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Home My WebLink About218-165STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS ;HVED JAN 0 2 2020 1. Operations Abandon LJ Plug Perforations Li Fracture Stimulatdi Pull Tubing Ll AWGGwn Ll Performed: Suspend ❑ Perforate ❑ Other Stimulat Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Wel❑ Re-enter Susp Well ❑ Other: Forward Circulating JP ❑� 2. Operator Hilcorp Alaska LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development Q Stratigraphic❑ Exploratory ❑ Service ❑ 218-165 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-029-23617-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL025514, ADL388235, ADL025515 MILNE PT UNIT M-10 9. Logs (List logsand submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A MILNE POINT / SCHRADER BLUFF OIL 11. Present Well Condition Summary: Total Depth measured 15,082 feet Plugs measured N/A feet true vertical 4,047 feet Junk measured N/A feet Effective Depth measured 15,082 feet Packer measured 5,885 & 6,486 feet true vertical 4,047 feet true vertical 3,881 & 3,984 feet Casing Length Size MD TVD Burst Collapse Conductor 106' 20" 106' 106' N/A N/A Surface 6,650' 9-5/8" 6,650' 3,999' 5,750psi 3,090psi Production 6,493' 7" 6,493' 3,985' 7,240psi 5,410psi Liner 8,596' 6-5/8" 15,082' 4,047' N/A N/A Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / L-80 / EUE 6,520' 3,988' 7" x 3.5" HES PHIL Packers and SSSV (type, measured and true vertical depth) SLZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 864 175 0 3,442 316 Subsequent to operation: 1 905 322 0 3,434 277 14. Attachments (requimd per20 AAC 25.070, 25.071, &25.283) 15. Well Class after work: Daily Report of Well Operations ❑� Exploratory❑ Development ❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑' Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-359 Authorized Name: Chad Helgeson Contact Name: David Haakinso / Authorized Title: Operations Manager Contact Email: dhaakinSon(olihilcorq.cor Authorized Signature: r%,C1-W R&I „` Date: 12/30/2019 Contact Phone: 777-8343 Form 10-404 Revised 4/2017 /— P ar-C' ARDMS and o i mn Submit Original Only H Hileoiy Alaska, LLC December 30, 2019 Re: Summary of Operations for MPU M-10 (Sundry # 319-359) 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8301 Hilcorp Alaska, LLC (HAK) successfully completed a test of a forward circulatingjet- pump system within the existing tubular completion installed in MPU M-10. The results proved successful in reducing emulsions and proved up mechanical success of converting a typical MPU reverse jet -pump completion to forward circulating jet pump without a rig-workover. After the test was completed, the well was returned to the previous operating state with a reverse circulating jet pump with all surface safety systems in place. A production chemical solution has been found to effectively treat the emulsion and the forward circulating jet pump is not needed at this time. If you have any additional questions concerning this request, please contact me at 777- 8343 or by email at dhaakinson@hilcorp.com. Sincerely, Daakinson Operations Engineer Hilcorp Alaska, LLC Hilcorp Alaska, LLC HWeekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP M-10 Slickline 50-029-23617-00-00 1 218-165 11/24/2019 11/29/2019 11/20/2019- Wednesday No operations to report. 11/21/2019 - Thursday No operations to report. 11/22/2019 - Friday No operations to report. 11/23/2019 -Saturday No operations to report. 11/24/2019 -Sunday WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,500H. PULL 3" JET PUMP (serial# BP -1200, ratio: 11D) FROM XD -SS AT 5,783' SLM/5,802' MD. (lost 1 nubbin from lock, recovered all packing but 1 stack torn from nubbin). SET FORWARD CIRCULATING JET PUMP (ratio: E:11) (No serial#) IN XD -SS AT 5,783' SLM/5,802' MD. RDMO, TAG WELL, CLOSE PERMIT W PAD -OP. 11/25/2019 - Monday Rig up temporary normal flow hardline and piping as per TMOC, FCO function tested all safety system components for operation. Well was put on production 11/25/19 at 09:00pm. 11/26/2019 -Tuesday No operations to report. Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP M-10 Slickline 50-029-23617-00-00 218-165 11/24/2019 11/29/2019 11/27/2019 - Wednesday No operations to report. 11/28/2019 -Thursday T/1/0=3460/350/0 Pump Power Fluid (Experiment) (PT surface lines 250/4,000 psi) Pump 381 bbls source water down tbg as power fluid support. Pump 2 bbls 60/40 to flush surface equipment FWHPs=vac/350/0. 11/29/2019 - Friday. WELL S/I ON ARRIVAL, OPEN PERMIT W/ DSO, PT PCE 250L/2,500H. PULLED FORWARD CIRCULATING JET PUMP FROM 5,783' SLIM (5,802' MD), (ALL PINS & PACKING RECOVERED). LRS PUMPED SOBBLS HOT DIESEL. SET 2.813" X -LOCK, 3" JET PUMP W/ SCREEN (SER# BP -1200, RATIO 11D) @ 5,783' SUM (5,802' MD). WELL S/I ON DEPARTURE, DSO NOTIFIED. T/1/0=vac/vac/0 Assist Slickline (Set Jet Pump) (PT surface lines 250/2500 psi) Displace tbg with 50 bbls hot diesel 11/30/2019 -Saturday No operations to report. 12/1/2019 -Sunday No operations to report. 12/2/2019- Monday No operations to report. 12/3/2019 -Tuesday No operations to report. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-10 Permit to Drill Number: 218-165 Sundry Number: 319-359 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this Z d da of August, 2019. RBDMSAUb 2 12019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 kk.-CIVED AUG 0 5 ?U1g IkOGC, V 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Reddll ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Forward Circulating JP ❑� 2. Operator Name: 4. Current Well Class: , 5. Permit to Drill Number: , Hilcorp Alaska LLC Exploratory ❑ Development El Straligraphic ❑ Service ❑ 218-165 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23617-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No 21 MILNE PT UNIT M-10 9. Property Designation (Lease Number):, 10. Field/Pool(s): r ADL025514, ADI -388235, ADL025515 I MILNE POINT / SCHRADER BLUFF OIL it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 15,082' 4,047' 15,082' 4,047' 1,800 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 106' 20" 106' 106' N/A N/A Surface 6,650' 9-5/8" 6,650' 3,999' 5,750psi 3,090psi Production 6,493' 7" 6,493' 3,985' 7,240psi 5,410psi Liner 8,596' 6-5/8" 1 15,082' 4,047' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 3-1/2" 9.3# / L-80 / EUE 6,520' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7" x 3.5" HES PHL & SLZXP LTP and N/A 5,885' MDI 3,881' TVD & 6,486 MD/ 3,984 TVD and N/A 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 2] Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/14/2019 OIL Q ' WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: David Haakinson Authorized Title: Operations Manager Contact Email: dhaakinson hllcor .Corn Contact Phone: 777-8343 Authorized Signature: Date: 8/5/2019 61 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: / �• n� Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑✓j Other: (S z-6 *4t- S i n Elik.o "AI.A., LL, Temporary Flow Well: MPU M-10 Date:08/03/2019 Well Name: MPU M-10 API Number: 50-029-23617-00 Current Status: Shut in Producer Pad: M -Pad Estimated Start Date: August 141h, 2019 Rig: N/A Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218-165 First Call Engineer: David Haakinson (907) 777-8343 (0) (307) 660-4999 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: 1954236 Job Type: Temporary Flow Current Bottom Hole Pressure: 1,300 psi @ 3,855' TVD 6.5ppg EMW Downhole Gauge Maximum Expected BHP: 1,350 psi @ 3,855' TVD 6.7ppg EMW Downhole Gauge MPSP: 965 psi (0.1psi/ft gradient to surface) Brief Well Summary: MPU M-10 was drilled and completed as a Schrader Bluff OA production well. The well was completed with a jet pump artificial lift mechanism and brought online April 2019. Power fluid demand and emulsion generation has been higher than originally premised. As an attempt to reduce power fluid usage and troubleshoot the cause of emulsion, it has been proposed to trial a conversion from a reverse circulating met Dump to forward circulating met pump. Power fluid will be supplied by the M -pad facility pumps and M-10 production will be processed at the M -pad facility. Notes Regarding Wellbore Condition: • The 3-1/2"x7" casing passed an MIT -IA to 3,500psi on 2/16/2019. • The 7"x9-5/8" casing passed an MIT -IA to 1,200psi on 1/31/2019 (during the original completion). Objective: Produce the well under temporary flow operations until the forward (conventional) circulatingjet pump artificial lift method can be proven or disproven as an improvement in the production of M-10. If successful, permanent piping will be put in place. Variance Request: Hilcorp Alaska, LLC (HAK) requests a variance to 20 AAC 25.265(c)(1) to operate a surface safety valve (SSV) that is not located in the vertical run of the tree on Milne Point Unit (MPU) well M-10 (PTD # 2181650). The proposed conversion to a conventional forward flow jet pump with high pressure power fluid to be pumped down the 3-1/2" completion and lower pressure production fluids returning up the 7" inner annulus will require a SSV to be located on the IA. Hilcorp Alaska will install the SSV in a horizontally mounted position as viewed in the wellhead schematic attached. The valve will be a standard 4-1/16" SM FE CIW valve that will be tied into the SVS low pressure trip. This configuration provides an equivalent level of protection to an SSV mounted in the vertical run of the tree. The vertical tree SSV will be left in place and will be utilized again if the jet pump flow is converted back to the reverse direction. During the flow operation, the vertical SSV will not be tied in as the surface piping to the M - pad separation unit is pressure rated to handle the power -fluid system pressure. Wellbore schematic, P&IDs and the wellhead drawing are attached for reference. U Ilik,,rp Alaska. LLI Well -work Procedure: 1) RU Slick -line and PT lubricator to 200 psig low, 2000 psig high. 2) Pull jet pump from sliding sleeve @ 5,802' MD 3) Set standing valve in X -nipple @ 5,832' MD. 4) Set forward circulatingjet pump (Size D:30) in sliding sleeve @ 5,802' MD. 5) RD Slick -line and turn well over to operations. Q-B�, SSC/ Attachments: 1. Current Schematic 2. Proposed Schematic 3. Proposed Tree Schematic 4. P&ID / Drawings Temporary Flow Well: MPU M-10 Date: 08/03/2019 ". 4� �'�Y,_'_ _/ 3 'e. /7 ff I1&.V Ala6ka. ld.0 Orig. KB Elev.: 5&5/ GL Elev.: 24.5 TD=15,082' (MD)/TD=4,O47(TVD) PBTD=15,077' (MD) /TD= 4,047(TV)) SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-10 Last Completed: 2/02/2019 PTD: 218-165 Tree Cameron 3 1/8" 5M Wellhead FMC 11" SM TC -1A w/11" x 3 1/2" TC -II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE/ CEMENT DETAIL 42" 50 bbl(10 yards Pilecrete dumped down backside) 12-1/4" 1st stage 525 sx 12.01 Extenda, 400 sx 15.8# SwiftCEM 12-1/4" 2nd stage 410 sx 10.7# Perm L, 270 sx 15.8# SwiftCEM 8-1/2" Cementless Pre -Drilled Liner in 8-1/2" hole CACIN(; DFTAII Size Type Wt/ Grade/ Conn Drih ID Top BPF '0"x34" Conductor (Insulated) 215.5/A-53/Weld N/A SurtpeN/A 2 9-5/8" Surface 40/L-80/TXP 8.679" Surface E65 0.0758 7" Tieback 26/L-80/TXP 6.151" Surface 3.5" Gauge Mandrel w/ Y."Wire (Intake Gauge) 2,875" 5-5/8" Liner(Pre-Drilled) 20/L-80/Hydril 563 5.924" 6,486'0.0355 7" x 3.5" PHL Retrievable PackerShear Release) TUBING DETAIL Tubing 9.3/L-80/EUE 2.867" Surf I 6,520' 1 0.0087 WELL INCLINATION DETAIL KOP @ 350' Max Hole Angle = 70.00 deg. @ Jet Pump Max Hole Angle = 74.00 deg. @ XN profile Max Hole Angle = 84.00 deg. @ Tubing tail Max Hole Angle = 90.00 deg. @ 6,994' MD IFWFI RV DFTAII No. Top MD Item Drift ID Upper Completion 1M��g Tubing Hanger (3-1/2" TC -II Top & Btm) w/ Blast Rings on hanger pup 2.867" 2 3.5" GLM w/ 1.5" Shear Out Valve (2,000 psi) 2,g67•• 3 3.5" Discharge Pressure Gauge Mandrel (Discharge Gauge) 2,g75•• 4 3.5" XD Sliding Sleeve 2.813" Packing Bore; 3,854' TVD; 70° / 13B JP Set 5/26/19 2.813" 5 3.5" Gauge Mandrel w/ Y."Wire (Intake Gauge) 2,875" 6 .5" X Nipple (2.813" Packing B 2.813"7 7" x 3.5" PHL Retrievable PackerShear Release) 2,885••8 .5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) MIn ID = 2.750"4Sleeve)6.170" 9 .5" WLEG (Btm @ 6,520') LowerCompletion 30 6,486' BOT SLZXP Liner Top Packer w/BD Slips 7-5/8" x 9-5/8" (11.33'Tiebac11 6,493' 7" Tieback Assy. (8.25" OD No -Go @ 6,483') 12 6,508' 7-5/8"" Hydril 563 L-80 x 6-5/8" Hydril 625 L-80 XO 13 6,628' 6--5 'Pre -Drilled Li"perft) w/ 1straight-vane ce14 15,082' Shoe; Btm @ 15,082') GENERAL WELL INFO API: 50-029-23617-00-00 Drilled and Completed by Doyon 14-2-02-2019 Revised By: DAH 7/26/2019 n Riicoru Alaska, LLC Orig. KB Elev.: 5&9'/ GL Elev.: 24.