2.441 1 Surface 5,790' 3/8" Dual Capstring SS N/A I Surface 5,790' WELL INCLINATION DETAIL KOP @ 43' Max Hole Angle = 94.5 deg. @ 7,954' JEWELRY DETAIL No Depth Item 1 159' Sta M2: GLM- 1" Side Pocket KBMM w/ Orifice 2 4,898' Sta #1: GLM- 1" w/ Dummy 3 4,975' 2-7/8" XN-Nipple (2.205 No-go ID 4 5,701' Discharge Head: FPDIS 5 5,702' Upper Tandem Pump: 62 STG FLEX 17.5 6 5,725' Lower Tandem Pump: 134 STG FLEX 17.5 7 5,748' Gas Separator: GRS FER N AR 8 5,754' Upper Tandem Seal: GSB3DBUT SB/SB PFSA 9 5,761' Lower Tandem Seal: GSB3DBUTSB/S8 PFSA 30 5,768' Motor: CL5 XP —200hp / 3635V / 34A 11 5,784' Sensor, Zenith S/S TB12629 12 5,788' Centralizer: Bottom @ 5,790' 13 6,092' BOT SLZXP Liner Top Pkr w/BD Slips, 7" x 9 5/8" 14 6,114' Crossover Sub, 7" H563 x 6.625" Hyd 563 15 14,709' 4-1/2" Drillable Packoff Sub 16 14,740' WIV Valve with 1" Ball on Seat 17 14,745' Round Nose Float Shoe: GENERAL WELL INFO API: 50 -029 -23615 -00 - Drilled, Cased and Completed by Innovation -12/29/18 6-5/8" Predrilled Liner Detail 6-5/8" Predrilled Liner, 78 holes/foot, 3/8" holes, Ix 6.625"x7.75" free floating cent1jnt Edited By: CID 1/29/2019 n Well Name: MP E-35 Field: Milne Point County/State: , Alaska (LAT/LONG): ovation (RKB): 27.02 API #: Spud Date: 11/19/2018 Job Name: 1813043D MPE-35 Drilling Contractor Innovation APE #: APE $: Hilcorp Energy Company Composite Report . .... .. 11/17/2018 Rig down bridle lines. Spot cuttings box. Power up TDS and ID motor with drivehouse. Install brakes and inspection covers on, wire tire all bolts. Prime and paint pipe handling equipment. Clean out U-tube on gasbuster. C/O blower motor on boiler 2. commission shakers and centrifuges with NOV.;Rep. Torque upper and lower IBOP and saversub. Replace worn sproket bearings on drag chain. Bring MWD tools into shed. Inspect mud pit suction rubbers and tank inspection.;Change out fuel pump on Boiler 2. cont. priming, painting and assembling pipe handling equipment. Function test pipe shed equipment. Berm up cuttings box. Function test top drive. Install bails and bell guide on TD. Run hot water through pump pop-off. Change oil in mud pump #2. Check endplay;in quill shaft on TD -within spec. Install wash pipe. R/U rig tongs and install. Re -assembly hydraulic elevators install and test. Install 4" ball valves on conductor. 11/18/2018 Continue working on rig acceptance checklist. Warm up mud pump land change oil. Work on cleaning and re -plumbing pipe rack drainage. Change out Kill HCR 4 -way. Air up boots. Install derrick camera. fix flow box jet. N/U stack and diverter lines. Crane last piece of diverter in place.:Test diverter/annular_ _ system. AOGCC Austin McLeod witness. Knife open 5 sec, bag close 10 sec. Initial pressure 3000psi, final 1950psi, 200 psi recover 13 sec, full recover 46 sec. 6N2 at 2260 psi average. Test PVT, gas alarms, Flow paddle. Total length diverter = 177', closest Ignition 80'.;Continue working on rig acceptance checklist. Continue assembling pipe handling equipment. Start processing 5" drill pipe in shed.;Rig acceptance checklist. Ongoing housekeeping throughout rig. Assemble 5" manual elevators. Mobilize subs to rig floor. Continue working on pipe rack drainage plumbing. Test centrifuge feed pumps. Adjust and tighten cement line at pits/mezz interconnect. Install blind rams in stack. Rig up;hawk jaws on rig floor. Continue to process 5" drill pipe. Install drain hose on catch pan. Rig up cellar pump. Obtain RKB's. Perform walk around/hazard hunt and continue housekeeping. 11/19/2018 Complete rig acceptance checklist. Accepted rig @ 06:00 am.;PJSM, Complete thorough derrick inspection. Found derrick camera w/ out secondary restraint (installed secondary fall restraint). Inspected all traveling equipment and service loop (good).; PIU and rack back 129 stds NC50 dp (258 jts). Drift w/ 3.125". PIU and rack back 3 stds 5" HWDP.;UD mouse hole, Hawk jaw. Clean and clear rig floor. Rig up tongs sensor. Pressure up on mud line with air to check for leaks, pump through bleeder on floor and check for leaks; pop off on pump 1 leaking. Rebuild pop off.;Pre-Spud meeting with both crews.; PJSM. Pick up motor with 1.5° bend. WU 12-1/4" Kymem bit and RIH with one stand. Fill conductor and check for leaks. PT surface lines to 3000 psi - good.;RIH tag up at 106. Drill from 105' to 220' with 400gpm/500 psi, 40 rpms/1500 ft -lbs, WOB 4-5K, swap to drilling fluid at 11V with good formation over shakers, Consistently jet flowline with air/mud to keep clear. At 21V pickup off bottom and adjust tension in drag chain (slipping).;Note: At 20:54 hm rig and E -Pad blacked out. Swap to highline power reset fault on top drive. Back on bottom drilling at 21:24 hrs.;POOH from 220' to 31', pumping annular volume while pulling first stand out of hole.;PJSM. R/U Pollard E -Line sheave for gyro.;Sewice rig: trouble shoot leaks on spinners.; POOH and inspect bit -good. Pickup drift and rack back 5 stands of HWDP, 1 stand HWDP/Jam.;M/U remaining BHA to 12-1/4" Kymera bit and SperryDrill motor with 1.5° bend: DM collar, DGR, EWR-P4, PWD, HCIM collar, HOC collar, UBHO sub. upload MWD (sim Ops jet flowline with mud pumps through bleeder). Scribe and measure RFO MWD to Motor= 5.45/7.88=248.98'. Scribe and orientate UBHO.; Hauled 0 bbls Fluid to MPG&I total = 0 bbls Hauled 0 bbls fluid to B-50 total = 0 bole Hauled 0 bbls fluid to Milne B-50 total = 705 bbls Hauled 140 bbls H2O from L -Pad Lake total = 980 We Lost 0 bbls to formation total fluid lost = 0 bola 11/20/2016 Continue making up BHA, pick up non mag drill collars to 145'. RIH on HWDP and tag up at 176. Wash and ream from 178' to 220'400 gpm/1120 psi, 40 rpms/1100 ft-Ibs.;Drill 12-1/4" hole from 220' to 390' (170') AROP = 48 fph. Slide as needed to maintain WP09. WOB 5K, 450gpm/950 psi, 50 rpms/2000 ft- Ibs on bottom 1100ft-lbs off. PUW 55K, SOW 55K. Collect gyro surveys at 100', 196', and 225' until surveys clean up.;POOH 1 stand and pickup Jars. RIH to 390'.;Continue drilling from 390' to 1,146'MD (756') AROP = 116 fph. Slide as needed to maintain WP09. WOB 8-15K, 475gpm/1370 psi, 60 rpms/3600 ft- Ibs ECUs 9.7ppg with 8.8 ppg mud. PUW 76K, SOW 76K. Release Gyro at 800'.;Continue drilling from 1,146' to 1,843'MD (697') AROP = 116 fph. Sli as needed to maintain WP09. W0138 -15K. Increase flow to 550gpm/1790 psi for hole cleaning, 60 rpms/4500 ft -lbs on, 2000 ft -lbs off bottom. ECD's 10.4ppg with 9.1 ppg mud. PUW 90K, SOW 75K, ROTW 82K. Base of Permafrost 1884'.;Pump tandem low vis/high vis sweep at 1776'MD 15 bbls late 0% increase in cuttings.;Continue drilling from 1,843'to 2555'MD (712') AROP = 118 fph. Slide as needed to maintain WP09. W084 -6K. flow to 550gpm/1797 psi for hole cleaning, 60 rpms/5100 ft -lbs on, 4400 ft -lbs off bottom. ECUs 10.2ppg with 9.1 ppg mud. PUW 106K, SOW 88K, ROTW 96K. Max gas observed 494U.;Distance from WP09 = 5.22'; 5.22' Right.;Hauled 0 bbls Fluid to MPG&1 total = 0 bbls Hauled 0 bbls fluid to B-50 total = 0 bbls Hauled 840 bbls H2O from L -Pad lake total = 1820 bbls Lost 0 bbls to formation total fluid lost = 0 bbls 11/21/2018 Drill 12 1/4" Hole F/2555' to 3227'MD (672') AROP = 112 fph. Slide as needed to maintain WP09. WOB 5K. GPM 575/2030 PSI, 80 rp/6K Vies on, 6K ft -lbs off bottom. ECD's 10.2ppg with 9.1 ppg mud. PUW 122K, SOW 94K, ROTW 105K.;Max gas 1797'u at 2,840' and and 2,985' md, Pump sweep at 3220' back on time no increase. Started lowering Vis to 80-100 range @ 3500'.;Drill 12 1/4" Hole F/3227'to 3790'MD (563') AROP = 94 fph. Slide as needed to maintain WP09. WOB 14K. GPM 600/2300 PSI, 80 rp/9K ft -lbs on, 7K ft -lbs off bottom. ECD's 9.8 ppg with 9.1 ppg mud. PUW 135K, SOW 100K, ROTW 114K. Max Gas 1587u.;Drill 12 1/4" Hole F/3790' to 3989MO (190') AROP = 32 fph. Slide as needed to maintain WP09. WOB 8-16K. GPM 600/2300 PSI, 80 rp/9.6K ft -lbs on, 8.2K ft -lbs off bottom. ECD's 9.65 ppg with 8.9 ppg mud. PUW 143K, SOW 104K, ROTW 121K. Max Gas 539u.;Observe small coal with several larger pieces over the shakers and a couple slight packoffs while sliding. Pump tandem sweep at 3955', back on time, no increase in cuttings.;Drill 12 1/4" Hole F/3989to 4551'MD (571') AROP = 95 fph. Slide as needed to maintain WP09. WOB 5-15K. GPM 600/2200 PSI, 80 rp/10AK ft -lbs on, 8.7K ft- Ibs off bottom. ECD's 9.86 ppg with 9.0 ppg mud. PUW 150K, SOW 108K, ROTW 124K. Max Gas 1004u. Oil observed over shakers at 4350'.;Distance to WP09 1.46'; 0.42' High, 1.4' right.; Hauled 580 bbls Fluid to MP G&I total = 580 bbls Hauled 0 bels fluid to B-50 total = 0 bbls Hauled 1680 bbls H2O from L -Pad Lake total = 3500 bible Lost 0 bels to formation total fluid lost = 0 bbls 11/22/2018 Drill 12 1/4" Hole F/4551' to 4995'MD (444') AROP = 74 fph. Slide as needed to maintain WP09. WOB 9K. GPM 600/2150 PSI, 80 rpm/12K ft -lbs on, 9.4K ft Ibs off bottom. ECD's 9.76 ppg with 9.0 ppg mud. PUW 160K, SOW 102 K, ROTW 125K. Max Gas 615u.; Pump Sweep @ 4650, back 44 bbls late with no increase in cuttings.;Drill 12 1/4" Hole F/4995'to 5373'MD (378') AROP = 63 fph. Slide as needed to maintain WP09. WOB 16K. GPM 600/2390 PSI, 80 rp/13K ft-Ibs on, 9.1K ft -lbs off bottom. ECD's 9.91 ppg with 9.2 ppg mud. PUW 155K, SOW 98K, ROTW 120K. Max Gas 1024u. Pump sweep at 5114'.;Continue drilling from 5373' to 5689 (316) AROP = 53 fph. Slide as needed to maintain WP09. WOB 17K. GPM 600/2350 PSI, 60-80 rpm/14Kft-lbs on, 11.1 K ft-Ibs off bottom. ECD's 9.86 ppg with 9.2 ppg mud. PUW 152K, SOW 94K, ROTW 119K. Max Gas 1373u. Start tangent for ESP pump at 5484' with;minimal sliding to counteract inital 2° /100 right hand walk, and then build. Max Dogleg 2.43°/100' down to 5775'.;Continue drilling from 5689' to 6157' (468') AROP =78 fph. WOB 7-18K. GPM 600/2370 PSI, 80 rpm/14K ftlbs on, 11.91<ft-Ibs off bottom. ECD's 9.85 ppg with 9.2 ppg mud. PUW 153K, SOW 94K, ROTW 119K. Max Gas 709Xu. Start dropping angle at 5755' with formations coming in low and no fault crossed.;Obsewed OA sands at 6080'MD. Pump sweep at 5939' with no increase in cuttings.;Hauled 1160 bbls Fluid to MPG&I total = 1740 bbls Hauled 0 bbls fluid to B-50 total = 0 bbls Hauled 1820 bbls H2O from L -Pad Lake total = 5320 bbls Lost 0 bible to formation total fluid lost = 0 bible 11!2312018 Drill 12 1/4" Hole F1615T to 6282'MD (125') AROP = 62.5 fph. Sliding to build angle up to 93*. WOB 12-13K. GPM 600/2400 PSI, 80 rpm/14K ft -lbs on, 11.9ft-lbs off bottom. ECD's 9.91 ppg with 9.2 ppg mud. PUW 153K, SOW 94K, ROTW 119K. Max Gas 1097u. Obtain final survey.;BROOH from 6282' to 6003' 600gpm/2150 psi, 80rpms.; Pump tandem sweep, Io vis/high vis &wt no increase. Circulate hole clean at 600gpm/2110psi, 80rpms/10.5Kft-Ibs reciprocating pipe.;RIH from 6030' to 6282' with no issues, no fill on bottom.;BROOH from 6282'to 4301' at 600 gpm/1950psi, 80 rpms/11.4K. Slow speed to Y �L 5-15 fpm at 5490' (base of build) due to erratic torque with spikes up to 20Kft-Ibs. PUW 155K, SOW 103K, ROTW 125K.;Continue to BROOH from 4301' to 2220' at 10-25 fpm based on hole conditions (erratic torque). 600gpm/1680 psi, 80 rpms/5-8Kft-lbs. Observe hole unload at 2300', slow pulling speed and S allow to cleanup, mostly clay.;Circulate annular volume x 2 just below the permafrost while BROOH from 2220' to 2155' at 600 gpm/1630 psi, 80 rpms/4.5Kft- Ibs. Shakers relatively clean during second bottoms up.;Continue to BROOH from 2155' to 704' (HWDP) 6009pm/80rpms. Hole unloaded at 820' with mostly sand some clay. Circulate hole clean. PUW 72K, SOW 72K.;Projected survey at 6282': 4437'TVD, 93° Inc, 292" Az. Distance to WP09 = 10.86', 9.83' low, 4.62' Right.;Hauled 560 bbls Fluid to MPG&I total = 2300 bbls Hauled 0 bbls fluid to B-50 total = 0 bbls Hauled 1400 bbls H2O from L -Pad Lake total = 6720 bbls Lost 0 bible to formation total fluid lost = 0 bels 11/24/2018 Attempt to POOH on elevators from 704', observe overpull. Continue BROOH from 704' to 260' at 450 gpm/700 psi, 40-80 rpms with erratic torque from 2 -80 - lbs. Adjust pulling speed based on hole conditions 2-15fpm.; Rack back last two stands of HWDP. Blow down top drive. UD BHA: Flex collars, UBHO. Download tools. Continue to UD BHA. Unable to break out of TM collar due to gaulded threads. clean and clear rig floor. Rig down hawkjaw and 3' rig tongs. Bit Grade: 1-4-LT-T-X-1-BT-TD.;Rig up Volant CRT: remove sub extension from Volant (too long). Rig up bail extensions, elevators, and power tongs.;Make up Shoe track assembly and Baker lock. Check floats. Continue to RIH with 9-5/8" 40# L-80 TXP casing to 205'.;Continue to RIH with 9-5/8' 40# L-80 TXP casing from 205' to 830'. Set down at 830', attempt to work through. Unable to. Wash down from 83U staging pumps up to 7 bpm/135 psi. Was able to RIH without pumps from 95U to 1030' set down. Continue to wash down to 1075'. Circulate annular;volume x2 while working joint clean.;Change out lube oil pump while pumping 3 bpm/80 psi. Drain oil and remove pump. Reciprocate pipe. Re -install pump and fill with oil; leaking oil between reservoir and pump. Reciprocate pipe again at 7 bpm. Build gasket, drain oil. Observe seepage losses 5 bph.;Attempt to wash 9-5/8" casing down from 1075' at 7 bpm/130 psi, tight. establish rotary and wash and ream casing at 5 -10 rpms/4K-5K ft -lbs from 1075' to 1308'.;Hauled 515 bbls Fluid to MP G&I total = 2815 bbis Hauled 0 bbls fluid to 8-50 total = 0 bbls Hauled 840 bels H2O from L -Pad Lake total = 7560 bels Lost 0 bels to formation total fluid lost = 0 bels 11/25/2018 Continue RIH Washing/Reaming 9 5/8" 40# L-80 TXP Csq-down f/1308' to 1509, w/5 bpm/130 psi, 5-10 rpm/4-9K Tq'. Wash down no rotation t/2100'@5 bpm/130 psi, PUW 115K, SOW 85K. ;. UD 2 bad Jts 36 & 37.;CBU 200' below base of Permfrost w/7 bpm/160 psi, 8 rpm/7-8k Tq, PUW 115K, SOW 85K, Rot 95K.;Continue to wash casing down from 2100' to 2450'. w/5 bpm/130 psi. PUW 125K, SOW 90K, Rot 95K. Started to see 140 psi pump pressure increase 270 psi while breaking circulation.;Work Pipe and CBU x2 from 2450' staging pump to 7.5 bpm/190 psi FCP. Slow rate to 5 bpm and observe previous 150 psi pump pressure.;Continue to wash casing down from 2450' to 312T. w/5 bpm/150 psi, PUW 150K, SOW 106K. No Issues washing down .;Continue to wash casing down from 3127' to 3580', w/5 bpm/165 psi, PUW 170K, SOW 104K. No Issues washing down . Observe swivel leaking attempt to grease, still leaking. Seepage losses at 5 bph.;Circulate annular volume staging pumps up to 7 bpm in upstroke / 190 psi, reciprocating pipe.;Change out cement swivel above Volant tool.;Continue to wash casing down from 3580' to 4046'. w/5 bpm/165 psi. Pickup ES Cementer between joints in hole 97 & 98 and Bakerl-ok, install centralizers 5 joints below and 10 joints above. PUW 200K, SOW 115K. Observe pump pressure up to 350psi while breaking circulation.;Circulate annular volume x 2 while reciprocating pipe. Staging up to 7 bpm in upstroke. ICP 280 psi FCP 200.;Continue to wash casing down from 4046' to 4610'. w/5 bpm/210 psi. PUW 225K, SOW 117K. Observe pump pressure breaking over at 350-400 psi while breaking circulation. Seepage losses at 5 bph.;Circulate and condition 1.5 x annular volume, staging pumps up to 8 bpm/250 psi.;Continue to wash casing down from 4610' to 4735' at 5bpm/210 psi. PUW 240K, SOW 105K working pipe as needed.;Hauled 515 bbls Fluid to MPG&I total = 2815 bbls Hauled 0 bbls fluid to B-50 total = 0 bbls Hauled 420 bbls H2O from L -Pad Lake total = 7980 bbls Lost 65 bbis to formation total fluid lost = 82 bbls 11/26/2018 j( S/ Continue to wash casing down f/4735' to 5405 w/5 bpm/225 psi, P/U 255K, S/O 115K.;CBU, staging pump to 7.5 bpm/275 psi. Work pipe 20'-40'. P/U 255K, S/O 115K.;Continue to wash casing down f/5403' to 6277" w/4 bpm/250 psi, P/U 262K, S/O 110K.;Circulate and condition mud lowering VP to 18, MW, 9.3, Vis 55. Recip pipe 20', P/U 254K, S/O 110K. Cannot move pipe without circulation. Off load excess mud from pits and prep pits for Cement job. R/D Weatherford tongs & bail extensions. R/U 3" water line to cementem.;Shut down pumps, blow down Top Drive. R/U swing, low Tq Valve & Cmt Hose to CMT Swivel/Volant Tool. Blow air to cementer via cement line. Bring on pumps and circulate through cmt line 6bpm/540 psi, P/U 260K, S/O 102K. Hold PJSM on Cement Job.;Circulate through cement line while W/O HES to batch Spacer.; PJSM, 1 stg surface cmt: Clear cmt line to cmt unit. Flood lines w/ 5 bbls water. P/T lines 1000/4000 psi (good). 60 bbls 10# Tuned Spacer III at 3.4 bpm/280 psi w/ 4# red dye first 10 bbls. Drop bypass plug.;Mix and pump 425 sxs, (180 bbls) Extenda Cam Lead Cement at 12 ppg at 5.5 bpm/460 psi. Mix and pump 397 sxs (82 bbls) Hal CemTail Cement at 15.8 ppg at 4.5 bpm/840 psi. Drop Shut off Plug.;Displace cmt w/ 20 bbls FW f/ Cmt Unit. Rig Pump 222 bbls 9.3 ppg mud 7bpm/470psi, Cmt Unit 80 bbls FW @ 5 bpm/700psi, Rig pump 146.7 bbls (2bbls over calculated) 9.3 ppg mud, 5 bpm ICP 563 psi, FCP 940 psi @ 3 bpm last 20 bbls. Pressure up to 1463 psi and hold for five minutes. Check floats -;Good, 3 bbls bled back. Lost 6 bbls throughout job CIP at 22:05. Reciprocated pipe until 107 bola left in displacement where hole started to get sticky. Park on depth intension. PUW 245K, SOW 85K.;Using rig pump, stage pressure up 2280 psi to inflate packer as per Halliburton, hold for 5 five minutes and observe 20 psi drop. Pressure up to 2380 psi and observe tool shear open.;CBU x3 at 5 bpm/410 psi, observe 30 blots of clean spacer after first bottoms up no increase of pH. Observe clobbered contaminated mud with 10.4pH at second bottoms up. No cement. Treat mud. Shutdown and breakout of Volant tool and rinse off. Flush stack with black water. Continue to circulate;hole at 3 bpm/220 psi. Thick clobbered up mud continues to comeback in waves oftentimes packing off the flow line. Clear flow line and treat mud.;Continue to circulate while prepping for second stage cement job. Lower volume in pits, super suckers hauling contaminated mud in convoys due to Phase II weather conditions. Build more black water. Continue treating thick mud as it returns. 11/27/2018 Continue to circulate through stage tool @ 3 bpm 1100 psi while prepping for 2nd stage Cement.;PJSM, Pump 2nd stage cmt iob Lineup to cmtrs, wet lines w/ 5 blols FW. 60 bbls 10.5# Tuned Spacer III w/ 4# red dye first 10 bbls, 5 BPM, 415 psi.;414 bbls 10.7# lead Perm "L" cmt, 4.33 yld, 416 sxs, 5.5 BPM, 730 psi, 56 bbls 15.8# tail Premium "G" cmt, 1.169 yld, 270 sxs, 4 BPM, 4285psi. Drop closing plug. HES pump 20 bbls FW, 7 bpm, 488 psi.;Tumover to rig. Disp & bump @ 164 bbls/ 2610 stks (164.1 bols calc) 9.3# mud 6 BPM, 960 psi. Slowed last 15 bbls, 3 bpm, 700FCP. Bumped and psi up to 1800 psi (ES �✓�/// shift @ 1350 psi)Held 5 min. Bled back 1 bbls, flow stopped. CIP @ 11:30 hrs. 100% returns.;See green Cmt 0 surface 383 bbls into Lead. Pumped 414 bbls Lead before going into tail. Over board 271 bbls cement.;Flush cement lines and stack with black water. Function Annular several times. Blow down cement service line to unit. R/D Weatherford casing CRT. RD cement lines and clear same. LD CRT to cradle.;RD outer sub diverter sections. RD diverter tube from knife valve. 4 bolt bottom of diverter "T". Clean out cellar box. Vac out casing joint (landing joint). RU stack trolly's. Raised BOP stack off conductor, PU to 100K on jnt. Wellhead Reps installed slips, centered joint in wellhead,;SO setting casing with t00K on slips. (Made rough cut on casing and LD same. Cut off jnt = 28.38') Re-set stack on conductor, MU stack wash tool on TDS. Flush stack and wellhead with black water. RD wash tool and blow down TDS.;PJSM Bleed down Koomey and remove Knife Valve. Stage Diverter line in cellar and hot bolt all flanges. Pull starter head W/ Stack. Set back Stack on stump. Remove Diverter Tee and Starter Head. SIMOPS Clean Pits, remove Diverter section W/ Crane and load 5" D.P. in Pipe Shed.;Make final cut and dress 9 5/8" Csg. Set lower Csg. Head Assy. Lower slip studs contacted 9 5/8" Csg. slips making Head Assy 3/4" from landing. Cut 1" off lower studs and land Head. Tested inner O-Ring Seal to 2,476 PSI for 15 Min witnessed by DSM.;Stage BOPE over well and attempt to lower. ODS Bridge Crane was not functioning properly. R/U SOPE pick up slings from Top Drive to BOPE. Pick up HOPE and release Bridge Cranes. Lower BOPE W/ Top Drive. N/U ROPE SIMOPS Cont. Cleaning Pits and loading 5" D.P. in Pipe Shed. 11/28/2018 Finish tightening bolts on ROPE. Install riser, air boots, Choke and Kill line, Choke and Kill HCR. Grease Choke Manifold, HCR's and manuals. Check Upper and Lower Rams. Install 1502 flange on OA. SIMOPS Take on new 8.9 ppg Baradrill N mud to Pits. R/U Hawk Jaw and install Hydraulic Elevators.;M/U 1502 pump in sub, TIW and Dart Valve to 5" Test Jnt. M/U Test Jnt to test plug. Flood lines and work air out of system. Perform shell test to 3,000 PSI.;Perform BOP test. Test W/ 5" and 3.5" Test Jnt to 250 PSI low and 3,000 PSI high for 5 Min all charted. Test Choke Manifold valves 1-15, Me= Kill, 5" Dart and TIW, Upper nad Lower IBOP, Kill & Choke HCR, Manual Choke & Kill, Upper, Lower and Blind Rams, Super Choke and Manual Choke.;Average 6 bottles Nitrogen 2,308 PSI. Perform Koomey draw down 200 PSI increase 200 PSI, Full charge 99 Sec. Witnessed waived by AOGCC Rep Jeff Jones.;R/D test Equip. Blow down all lines. M/U 5" D.P. to test joint to check torque on IDS 350. Install Rotary Table lock pressure regulator.;Pull test plug and UD. Set Wear Ring ID 9". UD 5" Test Jnt and clear rig floor.;PJSM P/U M/U 8.5" Clean out BHA #2 as per Halliburton Rep. M/U 8.5" Smith Tri Cone, 6 3/4" SperryDrill Lobe 6/70 6.0 Stg, 6 Jnts 5" HWDP, 6 1/4" Combo Jars, 11 Jnts 5" HWDP. 588' MD. Cont to single in hole 5" D.P. NC50 19.5# F/ 588' to 2,400' MD. Filling D.P. every 2,009.;Tagged up 10K at 2,400' MD. Obtain parameters 300 GPM, 450 PSI, 15 RPM, TRQ 4.8K, Drill up cement F/ 2,400' to 2,425' MD. Drill ES Cementer plug F/ 2,425'to 2,427' MD. Work through multiple times W/ and with pumps. P/U 103K, SLK 83K, ROT 92K.;Cont. single in hole 5" D.P. from Pipe Shed F/ 2,427' to 6,048' MD. Filling every 2,000'.;Tagged Cement stringer. Wash and ream F/ 6,048' to 6,138' MD Pump at 450 GPM, 945 PSI, 25 RPM, TRQ 13.5K.;CBU 1.5X. Stage up pumps to 550 GPM, 1,345 PSI, 25 RPM, TRQ 13.5K. Working clobbered mud at shakers breaking over mud.;Daily Fluid Hauled to G&I: 285 bbls Total Fluid Hauled to G&I: 4,588 bbls Daily Fluid Hauled to B-50: 0 Total Fluid Hauled to B-50: 0;Daily H2O From L-Pad Lake: 240 bbls Total H2O From L-Pad Lake: 9,740 bbls Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 Daily Lost To Formation: 0 bbls Total Lost To Formation: 151 bbls 11/29/2018 Cont. Circ. until cleaned up. 450 GPM, 1,200 PSI, ROT WT 122K. Blow down Top Drive.; R/U to test 9 518" Csg. Test 9 5/8" Cso to 2,Z PGI f - M'n nn _ chart. Bleed off Press. and RID test Equip.;Drill out Shoe Track, Baffle, Float Collar and Shoe F/ 6,139' to 6,282' MD. 450 GPM, 1,080 PSI, 50 RPM, TRQ 13K, WOB 5-8K, ROT WT 123K.; Drill 20' of new hole F/ 6,282'to 6,302' MD. 550 GPM, 1,300 PSI, 40 RPM, TRQ 13K, WOB 10K, ROT WT 125K.;Displace W/ 35 bbls Hi Vis Spacer and 434 bbis 8.9 ppg BamDrill Nat 550 GPM, 1,180 PSI, 40 RPM, TRQ 12K, ROT WT 122K.;Blow down Top Drive. R/U test Equip. flood lines. Perform FIT 12 ppg EMW to 715 PSI W/ 8.9 ppg Mud recorded on chart, Pumped 1.6 bbis and bled back 0.6 bbls.;10.0 ppg 20 bbis Pump Dry Job and POOH F/ 6,302' to 588' MD.;UD 5" HWDP, rack back Jars and UD BHA #2 F/ 588'. Bit Grade 1-1-WT-A-E-1-NO-BHA.;Clean and clear rig floor. P/U & stage BHA #3 components on rig floor.;PJSM W/ all essential personnel. Makeup BHA #3 as per Halliburton Reps. P/U M/U 8.5" SK616-J1 D Bit, 8.5" NOV NRP, Geo -Pilot 7600, 6 3/4" DGR, 6 3/4" PWD, 8 3/8" ILS, 6 3/4" ADR, 6 3/4" HCIM, 6 314" DM, 6 3/4" TM, 6 314" Flot Sub, 3 ea NM Flex Collars, 5" HWDP, Jars and 5" HWDP to 267' MD.;PJSM RIH W/ BHA #3 W/ 5" D.P. NC -50 19.5# F/ 267' to 6,132' MD. Shallow hole tested tools at 333' MD. Filling D.P. every 2,500'.;Slip and cut drilling line'. Monitor well Circ. from Trip Tank, static. Repair spooler motor to spool key way.;Daily Fluid Hauled to G&I: 391 bbls Total Fluid Hauled to G&I: 4,979 bola Daily Fluid Hauled to B-50: 0 Total Fluid Hauled to B-50: 0: Daily H2O From L -Pad Lake: 660 bbis Total H2O From L -Pad Lake: 10,400 bbis Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 Daily Lost To Formation: 0 bbis Total Lost To Formation: 151 bbis 11/30/2018 Finish Slip and cut Drill Line. Unhang and Calibrate Blocks.;Wash and Ream f/6200'to 6302', Log Down.;Drill 8.5"" Hole F/6302'to 6700'MD (398') AROP = 79.6 FPH. 500 gpm/1485 psi, 100 rpm/14K Tq, 10-15 WOB, PU 158K, SO 73K, Rot 112K, ECD 10.0 Max Gas 1,866U.;Drill 8.5"" Hole F/6700' to 6,953'MD (253') AROP = 42' FPH. 500 gpm/1485 psi, 100 rpm/14K Tq, 10-15 WOB, PU 158K, SO 73K, Rot 112K, ECD 10.0. Pump Tandem Sweep 25 bbl Low Vis, 25 bbl 240 Vis, 10.3 ppg high Vis, IGO% increase at Shakers of Clay.: Drilled ahead in OA -2 and came up to OA -1 at 6.380' MD. Crossed unexpected fault at C,,4411'1111 holdin 93.5° was unable to find OA Sand. Came within 12' of E-33 trying to find OA Sand from previous logs. Was unable to find OA Sand. At 6,954' MD decision was made to perform open hole side track.;CBU rotating and reciprocating F/ 6,953'to 6,893' MD. 550 GPM, 1,745 PSI, 120 RPM, 15K TRQ, ECD 9.9 ppg, P/U 160K, SLK 72K, ROT 112K. Minimal increase at Shakers. Gas 218U. Monitor well, static.;POOH on elevators F/ 6,953' to 6,380' MD. Encountered 15K over pull at 6,448' MD right at the fault. Kelly up, ream through tight spot with no indication.;Side track 8.5" hole F/ 6 380' to 6 400' Set parameters 450 GPM, 1,200 PSI, 110 RPM, TRQ 12.3K, WOB 1 K. Hold 80% deflection at 93.04'. Work trough 3X to 91.3 at 20at 20 fl/h ew Q hole at 6,400'at 20' fUhr, at 6,410' to 6,432' MD increase to 100' ft/hr holding 91° W/ WOB 4K.;Work through old well bore to new well bore 2X and tagged up at 6,432' MD.;Drill ahead 8.5" Hole F/6,432' to 7,269; MD. 837' total (98' AROP) 550 GPM, 1,780 PSI. 120-130 RPM, 14-16kK TRQ, 15K WOB, P/U 174K, SLK 60K, ROT 112K. ECD 10.24 ppg Max Gas 3,094U, MW 9.1 ppg. Increase Mud weight F/ 9.0 to 9.1 ppg due to 3,000+ U Gas at 6,640' MD.;At 6,775' MD Pumped Tandem Sweep 25 bbl Low Vis, 25 bbl 240 Vis, 10.3 ppg high Vis, 100% increase at Shakers of Clay. Crossed Fault at 7,028' MD came out below OA Sand. Was holding 89° increasing to 93° to re enter OA -3 Sand ensuring not to exceed 3° dogleg.; Encountered concretions at 6,970' -6,912' and 6,978' - 6,988' MD. Running both Centrifuges and water at 15 bph to control solids.;SPR @ 6,894' MD (4,442' TVD) MW 9.0 ppg MP #1 32-202 PSI, 48-260 PSI MP #2 32-200 PSI, 48-258 PSI.;Daily Fluid Hauled to G&I: 171 bbis Total Fluid Hauled to G&I: 5,150 bbis Daily Fluid Hauled to B-50: 0 Total Fluid Hauled to B-50: 0; Daily H2O From L -Pad Lake. 130 bbis Total H2O From L -Pad Lake: 10530 bbls Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 Daily Lost To Formation: 0 bbis Total Lost To Formation: 151 bbis 12/1/2018 Drill ahead 8.5" Hole F/7269' to 8030' MD. 761' total (126AROP) 550 GPM, 1,880 PSI. 120-130 RPM, 16-17K TRQ, 6-12K WOB, P/U 170K, SLK 57K, ROT 110K. ECD 10.5 ppg Max Gas 272UT MVV7.7 ppg. We have been in pay since we crossed the fault back at 7,028' md.;Drill ahead 8.5" Hole F/8039to 8656' MD. 626 total (156.5' AROP) 550 GPM, 1,950 PSI. 100-120 RPM, 16-17K TRQ, 6-10K WOB, P/U 175K, ROT 109K. ECD 10.8 ppg Max Gas 2,024U , MW 9.2 ppg. Lost slack off Wt @ 8470'.; Pup Tandem Sweep due to ECD increase to 10.8+, Rot/Recip Pipe while circulating @ 550 gpm/1850 psi. Hole unloaded 300% @ BUS and very little change after sweep.;Drill ahead 8.5" Hole F/8656' to 8784' MD. 128' total (128' AROP). 550 GPM, 1,900 PSI. 100-120 RPM, 16- 17K TRQ, 6-10K WOB, P/U 175K, ROT 109K. ECD 10.8 ppg Max Gas1,951 U , MW 9.2 ppg.;SPR @ 8,780' (4,368' TVD) W/ 9.2 ppg MW MP #1 32-263 PSI, 48- 330 PSI MP #2 32-266 PSI, 48-332 PSI.;Drill ahead 8.5" Hole F/8,784' to 9,516' MD. 732' total (122' AROP) 550 GPM, 1,970 PSI. 100-120 RPM, 18- 20K TRQ, 10-20K WOB, P/U 175K, ROT 112K. ECD 10.7 ppg Max Gas 2,212U , MW 9.3 ppg. Running both Centrifuges and water at 20 bph.;CBU At 9,350' MD to clean up the hole. and control ECD's. At -4,200 and BV increase at Shakers 300% of slight Clay and mostly Sand. SPR @ 9,354' (4,380' TVD) W/ 9.2 ppg MW MP #132-242 PSI, 48- 310 PSI MP #2 32-248 PSI, 48-314 PSI.;DnIl ahead 8.5" Hole F/9,516' to 10,109' MD. 593' total (98' AROP) 550 GPM, 2,014 PSI. 100-120 RPM, 20-21 K TRQ, 7-10K WOB, P/U 191K, ROT 112K. ECD 10.8 ppg Max Gas 2,271 U , MW 9.2 ppg CBU @ 10,109' MD for hole cleaning.;SPR @ 10,045' (4,369' TVD) W/ 9.2 ppg MW MP #1 32-285 PSI, 48- 355 PSI MP #2 32-292 PSI, 48-351 PSI.;At 9,516' MD started addition of 0.5% Baralube to reduce TRQ. 4 faults were crossed so far this lateral (2 in the last 24hrs). 11 concretions have been drilled so far this lateral for a total footage of 80' (2.1%).;Daily Fluid Hauled to G&I: 570 bbis Total Fluid Hauled to G&I: 5,720 bbls Daily Fluid Hauled to 8-50: 0 Total Fluid Hauled to 8-50: 0 Metal from well: 3lb.; Daily H2O From L -Pad Lake: 650 bbis Total H2O From L -Pad Lake: 11,180 bbis Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 Daily Lost To Formation: 0 bbis Total Lost To Formation: 151 bbis 12/2/2018 Cont. CBU at 10,109' MD 550 GPM, 1,985 PSI, 80 RPM, TRQ 21K, P/U 200K, ROT 109K. Increase 300% of slight Clay and Sand at Shakers.;Drill ahead 8.5" Hole F110,109'to 10,849' MD. 740'total (135' AROP) 550 GPM, 2,225 PSI. 100-120 RPM, 19.4K TRQ, 12K WOB, P/U 158K, SLK 39K, ROT 106K. ECD 11.3 ppg Max Gas 2,262U , MW 9.25 ppg Pump Tandem Sweep @ 10,743' MD increase of 100% at BU, sweeps back 10 bbl late as calculated.;lncrease Lubes to 2% due to down hole torque.;SPR @ 10,550' MD ( 4,362' TVD) MW 9.25 ppg MP #132-330 PSI, 48-390 PSI MP #2 32-330 PSI, 48-390 PSI.;Drill ahead 8.5" Hole F/10,849' to 11,609' MD. 760' total (127' AROP). 550 GPM, 2,210 PSI. 100-120 RPM, 19.51K TRQ, 6-8K WOB, P/U 165K, SLK 35K, ROT 106K. ECD 11.3 ppg Max Gas 1,926U , MW 9.3 ppg.;SPR @ 11,300' MD ( 4,386' TVD) MW 9.3 ppg MP #1 32-330 PSI, 48-400 PSI MP #2 32-330 PSI, 48- 400 PSI.;Drill ahead 8.5" Hole F/11,609' to 12,254' MD. 645' total (108' AROP) 550 GPM, 2,210 PSI, 120 RPM, 19.5K TRQ, 6-81K WOB, P/U 165K, SLK 35K, ROT 106K. ECD 11.3 ppg Max Gas 2,242U , MW 9.3 ppg.;At 11,850' MD Pumped Tandem W/ Lube Sweeps 25 bbl low and 25 bbl 10.2 ppg 280 Vis High. 50% increase in cuttings and returned as calculated. At 12,254'to 12,450' MD Control drill at 100' R(hr for close approach to C-41.;SPR @ 12,131' MD 4,376' TVD) MW 9.3 ppg MP #1 32-333 PSI, 48-403 PSI MP #2 32-337 PSI, 48-407 PSI.;DnII ahead 8.5" Hole F/12,254'to 12,888' MD. 634' total (106' AROP) 550 GPM, 2,294 PSI. 100-120 RPM, 21-23K TRQ, 6-8K WOB, P/U 165K. SLK 35K, ROT 106K. ECD 11.1 ppg Max Gas 2,125U , MW 9.3 ppg About every 500' control drill at 100 ft/hr to CBU for hole cleaning.;Vary drilling parameters for hole cleaning and concretions while drilling. ( RPM, Wt Bit, ROP) 5 faults were crossed so far this lateral. 