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Home My WebLink About220-034MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, October 16, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC I-35 MILNE PT UNIT I-35 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/16/2024 I-35 50-029-23675-00-00 220-034-0 W SPT 3813 2200340 1500 504 505 502 503 4YRTST P Brian Bixby 8/19/2024 Monobore Completion 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT I-35 Inspection Date: Tubing OA Packer Depth 342 1727 1660 1643IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB240820131555 BBL Pumped:1.8 BBL Returned:1.8 Wednesday, October 16, 2024 Page 1 of 1 9 9 9 9 99 999 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.10.16 10:42:29 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 3/03/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-35 (PTD 220-034) PERF 2/02/2022 Please include current contact information if different from above. 220-034 T36386 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.03.04 09:26:08 -09'00' 2SHUDWLRQV $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 3XOO7XELQJ 2SHUDWLRQVVKXWGRZQ 3HUIRUPHG 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH $OWHU&DVLQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HSDLU:HOO 5HHQWHU6XVS:HOO 2WKHUBBBBBBBBBBBBBBBBBBBBBB 'HYHORSPHQW ([SORUDWRU\ 6WUDWLJUDSKLF 6HUYLFH $3,1XPEHU 3URSHUW\'HVLJQDWLRQ/HDVH1XPEHU 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>ŽǁĞƌŽŵƉůĞƚŝŽŶ ϱ ϰ͕ϴϮϴ͛ ϳ͟ǆϵͲϱͬϴ͟^>yW>dWǁͬϳ͘ϯϴ͟^ĞĂůŽƌĞʹϯ͕ϴϭϭ͛ds ϲ͘ϭϴϬ͟ ϲ ϭϮ͕ϴϲϯ͛ ^ŚŽĞŽƚƚŽŵΛϭϮ͕ϴϲϱ͛D ϯ͘ϵϳϬ͟ KWE,K>ͬDEdd/> ϰϮΗ цϮϳϬĨƚϯ ϭϮͲϭͬϰΗ ^ƚŐϭʹ>ĞĂĚϯϳϬƐǆͬdĂŝůϯϵϴƐǆ ^ƚŐϮʹ>ĞĂĚϰϱϰƐǆͬdĂŝůϮϳϬƐǆͲϮϬϬďďůƐƌĞƚƵƌŶĞĚƚŽƐƵƌĨĂĐĞ ϴͲϭͬϮ͟ ĞŵĞŶƚůĞƐƐ/ŶũĞĐƚŝŽŶ>ŝŶĞƌŝŶϴͲϭͬϮ͟ŚŽůĞ t>>/E>/Ed/KEd/> <KWΛϵϱϯ͛ ,ŽůĞŶŐůĞΛyEсϲϲΣ ,ŽůĞŶŐůĞΛ>ŝŶĞƌdŽƉсϴϱΣ DĂǆ,ŽůĞŶŐůĞсϵϲΣ dZΘt>>, dƌĞĞ ĂŵĞƌŽŶϯϭͬϴΗϱDǁͬϯͲϭͬϴ͟ϱDĂŵĞƌŽŶtŝŶŐ tĞůůŚĞĂĚ ĂŵĞƌŽŶϭϭ͟ϱ<ǆƐůŝƉůŽĐŬďŽƚƚŽŵǁͬ;ϮͿϮͲϭͬϭϲ͟ϱ<ŽƵƚƐ 'EZ>t>>/E&K W/η͗ϱϬͲϬϮϵͲϮϯϲϳϱͲϬϬͲϬϬ ŽŵƉůĞƚĞĚďǇ/ŶŶŽǀĂƚŝŽŶ͗ϱͬϮϬͬϮϬϮϬ ĞƉƚŚ D ĞƉƚŚ ds/ͬ^ǁĞůůWĂĐŬĞƌĞƚĂŝů ϱ͕ϬϮϬ͛ ϯ͕ϴϮϲ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϱ͕Ϯϰϱ͛ ϯ͕ϴϮϯ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϱ͕ϯϰϴ͛ ϯ͕ϴϮϮ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϱ͕ϵϴϱ͛ ϯ͕ϴϮϬ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϲ͕Ϯϱϯ͛ ϯ͕ϴϮϬ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϲ͕ϳϲϳ͛ ϯ͕ϴϯϯ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϳ͕Ϭϳϲ͛ ϯ͕ϴϯϭ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϴ͕ϬϬϮ͛ ϯ͕ϴϴϳ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϴ͕ϭϰϰ͛ ϯ͕ϴϵϱ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϴ͕ϱϯϭ͛ ϯ͕ϵϬϴ͛ 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W/η͗ϱϬͲϬϮϵͲϮϯϲϳϱͲϬϬͲϬϬ ŽŵƉůĞƚĞĚďǇ/ŶŶŽǀĂƚŝŽŶ͗ϱͬϮϬͬϮϬϮϬ ĞƉƚŚ D ĞƉƚŚ ds/ͬ^ǁĞůůWĂĐŬĞƌĞƚĂŝů ϱ͕ϬϮϬ͛ ϯ͕ϴϮϲ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϱ͕Ϯϰϱ͛ ϯ͕ϴϮϯ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϱ͕ϯϰϴ͛ ϯ͕ϴϮϮ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϱ͕ϵϴϱ͛ ϯ͕ϴϮϬ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϲ͕Ϯϱϯ͛ ϯ͕ϴϮϬ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϲ͕ϳϲϳ͛ ϯ͕ϴϯϯ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϳ͕Ϭϳϲ͛ ϯ͕ϴϯϭ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϴ͕ϬϬϮ͛ ϯ͕ϴϴϳ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϴ͕ϭϰϰ͛ ϯ͕ϴϵϱ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϴ͕ϱϯϭ͛ ϯ͕ϵϬϴ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϴ͕ϴϯϴ͛ ϯ͕ϵϭϴ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϴ͕ϵϯϴ͛ ϯ͕ϵϮϮ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϵ͕ϯϮϮ͛ ϯ͕ϵϬϬ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϵ͕ϱϴϯ͛ ϯ͕ϴϵϬ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϵ͕ϵϴϱ͛ ϯ͕ϴϵϬ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϭϬ͕ϯϬϬ͛ ϯ͕ϴϵϳ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϭϬ͕ϴϭϵ͛ ϯ͕ϵϭϱ͛ dĞŶĚĞŬĂtĂƚĞƌ^ǁĞůůWĂĐŬĞƌ ϭϭ͕Ϭϴϱ͛ ϯ͕ϵϮϬ͛ dĞŶĚĞŬĂͲ/ǁͬϮϱϬ>ŵĞƐŚ͕^ůŝĚŝŶŐ^ůĞĞǀĞϭϯ͘ϱηďǆƉϲϮϱtĞĚŐĞ ϭϭ͕ϱϱϴ͛ ϯ͕ϵϮϴ͛ 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Thanks, Sam From: Tom Fouts <tfouts@hilcorp.com> Sent: Tuesday, January 11, 2022 1:25 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: David Gorm <dgorm@hilcorp.com>; David Haakinson <dhaakinson@hilcorp.com> Subject: Sundry Withdrawal Request for MPU I‐35, sundry# 321‐359 Samantha, Hilcorp Alaska LLC respectfully requests the withdrawal of Sundry: 321‐359 for MPU I‐35 liner perforation. We will be submitting a new sundry request for this well. Regards, Tom Fouts | Senior Ops/ Reg Tech Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907) 777‐8398 Mobile: (907) 351‐5749 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, 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. 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. 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): 13,130'N/A Casing Collapse Conductor N/A Surface 4,760psi Surface 3,090psi Liner 8,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: Operations Manager Contact Email:dhaakinson@hilcorp.com Contact Phone: 777-8343 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 7/30/221 3-1/2" Perforation Depth MD (ft): See Schematic MILNE PT UNIT I-35 C.O. 477.05 See Schematic and N/A See Schematic and N/A 186'20" 12,865' 5,750psi See Schematic 9.3# / L-80 / EUE 8rd 9-5/8" 4-1/2" 1,968' 8,037' 3,016'9-5/8" 4,836' MD N/A 5,009'3,824' 6,870psi 9,020psi 1,972' 3,959' 1,993' 4,002'1,194 N/A MILNE POINT / SCHRADER BLUFF OIL 186'186' TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025906 & ADL315848 220-034 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23675-00-00 Hilcorp Alaska LLC Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 4,002' 13,130' David Haakinson COMMISSION USE ONLY Authorized Name: Authorized Signature: Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Chad Helgeson (1517) 2021.07.20 15:33:29 - 08'00' By Meredith Guhl at 8:07 am, Jul 21, 2021 321-359 SFD 7/21/2021 DSR-7/21/21 10-404 MGR22JUL21 dts 7/23/2021 JLC 7/23/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.23 09:41:55 -08'00' RBDMS HEW 7/26/2021 CT Perforate Well: MPU I-35 Date: 7/20/2021 Well Name:MPU I-35 API Number:50-029-23675-00-00 Current Status:Injector - Online Pad:I-Pad Estimated Start Date:July 30th, 2021 Rig:CTU 6 Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:220-034 First Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 AFE Number:Job Type:Perforate Current Bottom Hole Pressure: 1,561 psi @ 3,669’ TVD Downhole Gauge 7/17/21 |8.18 PPGE Max Anticipated Pressure:1,561 psi @ 3,669’ TVD Pressure to continue fall-off MPSP:1,194 psi (0.1psi/ft gas gradient) Max Deviation:95.8° @ 9,231’ MD Max Dogleg:9.5°/100ft @ 4,979’ MD Min ID:2.75” ID @ 4,064’ MD XN Nipple Brief Well Summary: MPU I-35 is a Schrader Bluff NB sand injector that was drilled and completed in 2020. The well was completed with ICD sleeves with auto-trip devices. In late 2020, polymer injection was started on the well, but the injector began to have problems with tripping of the AICDs. This was due to the increased dP caused by the higher viscosity of the water. The AICDs trip in a rapid reaction and has ultimately limited the maximum injection rate to approximately 1,500 BPD as opposed to a possible 3,500 BPD. Objective: x Rig up coiled tubing and TCP to perforate solid liner to bypass ICDs o Targeting a 2,000 BWPD injection increase to result in ~200 BOPD increase in I-36. x Plan is to use Ballistic Time-Delay Fuse (BTDF) to initiate an on-time delay system to perforate seven intervals on a single CT run by moving the gun-string between the shots. This will require open-hole deployment of perf guns. Notes Regarding the Well & Design x IA was pressure tested to 2,500 psi on 8/22/2020. x Well has only been entered to XN Nipple on slickline. x Currently injecting 1,700 BPD @ 300 psi. Coil Tubing Perforating Procedure 1. MIRU Coiled Tubing Unit with 2” coiled tubing and spot ancillary equipment. 2. Pressure test BOPE to 3,500 psi Hi 250 Low, 10 min each test. a. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. b. No AOGCC notification required. c. Record BOPE test results on 10-424 form. d. If within the standard 7-day test BOPE test period for Milne Point, a full body test and function test of the rams is sufficient to meet weekly BOPE test requirement. 3. Document shut in tubing pressure. Bleed gas head off to tanks. CT Perforate Well: MPU I-35 Date: 7/20/2021 4. MU GR/CCL and drift assembly w/ circulating sub and 100’ of 2.3” OD spent perf guns. 5. Perform TIW valve stab drill with CT crew. 6. RIH to ~200’ past ICD #8 @ 11,085’ MD or lock-up. Bottom Perf Interval planned for 11,150-11,155’ MD. 7. Flag pipe for correlation. 8. Contact Engineer to review depth and planned perforation depths. 9. POOH to lateral KOP @ 5,000’ MD (3,826’ TVD) and confirm well is dead. Bleed any gas head pressure to return tank and document pressures for 15 minutes. 10. Circulate in KWF if necessary. Contact Engineer to confirm calculations for KWF. a. Current estimates are that the well can be killed with source water. 11. At surface, prepare for deployment of TCP guns. 12. Confirm well is dead. Bleed any pressure off to return tank. Kill well as needed. Maintain continuous hole fill taking returns to tank until lubricator connection is reestablished. 13. Monitor tankage and document with trip sheet, managing fluids following coil displacement. 14. Pickup safety joint and TIW valve and space out before MU guns. 15. Begin makeup of TCP guns and deployment bars per the outlined BHA below. Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. a.Note: This will require two perforating runs. b.Note: Gun lengths need to be verified and confirmed post drift and tie-in run with remaining BHA components. Contact Engineer to review BHA components. c. Guns are 6 SPF, 60-degree phasing. Note: Well temperature is estimated at 68 deg F. Delay fuses are temperature dependent and nominal burn time is estimated at 7.84 minutes per delay fuse at this temperature. Minimum time before picking up BHA above 5,020’ MD is after activating firing head is 48 minutes to ensure completion of maximum burn time of all delay fuses in the string.Do not pick up above LTP @ 4,850’ MD before 50 minutes after activation to avoid perforating tubing. 16. Tie into flagged CT depth. Space out for bottom shot. 17. Once on depth. Confirm plan of operations and firing sequence with coil crew. Equipment (RUN 1) Length (ft) Top Depth (MD) Bottom Depth (MD) Top Depth (TVD) Bottom Depth (TVD) Sand Firing Head 3.65 Spacer 7 Perf Gun 10 11150 11160 3919 3919 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 10350 10360 3897 3897 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 9610 9620 3888 3888 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 8860 8870 3918 3918 Schrader NB Sand Total Length 89.65 800' Pick Up. Estimate 11 minutes travel time. 750' Pick Up. Estimate 10 minutes travel time. 740' Pick Up. Estimate 10 minutes travel time. Stab injector. RIH. CT Perforate Well: MPU I-35 Date: 7/20/2021 18. Pre-plan stop depths to account for space out of guns in BHA. Send to Engineer prior to dropping 1/2” activation ball. 19. Launch ½” ball to activate firing head. a.Note: Once ½” ball is launched and firing head is activated, there is no ability to stop the delay fuses from continuing. Indication of first zone will occur when shift of firing head is observed. b. A portable shot detection system needs to be used to detect gun activation. 20. Continue to observe weight indicator and pressure for other signs of gun activation. 21. Begin working up-hole for additional perforation depths. 22.If no indication is observed for a zone; stop and do not pick up past top perf depth of 8,860’ MD until full duration of delay period has elapsed of 47 minutes from time of firing head activation. 23. POOH to KOP @ 5,000’ MD and stop to confirm that the well is dead. If any pressure builds, contact engineer and prepare to circulate KWF. 24. Continue to POOH and stop at surface to reconfirm well dead and hole full. 25. Complete No Flow Test for 15 minutes prior to pulling BHA through BOP stack. 26. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 27. Lay-down spent TCP guns and deployment bar sections. Repeat steps 10-14. 28. Begin makeup of second set of TCP guns and deployment bars per the outlined BHA below. Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. a.Note: Gun lengths need to be verified and confirmed post drift and tie-in run with remaining BHA components. Contact Engineer to review BHA components. b. Guns are 6 SPF, 60-degree phasing. Note: Well temperature is estimated at 68 deg F. Delay fuses are temperature dependent and nominal burn time is estimated at 7.84 minutes per delay fuse at this temperature. Minimum time before picking up BHA above 5,020’ MD is after activating firing head is 55 minutes to ensure completion of maximum burn time of all delay fuses in the string.Do not pick up above LTP @ 4,850’ MD before 60 minutes after activation to avoid perforating tubing. Equipment (RUN 2) Length (ft) Top Depth (MD) Bottom Depth (MD) Top Depth (TVD) Bottom Depth (TVD) Sand Firing Head 3.65 Spacer 7 Perf Gun 10 8170 8180 3895 3895 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 6800 6810 3831 3831 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 6010 6020 3819 3819 Schrader NB Sand Deployment Bar 6.5 Deployment Bar 6.5 Perf Gun 10 5265 5275 3821 3821 Schrader NB Sand Total Length 96.15 1370' Pick Up. Estimate 18 minutes travel time. 790' Pick Up. Estimate 11 minutes travel time. 745' Pick Up. Estimate 10 minutes travel time. Assure ability to circulate KWF across top of well if taking fluids. CT Perforate Well: MPU I-35 Date: 7/20/2021 29. Tie into flagged CT depth. Space out for bottom shot. 30. Once on depth. Confirm plan of operations and firing sequence with coil crew. 31. Pre-plan stop depths to account for space out of guns in BHA. Send to Engineer prior to dropping 1/2” activation ball. 32. Launch ½” ball to activate firing head. a.Note: Once ½” ball is launched and firing head is activated, there is no ability to stop the delay fuses from continuing. Indication of first zone will occur when shift of firing head is observed. b. A portable shot detection system needs to be used to detect gun activation. 33. Continue to observe weight indicator and pressure for other signs of gun activation. 34. Begin working up-hole for additional perforation depths. 35.If no indication is observed for a zone; stop and do not pick up past top perf depth of 5,265’ MD until full duration of delay period has elapsed of 55 minutes from time of firing head activation. 36. POOH to KOP @ 5,450’ MD and stop to confirm that the well is dead. If any pressure builds, contact engineer and prepare to circulate KWF. 37. Continue to POOH and stop at surface to reconfirm well dead and hole full. 38. Complete No Flow Test for 15 minutes prior to pulling BHA through BOP stack. 39. Review well control steps with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 40. Lay-down spent TCP guns and deployment bar sections. 41. RDMO CTU. 42. Do not freeze protect well. Bring well on injection. Attachments: 1. Current schematic 2. Proposed schematic 3. Coiled Tubing BOP Schematic 4. Equipment Layout Diagram 5. Standing Orders for Open Hole Well Control during Perf Gun Deployment Stab injector. RIH. Assure ability to circulate KWF across top of well if taking fluids. _____________________________________________________________________________________ Revised By: TDF 7/19/2021 SCHEMATIC Milne Point Unit Well: MPU I-35 PTD: 220-034 API: 50-029-23675-00-00 TD =13,130’(MD) / TD =4,002(TVD) 20” Orig. KB Elev.: 60.3’/ GL Elev.: 33.6’ 3-1/2”2 9-5/8 ” 1 3&4 6 See ICD & Swell Packer Detail PBTD =13,130’ (MD) / PBTD =4,002’(TVD) 9-5/8” ‘ES’ Cementer @ 1,933’ MD 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-56 / Weld N/A Surface 186’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 1,993’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 1,993’ 5,009’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 4,828’ 12,865’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 4,836’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,001’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,064’ Brace XN Landing Nipple w/ 2.750” Packing Bore 2.813” 3 4,825’ 8.25” No Go Locater Sub (1.45’ off No-go) 6.170” 4 4,826’ Bullet Seals – Mule Shoe bottom @ 4,836’ MD 6.170” Lower Completion 5 4,828’ 7” x 9-5/8” SLZXP LTP w/ 7.38” Seal Bore – 3,811’ TVD 6.180” 6 12,863’ Shoe Bottom @ 12,865’ MD 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –Lead 370 sx / Tail 398 sx Stg 2 –Lead 454 sx / Tail 270 sx - 200 bbls returned to surface 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 953’ Hole Angle @ XN = 66° Hole Angle @ Liner Top = 85° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23675-00-00 Completed by Innovation: 5/20/2020 Depth MD Depth TVD ICD/Swell Packer Detail 5,020’ 3,826’ Tendeka Water Swell Packer 5,245’ 3,823’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 5,348’ 3,822’ Tendeka Water Swell Packer 5,985’ 3,820’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,253’ 3,820’ Tendeka Water Swell Packer 6,767’ 3,833’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,076’ 3,831’ Tendeka Water Swell Packer 8,002’ 3,887’ Tendeka Water Swell Packer 8,144’ 3,895’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,531’ 3,908’ Tendeka Water Swell Packer 8,838’ 3,918’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,938’ 3,922’ Tendeka Water Swell Packer 9,322’ 3,900’ Tendeka Water Swell Packer 9,583’ 3,890’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,985’ 3,890’ Tendeka Water Swell Packer 10,300’ 3,897’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,819’ 3,915’ Tendeka Water Swell Packer 11,085’ 3,920’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,558’ 3,928’ Tendeka Water Swell Packer 11,942’ 3,933’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,292’ 3,936’ Tendeka Water Swell Packer 12,765’ 3,953’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge _____________________________________________________________________________________ Revised By: TDF 7/19/2021 PROPOSED Milne Point Unit Well: MPU I-35 PTD: 220-034 API: 50-029-23675-00-00 TD =13,130’(MD) / TD =4,002 (TVD) 20” Orig. KB Elev.: 60.3’/ GL Elev.: 33.6’ 3-1/2”2 9-5/8” 1 3 & 4 6 See ICD & Swell Packer Detail PBTD =13,130’(MD) / PBTD =4,002’(TVD) 9-5/8” ‘ES’ Cementer @ 1,933’ MD 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-56 / Weld N/A Surface 186’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 1,993’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 1,993’ 5,009’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 4,828’ 12,865’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 4,836’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,001’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,064’ Brace XN Landing Nipple w/ 2.750” Packing Bore 2.813” 3 4,825’ 8.25” No Go Locater Sub (1.45’ off No-go) 6.170” 4 4,826’ Bullet Seals – Mule Shoe bottom @ 4,836’ MD 6.170” Lower Completion 5 4,828’ 7” x 9-5/8” SLZXP LTP w/ 7.38” Seal Bore – 3,811’ TVD 6.180” 6 12,863’ Shoe Bottom @ 12,865’ MD 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4"Stg 1 –Lead 370 sx / Tail 398 sx Stg 2 –Lead 454 sx / Tail 270 sx - 200 bbls returned to surf. 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 953’ Hole Angle @ XN = 66° Hole Angle @ Liner Top = 85° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23675-00-00 Completed by Innovation: 5/20/2020 Depth MD Depth TVD ICD/Swell Packer Detail 5,020’ 3,826’ Tendeka Water Swell Packer 5,245’ 3,823’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 5,348’ 3,822’ Tendeka Water Swell Packer 5,985’ 3,820’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,253’ 3,820’ Tendeka Water Swell Packer 6,767’ 3,833’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,076’ 3,831’ Tendeka Water Swell Packer 8,002’ 3,887’ Tendeka Water Swell Packer 8,144’ 3,895’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,531’ 3,908’ Tendeka Water Swell Packer 8,838’ 3,918’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,938’ 3,922’ Tendeka Water Swell Packer 9,322’ 3,900’ Tendeka Water Swell Packer 9,583’ 3,890’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,985’ 3,890’ Tendeka Water Swell Packer 10,300’ 3,897’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,819’ 3,915’ Tendeka Water Swell Packer 11,085’ 3,920’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,558’ 3,928’ Tendeka Water Swell Packer 11,942’ 3,933’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,292’ 3,936’ Tendeka Water Swell Packer 12,765’ 3,953’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Schrader Bluff ±5,265’ ±5,275’ ±3,821’ ±3,821’ ±10 2” Future Pending ±6,010’ ±6,020’ ±3,819’ ±3,819’ ±10 2” Future Pending ±6,800’ ±6,810’ ±3,831’ ±3,831’ ±10 2” Future Pending ±8,170’ ±8,180’ ±3,895’ ±3,895’ ±10 2” Future Pending ±8,860’ ±8,870’ ±3,918’ ±3,919’ ±10 2” Future Pending ±9,610’ ±9,620’ ±3,888’ ±3,888 ±10 2” Future Pending ±10,350’ ±10,360’ ±3,897’ ±3,898’ ±10 2” Future Pending ±11,150 ±11,160’ ±3,919’ ±3,919’ ±10 2” Future Pending CT Perforate Well: MPU I-35 Date: 7/20/2021 CT Perforate Well: MPU I-35 Date: 7/20/2021 Equipment Layout Diagram CT Perforate Well: MPU I-35 Date: 7/20/2021 Standing Orders for Open Hole Well Control during Perf Gun Deployment DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23675-00-00Well Name/No. MILNE PT UNIT I-35Completion Status1WINJCompletion Date5/20/2020Permit to Drill2200340Operator Hilcorp Alaska, LLCMD13130TVD4002Current Status1WINJ9/22/2020UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, DGR, AGR, ABG, ADR, EWR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF7/3/2020105 13130 Electronic Data Set, Filename: MPU I-35 LWD Final.las33470EDDigital DataDF7/3/20204998 13092 Electronic Data Set, Filename: MPU I-35 ADR Quadrants All Curves.las33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35 LWD Final MD.cgm33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35 LWD Final TVD.cgm33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35i_Definitive Survey Report.pdf33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35i_DSR.txt33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35i_DSR.xlsx33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35i_GIS.txt33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35i_Plan.pdf33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35i_VSec.pdf33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35 LWD Final MD.emf33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35 LWD Final TVD.emf33470EDDigital DataDF7/3/2020 Electronic File: MPU_I-35_Geosteering.dlis33470EDDigital DataDF7/3/2020 Electronic File: MPU_I-35_Geosteering.ver33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35 LWD Final MD.pdf33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35 LWD Final TVD.pdf33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35 LWD Final MD.tif33470EDDigital DataDF7/3/2020 Electronic File: MPU I-35 LWD Final TVD.tif33470EDDigital DataDF7/3/2020 Electronic File: EMFView3_1.zip33470EDDigital DataTuesday, September 22, 2020AOGCCPage 1 of 3MPU I-35 LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23675-00-00Well Name/No. MILNE PT UNIT I-35Completion Status1WINJCompletion Date5/20/2020Permit to Drill2200340Operator Hilcorp Alaska, LLCMD13130TVD4002Current Status1WINJ9/22/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:5/20/2020Release Date:4/8/2020DF7/3/2020 Electronic File: Readme.txt33470EDDigital Data0 0 2200340 MILNE PT UNIT I-35 LOG HEADERS33470LogLog Header ScansDF8/19/2020 Electronic File: MPI-35 Post-Well Geosteering X-Sec.pdf33672EDDigital DataDF8/19/2020 Electronic File: MPU I-35 Geosteering End of Well Report.pdf33672EDDigital DataDF8/19/2020 Electronic File: MPU I-35 Geosteering Final Log.pdf33672EDDigital Data0 0 2200340 MILNE PT UNIT I-35 LOG HEADERS33672LogLog Header ScansDF8/27/2020 Electronic File: MPU I-35 LWD Final MD.emf33672EDDigital DataDF8/27/2020 Electronic File: MPU I-35 LWD Final TVD.emf33672EDDigital Data0 0 2200340 MILNE PT UNIT I-35 LOG HEADERS (Resubmittal from 08/19/2020)33672LogLog Header ScansTuesday, September 22, 2020AOGCCPage 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23675-00-00Well Name/No. MILNE PT UNIT I-35Completion Status1WINJCompletion Date5/20/2020Permit to Drill2200340Operator Hilcorp Alaska, LLCMD13130TVD4002Current Status1WINJ9/22/2020UICYesComments:Compliance Reviewed By:Date:Tuesday, September 22, 2020AOGCCPage 3 of 3M Guhl9/22/2020 MEMORANDUM To: Jim Regg P.I. Supervisor l FROM: Lou Laubenstein Petroleum Inspector Well Name MILNE PT UNIT I-35 IInsp Num: mitl.OL200823150045 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, August 27, 2020 SUBJECT: Mechanical Integrity Tests Hilcoip Alaska, LLC I-35 MILNE PT UNIT 1-35 Sre: Inspector Reviewed By: P.I. Supry T52 -- Comm API Well Number 50-029-23675-00-00 Inspector Name: Lou Laubenstein Permit Number: 220-034-0 Inspection Date: 8/22/2020 Packer Well 135 ]Type Inj w iTVD PTD 2200340 Type Test; sPT'4est psi BBL Pumped: 2.7 BBL Returned: - INITAL PAF Interval Depth -3813 Tubing 1500 IA 2.7 OA P Notes' Initial MIT -IA Pretest Initial 15 Min 30 Min 45 Min 60 Min 328 - 329 - 328 ' 328 358 2511 2411 - 2388 ' Thursday, August 27, 2020 Page I of 1 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-5256 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 8/27/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-35 (PTD 220-034) EMF of MPU I-35 LWD FINAL Log - Resubmission Received by the AOGCC 08/27/2020, re submittal of partial data package from 08/19/2020 Abby Bell 08/27/2020 PTD: 2200340 E-Set: 33672 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/02/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU I-35 (220-034) Halliburton LWD FINAL 04 MAY 2020 MPU I-35 Received by the AOGCC 07/03/2020 Abby Bell 07/06/2020 PTD: 2200340 E-Set: 33470 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 33.6' BF:33.6' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 20" X-56 186' L-80 1,973' L-80 3,826' 4-1/2" L-80 3,961' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate 9-5/8"47# Surface 1,993' May 15, 2020 May 4, 2020 ADL025906, ADL315848 LONS 88-04 1,806' MD / 1,790' TVD N/AN/A N/A 13,130' MD / 4,002' TVD ROP, DGR, AGR, ABG, ADR, EWR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: Oil-Bbl: 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 N/A **Please see attached schematic for ICD/Swell Packer Detail** Liner run on 5/18/20 Water-Bbl: PRODUCTION TEST N/A Date of Test: N/A Flow Tubing 129.5# 186' Gas-Oil Ratio:Choke Size: Surface 40# 1,993' Per 20 AAC 25.283 (i)(2) attach electronic information 12,865' 3,813' DEPTH SET (MD) 4,828' MD / 3,813' TVD PACKER SET (MD/TVD) 5,009' 1,973' CASING WT. PER FT.GRADE 13.5# 551442 552162 TOP SETTING DEPTH MD Surface SETTING DEPTH TVD 6019213 BOTTOM TOP 200 bbls Surface HOLE SIZE AMOUNT PULLED 50-029-23675-00-00 MPU I-35 551803 6009439 1036' FNL, 1370' FWL, Sec 33, T13N, R10E, UM, AK CEMENTING RECORD 6011358 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 5/20/2020 2322' FSL, 3567' FEL, Sec 33, T13N, R10E, UM AK 1535' FSL, 2164' FWL, Sec 21, T13N, R10E, UM, AK 220-034 Milne Point Field / Schrader Bluff Oil Pool 60.3' 13,130' MD / 4,002' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas Driven Stg 1 L - 370 sx / T - 398 sx Driven Stg 2 L - 454 sx / T - 270 sx 4,828' 12-1/4" Cementless Injection Liner w/ ICDs & Swell Pkrs 4,836'3-1/2" Tieback Tubing SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 8-1/2" TUBING RECORD Liner Top Packer WINJ SPLUG Other Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 12:07 pm, Jun 03, 2020 Completion Date 5/20/2020 HEW RBDMS HEW 6/8/2020 DSR-6/8/2020DLB 06/09/2020 SFD 6/10/2020 MGR21SEP2020 G Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD 1,806' 1,790' Top of Productive Interval SB NB 5,245' 3,823' 1,354' 1,350' 2,207' 2,005' 3,438' 3,311' 4,501' 3,791' 4,842' 3,812' SB NB 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: 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. