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^Zηϭ ϱϬͲϬϮϵͲϮϯϲϰϲͲϬϬͲϬϬ ϮϭϵͲϭϭϯ ϵͬϭϲͬϮϬϮϮ ϵͬϮϭͬϮϬϮϮ ϵͬϮϯͬϮϬϮϮͲ&ƌŝĚĂLJ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϮϭͬϮϬϮϮͲtĞĚŶĞƐĚĂLJ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞĞŬůLJKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌLJ >ĂŶĚƚƵďŝŶŐŚĂŶŐĞƌ͕Z/>^͕WsŝƐŝŶƐƚĂůůĞĚ͕WhtсϰϮ<͕^KtсϯϮ<͖ůŽǁĚŽǁŶĂůůĐŝƌĐƵůĂƚŝŶŐůŝŶĞƐ͘ZͬĂůůƚƵďƵůĂƌŚĂŶĚůŝŶŐ ĞƋƵŝƉŵĞŶƚ͘ZͬĨůŽǁůŝŶĞƐƉŽŽůƐ͕ZͬĂƚǁĂůŬ͕ZͬĂůůĂŶĐŝůůĂƌLJůŝŶĞƐĂŶĚĞƋƵŝƉŵĞŶƚ͘dƌĂŶƐĨĞƌǁŽƌŬŽǀĞƌĨůƵŝĚĨƌŽŵƚŚĞƉŝƚƐ͘ZŝŐ ZĞůĞĂƐĞĚĂƚϭϮ͗ϬϬŚƌƐ͘ ϵͬϮϮͬϮϬϮϮͲdŚƵƌƐĚĂLJ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϮϰͬϮϬϮϮͲ^ĂƚƵƌĚĂLJ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϮϳͬϮϬϮϮͲdƵĞƐĚĂLJ ϵͬϮϱͬϮϬϮϮͲ^ƵŶĚĂLJ EŽŽƉĞƌĂƚŝŽŶƐƚŽƌĞƉŽƌƚ͘ ϵͬϮϲͬϮϬϮϮͲDŽŶĚĂLJ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu bm itt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:ASR 1 DATE: 9/19/22 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2191130 Sundry #322-524 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:622 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1P Permit On Location P Hazard Sec.P Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 1P Test Fluid Water Inside BOP 1FP 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 5-1/2" Solid Body P Flow Indicator PP #2 Rams 1 Blinds P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 2 1/16"P Time/Pressure Test Result HCR Valves 1 2 1/16"P System Pressure (psi)3025 P Kill Line Valves 2 2 1/16"P Pressure After Closure (psi)1925 P Check Valve 0NA200 psi Attained (sec)15 P BOP Misc 0NAFull Pressure Attained (sec)48 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4 / 2237 PSI P No. Valves 16 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 25 P #1 Rams 6 P Coiled Tubing Only:#2 Rams 4 P Inside Reel valves 0NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:6.5 HCR Choke 1 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 9/18/22 01:33 Waived By Test Start Date/Time:9/19/2022 9:30 (date) (time)Witness Test Finish Date/Time:9/19/2022 16:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Austin McLeod Hilcorp Test # 1; test on High failed due to IBOP. Redress & re-test PASS. Bottle precharge - 1000 psi. C. Greub / C. Pace Hilcorp Alaska LLC S. Heim / R. Gallen MPU M-06 Test Pressure (psi): askans-asr-toolpushers@hilcorp.c ans-asrwellsitemanagers@hilcorp Form 10-424 (Revised 08/2022) 2022-0919_BOP_Hilcorp_ASR1_MPU_M-06 9 9 99 9999 9 9 9 9 9 9 - 5HJJ 9 9 FP High failed due to IBOP. 7\SHRI5HTXHVW $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 5HSDLU:HOO 2SHUDWLRQVVKXWGRZQ 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH 3XOO7XELQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HHQWHU6XVS:HOO $OWHU&DVLQJ 2WKHU (63&KDQJHRXW 2SHUDWRU1DPH &XUUHQW:HOO&ODVV 3HUPLWWR'ULOO1XPEHU ([SORUDWRU\ 'HYHORSPHQW $GGUHVV 6WUDWLJUDSKLF 6HUYLFH $3,1XPEHU ,ISHUIRUDWLQJ :HOO1DPHDQG1XPEHU :KDW5HJXODWLRQRU&RQVHUYDWLRQ2UGHUJRYHUQVZHOOVSDFLQJLQWKLVSRRO" :LOOSODQQHGSHUIRUDWLRQVUHTXLUHDVSDFLQJH[FHSWLRQ" <HV 1R 3URSHUW\'HVLJQDWLRQ /HDVH1XPEHU )LHOG3RRO V 7RWDO'HSWK0' IW 7RWDO'HSWK79' IW (IIHFWLYH'HSWK0' (IIHFWLYH'HSWK79' 0363 SVL 3OXJV 0' -XQN 0' 1$ &DVLQJ &ROODSVH &RQGXFWRU 1$ 6XUIDFH SVL 3URGXFWLRQ SVL 3DFNHUVDQG66697\SH 3DFNHUVDQG66690' IW DQG79' IW $WWDFKPHQWV 3URSRVDO6XPPDU\ :HOOERUHVFKHPDWLF :HOO&ODVVDIWHUSURSRVHGZRUN 'HWDLOHG2SHUDWLRQV3URJUDP %236NHWFK ([SORUDWRU\ 6WUDWLJUDSKLF 'HYHORSPHQW 6HUYLFH (VWLPDWHG'DWHIRU :HOO6WDWXVDIWHUSURSRVHGZRUN &RPPHQFLQJ2SHUDWLRQV 2,/ :,1- :7563/6XVSHQGHG 9HUEDO$SSURYDO 'DWH *$6 :$* *6725 63/8* $2*&&5HSUHVHQWDWLYH *,1-2S6KXWGRZQ $EDQGRQHG &RQWDFW1DPH &RQWDFW(PDLO &RQWDFW3KRQH &RQGLWLRQVRIDSSURYDO 1RWLI\$2*&&VRWKDWDUHSUHVHQWDWLYHPD\ZLWQHVV 6XQGU\1XPEHU 3OXJ,QWHJULW\ %237HVW 0HFKDQLFDO,QWHJULW\7HVW /RFDWLRQ&OHDUDQFH 2WKHU 3RVW,QLWLDO,QMHFWLRQ0,75HT G"<HV 1R 6SDFLQJ([FHSWLRQ5HTXLUHG"<HV 1R 6XEVHTXHQW)RUP5HTXLUHG $33529('%< $SSURYHGE\ &200,66,21(5 7+($2*&& 'DWH &RPP &RPP 6U3HW(QJ 6U3HW*HR 6U5HV(QJ 1$ ,KHUHE\FHUWLI\WKDWWKHIRUHJRLQJLVWUXHDQGWKHSURFHGXUHDSSURYHGKHUHLQZLOOQRWEHGHYLDWHGIURPZLWKRXWSULRUZULWWHQDSSURYDO $XWKRUL]HG1DPHDQG 'LJLWDO6LJQDWXUHZLWK'DWH $2*&&86(21/< %ULDQ*ODVKHHQ %ULDQ*ODVKHHQ#KLOFRUSFRP $XWKRUL]HG7LWOH 2SHUDWLRQV0DQDJHU 7XELQJ*UDGH 7XELQJ0' IW 3HUIRUDWLRQ'HSWK79' IW 7XELQJ6L]H 35(6(17:(//&21',7,216800$5< 67$7(2)$/$6.$ $/$6.$2,/$1'*$6&216(59$7,21&200,66,21 $33/,&$7,21)25681'5<$33529$/6 $$& $'/ &HQWHUSRLQW'U6XLWH$QFKRUDJH$. +LOFRUS$ODVND//& 0380 0LOQH3RLQW)LHOG3ULQFH&UHHN:DWHU7HUWLDU\8QGHI:7563 1$ /,%702' 79' %XUVW 1$ SVL SVL /HQJWK 6L]H 0' 3HUIRUDWLRQ'HSWK0' IW 6HH6FKHPDWLF 6HH6FKHPDWLF ´9HUVD7ULHYH3DFNHU %:'7RS6QDS6XPS3DFNHUDQG1$ 0'79' 0'79'DQG1$ U\ 6WDWX )RUP5HYLVHG$SSURYHGDSSOLFDWLRQLVYDOLGIRUPRQWKVIURPWKHGDWHRIDSSURYDO Taylor Wellman for David Haakinson 'LJLWDOO\VLJQHGE\7D\ORU :HOOPDQ '1 FQ 7D\ORU:HOOPDQ RX 8VHUV 'DWH 7D\ORU:HOOPDQ By Anne Prysunka at 3:48 pm, Sep 02, 2022 '/% '65 ; %23(WHVWWRSVL 0*56(3 GWV Jessie L. 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ůĞĞĚĂŶLJƉƌĞƐƐƵƌĞŽĨĨƚƵďŝŶŐĂŶĚĐĂƐŝŶŐƚŽƚŚĞƌĞƚƵƌŶƐƚĂŶŬ͘WƵůůd^͕ůƵďƌŝĐĂƚĞŝĨƉƌĞƐƐƵƌĞĞdžƉĞĐƚĞĚ͘ <ŝůůǁĞůůǁŝƚŚ<>ĂƐŶĞĞĚĞĚ͘ ϭϯ͘ DhůĂŶĚŝŶŐũŽŝŶƚŽƌƐƉĞĂƌĂŶĚK>^͘ ϭϰ͘ tĞůůŝƐĂůŝǀĞǁĞůůĂŶĚŚŽůĞĨŝůůŶĞĞĚƐƚŽďĞŵĂŶĂŐĞĚƚŚĞĞŶ ƚŝƌĞũŽď͘/ĨǁĞůůǁŝůůŚŽůĚĂĐŽůƵŵŶŽĨĨůƵŝĚ ĞƐƚĂďůŝƐŚŚŽůĞĨŝůůƌĂƚĞƚŽƐĞĞĨůƵŝĚĂƚƐƵƌĨĂĐĞĂƚĂůůƚŝŵĞƐ͘ ϭϱ͘ ƚƚĞŵƉƚƚŽƉƵůůƚƵďŝŶŐ͘ Ă͘ WhǁĞŝŐŚƚϮϬϭϵZtKǁĂƐϴϬŬ^KǁĂƐϳϱ< ď͘ ŽŶŽƚĞdžĐĞĞĚϴϬƉĞƌĐĞŶƚŽĨƚƵďŝŶŐ͘ ϭϲ͘ ZĞĐŽǀĞƌƚŚĞƚƵďŝŶŐŚĂŶŐĞƌ͘ ŽŶƚŝŶŐĞŶĐLJ;/ĨĂƌŽůůŝŶŐƚĞƐƚǁĂƐĐŽŶĚƵĐƚĞĚͿ͗DhŶĞǁŚĂŶŐĞƌŽƌƚĞƐƚƉůƵŐƚŽƚŚĞĐŽŵƉůĞƚŝŽŶ ƚƵďŝŶŐ͘ZĞͲůĂŶĚŚĂŶŐĞƌ;ŽƌƚĞƐƚƉůƵŐͿŝŶƚƵďŝŶŐŚĞĂĚ͘dĞƐƚK W ƉĞƌƐƚĂŶĚĂƌĚƉƌŽĐĞĚƵƌĞ͘ ϭϳ͘ WKK,ĂŶĚůĂLJĚŽǁŶƚŚĞϱͲϭͬϮ͛͛ƚƵďŝŶŐ͘ZŝŐƵƉƐƉŽŽůĞƌĨŽƌ ^W ĐĂďůĞ͘ Ă͘ /ŶƐƉĞĐƚƚŚĞdƵďŝŶŐĂŶĚƉůĂĐĞŐŽŽĚũŽŝŶƚƐŝŶƚŽŝŶǀĞŶƚŽƌLJ͘ ď͘ WůĂŶƚŽŬĞĞƉĐůĂŵƉƐĂŶĚƚƵďŝŶŐƚŽƌĞƌƵŶŝŶŚŽůĞ͘ Đ͘ DĂŬĞƐƵƌĞƚŽĂĐĐŽƵŶƚĨŽƌĂůůĐůĂŵƉƐďĞůŽǁ͗ ϯƉƌŽƚĞĐƚŽůŝnjĞƌƐ͕ϱϮĐƌŽƐƐĐŽƵƉůĞƌĂŶŶŽŶĐůĂŵƉƐĂŶĚϮƐƚĂŝŶůĞƐ ƐƐƚĞĞůďĂŶĚƐƌĂŶ ϭϴ͘ ZhƚŽƌƵŶϱͲϭͬϮ͟ ^WĐŽŵƉůĞƚŝŽŶ͘ ϭϵ͘ Z/,ǁŝƚŚƚŚĞĨŽůůŽǁŝŶŐ ^WĐŽŵƉůĞƚŝŽŶĞƋƵŝƉŵĞŶƚƚŽΕϭϴϳϬ͛DŝŶƐƚĂůůŝŶŐĐƌŽƐƐĐŽƵƉůŝŶŐĐůĂŵƉƐŽŶ ĞǀĞƌLJĐŽŶŶĞĐƚŝŽŶ͗ Ĩ͘ ĞŶƚƌĂůŝnjĞƌ Ő͘ DŽƚŽƌ'ĂƵŐĞ͕ĞŶŝƚŚ Ś͘ ^WŵŽƚŽƌ͕ϴϬϬ,W͕ϰϮϮϱs͕ϭϭϰ ŝ͘ >ŽǁĞƌƚĂŶĚĞŵƐĞĂů ũ͘ hƉƉĞƌƚĂŶĚĞŵƐĞĂů Ŭ͘ /ŶƚĂŬĞ ů͘ ϲϳϱƉƵŵƉ ŵ͘ ŝƐĐŚĂƌŐĞ,ĞĂĚ͕ϱͲϭͬϮ͕͟ϭϳη͕>ͲϴϬ͕>dďŽdžƵƉ Ŷ͘ ƌŽƐƐŽǀĞƌ͕ϱͲϭͬϮ͕͟ϭϳη͕>ͲϴϬ/dŽdždž>dWŝŶ Ž͘ ϭũŽŝŶƚ͕ϱͲϭͬϮ͕͟ϭϳη͕>ͲϴϬ/dŽdždžWŝŶ Ɖ͘ EŝƉƉůĞ͕, ^͕ϰ͘ϱϲϮ͟yEWƌŽĨŝůĞǁŝƚŚϰ͘ϰϱϱ͟ŶŽͲŐŽ͕ϭϬ͛ŚĂŶĚůŝŶŐƉƵƉƐĂďŽǀĞĂŶĚďĞůŽǁ͘ PJU $VVXUHJRRGIOXLGVVXSSRUW t^tZĞƉůĂĐĞ ^W tĞůů͗DWhDͲϬϲ ĂƚĞ͗ϬϵͬϬϮͬϮϬϮϮ DhƚŚĞĨŝƌƐƚϭϱũŽŝŶƚƚŽƚŚĞďĂƐĞŽĨƚŚĞƐƚĂŵƉĞĚƚƌŝĂŶŐůĞƚĂŬŝŶŐŶŽƚĞŽĨƚŚĞƌĞƋƵŝƌĞĚƚŽƌƋƵĞĨŽƌ ĞĂĐŚĐŽŶŶĞĐƚŝŽŶ͘ĂůĐƵůĂƚĞƚŚĞĂǀĞƌĂŐĞƚŽƌƋƵĞĂŶĚƵƐĞƚŚĂƚDhƚŽƌƋƵĞŽŶƚŚĞƌĞŵĂŝŶŝŶŐ ĐŽŶŶĞĐƚŝŽŶ͘ ϮϬ͘ ŽŶƚŝŶƵĞƚŽZ/,ǁŝƚŚƚŚĞ ^WĐŽŵƉůĞƚŝŽŶŽŶϱͲϭͬϮ͕͟ϭϳη͕>ͲϴϬ͕/dƚƵďŝŶŐ͘ Ϯϭ͘ WhĂŶĚDhƚŚĞƚƵďŝŶŐŚĂŶŐĞƌǁŝƚŚƚŚĞůĂŶĚŝŶŐũŽŝŶƚ͘dĞƌŵŝŶĂ ƚĞƚŚĞ ^WĐĂďůĞĂŶĚƐƉůŝĐĞƚŽƚŚĞ ƉĞŶĞƚƌĂƚŽƌ͘ ŶƐƵƌĞĂůůĐŽŶƚƌŽůůŝŶĞƉŽƌƚƐĂƌĞĚƵŵŵŝĞĚŽĨĨ͘ ϮϮ͘ >ĂŶĚƚŚĞƚƵďŝŶŐŚĂŶŐĞƌǁŝƚŚĞdžƚƌĞŵĞĐĂƵƚŝŽŶƚŽĂǀŽŝĚĚĂŵĂŐŝŶŐƚŚĞ ^WĐĂďůĞŽƌƉĞŶĞƚƌĂƚŽƌ͘ Z/>^͘ Ϯϯ͘ /ŶƐƚĂůůƚŚĞdt͘ Ϯϰ͘ EƚŚĞKWƐƚĂĐŬ͘ Ϯϱ͘ EhƚŚĞƚƵďŝŶŐŚĞĂĚĂĚĂƉƚĞƌĂŶĚWdƚŚĞƚƵďŝŶŐŚĂŶŐĞƌǀŽŝĚƚŽϮϱϬͬϱϬϬϬƉƐŝ͘ Ϯϲ͘ EhƚŚĞƚƌĞĞĂŶĚWdƚŚĞƚƌĞĞƚŽϮϱϬͬϱϬϬϬƉƐŝ͘ Ϯϳ͘ /ŶƐƚĂůůŐĂƵŐĞƐŽŶƚŚĞƚƌĞĞĂŶĚƐĞĐƵƌĞƚŚĞĐĞůůĂƌ͘ZĞůĞĂƐĞĂŶĚZDKZŝŐ͘ Ϯϴ͘ dƵƌŶƚŚĞǁĞůůŽǀĞƌƚŽŽƉĞƌĂƚŝŽŶƐǀŝĂŚĂŶĚŽǀĞƌĨŽƌŵ͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ ^ĐŚĞŵĂƚŝĐ Ϯ͘ WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘ KW^ĐŚĞŵĂƚŝĐ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB ZĞǀŝƐĞĚLJ͗d&ϭϬͬϵͬϮϬϭϵ ^, Dd/ DŝůŶĞWŽŝŶƚhŶŝƚ tĞůů͗DWhDŽŽƐĞWĂĚDͲϬϲ >ĂƐƚŽŵƉůĞƚĞĚ͗ϵͬϮϱͬϮϬϭϵ Wd͗ϮϭϵͲϭϭϯ ^/E' d/> ^ŝnjĞdLJƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵW& ϮϬΗdžϯϰ͟ŽŶĚƵĐƚŽƌ;/ŶƐƵůĂƚĞĚͿϮϭϱ͘ϱͬͲϱϯͬtĞůĚEͬ^ƵƌĨĂĐĞϭϭϯ͛Eͬ ϭϬͲϯͬϰΗ^ƵƌĨĂĐĞͬWƌŽĚƵĐƚŝŽŶϰϱ͘ϱͬ>ͲϴϬͬdyW^Zϵ͘ϵϱϬ͟^ƵƌĨĂĐĞϭ͕ϵϮϬ͛Ϭ͘ϬϵϲϮ ϵͲϱͬϴΗϰϬͬ>ͲϴϬͬdyW^Zϴ͘ϴϯϱ͟ϭ͕ϵϮϬ͛ϯ͕ϮϮϴ͛Ϭ͘Ϭϳϱϴ dh/E' d/> ϱͲϭͬϮ͟dƵďŝŶŐϭϳͬ>ͲϴϬͬ/dͲDKϰ͘ϴϵϮ͟^ƵƌĨĂĐĞϮ͕Ϯϭϰ͛Ϭ͘ϬϮϯϮ KW E,K> ͬ D Ed d/> ϰϮ͟ϱϬďďůƐ;ϭϬzĂƌĚƐWŝůĞĐƌĞƚĞĚƵŵƉĞĚĚŽǁŶďĂĐŬƐŝĚĞͿ ϭϯͲϭͬϮ͟>ʹϱϬϱƐdžͬdʹϭϬϮϬƐdžŝŶϭϯͲϭͬϮ͟ŚŽůĞ t >>/E>/Ed/KE d/> <KWΛϱϬϴ͛ DĂdž,ŽůĞŶŐůĞсϰϵΣΛϮ͕Ϯϭϱ͛D dZ Θt >>, dƌĞĞĂŵĞƌŽŶ&>^͕ϳ͟džϱͲϭͬϮΗϱDdƌĞĞ tĞůůŚĞĂĚϭϭΗϱDtĞůůŚĞĂĚ͘ϱͲϭͬϮΗdͲ//dŽƉĂŶĚŽƚƚŽŵdƵďŝŶŐ,ĂŶŐĞƌ ǁŝƚŚϱΗΗ,ΗWs'͘ϱĞĂϭͬϰΗEWdĐŽŶƚƌŽůůŝŶĞƐ͘ : t >Zz d/> EŽ͘dŽƉD/ƚĞŵ/ ϭϮϵ͛yK͗ϰ͘ϱ͟d//WŝŶyϰ͘ϱ͟dWŝŶʹDŝŶ/сϯ͘ϵϱϴ͟ϰ͘ϴϵϮ ϮϮ͕Ϭϴϳ͛EŝƉƉůĞ, ^ϰ͘ϱϲϮΗyEƉƌŽĨŝůĞǁͬϰ͘ϰϱϱΗŶŽŐŽϰ͘ϰϱϱ ϯϮ͕ϭϰϬ͛ŝƐĐŚĂƌŐĞ,ĞĂĚ͗ŽůƚKŶϲϳϱ^ĞƌŝĞƐWƵŵƉEͬ ϰϮ͕ϭϰϭ͛WƵŵƉ͗ϲϳϱWDW,W,s>Ϭϯϱ,ϮϬϬϬϬ& Z/Eͬ ϱϮ͕ϭϲϬ͛hƉƉĞƌdĂŶĚĞŵ^ĞĂů͗,^ϯy>d/Es^^s ,>W&Eͬ ϲϮ͕ϭϲϳ͛>ŽǁĞƌdĂŶĚĞŵ^ĞĂů͗,^ϯy>d/Es^^s ,>W&Eͬ ϳϮ͕ϭϳϰ͛DŽƚŽƌ͗,D/yϴϬϬ,Ɖͬϰ͕ϮϮϱsͬϭϭϰEͬ ϴϮ͕ϮϬϵ͛^ĞŶƐŽƌ͗ĞŶŝƚŚǁͬĞŶƚƌĂůŝnjĞƌ͗ƚŵΛϮ͕Ϯϭϰ͛Eͬ >Kt ZKDW> d/KE d/> ϵϮ͕ϯϱϴ͛ϵͲϱͬϴ͟sĞƌƐĂͲdƌŝĞǀĞWĂĐŬĞƌϲ͘ϬϬϬ ϭϬϮ͕ϯϴϯ͛ϳͲϱͬϴ͟džϱͲϭͬϮƌŽƐƐŽǀĞƌ͟ϰ͘ϴϲϬ ϭϭϮ͕ϯϴϳ͛ůĂŶŬWŝƉĞ͕ϱͲϭͬϮ͕͟ϭϳη͕>ͲϴϬ͕>důĂŶŬWŝƉĞϰ͘ϴϭϴ ϭϮϮ͕ϰϳϬ͛ϱͲϭͬϮ͟'ƌĂǀĞůWĂĐŬ^ĐƌĞĞŶƐ;ϮϱϬDŝĐƌŽŶͿϰ͘ϴϭϴ ϭϯϮ͕ϴϴϯ͛ůĂŶŬWŝƉĞ͕ϱͲϭͬϮ͕͟ϭϳη͕>ͲϴϬ͕>důĂŶŬWŝƉĞϰ͘ϴϭϴ ϭϰϮ͕ϴϴϳ͛tdŽƉͲ^ŶĂƉ^ƵŵƉWĂĐŬĞƌϰ͘ϲϲϱ ϭϱϮ͕ϴϵϯ͛DƵůĞƐŚŽĞ͕ϱϭͬϮΗϰ͘ϴϴϴ W Z&KZd/KE d/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿ&dĂƚĞ^ƚĂƚƵƐ >ŽǁĞƌWƌŝŶĐĞŬϮ͕ϱϬϵΖϮ͕ϲϬϬ͛Ϯ͕ϭϰϰ͛Ϯ͕ϮϬϱ͛ϵϭ͛ϵͬϮϮͬϮϬϭϵKƉĞŶ Ϯ͕ϲϱϰ͛Ϯ͕ϴϴϴ͛Ϯ͕Ϯϰϭ͛Ϯ͕ϯϳϵ͛Ϯϯϰ͛ϵͬϮϮͬϮϬϭϵKƉĞŶ ' E Z>t >>/E&K W/͗ϱϬͲϬϮϵͲϮϯϲϰϲͲϬϬͲϬϬ ƌŝůůĞĚĂŶĚĂƐĞĚďLJŽLJŽŶϭϰͲϵͬϮϮͬϮϬϭϵ 'WĂŶĚŽŵƉůĞƚŝŽŶďLJŽLJŽŶϭϰʹϵͬϮϱͬϮϬϭϵ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB ZĞǀŝƐĞĚLJ͗d&ϵͬϮͬϮϬϮϮ WZKWK^ DŝůŶĞWŽŝŶƚhŶŝƚ tĞůů͗DWhDŽŽƐĞWĂĚDͲϬϲ >ĂƐƚŽŵƉůĞƚĞĚ͗ϵͬϮϱͬϮϬϭϵ Wd͗ϮϭϵͲϭϭϯ dс ϯ͕Ϯϯϱ͛;DͿͬdсϮ͕ϲϯϮ͛;dsͿ ϮϬ͟ KƌŝŐ͘< ůĞǀ͗͘ϱϴ͘ϱ͛ͬ'> ůĞǀ͗͘Ϯϰ͘ϵ͛ Z<ʹ d,&͗ Ϯϴ͘ϵ͛;ŽLJŽŶϭϰͿ ϭϬͲϯͬϰ͟ Wdсϯ͕ϭϮϴ͛;DͿͬWdсϮ͕ϱϲϬ͛;dsͿ /RZHU3ULQFH ϱͲϭͬϮ͟ /RZHU3ULQFH ϵͲϱͬϴ͟ ^/E' d/> ^ŝnjĞ dLJƉĞ tƚͬ'ƌĂĚĞͬŽŶŶ / dŽƉ ƚŵ W& ϮϬΗdžϯϰ͟ ŽŶĚƵĐƚŽƌ;/ŶƐƵůĂƚĞĚͿ Ϯϭϱ͘ϱͬͲϱϯͬtĞůĚ Eͬ ^ƵƌĨĂĐĞ ϭϭϯ͛ Eͬ ϭϬͲϯͬϰΗ ^ƵƌĨĂĐĞͬWƌŽĚƵĐƚŝŽŶ ϰϱ͘ϱͬ>ͲϴϬͬdyW^Z ϵ͘ϵϱϬ͟ ^ƵƌĨĂĐĞ ϭ͕ϵϮϬ͛ Ϭ͘ϬϵϲϮ ϵͲϱͬϴΗ ϰϬͬ>ͲϴϬͬdyW^Z ϴ͘ϴϯϱ͟ ϭ͕ϵϮϬ͛ ϯ͕ϮϮϴ͛ Ϭ͘Ϭϳϱϴ dh/E' d/> ϱͲϭͬϮ͟ dƵďŝŶŐ ϭϳͬ>ͲϴϬͬ/dͲDK ϰ͘ϴϵϮ͟ ^ƵƌĨĂĐĞ цϮ͕Ϯϭϰ͛ Ϭ͘ϬϮϯϮ KW E,K> ͬ D Ed d/> ϰϮ͟ ϱϬďďůƐ;ϭϬzĂƌĚƐWŝůĞĐƌĞƚĞĚƵŵƉĞĚĚŽǁŶďĂĐŬƐŝĚĞͿ ϭϯͲϭͬϮ͟ >ʹϱϬϱƐdžͬdʹϭϬϮϬƐdžŝŶϭϯͲϭͬϮ͟ŚŽůĞ t >>/E>/Ed/KE d/> <KWΛϱϬϴ͛ DĂdž,ŽůĞŶŐůĞсϰϵΣΛϮ͕Ϯϭϱ͛D dZ Θt >>, dƌĞĞ ĂŵĞƌŽŶ&>^͕ϳ͟džϱͲϭͬϮΗϱDdƌĞĞ tĞůůŚĞĂĚ ϭϭΗϱDtĞůůŚĞĂĚ͘ϱͲϭͬϮΗdͲ//dŽƉĂŶĚŽƚƚŽŵdƵďŝŶŐ,ĂŶŐĞƌ ǁŝƚŚϱΗΗ,ΗWs'͘ϱĞĂϭͬϰΗEWdĐŽŶƚƌŽůůŝŶĞƐ͘ : t >Zz d/> EŽ͘ dŽƉD /ƚĞŵ / ϭ цϮϵ͛ yK͗ϰ͘ϱ͟d//WŝŶyϰ͘ϱ͟dWŝŶʹDŝŶ/сϯ͘ϵϱϴ͟ϰ͘ϴϵϮ Ϯ цϮ͕Ϭϴϳ͛ EŝƉƉůĞ, ^ϰ͘ϱϲϮΗyEƉƌŽĨŝůĞǁͬϰ͘ϰϱϱΗŶŽŐŽ ϰ͘ϰϱϱ ϯ цϮ͕ϭϰϬ͛ ŝƐĐŚĂƌŐĞ,ĞĂĚ͗Eͬ ϰ цϮ͕ϭϰϭ͛ WƵŵƉ͗Eͬ ϱ цϮ͕ϭϲϬ͛ hƉƉĞƌdĂŶĚĞŵ^ĞĂů͗Eͬ ϲ цϮ͕ϭϲϳ͛ >ŽǁĞƌdĂŶĚĞŵ^ĞĂů͗Eͬ ϳ цϮ͕ϭϳϰ͛ DŽƚŽƌ͗Eͬ ϴ цϮ͕ϮϬϵ͛ ^ĞŶƐŽƌ͗ĞŶŝƚŚǁͬĞŶƚƌĂůŝnjĞƌ͗ƚŵΛцϮ͕Ϯϭϰ͛Eͬ >Kt ZKDW> d/KE d/> ϵ Ϯ͕ϯϱϴ͛ ϵͲϱͬϴ͟sĞƌƐĂͲdƌŝĞǀĞWĂĐŬĞƌ ϲ͘ϬϬϬ ϭϬ Ϯ͕ϯϴϯ͛ ϳͲϱͬϴ͟džϱͲϭͬϮƌŽƐƐŽǀĞƌ͟ ϰ͘ϴϲϬ ϭϭ Ϯ͕ϯϴϳ͛ ůĂŶŬWŝƉĞ͕ϱͲϭͬϮ͕͟ϭϳη͕>ͲϴϬ͕>důĂŶŬWŝƉĞ ϰ͘ϴϭϴ ϭϮ Ϯ͕ϰϳϬ͛ ϱͲϭͬϮ͟'ƌĂǀĞůWĂĐŬ^ĐƌĞĞŶƐ;ϮϱϬDŝĐƌŽŶͿ ϰ͘ϴϭϴ ϭϯ Ϯ͕ϴϴϯ͛ ůĂŶŬWŝƉĞ͕ϱͲϭͬϮ͕͟ϭϳη͕>ͲϴϬ͕>důĂŶŬWŝƉĞ ϰ͘ϴϭϴ ϭϰ Ϯ͕ϴϴϳ͛ tdŽƉͲ^ŶĂƉ^ƵŵƉWĂĐŬĞƌ ϰ͘ϲϲϱ ϭϱ Ϯ͕ϴϵϯ͛ DƵůĞƐŚŽĞ͕ϱϭͬϮΗ ϰ͘ϴϴϴ W Z&KZd/KE d/> ^ĂŶĚƐ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ĂƚĞ ^ƚĂƚƵƐ >ŽǁĞƌWƌŝŶĐĞŬ Ϯ͕ϱϬϵΖ Ϯ͕ϲϬϬ͛ Ϯ͕ϭϰϰ͛ Ϯ͕ϮϬϱ͛ ϵϭ͛ ϵͬϮϮͬϮϬϭϵ KƉĞŶ Ϯ͕ϲϱϰ͛ Ϯ͕ϴϴϴ͛ Ϯ͕Ϯϰϭ͛ Ϯ͕ϯϳϵ͛ Ϯϯϰ͛ ϵͬϮϮͬϮϬϭϵ KƉĞŶ ' E Z>t >>/E&K W/͗ϱϬͲϬϮϵͲϮϯϲϰϲͲϬϬͲϬϬ ƌŝůůĞĚĂŶĚĂƐĞĚďLJŽLJŽŶϭϰͲϵͬϮϮͬϮϬϭϵ 'WĂŶĚŽŵƉůĞƚŝŽŶďLJŽLJŽŶϭϰʹϵͬϮϱͬϮϬϭϵ hƉĚĂƚĞĚϵͬϮͬϮϬϮϮ DŝůŶĞWŽŝŶƚ ^ZZŝŐϭKW ϮϬϮϬ ϭϭ͟KW ϰ͘ϰϴΖ ϰ͘ϱϰΖ Ϯ͘ϬϬΖ /tͲh ϰ͘ϯϬΖ,LJĚƌŝů'< ϭϭΗͲϱϬϬϬ sZŽƌWŝƉĞZĂŵƐ ůŝŶĚϭϭΖ͛ͲϱϬϬϬ ^͕ϭϭϱDyϳϭͬϭϲϱD;/ĨEĞĞĚĞĚͿ ϮϭͬϭϲϱD<ŝůů>ŝŶĞsĂůǀĞƐ ϮϭͬϭϲϱDŚŽŬĞ>ŝŶĞsĂůǀĞƐ ,ZDĂŶƵĂůDĂŶƵĂů,Z ^ƚƌŝƉƉŝŶŐ,ĞĂĚ ´[ ´9%5 DATA SUBMITTAL COMPLIANCE REPORT 1/1412020 Permit to Drill 2191130 Well NamelNo. MILNE PT UNIT M-06 MD 3235 TVD 2632 Completion Date 9/25/2019 REQUIRED INFORMATION / Mud Log No V DATA INFORMATION List of Logs Obtained: ROP/DGR/EWR/ALD/CTN MD & TVD, CCL/GR(Pollard) Well Log Information: Logi Electr Operator Hilcorp Alaska LLC Completion Status WTRSP Current Status WTRSP Samples No V/ Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data 'ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data ED C 31404 Digital Data Log 2191130 MILNE PT UNIT M-06 LOG HEADERS 31404 Log Header Scans Well Cores/Samples Information Name GS4KK9 Interval Start Stop Page I of Interval OHI Start Stop CH 110 3235 0 0 Sent Received API No. 50-029-23646-00-00 UIC No Directional Survey Yes✓ (from Master Well Data/Logs) Received Comments _ 11/4/2019 Electronic Data Set, Filename: MPU M-06 LWD Sample Set Number Comments Tuesday, January 14, 2020 Final.las 11/4/2019 Electronic File: MPU M-06 LWD Final MD.cgm 11/4/2019 Electronic File: MPU M-06 LWD Final TVD.cgm 11/4/2019 Electronic File: MPU M-06—Definitive Survey Report.pdf 11/4/2019 Electronic File: MPU M-06_DSR.tM 11/4/2019 Electronic File: MPU M-06_GIS.bd 11/4/2019 Electronic File: MPU M-06 LWD Final MD.emf 11/4/2019 Electronic File: MPU M-06 LWD Final TVD.emf 11/4/2019 Electronic File: MPU M-06 LWD Final MD.pdf 11/4/2019 Electronic File: MPU M-06 LWD Final TVD.pdf 11/4/2019 Electronic File: MPU M-06 LWD Final MD.tif 11/4/2019 Electronic File: MPU M-06 LWD Final TVD.tif 11/4/2019 Electronic File: EMFView3_1.zip 11/4/2019 Electronic File: Readme.txt 2191130 MILNE PT UNIT M-06 LOG HEADERS Sample Set Number Comments Tuesday, January 14, 2020 DATA SUBMITTAL COMPLIANCE REPORT 1/14/2020 Permit to Drill 2191130 Well Name/No. MILNE PT UNIT M-06 MD 3235 TVD 2632 INFORMATION RECEIVED Completion Report `l Production Test InformatiorD/ NA Geologic Markers?ops V COMPLIANCE HISTORY Completion Date: 9/25/2019 Release Date: 8/29/2019 Description Comments: Completion Date 9/25/2019 Operator Hilcorp Alaska LLC Completion Status WTRSP Current Status WTRSP API No. 50-029.23646.00-00 LIC No Directional / Inclination Data G) Mud Logs, Image Files, Digital Data Y /(5 Core Chips Y Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files Core Photographs Y NA Daily Operations Summary GCuttings V Samples Yo Laboratory Analyses Y / Date Comments Compliance Reviewed ByDate: AOGCC Page 2 of 2 Tuesday, January 14, 2020 Surface Casing by Conductor Annulus Fill Coat Corrosion Inhibitor (CI) Applications Well Field API PTD Top of Cement (ft.) Corrosion Inhibitor Fill Volume (gal) Final Cl Top (ft.) Corrosion Inhibitor Treatment Date E-35 Milne Point 50029236150000 2181520 Surface 22.5 Topof Cond 10/24/2019 E-36 Milne Point 50029236200000 2190050 Surface 15 Top of Cord 10/24/2019 E-38 Milne Point 50029236260000 2190440 Surface 20 Top of Cord 10/24/2019 E-39 Milne Point 50029236400000/60-00 2190960 Surface 20 Topof Cond 10/24/2019 E-40 Milne Point 50029236260000 2190440 Surface 25 Topof Cond 10/25/2019 E-41 Milne Point 50029236220000 2190310 Surface 15 Topof Cond 10/24/2019 E-42 Milne Point 50029236350000/60-00 2190820 Surface 17 Top of Cord 10/25/2019 M-18 Milne Point 50029236320000 2190700 3 50 Topof Cond 10/26/2019 M-06 Milne Point 50029236460000 2191130 3 30 Topof Cond 10/26/2019 Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat Notes: #7 Initial top of Cement footage measurement was taken from the 4" outlet down to the TOC The 4" conductor outlets are any where from 1 to 3' down from the top of the conductor RECEIVED DEC 0 6 2019 AOGCC STATE OF ALASKA ALAS JIL AND GAS CONSERVATION COMMIS, A REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Ll Plug Perforations LJ Fracture Stimulat Pull Tubing Ll Operations shutdown Li Performed: Suspend ❑ Perforate ❑ Acid Stimulat Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ :rforate New Pool ❑ Repair Wel❑ Re-enter Susp Well ❑ Other: ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska LLC Development ❑ Exploratory ❑ Stratigraphic ❑ Service ❑� 219-113 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-23646-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0025514 MPU M-06 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): NIA Ailne Point Field / Prince Creek Water Tertiary Undef WTRS 11. Present Well Condition Summary: Total Depth measured 3,235 feet Plugs measured N/A feel true vertical 2,632 feet Junk measured N/A feet Effective Depth measured 3,128 feet Packer measured 2,358 & 2,893 feet true vertical 2,560 feet true vertical 2,044 & 2,400 feet Casing Length Size MD TVD Burst Collapse Conductor 113' 20" 113' 113' N/A N/A Surface 1,920' 10-3/4" 1,920' 1,753' 5,210psi 2,470psi Production 1,308' 9-5/8" 3,228' 2,627' 5,750psi 3,090psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 5-1/2" 17# / L-80 / IBT-MOD 2,214' 1,949' 9-5/8" Versa-Trieve Packers and SSSV (type, measured and true vertical depth) BWD Sump N/A See Above N/A 12. Stimulation or cement squeeze summary: Pump 56 bbls 15% DAD Acid and 3 bbls 60/40. Displace acid w/ 97 bbls source water. Intervals treated (measured): 2,509' to 2,600'& 2,654' to 2,888' Treatment descriptions including volumes used and final pressure: 56 bbls 15% DAD, 3 bbls 60/40 & 97 bbls of source water. 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 4,300 0 423 Subsequent to operation:1 0 0 5,582 0 563 14. Attachments (required per 20 MC 29.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations Exploratory❑ Development ❑ Serviced Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑ Gas WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WTRSP ❑� WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-467 Authorized Name: Chad Helgeson Contact Name: David Haakinsorh"� Authorized Title: Operations Manager Contact Email: dhaakinson(a.hilcorp.cor Authorized Signature: Date: 11/12/2019 Contact Phone: 777-8343 Form 10-404 Revised 4/2017 Z13DIMS-11�'Nov 14 2019 RECEIVED NOV 13 2019 AOmJLnil�r .', Only Hilcorp Alaska, LLC Weekly Operations Summary Well NameRig API Number Well Permit Number Start Date End Date MP M-06 Pump 50-029-23646-00-00 219-113 10/14/2019 10/18/2019 10/9/2019- Wednesday No operations to report. 10/10/2019 -Thursday No operations to report. 10/11/2019 - Friday No operations to report. 10/12/2019 -Saturday No operations to report. 10/13/2019 -Sunday No operations to report. 10/14/2019 - Monday No operations to report. 10/15/2019 -Tuesday Inj. Test (PT surface lines 250/2,500 psi) Pump 252 bbls Source water and Freeze protect IA w/ 86 bbls Dsl @ 2 bpm. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP M-06 Pump 50-029-23646-00-00 219-113 10/14/2019 10/18/2019 10/16/2019 - Wednesday No operations to report. 10/17/2019 - Thursday No operations to report. 