% ...................... TD=15,082' (MD) /TD=4,047(TVD) PBTD=15,077' (MD) / TD=4,04i'(TVD) PROPOSED TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-10 Last Completed: 2/02/2019 PTD: 218-165 Tree Cameron 31/8" 5M Wellhead FMC 11" 5M TC -3A w/11" x 31/2" TC -II Top and Bottom Tubing Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 42" 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4" 1st stage 525 sx 12.0# Extenda, 400 sx 15.8# SwiftCEM 12-1/4" 2nd stage 410 sx 10.7# Perm L, 270 sx 15.805wiftCEM 8-1/2" Cementless Pre -Drilled Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn Drift I Top Btm BPF 0"x34" Conductor (insulated) 215.5/A-53/Weld N/A Surface 113' N/A 9-5/8" Surface 40/L-80/TXP 8.679" Su rface 6,650' 0.0758 7" Tieback 26/L-80/TXP 6.151" Surface 6,493' 0.0383 5-5/8" Liner (Pre -Drilled) 20/L-80/Hydril 563 5.924" 6,486' 15,082' 0.0355 TUBING DETAIL 3-1/2" Tubing 9.3/L-80/EUE 1 2.867" 1 Surf 1 6,520' 1 0.0087 WELL INCLINATION DETAIL KOP @ 350' Max Hole Angle = 70.00 deg. @ Jet Pump Max Hale Angle = 74.00 deg. @ XN profile Max Hole Angle = 84.00 deg. @ Tubing tail Max Hole Angle = 90.00 deg. @ 6,994' MD JEWELRY DETAIL Top MD Item Drift ID Upper Completion 29' Tubing Hanger (3-1/2" TC -II Top & Btm) w/ Blast Rings on hanger pup 2.867" 2,534' 3.5" GLM w/ 1.5" Shear Out Valve (2,000 psi) 2.867" 5,791' 3.5" Discharge Pressure Gauge Mandrel (Discharge Gauge) 2.875" 5,802' 3.5" XD Sliding Sleeve 2.813" Packing Bore; 3,854' TVD; 70° 2.813" 5,814 3.5" Gauge Mandrel w/ Y" Wire (intake Gauge) 2.875" 5,832' 3.5" X Nipple (2.813" Packing Bore) 2.813" 5,885' 7" x 3.5" PHIL Retrievable Packer (50k Shear Release) 2.885" 5,942' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) Min ID=2.750" 2.750" 6,519' 3.5" WLEG (Btm @ 6,520') 1 2,867" Lower Completion 6,486' BOT SLZXP Liner Top Packer w/BD Slips 7-5/8" x 9-5/8" (11.33' Tieback Sleeve) 6.170" ,493' 7" Tieback Assy. (8.25" OD No -Go @ 6,483') 6.151" 266,508' 7-5/8"" Hydril 563 L-80 x 6-5/8" Hydril 625 L-80 XO 5.924" ,628' 6-5/8" Pre -Drilled Liner (78 ea 3/8" holes per ft) w/ 1 straight -vane centlzr perit 5.924" ,082' Shoe; Btm @ 15,082') _ GENERAL WELL INFO API: 50-029-23617-00-00 Drilled and Completed by Doyon 14-2-02.2019 Revised By: DAH 8/5/2019 BHTA, Otis, 3-1/8" 5M nao KA -In Schwartz, Guy L (CED) From: Sent: To: Cc: Subject: Attachments: Follow Up Flag: Flag Status: Guy, David Haakinson <dhaakinson@hilcorp.com> Friday, August 16, 2019 7:52 AM Schwartz, Guy L (CED) Taylor Wellman RE: MPU M-10 (PTD #218-165) "Normal Flow" Jet Pump 20190815152710202.pdf Follow up Flagged Attached is a more explicit drawing of our planned piping changes for the conversion of M-10 from reverse to forward circulating jet pump artificial lift. The primary change to the initial 10-403 documentation is that Hilcorp will install safety valve systems on both the power fluid and production piping systems. Please let me know if you have any further questions. I've returned from vacation and will be available. Thank you, David Haakinson Operations Engineer I North Slope Asset Team Hilcorp Alaska, LLC Office: (907) 777-8343 1 Cell: (307) 660-4999 dhaakinson P.Whilcorp.corn From: Taylor Wellman Sent: Wednesday, August 14, 2019 3:26 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: David Haakinson <dhaakinson@hilcorp.com> Subject: MPU M-10 (PTD #218-165) "Normal Flow" Jet Pump Guy, With respect to MPU M-10 (PTD #218-165) and the sundry application for installing a 'normal flow' jet pump, our team had another idea and is walking down the system again. The walkdown is aimed at ensuring a safe operation and tie-in points for possibly fabricating spools. I'm sorry for the delay in answering your question but will be able to provide a better answer tomorrow. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of vimses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. III D I I I 1 _ I I -T-- I I I XS 37 START-01S LOB PRESS. RESET BYPASS 7 SHUT IN SSV WSDP P WEIL STATUS SHUT IN STI R91 KZ UA 221 221 221 S 1 OUTSIDE NELLHWSE I 1 I INSIDE V£LLHWSE I I ' I I ' I ---fir---- I I ' I I ' I I ' I I I I I ' I I I I I ' I I I I ' PUMP H ONTRM PUMP SET 0 1 I I HOA SW. CONWM PAE59AtE J880 PSIG I I® E 1 R�FUY I IERER UY �� SET 0 2588 PSIG " L 1 I INCAEASINC G I HYO VUC SUPPLY SSV I � ' wSDP-42010 gUHEM SNUTDOWN PANEL I I 1 x»TAwc I I L PTV SOL p LOCK LOO( 5 rl, ------ ---I -- (NOTE 2) SET I I IBBF� I I ESDI i I YES i/O RDAYI I I I PRODIIC�Y�� RFlA 1 I i I I I I I I OPEN sw. A INTAKE DRAWDOWN PRESS INTAKE PRESS DISCHARGE PRESS INTAKE TEMP DISCHARGE TEMP SENSOR FAULT 4 Io PC-3251-FNC/-4'-N 3 0 PSIG PSIG _—__-7_T__- ON 1 1 �-� 1j II f limo 1 1 by 3�4. G, TAB _ 4201 1Fv/1 I O� I 8 1 7 1 6 5 4 NOT TO SCAIE 2 NEITHER DUET; DIVERT VALVE OPEN L KAT MA MRygATED AT YAl11WSE WNL O10 50 o!n 2. RKERATNF SUMN xa MR PRE SNTTY mumm. LIC 26, AND W I SEIPONT NDT TO UMD M MO. F 4, Fµ f^ NFNN ME "STI ON NW. & PiciC I I I I 3/4' VOCWD 3/4' VOCAB �-- �- 6'9f I T '(N07E Q PC-0251-FNC7-f{ N I --- PRG - Fill -- - Ph CRY 1 I 115_ 18 I (NOTE T) PC-3152-MC1-C-E 70 A C (C YOM I TEST N04t s I CG c� l n4 X lV-4/A� 10 h' 01 • �� UH -42010 I� I /`o Jvci t- r �/cx..t' p '� Cg) u 4PV ��tll i<l ��, ssv �►,� 42e2e I C- 3 u Bi NOT E 4 1 B Fi 211 1 M SET SET 0 211 211 NOTE 4 E NOTE 4 421 145 ULTRASONIC (SMAP-ON) (NOTE 1) yA_3B89-CND7-2'-E FROM M I- PoMFN FLUID _____ PI-�11-0801&-081 ® t/1 -t AU zi3416 b71 %?Vhxr 1111fe/ PI ��}S7d lu he ISSUED FON CONSTRUCTION 02/21/19 `0 Cl1NAM FororRumRxfnmxr DSG N/CNSTISYI54iQAS SHOWN ON HIS DRAWING A 7V�6RSG le MOD 42 & IN PIPING INSTRUMENT DIAGRAM M-10 SCHRADER JET PUMP PRODUCER P&ID !MLY6YR WACO NuWxR FEY SIF£1 HILCORP ALASKA, LLC /8112102 PI—MOM-10002 00 1 001 NaoulE: 42 a 8 3 1 2 1 I a I I A INTAKE DRAWDOWN PRESS INTAKE PRESS DISCHARGE PRESS INTAKE TEMP DISCHARGE TEMP SENSOR FAULT 4 Io PC-3251-FNC/-4'-N 3 0 PSIG PSIG _—__-7_T__- ON 1 1 �-� 1j II f limo 1 1 by 3�4. G, TAB _ 4201 1Fv/1 I O� I 8 1 7 1 6 5 4 NOT TO SCAIE 2 NEITHER DUET; DIVERT VALVE OPEN L KAT MA MRygATED AT YAl11WSE WNL O10 50 o!n 2. RKERATNF SUMN xa MR PRE SNTTY mumm. LIC 26, AND W I SEIPONT NDT TO UMD M MO. F 4, Fµ f^ NFNN ME "STI ON NW. & PiciC I I I I 3/4' VOCWD 3/4' VOCAB �-- �- 6'9f I T '(N07E Q PC-0251-FNC7-f{ N I --- PRG - Fill -- - Ph CRY 1 I 115_ 18 I (NOTE T) PC-3152-MC1-C-E 70 A C (C YOM I TEST N04t s I CG c� l n4 X lV-4/A� 10 h' 01 • �� UH -42010 I� I /`o Jvci t- r �/cx..t' p '� Cg) u 4PV ��tll i<l ��, ssv �►,� 42e2e I C- 3 u Bi NOT E 4 1 B Fi 211 1 M SET SET 0 211 211 NOTE 4 E NOTE 4 421 145 ULTRASONIC (SMAP-ON) (NOTE 1) yA_3B89-CND7-2'-E FROM M I- PoMFN FLUID _____ PI-�11-0801&-081 ® t/1 -t AU zi3416 b71 %?Vhxr 1111fe/ PI ��}S7d lu he ISSUED FON CONSTRUCTION 02/21/19 `0 Cl1NAM FororRumRxfnmxr DSG N/CNSTISYI54iQAS SHOWN ON HIS DRAWING A 7V�6RSG le MOD 42 & IN PIPING INSTRUMENT DIAGRAM M-10 SCHRADER JET PUMP PRODUCER P&ID !MLY6YR WACO NuWxR FEY SIF£1 HILCORP ALASKA, LLC /8112102 PI—MOM-10002 00 1 001 NaoulE: 42 a 8 3 1 2 1 DATA SUBMITTAL COMPLIANCE REPORT 5/13/2019 Permit to Drill 2181650 Well Name/No. MILNE PT UNIT M-10 L o Operator HILCORP ALASKA LLC API No. 50-029-23617-00-00 P�3 ' MD 15082 TVD 4047 Completion Date 2/2/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No REQUIRED INFORMATION / . Mud Log No ✓ Samples No V Directional Survey Yesvl DATA INFORMATION List of Logs Obtained: ROP/ABG/DGR/EWR/ADR 2"/5" MD, ABG/DGR/EWR/ADR 2"/5" TVD (from Master Well Data/Logs) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH I Type Med/Frmt Number Name Scale Media No Start StopReceived CH Comments ED C 30522 Digital Data 100 15083 3/28/2019 Electronic Data Set, Filename: MPU M-10 DGR ABG EWR ADR.las ED C 30522 Digital Data 6620 15045 3/28/2019 Electronic Data Set, Filename: MPU M-10 ADR Quadrants All Curves.las ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 LWD MD Final.cgm ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 LWD TVD Final.ogm ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 Definitive Survey Report.pdf ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10—Definitive Survey Report.bd ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 GIS.txt ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 LWD MD Final.emf ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 LWD TVD Final.emf ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 Geosteering.dlis ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 Geosteering.ver ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 LWD MD Final.pdf ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 LWD TVD Final.pdf ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 LWD MD Final.tif ED C 30522 Digital Data 3/28/2019 Electronic File: MPU M-10 LWD TVD Final.tif ED C 30522 Digital Data 3/28/2019 Electronic File: EMFView3_1.zip ED C 30522 Digital Data 3/28/2019 Electronic File: Readme.bd Log C 30522 Log Header Scans -- 0 0 — 2181650 MILNE PT UNIT M-10 LOG HEADERS AOGCC Pagel of 5 Monday, May 13, 2019 DATA SUBMITTAL COMPLIANCE REPORT 5/13/2019 Permit to Drilt 2181650 Well Name/No. MILNE PT UNIT M-10 Operator HILCORP ALASKA LLC API No. 50-029-23617-00-00 MD 15082 TVD 4047 Completion Date 2/2/2019 Completion Status 1-011- Current Status 1 -OIL UIC No Log C 30523 Log Header Scans 0 0 2181650 MILNE PT UNIT M-10 PB1 LOG HEADERS ED C 30523 Digital Data 100 12630 3/29/2019 Electronic Data Set, Filename: MPU M-10 P81 DGR ABG EW R ADR.las ED C 30523 Digital Data 6620 12592 3/29/2019 Electronic Data Set, Filename: MPU M-10 P61 ADR Quadrants All Curves.las ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 PB1 LWD MD Final.cgm ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 PB1 LWD TVD Final.cgm ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M -1 0P61 Definitive Survey Report.pdf ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10PB1_Definitive Survey Report.txt ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 PB1 LWD MD Final.emf ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 PB1 LWD TVD Final.emf ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 P81 Geosteering.dlis ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 PB1 Geosteering.ver ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 PB1 LWD MD Final.pdf ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 PB1 LWD TVD Final.pdf ED C 30523 Digital Data 3/29/2019 Electronic File: MPU M-10 1381 LWD MD Final.tif ED C 30523 Digital Data 329/2019 Electronic File: MPU M-10 PB1 LWD TVD Final.tif ED C 30523 Digital Data 3/29/2019 Electronic File: EMFView3_1.zip ED C 30523 Digital Data 3/29/2019 Electronic File: Readme.txt ED C 30524 Digital Data 100 12821 3/28/2019 Electronic Data Set, Filename: MPU M-10 P82 DGR ABG EWR ADR.las ED C 30524 Digital Data 6620 12783 3/28/2019 Electronic Data Set, Filename: MPU M-10 PB2 ADR Quadrants All Curves.las ED C 30524 Digital Data 328/2019 Electronic File: MPU M-10 PB2 LWD MD Final.cgm AOGCC Page 2 o£5 Monday, May 13, 2019 DATA SUBMITTAL COMPLIANCE REPORT 5/13/2019 Permit to Drill 2181650 Well Name/No. MILNE PT UNIT M-10 MD 15082 TVD 4047 Completion Date 2/2/2019 ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data Operator HILCORP ALASKA LLC API No. 50-029-23617-00-00 Completion Status 1 -011 - ED -OIL ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data ED C 30524 Digital Data Log C 30524 Log Header Scans 0 0 Log C 30525 Log Header Scans 0 0 ED C 30525 Digital Data 100 15406 ED C 30525 Digital Data 6620 15368 ED C 30525 Digital Data ED C 30525 Digital Data Current Status 1 -OIL UIC No 3/28/2019 Electronic File: MPU M-10 P132 LWD TVD Final.cgm 3/28/2019 Electronic File: MPU M -10P82 Definitive Survey Report.pdf 3/28/2019 Electronic File: MPU M-10PB2_Definitive Survey Report.tM 3/28/2019 Electronic File: MPU M-10PB2 GIS.I# 3/28/2019 Electronic File: MPU M-10 PB2 LWD MD Final.emf 3/28/2019 Electronic File: MPU M-10 1382 LWD TVD Final.emf 3/28/2019 Electronic File: MPU M-10 1362 Geosteering.dlis 3/28/2019 Electronic File: MPU M-10 P132 Geosteering.ver 3/28/2019 Electronic File: MPU M-10 PB2 LWD MD Final.pdf 3/28/2019 Electronic File: MPU M-10 P132 LWD TVD Final.pdf 3/28/2019 Electronic File: MPU M-10 PB2 LWD MD Final.tif 3/28/2019 Electronic File: MPU M-10 PB2 LWD TVD Final.tif 3/28/2019 Electronic File: EMFVieW3_1.zip 3/28/2019 Electronic File: Readme.txt 2181650 MILNE PT UNIT M-10 PB2 LOG HEADERS 2181650 MILNE PT UNIT M-10 PB3 LOG HEADERS 3/28/2019 Electronic Data Set, Filename: MPU M-10 P83 DGR ABG EWR ADR.Ias 3/28/2019 Electronic Data Set, Filename: MPU M-10 PB3 ADR Quadrants All Curves.las 3/28/2019 Electronic File: MPU M-10 P133 LWD MD Final.cgm 3/28/2019 Electronic File: MPU M-10 PB3 LWD TVD Final.cgm AOGCC Page 3 of 5 Monday, May 13, 2019 DATA SUBMITTAL COMPLIANCE REPORT 5/13/2019 Permit to Drill 2181650 Well Name/No. MILNE PT UNIT M-10 Operator HILCORP ALASKA LLC API No. 50-029-23617-00-00 MD 15082 TVD 4047 