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). 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. 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. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). 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. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: SB NA Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report, FIT. Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS 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. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME SB NB SV1 Ugnu LA3 SV5 This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. 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. 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. Authorized Name: Monty Myers Authorized Title: Drilling Manager Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.06.03 11:25:45 -08'00' Monty M Myers _____________________________________________________________________________________ Revised By: CJD 6/3/20 Schematic Milne Point Unit Well: MPU I-35 PTD: 220-034 API: 50-029-23675-00-00 Depth MD Depth TVD ICD/Swell Packer Detail See Page 2 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X-56 / Weld N/A Surface 186’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 1,993’ 0.0732 9-5/8" Surface 40 / L-80 / TXP 8.679” 1,993’ 5,009’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.795” 4,828’ 12,865’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 4,836’ 0.0087 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 4,001’ 3-1/2” Gauge Mandrel w/ ¼” Wire 2.992” 2 4,064’ Brace XN Landing Nipple w/ 2.750” Packing Bore 2.813” 3 4,825’ 8.25” No Go Locater Sub (1.45’ off No-go) 6.170” 4 4,826’ Bullet Seals – Mule Shoe bottom @ 4,836’ MD 6.170” Lower Completion 5 4,828’ 7” x 9-5/8” SLZXP Liner Top Packer with 7.38” Seal Bore 6.180” 6 12,863’ Shoe Bottom @ 12,865’ MD 3.970” OPEN HOLE / CEMENT DETAIL 42" ±270 ft3 12-1/4" Stg 1 –Lead 370 sx / Tail 398 sx Stg 2 –Lead 454 sx / Tail 270 sx - 200 bbls returned to surface 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 953’ Hole Angle @ XN = 66° Hole Angle @ Liner Top = 85° Max Hole Angle = 96° TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23675-00-00 Completed by Innovation: 5/20/2020 Depth MD Depth TVD ICD/Swell Packer Detail 5,020’ 3,826’ Tendeka Water Swell Packer 5,245’ 3,823’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 5,348’ 3,822’ Tendeka Water Swell Packer 5,985’ 3,820’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 6,253’ 3,820’ Tendeka Water Swell Packer 6,767’ 3,833’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 7,076’ 3,831’ Tendeka Water Swell Packer 8,002’ 3,887’ Tendeka Water Swell Packer 8,144’ 3,895’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,531’ 3,908’ Tendeka Water Swell Packer 8,838’ 3,918’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 8,938’ 3,922’ Tendeka Water Swell Packer 9,322’ 3,900’ Tendeka Water Swell Packer 9,583’ 3,890’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 9,985’ 3,890’ Tendeka Water Swell Packer 10,300’ 3,897’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 10,819’ 3,915’ Tendeka Water Swell Packer 11,085’ 3,920’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 11,558’ 3,928’ Tendeka Water Swell Packer 11,942’ 3,933’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge 12,292’ 3,936’ Tendeka Water Swell Packer 12,765’ 3,953’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge Activity Date Ops Summary 5/1/2020 Scope derrick down. Blow down steam and water lines. Finish disconnect interconnects. Unplug and swap from gen to cold start at 01:30. Disconnect and move break shack and envirovac. rig down and move cuttings box.;Peak on location at 02:30. Pull pipe shed, gen mod, mud mod, and cattle chute away from sub base and stage on pad. Remove all rig mats. Prep to pull sub base of K-44B. 5/2/2020 Pull sub off K-44B. Mob sub , pipe shed and cattle chute to I-Pad. Sim Ops: hook up DSA and diverter ‘T’ to I-35 and stage rig mats.;Remove Rear tires and all stair landings on sub base. Spot sub base over I-35. Mob mud and Gen mod from K-Pad to I-Pad.;Shim up sub base. Spot cattle chute, mud mod, gen mod and pipe shed. Shim and level all mods. Spot break shack. Begin hooking up steam system and interconnect.;Spot and hook up envirovac and break shack. Spot MPD choke house. Set and berm up cutings box. Rig up all interconnects. Hook up steam, water and air systems. Scope derrick and bridal down. Work on rig acceptance checklist. Safe-out all stairs, walk ways and landings. Move camp and shop. 5/3/2020 Work on rig acceptance checklist. Perform 3 month EAM for top drive. Replace solenoid coil for drawworks brake. Work on 6 month EAM for MP2 crosshead. Replace bearings on drag chain.;Install stack on diverter 'T' and tighten BOP bolts. Install knife valve. Hook up chain and binders to stack. Continue working on EAM for mud pumps and replace bearing on drag chain. Change out solenoid coil for drawworks brake.;N/U diverter system; continue installing knife valve and torque stack bolts. Bolt up three diverter sections. Install bell nipple and riser. Center stack and tighten chains. Test starter head seals to 500 psi for 10 minutes - good.;Sim Ops Re-install grease lines on drag chain. Complete mud pump cross head inspections on both pumps. Process 5" drill pipe.;Finish processing 5" drill pipe and HWDP. re-assembly mud pumps. Flush MP's with water, move water in pits and check for leaks and PVT system - good. Derrick inspection. Grease crown, blocks, top drive, spinners and iron roughneck. Change out dies in iron roughneck. Rig Accepted at 21:00 hrs.;Pick up , drift (3.125") and rack back 58 stands of 5" drill pipe. SimOps: take on mud in pits. Move shop and pusher camp. use crane to set remaining diverter section.;Continue to pick up, drift (3.125") and rack back total of 95 stands 5" drill pipe, 9 stands HWDP (including jars). Sim Ops: Finish setting and hooking up diverter line with crane.;Test diverter system on 5" drill pipe. Knife opening time 6 seconds, annular closing time 10 seconds. Drawdown: starting pressure 2950 psi, final pressure 1950 psi first 200 psi recharge 17 seconds, final 58 seconds. (6) N2 bottles with 2395 psi average. AOGCC right to witness waived by Brian Bixby;Test gas alarms.;Install short mouse hole. Pick up and stage BHA components on rig floor, and in shed as per DD. Pick up Mud motor. Pre-spud meeting with all hands. 5/4/2020 M/U 12-1/4" K5M633 (BHI) w/ 8" Terraforce Mtr 1.5° (4/5 lobe - 5.3 stg) xo, 5" HWDP RIH to tag depth of 47' MD. Flood surface lines and conductor with water. P/T high psi lines to 3000 psi without issue. Knife valve leaking @ gate. Drain stack and adjust gate guide and retest (test good).;Wash down thru ice F/ 47' to 107' then displace to 8.9 spud mud. Drill ahead F/ 107' - T/ 221' MD @275-380 gpm, 180-270 psi, 20-40 rpm 1-3k tq, 1-3k wob, 47 up/dn/rot. CBU 2x. Returns showed coarse sand w/ slight pea gravel.;Attempt to POOH on elevators F/ 221' MD. Pulled 10k over @ 190' MD. Attempt to work thru with no pump/rot (no go). BROOH F/ 221' - T/ 160' MD then pulled clean on elevators with no issue. B/D TDS. Continue to jet flowline and clear from packing off.;Inspect bit (good). M/U DM, EWR, TM and UBHO sub. Perform RFO mwd/mtr (492/805x360=220.02°) witnessed by Shane Barber. Plug in and download MWD. Orient UBHO HS. M/U 1x Flex DC and RIH tagging up @ 102' MD 5x. L/D collar and M/U 1 std HWDP. Sym Ops - Hang Gyro sheave in derrick.;Wash dn F/ 102' - T/ 221' MD. 300 gpm, 400 psi, 1k wob, 20 rpm, 1k tq. No issues washing down.;Drill ahead F/ 221' - T/ 461' MD. 388 gpm, 730 psi, 30-50 rpm, 1-2k tq, 3k wob, 62k up/dn/rot. Obtain clean surveys starting at 234'.;Attempt to POOH on elevators F/ 461' MD. Continually saw overpulls up to 30k after 20' MD. Make several attempts to pull past obstruction with no success. BROOH w/ minimal rates. Did not see overpulls or packing off issues. Attempted to POOH on elevators w/ 196' with same results.;Pulled clean F/ 142' to MWD.;Pick up and RIH with (2) flex collars, on third collar set down at 140'MD. Attempt to work past unable to. L/D flex collar. Wash down with 1 stand HWDP, rack back. Pick up last flex collar and RIH. Continue washing down to 461' at 400 gpm, 700 psi, 30 rpms, 1.2Kft-lbs.;Continue drilling 12-1/4" hole from 461' to 928' (total 467', AROP 117 fph) staging up to 465 gpm, 1370 psi, 55 rpms, 2.8Kft-lbs, WOB 6K. ECD 10.0 ppg with 8.9 ppg mud. PUW 77K, SOW 81K, ROTW 77K. Rig down and release gyro at 900' - no gyro surveys collected.;Continue drilling 12-1/4" hole from 928' to 1437' (total 509', AROP 85 fph) staging up to 495 gpm, 1345 psi, 60 rpms, 4Kft-lbs, WOB 6-14K. ECD 10.0 ppg with 9.1 ppg mud. PUW 88K, SOW 88K, ROTW 85K. Max Gas 15U. KOP at 930', start sliding for 4°/100 build rate.;Daily fluid hauled to G&I 684 bbls total = 684 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 910 bbls total = 1,050 bbls Daily Fluid lost 0 bbls total surface hole = 0 bbls Distance to WP#8 = 6.03', 0.31' low, 6.21' Right (LAT/LONG): vation (RKB): API #: Well Name: Field: County/State: MP I-35 Milne Point Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2011149D MPU I-35 Drilling Spud Date: 5/5/2020 Drill 12-1/4" surface f/ 1437' - t/ 1628' (191' total, 127 fph AROP). WOB 10K, 495 gpm, 1415 psi, 60 rpm, 4K tq on, 10.16 ECD's with 9.1 ppg MW. P/U 91K, S/O 91K, ROT 91K. Backream 15' per stand. Turning 4°/100 as per WP8.;Service rig: Open coffin lid on top drive and tighten leaking hydraulic hose.;Drill 12-1/4" surface f/ 1628' - T/ 2056' (428' total, 107 fph AROP). WOB 4-8K, 500 gpm, 1620 psi, 80 rpm, 3.2K tq on, 10.1 ECD's with 9.1 ppg MW. Max Gas 67U. P/U 99K, S/O 98K, ROT 99K. Backream 15' per stand. Maintenance slides as needed through tangent.;Base of Permafrost logged at 1806'MD.;Drill 12-1/4" surface f/ 2056' - t/ 2865' (809' total, 135 fph AROP). WOB 6K, 500 gpm, 1800 psi, 80 rpm, 4.7K tq on, 10.1 ECD's with 9.1 ppg MW. Max Gas 1125U. P/U 118K, S/O 110K, ROT 112K. Backream 30' per stand. Start 4°/100 build and turn at 2390'.;Drill 12-1/4" surface f/ 2865' - t/ 3346' (481' total, 80 fph AROP). WOB 10K, 555 gpm, 2010 psi, 80 rpm, 5.8K tq on, 9.88 ECD's with 9.1 ppg MW. Max Gas 41U. P/U 122K, S/O 110K, ROT 116K. Backream full stands. Primarily sliding for 4°/100 build and turn at 2390'.;Drill 12-1/4" surface f/ 3346' - t/ 3915' (571' total, 95 fph AROP). WOB 5-18K, 555 gpm, 1980 psi, 80 rpm, 5.5K tq on, 9.87 ECD's with 9.1 ppg MW. Max Gas 726U. P/U 133K, S/O 111K, ROT 121K. Backream full stands. Primarily sliding for 4°/100 build at 2390'.;Daily fluid hauled to G&I 1140 bbls total = 1824 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 1300 bbls total = 2,350 bbls Daily Fluid lost 0 bbls total surface hole = 0 bbls Distance to WP#8 = 7.59', 7.33' Low, 1.98' Left 5/6/2020 Drill 12-1/4" surface f/ 3915' - t/ 4297' (382' total, 64 fph AROP). WOB 2-21K, 555 gpm, 2150 psi, 80 rpm, 10.5K tq on, 9.65 ECD's with 9.2 ppg MW. Max Gas 1729U. P/U 131K, S/O 108K, ROT 120K. Backream full stands. Primarily sliding for 4°/100 build. Observe pack-off and stalls;between 4214' and 4223'. Control drill at 50 fph through section.;Drill 12-1/4" surface f/ 4297' - t/ 4996' (699' total, 117 fph AROP). WOB 10- 20K, 555 gpm, 2060 psi, 80 rpm, 7.8K tq on, 10.15 ECD's with 9.2 ppg MW. Max Gas 872U. P/U 125K, S/O 95K, ROT 109K. Backream full stands. Primarily sliding for 4°/100 build.;Slide Drill 12-1/4" surface f/ 4996' - t/ 5019'; casing point. WOB 10-30K, 555 gpm, 2060 psi, 10.15 ECD's with 9.2 ppg MW. Max Gas 1050U. P/U 125K, S/O 95K, ROT 109K. Backream full stands. Obtain final survey. NB sands logged at 4,848'.;BROOH to above NB sands from 5019' to 4745'. 555gpm, 1850 psi, 80 rpms, 8K ft-lbs, PUW 133K, SOW 96K, ROTW 111K.;Circulate hole clean, CBU x 2 at 580 gpm, 2050 psi, 80rpms, 8K ft-lbs, PUW 125K, SOW 95K, ROTW 109K. ECD's 907-9.89 ppg with 9.2 ppg mud. Monitor well, static.;TIH on elevators to 5019', casing point with no issues.;BROOH from 5019' to 3855' at 555 gpm, 1850 psi, 80 rpms, 8Kft-lbs. Pull 35 fpm with no issues. PUW 133K, SOW 96K, ROTW 111K.;Continue to BROOH from 3855' to 1185' at 555 gpm, 1525 psi, 80 rpms, 2Kft-lbs. Pull 20-35 fpm as hole dictates. PUW 82K, SOW 81K, ROTW 82K. Slow pulling speed from 1948' to 1806' and obtain 2 x BU prior to entering permafrost.;Daily fluid hauled to G&I 1259 bbls total = 3083 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 910 bbls total = 3,260 bbls Daily Fluid lost 0 bbls total surface hole = 0 bbls Distance to WP#8 = 2.53', 1.55' High, 2.0' Right 5/7/2020 Cont. to BROOH from 1185' to 739' at 450 gpm, 1050 psi, 60 rpms, 1.2Kft-lbs. Max gas 182U. ECD 9.7 ppg with 9.2 ppg mud. PUW 75K, SOW 75K, ROTW 75K. Pull 20-35 fpm as hole allows.;POOH on elevators from 739' to 605'. Pull 15K over. BROOH to 400' at 450 gpm, 1010 psi, 60 rpms, 1.2Kft-lbs.;L/D BHA, (3) flex collars, UBHO. Plug in and upload MWD tools. Pull pulser from TM. L/D remaining BHA. Bit Grade 1-1-BT-S-E-I- CT-TD.;Clean and clear rig floor of BHA components.;Service rig: grease crown and blocks. Open coffin lid on a begin C/O leaking hydraulic hose. Sim Ops: pump through bleeder and flush flow line. B/D cement line.;Service rig: replace 2 o-rings on top drive, verify no leaks.;Rig up to run casing. Bring up casing handling tools, power tongs. M/U volant tool. M/U bail extensions. Hang elevators. Complete casing checklist.;RIH with 9-5/8", L-80, TXP casing from surface to 1984'. Bakerlok shoe track, install top hat on top of float collar. Check floats - good. PUW 113K , SOW 103K. Fill every 5 joints, top off every 10. torquing 40# to 21K-ftlbs.;Circulate bottoms up, staging pumps up to 6 bpm/110 psi, 10rpms/3K-ftlbs reciprocating pipe.;Cont. to RIH with 9-5/8", L-80, TXP casing from 1984' to 3623' torquing 40# to 21Kft-lbs, 47# to 23.8Kft-lbs. PUW 174K, SOW 134K. Fill every 5 joints, top off every 10.;Circulate bottoms up, staging pumps up to 6 bpm, 160 psi, 10 rpms, 11Kft-lbs, reciprocating pipe. PUW 174K, SOW 134K, ROTW 145K.;Cont. to RIH with 9-5/8", L-80, TXP casing from 3623' to 4031' torquing 40# to 21Kft-lbs, 47# to 23.8Kft-lbs. PUW 174K, SOW 134K. Fill every 5 joints, top off every 10. Calc disp 60 bbls, Act. 31 bbls.;Cont. to RIH with 9-5/8", L-80, TXP casing from 4031' to 5014' torquing 47# to 23.8Kft- lbs. PUW 195K, SOW 138K. Fill every 5 joints, top off every 10. Calc disp 16 bbls, Act. 9 bbls.;CBU x 2 staging pumps up to 6 bpm, 165 psi, 1-5 rpms with torque limiter set at 15Kft-lbs. Lowering YP to 17. No losses.;PJSM. Blow down to cementers, double check all equipment. R/U cement hose to Volant. Blow down top drive. Cementers batch up spacer. Break circulation with mud through cement line staging up to 6 bpm, 370 psi. Halliburton fill lines with 5 bbls H2O. PT cement lines 1000/4000 psi.;Daily fluid hauled to G&I 399 bbls total = 3482 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 520 bbls total = 3,780 bbls Daily Fluid lost 29 bbls total surface hole = 29 bbls 5/8/2020 PJSM, 1st stg surface cmt: Clear cmt line to cmt unit. Flood lines w/ 5 bbls water. P/T lines 1000/4000 psi. Pump 60 bbls 10# Tuned Spacer III w/ #4 red dye in first 10 bbls. Drop bypass plug.;Mix and pump 370 sxs (155 bbls) 12.0 ppg Type i/II Lead Cement at 5 bpm, 400 psi. Mix and pump 398 sxs (82 bbls) 15.8 ppg Hal CemTail Cement at 4.7 bpm, 800 psi. Drop Shut off Plug.;Displace cmt w/ 20 bbls FW f/ Cmt Unit. Rig Pump 193 bbls, 9.3 ppg mud, Cmt Unit 80 bbls Spacer @ 4.5 bpm, 400 psi FCP, Rig 77.2 bbls 9.3 ppg mud, 5 bpm/740 psi, FCP 680 psi @ 3 bpm last 13 bbls. Rotate while reciprocating pipe 20', Park in tension @ 5009' 213 bbls into displacing.;Bump Plug 4.7 bbls over calculated, pressure 500 over FCP to 1180 PSI, check floats, good. Full returns, no losses. CIP @ 09:00. Using rig pump, stage pressure up to 2930 psi, open ES Cementer. CBU x 2 through Stage tool staging up to 5 bpm, 350 psi bring all spacer/ 45 bbls green CMT to Surf.;Continue to circulate through stage tool @ 4 bpm / 230 psi, while prepping for 2nd stage Cement.;Perform 2nd stage cement job. B/D cement and water line to ensure clear. HES pumped: 5 bbls water at 4.5 bpm, 337 psi, 60 bbls 10.0 ppg tuned spacer with 0.5 ppg Poly-E-Flake and 4# red dye at 5 bpm, 286 psi, 454 sacks (238 bbls) 10.7 ArcticCem Lead cement at 5 bpm, 470 psi.;Observe green cement at surface, Pump 270 sacks (56 bbls) 15.8 ppg Class G tail cement at 5 bpm 771 psi, Drop closing plug HES Displace with 20 bbls water at 5 bpm 250 psi, swap to rig pumps with 120 bbls of 9.3 at 7 bpm, 900 psi. Slow to 3 bpm with 10 bbls to go, FCP 576 psi.;Bump plug 2 bbls early. Pressure up to 2000 psi, observing ES cementer shifting close at 1460 psi. Hold pressure for 5 minutes and bleed back 1 bbls - confirm tool closed. CIP at 18:45. No losses during job, 200 bbls of green lead cement returned to surface.;Drain stack and flush with black water x 2. Rig down cement line, and Volant tool. Flush cement line with black water. Install casing elevators.;Disconnect accumulator and knife valve. Flush stack x3: fill will black water and function annular 3 times. Pull mousehole. Hook up bridge cranes to stack and remove chains. Remove diverter sections. Deflate airboot. Pick up on stack. Set 'E' Slips on 9-5/8" casing with 115K wt.;Prep to cut casing: suck out mud from cut joint. Cut casing (cut joint length 31.05'). Pull riser and move stack out of way. Clean cellar box, and casing stump. Dress off casing stump. Set stack on starting head and 4-bolt. Install riser. P/U stack washing tool. Wash BOPE stack with black water.;SimOps: Cont. emptying and cleaning pits. Load 5" drill pipe.;Drain stack, pull riser. Remove knife valve. Remove bell nipple. Remove bolts from stack/diverter 'T'. Pick stack out of way and remove diverter 'T' and set back. Sim Ops: Cont cleaning pits. Remove riser, master bushing from rig floor. Begin MP1 6-month inspection.;Daily fluid hauled to G&I 1717 bbls total = 5,199 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 980 bbls total = 4,760 bbls Daily Fluid lost 7 bbls total surface hole = 36 bbls 5/9/2020 Attach spacer spool to stack. Remove 4" conductor valves and install caps. Remove chains from stack and set back on pedestal. Sim Ops: Cont. cleaning pits, working on MP 6-month EAM. Rig remaining diverter vent line down with crane.;Pull slip lock head and set asie in cellar. Install T-103 adapter. Test T-103 adapter void to 3800 psi (80% of 47# casing collapse) for 10 minutes - good. Install well head and test void 500 psi/5 min, 5000/10 minutes - good. Install test plug, RILDS. Sim Ops Cont. cleaning pits.;P/U DSA and orientate for stack alignment. P/U RCD with blocks. N/U BOPE, hook up choke and kill lines. SimOps: cont cleaning pits, load mud. Process 5" drill pipe.;Cont. torquing BOPE flange bolts, install accumulator lines, change out vacuum degasser pump. Change out saver sub, check grabber dies. Torque lock ring bolts and wire tie. Adjust top drive back up wrench height. Change out wash pipe.;Flood lines and test MPD system 250/1400 psi - good. Pull test cap. Install riser. air up boot and check for leaks - good.;Test BOPE's: Pick up 5" test join with pump in sub, TIW's and dart valve. Flood lines and work air out. Obtain good shell test. Test BOPE's 250/3000 psi, AOGCC Guy Cook witness. 