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Home My WebLink About215-160Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 12/15/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221215 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 14A 50133205390100 213196 9/22/2022 YELLOW JACKET PERF CLU 10RD 50133205530100 222113 10/24/2022 YELLOW JACKET PERF-GPT CLU 05RD 50133204740100 215160 7/15/2022 YELLOW JACKET PLUG-PERF CLU 10 50133205530000 205106 7/16/2022 YELLOW JACKET PERF KALOTSA 4 50133206650000 217063 8/24/2022 YELLOW JACKET PERF MPU K-09 50029232470000 205014 12/11/2022 READ CaliperSurvey Please include current contact information if different from above. T37376 T37377 T37378 T37379 T37380 T37381 By Meredith Guhl at 10:10 am, Dec 16, 2022 CLU 05RD 50133204740100 215160 7/15/2022 YELLOW JACKET PLUG-PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.12.16 10:11:16 -09'00' Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/22/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221122-1 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# SRU 213-15 50133206520000 215100 6/24/2022 Yellowjacket PERF KBU 33-06X 50133205290000 203183 6/26/2022 Yellowjacket PERF BCU 7A 50133202840100 214060 6/28/2022 Yellowjacket GPT-PERF END 3-17F 50029219460600 203216 7/2/2022 Yellowjacket PERF-RETAINER KBU 32-08 50133206240000 214014 7/12/2022 Yellowjacket PERF BCU 7A 50133202840100 214060 7/15/2022 Yellowjacket GPT-PERF SRU 213-15 50133206520000 215100 7/19/2022 Yellowjacket GPT-PLUG MPU I-17 50029232120000 204098 7/19/2022 Yellowjacket TUBING CUT CLU 05RD 50133204740100 215160 7/21/2022 Yellowjacket PLUG CLU 10 50133205530000 205106 7/21/2022 Yellowjacket RCT-JET CUT SRU 213-15 50133206520000 215100 7/22/2022 Yellowjacket PERF Please include current contact information if different from above. By Meredith Guhl at 8:52 am, Nov 23, 2022 T37295 T37295 T37295 T37296 T37297 T37297 T37298 T37299 T37300 T37301 T37302 CLU 05RD 50133204740100 215160 7/21/2022 Yellowjacket PLUG Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.11.23 09:08:15 -09'00' 5HJJ-DPHV%2*& )URP%URRNV3KRHEH/2*& 6HQW:HGQHVGD\6HSWHPEHU$0 7R-D\0XUSK\& &F5HJJ-DPHV%2*& 6XEMHFW5(+LOFRUS $WWDFKPHQWV+LOFRUS5HYLVHG[OV[ :ĂǇ͕ ƚƚĂĐŚĞĚŝƐĂƌĞǀŝƐĞĚƌĞƉŽƌƚĂĚĚŝŶŐƚŚĞWdηϮϭϱϭϲϬϬĨŽƌ>hͲϬϱZĂŶĚĐŚĂŶŐŝŶŐƚŚĞD^WƚŽƌĞĨůĞĐƚϮϯϳϴďĂƐĞĚŽŶ ƐƵŶĚƌǇηϯϮϮͲϰϯϯ͘/ŵŽǀĞĚƚŚĞϵϮϴƉƐŝŽƚƚůĞWƌĞĐŚĂƌŐĞƚŽƚŚĞƌĞŵĂƌŬƐ;ƐŝŶĐĞƚŚŝƐŝƐĂWͬ&ĨŝĞůĚͿ͘WůĞĂƐĞƌĞǀŝĞǁĂŶĚ ƵƉĚĂƚĞǇŽƵƌĐŽƉǇ͘ dŚĂŶŬǇŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗:ĂǇDƵƌƉŚǇͲ;Ϳф:ĂǇ͘DƵƌƉŚǇΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗&ƌŝĚĂǇ͕^ĞƉƚĞŵďĞƌϵ͕ϮϬϮϮϭϮ͗ϮϯWD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗,ŝůĐŽƌƉϭϲϵϵͲϴͲϮϬϮϮ dŚĂŶŬzŽƵĂŶĚĞƐƚZĞŐĂƌĚƐ͕ :ĂǇDƵƌƉŚǇͬ^D +LOFRUS$ODVND//& ,<ZŝŐϭϲϵ KĨĨŝĐĞ͗ϵϬϳͲϮϴϯͲϭϯϲϵ Ğůů͗ϵϬϳͲϳϭϱͲϵϮϭϭ :ĂǇ͘DƵƌƉŚǇΛ,ŝůĐŽƌƉ͘ĐŽŵ &$87,217KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH &DQQHU\/RRS8QLW5' 37' ƌĞǀŝƐĞĚƌĞƉŽƌƚĂ 7KHLQIRUPDWLRQFRQWDLQHGLQWKLVHPDLOPHVVDJHLVFRQILGHQWLDODQGPD\EHOHJDOO\SULYLOHJHGDQGLVLQWHQGHGRQO\IRUWKHXVHRIWKHLQGLYLGXDORUHQWLW\QDPHG DERYH,I\RXDUHQRWDQLQWHQGHGUHFLSLHQWRULI\RXKDYHUHFHLYHGWKLVPHVVDJHLQHUURU\RXDUHKHUHE\QRWLILHGWKDWDQ\GLVVHPLQDWLRQGLVWULEXWLRQRUFRS\RIWKLV HPDLOLVVWULFWO\SURKLELWHG,I\RXKDYHUHFHLYHGWKLVHPDLOLQHUURUSOHDVHLPPHGLDWHO\QRWLI\XVE\UHWXUQHPDLORUWHOHSKRQHLIWKHVHQGHU VSKRQHQXPEHULVOLVWHG DERYHWKHQSURPSWO\DQGSHUPDQHQWO\GHOHWHWKLVPHVVDJH :KLOHDOOUHDVRQDEOHFDUHKDVEHHQWDNHQWRDYRLGWKHWUDQVPLVVLRQRIYLUXVHVLWLVWKHUHVSRQVLELOLW\RIWKHUHFLSLHQWWRHQVXUHWKDWWKHRQZDUGWUDQVPLVVLRQ RSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQG WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH 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.:169 DATE: 9/8/22 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2151600 Sundry #322-433 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/ 4000 Annular:250/ 4000 Valves:250/ 4000 MASP:2378 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 1P Standing Order Posted P Misc.NA Ball Type 1P Test Fluid Water Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank PP Annular Preventer 1 11"FP Pit Level Indicators PP #1 Rams 1 2-7/8" x 5" VBR P Flow Indicator PP #2 Rams 1 Blind P Meth Gas Detector PP #3 Rams 1 4-1/2" Fixed P H2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 3-1/8"P Time/Pressure Test Result HCR Valves 2 2-1/16", 3-1/8"P System Pressure (psi)3000 P Kill Line Valves 2 2-1/16"P Pressure After Closure (psi)1650 P Check Valve 0NA200 psi Attained (sec)22 P BOP Misc 0NAFull Pressure Attained (sec)83 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4 @ 2425 P No. Valves 15 P ACC Misc 0NA Manual Chokes 1P Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 24 P #1 Rams 5 P Coiled Tubing Only:#2 Rams 5 P Inside Reel valves 0NA #3 Rams 5 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:7.5 HCR Choke 2 P Repair or replacement of equipment will be made within 0 days. HCR Kill 2 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 9/7/22 05:23 Waived By Test Start Date/Time:9/8/2022 7:00 (date) (time)Witness Test Finish Date/Time:9/8/2022 14:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Test was conducted with a 4-1/2" Test Joint. One Fail Pass on the Annular Preventer high pressure test due to air in the system. Bottle Precharge - 928 psi. Davis/ Deshotel Hilcorp Alaska, LLC Murphy/ Lawson CLU-05RD Test Pressure (psi): midavis@hilcorp.com Jay.Murphy@hilcorp.com Form 10-424 (Revised 08/2022) 2022-0908_BOP_Hilcorp169_CLU_5RD 9 9 9 9 9 9 9 9 9 9 9 9 9 9 MEU -5HJJ One Fail Pass on the Annular Preventer MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 7 Township: 5N Range: 11W Meridian: Seward Drilling Rig: Hilcorp 401 Rig Elevation: 11.58 ft Total Depth: 12940 ft MD Lease No.: Fee Hilcorp Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 142 Feet Csg Cut@ Feet Surface: 13 3/8" O.D. Shoe@ 2970 Feet Csg Cut@ Feet Intermediate: 9 5/8" O.D. Shoe@ 9178 Feet Csg Cut@ Feet Liner1 7 5/8" O.D. Shoe@ 10448 Feet Csg Cut@ Feet Liner2: 4 1/2" O.D. Shoe@ 12915 Feet Csg Cut@ Feet Tubing: 2 7/8" O.D. Tail@ 6883 Feet Tbg Cut@ 6847 Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Bridge plug 6847 ft 6700 ft 8.6 ppg Drillpipe tag Initial 15 min 30 min 45 min Result Casing 2275 2266 2260 Remarks: Attachments: Inspector Austin McLeod accompanied on this plug verification. Hilcorp milled out cement retainer and cement from 6530 ft MD through perfs to 6700 ft MD using 6.75-inch tricone bit and 4.75-inch jar BHA. They picked up and set down 3 times with 15k lbs for tag at 6700 ft MD. Pressure tested to 2275 psi with rig pump and held for 30 minutes losing only 15 psi total for a passing test. July 29, 2022 Kam St.John Well Bore Plug & Abandonment CLU 5RD Hilcorp Alaska LLC PTD 2151600; Sundry 322-351 none Test Data: P Casing Removal: Wade Hudgens Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 11-28-18 2022-0729_Plug_Verification_CLU_5RD_ksj 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9set down 3 times with 15k lbs gp for tag at 6700 ft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ŝŶŐƐĂĨƌŽŵϲϬϳϭ͚DʹϲϮϵϱ͛D;Ͳϰϴϴϱ͛ͲͲͲϱϬϵϬ͛dsƐƐͿ tĞůů͗>hͲϬϱZ WƌĞͲƐŝĚĞƚƌĂĐŬĞĐŽŵƉůĞƚĞ sZ^/KEηϮ;ϳͲϮϭͲϮϮͿ WƌĞͲZŝŐƉƌŽĐĞĚƵƌĞ ϭ͘D/dͲ/ŽĨƚŚĞϵͲϱͬϴ͟ǆϮͲϳͬϴ͟ĂŶŶƵůƵƐƚŽϯϱϬϬƉƐŝ;ƚŚŝƐǁŝůůĞǆĐĞĞĚƚŚĞƉůĂŶŶĞĚDW^WŽĨĨƵƚƵƌĞWdͿ Ϯ͘^ĞƚϮͲϳͬϴ͟ddWŽƌ/WŝŶƚƵďŝŶŐƚĂŝůďĞůŽǁƉĂĐĞƌĂƚцϲ͕ϴϲϬ͛D ϯ͘>ŽĂĚƚƵďŝŶŐǁŝƚŚƉƌŽĚƵĐĞĚǁĂƚĞƌ;Εϴ͘ϲƉƉŐͿ ϰ͘D/dͲdƚŽϭϱϬϬƉƐŝƚŽĐŽŶĨŝƌŵƉůƵŐŝƐŚŽůĚŝŶŐ;ŶŽĐŚĂƌƚŝŶŐƌĞƋƵŝƌĞŵĞŶƚͿ ŽŶƚŝŶŐĞŶĐǇŝĨŐĂƐŝƐƐƵƐƉĞĐƚĞĚďĞůŽǁƚŚĞƵƉƉĞƌƉĂĐŬĞƌ͗ WƵŶĐŚϮͲϳͬϴ͟ƚƵďŝŶŐũƵƐƚďĞůŽǁƚŚĞƵƉƉĞƌƉĂĐŬĞƌĂƚцϲϯϳϱ͛D ZtKĚĞĐŽŵƉůĞƚĞWƌŽĐĞĚƵƌĞ ϭ͘D/Zh,ŝůĐŽƌƉƌŝŐηϰϬϭ Ϯ͘&ŝůůǁĞůůǁŝƚŚƉƌŽĚƵĐĞĚǁĂƚĞƌ;Εϴ͘ϲƉƉŐͿĂŶĚĞŶƐƵƌĞǁĞůůŝƐĚĞĂĚ;dƵďŝŶŐǀŽůƵŵĞсϰϬďďůƐͿ ϯ͘^ĞƚWsŽƌdt ϰ͘EhKW͛ƐĂŶĚƚĞƐƚ Ă͘WdƚŽϮϱϬƉƐŝůŽǁͬϮϱϬϬƉƐŝŚŝŐŚͬϮϱϬϬƉƐŝĂŶŶƵůĂƌ ď͘dĞƐƚǁŝƚŚϮͲϳͬϴ͟ƚĞƐƚũŽŝŶƚ͕ĂŶĚϯͲϭͬϮ͟ƚĞƐƚũŽŝŶƚŝĨƚŽďĞƵƐĞĚĂƐĂǁŽƌŬƐƚƌŝŶŐ ϱ͘WƵůůWsͬdt ϲ͘DŽŶŝƚŽƌǁĞůůƚŽĞŶƐƵƌĞŝƚƐƐƚĂƚŝĐ ϳ͘WhŽŶϮͲϳͬϴ͟ƚƵďŝŶŐƚŽƌĞůĞĂƐĞĨƌŽŵƐŶĂƉůĂƚĐŚĂƚϲϴϰϳ͛D Ă͘ϱϴŬŽǀĞƌƐƚƌŝŶŐǁĞŝŐŚƚƌĞƋƵŝƌĞĚƚŽƵŶƐĞĂƚϵͲϱͬϴ͟ƉĂĐŬĞƌĂƚϲϯϲϴ͛D ď͘ϱŬĂĚĚŝƚŝŽŶĂůƚŽƌĞůĞĂƐĞƐŶĂƉůĂƚĐŚĂƚϲϴϰϳ͛D ϴ͘WKK,ǁŝƚŚϮͲϳͬϴ͟ƚƵďŝŶŐƌĂĐŬŝŶŐƐŽŵĞďĂĐŬƚŽďĞƵƐĞĚĂƐŬŝůůƐƚƌŝŶŐ͘ ϵ͘ŶƐƵƌĞĨƵůůƌĞĐŽǀĞƌǇĚŽǁŶƚŽƐŶĂƉůĂƚĐŚ ŽŶƚŝŶŐĞŶĐǇ͗/ĨƵƉƉĞƌƉĂĐŬĞƌǁŽŶ͛ƚƌĞůĞĂƐĞ͕ŵĂǇŶĞĞĚƚŽĐƵƚĂďŽǀĞĂŶĚĨŝƐŚŽƌŵŝůůǁŝƚŚϮͲϳͬϴ͟ǁŽƌŬƐƚƌŝŶŐ ŽŶƚŝŶŐĞŶĐǇ͗/ĨƐŶĂƉůĂƚĐŚǁŽŶ͛ƚƌĞůĞĂƐĞ͕ŵĂǇŶĞĞĚƚŽĐƵƚĂďŽǀĞůŽǁĞƌƉĂĐŬĞƌ tĞůů͗>hͲϬϱZ WƌĞͲƐŝĚĞƚƌĂĐŬĞĐŽŵƉůĞƚĞ sZ^/KEηϮ;ϳͲϮϭͲϮϮͿ ϭϬ͘WĞƌĨŽƌŵďĂƐĞůŝŶĞŝŶũĞĐƚŝǀŝƚǇƚĞƐƚŝŶƚŽhϳĂŶĚhϰŽƉĞŶƉĞƌĨƐƉĞƌK ϭϭ͘Zh>ǁŝƚŚϳͲϱͬϴ͟/W ϭϮ͘Z/,ĂŶĚƐĞƚϳͲϱͬϴ͟/WĂƚцϲ͕ϲϵϬ͛Dϲ͕ϳϮϱ͛D;ǆĂĐƚĚĞƉƚŚǁŝůůďĞŽƉƚŝŵŝǌĞĚĨŽƌ<KWĐŽůůĂƌ ĂǀŽŝĚĂŶĐĞͿ ϭϯ͘ƵŵƉďĂŝůϮϱ͛ĐĞŵĞŶƚŽŶƚŽ/WǁŝƚŚ> Ă͘WůĂŶŶĞĚdŽцϲ͕ϳϬϬ͛D ď͘ϰϵŐĂůůŽŶƐĐĞŵĞŶƚƌĞƋƵŝƌĞĚ ϭϰ͘ZĞƉĞĂƚŝŶũĞĐƚŝǀŝƚǇƚĞƐƚŶŽǁƚŚĂƚŽŶůǇhͲϰƉĞƌĨƐĂƌĞŽƉĞŶ͕ĂŶĚĐŽŶĨŝƌŵĚĞĐƌĞĂƐĞĚŝŶũĞĐƚŝǀŝƚǇ ϭϱ͘hƐŝŶŐϮͲϳͬϴ͟ŽƌϯͲϭͬϮ͟ǁŽƌŬƐƚƌŝŶŐ͕ƉĞƌĨŽƌŵƐƋƵĞĞǌĞŽĨhͲϰƉĞƌĨƐĨƌŽŵϲϱϳϴ͛ʹϲϱϵϰ͛D Ă͘hƐĞƉĂĐŬŽĨĨƚŽƐƚŝŶŐŝŶƚŽ^ZŽĨyWůŝŶĞƌƚŽƉƉĂĐŬĞƌĂƚϲϰϯϯ͛ŝĨĂĐĞŵĞŶƚƌĞƚĂŝŶĞƌŝƐŶŽƚƵƐĞĚ ď͘tĂŶƚƚŽŬĞĞƉĐĞŵĞŶƚŽƵƚŽĨϵͲϱͬϴ͟ĐĂƐŝŶŐƚŽĨĂĐŝůŝƚĂƚĞŵŝůůŽƵƚ Đ͘ƵůůŚĞĂĚĐĞŵĞŶƚŝŶƚŽƉĞƌĨƐ Ě͘WĞƌĨŽƌŵŚĞƐŝƚĂƚŝŽŶƐƋƵĞĞǌĞƉĞƌK ϭϲ͘hŶƐƚŝŶŐĨŽƌŵ^ZŽƌĐĞŵĞŶƚƌĞƚĂŝŶĞƌĂƚϲϰϯϯ͛ĂŶĚĐŝƌĐƵůĂƚĞŽƵƚĞǆĐĞƐƐĐĞŵĞŶƚƚŽƐƵƌĨĂĐĞ ϭϳ͘WKK,ĂŶĚtŽ ϭϴ͘DhŵŝůůŽŶǁŽƌŬƐƚƌŝŶŐ͕ĂŶĚŵŝůůŽƵƚƐƋƵĞĞǌĞĐĞŵĞŶƚŝŶƚŚĞϳͲϱͬϴ͟ůŝŶĞƌ Ă͘EŽƚĞϲ͘ϲϮϱ͟/>dWĂƚϲ͕ϰϯϯ͛D ď͘/ĨŶĞĞĚĞĚ͕ŵŝůůŽƵƚϲ͘ϲϮϱ͟ƌĞƐƚƌŝĐƚŝŽŶ Đ͘ǆĂĐƚĚĞƉƚŚƚŽŵŝůůƚŽƉĞƌĚƌŝůůŝŶŐĞŶŐŝŶĞĞƌ;ǁŝůůďĞďĂƐĞŽĨǁ ŚŝƉƐƚŽĐŬͿ Ě͘EĞĞĚƚŽůĞĂǀĞĂƚůĞĂƐƚϮϱ͛ĐĞŵĞŶƚŽŶƚŽƉŽĨ/W ϭϵ͘^ĞƚϭϱŬĚŽǁŶŽŶ/WǁŝƚŚϮϱ͛ĐĞŵĞŶƚǁŝƚŚŵŝůůŽƵƚǁŽƌŬƐƚƌŝŶŐƚŽĐŽŶĨŝƌŵĂďĂŶĚŽŶŵĞŶƚƉůƵŐ ϮϬ͘D/dϵͲϱͬϴ͟ǆϳͲϱͬϴ͟ĐĂƐŝŶŐ;ĂŶĚƐƋƵĞĞǌĞƉĞƌĨƐͿƚŽϮϬϬϬƉƐŝĨŽƌϯϬŵŝŶƵƚĞƐ;ĐŚĂƌƚĞĚͿ Ϯϭ͘^ĞƚWsŽƌdt ϮϮ͘EKWƐ͕EhƚƌĞĞ Ϯϯ͘ZDKƌŝŐϰϬϭ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƵƌƌĞŶƚƐĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘ƵƌƌĞŶƚǁĞůůŚĞĂĚƐĐŚĞŵĂƚŝĐ ϰ͘zĞůůŽǁũĂĐŬĞƚKW͛Ɛ;ϭϭ͟Ϳ;ϭϯͲϱͬϴ͟Ϳ ϱ͘K'ZtKŚĂŶŐĞ&Žƌŵ 3URYLGH KUV QRWLFH IRU $2*&& WR ZLWQHVV 0,7 DQG ZHLJKW WHVW EMP BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇZZϲͬϮͬϮϮ ^,Dd/&RRN,QOHW%DVLQ$ODVND 0LGGOH*URXQG6KRDO /DVW&RPSOHWHG 2LO:HOO!:DWHULQMHFWRU!*DVSURGXFHU IRU3ODWIRUP tĞůů͗>hϬϱZ W/͗ϱϬͲϭϯϯͲϮϬϰϳϰͲϬϭͲϬϬ Wd͗ϮϭϱͲϭϲϬ KWE,K>ͬDEdd/> ϭϯͲϯͬϴ͟&ƵůůǇĐĞŵĞŶƚĞĚǁŝƚŚϭϰϬďďůƐďĂĐŬƚŽƐƵƌĨĂĐĞ;>hͲϬϱŝŶϭϵϵϲͿ ϵͲϱͬϴ͟ϭϮͲϭͬϰ͟ŚŽůĞ͗WƵŵƉĞĚĨƌŽŵϵϭϳϴ͛D͘ϴϱϬƐǆƐůĞĂĚ;ϯϳϱďďůƐͿĂŶĚϭϬϲϵƐǆƐ;ϮϮϮďďůƐͿƚĂŝů;>hͲϬϱŝŶ ϭϵϵϲͿϭϭͬϭϵͬϵϲh^/dƐŚŽǁƐϵͲϱͬϴ͟ĐĞŵĞŶƚĞĚƵƉƚŽĂƚůĞĂƐƚϮϴϬϬ͛D;ƐƚŽƉƉĞĚůŽŐŐŝŶŐƚŚĞƌĞͿ ϳͲϱͬϴ͟ϴͲϭͬϮ͟ŚŽůĞ͗ĞŵĞŶƚĞĚǁŝƚŚϭϬϮ͘ϳďďůƐϭϱ͘ϯƉƉŐĐůĂƐƐ'͘ŚĂĚůŽƐƐĞƐĂŶĚŐŽƚŶŽĐĞŵĞŶƚďĂĐŬƚŽƐƵƌĨĂĐĞ͘ ϵͬϮϰͬϮϬ^DdƐŚŽǁƐŐŽŽĚĐĞŵĞŶƚƵƉƚŽĂƚůĞĂƐƚϲ͕ϱϮϱD;ďĞŚŝŶĚƚƵďŝŶŐĂďŽǀĞƚŚĂƚͿ hWWZWZ&KZd/KEd/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿ^W&ĂƚĞ^ŝǌĞ^ƚĂƚƵƐ hͲϰϲ͕ϱϳϴ͛ϲ͕ϱϵϰ͛ϱ͕ϰϬϯ͛ϱ͕ϰϭϵ͛ϭϲϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hͲϳhƉƉĞƌϲ͕ϳϯϱ͛ϲ͕ϳϲϮ͛ϱ͕ϱϱϮ͛ϱ͕ϱϳϳ͛ϮϳϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hͲϳ>ŽǁĞƌϲ͕ϳϵϱ͛ϲ͕ϴϮϬ͛ϱ͕ϲϬϳ͛ϱ͕ϲϯϬ͛ϮϱϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Dͺϰ ϳ͕ϯϯϱΖϳ͕ϯϱϯΖϲ͕ϬϳϯΖϲ͕ϬϵϭΖϭϴΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϯϯϱΖϳ͕ϯϱϯΖϲ͕ϬϳϯΖϲ͕ϬϵϭΖϭϴΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϯϳϮΖϳ͕ϯϴϳΖϲ͕ϭϬϮΖϲ͕ϭϭϳΖϭϱΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϯϳϮΖϳ͕ϯϴϳΖϲ͕ϭϬϮΖϲ͕ϭϭϳΖϭϱΖϬϴͬϮϭͬϮϭϮ͟KƉĞŶ Dͺϳ ϳ͕ϳϰϱΖϳ͕ϳϱϬΖϲ͕ϰϭϯΖϲ͕ϰϭϴΖϱΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϰϱΖϳ͕ϳϱϬΖϲ͕ϰϭϯΖϲ͕ϰϭϴΖϱΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϳϱϵΖϳ͕ϳϲϳΖϲ͕ϰϮϰΖϲ͕ϰϯϮΖϴΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϱϵΖϳ͕ϳϲϳΖϲ͕ϰϮϰΖϲ͕ϰϯϮΖϴΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϳϳϴΖϳ͕ϳϴϴΖϲ͕ϰϰϬΖϲ͕ϰϱϬΖϭϬΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϳϴΖϳ͕ϳϴϴΖϲ͕ϰϰϬΖϲ͕ϰϱϬΖϭϬΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϮϯΖϴ͕ϬϮϵΖϲ͕ϲϰϯΖϲ͕ϲϰϵΖϲΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϯϴΖϴ͕ϬϱϲΖϲ͕ϲϱϲΖϲ͕ϲϳϰΖϭϴΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϳϰΖϴ͕ϬϳϵΖϲ͕ϲϴϲΖϲ͕ϲϵϭΖϱΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭ&ϴ͕ϭϯϳΖϴ͕ϭϰϵΖϲ͕ϳϯϴΖϲ͕ϳϱϬΖϭϮΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ ϴ͕ϭϵϲΖϴ͕ϮϬϯΖϲ͕ϳϴϳΖϲ͕ϳϵϰΖϳΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ Wdсϴ͕ϯϮϴ͛Dͬϲ͕ϴϵϳ͛ds dсϭϮ͕ϵϰϬ͛Dͬϭϭ͕Ϯϱϯ͛ds $% ϮϬ͟ Z<сϭϴ͛ ϵͲϱͬϴ͟ ϭϯͲϯͬϴ͟ DE ϰͲϭͬϮ͟ ϳͲϱͬϴ͟ &LQJVD )URP¶ ¶0' 3 3 * . & / ^/E'd/> ^ŝǌĞdǇƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵ ϮϬΗŽŶĚƵĐƚŽƌϭϮϵͬEͬͬEͬEͬ^ƵƌĨϭϰϮΖ ϭϯͲϯͬϴΗ^ƵƌĨĂĐĞϲϭͬ<ͲϱϱͬdϭϮ͘ϱϭϱ͟^ƵƌĨϮ͕ϵϳϬΖ ϵͲϱͬϴΗ/ŶƚĞƌŵĞĚŝĂƚĞϱϯ͘ϱͬ>ͲϴϬͬdϴ͘ϱϯϱ͟^ƵƌĨϭ͕ϮϭϮ͛ ϰϳͬWͲϭϭϬͬdϴ͘ϲϴϭ͟ϭ͕ϮϭϮ͛ϲ͕ϱϮϳ͛ ϳͲϱͬϴ͟ >ŝŶĞƌ Ϯϵ͘ϳͬ>ͲϴϬͬ,zϱϭϭϲ͘ϴϳϱ͟ϲ͕ϰϯϯ͛ϲ͕ϵϭϬ͛ Ϯϵ͘ϳͬ>ͲϴϬͬ^>/:Ͳ//ϲ͘ϴϳϱ͟ϲ͕ϵϭϬ͛ϭϬ͕ϰϰϴ͛ ϰͲϭͬϮ͟>ŝŶĞƌϭϮ͘ϲͬ>ͲϴϬͬtͬϯ͘ϵϱϴ͟ϭϬ͕ϮϰϬ͛ϭϮ͕ϵϭϱ͛ dh/E'd/> ϮͲϳͬϴ͟ϲ͘ϰηͬ>ͲϴϬͬhϴZϮ͘ϰϰϭ͟^ƵƌĨΕϲ͕ϴϴϯ͛ hWWZ:t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϭϴ͛ϰ͘ϬϬϬ͟ϲ͘ϳϱϬ͟dƵďŝŶŐ,ĂŶŐĞƌ͕ϰͲϭͬϮ͟ ϮϮϵϵ͛Ϯ͘ϰϰϭ͟ϳ͘ϭϭϬ͟^ĂĨĞƚǇsĂůǀĞ ϯĂϲ͕ϯϲϴ͛ ϯ͘ϵϴϬ͟ͲϵͲϱͬϴ͟,ǇĚƌĂƵůŝĐZĞƚƌŝĞǀĂďůĞWĂĐŬĞƌ;ϱϴŬƐƚƌĂŝŐŚƚƉƵůů ƚŽƌĞůĞĂƐĞͿ ϯďϲ͕ϯϵϬ͛Ϯ͘ϯϭϯ͟ͲϮͲϳͬϴ͟y>ĂŶĚŝŶŐEŝƉƉůĞ ϰϲ͕ϰϯϯ͛ϲ͘ϲϮϱ͟ϴ͘ϰϲϬ͟ϳͲϱͬϴ͟yW>ŝŶĞƌdŽƉWĂĐŬĞƌ ϱϲ͕ϱϮϳ͛ϴ͘ϱ͟ϳͲϱͬϴ͟tŚŝƉƐƚŽĐŬͬ<ŝĐŬŽĨĨƉŽŝŶƚ;ŵŝůůĞĚǁŝŶĚŽǁͿ ϲϲ͕ϴϰϳ͛Ϯ͘ϵϵϬ͟ϱ͘ϭϵϬ͟^ŶĂƉ>ĂƚĐŚĂƐƐĞŵďůǇ;^ƚƌĂŝŐŚƚƉƵůůƚŽƌĞůĞĂƐĞͿ ϳϲ͕ϴϰϴ͛ϰ͘ϬϬϬ͟ϲ͘ϮϱϬ͟ϳͲϱͬϴ͟WĞƌŵĂŶĞŶƚWĂĐŬĞƌ ϴĂϲ͕ϴϳϭ͛Ϯ͘ϯϭϯ͟ͲϮͲϳͬϴ͟y>ĂŶĚŝŶŐEŝƉƉůĞ ϴďϲ͕ϴϴϯ͛Ϯ͘ϰϱϬ͟ͲϮͲϳͬϴ͟t>' ϵϴ͕ϯϱϱ͛Ͳϳ͘ϲϮϱ͟/WǁͬϮϳ͛ĐŵƚdKϴ͕ϯϮϴ͛ϭϬͬϭϮͬϮϬ &ŝƐŚ͗DŝůůĞĚϰͲϭͬϮ͟ǆϳͲϱͬϴ͟ƉĂĐŬĞƌĂŶĚ ƚƵďŝŶŐƚĂŝůĨƌŽŵϳͬϯϭͬϮϭZtK͘K>ΕϱϬ͛ tĞůů͗>hϬϱZ ^,Dd/W/͗ϱϬͲϭϯϯͲϮϬϰϳϰͲϬϭͲϬϬ Wd͗ϮϭϱͲϭϲϬ >KtZͬ/^K>d:t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϬϭϬ͕ϮϬϴ͛Ͳϳ͘ϲϮϱ͟/Wǁͬϯϱ͛ĐĞŵĞŶƚ;dKϭϬ͕ϭϳϯ͛ͿϲͬϮϯͬϮϬ ϭϭϭϬ͕ϮϯϬ͛Ͳϳ͘ϲϮϱ͟/WϲͬϭϳͬϮϬ ϭϮϭϬ͕ϮϰϬ͛ʹϭϬ͕ϮϳϮ͛ϰ͘ϴϮϬ͟ϲ͘ϱϲϬ͟ϰͲϭͬϮ͟yWE>ŝŶĞƌdŽƉWĂĐŬĞƌ ϭϯϭϬ͕ϮϳϮ͛ʹϭϬ͕Ϯϵϴ͛ϰ͘ϳϰϬ͟ϲ͘ϮϳϬ͟>ŝŶĞƌ^ĞĂůďŽƌĞǆƚĞŶƐŝŽŶ ϭϰϭϬ͕Ϯϳϵ͛Ͳϰ͘ϱϬϬ͟/WϲͬϭϱͬϮϬ ϭϱϭϬ͕ϯϰϵ͛Ͳϰ͘ϱϬϬ͟/W ϭϲϭϭ͕ϭϳϬ͛Ͳϯ͘ϱϬϬ͟/W;dKϭϭ͕ϭϳϬ͛Ϳ ϭϳϭϭ͕ϰϯϬ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϰϮϬ͛Ϳ ϭϴϭϭ͕ϱϬϱ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϰϵϱ͛Ϳ ϭϵϭϭ͕ϱϲϱ͛Ͳϯ͘ϱϬϬ͟/Wǁͬϭϱ͛ĐĞŵĞŶƚ;dKϭϭ͕ϱϱϬ͛Ϳ ϮϬϭϭ͕ϳϬϬ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϲϵϬ͛Ϳ Ϯϭϭϭ͕ϳϮϯ͛Ͳϯ͘ϱϬϬ͟/W >KtZWZ&KZd/KEd/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿ^W&ĂƚĞ^ŝǌĞ^ƚĂƚƵƐ >ͲϮϴ͕ϰϬϳ͛ϴ͕ϰϯϭ͛ϲ͕ϵϲϭ͛ϲ͕ϵϴϭ͛ϮϰϬϳͬϭϯͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hdͲϵϭϬ͕ϯϬϲ͛ϭϬ͕ϯϮϲ͛ϴ͕ϲϮϬ͛ϴ͕ϲϰϬ͛ϲϬϯͬϯϬͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϯϮϲ͛ϭϬ͕ϯϰϲ͛ϴ͕ϲϰϬ͛ϴ͕ϲϲϬ͛ϲϬϯͬϮϴͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϵϭͲϮ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϱ͛ϵ͕Ϭϴϭ͛ϵ͕Ϭϵϵ͛ϲϭϬͬϭϬͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϳ͛ϵ͕Ϭϴϭ͛ϵ͕ϭϬϭ͛ϲϬϲͬϬϯͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϳ͛ϵ͕Ϭϴϭ͛ϵ͕ϭϬϭ͛ϲϬϯͬϭϯͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ͲϮϭϭ͕Ϭϴϭ͛ϭϭ͕ϭϬϲ͛ϵ͕ϯϵϱ͛ϵ͕ϰϮϬ͛ϲϭϮͬϮϮͬϭϲϮͲϳͬϴ͟^ƋƵĞĞǌĞĚ Ͳϯϭϭ͕ϯϮϭ͛ϭϭ͕ϯϰϲ͛ϵ͕ϲϯϱ͛ϵ͕ϲϲϬ͛ϲϭϭͬϮϱͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϰϭϭ͕ϰϲϬ͛ϭϭ͕ϰϴϬ͛ϵ͕ϳϳϰ͛ϵ͕ϴϬϰ͛ϲϭϬͬϮϵͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϰϲϬ͛ϭϭ͕ϰϵϬ͛ϵ͕ϳϳϰ͛ϵ͕ϴϬϰ͛ϲϭϬͬϭϰͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϱϭϭ͕ϱϭϬ͛ϭϭ͕ϱϯϬ͛ϵ͕ϴϮϰ͛ϵ͕ϴϰϰ͛ϲϬϲͬϭϱͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϱϭϭ͕ϱϳϮ͛ϭϭ͕ϱϴϬ͛ϵ͕ϴϴϲ͛ϵ͕ϴϵϰ͛ϲϬϭͬϮϮͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϱϴϲϭϭ͕ϱϵϴϵ͕ϵϬϬϵ͕ϵϭϮϲϬϱͬϮϲͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϲϭϭ͕ϳϭϮ͛ϭϭ͕ϳϮϮ͛ϭϬ͕ϬϮϲ͛ϭϬ͕Ϭϯϲ͛ϲϭϮͬϬϳͬϭϱϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϳϮϲ͛ϭϭ͕ϳϯϴ͛ϭϬ͕Ϭϯϵ͛ϭϬ͕Ϭϱϭ͛ϲϬϭͬϬϴͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇDϬϲͲϭϬͲϮϮ WZKWK^&RRN,QOHW%DVLQ$ODVND 0LGGOH*URXQG6KRDO /DVW&RPSOHWHG 2LO:HOO!:DWHULQMHFWRU!*DVSURGXFHU IRU3ODWIRUP tĞůů͗>hϬϱZ W/͗ϱϬͲϭϯϯͲϮϬϰϳϰͲϬϭͲϬϬ Wd͗ϮϭϱͲϭϲϬ KWE,K>ͬDEdd/> ϭϯͲϯͬϴ͟&ƵůůǇĐĞŵĞŶƚĞĚǁŝƚŚϭϰϬďďůƐďĂĐŬƚŽƐƵƌĨĂĐĞ;>hͲϬϱŝŶϭϵϵϲͿ ϵͲϱͬϴ͟ϭϮͲϭͬϰ͟ŚŽůĞ͗WƵŵƉĞĚĨƌŽŵϵϭϳϴ͛D͘ϴϱϬƐǆƐůĞĂĚ;ϯϳϱďďůƐͿĂŶĚϭϬϲϵƐǆƐ;ϮϮϮďďůƐͿƚĂŝů;>hͲϬϱŝŶ ϭϵϵϲͿϭϭͬϭϵͬϵϲh^/dƐŚŽǁƐϵͲϱͬϴ͟ĐĞŵĞŶƚĞĚƵƉƚŽĂƚůĞĂƐƚϮϴϬϬ͛D;ƐƚŽƉƉĞĚůŽŐŐŝŶŐƚŚĞƌĞͿ ϳͲϱͬϴ͟ϴͲϭͬϮ͟ŚŽůĞ͗ĞŵĞŶƚĞĚǁŝƚŚϭϬϮ͘ϳďďůƐϭϱ͘ϯƉƉŐĐůĂƐƐ'͘ŚĂĚůŽƐƐĞƐĂŶĚŐŽƚŶŽĐĞŵĞŶƚďĂĐŬƚŽƐƵƌĨĂĐĞ͘ ϵͬϮϰͬϮϬ^DdƐŚŽǁƐŐŽŽĚĐĞŵĞŶƚƵƉƚŽĂƚůĞĂƐƚϲ͕ϱϮϱD;ďĞŚŝŶĚƚƵďŝŶŐĂďŽǀĞƚŚĂƚͿ ^ĂŶĚƐdŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿĨƚĂƚĞ ^ƚĂƚƵƐ hͲϰϲ͕ϱϳϴ͛ϲ͕ϱϵϰ͛ϱ͕ϰϬϯ͛ϱ͕ϰϭϵ͛ϭϲϭϬͬϭϮͬϮϬdŽďĞƐƋƵĞĞǌĞĚ hͲϳhƉƉĞƌϲ͕ϳϯϱ͛ϲ͕ϳϲϮ͛ϱ͕ϱϱϮ͛ϱ͕ϱϳϳ͛ϮϳϭϬͬϭϮͬϮϬdŽďĞ/ƐŽůĂƚĞĚ hͲϳ>ŽǁĞƌϲ͕ϳϵϱ͛ϲ͕ϴϮϬ͛ϱ͕ϲϬϳ͛ϱ͕ϲϯϬ͛ϮϱϭϬͬϭϮͬϮϬdŽďĞ/ƐŽůĂƚĞĚ Dͺϰ ϳ͕ϯϯϱΖϳ͕ϯϱϯΖϲ͕ϬϳϯΖϲ͕ϬϵϭΖϭϴΖϬϱͬϬϰͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ ϳ͕ϯϯϱΖϳ͕ϯϱϯΖϲ͕ϬϳϯΖϲ͕ϬϵϭΖϭϴΖϬϴͬϮϬͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ ϳ͕ϯϳϮΖϳ͕ϯϴϳΖϲ͕ϭϬϮΖϲ͕ϭϭϳΖϭϱΖϬϱͬϬϰͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ ϳ͕ϯϳϮΖϳ͕ϯϴϳΖϲ͕ϭϬϮΖϲ͕ϭϭϳΖϭϱΖϬϴͬϮϭͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ Dͺϳ ϳ͕ϳϰϱΖϳ͕ϳϱϬΖϲ͕ϰϭϯΖϲ͕ϰϭϴΖϱΖϬϱͬϬϰͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ ϳ͕ϳϰϱΖϳ͕ϳϱϬΖϲ͕ϰϭϯΖϲ͕ϰϭϴΖϱΖϬϴͬϮϬͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ ϳ͕ϳϱϵΖϳ͕ϳϲϳΖϲ͕ϰϮϰΖϲ͕ϰϯϮΖϴΖϬϱͬϬϰͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ ϳ͕ϳϱϵΖϳ͕ϳϲϳΖϲ͕ϰϮϰΖϲ͕ϰϯϮΖϴΖϬϴͬϮϬͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ ϳ͕ϳϳϴΖϳ͕ϳϴϴΖϲ͕ϰϰϬΖϲ͕ϰϱϬΖϭϬΖϬϱͬϬϰͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ ϳ͕ϳϳϴΖϳ͕ϳϴϴΖϲ͕ϰϰϬΖϲ͕ϰϱϬΖϭϬΖϬϴͬϮϬͬϮϭ/ƐŽůĂƚĞĚ;ϳͬϭϱͬϮϮͿ 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&KDQJHVWR$SSURYHG6XQGU\3URFHGXUHIRU:HOO&/85'37'6XQGU\;;;;;;$Q\PRGLILFDWLRQVWRDQDSSURYHGVXQGU\ZLOOEHGRFXPHQWHGDQGDSSURYHGEHORZ&KDQJHVWRDQDSSURYHGVXQGU\ZLOOEHFRPPXQLFDWHGWRWKH$2*&&E\WKHULJZRUNRYHU5:2³ILUVWFDOO´HQJLQHHU$2*&&ZULWWHQDSSURYDORIWKHFKDQJHLVUHTXLUHGEHIRUHLPSOHPHQWLQJWKHFKDQJH6HF3DJH'DWH3URFHGXUH&KDQJH1HZ5HTXLUHG"<1+$.3UHSDUHG%\,QLWLDOV+$.$SSURYHG%\,QLWLDOV$2*&&:ULWWHQ$SSURYDO5HFHLYHG3HUVRQDQG'DWH$SSURYDO $VVHW7HDP2SHUDWLRQV0DQDJHU 'DWH 3UHSDUHG )LUVW&DOO2SHUDWLRQV(QJLQHHU 'DWH From:McLellan, Bryan J (OGC) To:Ryan Rupert Cc:Wade Hudgens - (C); Donna Ambruz; Roby, David S (OGC); Boyer, David L (OGC); Davies, Stephen F (OGC) Subject:RE: [EXTERNAL] RE: CLU-05RD (PTD#215-160) decomplete for drilling Date:Wednesday, July 20, 2022 10:50:00 AM Ryan, Verbal Approval granted to modify the squeeze plan as stipulated in your revised procedure attached and the email below. Original conditions of approval on Sundry 322-351 still apply. Please follow up with a Sundry with a change of approved program and include the steps to set 15k on the CIBP as mentioned below. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Wednesday, July 20, 2022 9:03 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Wade Hudgens - (C) <Wade.Hudgens@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: CLU-05RD (PTD#215-160) decomplete for drilling 10-4. We’ll plan on setting down 15k on the CIBP + 25’ dump bailed cement with our mill out assembly after the squeeze cement job is milled out. Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, July 18, 2022 6:54 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Wade Hudgens - (C) <Wade.Hudgens@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: [EXTERNAL] RE: CLU-05RD (PTD#215-160) decomplete for drilling CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Ryan, You’ll need to verify the P&A plug integrity per 20 AAC 25.112(g)(1) or (2). It’s either: 1. Wireline tag plug pressure test; or 2. Setting at least 15,000 lbs weight on the plug with the work string. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, July 18, 2022 4:04 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Wade Hudgens - (C) <Wade.Hudgens@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: CLU-05RD (PTD#215-160) decomplete for drilling Bryan- Please see attached for Hilcorp’s proposed changes to approved sundry #322-351. The changes pertain to how the perfs are abandoned and squeezed. Given the unknown behavior of squeeze cementing, we’d like to sting int the SBR at the ZXP liner top packer at 6433’ MD. This will allow us to pump a large volume while keeping cement from setting up in the 9-5/8” casing. We’ll be able to unsting from the SBR and circ out any excess cement once the well squeezes off, regardless of how many bbls into the job we are. This approach should give us a better squeeze vs. laying in cement, however there’s a good chance we won’t have sufficient slumping of cement to fill the void between our CIBP below, and the bottom perf. SO, I’m proposing to dump bail 25’ of cement on top of that CIBP when we set it to satisfy the abandonment requirement ahead of the squeeze. Please let me know your thoughts, and if we’re approved to proceed as amended. We’ll eb looking to execute the EL CIBP and dump bail as soon as Thursday 7/21. Thank you Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________CANNERY LOOP UNIT 05RD JBR 08/29/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Tested with 2 7/8 and 3 1/2 TJ. On Kill line valve K2 failed low PT cycled valve and passed. All other tests passed. Accumulator bottles 24@ 1000psi. Annular 22 sec, VBR 8 sec, HCR 2 Sec. Location was in good shape. Testing witnessed by AOGCC Inspectors Kam StJohn and Adam Earl. Test Results TEST DATA Rig Rep:Wade HudgensOperator:Hilcorp Alaska, LLC Operator Rep:Kevin Reed Rig Owner/Rig No.:Hilcorp 401 PTD#:2151600 DATE:7/19/2022 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopAGE220718145542 Inspector Adam Earl Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 4 MASP: 2378 Sundry No: 322-351 CLOSURE TIME (sec) Time/Pressure P/F Location Gen.:P Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec.NA Misc NA Upper Kelly 0 NA Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 8 PNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8" 5K P #1 Rams 1 VBR 2 7/8"X P #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8" 5K P HCR Valves 1 3 1/8" 5K P Kill Line Valves 3 3 1/8" & 2 1/1 FP Check Valve 0 NA BOP Misc 0 NA System Pressure P2950 Pressure After Closure P1850 200 PSI Attained P22 Full Pressure Attained P106 Blind Switch Covers:YAll Stations Nitgn Btls# &psi (avg)P6@2200 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators NA NAFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA 9 9 9 9 9 9 9 9 9 9 FP Kill line valve K2 failed Annular 22 sec, VBR 8 sec, HCR 2 Sec. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: CLU 05RD PTD 215-351/ Approved Sundry 322-351 Date:Monday, July 18, 2022 12:26:20 PM Attachments:YJOS 13.625-in 5M Type U Double_02Mar22.pdf CLU 05RD AOGCC 10-403 322-351 PTD 215-160 Approved 07-12-22.pdf CLU 5RD (PTD 2151600) Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Wade Hudgens - (C) <Wade.Hudgens@hilcorp.com> Sent: Monday, July 18, 2022 10:54 AM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: CLU 05RD PTD 215-351/ Approved Sundry 322-351 Good Morning Jim, The CLU-05 Sundry was approved with the 11” BOP package. We are planning to use the 13-5/8” 5M BOP package instead of the 11’ BOP’s for the upcoming CLU-05 RWO. I have attached the schematic for the 13-5/8” BOP Package. Please let me know if you need any additional information regarding the changes. Thank You, Wade Hudgens Well Site Manager (903) 331-6711 – C wade.hudgens@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 13-5/8"SPHERICAL ANNULAR HEIGHT: 45.28" WEIGHT: 12,806 LBS 13-5/8"TYPE U DOUBLE BOP HEIGHT: 55.81" WEIGHT: 14,800 LBS The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 13-5/8" MUD CROSS W/ 4- 1/16" OUTLETS HEIGHT: 36" APROX. WEIGHT: 2,500 LBS INSIDE TO OUTSIDE 4-1/16" 5M X 3-1/8" 5M ADAPTER SPOOL 3-1/8" 5M MANUAL GATE 3-1/8" 5M MANUAL GATE INSIDE TO OUTSIDE 4-1/16" 5M X 3-1/8" 5M ADAPTER SPOOL 3-1/8" 5M Manual Gate valve 3-1/8" 5M HCR KILL SIDE CHOKE SIDE HEIGHT ADDITION FOR RING GASKETS: 0" BOP TOTAL HEIGHT: 137.06" WEIGHT: 30,106 LBS 13-5/8" 5m BOP Package W/ 3-1/8" Valves David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: Date: 07/08/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 05RD (PTD 215-160) CBL 09/24/2020 Please include current contact information if different from above. 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ϭ͘D/dͲ/ŽĨƚŚĞϵͲϱͬϴ͟ǆϮͲϳͬϴ͟ĂŶŶƵůƵƐƚŽϯϱϬϬƉƐŝ;ƚŚŝƐǁŝůůĞǆĐĞĞĚƚŚĞƉůĂŶŶĞĚDW^WŽĨĨƵƚƵƌĞWdͿ Ϯ͘^ĞƚϮͲϳͬϴ͟ddWŽƌ/WŝŶƚƵďŝŶŐƚĂŝůďĞůŽǁƉĂĐĞƌĂƚцϲ͕ϴϲϬ͛D ϯ͘>ŽĂĚƚƵďŝŶŐǁŝƚŚƉƌŽĚƵĐĞĚǁĂƚĞƌ;Εϴ͘ϲƉƉŐͿ ϰ͘D/dͲdƚŽϭϱϬϬƉƐŝƚŽĐŽŶĨŝƌŵƉůƵŐŝƐŚŽůĚŝŶŐ;ŶŽĐŚĂƌƚŝŶŐƌĞƋƵŝƌĞŵĞŶƚͿ ŽŶƚŝŶŐĞŶĐǇŝĨŐĂƐŝƐƐƵƐƉĞĐƚĞĚďĞůŽǁƚŚĞƵƉƉĞƌƉĂĐŬĞƌ͗ WƵŶĐŚϮͲϳͬϴ͟ƚƵďŝŶŐũƵƐƚďĞůŽǁƚŚĞƵƉƉĞƌƉĂĐŬĞƌĂƚцϲϯϳϱ͛D ZtKĚĞĐŽŵƉůĞƚĞWƌŽĐĞĚƵƌĞ ϭ͘D/Zh,ŝůĐŽƌƉƌŝŐηϰϬϭ Ϯ͘&ŝůůǁĞůůǁŝƚŚƉƌŽĚƵĐĞĚǁĂƚĞƌ;Εϴ͘ϲƉƉŐͿĂŶĚĞŶƐƵƌĞǁĞůůŝƐĚĞĂĚ;dƵďŝŶŐǀŽůƵŵĞсϰϬďďůƐͿ ϯ͘^ĞƚWsŽƌdt ϰ͘EhKW͛ƐĂŶĚƚĞƐƚ Ă͘WdƚŽϮϱϬƉƐŝůŽǁͬϮϱϬϬƉƐŝŚŝŐŚͬϮϱϬϬƉƐŝĂŶŶƵůĂƌ ď͘dĞƐƚǁŝƚŚϮͲϳͬϴ͟ƚĞƐƚũŽŝŶƚ ϱ͘WƵůůWsͬdt ϲ͘DŽŶŝƚŽƌǁĞůůƚŽĞŶƐƵƌĞŝƚƐƐƚĂƚŝĐ ϳ͘WhŽŶϮͲϳͬϴ͟ƚƵďŝŶŐƚŽƌĞůĞĂƐĞĨƌŽŵƐŶĂƉůĂƚĐŚĂƚϲϴϰϳ͛D Ă͘ϱϴŬŽǀĞƌƐƚƌŝŶŐǁĞŝŐŚƚƌĞƋƵŝƌĞĚƚŽƵŶƐĞĂƚϵͲϱͬϴ͟ƉĂĐŬĞƌĂƚϲϯϲϴ͛D ď͘ϱŬĂĚĚŝƚŝŽŶĂůƚŽƌĞůĞĂƐĞƐŶĂƉůĂƚĐŚĂƚϲϴϰϳ͛D ϴ͘WKK,ǁŝƚŚϮͲϳͬϴ͟ƚƵďŝŶŐƌĂĐŬŝŶŐƐŽŵĞďĂĐŬƚŽďĞƵƐĞĚĂƐŬŝůůƐƚƌŝŶŐ͘ ϵ͘ŶƐƵƌĞĨƵůůƌĞĐŽǀĞƌǇĚŽǁŶƚŽƐŶĂƉůĂƚĐŚ ŽŶƚŝŶŐĞŶĐǇ͗/ĨƵƉƉĞƌƉĂĐŬĞƌǁŽŶ͛ƚƌĞůĞĂƐĞ͕ŵĂǇŶĞĞĚƚŽĐƵƚĂďŽǀĞĂŶĚĨŝƐŚŽƌŵŝůůǁŝƚŚϮͲϳͬϴ͟ǁŽƌŬƐƚƌŝŶŐ ŽŶƚŝŶŐĞŶĐǇ͗/ĨƐŶĂƉůĂƚĐŚǁŽŶ͛ƚƌĞůĞĂƐĞ͕ŵĂǇŶĞĞĚƚŽĐƵƚĂďŽǀĞůŽǁĞƌƉĂĐŬĞƌ ϭϬ͘WĞƌĨŽƌŵďĂƐĞůŝŶĞŝŶũĞĐƚŝǀŝƚǇƚĞƐƚŝŶƚŽhϳĂŶĚhϰŽƉĞŶƉĞƌĨƐƉĞƌK ϭϭ͘Zh>ǁŝƚŚϳͲϱͬϴ͟/W ϭϮ͘Z/,ĂŶĚƐĞƚϳͲϱͬϴ͟/WĂƚцϲ͕ϲϵϬ͛D;ǆĂĐƚĚĞƉƚŚǁŝůůďĞŽƉƚŝŵŝǌĞĚĨŽƌ<KWĐŽůůĂƌĂǀŽŝĚĂŶĐĞͿ ϭϯ͘ZĞƉĞĂƚŝŶũĞĐƚŝǀŝƚǇƚĞƐƚŶŽǁƚŚĂƚŽŶůǇhͲϰƉĞƌĨƐĂƌĞŽƉĞŶ͕ĂŶĚĐŽŶĨŝƌŵĚĞĐƌĞĂƐĞĚŝŶũĞĐƚŝǀŝƚǇ ϭϰ͘hƐŝŶŐϮͲϳͬϴ͟ǁŽƌŬƐƚƌŝŶŐ͕ƉĞƌĨŽƌŵƐƋƵĞĞǌĞŽĨhͲϰƉĞƌĨƐĨƌŽŵϲϱϳϴ͛ʹϲϱϵϰ͛D ϭϱ͘WKK,ĂŶĚtŽ ϭϲ͘DhŵŝůůŽŶǁŽƌŬƐƚƌŝŶŐ͕ĂŶĚŵŝůůŽƵƚƐƋƵĞĞǌĞĐĞŵĞŶƚŝŶƚŚĞϳͲϱͬϴ͟ůŝŶĞƌ Ă͘EŽƚĞϲ͘ϲϮϱ͟/>dWĂƚϲ͕ϰϯϯ͛D ď͘ǆĂĐƚĚĞƉƚŚƚŽŵŝůůƚŽƉĞƌĚƌŝůůŝŶŐĞŶŐŝŶĞĞƌ;ǁŝůůďĞďĂƐĞŽĨǁŚŝƉƐƚŽĐŬͿ Đ͘EĞĞĚƚŽůĞĂǀĞĂƚůĞĂƐƚϮϱ͛ĐĞŵĞŶƚŽŶƚŽƉŽĨ/W ϭϳ͘D/dϵͲϱͬϴ͟ǆϳͲϱͬϴ͟ĐĂƐŝŶŐ;ĂŶĚƐƋƵĞĞǌĞƉĞƌĨƐͿƚŽϮϬϬϬƉƐŝĨŽƌϯϬŵŝŶƵƚĞƐ;ĐŚĂƌƚĞĚͿ ϭϴ͘^ĞƚWsŽƌdt ϭϵ͘EKWƐ͕EhƚƌĞĞ ϮϬ͘ZDKƌŝŐϰϬϭ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƵƌƌĞŶƚƐĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘ƵƌƌĞŶƚǁĞůůŚĞĂĚƐĐŚĞŵĂƚŝĐ ϰ͘zĞůůŽǁũĂĐŬĞƚKW͛Ɛ;ϭϭ͟Ϳ ϱ͘K'ZtKŚĂŶŐĞ&Žƌŵ &LUFXODWH ERWWRPV XS RU EXOOKHDG ,$ EHIRUH 322+ WR FOHDU SDFNHU JDV EMP 3URYLGH KUV QRWLFH WR $2*&& IRU RSSRUWXQLW\ WR ZLWQHVV SOXJ WDJ DQG SUHVVXUH WHVW EMP 1HHG WR OHDYH RQ WRS SHU $$& F( EMP 6HW GRZQ OEV ZHLJKW RQ FHPHQW SOXJ EMP BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇZZϲͬϮͬϮϮ ^,Dd/&RRN,QOHW%DVLQ$ODVND 0LGGOH*URXQG6KRDO /DVW&RPSOHWHG 2LO:HOO!:DWHULQMHFWRU!*DVSURGXFHU IRU3ODWIRUP tĞůů͗>hϬϱZ W/͗ϱϬͲϭϯϯͲϮϬϰϳϰͲϬϭͲϬϬ Wd͗ϮϭϱͲϭϲϬ KWE,K>ͬDEdd/> ϭϯͲϯͬϴ͟&ƵůůǇĐĞŵĞŶƚĞĚǁŝƚŚϭϰϬďďůƐďĂĐŬƚŽƐƵƌĨĂĐĞ;>hͲϬϱŝŶϭϵϵϲͿ ϵͲϱͬϴ͟ϭϮͲϭͬϰ͟ŚŽůĞ͗WƵŵƉĞĚĨƌŽŵϵϭϳϴ͛D͘ϴϱϬƐǆƐůĞĂĚ;ϯϳϱďďůƐͿĂŶĚϭϬϲϵƐǆƐ;ϮϮϮďďůƐͿƚĂŝů;>hͲϬϱŝŶ ϭϵϵϲͿϭϭͬϭϵͬϵϲh^/dƐŚŽǁƐϵͲϱͬϴ͟ĐĞŵĞŶƚĞĚƵƉƚŽĂƚůĞĂƐƚϮϴϬϬ͛D;ƐƚŽƉƉĞĚůŽŐŐŝŶŐƚŚĞƌĞͿ ϳͲϱͬϴ͟ϴͲϭͬϮ͟ŚŽůĞ͗ĞŵĞŶƚĞĚǁŝƚŚϭϬϮ͘ϳďďůƐϭϱ͘ϯƉƉŐĐůĂƐƐ'͘ŚĂĚůŽƐƐĞƐĂŶĚŐŽƚŶŽĐĞŵĞŶƚďĂĐŬƚŽƐƵƌĨĂĐĞ͘ ϵͬϮϰͬϮϬ^DdƐŚŽǁƐŐŽŽĚĐĞŵĞŶƚƵƉƚŽĂƚůĞĂƐƚϲ͕ϱϮϱD;ďĞŚŝŶĚƚƵďŝŶŐĂďŽǀĞƚŚĂƚͿ hWWZWZ&KZd/KEd/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿ^W&ĂƚĞ^ŝǌĞ^ƚĂƚƵƐ hͲϰϲ͕ϱϳϴ͛ϲ͕ϱϵϰ͛ϱ͕ϰϬϯ͛ϱ͕ϰϭϵ͛ϭϲϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hͲϳhƉƉĞƌϲ͕ϳϯϱ͛ϲ͕ϳϲϮ͛ϱ͕ϱϱϮ͛ϱ͕ϱϳϳ͛ϮϳϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hͲϳ>ŽǁĞƌϲ͕ϳϵϱ͛ϲ͕ϴϮϬ͛ϱ͕ϲϬϳ͛ϱ͕ϲϯϬ͛ϮϱϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Dͺϰ ϳ͕ϯϯϱΖϳ͕ϯϱϯΖϲ͕ϬϳϯΖϲ͕ϬϵϭΖϭϴΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϯϯϱΖϳ͕ϯϱϯΖϲ͕ϬϳϯΖϲ͕ϬϵϭΖϭϴΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϯϳϮΖϳ͕ϯϴϳΖϲ͕ϭϬϮΖϲ͕ϭϭϳΖϭϱΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϯϳϮΖϳ͕ϯϴϳΖϲ͕ϭϬϮΖϲ͕ϭϭϳΖϭϱΖϬϴͬϮϭͬϮϭϮ͟KƉĞŶ Dͺϳ ϳ͕ϳϰϱΖϳ͕ϳϱϬΖϲ͕ϰϭϯΖϲ͕ϰϭϴΖϱΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϰϱΖϳ͕ϳϱϬΖϲ͕ϰϭϯΖϲ͕ϰϭϴΖϱΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϳϱϵΖϳ͕ϳϲϳΖϲ͕ϰϮϰΖϲ͕ϰϯϮΖϴΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϱϵΖϳ͕ϳϲϳΖϲ͕ϰϮϰΖϲ͕ϰϯϮΖϴΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϳϳϴΖϳ͕ϳϴϴΖϲ͕ϰϰϬΖϲ͕ϰϱϬΖϭϬΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϳϴΖϳ͕ϳϴϴΖϲ͕ϰϰϬΖϲ͕ϰϱϬΖϭϬΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϮϯΖϴ͕ϬϮϵΖϲ͕ϲϰϯΖϲ͕ϲϰϵΖϲΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϯϴΖϴ͕ϬϱϲΖϲ͕ϲϱϲΖϲ͕ϲϳϰΖϭϴΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϳϰΖϴ͕ϬϳϵΖϲ͕ϲϴϲΖϲ͕ϲϵϭΖϱΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭ&ϴ͕ϭϯϳΖϴ͕ϭϰϵΖϲ͕ϳϯϴΖϲ͕ϳϱϬΖϭϮΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ ϴ͕ϭϵϲΖϴ͕ϮϬϯΖϲ͕ϳϴϳΖϲ͕ϳϵϰΖϳΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ Wdсϴ͕ϯϮϴ͛Dͬϲ͕ϴϵϳ͛ds dсϭϮ͕ϵϰϬ͛Dͬϭϭ͕Ϯϱϯ͛ds $% ϮϬ͟ Z<сϭϴ͛ ϵͲϱͬϴ͟ ϭϯͲϯͬϴ͟ DE ϰͲϭͬϮ͟ ϳͲϱͬϴ͟ &LQJVD )URP¶ ¶0' 3 3 * . & / ^/E'd/> ^ŝǌĞdǇƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵ ϮϬΗŽŶĚƵĐƚŽƌϭϮϵͬEͬͬEͬEͬ^ƵƌĨϭϰϮΖ ϭϯͲϯͬϴΗ^ƵƌĨĂĐĞϲϭͬ<ͲϱϱͬdϭϮ͘ϱϭϱ͟^ƵƌĨϮ͕ϵϳϬΖ ϵͲϱͬϴΗ/ŶƚĞƌŵĞĚŝĂƚĞϱϯ͘ϱͬ>ͲϴϬͬdϴ͘ϱϯϱ͟^ƵƌĨϭ͕ϮϭϮ͛ ϰϳͬWͲϭϭϬͬdϴ͘ϲϴϭ͟ϭ͕ϮϭϮ͛ϲ͕ϱϮϳ͛ ϳͲϱͬϴ͟ >ŝŶĞƌ Ϯϵ͘ϳͬ>ͲϴϬͬ,zϱϭϭϲ͘ϴϳϱ͟ϲ͕ϰϯϯ͛ϲ͕ϵϭϬ͛ Ϯϵ͘ϳͬ>ͲϴϬͬ^>/:Ͳ//ϲ͘ϴϳϱ͟ϲ͕ϵϭϬ͛ϭϬ͕ϰϰϴ͛ ϰͲϭͬϮ͟>ŝŶĞƌϭϮ͘ϲͬ>ͲϴϬͬtͬϯ͘ϵϱϴ͟ϭϬ͕ϮϰϬ͛ϭϮ͕ϵϭϱ͛ dh/E'd/> ϮͲϳͬϴ͟ϲ͘ϰηͬ>ͲϴϬͬhϴZϮ͘ϰϰϭ͟^ƵƌĨΕϲ͕ϴϴϯ͛ hWWZ:t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϭϴ͛ϰ͘ϬϬϬ͟ϲ͘ϳϱϬ͟dƵďŝŶŐ,ĂŶŐĞƌ͕ϰͲϭͬϮ͟ ϮϮϵϵ͛Ϯ͘ϰϰϭ͟ϳ͘ϭϭϬ͟^ĂĨĞƚǇsĂůǀĞ ϯĂϲ͕ϯϲϴ͛ ϯ͘ϵϴϬ͟ͲϵͲϱͬϴ͟,ǇĚƌĂƵůŝĐZĞƚƌŝĞǀĂďůĞWĂĐŬĞƌ;ϱϴŬƐƚƌĂŝŐŚƚƉƵůů ƚŽƌĞůĞĂƐĞͿ ϯďϲ͕ϯϵϬ͛Ϯ͘ϯϭϯ͟ͲϮͲϳͬϴ͟y>ĂŶĚŝŶŐEŝƉƉůĞ ϰϲ͕ϰϯϯ͛ϲ͘ϲϮϱ͟ϴ͘ϰϲϬ͟ϳͲϱͬϴ͟yW>ŝŶĞƌdŽƉWĂĐŬĞƌ ϱϲ͕ϱϮϳ͛ϴ͘ϱ͟ϳͲϱͬϴ͟tŚŝƉƐƚŽĐŬͬ<ŝĐŬŽĨĨƉŽŝŶƚ;ŵŝůůĞĚǁŝŶĚŽǁͿ ϲϲ͕ϴϰϳ͛Ϯ͘ϵϵϬ͟ϱ͘ϭϵϬ͟^ŶĂƉ>ĂƚĐŚĂƐƐĞŵďůǇ;^ƚƌĂŝŐŚƚƉƵůůƚŽƌĞůĞĂƐĞͿ ϳϲ͕ϴϰϴ͛ϰ͘ϬϬϬ͟ϲ͘ϮϱϬ͟ϳͲϱͬϴ͟WĞƌŵĂŶĞŶƚWĂĐŬĞƌ ϴĂϲ͕ϴϳϭ͛Ϯ͘ϯϭϯ͟ͲϮͲϳͬϴ͟y>ĂŶĚŝŶŐEŝƉƉůĞ ϴďϲ͕ϴϴϯ͛Ϯ͘ϰϱϬ͟ͲϮͲϳͬϴ͟t>' ϵϴ͕ϯϱϱ͛Ͳϳ͘ϲϮϱ͟/WǁͬϮϳ͛ĐŵƚdKϴ͕ϯϮϴ͛ϭϬͬϭϮͬϮϬ &ŝƐŚ͗DŝůůĞĚϰͲϭͬϮ͟ǆϳͲϱͬϴ͟ƉĂĐŬĞƌĂŶĚ ƚƵďŝŶŐƚĂŝůĨƌŽŵϳͬϯϭͬϮϭZtK͘K>ΕϱϬ͛ tĞůů͗>hϬϱZ ^,Dd/W/͗ϱϬͲϭϯϯͲϮϬϰϳϰͲϬϭͲϬϬ Wd͗ϮϭϱͲϭϲϬ >KtZͬ/^K>d:t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϬϭϬ͕ϮϬϴ͛Ͳϳ͘ϲϮϱ͟/Wǁͬϯϱ͛ĐĞŵĞŶƚ;dKϭϬ͕ϭϳϯ͛ͿϲͬϮϯͬϮϬ ϭϭϭϬ͕ϮϯϬ͛Ͳϳ͘ϲϮϱ͟/WϲͬϭϳͬϮϬ ϭϮϭϬ͕ϮϰϬ͛ʹϭϬ͕ϮϳϮ͛ϰ͘ϴϮϬ͟ϲ͘ϱϲϬ͟ϰͲϭͬϮ͟yWE>ŝŶĞƌdŽƉWĂĐŬĞƌ ϭϯϭϬ͕ϮϳϮ͛ʹϭϬ͕Ϯϵϴ͛ϰ͘ϳϰϬ͟ϲ͘ϮϳϬ͟>ŝŶĞƌ^ĞĂůďŽƌĞǆƚĞŶƐŝŽŶ ϭϰϭϬ͕Ϯϳϵ͛Ͳϰ͘ϱϬϬ͟/WϲͬϭϱͬϮϬ ϭϱϭϬ͕ϯϰϵ͛Ͳϰ͘ϱϬϬ͟/W ϭϲϭϭ͕ϭϳϬ͛Ͳϯ͘ϱϬϬ͟/W;dKϭϭ͕ϭϳϬ͛Ϳ ϭϳϭϭ͕ϰϯϬ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϰϮϬ͛Ϳ ϭϴϭϭ͕ϱϬϱ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϰϵϱ͛Ϳ ϭϵϭϭ͕ϱϲϱ͛Ͳϯ͘ϱϬϬ͟/Wǁͬϭϱ͛ĐĞŵĞŶƚ;dKϭϭ͕ϱϱϬ͛Ϳ ϮϬϭϭ͕ϳϬϬ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϲϵϬ͛Ϳ Ϯϭϭϭ͕ϳϮϯ͛Ͳϯ͘ϱϬϬ͟/W >KtZWZ&KZd/KEd/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿ^W&ĂƚĞ^ŝǌĞ^ƚĂƚƵƐ >ͲϮϴ͕ϰϬϳ͛ϴ͕ϰϯϭ͛ϲ͕ϵϲϭ͛ϲ͕ϵϴϭ͛ϮϰϬϳͬϭϯͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hdͲϵϭϬ͕ϯϬϲ͛ϭϬ͕ϯϮϲ͛ϴ͕ϲϮϬ͛ϴ͕ϲϰϬ͛ϲϬϯͬϯϬͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϯϮϲ͛ϭϬ͕ϯϰϲ͛ϴ͕ϲϰϬ͛ϴ͕ϲϲϬ͛ϲϬϯͬϮϴͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϵϭͲϮ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϱ͛ϵ͕Ϭϴϭ͛ϵ͕Ϭϵϵ͛ϲϭϬͬϭϬͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϳ͛ϵ͕Ϭϴϭ͛ϵ͕ϭϬϭ͛ϲϬϲͬϬϯͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϳ͛ϵ͕Ϭϴϭ͛ϵ͕ϭϬϭ͛ϲϬϯͬϭϯͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ͲϮϭϭ͕Ϭϴϭ͛ϭϭ͕ϭϬϲ͛ϵ͕ϯϵϱ͛ϵ͕ϰϮϬ͛ϲϭϮͬϮϮͬϭϲϮͲϳͬϴ͟^ƋƵĞĞǌĞĚ Ͳϯϭϭ͕ϯϮϭ͛ϭϭ͕ϯϰϲ͛ϵ͕ϲϯϱ͛ϵ͕ϲϲϬ͛ϲϭϭͬϮϱͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϰϭϭ͕ϰϲϬ͛ϭϭ͕ϰϴϬ͛ϵ͕ϳϳϰ͛ϵ͕ϴϬϰ͛ϲϭϬͬϮϵͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϰϲϬ͛ϭϭ͕ϰϵϬ͛ϵ͕ϳϳϰ͛ϵ͕ϴϬϰ͛ϲϭϬͬϭϰͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϱϭϭ͕ϱϭϬ͛ϭϭ͕ϱϯϬ͛ϵ͕ϴϮϰ͛ϵ͕ϴϰϰ͛ϲϬϲͬϭϱͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϱϭϭ͕ϱϳϮ͛ϭϭ͕ϱϴϬ͛ϵ͕ϴϴϲ͛ϵ͕ϴϵϰ͛ϲϬϭͬϮϮͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϱϴϲϭϭ͕ϱϵϴϵ͕ϵϬϬϵ͕ϵϭϮϲϬϱͬϮϲͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϲϭϭ͕ϳϭϮ͛ϭϭ͕ϳϮϮ͛ϭϬ͕ϬϮϲ͛ϭϬ͕Ϭϯϲ͛ϲϭϮͬϬϳͬϭϱϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϳϮϲ͛ϭϭ͕ϳϯϴ͛ϭϬ͕Ϭϯϵ͛ϭϬ͕Ϭϱϭ͛ϲϬϭͬϬϴͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇDϬϲͲϭϬͲϮϮ WZKWK^&RRN,QOHW%DVLQ$ODVND 0LGGOH*URXQG6KRDO /DVW&RPSOHWHG 2LO:HOO!:DWHULQMHFWRU!*DVSURGXFHU IRU3ODWIRUP tĞůů͗>hϬϱZ W/͗ϱϬͲϭϯϯͲϮϬϰϳϰͲϬϭͲϬϬ Wd͗ϮϭϱͲϭϲϬ KWE,K>ͬDEdd/> ϭϯͲϯͬϴ͟&ƵůůǇĐĞŵĞŶƚĞĚǁŝƚŚϭϰϬďďůƐďĂĐŬƚŽƐƵƌĨĂĐĞ;>hͲϬϱŝŶϭϵϵϲͿ ϵͲϱͬϴ͟ϭϮͲϭͬϰ͟ŚŽůĞ͗WƵŵƉĞĚĨƌŽŵϵϭϳϴ͛D͘ϴϱϬƐǆƐůĞĂĚ;ϯϳϱďďůƐͿĂŶĚϭϬϲϵƐǆƐ;ϮϮϮďďůƐͿƚĂŝů;>hͲϬϱŝŶ ϭϵϵϲͿϭϭͬϭϵͬϵϲh^/dƐŚŽǁƐϵͲϱͬϴ͟ĐĞŵĞŶƚĞĚƵƉƚŽĂƚůĞĂƐƚϮϴϬϬ͛D;ƐƚŽƉƉĞĚůŽŐŐŝŶŐƚŚĞƌĞͿ ϳͲϱͬϴ͟ϴͲϭͬϮ͟ŚŽůĞ͗ĞŵĞŶƚĞĚǁŝƚŚϭϬϮ͘ϳďďůƐϭϱ͘ϯƉƉŐĐůĂƐƐ'͘ŚĂĚůŽƐƐĞƐĂŶĚŐŽƚŶŽĐĞŵĞŶƚďĂĐŬƚŽƐƵƌĨĂĐĞ͘ ϵͬϮϰͬϮϬ^DdƐŚŽǁƐŐŽŽĚĐĞŵĞŶƚƵƉƚŽĂƚůĞĂƐƚϲ͕ϱϮϱD;ďĞŚŝŶĚƚƵďŝŶŐĂďŽǀĞƚŚĂƚͿ hWWZWZ&KZd/KEd/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿ^W&ĂƚĞ^ŝǌĞ^ƚĂƚƵƐ hͲϰϲ͕ϱϳϴ͛ϲ͕ϱϵϰ͛ϱ͕ϰϬϯ͛ϱ͕ϰϭϵ͛ϭϲϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hͲϳhƉƉĞƌϲ͕ϳϯϱ͛ϲ͕ϳϲϮ͛ϱ͕ϱϱϮ͛ϱ͕ϱϳϳ͛ϮϳϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hͲϳ>ŽǁĞƌϲ͕ϳϵϱ͛ϲ͕ϴϮϬ͛ϱ͕ϲϬϳ͛ϱ͕ϲϯϬ͛ϮϱϭϬͬϭϮͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Dͺϰ ϳ͕ϯϯϱΖϳ͕ϯϱϯΖϲ͕ϬϳϯΖϲ͕ϬϵϭΖϭϴΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϯϯϱΖϳ͕ϯϱϯΖϲ͕ϬϳϯΖϲ͕ϬϵϭΖϭϴΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϯϳϮΖϳ͕ϯϴϳΖϲ͕ϭϬϮΖϲ͕ϭϭϳΖϭϱΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϯϳϮΖϳ͕ϯϴϳΖϲ͕ϭϬϮΖϲ͕ϭϭϳΖϭϱΖϬϴͬϮϭͬϮϭϮ͟KƉĞŶ Dͺϳ ϳ͕ϳϰϱΖϳ͕ϳϱϬΖϲ͕ϰϭϯΖϲ͕ϰϭϴΖϱΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϰϱΖϳ͕ϳϱϬΖϲ͕ϰϭϯΖϲ͕ϰϭϴΖϱΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϳϱϵΖϳ͕ϳϲϳΖϲ͕ϰϮϰΖϲ͕ϰϯϮΖϴΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϱϵΖϳ͕ϳϲϳΖϲ͕ϰϮϰΖϲ͕ϰϯϮΖϴΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ ϳ͕ϳϳϴΖϳ͕ϳϴϴΖϲ͕ϰϰϬΖϲ͕ϰϱϬΖϭϬΖϬϱͬϬϰͬϮϭϮ͟KƉĞŶ ϳ͕ϳϳϴΖϳ͕ϳϴϴΖϲ͕ϰϰϬΖϲ͕ϰϱϬΖϭϬΖϬϴͬϮϬͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϮϯΖϴ͕ϬϮϵΖϲ͕ϲϰϯΖϲ͕ϲϰϵΖϲΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϯϴΖϴ͕ϬϱϲΖϲ͕ϲϱϲΖϲ͕ϲϳϰΖϭϴΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭϴ͕ϬϳϰΖϴ͕ϬϳϵΖϲ͕ϲϴϲΖϲ͕ϲϵϭΖϱΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ >ͺϭ&ϴ͕ϭϯϳΖϴ͕ϭϰϵΖϲ͕ϳϯϴΖϲ͕ϳϱϬΖϭϮΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ ϴ͕ϭϵϲΖϴ͕ϮϬϯΖϲ͕ϳϴϳΖϲ͕ϳϵϰΖϳΖϬϰͬϭϱͬϮϭϮ͟KƉĞŶ Wdсϴ͕ϯϮϴ͛Dͬϲ͕ϴϵϳ͛ds dсϭϮ͕ϵϰϬ͛Dͬϭϭ͕Ϯϱϯ͛ds ϮϬ͟ Z<сϭϴ͛ ϵͲϱͬϴ͟ ϭϯͲϯͬϴ͟ DE ϰͲϭͬϮ͟ ϳͲϱͬϴ͟ &LQJVD )URP¶ ¶0' L ^/E'd/> ^ŝǌĞdǇƉĞtƚͬ'ƌĂĚĞͬŽŶŶ/dŽƉƚŵ ϮϬΗŽŶĚƵĐƚŽƌϭϮϵͬEͬͬEͬEͬ^ƵƌĨϭϰϮΖ ϭϯͲϯͬϴΗ^ƵƌĨĂĐĞϲϭͬ<ͲϱϱͬdϭϮ͘ϱϭϱ͟^ƵƌĨϮ͕ϵϳϬΖ ϵͲϱͬϴΗ/ŶƚĞƌŵĞĚŝĂƚĞϱϯ͘ϱͬ>ͲϴϬͬdϴ͘ϱϯϱ͟^ƵƌĨϭ͕ϮϭϮ͛ ϰϳͬWͲϭϭϬͬdϴ͘ϲϴϭ͟ϭ͕ϮϭϮ͛ϲ͕ϱϮϳ͛ ϳͲϱͬϴ͟ >ŝŶĞƌ Ϯϵ͘ϳͬ>ͲϴϬͬ,zϱϭϭϲ͘ϴϳϱ͟ϲ͕ϰϯϯ͛ϲ͕ϵϭϬ͛ Ϯϵ͘ϳͬ>ͲϴϬͬ^>/:Ͳ//ϲ͘ϴϳϱ͟ϲ͕ϵϭϬ͛ϭϬ͕ϰϰϴ͛ ϰͲϭͬϮ͟>ŝŶĞƌϭϮ͘ϲͬ>ͲϴϬͬtͬϯ͘ϵϱϴ͟ϭϬ͕ϮϰϬ͛ϭϮ͕ϵϭϱ͛ dh/E'd/> ϮͲϳͬϴ͟ϲ͘ϰηͬ>ͲϴϬͬhϴZϮ͘ϰϰϭ͟^ƵƌĨΕϲ͕ϴϴϯ͛ hWWZ:t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϲ͕ϰϯϯ͛ϲ͘ϲϮϱ͟ϴ͘ϰϲϬ͟ϳͲϱͬϴ͟yW>ŝŶĞƌdŽƉWĂĐŬĞƌ Ϯϲ͕ϱϮϳ͛ϴ͘ϱ͟ϳͲϱͬϴ͟tŚŝƉƐƚŽĐŬͬ<ŝĐŬŽĨĨƉŽŝŶƚ;ŵŝůůĞĚǁŝŶĚŽǁͿ ϯцϲ͕ϲϵϬ͛ϳ͘ϲϮϱ͟/WǁͬϮϱ͛ĐĞŵĞŶƚdKΛцϲ͕ϲϲϱ͛ ϰϲ͕ϴϰϳ͛Ϯ͘ϵϵϬ͟ϱ͘ϭϵϬ͟^ŶĂƉ>ĂƚĐŚĂƐƐĞŵďůǇ;^ƚƌĂŝŐŚƚƉƵůůƚŽƌĞůĞĂƐĞͿ ϱϲ͕ϴϰϴ͛ϰ͘ϬϬϬ͟ϲ͘ϮϱϬ͟ϳͲϱͬϴ͟WĞƌŵĂŶĞŶƚWĂĐŬĞƌ ϲĂϲ͕ϴϳϭ͛Ϯ͘ϯϭϯ͟ͲϮͲϳͬϴ͟y>ĂŶĚŝŶŐEŝƉƉůĞ ϲďϲ͕ϴϴϯ͛Ϯ͘ϰϱϬ͟ͲϮͲϳͬϴ͟t>' ϳϴ͕ϯϱϱ͛Ͳϳ͘ϲϮϱ͟/WǁͬϮϳ͛ĐŵƚdKϴ͕ϯϮϴ͛ϭϬͬϭϮͬϮϬ &ŝƐŚ͗DŝůůĞĚϰͲϭͬϮ͟ǆϳͲϱͬϴ͟ƉĂĐŬĞƌĂŶĚ ƚƵďŝŶŐƚĂŝůĨƌŽŵϳͬϯϭͬϮϭZtK͘K>ΕϱϬ͛ tĞůů͗>hϬϱZ WZKWK^ W/͗ϱϬͲϭϯϯͲϮϬϰϳϰͲϬϭͲϬϬ Wd͗ϮϭϱͲϭϲϬ >KtZͬ/^K>d:t>Zzd/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϴϭϬ͕ϮϬϴ͛Ͳϳ͘ϲϮϱ͟/Wǁͬϯϱ͛ĐĞŵĞŶƚ;dKϭϬ͕ϭϳϯ͛ͿϲͬϮϯͬϮϬ ϵϭϬ͕ϮϯϬ͛Ͳϳ͘ϲϮϱ͟/WϲͬϭϳͬϮϬ ϭϬϭϬ͕ϮϰϬ͛ʹϭϬ͕ϮϳϮ͛ϰ͘ϴϮϬ͟ϲ͘ϱϲϬ͟ϰͲϭͬϮ͟yWE>ŝŶĞƌdŽƉWĂĐŬĞƌ ϭϭϭϬ͕ϮϳϮ͛ʹϭϬ͕Ϯϵϴ͛ϰ͘ϳϰϬ͟ϲ͘ϮϳϬ͟>ŝŶĞƌ^ĞĂůďŽƌĞǆƚĞŶƐŝŽŶ ϭϮϭϬ͕Ϯϳϵ͛Ͳϰ͘ϱϬϬ͟/WϲͬϭϱͬϮϬ ϭϯϭϬ͕ϯϰϵ͛Ͳϰ͘ϱϬϬ͟/W ϭϰϭϭ͕ϭϳϬ͛Ͳϯ͘ϱϬϬ͟/W;dKϭϭ͕ϭϳϬ͛Ϳ ϭϱϭϭ͕ϰϯϬ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϰϮϬ͛Ϳ ϭϲϭϭ͕ϱϬϱ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϰϵϱ͛Ϳ ϭϳϭϭ͕ϱϲϱ͛Ͳϯ͘ϱϬϬ͟/Wǁͬϭϱ͛ĐĞŵĞŶƚ;dKϭϭ͕ϱϱϬ͛Ϳ ϭϴϭϭ͕ϳϬϬ͛Ͳϯ͘ϱϬϬ͟/WǁͬϭϬ͛ĐĞŵĞŶƚ;dKϭϭ͕ϲϵϬ͛Ϳ ϭϵϭϭ͕ϳϮϯ͛Ͳϯ͘ϱϬϬ͟/W >KtZWZ&KZd/KEd/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿ^W&ĂƚĞ^ŝǌĞ^ƚĂƚƵƐ >ͲϮϴ͕ϰϬϳ͛ϴ͕ϰϯϭ͛ϲ͕ϵϲϭ͛ϲ͕ϵϴϭ͛ϮϰϬϳͬϭϯͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ hdͲϵϭϬ͕ϯϬϲ͛ϭϬ͕ϯϮϲ͛ϴ͕ϲϮϬ͛ϴ͕ϲϰϬ͛ϲϬϯͬϯϬͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϯϮϲ͛ϭϬ͕ϯϰϲ͛ϴ͕ϲϰϬ͛ϴ͕ϲϲϬ͛ϲϬϯͬϮϴͬϮϬϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϵϭͲϮ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϱ͛ϵ͕Ϭϴϭ͛ϵ͕Ϭϵϵ͛ϲϭϬͬϭϬͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϳ͛ϵ͕Ϭϴϭ͛ϵ͕ϭϬϭ͛ϲϬϲͬϬϯͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϬ͕ϳϲϳ͛ϭϬ͕ϳϴϳ͛ϵ͕Ϭϴϭ͛ϵ͕ϭϬϭ͛ϲϬϯͬϭϯͬϭϳϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ͲϮϭϭ͕Ϭϴϭ͛ϭϭ͕ϭϬϲ͛ϵ͕ϯϵϱ͛ϵ͕ϰϮϬ͛ϲϭϮͬϮϮͬϭϲϮͲϳͬϴ͟^ƋƵĞĞǌĞĚ Ͳϯϭϭ͕ϯϮϭ͛ϭϭ͕ϯϰϲ͛ϵ͕ϲϯϱ͛ϵ͕ϲϲϬ͛ϲϭϭͬϮϱͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϰϭϭ͕ϰϲϬ͛ϭϭ͕ϰϴϬ͛ϵ͕ϳϳϰ͛ϵ͕ϴϬϰ͛ϲϭϬͬϮϵͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϰϲϬ͛ϭϭ͕ϰϵϬ͛ϵ͕ϳϳϰ͛ϵ͕ϴϬϰ͛ϲϭϬͬϭϰͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϱϭϭ͕ϱϭϬ͛ϭϭ͕ϱϯϬ͛ϵ͕ϴϮϰ͛ϵ͕ϴϰϰ͛ϲϬϲͬϭϱͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϱϭϭ͕ϱϳϮ͛ϭϭ͕ϱϴϬ͛ϵ͕ϴϴϲ͛ϵ͕ϴϵϰ͛ϲϬϭͬϮϮͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϱϴϲϭϭ͕ϱϵϴϵ͕ϵϬϬϵ͕ϵϭϮϲϬϱͬϮϲͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ Ͳϲϭϭ͕ϳϭϮ͛ϭϭ͕ϳϮϮ͛ϭϬ͕ϬϮϲ͛ϭϬ͕Ϭϯϲ͛ϲϭϮͬϬϳͬϭϱϮͲϳͬϴ͟/ƐŽůĂƚĞĚ ϭϭ͕ϳϮϲ͛ϭϭ͕ϳϯϴ͛ϭϬ͕Ϭϯϵ͛ϭϬ͕Ϭϱϭ͛ϲϬϭͬϬϴͬϭϲϮͲϳͬϴ͟/ƐŽůĂƚĞĚ &DQQHU\/RRS8QLW &/8&XUUHQW dƵďŝŶŐŚĞĂĚ͕/tͲͲ^͕ ϭϯϱͬϴϱDyϭϭϱD͕ǁͬϮͲ ϮϭͬϭϲϱD^^K͕yͲďŽƚƚŽŵ ƉƌĞƉ͕EƚǇƉĞƉŝŶƐ sĂůǀĞ͕t<DͲD͕Ϯϭͬϭϲ ϱD&͕,tK͕ YƚǇϮ ĂƐŝŶŐŚĞĂĚ͕DĐǀŽǇ͕ ϭϯϱͬϴϱDyϭϯϯͬϴΖ͛^Kt ďŽƚƚŽŵ͕ǁͬϮͲϮϭͬϭϲϱD &K sĂůǀĞ͕DĐǀŽǇͲ͕ ϮϭͬϭϲϱD&͕,tK͕ 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Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 05RD (PTD 215-160) Perf 08/20/2021 Please include current contact information if different from above. 11/02/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Recomplete, CTU, N2, Install Cap String Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,940 feet feet true vertical 11,253 feet N/A feet 6368; 6433; Effective Depth measured 8,328 feet 6848; 10240 feet true vertical 6,897 feet 5201; 5263; feet 5656; 8555 Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.4# / L-80 6,883' MD 5,687' TVD Ret, Liner Top, Perm, Liner Top Pkrs Packers and SSSV (type, measured and true vertical depth)Baker TE-5 SSSV TR 298' MD/ 298' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst 6,890psi 142' 1,200' Casing Collapse 1,540psi 6,620psi 4,790psi See Attached 20" 13-3/8" 9-5/8" Length 2,578' 142' 2,970' 1,212' 4,015' Conductor Surface Intermediate Liner Intermediate 7,966' 0 Representative Daily Average Production or Injection Data 7,500psi Gas-Mcf 0 71 6368, 6433, 6848, 10240 MD / 5201, 5263, 5656, 8555 TVD Authorized Signature with date: Authorized Name: 62 Casing Pressure 2. Operator Name:Hilcorp Alaska, LLC Plugs Junk 0 Cannery Loop Unit (CLU) 05RD 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-257 / 321-361 / 321-403 243 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Tubing Pressure STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-160 50-133-20474-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: FEE Hilcorp (ADL060569); ADL324602 1,212' 9-5/8"7,599' measured measured true vertical Liner 2,675' 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai C.L.U. / Beluga Gas PoolN/A measured TVD 119 9,178' Oil-Bbl Packer 7-5/8" 4-1/2" 10,448' 9,440psi 5,300psi 11,229' 8,762' 7,930psi 3,090psi WINJ WAG 0 Water-Bbl MD 142' 2,970' 12,915' N/A 239 t Fra O 6. A G L PG , R g Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 3:06 pm, Sep 15, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.15 14:46:32 -08'00' Dan Marlowe (1267) Rig Start Date End Date 6/20/21 8/21/21 Daily Operations: 06/20/2021 - Sunday PTW JSA with crews. MIRU HAK hot oil truck and AK E-line. Rig up Hot oil truck to IA. Bleed residual gas off. Pump 3 bbls of produced water to catch fluid level. Walk pressure up and start MIT for 30 minutes at 1,540 psi. Held 1,540 psi for 30 minutes and charted on Hot oil acquisition system. Bleed down to 0 psi and shut in IA valve. AK E-line rigged up on well. Swap pump hose to E-line pump in sub. PT lubricator 250/3,500 psi. Bleed down. Pump 102 bbls of produced water down tubing. Tubing on vac. Open well RIH to 6,510' CCL depth. LOG OOH and find D&L permanent packer and 8' pump joint above packer. Correct depth to schematic. Log into position. CCL to cut 12.1'. Park CCL at 6,455.9' + 12.1' puts cutter at 6,468' (2' above packer). Cut tubing. PIck up OOH 50'. Was not able to hold positive or overbalanced pressure on tubing while making cut. Decided to RIH and tag or Log OOH to see if tubing collars near cut have moved up hole. RIH at stacked out at tubing cut at 6,468'. Good indication tubing is severed. POOH to surface. Tagging up at SSSV at 300' Called for enerpac due to wellhead and surface equipment being rigged down prior to Pre rig work. Pressure was low on SSSV. Pumped up and continue to POOH. Tagged up. Secure well and Rig down HAK hot oil truck and AK Eline. Previous issues with SSSV after completion in 2020 as well. We may have pushed SSSV flapper open and then dragged E-line next to it when POOH. Highly recommended that a new SSSV be ordered and available for the 401 rig when recompleting. Possible damage to the SSSV flapper. Continue rigging down AK E-line and Hot oil. Location secure SDFN. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00-00 215-160 Well Name CLU 05RD 07/03/2021 - Saturday PJSM with crew, emphasis on pre-spud of workover operation on CLU-005 and rigging up. Inspect site, determine layout. Lay out herculite, place rig mats to build up around cellar. Stage in base beam, pull in Carrier. Stage in equipment, RU circulation path. SMOPS: mechanics on site to determine vibration issues while operating drawworks. Initial thought was Right Angle Motor, suspect it could be dual-chain drive sand bearing. Sent BOP 24-hr Test notice to AOGCC at 1100 hrs for 1200 test 7/4. Continue with staging in equipment and rigging up. Fill pits, line up circ path through choke and MGS. Tubing pressure 450 psi, bleed off through choke, quick bleed. Open to IA, 1200 psi. Attempt to bleed, remains at ,1200 psi. Shut in. Circ down tubing at ~2.5 bpm / 600 psi with returns through IA to choke and MGS. Did not catch fluid with 70 bbls away, no increase on circulation pressure and IA pressure at choke not moving. Line up to pump down IA. Pump open SSSV. Initial readings: Tubing at 250 psi, IA at 1100 psi. Pump down IA, caught returns from tubing after 5 bbls. Verifies previous tubing cut is good, well is on slight vac. Re-line up to circ down tubing with IA returns through choke to MGS. Circ at ~3.5 bpm, 700 psi, increased to 1100 psi as IA begins to fluid pack. Continue circulating at ~4 bpm, 1,100 psi taking returns from IA through choke. Both pump and IA pressures dropping off, pressures dropped to 0 psi with no more gas from MGS but still not catching clean returns. Total volume pumped 530 bbls (calculated full well volume 567 bbls). Close in tree to secure well for evening. Volume received from supply well 573.1 bbls. Rig Start Date End Date 6/20/21 8/21/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00-00 215-160 Well Name CLU 05RD 07/04/2021 - Sunday PJSM with crew, emphasis on opening to well, hazards associated with ND and NU. Open to well, 0 psi on tubing and IA. Break circulation, took 57 bbls to fill, averaging 4.5 bph loss rate. Install TWC. Terminate SSSV control line, ND Tree. NU BOP stack: 11" Annular, 2-7/8" x 5" variable rams, Blind Rams, Mud cross with 2 manual valve Kill side and HCR Choke side. Roll out lines, NU and function test hydraulics. Install rig floor. Fluid pack BOP and conduct shell test. Test BOP per Sundry to 250 psi low / 2,500 psi high for 5 minutes each with 2-7/8" test joint. AOGCC witness waived by Jim Regg. Test all alarms, conduct Accumulator drawdown test. Complete bleed to bleed trailer, pull TWC. Fill well with 37 bbls, did not catch returns. Secure well. Build Landing joint, prep equipment for pulling hanger. Location secure for evening. Cumulative total from supply water well 692 bbls. 07/05/2021 - Monday Safety Meeting with Rig and Wellhead crew, emphasis on pressure from well, Control of Work while backing out lockdowns, overhead loads during lift of hanger. Open to well, no pressure on Tubing (SSSV closed?), ~400 psi on annulus. Line up to bleed trailer and bleed while rigging up to pull, all gas and no fluid. Back out lockdown screws while crew installs landing joint, measure space out in Annular, lines up to circulate 8.4 ppg source water down tubing taking returns through choke and MGS once hanger is pulled. Calculated string weight 41.6k. Pressure up Annular on pipe, pick up, hanger free at 20k. Close in Annular fully on pipe. Break circulation with 8.4 ppg water down tubing at 2 bpm, 300 psi. Lined up for returns through choke and MGS. Stage rate to 3.5 bpm, 700-800 psi. Very dirty returns with 112 bbls away (~5 bph loss rate). Continue to circ at 3.5 bpm until no more gas at MGS and returns clean up. Close in, 20 psi on well and slowly increasing. Line up to bullhead with annulus side shut in. Bullhead 50 bbls down tubing at 2.75-3.0 bpm, 780-970 psi. Shut down, bleed off pump and monitor for pressure. Fairly quick rise up to 35-40 psi and stabilize. Line up to bleed trailer, re-seat hanger, bleed annulus to bleed trailer, all gas no fluid. Monitor well while developing plan forward. Lay out and strap workstring. Replace 3" Kelly Hose in derrick to 2" hose - planned operation due to 3" interference with RU of Power Swivel. Monitor well, slight bleed to bleed trailer, all gas. Close in, built back up to 20 psi in 30 min and maintaining 20 - 25 psi. Break circulation down tubing taking returns from annulus through MGS. 47 bbls to get very dirty returns, loss rate has increased from ~5 up to ~10 bph. Circulate a surface-to-surface volume of 567 bbls after returns cleaned up at 4 bpm, 800 psi (released all but Driller and Pump Operator at 1530). Close in, 0 psi initially. Secure well for night. Cumulative total from supply water well 958 bbls. 07/06/2021 - Tuesday Safety meeting, emphasis on no spills during mixing and displacement. Check equipment, IA has 150 psi on it, Tubing 0 psi, SSSV has most likely bled off and is in closed position. Stage in KCL, mix hopper, 500-bbl open top while lining up to fill well. Break circulation, 47 bbls to catch returns through MGS. Circulate across top while weighting up fluid from 8.4 ppg Source Water to 8.6 ppg KCL. Displace well to 8.6 ppg KCL at 6,741' md. With 70 bbls away (~ 2x tubing volume), bullhead 30 bbls in attempt to squeeze 8.6 ppg KCL below tubing cut. Continue mixing and displacing on fly. Displaced total of 597 bbls, fluid weight at end of surface-to-surface circulation 8.7 ppg. Line up to continue circulating across top while pulling completion. Wellhead reps pulling LDS. RU to pull hanger. Hanger free with 31k PUW, lay hanger down. Pull 2-7/8" 6.4" L- 80 EUE completion out of hole. Pull 300' of control line. LD SSSV with pups. Swap out tongs. PUW at 30k. Continue to POH with 2-7/8" tubing. Loss rate to well after displacement at ~25 bph. Cumulative count of water pulled from source well 1,361 bbls. 17 stands out. Secure well for evening. Rig Start Date End Date 6/20/21 8/21/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00-00 215-160 Well Name CLU 05RD 07/07/2021 - Wednesday 07/08/2021 - Thursday Safety meeting with crew, emphasis on opening to well, milling operations, possible gas under packer. Open to well, 0 psi. Took 41 bbls to fill, ~3-1/2 bph loss while static overnight. Continue RIH with Milling BHA #1 on 2-7/8" workstring. Tag up on depth at 6,470'. Pick up, set string in slips, lay down upper joint. RU Power Swivel and hoses. Secure ears, function test. Leak during test. Send man up, leak at grease zert, no ball in zert. Call maintenance rep. Lay down joint and lower Power Swivel to rig floor. Mechanic on site to replace zert. Raise Power Swivel back up into position, make up connection. Function test, no leak. Mill on packer: torque limit set to 4,000 ft/lbs, circ at 2.3 -3.0 bpm, 200-370 psi. Average reactive torque between 2-3k initially with ~5k. Clear indication of milled past elements with gas burp to surface. Continuing with milling varying weight down and pump pressures with less reactive torque of .8 to 1.2. Pick up, attempt to push several times with slight movement. Vary rpm between 30-80 rpm, not seeing reactive tor. Pick up and space out in rams. Send man up, close in TIW. Cumulative source water drawn 1,936 bbls. 07/09/2021- Friday Safety meeting with crew and Fishing rep, emphasis on opening to well, milling ops. Open to well, no pressure, on slight vac. Took 41 bbls to fill with 8.6 ppg KCL. Prep for milling ops. Break circulation at 2 bpm, 300 psi. Move down and begin milling. Vary set down weights and rpm from 30 to 60 rpm, no gain. Calculate 20" into packer which is just above lower anchors. Possibility mill is polished off. Break out joint from string, pull back and secure Power Swivel in derrick at A-leg. POH with 2-7/8" workstring standing back in derrick. Change out handling equipment. Stand back drill collars, lift Milling BHA #1 for inspection. Mill condition shows significant wear (smoothing) of cutrite on ~50% of the face and 30% of the inside. Obvious gouges on ~1/2 of outer gauge where metal debris got caught. One piece of rubber in boot baskets. MU Milling BHA #2: Change out mill to new 6.70" Flat Bottom Shoe on to Drive Sub, 2 ea Boot Baskets, add in 7-5/8" casing scraper, Bumper Sub and Oil Jar. MU 4 ea 4-3/4" Drill Collars out of derrick, OAL 174.73' long. Change out handling equipment. RIH with Milling BHA #2 on 2-7/8" workstring. RU Power Swivel, function test. Secure well for evening. Well took 85 bbls 8.6 ppg KCL. Cumulative volume source water pulled from source well 2,132 bbls. PJSM with crew, emphasis on opening to well, monitoring fluids, handling pipe during tripping. Open to well, no pressure and on vacuum. Line up to fill well. Transfer 8.7 ppg from mix tank to pits, fill well. 67 bbls to fill. SIMOPS: inspect handling equipment for POH. POH with 2-7/8" 6.4# L-80 EUE completion string standing back. 203full jts recovered, cut joint length 5.5'. Move in Skate, swap out handling equipment, stage in milling components BHA. MU lower milling BHA on ground in order to tail-in: 6.70" Flat Bottom Shoe, Drive Sub, 2 ea Boot Baskets, Bumper Sub and Oil Jar. PU and MU 4 ea 4-3/4" Drill Collars, OAL 170.08' long. Well loss is ~18 bph while circulating across top. RIH with Milling BHA on 2-7/8" workstring picking up one by one. Mixing 100 bbl batch of 8.6 ppg KCL for filling well in AM, loss rate has dropped to ~10 bph. Install TIW, hang off at 4,510'. Secure well for evening. Rig Start Date End Date 6/20/21 8/21/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00-00 215-160 Well Name CLU 05RD 07/10/2021 - Saturday PJSM with crew and Fishing rep, emphasis on opening to well, milling and tripping operations, inclimate weather. Open to well, 0 psi, fill well with 41 bbls 8.6 ppg KCL. Record parameters, begin milling. Initial free spin circulation at 1.3 bpm, 125 psi, torque at ~1500 ft / lbs with scraper on. Initiate rotation, mark pipe, set down weight ~6-7k. Initial reactive torque ~500 ft/lbs. Torque falling off even with varying rpm, slack off and circ rates. Pick up several times and not able to gain back reactive torque. Line up to reverse circulate. Reverse 20 bbls in attempt to circ any debris / junk up into Boot Baskets. Line back up for regular circulation. Attempt to gain milling torque, no reaction. RD Power swivel and secure in A- leg. POH standing back 2-7/8" workstring. Stand back Drill Collars. Inspect BHA, very little debris in Boot Baskets. Face of mill in good condition, inside shows markings as if over tubing stub, outer gauge a little smoothed off but still in good cutting condition. Stand back complete assembly. RU Pollard Wireline for cement dump bail run, mix 17 ppg cement. (Release all but two Rig crew - Mill is cooling down from applying cut-rite, can't MU and WoC is 18 hrs). RIH with 5" dump bail with 18' of 17.0 ppg cement with accelerant to cover ~10' in 7-5/8" ID (2.5' tubing stub up and well is on vac). Lay in cement, POH. Reload Bailer, close in, pressure to 200 psi to ensure cement pushed through packer anchor. RIH with second Bailer with 18' of cement to cover ~10' (will retain 2.5' above packer). Lay in second load, POH and RD Wireline. Cum source water used 2,228 bbls. 07/11/2021 - Sunday PJSM with crew on opening to well, transferring fluid, milling operations. Open to well, 0 psi and slight vac, took 25 bbls to catch returns. Submitted notice to AOGCC for Weekly BOP test on Monday morning at 0630 hrs. MU Milling BHA #3 with 6.75" OD 3-blade Piranha mill (Junk Blade with cutrite welded on), 3 each boot baskets, 7-5/8" (6.35" min OD, springs out to 7.0") casing scraper, Bumper Sub, Jar, 4 each drill collars for OAL 170.44'. Change out handling equipment. RIH with Milling BHA #3 on 2-7/8" workstring. Tag at 6,443' workstring MD. Pick up, tag again. Crew in process of rigging up Power Swivel when shut down after looking at schematic, ID of ZXP packer is 6.625", OD of mill is 6.75". Secure Power Swivel back in A-leg. POH with BHA #3. SIMOPS: begin to MU BOP test joint. Received call from AOGCC Rep Jim Regg, gave permission to test early and witness waived. Stand back Milling BHA. Complete prep of test joint, RU for BOP test. Test BOP per Sundry and AOGCC requirements with 2-7/8" test joint to 250 psi low / 2,500 psi high for 5 minutes on Rams and Annular Bag. Conduct Accumulator Drawdown test. MU 6.60" Piranha Mill to existing BHA and hang off with 2-7/8" joint, close in rams to secure well for the evening. Total volume to well today 66 bbls. Cumulative volume of water taken from source well 2,395 bbls. 07/12/2021 - Monday Safety Meeting with crew with emphasis on opening to well, tripping operations. Open to well 0 psi, 26 bbls to fill. Change out tongs on rig floor. RIH with Milling BHA #4 on 2-7/8" workstring. No issues by Liner Top. RU Power Swivel unit, function test. Pick up last joint, MU and RIH to tag stump. Tag up at 6,469'. Pick up and obtain free spin parameters: 2.0 bpm at 320 psi, PUW 41k, SOW 35k, rotate at 65 rpm with free torque 1,500 ft/lbs. Once engaged, 2,100-2,400 ft/lbs of milling torque. Leak at Power Swivel, send man up to inspect / hammer up at packoff seal. Milling ~2 fph, broke loose at just over 2' of milling. Packer is free, begin chasing down with singles rotating with scraper, Mill TD of 6,873'. RD Power Swivel and remove from floor. Swap out handling equipment and RU. POH with 2-7/8" workstring and stand back. Break off and lay down Milling BHA #4. Mill has uneven wear on face, one blade worn down, other two in remarkably good shape. Close in Blinds, secure well for evening. Well on slight vac all day. Rig Start Date End Date 6/20/21 8/21/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00-00 215-160 Well Name CLU 05RD 07/13/2021 - Tuesday Safety Meeting with crew and third party personnel, emphasis on monitoring well conditions, overhead loads working with BHA, tripping ops. Open to well, 0 psi, 25 bbls to fill.;MU Permanent Packer completion: Mule shoe, Landing Nipple with 2.313" ID, Seal bore assembly, 7-5/8" x 4" Permapak Packer (with Setting sleeve, setting tool that will POH). RIH with Packer on 2-7/8" workstring. Set on depth, Muleshoe at 6,883' and PermaPak packer at 6,850'. Drop 1" ball, rig up to circulate. Break circulation, pressure up to set hanger and shear from running tool. Breakover at 2595 psi, clear indication of shear. Pick up, released from running tool. Set down 5k, confirm set. RD from circulation.;POH with 2-7/8" workstring laying down 1 by 1. LD Packer running tools. Swap out handling equipment for running tubing. Stage in upper completion to skate. Secure well for evening. 07/14/2021 - Wednesday PJSM with crew, emphasis on opening to well, tripping operations, pressure testing. Open to well 0 psi, 15 bbls to fill. MU Snap Latch Assembly and RIH on 7 stands of 2-7/8" 6.5# L-80 EUE tubing. MU Landing Nipple and 9-5/8" x 4-1/2" Hydraulic Packer assemblies. Continue to RIH on stands of 2-7/8" EUE tubing. MU SSSV assembly and continue to RIH on tubing with control line to surface. RIH with two joints, tag and mark. Pick up to unsting, sting back in to confirm. Space out, MU hanger with landing joint, land out and RILDS. Drop rod. With rod falling, MU circulation equipment and grease pack / test hanger void. Pressure up to 3800 psi to set packer. Conduct 3,000 psi MIT-Tubing for 30 minutes on chart, loss of 75 psi, good test. Bleed off, swap over to test IA to 1,500 psi for 30 minutes on chart, 0 psi loss, good test. Prep to ND BOP. Install TWC, ND BOP while removing equipment from floor, remove floor. Prep for NU Tree, stage to side. NU Tree. Test void to 5,000 psi, good test. Pump open SSSV. Total volume drawn from Source Well on CLU is 2,489 bbls. Well is fluid packed with 8.6 ppg KCL, ball and rod left in well in packer profile at 6,368'. 08/09/2021 - Monday PTW, JSA with crew. MIRU Petrospec CTU 131 with 1.75" coil. 24 hr BOPE test witness notification sent 8/8/21 @ 1614 hrs. Witness waived by Jim Regg 8/8/21 @ 1730 hrs. Start BOPE test. Test all rams and valves 250/4,000 psi. Rig back CTU. 08/10/2021 - Tuesday PTW, JSA with personnel. Pick injector head and install roll on coil connector, DFCV, 1.90" jet swirl nozzle. (CC pull tested to 35k). Stab on well. Fluid pack stack and pressure test 250/4,000 psi. Open master and swab 23.5 turns. WHP 120 psi. Previous day pad operator bleed well down through production facility. Upon opening well and performing the tree walk down noticed SSSV was shut. Start RIH with coil. Pumped SSSV up to 3,200 psi. When CT reached 300' CTMD. Large surge of gas noticed at return tank. WHP 1,500 psi. Pinch in choke. Previous well work operations used CLU-14 gas of 1,847 psi to attempt to unload fluid through cap string. The previous days attempt at bleeding gas off well was bleed off from a closed SSSV to surface. Continue RIH with coil. 8,000' weight check 12.5K. Continue in hole for a dry tag. Tagged at 8,154' CTMD. Clean pick up. Online with N2. Pick up to tubing tail until returns of water and nitrogen are seen at surface. Initial lift only returned. 12 bbls of fluid. Work back down at stack 5K at previous depth of 8,154' CTMD. Weight broke back and traveled to 8,158' CTMD. Pick up 1' off bottom and continue to lift well with N2 @ 800 scf/min. Slugs of water. Call town to discuss. POOH to surface and let well fill up overnight giving us a possible water influx rate. Night operator will continue to ensure WHP is 0 to help build a column of fluid. Shut down n2 and bleed WHP through choke. Total fluid returned 26 bbls. N2 pumped 112,454 SCF. RIg back equipment. SDFN. Rig Start Date End Date 6/20/21 8/21/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00-00 215-160 Well Name CLU 05RD 08/20/2021- Friday Spot Equipment. PTW and JSA. Rig up lubricator, PT 250 psi low and 2,500 psi high. TP - 1014 psi. RIH w/ Gun #1, 2-1/8" x 10' Spiral, 6 spf, ~ 45 deg phase perf gun and tie into OHL. Run correlation log and send to town. Get ok to perf from 7,778' to 7,788' w/1,042.5 psi. Spotted and fired gun. After 5 min - 1,043.1 psi, 10 min - 1,043.1 psi and 15 min 1,041 psi. POOH. All shots fired/gun wet. MB_7A sand. RIH w/Gun #2, 2-1/8" x 8' Spiral, 6 spf, ~ 45 deg phase perf gun and tie into OHL. Run correlation log and send to town. Told to add 1' and perf from 7,759' to 7,767' w/1,055.4 psi. Fired gun and after 5 min - 1,055.4 psi, 10 min - 1,055.9 psi - 15 min -1,054.4. POOH. All shots fired/Gun wet. MB_7A sand. RIH w/Gun #3, 2-1/8" x 5'' Spiral, 6 spf, ~ 45 deg phase perf gun and tie into OHL. Run correlation log and send to town. Get ok to perf from 7,745' to 7,750' w/1,067.7 psi. Spotted and fired gun. After 5 min - 1,068.9 psi, 10 min - 1,068.6 psi and 15 min - 1,067.8 psi. POOH. All shots fired/Gun was wet. MB_7A sand. While picking the 15' strip gun up it got bent. Tried a different ways of straighten it but was unsuccessful. Called town and decision made to shoot the last gun (18') tonight. Yellowjacket will build another 15' gun and will shoot it in the morning. RIH w/Gun #4, 2-1/8" x 18' Spiral, 6 spf, ~ 45 deg phase perf gun and tie into OHL. Run correlation log and send to town. Get ok to perf from 7,335' to 7,353' w/1,089 psi. Spotted and shot gun. After 5 min - 1,130 psi (stuck at nipple at 6,871' and got free), 10 min - 1,143.7 psi and 15 min - 1,152.5 psi. POOH. Left approx. 15' of strip in the hole. Lay lubricator down and secure well. Will be back in AM. 08/21/2021 - Saturday Spot Equipment. PTW and JSA. Rig up lubricator, PT 250 psi low and 2,500 psi high. TP - 1,740 psi. RIH w/Gun #1, 2-1/8" x 15' Spiral, 6 spf, ~ 45 deg phase perf gun and tie into OHL. Run correlation log and send to town. Get ok to perf from 7,372' to 7,387' w/1,796.6 psi. Spot and fired gun. After 5 min - 1,825.9 psi, 10 min - 1,844 psi and 15 min - 1,856.1 psi. POOH. All shots fired and gun wet. Rig down lubricator, equipment and turn well over to field. 08/11/2021 - Wednesday PTW, JSA with crew. Pick injector head and make up lubricator. Stab on well. PT stack 250/4,000 psi. Open master swab 23.5 turns. WHP 0 psi, IA 0 psi, OA 0 psi. RIH Dry tag 8,150' CTMD hard tag. RKB 8,157'. Calculated TOC is 8,328' RKB. LB- 1F still covered. Pick up online with N2 1,500 scf/min. Increase to 2,500 scf/min. Circ pressure 2,500 psi. N2 at surface. 13 bbls returned from well. Pick up to 8,000'. Hot oil truck and vac truck loaded with produced water. Online down coil with produced water at 2 bbls/min 3,500 psi. Fill reel with 19.2 bbls RIH for FCO to open LB-1F perfs. Washed from 8,150' to 8,163' and tagging hard. Continue to wash. Not able to make hole past 8,163' CTMD or 8,170 RKB. Fluid returns to surface are 1:1 and fair amount of sand. Out of fluid. Online with N2 CT remains at 8,164' CTMD. Increase N2 rate to 2,500 scf/min. Circ pressure 2,800 psi. Not able to pass 8,164'. Previous slick line attempts had metal marks on bailer at same depth. Pumped 80 bbls for FCO and returned same with N2. Returns all N2. POOH to surface with coil. Close choke to pressure up well and inject N2 into formation. Max N2 pressure seen was 3,100 psi. N2 broke over and was a static 2,730 psi when shut in at surface. 1,286 gallons used of N2 to pressure up and inject into formation. No alarms of LEL during FCO or N2 lift seen at return tank. 2730 WHP SITP. Rig down Petrospec CTU. _____________________________________________________________________________________ Updated by DMA 09-10--21 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Unit Well: CLU 05RD API: 50-133-20474-01-00 PTD: 215-160 PBTD = 8,328’ MD / 6,897’ TVD TD = 12,940’ MD / 11,253’ TVD 11 3,4 17 20” RKB = 18’ 2 8-1/2” window at 6,527’ MD 5,354’ TVD 9-5/8” 4-1/2” 1 7-5/8” 13-3/8” 20 19 18 16 5 6 14 15 9 10 12,13 21 7 8 - d i RA Mkr Jt 11,090’ RA Mkr Jt 11,633’ RA Mkr Jt 12,060’ RA Mkr Jt 12,474’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf ~6,883’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 299’ 2.441” 7.110” Safety Valve 3 6,368’ 3.980” - 9-5/8” Hydraulic Retrievable Packer 4 6,390’ 2.313” - 2-7/8” X Landing Nipple 5 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 6 6,848’ 4.000” - 7-5/8” Permanent Packer 7 6,871’ 2.313” - 2-7/8” X Landing Nipple 8 6,883’ 2.450” - 2-7/8” WLEG 9 8,355’ - 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 10 10,208’ - 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 11 10,230’ - 7.625” CIBP 6/17/20 12 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 13 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 14 10,279’ - 4.500” CIBP 6/15/20 15 10,349’ - 4.500” CIBP 16 11,170’ - 3.500” CIBP (TOC 11,170’) 17 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 18 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 19 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 20 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 21 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Isolated UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Isolated UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Isolated MB_4 7,335' 7,353' 6,073' 6,091' 18' 05/04/21 2” Open 7,335' 7,353' 6,073' 6,091' 18' 08/20/21 2” Open 7,372' 7,387' 6,102' 6,117' 15' 05/04/21 2” Open 7,372' 7,387' 6,102' 6,117' 15' 08/21/21 2” Open MB_7A 7,745' 7,750' 6,413' 6,418' 5' 05/04/21 2” Open 7,745' 7,750' 6,413' 6,418' 5' 08/20/21 2” Open 7,759' 7,767' 6,424' 6,432' 8' 05/04/21 2” Open 7,759' 7,767' 6,424' 6,432' 8' 08/20/21 2” Open 7,778' 7,788' 6,440' 6,450' 10' 05/04/21 2” Open 7,778' 7,788' 6,440' 6,450' 10' 08/20/21 2” Open LB_1B 8,023' 8,029' 6,643' 6,649' 6' 04/15/21 2” Open LB_1C 8,038' 8,056' 6,656' 6,674' 18' 04/15/21 2” Open LB_1D 8,074' 8,079' 6,686' 6,691' 5' 04/15/21 2” Open LB_1F 8,137' 8,149' 6,738' 6,750' 12' 04/15/21 2” Open 8,196' 8,203' 6,787' 6,794' 7' 04/15/21 2” Open LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated 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: 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,940'N/A Casing Collapse Conductor Surface 1,540psi Intermediate 6,620psi Intermediate 5,300psi Liner 4,790psi Liner 7,500psi Packers and SSSV Type: Baker T-E5 SSSV Packers and SSSV MD (ft) and TVD (ft): SSSV: 299' (MD) 299' (TVD) 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 12,915' 142' 9-5/8"1,212' 2,970' 10,448' 142' 2,970' 20" 13-3/8" Perforation Depth MD (ft): 1,212' 4,015' 4-1/2" 7,966' 1,200' 8,762'7-5/8" 9-5/8"9,178' Burst 6,883' 6,890psi MD 7,930psi 8,430psi 3,090psi 142' 2,578' Length Size CO 231A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE Hilcorp (ADL060569) / ADL324602 215-160 50-133-20474-01-00 Cannery Loop Unit (CLU) 05RD Kenai C.L.U. / Beluga Gas Pool Tubing Grade: Tubing MD (ft): See Attached Schematic August 25, 2021 Retr 9-5/8: x 2-7/8" Pkr, Perm 7-5/8" x 2-7/8" Pkr Pkrs: 6,368' (MD) 5,201' (TVD) / 6,848' (MD) 5,656' (TVD) 6.4# / EUE 8RDSee Attached Scheamtic 2,675' 2-7/8" 11,229' Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 7,599' 9,440psi todd.sidoti@hilcorp.com 11,253'10,349'8,663'2,307 See Schematic eee d ed ss No ss No Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 7:55 am, Aug 17, 2021 321-403 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.16 16:09:24 -08'00' Taylor Wellman (2143) SFD 8/17/2021 DSR-8/17/21BJM 8/17/21 10-404 dts 8/18/2021 JLC 8/18/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.18 11:46:30 -08'00' RBDMS HEW 8/19/2021 Well Prognosis Well: CLU 05RD Date: 8/12/2021 Well Name: CLU 05RD API Number: 50-133-20474-01-00 Current Status: Gas Well Leg: N/A Estimated Start Date: August 25, 2021 Rig: Eline Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) AFE Number: Current BHP: ~2986 psi @ 5,200’ TVD (Based on normal gradient) Max. Potential Surface Pressure: ~2307 psi (Based on BHP – 0.1 psi/ft gradient) Current Situation CLU 05RD was worked over in July, 2021 in order to shut off water production. The water producing UB4 and UB7 zones were straddled off with packers. During the workover a large volume of fluid was lost (2000 bbls). The purpose of this work is to Re-perforate the Middle Beluga sands in attempt to overcome formation damage induced by water. Notes Regarding Wellbore Condition x Max deviation: 49 degrees at 3411’ MD. x SL tagged TOC @ 8210 SLMD on 3-13-2021. x Minimum ID: 2.31”, 2-7/8” X nipple @ 6485’ MD. Eline Procedure: 1. MIRU Eline unit. Pressure test lubricator to 250 psi low / 3000 psi high. 2. RIH and perforate the following intervals with 2-1/8” spiral strip guns. o Re-perforate the Middle Beluga sands Well Prognosis Well: CLU 05RD Date: 8/12/2021 Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Estimated Reservoir Pressure MB_4 ±7,335' ±7,353' 18' ±6,073' ±6,091' 2500 MB_4 ±7,372' ±7,387' 15' ±6,102' ±6,117' 2500 MB_7A ±7,745' ±7,750' 5' ±6,413' ±6,418' 1500 MB_7A ±7,759' ±7,767' 8' ±6,424' ±6,432' 1500 MB_7A ±7,778' ±7,788' 10' ±6,440' ±6,450' 1500 3. Turn well over to production. Attachments: 1. Current Schematic _____________________________________________________________________________________ Updated by TCS 07-21-21 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 PBTD = 8,355’ MD / 6,919’ TVD TD = 12,940’ MD / 11,253’ TVD 11 3,4 17 20” RKB = 18’ 2 8-1/2” window at 6,527’ MD 5,354’ TVD 9-5/8” 4-1/2” 1 7-5/8” 13-3/8” 20 19 18 16 5 6 14 15 9 10 12,13 21 7 8 RA Mkr Jt 11,090’ RA Mkr Jt 11,633’ RA Mkr Jt 12,060’ RA Mkr Jt 12,474’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf ~6,883’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 2.441” 7.110” Safety Valve 3 ~6,368’ 2.441” - 9-5/8” x 2-7/8” Retrievable Packer 4 ~6,390’ 2.313” - 2-7/8” X Profile Landing Nipple 5 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 6 ~6,848’ 2.441” - 7-5/8” x 2-7/8” Permanent Packer 7 ~6,871’ 2.313” - 2-7/8” X Profile Landing Nipple 8 ~6,883’ 2.441” - 2-7/8” WLEG 9 8,355’ - 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 10 10,208’ - 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 11 10,230’ - 7.625” CIBP 6/17/20 12 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 13 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 14 10,279’ - 4.500” CIBP 6/15/20 15 10,349’ - 4.500” CIBP 16 11,170’ - 3.500” CIBP (TOC 11,170’) 17 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 18 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 19 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 20 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 21 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Isolated UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Isolated UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Isolated MB_4 7,335' 7,353' 6,073' 6,091' 18' 05/04/21 2” Open 7,372' 7,387' 6,102' 6,117' 15' 05/04/21 2” Open MB_7A 7,745' 7,750' 6,413' 6,418' 5' 05/04/21 2” Open 7,759' 7,767' 6,424' 6,432' 8' 05/04/21 2” Open 7,778' 7,788' 6,440' 6,450' 10' 05/04/21 2” Open LB_1B 8,023' 8,029' 6,643' 6,649' 6' 04/15/21 2” Open LB_1C 8,038' 8,056' 6,656' 6,674' 18' 04/15/21 2” Open LB_1D 8,074' 8,079' 6,686' 6,691' 5' 04/15/21 2” Open LB_1F 8,137' 8,149' 6,738' 6,750' 12' 04/15/21 2” Open 8,196' 8,203' 6,787' 6,794' 7' 04/15/21 2” Open LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated 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: Install Cap String 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,940'N/A Casing Collapse Conductor Surface 1,540psi Intermediate 6,620psi Intermediate 5,300psi Liner 4,790psi Liner 7,500psi Packers and SSSV Type: Baker T-E5 SSSV Packers and SSSV MD (ft) and TVD (ft): SSSV: 299' (MD) 299' (TVD) 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 7,599' 9,440psi todd.sidoti@hilcorp.com 11,253'10,349'8,663'2,307 See Schematic 2,675' 2-7/8" 11,229' Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Authorized Title: Tubing Grade:Tubing MD (ft): See Attached Schematic July 25, 2021 Retr 9-5/8: x 2-7/8" Pkr, Perm 7-5/8" x 2-7/8" Pkr Pkrs: 6,368' (MD) 5,201' (TVD) / 6,848' (MD) 5,656' (TVD) 6.4# / EUE 8RDSee Attached Scheamtic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE Hilcorp (ADL060569) / ADL324602 215-160 50-133-20474-01-00 Cannery Loop Unit (CLU) 05RD Kenai C.L.U. / Beluga Gas Pool Length Size CO 231A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY TVD Burst 6,525' 6,890psi MD 7,930psi 8,430psi 3,090psi 142' 2,578' Perforation Depth MD (ft): 1,212' 4,015' 4-1/2" 7,966' 1,200' 8,762'7-5/8" 9-5/8" 9,178' 12,915' 142' 9-5/8"1,212' 2,970' 10,448' 142' 2,970' 20" 13-3/8" Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 11:18 am, Jul 21, 2021 321-361 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.21 11:09:57 -08'00' Taylor Wellman (2143) 10-404 SFD 7/21/2021 DSR-7/21/21BJM 7/26/21 The well must be continuously manned while the capstring is installed. dts 7/26/2021 JLC 7/26/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.26 15:26:20 -08'00' RBDMS HEW 7/28/2021 Well Prognosis Well: CLU 05RD Date: 7/21/2021 Well Name: CLU 05RD API Number: 50-133-20474-01-00 Current Status: Gas Well Leg: N/A Estimated Start Date: July 25, 2021 Rig: N/A Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Todd Sidoti (907) 777-8443 (O)(907) 632-4113 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (O)(985) 867-0665 (M) AFE Number: Current BHP: ~2986 psi @ 5,200’ TVD (Based on normal gradient) Max. Potential Surface Pressure: ~2307 psi (Based on BHP – 0.1 psi/ft gradient) Current Situation CLU 05RD was worked over in July, 2021 in order to shut off water production. The water producing UB4 and UB7 zones were straddled off with packers. During the workover a large volume of fluid was lost (2000 bbls). The purpose of this work/sundry is to install a Capillary line in the well to allow for gradual unloading of fluid from the well until it is able to flow to surface. Notes Regarding Wellbore Condition x Max deviation: 49 degrees at 3411’ MD. x SL tagged TOC @ 8210 SLMD on 3-13-2021. x Minimum ID: 2.31”, 2-7/8” X nipple @ 6485’ MD. x SSV is installed on a horizontal run and will not be defeated by the capillary string. Capillary Truck Procedure: 1. MIRU Dyna Coil Unit. 2. Remove tree cap and install wellhead pack-off assembly. 3. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 4. RIH with 3/8” capillary string to ±8,275’ MD or as deep as possible before lock-up. 5. Install slips, stand back injector and remove spool. 6. Install double block and bleed to cap string and route to a gas diffuser return tank. 7. RD Dyna Coil Unit. 8. Turn well over to production. Operations: 1. Jumper gas from CLU-14 to CLU 05RDs flow line in order to evacuate water. 2. Operator must be on location actively monitoring returns during this operation. 3. This operation may continue for a number of days depending on unloading rate and volume of water necessary to recover.. 4. Once enough water has been removed and the well will flow unassisted, shut-in cap string. Capillary Truck Procedure: Operator must be on location actively monitoring returns during this operation. Install check valve adjacent to the companion valve (wing valve) to protect against backflow into the jumper line from CLU-05RD. - bjm See attached RU diagram. Well Prognosis Well: CLU 05RD Date: 7/21/2021 1. MIRU Dyna Coil Unit. 2. Pull slips and POH with 3/8” capillary string. 3. Remove wellhead pack-off assembly and install tree cap. 4. RD Dyna Coil Unit. 5. Turn well over to production. Attachments: 1. Current Schematic _____________________________________________________________________________________ Updated by TCS 07-21-21 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 PBTD = 8,355’ MD / 6,919’ TVD TD = 12,940’ MD / 11,253’ TVD 11 3,4 17 20” RKB = 18’ 2 8-1/2” window at 6,527’ MD 5,354’ TVD 9-5/8” 4-1/2” 1 7-5/8” 13-3/8” 20 19 18 16 5 6 14 15 9 10 12,13 21 7 8 RA Mkr Jt 11,090’ RA Mkr Jt 11,633’ RA Mkr Jt 12,060’ RA Mkr Jt 12,474’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf ~6,883’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 2.441” 7.110” Safety Valve 3 ~6,368’ 2.441” - 9-5/8” x 2-7/8” Retrievable Packer 4 ~6,390’ 2.313” - 2-7/8” X Profile Landing Nipple 5 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 6 ~6,848’ 2.441” - 7-5/8” x 2-7/8” Permanent Packer 7 ~6,871’ 2.313” - 2-7/8” X Profile Landing Nipple 8 ~6,883’ 2.441” - 2-7/8” WLEG 9 8,355’ - 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 10 10,208’ - 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 11 10,230’ - 7.625” CIBP 6/17/20 12 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 13 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 14 10,279’ - 4.500” CIBP 6/15/20 15 10,349’ - 4.500” CIBP 16 11,170’ - 3.500” CIBP (TOC 11,170’) 17 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 18 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 19 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 20 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 21 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Isolated UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Isolated UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Isolated MB_4 7,335' 7,353' 6,073' 6,091' 18' 05/04/21 2” Open 7,372' 7,387' 6,102' 6,117' 15' 05/04/21 2” Open MB_7A 7,745' 7,750' 6,413' 6,418' 5' 05/04/21 2” Open 7,759' 7,767' 6,424' 6,432' 8' 05/04/21 2” Open 7,778' 7,788' 6,440' 6,450' 10' 05/04/21 2” Open LB_1B 8,023' 8,029' 6,643' 6,649' 6' 04/15/21 2” Open LB_1C 8,038' 8,056' 6,656' 6,674' 18' 04/15/21 2” Open LB_1D 8,074' 8,079' 6,686' 6,691' 5' 04/15/21 2” Open LB_1F 8,137' 8,149' 6,738' 6,750' 12' 04/15/21 2” Open 8,196' 8,203' 6,787' 6,794' 7' 04/15/21 2” Open LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564.4422 Received By: Date: DATE: 07/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU-05RD (PTD 215-160) Jet Cut Record 06/25/2021 Please include current contact information if different from above. Received By: 07/15/2021 37' (6HW By Abby Bell at 3:38 pm, Jul 15, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 06/22/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company CLU 05RD 501332047401 215160 6/15/2021 SET PLUG Yellowjacket CLU-06RD 501332049201 220074 1/26/2021 PERF Yellowjacket CLU-06RD 501332049201 220074 1/28/2021 GPT Yellowjacket CLU 14 501332068400 219078 7/23/2020 SET PLUG/PERF Yellowjacket CLU-15 501332068700 220003 5/27/2020 PERF Yellowjacket Please include current contact information if different from above. 06/28/2021 eceived By: 37' (6HW By Abby Bell at 11:55 am, Jun 28, 2021 David Douglas Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Hilcorp North Slope, LLC Date: 05/26/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type CLU 01RD 50133203230100 203129 4/29/2021 PERF GAMMA RAY CLU 05RD 50133204740100 215160 4/15/2021 PERF GAMMA RAY CLU 05RD 50133204740100 215160 5/4/2021 PERF GAMMA RAY Please include current contact information if different from above. PTD: 2151600 E-Set: 35173 06/01/2021 David Douglas Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Hilcorp North Slope, LLC Date: 05/26/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type CLU 01RD 50133203230100 203129 4/29/2021 PERF GAMMA RAY CLU 05RD 50133204740100 215160 4/15/2021 PERF GAMMA RAY CLU 05RD 50133204740100 215160 5/4/2021 PERF GAMMA RAY Please include current contact information if different from above. PTD: 2151600 E-Set: 35174 06/01/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,940 feet feet true vertical 11,253 feet N/A feet 6,433; Effective Depth measured 8,355 feet 6,471;10,240 feet true vertical 6,919 feet 5,263; 5,300; feet 8,555 Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.4# / L-80 6,525' MD 5,353' TVD Baker ZXP + Ret Pkr + Baker ZXPN Pkrs 6,433' MD/5,263' TVD; 6,471' MD/5,300' TVD; 10,240' MD/8,555' TVD Packers and SSSV (type, measured and true vertical depth)Baker TE-5 SSSV TR 298' MD/ 298' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst 6,890psi 142' 1,200' Casing Collapse 1,540psi 6,620psi 4,790psi See Attached 20" 13-3/8" 9-5/8" Length 2,578' 142' 2,970' 1,212' 4,015' Conductor Surface Intermediate Liner Intermediate 7,966' 0 Representative Daily Average Production or Injection Data 7,500psi Gas-Mcf 579 39 Authorized Signature with date: Authorized Name: 60 Casing Pressure 2. Operator Name:Hilcorp Alaska, LLC Plugs Junk 0 Cannery Loop Unit (CLU) 05RD 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-154 62 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Tubing Pressure STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-160 50-133-20474-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: FEE Hilcorp (ADL060569); ADL324602 1,212' 9-5/8"7,599' measured measured true vertical Liner 2,675' 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai C.L.U. / Beluga Gas PoolN/A measured TVD 263 9,178' Oil-Bbl Packer 7-5/8" 4-1/2" 10,448' 9,440psi 5,300psi 11,229' 8,762' 7,930psi 3,090psi WINJ WAG 0 Water-Bbl MD 142' 2,970' 12,915' N/A 307 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:19 am, May 26, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.25 15:45:19 -08'00' Taylor Wellman (2143) RBDMS HEW 6/9/2021 SFD 5/26/2021DSR-5/26/21BJM 9/27/21 Rig Start Date End Date 4/15/21 5/4/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00-00 215-160 Well Name CLU 05RD Daily Operations: Spot equipment. PTW and JSA. Rig up lubricator. PT lubricator to 250 psi low and 3,000 psi high. TP - 872.9 psi. MU and arm 3 gun sizes with switches. Attempt to go in hole and stop at tubing hanger. Did some double checking and found out we had 2-7/8" tubing in hole instead of 4-1/2". Called town and discussed. Roy w/Yellowjacket went back to his shop to see about getting right guns. Lay guns and lubricator down and secure well. Break the three guns apart and take out the switches. Do a walk around and clean up work place. TP is 809.7 psi. 05/04/2021 - Tuesday PTW and JSA, Rig equipment and lubricator back up while pressuring well back up to 800 psi. PT from 250 psi low and 3,000 psi high. RIH w/ gun #1, 2"x10', HC, 6 SPF, 60 deg phase (7,778' to 7,788'), switch, gun #2, 2" x 8' HC (7,759' to 7,767'), switch, gun #3 2"x5'HC (7,745' to 7,750') and tie into OHL. Run correlation log and send to town. Get ok to perf all 3 guns. Spot and fire gun #1 with 795.7 psi, spot and attempt to fire both #2 and #3 gun. Did not fire POOH. Found detonator wires cut into. #1 gun fired but 2 and 3 didn't. Gun was wet RIH w/ gun #2, 2"x8'', HC, 6 SPF, 60 deg phase (7,759' to 7,767'), switch, gun #3, 2" x5' HC (7,745' to 7,750'), Spot and fire gun #2 with 757 psi, pull up and fired gun #3 with 756.3 psi. After 5 min - 756.4 psi, 10 min - 757.2 psi and 15 min - 757.4 psi. POOH. All shots fired/gun was wet RIH w/Gun #4, 2" x 14' HC 6 spf, 60 deg phase (7,372' to 7,386'), switch, gun #5, 2'x18' HC (7,335' to 7,353'), run correlation log and send to town. Get ok to perforate both guns. Spot and fire gun #4 w/730.2 psi, move up hole, spot and fire gun #5 w/731 psi. After 5 min - 732 psi, 10 min - 744 psi and 15 min - 750 psi. POOH. All shots fired/gun wet. Rig down lubricator and wireline valves off tree. Break down wireline tools. and load up equipment. Clean up work area and do a walk around. 04/15/2021 - Thursday PTW, JSA and SIMOPS w/YellowJacket/Fox Energy (N2). Spot and rig up equipment, hard lines, lubricator etc. PT to 250 psi low and 4,000 psi high. TP - 880 psi. Pressure tubing up to 1,820 psi while going in hole w/N2. Turned Fox N2 loose after press up to 1,830 psi. Pump 452 gals N2 RIH w/Gun #1, 2" x 7' Razar HC, 6 spf, 60 deg phase, Gun #2 , 2" x 12' Razor, 6 spf, 60 deg phase and tie into CBL Log. Run correlation and send to town. Told to add 2'. Added 2' and perf gun #1 from 8,196' to 8,203' (7') , move up and shot gun #2 from 8,137' to 8,149' (12') w/ 1,785 psi. After 5 min - 1,813 psi, 10 min - 1,795 psi and 15 min - 1,783 psi. POOH. All shots fired/gun was wet. Guns fired with switches. RIH w/Gun #3, 2" x 5' Razar HC, 6 spf, 60 deg phase, Gun #4 , 2" x 18' Razor, 6 spf, 60 deg phase and tie into Perf Log. Run correlation and send to town. Got ok to perf Gun 3 from 8,074' to 8,079' (5') and gun #4 from 8,038' to 8,056' (18'). Spotted Gun 3 and Gun 4 w/ 1,695 psi on tubing. Fired gun #3 first and the gun #4 w/ 1,695 psi. After 5 min - 1,694 psi, 10 min - 1,690 psi and 15 min - 1,689 psi. POOH. All shots fired/Gun wet. Guns were fired with switches. RIH w/Gun #5, 2" x 6' Razar HC, 6 spf, 60 deg phase and tie into Perf Log. Run correlation log and send to town. Told to shift down 1'. Shift down 1', spot and fire gun from 8,023' to 8,029' w/ 1,676.2 psi. After 5 min - 1,675.8 psi, 10 min - 1,675.1 psi and 15 min - 1,674.6 psi. POOH All shots fired/gun was wet. Rig down lubricator off tree, secure the well and turn well over to field. 05/03/2021 - Monday (7,745' to 7,750'), S shot gun #2 from 8,137' to 8,149' (12') w (7,335' to 7,353' o perf Gun 3 from 8,074' to 8,079' (5') and gun #4 from 8,038' to 8,056' (18'). S perf gun #1 from 8,196' to 8,203' (7') , (7,372' to 7,386' (7,759' to 7,767' . #1 gun fired but 2 and 3 didn't. Gun w spot and fire gun from 8,023' to 8,029' w (7,778' to 7,788'), _____________________________________________________________________________________ Updated by TCS 05-18-21 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 PBTD = 8,355’ MD / 6,919’ TVD TD = 12,940’ MD / 11,253’ TVD 9 3 15 UB-7B Upper 20” RKB = 18’ 2 8-1/2” window at 6,527’ MD 5,354’ TVD 9-5/8” 4-1/2” 1 7-5/8” 13-3/8” UB-7B Lower D-6 LB-2B D-5A D-6A 18 17 D-5 16 D-2C D-4A D-3A 14 91-2 4 5 6 UT-9B 12 UB-4B 13 7 8 10, 11 19 - ’ RA Mkr Jt 11,090’ RA Mkr Jt 11,633’ RA Mkr Jt 12,060’ RA Mkr Jt 12,474’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf 6,525’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 2.441” 7.110” Safety Valve 3 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 4 6,471’ D&L 7-5/8” x 4” Permanent Pkr 6/26/20 5 6,485’ 2.310 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 6,525’ 2-7/8” WLEG 7 8,355’ 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 8 10,208’ 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 9 10,230’ 7.625” CIBP 6/17/20 10 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 11 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 12 10,279’ 4.500” CIBP 6/15/20 13 10,349’ 4.500” CIBP 14 11,170’ - 3.500” CIBP (TOC 11,170’) 15 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 16 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 17 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 18 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 19 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Open UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Open UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Open MB_4 7,335' 7,353' 6,073' 6,091' 18' 05/04/21 2” Open 7,372' 7,387' 6,102' 6,117' 15' 05/04/21 2” Open MB_7A 7,745' 7,750' 6,413' 6,418' 5' 05/04/21 2” Open 7,759' 7,767' 6,424' 6,432' 8' 05/04/21 2” Open 7,778' 7,788' 6,440' 6,450' 10' 05/04/21 2” Open LB_1B 8,023' 8,029' 6,643' 6,649' 6' 04/15/21 2” Open LB_1C 8,038' 8,056' 6,656' 6,674' 18' 04/15/21 2” Open LB_1D 8,074' 8,079' 6,686' 6,691' 5' 04/15/21 2” Open LB_1F 8,137' 8,149' 6,738' 6,750' 12' 04/15/21 2” Open 8,196' 8,203' 6,787' 6,794' 7' 04/15/21 2” Open LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated MB_4 7,335'7,353'6,073'6,091'18'05/04/21 2” Open 7,372'7,387'6,102'6,117'15'05/04/21 2” Open MB_7A 7,745'7,750'6,413'6,418'5'05/04/21 2” Open 7,759'7,767'6,424'6,432'8'05/04/21 2” Open 7,778'7,788'6,440'6,450'10'05/04/21 2” Open LB_1B 8,023'8,029'6,643'6,649'6'04/15/21 2” Open LB_1C 8,038'8,056'6,656'6,674'18'04/15/21 2” Open LB_1D 8,074'8,079'6,686'6,691'5'04/15/21 2” Open LB_1F 8,137'8,149'6,738'6,750'12'04/15/21 2” Open 8,196'8,203'6,787'6,794'7'04/15/21 2” Open ,,,,///p ’’’/”//’ 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: Recomplete, CTU, N2 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,940'N/A Casing Collapse Conductor Surface 1,540psi Intermediate 6,620psi Intermediate 5,300psi Liner 4,790psi Liner 7,500psi Packers and SSSV Type: Baker T-E5 SSSV Packers and SSSV MD (ft) and TVD (ft): 298' (MD) 298' (TVD) 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 7,599' 9,440psi todd.sidoti@hilcorp.com 11,253'10,349'8,663'2,307 See Schematic 2,675' 2-7/8" 11,229' Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Authorized Title: Tubing Grade:Tubing MD (ft): See Attached Schematic June 10, 2021 Baker ZXP + Perm Pkr + ZXPN Packer 6,433' (MD) 5,263' (TVD) / 6,471' (MD) 5,300' (TVD) / 10,240' (MD) 8,555' (TVD) 6.4# / EUE 8RDSee Attached Scheamtic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE Hilcorp (ADL060569) / ADL324602 215-160 50-133-20474-01-00 Cannery Loop Unit (CLU) 05RD Kenai C.L.U. / Beluga Gas Pool Length Size CO 231A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY TVD Burst 6,525' 6,890psi MD 7,930psi 8,430psi 3,090psi 142' 2,578' Perforation Depth MD (ft): 1,212' 4,015' 4-1/2" 7,966' 1,200' 8,762'7-5/8" 9-5/8" 9,178' 12,915' 142' 9-5/8"1,212' 2,970' 10,448' 142' 2,970' 20" 13-3/8" Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:19 am, May 26, 2021 321-257 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.25 15:34:55 -08'00' Taylor Wellman (2143) X BJM 6/8/21 DSR-5/26/21 MIT-IA to 2400 psi. Provide 24 hr notice to witness MIT-T and MIT-IA. SFD 5/26/2021 10-404 BOP test to 2500 psi. X dts 6/9/2021 JLC 6/9/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.09 14:51:11 -08'00' RBDMS HEW 6/10/2021 Well Prognosis Well: CLU 5RD Date: 5/14/2021 Well Name: CLU 5RD API Number: 50-133-20474-01-00 Current Status: Gas Well Leg: N/A Estimated Start Date: 6/10/2021 Rig: 401 Reg. Approval Req’d? 10-403 Sundry Number: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) AFE Number Maximum Expected BHP: ~2986 psi @ 6787’ TVD Based on normal gradient Max. Potential Surface Pressure: ~2307 psi Based on BHP minus 0.1 psi/ft gas gradient Brief Well Summary: CLU 5RD was drilled and completed in December 2015 down to deep Tyonek. Initial perfs in DT-6 produced ~2mmscfd but brought in water and fill. Set CIBP over DT-6. Performed coil cleanout w/ N2 to remove water and sand from well. Perforated DT-5B. Flowed at ~14 MMSCFD until water influx loaded up well in May 2016. Set CIBP over DT-5B. Perforated DT-5. Well produced 1-2 MMscfd before loading up in July 2016. In October 2016 perforated DT-4A, no gas production. Perforated DT-3A, DT-3, & DT-2 in following months, also unsuccessful. In March 2017 perforated DT-1 (“91-2”). Well came on strong at ~10 MMscfd and flowed until it loaded up with sand and water in November 2019. February 2020 in preparation to set a CIBP over the 91-2 sand, E-line ran in hole with a gauge ring and GPT tool string. The tool string became stuck in the fill. Several attempts were made with slickline, and eventually coil, to remove the stuck tools. Decision was made to set CIBP over stuck fish. Due to the unplanned location of the CIBP, only the upper [lower quality] half of the T9B sand was available to perforate. The upper half of T9B was perforated on 3/31/2020. The perforations resulted in <100 MCFD rate at ~100psi WHP. A RWO was performed in the summer of 2020 to access the Beluga sands. Installed 2-7/8” tubing. Perf’d LB-2B. Built ~30psi in 15min. Well flowed 20 – 70 MCFD between July – Sept. Found FL at 4530’ MD (~3900’ above perforations). Decided to push fluid back and set umbrella plug & cement over LB-2B. Perf’d MB-7 & UB-4B. Pressure fell from 1997psi to 1855psi in 15 min. Well only flowed 30 – 50 MCFD. In October Found FL at 2154’. Well loaded up two months later. In April 2021 pressured up well to 1820psi. Perf’d LB 1F-1B. Pressure dropped to 1675psi during perf job. No flow post-perfs. In May 2021 shot the MB-7A & MB-4. Starting pressure of 796 psi, dropped to 750 psi throughout perf job. Unloaded water, flowed fluctuated around 1000 MCFD, eventually stabilizing at ~160 MCFD. Well producing 250 – 300 BWPD. The objective of this work is to increase production by shutting off the water producing UB-4. Well Condition: - Max deviation: 49 degrees at 3411’ MD. - SL tagged TOC @ 8210 SLMD on 3-13-2021. - Minimum ID: 2.31”, 2-7/8” X nipple @ 6485’ MD. Pre Rig Work 1. Perform MIT-IA to 1500 psi and record for 30 minutes. 2. MIRU E-line. PT lubricator to 250 psi low / 2500 psi high. 3. Load tubing with 124 bbls of 6% KCl or until hole is full. 4. RIH with CCL, weight bars and Owen jet cutter. 5. Log across packer assembly. 6. Cut the 8’ pup joint 2’ above the packer. Well Prognosis Well: CLU 5RD Date: 5/14/2021 a. Confirm that fluid level is still very shallow, and that no pressure needs to be applied to tubing for cut. b. Monitor and report IA and tubing pressures pre and post cut. Rig 401 Procedure 1. MIRU 401 workover rig. 2. Load tubing with produced water or 6% KCl & monitor fluid level for stability. 3. Set BPV, ND Tree and THA, NU 11” BOPE per attached schematic. 4. Pick up and rack back 2-7/8” or 3-1/2” work string depending on availability. 5. Perform BOP Test 250 psi low & 2500 psi high, annular to 250 psi low & 2500 psi high. a. Provide 24hr notice to AOGCC of BOP Test. b. Test with 2-7/8” and 3-1/2” test joint (if using 3-1/2” work string). c. Record with chart & submit to AOGCC within 5 days of test. 6. Pull BPV. 7. PU landing joint, stab into hanger and back out LDS. 8. Pull hanger to floor, remove and lay down landing joint. 9. Pull and rack back 2-7/8” completion. a. Tubing was ran used in 2020 but should still be in good condition. Inspect and break connections with care. b. Spool up SSSV control line while pulling tubing until valve is laid down. 10. MU BHA including scraper for 7-5/8” casing, weight bars, boot baskets and burn shoe to work string and trip in hole to packer. 11. Pick up off packer, rig-up power swivel and establish milling parameters. 12. Burn over packer and push to bottom. Set down work string weight. a. Identify risk of trapped gas below the packer. 13. POOH and back ream from 6900’-6420’. 14. Rig-down power swivel and POOH laying down work string. a. Identify risk that packer could be swallowed inside of burn shoe. 15. MIRU e-line. PT lubricator to 250 psi low / 2500 psi high. 16. MU WLEG, tailpipe, X nipple with RHC plug installed, pup and 7-5/8” x 2-7/8” permanent packer with snap latch receptacle. 17. RIH and set packer at ~6850’. POOH. a. Make correlation pass and send log in to, Reservoir Engineer (Anthony McConkey) and Geologist (Ben Siks). 18. RDMO e-line. 19. Run 2-7/8” 6.4# L-80 completion as follows (assume all jewelry is made up to pups): a. 2-7/8” snap-latch pin b. 2-7/8” X landing nipple c. 9-5/8” x 2-7/8” hydraulic set retrievable packer d. 2-7/8” 6.4# L-80 EUE tubing e. 2-7/8” SSSV with control line clamped to tubing f. 2-7/8” 6.4# L-80 EUE tubing 20. Snap in to snap latch and unsnap to ensure we are at the correct depth. Well Prognosis Well: CLU 5RD Date: 5/14/2021 21. Space out, install hanger with control line and land hanger in tubing spool with landing joint. Unsnap and re-land to verify space out. 22. Run in LDS and lay down landing joint. 23. Drop ball & rod and pressure up per packer representative’s specification to set retrievable packer. 