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218-140
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, February 10, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-03 MILNE PT UNIT M-03 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 02/10/2025 M-03 50-029-23614-00-00 218-140-0 W SPT 2681 2181400 1500 970 969 971 970 144 339 294 291 4YRTST P Adam Earl 1/5/2025 MIT-IA to 2600 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 M-03 Inspection Date: Tubing OA Packer Depth 512 2776 2676 2676IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE250107082847 BBL Pumped:1.2 BBL Returned:1.2 Monday, February 10, 2025 Page 1 of 1 9 9 9 9 9 9 9 999 9 9 99 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.02.10 14:39:03 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, July 27, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-03 MILNE PT UNIT M-03 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/27/2023 M-03 50-029-23614-00-00 218-140-0 W SPT 2681 2181400 2600 812 810 804 799 189 384 348 315 4YRTST P Adam Earl 6/16/2023 MIT IA test psi moved from 1500 to 2600 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 M-03 Inspection Date: Tubing OA Packer Depth 624 2852 2782 2770IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE230620120744 BBL Pumped:1 BBL Returned:1 Thursday, July 27, 2023 Page 1 of 1 By Samantha Carlisle at 2:43 pm, Aug 22, 2022 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: 5/16/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-03 (PTD 218-140) PERF 4/28/2022 Please include current contact information if different from above. PTD:218-140 T36613 Kayla Junke Digitally signed by Kayla Junke Date: 2022.05.17 09:22:38 -08'00' 1 Carlisle, Samantha J (OGC) From:Rixse, Melvin G (OGC) Sent:Thursday, December 23, 2021 11:01 AM To:Brian Glasheen Subject:20211223 1100 PTD218-140 ADD PERFORATIONS APPROVAL M-03 Attachments:MP M-03 AOGCC 10-403 APPROVAL 6-2-2021.pdf; MPU M-03 Add Perf 12-22-21 BPG.docx Brian, Hilcorp is approved to add additional perforations to the Ugnu water disposal well as described in the attached MS‐ Word document. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907‐793‐1231 Office 907‐223‐3605 Cell CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907‐793‐1231 ) or (Melvin.Rixse@alaska.gov). From: Brian Glasheen <Brian.Glasheen@hilcorp.com> Sent: Wednesday, December 22, 2021 4:19 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: M‐03 PTD 218‐140 Mel, Wanted to send you a curtesy note on M‐03 sundry that was approved back in June. We are planning to execute it soon and I added some re perf footage to take advantage of the standard lubricator length of 30’ perf guns. Let me know if you see this as a problem as I read the regs as RE perf not needing a 403. Sundry and new program attached. Thanks, Brian Glasheen 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, 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. Perforate Ugnu Sand 5/24/2021 Well Name: MPU M‐03 API Number: 50‐029‐23614‐00‐00 Current Status: Online – Disposal Injector Pad: M‐Pad Estimated Start Date: June 5th, 2021 Wellwork unit: EL Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218‐140 First Call Engineer: Brian Glasheen 9075451144 Second Call Engineer: AFE Number: Job Type: Perforate Current Bottom Hole Pressure: Maximum Expected BHP: 1,508 psi @ 3,126’ TVD SBHP (2/6/2021) | 9.27 PPG MPSP: 1,195 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 70° @ 2,768’ MD MIN ID: 3.725” XN @ 4,535’ MD Last Tag: 5,485’ MD on 2/6/2021 Brief Well Summary MPU M‐03 was drilled and completed as a water disposal well in December 2018. Since inception, the disposal well has injected 20,000 to 25,000 BWPD. As water production has increased from the field and M‐pad, the goal is to increase the injectivity of the well to reduce wellhead injection pressure and allow for a target of 30,000 BWPD of disposal based on facility pump capacity. Notes Regarding Wellbore Condition Last Wellbore Entry: Drift and Tag and SBHP completed 2/6/21 MIT‐IA to 2,800 psig completed on 6/2/2019. Objective Perforate the Ugnu sands to increase the injectivity index Procedure E‐Line / FB 1. Send Vac truck to PBU to load 104 bbls of SBG at 180 degrees. 2. RU LRS. PT lines to 250 psi L / 1500 psi H 3. Pump 104 bbls of SBG Mixture. Let soak for ~3 hours 4. Displace SBG mixture with 70 bbls of hot 180° Water. Let soak for another 3 hours. a. DNE 1500 psig WHIP b. Target 180° fluid temperature for water. c. FP as needed to complete Eline operation below. 5. During soak times perform Eline work below: 6. MIRU EL. PT lubricator to 200 psig low and 2,500 psig high. 7. MU GR/CCL and 30’ x 2‐7/8” OD dummy gun. Perforate Ugnu Sand 5/24/2021 a. This is for correlation run and to ensure E‐line can get to bottom. 8. RIH to tag @ 5,485’ MD. 9. Perform Up‐pass to the tubing tail at 4,580 MD for correlation pass. a. Tie into MWD Log dated 12/18/2018. 10. POOH to surface. a. Contact engineer and/or geologist Katrine Cuhna with depth correction estimate and to review tie‐ in. 11. PU perf guns. a. 2‐7/8” Guns, 6 SPF, 60° phasing. 12. Perform Confirmation Pass prior to each perforating run. a. Send log to Engineer Brian Glasheen and Katrine Cuhna seek approval prior to perforating. 13. Make the following perforation runs: Sand Top Depth (MD) Bottom Depth (MD) Length Ugnu ±5,225’ ±5,285’ ±60’ Ugnu ±5,314’ ±5,344 ±30’ Ugnu ±5,381’ ±5,471’ ±90’ a. Document condition of fired guns including any damage or un‐fired charges. 14. Assuming all shots fired, RDMO E‐Line. Attachments: 1) Current Schematic 2) Proposed Schematic 3) Tie log Perforate Ugnu Sand 5/24/2021 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): 6,400'N/A Casing Collapse Conductor N/A Surface 2,470psi Production 4,790psi 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 DISPIWC2 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 DIO No. 42 7-5/8" x 4-*1/2" Hyd Perm and N/A 4,477 MD/ 2,680 TVD and N/A Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 6/5/2021 4-1/2" Perforation Depth MD (ft): See Schematic MILNE PT UNIT M-03 See Schematic 80' 20" x 34" 10-3/4" 7-5/8" 2,810' 5,615' 5,210psi 6,890psi 2,053' 3,291' 2,846' 5,648' N/A MILNE POINT / UNDEFINED WDSP 114'114' 12.6 L-80 / Vam Top TVD Burst 4,583' MD N/A 218-140 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23614-00-00 Hilcorp Alaska LLC Length Size 3,886'5,563'3,231'1,195 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025514 5-1/2"17# / L-80 / IBT-MOD 4,471' David Haakinson COMMISSION USE ONLY Authorized Name: ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:22 am, May 25, 2021 321-255 Chad Helgeson (1517) 2021.05.25 07:56:22 - 08'00' 10-404 SFD 5/26/2021MGR28MAY21 DSR-5/26/21dts 6/1/2021 6/1/21 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.06.01 12:01:47 -08'00' RBDMS HEW 6/2/2021 Perforate Ugnu Sand 5/24/2021 Well Name:MPU M-03 API Number: 50-029-23614-00-00 Current Status:Online – Disposal Injector Pad:M-Pad Estimated Start Date:June 5th, 2021 Wellwork unit:EL Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:218-140 First Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:Ian Toomey (907) 903-3987 (M) AFE Number:Job Type:Perforate Current Bottom Hole Pressure: Maximum Expected BHP:1,508 psi @ 3,126’ TVD SBHP (2/6/2021) |9.27 PPG MPSP:1,195 psi Gas Column Gradient (0.1 psi/ft) Max Inclination 70° @ 2,768’ MD MIN ID:3.725” XN @ 4,535’ MD Last Tag:5,485’ MD on 2/6/2021 Brief Well Summary MPU M-03 was drilled and completed as a water disposal well in December 2018. Since inception, the disposal well has injected 20,000 to 25,000 BWPD. As water production has increased from the field and M-pad, the goal is to increase the injectivity of the well to reduce wellhead injection pressure and allow for a target of 30,000 BWPD of disposal based on facility pump capacity. Notes Regarding Wellbore Condition x Last Wellbore Entry: Drift and Tag and SBHP completed 2/6/21 x MIT-IA to 2,800 psig completed on 6/2/2019. Objective x Perforate the Ugnu sands to increase the injectivity index Procedure E-Line 1. MIRU EL. PT lubricator to 200 psig low and 2,500 psig high. 2. MU GR/CCL and 30’ x 2-7/8” OD dummy gun. a. This is for correlation run and to ensure E-line can get to bottom. 3. RIH to tag @ 5,485’ MD. 4. Perform Up-pass to the tubing tail at 4,580 MD for correlation pass. a. Tie into MWD Log dated 12/18/2018. 5. POOH to surface. a. Contact engineer and/or geologist John Salsbury with depth correction estimate and to review tie- in. 6. PU perf guns. Perforate Ugnu Sand 5/24/2021 a. 2-7/8” Guns, 6 SPF, 60° phasing. 7. Perform Confirmation Pass prior to each perforating run. a. Send log to Engineer David Haakinson (dhaakinson@hilcorp.com) and Seth Nolan (jsalsbury@hilcorp.com) and seek approval prior to perforating. 8. Make the following perforation runs: Sand Top Depth (MD) Bottom Depth (MD) Top Depth (TVD) Bottom Depth (TVD) Length Ugnu ±5,225’ ±5,269’ ±3,021’ ±3,046’ ±44’ Ugnu ±5,321’ ±5,344’ ±3,077’ ±3,091’ ±23’ Ugnu ±5,381’ ±5,459’ ±3,114’ ±3,163’ ±78’ a. Perform Confirmation Pass prior to perforating. b. Send log to Engineer David Haakinson (dhaakinson@hilcorp.com) and Seth Nolan (jsalsbury@hilcorp.com) to seek approval prior to perforating. c. Document condition of fired guns including any damage or un-fired charges. 9. Assuming all shots fired, RDMO E-Line. Attachments: 1) Current Schematic 2) Proposed Schematic _____________________________________________________________________________________ Revised By: TDF 9/4/2019 SCHEMATIC Milne Point Unit Well: MPU Moose Pad M-03 Last Completed: 12/22/2018 PTD: 218-140 TD =6,400’ (MD) /TD =3,886’(TVD) 20” Top of Fill @ 5,485’ Tagged on 2/6/2021 Orig. KB Elev.:58.7’/ GL Elev.: 25.0’ RKB-THF: 30.68’ (Doyon 14) 10-3/4” 1 PBTD =5,563’ (MD) / TD =3,231’(TVD) 7-5/8” Shoe @ 5,648’ 2 5-1/2” Tubing 9-7/8” Hole 5Min ID 3.725” 4 6 Min ID 4.562” 3 CBL TOC 3,820’ MD 12/18/18 OH PBTD 5,660’ MD CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34” Conductor 215.5 / A-53 / Weld N/A Surface 114’ N/A 10-3/4" Surface 45.5 / L-80 / TXP SR 9.875” Surface 2,846’ 0.0961 7-5/8" Production 29.7 / L-80 / Hydril 563 6.750” Surface 5,648’ 0.0459 TUBING DETAIL 5-1/2” Tubing 17 / L-80 / IBT-MOD 4.767” Surface 4,471’ 0.0232 4-1/2” Tubing 12.6 / L-80 / Vam Top 3.833” 4,471’ 4,583’ 0.0152 OPEN HOLE / CEMENT DETAIL 42” 50 bbls (10 Yards Pilecrete dumped down backside) 13-1/2” 475 sx 10.7# Perm L, 355 sx 15.8# Class G SwiftCEM 9-7/8” 440 sx 15.8# SwiftCEM WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 70.09 deg. @ 2,769’ MD Max Hole Angle = 67.00 deg. @ Top Perf TREE & WELLHEAD Tree 7-1/16" 5M Tree (5-1/8” Bore) Wellhead 11" 5M Wellhead x 5-1/2" Hydril 563 Top and Bottom Hanger with 5-1/2" CIW "H" BPV profile w/o control lines. JEWELRY DETAIL No. Top MD Item Drift ID 1 31’ Tubing Hanger (5-1/2” Hydril 563 Top & Btm) 4.767” 2 4,387’ 5-1/2” X Nipple, 4.562” Packing Bore 4.562” 3 4,473’ 5-1/2” IBT-Mod x 4-1/2” Vam Top XO 3.833” 4 4,477’ 7-5/8” x 4-1/2” Hydraulic Permanent Packer (Vam Top B x P) 3.856” 5 4,535’ 4-1/2” XN Nipple,Min ID = 3.725” No-Go, 3.813” Packing Bore 3.725” 6 4,581’ 4-1/2” Mule Shoe (Btm @ 4,583’) 3.833” PERFORATION DETAIL Ugnu Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Ugnu Sands 4,630’ 4,680’ 2,737’ 2,756’ 50’ 12/19/18 Open 4,740’ 4,790’ 2,781’ 2,802’ 50’ 12/19/18 Open 4,820’ 4,870’ 2,816’ 2,839’ 50’ 12/19/18 Open 5,030’ 5,050’ 2,916’ 2,926’ 20’ 12/19/18 Open 5,070’ 5,100’ 2,937’ 2,952’ 30’ 12/19/18 Open 5,270’ 5,320’ 3,047’ 3,076’ 50’ 12/19/18 Open 5,460’ 5,510’ 3,163’ 3,196’ 50’ 12/19/18 Open Ugnu – TCP 5” 5132 Razor RDX SBH TL LD, 16 spf (32.0 gr, 1.04 EH, 6.7 Pen) GENERAL WELL INFO API: 50-029-23614-00-00 Drilled and Cased by Doyon 14 - 12/22/2018 _____________________________________________________________________________________ Revised By: TDF 5/17/2021 PROPOSED Milne Point Unit Well: MPU Moose Pad M-03 Last Completed: 12/22/2018 PTD: 218-140 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"x34” Conductor 215.5 / A-53 / Weld N/A Surface 114’ N/A 10-3/4" Surface 45.5 / L-80 / TXP SR 9.875” Surface 2,846’ 0.0961 7-5/8" Production 29.7 / L-80 / Hydril 563 6.750” Surface 5,648’ 0.0459 TUBING DETAIL 5-1/2” Tubing 17 / L-80 / IBT-MOD 4.767” Surface 4,471’ 0.0232 4-1/2” Tubing 12.6 / L-80 / Vam Top 3.833” 4,471’ 4,583’ 0.0152 OPEN HOLE / CEMENT DETAIL 42” 50 bbls (10 Yards Pilecrete dumped down backside) 13-1/2” 475 sx 10.7# Perm L, 355 sx 15.8# Class G SwiftCEM 9-7/8” 440 sx 15.8# SwiftCEM WELL INCLINATION DETAIL KOP @ 500’ Max Hole Angle = 70.09 deg. @ 2,769’ MD Max Hole Angle = 67.00 deg. @ Top Perf TREE & WELLHEAD Tree 7-1/16" 5M Tree (5-1/8” Bore) Wellhead 11" 5M Wellhead x 5-1/2" Hydril 563 Top and Bottom Hanger with 5-1/2" CIW "H" BPV profile w/o control lines. JEWELRY DETAIL No. Top MD Item Drift ID 1 31’ Tubing Hanger (5-1/2” Hydril 563 Top & Btm) 4.767” 2 4,387’ 5-1/2” X Nipple, 4.562” Packing Bore 4.562” 3 4,473’ 5-1/2” IBT-Mod x 4-1/2” Vam Top XO 3.833” 4 4,477’ 7-5/8” x 4-1/2” Hydraulic Permanent Packer (Vam Top B x P) 3.856” 5 4,535’ 4-1/2” XN Nipple,Min ID = 3.725” No-Go, 3.813” Packing Bore 3.725” 6 4,581’ 4-1/2” Mule Shoe (Btm @ 4,583’) 3.833” PERFORATION DETAIL Schrader Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Ugnu Disposal 4,630’ 4,680’ 2,737’ 2,756’ 50’ 12/19/18 Open Ugnu Disposal 4,740’ 4,790’ 2,781’ 2,802’ 50’ 12/19/18 Open Ugnu Disposal 4,820’ 4,870’ 2,816’ 2,839’ 50’ 12/19/18 Open Ugnu Disposal 5,030’ 5,050’ 2,916’ 2,926’ 20’ 12/19/18 Open Ugnu Disposal 5,070’ 5,100’ 2,937’ 2,952’ 30’ 12/19/18 Open Ugnu Disposal ±5,225’ ±5,269’ ±3,021’ ±3,046’ ±44’ Future Future Ugnu Disposal 5,270’ 5,320’ 3,047’ 3,076’ 50’ 12/19/18 Open Ugnu Disposal ±5,321’ ±5,344’ ±3,077’ ±3,091’ ±23’ Future Future Ugnu Disposal ±5,381’ ±5,459’ ±3,114’ ±3,163’ ±78 Future Future Ugnu Disposal 5,460’ 5,510’ 3,163’ 3,196’ 50’ 12/19/18 Open Ugnu – TCP 5” 5132 Razor RDX SBH TL LD, 16 spf (32.0 gr, 1.04 EH, 6.7 Pen) GENERAL WELL INFO API: 50-029-23614-00-00 Drilled and Cased by Doyon 14 - 12/22/2018 TD =6,400’ (MD) /TD =3,886’(TVD) 20” Top of Fill @ 5,485’ Tagged on 2/6/2021 Orig. KB Elev.:58.7’/ GL Elev.: 25.0’ RKB-THF: 30.68’ (Doyon 14) 10-3/4” 1 PBTD =5,563’ (MD) / TD =3,231’(TVD) 7-5/8” Shoe @ 5,648’ 2 5-1/2” Tubing 9-7/8” Hole 5Min ID 3.725” 4 6 Min ID 4.562” 3 CBL TOC 3,820’ MD 12/18/18 OH PBTD 5,660’ MD DATE: 10/25/2019 2181b0 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 3 1 4 0 1 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-03 (PTD 218-140) RECEIVED 0j2019 A®GCC CD: HALLIBURTON - PRESSURE TEMP SURVEY 22 JUL 2019 MPPv1-03 PTSurvey 22JUL79 7/30/20191:01 PM PDF Document 6,706 KB PvlPtA-CG_PTSurvey_22PUL19_40dwn 7/3CV2019 1 ;01 PM - LAS File - 4,673 KB MP1-03_PTSurvey_22PUL19_img 7130/20191:01 PM TIFF File 12,369 KB MPPvT-03_PTSurvey_MUL19_stop-500 /30/20191:01 PM LAS File 330 KB _ MP'M-03_PTSurvey221UL79_stop-10M 7/3W20191:01 PM LAS File 341 KB MPPvT 03_PTSurrey 22JUL19_stop-15DO 7130/20191:01 PM LAS File 344 KB MP'M-03_PT5urvey_22JUL19_stop-20D0 7/30/20191:01 PM LAS File 345 KB J MPM-03_PTSurvey MUL19_stop-2500 7/30120191:01 PPvi LAS File 344 KB LA MPM-03_PTSuney_22JUL19_stop-30ID0 7/33AK191:D1 PTvT LAS File 352 KB MPM-03_PTSurvey-22.PUL19 stop -350[) ,/30/20191,41 PM LAS File 351 KB MPM-03_P'TSurrey_221UL19_stop-4090 7130.120191: D1 PM LAS File 359 KB MPM-03_PTSurvey_MUL19_stop-4500 7130,120191:01 PM LAS File 351 KB MPM-0_3PTS'urrey 221UL19 stop -47001 7130/20191:01 PM LAS File 351 KS MP'M-03_PTSurvey-MUL19_stop-4300 7/30.120191:01 PM LAS File 359,, KB Pv1PM 03_PTSumrey 22JUL19_s€op- 0 W30/2019 PM LAS File 35E KB MPM-03_PTSurvey 22JUL39_stop-52,D0 71301120191:01 PM LAS File 355 KB MPM-03_PTSur,ey22JUL19_stop-540© 7.30/2019 1:01 PM LAS File 327 KB MPMi-03_PTSurvey_22DUL19 stop -5430 7130.120191:01 PM LAS File 323 KB MPM-03_PTSurvey22JUL19_ stop-duwn25... 7,/30/20191; D1 PM LAS 4,201 KB Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 / .n 1 t j J V � Wal From: Sent: To: Cc: Subject: Chris D Wallace, Chris D (CED) Tuesday, June 25, 2019 10:25 AM David Haakinson Wyatt Rivard; Alaska NS - Wells Foreman; Brooke Locke; Nick Fortney RE: MPU Class II Disposal Well M-03 (PTD #21 1_ 81400Ready for Injection 1 David, A two week deferral seems appropriate as our goal is to achieve a reliable reproducible test under normal operating conditions. Let us know if another delay occurs. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7'^ Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallacePalaska eov 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 if, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska aoy. From: David Haakinson <dhaakinson@hilcorp.com> Sent: Tuesday, June 25, 2019 10:02 AM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Alaska NS - Wells Foreman<AlaskaNS-WellsForeman@hilcorp.com>; Brooke Locke <blocke@hilcorp.com>; Nick Fortney <nfortney@hilcorp.com> Subject: RE: MPU Class II Disposal Well M-03 (PTD # 2181400) Ready for Injection Chris, In accordance with Disposal Injection Order 42 and well M-03 injection start-up on 5/25/19, Hilcorp Alaska will comply with Rule 6 stating "A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids." At this time, well M-03 is currently inaccessible for slick -line well work due to the ASR workover rig being lined up over offset well M-04. Furthermore, injector M-03 has been injecting a minimal flow rates as Milne Point operations continues to progress ramping up the M -pad facility. Hilcorp Alaska seeks acceptance of a two-week deferral (7/9/19) of the M-03 temperature log to allow for well -work accessibility and an increase of injection rate to planned stable operational levels. Please let us know if you have any questions. Thank You, MEMORANDUM TO: Jim Regg n P.I. Supervisor �—) ( / 1151( % FROM: Jeff Jones Petroleum Inspector Well Name MILNE PT UNIT M-03 Insp Num: mitJJ190707163432 Rel Insp Num: State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, July 15, 2019 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska LLC M-03 MILNE PT UNIT M-03 See: Inspector Reviewed By: P.I. Supry ll'al Comm API Well Number 50-029-23614-00-00 Inspector Name: Jeff Jones Permit Number: 218-140-0 Inspection Date: 6/3/2019 Packer Well M-03 Type Inj j w -TVD PTD 2181400 - Type Test SPT Test ps BBL Pumped: fs BBL Returned: Interval Notes: I well inspected, no exceptions noted. Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min 2681 Tubing 504 - 519 52i 536" 1500 - IA tab 2818 2794 2786 1.4 OA zoo zaz - n6 204 P ✓ Monday, July 15, 2019 Page I of I DATA SUBMITTAL COMPLIANCE REPORT 3129/2019 Permit to Drill 2181400 Well Name/No. MILNE PT UNIT M-03 MD 6400 TVD 3886 Completion Date 12/22/2018 REQUIRED INFORMATION Mud Log Operator HILCORP ALASKA LLC API No. 50-029-23614-00-00 Completion Status WDSP2 Current Status WDSP2 UIC Yes Samples Vd-`SL r � Directional Survey YpsY/ DATA INFORMATION Electronic Data Set, Filename: List of Logs Obtained: ROP DGR EWR LD CTN MD & TVD, CBL I yvl� s.las Well Log Information: Electronic Data Set, Filename: Log/ Electr ass.las Data Digital Dataset Log Log Run Interval Type Med/Frmt Number Name Scale Media No Start Stop ED C 30229 Digital Data 55N 3000 ED C 30229 Digital Data 5531 5243 ED C 30229 Digital Data Electronic File: ED C 30229 Digital Data nt.Pdf ED C 30229 Digital Data Electronic File: ED C 30229 Digital Data nt.Pdf Log C 30229 Log Header Scans 0 0 ED C 30265 Digital Data 110 6400 ED C 30265 Digital Data Electronic File: MPU M-03 LWD Final MD.cgm 1/17/2019 ED C 30265 Digital Data 1/17/2019 Electronic File: MPU M -03 -Definitive Survey ED C 30265 Digital Data Report.pdf 1/17/2019 ED C 30265 Digital Data Report.txt (from Master Well Data/Logs) OHI CH Received 1/10/2019 Electronic Data Set, Filename: Hilcorp_M03_USIT_18Dec2018_ConPr_MainPas s.las 1/10/2019 Electronic Data Set, Filename: Hilcorp_M03_USIT_18Dec2Ol8_ConPr_RepeatP ass.las 1/10/2019 Electronic File: Hilcorp_M03_USIT_18Dec2Ol8_ConCu_MainPa ss.dlis 1/10/2019 Electronic File: Hilcorp_M03_USlT_l8Dec2Ol8_ConCu_Repeat Pass.dlis 1/10/2019 Electronic File: Hilcorp_M03_U SIT_ Casing_180ec2018_FieId Pd nt.Pdf 1/10/2019 Electronic File: Hilcorp_M03_US IT_Cement_18Dec2Ol8_FieldPri nt.Pdf 2181400 MILNE PT UNIT M-03 LOG HEADERS 1/17/2019 Electronic Data Set, Filename: MPU M-03 DGR_EWR-P4_ALD_CTN Final.las 1/17/2019 Electronic File: MPU M-03 LWD Final MD.cgm 1/17/2019 Electronic File: MPU M-03 LWD Final TVD.cgm 1/17/2019 Electronic File: MPU M -03 -Definitive Survey Report.pdf 1/17/2019 Electronic File: MPU M -03 -Definitive Survey Report.txt AOGCC Page l of 8 Friday, March 29, 2019 Permit to Drill MD 6400 DATA SUBMITTAL COMPLIANCE REPORT 3/29/2019 2181400 Well Name/No. MILNE PT UNIT M-03 Operator HILCORP ALASKA LLC API No. 50-029-23614-00-00 TVD 3886 Completion Date 12/22/2018 Completion Status WDSP2 Current Status WDSP2 UIC Yes ED C 30265 Digital Data 1/17/2019 Electronic File: MPU M-03 LWD Final MD.emf ED C 30265 Digital Data 1/17/2019 Electronic File: MPU M-03 LWD Final TVD.emf ED C 30265 Digital Data 1/17/2019 Electronic File: MPU M-03 LWD Final MD.pdf ED C 30265 Digital Data 1/17/2019 Electronic File: MPU M-03 LWD Final TVD.pdf ED C 30265 Digital Data 1/17/2019 Electronic File: MPU M-03 LWD Final MD.tif ED C 30266 Digital Data 1/17/2019 Electronic File: MPU M-03 LWD Final TVD.tif ED C 30265 Digital Data 1/17/2019 Electronic File: EMFView3_l.zip ED C 30265 Digital Data 1/17/2019 Electronic File: Readme.txt Log C 30265 Log Header Scans 0 0 2181400 MILNE PT UNIT M-03 LOG HEADERS ED C 30289 Digital Data 2700 6450 1/24/2019 Electronic Data Set, Filename: MPU M-03.1as yv'" (,o u ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 Nabors AM Report 12-S 1D-2018.pdf ED C 30289 Digital Data 1/24/2019 Electronic Fife: MPU M-03 Nabors AM Report 12- 11-2018.pdf ED - C 30289 Digital Data 124/2019 Electronic File: MPU M-03 Nabors AM Report 12- 9-2018.pdf ED C 30289 Digital Data 1/24/2019 Electronic File: MPU_M-03.dbf' ED C 30289 Digital Data 124/2019 Electronic File: mpu_m-03.hdr ED C 30289 Digital Data 124/2019 Electronic File: MPU_M-03.mdx ED C 30289 Digital Data 124/2019 Electronic File: mpu_m-03r.dbf ED C 30289 Digital Data 124/2019 Electronic File: mpu_m-03Lmdx ED C 30289 Digital Data 1/24/2019 Electronic File: MPU_M-03_SCL.DBF ED C 30289 Digital Data 1/24/2019 Electronic File: MPU_M-03_SCL.MDX ED C 30289 Digital Data 1/24/2019 Electronic File: MPU_M-03_TVD.DBF ED C 30289 Digital Data 124/2019 Electronic File: MPU_M-03_TVD.mdx ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 Final Well Report.pdf ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - 5in Drilling Dynamics Log MD.pdf ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - 5in Drilling Dynamics Log TVD.pdf AOOCC Page 2 of 8 Friday, March 29, 2019 DATA SUBMITTAL COMPLIANCE REPORT 3/29/2019 Permit to Drill 2181400 Well Name/No. MILNE PT UNIT M-03 MD 6400 TVD 3886 Completion Date 12/22/2018 ED C 30289 Digital Data ED C 30289 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data 30289 Digital Data Operator HILCORP ALASKA LLC API No. 50-029-23614-00-00 Completion Status WDSP2 Current Status WDSP2 UIC Yes 1/24/2019 Electronic File: MPU M-03 - 5in Formation Log MD.pdf 124/2019 Electronic File: MPU M-03 - 5in Formation Log TVD.pdf 124/2019 Electronic File: MPU M-03 - 5in Gas Ratio Log MD.pdf 1/24/2019 Electronic File: MPU M-03 - 5in Gas Ratio Log TVD.pdf 1/24/2019 Electronic File: MPU M-03 - 5in LWD Combo Log MD.pdf 124/2019 Electronic File: MPU M-03 - 5in LWD Combo Log TVD.pdf 1/24/2019 Electronic File: MPU M-03 - Drilling Dynamics Log MD.pdf 1/24/2019 Electronic File: MPU M-03 - Drilling Dynamics Log TVD.pdf 1/24/2019 Electronic File: MPU M-03 - Formation Log MD.pdf 124/2019 Electronic File: MPU M-03 - Formation Log TVD.pdf 1/24/2019 Electronic File: MPU M-03 - Gas Ratio Log MD.pdf 124/2019 Electronic File: MPU M-03 - Gas Ratio Log TVD.pdf 1/24/2019 Electronic File: MPU M-03 - LWD Combo Log MD.pdf 1/24/2019 Electronic File: MPU M-03 - LWD Combo Log TVD.pdf 124/2019 Electronic File: MPU M-03 - 5in Drilling Dynamics Log MD.tif 124/2019 Electronic File: MPU M-03 - 5in Drilling Dynamics Log TVD.tif 1/24/2019 Electronic File: MPU M-03 - 5in Formation Log MD.tif 1/24/2019 Electronic File: MPU M-03 - 5in Formation Log TVD.tif AOGCC Page 3 of 8 Friday, March 29, 2019 DATA SUBMITTAL COMPLIANCE REPORT 3/2912019 Permit to Drill MD 6400 21$1400 Well Name/No. MILNE PT UNIT M-03 TVD 3886 Completion Date 12/22/2018 Operator HILCORP ALASKA LLC API No. 50-029-23614-00-00 Completion Status WDSP2 Current Status WDSP2 UIC Yes ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - 5in Gas Ratio Log MD.tif ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - 5in Gas Ratio Log TVD.tif ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - 5in LWD Combo Log MD.tif ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - 5in LWD Combo Log TVD.tif ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - Drilling Dynamics Log MD.tif ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - Drilling Dynamics Log TVD.tif ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - Formation Log MD.tif ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - Formation Log TVD.tif ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 - Gas Ratio Log MO.tif ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 - Gas Ratio Log TVD.tif ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 - LWD Combo Log MD.tif I ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 - LWD Combo Log TVD.tif ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5540'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5550'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5560'.jpg ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5570'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5580'.jpg ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5590'.jpg ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5600'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5610'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5620'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5630'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5640'.jpg AOGCC Page 4 of 8 Friday, March 29, 2019 DATA SUBMITTAL COMPLIANCE REPORT 3/29/2019 Permit to Drill 2181400 Well Name/No. MILNE PT UNIT M-03 Operator HILCORP ALASKA LLC API No. 50-029-23614-00-00 MD 6400 TVD 3886 Completion Date 12/22/2018 Completion Status WDSP2 Current Status WDSP2 UIC Yes ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5650'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5660'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5670'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5680'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5690'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5700.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5710'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5720'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5730.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5740'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5750'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5760'.jpg ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5770'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5780'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5790'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5800'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5810'.jpg ! ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5820'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5830'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5840'.jpg ! ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5850'.jpg I ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5860'.jpg ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5870'.jpg ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5880'.jpg ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5890'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5900'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5910'.jpg ED C 30289 Digital Data 124/2019 Electronic File: MPU M-03 5920'.jpg ED C 30289 Digital Data 1/24/2019 Electronic File: MPU M-03 5930'.jpg AOGCC Page 5 of 8 Friday, March 29, 2019 DATA SUBMITTAL COMPLIANCE REPORT 3/29/2019 Permit to Drill 2181400 Well Name/No. MILNE PT UNIT M-03 MD 6400 TVD 3886 Completion Date 12/22/2018 ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data I ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data I ED C 30289 Digital Data I ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data Operator HILCORP ALASKA LLC Completion Status WDSP2 Current Status WDSP2 API No. 50-029.23614-00-00 UIC Yes 1/24/2019 Electronic File: MPU M-03 5940'.jpg 1/24/2019 Electronic File: MPU M-03 5950'.jpg 1/24/2019 Electronic File: MPU M-03 5960'.jpg 1/24/2019 Electronic File: MPU M-03 5970'.jpg 1/24/2019 Electronic File: MPU M-03 5980'.jpg 1/24/2019 Electronic File: MPU M-03 5990'.jpg 1/24/2019 Electronic File: MPU M-03 6000'.jpg 1/24/2019 Electronic File: MPU M-03 6010'.jpg 1/24/2019 Electronic File: MPU M-03 6020'.jpg 1/24/2019 Electronic File: MPU M-03 6030'.jpg 124/2019 Electronic File: MPU M-03 6040'.jpg 124/2019 Electronic File: MPU M-03 6050'.jpg 124/2019 Electronic File: MPU M-03 6060'.jpg 124/2019 Electronic File: MPU M-03 6070'.jpg 124/2019 Electronic File: MPU M-03 6080'.jpg 124/2019 Electronic File: MPU M-03 6090'.jpg 124/2019 Electronic File: MPU M-03 6100'.jpg 1/24/2019 Electronic File: MPU M-03 6110'.jpg 1/24/2019 Electronic File: MPU M-03 6120'.jpg 1/24/2019 Electronic File: MPU M-03 6130'.jpg 1/24/2019 Electronic File: MPU M-03 6140'.jpg 1/24/2019 Electronic File: MPU M-03 6150'.jpg 1/24/2019 Electronic File: MPU M-03 6160'.jpg 1/24/2019 Electronic File: MPU M-03 6170'.jpg 1/24/2019 Electronic File: MPU M-03 6180'.jpg 1/24/2019 Electronic File: MPU M-03 6190'.jpg 1/24/2019 Electronic File: MPU M-03 6200'.jpg 1/24/2019 Electronic File: MPU M-03 6210'.jpg 1/24/2019 Electronic File: MPU M-03 6220'.jpg AOGCC Page 6 of 8 Friday, March 29, 2019 DATA SUBMITTAL COMPLIANCE REPORT 3/29/2019 Permit to Drill 2181400 Well Name/No. MILNE PT UNIT M-03 MD 6400 TVD 3886 ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data I ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data ED C 30289 Digital Data Completion Date 12/22/2018 ED C 30289 Digital Data Log C 30289 Log Header Scans ED C 30490 Digital Data AOGCC Operator HILCORP ALASKA LLC API No. 50-029-23614-00-00 Completion Status WDSP2 0 0 Page 7 of 8 Current Status WDSP2 UIC Yes 1/24/2019 Electronic File: MPU M-03 6230'.jpg 1/24/2019 Electronic File: MPU M-03 6240'.jpg 1/24/2019 Electronic File: MPU M-03 6250'.jpg 1/24/2019 Electronic File: MPU M-03 6260'.jpg 1/24/2019 Electronic File: MPU M-03 6270'.jpg 1/24/2019 Electronic File: MPU M-03 6280'.jpg 1/24/2019 Electronic File: MPU M-03 6290'.jpg 1/24/2019 Electronic File: MPU M-03 6300'.jpg 1/24/2019 Electronic File: MPU M-03 6310'.jpg 1/24/2019 Electronic File: MPU M-03 6320'.jpg 1/24/2019 Electronic File: MPU M-03 6330'.jpg 1/24/2019 Electronic File: MPU M-03 6340'.jpg 124/2019 Electronic File: MPU M-03 6350'.jpg 124/2019 Electronic File: MPU M-03 6360'.jpg 124/2019 Electronic File: MPU M-03 6370'.jpg 1/24/2019 Electronic File: MPU M-03 6380'.jpg 124/2019 Electronic File: MPU M-03 6390'.jpg 1/24/2019 Electronic File: MPU M-03 6400'.jpg 1/24/2019 Electronic File: Show Report #1 MPU M-03 5655- 5761.pdf 1/24/2019 Electronic File: Show Report #2 MPU M-03 5950- 6005.pdf 1/24/2019 Electronic File: Show Report #3 MPU M-03 6011- 6071.pdf 124/2019 Electronic File: Show Report #4 MPU M-03 6150- 6204.pdf 124/2019 Electronic File: Show Report #5 MPU M-03 6253- 6300.pdf 2181400 MILNE PT UNIT M-03 LOG HEADERS 3/26/2019 Electronic File: M-03 Step Rate Test (from WSR data) - 1-27-19 - RTE.XLSX Friday, March 29, 2019 DATA SUBMITTAL COMPLIANCE REPORT 3/29/2019 Permit to Drill 2181400 Well Name/No. MILNE PT UNIT M-03 MD 6400 TVD 3886 Completion Date 12/22/2018 Well Cores/Samples Information: Name Cuttings Operator HILCORP ALASKA LLC Completion Status WDSP2 Current Status WDSP2 Sample Interval Set Start Stop Sent Receiver/ Number Comments 2850 6400 1/9/2019 1691 API No. 50-029-23614-00-00 UIC Yes INFORMATION RECEIVED Completion Report V Directional / Inclination Data YO Mud Logs, Image Files, Digital Dat&Y / NA Core Chips Y / 10A Production Test Information Y / �A Mechanical Integrity Test Information NA Composite Logs, Image, Data Files (P Core Photographs Y /6) Geologic Markers/Tops LY �Y^/ Daily Operations Summary U Cuttings Samples t r / NA Laboratory Analyses Y / e) COMPLIANCE HISTORY Completion Date: 12/22/2018 Release Date: 12/4/2018 Description Date Comments Comments: Compliance Reviewed By: Date: AOGCC Page 8 of 8 Friday, March 29, 2019 2101',0 30 49 4 14 Hilc„7, A64., I.LC DATE: 3/28/2019 .Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 RECEIVED APR 0 1 2019 AOGCC REPLACEMENT DISK CD: HALLIBURTON — PRESSURE TEMP SURVEY 25 JAN 2019 Name Date modified Type Size . MPUM-03_PRESSTEMP25JAN19_stop-3... 2/13/20199:19AM LAS File 148 KB _MPU_M-03PRESSTEMP25JAN19stop-3... 2/13/20199:19 AM LAS File 147 KB MPU M-03PRESSTEMP_25JAN19_stop-4... 2/13/20199:19 AM LAS File 149 KB MPU M-03_PRESSTEMP 25JAN19 stop -4... 2/13120199:19AM LAS File 147 KB MPU_ -03 PRESSTEMP_25JAN19_stop-4... M Z/13/20199:19 AM LAS File 149 KB ]-! MPU M-03 PRESSTEMP25JAN19_stop-4... 2/13/20199;19 AM LAS File 147 KB MPU_M-03_PRESSFEMP 25JAN19 stop -5... 2/13/20199:19AM LAS File 148 KB J MPU_M-03 PRESSTEMP 25JAN19 stop -5... 2/13/20199:19 AM LAS File 148 KB DMPUM-03_PRESSTEMP_25JAN19_stop-5... 2/13/20199:19AM LAS File 148 KB .71) MPU M-03_PRESSTEMP 25JAN1Qstop-5... 2113/20199:19AM LAS File 147 KB L MPU_M-03_PRESSTEMP25JAN19 2/13/20199:19AM PDF Document 3,756 KB 2I MPU_M-03_PRESSTEMP25JAN19_040dn... 2/13/20199:19 AM LAS File 2634 KB � W MPU M-03_PRESSTEMP25JAN19_img Z/13/20199:19AM TIFF File 8,862 KB MPU _M-03_PRESSTEMP 251AN19 stop -5... 2/13,/20199:19 AM LAS File 151 KB MPU_M-03PRESSTEMP 25JAN19stop-1... 2/13/2019 9:19 AM LAS File 147 KB MPU_M-03 PRESSTEMP_251AN19_stop-1... 2/13/20199:19 AM LAS File 149 KB MPU _M-03_PRESSTEMP_25JAN19_stop-2... 2/1312019 9:19 AM LAS File 148 K6 MPU _M-03_PRESSTEMP25JAN19stop-2... 2/13/20199:19 AM LAS File 153 KB Please acknowledge receipt by sing and returning one copy of this transmittal or FAX to 907 777.8510 I VA L) 218140 Debra Oudean 30 4 9 0 Hilcoip Alaska, LLC 3800 Centerpoint Drive, Ste 1400 1 Anchorage, Alaska 99503 Office: 907.777.8337 doudean@hilcorp.com DATE 3/26/2019 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite100 Anchorage, AK 99501 M-03 Step Rate Test Please acknowledge by signing RE(;Ejv ED MAR 2 6 2019 p%GGCC one copy of this Received By: /, ) // / ' Q / \ ) I Date: or FAX to 907 777.8337 Wallace, Chris D (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Friday, March 8, 2019 4:44 PM To: Regg, James B (DOA); Wallace, Chris D (DOA) Cc: Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay; Wyatt Rivard; Chad Helgeson; Walton Crowell; Brooke Locke; Nick Fortney; Alaska NS - Wells Foreman Subject: PTD 218-140 MPU M-03 Class 11 Disposal Well - 10 -day notice of first injection (DIO 42) Jim/Chris, Hilcorp Alaska is providing 10 -day notice prior to the start of injection of Class II fluids in well MPU M-03 (PTD 218-140) as approved under DID 42. A separate notice will be sent for the witnessing of the subsequent MIT -IA after stabilized injection has been achieved. The subsequent pressure -temperature survey will take place approximately 1 month after initial injection is started. Annular pressure surveys will also be conducted per the DID (the survey for 2019 was completed on 1/08/2019). Let us know if you have any questions. Regards, Stan Porhola I Operations Engineer North Slope Asset Team Hilcorp Alaska, LLC soorhola@hilcorp.com Office: (907) 777-8412 Mobile: (907) 331-8228 SCANNED wp 19 2019 JAPV KA - INS 21511f0o Regg, James B (DOA) From: Jones, Jeffery B (DOA) Sent: Monday, January 28, 2019 3:52 PM To: Regg, James B (DOA); Rixse, Melvin G (DOA) Subject: Copy of MPM-03 Step Rate & ISP 28Jan2019.xlsx Attachments: Copy of MPM-03 Step Rate & ISP 28Jan2019.xlsx; ATT00001.txt I planned to witness but was unable to due to phase 2 weather travel restrictions. 5kee zr�'ec,u .Test - C MPM-03 Step Rate Test Volume (bbls) Rate (BPM) Rate (BWPD) Start Time Duration T IA OA Notes 13:40 175 0 0 Initial readings 66 4 13:40 13 min 350 380 0 66 bbls to achieve stabilization 120 4 5760 13:53 30 min 340 1100 100 Bleed IA from 1,100 psi to 800 psi 90 6 8640 14:23 15 min 375 895 100 120 8 11520 14:38 15 min 400 1050 150 Bleed IA from 1,060 psi to 680 psi 150 10 14400 14:53 15 min 470 840 150 180 12 17280 15:08 15 min 480 650 150 Bleed IA from 1,050 psi to 600 psi SummarV Note: Leave injection pressure transmitter in communication with well (Wing Open) for at least 12 hrs following the Step Rate test or until wellhead pressure has stabilized to obtain Initial Shut -In Pressure (ISP). ISP = 47 psi stablized after _3:40 hrs 580 560 540 520 500 480 460 420 Y 400 u�) 380 • 360 340 N > 320 300 ` 280 , 260 N240 •� 220 •• �; •• 200 180 160 140 • ' 120 • 100 ,•• 80 60 •• 40 20 0 13:12',00 • L 1 •• ad 0 14* •i 14:2400 15,3600 164800 18:0000 19:1200 14 12 10 8 6 4 2 0 20:24:00 DATE: 1/22/2019 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DRILLING DYNAMICS LOG FORMATION LOG GAS RATIO LOG LWD COMBO LOG DRILLING DYNAMICS LOG CD NABORS i Daily Reports DML Data Final Well Report I LAS Data I Log PDFs I Log TIFFs I Sample Photography I Show Reports RECEIVED JAN 242019 AOGCC 1/13/2019 9:54 AM 1/13/2019 9:55 AM 1/17/2019 11:07 A... 1/12/2019 2:48 PM 1/12/2019 12:44 PM 1/12/2019 3:01 PM 1/17/201911:08 A... 1/13/2019 9:56 AM Please acknowledge receipt by signing and returning one copy of this File folder File folder File folder File folder File folder File folder File folder File folder 2 18 140 30209 or FAX to 9,07 77.8510 Received By: I 11 I LI fl ' J� I Date: ( / kJ/ // /- \ filkVVL.1 V LL/ JAN 18 2019 STATE OF ALASKA At ABKA Oil AND GAS CONSERVATION COMMISSION A /Inst % WELL COMPLETION OR RECOMPLETION REPORT ANIAOY 1a. Well Status: pit ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended Z 20AAC 25.105 20MC 25.110 GINJ❑ WINJ❑ WAG❑ WDSPLQ No. of Completions:_ 1 1b. Well Class: Development ❑ Exploratory ❑ Service EJ Stratigraphic Test❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Abend.: 12/22/2018 14. Permit to Drill Number/ Sundry: 218-140 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: December 3, 2018 15. API Number: 50-029-23614-00-00 4a. Location of Well (Governmental Section): Surface: 504V FSL, 801' FEL, Sec 14, T13N, R9E, UM, AK Top of Productive Interval: 1926' FSL, 757' FEL, Sec 14, T13N, R9E, UM, AK Total Depth: 578' FSL, 747' FEL, Sec 14, T13N, R9E, UM, AK 8. Date TO Reached: December 11, 2018 16. Well Name and Number: MPU M-03 9. Ref Elevations: KB: 58.7' GL: 25' BF:25' 17. Field / Pool(s): Milne Point Field Ugnu Undefined 10. Plug Back Depth MD/TVD: 5,563' MD / 3,231' TVD 18. Property Designation: , ADLO25514 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 533363 y- 6027889 Zone- 4 TPI: x- 533423 y- 6024776 Zone- 4 Total Depth: x- 533441 y- 6023428 Zone- 4 11. Total Depth MD/TVD: 6,400' MD / 3,886' TVD 19. DNR Approval Number: LONS 16-008 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,202' MD / 1,819' TVD 5. Directional or Inclination Survey: Yes � (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: 1 N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and Perforation record. Acronyms may be used. Attach a separate page if necessary ROP DGR EAR ALD CTN MD & TVD, CBL. 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CEMENTING RECORD CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE PULLED !' 20" 78.6# A53B Surface 114' Surface 114' 42" —270 ft3 10-3/4" 45.5# L-80 Surface 2,846' Surface 2,055' Je' 3.f L - 475 sx / T - 355 sx 218 bbls 7-5/8" 29.7# L-80 Surface 5,648' Surface 3,291' 9-7/8" L - 440 sx 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ""Please see attached schematic for perforation detail`" COMPLETION DAME Kw 12-17- ZI 1 VERIFIED 11 IJ4/^ 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 5-1/2" x 4-1/2" 4,583' 4,479' MD / 2,681' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during complebon? Yes No Per 20 AAC 25.283 (1)(2) attach electronic and printed information DEPTH INTERVAL (MD) IAMOUNT AND KIND OF MATERIAL USED 27, PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Test Period Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casing Press: Calculated 24 -Hour Rate •♦ Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Form 10-407 Revised 512017 CONTINUED ON PAGE 2 Submit ORIGINAL cnlJ caw 113q.011 Al. 30. D Irl '4f W11 RE1=13�cr a :: _,1s G 28. CORE DATA Conventional Corals): Yes ❑ No Q Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD ' TVD Well tested? Yes ❑ No Q If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,202' 1,819' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval N/A N/A information, including reports, per 20 AAC 25.071. SV5 1,361' 1,303' SV1 2,280' 1,849' UG15 (Top Disposal Zone) 4,607' 2,729' UG LD (Base Disposal Zone) 5,514' 3,198' Schrader NA 5,949' 3,520' Schrader OA 6,158' 3,687' Formation at total depth: Schrader Bluff 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cditl eT hilcor .cord Authorized Contact Phone: 777-8389 _ Signature: — Date: I I % t - INSTRUCTIONS General: This form and the required attachmen s provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only K UilcorP Alaske, LLC Orig. KB Elev.: 58.7/ GL Elev.: 25.0' RKB-THF: 30.68' D fn 14 4 103/4" Type R DriftID Top Btm 5-1/Y'Tubing 20'x34" Conductor (insulated) 78.6/A-53/Weld N/A CBLTOC 114' N/A 3,820 M7 Mn ID 45.5/L-80/TXP SR 12/18118 4.567' I, 2 y K 3 4 3,�H 5 HI) 6 SCHEMATIC Milne Point Unit Well: MPU Moose Pad M-03 Last Completed: 12/22/2018 PTD: 218-140 TREE & WELLHEAD D,'S�i¢c, w Tree 7-1/16" SM Tree (5-1/8" Bore) Wellhead 11" 5M Wellhead x 5-1/2" Hydril 563 Top and Bottom Hanger with 5-1/2" CIW "H" BPV profile w/o control lines. OPEN HOLE / CEMENT DETAIL 42" 50 bbls (30 Yards Pilecrete dumped down backside) /3 475 sx 10.7# Perm L, 355 sx 15.8# Class G SwiftCEM 9-7/8" 1 440 sx 15.8# SwiftCEM rACING nFTAll Size Type Wt/ Grade/Conn DriftID Top Btm BPF 20'x34" Conductor (insulated) 78.6/A-53/Weld N/A Surface 114' N/A 10-3/4" Surface 45.5/L-80/TXP SR 9.875" Surface 2,846' 0.0961 7-5/8" Production 29.7/L-80/Hydril563 6.750' Surface 5,648' 0.0459 TI IRING nFTAII 5-1/2" Tubing 17/ L-80/ IBT-MOD 4.767" 1 Surf 1 4,471' 0.0232 4-1/2" Tubing 12.6/L-80/Vam Top 3.833" 4,471' 4,583' 0.0152 4,689 M1 4,87tl W ardS S,OW M) ands 5,10O M1 ands 5,32U MJ ands 5.51(y M1 L( WELL INCLINATION DETAIL Max Hole Angle = 70.09 deg. @ 2,769' MD Max Hole Angle = 67.00 deg. @ Top Perf IFWELRY DETAIL No. Top MD I Item Drift ID 1 31' Tubing Hanger (5-1/2" Hydril563 Top & Btm) 4.767" 2 4,387' 5-1/2" X Nipple, 4.562" Packing Bore 4.562" 3 4,473' 5-1/2" IBT-Mod x 4-1/2" Vam Top XO 3.833" 4 4,479' 7-5/8" x 4-1/2" Hydraulic Permanent Packer (Vam Top B x P) 3.856" 5 4,535' 4-1/2" XN Nipple, Min ID = 3.725" No -Go, 3.813" Packing Bore 3.725" 6 4,581' 4-1/2" Mule Shoe (Btm @ 4,583') 3.833" PERFORATION DETAIL Schrader Sands FTOP (MD) Btm (MD) Top (TVD) ) FT Date Status Ugnu Disposal 4,630 4,680' 2,737'S0' PBTD = 5,563' (MD) /TD= 3,231'(TVD) 12/19/18 Open Ugnu Disposal 4,740' 4,790' 2,781'S0' 12/19/18 Open Ugnu Disposal 4,820' 4,870 2,816'S0' U2,926'2O' 12/19/18 Open Ugnu Disposal 5,030' 5,050 21,916'20' 12/19/18 Open Ugnu Disposal 5,070' 5,100' 2,937'30' 12/19/18 Open Ugnu Disposal 5,270' 5,320 3,047'S0' 12/19/18 Open Ugnu Disposal 5,460' 5,510 3,163'S0' 12/19/18 Open Ugnu—TCP 5" 5132 Razor RDX SBH TL LD, 16 spf (32.0 gr, 1.04 EH, 6.7 Pen) GENERAL WELL INFO APC 50-029-23614-00-00 Drilled and Cased by Doyon 14 -12/22/2018 Revised By: STP 1/03/2019 hoe OH PBID Shoe @ 5,660 ND.:r 5,649 ,�/ (/µVV4.LpT" 9-7/8.' i Hole kP1(ikb 0P✓ Coybl7k TD=6,40d(MD)/TD=3,886'(TVD) L, PBTD = 5,563' (MD) /TD= 3,231'(TVD) GENERAL WELL INFO APC 50-029-23614-00-00 Drilled and Cased by Doyon 14 -12/22/2018 Revised By: STP 1/03/2019 Spud Date: 12/3/2018 Job Name: 1813836D MP M-03 Drilling Contractor Doyon 14 AFE #: AFF $' Hilcorp Energy Company Composite Report ...:.,. Date.. ,, ; ... Ops Summary ...,. _. Well Name: MP M-03 Field: Milne Point County/State: , Alaska (LAT/LONG): Drill Site Manager and Doyon tool pushers performed final route inspection. Notify L & M pad operators and Milne security of rig move.;Move Doyon 14 from L - avation (RKB): 33.98 API #: Notify security and pad operators of arrival at M -Pad. PJSM, Remove rear boosters, install BOPS in cellar.;Lay rig mats around M-03, install choke line on Spud Date: 12/3/2018 Job Name: 1813836D MP M-03 Drilling Contractor Doyon 14 AFE #: AFF $' Hilcorp Energy Company Composite Report ...:.,. Date.. ,, ; ... Ops Summary ...,. _. 12/112018 Finish completing L-20 and begin R/D See L-20 report for details. Submit 24 hr. diverter test notification for M-03 to AOGCC at 07:51 .,Blow down rig floor water and steam lines. Skid #2 conveyor into the rig. Continue to clean the pits. Skid rig floor into moving position. Sim -ops: move rock washer and fuel trailer.;Move rig off L-20 and position on the pad. Remove BOP stack from the cellar. Position rig mats and 3x12 boards in the cellar. Install rear booster tires. Drill Site Manager and Doyon tool pushers performed final route inspection. Notify L & M pad operators and Milne security of rig move.;Move Doyon 14 from L - d to M- d. Begin removina rear booster tires. 1 2/212 01 8 Notify security and pad operators of arrival at M -Pad. PJSM, Remove rear boosters, install BOPS in cellar.;Lay rig mats around M-03, install choke line on BOPS, install studs on diverter tee.. Conduct pre spud meeting with Construction foreman, Milne point supervisors, DSM, Tool pusher, Doyon safety.;Set rock washer on ODS of rig. Spot rig over well and shim same.;Skid rig Floor and set conveyer #2 into drill position, spot the rock washer.;Prep annular and diverter tee. Torque wellhead to spec as per Hilcorp wellhead rep. Install 4" valves on conductor. Spot rock washer in position.;lnstall bell nipple. Test conductor seal to 400 PSI for 10 min. Change chain, sprockets, idler rollers, bearings and paddles on #2 conveyor. Place rock washer cuttings tank. Load 40 joints of 5" DS -50 drill pipe.;lnstall diverter lines. Continue to work on #2 conveyor. Off load trucks. Work on rig acceptance checklist. Load BHA components into the pipe shed.;lnstall riser and turnbuckles. Install accumulator lines to annular and knife valve. Replace leaking bladder on accumulator bottle. Continue to work on #2 conveyor. Spot fuel trailer. Spot MWD and mud shacks.;Change top drive saver sub from 4" XT -39 to 5" DS -50. Continue to load & strap 5" drill pipe into the pipe shed. Continue to replace leaking bladder on accumulator bottle and work on #2 conveyor.;Hauled 0 bbis H2O from L -Pad lake for total = 0 bots. Hauled 0 bbls cultings/liquids to MPU G&I for total = 0 bbls 12/3/2018 Change out saver sub f/ 4" XT -39 to 5" DS50. Continue to work on #2 conveyer, Prep shakers and pits to take on Fluid. Set mouse hole in rotary. Accept rig @ 10:00.;Drift and P/U 90 jts 5" DS50 OP racking 30 ales in derrick. Load 580 bbls 8.8 ppg spud mud into pits. Quadco calibrate and test PVT and gas alarms. IT R/U toms in Sperry and MI shacks. Cement silo on location. Note, AOGCC rep Matt Herrera waived witness for rr,.a,im test at 12 Qq hm-P ICM Radom Diverter function test using jt 5" DP. Knife valve opened 9 sec, Annular closed in 35 sec, perform accumulator drawdown test, initial 2900 psi, after closure 1800 psi, 200 psi attained 38 sec, full pressure attained 151 sec. N2 avg, 6 @ 2000 psi. Closest ignition source f/ EOD is 76.; Drift and P/U 17 jts of new 5" HWDP and jars, make/break/re-dope/ re -torque HWDP racking 6 stds in derrick, Pull mouse hole from rotary.;Slip and cut drilling line. Service rig.;PJSM for making up BHA. M/U 13-1/2" Kymera KM633X bit, 8" mud motor with 1.5°AKO (4:5 lobe, 5.3 stage), XO sub and one stand of HWDP.;Pre-spud meeting with Doyon, Peak, Halliburton, MI Swaco and DSM. Discussed drilling on new pad and to watch for different cuttings, gas hydrates unusual drilling trends. Table top rig evacuation drill with all parties involved.;Attempt to fill stack, valve 920 Demco valve Rebuild valve. Fill stack, check for leaks - none. Pressure test mud lines to 300 PSI low 13500 PSI high - good test.;Cleanout 20" conductor from 110'to 114'. Drill 13-1/2" hole f/ 114' V 127' with water. Displace to 8.8 ppg spud mud. Continue to drill 13-1/2" hole f/ 127't/ 217'. 350 GPM, 450 PSI, 30 RPM, 0.5K, 5-8K WOB. 103' drilled AROP 51.5. MW 8.8 in / 8.8 out, Vis 300 in / 300 out. Max gas 15u.;Circu -area Moms up while reaming f/ 217't/ 127'. Blow down top drive. POOH f/ 12T, inspect bit - good. WU MWD directional, gamma, resistivity & PWD to 83.44'. Measure offset 2.24/8.11=99.43°. Test & initialize tools. M/U three NM Flex drill collars and XO sub to 175.09'.;TIH w/ HWDP U 217' and resume drilling.;Drill 13-1/2" surface hole f/ 217't/ 280', 68' drilled, 68 AROP. 450 GPM, 700 GPM, 30 RPM, 0.8K, 7K WOB. MW 8.9 in / 8.9 out, Vis 310 in 1310 out. Max gas 13u.;Hauled 250 bbis H2O from L -Pad lake for total = 250 bbls. Hauled 0 bbis cuttings/liquids to MPU G&I for total = 0 bola 12/4/2018 Drill 13.1/2" surface hole If 280' ti 906', 626' drilled, 104.3 AROP. 510 GPM, 1250 PSI, 60 RPM, 2-5K TO. 10K WOB. PU/SO/ROT 80/84/83 MW in 8.851 out Vis in ax out 71. Mgas 18u. Start 4 /100' build at 423'.;Drill 13-112" surface hole V 906'V 143T, 531' drilled, 88.5 AROP. 535 GPM, 1420 PSI, 80 RPM, 3-5K TO, 7-10K WOB, 9.92 ECD. PU/SO/ROT 95/90/95 MW in 9.01 out 9.1, Vis in 151 / out 149. Max gas 31u.;Drill 13-1/2" surface hole f/ 1437't/ 2055', 618' drilled, 103 AROP. 495 GPM, 1460 PSI, 80 RPM, 5-7K TO, 10-14K WOB, 9.9 ECD. PU/SO/ROT 110/89/96 MW in 9.2 / out 9.2, Vis in 152 / out 197. Max gas 53u.;Drill 13-1/2" surface hole f/ 2055't/ 2748', 693' drilled, 115.5 AROP. 550 GPM, 1600 PSI, 80 RPM, 6K TO, 8K WOB, 10.1 ECD. PU/SO/ROT 105/79/88 MW in 9.25 / out 9.6, Vis in 1461 out 164. Max gas 106u. Begin 68° tangent at 2184.;Survey at 2674.22' MD / 1994.12' ND, 69.84° inc., 179.70° azm. 8.84' from plan, 2.68' high, 8.42' right.;Hauled 1260 bbis H2O from L -Pad lake for total = 1510 blots. Hauled 1273 bbls cuttings/liquids to MPU G&I for total = 1273 bible 12/5/2018 Drill 13-1/2" surface hole F/2748', T/2855 107' ddlled,107AROP. 600 GPM, 1640 PSI, 80 RPM, 6K TQ, 8K WOB, 10.1 ECD. PU/SO/ROT 105/79/91 MW in 9.2 /out 9.5, Vis in 146 /out 164. Max gas 110u.;Circ sweep around. Came back on time at 100% increase. 50 RPM, 550 GPM, 1580 PSI.;Monitor well, Static. Back ream out at 60 RPM, 550 GPM. F/ 2855' T/ 1700'. 5 Min Per stand. Cuttings started to increase. Pull slow and let the hole cleanup. Continue backreaming T 720'.;POOH on elevators F/ 720' T/ MWD. Stand back HWDP & jars. UD DC to MWD.;Down load Data & UD BHA.;Clean and clear rig floor. Rig up to run 10-3/4" casing.;Attempt dummy run with 10-3/4" casing hanger. Snap ring would not hold fluted mandrel in place. Consult Cameron wellhead. Tack weld snap ring in place. Perform dummy run and land on depth at 35.80' and mark landing joint.;PJSM for running casing. M/U 10-3/4" shoe track to 162'. Float shoe, shoe joint, Baker Loc joint, float collar, float collar joint and joint #1. Baker Loc all connections and torque to 22,600 ft/lbs. with Volant tool. Pump through shoe track and check floats - good.;One 13-1/2" Centek centralizer w/ stop ring 10' from shoe on shoe joint, one expand-o-lizer cross coupler centralizer on shoe joint, one each Centek centralizer w/ 2 stop rings mid -joint on Baker Loc joint & float collarjoint. Total of 3 Centex and 66 expand-o-lizer centralizers & 5 stop rings ran.;Run 10-314" TXP-BTC 45.5# L-80 casing from 162' to 2805' torque to 22,600 ft/lbs. with Volant tool. Install 10-3/4"x13-1/2" expand-o-lizer cross coupler centralizer on each connection. Fill on the fly & top off every 10 joints. 15.8 bbl, lost while running casing.;M/U landing joint and wash down from 2805' to 2845'w/ 1 BPM, 140 PSI. Land on hanger 145K PUW, 98K SOW. Stage up pumps in 1 bbl increments to 6 BPM, 150 PSI. Circulate 4200 511x,, 2.3 bottoms up, reciprocate 7'. PJSM for cement job while circulating. 10 bbls lost while circulating - 98% returns.;R/D Volant casing running tool, blow down top drive and install Halliburton cement head and cement Iines.;Pump 5 bbls water at 2 BPM, 168 PSI. Pressure lest lines to 600 PSI low 13800 PSI high - good test. Mix Clean Spacer.;Hauled 700 bbis H2O from L -Pad lake for total = 2210 bbis Hauled 925 bbis cuttings/liquids to MPU G&I for total = 2198 bbis I Ovi�rt 5� v Notified AOGCC of upcoming BOP test at 18:56. 12/612018 Pump 60 bbis 10.0 ppg Clean Spacer with 4# red dye & 5# Pol-E-Flake in the 1st 10 bbis. Drop btm plus Mix & pump 396 bbl 10.7 ppg Permafrost L Cmt. (475 SX) Mix & pump 73 bbl 15.8 PPG remium G cmt. 355 sx).;Dro to lu Halliburton um 20 bbl H2O. Swapto rig pumps and displace with 9.1 ppg spud mud at 3-5 bpm. Slow pump rate to 2 bpm 20 bbl before bumping. Bump plug 7 stks early. Final lift 570 psi. Hold 500 over. Bleed down and check floats. Good. Bled back 1 bbl. CIP @ 11:17.;Total good cmt returned to surface 218 bbl. 23 bbls lost during the cement job.; Drain stack, Flush all surface equipment with black water. RID cmt head and lines. L/D landing joint. N/D diverter system and 20" annular. Empty pits and start cleaning process for next section.;N/U cameron wellhead system. Test void to 500 PSI for 5 min. 5000 PSI for 10 min. - good tests. Spot GEO shack to suport the Mud loggers shack. 3l� Work on wiring them in to rig. Continue cleaning pits.;N/U BOP stack, bell nipple, Will line, accumulator lines, riser and install turnbuckles. Continue cleaning pits. Continue to work on electrical / comms to mud logger shack.;R/U to test BOPS. Install new test plug. Continue cleaning pits. Continue to work on electrical I comms to mud logger shack.;Fill stack to check for leaks, test plug not holding. Run in lock down screws to energize seal, still leaking. Call Hilcorp well head rep. Verified RKB measurement & ensure test plug seated. Pull test plug & inspect. Found 1/2" NPT plug not installed in bottom up test plug. Install 112" plug.; Re -install test plug -no leaks. Continue cleaning pits. Continue to work on comms to mud logger shack.;Perform BOP shell test 250 PSI low/ 3000 PSI high - good test. Continue cleaning pits. Continue to work on comms to mud logger shack. Test rig gas detection equipment. Notified Moose pad operators prior to testing.;Test BOP equipment as per PTD & AOGCC requirements. Upper & lower 2-7/8"x5" VBR and annular tested on 5" drill pipe. Test 14 choke valves, lower ISOP, dart valve, FOSV, manual & HCR choke & kill valves, manual & hydraulic chokes. Test blind rams.;Annular tested to 250 psi low 12500 psi high. All other tests to 250 psi low 13000 psi high. All test held for 5 min. & charted. Upper IBOP failed and will be replaced and re -tested. Perform accumulator test: 3000 system, 1700 after closure, 41 sec for 200 PSI, 187 full, 6 bottles at 2050 PSI.;AOGCC inspector Austin McLeod witnessed testing.; Due to Code 99 Blue on 1Rig, instructed to finish testing then stop all work. Will replace upper IBOP when work resumes.; Hauled 175 bbis H2O from L -Pad lake for total = 2385 bbls p�� Hauled 1640 bbls cuttings/liquids to MPU G&I for total = 3838 bbis /x C 5 12/7/2018 Field wide safety stand down. Rig crews work performing safety audits, inventory and light cleaning.;Hauled 0 bbis H2O from L -Pad lake for total = 2385 bbls Hauled 29 bbls cuttingsiliquids to MPU G&I for total = 3867 bbis 12/8/2018 Field wide safety stand down.;Safety meeting led by Drill Site Manager and tool pusher with rig crew prior to resuming work.;Change out upper IBOP valve. Sim -ops: perform derrick inspection, install new 91 conveyor paddles and change out cables for drillers console camera display.;Attempt to test upper SOP valve - leaking. Grease, re -test - still Ieaking.;Change out upper SOP valve.;Test upper IBOP to 250 psi low for 5 min. and 3000 PSI high for 5 min. - good test.;R/D test equipment, pull test plug and install 10" I.D. wear bushing. Install bails and 5" drill pipe elevators. Sperry found a bad ground wire in their surface equipment and was able to successfully test all the MWD tools.; Pick up 6 joints of 5" NC -50 drill pipe and rack back in the derrick.;Service rig. Replace broken link tilt stop bolt on top drive.;Pick up 66 joints of 5" NC -50 drill pipe and rack back in the derrick. UD 2 stands of excess 5" HWDP.;Mobilize BHA components to the rig floor. M/U BHA #2, 9-7/8" drilling assembly to 138'. 9-718" Kymera bit, T' mud motor, MWD DM/DGR/EWR/PWD/ALD/CTN and one flex collar. Plug into MWD and begin testing.;Hauled 195 bbis H2O from L -Pad lake for total = 2580 bbis Hauled 20 bbis cuttings/liquids to MPU G&I for total = 3887 bbis 12/9/2018 Test & initialize MWD tools. Pulse test w/ 550 GPM, 1100 PSI - good test. Continue to PIU BHA & encountered an ice plug at 149. M/U stand of HWDP & wash down f/ 140 t/ 232'w/ 150 GPM, 300 PSI. Rack back HWDP, pick up remaining 2 drill collars to 199'. TI w/ HWDP to 571'.;TIH with 5" NC -50 drill pipe It 768'1112137' picking up singles from the pipe shed.; Perform rig evacuation drill with all Moose pad personnel. Well secured in 2 min. then assembled at muster area. All drilling personnel accounted for in 8.25 min. and all construction personnel in 15 min.;Continue to single in the hole f/ 2137't/ 2360' then TIH out of derrick f/ 2360' V 2548'.;Circulate and condition the mud. 405 GPM, 1040 PSI. 20 RPM, 4-6K TQ. PU/SO/ROT 85K/75K/100K.;R/U equipment to test Vy� casing & close UPR. Pressure test 10-3/4" 45.5# L-80 casing to 2600 PSI to 30 min. Pumped 3.5 bbis, bled back 3.5 bbls. RID test equipment & blow down llnes.;TIH f/ 2548't) 2668' and tag cement w/ 5K. Drill 10-3/4" shoe track and rathole f/ 2668'V 2855' w/ 475 GPM. 1540 PSI, 20 RPM, 5-71K TQ.;Dri1120' of new 9-7/8" hole from 2855' to 2875' with 470 GPM, 1640 PSI, 20 RPM, 6-71K TO. 5-10K WOB. PU/SO/ROT 110K/75K/85K.;Pump 30 bbls spacer then displace well bore to new 8.8 ppg LSND mud.'R/U to attempt FIT to 12.5 ppg & close UPR. Pump down drillstring & kill line. Pressure up and achieved a 12.4 ppg LOT. 388 PSI at 2053' TVD = 12.43 ppg. Pumped 2.4 bbis and bled back 1.0 bbis. Contact drilling engineer & confirm good to proceed. RID test equipment and blow down Iines.;Drill 9-7/8" hole from 2875' to 3356. 481' drilled, 120 AROP. 545 GPM, 1130 PSI, 80 RPM, 5-6K TO, 3-6K WOB. PU/SO/ROT 113K/79K/95K MW in 8.8 /out 8.8, Vis in 571 out 57. Max gas 484u.;Drill 9-7/8" hole from 3356' to 4053'. 697' ddlled, 116 AROP. 550 GPM, 1530 PSI, 80 RPM, 5K TQ, 5K WOB. PU/SO/ROT 126K/81 K/100K MW in 8.95 /out 9.0, Vis in 52 /out 54. Max gas 42u.;Last survey at 4019.84 MD I 2489.94' TVD, 66.39° inc., 177.24° zzm. 14.09' from plan, 12.1' high, 7.0' Ieft.;Hauled 550 bbis H2O from L -Pad lake for total= 3130 bbis Hauled 520 bbis cuttings/liquids to MPU G&I for total = 4407 bbls 25 bbls daily losses, 25 bbls cumulative losses for interval. 