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Home My WebLink About218-001By Anne Prysunka at 11:26 am, Jul 26, 2022 Mgr07sep2022 From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220622 1610 Approved Revision_ MPU F-107 (PTD 218-001) Convert to Jet Pump Workover Sundry #322-270 Date:Thursday, June 23, 2022 2:15:12 PM From: Rixse, Melvin G (OGC) Sent: Wednesday, June 22, 2022 4:10 PM To: Taylor Wellman <twellman@hilcorp.com> Subject: RE: [EXTERNAL] FW: MPU F-107 (PTD 218-001) Convert to Jet Pump Workover Sundry #322-270 Taylor, Plan approved. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Wednesday, June 22, 2022 2:21 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] FW: MPU F-107 (PTD 218-001) Convert to Jet Pump Workover Sundry #322-270 Mr. Rixse, As an update to the progress we’ve made on the well, we are in step 30 listed below. We have identified that the SLZXP Liner Top Packer is holding and that the leak is in the 9-5/8” casing. We pulled up hole testing 3 points so far and achieved a passing test the 9-5/8” as deep as 5,614’ MD. This puts the leak between 5,614’ – 6,150’ MD, and notably means that the leak in the 9-5/8” is within the Schrader Pool as the top of the Schrader Pool is at 5,390’ MD. I also wanted to provide you with the updated proposed plan. Extend the 7” patch across the 9-5/8”. The proposed procedure had been 1 joint. This would extend up to a maximum length of 760’ (5,390’ – 6,150’ md). 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. This proposal allows Hilcorp to monitor the integrity of the casing through to the Schrader Pool. This would be deployed without a 7” ram installed. Justification: Tested annular preventor in service (Full BOP test performed on 6/20/22). Safety joint w/ 7” casing x 3-1/2” workstring xo’s and TIW at the ready to PU and RIH. Well has been very predictable, repeatable and remained dead during the operation so to date. Maintaining a FL at ~1,000’ md Loading well w/ 5bbls while TIH Loading at x2 displacement while TOOH If this course of action is not acceptable or if you would like additional information please let me know and I will get it. Thank you, Taylor On Jun 17, 2022, at 14:41, Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> wrote: Taylor, The scope of your plan is approved. Thanks for the notice. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Friday, June 17, 2022 1:44 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPU F-107 (PTD 218-001) Convert to Jet Pump Workover Sundry #322-270 Mr. Rixse, Thank you for the phone call to discuss current operations and plans forward for MPU F-107. During the conversion to jet pump workover for MPU F-107 (PTD 218-001) under approved sundry #322-270, indications are that there is a leak in the 9-5/8” casing or the 7”x9-5/8” SLZXP liner top packer. To be able to confirm this leak and remediate to restore integrity to the casing we would like to perform the following higher level steps to the workover. These steps would take over from Step 27. 27. Change out to 7-5/8” rams and test to 500/2,500psi. 28. Pull and recover all the 7-5/8” casing (utilizing casing jacks for the first 5-10 joints). 29. Change out to 2-7/8”x5” VBR’s and test to 500/2,500psi. – Performed full BOP test. 30. TIH w/ 9-5/8” test packer on 3-1/2” workstring. Test casing to identify leak point. a. Assuming leak is at the 7”x9-5/8” SLZXP Liner Top Packer. – Currently on this step. 31. Run 7”x9-5/8” SLZXP w/ +/-1 joint not to exceed 536’ of 7” casing (stacker packer style completion on the casing) and set packer. Test casing to 1,000psi. 32. Change out to 7” rams and test to 500/2,500psi. 33. Run 7” casing w/ bullet seals and stab into new SLZXP. Circulate in corrosion inhibited brine and freeze protect. Land and test 7”x9-5/8” annulus to 1,000psi (charted). 34. Change out to 2-7/8”x5” VBR’s and test to 500/2,500psi. 35. Run new 3-1/2” jet pump completion. Set packer, pressure test tbg to 3,000psi and 3-1/2”x7” annulus to 3,700psi. 36. Set BPV and begin RD. If you have any questions or would like additional information please let me know and I will provide. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC – Ops Engineer: Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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. 5HJJ-DPHV%2*& )URP$ODVND16$65:HOO6LWH0DQDJHUV$ODVND16$65:HOO6LWH0DQDJHUV#KLOFRUSFRP! 6HQW:HGQHVGD\-XQH$0 7R5HJJ-DPHV%2*&'2$$2*&&3UXGKRH%D\%URRNV3KRHEH/2*& 6XEMHFW)%23WHVW $WWDFKPHQWV+LOFRUS$65038)%23(7HVW:HHNO\[OV[ WůĞĂƐĞƐĞĞĂƚƚĂĐŚĞĚKWƚĞƐƚĨŽƌŵ͕dŚĂŶŬǇŽƵ Regards, Russell Gallen ASR DSM, Mobile: 907-529-7202 Office: 907-685-1266 russell.gallen@hilcorp.com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ll 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: 6/20/22 Rig Rep.: Rig Phone: 685-1266 Operator: Op. Phone:685-1266 Rep.: E-Mail Well Name: PTD #22180010 Sundry #322-270 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: x Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:875 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 FP 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"P 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)1800 P Quantity Test Result 200 psi Attained (sec)17 P No. Valves 16 P Full Pressure Attained (sec)53 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4x2200 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:8.3 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 6/22/22 11:15 Waived By Test Start Date/Time:6/20/2022 06:15 HRS (date) (time)Witness Test Finish Date/Time:6/20/2022 14:30 HRS BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Adam Earl Hilcorp Fail / Pass on blinds, leak out of exteral weep hole. Replaced the hydraulic /mud seal in blind on DS side, Retest . Tested W/ 3.5" test joints. Annular closing time = 25 secs J. Haberthur, A. Haberthur Hilcorp Alaska M. Strom , R. Gallen MPU F-107 Test Pressure (psi): skaNS-ASR-Well Site Managers@hilcorp.c Form 10-424 (Revised 02/2022) 2022-0620_BOP_Hilcorp_ASR1_MPU_F-107 9 9 9 9999 9 9 9 9 9 9 FP Annular closing time = 25 secs Fail / Pass on blinds, STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT F-107 JBR 07/20/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:2 Tested with 2 7/8" and 3 1/2" test joints, VBR's failed where changed out and passed retest, K1 failed was changed out and passed retest. Closer times = Ann. = 23sec, rams = 6 sec., blinds = 6 sec. hcr = 2 sec. There are 12 each precharge bottles 11 at 1000psi and 1 at 1100psi. Test Results TEST DATA Rig Rep:J. HaberthurOperator:Hilcorp Alaska, LLC Operator Rep:M. Storm Contractor/Rig No.:Hilcorp ASR 1 PTD#:2180010 DATE:6/13/2022 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopBDB220614151516 Inspector Brian Bixby Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 9.5 MASP: 875 Sundry No: 322-270 Location Gen.:P Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec.P Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 16 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2 7/8x5 FP #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16 P HCR Valves 1 2 1/16 P Kill Line Valves 2 2 1/16 FP Check Valve 0 NA BOP Misc 0 NA System Pressure P3100 Pressure After Closure P1900 200 PSI Attained P16 Full Pressure Attained P56 Blind Switch Covers:PYES Nitgn. Bottles (avg):P4@2325 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA       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Ě͘ŶƐƵƌĞƚŽŵŽŶŝƚŽƌƐŝĚĞŽƵƚůĞƚǀĂůǀĞƐĂŶĚĂŶŶƵůƵƐǀĂůǀĞƉƌĞƐƐƵƌĞŐĂƵŐĞƐƚŽĞŶƐƵƌĞ ŶŽƉƌĞƐƐƵƌĞŝƐƚƌĂƉƉĞĚƵŶĚĞƌŶĞĂƚŚƚĞƐƚƉůƵŐ͘ Ğ͘KŶĐĞKWƚĞƐƚŝƐĐŽŵƉůĞƚĞ͕ƐĞŶĚĂĐŽƉǇŽĨƚŚĞƚĞƐƚƌĞƉŽƌƚ;ϭϬͲϰϮϰĨŽƌŵͿƚŽK' ĂŶĚƚŽǁŶĞŶŐŝŶĞĞƌ͘ ϮϬ͘ůĞĞĚĂŶǇƉƌĞƐƐƵƌĞŽĨĨĐĂƐŝŶŐƚŽƚŚĞƌĞƚƵƌŶƐƚĂŶŬ͘WƵůůd^ƉůƵŐĂŶĚWs͘<ŝůůǁĞůůǁŝƚŚƉƌŽĚƵĐĞĚ ǁĂƚĞƌŽƌƐŽƵƌĐĞǁĂƚĞƌĂƐŶĞĞĚĞĚ͘ Ϯϭ͘DhůĂŶĚŝŶŐũŽŝŶƚŽƌƐƉĞĂƌĂŶĚWhŽŶƚŚĞƚƵďŝŶŐŚĂŶŐĞƌ͘ Ă͘dŚĞWhǁĞŝŐŚƚĚƵƌŝŶŐƚŚĞϮϬϮϮ^WƐǁĂƉǁĂƐϭϭϬ<ůďƐƚŽĨƌĞĞƉŝƉĞ͘dŚĞĐƵƌƌĞŶƚ ĐŽŵƉůĞƚŝŽŶǁĂƐůĂŶĚĞĚǁŝƚŚĂWhtŽĨϴϬŬĂŶĚƐůĂĐŬŽĨĨǁƚŽĨϲϱŬ͘ ϮϮ͘ZĞĐŽǀĞƌƚŚĞƚƵďŝŶŐŚĂŶŐĞƌ͘ Ϯϯ͘WKK,ĂŶĚůĂǇĚŽǁŶƚŚĞϮͲϳͬϴ͟ƚƵďŝŶŐ͘EƵŵďĞƌĂůůũŽŝŶƚƐ͘dďŐǁ ŝůůďĞŝŶƐƉĞĐƚĞĚĂŶĚďƌŽƵŐŚƚƚŽ ŝŶǀĞŶƚŽƌǇƵŶůĞƐƐĚĂŵĂŐĞŽƌŽƚŚĞƌŽďƐĞƌǀĂƚŝŽŶƐĂƌĞƐĞĞŶǁŚŝůĞƉƵůůŝŶŐ͘>ĂǇĚŽǁŶĨĂŝůĞĚ^W͘ Ă͘WƵůůŽƵƚĂůůǀŝƐƵĂůůǇďĂĚũŽŝŶƚƐĂŶĚŵĂƌŬĨŽƌĚŝƐƉŽƐĂů͘ ď͘>ŽŽŬĨŽƌŽǀĞƌͲƚŽƌƋƵĞĚĐŽŶŶĞĐƚŝŽŶƐĨƌŽŵƉƌĞǀŝŽƵƐƚƵďŝŶŐƌƵŶƐĂŶĚũƵŶŬƚŚĞŵ͘ ŽŶǀĞƌƚƚŽ:W ZĞǀŝƐŝŽŶϭʹϬϱͬϭϮͬϮϬϮϮtĞůů͗DWh&ͲϭϬϳ ĂƚĞ͗ϬϮͬϭϲͬϮϬϮϮ Đ͘dŚŝƐǁĞůůŚĂƐĂŶĞǆƚƌĞŵĞůǇŚŝŐŚŶƵŵďĞƌŽĨĐůĂŵƉƐŝŶƐƚĂůůĞĚƚŽƉ ƌŽƚĞĐƚƚŚĞ^WĐĂďůĞĨƌŽŵ ĚĂŵĂŐĞĚƵĞƚŽĂŶĞǆƚĞŶĚĞĚƐĞĐƚŝŽŶŽĨŚŝŐŚ>^͘dŚĞĨŽůůŽǁŝŶŐŶ ƵŵďĞƌŽĨĐůĂŵƉƐǁĞƌĞ ŝŶƐƚĂůůĞĚ͗ 5HFHVVFODPSVRQ/7VHDO87VHDOSXPSDQGGLVFKDUJH &DQQRQFODPSVRQHHDFKRQ/7VHDO87VHDOSXPS DQGRQSXPS &DQQRQKDOIFODPSLQSXSDERYHGLVFKDUJH 0RGLILHG*/0FODPSV 0RGLILHGFODPSIRUFURVV;1LSSOH FODPSV PLGFODPSV &URVVFROODUFODPSV Ϯϰ͘DhůĞĂŶŽƵƚĂƐƐĞŵďůǇǁŝƚŚĐĂƐŝŶŐƐĐƌĂƉĞƌĂďŽǀĞ͘ Ă͘Z/,ƚŽцϲ͕ϭϲϱ͛DƚŽĞŶƐƵƌĞŶĞǁ:WĐŽŵƉůĞƚŝŽŶǁŝůůĚƌŝĨƚƚŽĚĞƐŝƌĞĚĚĞƉƚŚ͘ ď͘ůĞĂŶŽƵƚǀŝĂƌĞǀĞƌƐĞĐŝƌĐƵůĂƚŝŶŐƚŽϲϭϴϭ͛D͘ Ϯϱ͘WhϳͲϱͬϴ͟ƚĞƐƚƉĂĐŬĞƌĂŶĚd/,ƚŽцϲ͕ϭϲϱ͛D͘>ŽĂĚǁĞůůĂŶĚWdϵͲϱͬϴ͟ĐĂƐŝŶŐƚŽϭ͕ϱϬϬƉƐŝ͘ Ă͘^ƵƐƉĞĐƚĞĚŚŽůĞŝŶƚŚĞϳͲϱͬϴ͟ĐĂƐŝŶŐǁŝůůŚĂǀĞĚŝƌĞĐƚĐŽŵŵƵŶŝĐĂƚŝŽŶďĞƚǁĞĞŶϳͲϱͬϴ͟ĂŶĚϵͲ ϱͬϴ͘͟ Ϯϲ͘WƵůůƵƉŚŽůĞĂŶĚWdϳͲϱͬϴ͟ĐĂƐŝŶŐƚŽϭ͕ϬϬϬƉƐŝƵŶƚŝůƉĂƐƐŝŶŐƚĞƐƚŝƐĂĐŚŝĞǀĞĚ͘ Ă͘dĂƌŐĞƚĚĞƉƚŚĨŽƌĐŽŵƉůĞƚŝŽŶƉĂĐŬĞƌŝƐцϱ͕ϯϮϬ͛D͘ ď͘ŽŶƚĂĐƚKǁŝƚŚůĞĂŬĚĞƉƚŚŽƌƉĂƐƐŝŶŐWdŽĨƚŚĞϳͲϱͬϴ͟ĐĂƐŝŶŐĚĞƉƚŚ͘ Ϯϳ͘WhůŽǁĞƌƉĂƚĐŚĂƐƐĞŵďůǇ;ϳ͟ǆϰͲϭͬϮ͟dƌŝƉŽŝŶƚWĂĐŬĞƌĂŶĚƚŝĞďĂĐŬͬƐŶĂƉůĂƚĐŚĂƐƐĞŵďůǇͿĂŶĚZ/,͘ ŽůŽƌƐŝŶĚŝĐĂƚĞĂƐƐĞŵďůŝĞƐƚŽďĞďƵĐŬĞĚƵƉƉƌŝŽƌƚŽZtK͘ 1RP 6L]H a/HQJW K,WHP/EI W 0DWHULD O1RWHV :/(*/ 3XS-RLQW/ ;1LSSOH/ ;2/RFDWRU/ [7ULSRLQW3DFNHU/¶0' 6QDS/DWFK$VVHPEO\/ Ϯϴ͘d/,ĂŶĚůĂŶĚƚŚĞŶŽͲŐŽĂƐƐĞŵďůǇŽŶƚŚĞϳ͟ůŝŶĞƌƚŝĞͲďĂĐŬĂƚцϲ͕ϭϲϬ͛D͘ 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ϯ͘EhƚƌĞĞĂŶĚƚƵďŝŶŐŚĞĂĚĂĚĂƉƚĞƌ͘ ϰ͘dĞƐƚďŽƚŚƚƌĞĞĂŶĚƚƵďŝŶŐŚĂŶŐĞƌǀŽŝĚƚŽϱϬϬƉƐŝůŽǁͬϱ͕ϬϬϬƉƐŝŚŝŐŚ͘ ϱ͘WƵůůd^ƉůƵŐΘWs͘ ϲ͘ZĐƌĂŶĞ͘DŽǀĞϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬĂŶĚƌŝŐŵĂƚƐƚŽŶĞǆƚǁĞůůůŽĐĂƚŝŽŶ͘ ϳ͘ZĞƉůĂĐĞŐĂƵŐĞ;ƐͿŝĨƌĞŵŽǀĞĚ͘ ϴ͘dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ZhǁĞůůŚŽƵƐĞĂŶĚĨůŽǁůŝŶĞƐĨŽƌĂ:ĞƚWƵŵƉĐŽŵƉůĞƚŝŽŶ͘ WŽƐƚZŝŐtŽƌŬ ^ůŝĐŬůŝŶĞ ϭ͘^ƉŽƚ^ůŝĐŬůŝŶĞƵŶŝƚĂŶĚZh͘ Ϯ͘WƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌƚŽϯϬϬƉƐŝůŽǁĂŶĚϮ͕ϴϬϬƉƐŝŚŝŐŚ͘ ϯ͘WƵůůĂůůĂŶĚƌŽĚ͘ ϰ͘WƵůůZ,ƉƌŽĨŝůĞ͘ ϱ͘^ŚŝĨƚ^^ŽƉĞŶ͘ ϲ͘^ĞƚϭϮ:W͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƐͲďƵŝůƚ^ĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘KW^ĐŚĞŵĂƚŝĐ ŽŶǀĞƌƚƚŽ:W tĞůů͗DWh&ͲϭϬϳ ĂƚĞ͗ϱͬϰͬϮϬϮϮ tĞůůEĂŵĞ͗DWh&ͲϭϬϳ W/EƵŵďĞƌ͗ϱϬͲϬϮϵͲϮϯϱϵϮͲϬϬͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗KŝůtĞůů΀&ĂŝůĞĚ^W΁ WĂĚ͗&ͲWĂĚ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗DĂǇϮϱƚŚ ZŝŐ͗^Z ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍zĞƐ ĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗ĂƌĐŝ,ŽƌŶĞƌ WĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϮϭϴͲϬϬϭ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗ƌŝĂŶ'ůĂƐŚĞĞŶ ϵϬϳϱϰϱϭϭϰϰ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗dĂǇůŽƌtĞůůŵĂŶ ;ϵϬϳͿϳϳϳͲϴϰϰϵ;KͿ ;ϵϬϳͿϵϰϳͲϵϱϯϯ;DͿ &XUUHQW%RWWRP+ROH3UHVVXUH SVL#¶79' )/DWVXUIDFHSSJ(0: 0D[LPXP([SHFWHG%+3SVL#¶79' )/DWVXUIDFHSSJ(0: 0363SVL SVLIWJUDGLHQWWRVXUIDFH ƌŝĞĨtĞůů^ƵŵŵĂƌǇ͗ DWh&ͲϭϬϳǁĂƐĚƌŝůůĞĚĂŶĚĐŽŵƉůĞƚĞĚǁŝƚŚĂƉƌĞͲĚƌŝůůĞĚůŝŶĞƌŝŶ ƚŚĞ^ĐŚƌĂĚĞƌůƵĨĨKƐĂŶĚƐŝŶ&ĞďƌƵĂƌǇϮϬϭϴ͘ ƵĞƚŽǁĞůůďŽƌĞŐĞŽŵĞƚƌǇ͕ƚŚĞ^WǁĂƐƐĞƚĂƚĂƐƵďͲŽƉƚŝŵĂůĚĞƉƚŚ͘dŚĞ^WǁĂƐĞůĞĐƚŝǀĞůǇƉƵůůĞĚĂŶĚƌĞͲƌƵŶƚŽ ĂĚĞĞƉĞƌĚĞƉƚŚŽŶϭϭͬϭͬϮϬϭϴ͘dŚĞĚĞĞƉĞƌƐĞƚĂůůŽǁĞĚĨŽƌĂĚĚŝƚŝŽŶĂůĚƌĂǁĚŽǁŶ͘dŚĞƌĞǁĂƐĂŶŝŶĨůƵǆŽĨƐŽůŝĚƐ ƚŚĂƚƉůƵŐŐĞĚƚŚĞůŝŶĞƌ͘dŚĞƐĞƐŽůŝĚƐǁĞƌĞďĂĐŬĨůƵƐŚĞĚĂŶĚĐůĞĂƌĞĚĚŽǁŶƚŚĞůŝŶĞƌ͘dŚĞ^WǁĂƐƉƵůůĞĚŽŶϭͬϭϱ ĂŶĚĂƉƉĞĂƌĞĚƚŽŚĂǀĞĂďƌŽŬĞŶƐŚĂĨƚĂŶĚĂŬŝůůƐƚƌŝŶŐǁĂƐƌƵŶƚŽ ĂůůŽǁĨŽƌĂĐŽŝůƚƵďŝŶŐEϮĨŝůůĐůĞĂŶŽƵƚ͘Ŷ^W ǁĂƐƌƵŶŝŶ:ĂŶƵĂƌǇŽĨϮϬϭϵĨĂŝůĞĚŝŶϮϬϮϮ͘Ŷ^WǁĂƐƌĞĐĞŶƚůǇƌƵŶDĂƌĐŚϮϬϮϮĂŶĚĨĂŝůĞĚůĞƐƐƚŚĂŶϮŵŽŶƚŚƐ ůĂƚĞƌ͘ EŽƚĞƐZĞŐĂƌĚŝŶŐtĞůůďŽƌĞŽŶĚŝƚŝŽŶ x dŚĞϳͲϱͬϴ͟ǆϵͲϱͬϴ͟ĂŶŶƵůƵƐǁĂƐƚĞƐƚĞĚĚŽǁŶƚŽϲ͕ϭϱϯ͛Dͬϭ͕ϱϬϬƉƐŝŽŶƉƌŝůϯϬ͕ϮϬϭϴ͘ KďũĞĐƚŝǀĞ͗ WƵůůĨĂŝůĞĚ^WƌƵŶĂŶĞǁũĞƚƉƵŵƉĐŽŵƉůĞƚŝŽŶ͘ ^ůŝĐŬůŝŶĞ;EŽŶͲƐƵŶĚƌŝĞĚƐƚĞƉƐͿ ϭ͘ Zh^ůŝĐŬůŝŶĞƵŶŝƚĂŶĚƉƌĞƐƐƵƌĞƚĞƐƚWƚŽϮϱϬƉƐŝͬϭ͕ϱϬϬƉƐŝŚŝŐŚ͘ Ϯ͘ ƌŝĨƚĂŶĚƚĂŐǁŝƚŚƐĂŵƉůĞƌďĂŝůĞƌ ϯ͘ WƵůůůŽǁĞƌ'>sĨƌŽŵϰ͕ϲϴϱ͛ŵĚ͘ ϰ͘ WƵůů>'>sĂŶĚƐĞƚ'>sŝŶƵƉƉĞƌ'>DĂƚϭϲϱ͛ŵĚ͘ ϱ͘ Z^>ƵŶŝƚ͘ WƌĞͲZŝŐWƌŽĐĞĚƵƌĞ͗ ϲ͘ ůĞĂƌĂŶĚůĞǀĞůƉĂĚĂƌĞĂŝŶĨƌŽŶƚŽĨǁĞůů͘^ƉŽƚƌŝŐŵĂƚƐĂŶĚĐŽŶƚĂŝŶŵĞŶƚ͘ ϳ͘ ZǁĞůůŚŽƵƐĞĂŶĚĨůŽǁůŝŶĞƐ͘ůĞĂƌĂŶĚůĞǀĞůĂƌĞĂĂƌŽƵŶĚǁĞůů͘ ϴ͘ Zh>ŝƚƚůĞZĞĚ^ĞƌǀŝĐĞƐ͘ZhƌĞǀĞƌƐĞŽƵƚƐŬŝĚĂŶĚϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬ͘ ϵ͘ WƌĞƐƐƵƌĞƚĞƐƚůŝŶĞƐƚŽϯ͕ϬϬϬƉƐŝ͘ ϭϬ͘ ŝƌĐƵůĂƚĞĂƚůĞĂƐƚŽŶĞǁĞůůďŽƌĞǀŽůƵŵĞǁŝƚŚƉƌŽĚƵĐĞĚǁĂƚĞƌͬƐŽƵƌĐĞǁĂƚĞƌĚŽǁŶƚƵďŝŶŐ͕ƚĂŬŝŶŐ ƌĞƚƵƌŶƐƵƉĐĂƐŝŶŐƚŽϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬ͘ƵůůŚĞĂĚĚŽǁŶƚŚĞ/ƚŽĞŶƐƵƌĞƉƌŽĚƵĐĞĚǁĂƚĞƌͬƐŽƵƌĐĞ ǁĂƚĞƌŝƐĐŽŵƉůĞƚĞůǇĐŝƌĐƵůĂƚĞĚ͘ 6XSHUFHGHG ŽŶǀĞƌƚƚŽ:W tĞůů͗DWh&ͲϭϬϳ ĂƚĞ͗ϱͬϰͬϮϬϮϮ ϭϭ͘ ŽŶĨŝƌŵǁĞůůŝƐĚĞĂĚ͘ŽŶƚĂĐƚƚŚĞŽƉĞƌĂƚŝŽŶƐĞŶŐŝŶĞĞƌŝĨĨƌ ĞĞǌĞƉƌŽƚĞĐƚŝŽŶŝƐŶĞĞĚĞĚĚĞƉĞŶĚŝŶŐŽŶ ^ZĂƌƌŝǀĂů͘ ϭϮ͘ Z>ŝƚƚůĞZĞĚ^ĞƌǀŝĐĞƐĂŶĚƌĞǀĞƌƐĞŽƵƚƐŬŝĚ͘ ϭϯ͘ ^ĞƚWs͘ ƌŝĞĨZtKWƌŽĐĞĚƵƌĞ͗ ϭϰ͘ D/Zh^Z͕ĂŶĐŝůůĂƌǇĞƋƵŝƉŵĞŶƚĂŶĚůŝŶĞƐ͘ ϭϱ͘ ŚĞĐŬĨŽƌƉƌĞƐƐƵƌĞĂŶĚŝĨϬƉƐŝ͘/ĨŶĞĞĚĞĚ͕ďůĞĞĚŽĨĨĂŶǇƌĞƐŝĚƵĂůƉƌĞƐƐƵƌĞŽĨĨƚƵďŝŶŐĂŶĚĐĂƐŝŶŐ͘/Ĩ ŶĞĞĚĞĚ͕ŬŝůůǁĞůůǁͬƉƌŽĚƵĐĞĚǁĂƚĞƌŽƌƐŽƵƌĐĞǁĂƚĞƌ͘^Ğƚd^WůƵŐ͘ ϭϲ͘ EhKW͘ ϭϳ͘ dĞƐƚKWƚŽϮϱϬͬϮ͕ϱϬϬƉƐŝĨŽƌϱͬϱŵŝŶ͘dĞƐƚĂŶŶƵůĂƌƚŽϮϱϬͬϮ͕ϱϬϬƉƐŝĨŽƌϱͬϱŵŝŶ͘ Ă͘ EŽƚŝĨǇƚŚĞK'ϮϰŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨKWƚĞƐƚ͘ ď͘ dĞƐƚƵƉƉĞƌϮͲϳͬϴ͟ǆϱ͟ƌĂŵƐǁŝƚŚƚŚĞϮͲϳͬϴ͟ƚĞƐƚũŽŝŶƚĂŶĚϯЪ͛͛ƚĞƐƚũŽŝŶƚ͘ Đ͘ ŽŶĨŝƌŵƚĞƐƚƉƌĞƐƐƵƌĞƐǁŝƚŚƉƉƌŽǀĞĚ^ƵŶĚƌǇ͘ Ě͘ ŶƐƵƌĞƚŽŵŽŶŝƚŽƌƐŝĚĞŽƵƚůĞƚǀĂůǀĞƐĂŶĚĂŶŶƵůƵƐǀĂůǀĞƉƌĞƐƐƵƌĞŐĂƵŐĞƐƚŽĞŶƐƵƌĞ ŶŽƉƌĞƐƐƵƌĞŝƐƚƌĂƉƉĞĚƵŶĚĞƌŶĞĂƚŚƚĞƐƚƉůƵŐ͘ Ğ͘ KŶĐĞKWƚĞƐƚŝƐĐŽŵƉůĞƚĞ͕ƐĞŶĚĂĐŽƉǇŽĨƚŚĞƚĞƐƚƌĞƉŽƌƚ;ϭϬͲϰϮϰĨŽƌŵͿƚŽK' ĂŶĚƚŽǁŶĞŶŐŝŶĞĞƌ͘ ϭϴ͘ ůĞĞĚĂŶǇƉƌĞƐƐƵƌĞŽĨĨĐĂƐŝŶŐƚŽƚŚĞƌĞƚƵƌŶƐƚĂŶŬ͘WƵůůd^ƉůƵŐĂŶĚWs͘<ŝůůǁĞůůǁŝƚŚƉƌŽĚƵĐĞĚ ǁĂƚĞƌŽƌƐŽƵƌĐĞǁĂƚĞƌĂƐŶĞĞĚĞĚ͘ ϭϵ͘ DhůĂŶĚŝŶŐũŽŝŶƚŽƌƐƉĞĂƌĂŶĚWhŽŶƚŚĞƚƵďŝŶŐŚĂŶŐĞƌ͘ Ă͘ dŚĞWhǁĞŝŐŚƚĚƵƌŝŶŐƚŚĞϮϬϮϮ^WƐǁĂƉǁĂƐϭϭϬ<ůďƐƚŽĨƌĞĞƉŝƉĞ͘dŚĞĐƵƌƌĞŶƚ ĐŽŵƉůĞƚŝŽŶǁĂƐůĂŶĚĞĚǁŝƚŚĂWhtŽĨϴϬŬĂŶĚƐůĂĐŬŽĨĨǁƚŽĨϲϱŬ ͘ ϮϬ͘ ZĞĐŽǀĞƌƚŚĞƚƵďŝŶŐŚĂŶŐĞƌ͘ Ϯϭ͘ WKK,ĂŶĚůĂǇĚŽǁŶƚŚĞϮͲϳͬϴ͟ƚƵďŝŶŐ͘EƵŵďĞƌĂůůũŽŝŶƚƐ͘dď ŐǁŝůůďĞŝŶƐƉĞĐƚĞĚĂŶĚďƌŽƵŐŚƚƚŽ ŝŶǀĞŶƚŽƌǇƵŶůĞƐƐĚĂŵĂŐĞŽƌŽƚŚĞƌŽďƐĞƌǀĂƚŝŽŶƐĂƌĞƐĞĞŶǁŚŝůĞƉƵůůŝŶŐ͘>ĂǇĚŽǁŶĨĂŝůĞĚ^W͘ Ă͘ WƵůůŽƵƚĂůůǀŝƐƵĂůůǇďĂĚũŽŝŶƚƐĂŶĚŵĂƌŬĨŽƌĚŝƐƉŽƐĂů͘ ď͘ >ŽŽŬĨŽƌŽǀĞƌͲƚŽƌƋƵĞĚĐŽŶŶĞĐƚŝŽŶƐĨƌŽŵƉƌĞǀŝŽƵƐƚƵďŝŶŐƌƵŶƐĂ ŶĚũƵŶŬƚŚĞŵ͘ Đ͘ dŚŝƐǁĞůůŚĂƐĂŶĞǆƚƌĞŵĞůǇŚŝŐŚŶƵŵďĞƌŽĨĐůĂŵƉƐŝŶƐƚĂůůĞĚƚŽ ƉƌŽƚĞĐƚƚŚĞ^WĐĂďůĞĨƌŽŵ ĚĂŵĂŐĞĚƵĞƚŽĂŶĞǆƚĞŶĚĞĚƐĞĐƚŝŽŶŽĨŚŝŐŚ>^͘dŚĞĨŽůůŽǁŝŶŐŶ ƵŵďĞƌŽĨĐůĂŵƉƐǁĞƌĞ ŝŶƐƚĂůůĞĚ͗ ϲ ZĞĐĞƐƐĐůĂŵƉƐŽŶ>dƐĞĂů͕hdƐĞĂů͕ƉƵŵƉηϭ͕ηϮ͕ηϯĂŶĚĚŝƐĐŚĂƌŐĞ ϲ ĂŶŶŽŶĐůĂŵƉƐ͗ŽŶĞĞĂĐŚŽŶ>dƐĞĂů͕hdƐĞĂů͕ƉƵŵƉηϭΘϮĂŶĚϮŽŶƉƵŵƉ ηϯ͘ ϭ ĂŶŶŽŶŚĂůĨĐůĂŵƉŝŶƉƵƉĂďŽǀĞĚŝƐĐŚĂƌŐĞ Ϯ DŽĚŝĨŝĞĚ'>DĐůĂŵƉƐ ϭ DŽĚŝĨŝĞĚĐůĂŵƉĨŽƌĐƌŽƐƐyE ϯϭϬ ϱΖĐůĂŵƉƐ ϭϬϮ ŵŝĚĐůĂŵƉƐ ϭϱϰ ƌŽƐƐĐŽůůĂƌĐůĂŵƉƐ 6XSHUFHGHG ŽŶǀĞƌƚƚŽ:W tĞůů͗DWh&ͲϭϬϳ ĂƚĞ͗ϱͬϰͬϮϬϮϮ ϮϮ͘ DhůĞĂŶŽƵƚĂƐƐĞŵďůǇǁŝƚŚĐĂƐŝŶŐƐĐƌĂƉĞƌĂďŽǀĞ͘ Ă͘ Z/,ƚŽϲ͕ϭϴϭ͛DƚŽĞŶƐƵƌĞŶĞǁ:WĐŽŵƉůĞƚŝŽŶǁŝůůĚƌŝĨƚƚŽĚĞ ƐŝƌĞĚĚĞƉƚŚ͘ ď͘ ůĞĂŶŽƵƚǀŝĂƌĞǀĞƌƐĞĐŝƌĐƵůĂƚŝŶŐƚŽϲ͕ϭϴϭ͛D͘ Ϯϯ͘ WhŶĞǁϯͲϭͬϮ͟:ĞƚWƵŵƉŽŵƉůĞƚŝŽŶĂŶĚZ/,͘ ŽůŽƌƐŝŶĚŝĐĂƚĞĂƐƐĞŵďůŝĞƐƚŽďĞďƵĐŬĞĚƵƉƉƌŝŽƌƚŽZtK͘ 1RP 6L]H a/HQJW K ,WHP /EI W 0DWHULD O 1RWHV :/(*/ -RLQWV //DQG:/(*DWa 3XS-RLQW / ;11LSZLWK5+&SURILOH /6HWEHORZGHJUHHVa 0' 3XS-RLQW / MRLQW / ;2 WR -RLQW / ´´3DFNHU /7UL3RLQW3DFNHUVHWa 0' ;2 WR -RLQW / MRLQW / 3XS-RLQW / %+3*XDJH / 3XS-RLQW / MRLQW / 3XS-RLQW / +$/6OLGLQJ6OHHYH / 3XS-RLQW / -RLQWV / 6SDFHRXW3836 / MRLQW / 383 / 7XELQJ+DQJHU / Ϯϰ͘ ^ƉĂĐĞŽƵƚĂŶĚůĂŶĚƚŚĞŚĂŶŐĞƌ͘ Ă͘ hƐĞĐĂƵƚŝŽŶŶŽƚƚŽĂŵĂŐĞ,W'ĂďůĞǁŚŝůĞůĂŶĚŝŶŐƚŚĞŚĂŶŐĞƌ ͘ ď͘ EŽƚĞWh;WŝĐŬhƉͿĂŶĚ^K;^ůĂĐŬKĨĨͿǁĞŝŐŚƚƐŽŶƚĂůůǇ͘ Ϯϱ͘ Z/>^͘>ĂǇĚŽǁŶůĂŶĚŝŶŐũŽŝŶƚ͘ 6XSHUFHGHG ŽŶǀĞƌƚƚŽ:W tĞůů͗DWh&ͲϭϬϳ ĂƚĞ͗ϱͬϰͬϮϬϮϮ Ϯϲ͘ WƵŵƉϰϬďďůƐϭй<>ǁŝƚŚŽƌƌŽƐŝŽŶŝŶŚŝďŝƚŽƌĚŽǁŶƚŚĞ/͘dĂ ŬŝŶŐƌĞƚƵƌŶƐƵƉd'͘ Ϯϳ͘ dŚŝƐŝƐƚŽƉƌŽƚĞĐƚƚŚĞĂƌĞĂďĞƚǁĞĞŶƚŚĞƉĂĐŬĞƌĂŶĚ^ůŝĚŝŶŐ^ůĞĞǀĞ͘tŚŝůĞƚĂŬŝŶŐƌĞƚƵƌŶƐƵƉƚŚĞd' Ϯϴ͘ WƵŵƉĂŶĂĚĚŝƚŝŽŶĂůϲϱďďůƐŽĨϭй<>ĨŽůůŽǁĞĚďǇϵϱďďůƐŽĨĚŝĞƐĞůĨƌĞĞǌĞƉƌŽƚĞĐƚĚŽǁŶƚŚĞ/ƚŽ ůĂŶĚŝŶŚŝďŝƚŽƌďĞƚǁĞĞŶ^ůŝĚŝŶŐ^ůĞĞǀĞĂŶĚƚŚĞƉĂĐŬĞƌǁŚŝůĞƚĂŬŝŶŐƌĞƚƵƌŶƐƵƉƚŚĞd'͘ Ϯϵ͘ ^ǁĂƉƚŽƉƵŵƉŝŶŐĚŽǁŶƚŚĞd'ƚĂŬŝŶŐƌĞƚƵƌŶƐƵƉƚŚĞ/ĂŶĚWƵŵƉϮϬďďůƐŽĨ&W͘ ϯϬ͘ ƌŽƉďĂůůĂŶĚƌŽĚĂŶĚĐŽŵƉůĞƚĞůŽĂĚŝŶŐƚƵďŝŶŐǁŝƚŚ&WĂŶĚŚǇ ĚƌĂƵůŝĐĂůůǇƐĞƚƚŚĞƉĂĐŬĞƌĂƐƉĞƌ ŵĂŶƵĨĂĐƚƵƌĞƌƐƐĞƚƚŝŶŐƉƌŽĐĞĚƵƌĞ ϯϭ͘ WƌĞƐƐƵƌĞƵƉĂŶĚƚĞƐƚƚŚĞƚƵďŝŶŐƚŽϯ͕ϬϬϬƉƐŝĨŽƌD/dͲdǁŝƚŚϭ͕ϬϬϬƉƐŝŽŶƚŚĞ/͘ůĞĞĚŽĨĨƚŚĞƚƵďŝŶŐ ƚŽϭϬϬϬƉƐŝ͘dĞƐƚƚŚĞ/ƚŽϯ͕ϳϬϬƉƐŝĨŽƌD/dͲ/͘ZĞĐŽƌĚĂŶĚŶŽƚĂƚĞĂůůƉƌĞƐƐƵƌĞƚĞƐƚƐ;ϯϬŵŝŶƵƚĞƐͿŽŶ ĐŚĂƌƚ͘ ϯϮ͘ ^Ğƚd^ƉůƵŐ͘ ϯϯ͘ ZDK^Z͘ WŽƐƚͲZŝŐWƌŽĐĞĚƵƌĞ͗ tĞůů^ƵƉƉŽƌƚ ϭ͘ ZŵƵĚďŽĂƚ͘ZKW͘DŽǀĞƚŽŶĞǆƚǁĞůůůŽĐĂƚŝŽŶ͘ Ϯ͘ ZhĐƌĂŶĞ͘EKW͘ ϯ͘ EhƚƌĞĞĂŶĚƚƵďŝŶŐŚĞĂĚĂĚĂƉƚĞƌ͘ ϰ͘ dĞƐƚďŽƚŚƚƌĞĞĂŶĚƚƵďŝŶŐŚĂŶŐĞƌǀŽŝĚƚŽϱϬϬƉƐŝůŽǁͬϱ͕ϬϬϬƉƐŝŚŝŐŚ͘ ϱ͘ WƵůůd^ƉůƵŐ͘ ϲ͘ ZĐƌĂŶĞ͘DŽǀĞϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬĂŶĚƌŝŐŵĂƚƐƚŽŶĞǆƚǁĞůůůŽĐĂƚŝŽŶ͘ ϳ͘ ZĞƉůĂĐĞŐĂƵŐĞ;ƐͿŝĨƌĞŵŽǀĞĚ͘ ϴ͘ dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ZhǁĞůůŚŽƵƐĞĂŶĚĨůŽǁůŝŶĞƐĨŽƌĂ:ĞƚWƵŵƉĐŽŵƉůĞƚŝŽŶ͘ WŽƐƚZŝŐtŽƌŬ ^ůŝĐŬůŝŶĞ ϭ͘ ^ƉŽƚ^ůŝĐŬůŝŶĞƵŶŝƚĂŶĚZh͘ Ϯ͘ WƌĞƐƐƵƌĞƚĞƐƚůƵďƌŝĐĂƚŽƌƚŽϯϬϬƉƐŝůŽǁĂŶĚϮ͕ϴϬϬƉƐŝŚŝŐŚ͘ ϯ͘ WƵůůĂůůĂŶĚƌŽĚ ϰ͘ WƵůůZ,ƉƌŽĨŝůĞ ϱ͘ ^ŚŝĨƚ^^ŽƉĞŶ ϲ͘ ^Ğƚ:WƉĞƌK ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ ƐͲďƵŝůƚ^ĐŚĞŵĂƚŝĐ Ϯ͘ WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘ KW^ĐŚĞŵĂƚŝĐ 6XSHUFHGHG BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB ZĞǀŝƐĞĚǇ͗ddtϱͬϭϳͬϮϬϮϮ WZKWK^ DŝůŶĞWŽŝŶƚhŶŝƚ tĞůů͗DWh&ͲϭϬϳ >ĂƐƚŽŵƉůĞƚĞĚ͗ϯͬϮϬͬϮϬϮϮ Wd͗ϮϭϴͲϬϬϭ dсϭϮ͕ϵϴϬ͛;DͿͬdсϰ͕ϭϯϮ͛;dsͿ ´ KƌŝŐ͘<ůĞǀ͗͘Ϯϲ͘ϱ͛;/ŶŶŽǀĂƚŝŽŶͿ ϳͲϱͬϴ͟ ϵͲϱͬϴ͟ WŽƚĞŶƚŝĂů,ŽůĞ ŝŶϳͲϱͬϴ͟ ĐĂƐŝŶŐ WdсϭϮ͕ϵϳϬ͛;DͿͬWdсϰ͕ϭϯϮ͛;dsͿ ^ĞŵĞŶƚĞƌ ΛϮ͕ϱϯϯ͛D DŝŶ/с Ϯ͘ϴϭϯ͟Λ цϱ͕ϯϲϬ͛ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ϮϬΗŽŶĚƵĐƚŽƌͲͬyͲϱϮͬtĞůĚĞĚEͬ^ƵƌĨĂĐĞϭϬϳΖ ϵͲϱͬϴΗ ^ƵƌĨĂĐĞϰϬͬ>ͲϴϬͬtϴ͘ϴϯϱ^ƵƌĨĂĐĞϲ͕ϯϱϯ͛ ϳͲϱͬϴΗ dŝĞďĂĐŬϮϵ͘ϳͬ>ͲϴϬͬsD^d>ϲ͘ϴϳϱ^ƵƌĨĂĐĞϲ͕ϭϱϯ͛ ϰͲϭͬϮ͟WƌĞƌŝůůĞĚ>ŝŶĞƌ ϳϲŚŽůĞƐͬĨŽŽƚ ϭϯ͘ϱͬ>ͲϴϬͬ,ǇĚϲϮϱ ϯ͘ϵϮϬ ϲ͕ϭϱϮ͛ ϭϮ͕ϵϳϱ͛ dh/E'd/> ϯͲϭͬϮΗ dƵďŝŶŐϵ͘Ϯͬ>ͲϴϬͬhϴƌĚϮ͘ϵϵϮ^ƵƌĨĂĐĞцϰ͕ϵϬϯ͛ :t>Zzd/> EŽ ĞƉƚŚ /ƚĞŵ ϭцϱ͕ϮϰϬ͛^ůŝĚŝŶŐ^ůĞĞǀĞ Ϯцϱ͕ϮϴϬ͛'ĂƵŐĞ ϯцϱ͕ϯϮϬ͛WĂĐŬĞƌ ϰцϱ͕ϯϲϬ͛ϯͲϭͬϮ͟yͲEŝƉƉůĞ;DŝŶ/Ϯ͘ϴϭϯͿ ϱцϲ͕ϭϮϱ͛^ŶĂƉ>ĂƚĐŚƐƐĞŵďůǇ ϲцϲ͕ϭϱϱ͛ϳͲϱͬϴ͟ǆϰͲϭͬϮ͟dƌŝƉŽŝŶƚWĂĐŬĞƌ ϳцϲ͕ϭϲϳ͛ϯͲϭͬϮ͟yͲEŝƉƉůĞ;DŝŶ/Ϯ͘ϴϭϯEŽͲŐŽ/Ϳ ϴцϲ͕ϭϳϱ͛t>' ϵϲ͕ϭϱϮ͛Kd^>yW>ŝŶĞƌdŽƉWŬƌǁͬ^ůŝƉƐ͕ϳΗǆϵϱͬϴΗ ϭϬϲ͕ϭϴϭ͛ƌŽƐƐŽǀĞƌ^Ƶď͕ϳΗ,ϱϲϯǆϰ͘ϱΗ,ǇĚϲϮϱ ϭϭϭϮ͕ϵϳϬ͛t/ssĂůǀĞǁŝƚŚϭ͟ĂůůŽŶ^ĞĂƚ ϭϮϭϮ͕ϵϳϱ͛ZŽƵŶĚEŽƐĞ&ůŽĂƚ^ŚŽĞ͗ŽƚƚŽŵΛϭϮ͕ϵϳϱ͛ t>>/E>/Ed/KEd/> <KWΛϰϯ͛ DĂǆ,ŽůĞŶŐůĞсϵϯ͘ϵĚĞŐ͘Λϭϯ͕ϰϱϴ͛ 'EZ>t>>/E&K W/͗ϱϬͲϬϮϵͲϮϯϱϵϮͲϬϬͲϬϬ ƌŝůůĞĚ͕ĂƐĞĚĂŶĚŽŵƉůĞƚĞĚďǇ/ŶŶŽǀĂƚŝŽŶͲ ϮͬϭϱͬϮϬϭϴ ^W^ǁĂƉďǇ^ZʹϭϬͬϯϭͬϮϬϭϴ ^W^ǁĂƉďǇ^ZʹϭͬϮϴͬϮϬϭϵ ^W^ǁĂƉďǇ ŽǇŽŶϭϰʹϯͬϮϬͬϮϬϮϭ dZΘt>>, dƌĞĞϱ<ĂŵĞƌŽŶ&>^ϮͲϵͬϭϲ͟ tĞůůŚĞĂĚ&D'ĞŶϱ DEdd/> ϮϬ͟ϮϳϬĐĨŽĨĐĞŵĞŶƚŝŶĂϰϮ͟,ŽůĞ ϵͲϱͬϴΗ ^ƚĂŐĞϭ͗>ĞĂĚϰϲϬƐǆ;ϮϬϯďďůƐͿŽĨϭϭ͘ϳηǆƚĞŶĚĂĞŵ dĂŝůϰϬϬƐǆ;ϴϭ͘ϲďďůƐͿŽĨϭϱ͘ϴη^ǁŝĨƚĞŵ ^ƚĂŐĞϮ͗>ĞĂĚϰϭϲƐǆ;ϯϮϬďďůƐͿŽĨϭϬ͘ϳηWĞƌŵĂĨƌŽƐƚ>Ğŵ dĂŝůϮϳϬƐǆ;ϱϲďďůƐͿŽĨϭϱ͘ϴη^ǁŝĨƚĞŵ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB ZĞǀŝƐĞĚǇ͗d&ϯͬϮϬͬϮϬϮϮ ^,Dd/ DŝůŶĞWŽŝŶƚhŶŝƚ tĞůů͗DWh&ͲϭϬϳ >ĂƐƚŽŵƉůĞƚĞĚ͗ϯͬϮϬͬϮϬϮϮ Wd͗ϮϭϴͲϬϬϭ dс ϭϮ͕ϵϴϬ͛;DͿͬdсϰ͕ϭϯϮ͛;dsͿ ´ KƌŝŐ͘<ůĞǀ͗͘Ϯϲ͘ϱ͛;/ŶŶŽǀĂƚŝŽŶͿ ϳͲϱͬϴ͟ ϵͲϱͬϴ͟ WdсϭϮ͕ϵϳϬ͛;DͿͬWdсϰ͕ϭϯϮ͛;dsͿ ^ĞŵĞŶƚĞƌ ΛϮ͕ϱϯϯ͛D DŝŶ/с Ϯ͘ϮϬϱ͟Λ ϰ͕ϳϵϲ͛ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ϮϬΗ ŽŶĚƵĐƚŽƌ ͲͬyͲϱϮͬtĞůĚĞĚ Eͬ ^ƵƌĨĂĐĞ ϭϬϳΖ ϵͲϱͬϴΗ ^ƵƌĨĂĐĞ ϰϬͬ>ͲϴϬͬt ϴ͘ϴϯϱ ^ƵƌĨĂĐĞ ϲ͕ϯϱϯ͛ ϳͲϱͬϴΗ dŝĞďĂĐŬ Ϯϵ͘ϳͬ>ͲϴϬͬsD^d> ϲ͘ϴϳϱ ^ƵƌĨĂĐĞ ϲ͕ϭϱϯ͛ ϰͲϭͬϮ͟WƌĞƌŝůůĞĚ>ŝŶĞƌ ϳϲŚŽůĞƐͬĨŽŽƚ ϭϯ͘ϱͬ>ͲϴϬͬ,ǇĚϲϮϱ ϯ͘ϵϮϬ ϲ͕ϭϱϮ͛ ϭϮ͕ϵϳϱ͛ dh/E'd/> ϮͲϳͬϴΗ dƵďŝŶŐ ϲ͘ϱͬ>ͲϴϬͬhϴƌĚ Ϯ͘ϰϰϭ ^ƵƌĨĂĐĞ ϰ͕ϵϯϴ͛ ϯͬϴ͟ ƵĂůĂƉƐƚƌŝŶŐ ^^ Eͬ ^ƵƌĨĂĐĞ ϰ͕ϵϯϴ͛ :t>Zzd/> EŽ ĞƉƚŚ /ƚĞŵ ϭϭϲϱ͛^ƚĂηϮ͗'>DͲǁͬ^K'>s Ϯϰ͕ϲϴϱ͛^ƚĂηϭ͗'>DͲǁͬ'>s ϯ ϰ͕ϳϵϮ͛ ϮͲϳͬϴ͟yEͲEŝƉƉůĞ;Ϯ͘ϮϬϱEŽͲŐŽ/Ϳ ϰ ϰ͕ϴϯϰ͛ ŝƐĐŚĂƌŐĞ,ĞĂĚ͗ϰϬϬhϭϬϰϬ ϱ ϰ͕ϴϯϱ͛ ĞŶŝƚŚWŽƌƚĞĚ^Ƶď͗,^ͬͬKWZ^^WKZdϰϬϬW ϲ ϰ͕ϴϯϱ͛ WƵŵƉηϯ͗ϰϬϬWD^yϭϯϰ&>yϭϳ͘ϱ,ϲ&Z^dWEd ϳ ϰ͕ϴϱϵ͛ WƵŵƉηϮ͗ϰϬϬWD^^Ϭϰϱ'ϭϮ,ϲ&Z ϴ ϰ͕ϴϲϳ WƵŵƉηϭ͗ϰϬϬWD^yϬϮϰ'/EW^,>,ϲ&Z^dWEd ϵ ϰ͕ϴϳϴ͛ 'ĂƐ^ĞƉĂƌĂƚŽƌ͗'^d,ssy ϭϬ ϰ͕ϴϴϮ͛ hƉƉĞƌdĂŶĚĞŵ^ĞĂů͗'^hd,ϲ^ͬW&^ ϭϭ ϰ͕ϴϴϵ͛ >ŽǁĞƌdĂŶĚĞŵ^ĞĂů͗'^>d,ϲ^ͬW&^ ϭϮ ϰ͕ϴϵϱ͛ DŽƚŽƌ͗ϱϲϮyW^^ϭϮϱŚƉͬϭ͕ϴϵϬsͬϰϭ ϭϯ ϰ͕ϵϬϱ͛ ĞŶŝƚŚ^ĞŶƐŽƌΘĞŶƚƌĂůŝǌĞƌ͗ŽƚƚŽŵΛϰ͕ϵϭϬ͛ ϭϰ ϲ͕ϭϱϮ͛ Kd^>yW>ŝŶĞƌdŽƉWŬƌǁͬ^ůŝƉƐ͕ϳΗǆϵϱͬϴΗ ϭϱ 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Suprv Comm ________MILNE PT UNIT F-107 JBR 04/01/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:3 Upper pipe rams had to be cycled to get to hold pressure. HCR choke and Manual kill both were serviced and cyceled to get to hold pressure. Test Results TEST DATA Rig Rep:ShonesOperator:Hilcorp Alaska, LLC Operator Rep:Demoski Contractor/Rig No.:Doyon 14 PTD#:2180010 DATE:3/17/2022 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopRCN220321090254 Inspector Bob Noble Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 8.5 MASP: 875 Sundry No: 322-081 Location Gen.:P Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec.P Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 14 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 none NA Annular Preventer 1 13 5/8"P #1 Rams 1 2 7/8" x 5"FP #2 Rams 1 Blinds P #3 Rams 1 2 7/8" x 5"P #4 Rams 0 none NA #5 Rams 0 none NA #6 Rams 0 none NA Choke Ln. Valves 1 3 1/8"P HCR Valves 2 3 1/8"FP Kill Line Valves 2 3 1/8"FP Check Valve 0 none NA BOP Misc 0 none NA System Pressure P2950 Pressure After Closure P1600 200 PSI Attained P52 Full Pressure Attained P186 Blind Switch Covers:PAll Stations Nitgn. 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ǁĂƐůĂŶĚĞĚǁŝƚŚĂWhtŽĨϰϬŬĂŶĚƐůĂĐŬŽĨĨǁƚŽĨϮϯŬ͘ ϮϮ͘ ZĞĐŽǀĞƌƚŚĞƚƵďŝŶŐŚĂŶŐĞƌ͘ Ϯϯ͘ WKK,ĂŶĚůĂǇĚŽǁŶƚŚĞϮͲϳͬϴ͟ƚƵďŝŶŐ͘EƵŵďĞƌĂůůũŽŝŶƚƐ͘dďŐǁŝůůďĞƌĞͲƌĂŶƵŶůĞƐƐĚĂŵĂŐĞŽƌ ŽƚŚĞƌŽďƐĞƌǀĂƚŝŽŶƐĂƌĞƐĞĞŶǁŚŝůĞƉƵůůŝŶŐ͘>ĂǇĚŽǁŶĨĂŝůĞĚ^W͘ Ă͘ WƵůůŽƵƚĂůůǀŝƐƵĂůůǇďĂĚũŽŝŶƚƐĂŶĚŵĂƌŬĨŽƌĚŝƐƉŽƐĂů͘ ď͘ >ŽŽŬĨŽƌŽǀĞƌͲƚŽƌƋƵĞĚĐŽŶŶĞĐƚŝŽŶƐĨƌŽŵƉƌĞǀŝŽƵƐƚƵďŝŶŐƌƵŶƐĂ ŶĚũƵŶŬƚŚĞŵ͘ Đ͘ dŚŝƐǁĞůůŚĂƐĂŶĞǆƚƌĞŵĞůǇŚŝŐŚŶƵŵďĞƌŽĨĐůĂŵƉƐŝŶƐƚĂůůĞĚƚŽ ƉƌŽƚĞĐƚƚŚĞ^WĐĂďůĞĨƌŽŵ ĚĂŵĂŐĞĚƵĞƚŽĂŶĞǆƚĞŶĚĞĚƐĞĐƚŝŽŶŽĨŚŝŐŚ>^͘dŚĞĨŽůůŽǁŝŶŐŶ ƵŵďĞƌŽĨĐůĂŵƉƐǁĞƌĞ ŝŶƐƚĂůůĞĚ͗ ŝ͘ ϱŵŽƚŽƌĐůĂŵƉƐ ŝŝ͘ ϭϱƉƵŵƉĐůĂŵƉƐ ŝŝŝ͘ ϲƐĞĂůĐůĂŵƉƐ ŝǀ͘ ϮŵŽĚŝĨŝĞĚ'>DĐůĂŵƉƐ ^WŚĂŶŐĞKƵƚ tĞůů͗DWh&ͲϭϬϳ ĂƚĞ͗ϬϮͬϭϲͬϮϬϮϮ ǀ͘ ϭŵŽĚŝĨŝĞĚĐůĂŵƉĂĐƌŽƐƐƚŚĞyE ǀŝ͘ ϯϭϬϱ͛ĐůĂŵƉƐ ǀŝŝ͘ ϭϬϮŵŝĚũŽŝŶƚĐůĂŵƉƐ ǀŝŝŝ͘ ϭϱϰĐƌŽƐƐĐŽůůĂƌĐůĂŵƉƐ Ϯϰ͘ WhŶĞǁ^WĂŶĚZ/,ŽŶϮͲϳͬϴ͕͟ϲ͘ϱη͕>ͲϴϬƚƵďŝŶŐ͘ŚĞĐŬĞůĞĐƚƌŝĐĂůĐŽŶŶĞĐƚŝŽŶƐĞǀĞƌǇϮ͕ϬϬϬ͛ Ă͘ ĂƐĞŽĨ^WĂƚцϰ͕ϵϰϬ͛D͘ Ă͘dŚĞƐĞƚƚŝŶŐǁŝŶĚŽǁĨŽƌƚŚĞĞŶƚŝƌĞ^WŝƐцϰ͕ϴϮϬͲϰ͕ϵϰϬ͛D͘dŚŝƐŝƐƚŚĞŽŶůǇ ƐĞĐƚŝŽŶƚŚĂƚŚĂƐ>^ďĞůŽǁϮΣ͘ ď͘ ϭũŽŝŶƚŽĨϮͲϳͬϴ͟ƚƵďŝŶŐ Đ͘ ϮͲϳͬϴ͟yEEŝƉƉůĞ;Ϯ͘ϮϬϱ͟EŽͲ'ŽͿ Ě͘ ϯũŽŝŶƚƐŽĨϮͲϳͬϴ͟ƚƵďŝŶŐ Ğ͘ >ŽǁĞƌϮͲϳͬϴ͟'>DǁͬĚƵŵŵǇ'>sŝŶƐƚĂůůĞĚ Ĩ͘ DƵůƚŝƉůĞũŽŝŶƚƐϮͲϳͬϴη͕ϲ͘ϱη͕>ͲϴϬ͕hϴƌĚƚƵďŝŶŐ Ő͘ hƉƉĞƌϮͲϳͬϴ͟'>DǁͬŽƌŝĨŝĐĞŝŶƐƚĂůůĞĚĂƚцϭϲϬ͛D Ś͘ ůĂŵƉŝŶŐ^ĐŚĞĚƵůĞ͗ Ă͘ ^WWƵŵƉͬ^ĞĂůƐĞĐƚŝŽŶĐůĂŵƉƐ ď͘ D>ͬĐĂďůĞƐƉůŝĐĞĐůĂŵƉ Đ͘ Ϯ͕ϴϱϬ͛ʹdŽƉŽĨ^W͗ϱ͛ĨƵůůĐŽǀĞƌĂŐĞĐŚĂŶŶĞůĐůĂŵƉƉůƵƐĐŽůůĂƌĐůĂŵƉĞǀĞƌǇũŽŝŶƚ Ě͘ ϭ͕ϲϬϬʹϮ͕ϴϱϬ͛D͗DŝĚͲũŽŝŶƚĐůĂŵƉĞǀĞƌǇũŽŝŶƚ͘ƌŽƐƐĐŽůůĂ ƌĐůĂŵƉĞǀĞƌǇũŽŝŶƚ Ğ͘ ^ƵƌĨĂĐĞʹϭ͕ϲϬϬ͛D͗ƌŽƐƐĐŽůůĂƌĐůĂŵƉĞǀĞƌǇũŽŝŶƚ Ϯϱ͘ >ĂŶĚƚƵďŝŶŐŚĂŶŐĞƌ;ĂƵƚŝŽŶŶŽƚƚŽĂŵĂŐĞĂďůĞǁŚŝůĞůĂŶĚŝŶ ŐƚŚĞŚĂŶŐĞƌͿ͘>ĂǇĚŽǁŶůĂŶĚŝŶŐ ũŽŝŶƚ͘EŽƚĞWh;WŝĐŬhƉͿĂŶĚ^K;^ůĂĐŬKĨĨͿǁĞŝŐŚƚƐŽŶƚĂůůǇ͘ Ϯϲ͘ ^ĞƚWs͘ WŽƐƚͲZŝŐWƌŽĐĞĚƵƌĞ͗ ϭ͘ EKWƐƚĂĐŬĂŶĚEhĞǆŝƐƚŝŶŐϮͲϵͬϭϲ͟ϱ͕ϬϬϬηƚƌĞĞͬĂĚĂƉƚĞƌĨůĂŶŐĞ͘dĞƐƚƚƵďŝŶŐŚĂŶŐĞƌǀŽŝĚƚŽϱϬϬ ƉƐŝůŽǁͬϱ͕ϬϬϬƉƐŝŚŝŐŚ͘WƵůůWs͘ Ϯ͘ ZŽǇŽŶϭϰ͘DŽǀĞƚŽŶĞǆƚǁĞůůůŽĐĂƚŝŽŶ͘ ϯ͘ ZĐƌĂŶĞ͘DŽǀĞϱϬϬďďůƌĞƚƵƌŶƐƚĂŶŬĂŶĚƌŝŐŵĂƚƐƚŽŶĞǆƚǁĞůůůŽĐĂƚŝŽŶ͘ ϰ͘ ZĞƉůĂĐĞŐĂƵŐĞ;ƐͿŝĨƌĞŵŽǀĞĚ͘ ϱ͘ dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ZhǁĞůůŚŽƵƐĞĂŶĚĨůŽǁůŝŶĞƐ͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ ƐͲďƵŝůƚ^ĐŚĞŵĂƚŝĐ Ϯ͘ WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘ KW^ĐŚĞŵĂƚŝĐ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB ZĞǀŝƐĞĚǇ͗d&ϮͬϭϰͬϮϬϭϵ ^,Dd/ DŝůŶĞWŽŝŶƚhŶŝƚ tĞůů͗DWh&ͲϭϬϳ >ĂƐƚŽŵƉůĞƚĞĚ͗ϭͬϮϴͬϮϬϭϵ Wd͗ϮϭϴͲϬϬϭ dсϭϮ͕ϵϴϬ͛;DͿͬdсϰ͕ϭϯϮ͛;dsͿ ´ KƌŝŐ͘<ůĞǀ͗͘Ϯϲ͘ϱ͛;/ŶŶŽǀĂƚŝŽŶͿ ϳͲϱͬϴ͟ ϵͲϱͬϴ͟ ƵĂů ϯͬϴ͟^^ ĂƉƐƚƌŝŶŐ Wdс ϭϮ͕ϵϳϬ͛;DͿͬ Wdсϰ͕ϭϯϮ͛;dsͿ ^ĞŵĞŶƚĞƌ ΛϮ͕ϱϯϯ͛D DŝŶ/с Ϯ͘ϮϬϱ͟Λ ϰ͕ϳϵϲ͛ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ ϮϬΗ ŽŶĚƵĐƚŽƌ ͲͬyͲϱϮͬtĞůĚĞĚ Eͬ ^ƵƌĨĂĐĞ ϭϬϳΖ ϵͲϱͬϴΗ ^ƵƌĨĂĐĞ ϰϬͬ>ͲϴϬͬt ϴ͘ϴϯϱ ^ƵƌĨĂĐĞ ϲ͕ϯϱϯ͛ ϳͲϱͬϴΗ dŝĞďĂĐŬ Ϯϵ͘ϳͬ>ͲϴϬͬsD^d> ϲ͘ϴϳϱ ^ƵƌĨĂĐĞ ϲ͕ϭϱϯ͛ ϰͲϭͬϮ͟WƌĞƌŝůůĞĚ>ŝŶĞƌ ϳϲŚŽůĞƐͬĨŽŽƚ ϭϯ͘ϱͬ>ͲϴϬͬ,ǇĚϲϮϱ ϯ͘ϵϮϬ ϲ͕ϭϱϮ͛ ϭϮ͕ϵϳϱ͛ dh/E'd/> ϮͲϳͬϴΗ dƵďŝŶŐ ϲ͘ϱͬ>ͲϴϬͬhϴƌĚ Ϯ͘ϰϰϭ ^ƵƌĨĂĐĞ ϰ͕ϵϯϴ͛ ϯͬϴ͟ ƵĂůĂƉƐƚƌŝŶŐ ^^ Eͬ ^ƵƌĨĂĐĞ ϰ͕ϵϯϴ͛ :t>Zzd/> EŽ ĞƉƚŚ /ƚĞŵ ϭ ϭϲϱ͛^ƚĂηϮ͗'>DͲǁͬ^K'>s Ϯ ϰ͕ϲϴϰ͛^ƚĂηϭ͗'>DͲǁͬ'>s ϯ ϰ͕ϳϵϱ͛ ϮͲϳͬϴ͟yEͲEŝƉƉůĞ ;Ϯ͘ϮϬϱEŽͲŐŽ/Ϳ ϰ ϰ͕ϴϯϲ͘ϳ͛ ŝƐĐŚĂƌŐĞ,ĞĂĚ͗ϰϬϬK ϱ ϰ͕ϴϯϳ͛ hƉƉĞƌdĂŶĚĞŵWƵŵƉ͗ϭϯϰ&>yϭϳ͘ϱ^y ϲ ϰ͕ϴϲϭ͛ >ŽǁĞƌdĂŶĚĞŵWƵŵƉ͗ϭϯϰ&>yϭϳ͘ϱ^y ϳ ϰ͕ϴϴϰ͛ 'ĂƐ^ĞƉĂƌĂƚŽƌ͗ϰϬϬ'^syD&Z ϴ ϰ͕ϴϴϳ͛ hƉƉĞƌdĂŶĚĞŵ^ĞĂů͗&^ϯ,ϲ&ZW&^,> ϵ ϰ͕ϴϵϯ͛ >ŽǁĞƌdĂŶĚĞŵ^ĞĂů͗&^ϯ,ϲ&ZW&^,> ϭϬ ϰ͕ϴϴϵ͛ DŽƚŽƌ͗>ϱ^WϮϲϰ,W͕sͲϮϴϳϱ͕DWϱϵ ϭϭ ϰ͕ϵϯϮ͛ ^ĞŶƐŽƌ͗E/d,WdϬϬϳϱϮ ϭϮ ϰ͕ϵϯϱ͛ ĞŶƚƌĂůŝǌĞƌ͗ŽƚƚŽŵΛϰ͕ϵϯϳ͛ ϭϯ ϲ͕ϭϱϮ͛ 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Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing ✓ Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Fill Clean-out w/ N2 0 Plug for Redrill ❑ Womte New Pool ❑ Repair Well 0 Re-enter Susp Well ❑ Other: ESP Change -out 0 2. Operator Hilcorp Alaska LLC 4. Well Class Before Work: 15. Permit to Drill Number: Name: Development ❑✓ Exploratory ❑ 1 218-001 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6. API Number: AK 99503 50-029-23592-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL025509 & ADL388235 MPU F-107 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point / Schrader Bluff Oil Pool 11. Present Well Condition Summary: Total Depth measured 12,980 feet Plugs measured 12,970 feet true vertical 4,132 feet Junk measured N/A feet Effective Depth measured 12,970 feet Packer measured 6,152 feet true vertical 4,132 feet true vertical 4,101 feel Casing Length Size MD TVD Burst Collapse Conductor 107' 20" 107' 107' N/A N/A Surface 6,326' 9-5/8" 6,353' 4,123' 5,750psi 3,090psi Tieback 6,128' 7-5/8" 6,153' 4,101' 6,890psi 4,790psi Drilled Liner 6,823' 4-1/2" 12,975' 4,132' 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-80 / EUE 8rd 4,937' 3,704' Packers and SSSV (type, measured and true vertical depth) BOT SLZXP LTP See Above N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 1 0 0 0 320 0 Subsequent to operation: 440 142 179 220 281 14. Attachments (required per 20 AAc 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations Exploratory❑ Development❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil 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 O.O. Exempt: 318-582 & 319-020 Authorized Name: Chad Helgeson Contact Name: Taylor Wellman`'"/ Authorized Title: llOperations Manager Contact Email: twellrnan0hllcorn.cot11 Authorized Signatu Qy'a'/ ,.. Date: 2/14/2019 Contact Phone: 777-8449 U Form 10-404 Revised 4/2017 RBDMSl- FEB 191019 2.�20 i� y/y oI9 Submit Original Only 0 corp Alaska, LLC Orig. KB Elev.: 26.5'(Innovation) SCHEMATIC Milne Point Unit Well: MPU F-107 Last Completed: 1/28/2019 PTD: 218-001 TREE & WELLHEAD Tree SK Cameron FLS 2-9/16" Wellhead FMCGenS CEMENT DETAIL 20" 270 cf of cement in a 42" Hole Wt/Grade/Conn Stage 1: Lead 460 sx(203 bbls) of 11.7# Extenda Cern 9 Tail 400 sx (81.6 bbls) of 15.8# Swift Cern 5/8" Stage 2: Lead 416 sx (320 bbls) of 10.7# Permafrost L Cern -/X-52/Welded Tail 270 sx (56 bbls) of 15.8# Swift Cem 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/DWC 8.835 Surface 6,353' 7-5/8" Tieback 29.7/L-80/VAM STL 6.875 Surface 6,153' 4-1/2" PreDrilled Liner 76 holes/foot 13.5 / L-80 / Hyd 625 3.920 6,152' 12,975' TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 4,938' 3/8" Dual Capstring SS N/A Surface 4,938' WELL INCLINATION DETAIL KOP @ 43' Mau H01e Angle = 93.9 deg. @ 13,458' JEWELRY DETAIL No Depth Item 1 165' Sta#2: GLM-w/SOGLV 2 4,684' Sta#1: GLM-w/DGLV 3 4,795' 2-7/8" XN-Nipple (2.205 No-go ID) 4 4,836.7' Discharge Head: 400 BO 5 4,837' Upper Tandem Pump: 134FLEX17.5 SXD 6 4,861' Lower Tandem Pump: 134FLEX17.5 SXD 7 4,884' Gas Separator: 400GSV X M FER 8 4,887' Upper Tandem Seal: FSB31)B H6 FER PFSA HL 9 4,893' Lower Tandem Seal: FSB313B H6 FER PFSA HL 10 4,889' Motor: CLS SP 264HP, V-2875, AMP 59 11 4,932' Sensor: ZENITH PT00752 12 4,935' Centralizer: Bottom @ 4,937' 13 6,152' BOT SLZXP Liner Top Pkr w/BD Slips, 7" x 9 5/8" 14 6,181' Crossover Sub, 7"H563x 4.5"H d625 15 12,970' WIV Valve with 1" Ball on Seat 16 12,975' Round Nose Float Shoe: Bottom @ 12,975' TD=12,980' (MD)/TD=4,132'CM) PBTD = 12,97U(MD) / PBTD= 4,132'M) GENERAL WELL INFO API: 50-029-23592-00-00 Drilled, Cased and Completed by Innovation - 2/15/2018 ESP Swap by ASR —10/31/2018 ESP Swap by ASR —1/28/2019 Revised By: TDF 2/14/2019 Hilcorp Alaska, LLQ Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP F-107 ASRC 50-029-23592-00-00 218-001 1/12/2019 1/28/2019 Daily Operations. 1/9/2019 - Wednesday No activity to report. 1/10/2019 - Thursday No activity to report. 1/11/2019 - Friday No activity to report. 1/12/2019 -Saturday Notified AOGCC inspector of successful shell test. Inspector in -route to witness BOP test. Test BOPE as per Hilcorp & AOGCC requirements, test w/ 2-3/8 & 3-1/2" TJ, 250 /2,500 psi, test witnessed by AOGCC inspector Matt Herrera. 1/13/2019 -Sunday Cont. Test BOPE as per Hilcorp & AOGCC requirements, test w/ 2-3/8 & 3-1/2" TJ, 250 /2,500 psi, test witnessed by AOGCC inspector Matt Herrera, all good. Blow down & r/d test eq. Service Rig Eq., change fluids on Rig & generators. Load wk string into warm up trailer. Continue Service Equipment. Prep to pull blanking sub, attempt to screw pulling sub into blanking sub, found starting threads bad on pulling tool. Brought new pulling tool from wellhead shop and screwed into blanking sub and pulled blanking sub. Pulled BPV, unscrewed lock downs in WH. Pull up hanger, pulling weight 44K, pull and lay down hanger,. Continue POOH w/ 2-7/8 tubing pulling clamps and connecting ESP power cable and control line to spooling unit. Continue POOH w/ 2-7/8" Tubing t/2,731', removing clamps and laying down tubing. Laying down joint 70 of 154 @ 0600 hrs. Pulling weight 23K. 1/14/2019 - Monday Cont. POOH I/d 2 7/8" completion (/2,731' t/ ESP assy, I/d 154 jts, 2 -GLM assy, pipe came wet @ lower GLM, (valve had been pulled ). POOH I/d ESP assy, found solids at discharge head, small amount of solids top of 2nd pump, had scar in top of upper seal. Complete lay down ESP assembly and load out for Centri-lift to haul to shop. Take on 150 bbls P/W and fill pits. Pick up Washington head and make up spools, blind off flowline to pits. Had to get replacement blind flange from well support. 100K JD generator run out of diesel, re -fueled and re -started. Completed fluid checks on equipment. Start P/U Clean out BHA consisting of 3.750 tri -cone bit, bumper sub, hydraulic jars, 4- 3.125 drill collars and X -over to 2-3/8" PH -6 5.9# tubing. RIH with clean out BHA and 2-3/8" PH -6 5.9# tubing Currently on jt 30 @ 0600 hrs. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP F-107 ASRC 50-029-23592-00-00 218-001 1/12/2019 1/28/2019 Daily Operations. 1/15/2019 - Tuesday Cont. RIH w/ cleanout assembly, t/6,089', P/U 2 3/8" PH -6 wk string, making adjustments to tongs as needed while having issues to preform better making connections. Continue RIH to 6,090' near top of liner. Pump 5 bbls down tubing @ 4bpm and caught pressure with 5 bbls away. Fluid Level at 1,470'. Turned around and pumped 70 bbls down backside at 4bpm and caught circulation. Returns 1 bpm at best. S/D Pump and caught pick and slack off weights. 