10/18/2019 - Friday Acid Treatment (PT surface lines 250/2,500 psi) Pump 56 bbls 15% DAD Acid and 3 bbls 60/40. Displace acid w/ 77 bbls source water. Let Soak for two Hours. Pump 20 bbls more of source water. Freeze protect surface lines w/ 3 bbls 60/40. 10/19/2019 -Saturday No operations to report. 10/20/2019 -Sunday No operations to report. 10/21/2019 - Monday No operations to report. 10/22/2019 -Tuesday No operations to report. DATE: 10/29/2019 Debre Judean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTA =PTD 213-^33 CD: HALLIBURTON FINAL DATA 21 SEP 2019 ROP DGR EWR-PHASE 4 DECEIVED NOV 0 4 2019 AOGCC CGM 10/29+'20192:15PM Filefolder Definitive Survey 10/29,12019 2:16 PM Filefolder EMF 10;'29/20192:16PM Filefolder LAS 10/29/2019 2:16 PM File folder PDF 10/29/20192:16 PM Filefolder TIFF 10,'29/2019116 PM Filefolder _Log Viewers 10/29/20192:16 PM Filefolder 21 91 13 3 140 4 Please acknowledge receipt by sig ni}g and retming one copy of this transmittal or FAX to 907 777.8510 IM IM, blm, IM, -. STATE OF ALASKA ' ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a. Well Status: oil El Gas SPLUG❑ Other ❑✓ Abandoned ❑ Suspended[] 1b. Well Class: WT(LSf 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory ❑ GINJ ❑ WINJ ❑ WAG[:] WDSPL ❑ No. of Completions: _ 1 Service ❑✓ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Abend.: 9/25/2019 14. Permit to Drill Number / Sundry: 219-113 / 319-412 / 319-467 3. Address: 7. Date Spudded: 15. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 September 15, 2019 50-029-23646-00-00 4a. Location of Well (Governmental Section): 8. Date TO Reached: 16. Well Name and Number: Surface: 4916' FSL, 861' FEL, Sec 14, T13N, R9E, UM, AK September 16, 2019 MPU M-06 Top of Productive Interval: 9. Ref Elevations: KB: 58.5' , 17. Field / Pool(s): Milne Point Unit 507' FNL, 1866' FEL, Sec 14, T13N, R9E, UM, AK GL: 24.9' BF: 24.9' ` Prince Creek Undef (TER Undef WTRSP) Total Depth: 10. Plug Back Depth MDTFVD: 18. Property Designation: 580' FNL, 2405' FEL, Sec 14, T13N, R9E, UM, AK 3,128' MD / 2,632' TVD ADL025514 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 533303 y- 6027765 Zone- 4 3,235' MD / 2,632' TVD LONS 16-004 TPI: x- 532300 - y- 6027617 - Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 531761 y- 6027542 Zone- 4 N/A 2,015' MD / 1,817' TVD 5. Directional or Inclination Survey: Yes ✓ (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP DGR EWR ALD CTN MD & TVD, CCL & GR (Pollard) RECEIVED OCT 22 2019 A 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CASING FT TOP BOTTOM -T3F--T BOTTOM CEMENTING RECORD AMOUNT PULLED 20" 215.5# X-42 Surface 113' Surface 113' 42" ±270 ft3 10-3/4" 45.5# L-80 Surface 1,920' Surface 1,754' 13-1/2" L - 505 sx / T - 1020 sx 40 bbls 9-5/8" 40# L-80 1,920' 3,228' 1,754' 2,626' 24. Open to production or injection? Yes ❑✓ No ❑ 25. TUBING RECORD If Yes, list each interval open (MD1TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MDf FVD) Size and Number; Date Perfd): 5-1/2^ 2,214' N/A "Please see attached schematic for perforation details - 4 -5/8" guns / 12 SPF COMPLETION 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ✓ No Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED VOPDATE /_bls ' 2509-2600' 56 bbls 15% DAD Acid and 3 b 60/40 -kton 2654-2888' 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 10/4/2019 ESP Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 10/11/2019 24 Test Period 0 0 4730 N/A N/A Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 492 0 24 -Hour Rate --J� 0 0 4730 N/A Form 10-407 Revised 5/2017 /� Zr ,�CONT,INUED ON PAGE 2ABDMSAK-14 OCT 2 8 Y019�ubmit onip 28. CORE DATA Conventional Core(s): Yes ❑ No ❑D Sidewall Cores: Yes ❑ No ❑� If Yes, list formations and intervals cored (MD/TVD, From/ro), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost- Base 2,015' 1,817' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 2,509' Prince Creek 2,144' information, including reports, per 20 AAC 25.071. SV5 1,345' 1,301' SV1 2,081' 1,861' UG3 2,928' 2,424' Formation at total depth: Ugnu 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: Cdlfl Bf hIICOf .COtll Authorized Contact Phone: 777-8389 Signature: Date: / ;• 2 / INSTRUCTIONS General: This form and the required a ac is provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10407 Revised 5/2017 Submit ORIGINAL Only K Hamm Ataeka, LLC 04 KB 13w: 58.5'/GLELwt 24.9' TD = 3,235' (MD) /TD = 2,632'UM) PBTD= 3,128'(MD)/ PBTD= 2,560' (CVD) SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-06 Last Completed: 9/25/2019 PTD: 219-113 Tree Cameron FIS, 7" x 5-1/2" 5M Tree Surface 1,920' 0.0962 11" SM Wellhead. 5-1/2"TC-Il Top and Bottom Tubing Hanger Wellhead with 5" "H" BPVG.5 ea 1/4" NPT control lines. OPEN HOLE / CEMENT DETAIL 42" 50 bbls(10 yards Pilecrete dumped down backside) 13-1/2" L-505sx/T-1020sx in 13-1/2" hole BPF 20"x34" I Conductor finsulatedl 1 215.5/A-53/Weld I N/A I Surface 1 113' 1 N/A I 10-3/4" 45.5/L-80/T%P SR 9.950 Surface 1,920' 0.0962 Surface/Production 1 29' 9 5/8" 40 / L-80 / TXP SR 8.835" _1,92.0' _ 3,228' 0.0.758 2,087' TUBING DETAIL 4.455 5-1/2" Tubing 17/L -80/167 -MOD 4.892" Surface 2,214' 0.0232 N/A WELL INCLINATION DETAIL 2,141' Pump: 675 PMP HPHVL 035 HC20000 FER I KOP @ 508' 5 2,160' Upper Tandem Seal: HSB3DBXLT INV SSCV EHL PF Max Hole Angle =49* @ 2,215' MD 6 2,167' Lower Tandem Seal: HS9313MLT INV SSCV EHL PF IFWFI RY nFTAII 7 No. Top MD Item ID 1 29' XO: 4.5"TCII Pin X4.5"3TC Pin - Min ID=3.958" 4.892 2 2,087' Nipple HES 4.562" XN profile w/4.455" nogo 4.455 3 2,140' Discharge Head: Bolt On 675 Series Pump N/A 4 2,141' Pump: 675 PMP HPHVL 035 HC20000 FER I N/A 5 2,160' Upper Tandem Seal: HSB3DBXLT INV SSCV EHL PF N/A 6 2,167' Lower Tandem Seal: HS9313MLT INV SSCV EHL PF N/A 7 2,174' Motor: HMIX 800Hp/4,225V/114A N/A 8 2,209' Sensor: Zenith w/Centralizer: Btm @ 2,214' N/A LOWER COMPLETION DETAIL 9 2,358' 9-5/8" Versa-Trieve Packer 6.000 30 2,383' 7-5/8" x 5-1/2 Crossover" 4.860 11 2,387' Blank Pipe, 5-1/2", 17#, L-80, LTC Blank Pipe 4.818 12 2,470' 5-1/2" Gravel Pack Screens (250 Micron) 4.818 13 2,883' Blank Pipe, 5-1/2', 17#, L-80, LTC Blank Pipe 4.818 14 2,887' BWD Top -Snap Sump Packer 4.665 15 2,893' Muleshoe, 5 1/2" 4.888 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status 2.509' 2,600' 2,144' 2,205' 91 9/22/2019 1 Open Lower Prince Ck 2,654' 2,888' 2,241' 2,379' 234' 9/22/2019 1 Open GENERAL WELL INFO API: 50-029-23646-00-00 Drilled and Cased by Doyon 14 - 9/22/2019 GP and Completion by Doyon 14-9/25/2019 Revised By: TDF 10/9/2019 n Well Name: MP M-06 Field: Milne Point County/State: , Alaska (LAT/LONG): ovation (RKB): API #: Spud Date: Job Name: 1914443D MPU M-06 Drilling Contractor Doyon 14 ARE #: ARE S: Hilcorp Energy Company Composite Report Activity Date: Ops Summary 9'142019 Skid Rig floor into moving position & move off Well M-22.; Move, spot & shim Rig level over Well M-06.;Sed Rig floor into Drilling position, Spot Rockwasher into place - Berm Cuttings Tank. Prep Cellar, start install 16" Diverter line. Prep mud pits for mud and rig up stream, air and water to the rig floor. Sim ops: Move rig shop and spot at entrance to pad.;Nipple up surface BORE, spot remaining support shacks around rig. work on rig acceptance checklist. Perp mud pumps for drilling. Continue install 16" diverter line.;Prep pad for cement silos. Spot water tank and rig up water transfer pump. Bring on water to pits. Finish torquing bolts on diverter line. Finalize acceptance checklist, Rig accepted at 21:OO.;Load, and finish processing 140 jts 5" Drilipipe. Load Sperry BHA components into pipe shed. Start bring on Spud mud to pits.;Perform diverter function test on 5" drill pipe. "' Test witness waived by AOGCC. insp Jeffery Jones @ 05:48, 9/14/2019" Knife valve opened -13 sec & annular closed- 25 sec. Accumulator: 3000 PSI system, 1850 PSI after closure, 39 sec. 200 PSI recharge, 147 sec. full recharge, 1977 PSI 6 Bottle Avg.;PJSM. PIU 84 joints of 5" drill pipe & rack back 28 stands in the derrick.;Sewice Top Drive, Skate, Drawworks and Iron Roughneck.;Continue to PIU and rack back 5" Drill pipe. 9/15/2019 Continue to M/U and rack back 5" DP. 120 jts 140 stds total picked up. Load, process, pick up and rack back 6 stds 5" HWDP and Jars.;Perform Pre -Spud Derrick inspection. "Rig on Hi -Line @ 09:00";Service Rig, Cut and Slip 54' of drilling Iine.;Hold Pre -Spud and PJS Meetings with Rig Crew and Service hands. MU 13-1/2" Kymera Bit to Sperry Mud Motor, BNXO and 1 std 5" HWDP.;PJSM with all hands. Flood stack with water & fill conductor. Test lines to 3500 psi. Good.; RIH & tag bind of conductor at 113'. Drill to 120'& displace to Spud mud. Drill to 220' at 400 GPM. 20 RPM. Back ream up to conductor & GQ circ clean. POOH & stand back HW DP.;M/U MWD tool to the BHA and BNXO. Upload tools & shallow hole test - Good -;RIH and Drill 13-1/2" surface hole f/ JJ 229 t/ 641', (633' TVD) 421' drilled, 607hr AROP. 440 GPM, 930 PSI, 40 RPM, 3K TO, 3-7K WOB. 81 K PU 181 K SO / 81 K ROT. 8.8 ppg MW, 110 vis, 9.25 ECD. Began 3°/100' build at 453'.;Drill 13-1/2" hole f,' 641' U 1208',(1195' TVD) 567'@ 94'/hr AROP. 505 GPM, 1290 PSI, 40 RPM, 2-6K TO, 5K WOB. 91 K PU / 91 K SO / 91 K ROT. 9.1 MW, 155 vis, 9.79 ECD. Start 4° BUR @ 732'. Last survey at 1168.32' MD / 1146.62' TVD, 25.89° inc, 265.99° azm, 18.39' from plan, 18.19 high, 2.74' left.; Hauled 400 bbis H2O from L -Pad Lake for total = 400 bbls Hauled 400 bbis H2O from A -Pad for total = 400 bbls Hauled 466 bbls cuttings/liquids to MPU G&I for a toal = 466 bbis 9/16/2019 Drill 13-1/2" surface hole from 1208' to 1778' (1650' TVD), 570' with AROP of 95 FPH. 525 GPM, = 1510 PSI, 80 RPM = 3-5K ftllbs TO, 5-7K WOB. MW = 9.1 ppg, Vis = 164, ECD = 10.05 ppg, max gas = 146 units. PU = 103K, SO = 95K, ROT = 98K. Backream 30'. Continue 4° BUR.; Drill 13-1/2" surface hole from 1778' to 220D'(1 956' TVD), 422' with AROP of 120 FPH. 520 GPM, = 1330 PSI, 80 RPM = 4-7K ft/lbs TO, 2-5K WOB. MW = 9.0 ppg, Vis = 113, ECD = 10.00 ppg, max gas = 126 units. PU = 109K, SO = 95K, ROT = 101 K. Backream 30'.;Built with 4°/100' to 48.4° inclination at 1949' and held to TD.;Troubleshoot conveyor #2 problems. Pull off bottom, rotate and reciprocate stand. 282 GPM, 50 RPM.;Change out links on #2 conveyor, Wash and ream while BROOH slowly from 2200' 1971'282 GPM, 50 RPM. With conveyor fixed, trip back in hole on elevators t/ 2066' Wash & Ream down from 2066' 300 GPM, 30 RPM. Tag bottom on depth w/ no fill at 2200'.; Drill 13-1/2" surface hole from 2200' to 2826' (2356' TVD), 626' with AROP of 104 FPH. 525 GPM, _ 1580 PSI, 80 RPM = 7-8K fUlbs TO, 5-8K WOS. MW = 9.0 ppg, Vis = 128, ECD = 10.25 ppg, max gas = 162 units. PU = 119K, $O = 99K, ROT = 107K. Backream Full Stands.:Drlll 13-1/2" surface hole from 2826to 3235' (2631' TVD), 409' with AROP of 117 FPH. 520 GPM, = 1580 PSI, 80 RPM = 7-8K fulbs 1<9 TO, 10K WOB. MW = 9.3 ppg, Vis = 145, ECD = 10.14 ppg, max gas = 173 units. PU = 133K, SO = 100K, ROT= 114K. Backream Full Stands.;Final survey at 3194.95' MD / 2604.71' TVD, 47.48° inc, 260.86° azm, 7.96' from plan, 7.68' high, 2.12' right.;Circulate tandem 30 bbl sweeps around. 550 GPM, 80 RPM. BROOH slowly 1:13085 while circulating. No increase in cuttings with sweep back. Continue circulating another bottoms up. Shakers clean. 2.5 total bottoms up pumped. RIH t/ bottom on elevators.;Hauled 1600 bbls H2O from L -Pad Lake for total = 2000 bbis Hauled 0 bbis H2O from A -Pad for total = 400 bbls Hauled 1529 little cuttings/liquids to MPU G&I for a toal = 1995 bbis 9/17/2019 BROOH from 3235' to 1208' MD. 521 gpm/1340 psi, 80 rpm/3-10K Tq,. MW 9.2 ppg, ECD 10.9 ppg, 5-10 minutes per stand. No issues BROOH to 1209.;Continue to BROOH from 1208' to 734'. 522 gpm/1280 psi, 80 rpm/4-6K Tq, Rot 90K, MW 9.2 ppg, ECD 10.9 ppg, pulling speed @ 20 fpm.;Monitor Well, Static. UD 5" HWDP and Jars. UD Flex Collars and POOH to 87'. Down Load MWD Tools and clean and clear rig floor.;Down Load MWD Tools and clean up rig floor.;UD remaining BHA. Bit graded 1-1-WT-A-E-1-NO-TD.;Clean and Clear rig floor. RIU to mn 10 3/4" x 9 5/8" tapered casing string. 0.6 BPH static lOsses.;PJSM. M/U 9-5/8" 40# L-80 TXP-BTC shoe track to 160'. float shoe joint, Baker Loc joint, float collar joint and joint #1. Baker Loc all connections / rT'.y & torque to 21,000 ft/lbs. Pump through shoe track @ 3.5 BPM, 40 PSI. Check floats - good.;Two 9-518"x12-1/2" Expand-o-lizer centralizer w/ four stop rings installed on shoe joint, one free floating on Baker Loc joint, one w/ two stop rings on float collarjoint & one free floating on joint #1 .;Run 9-5/8" 40# L-80 TXP- Al'� BTC casing f/ 160 U 1305'. Torque connections to 21,000 ft/lbs with Doyon Volant tool. Install one 9-5/6'x12-1/2" Expand-o-lizer centralizer free-floating on 930. Fill fly, 10 & 20 bills 20 to 6 BPM, 120 PSI in 1 bbl increments. Circulate two everyjoinl #2 to on the top off every pump every joints.;Stage pumps up i bottoms up while reciprocating f/ 1305't/ 1275'.;Redress the Volant tool for 10-3/4". Remove & replace dies, backing cup, seal cup & stabbing guide. Install additional segment in casing hand slips.: Run 10-3/4" 45.5# L-80 TXP-BTC casing f/ 1305' U 3228'. Torque to 23,000 ft/lbs with Doyon Volant tool. Fill on the v5 fly, top off every 10 & pump 20 bbis every 20 joints. Install 10-3/4"x13-1/2" bow spring centralizer across every other casing collar. 174k PU / 130K SO.;Wash down last joint @ 2 BPM, 40 PSI. 33 joints 9-5/8" casing ran w/ 34 each 9-5/8"x12-1/2" Expand-o-lizer centralizers and 47 joints 10-3/4" casing ran w/ 23 each 10-3/4"x13-1/2" bow spring centralizers.; Hauled 820 bbis H2O from L -Pad Lake for total = 2820 bbis Hauled 0 bbls H2O from A -Pad for total = 400 bbis Hauled 660 bbis Source Water from G&I = 660 bible Hauled 807 bbis cuttings/mud/cement = 2802 bbis Daily losses (midnight) = 9 bills, cumulative losses for interval = 9 bbis. 9/18/2019 Circulate and condition mud for curt job, staging pumps to 6 bpm/100 psi, 10 rpm/18-21 Tq.;Blow down Top Drive. R/U cement line to Volant Cmt Swivel.;Pump cement job: HAL fill lines with 5 bbls H2O PT 1000 psi low, 4000 psi high -good. Pump 5 bels 10.0 ppg Clean Spacer, Drop Btm Plug, pump remaining 55 bels spacer, with red dye at 4.5bpm235 psi. PumD 392bbls 10.7 Doe Perm L lead cmt at 5bpm/350 psi, Pump 212 bbls Tail cmt @ 5 bpm/625 psi.;Drop Top Plug. Displace cmt with 20 bels FW f/HES, Turn over to rig and pump 261 bbis mud @ 6 bpm/810 psi. Slow to 3 bpm/ 770 FCP. Bump plug 4 bels over calculated. Hold 1250 psi. Check Floats, Floats good. CIP @ 13:45. Dumped 212 bbls areen cmt at surface. Zero losses through out job.;Disconnect knife valve. Flush diverter stack w/ black water. Blow and rig down cement lines, diverter and Volant tool. Clean mud pit surface equipment.; Hoist diverter stack. Install 10-3/4" casing slips with 100K weight on slips. Rough out 10-314" casing & UD cut joint. Set diverter stack back down.— AOGCC notified of upcoming BOP at 16:34 "';N/D bell nipple, riser, surface annular, knife valve & tee. Sim ops: Clean mud pits. Clean and clear rig floor of casing equipment.;Make finish cut on 10-3/4" casing, 26.64'total cut. Install FMC 11" SK slip lock casing head. Pressure test casino head seals to 500 PSI for 5 min. & 1976 PSI for 10 min. (80% of 10-3/4" collapse). N/U 11" 5K casing and tubing spools. N/U BOP stack, kill line and turnbuckles.;Change out lower rams from 2-7/8"x5" VBR to 3-112"x6" VBR.;Install test plug & 5" test joint. Rig up test equipment. Fill BOP stack, choke and lines with water.;Hauled 190 bbls H2O from L -Pad Lake for total = 3010 bbis Hauled 0 bbis H2O from A -Pad for total = 400 bbis Hauled 0 bbis Source Water from G&I = 660 bbls Hauled 1945 bels cuttings/mud/cement = 4747 bbls Daily losses = 0 bbls. cumulative losses for interval = 9 bbis 9/19/2019 Pump through gas buster to purge air. Perform shell test of BOPS, 250 PSI low and 3000 PSI high for 5 min. each - good test.;Test BOP equipment as per AOGCC PTD requirements. AOGCC representative Matthew Herrera waived right to witness at 07:23 on 19 Sept 2019. All tests performed w/ fresh water to 250 PSI low & 3000 PSI high. Tests held for 5 min. & charted.;#1: Annular on 5" test joint, valves 1, 12, 13 14, 3" kill Demco & upper IBOP - pass #2: Upper 4.5'x7" VBR on 5" test joint, valves 9 &11, HCR kill & lower IBOP - pass #3: Valves 5, 8, 10, manual kill, 5" FOSV #1 - valve #10 F/P - grease & retest good #4: Valves 4, 6, 7 & 5" dart valve - pass.;#5: Valve 2 - pass #6: HCR choke & 5" FOSV #2 - pass 97: Manual choke - pass 98 Lower 3.5"x6" VBR on 5" test joint - F/P - test joint aired up, bleed air & retest good #9: Blind rams & valve 3 -pass #10: Lower 3.5'x6" VBR on 5.5" test joint - fail - UD test joint & continue testing.;#11: Valve "A" super choke -good #12: Valve "B" super choke -good #13: 3.5" IF dart valve #14: 3.5" IF FOSV Accumulator test: 3000 PSI system pressure, 1700 PSI after closure, 200 PSI in 47 sec, full recovery in 189 sec. Six nitrogen bottles @ 2007 PSI avg.;Milne Point 08 generator went down and rig was kicked off highline power. Start rig generator, warm up and swap to rig power.;lnstall second 5.5" test joint. Fill stack & rams would not even hold water. Change out lower set of rams from 3-1/2"W' VBR to backup set of 3-112"x6" VBR. No damage found on ram elements.;Fill stack & attempt to body test, but would not hold fluid. Drain stack, observe one side of lower rams not cycling properly. Troubleshoot rams, found operator not working properly. Decision made to replace operator. Remove ram door / operator assembly from lower rams.;Transport replacement from Doyon yard in Deadhorse. Remove doodoperator from replacement ram block. Mobilize to the cellar and install ram door / operator. "' Back on highline power at 00:15 "';Hauled 270 bbis H2O from L -Pad Lake for total = 3280 bels Hauled 0 bbls H2O from A -Pad for total = 400 bbis Hauled 0 bbls Source Water from G&I = 660 bbis Hauled 87 bbls cuttings/mud/cement = 4834 bbis 0 bbis daily losses, 9 bels cumulative losses. 