Completion Date 2/2/2019 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 30525 Digital Data 3/28/2019 Electronic File: MPU M-10PB3 Definitive Survey Report.pdf ED C 30525 Digital Data 328/2019 Electronic File: MPU M-10PB3_Definitive Survey Report.txt '.. ED C 30525 Digital Data 328/2019 Electronic File: MPU M-10PB3_GIS.t)d ED C 30525 Digital Data 3/28/2019 Electronic File: MPU M-10 PB3 LWD MID Final.emf ED C 30525 Digital Data 3/28/2019 Electronic File: MPU M-10 PB3 LWD TVD Final.emf ED C 30525 Digital Data 3/28/2019 Electronic File: MPU M-10 PB3 Geosteering.dlis ED C 30525 Digital Data 328/2019 Electronic File: MPU M-10 PB3 Geosteering.ver ED C 30525 Digital Data 3/28/2019 Electronic File: MPU M-10 PB3 LWD MD Final.pdf ED C 30525 Digital Data 3/28/2019 Electronic File: MPU M-10 PB3 LWD TVD Final.pdf ED C 30525 Digital Data 3/28/2019 Electronic File: MPU M-10 PB3 LWD MD Final.tif ED C 30525 Digital Data 3/28/2019 Electronic File: MPU M-10 PB3 LWD TVD Final.tif ED C 30525 Digital Data 3/28/2019 Electronic File: EMFView3_l.zip ED C 30525 Digital Data 328/2019 Electronic File: Readme.txt Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED�� Completion Report f Y/ Production Test InformationlYY & Geologic Markers/Tops 0 COMPLIANCE HISTORY Directional / Inclination Data ()y Mechanical Integrity Test Information Y / NA Daily Operations Summary Y Mud Logs, Image Files, Digital Data Y /MA 1 Composite Logs, Image, Data Files 5 Cuttings Samples Y / A� Core Chips Y / Core Photographs Y lA� Laboratory Analyses Y(9) AOGCC Page 4 of 5 Monday, May 13, 2019 DATA SUBMITTAL COMPLIANCE REPORT 5/13/2019 Permit to Drill 2181650 Well Name/No. MILNE PT UNIT M-10 Operator HILCORP ALASKA LLC MD 15082 TVD 4047 Completion Date 2/2/2019 Completion Status 1-0I1- Current Status 1-0IL Completion Date: 2/2/2019 Release Date: 12/17/2018 Description Date Comments Comments: Compliance Reviewed By: API No. 50-029-23617-00-00 UIC No Date: S I I l I AOGC(' Page 5 of Monday, May 13, 2019 Schwartz, Guy L (DOA) From: Sent: To: Cc: Subject: Follow Up Flag: Flag Status: Mr. Schwartz and Mr. Roby, Taylor Wellman <twellman@hilcorp.com> Thursday, May 2, 2019 5:29 PM Schwartz, Guy L (DOA); Roby, David S (DOA) Tom Fouts Milne Point Wells M-10 (PTD 218-165) Sundry 319-170 & M-12 (PTD 218-176) Sundry 319-171 For Temp Flow Extension Request Follow up Flagged We request to extend the temporary flow configuration for Milne Point wells M-10 (PTD 218-165) & M-12 (PTD 218-176) by 1-2 weeks. Both wells are currently operating under Sundry 319-170 & 319-171 respectively. Facility Update The construction of the facility on Moose Pad is complete but we are currently commissioning all the control systems. All the fluid systems in the facility are fluid packed and are cycling fluids (isolated from outside fluids). This has been a little slower than our original estimations to ensure everything is correct prior to running full production fluids through the facility. Our plans are to introduce hydrocarbons from F&L pads today and continue with the confirmation checks that all our control systems are operating as intended. Following this we would follow with introducing the production header from Moose Pad (currently M-10 & M-12) into the facility. The timing for this will be after 5/4/19, which is the end date for the flow configuration approved under Sundry 319-170 & 319-171. While the well's safety systems are hooked up we do not want to put them into full service yet as while we are dialing in the facility controls, there are times that the facility shuts in, which in turn sends the signals to shut in all the wells. Once the facility is running with F&L fluids and begin injection of disposal water into 49A4our primary target would be to get M-10 & M -12's safety surface safety systems operational & tested (inspectors witnessed) as soon as possible. Following this the power fluid pumps and the test separator. If you would like further information or to discuss this please let me know and I will provide. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC —Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-10 Permit to Drill Number: 218-165 Sundry Number: 319-170 Dear Mr. Helgeson: Alaska Oil and Cas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Conditions of approval: 1. Well must be manned 24/7 while operating. Hourly inspections of wellhead and hardlines must be documented. Include wellhead T /IA/OA pressures. 2. SSV must be function/performance tested within 2 days of start-up. SSV test procedure must be on site for review by AOGCC inspector. 3. Written procedure for ESD of power -fluid and well SSV on location. 4. Per CO 477 Rule 6.c. Moose pad wells must be tested twice during the month of April. If the production facility is not operable by month end a portable test separator must be used to test M- 10 and M-12. 5. This flowback configuration is valid for 30 days. Additional flowback time using temporary flowline and pumps must be approved in writing by the AOGCC. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, / /A Je sie�lowski Commissioner DATED this 5 day of April, 2019. RBDNIS APR 0 51019 SCANNED -A )R 16 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED APR 0 3 2019 A0� e1iC iF ' Eta 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Rdrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Temporary Flow Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: , ;� 4 Hilcorp Alaska LLC Exploratory ❑ Development ❑r • Stratigraphic ❑ Service ❑ 218-165 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23617-00-00 7. If perforating: B. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 ' Will planned perforations require a spacing exception? Yes ❑ No ❑Q - MILNE PT UNIT M-10 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025514, ADI -388235, ADL( I MILNE POINTISCHRADER BLUFFOIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 15,082' 4,047' 15,082' 4,047' 1,800 NIA N/A Casing Length Size MD TVD Burst Collapse Conductor 106 20" 106' 106' N/A N/A Surface 6,650' 9-5/8" 6,650' 3,999' 5,750psi 3,090psi Production 6,493' T' 6,493' 3,985' 7,240psi 5,410psi Liner 8,596' 6-5/8" 15,082' 4,047' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 3-1/2" 9.3# / L-80 / EUE 6,520' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): T' x 3.5' HES PHIL & SLZXP LTP and N/A 5,885' MD/ 3,881' TVD & 6,486 MD/ 3,984 TVD and N/A 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic ❑ Development ❑Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing operations: 4/4/2019 OIL [a WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Taylor Wellman Authorized Title: Operations Manager Contact Email: twellmarl hilcor .COM Contact Phone: 777-8449 ' / Authorized Signature' k`" ->t l •.— Dale: 4/3/2019 COMMISSION USE ONLY Conditions of approva : otify Commission so that a representative may witness Sundry Number: /✓',//11 !Vl Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test Location Clearance ❑ * `n❑ Other: - F�ow L1d•t -�: �-� tlu-�c_J� 3U,,___ Post Initial Injection MIT Req'd? Yes ❑ No ❑ R Spacing Exception Required? Yes No Subsequent Form Required: /lp -' C ` APR 0 5 2015 ❑ R13DMSK^J APPROVED BY A q1 COMMISSIONER THE COMMISSION Date: r'l Approved by:X N��F \ 0- 0 Revised 412017 /Approv d applicat�Q,I icG rlo!t koL date of approval. Submit Form and A achments in Duplicate. R Hik.p Alaska, LLi Temporary Flow Well: MPU M-10 Date:04/30/2019 Well Name: MPU M-10 API Number: 50-029-23617-00 Current Status: Shut in Producer Pad: M -Pad Estimated Start Date: April 4, 2019 Rig: N/A Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218-165 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Second Call Engineer: Stan Porhola (907)777-8412 (0) (907)331-8228 (M) AFE Number: Job Type: Temporary Flow Current Bottom Hole Pressure: 2,184 psi @ 4,000' TVDss Weight of completion fluid/ 10.5ppg EMW Maximum Expected BHP: 2,184 psi @ 4,000' TVDss Weight of completion fluid/ 10.Sppg EMW MPSP: 1,784 psi (0.1psi/ft gradient to surface) Brief Well Summary: MPU M-10 was drilled and completed as a Schrader Bluff OA production well. The well was completed with a jet pump artificial lift mechanism in January 2019. The well and M-10 are scheduled to be the first 2 production wells on the newly constructed Moose Pad. The fluid flow path after commissioning the Moose Pad facility, is to comingle with F&L fluids at Moose Pad Facility, separate out and dispose of the water before shipping the combined oil/gas to the Milne Central Plant. As time has progressed the Moose Pad Facility commissioning date has slipped. The wells M-10 & M-12 have completed their post rig work and are ready to be brought online. Notes Re¢ardink, Wellbore Condition: • The 3-1/2"0" casing passed an MIT -IA to 3,500psi on 2/16/2019. • The 7"x9-5/8" casing passed an MIT -IA to 1,200psi on 1/31/2019 (during the original completion). Objective: Produce the well undertemporaryflow operations until Moose Pad Facility is operational and 'normal' operating of the well is possible. Temporary Flow System Description: SVS System These wells will not have functional pressure trips installed to automatically shut in the well at the SSV and will J therefore be continuously manned to comply with 20AAC25.265.J.2. Seethe attached redlined P&ID for the 10 wells flowpath. Also note that the pump truck will need to be continuously operated (manned operation) so in the case of an emergency, it can be shut down immediately by the operator. SSV will be in open and able to be dumped via valve 1/4 turn valve or button located in the wellhouse. These are captured as part of an MOC for temporary flow conditions until the facility is commissioned and the temporary piping is removed. Temporary Piping There are 4 sections of temporary 2" hardline piping that will be installed and monitored for leaks during operation. 1. 2" hardline from the pump truck to the power fluid line upstream of the check valve for M-12 (highlighted on sheet #2 or Drawing # PI -MOM -10003 of the P&ID's attached). 2. 2" hardline from the pump truck to the power fluid line upstream of the check valve for M-10 (highlighted on sheet #1 or Drawing # PI -MOM -10002 of the P&ID's attached). p�-"I Temporary Flow w �'` Well: MPU M-30 Hilcorp Alaska. LL- ,_,) -' Date: 04/30/2019 3. 2" hardline (approx. 20') from Methanol Header to the Oil & Gas Header routing fluids back to the Milne Central Processing Facility (reference sheet #3 & 4 or Drawing #'s PI -MOM -00007-002 & PI -MOM - 00004 -001). 4. 2" hardline (approx. 20') from Disposal Header to the F&L Production Header which connects to the Oil & Gas Header routing fluids back to the Milne Central Processing Facility (reference sheet #3 & 4 or Drawing #'s PI -MOM -00007-002 & PI -MOM -00004-001). Jet Pump Flow Direction The original plan was using Normal Flow jet pumps (power fluid down tubing and returns/production from the IA). One of the test lower completions was on well MPU F-107, where we encountered solids production which required a coil clean out of the lateral to return to production. The risk of depositing sand in the IA has lead us to opt for Reverse Flow jet pumps (power fluid down the IA and returns/production up the tubing). Both Normal Flow and Reverse Flow will be used on Moose Pad. For the M-10 and M-12 completions, these wells are configured for Reverse Flow and will have the SSV in the vertical run of the tree. Well Testing We will obtain a well test on these wells by month end. We are currently working the details on this with options including the following. - Primary Option: Have Moose Pad Facility commissioned and able to use the pad test separator. If the facility is not looking to be completed, we will contact ahead of time for discussion on approved test method. - Flow to a tank and measure the fluids produced. This will account for the oil/water and the gas will be allocated based on the solution GOR. Strap on Ultrasonic meter for fluid measurement, shake out samples for WC and gas will be allocated based on the solution GOR. Portable test separator. Attachments: 1. As -built Schematic 2. Wellhead / Tree Schematic 3. P&ID / Drawings K corp Alaska, LLC Orig. KB Elev.: 58.9'/ GL Elev.: 24.9' TD= 15,082' (MD)/TD=4,047(TVD) PBTD=15,077 (MD) / TD = 4,D47(TVD) SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-10 Last Completed: 2/02/2019 PTD: 218-165 Tree Cameron 3 1/8" 5M Wellhead FMC 11" 5M TC -1A w/31" x 3 1/2" TC -II Top and Bottom Tubing 12-1/4" 2nd stage Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE/ CEMENT DETAIL 42" 50 bbls (30 Yards Pilecrete dumped down backside) 12-1/4" 1st stage 525 sx 12.0# Extenda, 400 sx 15.8# SwiftCEM 12-1/4" 2nd stage 410 sx 10.7# Perm L, 270 sx 15.8# SwiftCEM 8-1/2" Cementless Pre -Drilled Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn Drift lD I Top I Btm BPF 20"04" Conductor (insulated) 215.5 /A-53/Weld N/A Surface 113' N/A 9-5/8" Surface 40/L-80/TXP 8.679" Surface 6,650' 0.0758 7" Tieback 26/L-80/TXP 6.151" Surface 6,493' 0.0383 6-5/8" Liner (Pre -Drilled) 20/ L-80/ Hydril 563 5.924" 6,486' 15,082' 0.0355 TUBING DETAIL 3-1/2" Tubing 9.3/L-80/EUE 1 2.867" 1 Surf 1 6,520' 1 0.0087 WELL INCLINATION DETAIL KOP @ 350' Max Hole Angle = 70.00 deg. @ let Pump Max Hole Angle = 74.00 deg. @ XN profile Max Hole Angle = 84.00 deg. @ Tubing tail Max Hole Angle = 90.00 deg. @ 6,994' MD JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 29' Tubing Hanger (3-1/2" TC -II Top & Bon) w/ Blast Rings on hanger pup 2.867" 2 2,534' 3.5" GLM w/ 1.5" Shear Out Valve (2,000 psi) 2.867" 3 5,791' 3.5" Discharge Pressure Gauge Mandrel (Discharge Gauge) 2.875" 4 5,802' 3.5" XD Sliding Sleeve 2.813" Packing Bore; 3,854' TVD; 70° / 81) JP Set 4/01/19 2.813" 5 5,810' 3.5" Gauge Mandrel w/ Y" Wire (intake Gauge) 2.875" 6 5,832' 3.5" X Nipple (2.813" Packing Bore) 2.813" 7 5,885' 7" x 3.5" PHL Retrievable Packer (50k Shear Release) 2.885" 8 5,942' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) Min ID = 2.750" 2.750" 9 6,519' 3.5" WLEG (Btm @ 6,520') 2.867" Lower Completion 30 6,486' BOT SLZXP Liner Top Packer w/BD Slips 7-5/8" x 9-5/8" (11.33' Tieback Sleeve) 6.170" 11 6,493' 7" Tieback ASSY. (8.25" OD No -Go @ 6,483) 6.151- 12 6,508' 7-5/8"" Hydril 563 L-80 x 6-5/8" Hydril 625 L-80 XO 5.924" 13 6,628', 6-5/8" Pre -Drilled Liner (78 ea 3/8" holes per ft) w/ 1 straight -vane centlzr per jt 5.924" 14 15,082' Shoe; Btm @ 15,082') GENERAL WELL INFO API: 50.029-23617-00-00 Drilled and Completed by Doyon 14-2-02-2019 Revised By: STP 2/21/2019 3.... f s d IN E "3\ ♦ Oil 41ea nnnniii ■ i ♦ g u; a. 2 �Jjj ---- ------ wit -----a 9nv"�Q �ZE 90 �� IPM Y - Iri 'A 3 ga+c� MENEM r------ --, I V MON u - .