24. Perform charted MIT-T to 3000 psi. 25. Perform charted MIT-IA to 1500 psi. 26. Set BPV, ND BOP. 27. NU THA and production tree & test to 5000 psi. 28. Pull BPV. 29. RDMO. Slickline Procedure 1. MIRU Slickline. PT lubricator to 250 psi low / 2500 psi high. 2. Pull ball & rod. 3. Pull RHC plug. 4. Swab well down. 5. RDMO. Contingent Coiled Tubing: If slickline is unable to swab all water off well. 1. MIRU Coiled Tubing Unit. 2. PT BOP equipment to 250 psi Low / 4,000 psi High. a. If Schlumberger is the provider and within their 7 day testing window then a shell and function test are all that is required. b. Provide 24hr notice to AOGCC of BOP Test. c. Record with chart & submit to AOGCC within 5 days of test. 3. MU nozzle, and RIH to PBTD. 4. RU N2 pumping unit. 5. Blow well dry with N2 taking returns to tanks. 6. Once well is dry, leave N2 pressure on well per OE for the first perforation interval. 7. POOH w/ coil. RDMO CTU. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Rig 401 BOP Schematic 4. Coil BOP Schematic 5. Standard Nitrogen Procedure 6. RWO Change Form MITIA to 2400 psi. Provide 24 hrs notice to AOGCC to witness pressure test of tubing and IA. _____________________________________________________________________________________ Updated by TCS 05-18-21 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 PBTD = 8,355’ MD / 6,919’ TVD TD = 12,940’ MD / 11,253’ TVD 9 3 15 UB-7B Upper 20” RKB = 18’ 2 8-1/2” window at 6,527’ MD 5,354’ TVD 9-5/8” 4-1/2” 1 7-5/8” 13-3/8” UB-7B Lower D-6 LB-2B D-5A D-6A 18 17 D-5 16 D-2C D-4A D-3A 14 91-2 4 5 6 UT-9B 12 UB-4B 13 7 8 10, 11 19 - ’ RA Mkr Jt 11,090’ RA Mkr Jt 11,633’ RA Mkr Jt 12,060’ RA Mkr Jt 12,474’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf 6,525’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 2.441” 7.110” Safety Valve 3 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 4 6,471’ D&L 7-5/8” x 4” Permanent Pkr 6/26/20 5 6,485’ 2.310 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 6,525’ 2-7/8” WLEG 7 8,355’ 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 8 10,208’ 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 9 10,230’ 7.625” CIBP 6/17/20 10 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 11 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 12 10,279’ 4.500” CIBP 6/15/20 13 10,349’ 4.500” CIBP 14 11,170’ - 3.500” CIBP (TOC 11,170’) 15 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 16 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 17 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 18 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 19 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Open UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Open UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Open MB_4 7,335' 7,353' 6,073' 6,091' 18' 05/04/21 2” Open 7,372' 7,387' 6,102' 6,117' 15' 05/04/21 2” Open MB_7A 7,745' 7,750' 6,413' 6,418' 5' 05/04/21 2” Open 7,759' 7,767' 6,424' 6,432' 8' 05/04/21 2” Open 7,778' 7,788' 6,440' 6,450' 10' 05/04/21 2” Open LB_1B 8,023' 8,029' 6,643' 6,649' 6' 04/15/21 2” Open LB_1C 8,038' 8,056' 6,656' 6,674' 18' 04/15/21 2” Open LB_1D 8,074' 8,079' 6,686' 6,691' 5' 04/15/21 2” Open LB_1F 8,137' 8,149' 6,738' 6,750' 12' 04/15/21 2” Open 8,196' 8,203' 6,787' 6,794' 7' 04/15/21 2” Open LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated _____________________________________________________________________________________ Updated by TCS 05-18-21 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 PBTD = 8,355’ MD / 6,919’ TVD TD = 12,940’ MD / 11,253’ TVD 11 3,4 17 20” RKB = 18’ 2 8-1/2” window at 6,527’ MD 5,354’ TVD 9-5/8” 4-1/2” 1 7-5/8” 13-3/8” 20 19 18 16 5 6 14 15 9 10 12,13 21 7 8 RA Mkr Jt 11,090’ RA Mkr Jt 11,633’ RA Mkr Jt 12,060’ RA Mkr Jt 12,474’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf ~6,920’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 2.441” 7.110” Safety Valve 3 ~6,380’ 2.441” - 9-5/8” x 2-7/8” Retrievable Packer 4 ~6,390’ 2.313” - 2-7/8” X Profile Landing Nipple 5 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 6 ~6,850’ 2.441” - 7-5/8” x 2-7/8” Permanent Packer 7 ~6,860’ 2.313” - 2-7/8” X Profile Landing Nipple 8 ~6,870’ 2.441” - 2-7/8” WLEG 9 8,355’ - 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 10 10,208’ - 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 11 10,230’ - 7.625” CIBP 6/17/20 12 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 13 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 14 10,279’ - 4.500” CIBP 6/15/20 15 10,349’ - 4.500” CIBP 16 11,170’ - 3.500” CIBP (TOC 11,170’) 17 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 18 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 19 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 20 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 21 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Isolated UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Isolated UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Isolated MB_4 7,335' 7,353' 6,073' 6,091' 18' 05/04/21 2” Open 7,372' 7,387' 6,102' 6,117' 15' 05/04/21 2” Open MB_7A 7,745' 7,750' 6,413' 6,418' 5' 05/04/21 2” Open 7,759' 7,767' 6,424' 6,432' 8' 05/04/21 2” Open 7,778' 7,788' 6,440' 6,450' 10' 05/04/21 2” Open LB_1B 8,023' 8,029' 6,643' 6,649' 6' 04/15/21 2” Open LB_1C 8,038' 8,056' 6,656' 6,674' 18' 04/15/21 2” Open LB_1D 8,074' 8,079' 6,686' 6,691' 5' 04/15/21 2” Open LB_1F 8,137' 8,149' 6,738' 6,750' 12' 04/15/21 2” Open 8,196' 8,203' 6,787' 6,794' 7' 04/15/21 2” Open LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated 10,326’ 10,346’8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 10,767’ 10,787’9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 10,767’ 10,787’9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated 11,460’ 11,490’9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated 11,726’ 11,738’10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Cannery Loop Field CLU 05RD 5/21/2021 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well CLU 5RD (PTD 215-160) Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 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: 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,940'N/A Casing Collapse Conductor Surface 1,540psi Intermediate 6,620psi Intermediate 5,300psi Liner 4,790psi Liner 7,500psi Packers and SSSV Type: Baker T-E5 SSSV Packers and SSSV MD (ft) and TVD (ft): 298' (MD) 298' (TVD) 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 7,599'9,440psi tkramer@hilcorp.com 11,253'10,349'8,663'2,292 See Schematic 2,675' 2-7/8" 11,229' Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Authorized Title: Tubing Grade:Tubing MD (ft): See Attached Schematic April 7, 2021 Baker ZXP + Pet Pkr + ZXPN Packers 6,433' (MD) 5,263' (TVD) / 6,471' (MD) 5,300' (TVD) / 10,240' (MD) 8,555' (TVD) 6.4# / EUE 8RDSee Attached Scheamtic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE Hilcorp (ADL060569) / ADL324602 215-160 50-133-20474-01-00 Cannery Loop Unit (CLU) 05RD Kenai C.L.U. / Beluga Gas Pool Length Size CO 231A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY TVD Burst 6,525' 6,890psi MD 7,930psi 8,430psi 3,090psi 142' 2,578' Perforation Depth MD (ft): 1,212' 4,015' 4-1/2" 7,966' 1,200' 8,762'7-5/8" 9-5/8"9,178' 12,915' 142' 9-5/8"1,212' 2,970' 10,448' 142' 2,970' 20" 13-3/8" m n P 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:39 am, Mar 30, 2021 321-154 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.03.30 10:00:31 -08'00' Taylor Wellman (2143) DSR 3/30/21SFD 3/30/2021 10-404 BJM 4/7/21 Comm. 4/8/21 dts 4/8/2021 JLC 4/8/2021 RBDMS HEW 4/8/2021 Well Prognosis Well: CLU-05RD Date: 3/24/2021 Well Name: CLU-05RD API Number: 50-133-20474-01-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: April 7, 2021 Rig: E-Line Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Ryan Rupert (907)-777-8503 (907)-301-1736 AFE Number: Actual BHP: ~ 2,462 psi @ 5,630’ TVD (Calculated using a .437 psi/ft gradient) Max. Expected BHP: ~ 2,972 psi @ 6,794’ TVD (Calculated using a .437 psi/ft gradient) Max. Potential Surface Pressure: ~ 2,292 psi (Based on expected BHP and 0.1 psi/ft gas gradient) Brief Well Summary CLU-05RD was drilled in 2015 and completed in 2016. The well has been perforated in the D-6, D-5A, D-4A, D- 3A, D-2C and 91-2 sands, all of which have since been isolated. The UT 9B upper and Lower was added in March of 2020 and the LB-2b was perfed in July of 2020. The purpose of this work/sundry is to add perforations in the LB1 B, C, D, and F, MB 7A, MB 4, and the UB 5A sands. Perforating will be from bottom to top starting with the LB1. ( Note: All of the lower beluga will be shot together.) Notes Regarding Wellbore Condition x Last tag w/ 2” Fluted centralizer to 8,210’ 3/13/ 2021 x Well is currently SI Safety Concerns x Ensure all crews are aware of stop job authority. E-Line Procedure 1. Pump up and lock open SSSV. 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 3. RIH with GPT tool and find fluid level. If fluid is over the depth of the new perfs, discuss using methane or Nitrogen with the Operations Engineer to depress FL. 4. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 5. RU perf guns. 6. RIH and perforate the below interval: add perforations in the LB1 B, C, D, and F, MB 7A, MB 4, and the UB 5A Well Prognosis Well: CLU-05RD Date: 3/24/2021 Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Estimated Reservoir Pressure UB_5A ±6,641' ±6,650' 9' ±5,465' ±5,474' 2000 MB_4 ±7,335' ±7,353' 18' ±6,073' ±6,091' 2500 MB_4 ±7,372' ±7,387' 15' ±6,102' ±6,117' 2500 MB_7A ±7,745' ±7,750' 5' ±6,413' ±6,418' 1500 MB_7A ±7,759' ±7,767' 8' ±6,424' ±6,432' 1500 MB_7A ±7,778' ±7,788' 10' ±6,440' ±6,450' 1500 LB_1B ±8,023' ±8,029' 6' ±6,643' ±6,649' 2500 LB_1C ±8,038' ±8,056' 18' ±6,656' ±6,674' 2500 LB_1D ±8,074' ±8,079' 5' ±6,686' ±6,691' 2500 LB_1F ±8,137' ±8,149' 12' ±6,738' ±6,750' 2500 LB_1F ±8,196' ±8,203' 7' ±6,787' ±6,794' 2500 a. Pressure up well to Push away fluid before perforating using Methane gas or Nitrogen. b. Proposed perfs also shown on the proposed schematic in red font. c. Final perfs tie-in sheet will be provided in the field for exact perf intervals. d. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. e. Spacing allowance is based on CO 231. f. Use Gamma/CCL to correlate. g. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. h. Record 5, 10 and 15 minutes pressures after firing guns. 7. POOH. 8. RD E-Line. 9. Turn well over to production to flow test. E-Line Procedure (Contingency) 1. If this zone produces sand and/or water and needs to be isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,000 psi High. 3. RIH and plug above the zone and dump 25’ of cement on top of the plug. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Standard Well Procedure – N2 Operations A SFD 3/30/2021 _____________________________________________________________________________________ Updated by DMA 10-30-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf 6,525’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Safety Valve 3 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 4 6,471’ 7-5/8” x 2-7/8” Ret Pkr 6/26/20 5 6,485’ 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 6,525’ 2-7/8” WLEG 7 8,355’ 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 8 10,208’ 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 9 10,230’ 7.625” CIBP 6/17/20 10 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 11 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 12 10,279’ 4.500” CIBP 6/15/20 13 10,349’ 4.500” CIBP 14 11,170’ - 3.500” CIBP (TOC 11,170’) 15 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 16 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 17 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 18 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 19 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Open UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Open UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Open LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated _____________________________________________________________________________________ Updated by DMA 03-10-21 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf 6,525’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Safety Valve 3 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 4 6,471’ 7-5/8” x 2-7/8” Ret Pkr 6/26/20 5 6,485’ 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 6,525’ 2-7/8” WLEG 7 8,355’ 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 8 10,208’ 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 9 10,230’ 7.625” CIBP 6/17/20 10 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 11 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 12 10,279’ 4.500” CIBP 6/15/20 13 10,349’ 4.500” CIBP 14 11,170’ - 3.500” CIBP (TOC 11,170’) 15 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 16 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 17 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 18 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 19 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB_5A ±6,641' ±6,650' ±5,465' ±5,474' 9' Proposed TBD UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Open UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Open UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Open MB_4 ±7,335' ±7,353' ±6,073' ±6,091' 18' Proposed TBD MB_4 ±7,372' ±7,387' ±6,102' ±6,117' 15' Proposed TBD MB_7A ±7,745' ±7,750' ±6,413' ±6,418' 5' Proposed TBD MB_7A ±7,759' ±7,767' ±6,424' ±6,432' 8' Proposed TBD MB_7A ±7,778' ±7,788' ±6,440' ±6,450' 10' Proposed TBD LB_1B ±8,023' ±8,029' ±6,643' ±6,649' 6' Proposed TBD LB_1C ±8,038' ±8,056' ±6,656' ±6,674' 18' Proposed TBD LB_1D ±8,074' ±8,079' ±6,686' ±6,691' 5' Proposed TBD LB_1F ±8,137' ±8,149' ±6,738' ±6,750' 12' Proposed TBD LB_1F ±8,196' ±8,203' ±6,787' ±6,794' 7' Proposed TBD LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,940 feet feet true vertical 11,253 feet N/A feet 6,433; Effective Depth measured 8,355 feet 6,471;10,240 feet true vertical 6,919 feet 5,263; 5,300; feet 8,555 Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.4# / L-80 6,525' MD 5,353' TVD Baker ZXP + Ret Pkr + Baker ZXPN Pkrs 6,433' MD/5,263' TVD; 6,471' MD/5,300' TVD; 10,240' MD/8,555' TVD Packers and SSSV (type, measured and true vertical depth)Baker TE-5 SSSV TR 298' MD/ 298' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 7 Water-Bbl MD 142' 2,970' 12,915' N/A 15 Packer 7-5/8" 4-1/2" 10,448' 9,440psi 5,300psi 11,229' 8,762' 7,930psi 3,090psi 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai C.L.U. / Beluga Gas PoolN/A measured TVD 0 9,178' Oil-Bbl FEE Hilcorp (ADL060569); ADL324602 1,212' 9-5/8"7,599' measured measured true vertical Liner 2,675' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-160 50-133-20474-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-375 95 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Tubing Pressure Authorized Signature with date: Authorized Name: 808 Casing Pressure 2. Operator Name:Hilcorp Alaska, LLC Plugs Junk 0 Cannery Loop Unit (CLU) 05RD 0 Representative Daily Average Production or Injection Data 7,500psi Gas-Mcf 67 73 4,015' Conductor Surface Intermediate Liner Intermediate 7,966' 20" 13-3/8" 9-5/8" Length 2,578' 142' 2,970' 1,212' Collapse 1,540psi 6,620psi 4,790psi See Attached tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst 6,890psi 142' 1,200' Casing t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 4:12 pm, Nov 04, 2020 gg Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.04 15:52:11 -09'00' Taylor Wellman SFD 11/5/2020DSR-11/4/2020 gls 11/25/20 Perforate CBL Nitrogen Plug Perforations gls 11/25/20 RBDMS HEW 11/5/2020 X X Rig Start Date End Date E-Line 9/14/20 10/12/20 PTW, JSA and Simops with AKE-line and SLB N/2. Spot equipment, pressure test lubricator and hard lines to 4,000 psi. 1,267, 4 psi. RIH w/GPT tool and correlate with CBL at 6,300'. Found fluid level at 4,470' with 1,430 psi on tubing. Started pushing fluid away at approx 1,500 psi, pressure kept climbing slowly until it reached 3,000 psi and then pushed fluid away like it broke over. Push fluid away at steady at 3,000 psi. Raised the pressure to 3,500 psi but slowed down fluid level rate. Went back to 3,000 psi and got a better fluid push than 3,500 psi. 10/10/2020 - Saturday Safety meeting with Schlumberger and Alaska E-line crews, emphasis on working with Nitrogen, pressure testing equipment. Discuss sequence of work for RU and RIH with tools. ~2,100 psi on tree from well. Make up downhole tools, make up hardline for Nitrogen. Conduct surface test of plug setting, good test. MU lubricator to tree, PT to 4,200 psi. Bleed to 2,100 psi, open to well. RIH with Neo Plug hanging below GPT / CCL / GR tools. Fluid level at 7,910' MD. On with Nitrogen, continue to RIH. Log plug setting area, send to town, +4.5' correction. Fluid level slow to drop, moved from 7,910’ to 8,060’ in 140 minutes. consult with ODE, decide to stop N2 influence and log proposed perf interval and monitor fluid level for 2 hours. Bleed off N2 to 2,800 psi before moving up to log perf area, 0 correction. POH, swap out tools. Add beads, RIH. Set tools on depth, lay in beads into basket of plug. Begin mixing cement while POH. Swap out tools, add mixed 17.0 ppg cement with accelerator. RIH, lay in cement. 15 hr WoC time start at 1830 hrs. 10/11/2020 - Sunday Attend Operations morning safety meeting, crew warming and prepping equipment. Open up to well, 2,550 psi on well. Conduct PJSM on days activities. MU Bailer, test conductivity. Test lubricator to 3,000 psi. RIH with BHA, confirm plug at 8,309' MD on down movement. Total of 9 runs with 17.0 ppg cement with accelerator to meet 25' of cement above plug in 7" casing. 09/14/2020 - Monday Sign in. PTW and JSA. Spot equipment and rig up lubricator. PT lubricator to 250 psi low and 2500 psi high. O tubing pressure. RIH w/1-11/16" CBL tool and RIH to 7,000'. Calibrate CBL tool and correlate log with schematic. Logged from 8,500' to 6,400'. Found FL at 4,170'. Sent log to Ben and Ted and they said it was good. Rig down E-line equipment and turn well over to field. 10/01/2020 - Thursday Sign in, Spot equipment,and rig up equipment and lubricator. PT lub 250 psi low, and 3,000 high. RIH w/GPT and tie into the OHL. Found FL at 4,530' with 1,267 psi. Called town and discussed. Decision made to wait on N2 and perform the job in the morning. Rig down for the night. Rig down quipment and take to shop to clean up. 10/02/2020 - Friday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD CBL log run Rig Start Date End Date E-Line 9/14/20 10/12/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD 10/12/2020 - Monday Attend Operations Safety Meeting, conduct PJSM with crew. emphasis on working with perf guns and working with pressure after firing guns. Rig up perf equipment, test electrical conductivity. Open to well, 2,550 psi on well. Close in, pressure test lubricator to 3,000 psi. Open up to well, increase pressure to 3,000 psi (500 psi over) to test integrity of plug. Solid, no pressure loss. Bleed off to 2,500 psi. RIH with perf BHA. guns are 2" LowSwell, 6 shot per foot, 60 deg phasing. Lightly tag cement top at 8,328' MD (27' of cement on top of plug set at 8,355'). Log for correlation pass, send to town. Place perf guns on depth with firing interval of 6,795' - 6,820' MD, 5,607' - 5,630' TVD. Initial pressure on well 2,564 psi. Fire and begin POH. Pressure at 5 minutes 2,508 psi, 10 minutes 2475 psi, 15 minutes 2,429 psi. Pull to surface, swap out BHA. RD Nitrogen unit. RIH with new BHA. Log correlation, on depth. Place perf guns on depth with firing interval of 6,735' - 6,762' MD, 5,552' - 5,577' TVD. Initial pressure on well 2,062 psi. Fire and begin POH. Pressure at 5 minutes 2,059 psi, 10 minutes 2,055 psi, 15 minutes 2,063 psi. Swap out BHA, RIH. Place perf guns on depth with firing interval of 6,578' - 6,594' MD, 5,403' - 5,419' TVD. Initial pressure on well 1,997 psi. Fire and begin POH. Pressure at 5 minutes 1,995 psi, 10 minutes 1,907 psi, 15 minutes 1,855 psi. Rig down E-Line unit, secure well and hand over to Operations. _____________________________________________________________________________________ Updated by DMA 10-30-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf 6,525’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Safety Valve 3 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 4 6,471’ 7-5/8” x 2-7/8” Ret Pkr 6/26/20 5 6,485’ 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 6,525’ 2-7/8” WLEG 7 8,355’ 7.625” CIBP w/ 27’ cmt TOC 8,328’ 10/12/20 8 10,208’ 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 9 10,230’ 7.625” CIBP 6/17/20 10 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 11 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 12 10,279’ 4.500” CIBP 6/15/20 13 10,349’ 4.500” CIBP 14 11,170’ - 3.500” CIBP (TOC 11,170’) 15 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 16 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 17 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 18 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 19 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B 6,578’ 6,594’ 5,403’ 5,419’ 16 10/12/20 2-7/8” Open UB-7 Upper 6,735’ 6,762’ 5,552’ 5,577’ 27 10/12/20 2-7/8” Open UB-7 Lower 6,795’ 6,820’ 5,607’ 5,630’ 25 10/12/20 2-7/8” Open LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Isolated UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated NeoPlug UB-4B 6,578’ 6,594’ 5,403’5,419’16 10/12/20 2-7/8” Open UB-7 Upper 6,735’ 6,762’ 5,552’5,577’27 10/12/20 2-7/8” Open UB-7 Lower 6,795’ 6,820’ 5,607’5,630’25 10/12/20 2-7/8” Open p p Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 10/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU-05RD (PTD 215-160) Depth Correlation 03/21/2020 Please include current contact information if different from above. Received by the AOGCC 10/16/2020 PTD: 2151600 E-Set:34106 Abby Bell 10/20/2020 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: 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,940'N/A Casing Collapse Conductor Surface 1,540psi Intermediate 6,620psi Intermediate 5,300psi Liner 4,790psi Liner 7,500psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 12,915' 142' 9-5/8"1,212' 2,970' 10,448' 142' 2,970' 20" 13-3/8" Perforation Depth MD (ft): 1,212' 4,015' 4-1/2" 7,966' 1,200' 8,762'7-5/8" 9-5/8"9,178' Burst 6,525' 6,890psi MD 7,930psi 8,430psi 3,090psi 142' 2,578' Length Size CO 231A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE Hilcorp (ADL060569) / ADL324602 215-160 50-133-20474-01-00 Cannery Loop Unit (CLU) 05RD Kenai C.L.U. / Beluga Gas Pool Tubing Grade:Tubing MD (ft): See Attached Schematic September 25, 2020 Baker ZXP & ZXPN Packers & Baker T-E5 SSSV 6,433' (MD) 5,263' (TVD) / 10,240' (MD) 8,555' (TVD) & 298' (MD) 298' (TVD) 6.4# / EUE 8RDSee Attached Scheamtic 2,675' 2-7/8" 11,229' Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 7,599'9,440psi tkramer@hilcorp.com 11,253'10,349'8,663'~2,522psi See Schematic m n P 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:20 pm, Sep 11, 2020 320-375 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.11 14:34:42 -08'00' Taylor Wellman SFD 9/11/2020gls 9/24/20 DSR-9/15/2020Comm. 9/25/2020 10-404 dts 9/25/2020 JLC 9/25/2020 RBDMS HEW 10/28/2020 Well Prognosis Well: CLU 5RD Date: 09-11-2020 Well Name: CLU 5RD API Number: 50-133-20474-01-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: September 25th, 2020 Rig: 401 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Ryan Rupert (907) 777-8503 (O) (907) 301 - 1736 AFE Number: Max. Expected BHP: ~ 2,522 psi @ 5,771’ TVD (Based on normal pressure gradient) Max. Potential Surface Pressure: ~ 1,945 psi (Based on expected BHP and gas gradient to surface (0.10 psi/ft)) Brief Well Summary CLU-05RD was drilled in 2015 and completed in 2016. The well has been perforated in the D-6, D-5A, D-4A, D- 3A, D-2C and 91-2 sands, all of which have since been isolated. In March 2020 the UT-9B sand was perforated. In July of 2020 the LB-2B Sand was perforated and flowed Methane Gas at 30 to 50 mcfd. Efforts to swab the well were unsuccessful to bring in more gas. The purpose of this work/sundry is to add the UB- 4, 7 upper and lower, 8, and 9 sands. Note: The perforations below are 302 feet TVD below the Sterling C gas pool (Storage Interval) defined in CO 231A. E-Line Procedure 1) MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,500 psi High. 2) If needed, RIH with GPT tool and find fluid level. If fluid is over the depth of the new perfs, discuss using methane or Nitrogen with the Operations Engineer. 3) If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4) RU perf guns. 5) RIH and perforate the intervals below (Note: Sand intervals will be shot one at a time except the UB 8 and 9 and flow tested.): Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt Upper Beluga UB-4B ±6,578’ ±6,594’ ±5,403’ ±5,419’ 16’ Upper Beluga UB-7 Upper ±6,735’ ±6,762’ ±5,552’ ±5,577’ 27’ Upper Beluga UB-7 Lower ±6,795’ ±6,820’ ±5,607’ ±5,630’ 25’ Upper Beluga UB-8 & UB-9 ±6,916’ ±6,978’ ±5,716’ ±5,771’ 62’ a. Pressure up well to 2,500 psi before perforating. b. Proposed perfs also shown on the proposed schematic in red font. c. Final perfs tie-in sheet will be provided in the field for exact perf intervals. e perforations below are 302 feet TVD below the Sterling C gas pool (Storage Interval) defined in CO 231A. Upper Beluga UB-4B ±6,578’±6,594’±5,403’±5,419’16’ Upper Beluga UB-7 Upper ±6,735’±6,762’±5,552’±5,577’27’ Upper Beluga UB-7 Lower ±6,795’±6,820’±5,607’±5,630’25’ Upper Beluga UB-8 & UB-9 ±6,916’±6,978’±5,716’±5,771’62’ CBL run on 9/24/20 verified good bond over the 7 5/8" casing. glsNo bond log run during well sidetrack. (gls ) Well Prognosis Well: CLU 5RD Date: 09-11-2020 d. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. e. Spacing allowance is based on CO 231A Beluga Gas Pool. f. Use Gamma/CCL to correlate. g. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. h. Record 5, 10 and 15 minutes pressures after firing guns. 6) POOH. 7) RD E-Line. 8) Turn well over to production. E-Line Procedure (Contingency) 1) If this zone produces sand and/or water and needs to be isolated: 2) MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,500 psi High. 3) RIH and set 7-5/8” Plug above the zone and dump 25’ of cement on top of the plug. Attachments: 1) Current Well Schematic 2) Proposed Well Schematic 3) Standard Well Procedure – N2 Operations _____________________________________________________________________________________ Updated by DMA 05-11-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf 6,525’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Safety Valve 3 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 4 6,471’ 7-5/8” x 2-7/8” Ret Pkr 6/26/20 5 6,485’ 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 6,525’ 2-7/8” WLEG 7 10,208’ 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 8 10,230’ 7.625” CIBP 6/17/20 9 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 10 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 11 10,279’ 4.500” CIBP 6/15/20 12 10,349’ 4.500” CIBP 13 11,170’ - 3.500” CIBP (TOC 11,170’) 14 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 15 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 16 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 17 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 18 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 07/13/20 2-7/8” Open UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated window 6527' CBL ran 9/24/20 indicates good bond over 7 5/8" (logged 8500 - 6400 ft) _____________________________________________________________________________________ Updated by DMA 09-11-20 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf ~6,400’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Safety Valve 3 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 4 ~6,460’ 7-5/8” x 2-7/8” Retrievable Packer 5 ~6,470’ 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 ~6,500’ 2-7/8” WLEG 7 +10,230’ 7.625” CIBP w/ 25’ cement (TOC +10,205’) 8 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 9 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 10 +10,305’ 4.500” CIBP 11 10,349’ 4.500” CIBP 12 11,170’ - 3.500” CIBP (TOC 11,170’) 13 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 14 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 15 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 16 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 17 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B +6,578’ +6,594’ +5,403’ +5,419’ Proposed 2-7/8” TBD UB-7 Upper +6,735’ +6,762’ +5,552’ +5,577’ Proposed 2-7/8” TBD UB-7 Lower +6,795’ +6,820’ +5,607’ +5,630’ Proposed 2-7/8” TBD UB-8 & UB-9 +6,916’ +6,978’ +5,716’ +5,771’ Proposed 2-7/8” TBD LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 24 07/13/20 2-7/8” Open UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Open UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Open 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Open D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated Sterling C pool STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1 Carlisle, Samantha J (CED) From:Ted Kramer <tkramer@hilcorp.com> Sent:Thursday, September 24, 2020 1:47 PM To:Schwartz, Guy L (CED) Cc:Donna Ambruz Subject:FW: CLU-05RD CBL Log, PTD 215-160 Attachments:CLU-05RD CBL 24SEPT20.pdf; clu-05rd_cbl-24spt20_CLU_05RD_CBL1_pass6.3.las Follow Up Flag:Follow up Flag Status:Flagged Guy, IlocatedaCBLtooltologthiswellsoIhaditloggedtoday. SothisCBLisinsupportoftheSundrysubmittedtoperftheupperBeluga.Thecementlooksverygoodhereuptothe currenttubingtail.Thisshouldgiveeveryonegoodconfidencethatwehaveisolation. TedKramer Sr.OperationsEngineer HilcorpͲAlaskaLLC Office–907Ͳ777Ͳ8420 Cell–985Ͳ867Ͳ0665 From:BillyApplewhiteͲ(C) Sent:Thursday,September24,20201:34PM To:TedKramer<tkramer@hilcorp.com>;BenjaminSiks<bsiks@hilcorp.com>;AnthonyMcConkey <amcconkey@hilcorp.com>;KraigMcghie<kmcghie@hilcorp.com>;ChrisWalgenbach<cwalgenbach@hilcorp.com>; TaylorWellman<twellman@hilcorp.com> Cc:BillyApplewhiteͲ(C)<bapplewhite@hilcorp.com> Subject:CLUͲ05RDCBLLog Ben, Loggedfrom8500’to6400’.Correlatedtoschematicdated5Ͳ11Ͳ20schematicinsteadofproposedschematic Billy The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Upper Completion, N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,940 feet feet true vertical 11,253 feet N/A feet 6,433; Effective Depth measured 10,173 feet 6,471;10,240 feet true vertical 8,487 feet 5,263; 5,300; feet 8,555 Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.4# / L-80 6,525' MD 5,353' TVD Baker ZXP + Ret Pkr + Baker ZXPN Pkrs 6,433' MD/5,263' TVD; 6,471' MD/5,300' TVD; 10,240' MD/8,555' TVD Packers and SSSV (type, measured and true vertical depth)Baker TE-5 SSSV TR 298' MD/ 298' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 0 Water-Bbl MD 142' 2,970' 12,915' N/A 95 Packer 7-5/8" 4-1/2" 10,448' 9,440psi 5,300psi 11,229' 8,762' 7,930psi 3,090psi 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai C.L.U. / Beluga Gas PoolN/A measured TVD 0 9,178' Oil-Bbl FEE Hilcorp (ADL060569); ADL324602 1,212' 9-5/8"7,599' measured measured true vertical Liner 2,675' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-160 50-133-20474-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-202 255 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Tubing Pressure Authorized Signature with date: Authorized Name: 31 Casing Pressure 2. Operator Name:Hilcorp Alaska, LLC Plugs Junk 0 Cannery Loop Unit (CLU) 05RD 0 Representative Daily Average Production or Injection Data 7,500psi Gas-Mcf 463 319 4,015' Conductor Surface Intermediate Liner Intermediate 7,966' 20" 13-3/8" 9-5/8" Length 2,578' 142' 2,970' 1,212' Collapse 1,540psi 6,620psi 4,790psi See Attached tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst 6,890psi 142' 1,200' Casing t Fra O 6. A G L PG , R 2 Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 1:03 pm, Aug 12, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.08.12 12:54:31 -08'00' Taylor Wellman DSR-8/13/2020 RBDMS HEW 8/12/2020 gls 9/17/20 SFD 8/13/2020 SFD 8/13/2020 Rig Start Date End Date 6/15/20 7/13/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD 06/18/2020 - Thursday PJSM, check well bore for pressure. Cont. N/U BOP and grease choke manifold. P/U Tripoint AS1-X 4-1/2" X 2-3/8" retrieveable packer. RIH t/ 20'. Set packer and pull off of it. Confirm packer is set. POOH and L/D running tool M/U and P/U 2-7/8" donut test jt. Fill stack and get a shell test at 250 low - 4,000 high. Start testing BOP w/ AOGCC Jeff Jones witnessing. Tested all BOP and choke manifold components, PVT system and Total Safety gas detection system. C/O 2- 7/8 donut jt to 4-1/2" donut jt and test VBR's. L/D 4-1/2" test jt. P/U tripoint running tool and recover AS1-X packer. L/D same and secure well for the night. 06/20/2020 - Saturday PJSM, Check well for pressure. Well is stable. M/U Yellow jacket 4-1/2" spear. Spear into pup jt. below hanger due to bad hanger threads. BOLDS w/ Clint the wellhead man present. Unseat hanger. P/U weight 113K - 155K, worked it a few times and seals started to slide out at 159K. brought hanger to the floor and removed control/chemical injection lines. L/D hanger and spear. R/U pipe handler for range 3 tubing., spooler for ss tubing. prepare to start laying down pipe. POOH w/ range 3 4-1/2" IBT tubing. L/D chemical injection mandrel and cross over to range 2 4-1/2" supermax tubing and cont. POOH. Layed down a total of 4,000' and recovered 65 SS bands. Secured well for the night. 06/15/2020 - Monday SPOT & R/U YELLOW JACKET E-LINE & LUBRICATOR. M/U 3.75" GR/JB ASSEMBLY WITH CCL & GAMMA RAY. P/U LUBRICATOR & ATTEMPT TO STAB ON WELL, UNABLE TO STAB INTO 4" OTIS CONNECTION, TROUBLE SHOOT & FOUND ENLARGED O-RING ON YELLOW JACKET LUBRICATOR. REPLACE & STAB ONTO TREE. TEST LUBRICATOR TO 250/2,000, EQUALIZE TO 800 PSI AGAINST THE WELL & OPEN SAME. RIH WITH 3.75" GR/JB COMBO TO 10,349' & TAG ON CIBP. LOG UP PAST PERFORATIONS & SEAL ASSEMBLY. POOH TO SURFACE. L/D JB/GR TOOLS P/U SETTING TOOL WITH 4.5" CIBP & STAB ONTO WELL. TEST LUBRICATOR TO 250/2,000, EQUALIZE TO 800 PSI & RIH TO 10,315'. LOG UP HOLE, TIE IN & GET ON DEPTH SETTING CIBP @ 10,297'. POOH TO SURFACE & L/D TOOL ASSEMBLY. R/D YELLOW JACKET E-LINE, ASSIST PRODUCTION DISCONNECTING ELECTRICAL TO WELL HOUSE, REMOVE PRODUCTION LINE FOR SAND BUSTER. P/U & REMOVE WELL HOUSE FROM CLU 5RD & SET AWAY FROM WELL, PREP TO SPOT & R/U HAK 401. 06/17/2020 - Wednesday PJSM w/ Yellow Jacket, check well for pressure. R/U Yellow Jacket wireline. RIH t/ 10,222', pressure up on tubing t/200psi. Annulus was 0 psi. Shot 3' of shots at 6 shots/ft. Annulus pressure rose to/ 125psi. POOH w/ wireline and displace the well w/ produced water @ 3bbl/min. Bleed off well. No issues. R/D yellow jacket. P/U BPV and attempt to set several times. Could not get BPV to seal due to bad hanger threads. Discuses with engineer, decision was made to set another CIBP in the tail pipe. P/U 4-1/2" CIBP and RIH with wireline t/ 10,230' set same. Release and POOH. R/D wireline. Test and chart casing t/ 2,000psi for 30min as per AOGCC. Good test. ND tree, inspect hanger. Found corroded threads due to wirelineing. Attempt to dress the threads with no success. N/U mud cross and double gates. Secure well for the night. Could not get BPV to seal due to bad hanger threads. P/U weight 113K - 155K, Test and chart casing t/ 2,000psi for 30min as per AOGCC. Tested all BOP and choke manifold components, Rig Start Date End Date 6/15/20 7/13/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD 06/21/2020 - Sunday Hold PJSM, check well for pressure, all good. Cont. POOH and L/D 4-1/2" tubing. L/D a total of 302 jts, seal assembly and CIBP. Seals were in good condition with only one seal half missing. No traces of sands on seals. Strap 2-7/8" production string and work string needed to get on bottom with scraper. M/U Yellow Jacket BHA #2 w/ 6-3/4 mill tooth bit, mud motor and 7-5/8" casing scraper and a set of jars. Stand BHA #2 back and secure well for the night. 06/22/2020 - Monday PJSM, check well bore for pressure. Cont. RIH P/U 6400' 2-7/8" production string, cross over to 2-7/8" PH6 workstring. Cont. RIH and tag TOL @ 6,425'. no issues, cont. RIH T/ 10,239'. Tag up on 4-1/2" packer @ 10,239' w/ 401 RKB. Broke circulation at 2bbl/min w/ 700PSI. Secure well for the night. 06/23/2020 - Tuesday Hold PJSM, check well pressure, all good. Circulate one and half times bottoms up @10,230' with 3.5 bbls /min w/ 1,850 PSI, All good. Add 6% of clay break 1000 (KCL substitute) to mud system. Had small issue with the mud pump. L/D 3800' of 2-7/8" work String and Stand Back 6400' 2-7/8'' 8RD production tubing. L/D yellow-jacket BHA #2. Hold PJSM R/U Alaska E-Line and M/U 7-5/8" CIBP. RIH w/ same Set @ 10208' WLM tag and confirm POOH m/u cmt barrel and load w/ 17- PPG. RIH and Dump on Plug @ 10,208' 18' of cement POOH and reload. RIH and Dump 7 more feet EST cement @ 10,183' POOH R/D and secure well for the night. 06/24/2020 - Wednesday Hold PJSM, check well for pressure, all good. R/U up AK E-line and prepare for tag. Prep for completion with all vendors while waiting on cement to set. RIH and tag cement @ 10,173'. POOH, R/D E-line M/U completion assembly, RIH w/ 2- 7/8" tubing from derrick w/ 7-5/8" MFH hydraulic retrievable packer. RIH t/ 6,212', secure the well for the night. 06/25/2020 - Thursday Hold PJSM, check well for pressure, all good. P/U SSSV, test same to 5,000 psi for 10min. Cont. RIH banding each collar. Enter liner top with mule shoe w/ no issue. Packer entered the liner top and hung up below the liner top. Discussed with town and found there was a nipple profile that was smaller than packer. Decision was made to POOH and pick up a permanent packer. Jim Riggs gave permission to cont. on w/out BOP test. POOH, L/D SSSV and Packer racking back tubing. P/U new permanent packer and start RIH t/ 2300' and secured well for the night. 06/26/2020 - Friday Hold PJSM, check well for pressure, all good. Cont. RIH w/ 2-7/8" EUE completion t/ 6,221' and P/U SSSV. M/U same, hook control lines up and test t/5,000psi for 15min, good test. cont. RIH from 6,221' t/ 6,511' P/U tubing hanger, set in the bowl. Run in LDS. PUW 31K, SOW 24K. Terminate control line in the hanger. test same, all good. Hook up test hoses, drop rod and ball. Pressure up on packer t/ 3,800 PSI. Set packer, bleed off to zero. line up on back side and test annulus t/ 2,000 PSI, hold for 30min. Bleed off to zero w/ no loss. R/D test equipment, set BPV w/ NOS. N/D BOP and N/U Tree. Cont. t/ R/D the rig, prep for rig move. Pressure up on packer t/ 3,800 PSI. Set packer, bleed off to zero.line up on back side and test annulus t/ 2,000 PSI, hold for 30min. RIH w/ 2- 7/8" tubing from derrick w/ 7-5/8" MFH hydraulic retrievable packer. RIH t/ 6,212', secure the well for the night. P/U new permanent packer and start RIH t/ 2300' and secured well for the night. Cont. RIH P/U 6400' 2-7/8" production string, c MIT-IA and MIT-T set packer CIBP at 10208' RIH w/ same Set @ 10208' WLM tag and confirm POOH Rig Start Date End Date 6/15/20 7/13/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD Sign in. Spot equipment and rig up lubricator. PT lubricator to 250 psi low and 3,500 psi high. TP - 1,850 psi. RIH w/GPT and tie into Halliburton TM3D log. Stop at 8,620' and find fluid level at 8,570'. Ran correlation log and send to town. Told to add 3' to log. Added 3'.POOH RIH w/ 1-3/4" x 24' and tie into GPT log. Ran correlation perf log and send to town. to run a longer correlation log and send back to town. Ran longer correlation log and send to town. Told to add 24' and send back to town. Added 24' and sent back to town. Got the ok to perforate the LB-2B sand from 8,407' to 8,431' with 1,815 psi on tubing. Spotted and fired gun. 5 and 10 min - 1,815 psi. 15 min - 1,820 psi and 20 min/ 1,840 psi. Rig down lubricator and equipment and turn well over to field. 07/11/2020 - Saturday PTW, JSA. Pick injector head. Make up 10' lubricator. Make up BHA. Coil connector 1.75", DFCV 1.75", MBT 1.75" x 5', Jet swirl nozzle. Stab on well. Pt stack 250/4,000 psi. Bleed down. Open well. O psi tubing. RIH taking fluid displacement to return tank. 2,000' start cooling down N2 . Continue IH to 5,800'. 20 bbls displaced. Online with N2 @ 1,200 scf/min. 8,600' circ pressure breaks over 2,885 psi. Tagged PBTD @ 10,200' CTMD. 130 bbls returned. Crew attempted to transfer N2 from offshore tank and realize there was no N2 available. Wrong N2 tank was loaded out from yard. Sent coil hand to shop and dispatched Weaver Bros to hot shot N2 tank to location. Rig up new tank. cool down N2 transfer hose. Online with N2 1500 scf/min. Circ pressure building and broke over. Start in hole from 8,000' tag PBTD @ 10,200' CTMD. Crews strapping N2 tank. Looks like equalizing valve was left closed and there is less N2 than originally anticipated. 713 gallons remain. Start returns 130 bbls. Start POOH to surface chasing slug of fluid. Fluid returns and N2 at surface. Total fluid returns to surface 154 bbls out of 205 bbls. 51 bbls remain. 1,110' of fluid on top of cement. Fluid level calculated at 9,062'. Per add interval is out of fluid 8,407'-8,431'. Called town to discuss. Continue OOH. N2 only at surface. Close in choke to pressure up well. Tagged up at surface. SITP 1,900 psi. Reported that 4,553 gallons of N2 was pumped for job. 154 bbls removed from well bore. Rig back CTU equipment. 07/13/2020 - Monday 07/10/2020 - Friday PTW, JSA with SLB , Cruz construction, and Hilcorp Rep MIRU SLB CTU 13 with 1.75" Coil. 24 hr BOPE test witness notification sent 7/9/2020 @ 11:34 AM. Witness waived by Jim Regg 7/10/2020 @ 14:52 pm. Test all rams and valves to 250/4,000 psi. Perform BOPE accumulator draw down test. BOPE test finished. Make up roll on coil connector. Spot trailer with N2 tanks. Spot weaver trailer with fishing tools from YJOS . (Wash pipe barrels). Location secure. SDFN. Total fluid returns to surface 154 bbls out of 205 bbls. 5 Got the ok to perforate the LB-2B sand from 8,407' to 8,431' Perf LB-2B CTU _____________________________________________________________________________________ Updated by DMA 05-11-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf 6,525’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Safety Valve 3 6,433’ 6.625” 8.460” 7-5/8” ZXP Liner Top Packer 4 6,471’ 7-5/8” x 2-7/8” Ret Pkr 6/26/20 5 6,485’ 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 6,525’ 2-7/8” WLEG 7 10,208’ 7.625” CIBP w/ 35’ cement (TOC 10,173’) 6/23/20 8 10,230’ 7.625” CIBP 6/17/20 9 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 10 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 11 10,279’ 4.500” CIBP 6/15/20 12 10,349’ 4.500” CIBP 13 11,170’ - 3.500” CIBP (TOC 11,170’) 14 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 15 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 16 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 17 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 18 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status LB-2B 8,407’ 8,431’ 6,961’ 6,981’ 07/13/20 2-7/8” Open UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Isolated UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Isolated 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Isolated 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Isolated D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated Open2-7/8”LB-2B 8 407’8 431’6 961’6,981’07/13/20 window @6527 ft MD packer @6471ft TOC UNKNOWN CBL? sterling C NEW PERFS 8407-8431 FT STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: 7/17rZ P.I. Supry', I HOPE Test Report for: CANNERY LOOP UNIT 05RD Comm Contractor/Rig No.: Hilcorp 401 - PTD#: 2151600 - DATE: 6/19/2020 - Inspector Jeff Jones Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: R. Dalton - Rig Rep: C. Johnson Inspector Type O yP Operation: WRKOV Type Test: IIJ77' Sud Test Pressures: Sundry No: 320-202 Rams: Annular: Valves: 250/4000 - 250/4000 • 250/4000 ' Inspection No: bop7I200623095641 MASP: 2951 - Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: P/F Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank NA . NA- System Pressure 3050 - P Housekeeping: P - Pit Level Indicators P P - Pressure After Closure 1750 P PTD On Location P • Flow Indicator NA NA 200 PSI Attained 22 - P ' Standing Order Posted _P Meth Gas Detector P P - Full Pressure Attained 114 -_ P Well Sign _P = H2S Gas Detector _P __ P Blind Switch Covers: All P DO. Rig P MS Misc NA NA Nitgn. Bottles (avg): _ (&2075 " P Hazard Sec. _ P _ ACC Mise 0 NA Misc NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 0 - NA_ Stripper _O NA No. Valves 8 P ' Lower Kelly 0 NA,' Annular Preventer 1 -135/8 P Manual Chokes 2 P " Ball Type 2 -_ P , #1 Rams I -27/8x5 _ P Hydraulic Chokes 0 NA Inside BOP 1 P- #2 Rams 1 'Blind _ PCH Misc 0 NA FSV Misc 0 ___NA 93 Rams 0 _ NA #4 Rams 0 NA #5 Rams 0 NA INSIDE REEL VALVES: _ #6 Rams 0_ NA (Valid for Coil Rigs Only) Choke La. Valves 1 - 21/16 P Quantity P/F HCR Valves 1 -21/16 _- P - Inside Reel Valves 0 _ _ NA_ Kill Line Valves 2 -21/16 - P ' Check Valve 0 NA BOP Misc 0 NA Number of Failures: 0 Test Results Test Time 5 Remarks: All American Oilfield personnel performed the tests today in a safe manner using 2 7/8" and 4.5" test joints with no failures observed. The gas detection and pit volume totalizer alarm systems were tested and operated properly. The replacement ✓ Koomey control system with associated electric remote BOPE controls appears to working well and is a welcome equipment improvement to Hilcorp's rig #401. From: Loeoo. Victoria T (CED) To: Ted Kramer Cc: Schwartz. Guy L (CED) Subject: Re: CLU SRD Program Change -Mrr1A Test, PTD# 215-160, Sundry # 320-202 Date: Friday, June 26, 2020 2:32:57 PM Hi Ted, Guy may be on his way to Seward and his vacation. Approval is granted to MIT -IA to 2000 psig in Step 17 of procedure. Thanx, Victoria Sent from my Whone On Jun 26, 2020, at 1:19 PM, Ted Kramer <tkramer@hilcorp.com> wrote: Guy, I would like to change the Pressure test in Step 17 from 3,000 psi to 2,000 psi. There is no pressure on the tubing and If the packer is going to leak, it will leak at 2,000 psi differential. Also I would just as soon not put any more pressure on the linertop than we need to. Please let me know if this is agreeable to AOGCC. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp-Alaska LLC Office — 907-777-8420 Cell — 985-867-0665 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: Install Upper Completion, N2 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,940'N/A Casing Collapse Conductor Surface 1,540psi Intermediate 6,620psi Intermediate 5,300psi Liner 4,790psi Liner 7,500psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Christina Twogood Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10,448' Perforation Depth MD (ft): 1,212' See Attached Scheamtic 4,015' 4-1/2" 7,966'9-5/8"9,178' 12,915' 8,762'7-5/8" 20" 13-3/8" 142' 9-5/8"1,212' 2,970'3,090psi 142' 2,578' 1,200' 142' 2,970' 12.6# / L-80 TVD Burst 10,289' 6,890psi MD 7,930psi Length Size CO 231 Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE Hilcorp (ADL060569) / ADL324602 215-160 50-133-20474-01-00 Cannery Loop Unit (CLU) 05RD Kenai C.L.U. / Beluga Gas Pool 8,430psi Tubing Grade:Tubing MD (ft): See Attached Schematic May 21, 2020 2,675' 4-1/2" 11,229' Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 7,599'9,440psi ctwogood@hilcorp.com 11,253'10,349'8,663'~2,951psi See Schematic Baker ZXP & ZXPN Packers & Baker T-E5 SSSV 6,433' (MD) 5,263' (TVD) / 10,240' (MD) 8,555' (TVD) & 298' (MD) 298' (TVD) m n P O 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.05.13 16:19:18 -08'00' Taylor Wellman By Samantha Carlisle at 4:31 pm, May 13, 2020 320-202 10-404 Perforate GAS DSR-5/13/2020 Install Upper Completion, N2 401&CT X * 4000 psi BOPE test (CT and rig 401) Pull Tubing * * For any perforations that lie within 1,500' TVD of the base of the Sterling C Gas Storage Pool per 20 AAC 25.055(a)(2) since the Sterling C Gas Pool base is a property line for the vertically segmented lease. SFD 5/17/2020 SFD 5/17/2020 *Lower Beluga perforations approved only. ( LB-2B ) gls 5/20/20Comm. 5/20/2020 JLC 5/20/2020dts 5/20/2020 RBDMS HEW 5/22/2020 Well Prognosis Well: CLU 5RD Date: 05-06-2020 Well Name: CLU 5RD API Number: 50-133-20474-01-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: March 5th, 2020 Rig: 401 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Christina Twogood (907) 777-8443 (O) (907) 378-7323 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Max. Expected BHP: ~ 3,141 psi @ 6,981’ TVD (Based on normal pressure gradient) Max. Potential Surface Pressure: ~ 2,443 psi (Based on expected BHP and gas gradient to surface (0.10 psi/ft)) Brief Well Summary CLU-05RD was drilled in 2015 and completed in 2016. The well has been perforated in the D-6, D-5A, D-4A, D- 3A, D-2C and 91-2 sands, all of which have since been isolated. In March 2020 the UT-9B sand was perforated. The purpose of this work/sundry is to pull the existing 4-1/2” Tieback, set a CIBP to isolate the open UT-9B perforation, install a 2-7/8” Velocity String and Packer, blow the well dry and perforate multiple intervals in the Beluga sands. Notes Regarding Wellbore Condition x Fish left in hole at 10,419’ SLM (original stuck at 10,305’ ELM) on 2/10/2020 x Tagged plug at 10,347’ on 4/1/2020 x Well is currently SI Safety Concerns x Discuss Nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job). x Ensure all crews are aware of stop job authority. updated smaller tubing Well Prognosis Well: CLU 5RD Date: 05-06-2020 E-Line Procedure 1) MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 4,000 psi High. 2) RIH with 4-1/2” CIBP and set at approx. 10,305’ (just above the UT-9B open perf). PT CIBP to 4,000 psi. 3) POOH & RD E-Line. Rig Procedure 1) MIRU workover rig 401. 2) Notify AOGCC 24 hours in advance of test to extend the opportunity to witness. 3) Set back pressure valve. 4) ND wellhead, NU 13-5/8” BOP and test to 250 psi low & 4,000 psi high, annular to 250 psi low & 4,000 psi high. Record accumulator pre-charge pressures and chart tests. a) Perform Test. b) Test VBR rams on 4-1/2” and 2-3/8” test joints. c) Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 5) Fill tubing with 8.4 ppg brine. 6) PU on 4-1/2” tubing string and pull out of 7-5/8” x 4-1/2” Liner Hanger & Seal Assembly, circulate 8.4 ppg brine. 7) POOH with 4-1/2” tubing, laying down SSSV and tubing. 8) RIH with workstring and clean out BHA to 7-5/8” casing toe and circulate hole clean with 2 bottoms up. 9) POOH laying down workstring. 10) MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 4,000 psi High. 11) RIH with 7-5/8” CIBP and set at approx. 10,230’ and dump bail 25’ of cement on top of plug. 12) Tag cement. 13) POOH & RD E-Line. 14) PU & RIH with 2-7/8” tubing tail w/ completion jewelry, 7-5/8” packer and 2-7/8” tubing back to surface (w/ SSSV) to approx. 6,400’ MD. Hang off in tubing hanger. a) Proposed equipment configuration also shown on the proposed schematic in red font. 15) Drop ball & rod. 16) Set packer with 3,500 psi tubing pressure. 17) Chart pressure test on backside to 3,000 psi. 18) ND BOP/ NU wellhead and test. 19) Move off rig 401. Slickline Procedure 1) MIRU Slickline Unit and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 2) RIH with Retrieving Tool and POOH to surface with ball & rod and plug. 3) RDMO Slickline. (Load well?) (verify tubing and IA have same hydrostatic fluid column before pulling hanger. ) BOPE test 4000 psi CIBP #1 CIBP #2 MIT-IA Well Prognosis Well: CLU 5RD Date: 05-06-2020 Coiled Tubing Procedure 1) MIRU Coiled Tubing Unit (CTU), onto the 2-7/8” tubing. 2) RIH with 1-3/4” coiled tubing to ~10,200’. 3) RU Nitrogen (N2) and blow the 8.4 ppg brine out of the tubing. Leave 3,000 psi on well. RD N2. 4) POOH with coiled tubing. E-Line Procedure 1) MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,500 psi High. 2) If needed, RIH with GPT tool and find fluid level. If fluid is over the depth of the new perfs, discuss using methane or Nitrogen with the Operations Engineer. 3) If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4) RU perf guns. 5) RIH and perforate the below interval: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt Upper Beluga UB-4B ±6,578’ ±6,594’ ±5,403’ ±5,419’ 16’ Upper Beluga UB-7 Upper ±6,735’ ±6,762’ ±5,552’ ±5,577’ 27’ Upper Beluga UB-7 Lower ±6,795’ ±6,820’ ±5,607’ ±5,630’ 25’ Upper Beluga UB-8 & UB-9 ±6,916’ ±6,978’ ±5,716’ ±5,771’ 62’ Lower Beluga LB-2B ±8,407’ ±8,431’ ±6,961’ ±6,981’ 24’ a. Pressure up well to 2,500 psi before perforating. b. Proposed perfs also shown on the proposed schematic in red font. c. Final perfs tie-in sheet will be provided in the field for exact perf intervals. d. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. e. Spacing allowance is based on CO 231 Beluga Gas Pool. f. Use Gamma/CCL to correlate. g. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. h. Record 5, 10 and 15 minutes pressures after firing guns. 6) POOH. 7) RD E-Line. 8) Turn well over to production. E-Line Procedure (Contingency) 1)If this zone produces sand and/or water and needs to be isolated: 2) MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 3,500 psi High. 3) RIH and set 7-5/8” Inflatable Plug above the zone and dump 25’ of cement on top of the plug. Revised Received 5/18/2020 SFD (UPDATED 5/18/20) In CLU 5RD, Sterling C gas Storage Pool base is 6,300' MD, 5,135' TVD 5/18/2020 SFD See also 20 AAC 25.055(a)(2). SFD 5/17/2020 r Beluga UB Up 578 pper wer ±6,795 6,978’ pper Be uga UB ±5 ±5,7 16’ 7 0’ 62 ±5 403 ±5,5 Lower Beluga LB-2B ±8,407’±8,431’±6,961’±6,981’24’approved perfs (PRESSURE TEST CT 4000 PSI ... NOTIFY AOGCC INSPECTOR) Well Prognosis Well: CLU 5RD Date: 05-06-2020 Attachments: 1) Current Well Schematic 2) Proposed Well Schematic 3) BOPE Schematic 4) CTU BOPE Schematic 5) Standard Well Procedure – N2 Operations 6) RWO Sundry Revision Change Form (UPDATED 5/18/20) _____________________________________________________________________________________ Updated by DMA 05-11-20 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 _________________________________________________________ for Platform ______________ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf ~6,400’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Safety Valve 3 6,433’ 6.750” 8.460” 7-5/8” ZXP Liner Top Packer 4 ~6,460’ 4-1/2” Retrievable Packer 5 ~6,470’ 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 ~6,500’ 2-7/8” WLEG 7 +10,230’ 7.625” CIBP w/ 25’ cement (TOC +10,205’) 8 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 9 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 10 +10,305’ 4.500” CIBP 11 10,349’ 4.500” CIBP 12 11,170’ - 3.500” CIBP (TOC 11,170’) 13 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 14 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 15 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 16 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 17 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B +6,578’ +6,594’ +5,403’ +5,419’ Proposed 2-7/8” TBD UB-7 Upper +6,735’ +6,762’ +5,552’ +5,577’ Proposed 2-7/8” TBD UB-7 Lower +6,795’ +6,820’ +5,607’ +5,630’ Proposed 2-7/8” TBD UB-8 & UB-9 +6,916’ +6,978’ +5,716’ +5,771’ Proposed 2-7/8” TBD LB-2B +8,407’ +8,431’ +6,961’ +6,981’ Proposed 2-7/8” TBD UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Open UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Open 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Open D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated (UPDATED 5/18/20) Revised Received 5/18/2020 SFD CINGSA Gas Pool base 5135 ' TVD LB-2B +8,407’+8,431’+6,961’+6,981’Proposed 2-7/8”TBD NOTE:LB-2B interval is only interval approved in this Sundry. (remaining are within 1500 ' tvd of CINGSA Storage Pool) +6,73 wer UB 8 +6594’ 35’35 +6,8 8’+5, UB-4B 67373 5,63 716 30 2 7 30 roposed P 5,403 + 563 7/8” 63 7/8 T BD Proposed 2-77/ approved CIBP #2 CIBP #1 Not approved _____________________________________________________________________________________ Updated by DMA 05-11-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01-00 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 4-1/2” 12.6# / L-80 / IBT-M 3.958” Surf 1,200’ 12.6# / L-80 / SuperMax 3.958” 1,200’ 10,289’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Baker TE-5 Safety Valve 3 1,210’ 3.813” 6.500” 4-1/2” Chemical Injection Mandrel 4 6,433’ 6.750” 8.460” 7-5/8” ZXP Liner Top Packer 5 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 6 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 7 10,245’ – 10,289’ 3.850” 4.500” 4-1/2” Seal Assembly 44’ of Seal Assembly and 5’ of first tubing joint are inside SBE and Liner Top Packer 8 10,349 4.500” CIBP 9 11,170’ - 3.500” CIBP (TOC 11,170’) 10 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 11 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 12 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 13 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 14 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Open UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Open 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Open D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated Fish @ 10,419 SLM CINGSA Sterling C base at 5135 ft TVD _____________________________________________________________________________________ Updated by DMA 05-11-20 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 _________________________________________________________ for Platform ______________ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 2-7/8” 6.4# / L-80 / EUE 8RD 2.441” Surf ~6,400’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Safety Valve 3 6,433’ 6.750” 8.460” 7-5/8” ZXP Liner Top Packer 4 ~6,460’ 4-1/2” Retrievable Packer 5 ~6,470’ 2-7/8” X Profile Landing Nipple (w/ pup joints) 6 ~6,500’ 2-7/8” WLEG 7 +10,230’ 7.625” CIBP w/ 25’ cement (TOC +10,205’) 8 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 9 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 10 +10,305’ 4.500” CIBP 11 10,349’ 4.500” CIBP 12 11,170’ - 3.500” CIBP (TOC 11,170’) 13 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 14 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 15 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 16 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 17 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UB-4B +6,578’ +6,594’ +6,578’ +6,594’ Proposed 2-7/8” TBD UB-7 Upper +6,735’ +6,762’ +6,735’ +6,762’ Proposed 2-7/8” TBD UB-7 Lower +6,795’ +6,820’ +6,795’ +6,820’ Proposed 2-7/8” TBD UB-8 & UB-9 +6,916’ +6,978’ +6,916’ +6,978’ Proposed 2-7/8” TBD LB-2B +8,407’ +8,431’ +8,406’ +8,430’ Proposed 2-7/8” TBD UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/30/20 2-7/8” Open UT-9B 10,326’ 10,346’ 8,640’ 8,660’ 6 03/28/20 2-7/8” Open 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Open D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated CIBP #1 CIBP #2 (10230') CINGSA Pool 6527' WINDOW SUPERCEDED SUPERCEDED ϭϯͲϱͬϴΗϱDKW ,<ϰϬϭZ/' ϭϯͲϱͬϴΗϱD^,&&Z^W,Z/>EEh>Z ϰϱΗd>> ϭϯͲϱͬϴΗϱDEKs>yd>'d͕ϯϭΗd>> Z^^tͬϮͲϳͬϴΗͲϱͲϭͬϮΗDh>d/ZD^/EdKW Z^^tͬ>/EZD^/EKddKD ϭϯͲϱͬϴΗϱDDhZK^^͕ϮϰΗd>> tͬϯ,ϮͲϭͬϭϲΗϱDD's Θϭ,ϮͲϭͬϭϲΗϱD,Z ϭϯͲϱͬϴΗϱD^WZ^WKK>͕ϮϰΗd>> ,<KtE ϭϯͲϱͬϴΗϱD^WZ^WKK>͕ϮϰΗd>> ,<KtE ΕϭϰϴΗdKd>^d<,/',d EEh>Z^dz>KW&>h/^W^͗ ͲϮϯ͘ϱϴŐĂůůŽŶĐůŽƐĞĐŚĂŵďĞƌǀŽůƵŵĞ Ͳϭϳ͘ϰϭŐĂůůŽŶŽƉĞŶĐŚĂŵďĞƌǀŽůƵŵĞ >ydKW&>h/^W^͗ Ͳϱ͘ϭϰŐĂůůŽŶƐƚŽĐůŽƐĞƉĞƌŐĂƚĞ Ͳϰ͘ϴϲŐĂůůŽŶƐƚŽŽƉĞŶƉĞƌŐĂƚĞ Ͳϲ͘ϰϳ͗ϭĐůŽƐŝŶŐƌĂƚŝŽ td,Z&KZ Coiled Tubing HydraCo 60K Injector Head & Gooseneck Weight = 3500 lbs 3" 500psi ArmorPak Stripper Bowen Type 5K 5.5" Lubricator 5K CJS ArmorPak Guide Bowen Type 5K x 5-1/8" 10K Flange 5-1/8" 10K Quad BOP 1.ArmorPak 1.5" x 1.5" Pipe Ram 2.ArmorPak 1.5" x 1.5" Pipe Ram 3.Shear Ram 4.Blind Ram 5-1/8 10K Spool with 2-1/16" 10K Outlets - Kill Port Manual Valve 1: 2-1/16" 10K Manual Valve 2: 2-1/16" 10K Manual Valve 3: 2" Weco 1502 Adapter Spool 5-1/8" 10K x 7-1/16" 5K Adapter Spool 7-1/16" 5K x 5-1/8" 5K 5-1/8" 5K ArmorPak 1.5" x 1.5" CT Head Wellhead STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well: Cannery Loop Unit 5RD (PTD 215-160) Sundry #: XXX-XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: CTCO, Fish Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,940 feet feet true vertical 11,253 feet N/A feet Effective Depth measured 11,170 feet 6,433 & 10,240 feet true vertical 9,484 feet 5,263 & 8,555 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 10,289 (MD) 8,603 (TVD) Baker ZXP + ZXPN Pkrs; 6,433' MD/5,263' TVD & 10,240' MD/8,555' TVD Packers and SSSV (type, measured and true vertical depth)Baker TE-5 SSSV TR 298' MD/ 298' TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 11,170; 11,420; 11,495; 11,550; 11,690; 11,723 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst 6,890psi 142' 1,200' 8,762' 7,930psi 3,090psi Collapse 1,540psi 6,620psi 4,790psi Casing Structural 20" 13-3/8" 9-5/8" Length 2,578' 142' 2,970' 1,212' 3,538' Conductor Surface Intermediate Liner Intermediate 7,966' Liner 2,675' 7 11,229' 0 Representative Daily Average Production or Injection Data 7,500psi Gas-Mcf 61 Authorized Signature with date: Authorized Name: 439 Casing Pressure 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 319-434 & 320-098 86 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-160 50-133-20474-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: Tubing Pressure 2731 Cannery Loop Unit (CLU) 05RD N/A FEE Hilcorp (ADL060569); ADL324602 1,212' 9-5/8"7,599' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai C.L.U. / Upper Tyonek - Tyonek D Gas PoolsN/A measured TVD 0 9,178' Oil-Bbl measured true vertical Packer 7-5/8" 4-1/2" 10,448' 9,440psi 5,300psi WINJ WAG 33 Water-Bbl MD 142' 2,970' 12,915' t Fra O 6. A G L PG , R h Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.05.07 16:31:20 -08'00' Taylor Wellman By Samantha Carlisle at 8:10 pm, May 07, 2020 RBDMS HEW 5/8/2020 gls 5/8/20 DSR-5/11/2020 SFD 5/8/2020 Rig Start Date End Date 2/3/20 4/29/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD 02/03/2020 - Monday PTW, JSA and SIMOPS with AKE-Line and SLB N2. Spot equipment and rig up Lubricator. PT to 250 psi low and 4,000 psi high. RIH w/3.75"gauge ring and GPT tool to 10,305'. Tools set down. Pick up 30' with 100 lb over pull and went back and tagged again. Tried to pick up and tools were stuck. Tried working tools, pull up to just below pull out wt. but didn't come free. Called town and discussed. Tool wt at this depth was 1,700 lb. Worked weight up to min pull out at 2800 lb and back down to 900 lb. Started adding 100 lbs up wt. each time. At 3,500 lbs (about max pull out wt) line pulled out of rope socket. We had started blowing well down before we pulled out of rope socket but it didn't help. POOH while we finished blowing well down to 513.2 psi. Once we get the line out of the well we will start pressuring the well back up. Left tools in well but no wire left in well. Rig down all equipment and secure well. E-line is taking their equipment back to theie shop to cut about 500' of e-line off and replace an air swith on the crane. Pollard slickline will be here in the morning. TP - 511.1 psi 02/04/2020 - Tuesday ARRIVE AT PWL SHOP - GATHER TOOLS AND EQUIPMENT - MOB TO LOCATION. ON LOCATION - TGSM - JSA - PERMIT. RIG UP .160" WIRE - BUILD 60' LUB SUFFICIENT TO COVER ELINE TOOLS - PT LUB 4,000 PSI TP - 1,412 psi. RIH W/ 4" GR W/ BAIT SUB W/ SERIES 70 OVER SHOT FOR 1-11/16" TO 10,393'KB WT LATCH. POOH - 7,000'KB LOSE WEIGHT - CONTINUE OOH - OOH W/ OVER SHOT - DID NOT GET DEEP ENOUGH BITE. RIH W/ SAME TO 10,338'KB WT CAN NOT LATCH - POOH - OOH W/ OVER SHOT. RIH W/ 3.5" LIB TO 10,338'KB WT - POOH - OOH W/ FAINT IMPRESSION OF SINGLE STRAND OF WIRE - NOTHING DEFINITIVE. RIH W/ 3" X 7' PUMP BAILER TO 10,338'KB WT GAIN NO HOLE. POOH - OOH W/ TRACE AMOUNT. OF SAND - NO SIGNIFICANT METAL MARKS ON BAILER BTM. RIH W/ SAME TO 10,338'KB WT GAIN NO HOLE - POOH - OOH W/ EMPTY BAILER. Rig down lubricator. Secure well TP - 962 psi Will come back in am with more tools. Daily Operations: 02/05/2020 - Wednesday ARRIVE AT PWL SHOP - GATHER TOOLS AND PERSONNEL - MOB TO LOCATION. ON LOCAION TGSM - JSA - PERMIT. RIG UP W/L - PT LUB 4,000 PSI - GOOD. BLEED PRESSURE OFF WELL THROUGH SYSTEM FROM 1,300 PSI TO 500 PSI. RIH W/ BOW SPRING CENTRALIZER W/ 3" LIB TO 10,336'KB WT - POOH - OOH W/ IMPRESSION OF NO ROPE SOCKET - POSSIBLY SAND - INCONCLUSIVE. RIH W/ 3" X 7 PUMP BAIER TO 10,336'KB WT TO 10,347'KB. POOH - OOH W/ BAILER BOTTOM. PACKED WITH MUD. RIH W/ SAME TO 10,347'KB WT TO 10,348'KB POOH - OOH W/ EMPTY BAILER - METAL MARKS. ON BAILER BOTTOM INDICATE ELINE ROPE SOCKET. RIH W/ 4" GR tool W/ BAIT SUB AND SERIES 70 OVER SHOT TO 10,348'KB WT 100 LBS OVER PULL. POOH - OOH W/ BAIT SUB - NO FISH RIH W/ BOW SPRING CENTRALIZER W/ 3" LIB TO 10,378'KB WT - POOH - OOH W/ IMPRESSION. CLEAN ROPE SOCKET RIH W/ 3" GR W/ BAIT SUB W/ SERIES 20 OVER SHOT (2.77" OD) TO 10,380'KB WT - LATCH FISH. 1,800 LBS TO 2,500 LBS OIL JAR LICKS - SLIP OFF REPEATEDLY - POOH - OOH W/ OVER SHOT. GR IS SHEARED BUT DID NOT FULLY RELEASE LAY DOWN LUB - SECURE WELL - MOB TO PWL SHOP. ETA PWL SHOP. Left fish GPT tool at 10305 ft SIMOPS with AKE-Line and SLB N2. S At 3,500 lbs (about max pull out wt) line pulled out of rope socket. W Rig Start Date End Date 2/3/20 4/29/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD Daily Operations: 02/08/2020 - Saturday ARRIVE AT PWL SHOP - GATHER TOOLS AND PERSONNEL - MOB TO LCATION. ON LOCATION - TGSM - JSA - PERMIT. RIG UP W/L - CUT WIRE AND REHEAD - CHANGE OUT OIL JARS TO LONG STROKE - PT LUB TP - 433 psi. 4,000 PSI - GOODRIH W/ 3" GS WITH NO DOGS TO 10,396'KB WT (TO SEE IF SHEAR DOWN TOOL WILL SHEAR). POOH - OOH W/ GS NOT SHEARED - FULL OF MUD. RIH W/ 3" X 7' PUMP BAILER TO 10,399'KB WT TO 10,403'KB - GAIN NO MORE HOLE - POOH. OOH W/ 2 CUPS SAND - METAL MARKD ON BOTTOM SHOW BAIT SUB FISHING NECKRIH W/ 3" GR TO 10,403'KB WT CAN NOT LATCH - POOH - OOH W/ GR NOT SHEARED. RIH W/ 2" X 8' PUMP BAILER TO 10,403'KB WT TO 10,404'KB - POOH - OOH W/ 2 CUPS SAND. RIH W/ 3" GR TO10,404'KB WT - TOOLS APPEAR TO BE FALLING - 10,410'KB - CAN NOT LATCH - POOH - OOH W/ GR NOT SHEAREDSTANDBY FOR HYDROSTATIC BAILER. SHUT DOWN FOR WIND - RIG DOWN W/L - SECURE WELL TP - 412.1 psi. MOB TO PWL SHOP. 02/06/2020 - Thursday ARRIVE AT PWL SHOP - GATHER TOOLS AND PERSONNEL - MOB TO LOCATION. ON LOCATION - TGSM - JSA - PERMIT. RIG UP W/L - SWAP OUT 1.75" X 10 STEM FOR 2.25" X 13' - PT LUB 4,000 PSI - GOOD. RIH W/ 3" X 7' PUMP BAILER TO 10,361'KB WT TO 10,372'KB. POOH - OOH W/ FULL BAILER SAND RIH W/ SAME 10,367'KB WT TO 10,377'KB. POOH - OOH W/ 1/3 FULL SAND AND MUD. RIH W/ 3" GS W/ BAIT SUB W/ SERIES 20 OVERSHOT TO 10,380'KB WT. LATCH - 5 X 3000LBS. OIL JAR LICKS COME FREE - APPEAR TO HAVE EXTRA WEIGHT - POOH - OOH W/ OVER SHOT RIH W/ 4" GR W/ BAIT SUB W/ SERIES 70 OVER SHOT TO 10,385'KB WT COULD NOT LATCH. POOH - OOH W/ OVER SHOT W/ REMNANTS OF MUD INSIDE. RIH W/ 3" X 7' PUMP BAILER TO 10,386'KB WT TO 10,389'KB. POOH - OOH W/ 1/2 FULL SAND RIH W/ SAME TO 10,387'KB WT TO 10,389'KB. POOH - OOH W/ 1 CUP SAND - BTM SHOWS METAL MARKS REPEATEDLY HITTING ELINE ROPE SOCKET RIH W/ 3" GR W/ BAIT SUB W/ SERIES 20 LONG REACH OVER SHOT (2.31 OD) TO 10,403'KB WT. LATCH 15 X 3000LBS OIL JAR LICKS - 5 X 3500LBS OIL JAR LICKS - GR SHEARS - POOH - OOH W/ SHEARED GR. RIG DOWN W/L - SECURE WELL - MOB TO PWL SHOP Anchorage will have meeting on next move. ETA PWL SHOP. 02/10/2020 - Monday ARRIVE AT PWL SHOP - GATHER TOOLS AND PERSONNEL - MOB TO LOCATION. ON LOCATION - TGSM - JSA - PERMIT. RIG UP W/L - PT LLUB 4,000 PSI - GOOD. RIH W/ 3" X 7' PUMP BAILER TO 10,408'KB WT TO 10,410'KB - POOH - OOH W/ FULL SAND RIH W/ SAME TO 10,413'KB WT TO 10,416'KB - POOH - OOH W/ 1/3 FULL SAND. RIH W/ 1.75" X 6' HYDROSTATIC BAILER W/ 2.5" SNORKEL BTM TO 10,416'KB WT TO 10,419'KB. POOH - OOH W/ 3 CUPS SAND. RIH W/ 3" GR (Not gauge - it's pulling tool) TO 10,419'KB WT COULD NOT LATCH - POOH. RIH W/ SAME W/ KJ ABOVE TO 10,419'KB WT COULD NOT LATCH - POOH. Town called and decision was made to rig down and do a workover on the well. RIG DOWN EQUIPMENT, SECURE WELL AND CLEAN UP WORK AREA. RIG DOWN SLB N2 HARD LINES AND SLB TOOK EQUIMENT BACK TO THEIR SHOP. - TOOLS APPEAR TO BE FALLING - 10,410'KB - CAN NOT LATCH - POOH - OOH W/ GR NOT SHEAREDSTANDBY FOR HYDROSTATIC BAILER. S Rig Start Date End Date 2/3/20 4/29/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD Daily Operations: PTW, JSA with SLB coil, Cruz, and Hilcorp Rep. Fire equipment. Pick injector head and 1x 10' stick of lubricator. Read memory tech checking connectivity, depth vs coil depth, and tool battery life. Pull test CT connector (roll on ) to 25k. Make up logging tools. BHA details. 1.75" OD x.2' roll on coil connector, 1.75" OD x 1.12' DFCV, X over 1.51" SA box by 1.5" MT pin, Memory battery 1.69" OD x 2.38', Ultra wire memory tool 1.69" OD x 2.14', Gamma Ray 1.69" OD x 1.92', CCL 1.69" OD x 1.54', Bull nose terminator 1.68" OD x .22', 1.75" jet swirl nozzle. ( Shroud installed over memory tools to enable CT pumping around tools. Stab on well. PT stack 250/3,500 psi. Open swab swab 23.5 turns. Initial WHP 335 psi. Crack choke to bleed off while RIH with 1.75" CT and Memory tools. Cool down N2 pump. Online down CT with N2 at 500 scf/min @ 3,500' CTMD. 5,100' WT check clean 10K, 10,000' WT check clean 19K, Tagged top of fish or fill at 10,328' CTMD. N2 rate still 500 scf/min down CT. WHP 45 psi, CT circulating pressure 48 psi. With no circulation pressure its a good indication that there was no fluid level above the fish. 2x 50 bbl batches of flo-vis-L gel and F104 foam mixed up. 65,000 scf pumped prior to adding fluid rate. Increase N2 rate to 700 scf/min and fluid/foam rate to .4 bbls/min. Attempt to set weight on fish to move down hole. Foam at nozzle. Wash into GS profile of fish and PU 50' Repeat 4 times. Start POOH from 10,328' until foam/N2 returns are seen at surface. At 7,348' CTMD Circ pressure broke over 3,695 psi, Returns to surface. 3-5 bbls of thick black greasy fluid. Returns cleaned up foam quality increasing. Run in hole from 7,483' to start cleaning and washing fish neck at 10,328' CTMD. Tagged TOF stack 5k down. Not moving Attempt to hit fish at different speeds stacking up to 12K down. Fish not moving. Pump 2 bottoms up from 10,328' CTMD. Wait at 10,300' for 5 minutes for logging tool delay. Start logging OOH t 80 ft/min to 9,500' and stop for logging break for 5 minutes. POOH at 120 ft/min to surface. Shut down N2 pump after 2nd bottoms up reached surface . Tagged up shut in well 752 psi SITP. N2 fill clean out data. 1,000 scf/min, .6 bbls/min, choke 150 psi, Circ 3,645 psi = Equivalent circulating density of 3.5 PPG, 1.51 bbls/min, Annular Velocity of 120 ft/min. Hydro-static at CT depth of 10,328' is 2,033 psi. Popped off well. Break down Memory tools and check for data. Data confirmed. Continue to rig back CT unit. Total fluid (foam) pumped 101 bbls. N2 pumped for job 243,942 scf or 2,619 gal. Used CLU-05RD_TM3D log to tie in memory gamma/CCL. sent log to town. +21' correction for coil depth/flag. Top of fish is at 10,355.12'. 03/20/2020 - Friday PTW/JSA with SLB coil, Cruz crane and vac truck and Hilcorp rep. Fire equipment. Spot in CTU Unit with 1.75" coil, MPF fluid pump, crane, and Rain for rent supply and return tanks. Unload and spot auxiliary equipment. RU hard line . Load supply tank with 250 bbls of produced water. Air liquid on location. Fill SLB N2 tank with 3,200 gallons of N2. Spot in SLB batch mixer. United rentals deliver man lift. Install ground thaw hoses into supply tank. 24 Hr BOPE test witness notification sent 3/18/2020 @ 12:28. Witness waived by Jim Regg on 3/18/2020 @ 12:37 hrs. Start BOPE test. Test all rams and valves 250/3,500 psi. Perfomr accumulator draw down test. All tests passed. BOPE test complete. Location walk around completed with SLB coil supervisor and Hilcorp Wellsite Supervisor. Location secure. Pick up Reed cased hole tools from Otter hanger. 03/21/2020 - Saturday Top of fish is at 10,355.12'. N2 pumped for job 243,942 scf or 2,619 gal. Returns cleaned up foam quality increasing. Run in hole from 7,483' to start cleaning and washing fish neck at 10,328' CTMD. Ta fish at 10355 (GPT tool) PTW/JSA with SLB coil, Cruz crane and vac truck and Hilcorp rep. Spot in CTU Unit w Rig Start Date End Date 2/3/20 4/29/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD Daily Operations: 03/28/2020 - Saturday Sign in. PTW and JSA. Spot and rig up equipment. Had trouble keeping the tri-plex pump running. Mechanic came out and it started and ran right off the bat. Brought pressure up to 250 psi and tree cap leaked. Tightened tree cap. Pressure test lubricator to 250 psi low and 4,000 psi high. RIH w/ 2-7/8" x 20' Razor HC, 6 spf, 60 deg phase and tie into the OHL. Bleed well down to 1,000 psi while running in hole. Run correlation log and send to town. Get ok to perf from 10,346' to 10,326'. Spotted and fired gun with 1021 psi on tubing. Pressure went to 1054 psi in less than a minute. Then level off to 1,055.9 psi. POOH to about to -21' and stopped dead. Tried to close swab, middle master and bottom master and the turns showed the e-line tools were across all valves. Checked the wireline valve and tools across them. Called town and discussed. Will talking to town the e-line hands hand pushed the kinked line thru grease tube. Closed all valves and thought they had the tools. Broke off lubricator and tools were gone. I have slickline coming out in the morning to fish the tools and E-line out to perf the last zone when we get them out. Rigged off lubricator. Checked line and cut some curled up line off. Checked lubricator and going to bring one joint in. Well is shut in. PTW and JSA. PT to 250 psi low and 3,500 psi high. RIH with coil and Jet nozzle down to 2,300'. Bring on N2 at 800 scf and RIH pumping at that rate down to 10,345' ctm and tag plug. That is coil tubing measurement and not correlated. Set on bottom until we were getting N2 back. Waited another 10 min while it leaned up. POOH pumping N2 until we got to 8300' and then shut down the N2 and pulled out of hole at 85 fpm. TP was 2,800 to 3,000 psi. Got on surface and blew well down to 1,300 psi. Pressure should drop some after it cools down. SLB used 2,700 gals of N2. SLB coil unloaded approx 160 bbls of fluid from well. Rig down coil tubing and secure well. Coil will be moved to Beaver Creek in the AM. 03/24/2020 - Tuesday PTW, JSA and SIMOPS with SLB Coil and HLB. TP - 0 psi SLB is taking off their BOP and putting the 4-1/2" Otis well head connection back on tree. Halliburton does not have the cross over from coil lubricator to their lubricator is reason why are doing this. RIH with 3.50" OD CIBP and tie into Coil memory log. Tools set down at 10,351'. Ran correlation log and send to town. Got ok to set plug at 10,349' (Top Of Plug). Spotted and set plug with 0 psi on tubing. Lost 250 lbs of line tension when plug set. Pick up 30' and went back down and tagged. POOH. Setting tool look good. Looks like a good plug set. Rig down lubricator and secure well for coil tomorrow. 03/25/2020 - Wednesday SetCIBPontopoffish 10,326' gun 1 Got ok to set plug at 10,349' (Top Of Plug) Get ok to perf from 10,346' to SIMOPS with SLB Coil and HLB. Rig Start Date End Date 2/3/20 4/29/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-133-20474-00 215-160 Well Name CLU 05RD Daily Operations: TW and JSA. Rig lubricator up. PT lubricator to 250 psi low and 3,500 psi high. TP - 1,093 psi. RIH w/ 2-7/8" x 20' HC, 6 spf, 60 deg phase, tie into perf log and tag plug at 10,347'. Run correlation log and send to town. Get ok to perforate from 10,306' to 10,326' with 1,093.6 psi on well. Spot and fire gun with 1,093.6 psi on tubing. After 5 min - 1,096.9 psi, 10 min - 1,097.0 psi and 15 min - 1,097.9 psi. Fired gun at 1109 hrs. POOH. All shots fired gun was wet. Rig down lubricator and equipment. Turn well over to field. TP - 1,098.8 psi. 03/29/2020 - Sunday PTW, JSA and SIMOPS w/Pollard SL and AKE-Line. Spot SL equipment, PT to 250 low and ,3000 high. TP -1,050 psi RIH w/ 3.70' LIB and tagged top of fish at 10,321' KB WLM. Top of tools should be 10,313' correlated. Hit down on fish and POOH. Had good impression of rope socket. Took picture and sent to town. RIH w/GS pulling tool baited overshot to catch 1-7/16" rope socket body and tagged top of fish at 10,321' KB wlm. beat down trying to latch fish. Could not latch up. POOH. Could not see anything wrong. Operator called his supervisor and discussed. Added more weight. RIH w/GS pulling tool baited overshot to catch 1-7/16" rope socket body and tagged top of fish at 10,321' KB wlm. beat down trying to latch fish. Beat down pretty hard 5 more times and POOH. No fish. RIH with/GS pulling tool, baited overshot to catch 2" shooting CCL/Gama Ray protector sleeve. Tag fish at 10,321' KB WLM and latch fish. POOH with 1,300 lbs of extra line wt. (fish weigh about 450 lbs). Got all tools out of hole. All shots had fired and gun was dry. Rig down lubricator and secure well. Break lubricator apart one section at a time after we got 20' gun off. Broke off fish from slickline tools. Going to rig up e-line wireline valves tonight and get things ready to perf first thing in the morning. TP - 1,054 psi. 03/30/2020 - Monday 04/29/2020 - Wednesday Decided to close out and perform RWO. Tag fish at 10,321' KB WLM and latch fish. POOH w gun 2 All shots had fired and gun was dry. o perforate from 10,306' to 10,326' wit fish _____________________________________________________________________________________ Updated by DMA 05-07-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01-00 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515” Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535” Surf 1,212’ 47 / P-110 / BTC 8.681” 1,212’ 9,178’ 7-5/8” Liner 29.7 / L-80 / HYD 511 6.875” 6,433’ 6,910’ 29.7 / L-80 / SLIJ-II 6.875” 6,910’ 10,448’ 4-1/2” Liner 12.6 / L-80 / DWC/ C 3.958” 10,240’ 12,915’ TUBING DETAIL 4-1/2” 12.6# / L-80 / IBT-M 3.958” Surf 1,200’ 12.6# / L-80 / SuperMax 3.958” 1,200’ 10,289’ JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.000” 6.750” Tubing Hanger, 4-1/2” 2 298’ 3.812” 7.110” Baker TE-5 Safety Valve 3 1,210’ 3.813” 6.500” 4-1/2” Chemical Injection Mandrel 4 6,433’ 6.750” 8.460” 7-5/8” ZXP Liner Top Packer 5 10,240’ – 10,272’ 4.820” 6.560” 4-1/2” ZXPN Liner Top Packer 6 10,272’ – 10,298’ 4.740” 6.270” Liner Sealbore Extension 7 10,245’ – 10,289’ 3.850” 4.500” 4-1/2” Seal Assembly 44’ of Seal Assembly and 5’ of first tubing joint are inside SBE and Liner Top Packer 8 10,349 4.500” CIBP 9 11,170’ - 3.500” CIBP (TOC 11,170’) 10 11,430’ - 3.500” CIBP w/ 10’ cement (TOC 11,420’) 11 11,505’ - 3.500” CIBP w/ 10’ cement (TOC 11,495’) 12 11,565’ - 3.500” CIBP w/ 15’ cement (TOC 11,550’) 13 11,700’ - 3.500” CIBP w/ 10’ cement (TOC 11,690’) 14 11,723’ - 3.500” CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status UT-9B 10,306’ 10,326’ 8,620’ 8,640’ 6 03/29/20 2-7/8” Open 91-2 10,767’ 10,785’ 9,081’ 9,099’ 6 10/10/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 06/03/17 2-7/8” Open 91-2 10,767’ 10,787’ 9,081’ 9,101’ 6 03/13/17 2-7/8” Open D-2C 11,081’ 11,106’ 9,395’ 9,420’ 6 12/22/16 2-7/8” Squeezed D-3A 11,321’ 11,346’ 9,635’ 9,660’ 6 11/25/16 2-7/8” Isolated D-4A 11,460’ 11,480’ 9,774’ 9,804’ 6 10/29/16 2-7/8” Isolated D-4A 11,460’ 11,490’ 9,774’ 9,804’ 6 10/14/16 2-7/8” Isolated D-5 11,510’ 11,530’ 9,824’ 9,844’ 6 06/15/16 2-7/8” Isolated D-5A 11,572’ 11,580’ 9,886’ 9,894’ 6 01/22/16 2-7/8” Isolated D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8” Isolated D-6 11,712’ 11,722’ 10,026’ 10,036’ 6 12/07/15 2-7/8” Isolated D-6 11,726’ 11,738’ 10,039’ 10,051’ 6 01/08/16 2-7/8” Isolated Fish @ 10,419 SLM set 3/24/20 Fish @ 10,419 SLM PERF interval should be 10306-10346' gls 8 10,349 4.500”CI THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Taylor Wellman Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Kenai CLU Field, Upper Tyonek and Tyonek D Gas Pool, CLU 05RD Permit to Drill Number: 215-160 Sundry Number: 320-098 Dear Mr. Wellman: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, J eprice Chair DATED this q day of March, 2020. RBDMS��MAR 0 5 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n oar )F 9nn RECEIVE® MAR 3 2020 #07S 319-1-4,c) A®GCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate (] Repair Well ❑ Operations shutdown El Suspend © Perforate 0 Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Coiled Tubing Clean Out 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ;yA Hilcorp Alaska, LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 215-160 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-133-20474-01-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231, Rule 3 ' Will planned perforations require a spacing exception? Yes[—] No Cannery Loop Unit (CLU) 05RD 9. Property Designation (Lease Number): 10. Field/Pool(s):'' Kenai C.L.U. / ak upper Tyonek Gas Pooled rzq i°7Xi FEE Hilcorp (ADL060569) / ADL324602 B0- cTi� `� l 11. PRESENT WELL CONDITION SUMMARY 3.:3 a 2G Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,940 11,253 X11,170 9,484 —416 psi See Schematic N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090 psi 1,540 psi Intermediate 1,212' 9-5/8" j 1,212' 1,200' 1 7,930 psi 6,620 psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440 psi 5,300 psi Liner 4,015' 7-5/8" 10,448' 8,762' 6,890 psi 4,790 psi Liner 2,675' 4-1/2" 12,915' 11,229' 1 8,430 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 10,767' - 10,787' 9,081' - 9,101' 4-1/2" 12.6# / L-80 10,289' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker ZXP & ZXPN Packers & Baker T -E5 SSSV 6,433' (MD) 5,263' (TVD) / 10,240' (MD) 8,555' (TVD) & 298' (MD) 298' (TVD) 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch [2) Exploratory ❑ Stratigraphic ❑ Development I] ' Service 14. Estimated Date for 15. Well Status after proposed work: March 16th, 2020 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ El 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: Taylor Wellman 907-777-8449 Contact Name: Christina Twogood Authorized Title: Operations a Contact Email: gtmogood@hileorp.com Contact Phone: 907-777-8443 Authorized Signature: Date: oS e@ zirL;y COMMIS ION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3;IL0 -O Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance (] Other: nclms �� MAR R 5 mo Post Initial Injection MIT Req'd? Yes © No Spacing Exception Required? Yes No Subsequent Form Required: / Q r Ll Oq APPROVED BY -3/4i2O Approved by: COMMISSIONER THE COMMISSION Date: �/ 3/`l/ Po ed(al2t App o d application is(Al f e of a royal. ;` 3`Zp'Submit Form and PP � �1cents in Duplicate H Iflimm Alaska, LL Well Prognosis Well: CLU 5RD Date: 3-2-2020 Well Name: CLU 5RD API Number: 50-133-20474-01-00 Current Status: Shut -In Gas Well Leg: N/A Estimated Start Date: March 16th, 2020 Rig: CTU Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) AFE Number: Max. Expected BHP: Max. Potential Surface Pressure: Brief Well Summary 1,326 psi @ 9,101' TVD '" 416 psi (Based on CLU 1RD pressure) (Based on expected BHP and gas gradient to surface (0.10 psi/ft)) CLU-05RD was drilled in 2015 and completed in 2016. The well has been perforated in the D-6, D -5A, D -4A, D - 3A, D -2C and 91-2 sands, all of which have since been isolated. The purpose of this work/sundry is to rig up coiled tubing and RIH cleaning out fill to the top of the fish. The well will then be jetted dry with nitrogen. Notes Regarding Wellbore Condition 2 Fish left in hole at 10,419' SLM (original stuck at 10,305' ELM) on 2/10/2020 Previous tag w/ 3" x 5' bailer at 10,786' MD on 5/1/2019 Well is currently SI Safety Concerns • Discuss Nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people cou a"�—` • Considertank placement based on wind direction and current weather forecast (venting Nitrogen during thisjob). • Ensure all crews are aware of stop job authority. n JuIc,.m Alaeka, LL Coiled Tubing Procedure Well Prognosis Well: CLU 5RD Date: 3-2-2020 1. MIRU Coiled Tubing Unit onto the 4-1/2" tubing string. Pressure test BOPE to 250 psi Low / 3,500 psi High. 2. RU Nitrogen Pump. 3. PU & RIH with GR/CCL Memory Tool and nozzle BHA on Coil. 4. Clean out in increments with Nitrogen and/or brine down to fish located at approx. 10,419' SLM. 5. Tag fish and push approx. 100' down wellbore. 6. Blow well dry with Nitrogen. 7. Perform correlation pass from depth of fish to approx. 10,000'. 8. POOH to surface, unload memory tool and download data. 9. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer and Geologist for confirmation. 10. Discuss correlated depth of fish with Operations Engineer and confirm it is deep enough for planned perforations. If needed, push fish further down or proceed to retrieve fish. 11. RDMO Coiled Tubing Unit. 12. Proceed with well operations as per Approved Sundry 319-434. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. CTU BOPE Schematic 4. Standard Well Procedure— N2 Operations S. RWO Sundry Revision Change Form �nm 13-3/8" S1 1 3 8-1/2" windowat 6,527'MD 5,354' TVD 9-5/8" 7-5/8" Type Wt/Grade/Conn 5.6.7 Top Btm Fish Q 10,419 SIM1-2 Conductor 7ID-2C N/A RgWj11'090 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" 8 , 53.5/L-80/BTC 47/P-110/BTC 8.535" 8.681" Surf 1,212' 1,212' 9,178' D -3A 9 `> 6.875" 6,433' 6,910' D -4A m 4-1/2" 1 Liner 12.6 / L-80 / DWC/ C 3.958" MM 11 4.500" 4-1/2' Seal Assembly 6 sa D -5A inside SBE and Liner Top Packer 8 U64 RA WJl 1 1 CIBP (TOC 11,170') 11,633 11,430' 12,13 RA ""' 12,OW' RAI -t 12,474 41/2" PBTD=11,170' VID/9,484'TVD TO =12,940' MD / 11,253' TVD SCHEMATIC Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 129/N/A/N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5/L-80/BTC 47/P-110/BTC 8.535" 8.681" Surf 1,212' 1,212' 9,178' 7-5/8" Liner 29.7/L-80/HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / 5LI1-II 6.875" 6,910' 10,448' 4-1/2" 1 Liner 12.6 / L-80 / DWC/ C 3.958" 10,240' 12,915' TUBING DETAIL JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'-10,289' 3.850" 4.500" 4-1/2' Seal Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 11,170' - 3.500" 1 CIBP (TOC 11,170') 9 11,430' 2-7/8" 3.500" CIBP w/ 10' cement (TOC 11,420') 10 11,505' 9,635' 3.500" CIBP w/ 30' cement (TOC 11,495') 11 11,565' - 3.500" CIBP w/ 15' cement (TOC 11,550') 12 11,700' - 3.500" CIBP w/ 10' cement (TOC 11,690') 13 11,723' - 3.500" CIBP Updated by CMT 2-19-2020 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) I Btm (TVD) SPF Date Size Status 91-2 10,767' 10,785' 9,081' 9,099' 6 10/10/17 2-7/8" Open 91-2 10,767' 10,787' 9,081' 9,101' 6 06/03/17 2-7/8" Open 91-2 10,767' 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Open D -2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed D -3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated D -4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated D -4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 2-7/S" Isolated D-5 11,510' 11,530' 9,824' 9,844' 1 6 06/15/16 2-7/8" Isolated D -SA 11,572' 11,580' 9,886' 9,894'6 01/22/16 2-7/8" Isolated D -SA 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated Updated by CMT 2-19-2020 n Hilcorp Alaska, LLC RKB =18' � 7 20 2 SSW 13-3/8" 3 9-5/8" JO1 PROPOSED SCHEMATIC 8-1/' windowat 6,527'MD 5,354' TVD R4 Mu 11,633 12, 13 D-6 PAMTJ1 12060 RA NTA M474' 4112" �K PBTD =11,170' MD / 9,484' TVD TD =12,940' MD / 11,253' TVD Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size 4 Wt/Grade/Conn 7-5/8'5,6,7 1 Item Btm 20" �- [,,h Q+10,519 SLM N/A I Surf 91-2 RA MT Jt Surface 61/K-55/BTC 11,09x' Surf 2,970' 9-5/8" Intermediate D -2C 8 Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' D -3A 9 29.7 / L-80 / HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / SUJ-I I 6.875" 6,910' to Liner Sealbore Extension r7 12.6/L-80/DWC/C 3.958" 1 as 11 6 44' of Seal Assembly and 5' of first tubing joint are R4 Mu 11,633 12, 13 D-6 PAMTJ1 12060 RA NTA M474' 4112" �K PBTD =11,170' MD / 9,484' TVD TD =12,940' MD / 11,253' TVD Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/Grade/Conn IDTop Item Btm 20" Conductor 129/N/A/N/A N/A I Surf 142' 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5/L-80/BTC 8.535" Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29.7 / L-80 / HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / SUJ-I I 6.875" 6,910' 10,448' Liner Sealbore Extension Liner 12.6/L-80/DWC/C 3.958" 1 10,240' 12,915' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" 2 298' 3.812' 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272'- 10,298' 4.740" 6.270" Liner Sealbore Extension 7 1 10,245'-10,289' 3.850" 4.500" -Z:1/2' Sea] Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 11,170' - 3.500" CIBP (TOC 11,17(') 9 11,430' - 3.500" CIBP w/ 10' cement (TOC 11,420') 10 11,505' - 3.500" CIBP w/ 10' cement (TOC 11,495') 11 11,565' - 3.500"CIBP w/ 15' cement (TOC 11,550') 12 11,700' - 3.500" CIBP w/ SO' cement (TOC 11,6901) 13 11,723' - 3.500" CIBP Updated by CMT 3-2-2020 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status 91-2 10,767' 10,785' 9,081' 9,099' 6 10/10/17 2-7/8" Open 91-2 10,767' -10,767' 10,787' 9,081' 9,101' 6 06/03/17 2-7/8" Open 91-2 10,787' 9,081' 9,101' 6 03/13/17 " Open D -2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 Squeezed D -3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 " Isolated D -4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 :2-7/8" " Isolated D -4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 " Isolated D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 " Isolated D -SA 11,572' 11,580' 9,886' 91894' 6 01/22/16 2-7/8" Isolated D -SA 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated Updated by CMT 3-2-2020 2-1116 10K 9 SL6 Cr Coiled Tubing HR580 Injector Head R Gooseneck Weight = 12,860 lbs 4.1116" 1 OK Conventional Stripper SK C062 Lubricator SK 0062 x 4-1116" 10K Flange 4-1/16" 10K Combi BOP Top Set SindlSnear Se^.d Set P e , 4-1116" 10K Flow Cross MmWI 2x2 Valva 1 2" 1502 x 2-1116" 10K Range Manus) 2x2 Valval. 2A/16" 10K x2-1116" 10K Rarge Mand 2x2 Valva 3 2-1116" 10K x 2-1116" 10K Flange Manus 2x2 Valve 4'. 2" 1502 x 2-1/16" 10K Range 4.1116" 10K x Wellhead Adapter Flange Wellhead STANDARD WELL PROCEDURE Ililcorp:kla6ka.LLL NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINALv1 Page 1 of 1 a a io 0 U m i r w>� U R c O 2 y O a `0 CL CL N y Y O �. R 2 CL m a a � a dy 2 ym+� CL M Cl O � d v �- Z d rn c m r U 3 d U O a` Y 0 d a m CL U d co Em d A O 1 •o Q a d N ❑ n THE STATE Alaska Oil and Gas ALASKA TASK A Conservation Commission GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai CLU Field, Upper Tyonek Gas Pool, CLU 05RD Permit to Drill Number: 215-160 Sundry Number: 319-434 Dear Mr. York: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279,1433 Fax: 907.276.7542 www. a o g c c. a l a s ka, g o v Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Vr DATED thisAay of January, 2020. 3BDMS4 � JAN 3 12020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS i .t IATA -Ar 9R 9Rn Z7/act 4� is • 1. Type of Request: Abandon ❑ Plug Perforations ^Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate 0 Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 215-160 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-133-20474-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231, Rule 3 Will planned perforations require a spacing exception? Yes ❑ No El Cannery Loop Unit (CLU) 05RD 9. Property Designation (Lease Number): 10. Field/Pool(s): FEE Hilcorp (ADL060569) / ADL324602 I Kenai C.L.U. /Aqqng� Upper Tyonek Gas Poof /',&S, 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,940 11,253 11,170 9,484 3,686 psi See Schematic N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090 psi 1,540 psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930 psi 6,620 psi Intermediate 7,966' 9,178' 7,599' 9,440 psi 5,300 psi Liner 4,015' 10,448' 8,762' 6,890 psi 4,790 psi Liner 2,675' 12,915' 11,229' 8,430 psi 7,500 psi ETVD(ft): Perforation Depth MD (ft): Perforation DepTubing Size: Tubing Grade10,767-10,787 9,081-9,1014-1/2" 12.6#/L-80 10,289 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker ZXP &7XPN Packers & Baker T -E5 SSSV 6,433' (MD) 5,263' (TVD) / 10,240' (MD) 8,555' (TVD) & 298' (MD) 298' (TVD) 12. Attachments: Proposal Summary Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: October 7, 2019 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS Q 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: Bo York - Contact Name: Christina Twogood Authorized Title: OperatPs Manager Contact Email: CtwO oOd hilcor .Cont r+ Contact Phone: 907-378-7323 Authorized Signature: Ni Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 0 - Y 3 —! Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: ' ]AN 3 12020 RMAS Post Initial Injection MIT Req'd? Yes ❑ No Spacing Exception Required? Y No Subsequent Form Required: 1 C) — A -lo Lf APPROVED BY Approved by: \ � COMMISSIONER THE COMMISSION Date: CIVIC /y t D 1 I Submit Form and Llyft 10-403 ;vise 7 Approve appli ti li r 1 L the date of approval nachmrnts f Dyoiicatte H IIac.0 Alaska, LLi Well Prognosis Well: CLU-05RD Date: 9/18/2019 Well Name: CLU-05RD API Number: 50-133-20474-01-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: October r, 2019 Rig: E -Line Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) AFE Number: Actual BHP: Max. Expected BHP: Max. Potential Surface Pressure: Brief Well Summary 4,747 psi @ 9,051' TVD — 4,554 psi @ 8,683' TVD 3,686 psi @ 8,683' TVD (Based on 4/9/17 static buildup) (Based on static buildup gradient) (Based on expected BHP and gas gradient to surface (0.1 psi/ft)) CLU-05RD was drilled in 2015 and completed in 2016. The well has been perforated in the D-6, D -5A, D -4A, D - 3A, D -2C and 91-2 sands, all of which have since been isolated. The purpose of this work/sundry is to add perforations in the Tyonek UT -96 sand. Notes Regarding Wellbore Condition • Last tag w/ 3" x 5' bailer at 10,786' MD on 5/1/2019 • Well is currently SI Safety Concerns • Discuss Nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Considertank placement based on wind direction and current weatherforecast (venting Nitrogen during this job). • Ensure all crews are aware of stop job authority. E -Line Procedure 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low/4,000 psi High. 2. RIH with GPT tool and find fluid I. If fluid is over the depth of the new perfs, discuss using methane or Nitrogen with the Operations Engineer. 3. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4. RIH with 4-1/2" CIBP and set at + 10,750' MD n. t,�`cement on top. POOH. 5. RU perf guns. 6. RIH and perforate the below interval: ZoneSand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Tyonek UT -913 ±10,307' ±10,369' ±8,621' ±8,683' 62' ff HikorP Alaska. LLi Well Prognosis Well: CLU-05RD Date:9/18/2019 a. Pressure up well to 3,500 psi before perforating. b. Proposed perfs also shown on the proposed schematic in red font. c. Final perfs tie-in sheet will be provided in the field for exact perf intervals. d. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. e. Spacing allowance is based on CO 231, Rule 3. f. Use Gamma/CCL to correlate. g. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. h. Record 5, 10 and 15 minutes pressures after firing guns. 7. POOH. 8. RD E -Line. 9. Turn well over to production. E -Line Procedure (Contingency) 1. If this zone produces sand and/or water and needs to be isolated: 2. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low/ 4,000 psi High. 3. RIH and set 4-1/2" Casing Patch or set 4-1/2"" CIBP above the zone and dump 25' of cement on top of the plug. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Standard Well Procedure—N2 Operations K thlcorp Alaska, LLC RKB =18' 1 20" 2 r; 13-3/8" 3 E ti 7-5/8" 5, 6,7 791-2 RAM A Type Wt/Grade/Conn 11,[90 Top Bit, 20" Conductor 0.2C 8 Surf 142' 13-3/8" Surface 0.3A 9 r 2,970' 9-5/8" Intermediate -D-4A 10 ' Surf 1,212' 1,212' 9,178' 7-5/8" Liner o -s 11 6,433' 6,910' 29.7 / L-80 / SLIJ-II 6.875" fi,9101 10,448' D -5A Liner 12.6/L-80/DWC/C D 6A RAMP 12,915' 4.500" 11,633 6 tZ 13 RA MPJI 1zow RA Mvh 12,471' 4-1/T PBTD =11,170' MD / 9,481' TVD TD =12,940' MD / 11,753' TVD SCHEMATIC Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/Grade/Conn ID Top Bit, 20" Conductor 129/N/A/N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5/L-80/BTC 47/P-110/BTC 8.535" 8.681" Surf 1,212' 1,212' 9,178' 7-5/8" Liner 29.7/L-80/HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / SLIJ-II 6.875" fi,9101 10,448' 4-1/2" Liner 12.6/L-80/DWC/C 1 3.958" 10,240' 12,915' IUCIIVV ULIAIL 4-1/2" 12.6#/L-80/IBT- M 3.958" Surf 1,200' 12.611/L-80/SuperMax 3.958" 1,200' 10,289' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 471/2" ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'-10,289' --3 -850" 4.500" 4-1/2" Seal Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 11,17(Y - 3.500" 1 CIBP (TOC 11,170') 9 11,430' - 3.500" CIBP w/ 10' cement (TOC 11,420') 10 11,505' - 3.500" CIBP w/ 10' cement (TOC 11,495') 11 11,565'- 11/25/16 3.500'' CIBP w/ 15' cement (TOC 31,554) 12 11,700' 11,480' 3.500" CIBP w/ W cement (TOC 11,690') 13 11,723' - 3.500" CIBP Updated by DMA 10-11-17 PERFORATION DETAIL Sands Top (MD) Btm (MD) Tap (TVD) Btm (TVD) SPF Date Size Status 91-2 10,767' 10,785' 9,081' 9,099' 6 10/10/17 2-7/8" Open 91-2 10,767' 10,787' 9,081' 9,101' 6 06/03/17 2-7/8" Open 91-2 10,767' 10,787' 9,081' 91101' 6 03/13/17 2-7/8" Open D -2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed D -3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated D -4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated D -4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 2-7/8" Isolated D-5 11,510' 11,530' 9,824' 9,844' 1 6 06/15/16 2-7/8" Isolated D -5A 11,572' 11,580' 9,886' 9,894'6 01/22/16 2-7/8" Isolated D -5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1 01/08/16 1 2-7/8" I Isolated Updated by DMA 10-11-17 ff Hilcorp Alaska, LLC 20" 13-3/8" Im 3 9-5/8" PROPOSED SCHEMATIC &1/2" windowat 6,527 MD 5,354' TVD 7-5/8" Type 5, 6, 7 ID Top UT -9B 0 / 91-2 91 � V� R4 MVA N/A 11,090 142' 13-3/8" Surface 61/K-55/BTC D -2C 8 2,970' 9-5/8" Intermediate 53.5/L-80/BTC ID -3A 9 { -. 7-5/8" ZXP Liner Top Packer 5 47 / P-110 / BTC D -0A 1,212' 9,178' 7-5/8" Liner 29'7 / L-80 / HYD 511 D-5 11 6,910' 29--7/L-110/1111-11 6.875" 6,910' 10,448' 4-1/2" D -5A 12.6/L-80/DWC/C 3.958" Dfi4 RA MVA 91-2 4,500" 11,633 8 12 13 R4 NWA 12,060 RA MVA 12,474' 41/2„ PBTD =11,170' MD / 9,484' TVD TD =12,940' MD / 11,253' TVD Cannery Loop Field Well: CLU 05RD AN: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 129/N/A/N/A N/A Surf 142' 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5/L-80/BTC 8.535" Surf 1,212' 7-5/8" ZXP Liner Top Packer 5 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29'7 / L-80 / HYD 511 6.875" 6,433' 6,910' 29--7/L-110/1111-11 6.875" 6,910' 10,448' 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' TUBING DETAIL JEWELRY DETAIL No. Depth ID OD Item 1 18' 4A00" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6,750" 8 660" 7-5/8" ZXP Liner Top Packer 5 10,244-10,272' 4,820" 6560" 4-1/2" ZXPN Liner Top Packer 6 10,272'-10,298' 4.74W 6.270" Liner Sealbore Extension 7 10,245'-10,289' 1 3.850" 4.500" 71/2"Seal Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 7A ±10,750' 91-2 4,500" CIBP w/ 25'cement(TOC 110,725') 8 11,170' - 3.500" CIBP (TOC 11,170') 9 11,430' - 3.500" CIBP w/ 10' cement (TOC 11,420') 10 111505' 12/22/16 3.500" CIBP w/ 30' cement (TOC 11,495') 11 11,565' - 3.500" CIBP w/ 15' cement (TOC 11,550') 12 11,700' 2-7/8" 3,500" CIBP w/ 10' cement (TOC 11,690') 13 11,723' - 3.500" CIBP Updated by DMA 09-13-19 r 1 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (ND) SPF Date Size Status UT -98 ±10,307' ±10,369' ±8,621' ±8,683' Proposed TBD 91-2 10,767' 10,785' 9,081' 9,099' 6 10/10/17 2-7/8" Isolated 91-2 10,767' 10,787' 9,081' 9,101' 6 06/03/17 2-7/8" Isolated 91-2 10,767 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Isolated D -2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed D -3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated D -4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated D -4A 11,464 11,490' 9,774' 9,804' 6 10/14/16 2-7/8" Isolated D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 2-7/8" Isolated D -SA 11,572' 11,580' 9,886 9,894' 6 01/22/16 2-7/8" Isolated D -5A 11,586 11,598 91900 9,912 6 05/26/16 2-7/8" Isolated D-6 11,712' 11,722' 10,026' 10,036' 1 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1 01/08/16 2-7/8" Isolated Updated by DMA 09-13-19 r 1 STANDARD WELL PROCEDURE lfileorp.%Iasea.t.i.c NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 Davies, Stephen F (CED) From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Monday, January 27, 2020 10:31 AM To: Davies, Stephen F (CED) Cc: Ted Kramer; Schwartz, Guy L (CED); Carlisle, Samantha J (CED) Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) and CLU 1 RD (PTD 203-129; Sundry 319-581) - Spacing Question Steve, Thank you for the clarification. Hilcorp kindly requests to withdraw the Application for Spacing Exception for CLU 5RD (dated November 21, 2019) and proceed forward with the request for sundry approval (submitted September 23, 2019). Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w)907-777-8443 (c) 907-378-7323 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Friday, January 24, 2020 10:31 AM To: Christina Twogood - (C) <ctwogood@hilcorp.com> Cc: Ted Kramer <tkramer@hilcorp.com>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov>; Carlisle, Samantha J (CED) <sa mantha.cariisle@alaska.gov> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) and CLU 1RD (PTD 203-129; Sundry 319-581) -Spacing Question Christina, Based upon Hilcorp's recent operations described in Sundry Report 319-581, Hilcorp's proposed Upper Tyonek (UT) 9B sand perforations in CLU 5RD* will now conform to the spacing requirements of Conservation Order 231, so a spacing exception is no longer needed for before adding those proposed UT -9B perforations. If Hilcorp wishes to withdraw the Application for Spacing Exception for CLU 5 RD (dated November 21, 2019), please provide a written request to the AOGCC. Regards, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, Including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC Is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesraalaska.cov. Davies, Stephen F (CED) From: Davies, Stephen F (CED) Sent: Friday, January 24, 2020 10:31 AM To: Christina Twogood - (C) Cc: Ted Kramer; Schwartz, Guy L (CED); Carlisle, Samantha 1 (CED) Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) and CLU 1 RD (PTD 203-129; Sundry 319-581) - Spacing Question Christina, Based upon Hilcorp's recent operations described in Sundry Report 319-581, Hilcorp's proposed UpperTyonek (UT) 9B sand perforations in CLU 5RD* will now conform to the spacing requirements of Conservation Order 231, so a spacing exception is no longer needed for before adding those proposed UT -9B perforations. If Hilcorp wishes to withdraw the Application for Spacing Exception for CLU 5 RD (dated November 21, 2019), please provide a written request to the AOGCC. Regards, Steve Davies AOGCC CONFIDENTIALITY NOTICE, This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesCelalaska gov. * See Sundry Application 319-434 Details: CO 231 Rule 3 established the Drilling Unit for the UpperTyonek Gas Pool as a quarter -quarter subdivision of a governmental section. CLU 1RD is open to the Upper Tyonek Gas Pool in the NW/4 of NE/4 of Section 8, T5N, R11W, SM. The proposed UT -9B sand perforation operations in CLU 5RD (Sundry 319-434 ) will open the Upper Tyonek Gas Pool in the SW/4 of NE/4 of Section 8, T5N, R11W, SM. The perforation operations in CLU 5RD proposed in Sundry 319-434 will not violate Rule 3 of CO 231. From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Thursday, January 23, 2020 1:59 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Cc: Ted Kramer <tkramer@hilcorp.com>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) and CLU 1RD (PTD 203-129; Sundry 319-581) - Spacing Question Steve, The T-1 perforations in CLU 1RD have been successfully isolated as per Approved Sundry 319-581 (PTD 203-129). A Sundry Report demonstrating this has been submitted as of today. As such, is it now appropriate to withdraw the spacing exception and request approval of the CLU 5RD sundry to perforate the UT -98; sand? Respectfully, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907-777-8443 (c) 907-378-7323 From: Christina Twogood - (C) Sent: Friday, December 20, 2019 11:20 AM To:'Davies, Stephen F (CED)' <steve.davies@alaska.gov> Cc: Ted Kramer <tkramer@hilcorp.com>; Schwartz, Guy L (CED) <guv.schwartz@alaska.gov> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) and CLU 1RD (PTD 203-129; Sundry 319-581) - Spacing Question Thank you for the detailed explanation. We will leave the request for spacing exception in place for CLU 5RD. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907-777-8443 (c) 907-378-7323 From: Davies, Stephen F (CED)[mailto:steve.davies@alaska.govl Sent: Thursday, December 19, 2019 4:49 PM To: Christina Twogood - (C) <ctwogood@hilcorp.com> Cc: Ted Kramer <tkramer@hilcorp.com>; Schwartz, Guy L (CED) <guy.schwartz@alaska.eov> Subject: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) and CLU 1RD (PTD 203-129; Sundry 319-581) - Spacing Question Christina, Short question, long answer: CO 231 Rule 2, Definition of Pools, states in part b: "The Upper Tyonek Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 9171' and 10,831' in Cannery Loop Unit Well #1." CO 231 Rule 3, Well Spacing, states: "A Drilling Unit for the Beluga, Upper Tyonek, orTyonek "D" Gas Pools is established as the quarter -quarter subdivision of a governmental section occurring within the affected area." Note that the well spacing requirements of CO 231 are all based on pools, not individual sands within a pool. The proposed UT -5A perfs in CLU 1RD, the open T-1 perfs in CLU 1RD, the proposed UT -913 perfs in CLU 5RD, and the open 91-2 perfs in CLU 5RD all lie within the Upper Tyonek Gas Pool. The open T-1 perfs in CLU 1RD, the open 91-2 perfs in CLU 5RD, and the proposed UT -96 perfs in CLU 5RD all lie within the same governmental quarter -quarter section (SW/4 of NE/4 of Section 8). According to my map, the open T-1 perfs in CLU 1RD lie very close to the quarter -quarter section boundary, but they are still inside of the SW/4 of NE/4 of Section 8. 1 missed this in the past, and a spacing exception should have been required to open the 91-2 perforations in CLU 5RD. That was my mistake. But, looking forward, Hilcorp's proposed UT -913 perfs in CLU SRD will require a spacing exception as long as the T-1 perforations in CLU 1RD remain open. Submitting a Sundry application proposing to isolate those perforations doesn't nullify this requirement. Until AOGCC receives a Sundry Report demonstrating the T-1 perforations in CLU 1RD have been successfully isolated (are no longer open to the pool), the proposed UT -913 perfs WILL require a spacing exception. The curving wellbore trajectory of CLU 1RD places Hilcorp's proposed UT -5A perforations in a separate governmental quarter -quarter section (NW/4 of NE/4 of Section 8) from any of the Upper Tyonek Gas Pool perforations open in CLU 5RD (all located in SW/4 of NE/4 of Section 8), so those proposed UT -5A perforations in CLU 1RD will NOT require a spacing exception. Please let me know if you have any questions. Regards, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska gov. From: Christina Twogood - (C) <ctwogood@hilcoro.com> Sent: Thursday, December 19, 2019 1:10 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Ted Kramer <tkramer@hilcoro.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Steve, Since submitting the sundry to add perforations in the UT -96 in CLU 5RD, we have stopped producing from the currently open intervals in CLU 1RD and have recently submitted a sundry to isolate those existing perforations and perforate the UT -5A sand. With the current non-productive status and the isolation requested in the sundry for CLU 1RD, I believe this may subsequently eliminate the requirement for a spacing exception to produce from the UT -98 in CLU 5RD. If that is correct, would it be appropriate to withdraw the spacing exception and request approval of the CLU 5RD sundry? Referenced documents are attached. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w)907-777-8443 (c) 907-378-7323 From: Cody Terrell Sent: Friday, October 11, 2019 2:25 PM To: 'Davies, Stephen F (CED)' <steve.davies@alaska.gov>; Christina Twogood - (C) <ctwogood@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question That answers my question thank you Steve. The perfs in the CLU 5RD well within the Upper Tyonck Gas Pool will be within the same quarter -quarter as CLU 1 RD. I will get a spacing exception together. I will also discuss with the team if it makes sense to amend the existing pool rules for unlimited spacing. If we continue to do work like this it would make sense. Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.aovl Sent: Friday, October 11, 2019 1:16 PM To: Cody Terrell <cterrell@hilcorp.com>; Christina Twogood - (C) <ctwogood@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, "Does a well need a spacing exception even if it's staying within the same pool?" In almost all cases, no it does not, but here I apparently made a mistake and a spacing exception should have been required for CLU 5RD when Hilcorp initially perforated the 91-2 interval within the Upper Tyonek Gas Pool. As the perforations in the 91-2 interval in CLU 5RD are located only between 44 and 64 feet above the top of the 1,000 - foot thick Tyonek D Gas Pool, I overlooked that they fell within anew pool (the Upper Tyonek Gas Pool). Looking back through the CLU 5RD well history file, I see that the "Perforate New Pool" boxes were not checked on Hilcorp's Sundry Application forms requesting approval to initially perforate the 91-2 interval in CLU 5RD (Sundry Nos. 316-577 and 317- 048); the "Perforate" box was checked instead. In addition, the "Field/Pools" boxes on both forms specified only "Cannery Loop / Tyonek D Gas Pool." I missed these during my review. So to help me sort this out, my questions for you and Christina are now: • When planned in early 2017, did the 91-2 interval perforations in CLU 5RD conform to the requirements of CO 231 Rule 3? • Do the currently planned UT -9B perforations for CLU 5RD conform to the spacing requirements of CO 231 Rule 3? • Since CLU is a very mature field with many discontinuous reservoir sands, has Hilcorp considered applying to amend the well spacing requirements of CO 231 to minimize the need for spacing exceptions? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska gov. From: Cody Terrell <cterrellC@hilcoro.com> Sent: Friday, October 11, 2019 10:28 AM To: Davies, Stephen F (CED) <steve.davies( alaska.gov> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Yes that is correct. I guess my question is why wasn't one required when CLU 5RD was completed in the Upper Tyonek Gas Pool to begin with? Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED)[mailto:steve.davies@alaska.gov] Sent: Friday, October 11, 2019 10:26 AM To: Cody Terrell <cterrell@hilcoro.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, Will Hilcorp's planned perforations in CLU 5RD lie within the same quarter -quarter governmental section as the same sand interval where it is open to the barefoot completion within CLU 1RD? ? If so-- according to CO 231 Rule 3 --yes, an exception must be obtained before perforating. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviescatalaska.gov. From: Cody Terrell <cterrell@hilcoro.com> Sent: Friday, October 11, 2019 10:21 AM To: Davies, Stephen F (CED) <steve.davies@alaska.aov>; Christina Twogood - (C) <ctwoaood@hilcoro.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Steve, The CLU 5RD well is currently producing from the Upper Tyonek Gas Pool. We are not moving into a different pool. Does a well need a spacing exception even if it's staying within the same pool? Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska aov] Sent: Friday, October 11, 2019 9:59 AM To: Cody Terrell <cterrell@hilcorp.com>; Christina Twogood - (C) <ctwoeood@hilcoro.com> Subject: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, Christina Apologies for this delayed response, I've had to focus on other projects for the past few days Per CO 231 Rule 2, the Upper Tyonek Gas Pool within the Cannery Loop Unit is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 9,171' and 10,831' MD in Cannery Loop Unit 1. According to my well log correlations, Hilcorp's planned perforations in CLU 5RD from 10,307' to 10,369' MD will open a reservoir sand in the upper Tyonek that is currently open in the barefoot completion within CLU 1RD. (That barefoot openhole interval in CLU 1RD extends from 10,766' to 10,835' MD). CO 231 Rule 3 states: "A Drilling Unit for the Beluga, Upper Tyonek, or Tyonek "D" Gas Pools is established as the quarter -quarter subdivision of a governmental section occurring within the affected area." Will Hilcorp's planned perforations in CLU 5RD lie within the same quarter -quarter governmental section as the same sand interval where it is open to the barefoot completion within CLU 1RD? If so, a spacing exception will be needed. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesrdalaska zov. The information contained in this e-mail message is confidential infonnation 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. ZlS�- l6ZD Davies, Stephen F (CED) From: Davies, Stephen F (CED) Sent: Thursday, December 19, 2019 4:49 PM To: Christina Twogood - (C) Cc: Ted Kramer; Schwartz, Guy L (CED) Subject: CLU SRD (PTD 215-160; Sundry 319-434) and CLU 1 RD (PTD 203-129; Sundry 319-581) - Spacing Question Christina, Short question, long answer: CO 231 Rule 2, Definition of Pools, states in part b: "The Upper Tyonek Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 9171' and 10,831' in Cannery Loop Unit Well #1." CO 231 Rule 3, Well Spacing, states: "A Drilling Unit for the Beluga, Upper Tyonek, or Tyonek "D" Gas Pools is established as the quarter -quarter subdivision of a governmental section occurring within the affected area." Note that the well spacing requirements of CO 231 are all based on pools, not individual sands within a pool. The proposed UT -5A perfs in CLU 1RD, the open T-1 perfs in CLU 1RD, the proposed UT -96 perfs in CLU 5RD, and the open 91-2 perfs in CLU 5RD all lie within the Upper Tyonek Gas Pool. The open T-1 perfs in CLU 1RD, the open 91-2 perfs in CLU 5RD, and the proposed UT -9B perfs in CLU 5RD all lie within the same governmental quarter -quarter section (SW/4 of NE/4 of Section 8). According to my map, the open T-1 perfs in CLU 1RD lie very close to the quarter -quarter section boundary, but they are still inside of the SW/4 of NE/4 of Section 8. 1 missed this in the past, and a spacing exception should have been required to open the 91-2 perforations in CLU 5RD. That was my mistake. But, looking forward, Hilcorp's proposed UT -96 perfs in CLU 5RD will require a spacing exception as long as the T-1 perforations in CLU 1RD remain open. Submitting a Sundry application proposing to isolate those perforations doesn't nullify this requirement. Until AOGCC receives a Sundry Report demonstrating the T-1 perforations in CLU 1RD have been successfully isolated (are no longer open to the pool), the proposed UT -96 perfs WILL require a spacing exception. The curving wellbore trajectory of CLU 1RD places Hilcorp's proposed UT -5A perforations in a separate governmental quarter -quarter section (NW/4 of NE/4 of Section 8) from any of the Upper Tyonek Gas Pool perforations open in CLU 5RD (all located in SW/4 of NE/4 of Section 8), so those proposed UT -5A perforations in CLU 1RD will NOT require a spacing exception. Please let me know if you have any questions. Regards, Steve Davies AOGCC CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or stgve.daviesPalaska.cov. From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Thursday, December 19, 2019 1:10 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Ted Kramer <tkramer@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Steve, Since submitting the sundry to add perforations in the UT -96 in CLU 5RD, we have stopped producing from the currently open intervals in CLU 1RD and have recently submitted a sundry to isolate those existing perforations and perforate the UT -5A sand. With the current non-productive status and the isolation requested in the sundry for CLU 1RD, I believe this may subsequently eliminate the requirement for a spacing exception to produce from the UT -9B in CLU 5RD. If that is correct, would it be appropriate to withdraw the spacing exception and request approval of the CLU 5RD sundry? Referenced documents are attached. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w)907-777-8443 (c) 907-378-7323 From: Cody Terrell Sent: Friday, October 11, 2019 2:25 PM To: 'Davies, Stephen F (CED)' <steve.davies@alaska.eov>; Christina Twogood - (C) <ctwoaood@hilcorp.com> Subject: RE: [EXTERNAL] CLU SRD (PTD 215-160; Sundry 319-434) - Spacing Question That answers my question thank you Steve. The perfs in the CLU 5RD well within the Upper Tyonek Gas Pool will be within the same quarter -quarter as CLU l RD. 1 will get a spacing exception together. I will also discuss with the team if it makes sense to amend the existing pool rules for unlimited spacing. If we continue to do work like this it NroOUld make sense. Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska gov] Sent: Friday, October 11, 2019 1:16 PM To: Cody Terrell <cterrell@hilcorp.com>; Christina Twogood - (C) <ctwogood@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, "Does a well need a spacing exception even if it's staying within the same pool?" In almost all cases, no it does not, but here I apparently made a mistake and a spacing exception should have been required for CLU 5RD when Hilcorp initially perforated the 91-2 interval within the Upper Tyonek Gas Pool. As the perforations in the 91-2 interval in CLU 5RD are located only between 44 and 64 feet above the top of the 1,000 - foot thick Tyonek D Gas Pool, I overlooked that they fell within a new pool (the Upper Tyonek Gas Pool). Looking back through the CLU 5RD well history file, I see that the "Perforate New Pool" boxes were not checked on Hilcorp's Sundry Application forms requesting approval to initially perforate the 91-2 interval in CLU 5RD (Sundry Nos. 316-577 and 317- 048); the "Perforate" box was checked instead. In addition, the "Field/Pools" boxes on both forms specified only "Cannery Loop / Tyonek D Gas Pool." I missed these during my review. So to help me sort this out, my questions for you and Christina are now: • When planned in early 2017, did the 91-2 interval perforations in CLU 5RD conform to the requirements of CO 231 Rule 3? • Do the currently planned UT -9B perforations for CLU 5RD conform to the spacing requirements of CO 231 Rule 3? • Since CLU is a very mature field with many discontinuous reservoir sands, has Hilcorp considered applying to amend the well spacing requirements of CO 231 to minimize the need for spacing exceptions? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or Steve.davies@alaska.gov. From: Cody Terrell <cterrell@hilcorp.com> Sent: Friday, October 11, 2019 10:28 AM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Yes that is correct. I guess my question is why wasn't one required when CLU 5RD was completed in the Upper'I'yonek. Gas Pool to begin with'? Regards. Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED)[mailto:steve,davies@alaska.gov] Sent: Friday, October 11, 2019 10:26 AM To: Cody Terrell <cterrell@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, Will Hilcorp's planned perforations in CLU 5RD lie within the same quarter -quarter governmental section as the same sand interval where it is open to the barefoot completion within CLU 1RD? ? If so-- according to CO 231 Rule 3 --yes, an exception must be obtained before perforating. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davles@alaska.gov. From: Cody Terrell <cterrell@hilcorp.com> Sent: Friday, October 11, 2019 10:21 AM To: Davies, Stephen F (CED) <steve.davies@alaska.eov>; Christina Twogood - (C) <ctwogood@hilcorp.com> Subject: RE: [EXTERNAL] CLU SRD (PTD 215-160; Sundry 319-434) - Spacing Question Steve, The CLU 5RD well is currently producing from the Upper Tyonek Gas Pool. We are not moving into a different pool. Does a well need a spacing exception even if ifs staying within the same pool? Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska gov] Sent: Friday, October 11, 2019 9:59 AM To: Cody Terrell <cterrell@hilcorp.com>; Christina Twogood - (C) <ctwoaood@hilcorp.com> Subject: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, Christina: Apologies for this delayed response, I've had to focus on other projects for the past few days. Per CO 231 Rule 2, the Upper Tyonek Gas Pool within the Cannery Loop Unit is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 9,171' and 10,831' MD in Cannery Loop Unit 1. According to my well log correlations, Hilcorp's planned perforations in CLU 5RD from 10,307' to 10,369' MD will open a reservoir sand in the upper Tyonek that is currently open in the barefoot completion within CLU 1RD. (That barefoot openhole interval in CLU 1RD extends from 10,766' to 10,835' MD). CO 231 Rule 3 states: "A Drilling Unit forthe Beluga, UpperTyonek, or Tyonek V' Gas Pools is established as the quarter -quarter subdivision of a governmental section occurring within the affected area." Will Hilcorp's planned perforations in CLU 5RD lie within the same quarter -quarter governmental section as the same sand interval where it is open to the barefoot completion within CLU 1RD? If so, a spacing exception will be needed. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is forth sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviestmalaska gov. 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. Davies, Stephen F (CED) From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Thursday, December 19, 2019 1:10 PM To: Davies, Stephen F (CED); Schwartz, Guy L (CED) Cc: Ted Kramer Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Attachments: Doc 415 11-20-2019.pdf; CLU -01 RD 10-403 Submitted 12-18-19.pdf; CLU-05RD AOGCC 10-403 Submittal 09-23-19.pdf Steve, Since submitting the sundry to add perforations in the UT -96 in CLU 5RD, we have stopped producing from the currently open intervals in CLU 1RD and have recently submitted a sundry to isolate those existing perforations and perforate the UT -5A sand. With the current non-productive status and the isolation requested in the sundry for CLU 1RD, I believe this may subsequently eliminate the requirement for a spacing exception to produce from the UT -96 in CLU 5RD. If that is correct, would it be appropriate to withdraw the spacing exception and request approval of the CLU 5RD sundry? Referenced documents are attached. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w)907-777-8443 (c) 907-378-7323 From: Cody Terrell Sent: Friday, October 11, 2019 2:25 PM To: 'Davies, Stephen F (CED)' <steve.davies@alaska.gov>; Christina Twogood - (C) <ctwogood@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question That answers my question thank you Steve. The perfs in the CLU 5RD well within the Upper Tyonek Gas Pool will be within the same quarter -quarter as CLU IRD. 1 will get a spacing exception together. I will also discuss with the team if it makes sense to amend the existing pool rules for unlimited spacing. If we continue to do work like this it would make sense. Regards, Cody T. Terrell Landman Hilcorp Alaska. LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Friday, October 11, 2019 1:16 PM To: Cody Terrell <cterrell@hilcorp.com>; Christina Twogood - (C) <ctwoaood@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, "Does a well need a spacing exception even if it's staying within the same pool?" In almost all cases, no it does not, but here I apparently made a mistake and a spacing exception should have been required for CLU 5RD when Hilcorp initially perforated the 91-2 interval within the Upper Tyonek Gas Pool. As the perforations in the 91-2 interval in CLU 5RD are located only between 44 and 64 feet above the top of the 1,000 - foot thick Tyonek D Gas Pool, I overlooked that they fell within a new pool (the Upper Tyonek Gas Pool). Looking back through the CLU 5RD well history file, I see that the "Perforate New Pool' boxes were not checked on Hilcorp's Sundry Application forms requesting approval to initially perforate the 91-2 interval in CLU 5RD (Sundry Nos. 316-577 and 317- 048); the "Perforate" box was checked instead. In addition, the "Field/Pools" boxes on both forms specified only "Cannery Loop /Tyonek D Gas Pool." I missed these during my review. So to help me sort this out, my questions for you and Christina are now: • When planned in early 2017, did the 91-2 interval perforations in CLU 5RD conform to the requirements of CO 231 Rule 3? • Do the currently planned UT -96 perforations for CLU 5RD conform to the spacing requirements of CO 231 Rule 3? • Since CLU is a very mature field with many discontinuous reservoir sands, has Hilcorp considered applying to amend the well spacing requirements of CO 231 to minimize the need for spacing exceptions? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska.aov. From: Cody Terrell <cterrell@hilcorp.com> Sent: Friday, October 11, 2019 10:28 AM To: Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Yes that is correct. I guess my question is why wasn't one required when CLU 5RD was completed in the Upper Tyonek Gas Pool to begin with? Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Friday, October 11, 2019 10:26 AM To: Cody Terrell <cterrell@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, Will Hilcorp's planned perforations in CLU 5RD lie within the same quarter -quarter governmental section as the same sand interval where it is open to the barefoot completion within CLU 1RD? ? If so-- according to CO 231 Rule 3 --yes, an exception must be obtained before perforating. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Cody Terrell <cterrell@hilcorp.com> Sent: Friday, October 11, 2019 10:21 AM To: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Christina Twogood - (C) <ctwogood@hilcorp.com> Subject: RE: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Steve. The CLU 5RD well is currently producing from the Upper Tyonek Gas Pool. We are not moving into a different pool. Does a well need a spacing exception even if it's staying within the same pool? Regards, Cody T. Terrell Landman Hilcorp Alaska, L,LC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov] Sent: Friday, October 11, 2019 9:59 AM To: Cody Terrell <cterrell@hilcorp.com>; Christina Twogood - (C) <ctwogoodphilcorp.com> Subject: [EXTERNAL] CLU 5RD (PTD 215-160; Sundry 319-434) - Spacing Question Cody, Christina: Apologies for this delayed response, I've had to focus on other projects for the past few days. Per CO 231 Rule 2, the Upper Tyonek Gas Pool within the Cannery Loop Unit is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 9,171' and 10,831' MD in Cannery Loop Unit 1. According to my well log correlations, Hilcorp's planned perforations in CLU 5RD from 10,307' to 10,369' MD will open a reservoir sand in the upper Tyonek that is currently open in the barefoot completion within CLU 1RD. (That barefoot openhole interval in CLU 1RD extends from 10,766' to 10,835' MD). CO 231 Rule 3 states: "A Drilling Unit for the Beluga, Upper Tyonek, or Tyonek "D" Gas Pools is established as the quarter -quarter subdivision of a governmental section occurring within the affected area." Will Hilcorp's planned perforations in CLU 5RD lie within the same quarter -quarter governmental section as the same sand interval where it is open to the barefoot completion within CLU 1RD? If so, a spacing exception will be needed. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska.gov. 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. Conservation Order No. 231 August 3, 1987 Page 4 Rule 1 Designation of Affected Area The area affected by this Order may be referred to as the Cannery Loop Extension of the Kenai Gas Field. Rule 2 Definition of Pools a) The Beluga Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphic- ally equivalent to the interval between the measured depths of 6081' and 9171' in Cannery Loop Unit Well 01. b) The Upper Tyonek Gas Pool is defined as the accumulation of gas occurring within the affected area in sands strati - graphically equivalent to the interval between the measured depths of 9171' and 10,831' in Cannery Loop Unit Well #1. c) The Tyonek "D" Gas Pool is defined as the accumulation of gas occurring within the affected area in sands strati - graphically equivalent to the interval between the measured depths of 10,831' and 11,962' in Cannery Loop Unit Well #1. Rule 3 Well Spacing A Drilling Unit for the Beluga, Upper Tyonek, or Tyonek "D" Gas Pools is established as the quarter -quarter subdivision of a governmental section occurring within the affected area. Rule 4 Offset Limitations A well bore may not expose for the purposes of regular production any interval of a pool that is located closer than 1,500' to the boundary of the affected area, or closer than 500' to the boundary of the participating area established for that pool. Rule 5 Reservoir Pressure Surveillance Within six months of the start of regular production, the operator shall submit for approval an initial plan for monitoring reservoir pressure in each pool. The initial plan shall include but may not be limited to: 1) Establishing pool datums. 2) Initial reservoir pressure of each pool. 3) Method for determining average reservoir pressure at least once each year. Conservation Order No. 231 August 3, 1987 Page 5 Rule 6 Administrative Approval Upon request the Commission may administratively amend this Order so long as the operator demonstrates to the Commission's satis- faction that sound engineering practices are maintained and the amendment will not result in physical waste or the impairment of correlative rights. DONE at Anchorage, Alaska, and dated August 3, 1987. Qy�A otL �� )ON u. v. unaLterton, ugairman Alaska Oil and Gas Conservation Commission Alaska Oil and Gas Conservation Commission w. w. narnweii, commissioner Alaska Oil and Gas Conservation Commission DATE 10/29/2019 215160 Debra Oudean Hilcorp Alaska, LLC 3 14 1 1 GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 Halliburton TMD3D 6 SEP 2019 CLU 5RD CLU_95RD_TMD3D 9Y6/2019 8:30 PrA s CLU 05RD TMD3D 9/612019 8:35 Plot % CLU 05RDTMD3D 9,+6•+2019 8:38 Pwt Please include current contact information if different from above. RECEIVED NOV 0 4 2019 AOGCC LAS File 9,935 KB PDF Document 3,232 KB TIF File 8,215 KB Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 A I A n IN STATE OF A AOKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS t)(;.I 2 5 Z017 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing Udown U Performed: Suspend ❑ Perforate U Other Stimulate ❑ Alter Casing ❑ Change Approved rogram ❑ Plug for Red rill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Re-Perforate Q 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑., Exploratory ❑ 215-160 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20474-01 7.Property Designation(Lease Number): 8.Well Name and Number: FEE Hilcorp(ADL060569);ADL324602 Cannery Loop Unit(CLU)05RD 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai C.L.U./Beluga&Upper Tyonek Gas Pools 11.Present Well Condition Summary: 11,170;11,420; 11,495;11,550; Total Depth measured 12,940 feet Plugs measured 11,690;11,723 feet true vertical 11,253 feet Junk measured N/A feet Effective Depth measured 11,170 feet Packer measured 6,433&10,240 feet true vertical 9,484 feet true vertical 5,263&8,555 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090 psi 1,540 psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930 psi 6,620 psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440 psi 5,300 psi Liner 3,538' 7-5/8" 10,448' 8,762' 6,890 psi 4,790 psi Liner 2,675' 4-1/2" 12,915' 11,229' 8,430 psi 7,500 psi Perforation depth Measured depth See Schematic feet , SCANNED NOV 1 3. 01(, True Vertical depth See Schematic feet Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 10,289(MD) 8,603(TVD) Baker ZXP+ZXPN Pkrs;6,433'MD/5,263'TVD&10,240'MD/8,555'TVD Packers and SSSV(type,measured and true vertical depth) Baker TE-5 SSSV TR 298'MD/298'TVD 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 3790 3 682 1870 Subsequent to operation: 0 5123 0 797 1583 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations U Exploratory ❑ Development❑., Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas 0 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-460 Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hiIcorp.com Authorized Signature: ..,/,/,',.../ ...g �� Date: /0/Z y(17 Contact Phone: 777-8420 Form 10-404 Revised 4/2017 / // , /�/ RBD i IS IN OCT 2 7 2U 1/ ,011 "'/7 Submit Original Only • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 10/10/17 10/10/17 Daily Operations: 10/10/2017 -Tuesday Sign in. Mobe to Location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 low and 5,000 high. Well flowing 2.5 mil at 1,675 ps.i RIH w/CCL/GR and tie into Halliburton perf log dated 6-3-17. Tagged at 10,784'. Run correlation log to town and had to down shift log 2'. That made tag depth at 10,786'. Send back to town and got ok. Sent gun to Halliburton shop to down load 2' off of the 20'gun. Will be able to perf from 10,785' to 10767' (18'). Wait on perf gun. RIH w/2-78" x 20' (18' loaded) HC Razor, 6 spf, 60 deg phase and tie into Halliburton Tag Run, dated 10-10- 17. Run correlation log and send to town. Get ok to perf from 10,767. to 10,785'. Spot and fire gun w/well flow 2.734 mil at 1,786.2 psi. 5 min - 2.813 mil at 1,833.1 psi, 10 min - 2.819 mil at 1,842.1 psi and 15 min - 2.822 mil at 1,848.8 psi. POOH.Rig down lubricator and turn well over to production. Well flowing 2.72 mil at 1,958 psi. All shots fired. Unscrewed bull plug off perf gun and it was dry. . Cannery Loop Field 14 SCHEMATIC • Well: CLU05RD API: 50-133-20474-01 Hilcorp Alaska,LLC PTD: 215-160 RKB=18' CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm ni III 1 20" Conductor 129/N/A/N/A N/A Surf 142' 20' r 4 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' VI 2 1-11. 53,5/L-80/BTC 8.535" Surf 1,212' 9-5/8" Intermediate 47/P-110/BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29.7/L-80/HYD 511 6.875" 6,433' 6,910' 29.7/L-80/SLIJ-II 6.875" 6,910' 10,448' r 04 1 ! 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' TUBING DETAIL 13-3/8" ' 3 12.6#/L-80/IBT-M 3.958" Surf 1,200' f 4-1/2" 12.6#/L-80/SuperMax 3.958" 1,200' 10,289' LI 8-1/2 it window at v ig 6,527'MD JEWELRY DETAIL 5,354'TVD 9-5/8" 4 No. Depth ID OD Item T, 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" f 2 298' 3.812" 7.110" Baker TE-5 Safety Valve . 3 1,210' 3.813" 6.500" 4-1/2"Chemical Injection Mandrel ' 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension V > 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly x4 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer 8 11,170' - 3.500" CIBP(TOC 11,170') 9 11,430' - 3.500" CIBP w/10'cement(TOC 11,4201 10 11,505' 3.500" CIBP w/10'cement(TOC 11,495') 11 11,565' 3.500" CIBP w/15'cement(TOC 11,550') r12 11,700' 3.500" CIBP w/10'cement(TOC 11,6901 7-5/8" 5,6,7 13 11,723' - 3.500" CIBP I 91-2 RAJt ' PERFORATION DETAIL 11,090' Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Date Size Status •'-D 2C 91-2 10,767' 10,785' 9,081' 9,099' 6 10/10/17 2-7/8" Open 91-2 10,767' 10,787' 9,081' 9,101' 6 06/03/17 2-7/8" Open 8 91-2 10,767' 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Open 1' ! D-3A D-2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed 9 D-3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated D 4A D-4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated 10 D-4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 2-7/8" Isolated pm11 ' D-5 D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 2-7/8" Isolated D-5A D-5A 11,572' 11,580' 9,886' 9,894' 6 01/22/16 2-7/8" Isolated D-6A D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated RAMkrJt D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated 11,633 12,13 0-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated *IC.- D-6 4 4 4 RA My Jt .7i 12,060 RAMkrJt 12,474' �- 4-1/2" vim_ PBTD=11,170'MD/9,484'TVD TD=12,940'MD/11,253'TVD Updated by DMA 10-11-17 QF T� • • g;w\� 1yy�,�A THE STATE Alaska Oil and Gas f.7,741r,fr," ' � �-'�'a of T a Conservation Commission -�sKA 333 West Seventh Avenue ne GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 op�v Main: Fax: 907.279.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager SCANNED ,a()V 2 1 Z+U 77 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Cannery Loop Unit, Beluga& Upper Tyonek Gas Pools, CLU 05RD Permit to Drill Number: 215-160 Sundry Number: 317-460 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair f-. DATED this 6) day of October, 2017. RBD:°".73 6 2017 • • RECEIVED STATE OF ALASKA SEP 2 9 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION jot( 1 1 7 �'1's APPLICATION FOR SUNDRY APPROVALS 44,0Gre 20 MC 25.280 1.Type of Request: Abandon El Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown El Suspend El Perforate 2• Other Stimulate El Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool El Re-enter Susp Well El Alter Casing El Other. Re-Perforate El 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC • Exploratory El Development (] . 215-160 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20474-01-00• 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231,Rule 3 Will planned perforations require a spacing exception? Yes ❑ No El Cannery Loop Unit(CLU)05RD • 9.Property Designation f Lease Number): 10.Field/Pool(s): FEE Hilcorp(ADL060569)/ADL324602 Kenai C.L.U./Beluga&Upper Tyonek Gas Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,940 P 11,253 • 11,170 9,484 3,841 psi See Schematic N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090 psi 1,540 psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930 psi 6,620 psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440 psi 5,300 psi Liner 4,015' 7-5/8" 10,448' 8,762' 6,890 psi 4,790 psi Liner 2,675' 4-1/2" 12,915' 11,229' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 10,767-10,787 9,081 -9,101 4-1/2" 12.6#/L-80 10,289 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker ZXP&ZXPN Packers&Baker T-E5 SSSV 6,433'(MD)5,263'(TVD)/10,240'(MD)8,555'(TVD)&298'(MD)298'(TVD) 12.Attachments: Proposal Summary 2 Wellbore schematic El 13.Well Class after proposed work: Detailed Operations Program El BOP Sketch ❑ Exploratory El Stratigraphic El Development 0 Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 10/6/2017 OIL ❑ WINJ El WDSPL ❑ Suspended El 16.Verbal Approval: Date: GAS El WAG El GSTOR El SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown El Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkram _er hiIcorp.com Authorized Signature: �� Date: Q)j(Z-7 I7COMMIION USE ONLY Contact Phone: (907)777-8420 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 17_ 41 C0 o Plug Integrity El BOP Test❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No El y RBD' S C. 1 - 6 2017 Spacing Exception Required? Yes EI No Subsequent Form Required: /6--.4041bs) 1� APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: I (V/( 0 �J6� i��" " //y norm� /� Submorm and porm 10-403 Revised 4/2017 aLNAL lid for 12 months from the date of approval. Attachments in Duplicate \0 • • Well Prognosis Well: CLU-05RD Hilcorp Alaska,LU Date:9/29/2017 Well Name: CLU-05RD API Number: 50-133-20474-01 Current Status: Gas Producer Leg: N/A Estimated Start Date: October 6, 2017 Rig: Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907)777-8354 (0) (907) 903-0341 (C) AFE Number: Maximum Expected BHP: 4,747 psi @ 9,051' TVD From Static Buildup on 4-9-17 Max. Predicted Surface Pressure: —3,841 psi (0.10 psi/ft gas gradient) Brief Well Summary CLU-05RD 91-2 Sand was re-perforated in June 2017. After the re-perf the well flowed at a rate of 6 MMscfd • until September 23, 2017 when the rate declined suddenly. Slickline was placed on the well and fill was r observed over the top perforation. This fill was bailed to below the bottom perforation. The purpose of this work/sundry is to re, erfnrate the 91-2 Tyonek interval to create new perforation tunnels ' for the gas to flow through and to decrease the pressure drop across individual perforations. E-Line Procedure 1. MIRU E-line, PT lubricator to 5,000 psi Hi 250 Low. 2. If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 3. Perforate the Tyonek 91-2 sand from ±10,767 to±10,787'. 4. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. 5. POOH. 6. Flow through test separator and record water and gas rates. 7. RD e-line. 8. Turn well over to production. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic • • SCHEMATIC Cannery Loop Field • Well: CLU 05RD API: 50-133-20474-01 Hilcorp Alaska,LLC PTD: 215-160 CASING DETAIL RKB=18' Size Type Wt/Grade/Conn ID Top Btm 1 20" Conductor 129/N/A/N/A N/A Surf 142' 20" . 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' 2 9-5/8" Intermediate 53.5/L-80/BTC 8.535" Surf 1,212' 47/P-110/BTC 8.681" 1,212' 9,178' 41 29.7/L-80/HYD 511 6.875" 6,433' 6,910' 7-5/8" Liner ',-i 29.7/L-80/SLIJ-II 6.875" 6,910' 10,448' y ,i 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' "`; TUBING DETAIL 13-3/8" •; 3 4-1/2" 12.6#/L-80/IBT-M 3.958" Surf 1,200' 12.6#/L-80/SuperMax 3.958" 1,200' 10,289' % 8-1/2" window at 6,527'MD JEWELRY DETAIL 5,354'ND 9-5/8" a No. Depth ID OD Item 4{^ 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" 2 298' 3.812" 7.110" Baker TE-5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2"Chemical Injection Mandrel '" 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly • 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer r, ., 8 11,170' - 3.500" CIBP(TOC 11,170') 5 t, 9 11,430' - 3.500" CIBP w/10'cement(TOC 11,420') 10 11,505' - 3.500" CIBP w/10'cement(TOC 11,495') 11 11,565' - 3.500" CIBP w/15'cement(TOC 11,550') 12 11,700' - 3.500" CIBP w/10'cement(TOC 11,690') 13 11,723' - 3.500" CIBP 91-2 RAJt PERFORATION DETAIL 11,090' Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) SPF Date Size Status AA D-2C 91-2 10,767' 10,787' 9,081' 9,101' 6 06/03/17 2-7/8" Open 91-2 10,767' 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Open 8 D-2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed - D3 D-3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated D-4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated 9 i, D-4A D-4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 2-7/8" Isolated 10 D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 2-7/8" Isolated 11 o-5 D-5A 11,572' 11,580' 9,886' 9,894' 6 01/22/16 2-7/8" Isolated Q5A D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated - D-6A D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated RA Mkr Jt AA D-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated 11,633' ,r 12,13 D-6 f X RA Mb-Jt I -- 12,060' II RAMkrJt 12,474' 4-1/2" ii' .........__........... PBTD=11,170'MD/9,484'ND TD=12,940'MD/11,253'TVD Updated by DMA 06/19/17 • • • Cannery Loop Field III PROPOSED Well: CLU 05RD API: 50-133-20474-01 Hilcorp Alaska,LLC PTD: 215-160 RKB=18' CASING DETAIL y Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 129/N/A/N/A N/A Surf 142' 20" 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' I 2 53.5/L-80/BTC 8.535" Surf 1,212' 71 9-5/8" Intermediate 47/P-110/BTC 8.681" 1,212' 9,178' '»� 29.7/L-80/HYD 511 6.875" 6,433' 6,910' 7-5/8" Liner 29.7/L-80/SLIJ-II 6.875" 6,910' 10,448' w% 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' TUBING DETAIL 13-3/8 $ 3 4-1/2" 12.6#/L-80/IBT-M 3.958" Surf 1,200' 12.6#/L-80/SuperMax 3.958" 1,200' 10,289' N 8-1/r, t window at 6,527'MD JEWELRY DETAIL , t 5,354'1VD 9-5/8" ..1. 4 No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" 2 298' 3.812" 7.110" Baker TE-5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2"Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension x; 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer 8 11,170' - 3.500" CIBP(TOC 11,170') 9 _ 11,430' - 3.500" CIBP w/10'cement(TOC 11,420') 10 11,505' - 3.500" CIBP w/10'cement(TOC 11,495') 11 11,565' 3.500" CIBP w/15'cement(TOC 11,550') t- 12 11,700' - 3.500" CIBP w/10'cement(TOC 11,690') 7-5/8" 5,6,7 13 11,723' - 3.500" CIBP i91-2 g._> PERFORATION DETAIL RA IVIu-Jt 11,090' , Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Date Size Status ••`D-2C 91-2 ±10,767' ±10,787' • ±9,081' ±9,101' FUTURE PROPOSED • 91-2 10,767' 10,787' 9,081' 9,101' 6 06/03/17 2-7/8" Open 8 91-2 10,767' 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Open D-3A D-2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed D-3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated 9 `+ D-4A D-4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated 10 ",4 D-4A 11,460' _ 11,490' 9,774' 9,804' 6 10/14/16 2-7/8" Isolated 0.5 D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 2-7/8" Isolated D-5A D-5A 11,572' _ 11,580' 9,886' 9,894' 6 01/22/16 2-7/8" Isolated ' D-6A D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated RA Mu a , D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated 11633 Mk,, 12,13 D-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated ', ; D-6 1 f RA Mkr JI I '1 12,060' RA Mkr Jt i 12,474' a 4-1/2" I.r PBTD=11,170'MD/9,484'TVD TD=12,940'MD/11,253'TVD Updated by JLL 09/29/17 • • 21 51 60 Seth Nolan Hilcorp Alaska, LLC 2 8 4 8 5 GeoTech 3800 Centerpoint Drive, Suite 100 RECEIVED Anchorage, 99503 Tele: 907 77777 8308 Nilanrp ATuek., .IA: Fax: 907 777-8510 AUG O 9 Za�7 E-mail: snolan©hilcorp.com DATA LOGGED td As/2011 r vl. K BENDER DATE 08/09/2017 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 5RD %NNE) AUG 1 8 2Ci7. Prints: Perforation record CD: 1 'CLU-05RD_PERF 03JUN 17.pdf 7/13/2017 1:31 PM PDF Document 511 KB U CLU-05RD_PERF 03JUN 17 Correlation.las 7/13/2017 1:31 PM LAS File 551 KB CLU-05RD_PERF_033UN 17 img.tiff 7/13/2017 1:31 PM TIFF File 1,378 KB CLU-05RD_PERF 03JUN 17 ShootingPass.las 7/13/2017 1:31 PM LAS File 602 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: STATE OF ALASKA AKA OIL AND GAS CONSERVATION COMOSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Plug Perforations UFracture Stimulate LJ Pull Tubing U Operations shutdown LJ Performed: Suspend ❑ Re-Perforate ❑., Other Stimulate ❑ Alter Casing 0 Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 1 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑✓ Exploratory ❑ 215-160 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20474-01 7.Property Designation(Lease Number): 8.Well Name and Number: FEE Hilcorp(ADL060569);ADL324602 Cannery Loop Unit(CLU)05RD 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai C.L.U./Beluga&Upper Tyonek Gas Pools 11.Present Well Condition Summary: 11,170;11,420; 11,495;11,550; sECEIVED Total Depth measured 12,940 feet Plugs measured 11,690;11,723 true vertical 11,253 feet Junk measured N/A feet 8 2017 Effective Depth measured 11,170 feet Packer measured 6,433&10,240 feetit }` true vertical 9,484 feet true vertical 5,263&8,555 feet ,, Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090 psi 1,540 psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930 psi 6,620 psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440 psi 5,300 psi Liner 4,048' 7-5/8" 10,448' 8,762' 6,890 psi 4,790 psi Liner 2,675' 4-1/2" 12,915' 11,229' 8,430 psi 7,500 psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 10,289(MD) 8,603(TVD) Baker ZXP+ZXPN Pkrs;6,433'MD/5,263'TVD&10,240'MD/8,555'TVD Packers and SSSV(type,measured and true vertical depth) Baker TE-5 SSSV TR 298'MD/298'TVD 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A e Treatment descriptions including volumes used and final pressure: SCANNED (� 1 I i` N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: - 6143 3 413 1325 Subsequent to operation: - 6702 7 555 2340 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0Exploratory ❑ ❑Development 0 Service p ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ 0 WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-204 Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcorp.com Authorized Signature: OW Date: 7,07 Contact Phone: 777-8420 Form 10-404 Revised 4/2017 7 J/RBDMS 4r\, JUN 1 9 2017 Submit Original Only r • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 6/2/17 6/3/17 Daily Operations: 06/02/2017 - Friday PTW and JSA. Mobe to location. SIMOPS w/coil tubing. Rig up E-Line lubricator. PT to 250 psi low and 5,000 psi high. TP -3,487 psi. RIH w/3.60" GR,JB, CCL/GR and tied into Halliburton RMTI log. Sat down 10,780'. Tried to work gauge ring past obstruction but wouldn't go. POOH. Have Halliburton slickline on the way out. Wait on slickline. PTW and JSA. Spot equipment. Put 160 wire rope socket on line. Rig up slickline on same lubricator as e-line. PT to 250 psi low and 5,000 psi high. RIH w/3.5" x 10' DD bailer and tag obstruction at 10,760' WLM. Bailed on obstruction and made about 2'. Tools weighing 1,200 lbs and had to hit jars at 2,300 lbs 3 times to get free. POOH to see what bailer has in it and if there are metal marks on it. No metal marks and bailer had about 1' of mud and fine sand RIH w/3" x 10' DD bailer and tag obstruction at 10,762' WLM. Bailed from 10,762' to 10,772' WLM. (10,790 KB). POOH. TP- 3,506.8 psi. Bailer was packed full of course sand. Not like the mud/fine sand on the 3-1/2" bailer run. RIH w/3"x 10' DD bailer and tag obstruction at 10,768' WLM. Bailed from 10,768' to 10,774' WLM. (10,792 KB). POOH. TP- 3,517.7 psi. Bailer full of course moist sand. We tagged 4' higher than last run. Rig down lubricator and clean up area. Be back in AM. TP- 3,519.0 psi. 06/03/2017 -Saturday PTW and JSA. Change out packing in stuffing box on pack-off. Rig up lubricator, PT to 250 psi low and 5,000 psi high. TP- 3,539.5 psi. RIH w/2" x 10' DD bailer w/2.14 " fluted centralizer, to see if it would go to bottom and tag obstruction at 10,783' KB. Bailed to 10,793' KB. Bailed one time and it went to 10,788'. Bailed to 10,793' KB POOH. Had about 5' of course sand. TP 3,523.1 psi. RIH w/3" x 15' DD bailer and tag obstruction at 10,793' KB. Bailed to 10,796' KB (3'). POOH. Bailer had about 8' of course sand. Hard bailing. TP- 3,529.2 psi. RIH w/3" x 10' DD bailer and tag obstruction at 10,796' KB. Bailed to 10,799' KB (3'). POOH. Bailer had about 8' of course sand. Hard bailing. TP- 3,528 psi. Tools weighed 1,250 lbs, RIH w/3" x 10' DD bailer and tag obstruction at 10,798' KB. Bailed to 10,799' KB (1'). POOH. Bailer had about 4 ' of course sand. Hard bailing. TP- 3,530 psi. Had to hit 5 jar licks at 2,400 lbs and spang hard to get loose. TP- 3,528.4 psi. Ran 3-1/2" x 10' DD bailer down to 10,782' KB. Bailed and made maybe a foot. Real sticky. POOH and had about 4' of course sand in bailer.TP - 3,529 psi. Ran 1.75" x 2' sample catcher and 3.25" fluted centralizer down to 10,797' and sat down with no trouble. Picked straight up with no overpull. POOH. We will be switching over to E-line. It looks like we can perf the zone ok. TP- 3,529.3 psi. Rig down slickline and rig up E-line. PT to 250 low and 5,000 psi high. RIH w/2- 7/8" x 20' Connex HC, 6 spf, 60 deg phase and tie into Halliburton RMTI log dated 21 Nov 2015 and tagged at 10,799'. Run correlation log and send to town (shifted log up 1'). Get ok to perforate from 10,767'to 10,787'. Spotted gun and fired gun with 3,535 psi on well. Well went to 3,534 and back to 3,535 psi. After 5 min pressure was 3,537.7 psi. POOH. All shots fired. Rig down lubricator and turn well over to field. 3,536.8 psi. • . Cannery Loop Field • SCHEMATIC Well. CLU 05RD API: 50-133-20474-01 Hilcorp Alaska,LLC PTD: 215-160 RKB=18' CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 4 20" Conductor 129/N/A/N/A N/A Surf 142' 20" r 1" 4 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' 4 2 9-5/8" Intermediate 53.5/L-80/BTC 8.535" Surf 1,212' 47/P-110/BTC 8.681" 1,212' 9,178' P « 29.7/L-80/HYD 511 6.875" 6,433' 6,910' %� 7-5/8" Liner 29.7/L-80/SLIJ-II 6.875" 6,910' 10,448' •• 0.0 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' TUBING DETAIL 13-3/8" Ill 1 011 4-1/2" 12.6#/L-80/IBT-M 3.958" Surf 1,200' 12.6#/L-80/SuperMax 3.958" 1,200' 10,289' 8-1/2" window at 6,527'MD JEWELRY DETAIL 1 5,354'TVD 9-5/8" 4 No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" w 2 298' 3.812" 7.110" Baker TE-5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2"Chemical Injection Mandrel :1 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer T tom', 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension • ?' 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly e 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer %j 8 11,170' - 3.500" CIBP(TOC 11,170') -!, 9 11,430' - 3.500" CIBP w/10'cement(TOC 11,420') 10 11,505' - 3.500" CIBP w/10'cement(TOC 11,495') 11 11,565' - 3.500" CIBP w/15'cement(TOC 11,550') 7-5/8" 5 6 7 12 11,700' - 3.500" CIBP w/10'cement(TOC 11,690') 13 11,723' - 3.500" CIBP 91-2 RANkr� PERFORATION DETAIL 11,090' Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) SPF Date Size Status D-2C 91-2 10,767' 10,787' 9,081' 9,101' 6 06/03/17 2-7/8" Open • 91-2 10,767' 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Open 8 r D-2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed a3A D-3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated 9 41 D-4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated D-4A D-4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 Z-7/8" Isolated 10 '. ';.1'; t D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 2-7/8" Isolated 11 `, - f+ ', DS D-5A 11,572' 11,580' 9,886' 9,894' 6 01/22/16 2-7/8" Isolated D-5A D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated - D-6A D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated RA Mk,It , D-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated 11,633' P LL 12,13 D-6 RA Mkr Jt 12,060 RA Mkr.8 12,474' Y 4-1/2" -=•cs PBTD=11,170'MD/9,484'TVD TD=12,940'MD/11,253'ND Updated by DMA 06/19/17 • • OF r„, THE STATE Alaska Oil and Gas ofLASA <:A Conservation Commission __= � tfz_�_ 333 West Seventh Avenue C GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 r Main: 907.279.1433 OFA S7iFax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager SC W Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Kenai Cannery Loop Field,Upper Tyonek Gas Pool, CLU 5RD Permit to Drill Number: 215-160 Sundry Number: 317-204 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ai",41 /6124. Cathy P. Foerster 2-41t Chair DATED this 24 day of May,2017. RBDMS MAY 2 4 2017 • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 19017 APPLICATION FOR SUNDRY APPROVALS ' 5/23/' 7 20 AAC 25.280 AOGCC 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend 0 r rt,-Perforate Q. Other Stimulate 0 Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory El Development 0. 215-160 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service 0 6.API Number: f;.i Anchorage Alaska 99503 50-133-20474-90. 7.If perforating: 8.Well Name and Number: S Z-",((7 What Regulation or Conservation Order governs well spacing in this pool? CO 231,Rule 3 • Cannery Loop Unit(CLU)05RD, Will planned perforations require a spacing exception? Yes 0 No1:1 9.Property Designation(Lease Number): 10.Field/Pool(s): Fee-Hilcorp;ADL 324602 Kenai Cannery Loop/Upper Tyonek Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,940' • 11,253' ' 11,170' 9,484' -3,841 psi See Attached N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090psi 1,540psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930psi 6,620psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440psi 5,300psi Liner 4,048' 7-5/8" 10,448' 8,762' 6,890psi 4,790psi Liner 2,675' 4-1/2" 12,915' 11,229' 8,430psi 7,500psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 10,289' Packers and SSSV Type: Baker ZXP+ZXPN Pkrs; Packers and SSSV MD(ft)and TVD(ft): 6,433'MD/5,263'TVD;10,240'MD/8,555'TVD; Baker TE-5 SSSV TR 298'MD/TVD 12.Attachments: Proposal Summary ❑✓ Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development❑✓ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: June 1,2017 CommencingOperations: OIL 0 WINJ 0 WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS Q • WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Ope ations Manager Contact Email: tkramer c@i hilcorp.com '�� Contact Phone: 777-8420 Authorized Signature: eF ,pr„ Date: 1/r/17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 t7-2. a `f Plug Integrity 0 BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes 0 No 0 RBDMS I 2 4 2017 Spacing Exception Required? Yes ❑ No Subsequent Form Required: /0--y ©'-/ '/ APPROVED BY Approved by: % (L,� COMMISSIONER THE COMMISSION Date:6- ..25.f._(7 0RIZ/ cl •� .2 3 �� Submit Form and Form 10-403 evised 4/2017 a alid for 1 months from the date of approval. .��Attachments in Duplicate • • Well Prognosis Well: CLU-05RD Ililcorp Alaska,LL Date:5/18/2017 Well Name: CLU-05RD API Number: 50-133-20474-01 Current Status: Gas Producer Leg: N/A Estimated Start Date: June 1, 2017 Rig: Reg.Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: Maximum Expected BHP: 4,747 psi @ 9,051' TVD From Static Buildup on 4-9-17 Max. Predicted Surface Pressure: — 3,841 psi (0.10 psi/ft gas gradient) Brief Well Summary CLU-05RD Was perforated in the 91-2 sand after a straddle squeeze was performed with CTU to isolate this interval. The well came in strong at over 10MMscfd but has been performing erratic in that it is dropping flowing tubing pressure for a period of time and then recovers. Slick line was ran in the well to check for hydrates but none were found. It is believed that some of the perfs may be partially plugged with debris. - / The purpose of this work/sundry is to re-perforate the 91-2 Tyonek interval. E-Line Procedure 1. MIRU E-line, PT lubricator to 5,000 psi Hi 250 Low. 2. If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 3. Perforate the Tyonek 91-2 sand from 10,767 to 10,787'. 4. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. 5. POOH. 6. Flow through test separator and record water and gas rates. 7. RD e-line. 8. Turn well over to production. Attachments: 1. Current and Proposed Wellbore Schematics 111 • Cannery Loop Field SCHEMATIC Wen: CLU05RD ` API: 50-133-20474-01 1fIilcorp Alaska,LLC PTD: 215-160 RKB=18' CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 1 20" Conductor 129/N/A/N/A N/A Surf 142' 20" ,,, ,• 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' 2h, 53.5/L-80/BTC 8.535" Surf 1,212' 9-5/8" Intermediate 47/P-110/BTC 8.681" 1,212' 9,178' " e.; 29.7/L-80/HYD 511 6.875" 6,433' 6,910' 1 7-5/8" Liner p+ i /L-80/SLIJ-II 6.875" 6,910' 10,448' i 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' 1,200' 'ATUBING DETAIL 3 12.6#/L2-8903/IBT-M 3.958" Surf 13-3/8" 4 1/2" 84/2" 12,64/L-80/SuperMax 3.958" 1,200' 10,289' ¢ � r, window at `, �, 6,527'MD JEWELRY DETAIL a9 1 0 5,354'TVD 9-5/8" 4 No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" ii ? 2 298' 3.812" 7.110" Baker TE-5 Safety Valve , 3 1,210' 3.813" 6.500" 4-1/2"Chemical Injection Mandrel Oil .` 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer ;s 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension ' 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly e 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer 1 8 11,170' - 3.500" CIBP(TOC 11,170') 9 11,430' - 3.500" CIBP w/10'cement(TOC 11,420') At '',01 10 11,505' 3.500" CIBP w/10'cement(TOC 11,495') F 1 11 11,565' 3.500" CIBP w/15'cement(TOC 11,550') u 12 11,700' - 3.500" CIBP w/10'cement(TOC 11,690') 7-5/8" 5,6 7 13 11,723' - 3.500" CIBP t - 91-2 RA � PERFORATION DETAIL Aticr11,090 ' Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Date Size Status •`-D-2C 91-2 10,767' 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Open D-2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed 8 D-3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated D 3A D-4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated 9 t D-4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 2-7/8" Isolated D-4A D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 2-7/8" Isolated 10 D-5A 11,572' 11,580' 9,886' 9,894' 6 01/22/16 2-7/8" Isolated 11 , D5 D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated D-5A D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6A D-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated RA My Jt 11,633' 12,13 r1114111k7: D6 k 4 , { k RA Iiikr.it J 12,060' RAAAvJt 12,474' 4-1/2" -.r PBTD=11,170'MD/9,484'TVD TD=12,940'MD/11,253'TVD Updated by DMA 05-18-17 4 Cannery Loop Field 11 illPR POSED SCHEMATIC Well: CLU 05RD API: 50-133-20474-01 Hilcorp Alaska,LLC PTD: 215-160 CASING DETAIL RKB=18' Size Type Wt/Grade/Conn ID Top Btm 120" Conductor _ 129/N/A/N/A N/A Surf 142' 20' p 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' 2 w 53.5/L-80/BTC 8.535" Surf 1,212' r 9-5/8n Intermediate 47/P-110/BTC 8.681" 1,212' 9,178' 429,7/L-80/HYD 511 6.875" 6,433' 6,910' .M 7-5/8" Liner 29.7/L-80/SLIJ-II 6.875" 6,910' 10,448' 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' TUBING DETAIL 13 3/8" F 12.6#/L-80/IBT-M 3.958" Surf 1,200' w1 4-1/2" 12.6#/L-80/SuperMax 3.958" 1,200' 10,289' v; 4•s 8-1/2" r window at 6,527 MD JEWELRY DETAIL 4 N 5,35D No. Depth ID OD Item 9-5/8" 4 $ a. 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" 2 298' 3.812" 7.110" Baker TE-5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2"Chemical Injection Mandrel " tr 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer 4. 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer 8 11,170' - 3.500" CIBP(TOC 11,170') 9 11,430' - 3.500" CIBP w/10'cement(TOC 11,420') 10 11,505' 3.500" CIBP w/10'cement(TOC 11,495') ,' 11 11,565' - 3.500" CIBP w/15'cement(TOC 11,550') 7 5/8" 12 11,700' - 3.500" CIBP w/10'cement(TOC 11,690') 5,6,7 Si 13 11,723' - 3.500" CIBP 91-2 1 �Mr� PERFORATION DETAIL ttosa $ands Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Date Size Status D-2C 91-2 ±10,767' ±10,787' ±9,081' ±9,101' 6 TBD 2-7/8" Proposed 91-2 10,767' 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Open 8 D3A D-2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed D-3A 11,321' 11,346' 9,635' 9,660 6 11/25/16 2-7/8" Isolated D-4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated D-4A D 4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 2-7/8" Isolated 10 '. D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 2-7/8" Isolated 11 • a5 D-5A 11,572' 11,580' 9,886' 9,894' 6 01/22/16 2-7/8" Isolated D-5A D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated D-6A D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated RA Mkr Jt 1 D-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated 11,633' 12,13 D-6 RA Mkr Jt A 12,060 • RA Mkr it .. 12,474' 4-1/2" mt. PBTD=11,170'MD/9,484'ND TD=12,940'MD/11,253'TVD Updated by DMA 05-18-17 21 51 50 w 28219 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 RECEIVED Anchorage, 99503 Tele: 907 77777 8308 Riknrp Alaska,1,11: Fax: 907 777-8510 DATA LOGGED /201 E-mail: snolan@hilcorp.com 5'2'ER MAY 1 9 2017 NDENDER DATE 05/02/17 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 05RD smote MAY 3 02017 Production profile and digital data Prints: Radial Cement Bond Log CD1: CLU-05RD RBT_10MAR17.pdf 3/27/2017 8:36 AM PDF Document 3,312 KB CLU-05RD RBT_10MAR17 img.tiff 3/27/2017 8:36 AM TIFF File 8,160 KB CLU-05RD RBT_10MAR17 MainPass.las 3/27/2017 9:38 AM LAS File 1,938 KB CLU-05RD RBT_10MAR17 RepeatPass.las 3/27/2017 9:38 AM LAS File 901 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: ✓� /1'j Date: STATE OF ALASKA RECEIVED ti ALI.OIL AND GAS CONSERVATION COM�ION APR 1 1 2011 REPORT OF SUNDRY WELL OPERATIONS A0C 1.Operations Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Pull Tubing 0 6pera ons shutdown ❑ Performed: Suspend 0 Perforate [/ Other Stimulate 0 Alter Casing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool d Repair Well 0 Re-enter Susp Well 0 Other: N2 Pumping 9 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 9 Exploratory 0 215-160 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic 0 Service❑ 6.API Number: Anchorage,AK 99503 50-133-20474-01 7.Property Designation(Lease Number): 8.Well Name and Number: FEE Hilcorp(ADL060569);ADL324602 Cannery Loop Unit(CLU)05RD 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A �8L--- Kenai C.L.U./Beluga&Upper Tyonek Gas Pools 11.Present Well Condition Summary: 11,170; 11,420; 11,495;11,550; Total Depth measured 12,940 feet Plugs measured 11,690;11,723 feet true vertical 11,253 feet Junk measured N/A feet Effective Depth measured 11,170 feet Packer measured 6,433&10,240 feet true vertical 9,484 feet true vertical 5,263&8,555 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090 psi 1,540 psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930 psi 6,620 psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440 psi 5,300 psi Liner 4,048' 7-5/8" 10,448' 8,762' 6,890 psi 4,790 psi Liner 2,675' 4-1/2" 12,915' 11,229' 8,430 psi 7,500 psi Perforation depth Measured depth See Schematic feet r True Vertical depth See Schematic feet SCAM A! P 4 J Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 10,289(MD) 8,603(TVD) Baker ZXP+ZXPN Pkrs;6,433'MD/5,263'TVD&10,240'MD/8,555'TVD Packers and SSSV(type,measured and true vertical depth) Baker TE-5 SSSV TR 298'MD/298'TVD 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 168 120 Subsequent to operation: 0 10348 2 584 1985 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory ❑ Development 0 Service 0 Stratigraphic ❑ Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 0 Gas 9 WDSPL❑ Printed and Electronic Fracture Stimulation Data 0 GSTOR 0 WINJ 0 WAG 0 GINJ 0 SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-302;316-577;317-048 Authorized Name: Chad Helgeson Contact Name: Taylor Nasse Authorized Title: Operations Manager Contact Email: tnasse@hilcorp.com Authorized Signature: (" Lr ��Z�7i.,,_ \ Date: Vfi/C 7 Contact Phone: (907)777-8354 Form 10-404 Revised 4/2017 y-� 1� RBDMS `' /e�C `"� �� ,�� 1 2 2017 Submit Original Only • • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 6/13/16 3/13/17 Daily Operations: 06/13/2016-Monday Sign in, mobe to location and spot equip.SIMOPS, PTW and JSA. Rig up lubricator and SLB N2 pump truck.Started ppping N2 at 1,400 psi/1,900 scf/min until we finished with 3,390 psi/2,400 scf-min.We pumped a total of 230,200 scf. , e t in hole with 3,200 psi on tubing with P/Ttool to find fluid level.Tagged at 11,612'and found fluid at 11,598'tied in with perf log dated 5-26-16. POOH. RIH with 3" OD magna range plug and tied into perf log dated 5-26-16. Set plug at 11,565'. Pick up 20' and go back down and tag plug.TP-3,130 psi. POOH and everything looks good. RIH w/3.5"x 30' pt,1, dump bailer filled with 10 gals of water and dump bail water on top of plug at 11,565'. POOH.TP-3,057 ps.i RIH w/3.5" x 30'dump bailer filled with 15#cement and dump bail 15' (10 gals)on top of plug at 11,565'. Estimated top of cement at 11,550'. POOH.TP-3,035 psi. Cement in place at 2130 hrs. Rig down lubricator and get equipment ready to move toy Swanson for plug and perf.TP-3,012 psi /4 06/15/2016-Wednesday Sign in, mobe to location and spot equip.SIMOPS, PTW and JSA. Rig up lubricator pressure test 250 psi low and 5,000 psi high. RIH with 2-7/8"x 20'Connex HC, 6 spf,60 deg phase and tie into Halliburton RMTI log dated 21 Nov 15. Run correlation log and send to town.Get ok to perf from 11,510'to 11,530'. Bled well down to 2,522 psi.Spotted shot and fired gun. Pressure went to 2,532 psi right away and after 5 min it was 2,599 psi and climbing.After approx. 20 min it went to 2,866'and climbing. POOH. Rig down lubricator and turn well over to field.TP-2,988.5 psi and still climbing when we closed the swab. 10/07/2016-Friday PTW and JSA with SLB N2. HLB gets to location at 10:00 hrs. PTW and JSA with HLB.SIMOPS with both crews. Rig up both SLB and HLB. Pressure test lubricator and lines to 5,000 psi.Start pumping N2 and running in hole with GPT tool. Correlated with D-5 perf log. Found fluid level at 5,834'going in hole with about 1,500 psi and found fluid level at 7,893' with 4,000 psi on well. Called town and discussed.Well never broke over and talked about max pressure of 4,200 psi. HLB had to put more wt bars on and tighten flange on N2 hookup. RIH w/GPT tool with 3,300 psi surface pressure and tie into log. Found fluid level at 7,765'. Pressured up to 4,000 psi with N2 and fluid level went to 7,907'. At 4,000 psi fluid level was dropping 6.5' per min. as it bleed down it got to 3.5' a minute with 3,750 psi on well. Fluid level was 8,061'with / 3,740 psi. Called town and discussed. POOH with GPT tool and rig down lubricator. Pressured well up to 4,200 psi with N2 and shut in. Rig for standby. Have N2 tanker be here at 8 am.Will start back up at 7 am in the morning. Pumped total of 1,850 gals N2.Will have night operator take a few pressure during readings during the night. 10/08/2016-Saturday Sign in. Mobe to location. PTW,JSA and SIMOPS with SLB and HLB. Rig up lubricator and N/2. PT N2 hard lines, lubricator to 250 low and 5,000 psi high.TP-3,450 psi RIH with GPT tool and find fluid level at 9,200'with 3,450 psi tubing pressure.Start pumping N2. Pressure up tubing to 4,135 psi and try to maintain pressure while monitoring fluid level. Pressure fell to 4,000 psi in 53 min and fluid level fell to 9,408'. Started pressuring up to 4,200 psi and as fluid level went down I raised pressure until I was at 4,436 psi and FL was 10,650'.After one hour FL was 10,800'and pressure was 4,280 psi.SLB and HLB said they could have night crew. Kept pressuring up to approx.4,470 psi and wait one hour to / pressure up again. Got fluid pumped away at 0030 hrs.(11,520'). POOH with Halliburton GPT tool. RIH with 3-1/2"x 35' bailer filled with cement. Kept pumping pressure up to 4,470 psi and it was falling back to 4,000 psi within an hour.Tools set down at 11,500' and had to work tools free. Decided to come out of hole and get rid of cement. POOH. Get HLB off well. TP-3,693 psi. Pump Approx 1,750 gals of N/2. 10/09/2016-Sunday • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 6/13/16 3/13/17 Daily Operations: Finish emptying bailer of cement and rigging down.Sign in at office, PTW and JSA. Mobe to location,spot equipment. Rig up N2 and slickline lubricator. PT to 250 psi low and 4,600 psi high.TP-3,500 psi. RIH w/3.56"GR to 6,600' and tools started slowly going down hole. Pick up was real heavy. Discussed with town about pumping 10 gals diesel in hole. POOH and tools covered in e-line grease. Had diesel tank brought down. Filled lubricator with 10 gals of diesel and dumped in hole followed with 3.56" GR to 6,800'and tools slowed way down. POOH and dumped 10 more gals of diesel and went back down to 11,498'and tagged.Worked GR down to 11,504'. POOH. Found FL at 9,720'. Pressure well up to 4,370 psi w/N2. RIH W/3"x 5' DD found FL at 10,050' KB. Bailed from 11,504'to 11,512' KB. POOH. Bailer had hard sand at bottom of bailer and rest fluid. Not much sand. Pressure well up to 4,335 psi w/N2. RIH with 3"x 5' DD bailer and bailed from 11,512'to 11,516' KB. POOH and had about same as last bailer run. Pressure well up to 4,335 psi w/N2. RIH W/ 3.55"GR to 11,516'and work tools to 11,523'. Had to hit jars twice to get free. POOH.Change out slick line crews.TP- 3,600 psi. 10/10/2016-Monday Stand by to pump nitrogen. Pressure lubricator up to 3,500 psi. RIH w/3.50"G ring w/teeth to 11,529' KB,sat down W/T sticky. POOH,TP-3500 psi.Stand by to pump nitrogen, pressure lubricator up to 3,500 psi. RIH w/3.71" blind box to 11,529' KB tag fill-W/T. POOH. RIH, pressure lubricator up to 3,500 psi. RIH w/3" DD bailer to 11,685'. POOH. RIH, pressure lubricator up to 3,500 psi. RIH w/same to 11,534' KB,sat down W/T. POOH, hard little sticky. RIH, pressure lubricator up to 3,500 psi. RIH w/same to 11,534' KB,sat down WIT. POOH, hard little sticky. RIH, pressure lubricator up to 3,500 psi. RIH w/3-1/8"dummy guns to 11,532' KB. Tag fill. POOH, hung up,will not move. Bleed tubing to 3,400 psi and work tools to get free. Unable to free tools up.Jars did not work and spangs were not much better.Change out crews,work tools to try and free up.Close rams bleed lub. Install 1.50"x 3'cutter bar open rams wire cut in 8:37 min. POOH,97 on counter. Rig down .125"S/L rig up .160"S/L unit, redress wireline valve, P/T lub to 3,500 psi,wireline valve - leak, C/O o-ring retest,test good. RIH w/2"JDC w/3.5" bell guide to 11,900' KB,wire was out of counter wheel. POOH, P/T lub to 3,500 psi,wireline valve leak, C/O o-ring retest,test good. RIH w/2"JDC w/3.5" bell guide to 11,900' KB. POOH. 10/11/2016-Tuesday RIH w/2"JDC w/3.5" bell guide to 11,496' KB W/T. POOH, OOH w/cutter bar. RIH w/2-1/2"JDC w/2.70" bell guide to 11,499' KB W/T. POOH with fish rig down fish, all tool string accounted for. RIH w/3.71" blind box to 11,551' KB. POOH, did not see fluid. RIH w/3.375"x 18'dummy guns to 11,525' KB-PUW's 10,000' = 1860#, 10,500' =2,000#, 11,000'= 2,170#. 11,200'=2,230#, 11,400' =2,250#, 11,450' =2,280#, 11,500'=2 320#, 11,525'=2,400#. POOH, rig down SL and rig up E-line.SIMOPS, PTW and JSA for E-line and SLB N2. Pressure test lubricator to 250 psi and 5,000 psi high. RIH w/GPT tool and tie into perf log.Tagged fill at 11,518'and also fluid level was at that depth.TP is 3,325 psi.Very sticky on bottom. POOH. Pressure tubing up to 3,500 psi. MU 3-1/2"x 30' bailer and fill with 7.3 gals(10') of cement. RIH with bailer and tie into perf log to 11,508' (10'above bottom). Dump, bail cement on top of fill and across perfs from 11,518' to 11,510'.Start pumping N2 and POOH with E-line.Cement dumped sat 0100 hrs. 10/12/2016-Wednesday RIH w/3-1/2"x 20' Bailer with 7 gals cement(10') and tie into perf log.Tagged plug at 11,505'. Pick up 10'and dump 10' of cement on top of plug at 11,505'.TP-4,000 psi. POOH. Est TOC is 11,495'and cement in place at 0730 hrs. Got out of hole and cement just dumped first 1-1/2'. Looked like it was a good dump.When they broke bailer in half it had pretty dry (not set up) cement in all but bottom 1-1/2'. Rig down lubricator and secure well. HLB will take bailer back to shop and clean out. Will finish cement job in the morning.We have pumped 2,400 gals N2 in last 24 hrs.We have approx. 4,500 gals of N2 on location. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 6/13/16 3/13/17 Daily Operations: 10/13/2016-Thursday PTW and JSA. Rig up lubricator and pressure test to 250 psi low and 5,000 psi high. RIH w/3-1/2"x 20'dump bailer filled with 6.7 (9')gals of cement and tied into perf log.Tagged TOC at 11,504' (Figured bailer dumped approx. 1/2-1' cement on plug at 11,505'. Cement is probably no good).Tried to pick up but tools were stuck. Bled well down from 4,000 psi to 2,492 psi with wireline tool wt at 2,500 lbs.Tools weighed 1,550 lbs.Tools did not come free. Worked tool wt from 2,500 lbs to 2,900 lbs in 100 lb increments and tools came free at 2900 lbs. Checked correlation and dumped 9' of cement from 11,504'to 11,495'. Lost 100 lbs of weight. Cement in place at 1315 hrs. POOH. Bailer had dumped ok. Rig down lubricator and WOC. Plan on perforating tomorrow afternoon. 10/14/2016- Friday PTW and JSA. Rig back up lubricator and PT to 250 psi low and 5,000 psi high. Cement sample is hard from yesterday's dump. Arm gun.TP-2,512 psi RIH w/2-7/8"x 20' Connex HC,6 spf, 60 deg phase perf gun,tie into plug log dated 10-12- 16 and tag TOC at 11,495.5'. Run correlation log and send to town. Get ok to perf from 11,490'to 11,470'. Spot and fired gun with 2,528.5 psi. Went to 2,643 psi after 2 min and 2,708 psi after 5 min. 2,827 psi after 20 min. POOH. 2,994.4 psi when we closed swab.All shots fired and gun was dry.TP pressure is 3,038 psi. RIH w/2-7/8"x 10' Connex HC, 6 spf, 60 deg phase perf gun,tie into plug log dated 10-12-16 and tag TOC at 11,495.5'. Run correlation log and send to town. Get ok to perf from 11,470'to 11,460'. Spot and shoot gun with 3,077.7 psi. Pressure was at 3,079.6 psi after 5 min. POOH. All shots fired and gun was dry. Rig down E-line and turn well over to field.TP-3,087.4 psi. 10/16/2016-Sunday PTW and JSA. Rig up lubricator and PT to 250 psi low and 5,000 psi high.TP-800 psi. RIH w/3-1/2" GR and tag fill at 11,489' KB WLM. Found fluid level at 9,190' KB WLM. POOH. NOTE: This slickline unit is the same we were bailing with. It was running about 12' deeper than Halliburton E-line unit. If that is the case top of fill would be around 11,477' E-line depth after tie-in with perf log. FL would be about 9,178' E-Line measurement. Rig down lubricator and turn well over to field. 10/26/2016-Wednesday PTW and JSA. Rig up lubricator and PT to 250 psi low and 5,000 psi high.TP 2,990 psi. RIH w/3"x 10' DD bailer with 160 wire to 10,100'. Had trouble going in hole because of dry wire with new packing in pack off head. Greased line until tools were running good. Notice wire was smashed. POOH. Changed from 160 wire to 125 wireline. Re-test lubricator and it was ok. RIH with 3"x 10' DD bailer and tagged fill at 11,445'WLM KB. Bailed to 11,453'. POOH and bailer was empty. Probably something wedged flapper open.TP- 1,960 psi. Called town and discussed. RIH with 3"x 10' DD bailer and tagged fill at 11,447'WLM KB. Bailed to 11,455' WLM KB. Bailer full of moist sand. Get sample out of bailer and leave at KGF office. Rig down lubricator, secure well and rig for standby.Will return at 0800 hrs.TP-2,932 psi. 10/27/2016-Thursday Rig up lubricator, PT to 250 psi low and 5,000 psi high. TP-2,998.5 psi. Ran 3.7" Blind box and found fluid level at 9,825'. Tagged at 11,450'WLM KB. RIH w/3"x 8' DD bailer and tag fill at 11,450'. Ran bailer 6 times and made it to 11,476' WLM KB.Getting fluid level at approx 9,770'with still approx 2,990 psi on well.All bailers were filled with the same moist sand. We got water back sometimes when bailer wasn't full. Had one bailer that lost most of the sand because of a flapper stuck open part way,should be able to bail the rest and perforate tomorrow. Rig down lubricator and secure well.SDFN. Will be back at 7 am to finish up. 10/28/2016- Friday • • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 6/13/16 3/13/17 Daily<Operations: PTW and JSA. Rig up lubricator, PT to 250 psi low and 5,000 psi high.-TP-3,025.9 psi. RIH w/3"x 10' DD bailer and tag fill at 11,473' and bailed to 11,475'. Bailing was hard and stop making hole. POOH. Bailer was full of sand and a little bit of mud. RIH w/3"x 10' DD bailer and tag fill at 11,471'and bailed to 11,473'. Bailing was hard and stopped making hole. POOH. Bailer was half full of sandy mud and half full of water. POOH. Found FL at 9,850' (9,775' last night).TP-2,993.9 psi. RIH w/2.5"x 15' DD bailer and tag fill at 11,473' and bailed to 11,475'. POOH and bailer had about 1'sand and the rest water. RIH w/3"x 10' DD bailer and tag fill at 11,475' and bailed to 11,477'. Bailing was hard. POOH. Bailer 1/2 full of sand and 1/2 full water.TP-2,990.5 psi PTW and JSA. Rig down slickline and rig up E-line. PT 250 psi low and 5,000 psi high. RIH w/GPT tool and correlated to last perf log. Found fluid level at 9,551'and tagged fill at 11,482'. POOH. Called town and decided to bail some more. PTW and JSA. Rig down E-line and rig up slickline. PT to 250 low and 5,000 psi high. RIH w/3"x 10' bailer and tag fill at 11,474'. Bailed to 11,476'. Had to jar loose one time. POOH. TP-2,978 psi. Rig down lubricator and secure well.SDFN. Be back at 0700 hrs. 10/29/2016-Saturday PTW and JSA. Rig up lubricator PT 250 psi low and 5,000 psi high.TP-2,990 psi. RIH w/2-1/4"x 10' DD bailer and tag at 11,473'WLM KB. Bailed to 11,477'WLM KB(should be about 11,483' E-Line). Could not bail deeper. POOH. Had about 2' of sand in bailer. RIH w/3"x 10' DD bailer and tag at 11,475'WLM KB. Bailed to 11,477'WLM KB. POOH. Got about 1- 1/2'sand out of bailer.Called town and discussed. TP-2960'. Ran the 2-1/4'x10' bailer and tagged at 11,476'WLM KB. Bailed to 11,477'. POOH and get approx. 2'sand from bailer. RIH w/3"x 10' DD bailer and tag at 11,477'WLM KB. Bailed at this spot and didn't make any hole. POOH. Had about 1'of dry sand. 2,935 psi. Rig down slickline and rig up E-line. Go over JSA before rig up. PT to 250 low and 5,000 psi high.Arm gun. RIH w/2-7/8"x 20'Connex HC,6 spf,60 deg phase perf gun and tie into last perf log. Run correlation log and send to town. Get ok to perf from 11,460'to 11,480'.Spot gun and fired with 2,935 psi on well.After 7 min 2,935.6 psi. POOH. Rig down lubricator and turn well over to production. 11/21/2016-Monday PTW,JSA SIMOPS with HLB and SLB N2. Mobe to location.Spot and rig up equip. PT lines and lubricator to 5,000 psi.TP- 2,680 psi. RIH w/Press/Temp tool and find fluid level at 8,210'and tagged fill at 11,482'. Bring N2 up from 2,680 psi to 4,500 psi. Keeping pressure at 4,500 psi with 500 scf rate. POOH with PT tool leaving fluid level at 10,082'.We used approx.3,000 gals of N2. Rig down lubricator, put 4,500 psi on well and close in for the night.Will come back in morning and finish up. 11/22/2016-Tuesday PTW and JSA. Rig up N2 and HLB lub. PT to 250 psi low and 5,000 psi high.TP-3,870 psi. RIH w/Press/Temp tool and find fluid level at 11,410'.Started pressuring N2 at 4,500 psi 500 scf. Got fluid pushed away. POOH w/PT tool while maintaining N2 pressure.Trouble shoot HLB cement dump bailer bottom. RIH with 3"x 30' dump bailer and dump bailed 20'of cement 2'above perfs at 11,458' correlated with 3,900 psi on tubing. Raised pressure to 4,100 psi at 750 scf. POOH at 100' per min due to line wiper not cleaning grease off line if going any faster. RIH w/4-1/2"CIBP and tie into HLB plug correlation log. Run correlation log and send to town.Get ok to set plug at 11,430'.Spotted plug with 3,700 psi on tubing at 11,430'. Lost 200 lbs of line wt when plug set. Picked up 30'and went back down and tagged. POOH at 100' per min because of line wiper problem. Looked like good set but still could pump N2 at 3,800 psi at 500 scf.Talked to town about pressure. RIH w/3-1/2"x 20' bailer and tagged plug at 11430'. Dumped 10'of cement on top of plug with 3,800 psi on tubing. Good dump. Est TOC at 11,420'. POOH. Pressured tubing up to 4,100 psi and it was holding rock steady. Looks like good isolation. Rig down lubricator and N2 lines and secure well.WOC. Used approx.3,200 gals of N2. 11/25/2016-Friday 41, • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 6/13/16 3/13/17 Daily Operations: PTW and JSA. Rig up lubricator, PT to 250 psi low and 5,000 psi high.TP-3,500 psi. RIH with PT tool and tie into plug log. Tag at 11,425'. Bled well down from 3,600'to 3,080'. Run PT log and send to town. Found no fluid in well. RIH w/2-7/8"x 25'Connex HC, 6 spf, 60 deg phase perf gun and tie into plug correlation log. Run correlation log and send to town. Get ok to perf.Spot and fire gun from 11,321'to 11,346'with 3090.4 psi and after 5 min pressure was 3094.6 psi. POOH.All shots fired and gun was dry. Rig down lubricator and turn well over to field.TP-3,091.7 psi. 12/22/2016-Thursday Sign in, PTW,JSA and mobe to location.Spot equipment. PT to 250 psi low and 5000 psi high.TP-3384 psi. Had trouble getting wire line to go thru grease tubes. Finally got line cleaned up and RIH with GPT tool.Tied into Halliburton RMTI log,found fluid level at 11,292' and line stopped at 11,340' due to line being new and hadn't been run thru grease tubes. POOH, RIH w/2-7/8"x25' Connex HC, 6 spf, 60 deg phase perf gun and tie in to Halliburton RMTI log. Run correlation log and send to town. Get ok to perf from 11,081'to 11,106'.Spot and fire shot with 3353.6 psi on tubing.TP pressure started dropping immediately after shot was fired.TP was 3242.2 after 20 min, 3302.5 psi after 5 min.Still slowly dropping. POOH.All guns fired and gun wasn't dry but it wasn't real wet either. Rig for standby and turn well over to field. 