9/20/2019 Continue to install ODS Ram Door and C/O Wear Plate. Attempt to test LPR's on both sets of 3 1/2" x 6" VBR Ram blocks. Both sets failed test in Lower Single gate.;PJSM, on C/O Rams. Install 5" solid body Rams in LPR. P/U 5" Test joint screw into test plug. Close LPR and fill from top. Hydrostatic test Nailed. Prep to C/O Single Gate.;PJSM. Remove Trip Nipple and send to shop and add 6" to same. Remove 4" Choke Line. and kill line Remove 5" Ram Blocks from Single gate.;N/D annular, double gate rams and mud cross and rack back on stump. N/D single gate ram and transport to the Doyon rig shop.;Remove operator assembly from old single gate and install on replacement single gate.;N/U replacement single gate rams. N/U annular, double gate rams and mud cross. Install 3-112"x6!'VBR in lower rams. Install kill line and tighten choke line. Install Flow nipple and turn buckles.; Install 5-1/2" test joint. Fill BOP stack and lines with water and purge air from system. Perform BOP shell test to 250 PSI low / 3000 PSI high against choke valve #1, kill line Demco and upper 4-1/2"x7" VBR on 5- 1/2" test joint.;Resume BOP testing. All tests performed with fresh water, held for 5 min. each to 250 PSI low / 3000 PSI high. #15: Upper 4-1/2"x7" VBR on 5- 1/2" test joint, valve 1 and kill line Demco - good. #16: Lower 3-1/2"x6" VBR on 5-1/2" test joint - good. 9/21/2019 Continue test ROPE after changing out Single gate. 250/3000 psi. Witness waived by Matt Herrera. Test Upper and Lowerpipe rams with 5 1/2" test joint. Test lower pipe ram with 5" Test joinl.;Rig down test equipment. Did not set Wear bushing due to clearance for 10 3/4" scraper.;M/U & TIH with tandem 9 518" x 10 3/4" Scraper assy to 3056. Pipe started running wet when in 9 5/8" Casing. Make Top Drive connection to Mitigate wet pipe. Set down @ 2113'. W/R from 2113' to 2160'. Wash last stand to bottom and Tag hard cement @ 3128'. (Top of FC @ 3145'.);PJSM, Pump 30 bbis spacer, Displace well to 8.6 2% KCL .I., Brine @ 8.8 bpm/450 psi. Over board all returns until clean brine at surface.;Test 10 3W' x 9 5/8" casing to 3500 psi on chart for 10 minutes. Good test.;PJSM, C S (y/ POOH with Scraper BHA standing back 5" DP from 3128' to surface. UD BHA. Scrapers and bit looked good. Install long wear bushing, 9-1/16" I.D.;PJSM. V Mobilize logging tools & R/U a -line sheaves. M/U CCL & gamma ray tools, TIH & tag cement @ 3130'. Perform CCL / GR log out of the hole.;M/U Halliburton sump packer with CCL on a -line. RIH to 3090' & perform correlation log. 1250# PU / 400# SO. Center of packer at 2900'. Top of Packer is at 2896.27'. Fire setting charge - observe good indication of firing. PU 875# after firing/setting/release. POOH and UD running tool.;R/D a -line sheaves & clear casing scraper BHA components from the rig floor. Mobilize Halliburton perforating gun equipment to the rig floor.;PJSM. WU 4-518" Halliburton 12 spf Maxforce perforating assy to 382.66'. Snap latch w/ XOs to 10 full guns (226'), 2 full blanks w/ 8' blank pup (54'), 4 full guns (91') & firing head. 317' total of perforations. WU safety pint wgh perf gun XO for trip out. 1 , to 1,rP av-7" low Well Name: MP M-06 Field: Milne Point County/State: , Alaska (LAT/LONG): ovation (RKB): API #: Hilcorp Energy Company Composite Report Spud Date: Job Name: 1914443C MPU M-06 Completion Contractor AFE #: Ops SummaryRIH with TCP Gun Ass on 5" OP from 382'to 2856'. Obtain Parameters PUW 100K SOW 80K. RIH from 2856' and snap into sump PKR x2 @ 2887' W/5K Down. Unsnap f/PKR w/15K Over to confirm Depth. Tagged top of PKR -9' shallow. Review and confirm tally depths are correct., Decision made to R/U E -Line and log top of PKRdue to discrepancy in Sump PKR set depth.. Snap into Sump PKR. R/U and RIH through DP with GR/CCL(6.30') w/2.75"OD No -Go. Set 79/2212019 down on 4 1/2" IF x 2 7/8" eue XO above firing head@ 2505'. Confirming PKR Set 8.61'Shallow when snapped in w/5K set Dn. POOHandR/DE-Line. Confirm Perforation depths with Engineer.,Unsnap from Sump PKR, and place Bim Shot Lower Zone f/ 2880-2654' Bim Shot Upper Zone f/2600'-2509. Close UPR, Line up to Closed Choke. With 1 3/8" Ball on seat, pressure up @ i/4 bpm and see guns fire @ 2100 psi. Monitor Choke pressure with 0 psi. Open Choke and UPR. 3 bbis to fill hole. CBU from 2500'. Lost 5 bbls on circulation. Snap into sump PKR to ensure no debris on top of PKR. Monitor well @ 6 ph loss rate-TOOH with 5" DP to 382'. UD Spent guns - all guns fred and looked normal. Clear Halliburton equipment off the rig Floor. 9.5 bbis lost on TOOH, 2 BPH average.,Mobilize 5.5" and 3.5" equipment to the rig Floor. Load 5.5" screens & blanks and 3.5" inner string into the pipe shed. R/U 5.5" elevators, casing tongs & slips. M/U XO on FOSV. Sim -ops: load 290 bbls 8.6 ppg brine into the mud pits. 3.5 BPH avg static loss rate.,PJSM with Doyon rig crew, Doyon casing crew & Halliburton screen personnel. P/U seal assy with mule shoe, pup joint & snap lock locator to 9.98'. Run 5-1/2" 17# L-80 LTC screen completion If 10' t/ 504'. 10 screens & two blanks. Torque to 3410 It/lbs w/ Doyon casing double stack tongs. 2 BPH loss rate.,Change elevators and tongs to 3.5". P/U mule shoe, perforated pup & 3 pup joints to 27'. Run 3-112" 9.2# L-80 Hydril 511 inner string f/ 27' U 497'. Torque to 1400 ft/lbs w/ Doyon double stack tongs. 2.5 BPH loss rate.,Change elevators to 5" drill pipe. M/U 9-5/8"x7-518" VGH Versa-Trieve packer wl safety shear joint and XO to 5.5" LTC & 3.5" H511 inner string to 543'. 2 BPH loss rate-TIH with 5-1/2" gravel pack completion on 5" drill pipe out of the derrick f/ 543' U 2509'. 1.5 BPH loss rate.,Hauled 275 bbis H2O from L -Pad Lake for total = 3905 bbis Hauled 0 bats H2O from A -Pad for total = 400 bbis Hauled 0 bbis Source Water from G&I = 660 bbls Hauled 327 bbls cuttings/mud/cement = 5863 bbis Daily losses = 21 bbis, Cumulative losses for interval = 30 bbis Diesel: 0 gal reed, 320 gal used, 9375 gal on hand. 9123/2019 Parked above Top Perf @ 2509. Rig up and Reverse circulate 1.5 DP Volume to ensure clear pipe. 2 bpm/40 psi, lost 4 bbis on circulation. RID Lines and Blow Down same-RIH from 2500'. Snap into Sump PKR @ 2887'. Unsnap and UD top single DP, MU 10' DP Pup.,Drop 1 3/4" Ball and pump on seat. Pressure up to 2600 psi in 500 psi increments, hold each for 3 min. Bleed to 0. Perform 10K Push/Pull test on slips. Pressure up to 3000 psi and hold for 5 min to finish PKR setting sequence. Bleed to 0., Line up to PT IA. Close UPR and pump IA to pressure test 5" x 10 3/4"/9-5/8" IA to verify packer set for 10 min. - good test. Increase pressure to burst rupture disc in packer running tool, burst at 2500 PSI (2500 PSI design), then bleed off pressure. Line up and Pump down drill pipe to 3000 PSI then P/U and release from tool 45K Over. Bleed off pressure. R/U Superior Hard Iron to Rig Floor.,PJSM with Doyon, Halliburton, Supreme Services, M -I and Peak. Make walk through of dg up. Re configure reverse line removing it from upper annulus to lower annulus valve. Halliburton tested gravel pack equipment to 6500 psi PSI. Good tests. PU to reverse position, close Bag, HES pump down DP, shear ball seat @ 5670 psi. Slack off to to circulate position, close bag and line up rig to pump down IA.,PT to 500 psi, strip up hole, see pressure dump, mark pipe as reverse position.,Pump 6 bbis 15% HCI pickle solution @ 2 BPM, 40 PSI then chase with 36 bbis of brine @ 2.7 BPM, 70 PSI. Line up to reverse circulate with rig pumps. Reverse circulate 2 DP volumes (80 bbls) @ 6 BPM, 530 PSI to Bow back tank. Perform Reverse circulation Test: 2 bpm DP/100, IA/100, 4 bpm DP/200, IA/200, 6 bpm DP/400, IA/500, 8 bpm DP/590, IA/800.,Position tool in frac position. Perform circulation test: .50 bpm DP/35, 1 bpm DP/50, 1.5 bpm DP/70, IA/30, 2 bpm DP/100 IA/40, 2.5 bpm DP/130 IA/53, 3.5 bpm DP/210 IA/82. Perform Infectivity Test: 2 bpm DP/140, 3 bpm DP/277, IA/225, 4 bpm DP/375, A/280, 4.5 bpm DP/440 IA/335, 5.5 bpm DP/220, IA/425., Perform gravel pack with 1/2 choke closed. Pump 5 BPM - 465 psi initial circ pressure, stage proppant feed up from .25 lbs/gal to 2.0 lbs/gal. Maintain 2 bpm returns on choke. Slow rate to 1.5 bpm/2300 psi FCP, with 1.5 bpm returns through choke.,Treatment pumped consisted of: 75 gal of FE ACID - SBM (341772). • 3565 gal of 3% KCL. • 260 gal of DFS -ACID HCL 15%. • 6954 gal of 3% KCL carrying 138.66 100'16 of Wanli - 20/40. The average BH treating rate was 3.0 bpm and average WH pressure was 597.12 psi. The total liquid load to recover is 10781 gal.,Line up to reverse circulate out drill pipe with rig pumps. Pressure up to 900 PSI, then P/U to reverse position. Pump 12 BPM, 1300 PSI for 2 drill pipe volumes (80 bbls).,Open annular preventer, line up & monitor well via trip tank. Blow down all lines and RID hard lines. UD Bail extensions act. RID Gravel Pack Equipment.,POOH it 2890' to 574' laying down 5" drill pipe. Lay down Halliburton liner running tool - in good R/U 3-1/2" handling equipment. POOH laying down 3-1/2" inner string f/ 574'. Clear rig floor of 3-1/2" equipment & R/U 5" equipment. R/U ESP spooler & load ESP spool. 7 BPH loss avg.,RIH w/ 15 stands of 5" drill pipe from the derrick to 1436'. POOH laying down 45 joints of 5" drill pipe. 6.5 BPH loss avg.,Pull wear bushing. Mobilize ESP equipment to the rig floor and R/U to run 5-1/2" ESP completion. Hang ESP sheave in the derrick and pull ESP cable through. Load pipe shed with 5-12" IBT tubing, ESP pump, landing joint & XN nipple. Mobilize tubing hanger & ESP XO to the rig floor. M/U 5.1/2" IBT XO on FOSV. R/U Doyon double stack tongs. PJSM for running ESP completion. 6 BPH loss avg.,Hauled 0 bbis H2O from L -Pad Lake for total = 3905 bats Hauled 0 bbis H2O from A -Pad for total = 400 bbis Hauled 0 bbis Source Water from G&I = 660 bbls Hauled 432 bbis cuttings/mud/cement = 6295 bbis Daily losses = 62 bbis, cumulative losses for interval = 92 bbis Diesel (gallons): 0 rec'd, 315 used, 9060 on hand. 9/24/2019 M/U Baker Centrilift 7.25" centralizer, Zenith Motor Gauge, HMX 800/42251114 motor, tandem seals and 675 HPHVL pump to 72'. Bolt-on discharge head and XO were damaged while making up XO with power tongs. 5.5" STC thread on discharge head & 5.5 LTC thread on XO. Replacement discharge head available, but needed to re-cul threads on XO sub. 6 BPH loss rate.,Machine new threads on XO sub at Baker Machine in Deadhorse and M/U to discharge head. Sim-ops: Prep/clean for rig move, perform house keeping, perform inspection on #1 boiler & commission #1 boiler. 5 BPH loss rate.,WU new discharge head to ESP motor/pump assembly. Continue to run ESP completion f/ 72't/ 1973' M/U 5-1/2" 17# L-80 IBT tubing with Doyon double stack tongs to make-up mark - 6000 ft/lbs avg. Install cross coupler Cannon clamp every joint. 3 BPH loss rate. '"• Swap to rig generators at 18:05 """' Notified AOGCC of M-17 diverter test at 18:58 on 24 Sept 2019'"".,ESP cable on spool was near the end. Anchor ESP cable with rope then lower over the sheave to rig floor and send down the beaver slide. 3 BPH loss rate-Continue to run 5-1/2" ESP completion f/ 1973' U 2180'. M/U tubing w/ Doyon double stack tongs to make-up mark - 6000 ft/lbs avg. Install cross coupler Cannon clamp every joint. Ran out of ESP cable. Contacted completions engineer & received approval to land at 2214' rather than 2259. M/U 5-1/2" IST pin x 5-1/2" TCII box XO (torque TCII to 4500 ft/lbs.), tubing hanger w/ pup joint and 5-1/2" TCII landing joint.,Orient penetrations to wing valve as per well head representative. 51 joints of 5.5" 17# L-80 IBT tubing with 3 protectolizers, 52 cross coupler Cannon clamps and 2 stainless steel bands ran.,Perform ESP cable spice to lower pigtail. Test cable - good. M/U penetrator through hanger. 4 BPH loss rate.,Install TWC in the hanger. RIH on 5-1/2" TC-II landing joint f/ 2180' to 2214'. 80K PU / 75K SO. 35K set on hanger. Run in lock down screws. Back out & L/D landing joint.,N/D BOP stack. Attach bridge cranes. Remove flow nipple, turn buckles, kill line from BOP stack. Hoist stack and set back on pedestal. Sim-ops: Empty pits and rock washer in preparation for rig move.,Hauled 0 bbls H2O from L-Pad Lake for total = 3905 bbis Hauled 0 bbis H2O from A-Pad for total = 400 bbls Hauled 0 bbis Source Water from G&I = 660 bbis Hauled 57 bbls cuttings/mud/cement = 6357 bbis Daily losses = 106.5 bbis, cumulative losses for interval = 198.5 Diesel (gallons): 0 recd, 497 used, 8563 on hand 9/2512019 N/U 11-1116'x7-1116" adapter flange and perform ESP penetrations. Pressure test hanger void to 500 PSI / 5 min and 5000 PSI 110 min - good.,NlU 7-1/16" tree, fill with diesel and pressure test to 250 PSI 15 min and 5000 PSI / 5 min - charted. Pull TWC. Secure well. 0 PSI tubing, 0 PSI IA, 0 PSI OA. Close SSV.,Skid rig floor to the moving position. Notify pad operator and move off M-06. Spot matting boards on M-17 and move rig over M-17. Shim rig level. Install stairs and Iandings.,Release rig from M-06. See M-17 report for details.,Hauled 0 bbis H2O from L-Pad Lake for total = 3905 bbls Hauled 0 bbis H2O from A-Pad for total = 400 bbis Hauled 0 bbis Source Water from G&I = 660 bbis Hauled 205 bbis cuttings/mud/cement = 6562 bbis Daily losses = 0 bbls, Cumulative losses = 198.5 bbis Diesel (gallons): 0 recd, 958 used, 7605 on hand. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP M-06 Pump 50-029-23646-00-00 219-113 9/22/2019 10/18/2019 10/9/2019- Wednesday No operations to report. 10/10/2019 - Thursday No operations to report. 10/11/2019-Friday No operations to report. 10/12/2019-Saturday No operations to report. 10/13/2019-Sunday No operations to report. 10/14/2019 - Monday No operations to report. 10/15/2019-Tuesday Inj. Test (PT surface lines 250/2,500 psi) Pump 252 bbls Source water and Freeze protect IA w/ 86 bbls Dsl @ 2 bpm. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP M-06 Pump 50-029-23646-00-00 219-113 9/22/2019 1 10/18/2019 10/16/2019- Wednesday No operations to report. 10/17/2019 - Thursday No operations to report. 10/18/2019 - Friday Acid Treatment (PT surface lines 250/2,500 psi) Pump 56 bbls 15% DAD Acid and 3 bbls 60/40. Displace acid w/ 77 bbls source water. Let Soak for two Hours. Pump 20 bbls more of source water. Freeze protect surface lines w/ 3 bbls 60/40. 10/19/2019 -Saturday No operations to report. 10/20/2019 -Sunday No operations to report. 10/21/2019 - Monday No operations to report. 10/22/2019- Tuesday No operations to report. Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-06 500292364600 Sperry Drilling Definitive Survey Report 18 September, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-06 Project: Milne Point TVD Reference: MPU M-06 Actual RKB @ 58.50usft Site: M Pt Moose Pad MD Reference: MPU M-06 Actual RKB @ 58.50usft Well: MPU M-06 North Reference: True Wellbore: MPU M-06 Survey Calculation Method: Minimum Curvature Design: MPU M-136 Database: NORTH US + CANADA 'roject Milne Point, ACT, MILNE POINT Aap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Aap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-06, WSW -Slot 1 ACTUAL Depth From (TVD) +N/ -S (usft) Well Position +N/ -S 0.00 usft Northing: 6,027,765.65 usfl Latitude: 70° 29' 12.806 N +EI -W 0.00 usft Easting: 533,303.92 usfl Longitude: 149° 43'40.066 W Position Uncertainty 0.00 usft Wellhead Elevation: usfl Ground Level: 24.90 usft Wellbore MPU M-06 Magnetics Model Name Sample Date BGGM2018 Design MPU M-06 Audit Notes: Version: 1.0 Vertical Section: 9/12/2019 Declination 16.46 Phase: ACTUAL Depth From (TVD) +N/ -S (usft) (usft) 33.60 0.00 Dip Angle Tie On Depth +E/ -W (usft) 000 IIMIM Field Strength (nT) 57,414.03301053 33.60 Direction (`) 261.77 Survey Program Date 9/17/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 226.26 3,194.95 MPU M-06 MWD+IFR2+MS+Sag (1) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 09/08/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) M V) (usft) (usft) (usft) (usft) (ft) (ft) (1/1001) (ft) Survey Tool Name 33.60 0.00 0.00 33.60 -24.90 0.00 0.00 6,027,765.65 533,303.92 0.00 0.00 UNDEFINED 226.26 0.26 125.61 226.26 167.76 -0.25 0.36 6,027,765.40 533,304.28 0.13 .0.32 2_MWD+IFR2+MS+Sag(1) 317.69 0.29 152.69 317.69 259.19 -0.58 0.63 6,027,765.07 533,304.55 0.14 -0.54 2_MWD+IFR2+MS+Sag(1) 412.19 0.39 101.31 412.19 353.69 -0.86 1.06 6,027,764.80 533,304.98 0.33 41.92 2_MWD+IFR2+MS+Sag(1) 508.18 0.73 236.09 508.17 449.67 -1.26 0.87 6,027,764.39 533,304.79 1.09 -0.68 2_MWD+IFR2+MS+Sag(1) 597.41 3.47 257.35 597.34 538.84 -2.17 -2.24 6,027,763.47 533,301.69 3.14 2.53 2_MWD+IFR2+MS+Sag(1) 692.70 7.11 256.14 692.21 633.71 -4.22 -10.78 6,027,761.39 533,293.16 3.82 11.27 2_MWD+IFR2+MS+Sag(1) 787.78 9.96 260.55 786.22 727.72 -6.98 -24.61 6,027,758.57 533,279.35 3.07 25.35 2_MWD+IFR2+MS+Sag(1) 883.27 14.38 263.75 879.55 821.05 -9.62 -04.55 6,027,755.83 533,259.42 4.68 45.47 2_MWD+IFR2+MS+Sag(1) 978.16 19.00 265.22 970.41 911.91 -12.19 -71.67 6,027,753.14 533,232.31 4.89 72.68 2_MWD+IFR2+MS+Sag(1) 1,072.75 21.53 265.05 1,059.14 1,000.64 -14.98 -104.31 6,027,750.21 533,199.69 2.68 105.38 2_MWD+IFR2+MS+Sag(1) 1,168.32 25.89 265.99 1,146.62 1,088.12 -17.95 -142.62 6,027,747.06 533,161.40 4.58 143.72 2_MWD+IFR2+MS+Sag(1) 1,263.10 29.70 264.56 1,230.45 1,171.95 -21.62 -186.65 6,027,743.19 533,117.39 4.08 187.82 2 MWD+IFR2+MS+Sag (1) 1,357.97 30.54 265.07 1,312.51 1,254.01 -25.92 -234.06 6,027,738.68 533,070.00 0.93 235.36 2_MWD+IFR2+MS+Sag(1) 9/182019 2:08:09PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-06 MPU M-06 MPU M-06 Local Co-ordinate Reference: Well MPU Mr06 TVD Reference: MPU M-06 Actual RKB @ 58.50usft MD Reference: MPU M-06 Actual RKB @ 58.50usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) ("/1001) (ft) Survey Tool Name 1,452.70 32.90 263.46 1,393.09 1,334.59 -30.92 -283.61 6,027,733.46 533,020.48 2.65 285.11 2_MWD+IFR2+MS+Sag(1) 1,548.27 35.72 261.39 1,472.02 1,413.52 -38.06 -336.99 6,027,726.09 532,967.14 3.19 338.97 2_MWD+IFR2+MS+Sag(1) 1,643.65 37.85 261.14 1,548.41 1,489.91 -46.73 -393.44 6,027,717.16 532,910.73 2.24 396+08 2-MWD+IFR2+MS+Sag(1) 1,738.57 40.20 258.76 1,622.15 1,563.65 -57.19 452.27 6,027,706.44 532,851.95 2.94 455.80 2_MWD+IFR2+MS+Sag(1) 1,834.17 43.20 258.37 1,693.52 1,635.02 -69.81 -514.60 6,027,693.55 532,789.69 3.15 519.29 2_MWD+IFR2+MS+Sag(1) 1,928.72 48.32 258.97 1,759.46 1,700.96 -83.09 -580.99 6,027,679.96 532,723.36 5.43 586.91 2_MWD+IFR2+MS+Sag(1) 2,024.36 48.66 260.80 1,822.85 1,764.35 -95.67 -651.49 6,027,667.08 532,652.92 1.48 658.48 2 MWD+IFR2+MS+Sag (1) 2,119.69 47.80 261.46 1,886.35 1,827.85 -106.63 -721.74 6,027,655.80 532,582.73 1.04 729.57 2_MWD+IFR2+MS+Sag(1) 2,214.98 49.08 262.00 1,949.57 1,891.07 -116.89 -792.30 6,027,645.23 532,512.23 1.41 800.87 2_MWD+IFR2+MS+Sag(1) 2,309.87 48.79 262.66 2,011.90 1,953.40 -126.44 -863.20 6,027,635.36 532,441.38 0.61 872.41 2_MWD+IFR2+MS+Sag(1) 2,403.73 48.26 262.60 2,074.07 2,015.57 -135.46 -932.95 6,027,626.03 532,371.68 0.57 942.73 2_MWD+IFR2+MS+Sag(1) 2,500.67 48.02 264.25 2,138.76 2,080.26 -143.72 -1,004.67 6,027,617.44 532,300.01 1.29 1,014.89 2_MWD+IFR2+MS+Sag(1) 2,595.82 48.31 264.99 2,202.22 2,143.72 -150.37 -1,075.25 6,027,610.48 532,229,46 0.65 1,085.70 2_MWD+IFR2+MS+Sag(1) 2,690.85 48.78 263.47 2,265.14 2,206.64 -157.53 -1,146.10 6,027,603.00 532,158.65 1.30 1,156.85 2_MWD+IFR2+MS+Sag(1) 2,786.53 48.46 261.66 2,328.39 2,269.89 -166.82 -1,217.29 6,027,593.40 532,087.51 1.46 1,228.63 2_MWD+IFR2+MS+Sag(1) 2,881.18 47.24 261.36 2,391.90 2,333.40 -177.18 -1,286.69 6,027,582.73 532,018.16 1.31 1,298.80 2_MWD+IFR2+MS+Sag(1) 2,975.93 46.56 261.99 2,456.64 2,398.14 -187.20 -1,355.14 6,027,572.41 531,949.76 0.87 1,367.98 2_MWD+IFR2+MS+Sag(1) 3,072.25 48.06 261.51 2,521.95 2,463.45 -197.36 -1,425.20 6,027,561.93 531,879.75 1.60 1,438.78 2_MWD+IFR2+MS+Sag(1) 3,167.13 47.24 261.13 2,585.87 2,527.37 -207.94 -1,494.52 6,027,551.04 531,810.49 0.91 1,508.90 2_MWD+IFR2+MS+Sag(1) 3,194.95 47.48 260.86 2,604.71 2,546.21 -211.14 -1,514.73 6,027,547.75 531,790.30 1.12 1,529.36 2_MWD+IFR2+MS+Sag(1) 3,235.00 47.48 260.86 2,631.78 2,573.28 -215.83 -1,543.88 6,027,542.93 531,761.18 0.00 1,558.87 PROJECTEDto TD Checked By: Chelsea Wright w ,' p Approved By: Benjamin Hand m -- Date: 09-18-2019 9/1812019 2:08:09PM Page 3 COMPASS 5000.15 Build 91 Lease & Well No. County Hilcorp Energy Company CASING & CEMENTING REPORT MP M-06 Date Run 17 -Sep -19 State Alaska Supv. J. Lott / J. Vanderpool CASING RECORD Surface V c nn ch..e nom, 3 99A nn PBTD: Csg Wt. On Hook: 140,000 Type Float Collar: Innovex No. HIM to Hun: to Csg Wt. On Slips: 100,000 Type of Shoe: Innovex —Casing Crew: Doyno Rotate Csg X Yes No Recip Csg X Yes _ No 5.38 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: 34 total 9-5/8'x12-1/2" Expand-o-lizer centralizes rand: Two w/ four stop rings installed on shoe joint, one free floating on Baker Loc joint, one w/ two stop rings on float collar joint & one free floating on joints #1 to #30 23 total 10-3/4'x13-1/2" bow spring centralizer across every other casing collar from 10-3/4" joint #1 to #45 CEMENTING REPORT Shoe @ 3228 FC @ 3,145.42 Top of Liner Casing (Or Liner) Detail Setting Depths As. Component Size wt. Grade THD Make Length Bottom Top 1 Shoe 1 103/4 50.0 ,. Tail TXP BTC Innovex 1.56 3,228.00 3,226.44 2 Casing 95/8 40.0 L-80 TXP BTC Tubular Sol. 79.69 3,226.44 3,146.75 1 Float Collar 103/4 50.0 TXP BTC Innovex 1.33 3,146.75 3,145.42 31 Casing 95/8 40.0 L-80 TXP BTC Tubular Sol. 1,223.33 3,145.42 1,922.09 1 Casing XO 113/4 50.0 TXP BTC 1.64 1,922.09 1,920.45 46 Casing 103/4 45.5 L-80 TXP BTC Tubular Sol. 1,876.81 1,920.45 43.64 1 Casing Cut Joint 103/4 45.5 L-80 I TXP BTC Tubular Sol. 13.27 43.64 30.37 Csg Wt. On Hook: 140,000 Type Float Collar: Innovex No. HIM to Hun: to Csg Wt. On Slips: 100,000 Type of Shoe: Innovex —Casing Crew: Doyno Rotate Csg X Yes No Recip Csg X Yes _ No 5.38 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: 34 total 9-5/8'x12-1/2" Expand-o-lizer centralizes rand: Two w/ four stop rings installed on shoe joint, one free floating on Baker Loc joint, one w/ two stop rings on float collar joint & one free floating on joints #1 to #30 23 total 10-3/4'x13-1/2" bow spring centralizer across every other casing collar from 10-3/4" joint #1 to #45 CEMENTING REPORT Shoe @ 3228 FC @ 3,145.42 Top of Liner lush (Spacer) ,. Tuned Spacer Density (ppg) 10 Volume pumped (BBLs) 60 1 Slurry ,. Permafrost L Sacks: 505 Yield: 4.41 sity (ppg) 10.7 Volume pumped (BBLs) 392 Mixing / Pumping Rale (bpm): 5 Slurry ,. Tail Sacks: 1020 Yield: 1.16 sity (ppg) 15.8 Volume pumped (BBLs) 212 Mixing / Pumping Rate (bpm): 5 t Flush (Spacer) ,. Density (ppg) Rate (bpm): Volume: Spud Mud Density (ppg) 9.4 Rate (bpm): 6 Volume (actual / calculated): 261/257 (psi): 770 Pump used for disp: Rig Bump Plug? X Yes _ No Bump press 1250 ig Rotated? X Yes _No Reciprocated? X Yes —No % Returns during job 100 ant returns to surface? X Yes —No Spacer retums? X Yes —No Vol to Surf: 21� ant In Place At: 13:45 Date: 911812019 Estimated TOC: 34 od Used To Determine TOC: Returns to surface Post Job Calculations: Calculated Cart Vol @ 0% excess: 246.4 Total Volume crit Pumped: 604 Cmt returned to surface: 212 Calculated cement left in wellbore: 392 OH volume Calculated: 238.4 OH volume actual: 384 Actual % Washout: 61 www.wellez.net WellEz Information Management LLC ver 04818br THE STATE ALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 1 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogc c.alaska.gov Re: Milne Point Field, Prince Creek Water Tertiary Undefined WTRSP Pool, MPU M-06 Permit to Drill Number: 219-113 Sundry Number: 319-467 Dear Mr. Helgeson: 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, II r y M. Price Chair DATED this day of October, 2019. RBDMS±�'OCT 16 2019 SCANNED OC 1 2 3 2919 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 f7TS !o/l�C�� 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Acid Stimulate ❑✓ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Reenter Susp Well ❑ Alter Casing ❑ Other: ESP Change -out ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service ❑✓ 219-113 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23646-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑✓ MPU M-06 9. Property Designation (Lease Number):10. Field/Pool(s): L 0'0 Milne Point Field / Prince Creek Water Tertiary Undef WTRSP 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): 3,235' 2,632' 3,128' 2,560' 0 N/A We Casing Length Size MD TVD Burst Collapse Conductor 113' 20" 113' 113' N/A N/A Surface 1,920' 10-3/4" 1,920' 1,753' 5,210psi 2,470psi Production 1,308' 9-5/8" 3,228' 2,627' 5,750psi 3,090psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 5-1/2" 17# / L-801 IBT-MOD 2,214' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 9-5/8" Versa-Trieve Packer & BWD Top -Snap Sump Packer and N/A 2,358 MD/ 2,044 TVD & 2,893 MD/ 2,400 TVD and N/A 12. Attachments: Proposal Summary ✓ Wellbore schematic Laj 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑ Service ❑✓ 14. Estimated Date for 15. Well Status after proposed Commencing Operations: 1 0/1 412 01 9 r �work: OIL ❑ WT [! RSP 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: David Haakinson1 Authorized Title: Operations Manager Contact Email: dhaakinson hil or .Com Contact Phone: 777-8343 Authorized Signature: L Date: 10/11/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: rr ^^ Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: �BDMS 4� 4v r 1 6 2019 Yes ❑ Non „ y � O (� Post Initial Injection MIT Required? Subsequent Form Required: 0 .^ "I Spacing Exception RequiMed? No LLL�777J ^ � APPROVED �� J r I ' i SI 1 0� Approved by: COMMISSIONER THE COMMISSION tate: V- n ORIGINAL lForm 10403 Revised -0/2017 Approved application is valid for 12 months from the date of approval. Submit Form and Attachments in Duplicate Yilq U Ilil.p Alaska. 11U Acid Stimulation Well: MPM-06 10-9-19 Well Name: MPU M-06 API Number: 50-029-23646-00 Current Status: Online Producer (Source Well) Pad: M -Pad Estimated Start Date: 10/14/19 Rig: Pump Truck Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 31O.4tT Ali - 11.3 First Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 331-8228 (M) AFE Number: Job Type: ESP RWO Current Bottom Hole Pressure: Maximum Expected BHP: MPSP: Brief Well Summary: 1,130 psi @ 2,600' TVD Downhole Gauge 18.37 ppg EMW 1,130 psi @ 2,600' TVD No offset injection support 0 psi Well on vacuum when shut in Water source producer M-06 was drilled and completed in September 2019. The well was perforated in the Prince Creek formation and a subsequent gravel -pack was completed in the well. After the well was brought online in early -October, productivity was found to be substantially less than projected. A subsequent pressure buildup found a significantly high skin factor. Prior to the gravel pack, the well was found to have injectivity that was more in-line with reservoir projections at 5.5 BPM with 200 psig surface pressure. The cause of the high skin factor has been premised to be one or more of the following: 1) Improper screen size/installation 2) Gravel Pack Contamination 3) Perforation tunnel collapse/plugging 4) Fines migration into gravel pack Notes Regarding the Well & Design • The 10-3/4" x 9-5/8" Casing MIT to 3,500 psig passed on 9/22/19 • Volumes for pumping:�L -ft�A o Total Wellbore Volume: 193 bbls S o To top of perfs: 164 bbls 37 Objective: 2 TY 1-1-te • Pump 15% Hydrocloric Acid in attempt to remove possible cement perf plugging • Flow acid back to tanks • Perform Pressure build-up after cleanup • If necessary: Pump Mud -Acid in attempt to remove formation fines from gravel pack Pre-Workover Prep Procedure: 1. MIRU two 400 bbl flow -back tanks. 2. RU Pumping unit and hardline to pump from transports down the Inner-Annu of M-06. 3. Pressure test all hardline to 250 psig low and 2500 psig high. H Hilmru Al"kx, LG r �! 4. Pump the following down the taking all fluids to formation. a. DNE 2000 psig on surface b. Max Pump Rate: 2 BPM Acid Stimulation Well: MPM-06 10-9-19 c. Note that the injectivity test should be pumped a few days ahead of the acid job, prior to mixing acid. Stage Fluid Action Stage Vol (bbls) Cum Vol (bbls) 1 Source Water Matrix injectivity test 250 250 Turn well online for 1-3 days 2 15% HCI Acid 53 303 3 Source Water Displacement 173 476 4 N/A Soak (120 Minutes) - 476 5 Source Water Displacement 20 496 6 N/A Soak (120 Minutes) - 496 7 N/A Turn well to production. Flow to tanks 496 5. RD Pumping Service Unit and all auxiliary equipment. 6. RU hardline to flow -back tanks. 7. After soak period, start M-06 ESP WSW at 35 hz. 8. Produce M-06 HCI acid back to until pH normalizes at 7-8. a. Estimate —200 bbls to tanks. 9. Turn well over to facility and injection header. K corn Alaska. LLC Crig. IB Elev.: 5&5'/ GL Bev.: 24.9' TD=3,235' (MD)/TD=2,632'(TVD) PBTD= 3,129(MD)/ PBTik 2,560' OW) line Point Unit Well: MPU Moose Pad M-06 SCHEMATIC Last Completed: 9/25/2019 PTD: 219-113 TREE & WELLHEAD OPEN HOLE / CEMENT DETAIL 42" 50 bbis 110 Yards Pilecrete dumped down backside) 13-1/2" L-505sx/T-1020sxin13-1/2"hole CASING DETAIL )e Wt/Grade/Conn I ID I Top 20"x34" Tree I Cameron FLS, 7" x 5-1/2" 5M Tree ID 113' N/A 11"5M Wellhead. 5-1/2" TC -1 l Top and Bottom Tubing Hanger 10-3/4" 2 Wellhead with 5" "H" BPVG. 5 ea 1/4" NPT control lines. 1,920' OPEN HOLE / CEMENT DETAIL 42" 50 bbis 110 Yards Pilecrete dumped down backside) 13-1/2" L-505sx/T-1020sxin13-1/2"hole CASING DETAIL )e Wt/Grade/Conn I ID I Top 20"x34" I Conductor (insulated) 215.5/A-53/Weld N/ASurface ID 113' N/A XO:4.S"TCIIPin X4.5"BTCPin-Min ID=3.958" 10-3/4" 2 45.5/L-80/TXP SR 9.950" Surface 1,920' 0.0962 2,140' 35/8„ Surface/Production 40/L-80/TXP SR 8.835" 1,920' 3,228' 0.0758 5 2,160' Upper Tandem Seal: HSB3DBXLT INV SSCV EHL PF TUBING DETAIL 6 2,167' Lower Tandem Seal: HSB3DBXLT INV SSCV EHL PF 5-1/2" Tubing 17/L-80/IBT-MOD 4.892" Surface 2,214' 0.0232 2,209' Sensor: Zenith w/Centralizer: Btm @ 2,214' WELL INCLINATION DETAIL 1 9 KOP @ 508' 9-5/8" Versa-Trieve Packer 6.000 10 2,383' Max Hole Angle=49"@2,21S'MD 4.860 11 2,387' LN 3 4.818 12 2,474 5-1/2" Gravel Pack Screens (250 Micron) 4.518 13 2,883' JEWELRY DETAIL 4.818 14 BWD Top -Snap Sump Packer 4.665 15 2,893' Muleshoe, 5 1/2" ri No. Top MD Item ID 1 29' XO:4.S"TCIIPin X4.5"BTCPin-Min ID=3.958" 4.892 2 2,087' Nipple HES 4.562" XN profile w/ 4.455" nogo 4.455 3 2,140' Discharge Head: Bolt On 675 Series Pump N/A 4 2,141' Pump: 675 PMP HPHVL 035 HC20000 FER I N/A 5 2,160' Upper Tandem Seal: HSB3DBXLT INV SSCV EHL PF N/A 6 2,167' Lower Tandem Seal: HSB3DBXLT INV SSCV EHL PF N/A 7 2,174' Motor: HMIX SDOHp/4,225V/114A N/A 8 2,209' Sensor: Zenith w/Centralizer: Btm @ 2,214' N/A LOWER COMPLETION DETAIL 9 2,358' 9-5/8" Versa-Trieve Packer 6.000 10 2,383' 7-5/8" x 5-1/2 Crossover" 4.860 11 2,387' Blank Pipe, 5-1/2",178, L-80, LTC Blank Pipe 4.818 12 2,474 5-1/2" Gravel Pack Screens (250 Micron) 4.518 13 2,883' Blank Pipe, 5-1/2", 17N, 480, LTC Blank Pipe 4.818 14 2,887' BWD Top -Snap Sump Packer 4.665 15 2,893' Muleshoe, 5 1/2" 4.888 PERFORATION DETAIL Schrader Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status 2,509 2,600' 2,144' 2,205' 91' 9/22/2019 Open Lower Prince Ck 2,654' 2,888' 2,241' 2,379' 234' 1 9/22/2019 1 Open GENERAL WELL INFO API: 50-029-23646-00-00 Drilled and Cased by Doyon 14 - 9/22/2019 GP and Completion by Doyon 14-9/25/2019 Revised By: TDF 10/9/2019 THE STATE OIALASKA GOVERNOR MIKF, DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. a og cc.o I as ka.g ov Re: Milne Point Field, Prince Creek Water Tertiary Undefined WTRSP Pool, MPU M-06 Permit to Drill Number: 219-113 Sundry Number: 319-412 Dear Mr. Helgeson: 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, Jesse L. C ielowski Commissioner DATED this —aday of September, 2019. RBDMSA&-tQEP 19 2019 SCANNED TP 2 7 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVE® SEP 0 9 2019 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program _ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ESP & Gravel Pack ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service Ei. 219-113 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23646-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No Q MPU M-06 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025514 Milne Point Field / Prince Creek Water Tertiary Undef WTRSP ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD iff): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 13,583 ±2,870 ±3,583 ±2,870 976 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 1113' 20" ±113' ±113' N/A N/A Surface ±2,000' 10-3/4" ±2,000' ±1,791' 5,210psi 2,470psi Production ±1,583' 9-5/8" ±3,583' ±2,870' 5,750psi 3,090psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 5-1/2" 17# / L-80 / IBT-MOD ±2,000' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): HES VGH & Sump and N/A TBD & TBD and N/A 12. Attachments: Proposal Summary ✓j Wellbore schematic lal 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑ Service ❑� ' 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/17/2019 OIL ❑ WTRSP Q 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. Wti-mow. -r[ rwS• ��.A• w.� Fol Authorized Name: Chad Helgeson Contact Name: Ian Toomeya Ti'zl Authorized Title: Operations Manage Contact Email: itoomB o hilcof .coni Contact Phone: 777-8434 Authorized Signature: Date: 9/9/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ;p (/� L� •! Plug Integrity ❑ BOP Test 5 Mechanical Integrity Test ❑ Location Clearance ❑ Other: 300© p s IMS. ►°/ SEP 19 2019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ r1 % Spacing Exception Required? Yes No Subsequent Form Required: �� •- y 02 C61h J Ule_�i tee-' — ❑ APPROVED BY Approved by: (�_�, COMMISSIONER THE COMMISSION Date: 1/ s'�r at�,� � q•��r� ORIGINAL Submit Form and Form 10"403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate /Le .ff Hil.m A6.ka, LLC WSW GP Well: MPU M-06 Date:09/09/2019 Well Name: MPU M-06 API Number: 50-029-23646-00-00 Current Status: Conductor installed Pad: MP M -Pad Estimated Start Date: September 18th, 2019 Rig: Doyon 14 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 219-113 First Call Engineer: Ian Toomey (907) 777-8434 (0) (907) 909-3987 (M) Second Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) AFE Number: 19144430 Job Type: WSW GP Current Bottom Hole Pressure: Not perforated Maximum Predicted BHP: 1263 psi at 2870' TVD MPSP: 976 psi (0.10 psi/ft gas gradient) Surface Casing: 10-3/4", 45.5#, L-80 TXP to ±2000' x 9-5/8", 40#, L-80 TXP ±2000' to ±3583'. Brief Well Summary: MPU M-06 will be drilled by Doyon 14 in September 2019 in the Prince Creek formation for the Moose pad water source well (WSW). Objective: omplete the M-06 WSW well by perforating the upper and lower Prince Creek formation. Run a gravel pack lower completion and run ESP in the upper completion. Procedural Note: This work will beoerformed by Doyon 14 as a continuation drilling of MPU M-06. These steps will replace Section 4---- 16 of the approved PTD #219-113. Also note that a request to change the VBR sizes in Section 14 to 3-1/2" x 6" VBR's will be submitted and should cover the applicable drill pipe and tubing sizes in this sundry application. Completion Procedure: 1. RU E -line. PU and MU GR/CCL tool string. RIH, tag top of cement and POOH logging GR/CCL (use open hole MWD log for correlation). 