12/10/2018 Drill 9-7/8" production hole V 4053' V 4616', 563' drilled, 99 AROP. 540 GPM, 1420 PSI, 80 RPM, 8-9K TQ, 5K WOB. PU/SO/ROT 150K180K/107K. MW in 8.951 out 9.0, Vis in 52/ out 54. Max gas 75u.;D0119-7/8" production hole V 4616' V 5208', 592' drilled, 99 AROP. 540 GPM, 1580 PSI, 80 RPM, 11-12K TQ, 10-15K WOB. PU/SO/ROT 1571<1851<1110K. MW in 8.81 out 8.85, Vis in 481 out 53. Max gas 36u.;Pumped 25 bbl hi -vis sweep @ 4620', back on time wl 25% increase. Pumped 35 bbl hi -vis sweep @5160', back on time w/25% increase.;Ddll 9-718" production hole f/ 5208'V 5620', 412' drilled, 69 AROP. 550 GPM, 1570 PSI, 70 RPM, 12-15K TQ, 2-3K WOB. PU/SO/ROT 180K/87K/117K. MW in 8.8/ out 8.9, Vis in 51 1 out 48. Max gas 28u. Start collecting 10' cuttings samples and 50' mud samples from 5450'. Limit ROP to 50-60' per hour.;Quadco technician repaired 91 mud pump stroke counter, found broken wire in mud pits junction box.;Drill 9-7/8" production hole fl 5620' V 5892', 272' drilled, 45 AROP. 550 GPM, 1470 PSI, 70 RPM, 14-16K TQ, 5K WOB. PU/SO/ROT 190K/90K/121 K. MW in 8.95 in 18.95 out, Vis in 52 / out 53. Max gas 407u.;At 5624' observed free oil on the shakers. Pumped 30 bbl hi -vis sweep @ 5755', back on time wt 50% increase. Last survey at 5812.45' MD / 3414.38' TVD, 39.849 Inc., 181.47° azm. 4.35' from plan, 1.18' high and 4.19' Ieft.;Hauled 705 bbls H2O from L -Pad lake for total = 3835 bbis Hauled 288 bbls cultings/liquids to MPU G&I for total = 4695 bbls 6 bbls daily losses 31 bbls cumulative losses for interval 12/11/2018 Drill 9-7/8" production hole from 5892" to 6144' (3675' TVD), 252' with AROP of 42 FPH. 550 GPM = 1600 psi, 80 RPM = 17K ft -lbs torque, WOB = 5K, MW = in + in/out + out ppg, Vis = in 49/out 53, ECD = 9.8 ppg, Max gas = 336 units. PU = 207K, SO = 95K, ROT = 126K.;Drill 9-7/8" production hole from 6144' to TD at 6400' 3885' TVD), 256' wfth AROP of 51.2 FPH. 557 GPM = 1770 psi, 80 RPM = 15-20K ft -lbs torque, WOB = 3-5K, MW = in 9.1 in/out 9.1 out ppg, Vis = in 49/out 56, ECD = 10.1 ppg, Max gas = 426 units PU = 225K, SO = 98K, ROT = 135K.;Final survey at 6400' MD, 3885' TVD, 34.49' Inc, 178.05° Az. Distance to Well Plan #5 = 0.81' (0.56' high and 0.58' right).;Pump 25 bbl low vis followed by 25 bbl hi vis sweep and circulate out. Sweeps back on time with 40% increase in cuttings. Circulate the well clean at 578 GPM = 1890 psi, 65 RPM= 17-20K fl -lbs torque. Circulated 4 bottoms up. Reciprocating from 6400' to 6320'.;Observe the well for flow and the well is static.;BROOH from 6400' to 3677' at 550 GPM = 1690 psi, 40 RPM = 19-20K ft -lbs torque. MAD pass at �1 200.225 FPH per MWD/DD.;Hauled 375 bbis H2O from L -Pad lake for total = 4210 bbls Hauled 405 bbls cuttings/liquids to MPU G&I for total = 5100 bbls 12/12/2018 Continue BROOH from 3677 to in side shoe / 0-3/4" shoe V 2827' at 550 GPM = 1690 psi, 65 RPM = 19-20K ft -lbs torque. w/ no real issues just couple 10K over pulls and 300 psi pressures increases.;Circ clean while rotating and reciprcating pipe f/ 2827' V 2735' @ 555 gpm @ 1480 psi, 60 rpm @ 4-6k tq, blow do TDS flow check static.;TOOH on elevators racking back f/ 2735't/ 107' (PU = 115K and SO = 85K).;PJSM. Remove nuclear sources from the BHA. Download the MWD data. SimOps: Clean the rig floor.;Lay down 9-7/8" drilling BHA. Bit grade= 1-2.CT-N-E-1-NO-TD.;Clear the rig floor. Mobilize 2-718" handling equipment and power tubing tongs to the rig floor. RU 2-718" handling equipment and power tubing tongs.;PU 2-7/8" cement stinger and RIH on 2- 7/8", 6.59, L-80 EUE 8rd tubing to 692'. MU 2-7/8" x 5" DP crossover.;TIH with 2-7/8" cement stinger from 694' to 2765' (PU = 85K and SO= 75K).;Break circulation at 350 GPM = 350 psi. Wash down from 2765 to 2841'. Circulate bottoms up. Observe the well for flow and the well is static. Blow down the top drive.;Continue to TIH with 2-718" cement stinger from 2641' to 6348' breaking circulation every 10 stands (PU = 180K and SO= 85K).;Break circulation at 51 GPM = 210 psi. Wash down from 6348' to tag at 6404' with 5K down.;Circulate and condition the mud at 213 GPM = 330 psi. Blow down the top drive.;Lay down two singles. PU and MU 19.7' pup joint. RU the cement line.;PJSM. Pump 3 bbls freshwater. PT lines to 1000/3900 psi (good test). Mix 30 bbl 10.5 ppg spacer.; 1 st balanced cement plug. Pump 27 bbls of 10.7 ppg spacer (cement wet at 01:40 hours), 39 bbls 15.8 oog class G cement and 3 bbls of 10.5 ppg spacer. Displace the cement with 98 bbls of 9.2 ppg mud with the rig.;Lay down 197 pup joint and a single. Stand back 3 stands at 15-20 FPH, had to 2 , Kelly up due to well being out of balance. Lay down two singles. MU 19.7' pup joint and RU the cement line. End of stinger at 6020' ;Circulate bottoms up at 4 BPM = 860 psi. Got spacer and a trace of cement back to surface.;Mix 30 bbl 10.5 ppg spacer. 2nd balanced cement plug. Pump 27 bbls of 10.7 ppg spacer r' (cement wet at 05:25 hours), 39 bbls 15.8 ppg class G cement and 3 bbls of 10.5 ppg spacer. Displace the cement with 88 bbls of 9.2 ppg mud with the 1 rig.;Hauled 75 bbis H2O from L - Pad a e foroe = 47.35 bbis L�OD Hauled 450 bbls heated H2O from MPU G&I for total = 450 bbls .J Hauled 417 bbls cuttings/liquids to MPU G&I for total = 5517 bbls 12/13/2018 POOH F/ 602U T/ 5402'. 15-20 FPH.;Drop wiper ball & CBU at 543 GPM, 1010 psi. Blow down TO & flow check well. Good.;POOH F/ 5402' T/ 691' standing 5' pipe back in the derrick.;PJSM, UD 2 7/8 cmt stinger and defuser. Clean and clear rig floor.;M/U BHA #3, 9 7/8 Bit, Motor, MWD, DC & RIH on HWDP. Test MWD. Good. RIH F/ 512' T/ 2395' (PU/SO = 105K).;Slip & cut 60' of drilling Iine.;Service the top drive and calibrate the block height.;Continue to TIH with cleanout assembly from 2395' to 5560' and started taking weight.;Kelly up. Wash down from 5560' to 5660' at 550 GPM = 1890 psi, 40 RPM = 12-13K ft -lbs torque, WOB = 3-5K, PU = 178K, SO = 80K and ROT = 110K.;Circulate and condition the mud at 550 GPM = 1890 psi, 40 RPM = 12K ft -lbs torque and reciprocating 60'. Circulated a total of 6.5 BU. MW in/out = 9.2+19.2+ and Vis in/out = 56/58.;BROOH from 5660'to inside the shoe at 2768' at 550 GPM = 1800 psi and 40 RPM = 13-14K ft -lbs torque (PU = 160K and SO = 80K).;CBU at 550 GPM = 1700 psi. Observe the well for flow and the well is static. Blow down the top drive.;POOH laying down 5" DP from 2768' to 1784'.;Hauled 280 bbls H2O from L -Pad lake for total = 5015 bbls Hauled 0 bbls heated H2O from MPU G&I for total = 450 bbls Hauled 642 bbls cuttings/liquids to MPU G&I for total = 6159 bbls 12/14/2018 Continue POOH laying down 5" DP from 1784' to 136'.;UD BHA #3. UD HWDP, Collars, MWD, Motor & Bit. Bit Grade- 1-2-CT-N-E-1-NO-TD.;Clean and clear floor. Pull wear bushing and install test plug.;Change top rams to 7 5/8. R/U testing equipment & test upper rams to 250/3000 psi. Test annular on 7 5/8 test joint to 2500 psi. Good.;Drain stack, RID testing equipment. FVU Doyon casing equipment. PIU Hanger and WU landing joint. M/U with chain tongs. Make �y,+^ dummy ran and lay down same.;P/U volant tool with cmt swivel. M/U to TD. Install bale extensions.; PJSM for running 7-5/8" casing.;PU the shoe joint and attempt to MU the first joint of casing but the swivel would not rotate. MU the joint using the pipe handler. Apply steam to the swivel and change to shorter / tieback cable on the swivel.;PU and MU the float collar joint. RIH with the shoe track on 7-5/8". 29.7#. L-80 Hydril 563 casing torque = 10300 ft -lbs, filling on the fly topping off every 10 joints and installing centralizers per tally to 2838' (PU = 112K and SO = 84K).;CBU staging pumps up to 4 BPM = 90-130 psi.;Continue RIH with 7-5/8" casing from 2838'to 4433'.;Hauled 40 bbls H2O from L -Pad lake for total = 5055 bbls Hauled 300 bbls heated H2O from MPU G&I for total = 450 bbls Hauled 149 bbls cuttings/liquids to MPU G&I for total = 6308 bbls ,ntinue to run casing 7 518 29.57# U80 Hydril 563 F/ 4433' T/ 5610'. Pushing fluid away no mater what speed of running.;Blow down TD. R/U cmt lines to it swivel. P/U landing joint and hanger. M/U with Doyon casing tongs. Wash down at 1-2 bpm F/ 5610'T/ 5648'. Land hanger. Stage up pumps to 5 bpm. losses while circulating. Halliburton cmt unit on location and rigging up. PJSM for cmt job.;Shut down and blow down the TD. R/U Tee & Hoses for wash Line up to Halliburton and pump 5 bbl H2O. Test lines and had a chicksan leak. Remove from service. Retest good. Line up & pump 40 bbl 10.5 Tuned lacer. Drop btm plug Mix & pump 90 bbl 440 sxs of 15.8 Primary cmt Drop top plug Wash up lines to nits Line back up down. hole and pump 20 bbl H2o !h Halliburton. Line up to rig pump. Displace with 234.6 bbl mud. Slow for last 10 bbl. Bump 9 stks early. Final lift 920 psi. Pressure up and hold 1400 for 5 n. Bleed back and check floats. Good. Bled back 2.25 bbl. No Iosses.;Break down circ lines and landing joint. UD Volant tool & cmt swivel. Change handling uipment to set pack off.;Grease the top drive, draws works and iron roughneck.;Went to MU the pack -off running tool and could not find the 4-112" IF x 3-1/2" crossover. Obtain one from the I -Rig. Install the 7-5/8" casing pack -off and RILDS.;PT pack -off to 25014000 psi for 10 minutes each (good test). SimOps: 1 LRS.;PJSM. Freeze protect the OA (10-3/4" x 7-5/8") with 100 bbls of diesel at 2 BPM (ICP = 500 psi and FCP = 1100 psi). SimOps: RU to lay down 5" '.;Lay down remaining 5" DP from the derrick in the mouse hole. SimOps: hang; the UPR to 3-1/2" x 6" VBRs.;Continue laying down remaining 5' DP m the derrick in the mouse hole.;Pull the mouse hole from rotarytable and place in the floor. Install the test plug and RILDS.;RU to test with 4" and 5-1/2" ,t joints.;PT the UPR (3-1/2" x 6" VBR) to 250/3000 psi with 5-1/2" test joint. PT the annular to 250/2500 psi with 5-1/2" test joint. PT the LPR (2-7/8" x5" IR) to 250/3000 psi with 4" test joint. PT 4" XT -39 FOSV and Dart Valve to 250/3000 psi. Hilcorp Energy Company Composite Report Well Name: MP M-03 Field: Milne Point County/State: , Alaska (LAT/LONG): avation (RKB): API #: Spud Date: 12/3/2018 Job Name: 1813836C MP M-03 Completion Contractor AFE #: AFE $: Activity Date ,, 4 ,.,,, ,. _ Q-...4'__m.e Owl 1 2/1 612 01 8 Finish testing UPR with 4" test joint to 250/3000 psi. Test annular to 250/2500. R/D testing equipment.,RD ROPE testing equipment. Pull the test plug.,Change saver sub to XT -39. Clean & clear the rig floor. Set 7.25 ID wear bushing.,Clean and clear the floor. Install wear ring (ID = 7.25").,M/U 6.75+ OD Baker bit, Bit sub with W/ Ported float, & 7 5/8 casing scraper. P/U 4" DPT/ 128'. Tag up. Unable to work through. Kelley up and wash down @ 5 bpm 20 RPM. Tag up. ROT down T/ 132'. Stall out & Over pull out. Nothing back at shakers. POOH & inspect bit. Nothing visible. Change bit to 6.125 & blow down TD. RIH & tag up at 132'. Try and rot through at 40 rpm 5 bpm. Tag and stall out.,Bring pumps to 8 BPM & wash through getting Quarter size chunks of ice back. Wash down to 195'.,Continue to RIH with cleanout assembly on 4" XT -39 DP from 199 to 5462' (PU = 116K and SO = 65K) filling every 20 stands -Wash down from 5462' to tag at 5544' at 5 BPM = 500 psi. Rack one stand and PU a single. Wash down from 5493' to 5544'., Drill cement from 5544' to 5560' at 80 RPM = 3-4K ft -lbs torque, 5 BPM = 480 psi, WOB = 1-2K. Shutdown the rotary and pumps. Tag the float collar at 5560' with 10K down.,CBU x2 at 515 GPM = 2050 psi, 30 RPM = 3K ft -lbs torque, reciprocating 60'.,Lay down a single and blow down the top drive. RU testing equipment.,PT the 7-518" casing to 3400 psi for 30 minutes (good test) with 9.25 ppg LSND mud. Bleed pressure to 0 psi and RD testing equipment.,Pump 20 bbl 8.3 ppg hi -vis sweep at 5 BPM = 480 psi and displace the well over to 8.8 ppg NaCl with 2% KCI at 11 BPM = 1500 psi while rotating at 20 RPM = 3K ft -lbs torque reciprocating 20'. Observe the well for flow and the well is static. Blow down the top drive.,TOOH with cleanout assembly from 5550' to 3122'.,Hauled 130 bails H2O from L -Pad lake for total = 5265 bbls Hauled 0 bails heated H2O from MPU G&I for total = 450 bels Hauled 444 bbIs c ttin s/Ii uids to MPU G I for total = 7357 bbl 12/17/2018 Continue to TOOH with cleanout assembly from 3122' T/ BHA., Inspect & UD Scraper & Bit. No signs of damage or wear., PJSM, R/U Schlumberger wire line & logging unit. hang sheave on blocks. Build tools on rig floor. String wire. RIH to 1890. Set down. Work several times setting down F/ 1800' to 1896. POOH & inspect tools. No signs of debris. RIH with same set downs. Unable to work past. POOH & UD upper portion of tool string. RIH & unable to make it past 1400'. Possible ice sheath. POOH & R/D Schlumberger.,PU and MU stack wash tool. Flush the stack and lay down the stack wash tool. Blow down the top drive.,M/U Clean out BHA, 6.625" junk mill, 6.75" string mill, two boot baskets, float sub and XO. RIH to tag at 5560'.,Pump 30 bbl hi vis sweep and circulate 5 1% out of the well at 15BPM = 2880 psi, 30 RPM = 5K ft -lbs torque reciprocating 30'. Seen plug rubber over the shakers.,Observe the well for flow and the well is ✓ static. Blow down the lop drive. TOOH with cleanout assembly from 5560' to 2563'.,Circulate the well to 88°F 8.8 ppg brine at 8 BPM = 550 psi. Blow down the top drive.,Continue to TOOH with cleanout assembly from 2563' to surface. Lay down the cleanout assembly. Empty the boot baskets and recovered minimal debris.,PJSM. RU SLB E -line. RIH USIT/CBL to tag at 1993'. ,POOH and remove the bow spring centralizers. RIH to tag at 1950'. POOH and remove the centralizer stiffeners. RIH to 5530'., Log up from 5530'to 2500'. Make repeat pass and POOH. TOC at 3820'.,RD SLB E -line. Clean and clear the floor -Mobilize TCP handling equipment to the rig floor. RU for running TCP guns. Verify gunrunning order with SLB representative., Hauled 65 bbls H2O from L -Pad lake for total = 5330 bbls Hauled 0 bails heated H2O from MPU G&I for total = 450 bbls Hauled 508 bails cuttings/liquids to MPU G&I for total = 7865 bbls,Rig Fuel (gallons): OH = 10570, Used = 1880 & Rae = 6100 OA oressure at midni ht = 190 psi 12/18/2018 PJSM. PU and MU 5" 16 SPF 5132 RAZOE SBH TCP guns. BHA length = 976.61' with 300' of guns spaced out per plan.,TIH with TCP guns conveyed on 4" drill pipe from 976'to 5518', park with string in tension. Correct displacement on TIH. PU 115K, SO 70K.,PJSM, R/U Alaska a -line, M/U FOSV, pump in sub with block valve and hose, M/U log tools, GR/CCL, wt bar, roller, wt bar, roller, rope socket, pack off, OAL= 18'.,RIH setting down @ 2200' continue to work () down to 4585' WLM. GR not communicating.,POOH, change out tools and add roller stem. RIH to 4585' WLM and attempt to log but GR is having interference issues -POOH and MU new GR tool. RIH to 4585' WLM and attempt to log but GR still having interference issues. POOH and inspect the tool string. Found a loose connection. RIH to 300' and shallow test the GR (good). RIH to 4585'.. Log up making several correlation passes.,Upload log and send Review logs town SimOps: POOH with E-Iine.,RD Pollard E-llne.,PJSM. PU the DP 3' to P� < to town engineer and geologist. with engineer and geologist. place the guns on depth at 5511' (top shot at 4630'). Break circulation to fill lines. Close the annular, pressure up the well to 2400 psi and hold for 6 minutes. Bleed the pressure to 0 psi and open the annular. The guns fired 22.5 minutes later (positive indication of detonation on surface). Well went on Iosses.,Lay down a single and TOOH from 5511' to 5207' (PU = 120K and $O = 70K). Circulate a DP volume at 3 BPM = 130 psi. Loss rate while pumping= 90 BPH.,Observe the well for flow. Static loss rate at 30 BPH. SimOps: Blow down the top drive.,TOOH with TCP gun assembly from 520T to 979.,Rig Fuel (gallons): OH= 9140, Used = 1430 & Rec = 0 OA pressure at midnight = 160 psi,Hauled 40 bbls H2O from L -Pad lake for total = 5370 bbls Hauled 0 bbls heated H2O from MPU G&I for total = 450 bbls Hauled 50 bbls cuttings/fiam its to MPU G&I for total = 7915 bbl 12/19/2018 PJSM, M/U safety joint with XO, R/U handling equipment to UD TCP perf guns., LID pup its, XOs and firing head., UD fired 5" TCP guns and blanks as per SLB rep V 929' to surface filling hole at 30 bph. Break and UD safety joint. Note: damage on 12 out of 20 pert guns that fired, severe splitting in several sections.,C/O to 4" handling equipment. Drain, clean and Load out guns from pipe shed, clear and clean rig floor. Load tools to rig floor.,M/U Cleanout BHA, 6 5/8" junk mill, BS, 6 3/4" string mill, XO, 3 boot baskets, BS w/ ported I t, 2 XOs, 2 string magnets, jars, bumper sub and X0= 77.05'.,TIH with cleanout BHA f/ 77to 5569, fill pipe at 2000'& 4500'. Wash down f/ 4591' w/ 3 BPM, 130 PSI. Observe intermittent 3-5K drag V 5290'. Observed 15K overpull at 5525', wash down then pickup clean. Tag bottom w/ 8K. 127K PU / 62K SO. Final circ. 200 PSI @ 3 BPM. 36 BPH losses while circulating., Displace well from 8.8 ppg KCUNaCI brine to 8.5 ppg seawater. Pumped 30 bbl viscosified spacer at 3 BPM, 340 PSI then displace at 5 BPM, 400 PSI ICP, 460 PSI FCP. Large amounts of sand over shakers. Minimal calculated losses during displacement. Perform 5 min. flow check - fluid level dropped 12".,Pump 25 bbl hi vis sweep at 5 BPM with large amounts of sand returned over shakers and did not clean up. 19 BPH losses while circulating 2nd sweep. Perform 5 min. flow check - fluid level dropped 12".,POOH f/ 5560'V 4591', above perforations at 4630'. Mix hi vis sweep and load 22 bbl hi vis sweep at 3 BPM, 120 PSI into drill pipe.,30 minute rig service - grease blocks and drawworks while beginning to change Totco drawworks encoder. 30 minute rig repair - finish changing Totco drawworks encoder.,Circulate out sweep with seawater at 7 BPM. 530 PSI ICP, 630 PSI FCP. 500% increase of sand observed at shakers and cleaned up. 54 BPH losses while circulating. Blow down top drive and perform flow check - fluid level dropped 24" over 15 min.,POOH f/ 4591' V 77' racking back 4" drill pipe. 21.6 bbls lost on trip out of the hole. Two string magnets were full with 1011 of metal shavings of small metal pieces up to 1/2" and twelve pieces up to 2"xt-1/2". Boot baskets filled primarily with sand with some metal cuttings and shavings. 6 BPH static losses while working on BHA.,M/U Cleanout BHA (same as previous), 6 5/8" junk mill, BS, 6 3/4" string mill, XO, 3 boot baskets, BS w/ ported fit, 2 XOs, 2 string magnets, jars, bumper sub and XO= 77.06. TIH from 77' to 1108' with 4" drill pipe from the derrick -Hauled 190 bbls H2O from L -Pad lake for total = 5,560 bbis Hauled 0 bbis heated H2O from MPU G&I for total = 450 bbls Hauled 325 bbis cuttings/liquids to MPU G&I for total = 8,240 bbis 710 bbis daily losses, 904 bbls cumulative losses. 12/20/2018 TIH with 6 3/4" cleanout assy f/ 1108' to 5531' filling pipe at 2000' and 4000', M/U TD, wash down 1 bpm, 40 psi tagging bottom @ 5560'. PU 120K, SO 70K. 35 bbl losses on TIH.,Pump 25 bbl Hi Vis sweep 3 bpm, 150 psi, increase pump to 7 bpm, 650 psi, work pipe 15' tagging bottom ea. time. 100% increase in sand at shakers, pump 2nd 25 bbl Hi Vis sweep around, 10% increase, circulate clean, flow check well, slight losses, BD TD. 18 bph loss rate while circulating.,TOOH f/ 5560'to 4588' just above perfs, circulate 25 bbl Hi Vis sweep around 7 bpm, 530 psi. No increase with sweep returns, wellbore clean, flow check well, slight losses. BD TD.,TOOH f/ 4588'to 77', Clean string magnets, UD and empty boot baskets, 3lbs metal fines and 1/2" pieces recovered off magnets, 1 gallon sand and fine metal recovered in boot baskets. Flow check well, Static loss rate 4 bph. 8 bbl losses on TOOH.,M/U scraper BHA, put 7-5/8" Scraper in place of boot baskets, TIH f/ 72' to 4545'. Work casing scraper V 4545' V 4425' five times. RIH to 4581' and pump 25 bbl hi vis sweep, 7 BPM, 450 PSI w/ no increase observed at shakers. 34 bph loss rate while circulating. Monitor well 5 min. -static. Blow down top drive., POOH V 4581' while laying down 'J 144 joints of 4" drill pipe. RIH 10 stands of 4" drill pipe from the derrick. UD 30 joints of 4" drill pipe. UD 7-518" scraper BHA. 112 gallon of fine metal shavings recovered from magnets. 14.9 bbis over displacement lost on trip out.,Clear rig floor of cleanout BHA components. Mobilize casing equipment to the rig floor. R/U to run 4-1/2" x 5-1/2" disposal well completion.,WU 4-1/2" tubing w/ WLEG, pup joint, XN w/ RHC, pup joint, 4-1/2" tubing joint, pup joint, 4-1/2" x 7-5/8" Halliburton TNT packer, pup joint, XO, 2 joints 5-1/2" tubing, pup joint, X nipple and pup joint to 206'. Torque 4-1/2" Vern to 4,400 fi/Ibs. and 5-1/2" Imp. BTC to 6,000 fl/lbs. verified with make-up mark on pin end of joint.,Run 5-1/2" 17# L-80 Imp. BTC completion It 206' V 989'. Torque to 6,000 ft/Ibs with Doyon double stack tongs.,Hauled 40 bbls H2O from L -Pad lake for total = 5,600 We Hauled 0 bbls heated H2O from MPU G&I for total = 450 bbis Hauled 200 bbls cuttings/liquids to MPU G&I for total = 8,440 bible 263 bbis daily losses, 1167 bbls cumulative losses. 12/21/2018 Continue to PIU and Run 5-1/2" 17# L-80 Imp. BTC completion V 989" 4546 Torque to 6,000 ft/lbs with Doyon double stack tongs. 6 bbl Losses over calculated displacement on TI H.,M/U XO pup, Hanger, XO pup and landing jt. Drain stack, RIH 30.68' RKB landing out hanger putting WLEG @ 4582.77'. RI LDS @ per WH rep. UD landing jt, install BPV. PU 95K, SO 70K w/ 30K setting on hanger., Blow down lines, RID handling equipment and power tongs, load out tools and clear rig floor. Note: AOGCC rep Guy Cook waived witness for VA MIT @ 12:02.,N/D BOPE, PIU and set stack on pedestal, clean welihead.,N/U tree. Test hanger void to 800 PSI low for 5 min. and 5000 PSI high for 10 min. - good test. Pull BPV & install TWC. Pressure test tree to 250 low for 5 min. and 5000 high for 5 min. Pull TWC.,R/U lines to circulate. Pressure test lines to 3700 PSI. Thaw external mud pump line. Pump 80 bbis of 8.5 ppg seawater corrosion inhibited with Conqor 304A directly from vac truck down the tubing. 4 BPM, 410 PSI max rate. 55 bbls returns to rockwasher.,R/U Little Red Services. Pump 100 bbls of heated diesel down the tubing. 1.5 BPM, 70 PSI ICP, 255 PSI FCP. 72 bbis returns to the rock washer. Allow to u -tube to annulus. 170 PSI observed at surface after u -tube complete. Ball and rod 92" length, only 8'4" from master valve to tree cap. Contact wells group to get OTIS extension for cap.,Hauled 130 bbls H2O from L -Pad lake for total = 5,730 bbis Hauled 0 bbis heated H2O from MPU G&I for total = 450 bbis Hauled 490 bbis cuttings/liquids to MPU G&I for total = 8,930 bbis 6 bbis daily losses, 1173 bbis cumulative losses. 12/22/2018 W/O wire line to arrive with 7" extension to install on tree allowing ball and rod drop, PJSM, set ball and rod in tree, M/U extension cap. Open master valve, drop ball and rod 07:35 close master. RID extension, install tree cap and gauge,PJSM, Pressure up the tbg w/ LRS to 3600 psi and hold for 5 min setting packer, test 5 1/2" tbg to 3500 psi for 30 min. charted. 1.4 bbis pumped, I/A 305 psi, CIA 200 psi, bleed off tbg pressure to psi, line up and pressure test SJI I/A to 2600 psi for 30 charted min. 1 bbl pumped, tbg 1950 psi, O/A 350 psi, bleed off I/A, 1 bbl bled back, bleed tbg to 300 psi. shut in well, Blow down lines, RID LRS.,P/U lubricator, leak test lubricator to 500 psi with diesel, open master valve, attempt to install BPV as per WH rep, PIU lubricator, rubber seal on BPV dislodging, replace seal, re -install and leak test lubricator, attempt to install BPV, same results, P/U lubricator, re -install seal on BPV, set and pressure lubricator to 300 psi with diesel, install BPV, RID lubricator. Final tbg = 300 psi, I/A= 0 psi, CIA =110 psi,Simops: Remove rock washer, cuttings tank, prep rig floor to skid, move 5 star shack, MI shack, rebuild 91 MP. Release rig @ 16:00 HRS,RD & MO to M-10. Please see M-10 report for details.,Hauled 0 bbis H2O from L -Pad lake for total = 5,730 bbls Hauled 0 bbls heated H2O from MPU G&I for total = 450 bbis Hauled 250 bbls cuttings/liquids to MPU G&I for total = 9,180 bbis 53 bbis daily losses 1226 bbis cumulative losses. 1/7/2019 PT PCE 250U3000H" UNABLE TO GET PAST TBG HANGER @ 0' SLM, BPV still in hole. WELL HEAD GUYS ON LOC TO REMOVE BPV 118/2019 PT PCE 250U3000H" PULL 1-318" F.N. BALL & ROD @ 4493' SLM. PULL 4-1/2" RHC PLUG BODY FROM XN-NIPPLE @ 4502' SLM DRIFT TBG & TAG TD @ 5525' SLM 15558' MD, SAND & CEMENT LOG BASELINE FROM SURFACE CED 40fpm DOWN TO 5529 SLM / 5553' MD, Hilcorp Alaska, LLC Milne Point M Pt Moose Pad M-03 50-029-23614-00 Sperry Drilling Definitive Survey Report 17 December, 2018 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Coordinate Reference: Well MPU M-03 Project: Milne Point TVD Reference: M-03 Actual RKB @ 58.70usft Site: M Pt Moose Pad MD Reference: M-03 Actual RKB @ 58.70usft Well: MPU M-03 North Reference: True Wellbore: M-03 Survey Calculation Method: Minimum Curvature Design: M-03 Database: NORTH US+CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-03 Well Position +N/S 0.00 usft Northing: +EI -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore M-03 Magnetics Model Name Sample Date BGGM2018 9/13/2018 6,027,889.71 usfl Latitude: 70° 29' 14.024 N 533,363.90 usft Longitude: 149° 43'38.285 W 25.00 usfl Ground Level: 25.00 usft Declination Dip Angle (1 (') 17.00 Field Strength (nT) 80.98 57,451.62200919 Design M-03 Audit Notes: Map Version: 1.0 Phase: ACTUAL Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +Nl-S +E/ -W Direction +NIS (usft) (usft) (usft) (usft) (I DLS (°170(') 33.70 0.00 0.00 179.26 Survey Program Date 12/13/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 226.29 2,815.67 MPU M-03 MWD+IFR2+MS+Sag(1)(M-2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 11126/2018 2,888.73 6,365.39 MPU M-03 MWD+IFR2+MS+Sag (2) (M-2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 12/10/2018 Survey Map Map Vertical MD (usft) Inc (I Azi N TVD (usft) TVDSS (usft) +NIS (usft) +El -W (usft) Northing (ft) Easting (ft) DLS (°170(') Section (ft) Survey Tool Name 33.70 0.00 0.00 33.70 -25.00 0.00 0.00 6,027,889.71 533,363.90 0.00 0.00 UNDEFINED 226.29 1.37 56.16 226.27 167.57 1.28 1.91 6,027,891.00 533,365.81 0.71 -1.26 2_MWD+IFR2+MS+Sag(1) 320.41 1.92 71.16 320.35 261.65 2.42 4.34 6,027,892.15 533,368.23 0.74 -2.36 2_MWD+IFR2+MS+Sag(1) 413.43 2.39 68.23 413.31 354.61 3.64 7.62 6,027,893.38 533,371.50 0.52 -3.54 2_MWD+IFR2+MS+Sag(1) 506.97 2.19 121.39 506.78 448.08 3.43 10.95 6,027,893.19 533,374.84 2.20 -3.29 2_MWD+IFR2+MS+Sag(1) 598.05 4.91 168.81 597.69 538.99 -1.30 13.20 6,027,888.47 533,377.10 4.16 1.47 2 MWD+IFR2+MS+Sag(1) 691.43 8.04 175.68 690.47 631.77 -11.73 14.46 6,027,878.04 533,378.41 3.45 11.92 2_MWD+IFR2+MS+Sag(1) 786.48 12.25 182.75 784.02 725.32 -28.44 14.48 6,027,861.34 533,378.51 4.61 28.63 2_MWD+IFR2+MS+Sag(1) 880.57 16.45 184.28 875.15 816.45 -51.71 13.01 6,027,838.07 533,377.14 4.48 51.87 2_MWD+IFR2+MS+Sag(1) 974.01 20.09 182.80 963.86 905.16 -80.94 11.23 6,027,808.83 533,375.50 3.93 81.08 2_MWD+IFR2+MS+Sag(1) 1,067.66 23.91 179.62 1,050.68 991.98 -116.00 10.57 6,027,773.77 533,374.99 4.27 116.12 2_MWD+IFR2+MS+Sag (1) 1,165.25 28.43 176.35 1,138.25 1,079.55 -158.98 12.19 6,027,730.80 533,376.80 4.86 159.13 2_MWD+IFR2+MS+Sag (1) 1,260.14 33.70 175.90 1,219.50 1,160.80 -207.82 15.51 6,027,681.99 533,380.34 5.56 208.00 2_MWD+IFR2+MS+Sag (1) 1211712018 1:24:37PM Page 2 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-03 Wellbore: M-03 Design: M-03 Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU M-03 TVD Reference: M-03 Actual RKB @ 58.70usft MD Reference: M-03 Actual RKB @ 58.70usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map MD Inc Azi TVD TVDSS +NIS +EI -W Northing (usft) (°) (°) (usft) (usft) (usft) (usit) (ft) 1,354.30 34.83 175.92 1,297.32 1,238.62 -260.69 19.29 6,027,629.13 1,447.98 37.09 176.19 1,373.14 1,314.44 -315.57 23.07 6,027,574.28 1,542.31 41.97 177.84 1,445.88 1,387.18 -375.51 26.15 6,027,514.36 1,636.78 45.21 179.34 1,514.29 1,455.59 440.61 27.73 6,027,449.27 1,728.95 48.97 179.48 1,577.04 1,518.34 -508.10 28.42 6,027,381.79 1,825.09 51.49 179.81 1,638.53 1,579.83 -581.99 28.87 6,027,307.91 1,918.06 57.17 179.29 1,692.72 1,634.02 -657.49 29.48 6,027,232.43 2,014.05 61.47 179.29 1,741.69 1,682.99 -740.01 30.50 6,027,149.91 2,108.64 66.57 179.06 1,783.11 1,724.41 -825.01 31.73 6,027,064.93 2,203.08 68.08 179.73 1,819.52 1,760.82 -912.14 32.65 6,026,977.81 2,297.63 67.26 179.87 1,855.44 1,796.74 -999.60 32.95 6,026,890.37 2,391.98 68.48 180.84 1,890.98 1,832.28 -1,086.99 32.41 6,026,802.98 2,486.34 67.86 181.39 1,926.07 1,867.37 -1,174.57 30.70 6,026,715.40 2,580.50 68.66 181.16 1,960.95 1,902.25 -1,262.01 28.76 6,026,627.97 2,674.22 69.84 179.70 1,994.15 1,935.45 -1,349.65 28.10 6,026,540.34 2,768.83 70.09 179.30 2,026.57 1,967.87 -1,438.53 28.88 6,026,451.47 2,815.67 69.62 179.01 2,042.70 1,984.00 -1,482.50 29.53 6,026,407.51 2,888.73 68.98 178.88 2,068.52 2,009.82 -1,550.83 30.79 6,026,339.19 2,983.28 69.16 178.65 2,102.30 2,043.60 -1,639.12 32.69 6,026,250.92 3,076.34 68.77 178.31 2,135.70 2,077.00 -1,725.95 34.99 6,026,164.11 3,167.77 67.68 178.36 2,169.62 2,110.92 -1,810.81 37.46 6,026,079.26 3,265.01 66.56 179.56 2,207.43 2,148.73 -1,900.39 39.09 6,025,989.71 3,359.82 68.43 178.92 2,243.72 2,185.02 -1,987.96 40.26 6,025,902.14 3,454.10 68.06 179.01 2,278.66 2,219.96 -2,075.51 41.84 6,025,814.61 3,547.53 67.79 178.59 2,313.77 2,255.07 -2,162.08 43.65 6,025,728.07 3,643.41 67.83 179.07 2,349.98 2,291.28 -2,250.84 45.46 6,025,639.32 3,737.77 68.44 178.82 2,385.13 2,326.43 -2,338.39 47.08 6,025,551.78 3,831.04 69.24 178.40 2,418.79 2,360.09 -2,425.35 49.19 6,025,464.85 3,926.12 67.86 178.08 2,453.56 2,394.86 -2,513.80 51.90 6,025,376.42 4,019.84 66.39 177.24 2,489.99 2,431.29 -2,600.07 55.43 6,025,290.17 4,114.85 66.32 178.81 2,528.10 2,469.40 -2,687.05 58.43 6,025,203.21 4,207.41 65.12 180.79 2,566.16 2,507.46 -2,771.42 58.73 6,025,118.86 4,302.73 64.14 180.83 2,607.00 2,548.30 -2,857.53 57.51 6,025,032.75 4,396.64 64.44 182.55 2,647.75 2,589.05 -2,942.10 55.01 6,024,948.17 4,489.00 68.20 183.28 2,684.83 2,626.13 -3,026.56 50.70 6,024,863.70 4,583.08 68.52 182.86 2,719.53 2,660.83 -3,113.89 46.02 6,024,776.37 4,678.68 66.72 180.98 2,755.93 2,697.23 -3,202.23 43.05 6,024,688.03 4,774.18 64.38 179.85 2,795.45 2,736.75 -3,289.15 42.41 6,024,601.11 4,868.92 62.09 179.37 2,838.12 2,779.42 -3,373.73 42.99 6,024,516.54 4,962.77 60.95 180.38 2,882.87 2,824.17 -3,456.22 43.17 6,024,434.06 Map Easting DLS (1t) 533,384.36 1.20 533,388.38 2.42 533,391.73 5.29 533,393.60 3.60 533,394.60 4.08 533,395.38 2.63 533,396.32 6.13 533,397.72 4.48 533,399.33 5.40 533,400.63 1.73 533,401.33 0.88 533,401.18 1.61 533,399.87 0.85 533,398.32 0.88 533,398.06 1.93 533,399.23 0.48 533,400.08 1.16 533,401.64 533,403.94 533,406.63 533,409.48 533,411.51 533,413.07 533,415.04 533,417.24 533,419.46 533,421.46 533,423.96 533,427.07 533,430.98 533,434.37 533,435.05 533,434.22 533,432.10 533,428.18 533,423.88 533,421.31 533,421.06 533,422.01 533,422.57 0.89 0.30 0.54 1.19 1.62 2.07 0.40 0.51 0.47 0.69 0.96 1.48 1.77 1.52 2.34 1.03 1.68 4.13 0.54 2.62 2.68 2.46 1.54 Vertical Section (ft) Survey Tool Name 260.92 2_MWD+IFR2+MS+Sag(1) 315.84 2_MWD+IFR2+MS+Sag(1) 375.81 2_MWD+IFR2+MS+Sag (1) 440.93 2_MWD+IFR2+MS+Sag(1) 508.43 2_MWD+IFR2+MS+Sag(1) 582.32 2_MWD+IFR2+MS+Sag(1) 657.81 2_MWD+IFR2+MS+Sag (1) 740.35 2_MWD+IFR2+MS+Sag(1) 825.35 2_MWD+IFR2+MS+Sag(1) 912.49 2_MWD+IFR2+MS+Sag(1) 999.94 2_MWD+IFR2+MS+Sag(1) 1,087.32 2_MWD+IFR2+MS+Sag(1) 1,174.87 2_MWD+IFR2+MS+Sag(1) 1,262.28 2_MWD+IFR2+MS+Sag(1) 1,349.90 2_MWD+IFR2+MS+Sag(1) 1,438.78 2_MWD+IFR2+MS+Sag(1) 1,482.75 2_MWD+IFR2+MS+Sag(1) 1,551.10 2_MWD+IFR2+MS+Sag(2) 1,639.40 2_MWD+IFR2+MS+Sag(2) 1,726.25 2_MWD+IFR2+MS+Sag(2) 1,811.15 2_MWD+IFR2+MS+Sag(2) 1,900.73 2_MWD+IFR2+MS+Sag(2) 1,988.32 2_MWD+IFR2+MS+Sag(2) 2,075.88 2_MWD+IFR2+MS+Sag(2) 2,162.46 2_MWD+IFR2+MS+Sag(2) 2,251.23 2_MWD+IFR2+MS+Sag(2) 2,338.81 2_MWD+IFR2+MS+Sag (2) 2,425.78 2_MWD+IFR2+MS+Sag (2) 2,514.26 2_MWD+IFR2+MS+Sag(2) 2,600.57 2_MWD+IFR2+MS+Sag (2) 2,687.58 2_MWD+IFR2+MS+Sag(2) 2,771.94 2_MWD+IFR2+MS+Sag (2) 2,858.04 2_MWD+IFR2+MS+Sag (2) 2,942.57 2_MWD+IFR2+MS+Sag (2) 3,026.96 2 MWD+IFR2+MS+Sag (2) 3,114.22 2_MWD+IFR2+MS+Sag (2) 3,202.52 2_MWD+IFR2+MS+Sag (2) 3,289.43 2 MWD+IFR2+MS+Sag (2) 3,374.01 2_MWD+IFR2+MS+Sag (2) 3,456.49 2_MWD+IFR2+MS+Sag (2) 12/172018 1:24:37PM Page 3 COMPASS 5000.15 Build 91 Company: Project: Site: Well: Wellbore: Design: Survey Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-03 M-03 M-03 Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-03 M-03 Actual RKB @ 58.70usft M-03 Actual RKB @ 58.70usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (°1100') (ft) Survey Tool Name 533,424.42 3.13 3,538.37 2_MWD+IFR2+MS+Sag(2) 533,428.35 2.39 3,618.42 2_MWD+IFR2+MS+Sag(2) 533,432.65 2.51 3,697.23 2_MWD+IFR2+MS+Sag(2) 533,437.41 2.46 3,770.52 2_MWD+IFR2+MS+Sag (2) 533,441.86 2.15 3,846.23 2_MWD+IFR2+MS+Sag (2) 533,444.27 2.89 3,918.20 2_MWD+IFR2+MS+Sag(2) 