34K up and 13K down. Free torque at 1,400 ft/lbs. Weight rotating: 28K up and 15 K down. Prep to continue to RIH. Continue RIH to 8,464' MD Joint 259. tag fill or obstruction, pick up 10 ft and set back down hard and broke through obstruction. Line up to pump down backside and pump 80 bbls @ 4 bpm. with no returns. Blow down and prep to RIH. RIH w/ down with @ 12K, RIH 15' and tag hard obstruction, P/U and spud on obstruction without making hole. R/U to pump down tubing - pump down tubing @ 4bpm and wash through obstruction, wash down 26' past obstruction with good indication of washing fill. Pull up 30' and run back through washed area @ 12K down and slick movement. Pumped 60 bbls with no returns. R/U tp pump reverse, pump 93 bbls before catching returns, returns at 1 bpm. Pumped 150 bbls total and shut down due to pits running low. Blow down and prep to RIH. U/ I Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP F-107 ASRC 50-029-23592-00-00 218-001 1/12/2019 1/28/2019 Daily Operations. 1/16/2019- Wednesday POOH I/d 3-1/2" wk string, c/o handling tools, cont. POOH I/d 2-3/8" wk string. L/D BHA and secure well. Move out 3.5" work -string and 2-3/8" work string, move in 3.5" EUE 8rnd string, R/D ESP "elephant trunk" and ESP handling equipment, R/D Washington head. RIH w/ 3.5" EUE 8 rnd 9.3# L-80 tubing with 30 75' foot muleshoe joint on bottom Joint 144 in hole when rig engine died. Muleshoe @ 4659' MD. Troubleshoot rig engine dying. Found Oil filter seal failed and engine died on low oil. Necessary to replace oil filter and refill. ' c) 1/17/2019 - Thursday Cont. RIH w/ 3.5" EUE 8 rnd 9.3# L-80 tubing with 30.75' foot mule shoe t/ 6,193'tag no-go, P/U t/space out (did get hung up coming out of liner top worked free) P/U & m/u spaceout pups, M/U hanger assembly& landing jt, land hanger & run in I/d pins placing tubing tail @ 6,187', set BPV & pull landing it. Blow down lines & start Rigging down. Continue RDMO ASR to E-15, N/D BOPE, N/U tree, test void 250/5000 good 1/18/2019 - Friday Complete RD and move of ASR. RU CTU flowback equipment. RU CTU#6. BOP testing. 1/19/2019 -Saturday CT Crew on location. MU BHA #1- 2" CTC Roll on, dual checks, 2 each 2" Straight bar 5', 2.2" JSN with 9 ports Stab on well. Fluid pack CT. Halliburton N2 on location. PT CTE and CT low/ High 271/ 3,900psi. RIH with BHA #1. RIH to dry g. Rlh to 8,600'. did not set down. Puh to 8,400'. Start circulating Slick KCI with NXS lub down DCT. Safety meeting for N2 operations. PT Halliburton N2 hardline low high300/4,250psi. Start N2 at 1000scfm with slick. Estimate down hole at 2.4 bpm eq. rate. Circulate waiting for n2 to come around to surface. N2 back to surface. well flowing. Pump first slug of N -vis. RU+IH jetting slick/ Gell with 1,000 scfm n2. Taking 150' bites and pickups. make short trip at 10,150' to 9,700'. continue working down making 150' bites with pickups. Sending NVis pill about every 30 bbls of slick. Getting goo returns until 10,600'. Lost returns. Puh reducing liquid rate. Had to pull back up to 5,880' for returns to start back up. RIH again. Start taking 200 ft pites and pick ups. Continue in hole with reduced liquid rate of 1 bpm and 1,000scfm n2 rate. Seeing fine grit material in samples. some crude returns. Continue in hole making 200 ft bites. Made short trip at 11,150'. Jet down to 12,200' Coil getting close to lock up. Made a short trip. Could not get back to 12,200'. POH jetting on way out of hole. Getting good returns to surface through most of POH. Shut off slick water at 6,000'. SD N2 at 3,000'. On surface. Secure well for the night Rack back CT. 1/20/2018 -Sunday No activity to report. 1/21/2018 - Monday No activity to report. 1/22/2018 -Tuesday No activity to report. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP F-107 ASK 50-029-23592-00-00 218-001 1/12/2019 1/28/2019 Daily Operations. 1/23/2019 - Wednesday No activity to report. 1/24/2019 -Thursday No activity to report. 1/25/2019 - Friday MIRU ASR (Performed well kill on 1-23-19, set BPV, N/d tree/ N/U BOPE 1-24-19). Continue MIRU ASR 60% complete. 1/26/2019 -Saturday Cont. R/U lines & winterize. Check temps good, fill surface eq. & lines, shell test 250 low & 3,500 high repair leaks as needed until good. Test BOPE as per Hilcorp & AOGCC requirements, witness was waived by AOGCC inspector Jeff Jones, test 250 low & 2,500 high as per Sundry, tested with 2-7/8" & 3-1/2" Us. P/U landing joint and blanking sub retrieval tool, pull blanking sub and find pressure under BPV, Line up and pump into tubing @ 800psi @ 3bpm, pump 1.5 tubing volumes with pressure falling to 350psi @ 3bpm (friction/restriction), pump 80 bbls (1.5 tubing volume), shut down and monitor tubing. Tubing @ Opsi, pull BPV and prep to pull hanger. Check well for no pressure, back out lock down screws, Pull hanger offseat w/ 39K and POOH w/ hanger @ 45K - prep to POOH. POOH L/D 3.5" 9.3# L-80 tubing t/surface, Filling w/ double displacement every 15 jts. 1/27/2019 -Sunday C/O handling tools, prep t/ p/u ESP completion Assy. P/U & service Baker ESP Assy. M/U MLE test cable good. Cont. rih p/u 2-7/8" 6.5# 1-80 EUE 8rd tubing t/ 1,062' installing cannon clamps full coverage first 1954', test cable every 1000'. Cont. rih p/u 2-7/8" 6.5# L-80 EUE 8rd tubing to 2, 880' installing cannon clamps full coverage , run collar and mid joint clamps from 2,880' to 1,613', then collar clamps from 1,613' to 30', pumping double displacement of 8.4# P/W. Testing every 1,000'. P/U hanger 1/28/2019 - Monday Cont. M/U hanger & penetrations, test same good. Land hanger placing tubing tail @ 4,935', up wt 40k, do wt 23k, rin in L/D pins, test cable good, pull landing jt & set BPV. Blow down, rig down, prep & start moving eq.to move to A -pad. Cont Prep & move eq. N/D BOPE & N/U tree tested void same 500 /5k good & secured same. 1/29/2019 -Tuesday No activity to report. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU F -I07 Permit to Drill Number: 218-001 Sundry Number: 319-020 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .00gcc.alaska.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/ p day of January, 2019. RBDMS�(,)P� 111019 RECEIVED STATE OF ALASKA )AN 17 2019 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well D Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing D ESP Changeout Q Plug for Redrill ❑ Perforate Now Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Fill Clean-out w N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development 121 Stratigraphic ❑ Service ❑ 218-001 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23592-00-00 ' 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 F-107 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025509 & ADL388235 Milne Point / 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): 12,980' 4,132' 12,970' 4,132' 874 12,970' N/A Casing Length Size MD ND Burst Collapse Conductor 107' 20" 107' 107' N/A N/A Surface 6,326' 9-5/8" 6,353' 4,123' 5,750psi 3,090psi Tieback 6,128' 7-5/8" 6,153' 4,101' 6,890psi 4,790psi Drilled Liner 6,823' 4-1/2" 12,975' 4,132' N/A N/A Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 2-7/8" 6.5# / L-801 EUE 8rd 4,938' Packers and SSSV Type: Packers and SSSV MD (ft) and ND (ft): BOT SLZXP LTP and N/A 6,152 MD/ 4,101 and N/A 12. Attbchmenl a: Proposal Summary Wellbore schematic ❑ 13. Wel. Class after proposed work: Detailed Operations Program.. ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 1/10/2019 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 Authorized Title: Operations Manager Contact Email: tvvellmaD hilcor .com Contact Phone: 777-8449 Authorized Signature: Date: 111712018 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: — /, I U A5P' Plug Integrity ❑ BOP Test d Mechanical Integrity Test ❑ Location Clearance ❑ Other: k Z5_00 /5�, AOP g � s Post Initial Injection MIT Req'd? Yes ❑ No ❑ / C�osc- �0-4a3 31d 'S L L C ar Spacing Exception Required? Yes ❑ No Subsequent Form Required: l0 `y � / 3i i _ e— APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: GUC 41% k RBDMSS3VIAN 2 2 201ORIGINAL �� \ Form 10-403 Revised 412017 A Submit Form and 1 Approved application is valid for 12 months from the ate of approval. Attachments in Duplicate '� Dill A . U Hile Ale" LLC ESP Change -Out Well: MPU F-107 Date:01/16/2019 Well Name: MPU F-107 50-029-23592-00 Current Status: Shut in — ESP Down F -Pad Estimated Start Date: January 17, 2018 ASR Reg. Approval Req'd? Yes Approval Rec'vd:Regulatory Contact: Tom Fouts 11ber: Drill Number: 218-001First Call Engineer: Taylor Wellman -8449 (0) (907) 947-9533 (M)Second Call Engineer: Stan Porhola 8412 (0) (907) 331-8228 (M)AFE Number: 1950265; a' ESP Swap Current Bottom Hole Pressure: 1,240 psi @ 3,664' TVDss ESP Gauge 12/20/2018/6.51 ppg EMW Maximum Expected BHP: 1,240 psi @ 3,664' TVDss ESP Gauge 12/20/2018/6.51 ppg EMW MPSP: 874 psi (0.1 psi/ft gas gradient) Brief Well Summary: MPU F-107 was drilled and completed with a pre -drilled liner in the Schrader Bluff OA sands in February 2018. Due to wellbore geometry, the ESP was set at a sub -optimal depth. The ESP was electively pulled and re -run to a deeper depth on 11/1/2018. The deeper set allowed for additional drawdown. There was an influx of solids that plugged the liner. These solids were backflushed and cleared down the liner. The ESP was started but would not surface fluids. A coil tubing FCO was conducted to the top of the ESP discharge and the ESP would not surface any fluids. The ESP was pulled on 1/15 and appeared to have a broken shaft. (Red font in procedure is the updated steps for CT cleanout using N2 on existing approved sundry #318-582.) Notes Regarding Wellbore Condition The 7-5/8" x 9-5/8" annulus was tested down to 6,153' MD / 1,500 psi on March 30, 2018. CO 390A: Hilcorp Alaska plans to not run a packer on this ESP completion as the pressure is less than 8.55ppg EMW in accordance with CO 390A. Objective: Pull ESP and replace plugged component. Clean fill from well lateral with coil tubing. Run functional ESP completion. Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) • Ensure all crews are aware of stop job authority Pre -Rig Procedure: 1. RU slickline and pressure test PCE to 250psi low/ 1500psi high. 2. Pull GLV at 4,717' md. RD SL unit. 3. Clear and level pad area in front of well. Spot rig mats and containment. 4. RD well house and flowlines. Clear and level area around well. UESP Change -Out Hilcorp M.A.. LLC Well: MPU F-107 Date:01/16/2019 5. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 6. Pressure test lines to 3,000 psi. 7. Circulate at least one wellbore volume with 8.5 ppg sea water down tubing, taking returns up casing to 500 bbl returns tank. 8. 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. 9. RD Little Red Services and reverse out skid. 10. RU crane. Set BPV. NO Tree. NU BOPE. RD Crane. 11. NU BOPE house. Spot mud boat. Brief RWO Procedure: ASR #1 Pull ESP/Run FCO String Procedure 12. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 13. 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. 14. 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 rams on 2-3/8" and 3-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 15. 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. 16. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ 8.5 ppg sea water as needed. 17. MU landing joint or spear and PU on the tubing hanger. a. The PU weight during the 2018 ESP Swap was 44K lbs. (Block weight not noted) HESP Change -Out Hil.q) Arsske, LLC Well: MPU F-107 Date:01/16/2019 b. If needed, circulate (long or reverse) pill with lubricant and/or baraclean pill prior to laying down the tubing hanger. 18. 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. 19. POOH and lay down the 2-7/8" tubing. Number all joints. Tubing will be re -used as noted. Lay down ESP. a. Pulling speed needs to be limited to 1jt/90 sec or as per Baker ESP Supervisor. This is to minimize chances for damaging the pump and motor. b. Take extreme care with the clamps. These are long lead items and are planned to be re- run on the next ESP. c. Replace bad joints of tubing as necessary and note on tally new tubing run. Note that during the Oct 2018 RWO, 60 joints were changed out due to galled or damaged threads. d. Note any sand or scale inside or on the outside of the ESP on the morning report. e. Look for over -torqued connections from previous tubing runs. DP ° f. The theory is that the discharge head has a blockage in it and will need to be replaced. If the blockage can't be readily identified (example in the discharge head alone), we will n `~ replace the pump seals, pumps and cable. 20. PU workstring and perform FCO of liner to target depth of 12,950' md. C&4_ev`� a. Reverse circulate as needed to obtain best cleanout possible. Use of N2 is not permitted without further approvals. 21. PU ar.:' run 3-1/2" fill clean out string into we�_�,/! S r0 rl i e T) a. End of the clean out string to be a muleshoe fr m cu': 3-1/2" joint . �2� b. Confirm 3-1/2" is stabbed into the 4-1/2" liner and PU to space out and land the hanger. '5 22. Land tubing hanger. RILDS. Lay down landing joint. Note: PU (Pick Up) and SO (Slack Off) weights on tally. 1,41 r 23. Set BPV. 24. RU crane. ND BOPE. 25. NU existing 4-1/16" 5,000# dryhole tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 26. Complete the RD and move of the ASR #1 to the next location. Coil Tubing FCO w/ N2 Procedure 27. RU CT unit and spot ancillary equipment. Fill tapks with 8.5ppg water or 1% KCI. 28. Pressure test BOPE to 3,500 psi Hi 250 Low, 1✓0 min Hi 5 min Low each test a. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks b. Record BOPE test results on 10-424 form. /C� 29. RIH w/ 2.00" coil w/ 2.0" to 2.5" max OD wash nozzle and extended reach cleanout BHA and I`✓ v cleanout to PBTD at+/- 14,804' MD. POOH. a. Recommended to include a circ sub in the BHA. b. Circulate out fill using 8.5 ppg 1% KCI w/liquid foamer and mix with Nitrogen (see Nitrogen procedure and diagram). c. Use gel sweeps as needed to help carry out solids. Utilize defoamer for returns in Kill Tank. d. Based on how well is reacting, use short trips up to the 3-1/2" tubing tail at ±6,200' and to ensure fill is carried out of hole. ESP Change -Out Well: MPU F-107 Hiles , Alaska. LLC Date: 01/16/2019 Note: During the ASR attempted FCO w/2-3/8"jointed pipe, abridge was encountered at 8,464' and and were able to wash down to 8,479' md. They were able to establish 25% returns while reverse circulating. Contingency: If unable to wash down with nozzle, RIH w/ 2.0" to 2.5" mill and extended reach cleanout BHA and cleanout to PBTD at +/- 14,804' MD using 8.5 ppg 1% KCI w/liquid foamer and mix with Nitrogen. POOH. 30. PU to 2,000' and freeze protect well. POOH w/ coil. 31. RD Coiled Tubing and ancillary equipment. 3 //1 - ASR #1 Pull FCO string/Run ESP Procedure s 4' 32. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 33. NU BOPE house. Spot mud boat. 34. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 35. 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 water prior to pulling BPV. Set TWC. 36. Test BOPE to 250 psi Low/ 2,50�i High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. f. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. g. Notify AOGCC 24 hours in advance of BOP test. h. Confirm test pressures per the Sundry Conditions of approval. i. Test VBR rams on 2-7/8" and 3-1/2" test joints. j. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 37. Contingency: (If+.he 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 se: with free en.) g. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via einail explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. h. With stack out of the test path, test choke manifold per standard procedure I. 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.) j. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. k. 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.) I. 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. 38. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ 8.5 ppg water as needed. 39. MU landing joint or spear and PU on the tubing hanger. 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. 40. POOH and lay down the 3-1/2" fill clean out string. H Hil n Al"Il LLC ESP Change -Out Well: MPU F-107 Date:01/16/2019 41. PU new ESP/cap string and RIH on 2-7/8" tubing. Set base of ESP assembly at ±4,940' MD. a. Upper GLM @ ± 140' MD w/SO b. 2-7/8" tubing C. Lower GLM w/ DGLV d. 3 joints of 2-7/8" tubing e. 2-7/8" XN (2.205" No -Go) f. 1 joint of 2-7/8" tubing g. Downhole gauge for discharge temperature and pressure (connected with a jumper from the lower sensor. Does not require a separate tech wire). h. Base of ESP centralizer @ ±4,940' MD Clamping schedule: • ESP Pump/Seal section clamps • MLE/cable splice clamp • 2,900' — Top of ESP: 5' full coverage channel clamp plus collar clamp every joint • Surface -2900' MD: Mid -joint clamp every joint. Cross collar clamp every joint 42. Land tubing hanger. RILDS. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off) weights on tally. 43. Set BPV. Post -Rip Procedure: 44. RD mud boat. RD BOPE house. Move to next well location. 45. RU crane. NO BOPE. 46. NU existing 2-9/16" 5,000# tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 47. RD crane. Move 500 bbl returns tank and rig mats to next well location. 48. Replace gauge(s) if removed. 49. Turn well over to production. RU well house and flowlines. Attachments: 1. As -built Schematic 2. Fill Clean Out String Schematic 3. Proposed Schematic 4. BOPE Schematic S. Coil BOPE Schematic 6. Nitrogen Operations Procedure 7. Coil Tubing Nitrogen and Foam Flow Diagram 8. Blank RWO MOC Form Orig, KB Elm: 26.5'(Irrtmetion) TD=12,980' (MD)/TD=4,132'(TVD) PBTD=12,970(MD) / PBrD= 4,132'(IVD) Milne Point Unit Well: MPU F-107 SCHEMATIC Last Completed: 10/31/2018 PTD: 218-001 TREE & WELLHEAD Tree SK Cameron FLS 2 Wellhead I FMC Gen5 CEMENT DETAIL 20" 270 d of cement In a 42" Hole Wt/Grade/Conn Stage 1: Lead 460 5x(203 bbls) of 31.78 Extenda Cem 9-5/8, Tall 400 sz (81.6 bbls) of 15.8# SLAIN Cem 20" Stage 2: Lead 416 sz (320 bbls) of 10.7# Permafrost L Cem -/X-52/Welded Tall 270 sz 56 bbls) of 15.89 Swift Cem CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor -/X-52/Welded N/A Surface 707' 9-5/8" Surface 40/L-80/DWC 8.835 Surface 6,353' 7-58" Tieback 29.7 / L-80 / VAM STL 6.875 Surface 6,353' 4-1/Y' PreOdlled Uner 76holes1foot 13.5 / L-80 / Hyd 625 3.920 6,152' 12,975' TUBING DETAIL 2-7/8" Tubi 6.5/L-80/EUE8rd 1 2.441 Surface 4,938' 3/8" Dual Ca string SS N/A Surface 1 4,938' WELL INCLINATION DETAIL KOP 8a 43' Max Hole Angle - 93.9 deg. @ 13,458' JEWELRY DETAIL No Depth Item 1 164' Sts #2: GLM•S/O 2 4,717 Ste#1: GLM -Dr LV 3 4 796' 2-7 8" XN-Nipple 1[2.205 No- o ID) 4 4,838' Discharge Head: FPDIS 5 4 839' _ UDE•_f Tandem Pump: PiASXD FLEX 17.5 6 4,862' Lower Tandem Pum : PMSXD FLEX 17.5 7 4,886' r.*._s Se orator: 400GSV X M FER 8 4,888' Uiper Tandem Seal: FS83DBW H6 FER HL PFSA 9 4,894' Lower Tandem Seal: FS83D8 IT H6 FER HL Pd FSA 4,900 Motor: SP Berated to 191HP/2653V/46A 11 4,933' Sensor: ZENITH E7 175C 12 4,936' Centralizer: Bottom —@4,938' 13 6,157 eOTSLZXP Liner To Pkr w/BDSII s,7"x95/8" 14 6,181' Crossover sub 7" H563 x 4.5" H d 625 YS 12,970' WIV Valve with I" Ball on Seat 16 12 975' Round Nose Float Shoe: Bottom @ 12,975' GENERAL WELL INFO API: 50029-23592-00-00 Drilled, Cased and Completed Innovation - 2/15/2018 ESP swap by ASR -10/31/2018 Revised By: TTW 12/17/2018 'n PROPOSED SCHEMATIC Rev 1 Nileam Alaska, LLC Odg. KB Elev.: 26.5'(Innovation) TD =12,980' (NU) /TD=4,132'(TVD) PB1D=12,97a(MD) / PB1D= 4,13Y(ND) L / . Milne Point Unit Well: MPU F-107 Last Completed: 10/31/2018 PTD: 218-001 TREE & WELLHEAD Tree SK Cameron FLS 2 -9/16 - Wellhead I FMC Gen 5 CEMENT DETAIL 20" 270cfof cement ina42"Hole Wt/Grade/Conn Stage 1: Lead 460 5x(203 bbls)Extend- Cem 9 5/8" Tail 400 sx (81.6 6615) of 15.8# Swift Cem Stage 2: Lead 416 sx (320 bbls) of 10.7# Permafrost L Cem -/x-52/Welded Tail 270 sx (56 bbls) of 15.8# Swift Cern CASING nFTAII "f � FC -C, W TUBING DETAIL WELL INCLINATION DETAIL KOP @ 43' Max Hole Angle = 93.9 deg. @ 13,458' JEWELRY DETAIL Type Wt/Grade/Conn ID Top Btm Conductor -/x-52/Welded N/A Surface 107' V Surface 40/L-80/DWC 8.835 Surface 6,353' Tieback 29.7/L-80/VAMSTL 6.875 Surface 6,153' PreDrilled Liner 76 holes/foot 13.5 / L-80 / Hyd 625 3.920 6,152' 12,975' "f � FC -C, W TUBING DETAIL WELL INCLINATION DETAIL KOP @ 43' Max Hole Angle = 93.9 deg. @ 13,458' JEWELRY DETAIL GENERAL WELL INFO API: 50-029-23592-00-00 Drilled, Cased and Completed by Innovation - 2/15/2018 ESP Swap by ASR —10/31/2018 Revised By: TTW 01/16/2019 MwithlV KPLiner Top Pkr w/BD Slips, 7"x95/8"er Sub, 7".563 x 4.5" Hyd 625ve with i" Ball on Seat 16 1 12,975' 1 Round Nose Float Shoe: Bottom @ 12,975' GENERAL WELL INFO API: 50-029-23592-00-00 Drilled, Cased and Completed by Innovation - 2/15/2018 ESP Swap by ASR —10/31/2018 Revised By: TTW 01/16/2019 Nf Ong. KB Elev.: 26.5'(Innovadon) PROPOSED SCHEMATIC TD=12,980' (MD) /TD=4,132'(TW) PBTD = 12,97U(MD) / PBTD=4,132(TVD) Milne Point Unit Well: MPU F-107 Last Completed: 10/31/2018 PTD: 218-001 TREE & WELLHEAD Tree SK Cameron FLS 2-9/16" Wellhead FMC Gen5 CEMENT DETAIL 20" 270 cf of cement In a 42" Hole Wt/Grade/Conn Stage 1: Lead 460 sx(203 bbls) of 31.7# Extenda Cent Top Tall 400 sx 181.6 bbls) of 15.80 Swift Cem 9-5/8" Stage 2: Lead 416 sx (320 bbls) of 10.7# Permafrost L Cent -/X-52/Welded Tail 270 sx 56 bbls) of 15.8# Swift Cem 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/DWC 8.835 Surface 6,353' 7-5/8" Tieback 29.7/480/VAM STL 6.875 Surface 6,153' 4-1/2" PreDrilled Liner 76 holes/foot 13.5/L-80/Hyd 625 3.920 6,152' 12,975' TUBING DETAIL 2-7/8" Tubing 6.5/L-SO/EUEBfd 2.441 1 Surface 4,938' 3/8" Dual Ca strip SS N/A I Surface ji 4,938' WELL INCLINATION DETAIL WK @ 43' Max Hole Angle = 93.9 deg. @ 13,458' JEWELRY DETAIL No Depth Item 1 ±164' Sto 112: GLM -S/0 2 ±4,717' Sta #1: GLM- DGLV 3 ±4,796' 2-7/8" XN-NI ple (2.205 No-go ID) 4 Se.uor. Zenith 5 _ :4,838' Discharge Head: FPDIS 6 ±4,839' Upper Tandem Pump: PMSXD FLEX 17.5 ±4,862' Lower Tandem Pump: PMSXD FLEX 17.5 8 ±4,886' Gas Se atator: 400GSV X M FER 9 14,888' Upper Tandem Seal: FSB3DB UT H6 FER HL PFSA 10 34,894' Lower Tandem Seal: FS830D LT H6 FER HL PFSA 11 14,900' Motor: SP Berated to 191HP / 2,653V / 46A 12 ±4,933' Sensor: ZENITH E7 175C 13 ±4,936' Centralizer: Bottom @ 4,938' 14 6152' BOT SIZXP Liner lop Pkr WED Slips, 7" z 9 5/8" 15 6,181' Crossover Sub, 7" H563 x 4.5" H d 625 16 12,970' WIV Valve with 1" Ball on Seat 17 12,975' Round Nose Float Shoe: Bottom @ 12,975' GENERAL WELL INFO API:50-029-23592-00-00 Drilled,Casedand Completedb Innovation -2/15/2018 ESP Swa ASR -30/31/2018 Revised By: TTW 12/20/2018 Milne Point ASR Rig 1 80PE 2018 11" BOPE Updated 5/14/2018 BR or Pipe Rams es COIL BOPE MILNE POINT UNIT 1 clen�p .w��hn, t,t,c 20X 10'/,X 7%X 4Y,, Coll Tubing BOP Blind/Shear4 1/16 Lubricator to Injection head 2.00" Single Stripper �_t_ Mm Pipe }---i F ----I Pipe Crossover spco! 41/16 10M X 4 1/16 SM Pump -In Sub 4 1/16 5M Manual Gate Manual Gate 1502 Union FMC .65 Generation 5 SH Wellhead System 0 0 1.4 Date: 1/2712018 O 85 Rig: Inovation #1 Well Number: MPF -107 O 1.4 L O o 1.4 2-9/16-5k Fig. --- —t 1.7 11-5k Fig. 0 o O FMC O 2.2 O jjjLLL�� 11-5k Fig. I FMC 0 1.95 J o O v� O STANDARD WELL PROCEDURE 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 1C.) WelWte Manager shall walk down valve alignmen*s and ensure valve position is correct. 1x.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly tat detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 40OBSt UPRIGHT I SEAWATER W/ DEFOAMER SOO BEL KILL TANK Coil Tubing Unit Fluid Flow Diagram Cleanout w/ Nitrogen & Foam SW or KCL W/ 408881 UPRIGHT FOAMER OR FRICTION SW or KCL 40D BBL UPRIGHT W/ FORMER OR FRICTION COIL UNTrWfTH 1.5" to 2.0" COIL REDUCER Choke Manifold I COIL PUMP NRROGENPUMP&TANK Fluids Pumped Fluids Returned Q 50 SOL F0.EEZE Valve Open Valve Cimed W PROCT TANK TE 11a. Date Valve Butterfly Valve DC N Ball Valve LOO Lo Torg Valve OM � Check Valve N Manual Choke Pg Updated 962/16 Pressure Gauge 0 H Hilcotp Hilcorp Alaska, LLC Changes to Approved Rig Work Over Suindry Procedure Date: 1 2/2112 01 8 Subject: Changes to Approved Sundry Procedure for Well MP F-107 File #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. 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O I I— U a m ! , Q Z 2 2 20 v I- U U co I J a O w i J w C ,' (�Q N ,mom V�J OI o z £ m �/ m J c N I6 N J r 0 a To as a £ y £ °' a NW y 3 ai f� Z N ch I I.,. a. m u E UJ O v I O• v) 2 d E J E Z dN '') 1 Q.!1 _O• a m 3 1 o Or Ja = D 1o U Ua n d 2 � o o N N a, O ap III Q ' H wV � UI Z d >0i E O V o 00 II libli , 0 N 1- d 0 co m o E N O H E ,-:m 1111 a w cm II I :: COCO co °Zp 03 Q J Cli 16 O To (0 Q a m O 1 O E U s >, , U• c 1 6 o Z u) I 03 d I0 I W ' • N c Z N N I • SILO a- O ill i17 N d ° co U) Z77a , to co 0 H m c a) Q O N d V po O '•+ C U NQ' N •l0 :.-i Q d £ O.m cnV a c OOE o o a f0 V Eo £ £Q _3 0C °a M J I Z0 a 0 1 1 0 • O 0 Seth Nolan Hilcorp Alaska, LLC 8 0 0 1 GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 2 9 1 4 3 Tele: 907 777-8308 iiar„rn:#I4.4ka Li.(: Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATE 03/12/2018 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU F-107 Prints: ROP-DGR-ABG-EWR-ADR 2"/5" MD DGR-EWR-ADR 2"/5"TVD CD: Log Viewers 3/12/2018 9:30 AM File folder CGM 3/12/2018 9:31 AM File folder Definitive Survey 3/12/2018 9:31 AM File folder EMF 3/12/2018 9:31 AM File folder LAS 3/12/2018 9:31 AM File folder PDF 3/12/2018 9:31 AM File folder TIFF 3/12/2018 9:32 AM File folder RECEIVED MAR 2 0 2018 AOGCC Please include current contact information if different from above. Please acknowledge receipt b ning and returning one copy of this transmittal or FAX to 907 777.8337 Received `O„ n , Date: 3tz1 kl— (/� c1 RECEIVED • STATE OF ALASKA • MAR 1 L 201$ ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT ANAM)gtc la.Well Status: Oil 0• Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20AAc 25.105 20AAc 25.110 Development ❑., • Explorator'' ❑ GINJ ❑ WINJ ❑ WAGE WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date.,Susp.,or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 2/15/2018 , 218-001 • 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 January 23,2018 50-029-23592-00-00 • 4a.Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 1488'FSL,3246'FEL,Sec 6,T13N, R10E, UM,AK February 4,2018 MPU F-107 Top of Productive Interval: 9. Ref Elevations: KB: 37.7 17. Field/Pool(s):Milne Point Field 588'FSL,372'FWL,Sec 6,T13N, R10E,UM,AK GL:10.8' BF: 10.8' Schrader Bluff Oil Pool • Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 332'FSL, 1258'FEL,Sec 7,T13N, R10E, UM,AK 12,970'MD/4,132'TVD , ADL025509,ADL388235 ' 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 541322 y- 6034937 Zone- 4 12,980'MD/4,132'TVD • LONS 94-109 i TPI: x- 539782 y- 6034028 Zone- 4 12. SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 543371 y- 6028513 Zone- 4 N/A 2,380'MD/1,877'TVD i 5. Directional or Inclination Survey: Yes kJ (attached) • No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MDITVD: 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 potehtial, 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-DGR-ABG-EWR-ADR 2"/5"MD DGR-EWR-ADR 2"/5"TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE HOLE SIZE CEMENTING RECORD FT. TOP BOTTOM TOP BOTTOM PULLED 20" - X-52 Surface 107' Surface 107' 42" 270 ft3 , Stg 1 L-460 sx/T-400 sx 56bls 9-5/8" 40# L-80 Surface 6,353' Surface 4,123' 12-1/4" Stg 2 L-416 sx/T-270 sx 2681bbls 7-5/8" 29.7# L-80 Surface 6,153' Surface 4,101' Tieback TiebackAssy 4-1/2" 13.5# L-80 6,152' 12,975' 4,101' 4,132' 8-1/2" Cementless PreDrilled Liner 24.Open to production or injection? Yes Q No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/1VD) Size and Number; Date Perfd): 2-7/8" 2,985' N/A PreDrilled 4-1/2"Liner 6,394'-12,850'MD/4,135'-4,127'TVD Liner has 76 holes/foot,3/8"hole 26.ACID, FRACTURE,CEMENT SQUEEZE, ETC. s.M1i't.t: >1`+ Was hydraulic fracturing used during completion? Yes❑ NOQ 20 AAC 25.283 ionl ;)ATE 1Ar� DEPTHr INTERVAL(MD) AMOUNT AND KIND OFMATERIAL USI T.Ilcj_I ohprinted attach electronic and t D Vpi !F'F:'-! I - 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 1 2/21/2018 ESP Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio': 3/2/2018 24 Test Period 369 92.7 19.1 N/A 249 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 246 260 24-Hour Rate 369 92.7 19.1 15.7 Form 10-407 Revised 5/2017 ,�,J j,./1./S' _C,ONTINUED ON PAGE 2 RBDMS mu + J 2C18 Submit ORIGINIAL oG dub •&gala / /�Xiiii 0, • • 28.CORE DATA Conventional Core(s): Yes ❑ No ❑Q Sidewall Cores: Yes ❑ No ❑✓ If Yes, list formations and intervals cored(MDITVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with thip 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 Q Permafrost-Top If yes, list intervals and formations tested, briefly summarizing test results. Permafrost-Base 2,380' 1,877' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval Schrader OA 6,394' 4,135' information, including reports,per 20 AAC 25.071. SV5 1,558' 1,381' SV1 2,706' 2,069' Ugnu LA3 4,476' 3,409' Schrader NA 5,387' 3,941' Schrader OA 6,287' 4,116' Formation at total depth: Schrader OA 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cement 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. I 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: Cdinger(C7hiIco .Com Authorized t Contact Phone: 777.8389 Signature: Date: 1 Z Z® i INSTRUCTIONS General: This orm and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. 