2. PU and MU HES sump packer assembly. RIH and set the sump packer at ±3400' MD. RD E -line. 3. PU and MU 4-5/8", 12 SPF, MaxForce, HMX TCP gun assembly per HES representative (blank sections will be determined by Geologist after drilling reservoir). 4. RIH with TCP gun assembly on 5" DP to "'3350' MD. 5. Lightly tag the sump packer set at ±3400' MD. 6. PU and space out to place the guns on depth; base of source water at±3360' MD and top of source water at ±2080' MD. 7. Close the annular or UPR. Drop activation ball and allow the ball to gravitate to seat. Pressure up on the DP to "2500 psi to fire the guns. 8. Check for pressure under the annular and bleed to 0 psi if needed. Open the annular or UPR observe the well for flow (the well should go on a slight vac). 9. Circulate a bottoms up. Ensure the well is static or on a vac. 10. TOOH with 5" DP and lay down spent TCP gun assembly. 11. PU, MU and RIH with the following gravel pack assembly: a. Gravel pack seal assembly with 10' handling pup, 5-1/2", 17#, L-80, LTC Box x Pin WSW GP Well: MPU M-06 Flik.fl, AMA., LLC Date: 09/09/2019 b. (TBD) Gravel pack screen joints (250 micron), 5-1/2", 17#, L-80, LTC Box x Pin c. (TBD) 5-1/2" blank joints, 5-1/2", 17#, L-80, LTC Box x Pin Recommended MU Torque for 5-1/2", 17#, L-80, LTC = 3410 ft -lbs 12. RU false rotary table and change handling equipment to 3-1/2". 13. PU, MU and RIH with 3-1/2", 9.2#, P110, Hydril 511 inner string. • Recommended MU Torque for 3-1/2", 9.2#, P110, Hydril 511 = 1400 ft -lbs 14. PU the gravel pack packer assembly. MU the 3-1/2" inner string to the running tool and MU the packer assembly to the blankjoint. 15. RD false rotary table. 16. TIH with the gravel pack assembly on 5" DP to just above the perforations. 17. Reverse circulate 1.5 DP volume at 2 BPM (max) to ensure DP is clear. 18. Continue to RIH with the gravel pack assembly to the top of the sump packer at ±3400' MD. 19. Snap into the sump packer with -6.5K SO and snap out with -16K PU. Snap back into the sump packer Note: Do not exceed 30K over pull if unable to snap out of the sump packer. 20. PU to neutral weight and drop 1-3/4" setting ball. Allow time for the ball to gravitate to the ball seat. 21. Pressure up and set the gravel pack packer per HES representative. Note: Packer initiation setting pressure = 1840 psi and final set pressure = 3121 psi. 22. PT the IA to 1000 psi for 10 minutes. Continue to pressure up on the IA to 2500 psi to burst the rupture disc. Bleed the IA to 0 psi. 23. Pressure up on the DP to 3000 psi and slowly PU to release the running tool. Once it is verified the running tool is release bleed the DP to 0 psi. 24. PU to reverse position. Slowly pressure up to 4700 psi (± 500 psi) to shear the ball seat. 25. SO, set down 30K and mark the pipe as circulating position. PU the string weight, close the annular and pressure up the IA to 500 psi. Slowly strip through the annular until the IA pressure dumps, stop and mark the pipe as reverse position. Ensure the IA pressure is 0 psi and open the annular. 26. With the running tool in the reverse position, pump 6.2 bbls of pickle (15% HCI) displace down to the DP crossover with 8.8 ppg brine with 2% KCI. 27. Line up to take return from the OP. Reverse circulate out the pickle to the flow back tank. 28. SO to circulating position and perform injection step rate test at 1, 2, 4 & 6 BPM. Shut down and monitor the tubing and casing pressures. c 29. Pump the gravel pack with TBD K lbs of 20/40 Carbolite proppant per HES representative, Exact W jvolume of proppant to be determined by length of perforated interval. 30. PU to reverse position and reverse circulate until returns are clean. 31. Slowly PU and shift the MCS closing sleeve closed. 32. POOH laying down the 5" DP and lay down the running tool. 33. Change handling equipment to 3-1/2". POOH laying down 3-1/2" inner string. .p 34. RU to run 5-1/2" ESP completion. Pull the wear ring. f 35. RIH with the following ESP completion equipment to -1870' MD installing cross coupling clamps on every connection: a. Centralizer b. Motor Gauge, Zenith ,ff Hilmrp Almka, LLC c. ESP motor, 400 HP, 2785 V, 88A d. Lower tandem seal e. Uppertandem seal f. Intake WSW GP Well: MPU M-06 Date: 09/09/2019 g. 675 pump h. Discharge Head, 5-1/2", 17#, L-80, LTC box up i. Crossover, 5-1/2", 17#, L-80 IBT Box x LTC Pin j. 1 joint, 5-1/2", 17#, L-80 IBT Box x Pin k. Nipple, HES, 4.562" XN Profile with 4.455" no-go, 10' handling pups above and below. MU the first 15 joint to the base of the stamped triangle taking note of the required torque for each connection. Calculate the average torque and use that MU torque on the remaining connection. 36. Continue to RIH with the ESP completion on 5-1/2", 17#, L-80, IBT tubing. 37. PU and MU the tubing hanger with the landing joint. Terminate the ESP cable and splice to the penetrator. Ensure all control line ports are dummied off. a. Tubing Hanger, FMC TC -IA -EMS, 11" x5-1/2" TC -II top and bottom with 5" H BPVG b. Crossover Pup, 5-1/2", 17#, L-80 TC -II Pin x IBT Pin 38. Land the tubing hanger with extreme caution to avoid damaging the ESP cable or penetrator. RILDS. 39. Install the TWC. 40. ND the BOP stack. 41. NU the tubing head adapter and PT the tubing hanger void to 250/5000 psi. 42. NU the tree and PT the tree to 250/5000 psi. 43. Install gauges on the tree and secure the cellar. Release and RDMO Innovation Rig. 44. Turn the well over to operations via handover form. Attachments: 1. Proposed Schematic (Prince Creek) 2. Blank MOC Form H HileorP Alaska, LLC Orig. KB Elev.: 58.6/ GL Elev.: 24.9' PROPOSED SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-06 Last Completed: FUTURE PTD: TBD Tree 41/16" SM Tree (Dry Hole Tree) Wellhead 11" SM Wellhead x 7" TXP Top and Bottom Hanger with 7" CIW "1" 1 BPV profile. Zea 3/8" NPT control lines. TD = 3,583' (MD) /TD = 2,87U(TVD) TUBING DETAIL 5-1/2" Tubing 17/L-80/IBT-MOD 4.892" 1 Surface 1 2,000' 0.0232 WELL INCLINATION DETAIL KOP @±520' Max Hole Angle = 47" @ 1,700-3,583' MD JEWELRY DETAIL No. Top MD OPEN HOLE/ CEMENT DETAIL Drift ID 1 29' Tubing Hanger, FMC, 5-1/2" TXP Top & Btm with 5" H BPVG 4.892" 42" 50 bbls (30 Yards Pilecrete dumped down backside) Nipple, HES, 4.562" XN Profile— Min ID= 4.455" no-go 4.455" 3 Planned Discharge Head: 13-1/2" 3414ft3 ±TBD Pump: N/A 5 .ower Prince Ck CASING DETAIL N/A 6 ±TBD size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34" Conductor(Insulated) 215.5/A-53/Weld N/A Surface 113' N/A 10-3/4" 9-5/8" Surface/Production 45.5/L-80/TXPSR 9.950" 40/L-80/TXP SR 8.835" Surface 2,000' 2,000' 3,583' 0.0961 0.0758 TD = 3,583' (MD) /TD = 2,87U(TVD) TUBING DETAIL 5-1/2" Tubing 17/L-80/IBT-MOD 4.892" 1 Surface 1 2,000' 0.0232 WELL INCLINATION DETAIL KOP @±520' Max Hole Angle = 47" @ 1,700-3,583' MD JEWELRY DETAIL No. Top MD Item Drift ID 1 29' Tubing Hanger, FMC, 5-1/2" TXP Top & Btm with 5" H BPVG 4.892" 2 ±TBD Nipple, HES, 4.562" XN Profile— Min ID= 4.455" no-go 4.455" 3 Planned Discharge Head: N/A 4 ±TBD Pump: N/A 5 .ower Prince Ck Intake: N/A 6 ±TBD Upper Seal Section: N/A 7 Lower Seal Section: N/A 8 Moor. Bottom at XXX N/A 9 TBD 9-5/8" HES VGH Gravel Pack Packer 6.000" 30 TBD Blank Pipe, 5-1/2", 17p, L-80, LTC Blank Pipe 4.767" 11 TBD 5-1/2" Gravel Pack Screens (250 Micron), 4.767" 12 TBD Snap Latch Seal Assem bly 4.640" 13 TBD 9-5/8" HES BW D Sump Packer/Bridge Plug - PERFORATION DETAIL ,chrader Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Jpper Prince Ck ±TBD ±TBD -TBD -TBD -XX' Future Planned nP ±TBD ±TBD ±TBD ±TBD ±XX' Future Planned .ower Prince Ck ±TBD ±TBD ±TBD ±TBD ±XX' Future Planned GRAVEL PACK DETAIL UPC/LPC-sands: GENERAL WELL INFO API: TBD Drilled and Cased by Doyon 14 -TBD GP and Completion by Doyon 14—TBD nP Revised By: CJD 8/21/2019 UHileorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: 09-09-19 Subject: Changes to Approved Sundry Procedure for Well MPU M-06 Sundry #:219-113 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. Sec Page Date Procedure Change HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date Schwartz, Guy L (CED) From: Schwartz, Guy L (CED) Sent: Tuesday, September 17, 2019 10:12 AM To: Ian Toomey - (C) Subject: RE: M-06 perforation depths Ian, Thanks for update. I will update the completion sundry with these perf depths. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-7931226) or (Guv schwartz@alaska.aov). From: Ian Toomey - (C) <itoomey@hilcorp.com> Sent: Tuesday, September 17, 2019 9:23 AM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: M-06 perforation depths Guy, We reached a TD of 3235' MD on M-06. After reviewing the logs we will be perforating from 2470' to 2600' MD and 2644' to 2880' MD. Let me know if you need more information. Regards, Ian Toomey I Operations Engineer Hilcorp Alaska, LLC I Milne Point Cell: 907-903-3987 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov Re: Milne Point Field, Prince Creek Water and Tertiary Undefined WTRSP Pool, MPU M-06 Hilcorp Alaska, LLC Permit to Drill Number: 219-113 Surface Location: 4916' FSL, 861' FEL, SEC. 14, TI 3N, R9E, UM, AK Bottomhole Location: 616' FNL, 2633' FWL, SEC. 14, T13N, R9E, UM, AK Dear Mr. Helgeson: Enclosed is the approved application for the permit to drill the above referenced service well. 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, Daniel T. Seamount, Jr. Commissioner DATED thisda of August, 2019. STATE OF ALASKA A,SKA OIL AND GAS CONSERVATION COMM,. SION PERMIT TO DRILL 20 AAC 25.005 ,IJ^� r ., u l,. 1a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1c. Specify if well is proposed for: Drill ❑� Lateral ❑ Stratigraphic Test ❑ Development -Oil ❑ Service - Winj ❑ Single Zone ❑� Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ED ' Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU M-06 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 3,583' TVD: 2,870' Milne Point Field Prince Creek Water 4a. Location of Well (Govemmental Section): 7. Property Designation: Surface: 4916' FSL, 861' FEL, Sec 14, T1 3N, R9E, UM, AK •" ADL025514 Tertiary Undef WTRSP Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 461' FNL, 1572' FEL, Sec 14, T1 3N, R9E, UM, AK LONS 16-004 9/7/2019 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 616' FNL, 2633' FWL, Sec 14, T13N, R9E, UM, AK 2560 - 460'to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 58.6' 15. Distance to Nearest Well Open Surface: x-533303 y- 6027765 Zone -4 GL / BF Elevation above MSL (ft): 24.9' to Same Pool: 840'to MPU M-04 16. Deviated wells: Kickoff depth: 520 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 47 degrees Downhole: 1262 • Surface: 976 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD ' TVD (including stage data) Cond 20" 215# A-53 Weld 113' Surface Surface 113' 113' ±270 ft3 10-3/4" 45.5# L-80 TXP SR 2,000' Surface Surface 2,000' 1,791' L 3414 ft3 13-112" 2,000' 1,791' 3,583' 2,870' - 9-5/8" 40# L-80 TXP SR 1,583' 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No ❑� 20. Attachments: Property Plat ❑ BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch e Seabed Report B Drilling Fluid Program B 20 AAC 25.050 requirementse 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hilcor .com Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: - _ Date: Z Commission Use Only Permit to DrillI Number: Permit Approval See cover letter for other Number: 2.11p - 113 50- OZ: -Z3' s*a- 00 -Da Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed-melthane,gas hydrates, or gas contained in shales: Other: yy'� 2 �OO r/j d ✓ E- 3 Samples req'd: Yes ❑ No .LI• Mud log req'd: Yes r❑yNo [� 7r "-S PS` HzS measures: Yes ❑ No &' Directional svy req'd: Yes L� No❑,/ Spacing exception req'd: Yes ❑ No [� Inclination -only svy req'd: Yes ❑ No F Post initial injection MIT req'd: Yes ❑ No[] APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: (j J I Submit Form and F 10.;f�1Mi p6�2017 ` �� is Permit is0it'j�{�r #4�rrr�r�h�fr'orr�htdate of approval per 20 AAC 25.005(g) achments in Duplicate 7J.-r'V ii l 11 tp,[` I G 111 V H L 4011 - $% 14 Hilcorp Alaska, LLC Milne Point Unit (MPU) M-06 Water Source Well Drilling Program Version 1 August 19, 2019 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 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 13-1/2" Hole Section.............................................................................................................12 12.0 Run 10-3/4" X 9-5/8" Surface/Production Casing......................................................................15 13.0 Cement 10-3/4" X 9-5/8" Surface Casing....................................................................................20 14.0 BOP NIU and Test.........................................................................................................................23 15.0 Wellbore Clean Up & Displacement............................................................................................24 16.0 Completion Operations.................................................................................................................24 17.0 Diverter Schematic........................................................................................................................25 18.0 BOP Schematic..............................................................................................................................26 19.0 Wellhead Schematic......................................................................................................................27 20.0 Days Vs Depth................................................................................................................................28 21.0 Formation Tops & Information...................................................................................................29 22.0 Anticipated Drilling Hazards.......................................................................................................30 23.0 Doyon 14 Rig Layout.....................................................................................................................32 24.0 Choke Manifold Schematic...........................................................................................................33 25.0 Casing Design Information...........................................................................................................34 26.0 13-1/2" Hole Section MASP..........................................................................................................35 27.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................36 28.0 Surface Plat (As Staked) (NAD 27)..............................................................................................37 Milne Point Unit M-06 WSW Drilling Procedure Hilcorp E.e Company 1.0 Well Summary Well MPU M-06 Pad Milne Point "M" Pad Planned Completion Type 5-1/2" ESP Target Reservoir(s) Prince Creek Planned Well TD, MD / TVD 3,582' MD / 2,870' TVD PBTD, MD / TVD 3,502' MD / 2,813' TVD Surface Location Governmental 4916' FSL, 861' FEL Sec 14, TON, R9E, UM, AK Surface Location (NAD 27 — Zone 4) X=533,303.8 Y=6,027,765.62 Top of Productive Horizon (Governmental) 461' FNL, 1572' FEL, Sec 14, T13N, R9E, UM, AK TPH Location AD 27 X=532,593.22, Y=6,027,665.46 BHL (Governmental) 616' FNL, 2633' FWL, Sec 14, T13N, R9E, UM, AK BHL (NAD 27) X=531,520.25, Y=6,027,505.41 AFE Number 1914443 AFE Drilling Das 6 AFE Completion Das 6 AFE Drilling Amount $1,624,001 AFE Completion Amount $2,435,225 AFE Facility Amount $391,000 Maximum Anticipated Pressure Surface 976 psi Maximum Anticipated Pressure Downhole/Reservoir 1262 psi KB Elevation above MSL: 33.7 ft + 24.9 ft = 58.6 ft GL Elevation above MSL: 24.9 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Milne Point Unit M-06 WSW Drilling Procedure Hileorp Energy c2, 2.0 Management of Change Information 11 Hilcorp Alaska, LLC I -tit o E�C.rp Changes to Approved Permit to Drill Date: August 16, 2019 Subject: Changes to Approved Permit to Drill for MPU M-06 File #: MPU M-06 Drilling Program Any modifications to MPU M-06 Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the AOGCC prior to continuing forward with work. Approval: Drilling Manager Prepared: Drilling Engineer Page 3 By Date Date IN Milne Point Unit M-06 WSW Drilling Procedure Hileorp E.n C2,T 3.0 Tubular Program: Holeade Conn Burst Collapse Tension Section (in) O�'(ii]) (#1fi)� (psi) (psi) (k -lbs) Cond 20" 19.25" - - 78.6 A-53 Weld 10-3/4" 9.95" 9.794" 11.25" 45.5 5,210/ 2,470/ 1,040/ 13-1/2" X X X X X L-80 TXP/SR 5,750 3,090 916 9-5/8" 8.835" 8.679" 10.625' 40 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks) 4.0 Drill Pipe Information: Page 4 Milne Point Unit M-06 WSW Drilling Procedure Hilcorp &� C—�Y 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 tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to mmyers@hilcgM.com, pmazzolinina hilcoM.com , ieneel@hilcorp.com and cdinger(a),hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EBS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager & Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyers@hilcorp.com and cdin eg_r c@hilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmxers hilcorp.com and cdinger@hilcoM.