27 concretions have been drilled so far this lateral for a total footage of 187' (2.9%). Running water at 20 bph and both Centrifuges.;Daily Fluid Hauled to G&I: 684 bbis Total Fluid Hauled to G&I: 6,404 bbls Daily Fluid Hauled to 8-50: 0 Total Fluid Hauled to B-50: 0 Metal from well: 3lb.:Daily H2O From L -Pad Lake: 910 bbls Total H2O From L -Pad Lake: 12,090 bible Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 Daily Lost To Formation: 0 bbis Total Lost To Formation: 151 bbis 12/3/2018 Drill ahead 8.5" Hole F/12,888' to 13,375' MD. 487' total (88.5' AROP) 550 GPM, 2,340 PSI, 100-120 RPM, 23.5K TRQ, 6-10K WOB, P/U 175K, SLK 35K, ROT 105K. ECD 11.1 ppg, Max Gas 2,785U , MW 9.3 ppg Control drill f/12889'-12957'@ 100 fph for hole cleaning.;Wash Pipe Leaking. Rack Back stand from 13,375 to 13,329. Blow down Top Drive, R/U Head Pin and circulate well @ 170 GPM/485. C/O Wash Pipe. Monitor well, well taking about 8 bph. Increased Bare Carb to 10 ppb.;Drill ahead 8.5" Hole F/13,375" to 13,960' MD. 585' total (106' AROP) 550 GPM, 2,350 PSI. 120-135 RPM, 22.51K TRQ, 10K WOB, P/U 182K, SLK 35K, ROT 102K. ECD 11.2 ppg, Max Gas 2,6000 , MW 9.3 ppg 13331-13394'@ 75 fph, 13899-13962'@ 75 fph, for hole cleaning.;Drill ahead 8.5" Hole F/13,960" to 14,445' MD. 485'total (80' AROP) 550 GPM, 2,300 PSI. 120 RPM, 22.5K TRQ, 5-10K WOB, P/U 192K, SLK 35K, ROT 101 K. ECD 11.2 ppg, Max Gas 55000 , MW 9.3 ppg.;Al 14,350' MD Gas units increased to S,OOO+U, Mud weight was increased to 9.4 ppg W/ BaraCarb . Increased Lube additions to 4% due to drilling torque.;Ddil ahead 8.5" Hole F/14,445" to 14913' MD. 468' total (' 78 AROP) 550 GPM, 2,300 PSI. 120 RPM, 22.SK TRQ, 5-10K WOB, P/U 192K, SLK 35K, ROT 101K. ECD 11.2 ppg, Max Gas 4950U , MW 9.4 ppg.;Cont, running both Centrifuges and water at 20 bph. 5 faults were crossed so far this lateral. 40 concretions have been drilled so far this lateral for a total footage of 317' (3.8%).: Daily Fluid Hauled to G&I: 684 bbis Total Fluid Hauled to G&I: 7,088 bible Daily Fluid Hauled to B-50: 0 Total Fluid Hauled to B-50: 0 Metal from well: 3lb.;Daily H2O From L -Pad Lake: 780 bbls Total H2O From L -Pad Lake: 12,870 bbis Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 IT�tgl Daily Lost To Formation: 104 bbls I o,t To Formation 255 bbls 12/4/2018 Drlg 8.5" hole F/ 14,909 - T/ 15,000' MD / 4362' TVD TD in lateral. 550 gpm, 2430 psi, 150 rpm, 28k tq, 60% flow, 196k Up, No down, 103k Rot. ECD = 11.3 w/ 9.4 MW. Obtain final survey. 29.5' from plan, 8.2' low & 28.34' right projected at 15,009.;Screen up to 3x200's, 1x270 (same on both shakers). Pump tandem sweep, back 51 bbis late w/ minimal Inc. Circulate a total of 2.5 btms up, 550 gpm, 130 rpm, 2325 psi, 22.5k tq w/ max gas @ btms up 5,288 units. Washpipe started leaking during cleanup cycle.; Rack back 1 std F/ 15,000' - T/ 14,93T MD. B/D TDS and R/U head pin. C/O washpipe while circulating lhru headpin @ 3 bpm, 405 psi, 32% flow, 400u bgg.;Wash and ream do F/ 14,93T - T/ 15,000' MD and continue circulating another 2.5 Btms up, 500 gpm, 2115 psi, 140 rpm, 22.6k tq, 58% flow, 11.1 ECD. 3966u max gas @ btms up, 680u bgg final. 192k up, 106k rot, no dn. Shakers unloaded @ 3 btms up (fine silt).; Line up on trip tank and monitor well (flowing). Obtained flow rate (55 bph +/-). Flowed back 12 bbis to trip tank. Continue circulating @ 500 gpm, 2100 psi, 58% flow, 140 rpm, 22.6k while weighting up F/ 9.3 - T/ 9.5 MW. Started seeing losses @ 3/4 surface to surface (20 bph +/-).;Decrease pump rate to 390 gpm, 1450 psi. to minimize losses. 4370u max gas @ btms up.; Line up on TT and monitor well (flowing). Obtained flow rate (28 bph, reducing to 22 bph after 15 min). Flowed back 10 bbis to trip tank. Cont circulating @ 370 gpm, 1320 psi, 52% flow, 100 rpm, 21.5k while weighting up F/ 9.5 - T/ 9.7 MW. Losses continue at 15 bph +/-. 341 Ou max gas @ BU.; Line up on TT and monitor well (flowing). Obtained flow rate (24 bph, reducing to 14 bph after 20 min). Flowed back 10 bible to trip tank. Cont circulating @ 370 gpm, 1320 psi, 52% flow, 80 rpm, 19.9k while weighting up F/ 9.7 - T/ 9.8 MW. Losses continue at 10 bph +/- . 3363u max gas @ BU.; Reduced the flow rate to 300 gpm , 1175 psi after 9.8 ppg fluid exited the bit, subsequently the losses reduced to 5 bph+/-.;Line up on trip tank and monitor well (Flowing). Obtained flow rate (16 bph +/-, reducing to 10 bph after 30 min). Flowed back 7 bbis to trip tank.;Obtain SPR's then lay down working single DP. Backream out of hole to 13,875', 300 GPM - 1115 psi, 140 RPM - 21,400k tq. 500-800'/hr pulling speed, 110k hookload.;Daily Fluid Hauled to G&l: 456 bbis Total Fluid Hauled to G&I: 7,544 bbis Daily Fluid Hauled to B-50: 0 Total Fluid Hauled to B-50: 0 Metal from well: 7lb.;Daily H2O From L -Pad Lake: 520 bbis Total H2O From L -Pad Lake: 13,390 bbls Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 Daily Lost To Formation: 174 bbls Total Lost To Formation: 429 bbls 12/5/2018 BROOH F/ 13,875- T/ 13,259' MD. 300 gpm, 1075 psi, 47% flow, 140 rpm, 20k tq, 11.3 ECD's. 700 FPH pulling speed. 9.75 In / 9.85 Out.;C/O leaking washpipe. R/U headpin and circ at 3 bpm while changing washpipe. Inspect washpipe for damage (none noted), inspect new washpipe for potential fail issues (none noted). 125 gpm, 445 psi, 29% flow.; R/D headpin. Continue BROOH F/ 13,259' - T/ 12,561' MD. 300 gpm, 1000 psi, 46% flow, 120 rpm, 19.5k tq, 10.9 ECD. 700 FPH pulling speed.;Continue BROOH F/ 12,561' - T/ 10,545' MD. 300 gpm, 900 psi, 46% flow, 120 rpm, 14.3k tq, 10.8 ECD. Increase pulling speed to 1200 FPH.;Continue BROOH F/ 10,545 - T/ 10,270' MO. 400 gpm, 1360 psi, 50% flow, 120 rpm, 14.5k tq, 11.1 ECD. Decrease pulling speed to 300 FPH and allow hole to clean up.;Continue BROOH F/ 10,270'- T/ 10,174' MD. 300 gpm, 1000 psi, 49% flow, 120 rpm, 13.9k tq, 10.8 ECD. Increase pulling speed to 500 FPH.;Continue BROOH F/ 10,174' - T/ 7,780' MD. 400 gpm, 1035 psi, 49% flow, 140 rpm, 13.Ok tq, 10.8 ECD. Increase pulling speed to 1200 FPH. BGG = 55u, Max gas = 603u.;Continue BROOH F/ 7,780' - T1 7,200' MD. 450 gpm, 1023 psi, 56% flow, 140 rpm, 10.Ok tq, 10.8 ECD. Pulling speed -1200 FPH. BGG = 55u, Max gas = 58u.;Continue BROOH F/ 7,200'- T/ 6,887' MD. 350 gpm, 1150 psi, 53% flow, 140 rpm, 13.Ok tq, 11.4 ECD. Reduced pulling speed to 300 FPH due to increase in pressure, torque and ECD. 50% increase in cutting return, clay & sand. Max gas = 803u.;Continue BROOH F/ 6,887'- T/ 6,262' MD. 400 gpm, 1035 psi, 49% flow, 140 rpm, 13.Ok tq, 10.8 ECD. Increase pulling speed to 1200 FPH. BGG = 55u, Max gas = 603u. Pulled clean up into shoe without issue.;Line up on trip tank and monitor well (flowing). Obtained flow rate (2.2 bph +/-, increasing to 12 bph after 15 min). Flowed back 2 bible to trip tank.;Pump tandem sweep, 34 bbl to vis 125 bbl high vis & wt. 500 gpm - 1530 psi, 57% flow, 120 rpm - 6.4k tq, 10.6 ECD.;Daily Fluid Hauled to G&I: 57 bbls Total Fluid Hauled to G&I: 7,601 bbls Daily Fluid Hauled to B-50: 0 Total Fluid Hauled to B-50: 0 Metal from well: 12 Ib.;Daily H2O From L-Pad Lake: 230 bbls Total H2O From L-Pad Lake: 13,620 bbls Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 Daily Lost To Formation: 80 bbls Total Lost To Formation: 509 bbls 12/6/2018 Circulate and condition hole @ the shoe (6277' MD) 550 gpm, 1825 psi,62% flow, 120 rpm, 6.2k tq, 55u max gas w/ 10.6 ECD. Pumped tandem sweep. Back on time w/ 25% Inc in cuttings (sand/silt).;Monitor well (flowing). Initial flow rate showed 22 BPH but gradually decreased to 7.2 BPH before leveling out and maintaining a -7.2 BPH flow rate. Sym Ops - Troubleshoot washpipe issues on gooseneck of top drive.; Found gooseneck was out of alignment which in turn appears to be what was causing premature failures on washpipe seals.;Sewice rig - Grease traveling equipment and crown.;Circulate and condition mud. Weight up from 9.9 MW to 10.1 MW. 500 gpm, 1500 psi, 10.5 ECD. No notable gas @ btms up.;Monitor well on trip tank. Initial flow rate showed 5.9 BPH V gradually slowed to 2.9 BPH where it leveled off and maintained 2.9 BPH flow mte.;Circulate and condition mud. Weight up from 10.1 MW to 10.3 MW. gpm, 1675 psi. Sym Ops- Break bolts on gooseneck, adjust and re-tq bolts to put gooseneck in alignment as per NOV specs. Install washpipe.;Monitor livell on trip tank. Initial flow rate showed 1.9 BPH and gradually slowing until becoming static.;Pull out of hole f/ 6262' to 4765', laying down drill pipe to shed. Start to see losses at 0.5 BPH.;Continue pulling out of hole to 1452' laying down drill pipe to shed. Losses continue at -0.5 BPH.;Joint of DP was dropped from elevators while lowering onto the pipe skate. Elevators were approx 25' high. Drill pipe struck an employee. Emergency response dispatched.;Well shut in at 04:35 and rig in safety standby.;Daily Fluid Hauled to G&I: 114 bbls Total Fluid Hauled to G&I: 7,715 bbls Daily Fluid Hauled to B-50: 0 Total Fluid Hauled to B-50: 0 Metal from well: 4 Ib.;Daily H2O From L-Pad Lake: 260 bbls Total H2O From L-Pad Lake: 13,880 bbls Daily H2O From Lake 2: 0 Total H2O From Lake 2: 0 Daily Lost To Formation: 0 bbls Total Lost To Formation: 509 bible 12/712018 Rig on safety standby. 12/8/2018 Continue safety stand down.;Continue safety stand down.;Continue safety stand down. Crew performing work orders and inventory on parts.;PJSM & JSA with crew on opening up the shut-in well.; Blow air through topdrive and choke manifold to ensure no blockage. MU topdrive to closed TIW. Ensure valves are lined up from stack to choke and properly shut-in to pits. Open HCR choke and monitor SICP - 0 psi obsewed.;Open TIW to shut-in standpipe bleeder valve and monitor SIDPP - 0 psi observed. Open choke to pits and observe no returns. Open standpipe bleeder valve and observe no returns. Establish hole fill circulation on trip tank and obtain baseline strap.;Open upper pipe rams. No gain/loss recorded. Shut down hole fill and establish circulation down string. 200 gpm - 460 psi, 30 rpm - 2.2k tq. BGG = 8u. Initial mud temp 61 ° in / 55° out.;Various return mud weights of 10.1 to 10.2+ ppg being recorded with 10.3 ppg going in. Circulate and condition mud until even 10.3 ppg mud weight in and out. Final mud temp 63° in 162° out.;Monitor well - Static - Blow down topdrive and monitor well again. - Static - Shut well in (UPR), Close TIW valve and blow down choke manifold and mud Iines.;Continue safety stand down. 12/9/2018 Continue safety stand down.;Continue safety stand down.;Continue safety stand down. Rig crew performing safety inspections and hazard hunts throughout rig.;Continue safety stand down. Rig crew performing safely inspections and hazard hunts throughout rig.;PJSM & JSA with crew on opening up the shut-in well.; Blow air through topdrive and choke manifold. MU topdrive to closed TIW. Lined up from stack to super choke. Open HCR choke and monitor SICP - 0 psi observed. SIMOPS - Increasing YP in active mud pit system from 16 to 26 YP.;Open TIW to shut-in standpipe bleeder valve and monitor SIDPP - 0 psi observed. Open choke to pits and observe no returns. Open standpipe bleeder valve and observe no returns. Establish hole fill circulation on trip tank and obtain baseline strap.;Open upper pipe rams. No gain/loss recorded. Shut down hole fill and establish circulation down string. 400 gpm - 925 psi, 30 rpm -1.8k tq. BGG = 8u. Max gas = 11 u. No gain or loss recorded.;Mud weight 10.3+ ppg going in and return at both start and end of circulating. Circulated one full surface to surface volume, good 26 YP & 10.3 ppg wt mud around. Mud temp start 64° in / 46° out, End 64' in / 57' out.;Stop circulation and monitor well - Static - Blow down choke line to stack. Shut well in (UPR) & close TIW valve. Blow down topdrive, choke manifold, mud lines and mud pumps.;Continue safety stand down. Prep rig for temporary crew release. Rig will be monitored by several supervisory personnel. 12/10/2018 Continue Rig safety stand down.;Well is shut in with Upper Pipe Rams & TIW valve. 12/11/2018 Continue Rig safety stand down. 12112/2018 Continue with safety stand down. 12113/2018 Continue with safety stand down. Well is shut in with Upper Pipe Rams & TIW valve. 12/14/2018 Continue with safety stand down. Mobilize crews to MPU In novation.;Conduct pre-start up and incident review safety meeting with both crews, 3rd party rig support, John Menke, Sonny Kula and James Sweetsir. Discuss corrective actions from incident.;Conduct extensive hazard hunt with rig crew. Work on PLC operation for hydraulic elevators and troubleshoot closing signal switch.;Conduct pre-start up and incident review safety meeting. Discuss toolpusher authorizing all rig mentoring and training, driller notifying crew while mentoring on drillers console, and operating rig at reduced rate; doghouse distractions and Drillers right to stop rig activities;;during distractions; review initial list of activities not authorized while blocks are in motion.;Conduct extensive hazard hunt with night crew, review earlier findings. Work on correcting harzards. Continue to work on closing signal switch for hydraulic elevators. Update procedures/JSA's to include list of non-permitted activities while blocks are in motion. Condition surface mud. 12/15/2018 Continue with Hazard Hunt throughout rig. Complete "Restart Criteria Checklist" and send to town for approval. Add glycol to TDS coolant system. Repair toggle "Open/Close" indicator on hydraulic elevators and put back in service. Troubleshoot TDS coolant pump.;Monitor shut in @ 1452' MD. SICP - 24 psi. Bump test gas trap (good). Clear choke manifold, gas buster and lines with air (good). Bled off SICP and climbed to 20 psi over 15 min. Bled off via choke and visually monitor @ pits. 5 bph +/- Flow. Circ and cond with negligible gas @ btms up.;Stage up from 2 BPM,140 psi to 4 BPM, 270 psi. MW out initially 1OC. Condition mud to 10.3 In/Out. Circulate a total of 4x btms up.;Monitor well through choke. Initial flow rate 4.6 bph slowing to 1.3 bph after 20 minutes. Open up well. Blow down top drive.;RIH from 1452'to 3460' MD. PUW 111 K, SOW 94K.;Circulate and condition mud at 10 bpm/1075 psi mud weight in 10.4, mud weight out 10.1 to 10.4 ppg. Circulate until even mud weights. negligible gas. Monitor well, slight flow going static in 20 minutes. Blow down top drive.;POOH from 3460'to 267'. Rack back 1 stand HW DP, Drill collars and Jars to 85'. Proper hole displacement observed. PUW 54K, SOW 54K.;Plug in and download MWD. UD TM Collar.;Hauled 57 bbis Fluid to MPG&I total = 7772 bbls Hauled 0 bbis fluid to B-50 total = 0 bible Hauled 0 bbls H2O from L-Pad Lake total = 14270 bbis Lost 0 bbis to formation total fluid lost = 509 bbis 12/16/2018PJSM, Cont UI,PD BHA. B/O and UD MWD ADR collar. P/U and inspect Geo-Pilot (slight damage to lower housing). B/O and UD bit. Bit grade - 1,2,CT,T, ,N,TD. ound what appeared to be rubber lining from a steel re-enforced hose sitting on top of MWD and partially plugged in bit nozzle.;Drain stack, BOLDS and pull wear bushing. R/U BOP test equipment. Flood stack, choke and kill lines and choke manifold. Purge air. Shell test to 3k w/ 5" test it (test good). Call AOGCC rep Jeff Jones post shell test as requested.;Wait on inspector to witness BOP test. Clean and clear work areas. Rebuild cellar bridge crane hooks. Inspector arrived on location @ 12:30 hm.;Test CMV's 1-15, (2 ea 5" TIW), 5" Dart, HCR choke & kill, Manual choke & kill, blind ams, upper and lower pipe rams (2-7/8" x 5-1/2" vbrs) wl 2-7/8" & 5" test jt. 250 low, 3000 high w/ 5 min hold. Chart and record same. Tested gas alarms 10/20 H2S BOP test witnessed by AOGCC Jeff Jones.;Rig down testing equipment, blow down lines. rig down test joints. Flush through top drive and mud lines. Blow down top drive.;Remove kelly hose from top drive. Inspect inside with video-scope. Observe damage -5' from bottom and near goose-neck.;Trouble shoot rotary table. Disconnect hydraulic lines, remove drain system. Pull floor plates and secure. Pull rotary table motor. Motor good, rotary table still unable to spin.;Disconnect kelly hose and lay down. Install new kelly hose. 12/17/2018 Hook up Kelly hose to TDS, Install secondary restraint system on same. Test run TDS in derrick and orient Kelly hose so it hangs properly without hanging up. Tighten unions and install spiral hose guard.; PJSM, Shut blinds and monitor casing psi (0 psi). Pull and stage master bushings. Remove rotary table top plate, N/D riser and remove lower guard plate from rotary table. Break main rotary table bolts and remove rotary table. Stage on rig floor and secure same.;Remove anchoring bolts from bearing section and remove bearing section. Inspect bearings (good). Found table had a fair amount of rust and debris on rotary body that fits inside rotary housing just inside rotary labrynth seal (lower). Clean and inspect same (looked good after cleaning).;Test hydraulic system (tested good). Troubleshoot hydraulic drive motor for table.;Cont. Clean out labrynth seal , wire wheel and grease. Install rotary table into housing. Install motor. Lower rotary table and bolt into place. Install floor plate. Verify rotary table is functional. Clean and clear rig floor.;Rig up Hawk Jaw and function test. Rig up to pick up BHA.; Pick up BHA as per DD: 8-1/2" PDC, Geo-Pilot, MWD. Plug in and upload MWD. RIH with DC, HWDP, Jars from derrick. Shallow pulse test MWD.;Hauled 0 bbis Fluid to MP G&I total = 7829 bbis Hauled 0 bbis fluid to B-50 total = 0 bbis Hauled 0 bbis H2O from L-Pad Lake total = 14530 bbis Lost 0 bbis to formation total fluid lost = 509 bbis 12/18/2018 PJSM pick up drift and single in the hole with 5" drill pipe from 265' to 4994', filling pipe every 2500'.;Continue to RIH with pipe from derrick from 4994' to 6197', calculated displacement.;Circulate hole clean at 290 gpm/630 psi. No gas observed at bottoms up, PUW 128K, SOW 104K. Initial ECD 11.22 ppg, final 10.91 ppg; initial loss rate 40 bph slowing to 10-15 bph. Monitor well, slight flow slowing to static.;Cut and sip 63' of drill line while monitoring well on trip tank - static.;RIH from 6197' to 7455', set down 25K at 6400' attempt to work past x 3 unable to. Establish circulation and wash down at 2 bpm/320 psi and wipe clean down to 6440'. Continue to RIH on elevators after; observe 5-10K drag from 6658' and pushing away fluid when drag observed RIH at 12 fpm. Drag;increasing to 10-15K at 7300' and flow out % dropping from 21.9 % to 19% losing 6 bbis over 2 stands.;At 7455' establish circulation at 2 bpm/320 psi. Pump open hole volume staging pumps up in up stroke to 3.5 bpm/400 psi.;Wash down from 7455' to 8720' at 2 bpm 380 psi loss rate 5-8 bph; 0-5K drag.;Circulate annular volume, slowing pumps and increasing running speed in downstroke from 8720' to 8830' (2 stands). Staging pumps up to 300 gpm/887psi loss rate 20-30 bph, stage up to 360 gpm and observe loss rate drastically increase, slow pumps back down to 300 gpm. Max gas 251 U. MW 10.2 ppg.;Continue washing down from 8830' to 9287'MD at 2 bpm/350psi PUW 136K, SOW 85K.;Hauled 48 bbls Fluid to MP G&I total = 7877 bbis Hauled 0 bbis fluid to B-50 total = 0 bbis Hauled 360 bbis H2O from L-Pad Lake total = 14890 bbis Lost 42 bible to formation total fluid lost = 551 bible 12119/2018 Continue to wash in hole no rotation from 9287' to 10,550' @ 2 bpm/400 psi, PUW 145K, SOW 84K, Max gas @ 70u, MW 9.8. Lubes @ 4%.;Circulate STS from 10,550 working pipe 6Q'; 300 gpm/7 0 psi, reduce flow rate to 84 gpm/400 psi on down stroke. Peak gas observed 2750u, leveling out at 1900u.;Continue to wash down from 10,550' to 12.760'@ 3bpm, increasing MW to 10.0 ppg. Observe gas continually climbing while washing down. Saw 4000u gas @ 12,760'.;CBU from 12,760' with peak gas @ 4000u. Leveling out @ 1400u. See substantial amount of oil @ shakem.;Continue to wash down from 12,760' to 14,685' @ 2bpm/500 psi. Tight at 13,781' losing all down weight, rotate through at 10 rpms and wiping clean. At 14,685' Observe hole taking 15-20K, and pump pressure increase -200 psi. Pick up establish rotary at 10 rpms.;Wash and ream from 14,685' to 14,812' staging pumps up to 250 gpm/1080 psi, 40 rpms/18Kft-lbs deflecting geo-pilot toolface to highside (50-70% dell). Working consistent tight hole and pack-offs. Confer with town as hole exited sands at 14,664'.;Circulate 3 annular volumes pumping tandem sweeps (75 bbis late 10% increase) staging pumps up to 440 gpm/1980 psi, 120 rpms/22Kft-lbs with 10- 20 bph loss rate. ECD 12.0 ppg. Max Gas 3931 U.;BROOH from 14,812' to 12618' 100rpm/16.8Kft-lbs 440 gpm/1750 psi. PUW 160K, SOW 68K, ROTW 104K. Observe 5-10 bph loss rate while backreaming.;Hauled 173 bbis Fluid to MPG&I total = 8050 bbis Hauled 0 bbis fluid to B-50 total = 0 bbis Hauled 0 bbis H2O from L-Pad Lake total = 14890 bbis Lost 221 bbls to formation total fluid lost = 772 bbis HHilcorp Energy Company Composite Report Well Name: MP E-35 Field: Milne Point County/State: , Alaska (LAT/LONG): ovation (RKB): API #: Spud Date: 11/19/2018 Job Name: 1813043C MPE-35 Completion Contractor Innovation AFE #: AFE $: Activity {late OF -_S Summary 12/20,'2018 Continue to BROOH from 12,618'MD to 7425'MD 440 gpm/1400 psi 100 rpms/11 Kft-lbs. PUW 160K, SOW 80K, ROTW 104K. Worked tight spot at 10,318'. Max Gas 856U.,Pump out of hole from 7425' to 6228' 440 gpm slowing to 220 gpm/420 psi as BHA enters shoe. No issues.,Circulate hole clean and weigh up to 10.3 ppg at 440 gpm/1175psi Pump high viscosity sweep, did not observe at surface. Blow down top drive. Monitor well for 30 minutes, slight flow going to static.,POOH laying down drill pipe from 6228'to 267' PUW 50K, SOW 50K.,UD HWDP, Jars, Drill collars. Plug in and upload MWD. Continue laying down BHA.,Hauled 173 bbis Fiuid to MP G&I total = 8223 bbis Hauled 0 bbls fluid to B-50 total = 0 bbis Hauled 260 bbis H2O from L -Pad Lake total = 15540 bbis Lost 60 bbis to formation total fluid lost = 832 bbls 12/21/2018 Continue to UD BHA. Break bit and bit sleeve. UD Geo -pilot. Clean and clear rig floor. Rig down hawk Jaws.,Make up safety joint for 6-5/8" pre -drilled liner. Bring components for 3-1/2" safety joint to rig floor. Rig up Weatherford handling equipment and power tongs. Bring centralizersto rig floor.,Safety meeting with incoming crew. Hazard hunt with incoming crew.,PJSM. Makeup shoe track; round nose float shoe, WIV, drillable packoff. RIH with 6-5/8!'20#L-80 Wedge 563 pre -drilled liner to 8626' as per tally installing centralizers on every joint. PUW 120K, SOW 79K.,R/U to RIH with 3-1/2" EUE Ord inner string. M/U false rotary table. Change safety joint for 3-1/2" inner string with triple connect., Pick up slick joint. RIH picking up 3-1/2" inner string to 1639, PUW 47K, SOW observe -2.51oph flow continue to monitor with no increase. 12/22/2018 Continue to pickup and RIH with 3-112" EUE Ord tubing inside 6-5/8" pre -drilled liner from 1639 to 8585' PUW 75K, SOW 56K. No -Go out, UD 1 joint. P/U space out pups.,M/U swivel and spaceout pups to bottom of liner running tool/hanger. WU Liner hanger. Attempt to pickup on liner unable to, attempt to work pipe down. Establish circulation staging up to 4 bpm/540 psi. Continue to work pipe. Attempt to rotate, stall at 7000 ft -lbs (limiter set). Work pipe up to 275K broke free. Pickup single joint of HWDP and RIH to 8660'.,Rig down Weatherford. Change out pipe handling equipment. Clean and clear rig floor. Load pipe shed of HWDP. Continue circulating while rigging upstaging up to 5 bpm/800 psi. MW in 10.3, MW out 10.1.,RIH with 6-5/8" pre -drilled liner on HWDP from 8690' to 10,570' Picking up drifting and singling in, breaking in new threads. PUW 200K, SOW 124K. Calc displacement 24.6 Actual 19.8.,Circulate bottoms upstaging up to 5 bpm/940 psi reciprocating pipe. max gas 3800, crude oil observed on shakers. Average loss rate 9 bph, MW in 10.3, MW out 10.25. Blow down top drive.,Continue to RIH with 6-5/8" pre -drilled liner on HWDP from 10,570' to 11439'. Picking up drifting and singling in, breaking in new threads. PUW 220K, SOW 124K.,Hauled 290 bbis Fluid to MPG&I total = 8570 bbis Hauled 0 bbis fluid to 8-50 total = 0 bbis Hauled 130 bible H2O from L -Pad Lake total = 15800 blots ' Lost 0 blots to formation total fluid lost = 832 bbis 12/23/2018 Continue RIH on elevators with 6 5/8" LinericP king 5" HWDP from pipe shed (/11,493' to 13.203'. PUW 254K, SOW 125K. (Performing thread break in on new HWDP making up and break out x2 before RI H.),TIH on elevators out of Derrick with 5" OP f/13203' to 14,475' Liner Shoe Depth. (Drift pipe out of Derrick.) PUW 265K, SOW 98K. No Issues running liner to TD.,Circulate STS x 2 staging pump to 5.5 bpm 1300 psi. While prepping for Brine Displacement. Saw 4500 units gas @ BUS. Continually see Crude Oil in returns. Gas @ 1600u and falling after circulation.,Displace Well to 9.8 brine. Pump 40 blots spacer, follow with 800 bbis 9.8 ppg brine. At 5 bpm, 1,300 PSI. Back ground Gas 1,000U.,Shut down well monitor well. Initial flow rate 19.5 bph, After 30 Min flow rate was 16.5 bph. Go to closed loop system and Pump 3 ea 40 bbl 8.4 ppg SAPP pills with 50 bbls 9.8 ppg brine between each. At 5 bph, 1,000 PSI. BGG 7000. Over board Chem Train at surface. Pump 1.Sx OH Vol (350 bbls).,Shut down and monitor well, heavy Gas and Oil seen at surface. Cont. pumping 9.8 ppg Brine to try and Circ. out Gas. Max Gas 2,9000. Decision was made to weight up to 10 ppg.,Cont. Circ. and weighting up Brine F/ 9.8 to 10 ppg at 5 bpm, 800 PSI. BGG 670 U and heavy crude. Had an increase of 45 bbis Crude Oil seen at surface. Brine returns so contaminated unable to keep Brine weight at 10.0 ppg. Decision was made to set Packer and reduce IA volume., Drop closing 1.25" ball for wellbore isolation valve. Pump down at 5 bpm, 900 PSI, slowing to 2 bpm at 1,741 strokes, observe land on seat at 1,975 strokes. Pressure up to 3,500 psi to set ZXPN Packer, hold for 5 Min. continue to pressure up W/ test pump to 4,650 psi to set Pusher Tool. S/O confirm liner hanger set. P/U 5' to expose dog subs.,Blow down Top Drive. R/U Test Equip. Test Annulus to top of Packer to 1,700 psi and chart for 10 minutes. Witnessed by Cc Rep onsite. RID test Equip.,P/U 214K release from HRD setting tool. Observed flow of Crude Oil at Surface. Start Circ. at 5.5 bpm, 970 PSI to clear out inside of 6 5/8" X 3.5" IA with 9.8 ppg Brine. 1 212 4/2 01 8 TOL 6092.41' MD. Shoe at 14,745' MD. Circ. to clear out 6 5/8" X 3.5" at 5.5 bpm, 1,010 PSI. Pumping clean 9.8 ppg Brine from trucks. Shut down and monitor well for 45 Min. Initial flow rate 27 bph slowing to 19 bph.,Cont. Circ. at 7.5 bpm, 1,670 PSI slowing to 6 bpm, 1,100 PSI after BU. Dump contaminated Brine from Pits to make room for new 9.8 ppg Brine. Wart on trucks for 10.3 ppg Bromide Brine to perform displacement.,PJSM Displace W/ 315 bbls 10.3 ppg Brine F/ Vac Trucks, stage pumps up to 4.5 bpm, 600 PSI. Shut down line up and pump 255 bbis 9.8 ppg Brine F/ Pits stage pumps up to 7.5 bpm, 1,775 PSI. Swap to 10.3 ppg Brine from Trucks for 92 bbis at 4.5 bpm, 570 PSI. Max Gas 2,6000. Shut down and monitor well for 30 Min. Initial flow rate 7 bph, slowing to 5.8 bph. Blow down Top Drive., PJSM POOH on elevators laying down 5" D. P. NC -50 F/ 14,700' to 13,410' MD Calculated hole fill 11.1 bbls, actual 3.8 bbis. P/U 215K, SLK 145K.,Monitor well, Flow rate 3.3 bph, Perform well Control Drill, Fire Drill and relieve crew for dinner.,Cont. POOH laying down 5" D.P. F/ 13,410' to 13,200' MD. UD 5" HWDP F/ 13,200' to 9,804' MD. Calculated hole fill 55 bbl, actual 47.7 bbl gain 7.3 bbl. P/U 118K, SLK 98K.,PJSM Cont. UD 5" HWDP F/ 9,804'to 8,604' MD. Calculated hole fill 27.6 bbis, actual 25.7 bbis. 1.9 bbl gain. P/U 75K, SLK 65K. PJSM Lay down Baker running tool as per Baker Rep onsite., PJSM RID and UD Hawk Jaws. R/U Weatherford Power Tongs and 3.5" handling Equip. Thaw out and function tools. Average loss rate 1.4 bph gain.,PJSM POOH laying down 3.5" EUE 9.3# tubing F/ 8,604'to 7,961' MD. PIU 70K, SLK 66K. Calculated hole fill 2.2 bbis, actual 1.5 bbis. Gain 0.7 bbls.,Hauled 2,272 bbis Fluid to MP G&I total = 12,505 bbis Hauled 0 bbis fluid to B-50 total = 0 blots Hauled 260 bbis H2O from L -Pad Lake total = 16,320 bbis Lost 0 bbls to formation total fluid lost = 832 bbls 12/25/2018 Cont. POOH LID 3.5" Tubing 9.3# EUE F/ 7,961' to 5,97T MD. P/U 68K, SLK 64K. Calculated hole fill 8.48 bbls, actual 5.2 bbls. Gained 3.28 bbls.,Circ. Surf to Surf to ensure good 10.3 ppg Brine in and out. Add KCL and 11.2 ppg Bromide Brine to maintain 10.3 ppg out. Adjust pump rate to maintain weight at 3 to5 bpm, 140-300 PSI. Max Gas 1,150U.,Monitor well, hole taking 5 bph. Cont. POOH LID 3.5" Tubing 9.3# EUE F/ 5,977'to 1,118' MD. Calculated hole f119.54 bbis, actual 31.5 bbls. Lost 21.9 bbis-Relieve crew for Christmas dinner. Monitor well, average loss rate 5 bph.,PJSM Cont. POOH LID 3.5" Tubing F/ 1,118' to surface. Calculated hole fill 3.7 bbis, actual 9.5 bbis. Lost 5.8 bbls.,PJSM RID Weatherford Power Tings and handling Equip. R/U Hawk Jaw and 5" Elevators. Prep rig floor for running in hole 5" D.P. Loss rate 5 bph.,Service rig. Grease Crown, Blocks, Top Drive, Spinners and full Derrick inspection.,PJSM P/U M/U 3.5" EUE Stinger on 5" NC50 D.P. and RIH from Derrick to 3,373' MD. Calculated hole fill 27.8 bbls, actual 18.5 bbls. Lost 9.3 bbls. Average loss rate 4.5 bbls.,PJSM Cont. RIH from Derrick F/ 3,373' to 6,121' MD. Tag TOL W/ No/Go on top of 3.5" Stinger on depth at 6,092' MD. Calculated hole fill 22.2 bbis, actual 16.1 bbis. Lost 6.1 bbis. Average loss rate 4.5 bbls. P/U 127K, SLK 110K.,Circ. at 3 bpm, 80 PSI for about 20 bbis inside of liner top. Pull above liner top and stage pumps up to 5 bpm, 115 PSI CBU. Max Gas 720U. Pump 15 bbl 11.2 ppg Dry job and blow down Top Drive.,PJSM for Slip and cut drilling line 75'. Check Brake tolerance. torque on Dead Man and un hang Blocks. Monitor well, loss rate 3 bph.,POOH LID 5" D.P. F/ 6,092' to 5,288' MD. P/U 124K, SLK 106K. Calculated hole fill 5.6 bbis, actual 7.2 bbis. Lost 1.6 bbls.,Hauled 0 bbls Fluid to MP G&I total = 12,505 bbis Hauled 0 bbis fluid to B-50 total = 0 bbis Hauled 0 bbis H2O from L-Pad Lake total = 16,320 bbls Lost 76 bbis to formation total fluid lost = 908 bbis 12/26/2018 Continue to POOH LID 5" D.P. F/ 5266' to 4,824' . PUW 126K, SOW 110K-TIH with Remaining DP in Derrick (19 stds) f/4824' to 6024'. PUW 128K, SOW 111 K. Average loss rate @ 6 bph.,POOH LID 5" D.P. F/ 6,024' to Surface. Calc Hole fill 56 bbls, Actual 78 bbls.,Pull wear bushing. Drain stack, close bind ram, remove VBR if upper BOP, install 7 5/8" ram, open blind ram, R/U test equipment w/ 7 5/8" test jt, Test upper ram to 250/3000 psi 5 min ea. charted. RID test equip. close I/A. Monitor well , static loss rate 4.8 bph, RID and LID test equipment.,R/U to run 7 5B" casing, Setup torque turn equipment. M/U crossover to FOSV. R/U and make hanger dummy run per well head rep, hanger landed out @ 24.87' RKB. Monitor well on trip tank, 5.2 bph loss rate.,PJSM with all parties involved, review plan for well control. P/U and run 7 5/8" tie back per tally, P/U tie back seal assy, 8.25" nogo locator, XO and pup, P/U and RIH w/ 7 5/8" Wedge 521, 29.7# L-80 casing f/ 17'to 2,402' MD. Calculated displacement 25.8 bbls, actual 4.1 bbls. Lost 21.7 bbls Torque turn connections to optimum @ 11,000 fl/lbs. Utilize Dog Collar clamp on every connection., PJSM with all parties involved- Cont. to RIH RIH w/ 7 5/8" Wedge 521, 29.79 L-80 casing F/ 2,402' to 6,102' MD. Calculated displacement 38.7 bbis, actual 15.6 bbls. Lost 23.1 bbls., Land on no go on joint # 153 28.05' down. set down 9K verify tag. P/U 153K, SLK 127K. LID Joint #153. Double check Talley and calculated no need for Pups. Setting NoGo 1.49' off when landed. M/U Landing joint and Hanger. Land Hanger as per NOS Rep onsite. P/U 157K.,WU X/O and Circ. Equip for displacement.,Hauled 292 bbis Fluid to MP G&I total = 12,797 bbis Hauled 0 bbis fluid to B-50 total = 0 bbls Hauled 130 bbis H2O from L-Pad Lake total = 16,450 bbis Lost 98 bbis to formation total fluid lost = 1,006 bbis 12/27/2018 MU XO landing jt to DP, MU Top Drive, Close bag and PT Annulus to 500 psi to ensure proper space out and seal engagement. Bleed pressure to 250 psi, strip up hole until pressure dumped, exposing seal ports to annulus.,Using the Kill Line, Establish reverse circulation through ported seals with fluid from rig pits. Line up on and pump 88 bbis Corrosion inhibited 9.8 ppg KCL, chase surface lines with 10 bbis Brine. Turn over to LRS and Reverse in 58 bbis DSL. Strip in hole and land out Tie back seals Assy 1.5' off no go w/ Mule Shoe @ 6100.09. (TOL @ 6092') PU/SO 153ld127k. LRS Bleed off 575 psi with 1.1 bbis back.,Open lower annulus valve, Open bag, drain stack, RID Reversing equipment, Pull & LID 7 5/8" landing joint, MU pack off running tool to jt of 5" DP. Land and test pack off to 500/5000 psi. 10 min ea.,LRS PT 9 5/8" x 7 5/8" Annulus to 1800 psi on chart for 30 min.. RID LRS. Monitor well before changing UPR's. Well @ 0 bph loss rate.,Set Test Plug. Close blind ram. Change UPR back to 2 7/8" x 5 1/2" VBR's. Open blind ram.,RU test equipment w/ 2 7/8" test jt, test annular to 250 psi low and 3000 psi hi 5 min ea, charted, Test lower 2 7/8" x 5 1/2" VBR to 250 low and 3000 psi hi 5 min ea. Test upper VBR to 250 low and 3000 psi hi 5 min ea, charted, good test. RID test equipment, Close I/A.,Rig up to run ESP completion. R/U WOT equip. Hang Sheave for ESP cable. Thread ESP cable and 2-3/8" capillary lines thru sheave to rig floor. Load ESP tools and equipment to rig floor. M/U FOSV to XO. Static loss rate 4.2 bph.,PJSM W/ all Parties for picking up ESP Pump. P/U WU 5.85" Centralizer, Zenith Sensor, XP250 Motor, Lower and Upp Tandem Seals, Dual Gas Separator, 2 ea 134 Flex 17.5 SXD Pumps, Discharge Head and 2 7/8" Pup as per Baker Centrilift Rep onsite. Attach MLE Pothead to Motor Assy and 13/8" SS CAP line. 3 ea Motor Clamps, 2 Seal Clamps and 6 ea Pump Clamps. RIH 1 Jnt 2 7/8" EUE 8rd to 12T MD. Test CAP and Meg ESP Cable.,Zenith intake pressure gauge not reading correctly. Called engineer and discussed options. Decision was made to RIH.,PJSM for running Tubing. RIH 2 7/8" 6.5# EUE 8rd L-80 F/ 127'to 518' MD. P/U 42K, SLK 42K. Loss rate 3.8 bph.,Hauled 114 bbls Fluid to MP G&I total = 12,911 bbis Hauled 0 bbls fluid to B-50 total = 0 bbis Hauled 0 bbls H2O from L-Pad Lake total = 16,450 bbis Lost 127 bbis to formation total fluid lost = 1,133 bbls 12/28/2018 RIH 2 7/8" 6.5# EUE 8rd L-80 '1518' installing clamps on each collar of every jt ran. RIH to 814' (24 jts total), M/U XN nipple w/ 2.205" nogo, RIH to 873'(26 jts total) M/U GLM w/ DV, RIH to 561T (180 Jts total). M/U GLM w/oriface. RIH to 5760'(184 Jts total). Test cable @ 1000' and cap lines @ 2000'. TO 2 7/8 EUE to 2240 ft/Ibs. Static loss rate continues @ 3 bph.,Total 192 Cannon Clamps, 3 ea Motor Clamps, 2 Pump Clamps.,MU Tubing Hgr and landing joint. Centrilift splice ESP. Terminate control lines. Make test on cables. Test good. Drain stack. Land Hanger, RILDS, LID Landing Joint, install BPV. Bottom of Centralizer @ 57891. Pump set @ 5749'-5702'. Up Wt 70K w/Blocks, Dn Wt 54K w/Blocks. 