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 measurenpents 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,subnhit 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 HO • Milne Point Unit Well: MPU F-107 SCHEMATIC Last Completed: 2/15/2018 Hilcorp Alaska,LLC PTD: 218-001 Ong.KBEIev.:26.5'(Innovation) TREE&WELLHEAD Tree 5K Cameron 2-9/16" Wellhead FMC Gen 5 2O CEMENT DETAIL iii 1 20" 270 cf of cement in a 42"Hole Stage 1:Lead 460 sx(203 bbls)of 11.7#Extenda Cern Dual Tail 400 sx(81.6 bbls)of 15.8#Swift Cem 3/8"SS s' 9-5/8" Capstnng Stage 2: Lead 416 sx(320 bbls)of 10.7#Permafrost L Cern ��+► Tail 270 sx(56 bbls)of 15.8#Swift Cern CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm ES Cementer .; 20" Conductor -/X-52/Welded N/A Surface 107' @2,533'MD- 9-5/8" Surface 40/L-80/DWC 8.835 Surface 6,353' _ 1 7-5/8" Tieback 29.7/L-80/VAM STL 6.875 Surface 6,153' 44/2" PreDrilled Liner 13.5/L-80/Hyd 625 3.920 6,152' 12,975' 76 holes/foot Win ll: 2 TUBING DETAIL 2.205"r' , 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.441 Surface 2,985' 2.873' 3/8" Dual Capstring SS N/A Surface 2,985' 3 WELL INCLINATION DETAIL P 4 P KOP@43' ' 5&6 Max Hole Angle=93.9 deg.@ 13,458' e H 1,1 4 y7 t; Ai F ' JEWELRY DETAIL "s 8&9 No Depth Item il 10 1 135' Sta#2:GLM-1"Side Pocket KBMM w/Orifice `°± 2 2,761' Sta#1:GLM-1"w/Dummy .- F J )• 3 2,873' 2-7/8"XN-Nipple(2.205 No-go ID) Q1.- IJ 11 4 2,915' Discharge Head:FPDIS �( 10P 12 v 5 2,916' Upper Tandem Pump:62 STG FLEX 17.5 1"�: 6 2,927' Lower Tandem Pump:134 STG FLEX 17.5 5/8 ► 7 2,951' Gas Separator:GRS FER N AR 8 2,954' Upper Tandem Seal:GSB3DBUTSB/SB PFSA 9 2,961' Lower Tandem Seal:GSB3DBUTSB/SB PFSA ori - Fes,+ 13 10 2,967' Motor:CL5 XP–200hp/3635V/34A 9 5/8.,, 11 2,980' Sensor,Zenith S/S TB12629 14 12 2,983' Centralizer:Bottom @ 2,985' 13 6,152' BOT SLZXP Liner Top Pkr w/BD Slips,7"x 9 5/8" 1 • 14 6,181' Crossover Sub,7"H563 x 4.5"Hyd 625 15 12,970' WIV Valve with 1"Ball on Seat •' 16 12,975' Round Nose Float Shoe:Bottom @ 12,975' 1 • GENERAL WELL INFO • =" API:50-029-23592-00-00 • 1 Drilled,Cased and Completed by Innovation -2/15/2018 • • I . 15&16 TD=12,980'(MD)/TD=4,132'(TVD) PBTD=12,970'(MD)/PBTD=4,132'(TVD) Edited By:CJD 2/27/2018 • • Hilcorp Energy Company Composite Report Well Name: MP F-107 Field: Milne Point County/State: Prudhoe Bay,Alaska (LAT/LONG): avation(RKB): 26.5 API#: 50-029-23592-00-00 Spud Date: 1/23/2018 Job Name: 1714019D MPF-107 Drilling Contractor Innovation AFE#: AFE$: 1/19/2018 Continue wait on weather.Plug mods back in together.Get portable welder and torch staged in pipe shed.Trouble shoot Mud Mod Cold start.The louve s had blown shut due to wind,overheated and shut;down.Cooled down and started back up with no further issues.Get boiler#1 feed pump working.Install paddles on Drag Chain.Stage spool of new tugger line on rig floor.;Change out supply and return steam valve f/pits and Mezz to globe valves.C/0 purge system in pits. Install regulator,flow control&filter for purge system.Work writing Rig Procedures.;Continue to wait on weather.Work on various rig maintenance projects, welder work on centrifuge feed pump motor supports.Change out drillers side tugger line.Clean areas of rig.;R/D cuttings tank berm.Clear snow from a ound riq,L-pad and F-pad. 1/20/2018 Prep to move rig.Finish snow removal around rig.Clear snow from F-Pad and Set Matt boards.Trucks on location @ noon.Move shop to F-Pad Set same in place.Move Enviro and break shacks.;and stage on F-Pad.Separate Modules and move Motor Mod,Cat walk and Pipe Shed to F-Pad.Attempt to walk sub off L-52.Wellhead hands had to remove Actuator f/2nd master on tree.;Well head rep finish removing actuator and secondary master valve off tree,walk sub off L- 52.Orient sub,install sub rear tires,orient sub.install tow bar.Mobilize sub module to F-pad;Mud module broke bead on 2 front left tires while positioning on L- Pad. Notify Peak tire repair. Well head rep re-install actuator and secondary master valve on tree.;Finish setting mats around F-107,Place wellhead behind conductor,back and spot sub over F-107, lay rig mats,shim sub,set catwalk. 1/21/2018 Spot and Level Sub Base over F-107.Spot cattle/Pipe Shed.Continue to work with Peak tire Man replaced 0-rings in 7 back tires,6 front tires on Mud Module.;Cold Start on Sub Base shut down due to breather tube iced up..Fix Boiler flame issues.Clean up on L-Pad and turn L-52;over to Production.Lay Pit Liner for cutting box.Set Cuttings box.Welder modify sumps in pipe shed with new grating.Fuel Cold Starts.;Peak tire repair finished with 0-ring C/0 on mud module @ 19:00,mobilize mud module to F-Pad and position on pad,L/D mat boards,back in and spot mud module.;Peak tire repair replace 0-rings on 3 rear tires on motor module.L/D mat boards,back in and spot motor module.Remove jeep.Spot break shack and enviro-vac,Release Peak©03:00.;Install handrails,lower Mod landings and stairways.R/U interconnect utility lines.Get steam circulating on rig.Electrician on rig getting electrical interconnects tied in. Put riq on gen power. 1/22/2018 Hook up Pit/Mezz Interconnects.Work on rig acceptance check list.Fix leak on boiler#1 feed pump.Put mud pumps back together.Organize pad.Install grating in cellar. Hook up Wt Bucket and;Geronimo lines.Get water going through out the rig.Prep to scope Derrick.Scope and pin same.Bridle down and secure lines.Finish up Drag chain install.Fill pit with hot water and circulate;through pit lines to clear any ice.Continue moving misc trailers/equipment and mud products to F-Pad. Move Office Camp from L to F-Pad.Assist Electrician putting office camp on Rig Power.;Load and Tally 75 jts DS-50 DP.;N/U Diverter System.Dress and set speed head wt well head rep.Continue to circulate hot water thru pits.;PJSM,Set diverter tee,M/U knife valve,start positioning and flanging up diverter sections.Set BOP stack,TQ flanges.M/U conductor valves.R/U koomey lines to Knife valve and annular.;Charge accumulator dampener. Set bell nipple,secure stack.Continue to process 5"DP.;Continue to mobilize equipment f/L to F-pad.Clean rig,complete pre-spud checklist.Finish processing 152 jts 5"DP.R/U Hawk jaw and pipe handling equipment,ready rig floor to P/U DP.;Ready pipe shed for BHA.Work on rig acceptance checklist.;Power up accumulator, P/U jt 5"DP,Function diverter to check for leaks,annular closed in 12 sec,knife valve opened in 6 sec.;Service top drve, blocks and pipe handling equipment.;Set mouse hole in rotary table,drift and P/U 5"DS50 DP racking 76 stds in derrick. Rig accepted©06:00.;260 bbs H2O hauled from 6 mile lake for total 260 bbls 1/23/2018 While wait on HWDP: Grease Crown Cluster.Weld fluid deflector plate in Pill Pit 1 to deflect fluid away from Suction line.CIO Check valve on Boiler#1 feed pump.;Check all bolts on diverter system for full nuts. C/0 Dies on 5"slips.R/U tongs for surface BHA.Add Gear oil to TD. Received 44 jts HWDP and 41 Ey Jts DS-50 Load strap and Tally HWDP and DS-50.;Test Diverter System on 5"DP Start:2975,After close 1900 psi,200 psi build 9 sec,Full Recovery 51 sec. ' Ann.Close time 13 sec,Knife Valve Open 6 sec.Test Gas alarms and PVT System.All Pass.Test Witnesses . :• :-• u-, .- - -.;PU and rack back' UI 40 jts DS-50 Dp and 17 jts HWDP wlJars. Total DS-50 in derrick=192 jts+17jts HWDP=—6600'.;R/D and demob Hawk Jaw. Clean and clear rig floor. ',i `/ Prep for making up BHA and verify correct lineup in cellar and pits for spud.;Perform Evacuation drill. Notified Security,Pad Operator and sym ops on location. `') Post discussion about ensuring everyone is on rig POB or visitor log to be accounted for and logs are accurate:Pre-Spud meeting post drill. Discussed t' upcoming task and hazards associated with.;M/U 12.25"Kymera,1.5°bend motor,BN X0 and HWDP. Flood surface lines and conductor with H2O. Test surface lines to 3k and check for leaks(test good).:RIH and tag ice 0 76'MD. Clear ice to 106'then drill new formation to 120'MD. P/U and displace to 8.7# spud mud. Continue drill ahead to 220'MD. 400 gpm,300 psi,40 rpm,2.5k tq,3k wob.;B/D TDS. Rack back HWDP. M/U remaining MWD/LWD tools and scribe. Orient mtr,mwd&UBHO. Download MWD and R/U Gyro sym ops.;Cont drlg F/220'-T/605'MD. Last gyro svy©169'MD. Clean MWD svy's© 233'MD. Released Gyro @ 458'and R/D same. 400 gpm,710 psi,40 rpm,2.5k tq,5k wob.;Light to moderate gravel first 200-300 ft. Transitioned to more sand and pea gravel towards 500'then started seeing more fines(sand/silt w/some clay and gravel).;Last svy @ 419'MD,4.19°Inc,308.28°=1.28'low, .3'left of WP 11.;Hauled 171 bbls cuttings to G&I for total=171 bbls Hauled 520 bbls from 6 mi lake for total=780 bbls 1/24/2018 Drill 12 1/4"Hole F/605'-T/1145'.540'total(90'AROP)500 gpm/1365 psi.60 rpm/4.5k tq,10-12k wob 76k up,77k dn,80k rot.ECD 9.6,Max Gas 76u.;Continue to Process 9 5/8"Casing.;Drill 12 1/4"Hole F/1145'-T/1676'.531'total(88.5'AROP)550 gpm/1678 psi.80 rpm/5.1k tq,6-8k wob 80k up, 75k dn,80k rot.ECD 9.8,Max Gas 20u.;Drill 12 1/4"Hole F/1676'-T/2340'.664'total(110'AROP)550 gpm/1690 psi.80 rpm/5.3k tq,6-10k wob,93k up, 74k dn,80k rot.ECD 10.2.;Drill 12 1/4"Hole F/2340'-T/2843'.503'total(111'AROP)550 gpm/1650 psi.80 rpm/5.7k tq,6-10k wob,93k up,74k dn,80k rot.ECD 10.2.;Logged base of permafrost©2352'MD/1861'TVD.Start reducing mud vis from 220 to 150+/-@ 2500'MD.;CBU @ 2843'MD. Shakers blinding off. Reduce rate below acceptable drilling rate to allow shakers to clean up. Min 300 gpm and stg up to full drilling rate 550 gpm as shakers allow.;Mostly silt with clay©shakers.;Drill 12 1/4"Hole F/2843'-T/2906'.63'total(126'AROP)550 gpm/1650 psi.80 rpm/5.7k tq,6-10k wob,93k up,74k dn,80k rot.ECD 10.2.;Last svy @ 2740'MD,53.95°Inc,301.57°Az=1'low,4.5'left of well plan 11.;Hauled 923 bbls cuttings to G&I for total=1095 bbls Hauled 910 bbls H2O from 6 mi lake for total=1690 bbls • • 1/25/2018 Drill 12 1/4"Hole F/2940'-T/3409'.469'total(78'AROP)500 gpm/1650 psi.80 rpm/8k tq,4k wob,117k up,85k dn,98k rot.MW 9.4,ECD 10.2 Max Gas 675u.;Drill 12 1/4"Hole F/3409'-T/3874'.465'total(77'AROP)550 gpm/1789 psi.80 rpm/8k tq,10.2k wob,132k up,93k dn,110k rot.MW 9.3,ECD 9.85 Max Gas 38u.;Drill 12 1/4"Hole F/3874'-T/4310'.436'total(73'AROP)600 gpm/2250 psi.80 rpm/12.4k tq,10k wob,MW 9.1,ECD 9.8 Max Gas 38u. Lower directional work started @ 4100'for build/turn.;C/O swab#3 on MP#2 @ 4200'+/-.Repaired Centrifuge#2 and put back online @ 22:30 hrs(failed bearing).;Drill 12 1/4"Hole F/4310'-T/4856'. 546'total(91'AROP)600 gpm/2280 psi.80 rpm/12.5k tq,10k wob,163k up,92k dn,113 k rot.MW 9.2,ECD 10.;Last svy @ 4626'MD,47.43°Inc,183.82°Az=28'high,7'right of well plan 11.;Hauled 1385 bbls cuttings to G&I for total=2480 bbls Hauled 1040 bbls H2O from 6 mi lake for total=2730 bbls 1/26/2018 Drill 12 1/4"Hole F/4856'-T/4919'.Work pipe and circulate sweep OOH.;Drill 12 1/4"Hole F/4919'-T/5359'. 440'total(98'AROP)600 gpm/2205 psi.80 rpm/16k tq,12k wob,182k up,92k dn,116 k rot.MW 9.1,ECD 9.9 Start lower visc to 80-100 range @ 4900'.;Drilled 188'Pump tangent from 4817'to 5005'. Survey at 5005 showed a 1.8°DLS from drop in rotary.;Survey @ 5320'showed 8.3 DogLeg.Attempt to ream out DL. DL down to 7.50.;Drill 12 1/4"Hole F/5359'-T/5737'. 378'total(84'AROP)600 gpm/2245 psi.80 rpm/18k tq,4-12k wob,180k up,88k dn,114 k rot.MW 9.1+,ECD 9.9 Pump Hi Vis Sweep @ 5737'.;Circulate Sweep out of hole.No substantial change at shakers.;Drill 12 1/4"Hole F/5737'-T/5815'. 78'total(78'AROP)600 gpm/2245 psi.80 rpm /18k tq,4-12k wob,180k up,88k dn,114 k rot.MW 9.1+,ECD 9.9.;Drill 12 1/4"Hole F/5815'-T/5862'. 600 gpm/2360 psi. 80 rpm/17k tq,4-12k wob, 180k up,88k dn,114 k rot.MW 9.1+,ECD 9.9.;Saw 8.64°DL @ 5823'MD. Wash and ream to reduce DL. Re-shot svy showing 6.34°DL. Continue drilling ahead.;Drill 12 1/4"Hole F/5862'-T/5925'. 63'total(78'AROP)600 gpm/2315 psi.80 rpm/16k tq,12k wob,Flow 62%.MW 9.2,ECD 9.9 45 bgg.;Change out swab and liner on#3 pod,mud pump#2. Continue circulating with MP#1 while working on MP#2. 360 gpm,1000 psi,80 rpm,15.5k tq.;Drill 12 t4"Hole F/5925'-T/6125'.200'total(80'AROP)600 gpm/2365 psi.80 rpm/16k tq,12k wob,Flow 62%.MW 9.2,ECD 10 50 bgg.;Drill 12 1/4"Hole F/6125'-T/ 6359'(TD)as per Geo.234'total(94'AROP)600 gpm/2378 psi.80 rpm/16k tq,12k wob,Flow 62%.MW 9.2,ECD 10.16 60 bgg.;Onsite geo called TD 5'TVD below top of OA sand. OA @ 6302'MD/4118'TVD. Landed @ 85.6°Inc,146.2°Az.;Circulate and condition hole @ TD(6359'MD). 600 gpm 2100 psi,62%flow,80 rpm, 16.3k tq. Initial ECDs 10.1, Final ECD's 9.8. MW @ 9.3 PPG @ TD w/BGG averaging 33 units.;Reduced vis to 63 with a YP of 23. Screened up to 170's/140's.Projected OA top came in 7'low.Pumped tandem sweep @ TD,1000 stks late w/no increase.;Projected to bit @ 6359'MD/ 4123'TVD,85.57°Inc, 146.17°Az= 5' into OA sand, 16'right of well plan 11.;Hauled 1057 bbls cuttings to G&I for total=3537 bbls Hauled 1240 bbls H2O from 6 mi lake for total=3970 bbls 1/27/2018 Continue Circulate and condition hole @ 600 gpm,2100 psi,80 rpm,16.3k tq. Final ECD's 9.8.MW @ 9.3 PPG,Vis 63,Yp 23. Blow Dn TD.PU wt 183. Dn Wt 88K(no Pump).;Run Back To Bottom 2 stands.Monitor Well-Static.Leave Btm w/600 gpm/2105 psi,80 RPM/19-20K Tq, Rt Wt 113. BROOH '/6359' to 3595'w/no issues. Hole showing signs of unloading @ 3595'.;Pump Clean up cycle w/600 gpm/1795 psi,80 rpm/15K Tq,Rt Wt 100K. CBU x2 adjusting rate as shakers dictate.;BROOH from 3595'to 1965'.Slow pulling speed @ 2500' through Permafrost to 15 fpm.Hole starting to unload.;Pump Clean up cycle @ 1965'w/600 gpm/1795 psi.Hole unloaded for entire bottoms up.Mostly Clays.;BROOH to 1085'w/same parameters.Hole unloading again.;Pump Clean up cycle @ 1085'w/600 gpm/1625 psi.Hole cleaned up shortly after bottoms up.Mostly clays.Did see some gravels.;Pump OOH from 1085'to HWDP.POOH On elevators f/640'.;POOH F/640'-T/surface. UD 8"XO,DC's. Download MWD. B/O and UD MWD tools. Drain and flush mud mtr. B/O and UD Altr and bit. Bit graded-1,1,CT,C,E,I,NO,TD. Pics in"0"drive.;Clean and clear rig floor. UD surface tools.;Service Rig,Grease TDS,Blocks,Crown,Wash pipe. Check oil(good).;R/U WOT casing equipment. Install bail extensions w/250T side doors. M/U CRT. Inspect slips,dog collar. R/U 1450 Weatherford power tongs.;PJSM, Run DWC/C 9-5/8",40#,L-80 casing as per detail. M/U shoe track w/Bakerlok. Check floats(good). Circulate thru shoe track(good).Run Fl surface to 1217'MD.;Fill every 5 jts. Started pushing away fluid around 900'MD. Stage pumps up to 6 bpm. Saw partial losses but established full circulation after 10 bbl loss. Cont running casing.;Hauled 1005 bbls cuttings to G&I for total=4542 bbls Hauled 910 bbls H2O from 6 mi lake for total=4880 bbls 1/28/2018 Run DWC/C 9-5/8",40#,L-80 casing(/1217'to 3034'. Fill pipe every 5 jts and break circulation back to pits every 15 jts.;Circulate and Condition mud from 3034'.Stage pump to 8 bpm/120 psi.Up Wt 138K, Dn Wt 86K, Rt Wt 105K w/5rpm/13K Tq. CBU x 4 until 9.4 in/out.Initial MW out was 9.7+.;Continue to run casing from 3034'to 5033'with no hole issues.;Grease wash pipe/begin cleaning pump suction chambers.Trouble shoot Latch issues with Power Tong Backup Jaws.;Run DWC/C 9-5/8",40#,L-80 casing(/5033'to 6315'.Fill pipe every 5 jts.Wash last Jt to bottom.@ 5bpm.Pu Wt 320K,Dn Wt K 11OK.;Circulate and condition mud staging pump up to 7 bpm/180 psi. PU Wt 270K,Dn Wt 110K. Wash dn to 6354'MD. Reciprocate pipe w/full returns. N R/D WOT power tongs,bail extension,elevators.;R/U cmt line and swap over same. Continue circulating via cmt hose @ 7 bpm,445 psi 1.5x casing volume. Final MW In/Out 9.3 w/a 19 YP.;PJSM,1 stg surface cmt:Clear cmt line to cmt units. Flood lines w/5 bbls water. P/T lines 1000/4000 psi(good).6Q bbls ,A 10.5#Tuned Spacer III w/4#red dye first 10 bbls. Drop bypass plug.;Mix and pump 460 sxs(203 bbls)Extenda Cem Lead Cement at 11.7 ppg. Mix and b� pump 400 sxs(81.6 bbls)Hal CemTail Cement at 15.8 ppg.Drop Shut off Plug.;Displace cmt wl 20 bbls RN f/Cmt Unit.Rig Pump 219.8 bbls,9.3 ppg mud. g Cmt Unit 80 bbls FW @ 5.5 bpm,450 FCP. Rig 153.3 bbls 9.3 ppg mud,7 bpm/970 psi,FCP 760 psi @ 3 bpm last 25 bbls.;lst Stage Details: Total " Displacement 473.2 bbls CIP @ 01:20 hrs.Full Returns through out job.Pump Cement @ 5.5 BPM avg.;FCP 760 psi @ 3 BPM. Bump plug 500 psi over FCP to 1260 psi.Floats held.bled back 1.3 bbls.;Using rig pump,stage pressure up 2053 psi to open ES Cementer. CBU through Stage tool staging up to 7 0bpm/500 psi,bringing all spacer and 56 bbls green CMT to surface.;Shut down pumping, Disconnect knife valve. Flush stack and work annular with"B ack Water". Circulate"Black Water"through flow line jets and all surface lines.;Continue to circulate through stage tool @ 3 bpm/100 psi while prepping for 2nd stage Cement.;Hauled 202 bbls cuttings to G&I for total=4744 bbls Hauled 520 bbls H2O from 6 mi lake for total=5400 bbls 1/29/2018 Continue to circulate through stage tool @ 3 bpm/100 psi while prepping for 2nd stage Cement.;PJSM,Pump 2nd stage cmt iob.Lineup to cmtrs,wet lines w/5 bbls RN.60 bbls 10.5#Tuned Spacer III w/4#red dye first 10 bbls,5 BPM,415 psi.;320 bbls 10.7#lead Perm"L"cmt,4.33 yld,416 sxs,6 BPM,680 cVpsi.56 bbls 15.8#tail Premium"G"cmt, 1.169 yld,270 sxs,4 BPM,428 psi.Drop closing plug. HES pump 20 bbls RN,7 bpm,725 psi.;Turnover to rig (MP#1/.062 pump output)Disp&bump @ 172.2 bbls/2778 stks(172.2 bbls calc)9.3#mud 6 BPM,738 psi. Slowed last 10 bbls,3 bpm,575 .(? FCP.;Bumped and psi up to 1550 psi(ES shift @ 1480 psi)Held 5 min. Bled back 1 bbls,flow stopped.CIP @ 12:50 hrs.100%returns.;See Cmt @ surface 7''`) 300 bbls into Lead. Pumped 320 bbls Lead before going into tail. Cmt Left in Hole=164 bbls.(376 bbls slurry)-(20bbls excess Lead)-(192 bbls Displacement).;Cmt overboarded @ surface=-268 bbls.20 bbls(excess Lead)+56 bbls(Pump tail)+192 bbls(Pump Displacement).;Flush cmt lines and stack w/black water.Blowdown cmt service line to unit. R/D Weatherford casing CRT.R/D cmt lines and clear same. B/O and laydown CRT to cradle R/U side door 9-518"elevators.;Blow down TDS. UD remaining Weatherford handling equipment and release Casing Crew. Fill and drain Stack w/Black waver.R/D conductor valves. Pull Mouse hole.;R/D outer sub diverter sections. Break lower diverter T flange.Lift Stack& Ctr casing in wellhead. Set slips w/130k as per wellhead rep. Rough cut csg. Cut off jt=28.67'.;Set stack back down&hot bolt same.MU Flushing stinger&Flush BOPS with black water. UD same.;N/D diverter system. Remove riser,drain stack,remove knife valve. Raise stack and stage. N/D"T"and rack back along with BOP's. Cleanout cellar. Remove 4" conductor valves and install caps.;N/D starting head and DSA. Clean and prep cellar.;Make final cut on 9-5/8"stump. Dress same. Install wellhead transition nipple. Pre heat and weld out same as per procedure. Sym Ops on rig-C/O bearings on drag chain. Load drill pipe in shed.;Wait on wellhead to cool. Start temp @ 00:30 I 600°F. Cont working on drag chain. Onload 290 bbls Baradril"N"in pits. Cont load drill pipe. Cont cleaning pits.Wellhead 275°@ 5:30.;Hauled 1793 bbls cuttings to G&I for total=6537 bbls Hauled 1300 bbls from 6 mi lake for total=6700 bbls • • ex s 1/30/2018 Wait on wellhead to cool below 100 deg.275 @ 0600. Test welds to 1400 psi with N2.Good. Work on rig projects while waiting on wellhead to cool. Replace drag chain sprockets.;N/U wellhead.Set multi bowl,Set DSA, Set stack,Test metal seal to 1000 psi.10 Min Good. R/U choke and kill hoses,Accumulator lines and energize accumulator.Install bell nipple,Secure stack,;install mouse hole.;Service rig.;R/U to test bops and build test joint. Fill stack. Test gas alarms.;Test bops as per AOGCC to 250/3000 psi, Test witness waived by Adam Earl with AOGCC @ 1-29-2018 @ 5:14 PM.;Cont test BOP equip. 250/3000 psi w/5 min hold on each. Chart and record same. Test w/5"test jt. Test Annular,Pipe rams,Blinds,IBOP's,(2ea)TIW, Dart,NCR's and choke manifold.;Super choke failed. Rebuild super choke and retest. Finished testing super choke @ 03:00 hrs(1-31-18).R/D test equipment.;Attempt to set long wear bushing. Wear bushing landing out 1'+/-high. Troubleshoot and re-attempt several times(no go). Wellhead rep onsite. Troubleshoot and re-attempt (no go).;Determined long wear busing was"oval"and out of spec. Install short wear(9"ID)bushing without issue. Will plan to C/O with replacement long wear bushing after drillout.;Koomey drawdown test-Start psi 3050,drawdown psi 1500,200 psi inc @ 21 sec,full charge @ 82 sec,6 bottle N2 avg-2283 psi.;Thaw and re-install Kelly hose to top drive.;PJSM,M/U 8.5"milltooth w/1.22°bend motor, 16 jts HWDP,Jars,1 jt HWDP. Single in w/NC50 F/584'-T/ 897 MD.;Troubleshoot hydraulic leak on top drive.;Hauled 252 bbls cuttings to G&I for total=6789 bbls Hauled 130 bbls H2O from 6 mi lake for total=6830 bbls 1/31/2018 Service TD,Trouble shoot&fix TD hyd leak. Had loose JIC fittings.;P/U 5"DP F/897'T/2437'.;Wash down&tag es cmt tool on depth @ 2533'. Drill ES cmt tool F/2533'T/2537'. @ 3-5 K WOB.Work through clean. BDTD.;Continue to P/U 5"DP F/2562'T/4191'&jockey pipe in derrick standing back 10 s ands DS-50.;Service rig. Grease floor equipment.;Continue to P/U&stand pipe back as needed to get to 6175.Kelley up circ btm up @ 400 gpm.;Blow down TD. R/U Circ hose and head pin.Test casing T/3000 psi.30 min against pipe rams.good.Had to trouble shoot slight bleed off.Bump up and held solid.;took 91 stks to pressure up to 3100 psi. Bled back 4.1 bbl.;Attempted to bleed off with super choke and it would not operate. Bleed off with Manual bleeder and troubleshoot super choke.;Troubleshoot super choke. Found actuator tq limit switch out of adjustment due to coming loose. Re-adjusted tq limit and secured in place as designed. Function and re-test(good).;Cut and slip 81'drilling line. Service crown and handling equipment.;PJSM,Wash down and tag cement @ 6211'MD. Drill cement F/6211'-T/Baffle 0 6224'(On depth). 30 rpm,17.8k tq,400 gpm,730 psi,5-8k wob. Drill and trip thru baffle without issue.;Continue drilling shoe track F/6224'-T/6359'MD. Drilled float collar and float shoe on depth as per tally. 415 gpm,750 psi,30 rpm, 17.8k tq,5.8k wob.;Drill 8.5"hole F/6359'-T/6379'(20'new formation using single). Displace spud mud on the fly with 8.9 ppg Baradril"N". 40 rpm, 15.4k tq,43C gpm, 770 psi,48%flow,15k wob.;8.9 mud In/Out. L/D single and B/D TDS. R/U test equipment. Perform FIT to(EMW 12+ppg). Psi uo to 695 using upper pipe rams.;1.4 bbls pumped. 45 psi drop over 10 min. Bled back 1 bbl.;SPR's,Monitor well(Static). Pump dry job and POOH F/6365'-T/5528'MD.;Hauled 171 bblu cuttings0to H2Ofor total= a1 bbls (,V.-C' �ZPP Hauled 100 bbls H2from 6 mi lake for total=6930 bbls 2/1/2018 POOH with Clean out BHA F/5672'T/584'.Stand back HWDP&Jars,L/D BHA& Grade bit 1-1-WT-A-E-1-No-BHA.;Clean&clear rig floor.Pull short Wear bushing and install new long wear bushing with 10"ID.;PJSM,M/U 8.5 7600 EDL Geo Pilot with NOV DK 616M-J1 D,DM,ILS,ADR,DGR,PWD,HOC, NMFS,2 NMFC,2 Jts HWDP,Jars, 1 Jt HWDP. Uploaded tools and Pulse tested good.;RIH F/271'T/2155'.Shallow test and break in Geopilot Seals.450 GPM,570 PSi.Good.Blow down top drive.;RIH F/2155'T/6300.Kelly up and wash down @ 60 RPM 450 GPM, 1050 PSi. F/6300'T/6379'.;Drill 8.5" production F/6379'-T/7120'MD. (741'total)=124'AROP 450 gpm, 1120 psi,55%flow,120 rpm,17k tq,4k wob 120 bgg.;Drill 8.5"production F/7120'-17 7749'MD. (629'total)=105'AROP 400 gpm,995 psi,53%flow,120 rpm,19k tq,4k wob 140 bgg.;Reduced flow rate and max ROP due to fine silt and oil blinding off shakers. Able to drill ahead without issue @ 400 gpm,+/-200 fph max rop. Drill and pump faster as shakers allow.;Pumped tandem sweep @ 7620'MD,back on time with minimal increase in cuttings.;Last svy @ 7464'MD,91.52°Inc,146.07°Az=18'low,7.7'Left of directional well plan 11.;1-auled 910 bbls cuttings to G&I for total=7871 bbls Hauled 390 bbls H2O from 6 mi lake for total=7320 bbls 0 bbls lost to formation 0 lbs metal total 2/2/2018 Drilling ahead 8.5 Hole F/7749'T/8475'726',@ 121 FPH average.80 RPM,18.6k TQ, WOB 5-20 380 GPM,1020 PSi ECD 10.3 MW 9.0 Pump Sweep @ 8220'.Back on time with 200%Increase.;Drilling ahead 8.5 Hole F/8475'T/8850'375'@ 125 FPH average. 80 RPM,18.6k TQ, WOB 5-20 380 GPM,1020 PSi MW 9.0 ECD 10.3.;Having trouble with housing role. Lower GPM to 380&Increase ROP up to 280 to get build. Drilled through fault @ 8570'. Dri led from OA1 to OA#3. 100%in Zone.Backreaming full stands.;Drilling ahead 8.5 Hole F/8850'T/9069'219'@ 73 FPH average FPH. 80 RPM,18.6k TQ, WOB 5-20 380 GPM,1020 PSi MW 9.0 ECD 10.3.;Drilling ahead 8.5 Hole F/9069'T/9600'MD. 531'@ 89 fph AROP. 75 RPM,21k TQ, WOB 5-20 400 GPM,1100 PSi MW 9.0 ECD 10.3.;Drilling ahead 8.5 Hole F/9600'-T/9990'MD. 390'@ 65 fph AROP. 95 RPM,21.5k TQ, WOB 12 410 GPM,1160 PSi MW 9.0 ECD 10.3.;Lost down wt @ 9006'MD. Last svy @ 9791'MD,92.8°Inc,146.5°Az=2'low,27'left of directional well plan 11.26 concretions for 139'length(3.9%of lateral)have been drilled.;Continue backreaming full stands between connections. Pump tandem sweep @ 9100',on time w/50% nc. Pumped tandem sweep @ 9615',on time w/100%inc;Hauled 1026 bbls cutting to G&I for total=8897 bbls Hauled 1040 bbls fro 6 mi lake for total=8360 bbls Daily metal 8lbs for total=8lbs 2/3/2018 Drilling ahead 8.5 Hole F/ 9990'T/10703'MD.713'@ 118 av fph.80-110 RPM,23-25k TQ, WOB 6-15 380-410 GPM, 1250 PSi MW 9.0 ECD 10.7 Sweep @ 10136'back on time with 50%Increase.;Circ and condition while pumping a sweep out due to ECDs @ 11 LB. 415 GPM 110 RPM,Reduce ECDs to 11.6.Sweep brought back Minimal increase.;Drilling ahead 8.5 Hole F/ 10703'T/11145'MD.442'@ 98 av fph. 80-110 RPM,23-26k TQ, WOB 6-15 380-410 GPM, 1250 PSi MW 9.0 ECD 10.5 Sweep @ 10136'back on time with 50%Increase.;Drilling ahead 8.5 Hole F/11,145'-T/11,645'MD.500 @ 84 fph AROP. 120 RPM,24.5k TQ, WOB 13 405 GPM, 1250 PSi MW 9.1 ECD 10.9 Sweep @ 11,143'back 30 bbls early with 100%Increase.;Drilling ahead 8.5 Hole F/11,645'-T/12,186'MD.541'@ 90 fph AROP. 120 RPM,25.8k TQ, WOB 13 420 GPM,1280 PSi MW 9.1 ECD 10.9 Sweep @ 11778'back 37 bbls early with 100%Increase.;Last svy @ 11930'MD,91°Inc,149°Az=24.7'low,25.3'left of directional well plan 11.48 concretions for 275'length (4.8%of lateral)have been drilled.;Hauled 684 bbls cuttings to G&I for total=9582 bbls Hauled 1040 bbls H2O from 6 mi lake for total=9400 bbls 6 lbs metal for total=14 lbs 2/4/2018 Drilling F/12186'T/12980'TD. 794' @ 93 FPH Average.400 GPM,95 RPM, 1103 PSI. WOB 7-10K, 25K TQ.10.8 ECDs.;Started adding lubes @ 12300'. Bring lubes up to 4%with 1%ez glide and 3%Baro Lube Gold Seal. UP WT went from 325 to 174.TQ went from 28 to 17K. We were also able to get down wt.;Shut in L-48 Injector due to TD extension and closer approach. Shut in @ 10:41 and back on line @ 15:30.;Monitor well at TD before bringing L- 48 back online.Very slight flow. Pump tandem sweep staging up pumps to 450 GPM,130 RPM 1365 PSI,17K TQ.Sweep came back with minimal increase &100 bbl late.;Pump another tandem High/Low sweep while screening up to 200s. Stage pumps up from 260 to 390 GPM.;Continue circulating and conditioning mud. 390 max gpm w/200's,1050 psi,46%flow, 120 rpm,17k tq,52 BGG.Tandem sweep 93 bbls late w/minimal increase.;Perform PST on drilling fluid-Post shakers(Pass),Pre shakers(Failed)after 5 btms up. Final up/dn/rot wt-171k up,49k dn,110k rot w/17k tq(pumps on).;L/D working single. B/D TDS. Service crown and TDS.;Monitor well(slight flow). Work pipe and continue to monitor(static after 30 min).;BROOH F/12980'-T/12277' MD. 750 fph max pulling speed. Slow down and allow shakers to cleanup as needed. 375 gpm,990 psi,100 rpm, 18.7k tq.;Continue BROOH F/12277'-T/ 10264'MD. Screened dn on shaker#1 (3x170's,1x140)to minimize mud lost over shakers. 375 gpm,790 psi,100 rpm,13.7k tq. No issues.;Projecte to TD @ 12980'MD,91.3°Inc,145.9°Az=In 0A3 and 22.6'left of extended TD off directional well plan 11.Mostly fine sand/silt across shakers. BGG avg 1 -20 units while BROOH.;53 concretions were drilled in the lateral for a total length of 312'(4.7%of the lateral).;Hauled 741 bbls cuttings to G&I for total=10 323 bbls Hauled 520 bbls H2O from 6 mi lake for total=9920 bbls Daily metal 4lbs for total=18lbs • Hilcorp Energy Company Composite Report Well Name: MP F-107 Field: Milne Point County/State: Prudhoe Bay,Alaska (LAT/LONG): avation(RKB): 26.5 API#: 50-029-23592-00-00 Spud Date: 1/23/2018 Job Name: 1714019C MPF-107 Completion Contractor AFE#: AFE$: 2/5/2018 Backream out F/10264'T/8063'. 100 RPM,375 GPM.Pull at 5 min per stand and pull slow through 8 deg dog leg @ 8465'.,Backream out F/8063'TI 6350'. 100 RPM,375 GPM.Pull at 5 min per stand.Over Pull 5K @ 7150'6449'. Work back through after back reaming.Clean.,Circ&Condition at shoe @ 380 GPM, 100 RPM, MW 9.0,ECD 9.6. Pump High vis sweep.Minimal increase in cuttings. Just getting back fines.Cleaned up good. Monitor well 10 min. Slight breathing and went Static within 10 min.,Monitor well(static). Pump dry job. B/D TDS and drop 2.375"drift on wire. Final wts 141k up,101k do (pumps off).TOOH racking back F/6360'-TI 5422'MD.,TOOH laying down drill pipe Fl 5422'-T/BHA(270'). Hole took proper displacement.,UD HWDP and Jars. Found small retainer on mandrel was missing on jars and bumpers. UD Flex DC's. Download MWD. BIO and UD MWD,Bit and Geo-Pilot Bit Graded=3,2,CT,A,X,I,DL,TD. Build 5"safety joint while downloading MWD.,Clean and clear rig floor. R/U to run 4.5"Iiner..R/U Weatherford Casing Equipment. C/O elevators, R/U power tongs and bring handling equipment to rig floor.,Hauled 228 bbls cuttings to G&I for total=10551 bbls Hauled 130 bbls from 6 mi lake for a total=10050 bbls 0 losses to formation in lateral. 