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmvers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 iengel@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomev@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 Drilling Tech Cody Dinger 907.777.8389 1 509.768.8196 cdinger@hilcorp.com 71 Page 5 Milne Point Unit M-06 WSW Drilling Procedure Hilcorp E� C.Mpft 6.0 Planned Wellbore Schematic v`k Ao Milne Point Unit Well: MPU Moose Pad M-06 PROPOSED SCHEMATIC Last Completed: FUTURE PTD: TBD m=seas' (NQ I TD= 2.AVI rw7 Page 6 Milne Point Unit M-06 WSW Drilling Procedure Hilcorp E.c Czix 7.0 Drilling / Completion Summary MPU M-06 is a grassroots water source well intended for producing Prince Creek water to be used as injection water on M Pad injection wells. Wellbore is located on "Moose" pad. The directional plan is a slant well with the kick off point at 600' MD/TVD. Maximum hole angle is 47 degrees. • Doyon 14 will be used to drill and complete this wellbore. Drilling operations are expected to commence approximately September 7th, 2019, pending rig schedule A tapered surface/production casing string will be run to 3,582' MD / 2,870' TVD and cemented to surface via a single stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, 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 waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on `B" pad. General sequence of operations: MOB Doyon 14 to well site N/U 21-1/4" conductor and 16" diverter line 3. Drill 13-1/2" hole to TD. Run and cement 10-3/4" X 9-5/8" casing 4. NU Wellhead & BOPE, Test 5. Perform 9-5/8" Scraper Run Note: The following operations will be submitted on a separate sundry 6. RU Eline to perforate casing 7. Run gravel pack equipment and perform gravel pack operations 8. Run upper completion 9. NIU tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res Page 7 H �IlCcOrp Milne Point Unit M-06 WSW Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-06. Ensure 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 equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Milne Point Unit M-06 WSW Drilling Procedure Hilcolp Ewa c—Pffy Summary of Well Control Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 13-1/2" 21-1/4" 2M diverter (Hydril MSP) w/ 16" diverter line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate 30'f o Blind ram in btm cavity Initial Test: 250/4860" • Mud cross w/ 3" x 5M side outlets 8-1/2" • 13-5/8" x 5M Hydril MPL Single ram Subsequent Tests: • 3-1/8" x 5M Choke Line 250/4996'3t-Z1p • 3-1/8" x 5M Kill line • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc • Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. • Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, 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. i • 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: iim.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: V ictoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.eov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/oizc/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 Milne Point Unit M-06 WSW Drilling Procedure Hilcorp E.m Company 9.0 R/U and Preparatory Work 9.1 M-06 will use a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring 9.4 Ensure (2) 4" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. 9.5 Level pad and ensure enough room for layout of rig footprint and rig mat area. 9.6 MIRU Doyon #14. Ensure rig is centered over conductor to prevent any wear to BOPE & wellhead. 9.7 Mud loggers WILL NOT be used on M-06. 9.8 Mix spud mud for 13-1/2" surface hole section. Keep mud cool. 9.9 Install 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @110 spm @ 95% volumetric efficiency. Page 10 H Hilcorp Er C.wDr 10.0 NIU 21-1/4" 2M Diverter System Milne Point Unit M-06 WSW Drilling Procedure 10.1 N/U 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic at Sec 20 at back of program). • NAJ 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/LJ 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter RAJ 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 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 15.375" ID wear bushing in wellhead. 10.5 Rig & Diverter Orientation: M-06 75' Radius Clear of lanition Sources — Diverter line MPU M -Pad '°<a�`^a"otTof<°" Diverter Orlenta[ian MaY cMrne On laca[lon Page 1 1 Milne Point Unit M -O6 WSW Drilling Procedure Hilcorp Eo C—F=Y 11.0 Drill 13-1/2" Hole Section 11.1 P/U 13-1/2" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub 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. • Workstring will be 5" 19.5# S-135 NC -50 • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. • Drill 13-1/2" hole section to section TD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • 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 450-600 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • Take MWD surveys every stand drilled (95' intervals). • Be prepared for gas hydrates at the base of the permafrost. However, none have been encountered on M -Pad. • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding mud products such as Lecithin to allow the gas to break out. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is > 4. Page 12 Milne Point Unit M -O6 WSW Drilling Procedure Hilcotp Encgy Compay • Do not slide for 100' MD above the base of the permafrost or 100' below the base. We want to leave this transition as undisturbed as possible. 11.3 13-1/2" 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 anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office. • Hydrates: Hydrates have not been encountered on "L" or "M" pad but be prepared and don't stop to circulate out gas. Control drill when hydrates encountered. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBsBAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. • 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 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties. Section Density Viscosity Plastic Viscosity Yield Point AN Fl. Temp I pH Surface 8.8-9.5 75-175 20-40 25-45 <10 <70°F 1 8.5-9.0 Page 13 H Hilcorp E.e ,2,T Milne Point Unit M-06 WSW Drilling Procedure System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-1 Gel 50 lb sx 25 Soda Ash 50 Ib sx 0.3 Pol Pac Supreme UL 50 lb 5x 0.05 Caustic Soda 50 Ib sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity 11.5 RIH t/ bottom, proceed to BROOH t/ HWDP • 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, adjust as dictated by hole conditions • 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. 11.6 TOOH and LD BHA 11.7 No open hole logging program planned. Page 14 H Hilcorp Enmgy Cumymy Milne Point Unit M-06 WSW Drilling Procedure 12.0 Run 10-3/4" X 9-5/8" Surface/Production Casing 12.1 Make a dummy run with the 10-3/4" casing hanger. 12.2 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" TXP x NC -50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of. • (1) Shoe joint w/ float shoe bucked on (thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end & thread locked. 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. 9-5/811404 L-80 TXP Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 18,860 ft -lbs 23,060 ft -lbs 12.5 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Install (1) centralizer on each joint. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • 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 cmt returns to surface. Page 15 Milne Point Unit M-06 WSW Drilling Procedure Hilcorp 12.6 At approximately 1,582' make up a 9-5/8" TXP X 10-3/4" TXP crossover and change over equipment to run 10-3/4" casing. • —2000' of 10-3/4" to be run • Ensure 10-3/4" TXP x NC -50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 9.875" 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. 12.7 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Install (1) centralizer across couplings on every other joint. • 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 cmt returns to surface. 12.8 12.9 10-3/41145.5# L-80 TXP Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 10-3/4" 20,370 ft -lbs 24,890 ft -lbs Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 12.10 PIU casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.11 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.12 Have emergency slips ready to go in the event we cannot land the hanger. 12.13 R/U circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. Page 16 H Hilcorp Enemy C.m Milne Point Unit M-06 WSW Drilling Procedure 12.14 After circulating, lower string and land hanger in wellhead again. Page 17 Milne Point Unit M-06 WSW Drilling Procedure Hilcorp Ene , Company For the latest performance data, always visit our website: wwwAenaris.com TXP® BTC -- 0310412019 collapse 3090 as, CONNECTION DATA GEOMETRY Connection OD 10.625 N. C"., Length 10.836in. Connect. to 8.523in. Makeup Loss 4.691 In. outside Diameter 9.625 in. Min. Wall 87.5% PERFORMANCE Thickness Jam Yield SlrergM Cl Grade L80 low 6760.000 psi lbs Ty" 1 Cpmpres.n E?concy 100% Compresvon Seenglh Wall Thickness 0.395in. Connection 00 REGULAR bs option COUPLING qpE a00Y Body Red 1st Band'. Red Grace LBO Type T on" AN Standard 1st Band Brown 2nd Sam. 2ad Band. - Brown Type Casing 3rd Band. - 3rd Band - 4M Band. - PIPEBODY DATA GEOMETRY Ncnana100 9.625 in. Nominal Weight 40 Inch Dnft 6.59in. Nominal 10 Benin. Wall Th"hess 0.395m. Plain Fee Weghl MATbA W iplerance API PERFORMANCE Body YmId Strength 916 x1000 lbs Internal Year! 5750 psi SMYS woo psi collapse 3090 as, CONNECTION DATA GEOMETRY Connection OD 10.625 N. C"., Length 10.836in. Connect. to 8.523in. Makeup Loss 4.691 In. Threads per in 6 Connectcn OD colon REGULAR PERFORMANCE Tension Elroa., 100.0% Jam Yield SlrergM 916.000X1000 ImamalPressure Capacity In 6760.000 psi lbs Cpmpres.n E?concy 100% Compresvon Seenglh 916.000 x1000 Max. &I"able sending 38.1100 ft bs External Pressure Capadry 3090.000 ina MAKEJUPTORQUES Minimum la"oft�s OpOmmn 20960 flips Maximum 23060 Mies OPERATION LIMIT TORQUES 0porotin9 Toque 35600 ft -lbs Yield Torese 4UN Mos Notes This connection is fully interchangeable with: TXP® BTC - 9.625 in. - 36 / 43.5147153.5 / 58A IbSKt [1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3/ ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sales representative. Page 18 H Hilcorp Estogy company For the latest performance data, always visit our website: www.tenaris.com TXP® BTC Milne Point Unit M-06 WSW Drilling Procedure .,, - 10/17/2015 OPmide Diameter 10.750m. MIs. Wall 97.5% Thickness fl Graft L80 400 Type, 1 Wall hickness 0,400 M. conoedlon 00 REGULAR Option COUPLING PPE 80Dy Body Rad tat Band: Rad Grade LEO Type t- Drift APIStandaM isi Rand: Brown 2nd Band. 2nd Band. - Erevan Type casing 3rd Bang. - 3M Band:o - 4m Bard - PIPE BODY DATA GEOMETRY Nominal Do 10.750 in Nookinal Weight Ail Dns 9.791 at Nominal ID 9.950m. Walk Thickness 0.4010m. plain End Weight 4128ll ODTdoorce API PERFORMANCE Sony Yleas Soetgm 1040 x1000lbs Inmmal Yeas 5214 pv SUNS 80000 pal collapse 2470 Dsi CONNECTION DATA GEOMETRY ConnatOon OD 11.750 in. Coupling Length 10.825 in. connection to 9.918 in. Makewp Lwa 4.591 e. ihreaospenn 5 connection OD Option REGULAR PERFORMANCE Tahitian EBmmcy 100.0% Joint 'hood strength 1040AeNx1o00 ImemalPren acapadtyl: 5210.000 Dai ms Compression Emcam, 400% cpmocaion snength 1040.000x1000 Mas.AbrsaUc ecMng 54'limit be, Ederral Pressure C xi 2470.000 pa. MAKEarP TORQUES Manor'. 2037011-1. Optimum 22830 nabs Maximum 24890le1bs OPERATION LIMR TORQUES Opsholho Tow. 37200 itch, Yeld Toque 45400 nobs Notes This connection is fully interchangeable with TXP® BTC - 10.75 in. - 40.5 151 Ibs/ft 111 Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3 / ISO 10400 - 2007. Dalasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load. which will be reduced. Please contact a local Tenads technical sales representative. For further information on concepts indicated in this datasheet, download the Datasheet Manual from www.tenads.com T... has. i. dotement hr,hohM china'. polo. MO she nohoo. In IM1F de t,nIMry-11-1kh—, anY 1-e nnm,2, a Etlpna t'Mlgma. ml nim4nis rcmuiuin Pdcasinny«mr am+`rty{e hitaMtearttpmmmbinn arCap'wMM on 05,5"nao.,no.want,n& .T..ny,Mcondehay vCntM my ns;rmama+-1l anr-prondM hviMV9nmep✓2nNn mm.«M mcpVWSWMorWIMJnM1)lm wamoo1cmwda.Theowolthakfo itonnatw«s Wn rrsx rd *main aomw assuneairyrpapmabLry prlatYyol anY wind eronY bss, daml9e a iNun' mub^9 nom. «n tomnadn xm enY Nbmuwn <mmmed nerniMer Page 19 0 Hcorp E=VC Milne Point Unit M-06 WSW Drilling Procedure 13.0 Cement 10-3/4" X 9-5/8" Surface Casing 13.1 Hold a pre -job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates. • How to handle cmt 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 cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron 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 cmt pump or treating iron will not be pumped downhole. 13.4 R/U cmt head (if not already done so). Ensure top and bottom tapered plugs have been loaded correctly. 13.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 13.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug. Mix and pump cmt per below calculations. 13.8 Cement volume based on annular volume + hole excess based upon depth, see below. Job will be pumped in a single stage, TOC brought to surface. LI pA OV • Cement & Excess: Leap 1. 10-3/4" / Permafrost: 10.7ppg Perm L, 200% Excess 2. 9-5/8" / Below Permafrost: 15.8ppg Class G, 30% Excess,// Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) Conductor x 10-3/4" casing: 113 x 0.24 bpf = 28 bbls 157 ft3 13-1/2" OH x 10-3/4" casing: (2000'- 113') x 0.065 bpf x 3 = 368 bbls 2066 ft3 -1/2" OH x 9-5/8" casing: (3582'- 2000') x 0.087 bpf x 1.5 = 206 bbls 1159 113 —13 9-5/8" Shoe track: 80 x .07582 bpf = 6 bbls 34 ft3 Total: 608 bbls 3414 ft3 rage /u 7;�- 4n0 qIj Milne Point Unit M-06 WSW Drilling Procedure Hilcrp Ev C2jx Cement Slurry Design: 13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. 13.11 Ensure rig pump is used to displace curt. Displacement calcs have proven to be very accurate using 0.101 bps for pump output. 13.12 Displacement calculation: (2000' x .09617,bpf, 10-3/4") + (1502' x .07582, 9-5/8") = 305 bbls total 13.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 3 bbls before consulting with drilling engineer. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.16 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route curt. Page 21 Lead Tail System Permafrost L SwiftCEM Tm System (HAL Cem) Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.04 gal/sk 13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. 13.11 Ensure rig pump is used to displace curt. Displacement calcs have proven to be very accurate using 0.101 bps for pump output. 13.12 Displacement calculation: (2000' x .09617,bpf, 10-3/4") + (1502' x .07582, 9-5/8") = 305 bbls total 13.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 3 bbls before consulting with drilling engineer. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.16 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route curt. Page 21 H Hilcorp E.VCmpffr Milne Point Unit M -OL WSW Drilling Procedure 13.17 Flush out BOP, and clean out above hanger. Remove landing joint. 13.18 M/U pack -off running tool and pack -off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.19 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 & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping 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 mmyers2hilcoM. com and cdingerghilcorp com This will be included with the EDW documentation that goes to the AOGCC. Page 22 H Hileorp enew Company 14.0 BOP NIU and Test 14.1 N/D the diverter & N/U casing spool. Milne Point Unit M-06 WSW Drilling Procedure 14.2 NIU 13-5/8" x 5M 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" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should also be dressed with 2-7/8" x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.3 Run 5" BOP test assy, 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. • We will need to test on the following sizes: 5" for DP workstring 5-1/2" for production tubing 14.4 R/D BOP test assy. 14.5 Set 10" ID wearbushing in wellhead. 14.6 Keep 6" liners in mud pumps. Page 23 Milne Point Unit M-O6 WSW Drilling Procedure Hilcorp 15.0 Wellbore Clean Up & Displacement 15.1 M/U casing clean out assembly complete with 9-5/8" casing scrapers • 8.5" bit • Casing scraper for 9-5/8" 40# casing. • +/- 1500' 5" DP. • Casing scraper for 10-3/4" 45.5# casing. • 5" DP to surface. 15.2 After wellbore has been cleaned out satisfactorily using mud, test casing to 2,500 psi / 30 min. gC 15.3 Displace drilling fluid in wellbore with a hi -vis pill followed by 8.8 ppg 2% KCl brine. .09 • Consider catching drilling fluid in rain -for -rent tanks for use on a future well if feasible. • Circulate fresh water into wellbore until clean-up is satisfactory. Do not recirculate fluid, • After a couple circulations using 8.8 ppg 2% KCl brine, short trip the assy to bring the 10- 3/4" scraper to surface. • Pump a chemical train followed by 8.8 ppg 2% KCl brine. 