533,444.43 4.19 3,985.65 2_MWD+IFR2+MS+Sag(2) 533,442.99 4.14 4,051.02 2_MWD+IFR2+MS+Sag(2) 533,441.51 1.06 4,112.05 2_MWD+IFR2+MS+Sag(2) 533,440.37 0.75 4,171.56 2_MWD+IFR2+MS+Sag(2) 533,439.44 1.34 4,230.47 2_MWD+IFR2+MS+Sag (2) 533,438.64 1.38 4,287.74 2_MWD+IFR2+MS+Sag (2) 533,438.58 1.64 4,342.75 2_MWD+IFR2+MS+Sag (2) 533,439.32 1.16 4,397.05 2_MWD+IFR2+MS+Sag (2) 533,440.55 0.99 4,442.71 2_MWD+IFR2+MS+Sag (2) 533,441.31 0.00 4,462.31 PROJECTED to TD Checked By: Chelsea Wright ,Approved By: Mitch Laird Date: 12-17-2018 12/172018 1:24:37PM Page 4 COMPASS 5000.15 Build 91 Map MD Inc Azi TVD TVDSS +N1 -S +E/ -W Northing (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) 5,057.20 59.34 177.52 2,929.88 2,871.18 -3,538.09 44.65 6,024,352.20 5,151.42 57.09 177.36 2,979.51 2,920.81 -3,618.10 48.23 6,024,272.22 5,246.66 54.73 176.90 3,032.89 2,974.19 -3,696.87 52.17 6,024,193.48 5,337.76 52.57 176.16 3,086.88 3,028.18 -3,770.10 56.61 6,024,120.27 5,434.31 50.85 177.64 3,146.71 3,088.01 -3,845.76 60.72 6,024,044.64 5,528.85 48.34 179.06 3,207.98 3,149.28 -3,917.71 62.81 6,023,972.70 5,621.78 44.79 181.25 3,271.87 3,213.17 -3,985.18 62.66 6,023,905.25 5,718.07 40.82 181.81 3,342.50 3,283.80 4,050.57 60.93 6,023,839.86 5,812.45 39.84 181.47 3,414.45 3,355.75 4,111.62 59.18 6,023,778.80 5,906.09 39.15 181.25 3,486.71 3,428.01 4,171.16 57.76 6,023,719.26 6,000.74 37.89 181.07 3,560.76 3,502.06 4,230.10 56.57 6,023,660.33 6,095.43 36.58 181.03 3,636.15 3,577.45 -4,287.38 55.52 6,023,603.04 6,189.17 35.30 179.59 3,712.04 3,653.34 4,342.40 55.21 6,023,548.03 6,284.45 34.20 179.37 3,790.33 3,731.63 -4,396.70 55.70 6,023,493.74 6,365.39 34.49 178.05 3,857.16 3,798.46 -4,442.35 56.73 6,023,448.10 6,400.00 34.49 178.05 3,885.68 3,826.98 -4,461.94 57.40 6,023,428.51 Well MPU M-03 M-03 Actual RKB @ 58.70usft M-03 Actual RKB @ 58.70usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (°1100') (ft) Survey Tool Name 533,424.42 3.13 3,538.37 2_MWD+IFR2+MS+Sag(2) 533,428.35 2.39 3,618.42 2_MWD+IFR2+MS+Sag(2) 533,432.65 2.51 3,697.23 2_MWD+IFR2+MS+Sag(2) 533,437.41 2.46 3,770.52 2_MWD+IFR2+MS+Sag (2) 533,441.86 2.15 3,846.23 2_MWD+IFR2+MS+Sag (2) 533,444.27 2.89 3,918.20 2_MWD+IFR2+MS+Sag(2) 533,444.43 4.19 3,985.65 2_MWD+IFR2+MS+Sag(2) 533,442.99 4.14 4,051.02 2_MWD+IFR2+MS+Sag(2) 533,441.51 1.06 4,112.05 2_MWD+IFR2+MS+Sag(2) 533,440.37 0.75 4,171.56 2_MWD+IFR2+MS+Sag(2) 533,439.44 1.34 4,230.47 2_MWD+IFR2+MS+Sag (2) 533,438.64 1.38 4,287.74 2_MWD+IFR2+MS+Sag (2) 533,438.58 1.64 4,342.75 2_MWD+IFR2+MS+Sag (2) 533,439.32 1.16 4,397.05 2_MWD+IFR2+MS+Sag (2) 533,440.55 0.99 4,442.71 2_MWD+IFR2+MS+Sag (2) 533,441.31 0.00 4,462.31 PROJECTED to TD Checked By: Chelsea Wright ,Approved By: Mitch Laird Date: 12-17-2018 12/172018 1:24:37PM Page 4 COMPASS 5000.15 Build 91 Lease & Well No. County i Hilcorp Energy Company CASING & CEMENTING REPORT MP M-03 State Alaska Supv. CASING RECORD Surface TD 2,855.00 Shoe Depth: 2,845.69 PBTD: No. Jts. Delivered 83 No. Jts. Run 69 RKB 33.98 RKB to BHF RKB to CHF Date Run 5 -Dec -18 Sunderland / Demoski No. Jts. Returned 14 RKB to THF Csg Wt. On Hook: 145,000 Type Float Collar: Antelope No. Hrs to Run: 9.5 Csg Wt. On Slips: 58,000 Type of Shoe: Antelope Casing Crew: Doyon Rotate Csg Yes X No Recip Csg X Yes No 30 Ft. Min. 9.2 PPG Fluid Description: Spud Mud Liner hanger Info (Make/Model): Liner lop Packer?: _Yes —No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: One 13-1/2" Centek centralizer w/ stop ring 10' from shoe on shoe joint, one 13-1/2" expand-o-lizer cross coupler centralizer on shoe joint, one each Centek centralizer w/ 2 stop rings mid -joint on Baker Loc joint & float collar joint. Install 10-3/4"A3- 1/2" expand-o-lizer cross coupler centralizer on each connection to surface. Total of 3 Centek and 66 expand-o-lizer centralizers & 5 stop rings ran it 6t4 13,s - CEMENTING REPORT Shoe @ 2845 FC @ 2,761.00 ush (Spacer) Clean Spacer Density (ppg) 10 Slurry Permafrost L Density (ppg) 10.7 Volume pumped (BBLs) _ Tail Slurry w Type: Premium G F Density (ppg) 15.8 Volume pumped (BBLs) w Post Flush (Spacer) w Type: Density (ppg) LL Spud Mud Density (ppg) 9.1 Rate (bpm): (psi): 570 Pump used for disp: Rig ig Rotated? _Yes X No Reciprocated? X ant returns to surface? X Yes _ No Spacer returns? ant In Place At: 11:17 Date: 12/6/2018 ad Used To Determine TOC: Returns to surface Calculated Cmt Vol @ 0% excess: Cmt returned to surface: 218 OH volume Calculated: 174.12 www.wellez.net 396 73 Top of Liner Volume pumped (BBLs) 60 Sacks: 475' Yield 4.33 Mixing / Pumping Rate (bpm): 4 Sacks: 355., Yield: 1.17 Mixing / Pumping Rate (bpm): 5 Rate (bpm): Volume: 5 Volume (actual / calculated): 265.12 Bump Plug? X Yes _ No Bump press Yes _ No % Returns during job 100 X Yes No Vol to Surf: 218 Estimated TOC: 36 201.24 Total Volume cml Pumped: 469 Icula ment left in wellbore: 251 OH volume actual: 201.24 Actual % Washout: 29 WellEz Information Mana ver_ 9r-� 16"Jc /o3/'( L*, Casing (Or Liner) Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 113/4 P-110 BTC Antelope 1.76 2,845.69 2,843.93 2 Casing 103/4 45.5 L-80 TXP BTC Tenaris 81.18 2,843.93 2,762.75 1 Float Collar 11 3/4 P-110 BTC Antelope 1.40 2,762.75 2,761.35 67 Casing 103/4 45.5 L-80 TXP BTC Tenaris 2,720.80 2,761.35 40.55 1 Casing Pup Joint 103/4 45.5 L-80 TXP BTC Tenaris 4.75 40.55 35.80 Csg Wt. On Hook: 145,000 Type Float Collar: Antelope No. Hrs to Run: 9.5 Csg Wt. On Slips: 58,000 Type of Shoe: Antelope Casing Crew: Doyon Rotate Csg Yes X No Recip Csg X Yes No 30 Ft. Min. 9.2 PPG Fluid Description: Spud Mud Liner hanger Info (Make/Model): Liner lop Packer?: _Yes —No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: One 13-1/2" Centek centralizer w/ stop ring 10' from shoe on shoe joint, one 13-1/2" expand-o-lizer cross coupler centralizer on shoe joint, one each Centek centralizer w/ 2 stop rings mid -joint on Baker Loc joint & float collar joint. Install 10-3/4"A3- 1/2" expand-o-lizer cross coupler centralizer on each connection to surface. Total of 3 Centek and 66 expand-o-lizer centralizers & 5 stop rings ran it 6t4 13,s - CEMENTING REPORT Shoe @ 2845 FC @ 2,761.00 ush (Spacer) Clean Spacer Density (ppg) 10 Slurry Permafrost L Density (ppg) 10.7 Volume pumped (BBLs) _ Tail Slurry w Type: Premium G F Density (ppg) 15.8 Volume pumped (BBLs) w Post Flush (Spacer) w Type: Density (ppg) LL Spud Mud Density (ppg) 9.1 Rate (bpm): (psi): 570 Pump used for disp: Rig ig Rotated? _Yes X No Reciprocated? X ant returns to surface? X Yes _ No Spacer returns? ant In Place At: 11:17 Date: 12/6/2018 ad Used To Determine TOC: Returns to surface Calculated Cmt Vol @ 0% excess: Cmt returned to surface: 218 OH volume Calculated: 174.12 www.wellez.net 396 73 Top of Liner Volume pumped (BBLs) 60 Sacks: 475' Yield 4.33 Mixing / Pumping Rate (bpm): 4 Sacks: 355., Yield: 1.17 Mixing / Pumping Rate (bpm): 5 Rate (bpm): Volume: 5 Volume (actual / calculated): 265.12 Bump Plug? X Yes _ No Bump press Yes _ No % Returns during job 100 X Yes No Vol to Surf: 218 Estimated TOC: 36 201.24 Total Volume cml Pumped: 469 Icula ment left in wellbore: 251 OH volume actual: 201.24 Actual % Washout: 29 WellEz Information Mana ver_ 9r-� 16"Jc /o3/'( L*, Lease 9 Well No Counry Hilcorp Energy Company CASING & CEMENTING REPORT MP M-03 State Alaska CASING RECORD Production _ TD 6,400.00 Shoe Depth: 5,648.28 No. As. Delivered 148 No. As. Run RKB 33.98 RKB to BHF RKB to CHF Date Run 14 -Dec -18 Supv. Sunderland/Toomey _ PBTD: 5,562.91 140 No. As. Returned 8 RKB to THF Csg Wt. On Hook: 190,000 Type Float Collar: No. Hrs to Run: Casing (Or Liner) Detail Csg Wt. On Slips: 90,000 Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 85/8 Liner top Packer?: L-80 Hydril 563 2.49 5,648.28 5,645.79 2 Casing 75/8 29.7 L-80 Hydril563 79.11 5,645.79 5,566.68 1 Pup Joint 75/8 29.7 L-80 Hydril563 2.54 5,566.68 5,564.14 1 Float Collar 85/8 Type: Fresh Water L-80 Hydril563 1.23 5,564.14 5,562.91 138 Casing 75/8 29.7 L-80 Hydril563 5,525.31 5,562.91 37.60 1 Pup Joint 75/8 29.7 L-80 Hydril563 3.75 37.60 33.85 1 Mandrel Casing Hanger 103/4 L-80 Hydril 563 0.85 33.85 33.00 Csg Wt. On Hook: 190,000 Type Float Collar: No. Hrs to Run: 17 Csg Wt. On Slips: 90,000 Type of Shoe: Casing Crew: Doyon Casing Rotate Csg Yes X No Recip Csg _ Yes X No Ft. Min. 9.3 PPG Fluid Description: LSND Lead Slurry 100 ant returns to surface? Liner hanger Info (Make/Model): Type: Primary Cement Liner top Packer?: _Yes —No Liner hanger test pressure: Density (ppg) 15.8 Floats Held X Yes No CEMENTING REPORT LSND Shoe @ 5645.79 FC @ 5,562.91 Top of Liner 234.6/235.1 Preflush(Spacer) Pump used for disp: Rig Bump Plug? X Yes _ No Type: Tuned Spacer Density (ppg) 10.5 Volume pumped (BBLs) 40 No Reciprocated? _Yes Lead Slurry 100 ant returns to surface? Type: Primary Cement X No Vol to Surf: Sacks: 440 Yield: 1.15 ant In Place At: Density (ppg) 15.8 Volume pumped (BBLs) 90 Mixing / Pumping Rate (bpm): 3 3,820 ✓ Tail Slurry CBL I.. oA. _ Type: Sacks: Yield: w Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): v, Post Flush (Spacer) �n LL Type: Fresh Water Density (ppg) 8.4 Rate (bpm): 3 Volume: 20 LSND Density (ppg) 9.3 Rate (bpm): 8 Volume (actual / calculated): 234.6/235.1 (psi): 920 Pump used for disp: Rig Bump Plug? X Yes _ No Bump press 14 1g Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 ant returns to surface? X No Spacer returns? X No Vol to Surf: 0 ant In Place At: _Yes 13:30 Date: 12/15/2018 _Yes Estimated TOC: 3,820 ✓ od Used To Determine TOC: CBL I.. oA. _ Calculated Cmt Vol @ 0% excess: 64 Total Volume cmt Pumped: _ Cmt returned to surface: 0 Calculated cement left in wellbore: 90 OH volume Calculated: 60 OH volume actual: e0 Actual % Washout: Haa,.p Almkn. UC DATE: 1/16/2019 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-03 (PTD 218-140) ROP DGR EWR ALD CTN MD & TVD CD: HALLIBURTON 20 DEC 2018 I _Log Viewers I CGM I Definitive Survey �. EMF LAS �. PDF �. TIFF RECEIVE® JAN 1 7 2019 AOGCC 1/16/2019 8:35 AM File folder 1/16/2019 8:33 AM File folder 1/16/2019 8:34 AM File folder 1/16/2019 8:34 AM File folder 1/16/2019 8:34 AM File folder 1/16/2019 8:34 AM File folder 1/16/2019 8:35 AM File folder Please include current contact information if different from above. 21811,0 30 26 5 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: ��� I;A I // /1/— .1 / / I Date: l ilruq UaA.0 U.C. DATE 1/9/2019 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Meredith Guhl, Petroleum Geology Assistant 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 Transmitted herewith are cuttings from MPU M-03 WELL BOX # SAMPLE INTERVAL MPU M-03 1 2850' - 4020' MPU M-03 2 4020' - 5250' MPU M-03 3 5250' - 5690' MPU M-03 4 5690' - 6070' MPU M-03 5 6070' - 6400' Please include current contact information if different from above. o?t8- I q0 1011 RECEIVED JAN 0 9 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Receive By: Date: X11'1 1q DATE 1/09/2019 218140 Debra Oudean 30 2 2 9 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Ste 1400 1 Anchorage, Alaska 99503 Office: 907.777.8337 doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite100 Anchorage, AK 99501 CD: DLIS, LAS PDF USIT Corrosion GR USIT Cement Bond Log GR/CCL Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, December 18, 2018 2:32 PM To: 'Monty Myers' Cc: Taylor Wellman; Wyatt Rivard; Stan Porhola; Joe Engel Subject: RE: PTD 218-140 (MPU M-03 CBL results for disposal zone) Monty, The bond log looks good below 3700 ft MD.. which is about 2350ft TVD. DID 42 states in the Findings Section that cement should beat approximately 2100 ft TVD. 2350 ft TVD is acceptable based on the confining zones and proposed packer placement for the well. You have almost 1000 ft of excellent cement for confinement from the top disposal zone to the TOC. Additionally, the proposed packer placement of 4400 ft gives about 600 ft of cement above it. No Variance is needed. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENIIAUTY 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 schwarfz@alaska a9A. From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday, December 18, 2018 11:49 AM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com>; Stan Porhola <sporhola@hilcorp.com>; Joe Engel <jengel@hilcorp.com> Subject: PTD 218-140 (MPU M-03 CBL results for disposal zone) Good morning Guy, Attached are the results from the CBL run in the 7-5/8" casing on MPU M-03. The attached results depict TOC at approximately 3,820' TMD (2,415' TVD) . Our surface casing was set at 2,845' TMD (2,053' TVD) The Top of the disposal zone is: Top Disposal Zone: 4,607' MD Base Disposal Zone 5,489' MD Top Ugnu Heavy Oil: 5,626' MD Base Ugnu Heavy Oil: 5,745' MD Top Schrader Bluff: 5,949' MD We have ^'787' TMD of cement abov, the top of the disposal zone which keeps u_ ,n accordance with 20AAC 25.030(d)(5), but our cement top varies from what is required for D1O42 which states we would have TOC at 2,100' TVD in our intermediate string. This is a 315' TVD difference in cement height from actual to what is required in DID 42. Hilcorp respectfully asks for a variance from DID 42 item #7 since there is sufficient cement above the disposal zone and our top perforation depth will be 4,630' TMD (2,736' TVD), further increasing the distance of isolation to 810' TMD (321' TVD) Please provide guidance on this issue and if this is acceptable in the AOGCC's opinion. Thank you! Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7a' Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF Hilcorp Alaska, LLC. for disposal of Class II oil field wastes by underground injection in the Ugnu Formation in up to four wells located on the Moose Pad in the northwest portion of the Milne Point Unit Sections 12, 13, 14, 23, 24, TI 3N, R9E, and Sections 7, 18, 19, TON, R10E S.M. IT APPEARING THAT: Disposal Injection Order No. 42 Docket No. DIO-18-001 Ugnu Formation, Undefined Waste Disposal Pool Milne Point Unit October 24, 2018 L Hilcorp Alaska, LLC (Hilcorp) requested authorization for underground disposal of Class II oil field waste fluids into up to four yet to be drilled wells (Class II wells) on the Moose Pad in the northwest portion of the Milne Point Unit (MPU). Hilcorp's Application for Disposal Injection Order (DIO) was received by the Alaska Oil and Gas Conservation Commission (AOGCC) on July 20, 2018. 2. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing for September 5, 2018. On July 24, 2018, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On July 25, 2018, the notice was published in the ANCHORAGE DAILY NEWS. At the September 5, 2018 hearing Hilcorp provided testimony and presented evidence in support of its Application. The record was closed at the end of the hearing. 4. The information submitted by Hilcorp and public records for MPU wells are the basis for this order. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) There are no active wells within the %4 -mile area of review surrounding the disposal intervals for the proposed Class II wells. The plugged and abandoned Simpson Lagoon 32-14 well lies within '/4 mile of one proposed Class II well in the disposal interval. Future production and injection wells drilled from the Moose Pad may pass within %4 mile of the proposed Class II disposal wells. Disposal Injection Order 42 October 24, 2018 Page 2 of 7 2. Notification of Operators/Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Hilcorp is the only operator and the State of Alaska, Alaska Department of Natural Resources (ADNR) is the only surface owner within'/4-mile radius of the proposed disposal wells. Hilcotp provided AOGCC a copy of an affidavit affirming that ADNR was provided a copy of the DIO application. 3. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) The proposed disposal injection operations will affect strata that are assigned to the lower Tertiary -aged Ugnu Formation (Ugnu). In Moose Pad area, the Ugnu consists of predominately discrete, coarse-grained, moderate to well -sorted, fluvial/deltaic, wet sands with average porosity of 30-32% and average permeability of 1,000 millidarcies. On the MPU M-01 type log, these clean sands are bounded by impermeable siltstones and mudstones. Hilcorp plans injection within the permeable upper Ugnu sands between the informal MP LC and the MP UG 15 geologic markers from 3,282' measured depth (MD, equivalent to -2,714' true vertical depth subsea, or TVDSS) to 3,912' MD (-3,187' TVDSS). Upper confinement for the proposed injection interval consists of laterally continuous layers of mudstone, siltstone, and coal that lie within the Ugnu between 2,854' (-2,413' TVDSS) and 3,282' MD (-2,714' TVDSS) in MPU M-01. These confining layers, which range in true vertical thickness (thickness) from 10' to 45' and have a combined thickness of about 90', will serve as effective barriers to prevent vertical migration of injected fluids. Lower confinement will be provided by laterally continuous layers of mudstone, siltstone and coal within the upper Ugnu between 3,912' MD (-3,187' TVDSS) and 4,033' MD (-3,280' TVDSS). These impermeable intervals range from 11' to 15' in thickness and have a combined thickness of 40'. The proposed disposal well area is partially bound to the east and west by north -south oriented faults with significantly less displacement than the thickness of the entire proposed injection interval. 4. Evaluation of Fluid Confinement (20 AAC 25.252(c)(9)) The porous and permeable nature of the wet, upper Ugnu sands allows injection of produced water at pressures that are lower than Hilcorp's stated formation -fracture pressure limit of 2,500 psi for unconsolidated sands. Future wells within 1/4 -mile must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 5. Aquifer Exemption (20 AAC 25.252(c)(11))• Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)) Aquifer Exemption Order No. 2 governs the four potential Class II well locations near Moose Pad. Hilcorp does not have a water sample from the proposed disposal intervals in this area. Hilcorp provided information representing that it is cost -prohibitive to use subsurface aquifers near Moose Pad as a source of drinking water. 6. Well Logs (20 AAC 25.252(c)(5)) Log data from existing wells near Moose Pad are on file with the AOGCC. The representative well, MPU M-01, has a complete set of logs. Disposal Injection Order 42 October 24, 2018 Page 3 of 7 7. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) The proposed casing program is 10 -3/4 -inch surface casing set at 2,100' TVD and cemented to surface. A formation Integrity Test will be performed to 12.5 ppg equivalent and the production hole drilled. Production 7 -5/8 -inch casing will be set to 3,300' TVD and cemented to approximately 2,100' TVD and tested to 2,500 psi. A cement bond log will be run to confirm the cement top and that casing strings have adequate cement to prevent vertical migration of disposal fluids. Hilcorp requests packers be located more than 200' MD above the top of the disposal perforations. This will allow through -tubing access to the entire requested disposal zone. Tubing or other equipment will be designed and installed in accordance with 20 AAC 25.412. A casing mechanical integrity test will be performed in accordance with 20 AAC 25.412 prior to initiation of disposal operations. Hilcorp will perform mechanical integrity tests of the tubing and tubing -casing annulus (including packer) as part of the operations before disposal injection commences. Additional baseline assessments and subsequent evaluations may be necessary to confirm the wells have the proper mechanical integrity for disposal injection as proposed. Hilcorp will monitor the 7 -5/8 -inch casing by 5 -1/2 -inch tubing annulus pressure daily and report the results on the Monthly Injection Report. 8. Disposal Fluid Type Composition Source Volume and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) Hilcorp requests approval to dispose of drilling, production, completion, workover wastes, and other associated wastes that are intrinsically derived from primary field operations. Hilcorp expects daily injection volumes of a maximum of 36,000 barrels for the first well, up to a cumulative 72,000 barrels with the proposed two wells. Over the expected 17 -year life of the project, Hilcorp expects to dispose of approximately 355 million barrels of liquids. This equates approximately to a plume of about 1,880' assuming a 300 -foot thickness, radial flow, and 100% pore -space displacement around each of the two planned disposal wells. Injected fluids are expected to be compatible with the lithology and in-situ formation water of the proposed disposal injection zone based on operating experience and past performance of MPU Class I disposal wells B-24, B-34 and B-50 (e.g., pressures, rates, and volumes). No compatibility issues have been reported associated with disposal injection into the Ugnu at Milne Point or other fields on the North Slope. 9. Estimated Injection Pressures (20 AAC 25.252(c)(8)) Hilcorp estimates average surface injection pressure will range from 2,000 to 2,300 psig while injecting 27,000 barrels per day per well for two wells. Maximum surface injection pressure could reach 2,500 psig if sporadic plugging of perforations or fracture -flow channels occurs. Accordingly, Hilcorp requested 2,500 psig as maximum allowed surface injection pressure. Disposal Injection Order 42 October 24, 2018 Page 4 of 7 10. Mechanical Condition of Wells Penetrating the Disposal Zone Within a '/4 -Mile Radius of Kenai Loop #3 (20 AAC 25.252(c)(12)) Simpson Lagoon 32-14 is the only well to penetrate the proposed disposal injection zone within a'/4 -mile radius of the four proposed disposal wells. Well construction records show that this well is properly plugged and abandoned; however, there is no cement across the lower proposed Ugnu disposal zone or the underlying sands assigned to the Schrader Bluff Oil Pool (Schrader Bluff), and only partial cement across the upper Ugnu disposal zone. Hilcorp's application states the cement plugs in the production casing across the surface casing shoe will prevent upward fluid movement from the Ugnu disposal zone in this well. CONCLUSIONS: 1. The requirements of 20 AAC 25.252 for approval of an underground disposal application are met. 2. AEO No. 2 exempts the proposed Moose Pad disposal area for Class H injection activities only. 3. Hilcorp's plan to drill two disposal wells initially with another two wells as backup contingencies is a prudent approach for the MPU Moose Pad development. 4. Hilcorp's planned injection interval consists of poorly consolidated, porous and permeable Ugnu sands that lie from approximately 3,282' to 3,912' MD (-2,714' to -3,187' TVDSS), an interval that is about 473' thick with approximately 342' of net sand. 5. Upper confinement will be provided by a combined 90' of laterally continuous layers of mudstone, siltstone, and coal that lie within the Ugnu. 6. Lower confinement will be provided by laterally continuous layers of upper Ugnu mudstone, siltstone and coal that have a combined thickness of 40'. 7. No significant faults are present that could affect the proposed injection operations. 8. No compatibility issues have been reported associated with disposal injection into the Ugnu at Milne Point or other fields on the North Slope. 9. Fracture modeling indicates that disposed waste fluids will be contained within the receiving interval by confining lithologies, cement isolation of the well bore, and planned operating conditions. Modeling of rates up to 35,000 BPD per well predicts that fractures will not penetrate the upper confining zone or breach the lower confining zone. 10. Supplemental mechanical integrity demonstrations and regularly scheduled surveillance of injection operations—including baseline and subsequent temperature surveys, monitoring of injection performance (i.e., pressures and rates), and analyses of the data for indications of anomalous events—will ensure that waste fluids remain within the disposal interval and ensure appropriate operation of the field. 11. Increasing the distance between the packer and top of the disposal zone perforations will not compromise well integrity, so long as the top of production casing cement is at least 300' MD above the packer. Disposal Injection Order 42 October 24, 2018 Page 5 of 7 12. Hilcorp estimates a plume radius of about 1,880' for each disposal well over the 17 -year expected project life. 13. Future wells within 1/2 -mile of the proposed injection interval in each of the disposal wells must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 14. The proposed Ugnu disposal interval is not isolated by cement from the underlying Schrader Bluff in the Simpson Lagoon 32-14 well. No disposal well should be drilled within 3,000' of Simpson Lagoon 32-14 until Hilcorp demonstrates confinement and well integrity issues have been resolved. NOW, THEREFORE, IT IS ORDERED THAT the following rules, in addition to statewide requirements under AS 31.05 and 20 AAC 25 (to the extent not superseded by these rules), govern Class II disposal injection operations into the Ugnu within up to four wells drilled from MPU Moose Pad: RULE 1: Infection Strata for Disposal Underground disposal of Class II oil field waste fluids is permitted into the Ugnu Formation in the interval that is common to, and correlative with, the interval from 3,282' to 3,912' MD (-2,714' to -3,187' TVDSS) in well MPU M-01. RULE 2: Authorized Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production, workover, or abandonment operations, including: Drilling fluids; drill cuttings; well workover fluids; stimulation fluids and solids; produced water; rig wash water; formation materials; naturally occurring radioactive materials; scale; tracer materials; glycol dehydration; reserve pit fluids; chemicals used in the well or for production processing at the surface (in direct contact with produced fluids); and precipitation accumulating in drilling and production impoundment areas. The eligibility of other fluids for Class II waste disposal injection will be considered by the AOGCC on a case-by-case basis upon application by the operator. AOGCC approval is required prior to initiating commercial Class II disposal injection. RULE 3: Iniection Rate and Pressure Injection rates and pressures must be maintained such that the injected fluids will not initiate or propagate fractures through the confining intervals or migrate out of the approved injection stratum. Disposal injection is authorized at rates that do not exceed 35,000 BPD per well and wellhead injection pressures that do not exceed 2,500 psig. RULE 4: Demonstration of Mechanical Inteerity An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in the well, to be scheduled when injection conditions (temperature, pressure, Disposal Injection Order 42 October 24, 2018 Page 6 of 7 rate, etc.) have stabilized. Subsequent mechanical integrity tests must be performed at least once every two years after the date of the first AOGCC-witnessed test if the well injects solids laden slurries, and at least once every four years if the well only injects solids -free fluids. RULE 5: Well Inteerity Failure and Confinement The Operator shall immediately shut in the well if continued operation would be unsafe or threaten contamination of freshwater, or if so directed by the AOGCC. If fluids are found to be fracturing through a confining interval or migrating out of the approved injection stratum, the operator must immediately shut in the well. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Injection may not be restarted unless approved by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC if the well indicates any well integrity failure or lack of injection zone isolation. The AOGCC may immediately suspend, revoke, or modify this authorization if injected fluids fail to be confined to the approved disposal interval. No disposal well may be drilled within 3,000' of the Simpson Lagoon 32-14 until existing confinement and well integrity issues have been resolved for that well. To facilitate through -tubing access to the entire requested disposal zone, packers in the disposal wells may be located more than 200' MD above the top of the disposal zone; however, packers shall not be located above the confining zone. In cases where the packer distance is more than 200' above the disposal zone, the production casing cement volume should be sufficient to place cement a minimum of 300' MD above the planned packer depth. RULE 6: Surveillance The operator shall run a baseline temperature log and perform a baseline step -rate test prior to initial injection. A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids. Hilcorp shall perform an annual reservoir pressure survey of the disposal zone. Surface pressures and rates must be monitored continuously during injection for any indications of anomalous conditions. Results of daily wellhead pressure observations must be documented and available to the AOGCC upon request. The conduct of subsequent temperature surveys or other surveillance logging (e.g., water flow; acoustic) will be based on the results of the initial and follow-up temperature surveys and injection performance monitoring data. The annual report of underground injection (Form 10-413) shall also include data sufficient to characterize the disposal operation, including, among other information, the following: injection and annuli pressures (i.e., daily average, maximum, and minimum pressures); fluid volumes injected (i.e., in disposal and clean fluid sweeps); injection rates; an assessment of the fracture geometry; a description of any anomalous injection results; a calculated zone of influence for the injected fluids; and an assessment of the applicability of the disposal order findings, conclusions, and rules based on actual performance. The annual report shall also include a section titled "Induced Seismicity" in which Hilcorp shall detail its monitoring efforts and evaluate the risks. Disposal Injection Order 42 October 24, 2018 Page 7 of 7 RULE 7: Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 2 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification or other legal requirements of any other State or Federal agency remain the operator's responsibility. RULE 8: Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater or outside of the authorized injection zone. DONE at Anchorage, Alaska, and dated October 24, 2018. �ou,uvo //signature on file// //signature on file// //signature on file/1 = ;- Hollis S. French Daniel T. Seamount, Jr. Cathy P. Foerster Chair, Commissioner Commissioner Commissioner boN cu As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to nm is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Milne Point Field, Ugnu Undefined Oil Pool, MPU M-03 Hilcorp Alaska, LLC Permit to Drill Number: 218-140 Surface Location: 5040' FSL, 801' FEL, Sec. 14, TI 3N, R9E, UM Bottomhole Location: 572' FSL, 746' FEL, Sec. 14, TI 3N, R9E, UM Dear Mr. Myers: 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 vvvsw.aogcc.alaska.gov Enclosed is the approved application for the permit to drill the above referenced service well. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be nm. In addition to the well logging program proposed by Hilcorp Alaska, LLC in the attached application, the following well logs are also required for this well: - base of conductor to surface casing shoe, gamma ray and resistivity - surface casing shoe to TD; gamma ray, resistivity, and porosity Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Hollis S. French Chair +L DATED this 4 day of December, 2018. A STATE OF ALASKA AL. _,<A OIL AND GAS CONSERVATION COMMI_ -.ON PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp Q ' 1c. Specify if well is proposed for: Drill [D- Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑ Single Zone ❑Z Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket E - Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • MPU M-03 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 6,412' TVD: 3,901' MaePomt Unit` Ugnu Undefined 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 5040' FSL, 801 FEL, Sec 14, T13N, R9E, UM, AK ADL 025514 • C: S S T 8. DNR Approval Number: 13. Approximate Spud Date: Top of Productive Horizon: 2090' FSL, 755' FEL, Sec 14, T13N, R9E, UM, AK LONS 16-008 12/1/2018 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 572' FSL, 746' FEL, Sec 14, T13N, R9E, UM, AK 2560 3,190' to nearest unit boundary 41b. Location of Well (State Base Plane Coordinates - NAD 27):10. QOrr qN KB Elevation above MSL (ft): 58.7' 15. Distance to Nearest Well Open Surface: x-533363 • y- 6027889 • Zone?1 GL / BF Elevation above MSL (ft): 25' to Same Pool: 23,000' to MPJ -02 16. Deviated wells: Kickoff depth: 433 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 68 degrees Downhole: 1861 Surface: 1471 - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) 42" 20" 78.6# A53B Weld 107' Surface Surface 107' 107' 3270 ft3 4-1/2" 10-314" 45.5# L-80 TXP 2,800' Surface Surface 2,800' • 2,044' 2983 ft3 Stg1T-315 113 9-7/8" 7-5/8" 29.7# L-80 Hyd 563 6,412' Surface Surface 6,412' 3,901' 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No ❑✓ 20. Attachments: Property Plat Q BOP Sketch Drilling e v. Depth Plot B Shallow Hazard lents B Divertter Sketch Seabed 4 S Report Drilling Program E 20 AAC 25 050 requ em 21. Verbal Approval: Commission Representative: � rTTG Y x 'v Sry(K ouV 7—Date 17 -7 --IS) 22. 1 hereby certify that the foregoing is true and the pr dure approved herein will not be deviated from without prior written approval. Contact Name: Monty Myers Authorized Name: Monty Myers Contact Email: itriffiversCaft1corp.com Authorized Title: Drilling Manager Contact Phone: 777-8431 Authorized Signature '-' Date: rO • Z T _ i commission Use Only Permit to Drill / API Numbepr: 2 / Permit Approva See cover letter for other Number: .C—!� Li 50-(,G=.J tU Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed r9el6nneygas hydrates, or gas contained in shales: ,-v[-],•/ Other: ;(e- 3 Q� D L) 10 j� -S I Samples req'd: Yes [7 No L✓j Mud log req'd: Yes �Jo L,fv /. �i 1 +' p `5 1 i3, HzS measures: Yes i No [r� t(' Directional svy req'd: Yes wJ No ❑ t apo p5L /T� r - Spacing exception req'd: Yes ElL�Y No Inclination -only svy req'd: Yes�❑.JNo Ltp Post initial injection MIT req'd: Yes LI/ No ❑ PTO Ll 9 APPROVED BY I I by: i (y (� COMMISSIONER THE COMMISSION Date: 11-14 Submit Form and onn 10401 Revisers 512010 This permit is valid or o t r f approval per 20 AAC 25.005( )�tracnme sin Duplicate 3 [[A��f[ 0 0 �11C� 10/25/2018 Monty Myers Drilling Engineer Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7'h Avenue Anchorage, Alaska 99501 Re: MPU M-03 Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8431 Email mmyem@hilcorp.com Dear Commissioner, MPU M-03 is a grassroots disposal well intended for produced water infection Wellbore is located on "Moose" pad. The directional plan is a slant well with the kick off point at 433' MD/TVD. Maximum hole angle is 68 degrees. Drilling operations are expected to commence approximately Dec 151, 2018. If you have any questions, please don't hesitate to contact myself at 777-8431 or Paul Mazzolini at 777-8369. Sincerely, Monty — Drilling Engineer Hilcorp Alaska, LLC Page i of 1 HILCORP ALASKA LLC MILNE POINT FIELD AOR Map � iS0 1500 FEET w LL SWBOLS r os+ PaR(kl J], SWD REMA KS W YI SymM4 e1 Tap o104ryu1 Zm. .v.i oivv°o.0 :oa. m mai pAv'o°.°.e. 32-14A 32-14 I M-OP05 1 IA � M-01 Ll M -01A Hilcorp Alaska, LLC Milne Point Unit (MPU) M-03 Disposal Well Drilling Program Version 1 Nov 29", 2018 n Hilm&Aar comp.�y Contents Milne Point Drilling Procedure 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 Casing Inspection.......................................................................................................................4 6.0 Internal Reporting Requirements.............................................................................................5 7.0 Planned Wellbore Schematic.....................................................................................................6 8.0 Drilling / Completion Summary................................................................................................7 9.0 Mandatory Regulatory Compliance / Notifications..................................................................8 10.0 R/U and Preparatory Work.....................................................................................................10 11.0 N/U 21-1/4" 2M Diverter System.............................................................................................11 12.0 Drill 13-1/2" Hole Section........................................................................................................12 13.0 Run 10-3/4" Surface Casing....................................................................................................15 14.0 Cement 10-3/4" Surface Casing...............................................................................................18 15.0 BOP N/U and Test.................................................................................................................... 21 16.0 Drill 9-7/8" Hole Section..........................................................................................................22 17.0 Run 7-5/8" Intermediate Casing.............................................................................................. 25 18.0 Cement 7-5/8" Casing..............................................................................................................28 19.0 Wellbore Clean Up & Displacement.......................................................................................31 20.0 Completion Operations............................................................................................................32 21.0 Well Perforation: ..................................................................................................................... 32 22.0 Diverter Schematic..................................................................................................................33 23.0 BOP Schematic........................................................................................................................34 24.0 Wellhead Schematic.................................................................................................................35 25.0 Days Vs Depth..........................................................................................................................36 26.0 Formation Tops & Information...............................................................................................37 27.0 Anticipated Drilling Hazards..................................................................................................38 28.0 Doyon 14 Rig Layout...............................................................................................................41 29.0 FIT Procedure..........................................................................................................................42 30.0 Choke Manifold Schematic......................................................................................................43 31.0 Casing Design Information......................................................................................................44 32.0 9-7/8" Hole Section MASP.......................................................................................................45 33.0 Spider Plot (NAD 27) (Governmental Sections)......................................................................47 34.0 Surface Plat (As Built) (NAD 27).............................................................................................48 35.0 Directional Plan (wp 05)..........................................................................................................49 1.0 Well Summary Milne Point Unit M-03 Drilling Procedure Well MPU M-03 Pad Milne Point "M" Pad Planned Completion Type 5-1/2" Injection Tubing Target Reservoir(s) Ugnu Planned Well TD, MD / TVD 6,412' MD / 3,902' TVD PBTD, MD / TVD 6,300' MD / 3,806' TVD Surface Location (Governmental) 5,040' FSL, 801' FEL Sec 14, TI 3N, R9E, UM, AK Surface Location (NAD 27 — Zone 4) X=533,363.9 Y=6,027,889.71 Top of Productive Horizon (Governmental) 2090' FSL, 755' FEL, Sec 14, T13N, R9E, UM, AK TPH Location (NAD 27) X=533,424.69, Y=6,024,939.74 BHL Governmental 572' FSL, 746' FEL, Sec 14, TON, R9E, UM, AK BHL (NAD 27) X=533,441.96, Y=6,023,422.23 AFE Number 1813836 AFE Drilling Days AFE Completion Days AFE Drilling Amount AFE Completion Amount AFE Facility Amount Maximum Anticipated Pressure (Surface) 1471 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1861 psi KB Elevation above MSL: 33.7 ft + 25 ft = 58.7 ft GL Elevation above MSL: 25 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Version 0 November, 2018 H Hilcorp En. C=m Y 2.0 Management of Change Information Milne Point Unit M-03 Drilling Procedure Hilcorp Alaska, LLC xitoorp Changes to Approved Permit to Drill Date: October 17, 2018 Subject: Changes to Approved Permit to Drill for MPU M-03 File #: MPU M-03 Drilling Program Any modifications to MPU M-03 Drilling Program will be documented and approved below. Changes to an approved APD will 'be and approved by the AOGCC prior to continuing forward with work. Approval: Drilling Manager Date Prepared: Monty M Myers 10.172018 Drilling Engineer Date Page 3 Version 0 November, 2018 U Hilcorp ESC mpZr 3.0 Tubular Program: Milne Point Unit M-03 Drilling Procedure Hole Section OD (in) H) (in) Drift (in) Conn OD in Wt 0/111) Grade I Conn Burst i Collapse Tens' i Cond 20" 19.25" - 78.6 A-53 Weld 13-1/2" 10-3/4" 9.95" 9.794" 11.25" 1 45.5 L-80 TXP/SR 5,210 2,470 1,040 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 HYD 563t 6,890 4,790 683 4.0 Drill Pipe Information: 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 0 November, 2018 n Hilcorp Ems C.,—, Milne Point Unit M-03 Drilling Procedure 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to mmyersAhilcorp.com, pmazzolini(&hilcorp.com , ieneel(a,hilcorp.com and cdingerna hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager & Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final "As -Rud' Casing tally to mmversAhilcoro.com and cdinger cAhilcorp.com 6.6 Casing and Cement report • Send casing and cement report for each string of casing to mmvers(ahilcorn.com and cdinger(a),hilcorp. com 6.7 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 Lengel@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcori).com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kflemin¢@hilcormcom Safety Manager Chet Starkel 907.777.8344 406.544.7862 cstarkel@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdineer@hilcorp.com Page 5 Version 0 November, 2018 U Hilcorp Role. C .2 7.0 Planned Wellbore Schematic PROPOSED SCHEMATIC TREE & WELLHEAD D ssvrTmhg Milne Point Unit M-03 Drilling Procedure Milne 1'01111 Unit Well: MPU Moose 1'ad M U3 I ast (olnpleled: Plopose(i flit) lBD Tree I 51/8.5MTme W Grade/Conn 11"5M Wellhead x 5.1/2' TUI Top and Bottom Hanger with Wellhead 5-1/2" D W 9' BPV profile. Zea 3/8" NPT control lines Ipluggedl. OPEN HOLE /CEMENT DETAIL 42" 50 bbls(10 Yards Pllecrete dumped dmvn backside) 13-1/2" 19am 9-7/8" 507X3 CASING DETAIL Sixe Type W Grade/Conn Drift ID Top m BPF 20'x34' Contluctw(Imulated) 78.6/A-53/Weld N/A Surface 106.5' N/A 103/4" Surface 45.5/L -80/W SR 9975" Sudare I 2,800' 0.0961 7-5/8" Production 29.7/L-80/fl x4563 I 6.750" I Surface 1 61 0.0459 -Ta x M7 WELL INCLINATION DETAIL 3?D° NOP@433' Max Hole Angle = 68.04 deg.@2,189MO Max Hole Angle = 52.52 deg. @ Top Perf I[WCI OY r1CTall I No. Top MD Rem Drift lD 1 29' Tubing hanger (5-1/2'TC-11 Top& IBT-AIDD Btm 4.767- 2 4,317' 5-1/2'XNippk, 4.562 -Pa kingiswe 4.562' 3 4,403' 5-1/r TXP SRx 4-1/2" Vam Top XO 3.833" 4 4,409' 7-5/8' x 4-1/2' Hydraulic Permanent Packer LVAM Top 6 x P) 3.856" 5 4,452' 4-1/2'XN Nipple. A4711 D - 3.725'Nota,3.813-packing&ore 3.725' 6 4,484' 4-1/r Mule Shce Stm@4,485') 3.833" PERFORATION DETAIL Schrader Sands I Top (MID) &M (MD) TOP(TVD) MED(TVD) I FT I Date status U nu Deposal 5,300' 5,400' 3,074' 3,13Y 100 Prop Drop U u-TCP5-5132 Rawr RDX SBH 1LL0,16M(32.O8r, 1.Oa EH,6.7Pen uP��sens Tile TOC yvq 9ice@ 05500MD "far.p H* TD= 6p12' (MD) /TD=3,9(12'(TW) PBrD=6,327' (MD)/TD= 3A30'(TW) 0tv45l4i- 'LA GENERAL WELL INFO API: 50-029-23)0% Drilled and Cased by Doyon 14 - Future Page 6 Version 0 November, 2018 U Hilcorp Eni Company Milne Point Unit M•03 Drilling Procedure 8.0 Drilling / Completion Summary MPU M-03 is a grassroots disposal well intended for produced water injection. Wellbore is located on "Moose" pad. The directional plan is a slant well with the kick off point at 433' MD/TVD. Maximum hole angle is 68 degrees. Drilling operations are expected to commence approximately Dec 11, 2018. Surface casing will be run to 2,800' MD / 2,044' TVD and cemented to surface via a single stage primary cement job. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 —18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. There are no wells located within a % mile of the M-03 directional plan. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I, facility located on "B" pad. General sequence of operations: 1. MOB Doyon 14 to well site 2. N/U 21-1/4" conductor and 16" diverter line. 3. Drill 13-1/2" hole to TD of surface hole section. Run and cmt 10-3/4" surface casing. 4. N/D diverter, N/U & test 13-5/8" x 5M BOP. 5. Drill 9-7/8" hole to TD. 6. Run and cmt 7-5/8" production casing. Conduct CBL. 7. Run injection tubing. 8. N/D BOP, N/U temp abandonment cap, RDMO. 9. Perforate well. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: Mud logging. On site geologist. LWD: Triple Combo+GR + Res 3. Cased Hole Logs: CBL on production string. Page 7 Version 0 November, 2018 H Hilcorp evmgy cawp®y Milne Point Unit M•03 Drilling Procedure 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-03. Ensure to provide AOGCC 24 his notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 515 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Version 0 November, 2018 U Hikorp Milne Point Unit M-03 Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 13-1/2" • 21.1/4" 2M diverter (Hydril MSP) w/ 16" diverter line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/3000 o Blind ram in bum cavity (Annular 2500 psi) • Mud cross w/ 3" x 5M side outlets 9-7/8" 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. • Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. • The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: iim.regg(a)alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartzna alaska.eov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp(ctbalaska.eov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixseRalaska.gov Primary Contact for Opportunity to witness: AOGCC.InsnectorsOa alaska.gov Test/Inspection notification standardization format: htti3:Hdoa.alaska. ov/oQc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 0 November, 2018 U Hilcorp a��Wy 10.0 R/U and Preparatory Work 10.1 Install and cement insulated 20" x 34" conductor. 10.2 Dig out and set impermeable cellar inside existing culvert. Milne Point Unit M•03 Drilling Procedure 10.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.4 Install slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 10.5 Insure (2) 3" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack -off. 10.6 Level pad and ensure enough room for layout of rig footprint and R/U. 10.7 MIRU Doyon #14. 10.8 Mud loggers WILL NOT be used on M-03. 10.9 Mix spud mud for 13-1/2" surface hole section. Keep mud cool. 10.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.11 Install 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 10 Version 0 November, 2018 H Hilcotp enmgy compmy 11.0 NIU 21-1/4" 2M Diverter System Milne Point Unit M-03 Drilling Procedure 11.1 NIU 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic at Sec 20 at back of program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • NIU 21-1/4" diverter "T • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 11.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 11.4 Set 15.375" ID wear bushing in wellhead. 11.5 Rig & Diverter Orientation: Page 11 Version 0 November, 2018 U Hilcorp E� CMP®y 12.0 Drill 13-1/2" Hole Section Milne Point Unit M-03 Drilling Procedure 12.1 PIU 13-1/2" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135 NC -50 • Run a solid float in the surface hole section. 12.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.3 Drill 13-1/2" hole section to section TD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. We want to be approx. 200' through the base of the permafrost. Permafrost base is estimated at 2,246' TMD (1,850' TVD) • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 450-600 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • Take MWD surveys every stand drilled (95' intervals). • Be prepared for GAS HYDRATES at the base of the permafrost. However none were encountered on L -Pad • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding mud products such as Lecithin to allow the gas to break out. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. Page 12 Version 0 November, 2018 d H Hilcorp Milne Point Unit M-03 Drilling Procedure • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is > 4. • Do not slide for 100' MD above the base of the permafrost or 100' below the base. We want to leave this transition as undisturbed as possible. 12.4 13-1/2" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office. • Hydrates: Hydrates have not been encountered on "L" or "M" pad but be prepared and don't stop to circulate out gas. Control drill when hydrates encountered. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X -GIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud Pro erfies• Section Density I viscosity Plastic Viscosity Yield Point API FL Tem H Surface 1 8.8-9.5 1 75-175 1 20-40 1 25-45 1 510 1 <70°F 1 8.5-9.0 Page 13 Version 0 November, 2018 K Hilcorp Milne Point Unit M-03 Drilling Procedure System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg PAC -L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb 12.5 At TD; pump sweeps, CBU, and pull a wiper trip back to the 20" conductor shoe. 12.6 If hole conditions will not allow the BHA to be pulled out on elevators, prior to initiating backreaming, try to orient motor to high side and attempt to pump out to avoid damaging the wellbore. 12.7 Should backreaming be absolutely necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 — 4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (450 — 550 gpm), and maximize rotation. • Pull slowly, 5 —10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.8 TOH with the drilling assy, handle BHA as appropriate. 12.9 No open hole logging program planned. Page 14 Version 0 November, 2018 s/ H Hil ,MIT Ev 13.0 Run 10-3/4" Surface Casing 13.1 R/U and pull 15.375" wear bushing. 13.2 Make a dummy run with the 10-3/4" casing hanger. Milne Point Unit M-03 Drilling Procedure 13.3 R/U Weatherford 10-3/4" casing running equipment. • Ensure 10-3/4" TXP x NC -50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 13.4 P/U shoe joint, visually verify no debris inside joint. 13.5 Continue M/U & thread locking shoe track assy consisting of • (1) Shoe joint w/ float shoe bucked on (thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end & thread locked. Install (1) centralizer mid tube over a stop collar. Ensure proper operation of float equipment while picking up. Ensure to record S/N's of all float equipment and stage tool components. 13.6 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Install (1) centralizer across couplings on each joint. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cmt returns to surface. 10-3/4" 45.5# L-80 TXP Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 10-3/4" 1 20,370 ft -lbs 24,890 ft -lbs Page 15 Version 0 November, 2018 U UICI p Milne Point Unit M-03 Drilling Procedure 13.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.8 Slow in and out of slips. 13.9 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already WU. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 13.10 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 13.11 Have emergency slips ready to go in the event we cannot land the hanger. 13.12 R/U circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold WU water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 13.13 After circulating, lower string and land hanger in wellhead again. Page 16 Version 0 November, 2018 H Hilcorp Milne Point Unit M-03 Drilling Procedure For the latest performance data, always visit our website: www tenaris,com TXPO BTC ...,.<_ tDn7rzota 0011dp Diameter 10.TA In two. Wall 87.5`, 10 750.11 Nominal Wepn'. Nm'mal ID 9 cora Thickne3s Got anrraa.O Pl Gred0 LBO o0 PERFORMANCE 10443.000.10(0 mmrnAP,--C..rft eod)YeN Slmrgln 7". t lraar"IY'pb _ Wall Thickness 0,400 k, Connection OD REGULAR Ea GEOMETRY op110n carnal.— Ed COYKMf. p!E WY MMerrV Ina, 409tH Inrr•ana ter rn PERFORMANCE E' J, Red ISI Salo Red GnOe LBO TyM t' YM Orlll AN Standard tel Banc Brecon Ina Bard ErMnW PNennar Capwr, 1470.000 pa, L MAKE-UP TORQUES mdeard - ern.a Mrnmaas 20,7054ae Ty" Casing 3rd Gar 3rdBand.- 37700 Blas YkN Tagaa 1n Dand Page 17 PIP, HOD, DAlf cEOMETRr - - - NwncnlOD 10 750.11 Nominal Wepn'. Nm'mal ID 9 cora Wnll Tlucknea9 Got anrraa.O PPI PERFORMANCE 10443.000.10(0 mmrnAP,--C..rft eod)YeN Slmrgln IOW eI W01Es lraar"IY'pb _ Gullnf"e 2470 ,1, Mer.. A9mveMo Gra -119 CONNFCTION DATA Ea GEOMETRY carnal.— Ed 11.750 rn Cm,MnO t"h MMerrV Ina, 409tH Inrr•ana ter rn PERFORMANCE Tonuon Eircaen, 10.0% JOnM Ywk 5Ver , Ct,aa. Eff p to •n cerryrulsgn S4urglk ErMnW PNennar Capwr, 1470.000 pa, L MAKE-UP TORQUES _ Mrnmaas 20,7054ae Opumum OPERATION LIMIT TORQUES Openly, Toraw 37700 Blas YkN Tagaa Notes This connection Is fully Interchangeable with 5910,. says 00000 ps1 45.5 "11 0A00n - ----- Dn Man End WegN - r 9]94 11 14.}6!10 5 5910,. says 00000 ps1 n69011ba masirn;m 9W901', 165 154000J01 TXP® OTC - 10.75 in. - 40.5151 los/0 Iti Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as Per section 10.3 API 5C3 I ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sales representative. For further Information on concepts indicated In this datasheret. download the Dalasheel Manual from www.tenads.com tanem n..—rd rrv. aa:.,•.yd 4 x,11,ti .mw.n rcry. w un nwmawnn a. aen•nwx naky.ro ,..Irani k'rudca. -, xeari. m,«rm da.yn fkYam wnT rc•I nlendM loo'neelum pdemovin arymMrlkindeM[enrovimrivrimm�n xNnppgry an .—Na—a'— Tervle N.mNnaarardnnN widw rry nkamxo,lw•Y'We NWbwu.crn[omauun um.uMtM q/N.o or. no W—aacrt n.�rodarµrgy. Tn aY.d Yc F1wmq-n I.uusorewe an. ienrvu M. m1 msuremY reaYn.•Mry aNGaY d ercI W 1u nY Es. danss6e rv.yW nsnkuq M1wn. a nanlri.repi wm snY Ebmnrim [ava+w0 rrsryr Version 0 November, 2018 10.835 n Cnrxirc,.m IO 9.938111 5 Caorrm:nrr OU 0lmnr, REGULAR 10443.000.10(0 mmrnAP,--C..rft 5210.000 pili An 1040.000 a IM Mer.. A9mveMo Gra -119 84'1101)0 Ea n69011ba masirn;m 9W901', 165 154000J01 TXP® OTC - 10.75 in. - 40.5151 los/0 Iti Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as Per section 10.3 API 5C3 I ISO 10400 - 2007. Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local Tenaris technical sales representative. For further Information on concepts indicated In this datasheret. download the Dalasheel Manual from www.tenads.com tanem n..—rd rrv. aa:.,•.yd 4 x,11,ti .mw.n rcry. w un nwmawnn a. aen•nwx naky.ro ,..Irani k'rudca. -, xeari. m,«rm da.yn fkYam wnT rc•I nlendM loo'neelum pdemovin arymMrlkindeM[enrovimrivrimm�n xNnppgry an .—Na—a'— Tervle N.mNnaarardnnN widw rry nkamxo,lw•Y'We NWbwu.crn[omauun um.uMtM q/N.o or. no W—aacrt n.�rodarµrgy. Tn aY.d Yc F1wmq-n I.uusorewe an. ienrvu M. m1 msuremY reaYn.•Mry aNGaY d ercI W 1u nY Es. danss6e rv.yW nsnkuq M1wn. a nanlri.repi wm snY Ebmnrim [ava+w0 rrsryr Version 0 November, 2018 U Hilcorp r � C��Y Milne Point Unit M-03 Drilling Procedure 14.0 Cement 10-3/4" Surface Casing 14.1 Hold a pre -job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the curt pump or treating iron will not be pumped downhole. 14.4 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug. Mix and pump cmt per below calculations. 14.8 Cement volume based on annular volume + 100% open hole excess for lead cement. Job will be pumped in a single stage, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) Lead Cement: Conductor x 10-3/4" casing: 113 x 0.24 bpf = 28 bbls 157113 13-1/2" OH x 10-3/4" casing: (2300'- 113') x 0.06478 bpf x 2 = 284 bbls 1595113 Tail Cement: r ? sz- 13-1/2" OH x 10-3/4" casing: 500' x 0.06478 bpf= 33 bbls 185 ft3 10-3/4" Shoe track: 90 x .09617 bpf = 9 bbls 5113` Total: 354 bbls 1988 ft3 Page 18 Version 0 November, 2018 n Hilcorp Milne Point Unit M-03 Drilling Procedure Cement Slurry Design: 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. 14.11 Ensure rig pump is used to displace cmt. Displacement calcs have proven to be very accurate using 0.101 bps for pump output. 14.12 Displacement calculation: 2710' x .09617 bpf= 261 bbls total 1iil 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 3 bbls before consulting with drilling engineer. 14.15 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. 14.16 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 19 Version 0 November, 2018 Lead Slurry Tail Slurry System Permafrost L SwiftCEM Tm System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. 14.11 Ensure rig pump is used to displace cmt. Displacement calcs have proven to be very accurate using 0.101 bps for pump output. 14.12 Displacement calculation: 2710' x .09617 bpf= 261 bbls total 1iil 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 3 bbls before consulting with drilling engineer. 14.15 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. 14.16 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 19 Version 0 November, 2018 H Hilcotp E.V �9" Milne Point Unit M-03 Drilling Procedure 14.17 Flush out BOP, and clean out above hanger. Remove landing joint. 14.18 M/U pack -off running tool and pack -off to bottom of Landing joint. Set casing hanger packoff Run in lock downs and inject plastic packing element. 14.19 Lay down landing joint and pack -off running tool. Ensure to report the following on WellEz. • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Page 20 Version 0 November, 2018 H Hilcorp Emery C pmy 15.0 BOP N/U and Test 15.1 N/D the diverter & N/U 1 I" 5M tubing spool. 15.2 N/U 13-5/8" x 5M BOP as follows: Milne Point Unit M-03 Drilling Procedure • BOP configuration from Top down: 13-5/8" x 5M annular / 13-5/8" x 5M Double gate / 13- 5/8" x 5M mud cross / 13-5/8" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should also be dressed with 2-7/8" x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 15.3 Run 5" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave `B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes: 5" for DP workstring 5-1/2" for liner and injection tubing. 15.4 R/D BOP test assy. 15.5 Keep spud mud in pits for intermediate hole section. 15.6 Set 10" ID wearbushing in wellhead. 15.7 Rack back 5" DP in derrick. 15.8 Keep 6" liners in mud pumps. Page 21 Version 0 November, 2018 U HIICOl'p 16.0 Drill 9-7/8" Hole Section 16.1 P/U 9-7/8" directional BHA. Milne Point Unit M-03 Drilling Procedure • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Install ported float in the BHA. 16.2 9-7/8" hole section mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. • 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. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • 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: 8.8 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud PrnnerfiPe* , De ihs Densi Plastic Viscos Yleld Point LGS MBT HPHT H ntennediate 8.8-9.5 ppg 15-25 15-20 <6% 1 <20 1 <1 1.0 1 9-10 Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg PAC -L /DEXTRID LT if required for <I0 FL ALDACIDE G 0.1 ppb Page 22 Version 0 November, 2018 K Hilcor rp �� 16.3 TIH w/ 9-7/8" directional assy. 16.4 Note depth TOC tagged on AM report. Milne Point Unit M-03 Drilling Procedure 16.5 R/U and test casing to 2600 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 5210 / 2 = —2605 psi. Test pressure for the well is 2600 psi. 16.6 Drill out shoe track and 20' of new formation. 16.7 CBU and condition mud for FIT. 16.8 Conduct FIT to 12.5 ppg EMW. 16.9 Drill 9-7/8" hole section to section TD per Geologist and Drilling Engineer. • Pump at 450-550 gpm. • 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. • Pump high viscosity sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. 16.10 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the casing shoe. If backreaming is necessary: • Circulate at full drill rate (450 — 550 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 —10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 16.11 TOH with the drilling assy, L/D or handle BHA as appropriate. 16.12 No open hole wire line logs are planned. 16.13 The Schrader Bluff will be plugged back prior to running casing Page 23 Version 0 November, 2018 Milne Point Drilling Procedure H i1C0� 4 16.14 Pick up a cement stinger and 600' of 3-1/2" tubing (Hilcorp requests approval to not test BOP'S on 3-1/2" tubing due to the length of the cement stinger being 601') ACL rJ J•� / 16.15 Crossover to 5" DP PF' 16.16 RIH to 6400' and establish circulation. 