12/27/2016-Tuesday Sign in at office, PTW and JSA. Mobe to location. Rig up lubricator and N2 lines. PT lines and Lub to 250 psi low and 5000 psi high. RIH with GPT tool and find FL sat 5050'with 1326 psi on well. POOH. Pump N2 starting at 2500 scf at 1326 psi, went to 4450 psi at 1000 scf and ended up with 4500 psi at 220 scf. Went in and checked fluid level and it was at 10,160' with 4300 psi on well. Made pass with GPT tool across perfs and come out of hole. Put 4500 psi on well and close both masters and swab. Will be back in morning at 7 am. We used approx.4500 gals N2.SDFN. 12/28/2016-Wednesday Sign in at office, PTW and JSA. Mobe to location Rig up lubricator. PT lines and Lub to 250 psi low and 5,000 psi high. TP- 3,045.8 psi. RIH w/GPT tool and 3.5" CIBP and tie into Halliburton RMTI log. Found fluid level at 11,088'with 3,010 psi. Called town and discussed. Got ok to set plug at 11,170'.Spotted plug and set plug with 3,008 psi on tubing . Picked up 30' and went back and tagged plug. POOH. Looks like good set. RIH w/3"x20' cement dump bailer and tag plug at 11,170'. Pick up and dump 10' (6 gals) of cement on top of plug. Lost 100 lbs line wt when dumped. POOH. Good dump. Est TOC at 11,160'. Cement in place at 1400 hrs. Rig down lubricator,secure well and rig down equipment. WOC. TP- 2,808 psi. 12/29/2016-Thursday Sign in and mobe to location. PTW and JSA.Spot equip and rig up lubricator.Test the Halliburton water behind pipe tool. PT to 250 psi low and 5,000 psi high.TP-2,796.5 psi. RIH with Halliburton tool.Tie into Halliburton RMTI log. Find fluid level at 11,010' and tagged TOC at 11,154'.Set tool up and start well flowing at 1.0 MMSCFD. Run up pass with tool.Shut well in with 2,184 psi on tubing and POOH. Invert the tool for down flow and do checks. RIH with Halliburton tool.Tie into Halliburton RMTI log. Find fluid level at 10,855'with 2,184 psi. Flow well at 0.6-0.8 MMSCFD rate and run down pass. Found fluid level coming out of hole at 9,295' at 1,380 psi on tubing. Rig down lubricator and equipment and turn well over to field. 03/02/2017-Thursday RDMO from KU 12-17. RU SLB CTU 12 with 1.75" CT on CLU-05RD. Spot Insulated upright tank, 200 bbls (non freezable fluids) holding tank and 500 bbl diffuser return tank. Ready for BOPE test in the AM. 03/03/2017- Friday • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 6/13/16 3/13/17 Daily Operations: PTW. Safety meeting. Discuss BOPE test procedure. 24 BOPE test witness notification sent 3/1/17 @ 1312. Witness waived by Jim Regg 3/1/17 1458 hrs. Field Triplex on location ready to start BOPE test.Start BOPE test.Test all rams and valves to 250/4,500 psi.Accumulator draw down test. BOPE test passed. No failures. SLB off location. No unit charge for the day. Only add hours for BOPE test. Ground heater on location. Plumb into insulated upright tank. Load and heat 380 bbls of fresh water.400 gallons of neat methanol delivered. Mixed into tank and blended with fresh water and glycol. Location secure. 03/05/2017-Sunday Saxon 169 released SLB cement crew and equipment.Obtain PTW. Hold safety meeting and review job procedure. Fire equipment. Pick injector head. Stab 10' lubricator. Make up BHA as follows: 1.75" OD roll on coil connector, 1.75"OD DFCV, 2x 1.75" OD MBT, 2.0"OD ball drop nozzle drifted with 5/8" ball. BHA length 9.073'. Stab on well. PT stack 250/4,500 psi. Bleed down. Fluid pack CT reel at surface.Calculated reel volume is 35.6 bbls.Online with 1% KCL @ 68* down CT. Looking for accurate reel volume strap for cement job. 1.75 bbls/min 4,200 psi. Returns to open top tank. Reel volume confirmed 35.6 bbls. Pressure up stack to 3000 psi. Open well. WHP 2,916 psi. RIH.Stack 1K down at 302.5'. Cycle SSSV attempt to open. RIH. Bleeding WHP down.Tag TOC @ 11,159'CTMD.TOC at 11,160'. Pick up coil stretch to 17.8K. Correct depth to 11,160'. Increase pump rate to 1.8 bbls/min 3,700 psi. WHP 1,300 psi. Circulate bottoms up. 165 bbls pumped.Solid returns to surface. In and out micro motion showing 1:1. Close choke. Start injection test.0.5 bbls/min 2,700 psi CT pressure, 2,370 psi WHP. 0.8 bbls./min 3,200 psi CT pressure, 2,572 psi WHP. 1 bbl/min 3,500 psi CT pressure 2,772 psi WHP.5 bbls per each rate test. 15 bbls total. Hold safety meeting with coil, cement and Cruz vac truck driver.Start pulling water to shear chemicals and start blending cement. Having problems with frozen valve.68 degree water on board batch mixer and cement pump.75 bbls pulled on.50 bbls in rear batch mixer for cleanup. SLB cement having problems with frozen valve. Run heater hoses.Start blending cement. 14.0 PPG squeeze crete. 15 bbls requested volume. PT cement lines 250/5,000 psi. Online down CT with cement. Density on micro motion 14.1 ppg zero bbl counter. Pumping cement down CT at 1.3 bbls/min. CT parked at 11,110'. 5 bbls of fresh water pumped after 18.7 bbls of cement. Shut down cement pump. Start cleaning up batch mixer and pump. Online with CT pump at 1.5 bbls/min. CT pressure only 250 psi due to 14 ppg you tubing. Pinch in choke and increase pump rate to catch fluid. 36 bbls pumped cement at nozzle. Let 0.623 bbls get around CT and close in choke.WHP increasing 25' of perfs covered with cement. PU OOH to 11,078'at 20 ft/min. WHP increase to 3,080 psi before a light break over. Start injecting into formation at 0.5 bbls/min. Called max pressure to be 3,500 psi before circulating cement to surface. Nice steady increase in WHP as 18.7 bbls of cement injected. 3,487 psi WHP at end. 3,487 psi. Shut down for 30 minutes. WHP dropping and flat lined at 2,500 psi after 16.5 minutes. Calling 2,500 psi static hold pressure. Cementers mixing up powervis/cement retarder. 25 bbl volume. Launch 5/8" ball to land on seat and plug off ball drop nozzle. All fluids directed to side jet nozzles to assist in tubing wall cleanup. Online down CT at 1.3 bbls/min. Crack choke and hold 2,300 psi getting 1:1 on in and out micro motion.36 bbls away gel at nozzle. CT parked at 11,078' (should be 80' TOC). Gel out of nozzle+5 bbls of water. Start POOH. Pulling out of hole at 80 ft/min. Fluid velocity 105.3 ft/min. Chase contamination pill OOH.Wash 2x across CBP set depth from 10,780'-10,800'. Continue POOH at 85 ft/min. At 800'swap to freeze protect fluid 60/40 meth water.Tagged up at surface. Shit in wellhead. SITP 1100 psi. Blow down stack. Pop off well. Break down tools. Rig back for night. Move crane to make room for PESI in the AM. Location secure. 03/06/2017-Monday • • Hilcorp Alaska, LLC Well Operations Summary Well Name I Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 150-133-20474-00 215-160 6/13/16 3/13/17 Daily Operations: PESI on location. Obtain PTW.Safety meeting. Discuss job procedure. RU PESI. MU GR/CCL and composite bridge plug. Stab on well. PT stack 250/2,500 psi. 3.125"GR,#10 setting tool. 3.625"sleeve,3.625"composite bridge plug.Open well. RIH. Initial WHP 0 psi. Previous night SITP 1,200 psi. Log from 10,850 to 10,700'. Send log to Taylor Nasse. Confirmed on depth.SET CBP at 10,790'. POOH to surface. Close swab. Bleed down. Pop off well. Break down setting tool. Make up guns. Firing head, 2"OD circulation charges with 5/8" penetration 0.3" entry hole. 10'guns with 4 spf 0 degree phasing.Stab on well. RIH.Tag top of CBP @ 10,790. Pull strip. Verify log on location. On depth. 4'from CCL to top shot. Parked at 10,768'. Puts top shot at 10,772'-10,782' . Fire circulation charges. Pollard hand indicates WHP increase from 250 psi to 1,000 psi. POOH to surface. Tagged up. Close swab valve. Lay down tools and lubricator. Install SLB night cap. RDMO PESI. Location secure. 03/07/2017-Tuesday PTW. Safety meeting. Discuss job procedure. Review cold weather operations and best practices. Pick inj head.Stab 10' lubricator. Remove night cap. Make up BHA as follows: Coil connector 1.75"OD pull test 25K. 1.75"OD DFCV, 2x 1.75" OD MBT, 2.0"OD ball drop nozzle with side jets (5/8" ball seat) BHA length=9.073'.Stab on well. PT stack 250/4,500 psi. Circulate 60/40 freeze protect fluid out of coil with 1% KCL @ 78 degrees F,36 bbls reel volume. Close choke. Pressure up stack to 1000 psi. Open upper master and swab valve.23.5 turns. Initial WHP 1,170 psi. RIH. Crack choke to see what is being returned to OT tank.Getting gas returns and surges of fluid. Continue IH. Pumping 0.67 bbls/min attempting to maintain 1:1. WHP increase to 2,265 psi. 3,389 psi WHP stop increasing start flat line while RIH. Shut down fluid pump until below perfs. 10,500'WT chk. 20.5K. RIH WT-5K. 3,382 psi. Tag top of CBP @ 10,782'CTMD. 8' higher than set depth of CBP. Re-tag 3 times. Same depth of 10,782'. Pick up in tension to 23K. CT depth encoder reading 10,776'. 6' of CT stretch. Correct depth in tension to 10,790'.Start pumping bottoms up to circulate gas out of tubing to ensure fluid pack to properly place cement plug behind pipe.Online down CT at 1.3 bbls/min holding formation back by keeping 3,200 psi WHP and maintaining 1:1 returns. Calculated btms up 136 bbls gas and fluid surges to surface until 162.5 bbls pumped. Fluid only returns to surface. Well bore fluid pack.Start injection test as follows:0.6 bpm @ 3,160 psi WHP increase and flat line at 3,160 psi. 1.0 bpm @ 3,308 WHP flat line. Call Taylor N to discuss injection test results. Directed to squeeze 10-15 bbls of squeeze crete. Shut down fluid pump. Inform SLB cement of BBLS required for cement squeeze. Permission granted to start shearing pre cement chemicals. Pulling on 78°F fresh water. CT parked at 10,789'. Decided to stay 7' below perfs due to 7'off from CT tag depth of correlated CBP depth. Water and chemicals sheared and mixed up. Ready for squeeze crete. Hold safety meeting between CT and pumping services. 1500hrs-1520hrs safety meeting complete.Start mixing squeeze crete cement. Confirmed with cement sup 14.0 ppg via mud scale. PT cement lines to 250/4,500 psi.Zero in and out micro motions when density increased on IH micro motion. CT parked at 10,789'. Crack choke maintain 1:1 returns. WHP 3,030 psi. 14.1 ppg indicated on MM in hole. 15 bbls of cement in coil. Swap to CTU pump. Pump Cement to nozzle. 36 bbls cement at nozzle. Pump 0.256 bbls outside of coil nozzle. Close choke. Cement depth 10,765'-10,789'. Cement across perfs upon shutting choke. Injecting squeeze crete cement at 1 bpm at 3275 psi. 9 bbls Ci of cement injected and pressure broke over at 3,320 psi. Slight flat line. 14 bbls of cement slurry pumped at 3,300 psi rapid break over to 3,047 psi with 1 bbl left to go. After break over pressure start rising to 3,125 psi. 15 bbls injected. Shut down pump.Shut down for 30 minutes.WHP 3,100 psi. Pick up to 10,760'. Pressure flat lined at 3,078 psi for 30 Z C_ minutes. 10,760' launch 5/8" ball followed by 25 bbls of retarder/contamination pill. Hold WHP to 3,000 psi while V circulating bottoms up at 1:1 pumping 1.3 bpm.Start POOH chasing pill to surface maintaining 3,000 psi WHP. 136 bbls bottoms up complete.Swapped to 60/40 freeze protect fluid at 3200'.At surface. Close in swab and upper master valve 2,956 final SITP. Bleed down stack. Blow down stack with air. Pop off well. Rig back CTU unit. Location secure. SDFN. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-„Line 50-133-20474-00 215-160 6/13/16 3/13/17 ei 03/09/2017-Thursday PTW. Hold safety meeting. Review job procedure and JSA. Pick injector head. Make up coil connector. Pull test 25K. Make up BHA. 2.875"Slip CC, 2.875"OD motorhead assembly, 2.875"OD DAJ,3.125" OD CTD motor, 3.2"x over, 3.7"5 bladed junk mill. (MHA PT to 250/4,500 psi.)Stab on well. PT stack to 250/4,500 psi. Circulate out 60/40 freeze protect. Open upper master and swab 23.5 turns. RIH. Initial WHP 1,408 psi. Crack choke. Check returns. Fluid only. Bleed down to 0 psi. Returns are pipe displacement in volume. IA=300, OA=0 psi estimated/calculated TOC 10,760', estimated top of plug 10,790'. CIH, 10,600'shut down pump. RIH attempt dry tag. Tag top of cement 2x at 10,762.5'. PU wt 20.3K.Online down CT 2.3 bbls/min free spin pressure 2,600 psi. Stall pressure 3,400 psi. RIH,start milling tel! cement at 10,762.5'200-300 psi motor work. At 10,765'WHP increase to 260 psi. Gas returns noticed at surface. ,(10,770'motor stalled 3x. Found top of composite BP. Stalled 10,772'. Pick up stall 10,769.59'. Plug coming up hole. RIH,slight motor work and stalled motor at 10,913.7'. Plug loose. Pushing it. WHP 560 psi. 500 psi motor work at 10,914',weight stack and motor work increases then breaks off from 10,914'to 10,933.1'.Start pushing 5K down from normal RIH wt. 5K RIH down to 0. No slight 100 psi motor work. Possibly pushing the rest of the composite bridge plug in hole spinning it.Stack weight at 10,934'. Pick up clean 28.3K. RIH,stack at 10.956',3K down. 400 psi motor work. Milling off. 10,972' gel sweep at nozzle. Clean RIH wt until found top of cement at 11.076', 200 psi motor work 1K down. Milled cement 11,112'. RIH, 11,152'stalled motor. Found top of cement and CIBP at 11,152'. Gel sweep at nozzle. Circulate gel sweep to surface. POOH to surface. WHP 860 psi. Holding 1:1. Keeping well bore full of fluid for tomorrow's cement bond log.Tagged up at surface. 1,086 psi SITP. Close upper master and swab valve. Break down tools. Mill worn down. Residual cement between carbides. Rig back injector head. Move crane to make room for Halliburton E-line. 768 bbls pumped for milling job. 03/10/2017-Friday PTW. Safety meeting with Halliburton E-line. MIRU HES E-line unit. WHP 1,030 psi. PT lubricator to 250/3,500 psi. Open well 23.5 turns and RIH with 1-7/16"cable head, 1.69" OD swivel, 1.69"OD through tubing telemetry cartridge,2.875" centralizer,3.13" OD radial bond tool. Total BHA length=25.12'. Log from tag depth of 11,168'to 10,000'. Repeat log t"'pass.Send cement bond log to town. POOH to surface. SITP 1,030 psi. RDMO HES E-line unit.Wait on Cruz crane operator,spot crane. Pick off BOPE night cap. Pick injector head. Stab on well. PT stack 250/4,500 psi. Master swab open 23.5 turns. RIH, initial WHP 1,030 psi. 2,700'cooling down N2. 4,&00'online with N2 at 1,500 scf/min. Start craking choke to take returns.CIH,good returns of fluid and gas to tank. Tagged PBTD at 11,170' CTMD.Circ pressure NL max was 3,400 psi at 1,500 scf/min. As well bore unloaded fluid. WHP dropped from 1,030 psi to 586 psi. Circ pressure /,ice/ dropping as WHP increasing. On bottom for 45 minutes.Well blowing mostly N2 and gas. 210 bbls returned. Start )'s' POOH.Shut in choke and build WHP to 2,500 psi. 210 bbls returned. 209,000 scf pumped. Crews off location. 03/13/2017-Monday PTW and JSA.Spot equipment and rig up Lubricator. PT lubricator to 250 psi low and 4,500 psi high.TP-3,690 psi. RIH w/GPT tool and tie into Halliburton RMTI log dated 21 Nov 2015 and tag at 11,167'. Found fluid level at 9,730'. POOH.TP 3,690 psi. RIH w/2-7/8"x 20' Razor HC, 6 spf,60 deg phase and tie into Halliburton RMTI log dated 21 Nov 2015. Run correlation log and send to town. Get ok to perforate from 10,767'to 10,787'.Spot and fired gun with 3,678.4 psi on tubing.Tubing pressure stayed basically the same and after 5 min it was 3,679.3 psi. POOH. Rig down lubricator and turn well over to field. t 410 Cannery Loop Field El[ • SCHEMATIC Well: CLU 05RD S API: 50-133-20474-01 Llilcorp Alaska,LLC PTD: 215-160 RKB=18' CASING DETAIL t 1 Size Type Wt/Grade/Conn ID Top Btm A 20" Conductor 129/N/A/N/A N/A Surf 142' 2(1 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' 2 53.5/L-80/BTC 8.535" Surf 1,212' 9-5/8" Intermediate 47/P-110/BTC 8.681" 1,212' 9,178' 04 4' �;w 7-5/8" Liner 29.7/L-80/HYD 511 6.875" 6,433' 6,910' tilt* " 29.7/L-80/SLIJ-II 6.875" 6,910' 10,448' 0 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' TUBING DETAIL 13-3/8" 41 3Oil 4-1/2" 12.6#/L-80/IBT-M 3.958" Surf 1,200' 4 12.6#/L-80/SuperMax 3.958" 1,200' 10,289' 8-1/2" a' window at it 4, 6,527 MD JEWELRY DETAIL a 5,354'TVD 9-5/8" 4 No. Depth ID OD Item - „ 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" 2 298' 3.812" 7.110" Baker TE-5 Safety Valve ' 3 1,210' 3.813" 6.500" 4-1/2"Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension s7 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly 14 .1 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer 8 11,170' 3.500" CIBP(TOC 11,170') ,` 9 11,430' 3.500" CIBP w/10'cement(TOC 11,420') _ 14 (\ N Pet 10 11,505' ✓ 3.500" CIBP w/10'cement(TOC 11,495') ' \ r 11 11,565' - 3.500" CIBP w/15'cement(TOC 11,550') a 12 11,700' - 3.500" CIBP w/10'cement(TOC 11,690') $/8' i 7 , , 5,6,7 13 11,723' - 3.500" CIBP 912 6TtP ti RA[VITA PERFORATION DETAIL 11,090' t1 VD Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Date Size Status D-2 5`ti, 91-2 10,767' 10,787' 9,081' 9,101' 6 03/13/17 2-7/8" Open 8 i ' �� D-2C 11,081' 11,106' 9,395' 9,420' 6 12/22/16 2-7/8" Squeezed D-3A D-3A 11,321' 11,346' 9,635' 9,660' 6 11/25/16 2-7/8" Isolated D-4A 11,460' 11,480' 9,774' 9,804' 6 10/29/16 2-7/8" Isolated 9 6 D-4A f D-4A 11,460' 11,490' 9,774' 9,804' 6 10/14/16 2-7/8" Isolated D-5 11,510' 11,530' 9,824' 9,844' 6 06/15/16 2-7/8" Isolated 10 - fir D-5A 11,572' 11,580' 9,886' 9,894' 6 01/22/16 2-7/8" Isolated D-5 11 S► ,r s's D-5A 11,586 11,598 9,900 9,912 6 05/26/16 2-7/8" Isolated D-,A D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6A D-6 11,726' 11,738' 10,039' 10,051' 6 01/08/16 2-7/8" Isolated RA My Jt 11,633' �� 12,13 • I D.6 Cl i RA My Jt I r 12,060' y RA My Jt 12,474' 4-1/2' Ikt PBTD=12,790'MD/11,103'TVD TD=12,940'MD/11,253'TVD Updated by DMA 03-28-17 • 21 51 60 Seth Nolan Hilcorp Alaska, L 5 GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 RECEIVED Tele: 907 777-8308 Meng]: laska..llit Fax: 907 777-8510 E-mail: snolan@hilcorp.com MAR 0 9 2017 DATE 03/08/2017 AOGCC DATA LOGGED /t3;zo1/ K. BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 5RD Perforation and Plug prints and data SCANNE° JUN 2 0 2017 Prints: TMD3D Waterflow Analysis CD: 1 CLU-05RD_WATERFLOW_29DEC16_DLIS.zip 2/27/2017 2:35 PM Compressed(zippe... 236 KB CLU-05RD_WATERFLOW_29DEC16_process... 1/1/2017 10:22 AM PDF Document 11,849 KB CLU-05RD WATERFLOW_29DEC16_process... 1/1/2017 10:20 AM TIF File 15,130 KB CLU-05RD_IATERFLOW_29DEC16 Report.... 1/1/2017 10:31 AM PDF Document 982 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received BMAL2474Lic/) : Date: e i 215160 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503Tele: 907 0 8 �r�rt• ,i, thk.ka.�.t.c RECEIVED Fax 907 777-8510 2 7 9 8 8 E-mail: snolan@hilcorp.com FEB 1 5 2017 2 7 9 8 9 DATE 01/16/2017 AOGCC DATA LOGGED 2-/k1/2017 To: Alaska Oil & Gas Conservation Commission M.K.BENDER Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 5RD SCANNED MAY 0 12Q'.17 Perforation and Plug prints and data Prints: Perforation Record 5" MD (10/29/2016) Plug Setting and Perforation Record 5" MD (10/14/2016) CD: 1 (10/29/2016) CLU-05RD_PERF_290CT16.pdf 11/16/2016 9:16 AM PDF Document 528 KB CLU-05RD PERF_290CT16_CORRELATION.las 1.1/16/2016 9:16 AM LAS File 101 KB CLU-05RD_PERF_290CT16_img.tif 11/16/2016 9:16 AM TIF File 1,463 KB CLU-05RD_PERF_290CT16_SHOOTING PAS... 1.1/16/2016 9:16 AM LAS File 40 KB CD: 2 (10/14/2016) CLU-05RD_PERF_140CT16_11460-11470.1as 12/7/2016 10:57 AM LAS File 82 KB CLU-05RD_PERF_140CT16_11470-11490.1as 12/7/2016 10:57 AM LAS File 70 KB CLU-05RD PERF_140CT16_CORRELATION.las 10/14/2016 1:01 PM LAS File 96 KB CLU-05RD PLUG8PERF_140CT16.pdf 10/15/2016 2:33 PM PDF Document 856 KB CLU-05RD PLUGWERF_140CT16 jrng.tif 10/15/2016 2:33 PM TIF File 2,647 KB CLU-05RD PLUG_12.0CT16_CORRELATION.las 10/12/2016 5:18 AM LAS File 106 KB CLU-05RD_PLUG_120CT16_SETTING PASS.las 10/12/2016 5:52 AM LAS File 107 KB Thumbs.db 1/16/2017 1:00 PM Data Base File 10 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: 21 51 60 ©© Seth Nolan Hilcorp Alaska, LLC 1'IEC ��® Anchorage, 1nt Drive, Suite 100 Acorage, AK99503 Tele: 907 777-8308 1111,1191 Ua+key.I.i.i Fax: 907 777-8510 2 7 9 8 6 FEB 15 2017 E-mail: snolan@hilcorp.com 27987 AOGCC DATE 02/14/2017 DATA LOGGED /2011 To: Alaska Oil & Gas Conservation Commission M. /`BENDER Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 5RD SCANNED MAY 0 120.17 Perforation and Plug prints and data Prints: Plug and Perforation Record Water Flow Analysis CD: 1 CLU-05RD_PLUG-PERF_25N0V16_LAS.zip 1/26/2017 10:50 AM Compressed(zippe... 59 KB r CLU-05RDPLUG-PERF_Z5NOV 16.pdf 1/26/2017 10:41 AM PDF Document 648 KB CLU-05RD_PLUG-PERF_25N0V16_img.tif 1/26/2017 10:41 AM TIF File 1,984 KB CD: 2 j, CLU-05RD WATERFLOW_O8DEC 16_FIELD L... 1/26/2017 11:19 AM Compressed(zippe... 2.,671 KB CLU-05RD WATERFLOW_O8DEC 16_PROCES... 1/26/2017 11:19 AM Compressed(zippe... 886 KB ▪ CLU-05RD_WATERFLOW_08DEC16.pdf 12/9/2016 8:24 AM PDF Document 3,580 KB + ,CLU-05RD_WATERFLOW_O8DEC 16_img.tif 1219/2016 8:24 AM TIF File 17,710 KB ▪ CLU-05RD_WATERFLOW_O8DEC 16_Process... 12/9/2016 11:37 AM PDF Document 3,477 KB CLU-05RD_WATERFLOW_O8DEC 16 Procsse... 12/14/2016 8:12 AM TIF File 12,760 KB CLU-05RD_WATERFLOW_O8DEC 16 Report.... 12/9/2016 3:08 PM PDF Document 927 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received : ✓� Date: V OF Tits S S I//7; s. THE STATE Alaska Oil and Gas • ALAsKAL Conservation Commission = _-� 333 West Seventh Avenue GOVERNOR BILL WALKER , - Anchorage, Alaska 99501-3572 Oj4A^'S� Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager ��E® 20r!". Hilcorp Alaska, LLC SCA 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Cannery Loop Field, Tyonek D Gas Pool, CLU 5RD Permit to Drill Number: 215-160 Sundry Number: 317-048 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Stit7 P Cathy P. Foerster Chair DATED this { day of February,2017. RBDMS L-' FEB - 3 2017 • • RECEIVED STATE OF ALASKA JAN 2 6 2117 ALASKA OIL AND GAS CONSERVATION COMMISSION 0-3 2(/ (/2 `1 APPLICATION FOR SUNDRY APPROVALS ADCC " 20 AAC 25.280 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 LI Re-enter Susp Well ❑ Alter Casing ❑ Other:Cement Squeeze,N2 Jett] 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory ❑ Development 2• 215-160 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic IIIService El 6.API Number: Anchorage,Alaska 99503 50-133-20474-01 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231,Rule 3 • Cannery Loop Unit(CLU)05RD Will planned perforations require a spacing exception? Yes Ell No No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): Fe-444,V ABL g3 ADL 324602/6I._zi,,,/7 Cannery Loop/Tyonek D Gas Pool • 11. / PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,940' . 11,253' • 12,832' 11,146' 3,110 psig N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090psi 1,540psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930psi 6,620psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440psi 5,300psi Liner 4,048' 7-5/8" 10,448' 8,762' 6,890psi 4,790psi Liner 2,675' 4-1/2" 12,915' 11,229' 8,430psi 7,500psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" L-80 10,289' Packers and SSSV Type: Baker ZXP+ZXPN Pkrs; Packers and SSSV MD(ft)and TVD(ft): 6,433'MD/5,263'ND;10,240'MD/8,555'ND; Baker TE-5 SSSV TR 298'MD/TVD 12.Attachments: Proposal Summary U Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑Q • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: February 8,2017 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS 0 ' WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasse@hilcorp.com Printed Name Chad Helgeson Title Operations Manager " a Signature &,. ' // - Phone 907-777-8405 Date //Z,5/i COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 1 - O Li Cs Plug Integrity ❑ BOP est I Mechanical Integrity Test ❑ Location Clearance ❑ 44SC-- Z.j, la, Other: *95-6° I'S:- 6°C) . ;4- C Cr) Post Initial Injection MIT Req'd? Yes ❑ No Spacing Exception Required? Yes ❑ No Subsequent Form Required: /0 f ()Li _ 3 I� ,..20(_,,,,ittA., THEROVED BY Approved by: ^ O M�ONER THE COMMISSION Date: Z_/ � 17 ' _ � �� Submit Form and Form 10-403 Revised 11/2015 AA e i a 000www i I r 12 months from the date of approval. ttachment in Duplicate • • Well Prognosis Mom)Alaska,LL Well: CLU-05RD Date:1/23/2017 Well Name: CLU-05RD API Number: 50-133-20474-01 Current Status: Shut In Leg: N/A Estimated Start Date: February 8th, 2017 Rig: Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Taylor Nasse (907)777-8354(0) (907)903-0341(C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907)229-4824(C) AFE Number: Maximum Expected BHP: -4,050 psi @ 9,420'TVD (Original 0.43 psi/ft gradient) Max. Predicted Surface Pressure: -3,110 psi (0.10 psi/ft gas gradient) Brief Well Summary CLU-05RD is a sidetracked well targeting gas sands in the Beluga and Tyonek formations. It was brought on production in December 2015 in the D6 sand and was producing for about a month before watering up.The open intervals were plugged back and the D5A was perforated in January 2016, which watered out in May 2016.The - interval was plugged back and the D-5 and D-4A were then tested and flowed for 30 days in June. The D-3A was tested in November 2016 and found unproductive and was plugged back, as well. The D-2C was tested in December 2016 and initially made gas at low rates but watered out and died. Prior to moving up to the 91-2 interval,a water flow survey was performed to detect any possibly water movement behind casing in December 2016,which indicated there was some water migration when the well tubing pressure is dropped. AThe purpose of this work/sundry is to attempt to squeeze cement behind the casing to isolate the D-2C and 91- s'"2 sands and then perforate and test these two intervals. Notes Regarding Wellbore Condition • After successful cement squeeze, perforations will be added per Sundry 316-577. ' Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter(if nitrogen used during this job) • • Consider tank placement based on wind direction and current weather forecast(if venting methane and nitrogen during this job) • Ensure all crews are aware of stop job authority Coiled Tubing Procedure: 1. Submit 24 hr. witness notification to AOGCC via web base notification. 2. MIRU Coiled Tubing, PT BOPE to 250/4,500 psi. 3. Make up MHA. Stab on well and PT lubricator to 250/4,500 psi. 4. Rig up cement equipment. 5. RIH and tag top of CIBP at±11,160'.Circulate 3%KCI. Pick up to 11,106', close annular valve, and begin G e- injectivity test to determine amount of cement required. 5 f(i'' 6. Batch mix cement and begin pumping spacer and cement.As cement exits the nozzle, begin pulling up coiled tubing. Once all cement has been placed, pick up an additional 50'. • I Well Prognosis Well: CLU-05RD HiIcon)Alaska,LLQ Date:1/23/2017 7. Close CTX Tubing annulus and pressure up in 500 psig increments until squeeze/lock up pressure is achieved. Hold for 30 minutes. 8. RIH to 11,100'and circulate contaminated cement to surface. POOH. 9. Rig back Coiled Tubing. 10. MIRU E-line, PT lubricator to 4,500 psi Hi 250 Low. 11. RIH and set CIBP or com, posits plug at±10,790. POOH. 12. RIH and perforate from ±10,767'—10,787'with 2" 6 SPF 60 deg phased HC guns.Send the correlation i pass to the Operations Engineer, Reservoir Engineer,and Geologist for confirmation. rr� 13. RD e-line. 14. RU coiled tubing. 15. RIH and tag top of plug at±10,790. Pick up to 10,787'and begin injectivity test to determine amount of cement required. 16. Batch mix cement and begin pumping spacer and cement.As cement exits the nozzle, begin pulling up coiled tubing. Once all cement has been placed, pick up an additional 50'. 17. Close CTX Tubing annulus and pressure up in 500 psig increments until squeeze/lock up pressure is achieved. Hold for 30 minutes. 18. RIH to 10,790'and circulate contaminated cement to surface. POOH. 19. Wait 24 hrs.for cement to set. 20. MU mill and motor BHA. 21. RIH and mill cement and CIBP/composite plug at 10,790'.Continue milling/cleanout to 11,110'. 22. RU N2 pumping unit. 23. Drop ball and come online with N2 and jet well dry while maintaining a constant BHP.Once well is dry, verify desired surface pressure to leave on well with Operations Engineer. POOH. Ri down CT unit. 25. Perforate well per Sundry 316-577. .3 Attachments: 1. Current and Proposed Wellbore Schematic 2. Current Wellhead Diagram 3. CT BOPE Schematic 4. Flow diagram(forward and reverse jetting) • Cannery Loop Field SCHEMATIC Well: CLU05RD API: 50-133-20474-01 Hilcorp Alaska,LLC PTD: 215-160 CASING DETAIL RKB=18' Size Type Wt/Grade/Conn ID Top Btm 1 " 20" Conductor 129/N/A/N/A N/A Surf 142' 20" 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' k 2 53.5/L-80/BTC 8.535" Surf 1,212' 9-5/8" Intermediate 47/P-110/BTC 8.681" 1,212' 9,178' t� 29.7/L-80/HYD 511 6.875" 6,433' 6,910' xP Y 7-5/8" Liner 29 7/L-80/SLII II 6.875" 6,910' 10,448' + :" 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' �+ TUBING DETAIL 13-3/8" rr 3 4-1/2" 12.6#/L-80/IBT-M 3.958" Surf 1,200' 12.6#/L-80/SuperMax 3.958" 1,200' 10,289' 4 8-1/2' window at JEWELRY DETAIL 6,527'MD r 5,354 ND 9-5/g ," 4 No. Depth ID OD Item Irr 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" 2 298' 3.812" 7.110" Baker TE-5 Safety Valve 3 1,210 3.813" 6.500" 4-1/2"Chemical Injection Mandrel " 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer 14 ', x 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer # 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension it 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly A 1i 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer 8 9 11,170 3.500" CIBP w/10'cement(TOC±11,160') 11,430 3.500" CIBP w/10'cement(TOC±11,420') 10 11,505' 3.500" CIBP w/10'cement(TOC=11,495') 11 11,565' 3.500" CIBP w/15'cement(TOC=11,550') 1 12 11,700' - 3.500" CIBP w/10'cement(TOC=11,690') 7 5/8 w.' 5,6,7 13 11,723' - 3.500" CIBP 1 �� RAMvJt t , • 5 tali PERFORATION DETAIL 11,090' , Sands Top(MD) Btm(MD) Top(TVD) Btm(ND) SPF Date Size Status D-2C D-2C 11,081 11,106 9,395 9,420 6 12/22/16 2-7/8" Active D-3A 11,321 11,346 9,635 9,660 6 11/25/16 2-7/8" Isolated 8 D-4A 11,460' 11,490' 9,774' 9,804' 6 8/20/2016 2-7/8" Isolated s D 3A D-5 11,510' 11,530' 9,824' 9,844' 6 6/15/2016 2-7/8" Isolated d 9 ice, D-5A 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Isolated D-4A D-5A 11,586 11,598 9,900 9,912 6 5/26/16 2-7/8" Isolated 10 1 0-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated 65 D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" Isolated r D-5A " -D-6A RA Ma-Jt 11,633 12,13 s e RAMrJt I 12,060' RA Mg Jt j 12,474' v. 4-1/2" li• ,r y PBTD=12,790'MD/11,103'ND TD=12,940'MD/11,253'ND Updated byTWN 1-9-17 . Cannery Loop Field . H PROPOSED • Well: CLU 05RD • Hilcorp Alaska,LLC SCHEMATIC API:D50-136-0474-01 CASING DETAIL RKB=18' k Size Type Wt/Grade/Conn ID Top Btm kpp 1 it 20" Conductor 129/N/A/N/A N/A Surf 142' 20" , 13-3/8" Surface 61/K-55/BTC 12.515" Surf 2,970' 2 ), 53.5/L-80/BTC 8.535" Surf 1,212' 9-5/8" Intermediate 47/P-110/BTC 8.681" 1,212' 9,178' • 29.7/L-80/HYD 511 6.875" 6,433' 6,910' 7-5/8" Liner vit " r ; 29.7/L-80/SLIJ-II 6.875" 6,910' 10,448' 4-1/2" Liner 12.6/L-80/DWC/C 3.958" 10,240' 12,915' TUBING DETAIL b 3 12.6#/L-80/IBT-M 3.958" Surf 1,200' 13 3/8 4-1/2" 12.6#/L-80/SuperMax 3.958" 1,200' 10,289' 4. R• 8-1/2" 1' ' window at 4 • 4 6,527 MD JEWELRY DETAIL 5,354'TVD 9-5/8" .• 4 No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger,4-1/2" 2 298' 3.812" 7.110" Baker TE-5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2"Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8"ZXP Liner Top Packer 5 10,240'-10,272' 4.820" 6.560" 4-1/2"ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'-10,289' 3.850" 4.500" 4-1/2"Seal Assembly t 44'of Seal Assembly and 5'of first tubing joint are inside SBE and Liner Top Packer 8 11,170' - 3.500" CIBP w/10'cement(TOC±11,160') 9 11,430' - 3.500" CIBP w/10'cement(TOC±11,420') 10 11,505' - 3.500" CIBP w/10'cement(TOC=11,495') f }, ',. 11 11,565' - 3.500" CIBP w/15'cement(TOC=11,550') 12 11,700' - 3.500" CIBP w/10'cement(TOC=11,690') 7 5/8 M" 5,6,7 13 11,723' - 3.500" CIBP i , r91-2 PERFORATION DETAIL H1Mr Jt � 1,090i ' Sands Top(MD) Btm(MD) Top(ND) Btm(ND) SPF Date Size Status ID-2C ,.7 91-2 ±10,767 ±10,787 • ±9,081 ±9,101 6 TBD Squeezed D-2C 11,081 11,106 • 9,395 9,420 6 12/22/16 2-7/8" Squeezed 8 - '" D-3A 11,321 11,346 • 9,635 9,660 6 11/25/16 2-7/8" Isolated 0-3A D-4A 11,460' 11,490' • 9,774' 9,804' 6 8/20/2016 2-7/8" Isolated 9 .- , D-5 11,510' 11,530' • 9,824' 9,844' 6 6/15/2016 2-7/8" Isolated 11 D-4A D-5A 11,572' 11,580' • 9,886' 9,894' 6 1/22/16 2-7/8" Isolated 10 D-5A 11,586 11,598 ' 9,900 9,912 6 5/26/16 2-7/8" Isolated - 11 D-5 D-6 11,712' 11,722' • 10,026' 10,036' 6 12/07/15 2-7/8" Isolated , 00 D-5A D-6 11,726' 11,738' • 10,039' 10,051' 6 1/08/16 2-7/8" Isolated Mb D-6A RAMrJt 11,633 e --p 12,13 NINC— i i Y f R4 My Jt 12,060 RA MT Jt 0 12,474' 4-1/2" -et ell PBTD=12,790'MD/11,103'ND TD=12,940'MD/11,253'ND Updated by TWN 1-9-17 • Cannery Loop Unit . IICLU#05 Proposed 1/24/2017 niiro.p ‘11.1.4.1.14 Tubing hanger,CIW-DCB- FBB-CCL,11 X 4 1/2 EUE lift Cannery Loop and susp,w/4"type H BPV CLU/105 Tree cap,Otis,4 1/16 10M FE +, '/= + profile,6 Y.EN,2-''/:npt CCL 20 x 13 3/8 x 9 5/8 x 4 X 6/�Otis Quick Union ports IIII L\ <ck' /1111;014;its, Q� V Valve,Swab,CIW-FC, - <(' 4 1/16 10M FE,HWO, " � �e��'' . EE trim •' `Nrotit 42, N4‘ �.,ir �'' Valve,SSV,3 1/16 1OM FE, 'T' "'� ) ti w/18"Halliburton oper-air operated Cross,stdd,4 1/16 10M X 1� c�"\ O . I 31/1610M ./ '--,J �s L = �1 Valve,Upper Master, ki% , CIW-FC,4 1/16 10M FE, + 74: HWO,EE trim �Uj.II ii imi. Valve,Master, 'Ir CIW-FC,4 1/16 10M FE, y''C HWO,DD trim ,7., , /wim Spool,4 1/16 10M VG-42 Adapter,CIW-EN-CCL, 11 SM illiWIN grayloc FE x4 1/16 10M API ,.■,.,—+.*** Stdd x 4 1/16 1GM VG-42 FE top ..,M:2'.., grayloc top,prepped for 6'4 .•S:,- -.4° EN and 2-%npt CCL ports,EE material Tubing head,CIW-DCB-S, @, +_ lL110 _ Ai 13 5/8 SM X 11 5M,w/2- _�.. "I" i_._ 22 1/16 SM SSO,X-bottom prep,N type pins "�" • 0nu Valve,WKM-M,2 1/16 5M FE,HWO,AA II. `n - U Qty 2 , k Hillv tse.,,ic-ii 1 ginow_1._ ,.i 16111.4: Casing head, McEvoy, a-�' 13 5/8 SM X 13 3/8"SOW ar .. Valve,McEvoy-C, bottom,w/2-21/165MIII = 1�1 21/16 SM FE,HWO,AA EFO o1I - - ., lif r :i. '`I� ,_:. 116. • Cannery Loop Unit COIL BOPE CLU-05RD 1/24/2017 est Alaoka.EU: CLU-05RD 20X133/8X95/8X4>5 Coil Tubing BOP i Lubricator to injection head o pl l 1.75"Tandem Stripper I I f 111) .I. Blind/Sheai=a 1/16 10 !:BhmndfShe ar ar1111111 - —i // I/hi.1.I.I Blind/Shear — - Blind/Shear : _um p. �- 0emum- __ '9 _=Il (_: _ Slip Slip .II I Mud Cross iii •�1I1 uliffi 11.Mi Pipe ■I.I•: 4 1/16 10M X 4 1/16 10M Outlet w/ 2 1/16COM full • � opening FMC valves PI CO 11 011 I i li Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M "` I� 2 1/16 10M 2 1/16 10M Valve,Swab,CIW-FC, 0 �0\1 4 1/16 10M FE, HWO, OH d• `)' Valve,Wing,CIW-FC, EE trim3 1/16 10M FE, HWO,EE trim 1 (n> ' Cross,stdd,4 1/16 10M X I 'Ic � L. I 3 1/16 10M • ■ ;;;,- Valve,SSV,3 1/16 10M FE, illin w/18" Halliburton oper-air Valve, Upper Master, 4), ' operated CIW-FC,4 1/16 10M FE, 0 HWO,EE trim Valve, Master, 0 CIW-FC,4 1/16 10M FE, ,, HWO,DD trim so Spool,4 1/16 10M VG-42 ,�„�,�,i,,,, grayloc FE x4 1/16 10M API MEI 111110,1111 I Grade Level FE top • w < z81 D w x U i i ' J l c Q {J ~ � l Q . g ] U (D(1 ] 0_ zma e o Oz Y 'i U) 0w C C D Aill ►•4 N 7 z -H, EEES N N !gg CD V 47, Iii N lin i N i i z o �i ►.• L_ 0 47, C 0 O i- t a }: 1I i� j — '—''III' 0 '11.11■11 Iall I 14it a 1111 1- gi 3 :Z c c n 0 1- • � g n F � k � 5 • IL� c o a..c r O n • v v n U N OZ 0 0 6 N i • • z 83 r ! c v .1 CS U .Q ?L 1 1] : CDN 1 ,3 I— CD EL o 1 .] 0 oco I ,....9 z Y o w K ' O gin I , �44 (n liii L a 6, fY IIICS C II ►•4 N z (ll (.1") o c a) VV 3 =Z o Q) a I o r II 1111 1I11 III 0 — x 1111111111 0 111111•P;..liarIII IIIIIll I� o ki ; 3 C _ O T r n 0 r I N 1 • O i V • A 4 411,111111 i O i I I 0 .,_ e z e a a h I) ti ti0 U N 0 Z 0 0 E s e a r DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2151600 Well Name/No. CANNERY LOOP UNIT 05RD Operator HILCORP ALASKA LLC API No. 50-133-20474-01-00 MD 12940 TVD 11253 Completion Date 1/22/2016 Completion Status 1 -GAS Current Status 1 -GAS UIC No REQUIRED INFORMATION Mud Log yes'^ el-`$ Samples 'WVos Directional Survey YesV/ DATA INFORMATION 110 Types Electric or Other Logs Run: ROP-DGR-EWR-ALD-CTN, yyupl,(,slf_' (data taken from Logs Portion of Master Well Data Maint) Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data ED C 26599 Digital Data Log C 26599 Log Header Scans Log C 26600 Log Header Scans ED C 26600 Digital Data ED C 26600 Digital Data AOGCC Log Log Run Scale Media No Page I of 7 Interval OH / Start Stop CH Received Comments 6516 12940 12/23/2015 Electronic Data Set, Filename: CLU -05 RD TC MD_FINAL.las 12/23/2015 Electronic File: CLU 05RD TC MD.cgm, 12/23/2015 Electronic File: CLU 05RD TC TVD.cgm 12/23/2015 Electronic File: CLU-05RD - Definitive - Survey_final.pdf 12/23/2015 Electronic File: CLU-05RD final.txt 12/23/2015 Electronic File: CLU-05RD_final_parent.txt 12/23/2015 Electronic File: CLU -05 RD TC MD FINAL.dlis ' 12/23/2015 Electronic File: CLU -05 RD TC MD FINAL.ver ' 12/23/2015 Electronic File: CLU 05RD TC MD.emf 12/23/2015 Electronic File: CLU 05RD TC TVD.emf ' 12/23/2015 Electronic File: CLU 05RD TC MD.pdf ' 12/23/2015 Electronic File: CLU 05RD TC TVD.pdf ' 12/23/2015 Electronic File: CLU 05RD TC MD.tif 12/23/2015 Electronic File: CLU 05RD TC TVD.tif 0 0 2151600 CANNERY LOOP UNIT 05RD LOG HEADERS 0 0 2151600 CANNERY LOOP UNIT 05RD LOG HEADERS 6410 13000 12/23/2015 Electronic Data Set, Filename: CLU05-RD.las 12/23/2015 Electronic File: AM Report CLU 05RD 10-13— 15.pdf Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2151600 Well Name/No. CANNERY LOOP UNIT 05RD Operator HILCORP ALASKA LLC MD 12940 TVD 11253 ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data AOGCC Completion Date 1/22/2016 API No. 50-133-20474-01-00 Completion Status 1 -GAS Current Status 1 -GAS UIC No 12/23/2015 Electronic File: AM Report CLU 05RD 10-14- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-15- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-16- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-17- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-18- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-19- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-20- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-21- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-22- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-23- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-24- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-25- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-26- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-27- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-28- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-29- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-30- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 10-31- 15. pdf Page 2 of 7 Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2151600 Well Name/No. CANNERY LOOP UNIT 05RD Operator HILCORP ALASKA LLC MD 12940 TVD 11253 ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data AOGCC Electronic File: clu05rd.hd; 12/23/2015 Completion Date 1/22/2016 Completion Status 1 -GAS Page 3 of 7 API No. 50-133-20474-01-00 Current Status 1 -GAS UIC No 12/23/2015 Electronic File: AM Report CLU 05RD 11-1- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-10- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-11- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-12- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-13- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-14- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-2- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-3- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-4- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-5- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-6- 15. pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-7- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-8- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD 11-9- 15.pdf 12/23/2015 Electronic File: AM Report CLU 05RD set.pdf 12/23/2015 Electronic File: CLU05RD.dbf 12/23/2015 Electronic File: clu05rd.hd; 12/23/2015 Electronic File: CLU05RD.mdx. 12/23/2015 Electronic File: clu05rdr.dbf ' 12/23/2015 Electronic File: clu05rdr.mdx 12/23/2015 Electronic File: CLU05RD SCL.DBF Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2151600 Well Name/No. CANNERY LOOP UNIT 05RD Operator HILCORP ALASKA LLC MD 12940 TVD 11253 ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data ED C 26600 Digital Data AOGCC API No. 50-133-20474-01-00 Completion Date 1/22/2016 Completion Status 1 -GAS Current Status 1 -GAS UIC No 12/23/2015 Electronic File: CLU05RD SCL.MDX ` 12/23/2015 Electronic File: CLU05RD tvd.dbf 12/23/2015 Electronic File: CLU05RD tvd.mdx ' 12/23/2015 Electronic File: CLU05RD Final Well Report.docx Q T 12/23/2015 Electronic File: CLU05RD Final Well Report.pdf - 12/23/2015 Electronic File: CLU05RD - 5in Formation Log- MD.pdf 12/23/2015 Electronic File: CLU05RD - 5in Formation Log ' TVD.pdf 12/23/2015 Electronic File: CLU05RD - Drilling Dynamics - Log MD.pdf 12/23/2015 Electronic File: CLU05RD - Drilling Dynamics ' Log TVD.pdf 12/23/2015 Electronic File: CLU05RD - Formation Log P MD.pdf 12/23/2015 Electronic File: CLU05RD - Formation Log ' TVD.pdf 12/23/2015 Electronic File: CLU05RD - Gas Ratio Log MD.pdf 12/23/2015 Electronic File: CLU05RD - Gas Ratio Log TVD.pdf 12/23/2015 Electronic File: CLU05RD - LWD Combo Log. MD.pdf 12/23/2015 Electronic File: CLU05RD - LWD Combo Log ' TVD.pdf 12/23/2015 Electronic File: CLU05RD - 5in Formation Log , MD.tif 12/23/2015 Electronic File: CLU05RD - 5in Formation Log TVD.tif 12/23/2015 Electronic File: CLU05RD - Drilling Dynamics' Log MD.tif 12/23/2015 Electronic File: CLU05RD - Drilling Dynamics ' Log TVD.tif 12/23/2015 Electronic File: CLU05RD - Formation Log MD.tif Page 4 of 7 Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2151600 Well Name/No. CANNERY LOOP UNIT 05RD Operator HILCORP ALASKA LLC MD 12940 TVD 11253 Completion Date 1/22/2016 Completion Status 1 -GAS ED C 26600 Digital Data Electronic File: CLU05RD - Gas Ratio Log TVD.tif 12/23/2015 ED C 26600 Digital Data 12/23/2015 Electronic File: CLU05RD - LWD Combo Log ED C 26600 Digital Data Electronic File: CLU 05RD Show #1 9520' - ED C 26600 Digital Data 10795'.pdf ED C 26600 Digital Data 11160'.pdf 12/23/2015 ED C 26600 Digital Data 12/23/2015 Electronic File: CLU 05RD Show #5 11572' - ED C 26600 Digital Data Electronic File: CLU 05RD Show #6 11702' - ' ED C 26600 Digital Data 05RD_CAST_02DEC15_MAIN.las ED C 26600 Digital Data 05RD—CAST 02DEC15 REPEAT.las 1/22/2016 ED C 26600 Digital Data 1/22/2016 Electronic Data Set, Filename: CLU- - ED C 26600 Digital Data Electronic File: CLU-05RD_CAST_02DEC15.pdf 1/22/2016 ED C 26699 Digital Data 10200 12804 ED C 26699 Digital Data 10300 10500 ED C 26699 Digital Data 12803 6294 ED C 26699 Digital Data 12803 6294 ED C 26699 Digital Data ED C 26699 Digital Data ED C 26699 Digital Data ED C 26699 Digital Data AOGCC Page 5 of 7 API No. 50-133-20474-01-00 Current Status 1 -GAS UIC No 12/23/2015 Electronic File: CLU05RD - Formation Log ' TVD.tif 12/23/2015 Electronic File: CLU05RD - Gas Ratio Log MD.tif 12/23/2015 Electronic File: CLU05RD - Gas Ratio Log TVD.tif 12/23/2015 Electronic File: CLU05RD - LWD Combo Log MD.tif 12/23/2015 Electronic File: CLU05RD - LWD Combo Log TVD.tif 12/23/2015 Electronic File: CLU 05RD Show #1 9520' - 9620'.pdf 12/23/2015 Electronic File: CLU 05RD Show #2 10748' -- 10795'.pdf 12/23/2015 Electronic File: CLU 05RD Show #3 11111' - • 11160'.pdf 12/23/2015 Electronic File: CLU 05RD Show #4 11320' - 11369'.pdf 12/23/2015 Electronic File: CLU 05RD Show #5 11572' - 11605'. pdf 12/23/2015 Electronic File: CLU 05RD Show #6 11702' - ' 11743'.pdf 1/22/2016 Electronic Data Set, Filename: CLU- 05RD_CAST_02DEC15_MAIN.las 1/22/2016 Electronic Data Set, Filename: CLU- 05RD—CAST 02DEC15 REPEAT.las 1/22/2016 Electronic Data Set, Filename: CLU- 05RD_CBL_21 NOV15.las 1/22/2016 Electronic Data Set, Filename: CLU- - 05RD_RMT_21 NOV15.las Q1/22/2016 Electronic File: CLU-05RD_CAST_02DEC15.pdf 1/22/2016 Electronic File: CLU- 05RD_CAST_02DEC 15_img.tiff 1/22/2016 Electronic File: CLU- 05RD—CBL-21 NOV15_img.tiff 1/22/2016 Electronic File: CLU-05RD—RMT-21 NOV15.pdf Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2151600 Well Name/No. CANNERY LOOP UNIT 05RD Operator HILCORP ALASKA LLC MD 12940 ED C ED C Log C Log C ED C ED C ED C ED C ED C ED C ED C TVD 11253 Completion Date 1/22/2016 Completion Status 1 -GAS 26699 Digital Data 26699 Digital Data 26699 Log Header Scans 0 0 27613 Log Header Scans 0 0 27613 Digital Data 27613 Digital Data 27613 Digital Data 27614 Digital Data 11528 10995 27614 Digital Data 27614 Digital Data 27614 Digital Data ED C 27614 Digital Data ED C 27614 Digital Data ED C 27614 Digital Data ED C 27614 Digital Data Log C 27614 Log Header Scans Well Cores/Samples Information: Name Interval Start Stop 11524 11312 11614 11182 11611 11470 0 0 Sent Receive API No. 50-133-20474-01-00 Current Status 1 -GAS UIC No Received 1/22/2016 Electronic File: CLU- 05RD_RMT-21NOV15—img.tiff P 1/22/2016 Electronic File: CLU-05RD— CBL —21NOV15.pdf ' 2151600 CANNERY LOOP UNIT 05RD LOG, HEADERS 2151600 CANNERY LOOP UNIT 05RD LOG HEADERS 10/3/2016 Electronic File: CLU-05RD—PERF-26MAY16.pdf 10/3/2016 Electronic File: CLU- 05RD—PERF-26MAY16—LAS.zip ` 10/3/2016 Electronic File: CLU- 05RD—PERF-26MAY16—img.tif 10/3/2016 Electronic Data Set, Filename: CLU 05RD PERF 15JUN16 CORRELATION.la — — — — s 10/3/2016 Electronic Data Set, Filename: CLU_ 05RD_PERF_15JUN 16_SHOOTING_PAS S.las 10/3/2016 Electronic Data Set, Filename: CLU_05RD_PLUG 13JUN16 CORRELATION.la s' 10/3/2016 Electronic Data Set, Filename: C LU_05RD_PLUG_13J U N 16_S ETTI NG_PASS.I as ' ,P 10/3/2016 Electronic File: CLU-05RD_PERF-15JUN16.pdf 10/3/2016 Electronic File: CLU-05RD— PERF —15JUN16—img.tif ' 10/3/2016 Electronic File: CLU-05RD—PLUG 10/3/2016 Electronic File: CLU-05RD—PLUG-13JUN 16—img.tif 2151600 CANNERY LOOP UNIT 05RD LOG HEADERS Sample Set Number Comments AOGCC Page 6 of 7 Thursday, December 15, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2016 Permit to Drill 2151600 Well Name/No. CANNERY LOOP UNIT 05RD Operator HILCORP ALASKA LLC API No. 50-133-20474-01-00 MD 12940 TVD 11253 Completion Date 1/22/2016 Completion Status 1 -GAS Current Status 1 -GAS UIC No Cuttings 6540 12940 12/9/2015 1566 INFORMATION RECEIVED Completion Report Directional / Inclination Data D Mud Logs, Image Files, Digital DataNA Core Chips Y / fD Production Test Information NA Mechanical Integrity Test Information Y Composite Logs, Image, Data Files �®Y Core Photographs Y IN Geologic Markers/Tops) Daily Operations Summary0 Cuttings Samples 1 Y { NA Laboratory Analyses Y / A COMPLIANCE HISTORY Completion Date: 1/22/2016 Release Date: 9/16/2015 Description Date Comments Comments: Compliance Reviewed By: Date: -A 2- ( ' ✓ AOGCC Page 7 of 7 Thursday, December 15, 2016 CW- 5PT'N � 151C W Regg, James B (DOA) From: Rance Pederson - (C) <rpederson@hilcorp.com> Sent: Monday, November 02, 2015 9:42 PM �,Ik I3I (7 To: Regg, James B (DOA) 1\ Subject: Notification of BOP Closure Attachments: Notification for use of Blowout Equipment to control flow from a Well 11-2-15.docx Jim, Please see the attached notification pertaining to a closure we made today. We anticipate reaching TD and POOH around the 5th or 6th, at which time these components will be tested, prior to tripping back in hole. Our bi-weekly BOP test is due on the 8th, so we will most likely perform a full BOP test our next trip out. f Rance Pederson Drilling Foreman Cannery Loop 907-776-6776 Notification for use of Blowout Equipment to control flow from a Well Date: 11-2-15 Shut In Time: 10:30 am Location: Cannery Loop Pad, Cannery Road, CLU-05RD PTD#: 215-160 Rig: Saxon Rig 169 Drilling Foreman: Rance Pederson, Hilcorp Alaska BOP used: 11" 5M - Annular. Reason: Driller detected flow. Summary: We had drilled to a depth of 10,784. The Driller made a connection, drilled to a depth of 10,795' and detected an increase in return flow while working drill string to orient for slide drilling. We had just drilled through the 91-2 Sand at 10,781'. Driller picked up off bottom to position the tool joint above the rotary table, then shut down the pump and checked for flow. The Well was flowing, so he shut in the Well with the Annular. SIDPP — 0 psi. SICP — 450 psi. The Gas influx was circulated out while holding 760 psi backpressure with the Choke. The MW was increased from 10.2+ to 11.0 ppg. A second choke shut in and monitor was performed, with a gain of 35 psi on casing, 0 psi on drill pipe. Surface volume was increased to 11.2 ppg. We bled off the 35 psi through choke, opened the annular, and performed a second circulation. Flow check (static) confirmed 11.2 ppg to be sufficient MW. We then pulled 347' back into the 7 5/8" casing shoe and performed an FIT of 13 ppg EMW (previous FIT done at 12 ppg EMW). We then resumed drilling Production Hole from 10,795'. Last BOP test date: 10-25-15 The Annular, Choke HCR and choke valves will be tested as per PTD guidelines, during the next trip out of the hole to surface, and completed prior to re-entering Well Bore. We will more than likely look at performing our full bi-weekly BOP test early (due on 11-8-15), on our next trip out of hole. Rance Pederson Drilling Foreman Hilcorp Alaska rpederson@hilcorp.com 907-776-6776 THE STATE GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: Kenai Cannery Loop Field, Tyonek D Gas Pool, CLU 5RD Permit to Drill Number: 215-160 Sundry Number: 316-577 Dear Mr. Helgeson: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, -�p Daniel T. Seamount, Jr. Commissioner DATED this �� f November, 2016. RBDMS 1, J 1 6 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION NOV 0 7 2b APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280``` 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: ❑ 2. Operator Name: Hilcorp Alaska, LLC 4. Current Well Class: 5. Permit to Drill Number: Exploratory ❑ Development 0. Stratigraphic ❑ Service ❑ 215-160 " 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-20474-01 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231, Rule 3 Will planned perforations require a spacing exception? Yes El No No E Cannery Loop Unit (CLU) 05RD ° 9. Propert Designation (Lease Number): 10. Field/Pool(s): Ap�_Ll665b`9; ADL 324602 Cannery Loop / Tyonek D Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,940' " 11,253' 12,832' 11,146' 4,804 psig N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090psi 1,540psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930psi 6,620psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440psi 5,300psi Liner 4,048' 7-5/8" 10,448 8,762' 6,890psi 4,790psi Liner 2,675' 4-1/2" 12,915' 11,229' 81430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: T ubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" L-80 10,289' Packers and SSSV Type: Baker ZXP + ZXPN Pkrs; Packers and SSSV MD (ft) and TVD (ft): 6,433' MD/5,263' TVD; 10,240' MD/8,555' TVD; Baker TE -5 SSSV TR 298' MD/TVD 12. Attachments: Proposal SummaryJ/ Wellbore schematic ,/ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑� ' Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: November 21, 2016 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse - 777-8354 Email tnasse@hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature Phone 907-777-8405 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 1 Post Initial Injection MIT Req'd? Yes ❑ No ❑f Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required: RB- D F S V C t 16 2� G APPROVED BY Approved byz./O.�'_/ COMMISSIONER THE COMMISSION Date: 1 8 Submit Form and d Form 10-403 Rev' 11/2415r li i is valid for 12 months from the date of approval. Attachments in Duplicate Hilcorp Alaska, LL Well Prognosis Well: CLU -05111) Date: 11/07/2016 Well Name: CLU-05RD API Number: 50-133-20474-01 Current Status: Shut In Leg: N/A Estimated Start Date: November 21st, 2016 Rig: D -2C Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Tyonek Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: Maximum Expected BHP: — 5,784 psi @ 9,804' TVD (Original 0.59 psi/ft gradient) Max. Predicted Surface Pressure: — 4,804 psi (0.10 psi/ft gas gradient) Brief Well Summary CLU-05RD is a sidetracked well targeting gas sands in the Beluga and Tyonek formations. It was brought on production in December 2015 in the D6 sand and was producing for about a month before watering up. The open intervals were plugged back and the 135A was perforated in January 2016, which watered out in May 2016. The interval was plugged back and the D= -5 -an" 4A-weretherrtested and found unproductive. The purpose of this work/sundry is to perforate additional Tyonek intervals. E -Line Procedure 1. MIRU E -line, PT lubricator to 5,000 psi Hi 250 Low. 2. If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 3. Perforate the Tyonek sands with 2-7/8" 6 SPF 60 deg phased perf guns. All intervals are planned for 12 SPF so each zone may be shot twice. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Gross Proposed Perforated Intervals A.✓ 4. POOH. 5. Flow through test separator and record water and gas rates. 6. If any of the sands are not commercial or wet, the zone will be permanently plugged back. 7. RD a -line. 8. Turn well over to production. Attachments: 1. Current and Proposed Wellbore Schematic Sands Top (MD) Btm (MD) FT Tyonek D -3A ±11,321 ±11,346 ±25 Tyonek D -2C ±11,081 ±11,106 ±25 Tyonek 91-2 ±10,767 ±10,787 ±20 A.✓ 4. POOH. 5. Flow through test separator and record water and gas rates. 6. If any of the sands are not commercial or wet, the zone will be permanently plugged back. 7. RD a -line. 8. Turn well over to production. Attachments: 1. Current and Proposed Wellbore Schematic Hilcorp Alaska, LLC 20" 13-3/ 3 8" r x, i 9-5/8" 7-5/8" RA My Jt 11,090' 8 9 r, RA Mcr Jt 11,633 RA My Jt 12,OW RA MTA 12,474 8-1/2' windowat 6,527' MD 5,354 TVD 5, 6, 7 D -SA D -6A 10,11 Q6 4-1/2" 4'. r..* PBTD =12,790' MD/ 11,103' TVD TD =12,940' MD / 11,253' TVD SCHEMATIC Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535" Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29'7 / L-80 / HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / SLIJ-11 6.875" 6,910 10,448' Liner Sealbore Extension Liner 12.6 / L-80 / DWC/ C 3.958" 1 10,240 12,915' TUBING DETAIL 41/2„ 12.6# / L-80 / I BT- M 3.958" Surf 1,200' 12.6# / L-80 / SuperMax 3.958" 1,200' 10,289' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240' —10,272' 1 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272' —10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'— 10,289' 3.850" 4.500" 4-1/2" Seal Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 ±11,505' D -5A 3.500" CIBP w/ 30' cement (TOC = 11,495') 9 11,565' 6 3.500" CIBP w/ 15' cement (TOC =11,550') F10 11,700' 11,712' 3.500" CIBP w/ 10' cement (TOC = 11,690') 11 11,723' 12/07/15 3.500" CIBP Updated by TRH 11-1-16 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status D -4A 11,460' 11,490' 9,774' 9,804' 6 10/14/2016 2-7/8" Active D-5 11,510' 11,530' 9,824' 9,844' 6 6/15/2016 2-7/8" Isolated D -5A 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Isolated D -5A 11,586 11,598 9,900 9,912 6 5/26/16 2-7/8" Isolated D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" t Isolated Updated by TRH 11-1-16 Hilcorp Alaska, LLC RKB =18' '1 20" 13-3/8" ifl 3 8-1/2' window at 6,527 MD 5,354' TVD 9-5/8" 7-5/8" Rq My Type 5, 6, 7 ID 91-2 Btm 20" R4McrA 129 / N/A / N/A 11,090' v , 13-3/8" D -2C 61 / K-55 / BTC 1 D -3A 8 2,970' 9 Intermediate 53.5 / L-80 / BTC D-5 10 r 47 / P-110 / BTC 8.681" 1,212' D -5A 7-5/8" D -6A RA My it 6.875" 6,433' 11,633 29.7 / L-80 / SLIJ-II 6.875" 6,910' 11,12 -r= _ D-6 it 12,060' RA My it 12,474' 41/2" PBTD=12,790' MD/ 11,103' TVD TD =12,940' MD / 11,253' TVD PROPOSED SCHEMATIC Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535" Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29.7 / L-80 / HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / SLIJ-II 6.875" 6,910' 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 3.958" 10,240' 12,915' TUBING DETAIL 4-1/2" 12.6# / L-80 / I BT- M 3.958" Surf 1,200' 12.6# / L-80 / SuperMax 3.958" 1,200' 10,289' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240' —10,272' 4.820" 6.560 4-1/2" ZXPN Liner Top Packer 6 10,272'— 10,298' 4.740" 6.270" 1 Liner Sealbore Extension 7 10,245'— 10,289' 3.850" 4.500" 1 4-1/2" Seal Assembly 12 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 ±11,410' DAA 3.500" CIBP w/ 10' cement (TOC ± 11,400') 9 ±11,505' 6 3.500" CIBP w/ 10' cement (TOC = 11,495') 10 11,565' 11,510' 3.500 CIBP w/ 15' cement (TOC = 11,550') 11 11,700' 6/15/2016 3.500" CIBP w/ 10' cement (TOC = 11,690') 12 11,723' 11,580' 3.500" CIBP Updated by TRH 11-1-16 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status 91-2 ±10,767 ±10,787 ±9,081 ±9,101 12 TBD Proposed D -2C ±11,081 ±11,106 ±9,395 ±9,420 12 TBD Proposed D -3A ±11,321 ±11,346 ±9,635 ±9,660 12 TBD Proposed DAA 11,460' 11,490' 9,774' 9,804' 6 8/20/2016 2-7/8" Active D-5 11,510' 11,530' 9,824' 9,844' 6 6/15/2016 2-7/8" Isolated D -5A 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Isolated D -5A 11,586 11,598 9,900 9,912 6 5/26/16 2-7/8" Isolated D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" Isolated Updated by TRH 11-1-16 215160-) Seth Nolan Hilcorp Alaska, LLC 27 6 13 GeoTech 3800 Centerpoint Drive, Suite 100 2 % 6 4 Anchorage, AK 99503 Tele: 907 777-8308 HvIciap Fax: 907 777-8510 DATA LOGGED E-mail: snolan@hilcorp.com 0/'{/201f4 I. K. BENDER DATE 09/30/2016 EIVED ! To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 Perforation and Plug prints and data Prints: Perforation Record 5" MD (5/26/2016) Perforation Record 5" MD (6/15/2016) Plug Setting Record 5" MD (6/15/2016) CD: 1 (5/26/2016) 3 CLU-05RD_PERF_2.6MAY16_LAS.Zip 12 CLU'-05RD_PERF 26MAYl6.pdf iv CLU-05RD_P ERF_26MAY16_im g.tif CD: 2 (6/15/2016) PERF 15JUN16 PLUG_13JUN16 6/20/2016 2:15 PM zip Archive 6/20.'2016 2:12 PPA PDF Document 6/2T,2016 2:12 PNI TIF File 6/22/201610:46 ARI File fodder 6/22/201610:46 AM File fodder Please include current contact information if different from above. OCT 0 3 2016 1�01GC 32 KB l; 050 KB 1,730 KB Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By:, _ , . I Date: STATE OF ALASKA ALA, iA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdownLl Performed: Suspend ❑ Perforate F] Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ 3rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑� Stratigraphic ❑ Exploratory ❑ Service ❑ 215-160 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-133-20474-01 7. Property Designation (Lease Number): 8. Well Name and Number: FEE Hilcorp (ADL 060569); ADL 324602 Cannery Loop Unit (CLU) 05RD 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Cannery Loop / Tyonek D Gas Pool 11. Present Well Condition Summary: Total Depth measured 12,940 feet Plugs measured N/A feety" '� '.. � true vertical 11,253 feet Junk measured N/A feet JUL 0 1 2016 Effective Depth measured 12,832 feet Packer measured 6,433 & 10,240 feet true vertical 11,146 feet true vertical 5,263 & 8,555 feet /1 OGCC �'$ Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090psi 1,540psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930psi 6,620psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440psi 5,300psi Liner 4,048' 7-5/8" 10,448' 8,762' 6,890psi 4,790psi Liner 2,675' 4-1/2" 12,915' 11,229' 8,430psi 7,500psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / L-80 10,289' MD 8,603' TVD Baker ZXP + ZXPN Pkrs; 6,433' MD/5,263' TVD 10,240' MD/8,555' TVD Packers and SSSV (type, measured and true vertical depth) Baker TE -5 SSSV TR 298' MD/TVD 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 960 988 254 1108 Subsequent to operation: 0 0 0 254 1242 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations Exploratory[] Development 0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL Lj Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 316-251 Contact Taylor Nasse - 777-8354 Email tnasse@hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature jc Phone 907-777-8405 Date % 1 J�(� Form 10-404 Revised 5/2015 « Submit Original Only , ��,6 4' �- RBDMS V,U JUL 0 6 2016 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date CLU 05RD E-Line 50-133-20474-00 215-160 5/25/16 1 5/26/16 Daily Operations: 05/25/2016 - Wednesday Meet at office and sign in. Mobe to location. PTW and JSA. Rig up lubricator and pressure test from 250 psi low and 5,000 psi high, TP - 614 psi. RIH w/ 2-7/8" x 12' Connex HC, 6 spf 60 deg phase and tied into Halliburton MAD Pass log dated 11-10-15. Tools set down at 9,270'. Pick up and work tools down from 9,270' to 11,582'. Got as rough as we could with perf gun and could not run below this depth. It was sticky and it wasn't very hard until we got to this depth. Called town and decided to get slick line out. POOH, out of hole and prepared to run slickline. We could use Halliburton E-line crane and lubricator since we were using Halliburton slickline. Rig up Halliburton slickline. P/T to 250 psi low and 5,000 psi high. RIH w/ 2-1/2" drive down bailer and tagged at 11,581' SLM (11.582' E-line ). Bailed to 11,607' (Multiple runs. Getting course dry sand out of bailer). Acted like we broke thru bridge so pulled out of hole. TP = 785 psi. RIH w/ 3'x 15' drive down bailer and bailed from 11, 607' to 11,616' making multiple runs. Got a lot sand out of hole and thought it might be falling back in on us. Could not tell fluid level due to deviation of well. We tried for several hours to get past 11,616' with different tools but could not. Decided to get E-line out and see if we have enough room to perforate. Perf depth were suppose to be from 11,586' to 11,598'. POOH and get ready for E-line. 05/26/2016 - Thursday PTW and JSA. Rig back up E-line lubricator, PT 250 psi low to 5,000 psi high. Arm gun. RIH w/ 2-7/8" x 12' Connex HC, 6 spf 60 deg phase and tied into Halliburton MAD Pass log dated 11-10-15 and tag at 11,615'. Run correlation log and send to town. Jacob Dunston said log was 2' deep and to pull up 2' and shoot from 11,584' to 11,596' (that should make it 11,586' to 11,598' OHL). Spotted gun from 11,584' to 11,596' and fired gun with 825.6 psi and it was 829.2 psi after 5 min. POOH. Rigged down lubricator and turn well over to field. TP - 830.3 psi. Hilcorp Alaska, LLC RKB =18' 20" 2 ,t yl I 13-3/8" 3 8-1/2' window at 6,527' MD 5,354 iVD 9-5/8" 4 d ti a i 7-5/8" 5, 6, 7 R4 Nkr Jt 11,0917 D-5 D-6 R4MrJt 11,633 8,9 D-6 R4 My it 12,06(7 R4IVlcr it 12,474 41/2" PBTD =12,790' MD / 11,103' TVD TD =12,940' MD / 11,253' TVD SCHEMATIC innery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535" Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29.7 / L-80 / HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / SLIJ-II 6.875" 6,910' 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 3.958" 10,240' 12,915' TUBING DETAIL 4-1/2" 12.64 / L-80 / IBT-M 1 1958- Surf 1,200' 12.6# / L-80 / SuperMax 1 3.958" 1,200' 10,289' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240'— 10,272' 1 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272' —10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'— 10,289' 3.850" 1 4.500" 1 4-1/2" Seal Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 11,700' -3,500" 11,726' CIBP w/ 10' cement (TOC = 11,690') 9 11,723' 6 3.500" CIBP Updated by CJD 4-25-16 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status D-5 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Open D-6 11,586 11,598 9,900 9,912 6 5/26/16 2-7/8" Open D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" Isolated Updated by CJD 4-25-16 THE STATE of A LASKA I -I. GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Cannery Loop Field, Tyonek D Gas Pool, CLU 05RD Permit to Drill Number: 215-160 Sundry Number: 316-302 Dear Mr. Helgeson: Alaska Gil and Gas Conservati®n Commissi®n 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy7. Foerster Chair DATED this Zv�ay of June, 2016. RBDMS l,li Jv,l J 6 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS n s Z J 20 AAC 25280 1. Type of Request: Abandon ❑ Plug Perforations Q ' 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 in ❑ Other: N2 Pumping 9 ❑ 2. Operator Name: Hilcorp Alaska, LLC 4. Current Well Class: 5. Permit to Drill Number: Exploratory ❑ Development 0 " Stratigraphic ❑ Service ❑ 215-160 ' 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-20474-01 ° 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231. Rule 3 Will planned perforations require a spacing exception? Yes ❑ No 0 Cannery Loop Unit (CLU) 05RD 9. Property Designati n (Lease Number): 10. Field/Pool(s): ADL 06056 ADL 324602 Cannery Loop I Tyonek D Gas Pod " PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,940' ° 11,253' 12,832' 11,146' 4,823 psig N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090psi 1,540psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930psi 6,620psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440psi 5,300psi Liner 4,048' 7-5/8" 10,448' 8,762' 6,890psi 4,790psi Liner 2,675' 4-1/2" 1 12,915' 11,229' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" L-80 10,289' Packers and SSSV Type: Baker ZXP + ZXPN Pkrs; Packers and SSSV MD (ft) and TVD (ft): 6,433' MD/5,263' TVD; 10,240' MD/8,555' TVD; Baker TE -5 SSSV TR 298' MD/TVD 12. Attachments: Proposal Summary ❑✓ Wellbore schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: June 15, 2016 OILWINJ ❑ ❑ GAS ❑✓ WAG ❑ WDSPL ❑ Suspended ❑ 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. Contact Taylor Nasse - 777-8354 Email tnasse hilcor .com Printed Name Chad HHelgeson Title Operations Manager �'Y Signature Phone 907-777-8405 Date (r t COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ RDDMS LL, v' 0 6 2016 Spacing Exception Required? Yes ❑ No Subsequent Form Required: I ® U t � " APPROVED BY Approved by: COM ISSIONER THE COMMISSION Date:G - 2 f 1j s 4 /& Submit Form and Form 10-403 evised 11/2015 V d I t for 12 montrom the date of approv Attachments in Duplicate Hilcorp Alaska, LL Well Prognosis Well: CLU-05RD Date: 5/31/2016 Well Name: CLU-05RD API Number: 50-133-20474-01 Current Status: Producing Leg: N/A Estimated Start Date: June 15th, 2016 Rig: D -4A Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: Maximum Expected BHP: — 5,807 psi @ 9,844' TVD (Original 0.59 psi/ft gradient) Max. Predicted Surface Pressure: — 4,823 psi (0.10 psi/ft gas gradient) Brief Well Summary CLU-05RD is a sidetracked well targeting gas sands in the Beluga and Tyonek formations. It was brought on production in December 2015 in the D6 sand and was producing for about a month before watering up. The open intervals were plugged back and the D5A was perforated in January 2016. The D5A watered out in May 2016. The purpose of this work/sundry is to isolate the open intervals and perforate the D5A and 124A intervals. ' E -Line Procedure 1. MIRU E -line, PT lubricator to 5,000 psi Hi 250 Low. 2. RU nitrogen pumping unit and connecting hoses. PT equipment to 5,000 psi Hi X50 Low (Review Standard Well Procedure — Nitrogen Operations with all personnel on site,. f 3. Pressure up well with nitrogen to push water away. Injection pressure should be around 4,000 prig. Once injection pressure has stabilized, stop pumping and SI well. 4. RIH with Pressure/Temperature tool and check for fluid level. POOH. a. If fluid isn't completely pushed away, pump more nitrogen until water is below 11,000'_ 5. RD nitrogen pumping unit. 6. MU 4-1/2" CIBP and setting tool. 7. RIH and set CIBP at +/- 11,565'. POOH w/ setting tool. 8. MU dump bailer and fill w/ cement. 9. RIH and dump cement on top of CIBP (15' = 9 gallons). POOH w/ dump bailer. 10. Wait 24 hours for cement to set. 11. If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 12. Perforate the Beluga sands with 2-7/8" 6 SPF 60 deg phased perf guns. All intervals are planned for 12 SPF so each zone may be shot twice. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Gross Proposed Perforated Intervals 13. POOH. 14. Flow through test separator and record water and gas rates. Sands Top (MD) Btm (MD) FT Tyonek D-5 ±11,510 ±11,530 ±20 Tyonek D -4A ±11,460 ±11,490 ±30 13. POOH. 14. Flow through test separator and record water and gas rates. Well Prognosis Well: CLU -05111) Hilcorp Alaska, LL Date: 5/31/2016 15. If any of the sands are not commercial or wet, the zone will be permanently plugged back. Note: If zone is wet, follow steps 1 through 10 to push water away and plug back. 16. RD a -line. 17. Turn well over to production. Attachments: 1. Current and Proposed Wellbore Schematic 2. Standard Well Procedure — Nitrogen Operations Hilcorp Alaska, LLC RKB =18' 20" •• 2 7 sssV l , i. � �• 7 „a 13-3/8" !' 3' 9-5/8" window at 6,527' MD 5,354' ND 7-5/8" 5, 6, 7 RAWJt 11,090' ,fit. �}'ry , i L•.,A �a 1 1 1M D-5 D-6 RA Nkr Jl 11,633' 8 9 D-6 RA AAcr Jt 12,060' RA Yvkr it 12,474' 4-1/2" c PBTD =12,790' MD/ 11,103' TVD TD =12,940' MD / 11,253' TVD SCHEMATIC Iannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" 4-1/2" Chemical injection Mandrel 53.5 / L-80 / BTC 8.535" Surf 1,212' Intermediate 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" 4.820" 29.7 / L-80 / HYD 511 6.875" 6,433' 6,910' Liner 29.7 / L-80 / SLIJ-II 6.875" 6,910' 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 3.958" 10,240' 12,915' TUBING DETAIL 4-1/2" 12.6# / L-80 / I BT- M 3.958" Surf 1,200' 12.6# / L-80 / Su perMax 3.958" 1,200' 10,289' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240'— 10,272' 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272'— 10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245' —10,289' 3.850" 4.500" 4-1/2" Seal Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 11,700' D-6 3.500" CIBP w/ 10' cement (TOC = 11,690') 9 11,723' 6 3.500" CIBP Updated by CJD 4-25-16 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status D-5 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Open D-6 11,586 11,598 9,900 9,912 6 5/26/16 2-7/8" Open D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" Isolated Updated by CJD 4-25-16 I K Hileorp Alaska, LLC RKB =18' 20" 2 issv Sa r ;a 13-3/8" s 8-1/2' window at 6,527' MD r 5,354' TVD 9-5/8" 7-5/g' 5, 6, 7 RA Nkr Jt 11,090 D -4A D5 7 D-5 D-6 RA Mcr Jt 11,633 , R 8,9 D-6 RA My Jt 12,06(Y RA My Jt 12,474 r 4_1/2" e c PBTD =12,790' MD/ 11,103' TVD TD =12,940' MD / 11,253' TVD PROPOSED SCHEMATIC 'annery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5 / L-80/ BTC 8.535" Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29.7 / L-80 / HYD 511 6.875" 6,433' 6,910 29.7 / L-80 / SLIJ-II 6.875" 6,910 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 3.958" 10,240' 12,915' TUBING DETAIL 4-1/2" 12.6# / L-80 / IBT- M 3.958" Surf 1,200' 12.6# / L-80 / SuperMax 3.958" 11200' 10,289' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240'— 10,272' 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272'— 10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'— 10,289' 3.850" 4.500" 4-1/2" Seal Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 7 11,565' 9,900 3.500" CIBP w/ 15' cement (TOC = 11,550') 8 11,700' Isolated 3.500" CIBP w/ 10' cement (TOC = 11,690') 9 11,723' 10,036' 3.500" CIBP Updated by TWN 5-31-16 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status D -4A 11,460' 11,490' 9,774' 9,804' 6 TBD 2-7/8" Proposed D-5 11,510' 11,530' 9,824' 9,844' 6 TBD 2-7/8" Proposed D-5 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Isolated D-6 11,586 11,598 9,900 9,912 6 5/26/16 2-7/8" Isolated D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" Isolated Updated by TWN 5-31-16 11 STANDARD WELL PROCEDURE llilcorpAlaska. LIX NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINALv1 Page 1 of 1 THE STATE OPAL S GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Cannery Loop Field, Tyonek D Gas Pool, CLU 05RD Permit to Drill Number: 215-160 Sundry Number: 316-251 Dear Mr. Helgeson: Alaska Oil and (gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair DATED this 3 day of May, 2016. RBDMS UL1 4AY6 5 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations Q - 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: ❑ 2. Operator Name: Hilcorp Alaska, LLC 4. Current Well Class: 5. Permit to Drill Number: Exploratory ❑ Development F1 - Stratigraphic ❑ Service ❑ 215-160 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-20474-01 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 231. Rule 3` Will planned perforations require a spacing exception? Yes ❑ No ❑� Cannery Loop Unit (CLU) 05RD 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 060569; ADL 324602 Cannery Loop / Tyonek D Gas Pod 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,940' 11,253' 12,832' 11,146' 4,938 psig N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090psi 1,540psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930psi 6,620psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440psi 5,300psi Liner 4,048' 7-5/8" 10,448' 8,762' 6,890psi 4,790psi Liner 2,675' 4-1/2" 12,915'11,229' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" L-80 10,289' Packers and SSSV Type: Baker ZXP + ZXPN Pkrs; Packers and SSSV MD (ft) and TVD (ft): 8,433' MD/5,263' TVD; 10,240' MD/8,555' TVD; Baker TE -5 SSSV TR 298' MD/TVD 12. Attachments: Proposal Summary M Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Q* Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: May 13, 2016 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse - 777-8354 Email tnassetZbhilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature f Phone 907-777-8405 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. — I L� \ Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No ❑' Subsequent Form Required: r 0 — `l0 `l RBDMS LL- MAY 0 5 2016 APPROVED BY Approved by: �COMMISSIONER THE COMMISSION Date: l ^l Submit Form and Form 10-403 Revised 11/2015 v a pct n i for 12 months from the date of approvalAttachments in Duplicate Hilcorp Alaska, LL Well Prognosis Well: CLU-05RD Date: 4/29/2016 Well Name: CLU-05RD API Number: 50-133-20474-01 Current Status: Producing Leg: N/A Estimated Start Date: May 13th, 2016 Rig: Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: Maximum Expected BHP: — 5,848 psi @ 9,912' TVD (Original 0.59 psi/ft gradient) Max. Predicted Surface Pressure: — 4,857 psi (0.10 psi/ft gas gradient) Brief Well Summary CLU-05RD is a sidetracked well targeting gas sands in the Beluga and Tyonek formations. It was brought on production in December 2015 in the D6 sand and was producing for about a month before watering up. The open intervals were plugged back and the D5A was perforated in January 2016. The purpose of this work/sundry is to perforate the upper D6 interval and patch off the open D5A interval, if needed. Notes Regarding Wellbore Condition • Slickline drift and tag 4-1/2" tubing prior to perforating well. E -Line Procedure 1. MIRU a -line and pressure control equipment. PT lubricator to 250 psi low/5,000 psi high. , a. If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 2. Perforate the Tyonek sands with 2-7/8" 6 SPF 60 deg phased perf guns. All intervals are planned for 12 SPF so each zone may be shot twice. Depths are from the Halliburton MAD Pass log dated November - 101h, 2015. Send the correlation pass to the Reservoir Engineer, Operations Engineer, and Geologist for confirmation. Gross Proposed Perforated Intervals 3. POOH. 4. Flow through test separator and record water and gas rates. *2 5. If any of the sands are not commercial or wet, the zone will be permanently plugged back. Sands Top (MD) Btm (MD) FT Tyonek D-6 ±11,586 ±11,598 ±12 3. POOH. 4. Flow through test separator and record water and gas rates. *2 5. If any of the sands are not commercial or wet, the zone will be permanently plugged back. Well Prognosis Well: CLU-05RD I iieoru Alaska, LL' Date: 4/29/2016 Contingency: (If water from D -5A sand is killing well) 6. MU and RIH with 4-1/2" X -Span patch. Set patch across D-5 intervals per the proposed schematic. POOH. 7. RD a-line.�/�'� 8. Turn well over to production. Attachments: 1. Current and Proposed Wellbore Schematic I K IJilcorp Alaska, LLC 20" F• 3 i 8-1/r, window at 6,527 MD a 5,354' TVD ,a A a 7 5/8" 5, 6, 7 RA AAv Jt 11,090• D-5 RA MIT Jt 11,633' D-6 RA My Jt 12,060' RA MIT Jt 12,474 Y 41/2" PBTD =12,790' MD/ 11,103' TVD TD =12,940' MD / 11,253' TVD SCHEMATIC Iannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 21970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535" Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29.7 / L-80 / HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / SLIJ-II 6.875" 6,910' 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 3.958" 10,240' 12,915' TUBING DETAIL 4-1/2" 12.6#/ L-80 / IBT- M 3.958" Surf 1,200' 12.6# / L-80 / SuperMax 3.958" 1,200' 10,289' JEWELRY DETAIL No. Depth ID CID Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240' — 10,272' 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272'— 10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'— 10,289' 3.850" 4.500" 4-1/2" Seal Assembly 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 11,700' 3.500" CIBP 9 11,723' 3.500" CIBP 10' of cement bail dumped on top of CIBP @ 11,700. TOC at 11,690'. Updated by CJD 4-25-16 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status D-5 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Open D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" Isolated 10' of cement bail dumped on top of CIBP @ 11,700. TOC at 11,690'. Updated by CJD 4-25-16 Ifileorp Alaska, LLC 13-3/8" id -1 3 9-5/8" 7-5/8" RA Mcr Jt 11,0917 8-1/Y' window at 6,527 MD 5,354' TVD 5, 6, 7 D-5 PAT6'" 11 WE Q6 RAMrJt 11,633' z D-6 RA My Jt 12,060' RA My A 12,474 r PBTD=12,790' MD/ 11,103' TVD TD =12,940' MD/ 11,253' TVD PROPOSED SCHEMATIC Iannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535" Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29.7 / L-80 / HYD 511 6.875" 6,433' 6,910' 29.7 / L-80 / SLIJ-II 6.875" 6,910' 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 3.958" 10,240' 12,915' TUBING DETAIL 41/2„ 12.6# / L-80 / I BT- M 3.958" Surf 1,200' 12.6# / L-80 / SuperMax 1 3.958" 1,200' 10,289' JEWELRY DETAIL No. Depth ID CID Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 298' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,210' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240'— 10,272' 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272'-10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245'-10,289' 3.850" 4.500" 4-1/2" Seal Assembly 6 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 11,700'3.500" 11,738' 10,039' CIBP 9 11,723' 2-7/8" 3.500" 1 CIBP 10' of cement dump bailed on top of CIBP @ 11,700. TOC at 11,690'. Updated by CJD 4-25-16 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status D-5 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Isolated D-6 ±11,586 ±11,598 ±9,900 ±9,912 6 TBD 2-7/8" Proposed D-6 11,712' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" Isolated 10' of cement dump bailed on top of CIBP @ 11,700. TOC at 11,690'. Updated by CJD 4-25-16 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION -EB 0 1 2016 WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas Q ° SPLUG ❑ Other ❑ Abandoned ❑ Suspended[] 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG[] WDSPL ❑ No. of Completions: 1 • 1b. Well Class: Development a Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date CAlp., Susp., or Aband.: 1/22/2016 14. Permit to Drill Number / Sundry: • 215-160 / 315-705 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: October 13, 2015 15. API Number: 50-133-20474-01-00 ° 4a. Location of Well (Governmental Section): Surface: 180' FSL, 270' FEL, Sec 7, T5N, R11 W, SM, AK Top of Productive Interval: 1895' FNL, 1605' FEL Sec 8, T5N, R11 W, SM, AK Total Depth: 1898' FNL, 1615' FEL, Sec 8, T5N, R1 1W, SM, AK 8. Date TD Reached: November 5, 2015 16. Well Name and Number: CLU-05RD 9. Ref Elevations: KB: 313$.5 GL: 21' • BF: 20.7' • 17. Field / Pool(s): Cannery Loop Unit Tyonek D Gas Pool 10. Plug Back Depth MD/TVD: ° 12,790' MD / 11,103' TVD 18. Property Designation: Yee -W", lc �,. ADL 060569 (SHL) ADL 324602 (BHL/TPA 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 272700 y- 2388612 Zone- 4 TPI: x- 276709 y- 2391751 Zone- 4 Total Depth: x- 276699 y- 2391748 Zone- 4 11. Total Depth MD/TVD: ° 12,940' MD / 11,253' TVD . 19. Land Use Permit: N/A 12. SSSV Depth MD/TVD: 300' MD / 300' TVD 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore:21. N/A (ft MSL) J. Re-drill/Lateral Top Window MD/TVD: Top of window 6,527' MD / 5,354' TVD - 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 2"/5" MD/TVD, 5in Formation Log MD/TVD, 2in Formation Log MD/TVD, 2in LWD Combo MD/TVD, 2in Gas Ratio Log MD/TVD, 2in Drilling Dynamics Log MD/TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 7-5/8" 29.7# L-80 6,433' 10,448' 5,263' 8,761' 8-1/2" 102.7 bbls 15.3 ppg Class G 4-1/2" 12.6# L-80 10,240' 12,915' 8,552' 11,228' 6-1/8" 75 bbls 15.3 ppg Class G 24. Open to production or injection? Yes a No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): 1. 11,572'- 11,580' MD / 9,886'- 9,894' Open 3.5" CIBP set @ 11.700' MD / 10,014' TVD bail dumped 10' of cement on top TOC 11,690' 2. 11,712' - 11,722' MD /iU,026' - 10,036' TVD Isolated COMPLETION 3.5" CIBP set @ 11,723' MD / 10,036' TVD DATE 3. 11,726'- 11,738' MD / 10,039'- 10,051' TVD Isolated I /2Z- 14 6 SPF 2-7/8" VERIFIED �L 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" 10,289' Seal Assy @ 10,245' MD / 8,557' TVD 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 27. PRODUCTION TEST Date First Production: 12/8/2015 Method of Operation (Flowing, gas lift, etc.): I.L r I O' -J l N-� Date of Test: 1/28/2016 Hours Tested: 24 Production for Test Period Oil -Bbl: 0 Gas -MCF: 13746 Water -Bbl: 0 Choke Size: N/A Gas -Oil Ratio: N/A Flow Tubing Press. 3526 Casing Press: 0 Calculated 24 -Hour Rate --oo. Oil -Bbl: 0 Gas -MCF: 13746 Water -Bbl: 0 Oil Gravity - API (corr): N/A /2-4 3 -4 ��J / RBDMS L � FEB 01 1016 Form 10-407 Revised 1112015 CONTINUED ON PAGE 2 Submit ORIGINIAL onjj 28. CORE DATA Conventional G_ _ks): Yes ❑ No Q Sidewall Cores. fes ❑ No If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top N/A N/A Permafrost - Base N/A N/A Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 11,572' 9,886' information, including reports, per 20 AAC 25.071. Middle Beluga 7,061' 5,843' Lower Beluga 8,133' 6,734' Tyonek 9,525' 7,886' T913 Sand 10,308' 8,622' 91-2 Sand 10,765' 9,078' D2 Coal 11,035' 9,348' 133A Coal 11,321' 9,634' D4 Coal 11,396' 9,709' 135A Coal 11,568' 9,882' D6 Coal 11,711' 10,024' Formation at total depth: lTyonek 31. List of Attachments: Wellbore Schematic, Composite Drilling and Completion Reports, Days vs Depth, MW vs Depth, Definitive Directional Surveys, Casing and Cement Reports 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. Contact: Monty Myers Email: rpm erS hiLq coo Printed Name: Monty Myers Title: Drilling Engineer j Signature: Phone: 907-777-8431 Date: 2 I 20 P� INSTRUCTIONS General: This form and the required attaprovide 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 1a: 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 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 11/2015 Submit ORIGINAL Only Hilcorp Alaska, LLC RKB =18' 20„ 11H'11P-,,, i, 2 13-3/8" J-1 3 8-1/2" windowat 6,527 MD 5,354' TVD 9-5/8" 7-5/8!' 130' 5,6,7 7� RA Nlv Jt 11,E RA Wlv A 11,633' , D5 D-6 RA Nlv it 12,06(7 RA Nlv Jt 12,474' r 41/2" �. PBTD =12,790' MD / 11,103' TVD TD =12,940' MD / 11,253' TVD SCHEMATIC Cannery Loop Field Well: CLU 05RD API: 50-133-20474-01 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Intermediate 53.5 / L-80 / BTC 8.535" Surf 1,212' 47 / P-110 / BTC 8.681" 1,212' 9,178' 7-5/8" Liner 29.7 / L-80 / HYD 511 6.875" 6,400' 6,910' 29.7 / L-80 / SLIJ-II 6.875" 6,910' 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 3.958" 10,248' 12,938' TUBING DETAIL 4 1/2" 12.6#/ L-80/ IBT- M 3.958" Surf1,200' 12.6# / L-80 / SuperMax 3.958" 1,200' 10,289' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 300' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,200' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240' —10,272' 4.820" 6.560" 4-1/2" ZXPN Liner Top Packer 6 10,272'— 10,298' 4.740" 6.270" Liner Sealbore Extension 7 10,245' —10,289' 3.850" 4.500" 1 4-1/2" Seal Assembly 44' of Seal Assembly and 5' of first tubing joint are inside SBE and Liner Top Packer 8 11,700' 3.500" CIBP 9 11,723' 3.500" CIBP F c I 10' -f TIM bail dumped on top of CIBP @ 11,700. TOC at 11,690'. Updated by CJD 1-26-15 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status D-5 11,572' 11,580' 9,886' 9,894' 6 1/22/16 2-7/8" Open D-6 11,712' ' 11,722' 10,026' 10,036' 6 12/07/15 2-7/8" Isolated D-6 11,726' 11,738' 10,039' 10,051' 6 1/08/16 2-7/8" Isolated F c I 10' -f TIM bail dumped on top of CIBP @ 11,700. TOC at 11,690'. Updated by CJD 1-26-15 Hilcorp Energy Company Composite Report Well Name: CLU 005RD Field: Cannery Loop Unit County/State: , Alaska i (LAT/LONG): avation (RKB): 18 API #: 50-133-20474-01 Spud Date: 10/13/2015 Job Name: 1511837D CLU-05RD Drilling Contractor AFE #: 1511837D AFE $: Activity Date Ops Summary 10/12/2015 Rack 4 1/2" DP, cont PU single in hole from 6194' to 6316' when Driller felt drawworks brakes were not right. Stop and check brakes. Found 11 brass bolts broke off.;Cut and slip 95' foot of drill line while mechanic retrieve's brake bands from yard.;Remove brake bands, install new bands and pads.;Service rig and topdrive, check crown saver, callibrate block height.;Cont single in hole from 6316' to 6549' where we tagged up on CIBP. As per Baker Rep, slowly set down 25K on plug. PU V and park string. Up wt 140K, dwn wt 95K.;Break circ, line up on vac truck, pumped 20 bbl hi -vis sweep around. 304 gpm-235 psi.;POOH from 6549' racking back in derrick. Rack back milling assy.;BOLDS and remove wear bushing.;Set test plug, open annulus valve. R/U and test BOP equipment 250/4000 (250/2500 annular) w/ 5/10 min hold. Chart and record same. AOGCC waived witness (Jim Regg). No failures.; Drawdown test = 3100 psi start, 1500 psi drawdown, 16 sec bag closure, 2 secs ram closure, 17 sec for 200 psi inc, 87 sec for full charge. 2600 psi 4 bottle average.;Orient and install wear bushing (9" ID x 12" tall). RILDS;M/U 8 1/2" BOT Whipstock, Silverback Mills and MWD as per BOT rep. TFO 306.18° from MWD to face of whipstock (CW). TIH w/HWDP. 48k shear on whipstock w/ anchor pinned @ 19890#.; Shallow pulse test MWD (test good). TIH W/ whipstock assy to 2700' MD. TIH @ 45-60 ft/min as per BOT rep. 10/13/2015 Cont TIH at 45 to 60 ft/min with whipstock assembly, from 2700' to 6483'.;Displace well w/ 9.0 ppg 6% KCL PHPA used mud.;Orient whip stock and set anchor w/ 14L tool face verify w/ 10k over pull (ok) slack off and sheer bolt w/ 62k do wt Obtain parameters w/ 5k loss in up wt.;Mill window f/ 6527' U 6562' w/ 459 gpm @ 1248 psi w/ 80 rpm w/ TQ off 12k and TQ on 15-20k w/ total metal shaving recovered =278# (TOW @ 6527' BOW (o) 6544' );Lost circulation @ 6562' while milling window. Losses while pumping were +/- 600 BPH. Initial static losses were 260 BPH then within 20 min had decreased to 160 BPH static Iosses.;P/U and rack back stand. Saver sub broke out of TDS. Stood back w/ stand. M/U new saver sub on floor. Will breakout saver sub once we heal up losses.; Build and spot 25 bbl 40 ppb LCM outside of BHA. Build and spot 25 bbl 100 ppb LCM pill down backside followed by another 25 bbl 40 ppb Vanguard LCM pill down backside.; Continue to monitor and fill hole while building surface volume. Increased background LCM from 5 ppb to 20 ppb in active. Losses have decreased to 20 BPH from time of spotting initial LCM pill.;Lost a total of 450 bbls from OO:OO.;Hauled 0 bbls cuttings to KGF G&I for total of 0 bbls Hauled 630 bbls Class II junk fluid to KGF G&I for total of 1025 bbls �r01 Hauled 0 bbls cement to KGF G&I for total of 0 bbls 51 1j 10/14/2015 Monitor well fluid level +- 50' and loss rate w/ mud pump while building mud volume w/ loss rate tapering off to +- 8 bph.;Circ across top w/ well on trip tank and loss rate @ 6.6 bph.;Shut well in w/ bag and do squeeze thru kill line @ minimum pump rate 3.2 bpm and Push back side pills #2 & #3 U window monitoring pressures w/ Max DP pressure @ 208 psi and Max csg psi @ 165 psi w/;230 bbls squeezed way ( should have Vanguard pill #3 right at window).;Open well monitor loss rate on trip tank @ 1 bph loss rate. also Removed saver sub from std in derrick while monitoring and slide mills in out of window w/ no pump (smooth no bobbles).; Pooh f/ 6522't/ 943' and building mud volume w/ 20.2 bbls over cal displacement U bha.;Udn 10 jts of extra 4.5" HWDP and rack back 9 std in derrick.;Udn mwd Gauge and I/dn window mills (all mills in good shape w/ top polishing mill in guage). Static losses @ 0 BPH.;M/U V516PR 8-1/2" bit, 7" 7/8 - 7.5 stg motor. M/U MWD . TFO =241.88°. P/U Flex DC, Well Commander, 1 std HWDP, Jars and 15 jts HWDP. Install corrosion ring between top flex and Well Commander; Shallow pulse test MWD (test good).;TIH F/ 776' - T/ 4190' picking up singles off catwalk. Drift w/ 2.56". Lost 14 bbls to hole to this . JJ point. M/ 10/15/2015 Trip in hole w/ singles from 4200'- T/ 5058' MD. Drift 2.56"; Continue TIH out of derrick F/ 5058' - T/ 6482' MD. Hole took 14 bbls under calculated displacement (14 bbl loss).;R/U and perform FIT. Psi up to 620 osi w/ 9 ppg MW Ccil 6562' MD / 5389' TVD = 11.2 ppg EMW. Pumped a total of 44 gal and bled back 40 gal.;Rig service. Grease crown, Drawworks and Iron Roughneck.; Orient HS, exit window with no issues. Wash to bottom @ 6562', control drill 8-1/2" hole (150 ft/hr max) F/ 6562'- T/ 7076' MD. 320 gpm, 1320 spp, 1150 psi off, 32% flow, 40 rpm, 11k off, 13k tq on.;Hole took 16 bbl drink @ 6792' MD with no other significant losses.; Continue control drill 8-1/2" hole (150 ft/hr max) F/ 7076- T/ 7350' MD / 6086' TVD. 342 gpm, 1380 spp, 1200 psi off, 35% flow, 55 rpm, 11.6k off, 14k tq on, 50 units bgg (Canrig).;Circulate and condition hole @ 7350' MD. 341 gpm, 1235 psi, 36% flow, 56 rpm, 12.2k tq, Max gas 213, 9.66 ECD. 1.5-2 BPH static losses while drilling.; Monitor well (very slight losses). TOH F/ 7350' - T/ 6908' MD. Pulled 20-40k over @ 7145'. Orient mtr HS and continue pulling with several tight spots. Able to wipe through with no issue. 10/16/2015 Continue short trip to window encountered drag t/ 40k over through out w/ clean break backs. kelly up orient , 7018, 6970, 6951. 6905 kelly and orient, 6920, 6882, 6834, 6870, 6784,;Kelly up and pump ooh f/ 6713't/ 6550' do pump and pull bit thru window and above whipstock w/ no issue t/ 6507'.;Monitor static well loss while servicing rig Just seepage losses @ .8 bph.;Rih on elevators w/ no issues or fill.; Resume drilling 8-1/2" dir hole f/ 7350' to 8155' MD. Pumped 20 bbl high vis LCM sweep around while rotary drilling @ 7350' Back 21 bbls early w/ 45% increase; Continue working rotary trend and maintenance slides to maintain WP#2 and control drill for sample catchers unable to keep up @ 180 fph;345 gpm, 1695 psi on, 1470 psi off, 36% flow, 80 rpm, 15.8k tq on, 14k tq off, 90 units bgg (canrig). 