- , 1 --- --Y------------------SII---- �� I ---- c d-iiE �i3 Y g3 436a x �i x r444a6� I I Ei9a s I R IISI�IB"��i, 33"� I JSftS`ra�i mB"6q I. I j I 1 1 iF1g1-1 _ �cSwlFii Rf MaW pvavrn-�'-e _ m P1WM-IMW-W ® i i i A-&4'$d� I 1 J1 i S�1 Z f`� i I i 88==SY6 � s45gaaY, xiv I � e9 a ap E°v^ ! al a• I aQall 44 ElEES ' ! aERai i' m M a, a, E I 640 y y � I ^gfi gg•� ' i 3 8E> i 8 8 i i 6 d i E E 2 S Y Y C Y C Y C Y Y d Y Y tl Y 8 Y tl tl Y Y::::- e • • _ .....j ...............: / , [§ ` ; | §� / § ! j \ ) � \ } � ;| � Z � � �! weer ; z %:.IV \ ! Z e Date: 4/01/19 3-1/8" Rig: Doyon 14 1.00 Manual valve Well Number: MPM-10 0 1.56 Production _(�l- .92 3-1/8" Actuated valve CM) 1.56 3-1/8" Manual valve —� 4-1/16" 4-1/16" Manual valve Manual valve Power Fluid 11"-5K Fig. 1110 FMC IN FMC C 51 1.56 0.72 }' 2-1/16" A Manual valve o ® 2.25 04 2-1/16" a Manual valve VU 2.20 � v Schwartz, Guy L (DOA) From: Taylor Wellman <twellman@hilcorp.com> Sent: Thursday, April 4, 2019 4:13 PM To: Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL] RE: MPU M-10 (PTD 218-165) and M-12 (PTD 218-176) First Production Mr. Schwartz, The delayed startup of the Moose Pad Facility has been due to a series of events. Here are some of the pieces that have led to this and have had compounding effects on the total timeline as the sequencing had to be completed in a specific order for some of the construction: Fabrication delays from our vendors on major components such as the e -House, Process Building, and some of the skid modules. Skilled labor availability (additional crews beyond the ones that had selected and used through the entire project) & housing for them. We have reached capacity of our camp (including bringing in additional camps) to bring on additional crews. Interconnecting instrument cable that didn't meet our spec. Rather than fight random signal interference in our instrument cable, we elected to pull 8,300' of cable and replace to ensure reliable operations. This has led to further delays in sequencing of the commissioning of the various compoenents to the overall process inside the facility. All in all the project has gone very well and a phenomenal amount has been accomplished to date, but the startup commissioning has pushed to ensure it is right. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Thursday, April 4, 2019 7:56 AM To: Taylor Wellman <twellman@hilcorp.com> Subject: RE: [EXTERNAL] RE: MPU M-10 (PTD 218-165) and M-12 (PTD 218-176) First Production I can write a note in 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 Guy and Dave, Thanks for the phone conversation yesterday about bringing on the first wells at Moose Pad for production flow. The 2 wells would be MPU M-10 (PTD 218-165) and MPU M-12 (PTD 218-176). The original plan was to bring to commission the Moose Pad facility, bring these wells online to comingle with F&L fluids, separate out and dispose of the water before shipping the combined oil/gas to the Milne Central Plant. As time has progressed the Moose Pad Facility commissioning has slipped. We have adjusted plans to bring M-10 & M-12 online without flowing through the Moose Pad Facility. These wells (jet pump) would be brought online and flowed through a jumper into the pipeline to Milne Central Plant. Jet Pump Flow Direction Originally we had planned on using Normal Flowjet pumps (power fluid down tubing and returns/production from the IA). One of the test completions was MPU F-107, where we encountered solids production which required a coil clean out of the lateral to return to production. The risk of depositing sand in the IA has lead us to opt for Reverse Flow jet pumps (power fluid down the IA and returns/production up the tubing). Both Normal Flow and Reverse Flow will be used on Moose Pad. For the M-10 and M-12 completions, these wells are configured for Reverse Flow and will have the SSV in the vertical run of the tree. Updated tree schematics are included for both wells. Also note that I was incorrect when we talked yesterday and will stage a pump truck next to and connected via hardline to the section of the jet pump header directed to each well vs. engergizing the full header. SVS Testing These wells will not have functional pressure trips installed to automatically shut in the well at the SSV and will therefore be continuously manned to comply with 20AAC25.265.J.2. See the attached redlined P&ID for the wells flowpath. Also note that the pump truck will need to be continuously operated so in the case of an emergency, it can be shut down immediately. These are captured as part of an MOC for temporary flow conditions until the facility is commissioned and the temporary piping is removed. Well Testing We will obtain a well test on these wells by month end. We are currently working the details on this with options including the following. - Primary Option: Have Moose Pad Facility commissioned and able to use the pad test separator. If the facility is not looking to be completed, we will contact ahead of time for discussion on approved test method. - Flow to a tank and measure the fluids produced. This will account for the oil/water and the gas will be allocated based on the solution GOR. Portable test separator. If you have any additional questions that come up please feel free to reach out and we can talk again. Thanks, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com H Hilrnrp AL.A., IAd. DATE: 3/26/2019 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 ROP DGR ABG EWR ADR / MD & TVD CD: HALLIBURTON 31 JAN 2019 _Log Viewers 126/201910:06AP,1 Filefolder CGM 126/2019 10:07 AM Filefolder Definitive Survey 3/26/2019 10:07 AM Filefolder EMF 3/26.201910:07 AM Filefolder LAS 3/26201910: 07 AM Filefolder PDF 3/26/201910:07 AM Filefolder TIFF 3/26201910:07 AM Filefolder Please include current contact information if different from above. 218165 30522 RECEIVED MAR 2 8 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 BY: # 1 V _. III I Date: DATE: 3/26/2019 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-10 PB1 PB2 PB3 PTD(218-165) ROP DGR ABG EWR ADR / MD & TVD CD: HALLIBURTON 31 JAN 2019 _Log Viewers CGM Ls Definitive Survey Lli EMF LAS PDF TIFF 3/26/2019 10:06 AM Filefolder 3/26/201910;07AM Filefolder 3.126/201910:07 AM File folder 3/26.l201910:07AM Filefolder 3..r26/201910:07AM Filefolder 3,f26/201910:07AM Filefolder 3'26/201910:07 AM Filefolder Please include current contact information if different from above. 218165 30523 RECEIVED MAR 2 8 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: DATE: 3/26/2019 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-10 PB1 PB2 PB3 PTD(218-165 ROP DGR ABG EWR ADR / MD & TVD CD: HALLIBURTON 31 JAN 2019 _Log Viewers 3/26,1201910:D6 AM Filefolder CGM 3/26/201510:07 AM Filefolder Definitive Survey 3/26/2D1910:07AM Filefolder EMF 326r201910:07AM Filefolder LAS 3/26'201910:07 AM Filefolder PDF 3./26/201910.07AM Filefolder TIFF 3126/201910:07AM Filefolder Please include current contact information if different from above. 218155 RECEIVED MAR 2 8 2019 AOGCC 30 52 4 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: �� , � „ P1 I Date: DATE: 3/26/2019 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-10 PB1 PB2 PB3 PTD 218-165 ROP DGR ABG EWR ADR / MD & TVD CD: HALLIBURTON 31 JAN 2019 _Log Viewers CGM Definitive Survey EMF LAS PDF TIFF 3/26/201910:06 AM Filefolder 3/26/201910:07 AM Filefolder 3/26./2D1910;07AM Filefolder 3/Z6'Z01410;07AM Filefolder 3126201910:07AM Filefolder 3/26/201910:07AM Filefolder 3/26./201910:07AM Filefolder Please include current contact information if different from above. Please acknowledge receipt by Received 218165 30525 RECEIVED MAR 2 8 2019 AOGCC and returning one copy of this transmittal or FAX to 907 777.8510 V E STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Ia. Well Status: Oil ❑✓ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended[-] 2oAAc 25'0520a 625110 GINJ ❑ WINJ E]WAG❑ WDSPL [_1No. of Completions: _ 1 1b. Well Class: ;y Development ❑� Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Abend.: 2/2/2019 14. Permit to Drill Number/ Sundry: 218-165 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: December 24, 2018 15. API Number: 50-029-23617-00-00 4a. Location of Well (Governmental Section): Surface: 5037' FSL, 51' FEL, Sec 14, T13N, R9E, UM, AK Top of Productive Interval: 353' FNL, 767' FEL, Sec 13, T13N, R9E, UM, AK Total Depth: 113' FNL, 1205' FWL, Sec 20, T13N, R10E, UM, AK 8. Date TO Reached: January 20, 2019 16. Well Name and Number: MPU M-10 9. Ref Elevations: KB: 58.9 GL: 24.9' BF: 24.9' 17. Field / Pool(s): Milne Point Field Schrader Bluff Oil Pool 10. Plug Back Depth MD/TVD: 15,077' MD / 4,047' TVD 18. Property Designation: , , ADI-025514,ADL388235, ADL025515 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 534113 y- 6027889 Zone- 4 TPI: x- 538677 y- 6027801 Zone- 4 Total Depth: x- 545889 y- 6022803 Zone- 4 11. Total Depth MD/TVD: , 15,082' MD / 4,047' TVD 19. DNR Approval Number: LONS 16-008 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,623' MD / 2,098' TVD 5. Directional or Inclination Survey: Yes j (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD1 VD: 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/ABG/DGR/EWR/ADR 2"/5" MD / PBI, PB2, PB3 ABG/DGR/EWR/ADR 275" TVD / PBI, PB2, PB3 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CEMENTING RECORD PULLED TOP BOTTOM TOP BOTTOM HOLE SIZE 20" 215.5 A -53B Surface 113' Surface 113' 42" -270 ft3 9-5/8" 40# L-80 Surface 6,650' Surface 3,999' 12-1/4" Sig 1 L - 525 sx / T - 400 sx Stg 2 L - 410 sx / T - 270 sx 139 bbls 7" 26# L-80 Surface 6,493' Surface 3,984' Tieback Tieback Assy 6-5/8" 20# L-80 6,486' 15,082' 3,983' 4,047' 8-1/2" Cementless PreDrilled Liner 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MDIrVD of Top and Bottom; Perforation Size and Number; Date Perfd): 6,628' - 15,039' MD / 3,998' - 4,047' TVD 6-5/8" Predrilled Liner, 78 holes/foot, 3/8" holes, Installed on COMPLETION D E 7q r-0 � Z Z ZDl�( VERIFIED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 3-1/2" 6,520' 5,885' MD / 3,881' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No ❑ Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Future Method of Operation (Flowing, gas lift, etc.): Jet Pump 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 5/2017 �.7/��d q _It.�.i9 CONTINUED ON PAGE 2 ` • Submit ORIGIINI I` only-. 