184 jts 2 7/8" 6.5# L-80 EUE tubing ran.,PJSM RID BOT ESP Sheave and Equip. RID Weatherford tools and Equip. Clear Rig floor of Misc tools and Equip. Flush and Johnny Whack the BOPE with hot water and soap. R/U Hydraulic Elevators and function test.,Perform Pre start meeting with incoming crew. Perform hazard hunt around the rig. Familiarize new drilling controls with new crew. Discuss finding and review hazard hunt. Attendees Rig Crew, Tour Pusher, Tool Pusher, Day and Night DSM and Kuukpik HSE.,PJSM for N/D BOPE-Hauled 57 bbis Fluid to MP G&I total = 12,968 bbls Hauled 0 bbis fluid to B-50 total = 0 bbis Hauled 0 bbis H2O from L-Pad Lake total = 16,450 bbis Lost 49 bbis to formation total fluid lost = 1,182 bbis Test hanger void as per wellhead rep to 500 psi low for 5 min, 5000 psi high for 15 min on chart. Pull BPV & Set TWC. Test Tree to 25015000 psi. Test Good. Pull TWC.,PJSM Test lines to 3,000 PSI. Circ. down 2 7/8" Tubing taking returns from IA through Choke manifold. Pump at 1.5 bpm, 3,000 PSI 340 bbls 9.8 ppg Brine 6% NaCl/ KCL Brine to displace 10.5 ppg Bromide Brine in well. SIMOPS R/D tongs, R/U Bridle Lines, load 131 jnt 5" D.P. in Pipe Shed and process. Cont. to perform PM'S. Swap to Generator power @ 16:OO.,PJSM R/U LRS to Tree. PT lines to 250/ 3,000 PSI. Line up and bullhead 15 bbls Diesel down 2 7/8" Tubing at 1.3 bpm, ICP 2,940 PSI. FCP 604 PSI and falling. Swap over to IA PT 250/3,000 PSI. Bull head down 2 7/8" X 7 5/8" Annulus 95 bbls Diesel at 2 bpm, ICP 540 PSI, FCP 690 PSI and falling.,Flush surface Equip lines, Gas Buster, Choke Manifold, MP # 1 & 2 and blow down. Cont. to process 5" NC50 D.P. in Pipe Shed and monitoring SSE.,Prep cellar for rig move. Clean Pits and flush lines. R/D and inspect MP #1. C/O Top Drive trolley wear pads as needed. Raise Blocks to scope position and install sheave safety pins. Cont. process and load 5" D.P. in Pipe Shed. (Total 248 Jnts) Cont, working on PM'S.,Cont. processing 5" D.P. in Pipe Shed. Cont. working on PM's. Cont. inspecting MP #1 & 2. Replace Liner Seal and Wear Plate on MP #2. PJSM Scope Derrick down. Raise all stairs. Prep Pipe Shed. Check Hydraulic units for Mods. Raise roof caps and remove chain barriers. Remove all Centrifugal pugs. Finish cleaning Pits. Blow down water lines. Rig released 06:OO.,Hauled 704 bbis Fluid to MP G&I total = 13,672 bbls Hauled 0 bbls fluid to B-50 total = 0 bbls Hauled 100 bbls H2O from L -Pad Lake total = 16,550 bbls Lost 0 bbls to formation total fluid lost = 1,182 bbls Hilcorp Alaska, LLC Milne Point MPtEPad MPU E-35 50-029-23615-00 Sperry Drilling Definitive Survey Report 06 December, 2018 HALLIBURTON Sperry Drilling Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU E-35 TVD Reference: MPU E-35 Actual @ 48.72usft MD Reference: MPU E-35 Actual @ 48.72usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA 'roject Milne Point, ACT, MILNE POINT flap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level leo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point gap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU E-35 Model Name Sample Date Declination M Dip Angle (`) Well Position +N/ -S 0.00 usft Northing: 6,016,133.24 usfl Latitude: 70° 27'15.945 N +E/ -W 0.00 usft Easting: 569,426.37 usfl Longitude: 149° 26'0.437 W Position Uncertainty 0.00 usft Wellhead Elevation: 21.70 usfl Ground Level: 21.70 usft Wellbore MPU E-35 Magnetics Model Name Sample Date Declination M Dip Angle (`) BGGM2018 11/21/2018 16.97 Map Design MPU E-35 Vertical MD Audit Notes: Azi TVD TVDSS Version: 1.0 Phase: ACTUAL Tie On Depth: Vertical Section: Depth From (TVD) +N/ -S +EI -W (`) (usft) (usft) (usft) (usft) 27.02 0.00 0.00 Field Strength (nT) 80.98 57,447.90646164 6,378.78 Direction (1) 294.80 Survey Program Date 1216/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 225.00 MPU E-35PB1 SDI Gyro (MPU E-35 PB12_Gyro-NS-GC_Drill colt; H029Ga: North seeking single shot in drill colla 11/20/2018 262.56 6,242.79 MPU E-35PB1 MWD+IFR2+MS+Sag (1) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +as 11/20/2018 6,315.51 6,378.78 MPU E-35PB1 MWD+IFR2+MS+Sag (2) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 11/30/2018 6,400.00 14,929.17 MPU E-35 MWD+IFR2+MS+Sag (MPU E 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 11/30/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1 (`) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 27.02 0.00 0.00 27.02 -21.70 0.00 0.00 6,016,133.24 569,426.37 0.00 0.00 UNDEFINED 100.00 0.14 318.03 100.00 51.28 0.07 -0.06 6,016,133.31 569,426.31 0.19 0.08 2_Gyro-NS-GC_Drill collar (1 196.00 0.25 319.70 196.00 147.28 0.31 -0.27 6,016,133.55 569,426.09 0.11 0.38 2_Gyno-NS-GC_Drill collar (1 225.00 0.32 345.87 225.00 176.28 0.44 -0.33 6,016,133.68 569,426.03 0.50 0.49 2_Gyro-NS-GC Drill collar (1 262.56 0.36 352.06 262.56 213.84 0.66 -0.38 6,016,133.89 569,425.99 0.14 0.62 2 MWD+IFR2+MS+Sag(2) 291.48 0.47 19.21 291.48 242.76 0.86 -0.35 6,016,134.10 569,426.01 0.77 0.68 2_MWD+IFR2+MS+Sag(2) 354.46 2.10 39.09 354.44 305.72 2.00 0.46 6,016,135.24 569,426.81 2.64 0.42 2_MWD+IFR2+MS+Sag(2) 411.99 4.83 37.99 411.86 363.14 4.73 2.62 6,016,137.99 569,428.94 4.75 -0.39 2_MWD+IFR2+MS+Sag(2) 477.28 7.01 35.25 476.80 428.08 10.15 6.61 6,016,143.45 569,432.89 3.37 -1.74 2_MWD+IFR2+MS+Sag (2) 540.16 7.71 36.09 539.16 490.44 16.69 11.31 6,016,150.03 569,437.52 1.13 -3.27 2_MWD+IFR2+MS+Sag (2) 602.91 7.90 34.75 601.33 552.61 23.63 16.25 6,016,157.02 569,442.39 0.42 4.84 2_MWD+IFR2+MS+Sag (2) 12162018 11:10:30AM Page 2 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU E-35 MPU E-35 Actual @ 48.72usft MPU E-35 Actual @ 48.72usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +N1S +El -W Northing Easting DLS Section (usft) (') (') (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 665.39 7.45 42.58 663.25 614.53 30.15 21.44 6,016,163.58 569,447.52 1.82 E.81 2_MWD+IFR2+MS+Sag (2) 727.12 8.70 45.44 724.37 675.65 36.37 27.47 6,016,169.86 569,453.50 2.13 -9.68 2_MWD+IFR2+MS+Sag (2) 790.86 10.69 45.65 787.19 738.47 43.88 35.13 6,016,177.45 569,461.09 3.12 -13.49 2_MWD+IFR2+MS+Sag(2) 854.48 13.48 40.06 849.40 800.68 53.69 44.13 6,016,187.33 569,469.99 4.75 -17.54 2_MWD+IFR2+MS+Sag (2) 918.21 17.07 40.47 910.87 862.15 66.49 54.98 6,016,200.23 569,480.72 5.64 -22.02 2_MWD+IFR2+MS+Sag(2) 981.86 18.38 40.01 971.49 922.77 81.29 67.50 6,016,215.14 569,493.10 2.07 -27.18 2_MWD+IFR2+MS+Sag(2) 1,042.83 21.12 37.48 1,028.87 980.15 97.37 80.36 6,016,231.34 569,505.82 4.71 -32.11 2_MWD+IFR2+MS+Sag (2) 1,106.76 22.17 39.77 1,088.30 1,039.58 115.78 95.09 6,016,249.89 569,520.37 2.11 -37.76 2_MWD+IFR2+MS+Sag (2) 1,169.21 24.71 38.99 1,145.59 1,096.87 134.99 110.84 6,016,269.24 569,535.94 4.10 -44.00 2_MWD+IFR2+MS+Sag (2) 1,232.46 24.59 39.56 1,203.07 1,154.35 155.41 127.54 6,016,289.81 569,552.45 0.42 -50.59 2_MWD+IFR2+MS+Sag(2) 1,294.24 23.96 42.12 1,259.39 1,210.67 174.62 144.14 6,016,309.18 569,568.87 1.99 -57.60 2_MWD+IFR2+MS+Sag(2) 1,358.16 23.94 42.22 1,317.81 1,269.09 193.85 161.56 6,016,328.57 569,586.10 0.07 -65.35 2_MWD+IFR2+MS+Sag(2) 1,421.24 24.81 40.01 1,375.27 1,326.55 213.47 178.67 6,016,348.34 569,603.03 2.00 -72.65 2_MWD+IFR2+MS+Sag (2) 1,484.48 25.04 40.54 1,432.62 1,383.90 233.80 195.90 6,016,368.83 569,620.06 0.51 -79.77 2_MWD+IFR2+MS+Sag (2) 1,547.85 24.47 41.27 1,490.16 1,441.44 253.86 213.27 6,016,389.05 569,637.25 1.02 -87.12 2_MWD+IFR2+MS+Sag (2) 1,610.75 24.01 43.15 1,547.52 1,498.80 272.99 230.62 6,016,408.34 569,654.41 1.43 -94.85 2_MWD+IFR2+MS+Sag(2) 1,673.55 23.88 42.00 1,604.91 1,556.19 291.75 247.86 6,016,427.26 569,671.48 0.77 -102.63 2_MWD+IFR2+MS+Sag(2) 1,736.79 23.85 38.68 1,662.75 1,614.03 311.25 264.42 6,016,446.91 569,687.85 2.12 -109.48 2_MWD+IFR2+MS+Sag(2) 1,800.55 23.03 38.65 1,721.25 1,672.53 331.05 280.27 6,016,466.86 569,703.51 1.29 -115.56 2 MWD+IFR2+MS+Sag(2) 1,861.40 22.21 37.12 1,777.42 1,728.70 349.52 294.64 6,016,485.46 569,717.71 1.66 -120.86 2_MWD+IFR2+MS+Sag (2) 1,925.03 23.89 40.53 1,835.97 1,787.25 368.90 310.27 6,016,504.98 569,733.16 3.37 -126.92 2_MWD+IFR2+MS+Sag (2) 1,988.26 23.93 39.94 1,893.77 1,845.05 388.47 326.83 6,016,524.70 569,749.53 0.38 -133.74 2_MWD+IFR2+MS+Sag(2) 2,051.33 23.26 40.40 1,951.57 1,902.85 407.76 343.11 6,016,544.14 569,765.63 1.10 -140.43 2_MWD+IFR2+MS+Sag(2) 2,114.87 24.24 41.96 2,009.73 1,961.01 427.01 359.96 6,016,563.55 569,782.30 1.83 -147.65 2_MWD+IFR2+MS+Sag(2) 2,177.90 26.64 37.82 2,066.65 2,017.93 447.80 377.28 6,016,584.49 569,799.43 4.74 -154.66 2_MWD+IFR2+MS+Sag (2) 2,240.73 28.97 36.71 2,122.22 2,073.50 471.13 395.02 6,016,607.98 569,816.94 3.80 -160.97 2_MWD+IFR2+MS+Sag (2) 2,303.49 29.27 32.88 2,177.05 2,128.33 496.20 412.43 6,016,633.21 569,834.12 3.01 -166.26 2_MWD+IFR2+MS+Sag (2) 2,365.20 28.84 33.95 2,230.99 2,182.27 521.22 428.93 6,016,658.38 569,850.39 1.09 -170.75 2_MWD+IFR2+MS+Sag (2) 2,428.27 28.80 32.63 2,286.25 2,237.53 546.63 445.62 6,016,683.95 569,866.84 1.01 -175.24 2_MWD+IFR2+MS+Sag (2) 2,491.43 28.40 33.61 2,341.71 2,292.99 571.95 462.14 6,016,709.42 569,883.12 0.98 -179.61 2_MWD+IFR2+MS+Sag(2) 2,555.01 29.12 31.35 2,397.45 2,348.73 597.76 478.56 6,016,735.37 569,899.29 2.05 -183.69 2_MWD+IFR2+MS+Sag(2) 2,618.33 28.83 32.26 2,452.84 2,404.12 623.82 494.72 6,016,761.59 569,915.21 0.83 -187.43 2_MWD+IFR2+MS+Sag (2) 2,681.71 28.16 32.88 2,508.54 2,459.82 649.31 511.00 6,016,787.22 569,931.25 1.16 -191.52 2_MWD+IFR2+MS+Sag (2) 2,745.11 28.85 31.92 2,564.26 2,515.54 674.85 527.21 6,016,812.91 569,947.22 1.31 -195.52 2_MWD+IFR2+MS+Sag (2) 2,808.36 28.34 32.81 2,619.79 2,571.07 700.42 543.41 6,016,838.63 569,963.18 1.05 -199.50 2_MWD+IFR2+MS+Sag(2) 2,871.81 28.52 32.41 2,675.59 2,626.87 725.8 559.69 6,016,864.22 569,979.22 0.41 M7 -203.61 2_WD+IFR2+MS+Sag(2) 2,934.77 28.15 32.49 2,731.01 2,682.29 751.09 575.72 6,016,889.59 569,995.02 0.59 -207.58 2_MWD+IFR2+MS+Sag(2) 2,998.09 27.55 33.08 2,786.99 2,738.27 775.96 591.74 6,016,914.60 570,010.80 1.04 -211.69 2 MWD+IFR2+MS+Sag(2) 3,061.15 27.01 32.98 2,843.04 2,794.32 800.19 607.49 6,016,938.98 570,026.33 0.86 -215.83 2_MWD+IFR2+MS+Sag (2) 3,124.12 27.96 32.35 2,898.90 2,850.18 824.65 623.18 6,016,963.59 570,041.78 1.58 -219.80 2_MWD+IFR2+MS+Sag (2) 12/6/1018 11: 10:30AM Page 3 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 Survey Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU E-35 MPU E-35 Actual @ 48.72usft MPU E-35 Actual @ 48.72usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +NI -S +EI -W Northing Easting DIS Section (usft) (') V) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 3,187.36 27.34 31.67 2,954.92 2,906.20 849.54 638.74 6,016,988.61 570,057.10 1.10 -223.49 2_MWD+IFR2+MS+Sag(2) 3,250.15 26.77 31.93 3,010.84 2,962.12 873.81 653.78 6,017,013.02 570,071.92 0.93 -226.97 2_MWD+IFR2+MS+Sag (2) 3,313.76 28.20 27.24 3,067.27 3,018.55 899.33 668.24 6,017,038.68 570,086.14 4.08 -229.39 2_MWD+IFR2+MS+Sag(2) 3,377.06 28.71 22.53 3,122.93 3,074.21 926.68 680.92 6,017,066.14 570,098.56 3.63 -229.42 2_MWD+IFR2+MS+Sag(2) 3,439.79 28.43 17.94 3,178.03 3,129.31 954.81 691.29 6,017,094.36 570,108.67 3.53 -227.04 2_MWD+IFR2+MS+Sag(2) 3,502.67 28.14 11.45 3,233.42 3,184.70 983.59 698.85 6,017,123.20 570,115.95 491 -221.83 2_MWD+IFR2+MS+Sag(2) 3,565.96 28.79 8.22 3,289.06 3,240.34 1,013.30 703.99 6,017,152.96 570,120.82 2.64 -214.03 2_MWD+IFR2+MS+Sag (2) 3,629.02 30.16 2.95 3,343.96 3,295.24 1,044.16 706.97 6,017,183.84 570,123.52 4.65 -203.80 2_MWD+IFR2+MS+Sag (2) 3,691.02 31.92 356.42 3,397.10 3,348.38 1,076.08 706.75 6,017,215.76 570,123.00 6.12 -190.21 2_MWD+IFR2+MS+Sag (2) 3,754.69 32.91 352.01 3,450.85 3,402.13 1,110.01 703.30 6,017,249.65 570,119.23 4.02 -172.84 2_MWD+IFR2+MS+Sag (2) 3,819.10 33.76 346.08 3,504.68 3,455.96 1,144.72 696.56 6,017,284.30 570,112.17 5.23 -152.16 2_MWD+IFR2+MS+Sag(2) 3,881.18 34.16 341.37 3,556.18 3,507.46 1,177.99 686.84 6,017,317.47 570,102.14 4.29 -129.39 2_MWD+IFR2+MS+Sag (2) 3,944.17 34.69 336.02 3,608.15 3,559.43 1,211.13 673.90 6,017,350.48 570,088.89 4.87 -103.74 2_MWD+IFR2+MS+Sag (2) 4,007.33 36.69 331.74 3,659.45 3,610.73 1,244.18 657.66 6,017,383.38 570,072.34 5.06 -75.13 2_MWD+IFR2+MS+Sag (2) 4,070.51 38.00 330.27 3,709.68 3,660.96 1,277.70 639.07 6,017,416.72 570,053.45 2.51 -44.20 2_MWD+IFR2+MS+Sag (2) 4,133.42 40.07 329.82 3,758.55 3,709.83 1,312.02 619.29 6,017,450.85 570,033.35 3.32 -11.85 2_MWD+IFR2+MS+Sag(2) 4,196.68 41.32 326.30 3,806.51 3,757.79 1,347.00 597.46 6,017,485.62 570,011.20 4.13 22.64 2_MWD+IFR2+MS+Sag(2) 4,259.56 43.06 325.47 3,853.10 3,804.38 1,381.96 573.78 6,017,520.36 569,987.19 2.91 58.81 2_MWD+IFR2+MS+Sag(2) 4,322.74 44.64 324.44 3,898.66 3,849.94 1,417.79 548.64 6,017,555.95 569,961.72 2.74 96.65 2 MWD+IFR2+MS+Sag (2) 4,385.72 47.70 321.36 3,942.28 3,893.56 1,454.00 521.22 6,017,591.89 569,933.97 6.00 136.73 2_MWD+IFR2+MS+Sag (2) 4,449.06 49.21 321.73 3,984.29 3,935.57 1,491.12 491.74 6,017,628.73 569,904.15 2.42 179.06 2_MWD+IFR2+MS+Sag (2) 4,511.52 52.66 318.81 4,023.65 3,974.93 1,528.38 460.73 6,017,665.71 569,872.79 6.61 222.84 2_MWD+IFR2+MS+Sag (2) 4,577.02 54.87 315.43 4,062.37 4,013.65 1,567.07 424.77 6,017,704.05 569,836.48 5.36 271.71 2_MWD+IFR2+MS+Sag(2) 4,639.32 55.92 313.89 4,097.75 4,049.03 1,603.11 388.30 6,017,739.75 569,799.68 2.64 319.94 2_MWD+IFR2+MS+Sag (2) 4,703.14 56.03 311.05 4,133.47 4,084.75 1,638.82 349.29 6,017,775.08 569,760.34 3.69 370.33 2_MWD+IFR2+MS+Sag(2) 4,766.54 57.76 310.74 4,168.09 4,119.37 1,673.58 309.14 6,017,809.47 569,719.88 2.76 421.35 2_MWD+IFR2+MS+Sag (2) 4,829.30 60.84 308.30 4,200.13 4,151.41 1,707.90 267.51 6,017,843.40 569,677.93 5.94 473.54 2_MWD+IFR2+MS+Sag (2) 4,892.46 64.12 306.67 4,229.32 4,180.60 1,741.97 223.07 6,017,877.05 569,633.18 5.67 528.18 2_MWD+IFR2+MS+Sag (2) 4,955.79 67.64 304.75 4,255.19 4,206.47 1,775.69 176.14 6,017,910.33 569,585.94 6.21 584.92 2 MWD+IFR2+MS+Sag (2) 5,018.96 69.65 303.94 4,278.20 4,229.48 1,808.88 127.56 6,017,943.06 569,537.06 3.40 642.94 2_MWD+IFR2+MS+Sag (2) 5,082.24 72.18 301.45 4,298.89 4,250.17 1,841.17 77.24 6,017,974.87 569,486.44 5.46 702.17 2_MWD+IFR2+MS+Sag(2) 5,145.26 75.82 300.79 4,316.26 4,267.54 1,872.47 25.39 6,018,005.69 569,434.31 5.86 762.37 2_MWD+IFR2+MS+Sag (2) 5,208.33 77.40 298.56 4,330.86 4,282.14 1,902.84 -27.92 6,018,035.55 569,380.73 4.26 823.49 2_MWD+IFR2+MS+Sag (2) 5,270.29 78.47 296.99 4,343.81 4,295.09 1,931.07 -81.53 6,018,063.28 569,326.86 3.02 884.00 2_MWD+IFR2+MS+Sag(2) 5,334.12 80.40 295.23 4,355.52 4,306.80 1,958.68 -137.87 6,018,090.37 569,270.27 4.06 946.73 2_MWD+IFR2+MS+Sag (2) 5,397.14 82.78 295.99 4,364.73 4,316.01 1,985.63 -194.08 6,018,116.78 569,213.81 3.96 1,009.06 2_MWD+IFR2+MS+Sag (2) 5,460.03 84.80 295.97 4,371.54 4,322.82 2,013.01 -250.28 6,018,143.64 569,157.37 3.21 1,071.56 2_MWD+IFR2+MS+Sag (2) 5,523.60 84.49 295.47 4,377.47 4,328.75 2,040.48 -307.30 6,018,170.57 569,100.10 0.92 1,134.85 2 MWD+IFR2+MS+Sag (2) 5,585.46 85.59 296.49 4,382.82 4,334.10 2,067.48 J62.70 6,018,197.05 569,044.45 2.42 M 1,196.46 2_WD+IFR2+MS+Sag (2) 5,648.62 86.47 295.61 4,387.19 4,338.47 2,095.10 -419.33 6,018,224.14 568,987.57 2.08 1,259.45 2_MWD+IFR2+MS+Sag(2) 12/62018 11:10:30AM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU E-35 Project: Milne Point TVD Reference: MPU E-35 Actual @ 48.72usfl Site: M Pt E Pad MD Reference: MPU E-35 Actual @ 48.72usft Well: MPU E-35 North Reference: True Wellbore: MPU E-35 Survey Calculation Method: Minimum Curvature Design: MPU E-35 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) 01001) (ft) Survey Tool Name 5,711.90 87.02 294.88 4,390.78 4,342.06 2,121.99 476.50 6,018,250.50 568,930.17 1.32 1,322.63 2_MWD+IFR2+MS+Sag(2) 5,775.27 87.16 295.22 4,394.00 4,345.28 2,148.79 -533.83 6,018,276.76 568,872.59 0.58 1,385.92 2_MWD+IFR2+MS+Sag(2) 5,837.92 84.81 294.75 4,398.39 4,349.67 2,175.18 -590.48 6,018,302.62 568,815.71 3.82 1,448.41 2_MWD+IFR2+MS+Sag (2) 5,900.95 83.44 294.92 4,404.84 4,356.12 2,201.52 -647.38 6,018,328.42 568,758.57 2.19 1,511.10 2_MWD+IFR2+MS+8ag(2) 5,964.33 81.85 294.43 4,412.95 4,364.23 2,227.76 -704.49 6,018,354.13 568,701.22 2.62 1,573.96 2 MWD+IFR2+MS+Sag (2) 6,027.34 81.39 294.40 4,422.14 4,373.42 2,253.52 -761.26 6,018,379.36 568,644.22 0.73 1,636.30 2_MWD+IFR2+MS+Sag (2) 6,090.43 82.50 293.22 4,430.98 4,382.26 2,278.74 -818.41 6,018,404.04 568,586.85 2.55 1,698.75 2_MWD+IFR2+MS+Sag (2) 6,153.14 86.43 294.29 4,437.02 4,388.30 2,303.88 -875.52 6,018,428.65 568,529.50 6.49 1,761.15 2_MWD+IFR2+MS+Sag(2) 6,215.89 89.89 293.05 4,439.04 4,390.32 2,329.06 -932.95 6,018,453.28 568,471.84 5.86 1,823.84 2_MWD+IFR2+MS+Sag(2) 6,242.79 91.53 292.00 4,438.71 4,389.99 2,339.36 -957.80 6,018,463.35 568,446.91 7.24 1,850.72 2_MWD+IFR2+MS+Sag (2) 6,315.51 92.04 291.12 4,436.44 4,387.72 2,366.07 -1,025.40 6,018,489.43 568,379.07 1.40 1,923.28 2_MWD+IFR2+MS+Sag (3) 6,378.78 93.27 290.96 4,433.51 4,384.79 2,388.76 -1,084.38 6,018,511.57 568,319.88 1.96 1,986.35 2_MWD+IFR2+MS+Sag (3) 6,400.00 93.33 291.22 4,432.29 4,383.57 2,396.38 -1,104.15 6,018,519.00 568,300.04 1.26 2,007.49 2_MWD+IFR2+MS+Sag (4) 6,442.27 90.56 292.24 4,430.85 4,382.13 2,412.02 -1,143.39 6,018,534.27 568,260.66 6.98 2,049.67 2_MWD+IFR2+MS+Sag(4) 6,506.24 89.38 291.56 4,430.89 4,382.17 2,435.88 -1,202.74 6,018,557.58 568,201.10 2.13 2,113.56 2_MWD+IFR2+MS+Sag(4) 6,569.40 88.46 291.37 4,432.08 4,383.36 2,458.99 -1,261.51 6,018,580.14 568,142.12 1.49 2,176.60 2_MWD+IFR2+MS+Sag (4) 6,632.82 88.64 293.55 4,433.68 4,384.96 2,483.21 -1,320.10 6,018,603.81 568,083.32 3.45 2,239.94 2_MWD+IFR2+MS+Sag (4) 6,695.79 88.46 294.36 4,435.28 4,386.56 2,508.77 -1,377.62 6,018,628.82 568,025.56 1.32 2,302.88 2_MWD+IFR2+MS+Sag (4) 6,758.75 88.09 295.63 4,437.17 4,388.45 2,535.36 -1,434.66 6,018,654.88 567,968.28 2.10 2,365.81 2_MWD+IFR2+MS+Sag (4) 6,821.03 87.65 296.40 4,439.49 4,390.77 2,562.65 -1,490.59 6,018,681.65 567,912.11 1.42 2,428.04 2_MWD+IFR2+MS+Sag(4) 6,884.19 87.90 296.93 4,441.94 4,393.22 2,590.98 -1,546.99 6,018,709.45 567,855.45 0.93 2,491.11 2_MWD+IFR2+MS+Sag (4) 6,948.24 89.94 297.59 4,443.14 4,394.42 2,620.31 -1,603.91 6,018,738.24 567,798.26 3.35 2,555.09 2_MWD+IFR2+MS+Sag (4) 7,011.67 89.94 297.81 4,443.21 4,394.49 2,649.79 -1,660.07 6,018,767.20 567,741.84 0.35 2,618.44 2_MWD+IFR2+MS+Sag (4) 7,073.49 90.37 297.47 4,443.04 4,394.32 2,678.47 -1,714.84 6,018,795.36 567,686.81 0.89 2,680.18 2_MWD+IFR2+MS+Sag (4) 7,136.05 91.85 296.44 4,441.83 4,393.11 2,706.82 -1,770.59 6,018,823.19 567,630.80 2.88 2,742.68 2_MWD+IFR2+MS+Sag(4) 7,197.93 92.90 295.30 4,439.27 4,390.55 2,733.80 -1,826.22 6,018,849.65 567,574.93 2.50 2,804.50 2_MWD+IFR2+MS+Sag(4) 7,261.02 94.20 292.45 4,435.36 4,386.64 2,759.28 -1,883.79 6,018,874.59 567,517.13 4.96 2,867.45 2_MWD+IFR2+MS+Sag(4) 7,325.76 94.88 291.94 4,430.24 4,381.52 2,783.66 -1,943.55 6,018,898.41 567,457.16 1.31 2,931.92 2_MWD+IFR2+MS+Sag (4) 7,388.89 94.01 291.91 4,425.34 4,376.62 2,807.16 -2,001.93 6,018,921.36 567,398.56 1.38 2,994.78 2_MWD+IFR2+MS+Sag (4) 7,451.83 92.96 292.70 4,421.52 4,372.80 2,831.01 -2,060.05 6,018,944.66 567,340.22 2.09 3,057.54 2_MWD+IFR2+MS+Sag (4) 7,515.00 92.04 293.02 4,418.76 4,370.04 2,855.52 -2,118.21 6,018,968.63 567,281.85 1.54 3,120.62 2_MWD+IFR2+MS+Sag(4) 7,578.37 91.54 292.71 4,416.78 4,368.06 2,880.13 -2,176.57 6,018,992.70 567,223.27 0.93 3,183.92 2_MWD+IFR2+MS+Sag(4) 7,640.85 91.91 293.44 4,414.90 4,366.18 2,904.61 -2,234.02 6,019,016.64 567,165.59 1.31 3,246.34 2_MWD+IFR2+MS+Sag(4) 7,704.05 92.34 294.42 4,412.56 4,363.84 2,930.23 -2,291.75 6,019,041.71 567,107.63 1.69 3,309.49 2_MWD+IFR2+MS+Sag(4) 7,766.22 92.72 293.77 4,409.81 4,361.09 2,955.58 -2,348.45 6,019,066.54 567,050.71 1.21 3,371.59 2_MWD+IFR2+MS+Sag (4) 7,830.57 93.58 294.37 4,406.28 4,357.56 2,981.79 -2,407.11 6,019,092.19 566,991.81 1.63 3,435.84 2_MWD+IFR2+MS+Sag (4) 7,893.35 93.95 294.80 4,402.16 4,353.44 3,007.85 -2,464.08 6,019,117.72 566,934.61 0.90 3,498.48 2_MWD+IFR2+MS+Sag(4) 7,953.99 94.51 295.77 4,397.68 4,348.96 3,033.68 -2,518.76 6,019,143.04 566,879.69 1.84 3,558.96 2_MWD+IFR2+MS+Sag(4) 8,018.63 94.51 296.00 4,392.60 4,343.88 3,061.81 -2,576.73 6,019,170.62 566,821.46 0.35 3,623.38 2_MWD+IFR2+MS+Sag(4) 8,081.41 94.07 296.53 4,387.90 4,339.18 3,089.52 -2,632.87 6,019,197.80 566,765.07 1.10 3,685.97 2_MWD+IFR2+MS+Sag(4) 12/812018 11:10:30AM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt E Pad MPU E-35 MPU E-35 MPU E-35 Local Co-ordinate Reference: Well MPU E-35 ND Reference: MPU E-35 Actual @ 48.72usft MD Reference: MPU E-35 Actual @ 48.72usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (111001) (ft) Survey Tool Name 8,143.30 93.77 296.95 4,383.67 4,334.95 3,117.30 -2,688.02 6,019,225.06 566,709.68 0.83 3,747.68 2_MWD+IFR2+MS+Sag(4) 8,208.66 93.77 297.79 4,379.37 4,330.65 3,147.28 -2,745.93 6,019,254.50 566,651.49 1.28 3,812.83 2_MWD+IFR2+MS+Sag(4) 8,271.23 92.65 298.34 4,375.87 4,327.15 3,176.67 -2,801.06 6,019,283.38 566,596.10 1.99 3,875.20 2_MWD+IFR2+MS+Sag(4) 8,332.57 91.79 29229 4,373.50 4,324.78 31205.27 -2,855.27 6,019,311.47 566,541.63 2.21 3,936.41 2_MWD+IFR2+MS+Sag(4) 8,396.97 90.93 298.37 4,371.97 4,323.25 3,235.33 -2,912.20 6,019,340.99 566,484.42 2.14 4,000.70 2_MWD+IFR2+MS+Sag (4) 8,460.44 89.94 299.63 4,371.48 4,322.76 3,266.10 -2,967.71 6,019,371.24 566,428.64 2.52 4,063.99 2_MWD+IFR2+MS+Sag (4) 8,523.78 89.26 300.32 4,371.93 4,323.21 3,297.74 -3,022.58 6,019,402.37 566,373.48 1.53 4,127.07 2_MWD+IFR2+MS+Sag (4) 8,586.33 90.62 301.39 4,371.99 4,323.27 3,329.82 -3,076.27 6,019,433.94 566,319.50 2.77 4,189.27 2_MWD+IFR2+MS+Sag(4) 8,649.04 91.17 301.49 4,371.01 4,322.29 3,362.53 -3,129.77 6,019,466.14 566,265.70 0.89 4,251.55 2_MWD+IFR2+MS+Sag(4) 8,712.81 91.11 301.91 4,369.74 4,321.02 3,396.03 -3,184.01 6,019,499.14 566,211.15 0.67 4,314.85 2_MWD+IFR2+MS+Sag(4) 8,775.98 90.68 300.99 4,368.76 4,320.04 3,428.99 -3,237.90 6,019,531.58 566,156.97 1.61 4,377.58 2_MWD+IFR2+MS+Sag (4) 8,836.97 89.75 300.06 4,368.53 4,319.81 3,459.96 -3,290.43 6,019,562.07 566,104.15 2.16 4,438.27 2_MWD+IFR2+MS+Sag(4) 8,900.22 88.27 297.22 4,369.62 4,320.90 3,490.27 -3,345.93 6,019,591.85 566,048.38 506 4,501.36 2_MWD+IFR2+MS+Sag(4) 8,963.32 88.95 296.95 4,371.15 4,322.43 3,518.99 -3,402.09 6,019,620.05 565,991.96 1.16 4,564.39 2_MWD+IFR2+MS+Sag(4) 9,027.37 88.39 295.05 4,372.64 4,323.92 3,547.06 -3,459.64 6,019,647.58 565,934.16 3.09 4,628.41 2_MWD+IFR2+MS+Sag (4) 9,090.79 88.21 295.31 4,374.52 4,325.80 3,574.03 -3,517.01 6,019,674.01 565,876.55 0.50 4,691.80 2 MWD+IFR2+MS+Sag (4) 9,153.88 89.51 298.09 4,375.78 4,327.06 3,602.37 -3,573.35 6,019,701.82 565,819.95 4.86 4,754.83 2_MWD+IFR2+MS+Sag(4) 9,216.89 88.39 298.38 4,376.93 4,328.21 3,632.17 -3,628.86 6,019,731.10 565,764.17 1.84 4,817.72 2_MWD+IFR2+MS+Sag(4) 9,280.39 88.40 298.88 4,378.71 4,329.99 3,662.59 -3,684.57 6,019,760.99 565,708.18 0.79 4,881.05 2_MWD+IFR2+MS+Sag (4) 9,343.25 89.57 299.19 4,379.82 4,331.10 3,693.09 -3,739.52 6,019,790.98 565,652.96 1.93 4,943.73 2_MWD+IFR2+MS+Sag(4) 9,406.39 90.68 300.31 4,379.68 4,330.96 3,724.42 -3,794.34 6,019,821.79 565,597.86 2.50 5,006.53 2_MWD+IFR2+MS+Sag (4) 9,469.20 91.73 301.72 4,378.36 4,329.64 3,756.78 -3,848.15 6,019,853.64 565,543.75 2.80 5,069.05 2_MWD+IFR2+MS+Sag (4) 9,532.73 92.35 301.84 4,376.10 4,327.38 3,790.21 3,902.12 6,019,886.57 565,489.47 0.99 5,132.07 2_MWD+IFR2+MS+Sag (4)M 9,595.69 91.73 302.26 4,373.86 4,325.14 3,823.60 -3,955.45 6,019,919.46 565,435.84 1.19 5,194.49 2_WD+IFR2+MS+Sag(4) 9,658.24 90.37 302.72 4,372.71 4,323.99 3,857.20 -4,008.20 6,019,952.56 565,382.78 2.30 5,256.46 2_MWD+IFR2+MS+Sag (4) 9,722.55 89.57 302.36 4,372.75 4,324.03 3,891.79 -4,062.42 6,019,986.64 565,328.25 1.36 5,320.19 2_MWD+IFR2+MS+Sag(4) 9,785.58 89.88 302.79 4,373.05 4,324.33 3,925.72 -4,115.53 6,020,020.07 565,274.83 0.84 5,382.64 2_MWD+IFR2+MS+Sag (4) 9,849.93 89.94 302.77 4,373.15 4,324.43 3,960.56 4,169.63 6,020,054.40 565,220.41 0.10 5,446.36 2_MWD+IFR2+MS+Sag(4) 9,910.95 90.06 302.15 4,373.15 4,324.43 3,993.31 4,221.12 6,020,086.67 565,168.63 1.03 5,506.84 2_MWD+IFR2+MS+Sag (4) 9,972.50 90.74 301.91 4,372.72 4,324.00 4,025.95 -4,273.30 6,020,118.82 565,116.15 1.17 5,567.90 2_MWD+IFR2+MS+Sag(4) 10,038.45 90.68 300.62 4,371.91 4,323.19 4,060.18 -4,329.66 6,020,152.52 565,059.47 1.96 5,633.42 2_MWD+IFR2+MS+Sag(4) 10,100.60 90.74 299.69 4,371.14 4,322.42 4,091.40 -4,383.40 6,020,183.23 565,005.45 1.50 5,695.30 2_MWD+IFR2+MS+Sag(4) 10,164.39 90.25 299.30 4,370.58 4,321.86 4,122.80 4,438.92 6,020,214.11 564,949.65 0.98 5,758.87 2 MWD+IFR2+MS+Sag(4) 10,227.19 91.17 299.72 4,369.81 4,321.09 4,153.73 -4,493.57 6,020,244.53 564,894.72 1.61 5,821.45 2_MWD+IFR2+MS+Sag (4) 10,290.49 92.10 300.53 4,368.00 4,319.28 4,185.49 -4,548.29 6,020,275.77 564,839.70 1.95 5,884.45 2_MWD+IFR2+MS+Sag (4) 10,353.78 92.41 301.22 4,365.51 4,316.79 4,217.94 -4,602.57 6,020,307.72 564,785.13 1.19 5,947.34 2_MWD+IFR2+MS+Sag (4) 10,416.27 91.36 300.92 4,363.45 4,314.73 4,250.17 4,656.07 6,020,339.44 564,731.34 1.75 6,009.42 2_MWD+IFR2+MS+Sag (4) 10,479.92 90.49 300.56 4,362.43 4,313.71 4,282.70 -4,710.77 6,020,371.46 564,676.35 1.48 6,072.72 2_MWD+IFR2+MS+Sag (4) 10,542.55 89.63 300.22 4,362.36 4,313.64 4,314.39 -4,764.79 6,020,402.64 564,622.04 1.48 6,135.05 2 MWD+IFR2+MS+Sag (4) 10,607.21 88.27 297.45 4,363.55 4,314.83 4,345.56 -4,821.42 6,020,433.28 564,565.13 4.77 6,199.53 2_MWD+IFR2+MS+Sag (4) 1 ZSQ018 11:10:30AM Page 6 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 Survey MD Inc Azi TVD TVDSS (usft) V) (u) (usft) (usft) 10,669.55 87.53 295.36 4,365.83 4,317.11 10,732.78 87.28 293.43 4,368.69 4,319.97 10,793.08 87.16 293.31 4,371.62 4,322.90 10,856.86 87.34 293.36 4,374.68 4,325.96 10,922.12 88.21 294.41 4,377.21 4,328.49 10,985.78 88.64 295.07 4,378.96 4,330.24 11,047.74 88.64 294.42 4,380.43 4,331.71 11,111.67 88.58 293.62 4,381.98 4,333.26 11,174.61 88.64 294.79 4,383.51 4,334.79 11,237.67 89.44 296.23 4,384.57 4,335.85 11,300.58 87.59 296.11 4,386.20 4,337.48 11,364.35 88.70 294.67 4,388.26 4,339.54 11,427.48 89.07 294.61 4,389.49 4,340.77 11,490.80 89.57 294.87 4,390.24 4,341.52 11,554.37 89.14 294.92 4,390.96 4,342.24 11,615.93 89.01 294.22 4,391.95 4,343.23 11,679.45 90.19 293.37 4,392.39 4,343.67 11,742.80 90.80 292.81 4,391.85 4,343.13 11,806.14 90.80 292.34 4,390.96 4,342.24 11,869.54 91.05 291.26 4,389.94 4,341.22 11,933.05 92.22 293.06 4,388.13 4,339.41 11,995.63 91.73 294.39 4,385.97 4,337.25 12,058.67 90.55 293.38 4,384.72 4,336.00 12,122.20 90.12 293.31 4,384.34 4,335.62 12,185.08 91.98 294.46 4,383.19 4,334.47 12,248.29 91.60 294.74 4,381.22 4,332.50 12,311.85 91.48 295.18 4,379.51 4,330.79 12,375.26 91.17 295.26 4,378.04 4,329.32 12,438.51 91.85 295.77 4,376.38 4,327.66 12,500.40 91.98 296.35 4,374.31 4,325.59 12,563.76 92.22 296.41 4,371.99 4,323.27 12,626.45 92.41 296.12 4,369.45 4,320.73 12,690.18 92.41 296.81 4,366.77 4,318.05 12,753.63 91.61 296.40 4,364.55 4,315.83 12,816.54 90.49 295.65 4,363.40 4,314.68 12,880.13 90.31 293.77 4,362.95 4,314.23 12,942.95 89.63 291.91 4,362.98 4,314.26 13,006.22 89.38 291.78 4,363.53 4,314.81 13,069.31 89.75 292.64 4,364.01 4,315.29 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map +NI -S +EI -W Northing (usft) (usft) (ft) 4,373.27 -4,877.21 6,020,460.46 4,399.35 4,934.74 6,020,486.01 4,423.24 -4,990.02 6,020,509.38 4,448.48 -5,048.52 6,020,534.07 4,474.88 .5,108.14 6,020,559.91 4,501.51 -5,165.94 6,020,586.00 4,527.44 -5,222.19 6,020,611.40 4,553.46 -5,280.57 6,020,636.87 4,579.25 -5,337.96 6,020,662.13 4,606.41 -5,394.86 6,020,688.75 4,634.14 .5,451.30 6,020,715.95 4,661.47 -5,508.88 6,020,742.74 4,687.79 -5,566.25 6,020,768.52 4,714.28 5,623.75 6,020,794.47 4,741.04 -5,681.41 6,020,820.69 4,766.63 5,737.39 6,020,845.76 4,792.26 -5,795.51 6,020,870.84 4,817.10 -5,853.78 6,020,895.14 4,841.42 -5,912.26 6,020,918.90 4,864.96 -5,971.12 6,020,941.89 4,888.90 -6,029.91 6,020,965.29 4,914.07 -6,087.17 6,020,989.91 4,939.59 -6,144.79 6,021,014.89 4,964.76 -6,203.12 6,021,039.52 4,990.21 -6,260.60 6,021,064.43 5,016.51 -6,318.05 6,021,090.19 5,043.33 -6,375.65 6,021,116.47 5,070.34 -6,433.00 6,021,142.94 5,097.57 -6,490.06 6,021,169.64 5,124.75 -6,545.63 6,021,196.29 5,152.88 -6,602.35 6,021,223.89 5,180.60 -6,658.53 6,021,251.08 5,208.98 -6,715.53 6,021,278.93 5,237.37 -6,772.22 6,021,306.79 5,264.97 -6,828.74 6,021,333.86 5,291.55 -6,886.51 6,021,359.90 5,315.93 -6,944.40 6,021,383.74 5,339.47 -7,003.12 6,021,406.73 5,363.32 -7,061.53 6,021,430.03 13,132.40 91.30 293.59 4,363.43 4,314.71 5,388.09 -7,119.55 6,021,454.25 Well MPU E-35 MPU E-35 Actual @ 48.72usft MPU E-35 Actual @ 48.72usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (u11001) (ft) Survey Tool Name 564,509.08 3.55 6,261.80 2_MWD+IFR2+MS+Sag(4) 564,451.32 3.07 6,324.96 2_MWD+IFR2+MS+Sag(4) 564,395.82 0.28 6,385.17 2_MWD+IFR2+MS+Sag (4) 564,337.10 0.29 6,448.86 2_MWD+IFR2+MS+Sag(4) 564,277.24 2.09 6,514.06 2_MWD+IFR2+MS+Sag(4) 564,219.20 1.24 6,577.69 2_MWD+IFR2+MS+Sag (4) 564,162.71 1.05 6,639.63 2_MWD+IFR2+MS+Sag (4) 564,104.10 1.25 6,703.54 2_MWD+IFR2+MS+Sag (4) 564,046.48 1.86 6,766.46 2_MWD+IFR2+MS+Sag (4) 563,989.33 2.61 6,829.50 2_MWD+IFR2+MS+Sag(4) 563,932.64 2.95 6,892.37 2_MWD+IFR2+MS+Sag(4) 563,874.82 2.85 6,956.10 2_MWD+IFR2+MS+Sag (4) 563,817.21 0.59 7,019.22 2_MWD+IFR2+MS+Sag (4) 563,759.47 0.89 7,082.53 2_MWD+IFR2+MS+Sag (4) 563,701.57 0.68 7,146.10 2_MWD+IFR2+MS+Sag(4) 563,645.36 1.16 7,207.65 2_MWD+IFR2+MS+Sag(4) 