200k up, 98k dn, 130k rot (all wts taken with pumps off).;Circulate and condition hole @ 8155' MD. Reciprocate and Rot, 350 gpm, 1470 psi, 37% flow, 80 rpm / 40 rpm, 15k tq, 54 bgg. Pumped 20 bbl hi vis sweep w/ 20% increase & 600 stks early.;Monitor well (static). Wiper trip. TOH on elevators F/8155 -T/7856' MD. Various tight spots but were able to work past with moderate effort (20-40k overpull).; Unable to work past 7856' on elevators. Begin backreaming from 7856'- T/ 7340' (06:00 depth). Consistently pulled tight w/ packing off and stalling issues until 7750' MD.;From 7750' to current depth of 7340' seeing significant overpull and stalling issues (very little indication of packing off). Pump @ 314 gpm, 1500 psi, 30 rpm, 13-20k tq, 34% flow.; Saw moderate amounts of fines, clay & sand w/ slight traces of coal across shakers while backreaming out.;Hauled 74 bbls cuttings to KGF G&I for total = 111 bbls Hauled 376 bbls class II junk fluid to KGF G&I for total = 1624 bbls Hauled 0 bbls cement to KGF G&I for total = O;Currently 1.92' Low and 1.74' Right of WP #2. arm 10/17/2015 Continue short trip to window encounte-.4 drag U 50k over throughout w/ clean break backs. back rE_ ..ng f/ 7340' U 7300' Pump ooh f/ 7300't/ 6859'.;Pull on elevators f/ 6859' with no issues thru window t/ 6510'.;Monitor static well losses @ 1.8 bph while servicing rig also drained stack and attempted to see if missing slip die was on wear ring, findings inconclusive.;Rih w/ no issues and fill pipe once 1/2 way w/ No fill on btm and 7.25 bbls over calculated displacement.; Resume drilling 8-1/2" dir hole f/ 8155't/ 8590' MD / 7140' TVD. Pumped 20 bbl high vis sweep around while rotary drilling first std do Back 28 bbls early w/ 35% increase.; Continue working rotary trend and maintenance slides to maintain WP#2. and control drill for sample catchers @ 149 fph.;Circulate and condition @ 8590' MD. Rot & Recip pipe. 352 gpm, 1540 psi, 36% flow, 80 rpm, 14.6k tq, 9.85 ECD's, 80 bgg. Circulate a total of 8300 stks.;Pumped tandem sweeps (1 st 8.9 ppg, 38 vis w/ walnut -22 bbls) (2nd 11 ppg, 240 vis - 22 bbls) w/ 60% increase in cuttings, 26 bbls early. Monitor well (Slight seepage).;TOH F/ 8590'- T/ 8089' MD. 205k up, 100k dn. Pulled clean at slow rate. Would see 10-20k over when trying to increase pulling speed. Pulled 40k over @ 8366' but wiped through once w/ no issue.; Increased pulling speed once we were @ last wiper point (8150'). Pulled clean to 8089' w/ proper displacement. TIH w/ no issues. Hole took proper displacement. No fill.; Continue drilling 8-1/2" hole F/ 8590' - T/ 9023' MD. Pumped 20 bbl hi vis sweep once back on bottom w/ 35% increase in cutting - 16 bbls early. Maintain .5% lube NXS to help manage increasing tq.;352 gpm, 1845 psi on, 254 diff, 36% flow, 80 rpm, 17.5k tq on, 14k tq off, 9.94 ECD's, 80 units avg bgg. Maintaining 20 ppb background LCM (5 ppb barofibre/15 ppb steel seal 50);Hauled 36 bbls cuttings to KGF G&I for total = 147 bbls Hauled 304 bbls class 11 junk fluid to KGF G&I for total = 1928 bbls Hauled 0 bbls cement to KGF G&I for total= O;Last svy @ 8861' MD / 7338' TVD 4.2' Low, 2.8' Left= 5' Distance to plan 10/18/2015 Continue drilling 8-112" dir hole f/ 9025't/ 9147' MD.:Pumped tandem 22 bbl Low/ to and high/ hi sweeps around while rotating and reciprocating pipe w/ 100% increase in cuttings, on time and circ clean .;Short trip to 8695' on elevators w/ consistent drag U 60k+ over through out w/ clean break backs. Pump ooh f/ 8695'V 8647' continue pooh on elevators;U 7660' had two std clean pull. Monitor static well @ 1.2 bph Ioss.;Rih fill pipe 1/2 way did encounter 10-20k extra do wt drag @ had one hard set do @ 9001' and 17' fill ream wash out fill f/ 9130't/ td @ 9147'.;Resume drlg 8-1/2" dir hole f/ 9147' to 9476' MD. Control rotary drill std and pump around 20 bbl high vis sweep. Did not indentify sweep back @ surface (strung out).;Continue drilling 8-1/2" dir hole F/ 9476' to 9714' MD. Start 5°/100' drop @ 9581' MD. 400 gpm, 2000 psi, 135 diff, 38% flow, 8k wob, 75 rpm, 18.2k tq on, 16.4k tq off, 10.1 ECD's, 310 avg units bgu;Hauled 57 bbls cutting to KGF G&1 for total = 204 bbls Hauled 383 bbls class Il junk fluid to KGF G&I for total = 2311 bbls Hauled 0 bbls cement to KGF G&I for total= O;Last survey @ 9607' MD / 7956' TVD - 6.6' Low and 2.9' Left. 7.2' distance to plan. 10/19/2015 Continue drilling 8-1/2" dir hole F/ 9714' to 9767' MD. Cont drop section. 400 gpm, 2000 psi, 135 diff, 38% flow, 8k wob, 75 rpm, 18.4k tq on, 16.5k tq off, 10.1 ECD's, 310 avg units bg;Circulate and condition hole. Pump hi vis sweep w/ 80% increase in cuttings - 70 bbls early. 220k up, 116k dn. 411 gpm, 2033 psi, 60 rpm, 16.6k tq.;Short trip pooh f/ 9767' U 8520' Up/dn wt 220/116k base line before short trip. Still encountering +60k drag but 100 % better than last short trip. 3 bbl gain for trip out.;Found sheared bolt on torque bushing. Inspected tq bushing and TDS w/ no other issues found.;Monitor well (.9 bph static losses). rih f/ 8420' U 9767'. Trip was clean but had 29' of fill. Wash down to bottom. 5 bbl gain trip in.;Continue drilling 8-1/2" dir hole F/ 9767' to 10014' MD. Cont drop section. 400 gpm while rotating, 352 gpm while sliding. Saw 897 units max gas @ btm's up.;2000 psi, 135 diff, 38% flow, 8k wob, 70 rpm, 19k tq on, 17k tq off, 9.91 ECD's, 573 avg units bg.;Hauled 108 bbls cutting to KGF G&1 for total = 312 bbls Hauled 432 bbls class II junk fluid to KGF G&I for total = 2743 bbls Hauled 0 bbls cement to KGF G&I for total= O;Last svy @ 9855' MD / 8179' TVD. 11.7' Low and .3' Right w/ 11.7' distance to plan. 10/20/2015 Continue drilling 8-1/2" dir hole F/ 1001.4' U 10139 MD. Continue drop section. Rig torqued out unable to back ream slide area w/ out stalling.; Pull thru and ream stand do continue this until we were able to back ream and pump 44 bbl sweep @ .30 ppb Strata Kleen while rotating and reciprocating pipe.;Sweep came back 85 bbls early w/ 300% increase in cuttings and circ clean torque do 2k.;Resume drilling 8-1/2" hole dir hole f/ 10139't/ 10200' and continue drop section. up/dn /rot 240/118/154k TQ @ 18-19.5k w/ 60 rpm SPP @ 2279psi @ 411 gpm;pump up survey w/ projection to TD @ 2.14 degs.;Pump around 73 bbl sweep @ .30 ppb Strata Kleen while rotating and reciprocating pipe @ 430 gpm @ 2355 psi Back 52 bbls early w/ 300% increase and circ clean.;Rack back one std flow chk (8 min to static well) Pump ooh f/ 10200' U 9765' where we started to get a flow increase, pit gain of 2.5 bbls, and 933 units of gas. Also had issues packing off at 9930'.;Slowed pump rate down and worked through tight spots pulling 20 to 30k over and 50k over at 9890'.; Decided to run back to bottom and circ gas out. Had to MU TD and orientate tool to work through slide area at 9940'. Then RIH on elevators to 10184'.;Wash and ream to bottom at 10,200'. Had 16' of fill.;Circ bottoms up w/ 200% increase in cuttings about 1/3 of the way to bottoms up and 1000 units of gas. 425 GPM, 2335 psi. 48 RPM. 18500k TQ.;Circ and wt up f/ 9.6 ppg U 9.8 ppg. Reciprocating and rotating pipe. Back ground gas went from 650 to 330 units. ECD at 10.25 at 425 GPM. Continue weighting up to 9.9 ppg.;Gas units dropped do below 180 units.;Stand back one stand and monitor well. No flow. Pump out of the hole 9600' with no extra drag except pulling off slips on connections it would be 30 to 40k over.;At 9600' the pump pressure, up wt, and gas started to increase. Pressure increased from 1280 U1380 psi, Up wt f/ 230 U 240k., and gas f/ 180 t/ 800 units.;Work pipe f/9450' U9338' and circ. Gas built up to 1042 units them came back do to 910. Shut do and monitor well. Had slight flow for 5 min then stopped.;RIH Working and reaming through tight spots at 9600', 9750, & 9860. Ream to bottom f/ 10142 to 10200'. Had 4' of fill on bottom.;Hauled 24 bbis cutting to KGF G&1 for total = 336 bbls Hauled 156 bbls class II junk fluid to KGF G&I for total = 2899 bbls Hauled 0 bbls cement to KGF G&I for total = O;Last svy @ 10162' MD / 8477' TVD. 10.4' Low and 5.14' Right w/ 11.59' distance to plan. 10/21/2015 Continue circ while rotating and reciprocating dp F/ 10220'V 10140'@ 425 gpm @ 2355 psi 50 -60 rpm @ 17-18k TQ BBG @ 288 units.;Pump around 41 bbl sweep @ .30 ppb Strata Kleen while rotating and reciprocating pipe @ 430 gpm @ 2355 psi Back 31 bbls early w/ 300% increase and circ clean.;also weight up f/ 9.9 ppg U 10.0 ppg w/ Bara-carb and increase vis f/ 57 U 62 and take lube % f/ 2.5 U 3% BBG @ 180 units.; Rack back std monitor well w/ just slight seepage loss. Pooh f/ 10200't/ 7040' w/ over pulls U 80k over and clean brake backs. Work thru all on elevators.;with 3.1 bbls over calculated displacement.; Pump around a 30 bbl sweep @.30 ppb Strata Kleen while rotating and reciprocating pipe @ 430 gpm @ 2100 psi. Came back 35 bbls early w/ 200% increase. Highest gas was 182 units.;Got back several baseball size chunks of coal about 1/2 way into bottoms up and one even larger with sweep. Also got back a lot of coal slivers and fines.;Monitor well with slight seepage. POH to 6497' with one 15k overpull and a couple 5k overpulls. Blow do TD.;Monitor well while cutting and slipping drilling line 170'. Hole taking 1/2 BPH static Ioss.;Service rig. Grease all equip, Adjust brakes, Check Rig Smart, and replace bolt on torque tube.;POH to BHA.;Stand back HWDP, Lay do jars, Stand back flex collars, Down load tools, and lay do rest of BHA. Hole took 7 bbls over displacement POH from window.; Hauled 0 bbis cutting to KGF G&I for total = 336 bbls Hauled 90 bbls class II junk fluid to KGF G&I for total = 2989 bbls Hauled 0 bbls cement to KGF G&I for total = 0 10/22/2015 Continue I/dn Bha #2 ( bit 1-2 in ).;Service rig and Monitor well 1/2 bph loss rate.;P/up bha #3 up load tools test (had to re-test ok) load nukes P/up new jars.;Rih w/ bha #3 f/ 311' to 3300'.;Fill pipe 1/2 way shoe stage pumps up warm mud and brk gels and circ btm up while rotating @ max rate 89 rpm and circ max rate 510 gpm reciprocating full std.;Recovered couple dozen fist sized chunks of coal. golf ball and 1/2 dollar sized also.;Continue Rih w/ bha #3 f/ 3300' to right above window @ 6476'.; Fill pipe, stage pumps up warm mud and brk gels and circ btm up while rotating @ max rate 89 rpm and circ max rate 510 gpm reciprocating full std.;Pump 45 bbl .30 ppg strata kleen Pill. Came back 31 bbls early w/ 200% increase in cuttings recovered 6 fist sized, 8 golf ball & 10 1/2 dollar sized chunks of coal;w/ countless coal slivers and a lot of fines. Establish base line parameters = 509 GPM, 2136 psi, up 140, do 93, rt 110. W/ no pump.= up 135, do 95, rt 114.;RIH and ease thru window w/ no issues. Continue RI on elevators filling pipe at 8275' & 10180'. Tag fill at 10186 and clean out to 10197'. Had 16 spots where we had to PU and;work through. First tight spot at 6758' and last being at 9695'. Loss to well during trip was 2.2 bbls.;Circ bottoms up and Pump 45 bbl .30 ppg Strata Kleen Pill. Came back on time with a 300% increase in cuttings. Only got back 2 large chunks of coal. High gas was 1077 units.;Get check shot survey on bottom. Get SPRs. Sperry's computer went down. Get tech help and get computer back on Iine.;POH MAD PASSING at 240 to 300 FPH, 80 RPM, 500 GPM. f/ 10197't/ 9766'.;Hauted 0 bbls cutting to KGF G&I for total = 336 bbls 10/23/2015 Continue Pooh MAD passing at 240 to _ FPH, 80 RPM, 500 GPM. f/ 9766' t/ 8400' w/ 60% increas, . cuttings while logging. Mainly pencil eraser sized coal chunks;with occasional fist sized and golf ball sized coal chunks. Gas low of 30 units and two coal gas spikes to +-400 units and conn gas to 130 units.;Still acquiring good log but operating out of spec do to slip/stick and vibrations.; Continue POH MAD passing f/ 8400' t/ 6800'. At 8210' we pumped a48 bbl .30 PPB Strata Kleen sweep. It came back 28 bbls early w/ a 100% increase in cuttings.;The main increase in cuttings came back just before the sweep and just after the sweep. Didnt get back any large chunks of coal.;Hauled 0 bbls cutting to KGF G&I for total = 336 bbls Hauled 270 bbls class II junk fluid to KGF G&I for total = 3349 bbls Hauled 0 bbls cement to KGF G&I for total = 0 10/24/2015 Continue pooh MAD pass logging @ 240-300 fph F/ 6784't/ 6625' @ 80 rpm w/ TQ @ 14k and 507 gpm @ 2050 psi.;Orient source and log and pull bha through window while just pumping (no rotation) f/ 6625't/ 6472' (had 15k bobble @ nuke stab);Circ and pump 49 bbl strata Kleen pill @.30 ppb w/ 200 % increase and 43 bbls early while rotating and reciprocating full std ( TQ dropped 1k after pumping sweep).;Pooh pumping and rotating until shakers clean up (getting centrifuge putty type cuttings f/ 6472't/ 4900'. Cuttings fell off to nothing at 4670'.;Also working on upping LCM concentrations of premix tanks and r/up to test choke manifold and Total Safety is testing gas alarms.;Pump out at 500 gpm, 45 RPM, and 2300 FPH f/ 4670't/ 4170'. Slow back do to 250 FPH t/ 4050. Still no increase in cuttings. Pump out fast to 3055'.;Test choke manifold to 250 psi for 5 min and 4000 psi for 10 min. No failures. Continue adding LCM to pre- mix.;Pump out of the hole at 250 FPH, 500 GPM, and 45 RPM f/ 3050' t/ 2929'. Very slight increase in cuttings.;Blow do TD and POH on elevators to BHA. Isolate pit 1 and 2 for a short circ system and start adding LCM to pits 3, 4, 5, and 6. Go through #1 mud pump.;Lay do BHA. LD Well Commander, Stand back flex collars, download and lay do smart iron.;Have Atigun tank, Rig tank, and Up right tank full of water. Still mixing LCM in mud tanks 3, 4, 5, 6, 7, and 8. Have pump rigged up to fill hole from top from 7, and 8.;Hauled 0 bbls cutting to KGF G&I for total = 336 bbls Hauled 90 bbls class 11 junk fluid to KGF G&I for total = 3439 bbls Hauled 0 bbls cement to KGF G&I for total = 0-'` Total do hole losses= 1017 bbls 10/25/2015 Continue finish Udn bha #3.;Clear and clean rig floor.;Drain flush stack, pull wear ring, install test plug and test jt.;Test BOPE as per regulations 250L /4000H w/ one fail pass (blinds rams) pull test plug chg out o-ring and retest good pull test plug and set wear ring r/dn test equipment blow do Iines.;Service rig. Change out swivel packing.;P/up & M/up BHA #4. PU 8 more jts of HWDP.;RIH to 3108', getting 150 units of gas while RIH. Fill pipe and circ 1103 units of gas out. [Mix 25 bbl 120 ppb LCM pill and store on vac truck];Continue RIH to just above window at 6500'. Getting back up to 230 units of gas while RIH.;Fill pipe and circ gas out on short circ system. Had a spike of 1055 units of gas and it fell back off to 300 units. 600 units on bottoms up.;RIH to 8511'. Fill pipe and continue to RIH to first tight spot at 9217'. Work through tight spot at 9228', and 9455'. Couldnt work thru spot at 9547' without pump or rotation.;Wash and ream through spots at 9547', 9563', 9725', 9785', and 9815'. Wash and ream the rest of the way to bottom f/ 9815't/ 10200'. Had T of fill.;Circ hole clean and treat mud with LCM. Got back a lot of chunks, slivers, and shards of coal back on bottoms up. The high gas was 827 units.; Hauled 0 bbls cutting to KGF G&I for total = 336 bbls Hauled 90 bbls class 11 junk fluid to KGF G&I for total = 3549 bbls Hauled 0 bbls cement to KGF G&I for total = 0 Total do hole losses= 1017 bbls 10/26/2015 Continue circ and rotate and reciprocate pipe while finishing getting background LCM U 60 ppb and pull shaker screens.; Feather btm and establish a roller cone pattern for the first few feet and stage up WOB Drlg 8-1/2" hole w/ dirty mud system f/ 10200' tJ 10340'.;WOB 23, RPM 80, TQ 15500, GPM 506, PSI 2330. No Iosses.Qrill 8 1/2 hole w/ dirty mud system f/ 10340' tJ 10450'. Drilling 5' and picking up to check hole. At 10355' we pumped a 25 bbl 60 PPB LCM pill that came back on time. No losses during drilling.;WOB 23, RPM 80, TQ 16000, GPM 506, PSI 2390. Pumps on 230 UP, 120 DN, 150 RT. Pumps off 247 UP, 130 dn, 170 RT.;Circ and condition mud keeping pipe moving. Put shaker screens back on and start stripping LCM out of mud f/ 60 ppb to 20 ppb.;Monitor well and hole static. Start POH f/ 10450'. Pulled to 10430' and encountered 70k over pull. Ended up pumping and backreaming out of new hole to 10200'.;POH on elevators f/ 10200' t/ 9560' with no more than 5k overpull at report time.;Hauled 0 bbls cutting to KGF G&I for total = 336bbls 4k ,L Hauled 90 bbls class II junk fluid to KGF G&I for total = 3639 bbls i C' Hauled 0 bbls cement to KGF G&I for total = 0`� `b Daily losses 0, Total=1017 bbl 10/27/2015 Continue short trip pooh f/ 9560' U 9180' with no issue;Rih Short trip 9180' U 10450' tag bottom w/ no fill;Circ gas out @ 1054 units and circ around 20 bbl 120 ppg Icm sweep @ 7 bbls early w/ +50% increase in cuttings circ clean few golf ball sized chunks of coal; Pull std attempt monitor well (well U-tubing ) & having +60k over pull, Run back to btm @ 10450' Circ 68 bbl 60 ppb LCM mud off trk & add .30 ppb Strata Kleen & circ around on time;w/ 100 % increase and one fist sized chunk of coal. Pumped at 505 gpm-2337 psi, 55 rpm-17,030 ft/lbs off bott torque. Circ until clean on shakers.;POOH from 10,450' to 10,345' and pulled 60K over. Made 3 more attempts with no clean up. MU topdrive and pumped up through 10,345' with no problem. Down pumps, SO and pulled up through; 10,345' to 10,328' with no problem. Cont POOH on elevators from 10,328't/ 6490' in csg. Hole took 3 bbls over displacement.; Service rig and topdrive. Change dyes in grabber.;Circ bottoms up with a high of 300 units of gas and slight increase in cuttings at 506 gpm-1738 psi. Blow do TD. Drop 2 3/8" OD hollow drift with wire.;POH to BHA. Having to break DP w/ tongs due to changing the breaks and high torque.;Lay do 6 jts of HWDP, Jars, Well Comander, and flex collars. Break and grade bit. 1-1-ER-A-E-1-NO-TD-Chanae unser rams to 7 5/8" and test to 250 low for 5 min and 4000 psi hiah for 10 min. Set wear ring.;RU to run 7 5/8" liner.; Hauled 0 bbls cutting to KGF G&I for total = 336 bbls Hauled 360 bbls class 11 junk fluid to KGF G&I for total = 3999 bbls Hauled 0 bbls cement to KGF G&I for total = 0 Daily losses 0, Total=1017 bbl 19,.- 10/28/2015 MU 7 5/8" shoe track, filled same and (,, . _.,Ked floats (OK). Cont to PU single in hole with 54 joints SL,_ ., 29.7# L-80 casing, top filling on the fly, completely filling every 10 joints to 2375'.;At 2375' ant 54) we lost all displacement returns. Attempt to fill backside with hole fill and could not fill hole. Load trip tank and cont to fill hole with 70 bbl, 10.3 ppg, 120 ppb LCM;pill stored on vac truck. Sent empty vac to G&I to retrieve 140 bbls of 9.2 ppg, 60 ppb LCM mud stored there. Started to get hole full but not sure if LCM is packing off around casing. Cont to ease;in hole in 10 joint increments, cont to fill backside with LCM pill. Every 10 joints attempt to topfill casing per capacity ofjoints ran. Could not get pipe full, backside continues to fill then drop;Initial static loss rate = 54 bph. Started building 300 bbls new mud in pits 7 and 8.;Cont easing in hole in 10 joint increments, now filling backside with 9.2 ppg, 60 ppb LCM mud from trip tank. Backside continues to fill but continues to drop in wellbore. Cannot get pipe to fill.;Ran total 80 jnts SLIJ II and 11 jnts Hydril 511 casing to a depth of 3980'. Static loss reduce from 54 bph to 10 bph on backside while tripping very slowly in hole.;At 3980', up wt 90K, dwn wt 74K. Attempt to topfill with 30 bbls 10.3ppg mud with no luck. After 30 minutes backside filled with 3/4 of a bbl. RU fillup hose to trip tank to fill pipe with 9.2 ppg mud;Total losses thus far = 494 bbis. Still building 9.0 ppg mud in pits 3-4-5. Discuss with Drilling Engineer on MU liner hanger assembly and cont TIH to window at 6427';Top filled casing with 33.3 bbls 9.2 ppg, 60 ppb LCM mud. Monitor well and hole setting full on both sides. Count csg to ensure right amount is Ieft.;MU Baker ZXP liner top packer. Fill liner sleeve with Pal Mix. RD weatherford while mixture is setting up.;Run and drift 2 stds of HWDP. Establish up wt 100k, do wt, 85k, rt wt 95k. TQ at 20 rpm = 77k, 30 rpm = 81 k, 40 rpm = 84k. Didn't cir due to losses.;RIH at about 6 min per stand U 6517'. Mud falling on back side when RIH. Fill back side every 2 stds w/ 9.2 ppg w/ 60 ppb LCM. and put 10.3 ppg w/ 60 ppb pipe cap in every 10 stds.;At 6517' we put in double the the pipe cap for 10 stds and still didn't catch pressure. Ann staying full while static. When you move the pipe up it swabs and moving down it falls.;Pumped away 64 bbls do back side and 35 bbls do DP while RIH.;Monitor well and call town to discuss options. Decided to see if we can pump and get circulation. Transfer 9.1 ppg mud from pits 7 & 8 to pit 3 for circ. Well stayed full while static.;Pump down DP while stroking pipe up and killing pump while moving down to try and establish circ. 46 spm 230 psi to start with but after pumping 100 bbis 107 psi.;Mud comes up in the well when you PU on the pipe and falls when you go down.;Prep mud in pits 4,5, & 6 for spotting pill by bringing the LCM up to 60 PPB. Static loss 2 BPH; Pump 28 bbl 9 ppg 120 ppb LCM pill and chase with 225 bbis of 9 ppg 60 ppb LCM mud. Spot just outside of shoe. Rotating pipe at 20 RPM and 12,800 Tq.;Had slight returns for first 100 bbls then mud fell about 2' in bell nipple by the time pill was spotted. Pumped at 190 GPM and 280 psi w/ a final press of 265 psi.;Hauled 0 bbls cutting to KGF G&I for total = 336 bbis Hauled 0 bbls class II junk fluid to KGF G&I for total = 3999 bbis Hauled 0 bbls cement to KGF G&I for total = 0 Daily losses 485, Total= 1502 bbls 10/29/20157 5/8" casino shoe arkark^d iust above window (6527') Shut down rig pump and PU 30' to let 120 ppb LCM pill soak while building volume. Rolled pump every 15 minutes, pumping 10 bbls at a time,;141 gpm-214 psi, and rotated string at 20 rpm -10,700 ft/lbs torque during pumping. Getting no returns when pumping. Built 300 bbis 9.1 ppg mud in pits 7 and 8. Decision made to TIH with casing.;Pulled up hole and racked back one stand. PU Baker cement head and single joint, MU same and staged on catwalk. RIH one stand pumping 10 bbls to attempt fill pipe. Cont building surface volume.;At window, up wt 150K, dwn wt 100K, 10 rpm=12,700 ft/lbs, 20 rpm=13,300 ft/lbs, 30 rpm=13,300 ft/lbs. Ease out window into open hole with no issue exiting window. Keeping backside full with;trip tank as fluid drops while slack off, fill DP with topdrive every 10 stands (never would fill), had no issue tripping in open hole from 6527' to 10,233'. At 10,233' we started to differential; stick down to 10,327'. Once shoe passed below 10,327' we could slack off to bottom at 80K down. MU 10' and 15' pups between stnd 93 and 94, PU cement head and single, SO and tagged bottom at 10,450'.;PU to 275K with no break over. Park string at 100K with shoe on bottom at 10,450'. f Losses to hole at this time = 497 bbls • Roll rig pump at an idle, 142 gpm-984 icp, to attempt to fill pipe and get circulation. Initially getting returns at 1% on flow ►.+ show, which then increased to 4% (getting about 50% fluid to surface).;Then returns tapered off to 1 % on the flow show again. Pumped 309 bbls with a max of �r O 'A 566 units gas at bottoms up, and lost 112 bbls during the circulation. Shut down pump.;Build surface volume and roll pump every 15 minutes while RU J ry, Schlumberger cementers. Mix 25 bbl 12.5 ppg mud push.;Hold PJSM. SLB pumped 5 bbis water to clear lines, then 5 bbis to fill lines. Shut in cement head and V PT lines at 650 and 4800 psi.;Rig pumped 21.6 bbls 12.5 ppg Mud Push II at 5 bpm-850psi, then lined up cement head to SLB. SLB pumped 102.7 bbls (434 sx) 15.3 opo Class "G" Easy Blok cement at2.7 bpm, 400 So 100 psi with slight returns and shut down. Baker released dart, then SLB displaced with 10.3 bbis water & 90 bbis of 9.1 ppg 6% KCL mud;at 1.5 bpm -150 psi. Couldn't get mud fast enough to cmt unit so we swapped over to rig pump and displace at 4 BPM and a total of 253 bbls away.; Went back to cementers and slowed to 1.5 bpm with 265.6 bbls away 1300 psi and bumped plug/landing collar at 2 bbls over displacement.;FCP 1300 psi. Held 2700 psi (1400 psi over fcp) for 3 minutes. SLB increased to 4500 psi and held 2 minutes. Bled off 4 bbls back to pump truck and floats held.;PU 5' to clear dogs from hanger top, SO to 40k with good indication of shear, PU 115k and had good indication we released liner string.;Closed bag, line up on kill line, pressured up on annulus to 1170 psi and held for 10 minutes, good indication liner packer set. Bled off, lined up on topdrive;and pressured up to 1,200 psi with rig pump. PU out of liner hanger with run tool and started pumping as soon as psi started dropping off.;lncreased pump rate to 6 bpm -400 psi pumping 9.1 ppg 6% KCL mud. Circulated 1 bottoms up with 0 bbis Mud Push 11 to surface, and 0 bbis cement to surface.;267 bbl loss throughout the job, CIP at 02:30 on 10-30-15. Highest gas on bottoms up 1155 units.; Lay down cmt head w/ pup on top and single on bottom. Drop wiper plug in pipe and circ full circ to ensure pipe is clean. Cut and slip drlg line while circ.;Hauled 0 bbls cutting to KGF G&I for total = 336 bbis Hauled 25 bbls class II junk fluid to KGF G&I for total = 4251 bbis Hauled 0 bbis cement to KGF G&I for total = 0 Daily losses 451, Total= 1953 bbl 10/30/2015 Slip and cut drill line prior to POOH, start pit cleaning, blew down topdrive.;POOH from 6396' to Baker liner hanger run tool and LD same. Tool in good condition. PU cement head and break off single, XO's and pup jnt.;Drain BOP stack, pull wear ring, install test plug, remove upper 7 5/8" rams and install variable rams. Install 4 1/2" test joint.;Fill stack with water, purge air, test upper variable rams at 250 low/4000 high at 5/10 minutes on chart. Install wear ring and RD test equip. Cont working on rig pump and building surface volume.;Build new 10.3 ppg mud in pits 7, and 8. Change liners in #1 pump to 5" and change out valves and seats.;Lay do excess HWDP, PU jars and flex collars and stand back in derrick. Still working on building new 10.3 mud.;PU mud motor and set at 1.15. MU bit and PU smart iron. PU DM, Slim Phase 4, ADL, CTN, PWD, and TM collar. Continue to build new 10.3 ppg mud.;Hauled 0 bbls cutting to KGF G&I for total = 336 bbls Hauled 750 bbls class II junk fluid to KGF G&I for total = 5001 bbls Hauled 0 bbls cement to KGF G&I for total = 0 Daily losses 267, Total=2220 10/31/2015 Offload vac truck of mud into pit 2, circ through BHA to warm up smart tools, download MWD, shallow test, install RA sources, cont MU BHA-HWDP to 666'.;TIH on 4 1/2" DP from 666' to 5977' filling pipe every 2500'. Peak drifting 4 1/2" liner in yard at 3.833". Added 10 NRST's (non -rotating spiro torques) from stand 75 to 85.; Prep rig floor to single in hole, rack/tally 4 1/2" DP on pipe rack. Single in hole 4 joints and start adding "IT" type spiro torques on each stand from #87 #92. Just above liner top we filled pipe;at 6422' and rotated drill string at 35 rpm, with a torque of 8400 ft/lbs. Stopped rotation and pump, eased down into liner top at 6433' with no problem, but 23' into liner hanger assembly;we tagged up at 6456'. PU and rotated string numerous times with no luck getting below 6456'. Looking at liner hanger drawing, it appears the "RS" packoff seal nipple joint (2.45' long);has an ID of 6.75", and the lower 18" of that, has a profile ID of 6.625" (not on drawing). PU to 6422' and fill pipe/CBU at 117 gpm-440 psi.;Notified Drilling Engineer of issue, located 2 local 6 1/8" PDC bits, decision made to POOH and change bit size rather than mill out RS packoff seal nipple joint. Will drop "nukes" from BHA;due to collar/stabilizer size and run gamma/resistivity/PWD tools only. No 6 1/4" or 6 1/2" bits available. Blow down topdrive.;POOH from 6422' to BHA at 666'.;Stand back HWDP, jars, and Flex collars. Hold PJSM and remove source. Download tools. LD TM, PWD, ADL and CNT collars. Break 6 3/4 bit and MU 6 1/8 bit.; PU PWD and TM collar. Orientate tool. Download tool. RIH w/ Flex collars, Jars, and HWDP. [Actual time was 2.5 hrs but charged 1.5 due to daylight savings time.];RIH with DP to 3304' and fill pipe. Continue RIH to 6430' and fill pipe. Run down through liner hanger to 6475';Hauled 0 bbis cutting to KGF G&I for total = 336 bbls Hauled 185 bbls class 11 junk fluid to KGF G&I for total = 5186 bbis Hauled 0 bbis cement to KGF G&I for total = 0 Daily losses 0 Total=2220 11/1/2015 Cont PU single in hole from 6470' to 8b_ _ . No issue entering liner top or passing through liner hanger. .,i from 8389' to 10,251' with stands. Added spiro torques as per tally. Sent Baker hanger; and shoe track back to Baker shop to be mic'd for OD and removal of oversize centralizers from shoe track.;MU topdrive at 10,251' and CBU 1 time at 259 gpm-1332 psi. Had a max of 418 units gas at bottoms up. Worked string with no rotation. Obtained SPR's and RU test equipment. Circ through kill Iine.;With rig pump, pumped down kill line and DP, 112 strokes to 3550 psi, 6.5 bbls pumped. Held 3550 for 30 minutes on chart. Bled off 6.5 bbls, RD test equipment, blew down kill line. Good test.;MU next stand and spiro torque, slacked off and tagged cement/wiper plugs at 10,296' (4' above landing collar), PU 10'. Broke circ at 259 gpm-1500 psi, 30 rpm-15,000 ft/lbs torque. Drill shoetrack.;Drilled out landing collar at 10,300', float collar at 10,362', shoe track and shoe to 10,448'. Drilled cement and 20' new formation to 10,470'. 259 gpm-1417 psi, 30 rpm-15,500 ft/lbs on bott torque.;Start displacing well with 10.3 ppg KCl Polymer. Reciprocate and rotate. Torque increased to 18,000 ft/lbs when new mud came around. Pumped 584 bbls and new mud came around 10 bbls early.;Circ and condition until we had a even mud wt all around of 10.15 ppg. Peak hauled all the old mud to G&I.;Rigged up to erform FIT to 12 EMW. With test mud wt at 10.15 ppg we pressured up to 842 psi. Held pressure for 10 min with no bleed off. Pumped 64 gals and got back 64 gals.;Blow do test hoses and kill line. RD test equip.;Dril 6 1/8 directional hole f/ 10470 t/ 10600'. Adding lube to 1 %, and bringing mud wt up to 10.3 ppg. Torque=16200, RPM 30, GPM 250, 1790 psi,;Hauled 0 bbls cutting to KGF G&1 for total = 336 bbls Hauled 725 bbls class II junk fluid to KGF G&I for total = 5911 bbls Hauled 0 bbls cement to KGF G&I for total = 0 Daily losses 0 Total=2220; Distance to plan=6.16, High .68, Right 6.12 6V 11/2/201 tating wob 6K, 300 gpm-2200 psi, 60 rpm-17,000 ft/lbs on bott torque, 33 to 100 ft/hr ROP, MW 10.2+/vis 64, ECD's at 10.6 ppg, BGG 50;to 100 units, 33 to 34% flow. Had a spike of 485 units gas after drilling through the T12 coal at 10,720'. Made connection at 10,784', adding a spiro torque to string. Drilled from 10,784' to 10,795',;then PU off bottom and working torque out of drill string to orient for slide. During this process we noticed ECD's had dropped from 10.6 to 9.9 ppg, and flow increased from normal 34% to 41 %.; Driller PU 15' off bottom and shut down pump. Well flowing at 27% on flow show. Driller sounded well control alarm and shut in annular, opened HCR to choke manifold. Notified Drilling Engineer.;MD 10,795', TVD 9109'. Took a 30 bbl gain over the time of working pipe, shutting down and flow check, and shutting in.;Monitored well shut in pressures. After 30 minutes 0 psi on DP, 0 psi on casing. Weighted up surface volume from 10.2+ to 10.5 ppg. Updated Drilling Engineer and Drilling Manager via phone.;Attempt to ease auto choke open and roll rig pump. Had considerable mud and gas move into poorboy degasser, to the point it was starting to come out vent pipe. Closed choke and shut down pump.;Still seeing 0 psi on casing, but 1234 psi on DP. Checked both psi sensors on choke manifold and both not working (one electric, one hydraulic). Replace hydraulic sensor and opened up to gauge, now;seeing 1650 psi on casing. Bled casing down to 850 psi, ease auto choke open and roll pump at SPR of 46 spm. ICP 850 psi on DP, 450 psi on casing. Rig crew mixing surface volume to 11.0 ppg.;Pumped 11.0 ppg mud around through choke/degasser at 46 spm-111 gpm with a max of 1108 units gas at shakers after mud passed through degasser. Circ a total of 10,571 strokes. FC 576 psi on DP,;O psi on casing, gas down to 575 units at shakers. Held 760 psi back pressure with the choke while circulating. Shut down and shut in choke to monitor pressure build.;Monitor well for 30 minutes while shut in at annular and choke. SIDP = 0 psi, SICP = 35 psi. Opened choke and bled off the 35 psi, opened annular. Mud in hole very foamy.;Work string w/no issues, up wt 215K, notified Drilling Engineer and decision made to increase MW to 11.3 ppg and circulate that around. Weight up surface volume.;Break circ from 112 gpm to 186 gpm-1092 psi and circulate one full circ. Max gas of 1200 units which dropped to 80 units with 11.2 ppg surface to surface. Shut down monitored well, well static.;Get new SPR at 10780'w/ 11.2 ppg mud. #1 46 spm 632 psi. #2 48 spm, 630 psi.;Pull up hole from 10,795' to 10,385' (inside 7 5/8" casing), Had one spot at 10,692' where it pulled 10k over and fell back to up wt. Hole took proper displacement.; RU to do FIT. Perform FIT to 13 ppg EMW, Test MW 11.2, Test pressure 820 psi. Held for 10 min with no bleed off. Pumped 79 gals to press up and bled back 77 gals. Blow do Iines.;Service rig. Grease drwks, TD, Iron roughneck, Crown and blocks. Check brakes. Well static.;RIH picking up spiro-torq subs to 10,795'. Fill pipe. Displacement was good going in the hole.;Drill 6 1/8" directional hole f/ 10,795't/ 11,144';Hauled 12 bbls cutting to KGF G&I for total = 348 bbls Hauled 78 bbls class II junk fluid to KGF G&I for total = 5989 bbls Hauled 0 bbls cement to KGF G&I for total = 0 Daily losses 0 Total=222 11/3/2015 Cont drilling 6 1/8" hole from 11,144' to 11,673'. Rotating wob 6K, 301 gpm-2589 to 2673 psi, 60 rpm-18,100 ft/lbs on bott torque, 22 to 100 ft/hr ROP, MW 11.2+ to 11.3 ppg/ vis 62,E D's o 12. 1;ppg, BGG 22 to 38 units with spikes of 387 to 613 units after drilling coal seams. Pumped hi-vis sweeps at 11,315' and 11,600' with 20% and 50% increase in cuttings to surface. Up wt 260K, dwn wt 122K;Cont drilling 6 1/8" hole from 11,673' to 11,761' MD. Rot wob 6K, 301 gpm-2885 psi, 33% flow, 60 rpm-19,500 ft/lbs on bot tq, 22 to 100 ft/hr ROP, MW 11.2+ to 11.3 ppg/ vis 62, ECD's 12.2;BGG 45 units, 260k up, 122k dn, 165k rot (pumps off).;Circulate bottoms up @ 11,761' MD. Unable to rotate pipe while reciprocating in up stroke due to high tq 20k ft/lbs. Straight pull up and rotate down. Lube currently @ 1%, Increase to 2%.;298 gpm, 2400 spp, 33% flow, 60 rpm, 16.5k tq w/ BGG 45 units. Clean @ shakers. Shut down and monitor (slight drop). SPR #1-46 spm/777 psi. #2-48 spm/768 psi (11,750' w/ 11.3 MW);Wiper trip from 11,761' to 10,700' with no issues. Pulled clean w/ no swabbing. TOH 1.6 bbls over displacement, Monitor well @ 10,700' (static),; TIH w/ no issues. M/U NRST (make and break new connections) on stands while tripping back in. Tagged up on depth w/ no fill. TIH took proper displacement.; Cont drilling 6 1/8" hole from 11,761' to 11,971' MD. Rot wob 6K, 301 gpm- 2820 psi, 33% flow, 60 rpm-17,700 ft/lbs on bot tq, MW 11.3 ppg/ vis 62, ECD's 12.24.;Tq dropped from 20k to 17.5k after increasing lubes from 1% to 2%. Saw 143 units BGG @ btm's up after trip.; Hauled 35 bbls cutting to KGF G&I for total = 383 bbls Hauled 145 bbls class II junk fluid to KGF G&I for total = 6134 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls;Last svy @ 11865' MD / 10179' TVD . 12.9' distance to plan. 11/4/2015 Cont drilling 6 1/8" hole from 11,971' to 12,408'. Rotating wob 5 to 7K, 301 gpm-2951 psi, 60 rpm-16,363 ft/lbs on bott torque, BGG 98 units, MW 11.2 ppg/vis 54, ECD's at 12.2 ppg, 18 to 104 ft/hr ROP;drilling in tuffaceous claystone, siltstone, sand and coal. Bumped up NXS lube to 2.5% due to increase in on and off bottom torque. 18,600 ft/lbs dropped to 16,500 ft/lbs. Pumped a hi-vis sweep at;12,100' with an increase of 10% in cuttings to surface.;At 12,408' CBU 1 time at 300 gpm-2536 psi, 60 rpm-16,918 ft/lbs off bott torque. Could not PU on string and rotate without stalling. Rotated on down stroke of string. Flow check was static, obtained;slow pump rates, survey and blew down topdrive.;Pulled up hole on elevators from 12,408' to 11,700'. Up wt 265K, down wt 125K. At 11,970' pulled 20K over, slacked off, PU and hole was clean. TOH - Hole took proper displacement.; Monitor well (slight seepage). TIH F/ 11,700' to 12,408' MD w/ no issues. Tagged up on depth w/ no fill. Hole took proper displacement for trip in.;Cont drilling 6 1/8" hole from 12,408' to 12,660'. Rotating wob 5 to 7K, 301 gpm 3200 psi, 60 rpm-17.4k ft/lbs on bott tq, BGG 98 units, MW 11.3 ppg/vis 54, ECD's at 12.3 ppg,;Blew popoff #1 MP. Pump 20 bbl hi vis sweep around while replacing popoff on mud pump. 20% increase - Sweep came back 14 bbls early- mostly fine to pea sized coal but some chips and 2-3" shards;Cont drilling 6 1/8" hole from 12,660' to 12,810'. Rotating wob 5 to 7K, 290 gpm-2990 psi on, 290 diff, 60 rpm-18.3k ft/lbs on bolt tq, BGG 60 units, MW 11.3 ppg/vis 54, ECD's at 12.5 ppg,; Troubleshoot detection issues. Clean both pumps suction and discharge screens w/ no or poor detection. Mode switch MWD and re-establish good detection. Continue drilling ahead.;Cont drilling 6 1/8" hole from 12,810' to 12,816'. Rotating wob 5 to 7K, 290 gpm-2990 psi on, 290 diff, 60 rpm-18.3k ft/lbs on bolt tq, BGG 60 units, MW 11.3 ppg/vis 54, ECD's at 12.5 ppg.;Hauled 33 bbls cuttings to KGF G&I for total = 416 bbls Hauled 147 bbls class 11 junk fluid to KGF G&I for total = 6281 bbls Hauled 0 bbls cmt KGF G&I for total =0 bbls; Last svy @ 12744'. 3.6' High / 16' Right gives 16.6' distance to plan. 1� "(-D & I el 4, 11/5/2015 Cont drilling 6 1/8" hole from 12,816' to —at 12,940' and 11 254' tvd. Rotating wob 2 to 8K, 294 gpn s1 psi, 60 rpm -17,000 to 18,500 ft/lbs on bott torque, 10 to 60 ft/hr ROP, MW 11.3 ppg/vis 52,;ECD's at 12.5 ppg, BGG 52 units. Last survey at 12,940' md, Inc 1.05°, Azi 246.24°, 11,254' tvd puts us 10.41' high and 14.84' right of the line (18.13' center to center).;CBU at 300 gpm-2918 psi, rotating and reciprocating 60 rpm -16,800 to 18,300 ft/lbs off bottom torque. 250K up, 145K down while pumping and rotating. Max of 75 units gas at bottoms up.;Obtained survey, SPR's and flow check (static), turned elevators for wiper trip. Sent State 24 hr notification for bi-weekly BOP test when out of hole.; POOH on elevators from 12,940', up wt 290K with no pump or rotation, to 12,588'. At 12,588' started over pull 310 to 320K. Slack off and pull with no cleanup. MU topdrive and pump up hole at 213 gpm; 1623 psi, to 12,528'. SO and down pump. Still have 31 OK up wt. Cont to pump up hole from 12,528' to 11,705', pumping 300 gpm-2377 psi and no string rotation. Made numerous attempts to pull with no;pump but still seeing 31 OK steady. No jars fired. Possibly loaded up with cuttings in 9 5/8" casing. At 11,705' cont to pull up hole on elevators, up wt now 280K. Pulled clean into 7 5/8" shoe;at 10,448' with no issue. Up wt 240K entering shoe. Hole taking proper displacement. Parked string at 10,431'. Monitored well (slight seepage) while making crew change, prepped hi -wt hi -vis pill.; Pumped 20 bbl hi -wt hi -vis sweep around at 304 gpm-2156 psi, 85 rpm -16,000 ft/lbs off bolt torque. Had a max of 443 units gas at bottoms up. Cont circ sweep out with 50% increase in cuttings.;Hole unloaded 1/2" to 3/4" size cuttings for the first btm's up (mostly coal). Cleaned up then sweep brought back moderate amounts of fine coals and sand then cleaned up.;Saw a decrease of 3k ft/lbs tq after circulating, a decrease of 250 psi and a reduction of .27 ECD's from start to finish of clean up cycle.;B/D top drive. Line up and monitor well via trip tank. Cut and slip 85' drilling line. Set and check COM.;RIH F/ 10,448' to 12,940' MD. Tagged up on 12' fill. Wash down last 12'. No issues tripping in. Hole took proper displacement.; Circulate and condition hole @ 12,940' MD. Rot and recip pipe, 301 gpm, 2510 psi, 31%, 55 rpm, 16.5k -18k tq. Pumped tandem hi wt/vis - low wt/vis sweeps w/ 100% increase in cuttings.;Sweep came back 17 bbls early w/ 1/4" size coal initially then turned more into fine coal and sand. Saw 547 units bgg @ btm's up. Avg bgg was 25 units after clean up cycle;Monitor well (static). 330k up, 122k dn. Pulled cleaned from 12,940' to current depth of 11,502' MD. Had increase in tq and up wts due to decrease in lube percentage in mud 1%.;Pulled 5 stds then blow down top drive. Continue pulling out of hole. Displacement showing a 2 bbl loss thus far.; Hauled 11 bbls cutting to KGF G&I for total = 427 bbls Hauled 79 bbis class 11 junk fluid to KGF G&1 for total = 6360 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls;Projected to TD depth of 12,940' showed 18.2' distance to plan. 11/6/2015 Cont POOH on elevators, in open hole, from 11,502' to 10,448' (inside 7 5/8" casing). Up wt 270K. BHA pulled clean into shoe at 234K. Parked string at 10,368' and MU topdrive.; Pumped hi -vis sweep around at 301 gpm-2444 psi, 80 rpm -15,500 ft/lbs torque. Had a max of 64 units at bottoms up, and 50% increase in cuttings with sweep to surface. Blew down topdrive.;Cont POOH, in 7 5/8" casing, from 10,368', and into the 9 5/8" casing at 6,433'. No issue pulling BHA through liner hanger at 115K. Flow check and MU topdrive. Hole fill doing good.; Pumped hi -vis Strata-Kleen sweep around at 302 gpm-1931 psi, 80 rpm -9000 ft/lbs torque. Had a max of 117 units gas at bottoms up, and little to no increase in cuttings to surface. Blew down topdrive.;Cont POOH in 9 5/8" casing from 6403' to surface. (Total Safety on location at 20:00 calibrating/testing gas detection equip). Std back dp, hwdp and collars. UD directional tools.;Download MWD, Flush and Drain mtr, check end play and B/O bit. Bit grade = 1,3,BT,S,X,1,CT,TD.;Clean and clear rig floor. BOLDS and remove wear bushing.;Total Safety calibrated and bump tested alarms 10/20 1-12S, 20/40 LEL. R/U test equipment, set test plug and flood stack, manifold w/ water. Test BOP's 250/4000. 5/10 min hold, chart and record same; Test annular 250 / 2500. No failures. 2600 psi 4 bottle avg, Drawdown - start 3100 psi, drawdown 1425 psi, 200 psi inc=22 secs, full charge = 101 secs. AOGCC waived witness by Jim Regg;See test report and charts in "O" drive. AOGCC waived witness by Jim Regg;Hauled 0 bbls cuttings to KGF G&I for total = 427 bbls Hauled 160 bbls class II junk fluid to KGF G&I for total = 6520 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls `✓�� " 11/7/2015 Test blind rams at 250 low/4000 high to complete the bi-weekly BOP test„ RD test equip, blow down surface equip and lines, set wear ring and clear rig floor.; Held PJSM with rig crew and SLB loggers, RU sheaves and string a -line. MU quad combo tool string and test same. Telemetry tool failed. Replaced same. Tested OK. Loaded RA sources.;With well on trip tank, TIH with 123.39' quad combo tool string on a -line to 10,300'. SLB pulled up hole to get string weight parameters, then worked down in open hole at 500' intervals.; Every 500' in SLB pulled up hole to check string weight parameters. Tool set down at t 11,300' and could not go any deeper (coal seam from 11,270' to 11,310'). Pulled back up hole to 10,448'.;E -Line pulled to 8400K initially at 11,300' (predicted 6600K) and consistently 8000K to shoe at 10,448'. Notified Geologist and Drilling Engineer, decision made to POOH RD SLB loggers, MU;triple combo logging/cleanout assembly, and madpass on drillstring.;SLB POOH from 10,300' to 200', held PJSM, pulled up hole and removed RA sources. RD SLB loggers and released same.;M/U 6 1/8" PDC w/ triple combo logging package. Download, Shallow pulse test (good). PJSM and install sources. BHA length -- 629.61'; 629.61'; Continue tripping in hole out of derrick w/ BHA #7 (Cleanout /Logging assy) from 629' to 6212' MD. Fill pipe every 2500'. UD spiro tq's.;Obtain tq values every 5000' to see difference w/ and without tq reducers;Hauled 0 bbls cuttings to KGF G&I for total = 427 bbls Hauled 0 bbls class II junk fluid to KGF G&I for total = 6520 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls 11/8/2015 Cont TIH with logging/cleanout assembly from 6212' to 6400' Oust above liner top) laying down spiro torques. Fill pipe and get rotating parameters at 300 gpm- 1634 psi, 80 rpm -9000 ft/lbs torque;(same as previous torque), 60 rpm -8000 ft/lbs.;Cont TIH inside 7 5/8" casing from 6400' to 10,423' Oust above shoe) laying down spiro torques. Fill pipe and get rotating parameters at 300 gpm-2165 psi, 80 rpm -13,500 ft/lbs torque; (previous torque was 15,500 ft/lbs). Previous up wt at this depth was 210K, this trip was 190K, previous down wt was 115K, this trip was 108K. 60 rpm -12,500 ft/lbs.;Cont to trip in exiting 7 5/8" casing shoe at 10,448'. Trip in open hole from 10,448' to 11,385' and tagged up 10K. PU 20', S/O and set down 20K then fell through. PU 20', S/O and saw no obstruction.; Cont TIH on elevators to 12,550' and tagged up 20K. Worked through that obstruction and cont TIH to 12,775', tagged up again. Had 50K overpull at 12,775'. MU topdrive and fill pipe.;Start circ at 125 gpm staging pump rate up to 300 gpm-2623 psi, 40 rpm -14,500 ft/lbs torque. Observed slight stalling and packing off issues. 105k dn, 340k up prior to circulating hole clean.;Cont CBU one time washing down to 12,785'. Had a max of 1041 units gas at bott up. Hole unloaded coal chips 1/4" to 1/2" in size. Saw significant decrease in pump psi and tq after circulating.; Cont to circ until clean at shakers, rotating and reciprocating string. Make connection and cont to wash/ream down slowly from 12,785' to 12,940', 302 gpm-2686 psi -60 rpm -15,000 to 17,000 f /lbs.;Circulate and condition hole clean. Rot and Recip - 302 gpm, 2460 psi, 34% flow, 58 rpm, 17.1 k tq, 1041 max gas @ btms up w/ avg 51 units bgg. 130k dn, 260k up after circulating hole clean.;Mad Pass w/ triple combo logging package from 12,940' to 12,281' MD. 302 gpm, 2380 psi, 32% flow, 45 rpm, 13.5k tq. 180 ft/minute - max pull speed.;Hauled 0 bbls cuttings to KGF G&I for total = 427 bbls Hauled 95 bbls class II junk fluid to KGF G&I for total = 6615 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls 11/9/2015 Cont madpass logging at 180 ft/hr, from 12,281' to 11,297'. Pumping at 301 gpm-2300 psi, 55 rpm -13,500 ft/lbs torque, BGG 48 units, MW 11.3 ppg/vis 45. At 11,297' up wt 190K, dwn wt 130K.;At 11,600' we had a slight pump pressure increase, and 866 units gas after working through coal.;Cont madpass logging at 180 ft/hr, from 11,297' to 10,919'. 70 rpm, 13.8k tq, 302 gpm, 30% flow. Observed steady psi loss starting @ 11,157' MD. SPP went from 2200 psi to 1400 over 3 hrs.;Troubleshoot psi loss w/ no definitive conclusion while continuing mad pass operations. Assumed to be a washout at this point in time.;Continue mad passing from 10,919' to 10,448'w/ no pumps. Continue rotating while logging @ 30 rpm's, 11.8k Tq. Pump up MWD data every other stand to monitor MWD tool temp (135° F +/-);TOH from 10,448' to 7,507' MD. Inspect and look for washout. 4.2 bbl loss for trip thus far. Pulling wet. 118k up, 85k dn.;Service rig - Grease drawworks, top drive, blocks, iron roughneck and crown. Check fluid levels in top drive. 11/10/2015 Continue pooh f/ 7507't/ 6448'.;R/up test pump and chk bleeder valve on mud manifold (good) received new orders to continue pooh and I/dn smart tools. Blow do TDS and lines PJSM w/ crew on M.O.C.;Continue pooh f/ 6448't/ 4631' found wash out in dp @ 12" from bottle neck of TJ Oust above slip area) see photos in "O" Drive. Chg out jt continue pooh t/ 74'.;PJSM w/ crew, unload sources and download tools and I/dn bha.;M/U cleanout assy BHA #8 (565.45' length). RR 6 1/8" PDC 1,3,BT,S,X,1/16,CT,TD bit grade prior to this run.;Trip in hole from 565' to 6400' MD. Installed 6.625" string mill between std #35 and #36 (mills w/ XO's = 9.81') 20rpm, 7k tq, 92k up, 76k dn, 82k rot prior to entering top of liner.; Continue tripping in from 6,400' to 11,400' MD. Trip slow past liner top with no issues. trip clean past "RS" profile 2x with mills no rotor pump. Fill pipe every 25 stds. B/D top each time.; Hauled 0 bbls cuttings to KGF G&I for total= 427 bbls Hauled 0 bbls class II junk fluid to KGF G&I for total = 6705 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls 11/11/2015 Attempt trip in F/ 11,400'. Tagged up L 405' MD. Unable to work past without pumps or rotation. alated btms up after working past bridge. 302 gpm, 1780 psi, 32% flow. 262 btms up gas; Saw mostly 1/8" to 1/4" in size cuttings come back across shakers w/ moderate to significant amount. Lost #1 shaker motor, isolated on #2 while repairing #1 shaker motor (repaired).;Wash and Ream as needed ( every stand) F/ 11,405' to 11,924' MD. 300 gpm, 20 rpm, 1890 spp, 32% flow w/ max gas 748 units. Saw stalling and packoff issues while working through tight spots.;Trip in on elevators F/ 11,924' to 12,118' MD. Tag @ 12,118' MD. Wash and ream F/ 12,118'- T/ 12,940' MD. 302 gpm, 2220 psi, 33% flow, 20-30 rpm, 14-17k tq, 182 units max gas.;Tag on depth @ 12,940' MD. Circ and condition hole @ 12,940' MD. 302 gpm, 2020 ICP, 33% flow, 20-40 rpm, 40-17.5k tq, 350 units max gas. Pump 20 bbl 12.5 ppg, 240 vis sweep.;Saw packing off issues shortly after sweep cleared the bit. Max psi 3500 psi along with stalling issues (18.3K tq) while trying to work pipe. Able to establish rotation and good circulation.; Continue pumping sweep around but notice a continual drop in pump psi from that point. Verify no issues with surface equipment while circulating (equip good).;At 8900 stks into 11550 stk circulation, shutdown pumps due to continual psi drop w/ FCP 1340 psi, 33% flow. Did not clear sweep from wellbore. Monitor well (static). Suspect washout (drillstring);Trip out of hole F/ 12,940' - T/ 11,015' MD (midnight depth) looking for washout. 290k when pulling off bottom. Had no significant overpulls. Hole took proper displacement w/ no signs of swabbing.; Continue tripping out from 11,015' to 7290' MD. Found washout on jt# 217. 1/2" hole, 10" below tool jt. UD and replace. adjust in tally. Continue pulling out for mills. TOH F/ 7290'- T/ 4854';Hole took 13 bbls for trip thus far.; Hauled 0 bbls cuttings to KGF G&I for total = 427 bbls Hauled 90 bbls class II junk fluid to KGF G&I for total = 6795 bbls 11/12/2015 Continue pooh f/ 4854't/ 2700' Chk mill (ok) w/ total of 14.88 bbls over cal displacement I/& mill and XO's . Clean and clear rig floor prep for trip in.; RIH f/ 2700' U 10396' and fill pipe every 2500' and chg/out top jt on std #88 due to OD grooves.;Slip and cut drill line while circ and warming mud.;TIH F/ 10,396' to 12,844' MD. Work past bridges @ 12136', 12333'-12347', 12579'-12588' MD. Worked past with rotary @ 20 rpm's / no pumps. 5.6 bbl loss for trip.; Unable to work past bridge @ 12,862'. P/U to 12,844' MD. Wash and Ream F/12,844' -T/12,940'. 235 gpm, 1800 psi, 28% flow, 23 rpm, 14k tq. Packing off and stalling issues when breaking circulation.; Circulate and condition hole. Work pump rate up to 302 gpm, 1910 psi, 32% flow, 35 rpm, 15.5k tq. Pump 20 bbls hi vis sweep (5 bbl early w/ 50% increase in cuttings) Coal and Sand.;Circulate a total of 3 btm's up. Max gas @ btms up 518 units, 57 units BGG.;Monitor well (static). Wiper trip F/ 12,940'- T/ 11,298' MD. 115k dn, 265k up. Pulled steady w/ 30-35k over on way out. Trip back to bottom with little issue.;set do 10k @ 12,428'. Rotate past then pick up and trip through clean. Worked past bridge @ 12,885' to 12,888' MD w/ rotary. Tagged up on 20' fill @ 12,920' MD. Washed down last 20'.;1.2 bbl loss for trip out, .2 bbl loss for trip in.;Circulate and condtion @ 12,940' MD. Saw stalling and packing off when initially establishing circulation. Stage pumps up to 302 gpm, 1830 psi, 32% flow, 40 rpm, 17k tq, 192 max gas, 31 avg gas.;Pumped 20 bbl hi vis sweep but unable to identify it back at surface. Decision made to wt up from 11.3 ppg to 11.6 ppg for wellbore stability.; Hauled 0 bbls cuttings to KGF G&I for total = 427 bbls Hauled 90 bbls class II junk fluid to KGF G&I for total =6885 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls 11/13/2015 Continue weight up t/ 11.6 ppg for hole stabilization and spot and balance 64.5 bbls of 12 ppb black product soak in open hole @ 6 ppb soltex and 6 ppb baratrol.;Rack back one std and flow chk Static. Blow do tds and lines, Pooh on elevators w/ steady drag 25-30k over f/ 12940' t/ just inside 7-5/8" csg shoe @ 10420'.;Circ @ max rate 490 gpm @ 3250 psi while rotating and reciprocating full std @ 85 rpm well unloaded + 100% increase in coal cutting starting 2000 strokes into circ to just after cal btm/up;with reduction of 1000# TQ, 100 psi in SPP,6k in up wt and 5k in do weight. Blow do TDS and Iines;Continue pooh U 6396' just inside 9-5/8" csg. held fire drill @ 7182' (Prop was dryer on fire in boiler house).; Pump 22 bbl Strata Kleen pill and Circ @ max rate 490 gpm @ 3250 psi while rotating and reciprocating full std @ 85 rpm. Sweep on time w/ 10% increase in returns.;TOH F/ 6396'- T/ 3831' MD laying down excess drill pipe. Laid down a total of 41 stds.;TOH F/ 3831'- T/ Surface standing back in derrick remaining drill pipe. 159 stds dp, 7 stds HWDP. UD Flex DC's, stabilizer, bit sub and bit. Bit grade= 1,3,BT,S,X,1,CT,TD.;Btm NM Flex DC was noticeably bent approximately 6' from pin end (SN:11474510 as per tally). Cause is undetermined.; Clean and clear rig floor. UD any and all tools unneeded to make room for casing equipment.;R/U Weatherford casing equipment. Power tongs, Cavan slips, elevators (check size), R/U fill line. Stage liner as per detail. Verify float equipment and landing collar is clear.; Make up shoe track and check floats (good). Baker lok shoe track and tq all connections to 6500 ft/lbs. Run 4 1/2" DWC/C, 12.6#. L-80 from surface to 777' MD. Till on fly, safet L�4 clamp first 10 jts, Track displacement every 10 jts for trip.;Hauled 0 bbls cuttings to KGF G&I for total = 427 bbls tIt Hauled 95 bbls class 11 junk fluid to KGF G&I for total = 6980 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls 11/14/2015 Continue p/up run 4 1/2" DWC/C, 12.6#, L-80 liner f/ 777't/ 2642'. tq all connections to 6500 ft/lbs. Clear clean rig floor.;PJSM p/up and m/up and chk and prep B.O.T 5-1/2" SBE Assy, 5.1/2" X 7-5/8" flex -lock liner hanger assy and 5-1/2" X 7-5/8" HRD-E ZXPN liner top pkr assy.;M/up first std and brk circ and circ round an warm mud liner weight w/ TDS = 34k up/dn @ 2682'.;Rih w/ liner assy. on dp out of derrick filling on fly topping off every 10 std f/ 2682' t/ 6401' with 1.2 bbls over cal.;Circ and warm mud stage pump rate U 6 bpm 250 gpm @ 497 psi w/ 11.5+ ppg MW. PTSM and crew chg/out.;Continue running 4 1/2" liner F/ 6401' - T/ 10,370' . Fill on the fly. Trip clean when entering 7 5/8" liner top w/ 4 1/2" shoe and when cents entered 7 5/8" liner. 69k do before and after liner top;Circulate and condition mud @ 10,370' MD. Stage pumps up 189 gpm, 500 psi, 18% flow. Slight packing off issues for first 20 bbls circulated. Max psi 730. Bring light spots in mud from 11.4 to 11.6;Circulated a total of 3x btms up conditioning mud. 17 units btm's up gas w/ 5-6 units bgg.;Obtain parameters prior to open hole. W/ pumps 152k up, 102k dn, 121 k rot. 10 rpm -7.7k tq, 15 rpm -8.2k, 20 rpm -9.3k. 118k do w/ rot (6.7k tq), 122k up w/ rot (7.7k tq) taken w/ 10 rpms.;Pumps off 152k up, 108k dn. Adjust max tq on TDS to 14,500 ft/lbs. P/U and M/U pups on cement head, UD same.;Continue RIH with liner F/ 10,370'- T/ 11,233' MD. 180k up, 116k dn.;Condition mud @ 11,233'w/ no rotary. Reciprocate pipe. 143 gpm, 605 psi, 26% flow. Circulated 2x liner annulus volumes. Slight packing off issues.; Continue RIH with liner F/ 11,233'- T/ 12,049' MD. 190k up, 120k dn.;Circulate and condition mud. Reciprocate pipe. Stage pumps up to 150 gpm, 613 psi, 23% flow w/ no rotary. 38 units max gas. 11/15/2015 Circulate and condition mud @ 12049' MD and stage up pump rate 111, 125, and 175 gpm, and work thru pack off issues while working pipe.;TIH F/ 12049' to 12477' MD with no issue.; Circulate and condition mud @ 12477' MD and stage up pump rate 111, 125, gpm, and work thru pack off issues while working pipe.;TIH F/ 12,477' to 12,890' MD with no issue.;Tag up @ 12,890' MD. Wash down from 12,890' to 12,912' MD. P/U rotating cement head and m/u same. Wash down from 12,912' to 12,916' MD. Unable to work past 12,916' MD.;Circulate and condition mud 12,916' and stage up rate t/ 180 gpm, 900 psi, Work pipe and manage packing off issues while circulating rotate @ 10 rpm, 9.5k tq. .;Set shoe at 12915' and rotate @ 10 rpm, 9.5 - 11.5 k tq. and stage up rate U 180 gpm w/ less pack off issues.;R/U cmt line and manifold on rig floor. Continue circulating through manifold. 175 gpm, 897 psi, 10 rpm, 9.3k tq.;PJSM rN cementing. Clear cmt lines with air then flush with H2O, SLB pump 2 bbls H2O, P/T 7000 psi (good), Rig pumped 20 bbls 12.5 ppg Mud Push 11[ya 5 bpm, Turnover to SLB cementers.;Pump 75 bbls 15.3# gasblok class "G" cmt @ 4 bpm avg w/ 500 psi FCP, clear lines H2O, drop top dart (indicator tripped), Displace w/ 11.6# KCUPolymer mud. Rotated within 10 bbls of bumping.; Pumped first 167 bbls @ 5 bpm / 1250 psi then slowed to 3 bpm for last 11 bbls pumped. FCP 1100 psi. Bumped @ 178 bbls. Psi up to 2800 psi and set packer as per BOT Rep (Bruce Stephens).; Bleed off, floats held w/ 2 bbls bled back. CIP @ 18:58 hrs. 4 1/2" liner shoe final set depth @ 12,915' MD,, TOL set @ 10,239' MD.;P/U 160k (30k less than previous up wt prior to cement job, indicating liner released). Set back do w/ 40k. Felt shear screws as expected when tool shifted downhole as designed.; P/U w/ LRT and verify liner on depth (good). Psi up 900psi P/U to 10,236' MD. Saw psi loss clearing cup from packer seal bore. B/0 -UD cmt head. Install wiper ball. Circulated excess cement out.;CBU @ 300 gpm, 1084 psi, 32% flow. No indication of mudpush or cement back to surface. Monitored w/ ph meter/scale MW.;P/U to 10,174' MD. Circulate another btms up @ increased pump rate. 494 gpm, 2320 psi, 40% flow (no rotation). No mudpush or cement back to surface.;TOH F/ 10,174'- T/ 6384' MD just above 7 5/8" liner top in 9 5/8" casing.;CBU @ 6,384' MD. 452 gpm, 1264 psi, 38% flow. Pump dryjob. B/D TDS back to pumps.;TOH F/6,384' - T/ 2,700' MD w/ liner running tool.; Hauled 0 bbls cuttings to KGF G&I for total= 427 bbls Hauled 150 bbls class II junk fluid to KGF G&I for total = 7130 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls Hilcorp Energy Company Composite Report Well Name: CLU 005RD Field: Cannery Loop Unit County/State: , Alaska (LAT/LONG): .vation (RKB): API #: 50-133-20474-01 Spud Date: Job Name: 1511837C CLU-05RD Completion Contractor AFE #: 1511837C AFE $ Activity Date Ops Summary 11/16/2015 Continue POOH w/ liner running tool and racking back DP. Continue cleaning pits.,lnspect and LD liner running tool. (Good, pins sheered and gap was closed. ) Continue cleaning pits.,PU cmt head, brk out pup and XO's LD same. Continue clean pits.,PU wash tool wash out stack, pull wear ring set test plug and test rams and annular t/ 250L and 4,000H (ok) RD test equipment., Strap and tally 2-7/8" DP, ID/OD SLM OX and scrapers, C/out IR ram blocks and dies to fit 2-7/8" and service rig. C/O saver sub. Leave wear ring out.,MU 4-1/2" liner scraper assy w/ 3.7" 4 blade drag bit. Scraper is 4' from bit. 4-1/2" scraper assy length =5.68'. TIH picking up 2-7/8" singles T/ 2,567' MD., MU 7-5/8" scraper assy and continue trip in from 2,567' to 3,008' on 4-1/2" HWDP out of derrick. Cut and slip 150'drillina line. Service rig and calibrate block ht. 11/17/2015 Continue RIH w/ C/out assy #1 f/ 3,008't/ 6,389' fill pipe every 1,500' and warm mud. Continue clean pits. PU 9-5/8" scraper assy chg/out bad XO continue RIH t/6,433' Up/dn wt before entering liner 82/75K and no issues entering liner. Continue RIH f/ 6,433' U 10,149' and fill pipe twice., Discovered that we filled pipe w/ 11.3 ppg mud had some dilution at pits while cleaning. Attempt RIH t/10,210' well out of balance flowing over. Kelly up circ and balance well., Blow do TDS and lines continue RIH w/ no issue entering 4-1/2" TOL @ 10,240' continue RIH t/ 12,760', MU TD and fill pipe, wash do and tag LC at 12,790'.,Circ well clean just getting back fines. Circ until mud was balanced at 11.5+ ppg. #2 pump= 108 spm, 261 GPM, 3,401 psi. #1 pump= 119 spm, 185 GPM, 2,100 psi. Dn wt 130, up wt 200.,Blow down TD and thaw out stand pipe bleeder loop off valve.,RU to test csg. Test csg to 3,500 psi for 30 min on a chart. Good test with no bleed off. RD test equip and blow dn. [Hold PJSM for displacing well with water during csg test].,MU floor valve and TD. Pump through kill line with #2 mud pump w/ water to flush pump. [Up wt 210, do wt 132].,Pump 24.7 bbls high vis spacer and continue displacing well w/ freshwater. #1 pump at 120 spm, 187 GPM, 2,500 psi. When spacer went through the mill the press had built to 3,349 psi. W/ a final press of 1,300 psi w/ 8.4 ppg water back to surface at 137 bbls over displacement. [Up wt 220, do wt 140].,Break out floor valve and stand back 1 std. Blow down TD and mud line. Clean out under shakers and trip tank.,Short trip from 12759' to 11,768'. 11/18/2015 Continue POOH for short trip to pass scrapers on clean out BHA #1 f/ 11,848' t/ 6,389' (drilling engineer Monty Myers inspected 9-5/8" scraper - ok). Continue to clean pits and haul fluid. Prep chemical train and brine for chg over. Drilling Environmental Coordinator Julieanna Orczewska inspected location went over new SPCC chk list and assisted Saxon tool pusher w/ with compliance inspection., Continue short trip RIH f/ 6,389'V 12,790'w/ no issues on TOL and 1.3 over cal displacement., Circ and prep for chemical train and brine at 178 GPM and 1,030 psi.,Pump 69 bbl chem train followed w/ KCL at 210 GPM and 1,560 psi. Up wt 240, do wt 140.,Blow down TD and mud line. Prep trip tank for POOH.,POOH standing back 4-1/2" DP f/ 12,790'V 12,573'.,Had a hyd hose on the TD start leaking so we shut do to service the rig and repair the hose.,POOH f/ 12,573' t/ 9,213'. Started flowing over DP.,Pump 9+ ppg KCL slug, still flowing back. Pump slug do pipe another 36 bbls and it came dry. Blow do TD and mud Iine.,POOH f/ 9,213' U 6,398' and LD 9-5/8" csg scraper., Continue POOH standing back 4- 1/2" DP t/ 3,600'. 11/19/2015 POH f/ 3,800' to 2,560' and LD 7-5P'8 csg scraper assem. Scraper was in good shape.,RU to pull and LD 2-7/8" DP. Change dyes and rams on iron roughneck., POOH, LD 2-7/8" DP f/ 2,560't/ mill and scraper assem. Mill and scraper looked to be in good shape.,Change dyes and rams on iron roughneck to fit 4-1/2" DP.,PU Baker PBR polish mill assem. and 15 jts HWDP = 494.01'. RIH on DP to top of 7-5/8" liner at 6,433'. Didn't see anything going into Iiner.,Continue RIH to 10,230'. PU 5' pup and screw into last std.,Circ at 4 BPM, 260 psi. Up wt 204, do wt 125, Rt wt 150. Wash do into liner top at 10,240' and continue washing do to where bottom of PBR mill was at 10,292'. Pressure increased to 380 psi when top of tool set down on liner top. PU to up wt + 20' and start to rotate. 20 RPM, 10,500 torque. Ream do through liner 3 times cleaning up tie back receptacle with no change of wt or torque until tool set do on liner top.,Then torque increased to 10,800. PU to where the bottom of the tool was at 10,262' and circ 85 bbls at 7 BPM and 600 psi. LD 2 sngs and the pup to 10,230'.,MU TD and circ at 7BPM, 690 psi, while cutting and slipping drlg line. Blow do TD and set rig smart. [Got back some fines and blue paint off tools].,Service rig.,POOH, LD 4-1/2" DP t/ 7,626'. 11 /20/2015 Continue POOH, LD 4-1/2" DP f/ 7,626 U HWDP received reply from Mr. Regg w/ AOGCC and waived witness of bope test (started testing choke manifold while I/dn dp ),Finish I/dn Hwdp and inspected and I/dn polish mill assy (ok) continue testing choke manifold (all 4-1/2" CDS40 dp work string was placed in pipe tubs nd sent for inspection), Clear floor and prep for bope test. Set test plug and test Bopes as per regulations and Saxon policy 250 Psi L for 5 min and 4,000 Psi H f �AZr 10 min. Test bag to 2,500 Psi H. Accumulator test = 3000 psi manifold, 1450 psi after operating all BOPs, 19 sec to gain 200 psi and 97 sec to get full ,r pressure. Avg for N2 bottles = 2,550 Psi. No failures! RD test equip and blow dn.,Hold PJSM w/ Halliburton E -Line. RU E -line. MU and PU 54.22' of tools. CBL & PNL. Start RIH at 01:20 hrs. Got to bottom 12,790' at 0430 hrs. POH logging at 157min. 11/21/2015 Continue pull Halliburton E -Line. CBL and PNL. l0 15 f m f/ 11073' t/ 6300' M est TOC on 4-1/2" = 11550' and est TOC on 7-5/8" was inconclusive. Pull repeat pass f/ 6950't/6750'' Pooh I/dn tools and r/dn equipment.,R/up to run 4-1/2" completion and leveled derrick . Hold PJSM. Total safety tested gas alarms., PU mule shoe w/ lower seal assem, upper seal assem, spacer pup, locator sub, tbg pup jt, and XO pup jt. = 44.20,RIH picking up 4 1/2" super max completion tbg to 6433'. Set do on top of 7 5/8 liner. Attempted to work through one more time but set do again. PU and turn pipe about 1/4 turn. Work pipe to get torque do and work back through the liner with a slight indication of entering the liner top.,Continue RIH picking up 4 1/2 super max completion tbg to 9065'. MU chemical injection mandrel w/ tbg XO to 4 1/2" IBT on top. Change XO on floor valve,RU Pollard control line spools, hang sheave, and tie into chemical injection mandrel. Test control line to 5000 psi. Cis �ii5' O �Ilz" � -7' 11/22/2015 Continue RIH picking up 4 1/2 IBT 12.6,. _nge 3 completion tbg to 9940' holding 1500 psi on CIM cor, iine w/ two 1/2" SS bands per jt,P/up and M/up BOT SSSV and dress w/ control line. Function test w/ opening pressure @ 1900 psi and fully open @ 2200 psi and test line U 5000psi (ok).,Continue Rih p/up 4-1/2" IBT 12.6# range #3 completion tbg and locate out at btm of tie back sleeve on the HRD-E profile @ 10251' monitoring pressure on both control lines and 2 SS bands per jt.,Mark pipe for space out Pooh I/dn extra jts M/up space out pups , P/up circ assy on landing jt and p/up m/up hanger and dress hanger w/ chemical and control lines P/up place Muleshoe just inside tieback sleeve, Pump Baracor corrosision inhibitor @ .30 by volume and balance 6 bbls diesel for 100' freeze protect on tbg and annulus. up/dn wt @ 130/72k and land hanger w/ locator 2.44' off locating. RILDS and pack -off same, MIT backside w/ tbg open t/ 2600 psi for 30 min on chart (ok).,Bleed backside do to 1500 psi [82 gals] and test tbg U 5000 psi for 30 min on chart (ok). Took 3.6 bbls to pressure upon tbg and it bled right off only getting 4 gals back. Appears that the SSSV closed when we pressured up and we have 5000 psi trapped below it. Attempt several times to pressure up on tbg and open SSSV with up to 6000 psi on control line, but SSV wouldn't open.,Called town and discussed options. Put 5000 on tbg and bled ann pressure off. Then pumped SSSV up to 6500 psi and observed indication of it opening. Also observed indication on tbg pressure gauge. Bled tbg off and got back 3.5 bbls. RU to pull tbg to SSSV. RU Weatherford tongs and back out LDS., Pull hanger free w/ 140k, wt fell back to 130k while pulling out of seals. Pull hanger to floor and remove control lines. Pump SSSV back up and it opened at 1700 psi, locked in 2200 psi. Fluid U -tubing from tbg to ann for about 15 min then died off. Pull circ head, landing jt, hanger and 4 pups standing it back in the derrick., Continue POH laying do 6 jts of 4 1/2 IBT tbg to SSSV.,Test SSSV and it seems to be operating correctly. Pressure up to 1800 psi and it opened. Break xo pups out of old SSSV and lay it down. MU pups in new SSSV and MU in string. Tie in control line but had issues with it leaking at the fitting. Change to different control line spool and test to 6500 psi. Valve opened at 1800 psi. Leave 4000 psi on line and start RIH installing 2 bands on every connection. 11/23/2015 Continue RIH p/up 4-1/2" ibt 12.6# range #3 tbg installing 2 bands on every connection. Grab pumping assy & hanger & pup assy out of derrick install , orient and re -dress hanger w/ new seals and hook up SSSV control line jumper to top hanger & test t/ 6500 psi (ok) up/dn wt @ 130k / 72k Rih and land hanger w/ locator 2.40' off Iocating,RILDS and pack off hanger,MIT back side w/ tbg open U 2600 psi for 30 min on chart w/ 5.8 bbls pumped. ok and 10-1/4 gal back on tbg ok (SSSV open) good test,Bled off annulus t/ 1550 psi w/ 2.4 bbls back and tbg Sucked up 3 gals ( well fluid packed) pressured up tbg U 5080 psi w/ 3.5 bbls ( annulus pressure up to 1850 psi expansion ) held tbg pressure for 30 min U 5000 psi on chart. good test Bled off tbg w/ 3.5 bbls back & bled off annulus pressure w/ 5 bbls back (ok) Bled off SSSV control line and cap line (valve closed) remove landing jt w/ pumping assy and install BPV,Nip/dn BOPs and trolly out to the front of the sub. (RD and move several loads from back of rig],Clean up and inspect hanger. Prep for 5,000 X 10,000 sng valve Vee. Land tree and MU 5,000 psi flange. Install fitting for SSSV and Chemical Injection Mandrel on top of tree flange. Test flange and void to 250 low and 5000 high for 15 min. Good test! [Remove rig floor windwalls],MU flange on top of tree. Pull BPV and install TWC. Test tree to 250 low and 10,000 psi high for 15 min. Good test! Pull TWC.,Pull 10,000 psi test flange off top of tree and install 10,000 X 5,000 dbl studded adaptor w/ Otis 6 1/2 Quick Union cap.,Blow dn, drain and freeze protect test pump. PU and clean up sub area. Put front grate back over cellar. Break dbl gate and turn back to line up with sng gate. Have Peak clean out cellar in prep for rig release.,Prep rig for rig do and move in the morning. Rig is 25 % rigged dn. [Rig released from CLU 05RD at 0600 hrs and changed to HV B-17 at rig move rate] 12/3/2015 Obtain PTW. Hold safety meeting. Discuss SLB JSA and job procedures.,Lay pit liner. Spot in equipment. Rig up CTU 12 loaded with 1.5in CT tapered string.,Start BOPE test. Test all rams and valves to 250 and 5,000 psi. AOGCC 24 hr witness test notification sent 12/2/15 @ 1700 hrs. Witness waived by Jim Regg, AOGCC on 12/3/15 @ 0923 hrs. Testing TOT 4.06 10M quad BOP dressed from top to bottom with blind shear, blind shear, 1.5in pipe slips, 1.5in pipe rams. BOPE test complete.,Secure location. All ground valves and tree valves confirmed closed. Gate locked behind crew. N2 will arrive in AM. 12/4/2015 Obtain PTW. Hold safety meeting. Review JSA., Fire equipment. Pick injector head. Stab 10 ft lubricator. Dress CT. Makeup coil connector. Pull test 20K. Stab on well. Pressure test stack to 5K. Bleed down. Open well RIH. Attempting to fire N2 pump. Mechanics called to location., No luck at getting N2 pump fired. POOH with coil. SLB needs to bring N2 pump back to shop for further diagnosis.,At surface. Master swab closed. Blow down stack. Pop off wellhead. Break down tools. Set down lubricator and injector head. Install nightcap. Shutdown. Crews headed to shop to work on N2 pump. 12/5/2015 Obtain PTW. Hold safety meeting., No flow BOP cap. Remove BOP cap. Pick injector head. Stab 10' lub, makeup BHA ball drop nozzle 2.25". Stab on well. Pressure test lubricator to 250/5,000 psi. Bleed down. Open well swab and master 23.5 turns. Confirm SSSV open., RIH. weight check at 5,000' 8,200 lbs. RIH., Small wellhead pressure increase. Choke is closed. Pack offs had a leak and filled up 5 gallon bucket, half drum, and duck pond. Shutdown operations to attend to fluids. N2 cooled down. Pressure test lines to 250/5,000 psi., Online with N2 down CT. 800 scf/min. Increase rate to 1,500 scf/min. Continue to RIH, at 8,000' start performing weight checks every 500'. 56 bbls returned. 8,500' 14K weight. 10,000' 18.3K weight, 89 bbls in open top start pinching in choke. 567 psi whp 2,258 psi CT pressure. 1,240 psi whp. 132 bbls in open top., RIH and perform weight check at 12,100'. Weight pulling to 80% coil limit 28K. Able to POOH. Parked at 12,000'. Blowing well dry. Continue to move pipe up hole 10' as fluid unloads. 148 bbls returned., 2,800 psi coil pressure 1,700 psi WHP. 12,000'. 167 bbls returned. 175 bbls returned, 180 bbls returned. Blowing dry. Only nitrogen returns to surface. WHP 1,895 psi CT pressure 2,950 psi.,Start POOH 27K weight. Continue pumping N2 to pressure up tubing. At surface 2,500 psi SITP. Close master and swab.,Bleed down CT. Pop off well. Unstab Iub, set injector down. Unstab pipe. Remove BOPE. Install tree cap. Pick injector head from stand and set on back deck of CTU. Start rigging down iron. 441,061 scf or 4,736 gallons scf pumped for job. 180 bbls returned from wellbore. 12/7/2015 Meet at office. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. Crane back spooled their line and shut down to fix. Got heater and put on test pump motor. PT to 250 psi low and 5,000 psi high. Arm gun. Slow going also because of the cold temp. Well has 2,400 psi on it. Have crystal gauge hooked up to we1I.,RIH w/ GPT tool, 2-7/8" x 10' Connex HC, 6 spf, 60 deg phase and tie into Halliburton RMT log dated 21 -Nov -2015. Run correlation log and send to town. Got ok to perf. Could not find/tell fluid level. Went to 12,500'. Spotted shot from 11,712' to 11,722'. Fired gun with 2,398 psi on well and did not gain pressure. After 5 min pressure was 2,397.6 psi.,BHP was 3,580 psi before gun was fired and 3,597 psi after gun was fired. Pull up and monitored well. Had some cooling affects after perf but don't know how good the temp log was. Sent logs to town. POOH. Brake on drum started engaging and then locked up at 3,500'. Halliburton called their mechanic to come out and he was at Swanson River working on the slickline unit. At 1700 hrs well has 2,426 psi on it., Mechanic got here and pulled out of hole at 30' per min. Got all tools out of well. All shots fired and gun was dry., Rigged down lubricator and turn well over to field. TP is .2 ,563.7 psi and still building. 1/8/2016 Meet at office. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. Pressure test to 250 psi low and 5,000 psi high. Arm gun. TP 1,738 psi., RIH w/ 2-7/8" x 12' Connex HC, 6 spf, 60 deg phase and tie into Halliburton RMTI log dated 21 Nov 2015. Run correlation log and send to town. Got ok from J. Dunston to perf. Bled tubing down to 1,200 psi. Fired gun from 11,726' to 11,738'. Pressure went to 1,226 psi and after 5 min pressure was 1,275 psi. Lost 500 lbs of line wt after shot but gained it right back.,POOH all shots fired. Note: Tool wt 2,450 lbs at 11,700'. Rig down lubricator and turn well over to field. TP - 1524 psi 1/10/2016 1/14/2016 Meet at office and sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 5,000 psi high. Make up CIBP. TP - 66 psi.,RIH with CCUGR, 3.5" OD (For 4-1/2" tubing) CIBP and tie into Halliburton RMTI log dated 21 Nov 2015. Run CIBP correlation log and send to town. Log was off 1'. Corrected depth 1' (1' off depth is critical due to the depth between perf sections) and sent correlation log #2 to town. Get ok to set top of plug at 11,723' and bottom of plug at 11,724.3'. Logged into position and set plug at 11,723'.,Picked up 50' and went back down and lightly tagged plug at 11,723'. TP was 56 psi when plug was set. POOH. Had some line weight loss at 1,400' that could of been fluid level. Just not real sure.,Rigged down lubricator and turn well back over to field. TP - 55 psi. 1/15/2016 Obtain PTW. Hold safety meeting. Discuss job procedure and daily objectives., MI RU SLB CTU 12., Begin BOPE test. Test all valves and Rams to 250/5,000 psi. No failures indicated. BOPE test complete., Shutdown equipment. Secure location. 1/16/2016 Fire equipment. Hold safety meeting.. ;uss JSA and daily objectives. Inform crews of the impor,_ ,e of working safe and making the right decisions to avoid spills. Discuss our most critical areas for spills and correct mitigation measures to prevent them.,Pick inejctor head. Stab 10' lubricator. Make up CC . Pull test coil connector to 12K. Make up checks, 2 straight bars and 1.75" jet swirl nozzle. BHA length 8.4'.,Stab on well. Change out weight cell cable. Fluid pack for pressure test. Notice small drip on lubricator o -ring. Blow down stack. Pop off. Replace o -ring. Stabbed back on and fluid packed. Pressure test stack to 250 and 5,000 psi. Good PT. Bleed down to OT. Close choke. Open well. 0 psi WHP. Confirmed SSSV open.,RIH with choke open. Watching for fluid returns from pipe displacement, at 4,000' cool down N2. 5,000' no returns. Come online with N2 at 800 scf/min down CT string. 5,700' start getting water returns to surface., 10,000' 86 bbls returned. Continue to RIH performing weight checks every 1,500'. Tagged top o plug at 11,715' uncorrected to RKB coil depth. Corrected to RKB puts us at 11,723'. Pick up off plug @ 80% Coil limit 30K. Pick up 20' and park coil. Blow well down. Increase N2 rate to 1,500 scf/min., Pulling heavy. Decided to pull to 11,600'. Lost fluid bouyancy and increasing metal to metal friction due to well becoming dry. POOH to 10,800'. 136 bbls in return tank. WHP 256 psi choke wide open. Small readings of 1%-5% LEL.,Tank surging N2 and fluid. Continue pumping N2 at 1,500 scf/min. 140 bbls returned. All N2 at surface. Shut down N2 pumps and monitor return tank for LEL. Pinch in choke to increase WHP. Working choke in and pressure is still dropping. No increase indication of LEL at return tank. WHP 40 psi.,Shut in choke to perform build up. 40 psi. 30 minutes later 44 psi. Decided to POOH. Estimated fluid level from return volume is 2,600'.,POOH to surface. Crack choke to bleed off any residual N2. No LEL indications. Tagged up. Close master and swab.,Start rigging down CTU. Close well in for build up test overnight. After SLB off tree open well to SCADA and attached Crystal gauge to monitor WHP pressure. Crews off location. SLB will arrive in AM to demobe equipment to yard. 140 bbls recovered, 3,100 gallons of N2 used or 288,000 scf. 1/18/2016 Meet at office. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator and MU 3-1/2" OD CIBP. PT to 250 psi low and 5,000 psi high. TP - 620 psi.,RIH with CCL/GR, 3.5" OD (For 4-1/2" tubing) CIBP and tie into Halliburton RMTI log dated 21 Nov 2015. Run correlation log and send to town. Get ok to set plug at 11,700'. Spot plug and set at 11,700'. Lost 250 lbs line wt when plug set (25.50 Seconds). Wait 3 min and pick up 50' and go back down and lightly tag plug. POOH. Everything looks like a good set.,RIH w/ 3" x 20' cement dump bailer tie into Halliburton RMTI log dated 21 Nov 2015, and tagged plug at 11,700'. Dump bail 10' of cement on top of plug at 11,700' (TP 642 psi). Cement in place at 1800 hrs and est top of cement is 11,690'. We lost some weight at 8,400' going in hole and also coming out but couldn't say for sure that was fluid level or not.,Rig down lubricator. Secure well and wait on cement. Cement in place at 1800 hrs. 1/20/2016 Obtain PTW. Hold safety mting. Review JSA and discuss rig up procedure.,RU CTU 12 with 1.5" CT. Make up 1.69" coil connector. Pull test 12K. Shell test BOPE to 250/5,000 psi full test on 1/15/16. Function test and perform draw down test.,Order 3,000 gallons of N2. Shut down equipment. Location secure. Crews will arrive at 0700 hrs to perform N2 lift. 1/21/2016 Fire equipment. Obtain PTW. Hold safety meeting. Discuss SLB JSA and job procedures and steps. Review spill reporting. Discuss and mitigate measure to prevent leaks at coils more critical areas., No flow. Remove night cap. Pick injector head, stab 10' lubricator. Make up CC, DFCV, 2 weight bars and 1.75" set swirl nozzle. BHA lenght 6.4'. Stab on well. Fluid pack. Pressure test lubricator to 250/5,000 psi. Bleed down to 500 psi. Open master swab 23.5 turns. Initial WHP 650 psi. SSSV confirmed opened and locked out.,RIH 9,000'. Cool down N2 at 10,000'. Pressure test N2 lines 250/5,000 psi. Online with N2 at 800 scf/min down CT. Open choke to half.,Continue RIH @ 11,020' increase N2 ratre to 1,300 scf/min. Tagged Plug at 11,685'. Pick up off plug close to 80% coil limit, 29K up weight. RIH to re tag plug, tagged at 11,685'. Pick up 5'. Continue to lift fluid. WHP 450 psi.,As fluid unloads start pinching in choke to increase whp to 1,500 psi to assist tubing from differential pressure limitations. 33 bbls returned. All N2 at surface. Choke 2 turns off closed with WHP 1,850 psi. Start POOH.,Montior return tank. No indications of oil. Sraight N2 returns to tank close. Isolate choke. Isolate CT string and line up N2 pump down coil x tubing annuli. Continue pumping 1,300 scf/min to increase WHP. At surface. Out of N2 SITP 1,650 psi. Close master swab. Bleed down CT.,Pop off well. Break down tools. Start rigging down SLB CTU 12. 420,000 scf of N2 pumped for lift. 33 bbls of wellbore fluids returned. Calculated fluid level 9,540'. Vac truck emptied return tank. CT equipment rigged down and staged on edge of pad. Ordered 2,500 gallons of N2 to arrive at 0730 hrs. Will continue to pressure up wellbore to 2,100 psi for perforating job. Location secure. 1/22/2016 PTW, JSA and SIMOPS. Spot SLB pump truck and pressure test lines to 5,000 psi.,Pump 49K SCF down tubing with SLB which pressured tubing up to 2,200 psi. Rig down SLB N2 equipment.,PTW and JSA. Spot equipment and rig up lubricator. Pressure test to 250 psi low and 5,000 psi high.,RIH w/ 2-7/8" x 8' Connex HC, 6 spf, 60 deg phase and tie into Halliburton RMTI log dated 21 Nov 2015. Run correlation log and send to town. Got ok from J. Dunston to pert. Spot shot from 11,572' to 11,580'. Fired gun with 2,216 psi on tubing and went to 2,316 psi right away. After 5 min it was 3,150 psi. POOH.,Rig down lubricator and turn well over to field. TP 3,205 psi. Hilcorp Energy Company Kenai C.I.U. Cannery Loop Unit #1 Pad Cannery Loop Unit 05RD 501332047401 501332047401 Sperry Drilling Definitive Survey Report 02 December, 2015 HALLIBURTON Sperry Orilaing Company: Hilcorp Energy Company Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 05 Wellbore: Cannery Loop Unit 05RD Design: CLU05RD Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Cannery Loop Unit 05 Actual @ 38.50usft Actual @ 38.50usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Project Kenai C.I.U. Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Well Cannery Loop Unit 05 Well Position +N/ -S 0.00 usft Northing: 2,388,612.84 usft Latitude: 60° 31'55.763 N Dip Angle Field Strength +E/ -W 0.00 usft Easting: 272,700.47 usft Longitude: 151 ° 15'43.366 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 20.50 usft Wellbore Cannery Loop Unit 05RD Magnetics Model Name Sample Date Declination Dip Angle Field Strength Vertical (°) (°) (nT) Azi TVD BGGM2015 10/15/2015 +N/ -S 16.37 73.49 55,392 Easting DLS Section (usft) (°) Design CLU05RD (usft) (usft) (usft) Audit Notes: (ft) (°/100') (ft) Survey Tool Name 18.00 Version: 1.0 Phase: ACTUAL Tie On Depth: 6,440.40 0.