2nd test fail, trouble shoot. UPR's leaking.;De-energize accumulator. Open UPR doors. Clean and inspect. C/O upper seals and re-energize accumulator.;Daily fluid hauled to G&I 238 bbls total = 5,437 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 260 bbls total = 5,020 bbls Daily Fluid lost 0 bbls total surface hole = 36 bbls 5/10/2020 Cont. testing BOPE's 250/3000 psi on 5" and 3-1/2" test joints. AOGCC Guy Cook witness. Check PVT alarms and sensors, flow paddle.Test gas alarms. Accumulator draw down: Initial pressure 3000 psi, final 1450 psi, first 200 psi recharge 20 seconds, full recharge 96 seconds. (6) N2 with 2308 psi ave.;Rig down test equipment. B/D top drive, kill and choke lines, choke manifold. BOLDS and pull test plug.;M/U running tool and install wear bushing, RILDS. ID = 10.75", L=12.125".;M/U Drillout BHA #2: Tri-cone Smith bit, motor, (6) HWDP, Hydra Jars, (11) HWDP.;Pick up, drift (3.125") and single in the hole from 595' to 1835'. PUW 80K, SOW 71K..;Wash down from 1835' and tag cement at 1,920'. Drill cement and ES cementer (1937), from 1920' to 1937' at 400 gpm, 550 psi, 40 rpms, 2500 ft-lbs. Ream back through ES cementer x2. Pick up and pass through ES cementer with no pumps or rotary.;Cont. to Pick up, drift (3.125") and single in the hole from 1,962' to 4,728'. Wash down from 4,728' to 4,852' at 350 gpm, 650 psi, 20 rpms, 8Kft-lbs.;Circulate hole clean, surface to surface at 500 gpm, 730 psi, 40 rpms, 8.2Kft-lbs, reciprocating pipe.;Rig up, fill lines, purge air and PT casing to 2500 psi for 30 minutes - good 4.1 bbls to pressure up 4 bbls bled back.;Obtain SPR's. Wash down from 4852' t o 4887' and tag baffle adapter, 450 gpm, 800 psi, 40 rpms, 9Kft-lbs.;Drill up float equipment, cement and 20' new hole from 4887' to 5039', tag baffle adapter at 4887', float collar at 4929', shoe at 5010' with WOB 5-15K, 500 gpm, 1125 psi, 50 rpms, 10.6Kft-lbs.;Daily fluid hauled to G&I 342 bbl s total = 5,779 bbls Daily metal recovered 0 lbs, total = 0 lbs Daily water hauled from L Pad Lake 260 bbls total = 5,280 bbls Daily Fluid lost 0 bbls total surface hole = 36 bbls 5/11/2020 Pump high vis spacer and displace to 8.9 ppg Baradril-N at 500 gpm, 675 psi, 50 rpms, 7Kft-lbs. PUW 125K, SOW 98K, ROT 105K. Obtain SPR's. Monitor well, static.;Pick up into shoe, racking one stand back. Flood lines and flush choke to purge air. Perform FIT to 12.0 ppg EMW; 1.6 bbls to pressure up, 1.4 bbls bled back. Blow down choke and kill.;POOH from 4979' to 4675', no indication of swabbing. Pump dry job, B/D top drive. Continue to POOH from 4675' to 595'.;Service rig: adjust pipe spinners and tighten bolts. Grease drawworks, and Iron roughneck.;L/D BHA. L/D excess HWDP, rack back jar stand. L/D remaining BHA. Bit grade 1-1-NO-A-E-I-NO-BHA.;P/U BHA: M/U NOV bit, NRP, Geo-pilot, ADR/HCIM, ILS, DGR, PWD, DM, TM, float, flex collar, float. Plug in and upload MWD. M/U HWDP, plug in and shallow pulse test - no pulse.;Trouble shoot MWD pulser, rack back HWDP, Jars, DC. Plug in and check ADR/trouble shoot. Pulser control module (PCM) locked up. Change out TM collar. Upload tools. Shallow pulse test - good.;RIH with HWDP, Jars, Drill collars from derrick. Pick up, drift (3.125") and single in the hole with 5" drill pipe from 211' to 1,801'. PUW 71K, SOW 71K.;Cont. to Pick up, drift (3.125") and single in the hole with 5" drill pipe from 1,801' to 3,072'. PUW 105K, SOW 91K. Fill pipe and break in Geo-pilot at 2434'. B/D top drive.;RIH out of derrick from 3,072' to 4,980'. PUW 120K, SOW 96K. Calculated displacement.;Fill pipe. CBU at 500 gpm, 1182 psi, 60 rpms, 6.2Kft-lbs, reciprocating pipe. Max gas 597U. Blow down top drive.;Hang blocks. Cut and slip 62' of drilling line. Check brake air gab, calibrate blocks height, monitor hole on trip tank, static.;Service rig: grease crown, blocks, wash pipe, top drive, drawworks, spinners, iron rough neck. Check oil in top drive. Check welds on TD cradle.;Daily fluid hauled to G&I 601 bbls total = 6,380 bbls Daily metal recovered 2 lbs, total = 2 lbs Daily water hauled from L Pad Lake 130 bbls total = 5,410 bbls Daily Fluid lost 0 bbls total fluid lost production hole = 0 bbls total fluid lost surface hole = 36 bbls 5/12/2020 PJSM Remove riser. Install RCD Bearing on 5" Stand. Install into RCD Head as per Beyond rep onsite. Line up and pump 2 bpm with both pumps checking flow sensor and lines through Beyond choke house. Good.;PJSM Wash down F/ 4,980' to 5,039' MD tag bottom. 450 GPM, 1,090 PSI, 60 RPM, TRQ 7K, P/U 128K, SLK 86K, ROT 102K.;SPR at 5,039' MD (3,823' TVD) MW 8.9 ppg MPD holding 255 PSI. MP #1 32-205, 48-250. MP #2 32-200, 48-245.;PJSM Drill 8.5" Production Hole F/ 5,039' to 5,486' MD ( 3,823' TVD) Total 447’ (AROP 111.7’) 520 GPM/ MPD 515, 1,540 PSI, 85 RPM, TRQ on 8K, TRQ off 8.5K, WOB 3K. ECD 10.3 ppg. P/U 136K, SLK 80K, ROT 102K. Max Gas 1,526U. BGG 480U. Phase 2 weather condition.;MPD 75 PSI dynamic, static 270 PSI 10.3-10.35 ppg EMW W/ 8.9.ppg MW. Back reaming 30' at connections. Use MPD to control Gas.;PJSM Drill 8.5" Production Hole F/ 5,486' to 6,188' MD ( 3,821' TVD) Total 702’ (AROP 117’) 520 GPM/ MPD 512, 1,630 PSI, 90 RPM, TRQ on 12K, TRQ off 11K, WOB 9K. ECD 10.4 ppg. P/U 134K, SLK 70K, ROT 100K. Max Gas 2,165U. BGG 320U. Phase 1 weather condition.;MPD 100 PSI dynamic, static 280 PSI 10.4-10.45 ppg EMW W/ 8.9 ppg MW. Adjusting drilling parameters to control high erratic D.P. torque at surface. SPR at 5,740' MD (3,821' TVD) MW 8.9 ppg MPD holding 255 PSI MP #1 32-235, 48-255 MP #2 32-230, 48-250.;PJSM Drill 8.5" Production Hole F/ 6,188' to 6,856' MD ( 3,832' TVD) Total 668’ (AROP 111.3’) 530 GPM/ MPD 527, 1,820 PSI, 80-100 RPM, TRQ on 12K, TRQ off 10.5K, WOB 15K. ECD 10.43 ppg. P/U 138K, SLK 65K, ROT 105K. Max Gas 2,165U. BGG 220U MPD 100 PSI dynamic, static 280 PSI 10.4-10.45 ppg EMW .;Increased lubes by 0.5% total 2.0% to mitigate erratic surface torque, no real change. Cont adjusting RPM & ROP to control surface torque. Increased MPD to maintain 10.4-10.45 ECD due to Gas. Close approach to J-03 at 6,276' MD Ellipse 62.76' CC 41.3' as per plan.;PJSM Drill 8.5" Production Hole F/ 6,856' to 7,335' MD ( 3,846' TVD) Total 479’ (AROP 79.8’) 530 GPM/ MPD 525, 1,835 PSI, 90-115 RPM, TRQ on 11.3K, TRQ off 10.5K, WOB 5- 15K. ECD 10.44 ppg. P/U 131K, SLK 71K, ROT 98K. Max Gas 942U. BGG 200 MPD 70 PSI dynamic, static 280 PSI 10.5 ppg EMW.;Trouble shooting MWD sending down links at 06:00. At 6,951' D.P. surface torque smoothed out. Drilled out NB-sand top at 6,946' Re entered 7,136' MD Dip 88.5°. Distance to WP #08: 19.33', 12.98' High, 14.33' Right.;Encountered Fault 1 at 7,311' MD. 30 concretions drilled this lateral, total footage of 100’ (4.3% of the lateral). 2,121' drilled in NB Sand, Total out of zone 190'.;Daily fluid hauled to G&I 570 bbls total = 6,950 bbls Daily metal recovered 8 lbs, total = 10 lbs Daily water hauled from L Pad Lake 650 bbls total = 6,060 bbls Daily Fluid lost 0 bbls total fluid lost production hole = 0 bbls total fluid lost surface hole = 36 bbls 5/13/2020 PJSM Pulled above fault 1 at 7,331' and was able to establish down link to MWD. Appeared to be noise interference.;Drill 8.5" Lateral Hole F/ 7,335' to 7,838' MD ( 3,878' TVD) Total 503’ (AROP 83.8’) 530 GPM/ MPD 525, 1,945 PSI, 115-120 RPM, TRQ on 10.8K, TRQ off 8.8K, WOB 10-20K. ECD 10.8 ppg. P/U 126K, SLK 79K, ROT 101K. Max Gas 1,013U. BGG 220 MPD 70 PSI dynamic, static 280 PSI 10.5 ppg EMW.;At 7,523' MD open Beyond choke 100% and CBU seeing only connection Gas. Decision was made to only hold 10.5 ppg EMW at connections W/ 320 PSI. Back reaming 30' at connections. MAX ROP 275 ft/hr. SPR at 7,838' MD (3,878' TVD) MW 8.9 ppg MPD holding 240 PSI. MP #1 32-575, 48-600. MP #2 32-565, 48-625.;Drill 8.5" Lateral Hole F/ 7,838' to 8,350' MD ( 3,895' TVD) Total 512’ (AROP 85.3’) 530 GPM/ MPD 520, 2,055 PSI, 120 RPM, TRQ on 12K, TRQ off 12K, WOB 16-20K. ECD 11.1 ppg. P/U 133K, SLK 67K, ROT 100K. Max Gas 1,740U. BGG 320. MPD static 320 PSI 10.5 ppg EMW.;Back reaming 30' at connections. MAX ROP 250 ft/hr. SPR at 8,347' MD (3,895' TVD) MW 9.0 ppg MPD holding 240 PSI. MP #1 32-580, 48-645. MP #2 32-580, 48-640.;Drill 8.5" Lateral Hole F/ 8,350' to 8,922' MD ( 3,923' TVD) Total 572’ (AROP 95.3’) 530 GPM/ MPD 525, 2,000 PSI, 120 RPM, TRQ on 9.5K, TRQ off 8.5K, WOB 3-6K. ECD 11.1 ppg. P/U 138K, SLK 66K, ROT 100K. Max Gas 1,513U. BGG 320. MPD static 340 PSI 10.5 ppg EMW. Fault 2 at 8,965' MD 42' DTS.;Adjusting parameters due erratic surface torque. Back reaming 30' at connections. MAX ROP 250 ft/hr. SPR at 8,856' MD (3,917' TVD) MW 8.95 ppg MPD holding 240 PSI. MP #1 32-530, 48-585. MP #2 32-535, 48-590.;Drill 8.5" Lateral Hole F/ 8,992' to 9,500' MD ( 3,892' TVD) Total 515’ (AROP 85.8’) 530 GPM/ MPD 521, 2,060 PSI, 120 RPM, TRQ on 11.6K, TRQ off 10.5K, WOB 10-17K. ECD 11.29 ppg. P/U 127K, SLK 74K, ROT 98K. Max Gas 1,211U. BGG 240. MPD static 330 PSI 10.5 ppg EMW. Reentered NB sand at 9,510' MD.;Adjusting parameters due erratic surface torque. Back reaming 30' at connections. MAX ROP 250 ft/hr. SPR at 9,491' MD (3,891' TVD) MW 9.0 ppg MPD holding 240 PSI. MP #1 32-550, 48-605. MP #2 32-550, 48-605.;Distance to WP #08: 17.17', 17.16' Low, 0.50' Right.;Encountered Fault 1 at 7,311' MD 49' DTN. Fault 2 at 8,965' MD 42' DTS. 56 concretions drilled this lateral, total footage of 223’ (5.1% of the lateral). 3,026' drilled in NB Sand, Total out of zone 1,392'.;Daily fluid hauled to G&I 741 bbls total = 7,691 bbls Daily metal recovered 5 lbs, total = 15 lbs Daily water hauled from L Pad Lake 910 bbls total = 6,970 bbls Daily Fluid lost 0 bbls total fluid lost lateral hole = 0 bbls total fluid lost surface hole = 36 bbls 5/14/2020 Drill 8.5" Lateral Hole F/ 9,500' to 10,255' MD ( 3,869' TVD) Total 755’ (AROP 125.8’) 550 GPM/ MPD 535, 2,225 PSI, 120 RPM, TRQ on 12.6K, TRQ off 11-13K, WOB 5K. ECD 11.37 ppg. P/U 145K, SLK 60K, ROT 98K. Max Gas 1,786U. BGG 310. MPD static 330 PSI 10.5 ppg EMW. Choke 100% open during drilling.;Cont adjusting parameters due erratic surface torque. Back reaming 30' at connections. MAX ROP 300 ft/hr. SPR at 10,064' MD (3,888' TVD) MW 9.05 ppg MPD holding 240 PSI. MP #1 32-510, 48-565. MP #2 32-510, 48-565.;Drill 8.5" Lateral Hole F/ 10,255' to 10,830' MD ( 3,869' TVD) Total 575’ (AROP 95.8’) 550 GPM/ MPD 530, 2,200 PSI, 120 RPM, TRQ on 13K, TRQ off 12.5K, WOB 4-6K. ECD 11.16 ppg. P/U 154K, SLK 52K, ROT 102K. Max Gas 1,670U. BGG 410. MPD static 330 PSI 10.5 ppg EMW. Choke 100% open during drilling.;Cont adjusting parameters due erratic surface torque. Back reaming 30' at connections. MAX ROP 300 ft/hr. SPR at 10,703' MD (3,914' TVD) MW 8.9 ppg MPD holding 240 PSI. MP #1 32-540, 48-601. MP #2 32-535, 48-589.;Drill 8.5" Lateral Hole F/ 10,830' to 11,338' MD ( 3,919' TVD) Total 508’ (AROP 84.7’) 550 GPM/ MPD 535, 2,280 PSI, 130 RPM, TRQ on 14.9K, TRQ off 14.5K, WOB 2-5K. ECD 11.26 ppg. P/U 158K, SLK 35K, ROT 98K. Max Gas 1,768U. BGG 510. MPD Dynamic 115 PSI 9.55 EMW, static 330 PSI 10.5 ppg EMW.;At ~10,830’ hole started unloading W/ heavy sand, oil & gas at Shakers. Adjusted pump rate 450-500 GPM. Max Gas 1,616 W/ 650 BBG Gas. CBU 4X ROP 100 ft/hr over 3 stands F/ 10,830’ to 11,027’ MD. Hole appeared to clean up W/ ~560U BBG. MPD 100% open W/ 60 PSI line friction.;At 11,149’ hole started unloading again W/ heavy sand, oil & gas, adjusting flow to manage Shakers 450-500 GPM 130 RPM TRQ on 15.1K. Max Gas 1,768U. CBU 2X ROP 100 ft/hr F/ 11,149’ to 11,282’ MD. MPB holding 115 PSI dynamic 9.55 EMW. Cont drilling at normal rate W/ no issues.;Drill 8.5" Lateral Hole F/ 11,338' to 11,780' MD ( 3,941' TVD) Total 442’ (AROP 73.7’) 550 GPM/ MPD 534, 2,310 PSI, 130 RPM, TRQ on 14K, TRQ off 12.7K, WOB 5-18K. ECD 11.48 ppg. P/U 149K, SLK 35K, ROT 98K. Max Gas 1,382U. BGG 110. MPD Dynamic 115 PSI 9.55 EMW, static 330 PSI 10.5 ppg EMW.;Started control drill 150 ft/hr F/ 11,400' to 11,700' due to close approach to J-11 at 11,617' MD CC 174' Ellipse -12'. SPR at 11,346' MD (3,918' TVD) MW 8.95 ppg MPD holding 200 PSI. MP #1 32-455, 48-520. MP #2 32-455, 48-520.;Distance to WP #08: 31.20', 31.26' Low, 7.60' Right.;Encountered Fault 1 at 7,311' MD 49' DTN. Fault 2 at 8,965' MD 42' DTS. 75 concretions drilled this lateral, total footage of 362’ (5.4% of the lateral). 5,180' drilled in NB Sand, Total out of zone 1,481'.;Daily fluid hauled to G&I 1,383 bbls total = 9,074 bbls Daily metal recovered 0 lbs, total = 15 lbs Daily water hauled from L Pad Lake 1,170 bbls total = 8,140 bbls Daily Fluid lost 0 bbls total fluid lost lateral hole = 0 bbls total fluid lost surface hole = 36 bbls 5/15/2020 Drill 8.5" Lateral Hole F/ 11,780' to 12,197' MD ( 3,936' TVD) Total 417’ (AROP 69.5’) 550 GPM/ MPD 526, 2,620 PSI, 140 RPM, TRQ on 19.5K, TRQ off 15K, WOB 22-25K. ECD 11.65 ppg. P/U 158K, SLK 35K, ROT 93K. Max Gas 870U. BGG 110. MPD static 350 PSI 10.5 ppg EMW.;At 12,046' open MPD choke 100% W/ 63 PSI line friction. Back reaming 30' at connections. MAX ROP 300 ft/hr. SPR at 12,037' MD (3,934' TVD) MW 9.0 ppg MPD holding 240 PSI. MP #1 32-595, 48-675. MP #2 32-600, 48-680.;Drill 8.5" Lateral Hole F/ 12,197' to 12,544' MD ( 3,936' TVD) Total 347’ (AROP 57.8’) 550 GPM/ MPD 526, 2,700 PSI, 120 RPM, TRQ on 18-20K, TRQ off 19K, WOB 22-25K. ECD 11.55 ppg. P/U 182K, SLK 35K, ROT 95K. Max Gas 1,034U. BGG 250. MPD static 350 PSI 10.5 ppg EMW.;At 12,344’ MD encountered 75% loss in returns pumping at 550 GPM/ MPD 135 GPM ECD 11.63. P/U off bottom and reduced flow rate to 450 GPM was able to regain full Circ. Lost a total of 90 bbls. Entered a porous sand at 12,350’ might have been the cause. Resume drilling W/ out issue.;Back reaming 30' at connections. MAX ROP 150 ft/hr.;Drill 8.5" Lateral Hole F/ 12,544' to 12,801' MD ( 3,957' TVD) Total 257’ (AROP 42.8’) 550 GPM/ MPD 528, 2,425 PSI, 115 RPM, TRQ on 18-22K, TRQ off 18-20K, WOB 18K. ECD 11.4 ppg. P/U 182K, SLK 35K, ROT 97K. Max Gas 1,013U. BGG 210. MPD static 350 PSI 10.5 ppg EMW.;Slow ROP due to numerous concretions and difficulty steering at times. Back reaming 30' at connections. MAX ROP 300 ft/hr. SPR at 12,798' MD (3,957' TVD) MW 9.0 ppg MPD holding 240 PSI. MP #1 32-620, 48-695. MP #2 32-621, 48-680.;PJSM Rot & Rec F/ 12,801' to 12,757' MD 320 GPM/ MPD 310 GPM 1,151 PSI, 80 RPM, TRQ 16-19K. Shut in MP #1 & C/O Wear Plate, Liner and Swab on Pod #4. Wear Plate and Liner washed.;Drill 8.5" Lateral Hole F/ 12,801' to TD 13,130' MD ( 4,001' TVD) Total 329’ (AROP 65.8’) 550 GPM/ MPD 528, 2,540 PSI, 120 RPM, TRQ on 19K, TRQ off 18K, WOB 8-15K. ECD 11.65 ppg. P/U 178K, SLK 35K, ROT 99K. Max Gas 1,191U. BGG 115. MPD static 350 PSI 10.5 ppg EMW.;NB-Sand base at 12,818’ MD targeted 87.5°, then 86.5°. Drop to 78° aggressively to drill down through the underlying NC-Sand. NC Sand top at 13,010' MD. Geologist calling TD 13,130' MD.;Distance to WP #08: 68.54', 68.24' Low, 6.47' Right.;Encountered Fault 1 at 7,311' MD 49' DTN. Fault 2 at 8,965' MD 42' DTS. 96 concretions drilled this lateral, total footage of 554’ (6.9% of the lateral). 6,339' drilled in NB Sand, Total out of zone 1,481'.;Daily fluid hauled to G&I 633 bbls total = 9,707 bbls Daily metal recovered 0 lbs, total = 15 lbs Daily water hauled from L Pad Lake 910 bbls total = 9,050 bbls Daily Fluid lost 90 bbls total fluid lost lateral hole =90 bbls total fluid lost surface hole = 36 bbls 5/16/2020 PJSM Obtain final survey at TD 13,130' MD. Send Geo Pilot to home. Rot & Rec F/ 13,130' to 13,090' MD. 550 GPM/ MPD 529 GPM, 2,485 PSI, 120 RPM, TRQ 19K, Max Gas 1,190U U, ECD 11.45, P/U 175K SLK 35K ROT 99K. Distance to WP #08: 68.54', 68.24' Low, 6.47' Right.;Pump 40 bbl low 32 vis WT 8.7 ppg, 40 bbl 252 vis WT 10.0 ppg sweeps. Sweeps bacl 25 bbl late W/ Inc 10%. CBU 5X. Parameters prior to displacement 550 GPM, 2,420 PSI, 120 RPM, TRQ 18K, P/U 180K, SLK 35K ROT 98K. SIMOPS Clean Pits and build SAPP pills.;PJSM Cont Rot Rec F/ 13,130' to 13,090' MD. Perform displacement. Pump 40 bbls SAPP Pill, 20 bbl 9.3 ppg Quickdril 3X Chase W/ 9.3 ppg Quickdril at 10 bpm, 1,300 PSI. Parameters after Dis 420 GPM, 1,300 PSI, 110 RPM TRQ 18K, ECD 10.6, P/U 178K SLK 35K ROT 103K. Max Gas 199U. Monitor well, static.;SIMOPS Clean Pits. SPR at 13,130' MD (4,001' TVD) MW 9.3 ppg MP #1 32-245, 48-305. MP #2 32-240, 48-300.;PJSM BROOH F/ 13,130' to 12,065' MD 550-500 GPM/ MPD 480, 2,950 PSI, 110-120 RPM, TRQ 15-20K, Max Gas 504U. ECD 10.9. P/U 175K SLK 35K ROT 98K. Pull speed 10-20 Ft/min. Dropped 2.4" OD Rabbit on 1' of wire. Slowed pump rate to 450 GPM F/ 12,400 to 12,300' MD due loss zone, dynamic lost 30 bbls.;BROOH F/ 12,065' to 10,211' MD 500 GPM/ MPD 480, 1,500 PSI, 120 RPM, TRQ 13-16K, Max Gas 504U. BGG 100U ECD 10.7. P/U 157K SLK 58K ROT 100K. Pull speed 10-30 Ft/min as hole dictates. No losses to formation.;BROOH F/ 10,211' to 8,985' MD 500 GPM/ MPD 480, 1,568 PSI, 120 RPM, TRQ 12-15K, Max Gas 715U. BGG 165U ECD 10.88. P/U 152K SLK 52K ROT 100K. Pull speed 10-30 Ft/min as hole dictates.;Encountered tight hole and slight pack offs F/ 9,430' to 9,260' MD NB Clay. And F/ 9,200' to 9,000' MD NC Clay pull speed 2-3 ft min. Over pull 15K W/ 10K drag. Same parameters.;Daily fluid hauled to G&I 1,954 bbls total = 11,661 bbls Daily metal recovered 0 lbs, total = 15 lbs Daily water hauled from L Pad Lake 650 bbls total = 9,700 bbls Daily Fluid lost 30 bbls total fluid lost lateral hole =120 bbls total fluid lost surface hole = 36 bbls 5/17/2020 BROOH F/ 8,985' to 7,396' MD 525 GPM/ MPD 505, 1,634 PSI, 120 RPM, TRQ 7-10K, Max Gas 1,308U. BGG 165U ECD 10.66. P/U 150K SLK 73K ROT 107K. Pull speed 10-30 Ft/min as hole dictates.;At 8,000' MD hole unloaded blinding of shakers W/ sand and 1,308U of Gas. Encountered tight hole & slight packing off F/ 7,800' to 7,400' MD Pull speed 3-8 ft/min W/ 5-10K drag in NA Clay. Lost 15 bbls for tour.;BROOH F/ 7,396' to 5,043' MD 525 GPM/ MPD 500, 1,420 PSI, 120 RPM, TRQ 4-6K, Max Gas 475U. BGG 60U ECD 10.3. P/U 120K SLK 90K ROT 103K. Pull speed 10-30 Ft/min as hole dictates. Pull F/ 5,043' to 4,980' W/out rotary W/ no issues going through Shoe 5,009' MD.;PJSM Rot & Rec F/ 4,980' to 4,916' MD 500 GPM/MPD 490, 1,325 PSI, 50 RPM, TRQ 4K, ECD 10.1, Max Gas 8U. P/U 120 SLK 90 ROT 103K. CBU 2X Pump 40 bbl Hi 300+ Vis sweep on time W/ 10% inc sand. Dynamic loss 24 bbls for trip.;PJSM Service rig. Grease Crown, Top Drive, Iron Roughneck and Drawworks. SIMOPS Bring trip nipple to rig floor. Prep for RCD Bearing. Monitor well through MPD, no Press build.;PJSM Break RCD clamp and remove RCD bearing as per Beyond rep onsite. Remove RCD bearing from stand and L/D. Install trip nipple. Blow down Beyond hard lines and Geo Span.;PJSM Monitor well 10 min, slight static loss rate ~3-4 bph. Pump 20 bbl 10.3 Dry Job. Blow down Top Drive. POOH L/D 5" D.P. F/ 4,916' to 211' MD. Cull Cat 5 inspection as per tally. 21 bbls lost.;PJSM L/D 5" HWDP, Jars, FC. Recovered corrosion ring and rabbit on Float Sub. Plug in and download MWD. Cont. L/D TM/DM, HICM, Geo Pilot and Bit. Cut groove about 1/8" on DM, ADR ILS had heavy wear. Bit Grade 5-6-BT-A-X-I-MC-TD.;PJSM Clean and clear rig floor. R/U Weatherford tons and Equip. C/O Elevators. Bring up 183 stop rings and 7" Centralizers. Static loss rate ~4 BPH.;Daily fluid hauled to G&I 285 bbls total = 11,946 bbls Daily metal recovered 8 lbs, total = 23 lbs Daily water hauled from L Pad Lake 260 bbls total = 9,960 bbls Daily Fluid lost 39 bbls total fluid lost lateral hole =159 bbls total fluid lost surface hole = 36 bbls 5/18/2020 PJSM Cont R/U Weatherford tongs and handling Equip. R/U fill up hose. Static loss rate 4 bph.;PJSM P/U Non ported shoe and RIH 4.5" 13.5# L-80 W625 Liner to 3,972' MD as per tally. Install stop ring (no screws) and 7" Centralizer every Jnt. TRQ 9.6K. Top off every 10 jnts. P/U 77K SLK 74K. Lost 17 bbls.;PJSM Cont RIH 4.5" 13.5# L-80 W625 Liner F/ 3,972' to 8,015' MD as per tally. Install stop ring (no screws) and 7" Centralizer every Jnt. TRQ 9.6K. Top off every 10 jnts. P/U 82K SLK 72K. Lost 8.8 bbls. Ran 185 Stop rings and 7" Centralizers, 10 ICD's and 12 SP as per tally.;PJSM P/U M/U 9 5/8" SLZXP Packer as per Baker Rep onsite F/ 8,015' to 8,052' MD. Install 2 3/8" Shear and ball seat assy shear 6 pin 4,800 psi. SLZXP 8 ea 1/2" screws shear 2,648 PSI, Neutralizer 14 ea 1/2" screws shear 4,186 PSI. ROT 10 RPM TRQ 4.2K, 15 RPM TRQ 5.5K.;PJSM Convey 4.5" liner and SLZXP W/ 24 stands 5" D.P. F/ Derrick F/ 8,052' to 9,578' MD. Filling every stand. Work tight spot at 8,626' MD. Tag up at 9,537'MD SP # at Fault #2 (8,965" MD). Work string W/ 10 RPM, (Limit 10K) TRQ 5.5K P/U 116K SLK 60K ROT 100K.;Work up/down W/ rotary and 37K block weight W/O stalls. Was able to pass. Cont RIH W/ elevators F/ 9,582' MD. Run speed 30-50 ft/min. Topping off every stand. Loss rate 4-5 bph. Lost 10.8 bbls.;PJSM Cont convey 4.5" Liner on 5" HWDP F/ skate on elevators F/ 9,578' to 11,987' MD. P/U 198K SLK 118K Fill every jnt. W ork tight spot at 10,122' MD. (OD 2.75" drift) Tag up at 11,196' work tight spot P/U 172 SLK 110K. Lost 13.4 bbls. Static loss ~4 bph.;Tagged up at 11,444' MD worked W/out Rot, work W/ ROT 10 RPM TRQ 8.1K (Limit 12K) no stalls setting down to block wt 37K P/U 180K SLK 110K ROT 145K Cont W/ elevators F/ 11,450' MD.;PJSM Cont convey 4.5" Liner on 5" HWDP F/ skate on elevators F/ 11,987' to 12,865' MD. P/U 218K SLK 108K Fill every jnt. Work tight spots W/ out rotation at 12,643', 12,723' & 12,813' MD. (OD 2.75" drift) Lost 4.2 bbls. Static loss ~4 bph.;P/U Working single at 12,849' and slack to 12,880' MD. P/U 15' and break Circ 1 bpm 180 PSI 2 bpm 300 PSI 3 bpm 475 PSI. Total 185 ea stop rings and 7" Centralizers.;Drop 29/32 Phenolic ball as per Baker rep onsite. Pump down at 2 bpm ICP 294 PSI FCP 300 PSI caught Press at 747 stks 46 bbls, 10 bbls early. Cont to Press up to 3,000 PSI, Packer set at 2,450 PSI. Hold 3,000 PSI 5 min. SLK off 68K 40K string wt. Swap to test pump and Press up to 4,400 PSI;shift Neutralizer and release HST. P/U to string wt 184K. Press bled to 1,200 PSI after Neutralizer shifted. Bled off Press and pumped 1 bbl to ensure Circ sub shifted open, good.. R/U and test ZLXP W/ 1,500 PSI for 10 min. Pumped 1.67 bbl, bled 1.63 bbl. TOL at 4,823' MD.;PJSM L/D 2 jnts F/ 4,823' to 4,766' MD. CBU 1.5X 10 bpm 840 PSI FO 53% Gas 2U. Monitor well for 10 min, static.;PJSM Pump Dry Job and blow down. Install stripping rubber and air slips. POOH L/D 5" HWDP F/ 4,766' to 4,243' MD. P/U 169K SLK 160K Cull CAT 5 inspection as per tally. No losses.;Daily fluid hauled to G&I 45 bbls total = 11,991 bbls Daily metal recovered 0 lbs, total = 23 lbs Daily water hauled from L Pad Lake 0 bbls total = 9,960 bbls Daily Fluid lost 72 bbls total fluid lost lateral hole =231 bbls total fluid lost surface hole = 36 bbls Activity Date Ops Summary 5/19/2020 Continue POOH laying down NC50 5" drill pipe w/ LRT F/ 4243' to surface. L/D and inspect LRT. Circ sub and rupture disc both open. 8.5 bbl loss for trip. 70k up/dn.,PJSM, Grease and inspect top drive, blocks and crown cluster.,M/U 3.5" stinger w/ 8.40" NoGo assy (30.71' total length). Trip in hole w/ 5" NC-50, 19.5#, S-135 out of derrick to 4799' MD. Wash down @ 6 bpm F/ 4799' to tag depth of 4826' (DP tally). P/U and wash clear top of liner @ 10 bpm, 350 psi.,Monitor well (static). Pump slug, B/D TDS. Install stripping rubber and air slips. POOH laying down 5" F/ 4826' to 984' MD. Trip back in hole with remaining 5" out of derrick to 2891' MD.,POOH 5" D.P. L/D to Pipe Shed F/ 2,891' to surface. L/D 3.5" NoGo stinger. Cull pipe CAT 5 inspection.,PJSM M/U Running tool and pull Wear Ring. L/D Running tool and jnt.,PJSM P/U M/U Weatherford tongs and Equip to rig floor. Load Baker Seal Assy in Pipe Shed. C/O Elevators to 3.5". Lost 22 bbls for tour.,PJSM Cont R/U Weatherford tongs. P/U 170 Cannon Clamps, Centrilift job box, Tec spooler and sheave. Hang sheave on ODS W/ tugger and tie back in Derrick.,PJSM M/U Baker Seal Assy and RIH W/ 3.5" 9.3# L-80 EUE F/ 834' to 3,987' MD. M/U 2.75" XN Nipple Assy and Zenith G6 Gauge Mandrel at 834' MD. Centrilift install Zenith Gauge and 1/4" Tec Wire and senor test line. Cont RIH W/ 3.5" Tubing Testing Tec every 1,000' MD. TRQ 8rd EUE to 3.2K.,Daily fluid hauled to G&I 57 bbls total = 12,048 bbls Daily metal recovered 0 lbs, total = 23 lbs Daily water hauled from L Pad Lake 0 bbls total = 9,960 bbls Daily Fluid lost 52 bbls total fluid lost lateral hole =283 bbls total fluid lost surface hole = 36 bbls 5/20/2020 Slack off tagging NoGo @ 4837.16' (seal depth / TOL @ 4827.58'). P/T IA to 500 psi w/ 5 min hold (test good). Bleed off psi and L/D jts #155-#153. M/U spaceout pups 10.15', 4.08' & 2.09' (btm pup). P/U jt # 153. M/U hanger, terminate tech wire. Landout on hanger w/ BPV installed (24' RKB/ULDS) w/ 27k string wt on wellhead and 1.45' off NoGo / TOL.,P/U 4.5' to clear wellhead w/ hanger. Close annular w/ 550 psi. PSI up to 500 psi on IA (seals engaged and holding psi). Bleed down to 250 psi and strip up 6' to establish communication between tbg/IA via 1" ports on bullet seal assy.,Displace wellbore to 9.3 ppg CI brine (184 bbls), 140 bbls diesel, 26 bbls 9.3 brine (displace 123 bbls diesel into IA, 17 bbls diesel left in tubing). Displaced at 3 bpm, 170 psi ICP, 150 FCP.,S/O and landout hanger on depth. RILDS. Demob running equipment from floor. B/O and L/D landing jt and XO.,R/U on IA with test equipment. P/T IA to 2500 psi w/ 30 min hold. Chart and record same. MIT witness waived by Adam Earl (AOGCC rep). 