2/6/2018 R/U Weatherford 4.5 handling equipment. Function test same. Prep floor and shed,count pipe. 160 joints Pre drilled liner and 16 Joints solid13.5# F ydril 625. PJSM,P/U shoe track WIV assembly and RIH with liner T/6787'. Install one stop collar and one 7"OD blade centralizer from rig floor on each joint ran. Stop ring and cent floating.165 Total plus two locked down on shoe track.,Had to UD Joint#46.Egged Box.Ran one extra Blank for the liner lap to make up the difference. Ran total of 159 Pre drilled liner and 6 joints of blank pipe as per tally. Set liner in an up wt.UP/DN 86/70K M/U to 9600 TQ„UD 4.5 handling equipment. R/U 2 3/8 false bowl and handling equipment.Install thread protector in box of liner. M/U 5"safety joint for the 2 3/8. Count 2 3/8,216 Joints in the shed.,P/U Baker slick stick&RIH with 2 3/8 PH-6 5.95# inner string T/668'. Drift on skate to 1.79".,Continue to drift,P/U and RIH w/2 3/8"inner string A, g f/668'to 6746' 216 jts,M/U jt 217,nogo out on drillable packoff 22.8'in @ 6768.40'.,UD jt 217,Space out as per BOT rep. Drift and M/U 10.13'pup,Swap to L 5"handling equip. Inner string PU/SO 70k/51 k.,M/U XO and swivel putting nogo 6.82'off packoff. M/U LT packer hanger assy as per baker. Let slips ride. I'lInspect packer in the table.verify hanger pinned @ 2355 psi shear w/6 screws,pusher tool pinned @ 2979 psi shear w/9 screws.PU/SO 122k/89k.,RIH with 1 std 5"DP f/6833'to 6893',M/U top drive,break circulation,pump 2 bpm 680 psi,pump 1 liner volume to ensure clear flow path.Set top drive drilling torque @ 10k.Troubleshoot hydraulic leak on top drive,tighten fittings.Blow down top drive.Load 27-6 1/8"drill collars into pipe shed.,RIH with lower completion conveyed on 5"DP @ 50 fpm f/6893'to 9020',start drifting stds in derrick at std#16, easy in and out of slips,fill pipe on the fly.Correct displacement TIH.,Hauled 0 bbls cuttings to G&I for total=10551 bbls Hauled 0 bbls from 6 mi lake for a total=10050 bbls 0 losses to formation in lateral. 2/7/2018 Continue to RIH on 5"DP From the derrick F/9034'T/9286'. UP/DN 137/85. M/U safety joint for collars and P/U 27-6 1/8 DC T/10150'.,RIH 1 stand of 5" DP from the derrick and circ DP inner string volume. UP/DN 177/120K. RIH with 5"DP from derrick dropping drift from the derrick. RIH to stand 60 @ 11450'. P/U HWDP Fl 11450'T/12920'. M/U Stand 61 &wash down @ 1 bpm Tag TD on depth. UP/DN 233/123K.,Stage up pump to 3 BPM @ 1670 PSI. Reciprocate pipe 50'. PJSM, Pump 50 bbl Spacer&Displace out 9.0 mud to 9.2 ppg 3%KCL. Dumping all returns until brine returns.3 BPM 1700 psi max. At btm up started getting gas in mud returns.Over 800 Units.,Shut in to closed loop system&pump 3 tandem 50 bbl sap pills with 50 bbl brine in between chase with brine and circ out to surface. Gas units steady at 600+units while circ out sap pills.Steady units dropping from 600-300+. Monitor gains and losses.No gains. Line up to clean brine and pump 500 bbl(1.5 OH volumes)dumping returns while monitoring gas. Note:seen 806u max gas displacing to brine.,Drop ball and pump down @ 3 bpm 1700 psi.Still getting 300+units.,Hauled 1085 bbls cuttings to G&I for total=10636 bbls Hauled 0 bbls from 6 mi lake for a total=10050 bbls 3 bbl daily losses to formation for a total of 3 bbls 2/8/2018 Pump down ball as per baker at 3 bpm.Ball on seat at 86.75 bbl.Pressure up to 2800&close WIV&set LT hanger.Set down 50K.P/U to up wt. Line up to test pump.Continue to pressure up to 3100 psi&saw pusher tool start to shift. Continue to pressure up to 4100&tool released.Seen indication at surface.,Hold for 5 min.Bleed down and P/U to verify running tool released. Break off and blow down TD.Test back side to 1500 for 10 min.Good. P/U and pull slick stick out of pack off.Monitor well. Static. Circ 1.5 btm up with max gas @ 728 units.Dropped to 30-50. Monitor well.Slight breathing. Then slight seeping.TOL @ 6152'w/shoe @ 12975'.,UD 5" HWDP F/12975'T/ 11414'. UD 5"DP F/11414'T/10125'. M/U safety joint for drill collars. UD 27-6 1/8 DC F/10125'T/9261'.,UD 5"DP F/9261' T/8821'.Stand back 5"Stands T/6761'. 13 BBL over calculated hole fill.,Monitor well,static loss rate @ 4 bph,R/U Weatherford power tongs.PJSM,Inspect and L/D running tool as per BOT rep.R/U 2 3/8"handling equipment.,POOH UD 216 jts 2 3/8"inner string f/6761'to surface,UD slick stick.Loss rate 2.5 bph on TOOH, 16 bbls over calculated hole fill.,Monitor well,static loss rate 1.5 bph.CIO handling equipment to 5", clear and clean rig floor. Unload pipe shed. Load hawk jaw to rig floor and R/U same.,M/U 3 1/2 EUE stinger and XO,RIH w/stds 5"DP from derrick to 2000'.1.5 bph loss rate TIH.,Hauled 1684 bbls cuttings to G&I for total=13320 bbls Hauled 230 bbls from 6 mi lake for a total=10280 bbls 41 bbl daily losses to formation for a total of 44 bbls • • 2/9/2018 RIH F/2576'T/6099'.,PJSM,Circ sweep around&clean out liner top©6152'. Circ clean.Got solids at btm up and cleaned up.,Slip&cut drilling line Service rig.,Work on TD leaks. Take.5 hrs down time.,Displace well to clean 9.2 3%KCL brine. Circ until clean dump all returns.,POOH L/D 5"DP F/6152' T/surface,L/D XO and 3 1/2"EUE stinger. Loss rate 1.5 bph,14 bbls over calculated displacement on TOOH.,Pull wear bushing.Drain stack.Change top rams to 7 5/8. R/U and test UPR to to 250/3000 psi on 7 5/8"Pipe size with no issues.R/D test equipment.Monitor well @ 5.5 bph loss rate.,R/U WO . Stage Landing Jt and hanger and prep for Drift Run. R/D Hawk Jaw and remove from floor,wellhead rep unable to M/U hanger onto landing jt,dress thr=ads and attempt to M/U,load out landing jt and hanger as per wellhead rep to have acme thread inspected at Baker machine.Ready XO on FOSV. 6 bph s'-tic loss rate.,PJSM,P/U and run 7 5/8"tie back per tally, P/U tie back seal assy,8.26"no-go locator,XO and pup,P/U and RIH w/7 5/8"Vam,STL,29.7'L-80 casing f/17'to 1225'.TQ turn 7 5/8"VAM ST-L 29.7#L-80 csg to optimum©5349 ft/lbs. se BOL 2000 pipe dope.,Hauled 849 bbls cuttings to G&I f.r total =14169 bbls Hauled 0 bbls from 6 mi lake for a total=10280 bbls b 43 bbl daily losses to formation for a total of 87 bbls ter/ 2/10/2018 Continue to run 7 5/8 Vam STL 29# Liner F/1270'T/6154'.Tag liner top 7'High from liner tally. Work through liner top with two 1/4 turns. Land out.n no go. UP/DN 176/109K Saw 5K drag on seals. 2 BPH Losses.,Space out as per baker and M/U 9.88&2.88 out pups under last joint#151. Land out .63 off of no go. Well head hand verify proper land out. R/U circ lines and pressure up to 100 psi down 7 5/8.P/U until pressure dumps and establish circ ou 1" ports. Line up to reverse circ and Pump 10 bbl to pits to verify proper line up.,Pump 80 bbl of 1%baracor 100 in 9.2#3%KCL chase to rig floor with 10 bbl. Shut down and Line up little red and pump 50 bbl down the annulus taking returns to the pits. Final pressure at annulus valve 240 @ 2 bpm.Land han.er and have little red suck diesel out of stack.Open annular. RID circ lines and back out landing joint. M/U pack off running tool and pack off&5"HWDP&r n same.L/D landing jt.,RILDS,test void to 500 psi for 5 min,5000 psi for 10 min.R/D weatherford tools.,With LRS,Pressure test 7 5/8"x 9 5/8 annulus ith diesel to 1000 psi for 30 charted min,good test,bleed off pressure,R/D LR.,Close blind ram,C/O UPR 7 5/8"casing ram to 2 7/8"x 5"VBR.Open blinram. j4.\, Monitor well,static loss rate 2.8 bph.Set ESP spooler in place.,lnstall test plug,test UPR,LPR and annular using 2 7/8"test jt to 250 low for 5 min and 3000 k. psi hi for 5 min charted. Tool jt to XO on top test jt leaking,re-torque same,NPT test pump fitting leaking,C/O same.Annular leaking on hi pressure te-t,open and inspect same,re-test annular to 250/3000 psi,good.,R/D test equipment.Drain stack,BD lines.Static loss rate 2 bph.,Rig up to run ESP completio .R/U WOT equip.Hang Sheave for ESP cable.Thread ESP cable thru sheave to rig floor.Load ESP tools and equipment to rig floor. R/U cap line spool on a DS rig floor,M/U FOSV to XO.,PJSM with all parties involved,discuss well control plan with motor and pump across BOP,ESP cable contingency plan for sh tting in well.M/U ESP pump assy as per centrilift.Static loss rate continues @ 2 bph.,Hauled 57 bbls cuttings to G&I for total=14226 bbls Hauled 0 bbls from 6 mi lake for a total=10280 bbls 34 bbl daily losses to formation for a total of 121 bbls 2/11/2018 M/U seals and service same.P/U GS,Pump,Pump, and hook up MLE and cap string lines and test same. Pump through cap string good. Check val es set at 1700 psi.,M/U discharge head to 10'pup with Weatherford and RIH with 2 7/8 installing clamps on each collar T/2458'. Test wire and cap lines @ 2000'. TQ 2 7/8 EUE to 2240 ft/lbs.,Continue to P/U and RIH w/2 7/8"ESP completion f/2458'to 4899'(152 jts)installing clamps on ea.collar.Meg test ca.le and PT cap lines @ 3700'.,M/U tbg hanger w/BPV installed,pup jt and landing jt.Meg test ESP cable and PT cap lines,cable failed meg test @ 58 mega o ms, previous test @ 3700'was 1.89 giga ohms.14.6 bbl over calculated displacement on TIH.,PJSM,UD hanger and landing jt.POOH f/4899'to 3740'rac ing tbg in derrick to jt 117 looking for damaged ESP cable.Meg test cable f/spool end-failed,Cut cable©spool,Meg test cable both ways,failed test on c:ble downhole. PU/SO 75/64k.,Continue POOH racking tbg in derrick f/3740'to 3650' finding damaged armor on ESP cable.Pull damaged spot to spooler cut and meg test cable,downhole failed.Continue POOH to 2275'.17.4 bbls over calculated displacement on trip out.,Hauled 114 bbls cuttings to G&I for t.tal= 14340 bbls Hauled 0 bbls from 6 mi lake for a total=10280 bbls 41 bbl daily losses to formation for a total of 163 bbls 2/12/2018 POOH standing back 2 7/8 stands looking for damaged cable from 2262'T/pump.Found damaged cable 8'below discharge head. Took pics and sent o town.L/D ESP assembly and cable.,Looks like cable twisted on pump.Missing 3"armor and worn 1/2 through the cable.BOP test notification submitte" @ 9:20 am.,Clean rig floor&pipe shed. P/U 2 7/8 cmt diffuser and RIH Tl 5000'. UP/DN 65/51 Had to P/U 9 joints of pipe.,Circ 40 bbl 10%Baralube gol. seal down @ 4 bpm and spot at+/_200'-1200'.POOH F/5000'T/4728'. L/D 9 joints of pipe. After Lube pill UP/DN 60/52.,POOH racking 2 7/8"EUE tbg in derrick f/4728'to surface,L/D wash tool.5.5 bbls over calculated displacement on TOOH.,R/D power tongs,clear rig floor.Drain stack.R/U BOP test equipment.Install test plug,flood stack with fresh water.Monitor well,loss rate 2.7 bph.,Test BOPE using 2 7/8"test jt,AOGCC rep Jim Regg waived :OP test witness©16:00 hrs.Test upper and lower VBR,Blind ram,mud cross valves,upper and lower IBOP,choke manifold valves,FOSV,dart valve to .50 psi low,3000 psi hi 5 min ea.charted.Unable to test annular due to element leaking. Perform choke bleed test and accumulator drawdown test,check N2 bottles.Continue to monitor well,2.8 bph loss rate.,Close I/A,pull test plug,drain ack. Close blind ram, Remove drip pan and riser,clean and inspect element,•severe wear on element.Open I/A and monitor well,3 bph loss rate.,Hauled 1.0 bbls cuttings to G&I for total=14460 bbls Hauled 130 bbls from 6 mi lake for a total=10510 bbls 65 bbl daily losses to formation for a total of 228 bbls 2/13/2018 PJSM on C/O Annular Element. Remove accumulator hose off Annular.N/D upper housing and hoist off annular. Remove damaged element.Clean, in pect and lubricate upper housing and adapter ring.Install new element.N/U upper housing. Run test joint and function test Annular.Install flow nipple and ris-r.Set Test plug. (Monitor Well via annulus valve @ 2.5 bph loss rate.),Welder and Electrician install new camera in pipe shed.,RU,Fill and test Annular to 2-0/3000 psi.Test good. R/D test equipment.Pull test plug.Test gas alarms and PVT System.,PJSM on running ESP Completion.Stage additional CC clamps o rig floor.Pull ESP and cap lines through sheaves to rig floor.Blow down choke and kill lines. Electrician C/O Sensor for TD frame Extend indicator. PU ES. Motor and Seals and service the same.,PJSM with all parties involved,discuss well control plan with motor and pump across BOP,ESP cable contingency pl-n for shutting in well.M/U ESP pump assy as per centrilift. M/U seals and service same.P/U GS,Pump, and hook up MLE and cap string lines and test sa e. Pump through cap string good. Check valves set at 1700 psi.,M/U discharge head to 10'pup with Weatherford,RIH with 2 7/8 stands tbg f/derrick,ins.all mid collar clamp on 1st 4 jts and clamp on each collar on every jt ran t/1827'. Test wire every 1000'and cap lines every 2000'. TQ 2 7/8 EUE to 2240 ft/lb Loss rate @ 2 bph.,Continue to RIH with 2 7/8 stands tbg f/derrick,install clamp on each collar on every jt ran f/1827'to 4080'. ESP cable failed meg test i5 4080'.7 bbls over calculated displacement on TIH.PU/SO 64/55.,PJSM, POOH f/4080'to 2700'racking tbg in derrick looking for damaged ESP cabl..Loss rate continues @ 2 bph.,Hauled 114 bbls cuttings to G&I for total=14574 bbls Hauled 130 bbls from 6 mi lake for a total=10640 bbls 55 bbl daily losses to formation for a total of 283 bbls • • uJ f Y V 2/14/2018 Continue POOH looking for ESP cable damage f/2617't/Surface standing back 2 7/8"Tubing in Derrick.Observed no visible damage to cable or MLE Lead. Recovered all clamps.Perform Meg Test at surface and obtain good test on Cable/Motor.UD Motor/Pump Assy in one piece as per centrilift Snake ESP Cable through sheaves to Spooler Unit.,Service Rig.Inspect TD/Saver Sub.CIO front Grabber dies for TD.Centrilift begin prepping to swap spools.,RIH with 1943'2 7/8"tubing(31 Stands)PU 44K,SO 44K.Centrilift begin swapping out ESP Spools.,POOH laying down 62 jts 2 7/8"tubing.Centrilift complete Spool change out.,Centrlift splice MLE to new spool.Stage new Motor and Seals in pipe shed.C/O Drag Chain Motor.Pump oil out of Gear Boxes on Mud Pumps and install temp switches for lube oil heaters.Re fill same,PJSM with all parties involved,discuss well control plan with motor and pump across BOP,ESP cable contingency plan for shutting in well.M/U ESP pump assy as per centrilift.,Flange between pumps bent.UD pump assy.Expedite new pump assy from centrilift to rig,load new pump into pipeshed.2.5 bph loss rate.,PJSM,M/U ESP pump assy as per centrilift. M/U seals and service same.P/U GS, Pump, and hook up MLE and cap string lines and test same. Pump through cap string good. Check valves set at 1700 psi.,M/U discharge head to 10'pup with Weatherford,RI H with 2 7/8 stands tbg f/derrick,install mid collar clamp on 1st 4 jts and clamp on each collar on every jt ran U 2700'. Note:replace jt 136 due to damaged threads,replace collar on jt 135.Test wire every 1000'and cap lines every 2000'. TQ 2 7/8 EUE to 2240 ft/lbs. Loss rate @ 2.5 bph.,Hauled 0 bbls cuttings to G&I for total=14574 bbls Hauled 130 bbls from 6 mi lake for a total=10770 bbls 61 bbl daily losses to formation for a total of 344 bbls 2/15/2018 RIH f/2700'to 2958'with 2 7/8 stands tbg f/derrick,install clamps on each collar on every jt. Test wire every 1000'and cap lines every 2000'. TQ 2 7/8 EU E to 2240 ft/lbs. Loss rate @ 2.5 bph.,MU Tubing Hgr and landing joint.Centrilift splice ESP.Terminate control lines.Make test on cables.Test good.Lard Hanger,RILDS,UD Landing Joint, install BPV.Bottom of pump @ 2985'.Up Wt 56K w/Blocks,Dn Wt 51K w/Blocks. Start Rigging Down and remov ng running equipment from Rig.,N/D BOPE:Pull Bell Nipple,R/D Choke and Kill Hoses and flange together.R/U Bridge Cranes.Bleed Koomey,R/D Koorrey Hoses.Pump hot flush thru kelly hose and blow down same.Hoist stack up and set back same.Flush and R/D choke/kill lines.,Centrilift test cable before installing tree. Remove DSA.Orient and install tree.Torque flange bolts.Terminate capillary lines.Test hanger void as per wellhead rep to 500 psi low for 5 min,5000 psi high for 10 min,good.Pull BPV,Install TWC.PT tree to 500/5000 psi.Test Good.Pull TWC.Centrilift make final test on ESP.Test good.,RU LRS,Spot and RU flow back tank to tubing side. Reverse Circ 96 bbls DSL down IA.Shut in IA.Set BPV.Put IA and Tubing in communication and U-tube FP to 2200',Vac out and R/D flowback tank.,Drain liner wash on both mud pumps, disassemble mud pump fluid ends to ensure dry for rig move.vac out cellar box,vac out sumps,cleanup cellar area. C/O saver sub and gripper dies.R/D tongs.Bridal up.Finish cleaning pits.Disconnect pit interconnects.Load DP in shed and Prep pipe shed for move.,Blow down water lines.PJSM,Scope derrick down.Roll up derrick wt bucket line. Flip up roof hatches between modules. Freeze protect laundry room.Cleanout and freeze protect Vac unit.R/D Pit interconnects.Fire up cold start generators."Empty test pup tank.Blow down steam lines. Remove cuttings box.Secure cellar for rig move.Secure pipe shed.Warm and function hydraulics.Peak trucks on location @ 03:00.,Move break trailer and envirovac,Jack up modules,install jeep to motor mod,separate modules and stage out of the way. Release rig @ 06:00,Hauled 252 bbls cuttings to G&I for total=14826 bbls Hauled 130 bbls from 6 mi lake for a total=10900 bbls 15 bbl daily losses to formation for a total of 359 bbls • • Hilcorp Alaska, LLC Milne Point M Pt F Pad MPU F-107(OA Producer) 50-029-23592-00-00 Sperry Drilling Definitive Survey Report 07 February, 2018 HALLIBURTON Sperry Drilling • • Halliburton Definitive Survey Report r Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-107 4 Project: Milne Point TVD Reference: MPU F-107 Actual @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-107 Actual @ 37.65usft Well: MPU F-107 "" North Reference: True Wellbore: MPU F-107(0A Producer) _;Survey Calculation Method: Minimum Curvature Design: MPU F-107 Database: Sperry EDM-NORTH US+CANADA 2 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 Using geodetic scale factor Well MPU F-107 ... Well Position +N/-S 0.00 usft Northing: 6,034,937.43 usft Latitude: 70°30'22.949 N +E/-W 0.00 usft Fasting: 541,322.13 usft Longitude: 149°39'42.969 W Position Uncertainty 0.00 usft Wellhead Elevation: 10.80 usft Ground Level: 10.80 usft I Wellbore MPU F-107(0A Producer) Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (1 (nT) BGGM2017 1/21/2018 17.33 81.03 57,488 I Design MPU F-107 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.85 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.85 0.00 0.00 163.35 i Survey Program Date 2/5/2018 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 50.00 169.00 SRG-SS Surveys(MPU F-107(0A Produ 2_Gyro-SR-GSS H047Ga:Surface readout gyro single shot 01/19/2018 233.45 6,318.45 MWD+IFR2+MS+sag(MPU F-107(0A P 2_MWD+IFR2+MS+Sag A013Mb:IIFR dec&multi-station analysis+sag 01/24/2018 6,394.58 12,948.90 MWD+IFR2+MS+sag(2)(MPU F-107(0A 2_MWD+IFR2+MS+Sag A013Mb:IIFR dec&multi-station analysis+sag 02/02/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.85 0.00 0.00 26.85 -10.80 0.00 0.00 6,034,937.43 541,322.13 0.00 0.00 UNDEFINED 50.00 0.24 120.39 50.00 12.35 -0.02 0.04 6,034,937.41 541,322.17 1.04 0.04 2_Gyro-SR-GSS(1) 100.00 0.32 155.19 100.00 62.35 -0.20 0.19 6,034,937.23 541,322.32 0.37 0.25 2_Gyro-SR-GSS(1) 169.00 0.49 140.69 169.00 131.35 -0.61 0.46 6,034,936.83 541,322.59 0.29 0.71 2_Gyro-SR-GSS(1) 233.45 0.53 161.84 233.45 195.80 -1.10 0.73 6,034,936.33 541,322.86 0.30 1.27 2_MWD+IFR2+MS+Sag(2) 296.36 0.83 303.83 296.35 258.70 -1.13 0.44 6,034,936.31 541,322.57 2.05 1.21 2_MWD+IFR2+MS+Sag(2) 357.19 2.29 309.70 357.16 319.51 -0.11 -0.86 6,034,937.32 541,321.27 2.41 -0.15 2_MWD+IFR2+MS+Sag(2) 419.01 4.19 308.28 418.88 381.23 2.08 -3.59 6,034,939.49 541,318.53 3.08 -3.02 2_MWD+IFR2+MS+Sag(2) 483.75 5.61 304.01 483.38 445.73 5.32 -8.07 6,034,942.70 541,314.04 2.26 -7.41 2_MWD+IFR2+MS+Sag(2) 546.09 7.45 303.81 545.31 507.66 9.27 -13.95 6,034,946.62 541,308.13 2.95 -12.88 2_MWD+IFR2+MS+Sag(2) 607.28 10.05 305.92 605.79 568.14 14.61 -21.57 6,034,951.92 541,300.48 4.28 -20.18 2_MWD+IFR2+MS+Sag(2) 665.41 13.44 305.79 662.69 625.04 21.54 -31.16 6,034,958.80 541,290.85 5.83 -29.57 2_MWD+IFR2+MS+Sag(2) 2/7/2018 11:30:51AM Page 2 COMPASS 5000.1 Build 81E • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-107 Project: Milne Point TVD Reference: a, MPU F-107 Actual @ 37.65usft Site: M Pt F Pad MD Reference: ' * ; MPU F-107 Actual @ 37.65usft Well: MPU F-107 North Reference: .= True Wellbore: MPU F-107(OA Producer) Survey Calculation Method: . Minimum Curvature Design: MPU F-107 Database: Sperry EDM-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) (°/100') (ft) Survey Tool Name 728.31 17.07 304.82 723.36 685.71 31.09 -44.67 6,034,968.27 541,277.29 5.79 -42.59 2_MWD+IFR2+MS+Sag(2) 791.54 19.75 305.05 783.35 745.70 42.53 -61.04 6,034,979.61 541,260.86 4.24 -58.23 2_MWD+IFR2+MS+Sag(2) 854.14 23.24 305.26 841.59 803.94 55.73 -79.79 6,034,992.71 541,242.04 5.58 -76.26 2_MWD+IFR2+MS+Sag(2) 917.07 26.49 305.14 898.68 861.03 70.98 -101.41 6,035,007.84 541,220.33 5.17 -97.07 2_MWD+IFR2+MS+Sag(2) 980.05 28.40 304.85 954.57 916.92 87.63 -125.19 6,035,024.35 541,196.47 3.04 -119.83 2_MWD+IFR2+MS+Sag(2) 1,043.30 30.18 305.18 1,009.73 972.08 105.39 -150.53 6,035,041.97 541,171.03 2.83 -144.10 2_MWD+IFR2+MS+Sag(2) 1,106.23 33.78 305.91 1,063.10 1,025.45 124.77 -177.64 6,035,061.19 541,143.82 5.75 -170.43 2_MWD+IFR2+MS+Sag(2) 1,168.75 36.84 305.03 1,114.11 1,076.46 145.72 -207.07 6,035,081.99 541,114.27 4.96 -198.95 2_MWD+IFR2+MS+Sag(2) 1,231.67 39.42 306.11 1,163.60 1,125.95 168.33 -238.66 6,035,104.41 541,082.56 4.24 -229.65 2_MWD+IFR2+MS+Sag(2) 1,294.35 42.51 306.66 1,210.93 1,173.28 192.71 -271.74 6,035,128.60 541,049.35 4.96 -262.49 2_MWD+IFR2+MS+Sag(2) 1,356.86 46.47 307.35 1,255.51 1,217.86 219.08 -306.71 6,035,154.77 541,014.24 6.38 -297.77 2_MWD+IFR2+MS+Sag(2) 1,420.23 50.18 306.35 1,297.64 1,259.99 247.45 -344.58 6,035,182.93 540,976.21 5.97 -335.80 2_MWD+IFR2+MS+Sag(2) 1,483.16 53.39 305.98 1,336.56 1,298.91 276.62 -384.50 6,035,211.88 540,936.14 5.12 -375.19 2_MWD+IFR2+MS+Sag(2) 1,545.96 53.16 305.89 1,374.12 1,336.47 306.16 -425.25 6,035,241.19 540,895.22 0.38 -415.17 2_MWD+IFR2+MS+Sag(2) 1,608.76 51.61 305.26 1,412.45 1,374.80 335.10 -465.71 6,035,269.90 540,854.61 2.59 -454.49 2_MWD+IFR2+MS+Sag(2) 1,671.83 50.73 304.35 1,451.99 1,414.34 363.14 -506.05 6,035,297.72 540,814.12 1.79 -492.91 2_MWD+IFR2+MS+Sag(2) 1,734.66 53.59 305.72 1,490.53 1,452.88 391.63 -546.66 6,035,325.98 540,773.35 4.87 -531.85 2_MWD+IFR2+MS+Sag(2) 1,797.44 53.29 305.70 1,527.93 1,490.28 421.07 -587.61 6,035,355.18 540,732.25 0.48 -571.78 2_MWD+IFR2+MS+Sag(2) 1,859.57 52.34 306.59 1,565.48 1,527.83 450.26 -627.58 6,035,384.15 540,692.12 1.91 -611.20 2_MWD+IFR2+MS+Sag(2) 1,923.13 54.29 307.45 1,603.45 1,565.80 480.95 -668.27 6,035,414.61 540,651.26 3.25 -652.26 2_MWD+IFR2+MS+Sag(2) 1,985.37 53.59 306.65 1,640.09 1,602.44 511.27 -708.43 6,035,444.70 540,610.94 1.53 -692.81 2_MWD+IFR2+MS+Sag(2) 2,049.41 52.41 306.50 1,678.63 1,640.98 541.74 -749.50 6,035,474.94 540,569.70 1.85 -733.78 2_MWD+IFR2+MS+Sag(2) 2,112.73 53.79 306.79 1,716.64 1,678.99 571.97 -790.12 6,035,504.94 540,528.91 2.21 -774.37 2_MWD+IFR2+MS+Sag(2) 2,173.84 51.76 306.14 1,753.61 1,715.96 600.89 -829.25 6,035,533.64 540,489.63 3.43 -813.29 2_MWD+IFR2+MS+Sag(2) 2,238.23 53.29 305.46 1,792.78 1,755.13 630.77 -870.70 6,035,563.29 540,448.02 2.52 -853.81 2_MWD+IFR2+MS+Sag(2) 2,300.45 52.87 305.18 1,830.16 1,792.51 659.53 -911.29 6,035,591.82 540,407.28 0.76 -892.99 2_MWD+IFR2+MS+Sag(2) 2,363.52 54.35 304.20 1,867.58 1,829.93 688.42 -953.03 6,035,620.48 540,365.38 2.66 -932.63 2_MWD+IFR2+MS+Sag(2) 2,426.44 54.78 303.24 1,904.06 1,866.41 716.88 -995.67 6,035,648.69 540,322.58 1.42 -972.11 2_MWD+IFR2+MS+Sag(2). 2,489.49 53.57 303.52 1,940.96 1,903.31 745.01 -1,038.36 6,035,676.58 540,279.74 1.95 -1,011.29 2_MWD+IFR2+MS+Sag(2) 2,552.63 52.64 304.41 1,978.87 1,941.22 773.22 -1,080.24 6,035,704.55 540,237.71 1.85 -1,050.31 2_MWD+IFR2+MS+Sag(2) 2,615.53 53.47 304.32 2,016.67 1,979.02 801.59 -1,121.74 6,035,732.69 540,196.06 1.32 -1,089.39 2_MWD+IFR2+MS+Sag(2) 2,678.24 55.48 303.12 2,053.11 2,015.46 829.92 -1,164.19 6,035,760.78 540,153.46 3.56 -1,128.69 2_MWD+IFR2+MS+Sag(2) 2,740.74 53.95 301.57 2,089.21 2,051.56 857.21 -1,207.28 6,035,787.83 540,110.22 3.18 -1,167.19 2_MWD+IFR2+MS+Sag(2) 2,803.73 52.21 301.82 2,127.05 2,089.40 883.67 -1,250.13 6,035,814.05 540,067.23 2.78 -1,204.81 2_MWD+IFR2+MS+Sag(2) 2,866.82 51.35 302.12 2,166.08 2,128.43 909.91 -1,292.18 6,035,840.05 540,025.04 1.41 -1,242.01 2_MWD+IFR2+MS+Sag(2) 2,929.96 50.85 302.56 2,205.73 2,168.08 936.20 -1,333.70 6,035,866.11 539,983.38 0.96 -1,279.08 2_MWD+IFR2+MS+Sag(2) 2,992.51 50.70 301.97 2,245.29 2,207.64 962.07 -1,374.67 6,035,891.74 539,942.27 0.77 -1,315.61 2_MWD+IFR2+MS+Sag(2) 3,055.43 50.13 298.29 2,285.39 2,247.74 986.41 -1,416.59 6,035,915.84 539,900.21 4.60 -1,350.94 2_MWD+IFR2+MS+Sag(2) 3,118.26 48.63 295.54 2,326.30 2,288.65 1,008.00 -1,459.10 6,035,937.20 539,857.59 4.09 -1,383.81 2_MWD+IFR2+MS+Sag(2) 3,181.35 46.41 291.50 2,368.91 2,331.26 1,026.59 -1,501.74 6,035,955.55 539,814.86 5.89 -1,413.83 2_MWD+IFR2+MS+Sag(2) 2/7/2018 11:30:51AM Page 3 COMPASS 5000.1 Build 81E • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-107 Project: Milne Point TVD Reference: MPU F-107 Actual @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-107 Actual @ 37.65usft Well: MPU F-107 North Reference: True Wellbore: MPU F-107(OA Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-107 Database: Sperry EDM-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) (°/100') (ft) Survey Tool Name 3,244.03 43.70 288.66 2,413.19 2,375.54 1,041.84 -1,543.38 6,035,970.57 539,773.13 5.38 -1,440.37 2_MWD+IFR2+MS+Sag(2) 3,306.84 40.58 285.36 2,459.76 2,422.11 1,054.20 -1,583.65 6,035,982.70 539,732.79 6.09 -1,463.75 2_MWD+IFR2+MS+Sag(2) 3,369.69 38.64 280.77 2,508.19 2,470.54 1,063.28 -1,622.65 6,035,991.57 539,693.75 5.58 -1,483.63 2_MWD+IFR2+MS+Sag(2) 3,432.36 36.14 275.74 2,557.99 2,520.34 1,068.79 -1,660.28 6,035,996.86 539,656.10 6.30 -1,499.69 2_MWD+IFR2+MS+Sag(2) 3,495.03 34.68 270.18 2,609.08 2,571.43 1,070.69 -1,696.51 6,035,998.57 539,619.86 5.64 -1,511.89 2_MWD+IFR2+MS+Sag(2) 3,557.98 34.33 264.78 2,660.97 2,623.32 1,069.13 -1,732.10 6,035,996.81 539,584.28 4.89 -1,520.60 2_MWD+IFR2+MS+Sag(2) 3,621.29 32.86 258.72 2,713.72 2,676.07 1,064.15 -1,766.73 6,035,991.63 539,549.68 5.78 -1,525.74 2_MWD+IFR2+MS+Sag(2) 3,684.04 32.33 252.24 2,766.60 2,728.95 1,055.70 -1,799.42 6,035,983.00 539,517.04 5.62 -1,527.01 2_MWD+IFR2+MS+Sag(2) 3,746.84 32.20 245.94 2,819.72 2,782.07 1,043.75 -1,830.70 6,035,970.88 539,485.83 5.36 -1,524.53 2_MWD+IFR2+MS+Sag(2) 3,809.40 32.80 238.60 2,872.50 2,834.85 1,028.12 -1,860.39 6,035,955.09 539,456.23 6.37 -1,518.06 2_MWD+IFR2+MS+Sag(2) 3,872.31 33.58 232.13 2,925.17 2,887.52 1,008.56 -1,888.68 6,035,935.37 539,428.05 5.76 -1,507.42 2_MWD+IFR2+MS+Sag(2) 3,935.66 33.61 226.85 2,977.95 2,940.30 985.80 -1,915.31 6,035,912.47 539,401.56 4.61 -1,493.26 2_MWD+IFR2+MS+Sag(2) 3,998.71 32.67 221.07 3,030.75 2,993.10 961.03 -1,939.23 6,035,887.57 539,377.78 5.23 -1,476.38 2_MWD+IFR2+MS+Sag(2) 4,061.41 32.55 214.15 3,083.59 3,045,94 934.31 -1,959.82 6,035,860.73 539,357.34 5.95 -1,456.67 2_MWD+IFR2+MS+Sag(2) 4,124.56 34.27 208.44 3,136.31 3,098.66 904.60 -1,977.83 6,035,830.93 539,339.49 5.67 -1,433.37 2_MWD+IFR2+MS+Sag(2) 4,187.13 36.77 205.89 3,187.24 3,149.59 872.26 -1,994.40 6,035,798.50 539,323.11 4.64 -1,407.13 2_MWD+IFR2+MS+Sag(2) 4,250.07 39.61 199.34 3,236.72 3,199.07 836.36 -2,009.28 6,035,762.52 539,308.43 7.85 -1,377.00 2_MWD+IFR2+MS+Sag(2) 4,313.18 40.57 196.62 3,285.01 3,247.36 797.71 -2,021.81 6,035,723.80 539,296.11 3.16 -1,343.56 2_MWD+IFR2+MS+Sag(2) 4,376.13 38.94 195.25 3,333.40 3,295.75 759.00 -2,032.87 6,035,685.04 539,285.27 2.94 -1,309.65 2_MWD+IFR2+MS+Sag(2) 4,439.35 40.72 192.05 3,381.96 3,344.31 719.66 -2,042.41 6,035,645.65 539,275.95 4.29 -1,274.69 2_MWD+IFR2+MS+Sag(2) 4,501.93 44.35 189.54 3,428.06 3,390.41 678.11 -2,050.29 6,035,604.06 539,268.30 6.40 -1,237.14 2_MWD+IFR2+MS+Sag(2) 4,564.62 47.47 187.18 3,471.68 3,434.03 633.57 -2,056.82 6,035,559.49 539,262.02 5.66 -1,196.33 2_MWD+IFR2+MS+Sag(2) 4,626.45 47.43 183.82 3,513.50 3,475.85 588.24 -2,061.18 6,035,514.14 539,257.91 4.00 -1,154.16 2_MWD+IFR2+MS+Sag(2) 4,690.77 49.59 180.29 3,556.11 3,518.46 540.11 -2,062.88 6,035,466.01 539,256.48 5.31 -1,108.53 2_MWD+1FR2+MS+Sag(2) 4,753.53 52.32 176.84 3,595.65 3,558,00 491.40 -2,061.63 6,035,417.31 539,258.00 6.09 -1,061.51 2_MWD+IFR2+MS+Sag(2) 4,816.46 54.19 174.96 3,633.30 3,595.65 441.11 -2,058.02 6,035,367.04 539,261.89 3.82 -1,012.29 2_MWD+IFR2+MS+Sag(2) 4,879.33 54.14 174.51 3,670.11 3,632.46 390.36 -2,053.34 6,035,316.32 539,266.85 0.59 -962.32 2_MWD+IFR2+MS+Sag(2) 4,942.31 54.18 174.41 3,706.99 3,669.34 339.54 -2,048.41 6,035,265.54 539,272.06 0.14 -912.22 2_MWD+IFR2+MS+Sag(2) 5,005.41 53.09 174.81 3,744.40 3,706.75 288.95 -2,043.64 6,035,214.99 539,277.12 1.80 -862.39 2_MWD+IFR2+MS+Sag(2) 5,067.54 52.62 174.85 3,781.91 3,744.26 239.63 -2,039.18 6,035,165.69 539,281.85 0.76 -813.86 2_MWD+IFR2+MS+Sag(2) 5,131.45 54.49 172.32 3,819.88 3,782.23 188.55 -2,033.42 6,035,114.65 539,287.89 4.32 -763.27 2_MWD+IFR2+MS+Sag(2) 5,194.09 57.77 171.44 3,854.79 3,817.14 137.07 -2,026.07 6,035,063.22 539,295.53 5.36 -711.84 2_MWD+IFR2+MS+Sag(2) 5,256.93 60.94 169.74 3,886.82 3,849.17 83.75 -2,017.22 6,035,009.95 539,304.68 5.56 -658.22 2_MWD+IFR2+MS+Sag(2) 5,320.04 65.46 168.16 3,915.27 3,877.62 28.48 -2,006.41 6,034,954.75 539,315.79 7.50 -602.17 2_MWD+IFR2+MS+Sag(2) 5,381.77 69.17 167.10 3,939.07 3,901.42 -27.14 -1,994.20 6,034,899.20 539,328.31 6.22 -545.39 2_MWD+IFR2+MS+Sag(2) 5,446.18 69.95 165.07 3,961.56 3,923.91 -85.72 -1,979.69 6,034,840.71 539,343.14 3.19 -485.11 2_MWD+IFR2+MS+Sag(2) 5,509.22 70.09 163.87 3,983.11 3,945.46 -142.80 -1,963.82 6,034,783.73 539,359.32 1.80 -425.87 2_MWD+IFR2+MS+Sag(2) 5,571.59 70.82 161.28 4,003.97 3,966.32 -198.87 -1,946.22 6,034,727.76 539,377.23 4.08 -367.11 2_MWD+IFR2+MS+Sag(2) 5,634.75 73.30 158.64 4,023.43 3,985.78 -255.31 -1,925.63 6,034,671.44 539,398.14 5.59 -307.14 2_MWD+IFR2+MS+Sag(2) 5,697.45 75.53 156.99 4,040.28 4,002.63 -311.22 -1,902.82 6,034,615.66 539,421.26 4.37 -247.03 2_MWD+IFR2+MS+Sag(2) 2/7/2018 11:30:51AM Page 4 COMPASS 5000.1 Build 81E • • Halliburton Definitive Survey Report --s« ..3. ,... .