15.4 TOH w/ clean out assy. Rack back 5" DP. Note any abnormal wear on the clean out assy. 16.0 Completion Operations /16.1 A separate sundry will be submitted to the AOGCC for approval to run a gravel pack completion on this well. Page 24 Milne Point Unit M-06 WSW Drilling Procedure Hilcorp Encu,2,w 17.0 Diverter Schematic 21-114' 2M Riser - 21 -114' 2M— Divener"T' 21-114"21 Spacer Spa 116-3/4'314 21.114" 2M OS Seaboard casinghead. S -22 -AP 16* SOW x15314"31 (2) ea 24116" 5M studied outle Page 25 —16" Full Opening Knife Valve `16' Diverter Line H Hilcorp �� C—,-, 18.0 BOP Schematic Hydril GK Annular BOP 13-518"x 5M J U 13-518" x 5M U L ❑ ❑ vOo ❑ ❑ ❑❑ ,tea ❑❑ Kill Line 9-518" DBL Casing 16-3/4" NOM 13-518"x 9-5/8" Page 26 13-518"x 5M Milne Point Unit M-06 WSW Drilling Procedure �3" x 5M HCR `Choke Line `3" x 5M Manual Gate Valve 11" x 5M ,,,---2-1116"x 5M x5M 13-5/8" x 5M \-2-1/16"x 5M -20" Casing 9-5/8" Casing Milne Point Unit M-06 WSW Drilling Procedure Hilcorp E.c Cmnpmy 19.0 Wellhead Schematic Page 27 I Page 27 Milne Point Unit M-06 WSW Drilling Procedure Hilcergy orp Enc2,7 20.0 Days Vs Depth 0 500 1000 t isoo n d v v w 2000 v 2500 3000 3500 Page 28 MPU M-06 WSW Days vs Depth I 0 2 4 6 8 10 12 Days K Hilcorp 21.0 Formation Tops & Information Milne Point Unit M-06 WSW Drilling Procedure MPU M-06 Formations (wp03) MD (ft) Til (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2045 -1763 1822 801.68 8.46 SV1-(Top Water Source) 2080 -1787 1846 812.24 8.46 Ug CoalI- (BaseWaterSource) 3360 -2675 2718 1195.92 8.46 TD8 .p fflc cad rg dadgn• dapdrs.. sites 46 3582 2811 2870 1262.8 IZ fo. bsz Z-S7fl L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL F as COMMENTSI TVD FM LITH DESCRIPTION vara NOTE: See indhiduel Well Program for T' .p fflc cad rg dadgn• dapdrs.. sites too r•.ights, groes end ca.l lon+. yy1 1lncreotiell.tl Cyre.b m>dbm YM ,M.m*I '.r,l ;. Mn mina.ce.trw. F SIGNIFICANT AMOUNTS OF GRAVEL 10000' ARE ENCOUNTERED WHEN DRILLING THE SURFACE HOLE, THE VISCOSITY Of THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. +t]0' Baso permafrost alyYeedo of saw. ch],.M Me.bAa MlR a[u.bnl zill show of Coad. sell Pwdele awls, acwlrg CAN eaP„ a weNnyuarYn� LJ] L LA 5. � No hydrates encountered on LAtKI wells drilled to date. Com.naed edYbd. W and. ebl and *Mabee. MIR «c.>b1Yl aRwn alta*- lest,. or P'/rlr.1 N. ]bo n 31400' Yrn„.,-].m n c,n wsacyr.ne 1pnl pntl Oen e.,re.a e.e.«n ]mo,naawon C >.>s. A aesr ewl UGNU: serlw alcanenRg 1pr.sd>enb Mlch.r. N.*MAY nrb W d: Ikam tap bepbml mese end 16*.Yq. Ylo rss e.eb .R.Ys nTau UDNU L Ind 0 Ide..Crriinp Pefeerl Wall* L ora M srwpbt Uyre .ntl 5[R1)br 81Jf Pw.IW lrytroutROA IImIM l.e.+r bsw con Ylaa tl.Mlapnant Mwnt wa u.e n IweV t.l ewrrsmciv. ora war. .]]g ll rae.m ��Yn00I° Schrader Bluff Sands: 4,000' CaMe.ral.y..w,rcurunwPop.o..d >.M>,..bo.. � Schrader Bluff_ Possible lost PlcYYtkOr tone while drilling long strings and running rian.- e RatomnxnddoaPings. coick'j fpV slvldgmtcasing. bcwcoa�...I Ylk�tl.wwpn�nc Car..a Cay .1. lso.t strings. Also. the er Muparuklong mmpr>.e.a sv senna.. 51ie1.s.d wnl.nenaa Sic hrddlx Bluff sande area potential Schrader Schrader LrMI>dnY IN l .,, .1 diffarcMlat stuck pipe interval If left un -rased Bluff C sWar a>ep WING, Hw eewr for KuparuM long strings. Sands: Uhmdo. 111.1 os.and set Ion”, n.eCR..r. l Page 29 n Hilcorp En Coa 22.0 Anticipated Drilling Hazards Surface Hole Section: Milne Point Unit M-06 WSW Drilling Procedure Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently 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 efficiently — control ROP and avoid loading the hole with gas. Minimize gas belching by reducing flow rate if necessary. 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. 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 adjacent wells in the vicinity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn 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 142S events have been documented on drill wells on this pad. Page 30 H Hilcorp Milne Point Unit M-06 WSW Drilling Procedure 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 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. Page 31 H Hilcorp Energy Compmy 23.0 D Page 32 14 Ri o emras 1. ut TM Cn I N s Milne Point Unit M-06 WSW Drilling Procedure 9, war= toL l •�+1 s X41 i1r�`I i17?'r� X41 �;� i _ � 1 CHOKE MANIFOLD [ftucs rJ I LEGEND White Handled Valves Normally Open (D Red Handled Valves Normally Closed Date: 08-22-14 Rev, 3 NOTES: 1) Valve A is a 3-1116" SM Remote Operated Hydraulic Choke Valve. 2) Valve B is a 3-118" 5M Adjustable Choke Valve. 3) Valve I is a 2-1116" 5M Manual Gate Valve. 4) Valves 2-14 are 3-1/8" SM Manual Gate Valves. Divert Line From BOP Divert Line To Mud/Gas Separator Milne Point Unit M-06 WSW Drilling Procedure Hilcorp Ene c2,7 25.0 Casing Design Information Calculation & Casing Design Factors Hole Size 13-1/2" Hole Size Hole Size Milne Point Unit DATE: Aug 19, 2019 WELL: MPU M-06 DESIGN BY: Joe Engel Criteria: Mud Density: 9.2 Mud Density: Mud Density: Drilling Mode MASP(13-1/2"): 976 psi (see attached MASP determination & calculation) Production Mode MASP: 1262 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2, 3 Max MW gradient external stress and the casing evacuated for the internal stress Page 34 Casing Section _ Calculation/Specification 1 T 1 Casing OD 10-3/4" 9-5/8" _ Top (MD) 0 2,000 Top (TVD) 0 1,791 Bottom (MD) 2,000 3,582 Bottom (TVD) 1,791 2,869 Length 2,000 1,582 Weight (ppf) 45.5 40 Grade L-80 L-80 Connection w Tv _ Weight w/o Bouyancy Factor (Ibs) 91,000 63,280 Tension at Top of Section (lbs) 91,000 63,280 Min strength Tension (1000 lbs) 1040 916 Worst Case Safety Factor (Tension) 11.43 14.48 Collapse Pressure at bottom (Psi) 770 1,234 Collapse Resistance w/o tension (Psi)----f,-470— Psi)2,470Worst WorstCase Safety Factor (Collapse) 3.21 3.88 MASP (psi) 976 976 Minimum Yield (psi) 5,210 51750 Worst case safety factor (Burst) 5.34 5.89 Page 34 Milne Point Unit M -O6 WSW Drilling Procedure Hil=Encs Company 26.0 H Hilcorp 13-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 13-1/2" Hole Section MPU M-06 Milne Point MD TVD Planned Top: 0 0 Planned TD: 3582 2870 D n4i rina4pd Fnrmarinnc and Praccurpc Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Base Permafrost 1822 801 1 Wet 8.45 0.440 Top Source Water 1846 812 Wet 8.46 0.440 Base Source Water 2718 1195 Wet 8.46 0.440 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date MPM-04 9.2 0 2,670 1 2019 Assumptions: 1. Maximum planned mud density forthe 13-1/2" hole section is 9.6 ppg. Fracture Pressure at 10.3/4" shoe considering a full column of gas from shoe to surface: 2870 (ft) x 0.78(psi/ft)= 2238.6 2238 (psi) - [0.1(psi/ft)*2870(ft)]= 1951 psi Drilling Mode MASP MASP from pore pressure (wellbore completely evacuated to gas) 2870(ft) x 0.44(psi/ft)= 1263 psi 1262 (psi) - [0.1(psi/ft)*2870(ft)]= 976 psi Summary: 1. MASP while drilling 13-1/2" hole is governed by drilling on diverter. Page 35 Milne Point Unit M -Ob WSW Drilling Procedure Hilcorp Enegy Czjx 27.0 Spider Plot (NAD 27) (Governmental Sections) Page 36 A Milne Paint Unit asks State Plane Zone 4 NAD 1927 MPU M-06 Well 0 500 1.000 wp 03 Feel ADL388235 ADL355023 KUPARUK RIVER UNIT A1PU- w ' Vee0e a�aa� ATL'\ _ pD0009e '• A4M5 MPL \1 [n INSP'1_TPII MPF yI-Ufif\YSR'1 BHC�� \ u • ••` U013N009E ' • u I • ' I i ,•` ---__-__ __ ' MILNE QOINT UNIT i t \ r ' ^`� ADL025514 Se- '4 ' / S. 13 i r I r n • t` r r 1 •'r I t �• t Legend ' � • t 1 • MPUM-06(WSW)_SHL Other Surface Holes (SHL) t d X MPU M_N(WSW)_TPH Other Bottom Holes(BHL) - - - Other Well Paths " MPU M-06 (WSW)_BHL _ Coastline (USGS 1-63k) 1 tvm Oil and Gas Uni Boundary n ' Ped Foolait t n Page 36 A Milne Paint Unit asks State Plane Zone 4 NAD 1927 MPU M-06 Well 0 500 1.000 wp 03 Feel H Hilcorp 28.0 Surface Plat (As Staked) (NAD 27) Milne Point Unit M-06 WSW Drilling Procedure Page 37 12 lH8 PR�O.JECT MOOSE PAD gt. 12 I I Mc 0 m pj SEC. 9 IT I —SEC --13I 14 Y PAO� 1 Y-10 ■ M -I1 ■ I I • W -1J I y}, M-12 ■ dry II ■ Y-14 I 23 7f 1 " MINE 4TE E Y-5) ■ ■ Y-15 M21 VICINITY MAP ■ Y -1a i -■ U-22 N ■ Y-1) I Y-iJ ■ ■ Y-10 -IU LEGE D. y M-25+ I 71 ffi I 4-24 ■ ■ Y-19 .� As-s1ANED OMDOOTOR I� E1PSINC CONOUC10fl M-26+ Y"■■ I NOTES,, I I M-030 1. AlA9fA STATE RALE O NABS ARE N027, ZME 4. M P"TKINS OM R1027. M-06 I 1 �s OF � rn � cMTINX 6 M=E �WTNL w YHi MW% PID SOME FmK" M. 09999011 S DAIS 6 91A .. AXLY M 2019. I S gEFpPEMOE FW 900X: X019-04 M 02-01 I GRAPHIC SCALE 1w 400 D D I PAD � (IN PUT) MOOSE 1 ne + 100 % LOCATED WITHIN PROTRACTED SEC, 14, T. 13 N., R. 9 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. T GEODETIC GEODETIC SECTION PAD CELLAR BASE NO. COORDINATES TES POSITION DMS POSITION O.DD OFFSETS ELEVATION BOX EL. FLANGE EL, Y= 6,027.765.62.98 70'29'12.806' 70.4868906' 4,916: FSL 24.9' N/A N/A M-6 X. 533,303.86.98 149'43'40.068" 149.7277967' 851' FEL Y= 6,027,869.642.01 E1,545 70'29'14.015' 70.4872264' 5,039' FSL 25.0' N/A N/A M-25 X- 533,543.86.00 -00 149"43'32.989" 149.7258304' 621' FEL Y= 6.027,889.642.01 7029'14.021" 70.4872281' 5,039' FSL 25.1' N/A N/A M-26 X= 533.423.87.00 149'43'36.520" 149.7268111' 741' FEL M4D9$ Hilcorp Alaska 7 9 �I MPU MOOSE PAD AS -STAKED CONDUCTORS WELLS 6, 25, 26 1.1 Page 37 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Proposal: MPU M-06WSW - Slot 1 MPU M-06 (WSW) Plan: MPU M-06 wp03A Standard Proposal Report 21 August, 2019 HALLIBURTON Sperry Drilling Services NALLIBURTON MD EM Sperry Drilling TVD -N/-S Hilcery Alaska, LLC Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio {( REFERENCE INFORMATION c. ce (N/E) Reference: Well Proposal: MPU 10-06WSW -Slot 1, True Vertical (TVD) Reference: MPU M-06 As -staked @ 5860us8 handled Depth Reference: MPU M-06 As -staked @ 58.60os6 Calculation Method: Minimum Curvature Sec MD Inc Azi TVD -N/-S +E/ -W Dleg TFace VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 519.70 0.00 0.00 519.70 0.00 0.00 0.00 0.00 0.00 Start Dir 3°/100':519.7' MD, 519.7 -TVD 3 719.70 6.00 266.76 719.33 -0.59 -10.45 3.00 266.76 10.42 Start Dir 4°/100':719.7' MD, 719.33'TVD 4 1746.27 47.04 261.77 1618.44 -59.94 -454.96 4.00 -5.56 458.86 End Dir : 1746.27' MD, 1618.44' TVD 5 3382.56 47.04 261.77 2733.60 -231.30 -1640.07 0.00 0.00 1656.29 M-06WSW wp03 Hardee 6 3582.56 47.04 261.77 2869.90 -252.25 -1784.93 0.00 0.00 1802.65 Total Depth :3582.56' MD, 2869.9' TVD CASING DETAILS TVD TVDSS MD Size Name 1791.36 1732.76 2000.00 10-3/4 10 3/4" x 13 1/2" 2869.90 2811.30 3582.56 9-5/8 95/8° x131/2" Project: Milne Point Site: M Pt Moose Pad Well: Proposal: MPU M-06WSW - Slot 1 Wellbore: MPU M-06 (WS WI Design: MPU M-06 wp03AA 0- 250- 500 500- - - - Start DIT Y/100' : 519.7' MD, 519.77VD Start Dir 4°/100' : 719.7' MD, 719.33'TVD 7501 _ 1000 1000 c on 1250 End Dir : 1746.27' MD, 1618.44' TVD x 1500 v 10 3/4" x 13 1/2" 1750- BPRF BPRF --- --n° m 2 SVt H 2000 - FORMATION TOP DETAILS TVDPath TVDssPath MDPath WELL DETAILS: Proposal: MPU M-06WSW -Slot 1 1621.60 1763.00 2044.37 24.90 1845.80 +N/ -S -E/-W Northing Easting Lati6ude Longitude 0.00 0.00 6027765.62 533303.86 70° 29' 12608 N 149° 43' 4 SURVEY PROGRAM Date:2018-06-28T00:00:00 Valldated:Yes Version: Depth From Depth To Survey/Plan Tool 33.70 2215.00 MPU M-06 wp03A(MPU W06 (WSW)) 2_MWD*IFR2 2215.00 3582.53 MPU M-06 wp03A(MPU 10-06 (WSW)) 2_MWD*IFR2 500 500- - - - Start DIT Y/100' : 519.7' MD, 519.77VD Start Dir 4°/100' : 719.7' MD, 719.33'TVD 7501 _ 1000 1000 c on 1250 End Dir : 1746.27' MD, 1618.44' TVD x 1500 v 10 3/4" x 13 1/2" 1750- BPRF BPRF --- --n° m 2 SVt H 2000 - oZ r�o MP_UG_COAL1 M-06WSW wp03 Hard �5 -o, Total Depth : 3582.56' MD, 2869.9' TVD 9 5/8" x 13 1/2" MPU M-06 wp03A -750 -500 -250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 Vertical Section at 261.77' (500 usTtlin) FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1621.60 1763.00 2044.37 BPRF 1845.80 1787.00 2079.59 SV1 2733.60 2675.00 3382.56 MP UG COALi oZ r�o MP_UG_COAL1 M-06WSW wp03 Hard �5 -o, Total Depth : 3582.56' MD, 2869.9' TVD 9 5/8" x 13 1/2" MPU M-06 wp03A -750 -500 -250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 Vertical Section at 261.77' (500 usTtlin) Vuswswu""v 1800 -I)M : oject: Milne Point Site: M Pt Moose Pad Well: Proposal: MPU M-06 Wellbore: MPU M-06 (WSW) 6.Iw ooU Plan: MPU M-06 wpO3A ® HALLIBUFrMN ee..ry o.11,l..a w6u pEL91L9: e,er�a'. MrNMnnwsw-smll a.M 0.6 .,7W6'LGSIinP I+titlWe InnPlllh SJJ]N HE M3413$95N IJ9°4J'J0.WBW mae.ns M'01 a[r«.z.:w v,o MPU Mcew -s 1. naN h IbIFY ((WI P,k— MW MPoMSW W �g{rNh "tl` u�om �k'aei isNm�i�a,.e4®se.cown rVO rwsS Mn siu Nva INLl6 173 276 M0,00 10-314 IO 3A'x 1116" 286991 3811.30 3582.56 9-58 9m"x13ta- lul'J'[IJII±' _t SGS �� e E a3 0' LQ 4 J9 , a� a� ?so ado o a -IMO .900 4ioO -700 600 -500 400 -300 -200 - 00 0 Wesl(-)/Fall(+) (200 ceiVin) HALLIBURTON Database: NORTH US+CANADA Company: Hilaorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Proposal: MPU M-06WSW - Slot 1 Wellbore: MPU M-06 (WSW) Design: MPU M-06 wp03A Halliburton Standard Proposal Report Local Co-ordinate Reference: Site M Pt Moose Pad TVD Reference: MPU M-06 As -staked @ 58.60usft MD Reference: MPU M-06 As -staked @ 58.60usft North Reference: True Survey Calculation Method: Minimum Curvature 'roject Milne Point, ACT, MILNE POINT Aap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level ieo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Aap Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt Moose Pad PLAN Tie On Depth: Depth From (TVD) Site Position: Northing: 6,027,877.65 usft Latitude: 70° 29'13.905 N From: Map Easting: 533,363.92usft Longitude: 149° 43'38.286 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: 0.26' Well Proposal: MPU M-06WSW - Slot 1 +E/ -W Rate Well Position +N/ -S -111.77 usft Northing: 6,027,765.62 usfl Latitude: 70° 29'12.806 N +E/ -W -60.57 usft Easting: 533,303.86 usft Longitude: 149" 43'40.068 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 24.90 usft Wellbore Magnetics Design Audit Notes: Version: Vertical Section: MPU M-06 (WSW) Model Name BGGM2018 MPU M-06 wp03A Sample Date 9/1/2019 Declination Dip Angle (1) (") 16.48 Phase: PLAN Tie On Depth: Depth From (TVD) +N/S +E/ -W (usft) (usft) (usft) 33.70 -111.77 -60.57 80.95 Field Strength (nT) 57,415.15642567 33.70 Direction (") 261.77 Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (") (") (usft) usft (usft) (usft) ("/100usft) (°/100usft) (°/100usft) (^) 33.70 0.00 0.00 33.70 -24.90 -111.77 -60.57 0.00 0.00 0.00 0.00 519.70 0.00 0.00 519.70 461.10 -111.77 -60.57 0.00 0.00 0.00 0.00 719.70 6.00 266.76 719.33 660.73 -112.36 -71.01 3.00 3.00 0.00 266.76 1,746.27 47.04 261.77 1,618.44 1,559.84 -171.71 -515.53 4.00 4.00 -0.49 -5.56 3,382.56 47.04 261.77 2,733.60 2,675.00 -343.06 -1,700.64 0.00 0.00 0.00 0.00 3,582.56 47.04 261.77 2,869.90 2,811.30 -364.00 -1,845.50 0.00 0.00 0.00 0.00 6!21/2019 5:16:23PM Page 2 COMPASS 5000.15 Build 91 Halliburton H A LL I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Site M Pt Moose Pad Company: Hilcorp Alaska, LLC TVD Reference: MPU M-06 As -staked @ 58.60usft Project: Milne Point MD Reference: MPU M-06 As -staked @ 58.60usft Site: M Pt Moose Pad North Reference: Two Well: Proposal: MPU M-06WSW - Slot 1 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-06 (WSW) Design: MPU M-06 wp03A Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +El -W Northing Easting DLS Vert Section (usft) V) (I (usft) usft (usft) (usft) (usft) (usft) -24.90 33.70 0.00 0.00 33.70 -24.90 -111.77 -60.57 6,027,765.62 533,303.86 0.00 0.00 100.00 0.00 0.00 100.00 41.40 -111.77 -60.57 6,027,765.62 533,303.86 0.00 0.00 200,00 0.00 0.00 200.00 141.40 -111.77 -60.57 6,027,765.62 533,303.86 0.00 0.00 300.00 0.00 0.00 300.00 241.40 -111.77 -60.57 6,027,765.62 533,303.86 0.00 0.00 400.00 0.00 0.00 400.00 341.40 -111.77 -60.57 6,027,765.62 533,303.86 0.00 0.00 500.00 0.00 0.00 500.00 441.40 -111.77 -60.57 6,027,765.62 533,303.86 0.00 0.00 519.70 0.00 0.00 519.70 461.10 -111.77 -60.57 6,027,765.62 533,303.86 0.00 0.00 Start Dir 3-1100': 519.7' MD, 519.7'TVD 600.00 2.41 266.76 599.98 541.38 -111.87 -62.25 6,027,765.52 533,302.18 3.00 1.68 700.00 5.41 266.76 699.73 641.13 -112.25 -69.06 6,027,765.10 533,295.37 3.00 8.47 719.70 6.00 266.76 719.33 660.73 -112.36 -71.01 6,027,764.98 533,293.42 3.00 10.42 Start Dir 4-1100': 719.7' MD, 719.33'TVD 800.00 9.20 264.82 798.92 740.32 -113.18 -81.60 6,027,764.12 533,282.84 4.00 21.02 900.00 13.20 263.71 896.99 838.39 -115.15 -100.92 6,027,762.06 533,263.53 4.00 40.42 1,000.00 17.19 263.11 993.48 934.88 -118.18 -126.95 6,027,758.91 533,237.52 4.00 66.61 1,100.00 21.19 262.73 1,087.90 1,029.30 -122.24 -159.56 6,027,754.70 533,204.92 4.00 99.47 1,200.00 25.19 262.47 1,179.80 1,121.20 -127.32 -198.61 6,027,749.45 533,165.91 4.00 138.64 1,300.00 29.19 262.27 1,268.73 1,210.13 -133.40 -243.88 6,027,743.18 533,120.66 4.00 184.52 1,400.00 33.19 262.12 1,354.26 1,295.66 -140.43 -295.18 6,027,735.91 533,069.40 4.00 236.30 1,500.00 37.19 262.00 1,435.97 1,377.37 -148.39 -352.24 6,027,727.69 533,012.38 4.00 293.91 1,600.00 41.19 261.90 1,513.47 1,454.87 -157.25 -414.79 6,027,718.56 532,949.88 4.00 357.09 1,700.00 45.19 261.81 1,586.36 1,527.76 -166.95 -482.52 6,027,708.56 532,882.20 4.00 425.51 1,746.27 47.04 261.77 1,618.44 1,559.84 -171.71 -515.53 6,027,703.65 532,849.22 4.00 458.85 End Dir : 1746.27' MD, 1615.44' TVD 1,800.00 47.04 261.77 1,655.06 1,596.46 -177.33 -554.44 6,027,697.85 532,810.33 0.00 498.17 1,900.00 47.04 261.77 1,723.21 1,664.61 -187.81 -626.87 6,027,687.05 532,737.96 0.00 571.35 2,000.00 47.04 261.77 1,791.36 1,732.76 -198.28 -699.30 6,027,676.26 532,665.59 0.00 644.53 10 314" x 13 112" 2,044.37 47.04 261.77 1,821.60 1,763.00 -202.92 -731.43 6,027,671.47 532,633.48 0.00 677.01 BPRF 2,079.59 47.04 261.77 1,845.60 1,787.00 -206.61 -756.94 6,027,667.67 532,607.99 0.00 702.78 SVII 2,100.00 47.04 261.77 1,859.51 1,800.91 -208.75 -771.72 6,027,665.46 532,593.22 0.00 717.71 2,200.00 47.04 261.77 1,927.66 1,869.06 -219.22 -844.15 6,027,654.67 532,520.84 0.00 790.90 2,300.00 47.04 261.77 1,995.82 1,937.22 -229.69 -916.58 6,027,643.87 532,448.47 0.00 864.08 2,400.00 47.04 