3 bbls pumped, 3 bbls bled back. 2540 initial psi, 2510 psi @ 15 min, 2500 psi @ 30 min. R/D test equipment and B/D lines.,PJSM Flush Kelly hose, Kill, Choke lines and Choke manifold W/ H2O. Blow down.,PJSM Remove riser and L/D. Install air boot saver. Remove split bushing and master bushing. R/D Kill & Choke lines. Suspend RCD W/ block slings. N/D BOP and secure to pedestal. Remove DSA 11 X 13 5/8". INstall CTS on BPV. Bring Tree into cellar. SIMOPS Clean Pits, Check tire Press and move Break Shack and Enviro Vac.,PJSM Install Cameron FL Tree. Test void to 500 PSI low 5 min and 5,000 PSI high 10 min. SIMOPS Cont Pit cleaning. Inspect fluid end on MP 1 & 2. C/O Pony Rod seals on MP #1. Prep pad for rig move. Clean and organize cellar. Baker Centrilift terminate and tested Tec line. ITP 1,500.76, DCP 1,534.54, ITT 75°, DT 74.8°. Vibs 0, Current 21.0. RIG Released at 02:30,PJSM Cont pit cleaning. C/O Pony Rod seals on MP #2. Prep I-36 area around cellar. Prep Pipe Shed for rig move. Bridle up. Blow down H2O and disconnect air. Disconnect inner connects. Scope down Derrick. SIMOPS Tested Tree 250 low 5 min, 5,000 high 15 min, good. Pull CTS F/ BPV.,Daily fluid hauled to G&I 611 bbls total = 12,659 bbls Daily metal recovered 0 lbs, total = 23 lbs Daily water hauled from L Pad Lake 0 bbls total = 9,960 bbls Daily Fluid lost 20 bbls total fluid lost lateral hole =303 bbls total fluid lost surface hole = 36 bbls n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: MP I-35 Milne Point Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2011149C MPU I-35 Completion Spud Date: 19 May, 2020 Milne Point M Pt I Pad MPU I-35i 500292367500 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-35i MPU I-35i Survey Calculation Method:Minimum Curvature MPU I-35i Actual RKB @ 60.35usft Design:MPU I-35i Database:NORTH US + CANADA MD Reference:MPU I-35i Actual RKB @ 60.35usft North Reference: Well MPU I-35i True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: MPU I-35i, Slot I-22 usft usft 0.00 0.00 6,009,439.12 551,803.68 33.60Wellhead Elevation:33.60 usft0.50 70° 26' 11.515 N 149° 34' 39.490 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU I-35i Model NameMagnetics IFR 5/13/2020 15.94 80.88 57,380.00000000 Phase:Version: Audit Notes: Design MPU I-35i 1.0 ACTUAL Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:26.75 3.500.000.0026.75 From (usft) Survey Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 5/19/2020 Survey Date 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa234.19 4,979.28 MPU I-35i MWD+IFR2+MS+Sag (1) (MP 04/28/2020 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa5,034.45 13,047.22 MPU I-35i MWD+IFR2+MS+Sag (2) (MP 05/13/2020 MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 26.75 0.00 0.00 26.75 0.00 0.00-33.60 6,009,439.12 551,803.68 0.00 0.00 UNDEFINED 234.19 0.65 94.15 234.19 -0.09 1.17173.84 6,009,439.04 551,804.85 0.31 -0.01 3_MWD+IFR2+MS+Sag (1) 298.61 0.34 110.47 298.60 -0.18 1.72238.25 6,009,438.95 551,805.40 0.52 -0.07 3_MWD+IFR2+MS+Sag (1) 360.88 0.72 111.00 360.87 -0.38 2.26300.52 6,009,438.75 551,805.94 0.61 -0.24 3_MWD+IFR2+MS+Sag (1) 422.32 0.49 74.67 422.31 -0.45 2.87361.96 6,009,438.69 551,806.55 0.71 -0.28 3_MWD+IFR2+MS+Sag (1) 449.34 0.56 115.56 449.33 -0.48 3.10388.98 6,009,438.66 551,806.78 1.38 -0.29 3_MWD+IFR2+MS+Sag (1) 511.40 0.37 115.03 511.38 -0.69 3.55451.03 6,009,438.45 551,807.24 0.31 -0.48 3_MWD+IFR2+MS+Sag (1) 573.85 0.39 114.07 573.83 -0.87 3.93513.48 6,009,438.28 551,807.62 0.03 -0.62 3_MWD+IFR2+MS+Sag (1) 635.95 0.31 131.25 635.93 -1.06 4.25575.58 6,009,438.09 551,807.94 0.21 -0.80 3_MWD+IFR2+MS+Sag (1) 698.19 0.66 127.05 698.17 -1.39 4.66637.82 6,009,437.76 551,808.35 0.56 -1.10 3_MWD+IFR2+MS+Sag (1) 762.18 0.81 147.56 762.15 -1.99 5.20701.80 6,009,437.16 551,808.89 0.47 -1.67 3_MWD+IFR2+MS+Sag (1) 825.95 0.89 142.31 825.92 -2.77 5.74765.57 6,009,436.39 551,809.44 0.17 -2.41 3_MWD+IFR2+MS+Sag (1) 890.62 0.87 135.87 890.58 -3.52 6.39830.23 6,009,435.65 551,810.10 0.16 -3.12 3_MWD+IFR2+MS+Sag (1) 5/19/2020 11:33:26AM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-35i MPU I-35i Survey Calculation Method:Minimum Curvature MPU I-35i Actual RKB @ 60.35usft Design:MPU I-35i Database:NORTH US + CANADA MD Reference:MPU I-35i Actual RKB @ 60.35usft North Reference: Well MPU I-35i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 952.76 1.72 210.79 952.71 -4.66 6.25892.36 6,009,434.51 551,809.96 2.76 -4.27 3_MWD+IFR2+MS+Sag (1) 1,015.53 2.67 214.04 1,015.43 -6.68 4.94955.08 6,009,432.48 551,808.67 1.53 -6.36 3_MWD+IFR2+MS+Sag (1) 1,076.17 4.07 233.11 1,075.97 -9.14 2.431,015.62 6,009,430.00 551,806.18 2.93 -8.97 3_MWD+IFR2+MS+Sag (1) 1,144.14 5.91 235.99 1,143.67 -12.54 -2.401,083.32 6,009,426.56 551,801.37 2.73 -12.67 3_MWD+IFR2+MS+Sag (1) 1,207.96 7.82 238.13 1,207.03 -16.68 -8.811,146.68 6,009,422.39 551,794.99 3.02 -17.18 3_MWD+IFR2+MS+Sag (1) 1,271.70 10.56 240.34 1,269.95 -21.86 -17.571,209.60 6,009,417.14 551,786.26 4.33 -22.89 3_MWD+IFR2+MS+Sag (1) 1,334.94 13.57 246.60 1,331.79 -27.67 -29.421,271.44 6,009,411.25 551,774.46 5.18 -29.42 3_MWD+IFR2+MS+Sag (1) 1,396.93 13.47 247.95 1,392.06 -33.27 -42.781,331.71 6,009,405.56 551,761.13 0.53 -35.82 3_MWD+IFR2+MS+Sag (1) 1,461.74 13.19 252.51 1,455.13 -38.33 -56.831,394.78 6,009,400.40 551,747.12 1.68 -41.72 3_MWD+IFR2+MS+Sag (1) 1,525.87 12.99 252.70 1,517.59 -42.67 -70.691,457.24 6,009,395.97 551,733.29 0.32 -46.90 3_MWD+IFR2+MS+Sag (1) 1,589.40 13.73 259.67 1,579.40 -46.14 -84.931,519.05 6,009,392.39 551,719.08 2.79 -51.24 3_MWD+IFR2+MS+Sag (1) 1,651.31 14.19 262.85 1,639.49 -48.41 -99.681,579.14 6,009,390.03 551,704.34 1.44 -54.40 3_MWD+IFR2+MS+Sag (1) 1,716.14 13.52 263.34 1,702.43 -50.27 -115.101,642.08 6,009,388.05 551,688.95 1.05 -57.21 3_MWD+IFR2+MS+Sag (1) 1,779.92 12.90 263.97 1,764.52 -51.89 -129.581,704.17 6,009,386.34 551,674.47 1.00 -59.70 3_MWD+IFR2+MS+Sag (1) 1,843.43 12.75 264.45 1,826.45 -53.31 -143.611,766.10 6,009,384.82 551,660.46 0.29 -61.98 3_MWD+IFR2+MS+Sag (1) 1,907.18 12.67 265.12 1,888.64 -54.58 -157.571,828.29 6,009,383.45 551,646.50 0.26 -64.10 3_MWD+IFR2+MS+Sag (1) 1,970.89 12.84 264.99 1,950.77 -55.80 -171.591,890.42 6,009,382.14 551,632.50 0.27 -66.17 3_MWD+IFR2+MS+Sag (1) 2,033.94 12.81 265.45 2,012.25 -56.96 -185.541,951.90 6,009,380.87 551,618.56 0.17 -68.18 3_MWD+IFR2+MS+Sag (1) 2,097.98 13.09 265.01 2,074.66 -58.16 -199.842,014.31 6,009,379.58 551,604.27 0.46 -70.25 3_MWD+IFR2+MS+Sag (1) 2,160.90 13.51 266.22 2,135.89 -59.26 -214.272,075.54 6,009,378.38 551,589.85 0.80 -72.23 3_MWD+IFR2+MS+Sag (1) 2,224.94 13.53 267.50 2,198.16 -60.08 -229.222,137.81 6,009,377.45 551,574.91 0.47 -73.96 3_MWD+IFR2+MS+Sag (1) 2,288.60 12.01 271.39 2,260.24 -60.25 -243.282,199.89 6,009,377.19 551,560.85 2.74 -74.99 3_MWD+IFR2+MS+Sag (1) 2,352.16 11.86 270.85 2,322.43 -59.99 -256.422,262.08 6,009,377.36 551,547.71 0.29 -75.53 3_MWD+IFR2+MS+Sag (1) 2,415.74 11.72 278.60 2,384.67 -58.93 -269.342,324.32 6,009,378.33 551,534.78 2.50 -75.26 3_MWD+IFR2+MS+Sag (1) 2,478.43 12.25 285.71 2,446.00 -56.17 -282.042,385.65 6,009,381.00 551,522.07 2.50 -73.29 3_MWD+IFR2+MS+Sag (1) 2,541.93 13.19 293.67 2,507.95 -51.44 -295.162,447.60 6,009,385.64 551,508.91 3.13 -69.36 3_MWD+IFR2+MS+Sag (1) 2,605.61 14.73 303.13 2,569.75 -44.10 -308.602,509.40 6,009,392.89 551,495.43 4.32 -62.85 3_MWD+IFR2+MS+Sag (1) 2,668.88 16.20 309.93 2,630.73 -34.03 -322.102,570.38 6,009,402.85 551,481.85 3.69 -53.63 3_MWD+IFR2+MS+Sag (1) 2,732.88 17.56 317.08 2,691.98 -21.23 -335.522,631.63 6,009,415.56 551,468.34 3.87 -41.68 3_MWD+IFR2+MS+Sag (1) 2,796.08 18.48 326.80 2,752.09 -5.87 -347.502,691.74 6,009,430.84 551,456.26 4.97 -27.07 3_MWD+IFR2+MS+Sag (1) 2,860.41 21.08 333.43 2,812.63 13.02 -358.262,752.28 6,009,449.65 551,445.37 5.33 -8.88 3_MWD+IFR2+MS+Sag (1) 2,923.73 23.94 338.35 2,871.13 35.15 -368.102,810.78 6,009,471.71 551,435.38 5.40 12.61 3_MWD+IFR2+MS+Sag (1) 2,986.94 25.59 341.52 2,928.52 60.02 -377.162,868.17 6,009,496.51 551,426.15 3.35 36.88 3_MWD+IFR2+MS+Sag (1) 3,050.25 26.88 344.48 2,985.31 86.78 -385.322,924.96 6,009,523.21 551,417.80 2.90 63.10 3_MWD+IFR2+MS+Sag (1) 3,114.19 28.97 346.60 3,041.81 115.78 -392.782,981.46 6,009,552.15 551,410.14 3.62 91.58 3_MWD+IFR2+MS+Sag (1) 3,177.50 30.42 349.26 3,096.80 146.44 -399.323,036.45 6,009,582.77 551,403.39 3.09 121.79 3_MWD+IFR2+MS+Sag (1) 3,241.29 31.27 351.23 3,151.57 178.67 -404.863,091.22 6,009,614.96 551,397.63 2.07 153.62 3_MWD+IFR2+MS+Sag (1) 3,305.14 33.56 352.34 3,205.47 212.54 -409.743,145.12 6,009,648.79 551,392.52 3.71 187.13 3_MWD+IFR2+MS+Sag (1) 3,369.20 36.72 352.67 3,257.85 249.10 -414.543,197.50 6,009,685.31 551,387.46 4.94 223.32 3_MWD+IFR2+MS+Sag (1) 3,432.19 38.59 352.35 3,307.72 287.25 -419.563,247.37 6,009,723.42 551,382.18 2.98 261.10 3_MWD+IFR2+MS+Sag (1) 5/19/2020 11:33:26AM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-35i MPU I-35i Survey Calculation Method:Minimum Curvature MPU I-35i Actual RKB @ 60.35usft Design:MPU I-35i Database:NORTH US + CANADA MD Reference:MPU I-35i Actual RKB @ 60.35usft North Reference: Well MPU I-35i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,495.81 40.49 352.74 3,356.78 327.40 -424.813,296.43 6,009,763.53 551,376.65 3.01 300.86 3_MWD+IFR2+MS+Sag (1) 3,559.78 44.15 354.04 3,404.07 370.18 -429.753,343.72 6,009,806.27 551,371.41 5.88 343.25 3_MWD+IFR2+MS+Sag (1) 3,623.39 45.97 354.52 3,449.00 414.98 -434.233,388.65 6,009,851.03 551,366.62 2.91 387.70 3_MWD+IFR2+MS+Sag (1) 3,687.05 48.96 355.90 3,492.03 461.72 -438.143,431.68 6,009,897.74 551,362.39 4.96 434.11 3_MWD+IFR2+MS+Sag (1) 3,750.52 52.84 356.58 3,532.05 510.86 -441.363,471.70 6,009,946.85 551,358.83 6.17 482.96 3_MWD+IFR2+MS+Sag (1) 3,813.96 55.55 357.78 3,569.16 562.24 -443.883,508.81 6,009,998.21 551,355.95 4.54 534.09 3_MWD+IFR2+MS+Sag (1) 3,877.44 56.94 358.05 3,604.44 614.98 -445.803,544.09 6,010,050.93 551,353.66 2.22 586.62 3_MWD+IFR2+MS+Sag (1) 3,941.10 58.60 359.12 3,638.39 668.81 -447.123,578.04 6,010,104.75 551,351.96 2.97 640.27 3_MWD+IFR2+MS+Sag (1) 4,004.53 62.62 359.45 3,669.51 724.07 -447.813,609.16 6,010,159.99 551,350.89 6.35 695.38 3_MWD+IFR2+MS+Sag (1) 4,068.09 66.94 0.05 3,696.58 781.55 -448.063,636.23 6,010,217.47 551,350.25 6.85 752.74 3_MWD+IFR2+MS+Sag (1) 4,131.55 70.78 0.84 3,719.47 840.73 -447.593,659.12 6,010,276.64 551,350.30 6.16 811.84 3_MWD+IFR2+MS+Sag (1) 4,193.10 72.48 2.33 3,738.87 899.12 -445.973,678.52 6,010,335.03 551,351.52 3.59 870.21 3_MWD+IFR2+MS+Sag (1) 4,257.28 76.41 3.26 3,756.07 960.86 -442.953,695.72 6,010,396.78 551,354.11 6.28 932.02 3_MWD+IFR2+MS+Sag (1) 4,322.87 79.76 3.10 3,769.61 1,024.93 -439.393,709.26 6,010,460.87 551,357.22 5.11 996.19 3_MWD+IFR2+MS+Sag (1) 4,386.10 82.47 3.51 3,779.38 1,087.29 -435.793,719.03 6,010,523.25 551,360.39 4.33 1,058.66 3_MWD+IFR2+MS+Sag (1) 4,449.94 82.93 3.97 3,787.49 1,150.48 -431.663,727.14 6,010,586.46 551,364.08 1.01 1,121.98 3_MWD+IFR2+MS+Sag (1) 4,513.12 84.40 5.81 3,794.46 1,213.04 -426.313,734.11 6,010,649.05 551,369.00 3.71 1,184.75 3_MWD+IFR2+MS+Sag (1) 4,576.64 85.42 5.28 3,800.10 1,276.01 -420.193,739.75 6,010,712.06 551,374.67 1.81 1,247.98 3_MWD+IFR2+MS+Sag (1) 4,639.77 87.70 5.25 3,803.88 1,338.76 -414.413,743.53 6,010,774.83 551,380.02 3.61 1,310.96 3_MWD+IFR2+MS+Sag (1) 4,703.83 88.59 6.15 3,805.96 1,402.46 -408.053,745.61 6,010,838.58 551,385.94 1.98 1,374.94 3_MWD+IFR2+MS+Sag (1) 4,766.42 86.56 6.43 3,808.61 1,464.62 -401.203,748.26 6,010,900.77 551,392.35 3.27 1,437.39 3_MWD+IFR2+MS+Sag (1) 4,830.65 85.06 7.17 3,813.30 1,528.22 -393.623,752.95 6,010,964.42 551,399.49 2.60 1,501.34 3_MWD+IFR2+MS+Sag (1) 4,894.38 83.79 7.79 3,819.49 1,591.11 -385.363,759.14 6,011,027.36 551,407.31 2.22 1,564.62 3_MWD+IFR2+MS+Sag (1) 4,958.26 86.95 7.73 3,824.65 1,654.19 -376.773,764.30 6,011,090.49 551,415.47 4.95 1,628.10 3_MWD+IFR2+MS+Sag (1) 4,979.28 88.94 7.60 3,825.40 1,675.01 -373.963,765.05 6,011,111.33 551,418.13 9.49 1,649.05 3_MWD+IFR2+MS+Sag (1) 5,034.45 89.46 6.95 3,826.17 1,729.73 -366.983,765.82 6,011,166.09 551,424.73 1.51 1,704.10 3_MWD+IFR2+MS+Sag (2) 5,099.55 90.94 7.49 3,825.94 1,794.31 -358.803,765.59 6,011,230.72 551,432.46 2.42 1,769.06 3_MWD+IFR2+MS+Sag (2) 5,163.52 90.82 4.19 3,824.96 1,857.93 -352.293,764.61 6,011,294.38 551,438.53 5.16 1,832.96 3_MWD+IFR2+MS+Sag (2) 5,227.66 91.31 4.47 3,823.77 1,921.88 -347.453,763.42 6,011,358.35 551,442.93 0.88 1,897.08 3_MWD+IFR2+MS+Sag (2) 5,289.76 90.32 4.18 3,822.89 1,983.79 -342.773,762.54 6,011,420.29 551,447.18 1.66 1,959.17 3_MWD+IFR2+MS+Sag (2) 5,354.16 90.20 4.44 3,822.59 2,048.01 -337.933,762.24 6,011,484.54 551,451.57 0.44 2,023.56 3_MWD+IFR2+MS+Sag (2) 5,416.82 89.70 4.78 3,822.65 2,110.47 -332.893,762.30 6,011,547.02 551,456.17 0.96 2,086.21 3_MWD+IFR2+MS+Sag (2) 5,480.57 90.14 5.12 3,822.74 2,173.98 -327.393,762.39 6,011,610.56 551,461.23 0.87 2,149.94 3_MWD+IFR2+MS+Sag (2) 5,544.00 89.70 5.04 3,822.83 2,237.16 -321.773,762.48 6,011,673.77 551,466.41 0.71 2,213.34 3_MWD+IFR2+MS+Sag (2) 5,607.36 90.08 5.87 3,822.95 2,300.23 -315.753,762.60 6,011,736.88 551,471.99 1.44 2,276.67 3_MWD+IFR2+MS+Sag (2) 5,671.00 89.95 5.71 3,822.93 2,363.55 -309.333,762.58 6,011,800.23 551,477.97 0.32 2,340.26 3_MWD+IFR2+MS+Sag (2) 5,734.64 90.32 6.13 3,822.78 2,426.85 -302.773,762.43 6,011,863.57 551,484.10 0.88 2,403.84 3_MWD+IFR2+MS+Sag (2) 5,798.40 90.63 6.37 3,822.25 2,490.23 -295.823,761.90 6,011,926.99 551,490.60 0.61 2,467.52 3_MWD+IFR2+MS+Sag (2) 5,861.91 90.32 6.44 3,821.73 2,553.34 -288.743,761.38 6,011,990.14 551,497.24 0.50 2,530.95 3_MWD+IFR2+MS+Sag (2) 5,925.67 90.51 6.02 3,821.26 2,616.72 -281.823,760.91 6,012,053.57 551,503.72 0.72 2,594.63 3_MWD+IFR2+MS+Sag (2) 5/19/2020 11:33:26AM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-35i MPU I-35i Survey Calculation Method:Minimum Curvature MPU I-35i Actual RKB @ 60.35usft Design:MPU I-35i Database:NORTH US + CANADA MD Reference:MPU I-35i Actual RKB @ 60.35usft North Reference: Well MPU I-35i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 5,989.36 90.32 5.42 3,820.80 2,680.09 -275.473,760.45 6,012,116.97 551,509.63 0.99 2,658.27 3_MWD+IFR2+MS+Sag (2) 6,053.10 90.07 5.06 3,820.59 2,743.56 -269.653,760.24 6,012,180.48 551,515.01 0.69 2,721.98 3_MWD+IFR2+MS+Sag (2) 6,116.73 89.89 4.51 3,820.61 2,806.97 -264.343,760.26 6,012,243.92 551,519.87 0.91 2,785.60 3_MWD+IFR2+MS+Sag (2) 6,180.18 90.14 4.29 3,820.59 2,870.23 -259.483,760.24 6,012,307.20 551,524.30 0.52 2,849.04 3_MWD+IFR2+MS+Sag (2) 6,243.87 90.39 3.93 3,820.30 2,933.76 -254.913,759.95 6,012,370.75 551,528.42 0.69 2,912.73 3_MWD+IFR2+MS+Sag (2) 6,307.53 89.58 2.95 3,820.31 2,997.30 -251.093,759.96 6,012,434.32 551,531.80 2.00 2,976.38 3_MWD+IFR2+MS+Sag (2) 6,371.11 87.91 2.76 3,821.71 3,060.79 -247.933,761.36 6,012,497.82 551,534.53 2.64 3,039.94 3_MWD+IFR2+MS+Sag (2) 6,434.55 87.48 2.07 3,824.26 3,124.12 -245.253,763.91 6,012,561.16 551,536.76 1.28 3,103.32 3_MWD+IFR2+MS+Sag (2) 6,498.32 87.98 1.63 3,826.78 3,187.81 -243.203,766.43 6,012,624.85 551,538.37 1.04 3,167.01 3_MWD+IFR2+MS+Sag (2) 6,561.63 87.67 1.98 3,829.19 3,251.04 -241.203,768.84 6,012,688.09 551,539.92 0.74 3,230.25 3_MWD+IFR2+MS+Sag (2) 6,624.98 87.42 2.74 3,831.90 3,314.28 -238.603,771.55 6,012,751.34 551,542.09 1.26 3,293.53 3_MWD+IFR2+MS+Sag (2) 6,688.79 89.34 5.12 3,833.70 3,377.90 -234.233,773.35 6,012,814.99 551,546.02 4.79 3,357.30 3_MWD+IFR2+MS+Sag (2) 6,752.24 90.20 7.05 3,833.96 3,440.99 -227.503,773.61 6,012,878.11 551,552.31 3.33 3,420.68 3_MWD+IFR2+MS+Sag (2) 6,816.22 92.24 8.44 3,832.60 3,504.37 -218.883,772.25 6,012,941.54 551,560.48 3.86 3,484.47 3_MWD+IFR2+MS+Sag (2) 6,878.98 92.18 7.10 3,830.18 3,566.50 -210.403,769.83 6,013,003.73 551,568.53 2.14 3,547.01 3_MWD+IFR2+MS+Sag (2) 6,942.85 90.57 6.33 3,828.64 3,629.92 -202.943,768.29 6,013,067.19 551,575.56 2.79 3,610.76 3_MWD+IFR2+MS+Sag (2) 7,006.33 89.15 6.11 3,828.80 3,693.02 -196.063,768.45 6,013,130.33 551,581.99 2.26 3,674.16 3_MWD+IFR2+MS+Sag (2) 7,070.00 87.54 5.31 3,830.64 3,756.35 -189.733,770.29 6,013,193.69 551,587.89 2.82 3,737.76 3_MWD+IFR2+MS+Sag (2) 7,133.90 87.48 5.37 3,833.41 3,819.91 -183.793,773.06 6,013,257.29 551,593.38 0.13 3,801.56 3_MWD+IFR2+MS+Sag (2) 7,197.06 85.87 4.07 3,837.08 3,882.74 -178.603,776.73 6,013,320.15 551,598.14 3.27 3,864.60 3_MWD+IFR2+MS+Sag (2) 7,261.13 86.00 3.39 3,841.62 3,946.52 -174.443,781.27 6,013,383.95 551,601.85 1.08 3,928.51 3_MWD+IFR2+MS+Sag (2) 7,325.41 86.25 3.38 3,845.96 4,010.54 -170.653,785.61 6,013,447.99 551,605.19 0.39 3,992.64 3_MWD+IFR2+MS+Sag (2) 7,387.78 84.76 2.97 3,850.85 4,072.62 -167.213,790.50 6,013,510.08 551,608.20 2.48 4,054.82 3_MWD+IFR2+MS+Sag (2) 7,451.61 84.39 3.04 3,856.88 4,136.08 -163.883,796.53 6,013,573.56 551,611.09 0.59 4,118.36 3_MWD+IFR2+MS+Sag (2) 7,515.71 85.44 3.46 3,862.57 4,199.82 -160.263,802.22 6,013,637.32 551,614.27 1.76 4,182.20 3_MWD+IFR2+MS+Sag (2) 7,579.43 86.50 3.43 3,867.04 4,263.27 -156.443,806.69 6,013,700.78 551,617.65 1.66 4,245.76 3_MWD+IFR2+MS+Sag (2) 7,643.21 86.00 2.44 3,871.22 4,326.83 -153.183,810.87 6,013,764.36 551,620.47 1.74 4,309.40 3_MWD+IFR2+MS+Sag (2) 7,705.82 87.98 2.54 3,874.50 4,389.29 -150.463,814.15 6,013,826.83 551,622.75 3.17 4,371.91 3_MWD+IFR2+MS+Sag (2) 7,769.51 89.83 3.33 3,875.72 4,452.88 -147.203,815.37 6,013,890.44 551,625.57 3.16 4,435.59 3_MWD+IFR2+MS+Sag (2) 7,832.99 87.67 3.20 3,877.10 4,516.24 -143.593,816.75 6,013,953.81 551,628.74 3.41 4,499.05 3_MWD+IFR2+MS+Sag (2) 7,896.70 85.99 3.48 3,880.63 4,579.74 -139.883,820.28 6,014,017.33 551,632.00 2.67 4,562.66 3_MWD+IFR2+MS+Sag (2) 7,960.34 85.88 3.31 3,885.14 4,643.11 -136.123,824.79 6,014,080.72 551,635.32 0.32 4,626.14 3_MWD+IFR2+MS+Sag (2) 8,023.94 86.18 2.98 3,889.54 4,706.46 -132.643,829.19 6,014,144.09 551,638.36 0.70 4,689.58 3_MWD+IFR2+MS+Sag (2) 8,087.22 86.62 2.92 3,893.52 4,769.53 -129.393,833.17 6,014,207.17 551,641.18 0.70 4,752.73 3_MWD+IFR2+MS+Sag (2) 8,150.90 88.41 3.90 3,896.28 4,833.03 -125.613,835.93 6,014,270.70 551,644.52 3.20 4,816.35 3_MWD+IFR2+MS+Sag (2) 8,214.49 89.53 5.50 3,897.42 4,896.40 -120.403,837.07 6,014,334.09 551,649.29 3.07 4,879.91 3_MWD+IFR2+MS+Sag (2) 8,278.69 88.34 5.61 3,898.61 4,960.28 -114.193,838.26 6,014,398.01 551,655.06 1.86 4,944.06 3_MWD+IFR2+MS+Sag (2) 8,341.95 88.04 5.20 3,900.61 5,023.23 -108.233,840.26 6,014,460.99 551,660.57 0.80 5,007.25 3_MWD+IFR2+MS+Sag (2) 8,405.34 87.05 4.61 3,903.33 5,086.33 -102.823,842.98 6,014,524.12 551,665.55 1.82 5,070.57 3_MWD+IFR2+MS+Sag (2) 8,468.94 87.24 4.73 3,906.49 5,149.64 -97.643,846.14 6,014,587.46 551,670.28 0.35 5,134.07 3_MWD+IFR2+MS+Sag (2) 5/19/2020 11:33:26AM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-35i MPU I-35i Survey Calculation Method:Minimum Curvature MPU I-35i Actual RKB @ 60.35usft Design:MPU I-35i Database:NORTH US + CANADA MD Reference:MPU I-35i Actual RKB @ 60.35usft North Reference: Well MPU I-35i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 8,532.64 89.65 5.15 3,908.22 5,213.07 -92.163,847.87 6,014,650.92 551,675.32 3.84 5,197.72 3_MWD+IFR2+MS+Sag (2) 8,596.29 88.10 4.65 3,909.47 5,276.48 -86.723,849.12 6,014,714.36 551,680.32 2.56 5,261.34 3_MWD+IFR2+MS+Sag (2) 8,659.96 88.41 5.53 3,911.41 5,339.87 -81.083,851.06 6,014,777.78 551,685.52 1.46 5,324.96 3_MWD+IFR2+MS+Sag (2) 8,723.55 88.35 5.88 3,913.21 5,403.12 -74.763,852.86 6,014,841.06 551,691.40 0.56 5,388.47 3_MWD+IFR2+MS+Sag (2) 8,787.30 86.37 4.22 3,916.15 5,466.55 -69.153,855.80 6,014,904.52 551,696.57 4.05 5,452.13 3_MWD+IFR2+MS+Sag (2) 8,850.53 86.87 2.98 3,919.87 5,529.54 -65.193,859.52 6,014,967.54 551,700.09 2.11 5,515.25 3_MWD+IFR2+MS+Sag (2) 8,913.96 88.66 3.62 3,922.35 5,592.81 -61.543,862.00 6,015,030.83 551,703.30 3.00 5,578.62 3_MWD+IFR2+MS+Sag (2) 8,977.26 90.08 4.71 3,923.04 5,655.94 -56.953,862.69 6,015,093.98 551,707.46 2.83 5,641.91 3_MWD+IFR2+MS+Sag (2) 9,040.75 91.25 5.72 3,922.31 5,719.16 -51.183,861.96 6,015,157.23 551,712.79 2.43 5,705.37 3_MWD+IFR2+MS+Sag (2) 9,104.13 93.23 6.53 3,919.83 5,782.13 -44.423,859.48 6,015,220.24 551,719.11 3.37 5,768.63 3_MWD+IFR2+MS+Sag (2) 9,168.02 94.91 6.41 3,915.29 5,845.45 -37.243,854.94 6,015,283.60 551,725.85 2.64 5,832.27 3_MWD+IFR2+MS+Sag (2) 9,230.55 95.84 6.33 3,909.44 5,907.32 -30.333,849.09 6,015,345.51 551,732.32 1.49 5,894.45 3_MWD+IFR2+MS+Sag (2) 9,294.86 95.08 6.46 3,903.32 5,970.94 -23.203,842.97 6,015,409.17 551,739.01 1.20 5,958.38 3_MWD+IFR2+MS+Sag (2) 9,356.99 94.15 5.94 3,898.32 6,032.50 -16.513,837.97 6,015,470.78 551,745.27 1.71 6,020.24 3_MWD+IFR2+MS+Sag (2) 9,421.97 92.42 5.69 3,894.60 6,097.04 -9.943,834.25 6,015,535.35 551,751.39 2.69 6,085.06 3_MWD+IFR2+MS+Sag (2) 9,485.93 91.49 5.66 3,892.41 6,160.65 -3.623,832.06 6,015,599.00 551,757.27 1.45 6,148.94 3_MWD+IFR2+MS+Sag (2) 9,549.44 91.50 5.24 3,890.76 6,223.85 2.413,830.41 6,015,662.23 551,762.86 0.66 6,212.39 3_MWD+IFR2+MS+Sag (2) 9,612.98 90.01 5.00 3,889.92 6,287.13 8.083,829.57 6,015,725.54 551,768.09 2.38 6,275.90 3_MWD+IFR2+MS+Sag (2) 9,676.70 90.26 5.20 3,889.77 6,350.60 13.753,829.42 6,015,789.04 551,773.32 0.50 6,339.59 3_MWD+IFR2+MS+Sag (2) 9,740.56 89.83 5.67 3,889.72 6,414.17 19.793,829.37 6,015,852.65 551,778.92 1.00 6,403.41 3_MWD+IFR2+MS+Sag (2) 9,804.12 89.46 4.95 3,890.11 6,477.45 25.683,829.76 6,015,915.97 551,784.36 1.27 6,466.94 3_MWD+IFR2+MS+Sag (2) 9,867.69 89.64 5.54 3,890.61 6,540.76 31.493,830.26 6,015,979.30 551,789.73 0.97 6,530.48 3_MWD+IFR2+MS+Sag (2) 9,931.26 90.33 6.36 3,890.63 6,603.98 38.083,830.28 6,016,042.57 551,795.88 1.69 6,593.99 3_MWD+IFR2+MS+Sag (2) 9,995.00 89.02 5.17 3,890.99 6,667.40 44.483,830.64 6,016,106.02 551,801.85 2.78 6,657.68 3_MWD+IFR2+MS+Sag (2) 10,058.91 89.28 4.53 3,891.94 6,731.07 49.883,831.59 6,016,169.72 551,806.80 1.08 6,721.56 3_MWD+IFR2+MS+Sag (2) 10,122.74 88.34 4.39 3,893.26 6,794.69 54.843,832.91 6,016,233.37 551,811.32 1.49 6,785.37 3_MWD+IFR2+MS+Sag (2) 10,186.04 88.16 3.92 3,895.20 6,857.80 59.433,834.85 6,016,296.50 551,815.47 0.79 6,848.63 3_MWD+IFR2+MS+Sag (2) 10,249.40 88.97 4.02 3,896.78 6,920.98 63.813,836.43 6,016,359.71 551,819.42 1.29 6,911.97 3_MWD+IFR2+MS+Sag (2) 10,313.07 88.72 3.91 3,898.07 6,984.49 68.223,837.72 6,016,423.24 551,823.38 0.43 6,975.63 3_MWD+IFR2+MS+Sag (2) 10,376.88 87.73 3.46 3,900.04 7,048.14 72.313,839.69 6,016,486.90 551,827.03 1.70 7,039.40 3_MWD+IFR2+MS+Sag (2) 10,440.52 87.61 3.69 3,902.63 7,111.60 76.283,842.28 6,016,550.39 551,830.56 0.41 7,102.99 3_MWD+IFR2+MS+Sag (2) 10,504.02 86.86 2.99 3,905.69 7,174.92 79.973,845.34 6,016,613.72 551,833.81 1.61 7,166.42 3_MWD+IFR2+MS+Sag (2) 10,567.39 88.11 4.62 3,908.48 7,238.08 84.183,848.13 6,016,676.91 551,837.57 3.24 7,229.72 3_MWD+IFR2+MS+Sag (2) 10,630.27 87.61 5.17 3,910.82 7,300.69 89.543,850.47 6,016,739.55 551,842.50 1.18 7,292.54 3_MWD+IFR2+MS+Sag (2) 10,694.84 88.41 6.30 3,913.07 7,364.90 95.993,852.72 6,016,803.79 551,848.50 2.14 7,357.02 3_MWD+IFR2+MS+Sag (2) 10,758.04 88.47 6.57 3,914.79 7,427.67 103.073,854.44 6,016,866.61 551,855.15 0.44 7,420.11 3_MWD+IFR2+MS+Sag (2) 10,821.82 89.40 8.21 3,915.97 7,490.91 111.273,855.62 6,016,929.90 551,862.91 2.96 7,483.73 3_MWD+IFR2+MS+Sag (2) 10,882.69 88.72 8.55 3,916.97 7,551.12 120.143,856.62 6,016,990.16 551,871.36 1.25 7,544.37 3_MWD+IFR2+MS+Sag (2) 10,948.21 88.59 8.83 3,918.51 7,615.87 130.043,858.16 6,017,054.97 551,880.80 0.47 7,609.61 3_MWD+IFR2+MS+Sag (2) 11,012.03 89.89 9.28 3,919.35 7,678.89 140.083,859.00 6,017,118.05 551,890.41 2.16 7,673.12 3_MWD+IFR2+MS+Sag (2) 5/19/2020 11:33:26AM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Definitive Survey Report Well: Wellbore: MPU I-35i MPU I-35i Survey Calculation Method:Minimum Curvature MPU I-35i Actual RKB @ 60.35usft Design:MPU I-35i Database:NORTH US + CANADA MD Reference:MPU I-35i Actual RKB @ 60.35usft North Reference: Well MPU I-35i True MD (usft) Inc (°) Azi (°) +E/-W (usft) +N/-S (usft) Survey TVD (usft) TVDSS (usft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 11,075.19 89.15 10.03 3,919.88 7,741.15 150.673,859.53 6,017,180.38 551,900.57 1.67 7,735.91 3_MWD+IFR2+MS+Sag (2) 11,138.96 89.77 10.27 3,920.49 7,803.92 161.913,860.14 6,017,243.22 551,911.37 1.04 7,799.25 3_MWD+IFR2+MS+Sag (2) 11,202.39 90.33 9.27 3,920.43 7,866.43 172.673,860.08 6,017,305.80 551,921.69 1.81 7,862.30 3_MWD+IFR2+MS+Sag (2) 11,265.53 90.14 8.57 3,920.17 7,928.81 182.463,859.82 6,017,368.23 551,931.05 1.15 7,925.16 3_MWD+IFR2+MS+Sag (2) 11,330.50 88.47 7.69 3,920.96 7,993.11 191.653,860.61 6,017,432.60 551,939.79 2.91 7,989.91 3_MWD+IFR2+MS+Sag (2) 11,392.63 88.47 8.69 3,922.62 8,054.59 200.503,862.27 6,017,494.13 551,948.21 1.61 8,051.80 3_MWD+IFR2+MS+Sag (2) 11,456.80 88.23 9.10 3,924.47 8,117.96 210.413,864.12 6,017,557.56 551,957.69 0.74 8,115.66 3_MWD+IFR2+MS+Sag (2) 11,520.58 87.48 8.83 3,926.85 8,180.92 220.353,866.50 6,017,620.58 551,967.18 1.25 8,179.11 3_MWD+IFR2+MS+Sag (2) 11,583.87 86.74 8.20 3,930.04 8,243.43 229.713,869.69 6,017,683.15 551,976.10 1.53 8,242.08 3_MWD+IFR2+MS+Sag (2) 11,647.71 86.61 7.33 3,933.75 8,306.58 238.323,873.40 6,017,746.35 551,984.27 1.38 8,305.63 3_MWD+IFR2+MS+Sag (2) 11,710.98 88.35 6.81 3,936.53 8,369.30 246.103,876.18 6,017,809.12 551,991.62 2.87 8,368.71 3_MWD+IFR2+MS+Sag (2) 11,774.62 90.82 7.25 3,936.99 8,432.46 253.883,876.64 6,017,872.32 551,998.97 3.94 8,432.23 3_MWD+IFR2+MS+Sag (2) 11,838.29 92.18 7.39 3,935.32 8,495.58 261.993,874.97 6,017,935.50 552,006.64 2.15 8,495.73 3_MWD+IFR2+MS+Sag (2) 11,901.80 91.62 6.58 3,933.22 8,558.59 269.713,872.87 6,017,998.54 552,013.92 1.55 8,559.09 3_MWD+IFR2+MS+Sag (2) 11,965.89 88.65 5.58 3,933.07 8,622.31 276.503,872.72 6,018,062.31 552,020.26 4.89 8,623.11 3_MWD+IFR2+MS+Sag (2) 12,029.63 88.97 4.43 3,934.39 8,685.79 282.063,874.04 6,018,125.82 552,025.38 1.87 8,686.81 3_MWD+IFR2+MS+Sag (2) 12,093.21 88.10 4.90 3,936.01 8,749.14 