� it Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-107 Project: Milne Point TVD Reference: MPU F-107 Actual @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-107 Actual @ 37.65usft Well: MPU F-107 North Reference: True Wellbore: MPU F-107(OA Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-107 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 5,760.48 77.56 154.69 4,054.94 4,017.29 -367.14 -1,877.73 6,034,559.88 539,446.66 4.79 -186.26 2_MWD+1FR2+MS+Sag(2) 5,822.72 80.45 151.94 4,066.81 4,029.16 -421.72 -1,850.29 6,034,505.47 539,474.40 6.35 -126.11 2_MWD+IFR2+MS+Sag(2) 5,884.86 82.01 150.65 4,076.29 4,038.64 -475.58 -1,820.79 6,034,451.78 539,504.19 3.24 -66.06 2_MWD+IFR2+MS+Sag(2) 5,949.19 85.06 147.97 4,083.53 4,045.88 -530.54 -1,788.17 6,034,397.01 539,537.11 6.29 -4.06 2_MWD+IFR2+MS+Sag(2) 6,012.01 85.56 147.24 4,088.67 4,051.02 -583.40 -1,754.63 6,034,344.34 539,570.95 1.41 56.20 2_MWD+IFR2+MS+Sag(2) 6,075.02 85.24 147.07 4,093.72 4,056.07 -636.17 -1,720.56 6,034,291.76 539,605.30 0.57 116.51 2_MWD+IFR2+MS+Sag(2) 6,137.96 84.26 146.04 4,099.48 4,061.83 -688.47 -1,686.02 6,034,239.67 539,640.13 2.25 176.51 2_MWD+IFR2+MS+Sag(2) 6,200.10 83.52 145.53 4,106.10 4,068.45 -739.56 -1,651.28 6,034,188.77 539,675.15 1.44 235.42 2_MWD+IFR2+MS+Sag(2) 6,263.79 82.94 146.42 4,113.60 4,075.95 -791.98 -1,615.89 6,034,136.56 539,710.83 1.66 295.78 2_MWD+IFR2+MS+Sag(2) 6,318.45 84.23 146.53 4,119.71 4,082,06 -837.26 -1,585.89 6,034,091.45 539,741.08 2.37 347.76 2_MWD+IFR2+MS+Sag(2) 6,394.58 84.97 146.95 4,126.88 4,089.23 -900.63 -1,544.32 6,034,028.31 539,782.99 1.12 420.38 2_MWD+IFR2+MS+Sag(3) 6,458.90 86.53 146.03 4,131.64 4,093.99 -954.11 -1,508.91 6,033,975.03 539,818.69 2.81 481.77 2_MWD+IFR2+MS+Sag(3) 6,522.37 87.26 146.09 4,135.08 4,097.43 -1,006.69 -1,473.53 6,033,922.66 539,854.37 1.15 542.28 2_MWD+IFR2+MS+Sag(3) 6,584.98 87.38 144.94 4,138.01 4,100.36 -1,058.24 -1,438.12 6,033,871.31 539,890.06 1.84 601.82 2_MWD+IFR2+MS+Sag(3) 6,648.12 88.75 145.54 4,140.14 4,102.49 -1,110.08 -1,402.14 6,033,819.68 539,926.32 2.37 661.79 2_MWD+IFR2+MS+Sag(3) 6,710.55 88.25 146.22 4,141.77 4,104.12 -1,161.75 -1,367.13 6,033,768.21 539,961.61 1.35 721.32 2_MWD+IFR2+MS+Sag(3) 6,773.99 89.43 148.34 4,143.06 4,105.41 -1,215.11 -1,332.85 6,033,715.05 539,996.19 3.82 782.27 2_MWD+IFR2+MS+Sag(3) 6,836.31 88.68 148.01 4,144.09 4,106.44 -1,268.05 -1,300.00 6,033,662.29 540,029.33 1.31 842.40 2_MWD+IFR2+MS+Sag(3) 6,899.71 88.81 147.21 4,145.47 4,107.82 -1,321.57 -1,266.04 6,033,608.97 540,063.58 1.28 903.41 2_MWD+IFR2+MS+Sag(3) 6,960.81 87.16 146.66 4,147.62 4,109.97 -1,372.74 -1,232.73 6,033,557.99 540,097.18 2.85 961.98 2_MWD+IFR2+MS+Sag(3) 7,024.78 87.89 145.49 4,150.39 4,112.74 -1,425.77 -1,197.06 6,033,505.16 540,133.14 2.15 1,023.01 2_MWD+IFR2+MS+Sag(3) 7,087.63 88.75 145.80 4,152.23 4,114.58 -1,477.64 -1,161.61 6,033,453.50 540,168.87 1.45 1,082.85 2_MWD+IFR2+MS+Sag(3) 7,150.56 89.55 145.08 4,153.16 4,115.51 -1,529.46 -1,125.91 6,033,401.89 540,204.85 1.71 1,142.73 2_MWD+IFR2+MS+Sag(3) 7,213.60 90.72 146.07 4,153.01 4,115.36 -1,581.45 -1,090.28 6,033,350.09 540,240.77 2.43 1,202.76 2_MWD+IFR2+MS+Sag(3) 7,276.20 91.59 147.28 4,151.75 4,114.10 -1,633.75 -1,055.89 6,033,298.00 540,275.44 2.38 1,262.71 2_MWD+IFR2+MS+Sag(3) 7,339.07 90.90 146.62 4,150.39 4,112.74 -1,686.43 -1,021.61 6,033,245.51 540,310.01 1.52 1,323.01 2_MWD+IFR2+MS+Sag(3) 7,401.71 90.79 145.76 4,149.46 4,111.81 -1,738.47 -986.76 6,033,193.67 540,345.15 1.38 1,382.85 2_MWD+IFR2+MS+Sag(3) 7,464.77 91.52 146.07 4,148.19 4,110.54 -1,790.69 -951.43 6,033,141.65 540,380.77 1.26 1,443.00 2_MWD+IFR2+MS+Sag(3) 7,527.38 90.66 145.94 4,147.00 4,109.35 -1,842.59 -916.43 6,033,089.95 540,416.05 1.39 1,502.75 2_MWD+IFR2+MS+Sag(3) 7,590.43 92.15 146.65 4,145.45 4,107.80 -1,895.02 -881.45 6,033,037.72 540,451.32 2.62 1,563.01 2_MWD+IFR2+MS+Sag(3) 7,652.63 92.70 146.07 4,142.82 4,105.17 -1,946.76 -847.03 6,032,986.18 540,486.02 1.28 1,622.44 2_MWD+IFR2+MS+Sag(3) 7,714.32 92.82 146.25 4,139.85 4,102.20 -1,997.94 -812.71 6,032,935.20 540,520.62 0.35 1,681.31 2_MWD+IFR2+MS+Sag(3) 7,778.68 92.63 146.74 4,136.79 4,099.14 -2,051.54 -777.23 6,032,881.80 540,556.40 0.82 1,742.83 2_MWD+IFR2+MS+Sag(3) 7,842.12 92.58 146.42 4,133.91 4,096.26 -2,104.44 -742.32 6,032,629.10 540,591.60 0.51 1,803.51 2_MWD+IFR2+MS+Sag(3) 7,904.78 92.07 147.02 4,131.37 4,093.72 -2,156.78 -707.97 6,032,776.96 540,626.24 1.26 1,863.50 2_MWD+IFR2+MS+Sag(3) 7,967.75 91.52 146.52 4,129.39 4,091.74 -2,209.43 -673.48 6,032,724.51 540,661.02 1.18 1,923.82 2_MWD+IFR2+MS+Sag(3) 8,029.62 91.77 146.02 4,127.62 4,089,97 -2,260.86 -639.14 6,032,673.27 540,695.64 0.90 1,982.94 2_MWD+IFR2+MS+Sag(3) 8,092.13 91.39 146.05 4,125.89 4,088.24 -2,312.68 -604.23 6,032,621.65 540,730.83 0.61 2,042.59 2_MWD+IFR2+MS+Sag(3) 8,155.00 90.65 145.82 4,124.77 4,087.12 -2,364.76 -569.02 6,032,569.78 540,766.33 1.23 2,102.57 2_MWD+IFR2+MS+Sag(3) 8,218.37 89.85 145.12 4,124.50 4,086.85 -2,416.96 -533.10 6,032,517.78 540,802.54 1.68 2,162.88 2_MWD+IFR2+MS+Sag(3) 2/7/2018 11:30:51AM Page 5 COMPASS 5000.1 Build 81E • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU F-107 Project: Milne Point TVD Reference: MPU F-107 Actual @ 37.65usft Site: M Pt F Pad MD Reference: MPU F-107 Actual @ 37.65usft Well: MPU F-107 North Reference: True If Wellbore: MPU F-107(OA Producer) Survey Calculation Method: Minimum Curvature Y Design: MPU F-107 Database: Sperry EDM-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) (°/100') (ft) Survey Tool Name 8,281.55 88.98 144.50 4,125.14 4,087.49 -2,468.59 -496.69 6,032,466.36 540,839.23 1.69 2,222.78 2_MWD+IFR2+MS+Sag(3) 8,343.92 88.25 144.63 4,126.65 4,089.00 -2,519.39 -460.54 6,032,415.76 540,875.65 1.19 2,281.81 2_MWD+IFR2+MS+Sag(3) 8,406.60 88.32 145.41 4,128.53 4,090.88 -2,570.73 -424.62 6,032,364.63 540,911.85 1.25 2,341.28 2_MWD+IFR2+MS+Sag(3) 8,469.92 91.36 149.48 4,128.70 4,091.05 -2,624.08 -390.56 6,032,311.47 540,946.21 8.02 2,402.16 2_MWD+IFR2+MS+Sag(3) 8,529.16 90.90 148.83 4,127.53 4,089.88 -2,674.93 -360.19 6,032,260.80 540,976.85 1.34 2,459.58 2_MWD+IFR2+MS+Sag(3) 8,595.86 90.16 148.61 4,126.92 4,089.27 -2,731.93 -325.56 6,032,204.00 541,011.80 1.16 2,524.11 2_MWD+IFR2+MS+Sag(3) 8,652.87 89.73 148.37 4,126.97 4,089.32 -2,780.54 -295.77 6,032,155.56 541,041.86 0.86 2,579.21 2_MWD+IFR2+MS+Sag(3) 8,721.54 89.85 148.30 4,127.22 4,089.57 -2,838.98 -259.72 6,032,097.32 541,078.23 0.20 2,645.54 2_MWD+IFR2+MS+Sag(3) 8,774.95 90.66 148.96 4,126.99 4,089.34 -2,884.59 -231.92 6,032,051.88 541,106.28 1.96 2,697.19 2_MWD+IFR2+MS+Sag(3) 8,847.42 89.91 148.83 4,126.63 4,088.98 -2,946.63 -194.48 6,031,990.05 541,144.06 1.05 2,767.37 2_MWD+IFR2+MS+Sag(3) 8,907.86 89.60 148.54 4,126.88 4,089.23 -2,998.27 -163.07 6,031,938.59 541,175.76 0.70 2,825.84 2_MWD+IFR2+MS+Sag(3) 8,973.31 89.05 148.43 4,127.66 4,090.01 -3,054.06 -128.86 6,031,883.00 541,210.27 0.86 2,889.09 2_MWD+IFR2+MS+Sag(3) 9,036.28 88.44 148.36 4,129.03 4,091.38 -3,107.68 -95.86 6,031,829.57 541,243.56 0.98 2,949.92 2_MWD+IFR2+MS+Sag(3) 9,099.91 90.24 150.83 4,129.77 4,092.12 -3,162.55 -63.67 6,031,774.89 541,276.06 4.80 3,011.71 2_MWD+IFR2+MS+Sag(3) 9,162.75 89.42 150.32 4,129.95 4,092.30 -3,217.28 -32.79 6,031,720.33 541,307.23 1.54 3,072.99 2_MWD+IFR2+MS+Sag(3) 9,225.50 89.05 149.48 4,130.79 4,093.14 -3,271.56 -1.33 6,031,666.23 541,339.00 1.46 3,134.02 2_MWD+IFR2+MS+Sag(3) 9,288.39 88.56 147.74 4,132.10 4,094.45 -3,325.24 31.42 6,031,612.75 541,372.04 2.87 3,194.82 2_MWD+IFR2+MS+Sag(3) 9,351.21 87.74 145.90 4,134.13 4,096.48 -3,377.78 65.78 6,031,560.40 541,406.69 3.21 3,255.01 2_MWD+IFR2+MS+Sag(3) 9,414.05 87.38 144.16 4,136.81 4,099.16 -3,429.23 101.76 6,031,509.16 541,442.95 2.83 3,314.61 2_MWD+IFR2+MS+Sag(3) 9,476.84 89.62 145.80 4,138.45 4,100.80 -3,480.63 137.78 6,031,457.96 541,479.25 4.42 3,374.17 2_MWD+IFR2+MS+Sag(3) 9,539.19 89.80 146.27 4,138.77 4,101.12 -3,532.34 172.61 6,031,406.45 541,514.37 0.81 3,433.70 2_MWD+IFR2+MS+Sag(3) 9,602.66 90.79 146.69 4,138.44 4,100.79 -3,585.25 207.66 6,031,353.74 541,549.71 1.69 3,494.43 2_MWD+IFR2+MS+Sag(3) 9,665.68 91.83 147.37 4,137.00 4,099.35 -3,638.11 241.95 6,031,301.08 541,584.28 1.97 3,554.90 2_MWD+IFR2+MS+Sag(3) 9,728.73 92.20 146.37 4,134.78 4,097.13 -3,690.87 276.39 6,031,248.51 541,619.01 1.69 3,615.32 2_MWD+IFR2+MS+Sag(3) 9,791.44 92.82 146.48 4,132.04 4,094.39 -3,743.07 311.03 6,031,196.51 541,653.94 1.00 3,675.25 2_MWD+IFR2+MS+Sag(3) 9,854.23 92.82 147.06 4,128.95 4,091.30 -3,795.53 345.40 6,031,144.25 541,688.60 0.92 3,735.36 2_MWD+IFR2+MS+Sag(3) 9,917.07 92.69 147.24 4,125.93 4,088.28 -3,848.26 379.45 6,031,091.72 541,722.94 0.35 3,795.64 2_MWD+IFR2+MS+Sag(3) 9,979.33 93.44 146.55 4,122.60 4,084.95 -3,900.34 413.40 6,031,039.83 541,757.18 1.64 3,855.26 2_MWD+IFR2+MS+Sag(3) 10,042.47 92.56 146.52 4,119.29 4,081.64 -3,952.94 448.17 6,030,987.43 541,792.24 1.39 3,915.62 2_MWD+IFR2+MS+Sag(3) 10,105.19 91.21 146.14 4,117.23 4,079.58 -4,005.11 482.92 6,030,935.46 541,827.27 2.24 3,975.56 2_MWD+IFR2+MS+Sag(3) 10,168.46 90.90 147.62 4,116.06 4,078.41 -4,058.09 517.49 6,030,882.68 541,862.13 2.39 4,036.22 2_MWD+IFR2+MS+Sag(3) 10,230.92 90.35 147.83 4,115.38 4,077.73 -4,110.89 550.84 6,030,830.07 541,895.77 0.94 4,096.37 2_MWD+IFR2+MS+Sag(3) 10,293.74 90.35 14824 4,115.00 4,077.35 -4,164.19 584.09 6,030,776.96 541,929.32 0.65 4,156.95 2_MWD+IFR2+MS+Sag(3) 10,356.86 90.59 148.83 4,114.48 4,076.83 -4,218.02 617.04 6,030,723.32 541,962.56 1.01 4,217.97 2_MWD+IFR2+MS+Sag(3) 10,419.57 89.86 147.67 4,114.24 4,076.59 -4,271.35 650.04 6,030,670.18 541,995.85 2.19 4,278.52 2_MWD+IFR2+MS+Sag(3) 10,482.99 89.61 146.41 4,114.53 4,076.88 -4,324.56 684.54 6,030,617.17 542,030.65 2.03 4,339.38 2_MWD+IFR2+MS+Sag(3) 10,545.84 88.79 144.13 4,115.41 4,077.76 -4,376.20 720.34 . 6,030,565.73 542,066.73 3.85 4,399.12 2_MWD+IFR2+MS+Sag(3) 10,608.81 89.11 144.90 4,116.56 4,078.91 -4,427.47 756.89 6,030,514.67 542,103.56 1.32 4,458.71 2_MWD+IFR2+MS+Sag(3) 10,671.38 89.73 146.11 4,117.19 4,079.54 -4,479.03 792.32 6,030,463.31 542,139.27 2.17 4,518.26 2_MWD+IFR2+MS+Sag(3) 10,734.62 89.98 148.03 4,117.35 4,079.70 -4,532.11 826.70 6,030,410.43 542,173.94 3.06 4,578.96 2_MWD+IFR2+MS+Sag(3) 2/7/2018 11:30:51AM Page 6 COMPASS 5000.1 Build 81E 0 • Halliburton Definitive Survey Report _ "M' x 4'�...IE v .,..>. __L.._s "�§f '• .• .. '.._+- R `5 ..Y:ssN _�.:2.�..s�}}..b'd-TM'&£«w' F.3T3##L ft. ..» s'ov ,sx«.2.,,..:9 Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: , Well MPU F-107 Project: Milne Point TVD Reference: : MPU F-107 Actual @ 37.65usft Site: M Pt F Pad MD Reference: .,, MPU F-107 Actual @ 37.65usft Well: MPU F-107 North Reference: I True t, 1 Wellbore: MPU F-107(OA Producer) Survey Calculation Method: Minimum Curvature Design: MPU F-107 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-5 +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 10,797.40 90.48 148.85 4,117.10 4,079.45 -4,585.60 859.56 6,030,357.13 542,207.09 1.53 4,639.63 2 MWD+IFR2+MS+Sag(3) 10,860.89 89.80 148.49 4,116.95 4,079.30 -4,639.84 892.57 6,030,303.09 542,240.40 1.21 4,701.04 2_MWD+IFR2+MS+Sag(3) 10,923.33 90.23 148.68 4,116.93 4,079.28 -4,693.12 925.11 6,030,249.99 542,273.24 0.75 4,761.42 2_MWD+IFR2+MS+Sag(3) 10,986.28 89.48 148.52 4,117.09 4,079.44 -4,746.85 957.91 6,030,196.44 542,306.33 1.22 4,822.30 2_MWD+IFR2+MS+Sag(3) 11,049.23 89.46 145.77 4,117.67 4,080.02 -4,799.73 992.06 6,030,143.77 542,340.77 4.37 4,882.74 2_MWD+IFR2+MS+Sag(3) 11,112.14 89.49 146.26 4,118.25 4,080.60 -4,851.89 1,027.22 6,030,091.81 542,376.22 0.78 4,942.79 2_MWD+IFR2+MS+Sag(3) 11,175.53 87.44 144.66 4,119.95 4,082.30 -4,904.08 1,063.15 6,030,039.82 542,412.43 4.10 5,003.09 2_MWD+IFR2+MS+Sag(3) 11,238.38 86.27 144.82 4,123.39 4,085.74 -4,955.32 1,099.37 6,029,988.78 542,448.94 1.88 5,062.56 2_MWD+IFR2+MS+Sag(3) 11,301.38 85.63 144.86 4,127.84 4,090.19 -5,006.70 1,135.56 6,029,937.61 542,485.41 1.02 5,122.15 2_MWD+IFR2+MS+Sag(3) 11,363.84 86.97 147.39 4,131.88 4,094.23 -5,058.44 1,170.30 6,029,886.07 542,520.43 4.58 5,181.68 2_MWD+IFR2+MS+Sag(3) 11,426.90 87.57 149.51 4,134.88 4,097.23 -5,112.12 1,203.25 6,029,832.58 542,553.68 3.49 5,242.54 2_MWD+IFR2+MS+Sag(3) 11,489.92 87.57 150.41 4,137.55 4,099.90 -5,166.62 1,234.77 6,029,778.26 542,585.50 1.43 5,303.80 2_MWD+IFR2+MS+Sag(3) 11,552.95 87.75 150.39 4,140.13 4,102.48 -5,221.38 1,265.88 6,029,723.68 542,616.91 0.29 5,365.17 2_MWD+IFR2+MS+Sag(3) 11,615.91 89.62 150.50 4,141.57 4,103.92 -5,276.13 1,296.93 6,029,669.11 542,648.25 2.98 5,426.52 2_MWD+1FR2+MS+Sag(3) 11,678.69 89.42 150.85 4,142.10 4,104.45 -5,330.87 1,327.67 6,029,614.55 542,679.30 0.64 5,487.77 2_MWD+IFR2+MS+Sag(3) 11,741.49 89.17 150.12 4,142.87 4,105.22 -5,385.51 1,358.61 6,029,560.08 542,710.54 1.23 5,548.99 2_MWD+IFR2+MS+Sag(3) 11,804.40 89.34 149.35 4,143.69 4,106.04 -5,439.84 1,390.31 6,029,505.94 542,742.54 1.25 5,610.13 2_MWD+IFR2+MS+Sag(3) 11,867.43 90.92 149.22 4,143.54 4,105.89 -5,494.03 1,422.51 6,029,451.94 542,775.03 2.52 5,671.26 2_MWD+IFR2+MS+Sag(3) 11,930.28 90.96 148.97 4,142.51 4,104.86 -5,547.95 1,454.78 6,029,398.20 542,807.60 0.40 5,732.17 2_MWD+IFR2+MS+Sag(3) 11,993.12 90.97 149.07 4,141.45 4,103.80 -5,601.82 1,487.12 6,029,344.52 542,840.24 0.16 5,793.05 2_MWD+IFR2+MS+Sag(3) 12,055.87 90.79 149.03 4,140.49 4,102.84 -5,655.63 1,519.39 6,029,290.90 542,872.80 0.29 5,853.84 2_MWD+IFR2+MS+Sag(3) 12,119.06 90.73 149.31 4,139.65 4,102.00 -5,709.88 1,551.77 6,029,236.83 542,905.48 0.45 5,915.10 2_MWD+IFR2+MS+Sag(3) 12,181.46 91.21 149.55 4,138.60 4,100.95 -5,763.60 1,583.50 6,029,183.29 542,937.51 0.86 5,975.66 2_MWD+IFR2+MS+Sag(3) 12,244.64 89.55 148.36 4,138.18 4,100.53 -5,817.73 1,616.08 6,029,129.35 542,970.39 3.23 6,036.85 2_MWD+IFR2+MS+Sag(3) 12,306.91 89.05 148.87 4,138.94 4,101.29 -5,870.88 1,648.51 6,029,076.38 543,003.11 1.15 6,097.07 2_MWD+IFR2+MS+Sag(3) 12,370.19 89.86 148.53 4,139.54 4,101.89 -5,924.95 1,681.38 6,029,022.51 543,036.28 1.39 6,158.29 2_MWD+IFR2+MS+Sag(3) 12,433.06 89.86 149.03 4,139.69 4,102.04 -5,978.71 1,713.97 6,028,968.93 543,069.16 0.80 6,219.14 2_MWD+IFR2+MS+Sag(3) 12,496.23 90.05 149.11 4,139.74 4,102.09 -6,032.90 1,746.44 6,028,914.93 543,101.92 0.33 6,280.36 2_MWD+IFR2+MS+Sag(3) 12,558.71 90.17 148.99 4,139.62 4,101.97 -6,086.48 1,778.57 6,028,861.53 543,134.35 0.27 6,340.90 2_MWD+IFR2+MS+Sag(3) 12,621.81 89.79 147.69 4,139.64 4,101.99 -6,140.19 1,811.69 6,028,808.01 543,167.77 2.15 6,401.85 2_MWD+IFR2+MS+Sag(3) 12,684.50 89.84 146.78 4,139.85 4,102.20 -6,192.91 1,845.62 6,028,755.49 543,201.98 1.45 6,462.07 2_MWD+IFR2+MS+Sag(3) 12,747.26 90.66 144.54 4,139.57 4,101.92 -6,244.72 1,881.02 6,028,703.88 543,237.67 3.80 6,521.86 2_MWD+IFR2+MS+Sag(3) 12,810.90 92.89 145.17 4,137.60 4,099.95 -6,296.73 1,917.63 6,028,652.08 543,274.57 3.64 6,582.18 2_MWD+IFR2+MS+Sag(3) 12,873.63 92.19 145.29 4,134.82 4,097.17 -6,348.21 1,953.37 6,028,600.80 543,310.59 1.13 6,641.74 2_MWD+IFR2+MS+Sag(3) 12,948.90 91.33 145.84 4,132.51 4,094.86 -6,410.26 1,995.91 6,028,539.00 543,353.47 1.36 6,713.38 2_MWD+IFR2+MS+Sag(3) 12,980.00 91.33 145.84 4,131.79 4,094.14 -6,435.99 2,013.37 6,028,513.37 543,371.07 0.00 6,743.03 PROJECTED to TD mitchell.laird4halliburton.com Michael Calkins=.-e..•...�.�:-�.-_ Checked By: 2018.02.0708.56:51-09'00' Approved By: �m,�,,,., Date: 2/7/2018 2/7/2018 11:30:51AM Page 7 COMPASS 5000.1 Build 81E • Hilcorp Energy Company • CASING&CEMENTING REPORT Lease 8 Well No. MP F-107 Date Run 28-Jan-18 County Prudhoe Bay State Alaska Supv. J.Lott/S.Barber CASING RECORD Surface V TD 6,359.00 Shoe Depth: 6,352.71 PBTD: 6,224.95 No.Jts.Delivered 157 No.Jts.Run 157 No.Jts.Returned Length Measurements W/O Ftg.Delivered 6,352.71 Ftg.Run 6,352.71 Ftg.Returned Threads Ftg.Cut Jt. 12.07 Ftg.Balance RKB 26.50 RKB to BHF RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Float Shoe 10 3/4 40.0 L-80 DWC/C Antelope 1.62 6,352.71 6,351.09 2 Casing 95/8 40.0 L-80 DWC/C Tenaris 81.97 6,351.09 6,269.12 1 Float Collar 10 3/4 40.0 L-80 DWC/C Antelope 1.30 6,269.12 6,267.82 1 Casing 95/8 40.0 L-80 DWC/C Tenaris 41.27 6,267.82 6,226.55 1 Cmt Baffle 103/4 40.0 L-80 DWC/C HES 1.60 6,226.55 6,224.95 92 Casing 95/8 40.0 L-80 DWC/C Tenaris 3,687.49 6,224.95 2,537.46 1 Stage Tool 103/4 40.0 L-80 DWC/C HES 3.90 2,537.46 2,533.56 64 Casing 95/8 40.0 L-80 DWC/C Tenaris 2,507.06 2,533.56 26.50 1 RKB 95/8 26.50 26.50 0 Csg Wt.On Hook: 165,000 Type Float Collar: Conventional No.Hrs to Run: 18 Csg Wt.On Slips: 130,000 Type of Shoe: Conventional Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg X Yes No 20 Ft.Min. 9.3 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: 2ea Solid centralizers shoe jt,lea Solid body centralizer ctr#2,1 ea every jt#3-25,lea every other jt from#27447.Sea bow spring centralizers across stage tool. Totals=3 solid body centralizers,40 bow spring centralizers CEMENTING REPORT Shoe @ 6353 FC @ 6,268.00 Top of Liner Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 10.5 Volume pumped(BBLS) 60 Lead Slurry ISI Type: Extenda Cern _Sacks: 460 Yield: 2.47 Density(ppg) 11.7 Volume pumped(BBLS) 203 Mixing/Pumping Rate(bpm): 6 Tail Slurry Type: Hal Cern Sacks: 400 Yield: 1.16 5,C.- ¢ Density(ppg) 15.8 Volume pumped(BBLS) 81.6 Mixing/Pumping Rate(bpm): 4 w Post Flush(Spacer) ill ET. Type: Density(ppg) Rate(bpm): Volume: Displacement: Type: Spud Mud Density(ppg) 9.3 Rate(bpm): 6 Volume(actual/calculated): 473.1/472 FCP(psi): 760 Pump used for disp: dg Bump Plug? X Yes No Bump press 1260 Casing Rotated? Yes X No Reciprocated? X Yes No %Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 56 Cement In Place At: 1:20 Date: 1/29/2018 Estimated TOC: 2,530 Method Used To Determine TOC: CMT to Surface Stage Collar @ 2533 Type ES II Closure OK Y Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 10.5 Volume pumped(BBLS) 60 Lead Slurry i' / Type: Perm L Sacks: 416 Yield: 4.33 '0'. 7 ✓ Density(ppg) 10.7 Volume pumped(BBLS) 320 ' Mixing/Pumping Rate(bpm): 6 Ilff Tail Slurry Type: Premium G Sacks: 270 Yield: 1.17 w Density(ppg) 15.8 Volume pumped(BBLS) 56 Mixing/Pumping Rate(bpm): 4 G Post Flush(Spacer) 8 Type: Density(ppg) Rate(bpm): Volume:ui Ili w Displacement: Type: Spud Mud Density(ppg) 9.3 Rate(bpm): 8 Volume(actual/calculated): 192.2/192.2 FCP(psi): 575 Pump used for disp: rig Bump Plug? X Yes No Bump press 1550 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 100 Cement returns to surface? X Yes_No Spacer returns? X Yes No Vol to Surf: 268 Cement In Place At: 12:50 Date: 1/29/2018 Estimated TOC: 0 Method Used To Determine TOC: Visual Post Job Calculations: Calculated Cmt Vol @ 0%excess: 348.7 Total Volume cmt Pumped: 660 Cmt returned to surface: 326 Calculated cement left in wellbore: 334 OH volume Calculated: 354.6 OH volume actual: 334 Actual%Washout: WELLHEAD Make FMC Type Multi Bowl Serial No. Size 11 W.P. 5000 Test head to 5000 PSIG 15 MIN OK Remarks: www.wellez.net WellEz Information Management LLC ver_102716bf OF Tit • v7;4' THE STATE Alaska Oil and as —" d ��9� Of111 1sJL`tel 1 �ConservationConservationCOn1n11SS1 n i ti �s��of ;_ _ s i}t .• 333 West Seventh Avenue I IF GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ""• Main: 907.279.1433 of ALAS*P Fax: 907.276.7542 www.aogcc.alaska. ov Monty Myers Drilling Manager Hilcorp Alaska,LLC 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool,MPU F-107 Hilcorp Alaska, LLC Permit to Drill Number: 218-001 Surface Location: 1488' FSL, 3246' FEL, SEC. 6, T13N,R10E,UM,AK Bottomhole Location: 574' FSL, 1435' FEL, SEC. 7,T13N,R10E,UM,AK Dear Mr.Myers: Enclosed is the approved application for 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 to TD. Cased hole gammy ray 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 Chair DATED this t day of January,2018. RECEIV STATE OF ALASKA AKA OIL AND GAS CONSERVATION COMIPSION JAN 0 PERMIT TO DRILL 201$ 20 AAC 25.005 /�j i�p la.Type of Work: 1 b.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp lc.Spe lEft ' fur: Drill El• Lateral 0 Stratigraphic Test ❑ Development-Oil ❑' • Service- Winj ❑ Single Zone • Coalbed Gas El Gas Hydrat•s 0 Redrill❑ Reentry 0 Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal 0 Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Q . Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 • MPU F-107 ' 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 12,688' • TVD: 4,132' • Milne Point Field 4a. Location of Well(Governmental Section): 7.Property Designation: Schrader Bluff Oil Pool Surface: 1488'FSL,3246'FEL,Sec 6,T13N,R10E,UM,AK ADL025509•40 'Z3 5-- OA Top of Productive Horizon: 8.DNR Approval Number: / Jy 13.Approximate Spud Date: 1108'FSL,65'FWL,Sec 6,T13N,R10E,UM,AK LONS 94-109 f'G'l 1/20/2018 Total Depth: 9.Acres in Property: 14.Distance to Nearest Prope I : 574'FSL, 1435'FEL,Sec 7,T13N,R10E,UM,AK 2533 Acres 6,516'to nearest unit bounI ary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 37.3 15.Distance to Nearest Well O uen Surface: x-541322 • y- 6034937 • Zone-4 GL/BF Elevation above MSL(ft): 10.8 • to Same Pool: 875'to MPL-48 16.Deviated wells: Kickoff depth: 275 feet 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: 1800 • Surface: 1397• 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sa ks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 344/x20" - X-52 Weld 80' Surface Surface 106.5' 106.5' 12.6 bbls/6 sacks Stg 1 -L-1108ft3/T-45:,ft3 12-1/4" 9-5/8" 40# L-80 DWC 6,220' Surface Surface 6,220' • 4,108' • Stg 2-L-1943 ft3/T-31 ft3 7-5/8" 29.7# L-80 VAM STL 6,070' Surface Surface 6,070' 4,092' Tieback Assy. 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 6,618' 6,070' 4,092' 12,688' 4,132' Cementless Slotted Lin-r 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(meas red): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Hydraulic Fracture planned? Yes❑ No ❑., 20. Attachments: Property Plat 0 BOP Sketch . Drilling Program 7 Time v.Depth Plot — Shallow Hazard Analysis— Diverter Sketch 7 Seabed Report Drilling Fluid Program 7 20 AAC 25.050 requirements 7 21. Verbal Approval: Commission Representative: Date 22. I 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: 1engele.hilcorD.com Authorized Title: Drilling Manager Contact Phone: 777-8395 ___^ Fo2 MoNTy MY G& / Authorized Signature: L Date: `(.1 /8 Commission Use Only Permit to Drill .k API Number: G, Permit Approval See cover letter for other Number: 7 J c'c-/ 50-6L`�-m Z,3 (Z -L'C-t•""��-` Date: ( l I I requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: ay Other: •g' �?ODD �c► V 4th 7 7_ Samples req'd: Yes ❑ No[ ,, Mud log req'd:Yes❑ No d J J H25 measures: Yes ❑ No a Directional svy req'd:Yes[►�No❑ Spacing exception req'd: Yes El No t"1 Inclination-only svy req'd:Yes❑ No a Post initial injection MIT req'd:Yes❑ No El ..\----- APPROVED BY A PProved by: 00411111 411\ COMMISSIONER THE COMMISSION Date: it t I t I � •� j/_gr—mit , 4 Submit Form and Form 10-401 Revised 5/2017 ' 'i•' This dermrt rs valid for 24 mon 1 r t e 'e • . . :I •er 20 AAC 25. 05 g) Attachm nts in Duplicate Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Hilcorp Anchorage,AK 99524-4027 EnCompany Tel 907 777 8395 ergyEmail: jengel@hilcorp.com 01.04.2018 RECEIVED Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 JAN 0 2018 Re: Application for Permit to Drill MPU F-107 AOGCC Dear Commissioner, Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point'F' Pad, well slot 107. Drilling operations are intended to commence approximately Jan 20, 2018, pending rig schedule. MPU F-107 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. F-107 is part of a five well program targeting the OA sand. The directional plan is a catenary wellpath 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 4.5" slotted 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 F-107, 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 777-8431 or mmyers@hilcorp.com. i Sincerely, 11.16 tg" u,„ Jbe_ngel flAb Drilling Engineer 3�1n CU Hilcorp Alaska, LLC Page 1 of 1 • Hilcorp Alaska, LLC Milne Point Unit (MPU) F-107 Drilling Program Version 1 1/4/2018 • • Milne Point F-107 SB 0 Producer Hilcorp Drilling Procedure Energy Company 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 13.0 Cement 9-5/8" Surface Casing 21 14.0 BOP N/U and Test 26 15.0 Drill 8-1/2"Hole Section 27 16.0 Run 4-1/2"Production Pre-Drilled Liner(Lower Completion) 31 17.0 Run 7-5/8"Tieback 36 18.0 Run ESP Assembly-Upper Completion 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 46 26.0 Innovation Rig Layout 48 27.0 FIT Procedure 49 28.0 Innovation Rig Choke Manifold Schematic 50 29.0 Casing Design 51 30.0 8-1/2"Hole Section MASP 52 31.0 Spider Plot(NAD 27) (Governmental Sections) 53 32.0 Surface Plat(As Built) (NAD 27) 54 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart 55 34.0 Drill Pipe Information 5" 19.5# S-135 DS-50 & NC50 56 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU F-107 • Pad Milne Point"F"Pad Planned Completion Type ESP on 2-7/8"Production Tubing Target Reservoir(s) Schrader Bluff OA Sand • Planned Well TD,MD/TVD 12,688' MD/4,132' TVD PBTD,MD/TVD 12,678' MD/4,132' TVD Surface Location(Governmental) 1488'FSL, 3246'FEL, Sec 6, T13N,R10E,UM,AK • Surface Location(NAD 27) X=541,322.13,Y=6,034,937.43 Surface Location(NAD 83) X= 1,681,353.17 ,Y=6,034,690.03 Top of Productive Horizon 1108'FSL, 65'FWL, Sec 6,T13N,R10E,UM,AK (Governmental) TPH Location(NAD 27) X=539,473.97 Y=6,034,547.16 TPH Location(NAD 83) X= 1,679,505 Y=6,034,299.72 BHL(Governmental) 574'FSL, 1435'FEL, Sec 7,T13N,R10E,UM,AK BHL(NAD 27) X=543,191.99,Y=6,028,753.3 BHL(NAD 83) X= 1,683,223.10,Y=6,028,505.93 AFE Number 1714019 AFE Drilling Days 18 days AFE Completion Days 6 days AFE Drilling Amount $3,910,736 • AFE Completion Amount $1,576,047 • AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1397 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1800 psig ' Work String 5" 19.5# S-135 DS-50 &NC 50 (Weatherford Rental) KB Elevation above MSL: 26.5 ft+ 10.9 ft=42.2 ft • GL Elevation above MSL: 10.9 ft • BOP Equipment 13-5/8"x 5M Annular,(3)ea 13-5/8"x 5M Rams Page 2 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcoip Alaska, LLC H ilc*rp Changes to Approved Permit to Drill Date: 1/3/2018 Subject: Changes to Approved Permit to Drill for MPU F-107 File#: MPU F-107 Drilling and Completion Program Any modifications to tv1PU F-107 Drilling &Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the BLM9 and AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section . _ (psi) . . Cond 20" 19.25" - - - X-52 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 DWC 5,750, 3,090✓ 916 Tieback 7-5/8" 6.875" 6.75" 7.625 29.7 L-80 v Mis L 6,890 4,790 683 4-1/2" 8-1/2" drilled 3.920 3.795 4.714 13.5 , L-80 H ydril 9020" 85401 279 5 liner 4.0 Drill Pipe Information: Hole OD ID (in) TJ ID TJ OD Wt Grade ConnMIXSe;� " . (in) (#/ft) ) (Max) (k lbs Surface& 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k1b Production 5" 4.276" 3.25" 6.625" 19.5 S-135 NC50 31,032 34,136 560k1b All casing will be new,PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Rev 0 January 2018 • S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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 Detailed Daily Plan Forwards • Distributed to jengel@hilcop.com and pmazzolini@hilcop.com 5.3 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.4 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.5 EHS Incident Reporting • Health and safety:Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drilling Manager&Drilling Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 5.6 Casing Tally • Send final"As-Run"Casing tally to pmazzolini@,hilcorp.com�jengel@hilcorp.com and cdinger@hilcorp.com 5.7 Casing and Cmt report • Send casing and cement report for each string of casing to pmazzolini@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.8 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini(c@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan@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 Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@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 cdinger@hilcorp.com Page 5 Rev 0 January 2018 TO • 11 Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 6.0 Planned Wellbore Schematic n Milne Point Unit Well: MPU F-107 PROPOSED SCHEMATIC Last Completed:TBD PTD:TBD Ilili,orn 41.1.1,4.1.1,4 TREE&WELLHEAD 1 Ortg.KB Bev.:26.5'/GL Bev.:10.8. . Tree FMC 2-9/16" 5M Well head FMC Gen V 20" t., 16.• • 1 2 1 OPEN HOLE/CEMENT DETAIL tv Conductor 3270 ft3 12-1/4" Planned Pump Vol:680 bbl v 2-7/3" . ,,.: 8-1/2" Cementless Pre-Drilled Liner in 8-1/2"hole ; t CASING DETAIL Z•. 10 r. Size Type Wt/Grade/Conn Grade/Conn ID Top B ,r1 6 P F 320 Conductor N/A/X-52/Weld N/A Surface 136.5' N/A , .. 9-5/8' Surface 40/L-80/DWC/C 8.835 Surface 6,223' 0 0758 0' 7-5/8" Tieback 29.7/L-80/Vam STL SMLS 6.875 Surface ±6,070' 0 0459 956 ES , .: 4-1/2" Pm-Drilled Liner 13.5/L-80/Hydril 625 3.920 ±6,07012,6613' 0149 Oerrnert0 ,:. •••• -2507 TUBING DETAIL ....,,, "4 2-7/8" Tubng 6.5 EUE-8rd 2.441 Surface r‘ .stl 3/8" . Dual Cap String L-80 / / 3/8" N/A 5 Surface D" 00058 .CO 35,CCC' . NIA Cc4 9 4 .,5i 51 WELL INCLINATION DETAIL KOP @ 275' mei ij Max Hole Angle"90 deg..@ 6,730'MD to TD %.+., JEWELRY DETAIL \..4, F ;0 , - No. i Top MD I Item ID ,,..: ... . ' Upper Completion 'N V 7-5/13" 1 r'-`7)() I 1 Tubing Hanger 2.441" , 1 2 3140' GLM BK-2 Latch,1"Packing Bore 2.347" 3 34,773' GLM BK-2 Latch,1"Packing Bore 2.347' , t.'• v4 4 ±4.880' XN Nipple 5 15,000' Base ESP Assembly Lower Completion 1C ±6,070' BOT ZXPN LT Packer/Flexlock Liner Hanger 7"x 9-5/8" 6.200" * * ' 11 ±6,065' 7-5/8"Tieback Assy. 6.151" li ^•,! iaih.....7L...w.,v ' 0 Ot,GI°6 12 ±6,070' 7"H563 x 4.5"HTTC L-130 X0 3.900" I "c.r. 41 14 312,600' 4-1/2"Drillable Packoff Sub 2.400" 'la 15 312,686' AIN Valve LTC13xe.(15"Ball on Seat/Closed) 13 II) t• 4-1/2"SOLID LINER DETAIL 4-1/2"Pre-Drilled LINER DETAIL ' I 1 . I.' ......,, Sal id 1/4.'rift ME Top(MD) Btm(MD) _Its Top(MD) Btm(MD) Liner TBD TBD IDetil 44/z. 14 GENERAL WELL INFO , Shoo Iif API:TSD Completion Date:TBD --17FR.• TD=12,6813(MD)/TD=4,132'(1VD) PBTD=12.6E6'(MD)/PBTD=4,132'(7VD) Created By:001-4-2015 Page 6 Rey 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 7.0 Drilling / Completion Summary MPU F-107 is a grassroots ESP producer planned to be drilled in the Schrader Bluff OA sand. F-107 is p. of a five well program targeting the OA sand. The directional plan is a catenary well path build, 12.25"hole with 9-5/8"surface casing set into the top o i the Schrader Bluff OA sand. An 8.5"lateral section will then be drilled. A 4.5"pre-drilled(slotted) liner will be run in the open hole section and the well produced with an ESP assembly. Drilling operations are expected to commence approximately Jan 20,2018. • The Innovation Rig will be used to drill and complete the wellbore. Surface casing will be run to 6,220' MD/4,108' TVD and cemented to surface via a 2 stage primary cem-nt job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observe., a • Temp log will be run between 6— 18 hrs after CIP to determine TOC. 