261.77 2,063.97 2,005.37 -240.17 -989.01 6,027,633.07 532,376.10 0.00 937.26 2,500.00 47.04 261.77 2,132.12 2,073.52 -250.64 -1,061.43 6,027,622.28 532,303.73 0.00 1,010.44 2,600.00 47.04 261.77 2,200.27 2,141.67 -261.11 -1,133.86 6,027,611.48 532,231.36 0.00 1,083.62 2,700.00 47.04 261.77 2,268.42 2,209.82 -271.58 -1,206.29 6,027,600.69 532,158.98 0:00 1,156.80 2,800.00 47.04 261.77 2,336.58 2,277.98 -282.05 -1,278.71 6,027,589.89 532,086.61 0.00 1,229.98 2,900.00 47.04 261.77 2,404.73 2,346.13 -292.53 -1,351.14 6,027,579.10 532,014.24 0.00 1,303.16 3,000.00 47.04 261.77 2,472.88 2,414.28 -303.00 -1,423.57 6,027,568.30 531,941.87 0.00 1,376.34 3,100.00 47.04 261.77 2,541.03 2,482.43 -313.47 -1,495.99 6,027,557.50 531,869.49 0.00 1,449.52 3,200.00 47.04 261.77 2,609.18 2,550.58 -323.94 -1,568.42 6,027,546.71 531,797.12 0.00 1,522.70 3,300.00 47.04 261.77 2,677.33 2,618.73 -334.41 -1,640.85 6,027,535.91 531,724.75 0.00 1,595.88 821/2019 5:16:23PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Site M Pt Moose Pad Company: Hilcorp Alaska, LLC TVD Reference: MPU M-06 As -staked @ 58.60usft Project: Milne Point MD Reference: MPU M-06 As -staked @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: Proposal: MPU M-06WSW - Slot 1 Survey Calculation Method: Minimum Curvature Wellbore: MPU M-06 (WSW) Design: MPU M-06 wp03A Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1 (0) (usft) usft (usft) (usft) (usft) (usft) 2,675.00 3,382.56 47.04 261.77 2,733.60 2,675.00 -343.06 -1,700.64 6,027,527.00 531,665.00 0.00 1,656.29 MP_UG_COAL1 3,400.00 47.04 261.77 2,745.49 2,686.89 -344.88 -1,713.28 6,027,525.12 531,652.38 0.00 1,669.06 3,500.00 47.04 261.77 2,813.64 2,755.04 -355.36 -1,785.70 6,027,514.32 531,580.01 0.00 1,742.24 3,582.56 47.04 261.77 2,869.90 2,811.30 -364.00 -1,845.50 6,027,505.41 531,520.26 0.00 1,802.65 Total Depth: 3562.56' MD, 2869.9' TVD Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting -Shape (") (°) (usft) (usft) (usft) (usft) (usft) M-06WSW wp03 Hardee 0.00 0.00 2,733.60 -343.06 -1,700.64 6,027,527.00 531,665.00 - plan hits target center -Circle (radius 50.00) Casing Points _ Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 2,000.00 1,791.36 103/4" x 131/2" 10-3/4 13-1/2 3,582.56 2,869.90 95/8" x131/2" 9-5/8 13-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology 2,044.37 1,821.60 BPRF 2,079.59 1,845.60 SV1 3,382.56 2,733.60 MP_UG_COAL1 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 519.70 519.70 -111.77 -60.57 Start Dir 3°/100' : 519.7' MD, 519.7'TVD 719.70 719.33 -112.36 -71.01 Start Dir 401100': 719.7' MD, 719.33'TVD 1,746.27 1,618.44 -171.71 -515.53 End Dir : 1746.27' MD, 1618.44' TVD 3,582.56 2,869.90 -364.00 -1,845.50 Total Depth : 3582.56' MD, 2869.9' TVD W112019 5:16:23PM Page 4 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad Proposal: MPU M-06WSW - Slot 1 MPU M-06 (WSW) MPU M-06 wp03A Sperry Drilling Services Clearance Summary Anticollision Report 21 August, 2019 Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) Reference Design: MPt Moose Pad -Proposal: MPU M-06WSW-Slot t -MPU M-06(WS"-MPU M-06 wp03A Well Coordinates: 6,027,765.62 N, 533,303.86 E (10" 29'12.81' N, 149° 43-40.07" W) Datum Height: MPU M-06 As -staked @ 58.60usft Scan Range: 0.00 to 3,582.56 usU. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft Geodetic Sese Factor Applied Version: 5000.15 Build: 91 Scan Type: Scan Type: 2500 =r_"gr=Pr_tiiwill Sperry Drilling Services HALLIBURTON Anticollision Report for Proposal: MPU M-06WSW - Slot 1 - MPU M-06 wp03A Hilcorp Alaska, LLC Milne Point Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) 130.05 Reference Design: MPt Moose Pad -Proposal: MPU M-06WSW-Slot t -MPU M-06(WSW)-MPU M-06 wp03A 123.35 Scan Range: 0.00 to 3,582.56 usff. Measured Depth. 19.412 Scan Radius Is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usfl Pass - Measured Minimum @Measured Ellipse @Measumd Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design lush) (usft) (us0) (usB) usR M Pt Moose Pad MPU M-03 - MPU M-03 - MPU M-03 MPU M-03 - MPU M-03 - MPU M-03 MPU M-03 - MPU M-03 - MPU M-03 MPU M-04 - MPU M-04 - MPU M-04 MPU M-04 - MPU M-04 - MPU M-04 MPU M-04 - MPU M-04- MPU M4M Plan: Kup S1 Deep KOP - Slot 17- Wellbore #1 -Kup Plan: Kup Si Deep KOP- Slot 17 - Wellbore #1 - Kup Plan: Kup S1 Deep KOP - Slot 17 - Wellbore #1 - Kup Plan: Kup S2 - Slot 11 - 62deg Sall - Kup S2 Early KOI Plan: Kup S2 - Slot 11 - 62deg Sail - Kup S2 Early KOI Plan: Kup S2 - Slot 11 -62deg Sail - Kup S2 Early KOI Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku Plan: Kup S3 - Slot 13 - 60deg Sail Doesnt Reach - Ku Plan: MPU M-0MSW - MPU M-07 (WSW) - M-07003 Plan: MPU M-07WSW -MPU M-07 (WSW) -M -OMS Plan: MPU M-OMSW - MPU M-07 (WSW) - M-07WS Plan: MPU M -1 9i- MPU M-1 9i - Jab Stuart - MPU M-1 Plan: MPU M -19i -MPU M -19i -Job Stuart - MPU M-1 Plan: MPU M -19i - MPU M -19i -Jeb Stuart - MPU M-1 Plan: MPU M-24- Slot 16 - M-24 - M-24 wp03 - Lower Plan: MPU M-24. Slot 16 - M-24 - M-24 wp03 - Lower Plan: MPU M-24 - Slot 16 - M-24 - M-24 wP03 - Lower Plan: MPU M-24 P2- Slot 14 - M-24 Phase 2 - M -24P: Plan: MPU M-24 P2 - Slat 14 - M-24 Phase 2 - M -24P: Plan: MPU M-24 P2 - Slot 14 - M-24 Phase 2 - M -24P; Plan: MPU M -25i - Slot 18 - M-251- M -25i wp03 866.96 130.05 866.96 123.35 89410 19.412 Centre Distance Pass - 875.00 130.09 875.00 123.33 902.66 19.234 Ellipse Separation Pass - 975.00 137.75 975.00 130.14 996.34 18.120 Clearance Factor Pass - 610.15 142.02 610.15 137.34 616.42 30.340 Centre Distance Pass - 625.00 142.08 625.00 137.29 631.10 29.679 Ellipse Separation Pass - 900.00 165.93 900.00 159.02 908.64 24.019 Clearance Factor Pass - 500.00 240.16 500.00 235.86 500.10 55.761 Centre Distance Pass - 525.00 240.17 525.00 235.69 525.10 53.540 Ellipse Separation Pass - 3,525.00 1,563.67 3,525.00 1,518.69 3,339.75 34164 Clearance F.rWr Pass - 275.00 150.16 275.00 147.46 275.10 55.739 Centre Distance Pass - 475.00 150.50 475.00 146.41 474.40 36.811 Ellipse Separation Pass - 750.00 174.53 750.00 168.44 738.56 28.651 Clearance Factor Pass - 275.00 180.16 275.00 177.49 275.10 67.445 Centre Distance Pass - 450.00 181.11 450.00 176.84 447.97 42.423 Ellipse Separation Pass - 825.00 227.89 825.00 217.78 800.00 22.540 Clearance Factor Pass - 302.03 60.15 302.03 56.83 302.13 18.117 Centre Distance Pass - 350.00 60.23 350.00 56.57 349.78 16.466 Ellipse Separation Pass - 550.00 66.44 550.00 61.40 545.66 13.175 Clearance Factor Pass - 450.00 209.98 450.00 206.05 446.10 53.373 Centre Distance Pass - 500.00 210.11 500.00 205.83 494.96 49.087 Ellipse Separation Pass - 850.00 252.42 850.00 245.74 825.81 37.796 Clearance Factor Pass - 375.00 243.92 375.00 240.51 375.10 71.639 Centre Distance Pass - 525.00 244.01 525.00 239.44 524.73 53.407 Ellipse Separation Pass - 2,725.00 1,404.41 2,725.00 1,368.43 3,151.72 39.035 Clearance Factor Pass - 325.00 218.93 325.00 215.45 325.10 62.827 Centre Distance Pass - 475.00 219.41 475.00 214.86 473.57 48.188 Ellipse Separation Pass - 3.582.56 550.20 3,582.56 501.27 4,274.97 11.243 Clearance Factor Pass - 500.00 270.47 500.00 266.16 500.10 62.797 Centre Distance Pass - 21 August, 2019 - 17,20 Page 2 of 6 COMPASS HALLIBURTON Hilcorp Alaska, LLC Milne Point Anticollision Report for Proposal: MPU M-06WSW - Slot 1 - MPU M-06 wp03A 172.47 Closest Approach 30 Proximity Scan on Current Survey Data (North Reference) 168.15 501.08 39.985 Centre Distance Reference Design: M Pt Moose Pad- Proposal: MPU M-06WSW -Slot 1 -MPU Md6 (WSW) - MPU M416 wp03A Plan: MPU M -26 -Slot 10 -M -26-M-26 wp04-lower1 525.00 172.50 Scan Range: 0.00 to 3,582.56 usft. Measured Depth. 168.00 525.40 38.407 Ellipse Separation Pass - Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft 3,582.56 1,023.66 3,582.56 958.61 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Plan :MPU M-26 P2 -Slot 09-M-26 Phase 2 -M -26P: Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 825.00 90.92 Plan: MPU M -25i -Slot 18 -M -25i -M -25i W03 1,575.00 27291 1,575.00 257.42 1,745.16 17.616 Ellipse Separation Pass - Plan :MPU M -25i -Slot 18 -M -251-M-251 wp03 3,582.56 360.83 3,582.56 311.45 3,913.20 7.308 Clearance Factor Pass - Plan: MPUM-251 P2 -Slot 12 -M -25i Phase 2 -M -25i 275.00 194.99 275.00 191.86 275.10 62.372 Centre Distance Pass - Plan :MPUM-25i P2 -Slot 12 -M -25i Phase 2 -M -25i 350.00 195.20 350.00 191.54 348.92 53.348 Ellipse Separation Pass - Plan: MPU M-251 P2 -Slot 12 -M -25i Phase 2 -M -25i 3,582.56 1,058.54 3,582.56 986.38 3,772.72 14.670 Clearance Factor Pass - Plan : MPU M -26 -Slot 10 -M -26-M-26 wp04-lower( 500.48 172.47 500.48 168.15 501.08 39.985 Centre Distance Pass - Plan: MPU M -26 -Slot 10 -M -26-M-26 wp04-lower1 525.00 172.50 525.00 168.00 525.40 38.407 Ellipse Separation Pass - Plan! MPUM-26-Slot 10 -M -26-M-26 wp04-1ower1 3,582.56 1,023.66 3,582.56 958.61 3,416.12 15.737 Clearance Factor Pasa- Plan :MPU M-26 P2 -Slot 09-M-26 Phase 2 -M -26P: 820.06 90.91 820.06 83.70 842.43 12.609 Centre Distance Pass - Plan: MPU M-26 P2 - Slot 09- M-26 Phase 2 - M -26P: 825.00 90.92 a25.00 83.86 847.52 12.532 Ellipse Separation Pass - Plan: MPH M-26 P2 -Slot 08-M-26 Phase 2 -M -26P: 1,025.00 105.70 1,025.00 96.24 1,048.37 11.175 C1ea.ce Factor Pass- Proposal: MPU M-05DSW-Slot 3 -MPU M-05(Beaur 525.00 25.38 525.00 20.50 525.80 SAW Ellipse Separation Pass- Proposal:MPUM-05DSW-Slot 3 -MPU M-05(Beaur 550.00 25.75 550.00 20.68 550.57 5.081 Clearance Factor Pass - Proposal: MPUM-08DSW-MOLaws-M-08DSW-Mc 276.60 90.15 276.60 87.31 272.70 31.794 Centre Distance Pass- Pmposal:MPU M-08DSW-MCLaws-M-08DSW-Mc 300.00 90.18 300.00 87.18 295.61 29.911 Ellipse Separation Pass - Proposal: MPU M-08DSW-Mcl-aws-M-08DSW-Mc 600.00 110.22 600.00 104.89 583.26 20.693 Clearance Factor Pass- Proposal: MPU M-09DSW-AP Hill -M-09DSW-APH 500.00 127.99 500.00 123.70 496.10 29.817 Centre Distance Pass - Proposal: MPU M-09DSW-AP Hill -M-09DSW-APH 675.00 128.61 675.00 123.08 674.44 23.268 Ellipse Separation Pass - Proposal: MPU M-09DSW-AP Hill -M-09DSW-APH 850.00 140.13 850.00 133.34 843.89 20.634 Clearance Factor Pass - From To SurveylPhm (usft) (usft) 33.70 2,215.00 MPU M-06 wp03A 2,215.00 3,582.53 MPU M06 p03A Survey Tool 2 MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 21 August, 2019 - 1120 Page 3 of 6 COMPASS HALLIBURTON Anticollision Report for Proposal: MPU M-06WSW - Slot 1 - MPU M-06 wp03A Ellipse error terms are correlated across survey tool fie -on points. Calculated ellipses incorporate sumacs, 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. Hilcorp Alaska, LLC Milne Point 21 August, 2019 - 1120 Page 4 o16 COMPASS FIALLIOUR N Project: Milne Point Site: MPt Moose Pad REFERENCE INFOR.TIGN S.]p.S➢mpa0 MP11MMWSW -Sbu NA ISII,NM NIOWII ArwM2aze0 eoawwle lNhl Relevy: w.uPwps.e emu uaw-sw tT.. wm �olrvnwglq uma.-a.uw®m:m®n .. o.a...° Well: Proposal: MPU M-06WSW-Slot :MPu Nwmme I1111c Wellbore: MPU M-06 (WSW) alabEon NNMt'. M'nmu�CurvNe o.aa o0n 1111o 5pn1sfi6x vn9�w m°xv nep6N 14ru•a6ma wl 1= Plan: MPUM4)6wp03A SURVEY PROGRAM No GLOBAL FILTER: Uzlnp user definetl selection d fittenrq 3J. TO To 358256 Dm, WIB ZBTW,0o:0o V IMaN6;Yes Ladder 8 S.F. Plots oepN Fmm oeyfi To Surv¢yNlen Tel 2MWD°IFR2°MS�Sap CASING DETAILS 'IND TV2$MDSi,,Name 2218.00 35U,53 MPU M-06 wp13A(MPU M-061 1191.36 2132.366 '_50900 10--1/4/4 103/4' z Il m, 2869.90 2622.30 3582,569.52 95/8" z IJ 2Q" 150.00— 50 00 M M Ww02-AP HII y ot2om —.• I t I. W26P2 Oa 9D 00 m V 0N SW .02 Ty ro 0000 . 1 ..-.I _..... y N U %Iv 830011 1R. I _ — I I I �� I I I 0.50 0 200 400 13110 800 1000 1200 1400 1600 18D0 200D 2200 2400 2500 2800 3000 3200 3400 3600 3800 Measured Depth (400 usitfin) -- 5.00 _ 4.00 o j I LL 3.00 `m 2.00 m Collision Risk Procedures Req. I �. Collision Avoidance Rq. t.0a No -Go Zone - Stop Drilling NOERRORS ! 0.00— a 250 500 750 1000 1250 1500 1350 2000 22M 2500 2350 3000 3250 3500 3350 Measured Depth (400 usftfin) Transform Points M^y/� X Source coordinate system M ��`-' I I — w Target coordinate system State Plane 1927 - Alaska Zone 4�t t/a�� r �e� l Albers Equal Area (-150) Datum: Datum: NAD 1927- North America Datum of 192 (Mean) NAD 1927 - North America Datum of 1927 (Mean) FF type- values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to opy and Ctd+V to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. < Back Finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: m you M—QK% PTD: 2N 19 -113 Development _/Service _ Exploratory _ Stratigraphic Test _ Non -Conventional i� CPvihee. G09_-e,k'W0.+v�(_ FIELD: POOL: i 4Y W 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 (ComRpy Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements 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. WELL PERMIT CHECKLIST Field & Pool MILNE POINT, TERTI UNDEF WTRSP - 525130 PTD#: 2191130 Company Hilcarp Alaska LLC Initial Class/Type SER / Well Name: MILNE PT UNIT M•06 _Program SER Well bore seg ❑ PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached _.......... ............-.....--. NA ... ---. ---. .._._.------. - -. -- - --- :2 Lease number appropriate- - - ... _ _ . - - - - - - - - - ------ - - - - - - ----- Yes _ _ ... _ . _ - - - ........... 3 Unique well name and number - - - - - - - - - - - - ---- - - - - - - - - - - Yes 4 Well located in. a. defined pool _ _ _ _ .. _ _ _ _ No.. _ Tertiary Undefined WTRSP- 5 Well located proper distance from drilling unit boundary.. _ _ _ _ .... - - - - - - Yes 6 Well located proper distance from other wells . . . ...... . . . . .. . _ Yes 7 Sufficient acreage available in drilling unit.... . . . . . . . . . . ...... . . . . . ... Yes 8 If deviated, is wellbore plat. included_ ........ _ - - - .. - - - - - - _ . --- Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ----- - - - - - - - - - - - - - 9 Operator only affected party.... _ . _ .. _ _ _ ---__. Yes ..... --- ----------------------- 10 Operator has appropriate bond In force _ _ _ _ _ _ _ _ . - - - - - - - - - Yes .....- 11 Permit can be issued without conservation order _ _ _ _ _ _ .... _ ... _ _ Yes- Appr Date 12 Permit can be issued without administrative approval - - _ _ _ _ _ _ _ _ .. - Yes 13 Can permit be approved before 15-daywait _ _ _ _ _ _ _ - - - - - .. Yes DLB 8/22/2019 14 Well located within area and strata authorized by Iniection Order # (put. 10# in.cornments) (For- NA_ .. _ _ _ ... _ _ 15 All wells.within 1/4 mile area of review identified (For service well only)... _ _ _ _ _ NA_____ 16 Pre-produced injector: duration-of pre-production less then 3 months (For service well only) - - NA. . ... 17 Nonconven. 9es.conforms to AS31.05,030(1.1.A),(j,2.A-D) ..... _ _ ... _ _ . NA. ........... --- - - - - — - 18 Conductor string-pfovided _ _ _ _ _ _ ...... .. _ _ _ ....... Yes - - - - - - - - - - - - - - - Engineering 19 Surface casing. protects all known USDWs _ _ _ _ _ _ _ _ _ _ _ ... - - NA. _ _ .... permafrost areas.. 20 CMT. vol adequate to circulate on conductor $ surf _csg __ _ _ _ _ _ _ _ _ _____ Yes _ _ _ _ _ _ _ Surface casing will be cemented to surface . 21 CMT. vol adequate to tie-in long string to surf csg- _ _ _ _ _ _ _ _ _ ------- - - - - - - - - Yes - - - _ _ _ _ 10.75.x 9.625 casing will be fully cemented. 22 CMT will cover all known productive horizons_ ....... . . . . . . . .... . . . .. . . . Yes ...... 23 Casing designs adequate for C. T, 13R. permafrost _ . . ........ . . . Yes 24 Adequate tankage or reserve pit _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _______ 25 if a_re-drill, has.a 10-403 for abandonment been approved _ . . . . . . ........ . . NA _ ... Grassroots service well... water source_ _ _ _ _ _ ......... 26 Adequate wellbore separation proposed.. _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ __ _ Yes _ _ _ _ _ - - - - - - 27 If diverter required, does it meet regulations_ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ ... - - - - - - - - - - - - - - ....... Appr Date 28 Drilling fluid. program schematic.& equip list adequate_ _ _ _ _ _ _ _ _ _ ____ _ _ _ _ _ _ _ Yes _ _ _ Max formation press= 1262-psi- 6.5 ppg EMW. ( Mud weight 8.5-.9.5 ppg) GLS 8126/2019 29 BOPEs, do they meet regulation _ _ _ _ _ - - - - - - - - ------ - - - - - - -Yes _ _ _ _ _ _ _ Doyon 14 has 13 5/8" BOPE 5000 psi WP . 30 ROPE press rating appropriate; test to _(put psig in-comments)..... . . ... . . . . . . . Yes .. _ . _ MASP=955 psi- will test BOPE to 3000. psi 31 Choke. manifold complies w/API. RP-53 (May 84). . . ..... . . . . . . ...... . . . . Yes _ _ ..... 32 Work will occur without operation shutdown- - - - - _ _______ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ ..... Sundry required to run-gravel.pack completion, 33 Is presence of H2S gas probable - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - Nc-- 34 Mechanical.condifion of wells within AOR verified (For service well only) _ _ _ _ _ _ _ _ _____ _ NA _ _ _ - - - - - - _ . _ _ - - . _ _ _ _ . _ - - - - _ _ _ _ 35 Permit can be issued w/o hydrogen sulfide measures . . . . . . .... . . . . . ...... .Yes _ _ _ _ _ _ _ M-_05 is, at shallow Prince Greek water source well, Geology 36 Data presented on potential overpressure zones _ .. Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Appr Date 37 Seismic analysis of sballow gas zones_ _ ...... _ _ _ _ _ .. - - - _ _ _ .. NA.... . . . . . . . . . . ...... . .. . . . . .......... DLB 8/2212019 38 ________ ___________________ .. Seabed condition survey (if offshore) NA - - - - - - - . 39 Contact name/phone for weeklyprogress reports, [exploratory only] _ _ _ ... - - _ _ _ _ .. NA.... .... _ _ Geologic Engineering Date Public Date sundry required for Gravel Pack completion phase. GIs Date: Commissioner: Commissioner: y Commissioner