28. CORE DATA Conventional Corals): Yes ❑ No Q Sidewall Cares: Yes ❑ No Q If Yes, list formations and intervals cored (MD/TVD, FromfTo), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,623' 2,098' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 6,628' 3,998' information, including reports, per 20 AAC 25.071. SV5 1,415' 1,344' SV1 2,675' 2,129' Ugnu LA3 4,669' 3,270' SB NA 5,658' 3,799' SB OA 6,646' 3,998' Formation at total depth: Schrader OA 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdinaeridhilcoro.com Authorized 1Contact Phone: 777-8389 Signature: Cl Date: INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, Fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071, Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only K cora Alaska. LLC Orig. KB Elev.: 58.9'/ GL Elev.: 24.9' TD =15,087 (MD) / TD=4,047(1VD) PBTD =15,077 (MD) /TD=4,047(TVD) SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-10 Last Completed: 2/02/2019 PTD: 218-165 Tree Cameron 31/8" 5M Wellhead FMC 11" 5M TC -1A w/11" x 31/2" TC -II Top and Bottom Tubing 12-1/4" 2nd stage Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 42" 50 bbis (10 Yards Pilecrete dumped down backside) 12-1/4" 1st stage 525 sx 12.0# Extends, 400 sx 15.8# SwiftCEM 12-1/4" 2nd stage 410 sx 10.7# Perm L, 270 sx 15.8# SwiftCEM 8-1/2" Cementless Pre -Drilled Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn DriftlD Top Btm BPF !0"x34" Conductor (insulated) 215.5/A-53/Weld N/A Surface 113' N/A 9-5/8" Surface 40/L-80/TXP 8.679" Surface 6,650' 0.0758 7" Tieback 26/L-80/TXP 6.151" Surface 6,493' 0.0383 6-5/8" Liner(Pre-Drilled)20/L-80/Hydril 563 5.924" 6,486' 15,082' 0.0355 3-1/2" 1 Tubing 1 9.3 / L-80 / EUE 1 2.867" 1 Surf 1 6.520' 1 0.0087 1 WELL INCLINATION DETAIL KOP @ 350' Max Hole Angle = 70.00 deg. @ Jet Pump Max Hole Angle = 74.00 deg. @ XN profile Max Hole Angle = 84.00 deg. @ Tubing tail Max Hole Angle = 90.00 deg. @ 6,994' MD IFWFI Ry nFTAll No. I Top MD Item Drift ID Upper Completion 1 29' Tubing Hanger (3-1/2" TC -II Top & Btm) w/ Blast Rings on hanger pup 2.867" 2 2,534' 3.5" GLM w/ 1.5" Shear Out Valve (2,000 psi) 2.867" 3 5,791' 3.5" Discharge Pressure Gauge Mandrel (Discharge Gauge) 2.875" 4 5,802' 3.5" XD Sliding Sleeve 2.813" Packing Bore; 3,854'TVD; 70°/BCJP Set 2/20/19 2.813" 5 5,810' 3.5" Gauge Mandrel w/Y." Wire (Intake Gauge) 2.875" 6 5,832' 3.5" X Nipple (2.813" Packing Bore) 2.813" 7 5,885' 7" x 3.5" PHIL Retrievable Packer (50k Shear Release) 2.885" 8 5,942' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) Min ID = 2.750" 2.750" 9 6,519' 3.5" WLEG (Btm @ 6,520') 2.867' Lower Completion 30 6,486' BOT SLZXP Liner Top Packer w/BD Slips 7-5/8" x 9-5/8" (11.33' Tieback Sleeve) 6.170" 116,493' 7" Tieback Assy. (8.25" OD No -Go @ 6,483') 6.151" 12 6,508' 7-5/8"" Hydril 563 L-80 x 6-5/8" Hydril 625 L-80 XO 5.924" 13 6,628' 6-5/8" Pre -Drilled Liner (78 ea 3/8" holes per ft) w/ 1 straight -vane centlzr perjt 5.924" 14 15,082' Shoe; Btm @ 15,082') GENERAL WELL INFO 7-0e-050.09-2361 ComplADrI illed et0d boy Doyon 14-2-02-2019 P6, l ioez-/ 133 Nar- S4,cy N . Revised By: STP 2/21/2019 n Well Name: MP M-10 Field: Milne Point Unit County/State: ,Alaska i (LAT/LONG): evation (RKB): 34.03 API #: Spud Date: 12/25/2018 Job Name: 1813837D MPU M-10 Drilling Contractor Doyon 14 AFE #: AFE $: Hilcorp Energy Company Composite Report AN& pate _ Ops Summary 12/22/2018 Doyon 14 on M-03 well. Please see M-03 report for details.;Cleanup tree and cellar box. Prep and secure cellar. Skid rig floor into move position. Jack up rig and remove shims.;Notify Moose pad operator before moving off well. Moose pad operator and DSM witness rig move. Move rig off M-03 and onto M-10.;Skid rig floor into drilling position.;Hook up air, steam, water, choke, kill, mud pump, gas buster and mud bucket lines to the rig floor. Install stairs and landings. Spot rock washer and continue rebuilding mud pump #1.;Run hot water through mud pit lines. Spot fuel trailer, Sperry unit, M-1 shack, geo shack and 5 star trailer. Spot water pump house and upright tank. Begin R!U diverter line. Note: diverter and knife valve were in place prior to rig move. 12/23/2018 Continue to R/U diverter. Totes calibrate PVT and gas trap in possum belly and check stroke counters. Check top drive rotation. Get coms working in shacks. Install bell nipple, tighten diverter bolts. Function drag chains, electric motor failed on #2 drag chain, source replacement.;Funotion pit agitators and centrifugal pumps. Install 80 mesh shaker screens and 4" ball valves on conductor, turn on accumulator, check annular and knife valve for leaks. Install riser, clamp and air boot.;R/U Diverter line (460' of diverter w/ one 45° targeted elbow), install diverter warning signs & barricades and drip pan. C/O electric motor #2 drag chain. Totco finish up calibrating and testing pit sensors. Setup coms to all shacks. Load 2 rows of 5" drill pipe in the shed. Spot cement silos.;Prime mud pumps. C/O saver sub to 5" DS -50. Slip & cut drilling line. Ensure pressure relief lines are clear. Pressure test mud lines to 3800 PSI. Complete rig acceptance checklist, rig accepted at 23:OO.;Load and strap remainder of 201 joints of 5" drill pipe into the pipe shed. Hook up water pump house and begin filling upright water tank.;P/U 18 joints 5" drill pipe and rack back 6 stands in the derrick.;Hauled 0 blots H2O from L -Pad lake for total = 0 bbis Hauled 0 bbis cuttings/liquids to MPU G&I for total = 0 bbls 12/24/2018 Using mouse hole in rotary, Continue to drift, P/U and rack 67 stds total of 5" DS50 DP in derrick. Pull mouse hole V rotary. Simops: spot 2nd cmt silo skid, unload 9 5/8" TXP casing as it arrives. Get water circulating in upright water tank.;Pelform diverter function test using 5" joint of drill Dine. Annular closed in 35 sec, knife valve opened in 11 sec. Perform accumulator drawdown, 6 N2 bottle avg = 1975 psi. Closest ignition source to end of diverter is 200'. Notify pad operator, calibrate and test rig gas atarms;AOGCC rep Lou Laubenstein waived witness to diverter test via phone call @ 06:25 am.;Strap and tally HWDP. Using mouse hole in rotary, P/U 17 jts 5" HWDP and jars, rack 6 stds in derrick.;Top drive hydraulic pump leaking. Remove, source replacement and install.;Remove mouse hole from the rotary table. Mobilize BHA components to the rig floor. M/U 12-1/4" Kymera bit, Sperry mud motor and XO sub to 36'. RIH and tag bottom at 112'.;Pre-spud meeting with both rig crews, Sperry, M-1 and Peak and notify Moose pad operator.;Fill stack with water, check for leaks - none. Wash down from 112' to 11 4'with 350 GPM, 220 PSI, 40 RPM, 0.5K TQ.;Drt11 12-1/4" surface hole f/ 11 4' V 221', 107' drilled, 71 AROP. Drilled the first 10' to 124' with water then displaced to 8.8 ppg spud mud. 350 GPM, 490 PSI, 40 RPM, 1 K TO, 5K WOB. PU/SO/ROT 55/50/55. MW in 8.9 / out 9.0, vis in 300+ out 300+, max gas 12u.;Circulate 1.5 bottoms up while POOH V 221't/ 124'. Blow down top drive. POOH V 124't/ 36. WU MWD DM and perform offset = 193.81'. Inspect bit. WU remainder of MWD tools & 3 drill collars to 177'. Initialized MWD tools in the pipe shed out of the critical path.;M/U stand of HWDP & SPT MWD tools. Obtain MWD survey @ 208' before resume drilling.;Drill 12-1/4" surface hole f/ 221' U 254', 33' drilled, 66 AROP. 450 GPM, 800 PSI, 35 RPM, 1.5K TO, 4K WOB. PU/SO/ROT 55/50/55. MW in 8.9 / out 9.0, vis in 300+ out 300+, max gas 6u.;Hauled 385 bbis H2O from L -Pad lake for total = 385 bbis Hauled 2 bbis cuttings/liquids to MPU G&I for total = 2 bbis 12/25/2018 Drill 12-1/4" surface hole f/ 254't/ 643' 389' dri le 64.8' AROP. Kickoff 3-4 deg/100' @ 354420 GPM, 970 PSI, 40 RPM, 3K TO, 12K WOB. PU/SO/ROT 74/80/77 MW in 8.91 out 9.1 vis in 160 out 220, ECD 9.6, max gas 15u.;Drill 12-1/4" surface hole f/ 643't/ 1114%471' drilled, 78.5' AROP. Build 4 deg/100', back ream 60' ea. std 425 GPM, 1150 PSI, 60 RPM, 4K TO, 10K WOB. PU/SO/ROT 87/87/85 MW in 9.0 / out 9.0 vis in 200 out 220, ECD 9.8, max gas 21 u.;Drill 12-1/4" surface hole V 1114' t/ 1546', 432' drilled, 72' AROP. Build 4 deg/109, back ream 90' ea. std 450 GPM, 1220 PSI, 60 RPM, 2-6K TO, 10K WOB. PU/SO/ROT 96/85/90 MIN in 9.1 / out 9.1, vis in 1311 out 185, ECD 10.0, max gas 25u.;Screened up to 120 mesh screens at 1303'. Pumped 30 bbl hi -vis sweep Q 1555' w/ 30% increase at shaker.;Drill 12-1/4" surface hole f/ 1546112245% 699' drilled, 116.5' AROP. End of build at 2085'. 500 GPM, 1635 PSI, 80 RPM, 5K TO, 5-12K WOB. PU/SO/ROT 102187/94 MW in 9.15 / out 9.25, vis in 164 / out 157, ECD 10.1, max gas 61 u.;Pumped 30 bbis hi -vis sweep at 2151' with 10% increase observed at shakers. Last survey at 2206.42' MD, 1861.18' TVD, 55.37° inc, 85.07" earn. 6.6' from plan, 5.5' low and 35 right.;Hauled 680 bbis H2O from L -Pad lake for total = 1065 bbis Hauled 856 bbis cuttingsfltquids to MPU G&I for total = 858 bbis 0 daily losses, 0 cumulative losses. 12/26/2018 Drill 12-114" surface hole V 224611 3000', 755' drilled, 125.8' AROP. Maintain 55 deg Inc. Back ream full stds, 550 GPM, 1680 PSI, 80 RPM, 5K TO. 7-12K WOB. PU/SO/ROT 114/92/101 MW in 9.1 / out 9.3, vis in 171 / out 120, ECD 10.12, max gas 81 u.;Base of permafrost came in at 2260' MD, 61 u max gas. SV -1 came in at 232T MD. Pump 30 bbl hi vis sweep @ 2617' with 10% increase at sweep returns.;Drill 12-1/4" surface hole V 3000' t/ 3558', 558' drilled, 93' AROP. Maintain 55 deg inc. Back ream full stds. 550 GPM, 1800 PSI, 80 RPM, 8K TO, 8K WOB. PU/SO/ROT 130/95/100. MW in 9.2 / out 9.2, vis in 111 / out 131, ECD 10, max gas 56u.;Pump 30 bbl hi vis sweep @ 3088' with 10% increase at sweep returns.;Drill 12-1/4" surface hole f/ 3556114039" 481' drilled, 80.2' AROP. Maintain 55 deg Inc. Back ream full stds. 600 GPM. 2050 PSI, 80 RPM, 10K TO, 12K WOB. PU/SO/ROT 148/90/112 MW in 9.2 / out 9.1, vis in 163 / out 110, ECD 9.8, max gas 43u.;Pump 30 bbl hi vis sweep @ 3662' with 10% increase at sweep returns.;Drill 12-1/4" surface hole It 4039' U 4699', 660' drilled, 110' AROP. Maintain 55 deg Inc. Back ream full stds. 600 GPM, 2290 PSI, 80 RPM, 11 K TO. 10K WOB. PU/SO/ROT 155/90/120 MW in 9.1 / out 9.15, vis in 2321 out 262, ECD 10.1, max gas 63u.;Pump 30 bbl hi vis sweep @ 4271' with 10% increase at sweep returns. Last survey at 4660.04' MD / 3265.08' TVD, 53.38' inc, 84.52° azm, 19.4' from plan, 15.5' high, 11.6' right.;Hauled 1180 bbls H2O from L -Pad lake for total = 2245 bbis Hauled 1614 bbis cuffings/liquids to MPU G&I for total = 2472 bbls 0 bbls daily losses, 0 bbls cumulative losses. 12/2712018 Drill 12-1/4" surface hole V 4699't/ 5265', 566 drilled, 94.3' AROP. Maintain 55 deg inc to 5135', then build and turn 4 deg/l OU 600 GPM, 2250 PSI, 80 RPM, 12K TQ, 1 OK WOB. PU/SO/ROT 155/95/129. MW in 9.1+ /out 9.2, vis in 185/ out 245, ECD 10.14, max gas 150u.;Note: add screen clean to avoid shakers blinding off f/ LA -3, 150u max gas, traces of oil @ 4760' Pump 30 bbl hi vis sweep @ 4792' with 10% increase seen at shakers.;Ddil 12-1/4" surface hole f,' 5265' 115642', 377' drilled, 62.8' AROP. Build and turn 4 deg/l OU 590 GPM, 2200 PSI, 80 RPM, 15K TO, 15K WOB. PU/SO/ROT 185/100/127 MW in 9.1 / out 9. 1, vis in 711 out 112, ECD 9.8, max gas 150u.;Pump 30 bbl hi vis sweep @ 5495' with 0% increase seen at shakers.;Drill 12-1/4" surface hole f/ 5642' t/ 5930', 288' drilled, 48' AROP. Build and turn 4 deg/100'. 580 GPM, 2300 PSI, 80 RPM, 16K TO. 15K WOB. PU/SO/ROT 185/90/125. MW in 9.3 / out 9.3, vis in 811 out 176, ECD 10.3, max gas 206u.;Schrader Bluff NA sand logged at 5658' MD / 3799' TVD, 53' high to prognosis.;Drill 12-1/4" surface hole V 5930'V 6306, 378' drilled, 63' AROP. Build and turn 4 deg/100'. 580 GPM, 2320 PSI, 80 RPM, 15-17K TO, 13K WOB, PU/SO/ROT 173/89/125. MW in 9.15 / out 9.25, vis in 66 / out 165, ECD 10.25, max gas 134u.;Last survey at 6263.30' MD / 3953.39 TVD, 81.71' inc, 120.62' azm, 21.8' from plan, 21.5' high and 3.5' right.;Hauled 940 bbis H2O from L -Pad lake for total = 3165 bbls Hauled 1730 bbls cuttings/liquids to MPU G&I for total = 4202 bbis 0 bbls daily losses, 0 bbls cumulative losses. 1228/2018 Drill 12-1 /4" surface hole f/ 6308' V 6660', 352' drilled, 70.4' AROP. TD surface section in OA -1 sand. 580 GPM, 2430 PSI, 80 RPM, 16-17K TO, 20K WOB, PU/SO/ROT 175/90/124. MW in 9.2 / out 9.3+, vis in 631 out 300, ECD 10.24, max gas 106u.;Last survey, 6619.48' MD, 3996.83' TVD, 86.01 inc. 124.83 az. 11.2' above the line, 9.9' Ieft.;Back ream to 6583', rack std back. POOH on elevators racking back 2 sts to 6397'. M/U top drive. PU/SO 195/90.;Ciculate and condition mud at 6397', Pump 40 bbl hi vis sweep around, 580 gpm, 2200 psi, reciprocate pipe 90', rotate 80 rpm, 14k tq. Sweep back 35 bbis late w/ no increase, continue to circulate hole clean. Lower YP f/ 29 to 25. MW in/out 9.2/9.3, Vis inlout 47/54, flow check well, static.;RIH with 3 stds tagging bttm @ 6660' w/ no fill, BROOH 5 min std, pumping 600 gpm, 2150 psi, 80 rpm, 13A 41k tq f/ 6660' to 2625'. BROOH slow to 5'/min f/ 2625' V 2415' to obtain a bottoms up below the base of permafrost. 