563,587.01 2.29 7,271.16 2_MWD+IFR2+MS+Sag(4) 563,528.51 1.31 7,334.48 2_MWD+IFR2+MS+Sag (4) 563,469.81 0.74 7,397.76 2_MWD+IFR2+MS+Sag (4) 563,410.75 1.75 7,461.06 2_MWD+IFR2+MS+Sag (4) 563,351.74 3.38 7,524.48 2_MWD+IFR2+MS+Sag(4) 563,294.26 2.26 7,587.01 2_MWD+IFR2+MS+Sag(4) 563,236.40 2.46 7,650.03 2_MWD+IFR2+MS+Sag(4) 563,177.84 0.69 7,713.53 2_MWD+IFR2+MS+Sag (4) 563,120.13 3.48 7,776.39 2_MWD+IFR2+MS+Sag (4) 563,062.45 0.75 7,839.57 2_MWD+IFR2+MS+Sag (4) 563,004.61 0.72 7,903.11 2_MWD+IFR2+MS+Sag(4) 562,947.01 0.50 7,966.50 2_MWD+IFR2+MS+Sag(4) 562,889.71 1.34 8,029.72 2_MWD+IFR2+MS+Sag(4) 562,833.89 0.96 8,091.56 2 MWD+IFR2+MS+Sag (4) 562,776.92 0.39 8,154.85 2_MWD+IFR2+MS+Sag (4) 562,720.49 0.55 8,217.47 2_MWD+IFR2+MS+Sag (4) 562,663.24 1.08 8,281.12 2_MWD+IFR2+MS+Sag (4) 562,606.28 1.42 8,344.50 2_MWD+IFR2+MS+Sag(4) 562,549.51 2.14 8,407.38 2_MWD+IFR2+MS+Sag(4) 562,491.51 2.97 8,470.97 2_MWD+IFR2+MS+Sag (4) 562,433.40 3.15 8,533.75 2_MWD+IFR2+MS+Sag (4) 562,374.46 0.45 8,596.93 2M_WD+IFR2+MS+Sag (4) 562,315.84 1.48 8,659.95 2 MWD+IFR2+MS+Sag (4) 562,257.60 2.88 8,723.01 2_MWD+IFR2+MS+Sag(4) 12/6201811:10:30AM Page 7 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU E-35 Project: Milne Point TVD Reference: MPU E-35 Actual @ 48.72usft Site: M Pt E Pad MD Reference: MPU E-35 Actual @ 48.72usft Well: MPU E-35 North Reference: True Wellbore: MPU E-35 Survey Calculation Method: Minimum Curvature Design: MPU E-35 Database: NORTH US+CANADA Survey Checked By: Chelsea Wright m`r Approved By: Mitch Laird - '- Date: 12-06-2018 1216/1018 11: f0.30AM Page 8 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 13,194.46 91.67 294.01 4,361.82 4,313.10 5,413.12 -7,176.31 6,021,478.75 562,200.61 0.90 8,785.04 2_MWD+IFR2+MS+Sag(4) 13,257.76 90.56 294.74 4,360.59 4,311.87 5,439.24 -7,233.96 6,021,504.33 562,142.73 2.10 8,848.32 2_MWD+IFR2+MS+Sag (4) 13,320.10 90.00 294.35 4,360.29 4,311.57 5,465.14 -7,290.66 6,021,529.69 562,085.79 1.09 8,910.66 2_MWD+IFR2+MS+Sag (4) 13,383.62 90.56 293.88 4,359.98 4,311.26 5,491.09 -7,348.64 6,021,555.10 562,027.58 1.15 8,974.18 2_MWD+IFR2+MS+Sag (4) 13,447.94 90.37 292.66 4,359.46 4,310.74 5,516.50 -7,407.72 6,021,579.96 561,968.27 1.92 9,038.47 2_MWD+IFR2+MS+Sag (4) 13,510.59 89.32 292.38 4,359.62 4,310.90 5,540.49 -7,465.59 6,021,603.41 561,910.18 1.73 9,101.07 2_MWD+IFR2+MS+Sag(4) 13,573.52 87.84 291.80 4,361.18 4,312.46 5,564.15 -7,523.89 6,021,626.52 561,851.68 2.53 9,163.91 2_MWD+IFR2+MS+Sag(4)M 13,636.39 86.91 293.23 4,364.06 4,315.34 5,588.20 -7,581.90 6,021,650.03 561,793.45 2.71 9,226.66 2_WD+IFR2+MS+Sag (4) 13,699.77 87.16 294.25 4,367.34 4,318.62 5,613.68 -7,639.84 6,021,674.96 561,735.28 1.65 9,289.94 2_MWD+IFR2+MS+Sag (4) 13,762.65 87.59 295.97 4,370.22 4,321.50 5,640.34 -7,696.71 6,021,701.08 561,678.16 2.82 9,352.75 2_MWD+IFR2+MS+Sag (4) 13,824.95 88.52 298.12 4,372.34 4,323.62 5,668.65 -7,752.17 6,021,728.87 561,622.46 3.76 9,414.97 2_MWD+IFR2+MS+Sag (4) 13,889.94 89.20 298.73 4,373.63 4,324.91 5,699.57 -7,809.31 6,021,759.27 561,565.03 1.41 9,479.81 2_MWD+IFR2+MS+Sag(4) 13,953.23 88.89 298.01 4,374.68 4,325.96 5,729.64 -7,864.99 6,021,788.81 561,509.08 1.24 9,542.97 2_MWD+IFR2+MS+Sag(4) 14,015.99 88.46 296.70 4,376.14 4,327.42 5,758.47 -7,920.71 6,021,817.12 561,453.09 2.20 9,605.65 2_MWD+IFR2+MS+Sag (4) 14,079.35 89.14 296.28 4,377.46 4,328.74 5,786.73 -7,977.41 6,021,844.84 561,396.14 1.26 9,668.97 2_MWD+IFR2+MS+Sag (4) 14,142.45 90.12 295.70 4,377.87 4,329.15 5,814.38 -8,034.13 6,021,871.96 561,339.18 1.80 9,732.05 2_MWD+IFR2+MS+Sag (4) 14,205.64 90.43 295.52 4,377.57 4,328.85 6,841.69 -8,091.11 6,021,898.74 561,281.95 0.57 9,795.24 2_MWD+IFR2+MS+Sag (4) 14,268.31 90.43 295.54 4,377.10 4,328.38 5,868.70 -8,147.66 6,021,925.22 561,225.16 0.03 9,857.90 2_MWD+IFR2+MS+Sag(4) 14,332.29 90.74 295.50 4,376.44 4,327.72 5,896.26 -8,205.39 6,021,952.24 561,167.17 0.49 9,921.87 2_MWD+IFR2+MS+Sag(4) 14,395.50 92.34 298.80 4,374.74 4,326.02 5,925.09 -8,261.61 6,021,980.54 561,110.70 5.80 9,984.99 2_MWD+IFR2+MS+Sag (4) 14,45905 90.00 297.75 4,373.45 4,324.73 5,955.19 -8,317.56 6,022,010.11 561,054.47 4.04 10,048.41 2_MWD+IFR2+MS+Sag (4) 14,521.48 89.20 295.88 4,373.88 4,325.16 5,983.35 -8,373.27 6,022,037.74 560,998.50 3.26 10,110.79 2_MWD+IFR2+MS+Sag (4) 14,584.50 89.32 294.79 4,374.70 4,325.98 6,010.31 -8,430.22 6,022,064.17 560,941.31 1.74 10,173.81 2_MWD+IFR2+MS+Sag (4) 14,647.88 88.27 294.95 4,376.03 4,327.31 6,036.96 -8,487.71 6,022,090.28 560,883.58 1.68 10,237.17 2_MWD+IFR2+MS+Sag (4) 14,710.89 89.75 296.32 4,377.12 4,328.40 6,064.22 -8,544.51 6,022,117.01 560,826.54 3.20 10,300.16 2_MWD+IFR2+MS+Sag(4) 14,773.47 91.54 296.87 4,376.41 4,327.69 6,092.23 -8,600.46 6,022,144.49 560,770.33 2.99 10,362.70 2_MWD+IFR2+MS+Sag(4) 14,835.73 93.40 297.24 4,373.73 4,325.01 6,120.52 -8,655.86 6,022,172.26 560,714.68 3.05 10,424.85 2_MWD+IFR2+MS+Sag(4) 14,900.03 94.51 297.30 4,369.30 4,320.58 6,149.91 -8,712.87 6,022,201.12 560,657.40 1.73 10,488.94 2_MWD+IFR2+MS+Sag (4) 14,929.17 94.14 296.41 4,367.10 4,318.38 6,163.04 -8,738.79 6,022,214.00 560,631.36 3.30 10,517.98 2_MWD+IFR2+MS+Sag (4) 15,000.00 94.14 296.41 4,361.98 4,313.26 6,194.46 -8,802.07 6,022,244.83 560,567.80 0.00 10,588.60 PROJECTED to TO Checked By: Chelsea Wright m`r Approved By: Mitch Laird - '- Date: 12-06-2018 1216/1018 11: f0.30AM Page 8 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt E Pad MPU E-35 PB1 41111)"4&*1411-WI] Sperry Drilling Definitive Survey Report 06 December, 2018 HALLIBURTON Sperry Drilling Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: MPU E-35 Wellbore: MPU E-35 PB1 Design: MPU E-35 PB1 Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU E-35 TVD Reference: MPU E-35 Actual @ 48.72usft MD Reference: MPU E-35 Actual @ 48.72usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Iroject Milne Point, ACT, MILNE POINT Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Nap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU E-35 Well Position +N/S +E/ -W Position Uncertainty Wellbore MPU E-35 Pet Magnetics Model Name 0.00 Usti Northing: 6,016,133.24 usfl 0.00 usft Easting: 569,426.37 usfl 0.00 usft Wellhead Elevation: 21.70 usfl Sample Date Declination (I BGGM2018 1211/2018 16.95 Design MPU E-35 PB1 Audit Notes: Version: 1.0 Vertical Section: Phase: ACTUAL Depth From (ND) +NIS (usft) (usft) 27.02 0.00 Latitude: 70° 27' 15.945 N Longitude: 149` 26'0.437 W Ground Level: 21.70 usft Dip Angle Field Strength (°) (nT) 80.98 57,446.86621756 Tie On Depth: 27.02 +EI -W Direction (usft) (°) 0.00 294.80 Survey Program Date 12/4/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 225.00 MPU E-35PBI SDI Gyro (MPU E-35 Pet 2_Gym-NS-GC_Drill toll; H029Ga: North seeking single shot in drill colla 11/20/2018 262.56 6,242.79 MPU E-35PB1 MWD+IFR2+MS+Sag (1) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +as 11/20/2018 6,315.51 6,883.82 MPU E-35PB1 MWD+IFR2+MS+Sag (2) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 11/30/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +EI -W Northing Easting DLS Section (usft) (°) (1 (usft) (usft) (usft) (usft) (ft) (ft) ('1100') (ft) Survey Tool Name 27.02 0.00 0.00 27.02 -21.70 0.00 0.00 6,016,133.24 569,426.37 0.00 0.00 UNDEFINED 100.00 0.14 318.03 100.00 51.28 0.07 -0.06 6,016,133.31 569,426.31 0.19 0.08 2_Gyro-NS-GC_Dnll collar (1 196.00 0.25 319.70 196.00 147.28 0.31 -0.27 6,016,133.55 569,426.09 0.11 0.38 2_Gyn>NS-GC_Dnll collar (1 225.00 0.32 345.87 225.00 176.28 0.44 -0.33 6,016,133.68 569,426.03 0.50 0.49 2Gyro-NS-GC_Drill aollar(1 262.56 0.36 352.06 262.56 213.84 0.66 -0.38 6,016,133.89 569,425.99 0.14 0.62 2_MWD+1FR2+MS+Sag(2) 291.48 0.47 19.21 291.48 242.76 0.86 -0.35 6,016,134.10 569,426.01 0.77 0.68 2_MWD+IFR2+MS+Sag(2) 354.46 2.10 39.09 354.44 305.72 2.00 0.46 6,016,135.24 569,426.81 2.64 0.42 2_MWD+IFR2+MS+Sag(2) 411.99 4.83 37.99 411.86 363.14 4.73 2.62 6,016,137.99 569,428.94 4.75 -0.39 2_MWD+IFR2+MS+Seg (2) 477.28 7.01 35.25 476.80 428.08 10.15 6.61 6,016,143.45 569,432.89 3.37 -1.74 2_MWD+IFR2+MS+Sag (2) 540.16 7.71 36.09 539.16 490.44 16.69 11.31 6,016,150.03 569,437.52 1.13 -3.27 2_MWD+IFR2+MS+Sag (2) 602.91 7.90 34.75 601.33 552.61 23.63 16.25 6,016,157.02 569,442.39 0.42 -0.84 2_MWD+IFR2+MS+Sag (2) 665.39 7.45 42.58 663.25 614.53 30.15 21.44 6,016,163.58 569,447.52 1.82 -6.81 2_MWD+IFR2+MS+Sag (2) 121612018 11:11:58AM Page 2 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: MPU E-35 Wellbore: MPU E-35 PB1 Design: MPU E-35 PB1 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU E-35 MPU E-35 Actual @ 48.72usft MPU E-35 Actual @ 48.72usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (°/100') (ft) Survey Tool Name 569,453.50 2.13 -9.68 2_MWD+IFR2+MS+Sa9 (2) 569,461.09 3.12 -13.49 2_MWD+IFR2+MS+Sag(2) 569,469.99 4.75 -17.54 2_MWD+IFR2+MS+Sag(2) 569,480.72 5.64 -22.02 2_MWD+IFR2+MS+Sag(2) 569,493.10 2.07 -27.18 2_MWD+IFR2+MS+Sag (2) 569,505.82 4.71 -32.11 2_MWD+IFR2+MS+Sag (2) 569,520.37 2.11 -37.76 2_MWD+IFR2+MS+Sag (2) 569,535.94 4.10 44.00 2_MWD+IFR2+MS+Sag(2) 569,552.45 0.42 -50.59 2_MWD+IFR2+MS+Sag(2) 569,568.87 1.99 -57.60 2_MWD+IFR2+MS+Sag(2) 569,586.10 0.07 -65.35 2_MWD+IFR2+MS+Sag (2) 569,603.03 2.00 -72.65 2 MWD+IFR2+MS+Sag (2) 569,620.06 0.51 -79.77 2_MWD+IFR2+MS+Sag (2) 569,637.25 1.02 -87.12 2_MWD+IFR2+MS+Sag (2) 569,654.41 1.43 -94.85 2_MWD+IFR2+MS+Sag(2) 569,671.48 0.77 -102.63 2_MWD+IFR2+MS+Sag(2) 569,687.85 2.12 -109.48 2_MWD+IFR2+MS+Sag(2) 569,703.51 1.29 -115.56 2_MWD+IFR2+MS+Sag (2) 569,717.71 1.66 -120.86 2_MWD+IFR2+MS+Sag (2) 569,733.16 3.37 -126.92 2_MWD+IFR2+MS+Sag (2) 569,749.53 0.38 -133.74 2_MWD+IFR2+MS+Sag(2) 569,765.63 1.10 -140.43 2_MWD+IFR2+MS+Sag(2) 569,782.30 1.83 -147.65 2_MWD+IFR2+MS+Sag(2) 569,799.43 4.74 -154.66 2_MWD+IFR2+MS+Sag (2) 569,816.94 3.80 -160.97 2_MWD+IFR2+MS+Sag (2) 569,834.12 3.01 -166.26 2_MWD+IFR2+MS+Sag (2) 569,850.39 1.09 A70.75 2_MWD+IFR2+MS+Sag (2) 569,866.84 1.01 -175.24 2_MWD+IFR2+MS+Sag (2) 569,883.12 0.98 -179.61 2_MWD+IFR2+MS+Sag(2) 569,899.29 2.05 -183.69 2_MWD+IFR2+MS+Sag(2) 569,915.21 0.83 -187.43 2_MWD+IFR2+MS+Sag (2) 569,931.25 1.16 -191.52 2_MWD+IFR2+MS+Sag (2) 569,947.22 1.31 -195.52 2_MWD+IFR2+MS+Sag(2) 569,963.18 1.05 -199.50 2_MWD+IFR2+MS+Sag(2) 569,979.22 0.41 -203.61 2_MWD+IFR2+MS+Sag(2) 569,995.02 0.59 -207.58 2_MWD+IFR2+MS+Sag(2) 570,010.80 1.04 -211.69 2_MWD+IFR2+MS+Sag (2) 570,026.33 0.86 -215.83 2 MWD+IFR2+MS+Sag(2) 570,041.78 1.58 -219.80 2_MWD+IFR2+MS+Sag (2) 570,057.10 1.10 -223.49 2_MWD+IFR2+MS+Sag (2) 12/&2018 11:11:68AM Page 3 COMPASS 5000.15 Build 91 Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing (usft) (') (') (usft) (usft) (usft) (usft) (ft) 727.12 8.70 45.44 724.37 675.65 36.37 27.47 6,016,169.86 790.86 10.69 45.65 787.19 738.47 43.88 35.13 6,016,177.45 854.48 13.48 40.06 849.40 800.68 53.69 44.13 6,016,187.33 918.21 17.07 40.47 910.87 862.15 66.49 54.98 6,016,200.23 981.86 18.38 40.01 971.49 922.77 81.29 67.50 6,016,215.14 1,042.83 21.12 37.48 1,028.87 980.15 97.37 80.36 6,016,231.34 1,106.76 22.17 39.77 1,088.30 1,039.58 115.78 95.09 6,016,249.89 1,169.21 24.71 38.99 1,145.59 1,096.87 134.99 110.84 6,016,269.24 1,232.46 24.59 39.56 1,203.07 1,154.35 155.41 127.54 6,016,289.81 1,294.24 23.96 42.12 1,259.39 1,210.67 174.62 144.14 6,016,309.18 1,358.16 23.94 42.22 1,317.81 1,269.09 193.85 161.56 6,016,328.57 1,421.24 24.81 40.01 1,375.27 1,326.55 213.47 178.67 6,016,348.34 1,484.48 25.04 40.54 1,432.62 1,383.90 233.80 195.90 6,016,368.83 1,547.85 24.47 41.27 1,490.16 1,441.44 253.86 213.27 6,016,389.05 1,610.75 24.01 43.15 1,547.52 1,498.80 272.99 230.62 6,016,408.34 1,673.55 23.88 42.00 1,604.91 1,556.19 291.75 247.86 6,016,427.26 1,736.79 23.85 38.68 1,662.75 1,614.03 311.25 264.42 6,016,446.91 1,800.55 23.03 38.65 1,721.25 1,672.53 331.05 280.27 6,016,466.86 1,861.40 22.21 37.12 1,777.42 1,728.70 349.52 294.64 6,016,485.46 1,925.03 23.89 40.53 1,835.97 1,787.25 368.90 310.27 6,016,504.98 1,988.26 23.93 39.94 1,893.77 1,845.05 388.47 326.83 6,016,524.70 2,051.33 23.26 40.40 1,951.57 1,902.85 407.76 343.11 6,016,544.14 2,114.87 24.24 41.96 2,009.73 1,961.01 427.01 359.96 6,016,563.55 2,177.90 26.64 37.82 2,066.65 2,017.93 447.80 377.28 6,016,584.49 2,240.73 28.97 36.71 2,122.22 2,073.50 471.13 395.02 6,016,607.98 2,303.49 29.27 32.88 2,177.05 2,128.33 496.20 412.43 6,016,633.21 2,365.20 28.84 33.95 2,230.99 2,182.27 521.22 428.93 6,016,658.38 2,428.27 28.80 32.63 2,286.25 2,237.53 546.63 445.62 6,016,683.95 2,491.43 28.40 33.61 2,341.71 2,292.99 571.95 462.14 6,016,709.42 2,555.01 29.12 31.35 2,397.45 2,348.73 597.76 478.56 6,016,735.37 2,618.33 28.83 32.26 2,452.84 2,404.12 623.82 494.72 6,016,761.59 2,681.71 28.16 32.88 2,508.54 2,459.82 649.31 511.00 6,016,787.22 2,745.11 28.85 31.92 2,564.26 2,515.54 674.85 527.21 6,016,812.91 2,808.36 28.34 32.81 2,619.79 2,571.07 700.42 543.41 6,016,838.63 2,871.81 28.52 32.41 2,675.59 2,626.87 725.87 559.69 6,016,864.22 2,934.77 28.15 32.49 2,731.01 2,682.29 751.09 575.72 6,016,889.59 2,998.09 27.55 33.08 2,786.99 2,738.27 775.96 591.74 6,016,914.60 3,061.15 27.01 32.98 2,843.04 2,794.32 800.19 607.49 6,016,938.98 3,124.12 27.96 32.35 2,898.90 2,850.18 824.65 623.18 6,016,963.59 3,187.36 27.34 31.67 2,954.92 2,906.20 849.54 638.74 6,016,988.61 Well MPU E-35 MPU E-35 Actual @ 48.72usft MPU E-35 Actual @ 48.72usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (°/100') (ft) Survey Tool Name 569,453.50 2.13 -9.68 2_MWD+IFR2+MS+Sa9 (2) 569,461.09 3.12 -13.49 2_MWD+IFR2+MS+Sag(2) 569,469.99 4.75 -17.54 2_MWD+IFR2+MS+Sag(2) 569,480.72 5.64 -22.02 2_MWD+IFR2+MS+Sag(2) 569,493.10 2.07 -27.18 2_MWD+IFR2+MS+Sag (2) 569,505.82 4.71 -32.11 2_MWD+IFR2+MS+Sag (2) 569,520.37 2.11 -37.76 2_MWD+IFR2+MS+Sag (2) 569,535.94 4.10 44.00 2_MWD+IFR2+MS+Sag(2) 569,552.45 0.42 -50.59 2_MWD+IFR2+MS+Sag(2) 569,568.87 1.99 -57.60 2_MWD+IFR2+MS+Sag(2) 569,586.10 0.07 -65.35 2_MWD+IFR2+MS+Sag (2) 569,603.03 2.00 -72.65 2 MWD+IFR2+MS+Sag (2) 569,620.06 0.51 -79.77 2_MWD+IFR2+MS+Sag (2) 569,637.25 1.02 -87.12 2_MWD+IFR2+MS+Sag (2) 569,654.41 1.43 -94.85 2_MWD+IFR2+MS+Sag(2) 569,671.48 0.77 -102.63 2_MWD+IFR2+MS+Sag(2) 569,687.85 2.12 -109.48 2_MWD+IFR2+MS+Sag(2) 569,703.51 1.29 -115.56 2_MWD+IFR2+MS+Sag (2) 569,717.71 1.66 -120.86 2_MWD+IFR2+MS+Sag (2) 569,733.16 3.37 -126.92 2_MWD+IFR2+MS+Sag (2) 569,749.53 0.38 -133.74 2_MWD+IFR2+MS+Sag(2) 569,765.63 1.10 -140.43 2_MWD+IFR2+MS+Sag(2) 569,782.30 1.83 -147.65 2_MWD+IFR2+MS+Sag(2) 569,799.43 4.74 -154.66 2_MWD+IFR2+MS+Sag (2) 569,816.94 3.80 -160.97 2_MWD+IFR2+MS+Sag (2) 569,834.12 3.01 -166.26 2_MWD+IFR2+MS+Sag (2) 569,850.39 1.09 A70.75 2_MWD+IFR2+MS+Sag (2) 569,866.84 1.01 -175.24 2_MWD+IFR2+MS+Sag (2) 569,883.12 0.98 -179.61 2_MWD+IFR2+MS+Sag(2) 569,899.29 2.05 -183.69 2_MWD+IFR2+MS+Sag(2) 569,915.21 0.83 -187.43 2_MWD+IFR2+MS+Sag (2) 569,931.25 1.16 -191.52 2_MWD+IFR2+MS+Sag (2) 569,947.22 1.31 -195.52 2_MWD+IFR2+MS+Sag(2) 569,963.18 1.05 -199.50 2_MWD+IFR2+MS+Sag(2) 569,979.22 0.41 -203.61 2_MWD+IFR2+MS+Sag(2) 569,995.02 0.59 -207.58 2_MWD+IFR2+MS+Sag(2) 570,010.80 1.04 -211.69 2_MWD+IFR2+MS+Sag (2) 570,026.33 0.86 -215.83 2 MWD+IFR2+MS+Sag(2) 570,041.78 1.58 -219.80 2_MWD+IFR2+MS+Sag (2) 570,057.10 1.10 -223.49 2_MWD+IFR2+MS+Sag (2) 12/&2018 11:11:68AM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt E Pad MPU E-35 MPU E-35 PB1 MPU E-35 PB1 Local Co-ordinate Reference: Well MPU E-35 TVD Reference: MPU E-35 Actual @ 48.72usft MD Reference: MPU E-35 Actual @ 48.72usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,250.15 26.77 31.93 3,010.84 2,962.12 873.81 653.78 6,017,013.02 570,071.92 0.93 -226.97 2_MWD+IFR2+MS+Sag(2) 3,313.76 28.20 27.24 3,067.27 3,018.55 899.33 668.24 6,017,038.68 570,086.14 4.08 -229.39 2_MWD+IFR2+MS+Sag(2) 3,377.06 28.71 22.53 3,122.93 3,074.21 926.68 680.92 6,017,066.14 570,098.56 3.63 -229.42 2_MWD+IFR2+MS+Sag(2) 3,439.79 28.43 17.94 3,178.03 3,129.31 954.81 691.29 6,017,094.36 570,108.67 3.53 -227.04 2_MWD+IFR2+MS+Sag(2) 3,502.67 28.14 11.45 3,233.42 3,184.70 983.59 698.85 6,017,123.20 570,115.95 4.91 -221.83 2_MWD+IFR2+MS+Sag (2) 3,565.96 28.79 8.22 3,289.06 3,240.34 1,013.30 703.99 6,017,152.96 570,120.82 2.64 -214.03 2_MWD+IFR2+MS+Sag (2) 3,629.02 30.16 2.95 3,343.96 3,295.24 1,044.16 706.97 6,017,183.84 570,123.52 4.65 -203.80 2_MWD+IFR2+MS+Sag(2) 3,691.02 31.92 356.42 3,397.10 3,348.38 1,076.08 706.75 6,017,215.76 570,123.00 6.12 -190.21 2_MWD+IFR2+MS+Sag(2) 3,754.69 32.91 352.01 3,450.85 3,402.13 1,110.01 703.30 6,017,249.65 570,119.23 4.02 -172.84 2_MWD+IFR2+MS+Sag(2) 3,819.10 33.76 346.08 3,504.68 3,455.96 1,144.72 696.56 6,017,284.30 570,112.17 5.23 -152.16 2_MWD+IFR2+MS+Sag(2) 3,881.18 34.16 341.37 3,556.18 3,507.46 1,177.99 686.84 6,017,317.47 570,102.14 4.29 -129.39 2_MWD+IFR2+MS+Sag(2) 3,944.17 34.69 336.02 3,608.15 3,559.43 1,211.13 673.90 6,017,350.48 570,088.89 4.87 -103.74 2_MWD+IFR2+MS+Sag(2) 4,007.33 36.69 331.74 3,659.45 3,610.73 1,244.18 657.66 6,017,383.38 570,072.34 5.06 -75.13 2_MWD+IFR2+MS+Sag (2) 4,070.51 38.00 330.27 3,709.68 3,660.96 1,277.70 639.07 6,017,416.72 570,053.45 2.51 -44.20 2_MWD+IFR2+MS+Sag (2) 4,133.42 40.07 329.82 3,758.55 3,709.83 1,312.02 619.29 6,017,450.85 570,033.35 3.32 -11.85 2_MWD+IFR2+MS+Sag (2) 4,196.68 41.32 326.30 3,806.51 3,757.79 1,347.00 597.46 6,017,485.62 570,011.20 4.13 22.64 2_MWD+IFR2+MS+Sag(2) 4,259.56 43.06 325.47 3,853.10 3,804.38 1,381.96 573.78 6,017,520.36 569,987.19 2.91 58.81 2_MWD+IFR2+MS+Sag (2) 4,322.74 44.64 324.44 3,898.66 3,849.94 1,417.79 548.64 6,017,555.95 569,961.72 2.74 96.65 2_MWD+IFR2+MS+Sag(2) 4,385.72 47.70 321.36 3,942.28 3,893.56 1,454.00 521.22 6,017,591.89 569,933.97 6.00 136.73 2_MWD+IFR2+MS+Sag(2) 4,449.06 49.21 321.73 3,984.29 3,935.57 1,491.12 491.74 6,017,628.73 569,904.15 2.42 179.06 2_MWD+IFR2+MS+Sag (2) 4,511.52 52.66 318.81 4,023.65 3,974.93 1,528.38 460.73 6,017,665.71 569,872.79 6.61 222.84 2_MWD+IFR2+MS+Sag (2) 4,577.02 54.87 315.43 4,062.37 4,013.65 1,567.07 424.77 6,017,704.05 569,836.48 5.36 271.71 2_MWD+IFR2+MS+Sag (2) 4,639.32 55.92 313.89 4,097.75 4,049.03 1,603.11 388.30 6,017,739.75 569,799.68 2.64 319.94 2_MWD+IFR2+MS+Sag (2) 4,703.14 56.03 311.05 4,133.47 4,084.75 1,638.82 349.29 6,017,775.08 569,760.34 3.69 370.33 2_MWD+IFR2+MS+Sag (2) 4,766.54 57.76 310.74 4,168.09 4,119.37 1,673.58 309.14 6,017,809.47 569,719.88 2.76 421.35 2_MWD+IFR2+MS+Sag(2) 4,829.30 60.84 308.30 4,200.13 4,151.41 1,707.90 267.51 6,017,843.40 569,677.93 5.94 473.54 2_MWD+IFR2+MS+Sag(2) 4,892.46 64.12 306.67 4,229.32 4,180.60 1,741.97 223.07 6,017,877.05 569,633.18 5.67 528.18 2_MWD+IFR2+MS+Sag(2) 4,955.79 67.64 304.75 4,255.19 4,206.47 1,775.69 176.14 6,017,910.33 569,585.94 6.21 584.92 2_MWD+IFR2+MS+Sag(2) 5,018.96 69.65 303.94 4,278.20 4,229.4B 1,808.88 127.56 6,017,943.06 569,537.06 3.40 642.94 2_MWD+IFR2+MS+Sag (2) 5,082.24 72.18 301.45 4,298.89 4,250.17 1,841.17 77.24 6,017,974.87 569,486.44 5.46 702.17 2_MWD+IFR2+MS+Sag (2) 5,145.26 75.82 300.79 4,316.26 4,267.54 1,872.47 25.39 6,018,005.69 569,434.31 5.86 762.37 2_MWD+IFR2+MS+Sag (2) 5,208.33 77.40 298.56 4,330.86 4,282.14 1,902.84 -27.92 6,018,035.55 569,380.73 4.26 823.49 2_MWD+IFR2+MS+Sag (2) 5,270.29 78.47 296.99 4,343.81 4,295.09 1,931.07 -81.53 6,018,063.28 569,326.86 3.02 884.00 2_MWD+IFR2+MS+Sag (2) 5,334.12 80.40 295.23 4,355.52 4,306.80 1,958.68 -137.87 6,018,090.37 569,270.27 4.06 946.73 2_MWD+IFR2+MS+Sag(2) 5,397.14 82.78 295.99 4,364.73 4,316.01 1,985.63 -194.08 6,018,116.78 569,213.81 3.96 1,009.06 2_MWD+IFR2+MS+Sag(2) 5,460.03 84.80 295.97 4,371.54 4,322.82 2,013.01 -250.28 6,018,143.64 569,157.37 3.21 1,071.56 2_MWD+IFR2+MS+Sag(2) 5,523.60 84.49 295.47 4,377.47 4,328.75 2,040.48 -307.30 6,018,170.57 569,100.10 0.92 1,134.85 2_MWD+IFR2+MS+Sag(2) 5,585.46 85.59 296.49 4,382.82 4,334.10 2,067.48 -362.70 6,018,197.05 569,044.45 2.42 1,196.46 2_MWD+IFR2+MS+Sag (2) 5,648.62 86.47 295.51 4,387.19 4,338.47 2,095.10 419.33 6,018,224.14 568,987.57 2.08 1,259.45 2_MWD+IFR2+MS+Sag (2) 5,711.90 87.02 294.88 4,390.78 4,342.06 2,121.99 -476.50 6,018,250.50 568,930.17 1.32 1,322.63 2_MWD+IFR2+MS+Sag(2) 12/82018 11:11:58AM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU E-35 Project: Milne Point TVD Reference: MPU E-35 Actual @ 48.72usft Site: M Pt E Pad MD Reference: MPU E-35 Actual @ 48.72usft Well: MPU E-35 North Reference: True Wellbore: MPU E-35 Pat Survey Calculation Method: Minimum Curvature Design: MPU E-35 PBI Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +El -W Northing Easting DLS Section (usft) (`) (1) (usft) (usft) (usft) (usft) (ft) (ft) ('1100') (ft) Survey Tool Name 5,775.27 87.16 295.22 4,394.00 4,345.28 2,148.79 -533.83 6,018,276.76 568,872.59 0.58 1,38592 2_MWD+IFR2+MS+Sag(2) 5,837.92 84.81 294.75 4,398.39 4,349.67 2,175.18 -590.48 6,018,302.62 568,815.71 3.82 1,448.41 2_MWD+IFR2+MS+Sag(2) 5,900.95 83.44 294.92 4,404.84 4,356.12 2,201.52 -647.38 6,018,328.42 568,758.57 2.19 1,511.10 2_MWD+IFR2+MS+Sag(2) 5,964.33 81.85 294.43 4,412.95 4,364.23 2,227.76 -704.49 6,018,354.13 568,701.22 2.62 1,573.96 2_MWD+IFR2+MS+Sag (2) 6,027.34 81.39 294.40 4,422.14 4,373.42 2,253.52 -761.26 6,018,379.36 568,644.22 0.73 1,636.30 2_MWD+IFR2+MS+Sag (2) 6,090.43 82.50 293.22 4,430.98 4,382.26 2,278.74 -818.41 6,018,404.04 568,586.85 2.55 1,698.75 2_MWD+IFR2+MS+Sag(2) 6,153.14 86.43 294.29 4,437.02 4,388.30 2,303.88 -875.52 6,018,428.65 568,529.50 6.49 1,761.15 2_MWD+IFR2+MS+Sag(2) 6,215.89 89.89 293.05 4,439.04 4,390.32 2,329.06 -932.95 6,018,453.28 568,471.84 5.86 1,823.84 2_MWD+IFR2+MS+Sag(2) 6,242.79 91.53 292.00 4,438.71 41389.99 2,339.36 -957.80 6,018,463.35 568,446.91 7.24 1,850.72 2_MWD+IFR2+MS+Sag(2) 6,315.51 92.04 291.12 4,436.44 4,387.72 2,366.07 -1,025.40 6,018,489.43 568,379.07 1.40 1,923.28 2_MWD+IFR2+MS+Sag(3) 6,378.78 93.27 290.96 4,433.51 4,384.79 2,388.76 -1,084.38 6,018,511.57 568,319.88 1.96 1,986.35 2_MWD+IFR2+MS+Sag (3) 6,441.52 93.46 291.72 4,429.83 4,381.11 2,411.55 -1,142.72 6,018,533.81 568,261.34 1.25 2,048.87 2_MWD+IFR2+MS+Sag (3) 6,504.72 92.84 292.65 4,426.35 4,377.63 2,435.38 -1,201.15 6,018,557.09 568,202.69 1.77 2,111.90 2_MWD+IFR2+MS+Sag (3) 6,568.37 92.78 292.69 4,423.23 4,374.51 2,459.88 -1,259.81 6,018,581.04 568,143.81 0.11 2,175.43 2_MWD+IFR2+MS+Sag (3) 6,631.82 93.52 292.91 4,419.75 4,371.03 2,484.43 -1,318.22 6,018,605.05 568,085.18 1.22 2,238.75 2_MWD+IFR2+MS+Sag (3) 6,695.05 93.89 293.79 4,415.66 4,366.94 2,509.44 -1,376.15 6,018,629.51 568,027.03 1.51 2,301.83 2_MWD+IFR2+MS+Sag (3) 6,758.27 93.83 294.38 4,411.40 4,362.68 2,535.18 -1,433.73 6,018,654.71 567,969.21 0.94 2,364.90 2_MWD+IFR2+MS+Sag (3) 6,821.06 92.41 294.68 4,407.99 4,359.27 2,561.21 -1,490.77 6,018,680.21 567,911.94 2.31 2,427.59 2_MWD+IFR2+MS+Sag (3) 6,883.82 91.11 294.82 4,406.06 4,357.34 2,587.47 -1,547.74 6,018,705.93 567,854.74 2.08 2,490.32 2_MWD+IFR2+MS+Sag(3) 6,954.00 91.11 294.82 4,404.70 4,355.98 2,616.93 -1,611.42 6,018,734.79 567,790.79 0.00 2,560.49 PROJECTEDto TD Checked By: Chelsea Wright Approved By: Mitch Laird == Date: 12-06-2018 12/6/2018 11:11:58AM Page 5 COMPASS 5000.15 Build 91 Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No. MP E-35 Dale Run 27 -Nov -18 County State Alaska Supv. JLoh/ C Montague CASING RECORD Surface v TO 6,282.00 Shoe Depth: 6,277.00 PBTD: Fig. Cut A 28.38 Fig. Balance RKB 27.02 RKB to BHF RKB to CHF RKBto THF Csg Wt. On Hook: 255,000 Type Float Collar: ES Casing (Or Liner) Detail Cap Wt. On Slips: Setting Depths its. Component Size wt. Grade THD Make Length Bottom Top 1 Shoe 95/8 0 Floats Held X Yes No DWC/C DHE 1.60 6,277.31 6,275.71 2 Casing 95/8 40.0 L-80 DWC/C 79.09 6,275.71 6,196.62 1 Float Collar 95/8 '^ Post Flush (Spacer) DWC/C 1.25 6,196.62 6,195.37 1 Casing 95/8 40.0 L-80 DWC/C 39.87 6,195.37 6,155.50 1 Baffle Adapter 95/8 DWC/C 1.41 6,155.50 6,154.09 94 Casing 95/8 40.0 L-80 DWC/C 3,700.53 6,154.09 2,453.56 1 Pup 95/8 40.0 L-80 DWC/C 13.47 2,453.56 2,440.09 1 ESC 95/8 40.0 L-80 DWC/C 12.77 2,440.09 2,427.32 1 Pu 95/8 40.0 L-80 DWC/C 13.86 2,427.32 2,413.46 61 Casing 40.0 1 L-80 DWC/C 2,387.06 2,413.46 26.40 RKB I i i 26.40 26.40 Csg Wt. On Hook: 255,000 Type Float Collar: ES No. Hrs to Run: 40.5 Cap Wt. On Slips: Preflush (Spacer) Type of Shoe: Casing Crew: 2 Rotate Csg X Yes No Recip Csg X Yes No 2.58 Ft. Min. 9.2 PPG Fluid Description: Spud Mud mt retums to surface? _Yes X No Liner hanger test pressure: Type: Type A 0 Floats Held X Yes No Centralizer Placement: Solid Bow Spnngs, Joint 1 10' from ends, Joint 2 Mid Joint, Joint 3 Mid Joint, Joints 425, 27, 29, 31, 33, 35, 37, 39, 41, 43, 176.5 Mixing / Pumping Rate (bpm): 45. 93-97 and 98-107. Tail Slurry CEMENTING REPORT Spud Mud Density (ppg) Shoe @ 6277 FC @ 6,195.00 Top of Liner 46 Preflush (Spacer) Rig Bump Plug? X Yes No Bump press Type: Clean Spacer W/Dye Density(ppg) 10 Volume pumped (BBLs) _ Yes -No % Returns during job Lead Slurry mt retums to surface? _Yes X No Spacerretums? Type: Type A 0 Sacks: 425 Yield: _ Date: Density (ppg) 12 Volume pumped (BBLs) 176.5 Mixing / Pumping Rate (bpm): A Used To Determine TOC: Tail Slurry W Type: Premium G Sacks: 397 Yield: Density (ppg) 15.8 Volume pumped (BBLs) 82 Mixing / Pumping Rale (bpm): '^ Post Flush (Spacer) rc LL Type: Density (ppg) Rate (bpm): Volume: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual / calculated): 46 (psi): 940 Pump used for tlisp: Rig Bump Plug? X Yes No Bump press ig Rotated? _Yes X No Reciprocated? X Yes -No % Returns during job 11 mt retums to surface? _Yes X No Spacerretums? X Yes _No Vol to Surf. 0 ant In Place At: 22:05 Date: 11/28/2018 Estimated TOC: 2,429 A Used To Determine TOC: Stage Tool Stage Collar@ 3440 Type DWC/C Closure OK Yes 'reflush (Spacer) we: Clean Spacer W/ Dye Density (ppg) 10 Volume pumped (BBLs) ead Slurry we: Perm L Sacks: 550 Yield: sity (ppg) Slurry 10.7 Volume pumped (BBLs) 414 Mixing / Pumping Rate (bpm): Premium G Sacks: 270 Yield: ily (ppg) 15.6 Volume pumped (BBLs) 55.8 Mixing / Pumping Rate (bpm): Flush (Spacer) Density (ppg) Rate (bpm): Volume: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual / calculated): 11 (psi): 700 Pump used for tlisp: Rig Bump Plug? X Yes No Bump press 1g Rotated? X No Reciprocated? _Yes X No % Returns during job 1( _Yes ent retums to surface? % Yes _ No Spacer returns? X Yes No Vol to Surf. 271 enl In Place At: 1134 Date: 11/27/2018 Estimated TOC: 0 od Used To Delennine TOC: Surface 4 BilmT aluoka. MA, DATE: 1/16/2019 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 ROP DGR ABG EWR ADR MD & TVD CD: HALLIBURTON 293AN2018 I _Log Viewers I CGM I Definitive Survey I - EMF I. LAS i. PDF TIFF RECEIVED JAN 17 2019 AOGCC 1/15/2019 2:06 PM File folder 1/15/2019 2:08 PM File folder 1/15/2019 2:09 PM File folder 1/15/2019 2:09 PM File folder 1/15/2019 2:09 PM File folder 1/15/2019 2:09 PM File folder 1/15/2019 2:10 PM File folder Please include current contact information if different from above. 21 8152 30 26 0 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: / _ ' 1'/1 /// I Date: 2 1 81 52 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 30 26 1 Anchorage, AK 99503 Tele: 907 777-8337 trl.y,q, A64.. 1,11. Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE: 1/16/2019 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 ROP DGR ABG EWR ADR MD & TVD CD: HALLIBURTON 291AN2018 _Log Viewers I CGM i . Definitive Survey I EMF I LAS i. PDF I TIFF RECEIVED JAN 17 2019 AOGCC 1/15/2019 2:02 PM File folder 1/15/2019 2:03 PM File folder 1/15/2019 2:04 PM File folder 1/15/2019 2:04 PM File folder 1/15/2019 2:04 PM File folder 1/15/2019 2:04 PM File folder 1/15/2019 2:04 PM File folder Please include current contact information if different from above. Please acknowledge r/rceigt by signing and rturn one copy of this transmittal or FAX to 907 777.8510 Received By: / / I // // / / \ I I Date: THE STATE °fALASKA GOVERNOR BILL WALKER Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.oloska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU E-35 Hilcorp Alaska, LLC Permit to Drill Number: 218-152 Surface Location: 3594' FSL, 1720' FEL, SEC. 25, T13N, R10E, UM, AK Bottomhole Location: 797' FNL, 17' FWL, SEC. 23, TI 3N, RI OE, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by Hilcorp Alaska, LLC in the attached application, the following well logs are also required for this well: Gamma ray log required from base of conductor pipe to surface casing shoe. Cased -hole gamma ray log is sufficient. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Hollis S. French k Chair DATED this �� day of November, 2018. STATE OF ALASKA ALA. A OIL AND GAS CONSERVATION COMMIS A PERMIT TO DRILL 20 AAC 25.005 DECEIVED NOV 0 9 2018 1a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas Service - WAG LJ Service - Disp ❑ 1c. SpectiV it/ar@I wipwr4for: Drill Q' Lateral F-1Stratigraphic Test ElDevelopment - Oil Q' Service- Winj ❑ Single Zone Q ` CoalbeJIMLM&~tes El Redrill❑ Reentry❑ Exploratory -Oil ❑ Development -Gas ❑ Service -Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q . Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244. MPU E-35 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 15,000' TVD: 4,353' Milne Point Field Schrader Bluff Oil Pool - 4a. Location of Well (Governmental Section): 7. Property Designation. Surface: 3594' FSL, 1720' FEL, Sec 25, T13N, R10E, UM, AK ' ADL025518, ADL047437 - Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 508' FSL, 2372' FEL, Sec 24, T13N, R10E, UM, AK LONS 94-017 11/15/2018 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 797' FNL, 17' FWL, Sec 23, T13N, R10E, UM, AK 5120 8961'to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 48.2 15. Distance to Nearest Well Open Surface: x-569426 - y- 6016133 . Zone -4 GL / BF Elevation above MSL (ft): 21.7. to Same Pool: -20' MO to MPC -41 L2 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) //,, Maximum Hole Angle: 95.1 degrees Downhole: 1 Surface: I'S .S0/0./ • 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) Cond 20" - X52 Weld 107' Surface Surface 107' 107 ±270ft3 Sig 1 L - 991 ft3 / T - 458 ft3 12-1/4" 9-5/8" 40# L-80 TXP 5,934' Surface Surface 5,934' 4,423' Stg 2 L - 1937 ft3 / T - 314 ft3 Tieback 7-5/8" 29.7# L-80 Hyd 521 5,734' Surface Surface 5,734' 4,405' Tieback Assy. 8-1/2" 6-5/8" 20# L-80 Hyd 563 9,266' 5,734' 4,405' 15,000 4,353' PreDrilled Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (it): Hydraulic Fracture planned? Yes ❑ No ❑� 20. Attachments: Property Plat F BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch B Seabed Report B Drilling Fluid Program e✓ 20 ASC 25.050 requirements ✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hilcor .cora Authorized Title: Drilling Manager Phone: 777-8395 Authorized Signature: G 7 /Contact Dale: l`/ Commission Use Only Permit to Drill ZIg� API Number. '1 � Permit ApprQv r I 20 See cover letter for other Number: 50- v 7— —Z �rif/'� Date: `V J requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coa ed m thane gas hydrates or gas contained in shales: Other: G - �— �-' Samples req'd: Yes ❑ No p�" fe Mud log regd: Yes❑ o 3Doc��s� r3oP e '�� / 3' HzS measures: Yes E, No [( Directional svy req'd: Yes [[�No❑ V O r0$:: Ah w...J ' �— Spacing // exception req'd: Yes ❑ No L_I Inclination -only svy req'd: Yes❑ NI Post initial injection MIT req'd: Yes❑ No❑ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: �JN t�—ty-l� 1/�1DI l J � \ Q JN Submit Form and 4Form 10-401 Revisetl 5/20 This permit is valid for 24 o h o h t a L11 per 20 AAC 25.005() ttechment in Duplicate \\ ,•fir fr�af� � 11,13.18 H Hilcorp Energy Campmy 11.9.2018 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7'h Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU E-35 Dear Commissioner, Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point'E' Pad, well slot 35. Drilling operations are intended to commence approximately Nov 15th, 2018, pending rig move. MPU E-35 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. E-35 is part of an eight well program targeting the Schrader Bluff sand on E -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" pre -drilled liner will be run in the open hole section, and the well produced with an ESP assembly. The Innovation Rig will be used to drill and complete the wellbore. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU E-35, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself (Joe Engel) at 777-8395 or jengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, af 0 o Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) E-35 Drilling Program Version 1 11/9/2018 l Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications .....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 13-5/8" 5M Diverter Configuration.....................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 26.0 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 27.0 14.0 BOP NX and Test.........................................................................................................................26 28.0 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 6-5/8" Production Pre -Drilled Liner...................................................................................31 17.0 Run 7-5/8" Tieback.......................................................................................................................36 18.0 Run ESP Assembly........................................................................................................................39 19.0 RDMO............................................................................................................................................40 20.0 Innovation Rig Diverter Schematic.............................................................................................41 21.0 Innovation Rig BOP Schematic....................................................................................................42 22.0 Wellhead Schematic......................................................................................................................43 23.0 Days Vs Depth................................................................................................................................44 24.0 Formation Tops & Information...................................................................................................45 25.0 Anticipated Drilling Hazards.......................................................................................................47 26.0 Innovation Rig Layout..................................................................................................................49 27.0 FIT Procedure................................................................................................................................50 28.0 Innovation Rig Choke Manifold Schematic................................................................................51 29.0 Casing Design.................................................................................................................................52 30.0 8-1/2" Hole Section MASP............................................................................................................53 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................54 32.0 Surface Plat (As Built) (NAD 27).................................................................................................55 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart ..................................................................56 34.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50...............................................................57 1.0 Well Summary Well MPU E-35 Pad Milne Point "E" Pad Milne Point Unit ESP on 2-7/8" Production Tubing Target Reservoir(s) Schrader Bluff OA Sand E-35 SB Producer 15,000' MD / 4,353' TVD Hilcorp E. c Drilling Procedure 1.0 Well Summary Well MPU E-35 Pad Milne Point "E" Pad Planned Completion Type ESP on 2-7/8" Production Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 15,000' MD / 4,353' TVD PBTD, MD / TVD 14,990' MD / 4,353' TVD Surface Location (Governmental) 3594' FSL, 1720' FEL, Sec 25, TUN, R10E, UM, AK Surface Location (NAD 27) X= 569,426.37, Y= 6,016,133.24 Top of Productive Horizon (Governmental 508' FSL, 2372' FEL, Sec 24, TON, R10E, UM, AK TPH Location AD 27) X= 568,752.83 Y= 6,018,320.44 BHL Governmental 797' FNL, 17' FWL, Sec 23, TUN, R10E, UM, AK BHL AD 27 X= 560,545.00, Y=6,022,224.0 AFE Number 1813045 AFE Drilling Das 18 days AFE Completion Das 9 days AFE Drilling Amount $4,514,520 AFE Completion Amount $2,929583 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1504 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1925 psig Work String 5" 19.5# 5-135 DS -50 & NC 50 KB Elevation above MSL: 26.5 ft + 21.7 ft = 48.2 ft GL Elevation above MSL: 21.7 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 2.0 Management of Change Information 11 Hilcorp Alaska, LLC Hite Changes to Approved Permit to Drill Date: 111812018 Subject: Changes to Approved Permit to Drill for MPU E-35 File #: MPU E-35 Drilling and Completion Program Any modifications to MPU E-35 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. ure Approval: Drilling Manager Date Prepared: Drilling Engineer pate Page 3 Milne Point unit E-35 SB Producer Hilco E Cm2 Drilling Procedure 2.0 Management of Change Information 11 Hilcorp Alaska, LLC Hite Changes to Approved Permit to Drill Date: 111812018 Subject: Changes to Approved Permit to Drill for MPU E-35 File #: MPU E-35 Drilling and Completion Program Any modifications to MPU E-35 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. ure Approval: Drilling Manager Date Prepared: Drilling Engineer pate Page 3 3.0 Tubular Program: 4.0 Drill Pipe Information: ram Cono Milne Point Unit E-35 SB Producer Hilco M X22— Drilling Procedure 3.0 Tubular Program: 4.0 Drill Pipe Information: All casing will be new, PSL I (100% mill inspected, 10% inspection upon delivery). Page 4 ram Cono Surface & 5" 4.276" 3.25' 6.625' 19.5 S-135 GPDS50 36,100 43,100 560klb Production 5" 4.276" 3.25' 6.625' 19.5 S-135 NC50 31,032 34,136 560k1b All casing will be new, PSL I (100% mill inspected, 10% inspection upon delivery). Page 4 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers .hilcorp, iengel@hilco!12.com and cdinger(a�hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mm, ers ehilcorp,com jensel@hilcorp.com and cdinger@hilcoip.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcorp.com ieneel@hileoM.eom and edinger cnr hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Milne Point Unit Drilling Manager Monty Myers 907.777.8431 E-35 SB Producer mmvers@hilcorp.com Hilc{y E1 -21T Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers .hilcorp, iengel@hilco!12.com and cdinger(a�hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mm, ers ehilcorp,com jensel@hilcorp.com and cdinger@hilcoip.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcorp.com ieneel@hileoM.eom and edinger cnr hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmvers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 ien¢el@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.907.9533 twellman@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kflemin¢@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdineer@hilcorp.com Page 5 Milne Point Unit Type E-35 SB Producer ID Hil 2x Drilling Procedure E gyC 20" 6.0 Planned Wellbore Schematic 11811 rmn .11:wLa, LLI Or -g. KB Elam: 26.5'(In-w or$ Page 6 Milne Point Unit Well: MPUE-35 SCHEMATIC Last Completed: PTD: xxx-xxx TREE & WELLHEAD CEMENT DETAIL Size Type Vy Grade/ Conn ID Top 20" Conductor -/X-52/We10eA N/A Surtace 9-5a.. SurfaceI 40/480/T(P 8.835 Surface 7-5/8" 1 Tieback I 29J/L-E0/jbg521 6.815 Surface 1 6-5/8" liner 20/L-B0/tb jS63 6.049 ±5442' v 5 TUBING DETAIL Upper Tandem ftm,,: 62 STG FL 17.5 6 WELL INCLINATION DETAIL 6-5/B" Predrilletl Dner Detail 6-£B"14edrs�ad v 3/3"holes 1 .62i'k7.75"9oatm"cem;" xOP � 43' Maz Hale Angle =939 de& � 13 458• ' IEWELRY DETAIL No Depth Item 1 ±131' 61a 82: GL W V Sitle Pocket IGIMM w( Orifice 2 ±5,000' Up %1: GLM - 1" w/ Dummy 3 ±5 35(Y 2-7/8" xN-Nrpple (2-205 No-gd ID) 4 ±5442' DisMarge Head: FFNS 5 ±5,443' Upper Tandem ftm,,: 62 STG FL 17.5 6 K465' Lnwer Tandem Pump: 134 STG FUD( 17.5 7 ±5489' Gas SeparatorGRSFERNAR 8 ±5,492' U per Tantlem SeaI:G583D8UTS8/SBPFSA 9 ±5,499' Lower Tandem Seal: 65830BUTSB%SSPRA 10 ±5,506' Motor.CLSx—2006p/363W/34A 11 ±5,518' Sensor, 2enhh S/S T812629 12 ±5,521' C Aralrser: Bm. @ 2,985' 13 ±6,00V BOTSLZXPIiner Top M./SDSIip.,7"x95/B" 14 ±6,03' Crossaver5ub, 7"H563 x6.625" 563 15 ±14,935' Gossover Sub, 6.625" 563x4.5" 16 ±14,94' 41/2 Sub 17 ±14 7C It WN Valve wnh 2" Bah an Seat SS ±14,975' Round Nose Float Slave: GENERAL WELL INFO API:5t1-029-xxaa-DO-OD Orllletl Cued and Com Irmovetian - 6-5/B" Predrilletl Dner Detail 6-£B"14edrs�ad v 3/3"holes 1 .62i'k7.75"9oatm"cem;" n Hilcorp Ene C T— 7.0 Drilling / Completion Summary Milne Point Unit E-35 SB Producer Drilling Procedure MPU E-35 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. E-35 is part of an eight well program targeting the Schrader Bluff sand on E -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" pre -drilled liner will be run in the open hole section and the well produced with an ESP assembly. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately Nov 15, 2018, pending Innovation rig move back from Endicott. Surface casing will be run to 5,934' MD / 4,423' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface arenot oTserved, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations: 1. MIRU Innovation to well site 2. N/U & Test 13-5/8" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing. 4. N/D diverter, N/U & test 13-5/8" x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 6-5/8" production liner. 6. Run 7-5/8" tieback. 7. Run production tubing. 8. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 7 Milne Point Unit E-35 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU E-35. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. GI,— • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources -1 • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: Hilcorp Alaska LLC does not request any variances at this time. Page 8 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12 1/4" Milne Point Unit Function Test Only • 13-5/8" x 5M Control Technology Inc Annular BOP E-35 SB Producer He Hilco Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12 1/4" 13-5/8" 5M CTI Annular BOP w/ 16" diverter line Function Test Only • 13-5/8" x 5M Control Technology Inc Annular BOP • 13-5/8" x 5M Control Technology Inc Double Gate Initial Test: 250/3000 o Blind ram in him cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" • 13-5/8" x 5M Control Technology Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg(a)alaska.gov Guy Schwartz / Petroleum Engineer/ (0): 907-793-1226 /(C): 907-301-4533 / Email: M.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loeppna alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-xxx-xxxx / Email: melvin.rixsengalaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: hn://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 U Hilcorp E . �' 1T 9.0 R/U and Preparatory Work Milne Point Unit E-35 SB Producer Drilling Procedure 9.1 E-35 will utilize a newly set 20" conductor on E Pad Expansion. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Set test plug in wellhead prior to NIU diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Ensure 5" liners in mud pumps. • White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 10 10.0 N/U 13-5/8" 5M Diverter Configuration 10.1 N/U 13-5/8" CTI BOP stack in diverter configuration (Diverter Schematic attached to program). • N/U 20" x 13-5/8" DSA • N/U 13 5/8", 5M diverter "T". • NU Knife gate & 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. • Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 11 J Milne Point Unit E-35 SB Producer Hilco+w F. it Co p.oy Drilling Procedure 10.0 N/U 13-5/8" 5M Diverter Configuration 10.1 N/U 13-5/8" CTI BOP stack in diverter configuration (Diverter Schematic attached to program). • N/U 20" x 13-5/8" DSA • N/U 13 5/8", 5M diverter "T". • NU Knife gate & 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. • Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 11 J 10.5 Rig & Diverter Orientation: 13 ■ ■ 5 26 ■ ■ 30 9 ■ ■ 6 25 ■ ■ 21 11 ■ ■ 7 18 ■ ■ 16 20 ■ ■ 23 24 ■ ■ 19 14 ■ 12 15 ■ 0 17 E—E-35 —36 E-4141 Page 12 E-37 E-36 i E-351- 75' -351 75' Radius Clear of Ignition Sources Diverter Line MPU E Pad Expansion "Drawing Not To Scale Milne Point Unit E-35 SB Producer Hilco E.. �,m Drilling Procedure 10.5 Rig & Diverter Orientation: 13 ■ ■ 5 26 ■ ■ 30 9 ■ ■ 6 25 ■ ■ 21 11 ■ ■ 7 18 ■ ■ 16 20 ■ ■ 23 24 ■ ■ 19 14 ■ 12 15 ■ 0 17 E—E-35 —36 E-4141 Page 12 E-37 E-36 i E-351- 75' -351 75' Radius Clear of Ignition Sources Diverter Line MPU E Pad Expansion "Drawing Not To Scale 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135. • Run a solid float in the surface hole section. 11.2 5" Drill string, HWDP, and Jars will come from Weatherford. 11.3 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if run through high dog legs. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure to leave a "Pump Tangent" section that is awrox. 300' long in the directional plan. The ESP will need a straight section to sit. Target location of ESP pump tangent is 1000' MD and 200' TVD above target reservoir. • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). Page 13 U Milne Point unit E-35 SB Producer HHilcorp Comyny Drilling Procedure 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135. • Run a solid float in the surface hole section. 11.2 5" Drill string, HWDP, and Jars will come from Weatherford. 11.3 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if run through high dog legs. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure to leave a "Pump Tangent" section that is awrox. 300' long in the directional plan. The ESP will need a straight section to sit. Target location of ESP pump tangent is 1000' MD and 200' TVD above target reservoir. • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). Page 13 • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. • Gas hydrates have been encountered on E -Pad, typically around 2100-2400' TVD (fust below permafrost). Be prepared for hydrates: • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Past wells on E pad have increased MW to 9.8 ppg and added 1-1.5ppb of Lechithin & .5% lube. After drilling through hydrate sands, MW was cut back to normal • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. • Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. 11.5 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW Surface — Base Permafrost 8.9+ . Base Permafrost - TD 9.8 (For Hydrates) MW can be cut once —500' below hydrate zone • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. Page 14 Milne Point Unit E-35 SB Producer Hilco Hi. _� Drilling Procedure • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. • Gas hydrates have been encountered on E -Pad, typically around 2100-2400' TVD (fust below permafrost). Be prepared for hydrates: • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Past wells on E pad have increased MW to 9.8 ppg and added 1-1.5ppb of Lechithin & .5% lube. After drilling through hydrate sands, MW was cut back to normal • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. • Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. 11.5 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW Surface — Base Permafrost 8.9+ . Base Permafrost - TD 9.8 (For Hydrates) MW can be cut once —500' below hydrate zone • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. Page 14 U Hilcorp E.'= Milne Point Unit E-35 SB Producer Drilling Procedure • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 - 9.8 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties. Section Density Viscosity Plastic Viscosity Yield Point I AN FL I pH I Tem Surface 1 8.8-9.8-1 75-175 1 20-40 1 25-45 1 <10 1 8.5 - 9.0 1 <- 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.2 ppg PAC -L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb 11.6 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.7 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.8 TOOH and LD BHA jJ Sf 11.9 No open hole togging program planned. Page 15 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint— 9-5/8" DWC, 2 Centralizers 10' from each end w/ stop rings Milne Point Unit — 9-5/8" DWC, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' E-35 SIR Producer — 9-5/8" DWC, 1 Centralizer mid joint with stop ring Hilc-nrPo � Drilling Procedure 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint— 9-5/8" DWC, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" DWC, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" DWC, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. z Page 16 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual Secfi m 5 Page 17 "A RiYmp ES -Il guriurg Order Part No. ff Milne Point Unit Shut Oe Plug M.. ID After Dnllout E-35 SB Producer OD Hil ...42 Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual Secfi m 5 Page 17 "A RiYmp ES -Il guriurg Order Part No. (hwall length B Shut Oe Plug M.. ID After Dnllout C OD Max. Twl OD D OD I Opening Seat ID E Shut -oft Plug closirg Seat ID Plug Set RiYmp ES -Il guriurg Order Part No. E$41 Eemenur SO No. Shut Oe Plug Closing Plug OD Opening Plug L l r OD I OD Shut -oft Plug OD Bypass Plug (fl used) Do RiYmp ES -Il guriurg Order E$41 Eemenur ,,��^^^ Shut Oe Plug Baffle AEaper By -Pass Plug L l r I By Pae. BzfBe Roat wie, r1k,ed shoe Milne Point Unit E-35 SB Producer Drilling Procedure 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu) • Verify depth of lowest UP.nu water sand for isolation with Geologist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H E II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). • Install centralizers over couplings on 5 joints below and 10 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 GEOMETRY Threads per. 5 Cmnection 00 00cn REGULAR PERFORMANCE Nominal .^._ Nominal It: 9.625in. 8.835 in Nominal Vraieht WaIThickness 40 lbmt x395.. Milne Point Unit 8.679 in. 32.97 tat Ibs Compression EScienry 100 % E-35 SB Producer 919.000 X1000 HilcQ Its Drilling Procedure E , ��P TXPC BTC . ,. 11IOW2018 Outside Diameter 9625 in Mia Wall 87.5% Thickness I")Grade LOD low Type 1 Wall Thickness 0.39511. Connect.. OD REGULAR Option COUPL.IO PIPE BODY Ecd( Red 1st Sand: Red Grade L80 Type 1• Orih API Standaw 1st earl: Broom 2nd Sand. 2nd Ba cr - Brown Type Casing 3n! Sand: - 3m Band: - 4th Eand: - GEOMETRY Threads per. 5 Cmnection 00 00cn REGULAR PERFORMANCE Nominal .^._ Nominal It: 9.625in. 8.835 in Nominal Vraieht WaIThickness 40 lbmt x395.. Drift Plir, End Might 8.679 in. 32.97 tat OD Totannce API PERFORMANCE Body Yekl Stergti 91fi X10001bs Internal Yet 5750 psi SMYS 00000 psi Coaatse 3080 psi GEOMETRY Conaact.n OD 10.025 in. CPupling Length 10925.. Connection ID 8.823 in Make-up'1Pss 4.331 in. Threads per. 5 Cmnection 00 00cn REGULAR PERFORMANCE Tem -ion Eftiency 100.0% . ,nz YOM SmNth 916BOB X1000 Internal Pressure Capacay 1. 5750.000 psi Ibs Compression EScienry 100 % C.ampn smn Strangth 919.000 X1000 Max. Allowable Bending 311 `1100 ft Its Ed..[ res:+"re CaPacrtd 3090.000 psi MAKE-UPTORQUES Maimum 18860 ft -lbs Opthnum 20960 Nds Maxnnum 23060 VA, OPERATION LIMIT TORQUES Operet.g T«tea 35600 R-Sz Yeld Torque 43400 hobs Notes — This connection is fully interchangeable with TXP& BTC - 9 6251n_ - 36143.5147 y 53.5158.4 IbsAl [1) Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3 ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tanana technical sales representative. Page 19 H Hilcorp �w ��, Milne Point Unit E-35 SB Producer Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 U Hilcorp E,Compmy 13.0 Cement 9-5/8" Surface Casing Milne Point Unit E-35 SB Producer Drilling Procedure 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) - HEC rep to witness. Mix and pump cement per below calculations for the I" stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated I" Stage Total Cement Volume: b4L c� Page 21 5'k 23D -?qH 12-1/4" OH x 9-5/8" (4,934'- 2500') x .0558 bpf x 1.3 = 176.5 991.3 J Casing Total Lead 176.5 991.3 12-1/4" OH x 9-5/8" (5,934'- 4,934') x.0558 bpf x 1.3 = 72.5 407 Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 5'k 23D -?qH U Hilcorp Ucmy r Milne Point Unit E-35 S8 Producer Drilling Procedure Cement Slurry Design (1St Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5814'x.0758 bpf = 440.7 bbls 40 bbls of weighted space to be left behind stage tool, confirm space is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, f4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Page 22 Lead Slurry Tail Slurry System ExtendaCEM 'm System SwiftCEM '"' System Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk ✓ 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 5814'x.0758 bpf = 440.7 bbls 40 bbls of weighted space to be left behind stage tool, confirm space is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, f4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Page 22 U Bile C22> Milne Point Unit E-35 SB Producer Drilling Procedure 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 U Hilcorp Enee®Ca T Second Stage Surface Cement Job: Milne Point Unit E-35 SB Producer Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2"d stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2"1 Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): SecILead Calculation Vol (bbl) Vol (ft3) SwiftCEM T" System (Hal Cem) 20" Conductoring (110') x .26 bpf x 1= 28.6 161 v 12-1/4" OH x (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 J Total 345 1937 12-1/4" OH x (2500'- 2000') x .0558 bpf x 2 = 55.8 314 Tota 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 "/ Lead Slurry Tail Slurry System Permafrost L SwiftCEM T" System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Page 24 "/ H Hilcorp soma,, Milne Point Unit E-35 SB Producer Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping ofjob. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run" casing tally & casing and cement report to 'e� nyel(2hilcorp. com and cdinger&hilcoW.corn This will be included with the EOW documentation that goes to the AOGCC. V/ Page 25 Milne Point unit E-35 SB Producer Hilcoorp Drilling Procedure rp 14.0 BOP N/U and Test 14.1 N/D the diverter T, 16" knife gate, 16" diverter line & N/U 11" x 13-5/8" 5M casing spool. N/U 13-5/8" x 5M CTI BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8'x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5.5" VBRs in top cavity, blind ram in bottom cavity. • Single ram should be dressed with 2-7/8" x 5.5" VBRs or 5" Solid Body Rams (� • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to mud cross) 14.3 Run 5" BOP test plug (if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.4 R/D BOP test equipment 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.7 Set wearbushing in wellhead. 14.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.9 Ensure 5" liners in mud pumps. Page 26 U Hilcorp Enema' CompmY 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.220 PDM) Milne Point Unit E-35 SB Producer Drilling Procedure 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tag ge on morning report. fA 15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = —3500 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. (\ Document incremental volume pumped (and subsequent pressure) and volume returned. IM-21U,9ZOUffi: XB N[�TiT•SSii is/1 15.9 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# 5-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Page 27 V/ Milne Point Unit E-35 SB Producer Drilling Procedure • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg Baradrill-N drilling fluid Properties: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT Production 1 8.9-9.5 `. 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Product Concentration Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N -VIS 1.0 — 1.5 ppb DEXTRID LT 5 ppb BARACARB 5 4 ppb BARACARB 25 4 ppb BARACARB 50 2 ppb BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.015 ppb Page 28 n Hilcorp sn<Br comv+�r 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid Milne Point Unit E-35 SB Producer Drilling Procedure 15.13 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to undulate between Schrader OAl & OA3 lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes • Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. • Target ROP is as fast as we can clean the hole without having to backream connections • Schrader Bluff OA Concretions: 5-10% of lateral L-47: 6%, L-50 9.5% F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. Page 29 H Hilcorp Eon 4T— Milne Point Unit E-35 SB Producer Drilling Procedure 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed • Once well has TD'd the production lateral, swalto the completion AFE • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary • Ensure mud has necessary lube % for running liner • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm max). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 —10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe 15.18 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.19 Monitor well for flow. Increase mud weight if necessary Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.20 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.21 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. i Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. 11 V Page 30 Milne Point unit E-35 SB Producer Hileorp Drilling Procedure 16.0 Run 6-5/8" Production Pre -Drilled Liner V/ 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 6- 5/8" pre drilled liner, the following well control response procedure will be followed: • P/U & M/U the 5" safe�tyj.Qint (with 6-5/8" crossover installed on bottom, TIW valve in open position on top, 6-5/8" handling joint above TIW). This joint shall be fully NIX and available prior to running the first joint of 6-5/8" Predrilled liner. • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. • Proceed with well kill operations. 16.2. Well control preparedness: In the event of an influx of formation fluids while running the 3- 1/2" inner string inside the 6-5/8" pre drilled liner: • P/U & M/U the 5" safety joint (with 6-5/8" x 3-1/2" triple connect crossover installed on bottom, TIW valve in open position on top, 3-1/2" handlingjoi— nt above TIW). M/U 3-1/2" and then 6-5/8" to triple connect. • This joint shall be fully M/U with crossovers prior to running the first joint of wash pipe. • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.3. R/U 6-5/8" pre -drilled liner running equipment. • Ensure 6-5/8" 20# Hydril 563 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.4. Run 6-5/8" pre -drilled production liner • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run packoff and float shoe on bottom. • 6-5/8" pre -drilled liner will auto –fill • 6-5/8" Liner will be centralized with 1/joint free floating • If needed, install swell packers as per the lower completion tally. • Remove protective packaging on swell packers just prior to picking up • Do not place tongs or slips on the packer element 6-5/8" 20 # Hvdril 563 Torque OD Minimum Optimum Maximum Yield Torque 6-5/8 5,900 ft -lbs 7,100 ft -lbs 1 10,300 ft -lbs 36,000 ft -lbs Page 31 J H Hileorp Eonp-21T Wedge 5630 Ia Milne Point Unit E-35 SB Producer Drilling Procedure r.--11AW2016 oelside DiameAer &w5n. Min -Wall 975+. ( GEOMETRY Thickness f9 Grade LOO am 20AOILmp OBIt 5.939:n Vim wlll Lm.:, Tyw I 0.3a9.n Wall Thickness 0299 n. COrsectron OD REGULAR Mil.. --up Locs k050sn. T9maniperlo PERFORMANCE Option REGULAR COWLING YPEBOOY ewr Ysad sv4mm 459,tcc0ros umpmm tlmd 60900.. Gcq Red 1 n Band. Red Grady Los Type 1- Drift Apo Standard 1zi Bad: Brown 2nd Bard: 2M Bard-. • or. TYp^ Casing 3b Baas - frd 8.M - Caroms .. Efl, r., 100-6 ?. dth Bard. - �.47A ( GEOMETRY GEOMETRY NpmirelOG 6.fi23:n. Npm:nal'KpiaM 20AOILmp OBIt 5.939:n Vim wlll Lm.:, Wa114M1r.4ness 0.3a9.n a.,1 End tVery:: 1951 Rim GG Tel... API Mil.. --up Locs k050sn. T9maniperlo PERFORMANCE Corm.['. Go Odw REGULAR PERFORMANCE ewr Ysad sv4mm 459,tcc0ros umpmm tlmd 60900.. 9HT5 80000 psi eplar-a Sara e.l Notes Ttus connection is fully interchangeable with: Wedge 563P, - 6.625 in. - 24 ! 28132 Ihslit connections wnh DopelessO Technology are fully compatible with the same connection in its Standard version Page 32 GEOMETRY Cunnactn-:CG T300:n. CpuPh+g lgnAN 9.391n. COnnD[Ilan 10 9999.n Mil.. --up Locs k050sn. T9maniperlo 399 Corm.['. Go Odw REGULAR PERFORMANCE w,) T.,. i. Met., 917 Jew Yaw 51rm-9m 939363.1" a iol PRs:Bm Cowav 6dw0 pl. Its Caroms .. Efl, r., 100-6 ?. GnmDmsibn sump': 059!00 s100] Mar A(cWaa'CEe,419 526'Mwh 16s 1 £alerNl Frowue ciipa.lh ]aT0A00 pa Caapi ea Face Load 3190003c 1v MAKE-UP TORQUES Bkmmum 33"1—es apnmum r100 A.ns Ma.�mum 10301 n.ro: OPERATION umrr TORQUES Opavalbq T«o oe 31000taes vwW TM. 36000 BUCK -ON Mnimum 10000A los •'-'mum 11300 9-21 Notes Ttus connection is fully interchangeable with: Wedge 563P, - 6.625 in. - 24 ! 28132 Ihslit connections wnh DopelessO Technology are fully compatible with the same connection in its Standard version Page 32 6-5/8" Lower Completion Running Order 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8" connection. 16.7. RAJ false rotary and run 3-1/2" 9# Inner String • Ensure inner string is drifted for WIV closing ball OD 16.8. Before picking up Baker ZXP liner hanger/ packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.9. M/U Baker ZXP liner top packer to inner string and 6-5/8" liner. Fill liner tieback sleeve with "Xanplex", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note PUW, SOW, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/ liner on 5" HWDP no faster than 30 ft/min — this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The inner string will prevent the DP from auto filling. Fill DP with mud every 5 stands, more frequently if SOW trend indicates. 16.13. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 rpm 16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.17. Rig up to pump down the work string with the rig pumps. NOTE: The wellbore will be swapped over to brine after the liner has reached TD to remove mud cake from the well bore. Mud cake will cause facility upsets. Page 33 d Milne Point Unit E-35 SB Producer Hilcorp Ele C22 Drilling Procedure 6-5/8" Lower Completion Running Order 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8" connection. 16.7. RAJ false rotary and run 3-1/2" 9# Inner String • Ensure inner string is drifted for WIV closing ball OD 16.8. Before picking up Baker ZXP liner hanger/ packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.9. M/U Baker ZXP liner top packer to inner string and 6-5/8" liner. Fill liner tieback sleeve with "Xanplex", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note PUW, SOW, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/ liner on 5" HWDP no faster than 30 ft/min — this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The inner string will prevent the DP from auto filling. Fill DP with mud every 5 stands, more frequently if SOW trend indicates. 16.13. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 rpm 16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.17. Rig up to pump down the work string with the rig pumps. NOTE: The wellbore will be swapped over to brine after the liner has reached TD to remove mud cake from the well bore. Mud cake will cause facility upsets. Page 33 d Milne Point Unit E-35 SB Producer Drilling Procedure 16.18. Break circulation and circulate out the mud. Begin circulating at —1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. Displace well to brine (-9.2 ppg KCl/NaCI). , over displace well by at least 100+ bbl. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. 16.19. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the swell packers (if run). Do not exceed 1,600 psi while circulating as noted above. Note all losses. Confirm all pressures with Baker. 16.20. Mix and pump 40 bbl 10 ppb SA -PP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 16.21. Displace 1.5 OH + Liner volume. 16.22. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.23. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. to 2700 usi to set the for 5 minutes. Slack off 20K lbs on the Flexlock liner hanger to ensure the HRDE setting tool is in compression for release from the ZXPN liner hanger/packer. Continue pressuring up 4500 psi to activate the hydraulic pusher tool to set the ZXPN packer. This will also release the HRDE running tool. 16.25. Bleed DP pressure to zero. Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.26. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.27. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.28. P/U pulling 3-1/2" out of the pack off & displace out liner with two volumes at max rate. Note: Flexlock Liner Hanger & separate packer will be run on E-35, with a hydraulic running tool with exposed ports that may inhibit circulation through the toe of the 3-1/2". 16.29. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 3-1/2" inner string. Leave enough 5" DP racked back to trip back to 9- 5/8" shoe. Page 34 H Hilcorp Erctgy Compoy Milne Point Unit E-35 SB Producer Drilling Procedure 16.30. M/U 3.5" wash tool & RIH w/ remaining DP out of derrick to liner top. 16.31. Wash through liner top at max rate & circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.32. POOH & L/D remaining 5" HWDP. Page 35 H Hilcorp Ercrp Compmy 17.0 Run 7-5/8" Tieback Z Milne Point Unit E-35 SB Producer Drilling Procedure 17.1 RIH with mule shoe on 5" DP to Liner Top and circulation Liner Top and SBE clean. POOH. 17.2 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7-5/8" (250/3000 psi) solid body casing rams. 17.2 R/U 7-5/8" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. • Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. 17.3 P/U tieback seal assembly and set in rotary table. Ensure 7-5/8" seal assembly has x4 1" holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7-5/8" annulus. 17.4 M/U first joint of 7-5/8" to seal assy. 17.5 Run 7-5/8" 29.7# H521 tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. • Following running procedure outlined above. Page 36 Milne Point Unit E-35 SB Producer Drilling Procedure Wedge 521® 3.28 G0nn0cllan OG Opfer. REGIRAR PERFORMANCE «w M 11Mar2019 Ovts:de Dremelm 7.625 T. Nin. Wail 87.5% loin! Y16d slrctyN 8061%.1Cb3 NwmN Pr Sumcapac 68"500 p. Thic .. 15s I'I Grade LOD OF& Cmmprcugn SIM"!. 597425.1000 3i.3 ':1C•5 It Type 5 Ls Wall Tlhickn9u 0.375 m. Connection OO REGULAR Option 001 UNG PIPEB DY Bad! Red isl 0,,11: Rea GI 31 L06 Type 1' Orin AN StarMard 1u Gad. an,. 2nd Ds d 2rd Uatd. • Br TYPO C.I.g 3rd Band. '..td bard: - SID Band. PIPE BODY DATA I GEOMETRY 1 Namna�cc 7.Qs.n. N.miviwepm 29701B,11 Onh fi.TS.n. WomIv10 &V5 II Wall Thdkness 0.375.n. Fain End%V.0 29.Of IC. -01 ODTet,,.. API PERFORMANCE - e.nre'adsvonplh 59s.tdagm. NdnmmY ld ON p:I stirs 9o0aa pal cdaKn 47N psi CONNECTION GEOMETRY Cpnhec0 ,00 T,%7.n Cmaocvn ID 6.800 r. &tale., Lcas 3.7N tI Thrcu,wi. 3.28 G0nn0cllan OG Opfer. REGIRAR PERFORMANCE Tenslan EOipncY 7121. loin! Y16d slrctyN 8061%.1Cb3 NwmN Pr Sumcapac 68"500 p. 15s Cmmprcisun EHclanry 11T5e Cmmprcugn SIM"!. 597425.1000 3i.3 ':1C•5 It Ls aalamai Frpswra cap xlrr aMAN pp MAKE-UP TORQUES Win.. 9100 T,.Gs 9p6mum 110109% I" 14701.u: OPERATION LIMB TORQUES Opxal:.a T.,.. 35000 tics Ylekl Tmeu. 5"Ild filY. Notes This cannectiw is fury elterchaNeat:8e with Wedge 521 t - 7.625 in. - 26 4 133.7 1 30 lbs+ft Connections vith DopelessO TechnoWgy are fully compatible With the same ccmnection in its Sar-Awd vemcln Page 37 17.6 M/U 7-5/8" to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — l0k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 PX string & remove unnecessary 7-5/8" joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7-5/8" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7-5/8" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7-5/8" x 9- 5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7-5/8", verify collapse pressure of 7-5/8" tie back. 17.16 Slack off and land hanger. 17.17 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.19 R/D casing running tools. 17.20 Test 7-5/8" x 9-5/8" production annulus to 1000 psi / 30 min. 17.3 Set test plug and change top rams from 7-5/8" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8" test joint, 250 low / 3000 psi high. Page 38 Milne Point Unit E-35 SB Producer Hilcorp Drilling Procedure 17.6 M/U 7-5/8" to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — l0k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 PX string & remove unnecessary 7-5/8" joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7-5/8" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7-5/8" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7-5/8" x 9- 5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7-5/8", verify collapse pressure of 7-5/8" tie back. 17.16 Slack off and land hanger. 17.17 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.19 R/D casing running tools. 17.20 Test 7-5/8" x 9-5/8" production annulus to 1000 psi / 30 min. 17.3 Set test plug and change top rams from 7-5/8" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8" test joint, 250 low / 3000 psi high. Page 38 U Hilcorp 18.0 Run ESP Assembly Milne Point Unit E-35 SB Producer Drilling Procedure 18.1 RU spooler with ESP power cable and heat trace. RU two 3/8" capillary string spoolers. The capillary strings should be filled with hydraulic fluid. 18.2 Verify the ESP components as per Centrilift. Verify that the length of the motor lead flat cable will place the splice between the discharge head and the 10' handling pup collar. A Centrilift rep shall be on the rig floor at all times during the running of the ESP. 18.3 Makeup new ESP assembly with new motor lead extension, seal section and motor. 18.4 Run the 2-7/8" ESP Completion as noted below. The completion includes two 3/8" capillary tube from surface to the centralizer on the motor. The capillary tube will be secured to the tubing with Cannon clamps. Function test the capillary tube every 2,000' by pumping --2 gallons of hydraulic oil through the check valves. Record the pressure at each testing point 18.5 M/U ESP assy and RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. • Centrilift ESP Assembly with bottom of assembly @ predetermined depth • 10' 2-7/8" 6.5#, L-80 Pup Joint • 1 joint 2-7/8" 6.5#, L-80 EUE 8rd tubing • 2-7/8" "XN" nipple (2.313" packing bore / 2.205" No -Go ID) • 3 joints 2-7/8" 6.5#, L-80 EUE 8rd tubing • 10' 2-7/8" 6.5#, L-80 Pup Joint • GLM 2-7/8" x 1" GLM w/ dummy installed • 10' 2-7/8" 6.5#, L-80 Pup Joint • 2-7/8" 6.5#, L-80 EUE 8rd tubing • 10' 2-7/8" 6.5#, L-80 Pup Joint • GLM 2-7/8" x l" w/ SO @ --140' MD • 10' 2-7/8" 6.5#, L-80 Pup Joint • 3 joints 2-7/8" 6.5#, L-80 EUE 8rd tubing • Tubing Hanger Check the conductivity of electric cable every 2,000' and every new splice while running in hole. o Function test the capillary tube every 2,000' when checking the conductivity of the electric cable. Page 39 Milne Point Unit E-35 SB Producer Drilling Procedure o Use Cannon clamps on every joint to secure the capillary tube. o The makeup torque values for 2-7/8" L-80 6.5# EUE 8rd tubing are: Minimum: 1,730 ft -lb, Optimum: 2,300 ft -lb, and maximum: 2,800 ft -lb. o The 2-7/8" L-80 6.5# EUE 8rd tubing performance properties are: Body Yield: 145,000#, Burst: 10,570 psi, Collapse: 11,160 psi. 18.6 Fill tubing while splicing cable, mid -cable splices and tubing hanger splices. After tubing is full, break circulation by pumping 10 bbls down the tubing to clear any debris. 18.7 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.8 MU tubing hanger and landing joint. Splice ESP power cable and terminate control lines. Test cable. Install a brass -shipping cap on the ESP penetrator. 18.9 Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. 18.10 RILDS and test hanger. LD landing joint. 18.11 Install BPV and N/D BOP. 18.12 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.13 Circulate diesel freeze protection down 2-7/8" x 7-5/8" annulus (Volume should equal capacity of tubing to 2500' + tubing annulus to 2500'). Connect IA to tree and allow diesel freeze protect to "U-tube" into position. Note — this may be done post -rig. 18.14 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 19.0 RDMO 19.1 REMO Innovation Rig Page 40 Milne Point Unit E-35 SB Producer Hilcorp Drilling Procedure � T 20.0 Innovation Rig Diverter Schematic 3116' Kill 135'8 Technolm Page 41 ontrol Technology 3.5!6.5M Contra echnology Double Ram -116' Choke Line 16' Diverler Line 0 Milne Point Unit E-35 SB Producer Hilcorp � �."�, Drilling Procedure 21.0 Innovation Rig BOP Schematic D D 13-518" 5M Control Technology Annular BOP 0 0 ®-13-5/8" 5M Control o Technology Double Ram 3-1/8" Kill Line I' �-3-118' Choke Line DC ® JD c ® c -----�-13.518" 5M Control - Technology Single Ram 13-5/8" x 5M — 11"x5M 9-5/8" DBL D Seal 2-1/16" x SM Casing Hanger 13-5/8" x 5M S-22 13-5/8" NOM 9-5/8" BTC Btm x 2-1116" x 5M 10.5" A SA Pin Top W/ Primary Seal 20" Casing 9-5/8" Casing Page 42 22.0 Wellhead Schematic — Y P _ 1 fnf 5 1 1 An !to iG.J9)PYA — J r1LOt 'il :i. r � JCG G l C00 2 F35 nrA14 Fi[^ . -,Eli a ;-. I rOLE 0 Milne Point Unit E•35 SB Producer Hilcorp I �om� Drilling Procedure 22.0 Wellhead Schematic — Y P _ 1 fnf 5 1 1 An !to iG.J9)PYA — J r1LOt 'il :i. r � JCG G l C00 2 F35 nrA14 Fi[^ . -,Eli a ;-. I rOLE F A E AIIC IIt FIDi'fIC Cr re n N fl9JL' IL Ifi_8-II - M. � 10.25 i ' qd va..r L...isnK +kM14. ]xl[r Lry rV18[o !V. ].. � -' :: P.� !1!r lnuG xYttE .x•i: ... ..., ,r ... •. ..... ,, ,. ,,. -. J. Gdfi, t. '025. DA60077)p'GI i Page 43 H Hilcorp U.M 23.0 Days Vs Depth m ems m 5000 Y Q v v 7000 d N O1 9000 11000 13000 15000 0 Page 44 Milne Point Unit E-35 SB Producer Drilling Procedure MPU E-35 SB OA Producer Days vs Depth 5 10 15 20 25 Days U6,, H Hilcorp 24.0 Formation Tops & Information Milne Point Unit E-35 SB Producer Drilling Procedure MPU E-35 Formations (w 09) MD (ft) TVDss (ft) ND (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 1875 1740 1788 786.72 8.46 SV1 2689 2467 2515 1106.6 8.46 LA3 4193 3759 3807 1675.08 8.46 Schrader Bluff NA 5036 4236 4284 1884.96 8.46 Schrader Bluff OA 5888 4371 4419 1 1944.36 8.46 Page 45 ��G� ve"ell ' fl3'1106 H Hilcorp Eos.o ,T 24.0 Formation Tops & Information Formation Top MD TVDSS TVD Base Permafrost 1875 1740 1788 SV1 2689 2467 2515 LA3 4193 3759 3807 SB NA 5036 4236 4284 SB OA 5888 4371 4419 Page 45 Milne Point Unit E-35 SB Producer Drilling Procedure n Hilo �Z X27 GENERALIZED GEOLOGICAL FORECAST tizaI GEOLOGICAL TVD I FM I LITH DESCRIPTION ie in GubI j - Unconaoiidaled coarse to medium send and small gravel with .,•aaa. 600 I •minor eiltstone. 4,000'z Heavy gravel conglomerate to 1600'. Wood fragments _ �; throughout permafrost zone. Abundant pyrite at 15DO ft. 1700' C site. L., It A u Laos 4flow Milne Point Unit E-35 SB Producer Drilling Procedure Base permafrost -4= RUNNING GRAVELS Be prepared for HYDRATE gas cut C mad 2070 to 25W' as (E -land E-6) (33111 E-10, 6-231). (E-14..30. E-32. HYDRATES. GAS CUT MUD A Predominantly clay to *t- 3000' with Interbeds of sand, clays end sillslones with occasional shows of coal. Y Continued interbeds of sand, clays and slltslones with occasional shows of coal- Clay. siitstone and sand interbeds between 3000 a" sess 6000'. LlgnHe 3600-3500 N. 5V intervals more ratty ("muddier")than (hose In the Prudhoe Bay area A UgnU: Thick package -200 to 300 ft In sortae areas, mostly water -filled at E -pad although y B some zones are tilled with hydrocarbon. The Ugnu section (Interbedded fluvial sandstone w C and shale) represents the Initial peogradslion d the Ugnu deltaic system over, the underlying r shallow marine Schrader Bluff section. Fluvial natua can make N difficult to delemvne top x D and base of Individual uruis. Bottom bounding surface of the entire Ugnu package Is picked V A at the regional unconlomdty, M705 [see Bre fill -sands, below). .7 M -Sands: Fluvial, deltaic channel sandstones prograded over the underlying shallow B merine sandstones of the Schrader BION. The M -Sands are subdivided Into three A Inhostratigraphc units (109. Mo. Mc from top to bottom) that can be difficult to correlate due v to their fluvial-deit uc nature. The M70S marks the lower most boundary. M -sand Intervals 5 B are typically coarsening upward packages of varying thicknesses. ran0ngfrom 50.80'thck, gD All zones are highly unconsolidated sandstones with porosities range in the 30-38% and i permeabilNes reaching upwards of 2000-5000 rod. Each Ma and Interval acts as a hydraulically separate mrservou based on currerd understanding. N N -Sands: The N -sands are composed or stacked. marineshoefece sandstones that 13 coarsen upwards from thin, silty mudsiones into thkn, low nel.gross very tine to medium - G C grained sandstones. The NB. NC & NOsands are the test quality reservoir rock of dean. 19 w 0 hgh n Lgross tine to medium gralned sandstone. Nsand porasny ranges ham 12a6%and Z' pemeabllities range from 100-3000 nor. The NIC & ND -sands are the primary larger with E secondary targets In the NB -eared. The more unconsalidaled sands (typically the NB, NC & NO) tend to washout and the Imer grained fifty mudslonef can cause slow ROP. Eich N -sand acts as a hydradlcally isolated separate reservoir. A O -Sands: The O -sends consist of stacked lower shorelare marine sands that clean upwards Nom silly mudstones (Intervening shales) to thin bedded, very fine to lure grained santlstones. These OA and OB sardstorus are 25-30'thick, and the OA -sand is the primary j target for horizontal wells at E -pad. Oland porasates range from 12-36$l and permead11Le5 I B In the 013 -sand reach upwards of Stiff and whereas permeabikties In the OA -sand reach only 350 Ind. There ere underlying OB winds (013b -MT that Correlate over the region. C May contain tight nodules and lenses that cause directional deflection (especially when horizontal) and slaw ROP. Each O -sand Interval acts as a hydraulically Isolated reservoir. TM numerous sub-seismk 5-30 ft faults and the lateral discontinuity of the NB- hcls make it 0 essential for clear pick denuflcalon dawn Waugh the Ugnu and N -sands. as well as careful geosteenng in horizontal"Us. Page 46 SWABBING/STICKY CILAWGUMBO: E -20a. -28. -32 & -12. GAS CUT MUD E-26 AT 3996 TVD; E4 3B @ 3618 tvd. TIGHTf`ACIUNG OFF, E -25A-, Surface casing seat - for Schrader Bluff completion. TIGHTILEDGES(COAL) RUNNING SURFACE CASING. E-26, -33 & -25. 25.0 Anticipated Drilling Hazards Milne Point Unit E-35 SB Producer Drilling Procedure 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have been seen on E Pad. Remember that hydrate gas behave differently from a gas sand. E Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non - pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No 112S events have been documented on drill wells on this pad. Page 47 VA 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 1-12S. No 1-12S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on this pad. Page 48 Milne Point Unit E-35 SB Producer Hilcorp E. Czr Drilling Procedure 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 1-12S. No 1-12S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on this pad. Page 48 26.0 Innovation Rig Layout Milne Point Unit E-35 SB Producer Drilling Procedure Page 49 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 50 Milne Point Unit E-35 SB Producer Bile Bile Drilling Procedure 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 50 28.0 Innovation Rig Choke Manifold Schematic Milne Point Unit E-35 SB Producer Drilling Procedure Page 51 n HilcoT E, mpmy 29.0 Milne Point Unit E-35 SB Producer Drilling Procedure Casing Design n xilcorp Calculation & Casing Design Factors DATE: 11/8/2018 WELL: MPU E-35 DESIGN BY: Joe Engel n Criteria: Hole Size 12-1/4" Mud Density: 9.2 ppg Hole Size 8-1/2" Mud Density: 9.2 ppg Hole Size Mud Density: Drilling Mode MASP: 1504 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1504 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Page 52 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 6-5/8" Top (MD) 0 5,934 Top (TVD) 0 4,423 Bottom (MD) 5,934 15,000 Bottom (TVD) 4,423 4,353 Length 5,934 9,066 Weight (ppf) 40 20 Grade L-80 L-80 Connection T1(P H563 Weight w/o Bouyancy Factor (lbs) 237,360 181,320 Tension at Top of Section (lbs) 237,360 181,320 Min strength Tension (1000 lbs) 916 459 Worst Case Safety Factor (Tension) 3.86 2.53 ✓ Collapse Pressure at bottom (Psi) 2,185 2,150 Collapse Resistance w/o tension (Psi) 3,090 3,470 Worst Case Safety Factor (Collapse) 1.41,/ 1.61 MASP (psi) 1,504 1,504 Minimum Yield (psi) 5,750 6,090 Worst case safety factor (Burst) 3.82 - 4.05 Page 52 Milne Point unit E-35 SB Producer Hilcorp Drilling Procedure U Camas 30.0 8-1/2" Hole Section MASP 11 Maximum Anticipated Surface Pressure Calculation Hilccoorrp 8-1/2" Hole Section MPU E-35 Milne Point Unit MD TVD Planned Top: 5934 4423 Planned TD: 12688 4353 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 1 4,423 4,375 1925 1 Oil 8.46 0.440 Offset Well Mud Densities XA/ell AA\A/ ranee Tnn rTvnl Rottnm (TVD) Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density forthe 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wel lbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 4423 (ft) x 0.78(psi/ft)= 3450 3450(psi) - [0.1(psi/ft)*4423(ft)]= 3008 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 4423 (ft) x 0.44(psi/ft)= 1946 psi 1946(psi) - 0.1(psi/ft)*4423(ft) 1503.8 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 53 Milne Point Unit E-35 SB Producer Hilcorp Drilling Procedure W, 31.0 Spider Plot (NAD 27) (Governmental Sections) ste • _ _ y MPB.3}PB, - - Sr 15 exs\c.ss Sec. 74 Sec. 13 MPU E-35 BHL .,, - 'eee�e � o -m e.ou R.r-i 1` •E 13 B1 'a Sec 22 ` Sec. 23 � / eOpee_ � % .: Ore Sec. 24 r ua MPU'TCTI X11 ERSE TION eee LtuF9] .. Eit I ,II . MPU E-35_TPH , MILNE POINT UNIT U013N010E___ r r .i NIPUE-35_SHL Sec 27 Sec. 26 25 �/ Sec: /I Gro JbL025916 i ADL025518 Legend • MPU E-3_SHL O2'ter SurfacetIIlt I H,It o le\s (S\ H\L) Sec: 35 X MPU E-35_TPH meBottom Hales (BHL) Set. 34 - - - Other Well Paths ` - MPU E-35 BHL [M Oil and Gas Und Boundary Pad Footpflm Milne Point Unit MPE-35 Well 0 1,250 2,500 Moe we: nlex,e WP09 Feet Page 54 32.0 Surface Plat (As Built) (NAD 27) Milne Point unit I of clan, E-35 SB Producer -- HilcoTp Drilling Procedure 32.0 Surface Plat (As Built) (NAD 27) Page 55 I of clan, --�, f'•- -- � AVID •fn0 24 3■ ■9 I W L ■ >S 2 4■ zr ■ ■ ■ u NAD ` 10 ■ 31 I 26 ■ ■ A p 291 ■ 1 TM P- 924■ ■ 5 26 a 0 9 ■ • 8 -N- 26■ •21 9.43a6211' VICINITY MAP / 663' FEL 11 ■ ■ 7 I x.7.5. 70.45at 6t 4' 9■ ■ 16 E -{t 1Fl} EGAD 10 ■ ■ 2S 1,844' FEL 24 ■ • 19 6OF,pZ ' •• •�'. E-39gyp. E-38 9 >f.. 9m (. .I . .:...... E-41 E-35 .......... ' m01hy ad 10200 j/ NOTES. 1. A.,A9G 51A1 "E 0Wt1NAR5 ME 2DRE N. LEGEND AAD27. + AS-9ULT CONDUCTa2 c1 iRL4'YOR'S CERTflCA1E 2. "S a LXATDM 6 "CHU ENiS M-3 AND E -i. HEREBY CdTH MAT AY ■ ENTSWIC 03IDUE1aR PROPERLY RE O ANa UfFIN 3. 9495 OF D.EVATpI WOE INXIT DAT1M "I rCE LAND AND A 00001:11C POSITIONS A RAW, T E S Ar a AL A TIAs 5 AM 111:M 1CME FACT01115: amoD54 GRAPHIC SCALE i M AS-BULT REPRE9EY19 A SURVEY 9. 9NtEY DAIS: MAY 31, 3016 Y AI.Y 1, 2115. p IN 2WIO2 MAGE 9Y AE M MER MY DIRECT 94PERK90N AND 1140 ALL r. RERPLREI PKID OW: HCI4 PDS. 24.29 Nv-02 PGS lw- /. ( W FRT) CORRECT ASAMID W MAYOTH�31 �11A 1 Nt'N . 200 h. LCCATED WIPHIN PROTRACTED SEC. 25, T. 13 N., R. 10 E-, U AIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC CELLAR SECTION N0. I COORDINATES COORDINATES POSITON(DMS) POSITON(O.OD) BOX ELEV. OFFSETS Y=6.016.133,24' N-1.829-99' 702775.9{5" 70.4544292' 21 T 3,594 FSL ' E-35 X. 599.426.37' E= 1.450.02' 1492b'CO.a38" 149.4334550' 1,720 FEL Y.S,076,156.74' N=1,680.12' 7027'15.178' 70.4544939' 21.7' 3,617 PSL E-36 X= 569407.$2- = E 450.03' 149'26'00.964' 149.4338087 1,738' FEL Y-6.016,180.3TN=7,890.56' 702718.412' 70.4543589' 217• 3,847'FSL E-37 X. 569388.31' E- 1449.84' 14925'01.542" 149,4337517- 1.757' FEL Y=6.016.061.05' N=1,940.22' 702715.446" 70.4542906' 21'6 3,543'F5L E-36 X. 569.265.12' E= 1,291.58' 149'26'05.189" 149.4347747 1.891 FEL Y=6A1b.D57.25' N-1,859.70 702715-210" 70.4542250' 21.7' .3.619' F5L E-39 X- 569.264.13' E= 1,291.52' 14426'04.636' t4 i Micorp Alaska 6 + 9 ' MILNE POINT, ALASKA UP E -PAD, LELLS 33. 36. 37. X 39 k 41 A[a5pi va .oR� �- � 9Ma ' 2DY CONDUCTOR AS -BUILT t =+ Page 55 9.43a6211' / 663' FEL Y=6,016,034.09' N-9,829.93' 702774.981" 70.45at 6t 4' 21'6 3,496'FSL E -{t 1 291.68' 1492604.091' 149.4344b97• 1,844' FEL H Hilcorp Er comwy Milne Point Unit E-35 SB Producer Drilling Procedure 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD mw, PPB 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 _- rnrn_ - - .._ 500 1000 1500 2000 r 0 2500 3000 3500 4000 4500 Page 56 —MPU L-46 (2015) —MPU L-47 (2015) —MPU L-48 (2015) —MPU L-49 (2015) —MPU L-50 (2015) —MPU F-106 (2017) —MPU F-107 (2017) —MPU F-108 (2017) —MPU F-109 (2017) —MPU F-110 (2017) Milne Point unit E-35 SB Producer Hilcotp Drilling Procedure Es,g/ Compny 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD w 5.000 Poe Body Wall Thichteas sm 0.362 Pipe Body Grade S-135 Drill Pipe Length Tool Joint SIMS Connection GPDS60 Tod Joint OD 6.625 Tod Joint ID IM. 3250 Pin Torg 9 Box Tong c : 12 80 % Ins .cion Clan Nominal Nominal Weight Designation 19.50 Dell Pipe Approximate Length m) 31.5 Smo Loge Height mi 3rJ2 Rased Tool Joint SIMS !.)11120,000 Upset Type 0 Max Upset OD (DTE) nm 5.125 Friction Factor 11.0 124 .c Tory :Nce I., Ilcl � naCiOi'.9 Drill Pipe Performance Drill -Pipe Length Range2 at Tenazn 1 i J row^w^wur 36,100 Tension Only 10 560.800 \.. ccmarca N.awo 32.100 467.400 vole. 0e new saTn NLLII: a: us gdlcns. wm: odl Nqe a:a.,mmr .em�-r. ve e..rs.�as:: m,o mvr r.+. e� m uoe osr mn mknru. ure,eal pamcca�wq ^ma ouwr xn:. Connection Performance GPDS.50 ( 6.625 my OD X 3.250 neo ID ) 120,000 rte) Tool Joint Dimensions Balanced OD IM 6.435 MwTlin Tod JOM OD 6f API 5.930 Prcm,an Cksa Ylnl anon.+, Teal Jtlwl ao or 5.93 Cgv�wrG2 MI Best Estimates moon , I rwm c ., Nominal rk.w maw) 23.29 K017J Nc J*am .........IP OOeNMal lend.. l Ta.)-37r--n-y"'W O'a - Tool Joint Torsional Strenoth c . , 71.800 Tod Jdnt Tensile Strandh mar 1,250000 Elevator Shoulder Information SmoothEdge HelAh1 3132 Raised Box OD m,16.8112 7Elevator Caaad Dost 1,658,000 Assumed Elevator Bore Diameter 'M J5-219 Pipe Body Slip Crushing Capacity ir Elevator OD 3+32 Rased 6.812 mr 001 Joint I Womto BeV¢I Wom W Min TJ OD for n Diamafer API Premium Class Nde: EkrvalttcipilY Ea:MM35fuReC Ek.sY, EUT. nO uen rxlu. ar'41-15 m,�u.�aWm. N. a e'W:N eYVa6, o01^cmi:ea ekvilCr u,na:tr vnMcul anRYnc nape -W bNue. Pipe Body ConNuredom ( 5 W OD 0.362 )m) Wall S-135) Pipe Bodv Performance K' Y Crane Page 57 Pipe Body Con%uradon ( 5 m) OD 0.362 u") Wall S-135) R9W rc. ] .dwamnTl eu t R al ]]. 'w aPi. Nominal 80 % Inspection Gass API Premium Class Pipe Tensile Strength (-1712100 560,800 560,800 Pipe Torsional Strerop 74.100 58,100 58.100 TJ4'ipeBody Torsional Ratio 0.97 124 1.24 80% Pipe Torsional Strength +Maar 59,300 46.500 46.500 Burst 1 17,105 15,638 15.638 Collapse 4m 15.672 10.029 10.029 Pipe DD tmj 5.000 4.855 4.655 Wan Thickness q^) 0.362 0290 0.290 Nominal Pipe ID rm 4276 4276 Cross Sections Area of Pi Body(mv, 5275 4.154 Cross Sectional Area of OD cw•zr 19.635 18.514 Cross Secdonal Area of ID t;-" 14. 14.360 n&953 Section Modulus cm^a) 5.708 4"476 Polar Section Modulus way 11.415 8.953 R9W rc. ] .dwamnTl eu t R al ]]. 'w aPi. H Hilcotp � 2 Milne Point Unit E-35 SB Producer Drilling Procedure 500204050016200 Weatherford Page 58 5" 19.50 Ibfft S-135 w/ NC 50 6-5/8" OD x 3-114" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection NC 50 Interchangeable With 5' XH 8 4-112' IF Upset Type IEU Nominal Weight per Foot 19.50 lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-518' Inside Diameter 3-1/4' API Drift 3.1/8' Rabbit OD, Suggested 3-1/16' Minimum Make-up Torque 25.900 ft -lbs Maximum Recommend Make-up Torque 26.800 ft -lbs Torsional Yield Strength 51,700 ft -lbs Tensile Strength 1,269,000 lbs TUBE DATA New Premium Outside Diameter 5.000' 4.855' Inside Diameter 4.276' 4.276' Wall Thickness 0.362' 0.290' Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook Load/Tensile Strength 712.000 lbs 560,800 lbs Slip Crushing / Slip Type (SDXL) 572.100 lbs 453,500 lbs Burst Pressure 17,100 psi 16.100 psi Collapse Pressure 15.700 psi 10.000 psi Torsional Yield Strength 74.100 ft -lbs 58.100 ft -lbs Capacity W/ Tool Joint 0.726 US gaVft 0.726 US gallft Displacement W/ Tool Joint 0.353 US al/ft 0.322 USgal/ft Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss, damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Hilcorp Alaska, LLC Milne Point M Pt E Pad Plan: MPU E-35 MPU E-35 Plan: MPU E-35 wp09 Standard Proposal Report 02 November, 2018 HALLIBURTON Sperry Drilling Services m a a a a a a u 2 U U U U U U 1= 0 0 0 0 0 0 0 0 0 0 0 r o 0 u M n I? m a a a a a a a u F N "� �oomNNNNmmNmNomm�wNwmowNMW�maMNammwmdNrmN ooNaon��WNNmNNo��odoNwMm�mewo�a+mmommin �mm p Wnm m oo6oio mai Nimn<--��roNvi(n ovi of vioeam.=vinooNn<vi iri i:dNo > �demNwemNmmamp mwo�WWo�W�aoM�Npp Mw�o m zwi� ry E ` a � ooOooWor0000000m000000000m000Mo�omoNomo $00000mono mm^ �� o o o o o o w o o 0000000moeoNOPoino�oNo LL O O O O O O �O O Oi OO O O O O O O A O O O O - - 0 g w a0000 0000000000000000000000000000000000 0 oma 0000$0000000a00000000000000000000000000o pCOriCoOeoVOa'O<dedrid6ovcdodooidodvovovo6d6o z f ng yQ U mo NN > pp J> p O N O m O m lma N N N N N r N m m 4 m m a M O P 0 dm O N V Q m 0 n �OOOMaid tG WfComOONCOmN�O�Omm�YClh ml�mNdo��N�-�MCJN p' ypp FQ N w m w a r m o m m d d w m m m N N m m m n m a m N N N N N M m W N m # W 13500 $ m zo N O O N N O N m n n N a W W M n m m N M w N p M N m n m m M M M m m m O 0 a d 3000 Unw �- 2mmNnmdn�d�ndnNMa(coNMNM roti of �o�cerooirvnrii[iNriprrori U# n N O m O N m N N W N m a W N d m M M m O m m W p 0 Yl r N r F n m W N m rj �Nj' m M m M m m m m e a e d Q d a a d N m N N N N N N m � y p d ❑ O O w O d O N m O O m O O N nn n m M a d M N M O m m P r O N O N N m m 0 12000 U uwi O )NON000NMmNmry�rnrym�ndomnwmul m lOM N.-nnnMnm�MN n �n O M d e p Q P P m m m m O a m m m M M m m m m M M m m m m m M m m N N M a a a a Q a p Q P Q Q P a d a a a a a d d e e e a a a a a d a a _. 0000rrO0oo.o00000o.m000000wwmmmMmmddmm �OOOOOOaaNNNNNNNNO000000000mmmmnrl�l`1`I�I�nnl� - mQQ 000cccNNd<d 66eee.000000000edoi oi6<dddPaiep a0 E�y<?01 ....................... 