287.233,875.66 6,018,189.19 552,030.11 1.56 8,750.35 3_MWD+IFR2+MS+Sag (2) 12,156.97 89.09 6.56 3,937.58 8,812.56 293.593,877.23 6,018,252.65 552,036.03 3.03 8,814.04 3_MWD+IFR2+MS+Sag (2) 12,220.31 90.89 8.40 3,937.59 8,875.35 301.843,877.24 6,018,315.50 552,043.84 4.06 8,877.23 3_MWD+IFR2+MS+Sag (2) 12,283.70 90.26 9.45 3,936.95 8,937.97 311.673,876.60 6,018,378.17 552,053.23 1.93 8,940.33 3_MWD+IFR2+MS+Sag (2) 12,347.04 89.46 10.23 3,937.11 9,000.38 322.493,876.76 6,018,440.65 552,063.62 1.76 9,003.28 3_MWD+IFR2+MS+Sag (2) 12,410.78 88.03 9.79 3,938.50 9,063.13 333.573,878.15 6,018,503.47 552,074.26 2.35 9,066.59 3_MWD+IFR2+MS+Sag (2) 12,474.40 89.28 9.69 3,940.00 9,125.82 344.333,879.65 6,018,566.22 552,084.59 1.97 9,129.82 3_MWD+IFR2+MS+Sag (2) 12,538.02 87.79 7.91 3,941.62 9,188.66 354.063,881.27 6,018,629.13 552,093.88 3.65 9,193.14 3_MWD+IFR2+MS+Sag (2) 12,601.46 88.29 7.70 3,943.79 9,251.48 362.673,883.44 6,018,692.00 552,102.05 0.85 9,256.36 3_MWD+IFR2+MS+Sag (2) 12,665.39 86.49 8.48 3,946.70 9,314.70 371.663,886.35 6,018,755.28 552,110.60 3.07 9,320.02 3_MWD+IFR2+MS+Sag (2) 12,727.98 85.56 7.70 3,951.04 9,376.52 380.443,890.69 6,018,817.15 552,118.95 1.94 9,382.26 3_MWD+IFR2+MS+Sag (2) 12,793.19 85.81 6.70 3,955.95 9,441.03 388.593,895.60 6,018,881.71 552,126.65 1.58 9,447.14 3_MWD+IFR2+MS+Sag (2) 12,856.84 86.32 6.22 3,960.32 9,504.13 395.743,899.97 6,018,944.85 552,133.36 1.10 9,510.56 3_MWD+IFR2+MS+Sag (2) 12,920.11 83.27 5.47 3,966.06 9,566.80 402.163,905.71 6,019,007.56 552,139.34 4.96 9,573.51 3_MWD+IFR2+MS+Sag (2) 12,984.14 81.53 6.59 3,974.53 9,629.91 408.823,914.18 6,019,070.71 552,145.57 3.22 9,636.91 3_MWD+IFR2+MS+Sag (2) 13,047.22 78.57 7.15 3,985.42 9,691.59 416.253,925.07 6,019,132.43 552,152.57 4.77 9,698.93 3_MWD+IFR2+MS+Sag (2) 13,130.00 78.57 7.15 4,001.83 9,772.10 426.353,941.48 6,019,213.00 552,162.11 0.00 9,779.90 PROJECTED to TD Approved By:Checked By:Date: 5/19/2020 11:33:26AM COMPASS 5000.15 Build 91E Page 7 Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.05.19 08:35:22 -08'00'Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.05.19 08:45:22 -08'00' TD Shoe Depth: PBTD: Jts. 2 1 1 46 X Yes No X Yes No 40 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type:Density (ppg)Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type:Density (ppg)Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe Cut Joint 10 3/4 40.0 L-80 247 -10273SECOND STAGERig 18:45 Returns Rotate Csg Recip Csg Ft. Min.PPG9.3 Shoe @ 5009 FC @ Top of Liner #N/A4,926.00 Floats Held 312.7 531 245 286 Spud Mud CASING RECORD County State Alaska Supv.J. Lott / C. Montague Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.MP I-35 Date Run 7-May-20 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top BTC Innovex 1.62 5,009.00 5,007.38 10.19 35.53 25.349 5/8 47.0 L-80 TXP Tenaris Csg Wt. On Hook:195 Type Float Collar:Conventional No. Hrs to Run:11.5 9.3 5 2000 10 10.7 238 5 100 680 Bump Plug?FIRST STAGE10Tuned Spacer 60 15.8 576 5 9.3 7 120/122 350/345.5 1180 45 Rig 15.8 82 Bump press Returns Bump Plug? Yes 9:00 5/8/2020 1,932 1932 5,009.005,019.00 CEMENTING REPORT Csg Wt. On Slips:115,000 Spud Mud Tuned Spacer 454 2.94 Stage Collar @ 60 Bump press 100 200 ES Cementer Closure OK 5208.34 56 12 155 Water Type of Shoe:Bullnose Casing Crew:Weatherford www.wellez.net WellEz Information Management LLC ver_04818br 5 208.34Water 4.7 Arctic Cem Type (2) on shoe joint; 1 every joint to 4013'; 1 every other joint from 4013' to 2270'; 1 every joint from 2153 to 1507 (5 below, 10 b ES t ) 1 th f 1507' t 117' Casing 9 5/8 40.0 L-80 TXP Tenaris 123.31 5,007.38 4,927.38 Float Collar 10 3/4 40.0 L-80 BTC Innovex 1.30 4,927.38 4,926.08 Casing 9 5/8 40.0 L-80 TXP Tenaris 40.16 4,926.08 4,885.92 Baffle Adapter 10 3/4 40.0 L-80 TXP HES 1.48 4,885.92 4,884.44 Casing 9 5/8 47.0 L-80 TXP Tenaris 2,932.00 4,884.44 1,952.44 Pup Joint 9 5/8 40.0 L-80 TXP Tenaris 16.76 1,952.44 1,935.68 ES Cementer 10 3/4 L-80 TXP Halliburton 2.85 1,935.68 1,932.84 Pup Joint 9 5/8 40.0 L-80 TXP Tenaris 14.95 1,932.84 1,917.89 Casing 9 5/8 47.0 L-80 TXP Tenaris 1,882.36 1,917.89 35.53 Type I/II 370 2.35 Class G 398 1.16 5 Class G 270 1.17 5/8/2020 27 Spud Mud CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU I-35 Date:5/11/2020 Csg Size/Wt/Grade:9.625 40#/47# L-80 Supervisor:Lott / Montague Csg Setting Depth:5,009 3,825 TVD Mud Weight:8.9 ppg LOT / FIT Press =630 psi LOT / FIT =12.07 ppg Hole Depth =5019 md Fluid Pumped=1.7 Bbls Volume Back =1.4 bbls Estimated Pump Output:0.062 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->2 11 ->0 0 ->4 17 ->10 58 ->6 44 ->20 406 ->8 93 ->30 735 ->10 163 ->40 1073 ->12 220 ->45 1257 ->14 292 ->50 1442 ->16 357 ->55 1632 ->18 414 ->60 1821 ->20 468 ->65 2008 ->22 516 ->70 2192 ->24 564 ->75 2399 ->26 601 ->80 2596 ->28 630 ->83 2697 Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 630 ->0 2692 ->1 586 ->1 2684 ->2 562 ->2 2682 ->3 542 ->3 2681 ->4 526 ->4 2679 ->5 512 ->5 2678 ->6498 ->10 2672 ->7486 ->15 2666 ->8476 ->20 2661 ->9468 ->25 2657 ->10 460 ->30 2654 -> -> -> -> -> -> 2 4 6 8 10 12 14 16 18 2022242628 0 10 20 30 40 45 50 55 60 65 70 75 80 83 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 0 102030405060708090Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 630586562542526512498486476468460 269226842682268126792678 2672 2666 2661 2657 2654 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 051015202530Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA ft— Zzoo-34c, Regg, James B (CED) From: Shane Barber - (C) <sbarber@hilcorp.com> , Z2 Sent: Thursday, May 21, 2020 5:03 PM To: Regg, James B (CED); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (CED); Wallace, Chris D (CED) Cc: Wyatt Rivard; Joseph Engel; Ian Toomey - (C); Oliver Amend - (C) Subject: MIT MPU 1-35 Attachments: MIT MPU 1-35 5-20-20.xlsx All, Please see attached MIT form. "Innovation rig", Hilcorp MPU 1-35. Thank you. Shane G. Barb r I Drilling Foreman LW Hilcorn Alaska. 1.1.(' Endicott / Milne Point Of5ce 907-670-3094 Mobile: 907-841-5208 sbarbcr(Uhi lcorp.com 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: ii m.regg(cbalaska.gov: AOGCC.lnspectors(cbalaska.gov: phoebe.brooks(cdalaska.gov OPERATOR: FIELD / UNIT! PAD: DATE: OPERATOR REP: AOGCC REP: Hilcorp Alaska, LLC Milne Point / I -Pad / 1-35 05/20/20 Shane Barber chris.wallaceO-alaska. goy ) ` 5-/ Z7'l ze" Well 1.35 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. S = Slurry PTD 220-034 Type Inj N Tubing 0 0 0 0 Form 10-426 (Revised 01/2017) Type Test P Packer TVD 3800 BBLPump 3.0 IA 0 2540 2510 2500 Interval I Test psi 2500 BBL Return 3.0 OA Result P Notes: Pre injection MIT -IA on rig. Witness waived by Adam Earl. Monobore completion, no OA Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBI -Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min, 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBI -Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type in Tubing Type Test Packer TVD BBL Pu IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I =. Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) MIT MPU 1-355-20-20 STATE OF ALASKA Reviewed By: J�j� OIL AND GAS CONSERVATION COMMISSION P.I. Supry BOPE Test Report for: MILNE PT UNIT I-35 Comm Contractor/Rig No.: Hilcorp Innovation PTD#: 2200340 DATE: 5/10/2020 Inspector Guy Cook ' Insp Source Operator: I-lilcorp Alaska, LLC Operator Rep: J. Lott/C. Monaque Rig Rep: M. Vanhoose/A. Leslie Inspector Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopGDC200510155432 Rams: Annular: Valves: MASP: Type Test: INIT 250/3000 ' 250/3000 250/3000 - 1361 1 Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: Upper Kelly 1 P/F Lower Kelly Visual Alarm Time/Pressure P/F Location Gen.: —P Trip Tank P P System Pressure 3000 P ' Housekeeping: P - Pit Level Indicators P P Pressure After Closure 1450 P PTD On Location P Flow Indicator P P 200 PSI Attained 20 P - Standing Order Posted P Meth Gas Detector P P Full Pressure Attained 96 - P ' Well Sign P H2S Gas Detector P--- P Blind Switch Covers: All Stations P - DO. Rig P_ -_ MS Misc NA NA Nitgn. Bottles (avg): 6@)_2308 - - P_ - -Hazard Hazard Sec. P ACC Misc 0 NA Mise NA FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly 1 P - Lower Kelly - 1 _ _ _ _ P Ball Type 2 P Inside BOP 1 P " FSV Mise 0 NA BOP STACK: Quantity Size P/F Stripper 0 NA Annular Preventer 1- 13 5/8 5000 - P #1 Rams 1 2 7/8"X5.5 V FP ✓ #2 Rams I Blinds P #3 Rams 1 - 2 7/8 X5.5 VB -P " #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 - 3 1/8" 5000 - P HCR Valves 2 3 1/8" 5000 - P Kill Line Valves 2 3 1/8" 5000 P Check Valve 0 NA BOP Misc 0 NA CHOKE MANIFOLD: Quantity P/F No. Valves 15 - FP Manual Chokes 1 _ P Hydraulic Chokes 1 P CH Mise 0 NA INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 NA Number of Failures: 2 ✓ Test Results Test Time 9.5 Remarks: 3.5 and 5" test joints were used for testing. Test #2 the upper pipe rams failed the intial on the 5" test _joint. Actuated the rams and retested for a fail. Pull and redress the rams and retest fora pass. On test #6 and #11 the pin was left down on the chart recorder and marked the chart when the rams were actuated for the next test. Test #7 the CMV #15 failed. The test continued after blocking off the leak with a 2" 1502 harding cap. The test was then redone as test and the valve passed. This was done for troubleshooting purposes to make sure the CMV #15 was the only leaking component. ✓ 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 Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-35 Hilcorp Alaska, LLC Permit to Drill Number: 220-034 Surface Location: 2322’FSL, 3567’FEL, SEC. 33, T13N, R10E, UM, AK Bottomhole Location: 2108’FNL, 2374’FWL, SEC. 21, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service 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, Jeremy M. Price Chair DATED this ___ day of April, 2020. Sincerely, Jeremy M Price 8 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2.Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3.Address: 6.Proposed Depth: 12.Field/Pool(s): MD:TVD: 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8.DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 15. Distance to Nearest Well Open Surface: x- y- Zone- to Same Pool: 16. Deviated wells: Kickoff depth: feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20.Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number: 50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 18. Casing Program: Top - Setting Depth - BottomSpecifications Total Depth MD (ft): Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) LengthCasing Effect. Depth MD (ft): Effect. Depth TVD (ft): Commission Use Only See cover letter for other requirements. Perforation Depth MD (ft): Authorized Title: Authorized Signature: 2.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): ions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane,gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No See cover letter for other requirements. Permit Approval Date: API Number: 50- to Drill er: Commission Use Only Contact Name: Contact Email: Contact Phone: Date: ized Name: ized Title: ized Signature: hereby certify that the foregoing is true and the procedure approved herein will not be ed from without prior wrritten approval. tachments: Property Plat BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements ulic Fracture planned?Yes No ation Depth MD (ft):Perforation Depth TVD (ft): TVDMDCementVolumeSizeLengthCasing Junk (measured):Effect. Depth TVD (ft):Effect. Depth MD (ft):Plugs (measured):Total Depth TVD (ft):l Depth MD (ft): PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)Y (including stage data)TVDMDTVDMDLengthCouplingGradeWeightCasinge Cement Quantity, c.f. or sacksTop - Setting Depth - BottomSpecificationssing Program: 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole:Surface: viated wells:Kickoff depth:feet Maximum Hole Angle:degrees 15. Distance to Nearest Well Open to Same Pool: 10. KB Elevation above MSL (ft):cation of Well (State Base Plane Coordinates - NAD 27): e: x- y-Zone- 14. Distance to Nearest Property: 7. Property Designation: 8.DNR Approval Number: 9. Acres in Property: ocation of Well (Governmental Section): e: Productive Horizon: Depth: 13. Approximate Spud Date: 12.Field/Pool(s):6.Proposed Depth: MD:TVD: ress: 11. Well Name and Number:5. Bond: Blanket Single Well Bond No. rator Name: 1c. Specify if well is proposed for: Coalbed Gas Gas Hydrates Geothermal Shale Gas 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp Stratigraphic Test Development - Oil Service - Winj Single Zone Exploratory - Oil Development - Gas Service - Supply Multiple Zone pe of Work: Lateral Reentry GL / BF Elevation above MSL (ft): Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Hilcorp Alaska, LLC 3800 Centerpoint Drive, St. 1400, Anchorage, AK 99503 2322' FSL, 3567' FEL, Sec 33, T13N, R10E, UM, AK 1557' FNL, 1314' FWL, Sec 33, T13N, R10E, UM, AK 2108' FNL, 2374' FWL, Sec 21, T13N, R10E, UM, AK 551803 6009438 4 022224484 14769 4005 ADL025906 / ADL315848 LONS 88-04 3840 60.10 33.6 MPU I-35 Milne Point Unit Schrader Bluff Oil Pool 04/13/2020 3723' to nearest unit boundary 50' to MPU J-01A 1000 91 1761 1361 Cond 20" 215#X-52 Weld 107' Surface Surface 107' 107' ±270 ft3 12-1/4" 9-5/8" 40#L-80 TXP 4,675' Surface Surface 4,675'3,825'Stg1 L - 478 ft3 / T - 458 ft3 Stg 2 L - 1937 ft3 / T - 314 ft3 8-1/2"4-1/2" 13.5#L-80 Hyd 625 10,244' 4,525' 3,811'14,769'4,005'Injection Liner w/ICDs & Swell Pkrs Tubing 3-1/2"9.3#L-80 EUE 8RD 4,525' Surface Surface 4,525'3,811'Tieback Monty Myers Drilling Manager Digitally signed by Monty Mack Myers DN: cn=Monty Mack Myers, ou=Users Reason: I am approving this document Date: 2020.04.01 09:18:49 -08'00' Monty Mack Myers 04/01/2020 Joe Engel jengel@hilcorp.com 777-8395 ✔✔✔ ✔ ✔ ✔✔ ✔ ✔✔ ✔✔ By Samantha Carlisle at 10:22 am, Apr 01, 2020 220-034 029-23675-00-00 x x * 3000 psi BOP test (2500 psi Annular test) x x x DLB 04/03/20 x DSR-4/1/2020 X x gls4/6/20 Sr 0 4/8/2020 Area of Review MPM-44PTD API WELL STATUSTop of SB NB (MD)Top of SB NB (TVD)CBL Top of Cement (MD)CBL Top of Cement (TVD)Schrader NB statusZonal Isolation195-151 50-029-22602-00-00 MPU I-07 Shut in SB Producer3809' 3785' 3100' 2977' OpenOpen to Injection Support190-09350-029-22068-00-00 MPU I-04 Well Sidetracked4412' 3886' 3250' 2889'Perfs left open during sidetrack operationsOpen to Injection Support190-097 50-029-22072-00-00 MPU J-03 SB Producer4856' 3822' 3500' 2912' Open*Open to Injection Support*204-135 50-029-23218-00-00 MPU I-19 OBa lateral Shut in6691' 3868' 3334' 2680' Not Open**Cased and Cemented**204-136 50-029-23218-60-00 MPU I-19L1 N/A OA LateralN/A N/A N/A N/A N/ANot Open204-17450-029-23224-00-00 MPU H-18 OBa lateral Shut in6205' 3965' 3652' 2795' Reopened (H-18L2)Open to Injection Support (because it is H-18L2)204-175 50-029-23224-60-00 MPU H-18L1 OA Lateral N/A N/A N/A N/A N/ANot Open204-17650-029-23224-61-00 MPU H-18L2 NB Lateral6442' 3967' N/A N/A Open Open to Injection Support191-09750-029-22198-00-00 MPU J-07SB NB/OA Prod Shut in 4161' 3988' 3000' 2848' OpenOpen to Injection Support. Sundry 320-081 approved to Plug and Abandon reservoir, work not yet complete.190-09550-029-22070-00-00 MPU J-01 Well Sidetracked4041' 3878' 3000' 2837' ClosedCement Retainer set at 3,670' MD, 18 bbls cement pumped below. 199-11150-029-22070-01-00 MPU J-01A OA Lateral Shut in4149' 3886' 3496' 3370' ClosedAt 4682' MD a cement valve was installed and pumped 21 bbls thru. Returns observed on displacement indicates cement from 4682' to Liner top packer at 3496'.201-021 50-029-22070-60-00 MPU J-01AL1 OBa lateral Shut inN/A N/A N/A N/A N/AN/A194-09550-029-22493-00-00 MPU J-06 Kuparuk Prod4256' 3884' 3640' 3435' ClosedCased and Cemented - ~31 bbls of cement pumped thru stage collar at 5,013' MD. 194-11850-029-22506-00-00 MPU J-12SB OA/OB WINJ Shut in 4287' 3893' 3533' 3245' ClosedCased and Cemented - 30 bbls of cement pumped thru stage collar at 4,861' MD. 204-01350-029-23192-00-00 MPU G-17SB OA/OB WINJ Shut in 6178' 3973' 5256' 3220' ClosedCased/Cemented Area of Review MPM-44194-11050-029-22500-00-00 MPU J-10 Kuparuk Prod4512' 3977' 3858' 3397' ClosedCased/Cemented, 22 bbls pumped thru ES cmtr @ 4832' MD.194-12650-029-22508-00-00 MPU J-13 Kuparuk WINJ4988' 3971' 4123' 3360' ClosedCased/Cemented, 33 bbls pumped thru ES cmtr @ 5584' MD.194-10650-029-22497-00-00 MPU J-08 P&A'd / Sidetracked5038' 3892' N/A N/A ClosedCmtr @ 4890', squeezed 23 bbls beneath.199-17750-029-22497-01-00 MPU J-08A SB OB Prod Shut in 5071' 3897' 4714' 3808' ClosedNB opened beneath whipstock - isolated with packer and cement. Cement valve at 5,776' MD, pump 15 bbls, returns observed on BU TOC at TOL @ 4,714' MD.194-11450-029-22502-00-00 MPU J-11 Kuparuk WINJ5091' 3916' 3900' 3166' ClosedCased and Cemented - 51 bbls of cement pumped thru stage collar at 5,739' MD. 195-16950-029-22615-00-00 MPU J-16 Kuparuk WINJ Shut in5748' 3911' 2998' 2529' ClosedCased and Cemented - 38 bbls of cement pumped thru stage collar at 4681' MD. * MPU J-03 - Hilcorp intends to abandon this reservoir prior to injecting into MPU I-35.** MPU I-19 - Hilcorp intends to abanon as a part of I-Pad redevelopment.* close crossing during drilling. I J H G 21 2829 3332 G-01 G-04J-05 J-07 J-06 J-09 J-09A J-08 J-08A J-10 J-11 J-12 J-13 I-05 G-10 G G-15 G-12 H-10 I-08 I-06 J-21 J-17 J-20 J-22 J-15 I-09 I-10 J-23 J-24 G-14 I-15 G-17 J-26 J-25 I-17 I-14 I-14L2 I-19 I-19L1 I-16 H-18 H-18L2 H-16 H-15 I-18 WSAK 25 H-04 I-01 I-02 I-03 I-04 J-01 J-01A J-02 J-03 J-04 G-05 G-08 G-08A I-07 J-19 J-19A J-16 23A J-24A J-28 -27 I-35 wp05 HILCORP ALASKA LLC MILNE POINT FIELD AOR MAP I-35 Injector (Proposed) FEET 0 1,000 2,000 3,000 POSTED WELL DATA Well Number WELL SYMBOLS Active Oil Shut In Oil INJ Well (Water Flood) P&A Oil Abandoned Injector Injector Location Shut In INJ REMARKS Well Sybols at top of Schrader Bluff NB Sand Black dash circle = 1320' radius from NB sand in heel and toe of proposed I-35 drill well March 23, 2020 PETRA 3/23/2020 12:20:27 PM Milne Point Unit (MPU) I-35 Drilling Program Version 1 3/30/2020 Table of Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 RU and Preparatory Work ...................................................................................................... 10 10.0 NU 13-5/8” 5M Diverter Configuration .................................................................................. 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22 14.0 BOP NU and Test..................................................................................................................... 27 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28 16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 33 17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 37 18.0 Innovation Rig Diverter Schematic ......................................................................................... 39 19.0 Innovation Rig BOP Schematic ............................................................................................... 40 20.0 Wellhead Schematic ................................................................................................................. 41 21.0 Days Vs Depth .......................................................................................................................... 42 22.0 Formation Tops & Information............................................................................................... 43 23.0 Anticipated Drilling Hazards .................................................................................................. 44 24.0 Innovation Rig Layout ............................................................................................................. 47 25.0 FIT Procedure .......................................................................................................................... 48 26.0 Innovation Rig Choke Manifold Schematic ............................................................................ 49 27.0 Casing Design ........................................................................................................................... 50 28.0 8-1/2” Hole Section MASP ....................................................................................................... 51 29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 52 30.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 53 Page 2 Milne Point Unit I-35 SB Injector Drilling Procedure 1.0 Well Summary Well MPU I-35 Pad Milne Point “I” Pad Planned Completion Type 3-1/2” Injection Tubing Target Reservoir(s) Schrader Bluff Nb Sand Planned Well TD, MD / TVD 14,768’ MD / 4,005’ TVD PBTD, MD / TVD 14,758’ MD / 4,005’ TVD Surface Location (Governmental) 2322' FSL, 3567' FEL, Sec 33, T13N, R10E, UM, AK Surface Location (NAD 27) X= 551,803 Y= 6,009,438 Top of Productive Horizon (Governmental) 1557' FNL, 1314' FWL, Sec 33, T13N, R10E, UM, AK TPH Location (NAD 27) X= 551,391 Y= 6,010,836 BHL (Governmental) 2108' FNL, 2374' FWL, Sec 21, T13N, R10E, UM, AK BHL (NAD 27) X= 552,356 Y=6,020,851 AFE Number AFE Drilling Days 17 days AFE Completion Days 3 days AFE Drilling Amount $3,752,120 AFE Completion Amount $1,628,642 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1,361 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1,761 psig Work String 5”, 19.5#, S-135, DS-50 & NC 50 KB Elevation above MSL: 26.5 ft + 33.6 ft = 60.1 ft GL Elevation above MSL: 33.6 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit I-35 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit I-35 SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.250” - - - X-52 Weld 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 TXP 5,750 3,090 916 8-1/2” 4-1/2” 3.960” 3.795” 4.714” 13.5 L-80 H625 9,020 8,540 279 Tubing 3-1/2” 2.992” 2.897” 4.500” 9.3 L-80 TXP-SR 9,289 7,399 163 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5” 4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560klb 5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 31,032 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit I-35 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x 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. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, jengel@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and cdinger@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and cdinger@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 6 Milne Point Unit I-35 SB Injector Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Milne Point Unit I-35 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU I-35 is a grassroots injector planned to be drilled in the Schrader Bluff Nb sand. I-35 is part of a multi well program targeting the Schrader Bluff sand on I-Pad The directional plan is a catenary well path build, 12-1/4” hole with 9-5/8” surface casing set into the top of the Schrader Bluff Nb sand. An 8-1/2” lateral section will then be drilled. A 4-1/2” ICD injection liner will be run in the open hole section. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately April 13, 2020, pending rig schedule. Surface casing will be run to 4,674’ MD / 4,005’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Innovation to well site 2. NU & Test 13-5/8” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and c ement 9-5/8” surface casing. 4. ND diverter, NU & test 13-5/8” x 5M BOP. 5. Drill 8-1/2” lateral to well TD. Run 4-1/2” injection liner. 6. Run 3-1/2” tubing. 7. ND BOP, NU Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit I-35 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-35. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivard@hilcorp.com for submission to AOGCC. x Hilcorp Alaska proposes to demonstrate isolation of the injected fluid as required under 20 AAC 25.412 (d) through cement job operational reports of a complete two stage cement job on the 9-5/8” surface casing. Planned surface cement volumes and cement returns to surface seen during both stages will indicate placement of cement in the entire surface casing annulus. A successful FIT after surface casing drill out will demonstrate isolation of injection fluid. AOGCC Regulation Variance Requests: Hilcorp Alaska LLC does not request any variances at this time. Page 9 Milne Point Unit I-35 SB Injector Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12 1/4” x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3,000 Subsequent Tests: 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit I-35 SB Injector Drilling Procedure 9.0 RU and Preparatory Work 9.1 I-35 will utilize a newly set 20” conductor on I-Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and RU. 9.6 Rig mat footprint of the rig. 9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Set test plug in wellhead prior to NU diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Ensure 5” liners in mud pumps. x White Star Quattro 1300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 11 Milne Point Unit I-35 SB Injector Drilling Procedure 10.0 NU 13-5/8” 5M Diverter Configuration 10.1 NU 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program). x NU 20” x 13-5/8” DSA x NU 13 5/8”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. x Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit I-35 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: *Orientation may differ on location Page 13 Milne Point Unit I-35 SB Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 PU 12-1/4” short collar directional only BHA: x This is for surface A/C and accurate gyro surveys closer to bit x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Be sure to run a UBHO sub for wireline gyro x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135 DS50 & NC50. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. 11.3 Drill 12-1/4” hole section to section to the end of build and/or until clean MWD surveys are seen, x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability x Perform wireline gyros until clean MWD surveys are seen . Take MWD surveys every stand drilled. 11.4 CBU and BROOH x POOH on elevators if possible 11.5 Make up remainder of full directional and LWD BHA Page 14 Milne Point Unit I-35 SB Injector Drilling Procedure 11.6 RIH 11.7 Drill 12-1/4” hole section to section TD, in the Schrader Nb sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Gas hydrates may be present on I-Pad. Historically encountered hydrates are typically around 2,100-2,400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 FPH MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface x A/C: x There are not wells with a clearance factor < 1.0 11.8 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Page 15 Milne Point Unit I-35 SB Injector Drilling Procedure Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL caustic soda BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT 0.905 bbl 0.5 ppb 15 - 20 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 8.8 –9.8 O.K. EMW=8.46 DLB Page 16 Milne Point Unit I-35 SB Injector Drilling Procedure ALDACIDE G 0.1 ppb 11.9 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. x This is to prevent washing out directional work to land the well 11.10 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 GPM), and maximize rotation. x Pull slowly, 5 – 10 FPM. x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.11 TOOH and LD BHA 11.12 No open hole logging program planned. Page 17 Milne Point Unit I-35 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 RU and pull wearbushing. 12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x DS50 XO on rig floor and MU to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x RU of CRT if hole conditions require. x RU a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.750” on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. 12.3 PU shoe joint, visually verify no debris inside joint. 12.4 Continue MU & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w ith stop rings 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record SN’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 18 Milne Point Unit I-35 SB Injector Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: 2500 Page 19 Milne Point Unit I-35 SB Injector Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POOH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost (~ 2,500’ MD). (Halliburton ESIPC with packer element may be used). x Install centralizers over couplings on 5 joints below and 10 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. x ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at ~ 2080 psi, and the tool to open at ~ 3000 psi. Reference ESIPC Procedure. 9-5/8”, 40#, L-80, TXP MU Torques: Casing OD Minimum Optimum Maximum 9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs Depth Interval Centralization Shoe – 1000’ Above Shoe 1/joints 1000’ above Shoe – 2000’ above Shoe (Top of Ugnu) 1/ 2 joints Page 20 Milne Point Unit I-35 SB Injector Drilling Procedure Page 21 Milne Point Unit I-35 SB Injector Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only with paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 PU landing joint and MU to casing string. Position the casing shoe ±10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold MU water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Milne Point Unit I-35 SB Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" Casing (3,674' - 2,500') x .0558 bpf x 1.3 = 85.2 478.2 Total Lead 85.2 478.2 12-1/4" OH x 9-5/8" Casing (4,674' - 3,674') x .0558 bpf x 1.3 = 72.5 407 9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail 81.6 458LeadTail 203 sx 394 sx Page 23 Milne Point Unit I-35 SB Injector Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 4,554’ x .0758 bpf = 345.2 bbls 80 bbls of tuned spacer to be left behind stage tool, confirm fluid is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mixed Water 13.92 gal/sk 4.98 gal/sk ok Page 24 Milne Point Unit I-35 SB Injector Drilling Procedure 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 25 Milne Point Unit I-35 SB Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. (If ESIPC is used and packer element inflated, CBU x1 minimum before pumping second stage). Hold pre-job safety meeting. x Minimize pump shutdowns while circulating through stage tool and keep shutdowns to 30 minutes or less. Longer shutdowns have lead to the stage tool packing off and losing circulation x If circulation is lost, slowly stage up pumps to 2000psi and gently work/stretch pipe to regain circulation. Contact drilling engineer if unable to gain circulation at 2000 psi 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161 12-1/4" OH x 9-5/8" Casing (2,000' - 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-5/8" Casing (2,500' - 2,000') x .0558 bpf x 2 = 55.8 314 Total Tail 55.8 314LeadTail Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk 270 sx 439 sx Page 26 Milne Point Unit I-35 SB Injector Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2,500’ x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 2,500’ x .0758 bpf = 190 bbls mud ok Page 27 Milne Point Unit I-35 SB Injector Drilling Procedure 14.0 BOP NU and Test 14.1 ND the diverter T, 16” knife gate, 16” diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M CTI BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity, blind ram in bottom cavity. x Single ram should be dressed with 2-7/8” x 5-1/2” VBRs or 5” Solid Body Rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to mud cross) 14.3 Run 5” BOP test plug (if not installed previously). x Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.4 RD BOP test equipment 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.7 Set wearbushing in wellhead. 14.8 Rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.9 Ensure 5” liners in mud pumps. NU 13-5/8” x 5M CTI BOP as follows: Page 28 Milne Point Unit I-35 SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) x Pending results of M-43 well, we may drill out shoe track with RSS BHA 15.2 TIH with 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on morning report. Drill out stage tool or ESIPC. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and test casing to 2,500 psi for 30 minutes charted. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = ~3500 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5”, 19.5#, S-135, DS50 & NC50. x Run a ported float in the production hole section. 15.10 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. test casing as per AOGCC Industry Guid ance Bullet in 17-001. Conduct FIT to 12 ppg EMW. C RU and test casing to 2RR,500 psi for 30 minutes charted. Page 29 Milne Point Unit I-35 SB Injector Drilling Procedure x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type: 8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT Production 8.9-9.5 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid 8.9-9.5 Page 30 Milne Point Unit I-35 SB Injector Drilling Procedure 15.13 Begin drilling 8-1/2” hole section, o n-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 RPMs at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations. x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes. 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 FPM, 385 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff NB Concretions: 4-6% of lateral x A/C, wells with < 1.0 clearance factor: x J-01A / J-01AL1 – a SB OA / OB Dual lateral that will be P&A’s prior to I-35 spud x J-03 – a Slant SB O & N sand producer that will be P&A’d prior to I-35 spud x J-11 – a slant kuparuk injector, single point close approach. Watch for mag interference, control drill past at 11,577’ MD. Will be S/I prior to spud. 15.15 Reference: Open hole sidetracking practice: x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 FPH with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 FPM AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed Page 31 Milne Point Unit I-35 SB Injector Drilling Procedure x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x Ensure mud has necessary lube % for running liner x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 rpm reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5 pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25 ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. x Record SO, PU weights and rotating torque to compare to pre-brine values in report. 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM). x Rotate at maximum rpm that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.22 Monitor well for flow / pressure build up with MPD. Increase fluid weight if necessary Page 32 Milne Point Unit I-35 SB Injector Drilling Procedure x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.23 POOH and LD BHA. 15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 33 Milne Point Unit I-35 SB Injector Drilling Procedure 16.0 Run 4-1/2” Injection Liner (Lower Completion) 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2” liner with ICD and swell packers, the following well control response procedure will be followed: x With ICD across the BOP: PU & MU the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully MU and available prior to running the first joint of 4-1/2” liner. x With 4-1/2” solid joint across BOP: Slack off and position the 4-1/2” solid jo int to MU the TIW valve. Shut in ram or annular on 4-1/2” solid joint. Close TIW valve. 16.2. Confirm VBR have been tested on 3-1/2” and 5” test joints to 250/3,000 psi. 16.3. RU 4-1/2” liner running equipment. x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and /U to FOSV. x Ensure the liner has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. 16.4. Run 4-1/2” injection liner. x Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only with paint brush. Wipe off excess. Thread compound can plug the ICDs. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Fill 4-1/2” liner with PST passed mud (to keep from plugging ICDs with solids) x Install ICDs and swell packers as per the Running Order (Estimate 8 evenly spaced, Operations Engineer to provide confirmation of set depths). x Do not place tongs or slips on swell packer elements or ICDs. x ICD and swell packer placement ±40’ x The ICD connection is 4-1/2”, 13.5#, L-80, Hydril 625. x Remove protective packaging on swell packers just prior to picking up x If liner length exceeds surface casing length, ensure centralizers are placed 1/joint for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. x Obtain PU and SO weights of the liner before entering open hole. Record rotating torque at 10 and 20 RPM 4-1/2”, 13.5#, L-80, Hydril 625 MU Torques Casing OD Minimum Optimum Maximum Operating Torque Yield Torque 4-1/2” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs 15,000 ft-lbs Page 34 Milne Point Unit I-35 SB Injector Drilling Procedure 16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger/packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. Page 35 Milne Point Unit I-35 SB Injector Drilling Procedure 16.8. MU Baker SLZXP liner hanger/packer to 4-1/2” liner. Fill liner tieback sleeve with “Pal mix”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 minutes for mixture to set up. 16.9. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH with liner on HWDP no faster than 30 FPM – this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.11. The liner will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW trend indicates. 16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.17. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.18. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,100 psi to neutralize and release running tools. 16.19. Bleed DP pressure to 0 psi, Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Contingency (if suspected not released from running tool) - Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.20. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.21. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. Page 36 Milne Point Unit I-35 SB Injector Drilling Procedure 16.22. POOH laying down DP then rack back enough 5” DP for the liner top cleanout run. LD and inspect the liner running tools. Once running tools are LD, swap to the Completion AFE. 16.23. Make up 3-1/2” wash tool and RIH on 5” DP to the liner top. 16.24. Flush liner top at max rate while displacing out well to clean brine. 16.25. POOH LD remaining 5” DP. Page 37 Milne Point Unit I-35 SB Injector Drilling Procedure 17.0 Run 3-1/2” Tubing (Upper Completion) 17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivard@hilcorp.com for submission to AOGCC. 17.2 MU injection assembly and RIH to setting depth. TIH no faster than 90 FPM. x Ensure wear bushing is pulled. x Ensure 3-1/2” EUE 8rd x NC-50 crossover is on rig floor and MU to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 3-1/2” Upper Completion Running Order: x 7.30” Baker Ported Bullet Nose seal (stung into the tie back receptacle, crossover to 3-1/2”, 9.3#, EUE 8rd) x 3 joints (minimum, more as needed), 3-1/2”, 9.3#, EUE 8rd tubing x 3-1/2” “XN” nipple at TBD (less than 70° hole angle) x 1 joints, 3-1/2”, 9.3#, EUE 8rd tubing x 3-1/2” Baker gauge mandrel o Cross collar clamps: Every joint for first 10 joints, every other joint beyond this to surface x XX Joints, 3-1/2”, 9.3#, EUE 8rd tubing x Space out pup(s), 3-1/2”, 9.3#, EUE 8rd tubing x 1 joint, 3-1/2”, 9.3#, EUE 8rd tubing x Tubing hanger with 3-1/2” EUE 8rd pin down 17.3 Locate and no-go out the seal assembly. Close annular and test to 500 psi to confirm seals engaged. 17.4 Bleed pressure and open annular. Space out the completion (±2’ above No-Go). Place all space out pups below the first full joint of the completion. Page 38 Milne Point Unit I-35 SB Injector Drilling Procedure 17.5 MU the tubing hanger and landing joint. 17.6 RIH. Close annular and test to 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 17.7 Reverse circulate the well with corrosion inhibited brine. 17.8 Freeze protect the IA to ~2,000’ TVD (base on actual well deviation) with diesel. 17.9 Land hanger and RILDS. 17.10 PT the IA to 2,500 psi for 30 minutes charted. i. Note this test must be witnessed by the AOGCC representative. 17.11 Set BPV, ensure new body seals are installed each time. 17.12 ND BOPE and install the plug off tool into the BPV. 17.13 NU the tubing head adapter and NU the tree. 17.14 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 17.15 Pull the plug off tool from the BPV. 17.16 Bullhead diesel down the tubing to ~2,000’ TVD (base on actual well deviation). 17.17 Install all tree gauges. Secure the tree and cellar. Release the rig. 17.18 RDMO the Innovation Rig. 17.19 Turn the well over to operations via handover form. Note this test must be witnessed by the AOGCC representative. PT the IA to 2,500 psi fo r 30 minutes chart ed. i.NNote this test must be witnessed by the AOGCC ** Witnessed MIT-IA after stabilized injection. Page 39 Milne Point Unit I-35 SB Injector Drilling Procedure 18.0 Innovation Rig Diverter Schematic Page 40 Milne Point Unit I-35 SB Injector Drilling Procedure 19.0 Innovation Rig BOP Schematic Page 41 Milne Point Unit I-35 SB Injector Drilling Procedure 20.0 Wellhead Schematic Page 42 Milne Point Unit I-35 SB Injector Drilling Procedure 21.0 Days Vs Depth Page 43 Milne Point Unit I-35 SB Injector Drilling Procedure 22.0 Formation Tops & Information MW is 0.5+ ppg above EMW DLB Page 44 Milne Point Unit I-35 SB Injector Drilling Procedure 23.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have been seen on E Pad. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non- pressurized scale will reflect the actual mud cut weight. Add 1.0 – 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well Specific A/C: x There are no wells with a clearance factor of <1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Page 45 Milne Point Unit I-35 SB Injector Drilling Procedure Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 46 Milne Point Unit I-35 SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Abnormal pressure has been seen on E-Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. x A/C, wells with < 1.0 clearance factor: x J-01A / J-01AL1 – a SB OA / OB Dual lateral that will be P&A’s prior to I-35 spud x J-03 – a Slant SB O & N sand producer that will be P&A’d prior to I-35 spud x J-11 – a slant kuparuk injector, single point close approach. Watch for mag interference, control drill past at 11,577’ MD. Will be S/I prior to spud. Anti-Collision *** See email dated 4/6/20 . Gyro will be run on J-11 prior to spudding. gls Page 47 Milne Point Unit I-35 SB Injector Drilling Procedure 24.0 Innovation Rig Layout Page 48 Milne Point Unit I-35 SB Injector Drilling Procedure 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 49 Milne Point Unit I-35 SB Injector Drilling Procedure 26.0 Innovation Rig Choke Manifold Schematic Page 50 Milne Point Unit I-35 SB Injector Drilling Procedure 27.0 Casing Design 12-1/4"Mud Density:9.2 ppg 8-1/2"Mud Density:9.2 ppg Mud Density: 1301 psi (see attached MASP determination & calculation) 1361 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress 1234 9-5/8"4-1/2" 04,674 03,825 4,674 14,768 3,825 4,005 4,674 10,094 40 13.5 L-80 L-80 TXP H625 186,960 136,269 186,960 136,269 916 307 4.90 2.25 1,890 1,978 3,090 8,540 1.64 4.32 1,301 1,361 5,750 9,020 4.42 6.63Worst case safety factor (Burst) MASP: Production Mode Minimum Yield (psi) Weight (ppf) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Worst Case Safety Factor (Collapse) Length Calculation & Casing Design Factors Calculation/Specification Casing OD Bottom (MD) Bottom (TVD) Top (MD) MASP: Drilling Mode MASP: Hole Size DATE: 3/31/2020 WELL: MPU I-35 DESIGN BY: Joe Engel Hole Size Hole Size Casing Section Design Criteria: Collapse Resistance w/o tension (Psi) Top (TVD) Tension at Top of Section (lbs) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) 8,540 1.64 2 6.63 4.90 2.25 1,890 1,978 .32 4. Page 51 Milne Point Unit I-35 SB Injector Drilling Procedure 28.0 8-1/2” Hole Section MASP MD TVD Planned Top: 4674 3825 Planned TD: 14768 4005 Anticipated Formations and Pressures: Formation Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NB Sand 1683 Oil 8.46 0.440 Offset Well Mud Densities Well Sand MW range Top (TVD) Bottom (TVD) Date M-43 SB NB 8.8 - 9.2 3,759 3520 2020 E-40 SB NB 8.9 - 9.2 4,373 4388 2019 E-41 SB NB 8.9 - 9.2 4,328 4350 2019 L-54 SB NB 8.8 - 9.1 3,949 3734 2018 L-56 SB NB 8.8 - 9.2 3,932 3678 2018 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3825 (ft) x 0.78(psi/ft)= 2983 2983(psi) - [0.1(psi/ft)*3825(ft)]= 2601 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff sand) 4005 (ft) x 0.44(psi/ft)= 1762 psi 1762(psi) - 0.1(psi/ft)*4005(ft) 1361 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Maximum Anticipated Surface Pressure Calculation 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 8-1/2" Hole Section MPU I-35 Milne Point Unit TVD 3,825 Page 52 Milne Point Unit I-35 SB Injector Drilling Procedure 29.0 Spider Plot (NAD 27) (Governmental Sections) Page 53 Milne Point Unit I-35 SB Injector Drilling Procedure 30.0 Surface Plat (As Built) (NAD 27) 25 March, 2020 Plan: MPU I-35 wp07 Milne Point M Pt I Pad PLAN: MPU I-35 - Slot I-22 MPU I-35 075015002250300037504500True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 3.50° (1500 usft/in)MPU I-35 (Antietam) wp04 ToeMPU I-35 (Antietam) wp04 CP2MPU I-35 (Antietam) wp04 CP3MPU I-35 (Antietam) wp04 HeelMPU I-35 (Antietam) wp02 CP1MPU I-35 (Antietam) wp02 CP49 5/8" x 12 1/4"6 5/8" x 8 1/2"50010001500200025003000350040004500500 0 550 0 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11 0 00 11 5 00 12000 12 500 13000 13 500140001450014769MPU I-35 wp07Start Dir 4º/100' : 1000' MD, 1000'TVDEnd Dir : 1618.26' MD, 1606.75' TVDStart Dir 4º/100' : 2405.99' MD, 2376.36'TVDEndDir : 4574.6' MD, 3816.38'TVDStartDir4º/100':4674.6'MD, 3825.1'TVDEndDir :4829.15' MD, 3830.25'TVDStartDir3º/100':5839.19'MD, 3809.42'TVDEndDir :5959.51' MD, 3810.18'TVDStartDir3º/100':8292.34'MD, 3885.09'TVDEndDir :8374.14' MD, 3886.38'TVDStartDir3º/100':10870.77'MD, 3885.09'TVDEndDir : 10960.39' MD, 3886.05'TVDStartDir3º/100':13352.36'MD, 3938.46'TVDEndDir :13437.4' MD, 3941.86'TVDTotal Depth:14768.88'MD,4005.1'TVDSV5BPRFSV1UG4ALA3UGNU MBSB_NASB_NB (heel)Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Pedal CurveWarning Method: Error RatioWELL DETAILS: PLAN: MPU I-35 - Slot I-2233.60+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006009438.87551803.81 70° 26' 11.512 N 149° 34' 39.487 WSURVEY PROGRAMDate: 2020-03-23T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 800.00 MPU I-35 wp07 (MPU I-35) 3_Gyro-GC_Csg800.00 4674.60 MPU I-35 wp07 (MPU I-35) 3_MWD+IFR2+MS+Sag4674.60 14768.88 MPU I-35 wp07 (MPU I-35) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1352.10 1292.00 1355.75 SV51788.10 1728.00 1803.88 BPRF2031.10 1971.00 2052.60 SV12409.10 2349.00 2439.50 UG4A3326.10 3266.00 3458.23 LA33558.10 3498.00 3808.67 UGNU MB3797.10 3737.00 4432.15 SB_NA3828.10 3768.00 4715.79 SB_NB (heel)REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PLAN: MPU I-35 - Slot I-22, True NorthVertical (TVD) Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well Elev)Measured Depth Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well Elev)Calculation Method:Minimum CurvatureProject:Milne PointSite:M Pt I PadWell:PLAN: MPU I-35Wellbore:MPU I-35Design:MPU I-35 wp07CASING DETAILSTVD TVDSS MD SizeName3825.10 3765.00 4674.60 9-5/8 9 5/8" x 12 1/4"4005.10 3945.00 14768.88 6-5/8 6 5/8" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 1000.00 0.00 0.00 1000.