0 16.17 Mix and pump 48 bbls of 15.8ppg Class G Neat cement and spot as a balanced plug from 6400' ( to 59001. SD 1 (I a 16.18 Displace DP and tubing with a nerf ball and leaving 3 bbls of cement inside pipe for balanced plug. 16.19 POOH to 5900' and circulate 2X bottoms up. V 16.20 Mix and pump 48 bbls of 15.8ppg Class G Neat cement and spot as a balanced plug from 5900' to 5400'. <Do 16.21 Displace DP and tubing with a nerf ball, leaving 3 bbls of cement inside pipe for balanced plug. 16.22 POOH slowly to 5200' and circulate 2X bottoms up and high rate. 16.23 POOH and lay down tubing and cement stinger. L 16.24 PU 9-7/8" clean out assembly and RIH to 5200' and circulate. Ab 16.25 Wash down to 5500' looking for hard cement.k4 a ice/ 16.26 POOH and lay down clean out assembly Page 24 Version 0 November, 2018 H Hilcorp Ene Cmnpnny 17.0 Run 7-5/8" Intermediate Casing Milne Point Unit M-03 Drilling Procedure 17.1 Pull wear bushing. Install and test 7-5/8" casing rams in upper ram cavity to (250/3000 psi). 17.2 R/U 7-5/8" casing running equipment. • Ensure 7-5/8" HYD563 X NC50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. W • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • R/U CRT if available. 17.3 M/U & threadlock shoe track assy consisting of: • (1) Float shoe joint w/ float shoe bucked on. Install (1) solid body centralizer free floating on joint. • (1) Baker locked joint. Install (1) solid body centralizer leave free floating. • (1) Float collar joint w/ float collar bucked on pin end. Install (1) free floating solid body centralizer. • Ensure proper operation of float shoe and float collar. 17.4 Run 7-5/8" 29.7# L-80 HYD563 casing. • Fill casing while running using CRT or fill up line. • Use "BOL 2000" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers on every joint to 2800' MD. No centralizers required above that. 17.5 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 17.6 Slow in and out of slips. 17.7 PU casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. The 7-5/8" casing packoff with the running tool will also be staged on the rig floor. 17.8 Lower string and land out in wellhead. Confirm measurements to indicate the hanger has correctly landed out in the wellhead profile. 17.9 Have emergency slips ready to go in the event we cannot land the hanger. Page 25 Version 0 November, 2018 H Hilcorp Milne Point Unit M-03 Drilling Procedure 17.10 R/U circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 17.11 After circulating, lower string and land hanger in wellhead again. 7-5/8" HYD 563 Estimated M/U torques Casing OD Torque (Min) Torque (Max) Torque (Yield) 7-5/8" 1 8,600 ft -lbs 15,100 ft -lbs 45,000 ft -lbs Page 26 Version 0 November, 2018 H HilmEnergy CmepAd For the latest performance data, always visit our website: www.lenaris.com Wedge 5630 Milne Point Unit M-03 Drilling Procedure r. 7Ur1912016 Oabrtla DIam0ler T.6251n Min. Wall foss' Thickness (-1 GnUe LM TYM 1 Wall Thickness 0.3751x. Connection OD REGULAR option COWLYIG 1T8BeeY RMy Red In Rand Red Grade LBO Typo 1' Drill API Standard to aanc Brown 2nd Band 2nd Rana Brown Type DasinB 3id BaM . 3rd Rn:M. 41, Band - PIPE BODY DA IA _ GEOMETRY. Non - MOD 7.035n Nn:nnsl Wegh; H.701haT DO 6.75k1 Nenerai ID 6.875h Wall Thickness 0.375,n Ran End We.O1I ALOI lbxfl OD Toki All PERFORMANCE Reay nea sinn"n 6433, 10(o Aha IMemal wild M90W SMYS 90000 nal rA6nlne 4790rei CDNNFC I ION DATA GEOMETRY cenwalm o0 9.500 in ConDing L.Irl 9.25,n. corn tvn 10 9.975 n A1Aea:P 1. oss Also. IMeaar ynn 3.29 Come[". oD o'so, REGULAR PERFORMANCE Toren l:Rinmry Ine% J'l Ywld strew 693000 x100) Imwrwl Raewoo capeoh "sawpo K 2s compca,, nEMucncy 1OCLO% connossan Sner th 083.000 al 000 Max. A9owadc Bence, 40'11006 an, EalernA Pmssore "a cny 1790.000 Dn G ,Ibhe F. Lead 955010 kn MAKEd1P TORQUES - - kWrrn.:m 960011ts oks. Naaon4hs Vanimem Machine OPERATKJ I LIMIT TORQUES orw.1" T«Roe 38000 n -Rs Yya Tong. 45000 lrPo. - - ---- BIJCK-ON Muwnam 146M k -Ila Mairmot law nms Notes This connection is fully interchangeable with'. Wedge 5530 - 7,625 in. - 29.7 Ibsi t Wedge 51- 7.625 in. - 26.4 / 33.7 lbs/ft Gonnettions with Dnpelsss*J Technology are fully compatible with the same connection in its Standard version For further information on concepts indicated in this datashect, download the Datasheet Manual from www.tenans.com Page 27 Version 0 November, 2018 K Hilcorp 18.0 Cement 7-5/8" Casing Milne Point Unit M-03 Drilling Procedure 18.1 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. • How to handle cement returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cement operation. • Extra hands in the pits to strap during the cement Job to identify any losses • Document efficiency of all possible displacement pumps prior to cement job. 18.2 Cement job will be a single stage, single slurry job. 18.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the curt pump or treating iron will not be pumped downhole. 18.4 R/U cement head (if not already done so). Ensure top and bottom plugs are loaded correctly. 18.5 Pump 5 bbls 10.5 ppg spacer. Close low torque on plug dropping head, test surface cement lines to 4000 psi. 18.6 Pump remaining 40 bbls 10.5 ppg spacer. 18.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1 st stage, confirm actual cement volumes with cementer after TD is reached. 18.8 Cement volume based on annular volume + 50% open hole excess. Section: Calculation: Vol lVol (ft3) 9.875" OH x 7-5/8" (5,500'— 4,000') x 0.03825 bpf x 1.5 = 86 484 Casing: 7-5/8" Shoe Track: 80' x .04591 bpf = 4 23 Total Volume: 90 507 g-315IRL Page 28 Version 0 November, 2018 H Hilcorp Eta C m�> Milne Point Unit M-03 Drilling Procedure Cement Slurry Design: 18.9 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good b seline measurement for pump displacement ahead of time. Displacement calcs: • 5,420' x .04591 bpf = 249 bbls. 18.10 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. 18.11 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —2 bbls before consulting with drilling engineer. 18.12 If the plug is not bumped, consult the drilling engineer. 18.13 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. 18.14 Flush out wellhead with FW and BOP stack thoroughly to ensure cement, mud and cuttings are removed. 18.15 M/U pack -off rumting tool and pack -off to bottom of Landing joint. Set casing slips packoff. Run in lock downs and inject plastic packing element. Pressure test t/ 2450 psi. 18.16 Lay down landing joint and pack -off running tool. 18.17 R/D cementing equipment. Flush out wellhead with FW. 18.18 Test void to 250/4000 psi for 10 min. 18.19 Freeze protect 9-5/8" x 7" Annulus Page 29 Version 0 November, 2018 Cement Slurry System ExpandaCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 4.972 gal/sk 18.9 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good b seline measurement for pump displacement ahead of time. Displacement calcs: • 5,420' x .04591 bpf = 249 bbls. 18.10 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. 18.11 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —2 bbls before consulting with drilling engineer. 18.12 If the plug is not bumped, consult the drilling engineer. 18.13 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. 18.14 Flush out wellhead with FW and BOP stack thoroughly to ensure cement, mud and cuttings are removed. 18.15 M/U pack -off rumting tool and pack -off to bottom of Landing joint. Set casing slips packoff. Run in lock downs and inject plastic packing element. Pressure test t/ 2450 psi. 18.16 Lay down landing joint and pack -off running tool. 18.17 R/D cementing equipment. Flush out wellhead with FW. 18.18 Test void to 250/4000 psi for 10 min. 18.19 Freeze protect 9-5/8" x 7" Annulus Page 29 Version 0 November, 2018 H Hilcorp E��Prm Milne Point Unit M-03 Drilling Procedure Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Page 30 Version 0 November, 2018 19.0 Wellbore Clean Up & Displacement Milne Point Unit M-03 Drilling Procedure 19.1 M/U casing clean out assy complete with 7-5/8" casing scraper assys. • 6.75" bit or mill. • Casing scraper for 7-5/8" 29.7# casing. • +/- 500' 5" DP. • Casing scraper for 7-5/8" 29.7# casing. • 5" DP to surface. 19.2 TIH & clean out well to Float Collar (+/- 5,420' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. 0-p 30 19.3 After wellbore has been cleaned out satisfactorily using mud, test casing to3 psi// 30 min. 19.4 Displace drilling fluid in wellbore with a hi -vis pill followed by fresh water. JM1 • Consider catching drilling fluid in rain -for -rent tanks for use on a future well if feasible. • Circulate fresh water into wellbore until clean-up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the 7-5/8" scraper to surface. • Pump a chemical train followed by clean water. 19.5 TOH w/ clean out assy. LDDP on the trip out. Note any abnormal wear on the clean out assy. Page 31 Version 0 November, 2018 Milne Point Unit M-03 Drilling Procedure Hilcorp COmP�Y 20.0 Completion Operations 20.1 R/U a -line unit and run a CBL across the 7-5/8" liner. R/D a -line unit. 20.2 R/U and run 4-1/2" x 5-1/2" tubing assembly, including nipple profile, production packer and WLEG. • Ensure appropriate well control crossovers on rig floor and ready. 20.3 Makeup the tubing hanger and landing joint. 20.4 Land hanger. RILDs and test hanger (500/5000 psi). Make note of actual weight on hanger on morning rpt. 20.5 Freeze protect IA and Tubing. 20.6 Drop ball and rod and set packer 20.7 Test the tubing to 3500 psi for 30 minutes. Monitor tubing to identify any packer leaks. Record and note all pressure tests on chart. AA ( r' TA `ot 56(0 20.8 Install BPV 20.9 ND BOPE ,, ,{ ), � i -C, 20.10 NU Tree & Pressure test to 5000 psi. /v 20.11 RDMO Doyon 14 21.0 Well Perforation: 21.1 A separate sundry will be submitted for perforating the well 7�— AO�cc Page 32 Version 0 November, 2018 H Hilcorp 22.0 Diverter Schematic Milne Point Unit M-03 Drilling Procedure —16" Full Opening Knife Valve Page 34 Version 0 October, 2018 `16- Diverter Line Milne Point Unit M-03 Drilling Procedure Hilcorp Encs c2,7 23.0 BOP Schematic Kill Line Hydril GK Annular BOP 13-5/8"x 5M J U 13-5/8" x 5M U L ❑❑ vOe ❑❑ ❑❑ (o ❑❑ 9-5/8" DBL IPS Casing Hanger S-22 16-314" NOM 13-5/8"x 9-5/8" 13-5/8"x 5M �3" x 5M HCR Choke Line x 5M Manual Gate Valve 11" x 5M 1116" x 5M 6"x 5M 13-5/8"x 5M `2-1/16" x 5M -20" Casing 9-518" Casing Page 35 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure Hilc T Energy C"mpe"y 24.0 Wellhead Schematic CUSTOMER PROVIDED 7" TREE FROM OTHER VENDOR PER MARK K. A 7-1116' 5K (5-1/8 BORE) 11'5K CW4--r{I 1 171_ FLI_-fAON% I I- WS STAMDMO SYSTEM F2F 11'5K 20" CONDUCTOR 10-314' CASING 7-5/8" CASING 5.112' TUBING 2-1116'5K 2-1116" 5K M K K ASKED OS TO CraNGE TO PSE NEW SLIP CONFIGURATION Page 36 Version 0 October, 2018 R Hilcorp 25.0 Days Vs Depth 0 1000 2000 3000 C 5000 6000 7000 8000 0 2 4 Milne Point Unit M-03 Drilling Procedure MPU M-03 Disposal Days vs Depth 6 8 10 12 Days Page 37 Version 0 October, 2018 14 16 n MIC 22 Paepq Company 26.0 Formation Tops & Information Milne Point Unit M-03 Drilling Procedure MPU M-03 Formations (wp05) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2246 1771 1830 805.2 8.46 SVl 2259 1779 1837 808.28 8.46 Ugnu Coal 4538 2635 2694 1185.36 8.46 LA3 5203 2956 3015 1326.6 8.46 LD 5416 3086 3145 1383.8 8.46 Schrader Bluff OA 6130 1 3606 1 3665 1612.6 8.46 L -Pad Data Sheet Formation Description (Closest & Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORECAST _— COMMENTS SS GEOLOGICAL TVD FM LITH DESCRIPTION urs NOTE: Sea ind idwl Wall Program for specific casing dealgn, dop hs. Starts. +m 600 walgllfa, Prada. and co.octions. o UnconsolidNad terse b mMiumaand AM .11 gravel 5 Wn Mlna alaaf.e. IF SIGNIFICANT AMOUNTS OF GRAVEL 1,000' ARE ENCOUNTERED WHEN DRILLING THE --10le SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. 1750' Base permafrost atkfbeds of saMrh . cbyrt am Nit.loa Mth occasional 1.000' maw of c.l. watch paalbb a1dafrack4p aNb waaNnglnamin4 Las a L -I s, Sagav rkta filljon, No hydrates encountered on L -Pad wells drilled to date. coalnwd iMwbam of uM, cbya -ads h wart weh a.bal .h. at coal. Latae of Pyrim at N 5100 fl 3,000' hwnal at an]aet h.n no shaky and light(Leri. Clay hWM. s baawen 5000ard AWdit. C }tri'. A SssY aaaaa UGNU:Sade. or coananhq up,.1d... ch ahkhaM 181" nude„of: Iaoof" to bamn) coart..ar4 fins sand. eed.r ayswpad loaMsnlnq sNla. as you aoroisInto UGNU pro,e.a lMotale LaMNldaPark and t Possible rydr'.-. llml+.tl Ughwn6 ,.rna, fMik.adar W SW camor of Mil<w dawlopanl NMlvm ares is r WS f,rel dwnslnr.twe era xal. •5750' ra.sns bab.tl X00° Schrader Bluff Sands: 000' lanc.o. coNiMed 4MdnpcarsanbgupweMaandsa eb.. .1♦ Schrader Bluff: PosslbIa lost circulation L.n as at mon condensed eM win...lanw Sal. zona while drilling long strings and running •41re ossna Say doh qub 1,11.14000 fo 4600 ft lhr and Schadar Bluff: Paa"e hydrocarbons llna+aa rasing. Recemmend deep setting surface ION S kswcomesorNw, aawroPn,.ne LJraMLi.,. casing for Kuparuk long strings. Also, the ..,bled in n. SLincbn Skin tend. ddnlwm,M, d Schrader Bluff sands are a potential Schrader L -Par la dewnalnwhaa and ant differential stuck pipe interval if len un -cased Bluff C surras casbq point at sale aloes for Kuparuk long strings. Sands:1 Smniar Bluff oft "M ler long. Mach walk. Page 38 Version 0 October, 2018 _ f� N Hilcorp 26.0 Anticipated Drilling Hazards Surface Hole Section: Lost Circulation Milne Point Unit M-03 Drilling Procedure Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section efficiently — control ROP and avoid loading the hole with gas. Minimize gas belching by reducing flow rate if necessary. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 —2.0 ppb DRILTREAT 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 adjacent wells in the vicinity. Take directional surveys every stand, take 2 additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any CrY✓� close approaches on AM report. Discuss offset wellbores with production foreman and consider r shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 38t t�.(8 Version 0 October, 2018 r B Hilcorp Milne Point Unit M-03 Drilling Procedure 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Intermediate & Production Hole Sections: 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> 500 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 are no known faults in either hole section. H2S: V Treat every hole section as though it has the potential for 1-12S. No 1-12S events have been documented on drill wells on "L" pad (nearest pad). 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures expected while drilling this well. Page 39 Version 0 October, 2018 2 /.0 14 Rig Lavout 0) Milne Point Unit M-03 Drilling Procedure Page 40 Version 0 October, 2018 n Hilcorp Enver Czw Milne Point Unit M-03 Drilling Procedure 28.0 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. J/ Page 41 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure Hilcorp Ev C�pevy 29.0 Choke Manifold Schematic Z v m u 6 w 0 o /l�j-�-/ m N R > M V V z z fir\ la 1 0 O� a I T Z 3 x 3 m mN V1 N 00 W tD y T d N 3 3 n u D H 3 N 3 c iv w A Q n T v 0 a �I 7 w 9 s y n Ma U z v W N 0 rJ d rn� v rt W r 0 OD p � _ r 0" r r "' D M . � o m o � Page 42 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure Hilc T Energy Company 30.0 Casing Design Information Calculation & Casing Design Factors Hole Size 141/2' Hole Size 9-7/8" Hole Size Drilling Mode MAS P(9-7/8"): 1471 Production Mode MASP: 1861 Milne Point Unit DATE: 10-23-2018 WELL: MPU M-03 DESIGN BY: Monty M Myers In Criteria: Mud Density: Mud Density: Mud Density: attached MASP determination & calcul attached MASP determination & 9.5 9.5 Collapse Calculation: Section Calculation 1, 2, 3 Max MW gradient external stress and the casing evacuated for the internal stress Page 43 Version 0 October, 2018 Casing Section Calculation/Specification 1 2 3 Casing OD 10-3/4" 7-5/8" Top (MD) 0 0 Top (ND) 0 0 Bottom (MD) 2,800 6,412 _ Bottom (TVD) 2,044 3,902 Length 2,800 6,412 Weight (ppf) 45.5 29.7 Grade L-80 L-80 Connection W HYD 563 Weight w/o Bouyancy Factor (Ibs) 127,400 190,436 Tension at Top of Section (lbs) 127,400 190,436 Min strength Tension (1000 lbs) 1040 683 Worst Case Safety Factor (Tension) 8.16/ 3.59 Collapse Pressure at bottom (Psi) 1,022 1,951 Collapse Resistance w/o tension (Psi) 2,470 4,790 Worst Case Safety Factor (Collapse) 2.42/ 2.46 MASP (psi) 1,181 1,471 Minimum Yield (psi) 5,210 6,890 Worst case safety factor (Burst) 4.41 4.68 Page 43 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure Hilc c2prprp Enm� 31.0 n Hilcorp 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 9-7/8" Hole Section MPU M-03 Milne Point Anticinated Formations and Pressures: Formation MD TVD Planned Top: 2800 2044 Planned TD: 6412 3902 Anticinated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Top Disposal Ugnu 2,694 1200 Wet 8.6 0.445 Base Disposal Ugnu 3,145 1450 Wet 8.9 0.461 Schrader 3,665 1750 Oil 9.2 0.477 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date MPL-43 9.3-9.8 439 _6,745 2004 MPB-28 9.0-9.4 Surface 4,435 I 2016 MPB-29 8.8-9.2 Surface 4,400 2016 Assumptions: 1. Fracture gradient at shoe is estimated at 0.7 psi / ft based on field test data. 2. Maximum planned mud density for the 9-7/8" hole section is 9.5 ppg. 3. Calculations assume Ugnu contains 100% gas (worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 10-3/4" shoe considering a full column of gas from shoe to surface: 2044 (ft) x 0.7(psi/ft)= 1431 psi 1431 (psi) - [0.1(psi/ft)*2044(ft))= 1227 psi Drilling Mode MASP MASP from pore pressure (wellbore completely evacuated to gas) i 3902(ft) x 0.477(psi/ft)= 1861 psi 1861(psi)-[0.1(psi/ft)*3902(ft)) 1471 psi Summary: 1. MASP while drilling 9-7/8" Intermediate hole is governed by 10-3/4" casing shoe integrity. Page 44 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure Hilcorp E�� c= 32.0 Spider Plot (NAD 27) (Governmental Sections) ADL355023 Sr. KUPARUK R i $ec. 14 � MILNE POINT UNIT it i i a� , i r woer:,e,vx,a �"y 11-0:_SIII 8 0 0 0 0 0 0 0 0 0 e 0 0 0 0 0 0 UD13NO09E Milne Point Unit MPU M-03 Well wp-05 M-03 BHL ADL383235 Sec. 12 Sec. 13 t tt, , , , , t , 1 , Legend • M -03 -SHL X M-03i_TPH t M-03_BHL Omer Surface Holes (SHL) • Omer Bogan Holes (BML) - - Omer Wes Paths QOil and Gas Unit Boundary Pad Fogpnnt 0 500 1.000 Feet Page 45 Version 0 October, 2018 . S:c. 23 woer:,e,vx,a �"y 11-0:_SIII 8 0 0 0 0 0 0 0 0 0 e 0 0 0 0 0 0 UD13NO09E Milne Point Unit MPU M-03 Well wp-05 M-03 BHL ADL383235 Sec. 12 Sec. 13 t tt, , , , , t , 1 , Legend • M -03 -SHL X M-03i_TPH t M-03_BHL Omer Surface Holes (SHL) • Omer Bogan Holes (BML) - - Omer Wes Paths QOil and Gas Unit Boundary Pad Fogpnnt 0 500 1.000 Feet Page 45 Version 0 October, 2018 H Hilcorp En=By c.pwy 33.0 Surface Plat (As Built) (NAD I N- SEC. 12 I - I_SEC. 13 SEC 11 T , SEC. 14 M-10 M-11 �• M-12 I I Milne Point Unit M-03 Drilling Procedure NTS I nr4TFn mT im PRnTRArTFn SFr. 14. IT 13 N_ R. 9 E. UMIAT MERIDIAN. ALASKA WELL A.S.P. GEODETIC GEODETIC I LEGEND AS -BUILT CONDUCTOR OF A I (qSL r NO. COORDINATES POSInON DMS ■ EXISTING CONWCTOR �P'�E:••"' nlla I BOX EL. Y= 6,027,889.71 ... 9m� .. 70.4872289' 51040' FSL 25.0' M-03• X= 533,363.90 149'43'38.285" 149.7273014' M-04 I F� Dnothy unhart ;. 70'29'14.021" M-03 51040' FSL 25.0' . ; X= 533,393.80 MPU MOOSE PAD 149.7270569' 771' FEL X10.2.00 "'�'tAIQ�rL NOTES: I 1. AIA9U STATE PLVE COORDINATES ARE NAD27. ZONE 4, I SURVEYOR'S CERTIFICATE I HEREBY CERTIFY THAT I AM 2. GEOOEIIC P09RONS ARE NAD27. GRAPHIC SCALE IS EKED AM UC NIS PROPERLY REGISTERED 3. Ras OF' NOPI2ORTAl AND YFRI CONTROL Is MOOSE 0 100 200 400 THE STATE OF ALASKA AND THAT PAD MONUMENT OP2. 51' FEL THIS AS -BUILT REPRESENTS A SURN 4. LPV MOOSE PAD SCALE FACTOR IS 0.99890255 ( N FEET) MADE BY ME OR UNDER MY DIRECT AT WPER SIO AND MAT ALL E 5. DATE OF SVRN .. SEPTEMBER 26, 2015 M 1 Nv 200 1L DIM SIGNS AND OVER DETAILSARE 6. REFERENCE FELD BOG(: M18-04 PP. 2 J4. X= 534,023.88 CORRECT AS OF SEPTEMBER 26. 2016. I nr4TFn mT im PRnTRArTFn SFr. 14. IT 13 N_ R. 9 E. UMIAT MERIDIAN. ALASKA WELL A.S.P. GEODETIC GEODETIC SECTION CELLAR NO. COORDINATES POSInON DMS POSITION O.DO OFFSETS BOX EL. Y= 6,027,889.71 70'29'14.024" 70.4872289' 51040' FSL 25.0' M-03• X= 533,363.90 149'43'38.285" 149.7273014' 801' FEL Y- 6.027,889.58 70'29'14.021" 70.4872281' 51040' FSL 25.0' M-04 X= 533,393.80 14943'37.405" 149.7270569' 771' FEL Y= 6,027,889.65 70'29'13.990" 70.4872194' 5,037' FSL 249' M-10 X- 534,113.80 149'43'16.220' 149.7211722' 51' FEL Y= 6,027,889.61 70'29'13.993" 70.4872203' 5,037' FSL 25.0' M-11 X= 534,023.88 1 149'43'18.865" 149.7219069' 141' FEL Y- 6.027,889.80 70'29'13.999" 70.4872219' 5,037' FSL 25'0 M-12 X= 533,933.89 149'4321.513" 149.7226425' 231' FEL I JACOBS bell Hficorp Ahska ,9R NX P"6 MILNE POINT, ALASKA P� MOOSE PAD, HELLS M-03, 04, 10, 11, 12 -=0tl�"' "�"'�'10 T• - 2Dy CONDUCTOR AS -BUILT t v t wv Mmv Page 46 Version 0 October, 2018 H Hilcorp E�C—pr 34.0 Directional Plan (wp 05) Milne Point Unit M-03 Drilling Procedure Page 47 Version 0 October, 2018 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-03 M-03 Plan: M-03 wp05 Standard Proposal Report 03 October, 2018 HALLIBURTON Sperry Drilling Services HALLIBURTON _ Hilcerp Alaska, LLC REFERENCE INFORMATION Project., Milne Point CalwlationMethod: Minimum Curvature Coordinate (N/E) Reference: Well MPU M-03, True North spis,v fJ'HU.9 Site: M Pt Moose Pad Eno, System: ISCWSA Vertical (TVD) Reference: M-03 ap05 RKB ® 58.70usft(DoWn 14) Well: MPU M-03 Scan Method: Error CElliplosest al Conic Approach 3D Measured Depth Reference: M-03 wp05 RKB @ 58.70usft (Doyon 14) Wellbore: M -Warning Method: Error Ratio Calculation Method: Minimum Curvature Design: M-03 wp05 T SECTION DETAILS Sec MD Inc Azi TVD +N/ -S +E/ -W Dleg TFace VSect Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 433.70 0.00 0.00 433.70 0.00 0.00 0.00 0.00 0.00 StartDir 3°/100' : 433.7' MD, 433.7TVD 3 634.40 6.02 170.00 634.03 -10.38 1.83 3.00 170.00 10.40 Start Dir4°/100' :634.4' MD, 634.03'TVD 4 734.40 10.02 170.00 733.03 -24.11 4.25 4.00 0.00 24.17 5 2188.79 68.04 179.60 1815.68 -899.72 33.43 4.00 10.49 900.08 End Dir : 2188.79' MD, 1815.68' TVD 6 4523.73 68.04 179.60 2688.70 -3065.26 48.36 0.00 0.00 3065.63 M-03 wpO4 - Ewell tgn Start Dir 2-1100'; 4523.73' MD, 2688.7'TVD 7 6412.28 30.27 179.60 3901.50 4468.22 58.03 2.00 180.00 4468.60 Total Depth : 6412.28' MD, 3901.5' TVD CASING DETAILS WELL DETAILS: MPU W03 TVD TVDSS MD Size Name Ground Level: 25.00 2044.21 1985.51 2800.00 10-3/4 103/4"x141/2"+NI-S +EI -W Northing Easting Lafiftude Longitude 3901.50 3842.80 6412.28 7-5/8 7 5/8" x 9-7/8' 0.00 0.00 6027889.71 533363.90 70° 29'14.024 N 149° 43' 38.285 W WWA Start Dlr 3°/100' : 433.7' MD, 433.7'TVD -Start Dir 4°/100' : 634.4' MD, 634.03'ND 750 �000 1125 y�0 1500 c m 1875 - - - - - - - - o BPRF r - L m2250 0 U 2625 SURVEY PROGRAM DDI = 5.946 Depth From Depth To Survey/Plan Tool 33.70 2800.00 M-03 wp05 (M-03) 2_MWD+IFR2+MS+Sag 2800.00 641228 M-03 wp05 (M-03) 2_MWD+IFR2+MS+Sag End Dir :2188.79' MD, 1815.68' TVD '�yoo 103/4"x1412" -N 0 � o00 � o �h0 m- _ - _ - - - - - - - - - _ - _ - _ - 2 MP_UG_COAL1 3000 41 MP LD MP -SB -OA 0 375 750 1125 1500 Start Dir 2-/100': 4523.73' MD, 2688.77VD ho _ M-03 wp04 - Ewell tgtl o- 00 \ h� Vertical Section at 179.26' (750 LOOT) - 7 5/8" x 9-7/8" M-03 wp05 Total Depth : 6412.28' MD, 3901.5' TVD 3750 4125 4500 4875 5250 Oate2018-09-13700:00:00 Validated: Vas Verson: FORMATION TOP DETAILS TVDPsth TVDssPalh MOPath Formation 1837.20 1778.50 2246.35 BPRF 2694.20 2635.50 4538.35 MP_UG_COALt 3145.20 3086.50 5416.66 MP LD 3665.20 3606.60 6130.10 MP SB -OA End Dir :2188.79' MD, 1815.68' TVD '�yoo 103/4"x1412" -N 0 � o00 � o �h0 m- _ - _ - - - - - - - - - _ - _ - _ - 2 MP_UG_COAL1 3000 41 MP LD MP -SB -OA 0 375 750 1125 1500 Start Dir 2-/100': 4523.73' MD, 2688.77VD ho _ M-03 wp04 - Ewell tgtl o- 00 \ h� Vertical Section at 179.26' (750 LOOT) - 7 5/8" x 9-7/8" M-03 wp05 Total Depth : 6412.28' MD, 3901.5' TVD 3750 4125 4500 4875 5250 -250 -1750 IC -2250 C 0 c -2500 0 0 m 4000 -4250 I MALLIBURTON Project: Milne Point 13 ."v U'lning Site: M Pt Moose Pad Well: MPU M-03 ® Wellbore: M-03 Plan: M-03 wp05 CASING DETAILS TVD TVDSS MD Si. Name 2044.21 1985.51 2800.00 10-3/4 10314".14112" 3901.50 3842.80 6412.28 7-5/8 7 5/8"x 9-7/8" WELL DETARS: MPU M413 Orpund Level: 25.00 +N/ -S +V -W N.Miny Eufine Iatittudc longitude 0.00 0.00 6027889.71 533363.90 70° 29' 14.024 N 149° 43' 38.285 W REFERENCE INFORMATION co Nlnate NX) Reference: Well MPU M-0 , Twe NoM VMicel (EVD) Reference: M-03 wp05 RKB @ 50]0us0 (Doyon 141 Measured Depth Reference: -03 "M RKB ® 58]OesR(Doyon 14) Calmlavon Met : MINMUM curvature Start D_r3°/100' :4317' MD, 433.71VD - - - -Stan D'v 4°/100':634.4' bID, 634.034 1250 1500 1750 __-_-__ End Dir: 2188.79' MD, 1815.68' TVD 2750 3000 3250 10 3/4••x 14 I/2" M-03 wy0a -Ewell lyl l Stan Dir 2°1100• :4523, ]3' M0.2688.TTVD M O3 wp05 ] 5/8" x 9-L8" TeW D<p01: 641238' MD, 3901.5' TVD II T,j I III K i l n I I I I I I I I I I I I I r I I I k I I I I I I i I 11 -2000 -1750 -1500 -1250 -1000 -750 -500 -250 0 250 500 750 1000 1250 1500 West( -)/Fast(+) (500 usPo;n) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-03 Wellbore: M-03 Design: M-03 wp05 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well MPU M-03 TVD Reference: M-03 wp05 RKB @ 58.70usft (Doyon 14) - MD Reference: M-03 wp05 RKB @ 58.70usft (Doyon 14) North Reference: True Survey Calculation Method: Minimum Curvature ' reject Milne Point, ACT, MILNE POINT lap System: US State Plane 1927 (Exact solution) • System Datum: Mean Sea Level leo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point lap Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt Moose Pad Site Position: From: Map Position Uncertainty: Well MPU M-03 Well Position +NIS +E/ -W Position Uncertainty Wellbore Magnetics Design Audit Notes: Version: Vertical Section: Northing: 6,027,877.65usft Latitude: 70° 29' 13.905 N Easting: 533,363.92 usft Longitude: 149° 43'38.286 W 0.00 usft Slot Radius: 13-3/16" Grid Convergence: 0.26 ° 0.00 usft Northing: 0.00 usft Easting: 0.00 usft Wellhead Elevation: M-03 Model Name 8GGM2018 M-03 wp05 6,027,889.71 usft Latitude: 533,363.90 usft Longitude: 25.00 usft Ground Level: Sample Date Declination Dip Angle (I r) 9/13/2018 17.00 Phase: PLAN Depth From (TVD) +NIS (usft) (usft) 33.70 0.00 Plan Sections Dogleg Build Turn +NIS +E/ -W Rate Measured Rate Tool Face (usft) Vertical TVD Depth Inclination Azimuth Depth System (usft) (`) V) 0.00 (usft) usft 33.70 0.00 0.00 0.00 33.70 -25.00 433.70 0.00 0.00 0.00 433.70 375.00 634.40 6.02 170.00 0.00 634.03 575.33 734.40 10.02 170.00 0.66 733.03 674.33 2,188.79 68.04 179.60 0.00 1,815.68 1,756.98 4,523.73 68.04 179.60 0.00 2,688.70 2,630.00 6,412.28 30.27 179.60 3,901.50 3,842.80 80.98 70° 29' 14.024 N 149° 43'38.285 W 25.00 usft Field Strength (nT) 57,452 Tie On Depth: 33.70 +EI -W Direction (usft) (1) 0.00 179.26 10/32018 3:47:04PM Page 2 COMPASS 5000.1 Build 81E Dogleg Build Turn +NIS +E/ -W Rate Rate Rate Tool Face (usft) (usft) ('/100usft) ("/100usft) ("/100usft) (^) 0.00 0.00 0.00 6.