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 facil' . • 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 4-1/2"production liner(slotted) • 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 Rev 0 January 2018 Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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 'th 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 F-107. Ens l e to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipme t 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 th well bore,AOGCC is to be notified and we must test all BOP components utilized for well contra prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BO" test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid progra 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 • 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 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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 btm 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@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email:guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://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 Rev 0 January 2018 S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 F-107 will utilize a newly set 20" conductor on F Pad Expansion. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Dig out and set impermeable cellar inside of existing cellar. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Install FMC landing ring. 9.5 Insure (2)4"threaded nipples aye installed on opposite sides of the conductor with ball valves i n each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off. 9.6 Level pad and ensure enough room for layout of rig footprint and RM. 9.7 Ensure rig mats cover the entire footprint of rig. 9.8 Confirm that the rig is over the appropriate well slot. 9.9 MIRU Innovation Rig 9.10 Mud loggers WILL NOT be used on either hole section. 9.11 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 9.12 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.13 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 Rev 0 January 2018 • S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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 in Sec 21 of 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. 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 Rev 0 January 2018 0 S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 10.5 Rig & Diverter Orientation: 1 I I F-106i I .0.--.` F-107 ,i • F-1061 F-1081 ` + F-107 • I F-109 •• F-110i 75'Radius Clear of Ignition Sources — Diverter Line .�, / *Drawing Not To Scale r4 r',/, a MPU F Pad Expansion Page 12 Rev 0 January2018 • s Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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 component. that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure Gyro MWD is R/U and operational. Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • 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# S-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 TD as per geologist and drilling engineer. • Monitor the area around the conductor for any signs of broaching. If broaching is observe., 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. Ensure shaker screens are set up to handle this flowrate. • Ensure to not out drill hole cleaning capacity,perform clean up cycles or reduce ROP if packoffs seen. • Keep swab and surge pressures low when tripping. • Ensure to leave a"Pump Tangent" section that is approx. 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 shale shakers are functioning properly. Check for holes in screens on connections. • maintain hole stability,MW as necessary to ensure MW is at a 9.2 at TD. • • TD the hole section just into the Schrader Bluff sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. • Take MWD surveys every stand drilled(60' intervals). • 0 2 1 Page 13 Rev 0 January 8 • S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company • Watch returns closely for signs of gas when near the base of the permafrost and circulate o t all gas cut mud before continuing to drill. There have been no indications of hydrates on . y of the "F"pad wells to date. • 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. 11.5 12-1/4"hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1)ppg above highest anticipa t-d MW. We will start with a simple gel +FW spud mud at 8.8 ppg and TD with 9.2+ppg • • PVT System: MD Totco PVT will be used throughout the drilling and completion pha•e. 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 syste with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all ti es 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( 0 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/Xi CIDE 207 MUST be made to control bacterial action. • 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: 8.8-9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8-9.2 75-175 20-40 25-45 <10 8.5-9.0 <_70 F Page 14 Rev 0 January 2018 Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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; pump sweeps, CBU, and POOH to the 20" conductor shoe. AV- 11.7 ✓11.7 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 —4 B/U have been circulated to get hole as clean as possible. • 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 11.9 No open hole logging program planned. Page 15 Rev 0 January 2018 S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 Make a dummy run with the 9-5/8" casing hanger. 12.3 R/U Weatherford 9-5/8" casing running equipment(CRT & Tongs) • Ensure 9-5/8"DWC 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. 12.4 P/U shoe joint, visually verify no debris inside joint. 12.5 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). Install (2) centralizers on shoe join over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end&thread locked. Install (1) centralizer mid to o e over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. ,.� 0110%1 VAN • (1) Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 Rev 0 January 2018 f S Milne Point Unit IIF-107 Producer Drilling Procedure Hilcorp Energy Company 12.6 Float equipment and Stage tool equipment drawings: "A II Overall Length —, Type H ES Cementer 1 8 Will Part . Mie.H)After0riout SO No. C 110151. No Max.Tool OD D Hamm ES-II Running Order Opening Seat ID A I Closing Sleeve No.Shear Pins ® E Closing Seat ID • I Opening Sleeve No.Shear Pins Plug Set ES-0 Cementer I mmilint. ES Cementer Part No. Depth —hi_` j SO No. noirgoy Closing Plug t w year = < Baffle Adapter(if used) OD Shut OffIII IDDepth Immo- Opening Plug OD Plug $ameAdapor ■ OD a 1 - 1 ' Bypass or Shut-off Baffle �, E ii'1 ID IMPain Plea I Depth Shut-off Plug t Float Collar Depth ipPass Wee IIIIIIIIIII II OD float nL Float Shoe Depot Bypass Plug ( (if used) Hole TD Hon Sim OD **Reference Camp sin Sales Manual Section 5 Page 17 Rev 0 January 2018 I TMilne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 12.7 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. • Install (1) centralizer every joint— 1000' MD from shoe, 1 centralizer every 2 joints to,,, 2000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu 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. 12.8 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100' TVD below the permafrost(—S 2,500' MD). • Install centralizers over couplings on 5 joints below and 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 p.i. 9-5/8" 40# L-80 DWC Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 29,800 ft-lbs 34,800 ft-lbs Page 18 Rev 0 January 2018 Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C Casing 9-5/8 in 40.00 lb/ft(0.395 in) L-80 standard Material L-80 Grade ariftrn 80,000 Minimum Yield Strength (psi) 111111111111111111111111111111,VSA 95.000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX 77041 Phone:713-479-3200 9.625 Nominal Pipe Body O.D. (in) Fax:713-479-3234 8.835 Nominal Pipe Body I.D.(in) E-rnail:VAMUSAsaleaOvam-usa.com 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight (Ibs;ft) 38.97 Plain End Weight(lbs./ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter(in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 916,000 Joint Strength (lbs) 16.360 Reference String Length (ft) 1.4 Design Factor 947,000 API Joint Strength (lbs) 916,000 Structural Compression Rating (lbs) 3,090 API Collapse Pressure Rating (psi) 5,750 API Internal Pressure Resistance (psi) 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft] TMX'` Appoximated Field End Torque Values 29.800 Minimum Final Torque (ft-lbs) 34,800 Maximum Final Torque(ft-lbs) 39,800 Connection Yield Torque (ft-lbs) Page 19 Rev 0 January 2018 Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy company 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 MAI water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 Rev 0 January 2018 i Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 13.0 Cement 9-5/8" Surface Casing 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 pump 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 iron 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 Pt 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 Total Cement Volume: 5 G, Section: Calculation: Vol (BBLS) Vol(ft3) 12-1/4" OH x 9-5/8" Casing (5,220'- 2500') x .0558 bpf x 1.3 = 197 bbls 1108 ft3 annulus: 9154 Total LEAD: 197 bbls 1108 ft3 .- 12-1/4" OH x 9-5/8" Casing (6220'- 5220')x .0558 bpf x 1.3 = 72.5 bbls 407.3 ft3 annulus: 9-5/8" Shoe track: 120 x .0758 bpf = 9.096 51.07 Total 15.8 ppg TAIL: 81.6 bbl 458 ft3 �`C` • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company Cement Slurry Design: Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System Density 12.0 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed 21.13 gal/sk 5.04 gal/sk Water 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 contin e with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out o 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 ve accurate using 0.0625 bps (5"liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 9 13.11 Displacement calculation: 6100' x .0758 bpf=462.38 bbls ei 80 bbls of water must be left across stage tool to ensure proper operation once opened. 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,±4.5 bbls before consulting with Drilling Engineer. Page 22 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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. 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 V pressure if pressure must be held, this is to ensure the stage tools 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 Ry/,7 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 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until 1 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 2nd 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 Total Cement Volume: S+‘ Section: Calculation: Vol (BBLS) Vol (ft3) 20" Conductor x 9-5/8" (110') x .27 bpf x 1 = 29.7 bbls 166.7 ft3 casing annulus: 12-1/4" OH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 bbls 1778 ft3 annulus: Total LEAD: 346 bbls i 1943 ft3 12-1/4" OH x 9-5/8" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ft3 annulus: Total TAIL: 55.8 bbls vi 314 ft3 2. Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L Type I/II Density 11.1 lb/gal 14.5 lb/gal Yield 4.3279 ft3/sk 1.39 ft3/sk Mixed Water 21.405 gal/sk 6.8 gal/sk Page 24 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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 ou 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 si.e outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump o t 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 sho ld 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 close... Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage too has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips and L/D landing joint. 13.30 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packof . Run in lock downs and inject plastic packing element. Pressure test packoff. 13.31 Lay down landing joint and pack-off running tool. 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& Ue 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 of job.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 jeneel@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy cerannny 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. 14.2 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. V • Single ram should be dressed with 2-7/8" x 5.5" VBRs X9/97 • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to OV mud cross). • Install (1) manual valve &HCR valve on choke side of mud cross. (manual valve closest ti mud cross) 14.3 Run 5" BOP test assembly, land out 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 leave "B" section side outlet valves open during BOP testing so pressure does no build up beneath the test plug. 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 10" ID 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 Install 5" liners in mud pumps. Page 26 Rev 0 January 2018 410 S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit& 1.15° PDM) 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 tagged on morning report. 5.4 R/U and test casing to 3000 psi/30 min. Ensure to record volume/press e and plot on FIT graph. AOGCC reg is 50%of burst=6870/2 =—3500 psi, but max test pressure on the well is 3,000 psi. Document incremental volume pumped (and subsequent pressure) and volume returned. 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. 15.8 POOH & LD Cleanout BHA 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 th.t 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# S-135 DS50 &NC50. • Run a ported float in the surface 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)pp above highest anticipated MW. • 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 Page 27 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company running to near the end of the shakers. It is okay if the shakers run slightly wet to ens e 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 hi:,h vis sweeps, instead use tandem sweeps. Ensure 6 rpm is> 8.5 (hole diameter) for 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 OA Lateral 8.9-9.5 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Product Concentration/Function Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N-VIS 1.0— 1.5 ppb N-DRIL HT PLUS 5 ppb BARACARB 5 4 ppb BARACARB 25 4 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.15 b 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid 15.13 Begin drilling 8.5"hole section, on-bottom staging technique: Page 28 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company • 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 pulsed up real time. • 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. 15.8 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 connectio . • Keep swab and surge pressures low when tripping. • Take MWD surveys every stand. • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD &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 OA1 & 0A3 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% 15.9 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight"kick-off ramp" in wellbore ahead of the fault s 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 stri 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. 15.10 At TD, CBU at least 4 times at maximum circulation(500 gpm) and rotation(120 rpm). Pump tandem sweeps if needed • Once well has TD'd the production lateral, swap to the completion AFE 15.11 TOH/BROOH with the drilling assembly to the 9-5/8" casing shoe. If backreaming is necessary: Page 29 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company • Circulate at full drill rate (350-550 gpm). • 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 and circ at least 2 b/u once at the shoe. 15.12 Ensure all mud pumped downhole passes production screen test prior to running pre-drilled lin-r. 15.13 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR+Res). There will not be any additional logging runs conducted. Page 30 Rev 0 January 2018 • • IIMilne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 16.0 Run 4-1/2" Production Pre-Drilled Liner (Lower Completion) 16. . Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2"production screens, the following well control response procedure will be followed: • P/U&M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in op-n position on top, 4-1/2"handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" screen. p • 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. n the event of an influx of formation fluids while running the 2-3/8" inner string inside the 4- 1/2"production screens: • P/U &M/U the 5" safety joint(with 4-1/2"x 2-3/8"triple connect crossover installed on 1 • bottom, TIW valve in open position on top, 2-3/8"handling joint above TIW). M/U 2-3/8' I/ and then 4-1/2"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. RAJ 4-1/2"pre-drilled liner running equipment. • Ensure 4-1/2" 13.5 Hydril 625 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 4-1/2"pre-drilled production liner • Use API Modified or"Best 0 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. • 4-1/2"pre-drilled liner will auto—fill • 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 • Swell packers placement±40' 4-1/2" 13.5 #Hydril 625 Torque OD Minimum Maximum Yield Torque 4.5" 8,000 ft-lbs 12,800 ft-lbs 15,000 ft-lbs Page 31 Rev 0 January 2018 ir • IIIMilne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company Wedge 625® PrROO.:10/31/2017 Outside Diameter 4,500 in. Min.Wall 87.5% Thickness (•)Grade L80 Type 1 Wail Thickness 0.290 in Connection OD REGULAR COUPLING PIPE BODY at Option Body:Red 1st Band:Red illW Grade 180 Type 1' Drift API Standard 1st Bard:Brown 2nd Band: 2nd Band:- Brown arta Band:- 3rd Band:- Type Casing 4th Band:- GEOMETRY tvcm.Ina'.00 4.500 in. Nominal Weight 13.50 kWh. Drift 3195 in. Nominal ID 3.920 in. Wall Thickness 0.290 in. Plain End Weight 13.05 Its:ft 00 Tolerance API PERFORMANCE Body Yield Strength 307 x1COl)lbs Internal Yield 9020 psi SMS 80000 psi Collapse 8540 psi GEOMETRY Connection 00 4.714 in. Connection ID 3.849 M. Make-up Loss 4.830 in.. Threads per in 3.59 Connecron OD Option REGULAR PERFORMANCE Terson Efficiency 91.0% Joint Yield Strength 279.370 x1003 Internal Pressure Capacity 9020.000 psi lbs Compression Efficiency 94.5% Compression Strength 290.115 K1030 Max.Allowable Bending 73.7°`l0C ft Its External Pressure Capacity 8540.000 psi MAKE-UP TORQUES 7 Minimum 8000 ft-Its Op'drrsum 9600 ft-lbs Maximum 12800 ft-Ibs OPERATION LIMIT TORQUES operating Torque 12800 It-lbs Yield Torque 15000 ft-lbs Page 32 Rev 0 January 2018 • • Milne Point Unit d DrillingF-107 Procedure Hilcorp Energy Company 4-1/2" Lower Completion Running Order • 4-1/2"Float Shoe, BTC box (Bakerlok all 4-'/2" shoe track connections below the last Hydril 62 connection) • 4-'/2" WIV (wellbore isolation valve), BTC box x pin • 4-1/2" spacer joint, —30 - 40', IBT-M box x BTC pin • 4-'/2" Drillable Pac Off Sub, IBT-M box x pin • 4.5" 13.5#Hydril 625 Box X 4.5" 12.6# IBT Pin crossover • 1 joint 4-1/2" 13.5#/ft L-80 Hydril 625 Liner(optional) • 4-1/2" 13.5#/ft L-80 Hydril 625 Pre-drilled liner from 6,220' to 12,688' MD • Joints of 4-1/2" 13.5#/ft Hydril 625 L-80 Liner(liner lap) as needed • 4' 4.5" 13.5#Hydril 625 Box X Pin pup joint(safety joint) • 7" 26#HYD 563 Box Up and 4.5" 13.5#Hydril 625 Pin crossover • Flex Lock hanger w/7" 26#DWC/C Pin Up and 7" 26# HYD 563 Pin Down • 7.625" 29.7#Vam Top HT Pin X 7" 26#HYD 563 Box crossover • Baker ZXPN Liner Top Packer w/7.625" 29.7#Vam Top HT Box 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. 16.7. R/U false rotary and run 2-3/8"4.6#Inner String 16.8. Before picking up Baker ZXP liner hanger/packer assy, count the # of joints on the pipe deck o make sure it coincides with the pipe tally. 16.9. M/U Baker ZXP liner top packer to inner string and 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", 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 weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure clear flow path exists. 16.11. RIH w/liner on DP no faster than 30 ft/min—this is to prevent buckilng the liner and drill stri g. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. Page 33 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 16.12. The inner string will prevent the DP from auto filling. Fill DP with PST passed 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+ SIO depth every stand. Record torque value if it becomes necessary to rotate the strin:, to bottom. 16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 0, & 20 rpm 16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensur- 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. 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. 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 e swell packers (if run). Do not exceed 1,600 psi while circulating as noted above. Note all loss-s. Confirm all pressures with Baker. 16.20. Monitor the returned fluids carefully and when no more filter cake appears at the shaker begin pumping SAPP pill. 16.21. Mix and pump 40 bbl 10 ppb SAPP pill. Keep circulation rate low to keep from packing off • around the ICDs (if run). Monitor shakers for returns of mud filter cake and calcium carbonat:. Circulate the well clean. 16.22. Repeat pumping SAPP pills as needed until the wellbore is clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is beim: removed, including an increase in the loss rate. 16.23. Displace entire wellbore to completion fluid (-9.2 ppg KC1/NaC1). Pump at 10-12 bpm. Moni or the returned fluids to ensure as much mud has been removed from the wellbore as possible. 16.24. 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. Page 34 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 16.25. 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. 16.26. Continue pressuring up to 2700 psi to set the ZXPN liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the Flexlock liner hanger to ensure the HRDE setting tool is in compressi on for release from the ZXPN liner hanger/packer. Continue pressuring up 4500 psi to activate th- hydraulic pusher tool to set the ZXPN packer. This will also release the HRDE running tool. 16.27. 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 rpt and set down 50k# again, 16.28. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.29. 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. 16.30. P/U above liner top packer and displace well to completion fluid. 16.31. POOH, L/D and inspect running tools. If settinv of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8"inner string. k/ 16.32. RIH w/remaining DP out of derrick and L/D same. Page 35 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 17.0 Run 7-5/8" Tieback 17.1 If necessary, RIH with mule shoe on 5" DP to Liner Top and circulation Liner Top and SBE clean. 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#VAM STL SMLS tieback to position seal assy two joints above tieback sleeve. Record up & down weights. • Following running procedure outlined above. Page 36 Rev 0 January 2018 I • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: ST-L Casing 7-5/8 in 29.70 ILA(0.375 in) L-80 STANDARD Material L-80 Grade 80,000 tolinimum Yield Strength (psi.) _ 95,000 Minimum Ultimate Strength(psi.) U SQA Pipe Dimensions VAM USA 7.625 Nominal Pipe Body O.D. (in.) 4424 W.Sam Houston Pkv,l.Suite 15F: 6.875 Nominal Pipe Body I.D. (in.) Phone.Houston,1 479--TX 3200 0.375 Nominal Wall Thickness(in.) Fax:713-479-3234 E-mail:'VAMUS.Asaleesvan-usa.corn 29.70 Nominal Weight(lbs./ft) 29.06 Plain End Weight(lbs./11.) 8.541 Nominal Pipe Body Area (sq. in.) Pipe Body Performance Properties 683,000 Minimum Pipe Body Yield Strength (lbs.) 4,790 Minimum Collapse Pressure(psi.) 6,890 Minimum Internal Yield Pressure(psi.) 6,300 Hydrostatic Test Pressure(psi.) Connection Dimensions 7.625 Connection O.D.(in.) 6.782 Connection I.D. (in.) 6.750 Connection Drift Diameter(in.) 4.39 Make-up Loss(in.) 5.550 Critical Area(sq. in.) 65.0 Joint Efficiency(%) Connection Performance Properties 444,000(1)Joint Strength(lbs.) 527,000(2) Reference Minimum Parting Load(lbs.) 10,910 Reference String Length(ft) 1.4 Design Factor 266,000 Compression Rating(lbs.) 4,790 Collapse Pressure Rating(psi.) 6,890 Internal Pressure Rating (psi.) 18.8 Maximum Uniaxial Bend Rating [degreesi100 ft] Recommended Torque Values 4,600(3)Minimum Final Torque(ft.-lbs.) 6,000(3)Maximum Final Torque (ft.-lbs.) Page 37 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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 ol f pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — 10k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 P/U 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. 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 Run in hanger lock downs. 17.19 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. Test void to 3000 psi/ 10 min. 17.20 R/D casing running tools. , e.:)\ 17.21 Test 7-5/8"x 9-5/8"production annulus to 1000 psi/30 min. 17.3 POOH and stand back 2-7/8"tubing for ESP run. Page 3 8 Rev 0 January 2018 41110 Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 18.0 Run ESP Assembly — Upper Completion 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 cabl: will place the splice between the discharge head and the 10' handling pup collar. A Centrilift r-p 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 e 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 @—5,000' MD • 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 1"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 o Check the conductivity of electric cable every 2,000' and every new splice while running in hole. Page 39 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company o Function test the capillary tube every 2,000' when checking the conductivity of the electric cable. o Use Cannon clamps on every joint to secure the capillary tube. o Install heat trace cable at 3500' MD. Install continuous flat guard clamps on entire heat trace cable. o The make up 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 1, 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 w th band/clamp summary. 18.8 Install a brass-shipping cap on the ESP penetrator. Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. 18.9 RILDS and test hanger. 18.10 Install BPV and N/D BOP. 18.11 N/U tree/adapter and test tree. Terminate the capillary tubes. Pull BPV. 18.12 Circulate diesel freeze protection down 2-7/8"x 7-5/8" annulus (Volume should equal capacit of tubing to 2500' +tubing annulus to 2500'). Connect IA to tree and allow diesel freeze prot:ct to "U-tube" into position. 18.13 Set BPV. Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. RDMO 19.0 RDMO 19.1 RDMO Innovation Rig Page 40 Rev 0 January 2018 • i Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 20.0 Innovation Rig Diverter Schematic Q a, firth 171111111thM ."--------13-5/8'SM Control Technology Annular BOP L thCI0 2 [1.7 ® �"---13-518'SM Control o L Technology Double Ram 1 ® _ 2 *ti IF�—t 3.118'KM line '•} -1 L ;,ti,:;. le ----------3-118'Choke Line o 2 — 13-51r SM Controol—" ® �- Technology Sthcie Ram �__ � �,.,.. 13-5/8'x 5M —II rle un -----"'--15 Diverter Lne ss j /�, ,;;X13-5/8'x5M `L¢ 1 1, 1 Ii ... w \-2-1116'x5M 20'Casing Page 41 Rev 0 January 2018 0 S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 21.0 Innovation Rig BOP Schematic o :if III tlMIl ltlt1-il� m Il 1 `"----13-518"5M Control Technology Annular BOP I iiii L .off Fod — ,11 cZN —'`''�--13-5/8"5M Control E )E • , Technology Double Ram di 3-1/8"Kill Linevtii a �)tkiiiy1 atc--, �,;;,� ---------3-1/8"Choke Line r 7 - 111 iii c= ----------13-5/8"5M Control i Technology Single Ram 13-518"x5M l 11"x5M iiiiih Is ilts 1] III r . . 9-5/8"DBL D Seal -1— t"moi lki II ,„ 2-1116"x5M �R I i Alb 13-518"x 5M Casing Hanger _1 t■ . i D r . I ; S-22 1 w• 'w 13-518"NOM 9-5/8"BTC Btm x 2-1116"x 5M 10.5"-4 SA Pin Top W/Primary Seal 20"Casing 9-5/8"Casing Page 42 Rev 0 January 2018 • Milne Point Unit IIF-107 Producer Drilling Procedure Hilcorp Energy Company 22.0 Wellhead Schematic . • 1 . AACPTEP,4-4-M _ Tu61tY:NdoA;EP,fC-1A EMS_ ri'T 51CC OTM E a r•l6-SP STOP C P A IJ-9E0 80r1. 006223 crT-leg 00 EN a 1.Z 8786-1,04 6TM P a'� 0 P111033-0002 '2 9T6 TOP, 1,5 7,o5 EN P -TLt81Nr II:A6 5ECTICPI ASST. i Pt04700388T -`z+ s TN3..' 10.380 1.11•90PE. . _ - sy 11-SP STDD 8104 .'"#,.- x & 14.51 FLO TOP .47 3,.... T f -- P120190-7502 I x3.03 I. '71 1 ,r-- 1,16-54 M120 PL.5 C. I r IA 26.47 E .,,_ 1 . ,,.._.,. .: St,i@ CIL•Orr,175___.. 1 CJ80 54YAt. , T '4 r,,-utneEAL.LEG tI 0E A95'r, 12-150.016 a ..«1 t .„-,,,,., t0.3C0 140L, •,... + t _. �41.�Nf��l 12 6NSH NOY TAPER Y-TO-,Y 5EAL gnu ===.> :www, il ,,,,,,m- r I1-SF ELc +CP 1 ,IF 51 11PI0010111365 1 I IUD le 0 Ilii SMI `ti,154-5r 0120 PUSS Cs CASING NIHGEP,E-31--•-.- 1 10,38 x T 1 ,, \;', 12-+033-112 • 22.T5 a 1 r 0A mm.1 ' ._6-... �CA51rl:HANGER.MANORfL.rLUTEO !______ ._ • F 10,360 E03•33.• BELLr/1PPLL. I T 754 563 25.0 L®rr1'+r10!L 9 5:9 509 yY' TR 06 C#0(.,`3µA*2r'-LM 2311:TOP I.rµ(1Y TAFER M-TO-M 5£Al TOR • 1 ..1 .1000 24695 P118 3 3 4-0045 1L -^I'154 NA(IIEP 31A2f5P£t,LANCING PING, 10.2s 'EUTEO,$t 15.6?540%I_. .,.469.3425 154 563 ICU54 1 (TII' t -- 60.750-4 SAW-ZS-LH tr1, CASING NANCEP,1^21--�,4 ilelI 1,y....... NJ 5 4E4 NOM M-TO-M SEAS,PREP TOP 1 .5.25 FP&a 5 5V5 _ lel - PIANO 174693 a STEP-00011 021 _ 12..096]-664 1 --I,&'CING PING I i : +6 SON VII PREP E ".'.,""'^ 16.00 51.I re 15' TOP. 14.60 ID r +5.23 EON& 13-140-660 7 9 5%8'GC .. .. _ CASINO II.