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O o a0 m s m irooa � a f0 U 10500 $ w o 0 $ U woo w � � $ c n i8500 S U s000 N N a 6 O O O O O n N N M M (uyysn 009L) 43daa goipeA anil �N�aa o _ a` 3 nen �nh yoo 0 vi ui Fve A O� a6 �r� f8a r� Oir, r4, s: ti ce O gYf6dpD�n �i fa <° Ota�. - nd d: �0,40, s � u "rf9 pOe OGG, e ej� f,Dd. P4, tDcG g� , Tn fbfd f6a yfn 'OOi s f C SCD � 8 g r u i (uygsn OOSI) (+)yvom/(-)9pnos 8 5 p p = p i m �o roryh�ryy OSCD &m��z ry�`�NY� y h$ c T f 8 5 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 wp09 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-35 TVD Reference: MPE-35 wp09 Q 48.20usft MD Reference: MPE-35 wp09 @ 48.20usft North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) - System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) - Using Well Reference Point Map Zone: Alaska Zone 04 1 Using geodetic scale factor Site M Pt E Pad, TR -13-10 PLAN Tie On Depth: 26.50 Site Position: Northing: 6,013,798.68usft Latitude: 70.448 From: Map Easting: 569,440.72 usft Longitude: -149.434 Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.53 ° Well Plan: MPU E-35 Well Position +N/ -S 0.00 usft Northing: 6,016,133.24 usfl Latitude: 70.454 +E/ -W 0.00 usft Easting: 569,426.37 usft . Longitude: -149.433 Position Uncertainty 0.00 usft Wellhead Elevation: 21.70 usfl Ground Level: 21.70 usft Wellbore MPU E-35 Magnetics Model Name Sample Date BGGM2018 11/21/2018 Design Audit Notes: Version: Vertical Section: MPU E-35 wp09 Declination Dip Angle (°) (°) 16.97 80.98 Field Strength (nT) 57,447.90646164 Phase: PLAN Tie On Depth: 26.50 Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 26.50 0.00 0.00 294.80 11/22018 5:17.07PM Page 2 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU E-35 Company: Hilcorp Alaska, LLC TVD Reference: MPE-35 wp09 @ 48.20usf1 Project: Milne Point MD Reference: MPE-35 wp09 @ 48.20usft Site: M Pt E Pad North Reference: True Well: Plan: MPU E-35 Survey Calculation Method: Minimum Curvature Wellbore: MPU E-35 Design: MPU E-35 wp09 Dogleg Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +EI -W Rate Rate Rate Tool Face (usft) (") (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 26.50 0.00 0.00 26.50 -21.70 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 251.80 0.00 0.00 0.00 0.00 0.00 0.00 550.00 7.50 40.00 549.29 501.09 12.52 10.50 3.00 3.00 0.00 40.00 700.00 7.50 40.00 698.00 64980 27.51 23.09 0.00 0.00 0.00 0.00 1,125.00 24.50 40.00 1,105.04 1,056.84 116.92 98.11 4.00 4.00 0.00 0.00 2,125.00 24.50 40.00 2,015.00 1,966.80 434.60 364.67 0.00 0.00 0.00 0.00 2,245.99 28.02 32.47 2,123.52 2,075.32 477.82 396.07 4.00 2.91 -6.23 -46.89 3,251.63 28.02 32.47 3,011.31 2,963.11 876.38 649.64 0.00 0.00 0.00 0.00 5,484.31 85.00 294.50 4,383.98 4,335.78 2,021.87 -276.38 4.00 2.55 -4.39 -99.37 5,934.31 85.00 294.50 4,423.20 4,375.00 2,207.77 -684.30 0.00 0.00 0.00 0.00 6,071.81 90.50 294.50 4,428.60 4,380.40 2,264.72 -809.28 4.00 4.00 0.00 0.00 7,138.93 90.50 294.50 4,419.28 4,371.08 2,707.24 -1,780.28 0.00 0.00 0.00 0.00 7,248.93 94.90 294.50 4,414.10 4,365.90 2,752.79 -1,880.24 4.00 4.00 0.00 0.00 7,323.93 94.90 294.50 4,407.70 4,359.50 2,783.78 -1,948.24 0.00 0.00 0.00 0.00 7,433.93 90.50 294.50 4,402.52 4,354.32 2,829.33 -2,048.20 4.00 -4.00 0.00 180.00 8,150.00 90.50 294.50 4,396.27 4,348.07 3,126.27 -2,699.77 0.00 0.00 0.00 0.00 8,333.33 90.50 300.00 4,394.67 4,346.47 3,210.18 -2,862.68 3.00 0.00 3.00 89.98 8,504.90 90.50 300.00 4,393.17 4,344.97 3,295.96 -3,011.26 0.00 0.00 0.00 0.00 8,619.90 85.90 300.00 4,396.78 4,348.58 3,353.42 -3,110.78 4.00 4.00 0.00 180.00 8,684.90 85.90 300.00 4,401.43 4,353.23 3,385.83 -3,166.92 0.00 0.00 0.00 0.00 8,799.90 90.50 300.00 4,405.04 4,356.84 3,443.29 -3,266.44 4.00 4.00 0.00 0.00 9,911.01 90.50 300.00 4,395.34 4,347.14 3,998.82 -4,228.65 0.00 0.00 0.00 0.00 10,026.01 95.10 300.00 4,389.73 4,341.53 4,056.24 -4,328.10 4.00 4.00 0.00 0.00 10,091.01 95.10 300.00 4,383.95 4,335.75 4,088.61 4,384.17 0.00 0.00 0.00 0.00 10,206.01 90.50 300.00 4,378.33 4,330.13 4,146.03 -4,483.62 4.00 -4.00 0.00 180.00 10,416.01 90.50 300.00 4,376.50 4,328.30 4,251.02 -4,665.48 0.00 0.00 0.00 0.00 10,589.34 90.50 294.80 4,374.99 4,326.79 4,330.76 -4,819.30 3.00 0.00 -3.00 -89.98 11,313.91 90.50 294.80 4,368.66 4,320.46 4,634.67 -5,477.03 0.00 0.00 0.00 0.00 11,445.14 85.44 293.39 4,373.31 4,325.11 4,688.19 -5,596.70 4.00 -3.85 -1.08 -164.40 11,498.41 85.44 293.39 4,377.54 4,329.34 4,709.26 -5,645.44 0.00 0.00 0.00 0.00 11,629.37 90.50 294.76 4,382.17 4,333.97 4,762.63 -5,764.89 4.00 3.86 1.05 15.23 12,714.37 90.50 294.76 4,372.70 4,324.50 5,217.03 -6,750.11 0.00 0.00 0.00 0.00 12,826.32 94.98 294.73 4,367.35 4.319.15 5,263.83 -6,851.64 4.00 4.00 -0.03 -0.41 12,903.01 94.98 294.73 4,360.70 4,312.50 5,295.78 -6,921.04 0.00 0.00 0.00 0.00 13,014.96 90.50 294.76 4,355.35 4,307.15 5,342.58 -7,022.57 4.00 -4.00 0.03 179.58 14,114.96 90.50 294.76 4,345.75 4297-55 5,803.26 -8,021.40 0.00 0.00 0.00 0.00 14,236.74 85.63 294.74 4,349.86 4,301.66 5,854.20 -8,131.91 4.00 -4.00 -0.02 -179.72 14,293.55 85.63 294.74 4,354.19 4,305.99 5,877.90 -8,183.36 0.00 0.00 0.00 0.00 14,415.34 90.50 294.76 4,358.31 4,310.11 5,928.84 -8,293.86 4.00 4.00 0.02 0.28 15,000.34 90.50 294.76 4,353.20 4,305.00 6,173.84 -8,825.06 0.00 0.00 0.00 0.00 1122018 5:17:07PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 wp09 Planned Survey Measured Vertical Depth Inclination Azimuth Depth TVDss (usft) (') (°) (usft) usft 26.50 0.00 0.00 26.50 -21.70 100.00 0.00 0.00 100.00 51.80 200.00 0.00 0.00 200.00 151.80 300.00 0.00 0.00 300.00 251.80 Start Dir 3°/100' : 300' MD, 300'TVD 400.00 3.00 40.00 399.95 351.75 500.00 6.00 40.00 499.63 451.43 550.00 7.50 40.00 549.29 501.09 End Dir : 550' MD, 549.29' TVD 600.00 7.50 40.00 598.86 550.66 700.00 7.50 40.00 698.00 649.80 Start Dir 40/100' : 700' MD, 698'TVD 800.00 11.50 40.00 796.61 748.41 900.00 15.50 40.00 893.83 845.63 1,000.00 19.50 40.00 989.18 940.98 1,100.00 23.50 40.00 1,082.20 1,034.00 1,125.00 24.50 40.00 1,105.04 1,056.84 End Dir : 1125' MD, 1105.04' TVD 1,200.00 24.50 40.00 1,173.29 1,125.09 1,300.00 24.50 40.00 1,254.29 1,216.09 1,400.00 24.50 40.00 1,355.28 1,307.08 1,500.00 24.50 40.00 1,446.28 1,398.08 1,600.00 24.50 40.00 1,537.27 1,489.07 1,700.00 24.50 40.00 1,628.27 1,580.07 1,800.00 24.50 40.00 1,719.27 1,671.07 1,875.75 24.50 40.00 1,788.20 1,740.00 BPRF 1,900.00 24.50 40.00 1,810.26 1,762.06 2,000.00 24.50 40.00 1,901.26 1,853.06 2,100.00 24.50 40.00 1,992.25 1,944.05 2,125.00 24.50 40.00 2,015.00 1,966.80 Start Dir 4°1100' : 2125' MD, 2015'TVD 2,200.00 26.63 35.11 2,082.66 2,034.46 2,245.99 28.02 32.47 2,123.52 2,075.32 End Dir : 2245.99' MD, 2123.52' TVD 2,300.00 28.02 32.47 2,171.20 2,123.00 2,400.00 28.02 32.47 2,259.48 2,211.28 2,500.00 28.02 32.47 2,347.76 2,299.56 2,600.00 28.02 32.47 2,436.05 2,387.85 2,689.66 28.02 32.47 2,515.20 2,467.00 SVt 2,700.00 28.02 32.47 2,524.33 2,476.13 2,800.00 28.02 32.47 2,612.61 2,564.41 2,900.00 28.02 32.47 2,700.89 2,652.69 3,000.00 28.02 32.47 2,789.17 2,740.97 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-35 TVD Reference: MPE-35 wp09 @ 48.20usft MD Reference: MPE-35 wp09 @ 48.20usft North Reference: True Survey Calculation Method: Minimum Curvature 17.52 14.70 Map Map 0.00 -6.00 +N/ -S +E1 -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) -21.70 -13.74 0.00 0.00 6,016,133.24 569,426.37 0.00 0.00 0.00 0.00 6,016,133.24 569,426.37 0.00 0.00 0.00 0.00 6,016,133.24 569,426.37 0.00 0.00 0.00 0.00 6,016,133.24 569,426.37 0.00 0.00 2.01 1.68 6,016,135.26 569,428.03 3.00 -0.69 8.01 6.73 6,016,141.32 569,433.02 3.00 -2.74 12.52 10.50 6,016,145.85 569,436.75 3.00 -4.28 17.52 14.70 6,016,150.89 569,440.90 0.00 -6.00 27.51 23.09 6,016,160.97 569,449.20 0.00 -9.42 40.16 33.69 6,016,173.70 569,459.69 4.00 -13.74 58.03 48.70 6,016,191.72 569,474.52 4.00 -19.86 81.07 68.02 6,016,214.93 569,493.63 4.00 -27.75 109.14 91.58 6,016,243.21 569,516.92 4.00 -37.35 116.92 98.11 6,016,251.06 569,523.38 4.00 -40.02 140.75 118.10 6,016,275.07 569,543.15 0.00 -48.17 172.52 144.76 6,016,307.08 569,569.50 0.00 -59.05 204.29 171.42 6,016,339.09 569,595.86 0.00 -69.92 236.05 198.07 6,016,371.11 569,622.21 0.00 -80.79 267.82 224.73 6,016,403.12 569,648.57 0.00 -91.67 299.59 251.38 6,016,435.13 569,674.93 0.00 -102.54 331.35 278.04 6,016,467.14 569,701.28 0.00 -113.41 355.42 298.23 6,016,491.39 569,721.25 0.00 -121.65 363.12 304.70 6,016,499.15 569,727.64 0.00 -124.28 394.89 331.35 6,016,531.16 569,754.00 0.00 -135.16 426.66 358.01 6,016,563.17 569,780.35 0.00 -146.03 434.60 364.67 6,016,571.18 569,786.94 0.00 -148.75 460.27 384.34 6,016,597.03 569,806.37 4.00 -155.84 477.82 396.07 6,016,614.68 569,817.93 4.00 -159.12 499.22 409.69 6,016,636.21 569,831.35 0.00 -162.51 538.85 434.90 6,016,676.07 569,856.19 0.00 -168.77 578.49 460.12 6,016,715.93 569,881.03 0.00 -175.04 618.12 485.33 6,016,755.80 569,905.88 0.00 -181.30 653.65 507.94 6,016,791.54 569,928.15 0.00 -186.92 657.75 510.55 6,016,795.66 569,930.72 0.00 -187.57 697.38 535.76 6,016,835.52 569,955.56 0.00 -193.83 737.02 560.98 6,016,875.38 569,980.40 0.00 -200.10 776.65 586.19 6,016,915.24 570,005.25 0.00 -206.37 112/2018 5:17:07PM Page 4 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 wp09 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured Map Map Vertical Northing Easting DLS Depth (usft) Inclination Azimuth Depth TVDss +N/ -S 6,016,955.10 (usft) 0.00 (1) 636.62 (o) 570,054.93 (usft) usft (usft) 6,017,015.55 3,100.00 0.00 28.02 661.09 32.47 570,079.02 2,877.45 2,829.25 816.28 6,017,077.65 3,200.00 4.00 28.02 692.42 32.47 570,109.53 2,965.73 2,917.53 855.91 6,017,169.90 3,251.63 4.00 28.02 697.55 32.47 570,113.76 3,011.31 2,963.11 876.37 6,017,270.29 Start Dir 4-1100': 3251.63' MD, 3011.31'TVD 570,091.64 4.00 3,300.00 656.06 27.76 570,070.80 28.36 -76.40 3,054.07 3,005.87 895.87 4.00 3,400.00 598.62 27.63 570,012.38 19.76 20.93 3,142.64 3,094.44 938.21 4.00 3,500.00 557.34 28.02 569,970.54 11.22 83.62 3,231.12 3,182.92 983.09 4.00 3,600.00 461.77 28.93 569,873.92 3.04 218.07 3,319.05 3,270.85 1,030.30 4.00 3,700.00 344.50 30.29 569,755.62 355.43 371.76 3,406.03 3,357.83 1,079.61 4.00 3,800.00 207.80 32.06 569,617.92 348.49 541.68 3,491.61 3,443.41 1,130.78 4.00 3,900.00 105.06 34.17 569,514.53 342.27 664.87 3,575.38 3,527.18 1,183.56 4.00 4,000.00 -27.74 36.56 569,380.99 336.72 819.70 3,656.94 3,608.74 1,237.69 4.00 4,100.00 -200.65 39.18 569,207.25 331.80 1,015.21 3,735.89 3,687.69 1,292.91 4.00 4,193.76 -290.60 41.81 569,116.91 327.67 1,114.60 3,807.20 3,759.00 1,345.44 0.00 LA3 -471.90 6,018,239.53 568,934.87 0.00 1,313.83 -562.55 6,018,279.99 568,843.84 0.00 4,200.00 -642.70 41.99 568,763.37 327.41 1,501.53 3,811.85 3,763.65 1,348.96 0.00 4,300.00 -684.30 44.94 568,721.59 323.49 1,547.25 3,884.43 3,836.23 1,405.55 4.00 4,400.00 -809.28 48.02 568,596.10 319.96 1,684.59 3,953.30 3,905.10 1,462.41 0.00 4,500.00 51.19 316.76 4,018.11 3,969.91 1,519.26 4,600.00 54.44 313.83 4,078.55 4,030.35 1,575.84 4,700.00 57.76 311.14 4,134.32 4,086.12 1,631.85 4,800.00 61.13 308.64 4,185.16 4,136.96 1,687.04 4,900.00 64.54 306.29 4,230.81 4,182.61 1,741.12 5,000.00 67.99 304.08 4,271.06 4,222.86 1,793.85 5,036.05 69.24 303.31 4,284.20 4,236.00 1,812.47 SIS NA 5,100.00 71.47 301.97 4,305.70 4,257.50 1,844.95 5,200.00 74.97 299.95 4,334.56 4,286.36 1,894.18 5,300.00 78.49 297.99 4,357.52 4,309.32 1,941.30 5,400.00 82.02 296.08 4,374.45 4,326.25 1,986.09 5,484.31 85.00 294.50 4,383.98 4,335.78 2,021.87 End Dir : 5484.31' MD, 4383.98' TVD - Start ESP Tangent Hold 5,500.00 85.00 294.50 4,385.35 4,337.15 2,028.35 5,600.00 85.00 294.50 4,394.06 4,345.86 2,069.66 5,700.00 85.00 294.50 4,402.78 4,354.58 2,110.97 5,800.00 85.00 294.50 4,411.49 4,363.29 2,152.28 5,888.41 85.00 294.50 4,419.20 4,371.00 2,188.81 SB OA 5,900.00 85.00 294.50 4,420.21 4,372.01 2,193.60 5,934.31 85.00 294.50 4,423.20 4,375.00 2,207.77 Start Dir 4°/100' : 5934.31' MD, 4423.2'TVD - 9 518" x 12 114" 6,000.00 87.63 294.50 4,427.42 4,379.22 2,234.95 6,071.81 90.50 294.50 4,428.60 4,380.40 2,264.72 End Dir : 6071.81' MD, 4428.6' TVD 6,100.00 90.50 294.50 4,428.35 4,380.15 2,276.41 Halliburton Standard Proposal Report Well Plan: MPU E-35 MPE-35 wp09 @ 48.20usft MPE-35 wp09 @ 48.20usft True Minimum Curvature 1122018 5:17 07PM Page 5 COMPASS 5000.15 Build 91 Map Map +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) 2,829.25 611.41 6,016,955.10 570,030.09 0.00 -212.63 636.62 6,016,994.97 570,054.93 0.00 -218.90 649.64 6,017,015.55 570,067.76 0.00 -222.13 661.09 6,017,035.15 570,079.02 4.00 -224.35 680.00 6,017,077.65 570,097.54 4.00 -223.76 692.42 6,017,122.64 570,109.53 4.00 -216.20 698.27 6,017,169.90 570,114.95 4.00 -201.72 697.55 6,017,219.20 570,113.76 4.00 -180.38 690.24 6,017,270.29 570,105.98 4.00 -152.28 676.39 6,017,322.94 570,091.64 4.00 -117.56 656.06 6,017,376.87 570,070.80 4.00 -76.40 629.35 6,017,431.84 570,043.58 4.00 -28.99 598.62 6,017,484.07 570,012.38 4.00 20.93 596.39 6,017,487.57 570,010.11 4.00 24.43 557.34 6,017,543.78 569,970.54 4.00 83.62 512.40 6,017,600.22 569,925.07 4.00 148.27 461.77 6,017,656.60 569,873.92 4.00 218.07 405.71 6,017,712.64 569,817.35 4.00 292.69 344.50 6,017,768.08 569,755.62 4.00 371.76 278.42 6,017,822.64 569,689.03 4.00 454.89 207.80 6,017,876.06 569,617.92 4.00 541.68 132.99 6,017,928.08 569,542.63 4.00 631.70 105.06 6,017,946.44 569,514.53 4.00 664.87 54.35 6,017,978.44 569,463.52 4.00 724.53 -27.74 6,018,026.90 569,380.99 4.00 819.70 -112.88 6,018,073.22 569,295.42 4.00 916.75 -200.65 6,018,117.18 569,207.25 4.00 1,015.21 -276.38 6,018,152.25 569,131.19 4.00 1,098.97 -290.60 6,018,158.60 569,116.91 0.00 1,114.60 -381.25 6,018,199.06 569,025.89 0.00 1,214.21 -471.90 6,018,239.53 568,934.87 0.00 1,313.83 -562.55 6,018,279.99 568,843.84 0.00 1,413.45 -642.70 6,018,315.76 568,763.37 0.00 1,501.53 -653.20 6,018,320.45 568,752.82 0.00 1,513.07 -684.30 6,018,334.33 568,721.59 0.00 1,547.25 -743.95 6,018,360.95 568,661.70 4.00 1,612.79 -809.28 6,018,390.11 568,596.10 4.00 1,684.59 -834.93 6,018,401.56 568,570.35 0.00 1,712.77 1122018 5:17 07PM Page 5 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 wp09 Planned Survey Measured MPE-35 wp09 @ 48.20usft MD Reference: Vertical North Reference: Depth Inclination Azimuth Depth TVDss (usft) (°) (°) (usft) usft 6,200.00 90.50 294.50 4,427.48 4,379.28 6,300.00 90.50 294.50 4,426.60 4,378.40 6,400.00 90.50 294.50 4,425.73 4,377.53 6,500.00 90.50 294.50 4,424.86 4,376.66 6,600.00 90.50 294.50 4,423.99 4,375.79 6,700.00 90.50 294.50 4,423.11 4,374.91 6,800.00 90.50 294.50 4,422.24 4,374.04 6,900.00 90.50 294.50 4,421.37 4,373.17 7,000.00 90.50 294.50 4,420.50 4,372.30 7,100.00 90.50 294.50 4,419.62 4,371.42 7,138.93 90.50 294.50 4,419.28 4,371.08 Start Dir 40/100' : 7138.93' MD, 4419.28'TVD 7,200.00 92.94 294.50 4,417.45 4,369.25 7,248.93 94.90 294.50 4,414.10 4,365.90 End Dir : 7248.93' MD, 4414.1' TVD 2,732.55 7,300.00 94.90 294.50 4,409.74 4,361.54 7,323.93 94.90 294.50 4,407.70 4,359.50 Start Dir 4°/100' : 7323.93' MD, 4407.7'TVD -1,926.54 7,400.00 91.86 294.50 4,403.21 4,355.01 7,433.93 90.50 294.50 4,402.52 4,354.32 End Dir : 7433.93' MD, 4402.52' TVD 6,018,929.32 7,500.00 90.50 294.50 4,401.94 4,353.74 7,600.00 90.50 294.50 4,401.07 4,352.87 7,700.00 90.50 294.50 4,400.19 4,351.99 7,800.00 90.50 294.50 4,399.32 4,351.12 7,900.00 90.50 294.50 4,398.45 4,350.25 8,000.00 90.50 294.50 4,397.58 4,349.38 8,100.00 90.50 294.50 4,396.70 4,348.50 8,150.00 90.50 294.50 4,396.27 4,348.07 Start Dir 3-/100': 8150' MD, 4396.279VD 6,019,173.00 8,200.00 90.50 296.00 4,395.83 4,347.63 8,300.00 90.50 299.00 4,394.96 4,346.76 8,333.33 90.50 300.00 4,394.67 4,346.47 End Dir : 8333.33' MD, 4394.67' TVD 6,019,254.83 8,400.00 90.50 300.00 4,394.09 4,345.89 8,504.90 90.50 300.00 4,393.17 4,344.97 Start Dir 4-1100': 8504.9' MD, 4393.17'TVD 6,019,316.30 8,600.00 86.70 300.00 4,395.50 4,347.30 8,619.90 85.90 300.00 4,396.78 4,348.58 End Dir : 8619.9' MD, 4396.78' TVD 566,384.82 8,684.90 85.90 300.00 4,401.43 4,353.23 Start Dir 401100': 8684.9' MD, 4401.43 TVD 4.00 8,700.00 86.50 300.00 4,402.43 4,354.23 8,799.90 90.50 300.00 4,405.04 4,356.84 End Dir : 8799.9' MD, 4405.04' TVD 4,295.06 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-35 TVD Reference: MPE-35 wp09 @ 48.20usft MD Reference: MPE-35 wp09 @ 48.20usft North Reference: True Survey Calculation Method: Minimum Curvature 112,2018 5:17.07PM Page 6 COMPASS 5000.15 Build 91 / Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 4,379.28 2,317.88 -925.92 6,018,442.18 568,478.98 0.00 1,812.77 2,359.35 -1,016.91 6,018,482.79 568,387.61 0.00 1,912.76 2,400.82 -1,107.90 6,018,523.40 568,296.25 0.00 2,012.76 2,442.29 -1,198.90 6,018,564.02 568,204.88 0.00 2,112.75 2,483.75 -1,289.89 6,018,604.63 568,113.52 0.00 2,212.75 2,525.22 -1,380.88 6,018,645.25 568,022.15 0.00 2,312.74 2,566.69 -1,471.88 6,018,685.86 567,930.78 0.00 2,412.74 2,608.16 -1,562.87 6,018,726.47 567,839.42 0.00 2,512.73 2,649.62 -1,653.86 6,018,767.09 567,748.05 0.00 2,612.73 2,691.09 -1,744.85 6,018,807.70 567,656.68 0.00 2,712.72 2,707.24 -1,780.28 6,018,823.51 567,621.11 0.00 2,751.65 2,732.55 -1,835.82 6,018,848.31 567,565.34 4.00 2,812.69 2,752.79 -1,880.24 6,018,868.13 567,520.74 4.00 2,861.50 2,773.89 -1,926.54 6,018,888.80 567,474.25 0.00 2,912.38 2,783.78 -1,948.23 6,018,898.48 567,452.47 0.00 2,936.23 2,815.27 -2,017.33 6,018,929.32 567,383.09 4.00 3,012.15 2,829.33 -2,048.19 6,018,943.10 567,352.10 4.00 3,046.07 2,856.73 -2,108.31 6,018,969.93 567,291.73 0.00 3,112.14 2,898.20 -2,199.31 6,019,010.55 567,200.36 0.00 3,212.14 2,939.67 -2,290.30 6,019,051.16 567,109.00 0.00 3,312.13 2,981.13 -2,381.29 6,019,091.77 567,017.63 0.00 3,412.13 3,022.60 -2,472.28 6,019,132.39 566,926.26 0.00 3,512.12 3,064.07 -2,563.28 6,019,173.00 566,834.90 0.00 3,612.12 3,105.54 -2,654.27 6,019,213.62 566,743.53 0.00 3,712.11 3,126.27 -2,699.77 6,019,233.92 566,697.85 0.00 3,762.11 3,147.60 -2,744.99 6,019,254.83 566,652.44 3.00 3,812.10 3,193.77 -2,833.67 6,019,300.16 566,563.33 3.00 3,911.98 3,210.18 -2,862.68 6,019,316.30 566,534.17 3.00 3,945.19 3,243.51 -2,920.42 6,019,349.09 566,476.14 0.00 4,011.59 3,295.96 -3,011.26 6,019,400.69 566,384.82 0.00 4,116.05 3,343.49 -3,093.58 6,019,447.44 566,302.07 4.00 4,210.71 3,353.42 -3,110.78 6,019,457.21 566,284.78 4.00 4,230.49 3,385.83 -3,166.92 6,019,489.10 566,228.34 0.00 4,295.06 3,393.37 -3,179.97 6,019,496.51 566,215.22 4.00 4,310.06 3,443.29 -3,266.44 6,019,545.62 566,128.30 4.00 4,409.50 112,2018 5:17.07PM Page 6 COMPASS 5000.15 Build 91 / HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E35 Design: MPU E-35 wp09 Planned Survey Measured MPE-35 wp09 @ 48.20usft MD Reference: MPE-35 wp09 @ 48.20usft North Reference: Vertical Survey Calculation Method: Minimum Curvature Depth Inclination Azimuth Depth TVDss (usft) (°) 564,822.92 (°) 6,019,594.85 (usft) usft 0.00 8,900.00 90.50 6,019,644.04 300.00 -4,665.48 4,404.17 4,355.97 0.00 9,000.00 90.50 -4,739.11 300.00 4,708.35 4,403.29 4,355.09 565,780.00 9,100.00 90.50 4,807.93 300.00 6,019,791.59 4,402.42 4,354.22 0.00 9,200.00 90.50 6,019,840.77 300.00 -4,919.75 4,401.55 4,353.35 0.00 9,300.00 90.50 -5,010.53 300.00 5,106.69 4,400.68 4,352.48 565,431.78 9,400.00 90.50 5,206.27 300.00 6,019,988.33 4,399.80 4,351.60 0.00 9,500.00 90.50 6,020,037.51 300.00 -5,282.85 4,398.93 4,350.73 0.00 9,600.00 90.50 -5,373.62 300.00 5,505.03 4,398.06 4,349.86 565,161.04 9,700.00 90.50 5,515.99 300.00 6,902.03 4,397.18 4,348.98 6,020,716.24 9,800.00 90.50 6,915.94 300.00 -5,555.44 4,396.31 4,348.11 4.00 9,900.00 90.50 -5,596.70 300.00 563,786.76 4,395.44 4,347.24 4,709.27 9,911.01 90.50 563,737.83 300.00 7,100.12 4,395.34 4,347.14 6,020,789.87 Start Dir 4'/100': 9911.01' MD, 4395.34'TVD 4,750.41 10,000.00 94.06 563,644.71 300.00 7,201.57 4,391.80 4,343.60 10,026.01 95.10 300.00 4,389.73 4,341.53 End Dir : 10026.01' MD, 4389.73' ND 10,091.01 95.10 300.00 4,383.95 4,335.75 Start Dir 4°/100' : 10091.01' MD, 4383.95'TVD 10,100.00 94.74 300.00 4,383.18 4,334.98 10,206.01 90.50 300.00 4,378.33 4,330.13 End Dir : 10206.01' MD, 4378.33' ND 10,300.00 90.50 300.00 4,377.51 4,329.31 10,400.00 90.50 300.00 4,376.64 4,328.44 10,416.01 90.50 300.00 4,376.50 4,328.30 Start Dir 3°/100' : 10416.01' MD, 4376.5'TVD 10,500.00 90.50 297.48 4,375.77 4,327.57 10,589.34 90.50 294.80 4,374.99 4,326.79 10,600.00 90.50 294.80 4,374.89 4,326.69 10,700.00 90.50 294.80 4,374.02 4,325.82 10,800.00 90.50 294.80 4,373.15 4,324.95 10,900.00 90.50 294.80 4,372.28 4,324.08 11,000.00 90.50 294.80 4,371.40 4,323.20 11,100.00 90.50 294.80 4,370.53 4,322.33 11,200.00 90.50 294.80 4,369.66 4,321.46 11,300.00 90.50 294.80 4,368.79 4,320.59 11,313.91 90.50 294.80 4,368.66 4,320.46 Start Dir 4°/100' : 11313.91' MD, 4368.66'TVD 11,400.00 87.18 293.87 4,370.40 4,322.20 11,445.14 85.44 293.39 4,373.31 4,325.11 End Dir : 11415.14' MD, 4373.31' ND 11,498.41 85.44 293.39 4,377.54 4,329.34 Start Dir 401100': 11498.41' MD, 4377.54'TVD 11,500.00 85.51 293.40 4,377.66 4,329.46 11,600.00 89.37 294.45 4,382.13 4,333.93 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-35 TVD Reference: MPE-35 wp09 @ 48.20usft MD Reference: MPE-35 wp09 @ 48.20usft North Reference: True Survey Calculation Method: Minimum Curvature +N/ -S (usft) 3,493.34 3,543.33 3,593.33 3,643.33 3,693.33 3,743.33 3,793.32 3,843.32 3,893.32 3,943.32 3,993.32 3,998.82 +E/ -W (usft) -3,353.13 -3,439.73 -3,526.33 -3,612.92 -3,699.52 -3,786.12 -3,872.72 -3,959.32 -4,045.92 -4,132.52 -4,219.12 -4,228.65 4,043.27 -4,305.65 4,056.24 -4,328.10 4,088.61 4,384.17 Map Map 6,020,184.84 564,996.91 4.00 5,703.75 Northing Easting 6,020,236.92 OLS Vert Section (usft) (usft) -4,565.01 4,355.97 564,822.92 0.00 6,019,594.85 566,041.16 -4,651.61 0.00 4,509.18 0.00 6,019,644.04 565,954.10 -4,665.48 0.00 4,608.76 0.00 6,019,693.22 565,867.05 -4,739.11 0.00 4,708.35 3.00 6,019,742.40 565,780.00 -4,819.30 0.00 4,807.93 3.00 6,019,791.59 565,692.94 -4,828.98 0.00 4,907.52 0.00 6,019,840.77 565,605.89 -4,919.75 0.00 5,007.10 0.00 6,019,889.96 565,518.84 -5,010.53 0.00 5,106.69 0.00 6,019,939.14 565,431.78 -5,101.30 0.00 5,206.27 0.00 6,019,988.33 565,344.73 -5,192.08 0.00 5,305.86 0.00 6,020,037.51 565,257.68 -5,282.85 0.00 5,405.44 0.00 6,020,086.70 565,170.63 -5,373.62 0.00 5,505.03 0.00 6,020,092.11 565,161.04 -5,464.40 0.00 5,515.99 0.00 6,020,135.84 565,083.64 4.00 5,604.53 6,020,148.59 565,061.07 4.00 5,630.35 6,020,180.44 565,004.71 0.00 5,694.83 4,093.09 -4,391.93 6,020,184.84 564,996.91 4.00 5,703.75 4,146.03 -4,483.62 6,020,236.92 564,904.74 4.00 5,809.19 4,193.02 -4,565.01 6,020,283.15 564,822.92 0.00 5,902.79 4,243.02 -4,651.61 6,020,332.33 564,735.87 0.00 6,002.37 4,251.02 -4,665.48 6,020,340.20 564,721.93 0.00 6,018.31 4,291.40 -4,739.11 6,020,379.89 564,647.93 3.00 6,102.09 4,330.76 -4,819.30 6,020,418.49 564,567.38 3.00 6,191.40 4,335.23 -4,828.98 6,020,422.88 564,557.66 0.00 6,202.06 4,377.17 -4,919.75 6,020,463.97 564,466.51 0.00 6,302.05 4,419.12 -5,010.53 6,020,505.06 564,375.36 0.00 6,402.05 4,461.06 -5,101.30 6,020,546.15 564,284.21 0.00 6,502.05 4,503.00 -5,192.08 6,020,587.24 564,193.05 0.00 6,602.04 4,544.95 -5,282.85 6,020,628.34 564,101.90 0.00 6,702.04 4,586.89 -5,373.62 6,020,669.43 564,010.75 0.00 6,802.04 4,628.83 -5,464.40 6,020,710.52 563,919.60 0.00 6,902.03 4,634.67 -5,477.03 6,020,716.24 563,906.92 0.00 6,915.94 4,670.13 -5,555.44 6,020,750.97 563,828.19 4.00 7,002.00 4,688.19 -5,596.70 6,020,768.63 563,786.76 4.00 7,047.03 4,709.27 -5,645.44 6,020,789.26 563,737.83 0.00 7,100.12 4,709.90 -5,646.90 6,020,789.87 563,736.37 4.01 7,101.70 4,750.41 -5,738.19 6,020,829.53 563,644.71 4.00 7,201.57 11212018 5: 17:07PM Page 7 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 wp09 Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU E-35 MPE-35 wp09 @ 48.20usft MPE-35 wp09 @ 48.20usft True Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +Nl-S +EI -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 4,333.97 11,629.37 90.50 294.76 4,382.17 4,333.97 4,762.63 -5,764.90 6,020,841.50 563,617.89 4.00 7,230,94 End Dir : 11629.37' MD, 4382.17' ND 11,700.00 90,50 294.76 4,381.55 4,333.35 4,792.21 -5,829.03 6,020,870.48 563,553.49 0.00 7,301.57 11,800.00 90.50 294.76 4,380.68 4,332.48 4,834.10 -5,919.83 6,020,911.51 563,462.31 0.00 7,401.56 11,900.00 90.50 294.76 4,379.81 4,331.61 4,875.98 -6,010.64 6,020,952.54 563,371.13 0.00 7,501.56 12,000.00 90.50 294.76 4,378.93 4,330.73 4,917.86 -6,101.44 6,020,993.57 563,279.95 0.00 7,601.56 12,100.00 90.50 294.76 4,378.06 4,329.86 4,959.74 -6,192.25 6,021,034.60 563,188.77 0.00 7,701.55 12,200.00 90.50 294.76 4,377.19 4,328.99 5,001.62 -6,283.05 6,021,075.62 563,097.59 0.00 7,801.55 12,300.00 90.50 294.76 4,376.32 4,328.12 5,043.50 -6,373.85 6,021,116.65 563,006.40 0.00 7,901.54 12,400.00 90.50 294.76 4,375.44 4,327.24 5,085.38 -6,464.66 6,021,157.68 562,915.22 0.00 8,001.54 12,500.00 90.50 294.76 4,374.57 4,326.37 5,127.26 -6,555.46 6,021,198.71 562,824.04 0.00 8,101.54 12,600.00 90.50 294.76 4,373.70 4,325.50 5,169.14 -6,646.26 6,021,239.74 562,732.86 0.00 8,201.53 12,700.00 90.50 294.76 4,372.83 4,324,63 5,211.02 -6,737.07 6,021,280.77 562,641.68 0.00 8,301.53 12,714.37 90.50 294.76 4,372.70 4,324.50 5,217.04 -6,750.12 6,021,286.66 562,628.58 0.00 8,315.90 Start Dir 4°/100' : 12714.37' MD, 4372.7TVD 12,800.00 93.93 294.74 4,369.39 4,321.19 5,252.85 -6,827.81 6,021,321.75 562,550.56 4.00 8,401.45 12,826.32 94.98 294.73 4,367.35 4,319.15 5,263.83 -6,851.65 6,021,332.50 562,526.62 4.00 8,427.69 End Dir : 12826.32' MD, 4367.35' TVD 12,903.01 94.98 294.73 4,360.70 4,312.50 5,295.79 -6,921.04 6,021,363.81 562,456.94 0.00 8,504.09 Start Dir 4011100': 12903.01' MD, 4360.7'7VD 13,000.00 91.10 294.76 4,355.56 4,307.36 5,336.31 -7,008.99 6,021,403.51 562,368.63 4.00 8,600.93 13,014.96 90.50 294.76 4,355.35 4,307.15 5,342.58 -7,022.57 6,021,409.65 562,354.99 4.00 8,615.89 End Dir : 13014.96' MD, 4355.35' TVD 13,100.00 90.50 294.76 4,354.61 4,306.41 5,378.19 -7,099.79 6,021,444.54 562,277.45 0.00 8,700.92 13,200.00 90.50 294.76 4,353.73 4,305.53 5,420.07 -7,190.59 6,021,485.57 562,186.27 0.00 8,800.92 13,300.00 90.50 294.76 4,352.86 4,304.66 5,461.95 -7,281.40 6,021,526.60 562,095.09 0.00 8,900.92 13,400.00 90.50 294.76 4,351.99 4,303.79 5,503.83 -7,372.20 6,021,567.63 562,003.91 0.00 9,000.91 13,500.00 90.50 294.76 4,351.12 4,302.92 5,545.72 -7,463.00 6,021,608.65 561,912.72 0.00 9,100.91 13,600.00 90.50 294.76 4,350.24 4,302.04 5,587.60 -7,553.81 6,021,649.68 561,821.54 0.00 9,200.90 13,700.00 90.50 294.76 4,349.37 4,301.17 5,629.48 -7,644.61 6,021,690.71 561,730.36 0.00 9,300.90 13,800.00 90.50 294.76 4,348.50 4,300.30 5,671.36 -7,735.41 6,021,731.74 561,639.18 0.00 9,400.90 13,900.00 90.50 294.76 4,347.63 4,299.43 5,713.24 -7,826.22 6,021,772.77 561,548.00 0.00 9,500.89 14,000.00 90.50 294.76 4,346.75 4,298.55 5,755.12 -7,917.02 6,021,813.80 561,456.82 0.00 9,600.89 14,100.00 90.50 294.76 4,345.88 4,297.68 5,797.00 -8,007.82 6,021,854.82 561,365.64 0.00 9,700.89 14,114.96 90.50 294.76 4,345.75 4,297.55 5,803.26 -8,021.41 6,021,860.96 561,352.00 0.00 9,715.84 Start Dir 4-1100': 14114.96' MD, 4345.75TVD 14,200.00 87.10 294.74 4,347.53 4,299.33 5,838.85 -8,098.61 6,021,895.83 561,274.48 4.00 9,800.85 14,236.74 85.63 294.74 4,349.86 4,301.66 5,854.20 -8,131.91 6,021,910.86 561,241.04 4.00 9,837.52 End Dir : 14236.74' MD, 4349.86' TVD 14,293.55 85.63 294.74 4,354.19 4,305.99 5,877.90 -8,183.36 6,021,934.08 561,189.38 0.00 9,894.16 Start Dir 401100': 14293.55' MD, 4354.19'TVD 14,300.00 85.89 294.74 4,354.67 4,306.47 5,880.59 -8,189.20 6,021,936.72 561,183.51 4.00 9,900.60 14,400.00 89.89 294.76 4,358.36 4,310.16 5,922.42 -8,279.93 6,021,977.69 561,092.40 4.00 10,000.51 14,415.34 90.50 294.76 4,358.31 4,310.11 5,928.84 -8,293.86 6,021,983.98 561,078.41 4.00 10,015.85 End Dir : 14415.34' MD, 4358.31' TVD 112/2018 5:17.,07PM Page 8 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E-35 Design: MPU E-35 wp09 Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (°) (°) (usft) 14,500.00 90.50 294.76 4,357.57 14,600.00 90.50 294.76 4,356.69 14,700.00 90.50 294.76 4,355.82 14,800.00 90.50 294.76 4,354.95 14,900.00 90.50 294.76 4,354.08 15,000.34 90.50 294.76 4,353.20 Total Depth : 15000.34' MD, 4353.2' TVD Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-35 TVD Reference: MPE-35 wp09 @ 48.20usft MD Reference: MPE-35 wp09 @ 48.20usft North Reference: True Survey Calculation Method: Minimum Curvature Targets Target Name - hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E! -W -Shape (°) (°) (usft) (usft) (usft) MPE-35 wp08 CP3 0.00 0.00 4,396.61 4,044.59 -4,207.51 - plan misses target center by 50.23usft at 9915.53usft MD (4395.30 TVD, 4001.08 N, -4232.56 E) - Point MPE-35 wp08 CP6 0.00 0.00 4,345.75 5,803.26 -8,021.40 - plan hits tarqet center - Point MPE-35 wp06 CPI 0.00 0.00 4,419.28 2,707.23 -1,780.28 - plan misses target center by 0.01usft at 7138.93usft MD (4419.28 TVD, 2707.24 N, -1780.28 E) - Point MPE-35 wp08 CP2 0.00 0.00 4,393.56 3,458.38 -2,936.21 - plan misses target center by 178.18usft at 8521.12usft MD (4393.12 TVD, 3304.07 N, -3025.31 E) - Point MPE-35 wp08 Toe 0.00 0.00 4,353.20 6,173.84 -8,825.06 - plan hits target center - Circle (radius 50.00) MPE-35 wp08 Heel 0.00 0.00 4,423.20 2,377.77 -609.30 - plan misses target center by 185.79usft at 5936.55usft MD (4423.39 TVD, 2208.70 N, -686.33 E) - Circle (radius 100.00) MPE-35 wp08 CP4 0.00 0.00 4,369.66 4,630.82 -5,478.81 - plan misses target center by 4.36usft at 11313.97usft MD (4368.66 TVD, 4634.69 N, -5477.08 E) - Point MPE-35 wp08 CPS 0.00 0.00 4,372.70 5,217.03 -6,750.11 - plan hits target center - Point Vert Section 10,100.50 10,200.50 10,300.50 10,400.49 10,500.49 10,600.82 Northing Easting (usft) (usft) 6,020,138.07 565,181.76 6,021,860.96 561,352.00 6,018,823.51 567,621.11 6,019,563.78 566,458.34 Map Map 560,545.00 TVDss +NIS +E/ -W Northing Easting DLS usft (usft) (usft) (usft) (usft) 4,309.37 4,309.37 5,964.30 -8,370.74 6,022,018.72 561,001.21 0.00 4,308.49 6,006.18 -8,461.54 6,022,059.75 560,910.03 0.00 4,307.62 6,048.06 -8,552.34 6,022,100.78 560,818.85 0.00 4,306.75 6,089.94 -8,643.15 6,022,141.80 560,727.67 0.00 4,305.88 6,131.82 -8,733.95 6,022,182.83 560,636.49 0.00 4,305.00 6,173.84 -8,825.06 6,022,224.00 560,545.00 0.00 Targets Target Name - hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E! -W -Shape (°) (°) (usft) (usft) (usft) MPE-35 wp08 CP3 0.00 0.00 4,396.61 4,044.59 -4,207.51 - plan misses target center by 50.23usft at 9915.53usft MD (4395.30 TVD, 4001.08 N, -4232.56 E) - Point MPE-35 wp08 CP6 0.00 0.00 4,345.75 5,803.26 -8,021.40 - plan hits tarqet center - Point MPE-35 wp06 CPI 0.00 0.00 4,419.28 2,707.23 -1,780.28 - plan misses target center by 0.01usft at 7138.93usft MD (4419.28 TVD, 2707.24 N, -1780.28 E) - Point MPE-35 wp08 CP2 0.00 0.00 4,393.56 3,458.38 -2,936.21 - plan misses target center by 178.18usft at 8521.12usft MD (4393.12 TVD, 3304.07 N, -3025.31 E) - Point MPE-35 wp08 Toe 0.00 0.00 4,353.20 6,173.84 -8,825.06 - plan hits target center - Circle (radius 50.00) MPE-35 wp08 Heel 0.00 0.00 4,423.20 2,377.77 -609.30 - plan misses target center by 185.79usft at 5936.55usft MD (4423.39 TVD, 2208.70 N, -686.33 E) - Circle (radius 100.00) MPE-35 wp08 CP4 0.00 0.00 4,369.66 4,630.82 -5,478.81 - plan misses target center by 4.36usft at 11313.97usft MD (4368.66 TVD, 4634.69 N, -5477.08 E) - Point MPE-35 wp08 CPS 0.00 0.00 4,372.70 5,217.03 -6,750.11 - plan hits target center - Point Vert Section 10,100.50 10,200.50 10,300.50 10,400.49 10,500.49 10,600.82 Northing Easting (usft) (usft) 6,020,138.07 565,181.76 6,021,860.96 561,352.00 6,018,823.51 567,621.11 6,019,563.78 566,458.34 6,022,224.00 Vertical 560,545.00 6,018,505.00 Depth 568,795.00 6,020,712.37 6,021,286.66 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name () ( ) 5,934.31 4,423.20 9 5/8" x 12 1/4" 9-5/8 12-1/4 15,000.34 4,353.20 7' x 8 1/2" 7 8-1/2 563,905.17 562,628.58 1112/2018 5:17:07PM Page 9 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US+CANADA Local Co-ordinate Reference: Well Plan: MPU E-35 Company: Hilcorp Alaska, LLC Local Coordinates TVD Reference: MPE-35 wp09 @ 48.20usft Project: Milne Point +N/ -S MD Reference: MPE-35 wp09 @ 48.20usft Site: M Pt E Pad (usft) North Reference: True Well: Plan: MPU E-35 0.00 Survey Calculation Method: Minimum Curvature Wellbore: MPU E-35 12.52 10.50 End Dir : 550' MD, 549.29' TVD Design: MPU E-35 wp09 27.51 23.09 Start Dir 40/100': 700' MD, 698'TVD Formations 1,105.04 116.92 98.11 End Dir : 1125' MD, 1105.04' TVD Measured Vertical Vertical 2,015.00 434.60 Dip Start Dir 4°/100' : 2125' MD, 2015'TVD Depth Depth Depth SS 2,123.52 477.82 Dip Direction End Dir : 2245.99' MD, 2123.52' TVD (usft) (usft) 3,011.31 Name Lithology (1) ( ) Start Dir 4°/100' : 3251.63' MD, 3011.31'TVD 1,875.75 1,788.20 BPRF 2,021.87 0.00 End Dir : 5484.31' MD, 4383.98' TVD - Start ESP Tangent Hold 2,689.66 2,515.20 SV1 2,207.77 0.00 Start Dir 4°/100' : 5934.31' MD, 4423.2rVD 4,193.76 3,807.20 LA3 2,264.72 0.00 End Dir : 6071.81' MD, 4428.6' TVD 5,036.05 4,284.20 SB -NA 2,707.24 0.00 Start Dir 4°/100': 7138.93'MD, 4419.28'TVD 5,888.41 4,419.20 SB -OA 2,752.79 0.00 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 300.00 300.00 0.00 0.00 Start Dir 3°/100' : 300' MD, 300 -TVD 550.00 549.29 12.52 10.50 End Dir : 550' MD, 549.29' TVD 700.00 698.00 27.51 23.09 Start Dir 40/100': 700' MD, 698'TVD 1,125.00 1,105.04 116.92 98.11 End Dir : 1125' MD, 1105.04' TVD 2,125.00 2,015.00 434.60 364.67 Start Dir 4°/100' : 2125' MD, 2015'TVD 2,245.99 2,123.52 477.82 396.07 End Dir : 2245.99' MD, 2123.52' TVD 3,251.63 3,011.31 876.37 649.64 Start Dir 4°/100' : 3251.63' MD, 3011.31'TVD 5,484.31 4,383.98 2,021.87 -276.38 End Dir : 5484.31' MD, 4383.98' TVD - Start ESP Tangent Hold 5,934.31 4,423.20 2,207.77 -684.30 Start Dir 4°/100' : 5934.31' MD, 4423.2rVD 6,071.81 4,428.60 2,264.72 -809.28 End Dir : 6071.81' MD, 4428.6' TVD 7,138.93 4,419.28 2,707.24 -1,780.28 Start Dir 4°/100': 7138.93'MD, 4419.28'TVD 7,248.93 4,414.10 2,752.79 -1,880.24 End Dir : 7248.93' MD, 4414.1' TVD 7,323.93 4,407.70 2,783.78 -1,948.23 Start Dir 4-/100': 7323.93' MD, 4407.7'TVD 7,433.93 4,402.52 2,829.33 -2,048.19 End Dir : 7433.93' MD, 4402.52' TVD 8,150.00 4,396.27 3,126.27 -2,699.77 Start Dir 3°/100' : 8150' MD, 4396.27'TVD 8,333.33 4,394.67 3,210.18 -2,862.68 End Dir : 8333.33' MD, 4394.67' TVD 8,504.90 4,393.17 3,295.96 -3,011.26 Start Dir 4°/100' : 8504.9' MD, 4393.17'TVD 8,619.90 4,396.78 3,353.42 -3,110.78 End Dir : 8619.9' MD, 4396.78' TVD 8,684.90 4,401.43 3,385.83 -3,166.92 Start Dir 4-1100': 8684.9' MD, 4401.43'TVD 8,799.90 4,405.04 3,443.29 -3,266.44 End Dir : 8799.9' MD, 4405.04' TVD 9,911.01 4,395.34 3,998.82 -4,228.65 Start Dir 4-/100': 9911.01' MD, 4395.34'TVD 10,026.01 4,389.73 4,056.24 4,328.10 End Dir : 10026.01' MD, 4389.73' TVD 10,091.01 4,383.95 4,088.61 -4,384.17 Start Dir 4-/100': 10091.01' MD, 4383.95'TVD 10,206.01 4,378.33 4,146.03 4,483.62 End Dir : 10206.01' MD, 4378.33' TVD 10,416.01 4,376.50 4,251.02 -4,665.48 Start Dir 3-/100': 10416.01' MD, 4376.5'TVD 11,313.91 4,368.66 4,634.67 -5,477.03 Start Dir40/100' : 11313,91' MD, 4368.66'TVD 11,445.14 4,373.31 4,688.19 -5,596.70 End Dir : 11445.14' MD, 4373.31' TVD 11,498.41 4,377.54 4,709.27 -5,645.44 Start Dir41/100' : 11498.41' MD, 4377.54'TVD 11,629.37 4,382.17 4,762.63 -5,764.90 End Dir : 11629.37' MD, 4382.17' TVD 12,714.37 4,372.70 5,217.04 -6,750.12 Start Dir 4°/100' : 12714.37' MD, 4372.7'TVD 12,826.32 4,367.35 5,263.83 -6,851.65 End Dir : 12826.32' MD, 4367.35' TVD 12,903.01 4,360.70 5,295.79 -6,921.04 Start Dir 4°/100' : 12903.01' MD, 4360.7'TVD 13,014.96 4,355.35 5,342.58 -7,022.57 End Dir : 13014.96' MD, 4355.35' TVD 14,114.96 4,345.75 5,803.26 -8,021.41 Start Dir 401100': 14114.96' MD, 4345.75'TVD 14,236.74 4,349.86 5,854.20 -8,131.91 End Dir : 14236.74' MD, 4349.86' TVD 14,293.55 4,354.19 5,877.90 -8,183.36 Start Dir 4°/100': 14293.55' MD, 4354.19'TVD 14,415.34 4,358.31 5,928.84 -8,293.86 End Dir : 14415.34' MD, 4358.31' TVD 15,000.34 4,353.20 6,173.84 -8,825.06 Total Depth: 15000.34' MD, 4353.2' TVD 11/2/2018 5:17:07PM Page 10 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt E Pad Plan: MPU E-35 MPU E-35 MPU E-35 wp09 Sperry Drilling Services Clearance Summary Anticollision Report 02 November, 2018 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU EJ5 - MPU E-35 - MPU E-35 wp09 Well Coordinates: 6,016,133.24 N, 569,426.37 E (70° 27' 15.94" N, 149' 26.00.44" W) Datum Height: MPE-35 wp09 @ 48.20usft Scan Range: 26.50 to 5,935.00 usft. Measured Depth. Scan Radius Is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation Is 1,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 10011000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU E-35 - MPU E-35 wp09 Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU E-35 - MPU E-35 - MPU E-35 wp09 Scan Range: 26.50 to 5,935.00 usft. Measured Depth. Scan Radius Is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Measured Minimum @Measured Ellipse Site Name Depth Distance Depth Separation Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) M Pt A Pad M Pt C Pad M Pt CFP MPCFP-2-MPCFP-2-MPCFP-2 5,453.29 522.88 5,453.29 456.82 MPCFP-2 - MPCFP-2 - MPCFP-2 5,501.50 525.09 5,501.50 458.59 M Pt E Pad Hileorp Alaska, LLC Milne Point @Measured Clearance Summary Based on 652.46 Depth Factor Minimum Separation Warning usft MPE-03 - MPE-03 - MPE-03 726.50 630.82 4,234.85 7.915 Ellipse Separation Pass - 4,231.99 7.896 Clearance Factor Pass - MPE-03 - MPE-03 - MPE-03 652.46 630.45 652.46 624.08 653.27 99.031 Centre Distance Pass - MPE-03 - MPE-03 - MPE-03 726.50 630.82 726.50 623.82 721.64 90.173 Ellipse Separation Pass - MPE-03 - MPE-03 - MPE-03 5,935.00 1,453.10 5,935.00 1,406.08 4,437.16 30.901 Clearance Factor Pass - MPE-04 - MPE-04 - MPE-04 1,900.42 67.29 1,900.42 40.13 1,988.95 2.477 Centre Distance Pass - MPE-04 - MPE-04 - MPE-04 1.926.50 68.81 1,926.50 39.61 2,010.73 2.357 Clearance Factor Pass - MPE-05 - MPE-05 - MPE-05 1,506.27 241.80 1,506.27 222.57 1,570.09 12.573 Centre Distance Pass - MPE-05 - MPE-05 - MPE-05 1,526.50 242.03 1,526.50 222.56 1,587.75 12.435 Ellipse Separation Pass - MPE-05 - MPE-05 - MPE-05 1,626.50 250.08 1,626.50 229.51 1,672.80 12.155 Clearance Factor Pass - MPE-06 - MPE-06 - MPE-06 1,893.10 148.18 1,893.10 124.72 1,944.71 6.318 Centre Distance Pass - MPE-06 - MPE-06 - MPE-06 1,901.50 148.22 1,901.50 124.65 1,952.35 6.288 Ellipse Separation Pass - MPE-06 - MPE-06 - MPE-06 1,976.50 152.29 1,976.50 127.64 2,020.06 6.176 Clearance Factor Pass - MPE-07 - MPE-07 - MPE-07 786.39 234.43 786.39 224.45 793.48 23.486 Centre Distance Pass - MPE-07 - MPE-07 - MPE-07 851.50 234.83 851.50 224.05 857.31 21.768 Ellipse Separation Pass - MPE-07 - MPE-07 - MPE-07 1,201.50 271.11 1,201.50 256.01 1,184.28 17.960 Clearance Factor Pass - MPE-08 - MPE-08 - MPE-08 2,676.50 67.84 2,676.50 33.00 2,772.33 1.947 Clearance Factor Pass - MPE-08 - MPE-08 - MPE-08 2,698.40 66.82 2,698.40 32.75 2,790.97 1.961 Ellipse Separation Pass - MPE-10 - MPE-10 - MPE-10 2,116.96 356.06 2,116.96 323.69 2,297.80 10.998 Centre Distance Pass - MPE-10 - MPE-10 - MPE-10 2,151.50 356.64 2,151.50 322.87 2,329.45 10.562 Ellipse Separation Pass - MPE-10 - MPE-10 - MPE-10 2,426.50 411.41 2,426.50 366.42 2,550.14 9.144 Clearance Factor Pass - MPE-12 - MPE-12 - MPE-12 261.79 120.01 261.79 116.43 270.95 33.494 Centre Distance Pass - 02 November, 2018 - 17:12 Page 2 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU E-35 - MPU E-35 wp09 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU E-35 - MPU E-35 - MPU E-35 wp09 Scan Range: 26.50 to 5,935.