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 1000' MD, 1000'TVD3 1400.00 16.00 235.00 1394.82 -31.83 -45.45 4.00 235.00 -34.544 1618.26 12.32 268.06 1606.75 -49.90 -93.45 4.00 129.95 -55.51 End Dir : 1618.26' MD, 1606.75' TVD5 2405.99 12.32 268.06 2376.36 -55.59 -261.37 0.00 0.00 -71.44 Start Dir 4º/100' : 2405.99' MD, 2376.36'TVD6 4574.60 85.00 5.73 3816.38 1275.99 -415.25 4.00 98.55 1248.26 End Dir : 4574.6' MD, 3816.38' TVD7 4674.60 85.00 5.73 3825.10 1375.11 -405.31 0.00 0.00 1347.80 MPU I-35 (Antietam) wp04 Heel Start Dir 4º/100' : 4674.6' MD, 3825.1'TVD8 4829.15 91.18 5.81 3830.25 1528.73 -389.78 4.00 0.78 1502.08 End Dir : 4829.15' MD, 3830.25' TVD9 5839.19 91.18 5.81 3809.42 2533.35 -287.48 0.00 0.00 2511.07 Start Dir 3º/100' : 5839.19' MD, 3809.42'TVD10 5956.67 88.16 4.00 3810.09 2650.38 -277.44 3.00 -149.02 2628.50 MPU I-35 (Antietam) wp02 CP111 5959.51 88.16 3.91 3810.18 2653.21 -277.24 3.00 -90.00 2631.34 End Dir : 5959.51' MD, 3810.18' TVD12 8292.34 88.16 3.91 3885.09 4979.40 -118.06 0.00 0.00 4962.90 Start Dir 3º/100' : 8292.34' MD, 3885.09'TVD13 8292.49 88.16 3.91 3885.09 4979.55 -118.05 3.00 -89.99 4963.06 MPU I-35 (Antietam) wp04 CP2 Start Dir 3º/100' : 8292.34' MD, 3885.09'TVD14 8374.14 90.03 5.49 3886.38 5060.90 -111.36 3.00 40.26 5044.67 End Dir : 8374.14' MD, 3886.38' TVD15 10870.77 90.03 5.49 3885.09 7546.07 127.61 0.00 0.00 7539.79 Start Dir 3º/100' : 10870.77' MD, 3885.09'TVD16 10870.85 90.03 5.49 3885.09 7546.16 127.62 3.00 -81.01 7539.87 MPU I-35 (Antietam) wp04 CP3 Start Dir 3º/100' : 10870.77' MD, 3885.09'TVD17 10960.39 88.74 7.85 3886.05 7635.07 138.01 3.00 118.60 7629.26 End Dir : 10960.39' MD, 3886.05' TVD18 13352.36 88.74 7.85 3938.46 10004.07 464.58 0.00 0.00 10013.77 Start Dir 3º/100' : 13352.36' MD, 3938.46'TVD19 13399.84 87.32 7.85 3940.09 10051.08 471.06 3.00 179.95 10061.09 MPU I-35 (Antietam) wp02 CP420 13437.40 87.28 6.72 3941.86 10088.29 475.82 3.00 -92.18 10098.52 End Dir : 13437.4' MD, 3941.86' TVD21 14768.88 87.28 6.72 4005.10 11409.13 631.51 0.00 0.00 11426.40 MPU I-35 (Antietam) wp04 Toe Total Depth : 14768.88' MD, 4005.1' TVD 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 South(-)/North(+) (1500 usft/in)-6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 West(-)/East(+) (1500 usft/in) MPU I-35 (Antietam) wp02 CP4 MPU I-35 (Antietam) wp02 CP1 MPU I-35 (Antietam) wp04 Heel MPU I-35 (Antietam) wp04 CP3 MPU I-35 (Antietam) wp04 CP2 MPU I-35 (Antietam) wp04 Toe MPU-SB-NB-Fault 130 MPU-SB-NB-Fault 131 9 5/8" x 12 1/4" 6 5/8" x 8 1/2" 750 1000225 03 0 0 0 3 5 00 3750 4005 MPU I-35 wp07 Start Dir 4º/100' : 1000' MD, 1000'TVD End Dir : 1618.26' MD, 1606.75' TVD Start Dir 4º/100' : 4674.6' MD, 3825.1'TVD End Dir : 4829.15' MD, 3830.25' TVD Start Dir 3º/100' : 5839.19' MD, 3809.42'TVD End Dir : 5959.51' MD, 3810.18' TVD Start Dir 3º/100' : 8292.34' MD, 3885.09'TVD End Dir : 8374.14' MD, 3886.38' TVD Start Dir 3º/100' : 10870.77' MD, 3885.09'TVD End Dir : 10960.39' MD, 3886.05' TVD Start Dir 3º/100' : 13352.36' MD, 3938.46'TVD End Dir : 13437.4' MD, 3941.86' TVD Total Depth : 14768.88' MD, 4005.1' TVD CASING DETAILS TVD TVDSS MD Size Name 3825.10 3765.00 4674.60 9-5/8 9 5/8" x 12 1/4" 4005.10 3945.00 14768.88 6-5/8 6 5/8" x 8 1/2" Project: Milne Point Site: M Pt I Pad Well: PLAN: MPU I-35 - Slot I-22 Wellbore: MPU I-35 Plan: MPU I-35 wp07 WELL DETAILS: PLAN: MPU I-35 - Slot I-22 33.60 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6009438.87 551803.81 70° 26' 11.512 N 149° 34' 39.487 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well PLAN: MPU I-35 - Slot I-22, True North Vertical (TVD) Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well Elev) Measured Depth Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well Elev) Calculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: PLAN: MPU I-35 - Slot I-22 MPU I-35 Survey Calculation Method:Minimum Curvature MPU I-35 prelim RKB @ 60.10usft (Original Well Design:MPU I-35 wp07 Database:NORTH US + CANADA MD Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well North Reference: Well PLAN: MPU I-35 - Slot I-22 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt I Pad, TR-13-10 usft Map usft usft °0.39Slot Radius:"0 6,008,388.01 550,245.83 0.00 70° 26' 1.282 N 149° 35' 25.422 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: PLAN: MPU I-35 - Slot I-22 usft usft 0.00 0.00 6,009,438.87 551,803.81 33.60Wellhead Elevation:usft0.50 70° 26' 11.512 N 149° 34' 39.487 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU I-35 Model NameMagnetics BGGM2019 4/23/2020 16.00 80.85 57,377.72079824 Phase:Version: Audit Notes: Design MPU I-35 wp07 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:26.50 3.500.000.0026.50 3/25/2020 1:00:34PM COMPASS 5000.15 Build 91E Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: PLAN: MPU I-35 - Slot I-22 MPU I-35 Survey Calculation Method:Minimum Curvature MPU I-35 prelim RKB @ 60.10usft (Original Well Design:MPU I-35 wp07 Database:NORTH US + CANADA MD Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well North Reference: Well PLAN: MPU I-35 - Slot I-22 True Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0026.500.000.0026.50 -33.60 0.000.000.000.000.000.001,000.000.000.001,000.00 939.90 235.000.004.004.00-45.45-31.831,394.82235.0016.001,400.00 1,334.72 129.9515.15-1.694.00-93.45-49.901,606.75268.0612.321,618.26 1,546.65 0.000.000.000.00-261.37-55.592,376.36268.0612.322,405.99 2,316.26 98.554.503.354.00-415.251,275.993,816.385.7385.004,574.60 3,756.28 0.000.000.000.00-405.311,375.113,825.105.7385.004,674.60 3,765.00 0.780.054.004.00-389.781,528.733,830.255.8191.184,829.15 3,770.15 0.000.000.000.00-287.482,533.353,809.425.8191.185,839.19 3,749.32 -149.02-1.54-2.573.00-277.442,650.383,810.094.0088.165,956.67 3,749.99 -90.00-3.000.003.00-277.242,653.213,810.183.9188.165,959.51 3,750.08 0.000.000.000.00-118.064,979.403,885.093.9188.168,292.34 3,824.99 -89.99-3.000.003.00-118.054,979.553,885.093.9188.168,292.49 3,824.99 40.261.942.293.00-111.365,060.903,886.385.4990.038,374.14 3,826.28 0.000.000.000.00127.617,546.073,885.095.4990.0310,870.77 3,824.99 -81.01-2.960.473.00127.627,546.163,885.095.4990.0310,870.85 3,824.99 118.602.63-1.443.00138.017,635.073,886.057.8588.7410,960.39 3,825.95 0.000.000.000.00464.5810,004.073,938.467.8588.7413,352.36 3,878.36 179.950.00-3.003.00471.0610,051.083,940.097.8587.3213,399.84 3,879.99 -92.18-3.00-0.113.00475.8210,088.293,941.866.7287.2813,437.40 3,881.76 0.000.000.000.00631.5111,409.134,005.106.7287.2814,768.88 3,945.00 3/25/2020 1:00:34PM COMPASS 5000.15 Build 91E Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: PLAN: MPU I-35 - Slot I-22 MPU I-35 Survey Calculation Method:Minimum Curvature MPU I-35 prelim RKB @ 60.10usft (Original Well Design:MPU I-35 wp07 Database:NORTH US + CANADA MD Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well North Reference: Well PLAN: MPU I-35 - Slot I-22 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -33.60 Vert Section 26.50 0.00 26.50 0.00 0.000.00 551,803.816,009,438.87-33.60 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 551,803.816,009,438.8739.90 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 551,803.816,009,438.87139.90 0.00 0.00 300.00 0.00 300.00 0.00 0.000.00 551,803.816,009,438.87239.90 0.00 0.00 400.00 0.00 400.00 0.00 0.000.00 551,803.816,009,438.87339.90 0.00 0.00 500.00 0.00 500.00 0.00 0.000.00 551,803.816,009,438.87439.90 0.00 0.00 600.00 0.00 600.00 0.00 0.000.00 551,803.816,009,438.87539.90 0.00 0.00 700.00 0.00 700.00 0.00 0.000.00 551,803.816,009,438.87639.90 0.00 0.00 800.00 0.00 800.00 0.00 0.000.00 551,803.816,009,438.87739.90 0.00 0.00 900.00 0.00 900.00 0.00 0.000.00 551,803.816,009,438.87839.90 0.00 0.00 1,000.00 0.00 1,000.00 0.00 0.000.00 551,803.816,009,438.87939.90 0.00 0.00 Start Dir 4º/100' : 1000' MD, 1000'TVD 1,100.00 4.00 1,099.92 -2.00 -2.86235.00 551,800.976,009,436.851,039.82 4.00 -2.17 1,200.00 8.00 1,199.35 -8.00 -11.42235.00 551,792.456,009,430.801,139.25 4.00 -8.68 1,300.00 12.00 1,297.81 -17.95 -25.64235.00 551,778.306,009,420.741,237.71 4.00 -19.49 1,355.75 14.23 1,352.10 -25.21 -36.00235.00 551,767.996,009,413.411,292.00 4.00 -27.36 SV5 1,400.00 16.00 1,394.82 -31.83 -45.45235.00 551,758.586,009,406.731,334.72 4.00 -34.54 1,500.00 13.77 1,491.49 -44.20 -67.78247.99 551,736.346,009,394.211,431.39 4.00 -48.25 1,600.00 12.44 1,588.92 -49.65 -89.55264.70 551,714.626,009,388.601,528.82 4.00 -55.03 1,618.26 12.32 1,606.75 -49.90 -93.45268.06 551,710.726,009,388.321,546.65 4.00 -55.51 End Dir : 1618.26' MD, 1606.75' TVD 1,700.00 12.32 1,686.61 -50.49 -110.88268.06 551,693.306,009,387.611,626.51 0.00 -57.17 1,800.00 12.32 1,784.31 -51.21 -132.19268.06 551,671.996,009,386.741,724.21 0.00 -59.19 1,803.88 12.32 1,788.10 -51.24 -133.02268.06 551,671.166,009,386.711,728.00 0.00 -59.27 BPRF 1,900.00 12.32 1,882.01 -51.94 -153.51268.06 551,650.686,009,385.871,821.91 0.00 -61.21 2,000.00 12.32 1,979.71 -52.66 -174.83268.06 551,629.376,009,385.011,919.61 0.00 -63.23 2,052.60 12.32 2,031.10 -53.04 -186.04268.06 551,618.166,009,384.551,971.00 0.00 -64.29 SV1 2,100.00 12.32 2,077.41 -53.38 -196.14268.06 551,608.066,009,384.142,017.31 0.00 -65.25 2,200.00 12.32 2,175.11 -54.10 -217.46268.06 551,586.756,009,383.272,115.01 0.00 -67.27 2,300.00 12.32 2,272.80 -54.82 -238.78268.06 551,565.446,009,382.402,212.70 0.00 -69.30 2,405.99 12.32 2,376.36 -55.59 -261.37268.06 551,542.856,009,381.482,316.26 0.00 -71.44 Start Dir 4º/100' : 2405.99' MD, 2376.36'TVD 2,439.50 12.19 2,409.10 -55.44 -268.47274.35 551,535.766,009,381.572,349.00 4.00 -71.72 UG4A 2,500.00 12.32 2,468.23 -53.20 -281.06285.75 551,523.166,009,383.722,408.13 4.00 -70.26 2,600.00 13.51 2,565.74 -43.95 -301.14302.92 551,503.016,009,392.832,505.64 4.00 -62.25 2,700.00 15.65 2,662.54 -27.83 -320.25316.42 551,483.796,009,408.822,602.44 4.00 -47.33 2,800.00 18.40 2,758.17 -4.91 -338.29326.37 551,465.596,009,431.612,698.07 4.00 -25.55 2,900.00 21.54 2,852.16 24.69 -355.18333.67 551,448.506,009,461.092,792.06 4.00 2.97 3,000.00 24.91 2,944.06 60.84 -370.84339.13 551,432.606,009,497.132,883.96 4.00 38.09 3,100.00 28.44 3,033.41 103.35 -385.18343.33 551,417.966,009,539.532,973.31 4.00 79.64 3,200.00 32.07 3,119.78 152.01 -398.13346.67 551,404.676,009,588.103,059.68 4.00 127.42 3/25/2020 1:00:34PM COMPASS 5000.15 Build 91E Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: PLAN: MPU I-35 - Slot I-22 MPU I-35 Survey Calculation Method:Minimum Curvature MPU I-35 prelim RKB @ 60.10usft (Original Well Design:MPU I-35 wp07 Database:NORTH US + CANADA MD Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well North Reference: Well PLAN: MPU I-35 - Slot I-22 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,142.65 Vert Section 3,300.00 35.77 3,202.75 206.60 -409.64349.39 551,392.786,009,642.603,142.65 4.00 181.20 3,400.00 39.53 3,281.91 266.83 -419.65351.65 551,382.366,009,702.763,221.81 4.00 240.72 3,458.23 41.73 3,326.10 304.40 -424.77352.81 551,376.986,009,740.283,266.00 4.00 277.90 LA3 3,500.00 43.32 3,356.88 332.43 -428.11353.58 551,373.456,009,768.293,296.78 4.00 305.68 3,600.00 47.14 3,427.30 403.07 -434.97355.26 551,366.096,009,838.873,367.20 4.00 375.77 3,700.00 50.98 3,492.82 478.41 -440.21356.74 551,360.336,009,914.163,432.72 4.00 450.64 3,800.00 54.84 3,553.13 558.08 -443.80358.07 551,356.196,009,993.803,493.03 4.00 529.94 3,808.67 55.17 3,558.10 565.18 -444.03358.18 551,355.916,010,000.903,498.00 4.00 537.02 UGNU MB 3,900.00 58.71 3,607.92 641.68 -445.72359.27 551,353.696,010,077.383,547.82 4.00 613.28 4,000.00 62.59 3,656.93 728.83 -445.960.39 551,352.846,010,164.513,596.83 4.00 700.24 4,100.00 66.48 3,699.92 819.08 -444.521.42 551,353.656,010,254.763,639.82 4.00 790.41 4,200.00 70.37 3,736.69 912.00 -441.412.40 551,356.126,010,347.693,676.59 4.00 883.35 4,300.00 74.27 3,767.05 1,007.14 -436.653.33 551,360.226,010,442.853,706.95 4.00 978.60 4,400.00 78.18 3,790.86 1,104.03 -430.254.22 551,365.956,010,539.783,730.76 4.00 1,075.71 4,432.15 79.43 3,797.10 1,135.48 -427.854.50 551,368.136,010,571.243,737.00 4.00 1,107.24 SB_NA 4,500.00 82.08 3,808.00 1,202.21 -422.245.09 551,373.276,010,638.003,747.90 4.00 1,174.19 4,574.60 85.00 3,816.38 1,275.99 -415.255.73 551,379.746,010,711.833,756.28 4.00 1,248.26 End Dir : 4574.6' MD, 3816.38' TVD 4,600.00 85.00 3,818.60 1,301.17 -412.735.73 551,382.106,010,737.023,758.50 0.00 1,273.55 4,674.60 85.00 3,825.10 1,375.12 -405.315.73 551,389.006,010,811.003,765.00 0.00 1,347.81 Start Dir 4º/100' : 4674.6' MD, 3825.1'TVD - 9 5/8" x 12 1/4" 4,700.00 86.02 3,827.09 1,400.31 -402.785.74 551,391.366,010,836.213,766.99 4.00 1,373.11 4,715.79 86.65 3,828.10 1,415.99 -401.205.75 551,392.836,010,851.903,768.00 4.00 1,388.86 SB_NB (heel) 4,800.00 90.02 3,830.55 1,499.72 -392.735.80 551,400.716,010,935.683,770.45 4.00 1,472.95 4,829.15 91.18 3,830.25 1,528.72 -389.785.81 551,403.466,010,964.703,770.15 4.00 1,502.07 End Dir : 4829.15' MD, 3830.25' TVD 4,900.00 91.18 3,828.79 1,599.19 -382.605.81 551,410.146,011,035.213,768.69 0.00 1,572.85 5,000.00 91.18 3,826.72 1,698.66 -372.485.81 551,419.586,011,134.733,766.62 0.00 1,672.75 5,100.00 91.18 3,824.66 1,798.12 -362.355.81 551,429.026,011,234.263,764.56 0.00 1,772.65 5,200.00 91.18 3,822.60 1,897.59 -352.225.81 551,438.456,011,333.783,762.50 0.00 1,872.54 5,300.00 91.18 3,820.54 1,997.05 -342.095.81 551,447.896,011,433.303,760.44 0.00 1,972.44 5,400.00 91.18 3,818.47 2,096.51 -331.965.81 551,457.326,011,532.823,758.37 0.00 2,072.34 5,500.00 91.18 3,816.41 2,195.98 -321.845.81 551,466.766,011,632.353,756.31 0.00 2,172.24 5,600.00 91.18 3,814.35 2,295.44 -311.715.81 551,476.206,011,731.873,754.25 0.00 2,272.13 5,700.00 91.18 3,812.29 2,394.91 -301.585.81 551,485.636,011,831.393,752.19 0.00 2,372.03 5,800.00 91.18 3,810.22 2,494.37 -291.455.81 551,495.076,011,930.923,750.12 0.00 2,471.93 5,839.19 91.18 3,809.42 2,533.35 -287.485.81 551,498.776,011,969.923,749.32 0.00 2,511.08 Start Dir 3º/100' : 5839.19' MD, 3809.42'TVD 5,900.00 89.62 3,808.99 2,593.89 -281.824.88 551,504.016,012,030.493,748.89 3.00 2,571.85 5,956.67 88.16 3,810.09 2,650.38 -277.444.00 551,508.006,012,087.003,749.99 3.00 2,628.50 3/25/2020 1:00:34PM COMPASS 5000.15 Build 91E Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: PLAN: MPU I-35 - Slot I-22 MPU I-35 Survey Calculation Method:Minimum Curvature MPU I-35 prelim RKB @ 60.10usft (Original Well Design:MPU I-35 wp07 Database:NORTH US + CANADA MD Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well North Reference: Well PLAN: MPU I-35 - Slot I-22 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,750.08 Vert Section 5,959.51 88.16 3,810.18 2,653.21 -277.243.91 551,508.186,012,089.843,750.08 3.00 2,631.34 End Dir : 5959.51' MD, 3810.18' TVD 6,000.00 88.16 3,811.48 2,693.59 -274.483.91 551,510.666,012,130.233,751.38 0.00 2,671.81 6,100.00 88.16 3,814.69 2,793.30 -267.653.91 551,516.796,012,229.983,754.59 0.00 2,771.75 6,200.00 88.16 3,817.90 2,893.02 -260.833.91 551,522.926,012,329.733,757.80 0.00 2,871.70 6,300.00 88.16 3,821.11 2,992.73 -254.013.91 551,529.056,012,429.483,761.01 0.00 2,971.64 6,400.00 88.16 3,824.32 3,092.45 -247.183.91 551,535.186,012,529.233,764.22 0.00 3,071.59 6,500.00 88.16 3,827.54 3,192.16 -240.363.91 551,541.316,012,628.983,767.44 0.00 3,171.54 6,600.00 88.16 3,830.75 3,291.88 -233.543.91 551,547.446,012,728.733,770.65 0.00 3,271.48 6,700.00 88.16 3,833.96 3,391.59 -226.713.91 551,553.576,012,828.483,773.86 0.00 3,371.43 6,800.00 88.16 3,837.17 3,491.31 -219.893.91 551,559.706,012,928.233,777.07 0.00 3,471.37 6,900.00 88.16 3,840.38 3,591.02 -213.073.91 551,565.836,013,027.983,780.28 0.00 3,571.32 7,000.00 88.16 3,843.59 3,690.74 -206.243.91 551,571.966,013,127.733,783.49 0.00 3,671.27 7,100.00 88.16 3,846.80 3,790.46 -199.423.91 551,578.096,013,227.483,786.70 0.00 3,771.21 7,200.00 88.16 3,850.01 3,890.17 -192.593.91 551,584.226,013,327.233,789.91 0.00 3,871.16 7,300.00 88.16 3,853.22 3,989.89 -185.773.91 551,590.356,013,426.983,793.12 0.00 3,971.10 7,400.00 88.16 3,856.43 4,089.60 -178.953.91 551,596.486,013,526.733,796.33 0.00 4,071.05 7,500.00 88.16 3,859.64 4,189.32 -172.123.91 551,602.616,013,626.483,799.54 0.00 4,170.99 7,600.00 88.16 3,862.86 4,289.03 -165.303.91 551,608.746,013,726.233,802.76 0.00 4,270.94 7,700.00 88.16 3,866.07 4,388.75 -158.483.91 551,614.876,013,825.983,805.97 0.00 4,370.89 7,800.00 88.16 3,869.28 4,488.46 -151.653.91 551,621.006,013,925.743,809.18 0.00 4,470.83 7,900.00 88.16 3,872.49 4,588.18 -144.833.91 551,627.136,014,025.493,812.39 0.00 4,570.78 8,000.00 88.16 3,875.70 4,687.89 -138.013.91 551,633.266,014,125.243,815.60 0.00 4,670.72 8,100.00 88.16 3,878.91 4,787.61 -131.183.91 551,639.396,014,224.993,818.81 0.00 4,770.67 8,200.00 88.16 3,882.12 4,887.32 -124.363.91 551,645.526,014,324.743,822.02 0.00 4,870.62 8,292.34 88.16 3,885.09 4,979.40 -118.063.91 551,651.186,014,416.853,824.99 0.00 4,962.91 Start Dir 3º/100' : 8292.34' MD, 3885.09'TVD 8,292.49 88.16 3,885.09 4,979.55 -118.053.91 551,651.196,014,417.003,824.99 3.02 4,963.06 8,300.00 88.33 3,885.32 4,987.04 -117.534.06 551,651.666,014,424.493,825.22 3.00 4,970.56 8,374.14 90.03 3,886.38 5,060.91 -111.365.49 551,657.316,014,498.393,826.28 3.00 5,044.67 End Dir : 8374.14' MD, 3886.38' TVD 8,400.00 90.03 3,886.37 5,086.65 -108.885.49 551,659.616,014,524.153,826.27 0.00 5,070.52 8,500.00 90.03 3,886.31 5,186.19 -99.315.49 551,668.496,014,623.743,826.21 0.00 5,170.45 8,600.00 90.03 3,886.26 5,285.73 -89.745.49 551,677.376,014,723.343,826.16 0.00 5,270.39 8,700.00 90.03 3,886.21 5,385.27 -80.175.49 551,686.256,014,822.933,826.11 0.00 5,370.33 8,800.00 90.03 3,886.16 5,484.81 -70.605.49 551,695.136,014,922.533,826.06 0.00 5,470.27 8,900.00 90.03 3,886.11 5,584.35 -61.025.49 551,704.016,015,022.123,826.01 0.00 5,570.21 9,000.00 90.03 3,886.06 5,683.90 -51.455.49 551,712.896,015,121.723,825.96 0.00 5,670.15 9,100.00 90.03 3,886.00 5,783.44 -41.885.49 551,721.766,015,221.313,825.90 0.00 5,770.09 9,200.00 90.03 3,885.95 5,882.98 -32.315.49 551,730.646,015,320.913,825.85 0.00 5,870.03 9,300.00 90.03 3,885.90 5,982.52 -22.745.49 551,739.526,015,420.513,825.80 0.00 5,969.97 9,400.00 90.03 3,885.85 6,082.06 -13.175.49 551,748.406,015,520.103,825.75 0.00 6,069.91 9,500.00 90.03 3,885.80 6,181.60 -3.605.49 551,757.286,015,619.703,825.70 0.00 6,169.85 9,600.00 90.03 3,885.75 6,281.14 5.985.49 551,766.166,015,719.293,825.65 0.00 6,269.79 9,700.00 90.03 3,885.69 6,380.68 15.555.49 551,775.046,015,818.893,825.59 0.00 6,369.73 3/25/2020 1:00:34PM COMPASS 5000.15 Build 91E Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: PLAN: MPU I-35 - Slot I-22 MPU I-35 Survey Calculation Method:Minimum Curvature MPU I-35 prelim RKB @ 60.10usft (Original Well Design:MPU I-35 wp07 Database:NORTH US + CANADA MD Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well North Reference: Well PLAN: MPU I-35 - Slot I-22 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,825.54 Vert Section 9,800.00 90.03 3,885.64 6,480.22 25.125.49 551,783.926,015,918.483,825.54 0.00 6,469.67 9,900.00 90.03 3,885.59 6,579.76 34.695.49 551,792.806,016,018.083,825.49 0.00 6,569.61 10,000.00 90.03 3,885.54 6,679.30 44.265.49 551,801.686,016,117.673,825.44 0.00 6,669.55 10,100.00 90.03 3,885.49 6,778.84 53.835.49 551,810.566,016,217.273,825.39 0.00 6,769.49 10,200.00 90.03 3,885.44 6,878.39 63.415.49 551,819.436,016,316.863,825.34 0.00 6,869.43 10,300.00 90.03 3,885.38 6,977.93 72.985.49 551,828.316,016,416.463,825.28 0.00 6,969.37 10,400.00 90.03 3,885.33 7,077.47 82.555.49 551,837.196,016,516.053,825.23 0.00 7,069.31 10,500.00 90.03 3,885.28 7,177.01 92.125.49 551,846.076,016,615.653,825.18 0.00 7,169.25 10,600.00 90.03 3,885.23 7,276.55 101.695.49 551,854.956,016,715.243,825.13 0.00 7,269.18 10,700.00 90.03 3,885.18 7,376.09 111.265.49 551,863.836,016,814.843,825.08 0.00 7,369.12 10,800.00 90.03 3,885.13 7,475.63 120.845.49 551,872.716,016,914.433,825.03 0.00 7,469.06 10,870.77 90.03 3,885.09 7,546.08 127.615.49 551,878.996,016,984.923,824.99 0.00 7,539.79 Start Dir 3º/100' : 10870.77' MD, 3885.09'TVD 10,870.85 90.03 3,885.09 7,546.16 127.625.49 551,879.006,016,985.003,824.99 3.12 7,539.87 10,900.00 89.61 3,885.18 7,575.15 130.606.26 551,881.786,017,014.013,825.08 3.00 7,569.00 10,960.39 88.74 3,886.05 7,635.08 138.017.85 551,888.786,017,073.983,825.95 3.00 7,629.26 End Dir : 10960.39' MD, 3886.05' TVD 11,000.00 88.74 3,886.92 7,674.31 143.427.85 551,893.916,017,113.243,826.82 0.00 7,668.75 11,100.00 88.74 3,889.11 7,773.34 157.077.85 551,906.886,017,212.363,829.01 0.00 7,768.44 11,200.00 88.74 3,891.30 7,872.38 170.737.85 551,919.846,017,311.493,831.20 0.00 7,868.12 11,300.00 88.74 3,893.49 7,971.42 184.387.85 551,932.806,017,410.613,833.39 0.00 7,967.81 11,400.00 88.74 3,895.68 8,070.46 198.037.85 551,945.766,017,509.733,835.58 0.00 8,067.50 11,500.00 88.74 3,897.87 8,169.50 211.687.85 551,958.736,017,608.853,837.77 0.00 8,167.19 11,600.00 88.74 3,900.06 8,268.54 225.347.85 551,971.696,017,707.983,839.96 0.00 8,266.88 11,700.00 88.74 3,902.25 8,367.58 238.997.85 551,984.656,017,807.103,842.15 0.00 8,366.56 11,800.00 88.74 3,904.44 8,466.62 252.647.85 551,997.626,017,906.223,844.34 0.00 8,466.25 11,900.00 88.74 3,906.64 8,565.66 266.297.85 552,010.586,018,005.343,846.54 0.00 8,565.94 12,000.00 88.74 3,908.83 8,664.70 279.957.85 552,023.546,018,104.473,848.73 0.00 8,665.63 12,100.00 88.74 3,911.02 8,763.74 293.607.85 552,036.506,018,203.593,850.92 0.00 8,765.32 12,200.00 88.74 3,913.21 8,862.78 307.257.85 552,049.476,018,302.713,853.11 0.00 8,865.01 12,300.00 88.74 3,915.40 8,961.82 320.907.85 552,062.436,018,401.833,855.30 0.00 8,964.69 12,400.00 88.74 3,917.59 9,060.86 334.567.85 552,075.396,018,500.953,857.49 0.00 9,064.38 12,500.00 88.74 3,919.78 9,159.90 348.217.85 552,088.366,018,600.083,859.68 0.00 9,164.07 12,600.00 88.74 3,921.97 9,258.94 361.867.85 552,101.326,018,699.203,861.87 0.00 9,263.76 12,700.00 88.74 3,924.17 9,357.98 375.517.85 552,114.286,018,798.323,864.07 0.00 9,363.45 12,800.00 88.74 3,926.36 9,457.02 389.177.85 552,127.256,018,897.443,866.26 0.00 9,463.13 12,900.00 88.74 3,928.55 9,556.05 402.827.85 552,140.216,018,996.573,868.45 0.00 9,562.82 13,000.00 88.74 3,930.74 9,655.09 416.477.85 552,153.176,019,095.693,870.64 0.00 9,662.51 13,100.00 88.74 3,932.93 9,754.13 430.127.85 552,166.136,019,194.813,872.83 0.00 9,762.20 13,200.00 88.74 3,935.12 9,853.17 443.787.85 552,179.106,019,293.933,875.02 0.00 9,861.89 13,300.00 88.74 3,937.31 9,952.21 457.437.85 552,192.066,019,393.053,877.21 0.00 9,961.57 13,352.36 88.74 3,938.46 10,004.07 464.587.85 552,198.856,019,444.953,878.36 0.00 10,013.77 Start Dir 3º/100' : 13352.36' MD, 3938.46'TVD 13,399.84 87.32 3,940.09 10,051.08 471.067.85 552,205.006,019,492.003,879.99 3.00 10,061.09 3/25/2020 1:00:34PM COMPASS 5000.15 Build 91E Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: PLAN: MPU I-35 - Slot I-22 MPU I-35 Survey Calculation Method:Minimum Curvature MPU I-35 prelim RKB @ 60.10usft (Original Well Design:MPU I-35 wp07 Database:NORTH US + CANADA MD Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well North Reference: Well PLAN: MPU I-35 - Slot I-22 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,881.76 Vert Section 13,437.40 87.28 3,941.86 10,088.29 475.826.72 552,209.506,019,529.243,881.76 3.00 10,098.52 End Dir : 13437.4' MD, 3941.86' TVD 13,500.00 87.28 3,944.83 10,150.39 483.146.72 552,216.396,019,591.393,884.73 0.00 10,160.95 13,600.00 87.28 3,949.58 10,249.59 494.836.72 552,227.396,019,690.663,889.48 0.00 10,260.68 13,700.00 87.28 3,954.33 10,348.79 506.526.72 552,238.396,019,789.933,894.23 0.00 10,360.41 13,800.00 87.28 3,959.08 10,447.99 518.216.72 552,249.406,019,889.203,898.98 0.00 10,460.14 13,900.00 87.28 3,963.83 10,547.19 529.916.72 552,260.406,019,988.463,903.73 0.00 10,559.87 14,000.00 87.28 3,968.58 10,646.39 541.606.72 552,271.406,020,087.733,908.48 0.00 10,659.60 14,100.00 87.28 3,973.33 10,745.59 553.296.72 552,282.406,020,187.003,913.23 0.00 10,759.33 14,200.00 87.28 3,978.08 10,844.79 564.996.72 552,293.416,020,286.273,917.98 0.00 10,859.06 14,300.00 87.28 3,982.83 10,943.99 576.686.72 552,304.416,020,385.543,922.73 0.00 10,958.79 14,400.00 87.28 3,987.58 11,043.19 588.376.72 552,315.416,020,484.813,927.48 0.00 11,058.51 14,500.00 87.28 3,992.33 11,142.39 600.076.72 552,326.426,020,584.083,932.23 0.00 11,158.24 14,600.00 87.28 3,997.08 11,241.59 611.766.72 552,337.426,020,683.353,936.98 0.00 11,257.97 14,700.00 87.28 4,001.83 11,340.79 623.456.72 552,348.426,020,782.623,941.73 0.00 11,357.70 14,768.88 87.28 4,005.10 11,409.12 631.516.72 552,356.006,020,851.003,945.00 0.00 11,426.40 Total Depth : 14768.88' MD, 4005.1' TVD - 6 5/8" x 8 1/2" Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Tar gets Dip Angle (°) Dip Dir. (°) MPU I-35 (Antietam) wp04 CP3 3,885.09 6,016,985.00 551,879.007,546.16 127.620.00 0.00 -plan hits target center - Point MPU I-35 (Antietam) wp04 Heel 3,825.10 6,010,811.00 551,389.001,375.11 -405.310.00 0.00 -plan hits target center - Circle (radius 30.00) MPU I-35 (Antietam) wp02 CP4 3,940.09 6,019,492.00 552,205.0010,051.08 471.060.00 0.00 -plan hits target center - Point MPU I-35 (Antietam) wp04 CP2 3,885.09 6,014,417.00 551,651.194,979.55 -118.050.00 0.00 -plan hits target center - Point MPU I-35 (Antietam) wp02 CP1 3,810.09 6,012,087.00 551,508.002,650.38 -277.440.00 0.00 -plan hits target center - Point MPU I-35 (Antietam) wp04 Toe 4,005.10 6,020,851.00 552,356.0011,409.13 631.510.00 0.00 -plan hits target center - Point 3/25/2020 1:00:34PM COMPASS 5000.15 Build 91E Page 8 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt I Pad Halliburton Standard Proposal Report Well: Wellbore: PLAN: MPU I-35 - Slot I-22 MPU I-35 Survey Calculation Method:Minimum Curvature MPU I-35 prelim RKB @ 60.10usft (Original Well Design:MPU I-35 wp07 Database:NORTH US + CANADA MD Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well North Reference: Well PLAN: MPU I-35 - Slot I-22 True Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 6 5/8" x 8 1/2"4,005.1014,768.88 6-5/8 8-1/2 9 5/8" x 12 1/4"3,825.104,674.60 9-5/8 12-1/4 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 2,439.50 2,409.10 UG4A 4,432.15 3,797.10 SB_NA 2,052.60 2,031.10 SV1 1,355.75 1,352.10 SV5 1,803.88 1,788.10 BPRF 3,458.23 3,326.10 LA3 4,715.79 3,828.10 SB_NB (heel) 3,808.67 3,558.10 UGNU