75% reduction of clay at shakers & 0.1 reduction in ECD to 10.1.;Continue at 5 mmJstd f/ 2415'V 2009'. Max gas 33u.;At 2009 the torque became erratic, ECD climbed to 10.6 & the hole began to unload. Slowed to 57min for a cleanup cycle. ECD reduced to 10.5 then climbed to 11.1. Slowed • to l7min, reduced flow to 550 GPM & rotary to 60 RPM. Cuttings changed from clay to sand/silt.;Hole began to unload. Reduce flow to 500 GPM. Rock washer [led with cuttings & mud pit level dropped. Called extra super sucker from iRig & recalled vac truck w/ 200 bbis mud from G&I. Slow to 450 GPM, 80 RPM. ECD S ropped to normal 10.1 Increase to 600 GPM & 57mm at 1854'. Max gas 90u.;Back ream out of the hole from 1854' to 1301'600 GPM, 1000 PSI, 80 RPM, 5K TQ at 5 min/stand. 10.2 ECD.;Hauled 1030 bbls H2O from L -Pad lake for total= 4215 bbis Hauled 915 bbis cuttings/liquids to MPU G&I for total= 5117 bbis 0 bbls daily losses, 0 bbls cumulative losses. 12/292018 Back ream out of the hole from 1301' to 737' @ HWDP 580 GPM, 1000 PSI, 80 RPM, 2-3K TO at 5 min/stand. 10.2 ECD.;Attempt to POOH on elevators V 737', swabbing, pump out 550 gpm 1300 psi pulling slow to 516, hole unloading, ECD climbing to 11.2, slow to 1 fpm until hole cleaned up, slow pump to 400 gpm, 630 psi to 486, POOH on elevators racking back HWDP and jars to 174'. .;UD 3 NMFCs, tie in and upload MWD., UD directional tools, motor and bit, grade=1-3-BT-A-F-I-LT-TD (#2 Bearing failed) 2 bbl losses over calc. displacement on TOOH.;Clear and clean rig floor, load 9 5/8" casing tools to rig floor, R/U Volant tool with swivel, handling equipment and power tongs. Monitor well, static.;PJSM with all parties, PU, flashlight and MU the shoe track; baker lock each connection and torque to 20960 ft -lbs. Check the float (good). Install top hat on top float wllar as per HES rep. Baker lock and MAl Baffle adaptor. 3 bbls Iosses.;Run 9-5/8" 40# L-80 TXP casino f/ 163't/ 329T Torque connections to 20,960 Nibs. Fill on the fly & top off every 10 then circulate 5-10 bbls. Install centralizers on every jt to jt 26, then every other to jt 44. RIH 10-40 fpm, returns but losing displacement even at 10'/min. 52.4 bbl Iost.;Est. circulate, stage up in 1/2 bbl increments to 6 BPM, 210 PSI. MW in 9.3 / out 9.5, vis in 39 / out 76. Slow to 4 BPM, 180 PSI to treat mud returns for weight. Circulate a bottoms up, 187 bbis w/ 17 bbis losses - 91 % returns.;Run 9-5/8" 40# L-80 TXP casing U 3297' V 5500', Torque connections to 20,960 Nlbs. Fill on the fly & top off every 10 then circulate 5-10 bbls. M/U Halliburton ESIPC between jt. #106 & 107. Install centralizers on joints 102-116, pup joints above & below ESIPC and every other joint #1 18-138.;250K up, 120K down. 44.9 bbis Iost.;Hauled 230 bible H2O from L -Pad lake for total = 4445 bbis Haulted 360 bbis heated H2O from G&I Hauled 689 bbis cuttings/Uiquids to MPU G&I for total = 5806 bible 12/30/2018 Run 9-5/8" 40# L-80 TXP casing V 5500' V 6523', Torque connections to 20,960 ft/lbs. Fill on the fly & top off every 10 then circulate 10-20 bbls, wash last 3 its down 1 bpm, 350 psi to 6640', MN 15' casing pup., wash down to 6659, verify 16 jts out. (164 jts 77 centralizers ran) PU/SO 250/115.;Note: 114.2 bbl total 1 losses TIH and circulating. Submit 24 hr notification to AOGCC for BOP test @ 8:18 hrs.;Circ/cond mud 1 bpm, 320 psi, R/D slips and dog bones. Work pipe L� 20', able to rotate pipe slow 3-4 rpm while reciprocating, tq set at 19k, stage pumps slowly to 4.5 bpm 300 psi, MW in/out start 9.2/9.6 vis 45/182, Final MW in/out A 9.2/9.3 vis 38/53. FCP 185 psi, 30-35 bph loss rate.;Thaw arctic dumps while circulating then offload 250 bbis mud f/ pits 1,2,5.30-35 bph loss rate.;Blow down • y TD, R/U cement hose and valves. Close upper and lower IBOP. Continue to circulate 412 bpm 280 psi working pipe 20'. 105 bbis lost while conditioning for cement job.;PJSM for pumping 1st stage cement with all parties involved. Back out volant, dope cup and M/U. Flood the lines with 5 bbis of fresh water and PT lines to 1000/4000 psi for 5 minutes each.;Mix and Pump 60 bbis of 10.0 ppg clean spacer with red dye and poly flake 3 bpm, 220 psi. Drop bypass plug. Mix �ryu 11 and pump 220 bbis, 525 sks of 12.0 ppg lead cement at 5 BPM, 420 psi. Rotate & reciprocate casing. Mix and pump 82 bbis, 400 sks of 15.8 ppg tail cement at 2.9 BPM, 332 psi.;Drop shutoff plug. Pump 20 bbls water at 5.2 BPM, 292 psi. 20 bbis lost while pumping cement Rotate & reciprocate 20' while cementing.;Displace cement w/ rig pump w/ 9.3 ppg mud, 6 BPM, 180 psi ICP / 630 PSI at 3600 stks. Slow to 5 PBM as lead cement exited the shoe, 650 psi ICP, 770 psi before slowing to 3 BPM, 700 psi. Plug bumped w/ 790 psi at 4642 stks - 52 arks early. CUP at 20:05. 78% returns wh le d splacina 105 bbls Iost;Rotate & reciprocate 20' while displacing. Set on depth for last 20 bbls pumped ;Pressure up to 1220 psi & hold for 5 min. Bleed off & check floats good. Inflate ESIPC - pressure up to 1200 psi then 2080 2120 2260 2440, 2620 PSI holdina 5 min. each. Cementer shifted open at 2770 PSI.;Circulate through ESIPC at 2460'. Stage up to 7 BPM, 2530 PSI, reduce to 4.5 BPM, 1900 PSI due to 18% losses. 1600 stks calculated bottoms up. At 1192 stks, begin overboarding contaminated mud. Thick mud packed off the stack 2x times. Drain stack to cellar & super sucker.;At 4250 silks, return good mud to the pits. Returns thickened up again at 4591 stks. Treat mud & stage up to 7 BPM, 1660 PSI by 6180 stks. Mud thickened up at 7755 stks & packed off stack. Drain stack to cellar & super sucker. Stage up to 7 BPM, 1400 PSI. Pump a total of 12620 elks - 7.9 bottoms up.;Spacer and Pol-E-Flake observed at surface. No confirmed cement retruns to surface, 9.7 ppg heaviest mud returned to surface. Losses while circulating through ESIPC will be calculated on tomorrows report.;Flush stack w/ black water to clear of any thick mud. Disconnect knife valve & function annular 2x times.;Circulate through ESIPC while preparing for 2nd stage cement job. 7 BPM, 1060 psi. No losses. Empty rock washer and all trucks. PJSM w/ Doyon, Halliburton, M -U and DSM.;Mix & pump 60 bbis of 10.0 ppg Clean Spacer w/ 4# & 5# of Pol-E-Flake in 1 st 10 bbis at 4.5 BPM, 530 PSI. Mix & pump 240 bbis of 10.7 ppg Perm L lead cement at 5.4 BPM, 575 PSI. Cement job continues into next report.;Hauled 475 bbis H2O from L -Pad lake for total=4445 bbis Hauled 290 bbis heated H2O from G&1=650 Hauled 1470 bbis cuttings/liquids to MPU G&I for total=7276 bbis 292 bbls daily losses, 364.4 bbis cumulative. 12/3112018 Performing 2nd stage surface cement job. Continue to pump a total of 316.25 bbis, 410 sks of 10.7 ppg Penn L lead cement at 5.4 BPM, 565 PSI. Mix & pump 56 bbis, 270 sks 15.8 ppg Premium G tail cement at 3.2 BPM, 310 PSI. Drop shutoff plug. Note: 50 bbls tail away see traces cmt at surface.;Pump 20 bbis water, swap to rig pump. Displace with 164 bbis of 9.2 ppg mud at 7 BPM 600 psi ( 25 bbls into displacement see good cement returns @ surface) 147 bbi away slow the pump to 3 BPM, 520 psi FCP, plug bumped 3.2 bbis early @ 1624 stks. Pressure toll60 psi.;Pressure to 1270 psi shifting cementer tool closed, increase to 1670 psi, hold for 5 min, bleed off pressure, no flow. CIP @ 07:32. 60 bbis spacer and 139 bbis good cement returned to surface no Iosses.;Flush all surface equipment w/ black water. Function test annular w/ black water 3 times. Blow down cement line. RID Volant & UD casing equipment. Start R/D diverter Iine.;Remove speed head LDS. Hoist diverter stack. Suck mud out of casing joint. Set casing slips w/ 100K weight on slips. Rig welder cut and dress 95/8' casing as per wellhead rep. Cut joint length = 21.64'.;PulI riser and UD bell nipple. N/D diverter stack. remove knife valve and tee. Continue to R/D diverter pipe., clean in pits.;lnstall wellhead and orient same as per well head rep. Install tbg spool. Test slip lock seal to 500 psi for 5 min and 2500 psi @ 80% of 9 5/8" 40# L- 80 collapse pressure for 10 min.;N/U BOP stack & install kill line. Sim-ops: clean mud pits, prep rig floor for testing, grease choke manifold & mud cross.;lnstall riser, change out riser because out of round. Install lower test plug. M/U top drive test sub, fill & purge lines of air. Perform BOP body test - good;Test BOP equipment as per PTD & AOGCC requirements. Upper & lower 2-7/8"x5" VBR and annular tested on 3.112" & 5" test joints. Test 14 choke valves, upper & lower IBOP, dart valve, FOSV, manual & HCR choke & kill valves, manual & hydraulic chokes. Remove test joint & test blind rams.;Annular tested to 250 psi low/ 2500 psi high. All other tests to 250 psi low 13000 psi high. All test held for 5 min. & charted. Test gas, PVT & flow alarms.;Perform accumulator drawdown test: initial 2975 psi, after closure 1750 psi, 200 psi attained in 43 sec, full psi in 177 sec, 6 N2 bottle average 2100 psi. AOGCC inspector Brian Bixby waived witness at 16:15.;R/D test equipment and blow down lines. Pull test plug and install 9" LD wear bushing.;Hauled 415 bbis H2O from L-Pad lake for total = 4860 bbis Hauled 545 bbis heated H2O from G&I = 1130 Hauled 1237 bbls cuttings/liquids to MPU G&I for total = 8513 bbls 0 daily losses, 364.4 cumulative losses for interval. 1/1/2019 RID Test equipment, install 9" ID wear dng.;M/U cleanout BHA 2, 81/2" mill tooth bit, 1.22 motor, FS, 3 NMFCs, 6 HWDP, jars, 11 HWDP= 683.33.;Drift, PIU and single in w/ 5" DS50 DP F/ 683' T/ 2413'.;Wash Down F/ 2413' T/ 2450' Hard Cmt. Drill cmt and Es cmter as per DO to 2463'- on depth. Work through clean. Circ btm Up.;Drift, PIU and single in w/ 5" DS50 DP F/ 2463'T1 6344'. Tag stringers at 6300. Wash down & circ btm up at 460 gpm.;Test casing T/ 2500 psi for 30 min. Pressured up to 2575 psi & bled down to 2550 psi over 30 min. Pumped 6 bbis and bled back 6 bbls. Blow down choke & kill Iines.;Wash down f/ 6344' t/ 6520'w/500 GPM, 1370 PSI, 40 RPM, 15K TO, 5-10K WOB. Tag landing collar @ 6526' & drill w/ 350 GPM, 40 RPM. Drill cement U float collar @ 6568' w/ 500 GPM, 1370 PSI. Drill float collar w/ 350 GPM, 910 PSI, 40 RPM, 15-16K TO, 5-1 OK WOB.;DrilI cement V shoe @ 6649 w/ 600 GPM, 1860 PSI, 40 RPM, / 16-17K TO. Drill shoe V 6649- V 6650' w/ 350 GPM, 1000 PSI, 40 RPM, 16K TQ, 5-7K WOB. Casing shoe track components tagged on depth.;Clean out rathole V 6650't/ 6660'. Drill 20' of new hole V 6660' 116680', 600 GPM, 1890 PSI, 40 RPM, 16K TO, 5-9K WOB, 20911hr AROP.;Pump 40 bbl high viscosity spacer and \ displace well 119.0 ppg spud mud to 9.0 ppg Flo-Pro. 250 GPM, 500 PSI, 40 RPM, 15K TO. Reciprocate pipe f/ 6620't/ 6648'. Obtain slow pump rates and observe well for flow - static. Rack back a stand to 6423', Blow down top drive.�Perform FIT to 12 ppg EMW. 9-5/8" shoe at 6650' MD 13999' TVD with 9.0 ppg Flo �J Pro mud, pressure up to 624 PSI. 1.2 bbl pumped and 1.0 bbl bled back. Rig down equipment and blow down Iines.;POOH f/ 6423't/ 1933'. Perform kick while tripping drill. Well secured in 1 min. 7 sec. and full response in 1 min. 45 sec. 200K PU 184K SO.;Hauled 290 bbls H2O from L-Pad lake for total = 5150 bbis Hauled 0 bbis heated H2O from G&I = 1130 Hauled 232 bbis cuftings/Iiquids to MPU G&I for total = 8745 bbis 6 bbis daily losses, 370.4 cumulative losses. 1/2/2019 POOH f/ 1933't/ 683'. UD 15 joints of HWDP and rack back stand with jars and stand of drill collars. UD mud motor and mill tooth bit. Bit grade: 1-1-WT-A-E-1- NO-BHA.;Clear rig floor and mobilize BHA components to the rig floor.:WU BHA #3:8-1/2" PDC bit, Geo-Pilot, MWD w/ ADR, DGR, PWD & directional to 86'.;Test & initialize MWD tools, difficulty communicating.;RIH w/ drill collars, HWDP and jars from the derrick to 273'. Pressure test Geo-Span lines to 2200 PSI - good. Shallow pulse test MWD tools w/ 500 GPM, 700 PSI - good.;Single in the hole with 5" NC-50 drill pipe f/ 273't/ 2156'. Break-in Geo-Pilot seals at 10, 20, 30, 40, 50 & 60 RPM w/ 2-3K TO. Pump 500 GPM, 850 PSI and function test Geo-Pilot. Continue to single in with 5" drill pipe H 2156'[/ 5744'. TIH from the derrick f/ 5744't/ 6594'.;Slip & cut drilling line. Calibrate block height and check crown-o-mai lines and wash down f/ 659411 6680' ;Drill 8-112" production lateral f/ 6680' V 7158', 478' drilled, 95.6/hr AROP. 475 GPM, 1160 PSI, 120 RPM, 15-17K TO, 4-14K WOB. 180 PU/75 SO1120 ROT. Obtain 4 each MWD checkshot surveys on the first 3 connections for IFR azimuth corrections.;Last survey at 6993.63' MD / 4009.52' TVD, 90.14° Inc, 123.89° azm, 23.2' from plan, 4.14' low, 22.8' Ieft.;Hauled 30 bbis. H2O from L-Pad lake for total = 5180 bbis Hauled 0 bbis heated H2O from G&I = 1130 Hauled 733 bbis cuttings/liquids to MPU G&I for total = 9478 bbis 0 bbis daily losses, 0 bbls cumulative losses for interval. 1/3/2019 Drill 8-1/2" production lateral F/ 7158' T/ 7819', 661' drilled, 1107h AROP. 475 GPM, 1280 PSI. 120 RPM, 15-17K TO, 4-14K WOB. 186 PU170 SO/118 ROT. OA-1 from 6,645'to 7,731' and (OA-1 top 6,645' md);Drili 8-1/2" production lateral F/ 7819' T/ 8383', 564' drilled, 94'1hrAROP. 