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction 0.00 UNDEFINED 198.40 (usft) (usft) (usft) (°) 159.89 1.06 18.00 0.00 0.00 50.80 0.48 1.32 MWD (1) 382.40 1.20 55.40 382.36 Survey Program Date 12/2/2015 3.29 2,388,616.01 272,703.82 From To 444.40 2.10 48.20 (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 198.40 2,953.40 Baker Hughes INTEQ MWD (Cannery Lo MWD Fixed:v2:standard declination 10/05/1996 2,953.40 6,440.40 Baker Hughes INTEQ MWD (Cannery Lo MWD Fixed:v2:standard declination 10/05/1996 6,527.00 6,754.62 Survey #1 (Cannery Loop Unit 05RD) MWD _Interp Azi Fixed:v2:standard dec with interpolated azimuth 10/15/2015 6,816.72 10,162.92 Survey #2 (Cannery Loop Unit 05RD) MWD+SC+sag Fixed:v2:standard dec & axial correction + sag 10/15/2015 10,483.40 12,901.73 Survey #3 (Cannery Loop Unit 05RD) MWD+SC+sag Fixed:v2:standard dec & axial correction + sag 11/02/2015 Survey 12/2/2015 12.46:32PM Page 2 COMPASS 5000.1 Build 73 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 18.00 0.00 0.00 18.00 -20.50 0.00 0.00 2,388,612.84 272,700.47 0.00 0.00 UNDEFINED 198.40 0.86 38.54 198.39 159.89 1.06 0.84 2,388,613.88 272,701.34 0.48 1.32 MWD (1) 382.40 1.20 55.40 382.36 343.86 3.23 3.29 2,388,616.01 272,703.82 0.25 4.59 MWD (1) 444.40 2.10 48.20 444.34 405.84 4.36 4.67 2,388,617.11 272,705.23 1.49 6.37 MWD (1) 506.40 2.80 48.80 506.28 467.78 6.11 6.66 2,388,618.83 272,70725 1.13 9.02 MWD (1) 568.40 4.10 50.90 568.17 529.67 8.51 9.52 2,388,621.17 272,710.15 2.11 12.75 MWD (1) 660.40 5.80 50.40 659.82 621.32 13.55 15.65 2,388,626.09 272,716.38 1.85 20.69 MWD (1) 753.40 7.90 55.30 752.15 713.65 20.18 24.53 2,388,632.55 272,725.38 2.34 31.76 MWD (1) 846.40 9.90 58.60 844.03 805.53 27.99 36.61 2,388,640.12 272,737.61 2.22 46.06 MWD (1) 938.40 11.30 58.20 934.46 895.96 36.86 51.02 2,388,648.71 272,752.19 1.52 62.83 MWD (1) 12/2/2015 12.46:32PM Page 2 COMPASS 5000.1 Build 73 Company: Hilcorp Energy Company Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 05 Wellbore: Cannery Loop Unit 05RD Design: CLU05RD Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Cannery Loop Unit 05 Actual @ 38.50usft Actual @ 38.50usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,031.40 13.90 55.90 1,025.21 986.71 47.92 68.02 2,388,659.45 272,769.40 2.85 83.00 MWD (1) 1,124.40 15.70 54.40 1,115.12 1,076.62 61.51 87.50 2,388,672.66 272,789.14 1.98 106.68 MWD (1) 1,217.40 17.90 53.80 1,204.15 1,165.65 77.28 109.27 2,388,688.01 272,811.20 2.37 133.52 MWD (1) 1,279.40 18.90 54.10 1,262.98 1,224.48 88.79 125.09 2,388,699.22 272,827.24 1.62 153.06 MWD (1) 1,372.40 21.50 54.40 1,350.25 1,311.75 107.55 151.15 2,388,717.47 272,853.66 2.80 185.11 MWD (1) 1,465.40 24.10 54.10 1,435.97 1,397.47 128.61 180.39 2,388,737.97 272,883.30 2.80 221.08 MWD (1) 1,557.40 25.20 54.10 1,519.59 1,481.09 151.11 211.48 2,388,759.87 272,914.81 1.20 259.39 MWD (1) 1,648.40 27.80 54.20 1,601.02 1,562.52 174.88 244.39 2,388,783.01 272,948.17 2.86 299.92 MWD (1) 1,740.40 31.10 54.70 1,681.12 1,642.62 201.17 281.19 2,388,808.58 272,985.47 3.60 345.05 MWD (1) 1,833.40 33.40 53.90 1,759.77 1,721.27 230.14 321.48 2,388,836.77 273,026.31 2.52 394.58 MWD (1) 1,926.40 35.40 54.70 1,836.50 1,798.00 260.79 364.15 2,388,866.60 273,069.56 2.20 447.02 MWD (1) 2,019.40 38.40 55.00 1,910.86 1,872.36 292.93 409.80 2,388,897.86 273,115.82 3.23 502.71 MWD (1) 2,111.40 40.30 54.00 1,982.00 1,943.50 326.81 457.28 2,388,930.82 273,163.94 2.18 560.92 MWD (1) 2,204.40 42.10 53.70 2,051.98 2,013.48 362.94 506.74 2,388,966.00 273,214.09 1.95 622.09 MWD (1) 2,297.40 45.60 53.90 2,119.03 2,080.53 400.99 558.73 2,389,003.04 273,266.79 3.77 686.42 MWD (1) 2,389.40 46.70 53.50 2,182.77 2,144.27 440.27 612.20 2,389,041.29 273,321.00 1.24 752.68 MWD (1) 2,482.40 48.40 55.00 2,245.54 2,207.04 480.34 667.89 2,389,080.29 273,377.45 2.18 821.17 MWD (1) 2,574.40 48.41 55.40 2,306.61 2,268.11 519.61 724.39 2,389,118.46 273,434.69 0.33 889.77 MWD (1) 2,668.40 48.20 55.60 2,369.14 2,330.64 559.37 782.23 2,389,157.10 273,493.29 0.27 959.72 MWD (1) 2,760.40 48.30 54.90 2,430.40 2,391.90 598.49 838.63 2,389,195.14 273,550.42 0.58 1,028.15 MWD (1) 2,853.40 47.80 55.50 2,492.57 2,454.07 637.96 895.42 2,389,233.52 273,607.97 0.72 1,097.11 MWD (1) 2,923.40 48.30 55.30 2,539.36 2,500.86 667.53 938.28 2,389,262.25 273,651.38 0.75 1,149.00 MWD (1) 3,041.40 46.37 55.88 2,619.33 2,580.83 716.56 1,009.85 2,389,309.91 273,723.88 1.68 1,235.46 MWD (2) 3,132.40 48.16 56.28 2,681.08 2,642.58 753.86 1,065.32 2,389,346.13 273,780.05 1.99 1,302.02 MWD (2) 3,225.40 48.41 56.93 2,742.96 2,704.46 792.07 1,123.28 2,389,383.22 273,838.73 0.59 1,371.08 MWD (2) 3,319.40 48.83 55.05 2,805.11 2,766.61 831.52 1,181.74 2,389,421.54 273,897.94 1.57 1,441.32 MWD (2) 3,411.40 48.92 54.61 2,865.61 2,827.11 871.44 1,238.39 2,389,460.37 273,955.34 0.37 1,510.45 MWD (2) 3,503.40 48.73 54.88 2,926.18 2,887.68 911.41 1,294.93 2,389,499.25 274,012.65 0.30 1,579.53 MWD (2) 3,597.40 48.78 55.02 2,988.16 2,949.66 952.00 1,352.79 2,389,538.72 274,071.28 0.12 1,650.02 MWD (2) 3,688.40 48.75 54.89 3,048.14 3,009.64 991.29 1,408.82 2,389,576.93 274,128.05 0.11 1,718.28 MWD (2) 3,781.40 48.63 54.50 3,109.53 3,071.03 1,031.67 1,465.83 2,389,616.21 274,185.82 0.34 1,787.97 MWD (2) 3,874.40 48.71 54.73 3,170.95 3,132.45 1,072.10 1,522.77 2,389,655.55 274,243.52 0.20 1,857.65 MWD (2) 3,965.40 48.62 54.68 3,231.05 3,192.55 1,111.58 1,578.53 2,389,693.95 274,300.03 0.11 1,925.82 MWD (2) 4,059.40 48.56 54.57 3,293.23 3,254.73 1,152.40 1,636.02 2,389,733.65 274,358.29 0.11 1,996.16 MWD (2) 4,121.40 48.54 54.65 3,334.27 3,295.77 1,179.31 1,673.90 2,389,759.83 274,396.68 0.10 2,042.53 MWD (2) 4,214.40 47.30 54.72 3,396.59 3,358.09 1,219.21 1,730.23 2,389,798.65 274,453.76 1.33 2,111.40 MWD (2) 4,307.40 46.10 53.40 3,460.37 3,421.87 1,258.93 1,785.02 2,389,837.31 274,509.31 1.65 2,178.96 MWD (2) 4,403.40 44.66 53.35 3,527.80 3,489.30 1,299.69 1,839.86 2,389,877.01 274,564.92 1.50 2,247.22 MWD (2) 4,493.40 43.40 52.80 3,592.51 3,554.01 1,337.27 1,889.87 2,389,913.62 274,615.64 1.46 2,309.73 MWD (2) 4,586.40 42.20 52.70 3,660.74 3,622.24 1,375.51 1,940.17 2,389,950.90 274,666.66 1.29 2,372.88 MWD (2) 12/2/2015 12:46:32PM Page 3 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Cannery Loop Unit 05 Project: Kenai C.I.U. TVD Reference: Actual @ 38.50usft Site: Cannery Loop Unit #1 Pad MD Reference: Actual @ 38.50usft Well: Cannery Loop Unit 05 North Reference: True Wellbore: Cannery Loop Unit 05RD Survey Calculation Method: Minimum Curvature Design: CLU05RD Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-9 +E/ -W Northing Easting DLS Section (usft) (I (I (usft) (usft) (usft) (usft) (ft) (ft) (°/low) (ft) Survey Tool Name 4,680.40 41.10 51.90 3,730.98 3,692.48 1,413.71 1,989.60 2,389,988.14 274,716.82 1.30 2,435.32 MWD (2) 4,773.40 39.82 52.06 3,801.74 3,763.24 1,450.88 2,037.14 2,390,024.39 274,765.06 1.38 2,495.66 MWD (2) 4,865.40 38.54 52.63 3,873.05 3,834.55 1,486.39 2,083.15 2,390,059.01 274,811.74 1.45 2,553.76 MWD (2) 4,955.40 37.73 52.13 3,943.84 3,905.34 1,520.32 2,127.17 2,390,092.08 274,856.41 0.96 2,609.31 MWD (2) 5,051.40 36.20 52.28 4,020.55 3,982.05 1,555.69 2,172.79 2,390,126.58 274,902.69 1.60 2,667.02 MWD (2) 5,143.40 35.29 51.29 4,095.22 4,056.72 1,588.93 2,215.01 2,390,159.01 274,945.55 1.17 2,720.75 MWD(2) 5,236.40 33.90 51.32 4,171.77 4,133.27 1,621.95 2,256.22 2,390,191.22 274,987.39 1.49 2,773.55 MWD (2) 5,328.40 31.97 51.98 4,248.98 4,210.48 1,652.98 2,295.44 2,390,221.50 275,027.19 2.13 2,823.56 MWD (2) 5,419.40 29.77 52.42 4,327.08 4,288.58 1,681.60 2,332.33 2,390,249.41 275,064.62 2.43 2,870.24 MWD (2) 5,513.40 28.32 53.13 4,409.26 4,370.76 1,709.22 2,368.66 2,390,276.32 275,101.48 1.59 2,915.85 MWD (2) 5,604.40 26.90 53.67 4,489.90 4,451.40 1,734.36 2,402.52 2,390,300.81 275,135.81 1.58 2,957.97 MWD (2) 5,696.40 25.72 53.59 4,572.36 4,533.86 1,758.54 2,435.35 2,390,324.36 275,169.10 1.28 2,998.70 MWD (2) 5,788.40 24.01 54.85 4,655.83 4,617.33 1,781.17 2,466.72 2,390,346.38 275,200.90 1.95 3,037.31 MWD (2) 5,681.40 23.05 53.83 4,741.10 4,702.60 1,802.81 2,496.89 2,390,367.43 275,231.48 1.12 3,074.37 MWD (2) 5,975.40 21.49 53.52 4,828.09 4,789.59 1,823.91 2,525.59 2,390,387.98 275,260.58 1.66 3,109.95 MWD (2) 6,067.40 20.06 51.89 4,914.10 4,875.60 1,843.67 2,551.56 2,390,407.24 275,286.92 1.68 3,142.56 MWD (2) 6,162.40 18.72 51.80 5,003.71 4,965.21 1,863.15 2,576.36 2,390,426.24 275,312.09 1.41 3,174.09 MWD (2) 6,254.40 16.89 50.74 5,091.30 5,052.80 1,880.74 2,598.31 2,390,443.41 275,334.38 2.02 3,202.22 MWD (2) 6,348.40 15.40 53.67 5,181.59 5,143.09 1,896.78 2,618.94 2,390,459.04 275,355.31 1.81 3,228.34 MWD (2) 6,440.40 13.96 55.29 5,270.59 5,232.09 1,910.33 2,637.91 2,390,472.23 275,374.53 1.63 3,251.60 MWD (2) 6,527.00 12.89 55.36 5,354.82 5,316.32 1,921.77 2,654.44 2,390,483.35 275,391.28 1.24 3,271.65 MWD _InterpAzi(3) 6,569.22 15.02 54.12 5,395.79 5,357.29 1,927.66 2,662.75 2,390,489.08 275,399.70 5.09 3,281.80 MWD _InterpAzi (3) 6,630.93 18.11 52.74 5,454.94 5,416.44 1,938.15 2,676.87 2,390,499.30 275,414.02 5.05 3,299.38 MWD _InterpAzi(3) 6,693.06 20.89 51.69 5,513.50 5,475.00 1,950.87 2,693.25 2,390,511.70 275,430.64 4.51 3,320.11 MWD_InterpAzi(3) 6,754.62 22.91 50.86 5,570.61 5,532.11 1,965.24 2,711.15 2,390,525.72 275,448.82 3.32 3,343.07 MWD_InterpAzi(3) 6,816.72 24.28 50.18 5,627.52 5,589.02 1,981.04 2,730.34 2,390,541.16 275,468.30 2.25 3,367.92 MWD+SC+sag (4) 6,878.52 26.53 46.62 5,683.34 5,644.84 1,998.66 2,750.13 2,390,558.39 275,488.43 4.40 3,394.40 MWD+SC+sag (4) 6,941.32 28.05 46.13 5,739.15 5,700.65 2,018.53 2,770.97 2,390,577.86 275,509.64 2.45 3,423.10 MWD+SC+sag (4) 7,002.65 30.30 43.22 5,792.70 5,754.20 2,039.80 2,791.96 2,390,598.72 275,531.04 4.34 3,452.82 MWD+SC+sag (4) 7,064.57 31.76 43.58 5,845.76 5,807.26 2,062.99 2,813.90 2,390,621.49 275,553.42 2.38 3,484.47 MWD+SC+sag (4) 7,127.61 32.06 43.48 5,899.27 5,860.77 2,087.15 2,836.85 2,390,645.20 275,576.82 0.48 3,517.52 MWD+SC+sag (4) 7,189.38 32.10 42.27 5,951.61 5,913.11 2,111.19 2,859.17 2,390,668.81 275,599.60 1.04 3,550.02 MWD+SC+sag (4) 7,251.09 33.98 43.88 6,003.34 5,964.84 2,135.76 2,882.15 2,390,692.93 275,623.05 3.36 3,583.35 MWD+SC+sag (4) 7,311.96 34.09 44.44 6,053.78 6,015.28 2,160.20 2,905.89 2,390,716.91 275,647.25 0.55 3,617.20 MWD+SC+sag (4) 7,375.31 34.76 43.58 6,106.04 6,067.54 2,185.95 2,930.77 2,390,742.19 275,672.62 1.31 3,652.76 MWD+SC+sag (4) 7,437.34 33.98 45.49 6,157.24 6,118.74 2,210.92 2,955.32 2,390,766.68 275,697.65 2.15 3,687.56 MWD+SC+sag (4) 7,498.39 33.93 45.56 6,207.88 6,169.38 2,234.81 2,979.65 2,390,790.10 275,722.43 0.10 3,721.52 MWD+SC+sag (4) 7,561.02 34.00 44.89 6,259.82 6,221.32 2,259.45 3,004.49 2,390,814.26 275,747.74 0.61 3,756.34 MWD+SC+sag (4) 7,622.70 33.73 44.83 6,311.04 6,272.54 2,283.81 3,028.73 2,390,838.15 275,772.45 0.44 3,790.53 MWD+SC+sag (4) 7,684.35 34.05 45.97 6,362.21 6,323.71 2,307.95 3,053.21 2,390,861.81 275,797.38 1.15 3,824.75 MWD+SC+sag (4) 12/2/2015 12:46:32PM Page 4 COMPASS 5000.1 Build 73 Company: Hilcorp Energy Company Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 05 Wellbore: Cannery Loop Unit 05RD Design: CLU05RD Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Cannery Loop Unit 05 Actual @ 38.50usft Actual @ 38.50usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Survey - - Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (I (I (usft) Nall) (usft) (usft) (ft) (ft) (°/low) (ft) Survey Tool Name 7,746.52 33.88 45.71 6,413.78 6,375.28 2,332.15 3,078.13 2,390,885.53 275,822.76 0.36 3,859.35 MWD+SC+sag (4) 7,808.23 33.68 45.67 6,465.07 6,426.57 2,356.11 3,102.68 2,390,909.02 275,847.77 0.33 3,893.53 MWD+SC+sag (4) 7,870.14 34.15 46.67 6,516.45 6,477.95 2,380.03 3,127.60 2,390,932.46 275,873.14 1.18 3,927.96 MWD+SC+sag (4) 7,932.15 34.06 47.32 6,567.79 6,529.29 2,403.75 3,153.03 2,390,955.68 275,899.02 0.61 3,962.65 MWD+SC+sag (4) 7,992.91 33.78 45.67 6,618.21 6,579.71 2,427.09 3,177.62 2,390,978.54 275,924.05 1.58 3,996.46 MWD+SC+sag (4) 8,056.17 33.84 45.35 6,670.77 6,632.27 2,451.76 3,202.73 2,391,002.73 275,949.63 0.30 4,031.51 MWD+SC+sag (4) 8,114.59 33.64 45.50 6,719.35 6,680.85 2,474.53 3,225.84 2,391,025.05 275,973.18 0.37 4,063.81 MWD+SC+sag (4) 8,180.33 33.89 44.08 6,774.01 6,735.51 2,500.46 3,251.58 2,391,050.48 275,999.41 1.26 4,100.15 MWD+SC+sag (4) 8,242.37 33.73 43.91 6,825.55 6,787.05 2,525.29 3,275.56 2,391,074.85 276,023.86 0.30 4,134.43 MWD+SC+sag (4) 8,304.33 33.47 43.27 6,877.16 6,838.66 2,550.13 3,299.20 2,391,099.23 276,047.97 0.71 4,168.44 MWD+SC+sag (4) 8,366.33 34.64 45.11 6,928.53 6,890.03 2,575.01 3,323.40 2,391,123.65 276,072.65 2.51 4,202.93 MWD+SC+sag (4) 8,428.22 34.39 45.21 6,979.53 6,941.03 2,599.74 3,346.27 2,391,147.89 276,097.98 0.41 4,237.83 MWD+SC+sag (4) 8,490.03 34.15 44.68 7,030.60 6,992.10 2,624.38 3,372.86 2,391,172.05 276,123.04 0.62 4,272.45 MWD+SC+sag (4) 8,551.13 33.84 43.77 7,081.26 7,042.76 2,648.85 3,396.69 2,391,196.07 276,147.33 0.98 4,306.39 MWD+SC+sag (4) 8,614.14 33.25 43.86 7,133.78 7,095.28 2,673.98 3,420.79 2,391,220.73 276,171.92 0.94 4,340.95 MWD+SC+sag (4) 8,675.64 34.49 45.22 7,184.84 7,146.34 2,698.40 3,444.83 2,391,244.68 276,196.42 2.36 4,375.02 MWD+SC+sag(4) 8,737.88 34.52 44.88 7,236.13 7,197.63 2,723.31 3,469.79 2,391,269.11 276,221.85 0.31 4,410.10 MWD+SC+sag (4) 8,799.11 34.19 44.25 7,286.68 7,248.18 2,747.93 3,494.03 2,391,293.26 276,246.56 0.79 4,444.45 MWD+SC+sag (4) 8,861.51 34.82 45.02 7,338.10 7,299.60 2,773.08 3,518.87 2,391,317.93 276,271.88 1.23 4,479.59 MWD+SC+sag (4) 8,924.03 34.38 44.64 7,389.57 7,351.07 2,798.26 3,543.90 2,391,342.62 276,297.38 0.78 4,514.90 MWD+SC+sag (4) 8,984.59 35.24 45.46 7,439.29 7,400.79 2,822.68 3,568.37 2,391,366.57 276,322.32 1.62 4,549.30 MWD+SC+sag (4) 9,048.38 34.88 45.72 7,491.50 7,453.00 2,848.32 3,594.54 2,391,391.70 276,348.98 0.61 4,585.79 MWD+SC+sag (4) 9,108.06 34.67 45.23 7,540.52 7,502.02 2,872.19 3,618.81 2,391,415.10 276,373.70 0.59 4,619.68 MWD+SC+sag (4) 9,173.61 34.63 44.65 7,594.45 7,555.95 2,898.57 3,645.14 2,391,440.97 276,400.53 0.51 4,656.76 MWD+SC+sag (4) 9,235.35 34.11 44.32 7,645.41 7,606.91 2,923.44 3,669.56 2,391,465.37 276,425.42 0.89 4,691.40 MWD+SC+sag (4) 9,297.11 34.13 43.95 7,696.54 7,658.04 2,948.30 3,693.68 2,391,489.76 276,450.02 0.34 4,725.81 MWD+SC+sag (4) 9,358.04 34.04 45.37 7,747.00 7,708.50 2,972.59 3,717.68 2,391,513.58 276,474.48 1.31 4,759.76 MWD+SC+sag (4) 9,421.37 33.88 45.74 7,799.53 7,761.03 2,997.36 3,742.94 2,391,537.87 276,500.21 0.41 4,794.98 MWD+SC+sag (4) 9,482.93 33.27 45.60 7,850.82 7,812.32 3,021.15 3,767.29 2,391,561.19 276,525.01 1.00 4,828.89 MWD+SC+sag (4) 9,544.75 32.68 44.91 7,902.68 7,864.18 3,044.83 3,791.19 2,391,584.41 276,549.36 1.13 4,862.38 MWD+SC+sag (4) 9,607.06 30.31 45.61 7,955.81 7,917.31 3,067.75 3,814.31 2,391,606.88 276,572.91 3.85 4,894.78 MWD+SC+sag (4) 9,667.98 28.08 46.77 8,008.99 7,970.49 3,088.32 3,835.74 2,391,627.04 276,594.73 3.78 4,924.40 MWD+SC+sag (4) 9,729.86 25.72 47.69 8,064.17 8,025.67 3,107.34 3,856.28 2,391,645.66 276,615.64 3.87 4,952.33 MWD+SC+sag (4) 9,793.26 23.89 46.32 8,121.71 8,083.21 3,125.47 3,875.74 2,391,663.41 276,635.44 3.03 4,978.87 MWD+SC+sag (4) 9,855.08 21.64 46.42 8,178.72 8,140.22 3,141.97 3,893.06 2,391,679.58 276,653.07 3.64 5,002.72 MWD+SC+sag (4) 9,915.35 18.60 46.84 8,235.30 8,196.80 3,156.21 3,908.12 2,391,693.53 276,668.40 5.05 5,023.40 MWD+SC+sag (4) 9,976.56 15.43 44.84 8,293.82 8,255.32 3,168.67 3,920.99 2,391,705.73 276,681.51 5.27 5,041.24 MWD+SC+sag (4) 10,040.55 11.48 46.78 8,356.05 8,317.55 3,179.07 3,931.63 2,391,715.93 276,692.35 6.21 5,056.06 MWD+SC+sag (4) 10,100.55 7.50 52.64 8,415.21 8,376.71 3,185.54 3,939.10 2,391,722.25 276,699.94 6.82 5,065.94 MWD+SC+sag (4) 10,162.92 4.20 57.77 8,477.25 8,438.75 3,189.23 3,944.27 2,391,725.84 276,705.18 5.35 5,072.27 MWD+SC+sag (4) 12/212015 12:46:32PM Page 5 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Cannery Loop Unit 05 Project: Kenai C.I.U. TVD Reference: Actual @ 38.50usft Site: Cannery Loop Unit #1 Pad MD Reference: Actual @ 38.50usft Well: Cannery Loop Unit 05 North Reference: True Wellbore: Cannery Loop Unit 05RD Survey Calculation Method: Minimum Curvature Design: CLU05RD Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) III (I (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 10,483.40 1.49 56.43 8,797.31 8,758.81 3,197.79 3,957.67 2,391,734.15 276,718.74 0.85 5,088.07 MWD+SC+sag (5) 10,548.80 1.96 55.16 8,862.68 8,824.18 3,198.90 3,959.30 2,391,735.22 276,720.39 0.72 5,090.03 MWD+SC+sag (5) 10,615.44 1.86 64.78 8,929.28 8,890.78 3,200.01 3,961.21 2,391,736.30 276,722.32 0.50 5,092.22 MWD+SC+sag (5) 10,681.04 1.57 68.46 8,994.85 8,956.35 3,200.79 3,963.01 2,391,737.05 276,724.14 0.47 5,094.11 MWD+SC+sag (5) 10,747.06 1.64 68.99 9,060.84 9,022.34 3,201.47 3,964.73 2,391,737.68 276,725.87 0.11 5,095.87 MWD+SC+sag (5) 10,812.43 0.80 4.12 9,126.20 9,087.70 3,202.26 3,965.64 2,391,738.46 276,726.80 2.28 5,097.07 MWD+SC+sag (5) 10,878.05 1.08 334.35 9,191.81 9,153.31 3,203.27 3,965.41 2,391,739.48 276,726.58 0.84 5,097.53 MWD+SC+sag (5) 10,944.00 1.59 303.96 9,257.75 9,219.25 3,204.34 3,964.38 2,391,740.57 276,725.57 1.30 5,097.41 MWD+SC+sag (5) 11,010.33 1.66 299.44 9,324.05 9,285.55 3,205.33 3,962.78 2,391,741.58 276,723.99 0.22 5,096.79 MWD+SC+sag (5) 11,075.50 1.87 305.57 9,389.19 9,350.69 3,206.41 3,961.09 2,391,742.70 276,722.33 0.43 5,096.17 MWD+SC+sag (5) 11,141.44 1.82 308.51 9,455.09 9,416.59 3,207.69 3,959.40 2,391,744.01 276,720.66 0.16 5,095.66 MWD+SC+sag (5) 11,206.82 2.08 308.41 9,520.44 9,481.94 3,209.07 3,957.65 2,391,745.43 276,718.94 0.40 5,095.19 MWD+SC+sag(5) 11,273.85 1.36 300.69 9,587.44 9,548.94 3,210.23 3,956.02 2,391,746.62 276,717.33 1.13 5,094.65 MWD+SC+sag (5) 11,338.76 1.19 292.70 9,652.33 9,613.83 3,210.89 3,954.73 2,391,747.30 276,716.06 0.38 5,094.07 MWD+SC+sag (5) 11,404.09 1.18 303.82 9,717.65 9,679.15 3,211.52 3,953.55 2,391,747.95 276,714.88 0.35 5,093.56 MWD+SC+sag (5) 11,469.72 1.09 299.71 9,783.26 9,744.76 3,212.21 3,952.44 2,391,748.66 276,713.79 0.18 5,093.13 MWD+SC+sag (5) 11,535.89 1.07 290.83 9,849.42 9,810.92 3,212.74 3,951.32 2,391,749.21 276,712.68 0.25 5,092.60 MWD+SC+sag (5) 11,602.37 1.08 308.99 9,915.89 9,877.39 3,213.36 3,950.25 2,391,749.85 276,711.62 0.51 5,092.16 MWD+SC+sag (5) 11,663.83 1.05 312.54 9,977.34 9,938.84 3,214.10 3,949.39 2,391,750.61 276,710.77 0.12 5,091.96 MWD+SC+sag (5) 11,723.32 0.99 310.21 10,036.82 9,998.32 3,214.80 3,948.59 2,391,751.33 276,709.99 0.12 5,091.79 MWD+SC+sag (5) 11,798.75 0.35 250.83 10,112.24 10,073.74 3,215.15 3,947.88 2,391,751.69 276,709.28 1.15 5,091.45 MWD+SC+sag (5) 11,865.17 0.06 188.28 10,178.66 10,140.16 3,215.04 3,947.68 2,391,751.59 276,709.09 0.49 5,091.24 MWD+SC+sag(5) 11,931.25 0.00 89.07 10,244.74 10,206.24 3,215.01 3,947.68 2,391,751.55 276,709.08 0.09 5,091.21 MWD+SC+sag (5) 11,996.98 0.29 25.82 10,310.47 10,271.97 3,215.16 3,947.75 2,391,751.70 276,709.16 0.44 5,091.36 MWD+SC+sag (5) 12,062.67 0.34 16.66 10,376.16 10,337.66 3,215.50 3,947.88 2,391,752.04 276,709.29 0.11 5,091.67 MWD+SC+sag (5) 12,124.34 0.43 359.78 10,437.83 10,399.33 3,215.90 3,947.93 2,391,752.44 276,709.35 0.23 5,091.97 MWD+SC+sag (5) 12,186.88 0.44 341.34 10,500.37 10,461.87 3,216.37 3,947.85 2,391,752.91 276,709.28 0.22 5,092.20 MWD+SC+sag(5) 12,248.94 0.70 260.89 10,562.43 10,523.93 3,216.53 3,947.40 2,391,753.08 276,708.83 1.23 5,091.96 MWD+SC+sag (5) 12,310.61 1.13 265.29 10,624.09 10,585.59 3,216.42 3,946.42 2,391,752.99 276,707.85 0.71 5,091.13 MWD+SC+sag (5) 12,372.23 0.90 244.07 10,685.70 10,647.20 3,216.16 3,945.38 2,391,752.75 276,706.81 0.71 5,090.16 MWD+SC+sag (5) 12,433.92 0.93 242.96 10,747.38 10,708.88 3,215.72 3,944.50 2,391,752.33 276,705.92 0.06 5,089.20 MWD+SC+sag (5) 12,497.41 1.00 233.22 10,810.86 10,772.36 3,215.15 3,943.60 2,391,751.78 276,705.00 0.28 5,088.14 MWD+SC+sag (5) 12,558.82 0.82 232.28 10,872.27 10,833.77 3,214.57 3,942.82 2,391,751.20 276,704.22 0.29 5,087.17 MWD+SC+sag (5) 12,619.76 0.68 231.96 10,933.20 10,894.70 3,214.08 3,942.19 2,391,750.72 276,703.58 0.23 5,086.37 MWD+SC+sag (5) 12,683.10 0.64 232.60 10,996.54 10,958.04 3,213.63 3,941.61 2,391,750.29 276,702.99 0.06 5,085.64 MWD+SC+sag (5) 12,744.91 0.57 233.10 11,058.34 11,019.84 3,213.23 3,941.09 2,391,749.90 276,702.46 0.11 5,084.99 MWD+SC+sag (5) 12,806.95 1.02 246.64 11,120.38 11,081.88 3,212.83 3,940.34 2,391,749.52 276,701.70 0.78 5,084.15 MWD+SC+sag (5) 12,868.91 0.89 246.87 11,182.33 11,143.83 3,212.42 3,939.39 2,391,749.13 276,700.75 0.21 5,083.16 MWD+SC+sag(5) 12,901.73 1.05 246.24 11,215.14 11,176.64 3,212.20 3,938.88 2,391,748.91 276,700.23 0.49 5,082.62 MWD+SC+sag (5) 12,940.00 1.05 246.24 11,253.41 11,214.91 3,211.92 3,938.24 2,391,748.64 276,699.59 0.00 5,081.94 PROJECTEDtoTD 12/2/2015 12:46:32PM Page 6 COMPASS 5000.1 Build 73 Company: Hilcorp Energy Company Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 05 Wellbore: Cannery Loop Unit 05RD Design: CLU05RD Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Cannery Loop Unit 05 Actual @ 38.50usft Actual @ 38.50usft True Minimum Curvature Sperry EDM - NORTH US + CANADA 1212/2015 12.46:32PM Page 7 COMPASS 5000.1 Build 73 rian.w er@ a i urt Checked By: on.com P ,tea» Approved By: cary.tayIor@haIIIburton.com � Date: 1212/2015 12.46:32PM Page 7 COMPASS 5000.1 Build 73 6000 6500 7000 7500 8000 8500 9000 s EL 9500 a 0 a 10000 m d 10500 11000 11500 12000 12500 13000 13500 CLU-05RD Days vs Depth CLU-05RD Actual CLU-05RD Plan 0 5 10 15 20 25 30 35 40 45 Days 1/29/2016 1:17 PM 5000 6000 7000 8000 CLU-OSRD MW vs Depth C 10000 11000 12000 13000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density (ppg) Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No. Kenai Gas Field CLU 05RD County Kenai Peninsula Burough State Alaska CASING RECORD TO 10450.00 Shoe Depth: 10448.00 SZ J et —7 g Date 30 -Oct -15 Supv. Rance Pederson/Marvin Rol PBTD: 10,300' MD Csg W. On Hook: 116,000 Type Float Collar: Float No. Hrs to Run: Csg W. On Slips: 115,00 on hanger Type of Shoe: DJ/Float Casing Crew: Fluid Description: 9,1 Liner hanger Info (Make/Model): "HRD-E" ZXP, RS, Flex -Lock Liner top Packer?: Liner hanger test pressure: 1170 Centralizer Placement: NA CEMENTING REPORT 35 x Yes No Preflush (Spacer) Casing (Or Liner) Detail Setting Depths No. of As. Size W. Grade THD Make Length Bottom Top Shoe 75/8 Density (ppg) 15.3 ppg SLIJ-II Baker 2.22 10,448.00 10,445.78 2 75/8 L-80 SLIJ-II VAM 81.33 10,445.78 10,364.45 F. Collar 75/8 Post Flush (Spacer) SLIJ-11 Baker 1.98 10,364.45 10,362.47 1 jt & pup 75/8 L-80 SLIJ-II VAM 60.76 10,362.47 10,301.71 L.C. 75/8 L-80 SLIJ-II Baker 1.69 10,301.71 10,300.02 76 As & pup 75/8 L-80 SLIJ-II VAM 3,389.87 10,300.02 6,910.15 XO & 11 jts 75/8 L-80 Hyd 511 Hydril 442.93 6,910.15 6,467.22 ZXP hanger 1 75/8 1 Lead Slurry Baker 34.10 6,467.22 6,433.12 Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Totals w Type: F 6,433.12 Csg W. On Hook: 116,000 Type Float Collar: Float No. Hrs to Run: Csg W. On Slips: 115,00 on hanger Type of Shoe: DJ/Float Casing Crew: Fluid Description: 9,1 Liner hanger Info (Make/Model): "HRD-E" ZXP, RS, Flex -Lock Liner top Packer?: Liner hanger test pressure: 1170 Centralizer Placement: NA CEMENTING REPORT 35 x Yes No Make Test Head To Remarks: Cameron Type 4000 PSIG VVtLLHt/iU DCB -S Serial No. 10 MIN X OK Size 11" W.P. 5000 Preflush (Spacer) Type: Mud Push II Density (ppg) 12.5 Volume pumped (BBLs) 21.6 Lead Slurry Type: Class G Easy Blok Density (ppg) 15.3 ppg Volume pumped (BBLs) 102.7 Mixing / Pumping Rate (bpm): 3 Tail Slurry Type: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): N Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: E Displacement: Type: 6% kcl Density (ppg) 9.1 ppg Rate (bpm): 4 bpm Volume (actual /calculated): 265 bbls / 267 bbls FCP (psi): 1300 Pump used for disp: Rig & Schlumberger Plug Bumped? X Yes No Bump press 2700 Casing Rotated? Yes X No Reciprocated? x No % Returns during job 0 Cement returns to surface? _Yes _Yes X No Spacer returns?_ Yes X No Vol to Surf. 0 bbls Cement In Place At: 2:30 Date: 10/30/2015 Estimated TOC: 10,233 Method Used To Determine TOC: Calculated from press increase when displacing Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry w Type: F Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): o Post Flush (Spacer) o Type: Density (ppg) Rate (bpm): Volume: yDisplacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: Plug Bumped? _ Yes No Bump press Casing Rotated? Yes _ No Reciprocated? _ Yes _ No % Returns during job Cement returns to surface? _Yes -No Spacer returns?_ Yes No Vol to Surf. Cement In Place At: Date: _ Estimated TOC: Method Used To Determine TOC: Make Test Head To Remarks: Cameron Type 4000 PSIG VVtLLHt/iU DCB -S Serial No. 10 MIN X OK Size 11" W.P. 5000 Lease & Well No. Hilcorp Energy Company CASING & CEMENTING REPORT CLU 005RD County State Alaska CASING RECORD Production V TO 12,940.00 Shoe Depth: 12,915.00 RKB 18.00 RKB to BHF RKB to CHF Date Run 15 -Nov -15 Supv. S Hauck / S Barber PBTD: 12,790.00 RKB to THF 18.00 Csg Wt. On Hook: 190,000 Type Float Collar: WFD model #402E No. Hrs to Run: Casing (Or Liner) Detail Csg W. On Slips: 30,000 Type of Shoe: WFD Reaming Casing Crew: Setting Depths As. Component Size W[. Grade THD Make Length Bottom Top Shoe 53/4 Liner top Packer?: DWC/C Weatherford 2.26 12,915.00 12,912.74 2 Casing 41/2 12.6 L-80 DWC/C 79.42 12,912.74 12,833.32 Float Collar 5 FC @ 12,831.91 DWC/C Weatherford 1.41 12,833.32 12,831.91 1 Casing 41/2 12.6 L-80 DWC/C Density (ppg) 12.5 40.43 12,831.91 12,791.48 Landing Collar 5 DWC/C 1.14 12,791.48 12,790.34 65 Casing 41/2 12.6 L-80 DWC/C Mixing / Pumping Rate (bpm): 2,941.66 12,790.34 10,298.68 Seal Bore Extenstion 51/2 Hydril 563 Baker 26.44 10,298.68 10,272.24 Liner Top Packer Density (ppg) 15.3 Volume pumped (BBLs) 75 Mixing / Pumping Rate (bpm): 4 Baker 32.35 10,272.24 10,239.89 LL Type: Density (ppg) Rate (bpm): Volume: Displacement: Csg Wt. On Hook: 190,000 Type Float Collar: WFD model #402E No. Hrs to Run: 27.5 Csg W. On Slips: 30,000 Type of Shoe: WFD Reaming Casing Crew: Weatherford Rotate Csg X Yes No Recip Csg _ Yes X No Ft. Min. 11.6 PPG Fluid Description: KCL Mud Liner hanger Info (Make/Model): Baker HRD-E ZXP, RS, Flex -Lock Liner top Packer?: X Yes No Liner hanger test pressure: 3500 Floats Held _ X Yes No Centralizer Placement: Ran 18 centralizers starting w/ It # 27 on every otherjt to # 61. _ CEMENTING REPORT Shoe @ 12915 FC @ 12,831.91 Top of Liner 10239.89 Preflush (Spacer) Type: MudPush Density (ppg) 12.5 Volume pumped (BBLs) 20 Lead Slurry Type: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Lu Type: GasBlok Class "G' r Density (ppg) 15.3 Volume pumped (BBLs) 75 Mixing / Pumping Rate (bpm): 4 r Post Flush (Spacer) LL Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: KCL Mud Density (ppg) 11.6 Rate (bpm): 5 Volume (actual / calculated) 178/177 (psi): 1250 ig Rotated? ant returns to surface? ant In Place At: od Used To Determine TOC Pump used for disp: SLB Bump Plug? X Yes No Bump press 2800 X_Yes _No Reciprocated? Yes X No % Returns during job 100 Yes X No Spacer returns? _ Yes X No Vol to Surf: 0 18:58 Date: 11/15/2015 Estimated TOC: 10,239 Calc lift / volume pumped Post Job Calculations: Calculated Cmt Vol @ 0% excess: 54.6 Total Volume cmt Pumped: 75 Cmt returned to surface: 0 Calculated cement left in wellbore: 75 OH volume Calculated: 41.4 OH volume actual: 61.8 Actual % Washout: 50 WELLHEAD Make CIW Type DCB -S Serial No. Size 13.63 W.P. 5000 Test head to 5000 PSIG 250 MIN yes OK Remarks: www.weliez.net WellEz Information LLC ver /LL 6 Seth Nolan GeoTech Ili lr#rrlm la skis. 1.1.4, E C E' V^ D JAN 22 2015 AOGM DATE 01/20/2016 215150 Hilcorp Alaska, LLC 26 6 9 9 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 Fax: 907 777-8510 E-mail: snolan@hilcorp.com To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 Electric Log prints and data Prints: Gamma Ray Reservoir Monitor Tool (RMTI) Gamma Ray Cement Bond Log Gamma Ray Cement Bond log with CAST -M CD: 1 Electric logs CAST_02DEC15 CBE -RMT 21NOV15 12;30;201511:29 ... 12/30/2015 11:29 ... Please include current contact information if different from above. File fol der File fielder DATA LOGGED 2 /T1201(0 K BENDER Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: �� /�j Date: DATE 12/14/2015 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 Fax: 907 777-8510 E-mail: snolan@hilcorp.com To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 Electric log and Mudlog prints and data 215160 DATA LOGGED M K BENDER Prints: ROP-DGR-EWR-ALD-CTN 2"/5" MD/TVD, Sin Formation Log MD/TVD, tin Formation Log MD/TVD, tin LWD Combo MD/TVD, tin Gas Ratio Log MD/TVD, 2in Drilling Dynamics Log MD/TVD CD: 1 Electric logs CGI Definitive Survey DLIS+LAS EMF PDF TIFF CD: 2 Mudlogs Daily Reports DIVIL Data Final Well Report LAS Data Log PDFs Log TIFFS 16 599 Uig 2015 4:131 PM File folder 1212V2015 01 PM Filefolder 12fZ 2015 4:01 PM File folder 12r{2+'20154:01 PM File folder 12,,2`20154:01 PM Filefolder 12/2,12015 4:131 PM File folder 12'3,•`2015 3:36 PrA File folder 12;'8/2015 3:34 Prwl Fine folder 12)14;`2015 8:45 A.r,,1 File folder 121/2015 3:36 Part File folder 12,'B;'2015 3:36 PrvIl File folder 12.'14,`2-015 8:46 AM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received BvA - ,q - I Date: Ifilrnria Mafia. LI.{. DATE 11/25/2015 Seth Nolan Hilcorp Alaska, LLC GeoTech 3000 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 Fax: 907 777-8510 E-mail: snolan@hilcorp.com To: Alaska Oil & Gas Conservation Commission Make. a l r► u U,-,,_rn u "'tost�- / s- 333 W 7th Ave Ste 100 Anchorage, AK 99501 nECEIVED DEC 0 9 2015 Washed and Dried Samples: 11 Boxes ^0GCC Transmitted herewith are cuttings from CLU 5RD WELL SAMPLE INTERVAL CLU 5RD 6540'- 7200' CLU 5RD 7200'- 7800' CLU 5RD 7800'- 8400' CLU 5RD 8400'- 8880' CLU 5RD 8880'- 9420' CLU 5RD 9420'- 9945' CLU 5RD 9945'- 10650' CLU 5RD 10650'- 11295 CLU 5RD 11295'- 11850' CLU 5RD 11850'- 12390' CLU 5RD 12390'- 12940' Please include current contact information if different from above. 2l5 -1, (,O 1510 (o Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 THE STATE Alaska Oil and Gas DMC1 Conservation Commission GOVERNOR BILL WALKER 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Z-` Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Cannery Loop Field, Tyonek D Gas Pool, CLU 05RD Sundry Number: 315-705 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P, oerster Chair DATED this � day of November, 2015 Encl. RBDMS*tC 0 4 2015 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 2s 2An RECEIVED NOV 19 2015 ,G 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ �-+•''� Perforate El, Other Stimulate ❑ Pull Tubing ❑ Change Approved ProN�jaam ❑ Plug for Redrill El Perforate New Pool EJRe-enterSusp Well ElAlter Casing ❑ Other. CT Jetting_❑✓ 2. Operator Name: Hilcorp Alaska, LLC 4. Current Well Class: 5. Permit to Drill Number: Exploratory ❑ Development Q " Strati ra hic ❑ g p ❑ Service 215-160 3. Address: 3800 Centerpoint Drive, Suite 1400 p 6. API Number: Anchorage, Alaska 99503 50-133-20474-01 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 231. Rule 3 Will planned perforations require a spacing exception? Yes ❑ No 0 Cannery Loop Unit (CLU) 05RD " 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 060569; ADL 324602 Cannery Loop / Tyonek D Gas Pod 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,940' 11,254' 12,832' 11,146' 4,938 psig N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 142' 20" 142' 142' Surface 2,970' 13-3/8" 2,970' 2,578' 3,090psi 1,540psi Intermediate 1,212' 9-5/8" 1,212' 1,200' 7,930psi 6,620psi Intermediate 7,966' 9-5/8" 9,178' 7,599' 9,440psi 5,300psi Liner 4,048' 7-5/8" 10,448' 8,762' 6,890psi 4,790psi Liner 2,675' 4-1/2" 12,915' 11,229' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" L-80 10,240' Packers and SSSV Type: Baker ZXPN Pkr; Packers and SSSV MD (ft) and TVD (ft): 10,240' MD18,555' TVD; Baker TE -5 SSSV TR 300' MDITVD 12. Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: December 3, 2015 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Ta for Nasse - 777-8354 Email tnasse hilcor .com Printed Name Chad Helgeson Title Operations Manager Signature Phone 907-777-8405 Date ( 5 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. G 1✓( Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: � J �..%r�:> � �� `� � 1[BDIVISZDEC 0 "i 2015 Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form ❑ [:A' Required: P � APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ( _2_ lS / Submit Form and Form 10-403 Revised 11/2015 Approved application is valid r e t� of approval. Attachments in Duplicate � RPM lomt . i ilcoru Alaska, LL, Well Prognosis Well: CLU-05RD Date: 11/18/2015 Well Name: CLU-05RD API Number: 50-133-20474-01 Current Status: Drilled, not completed Leg: N/A Estimated Start Date: December 3rd, 2015 Rig: Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-160 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: 1511837C API Number: 50-133-20474-00 Maximum Expected BHP: — 5,946 psi @ 10,078' TVD (Original 0.59 psi/ft gradient) Max. Predicted Surface Pressure: — 4,938 psi �,.= (0.10 psi/ft gas gradient) Brief Well Summary CLU-05RD is a sidetracked well targeting gas sands in the Beluga and Tyonek formations. This new well reached TD on 11/06/15. The purpose of this work/sundry is to jet the well dry with coiled tubing and perforate the well. No spacing exception is required; this will be the only producing well from the Tyonek "D" pool in the Cannery Loop Unit. .. Notes Regarding Wellbore Condition • Wellhead will be 10k rated, rather than 5k as initially proposed in PTD 215-160 (see attached drawing). • Well will be filled with filtered 6% KCI. • Slickline drift and tag 4-1/2" tubing prior to jetting well. Pull sleeve from SCSSV and function test. Install injection valve in chemical injection mandrel at ± 1,200'. • CBL completed prior to Saxon Rig #169 demob. Coiled Tubing Procedure: 1. MIRU Coiled Tubing, PT BOPE to 5,000 psi Hi 250 Low. Notify hrs_. in advance of BOP test. 2. RIH w/ 1-3/4" coiled tubing and 2-1/4" jet nozzle BHA to ±12,855' MD and tag PBTD. 3. PU 10ft and displace well fluids with Nitrogen. After 100 bbls have been evacuated to the open -top tank, begin holding 2,000 psig of back -pressure on the well at surface. a. Estimated volume of displaced 6% KCI is 196 bbl. 4. Leave well with ± 4,500_psi Nitrogen SITP. �V -CAP 5. POOH w/ coil. LD 2-1/4" jet nozzle BHA. 6. RD Coiled Tubing. E -Line Procedure 1. MIRU a -line and pressure control equipment. PT lubricator to 250 psi low/5,000 psi high. Note that the well is pressurized with nitrogen. a. If necessary, bleed nitrogen pressure down as requested by the RE to establish a drawdown on the formation. 2. Perforate the Tyonek sands with 2-7/8" 6 SPF 60 deg phased perf guns. All intervals are planned for 12 SPF so each zone may be shot twice. Depths are from the Halliburton MAD Pass log dated November 10`h, 2015. Send the correlation pass to Taylor Nasse and Jacob Dunston for confirmation. Hilcorp Alaska, LL Gross Proposed Perforated Intervals Well Prognosis Well: CLU-05RD Date: 11/18/2015 3. POOH. 4. Individually flow each zone through test separator and record water and gas rates. 5. If any of the sands are not commercial or wet, the zone will be permanently plugged back. 6. RD a -line. 7. Turn well over to production. 8. Within 5 days of stable production on well, notify AOGCC to witness testing of SSV and within 10 days of testing of SCSSV. Attachments: 1. Current and Proposed Wellbore Schematic 2. Coil BOPE Schematic 3. Wellhead Diagram 4. CT Flow Schematic (Forward and Reverse Jetting) Sands Top (MD) Btm (MD) FT Tyonek D -3A ±11,321 ±11,341 ±20 Tyonek D -4A ±11,455 ±11,484 ±29 Tyonek D-5 ±11,507 ±11,532 ±25 Tyonek D -5A ±11,570 ±11,596 ±68 Tyonek D-6 ±11,707 ±11,764 ±57 Well Prognosis Well: CLU-05RD Date: 11/18/2015 3. POOH. 4. Individually flow each zone through test separator and record water and gas rates. 5. If any of the sands are not commercial or wet, the zone will be permanently plugged back. 6. RD a -line. 7. Turn well over to production. 8. Within 5 days of stable production on well, notify AOGCC to witness testing of SSV and within 10 days of testing of SCSSV. Attachments: 1. Current and Proposed Wellbore Schematic 2. Coil BOPE Schematic 3. Wellhead Diagram 4. CT Flow Schematic (Forward and Reverse Jetting) Ifilcorp Alaska, LLC RKB =18' 1 �a. 20" SSSV 2 ° �t 13-3/8" 3 9-5/8" r S 7-5/8" Cannery Loop Field Well: CLU 05RD CURRENT SCHEMATIC API: 50-133-20474-00 PTD: 215-160 CASING DETAIL 8-1/2' window at 6,527' MD 5,355 TVD 4 5, 6, 7 Fl M 11,090 Jt RA My Jt 11,633 R4 K/kr Jt 12,0617 R4 Nkr A 12,474 r 41/2" PBTD =12,832' MD / 11,146' TVD TD=12,940' MD/ 11,254' TVD Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 21970' 9-5/8" Production 53.5 / L-80 / BTC 47 / P-110 / BTC 8.535" 8.681" Surf 1,212' 1,212' 9,178' 7-5/8" Liner 29.7 / L-80 / HYD 511 6.875" 6,400' 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 3.958" 10,240' 12,915' TUBING DETAIL 41/2„ 12.6# / L-80 / I BT- M 3.958" ±Surf ±1,200' 12.6# / L-80 / SuperMax 3.958" 1 ±1,200' ±10,400' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 300' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,200' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 10,240' 3.958" 4.500" 4-1/2" Seal Assembly 6 10,240' 4.500" 6.500" Liner Tie -Back Receptacle 7 10,240' 5.000" 6.672" Liner ZXPN Top Packer Updated by TWN 11-18-15 RKB =18' 1 20"� :. 2 13-3/8" 3 window at 6,527 MD 5,355' TVD 9-5/8" 1 a i 7-5/8" s, 6, 7 R4 My Jt R4 My Jt 12,060' R4 My Type 11,090' ID Top D -3A 20" D -4A 129 / N/A / N/A D-5 Surf D -5A RA Mcr Jt Surface 11,633 12.515" Surf D-6 it 12,474' r 41/2" f PBTD =12,832' MD/ 11,146' TVD TD =12,940' MD / 11,254' TVD PROPOSED SCHEMATIC Cannery Loop Field Well: CLU 05RD API: 50-133-20474-00 PTD: 215-160 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 129 / N/A / N/A N/A Surf 142' 13-3/8" Surface 61 / K-55 / BTC 12.515" Surf 2,970' 9-5/8" Production 53.5 / L-80 / BTC 47 / P-110 / BTC 8.535" 8.681" Surf 1,212' 1,212' 9,178' 7-5/8" ZXP Liner Top Packer Liner 29.7 / L-80 / HYD 511 6.875" 6,400' 10,448' 4-1/2" Liner 12.6 / L-80 / DWC/ C 1 3.958" 10,248' 12,938' TUBING DETAIL 4-1/2" 12.6# / L-80 / IBT- M 3.958" ±Surf ±1,200' 12.6# / L-80 / SuperMax 3.958" ±1,200' ±10,400' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.000" 6.750" Tubing Hanger, 4-1/2" 2 300' 3.812" 7.110" Baker TE -5 Safety Valve 3 1,200' 3.813" 6.500" 4-1/2" Chemical Injection Mandrel 4 6,433' 6.750" 8.460" 7-5/8" ZXP Liner Top Packer 5 1 10,240' 3.958" 1 4.500"1 4-1/2" Seal Assembly 6 10,240' 4.500" 1 6.500" Liner Tie -Back Receptacle 7 10,240' 5.000" 1 6.672" Liner ZXPN Top Packer Updated byTWN 11-18-15 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Size Status D -3A ±11,321' ±11,341' ±9,635' ±9,655' 12 TBD 2-7/8" 1 Proposed D -4A ±11,455' ±11,484' ±9,769' ±9,798' 12 TBD 2-7/8" Proposed D-5 ±11,507' ±11,532' ±9,821' ±9,846' 12 TBD 2-7/8" Proposed D -5A ±11,570' ±11,596' ±9,884' ±9,910' 12 TBD 2-7/8" Proposed D-6 ±11,707' ±11,764' ±10,021' ±10,078' 12 TBD 2-7/8" Proposed Updated byTWN 11-18-15 Cannery Loop Unit COIL BOPE CLU-05RD 11/18/2015 CLU-05RD 20X133/8X95/8X4% Coil Tubing BOP Blind/Shear Blind/Shear Slip Pipe Z) � "S Manual Manual 21/1610M 21/1610M Valve, Swab, CIW-FC, 4 1/1610M FE, HWO, EE trim Cross, stdd, 4 1/16 10M X 3 1/16 10M Valve, Upper Master, CIW-FC, 4 1/16 10M FE, HWO, EE trim Valve, Master, CIW-FC, 4 1/16 10M FE, HWO, DD trim Spool, 4 1/16 10M VG -42 grayloc FE x4 1/16 10M API FE top Lubricator to injection head 0 1.75" Tandem Stripper 1/1620 Blind/Shear Blind/Shear Oi Slip Pipe Mud Cross 4 1/16 10M X 4 1/16 10M Outlet w/ 2- 2 1/16 10M ful l m opening FMC valves Tquk"BA Manual Manual 21/1610M 21/1610M Valve, Wing, CIW-FC, 3 1/16 10M FE, HWO, EE trim Valve, SSV, 3 1/16 10M FE, w/ 18" Halliburton oper-air operated Grade Level Cannery Loop CLU #05 Tree cap Otis, 4 1/16 10M FE 20 x 13 3/8 x 9 5/8 x4 Y. X 6 Y. Otis Quick Union Valve, Swab, CIW-FC, 4 1/16 10M FE, HWO, EE trim Cross, stdd, 4 1/16 10M X 3 1/16 10M Valve, Upper Master, CIW-FC, 4 1/16 10M FE, HWO, EE trim Valve, Master, CIW-FC, 4 1/16 10M FE, HWO, DD trim Spool, 4 1/16 10M VG -42 grayloc FE x4 1/16 10M API FE top 104 Tubing head, CIW-DCB-S, 13 5/8 5M X 11 5M, w/ 2- 2 1/16 SM SSO, X -bottom prep, N type pins Casing head, McEvoy, 13 5/8 SM X 13 3/8" SOW bottom, w/ 2- 2 1/16 5M EFO Cannery Loop Unit CLU #05 Proposed 11/18/2015 Tubing hanger, CIW-DCB- FBB-CCL, 11 X 4 1/2 EUE lift and susp, w/ 4" type H BPV profile, 6 % EN, 2-%: npt CCL ports yeti Valve, SSV, 3 1/16 10M FE, w/ 18" Halliburton oper-air operated Adapter, CIW-EN-CCL, 11 5M Stdd x 4 1/16 10M VG -42 grayloc top, prepped for 6 Y4 EN and 2- Y2 npt CCL ports, EE material Valve, WKM-M, 2 1/16 5M FE, HWO, AA (� Qty 2 Valve, McEvoy -C, /16 5M FE, HWO, AA Open—Top Tank w/ Diffuser s up Annulus) COILED TUBING UNIT N2 JETTING FLOW SCHEMATIC Open—Top Tank w/ Diffuser riled Tubing) COILED TUBING UNIT N2 JETTING FLOW SCHEMATIC STATE OF ALASKA ALASKA OIL P%ND GAS CONSERVATION COMMISSI.,i4 RIG / BPS INSPECTION REPORT OPERATION: Drilling XX Workover Compl._ Well Name Drig Contractor: Saxon Rig# Saxon 169 Operator: Hilcorp Rep. Location: Section 7 'T. 5N - R. 11W M. S F INSPECTION ITEMS IN:C (A.) B.O.P. STACK I YES Annular preventer Pipe rams Blind rams Stack anchored Chke/kill line size All turns targeted ( chke & kill Ln.) HCR valves (chke & kill Ln.) Manual valves (chke & kill Ln.) Connections (Flgd, Whd, Clamped Drilling spool Flow Nipple Flow monitor Control lines fire protected 1 ;!INSPECTION ITEMS 16 Working pressure 17 Fluid level 18 Operating pressure 19 Pressure gauges 20 Sufficient valves 21 Regulator bypass 22 4 -way valves (actuators) 23 Blind rams handle cover 24 Driller control panel 25 Remote control panel 26 Firewall �r source (backu DATE CLU-05RD - Rep. Rance Peterson INSP!EGTION; 'ITEMS: (C.) MUD SYSTEM Pit level floats installed Flow rate sensor Mud gas separator Degasser Separator bypass Gas sensors Choke line connections Trip tank 11/9/2015 - PTD# 215-160 - Jay Compton Rig Ph.# 907-676-6728 N/A X 45 Flare/vent line X X _ 46 All turns targeted X X (downstream choke lines) X X 47 Reserve pit tankage X X 48 Personnel protective equip. avail. X X 49 All Drillsite Supervisors Trained I X 28 (Condition (leaks, hoses, ect.) X -I For Procedures X 50 H2S probes X 51 Rig housekeeping X. REMARKS: I met with Jay Compton (tour Pusher) then went to the rig. Talked with the Driller, Floorhands and Pit Watcher and all knew their roles on the rig and what they need to do during Well Control Issues. The entire Check List was conducted as a visual inspection. RECORDS: Date of Last Rig / BPS Inspection Date of Last BOP Test 11/6/2015 Resulting Non -Compliance Items: None witnessed during this inspection _ Non -Compliance not corrected & Reason: N/A Date Corrections Will Be Completed: N/A BOP Test & Results Properly Entered On Daily Record? Yes' Kill Sheet Current? Yes Distribution: AOGCC REP: Brian Bixby orig - Well File c - Oper./Rig OPERATOR REP: Jay Compton c - Database c - Trip Rpt File c - Inspector 2015-1109_Rig_Saxon169_bb.xlsx (Rev. 12/92) (D.) RIG FLOOR YES NO N/A 37 Kelly cocks (upper, lower, IBOP) X 38 Floor valves (dart, ball, ect.) X 39 Kelly & floor valve wrenches X 40 Drillers console (flow monitor, X flow rate indicator, pit level X indicators, gauges) X 41 Kill sheet up-to-date X 42 Gas detection monitors X (H2S & methane) X 43 Hydraulic choke panell X 44 IChoke manifold I X X 45 Flare/vent line X X _ 46 All turns targeted X X (downstream choke lines) X X 47 Reserve pit tankage X X 48 Personnel protective equip. avail. X X 49 All Drillsite Supervisors Trained I X 28 (Condition (leaks, hoses, ect.) X -I For Procedures X 50 H2S probes X 51 Rig housekeeping X. REMARKS: I met with Jay Compton (tour Pusher) then went to the rig. Talked with the Driller, Floorhands and Pit Watcher and all knew their roles on the rig and what they need to do during Well Control Issues. The entire Check List was conducted as a visual inspection. RECORDS: Date of Last Rig / BPS Inspection Date of Last BOP Test 11/6/2015 Resulting Non -Compliance Items: None witnessed during this inspection _ Non -Compliance not corrected & Reason: N/A Date Corrections Will Be Completed: N/A BOP Test & Results Properly Entered On Daily Record? Yes' Kill Sheet Current? Yes Distribution: AOGCC REP: Brian Bixby orig - Well File c - Oper./Rig OPERATOR REP: Jay Compton c - Database c - Trip Rpt File c - Inspector 2015-1109_Rig_Saxon169_bb.xlsx (Rev. 12/92) THE STATE 01ALASKA GOVERNOR BILL WALKER Monty Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 laskz Oil and, Gas C'anscervation Conmaissqio 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Re: Cannery Loop Field, Tyonek D Gas Pool, CLU 05RD Hilcorp Alaska, LLC Permit No: 215-160 Surface Location: 180' FSL, 270' FEL, SEC. 7, T5N, RI IW, SM, AK Bottomhole Location: 1910' FNL, 1603' FEL, SEC. 8, T5N, RI IW, SM, AK Dear Mr. Myers: Enclosed is the approved application for permit to re -drill the above referenced development 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, Cathy . Foerster Chair DATED this /6"day of September, 2015. STATE OF ALASKA AKA OIL AND GAS CONSERVATION COM (JN PERMIT TO DRILL 20 AAC 25.005 "cA•c1 v CU SEP 0 S 2015 AlOG0 1 a. Type of Work: 1 b. Proposed Well Class: Development - Oil Service - Winj Lj Single Zone ❑✓ 1 c. Specify if well is groposed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Gas Q Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑✓ • Reentry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: . Blanket ❑✓ Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 CLU 05RD ' 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage AK 99503 MD: 12,500' . TVD: 10,806' . Cannery Loop Unit Tyonek D Gas Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): i Surface: 180' FSL, 270' FEL, Sec 7, T5N, R11 W, SM, AK SHL -FEE ADL 060569 / TPH/BHL-ADL 324602 - Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 2523' FNL, 2220' FEL, Sec 8, T5N, R11 W, SM, AK N/A .1� 10/8/2015 Total Depth: 9. Acres in Property:�,� °�,` 14. Distance to Nearest Property: 1910' FNL, 1603' FEL, Sec 8, T5N, R11 W, SM, AK ADL 060569 -�Y Acres / ADL x24062' 426 Acres .. 3,060' from nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 39 1,8"feet 15. Distance to Nearest Well Open Surface: x- 272700.47 y- 2388612.841 Zone -4 GL Elevation above MSL: Meet to Same Pool: N/A 16. Deviated wells: Kickoff depth: 6,600 feet • 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 34 degrees Downhole: 4,863 psi • Surface: 3,783 psi 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) 8-1/2" 7-5/8" 29.7# L-80 Hyd 521 4,200' 6,400' 5,230' 10,600' 8,906' 578 ft3 y(3(s+ 6-3/4" 4-1/2" 12.6# L-80 DWC/C 2,100' 10,400' 8,705' 12,500' 10,806' 474 ft3 5-•) 7K Tieback 4-1/2" 12.6# L-80 IBT-M 10,400' 0 0 10,400' 8,705' Tieback Assembly 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 108' 20" 142' 142' Surface 2,936' 13-3/8" 1,790 sxs 2,970' 2,576' Intermediate 1,178' 9-5/8" 1,212' 1,200, Intermediate 7,966' 9-5/8" 1,919 sxs 9,178' 7,997' Liner 2,447' 7" 750 sxs 11,421' 10,239' Perforation Depth MD (ft): See Schematic Detail Perforation Depth TVD (ft): See Schematic Detail 20. Attachments: Property Plat Q BOP Sketch ❑✓ Drilling Program ❑✓ Time v. Depth Plot ❑✓ Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drlling Fluid Program 0 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Monty Myers Email mm ers hilcor .com Printed Name Monty Myers Title Drilling Engineer Signature Gt Phone 907-777-8431 Date 1 • ZO 1 S Commission Use Only Permit to Drill / _/ ��(�,-.-, API Number: p r L/ [ �7 Permit Approval See cover letter for other Number: -1 50-/� 7 "tel Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed metha , gas hydrates, or gas contained in shales: Other: � v y� 3 f Samples req'd: Yes ❑ N7 Mud log req'd: Ye.•E] kc' HZS measures: Yes ❑ NDF2/ Directional svy req'd: YeesX Re❑ �C;� r I�z" �er Spacing exception req'd: Yes: ❑ Nu' Inclination -only svy req'd: Yes nal' C !F P,4e Y APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ORIGINAL �Aw Form 10-401 (Revised 10/2012) This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) Submit Form and Attachments in Duplicate Monty Myers Drilling Engineer rlilem•p Alaska, LLC 9/8/2015 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Permit to Drill CLU-05RD Dear Commissioner, Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Tel 907 777 8431 Email mmyers@hilcorp.com SEP 0 8 2015 AGGCC CLU 05RD is a development gas well planned to be re -drilled in a Northeasterly direction from CLU 05, utilizing the existing casing program down to 6600' MD / 5426' TVD. At 6600' MD the parent wellbore will be sidetracked and a new wellbore will be drilled penetrating the Beluga and Upper Tyonek formations. A 4000', 8-1/2" open hole section is planned and after the depleted TY T-913 has been penetrated and drilled through a 7-5/8" flush joint drilling liner will be run and cemented to isolate the loss zone. We will drill a 1900', 6-3/4" open hole section through the remaining upper Tyonek and Deep Tyonek formations to a total depth of 12,500'. Once TD is reached a 4-1/2" production liner will be run to TD and cemented. The well will be cleaned out and swapped to clean production fluid, then a 4-1/2" production tieback assembly will be run to surface. The well will be perforated based on LWD data obtained while drilling the interval, after Saxon 169 has departed location. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and also for perforating the production interval. — r-'3 Drilling operations are expected to commence approximately October 8th, 2015. If you have any questions, please don't hesitate to contact myself at 777-8431 or Paul Mazzolini at 777-8369. Sincerely, Zs Monty Myers Drilling Engineer Hilcorp Alaska, LLC Page 1 of i Hilcorp Alaska, LLC CLU 05RD Drilling Program Cannery Loop ry d by: M My Revision 0 September 2015 CLU 05RD Drilling Procedure Rev 0 Ililcorp Alaska. L1.1: 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 Summary...........................................................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................................8 9.0 R/U and Preparatory Work.........................................................................................................................11 10.0 Mud Program and Density Selection Criteria............................................................................................11 11.0 Whipstock Running Procedure...................................................................................................................12 12.0 Whipstock Setting Procedure......................................................................................................................16 13.0 Drill 8-1/2" Hole Section..............................................................................................................................18 14.0 Run 7-5/8" Drilling Liner.............................................................................................................................21 15.0 Cement 7-5/8" Drilling Liner.......................................................................................................................24 16.0 Mud Program and Density Selection Criteria............................................................................................28 17.0 Drill 6-3/4" Hole Section..............................................................................................................................29 18.0 Run 4-1/2" Production Liner.......................................................................................................................32 19.0 Cement 4-1/2" Production Casing...............................................................................................................35 20.0 Wellbore Clean Up & Displacement...........................................................................................................39 21.0 Run 4-1/2" Tieback String...........................................................................................................................40 22.0 RDMO...........................................................................................................................................................40 23.0 BOP Schematic.............................................................................................................................................41 24.0 Wellhead Schematic.....................................................................................................................................42 25.0 Days vs Depth................................................................................................................................................43 26.0 Geo-Prog........................................................................................................................................................44 27.0 Anticipated Drilling Hazards.......................................................................................................................45 28.0 Rig Layout.....................................................................................................................................................46 29.0 FIT Procedure...............................................................................................................................................47 30.0 Choke Manifold Schematic..........................................................................................................................48 31.0 Casing Design Information..........................................................................................................................49 32.0 8-1/2" Hole Section MASP...........................................................................................................................50 33.0 6-3/4" Hole Section MASP...........................................................................................................................51 34.0 Plot (NAD 27) (Governmental Sections).....................................................................................................52 35.0 Surface Plat (As Built) (NAD 27)................................................................................................................53 36.0 Directional Program(PI) .............................................................................................................................54 1.0 Well Summary CLU 05RD Drilling Procedure Rev 0 Well CLU 05RD Pad & Old Well Designation Sidetrack of existing well CLU 05 (PTD #96-73) Planned Completion Type 4-1/2" 12.6# L-80 Liner/4-1/2" Tieback Target Reservoir(s) T onek Planned Well TD, MD / TVD 12500' MD / 10806' TVD PBTD, MD / TVD 12380' MD / 10686' TVD Surface Location (Governmental) 180' FSL, 270' FEL, Sec 7, TSN, R11 W, SM, AK Surface Location (NAD 27) X=272700.47, Y=2388612.841 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 2523' FNL, 2220' FEL, Sec 8, TSN, R1IW, SM, AK TPH Location (NAD 27) X=276084.2, Y=2391135.09 TPH Location (NAD 83) BHL (Governmental) 1910' FNL, 1603' FEL, Sec 8, TSN, R11 W, SM, AK BHL (NAD 27) X=276711.11, Y=2391736.5 BHL (NAD 83) AFE Number 1511837D AFE Drilling Das 29 AFE Drilling Amount $5.1 MM ✓� Work String 4-1/2" 16.64 5-135 CDS-40 RKB — AMSL 18' KB — 53.3' AMSL Ground Elevation 35.3' AMSL BOP Equipment 11" 5M T3 -Ener (Model 7082) Annular BOP 11" 5M T3 -Ener (Model 6011 i) Double Ram 11" 5M T3 -Energy (Model 6011i) Single Ram Page 2 Revision 0 September, 2015 I10 to Alaska, LI.1: 2.0 Management of Change Information CLU 05RD EDrilling Procedure Rev 0 11 Hileorp Alaska, LLC Hilcor F Changes to Approved Permit to Drill Date: Subject Changes to Approved Permit to Drill for CLU 05RD File #: CLU 05RD Drilling Program Any modifications to CLU 05RD Dulling Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by AOGCC, before making the change. Approval Prepared: Drilling Manager Drilling Engineer Date Date Page 3 Revision 0 September, 2015 CLU ORD Drilling Procedure Rev 0 Ililcorp Alaska, LLC 3.0 Tubular Program Hole Section OD in Wt(#/ft) Cou l OD ID in Drift in Grade Conn Top Bottom 8-1/2" 7-5/8" 29.7 7.625 6.875 6.75 L-80 HYD 511 6400 10600 6-3/4" 4-1/2" 12.6 5.0 3.918 3.833 L-80 DWC/C 10400 12500 Tieback Assy 4-1/2" 12.6 5.0 3.918 3.833 L-80 IBT-M 10400 0 4.0 Drill Pipe Information All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 September, 2015 1W) 41JIM TJ OD Wt Grade Conn Burst Collapse Tension Section in in #/ft(psi) (psi)k-lbs 8-1/2 4-1/2" 3.826 2-11/16" 5-1/4" 16.6 S-135 CDS-40 17693 16769 595k 6-3/4" All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ilil�•nr1) Alaska. LIA: 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. i. Report covers operations from 6am to 6am ii. 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. iii. Ensure time entry adds up to 24 hours total. iv. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates i. Submit a short operations update each work day to pmazzolinighilcorp.com, Ikeller o,hilcorp.com, mmyers@hilcorp.com and cdinger@hilcorp.com 5.3 5am Weekend Update i. Submit a short operations update each weekend and holiday to whoever is assigned weekend or vacation duty. Details will be sent before each weekend or holiday. ii. Copy pmazzolini@hilcorp.com, lkeller@hilcorp.com and mmyers@hilcorp.com 5.4 EHS Incident Reporting I. Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Mark Tornai: O: (907) 283-1372 C: (907) 748-3299 c. Thad Eby: O: (907) 777-8317 C: (907) 602-5178 2. Spills: Julieanna Orczewska: 0:907-777-8444 C:907-715-7060 ii. Notify Drlg Manager 1. Paul Mazzolini: O: 907-777-8369 C: 907-317-1275 iii. Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally i. Send final "As -Run" Casing tally to mmyers cghilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cmt report i. Send casing and cement report for each string of casing to mmyersghilcorp.com and cdin er o,hilcorp.com Page 5 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ilileorlo Alaska, I.I.0 6.0 Planned Wellbore Schematic .i Cannery Loop Unit .'1 Well: Cannery Loop 05RD PROPOSED SCHEMATIC API: 50-133-20474-00 EXISTING CASING DETAIL Size Type_t/ Gradej Cann ID Top �Ku 20" Conductor 129 / N/A / W.A N/A Surf 142' 13-3/5° Surface 6L/ K-55 f BTC 12.515 Surf 1,9-00' 9-5/5` Production 53.5 / L-501 BrC 47/P-111/BTC 5.535 B.68L Surf 1,21V 1,212' 9, 17V 3qBW TVD PROPOSED CASING DETAIL Type Wk/ Grade,' Conn ID Fop �Ku )rifling 29.7/L-80/HYD 511 6.875 6,4W 10,6m. Liner 3.958 10,401' 12'sw iAuction Lie12.6/L-5D/DWC/C Liner ner Prod rubing 12.68/L-IO/1lr-M1 3.958 Surf 10,401' CEMENTING DETAIL Casing Detail 75/5' w a Cass tal, a a: o sass TOCE: 6,400 ft MD, estimated (50 % excess) 41%2° mow. o cars al, ata: �7a sass TOCE:10,400 MD. estimated '50%excess) Fr r Page 6 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ililcorp Alaska. LIA: 7.0 Drilling Summary CLU 05RD is a development gas well planned to be re -drilled in a Northeasterly direction from CLU 05, utilizing the existing casing program down to 6600' MD / 5426' TVD. 9 v "w, J,..., & 1,6 r, ' A 0, At 6600' MD the parent wellbore will be sidetracked and a new wellbore will be drilled penetrating the Beluga and Upper Tyonek formations. A 4000', 8-1/2" open hole section is planned and after the depleted TY T-913 has been penetrated and drilled through a 7-5/8" flush joint drilling liner will be run and cemented W isolate tthe loss zone. We will drill a 1900', 6-3/4" open hole section through the remaining upper Tyonek and Deep Tyonek formations to a total depth of 12,500'. Once TD is reached a 4-1/2" production liner will be run to TD and cemented. The well will be cleaned out and swapped to clean production fluid, then a 4- 1/2" production tieback assembly will be run to surface. The well will be perforated based on LWD data obtained while drilling the interval, after Saxon 169 has departed location. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and also for perforating the production interval. Drilling operations are expected to commence approximately October 8�h 2015. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations pertaining to this approved drilling procedure: 1. MOB Saxon Rig #169 to CLU 05, NU and test BOPE (5 days) 2. Cut and pull dual completion string and prep wellbore. Test BOPE. (10 days) 3. Perform clean out run to _lu X6620' and test casing. (1 day) 6-/,, 4. Set Whipstock, mill 8-1/2" window at 6600'. Displace to mud. Perform FIT to 11 ppg (2 Days) 5. Drill 8-1/2" intermediate hole from 6600' to 10600' MD. (10 Days) v,.r ,u 6. Perform short trip and condition mud. POOH (1 day) 7. LD Directional Tools. RIH w 7-5/8" liner. Set liner and cement. Circ wellbore clean. (1 Days) D 8. RD cementers. Test BOPE. Begin PU drilling tools. (1 day) 9. RIH w/ 6-3/4" Drilling BHA, Drill out shoe. Perform FIT to 12 ppg. (1 day) 10. Drill 6-3/4" production hole from 10600' to 12500' MD. (4 Days) 11. Perform short trip and condition mud. POOH (1 day) 12. LD Directional Tools. RIH w 4-1/2" liner. Set liner and cement. Circ wellbore clean. (2 Days) 13. POOH, LD DP and lnr running tools. PU Scraper assembly and RIH to landing collar. (1 day) 14. Circ hole to 3% KCl production fluid, Pump chemical train to clean well. (1 day) 15. POOH, laying down DP and scraper BHA, ND BOPE, NU temp abandonment cap (1 day) 16. RDMO (1 Day) Page 7 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 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. • BOPs shall be tested at (2) week intervals during the drilling of CLU 05RD. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/5000 psi for 5/10 & subsequent tests of the BOP equipment will be to 250/5000 psi for 5/10 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, we must test ALL BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: No variance request required. Page 8 Revision 0 September, 2015 CLU ORD EDrilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) • 11" x 5M T3 -Energy (Model 7082) Annular BOP • 11" x 5M T3 -Energy Double Ram Initial Test: 250/5000 o Blind ram in btm cavity (Annular 2500 psi) 8-1/2" 0 Mud cross & • 11" x 5M T-3 Energy Single Ram 6-3/4" • 3-1/8" 5M Choke Line Subsequent Tests: • 2-1/16" x 5M Kill line 250/5000 • 3-1/8" x 2-1/16" 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Additional requirements may be stipulated on APD. Page 9 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ililcorp Alaska, 1.1.1: Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regggalaska.g_ov Guy Schwartz / Petroleum Engineer/ (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors e,alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 11ile-1) Alauka. HA: 9.0 R/U and Preparatory Work 9.1 A separate sundry will be submitted that will include the following: • MIRU Saxon rig. • Set BPV, remove tree. • N/U and test BOP. • P&A well as per Sundry 9.2 Mix mud for 8-1/2" hole section. 9.3 Set test plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.4 Verify 5" liners installed in mud pumps. • HHF-1000 Pumps are rated at 3457 psi (80%) with 5" liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 6-3/4" hole section with (1) mud pump. 10.0 Mud Program and Density Selection Criteria 10.1 8-1/2" Production hole mud program summary: Page 11 Revision 0 September, 2015 Ilile—p .%IaAa. LLC CLU 05RD Drilling Procedure Rev 0 Primary weighting material to be used for the hole section will be Barite and Calcium Carbonate. We will have barite on location to weight up the active system 1 ppg above highest anticipated MW in the event of a well control situation. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCl/PHPA fresh water based drilling fluid. Properties: System Formulation: 6% KCI / EZ Mud DP Product Concentration Water 0.905 bbl Yield Point 22 ppb (29 K chlorides) API fluid MD Density Viscosity Plastic Viscosity 0.75 ppb (initially 0.25 ppb) pH 1-2 ppb PAC -L � BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb Loss 6600'— 10600'. 9-10 ` 40-53 15-25 15-25 8.5-9.5 1 ppb System Formulation: 6% KCI / EZ Mud DP Product Concentration Water 0.905 bbl KCl 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb SOLTEX 2 ppb (if needed) BAROID 41 as required for a 9.0 — 10.0 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) 10.2 Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 10.3 A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. 11.0 Whipstock Running Procedure Page 12 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 11.1 Set wearbushing in wellhead. Ensure ID of wearbushing is > 8-1/2" 11.2 M/U window milling assembly and TIH w/ 4-1/2" DP off of pipe rack. • Use an 8-1/2" taper mill and a 8-1/2" string mill above to ensure whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. • Drift DP prior to RIH. • Lightly wash and ream any tight spots noted. 11.3 TIH to CIBP (6,620' MD). 11.4 CBU & circ at least (1) hi -vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the Whipstock. 11.5 TOH. 11.6 Test BOPE to 250 / 5000 psi for 5/10 min. Test annular to 2500 psi for 5/10 min. fll 11.7 Rig down BOPE test equipment. 11.8 Makeup mills on a joint of HWDP. 11.9 RIH & set in slips. 11.10 Makeup float sub, install float. 11.11 Make up UBHO sub. 11.12 Orient UBHO to starter mill. 11.13 Leave assembly hanging in the elevators, and stand back on floor. 11.14 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 11.15 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety screws. Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. REMOVE 3 screws for a set down shear of 6,630 x 3 =19,890 lbs. Note: Attach mills to Whipstock with (1) 35k mill shear bolt. Page 13 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ililcorp Alaska. HA: 11.16 If needed, open BOP Blinds. 11.17 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 11.18 Release pickup system at this point, Makeup mills. 11.19 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 11.20 The assembly can now be picked up to ensure that the shear bolt is tight. 11.21 Remove the handling system. 11.22 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 11.23 Run in hole at 1 %2 to 2 minutes per stand. 11.24 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 11.25 Call for Baker Rep. 15 — 10 stands before getting to bottom. 11.26 Orient at least 30' —45' above the cement CIBP. Ensure to have gyro personnel and equipment as well as a wireline unit R/U and ready. Page 14 Revision 0 September, 2015 ff I10 is Alaska, LIA: CLU 05RD Drilling Procedure Rev 0 WindowMaster G2 System on TorqueMaster BTA 9-5/8" 47# Csg — WindowMaster G2 On BTA BHA #1 Connection Length O.D. BOTTOM TRIP ANCHOR 4 Y2 IF -Box X Bottom Guide 3.42' 8.352" WINDOW MASTER WHIPSTOCK Shear Bolt X 4'/: IF -Pin 18.54' 8.00" WINDOW MILL -1/2 Reg -Pin X Mill 1.3' 8.5" LOWER WATER MELON MILL -1/2 IF -Box X 4-1/2 Reg -Box 5.67' 8.375" FLEX JOINT -1/2 IF- Box X 4-1/2 IF -Pin 9.0' 6.375" UPPER WATER MELON MILL -1/2 IF- Box X 4-1/2 IF -Pin 6.17' 8.5" 11T HWDP -1/2 IF -Box X 4-1/2 IF -Pin 30' 6.5" MWD Survey Tool -1/2 IF -Box X 4-1/2 IF -Pin 3' 6.5" UBHO -1/2 IF -Box X 4-1/2 IF -Pin 3' 6.5" Bowen Lubricated Bumper Jar -1/2 IF -Box X 4-1/2 IF -Pin 15' 6.75" 6 DRILL COLLARS -1/2 IF -Box X 4-1/2 IF -Pin 180' 6.75" 30 JTS — HWDP -1/2 CDS40 Box X 4-1/2 CDS40-Pin 1 900' 1 6.75" CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 15 Revision 0 September, 2015 12.0 Whipstock Setting Procedure CLU 05RD Drilling Procedure Rev 0 12.1 With the bottom of the Whipstock 30 — 45' above the CIBP, measure and record P/U and S/O weights. We will orient Whipstock face using Gyrodata. Ensure that UBHO and gyro tool mate up properly before making up UBHO sub. 12.2 Orient Whipstock to desired direction by turning DP in 'Around increments. P/U and S/O on DP to work all torque out (Being careful not to set BTA). 12.3 12.4 12.5 12.6 12.7 �V 12.8 12.9 Whipstock Orientation Diagram: 20 L HS 15LHS Desired orientation of the Whipstock face is in 15 to 20 degrees left of highside. Hole Angle at window interval (6600' MD) is 12 deg. The wellbore trajectory is planned to 45 degrees azimuth.And the original well bore azimuth is 53 degrees. Once Whipstock is in desired orientation, slack off and tag CIBP to set Bottom Trip Anchor. Set down 12-15K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (25k shear value). P/U 5-10' above top of Whipstock. Displace to 9.0 ppg 6% KCl/PHPA drilling fluid. Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. Install catch trays in shaker underflow chute to help catch metal. Keep metal in separate bbls. Record weight of metal recovered on ditch magnets. Page 16 Revision 0 September, 2015 12.10 Estimated metal cuttings volume from cutting window: CLU 05RD Drilling Procedure Rev 0 9-5/8" 4'/ REG -P X MILL 47# P-110 Cuttings Weight Window 4 Y IF -13 X 4'/ REG -B 5.67 8.375 FLEX JOINT Length Casing Weight Min (lbs) Avg (lbs) Max (lbs) 17 47# 150 225 300 12.11 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 12.12 Circulate Bottoms Up until MW in = MW out. 12.13 Conduct FIT to 11 ppg EMW. I • (11 — 9) * 0.052 * 5426' tvd = 564 psi 1 Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 11 ppg FIT results in a 2 ppg kick margin while drilling the interval with a 9 ppg fluid density. 12.14 Slug pipe and POOH. Gauge Mills for wear. Wit, 12.15 Should a second run be required pick up the following BHA. -r4-4- Back UD Mills Connection Lenath O.D. WINDOW MILL 4'/ REG -P X MILL 1.3 8.5 NEW LOWER WATERMELON MILL 4 Y IF -13 X 4'/ REG -B 5.67 8.375 FLEX JOINT 4 % 1F-13 X 4 Y2 IF -P 9.0 6.375 UPPER WATERMELON MILL 4 Y2" IF -13 X 4 Y2" IF -P 6.17 8.5 FLOAT'SUB 4'/2" IF -13 X 4 %" IF -P 3.00 4.75 XO sub and 30 jts-HWDP 4'/" CDS40-B X 4 Y2" IF -P 900' 5.25 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY.! Page 17 Revision 0 September, 2015 13.0 Drill 8-1/2" Hole Section 13.1 P/U 8-1/2" directional drilling assy. 13.2 Ensure BHA Components have been inspected previously. CLU 05RD Drilling Procedure Rev 0 13.3 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 13.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 13.5 Confirm that the bit is dressed with a TFA of 0.40 — 0.55 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 300 - 400 gpm. 13.6 Motor AKO should be set at 1.2 deg. Must keep up with 5 deg/100 DLS in the build section of the wellbore. 13.7 Primary bit will be the Varel 8-1/2" V513GH PDC bit. Ensure to have a back up bit available on location. Page 18 Revision 0 September, 2015 IIilcurp %laska.IAA: CLU 05RD Drilling Procedure Rev 0 _s Tool #:TTUV IADC Code: M232 � L r PRODUCT SPECIFICATIONS Cutter Size: Cutter Back Up: Total Cutter Count: Face Cutter Count: Connection: Nozzle 1 Qty.fType: Nozzle 2 CItyfType: Junk Slot Area: Gage Pad Length: Make Up Length: Shank Diameter: OPERATING PARAMETERS* 13 mm 33 28 4 1/2 API Regular 7 - Series 65 16.1in2 (103.9cm2) 2" (51mm) 9.7" (247.1 mm) 5.9" (149.9mm) Rotary Speed: For all rotary and motor applications Flowrate Min -Max: 250 - 750GPM (0.95 - 2.84malmin) Max Weight On Bit: 29,000lbs (12900daN) Makeup Torque: 12,000 - 16,00OFt-lbs. (16270 - 21693Nm) •Opc,alm paraq.4Cm -rYI Tr arc lygcal for the Y-t'tpe sF.ccrllc i Fa recd ndatlar o yr. r sGtaAc ap�W.Va cmlacl 1w v-6 Merna4rnal r4sct% Wll Voyager Series Bits - Voyager series bits utilize Varel's proprietary design, modeling, and programming software coupled with specialized manufacturing techniques to create the optimal drill bit for your fit -for -purpose applications. Engineered though Varel Simulator Suite for specific directional applications. Voyager bits incorporate the latest design features to maximize cuttings removal, enhance ROP potential, improve directional response, and create a more durable bit frame to aid in accomplishing your aggressive directional drilling objectives. Bit Features G - The premium gage consists of thermally stable potycrystalline diamond, and is designed to insure that correct hole diameter is maintained. H - Increased number of nozzles for improved bit cleaning. ................. V A R E L www.varelintl.com Page 19 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ilik•nrp Alaska. 1.1.1: 13.8 TIH to window. Shallow test MWD on trip in. 13.9 TIH through window, ensure Sperry MWD service rep on rig floor during this operation. • Do not rotate string while bit is across face of Whipstock. 13.10 Drill 8-1/2" hole to 10600' MD using motor assembly. • Prep for severe losses at 10,300'. We can use ALL forms of LCM to cure losses in T-913 • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 13.11 Hilcorp Geologists will follow mud log closely to determine exact TD. 13.12 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 13.13 TOH with drilling assembly, handle BHA as appropriate. Page 20 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ililrorp Alaska. LIA: 14.0 Run 7-5/8" Drilling Liner 14.1 The main purpose of this liner is to isolate the TY T-913. We need to be sure that we are setup to wash and ream casing to bottom if required. 14.2 R/U Weatherford 7-5/8" casing running equipment. • Ensure 7-5/8" HYD 511 x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • Make sure we have 7-5/8" HYD 511 lift nubbins and all equipment needed to handle flush joint pipe from Weatherford. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints 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. 14.3 P/U shoe joint, visually verify no debris inside joint. 14.4 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • Centralizers will be pre-installed on shoe joint, FC joint, and LC joint. • Install bowspring centralizers, every other joint, and leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe & FC. V° 14.5 Continue running 7-5/8" drilling liner • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 7-5/8" HYD 511 M/U torques Casing OD Minimum Maximum Yield Torque 7-5/8" 5900 ft -lbs 7100 ft -lbs 10300 ft -lbs Page 21 Revision 0 September, 2015 H September 02 2015 Tenons d ri I Connection: Wedge 511x"' Casing/ Tubing: CAS Nominal OD 7.625 in. Nominal ID 6.875 in. Plain End Weight 29.06 lWft Body Yield CLU 05RD Drilling Procedure Rev 0 1 Size: 7.625 in. Wall: 0.375 in. Weight: 29.70 lbs/ft Grade: L80.1 Min. Wall Thickness: 87.5 % Standard Drift Nominal Weight 29.70 lbs/ft Diameter 6.750 in. Special Drift Wall Thickness 0.375 in. N/A Diameter Strength Collapse 683 x 1000 ibs 4790 psi Internal Yield 6890 psi SMYS 80000 psi WEDGE 511rm CONNECTION DATA GEOMETRY Connection OD 7.625 in. Connection ID 6.787 in. Make -Up Loss 3.700 in. Critical Section 5.218 sq. in. Threads per in. 3.28 Area Page 22 417 x 1000 Internal Pressure Tension Efficiency 61.1 Joint Yield Strength 6890 psi lbs Capacity Compression Compression 504 x 1000 lbs 73.80/a Bending 29 0/100 ft Strength Efficiency External Pressure 4790 psi Capacity Minimum 5900 ft -lbs I Optimum 7100 ft�-ibs I Maximum C3 10300 ft -lbs Operating Torque 35000 ft -lbs I Yield Torque 52000 ft -lbs Revision 0 September, 2015 I/ CLU 05RD Drilling Procedure Rev 0 Ililrorp Alaska, HA: 14.6 Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 14.7 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 14.8 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 14.9 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 14.10 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 14.11 M/U top drive and fill pipe while lowering string every 10 stands. 14.12 Set slowly in and pull slowly out of slips. 14.13 Circulate 1-1/2 drill pipe and liner volume at 8-1/2" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 14.14 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14.15 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 14.16 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 14.17 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 14.18 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 23 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 llik•ogp Alaska. LI.1: 15.0 Cement 7-5/8" Drilling Liner • Cement will be mixed using batch mixer to ensure consistent density 15.1 Hold a pre job safety meeting over the upcoming cmt operations. 15.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky. 15.3 Pump 5 bbls 12.5 ppg MUDPUSH II spacer. 15.4 Test surface cmt lines to 4500 psi. 15.5 Pump remaining 10 bbls 12.5 ppg MUDPUSH II spacer. 15.6 Mix and pump 103 bbls of 15.3 ppg class "G" cmt per below recipe with 2 lbs/bbl of Cemnet or equivalent loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excessand give 200' of coverage above liner top, but if fluid caliper dictates otherwise we may increase excess volumes. Est TOC 6400' TMD., 15.7 Displacement fluid will be 9.0 ppg drilling mud. —220 bbls of displacement fluid Cement Calculations 9-5/8" x 4-1/2 DP" Overlap: (6200' — 6400') x 0.05766 = 11.5 bbls 9-5/8" x 7-5/8" Liner Overlap: (6400 — 6600') x 0.01673 = 3.3 bbls 8-1/2" OH x 7-5/8" Liner: (10600' — 6600') x 0.01371 x 1.5 = 82.3 bbls Shoe Track: 120' x 0.04591 = 5.5 bbls Total Volume (bbls): 1.5 + 3.3 + 82.3 + 5.5 = 102.6 bbls Total Volume (ft3): 103 bbls x 5.615 ft3/bbl = 578 ft3 Total Volume (sx): 578 ft3 / 1.34 ft3/sk = 431 sx r" Page 24 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 110corp Alaska. LLC Slurry Information: System Easy BLOK Density 15.3 lb/gal Yield 1.34 ft3/sk l�tl Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Bc at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 15.8 Drop DP dart and displace with 9.0 ppg drilling mud. 15.9 Pump cement at max rate of 8 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 15.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 15.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 15.12 Slack off total liner weight plus 30k to confirm hanger is set. 15.13 Do not overdisplace by more than 1/2 shoe track (-2.5 bbls). Shoe track volume is 5.5 bbls. 15.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 25 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Hiljo Ah,,ka. LLC 15.15 Bleed pressure to zero to check float equipment. 15.16 PIU, verify setting tool is released, and expose setting dogs on top of tieback sleeve 15.17 Rotate slowly and slack off 50k downhole to set ZXPN. 15.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 15.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 15.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 15.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 15.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. 15.23 RD cementers and prepare to drill 6-3/4" production hole section. Backup release from liner hanger: ✓ 15.24 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 15.25 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 15.26 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 26 Revision 0 September, 2015 uilvorp Alaska. LIA: CLU 05RD Drilling Procedure Rev 0 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 • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping ofjob. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + "As -Run" liner tally to mmyers(aa)hilcorp.com and cdinger6&hilcorn.com Page 27 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 iia jo .%IaAa, LLC 16.0 Mud Program and Density Selection Criteria 16.1 6-3/4" Production hole mud program summary: Primary weighting material to be used for the hole section will be Calcium Carbonate. We will have barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.5 ppg 6% KCl/PHPA fresh water based drilling fluid. Properties: System Formulation: 6% KCI / EZ Mud DP Product Concentration Water 0.905 bbl KCI 22 ppb (29 K chlorides) Caustic MD Density Viscosity Plastic Viscosity Yield Point pH API Fluid PAC -L 1 ppb BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb Loss 10600'- 12500'. 9.5-11 40-53 15-25 15-25 8.5-9.5 <_6.0 System Formulation: 6% KCI / EZ Mud DP Product Concentration Water 0.905 bbl KCI 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb BAROID 41 as required for a 9.5 —11 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate 16.2 Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Page 28 Revision 0 September, 2015 CLU 05111) Drilling Procedure Rev 0 Ifile 1) la'ka. LII: 17.0 Drill 6-3/4" Hole Section 17.1 P/U 6-3/4" directional drilling assy. d U , r 17.2 Ensure BHA Components have been inspected previously. 17.3 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 17.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 17.5 Confirm that the bit is dressed with a TFA of 0.46 — 0.56 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 150 - 250 gpm. 17.6 Motor AKO should be set at 1.2 deg. Must keep up with 5 deg/100 DLS in the build section of the wellbore. 17.7 Primary bit will be the Varel 6-3/4" V513PDHRU PDC bit. Ensure to have a back-up bit available on location. Page 29 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Il0"".1,A1114a. LIA: Assembly: A09986 Tool #: T10826 IADC Code: M333 • V513PD voyager PRODUCT SPECIFICATIONS Cutter Size: 13 mm Cutter Back Up: 13 mm PDC & Diamond Shock Studs Total Cutter Count: 45 Face Cutter Count: 30 Connection:. 3 112" ARI Regular Nozzle t Qty:Type: 7 - 50 series Nozzle 2 Qty7ype: - Junk Slot Area: 9.5tnl (61.3em') Gage Pad Length: 1" (25mm) Make Up Length: 8.1" (206.8mm) Shank Diameter: 4.9" (124.5mm) OPERATING PARAMETERS" Rotary Speed: For all rotary and motor applications Flowrate Min -Max: 130 - 350GPM (0.57 - 1.32m1fmin) Max Weight On Bit: 27000 lbs (12010daN) Makeup Torque: 7000 - 9000Ft-Lbs. (9491 - 12202Nm) 'Opel illnU F lrJrt'.F[Ul.'t5 :h:rnst we tYFlcal fqr the LYI h :{:cti'rflc•: Fey recarrmer,[W�IY)sr, un Yeu :pec a�Wlrarr —t-1Y>xrf Val. 4 hti nat'. M ff{iTG(.ClYllt..^ Voyager Series Bits - Voyager series bits utilize Varel's proprietary design, modeling. and programming software coupled with specialized manufacturing techniques to create the optimal drill bit for your fit -for -purpose applications. Engineered though Varel Simulator Suite for specific directional applications, Voyager bits incorporate the latest design features to maximize cuttings removal, enhance ROP potential, improve directional response, and create a more durable bit frame to aid in accomplishing your aggressive directional drilling objectives. Bit Features P - PowerCuttersTJ provide extra cutter density on the shoulder reducing excessive wear or cutting structure damage when drilling interbedded formations. 0 -'drop in cutter in gage pad - H - Increased number of nozzles for improved bit cleaning. R - diamond shock studs limit drill bit vibration and increase stability allowing smooth cutting action. This increases cutter life and overall bit performance. U - PDC cutters strategically placed to help reduce hole problems when up drilling or back reaming_ Page 30 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 1hh-, rp Alaska. I.I.0 17.8 TIH to shoe. Shallow test MWD on trip in. 17.9 TIH through liner hanger, ensure Sperry MWD service rep on rig floor during this operation. a. Do not rotate string through liner hanger. 17.10 Drill through landing collar and float equipment and 20' of new formation. 17.11 Displace hole to 9.5 ppg 6% KCl mud '? 17.12 Conduct FIT to 12 ppg EMW. a. (12 — 9.5) * 0.052 * 8906' tvd = 1157 psi [A -1.s z.S >' .KZ 17.13 Drill 6-3/4" hole to 12500' MD using motor assembly. TU • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 17.14 Hilcorp Geologists will follow mud log closely to determine exact TD. 17.15 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 17.16 TOH with drilling assembly, handle BHA as appropriate. Page 31 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ililcorp Alaska. 1.1.1: 18.0 Run 4-1/2" Production Liner 18.1 R/U Weatherford 4.5" casing running equipment. • Ensure 4.5" DWC/C x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints 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. 18.2 P/U shoe joint, visually verify no debris inside joint. 18.3 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. 1/ • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • Solid body centralizers will be pre-installed on shoe joint, FC joint, and LC joint. • Install solid body centralizers (Volant), one per joint, and leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe & FC. 18.4 Continue running 4.5" production casing • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. Utilize a collar clamp until weight is sufficient to keep slips set properly. 4.5" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2" 5800 ft -lbs 6500 ft -lbs 7200 ft -lbs Page 32 Revision 0 September, 2015 Connection Type: DWC/C Tubing standard Technical Specifications Size(O.D.): Weight (Wall): 4-112 in 12.60 lb/ft (0.271 in) Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) CLU 05RD Drilling Procedure Rev 0 Grade: L-80 AAM 11111111111111111111111�USA VAM USA 4424 W. Sam Houston Pkwy. suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsalesflZyam4m.com Page 33 Revision 0 September, 2015 Pipe Dimensions 4.500 Nominal Pipe Body O.D. (in) 3.958 Nominal Pipe Body I.D.(in) 0.271 Nominal Wall Thickness (in) 12,60 Nominal Weight (lbs/ft) 12.25 Plain End Weight (lbs/ft) 3.600 Nominal Pipe Body Area (sq in) CLU 05RD Drilling Procedure Rev 0 Grade: L-80 AAM 11111111111111111111111�USA VAM USA 4424 W. Sam Houston Pkwy. suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsalesflZyam4m.com Page 33 Revision 0 September, 2015 Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (Ibs) 7,500 Minimum Collapse Pressure (psi) 8,430 Minimum Internal Yield Pressure (psi) 7,700 Hydrostatic Test Pressure (psi) CLU 05RD Drilling Procedure Rev 0 Grade: L-80 AAM 11111111111111111111111�USA VAM USA 4424 W. Sam Houston Pkwy. suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsalesflZyam4m.com Page 33 Revision 0 September, 2015 Connection Dimensions 5.000 Connection O.D. (in) 3.958 Connection I.D. (in) 3.833 Connection Drift Diameter (in) 3.94 Make-up Loss (in) 3.600 Critical Area (sq in) 100.0 Joint Efficiency (%) CLU 05RD Drilling Procedure Rev 0 Grade: L-80 AAM 11111111111111111111111�USA VAM USA 4424 W. Sam Houston Pkwy. suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsalesflZyam4m.com Page 33 Revision 0 September, 2015 Connection Performance Properties 288,000 Joint Strength (Ibs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (Ibs) 288,000 Compression Rating (lbs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees1100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft -lbs) CLU 05RD Drilling Procedure Rev 0 Grade: L-80 AAM 11111111111111111111111�USA VAM USA 4424 W. Sam Houston Pkwy. suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsalesflZyam4m.com Page 33 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 18.5 Ensure to run enough liner to provide for approx 200' overlap inside 7-5/8" casing. Ensure hanger/pkr will not be set in a 7-5/8" connection. 18.6 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 18.7 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 18.8 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 18.9 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 18.10 M/U top drive and fill pipe while lowering string every 10 stands. 18.11 Set slowly in and pull slowly out of slips. 18.12 Circulate 1-1/2 drill pipe and liner volume at 7-5/8" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. t 18.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 18.14 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 18.15 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 18.16 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 18.17 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 34 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 11i1rorp Alaska, LI.1: 19.0 Cement 4-1/2" Production Casing • Cement will be mixed using batch mixer to ensure consistent density 19.1 Hold a pre job safety meeting over the upcoming cmt operations. 19.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky. 19.3 Pump 5 bbls 12.5 ppg MUDPUSH II spacer. 19.4 Test surface cmt lines to 4500 psi. 19.5 Pump remaining 10 bbls 12.5 ppg MUDPUSH II spacer. 19.6 Mix and pump 65 bbls of 15.3 ppg class "G" cmt per below recipe with 2 lbs/bbl of Cemnet or equivalent loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to give 500' of cement inside shoe in annulus between 7-5/8" casing and 4-1/2" casing. Est TOC 8400' TMD. 19.7 Displacement fluid will be produced water or 3% KCL. —153 bbls of displacement fluid Cement Calculations 7-5/8" x 4-1/2 DP" Overlap: (10400'— 10100') x 0.02624 = 7.9 bbls 7-5/8" x 4-1/2" Liner Overlap: (10600' — 10400') x 0.02624 = 5.3 bbls 6-3/4" OH x 4-1/2" Liner: (12500' — 10600') x 0.02459 x 1.5 = 70.0 bbls Shoe Track: 80' x 0.01522 = 1.2 bbls Total Volume (bbls): 7.9 + 5.3 + 70.0 + 1.2 = 84.4 bbls Total Volume (ft3): 84.4 bbls x 5.615 ft3/bbl = 474 ft3 Total Volume (sx): 474 ft3 / 1.35 ft3/sk = sx -3s(Jr/- Page 35 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 11ilcorp.Va4a, LI.L Slurry Information: System Easy BLOK Density 15.3 lb/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Be at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 19.8 Drop DP dart and displace with 8.6 ppg produced water. 19.9 Pump cement at max rate of 8 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 19.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 19.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 19.12 Slack off total liner weight plus 30k to confirm hanger is set. 19.13 Do not overdisplace by more than V2 shoe track (-1 bbls). Shoe track volume is 1.8 bbls. 19.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 36 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 11ilem-p .Uaska. LLC 19.15 Bleed pressure to zero to check float equipment. 19.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 19.17 Rotate slowly and slack off 50k downhole to set ZXPN. 19.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 19.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 19.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 19.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 19.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 19.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 19.24 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 19.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 37 Revision 0 September, 2015 I lile—p Alaska. H.0 CLU 05RD Drilling Procedure Rev 0 Ensure to report the following on Wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slung type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + "As -Run" liner tally to mmyersnahilcorp.com & cdinger(a),hilcorp.com Page 38 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 nilcnrp Alaska, LLC 20.0 Wellbore Clean Up & Displacement 20.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3-3/4" bit or mill • Casing scraper & brush for 4-1/2" 12.6# casing (MI Swaco - Multiback) • +/- 1900' 2-3/8" workstring. • Crossover (w/ PBR Polish Mills) • Casing scraper & brush for 7-5/8" 29.7# casing (MI Swaco - Multiback) • (2000') 4-1/2" DP • Casing scraper & brush for 7-5/8" 29.7# casing (MI Swaco - Multiback) • 4-1/2" DP to surface. 20.2 TIH & clean out well to landing collar (+/- 12,480' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. • Ensure 3-3/4" bit is worked down to the landing collar. • Space out the cleanout BHA so that the 3-3/4" bit reaches the 4-1/2" landing collar when crossover is +/- 30' above the 4-1/2" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. 20.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 3500 psi / 30 min. Ensure to chart record casing test. �- 20.4 Displace drilling fluid in wellbore with a hi -vis pill followed by fresh water. • Catch drilling fluid in rain -for -rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7-5/8" multi -back assy to surface. • RIH again & tag landing collar w/ 3-3/4" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by 6% KCl completion fluid. 20.5 TOH w/ clean out assy. LDDP on the trip out. L/D the 2-3/8" work string. Page 39 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 llilcorp .klaAa. LLC 21.0 Run 4-1/2" Tieback String c4c b; 20.6 MU 4-1/2 Tubing as per completion tally 20.7 RIH to +/- 20' from seal bore extension, obtain PU and SO weight 20.8 RIH slowly and engage seals to no go, space out and mark pipe 20.9 PU out of seals and install pup joints for space out 20.10 RIH to +/- 5' above seal bore extension. 20.11 Reverse circulate -454 bbls of corrosion inhibited completion fluid into annulus of tubing (-3% baracor in 6%KCl brine) 20.12 Sting into seals to space out mark 20.13 Land tubing hanger and RILDS, Rig up and test tubing to 3500psi. -f - /1't I T- _1i4 + Z,5 -0t, p 22.0 RDMO 21.1 Install BPV in wellhead. 21.2 RD BOPE, RU temporary abandonment cap, test void 21.3 Rig Down C�� Page 40 Revision 0 September, 2015 11ilcorp Alaska. IIA: 23.0 BOP Schematic Saxon 169 BOP stack CLU #5 CLU 05RD Drilling Procedure Rev 0 PFT-- -7 ut32 , W Page 41 Revision 0 September, 2015 Ililcorp Alaska, LII: 24.0 Wellhead Schematic Cannery Loop CLU N05 20 x 133/8 x 95/8 x 4A Tree cap Otis, 4 1/16 SM FE X 6 % Otis Quick Union Valve, Swab, WKM-M, 41/16 SM FE, HWO, DD trim Cross, stdd, 4 1/16 5M X 3 1/8 5M Valve, Upper Master, WKM-M, 4 1/16 5M FE, HWO, DD trim Valve, Master, WKM-M, 4 1/16 5M FE, HWO, DD trim Tubing head, CIW-DCB-S, 135/8 SM X11 SIM, w/2- 2 1/16 5M SSO, X -bottom prep, N type pins Casing head, McEvoy, 13 5/8 5M X 13 3/8" SOW bottom, w/ 2- 2 1/16 5M EFO CLU 05RD Drilling Procedure Rev 0 Tubing hanger, CIW-DCB- FBB-CCI, 11 X 4 1/2 EUE lift and susp, w/ 4" type H BPV profile, 6 Y. EN, 2- Y. npt CCL ports oet,a�ao roc 0a� �A era WSJ pec CoQ Valve, WKM-M, 2 1/16 SM FE, HWO, AA a Qty 2 Valve, McEvoy -C, e16 SM FE, HWO, AA Page 42 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ililenrp .�la:+ka, L1.1: 25.0 Days vs Depth MV F 6000 i YL 8 V G 7 a A 8000 pirICIA 14000 + 0 Days Vs Depth 05RD 5 10 15 20 25 30 35 40 45 50 Days Page 43 Revision 0 September, 2015 26.0 Geo-Prog CLU 05RD Drilling Procedure Rev 0 ANTICIPATED 91412015 13:36 TOPS & GEOHAZARDS GEOLOGICAL PROGNOSIS WELL NAME. CLU 05RD Hilcorp FIELD: Cannery Lo( SURFACE: X= 272700.5 BHL X: 276711.11 AFE: 1511837D Y= 2388612.8 Y: 2391736.5 STATE: Alaska PROPOSED TD: 12500' MD; 10806' TVD EST. KB: 38.5 API: TBD / EST. GL: 20.5 FLUID Est. MD TVD (FT) Sidetrack the CLU 5 well on the CL -1 pad below the CINGSA gas storage sand in the Pressure Cannery Loop Field to target several unbooked Tyonek D sands, updip from the CLU 1 Secondary Target and CLU 5. The sands were breifly tested in the CLU 1, however well bore conditions Objective and structural location prevented any signficant production. The sands were (5,765) previously targeted by the CLU 13, but due to lost returns in a severely depleted sand, Lower Beluga we were unsuccesful in reaching them. The secondary targets for this well include the gas Upper, Mid, and Lower Beluga sands. ANTICIPATED FORMATION TOPS & GEOHAZARDS EXPECTED Est. POOL FLUID Est. MD TVD (FT) SUBSEA Pressure Middle Beluga Secondary Target gas 7,034 5823 (5,765) 1747 Lower Beluga Secondary Target gas 8,129 6728 (6,670) 2018 Upper Tyonek Gas Upper Tyonek Secondary Target gas 9,551 7904 (7,846) 2371 TYT-9B DEPLETED SAND gas 10,333 8638 (8,580) 740 Pool TY 91-2 Primary(test) gas 10,778 9083 (9,025) 4087 TY D2 Primary(test) gas 11,066 9372 (9,314) 4217 TYD3A Primary(test) gas 11,321 9627 (9,569) 4332 TYD5A Primary(test) gas 11,594 9900 (9,842) 4455 Deep Tyonek Gas Pool TYD6 Primary (test) gas 11,696 10002 (9,944) 4501 TYD7 Secondary Target gas 11,866 10172 (10,114) 4577 TY D8 Secondary Target gas 12,1 1 1 10417 (10,359) 4688 TY D9 Secondary Target gas 12,367 10673 (10,615) 4803 DATA • • - • Mud Logging: Full suite with sample catchers LWD Data: Triple Combo from surface to TD E -Line Log Data: single 70%/3 mmcfpd Drilling please note depths of depleted T -9B sand above, as it is where we loss returns on CLU 13. Page 44 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 1ile-1; Alaska. HA: 27.0 Anticipated Drilling Hazards Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual -composition carbon -based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. • Minimize swab and surge pressures • Minimize back reaming through coals when possible H2S: 1-12S is not present in this hole section. No abnormal temperatures or pressures are present in this hole section. Page 45 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ilileorp Alaska, LLC 28.0 Rig Layout Page 46 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 llilrorp UaAa. 1.11: 29.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 47 Revision 0 September, 2015 30.0 Choke Manifold Schematic CLU 05RD Drilling Procedure Rev 0 NMI C %7•err" 1. utwt VM R CAINM Page 48 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 31.0 Casing Design Information Calculation & Casing Design Factors Cannery Loop Unit DATE: 9-4-2015 WELL: CLU 05RD FIELD: Cannery Loop DESIGN BY: Monty Myers Design Criteria: Hole Size 8-1/2" Mud Density: 9.0 ppg Hole Size 6-3/4" Mud Density: 10.0 ppg Hole Size Mud Density: Drilling Mode MASP(sec 2): 2939 psi (see attached MASP determination & calculation) MASP(sec 3): 3783 psi (see attached MASP determination & calculation) Production Mode MASP: 3,783 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation ' 1, 2, 3 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Page 49 Revision 0 September, 2015 Casing Section Calculation/Specification 1 2 Casing OD 7-5/8" 4-1/2" Top (MD) 6,400 10,400 Top (TVD) 5,232 8,706 Bottom (MD) 10,600 12,500 Bottom (TVD) 8,906 10,806 Length 4,200 1 2,100 Weight (ppf) 29.7 12.6 Grade L-80 L-80 Connection HYD 511 DWC/C HT Weight w/o Bouyancy Factor (lbs) 124,740 26,460 Tension at Top of Section (lbs) 124,740 26,460 Min strength Tension (1000 lbs) 417 288 Worst Case Safety Factor (Tension) 3.34 10.88 ,. Collapse Pressure at bottom (Psi) 4,168 5,619 Collapse Resistance w/o tension (Psi) 4,790 7,500 Worst Case Safety Factor (Collapse) 1.15 1.33 MASP (psi) 2,939 3,783 Minimum Yield (psi) 6,890 8,430 Worst case safety factor (Burst) 2.34 2.23 Page 49 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ildcorp Ala4a, LIA; 32.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation A!orp ' 8-1/2 Hole Section CLU 05RD Cannery Loop MD TVD Planned Top: 6600 5426 Planned TD: 10600 8906 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Middle Beluga 5,823 1747 Gas 5.8 1 0.300 Lower Beluga 6,728 2018 Gas 5.8 0.300 UpperTyonek 7,904 2371 Gas 5.8 0.300 TY T-913 8,638 740 Gas 1.6 0.086 Offset Well Mud Densities Well MW ranee Too (MDI Bottom (MD) Date CLU1 9.2 - 10 ppg 3,100 8,600 1979 CLU3 9 - 10.4 ppg 3,100 8,600 1981 CLU4 9.2 - 11.5 p pg 3,100 8,600 1987 CLU5 9.4-10.8 ppg 3,100 8,600 1996 Assumptions: 1. Fracture gradient at 3,000' MD / 2,817' TVD is estimated at 0.75 psi /ft based on field test data. 2. Maximum planned mud density for the 8-1/2" hole section is 9.0 ppg. 3. Calculations assume "Unknown" reservoir contains 100% gas (worst case). Fracture Pressure at 9-5/8" window considering a full column of gas from shoe to surface: 5426 (ft) x 0.75(psi/ft)= 4070 psi 4070(psi) - [0.1(psi/ft)*5426(ft))= 13527 psi MASP from pore pressure (unknown gas sand at TD, at 8.3 ppg) 8906(ft) x 0.43(psi/ft)= 3829 psi 3829(psi) - [0.1(psi/ft)*8906(ft))= 2939 psi Summary: 1. MASP while drilling 8-1/2" intermediate hole is governed by pore pressure at TD with entire wellbore evacuated to gas. Page 50 Revision 0 September, 2015 CLU 05RD Drilling Procedure Rev 0 Ilih-orio Alaska. i.i.c 33.0 6-3/4" Hole Section MASP 14 Maximum Anticipated Surface Pressure Calculation Hilcorp 6-3/4" Hole Section CLU 05RD Cannery Loop MD TVD Planned Top: 10600 8906 Planned TD: 12500 10806 Anticioated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad TY 91-2 9,083 4087 Gas 8.7 0.450 TY D2 9,372 4217 Gas 8.7 0.450 TY D3A 9,627 4332 Gas 8.7 0.450 TY D5A 9,900 4455 Gas 8.7 0.450 TY D6 10,002 4501 Gas 8.7 0.450 TY D7 10,172 4577 Gas 8.7 0.450 TY D8 10,417 4688 Gas 8.7 0.450 TY D9 10,673 4803 Gas 8.7 0.450 Offset Well Mud Densities Well MW ranee Too (MD) Bottom (MD) Date CLU1 9.2-10 ppg 3,100 8,600 1979 CLU3 9 - 10.4 ppg 3,100 8,600 1981 CLU4 9.2- 11.5 ppg 3,100 8,600 1987 CLU5 9.4-10.8 ppg 3,100 8,600 1996 Assumptions: 1. Maximum planned mud density for the 9-7/8" hole section is 10.5 ppg. 2. Calculations assume "Unknown" reservoir contains 1001/6 gas (worst case). Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface: 8,906(ft) x 0.75(psi/ft)= 6680 psi 6,680(psi)-[0.1(psi/ft)*8,906(ft)]= 5789 psi MASP from pore pressure (entire wellbore evacuated to gas from TD) 10,806(ft) x 0.45(psi/ft)= 4,863 psi 4,863 (psi) - [0.1(psi/ft)*10,806 (ft)]= 3,783 psi' Summary: 1. MASP while drilling 6-3/4" production hole is governed by SIBHP minus gas gradient (0.1 psi/ft) to surface after entire wellbore is evacuated to gas. Page 51 Revision 0 September, 2015 34.0 Plot (NAD 27) (Governmental Sections) CLU 05RD Drilling Procedure Rev 0 Cannery Loop Unit CLU 05RD Ilil.•urp .11�-k ��. L1.1: Page 52 Revision 0 2,0M 4,000 Feet N Alaska Stale Plane Zone 4, NAD27 Map Data: W3112015 September, 2015 LN 03 OHL, ADL 373302 CLU �E—�=5j AD p Lease Type Unleased r aX r f Federal ADL 324802 Private f 0 State. r� ,lr t2SHL"- CLU 048K CLU &1 OHL\ r fir f/ CIV It OHL+ l f f �t ADL 359153 ff FEE ADL 060588 cLu mi"t, rrLU c c CLU-05RD f '' cwc�ay CLU-05RD '�� {•`r'` TPH BHL r' CLU 14e r r ADL 4804 • ERY LOAF UN r'r f r ¢iiuooyYtr cLv rrr Private Hililccy,orrrp�p ff mss!! EE ADL 06056 rrr 5-3 3* L^ r' f� r 'M�I�f/© S005NO11W , j ` KENA1 r+U43j"- --- Ca.nte ^i d L / CLU-05RD CLU 10 ; SHL CW S-3 BHL, - FEE AA 092401 �1 it/ ADL 384396 ADL 3 Legend ADL 391575 AOL 002397 • CLU 05RD SHL Private X CLU 05RD TPH ADL 392872 + CLU 05RD BHL r • Other Surface Well Locations KENAI UNIT ; Other Bottom Hole Locations - Well Paths AOL 39 7 W®9 Pad Oil and Gas Unit Boundary Oat 11 -AkA 02440 -- Cannery Loop Unit CLU 05RD Ilil.