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point 02 November, 2018 - 17.12 Page 3 of 8 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Waltham Name - Design (usft) (usft) (usft) (usft) usft MPE-12 - MPE-12 - MPE-12 376.50 120.50 376.50 115.70 383.74 25.090 Ellipse Separation Pass - MPE-12 - MPE-12 - MPE-12 1,976.50 180.55 1,976.50 156.14 1,971.83 7.397 Clearance Factor Pass - MPE-13 - MPE-13B - MPE-13B 26.50 393.55 26.50 392.74 37.16 486.346 Centre Distance Pass - MPE-13 - MPE-13B - MPE-13B 76.50 393.73 76.50 392.61 84.58 353.864 Ellipse Separation Pass - MPE-13-MPE-13B-MPE-13B 1,426.50 546.12 1,426.50 533.28 1,350.42 42.565 Clearance Factor Pass - MPE-14 - MPE-14 - MPE-14 230.01 198.17 230.01 196.11 239.51 96.376 Centre Distance Pass - MPE-14 - MPE-14 - MPE-14 301.50 198.27 301.50 195.71 310.51 77.421 Ellipse Separation Pass - MPE-14 - MPE-14 - MPE-14 976.50 274.00 976.50 266.62 979.24 37.155 Clearance Factor Pass - MPE-14 - MPE-14A- MPE-14A 230.01 198.17 230.01 196.40 239.51 111.647 Centre Distance Pass - MPE-14 - MPE-14A- MPE-14A 301.50 198.27 301.50 195.99 310.51 86.973 Ellipse Separation Pass - MPE-14 - MPE-14A - MPE-14A 1,001.50 280.72 1,001.50 273.45 1,002.61 38.619 Clearance Factor Pass - MPE-14-MPE-I4APB1-MPE-I4APB1 230.01 198.17 230.01 196.11 239.51 96.376 Centre Distance Pass - MPE-14 - MPE-14APB1 - MPE-14APB1 301.50 198.27 301.50 195.71 310.51 77.421 Ellipse Separation Pass - MPE-14 - MPE-14APB1 - MPE-14APB1 976.50 274.00 976.50 266.62 979.24 37.154 Clearance Factor Pass - MPE-15 - MPE-15 - MPE-15 101.50 182.06 101.50 180.56 107.20 120.980 Centre Distance Pass - MPE-15 - MPE-15 - MPE-15 301.50 183.83 301.50 179.42 304.64 41.751 Ellipse Separation Pass - MPE-15 - MPE-15 - MPE-15 901.50 260.89 901.50 247.74 892.97 19.841 Clearance Factor Pass - MPE-16 - MPE-16 - MPE-16 26.50 209.51 26.50 208.59 32.22 227.978 Centre Distance Pass - MPE-16 - MPE-16 - MPE-16 1,476.50 215.97 1,476.50 201.59 1,471.18 15.009 Ellipse Separation Pass - MPE-16 - MPE-16 - MPE-16 4,801.50 280.44 4,801.50 234.12 4,532.56 6.055 Clearance Factor Pass - MPE-17 - MPE-17 - MPE-17 920.23 48.52 920.23 41.34 931.11 6.753 Centre Distance Pass - MPE-17 - MPE-17 - MPE-17 926.50 48.55 926.50 41.31 937.23 6.708 Ellipse Separation Pass - MPE-17 - MPE-17 - MPE-17 951.50 49.31 951.50 41.85 961.58 6.611 Clearance Factor Pass - MPE-19 - MPE-19 - MPE-19 212.41 149.79 212.41 147.85 248.31 77.360 Centre Distance Pass - MPE-19 - MPE-19 - MPE-19 251.50 149.91 251.50 147.70 286.45 67.857 Ellipse Separation Pass - MPE-19 - MPE-19 - MPE-19 5,935.00 1,167.43 5,935.00 1,052.72 4,922.36 10.177 Clearance Factor Pass - MPE-20 - MPE-20 - MPE-20 314.71 238.72 314.71 235.84 323.43 82.679 Centre Distance Pass - MPE-20 - MPE-20 - MPE-20 351.50 238.87 351.50 235.72 360.44 75.795 Ellipse Separation Pass - MPE-20 - MPE-20 - MPE-20 976.50 305.92 976.50 298.34 963.37 40.339 Clearance Factor Pass - MPE-20 - MPE-20A- MPE-20A 314.71 238.72 314.71 236.07 325.98 90.159 Centre Distance Pass - 02 November, 2018 - 17.12 Page 3 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU E-35 - MPU E-35 wp09 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU E-35 - MPU E-35 - MPU E-35 wp09 Scan Range: 26.50 to 5,935.00 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point 02 November, 2018 - 17:12 Page 4 of 8 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPE-20 - MPE-20A- MPE-20A 351.50 238.87 351.50 235.96 362.99 82.030 Ellipse Separation Pass - MPE-20 - MPE-20A- MPE-20A 1,001.50 312.96 1,001.50 305.44 988.27 41.626 Clearance Factor Pass - MPE-20 - MPE-20AL1 - MPE-20AL1 314.71 238.72 314.71 236.20 325.98 94.822 Centre Distance Pass - MPE-20 - MPE-20AL1 - MPE-20AL1 351.50 238.87 351.50 236.09 362.99 85.870 Ellipse Separation Pass - MPE-20 - MPE-20AL1 - MPE-20AL1 1,001.50 312.96 1,001.50 305.57 988.27 42.360 Clearance Factor Pass - MPE-20 - MPE-20AL1PB1 - MPE-20AL1 PB1 314.71 238.72 314.71 235.56 325.98 75.463 Centre Distance Pass - MPE-20 - MPE-20ALIPB1 - MPE-20AL1 PB1 351.50 238.87 351.50 235.44 362.99 69.690 Ellipse Separation Pass - MPE-20-MPE-20AL1PB1-MPE-20AL1 PBI 976.50 305.92 976.50 298.06 965.92 38.921 Clearance Factor Pass - MPE-21 - MPE-21 - MPE-21 1,119.90 225.37 1,119.90 217.66 1,144.88 29.225 Centre Distance Pass - MPE-21 - MPE-21 - MPE-21 1,126.50 225.40 1,126.50 217.65 1,150.84 29.110 Ellipse Separation Pass - MPE-21 - MPE-21 - MPE-21 3,401.50 830.70 3,401.50 788.35 3,331.69 19.616 Clearance Factor Pass - MPE-23 - MPE-23 - MPE-23 772.85 170.50 772.85 163.17 777.68 23.277 Centre Distance Pass - MPE-23 - MPE-23 - MPE-23 801.50 170.60 801.50 163.02 805.81 22.511 Ellipse Separation Pass - MPE-23 - MPE-23 - MPE-23 1,076.50 191.70 1,076.50 181.66 1,069.07 19.082 Clearance Factor Pass - MPE-24 - MPE-24 - MPE-24 222.04 217.39 222.04 215.37 230.94 107.456 Centre Distance Pass - MPE-24 - MPE-24 - MPE-24 276.50 217.54 276.50 215.14 284.18 90.521 Ellipse Separation Pass - MPE-24 - MPE-24 - MPE-24 876.50 310.48 876.50 303.73 841.08 45,966 Clearance Factor Pass - MPE-24 - MPE-24A - MPE-24A 222.04 217.39 222.04 215.48 227.54 113.599 Centre Distance Pass - MPE-24 - MPE-24A- MPE-24A 276.50 217.54 276.50 215.25 280.78 94.837 Ellipse Separation Pass - MPE-24 - MPE-24A- MPE-24A 876.50 310.48 876.50 303.84 837.68 46.719 Clearance Factor Pass - MPE-24 - MPE-24AL1 - MPE-24AL1 222.04 217.39 222.04 215.58 227.54 120.139 Centre Distance Pass - MPE-24 - MPE-24AL1 - MPE-24AL1 276.50 217.54 276.50 215.35 280.78 99.348 Ellipse Separation Pass - MPE-24 - MPE-24AL1 - MPE-24AL1 876.50 310.48 876.50 303.94 837.68 47.462 Clearance Factor Pass - MPE-30 - MPE-30 - MPE-30 3,551.50 224.78 3,551.50 171.59 3,611.35 4.226 Clearance Factor Pass - MPE-30 - MPE-30 - MPE-30 3,576.50 223.52 3,576.50 170.81 3,632.10 4.241 Ellipse Separation Pass - MPE-30 - MPE-30 - MPE-30 3,599.60 223.13 3,599.60 171.19 3,648.54 4.295 Centre Distance Pass - MPE-30 - MPE-30A- MPE-30A 3,551.50 224.78 3,551.50 171.58 3,611.35 4.225 Clearance Factor Pass - MPE-30 - MPE-30A- MPEJOA 3,576.50 223.52 3,576.50 170.79 3,632.10 4.239 Ellipse Separation Pass - MPE-30 - MPE-30A - MPE-30A 3,599.60 223.13 3,599.60 171.17 3,648.54 4.294 Centre Distance Pass - MPE-30 - MPE-30AL1 - MPE-30AL1 3,551.50 224.78 3,551.50 171.59 3,611.35 4.226 Clearance Factor Pass - 02 November, 2018 - 17:12 Page 4 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU E-35 - MPU E-35 wp09 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU E-35 - MPU E-35 - MPU E-35 wp09 Scan Range: 26.50 to 5,935.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point 02 November, 2018 - 17.12 Page 5 of 8 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPE-30 - MPE-30ALl - MPE-30ALl 3,576.50 223.52 3,576.50 170.81 3,632.10 4.240 Ellipse Separation Pass - MPE-30 - MPE-30AL1 - MPE-30ALl 3,599.60 223.13 3,599.60 171.18 3,648.54 4.295 Centre Distance Pass - MPE-30 - MPE-30AL1 PBI - MPE-30AL1 PB1 3,551.50 224.78 3,551.50 171.44 3,611.35 4.214 Clearance Factor Pass - MPE-30 - MPE-30ALl PBI - MPE-30ALIPBI 3,576.50 223.52 3,576.50 170.66 3,632.10 4.228 Ellipse Separation Pass - MPE-30 - MPE-30ALl PBI - MPE-30ALIPB1 3,599.60 223.13 3,599.60 171.03 3,648.54 4.283 Centre Distance Pass - MPE-30 - MPE-30APB1 - MPE-30APB1 3,551.50 224.78 3,551.50 171.49 3,611.35 4.218 Clearance Factor Pass - MPE-30 - MPE-30APB1 - MPE-30APB1 3,576.50 223.52 3,576.50 170.70 3,632.10 4.232 Ellipse Separation Pass - MPE-30 - MPE-30APB1 - MPE-30APB1 3,599.60 223.13 3,599.60 171.08 3,648.54 4.287 Centre Distance Pass - MPE-31 - MPE-31 - MPE-31 1,993.23 364.02 1,99323 336.75 1,979.62 13.348 Centre Distance Pass - MPE-31 - MPE-31 - MPE-31 2,051.50 364.43 2,051.50 336.14 2,034.68 12.880 Ellipse Separation Pass - MPE-31 - MPE-31 - MPE-31 2,326.50 373.26 2,326.50 341.88 2,274.02 11.894 Clearance Factor Pass - MPE-31 - MPE-31PB1 - MPE-31 PB1 1,993.23 364.02 1,993.23 336.75 1,979.62 13.348 Centre Distance Pass - MPE-31 - MPE-31PB1 - MPE-31 PB1 2,051.50 364.43 2,051.50 336.14 2,034.68 12.880 Ellipse Separation Pass - MPE-31 - MPE-31PB1 - MPE-31 PB1 2,326.50 373.26 2,326.50 341.88 2,274.02 11.894 Clearance Factor Pass - MPE-32 - MPE-32 - MPE-32 2,811.46 334.52 2,811.46 311.45 2,835.25 14.499 Centre Distance Pass - MPE-32 - MPE-32 - MPE-32 2,826.50 334.54 2,826.50 311.43 2,849.90 14.476 Ellipse Separation Pass - MPE-32 - MPE-32 - MPE-32 3,926.50 434.84 3,926.50 391.26 3,830.34 9.977 Clearance Factor Pass - MPE-32 - MPE-321-1 - MPE-321-1 2,811.46 334.52 2,811.46 311.58 2,835.25 14.582 Centre Distance Pass - MPE-32-MPE-32L1-MPE-321-1 2,826.50 334.54 2,826.50 311.56 2,849.90 14.558 Ellipse Separation Pass- MPE-32 - MPE-321-1 - MPE-321-1 3,926.50 434.84 3,926.50 391.39 3,830.34 10.007 Clearance Factor _ Pass - MPE-32 - MPE-32PBI - MPE-32PB1 2,811.46 334.52 2,811.46 311.45 2,835.25 14.499 Centre Distance Pass - MPE-32-MPE-32PB1-MPE-32PB1 2,826.50 334.54 2,826.50 311.43 2,849.90 14.476 Ellipse Separation Pass - MPE-32 - MPE-32PB1 - MPE-32PB1 3,926.50 434.84 3,926.50 391.26 3,830.34 9.977 Clearance Factor Pass - MPE-33 - MPE-33 - MPE-33 26.50 570.06 26.50 569.32 33.51 770.370 Centre Distance Pass - MPE-33 - MPE-33 - MPE-33 301.50 571.06 301.50 568.66 305.48 237.643 Ellipse Separation Pass - MPE-33 - MPE-33 - MPE-33 5,935.00 712.54 5,935.00 606.16 5,019.35 6.698 Clearance Factor Pass - Plan: MPU E-36 - MPE-35 BHL objectives - MPE-36 w 276.50 30.13 276.50 27.56 276.50 11.714 Centre Distance Pass - Plan: MPU E-36 - MPE-35 BHL objectives - MPE-36 w 576.50 30.93 576.50 26.22 575.27 6.564 Ellipse Separation Pass - Plan: MPU E-36 - MPE-35 BHL objectives - MPE-36 w 676.50 33.35 676.50 27.91 674.23 6.123 Clearance Factor Pass - Plan: MPU E-37 - MPE-37 - MPE-37 wp07 276.50 60.58 276.50 56.92 276.50 16.514 Centre Distance Pass - 02 November, 2018 - 17.12 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPU E-35 - MPU E-35 wp09 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU E-35 - MPU E-35 - MPU E-35 wp09 Scan Range: 26.50 to 5,935.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point NIFTAY-7a.. . .. From To (usft) (usft) 26.50 5,935.00 MPU E-35 wp09 5,935.00 15,000.34 MPU E-35 wp09 Survey/Plan Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles /(Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 02 November, 2018 - 17:12 Page 6 of 8 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft Plan: MPU E-37 - MPE-37 - MPE-37 wp07 576.50 61.37 576.50 54.02 573.87 8.349 Ellipse Separation Pass - Plan: MPU E-37 - MPE-37 - MPE-37 wp07 701.50 67.15 701.50 58.28 694.64 7.565 Clearance Factor Pass - Plan: MPU E-38 - MPE-37 BHL Swap Draft - MPE-38 V 1,003.26 124.21 1,003.26 115.50 1,048.80 14.258 Ellipse Separation Pass - Plan: MPU E-38 - MPE-37 BHL Swap Draft - MPE-38 V 5,935.00 873.25 5,935.00 791.79 5,546.70 10.720 Clearance Factor Pass - Plan: MPU E-40 - MPE-40i - MPE-40 wp01 276.50 160.83 276.50 158.26 276.50 62.529 Centre Distance Pass - Plan: MPU E-40 - MPE-40i - MPE-40 wp01 301.50 160.83 301.50 158.08 301.50 58.456 Ellipse Separation Pass - Plan: MPU E-40 - MPE-401 - MPE-40 wp01 801.50 223.58 801.50 217.28 785.75 35.533 Clearance Factor Pass - Plan: MPU E41 - MPE-41 - MPE-41 wp01 276.50 158.03 276.50 155.33 276.50 58.448 Centre Distance Pass - Plan: MPU E-41 - MPE-41 - MPE-41 wp01 301.50 158.03 301.50 155.15 301.50 54.815 Ellipse Separation Pass - Plan: MPU E-41 - MPE-41 - MPE-41 wp01 4,351.50 1,360.46 4,351.50 1,301.72 7,400.47 23.159 Clearance Factor Pass - Prelim Duall-atPlan: MPU E-39 - MPU E -39i - MPU E-: 276.50 161.28 276.50 158.71 276.50 62.705 Centre Distance Pass - Prelim Duall-atPlan: MPU E-39 - MPU E -39i - MPU E-: 326.50 161.45 326.50 158.52 326.50 55.102 Ellipse Separation Pass - Prelim Duall-atPlan: MPU E-39 - MPU E -39i - MPU E-: 701.50 216.16 701.50 210.67 673.99 39.375 Clearance Factor Pass - NIFTAY-7a.. . .. From To (usft) (usft) 26.50 5,935.00 MPU E-35 wp09 5,935.00 15,000.34 MPU E-35 wp09 Survey/Plan Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles /(Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 02 November, 2018 - 17:12 Page 6 of 8 COMPASS HALLIBURTON Sperry Orlllinq Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E-35 Plan: MPU E-35 wp09 Co-okinate (NUE) Reference: Well Plea: MPU E-35. Tme North Vertical (ND) Referenw'. MPE-35wa09 ®48.NU$ft Measured Depth Reference: WE -35 al,09@48.20uaa Calculation WWI: MInT,am Cvmatum Ladder/S.F. Plots - SH(1 of 2) SURVEY PROGRAM Depth Fram Depth To Survey/Plan Tool 26.50 5935.00 MPU E-35 wp09 2_MVvD+IFR2+MS+Sa9 5935.00 15000.34 MPU E-35 wp09 2_MW IFR2+MS+Sag WEII, DEAQ Man: MPU E-35 NAD 1927(NADCON COMMS) AlaskaZne04 Ground level: 21.70 +N/ -S +E/ -W Northing Eesting latitude Dmpmde 0.00 0.00 601613324 56942637 70,454 .149.433 NO GLOBAL FILTER: Using user defined selection & filtering criteria 26.50 To 15013(34 CASING DETAILS TVD TVDSS MD Size Name 4423.20 4375.00 5934.31 9-5/8 95/8" z 12 1/4" 4353.20 4305.00 15000.34 7 7" x 8 1/2" MPE-04 Collision Risk Procedures Req. Collision Avoidance Req. No -Go Zone - Stop Drilling 0 400 800 1200 1600 2000 2400 Measured Depth (700 usft/in) MPE-08 2800 3200 3600 4000 4400 4800 5200 5600 6000 Measured Depth (700 usft/in) Hilcorp Alaska, LLC Milne Point M Pt E Pad Plan: MPU E-35 MPU E-35 MPU E-35 wp09 Sperry Drilling Services Clearance Summary Anticollision Report 02 November, 2018 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU E-35 - MPU E-35 - MPU E-35 wp09 Well Coordinates: 6,016,133.24 N, 569,426.37E (70° 27' 15.94" N, 149° 26' 00.44" W) Datum Height: MPE-35 wp09 @ 48.20usft Scan Range: 5,935.00 to 15,000.34 usft. Measured Depth. Scan Radius Is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services 02 November, 2018 - 17:13 Page 2 of 5 COMPASS Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU E-35 - MPU E-35 wp09 Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU E-35 - MPU E-35 - MPU E-35 wp09 Scan Range: 5,935.00 to 15,000.34 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name -Design (usft) (usft) (usft) (usft) usft M Pt A Pad MPA -01 - MPA -01 - MPA -01 - MPA -03 - MPA -03 - MPA -03 - MPA -03 - MPA -03 - MPA -03 - M Pt C Pad MQU C-41 - MPC -41 - MPC -41 15,000.34 591.86 15,000.34 219.24 9,174.46 1.588 Clearance Factor Pass - }.,,,,. UC41-MPC41 L1-MPC41 L1 15,000.34 591.86 15,000.34 219.35 9,174.46 1.589 Clearance Factor Pass - �y ,b1PUC-4I-MPC-41L2-MPC-41L2 - MPU C-41 - MPC41 L2 - MPC -411-2 - MPU C-41 - MPC -41 L2 - MPC -41 L2 - MPU C41 - MPC41PB1 - MPC-41PB1 15,000.34 720.83 15,000.34 480.22 8,766.00 2.996 Clearance Factor Pass - MPU C-41 - MPC -41 PB2 - MPC -41 PB2 15,000.34 591.86 15,000.34 218.73 9,174.46 1.586 Clearance Factor Pass - M Pt CFP MPCFP-2 - MPCFP-2 - MPCFP-2 5,935.00 710.22 5,935.00 638.01 4,206.16 9.836 Clearance Factor Pass - M Pt E Pad MPE-03 - MPE-03 - MPE-03 8,004.96 165.32 8,004.96 76.83 5,964.23 1.868 Centre Distance Pass - MPE-03 - MPE-03 - MPE-03 8,060.00 169.72 8,060.00 71.47 6,003.60 1.727 Ellipse Separation Pass - MPE-03 - MPE-03 - MPE-03 8,085.00 174.53 8,085.00 73.04 6,021.05 1.720 Clearance Factor Pass - MPE-13 -MPE-13B - MPE-13B 10,985.00 1,215.22 10,985.00 762.61 8,852.00 2.685 Clearance Factor Pass - MPE-13 - MPE-13B - MPE-13B 11,010.00 1,214.88 11,010.00 762.53 8,852.00 2.686 Ellipse Separation Pass - MPE-13 - MPE-13B - MPE-13B 11,013.83 1,214.88 11,013.83 762.59 8,852.00 2.686 Centre Distance Pass - MPE-16 - MPE-16 - MPE-16 5,935.00 1,131.56 5,935.00 1,071.52 4,890.76 18.848 Clearance Factor Pass - MPE-19 - MPE-19 - MPE-19 6,335.00 1,090.47 6,335.00 973.13 5,090.49 9.293 Clearance Factor Pass - MPE-19 - MPE-19 - MPE-19 6,385.00 1,089.08 6,385.00 972.10 5,113.73 9.310 Ellipse Separation Pass - MPE-19 - MPE-19 - MPE-19 6,396.41 1,089.02 6,396.41 972.24 5,113.73 9.325 Centre Distance Pass - MPE33 - MPE-33 - MPE-33 - 02 November, 2018 - 17:13 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Plan: MPU E-35 - MPU E-35 wp09 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt E Pad - Plan: MPU E-35 - MPU E-35 - MPU E-35 wp09 Scan Range: 5,935.00 to 15,000.34 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Hilcorp Alaska, LLC Milne Point bInk-TVAMU.M.. From To Survey/Plan (usft) (usft) 26.50 5,935.00 MPU E-35 wp09 5,935.00 15,000.34 MPU E-35 wp09 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 02 November, 2018 - 17:13 Page 3 of 5 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPE-33 - MPE-33 - MPE-33 - MPE-33 - MPE-33 - MPE-33 - Plan: MPU E-36 - MPE-35 BHL objectives - MPE-36 w 10,523.31 960.18 10,523.31 696.33 10,452.35 3.639 Centre Distance Pass - Plan: MPU E-36 - MPE-35 BHL objectives - MPE-36 w 14,610.00 1,110.34 14,610.00 646.36 14,530.15 2.393 Ellipse Separation Pass - Plan: MPU E-36 - MPE-35 BHL objectives - MPE-36 w 14,635.00 1,111.63 14,635.00 646.88 14,530.15 2.392 Clearance Factor Pass - Plan: MPU E38 - MPE-37 BHL Swap Draft - MPE-38 V 6,013.60 872.90 6,013.60 789.95 5,619.17 10.522 Centre Distance Pass - Plan: MPU E38 - MPE-37 BHL Swap Draft - MPE-38 Y 15,000.34 1,155.39 15,000.34 687.01 14,604.70 2.467 Clearance Factor Pass - bInk-TVAMU.M.. From To Survey/Plan (usft) (usft) 26.50 5,935.00 MPU E-35 wp09 5,935.00 15,000.34 MPU E-35 wp09 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 02 November, 2018 - 17:13 Page 3 of 5 COMPASS HALLIBURTON SpercY Drilling Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-35 Wellbore: MPU E-35 Plan: MPU E-35 wpO9 Co-oNinate (ME) Returnees: MH Plan: MPU E-35. True Nnth Veeical CND) Reference: hi WPOB Q 48.20usa MeasuredDepth Reference: MPE 5 wp09 ®48.20usa Calnulagon MCNW: Minimum Curvaluro Ladder/S.F. Plots - Prod(2 of 2) SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 26.50 5935.00 MPU E-35 wpO9 2_MVVD+IFR2+MS+Sag 5935.00 15000.34 MPU E-35 wp09 2_MWD+IFR2+MS+Sag WELT. DErAg :Han: MPU E-35 NAU 1927 (NAUCON CUNUS) Alaiaa Lone Va Ground LewL 21,70 +N/ -S +F/ -W Northing Ewing Utim de Lor,tudc 0.00 0.00 601613324 56942637 70454 -149433 NO GLOBAL FILTER: Using user defined selection & filtering criteria 26.50 To 15000, 4 CASING DETAILS TVD TVDSS MD Size Name 4423.20 4375.00 5934.31 9-5/8 95/8"x121/4" 4353.20 4305.00 15000.34 7 7" x 8 12" `0 N LL 0 E2 `m n U) Collision Zone - 5500 6050 6600 MPE-03 R1_ 8800 9350 9900 10450 11000 11 Measured Depth (1000 usft/in) C-41 L2 13200 13750 14300 14850 I N O i I (0120.00 o MPA -01 R90.00 MPE-03 to ` MPE-3 - 0 60 .00 �'. MPA -03 — ---- co30.00- MPC411-2 0.00 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 121500 13000 13500 14000 14500 15000 Measured Depth (1000 usft/in) `0 N LL 0 E2 `m n U) Collision Zone - 5500 6050 6600 MPE-03 R1_ 8800 9350 9900 10450 11000 11 Measured Depth (1000 usft/in) C-41 L2 13200 13750 14300 14850 MPU E-35 A/C Descriptions Offset well Depth interval Min. CF Situation Mitigation Risk MPE-33 Ellipse -Ellipse Sep < 50' f/ 6644'-7100' 0.250 @ 6900' E-33 Close approach while drilling the lateral section of the Zontrol Drill & Monitor Possible damage to bit and possible CF < 1.5 f/ 6625'— 7125' well. or magnetic NPT for bit trip. E-33 is drilled in a different sand lobe than what E-35 is nterference. targeting. E-33 Is P&A'd MPA -01 Ellipse -Ellipse Sep <50' f/ 11394'— 0.820 @ 11516' A-01 is a vertical well close approach while drilling the Control Drill & Monitor Possible damage to bit and possible 11664 lateral. or magnetic NPT for bit trip. CF < 1.5 f/ 11375'— 1170(Y A-01 is P&A'd nterference. MPA -03 Ellipse -Ellipse Sep < 50' f/ 12000' — 0.860 @ 12135' A-03 is a near vertical well at time of close approach while ntrol Drill & Monitor Possible damage to bit and possible 12295' drilling the lateral or magnetic NPT for bit trip. CF < 1.5 f/ 11950' —12350' A-03 is P&A'd nterference. MPC -41L2 Ehipse-Ellipse Sep <5d f/ 11938' — 0.140 @ 12375' C -41L2 is a lateral in the Schrader Bluff Sands. It is in the ell will be 5/I. Possible damage to bit and possible 12740' other lobe of sand from where E-35 will be, and can be NPT for bit trip. CF < 1.5 f/ 11850'— 12825' geologically ruled out. ell is located in a C-411_2 will be shut in. ifferent 58 lobe than E- 5 target. Schwartz, Guy L (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Tuesday, November 13, 2018 4:03 PM To: Schwartz, Guy L (DOA) Subject: HAK MPU E-35 (PTD#: TBD) A/C Description Attachments: MPU E-35 AC Descriptions.pdf Guy — Attached are the descriptions and mitigations for the close approaches on E-35. Please let me know if you have any questions. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 MPU E-35 A/C Descriptions Otfset well Depth Interval We. CF Situation Willgation Risk MPE-33 Ellipse -Ellipse Sep < 50' f/ 6644'-7100' 0.250 @ 6900' E-33 Close approach while drilling the lateral section of the ontrol Drill & Monitor Possible damage to bit and possible CF < 1.5 f/ 6625'- 7125' well. or magnetic NPT for bit trip. E-33 is drilled in a different sand lobe than what E-35 is nterference. targeting. E-33 is P&A'd' I MPA -01 Ellipse -Ellipse Sep < 50' f/ 11394' - 0.820 @ 11516' A-01 is a vertical well close approach while drilling the ontrol Drill & Monitor Possible damage to bit and possible 11660' lateral.`/ or magnetic NPT for bit trip. CF < 1.5 f/ 11375'- 11700' A-01 is P&A'd nterference. MPA -03 Ellipse -Ellipse Sep < 50'f/ 12000' - 0.860 @ 12135' A-03 Is a near vertical well at time of close approach while ontrol Drill & Monitor Possible damage to bit and possible 12295' drilling the latera or magnetic NPT for bit trip. CF < 1.5 f/ 11950' -12350' A-03 is P&A'd nterference. MPC -41L2 Ellipse -Ellipse Sep < 50'f/ 11938'- 0.140 @ 12375' C-41LZ Is a lateral in the Schrader Bluff Sands. It is in the Nell will be 5/I. Possible damage to bit and possible 12740' other lobe of sand from where E-35 will be, and can be NPT for bit trip. CF < 1.5 f/ 11850'- 12825'led out. ell is located in a illn— ifferent SB lobe than E- 5 target. Davies, Stephen F (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Monday, November 12, 2018 9:46 AM To: Davies, Stephen F (DOA) Subject: RE: [EXTERNAL] RE: MPU E-35 (PTD 218-152) Attachments: Milne Point Unit E-35 Drilling Program_Version 1 -updated Formation Press .... pdf Hello Steve - My apologies for omitting the formation pressures. All formations are normally pressured. Attached is an updated formation top/information sheet, which includes formation pressures. Hilcorp has not recorded any H2S on E -pad. Please let me know if you have any other questions. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Friday, November 9, 2018 4:46 PM To: Joe Engel <jengel@hilcorp.com> Subject: [EXTERNAL) RE: MPU E-35 (PTD 218-152) Joe, Another question: Has Hilcorp recorded any H2S within the Schrader Bluff Oil Pool in wells drilled from E -Pad? Thank you, Steve Davies AOGCC 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 Steve Davies at 907-793-1224 or steve.daviesPalaska.gov. From: Davies, Stephen F (DOA) Sent: Friday, November 9, 2018 4:27 PM To:'Joe Engel' <lengel@hilcorp.com> Subject: MPU E-35 (PTD 218-152) Monty, I'm reviewing Hilcorp's Permit to Drill application for MPU E-35 and I didn't see Hilcorp's usual Geologic Prognosis within the supporting document. Could Hilcorp please provide anticipated formation pressures (in units of psi or ppg EMW) for SVi, LA3, SB NA, and any other markers where formation pressures change notably? Thank you, Steve Davies AOGCC 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 Steve Davies at 907-793-1224 or sieve daviesPalaska.eov. TRANSMITTAL LETTER CHECKLIST WELL NAME:�1� PTD: _/S (/Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: id% POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50 - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- -� from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are /Requirements also required for this well: Well Loggingz'tdGcC�_ I/ sr k r « C1L� i q 5�� eF /6- /05 15 Sid(/ «<� i/•9/ / Per tatute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC v/ within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 Im WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 PTD#:2181520 Company HILCORP ALASKA LLC Initial Class/Type Well Name: MILNE PT UNIT E-35 Program DEV _ _ Well bore seg ❑ DEV/PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven, gas conforms to AS31A5,0300,1.A),(j,2.A-D) ___ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ NA 1 Permitfee attached _ _ .. _ _ _ _ _ _ ...... NA.. 2 Lease number appropriate_ _ _ _ _ Yes _ _ _ Surface Location lies within.ADL0025518., Top Prod Int & TO lie within ADL0047437_ 3 Unique well. name and number _ .. _ _ _ _ _ _ _ _ Yes 4 Well located in a defined pool _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ Milne Point Schrader Bluff Oil Pool (525140), governed by. CO 477, amended by CO 477.05, 5 Well located proper distance from drilling unit. boundary_ _ . . ......... . ... Yes CO 477.05 specifies:_ "There are no restrictions as to well spacing except that no pay shall_ _ 6 Well located proper distance from other wells .... _ _ _ _ _ _ _ _ _ Yes _ _ be opened in a well closer than 500 feet from the exterior boundary of the affected area.".. 7 Sufficient acreage available in drilling unit... _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ Well bore conforms to spacing requirements. 8 If. deviated, is wellbore plat. included _ _ _ _ _ _ _ _ _ Yes 9 Operator only affected party____ _ _ _ _ _ _ _ _ _ _ _ _ _ - Yes 10 Operator has. appropriate bond in force ... . . ......... Yes Appr Date 11 Permit can be issued without conservation order _ _ _ _ _ _ _ _ _ Yes 12 Permit can be issued without administrative approval _ _ _ _ _ _ _ _ _ _ Yes SFD 11/9/2018 13 Can permit be approved before 15 -day. wait. ........... Yes 14 Well located within area and strata authorized by Injection Order # (put IO# in.comments) (For. NA..... 15 All wells within 114 mile area of review identified (For service well only) _ _ _ _ _ _ _ NA. 16 Pre -produced injector: duration of pre production less than 3 months (For service well only) - - NA _ ..... 18 Conductor string provided ... _ ... _ _ _ _ _ _ _ _ . Yes 20" conductor set at 107 ft... Engineering 19 Surface casing. protects all.known. U$DWS _ _ _ _ _ _ .. .. ...... NA NO aquifers.. 20 CMT_vol adequate to circulate on conductor& surf.csg .. - - .... _ _ .. _ _ _ Yes _ _ _ _ 9 5/8". surface casing to be fully cemented.,. 2. stages planned. 21 CMT. vol. adequate to tie-in long string to surf csg.... ... _ _ _ _ _ _ .. _ _ _ Yes 22 CMT will coverall known productive horizons_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 23 Casing designs adequate for C, T, B &_ permafrost _ _ _ _ _ _ _ _ _ _ _ _ _ Yes BTC calos provided and meet industry standards... 24 Adequate tankage. or reserve pit . . .................... Yes Rig has steel pits_. All waste to be transported to approved disposal. well. 25 If a_re-drill, has_a 10-403 for abandonment been approved ....... ........ _ . NA.. _ _ Grassroots well, 26 Adequate wellbore separation proposed _ _ _ _ Yes _ _ Some close crossings with existing wells. Gyros ran to mitigate. risk.. 27 If. djverter required, does it meet regulations _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ Diveter sketch is provided, Appr Date 28 Drilling fluid_ program schematic.& equip list adequate. .... ...... ..... Yes Max formation press= 1946_psi _(8.46 ppg. EMW) Will drill with 8.9 ppg mud GLS 11/14/2018 29 BOPEs, do they meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 30 BOPE.press rating appropriate; test to (put prig in comments)... _ Yes MASP = 1503_psi _will test BOPS to 3000 psi. Annular to 2500. psi 31 Choke. manifold complies w/API RP -53 (May 84)_ _ _ _ _ _ _ _ _ _ Yes 32 Work will occur without operation shutdown _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ Yes _ _ _ _ _ _ _ _ _ _____ 33 Is presence of H2S gas probable..... _ .. Yes ...... H2$ on pad rig has sensors and alarms. 34 Mechanical. condition of wells within AOR verified (For service well only) _ _ _ _ _ _ _ .. _ NA _ _ ___________ 35 Permit can be issued w/o. hydrogen. sulfide measures ...................... Yes ...... Per Hlcorp, 11/12/2018, Hitcorp has not recorded. any 1-12S on E -Pad.... Geology 36 Data presented on potential overpressure zones. _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ Normal _presure_gradient anticipated, Planned mud progrom.appears sufficient.. Appr Date 37 Seismic analysis of shallow gas zones.. _ _ _ _ _ _ _ _ _ _ _ _ _ NA. _ Gas hydrates expected. Mitigation.rrloasures discussed in "Anticipated Drilling Hazards" section. SFD 11/13/2018 38 Seabed condition survey (if off -shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ 39 Contact name/phone for weekly -progress reports [exploratory only] _ _ _ _ _ _ _ _ _ _ _ NA Geologic Engineering Public ESP completion. No packer required as BHP is less than 8.55 ppg EMW. GIs. Date: Commissioner: ,C Commissioner: �/ /s Date e Comm,Commissio DateI S t /1,07 _ _�r16C i t ( Il t 1a.-,