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -10.38 1.83 3.00 3.00 0.00 170.00 -24.11 4.25 4.00 4.00 0.00 0.00 -899.72 33.43 4.00 3.99 0.66 10.49 -3,065.26 48.36 0.00 0.00 0.00 0.00 -4,468.22 58.03 2.00 -2.00 0.00 180.00 10/32018 3:47:04PM Page 2 COMPASS 5000.1 Build 81E Planned Survey Halliburton HALLI B U RTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well MPU M-03 Company: Hilcorp Alaska, LLC TVD Reference: M-03 wp05 RKB @ 58.70usft (Doyon 14) Project: Milne Point MD Reference: M-03 wp05 RKB @ 58.70usft (Doyon 14) Site: M Pt Moose Pad North Reference: True Well: MPU M-03 Survey Calculation Method: Minimum Curvature Wellbore: M-03 Vertical Design: M-03 wp05 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -25.00 33.70 0.00 0.00 33.70 -25.00 0.00 0.00 6,027,889.71 533,363.90 0.00 0.00 100.00 0.00 0.00 100.00 41.30 0.00 0.00 6,027,889.71 533,363.90 0.00 0.00 200.00 0.00 0.00 200.00 141.30 0.00 0.00 6,027,889.71 533,363.90 0.00 0.00 300.00 0.00 0.00 300.00 241.30 0.00 0.00 6,027,889.71 533,363.90 0.00 0.00 400.00 0.00 0.00 400.00 341.30 0.00 0.00 6,027,889.71 533,363.90 0.00 0.00 433.70 0.00 0.00 433.70 375.00 0.00 0.00 6,027,889.71 533,363.90 0.00 0.00 Start Dir 3°1100' : 433.7' MD, 433.7'TVD 500.00 1.99 170.00 499.99 441.29 -1.13 0.20 6,027,888.58 533,364.10 3.00 1.14 600.00 4.99 170.00 599.79 541.09 -7.13 1.26 6,027,882.59 533,365.19 3.00 7.14 634.40 6.02 170.00 634.03 575.33 -10.38 1.83 6,027,879.34 533,365.78 3.00 10.40 Start Dir 4°1100' : 634.4' MD, 634.03'TVD 700.00 8.65 170.00 699.09 640.39 -18.62 3.28 6,027,871.11 533,367.27 4.00 18.66 734.40 10.02 170.00 733.03 674.33 -24.11 4.25 6,027,865.62 533,368.26 4.00 24.17 800.00 12.61 172.19 797.35 738.65 -36.83 6.22 6,027,852.91 533,370.28 4.00 36.91 900.00 16.58 174.22 894.11 835.41 -61.85 9.14 6,027,827.91 533,373.31 4.00 61.96 1,000.00 20.56 175.49 988.88 930.18 -93.56 11.96 6,027,796.21 533,376.27 4.00 93.71 1,100.00 24.54 176.36 1,081.22 1,022.52 -131.80 14.66 6,027,757.99 533,379.15 4.00 131.98 1,200.00 28.53 176.99 1,170.66 1,111.96 -176.40 17.23 6,027,713.40 533,381.92 4.00 176.61 1,300.00 32.53 177.49 1,256.78 1,198.08 -227.13 19.66 6,027,662.69 533,384.58 4.00 227.37 1,400.00 36.52 177.88 1,339.16 1,280.46 -283.75 21.94 6,027,606.09 533,387.11 4.00 284.01 1,500.00 40.51 178.21 1,417.38 1,358.68 -345.97 24.06 6,027,543.88 533,389.51 4.00 346.26 1,600.00 44.51 178.49 1,491.08 1,432.38 -413.51 26.00 6,027,476.37 533,391.75 4.00 413.81 1,700.00 48.51 178.73 1,559.89 1,501.19 -486.02 27.75 6,027,403.87 533,393.83 4.00 486.34 1,800.00 52.50 178.94 1,623.48 1,564.78 -563.15 29.31 6,027,326.75 533,395.74 4.00 563.49 1,900.00 56.50 179.13 1,681.54 1,622.84 -644.54 30.67 6,027,245.38 533,397.46 4.00 644.88 2,000.00 60.50 179.31 1,733.78 1,675.08 -729.78 31.83 6,027,160.16 533,399.00 4.00 730.13 2,100.00 64.49 179.47 1,779.95 1,721.25 -818.45 32.77 6,027,071.50 533,400.34 4.00 818.81 2,188.79 68.04 179.60 1,815.68 1,756.98 -899.72 33.43 6,026,990.24 533,401.36 4.00 900.07 End Dir : 2188.79' MD, 1815.61 ND 2,200.00 68.04 179.60 1,819.87 1,761.17 -910.11 33.50 6,026,979.85 533,401.48 0.00 910.47 2,246.35 68.04 179.60 1,837.20 1,778.50 -953.10 33.79 6,026,936.87 533,401.97 0.00 953.46 BPRF 2,300.00 68.04 179.60 1,857.26 1,798.56 -1,002.86 34.14 6,026,887.11 533,402.53 0.00 1,003.22 2,400.00 68.04 179.60 1,894.65 1,835.95 -1,095.60 34.78 6,026,794.38 533,403.59 0.00 1,095.96 2,500.00 68.04 179.60 1,932.04 1,873.34 -1,188.35 35.42 6,026,701.65 533,404.64 0.00 1,188.71 2,600.00 68.04 179.60 1,969.43 1,910.73 -1,281.09 36.05 6,026,608.92 533,405.70 0.00 1,281.45 2,700.00 3�i1 r 68.04 179.60 2,006.82 1,948.12 -1,373.84 36.69 6,026,516.19 533,406.75 0.00 1,374.20 10 2,800.00 68.04 179.60 2,044.21 1,985.51 -1,466.58 37.33 6,026,423.45 533,407.81 0.00 1,466.94 CA51 10 3/4" x 14 112" 2,900.00 68.04 179.60 2,081.60 2,022.90 -1,559.33 37.97 6,026,330.72 533,408.86 0.00 1,559.69 3,000.00 68.04 179.60 2,118.99 2,060.29 -1,652.07 38.61 6,026,237.99 533,409.92 0.00 1,652.44 •� 3,100.00 68.04 179.60 2,156.38 2,097.68 -1,744.82 39.25 6,026,145.26 533,410.97 0.00 1,745.18 3,200.00 68.04 179.60 2,193.76 2,135.06 -1,837.56 39.89 6,026,052.53 533,412.03 0.00 1,837.93 3,300.00 68.04 179.60 2,231.15 2,172.45 -1,930.31 40.53 6,025,959.79 533,413.09 0.00 1,930.67 3,400.00 68.04 179.60 2,268.54 2,209.84 -2,023.05 41.17 6,025,867.06 533,414.14 0.00 2,023.42 10/32018 3:4704PM Page 3 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-03 Wellbore: M-03 Design: M-03 wp05 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well MPU M-03 TVD Reference: M-03 wp05 RKB @ 58.70usft (Doyon 14) MD Reference: M-03 wp05 RKB @ 58.70usft (Doyon 14) North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Map Vertical +EI -W Depth Inclination Easting Azimuth Depth TVDss +NIS (usft) V) V) (usft) usft (usft) 3,500.00 68.04 179.60 2,305.93 2,247.23 -2,115.80 3,600.00 68.04 179.60 2,343.32 2,284.62 -2,208.54 3,700.00 68.04 179.60 2,380.71 2,322.01 -2,301.29 3,800.00 68.04 179.60,418 2,487.14 2,359.40 -2,394.03 3,900.00 68.04 179.60 2,455.49 2,396.79 -2,486.78 4,000.00 68.04 179.60 2,492.88 2,434.18 -2,579.52 4,100.00 68.04 179.60 2,530.27 2,471.57 -2,672.27 4,200.00 68.04 179.60 2,567.66 2,508.96 -2,765.01 4,300.00 68.04 179.60 2,605.05 2,546.35 -2,857.76 4,400.00 68.04 179.60 2,642.44 2,583.74 -2,950.50 4,500.00 68.04 179.60 2,679.83 2,621.13 -3,043.25 4,523.73 68.04 179.60 2,688.70 2,630.00 -3,065.26 Start Dir 2°1100' : 4523.73' MD, 2688.7"rVO 2.00 3,316.48 4,538.35 67.75 179.60 2,694.20 2,635.50 -3,078.80 MP_UG_COAL1 533,430.84 2.00 3,490.54 51.87 4,600.00 66.52 179.60 2,718.15 2,659.45 -3,135.60 4,700.00 64.52 179.60 2,759.59 2,700.89 -3,226.61 4,800.00 62.52 179.60 2,804.18 2,745.48 -3,316.11 4,900.00 60.52 179.60 2,851.86 2,793.16 -3,404.00 5,000.00 58.52 179.60 2,902.59 2,843.89 -3,490.17 5,100.00 56.52 179.60 2,956.29 2,897.59 -3,574.52 5,200.00 54.52 179.60 3,012.90 2,954.20 -3,656.95 5,300.00 52.52 179.60 3,072.35 3,013.65 -3,737.35 5,400.00 50.52 179.60 3,134.57 3,075.87 -3,815.62 5,416.66 50.19 179.60 3,145.20 3,086.50 -3,828.45 NIP LID _L 533,440.21 2.00 4,314.59 57.24 6,023,535.92 5,500.00 48.52 179.60 3,199.49 3,140.79 -3,891.68 5,600.00 46.52 179.60 3,267.02 3,208.32 -3,965.42 5,700.00 44.52 179.60 3,337.08 3,278.38 -4,036.77 5,800.00 42.52 179.60 3,409.60 3,350.90 -4,105.62 5,900.00 40.52 179.60 3,484.47 3,425.77 -4,171.90 6,000.00 38.52 179.60 3,561.60 3,502.90 1,235.53 6,100.00 36.52 179.60 3,640.91 3,582.21 4,296.43 6,130.10 35.92 179.60 3,665.20 3,606.50 -4,314.21 MP SB -OA 6,200.00 34.52 179.60 3,722.30 3,663.60 -4,354.52 6,300.00 32.52 179.60 3,805.67 3,746.97 -4,409.74 6,400.00 30.52 179.60 3,890.91 3,832.21 -4,462.01 6,412.28 - 30.27 179.60 3,901.50 3,842.80. -4,468.22 Total Depth : 6412.28' MD, 3901.5' TVD -10 314" x 14112" 10/32018 3:47:04PM Page 4 COMPASS 5000.1 Build 81E Map Map +EI -W Northing Easting DLS Vert Section (usft) (usft) (usft) 2,247.23 41.81 6,025,774.33 533,415.20 0.00 2,116.16 42.45 6,025,681.60 533,416.25 0.00 2,208.91 43.09 6,025,588.87 533,417.31 0.00 2,301.65 43.73 6,025,496.13 533,418.36 0.00 2,394.40 44.37 6,025,403.40 533,419.42 0.00 2,487.14 45.01 6,025,310.67 533,420.47 0.00 2,579.89 45.65 6,025,217.94 533,421.53 0.00 2,672.64 46.29 6,025,125.21 533,422.58 0.00 2,765.38 46.92 6,025,032.47 533,423.64 0.00 2,858.13 47.56 6,024,939.74 533,424.69 0.00 2,950.87 48.20 6,024,847.01 533,425.75 0.00 3,043.62 48.36 6,024,825.00 533,426.00 0.00 3,065.63 48.45 6,024,811.46 533,426.15 2.00 3,079.17 48.84 6,024,754.67 533,426.80 2.00 3,135.97 49.47 6,024,663.68 533,427.84 2.00 3,226.98 50.08 6,024,574.19 533,428.85 2.00 3,316.48 50.69 6,024,486.31 533,429.85 2.00 3,404.37 51.28 6,024,400.15 533,430.84 2.00 3,490.54 51.87 6,024,315.81 533,431.80 2.00 3,574.90 52.43 6,024,233.39 533,432.73 2.00 3,657.32 52.99 6,024,153.01 533,433.65 2.00 3,737.72 53.53 6,024,074.74 533,434.54 2.00 3,816.00 53.62 6,024,061.92 533,434.68 2.00 3,828.82 54.05 6,023,998.70 533,435.40 2.00 3,892.05 54.56 6,023,924.96 533,436.24 2.00 3,965.80 55.05 6,023,853.63 533,437.05 2.00 4,037.14 55.53 6,023,784.79 533,437.84 2.00 4,106.00 55.98 6,023,718.51 533,438.59 2.00 4,172.28 56.42 6,023,654.89 533,439.32 2,00 4,235.91 56.84 6,023,594.00 533,440.01 2.00 4,296.80 56.97 6,023,576.22 533,440.21 2.00 4,314.59 57.24 6,023,535.92 533,440.67 2.00 4,354.90 57.62 6,023,480.71 533,441.30 2.00 4,410.11 57.98 6,023,428.44 533,441.89 2.00 4,462.39 58.03 6,023,422.23 533,441.96 2.00 4,468.60 10/32018 3:47:04PM Page 4 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-03 Wellbore: M-03 Design: M-03 wp05 Targets Target Name - hittmiss target - Shape M-03 wp04 - Ewell tgtl - plan hits target center - Circle (radius 50.00) Casing Points Formations Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Dip Angle Dip Dir. TVD +NI -S (°) (°) (usft) (usft) 0.00 0.00 2,688.70 -3,065.26 Halliburton Standard Proposal Report Well MPU M-03 M-03 wp05 RKB @ 58.70usft (Doyon 14) M-03 wp05 IRKS @ 58.70usft (Doyon 14) True Minimum Curvature +E/ -W Northing (usft) (usft) 48.36 6,024,825.00 Easting (usft) 533,426.00 Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (11) (11) 2,800.00 2,044.21 10 3/4" x 14 1/2" 10-3/4 14-1/2 6,412.28 3,901.50 7 5/8" x 9-7/8" 7-5/8 9-7/8 Measured Depth (usft) 2,246.35 5,416.66 6,130.10 4,538.35 Plan Annotations Measured Depth (usft) 433.70 634.40 2,188.79 4,523.73 6,412.28 Vertical Vertical Depth Depth SS (usft) 1,837.20 3,145.20 3,665.20 2,694.20 Name BPRF MP_LD MP—SB-OA MP UG COALt Vertical Local Coordinates Depth +N/ -S +E/ -W (usft) (usft) (usft) 433.70 0.00 0.00 634.03 -10.38 1.83 1,815.68 -899.72 33.43 2,688.70 -3,065.26 48.36 3,901.50 -4,468.22 58.03 Comment Lithology Start Dir 3°/100' : 433.7' MD, 433.7'TVD Start Dir4°/100' : 634.4' MD, 634.037VD End Dir : 2188.79' MD, 1815.68' TVD Start Dir 2°/100' : 4523.73' MD, 2688.7'TVD Total Depth : 6412.28' MD, 3901.5' TVD Dip Dip Direction (°) (°) 0.00 0.00 0.00 0.00 10/3P2018 3:47:04PM Page 5 COMPASS 5000.1 Build 81E Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-03 M-03 M-03 wp05 Sperry Drilling Services Clearance Summary Anticollision Report 03 October, 2018 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-03 - M-03 - M-03 wp05 Well Coordinates: 6,027,889.71 N, 533,363.90 E (70° 29'14.02" N, 149° 43' 38.28" W) Datum Height: M-03 wp05 RKB @ 58.70usft (Doyon 14) Scan Range: 0.00 to 6,412.28 usft. Measured Depth. Scan Radius is 1,500.00 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 81E Scan Type:U11VIOL61:1-3411911191091 Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for MPU M-03 - M-03 wp05 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-03 - M-03 - M-03 wp05 Scan Range: 0.00 to 6,412.28 usft. Measured Depth. Scan Radius is 1,500.00 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Site Name Comparison Well Name - Wellbore Name - Design M Pt Moose Pad MPU M-04 - M-04 - M-04 wp01 MPU M-04 - M-04 - M-04 wp01 MPU M-04 - M-04 - M-04 wp01 MPU M-05 - M-05 - M-05 (Beauregard Disp) wp03 MPU M-05 - M-05 - M-05 (Beauregard Disp) wp03 M, U -05 - M-05 - M-05 (Beauregard Disp) wp03 MPU M -23i - M118 - M -23i wp0 MR6-M 24-M24_M.7.rLwpo,�' Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Depth Distance Depth Separation Depth Factor Minimum (usft) (usft) (usft) (usft) usft 578.05 29.40 578.05 24.78 573.91 6.361 Centre Distance 600.00 29.46 600.00 24.68 595.79 6.170 Ellipse Separation 675.00 31.01 675.00 25.71 670.39 5.851 Clearance Factor 351.40 127.11 351.40 124.04 340.20 41.472 Centre Distance 375.00 127.15 375.00 123.92 362.94 39.376 Ellipse Separation 1,150.00 200.41 1,150.00 191.93 1,057.25 23.629 Clearance Factor 1,125.82 9.B7 1,125.82 122 1,115.31 1.140 learance Factor 941.36 22.56 941.36 15.27 921.11 Clearance Factor From To Survey/Plan (usft) (usft) 33.70 2,800.00 M-03 wp05 2,800.00 6,412.28 M-03 wp05 Ellipse error terms are correlated across survey tool tieon points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Survey Tool 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag Hilcorp Alaska, LLC Milne Point Separation Warning Pass - Pass - Pass - Pass - Pass - Pass - Pass - Pass - 03 October, 2018 - 15:48 Page 2 of COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELLDEPAILSMPUM-03 NAD)927(NADCONCONUS) Aleskaaai,04 Cuordlnate (ME) Refemrce: Wed MPU M-03, Tme NoM Reference: Mz6 wP)S RKB@ 50]0uaft(Do,in 14) Measures Depth RaNZ.: M-03 wp05 RKB @ 5810ueft (Doyan 14) Camulaaon Method Minimum Cuvalure .00 Groand Level: 25.00 /_S +P/ -W Noruing Fa¢iin8 Leti6ude Longitudc 0.00 602]889.]I 533363.90 70° 29' 14.024 N 149° 43' 38.285 Site: M Pt Moose Pad Sperry Orillinn Well: MPU M-03M Wellbore: M-03 Plan: M-03 wp05 SURVEY PROGRAM GLORAL FILTER: Using user defined selection 6 filtering criteria 33.70 To 641228 Date: 2018.09-13T00:00:00 Validated Yes Version: CASMG DETAILS Ladder/S.F. Plots Depth From Depth To Survey/Plan Tool 33.70 2600.00 M-03 w05 (M-03) 2_MWD+IFR2+MS+Sag TVD WDSS MD Size Name 2800.00 6412.28 M-03W05(M-03) 2_MWD+IFR2+MS+Seg 2044.21 1985.51 280D.00 10-3/4 10 3/4" x 14 12" 3901.50 3842.80 6412.28 7-5/8 7 5/8" x 9-7/8" M -23i wp0 � l X750.00 M-24-w{�0.7 -M-05-( auregard ' p)+ P03 o 0.120.00 c 0 90.00 m a d I I I m U 30.00 O M-04 w0.) 1 I 0.00 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650 Measured Depth (700 usft/in) 4.50 I — — _ l -- —_---._-- 3.00 � I I I l i Ij LL 0 I C), Collision Risk Procedures Req. COO 1.50 - Collision Avoidance Req. No Go Zone - Stop Drilling l 0.00- .00 0 0 400 800 1200 1600 2000 2400 2000 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 Measured Depth (700 usft/in) Oct 5"', 2018 H Hilcorp En Company Contents Milne Point Drilling Procedure 1.0 Well Summary.................................................................................................... ..........................Z 2.0 Management of Change Information..........................................................................................3 3.0 Tubular Program: .................................................................................. ....................................... 4 4.0 Drill Pipe Information: .................................................................... ............................................. 4 5.0 Casing Inspection..........................................................................................................................4 6.0 Internal Reporting Requirements................................................................................................5 7.0 Planned Wellbore Schematic........................................................................................................6 8.0 Drilling / Completion Summary...................................................................................................7 9.0 Mandatory Regulatory Compliance / Notificatio.....................................................................8 10.0 R/U and Preparatory Work........................................................................................................10 11.0 N/U 21-1/4" 2M Diverter System...............................................................................................11 12.0 Drill 14-1/2" Hole Section...........................................................................................................12 13.0 Run 10-3/4" Surface Casing........................................................................................................15 14.0 Cement 10-3/4" Surface Casing.................................................................................................18 15.0 BOP N/U and Test........................................................................................................................21 16.0 Drill 9-7/8" Hole Section..............................................................................................................22 17.0 Run 7-5/8" Intermediate Casin with stage collar.....................................................................24 18.0 Cement 7-5/8" Casing (2 -stag s)..................................................................................................28 19.0 Wellbore Clean Up & Displ cement............................................................................................32 20.0 Completion Operations................................................................................................................33 21.0 Well Perforation: ........... .............................................................................................................. 33 22.0 Diverter Schematic......................................................................................................................34 23.0 BOP Schematic.............................................................................................................................35 24.0 Wellhead Schemati......................................................................................................................36 25.0 Days Vs Depth..............................................................................................................................37 26.0 Anticipated Dril ng Hazards.......................................................................................................38 27.0 Doyon 14 Rig yout.....................................................................................................................40 28.0 FIT Procedur................................................................................................................................41 29.0 Choke Mani f ld Schematic...........................................................................................................42 30.0 Casing Design Information...........................................................................................................43 31.0 9-7/8" Hole Section MASP............................................................................................................44 32.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................45 33.0 Surface Plat (As Built) (NAD 27).................................................................................................46 34.0 Directional Plan (wp 05)...............................................................................................................47 H Hileorp E.eW ,2,T 1.0 Well Summary Milne Point Unit M-03 Drilling Procedure Well MPU M-03 Pad Milne Point "M" Pad Planned Completion Type 5-1/2" Injection Tubing Target Reservoir(s) Ugnu Planned Well TD, MD / TVD 6,412' MD / 3,902' TVD PBTD, MD / TVD 6,300' MD / 3,806' TVD Surface Location (Governmental) 5,040' FSL, 801' FE ec 14, T13N, R9E, UM, AK Surface Location AD 27 — Zone 4 27,889.71 X=533,363.9 Y=027,889.71 Top of Productive Horizon (Governmental) 2090' FSL, 7/FEL, Sec 14, T13N, R9E, UM, AK TPH Location (NAD 27) X=533,424,/69, Y=6,024,939.74 BHL Governmental) 572' FS , 746' FEL, Sec 14, T13N, R9E, UM, AK BHL AD 27) X=5 ,441.96, Y=6,023,422.23 AFE Number 1 3836 AFE Drilling Days AFE Completion Days AFE Drilling Amount AFE Completion Amount AFE Facility Amount Maximum Anticipated Press re (Surface) 1471 psi Maximum Anticipated Pr ssure (Downhole/Reservoir) 1861 psi KB Elevation above SL: 33.7 ft + 25 ft = 58.7 ft GL Elevation above SL: 25 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Version 0 October, 2018 H Hilcrp Energy cgui 2.0 Management of Change Information Hilcorp Alaska, LLC Changes to Approved Permit to Drill Date: October 17, 2018 Subject: Changes to Approved Permit to Drill for MPU M-03 File #: MPU M-03 Drilling Program Any modifications to MPU M-03 Drilling Program will be di an approved APD will be communicated and approved by work. Approval: Milne Point Unit M-03 Drilling Procedure and approved below. Changes to prior to continuing forward with H Hilc ,zotp rp Drilling Manager Date Prepared: Monty M Myers 10.17.2018 Drilling Engineev Date Page 3 Version 0 October, 2018 H Hilcorp 3.0 Tubular Program: Milne Point Unit M-03 Drilling Procedure Cond 20" 19.25" 78.6 A-53 Weld 14-1/2" 10-3/4" 9.95" 1 9.794" 11.25" 1 45.5 L-80 TXP/SR 1 5,210 1 2,470 1 1,040 9-7/8" 7-5/8" 6.875" 1 6.75" 8.5" 1 29.7 L-80 HYD 563 1 6,890 1 4,790 1 683 4.0 Drill Pipe Information: 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 0 October, 2018 n Hileorp En1gy Company Milne Point Unit M-03 Drilling Procedure 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to mmyers@hilcorp.com hilcorp.com, pmazzolininhilcorp.com , ienselnn hilcpM.com and cdinizer@hileorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify ENS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager & Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final "As -Run" Casing tally to mmyers@hilegM.com and edinizerAhilcorp.com 6.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcoEp.com and cdinger@hilcorp.com 6.7 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 ien¢el@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchanAhilcoro.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kflemine@hilcorp.com Safety Manager Chet Starkel 907.777.8344 406.544.7862 cstarkel@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinrer@hilcorp.com Page 5 Version 0 October, 2018 H Hilcorp soggy co�v+or 7.0 Planned Wellbore Schematic a Milne Point Unit M-03 Drilling Procedure Milne Point Unit Well: MPU Moose Pad M-03 PROPOSED SCHEMATIC Last Completed: Proposed PTD: TBD Revised BY UD 10/25/201B Page 6 Version 0 October, 2018 H Hilcorp Enegy Cvmpmy 8.0 Drilling / Completion Summary Milne Point Unit M-03 Drilling Procedure MPU M-03 is a grassroots disposal well intended for produced water/injection.llbore is located on "Moose" pad. The directional plan is a slant well with the kick off point at 433' MDmum hole angle is 68 degrees. Drilling operations are expected to commence approximately De/l st, 2018. Surface casing will be run to 2,800' MD / 2,044' TVD ancemented to surface via a single stage primary cement job. Cement returns to surface will confine TOC a urface. If cmt returns to surface are not observed, a Temp log will be run between 6 —18 Ins after CIP to ermine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling operati ns will be hauled to the Milne Point G&I facility located on `B" pad. General sequence of operations: 1. MOB Doyon 14 to well site 2. N/U 21-1/4" conductor and 3. Drill 14-1/2" hole to TD of 4. N/D diverter, N/U & test 13 5. Drill 9-7/8" hole to TD. 6. Run and cmt 7-5/8" prod ct 7. Run injection tubing. 8. N/D BOP, N/U temp and4 9. Perforate well. iverter line. e hole section. Run and cmt 10-3/4" surface casing. x 5M BOP. casing. Conduct CBL. cap, RDMO. Reservoir Evaluation PI 1. Surface hole: N mud logging�On Site geologist. LWD: GR + ResI , 13 / 2. Production HoV: No mud logging. On site geologist. LWD: Triple Combo+GR + Res 3. Cased Hole L gs: CBL on production string. Page 7 Version 0 October, 2018 H Hilcorp E� C-qwy Milne Point Unit M-03 Drilling Procedure 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the ow AOGCC regulations. If additional clarity or guidance is required on how to comply with a pecific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the d completion of MPU M-03. Ensure to provide AOGCC 24 his notice prior to testing BOP/ • The initial test of BOP equipment will be to 250/3?00 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 5 /o rated WP, 25�si on the high test for initial and subsequent tests). Confirm that these test ressures match those specified on the APD. • If the BOP is used to shut in on the weliawell control situation, we must test all BOP components utilized for well control prhe next trip into the wellbore. This pressure test will be chartedsame as the 14 day BOP tes • All AOGCC regulations within 20 A A C 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system"./ • All AOGCC regulations within ?0 AAC 25.035 "Secondary well control for primary drilling and completion: blowout preventioyl equipment and diverter requirements". • Ensure AOGCC approved d/illing permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance r@guests at this time. Page 8 Version 0 October, 2018 n Hilcorp Enn Company Milne Point Unit M-03 Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 14-1/2" • 21-1/4" 2M diverter (Hydril MSP) w/ 16" diverter line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril NTL Double GateInitial Test: 250/3000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/ 3" x 5M side outlets 9-7/8" 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. • Primary closing hydraulics is provided by an electrical( driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled itrogen. • The remote closing operator panels are located in a doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized o shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to test in Ops. • 24 hours notice prior to case running & cement operations. • Any other notifications req red in APD. Regulatory Contact AOGCC Jim Regg / AOGCC Inspeor / (0): 907-793-1236 /Email: iim.relzg@alaska.gov Guy Schwartz / Petroleu Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guv.schwartz@alaska.g_ov Victoria Loepp / Petrole m Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum ngineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for portunity to witness: AOGCC.Insl2ectors@alaska.gov Test/Inspection notifcation standardization format: hitp://doa.alaska.gov/oizc/forms/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 0 October, 2018 l H Hilcorp 10.0 R/U and Preparatory Work 10.1 Install and cement insulated 20" x 34" conductor. 10.2 Dig out and set impermeable cellar inside existing culvert. Milne Point Unit M-03 Drilling Procedure 10.3 Ensure PTD and drilling program are posted in the rig office and 9,K the rig floor. 10.4 Install slip-on 16-3/4" 3M "A" section. Ensure to orient well ead so that tree will line up with flowline later. 10.5 Insure (2) 3" threaded nipples are installed on opposite des of the conductor with ball valves on each nipple. These will be used to take cement return to the cellar during the surface cmt job, and also to wash out the diverter and hanger in prep ation for running the pack -off. 10.6 Level pad and ensure enough room for layout of,lg footprint and R/U. 10.7 MIRU Doyon #14. 10.8 Mud loggers WILL NOT be used on 10.9 Mix spud mud for 14-1/2" surface 10.10 Set test plug in wellhead prior to accidentally dropped. 10.11 Install 6" liners in mud pt • Continental EMSCO 95% volumetric effic J4 l�.CAW : d-0 . ��C� section. Keep mud cool. diverter to ensure nothing can fall into the wellbore if it is In /r. ,3 :- 1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ Page 10 Version 0 October, 2018 H Hilcorp &m C®P&Y 11.0 N/U 21-1/4" 2M Diverter System Milne Point Unit M-03 Drilling Procedure 11.1 N/U 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic at Sec 20 at back of program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 11.3 Ensure to set up a clearly marked "warning zone" is vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running eqi • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle 11.4 Set 15.375" ID wear bushing in wellhead. 11.5 Rig & Diverter Orientation: only. each side and ahead of the J Page 11 Version 0 October, 2018 H Hilcorp EMU C-k-gy 12.0 Drill 14-1/2" Hole Section Milne Point Unit M-03 Drilling Procedure 12.1 P/U 14-1/2" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135 NC -50 • Run a solid float in the surface hole section. 12.2 Begin drilling out from 20" conductor at reduced flow rates to avy6d broaching the conductor. 12.3 Drill 14-1/2" hole section to section TD. Confirm this se Drilling Engineer while drilling the well. We want to be permafrost. Permafrost base is estimated at 2,246' TMD • Monitor the area around the conductor for any s Stop drilling (or circulating) immediately notify • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigati • Well control procedures and rig eva • Flow rates, hole cleaning, mud co ing epth with the geologist and rox. 200' through the base of the ,850' TVD) coaching. If broaching is observed, Engineer. procedures. etc. • Pump sweeps and maintain mud rheolo/rreens ensure effective hole cleaning. • Keep mud as cool as possible to keep fwashing out permafrost. • Pump at 450-600 gpm. Ensure shaker are set up to handle this flowrate. • Keep swab and surge pressures low • Make wiper trips if necessary. • Ensure shale shakers are functioniq • Adjust MW as necessary to • Take MWD surveys every • Be prepared for GAS HYD encountered on L -Pad tripping. properly. Check for holes in screens on connections. i hole stability. led (95' intervals). ✓ j at the base of the permafrost. However none were / • Do not stop to circulate out as hydrates — this will only exacerbate the problem by washing out additional permafrost./Attempt to control drill (150 fph MAX) through the zone completely and efficient) to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belch)hg over the bell nipple. Consider adding mud products such as Lecithin to allow the gas to break out. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. Page 12 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is > 4. • Do not slide for 100' MD above the base of the permafrost or 100' below the base. We want to leave this transition as undisturbed as possible. 12.4 14-1/2" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. • PVT System: An electronic PVT will be used throughout the dril ' g and completion phase. Remote monitoring stations will be available a/dril s console, Co Man office, and Toolpusher office. • Hydrates: Hydrates have not been encountered on "Ld but be prepared and don't stop to circulate out gas. Control drill when hydntered. • Rheology: Aquagel and Barazan D+ should be us to maintain rheology. Begin system with a 75 YP but reduce this once clays are enco ntered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increa the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L s uld be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BA OFI 3RE/STEELSEALs can be used in the system while drilling the surface inte al to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Ad rtions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the inci ence of bit balling and shaker blinding when penetrating the high -clay content sections f the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the p in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 7 MUST be made to control bacterial action. • Casing Running: Redu6e system YP with DESCO as required for running casing as allowed (do not jeopaydize hole conditions). Run casing carefully to minimize surge and swab pressures. Re46ce the system rheology once the casing is landed to a YP < 20 (check with the ce enters to see what YP value they have targeted). System Type: 8.8 — 9.5 ppg f re -Hydrated Aquagel/freshwater spud mud Properties: Section I/Densi;N Viscosity Plastic Viscosi Yield Point AN Fl. Tem H Surface j 8.8-9.5' 11 75-175 1 20-40 1 25-45 1 <10 <70°F 8.5-9.0 Page 13 Version 0 October, 2018 r n Hilcorp Encs Campmy Milne Point Unit M-03 Drilling Procedure System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 pg PAC -L /DEXTRID LT if required for <10 F ALDACIDE G 0.1 ppb 12.5 At TD; pump sweeps, CBU, and pull a wiper trip bacoto the 20" conductor shoe. 12.6 If hole conditions will not allow theBHA to be p ed out on elevators, prior to initiating backreaming, try to orient motor to high side attempt to pump out to avoid damaging the wellbore. 12.7 Should backreaming be absolutely necess ry to get out of the hole: • Prior to initiating backreaming, ens a at least 3 — 4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (450 — 55 gpm), and maximize rotation. • Pull slowly, '—loft/ minute. • Monitor well for any signs o packing off or losses. • Have the flowline jets hoo d up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced o combat overloaded shakers/flowline, stop back reaming until parameters are restored 12.8 TOH with the drilling 12.9 No open hole logging Page 14 , handle BHA as appropriate. planned. Version 0 October, 2018 %A 0 � CWV&y 13.0 Run 10-3/4" Surface Casing 13.1 R/U and pull 15.375" wear bushing. 13.2 Make a dummy run with the 10-3/4" casing hanger. Milne Point Unit M-03 Drilling Procedure 13.3 R/U Weatherford 10-3/4" casing running equipment. • Ensure 10-3/4" TXP x NC -50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendoj,&model info. 13.4 PIU shoe joint, visually verify no debris inside joint. 13.5 Continue M/U & thread locking shoe track assy consisti of: • (1) Shoe joint w/ float shoe bucked on (thread loc d). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin/enh ead locked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipmpicking up. • Ensure to record S/N's of all float equip stage tool components. 13.6 Continue running 10-3/4" surface casing • Fill casing while running using fill p line on rig floor. • Install (1) centralizer across coup ngs on each joint. • Utilize a collar clamp until wei tis sufficient to keep slips set properly. • Any packing off while runni casing should be treated as a major problem. It is preferable to POH with casing and co ition hole than to risk not getting cmt returns to surface. 10-3/4" 45.5#j'L-80 TXP Make Up Torques: Casing OD 71 Min M/U Torque Max M/U Torque 10-3/4" Lj 20,370 ft -lbs 24,890 ft -lbs Page 15 Version 0 October, 2018 n Hilcorp E.n C.pwy Milne Point Unit M-03 Drilling Procedure 13.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.8 Slow in and out of slips. 13.9 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 13.10 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 13.11 Have emergency slips ready to go in the event we cannot land the 13.12 R/U circulating equipment and circulate B/U. Reduce YP to <20/6 help ensure success of cement job. Ensure adequate amounts of cold M/U water are a Table to achieve this. Elevate hanger slightly above hang off point while circulating to avoi plugging the flutes. 