� I .. 4 bay.K GEN 5 SLIMM HOLE 2_ X P F. Z _- 2 F '_ ._ - _ 2 OL10TE 18.0131T PErr 00(1 00153363 PRIVATE AND CONFIDENTIAL OF5CPtPT10N 3R11,+: 1141.111 KIRZ 1 (1-0 Id IN 0111 K,A3 I00.111Nt le6 0(4(42 .".""...'"...'.....t".M‘...'.....1.u.... SURFACE WELLHEAD LAYOUT saarT,vs GCC., 140Th, r .__-..._.,^...._ MVO,61 1,n,.10442'II w,WI(5 eto(oara.l:111 t k r^ Z.MARQUEZ. IQ-25-1 7 5 54.O�n,IA vie wa co a,Parte P19x re LOAM(PNnme f4. 4 / k 7 )5 A 4.G „„,,....,,,•••II,11Uwi4NC.411441,r4.a01 I:.ttrrle0 m CASING PROGRAM., GESI2n AEvII,11 ._..__$ab 5.40151:2 PEt12(411 052(0(141 IS AO'tTIMNT 10 THE 150001(5. _._..,...,,,--AOINtc:ikN-ME R-.3EII1RWOU,, II-55P- 5 4 1116-5!. C.MchatS I€1 25 ( tdd ru1.5TMNe+060,,1n.NOt>.L:10(111 atmaaitt yr 11114 M*IN4TACTllPIr4.PPROVA., 6AT2, VII(AMBER FEY. (MOST'*IL a 1.1116.1111/0 104,150110 LY$0f.10 1411 I0-25-I`i A 3 M.PTri erect. 1.F1 +,..satyr'$014,1Jr et�Na .U11tL VV. MY V 344 In 141w1F.tT,{iR rP w,yn4P K . ♦'CIINVEr alt 04,{, •141.1,Nuvec. 5NEi3 I { 11111/14 51 Pe1a1 INTIM 1,1,-n,...pp.,.II 1x1N4*IQ- j.[Afb A '0 25 .1 i DM 00272�1an -- ((P P1cni T<1.,wrui Page 43 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 23.0 Days Vs Depth MPU F-107 SB OA Producer Days vs Depth MPU F-107 SB OA Producer 2000 ;i-._.`_- G ' � � I 4000 f � I 44 � � t 5000 _ _. . --__ _____._. ...._ I � c3 8000 2 100o0 ` i I I a j 12000 I j 14000 0 5 10 15 20 25 30 I ? Days Page 44 Rev 0 January 2018 • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 24.0 Formation Tops & Information Formation Top MD TVDSS TVD SV4 2000 -1608 1645 Base Permafrost 2343 -1811 1848 SV1 2712 -2030 2067 UgnuLA3 4461 -3374 3411 Schrader NA 5398 -3906 3943 • Schrader OA 6220' -4071 4108 GENERALIZED GEOLOGICAL FORECAST SS GEOLOGICAL TVD FM LITM DESCRIPTION COMMENTS ac Gocl L NOTE:See individual Well Program for ems" Gubik specific casing design.depths,sizes. weights.grades and connections. a _ Unconsolidated coria to medium sand and small gravel with minor siltstone. 1 0 00, a:� IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE •41110m SURFACE HOLE,THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE • RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. MO* Base permafrost Irterbeds of sand.clays and siltatones with occasional 2,000' show of coal. SWABBI.G!! Sageamettok ♦■ No hydrates encountered on F-Pad wells drilled to date. Continued interbeds of sand.clays and siltstones with occasional shows of coal. Interval at H-3400 ft can be 3,000' sticky and tight Clay interbeds between 3000 and 4500 ft. Traces of pyr, +-„_ 347?- r 365' K-sxnm UGNU:Series of coarsening upward sands which are Ids CO: made up of (from top to bottom)coarse sand,fine sand, silty shale.Better developed intervening shags us you UGNU press into the L end Al(deepen. Ugnu and Schrader Bluff:Possible hydrocarbonstmllad 14ands to Sri corner of AAttne development. Northern area is s� IA 6; downetructure and wet(F-50 had oil!). 3739' M-sands I-A,13,0: 4,000' wsnm Schrader Bluff Sands: Schrader Bluff: Possible lost circulation 3300- rtiec o Continued layering coarsening upward sands as abo`e zone while drilling long strings and running 4160' EFi except more condensed and with occasional coal. INN Clay rich shale interval 4300 to 4600 rt. casing. Recommend deep setting surface Schrader Ugnu and Schrader Stuff:Possible hydrocarbons limited casing for Kuparuk long strings. Also,the eo SW comer of Milne development.Northam area is Schrader Bluff sands are a potential Bluff downsaructure aid wet(F-SC had oil!). 4000 differential stuck pipe interval if left un-cased403!•Sands: c for Kuparuk long strings. If drilling over- OA) o-sands pressure Kalubik wells,plan on covering all qac. et.r, L Surface casing point in shale below lower Ugnu sands with deep set surface�111. 4270'- A Schrader Blurt OB sand for longer reach wens. casing. Over-pressured Kalubik intervals are y40g. op of found on C,L and F pads. eabee Page 45 Rev 0 January 2018 • Milne Point Unit 11 F-107 Producer Drilling Procedure Hilcorp Emmy Company 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of to .t circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Historically, no gas hydrates have been seen on 'F' Pad. Remember that hydrate gas behave differentljr from a gas sand. Additional fluid density will not prevent influx of gas hydrates. 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 DRILTREAT to the system to help thin the mud and releas''e 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 surveys roximit . Take directionalstand,take additional p Y Y every 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 ,3,f 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 H2S events have been documented on drill wells on this pad. Page 46 Rev 0 January 2018 • S Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Enonv Company 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm durin drilling operations. 2. The rig will have fully functioning automatic H2S 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 logit ' 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 H2S. No H2S events have been documented) on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S 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. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on this pad. Page 47 Rev 0 January 2018 • Milne Point Unit ItiF-107 Producer Drilling Procedure Hilcorp Energy Company 26.0 Innovation Rig Layout 170'-3 " r 0 T c .. arrr .. r d 0 � alp, "", -- a. Na` ' © d _ — I — '_—r— x fl I o li i , ml I I 1 r,•( t* I) i ' • , v ii o _ — c; c 1 r I. sir- El V i s 56'-4" I__. ■ .111111 IIIi, 1 co an HAK 2 FOOT PRINT � __ 05/21/16 -------- o !.- \ iis ig.F►.Irsy.1 I1I1IL1iwiF! G M 113'-11i" i id„," 36'-1 " Page 48 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 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) s. 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 stabiliz-s. 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 EM at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of k ck 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 flu d; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and press e monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document increme al / volume pumped and returned during test. ` /`7,vo/ Page 49 Rev 0 January 2018 H • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 28.0 Innovation Rig Choke Manifold Schematic 7 I l 1., =1czzz � � I' 4'1 0-4 Q C— k d_ Al _ I)--Ci G— p q T II 0114 , 4--, -n n,, , 3110." niia oft `' � _=� , , , . 14,Ar* , :III ' ' .... -OA I aln _ _ n n 2-SA"16 5Ah 68209 q III t 24145-SAA 8620'4 1 Papal Ban Vah is - - - - Paw Ban Vahnss s le!rr in-.71 milU -r,„„,,,i 1 , ,41-,,,,_ _.,,, p.p. iii-o Fin "„ NC)* i 14-1a i i 4- ..,. : r /JO �n o0 0 Page 50 Rev 0 January 2018 1 ii • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 29.0 Casing Design Calculation & Casing Design Factors DATE: 010412018 WELL: MPU F-107 DESIGN BY: Joe Engel Design Criteria: Hole Size 12-14" Mud Density: 9.2 ppg Hole Size 8-1'2" Mud Density: 9.2 ppg Hole Size Mud Density: Drilling Mode MASP: 1397 psi (see attached MASP determination&calculation) v MASP: Production Mode MASP: 1397 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 Casing Section Calculation/Specification 1 2 3 i 4 Casing OD 9-50 442" Top(MD) 0 6,070 Top(TVD) 0 4,092 Bottom(MD) , 6,220 12,688 a Bottom(TVD) 4,108 4,132 JPLength * 6,220 ✓' 6,618 v" �, Weight(ppf) 40 13.5 c �1 Grade L-80 L-80 ( � Connection DWC H625 CO Weight w10 Bouyancy Factor(lbs) * 248,800 89,343 t Tension at Top of Section(lbs) 248,800 89,343 N Min strength Tension(1000 lbs) 916)A 307 V-- . ,,../ Worst Case Safety Factor(Tension) 3.68 3.44 , Collapse Pressure at bottom(Psi) * 2,029 2,041 Collapse Resistance w/o tension(Psi) 3,090 8,540' Worst Case Safety Factor(Collapse) 1.52 . * 418 • . MASP(psi) 1,379 1,379 Minimum Yield(psi) 5,750 9,0204. Worst case safety factor(Burst) 417 °"� 6.54 /' t,(ti '1 Page 51 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 8-V2"Hole Section H ilcorp MPU F-107 Milne Point Unit MD TVD Planned Top: 6220 4108 Planned TO: 12688 4132 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure OillGasiWet PPG Grad Schrader Bluff OA Sand 4,108 4,071 1791 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top(TVD) Bottom(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 L-37(1998) 8.9-9.3 Surface 7,050 1998 L-35(1997) 8.4-9.2 Surface 5,687 1997 L-34i (1997) 8.4-9.4 Surface 5,842 1997 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 for the 842"hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8' shoe considering a full column of gas from shoe to surface: 4108(ft) x 0.78(psilft)= 3204.24 3204.24(psi) -[0.1(psilft)n4108(ft)]= 2793 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 4108(ft) x 0.44(psilft)= 1807.5 psi 1807.5(psi) -0.1(psilft)"4108(ft) 1397 psi • Summary: 1. MASP while drilling 8-''2"production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 52 Rev 0 January 2018 0 Milne Point Unit II F-107 Producer Drilling Procedure Hilcorp Energy Company 31.0 Spider Plot (NAD 27) (Governmental Sections) �,... 1 � 1 , r,, �, / + L-3P -41 i , ...‘,.:•',.,,,;‘s `,,,,•j__:??•\ I 1 1 i1 }rr r(p,+r 1` / 1 ,r , , , 1 , \ `a • `�` N. + �yE11 tilt �', // r I Y` 1, 111 1 1 • . y\ ' \ t\I 1 'I 1 il, U r1 j! it / / ` A 1 1 1 -�� ` `. \`` �pht y It11Y 1fj , +, / //, 1 1 r t _ t ♦ M�` t r� 1 1` ! /I, \yam/ ' F.r7 L' ! 1 1 r \n t1 r ` + I r y CCOlzb oOOo ' '�i` ' 1 f 1 1 t ° `Sec'.6 ',....7-1"' + }I+ \ 1 Sec.5,r Sec-1 • -_-0625J�K` =z� • r, tb ‘ ,r t 1 s i , y ----, \WI: F-10?i OA Produu ) _SILL 1'. 1 I r t ' r a F-05. _.... P-. IPV F-l!)?IO-\Producer) TPH `. ' +\ + / It r r /L-u —I A • �. _...— - ' •`• _ .1._.,..�_...4- 1 i , , •_. s ADL388235 00 `e. 'ADL025509` `, '`++ Ij'11 1' w '/ / ' o .1, ` '` ss,`'1 t\t //jam, 1 ,' O 1 ` _- �+..F":"-t ` i``1l?1Y ,/n`11 /f//, c 1 ti \ �4 / tr /, / O t / i t 14s„,/11 I, ,, 1 / 0 1 ' L-a=tiae2 c111y1. ii.1 1,// 1 MILNE POINT UNI �_g. F-esPet L-'c<P1�- ``- / 'It ` ifs: r /` U013N009E o U013N010E' •-...-;". <- r', r ,>t1G _ ...::::,::0:.°000 -`•'�i'-'aLt t P �Sec.7r /r ,,r/ ��1r Sec-8 Sec. 12 ,6281 r, / r/ / .,T o _ 4 ‘‘.:11:1,.',/ i r/' p111:';r':-IiiiAl'PrIodal,-.1.1_BliL I , r,,:i i /1/ \ 3. 1,1 ,r, ../ r - yr °e ,, 1 . /• 11 I: / /, c 1 H� , ,/\y/ 2 . \L17 5 I r / ,jR'a•Lio2 i t 1 r, / __ __.:_i_,..., ., __ , _-'cf. ,-' 0 / , ;i e' -J'I I //, 1 •• . i , 1,' 1 _ i / f, t 1 rLegend 'r ++ st i / 'r \ 1'\ MPU F-107_SHL • Other Surface Holes(SHL) ' 1'Ir `\ 1 •�,, F MPU F-107_TPH Other Bottom Holes(B1-1L) /S(630)ec 8 t r ` i '.,;Sec '7 L-3 - -- Other Well Paths ' Ir , +� L_ggpg; • MPU F-107_BHL Q 1 . 1 • - Oil and Gas Unrt Boundary1• ,1 a Pad Footprint I ` / t II Milne Point Unit N MPF-107 Well 0 1,000 2,000 Mao Da:e 1 72319 wp_10 Feet Page 53 Rev 0 January 2018 • �► Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 32.0 Surface Plat (As Built) (NAD 27) • T _ T 14 N _.. Lam -T-13..4 1 I M ",1•,-.,,i• SIMPSON LAGOON I I 1 wlW =1• O / I FF-1061 rt. 1 an T}iIS PROJECT / ,- F-108i / r P *L-PA:DN7----- // VICINITY MAP / N.T.S. I / / "'I .„I '''Cry 0 /' _':49g 1' :1x$ i • Z , .. _ as +J Timothy F.Barnhart - j � T7 ' .t%:' 10200 4'� 1 i� t F' '• $4.. r. I. SEIE PLANE COCADINATES AHE NAD27,ALASKA.ZOYE 4. / LEGEND I��gll«y • •N 2. BASIS OF LOCATION IS MINE POINT F PAD CPERATCR 4. AS-BJILT CONDUCTOR MONUMENTS. SLRVFYOR'S CERIIFICATF J. BASIS CF ELEVA11CJN IS MILNE°DINT F PAD OPENA17N 111 EXISTING CONDJCTOR I HERE;IY CERTIFY THAT I AM MCNUWENT5. PRLWE4Lr RE7ISTErIED AVC LICENSEJ TD FKACTICE LANG SJR'AET1NG IN I. EIEVA.TIDNS ACE 6PX0.WEAN SEA.LENEL DATUM. THE STATE Cf ALASKA.AND THAT .. CErcETIC CDUR"ANA1ES ARE NAC27 THIS A;-LILT PERREMNTSA St.9WEY NOT UV MADE HY ME oR DEN DIRECT 6. PAD MEAN.SCALE FACTOR IS 0.119990119. GRAPHIC SCALE SUPERNISICN ANC THAT ALL 7. CRAWL EXPANSION AREA NOT SURSESES,DESIGN 4 50 100 20D CIMEVSIAND OTHER DETAILS ARE CIWENSICRS LSE FDR NSUAL PURPOSES. F 1 CORRECTT A AS OF DEc:E1wL +20, 2ul r p REFERENCE FlEID BCCM. HC17-D7,P . 60-67. (IN FEET 1 9. CA1E CF SURVEY: CECEWHET1 20,2017. 1 meh'100 R LOCATED WITHIN PROTRACTED SEC. 06, T. 13 N., R. 10 E., JMIAT MERIDIAN, ALASKA ' WELL A.S.P. PLANT GEODETIC GEODETIC SECTION PAD CELLAR NO. COORDINATES COORDINATES POSIT1ON(DMS) POSITION(O.DD) OFFSETS ELEVATION BOX EL. F_1061 Y 6,034,949.46 N= 9,575.31 70'30'23.06r 70.5064074' 1,500' FSL 10.9' 10.8' X= 541,330.84 E= 4,879.35 _ 149'39'42.711` 149.6618640' 3,237' FEL Y= 6,034937.43 N= 9,550.45 70'30'22.949" 70.5063747' 1.488' FSL F-107 10.9' 10.8' • X= 541,322 13 E= 4,879.20 1493942.959149.66193583,246' FEL' F-108• Y= 6,034,900.70 N= 9,515.39 70'30'22.589" 70.5067475' 1,452' FSL 10.8' 10.6' X= 541,296.04 E= 4,879..5 _ 149'39'43.743" '49.6621510' 3,272' FEL Y= 6,034,863.78 N=9,470,24 70'30'22.227" 70.5061742' 1,415' FSL F-109 10.9' L.7' X= 541,270.05 E= 4,879.29 1493944.5'5149.6623653' 3,299' FEL Y= 6,034,851.59 N= 9.455 43 70'30'22.108" 70.5061411' 1,403' FSL F-110i10.8' X= 541,264.64 E= 4,879.47 149'39'44.765' 149.6624346' 3,307' FEL '6U.FV KEW- kII �~°'H�LLA,Ar Hilcorp Alaska DAY[Iz/28/17 Buwia:: SHEET r�D17 MPF an MP.. F-PAD J YC �,,,,,,,,,� FM AS-BUILT CONDUCTORS 1 art OD 12/26/17,ES-ED Ft* .FCRYHWn c.WH +� ',. 1....- fro• WELLS F-1061 - F-1101 ya-AorMC. DATE PEASM Bt 7k Page 54 Rev 0 January 2018 • • Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs ND MW,ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 500 1000 1500 MPU L-46(2015) -MPU L-47(2015) 2000 MPU L-48(2015) o MPU L-49(2015) 2500 -MPU L-50(2015) +- --1 rvtPU_ F-/n'7 3000 '1 �' �° )3500 �1 4000 4500 Page 55 Rev 0 January 2018 • 14Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 34.0 Drill Pipe Information 5" 19.5# S-135 DS-50 & NC50 Drill Pipe Configuration Pipe Body OD n 5.00E 80 5b Inspection Class Pipe Body Wail Thickness {n:0.362 Pipe Body Grade Nominal Weight Designation 19.50 S-135 DSII Pipe Approximate Length ->31.5 Drill Pope Length Rangel SrnaothEdge Height amti3f32 Raised Connection GPDS50 Joint SMYS ton 120.000 Tarot Joint OD 6.625 Upset Type IEU Tool Join:ID i 3.250 N4 ax Upset DC (CT.i on,5.125 I pin Tong g Friction Factor 11.0 Box Tar.; n a 12 N.ne Taru spate rat I,ctude'tarOr aclr� Drill Pipe Performance Drill-Pipe Length Rangel ANA Performance of Drill Pipe with Pipe Body at Best Estimates Nominal ' 80%Inspection Class fxrticAl.:catra, ,,,,yr.,Coaer9 leas:arcurale; 1 ' _ ir,,cseatuke,:oDrill Pipe,4djusted Weight Ims'n1 24.11 23.29 Operational M1axTen sicm • 11-BA. Torque .n-lest rosy Fluid Displacement .xacm 0.37 0.36 Maemtur A1U- 43 1 DO Tension Only 3 560.8130 Fluid Displacement e ' ^r 0 0088 0.0085 Ccfnbre.0 Coign 39.600 410.5Oi" n- Fluid Capacity leayltt 0.71 0.70 0.72 - Fluid Capacity teelsal 0.0169 0.0167 0.0172 it Mlrerna.rn MUT 36 100 Tension Only 0 560,800 Drtt Size ;Ire 3.125 Ccrnbnedtcanna 32.100 467,400 Male 0i:tela Garret eau=42 US 001100s. ®_ holt:Drtl Crc assentl'','.Glues are Oes.e estrnanes and tray'ray oLe to pipe tat,trill Ioerarce,I0.errapia.'c;..:a:10 aria alter t Ci:rs. Connection Performance GPDS50 ( 6.625 an: OD X 3.250 in) ID ) 120,000 (mu Aapled Makeup Terson at Snculaer Tension t Connector Tool Joint Dimensions Ta Veld pl-b) it.; (Iasi Balanced 00 Ilr:6.435 Maximum Make-up Torque 43,100 Tensile Limited 1,046.900 mi 'ro t�o n co ,f rip 5.930 o ____ Minimum Make-up Torque 36,100 1.202,500 1.250.000 =r° "^cess r ' Ilene The maximum make-sp Cole anoLltl to apcllea neer 0010Ce Mlnrnr.rn Tocl.lint CO obi. 5.93 C4LnlerWfe ;In; Ncrx Ta nazi-ore connects,aaerat3cnal Iemle.a Ni_?iT41'31".CO;n-Iris:.should he angled Tool Joint Torsional Strength aseni 71,800 Tool Joint Tensile Strength Past 1.250.000 Elevator Shoulder Information Elevator OD 3132 Raised 6.812 n., SmoothEdge Height Nominal Tool Joint Worn to Bevel Worn to Min TJ OD for V 132 Raised OD Diameter API Premium Class Box OD 6.812 6.625 6.063 5.930 1 . Elevator Capacity It 1,658,000 1.4-40,233 823,600 685.600 Assumed Elevator Bore Diameter I n 1521 Nen:Elesalor ca:s:.t,eased on assume:: vaxr Bare no wear fact on a d contact Ire s or to.`00001. Null A raised ee:a0r OD Increases el-,0100 caaasrr avritot anec..rmc rrake-Lo longue. Pipe Body Slip Crushing Capacity Pipe Body Configuration( 5 tilt OD 0.362 01) Wall S-135) Nominal 80%Inspection Class API Premium Class \p,'' ktp�/ Slip Crushing Capacity al.,498.300 396.500 396.500 \' r) time 010-r.snin0 Ole o'..4!`tc don a talcu mee mill re 00r-FerNnla m olar Iran vet'Cces 0,11 Pr. Z1 i rrr]]y Assumed Sllp Length tar)16.5 Fal In to Sip,wea'Aeric OS.1_t9 00 the sip Iergr:ale trarrs,ense 0aa'actor stews.aryn es nor I.mnnre sty St mr.trG s Cram:W.1 or re sI C aes00 ani sandbar.:aeltleni 00 maul knife calxrans rine n Transverse Load Factor t K1 42 up.silo lm 0oanti,Aal canaffer.and amfr aer s Ca-s.n min ane 5ra ma-r.fartres!or axua-ai rilmatian Pipe Body Performance Pipe Bcdy Configuration( 5("t OD 0.362 t0) Wall S-135) Nominal 80%Inspector Class API Premium Class Pipe Tensile Strength 0r.i 712,100 560.800 560,800 Pipe Torsional Srengtn .ft-it,,74.1C0 58.100 58.100 iq, TJ/PipeBody Torsional Ratio 0.97 1.24 124 80%P pe Torsional Stenon n-Itsl 5g.3CIG 46.500 46.5 0 Burst son 17,105 15.638 15,638 N:n:Nominal Bursa ti Collapse afc+l 15.672 10.029 10.029 CA i AFS al a=.z b ROW ._ Pipe OD atm 5.000 4.855 4.855 '" i Wall Thickness :0l 0.362 0 290 0.290 Nominal Pipe ID lint 4.276 4.276 4276 Cross Sectional Area of Pipe Body :I,-`21 5.275 4.154 4.154 Cross Sectional Area of OD 11,"21 19.635 18.514 18.514 Cross Sectional Area of ID lIi"21 14.360 14.360 14.360 Sermon Modulus alnwal 5.708 4.476 4.476 Polar Section Modulus 0.,31al 11.415 8.953 8.953953 Page 56 Rev 0 January 2018 Milne Point Unit F-107 Producer Drilling Procedure Hilcorp Energy Company 500204050016200 Weatherford 5" 19.50 lb/ft S-135 wl NC 50 6-5/8" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection NC 50 Interchangeable With 5'XH&4-1/2" IF Upset Type IEU Nominal Weight per Foot 1950 lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5/8' Inside Diameter 3-1t4' 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 1 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 gat/ft 0.726 US gal/ft Displacement W/Tool Joint 0.353 US aauft 0.322 US gal/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. Page 57 Rev 0 January 2018 S S \ } . a \ . \ \ � \ \ � � \ \ « Hilcorp Alaska, LLC \ ƒ Mine Point M P F Pad Plan: MPU F-107 MPU F-07(OA Producer) Plan: MPU F-07WPI0 \ \ � � Standard Proposal Report 03 January, 20 18 \ \ \ \ \ \ \ \ \ � « / HALLIBURTON \ \ Sperry Drilling Services � \ , • • • •• HALLIBURTON MN REFERENCE INFORMATION WELL DETAILS:Plan:MPU F-107 • zi uiIC� +1r' o ) Co-ordinate(NE)Reference:Well Plan:MPU F-107,True North Ground Level: 10.80 Sperry Drilling l� Vertical(TVD)Reference:As-Built @ 37.30usft(Innovation) +N/S +E/-W Northing Easting Latittude Longitude Measured Depth Reference:As-Built @ 37.30usft(Innovation) 0.00 0.00 6034937.43 541322.13 70 30'22.949 N 149°39'42.969 W • - ----_- Calculation Method:Minimum Curvature Project: Milne Point Site: M Pt F Pad Well: Plan:MPU F-107 • Wellbore: MPU F-107(OA Producer) Design: MPU F-107 WP10 Hllcorp Alaska,LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method:Closest Approach 3D Error Surface:Elliptical Conic Warning Method:Error Ratio A Start Dir 0/100':275'MD,275TV0 0 Start Dir 4°/100':508.33'MD,507.75TVD - _ - - UPDATED FORMATION TOP DETAILS SURVEY PROGRAM 500- 500Start Dir 5°/100':808.33'MD,799.53TV0 Date:201604-21100:00:00 Validated:Yes Version: - _ NDPath 1VDsaPath MOPath Formation _ __---" 1645.30 1608.00 2000.62 SV4 Depth Flan, Depth To Survey/Plan Tool 1848.30 1811.00 2343.14 Base Permafrost 26.50 6220.00 MPU F-107 WP10 2 MWD+IFR2+MS+Sag 2067.30 2030.00 2712.67 SV1 6220.00 12688.00 MPD F-107 WP10 2_M640+IFR2+MS+Sa0 - 3411.30 3374.00 4460.87 Ugnu L83 1000- 7O- 0 End Dir:1556.31 MD,1382.02'TVD 394330 3906.00 5397.99 Schrader NA 41D8,30 4071.00 6225.91 Schrader OA CASING DETAILS C - O-" TVD MD Nacre Size 4107.78 N 1500- SV4 �O 6220.00 9 5/8'x 12 1/4" 9-5/8 _ 4132.30 12688.00 4.5"n81/2' 4-1/2 C. -- Base Pelnefrat-__ ' 0 - 2000- c - SV1--- _Stan Dir 0/100:2881.06'MD,2167.ITVD a - Cl 3000 ( 2500- 3500 End Dir:4823.63'MD,3643.48'TVD,ESP Pump Tangent Start J - at _ Start Dir 5/100':5173.63'MD,3834.1TV0 if 3000- 000 - End Dir:5931.5'MD,4082.64'TVO _- ,O0 Ugnu LA3-- h ' Start Dir 1.09°/100:6271.71'MD,4112.3'1VD 3500- Total Depth:12688'MD,4132.3'TVD _- End Dir'6730.43'MD,4132.3'TVD MPU F-107 WP10 _ ESP Pump Tangent Telget- y -- 4000- '"� ----- - Schrader NA _--a g Schrader OA, o 0 0 8 0 $ - e o 0 o ie \ 4500- 9 5/8'x 12 1/4" - MPF-107 v4308 Heel(OA) 4.5'x 8 1/2" 5000- I I I : i i I i 6 M I i i i l l i ii ' < I h ~ i , I i iii I C Y o i I f [ I I I I I I I I I I I I I I I I i I I , # I 1 1 I1 @ W l ° I 1 1 1 ; I1 0 F \ I » 1 1 1 i 1 I I i I I 11 I1 H P -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7560 Vertical Section at 163.49°(1000 usft/in) • • HALLIBUPTON Project: Milne Point WELL DETAILS:Plan:MPUF-107 Site: M Pt F Pad Ground Level: 10.80 Sperry Drifting +N/-S +E!-W Longitude HI Northing Fasting Latittude Lode Well: Plan: MPU F-107 +0.00 0.00 6034937.43 541322.13 70°30'22.949N 1ngitu42.%9W Wellbore: MPU F-107(OA Producer) Plan: MPU F-107 WP10 REFERENCE INFORMATION Incur!)�a I Co-ordinate(N/E)Reference:Well Plan:MPU F-107,True North Vertical(TVD)Reference:As-Built @ 37.30usft(Innovation) Measured Depth Reference:As-Built @ 37.30usft(Innovation) CASING DETAILS Calculation Method:Minimum Curvature TVD TVDSS MD Size Name 4107.78 4070.48 6220.00 9-5/8 9 5/8"x 12 1/4" 4132.30 4095.00 12688.00 4-1/2 4.5"x 8 1/2" - End Dir:4823.63'MD,3643.48'TVD,ESP Pump Tangent Start a N Start Dir 5°/100':2881.06'MD,2167.1TVD - H~ 1000— -s ' End Dir:1556.37'MD,1382.02'TVD 3250 4`0 3500 Start Dir 5°/100':808.33'MD,799.53TVD 500— 5� Start Dir 5°/100':5173.63'MD,3834.1TVD - b -Start Dir 4°/100':508.33'MD,507.75TVD -_ 3750 �'ti "- 0— -, �o-____-Start Dr 3°/100':275'MD,275TVD ESP Pump Tangent Target - End Dir:5931.5'MD,4082.64'TVD -500— - 95/8"x121/4" Start Dir 1.09°/100':6271.71'MD,4112.3TVD -1000— MPF-107 wp08 Heel(OA) ^ 4500— C _ End Dir:6730.43'MD,4132.3'TVD 0 0 o -2000-- - 2000- 0 -2500— o - o _ -3000 -3500— -4000- -4500— -5000- -5500— _ 4.5"x81/2" -6000— Total Depth:12688'MD,4132.3'TVD - \01 J -6500— -4000 -3500 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 West(-)/East(+)(1000 usft/in) • • Halliburton HALLI B U RTO J Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: a Well Plan:MPU F-107 Company: Hilcorp Alaska,LLC TVD Reference: As-Built @ 37.30usft(Innovation) Project: Milne Point MD Reference: . As-Built @ 37.30usft(Innovation) Site: M Pt F Pad North Reference: True Well: Plan:MPU F-107 Survey Calculation Method: Minimum Curvature • Wellbore: MPU F-107(OA Producer) ?'` MPU F-107 WP10 - t Design: 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 Using geodetic scale factor Site M Pt F Pad,TR-13-10 Site Position: Northing: 6,029,958.49 usft Latitude: 70°29'34.438 N From: Map Easting: 531,814.44usft Longitude: 149°44'23.616 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.25° Well Plan:MPU F-107 Well Position +N/-S 0.00 usft Northing: 6,034,937.43 usft • Latitude: 70°30'22.949 N • +EI-W 0.00 usft Easting: 541,322.13 usft • Longitude: 149°39'42.969 W • Position Uncertainty 0.50 usft Wellhead Elevation: 10.80 usft Ground Level: 10.80 usft • Wellbore MPU F 107(OAProducer) ._, von"( Model Name Sample Date Declination s z Field Strength f (°) a # ..1 (nT) BGGM2017 1/21/2018 17.33 81.03 57,488 Design MPU F-107 WP10 Audit Notes: Version: Phase: PROTOTYPE Tie On Depth: 26.50 Vertical Section: '. Depth From(TVD) � ,. +N/-S »;+EI-W 4 '' Direction � yl, s„ (usft) (usft) (usft). (°) 26.50 0.00 0.00 163.49 Plan Sections uw-"tt Measured Vertical TVD Dogleg Build , urns, 80006 Depth Inclination Azimuth ` Depth System ""+N1S +E/-W Rate Rate -• Rate (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) 4, 44 1 26.50 0.00 0.00 26.50 -10.80 0.00 0.00 0.00 0.00 0.00 0.00 275.00 0.00 0.00 275.00 237.70 0.00 0.00 0.00 0.00 0.00 0.00 508.33 7.00 303.00 507.75 470.45 7.75 -11.94 3.00 3.00 0.00 303.00 808.33 19.00 303.00 799.53 762.23 44.44 -68.43 4.00 4.00 0.00 0.00 1,501.33 53.65 303.00 1,349.39 1,312.09 264.63 -407.49 5.00 5.00 0.00 0.00 1,556.37 53.65 306.42 1,382.02 1,344.72 289.87 -443.93 5.00 0.01 6.21 90.92 2,881.06 53.65 306.42 2,167.10 2,129.80 923.29 -1,302.54 0.00 0.00 0.00 0.00 4,823.63 57.00 175.00 3,643.48 3,606.18 459.44 -2,049.07 5.00 0.17 -6.77 -140.67 5,173.63 57.00 175.00 3,834.10 3,796.80 167.02 -2,023.49 0.00 0.00 0.00 0.00 5,931.50 85.00 147.59 4,082.64 4,045.34 -492.48 -1,784.69 5.00 3.69 -3.62 -48.30 6,271.71 85.00 147.59 4,112.30 4,075.00 -778.60 -1,603.04 0.00 0.00 0.00 0.00 6,730.43 90.00 147.59 4,132.30 4,095.00 -1,165.37 -1,357.49 1.09 1.09 0.00 0.00 12,688.00 90.00 147.59 4,132.30 4,095.00 -6,194.96 1,835.61 0.00 0.00 0.00 0.00 1/3/2018 6:00:11 PM Page 2 COMPASS 5000.1 Build 81D • II Halliburton HA,LLI B U ,.. i O N Standard Proposal Report Database: =Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: .Well Plan:MPU F-107 Company: Hilcorp Alaska,LLC TVD Reference: `>As-Built @ 37.30usft(Innovation) Project: Milne Point MD Reference: : As-Built @ 37.30usft(Innovation) Site: M Pt F Pad North Reference: True Well: Plan:MPU F-107 Survey Calculation Method: Minimum Curvature Wellbore 1" MPU F-107(OA Producer) ,-x Design: MPU F-107 WP10 t »s. r ' Planned Survey 4;� � s.has , s1111, „ { c t i„' I' Measured _ ,.? � �'Vertical � �'�.. Map Map �� . Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS"` , ettSe (usft) (°) (°) (usft) usft (usft) (usft) (usft) ° (usft) ''';.' -10.80V44',4,44-='.., i','.:4-711 26.50 0.00 0.00 26.50 -10.80 0.00 0.00 6,034,937.43 541,322.13 0.00 0.00 100.00 0.00 0.00 100.00 62.70 0.00 0.00 6,034,937.43 541,322.13 0.00 0.00 200.00 0.00 0.00 200.00 162.70 0.00 0.00 6,034,937.43 541,322.13 0.00 0.00 275.00 0.00 0.00 275.00 237.70 0.00 0.00 6,034,937.43 541,322.13 0.00 0.00 Start Dir 3°/100':275'MD,275'TVD 300.00 0.75 303.00 300.00 262.70 0.09 -0.14 6,034,937.52 541,321.99 3.00 -0.12 400.00 3.75 303.00 399.91 362.61 2.23 -3.43 6,034,939.64 541,318.69 3.00 -3.11 500.00 6.75 303.00 499.48 462.18 7.21 -11.10 6,034,944.58 541,310.99 3.00 -10.07 508.33 7.00 303.00 507.75 470.45 7.75 -11.94 6,034,945.12 541,310.15 3.00 -10.83 I Start Dir 4°/100':508.33'MD,507.75'TVD 600.00 10.67 303.00 598.32 561.02 15.42 -23.74 6,034,952.71 541,298.30 4.00 -21.53 700.00 14.67 303.00 695.86 658.56 27.36 -42.13 6,034,964.55 541,279.85 4.00 -38.20 800.00 18.67 303.00 791.64 754.34 42.98 -66.18 6,034,980.03 541,255.72 4.00 a -60.01 808.33 19.00 303.00 799.53 762.23 44.44 -68.43 6,034,981.49 541,253.46 4.00 -62.05 Start Dir 5°/100':808.33'MD,799.53'TVD 900.00 23.58 303.00 884.92 847.62 62.57 -96.34 6,034,999.45 541,225.45 5.00 -87.36 1,000.00 28.58 303.00 974.70 937.40 86.50 -133.20 6,035,023.18 541,188.46 5.00 -120.78 1,100.00 33.58 303.00 1,060.32 1,023.02 114.61 -176.49 6,035,051.05 541,145.02 5.00 -160.03 1,200.00 38.58 303.00 1,141.11 1,103.81 146.68 -225.87 6,035,082.84 541,095.47 5.00 -204.81 1,300.00 43.58 303.00 1,216.46 1,179.16 182.46 -280.97 6,035,118.31 541,040.18 5.00 -254.77 1,400.00 48.58 303.00 1,285.80 1,248.50 221.68 -341.36 6,035,157.19 540,979.58 5.00 -309.53 1,500.00 53.58 303.00 1,348.60 1,311.30 264.04 -406.59 6,035,199.18 540,914.12 5.00 -368.68 1,501.33 53.65 303.00 1,349.39 1,312.09 264.63 -407.49 6,035,199.76 540,913.21 5.00 -369.50 1,556.37 53.65 306.42 1,382.02 1,344.72 289.86 -443.92 6,035,224.79 540,876.64 5.00 -404.04 End Dir :1556.37'MD,1382.02'TVD 1,600.00 53.65 306.42 1,407.87 1,370.57 310.73 -472.20 6,035,245.49 540,848.25 0.00 -432.08 1,700.00 53.65 306.42 1,467.14 1,429.84 358.54 -537.02 6,035,292.94 540,783.18 0.00 -496.34 1,800.00 53.65 306.42 1,526.40 1,489.10 406.36 -601.84 6,035,340.40 540,718.10 0.00 -560.60 1,900.00 53.65 306.42 1,585.67 1,548.37 454.18 -666.65 6,035,387.85 540,653.03 0.00 -624.87 2,000.00 53.65 306.42 1,644.93 1,607.63 501.99 -731.47 6,035,435.30 540,587.95 0.00 -689.13 2,000.62 53.65 306.42 1,645.30 1,608.00 502.29 -731.87 6,035,435.59 540,587.55 0.00 -689.52 SV4 2,100.00 53.65 306.42 1,704.20 1,666.90 549.81 -796.29 6,035,482.75 540,522.88 0.00 -753.39 2,200.00 53.65 306.42 1,763.47 1,726.17 597.63 -861.10 6,035,530.20 540,457.80 0.00 -817.65 2,300.00 53.65 306.42 1,822.73 1,785.43 645.44 -925.92 6,035,577.65 540,392.73 0.00 -881.91 2,343.14 53.65 306.42 1,848.30 1,811.00 666.07 -953.88 6,035,598.12 540,364.65 0.00 -909.64 Base Permafrost 2,400.00 53.65 306.42 1,882.00 1,844.70 693.26 -990.74 6,035,625.10 540,327.65 0.00 -946.17 2,500.00 53.65 306.42 1,941.26 1,903.96 741.08 -1,055.55 6,035,672.55 540,262.58 0.00 -1,010.43 2,600.00 53.65 306.42 2,000.53 1,963.23 788.89 -1,120.37 6,035,720.00 540,197.50 0.00 -1,074.70 2,700.00 53.65 306.42 2,059.79 2,022.49 836.71 -1,185.19 6,035,767.45 540,132.43 0.00 -1,138.96 2,712.67 53.65 306.42 2,067.30 2,030.00 842.77 -1,193.40 6,035,773.46 540,124.18 0.00 -1,147.10 SV1 2,800.00 53.65 306.42 2,119.06 2,081.76 884.52 -1,250.00 6,035,814.90 540,067.35 0.00 -1,203.22 1/3/2018 6:00:11PM Page 3 COMPASS 5000.1 Build 81D • /� !! Halliburton H A LLI B L i RTO J Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU F-107 Company: Hilcorp Alaska,LLC TVD Reference: ?As-Built @ 37.30usft(Innovation) Project: 0$ Milne Point MD Reference: ^ ?'As-Built @ 37.30usft(Innovation) Site: M Pt F Pad North Reference: '1114711True Well: Plan:MPU F-107 Survey Calculation Method: Minimum Curvature Wellbore: MPU F-107(OA Producer) Design: MPU F-107 WP10 M Planned Survey 1 Measured Vertical Map Map 1 Depth Inclination Azimuth"?