•urp .11�-k ��. L1.1: Page 52 Revision 0 2,0M 4,000 Feet N Alaska Stale Plane Zone 4, NAD27 Map Data: W3112015 September, 2015 Ilih--p Alaska, HA: 35.0 Surface Plat (As Built) (NAD 27) N SN-g,�TyZDNO i Z'Q NW mt affil CLU 05RD Drilling Procedure Rev 0 OYAL STREET 30' RIW —a oA 1 mT=s� Z i 0D C Ox C C DOrtO 0 o C r rn g0-1 > 0 �w 0 n ZZ M < m m o 3 z 0 M n m Z~ c r m "- Z C Z OYAL STREET 30' RIW —a oA 1 mT=s� _c "s c r m 10 Dz p 4 R gs `; c ® zA m z Y�N- cc N al 1 o> g2a c—„n z 0 1 3 I g �ffi c'g4q,, �)p0, m m z' a fiwrxnac rcncc � c 'CAUTKIN' "W t BOW PICKER LANE 50' R/W p s x,E raw &8ffi _z ArjW MarathonOil Corporation n �D DZ 0 Z _m r� ;0 ° m O >C: Z_Z z N C a > I � us moC ANNERY LOOP UNIT PAD 7 SITE PIAN Page 53 Revision 0 September, 2015 36.0 Directional Program (P1) CLU 05111) Drilling Procedure Rev 0 Page 54 Revision 0 September, 2015 Hilcorp Energy Company Kenai C.I.U. Cannery Loop Unit #1 Pad Cannery Loop Unit 05 Plan: Cannery Loop Unit 05RD Plan: CLU05RD WP1.a Standard Proposal Report 08 September, 2015 HALLIBURTON Sperry Drilling Services C_ U) U) 7 O O to L CL Q) U_ N 7 F- WALLIGURTON Project: Kenai C.I.U. WELL DETAILS: Cannery Loop Unit 05 NAD 1927 (NADCON CONUS) Alaska Zone 04 Ground Level 21.00 Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 05 +N/ -S +E/ -W Northing E.ting Latittude Longitude Slot Wellbore: Plan: Cannery Loop Unit 05F 0.00 0.00 2388612.84 272700.47 60'31'55,763N 151° 15' 43.366 W Plan: CLU05RD WP1.a REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Cannery Loop Unit 05, True North Vertical (TVD) Reference: CLU 05 @ 34.10usfl (Original Well Elev) Measured Depth Reference: CLU 05 @ 34.10usft (Original Well Elev) Calculation Method Minimum Curvature -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 Vertical Section at 50.99° (1500 usfUin) NALLIBUPRTON Spent Drilling Se—leres 5200— A 200C O W + 1600 0 0 1200 sn 0 -400 0 Project: Kenai C.I.U. WELL DEMM S: Cannery Loop Unit 05 Ground Level: 21.00 Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 05 +N/ -S +E✓ -W Northing Easting Latiftude Longitude Slot Wellbore: Plan: Cannery Loop Unit 05R 0.00 0.00 2388612.84 272700.47 60'31'55.763N 151° 15'43.366 W REFERENCE INFORMATION Plan: CLU05RD WP1.a Co-ordinate (N/E) Reference: Well Cannery Loop Unit 05, True North Vertical (TVD) Reference: CLU 05 34.10usft (Original Well Elev) Measured Depth Reference: CLU 05 34.10usft (Original Well Elev) Calculation Method Minimum Curvature CLU05RD WPI.a i TD at 12500.00 End Dir : 10276.32' MD, `8582.1' D StartDir5°/100' 9591.84'MD,7937.6'TVD -04 _1/ 2_" CLU05 RD w pl Tgt 7 5/8" A CLU05Dwpl Tgt 5RD wpl Tgt 2400 End Dir : 7036.92' MD, 5825.08' TVD Start Dir 51/1001: 6632.6' MD, 5458.12'TVD End Dir : 6612.6' MD, 5438.73' TVD _ Start Dir 15.24o/100': 6600' MD, 5426.46'TVD : 150 LT TF CASING DETAILS TVD TVDSS MD Size Name 8905.78 8871.68 10600.00 7-5/8 7 5/8" 10805.78 10771.68 12500.00 4-1/2 4 1/2" T M Azimuths to True North Magnetic North: 16.40° Magnetic Field Strength: 55395.2snT Dip Angle: 73.49° Date: 9/6/2015 Model: BGGM2015 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 West( -)/Fast(+) (800 usft/in) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 05 Wellbore: Plan: Cannery Loop Unit 05RD Design: CLU05RD WP1.a Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Cannery Loop Unit 05 CLU 05 @ 34.10usft (Original Well Elev) CLU 05 @ 34.10usft (Original Well Elev) True Minimum Curvature Project Kenai C.I.U. Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Dogleg Build Turn Depth Inclination Site Cannery Loop Unit #1 Pad System +N/ -S +E/ -W Site Position: Northing: 2,388,631.67usft Latitude: 60° 31'55.930 N From: Map Easting: 272,605.07usft Longitude: 1510 15'45.280 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.10 ° 6,600.00 12.32 54.31 5,426.46 5,392.36 Well Cannery Loop Unit 05 0.00 0.00 0.00 Well Position +N/ -S 0.00 usft Northing: 2,388,612.84 usft Latitude: 60° 31'55.763 N 5,438.73 +E/ -W 0.00 usft Easting: 272,700.47 usft Longitude: 151 ° 15'43.366 W Position Uncertainty 0.00 usft Wellhead Elevation: -15.00 usft Ground Level: 21.00 usft 52.28 5,458.12 5,424.02 1,933.70 2,670.80 Wellbore Plan: Cannery Loop Unit 05RD 0.00 0.00 7,036.92 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 2,791.78 5.00 (1 (1) (nT) 9,591.84 BGGM2015 9/8/2015 16.40 73.49 55,395 Design CLU05RD WP1.a Audit Notes: Version: Phase: PLAN Tie On Depth: 6,600.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) V) 13.10 0.00 0.00 50.99 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) V) (1) (usft) usft (usft) (usft) ('/100usft) (°/100usft) (°/100usft) V) 6,600.00 12.32 54.31 5,426.46 5,392.36 1,928.97 2,664.60 0.00 0.00 0.00 0.00 6,612.60 14.19 52.28 5,438.73 5,404.63 1,930.70 2,666.92 15.24 14.79 -16.09 -15.00 6,632.60 14.19 52.28 5,458.12 5,424.02 1,933.70 2,670.80 0.00 0.00 0.00 0.00 7,036.92 34.22 45.09 5,825.08 5,790.98 2,045.45 2,791.78 5.00 4.96 -1.78 -11.75 9,591.84 34.22 45.09 7,937.60 7,903.50 3,059.92 3,809.47 0.00 0.00 0.00 0.00 10,276.32 0.00 213.30 8,582.10 8,548.00 3,200.00 3,950.00 5.00 -5.00 0.00 180.00 11,276.32 0.00 213.30 9,582.10 9,548.00 3,200.00 3,950.00 0.00 0.00 0.00 0.00 11,662.32 0.00 213.30 9,968.10 9,934.00 3,200.00 3,950.00 0.00 0.00 0.00 213.30 12,500.00 0.00 213.30 10,805.78 10,771.68 3,200.00 3,950.00 0.00 0.00 0.00 213.30 9/8/2015 1:56:26PM Page 2 COMPASS 5000.1 Build 73 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Cannery Loop Unit 05 Company: Hilcorp Energy Company TVD Reference: CLU 05 @ 34.10usft (Original Well Elev) Project: Kenai C.I.U. MD Reference: CLU 05 @ 34.10usft (Original Well Elev) Site: Cannery Loop Unit #1 Pad North Reference: True Well: Cannery Loop Unit 05 Survey Calculation Method: Minimum Curvature Wellbore: Plan: Cannery Loop Unit 05RD Inclination Azimuth Design: CLU05RD WP1.a +N/ -S +E/ -W Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) 5,392.36 6,600.00 12.32 54.31 5,426.46 5,392.36 1,928.97 2,664.60 2,390,490.36 275,401.58 0.00 3,284.69 Start Dir 15.24°/100' : 6600' MD, 5426.46'TVD : 15° LT TF 6,612.60 14.19 52.28 5,438.73 5,404.63 1,930.70 2,666.92 2,390,492.04 275,403.93 15.24 3,287.58 End Dir : 6612.6' MD, 5438.73' TVD 6,632.60 14.19 52.28 5,458.12 5,424.02 1,933.70 2,670.80 2,390,494.97 275,407.86 0.00 3,292.48 Start Dir 5°/100' : 6632.6' MD, 5458.12'TVD 6,700.00 17.50 50.00 5,522.95 5,488.85 1,945.27 2,685.10 2,390,506.26 275,422.38 5.00 3,310.88 6,800.00 22.45 47.83 5,616.90 5,582.80 1,967.77 2,710.78 2,390,528.26 275,448.49 5.00 3,344.99 6,900.00 27.41 46.41 5,707.56 5,673.46 1,996.48 2,741.62 2,390,556.37 275,479.88 5.00 3,387.03 7,000.00 32.39 45.40 5,794.23 5,760.13 2,031.17 2,777.38 2,390,590.38 275,516.30 5.00 3,436.66 7,036.92 34.22 45.09 5,825.08 5,790.98 2,045.45 2,791.78 2,390,604.38 275,530.96 5.00 3,456.83 End Dir : 7036.92' MD, 5825.08' TVD 7,100.00 34.22 45.09 5,877.24 5,843.14 2,070.50 2,816.90 2,390,628.93 275,556.56 0.00 3,492.11 7,200.00 34.22 45.09 5,959.92 5,925.82 2,110.20 2,856.73 2,390,667.87 275,597.15 0.00 3,548.06 7,300.00 34.22 45.09 6,042.61 6,008.51 2,149.91 2,896.57 2,390,706.81 275,637.74 0.00 3,604.01 7,400.00 34.22 45.09 6,125.29 6,091.19 2,189.61 2,936.40 2,390,745.74 275,678.33 0.00 3,659.95 7,500.00 34.22 45.09 6,207.98 6,173.88 2,229.32 2,976.23 2,390,784.68 275,718.91 0.00 3,715.90 7,600.00 34.22 45.09 6,290.66 6,256.56 2,269.03 3,016.07 2,390,823.61 275,759.50 0.00 3,771.84 7,700.00 34.22 45.09 6,373.34 6,339.24 2,308.73 3,055.90 2,390,862.55 275,800.09 0.00 3,827.79 7,800.00 34.22 45.09 6,456.03 6,421.93 2,348.44 3,095.73 2,390,901.48 275,840.67 0.00 3,883.73 7,900.00 34.22 45.09 6,538.71 6,504.61 2,388.15 3,135.56 2,390,940.42 275,881.26 0.00 3,939.68 8,000.00 34.22 45.09 6,621.40 6,587.30 2,427.85 3,175.40 2,390,979.35 275,921.85 0.00 3,995.62 8,100.00 34.22 45.09 6,704.08 6,669.98 2,467.56 3,215.23 2,391,018.29 275,962.43 0.00 4,051.57 8,200.00 34.22 45.09 6,786.77 6,752.67 2,507.27 3,255.06 2,391,057.22 276,003.02 0.00 4,107.51 8,300.00 34.22 45.09 6,869.45 6,835.35 2,546.97 3,294.90 2,391,096.16 276,043.61 0.00 4,163.46 8,400.00 34.22 45.09 6,952.14 6,918.04 2,586.68 3,334.73 2,391,135.09 276,084.20 0.00 4,219.40 8,500.00 34.22 45.09 7,034.82 7,000.72 2,626.39 3,374.56 2,391,174.03 276,124.78 0.00 4,275.35 8,600.00 34.22 45.09 7,117.51 7,083.41 2,666.09 3,414.39 2,391,212.96 276,165.37 0.00 4,331.29 8,700.00 34.22 45.09 7,200.19 7,166.09 2,705.80 3,454.23 2,391,251.90 276,205.96 0.00 4,387.24 8,800.00 34.22 45.09 7,282.87 7,248.77 2,745.51 3,494.06 2,391,290.84 276,246.54 0.00 4,443.18 8,900.00 34.22 45.09 7,365.56 7,331.46 2,785.21 3,533.89 2,391,329.77 276,287.13 0.00 4,499.13 9,000.00 34.22 45.09 7,448.24 7,414.14 2,824.92 3,573.73 2,391,368.71 276,327.72 0.00 4,555.08 9,100.00 34.22 45.09 7,530.93 7,496.83 2,864.63 3,613.56 2,391,407.64 276,368.30 0.00 4,611.02 9,200.00 34.22 45.09 7,613.61 7,579.51 2,904.33 3,653.39 2,391,446.58 276,408.89 0.00 4,666.97 9,300.00 34.22 45.09 7,696.30 7,662.20 2,944.04 3,693.22 2,391,485.51 276,449.48 0.00 4,722.91 9,400.00 34.22 45.09 7,778.98 7,744.88 2,983.75 3,733.06 2,391,524.45 276,490.07 0.00 4,778.86 9,500.00 34.22 45.09 7,861.67 7,827.57 3,023.45 3,772.89 2,391,563.38 276,530.65 0.00 4,834.80 9,591.84 34.22 45.09 7,937.60 7,903.50 3,059.92 3,809.47 2,391,599.14 276,567.93 0.00 4,886.18 Start Dir 5°1100' : 9591.84' MD, 7937.6'TVD 9,600.00 33.82 45.09 7,944.37 7,910.27 3,063.14 3,812.71 2,391,602.30 276,571.22 5.00 4,890.72 9,700.00 28.82 45.09 8,029.77 7,995.67 3,099.82 3,849.51 2,391,638.27 276,608.72 5.00 4,942.41 9,800.00 23.82 45.09 8,119.38 8,085.28 3,131.11 3,880.89 2,391,668.95 276,640.70 5.00 4,986.49 9,900.00 18.82 45.09 8,212.51 8,178.41 3,156.77 3,906.63 2,391,694.11 276,666.92 5.00 5,022.64 10,000.00 13.82 45.09 8,308.45 8,274.35 3,176.59 3,926.52 2,391,713.55 276,687.19 5.00 5,050.57 10,100.00 8.82 45.09 8,406.48 8,372.38 3,190.44 3,940.41 2,391,727.13 276,701.35 5.00 5,070.09 91812015 1:56:26PM Page 3 COMPASS 5000.1 Build 73 Halliburton H A L L I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Cannery Loop Unit 05 Company: Hilcorp Energy Company TVD Reference: CLU 05 @ 34.10usft (Original Well Elev) Project: Kenai C.I.U. MD Reference: CLU 05 @ 34.10usft (Original Well Elev) Site: Cannery Loop Unit #1 Pad North Reference: True Well: Cannery Loop Unit 05 Survey Calculation Method: Minimum Curvature Wellbore: Plan: Cannery Loop Unit 05RD Depth Inclination Design: CLU05RD WP1.a TVDss +N/ -S Planned Survey Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Measured Shape (") (") (usft) (usft) (usft) Vertical (usft) CLU05RD wpl Tgt2 0.00 0.00 9,582.10 3,110.67 3,884.14 Map Map plan misses target center by 110.99usft at 11276.32usft MD (9582.10 TVD, 3200.00 N, 3950.00 E) Depth Inclination Azimuth Depth TVDss +N/ -S +EI.W Northing Easting DLS Vert Section (usft) V) 0 (usft) usft (usft) (usft) (usft) (usft) 8,471.74 276,816.46 10,200.00 3.82 45.09 8,505.84 8,471.74 3,198.21 3,948.20 2,391,734.74 276,709.28 5.00 5,081.02 10,276.32 0.00 213.30 8,582.10 8,548.00 3,200.00 3,950.00 2,391,736.50 276,711.11 5.00 5,083.55 End Dir : 10276.32' MD, 8582.1' TVD 10,300.00 0.00 0.00 8,605.78 8,571.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 10,400.00 0.00 0.00 8,705.78 8,671.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 10,500.00 0.00 0.00 8,805.78 8,771.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 10,600.00 0.00 0.00 8,905.78 8,871.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 7518" 10,700.00 0.00 0.00 9,005.78 8,971.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 10,800.00 0.00 0.00 9,105.78 9,071.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 10,900.00 0.00 0.00 9,205.78 9,171.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,000.00 0.00 0.00 9,305.78 9,271.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,100.00 0.00 0.00 9,405.78 9,371.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,200.00 0.00 0.00 9,505.78 9,471.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,276.32 0.00 213.30 9,582.10 9,548.00 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,300.00 0.00 0.00 9,605.78 9,571.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,400.00 0.00 0.00 9,705.78 9,671.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,500.00 0.00 0.00 9,805.78 9,771.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,600.00 0.00 0.00 9,905.78 9,871.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,662.32 0.00 213.30 9,968.10 9,934.00 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,700.00 0.00 0.00 10,005.78 9,971.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,800.00 0.00 0.00 10,105.78 10,071.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 11,900.00 0.00 0.00 10,205.78 10,171.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 12,000.00 0.00 0.00 10,305.78 10,271.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 12,100.00 0.00 0.00 10,405.78 10,371.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 12,200.00 0.00 0.00 10,505.78 10,471.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 12,300.00 0.00 0.00 10,605.78 10,571.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 12,400.00 0.00 0.00 10,705.78 10,671.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 12,500.00 0.00 0.00 10,805.78 10,771.68 3,200.00 3,950.00 2,391,736.50 276,711.11 0.00 5,083.55 TD at 12500.00 - 4 112" Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (") (") (usft) (usft) (usft) (usft) (usft) CLU05RD wpl Tgt2 0.00 0.00 9,582.10 3,110.67 3,884.14 2,391,648.45 276,643.55 plan misses target center by 110.99usft at 11276.32usft MD (9582.10 TVD, 3200.00 N, 3950.00 E) Circle (radius 200.00) CLU05RD wpl Tgt 3 0.00 0.00 9,968.10 3,009.19 3,817.48 2,391,548.27 276,574.96 plan misses target center by 232.31usft at 11662.32usft MD (9968.10 TVD, 3200.00 N, 3950.00 E) Circle (radius 200.00) CLU05RD wpl Tgt 1 0.00 0.00 8,609.10 3,366.49 4,052.17 2,391,901.00 276,816.46 plan misses target center by 195.34usft at 10303.32usft MD (8609.10 TVD, 3200.00 N. 3950.00 E) Circle (radius 200.00) 9/8/2015 1:56:26PM Page 4 COMPASS 5000.1 Build 73 :'7_ • ► Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Kenai C.I.U. Site: Cannery Loop Unit #1 Pad Well: Cannery Loop Unit 05 Wellbore: Plan: Cannery Loop Unit 05RD Design: CLU05RD WP1.a Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Cannery Loop Unit 05 CLU 05 @ 34.10usft (Original Well Elev) CLU 05 @ 34.10usft (Original Well Elev) True Minimum Curvature Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 10,600.00 8,905.78 7 5/8" 7-5/8 9-7/8 12,500.00 10,805.78 41/2" 4-1/2 6 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 6,600.00 5,426.46 1,928.97 2,664.60 Start Dir 15.241/100': 6600' MD, 5426.46'TVD : 15° LT TF 6,612.60 5,438.73 1,930.70 2,666.92 End Dir : 6612.6' MD, 5438.73' TVD 6,632.60 5,458.12 1,933.70 2,670.80 Start Dir 51/100' : 6632.6' MD, 5458.12'TVD 7,036.92 5,825.08 2,045.45 2,791.78 End Dir : 7036.92' MD, 5825.08' TVD 9,591.84 7,937.60 3,059.92 3,809.47 Start Dir 5°/100' : 9591.84' MD, 7937.6'TVD 10,276.32 8,582.10 3,200.00 3,950.00 End Dir : 10276.32' MD, 8582.1' TVD 12,500.00 10,805.78 3,200.00 3,950.00 TD at 12500.00 9/6/2015 1:56:26PM Page 5 COMPASS 5000.1 Build 73 Hilcorp Energy Company Kenai C.I.U. Cannery Loop Unit #1 Pad Cannery Loop Unit 05 Plan: Cannery Loop Unit 05RD CLU05RD WP1.a Sperry Drilling Services Clearance Summary Anticollision Report 08 September, 2015 Closest Approach 3D Proximity Scan on Currant Survey Data (North Reference) Reference Design: Cannery Loop Unit #1 Pad - Cannery Loop Unit 05 - Plan: Cannery Loop Unit 05RD - CLU05RD WP1.a Well Coordinates: 2,388,012.04 N, 272,700.47 E (00.31' 55.70" N, 151115'43.37" VV) Datum Height: CLU 05 @ 34.10usft (Original Well Elev) Scan Range: 0.00 to 12,500.00 usft. Measured Depth. Scan Radius is 1,448.89 usft . Clearance Factor cutoff is Unlimited. Max Ellipse Separation Is Unlimited Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services Hilcorp Energy Company HALLIBURTON Kenai C.I.U. Anticollision Report for Cannery Loop Unit 05 - CLU05RD WP1.a Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Cannery Loop Unit #1 Pad - Cannery Loop Unit 05 - Plan: Cannery Loop Unit 05RD - CLU05RD WP1.a Scan Range: 0.00 to 12,500.00 usft. Measured Depth. Scan Radius is 1,448.69 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Cannery Loop Unit #1 Pad Cannery Loop Unit 01 - Cannery Loop Unit 01 - Canne 13.10 108.80 13.10 107.51 21.00 84.545 Centre Distance Pass - Cannery Loop Unit 01 - Cannery Loop Unit 01 - Canne 75.00 108.86 75.00 107.43 82.90 76.335 Ellipse Separation Pass - Cannery Loop Unit 01 - Cannery Loop Unit 01 - Canne 10,850.00 487.47 10,850.00 276.18 10,841.04 2.307 Clearance Factor Pass - Cannery Loop Unit 01 - Cannery Loop Unit 01 RD - CA 13.10 108.80 13.10 107.51 21.00 84.545 Centre Distance Pass - Cannery Loop Unit 01 - Cannery Loop Unit 01 RD - CA 75.00 108.86 75.00 107.43 82.90 76.335 Ellipse Separation Pass - Cannery Loop Unit 01 - Cannery Loop Unit 01 RD - CA 9,925.00 642.34 9,925.00 492.00 10,349.90 4.273 Clearance Factor Pass - Cannery Loop Unit 01 -Cannery Loop Unit 01 RDPB1 - 13.10 108.80 13.10 107.51 21.00 84.545 Centre Distance Pass - Cannery Loop Unit 01 - Cannery Loop Unit 01 RDPB1 - 75.00 108.86 75.00 107.43 82.90 76.335 Ellipse Separation Pass - Cannery Loop Unit 01 - Cannery Loop Unit 01 RDPB1 - 10,175.00 671.66 10,175.00 502.18 10,495.70 3.963 Clearance Factor Pass - Cannery Loop Unit 05 - Cannery Loop Unit 05 - CLU05 - Cannery Loop Unit 05 - Cannery Loop Unit 05 - CLU05 - Cannery Loop Unit 06 - Cannery Loop Unit 06 - Canne 1,765.10 72.09 1,765.10 50.62 1,851.66 3.357 Centre Distance Pass - Cannery Loop Unit 06 - Cannery Loop Unit 06 - Canne 1,775.00 72.15 1,775.00 50.43 1,861.08 3.321 Ellipse Separation Pass - Cannery Loop Unit 06 - Cannery Loop Unit 06 - Canne 1,825.00 73.98 1,825.00 51.32 1,908.57 3.265 Clearance Factor Pass - Cannery Loop Unit 07 - Cannery Loop Unit 07 - Canne 351.93 83.82 351.93 81.48 358.42 35.714 Centre Distance Pass - Cannery Loop Unit 07 - Cannery Loop Unit 07 - Canne 375.00 83.90 375.00 81.46 380.87 34.304 Ellipse Separation Pass - Cannery Loop Unit 07 - Cannery Loop Unit 07 - Canne 9,900.00 1,175.57 9,900.00 1,030.62 10,864.00 8.110 Clearance Factor Pass - Cannery Loop Unit 08 - Cannery Loop Unit 08 - Canne 1,456.16 102.67 1,456.16 87.42 1,511.97 6.733 Centre Distance Pass - Cannery Loop Unit 08 - Cannery Loop Unit 08 - Canne 1,475.00 102.78 1,475.00 87.32 1,529.79 6.647 Ellipse Separation Pass - Cannery Loop Unit 08 - Cannery Loop Unit 08 - Canne 8,625.00 650.13 8,625.00 458.40 8,978.75 3.391 Clearance Factor Pass - Cannery Loop Unit 09 - Cannery Loop Unit 09 - Canne 1,758.09 166.27 1,758.09 151.91 1,901.15 11.584 Centre Distance Pass - Cannery Loop Unit 09 - Cannery Loop Unit 09 - Canne 1,800.00 167.02 1,800.00 151.32 1,942.64 10.638 Ellipse Separation Pass - Cannery Loop Unit 09 - Cannery Loop Unit 09 - Canne 2,075.00 206.81 2,075.00 182.43 2,206.42 8.482 Clearance Factor Pass - Cannery Loop Unit 10 - Cannery Loop Unit 10 - Canne 1,621.33 261.18 1,621.33 250.86 1,758.99 25.303 Centre Distance Pass - Cannery Loop Unit 10 - Cannery Loop Unit 10 - Canne 1,625.00 261.19 1,625.00 250.83 1,762.33 25.209 Ellipse Separation Pass - Cannery Loop Unit 10 - Cannery Loop Unit 10 - Canne 2,150.00 376.82 2,150.00 356.83 2,253.00 18.845 Clearance Factor Pass - Cannery Loop Unit 13 - Cannery Loop Unit 13 - CLU # 1,264.20 49.79 1,264.20 42.22 1,258.52 6.579 Centre Distance Pass - Cannery Loop Unit 13 - Cannery Loop Unit 13 - CLU If 1,275.00 49.85 1,275.00 42.22 1,269.06 6.533 Ellipse Separation Pass - 08 September, 2015 - 13:55 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Cannery Loop Unit 05 - CLU05RD WP1.a Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Cannery Loop Unit #1 Pad - Cannery Loop Unit 05 - Plan: Cannery Loop Unit 05RD - CLU05RD WPi.a Scan Range: 0.00 to 12,500.00 usft. Measured Depth. Scan Radius is 1,448.69 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse Site Name Depth Distance Depth Separation Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) Cannery Loop Unit 13 - Cannery Loop Unit 13 - CLU # 10,421.38 464.94 10,421.38 373.42 Survey too/ prOQram From To Survey/Plan (usft) (usft) 215.00 6,600.00 6,600.00 12,500.00 CLU05RD WP1.a Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Energy Company Kenai C.I.U. @Measured Clearance Summary Based on Depth Factor Minimum Separation Warning usft 10,066.00 5.080 Clearance Factor Pass - Survey Tool MWD MWD+SC+sag 08 September, 2015 - 13:55 Page 3 o/5 COMPASS HALLIBURTON Anticollision Report for Cannery Loop Unit 05 - CLU05RD WP1.a Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to CLU 05 @ 34.10usft (Original Well Elev). Northing and Easting are relative to Cannery Loop Unit 05. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is -150.000, Grid Convergence at Surface is: -1.10 °. Hilcorp Energy Company Kenai C.I.U. 08 September, 2015 - 13:55 Page 4 of 5 COMPASS Ladder Plot 1N ,,♦ i i II � O � ��I - X13 LEGEND L0 Ir neryL pllnit0l,t:anneryLoopUnH01,CanneryLoopUnit01 VO O neryL)op Unit01,CanneryLoopUnitOIRD, CANNERY LOOP UNfi 1 neryL UniCanneryLoopUnit01RDPB1,CANNERY LOOP U 411 CL neryL pllnit05,Cannery Loop UniiCLU05VO neryL opUnit06,CanneryLoopUnit06,Cannery Loop UnK06VO N neryL opUnR07,CanneryLoopUnitO7,CannetyLoopUnM7VO neryL pUniCannery Loop Unit08,CanneryLoopUnM8VO U 4 neryL pUnd09,CanneryLoopUnitO9,CannefyLoopUnM9VO p neryL pL)n@10,CanneryLoopUnRlO,CanneryLoopUnit10VO neryL op Unit 13,CanneryLoopUnit 13,CLU#13VO )05RD NP1.a N U 5000 7500 10000 12500 0 2500 Measured Depth (2500 usft/in) 08 September, 2015 - 13:55 Page 4 of 5 COMPASS 1N ,,♦ i i II � O � ��I - Ir 08 September, 2015 - 13:55 Page 4 of 5 COMPASS HALLIBURTON Anticollision Report for Cannery Loop Unit 05 - CLU05RD WP1.a Clearance Factor Plot: Measured Depth versus Separation(Clearance) Factor Hilcorp Energy Company Kenai C.L.U. 10.00 8.75 — 7.50 c LEGEND �anrle LoopUnit0l,CanneryLoopUnk01,CanneryLoopUnil01 VO 625nr `o a jLoopUnitOl,CanneryLoopUnit01RD, CANNERY LOOP UNrl01 n e LoopUnit01,CanneryLoopUnit0lRDPBI,CANNERY LOOP UNIi LL $ n e LoopUnd05,CanneryLoopUnit05,CL1105VO C 5.00 .�0 n e LoopUnd06,CanneryLoopUni[O6,CanneryL.00pUnilO6V0 $ n e LoopLJnk07,CanneryLoopUnit07,Canneryl-oopUnit07VO 01 3.75 '1 n e Loop W408, CanneryLoop Unit08, Cannery Loop Un M8 VO n e Loop LInit09, Cannery Loop Un109,CanneryLoopUni109VO $ e Loop UndlO,CanneryLoopUndlO,CanneryLoopUnit10VO 2.50 a LoopUnkl3,CanneryLoopUnill3,CLU#13VO Collision Avoidance Req WP1.a o Zone -Stop I)n hn 1.25- 0.00 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 0 Measured Depth (25001 sflfn) 08 September, 2015 - 13:55 Page 5 of 5 COMPASS Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, September 16, 2015 9:52 AM To: 'Monty Myers' Cc: 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)' Subject: RE: CLU 5RD (PTD 215-160) USIT log in 9 5/8" Monty, Looks like there is adequate isolation between the storage sands and the S/T window. I see some decent cement at 6400-6500 ft. I don't really see much at the KOP (6600 ft ) but the picture is clipped here and may be better below. Good luck with the new well. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@alaska.gov). From: Monty Myers [mailto:mmyers@)hilcorp.com] Sent: Tuesday, September 15, 2015 5:22 PM To: Schwartz, Guy L (DOA); Taylor Nasse Cc: Davies, Stephen F (DOA) Subject: RE: CLU 5RD (PTD 215-160) Guy, This is some of the USIT log imagery we have for the CLU 05. The whole file was too big to send. You can see that we have decent bond across the CINGSA zone and pretty good cement around the KOP area. Let me know if you need any further explanation. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Schwartz, Guy L (DOA)[ma iIto: guy. schwa rtz(�)alaska.gov] Sent: Monday, September 14, 2015 4:57 PM To: Monty Myers; Taylor Nasse Cc: Davies, Stephen F (DOA) Subject: CLU 5RD (PTD 215-160) Monty/Taylor: In looking at the P & A sundry and new drilling PTD for the well I didn't see where the cement quality at the 9 5/8" window was addressed. As the CINGSA gas sands (6100-6350ft) are right above the window (cut at 6600 md) is there a CBL out there that can document that you will have isolation while drilling the 8 %" open hole? May be a good idea to get a 9 5/8" CBL before the window is cut to verify. Eline will be there anyway to set the CIBP at 7030 ft. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@alaska.aov). 4"140NIL _,*j"jt;j IP i .boa i Y G� Davies, Stephen F (DOA) From: David Duffy <dduffy@hilcorp.com> Sent: Friday, September 11, 2015 5:27 PM To: Davies, Stephen F (DOA) Cc: Kevin Tabler; Monty Myers Subject: RE: CLU 5 RD (PTD #215-160) - Lease Question Attachments: Cannery Loop Unit Ex B Legals.zip; Cannery Loop Unit Ex A maps.pdf Hi Steve, Monty forwarded your request for additional information regarding CLU-5RD. The highlighted numbers on the map below correspond to the four (4) Cannery Loop Unit Tracts that are affected by the wellbore. Sec. 7 W-1 005NO11 W 6i 74 Cant'If • Loop 19 i 1 CLU-05R.D SHL 76 '. Fac 75 •r' • 73 4A j L � CLU-05RD TPH 4A 4 U 5A Af�GVgf i LOOP M The attached Cannery Loop Unit Exhibit B provides additional detail regarding each tract's legal description, acreage, lease number, mineral ownership, mineral interest, ORRI (if applicable), and working interest ownership. A set of corresponding unit maps is attached as Exhibit A. These exhibits were last updated in April 2015. The Surface Hole Location (SHL) of CLU-05RD falls on Cannery Loop Unit Tract 5 (Fee ADL 060569). Hilcorp is the mineral owner of this 66 acre tract. See Exhibit B at pg. 3. NOTE: the lease acreage was incorrectly stated on the permit to drill and should be corrected (66 acres, not 441 acres). The wellbore then passes through Cannery Loop Unit Tract 73. This is a private fee lease comprised of 57 acres. See Exhibit B at pg 20. The TPI and BHL fall on Cannery Loop Unit Tract 4A. The State of Alaska is the mineral owner of this 426 acre lease (ADL 324602). See Exhibit B at pg. 2-3 Please let me know if you have additional questions or need additional information. Have a great weekend. Regards, David Duffy, Landman Hilcorp Alaska, LLC Direct: 907-777-8414 Cell: 907-301-2629 dduffy@hilcorp.com This email may contain confidential and / or privileged information and is intended for the recipient(s) only. In the event you receive this message in error, please notify me and delete the message. From: Monty Myers Sent: Friday, September 11, 2015 8:52 AM To: 'Davies, Stephen F (DOA)'; David Duffy; Kevin Tabler Subject: RE: CLU 5 RD (PTD #215-160) - Lease Question I will have to defer this question to our land folks. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Davies, Stephen F (DOA) [maiIto: steve.davies(a)alaska.gov] Sent: Friday, September 11, 2015 8:48 AM To: Monty Myers Subject: CLU 5 RD (PTD #215-160) - Lease Question Monty, Could Hilcorp please provide a land map that displays all leases affected by the planned CLU 5 re -drill and provide a legal description of those affected leases? According to DNR's LAS website, lease ADL 060569 consisted of 183 acres, and the lease was transferred to CIRI in 1981. Hilcorp's Permit to Drill application indicates that this is indeed a fee lease, but it states that 441 acres lie within this lease (see Box 9 on the form). Thanks, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies(@alaska.gov. Sent from my desktop PC Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Wednesday, September 09, 2015 1:58 PM To: Davies, Stephen F (DOA) Subject: RE: Cannery Loop Unit 05RD (PTD #215-160) - Question Attachments: pg 2 CLU 05RD Drilling Program.pdf Great question Steve! The plat for CLU 05 says 20.5 with a reference that says existing GL is 21' CLU NO. 1RO m 10' • 14' WELL HOUSE N: 2388392.39 CLU NO. 5 E: 1472619.76 16.5'x 14 5' WELL HOUSE ELEV. 20.4' W 2386374.89 E 1412720.70 ELEV. 20.6' IOUSE EXISTING GRAVEL PAD ELEVATION = 214 24.3' x 36.5' COMM, POLE 2S PRODUCED 18.47 x 14.0' FLU10S BUILDINGS BUILDINGQ 16,6 (TIED ' 2 Col r,t BUII — PIPE RACK The drilling program reference, was a blatant error that 1 failed to update. Please toss page 2 and replace with the attached corrected copy. The dir. plan references 21' for GL. It is correct Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Davies, Stephen F (DOA)[mailto:steve.davies(aalaska.00v] Sent: Wednesday, September 09, 2015 1:17 PM To: Monty Myers Subject: Cannery Loop Unit 05RD (PTD #215-160) - Question Monty, The KB and GL elevation values listed on the Permit to Drill application form don't match the values given on the as -built plat or the planned directional survey. Could Hilcorp please provide corrected values? Thank you, Steve Davies AOGCC '005NO11W A/-1 le-z5'—p 5 74 19 ICLU-OSRD SHL 4 ... ... 7 4 -W/ (Cfl -1p -1-ili'lLo x CLU-05RD TPH 4A ANNE 73 I Pad Z_ejAcs; e— A/_116-7 v 75 LOOP UNIT '7ZI' L f 4 CLU -05R 1" BHL x_ 166cs' Cal( 7A Z_ 5A 76 11A ----------------------- • - ------------------ . . . . ... ........ x ----------- ------------ = j 17E 1 � 111IL n �; MessageMcAfee E-mail Scan AdobePiz DF 1311011eetingPersonal ,.Ignore X _4L -' To Manager L'�� Rules - _j a Find -0" _�_J Team E-mail Done OneNote JIM Related - Junk , Delete Reply Reply Forward T More I An �, Reply& Delete Create New Move Actions - Mark Categorize Follow Translate Zoom Unread Up- S Select Delete Respond Quick Steps Move Tags Editing Zoom You replied to thi5 mes.3ge on 9 11;2015 5:31 PA. ----------- ---------------------------------------------------------------- _j Message Cannery Loop Untt Ex B Legals.zlp (3 MB) ........................... .............................................................................. Cannery Loop Unit Ex A maps.pdf (924 KB) ................. ..................................... '005NO11W A/-1 le-z5'—p 5 74 19 ICLU-OSRD SHL 4 ... ... 7 4 -W/ (Cfl -1p -1-ili'lLo x CLU-05RD TPH 4A ANNE 73 I Pad Z_ejAcs; e— A/_116-7 v 75 LOOP UNIT '7ZI' L f 4 CLU -05R 1" BHL x_ 166cs' Cal( 7A Z_ 5A 76 11A ----------------------- • - ------------------ . . . . ... ........ x ----------- ------------ = j 17E 1 � 111IL n �; Exhibit B Cannery Loop Unit Effective March 1, 2015 Tract Mineral Mineral Roval ORRI ORRI Working serst Working tv Interest Interest Tract Tract Legal Description Acreage Lease # Owner Interest Percent Owner Percent Ownership Owner % 004 T5N-RI IW, S.M. Sec 5: Lots #9-#11 Sec 8: Lots # l -l8, # 10, NW4NE4, SW4NW4, SE4SE4, Excluding the Sterling C Pool within the boundaries of AOGCC's Gas Storage Injection Order No. 9` Below 13,500'. ConocoPhillips Alaska, Inc. owns 100% Minerals, only as to Sec. 5: Lots 10& I I; See, 8: Lots 1, 2, 4-7, 10, Portion of Lot 8 within NE/4 S W/4; Sec. 8: NW/4 NEA, SEA SE/4, 440.310 HAK#95 Hilcorp Alaska, LLC 10000% 12.500% AKA #FEE ADL 60568 Hilcorp Alaska, LLC 10000% Cannery Loop Unit Exhibit B Last Update: 4/142015 Page I of 54 Working Working Tract Mineral Mineral Royalty ORRI ORRI Interest Interest Tract Tract Legal Description Acreage Lease # Owner Interest Percent Owner Percent Ownership Owner % 004A T5N-RI IW, S.M. Segment I Sec 5: Surveyed, that portion of the Kenai River tide and submerged lands, including all portions thereof surveyed as part of the Kenai Tidelands Survey, Alaska Tidelands Survey, or any other survey of tidelands property lying outside the S2SE4, S2N2SE4, E2SE4SW4, SE4NE4SW4, S2N2NE4SE4,S2NE4NW4SE4and covering all subsurface horizons, 106.63 acres; Sec 8: Surveyed, that portion of the Kenai River tide and submerged lands, including all portions thereof surveyed as part of the Kenai Tidelands Survey, Alaska Tidelands Survey, or any other survey of tidelands property lying outside the S2, NE4, S2NW4, NE4NE4NW4, S2NE4NW4, SE4NW4NW4 and covering all subsurface horizons, 7.26 acres; Segment2 Sec 5: Surveyed, that portion of the Kenai River tide and submerged lands, including all portions thereof surveyed as part of the Kenai Tidelands Survey, Alaska Tidelands Survey, or any other survey of tidelands property, lying within the S2SE4,S2N2SE4, E2SE4S W4, SE4NE4SW4, S2N2NE4SE4, S2NE4NW4SE4, from the surface to the measured depth of 6,690 feet (4,871 feet true vertical depth subsea (fVDSS) vertically defined in the "Pool Type Log" Cannery Loop Unit (CLU) #8—11(AP14 50-133-20534-00), 134.75 acres, lying above the Cannery Loop Sterling C Pool; Sec 8: Surveyed that portion of the Kenai River tide and submerged lands, including all portions thereof surveyed as part of the Kenai Tidelands Survey, Alaska Tidelands Survey, or any other survey of tidelands property lying within the S2, NE4, S2NW4, NE4NE4NW4, S2NE4NW4, SE4NW4NW4, from the surface to the measured depth of 6,690 feet (4,871 feet 425310 HAK # 12 State of Alaska, 100.00% 12.500% ADL # 324602 Department of Natural Resources Hilcorp Alaska, LLC 100.00% Cannery Loop Unit Exhibit B Last Update: 4/14/2015 Page 2 of 54 Working Working Tract Mineral Mineral Royalty ORRI ORRI Interest Interest Tract Tract Legal Description Acreage Lease # Owner Interest Percent Owner Percent Ownership Owner % true vertical depth subsea[TVDSS]) vertically defined in the "Pool Type Log" Cannery Loop Unit (CLU) #8 well (API 50- 133-20534-00), 176.67 acres, lying above the Cannery Loop Sterling C Pool Segment A Sec 5: Surveyed, that portion of the Kenai River tide and submerged lands, including all portions thereof surveyed as part of the Kenai Tidelands Survey, Alaska Tidelands Survey, or any other survey of tidelands property, lying within the S2SE4, S2N2SE4, E2SE4SW4, SE4NE4SW4, S2N2NE4SE4, S2NE4NW4SE4, below the measured depth of 6,945 feet MD (5,101 feet true vertical depth subsea [TVDSS] in the "Pool Type Log" Cannery Loop Unit (CLU) 48 well (API# 50-133-20534-00), 134.75 acres, lying below the Cannery Loop Sterling C Pool; Set 8: Surveyed, that portion of the Kenai River tide and submerged lands, including all portions thereof surveyed as part of the Kenai Tidelands Survey, Alaska Tidelands Survey, or any other survey of tidelands property, lying within the S2, NE4, S2NW4, NE4NE4NW4, S2NE4NW4, SE4NW4NW4, below the measured depth of 6,945 feet (5,101 feet true vertical depth subsea [TVDSS] vertically defined in the "Pool Type Log" Cannery Loop Unit (CLU) #8 well (API 450-133-20534-00), 176.67 acres, lying below the Cannery Loop Sterling C Pool. 005 T5N-RI 1 W, S.M. 66.140 HAK #336 Hilcorp Alaska, LLC 100.00% 12.500% Hilcorp Alaska, LLC 100.00% Sec 7: E2 E2 SE/4, Lots # 10-13 AKA # FEE ADL incl. those portions of Lots # 14 & # 15 60569 located within the SE/4 SE/4; Excluding the Sterling C Pool within the boundaries of AOGCC's Gas Storage Injection Order No. 9' Cannery Loop Unit Exhibit B Last Update: 4/14/2015 Page 3 of 54 HAK #74 David John Hakkinen 33.33% 12.500% 073 T5N-Rl IW, S.M. 57.250 HAK #75 Wards Cove Company 100.00% 12.500% Hilcorp Alaska, LLC 100.00% Sec 8: Lot #9 Sec 17: Lots #11 & #12 Excluding the Sterling C Pool within the boundaries of AOGCC's Gas Storage Injection Order No. 9* Cannery Loop Unit Exhibit B Last Update: 4/14/2015 Page 20 of 54 Working Working Tract Mineral Mineral Royalty ORRI ORRI Interest Interest Tract Tract Legal Description Acreage Lease # Owner Interest Percent Owner Percent Ownership Owner % 068 T5N-R1 IW, S.M. 0.410 HAK #72 Virginia A. Poore 100.00% 12.500% Hilcorp Alaska, LLC 100.00% East Addition to the Original Townsite of Kenai Block 48, Lots #2 & #3. 069 T5N-RI l W, S.M. 0.164 HAK 972 Virginia A. Poore 100.00% 12.500% Hilcorp Alaska, LLC 100.00% East Addition to the Original Townsite of Kenai Block #8, Lot #4. 071 T5N-Rl I W, S.M. 0.165 HAK 673 Brian W. Hakkinen 100.00% 12.500% Hilcorp Alaska, LLC 100.00% East Addition to the Original Townsite of Kenai Block #8, Lot #6. 072 T5N-RI I W, S.M. 0.212 HAK # 74 Brian Wayne Hakkinen 33,33% 12.500% Hilcorp Alaska, LLC 100.00% East Addition to the Original Townsite of Kenai Block 48, Lot #7. HAK #74 Daniel Hakkinen 3333% 12.500% HAK #74 David John Hakkinen 33.33% 12.500% 073 T5N-Rl IW, S.M. 57.250 HAK #75 Wards Cove Company 100.00% 12.500% Hilcorp Alaska, LLC 100.00% Sec 8: Lot #9 Sec 17: Lots #11 & #12 Excluding the Sterling C Pool within the boundaries of AOGCC's Gas Storage Injection Order No. 9* Cannery Loop Unit Exhibit B Last Update: 4/14/2015 Page 20 of 54 TRANSMITTAL LETTER CHECKLIST WELL NAME: �/_ PTD: VDevelopment _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD:- -L G �9 C �T+; POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of weld until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are 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. Revised 5/2013 WELL PERMIT CHECKLIST Field & Pool KENAI C.L.U., TYONEK D GAS - 449577 Well Name: gram _ CANNERY LOOP UNIT 05RD Pro DEV_ _ Well bore seg PTD#: 2151600 Company HILCORP ALASKA LLC Initial Class/Type DEV/ PEND GeoArea 820 Unit 10320 On/Off Shore On Annular Disposal ❑ Administration 17 _N_onconven. gas conforms to AS31.05.0300.1.AM12.A-1)) - NA- - - - - _ . _ - _ _ _ - - 1 Perm it fee attached ---------- --- -- ------ -- - - - - -- NA ------- ----------- --- -- -- ----- 2 Lease number appropriate - - - - --- - - - - - - Yes - Surface location in Hilco_rp fee lease_ (formerly ADL 060569); wellbore passes thru_private fee lease 3 Unique well name and number _ - - - - - - - - - - - - Yes - - - in which H- - p_owns 100_% working interest, top productive interval and TD lie in ADL 324602._ 4 We.11.located in..a_ defined _pool - - - . _ . ..... Yes - - - - _ _ KENAI C.L.U., TYONEK D GAS -_449577 governed by CO 231 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 5 Well -located proper distance from drilling unit_boundary. Yes - - - - - _ _ Rule 3,-Well_Spacing: A Drilling Unit for the Beluga, Upper Tyonek, or Tyonek-"D" Gas Pools -is 16 Well located proper distance from other wells_ _ _ Yes -- - - - - established as the quarter -quarter subdivision of a governmental section occurring within - - _ - - �7 Sufficient acreage_avail- - - indrillingunit_ - - - _ - - - - Yes the affected area. Rule 4, Offset Limitations: A well bore.may -no expose for th_e_purposes of _ - - _ - - - 18 If -deviated, is wellbore plat included _ _ Yes - - _ _ - - regular production any -interval of a pool that_is_ located closer than 1,500' to the boundary of -the affected 9 Operator only affected party_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes area, or closer than 500' -to the boundary of the participating_ area established for thatpool._ 10 Operator has_appropriate bond in force - - - - - - _ _ _ _ - - - - - - Yes - - - - As presented,_well will conform -to those spacing requirements. _ - _ Appr Date 11 Permit_ can beissuedwithoutconservationorder_ - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - 12 Permit_canbeissuedwithoutadministrative _approval _ - _ - _ _ - - N . A _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ SFD 9/15/2015 13 Ca permit be approved before 15 -day wait_ _ - _ - - - - - - _ - - - - - - . .. .. NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - 14 Well located within area and -strata authorized by Injection Order # (put 10# in comments) (For_ NA_ _ - - _ _------------ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- 15 All wells_within_1/4_mile-area-of review identified (For service well only)_ _ - - - - -- - -- I NA_ . - _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 16 Pre -produced injector: duration of pre production Less than 3 months_ (For -service well only) . - NA- - - - - - - - - - - - - - - - - - - - ---------------------------------------------- 18 Conductor string_provided - - - _ _ NA- - .. _ - _ - Conductor set-in CLU 5 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Engineering 19 Surface casing_ protects all -known USDWs _ _ _ . - . NA_ - - - - - - - Surface casing set and fully cemented - _ _ _ - - - - - _ 20 CMT_vol. adequate to circulate_on conductor & surf csg - - - - - - . - - N_A------------------------------------------------------------ - - - - - 21 CMT vol adequate_ to tie-in_long string to -surf csg--------- - -- - - - - - - - - - - - - - N_A-------- 9 5/8" casing already set and cemented. -Window to be cut at 6600 ft md, - _ 22 CMT -will coverall known_ productive horizons- - - - - - - - - - - -- - - -- Yes - - - _ _ 7 5/8" and 4.1/2" liners with—both—be -fully cemented, 23 _C_asing desions adequate for CJ, B &- permafrost ------------------- - - - - - - - Yes - - - - - - _ BTC calculations provided and meet industry standards._ _ _ _ _ _ - _ - - _ _ - - - _ _ _ _ _ _ _ _ 24 Adequate tankage_or reserve pit - - - - - - - - - - - - - - .. _ . - - - .. - _ - - - - _ - .. - - . Yes - - - _ _ _ _ Rig has steel tanks, _( Saxon 169)_ --All waste to be -transported to G_ & I_well. 25 -If _a_re-drill, has_a 1.0-403 for abandonment been approved - - - - - - - - - - - - - - - - - - - - - Yes _ - _ _ _ _ _ 315-554 (pulling dualstring-for P & A_)_ _ _ . _ _ _ - _ _ _ . _ - _ - 26 Adequate wellbore separation_pro- -ed- - - - - - - - - - - - - _ _ - - - -Yes _ _ _ - _ _ _ proximity_ analysis performed .. No_issues. - _ - _ _ _ - - - - - - - - - - - - - - _ - - 27 If_diverter required, does it meet regulations- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ _ _ _ _ _ _ - Wellhead in place. -BOPE will be used._ - _ - _ _ _ _ _ - - - - - Appr Date 28 Drilling fluid_ program schematic & equip list adequate- - - - - - - - - - - - - - Yes _ _ _ _ _ - _ Max formation_ press= 4863_psi_ ( 8.7 ppg) will_ drill with 9.5 - 11_ ppg mud- - - - _ _ - - - - - _ _ _ _ - _ - - - - _ GLS 9/15/2015 29 _B_OPEs,_do they meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Saxon 1169_ has 11"_5000 psi BOPE - _ _ - - _ - - - - - - _ - - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - - 30 _B_OPE_press rating appropriate; test to -(put psig in comments)_ _ _ _ _ - - - - - - _ Yes - - - - - - - MASP= 3783 psi (will test_BOPE_to 4000 -psi_- annular to 2500 psi)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 31 Choke manifold complies WAPI_RP-53 (_May 84)- - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - _ _ - _ _ _ _ _ _ - - - - - _ _ _ _ _ - - _ _ _ _ _ _ - - - - - - _ - _ - _ - _ - - - - - - - - - _ - - _ _ _ _ _ _ _ - - - - 32 Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - Sundry -required- for perforating well._ - - - - _ _ _ - - - - - - - - - _ _ - - _ - _ - - - - _ _ _ - _ _ _ _ _ _ _ - - 33 Is presence_ of H2S gas probable - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - No- I - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 34 Mechanical -condition of wells within AOR verified (For service well only_) - - - - - - - - - - - - - NA_ _ _ - - _ - _ _ _ _ _ - - - - - - - _ _ _ _ _ _ - - - _ _ _ _ - - - _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ - _ _ - - - - - - - _ _ _ _ _ _ _ _ . 35 Permit_can be issued w/o hydrogen_ sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ 1-112S not anticipated based on offset -wells -- _ _ . _ _ _ _ _ _ - - - - - _ - - - _ _ - _ _ _ - _ - - - - - - - _ _ _ _ _ _ . Geology 36 Data_presented on potential overpressure zones_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ - Planned mud weights appear a-deq uate_to control -the _operators forecast of most likely - - - - - -- Appr Date 37 Sei_smic_analysis of shallow gas -zones ---------------------------------- NA_ - _ - - - - - pressures in -the geologic prognosis that indicates_we_II Will -be -under -pressured -to - - - - - - _ - - _ _ _ _ _ _ - SFD 9/11/2015 38 Seabed condition survey (if off -shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ - - _ _ severely under -pressured from the KOP to the Tyonek D2 sand. _ _ - - - - _ _ _ _ _ _ _ - 39 Contact name/phone for weekly_ progress reports [exploratory only] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ _ _ - _ _ - - - - _ _ _ - - - - - _ - _ _ _ - - - - _ _ _ _ _ - - - - - - - _ - - - - - - - - _ - - - - - - - - _ _ _ _ _ _ _ _ _ _ - Geologic Engineering Public S/T of CLU 5 at 6600'ft (just below CINGSA sands) targeting bypassed Tyonek sands. GIs Proposed KOP will lie about 300' Commissioner: Date: Co . r: Date Commissioner Date below the base of CINGSA's gas storage sands. Guy requested a CBL across the 9-5/8" casing BEFORE the window is cut to ,7 j `tj 1 `) I'S verify cement quality and isolation. SFD 9/15 1 CLU 05RD 50-133-20474-01-00 Cannery Loop Unit Kenai Peninsula Borough, Alaska October 13, 2015 – November 5, 2015 Provided by: Approved by: David Buthman Compiled by: Donna New Ralph Winkelman Distribution Date: December 8, 201 5 2 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ............................................................................................ 3 1.1 Equipment Summary ................................................................................................................. 3 1.2 Crew.......................................................................................................................................... 3 2 GENERAL WELL DETAILS .............................................................................................................. 4 2.1 Well Objectives .......................................................................................................................... 4 2.2 Hole Data .................................................................................................................................. 5 2.3 Daily Activity Summary .............................................................................................................. 6 3 GEOLOGICAL DATA...................................................................................................................... 11 3.1 Lithostratigraphy ...................................................................................................................... 11 3.2 Lithology Details ...................................................................................................................... 12 3.3 Sampling Program ................................................................................................................... 22 4 DRILLING DATA ............................................................................................................................ 23 4.1 Surveys ................................................................................................................................... 23 4.2 Bit Record................................................................................................................................ 26 4.3 Mud Record ............................................................................................................................. 27 4.4. Drilling Progress ...................................................................................................................... 29 5 SHOW REPORTS .......................................................................................................................... 30 6 DAILY REPORTS ........................................................................................................................... 31 Enclosures 2” / 100’ Formation Log (MD/TVD) 5” / 100’ Formation Log (MD/TVD) 2” / 100’ LWD Combo Log (MD/TVD) 2” / 100’ Drilling Dynamics Log (MD/TVD) 2” / 100’ Gas Ratio Log (MD/TVD) Final Data CD 3 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type /Position Total Downtime Comments Computers – Surface Logging (3) Rigwatch Server, Rigwatch Remote DML, LWD WITS, Rigwatch Remote 0 Ditch gas QGM gas trap; Flame ionization total gas & chromatography. Hook Load / Weight on bit WITS from Pason 0 Mud Flow In Calculated value derived from Strokes/Minute and Pump Output 0 Mud Flow Out WITS from Pason 0 Pit Volumes, Pit Gain/Loss WITS from Pason 0 Pump Pressure WITS from Pason 0 Pump Stroke Counters (2) WITS from Pason 0 Rate of Penetration Calculated from Pason 0 RPM WITS from Pason 0 Torque WITS from Pason 0 WITS To/ From Pason Rigwatch Remote (HP Compaq) 0 1.2 Crew Mud Logging Unit Type: Arctic Mud Logging Unit Number: ML030 Logging Geologists Years1 Days 2 Sample Catchers Years Days 2 Donna New 9 10/13 Doug Merkert 6 15 Ralph Winkelman 24 10/13 Karen Austin 4 24 Paul Webster 36 23 Chad Record 6 23 Russell Wardner 16 7 *1 Years experience as Mudlogger *2 Days at wellsite between rig up and rig down of logging unit. 4 2 GENERAL WELL DETAILS 2.1 Well Objectives CLU 05RD, is a development gas well planned to be re-drilled in a northeasterly direction from CLU 05, utilizing the existing casing program down to 6600’MD/ 5426’ TVD. At 6600’ MD, the parent wellbore will be sidetracked and a new wellbore will be drilled penetrating the Beluga and Upper Tyonek formations. A 4000’, 8 ½” open hole section is planned and after the depleted TY T-9B has been penetrated and drilled through, a 7 5/8” flush joint drilling liner will be run and cemented. We will drill a 1900’, 6 ¾” open hole section through the remaining upper Tyonek and Deep Tyonek formations to a total depth of 12500’. A 4 ½” production liner will be hung and cemented in place. The well will be cleaned out and swapped to clean production fluid, and then a 4 ½” production tieback will be run to surface. Operator: HILCORP ALASKA, LLC Well Name: CLU 05RD Field: Cannery Loop Unit County: Kenai Peninsula Borough State: Alaska Company Representatives: Rance Pederson, Shane Hauck, Shane Barber, Marvin Rogers Location: Surface Coordinates 180’ FSL, 270’ FEL, Sec 7, T5N, R11W, SM, AK Ground ( Pad ) Elevation 20.5’ AMSL Rotary Table Elevation 38.5’ AMSL Classification: Single Zone Development Gas API #: 50-133-20474-01-00 Permit #: 215-160 Rig Name/Type: Saxon 169 / Land / Double Spud Date October 13, 2015 Total Depth Date: November 5, 2015 Total Depth 12940’ MD / 11253.95’ TVD Primary Targets Reserve Zones in the Upper Tyonek and Deep Tyonek Primary Target Depths Up to 5 known potential Primary Targets and 6 Secondary Total Depth Formation: Deep Tyonek Completion Status: 4.5” Casing LWD-MWD Services. Halliburton / Sperry Drilling Services Directional Drilling Halliburton / Sperry Drilling Services Drilling Fluids Service Halliburton / Baroid Wireline Logging Service Schlumberger 5 2.2 Hole Data Hole Section Max Depth TD Formation MW ppg Dev oinc Csg Dia Shoe Depth LOT ppg MD (ft) TVD (ft) MD (ft) TVD (ft) Window 6544’ 5371.91’ Beluga 8.95 13.15 9 5/8” 6544’ 5371.91’ 11.2 8 ½” 10450’ 8764.1’ Tyonek 10.4 4.2 7 5/8” 10448’ 8762.1’ 12.0 6 ¾” 12940’ 11253.95’ Tyonek 11.3 1.05 4 ½” 12917’ 11230.8’ -- 6 2.3 Daily Activity Summary 10/13/2015: Canrig arrives on location and rigs up. RIH to 6483’ will whipstock and mill assembly. Set whipstock @ 14L. Mill window from 6527’ – 6544’. Drill new formation 6544’ to 6562’. 10/14/2015: Lost all returns at 00:15. Lined up on trip tank to monitor losses. Trip tank could not keep up. Lined up to pump down kill line with mud pumps, pumped through kill across active, @ 00:45 mud lost was 113 bbls. @ 1:35 pumped 40 pp/bbl pill and spotted it outside the bit at 6517’. Broke out and racked back 1 stand, saver sub broke on top and stayed on stand. Monitored well and built 25 bb, 100pp/bbl Vanguard pill. @ 04:15 started to pump down backside. Monitor well while build mud volume. Monitor well with trip tank. Close bag and squeeze lcm pill downhole. Pumped away 230bbls. Continue monitor well and losing 1 bph. POOH from 6522’ to 943’. Lay down 10 joints HWDP. Total mud losses 340 bbls. Laydown directional tools and mills. Inspect same. Start pick up BHA, motor tagged up at 26.4’ from rig floor. Found out binding up on casing due to the ID and the 1.5 deg bend in the motor. Wait on orders, monitor well. Tried again, set down and then passed on through. 10/15/2015: Finish pick up BHA and pulse test MWD; TIH with singles from 773’ to 5058’. RIH 5058’ to 6482 with stands; Close Hydrill and perform FIT with test pump. 11.2 EQMW; rig service; Line up motor high side and slide through window; Drill 6562’ to7076’ 10/16/2015: Continue drill from 7076’ to 7350’. CBU. Wipe hole back to 6910’, tight at 7145’, 7018’, 6970’, 6951’. Wash out of hole from 6910’ to 6507’. Service rig. Monitor well for losses, .8 bbl/hr. RIH, no tight spots. Drill from 7350’ to 8155’. Pump 20 bbls high viscosity sweep and circulate until hole is clean. Begin wiper trip. 10/17/2015 : Wiper Trip from 7300' to 6510' pumping out of hole; pulled on elevators from 6859' to 6510'; rig service( grease crown, draw works, iron rough neck, blocks and TD; check all fluids in motors). Run in hole from 6510' - 8154' and drill ahead to 8590'. Wiper trip from 8590' to 8088' with no tight spots observed. Return to bottom and drill ahead. 10/18/2015: Drill ahead from 9025' to 9147'; pump tandem sweep and circulate out with 100% increase in cutting and sweep came back on time; POOH from 9142’to 7660' tight hole with constant overpull. Run in hole from 7660 to 9146 had 17' of fill; drill from 9147’ to 9150'. Drill from 9150' to midnight depth of 9467'. Continue to drill ahead to 9767’ for a planned short trip, currently at 9710’. 10/19/2015: Drill ahead from 9710' to 9767'; pump high vis sweep and circulate out with an 80% increase in cuttings; arrived 70 bbls early; pull out of hole from 9767' to 8520'; monitor well ( lo sing 0.9 bbls per hour;) run back in hole to 9767'; had 29' of fill in hole washed down; drilling from 9767' to 9780'. Change tour. Drill ahead from 9780' to 9861' midnight depth’ 10/20/2015: Drill from 9467'to 10139’; pump strata clean sweep and circulate out with 300% increase in cuttings – came back 85 barrels early; drill from 10139’ to 10200’; pump strata clean sweep and circulate out with 300% increase in cuttings – came back 52 barrels early; weighting up mud. Pump out of hole from 10000 to 9765 and started to get gas max gas 933 units; trip back to bottom and tag fill at10184’ and wash the remainder of the way back to bottom; circulate and condition mud and weight up from 9.6 to 9.9 ppg; pump out of hole from 10195 to 9450’ with gas reaching a max of 1044 units; run back in from 9450’ to 10200 washing and reaming as needed at tight spots at 9636’, 9750’, 9860’, 9885’, 10119’. Circulate bottoms up. 7 10/21/2015: Circulate and reciprocate, pump 41 barrels strata clean sweep; came back 31 barrels early wit 300% increase in cutting; increase lubes to 3% and bring mud weight up to 10ppg with BaraCarb; pull out of hole on elevators from 10200’ to 7040’; three barrels over calculated displacement. Pump 30Barrels Strata Clean Sweep. Sweep arrived back 35 ba rrels early with 200% increase in cuttings; flow check – slight seepage; pull out of hole from 7040’ to 6478’ on elevators with no issues. Slip and cut 170’ drill line; grease equipment; check and adjust brakes; check RigSmart; replace bolt on bolt tube. POOH to 776 ‘ with no issues; hole took 7 bbls over calculated displacement; rack back 8 stands HWDP and 2 stands flex collars; lay down unneeded BHA; download MWD data 10/22/2015: Lay down directional tools; inspect draw works; adjust brakes; inspect t op drive; grease wash pips; pick up directional tools; trip in hole from 311’ to 3300; fill pipe and circulate bottoms up with 510 gpm while rotating 90RPM and reciprocating; MWD pulse test okay; trip in hole from 3300’ to 5900’.Trip to bottom and circulate. 10/23/2015: Circulate out gas with trip gas of 1077 units and begin MAD pass; MAD pass 9766 ’to 9120’; MAD pass 9120’ to 8396’. MAD pass 8396’ to 7625’; Pump 45 barrel Strata Kleen sweep while MAD pass at 8215’; 100% increase in cuttings; MAD pass from 7625’ to 10/24/2015: Making MADPASS pull BHA through window while pumping; circulate and pump 50 barrel Strata Kleen sweep with 100% increasing cuttings; returned 43 bbls early; continue to pump out of hole to 3036' at report time. 10/25/2015: Pump out of hole after MADPASS from 3036’ to surface, lay down directional tools, organize and clean rig floor; drain and flush stack; pull wear bushings; install test plug and joint; fill stack with water and purge water from test lines and equipment; test BOPs; pull test plug and blow down test lines; install wear bushing; service top drive and draw works; check back lash and end play on top drive; change washed pipe; make up directional tools. Make up BHA and run in hole to 6460' filling pipe every 3000'; circulate bottoms up @6460' with return of 1055 units gas. Max Gas today 1103 units @ bit depth 3108'. 10/26/2015: Circulate and condition mud and add LCM in preparation for loss zone. Scratch bottom and break in and pattern bit then stage up WOB; drill ahead from 10200 to 10450' (casing point); circulate and condition mud and strip back LCM. 10/27/2015: Pull out of hole from 9683 to 9180; trip back in hole to bottom @ 10450’ no fill; circulate and condition mud; pump sweep around; and circulate out of hole; attempt to POOH at 10Am but experienced mud u tubing up the pipe and excessive drag when pulling on elevators; pump Strata Kleen sweep and circulate out of the hole; POOH from 10450’ to 6490’; with one tight spot at 10390’; service top drive and change grabber box dies; circulate bottoms up inside casing with 300 units gas at bottoms up; blow down top drive and kelly hose after circulating. POOH from 6490’ to surface while breaking with tongs due to over torque; laying down BHA and breaking off bit. 10/28/2015: Made up shoe track and trip in hole with casing from shoe to 2400’; lost returns at 2400’ fill down backside with trip tank and down casing with hole fill; pump LCM mud down backside with hole fill pump; creep into hole with casing from 2400’ to 3890’leeping backside full with LCM mud from trip tank; top fill casing and build mud volume in pits. At report time bit depth was 5636'. 8 10/29/2015: Build mud volume while sitting inside casing at 6491’ and pump 5 to 10 bbls down pipe every 15 minutes and rotate string while pumping. Make up crossovers, pony subs and drill pipe to cement head and lay out together on catwalk; trip in hole from 6490’ to10448’; circulate casing with 142 GPM@980psi; lost 497 bbls from 6am to 6pm. Circulate casing 133GPM@740psi while building mud volume; rig up cement lines; hold PJSM and prime cement pumps; pressure test lines, start pumping cement; Schlumberger pumped 102.7 barrels/15.3 cement. Started to displace; 100 barrels into displacement had to go to rig pump; pumpe d 152.6 bbls; returned to Schlumberger bumped plug with pressure up to 2700 psi; total displacement 265.5 cement in place @2:30am with no returns; set liner; set packer; pressure test annular to 1166 psi for 10 minutes; circulate bottoms up GPM 245 and Pressure 345; Max gas 1160 units; lay down cement head; drop wiper ball; circulate; prep tools for slip and cut; hang off blocks. 10/30/2015: Cut and slip 120’ of drill line; lay down pup joints; break down bottom side of cement head and lay back out to be turned around; POOH from 6400’ to stinger; break and lay down stinger; pick up cement head and break off cross over and pup joint off of top and lay back out; pull wear bushing and install test plug and test joint; change out upper pipe rams back to 2 7/8ths - 5”VBR; prep to test pipe rams; fill stack with water and begin purging air from equipment; test upper 1.5”VBR’s – 2510low for 5 minutes and 4000 high for 10minutes; remove test plug and install wear bushing and rig down test equipment. 10/31/2015: Continue to build new mud, clean tanks, redress mud pumps with 5” liners, stage BHA to catwalk, pick up and make up directional BHA. Transfer old mud to tank 2 to warm up MWD tool, warm up mud, MWD and LWD, upload data to LWD; Safety meeting over installing nukes; install nukes in LWD; continue to make up directional tools; trip into hole from 250’ to 6456’; pick up singles and Spiro-torque subs as tripping into hole; work to make through liner top @ 6456’. Circulate and prepare for trip out of hole; pull out of hole from 6456’ due to clearance issues. Lay down BHA; change bit and remove sources; make up BHA with new bit and upload; run in hole with 6 1/8 from 631’ to 6477’; pick up singles and Spiro, torque; 11/1/2015:Single in the hole from 6460’ to 8389’ and add Spiro Torque subs to string as per tally; trip out of derrick from 8389’ to 10254’; circulate bottoms up; test casing to 3000 psi for 30 minutes; pumped 7 barrels to pressure up to 3000 psi and bled back 6.5 barrels; tag plugs @ 10296’; establish off bottom drilling parameters; took weight and started drilling cement and plugs @ 10294’; drilled cement and plugs from 10294’ to 10297’. Drill out shoe track; displace over to 10.1 ppg mu; observed increase in Torque. 11/2/2015: Pump 584 barrels 10.1 ppg to displace; rig up test equipment and perform FIT test to 12.0ppg EMW;@ 842psi and held for 10 minutes; no pressure loss; pumped 64 gals and 64 gals returned when pressure bled off; Drill from 10470’ to 10595’. Noticed influx into well bore, opened choke, HCR, and closed annular on flow; established kill procedure; began killing well with 11ppg mud; circulating with 112 GPM and taking retur ns through choke and gas buster; circulated 1 full circulation; killed pump to check for pressure and flow. Continue to circulate 11.3 ppg around to influx with 187 GPM and 1235 psi pressure; reciprocate pipe; POOH from 10795’ to 10385’ with no issues-proper displacement –well static; perform fit test to 13.0ppg EMW to 820psi and held for 10 minutes; pumped 79 gals and returned 77 gals; blow down all test equipment, choke manifold, kill line poor boy; rig service – grease draw works, top drive IR, check brakes; grease crown and blocks; run in hole from 10385’ to 10795’ and pick up turbulizer; drill from 10795 to 11115. 11/3/2015: Drill from 1115 to 11394’, drill from 11394 to 11670’; drill from 11670 to 11761’; circulate bottoms up and prep for wiper trip; POOH – WIPER TRIP- from 11761’ to 10700 on elevators with no issues; hole took 1.6 barrels over calculated displacement; run in hole from 10700’ to 11761’ with no issues- correct displacement; drill from 11761’ to 11974’. 11/4/2015: Drill from 11794 to 12409’; circulate bottoms up; stand back one stand and blow down top drive turn elevator. POOH from 12409’-11700’; Run in hole from 11700’ to 12407’ (hole took prop displacement) drilling from 12409 to 12660’; Circulate sweep out; 9 11/5/2015: Drill form 12816’ to 12940’. Circulate bottoms up @ well TD. Max Gas 75Units survey flow check, no flow, POOH on Elevators from 12940’to 12588’ tight hole, pump from 12588 to 11705’; pull on elevators 11705’ top 10431’. Circulate 1.5 bottoms up with 50% increase in cuttings; slip and cut drill line; Run in hole from 10440 to 11807’ run in hole from11807 to 12928’; 12 feet of hole fill; wash down from 12928’ to 12940’circulate and pump tandem sweep and circulate out; POOH from 12940’ to 11499’. 11/6/2015 POOH on elevators from 11499’ hole fill good; flow check well; air out pump # 1; pump 25 barrel high vis sweep; max gas back 64 units; sweep back 20 barrels early with 50% increase in cuttings; blow down top drive; POOH on elevators 10368’ to 6407’ pump Strata Kleen sweep; max gas back 116 unit, back 46 barrels early, no increase in cuttings; blow down top drive; continue to POOH 6407’ to 4294’ hole fill good. POOH from 4294’ to 116’ (hole took 32 barrels over displacement;) lay down directional tools; down load data; lay down TM collar; PWD collar; PWD; slim phase; DM collar; and mud motor. Drain stack; remove wear bushing; install test plug; rig up test equipment; and fill BOP’s with water/perform shell test; Test #1 upper, Mez. kill valve; dart valve; Hydrill I-BOP and CM10, 11, 12 valves; Test #2 TIW, Manual I-BOP; choke and kill HCR valves; Test #3 inside kill and choke valves; Test#4 Lower pipe rams; Test # 5 Hydrill Bag low 250psi; high 2500psi’ Koomey draw down test stating 3100psi; After closures system pressure1425psi, 23 seconds to re-gain 200psi and 101 seconds to re -gain full system pressure. Test 6# Blind rams. 11/7/2015: Finish blind ram test; rig down test equipment; and blow down choke manifold, choke line, kill line; and top drive; install wear ring and clear rig floor; PJSM with e-line; rig up e-line; make up e-line tool; flow check well no flow; test e -line quad combo tool; bad test; change out EDTC section; re-test; test good; load RA source; Run in hole with e-line from surface to 2000’. Continue running in hole with e-line from 2000 to 10300 and check WT before running into open hole, continue to Run in hole from10300 to 11275’ – e-line string weight to high; Pull out of hole from 11275 to 200’. PJSM on rigging down wire line; Pull out of hole from 200’ to surface remove radioactive source and rig down e=line tools. Rig down Schlumberger wire line tools and equipment; pick up and make up directional tools; warm up MWD tools; down load data; load radioactive sources; run in hole from 135’ to 629’; continue to run in hole from 629’ to 6213’. 11/8/2015: Continue to run in on elevators from 6213’ to 6399’; fill pipe, obtain torque value 9.2K ; blow down top drive; continue to run in hole on elevators from 6399’ to 10430 filling pipe every 2500’; Fill pipe and obtain torque value 13.5K; blow down top drive; continue to run in on elevators from 10430’ to 12775’ with tight spots at 11385’ and 12550’; set down 20K and worked through 12775’ set down 25k worked pipe; over pull 50K; kelly up and break circulation at 125 GPM; Pressure showed signs of pack off, staged up pump and RPM and worked pipe to 12785’. Circulate bottoms up and got back 1041 units of gas; wash down 12775 to 12940’ circulate bottoms up, gas back 399 units; MAD pass from 12940’ to 12785’ bit depth at midnight. 11/9/2015: Continue to MAD pass from 12292’ to 11793’; continue to MAD pass from11793’ to 11297’; continue to MAD pass from 11297 to 10920; continue to MAD pass without pumps due to pump pressure drop from 10920’ to 10700’(mi dnight depth). Continue MAD pass from 10700’ to 10368’. Pull out of hole from 10368’ to 7507’’. Perform rig service; grease crown, blocks, TDS, draw works, and the iron rough neck. 11/10/2015: Continue to pull out of the hole from 7507’ to 6448’; stopped to load carbide bomb; retested surface equipment no bleed off, call from town made change of plan to pull out of hole and lay down BHA; blow down top drive; PJSM with crew on M.O.C.; continue to pull out on elevators; from 6448’ to 4631’, found hole in pipe in joint number 130; change out joint and continue out of hole to 74’; PJSM with MWD, directional and rig crew; unload source and download tools; lay down BHA; clear and clean rig floor and ready for picking up BHA; PJSM with rig crew and directional driller, make up bit; bit sub, stab T/NM collar and run in hole to 71’.Run in hole from 71’ to 6400’;( Midnight depth); continue to run in hole from 6400 to 11405’; Wash and ream from 11405’ to 11415. 10 11/11/2015: Wash and ream as needed from 11415 to 11924’ (@ 11458 circulate; @ 11509’ ream; @ 11695’ circulate; @ 11730’ to 11735’ ream; @ 11868’ circulate; wash and ream from 11924’ to 11986’; circulate bottoms up with max gas 757 units; run in hole on elevators from 11924’ to 12118; wash and ream from 12118’ to 12889’. Wash and ream from 12889’ back up to 11924’; wash and ream from 11924’ to 12940’; pump high vis sweep and circulate out; POOH from 12940’ to 4800 ‘ (Midnight Depth.) 11/12/2015: Continue to pull out of hole on elevators from 4800 to 2768’; lay down crossovers and mill; clean rig floor and get rig floor ready to trip back in hole; hole fill =14.88. Run in hole on elevators from 2768’ to 10394; fill pipe every 2500’ ; change out top joint on stand # 88 and replace; continue to run in hole; flow check well; install floor valve; hang block; slip and cut drill line; cut 152’ of drill line; reset com; re set rig smart; rig service; grease top drive, draw works, crown, and check fluid le vels in floor motor; torque drive line bolts; run in hole from 10394’ to 11574’; hole fill = 5.66 barrels. Run in hole from 11574’ to 12844’ with well taking proper displacement; wash and ream from 12844’ to 12940’; pump 19.6 barrels of vis 120 high vis sweep and circulate out with 50% increase in cuttings and 5 barrels early; Trip gas 518 units. Pull out of hole from 12940’ to 12931’ (Midnight depth.) Continue to pull out of hole from 12931’ to 11298’; run in hole from 11298’ to 12940’ 20’ of fill with hole fill 0.4 bbls over calculated; pump high vis sweep (19 bbls and134 vis) and circulate out. 11/13/2015:Condition mud and circulate; continue to weight up to 11.6ppg @7:15 pump 64.48bbls, black pill 12ppg and spot in open hole; flow check; no flow; blow down top drive; pull out of ole on elevators from 12940’ to 10427’ circulate bottoms up@shoe100% return; continue to pull out on elevators from 10427’ to 6396’; pump 22bbls Strata-Kleen sweep- returned on time 10% return; flow check well; stage equipment to lay down drill pipe; clean rig floor; pump 14 bbls dry job @ 13.6 ppg; pull out of hole laying down excess drill pipe starting with stand #94 from 6396’ to 6126’; continue laying down excess drill pipe from 6126’ to 3831’ ( 82 joints laid down); pull out of hole from 3831’ to 270’ (midnight depth). 11/14/2015: L/D BHA. Clear rig floor. Rig up Weatherford tools. PJSM with Weatherford for picking up casing. Pick up and test float equipment. RIH with 4 ½” liner.to 2642’. PJSM with Baker hand for picking up hanger. Pick up hanger. Rig down Weatherford tools. RIH with liner on drill pipe. 11/15/2015: Continue RIH. Land casing. CBU and condition mud for cement. Cement in place. 11 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Tops picked by Hilcorp Geo, Jacob Dunston FORMATION PROGNOSED ACTUAL MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) Middle Beluga 7034 5823 -5765 7061 5843 -5785 Lower Beluga 8129 6728 -6670 8148 6748 -6690 Upper Tyonek 9551 7904 -7846 9525 7886 -7828 TY T-9B 10333 8638 -8580 10308 8622 -8564 TY 91-2 10778 9083 -9025 10765 9079 -9021 TY D2 11066 9372 -9314 11035 9349 -9291 TY D3A 11321 9627 -9569 11269 9583 -9525 TY D5A 11594 9900 -9842 11568 9883 -9825 TY D6 11696 10002 -9944 11711 10025 -9967 TY D7 11866 10172 -10114 11923 10237 -10179 TY D8 12111 10417 -10359 12102 10416 -10358 TY D9 12367 10673 -10615 12346 10660 -10602 12 3.2 Lithology Details As per Hilcorp direction, a Canrig-provided full service mudlogging program, with lithology descriptions of interval-collected rock cuttings samples in the Beluga and Tyonek Formations , was initiated at the 9 5/8” window at (6544’ MD / 5371.91 ’ TVD ). The Kenai Group formations of Alaska’s Cook Inlet Basin, which include the Sterling, Beluga, and Tyonek were deposited in a variable -energy fluvial system within a large closed fore -arc basin. The stratigraphic column consists of very dominant thin to massive sections of sandstone and claystone -siltstone , which are interrupt ed by extensively -distributed thinner zones of coal and carbonaceous rocks, locally to generally abundant thin layers of original and re-deposited volcanic ash, and minor beds of basal or modal conglomerate. Gradational upward-fining sequences and bi -modal zones are abundant within the sandstones. Stratovolcanoes , perpetually forming along the fore-arc’s margins ; produced abundant widely -distributed deposits of vitric air fall volcanic ash; which became a major directly -derived source, and/or a consistent lithogenic influence, for all Tertiary soft -sediment rocks in the Cook Inlet Basin. Note that the special modifying term “tuffaceous” in Canrig Lithology Descriptions was created to address the div ersity of volcanic -origin rocks in the Cook Inlet basin, and its use may include everything from discernible micro-shard conce ntrations of disaggregated volcanic glass to rare layers of vitric ignimbrite. Sand (6544' - 6660') = note extremely poor sample quality (85% - 99%) nut plug and other lcm; medium to medium light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray; very fine upper to medium lower, dominantly fine; angular to subangular; poor to fair sorting; unconsolidated; non calcareous with abundant safe carb mud additive used as lcm. Sand (6660' - 6720') = continued poor sample quality 50% nut plug and safe carb; medium to medium light gray with individual grains dominantly clear to tra nslucent quartz and volcanic glass, light to dark gray, black and greenish gray; very fine upper to medium upper, dominantly fine; angular to subangular; fair to good sorting; unconsolidated; non calcareous. Coal (6720' - 6770') = black with brownish black secondary hues; very firm to hard and brittle; massive; platy to blocky; planar fracture dominant with trace conchoidal; smooth to slightly gritty texture; resinous to earthy luster; lignitic to subbituminous, occasionally grading to carbonaceous shale; no outgassing observed; present in thin beds in dominantly sand formation. Sand (6770' - 6840') = continued lcm contamination, 25% nut plug and safe carb; medium light to light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray, black, light gray, greenish gray; very fine upper to medium upper, dominantly fine upper to lower; angular to subangular, trace subrounded; fair to good sorting; unconsolidated; non calcareous; trace coal/ carbonaceous material. Tuffaceous Siltstone (6840' -6870') = pale blueish gray to medium gray with occasional dark gray; tenacity soft to crumbly; fracture earthy; cuttings habit wedge like to occasional tabular; luster dull to earthy; slight silty to smooth texture; massive structure; trace coal. Sand (6870' - 6950') = light gray to occasional light medium gray; quartz frame work with individual grains transparent colorless to translucent colorless to white with occasional whitish gray; medium to coarse grained; poorly sorted; unconsolidated; angular to sub angular; moderate to low sphericity; rare to no grain surface abrasion; associated with abundant tuffaceous siltstone and traces of tuffaceous claystone, carbonaceous shale and coal. 13 Tuffaceous Siltstone (6950'- 6990') = pale bluish gray to medium gray; soft tenacity; fracture earthy; cuttings habit wedge like to occasional sub tabular; luster dull to earthy; texture slightly silty to smooth; structure massive; ass ociated w/ fissile moderately carbonaceous shale and unconsolidated sands with occasional traces of coal showing slow sparse visible outgassing. Coal (6990' - 7080') = brownish black to greenish black with common black; crumbly to moderately crunchy tenacity; fracture sub planar to blocky with occasional fissility less mature in less mature specimens; cuttings habit blocky to wedge like with occasional bladed; luster dull with rare metallic and rare adamantine lusters; texture smooth; structure thinly laminated; grades to less developed thinly laminate carbonaceous shale with abundant planar parting; occasional very fine grained pyrite on better developed specimens; slow sparse visible outgassing in larger well developed cuttings. Carbonaceous Shale (7080' -7170') = dark brown to dark brownish black; tenacity soft to occasionally crunchy and rarely firmly crunchy; fracture sub planar to blocky with some irregular in the softer specimens; cuttings habit sub blocky to sub tabular and occasional wedge like; luster resinous to sub adamantine with occasional sub metallic; texture smooth; structure thinly laminated with common fissility in the least developed specimens; grades to coal; occasional slow, sparse de gassing evident in both coals and the carbonaceous shales with degassing depleting in minutes; trace very fine granular pyrite. Tuffaceous Claystone (7170’ - 7245') = pale bluish gray to very pale gray with occasional grayish white; tenacity very soft and malleable; fractur e earthy to elastic; gummy to sticky; fairly easily washed away; cuttings habit predominantly slightly spherical to rounded wedgelike; luster dull to earthy; texture smooth to very slight siltiness; structure massive; grades to tuffaceous siltstone; trace medium yellowish brown ash fragments with readily discernable glassy laminae. Sand (7245' - 7290') = light gray to very pale whitish gray; frame work predominantly transparent colorless to translucent whitish quartz with rare opaque pale gray grains; fine to lower coarse grained poorly sorted; angular to sub angular; sphericity moderate with occasional prismoidal grains; mostly unconsolidated; trace euhedral quartz crystal fragments. Tuffaceous Siltstone (7290'- 7350') = pale bluish gray to medium gray; soft to crumbly tenacity; fracture earthy; habit wedge like to occasional sub tabular; luster dull to earthy; texture slightly silty to smooth; struc ture massive; associated w/ fissile moderately carbonaceous shale and unconsolidated sands with occasional traces of coal; grades to tuffaceous claystone. Sand (7350' - 7430') = medium to medium dark gray with a weak salt and pepper appearance, individual grains dominantly medium to dark gray, clear to translucent quartz and volcanic glass, black and greenish gray; very fine upper to very coarse lower, dominantly medium; angular to subangular; poor to fair sorting; disaggregated; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (7430' - 7490') = medium light to light gray with light brown to brownish gray secondary hues; soft to slightly firm; irregular to shapeless cuttings; silty to clayey texture; dull luster; hydrophilic; moderate to very soluble and expansive; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Sand/ Conglomeratic Sand (7490'-7540') = medium to medium dark gray overall with individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass; very fine upper to very coarse lower, dominantly medium lower to coarse lower; angular to trace subrounded, dominantly subangular; poorly sorted; unconsolidated; non calcareous; trace thin coal beds. Coal (7540'-7600') = black with brownish black secondary hues; very firm to brittle and hard, occasionally malleable; massive to platy and blocky; planar fracture dominant; earthy to resinous luster; smooth to gritty texture; lignitic to subbituminous, commonly grading to carbonaceous shale; trace weak outgassing bubbles observed; present as thin beds in dominantly sand and clay formation. 14 Tuffaceous Claystone/ Tuffaceous Siltstone (7600' - 7660') = light gray to very light gray to light greenish gray; very soft; sticky at times; shapeless, amorphous cuttings; silty to clayey texture; dull to slightly greasy luster; very soluble; slightly expansive; hydrophilic; poor cohesiveness; poor to fair adhesiveness; non calcareous; trace dark brown to black mi crothin carbonaceous laminations and inclusions in firmer fragments; trace thin coal beds. Sand/ Conglomeratic Sand (7660'-7720') = medium to medium dark gray overall with individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass; very fine upper to very coarse lower, dominantly medium lower to coarse lower; angular to trace subrounded, dominantly subangular; poorly sorted; unconsolidated; non calcareous; trace thin coal beds. Tuffaceous Claystone/ Tuffaceous Siltstone (7720' - 7780') = medium light to light gray with light brown to brownish gray secondary hues; soft to slightly firm; irregular to shapeless cuttings; silty to clayey texture; dull luster; hydrophilic; moderate to very soluble and expansive; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Tuffaceous Claystone/ Tuffaceous Siltstone (7780' - 7840') = light gray to very light gray to light greenish gray; very soft; sticky at times; shapeless, amorphous cuttings; silty to clayey texture; dull to slightly greasy luster; very soluble; slightly expansive; hydrophilic; poor cohesiveness; poor to fair adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions in firmer fragments; trace thin coal beds. Sand/ Sandstone/ Conglomeratic Sand (7840' - 7910') = medium to medium dark gray with a weak salt and pepper appearance, individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass; very fine upper to coarse upper, dominantly medium; angular to subangular; poorly sorted; dominantly unconsolidated with trace sandstone; dark gray with salt and pepper appearance; hard; moderate to very calcareous cement; poor porosity and permeability. Coal (7910'-7970') = black with brownish black secondary hues; very firm to brittle and hard, occasionally malleable; massive to platy and blocky; planar fracture dominant; earthy to resinous luster; smooth to gritty texture; lignitic to subbituminous, commonly grading to carbonaceous shale; trace weak outgassing bubbles observed; present as thin beds in dominantly sand and clay formation. Carbonaceous Shale (7965' -8160') = very dark brown to blackish brown; tenacity soft and pliable to moderately crunchy; fracture hackly to irregular with occasional sub planar to sub blocky cuttings habit wedge like to sub tabular with occasional specimens showing rounded edges; luster dull to slightly resinous with occasional slightly metallic; texture predominantly smooth with occasional slight siltiness; structure very thinly laminated; thinly bedded with tuffaceous clays and tuffaceous siltstones; grading into well-developed coals. Tuffaceous Claystone (8040' -8160') = very pale whitish gray to light gray; gelatinous consistency; tenacity malleable and persistent; gummy with no fracture; cuttings habit rounded lumpy masses; luster dull; texture smooth clayey; structure massive. Tuffaceous Siltstone (8080' - 8160') = very pale whitish gray to light gray and occasional light bluish gray and rare pale yellowish brown; tenacity soft to very slight crumbly to earthy; fracture earthy; cuttings habit wedgelike with rounded edges to sub tabular; luster dull to earthy; texture very silty to moderately silty grades to tuffaceous shale; structure massive. Sand (8160' - 8240') = medium to medium dark gray overall with individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass, greenish gray; very fine upper to very coarse upper, dominantly medium lower to coarse lower; angular to trace subrounded, dominantly subangular; poor to fair sorting; disaggregated; trace thin coal beds throughout interval. 15 Tuffaceous Claystone/ Tuffaceous Siltstone (8240' - 8300') = medium light to light gray with very light gray secondary hues; very soft to slightly firm; irregular to shapeless, amorphous cuttings; mushy to pasty; silty to clayey texture; dull to greasy luster; hydrophilic; very soluble and moderately expansive; poor cohesiveness; poor to fair adhesiveness; trace dark brown to black microthin carbonaceous laminations and inclusions in firm fragments; non calcareous; trace thin coal beds throughout. Sand (8300' - 8350') = medium to medium dark gray overall; very fine upper to coarse lower, dominantly medium; angular to subangular; poor to fair sorting; unconsolidated; non calcareous; trace thin coal/ carbonaceous shale beds throughout interval. Tuffaceous Claystone/ Tuffaceous Siltstone (8350' - 8420') = medium light to light gray with very light gray secondary hues; very soft to slightly firm; irregular to shapeless, amorphous cuttings; mushy to pasty; silty to clayey texture; dull to greasy luster; hydrophilic; very soluble and moderately expansive; poor cohesiveness; poor to fair adhesiveness; trace dark brown to black microthin carbonaceous laminations and inclusions in firm fragments; non calcareous; trace to common thin coal beds throughout interval. Sand (8420' - 8470') = medium to medium dark gray overall with individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass, greenish gray; very fine upper to coarse lower, dominantly medium lower to fine upper; angular to trace subrounded, dominantly subangular; poor to fair sorting; dominantly disaggregated. Coal (8470'-8520') = black with brownish black secondary hues; firm to occasionally hard; malleable; splintery at times platy to flaky; brittle; resinous to slightly earthy luster; smooth to slightly gritty texture; subbituminous; weak trace outgassing bubbles observed. Tuffaceous Claystone/ Tuffaceous Siltstone (8520' - 8590') = medium light to light gray with very light gray secondary hues; very soft to slightly firm; irregular to shapeless, amorphous cuttings; mushy to pasty; silty to clayey texture; dull to greasy luster; hydrophilic; very soluble and moderately expansive; poor cohesiveness; poor to fair adhesiveness; trace dark brown to black microthin carbonaceous laminations and inclusions in firm fragments; non calcareous; abundant thin coal beds . Sand (8595'- 8640') = whitish gray to very light gray with trace dark gray on occasion; frame work predominantly translucent colorless to opaque very light gray to white grains; upper very fine to upper fine grained; poorly to moderately sorted; sub angular to sub rounded; sphericity moderately high; grain surfaces moderately abraded; predominantly unconsolidated with rare easily friable preserved specimens; grain supported with sparse argillaceous matrix. Tuffaceous Siltstone ( 8640' - 8720') = very pale gray to pale grayish white with common pale bluish gray; tenacity crumbly to very soft with occasional harder specimens; fracture sub planar to slightly hackly; cutting habit predominantly wedge like to slightly rounded edges to occasional tabular with slightly rounded edges; texture very slightly silty to moderate siltiness; structure massive; Tuffaceous Claystone ( 8720'- 8760' ) = consistency gelatinous to mushy with occasional gummy; persistent when washed; tenacity crumbly to occasional slightly tougher; fracture malleable to none; cuttings habit massive lumps; luster dull to earthy; texture slightly silty to abundantly silty with rare near smooth; structure massive. Tuffaceous Siltstone ( 8760 ' - 8820') = very pale gray to occasional very pale bluish gray or medium gray; tenacity very slightly crunchy to crumbly; fracture sub planar to earthy; cuttings habit wedge like to sub tabular; luster dull to earthy; texture slightly silty to moderately silty; structure massive. Coal (8820'- 8880') = black to very dark brown, brownish black; tenacity hard and brittle with occasional very firmly crunchy; fracture conchoidal to irregular platy with common irregular blocky; luster vitreous to a metallic adamantine texture; smooth; structure very thinly laminated; grades to common less well developed coal specimens; very thin laminae with in claystone. 16 Sand (8880' - 8960') = very light gray to whitish gray; frame work predominantly translucent colorless to translucent very pale gray; fine to lower medium grained; poorly sorted; sub angular to angular with rare sub rounded specimens; sphericity high; mostly unconsolidated with rare preserved specimens being soft to crumbly; sparse argillaceous matrix; grain supported; interstices moderately well filled; associated with thin coals and thinly bedded tuf faceous claystones and thinly bedded tuffaceous siltstones. Carbonaceous Shale (8955'- 9030') = very dark brown to blackish browns with occasional dark yellowish brown hues; tenacity crumbly to crunchy with occasional slightly malleable; fracture sub planar to hackly; cuttings habit wedge like to blocky, occasionally tabular; luster resinous to occasionally slightly vitreous on planar partings faces; texture smooth; structure very thinly laminated with some specimens very thinly interbedded w/ thin laminar tuffaceous siltstones and clays. Sand (9030' - 9140') = very pale gray light gray with rare darker gray; framework predominantly opaque to translucent white to light gray quartz; fine to upper medium grained; moderately to poorly sorted; sub angular to angular with occasional sub round; sphericity high to moderate high; moderate surficial abrasion; mostly unconsolidated with occasional easily friable specimens preserved; sparse argillaceous cementation with little to no matrix material; interstices on preserved specimens well to moderately well filled; yielding poor visible porosity. Sand (9140' - 9210') = medium to medium dark gray with individual grains dominantly medium to dark gray, black, clear to translucent quartz and volcanic glass very fine upper to coarse lower, dominantly fine upper to medium lower; angular to subangular; poor to fair sorting; unconsolidated; non calcareous; trace to common thin coal/ carbonaceous shale beds throughout interval. Carbonaceous Shale (9200'- 9280') = very dark brown to blackish brown with occasional black; tenacity crumbly to easily crunched with rare firmer specimens; fracture planar to sub planar with occasional slightly earthy; cuttings habit wedge like to tabular or blocky; luster predominantly dull to rare sub vitreous; texture smooth to occasional slightly silty; trace to occasional tuffaceous component; commonly thinly interbedded with tuffaceous clay stones and tuffaceous siltstones and lesser sands. Tuffaceous Claystone (9200' - 9325') = vary pale gray to whitish gray; slimy to gelatinous consistency; malleable tenacity; cuttings habit massive rounded blobs; luster dull; texture smooth; structure massive; associated with thin carbonaceous shales, tuffaceous siltstones and minor sands. Sandstone (9325' - 9420') = very light gray to white with common salt and pepper specimens; frame work mostly translucent to opaque light gray grains; translucent to transparent colorless grains with common white opaque; fine to lower coarse grained; poorly sorted; sub angular to angular with occasional sub rounded; sphericity moderately high; easily friable too soft with abundant unconsolidated grains; trace argillaceous cementation with no matrix; grains supported; interstices moderately well to well filled yielding poor to moderately poor visible porosity; massive bedding; trace chlorite accessory grains in the white specimens. Sandstone (9405' - 9510') = medium gray light gray with salt and pepper appearance to white with very fine grained green specks (chlorite?); frame work predominantly quartz opaque to translucent gray with the second white mode showing translucent to transparent colorless to white grains; very fine to upper medium with trace lower coarse; poorly sorted; sub angular to sub rounded; sphericity fairly high; hardness easily friable to slightly firmer friable; sparse cement very slightly calcareous with trace argillaceous component; grain supported; interstices well filled and showing poor visible porosity Coal (9510' - 9525') = black; tenacity hard and brittle; fracture conchoidal to blocky and planar; cuttings habit tabular to blocky with occasional irregular; luster vitreous to occasional resinous; rare sub resinous; texture smooth glassy; structure thinly laminated; visible slow degassing; grades to less well developed coals carbonaceous shales; associated with thinly interbedded tuffaceous siltstones and tuffaceous claystones; coal intervals also associated with rise in gas. 17 Tuffaceous Claystone (9525' - 9615') = very pale gray to whitish gray; very mushy consistency; tenacity malleable; cuttings habit low lumpy clots; luster dull to clayey; texture smooth; structure massive. Tuffaceous Siltstone ( 9615' - 9660') = very light gr ay to medium gray, occasional light blues and pale yellowish browns; crumbly to firmly crumbly tenacity; sub planar to occasionally earthy fracture; cuttings habit wedgelike to rounded platy; luster dull; texture silty to slightly silty; structure massive. Carbonaceous Shale (9660' - 9765') = very dark brown to brownish black with occasional black; tenacity firmly crunchy and scores with moderate pressure; fracture sub planar to hackly with common planar parting; cuttings habit tabular to occasional blocky; luster resinous to rare sub vitreous; texture smooth to very slightly silty; structure thinly laminated; grades to better developed near coals. Sand/ Tuffaceous Sandstone (9765'-9825') = medium light to light gray with individual grains dominantly clear to translucent colorless or white to very pale gray quartz; lower fine to lower medium grained; moderately to poorly sorted; sub rounded to sub angular; high to moderately high sphericity; soft with abundant loose grains; tuffaceous matrix is sparse with most specimens grain supported; interstices moderately well filled yielding moderate to poor visible porosity; bedding massive. Tuffaceous Siltstone ( 9825' - 9860') = very pale gray to very pale bluish gray with occasional white to whitish gray; tenacity soft, crumbly, trace firm crumbly; fracture planar to very slightly hackly; cuttings habit wedge like to tabular w/ rounded edges; luster dull to earthy; texture silty to slightly gritty; associated with thinly bedded sands and sandstones. Sandstone ( 9860'-9990') = very pale gray to occasional medium gray w/ occasional white; frame work transparent colorless quartz with common translucent to opaque white to very pale gray grains; very fine to lower medium; poorly sorted; sub rounded to sub angular; sphericity high to moderately high; soft to abundant loose/ disaggregated grains; occasional sparse tuffaceous cement; grain supported; interstices in preserved specimens; well to moderately well filled yielding a fairly poor visible porosity; massive bedding; rare micaceous accessories; trace other silica species of chert and chalcedony?; associated with many thin coals Coal (9975' - 10035') = black to very dark brown with occasional dark yellowish brown; tenacity brittle to very tough; fracture conchoidal to planar or blocky; cuttings habi t irregular bladed to blocky; luster vitreous in the best developed specimens and sub resinous in the least; texture smooth; thinly laminated structure; vigorous out gassing when scored; associated with soft and unconsolidated sands and sandstones. Sand/ Tuffaceous Sandstone (10035' - 10130') = medium light to light gray with a weak salt a pepper appearance, individual grains dominantly clear to translucent quartz and volcanic glass, light to medium gray, pale rose and light greenish gray; very fine lower to trace very coarse lower, dominantly fine; angular to subangular; fair to good sorting; dominantly unconsolidated with trace to common tuffaceous sandstone; ash matrix is bluish white to grayish white; very fragile; pulverulent; non calcareous; note abundant large coal fragments sloughing in. Coal (10130' - 10200') = black with brownish black secondary hues; hard; brittle; massive to platy; planar fracture dominant with trace conchoidal and birdeye; smooth to slightly silty texture; resinous to earthy luster; no outgassing bubbles observed; coal occasionally grades to a carbonaceous shale; sub bituminous to bituminous. Sand (10200' - 10310') = note: 95% - 99% lcm in sample; sand light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass light to medium gray, light greenish gray, pale rose and dusky red; very fine lower to medium lower, dominantly fine; angular to subangular; unconsolidated; fair to good sorting; non calcareous; common to abundant thin coal beds. 18 Sand/ Sandstone (10310'-10450') = note: lcm 95% - 99% of sample; medium light to light gray overall with individual liths dominantly clear to translucent quartz and volcanic glass, trace pale rose and light green to light greenish gray; very fine lower to medium lower, dominantly fine; angular to subangular; unconsolidated; fair to good sorting; non calcareous common disaggregated specimens with occasional preserved specimens; cementation tuffaceous to argillaceous; moderate amount matrix material with most preserved specimens matrix supported; occasional grain supported; associated with traces of tuffaceous claystone and tuffaceous siltstone; trace coal- probably from up hole. Sandstone (10450'- 10650')= light to medium gray with rare very light gray; frame work predominantly translucent to transparent colorless to white quartz grains; very fine to occasional lower course grained some specimens nearly conglomeritic; poorly sorted; sub angular to sub rounded; sphericity moderately high; very soft to easily friable; cementation tuffaceous with a minor argillaceous component; matrix variable most matrix supported with occasional grain supported; interstices well to moderately well filled resulting a poor to moderately poor visible porosity; grades to a like colored tuffaceous siltstone. Coal/ Carbonaceous Shale (10605'-10645') = very dark brownish black to black; firm to fissile tenacity; fracture conchoidal to planar; cuttings habit irregular tabular to sub blocky; luster resinous to vitreous; texture smooth to v slight silty; thin structure Sand/ Tuffaceous Sandstone (10645' - 10720') = medium light to light gray overall with darker secondary hues from ashy matrix, individual grains dominantly clear to translucent quartz and volcanic glass, light to medium gray and light green to light greenish gray; very fine lower to medium upper, domi nantly fine; angular to subangular; moderately well sorted; disaggregated to very loosely supported from ashy matrix; very fragile to pulverulent; non calcareous; coal beds common. Sand/ Tuffa ceous Sandstone (10720' - 10795') = light gray with individual liths dominantly clear to translucent quartz; very fine lower to coarse upper, dominantly fine upper to medium lower; angular to subangular; poor to fair sorting; dominantly unconsolidated with ashy supporting matrix; fragile. Sandstone (10795' - 10920') = white to very pale gray; frame work predominant transparent colorless or translucent white to very pale quartz grains with occasional opaque white to very pale gray quartz grains; very fine to lower course grained; very poor to occasionally moderately poorly sorted; sub angular to sub rounded; moderate to high sphericity; rare to occasional slightly abraded grain surfaces; crumbly to trace slight ly firmer easily friable; matrix tuffaceous to argillaceous with most specimens matrix supported; well filled interstices resulting in poor to moderately poor visible porosity; massive bedding; common reworked subangular lithic fragments <10%. Tuffaceous Siltstone ( 10920' -10965') = light medium gray to medium dark gray with occasional yellowish to orangish staining; crumbly to occasional very slightly crunchy; fracture earthy; cuttings habit sub tabular to wedge like; dull; slight silty; trace pale green volcanic glass; structure massive. Carbonaceous Shale/ Coal (10965' -11055') = very dark brown to brownish black to black; crunchy to fissile with occasion slightly hard; fracture conchoidal to sub planar; cuttings habit irregular blocky to irregular tabular with occasional elongated tabular or elongated bladed; luster dull and clayey on the softest carbonaceous shales to resinous and occasionally vitreous on best developed specimens; texture smooth with occasional slight siltiness; structure very thinly laminated; occasional slow sparse out gassing and rarely more vigorous out gassing; the least developed specimens show occasional planar parting. Tuffaceous Siltstone (11055'- 11105') = medium gray to light gray with occasional slightly yellowish hues; crumbly to vary slightly crunchy; cuttings habit predominantly wedge like; luster dull to earthy; texture silty to very slightly gritty; structure very thinly laminated w/ visible very thin dark laminar features possibly glass. 