MB Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 1,000.00 1,000.00 0.00 0.00 Start Dir 4º/100' : 1000' MD, 1000'TVD 1,618.26 1,606.75 -31.83 -45.45 End Dir : 1618.26' MD, 1606.75' TVD 2,405.99 2,376.36 -49.90 -93.45 Start Dir 4º/100' : 2405.99' MD, 2376.36'TVD 4,574.60 3,816.38 -55.59 -261.37 End Dir : 4574.6' MD, 3816.38' TVD 4,674.60 3,825.10 1,275.99 -415.25 Start Dir 4º/100' : 4674.6' MD, 3825.1'TVD 4,829.15 3,830.25 1,375.12 -405.31 End Dir : 4829.15' MD, 3830.25' TVD 5,839.19 3,809.42 1,528.72 -389.78 Start Dir 3º/100' : 5839.19' MD, 3809.42'TVD 5,959.51 3,810.18 2,533.35 -287.48 End Dir : 5959.51' MD, 3810.18' TVD 8,292.34 3,885.09 2,650.38 -277.44 Start Dir 3º/100' : 8292.34' MD, 3885.09'TVD 8,374.14 3,886.38 2,653.21 -277.24 End Dir : 8374.14' MD, 3886.38' TVD 10,870.77 3,885.09 4,979.40 -118.06 Start Dir 3º/100' : 10870.77' MD, 3885.09'TVD 10,960.39 3,886.05 4,979.55 -118.05 End Dir : 10960.39' MD, 3886.05' TVD 13,352.36 3,938.46 5,060.91 -111.36 Start Dir 3º/100' : 13352.36' MD, 3938.46'TVD 13,437.40 3,941.86 7,546.08 127.61 End Dir : 13437.4' MD, 3941.86' TVD 14,768.88 4,005.10 7,546.16 127.62 Total Depth : 14768.88' MD, 4005.1' TVD 3/25/2020 1:00:34PM COMPASS 5000.15 Build 91E Page 9 25 March, 2020Milne PointM Pt I PadPLAN: MPU I-35 - Slot I-22MPU I-35MPU I-35 wp07Reference Design: M Pt I Pad - PLAN: MPU I-35 - Slot I-22 - MPU I-35 - MPU I-35 wp07Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,009,438.87 N, 551,803.81 E (70° 26' 11.51" N, 149° 34' 39.49" W)Datum Height: MPU I-35 prelim RKB @ 60.10usft (Original Well Elev)Scan Range: 26.50 to 4,674.60 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referenceScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for PLAN: MPU I-35 - Slot I-22 - MPU I-35 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,674.60 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - PLAN: MPU I-35 - Slot I-22 - MPU I-35 - MPU I-35 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt H PadM Pt I PadMPI-01 - MPI-01 - MPI-0144.31 1,124.37 34.96 1,145.11 4.7361,124.37Centre Distance Pass - MPI-01 - MPI-01 - MPI-0144.32 1,126.50 34.95 1,147.05 4.7301,126.50Clearance Factor Pass - MPI-02 - MPI-02 - MPI-0298.08 1,223.52 87.90 1,250.40 9.6411,223.52Centre Distance Pass - MPI-02 - MPI-02 - MPI-0298.09 1,226.50 87.89 1,252.99 9.6171,226.50Ellipse Separation Pass - MPI-02 - MPI-02 - MPI-0299.15 1,251.50 88.75 1,274.36 9.5281,251.50Clearance Factor Pass - MPI-03 - MPI-03 - MPI-03211.52 1,194.61 201.58 1,200.00 21.2801,194.61Centre Distance Pass - MPI-03 - MPI-03 - MPI-03211.64 1,226.50 201.46 1,228.11 20.7931,226.50Ellipse Separation Pass - MPI-03 - MPI-03 - MPI-03221.46 1,426.50 210.09 1,400.00 19.4831,426.50Clearance Factor Pass - MPI-04 - MPI-04 - MPI-04286.23 1,151.47 276.61 1,166.48 29.7691,151.47Centre Distance Pass - MPI-04 - MPI-04 - MPI-04286.38 1,176.50 276.58 1,188.33 29.2131,176.50Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-041,106.76 4,674.60 1,055.76 3,859.90 21.7014,674.60Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A286.23 1,151.47 276.61 1,166.48 29.7691,151.47Centre Distance Pass - MPI-04 - MPI-04A - MPI-04A286.38 1,176.50 276.58 1,188.33 29.2131,176.50Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A1,106.76 4,674.60 1,055.76 3,859.90 21.7014,674.60Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL1286.23 1,151.47 276.61 1,166.48 29.7691,151.47Centre Distance Pass - MPI-04 - MPI-04AL1 - MPI-04AL1286.38 1,176.50 276.58 1,188.33 29.2131,176.50Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,106.76 4,674.60 1,055.76 3,859.90 21.7014,674.60Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB1286.23 1,151.47 276.61 1,166.48 29.7691,151.47Centre Distance Pass - MPI-04 - MPI-04APB1 - MPI-04APB1286.38 1,176.50 276.58 1,188.33 29.2131,176.50Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB11,106.76 4,674.60 1,055.76 3,859.90 21.7014,674.60Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB1286.23 1,151.47 276.61 1,166.48 29.7691,151.47Centre Distance Pass - MPI-04 - MPI-04PB1 - MPI-04PB1286.38 1,176.50 276.58 1,188.33 29.2131,176.50Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,106.69 4,674.60 1,055.80 3,862.61 21.7474,674.60Clearance Factor Pass - MPI-05 - MPI-05 - MPI-0544.33 1,593.15 33.00 1,602.26 3.9131,593.15Ellipse Separation Pass - MPI-05 - MPI-05 - MPI-0544.50 1,601.50 33.08 1,609.49 3.8981,601.50Clearance Factor Pass - MPI-06 - MPI-06 - MPI-06279.19 26.50 277.35 30.50 151.19726.50Centre Distance Pass - 25 March, 2020-13:07COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for PLAN: MPU I-35 - Slot I-22 - MPU I-35 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,674.60 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - PLAN: MPU I-35 - Slot I-22 - MPU I-35 - MPU I-35 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-06 - MPI-06 - MPI-06280.61 626.50 275.10 628.50 50.887626.50Ellipse Separation Pass - MPI-06 - MPI-06 - MPI-06333.66 1,801.50 320.35 1,700.00 25.0771,801.50Clearance Factor Pass - MPI-07 - MPI-07 - MPI-07163.40 2,145.67 148.88 2,118.88 11.2472,145.67Centre Distance Pass - MPI-07 - MPI-07 - MPI-07163.42 2,151.50 148.84 2,124.32 11.2122,151.50Ellipse Separation Pass - MPI-07 - MPI-07 - MPI-07234.58 3,351.50 211.34 3,263.77 10.0943,351.50Clearance Factor Pass - MPI-09 - MPI-09 - MPI-09148.21 711.04 141.97 715.14 23.754711.04Centre Distance Pass - MPI-09 - MPI-09 - MPI-09148.26 726.50 141.95 729.82 23.505726.50Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-09155.31 901.50 148.23 895.95 21.913901.50Clearance Factor Pass - MPI-10 - MPI-10 - MPI-1092.63 509.16 88.44 511.61 22.131509.16Centre Distance Pass - MPI-10 - MPI-10 - MPI-1092.72 526.50 88.40 528.02 21.495526.50Ellipse Separation Pass - MPI-10 - MPI-10 - MPI-10111.58 951.50 104.22 945.85 15.144951.50Clearance Factor Pass - MPI-15 - MPI-15 - MPI-1546.78 974.22 40.13 980.41 7.035974.22Centre Distance Pass - MPI-15 - MPI-15 - MPI-1546.79 976.50 40.12 982.62 7.020976.50Ellipse Separation Pass - MPI-15 - MPI-15 - MPI-1548.22 1,026.50 41.24 1,030.94 6.9021,026.50Clearance Factor Pass - MPI-15 - MPI-15L1 - MPI-15L146.78 974.22 40.13 980.41 7.035974.22Centre Distance Pass - MPI-15 - MPI-15L1 - MPI-15L146.79 976.50 40.12 982.62 7.020976.50Ellipse Separation Pass - MPI-15 - MPI-15L1 - MPI-15L148.22 1,026.50 41.24 1,030.94 6.9021,026.50Clearance Factor Pass - MPI-15 - MPI-15PB1 - MPI-15PB146.78 974.22 40.13 980.41 7.035974.22Centre Distance Pass - MPI-15 - MPI-15PB1 - MPI-15PB146.79 976.50 40.12 982.62 7.020976.50Ellipse Separation Pass - MPI-15 - MPI-15PB1 - MPI-15PB148.22 1,026.50 41.24 1,030.94 6.9021,026.50Clearance Factor Pass - MPI-16 - MPI-16 - MPI-1644.42 101.50 42.57 109.75 24.062101.50Centre Distance Pass - MPI-16 - MPI-16 - MPI-1644.66 201.50 42.14 209.51 17.776201.50Ellipse Separation Pass - MPI-16 - MPI-16 - MPI-1658.33 526.50 53.35 531.44 11.722526.50Clearance Factor Pass - MPI-17 - MPI-17 - MPI-1712.23 313.21 8.45 321.48 3.238313.21Centre Distance Pass - MPI-17 - MPI-17 - MPI-1712.38 351.50 8.19 359.67 2.951351.50Ellipse Separation Pass - MPI-17 - MPI-17 - MPI-1713.70 426.50 8.68 434.41 2.728426.50Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L112.23 313.21 8.45 321.48 3.238313.21Centre Distance Pass - MPI-17 - MPI-17L1 - MPI-17L112.38 351.50 8.19 359.67 2.951351.50Ellipse Separation Pass - MPI-17 - MPI-17L1 - MPI-17L113.70 426.50 8.68 434.41 2.728426.50Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB112.23 313.21 8.45 321.48 3.238313.21Centre Distance Pass - 25 March, 2020-13:07COMPASSPage 3 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for PLAN: MPU I-35 - Slot I-22 - MPU I-35 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,674.60 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - PLAN: MPU I-35 - Slot I-22 - MPU I-35 - MPU I-35 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-17 - MPI-17L1PB1 - MPI-17L1PB112.38 351.50 8.19 359.67 2.951351.50Ellipse Separation Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB113.70 426.50 8.68 434.41 2.728426.50Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L212.23 313.21 8.45 321.48 3.238313.21Centre Distance Pass - MPI-17 - MPI-17L2 - MPI-17L212.38 351.50 8.19 359.67 2.951351.50Ellipse Separation Pass - MPI-17 - MPI-17L2 - MPI-17L213.70 426.50 8.68 434.41 2.728426.50Clearance Factor Pass - MPI-18 - MPI-18 - MPI-1815.52 26.50 13.68 29.60 8.40726.50Centre Distance Pass - MPI-18 - MPI-18 - MPI-1815.75 101.50 13.61 104.52 7.356101.50Ellipse Separation Pass - MPI-18 - MPI-18 - MPI-1820.09 476.50 15.66 479.09 4.536476.50Clearance Factor Pass - MPI-19 - MPI-19 - MPI-1945.99 26.50 44.14 35.50 24.86826.50Centre Distance Pass - MPI-19 - MPI-19 - MPI-1946.21 101.50 44.00 110.23 20.884101.50Ellipse Separation Pass - MPI-19 - MPI-19 - MPI-1952.53 626.50 46.67 634.89 8.966626.50Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L145.99 26.50 44.14 35.50 24.86826.50Centre Distance Pass - MPI-19 - MPI-19L1 - MPI-19L146.21 101.50 44.00 110.23 20.884101.50Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L152.53 626.50 46.67 634.89 8.966626.50Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB145.99 26.50 44.14 35.50 24.86826.50Centre Distance Pass - MPI-19 - MPI-19PB1 - MPI-19PB146.21 101.50 44.00 110.23 20.884101.50Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB152.53 626.50 46.67 634.89 8.966626.50Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB245.99 26.50 44.14 35.50 24.86826.50Centre Distance Pass - MPI-19 - MPI-19PB2 - MPI-19PB246.21 101.50 44.00 110.23 20.884101.50Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB252.53 626.50 46.67 634.89 8.966626.50Clearance Factor Pass - PLAN: MPU I-36 - Slot I-26 - MPU I-36 - MPU I-36 wp0114.81 278.46 112.24 278.16 44.736278.46Centre Distance Pass - PLAN: MPU I-36 - Slot I-26 - MPU I-36 - MPU I-36 wp0114.85 301.50 112.19 300.00 43.147301.50Ellipse Separation Pass - PLAN: MPU I-36 - Slot I-26 - MPU I-36 - MPU I-36 wp01,028.34 4,674.60 980.54 5,224.05 21.5124,674.60Clearance Factor Pass - M Pt J PadMPJ-03 - MPJ-03 - MPJ-031,247.69 4,674.60 1,200.13 5,448.00 26.2364,674.60Clearance Factor Pass - 25 March, 2020-13:07COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for PLAN: MPU I-35 - Slot I-22 - MPU I-35 wp07Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 800.00 MPU I-35 wp07 3_Gyro-GC_Csg800.00 4,674.60 MPU I-35 wp07 3_MWD+IFR2+MS+Sag4,674.60 14,768.88 MPU I-35 wp07 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.25 March, 2020-13:07COMPASSPage 5 of 7 0.001.002.003.004.00Separation Factor0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750Measured Depth (500 usft/in)No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:PLAN: MPU I-35 - Slot I-22 NAD 1927 (NADCON CONUS)Alaska Zone 0433.60+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009438.87551803.81 70° 26' 11.512 N149° 34' 39.487 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PLAN: MPU I-35 - Slot I-22, True NorthVertical (TVD) Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well Elev)Measured Depth Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-03-23T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 800.00 MPU I-35 wp07 (MPU I-35) 3_Gyro-GC_Csg800.00 4674.60 MPU I-35 wp07 (MPU I-35) 3_MWD+IFR2+MS+Sag4674.60 14768.88 MPU I-35 wp07 (MPU I-35) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750Measured Depth (500 usft/in)MPI-10MPI-15MPI-01MPU I-36 wp04MPI-17MPI-09MPI-19MPI-16MPI-18GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 14768.88Project: Milne PointSite: M Pt I PadWell: PLAN: MPU I-35 - Slot I-22Wellbore: MPU I-35Plan: MPU I-35 wp07Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3825.10 3765.00 4674.60 9-5/8 9 5/8" x 12 1/4"4005.10 3945.00 14768.88 6-5/8 6 5/8" x 8 1/2" 25 March, 2020Milne PointM Pt I PadPLAN: MPU I-35 - Slot I-22MPU I-35MPU I-35 wp07Reference Design: M Pt I Pad - PLAN: MPU I-35 - Slot I-22 - MPU I-35 - MPU I-35 wp07Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,009,438.87 N, 551,803.81 E (70° 26' 11.51" N, 149° 34' 39.49" W)Datum Height: MPU I-35 prelim RKB @ 60.10usft (Original Well Elev)Scan Range: 4,674.60 to 14,768.88 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referenceScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for PLAN: MPU I-35 - Slot I-22 - MPU I-35 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,674.60 to 14,768.88 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - PLAN: MPU I-35 - Slot I-22 - MPU I-35 - MPU I-35 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt H PadMPH-18 - MPH-18 - MPH-181,011.31 8,349.60 753.11 8,635.60 3.9178,349.60Clearance Factor Pass - MPH-18 - MPH-18 - MPH-181,008.03 8,374.60 752.78 8,639.00 3.9498,374.60Ellipse Separation Pass - MPH-18 - MPH-18 - MPH-181,000.59 8,496.84 766.74 8,639.00 4.2798,496.84Centre Distance Pass - MPH-18 - MPH-18L1 - MPH-18L1975.15 7,814.86 789.00 7,939.76 5.2397,814.86Centre Distance Pass - MPH-18 - MPH-18L1 - MPH-18L1984.00 8,499.60 769.81 8,594.51 4.5948,499.60Clearance Factor Pass - MPH-18 - MPH-18L2 - MPH-18L2886.64 8,374.60 651.08 8,630.00 3.7648,374.60Clearance Factor Pass - MPH-18 - MPH-18L2 - MPH-18L2880.13 8,481.82 661.52 8,630.00 4.0268,481.82Centre Distance Pass - M Pt I PadMPI-04 - MPI-04 - MPI-041,106.56 4,705.52 1,055.01 3,875.11 21.4644,705.52Centre Distance Pass - MPI-04 - MPI-04 - MPI-041,106.98 4,749.60 1,054.58 3,895.80 21.1264,749.60Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-041,164.85 5,149.60 1,105.58 4,075.01 19.6525,149.60Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A1,106.56 4,705.52 1,055.01 3,875.11 21.4644,705.52Centre Distance Pass - MPI-04 - MPI-04A - MPI-04A1,106.98 4,749.60 1,054.58 3,895.80 21.1264,749.60Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A1,359.57 6,299.60 1,276.11 5,682.00 16.2916,299.60Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,106.56 4,705.52 1,055.01 3,875.11 21.4644,705.52Centre Distance Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,106.98 4,749.60 1,054.58 3,895.80 21.1264,749.60Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,171.87 6,124.60 1,089.90 5,598.00 14.2956,124.60Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB11,106.56 4,705.52 1,055.01 3,875.11 21.4644,705.52Centre Distance Pass - MPI-04 - MPI-04APB1 - MPI-04APB11,106.98 4,749.60 1,054.58 3,895.80 21.1264,749.60Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB11,393.48 6,249.60 1,296.56 5,627.00 14.3776,249.60Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,106.45 4,708.73 1,055.02 3,880.02 21.5124,708.73Centre Distance Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,106.81 4,749.60 1,054.67 3,899.84 21.2304,749.60Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,139.79 5,049.60 1,083.50 4,026.18 20.2455,049.60Clearance Factor Pass - MPI-07 - MPI-07 - MPI-071,149.86 4,674.60 1,122.31 3,861.18 41.7404,674.60Ellipse Separation Pass - MPI-07 - MPI-07 - MPI-071,173.60 4,699.60 1,144.89 3,863.40 40.8804,699.60Clearance Factor Pass - MPI-09 - MPI-09 - MPI-091,223.35 4,674.60 1,171.58 3,540.91 23.6294,674.60Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-091,667.37 5,924.60 1,541.18 4,417.04 13.2135,924.60Clearance Factor Pass - 25 March, 2020-13:11COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for PLAN: MPU I-35 - Slot I-22 - MPU I-35 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,674.60 to 14,768.88 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - PLAN: MPU I-35 - Slot I-22 - MPU I-35 - MPU I-35 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-19 - MPI-19 - MPI-19734.72 6,478.91 603.03 5,305.11 5.5796,478.91Centre Distance Pass - MPI-19 - MPI-19 - MPI-19767.91 8,974.60 508.45 7,898.91 2.9608,974.60Ellipse Separation Pass - MPI-19 - MPI-19 - MPI-19881.25 10,824.60 555.09 9,720.00 2.70210,824.60Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L1734.72 6,478.91 602.61 5,305.11 5.5626,478.91Centre Distance Pass - MPI-19 - MPI-19L1 - MPI-19L1743.66 8,974.60 481.90 7,915.50 2.8418,974.60Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L1797.72 9,649.60 511.51 8,539.99 2.7879,649.60Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB1734.72 6,478.91 602.61 5,305.11 5.5626,478.91Centre Distance Pass - MPI-19 - MPI-19PB1 - MPI-19PB1746.19 8,874.60 478.42 7,799.00 2.7878,874.60Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB1751.41 8,924.60 481.11 7,799.00 2.7808,924.60Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB2734.72 6,478.91 602.61 5,305.11 5.5626,478.91Centre Distance Pass - MPI-19 - MPI-19PB2 - MPI-19PB2752.02 9,174.60 487.12 8,116.17 2.8399,174.60Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB2796.23 9,649.60 506.26 8,532.00 2.7469,649.60Clearance Factor Pass - PLAN: MPU I-36 - Slot I-26 - MPU I-36 - MPU I-36 wp0765.48 14,768.88 470.89 15,447.72 2.59814,768.88Clearance Factor Pass - M Pt J PadMPJ-01 - MPJ-01 - MPJ-01121.519,803.5013.534,057.201.1259,803.50Clearance FactorPass - MPJ-01 - MPJ-01A - MPJ-01A42.509,974.60-61.884,173.800.4079,974.60Ellipse SeparationFAIL - MPJ-01 - MPJ-01A - MPJ-01A36.269,999.60-61.064,194.060.3739,999.60Clearance FactorFAIL - MPJ-01 - MPJ-01A - MPJ-01A35.1610,014.94-49.314,207.120.41610,014.94Centre DistanceFAIL - MPJ-01 - MPJ-01AL1 - MPJ-01AL142.509,974.60-61.874,173.800.4079,974.60Ellipse SeparationFAIL - MPJ-01 - MPJ-01AL1 - MPJ-01AL136.269,999.60-61.044,194.060.3739,999.60Clearance FactorFAIL - MPJ-01 - MPJ-01AL1 - MPJ-01AL135.1610,014.94-49.294,207.120.41610,014.94Centre DistanceFAIL - MPJ-03 - MPJ-03 - MPJ-0338.616,271.95-68.924,855.740.3596,271.95Clearance FactorFAIL - MPJ-06 - MPJ-06 - MPJ-06179.30 9,787.69 62.29 4,212.98 1.5329,787.69Centre Distance Pass - MPJ-06 - MPJ-06 - MPJ-06181.529,824.6059.824,236.601.4919,824.60Clearance FactorPass - MPJ-08 - MPJ-08 - MPJ-08588.54 9,660.99 509.10 3,795.82 7.4099,660.99Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08592.50 9,749.60 503.75 3,853.71 6.6769,749.60Ellipse Separation Pass - MPJ-08 - MPJ-08 - MPJ-081,673.45 14,249.60 1,326.86 8,526.44 4.82814,249.60Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A588.54 9,660.99 509.10 3,796.62 7.4099,660.99Centre Distance Pass - MPJ-08 - MPJ-08A - MPJ-08A592.50 9,749.60 503.75 3,854.51 6.6769,749.60Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A681.71 10,099.60 566.23 4,057.41 5.90310,099.60Clearance Factor Pass - 25 March, 2020-13:11COMPASSPage 3 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for PLAN: MPU I-35 - Slot I-22 - MPU I-35 wp07Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,674.60 to 14,768.88 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - PLAN: MPU I-35 - Slot I-22 - MPU I-35 - MPU I-35 wp07MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-10 - MPJ-10 - MPJ-101,207.48 10,217.52 1,084.60 4,004.61 9.82610,217.52Centre Distance Pass - MPJ-10 - MPJ-10 - MPJ-101,208.62 10,274.60 1,083.54 4,026.90 9.66310,274.60Ellipse Separation Pass - MPJ-10 - MPJ-10 - MPJ-101,230.96 10,474.60 1,100.47 4,084.93 9.43310,474.60Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11162.2111,577.45-29.375,027.300.84711,577.45Centre DistanceFAIL - MPJ-11 - MPJ-11 - MPJ-11162.8211,599.60-32.245,044.230.83511,599.60Clearance FactorFAIL - MPJ-11 - MPJ-11 - MPJ-11164.9611,624.60-32.465,063.330.83611,624.60Ellipse SeparationFAIL - MPJ-12 - MPJ-12 - MPJ-12617.37 10,235.78 484.80 4,239.76 4.65710,235.78Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-12617.49 10,249.60 484.56 4,246.72 4.64610,249.60Ellipse Separation Pass - MPJ-12 - MPJ-12 - MPJ-12619.82 10,299.60 485.97 4,272.42 4.63110,299.60Clearance Factor Pass - MPJ-13 - MPJ-13 - MPJ-131,267.02 10,834.72 1,109.73 4,659.69 8.05510,834.72Centre Distance Pass - MPJ-13 - MPJ-13 - MPJ-131,269.93 10,999.60 1,106.84 4,760.00 7.78710,999.60Ellipse Separation Pass - MPJ-13 - MPJ-13 - MPJ-131,302.79 11,324.60 1,131.20 4,981.17 7.59211,324.60Clearance Factor Pass - MPJ-16 - MPJ-16 - MPJ-16748.92 11,783.55 526.87 5,478.53 3.37311,783.55Centre Distance Pass - MPJ-16 - MPJ-16 - MPJ-16754.35 11,974.60 519.37 5,646.29 3.21011,974.60Ellipse Separation Pass - MPJ-16 - MPJ-16 - MPJ-16774.22 12,174.60 529.27 5,806.31 3.16112,174.60Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-25673.97 9,531.64 595.89 3,678.66 8.6329,531.64Centre Distance Pass - MPJ-25 - MPJ-25 - MPJ-25675.23 9,574.60 594.48 3,691.27 8.3629,574.60Ellipse Separation Pass - MPJ-25 - MPJ-25 - MPJ-25705.83 9,749.60 616.51 3,736.91 7.9029,749.60Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1673.97 9,531.64 595.89 3,678.66 8.6329,531.64Centre Distance Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1675.23 9,574.60 594.48 3,691.27 8.3629,574.60Ellipse Separation Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1705.83 9,749.60 616.51 3,736.91 7.9029,749.60Clearance Factor Pass - 25 March, 2020-13:11COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for PLAN: MPU I-35 - Slot I-22 - MPU I-35 wp07Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 800.00 MPU I-35 wp07 3_Gyro-GC_Csg800.00 4,674.60 MPU I-35 wp07 3_MWD+IFR2+MS+Sag4,674.60 14,768.88 MPU I-35 wp07 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.25 March, 2020-13:11COMPASSPage 5 of 7 0.001.002.003.004.00Separation Factor4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850Measured Depth (1100 usft/in)MPJ-03MPJ-01AL1MPJ-01MPJ-06MPJ-11No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.WELL DETAILS:PLAN: MPU I-35 - Slot I-22 NAD 1927 (NADCON CONUS)Alaska Zone 0433.60+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009438.87 551803.8170° 26' 11.512 N149° 34' 39.487 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well PLAN: MPU I-35 - Slot I-22, True NorthVertical (TVD) Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well Elev)Measured Depth Reference:MPU I-35 prelim RKB @ 60.10usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-03-23T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 800.00 MPU I-35 wp07 (MPU I-35) 3_Gyro-GC_Csg800.00 4674.60 MPU I-35 wp07 (MPU I-35) 3_MWD+IFR2+MS+Sag4674.60 14768.88 MPU I-35 wp07 (MPU I-35) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850Measured Depth (1100 usft/in)MPJ-01AMPJ-01AL1GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 14768.88Project: Milne PointSite: M Pt I PadWell: PLAN: MPU I-35 - Slot I-22Wellbore: MPU I-35Plan: MPU I-35 wp07Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3825.10 3765.00 4674.60 9-5/8 9 5/8" x 12 1/4"4005.10 3945.00 14768.88 6-5/8 6 5/8" x 8 1/2" 1 Carlisle, Samantha J (CED) From:Joseph Engel <jengel@hilcorp.com> Sent:Monday, April 6, 2020 3:59 PM To:Schwartz, Guy L (CED) Subject:RE: [EXTERNAL] I-35 injector (PTD 220-034) Guy– WeareplanningtorunagyrotoimprovelocationknowledgeofJͲ11withrespecttoIͲ35lateral,gyrowillberunpriorto spud.Oncewehavethegyrosurveys,ifneeded,wewillnudgethelateraltogiveusaclearancefactorgreaterthan1.0. Wewillalsoshutintheinjector,controldrillpastit,andwatchformagneticinterference. Pleaseletmeknowifyouhaveanyotherquestions. Thankyouforyourtime. ͲJoe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Monday,April6,20202:39PM To:JosephEngel<jengel@hilcorp.com> Subject:[EXTERNAL]IͲ35injector(PTD220Ͳ034) Joe, WhatmitigationsareyouimplementingwhendrillingbyJͲ11(Kupwaterinjector)? GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office 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 (Guy.schwartz@alaska.gov). WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT I-35Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2200340MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 10-B.14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)No MPU I-35 will not be pre-produced (per Operator).16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20 inch conductor set at 107 ft18 Conductor string providedNA19 Surface casing protects all known USDWsYes 9 5/8" casing to be cemented with 2 stage job20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes horizontal lateral with swell packers and ICD/'s22 CMT will cover all known productive horizonsYes BTC calculations are provided.23 Casing designs adequate for C, T, B & permafrostYes Rig has steel pits .24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes Close crossing with J-11 kup water injector.26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes Max form pressure 1761 psi (8.6 ppg EMW) drilling with 8.9-9.5 ppg mud28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MASP= 1361 psi will test BOPE to 3000 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo H2S not expected33 Is presence of H2S gas probableYes AOR completed.34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate4/2/2020ApprGLSDate4/6/2020ApprDLBDate4/2/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGWVJMP4/8/2020JLC 4/8/2020