$g Depth 3 VDss 11: +N/-S +E/-W Northing Easting '' DLS Vert Section (usft) (°) (°) (usft) , ,<usft (usft) (usft) :u` (usft) (usft) 2,129.80 2,881.06 53.65 306.42 2,167.10 2,129.80 923.29 -1,302.54 6,035,853 37 540,014.60 0.00 -1,255.31 Start Dir 5°/100':2881.06'MD,2167.1'TVD 2,900.00 52.92 305.66 2,178.42 2,141.12 932.22 -1,314.82 6,035,862.23 540,002.28 5.00 -1,267.36 3,000.00 49.16 301.44 2,241.30 2,204.00 975.23 -1,379.54 6,035,904.88 539,937.32 5.00 -1,326.99 3,100.00 45.56 296.71 2,309.06 2,271.76 1,011.03 -1,443.74 6,035,940.31 539,872.93 5.00 -1,379.55 3,200.00 42.18 291.39 2,381.16 2,343.86 1,039.34 -1,506.94 6,035,968.27 539,809.58 5.00 -1,424.65 3,300.00 39.09 285.35 2,457.07 2,419.77 1,059.94 -1,568.64 6,035,988.53 539,747.78 5.00 -1,461.93 3,400.00 36.34 278.51 2,536.21 2,498.91 1,072.68 -1,628.38 6,036,000.93 539,687.97 5.00 -1,491.12 3,500.00 34.04 270.80 2,617.97 2,580.67 1,077.46 -1,685.70 6,036,005.40 539,630.63 5.00 -1,511.99 3,600.00 32.27 262.24 2,701.73 2,664.43 1,074.25 -1,740.17 6,036,001.88 539,576.18 5.00 -1,524.39 3,700.00 31.14 252.97 2,786.85 2,749.55 1,063.07 -1,791.38 6,035,990.41 539,525.04 5.00 -1,528.22 3,800.00 30.70 243.27 2,872.70 2,835.40 1,044.00 -1,838.93 6,035,971.08 539,477.60 5.00 -1,523.45 3,900.00 31.00 233.52 2,958.60 2,921.30 1,017.19 -1,882.47 6,035,944.04 539,434.22 5.00 -1,510.11 4,000.00 32.00 224.14 3,043.92 3,006.62 982.85 -1,921.65 6,035,909.48 539,395.23 5.00 -1,488.31 4,100.00 33.65 215.43 3,127.99 3,090.69 941.23 -1,956.19 6,035,867.67 539,360.93 5.00 -1,458.22 4,200.00 35.86 207.55 3,210.19 3,172.89 892.65 -1,985.81 6,035,818.93 539,331.58 5.00 -1,420.06 4,300.00 38.52 200.54 3,289.88 3,252.58 837.48 -2,010.30 6,035,763.64 539,307.40 5.00 -1,374.13 4,400.00 41.56 194.36 3,366.46 3,329.16 776.15 -2,029.47 6,035,702.20 539,288.57 5.00 -1,320.77 4,460.87 43.55 190.96 3,411.30 3,374.00 735.99 -2,038.47 6,035,662.00 539,279.80 5.00 -1,284.82 Ugnu LA3 4,500.00 44.89 188.91 3,439.34 3,402.04 709.11 -2,043.18 6,035,635.10 539 275.24 5.00 -1,260.39 4,600.00 48.45 184.08 3,507.98 3,470.68 636.89 -2,051.30 6,035,562.83 539,267.52 5.00 -1,193.45 4,700.00 52.18 179.76 3,571.84 3,534.54 560.02 -2,053.80 6,035,485.96 539,265.45 5.00 -1,120.45 4,800.00 56.07 175.87 3,630.45 3,593.15 479.09 -2,050.64 6,035,405.06 539,269.06 5.00 -1,041.96 4,823.63 57.00 175.00 3,643.48 3,606.18 459.44 -2,049.07 6,035,385.42 539,270.74 5.00 -1,022.68 End Dir :4823.63'MD,3643.48'TVD,ESP Pump Tangent Start 4,900.00 57.00 175.00 3,685.07 3,647.77 395.64 -2,043.49 6,035,321.65 539,276.67 0.00 -959.92 5,000.00 57.00 175.00 3,739.53 3,702.23 312.09 -2,036.18 6,035,238.16 539,284.45 0.00 -877.74 5,100.00 57.00 175.00 3,794.00 3,756.70 228.54 -2,028.87 6,035,154.66 539,292.22 0.00 -795.55 5,173.63 57.00 175.00 3,834.10 3,796.80 167.02 -2,023.49 6,035,093.18 539,297.94 0.00 -735.04 Start Dir 5°1100':5173.63'MD,3834.17VD 5,200.00 57.88 173.84 3,848.29 3,810.99 144.90 -2,021.33 6,035,071.08 539,300.23 5.00 -713.22 5,300.00 61.32 169.63 3,898.90 3,861.60 59.60 -2,008.87 6,034,985.85 539,313.15 5.00 -627.89 5,397.99 64.80 165.76 3,943.30 3,906.00 -25.70 -1,990.22 6,034,900.66 539,332.28 5.00 -540.81 Schrader NA 5,400.00 64.88 165.69 3,944.16 3,906.86 -27.47 -1,989.77 6,034,898.90 539,332.74 5.00 -538.99 5,500.00 68.53 161.97 3,983.71 3,946.41 -115.64 -1,964.16 6,034,810.88 539,358.84 5.00 -447.17 5,600.00 72.27 158.44 4,017.25 3,979.95 -204.23 -1,932.24 6,034,722.47 539,391.25 5.00 -353.16 5,700.00 76.06 155.06 4,044.54 4,007.24 -292.59 -1,894.25 6,034,634.34 539,429.72 5.00 -257.66 5,800.00 79.90 151.78 4,065.36 4,028.06 -380.02 -1,850.48 6,034,547.16 539,473.97 5.00 -161.39 5,900.00 83.78 148.59 4,079.56 4,042.26 -465.87 -1,801.27 6,034,461.60 539,523.66 5.00 -65.10 5,931.50 85.00 147.59 4,082.64 4,045.34 -492.48 -1,784.70 6,034,435.08 539,540.38 5.00 -34.88 End Dir :5931.5'MD,4062.64'TVD 6,000.00 85.00 147.59 4,088.61 4,051.31 -550.09 -1,748.12 6,034,377,68 539,577.27 0.00 30.75 6,100.00 85.00 147.59 4,097.32 4,060.02 -634.19 -1,694.73 6,034,293.89 539,631.12 0.00 126.56 1/32018 8:00:11PM Page 4 COMPASS 5000.1 Build 81D • • Halliburton HALLIBURTON Standard Proposal Report .. ._...,,,...., „ ..,....,... .. ., ,....... - ... ..... _ ,......,....._. , ......, Database: „-':; Sperry EDM-NORTH US+CANADA 'Local Co-ordinate Reference: .,..if)n Well Plan:MPU F-107 Company: 1.1, Hilcorp Alaska,LLC TVD Reference: As-Built @ 37.30usft(Innovation) Project: ';:-.0Vi Milne Point MD Reference: 14;t0.7.774-aWit..t:qs...As-Built©37.30usft(Innovation) Site: ifilifiri M Pt F Pad Ob.,4*-71', North Reference: - 1,: ..,1 True Well: , 4.:V.-: Plan:MPU F-107 Survey Calculation Method: :te Minimum Curvature Wellbore: .-.4 MPU F-107(OA Producer) E., Design: '''''MPU F-1071NP10 .- Planned Survey - .ile"-:1',T.tt . .*:10Ailiii;...g*ti$At;!OV'-'4- Measured , '''',:;'-':1 0-itid,,i...,,..,.,,..,.....?..:Vertical 'i_j.ir'''''t.,;';',*:at;'.',:7'' ni-i'l;ei-.".1''' .i'1.':::g Map ,'''. Z Map ,,,,,'..r., .. .-.....-",:, Depth Inclination Azimuth Depth t,1TVDSS-ee, +NI-S +EI-W ' Y.':1 Northing r'qs4i: Easting ',:triP.,1S':;* .lf Vert Section :.- A:".` ft 4* ft '- I (usft) (°) (°) (usft) A usft 'i,' (usft) (usft) -5. (us ) . ,...., - (us ) 6,200.00 85.00 147.59 4,106.04 4,068.74 -718.29 -1,641.33 6,034,210 09 539,684.98 0.00 222.36 6,220.00 85.00 147.59 4,107.78 4,070.48 -735.11 -1,630.66 6,034,193.33 539,695.75 0.00 241.53 9 5/8"x 12 1/4" 6.225.91 85.00 147.59 4,108.30 4,071.00 -740.08 -1,627.50 6,034,188.38 539,698.93 0.00 247.19 Schrader OA 6,271.71 85.00 147.59 4,112.29 4,074.99 -778.60 -1,603.05 6,034,150.00 539,723.60 0.00 291.07 1 Start Dir 1.09°/100 :6271.71'MD,4112.3'TVD ' I 6,300.00 85.31 147.59 4,114.69 4,077.39 -802.40 -1,587.94 6,034,126.29 539,738.84 1.09 318.17 6,400.00 86.40 147.59 4,121.92 4,084.62 -886.60 -1,534.48 6,034,042.40 539,792.76 1.09 414.09 6,500.00 87.49 147.59 4,127.25 4,089.95 -970.90 -1,480.96 6,033,958.40 539,846.74 1.09 510.13 6,600.00 88.58 147.59 4,130.68 4,093.38 -1,055.27 -1,427.39 6,033,874.34 539,900.77 1.09 606.24 6,700.00 89.67 147.59 4,132.21 4,094.91 -1,139.69 -1,373.80 6,033,790.23 539,954.82 1.09 702.40 6,730.43 90.00 147.59 4,132.30 4,095.00 -1,165.38 -1,357.49 6,033,764.64 539,971.27 1.09 731.67 End Dir :673043'MD,4132.3'TVD 6,800.00 90.00 147.59 4,132.30 4,095.00 -1,224.11 -1,320.21 6,033,706.12 540,008.88 0.00 798.57 6,900.00 90.00 147.59 4,132.30 4,095.00 -1,308.53 -1,266.61 6,033,622.00 540,062.94 0.00 894.75 7,000.00 90.00 147.59 4,132.30 4,095.00 -1,392.96 -1,213.01 6,033,537.89 540,117.00 0.00 990.92 7,100.00 90.00 147.59 4,132.30 4,095.00 -1,477.38 -1,159.41 6,033,453.77 540,171.06 0.00 1,087.09 7,200.00 90.00 147.59 4,132.30 4,095.00 -1,561.80 -1,105.82 6,033,369.65 540,225.13 0.00 1,183.26 7,300.00 90.00 147.59 4,132.30 4,095.00 -1,646.23 -1,052.22 6,033,285.54 540,279.19 0.00 1,279.43 7,400.00 90.00 147.59 4,132.30 4,095.00 -1,730.65 -998.62 6,033,201.42 540,333.25 0.00 1,375.61 7,500.00 90.00 147.59 4,132.30 4,095.00 -1,815.07 -945.02 6,033,117.31 540,387.31 0.00 1,471.78 7,600.00 90.00 147.59 4,132.30 4,095.00 -1,899.50 -891.43 6,033,033.19 540,441.37 0.00 1,567.95 7,700.00 90.00 147.59 4,132.30 4,095.00 -1,983.92 -837.83 6,032,949.08 540,495.43 0.00 1,664.12 7,800.00 90.00 147.59 4,132.30 4,095.00 -2,068.34 -784.23 6,032,864.96 540,549.49 0.00 1,760.30 7,900.00 90.00 147.59 4,132.30 4,095.00 -2,152.77 -730.63 6,032,780.84 540,603.55 0.00 1,856.47 8,000.00 90.00 147.59 4,132.30 4,095.00 -2,237.19 -677.04 6,032,696.73 540,657.61 0.00 1,952.64 8,100.00 90.00 147.59 4,132.30 4,095.00 -2,321.61 -623.44 6,032,612.61 540,711.67 0.00 2,048.81 8,200.00 90.00 147.59 4,132.30 4,095.00 -2,406.04 -569.84 6,032,528.50 540,765.73 0.00 2,144.98 8,300.00 90.00 147.59 4,132.30 4,095.00 -2,490.46 -516.25 6,032,444.38 540,819.79 0.00 2,241.16 8,400.00 90.00 147.59 4,132.30 4,095.00 -2,574.88 -462.65 6,032,360.26 540,873.86 0.00 2,337.33 8,500.00 90.00 147.59 4,132.30 4,095.00 -2,659.31 -409.05 6,032,276.15 540,927.92 0.00 2,433.50 8,600.00 90.00 147.59 4,132.30 4,095.00 -2,743.73 -355.45 6,032,192.03 540,981.98 0.00 2,529.67 8,700.00 90.00 147.59 4,132.30 4,095.00 -2,828.15 -301.86 6,032,107.92 541,036.04 0.00 2,625.85 8,800.00 90.00 147.59 4,132.30 4,095.00 -2,912.58 -248.26 6,032,023.80 541,090.10 0.00 2,722.02 8,900.00 90.00 147.59 4,132.30 4,095.00 -2,997.00 -194.66 6,031,939.69 541,144.16 0.00 2,818.19 9,000.00 90.00 147.59 4,132.30 4,095.00 -3,081.42 -141.06 6,031,855.57 541,198.22 0.00 2,914.36 9,100.00 90.00 147.59 4,132.30 4,095.00 -3,165.85 -87.47 6,031,771.45 541,252.28 0.00 3,010.53 9,200.00 90.00 147.59 4,132.30 4,095.00 -3,250.27 -33.87 6,031,687.34 541,306.34 0.00 3,106.71 9,300.00 90.00 147.59 4,132.30 4,095.00 -3,334.70 19.73 6,031,603.22 541,360.40 0.00 3,202.88 9,400.00 90.00 147.59 4,132.30 4,095.00 -3,419.12 73.33 6,031,519.11 541,414.46 0.00 3,299.05 9,500.00 90.00 147.59 4,132.30 4,095.00 -3,503.54 126.92 6,031,434.99 541,468.53 0.00 3,395.22 9,600.00 90.00 147.59 4,132.30 4,095.00 -3,587.97 180.52 6,031,350.88 541,522.59 0.00 3,491.40 9,700.00 90.00 147.59 4,132.30 4,095.00 -3,672.39 234.12 6,031,266.76 541,576.65 0.00 3,587.57 9,800.00 90.00 147.59 4,132.30 4,095.00 -3,756.81 287.72 6,031,182.64 541,630.71 0.00 3,683.74 1/3/2018 6:00:11PM Page 5 COMPASS 5000.1 Build 81D . • Halliburton HALLI B Li R!TO J Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU F-107 Company: Hilcorp Alaska,LLC TVD Reference: -'- As-Built @ 37.30usft(Innovation) • Project: Milne Point MD Reference: --. As-Built @ 37.30usft(Innovation) Site: M Pt F Pad North Reference: True 0. Well: /`.; .:,Plan:MPU F-107 Survey Calculation Method: Minimum Curvature Wellbore: r}MPU F-107(OA Producer) Design: 1 =MPU F-107 WP10 Planned Survey f _ ,.s Measured gay., Vertical MapMap <g ' Depth Inclination Azimuth Depth TVDss^ +N/-S +E/W'„. Northing Easting DLS " .. ,: (usft) (°) (°) (usft) usft '' (usft) (usft). (usft) ..'";,:=::::,. (usft) 4,095,00 9,900.00 90.00 147.59 4,132.30 4,095.00 -3,841.24 341.31 6,031,098.53 541,684.77 0.00 3,779.91 10,000.00 90.00 147.59 4,132.30 4,095.00 -3,925.66 394.91 6,031,014.41 541,738.83 0.00 3,876.08 10,100.00 90.00 147.59 4,132.30 4,095.00 -4,010.08 448.51 6,030,930.30 541,792.89 0.00 3,972.26 10,200.00 90.00 147.59 4,132.30 4,095.00 -4,094.51 502.11 6,030,846.18 541,846.95 0.00 4,068.43 10,300.00 90.00 147.59 4,132.30 4,095.00 -4,178.93 555.70 6,030,762.07 541,901.01 0.00 4,164.60 10,400.00 90.00 147.59 4,132.30 4,095.00 -4,263.35 609.30 6,030,677.95 541,955.07 0.00 4,260.77 10,500.00 90.00 147.59 4,132.30 4,095.00 -4,347.78 662.90 6,030,593.83 542,009.13 0.00 4,356.94 10,600.00 90.00 147.59 4,132.30 4,095.00 -4,432.20 716.50 6,030,509.72 542,063.19 0.00 4,453.12 10,700.00 90.00 147.59 4,132.30 4,095.00 -4,516.62 770.09 6,030,425.60 542,117.26 0.00 4,549.29 10,800.00 90.00 147.59 4,132.30 4,095.00 -4,601.05 823.69 6,030,341.49 542,171.32 0.00 4,645.46 10,900.00 90.00 147.59 4,132.30 4,095.00 -4,685.47 877.29 6,030,257.37 542,225.38 0.00 4,741.63 11,000.00 90.00 147.59 4,132.30 4,095.00 -4,769.89 930.89 6,030,173.26 542,279.44 0.00 4,837.81 11,100.00 90.00 147.59 4,132.30 4,095.00 -4,854.32 984.48 6,030,089.14 542,333.50 0.00 4,933.98 11,200.00 90.00 147.59 4,132.30 4,095.00 -4,938.74 1,038.08 6,030,005.02 542,387.56 0.00 5,030.15 11,300.00 90.00 147.59 4,132.30 4,095.00 -5,023.16 1,091.68 6,029,920.91 542,441.62 0.00 5,126.32 11,400.00 90.00 147.59 4,132.30 4,095.00 -5,107.59 1,145.27 6,029,836.79 542,495.68 0.00 5,222.49 11,500.00 90.00 147.59 4,132.30 4,095.00 -5,192.01 1,198.87 6,029,752.68 542,549.74 0.00 5,318.67 11,600.00 90.00 147.59 4,132.30 4,095.00 -5,276.43 1,252.47 6,029,668.56 542,603.80 0.00 5,414.84 11,700.00 90.00 147.59 4,132.30 4,095.00 -5,360.86 1,306.07 6,029,584.44 542,657.86 0.00 5,511.01 11,800.00 90.00 147.59 4,132.30 4,095.00 -5,445.28 1,359.66 6,029,500.33 542,711.92 0.00 5,607.18 11,900.00 90.00 147.59 4,132.30 4,095.00 -5,529.70 1,413.26 6,029,416.21 542,765.99 0.00 5,703.36 12,000.00 90.00 147.59 4,132.30 4,095.00 -5,614.13 1,466.86 6,029,332.10 542,820.05 0.00 5,799.53 12,100.00 90.00 147.59 4,132.30 4,095.00 -5,698.55 1,520.46 6,029,247.98 542,874.11 0.00 5,895.70 12,200.00 90.00 147.59 4,132.30 4,095.00 -5,782.98 1,574.05 6,029,163.87 542,928.17 0.00 5,991.87 12,300.00 90.00 147.59 4,132.30 4,095.00 -5,867.40 1,627.65 6,029,079.75 542,982.23 0.00 6,088.04 12,400.00 90.00 147.59 4,132.30 4,095.00 -5,951.82 1,681.25 6,028,995.63 543,036.29 0.00 6,184.22 12,500.00 90.00 147.59 4,132.30 4,095.00 -6,036.25 1,734.85 6,028,911.52 543,090.35 0.00 6,280.39 12,600.00 90.00 147.59 4,132.30 4,095.00 -6,120.67 1,788.44 6,028,827.40 543,144.41 0.00 6,376.56 12,688.00 - 90.00 147.59 4,132.30 • 4,095.00 -6,194.96 1,835.61 6,028,753.38 • 543,191.99 • 0.00 6,461.19 Total Depth:12688'MD,4132.3'TVD-4.5"x 8 1/2" Targets .. � x Target Name i '. ! Vt.''4.4.,,-7„,:41'.1-'...A- - 7,..,--0444-9,4`k hit/miss targett'44.' Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape fo ,. :, O =mitt.. (°) (usft) (usft) :rt (usft) (usft) v " (usft),_ ESP Pump Tangent Target 0.00 0.00 3,834.10 167.02 -2,023.49 6,035,093.18 539,297.94 -plan hits target center -Point MPF-107 wp08 Heel(OA) 0.00 0.00 4,112.30 -778.60 -1,603.04 6,034,150.00 539,723.60 -plan misses target center by 0.01 usft at 6271.71 usft MD(4112.29 TVD,-778.61 N,-1603.04 E) -Circle(radius 50.00) 1/3/2018 6:00:11PM Page 6 COMPASS 5000.1 Build 81D • . Halliburton I-IALLIBURTON Standard Proposal Report Database: ' Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: :;Iiiii', Well Plan:MPU F-107 Company: Hilcorp Alaska,LLC TVD Reference: ;et 'Pk,As-Built @ 37.30usft(Innovation) Project: Milne Point MD Reference: 14-f 4 4'.,,f'..-4'4-4 As-Built @ 37.30usft(Innovation) Site: , . . M Pt F Pad North Reference: ''..f.!::.,-4 True Well: ..1'..tzl.'.4'Plan:MPU F-107 Survey Calculation Method: Minimum Curvature .. ...,,.. - . - Wellbore: MPU MPU F-107(0A Producer) Desi•n: 1.1*,;.-M,0.1 MPU F-107 INP10 ,,i...r.. 43 '::-t`% 7.4..0 Casing Points ':=1 Measured Vertical '04.1.K.:',-?...--:'"1-::::;-::,..Y'':''.''''Ii'it.-0;:-,l'tA6P,,,f-,--,,,:-t,--E*.p,,,inv.:,q,id- c - ' . ,.. : . 1„--,.,...g„,-,...,. .. $:::- ,..v„zi.,t..v:T,4.- asing 5 , lame er Diameter ' ,, 6220.00 4,107.78 9 5/8"x 12 1/4" 9-5/8 12-1/4 12,688.00 4,132.30 4.5"x8 1/2" 4-1/2 8-1/2 FormationsAt!P ii. .. ........... ..... .-,........”,,,,....... :. ....--......... „,...,,,..„-,* ....,,,,---,,, ,,,,. .,,, ,,-,,,,, , ...".15.,, ;,?1,1044,14ittiPtt,;3:1 ,frk;* " -141165..4... Measured ,=.:: Vertical 3 Vertical '-.'1,.P:-...q..n.gtifV.:t!If'.':':'i',,-'.;e,,ez,::,;,rl.!,...x.A4-:.%,„!.i...c.;-$.)L:-liikteia.ei,.-yegyefim:c:Q,TA11-7--'-,•.':,,', Dip 4,460.87 3,411.30 Ugnu LA3 2,712.67 2,067.30 SV1 2,343.14 1,848.30 Base Permafrost 1 ' 5,397.99 3,943.30 Schrader NA 2,000.62 1,645.30 SV4 6,225.91 4,108.30 Schrader OA Plan Annotations Measured Vertical -, ,, .....- Local Coordinates +E/-W .I Depth Depth :,:;,i1,7 +N/-S ,--- .. (usft) (usft) - i--,. (usft) (usft) Comment 275.00 275.00 0.00 0.00 Start Dir 3°/100':275'MD,275'TVD 508.33 507.75 7.75 -11.94 Start Dir 4°/100':508.33'MD,507.75'TVD 808.33 799.53 44.44 -68.43 Start Dir 5°/100':808.33'MD,799.53'TVD 1,556.37 1,382.02 289.86 -443.92 End Dir :1556.37'MD,1382.02'TVD 2,881.06 2,167.10 923.29 -1,302.54 Start Dir 5°/100':2881.06'MD,2167.1'TVD 4,823.63 3,643.48 459.44 -2,049.07 End Dir :4823.63'MD,3643.48'ND,ESP Pump Tangent Start 5,173.63 3,834.10 167.02 -2,023.49 Start Dir 5°/100':5173.63'MD,3834.1'TVD 5,931.50 4,082.64 -492.48 -1,784.70 End Dir :5931.5'MD,4082.64'TVD 6,271.71 4,112.29 -778.60 -1,603.05 Start Dir 1.09°/100':6271.71'MD,4112.3'TVD 6,730.43 4,132.30 -1,165.38 -1,357.49 End Dir :6730.43'MD,4132.3TVD 12,688.00 4,132.30 -6,194.96 1,835.61 Total Depth:12688'MD,4132.3'ND a 1/3/2018 6:00:11PM Page 7 COMPASS 5000.1 Build 81D • • Hilcorp Alaska, LLC Milne Point M Pt F Pad Plan: MPU F-107 MPU F-107(OA Producer) MPU F-107 WP10 Sperry Drilling Services Clearance Summary Anticollision Report r 03 January,2018 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design:M Pt F Pad-Plan:MPU F-107-MPU F-107(OA Producer)-MPU F-107 WP10 Well Coordinates:6,034,937.43 N,541,322.13 E(70°30'22.95"N,149°39'42.97"W) Datum Height:As-Built @ 37.30usft(Innovation) Scan Range:0.00 to 12,688.43 usft.Measured Depth. Scan Radius is 791.63 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version:5000.1 Build:810 Scan Type: NO GLOBAL FILTER:Using user defined selection 8.filtering criteria Scan Type: 25.00 HALLIBURTON Sperry Drilling Services • • Hilcorp Alaska,LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU F-107-MPU F-107 WP10 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt F Pad-Plan:MPU F-107-MPU F-107(OA Producer)-MPU F-107 WP10 Scan Range:0.00 to 12,688.43 usft.Measured Depth. Scan Radius is 791.63 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation Is Unlimited 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 All PtFPad MPF-05-MPF-05-MPF-05 5,987.66 513.72 5,987.66 458.34 5,482.21 9.277 Centre Distance Pass- MPF-05-MPF-05-MPF-05 6,000.00 513.86 6,000.00 457.94 5,480.62 9.189 Ellipse Separation Pass- MPF-05-MPF-05-MPF-05 6,150.00 538.32 6,150.00 476.09 5,461.04 8.650 Clearance Factor Pass- MPF-09-MPF-09-MPF-09 4,650.16 306.19 4,650.16 257.32 4,940.76 6.265 Centre Distance Pass- MPF-09-MPF-09-MPF-09 4,675.00 307.29 4,675.00 255.60 4,943.31 5.945 Ellipse Separation Pass- MPF-09-MPF-09-MPF-09 4,750.00 323.54 4,750.00 264.95 4,947.99 5.522 Clearance Factor Pass- MPF-80-MPF-90-MPF-80 4,800.00 183.66 4,800.00 120.76 4,596.10 2.920 Clearance Factor Pass- MPF-80-MPF-80-MPF-80 4,825.00 176.54 4,825.00 117.16 4,599.45 2.973 Ellipse Separation Pass- MPF-80-MPF-80-MPF-80 4,865.79 171.85 4,865.79 119.73 4,604.85 3.297 Centre Distance Pass- MPF-82-MPF-82-MPF-82 5,900.00 263.17 5,900.00 177.85 4,838.49 3.084 Clearance Factor Pass- MPF-82-MPF-82-MPF-82 5,975.00 235.75 5,975.00 164.90 4,843.81 3.327 Ellipse Separation Pass- MPF-82-MPF-82-MPF-82 6,029.27 229.45 6,029.27 168.96 4,847.06 3.793 Centre Distance Pass- MPF-82-MPF-82A-MPF-82A 5,900.00 263.17 5,900.00 176.48 4,838.49 3.036 Clearance Factor Pass- MPF-82-MPF-82A-MPF-82A 5,975.00 235.75 5,975.00 164.30 4,843.81 3.299 Ellipse Separation Pass- MPF-82-MPF-82A-MPF-82A 6,029.27 229.45 6,029.27 168.91 4,847.06 3.790 Centre Distance Pass- MPF-83-MPF-83-MPF-83 6,298.38 309.77 6,298.38 237.02 4,865.57 4.258 Centre Distance Pass- MPF-83-MPF-83-MPF-83 6,300.00 309.78 6,300.00 236.98 4,865.71 4.256 Ellipse Separation Pass- MPF-83-MPF-83-MPF-83 6,425.00 335.31 6,425.00 251.80 4,873.93 4.015 Clearance Factor Pass- MPF-84-MPF-84-MPF-84 4,829.22 109.12 4,829.22 53.09 4,652.23 1.947 Centre Distance Pass- MPF-84-MPF-84-MPF-84 4,850.00 111.01 4,850.00 49.43 4,656.31 1.803 Ellipse Separation Pass- MPF-84-MPF-84-MPF-84 4,875.00 118.00 4,875.00 51.31 4,661.20 1.769 Clearance Factor Pass- MPF-84-MPF-84A-MPF-84A 4,829.22 109.12 4,829.22 53.09 4,646.80 1.947 Centre Distance Pass- MPF-84-MPF-84A-MPF-84A 4,850.00 111.01 4,850.00 49.43 4,650.88 1.803 Ellipse Separation Pass- MPF-84-MPF-84A-MPF-84A 4,875.00 118.00 4,875.00 51.31 4,655.77 1.769 Clearance Factor Pass- MPF-84-MPF-84APB1-MPF-84APB1 4,829.22 109.12 4,829.22 53.09 4,646.80 1.947 Centre Distance Pass- MPF-84-MPF-84APB1-MPF-84APB1 4,850.00 111.01 4,850.00 49.43 4,650.88 1.803 Ellipse Separation Pass- MPF-84-MPF-84APB1-MPF-84APB1 4,875.00 118.00 4,875.00 51.31 4,655.77 1.769 Clearance Factor Pass- MPF-84-MPF-840-MPF-84B 4,829.22 109.12 4,829.22 53.09 4,649.55 1.947 Centre Distance Pass- 03 January,2018-18:04 Pape 2 of 7 COMPASS • • Hilcorp Alaska,LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU F-107-MPU F-107 WP1O Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt F Pad-Plan:MPU F-107-MPU F-107(OA Producer)-MPU F-107 WP10 Scan Range:0.00 to 12,688.43 usft.Measured Depth. Scan Radius is 791.63 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited 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 (unit) (usft) (usft) (usft) usft MPF-84-MPF-84B-MPF-84B 4,850.00 111.01 4,850.00 49.43 4,653.63 1.803 Ellipse Separation Pass- MPF-84-MPF-84B-MPF-84B 4,875.00 118.00 4,875.00 51.31 4,658.52 1.769 Clearance Factor Pass- MPF-96-MPF-96-MPF-96 3,337.05 469.68 3,337.05 333.67 3,553.50 3.453 Centre Distance Pass- MPF-96-MPF-96-MPF-96 3,350.00 469.81 3,350.00 333.39 3,562.99 3.444 Ellipse Separation Pass- MPF-96-MPF-96-MPF-96 3,400.00 472.82 3,400.00 335.09 3,599.38 3.433 Clearance Factor Pass- Plan MPF-1064.21-MPF-106i-MPF-106i WP03 1,121.27 331.65 1,121.27 321.67 1,259.19 33.234 Centre Distance Pass- Plan MPF-106 4.21-MPF-106i-MPF-106i WP03 1,125.00 331.66 1,125.00 321.66 1,262.67 33.176 Ellipse Separation Pass- Plan MPF-106 4.21-MPF-106i-MPF-106i WP03 1,250.00 339.91 1,250.00 329.31 1,376.74 32.080 Clearance Factor Pass- Plan MPF-108_WPO4SHL-MPF-108i-MPF-108i WP 1,159.04 256.36 1,159.04 246.72 1,350.06 26.594 Ellipse Separation Pass- Plan MPF-108_WPO4SHL-MPF-108i-MPF-108i 1NP 12,688.43 516.29 12,688.43 261.66 11,214.04 2.028 Clearance Factor Pass- Plan MPF-109_WPO6SHL-MPF-109-MPF-109WP0 1,118.48 370.59 1,118.48 358.23 1,277.06 29.991 Centre Distance Pass- Plan MPF-109_WP06SHL-MPF-109-MPF-109 WPO 1,125.00 370.61 1,125.00 358.23 1,283.89 29.926 Ellipse Separation Pass- Plan MPF-109_WPO6SHL-MPF-109-MPF-109 WPO 1,250.00 381.12 1,250.00 368.11 1,406.90 29.304 Clearance Factor Pass- Plan MPF-110i_WPOSSHL-MPF-110i-MPF-110i VW 1,125.66 215.85 1,125.66 202.86 1,291.54 16.613 Ellipse Separation Pass- Plan MPF-110i_WPOSSHL-MPF-110i-MPF-110i WP 1,200.00 223.40 1,200.00 209.66 1,350.34 16.255 Clearance Factor Pass- Plan MPF-111-MPF-111i-MPF-111iwp01a 12,688.43 371.91 12,688.43 188.30 10,134.12 2.026 Clearance Factor Pass- Plan:MPU F-106-MPU F-1061-MPU F-106i WP04 251.55 14.85 251.55 11.46 251.55 4,376 Centre Distance Pass- Plan:MPU F-106-MPU F-1061-MPU F-106i WP04 350.00 15.41 350.00 10.86 349.82 3.385 Ellipse Separation Pass- Plan:MPU F-106-MPU F-106i-MPU F-106i WP04 12,425.00 788.95 12,425.00 489.27 11,915.63 2.633 Clearance Factor Pass- Plan:MPU F-108-MPU F-1081-MPU F-108i WP05 351.45 45.01 351.45 40.44 351.21 9.849 Centre Distance Pass- !i Plan:MPU F-108-MPU F-108i-MPU F-108i WP05 375.00 45.14 375.00 40.29 374.28 9.312 Ellipse Separation Pass- Plan:MPU F-108-MPU F-108i-MPU F-108i WP05 500.00 50.40 500.00 44.06 496.59 7.948 Clearance Factor Pass- Plan:MPU F-109-MPU F-109(OA Producer)-MPU F 327.16 90.18 327.16 85.90 326.97 21.064 Centre Distance Pass- Plan:MPU F-109-MPU F-109(OA Producer)-MPU F 350.00 90.31 350.00 85.77 348.77 19.873 Ellipse Separation Pass- Plan:MPU F-109-MPU F-109(OA Producer)-MPU F 500.00 97.88 500.00 91.98 491.39 16.592 Clearance Factor Pass- Plan:MPU F-110i-MPU F-110i-MPU F-110i WP06 350.14 103.30 350.14 98.75 350.00 22.678 Centre Distance Pass- Plan:MPU F-110i-MPU F-1101-MPU F-110i WP06 375.00 103.46 375.00 98.62 373.58 21.369 Ellipse Separation Pass- Plan:MPU F-110i-MPU F-110i-MPU F-110i WP06 625.00 125.96 625.00 118.20 606.86 16.234 Clearance Factor Pass- Well#7-Well#7-Well#7 wp01 3,229.65 457.21 3,229.65 373.45 3,348.59 5.459 Centre Distance Pass- Well#7-Well#7-Well#7 wp01 3,250.00 457.41 3,250.00 373.19 3,367.93 5.431 Ellipse Separation Pass- 03 January,2018-18:04 Page3of7 COMPA-S • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU F-107-MPU F-107 WP10 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt F Pad-Plan:MPU F-107-MPU F-107(OA Producer)-MPU F-107 WP10 Scan Range:0.00 to 12,688.43 usft.Measured Depth. Scan Radius is 791.63 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited 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 Well#7-Nkli#7-Well#7 wp01 3,325.00 461.69 3,325.00 375.99 3,438.59 5.387 Clearance Factor Pass- Well#8-Well#8-Well#8 wp01 3,050.00 272.55 3,050.00 202.66 3,208.54 3.900 Clearance Factor Pass- Well#8-Well#8-Well#8 wp01 3,100.00 270.05 3,100.00 201.4.4 3,254.49 3.936 Ellipse Separation Pass- Well#8-Well#8-Well#8 wp01 3,109.73 269.98 3,109.73 201.68 3,263.43 3.953 Centre Distance Pass- Well#9-Well#9-Well#9 wp01 2,775.00 192.98 2,775.00 141.52 2,976.90 3.750 Clearance Factor Pass- Well#9-Well#9-Well#9 wp01 2,850.00 180.49 2,850.00 134.96 3,041.02 3.965 Ellipse Separation Pass- Nell#9-Well#9-Well#9 wp01 2,911.87 176.47 2,911.87 137.92 3,093.99 4.578 Centre Distance Pass- M Pt L Pad MPL-28-MPL-28-MPL-28 7,041.56 469.23 7,041.56 405.47 7,617.46 7.358 Centre Distance Pass- MPL-28-MPL-28-MPL-28 7,125.00 472.42 7,125.00 402.98 7,555.00 6.803 Ellipse Separation Pass- MPL-28-MPL-28-MPL-28 7,425.00 529.12 7,425.00 439.60 7,321.14 5.911 Clearance Factor Pass- MPL-28-MPL-28A-MPL-28A 7,132.71 490.92 7,13271 419.24 7,498.88 6.848 Centre Distance Pass- MPL-28-MPL-26A-MPL-28A 7,200.00 493.19 7,200.00 416.75 7,452.88 6.452 Ellipse Separation Pass- MPL-28-MPL-26A-MPL-28A 7,425.00 530.72 7,425.00 440.24 7,298.11 5.865 Clearance Factor Pass- MPL-34-MPL-34-MPL-34 11,875.03 553.06 11,875.03 502.56 5,478.97 10.953 Centre Distance Pass- MPL-34-MPL-34-MPL-34 11,900.00 553.59 11,900.00 501.94 5,484.83 10.719 Ellipse Separation Pass- MPL-34-MPL-34-MPL-34 12,175.00 624.97 12,175.00 558.15 5,557.73 9.353 Clearance Factor Pass- i MPL-37-MPL-37-MPL-37 12,688.43 568.64 12,688.43 520.65 5,639.84 8.658 Clearance Factor Pass- MPL-37-MPL-37A-MPL-37A 12,688.43 588.64 12,688.43 520.65 5,649.04 8.658 Clearance Factor Pass- MPL-40-MPL-40-MPL-40 10,125.00 564.40 10,125.00 420.81 5,478.85 3.931 Clearance Factor Pass- MPL-40-MPL-40-MPL-40 10,350.00 472.48 10,350.00 371.34 5,414.76 4.671 Ellipse Separation Pass- MPL-40-MPL-40-MPL-40 10,468.93 458.60 10,468.93 384.26 5,379.26 6.169 Centre Distance Pass- MPL-46-MPL-46-MPL-46 12,688.43 681.81 12,688.43 513.13 5,761.47 4.042 Clearance Factor Pass- MPL-46-MPL-46 PBI-MPL-46 PBI 12,688.43 681.81 12,688.43 513.13 5,761.47 4.042 Clearance Factor Pass- MPL-48-MPL-48-MPL-48 12,688.43 265.32 12,688.43 194.09 5,750.88 3.725 Clearance Factor Pass- MPL-48-MPL-48PB1-MPL-48PB1 12,688.43 296.66 12,688.43 210.88 5,784.40 3.458 Clearance Factor Pass- MPL-48-MPL-48PB2-MPL-48PB2 12,688.43 287.97 12,688,43 201.56 5,807.05 3.333 Clearance Factor Pass- MPL-48-MPL-48PB3-MPL-48 PB3 12,688.43 265.32 12,688.43 194.09 5,750.88 3.725 Clearance Factor Pass- MPU L-51-MPU L-51-MPU L-51 12,610.23 538.22 12,610.23 422.80 5,512.69 4.663 Centre Distance Pass- MPU L-51-MPU L-51-MPU L-51 12,688.43 543.06 12,688.43 418.13 5,540.88 4.347 Clearance Factor Pass- 03 January,2018- 18:04 Page 4 of 7 COMPASS • • Hilcorp Alaska,LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU F-107-MPU F-107 WP10 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt F Pad-Plan:MPU F-107-MPU F-107(OA Producer)-MPU F-107 WP10 Scan Range:0.00 to 12,688.43 usft.Measured Depth. Scan Radius is 791.63 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited 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) (unit) usft Plan:MPU L-54-MPU L-54-MPU L-54 WP06 12,688.43 733.79 12,688.43 647.04 5,761.95 8.459 Clearance Factor Pass- RIG:MPU L-52-MPU L-52-MPU L-52 11,102.38 642.25 11,102.38 551.67 5,213.08 7.091 Centre Distance Pass- RIG:MPU L-52-MPU L-52-MPU L-52 11,125.00 642.64 11,125.00 551.14 5,215.16 7.023 Ellipse Separation Pass- RIG:MPU L52-MPU L-52-MPU L-52 11,325.00 679.31 11,325.00 577.76 5,234.76 6.690 Clearance Factor Pass- RIG:MPU L-52-MPU L-52-MPU L-52 WP13 11,096.82 635.74 11,096.82 544.18 5,213.79 6.943 Centre Distance Pass- RIG:MPU L-52-MPU L-52-MPU L-52 WP13 11,125.00 636.36 11,125.00 543.60 5,216.52 6.860 Ellipse Separation Pass- RIG:MPU L-52-MPU L-52-MPU L-52 WP13 11,325.00 674.94 11,325.00 571.74 5,239.12 6.540 Clearance Factor Pass- Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 26.50 6,220.00 MPU F-107 WP10 2_MWD+IFR2+MS+Sag 6,220.00 12,688.00 MPU F-107 WP10 2_MWD+IFR2+MS+Sag 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 I(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 03 January,2018-18:04 Page bof7 COMPASS I', el • HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DETAILS:Plan:MPU F-107 NAD 1927(NADCONCONUS) Alaska Zone 04 Site: M Pt F Pad Coordinate(N/E)Reference:Well Fan:CPU F-107,True North Ground Level: 10.80 S perry Orit1/ Well: Plan:MPU F-107 Vertical(TVD)Reference:As-Bull1 a 37.30us0(Innova0on) +N/-S +F/-W Northing Easting Latitmde Longitude 9 Measured Depth Reference:As-Built @ 37.30ustt(Innovallonl 0.00 0.00 6034937 43 541322.13 7W 30'22.949 N 149°37 42.989 W Wellbore: MPU F-107(OA Producer' Calculation Method.Mnanum Curve/,re Plan: MPU F-107 WP10 SURVEY PROGRAM GLOBAL FILTER:Using user defined selection 868edng criteria 111-111corp Date:201804-21700:00:00 Validated:Yes Version: 26.50 To 12688.43 Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool CASING DETAILS 26.50 6220.00 MPU F-107 WP10 2 MWD+IFR2+MS+Seg 6220.00 12688.00 MPU F-107 WPIO 2_MWD+IFR2+MS+Sag TVD TVD33 MD Size Name 4107.78 4070.48 6220.00 9-5/8 9 5/8"x 12 1/4" 4132.30 4095.00 12688.00 4-1/2 4.5"0812" .,..._S150.00j / ' 3 MPL /66120.00— ...-- - r .,Ic oN90.00 / - 'a(. M �7�` MPF180 a1 • a) l �I so oo— o ��,11 • 30.00 PJ F-1081 WP U - MPU F',06i WPO4 _ I 0.00 1 l 1 I I 1 I I I i I 1 1 l 1 1 1 1 I l I I 1 1 1 1 1 1 1 1 1 1 1 1 11 l I I I I 1 1 I I I 1 I I 1 1 1 1 1 1 1 1 1 1 1 1 11 I 1 1 1 1 1 1 1 1 1 1 1 1 1 1111 1 I 1 0 700 1400 2100 2800 3500 4200 4900 5600 6300 7000 7700 8400 9100 9600 10500 11200 11900 12600 13300 Measured Depth(1400 usftfin) 4.50— -. _��—�� _/ ®.;.... _i • ®� ,. 1 l j_ 0 15 300— -__ I to '..11'Ne 41111111kc I • in 1.50—No-Golsion Zone-Stopnce DnlliRri e i. i 1I' j .I 1 • . • • • • • 0.00 0 1750 1 1 11500 1 1 12250 1 1 13 10 1 13 11 l 1 4500 1 5250 ' 1600 1 1 167150 1 1 17500 1 1 18250 1 1 l9 00 1 1 197150 10500 11250 12000 1 1 12750 1 1 1 1 750 350 Measured Depth(1400 usft/in) • • AOGCC Permit to Drill No. 218-001 -Coordinate Check 9 January 2018 INPUT OUTPUT Geographic,NAD27 State Plane,NAD27 5004-Alaska 4,U.S.Feet MPU F-107 1/1 Latitude: 70 30 22.949 Northing/Y: 6034937.437 Longitude: 149 39 42.969 Easting/X: 541322.130 Convergence: 0 19 07.27060 Scale Factor: 0.999901940 Remark: Corpscon v6.0.1,U.S.Army Corps of Engineers • . • TRANSMITTAL LETTER CHECKLIST WELL NAME: AO' �.� PTD: Z// l DevelopmentNon-Conventional Service _Exploratory _Stratigraphic Test _Non Conventional FIELD: / ` 790-i/AC 14 POOL: c/C. A 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 folloyving well logs are also required for this well: 4'4„,d �; /e._) i/r Well Logging j� _61,4,-v • <. �Qc ✓ Requirements h/ / ,�� 4 /``v /5 s f c /c<f1 CJ Per. 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