475 GPM, 1280 PSI, 120 RPM, 15-17K TO, 4-17K WOB. 200 PU/68 50/118 ROT. OA-2 from 7,731' to 7,945' and (OA-2 7,731' md) OA-3 from 7,945' to 8383. (OA-3 top @ 7,945' md).;Pump tandem low vis then weighted sweeps at 8192'. 50% increase of cuttings observed.;Drill 8-1/2" production lateral F/ 8383' T/ 8647', 264' drilled, 88'/hr AROP. Remain in OA3.510 GPM, 1200 PSI, 90-120 RPM, 15-16K TO, 6-10K WOB. 198 PU/65 SO/119 ROT. Mud wt in 9.11 out 9.1, vis in 37 / out 38, ECD 10.2 ppg. Max gas 625u ;Top drive shut down. Called electrician for troubleshooting. No errors or trouble codes found. Reset top drive and resume drilling. Shut down later while drilling, found VFD cooling fan motor failed. Source replacement motor. Lower VFD house temp by A/C and partially open door to keep drilling.;Drill 8-1/2" production lateral F/ 8647' T/ 8856', 209' drilled, 83.6'/hr AROP. Remain in OA3. 490 PSI, 1270 PSI, 80 RPM, 17K TO, 10K WOB. 197 PU/65 SO/118 ROT. Mud wt. in 9.1 / out 9. 1, vis in 37 / out 41, ECD 10.3 ppg. Max gas 679u.;Drili 8-1/2" production lateral F/ 8856' T/ 9619, 754' drilled, 1257/hr AROP. 485 GPM, 1510 PSI, 80 RPM. 18K TO, 10K WOB. 205 PU/60 SO/115 ROT. Mud wt. in 9.1 / out 9.1, vis in 401 out 39, ECD 10.4. Max gas 959u. OA-3 from 8856'to 9249. (OA- 3 top @ 9,240' md).;OA-2 from 9240' to 9402'. (OA-2 top @ 9402' md) OA-1 from 9402' to 9610'. Pumped tandem low vis/weighted sweeps at 9046. 50% increase of cuttings observed. Last survey 9446.02' MD/4034.2' TVD, 91.80° Inc, 125.44° azm. 11.81' from plan, 8.4' low, 8.3' right.;Observe aired up mud coming back weighing 8.95 ppg and slight breathing on connections. Start degasser and add defoamer.;Hauled 445 bbis H2O from L-Pad lake for total = 5625 bbis Hauled 0 bbls heated H2O from G&I = 1130 Hauled 230 bbis cuftingslliquids to MPU G&I for total = 9708 bbis 0 bbis daily losses, 0 bbis cumulative losses 1/4/2019 Drill 8-1/2" production lateral F/ 9610'T/ 10934', 1324' drilled, 1107hr AROP. Drilling in OA1. 485 GPM,1530 PSI, 120-140 RPM, 13K TO, 8-11 K WOB.156 PU/ 69 SO/ 111 ROT. Mud wt. in 9.1 lout 9.2, vis in 34/ out 37, ECD 11.09. Max gas 650u.;Tandem low vis / weighted sweeps pumped at 10555'w/50% increase observed at shakers.;Dril18-1/2" production lateral F/ 10934'T/ 12293', 1359' drilled, 113'/hr AROP. 485 GPM, 1850 PSI, 120 RPM, 15K TQ, 2-11K WOB. 170 PU/60 SO/ 111 ROT. Mud wt. in 9.35/ out 9.4, vis in 42/ out 47, ECD 11.40. Max gas 322u. Drilled OA1 to 10990', OA2 f/ 10990't'11146', currently in OA3.;Tandem low vis /weighted sweeps pumped at 11977' was 650 strokes late w/60% increase observed at shakers. Last survey @ 12182.75' MD 14089.46' TVD, 88.35° inc, 127.78' azm, 65.1' from plan, 65' low, 2.6' right. In zone building up from OA3 to OA1.;Hauled 350 bbls H2O from L -Pad lake for total = 5975 bbls Hauled 0 bible heated H2O from G&I = 1130 } �.7 / 27/ a 6.14 Hauled 750 bbls cuttings/liquids to MPU G&I for total= 10458 bbls �,J 12 y 1/5/2019 Drill 8-1/2" production lateral F/ 12293'T/ 12624, 331' drilled, 110'/hrAROP. 485 GPM, 1850 PSI, 120 RPM, 15K TQ, 2-11K WOB. 170 PU160 SO/ 111 ROT. Mud wt. in 9.35 /out 9.4, vis in 42 /out 47, ECD 11.40.623 Max Gas. Drilled OAt to 10990', OA2 f/ 10990' U 11146', currently in OA1;While thinking we were building up from the OA3 to the OA2 we drilled out of the top of the OA1. Looking back looks like we faulted out of the OA3 to OA1 around 11580'. Consult geologist and POOH to 12250'. Build trough at 30 FPM & drop inc. Start Side track at 12287'30 FPH to drop INC.;Side track DN @ 12287' T/ 12345'. 30 FPH. We got a good side track and worked through a couple times with and without rotary. Good. Drill ahead at 12445' in the OA1 dropping to the OA 3 as per plan. Fighting shakers blinding off. Having to shut down and pull off btm Until shakers cleaned up.;Drill ahead F/ 12345'T/ 12820', 475' drilled, 797hr AROP. 485 GPM, 1850 PSI, 120 RPM, 15K TO, 2-11 K WOB, 170 PU/-- SO/ 111 ROT. Mud wt. in 9.1 / out 9.2, vis in 42 out 47, ECD 11.40, 336 Max Gas. Drilled out the btm of the OA3 thinking we were in the OA1.;Lost slack off weight at 12349'.;Backream out of the hole F/ 12820' T/ 12255'. Perform kick while tripping drill, well secure in 66 sec, all hands responded in 80 sec. 225K PU.;Perform 20 min.flow, check. Well breathing, rate slowed from 4 bbls/5 min to 3 bbls/5 min. Allow Sperry to change computers for sidetrack.;Sidetrack @ 12210'. Control drill F/ 12210' T/ 12240' Gp 307hr w/ 100% deflection @ 165L down to 87.5° inc, then t/ 100% 90L. Increase to 60'/hr F/ 1224U T/ 12254'. 395 GPM, 1270 PSI, 120 RPM, 21-22K TO, 9-15K WOB. 186 PU1--SO/102 ROT. Mud wt. in 9.1 lout 9.2, vis in 39 out 40, ECD 10.64 329u gas.;Mud blinding off shakers at 12226, slow to 168 GPM until cleaned up. Ream through sidetrack point F/ 12254'T/ 12195' twice then work through with no issues. Test new water pump house: transfer 100 bbls in 16 min.;Drill 8-12" production lateral F/ 12254'T/ 12537', 283' drilled, 491hr AROP. 450 GPM, 1600 PSI, 120 RPM, 25K TO, 15K WOB. 200 PU / - SO / 115 ROT. Mud wt. in 9.21 out 9.25, vis in 38 out 41, ECD 10.68 387u gas.;Last survey at 12373.44' MD / 4091.50' ND, 92.120° inc, 126.41 ° azm, 66.5' from plan, 65.82' low, 9.40' right- geo-steering as directed. Drilled into OA4 F/ 12272' T/ 12319. Currently in OA3 building up to OA1.;Hauled 805 bbls H2O from L -Pad lake for total = 6780 bbls 1 ?-t Hauled 0 bbls heated H2O from G&I = 1130 9110 Hauled 1099 bbls cuttings/liquids to MPU G&I for total =11557 bbls j % 0 bbls daily losses, 0 bbls cumulative Iosses.;Pipe skate waiting on parts to be fully operational. Ejectorsand buggy not working. Mitigation plan w/ rig crews to pickup or laydown joint of pipe if necessary. Progress in the past 24 hrs was 244'. This does not include 343' drilled in PBl or 610' drilled in PB2. 1197' actually drilled in 24 hrs. 1/6/2019 Drill 8-1/2" production lateral F/ 12537'T/ 13103', 566' drilled, 947hr AROP. 494 GPM, 1900 PSI, 120 RPM, 25K TO, 15K WOB. 200K PU / -- SO / 117K ROT. Mud wt. in 9.2 / out 9.25, vis in 38 out 41, ECD 10.8, gas 387u. Drilled from OA3 to OA1. Shut in L-50 for Injection.;Drill 8-1/2" production lateral F/ 13101' T/ 13950', 849' drilled, 1417hr AROP. 494 GPM, 2000 PSI, 120 RPM, 25K TO, 15K WOB. 200K PU / -- SO / 117K ROT Mud wt. in 9.2 / out 9.25, vis in 38 out 41, ECD 11.15, gas 310u. Drilling in the OA1. Start drop to the OA2 13800'& entered OA2 @ 13882'.;Drill 8-1/2" production lateral F/ 13950'T/ 14216, 265' drilled, 447hr AROP. 485 GPM, 1970 PSI,120 RPM, 22-28K TO, 9-15K WOB. 200 PU / -- SO 1113 ROT. Mud wt. in 9.2 / out 9.3, vis in 41 out 42, ECD 11.01, gas 333u. Conflnue to drop & entered OA3 @ 13996'.;Torque increased to 28K, slow rotary to 100 RPM w/ 27K TO. Increase lube from 0.5% to 1.5% with 0.5% Lo- Torq and 0.5% 776.; Drill 8-1/2" production lateral F/ 14215' T/ 14517%302' drilled, 151'/hr AROP. 490 GPM, 2110 PSI, 120 RPM, 20K TO, 10K WOB. 200K PU / -- SO / 114K ROT . Mud wt. in 9.25 / out 9.3, vis in 43 out 41, ECD 11.02 gas 454u.; Perform kick while drilling drill, 65 sec. well secured & 78 sec. all hands responded. Blow down top drive & perform 30 min. well observation. Well breathing, initial pumps off flow 12% down to 1 %. Start 6 bbls/5 min. (72BPH) & slowed to 4.5 bbls/5 min. (54 BPH) after 30 minutes. Service rig sim-ops;Drill 8-112" production lateral F/ 14517' T/ 14614', 97' drilled, 327hr AROP. 465 GPM, 1890 PSI, 120 RPM, 20K TO. 5-8K WOB. 195K PU / -- $O / 113K ROT Mud wt. 1n 9.25 / out 9.35, vis in 38 out 42, ECD 10.90 gas 856u. Begin weighting up to 9.4 ppg.;Bottoms up from flow check: brief increase 20% to 32% and gas increase 382u to 856u and oil blinded off shakers. Slow to 120 GPM while cleaning screens. Last survey at 14447.72' MD / 4086.7T TVD, 91.12' inc, 124.90° azm, 85.23' from plan, 84.40' low and 11.87' left. Geo -steering as per geology.;Hauled 695 bbls H2O from L -Pad lake for total = 7475 bible Hauled 0 bbls heated H2O from G&I = 1130 Hauled 650 bbls cuttings/liquids to MPU G&I for total = 12207 bbls 0 bbls daily losses, 0 bbls cumulative Iosses.;Drilled 59 concretions in the mother bore for a total thickness of 432' (55% of the lateral). No faults have been observed so far this lateral. Mitigation plan w/ rig crew to utilize pipe skate while repairs in progress. Repaired broken wire to fix ejectors & carriage motor will be replaced today. 1/7/2019 Observed 14 deg dogleg. Ream out F/14610' T/ 14614'. 120 RPM, 30 FPH, Drill F/ 14614't/ 14616', still see dogleg. Ream to reduced DL down to 9.5 DEG.;Drill ahead F/ 14616'T/ 14707'. 91'@ 60 FPH average. Back ream through to clean up. 488 GPM, 2080 PSI, 60 RPM, 20K TO, Bring MW to 9.4. ECD 11.1.;Blow down TD, Monitor well on Trip Tank. Well flowing back at 90 BBL per hr.;Drill ahead F/ 14707'T/1 4820' 113'. Looking for btm up. Had to slow pumps at btm up due to shakers blinding off.;Circ & condition at reduced rate while screeing down and shakers blinding off. Screen down to 140s on all shakers. 9.4 MW in and out.Only 350 Units of gas at btm up.;Drill ahead F/ 14820' T/ 15042'. 222' @ 63 FPH average. 350-488 GPM, 2080 PSI, 120 RPM, 23K TO, Bring MW to 9.4, ECD 11.0 Started losing 60 bbl per hr. Bring water to 50 bbl per hr. Slow Pump rate to help build volume. Slow from 450 to 388 & start gaining volume.;Drill 8-1/2" production lateral F/ 15042'T/ 15327', 285' drilled, 577hr AROP. 430 GPM, 1720 PSI, 120 RPM, 23K TO, 11-14K WOB. MW 9.4 in / 9.5 out, Vis 38 in / 39 out, ECD 10.85, max gas 200u.;Shakers blinding off. Reduce flow to 230 GPM, 700 PSI, 90 RPM, 25K TO, clean screens and circulate out oil wet cuttings. Max gas 105u.;Drill 8-12" production lateral F/ 15327' T/15388', 61' drilled, 417hr AROP. 405 GPM, 1520 PSI,120 RPM, 24K TO. 5-71K WOB. MW 9.4+ in / 9.5+ out, Vis 39 in / 42 out, ECD 10.74, max gas 908u.;Shakers blinding off. Reduce flow to 160 GPM, 480 PSI, 100 RPM, 21K TO, clean screens and circulate out oil wet cuttings. Rig LEL gas sensor at the shakers read 24% with red light alarm. Gas watch system was 120u. Level returned to 0% shortly after. Had 1201 u afterwards with no LEL.;Change screens on one shaker to 200 mesh, but ran over worse. Change back to 140 mesh. Change screens on one shaker to 120 mesh. Attempt to drill, after T to 15391'the shakers blinded off again. Change all screens to 120 mesh.;Last survey @ 15297.44' MD / 4066.28' TVD, 91.00° inc, 125.01' azm, 63.97' from plan, 63.89' low, 3.09 left. Geo -steering as per geologist. We have drilled 62 concretions in the mother bore for a total thickness of 479' (5.5% of the lateral).;Hauled 920 bbis H2O from L -Pad lake for total = 8395 bbls Hauled 0 bbis heated H2O from G&I = 1130 Hauled 924 bbls cuttings/liquids to MPU G&I for total = 1313 0 bbls daily losses, 0 bbls cumulative losses for interval. 1/8/2019 Continue to circ with shakers blinding off trying to get a higher flow rate above 160. Screen all shakers to 140s. Rig up trash pump to recover fluid from rock washer. Drill F/ 15388'T/ 15405'running fluid over the shakers but able to call TO due to fault crossed at 15385'.'Getting gas spikes above 645 units.;Slow pump rate to manage losses to rock washer. Bring wt to 9.8 ppg in and out. Stage up pumps to 450 GPM. On btm up from higher rate we got over 5026K units of gas. No rig alarms activated.;Top drive low oil light started flashing. Driller shutdown to check and TD and would not comeback on. Continue to circ at 450 gpm, 1800. Cant work pipe. Send hands up 60' in the derrick at 35 below to check and add oil. Get it reset and running again.;Bring wt to 10.0 Circ at 460 GPM, 1931 PSI, 120 RPM, 24K TO Back ground gas running 190.;Obsewe the well for flow and the well was flowing back at 1.2 BPM (72 BPI-).;CBU at 347 GPM = 1130 psi while working the 90' altering stopping points. Did not see any increase in gas at bottoms up (background gas 120 units). Continue to circulate while building tandem sweeps.;Pump 20 bbl low vis followed by 20 bbl high vis sweeps and continue to circulate. Had to vary the pump rate due to the shakers blinding off with crude. Begin to add lubes (lo-torque and 776) to bring the mud system from 1.5% to 4%. Did not see the sweeps come back across the shakers.;Mud weight dropped to 9.8+ ppg. Bring the mud weight back up to 10.0 ppg. Having issues with frozen mud products.;Last survey at 15405' MD, 4065' TVD, 90.87° Inc, 124.92° Az. Distance to Well Plan #09 = 62.29' (62.22' low and 3.10' left). 