13.13 After circulating, lower string and land hanger in wellhegei again. Page 16 Version 0 October, 2018 r Milne Point Unit M-03 Drilling Procedure Hilcorp Energy Company For the latest performance data, always visit our website: w ew.tenaris.com TXP® BTC 10/17/2018 Outside Diameter 10.750 In. Min. Wan 90.5% Thickness CI Battle Lw 6e Typo 1 Wall Thickness 0.400 It. Donroacbed GD REGULAR COUPLWG PPE BODY Option Body. Red let Band: Rod Grad. Lw TypoV Drift AN Standard 1st Banc: Brown 2nd Band. 2nd Band'. - Brown Type casing 3rd Band: - 3rd Band' - 41h Band PIPE BODY DATA GEOMETRY Nominal OD 10.150 n. Nominal Weyn 45.5 moll Nit 9.794M. Noemal lD 9.950 m. Wail Thkknev 0.00m Main End Ween 4425 matt OD Toldmme API PERFORMANCE Body yield stiog:h Cdlapse 1040a10001ta 2470 psi Intemal Yield 5310 psi SMYsw)))psi CONNECTION DATA GEOMETRY Lonnedion 00 Makeupt.es 11.790 in. 4A91 m. Coupling Length Threads der in 10A25m. 5 ID Co.w. 000ptmn SAN in. REGULAR PERFORMANCE T«Kron Eemiwmy nnmwcsagn Elf.., Ealemal Pmssur.CaMiy 190.0% 100% 2420.000 peri hint Yield Sbenglh ccvnaessun Sae"m 1 .oaoalWo 10,10,0000M Imemai Preasurecapacty:" 5210.090pei U-11MR MAKE-UP TORQUES Maim um 303200 -IM Optimum nm ods Maximum 24990 nobs OPERATION LIMfT TORQUES CaemWg Tomue 3T20U h4M Yield Twe 4540)Rms Notes This connection is fully interchangeable wi TXP9p BTC - 10.75 in. - 40.51 1 lbs/8 ill Internal Pressure Capacity related t structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3 f ISO 10400 - 2007. Datasheel is also valid for Special vel option when applicable - except for Coupling Face Load, which will be reduced. Please contact a local T aris technical sales representative. For further information on concepts indicated in this datasheet, download the Datasheet Manual from www.tenads.com Tare nn.saod lNadmummi roc vanaaro«mavn«yv and me mm�nauon in nes nmamwn. ex9.ery Wlrwlkmexan. a^r od«na. aam�ga«mag+arw«mamn'I u is nlmaca manamumwnleaamal «.+v ovwvryoc d emu «rtomm«nwn am u wnvdea nn an'nn i.. tinea ne warrant ie D+e^. T«wa tea Yid �«lep«idenW ve�rtedw+rnwmmm�a am worded er loo tier«nrannmmn ww.«r«arc wapox m. vm h+o lnoncom. cd nem�nd�,.Tm eu otme mmmwonnnuxv.oan rM aM ierxvuhea M asaeme wryr.epmsW�ry oro bkyetalY kvq M an% bts. Aimi9e a �n«r resuaug hen. «n mmemenwTrany M«mTm cmtaned MnuMn Page 17 Version 0 October, 2018 V Milne Point Unit M-03 Drilling Procedure Hilcorp F� C.VA" 14.0 Cement 10-3/4" Surface Casing 14.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 14.4 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug. Mix and pump cmt per below calculations. 14.8 Cement volume based on annular volume + 10� pen hole excess. Job will be pumped in a single stage, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (113) Conductor x 10-3/4" casing: 113 x 0.24 bpf = 28 bbls 157 ft3 14-1/2" OH x 10-3/4" casing: (2800'- 113') x 0.09198 bpf x 2 = 494 bbls 2775 ft3 10-3/4" Shoe track: 90 x .09617 bpf = 9 bbls 51 ft3 Total: 531 bbls 2983 ft3 Page 18 Version 0 October, 2018 -2-'-p S¢ R Hilcorp EMV C=VwW Cement Slurry Design: Milne Point Unit M-03 Drilling Procedure 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. 14.11 Ensure rig pump is used to displace cmt. Displacement calcs have proven to be very accurate using 0.101 bps for pump output. 14.12 Displacement calculation: -1 o `k 2710' x .09617 bpf = 261 bbls total 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 3 bbls before consulting with drilling engineer. 14.15 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. 14.16 Be prepared for cement returns to -yt ,dace. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 19 Version 0 October, 2018 W,y IV Slurry System SwiftCEM'" System Density 15.8 Ib/gal 7 Yield 1.16 ft3/sk Mixed Water 5.04 gal/sk 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. 14.11 Ensure rig pump is used to displace cmt. Displacement calcs have proven to be very accurate using 0.101 bps for pump output. 14.12 Displacement calculation: -1 o `k 2710' x .09617 bpf = 261 bbls total 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 3 bbls before consulting with drilling engineer. 14.15 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. 14.16 Be prepared for cement returns to -yt ,dace. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 19 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure Hilcorp 14.17 Flush out BOP, and clean out above hanger. Remove landing joint. 14.18 MAJ pack -off running tool and pack -off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 14.19 Lay down landing joint and pack -off running tool. Ensure to report the following on WellEz: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run" casing rally & casing and cement report to mmyers&hilcorp.com and cdinVr@hilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 20 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure Hilc Eoe ,27 15.0 BOP N/U and Test 15.1 N/D the diverter & N/U 11" 5M tubing spool. 15.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from Top down: 13-5/8" x 5M annular / 13-5/8" x 5M Double gate / 13- 5/8" x 5M mud cross / 13-5/8" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should also be dressed with 2-7/8" x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. y ` 15.3 Run 5" BOP test assy, land out test plug (if not installed previously). G • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave `B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes: 5" for DP workstring 5-1/2" for liner and injection tubing. 15.4 R/D BOP test assy. 15.5 Keep spud mud in pits for intermediate hole section. 15.6 Set 10" ID wearbushing in wellhead. 15.7 Rack back 5" DP in derrick. 15.8 Keep 6" liners in mud pumps. Page 21 Version 0 October, 2018 PAP H Hilcorp cow c2x 16.0 Drill 9-7/8" Hole Section 16.1 P/U 9-7/8" directional BHA. Milne Point Unit M-03 Drilling Procedure • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure MWD is RAJ and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Install ported float in the BHA. 16.2 9-7/8" hole section mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. • 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. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • MD Toteo 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: 8.8 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties;--�_ De the Dens' Plastic Viscosity Yield Point LGS MBT HPHT PH ntermedi e 1 8.8-9.5 15-25 15-20 <6% <20 <11.0 9-10 M roduct Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.5 ppg PAC -L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb Page 22 Version 0 October, 2018 Milne Point Unit M-03 Drilling Procedure Hilcorp EMW C-nwy 16.3 TIH w/ 9-7/8" directional assy. 16.4 Note depth TOC tagged on AM report. 16.5 R/U and test casing to 2600 psi / 30 min. Ensure to record volume /pressure and plot on FIT graph. AOGCC reg is 50% of burst = 5210/2 =-2605 psi. Test pressure for the well is 2600 psi. 16.6 Drill out shoe track and 20' of new formation. 16.7 CBU and condition mud for FIT. 16.8 Conduct FIT to 12.5 ppg EMW. 16.9 Drill 9-7/8" hole section to section TD per Geologist and Drilling Engineer. • Pump at 450-550 gpm. • 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. • Pump high viscosity sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips if necessary. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. 16.10 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the casing shoe. If backreaming is necessary: • Circulate at full drill rate (450 — 550 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 16.11 TOH with the drilling assy, L/D or handle BHA as appropriate. 16.12 No open hole wire line logs are planned. Page 23 Version 0 October, 2018 H Hilcorp Milne Point Unit M-03 Drilling Procedure 17.0 Run 7-5/8" Intermediate Casing with stage collar 17.1 Pull wear bushing. Install and test 7-5/8" casing rams in upper ram cavity to (250/3000 psi). 17.2 R/U 7-5/8" casing running equipment. • Ensure 7-5/8" HYD563 X NC50 crossover is on rig floor and WU to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. • R/U CRT if available. 17.3 M/U & threadlock shoe track assy consisting of: • (1) Float shoe joint w/ float shoe bucked on. Install (1) solid body centralizer free floating on joint. • (1) Baker locked joint. Install (1) solid body centralizer leave free floating. • (1) Float collar joint w/ float collar bucked on pin end. Install (1) free floating solid body centralizer. • Ensure bypass baffle is correctly installed on top of float collar. This end up. -, Bypass Baffle • Ensure proper operation of float shoe and float collar. 17.4 Run 7-5/8" 29.7# L-80 HYD563 casing. • Fill casing while running using CRT or fill up line. • Use "BOL 2000" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 17.5 P/U ES cementer 900' from surface (+/- 21 jts) and MU in the casing string. Port collar opening tool will be staged on the rig floor to accelerate make up to drill pipe should cement not be circulated to surface. Page 24 Version 0 October, 2018 n Hilcorp Milne Point Unit M-03 Drilling Procedure Place Halliburton ES cementer at 5500' TMD in 7-5/8" string Install centralizers over couplings on 3 joints below and above stage tool. Do not place tongs on ES cementer, this can cause damage to the tool. Ensure tool is pinned with 6 opening shear pins. There are 6 holes, the tool is normally sent with only 4 pins installed. This will allow the tool to open at 3300 psi. Install centralizers on every joint to 2800' MD. No centralizers required above that. 17.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 17.7 Slow in and out of slips. Bypass or Shut-off Baffle ID Depth Foal Cd m Depth Float Shoe Depth Hole To •Welmmce C., S.W. Nlitr" uekes Page 25 ..A 0.ae1 Lerpat B Mn. IDAMr Drllan C Mv. ToeIOD D Dpenala Seelb E [beim Sew ID Plug Set Part No. so No. Closing Plug Opening Plug OD OO ShutM plug OD Bypass Plug (N uxg) OD Version 0 MkwpENlawwlrydeLa FSa<wnwaer BaMeneaCtw L?�Xx� ByDm GMe float Collo fbwgwe October, 2018 Type H ES Cementer Part No. SO No. -E— Closing Sleeve Pi No. Shear ns D Opening Sleeve C No. Shear Pins ES Cementer — B Depth Baffle Adapter (if used) ID Depth Bypass or Shut-off Baffle ID Depth Foal Cd m Depth Float Shoe Depth Hole To •Welmmce C., S.W. Nlitr" uekes Page 25 ..A 0.ae1 Lerpat B Mn. IDAMr Drllan C Mv. ToeIOD D Dpenala Seelb E [beim Sew ID Plug Set Part No. so No. Closing Plug Opening Plug OD OO ShutM plug OD Bypass Plug (N uxg) OD Version 0 MkwpENlawwlrydeLa FSa<wnwaer BaMeneaCtw L?�Xx� ByDm GMe float Collo fbwgwe October, 2018 K H11C0� emo war Milne Point Unit M-03 Drilling Procedure 17.8 PU casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. The 7-5/8" casing packoff with the running tool will also be staged on the rig floor. 17.9 Lower string and land out in wellhead. Confirm measurements to indicate the hanger has correctly landed out in the wellhead profile. 17.10 Have emergency slips ready to go in the event we cannot land the hanger. 17.11 RAJ circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 17.12 After circulating, lower string and land hanger in wellhead again. 7-5/8" HYD 563 Estimated NIX torques Casing OD Torque (Min) Torque (Max) Torque (Yield) 7-5/8" 8,600 ft -lbs 15,100 ft -lbs 45,000 ft -lbs Page 26 Version 0 October, 2018 H Hilmwhonk, Company For the latest performance data, always visit our website: www.lenaris.com Wedge 563® Outside Diameter 7.U5 In. Min. Wall 3.29 (') Grade L80 Thickness Wall Thickness 0.375 in. Conrwcllon OO REGULAR option Grade L.BU Type 1' Drat 683.000x1000 Ito 683.000x1000 tic 4550011 his Body Red Type Milne Point Unit M-03 Drilling Procedure mti.�... 10/19/2018 87.5% 4.050 m. Lhreada per m 3.29 (') Grade L80 sow PERFORMANCE Type 1 REGULAR Tension EOirianry Cornpresslon Eeiounq External pressure Capeciy COUPLING PPEBOGY 683.000x1000 Ito 683.000x1000 tic 4550011 his Body Red 1st Band Red AN Standard 1st Band: Brown 2no Band: 2nd Band: - Brown casing 3rd Band: - and Band: - 1030001es Maximum 41h Band - PIPE BODY DATA GEOMETRY Nominal OD 7.635 in. Nominal Weight 29.70 Meth No 6.75in. Nomloal to 6.075 in. Wall Thickness 0.375 in. Rain End Weight 29.06lo ft OD Tolerance API PERFORMANCE Body YIed Stoemp 683 s1000 to, Internal Y,eld 6690 psi SMYS 60000 y1 Collapse 4700 psi CONNECTION DATA GEOMETRY Connec4w, OD 0.5001n. Couyl�ng Length 9.25 m. Connecton lD 6.075 In, Makeup Loss 4.050 m. Lhreada per m 3.29 Connecsun 00 option REGULAR PERFORMANCE Tension EOirianry Cornpresslon Eeiounq External pressure Capeciy 100.0% 100.0% 4790.000 psi Joint Y kstrength Congression socngtn Coupkrq Face Lead 683.000x1000 Ito 683.000x1000 tic 4550011 his Internal pressure Capaay Max. Alkosado Bonding 6890.000 psi 48 'It 00A MAKE-UP TORQUES Minimum 860011.25 OpSmum 1030001es Maximum 151001:405 OPERATION LIMIT TORQUES Opera"Toque 38000 Roos Yield Torque 45000 hoes BUCK -ON Minimum 146008des McAnum 1650004es Notes This connection is fully interchangeable with: Wedge 5530- 7.625 in. - 29.7 Ibsi t Wedge 5638 - 7.625 in. - 26.4 / 33.7 lbs/ft Connections With Dopeless® Technology are fully compatible with the same connection in its Standard version For further information on concepts indicated in this datasheet, download the Datasheet Manual from www.tenaris.com Page 27 Version 0 October, 2018 18.0 Cement 7-5/8" Casing (2 -stages) Milne Point Unit M-03 Drilling Procedure 18.1 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. • How to handle cement returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cement operatio . • Document efficiency of all possible displacement pumps prior to ceme job. 18.2 Flush through cement pump and treating iron from pump to rig floor t the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 18.3 R/U cement head (if not already done so). Ensure top and bottgm plugs are loaded correctly. 18.4 Pump 5 bbls 10.5 ppg spacer. Close low torque on plug drgpping head, test surface cement lines to 4000 psi. 7 18.5 Pump remaining 35 bbls 10.5 ppg spacer. 18.6 Drop bottom plug (flexible bypass plug) — HEC calculations for the 1 st stage, confirm actual cer 18.7 Cement volume based on annular volume + Estimated I" to witness. Mix and pump cement per below volumes with cementer after TD is reached. open hole excess. Cement Volume: Section: alculation: Vol Vol (BBLS) (ft3) TAIL: 912' x.03825 bpf x 1.5 = 52 292 9-7/8"OH x 7-5/8"csg: TAIL: 90 x .04591 bpf = 4 23 7-5/8" Shoe track: Total TAIL: 56 315 Page 28 Version 0 October, 2018 .1-0 H Hilcorp Enc ,2x Milne Point Unit M-03 Drilling Procedure Cement Slurry Design (1" stage cement jobs): System BondCem Density 14.91b/gal Yield 1.315 ft3/sk Mix Water 6.160 gal/sk Expected 5:00 Thickening Time Expected ISO/API <50 cc/30min Fluid Loss 18.8 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: G.-" • 5,500' x .04591 bpf= 252 bbls. Lg0D a .0 f 20 69" 18.9 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. 18.10 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —3.3 bbls before consulting with drilling engineer. 18.11 If the plug is not bumped, consult the drilling engineer. Ensure the free fall stage tool opening plug is available if needed. This is the backup option to open the stage tool if the plugs are not bumped. 18.12 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. 18.13 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 18.14 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cement. Page 29 Version 0 October, 2018 n Hilcorp EneW Company i D Milne Point Unit M-03 Drilling Procedure Second Stage Cement Job: 18.15 Prepare for the 2nd stage as necessary. Circulate until 1 stage reaches sufficient compressive strength. Hold pre job safety meeting. 18.16 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 18.17 Fill surface lines with water and pressure test. 18.18 Pump 60 bbls 10.5 ppg tuned spacer. 18.19 Mix and pump cement per below recipe for the 2nd stage. 18.20 Cement volume based on annular volume + open hole excess (30% for lead and 20% for tail). TOC will be brought to 4,000' TMD. q Estimated 2"d Stage Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: s (5,500'- 4,000') x.03825 bpf x 1.3 75 421 9-7/8" OH x 7-5/8" csg: TAIL: 500' x .03825 bpf x 1.2 23 129 9-7/8"OH x 7-5/8"csg: 7-5/8" Shoe track 120' x .04591 6 34 Total Cement: 104 584 Cement Slurry Design (2nd stage cement job): 18.21 After pumping cement, drop ES Cementer closing plug and displace cement with drilling mud out of mud pits. Page 30 Version 0 October, 2018 q, I Lead Slurry Tail Slurry System VariCem SwiftCEM " System (Hal Cem) Density 12.51b/gal 15.8 Ib/gal Yield 1.997 ft3/sk 1.16 ft3/sk Mixed Water 11.024 gal/sk 5.08 gal/sk 18.21 After pumping cement, drop ES Cementer closing plug and displace cement with drilling mud out of mud pits. Page 30 Version 0 October, 2018 q, I n HilcOrp E.a Compmy 18.22 Displacement Calculatio : /r Z` / E' Milne Point Unit M-03 Drilling Procedure 5,500' x . 5 bpf = �,' bbls mud o is`1 ,ZT�2- 18.23 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 some sacks of sugar available to retard setting of cement if it is necessary to displace cement out of hole. 18.24 Land closing plug on stage collar and pressure up to 1000 —1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Set slips and back out and cut joint. 18.25 Flush out wellhead with FW and BOP stack thoroughly to ensure cement, mud and cuttings are removed. 18.26 M/U pack -off running tool and pack -off to bottom of Landing joint. Set casing slips packoff. Run in lock downs and inject plastic packing element. Pressure test t/ 2450 psi. 18.27 Lay down landing joint and pack -off running tool. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping ofjob. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Page 31 Version 0 October, 2018 H Hilcorp Enn C2mix 19.0 Wellbore Clean Up & Displacement Milne Point Unit M-03 Drilling Procedure 19.1 M/U casing clean out assy complete with 7-5/8" casing scraper assys. • 6.75" bit or mill. • Casing scraper for 7-5/8" 29.7# casing. • +/- 500' 5" DP. • Casing scraper for 7-5/8" 29.74 casing. • 5" DP to surface. 19.2 TIH & clean out well to ES cementer (+/- 5,500' MD). • Circulate as needed on trip in if string begins to take weight. p • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. V� 19.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 3400 psi / 30 min. 19.4 Displace drilling fluid in wellbore with a hi -vis pill followed by fresh water. • Consider catching drilling fluid in rain -for -rent tanks for use on a future well if feasible. • Circulate fresh water into wellbore until clean-up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the 7-5/8" scraper to surface. • Pump a chemical train followed by clean water. 19.5 TOH w/ clean out assy. LDDP on the trip out. Note any abnormal wear on the clean out assy. Page 32 Version 0 October, 2018 I ( Milne Point Unit M-03 Drilling Procedure Hilcorp 20.0 Completion Operations �-� 20.1 R/U e -line unit and run a CBL across the 7-5/8" liner. R/D e -line unit. �n 20.2 RAJ and run 4-1/2" x 5-1/2" tubing assembly, including nipple profile, production packer and WLEG. • Ensure appropriate well control crossovers on rig floor and ready. 20.3 Makeup the tubing hanger and landing joint. 20.4 Land hanger. RILDs and test hanger (500/5000 psi). Make note of actual weight on hanger on morning rpt. 20.5 Freeze protect IA and Tubing. 20.6 Drop ball and rod and set packer 20.7 Test the tubing to 3500 psi for 30 minutes. Monitor tubing to identify any packer leaks. Record and note all pressure tests on chart. 20.8 Install BPV 20.9 ND BOPE 20.10 NU Tree & Pressure test to 5000 psi. 20.11 RDMO Doyon 14 21.0 Well Perforation: 21.1 R/U e -line unit and wireline BOPs. 21.2 Perforate well. 21.3 R/D eline unit and BOPS. A p C,,C- �o Page 33 Version 0 October, 2018 Colombie, Jody J (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, December 4, 2018 7:49 AM To: Colombie, Jody J (DOA) Subject: FW: PTD 218-109 Verval for Frac Sundry Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@alaska.aov). From: French, Hollis (DOA) Sent: Sunday, December 2, 2018 4:12 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: Re: PTD 218-109 Verval for Frac Sundry Approve From: Schwartz, Guy L (DOA) Sent: Sunday, December 2, 2018 4:03:48 PM To: French, Hollis (DOA) Subject: FW: PTD 218-109 Verval for Frac Sundry Hollis, Can you look at this and authorize a verbal. Have not heard back from Dan. They are ready to go. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwariz@alaska aov). From: Schwartz, Guy L (DOA) Sent: Sunday, December 2, 2018 2:50 PM To: Seamount, Dan T (DOA) <dan.seamount@alaska.aov> Cc: Davies, Stephen F (DOA) (steve.davies@alaska.gov) <steve.davies@alaska.eov>; Wallace, Chris D (DOA) <chris.wallace@alaska.gov> Subject: PTD 218-109 Verval for Frac Sundry Dan, Hilcorp is also ready to frac this well ... brand new Kuparuk well so as usual we are on a short time line. Steve, Chris and I have reviewed the program and data. I talked with Steve this afternoon and we are in agreement that the well is adequately vetted and that it can go ahead. If the office is closed tomorrow it will need a verbal to go ahead. They have been waiting since yesterday. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without First saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ( or (Guv.schwartz@olaska.aov(. Schwartz, Guy L (DOA) From: Seamount, Dan T (DOA) Sent: Sunday, December 2, 2018 5:17 PM To: Schwartz, Guy L (DOA) Cc: Davies, Stephen F (DOA); Roby, David S (DOA) Subject: Re: Verbal approval for PTD 218-140 Ok Sent from my Whone On Dec 2, 2018, at 2:14 PM, Schwartz, Guy L (DOA) <guy.schwa rtz@a laska.Rov> wrote: Dan, Verbal approval is requested to proceed with drilling M-03. This is a class II disposal well. It will have to conform with DID 42 once that is finalized. The rig is on site... The will be ready to spud tonight. Steve, Dave and I have vetting the drilling program and it is good to go. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. It you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793- 1226) or (Guv.schwariz@olaska.aov). <M-03 PTD 2118-140.pdf> Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Thursday, November 29, 2018 12:02 PM To: Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL] M-03 disposal well ( PTD 218-140) Attachments: Milne Point Unit M-03 Drilling Program Rev 1.pdf Follow Up Flag: Follow up Flag Status: Flagged I made the changes to the drilling permit. Please see attached and answers below. I changed it to a single stage cement job for the production hole. Eliminated the ES cementer and spotted abandonment plugs below the casing shoe of the 7-5/8" casing. Let me know if you have questions Monty M Myers Drilling Manager 907.538.1168 (c) 907.777.8431 (o) From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday, November 26, 2018 9:46 AM To: Monty Myers <mmyers@hilcorp.com> Subject: [EXTERNAL] M-03 disposal well ( PTD 218-140) Monty, A couple of questions: 1. Why are you using 15.8 ppg cement in the surface casing? this is not standard for the permafrost area. Changed it on page 19 2. In lit stage of 7 5/8" (step 18.8) the displacement depth is listed at 5500 ft which the ES depth ......shouldn't this be the float collar depth at about 6400 ft? Removed the ES cementer 3. In the 20d stage of the 7 5/8" the TOC calculates out to be 3500 ft if pumped as per your plan . Can you check this ? On page 30.. step 18.20 Now a single stage job 4. In step 18.22 the displacement volume should be 5500 x.0459 bpf = 252 bbls ( looks like 7" was used ) You are correct — had a typo, Fixed on page 29 5. 1 did not see where you were freeze protecting the OA( 7 5/8 x 10%" ) after pumping the 2nd stage cement. Added it as 18.19 6. Will need a separate sundry to perforate the well and forward the CBL results to AOGCC. Made a note on page 32 21.1 7. The X mile review map shows no wells within the area. Can you state that in writing... Added a note on page 7 We are still finalizing DIO 42 wording. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONNDENTIAUTY 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 if to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.aov(. Davies, Stephen F (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Monday, November 12, 2018 4:08 PM To: Schwartz, Guy L (DOA); Davies, Stephen F (DOA) Cc: Monty Myers Subject: HAK MPU M-03 (PTD: Pending) Formation Information Attachments: Milne Point Unit M-03 Drilling Program Rev 0 -Formation Tops page 38.pdf Guy/Steve — We realized we did not include estimated formation pressures on our formation top/information section of the PTD/program for M-03. Please find the attached updated section, including formation tops and pressures. Please let me know if you have any questions. Thank you for your time. Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 AOGCC PTD No. 218-140 Coordinate Check 25 October 2018 INPUT Geographic, NAD27 OUTPUT State Plane, NAD27 5004 -Alaska 4, U.S. Feet MPU M-03 1/t Latitude: 70 29 14.02400 Northingly: 6027889.726 Longitude: 149 43 38.28500 EastinglX: 533363.884 Convergence: 0 15 25.33301 Scale Factor: 0.999901264 Remark: Corpscon v6.0.1, U.S. Army Corps of Engineers TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: Development i Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: HL b (ri POOL: I( 4 Gl l�(1� d �TyV5;k Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50 - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - -� from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Com an Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals throu target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements / Per Statute AS 31.05.030(d)(2�'(B) and ReVgulation 20 AAC 25.071, ✓ composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 7' WELL PERMIT CHECKLIST Field & Pool MILNE POINT, UNDEFINED WDSP - 525036 PTD#:2181400 Company _F IILLC_ORP ALASKA LLC_ Initial Class/Type Well Name: MILNE PT UNIT M-03 Program SER Well bore seg ❑ iER / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal El Administration 17 Nonconven, gas conforms to AS31,05,030(j.1.A),(j,2.A-D) _ _ _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ..... _ ........... 1 Permit fee attached _ _ _ _ _ _ _ _ _ _ _ _ _____ _ _ _ _ _ _ _ _ _ _ _ _ . NA. .............. 2 Lease number appropriate... . . .. . . . . . . . . ................. . . . . Yes _ _ _ _ _ - Entire Well lies within ADL0025514.. 3 Unique well. name and number _ _ . ..... _ _ _ . Yes .. First well drilled from Moose Pad. Conoco's existing M-01 and M-01A wells were drilled. from a separate site. 4 Well located in a. defined pool _ _ _ _ _ _ . - . _ - _ _ _ _ _ _ _ _ _ _ _ _ ___ _ ___ No....... - Ugnu undefined waste disposal pool. See DIO 42.. 5 Well located pmperdistance from drilling unit boundary. - - - _ _____ _ _ _ _ _ _ _ _ _ _ _ Yes 6 Well located proper distance_ from other wells_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ______ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ _ 7 Sufficient acreage available in drilling unit. .. _ _ .. _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 8 If deviated, is wellbore plat included _ _ _ _ _ _ _ - - _ _ - _ Yes 9 Operator only affected party.. - - - _ - - - _ - _ _ _ _ Yes 10 Operator has appropriate bond in force _ _ _ _ _ _ _ _ _ _ _ _ _ _ ... _ _ Yes_ Appr Date 11 Permit can be issued without conservation order_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .. No. 0I0-42issued October 24, 2018. 12 Permit can be issued without administrative approval - Yes 11/13/2018 13 Can permit be approved before 15-day.wait. _ _ _ _ _ _ _ _ _ _ YES 14 .Well located within area and strata authorized by Injection Order # (put -ID# in.comments) (For Yes _ _ DIO-42 issued October 24, 2018___ 15 All wells.within 1(4-mile area of review identified (For service well only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ Simpson Lagoon 32-14, 32-14A, MPU M-01,. M-01A . . 16 Pre-produced Injeolor; duration of pre-production less than 3 months (Fpr service well only) - - No_ .. ........................ . . . . . . . . . . 18 Conductor stringprovided_ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - Yes _ _ _ _ - 20" conductor setat107 ft - - - - - - - Engineering 19 Surface casing protects. allknown USDWs . _ _ _ ...... _ _ - - _ NA No aquifers ............. . 20 CMT vol. adequate to circulate on conductor & surf.esg _ _ _ _ _ _ _ _ _ _ _ _ _ ___________ Yes 21 CMT vol adequate. to tie-in long string to surf csg......... ..... . . . . . . . . . . . . . Yes _ 7 5/8" casing will be cemented to 400 ft, MD 22 CMT will cover all known productive horizons Yes ... TD at 6400 ft and set plug. across $8.. Set casing-at 55001t.. 23 Casing designs adequate for C, T, B A. permafrost. - - - - . . ............... Yes 24 Adequate tankage-or reserve pit _ _ ___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ____ _ _ _ _ _ Yes _ _ _ - Rig has steel pits,..- all-waste to approved disposal well. 25 If a. re-drill, has.a 10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ ___ NA. 26 Adequate wellbore separation proposed _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes ... Close crossing with MPU M-23i at about 1100 ft_md 27 if.diverter required, does it meet regulations _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Appr Date 28 Drilling fluid program schematic & equip list adequate _ _ _ _ _ _ ..... Yes _ _ _ - Max form. Press= 1861 psi (9.2 pp-9. EMW) will drill production hole with-8.9-9.5 DRS mud (_I S 11/29/2018 29 BOPEs, 0 they meet regulation _ _ _ _ _ _ _ - - - Yes _ - Doyon 14 has 135/8" 5000 psi -BOPE. 30 BOPE-press rating appropriate: test to _(put psig irlcomments)___ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes _ MASP = 1471psiWill test BOPE to 3000 psi .. _ ................. .. _ . 31 Chokemanifoldcomplies w/API RP-53 (May 84). - - - _ _ _ - - _ _ _ _ _ _ _ _ _ _ Yes ________ 32 Work will occur without operation sbutdown- - - - - - - - - - - - - ..... _ Yes _ _ _ _ - Sundry _required to perforate Well, .Must have witnessed MIT-IA-after startup.. 33 Is presence. of H2S gas probable _ _______ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _____ Yes _ _ _ H2S in area. Must have sensors and alarms functioning.... , ..... - .. 34 .Mechanical.00ndiffon of wells within AOR verified (For service well only) . . . ........... Yes _ the well will inject high volume,.., well must be operated in acooA with 010 42 35 Permit can be issued w/o hydrogensulfidemeasures _______ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ None observed in offset wells. Rig will have functioning, automatic detectors.. ..... Geology 36 Datapresented on potential overpressure zones _ ...... _ _ _ _ _ _ _ _ Yes ... Planned mud program appears adequate to control operator's forecast formation pressures... _ Appr Date 37 Seismic analysis of shallow gas. zones . . . . . . . ...... NA... SFD 11/13/2018 38 Seabed condition survey.(if off-shore)___ _ _... NA ........ _________.__._..__...._..._... 39 Contact name/phone for weekly progress reports_ [exploratory only] NA Geologic Engineering Date Public Date Well must operate in accordance with DIO 42. Date: Commissioner: t Commissioner: Co