19 Sandstone (11105'- 11175') = very pale gray to white or whitish gray; very fine to upper medium grained; moderately to poorly sorted; sub angular to sub rounded with moderately high to high sphericity; grained predominantly transparent to translucent colorless quartz with very minor surface abrasion; very soft to barely crumbly with abundant loose grains; argillaceous, non-calcareous matrix material; interstices well filled w/ poor to mod visible porosity; <10% reworked sediment inclusions. Sand/ Tuffaceous Sandstone/ Conglomerate (11175' - 11270') = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray, black and greenish gray; very fine upper to very coarse upper, dominantly fine; angular to subangular; poor to fair sorting; dominantly unconsolidated with ash matrix supported sands; dirty white with darker secondary hues; very fragile and pulverulent; non calcareous; trace sandstone; multicolored with white calcareous cement; hard to brittle; fine to medium; poor visible porosity and permeability. Coal (11270' - 11310') = black with brownish black secondary hues; hard to brittle, occasionally crumbly; massive to platy and flaky; planar fracture dominant with trace conchoidal and birdeye; vitreous to polished luster; smooth texture; trace visible outgassing bubbles. Sand/ Tuffaceous Sandstone (11310' - 11370') = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray; very fine upper to trace very coarse lower, dominantly fine upper to lower; angular to subangular; poor to fair sorting; dominantly unconsolidated with abundant ash matrix supported sands; dirty white with darker secondary hues; very fragile and pulverulent; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (11370' - 11440') = medium light to light gray with light olive gray secondary hues; soft; irregular, subdiscoidal with PDC bit action shaped cuttings; silty to clayey texture; dull to earthy luster; hydrophilic; moderately soluble and expansive; poor adhesiveness fair cohesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; abundant coal beds throughout interval. Coal (11440' - 11480') = black with brownish black secondary hues; hard to brittle, occasionally crumbly; massive to platy and flaky; planar fracture dominant with trace conchoidal and birdeye; vitreous to polished luster; smooth texture; trace visible outgassing bubbles. Sand/ Tuffaceous Sandstone/ Conglomerate (11480' - 11560') = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray, black and greenish gray; very fine upper to very coarse upper, dominantly fine; angular to subangular; poor to fair sorting; dominantly unconsolidated with ash matrix supported sands; dirty white with darker secondary hues; very fragile and pulverulent; non calcareous; trace sandstone; multicolored with whi te calcareous cement; hard to brittle; fine to medium; poor visible porosity and permeability. Sand/ Tuffaceous Sandstone (11560' - 11630') = very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, trace medium to dark gray, pale rose and light green to light greenish gray; very fine upper to trace coarse lower, dominantly fine; angular to subangular; moderately well sorted; dominantly disaggregated with dirty white ashy matrix supported sands; very fragile; crumbly; non calcareous. Coal (11630' - 11700') = black with brownish black secondary hues; hard to brittle, occasionally crumbly; massive to platy and flaky; planar fracture dominant with trace conchoidal and birdeye; vitreous to polished luster; smooth texture; trace visible outgassing bubbles; very well developed; bituminous with trace carbonaceous shale. 20 Sand/ Tuffaceous Sandstone/ Conglomerate (11680' - 11760') = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray, black, greenish gray, light green, pale rose and dusky red; very fine upper to trace very coarse upper, dominantly fine; angular to subangular; poor to fair sorting; dominantly unconsolidated with ash matrix supported sands; dirty white with darker secondary hues; very fragile and pulverulent; non to slightly calcareous. Sand (11760' - 11895') = very light gray to pale medium gray; frame work predominantly transparent colorless to translucent white to whitish gray quartz grains with less than 5% reworked sedimentary lithic fragments; trace colored quartz grains ,opaque bright orange and pale green with occasional transparent pale straw yellow; very fine to upper medium with trace lower coarse grains; poorly sorted yielding poor visible porosity; sub round to sub angular with high to moderately high sphericity; most grains show very little to no surface abrasion; predominantly disaggregated with preserved specimens rarely showing much more that 8-10 grains intact within a soft milky white matrix; relict impression on of plucked grains occasionally remains within matrix; non-calcareous; grain supported; bedding massive. Carbonaceous Shale/ Coal (11890' -11955') = very dark gray to dark brownish gray, black to occasionally bluish black; firmly crunchy to occasionally very firmly crunchy to tough or hard; sub planar to occasionally conchoidal fracture; cuttings habit sub tabular to splintery and occasionally sub blocky; luster resinous to vitreous with trace matte; texture smooth to very slightly silty; structure very thinly laminated; outgassing readily evident. Tuffaceous Sand ( 11955' - 12030') = very light gray to whitish gray with occasional darker light gray to medium gray; very soft to barely crumbly tenacity; fracture sub planar to slightly earthy; cuttings habit predominantly wedge like; luster dull to earthy; texture slightly gritty to slightly silty; structure massive with occasional thin laminar glassy material; occasional color quartz grains orange to very pale green and very pale blue; grades to tuffaceous siltstone; associated with specimens of tuff. Tuffaceous Claystone/ Tuffaceous Siltstone (12030' - 12100') = medium to medium light gray to brownish gray with light olive gray seco ndary hues; soft; irregular shaped cuttings with abundant PDC bit action 'scooped' appearance; silty to clayey texture; earthy luster; moderately soluble and expansive; poor adhesiveness; fair cohesiveness; non calcareous; trace to common dark brown to black microthin carbonaceous laminations and inclusions. Coal (12100' - 12160') = black with brownish black secondary hues; hard to brittle, occasionally crumbly; massive to platy and flaky; planar fracture dominant with trace conchoidal and birdeye; vitreous to polished luster; smooth texture; trace visible outgassing bubbles; very well developed; bituminous with trace carbonaceous shale. Sand/ Tuffaceous Sandstone/ Conglomerate (12160' - 12220') = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray, black and greenish gray; very fine upper to trace coarse upper, dominantly fine; angular to subangular; poor to fair sorting; dominantly unconsolidated with ash matrix supported sands; dirty white with darker secondary hues; very fragile and pulverulent; non calcareous Tuffaceous Claystone/ Tuffaceous Siltstone (12220'-12280') = medium to medium light gray with brownish gray secondary hues; soft; irregular, subdiscoidal with PDC bit action shaped cuttings; silty to clayey texture; dull to earthy luster; hydrophilic; moderately soluble and expansive; poor adhesiveness; fair cohesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds throughout interval. Coal (12280' - 12340') = black with brownish black secondary hues; hard to brittle, occasionally crumbly; massive to platy and flaky; planar fracture dominant with trace conchoidal and birdeye; vitreous to polished luster; smooth texture; weak trace outgassing bubbles; very well developed; bituminous with trace carbonaceous shale. 21 Tuffaceous Claystone/ Tuffaceous Siltstone (12340' - 12410') = medium to medium light gray with light brownish gray and light olive gray secondary hues; soft to trace firm; irregular shaped with PDC bit action appearance common; silty to clayey; dull, earthy to trace waxy; hydrophilic; poor adhesiveness; poor to fair cohesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Tuffaceous Sandstone/ Sandstone ( 12410'-12510') = white to very light gray with occasional medium gray; frame work translucent white to colorless quartz with minor reworked sedimentary lithic clasts; very fine to upper fine with rare lower medium grains; moderate to poorly sorted; sub angular to sub rounded; sphericity moderately high; soft to very easily friable; matrix: white, argillaceous, non-calcareous; most specimens matrix supported with poor visible porosity; bedding massive. Carbonaceous Shale (12465'-12585') = very dark brown to brownish black with occasional very black; tenacity crunchy to firmly crunchy with occasional easily crunched to crumbly; fracture predominantly sub planar with occasional earthy to irregular; cuttings habit sub tabular to wedge like; luster dull to occasional resinous with some vitreous in the more mature specimens; structure very thinly laminated; rare out gassing evident - short duration, slow, sparse; presents occasionally as very thinly interbedded with tuffaceous siltstones as very thin brittle laminae carbonaceous material; texture smooth to very slightly silty. Tuffaceous Siltstone (12570' - 12660') = medium gray to medium brownish gray with occasional whitish gray; tenacity crumbly to barely crunchy; fracture earthy to slightly hackly with occasional sli ghtly planar especially in the firmer specimens; cuttings habit wedge like to slightly tabular with all specimens having rounded edges due to trip up the hole; luster dull to earthy; texture silty to slightly gritty; structure massive. Conglomeratic Sand (12630' - 12765') = white to very light gray with rare very pale medium gray; frame work predominantly translucent white to colorless with lesser transparent colorless quartz grains; less than 5% reworked sedimentary lithics entrained within a sparse white matrix; very fine to upper fine occasional medium grains and rare lower coarse grains; poorly sorted yielding poor visible porosity; sub angular to sub rounded; moderately high sphericity; minor abrasion only of gr ain surfaces; very easily friable to soft and fragile; matrix material very soft; non calcareous; occasionally to commonly matrix is very sparse; most specimens grain supported; bedding massive; common abundant loose grains due to disaggregation of the fragile sandstone. Carbonaceous Shale ( 12765' -12860') = very dark brown to blackish brown with occasional black with slightly greenish hues; tenacity firmly crunchy to moderately hard; fracture irregular to sub planar w/ occasional conchoidal; cuttings habit blocky; sub tabular; irregular; luster dull to slightly vitreous; texture smooth to slightly silty; structure thinly laminated; no visible out gassing observed. Sand/ Sandstone/ Tuffaceous Sandstone (12860' - 12940') = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, trace dark gray to black and light green to greenish gray; very fine upper to trace coarse upper, dominantly fine lower to medium lower; angular to subangular; poor to fair sorting; dominantly disaggregated with sandstone; white with salt and pepper appearance; fine to medium; angular; moderately hard to brittle; white cement is non calcareous; abundant ash matrix sand; fragile to pulverulent. 22 3.3 Sampling Program Set Type and Purpose Interval Frequency Distribution A Washed and Dried Reference 6544 – 10200 10200-10450 10450-12940’ 15’ 30’ 15’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 B Washed and Dried Reference 6544 – 10200 10200-10450 10450-12940’ 15’ 30’ 15’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 C Wet, Lightly Rinsed Sieve Analysis 6544 – 10200 10200-10450 10450-12940’ 15’ 30’ 15’ James Kvidera Canrig Drilling Technology LTD 301 E 92 nd Ave, Suite #2 Anchorage, AK 99515 23 4 DRILLING DATA 4.1 Surveys Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 6527.00 13.15 55.34 5355.36 1919.21 2650.65 3267.70 1.23 6569.22 15.02 54.12 5396.31 1925.14 2659.03 3277.96 4.48 6630.93 18.11 52.74 5455.46 1935.64 2673.15 3295.53 5.05 6693.06 20.89 51.69 5514.01 1948.35 2689.53 3316.26 4.51 6754.62 22.91 50.86 5571.13 1962.72 2707.43 3339.22 3.32 6816.72 24.28 50.18 5628.04 1978.53 2726.61 3364.07 2.24 6878.52 26.53 46.62 5683.86 1996.15 2746.41 3390.55 4.40 6941.32 28.05 46.13 5739.67 2016.01 2767.25 3419.24 2.45 7002.65 30.30 43.22 5793.21 2037.28 2788.24 3448.94 4.34 7064.57 31.76 43.58 5846.28 2060.47 2810.17 3480.58 2.38 7127.61 32.06 43.48 5899.79 2084.63 2833.12 3513.62 0.48 7189.38 32.10 42.27 5952.13 2108.67 2855.44 3546.09 1.04 7251.09 33.98 43.88 6003.86 2133.24 2878.42 3579.42 3.37 7311.96 34.09 44.44 6054.30 2157.67 2902.16 3613.24 0.55 7375.31 34.76 43.58 6106.55 2183.44 2927.04 3648.80 1.31 7437.34 33.98 45.49 6157.75 2208.40 2951.59 3683.59 2.15 7498.39 33.93 45.56 6208.40 2232.29 2975.93 3717.53 0.10 7561.02 34.00 44.89 6260.34 2256.94 3000.76 3752.34 0.61 7622.70 33.73 44.83 6311.56 2281.30 3025.01 3786.52 0.44 7684.35 34.05 45.97 6362.73 2305.44 3049.48 3820.73 1.15 7746.52 33.88 45.71 6414.30 2329.63 3074.40 3855.32 0.36 7808.23 33.68 45.67 6465.59 2353.60 3098.95 3889.48 0.33 7870.14 34.15 46.67 6516.96 2377.52 3123.87 3923.90 1.18 7932.15 34.06 47.32 6568.31 2401.23 3149.30 3958.59 0.60 7992.91 33.78 45.67 6618.73 2424.57 3173.89 3992.39 1.59 8056.17 33.84 45.35 6671.30 2449.24 3199.00 4027.43 0.30 8114.59 33.64 45.50 6719.87 2472.01 3222.11 4059.72 0.37 8180.33 33.89 44.08 6774.53 2497.94 3247.85 4096.04 1.25 8242.37 33.73 43.91 6826.07 2522.77 3271.83 4130.30 0.30 8304.33 33.47 43.27 6877.68 2547.61 3295.47 4164.31 0.71 8366.33 34.64 45.11 6929.05 2572.49 3319.67 4198.78 2.51 8428.22 34.39 45.21 6980.05 2597.22 3344.54 4233.66 0.42 8490.03 34.15 44.68 7031.13 2621.85 3369.12 4268.27 0.62 8551.13 33.84 43.77 7081.79 2646.33 3392.95 4302.20 0.97 24 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 8614.14 33.25 43.86 7134.31 2671.46 3417.06 4336.75 0.94 8675.64 34.49 45.22 7185.37 2695.88 3441.10 4370.80 2.35 8737.88 34.52 44.88 7236.66 2720.79 3466.05 4405.87 0.31 8799.11 34.19 44.25 7287.21 2745.40 3490.30 4440.20 0.79 8861.51 34.82 45.02 7338.63 2770.55 3515.14 4475.33 1.23 8924.03 34.38 44.64 7390.10 2795.73 3540.16 4510.62 0.79 8984.59 35.24 45.46 7439.82 2820.15 3564.63 4545.00 1.62 9048.38 34.88 45.72 7492.04 2845.79 3590.81 4581.48 0.60 9108.06 34.67 45.23 7541.06 2869.66 3615.07 4615.36 0.60 9173.61 34.63 44.65 7594.99 2896.04 3641.40 4652.42 0.50 9235.35 34.11 44.32 7645.95 2920.90 3665.82 4687.05 0.89 9297.11 34.13 43.95 7697.08 2945.76 3689.94 4721.45 0.34 9358.04 34.04 45.37 7747.54 2970.05 3713.94 4755.38 1.31 9421.37 33.88 45.74 7800.06 2994.82 3739.20 4790.60 0.41 9482.93 33.27 45.60 7851.36 3018.61 3763.55 4824.50 1.00 9544.75 32.68 44.91 7903.22 3042.30 3787.45 4857.98 1.13 9607.06 30.31 45.61 7956.34 3065.21 3810.56 4890.36 3.85 9667.98 28.08 46.77 8009.52 3085.79 3832.00 4919.97 3.78 9729.86 25.72 47.69 8064.71 3104.80 3852.54 4947.90 3.86 9793.26 23.89 46.32 8122.25 3122.93 3872.00 4974.43 3.03 9855.08 21.64 46.42 8179.26 3139.44 3889.31 4998.27 3.65 9915.35 18.60 46.84 8235.84 3153.67 3904.37 5018.94 5.04 9976.56 15.43 44.84 8294.36 3166.13 3917.24 5036.78 5.26 10040.55 11.48 46.78 8356.58 3176.53 3927.89 5051.6 6.22 10100.55 7.50 52.64 8415.76 3183.00 3935.36 5061.47 6.81 10162.92 4.20 57.77 8477.79 3186.69 3940.53 5067.81 5.36 10483.40 1.49 56.43 8797.85 3195.25 3953.92 5083.61 0.85 10548.80 1.96 55.16 8863.22 3196.36 3955.55 5085.57 0.73 10615.44 1.86 64.78 8929.82 3197.47 3957.46 5087.76 0.51 10681.04 1.57 68.46 8995.39 3198.25 3959.26 5089.65 0.46 10747.06 1.64 68.99 9061.38 3198.93 3960.99 5091.41 0.10 10812.43 0.80 4.12 9126.74 3199.72 3961.89 5092.61 2.27 10878.05 1.08 334.35 9192.35 3200.73 3961.66 5093.07 0.84 10944.00 1.59 303.96 9258.28 3201.80 3960.63 5092.94 1.30 11010.33 1.66 299.44 9324.59 3202.79 3959.03 5092.32 0.22 11075.50 1.87 305.57 9389.73 3203.87 3957.34 5091.69 0.43 11141.44 1.82 308.51 9455.64 3205.14 3955.65 5091.18 0.16 11206.82 2.08 308.41 9520.98 3206.53 3953.91 5090.70 0.41 11273.85 1.36 300.69 9587.97 3207.69 3952.27 5090.16 1.13 11338.76 1.19 292.70 9652.87 3208.34 3950.98 5089.57 0.38 25 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 11404.09 1.18 303.82 9718.18 3208.98 3949.80 5089.05 0.35 11469.72 1.09 299.71 9783.80 3209.67 3948.69 5088.62 0.19 11535.89 1.07 290.83 9849.96 3210.20 3947.57 5088.08 0.25 11602.37 1.08 308.99 9916.43 3210.81 3946.51 5087.64 0.51 11663.83 1.05 312.54 9977.88 3211.56 3945.64 5087.44 0.11 11723.32 0.99 310.21 10037.36 3212.26 3944.85 5087.26 0.12 11798.75 0.35 250.83 10112.79 3212.60 3944.13 5086.93 1.15 11865.17 0.06 188.28 10179.20 3212.51 3943.94 5086.72 0.49 11931.25 0.00 89.07 10245.28 3212.47 3943.94 5086.69 0.09 11996.98 0.29 25.82 10311.02 3212.63 3944.01 5086.84 0.45 12062.67 0.34 16.66 10376.70 3212.96 3944.14 5087.16 0.10 12124.34 0.43 359.78 10438.37 3213.37 3944.19 5087.45 0.24 12186.88 0.44 341.34 10500.91 3213.83 3944.11 5087.68 0.22 12248.94 0.70 260.89 10562.96 3214 .00 3943.66 5087.44 1.23 12310.61 1.13 265.29 10624.63 3213.89 3942.68 5086.60 0.71 12372.23 0.90 244.07 10686.24 3213.63 3941.64 5085.63 0.71 12433.92 0.93 242.96 10747.93 3213.19 3940.76 5084.67 0.07 12497.41 1.00 233.22 10811.40 3212.62 3939.85 5083.61 0.28 12558.82 0.82 232.28 10872.81 3212.03 3939.08 5082.64 0.28 12619.76 0.68 231.96 10933.74 3211.54 3938.45 5081.84 0.24 12683.10 0.64 232.60 10997.08 3211.10 3937.87 5081.11 0.06 12744.91 0.57 233.10 11058.88 3210.70 3937.35 5080.46 0.10 12806.95 1.02 246.64 11120.92 3210.30 3936.60 5079.62 0.78 12868.91 0.89 246.87 11182.86 3209.89 3935.65 5078.62 0.21 12901.73 1.05 246.24 11215.69 3209.67 3935.14 5078.09 0.49 12940** 1.05 246.24 11253.95 3209.39 3934.50 5077.41 0.00 **Projected 26 4.2 Bit Record BIT NO. SIZE TYPE S/N JETS/ TFA IN OUT Feet Drilled HRS AVE ROP (Ft/HR ) CONDITION Mill 6527’ 6562’ 35 Mill assembly 1 8 ½” Varel V516PR 4007156 5x14/ .7517 6562’ 10200 3638’ 49.8 73.1 1-2-CT -G-X-I -NO -BHA 2 8 ½’ Hughes VM- 18DVHX 5216722 3x20/ .9204 10200 10200 0 0 0 MAD-Pass 3 8 ½” Smith XR+PS PT6003 3x24/ 1.3254 10200 10450 250’ 15.5 16.13 1-1-ER-A-E-I -NO -TD 4 6 ¾” Varel PDHRU 4008283 4x9,3x10/.479 10450 10450 0 0 0 Too big for hanger. 5 6 1/8” HDBS MM55 12487636 5x11/.4640 10450 12940 2490 39.8 62.6 1-3-BT -S-X-1-CT-TD 5RR 6 1/8” HDBS MM55 12487636 5x11/.4640 12940 12940 0 0 0 MAD-Pass 5RR2 6 1/8” HDBS MM55 12487636 5x11/.4640 12940 12940 0 0 0 Clean out w/ mill 27 4.3 Mud Record Contractor: M.I. Swaco Date Depth MW (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) O/W Ratio Sd (%) MBT pH Cl (ml/l) Ca (ml/l) MD (ft) TVD (ft) KCl Polymer 10/13/15 6555 5384 9.0 49 10 20 8/10/12 6.1 1/2 2.3 0/95.0 0.01 1.6 10.3 32000 40 10/14/15 6562 5390 8.95 66 11 19 7/9/12 6.1 1/2 2.0 0/95.3 0.01 1.0 9.6 32000 40 10/15/15/ 6948 5745 9.0 53 10 21 8/11/14 5.0 1/2 2.4 0/95.0 0.25 1.3 9.6 32000 80 10/16/15 8155 6753 9.3 57 14 24 8/11/15 4.3 1/2 4.7 0/92.7 0.15 2.0 9.1 32000 40 10/17/15 8590 7115 9.35 49 12 22 6/10/14 3.9 1/2 5.3 .5/91.8 0.15 2.5 9.8 30500 60 10/18/15 9339 7733 9.55 55 16 23 6/11/15 3.6 1/2 6.6 .8/90.2 0.20 3.0 9.0 31000 80 10/19/15 9864 8189 9.55 58 18 22 5/10/15 3.0 1/2 6.5 2.0/89.2 0.20 4.0 9.1 30000 60 10/20/15 10200 8515 9.8 58 18 20 4/9/12 2.9 1/2 6.9 2.5/88.1 0.15 3.8 9.7 32000 80 10/21/15 10200 8515 10.1 60 21 25 7/13/17 2.5 ½ 8.4 3.0/86.2 0.15 4.5 9.7 32000 80 10/22/15 10200 8515 10.1 61 18 23 6/11/16 2.5 ½ 8.0 3.0/86.6 0.15 4.5 10.0 32000 80 10/23/15 10200 8515 10.1 57 21 23 6/12/18 3.0 ½ 8.5 3.0/86.2 0.20 4.5 10.2 30000 80 10/24/15 10200 8515 10.0 61 21 23 5/9/13 2.8 ½ 7.4 3.0/87.2 0.20 4.5 9.9 31000 80 10/25/15 10200 8515 10.0 68 24 26 6/9/14 2.2 ½ 7.5 3.0/87.2 0.10 5.0 10.2 30000 80 10/26/15 10419 8741 10.4 88 28 34 9/15/22 3.0 ½ 7.5 3.0/87.2 0.50 5.0 10.0 30000 200 10/27/15 10450 8765 10.3 55 18 18 4/9/14 3.2 1/2 11.1 3.0/83.8 0.60 6.0 11.4 29000 100 10/28/15 10450 8765 10.3 55 35 40 9/12/19 3.6 1/2 11.0 2.5/84.4 0.75 6.0 9.6 29000 80 10/29/15 10450 8765 9.1 68 13 19 9/12/19 4.8 ½ 3.3 0/96.2 0.25 1.0 9.8 4000 80 10/30/15 10450 8765 8.7 50 12 14 3/5/11 4.8 1/2 1.8 0/97.4 0.50 1.0 8.5 8000 80 10/31/15 10450 8765 10.35 50 16 20 6/9/10 3.2 ½ 7.6 0/90.0 0 0 9.5 30000 100 11/1/15 10470 8783 10.15 63 13 21 7/9/13 4.0 ½ 7.1 0/90.5 0 0 10.1 31000 80 11/2/15 10795 9109 11.25 51 14 21 6/9/12 3.0 ½ 11.3 .8/85.5 0.10 1.0 9.3 33000 60 11/3/15 11761 10075 11.28 53 18 27 8/10/14 2.6 ½ 11.8 1/84.9 0.20 1.0 9.6 31000 60 11/4/15 12592 10908 11.3 59 21 26 8/11/15 2.2 ½ 11.8 3/82.8 0.10 1.8 9.0 33000 60 11/5/15 12940 11254 11.3 53 17 27 8/10/14 2.4 1/2 12.8 2/82.9 0.10 1.8 9.9 31500 40 11/6/15 12940 11254 11.3 52 18 26 8/10/13 2.4 1/2 12.8 1/84.0 0.10 2.0 10.0 30000 40 11/7/15 12940 11254 11.3 53 17 26 7/10/14 2.2 1/2 12.8 1/83.9 0.10 2.0 9.7 31000 40 11/8/15 12940 11254 11.35 52 17 26 8/10/13 2.8 1/2 13.3 1/83.5 0.10 2.3 10.2 30500 40 11/9/15 12940 11254 11.25 46 16 25 6/8/11 2.4 1/2 13.1 1.5/83.3 0.10 2.0 10.2 29000 40 11/10/15 12940 11254 11.35 48 15 24 6/8/10 2.3 1/2 13.5 1.5/82.8 0.10 2.0 10.2 30000 40 11/11/15 12940 11254 11.4 45 14 24 6/8/11 2.2 1/2 13.7 1.3/82.7 0.10 2.5 10.2 32500 40 28 Date Depth MD Depth TVD MW (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) O/W Ratio Sd (%) MBT pH Cl (ml/l) Ca (ml/l) 11/12/15 12940 11254 11.4 47 14 23 5/7/10 2.2 1/2 13.7 1.3/82.7 0.10 2.5 10.2 33000 40 11/13/15 12940 11254 11.6 48 16 25 6/8/11 2.1 ½ 14.4 1/82.2 0.10 2.5 10.1 33000 40 11/14/15 12940 11254 Abbreviations: MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Water or Filtrate Loss FC = Filter Cake O/W = Oil to Water ratio Sols = Solids Sd = Sand content MBT = Methylene Blue Alk, Pm = Alkalinity, Mud pH = Acidity Cl = Chlorides Ca = Hardness Calcium nr = Not Recorded 29 4.4. Drilling Progress 6000 7000 8000 9000 10000 11000 12000 13000 10/ 1 2 / 2 0 1 5 10/ 1 4 / 2 0 1 5 10/ 1 6 / 2 0 1 5 10/ 1 8 / 2 0 1 5 10/ 2 0 / 2 0 1 5 10/ 2 2 / 2 0 1 5 10/ 2 4 / 2 0 1 5 10/ 2 6 / 2 0 1 5 10/ 2 8 / 2 0 1 5 10/ 3 0 / 2 0 1 5 11/ 1 / 2 0 1 5 11/ 3 / 2 0 1 5 11/ 5 / 2 0 1 5 11/ 7 / 2 0 1 5 11/ 9 / 2 0 1 5 11/ 1 1 / 2 0 1 5 11/ 1 3 / 2 0 1 5 11/ 1 5 / 2 0 1 5 8 1/2" Hole 6 1/8" 30 5 SHOW REPORTS Hydrocarbon Show Report # 1 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 9520'MD 9620'MD Country: 20 7882'TVD 7968'TVD Averages Before During After Maximum ROP (fph) 85 ft/hr 101 ft/hr 93 ft/hr 314 ft/hr WOB 9 klbs 7 klbs 9 klbs 9 klbs RPM 74 rpm 55 rpm 74 rpm 75 rpm PP 2112 psi 2002 psi 2104 psi 2133 psi Mud Weight 9.6 lbs/gal 9.6 lbs/gal 9.6 lbs/gal 9.6 lbs/gal Chloride 30,000 30,000 30,000 30,000 Total Gas 99 476 534 813 C1 (ppm) 19,778 95,936 107,988 165,316 C2 (ppm) - - - - C3 (ppm) - - - - C4 (ppm) - - - - C5 (ppm) - - - - Lithology Odor None Amount None Type N/A Amount Amount N/A Distribution Intensity Color Color Intensity Color Color Intesity Color N/A Color Comments Report by: Residual Fluorescence Cuttings Analysis N/A Donna New GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Borough Alaska USA Fluorescence Cut Fluorescence N/A Stain Hilcorp Alaska, LLC 1332047-01-00 CLU 05-RD Cannery Loop Unit Saxon 169 10/19/2015 1:47 AM Residual Cut SANDSTONE = MEDIUM GRAY LIGHT GRAY WITH SALT AND PEPPER APPEARANCE TO WHITE WITH VERY FINE GRAINED GREEN SPECKS (CHLORITE?); FRAME WORK PREDOMINANTLY QUARTZ OPAQUE TO TRANSLUCENT GRAY WITH THE SECOND WHITE MODE SHOWING TRANSLUCENT TO TRANSPARENT COLORLESS TO WHITE GRAINS; VERY FINE TO UPPER MEDIUM WITH TRACE LOWER COARSE; POORLY SORTED; SUB ANGLAR TO SUB ROUNDED; SPHERICITY FAIRLY HIGH; HARDNESS EASILY FRIABLE TO SLIGHTLY FIRMER FRIABLE; SPARSE CEMENT VERY SLIGHTLY CALCAREOUS WITH TRACE ARGILLACEOUS COMPONENT; GRAIN SUPPORTED; INTERSTICES WELL FILLED AND SHOWING POOR VISIBLE POROSITY; BEDDING MASSIVE. THIN INTERBEDDED COAL CARBONACEOUS SHALES. THIS SANDSTONE MARKS THE TOP OF THE UPPER TYONEK. 1 10 100 1000 10000 100000 1000000 1 2 3 4 pp m Pixler Plot DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 2 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 10748'MD 10795'MD Country: 20 9062.38'TVD 9109'TVD Averages Before During After Maximum ROP (fph) 110 ft/hr 89 ft/hr 32 ft/hr 167 ft/hr WOB 5 klbs 4 klbs 0 klbs 5 klbs RPM 61 rpm 60 rpm 0 rpm 59 rpm PP 2432 psi 2370 psi 2450 psi 2420 psi Mud Weight 10.3 lbs/gal 10.3 lbs/gal 11.3 lbs/gal 10.3 lbs/gal Chloride 31,000 31,000 33,000 31,000 Total Gas 70 574 17 1,107 C1 (ppm) 12,733 108,588 3,929 214,289 C2 (ppm) 43 686 8 1,480 C3 (ppm) - 119 1 310 C4 (ppm) - 52 - 180 C5 (ppm) - 9 - 40 Lithology Odor None Amount None Type N/A Amount Amount N/A Distribution Intensity Color Color Intensity Color Color Intesity Color N/A Color Comments Report by: Residual Cut Sand/ Tuffaceous Sandstone = medium light to light gray overall with darker gray secondary hues from ashy matrix, individual grains dominantly clear to translucent quartz and volcanic glass with light to medium gray, trace light green to light greenish gray; very fine lower to coarse lower, dominantly fine; angular to subangular; poor to fair sorting; dominantly unconsolidated with ashy matrix common; very fragile to pulverulent with glass shards common; non calcareous. N/A Stain Hilcorp Alaska, LLC 133-20474-01-00 CLU 05-RD Cannery Loop Unit Saxon 169 11/2/2015 10:19 AM Cut Free Oil in Mud Kenai Borough Alaska USA Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis N/A Ralph Winkelman Note: The during interval was circulated up thru the choke at 46 spm. This was due to well control issue and resulted in lower gas readings than would have been observed at normal pump rate. While circulating thru choke, pumping 11.0 ppg kill mud down hole. GAS SHOW Oil Show Rating 1 10 100 1000 10000 100000 1000000 1 2 3 4 pp m Pixler Plot DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 3 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 11111'MD 11160'MD Country: 20 9425'TVD 9474.2'TVD Averages Before During After Maximum ROP (fph) 82 ft/hr 90 ft/hr 89 ft/hr 200 ft/hr WOB 4 klbs 4 klbs 5 klbs 5 klbs RPM 59 rpm 58 rpm 60 rpm 57 rpm PP 2766 psi 2643 psi 2593 psi 2705 psi Mud Weight 11.3 lbs/gal 11.3 lbs/gal 11.3 lbs/gal 11.3 lbs/gal Chloride 33,000 33,000 33,000 33,000 Total Gas 76 199 64 293 C1 (ppm) 13,428 35,019 11,343 51,448 C2 (ppm) 46 119 38 175 C3 (ppm) C4 (ppm) C5 (ppm) Lithology Odor None Amount None Type N/A Amount Amount N/A Distribution Intensity Color Color Intensity Color Color Intesity Color N/A Color Comments Report by: Residual Cut Sandstone (11111' - 11160) = very pale gray to white or whitish gray; very fine to upper medium grained; moderately to poorly sorted; sub angular to sub rounded with moderately high to high sphericity; grains predominantly transparent to translucent colorless quartz with very minor surface abrasion; very soft to barely crumbly with abundant loose grains; argillaceous; non calcareous matrix material; interstices filled with poor to moderately visible porosity; <10% reworked sediment inclusions. N/A Stain Hilcorp Alaska, LLC 133-20474-01-00 CLU 05-RD Cannery Loop Unit Saxon 169 11/3/2015 6:54 AM Cut Free Oil in Mud Kenai Borough Alaska USA Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis N/A Ralph Winkelman GAS SHOW Oil Show Rating 1 10 100 1000 10000 100000 1000000 1 2 3 4 pp m Pixler Plot DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 4 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 11320'MD 11369'MD Country: 20 9634.3'TVD 9683'TVD Averages Before During After Maximum ROP (fph) 96 ft/hr 85 ft/hr 86 ft/hr 154 ft/hr WOB 6 klbs 5 klbs 6 klbs 5 klbs RPM 62 rpm 57 rpm 61 rpm 56 rpm PP 2888 psi 2665 psi 2792 psi 2693 psi Mud Weight 11.3 lbs/gal 11.3 lbs/gal 11.3 lbs/gal 11.3 lbs/gal Chloride 33,000 33,000 33,000 33,000 Total Gas 233 312 108 454 C1 (ppm) 42,616 58,441 17,066 86,516 C2 (ppm) 181 310 55 487 C3 (ppm) 22 36 4 57 C4 (ppm) C5 (ppm) Lithology Odor None Amount None Type N/A Amount Amount N/A Distribution Intensity Color Color Intensity Color Color Intesity Color N/A Color Comments Report by: Residual Fluorescence Cuttings Analysis N/A Ralph Winkelman GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Borough Alaska USA Fluorescence Cut Fluorescence N/A Stain Hilcorp Alaska, LLC 133-20474-01-00 CLU 05-RD Cannery Loop Unit Saxon 169 11/3/2015 11:51 AM Residual Cut Sand/ Tuffaceous sandstone =light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray and black; very fine upper to trace very coarse lower, dominantly fine upper to lower; angular to subangular; poor to fair sorting; dominantly unconsolidated with with abundant ashy matrix supported sands; dirty white with darker secondary hues; very fragile and pulverulent; non calcareous. 1 10 100 1000 10000 100000 1000000 1 2 3 4 pp m Pixler Plot DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 5 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 11572'MD 11605'MD Country: 20 9886'TVD 9919'TVD Averages Before During After Maximum ROP (fph) 83 ft/hr 95 ft/hr 54 ft/hr 245 ft/hr WOB 5 klbs 5 klbs 7 klbs 5 klbs RPM 58 rpm 58 rpm 57 rpm 56 rpm PP 2866 psi 2804 psi 2869 psi 2798 psi Mud Weight 11.3 lbs/gal 11.3 lbs/gal 11.3 lbs/gal 11.3 lbs/gal Chloride 33,000 33,000 33,000 33,000 Total Gas 150 408 57 612 C1 (ppm) 27,581 74,099 10,019 111,051 C2 (ppm) 116 441 61 646 C3 (ppm) 19 67 19 85 C4 (ppm) C5 (ppm) Lithology Odor None Amount None Type N/A Amount Amount N/A Distribution Intensity Color Color Intensity Color Color Intesity Color N/A Color Comments Report by: Residual Fluorescence Cuttings Analysis N/A Ralph Winkelman GAS SHOW Oil Show Rating Cut Free Oil in Mud Kenai Borough Alaska USA Fluorescence Cut Fluorescence N/A Stain Hilcorp Alaska, LLC 133-20474-01-00 CLU 05-RD Cannery Loop Unit Saxon 169 11/3/2015 16:59 AM Residual Cut Sand/ tuffaceous sandstone = very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, trace medium to dark gray, pale rose and light green to light greenish gray; very fine upper to trace coarse lower, dominantly fine; angular to subangular; moderately well sorted; dominantly disaggregated with dirty white ashy matrix supported sands; very fragile; crumbly; non calcareous. 1 10 100 1000 10000 100000 1000000 1 2 3 4 pp m Pixler Plot DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 Hydrocarbon Show Report # 6 Operator: Well: API Number: Field: Date: Rig: Time: County: Depth Start End State: 20 11702'MD 11743'MD Country: 20 10016'TVD 10057'TVD Averages Before During After Maximum ROP (fph) 102 ft/hr 89 ft/hr 74 ft/hr 137 ft/hr WOB 5 klbs 6 klbs 6 klbs 6 klbs RPM 59 rpm 57 rpm 56 rpm 56 rpm PP 2871 psi 2787 psi 2819 psi 2826 psi Mud Weight 11.3 lbs/gal 11.3 lbs/gal 11.3 lbs/gal 11.3 lbs/gal Chloride 33,000 33,000 31,000 33,000 Total Gas 400 473 121 650 C1 (ppm) 74,672 88,579 22,114 122,114 C2 (ppm) 400 494 92 760 C3 (ppm) 43 70 16 97 C4 (ppm) 0 23 31 C5 (ppm) Lithology Odor None Amount None Type N/A Amount Amount N/A Distribution Intensity Color Color Intensity Color Color Intesity Color N/A Color Comments Report by: Residual Cut Sand/ tuffaceous sandstone/ conglomerate = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, medium to mdark gray, light green, pale rose and dusky red; very fine upper to trace very coarse upper, dominantly fine; angular to subangular; poor to fair sorting; dominantly unconsolidated with ash matrix supported sands; dirty white with darker secondary hues; very fragile and pulverulent; non to slightly calcareous. N/A Stain Hilcorp Alaska, LLC 133-20474-01-00 CLU 05-RD Cannery Loop Unit Saxon 169 11/3/2015 19:39 AM Cut Free Oil in Mud Kenai Borough Alaska USA Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis N/A Ralph Winkelman GAS SHOW Oil Show Rating 1 10 100 1000 10000 100000 1000000 1 2 3 4 pp m Pixler Plot DRY GAS GAS CONDENSATE OI L NON PRODUCTIVE C1/C2 C1/C4 C1/C5 C1/C3 31 6 DAILY REPORTS Hilcorp Alaska, LLC Kenai Burrough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 13, 2015 DEPTH 6562 PRESENT OPERATION Loss Remediation TIME 24:00 PM YESTERDAY 6548 24 HOUR FOOTAGE 14 CASING INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 8.50 Mill 6527 6562 35 4.3 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 17.6 @ 6559 1.9 @ 6557 5.1 2.09 FT/HR SURFACE TORQUE 12981 @ 6558 10647 @ 6561 12854.9 11946.10 FT-LBS WEIGHT ON BIT 27 @ 6559 14 @ 6548 18.6 18.24 KLBS ROTARY RPM 87 @ 6553 82 @ 6557 90.8 86.37 RPM PUMP PRESSURE 1012 @ 6548 725 @ 6552 833.0 767.78 PSI DRILLING MUD REPORT DEPTH MW 9.0 VIS 49 PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 6 @ 6555 2 @ 6562 4.8 TRIP GAS N/A CUTTING GAS 0 @ @ WIPER GAS N/A CHROMATOGRAPHY (ppm) SURVEY N/A METHANE (C-1) 0 @ 6562 0 @ 6562 0.0 CONNECTION GAS HIGH N/A ETHANE (C-2) 0 @ 6562 0 @ 6562 0.0 AVG N/A PROPANE (C-3) 0 @ 6562 0 @ 6562 0.0 CURRENT N/A BUTANE (C-4) 0 @ 6562 0 @ 6562 0.0 CURRENT BACKGROUND/AVG 2 / 5 PENTANE (C-5) 0 @ 6562 0 @ 6562 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Beluga PRESENT LITHOLOGY @ 6560' = 70% cement contamination and 30% sandy shale DAILY ACTIVITY SUMMARY Trip in hole to 6483' and displace with 9.0 KCL mud; Set whipstock and drill out window; start drilling new formation from 6544' to 6562'; encounter losses; currently engaged in efforts to remediate losses and re- establish returns. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2885.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Burrough, AK DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 14, 2015 DEPTH 6562 PRESENT OPERATION Tripping in TIME 23:59 pm YESTERDAY 6562 24 HOUR FOOTAGE 0 CASING INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5 Varel V516PR 4007156 5x14 6562 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 6562/5390 MW 8.95 VIS 66 PV 11 YP 19 FL 6.1 Gels 7/9/12 CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 1 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Beluga PRESENT LITHOLOGY @6560' 70% cement contamination and 30% sandy shale DAILY ACTIVITY SUMMARY Pump Vanguard pill down back side and slow losses to 10 bbls /hour pull out of hole and pick up well commanderand start tripping back into hole. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3645.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Burrough. Ak DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 15, 2015 DEPTH 7067 PRESENT OPERATION Wiper Trip TIME 23:59 pm YESTERDAY 6563. 24 HOUR FOOTAGE 504 CASING INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7064.57 31.76 43.58 5846.28 7127.61 32.06 43.48 5899.79 7189.38 32.1 42.27 5952.13 7251.09 33.98 43.88 6003.86 7311.96 34.09 44.44 6054.30 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5 Varel V516PR 4007156 5X14 6562 7350 787 9.8 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 416.4 @ 7103 2.3 @ 6563 105.1 76.63 FT/HR SURFACE TORQUE 14555 @ 7320 41 @ 6808 8375.5 14009.63 FT-LBS WEIGHT ON BIT 11 @ 6737 0 @ 6980 6.8 7.48 KLBS ROTARY RPM 54 @ 7255 0 @ 6808 31.2 52.82 RPM PUMP PRESSURE 1506 @ 7302 884 @ 6607 1273.1 1381.40 PSI DRILLING MUD REPORT DEPTH 53 MW 9.0 VIS 53 PV 10 YP 21 FL 5.0 Gels 8/11/14 CL- 32000 FC 1/2 SOL 2.4 SD 0.25 OIL 0/95.0 MBT 1.3 pH 9.6 Ca+ 80 Alk .30 MWD SUMMARY INTERVAL 6562 TO 7350 TOOLS Directional and Gamma GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 245 @ 6751.00000 1 @ 6563.00000 73.0 TRIP GAS N/A CUTTING GAS 0 @ 7350.00000 0 @ 7350.00000 0.0 WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 49239 @ 6751.00000 107 @ 6880.00000 14592.7 CONNECTION GAS HIGH 136 ETHANE (C-2) 225 @ 7041.00000 0 @ 7245.00000 25.8 AVG 21 PROPANE (C-3) 0 @ 7350.00000 0 @ 7350.00000 0.0 CURRENT 0 BUTANE (C-4) 0 @ 7350.00000 0 @ 7350.00000 0.0 CURRENT BACKGROUND/AVG 1 / 73 PENTANE (C-5) 0 @ 7350.00000 0 @ 7350.00000 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Middle Beluga PRESENT LITHOLOGY @7340' = Tuffaceous claystone 40%; Tuffaceous siltstone 40% ; Carbonaceous shale10% ; Sandstone 10%; DAILY ACTIVITY SUMMARY Trip to bottom with new BHA and drill ahead with no problems. currently at 7350 making a wiper trip. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Burrough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 16, 2015 DEPTH 8155 PRESENT OPERATION Making Wiper Trip TIME 23:59 PM YESTERDAY 7067 24 HOUR FOOTAGE 1088 CASING INFORMATION 9.625 @ 6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7437.34 33.98 45.49 6157.75 7498.39 33.93 45.56 6208.40 7561.02 34.00 44.89 6260.34 7622.70 33.73 44.83 6311.56 7684.35 34.05 45.97 6362.73 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5 Varel V516PR 4007156 5x14 6562' (8155) 1593 17.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 420.4 @ 7796 1.1 @ 8032 119.2 87.65 FT/HR SURFACE TORQUE 17049 @ 7800 2239 @ 7290 14353.6 15768.72 FT-LBS WEIGHT ON BIT 14 @ 7682 1 @ 7291 8.9 7.67 KLBS ROTARY RPM 80 @ 8032 0 @ 7667 66.3 78.48 RPM PUMP PRESSURE 1725 @ 8109 1197 @ 7227 1518.0 1716.30 PSI DRILLING MUD REPORT DEPTH 8155/6753 MW 9.3 VIS 57 PV 14 YP 24 FL 4.3 Gels 8/11/15 CL- 32000 FC 1/2 SOL 4.7 SD 0.15 OIL 0/92.7 MBT 2.0 pH 9.1 Ca+ 40 Alk 0.35 MWD SUMMARY INTERVAL 6562 TO 8155 TOOLS Directional and Gamma GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 300 @ 8140 17 @ 7229 97.5 TRIP GAS CUTTING GAS @ @ WIPER GAS 54 CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 56968 @ 8140 3443 @ 7229 19238.6 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 8155 0 @ 8155 0.0 AVG 0 PROPANE (C-3) 0 @ 8155 0 @ 8155 0.0 CURRENT 0 BUTANE (C-4) 0 @ 8155 0 @ 8155 0.0 CURRENT BACKGROUND/AVG 2 / 98 PENTANE (C-5) 0 @ 8155 0 @ 8155 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Lower Beluga PRESENT LITHOLOGY Tuffaceous Claystone 50%; Carbonaceous shale 20%; Tuffaceous siltstone 20%; Coal 10% DAILY ACTIVITY SUMMARY Continue drill from 7076’ to 7350’. CBU. Wipe hole back to 6910’, tight at 7145’, 7018’, 6970’, 6951’. Wash out of hole from 6910’ to 6507’. Service rig. Monitor well for losses, .8 bbl/hr. RIH, no tight spots. Drill from 7350’ to 8155’. Pump 20 bbls high viscosity sweep and circulate until hole is clean. Begin wiper trip. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Burrough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 17, 2015 DEPTH 8657 PRESENT OPERATION Drilling Ahead TIME 23:59 YESTERDAY 8156 24 HOUR FOOTAGE 501 CASING INFORMATION 9.625@ 6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8490.03 34.15 44.68 7031.13 8551.13 33.84 43.77 7081.79 8614.14 33.25 43.86 7134.31 8675.64 34.49 45.22 7185.37 8737.88 34.52 44.88 7236.66 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5 Varel V516PR 4007156 5x14 6562' (8657) 2095 23.7 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 217.2 @ 8412 0.5 @ 8652 90.6 29.50 FT/HR SURFACE TORQUE 17328 @ 8157 2250 @ 8344 15338.9 2266.25 FT-LBS WEIGHT ON BIT 12 @ 8244 0 @ 8653 7.9 2.76 KLBS ROTARY RPM 79 @ 8594 0 @ 8356 72.3 0.00 RPM PUMP PRESSURE 1801 @ 8471 1186 @ 8156 1647.7 1663.00 PSI DRILLING MUD REPORT DEPTH 8590/7115 MW 9.35 VIS 49 PV 12 YP 22 FL 3.9 Gels 6/10/14 CL- 30500 FC 1/2 SOL 5.3 SD 0.15 OIL 0.5/91.8 MBT 2.5 pH 9.8 Ca+ 60 Alk 0.30 MWD SUMMARY INTERVAL 6562 TO (8657) TOOLS gamma and directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 322 @ 8417 36 @ 8654 135.2 TRIP GAS -- CUTTING GAS @ @ WIPER GAS 222 CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 63860 @ 8417 9520 @ 8652 26985.2 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 8657 0 @ 8657 0.0 AVG 0 PROPANE (C-3) 0 @ 8657 0 @ 8657 0.0 CURRENT 0 BUTANE (C-4) 0 @ 8657 0 @ 8657 0.0 CURRENT BACKGROUND/AVG 49 / 135 PENTANE (C-5) 0 @ 8657 0 @ 8657 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Lower Beluga PRESENT LITHOLOGY Tuffaceous Claystone 40%; Carbonaceous Shale 30%; Tuffaceous Siltstone 30% DAILY ACTIVITY SUMMARY Wiper Trip from 7300' to 6510' pumping out of hole; pulled on elevators from 6859' to 6510'; rig service( grease crown , drawworks, iron rough neck, blocks and TD; check all fluids in motors). Run in hole from 6510' - 8154' and drill ahead to 8590'. Wiper trip from 8590' to8088' with no tight spots observed. Return to bottom and drill ahead. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Burrough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 18, 2015 DEPTH 9467 PRESENT OPERATION Drilling Ahead TIME 29:59 PM YESTERDAY 8673 24 HOUR FOOTAGE 794 CASING INFORMATION 9.625@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8861.51 34.82 45.02 7338.63 8924.03 34.38 44.64 7390.10 8984.59 35.24 45.46 7439.82 9048.38 34.88 45.72 7925.04 9108.06 34.67 45.23 7541.06 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5 Varel V516PR 4007156 5x14 6562' 9467' 2905' 33.2 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 366.4 @ 8874 5.2 @ 8965 98.3 110.51 FT/HR SURFACE TORQUE 19213 @ 9278 2274 @ 8838 16075.4 17203.71 FT-LBS WEIGHT ON BIT 12 @ 8686 0 @ 8839 7.8 7.86 KLBS ROTARY RPM 81 @ 9148 1 @ 8838 70.0 75.57 RPM PUMP PRESSURE 2240 @ 9282 1395 @ 9176 1892.0 2162.10 PSI DRILLING MUD REPORT DEPTH 9339/7733 MW 9.55 VIS 55 PV 16 YP 23 FL 3.6 Gels 6 /11/15 CL- 31,000 FC 1/2 SOL 6.6 SD 0.20 OIL 0.8/90.2 MBT 3 pH 9.0 Ca+ 80 Alk .30 MWD SUMMARY INTERVAL 6562' TO CURRENT TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 516 @ 8863 18 @ 9172 152.6 TRIP GAS -- CUTTING GAS @ @ WIPER GAS 956 CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 107364 @ 8862 3019 @ 9341 30420.7 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 9467 0 @ 9467 0.0 AVG 0 PROPANE (C-3) 0 @ 9467 0 @ 9467 0.0 CURRENT 0 BUTANE (C-4) 0 @ 9467 0 @ 9467 0.0 CURRENT BACKGROUND/AVG 152 / 733 PENTANE (C-5) 0 @ 9467 0 @ 9467 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Lower Beluga PRESENT LITHOLOGY Tuffaceous Claystone 60%; Tuffaceous Siltstone 20%; Carbonaceous shale10% ; Sand 10 % DAILY ACTIVITY SUMMARY Drill ahead from 9025' to 9147'; pump tandem sweep and circulate out with 100% increase in cutting and sweep came back on time; POOH from 9142 to 7660' tight hole withconstant overpull. Run in hole from 7660 to 9146 had 17' of fill ; drill from 9147 to 9150'. Drill from 9150' to midnight depth of 9467'. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna.New Hilcorp Alaska, LLC Kenai Burrough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 19, 2015 DEPTH 9861 PRESENT OPERATION Drilling Ahead TIME 23:59 YESTERDAY 9467 24 HOUR FOOTAGE 394 CASING INFORMATION 9.625'@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9482.93 33.27 45.6 7851.36 9544.75 32.68 44.91 7903.22 9607.06 30.31 45.61 7956.34 9667.98 28.08 46.77 8009.52 9729.86 25.72 47.69 8064.71 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.5 Varel V516PR 4007156 5x14 6562' 9861' 3299 41.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 314.0 @ 9526 0.5 @ 9835 73.2 36.93 FT/HR SURFACE TORQUE 20191 @ 9804 2508 @ 9582 12472.4 2596.70 FT-LBS WEIGHT ON BIT 12 @ 9718 0 @ 9843 6.8 5.65 KLBS ROTARY RPM 75 @ 9467 0 @ 9786 43.5 0.00 RPM PUMP PRESSURE 2254 @ 9677 1493 @ 9775 1982.4 1942.17 PSI DRILLING MUD REPORT DEPTH 9864/8189 MW 9.55 VIS 58 PV 18 YP 22 FL 3.0 Gels 5/10/15 CL- 30000 FC 1/2 SOL 6.5 SD 0.20 OIL 2.0/89.2 MBT 4.0 pH 9.1 Ca+ 60 Alk 0.15 MWD SUMMARY INTERVAL 6562' TO CURRENT TOOLS Gamma and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 897 @ 9768 48 @ 9509 437.2 TRIP GAS -- CUTTING GAS @ @ WIPER GAS 896 CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 179149 @ 9706 9686 @ 9509 84599.8 CONNECTION GAS HIGH 0 ETHANE (C-2) 595 @ 9776 6 @ 9829 45.2 AVG 0 PROPANE (C-3) 76 @ 9833 0 @ 9829 6.3 CURRENT 0 BUTANE (C-4) 0 @ 9861 0 @ 9861 0.0 CURRENT BACKGROUND/AVG 573 / 437 PENTANE (C-5) 0 @ 9861 0 @ 9861 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Tyonek PRESENT LITHOLOGY Sandstone 40%; carbonaceous shale 20%; sand 20%; tuffaceous siltstone 20% DAILY ACTIVITY SUMMARY Drill ahead from 9710' to 9767' ; pump high vis sweep and circulaste out with an 80% increae in cuttings; arrived 70 bbls early; pull out of hole from 9767' to 8520'; monitor well ( losing 0.9 bbls per hour;) run back in hole to 9767'; had 29' of fill in hole washed down; drilling from 9767' to 9780'. Change tour. Drill ahead from 9780' to 9861' midnight depth. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE 10/20/2015 DEPTH 10200 PRESENT OPERATION Weighting Up Mud System TIME 23:59 YESTERDAY 9861 24 HOUR FOOTAGE 339 CASING INFORMATION 9.625' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9915.35 18.60 46.84 8235.84 9976.56 15.43 44.84 8294.36 10040.55 11.48 46.78 8356.58 10100.55 7.50 52.64 8415.76 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.58 Varel V516PR 4007156 5x14 6562' 10200' 3638' 49.8 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 374.5 @ 10129 3.8 @ 9956 64.4 69 FT/HR SURFACE TORQUE 19466 @ 10076 775 @ 10163 6652.4 19333 FT-LBS WEIGHT ON BIT 18 @ 10118 0 @ 9921 7.8 3 KLBS ROTARY RPM 59 @ 9876 0 @ 9997 15.6 55 RPM PUMP PRESSURE 2495 @ 10069 1678 @ 9958 2053.1 2111 PSI DRILLING MUD REPORT DEPTH 10200'/8515' MW 9.80 VIS 58 PV 18 YP 20 FL 2.9 Gels 4/9/12 CL- 32000 FC 1/2 SOL 6.9 SD 0.15 OIL 2.5/88.1 MBT 3.8 pH 9.7 Ca+ 80 Alk 0.40 MWD SUMMARY INTERVAL 6562' TO 10200' TOOLS Gamma and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1028 @ 9892 400 @ 9869 771.7 TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 241124 @ 9892 0 @ 10200 166864.7 CONNECTION GAS HIGH 0 ETHANE (C-2) 1541 @ 10013 17 @ 9954 560.7 AVG 0 PROPANE (C-3) 148 @ 10013 2 @ 9954 73.5 CURRENT 0 BUTANE (C-4) 71 @ 10013 0 @ 10199 17.1 CURRENT BACKGROUND/AVG 302/ 772 PENTANE (C-5) 39 @ 10013 0 @ 10056 2.7 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Tyonek PRESENT LITHOLOGY Coal10%; Sand 60%; Sandstone10%; Tuffaceous Claystone10%; Tuffaceous Siltstone 10% DAILY ACTIVITY SUMMARY Drill from 9467'to 10139’; pump strata clean sweep and circulate out with 300% increase in cuttings – came back 85 barrels early; drill from 10139’ to 10200’; pump strata clean sweep and circulate out with 300% increase in cuttings – came back 52 barrels early; weighting up mud. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE 10/21/2015 DEPTH 10200 PRESENT OPERATION Rig Service TIME 23:59 YESTERDAY 10200 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625'@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9915.35 18.60 46.84 8235.84 9976.56 15.43 44.84 8294.36 10040.55 11.48 46.78 8356.58 10100.55 7.50 52.64 8415.76 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 8.58 Varel V516PR 4007156 5x14 6562' 10200' 3638' 49.8 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10200'/8515' MW 10.10 VIS 60 PV 21 YP 25 FL 2.5 Gels 7/13/17 CL- 32000 FC 1/2 SOL 8.4 SD 0.15 OIL 3.0/86.2 MBT 4.5 pH 9.7 Ca+ 80 Alk 0.40 MWD SUMMARY INTERVAL 6562' TO 10200' TOOLS Gamma and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0 /126 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Tyonek PRESENT LITHOLOGY Coal10%; Sand 60%; Sandstone10%; Tuffaceous Claystone10%; Tuffaceous Siltstone 10% DAILY ACTIVITY SUMMARY Circulate and reciprocate, pump 41 barrels strata clean sweep; came back 31 barrels early wit 300% increase in cutting; increase lubes to 3% and bring mud weight up to 10ppg with BaraCarb; pull out of hole on elevators from 10200’ to 7040’; three barrels over calculated displacement. Pump 30Barrels Strata Clean Sweep. Sweep arrived back 35 barrels early with 200% increase in cuttings; flow check – slight seepage; pull out of hole from 7040’ to 6478’ on elevators with no issues. Slip and cut 170’ drill line; grease equipment; check and adjust brakes; check RigSmart; replace bolt on bolt tube. Pull out to 4614'. Max Gas in the last 24 Hours 1038 units. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE 10/22/2015 DEPTH 10200 PRESENT OPERATION Circulating B/U TIME 23:59 YESTERDAY 10200 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625'@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9915.35 18.60 46.84 8235.84 9976.56 15.43 44.84 8294.36 10040.55 11.48 46.78 8356.58 10100.55 7.50 52.64 8415.76 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED MAD Pass Tools DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10200'/8515' MW 10.05 VIS 61 PV 18 YP 23 FL 2.5 Gels 6/11/16 CL- 32000 FC 1/2 SOL 8.0 SD 0.15 OIL 3.0/86.6 MBT 4.5 pH 10 Ca+ 80 Alk 0.70 MWD SUMMARY INTERVAL 10200' TO 10200' TOOLS MAD Pass tools GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 8 / 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Tyonek PRESENT LITHOLOGY Coal10%; Sand 60%; Sandstone10%; Tuffaceous Claystone10%; Tuffaceous Siltstone 10% DAILY ACTIVITY SUMMARY POOH to 776 ‘ with no issues; hole took 7 bbls over calculated displacement; rack back 8 stands HWDP and 2 stands flex collars; lay down unneeded BHA; download MWD data.Lay down directional tools; inspect draw works; adjust brakes; inspect top drive; grease wash pips; pick up directional tools; trip in hole from 311’ to 3300; fill pipe and circulsate bottoms up with 510 gpm while rotating 90RPM and reciprocating; MWD pulse test okay; trip in hole from 3300’ to 5900’. Trip in to bottom and pump 45 barrel sweep with Strata Kleen; Start to circulate out sweep at report time CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE 10/23/2015 DEPTH 10200 PRESENT OPERATION Making MAD pass TIME 23:59 YESTERDAY 10200 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625'@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9915.35 18.60 46.84 8235.84 9976.56 15.43 44.84 8294.36 10040.55 11.48 46.78 8356.58 10100.55 7.50 52.64 8415.76 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED MAD PassTools Huges VM180v 3x20 10200 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10200'/8515' MW 10.10 VIS 57 PV 21 YP 23 FL 3.0 Gels 6/12/18 CL- 30000 FC 1/2 SOL 8.5 SD 0.20 OIL 3.0/86.6 MBT 4.5 pH 10.2 Ca+ 80 Alk 0.70 MWD SUMMARY INTERVAL 10200' TO 10200' TOOLS MAD Pass tools GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 1077 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 15/ 106 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Tyonek PRESENT LITHOLOGY Coal10%; Sand 60%; Sandstone10%; Tuffaceous Claystone10%; Tuffaceous Siltstone 10% DAILY ACTIVITY SUMMARY Circulate out gas with trip gas of 1077 units; Begin MAD pass and currently at 7625' and continuing with MAD pass. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3345.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE 10/24/2015 DEPTH 10200 PRESENT OPERATION Making MAD pass TIME 23:59 YESTERDAY 10200 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625'@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9915.35 18.60 46.84 8235.84 9976.56 15.43 44.84 8294.36 10040.55 11.48 46.78 8356.58 10100.55 7.50 52.64 8415.76 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED MAD Pass Tools Huges VM180v 3x20 10200 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10200'/8515' MW 10.00 VIS 61 PV 21 YP 23 FL 2.8 Gels 5/9/13 CL- 31000 FC 1/2 SOL 7.4 SD 0.20 OIL 3.0/87.2 MBT 4.5 pH 9.9 Ca+ 80 Alk 0.70 MWD SUMMARY INTERVAL 10200' TO 10200' TOOLS MAD Pass tools GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 5 / 8 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Tyonek PRESENT LITHOLOGY Coal 10%; Sand 60%; Sandstone 10%; Tuffaceous Claystone 10%; Tuffaceous Siltstone 10%. DAILY ACTIVITY SUMMARY Making MAD pull BHA through window while pumping; circulate and pump 50 barrel Strata Kleen sweep with 100% increasing cuttings; returned 43 bbls early; continue to pump out of hole to 3036' at report time. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3345.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE 10/25/2015 DEPTH 10200 PRESENT OPERATION Tripping in TIME 23:59 YESTERDAY 10200 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625'@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9915.35 18.60 46.84 8235.84 9976.56 15.43 44.84 8294.36 10040.55 11.48 46.78 8356.58 10100.55 7.50 52.64 8415.76 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 8.5 Smith XR+PS TRICONE PT6003 3x24 10200 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10200'/8515' MW 10.00 VIS 68 PV 24 YP 26 FL 2.2 Gels 6/9/14 CL- 0000 FC 1/2 SOL 7.5 SD 0.10 OIL 3.0/87.2 MBT 5.0 pH 10.2 Ca+ 80 Alk 0.60 MWD SUMMARY INTERVAL 10200' TO 10200' TOOLS Well commander GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 48/ -- PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Upper Tyonek PRESENT LITHOLOGY Coal 10%; Sand 60%; Sandstone 10%; Tuffaceous Claystone 10%; Tuffaceous Siltstone 10%. DAILY ACTIVITY SUMMARY Pump out of hole after MADPASS, lay down directional tools, organize and clean rig floor; drain and flush stack; pull wear bushings; install test plug and joint; fill stack with water and purge water from test lines and equipment; test BOPs; pull test plug and blow down test lines; install wear bushing; service top drive and drw works; check back lash and end play on top drive; change washed pipe; make up directional tools. make up BHA and run in hole to 6460' filling pipe every 3000'; circulate bottoms up @6460' with return of 1055 units gas. Max Gas today 1103 units @ bit depth 3108'. CANRIG PERSONNEL ON BOARD 3 DAILY COST $3445.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 26, 2015 DEPTH 10450 PRESENT OPERATION Circulating TIME 23:59 YESTERDAY 10200 24 HOUR FOOTAGE 250 CASING INFORMATION 9.625"@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 3 8.5 Smith XR+PS TRICONE PT6003 3x24 10200 10450 250 12.3 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 269.5 @ 10405 2.7 @ 10410 31.5 49.17 FT/HR SURFACE TORQUE 19333 @ 10200 13920 @ 10368 15460.3 16201.66 FT-LBS WEIGHT ON BIT 23 @ 10320 1 @ 10393 20.3 21.39 KLBS ROTARY RPM 81 @ 10370 55 @ 10200 80.0 78.94 RPM PUMP PRESSURE 2432 @ 10356 2111 @ 10200 2351.0 2386.79 PSI DRILLING MUD REPORT DEPTH 10419/8741 MW 10.40 VIS 88 PV 28 YP 34 FL 3.0 Gels 9/15/22 CL- 30000 FC 1/2 SOL 7.5 SD 0.50 OIL 3.0/87.2 MBT 5.0 pH 10.0 Ca+ 200 Alk 0.60 MWD SUMMARY INTERVAL 10200 TO 10450 TOOLS well commander GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 666 @ 10200 55 @ 10208 191.8 TRIP GAS 1103 CUTTING GAS @ 0 @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 130026 @ 10200 8417 @ 10208 35162.1 CONNECTION GAS HIGH 504 ETHANE (C-2) 592 @ 10200 15 @ 10202 131.4 AVG 329 PROPANE (C-3) 92 @ 10200 1 @ 10391 19.7 CURRENT 350 BUTANE (C-4) 22 @ 10439 0 @ 10220 1.0 CURRENT BACKGROUND/AVG 225 / 192 PENTANE (C-5) 9 @ 10439 0 @ 10449 0.3 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY @10450' = 100% sand PRESENT LITHOLOGY Below the Tyonek T9B depleted sand DAILY ACTIVITY SUMMARY Circulate and condition mud and add LCM in preparation for loss zone. Scratch bottom and break in and pattern bit then stage up WOB; drill ahead from 10200 to 10450' (casing point); circulate and condition mud and strip back LCM. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3545.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 27, 2015 DEPTH 10450 PRESENT OPERATION Laying down BHA TIME 23:59 YESTERDAY 10450 24 HOUR FOOTAGE 250 CASING INFORMATION 9.625"@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10,450/8,765 MW 10.30 VIS 55 PV 18 YP 18 FL 3.2 Gels 4/9/14 CL- 29000 FC 1/2 SOL 11.1 SD 0.60 OIL 3.0/83.8 MBT 6.0 pH 11.4 Ca+ 100 Alk 1.0 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS 824 CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG -- PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY @10450' = 100% sand PRESENT LITHOLOGY Below the Tyonek T9B depleted sand DAILY ACTIVITY SUMMARY Pull out of hole from 9683 to 9180; trip back in hole to bottom @ 10450’ no fill; circulate and condition mud; pump sweep around; and circulate out of hole; attempt to POOH at 10Am but experienced mud u tubing up the pipe and excessive drag when pulling on elevators; pump Strata Kleen sweep and circulate out of the hole; POOH from 10450’ to 6490’; with one tight spot at 10390’; service top drive and change grabber box dies; circulate bottoms up inside casing with 300 units gas at bottoms up; blow down top drive and kelly hose after circulating. POOH from 6490’ to surface while breaking with tongs due to over torque; laying down BHA and breaking off bit. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3345.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 28, 2015 DEPTH 10450 PRESENT OPERATION Running Casing TIME 23:59 YESTERDAY 10450 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10,450/8,765 MW 10.30 VIS 55 PV 35 YP 40 FL 3.6 Gels 9/12/19 CL- 29000 FC 1/2 SOL 11.0 SD 0.75 OIL 2.5/84.4 MBT 6.0 pH 9.6 Ca+ 80 Alk 1.0 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG -- PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY @10450' = 100% sand PRESENT LITHOLOGY Below the Tyonek T9B depleted sand DAILY ACTIVITY SUMMARY 10/28/2015: Made up shoe track and trip in hole with casing from shoe to 2400’; lost returns at 2400’ fill down backside with trip tank and down casing wit ole fill; pump LCM mud down backside with hole fill pump; creep into hole with casing from2400’ to 3890’ keeping backside full with LCM mud from trip tank; top fill casing and build mud volume in pits. At report time bit depth = 5711'. Max gas at 2194' bit depth wile running casing in hole. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3345.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 29, 2015 DEPTH 10450 PRESENT OPERATION Prepping to pump cement TIME 23:59 YESTERDAY 10450 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10,450/8,765 MW 9.10 VIS 68 PV 13 YP 19 FL 4.8 Gels 9/12/19 CL- 4000 FC 1/2 SOL 3.3 SD 0.25 OIL 1.0 MBT 1.0 pH 9.8 Ca+ 80 Alk 0.20 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG -- PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY @10450' = 100% sand PRESENT LITHOLOGY Below the Tyonek T9B depleted sand DAILY ACTIVITY SUMMARY 10/29/2015: Build mud volume while sitting inside casing at 6491’ and pump 5 to 10 bbls down pipe every 15 minutes and rotate string while pumping. Make up crossovers, pony subs and drill pipe to cement head and lay out together on catwalk; trip in hole from 6490’ to10448’; circulate casing with 142 GPM@980psi; lost 497 bbls from 6am to 6pm. Circulate casing 133GPM@740psi while building mud volume; rig up cement lines; hold PJSM and prime cement pumps. Max Gas was 566 units while circulating after getting casing to bottom. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3345.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 30, 2015 DEPTH 10450 PRESENT OPERATION Prepping for return to drilling TIME 23:59 YESTERDAY 10450 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10,450/8,765 MW VIS PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG -- PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY @10450' = 100% sand PRESENT LITHOLOGY Below the Tyonek T9B depleted sand DAILY ACTIVITY SUMMARY Hold PJSM and prime cement pumps; pressure test lines, start pumping cement; Schlumberger pumped 102.7 barrels/15.3 cement; started to displace; 100 barrels into displacement had to go to rig pump; pumped 152.6 bbls; returned to Schlumberger bumped plug with pressure up to 2700 psi; total displacement 265.5 cement in place @2:30am with no returns; set liner; set packer; pressure test ann. to 1166 psi for 10 minutes; circulate bottoms up GPM 245 and Pressure 345; Max Gas 1160 units; lay down cement head; drop wiper ball; circulate; prep tools for slip and cut; hang off blocks. Cut and slip 120’ of drill line; lay down pup joints; break down bottom side of cement head and lay back out to be turned around; POOH from 6400’ to stinger; break and lay down stinger; pick up cement head and break off cross over and pup joint off of top and lay back out; pull wear bushing and install test plug and test joint; change out upper pipe rams back to 2 7/8ths - 5”VBR; prep to test pipe rams; fill stack with water and begin purging air from equipment; test upper 1.5”VBR’s – 250low for 5 minutes and 4000 high for 10minutes; remove test plug and install wear bushing and rig down test equipment. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3345.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Oct 31, 2015 DEPTH 10450 PRESENT OPERATION Trip out for smaller bit TIME 23:59 YESTERDAY 10450 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 6.75 Varel PDHRU 4008283 4x9; 3x10 10450 10450 0 0 New Size DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 10,450/8,765 MW 10.35 VIS 50 PV 16 YP 20 FL 3.2 Gels 6/9/10 CL- 30000 FC 1/2 SOL 7.6 SD -- OIL 0.0/90.0 MBT -- pH 9.5 Ca+ 100 Alk 0.50 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG -- PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY @10450' = 100% sand PRESENT LITHOLOGY Below the Tyonek T9B depleted sand DAILY ACTIVITY SUMMARY Continue to build new mud, clean tanks, redress mud pumps with 5” liners, stage BHA to catwalk, pick up and make up directional BHA. Transfer old mud to tank 2 to warm up MWD tool, warm up mud, MWD and LWD, upload data to LWD; Safety meeting over installing nukes; install nukes in LWD; continue to make up directional tools; trip into hole from 250’ to 6456’; pick up singles and Spiro-torque subs as tripping into hole; work to make through liner top @ 6456’. Circulate and prepare for trip out of hole; pull out of hole from 6456’ due to clearance issues. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3345.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 01, 2015 DEPTH 10470 PRESENT OPERATION Prep for Performing FIT test TIME 23:59 YESTERDAY 10450 24 HOUR FOOTAGE 20 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10162.92 4.20 57.77 8477.79 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 6.125 HDBS MM55 12487636 5x11 10450 (10470) 20 0.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 158.7 @ 10452 1.7 @ 10454 55.8 22.24 FT/HR SURFACE TORQUE 17346 @ 10463 16190 @ 10451 17716.1 17138.75 FT-LBS WEIGHT ON BIT 21 @ 10450 0 @ 10463 1.1 0.21 KLBS ROTARY RPM 78 @ 10450 24 @ 10470 30.3 24.02 RPM PUMP PRESSURE 2386 @ 10450 1331 @ 10453 1560.3 1417.94 PSI DRILLING MUD REPORT DEPTH 10470' MW 10.1 VIS PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL 10450 TO 10470 TOOLS Gamma and motor with 1.15° bend GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 225 @ 10450 0 @ 10467 11.5 TRIP GAS 418 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 41218 @ 10450 41218 @ 10450 2060.9 CONNECTION GAS HIGH N/A ETHANE (C-2) 172 @ 10450 172 @ 10450 8.6 AVG N/A PROPANE (C-3) 26 @ 10450 26 @ 10450 1.3 CURRENT N/A BUTANE (C-4) 9 @ 10450 9 @ 10450 0.5 CURRENT BACKGROUND/AVG 0 / 11.5 PENTANE (C-5) 0 @ 10470 0 @ 10470 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Below the Tyonek T9B depleted sand PRESENT LITHOLOGY @10450' = 100% sand ( Displacing mud no sample available @ 10455' or 10470') DAILY ACTIVITY SUMMARY Lay down BHA; change bit and remove sources; make up BHA with new bit and upload; run in hole with 6 1/8 from 631’ to 6477’; pick up singles and Spiro, torque. Single in the hole from 6460’ to 8389’ and add Spiro Torque subs to string as per tally; trip out of derrick from 8389’ to 10254’; circulate bottoms up; test casing to 3000 psi for 30 minutes; pumped 7 barrels to pressure up to 3000 psi and bled back 6.5 barrels; tag plugs @ 10296’; establish off bottom drilling parameters; took weight and started drilling cement and plugs @ 10294’; drilled cement and plugs from 10294’ to 10297’. Drill out shoe track; and drill 20’ new formation to 10470’; displace over to 10.3 ppg mud. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 02, 2015 DEPTH 10807 PRESENT OPERATION Drilling Ahead TIME 23:59 YESTERDAY 10470 24 HOUR FOOTAGE 337 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10483.40 1.49 56.43 8797.85 10548.80 1.96 55.16 8863.22 10615.44 1.86 64.78 8929.82 10681.04 1.57 68.46 8995.39 10747.06 1.64 68.99 9061.38 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 6.125 HDBS MM55 12487636 5x11 10450 10807 357' 4.7 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 205.8 @ 10747 2.4 @ 10678 85.0 32.43 FT/HR SURFACE TORQUE 17469 @ 10602 102 @ 10596 15441.2 0.00 FT-LBS WEIGHT ON BIT 5 @ 10650 0 @ 10801 4.0 0.00 KLBS ROTARY RPM 74 @ 10718 24 @ 10470 43.4 0.00 RPM PUMP PRESSURE 2420 @ 10774 1383 @ 10512 2075.5 2345.80 PSI DRILLING MUD REPORT DEPTH 10,795/9,109 MW 11.25 VIS 51 PV 14 YP 21 FL 3.0 Gels 6/9/12 CL- 33000 FC 1/2 SOL 11.3 SD 0.10 OIL 0.8/85.5 MBT 1.0 pH 9.3 Ca+ 60 Alk 0.25 MWD SUMMARY INTERVAL 10450 TO 10470 TOOLS Gamma and motor with 1.15° bend GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1107 @ 10783 1 @ 10757 184.5 TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 214289 @ 10783 262 @ 10757 33244.8 CONNECTION GAS HIGH 585 ETHANE (C-2) 1480 @ 10779 1 @ 10757 150.9 AVG 381 PROPANE (C-3) 310 @ 10779 0 @ 10673 21.3 CURRENT 585 BUTANE (C-4) 180 @ 10779 0 @ 10806 8.0 CURRENT BACKGROUND/AVG 39 / 185 PENTANE (C-5) 40 @ 10779 0 @ 10806 1.4 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek ; TY 91-2 PRESENT LITHOLOGY @ 10800’ = Sand 80%; Tuffaceous siltstone 10%; Carbonaceous shale 10% DAILY ACTIVITY SUMMARY Drill out shoe track; displace over to 10.1 ppg mu; observed increase in Torque. Pump 584 barrels 10.1 ppg to displace; rig up test equipment and perform FIT test to 12.0ppg EMW;@ 842psi and held for 10 minutes; no pressure loss; pumped 64 gals and 64 gals returned when pressure bled off; Drill from 10470’ to 10595’. Noticed influx into well bore, opened choke, HCR, and closed annular on flow; established kill procedure; began killing well with 11ppg mud; circulating with 112 GPM and taking returns through choke and gas buster; circulated 1 full circulation; killed pump to check for pressure and flow. Continue to circulate 11.3 ppg around to to influx with 187 GPM and 1235 psi pressure; reciprocate pipe; POOH from 10795’ to 10385’ with no issues-proper displacement –well static; perform fit test to 13.0ppg EMW to 820psi and held for 10 minutes; pumped 79 gals and returned 77 gals; blow down all test equipment, choke manifold, kill line poor boy; rig service – grease draw works, top drive IR, check brakes; grease crown and blocks; run in hole from 10385’ to 10795’ and pick up turbulizer; Return to drilling. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 03, 2015 DEPTH 11761 PRESENT OPERATION Circulate/Prep to return to drilling TIME 23:59 YESTERDAY 10807 24 HOUR FOOTAGE 954 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11273.85 1.36 300.69 9587.97 11338.76 1.19 292.70 9652.87 11404.09 1.18 303.82 9718.18 11469.72 1.09 299.71 9783.80 11535.89 1.07 290.83 9849.96 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 6.125 HDBS MM55 12487636 5x11 10450 (11761) 11311 18.7 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 263.3 @ 11440 4.0 @ 11271 84.1 6.38 FT/HR SURFACE TORQUE 19266 @ 11756 2410 @ 11276 17037.4 18417.57 FT-LBS WEIGHT ON BIT 9 @ 11618 0 @ 11569 4.3 7.05 KLBS ROTARY RPM 59 @ 11279 4 @ 11276 53.5 54.04 RPM PUMP PRESSURE 2882 @ 11646 2110 @ 11258 2602.8 2628.11 PSI DRILLING MUD REPORT DEPTH 11761/10075 MW 11.28 VIS 53 PV 18 YP 27 FL 2.6 Gels 8/10/14 CL- 31000 FC 1/2 SOL 11.8 SD 0.20 OIL 1.0/84.9 MBT 1.0 pH 9.6 Ca+ 60 Alk 0.30 MWD SUMMARY INTERVAL 10450 TO 11761 TOOLS Gamma and motor with 1.15° bend GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 650 @ 11722 10 @ 10814 164.9 TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 122114 @ 11722 1547 @ 10933 31386.9 CONNECTION GAS HIGH 28 ETHANE (C-2) 760 @ 11725 0 @ 10808 141.3 AVG 4 PROPANE (C-3) 97 @ 11724 0 @ 10925 17.4 CURRENT 0 BUTANE (C-4) 46 @ 11036 0 @ 10996 2.6 CURRENT BACKGROUND/AVG 13 / 164 PENTANE (C-5) 16 @ 11036 0 @ 10996 0.6 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyoneck (TY91-2) PRESENT LITHOLOGY @ 11761’ = Sand 40%; Tuffaceous sandstone 40%; Conglomeritic sandstone 10%; Tuff 10%. DAILY ACTIVITY SUMMARY Drill from 10795 to 11115. Drill from 1115 to 11394’, drill from 11394’ to 11670’; drill from 11670’ to 11761’; POOH from 11761’ to 10715’; Trip back to bottom; currently @ 11758’ and preparing to circulate and return to drilling. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 04, 2015 DEPTH 12660 PRESENT OPERATION Circulating Sweep TIME 23:59 YESTERDAY 11761 24 HOUR FOOTAGE 899 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12124.34 0.43 359.78 10438.37 12186.88 0.44 341.34 10500.91 12248.94 0.70 260.89 10562.96 12310.61 1.13 265.29 10624.63 12372.23 0.90 244.07 10686.24 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 6.125 HDBS MM55 12487636 5x11 10450 12660 2210 32.2 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 1025.7 @ 11852 1.7 @ 12100 77.1 106.66 FT/HR SURFACE TORQUE 18828 @ 12163 15142 @ 12375 17045.0 18099.71 FT-LBS WEIGHT ON BIT 40 @ 11763 0 @ 11779 5.8 7.210 KLBS ROTARY RPM 59 @ 12357 54 @ 11761 55.8 57.17 RPM PUMP PRESSURE 3244 @ 12606 2461 @ 11795 2927.6 3053.88 PSI DRILLING MUD REPORT DEPTH 12592/10908 MW 11.3 VIS 59 PV 21 YP 26 FL 2.2 Gels 8/11/15 CL- 33000 FC 1/2 SOL 11.8 SD 0.10 OIL 3.0/82.8 MBT 1.8 pH 9.0 Ca+ 60 Alk 0.25 MWD SUMMARY INTERVAL 10450 TO 12660 TOOLS Gamma and motor with 1.15° bend GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 274 @ 11885 8 @ 11784 93.9 TRIP GAS 198 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 50707 @ 12321 1470 @ 11782 16462.7 CONNECTION GAS HIGH 0 ETHANE (C-2) 281 @ 12561 0 @ 11969 86.2 AVG 0 PROPANE (C-3) 48 @ 12409 0 @ 11792 13.5 CURRENT 0 BUTANE (C-4) 50 @ 11886 0 @ 12035 3.8 CURRENT BACKGROUND/AVG 140 / 94 PENTANE (C-5) 23 @ 11886 0 @ 11815 0.7 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY 12660’ = Sand 30%; Tuffaceous Siltstone 30%; Conglomeritic sandstone 30%; Carbonaceous shale 10%. DAILY ACTIVITY SUMMARY : Run in hole from 10700’ to 11761’ with no issues- correct displacement; drill from 11761’ to 11974’. Drill from 11794 to 12409’; circulate bottoms up; stand back one stand and blow down top drive turn elevator. POOH from 12409’-11700’; Run in hole from 11700’ to 12407’ (hole took proper displacement) drilling from 12409 to 12660’; Circulate sweep out; drill ahead from 12660’ CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 05, 2015 DEPTH 12940 PRESENT OPERATION Tripping to bottom TIME 23:59 YESTERDAY 12660 24 HOUR FOOTAGE 280 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12744.91 0.57 233.10 11058.82 12806.95 1.02 246.64 11120.85 12868.91 0.89 246.87 11182.80 12901.73 1.05 246.24 11215.62 12940 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 6.125 HDBS MM55 12487636 5x11 10450 12940 2490 39.9 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 183.3 @ 12787 4.4 @ 12853 57.0 28.13 FT/HR SURFACE TORQUE 18780 @ 12937 16339 @ 12923 18044.7 18370.88 FT-LBS WEIGHT ON BIT 10 @ 12769 1 @ 12939 6.1 2.05 KLBS ROTARY RPM 62 @ 12812 55 @ 12928 59.8 55.99 RPM PUMP PRESSURE 3320 @ 12794 2733 @ 12923 3033.9 2851.37 PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.3 VIS 53 PV 17 YP 27 FL 2.4 Gels 8/10/14 CL- 31500 FC 1/2 SOL 12.8 SD 0.10 OIL 2.0/82.9 MBT 1.8 pH 9.9 Ca+ 40 Alk 0.50 MWD SUMMARY INTERVAL 10450 TO 12940 TOOLS Gamma and motor with 1.15° bend GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 280 @ 12837 28 @ 12771 91.6 TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 44519 @ 12837 3758 @ 12771 13244.4 CONNECTION GAS HIGH 239 ETHANE (C-2) 264 @ 12848 11 @ 12832 87.6 AVG 99 PROPANE (C-3) 39 @ 12851 0 @ 12667 9.3 CURRENT 0 BUTANE (C-4) 19 @ 12738 0 @ 12667 4.8 CURRENT BACKGROUND/AVG 5 / 92 PENTANE (C-5) 16 @ 12738 0 @ 12667 4.3 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone 40%. DAILY ACTIVITY SUMMARY Drill from 12660’ to 12810’. Troubleshoot MWD tool. Drill from 12810’ to12816’. Drill form 12816’ to 12940’. Circulate bottoms up @ well TD. Max Gas 75Units survey flow check, no flow, POOH on Elevators from 12940’to 12588’ tight hole, pump from 12588 to 11705’; pull on elevators 11705’ top 10431’. Circulate 1.5 bottoms up with 50% increase in cuttings; slip and cut drill line; Run in hole from 10440 to 11807’ run in hole from11807 to 12928’; 12 feet of hole fill; circulate . Prep for tandem sweep. CANRIG PERSONNEL ON BOARD 6 DAILY COST $3745.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 06, 2015 DEPTH 12940 PRESENT OPERATION Laying down BHA TIME 23:59 YESTERDAY 12660 24 HOUR FOOTAGE 280 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12744.91 0.57 233.10 11058.82 12806.95 1.02 246.64 11120.85 12868.91 0.89 246.87 11182.80 12901.73 1.05 246.24 11215.62 12940 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 5 6.125 HDBS MM55 12487636 5x11 10450 12940 2490 39.9 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.3 VIS 52 PV 18 YP 26 FL 2.4 Gels 8/10/13 CL- 30000 FC 1/2 SOL 12.8 SD 0.10 OIL 1.0/84 MBT 2.0 pH 10.0 Ca+ 40 Alk 0.50 MWD SUMMARY INTERVAL 10450 TO 12940 TOOLS Gamma and motor with 1.15° bend GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 547 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0/0 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone 40%. DAILY ACTIVITY SUMMARY Circulate 1.5 bottoms up with 50% increase in cuttings; slip and cut drill line; Run in hole from 10440 to 11807’ run in hole from11807 to 12928’; 12 feet of hole fill; wash down from 12928’ to 12940’circulate and pump tandem sweep and circulate out; POOH from 12940’ to 11499’. POOH on elevators from 11499’ hole fill good; flow check well; air out pump # 1; pump 25 barrel hi vis sweep; max gas back 64 units; sweep back 20 barrels early with 50% increase in cuttings; blow down top drive; POOH on elevators 10368’ to 6407’ pump Strata Kleen sweep; max gas back 116 unit, back 46 barrels early, no increase in cuttings; blow down top drive; continue to POOH 6407’ to 4294’ hole fill good. POOH from 4294’ to 116’ (hole took 32 barrels over displacement;) lay down directional tools; down load data; lay down TM collar; PWD collar; PWD; slim phase; DM collar; and mud motor. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3345.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 07, 2015 DEPTH 12940 PRESENT OPERATION Tripping in hole for MAD pass TIME 23:59 YESTERDAY 12940 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12744.91 0.57 233.10 11058.82 12806.95 1.02 246.64 11120.85 12868.91 0.89 246.87 11182.80 12901.73 1.05 246.24 11215.62 12940 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.3 VIS 53 PV 17 YP 26 FL 2.2 Gels 7/10/14 CL- 31000 FC 1/2 SOL 12.8 SD 0.10 OIL 1.0/83.9 MBT 2.0 pH 9.7 Ca+ 40 Alk 0.40 MWD SUMMARY INTERVAL 12940 TO 12940 TOOLS MAD pass- Quad Combo tools GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 8 / 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone 40%. DAILY ACTIVITY SUMMARY Drain stack; remove wear bushing; install test plug; rig up test equipment; and fill BOP’s with water/perform shell test; Test #1 upper, Mez. kill valve; dart valve; Hydrill I-BOP and CM10, 11, 12 valves; Test #2 TIW, Manual I-BOP; choke and kill HCR valves; Test #3 inside kill and choke valves; Test#4 Lower pipe rams; Test # 5 Hydrill Bag low 250psi; high 2500psi’ Koomey draw down test stating 3100psi; After closures system pressure1425psi, 23 seconds to re-gain 200psi and 101 seconds to re-gain full system pressure. Test 6# Blind rams. Finish blind ram test; rig down test equipment; and blow down choke manifold, choke line, kill line; and top drive; install wear ring and clear rig floor; PJSM with e-line; rig up e-line; make up e-line tool; flow check well no flow; test e-line quad combo tool; bad test; change out EDTC section; re-test; test good; load RA source; Run in hole with e-line from surface to 2000’. Continue running in hole with e-line from 2000 to 10300 and check WT before running into open hole, continue to Run in hole from10300 to 11275’ – e-line string weight to high; Pull out of hole from 11275 to 200’. PJSM on rigging down wire line; Pull out of hole from 200’ to surface remove radioactive source and rig down e=line tools. Rig down Schlumberger wire line tools and equipment; pick up and make up directional tools; warm up MWD tools; down load data; load radioactive sources; run in hole from 135’ to 629’; continue to run in hole from 629’ with bit depth at midnight 813’. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2025.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 08, 2015 DEPTH 12940 PRESENT OPERATION Making MAD pass TIME 23:59 YESTERDAY 12940 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12901.73 1.05 246.24 11215.62 12940.00 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED MAD pass 6.125 HDBS MM65 PDC 5x11 12940 12940 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.35 VIS 52 PV 17 YP 26 FL 2.8 Gels 8/10/13 CL- 30500 FC 1/2 SOL 13.3 SD 0.10 OIL 1.0/83.5 MBT 23.3 pH 10.2 Ca+ 40 Alk 0.60 MWD SUMMARY INTERVAL 12940 TO 12940 TOOLS MAD pass Quad Combo tools GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 1041 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 70 / 48 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Continue to run in hole from 629’ to 6213’. Continue to run in on elevators from 6213’ to 6399’; fill pipe, obtain torque value 9.2K ; blow down top drive; continue to run in hole on elevators from 6399’ to 10430 filling pipe every 2500’; fill pipe and obtain torque value 13.5K; blow down top drive; continue to run in on elevators from 10430’ to 12775’ with tight spots at 11385’ and 12550’; set down 20K and worked through 12775’ set down 25k worked pipe; over pull 50K; kelly up and break circulation at 125 GPM; Pressure showed signs of pack off, staged up pump and RPM and worked pipe to 12785’. Circulate bottoms up and got back 1041 units of gas; wash down 12775 to 12940’ circulate bottoms up, gas back 399 units; MAD pass from 12940’ to 12785’ bit depth at midnight. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2025.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 09, 2015 DEPTH 12940 PRESENT OPERATION Making MAD pass TIME 23:59 YESTERDAY 12940 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12901.73 1.05 246.24 11215.62 12940.00 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED MAD pass 6.125 HDBS MM65 PDC 5x11 12940 12940 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.25 VIS 46 PV 16 YP 25 FL 2.4 Gels 6/8/11 CL- 29000 FC 1/2 SOL 13.1 SD 0.10 OIL 1.5/83.3 MBT 2.0 pH 10.2 Ca+ 40 Alk 0.60 MWD SUMMARY INTERVAL 12940 TO 12940 TOOLS MAD pass Quad Combo tools GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 3 / 58 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Continue to MAD pass from 12292’ (midnight depth) to 11793’; continue to MAD pass from11793’ to 11297’; continue to MAD pass from 11297 to 10920; continue to MAD pass without pumps due to pump pressure drop from 10920’ to 10699’(midnight depth.) HIgh gas for today was 866 units at 14:15 pm at bit depth of 11604'. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2025.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov10, 2015 DEPTH 12940 PRESENT OPERATION Tripping in with mill TIME 23:59 YESTERDAY 12940 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and 7 5/8"@10447' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12901.73 1.05 246.24 11215.62 12940.00 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6.125 HDBS MM65 PDC 5x11 12940 12940 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.35 VIS 48 PV 15 YP 24 FL 2.3 Gels 6/8/10 CL- 30000 FC 1/2 SOL 13.5 SD 0.10 OIL 1.5/82.8 MBT 2.0 pH 10.2 Ca+ 40 Alk 0.60 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 8 / 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Continue MAD pass from 10700’ to 10368’. Pull out of hole from 10368’ to 7507’’. Perform rig service; grease crown, blocks, TDS, draw works, and the iron rough neck. Continue to pull out of the hole from 7507’ to 6448’; stopped to load carbide bomb; retested surface equipment no bleed off, call from town made change of plan to pull out of hole and lay down BHA; blow down top drive; PJSM with crew on M.O.C.; continue to pull out on elevators; from 6448’ to 4631’, found hole in pipe in joint number 130; change out joint and continue out of hole to 74’; PJSM with MWD, directional and rig crew; unload source and download tools; lay down BHA; clear and clean rig floor and ready for picking up BHA; PJSM with rig crew and directional driller, make up bit; bit sub, stab T/NM collar and run in hole from 71’ to 6400’; ( Midnight depth.) CANRIG PERSONNEL ON BOARD 2 DAILY COST $2025.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 11, 2015 DEPTH 12940 PRESENT OPERATION Tripping out TIME 23:59 YESTERDAY 12940 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and op of 7 5/8" liner @ 6433' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12901.73 1.05 246.24 11215.62 12940.00 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6.125 HDBS MM65 PDC 5x11 12940 12940 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.40 VIS 45 PV 14 YP 24 FL 2.2 Gels 6/8/11 CL- 32500 FC 1/2 SOL 13.7 SD 0.10 OIL 1.3/82.7 MBT 2.5 pH 10.2 Ca+ 40 Alk 0.80 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 2 / 67 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Continue to run in hole from 6400 to 11405’; Wash and ream from 11405’ to 11415. Wash and ream as needed from 11415 to 11924’ (@ 11458 circulate; @ 11509’ ream; @ 11695’ circulate; @ 11730’ to 11735’ ream; @ 11868’ circulate.) Wash and ream from 11924’ to 11986’; circulate bottoms up with max gas 748 units; run in hole on elevators from 11924’ to 12118; wash and ream from 12118’ to 12889’. Wash and ream from 12889’ back up to 11924’; wash and ream from 11924’ to 12940’; pump high vis sweep and circulate out; POOH from 12940’ to 10958‘ (Midnight Depth.) CANRIG PERSONNEL ON BOARD 2 DAILY COST $2025.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 12, 2015 DEPTH 12940 PRESENT OPERATION Tripping out TIME 23:59 YESTERDAY 12940 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and op of 7 5/8" liner @ 6433' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12901.73 1.05 246.24 11215.62 12940.00 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6.125 HDBS MM65 PDC 5x11 12940 12940 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.40 VIS 47 PV 14 YP 23 FL 2.2 Gels 5/7/10 CL- 33000 FC 1/2 SOL 13.7 SD 0.10 OIL 1.3/82.7 MBT 2.5 pH 10.2 Ca+ 40 Alk 0.60 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 518 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 42 / 30 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Wash and ream from 12889’ back up to 11924’; wash and ream from 11924’ to 12940’; pump high vis sweep and circulate out; POOH from 12940’ to 10393’ and perform rig service; pull out of hole from 10393’ to 4800’ hole fill – 13.49 over calculated displacement. Continue to pull out of hole on elevators from 4800 to 2768’; lay down crossovers and mill; clean rig floor and get rig floor ready to trip back in hole; hole fill =14.88. Run in hole on elevators from 2768’ to 10394; fill pipe every 2500’ ; change out top joint on stand # 88 and replace; continue to run in hole; flow check well; install floor valve; hang block; slip and cut drill line; cut 152’ of drill line; reset com; re set rig smart; rig service; grease top drive, draw works, crown, and check fluid levels in floor motor; torque drive line bolts; run in hole from 10394’ to 11574’; hole fill = 5.66 barrels. Run in hole from 11574’ to 12844’ with well taking proper displacement; wash and ream from 12844’ to 12040’; pump 19.6 barrels of vis 120 high vis sweep and circulate out with 50% increase in cuttings and 5 barrels early - trip gas of 518 units; Pull out of hole from 12940’ to 12931’(midnight depth). High gas = Trip gas of 518 units CANRIG PERSONNEL ON BOARD 2 DAILY COST $2025.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 13, 2015 DEPTH 12940 PRESENT OPERATION Tripping out TIME 23:59 YESTERDAY 12940 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and op of 7 5/8" liner @ 6433' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12901.73 1.05 246.24 11215.62 12940.00 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 6.125 HDBS MM65 PDC 5x11 12940 12940 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.60 VIS 48 PV 16 YP 25 FL 2.1 Gels 6/8/11 CL- 33000 FC 1/2 SOL 14.4 SD 0.10 OIL 1.0/82.2 MBT 2.5 pH 10.1 Ca+ 40 Alk 0.60 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 192 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 0/ 12 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Continue to pull out of hole from 12931’ to 11298’; run in hole from 11298’ to 12940’ 20’ of fill with hole fill 0.4 bbls over calculated; pump high vis sweep (19 bbls and134 vis) and circulate out. Condition mud and circulate; continue to weight up to 11.6ppg @7:15 pump 64.48bbls, black pill 12ppg and spot in open hole; flow check; no flow; blow down top drive; pull out of ole on elevators from 12940’ to 10427’ circulate bottoms up@shoe100% return; continue to pull out on elevators from 10427’ to 6396’; pump 22bbls Strata-Kleen sweep- returned on time 10% return; flow check well; stage equipment to lay down drill pipe; clean rig floor; pump 14 bbls dry job @ 13.6 ppg; pull out of hole laying down excess drill pipe starting with stand #94 from 6396’ to 6126’; continue laying down excess drill pipe from 6126’ to 3831’ ( 82 joints laid down); pull out of hole from 3831’ to 270’ (midnight depth) Max gas was the bottoms up at 5:10am @12940' brought back 192 units gas. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2025.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough DAILY WELLSITE REPORT CLU05RD REPORT FOR Hilcorp Alaska, LLC DATE Nov 14, 2015 DEPTH 12940 PRESENT OPERATION Circulating TIME 23:59 YESTERDAY 12940 24 HOUR FOOTAGE 0 CASING INFORMATION 9.625"@6544' and top of 7 5/8" liner @ 6433' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 12901.73 1.05 246.24 11215.62 12940.00 1.05 246.24 11253.88 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 12940/11254 MW 11.45 VIS 49 PV 15 YP 26 FL 2.1 Gels 5/8/11 CL- 33000 FC 1/2 SOL 13.8 SD 0.10 OIL 1.0/82.8 MBT 2.5 pH 10.0 Ca+ 40 Alk 0.60 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 9 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 6/ 1 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Deep Tyonek PRESENT LITHOLOGY @ 12940' = Conglomeritic Sandstone 10%; Sand 20%; Sandstone 10%; Tuff 10%; Tuffaceous siltstone 10%; Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Lay down jars, flex collars, bit; clean and clear rig floor; remove excess cross over subs; rig up Weatherford power tongs, elevators, air slips and hydraulic lines; lay out tubbing on pipe racks near cat walk; PJSM with crew and Weatherford casing hands; pick up and make up float equipment and test float equipment; run in hole from 165’ to 777’. ` Continue to run in hole with casing from777’ to 2642’; clean and clear rig floor; stage and ready equipment for picking up hanger; PJSM with Baker on picking up Seal Bore Ext; make up same with Weatherford Tong; Run in hole ; set tongs on floor; pick up liner hanger; fix 2 3/8 thread; make up and run in hole from 2642’ to 2682’; mix and pour in PAL-MIX; circulate 1.5 liner volume; stage pumps up continue circulating and dust up from 11.3ppg to 11.6 ppg; continue to trip in on elevators with drill pipe from 2682’ to 6401’ condition and circulate mud stage up pumps to 6 BPM; circulate bottoms up; run in hole from 6401’ to 10370’( midnight depth); circulating surface to surface; max gas to surface 9 units CANRIG PERSONNEL ON BOARD 2 DAILY COST $2025.00 REPORT BY Donna New