62 concretions have been drilled so far this lateral for a total footage of 479' (5.5% of the lateral).;Hauled bbls H2O from L-Pad lake for total = 9150 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 1150 bbls cutfings/liquids to MPU G&1 for total = 14281 bbls 1/16/2019 Continue to work pipe @ 12029' 3 BPM = 250 psi, 70 RPM. Notify town engineer that it appears the well bore sloughed in @ 12100'. Wait on orders for a plan forward, pull to 11982' rack 1 std back. Continue to work pipe 90' at 3 BPM = 260 psi, 70 RPM = 12.5K ft-lbs torque. Decision made to sidetmck.:Loss rate circulating at 6 bpm. PU 155K, SO 85K.;BD Geo span, BROOH 5 min std f/ 11982'to 9157' mcking back 29 stds 300 gpm, 900 psi, 100 rpm, 13k TQ with no j issues. SimOps: Load shed with 87 jts 5" NC50 DP previously UD, strap and tally same. Loss rate @ 9 bph BROOH;Blow down the top drive. PU, MU and RIH with 87 joints of NC50 DP from 9157' to 11885' (PU =150K and SO= 75K).;BROOH from 11885' to 11414' at 5 min/stand, 300 GPM = 950 psi, 60 RPM= 12K ft- Ibs torque.;Obtain slow pumps rates at 11414'(406& TVD) with 11.1 ppg mud. MP #1 -2 BPM = 260 psi; 3 BPM = 340 psi MP #2 -2 BPM = 260 psi; 3 BPM = 350 psi ;Begin open hole sidetrack at 11418'. Time drill from 11418'to 11505'. 420 GPM = 1620 psi, 140 RPM= 14Kft-lbs torque, WOB = 1-2K, MW = 11.1 ppg, Vis = 40, ECD = 12.1 ppg, Max gas = 57 units PU = 165K, SO = 75K, ROT = 115K.;PU to 11414' and work through new hole with no rotary two times without any issue.;Ddll from 11505' to 11682' (4077' TVD). 420 GPM = 1740 psi, 140 RPM =15K ft-Ibs torque, WOB = 5-10K, MW= 11.0+ ppg, Vis = 40, ECD = 12.21 ppg, Max gas = 270 units PU = 150K, SO = 115K, ROT=115K.;Hauled 525 bbls H2O from L-Pad lake for total= 13065 bbls l Hauled 0 bbls heated H2O from G&I = 1130 Hauled 150 bbls cuttings/liquids to MPU G&I for total = 20761 bbls;39 concretions have been drilled so far this lateral for a total footage of 273' (5.5% of the lateral). Last survey at 11532' MD, 4068' TVD, 87.29' Inc, 130.48' Az. Distance to Well Plan #05 = 0.31' (0.27' low and 0.14' left). 1117/2019 Drill 8 1/2" hole V 11682' to 11984' (4072' TVD) 302' ( avg top 50.3 fph) 427 GPM = 1750 psi, 140 RPM= 15K ft-lbs torque, WOB = 8-10K, MW in/out 10.9/ 11 ppg, Vis = 41, ECD = 12.29 ppg, Max gas = 411 units PU = 165K, SO = 60K, ROT= 112K.;Gradually lower mud wt 11+ to 10.9 ppg to help control ECDs, 20 bph loss rate drilling, 3 bpm flow back during connections. Note: start seeing traces of oil on shakers @ 11930'.;Drill8 12" hole f/ 11984' to 12480' (4063' TVD) 496' ( avg top 82.6 fph) 430 GPM =1750 psi, 140 RPM = 15-18K ft4bs torque, WOB = 5-15K, MW 10.9 ppg, Vis = 42, ECD = 12 ppg, Max gas = 359 units PU = 165K, SO = 55K, ROT=113K.;Back team 60' before connections, with 10.9 ppg MW -decreased loss rate to 5 bph drilling and 1 bpm flow back at connections.;Drill 8-1/2' production hole from 12480'to 12873' (4061' TVD), 393' with AROP of 65.5 FPH. Back ream 60' prior to connections. 425 GPM = 1700 psi, 140 RPM = i 8K ft-lbs torque, WOB = 11 K, MW = 10.8+ ppg, Vis = 42, ECD = 12.01 ppg, Max gas = 317 units PU = 178K, SO = 50K, ROT = 119K.;Drill 8-12" production hole from 12873'to 13270' (4080' TVD), 397' with AROP of 66.2 FPH. Back ream 60' prior to connections. 411 GPM = 1740 psi, 120 RPM= 20K ft-lbs torque, WOB = 5-7K, MW = 10.9 ppg, Vis = 41, ECD = 12.2 ppg, Max gas = 366 units PU = 183K, SO= OK, ROT= 112K.At 13000' pumped a tandem hUlow sweep (20 bbls each) and did not see it come back across the shakers.;Hauled 425 bbls H2O from L-Pad lake for total = 13490 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 342 bbls cuttings/liquids to MPU G&I for total = 21103 bbls;50 concretions have been drilled so far this lateral for a total footage of 343' (5.3% of the lateral). Last survey at 13135' MD, 4076' TVD, 87.35' Inc, 122.66° Az. Distance to Well Plan #05 = 32.44' (2.02' low and 32.38' right). 1/18/2019 Drill 8-12" production hole from 13270' to 13488' (4086' TVD), 218' with AROP of 36.3 FPH. Back ream 60' prior to connections. 403 GPM = 1730 psi, 120 RPM = 20K ft-lbs torque, WOB = 5K, MW = 10.8+ ppg, Vis = 44, ECD = 11.88 ppg, Max gas = 348 units PU = 180K, SO = OK, ROT = 110K.;Lower mud weight from 10.9 ppg to 10.8 ppg, losses at 4 BPH drilling, 2 BPM flow back during connections.;Drill 8-12" production hole from 13488'to 13812' (4084' TVD), 324' with AROP of 58.9 FPH. Back ream 60' prior to connections. 402 GPM = 1710 psi, 120 RPM = 24K ft-Ibs torque, WOB = 8K, MW = 10.8 ppg, Vis = 45, ECD = 11.91 ppg, Max gas= 362 units PU = 195K, SO= 40K, ROT= 110K.;At 13790' the bit glanced off a concretion causing a 13" dog leg. BROOH to 13720' and work to straighten out the dog leg by time drilling on the concretion at 407 PGM = 1730 psi, 120 RPM= 24K ft-lbs torque, 2-3K WOB to 13812'. Survey from 13794' to 13889' showed 1.88° dog leg ;Drill 8-1/2" production hole from 13812'to 14090' (4077' TVD), 278' with AROP of 46.3 FPH. Back ream 60' prior to connections. 420 GPM = 1820 psi, 120 RPM= 24Kft-lbs torque, WOB = 10K, MW= 10.8 ppg, Vis = 48, ECD = 12.25 ppg, Max gas = 367 units PU = 205K, SO= 40K, ROT= 112K.;Hauled 325 bbls H2O from L-Pad lake for total = 13815 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 285 bbls cuttings/liquids to MPU G&I for total = 21388 bbls;Last survey at 13984' MD, 4084' TVD, 92.36° Inc, 123.24° Az. Distance to Well Plan #05 = 19.a4'(1 8.88'low and 6.09' left). 63 concretions have been drilled so far this lateral for a total footage of 408'(5.5% of the lateral). 1/19/2019 Drill 8-1/2" production hole from 14090'to 14337' (4063' TVD), 247 with AROP of 41.1 FPH. Back ream 60' prior to connections. 404 GPM = 1850 psi, 120 RPM= 26K ft-Ibs torque, WOB = 9K, MW= 10.8 ppg, Vis = 50, ECD = 12.28 ppg, Max gas = 336 units PU = 214K, SO= 40K, ROT= 115K.;Drill 8-1/2" production hole from 14337' to 14621' (4056' TVD), 284' with AROP of 47.3 FPH. Back ream 60' prior to connections. 423 GPM = 2090 psi, 100 RPM = 27K ft- Ibs torque, WOB = 7K, MW = 10.8 ppg, Vis = 50, ECD = 12.32 ppg, Max gas = 338 units PU = 220K, SO = 40K, ROT = 110K.;Drill 8-1/2" production hole from 14621' to 14801' (4051' TVD), 180' with AROP of 60 FPH. Back ream 60' prior to connections. 410 GPM = 2000 psi, 100 RPM= 251(ft-Ibs torque, WOB =11K, MW = 10.8 ppg, Vis = 50, ECD = 12.45 ppg, Max gas= 248 units PU = 215K, SO= 40K, ROT= 107K.;Pump tandem low/hi sweeps (20 bbls each) and circulate into the shoe at 415 GPM = 2010 psi reciprocating the DP 99. ECO's dropped to a 12.05. Increase the lubes to 1.5%. Did not seethe sweep comeback over the shakers.;Drill &12" production hole from 14801'to 15013' (4048' TVD), 212' with AROP of 32.6 FPH. Back ream 60' prior to connections. 420 GPM = 2000 psi, 120 RPM= 24K ft-lbs torque, WOB=10-14K, MW= 10.7 ppg, Vis = 48, ECD = 12.45 ppg, Max gas = 248 units PU = 200K, SO= 40K, ROT= 112K.;Hauled 400 bbls H2O from L-Pad lake for total = 14215 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 321 bbls cuftings/liquids to MPU G&I for total = 21709 bbls Daily losses to the formation = 212 bbls;Last survey at 1492T MD, 4049' TVD, 91.06' Inc, 128.24' Az. Distance to Well Plan #05 = 61.93'(1 6.36'low and 59.73' left). 71 concretions have been drilled so far this lateral for a total footage of 489' (5.9% of the lateraD. 1120/2019 Drill 8-1/2" production hole from 15013'to 15082' (4047' TVD), 69' with AROP of 15 FPH. 420 GPM = 2000 psi, 120 RPM= 26K ft-lbs torque, WOB=15-18K, MW = 10.6+ ppg, Vis = 45, ECD = 12.07 ppg, Max gas= 172 units PU = 203K, $O = 40K, ROT= 109K.;ROP dropped to 2 FPH, consult with town, decision made to call TO at 15082', 4047' TVD in OA1. TD was called due to ROP dropping considerably despite no indications of concretions in the formation. Suspecting dull/worn bit. Obtain final survey.;Circulate 3 BU, condition mud and cleanup well bore, 410 GPM = 1910 psi, 110 RPM = 22k ft-Ibs torque, reciprocate pipe 90', increase lube from 1.9% to 2.5%. ( crude/lube content= 4% ) lower YP from 20 to 16. Rack 1 stand back after each BU. MW inlout = 10.7 ppg and vis = 48.;Wash and ream to TD. no fill. Flow check well for 10 min, started 1 BPM slowing to 0.68 BPM and continuing to slow down.;BROOH from 15082' to 11508' at 5 min/stand, 400 GPM = 1680 psi, 100 RPM= 15K ft-lbs torque, PU = 170K, SO= 70K and ROT= 120K. Continues to flow back at connections with 6BPH loses with pumps on.;Confinue to BROOH from 11508' to 8655' at 5 min/stand, 400 GPM = 1680 psi, 100 RPM= 15K ft-lbs torque, PU = 170K, SO = 70K and ROT = 120K. Continues to flow back at connections with 68PH loses with pumps on.;Hauled 345 bbls H2O from L-Pad lake for total = 14560 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 221 bbls cuttings/liquids to MPU G&I for total = 21930 bbls Daily losses to the formation = 169 bbls;Last survey at 15082' MD, 4047 TVD, 90.50° Inc, 129.32° Az. Distance to Well Plan #05 = 52.13' (19.73' low and 48.26' Hilcorp Energy Company Composite Report Well Name: MP M-10 Field: Milne Point Unit County/State: , Alaska i (LAT/LONG): evation (RKB): 34.03 API #: Spud Date: 12125/2018 Job Name: 1813837C MPU M-10 Completion Contractor AFE #: AFE $: Activity Date. Ops Summary 1/9/2019 Wash back to bottom at 15405' at 163 GPM = 410 psi, 120 RPM = 18K ft -lbs torque.,BROOH from 15405' to 14425', 175 - 375 GPM = 380-1100 psi, 100 RPM = 18K ft -lbs torque, max gas = 4202 units at bottoms up. At connections the well was flowing at 80 BPH.,Circulate at 161 GPM = 310 psi, 100 RPM = 19-201< Vlas torque, reciprocating from 14425'to 14331'. The mud is getting gas out and foaming up. Shakers are blinding off and having trouble keeping the mud weight up. Consult with drilling engineer and decided to displace to new 10.5 ppg mud.,TIH from 14425' to 15398' at 250 GPM = 620 psi, 80 RPM = 16K ft -lbs torque, PU = 185K, SO = 40K and ROT = 121 K. Had no issue getting back to bottom.,Wait for 580 bbls of 10.5 ppg mud from Deadhorse. Circulate at 275 GPM = 790 psi, 80 RPM = 20K ft -lbs torque reciprocating from 15399 to 15306' alternating stopping points. SimOps: Clean pit 4 &5, rock washer, pill pit and trip tank. Load pit o with 10.5 ppg mud. Build 200 bbls of 10.5 ppg mud in pit 5. Build 30 bbl 10.5 ppg spacer pill. Still having issues with frozen mud products.,The fourth load of 10.5 ppg mud arrived at 03:00 hours but an air line failed on the tracker upon reaching location. Called for a Peak mechanic to repair the air Iine.,PJSM for displacement with rig crew and Peak truck drivers.,Pump remaining 10.0 ppg mud in pits 1-3 to the rock washer. Pump 20 bbl 10.5 ppg spacer pill followed by 10.5 ppg mud.,Hauled 750 bbls H2O from L -Pad lake for total = 9900 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 1256 bbls cuttings/liquids to MPU G&I for total = 15537 bbls,Rig Fuel (gallons): OH = 5270, Used = 3164 & Rec = 0 1/10/2019 Continue to displace to 10.5 ppg flow pro. Pump 1300 bbl of 10.5 ppg mud taking returns to the rock washer. Still getting 10-10.3 back. No new mud back at surface.Out of mud. Shut down and well was flowing at 60 BPH. Took back 10 bbl to trip tank while monitoring. Returning mud has lots of oil breaking out.,Shut in well with top VBR rams against a closed choke & kill on 5" DP & Full open safety valve installed on 1-10-2019 @ 11:25. Pressure built to 85 psi on the annulus in 4 hrs. Bump float & SIDPP 90 psi. Build 180 bbl 10.5 Flow Pro mud while waiting on mud from the Mud plant. Open up choke taking back 4 bbl to trip tank. Open Top rams. Pump at 5 bpm 180 bbl still getting old mud back.,Pump at 5 bpm 180 bbl still getting old mud back at 10.0 PPG. Lots of oil in returns. Mud aired up. Well still flowing with the pumps off.,Shut down and shut in well on 1-10-2019 @ 17:34 with top VBR rams against a closed choke and kill on 5" DP with full open safety valve installed. Initial SICP = 55 psi. SCI dropped to 48 psi in 1 hr. Al midnight SICP = 37 psi. Continue to monitor casing pressure: SICP = 36 psi since 01:40 hours.,Consult Drilling engineer and mudman and decide to go to Bromide system to prevent greasing out the mud due to oil contamination. Build 200 bbls of 10.5 ppg mud in pit 5. Clean pits 1-3. Order out 750 bbl 12.2 Bromide for spike fluid to weight up the mud system. Roll Mud through gas buster to prevent freezing.,Take on 290 bbls of 11.0 ppg mud, water back to 10.5 ppg and roll the pits to get a consistent 10.5 ppg throughout. Pit 2 had a pinhole leak inside the rig and emptied pit 2. Call out welder to repair.,Rig Fuel (gallons): OH = 9095, Used = 2056 & Rec = 5881,Hauled 730 bbls H2O from L -Pad lake for total = 10630 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 2240 bbls cuttingsfliquids to MPU G&I for total = 17777 bbls 1/112019 Welder repairing pinhole leak in pit 2. Build surface volume in pits up to 500 bbl of 10.5 Flow pro. Well shut in for 12 hours holding at 36 psi on the annulus. Bleed down to 0 & well flowing slightly. Open top rams & break over with ROT at 100 RPM. No problem. Stage up pumps to 5 bpm while dumping all returns. Pump an additional 270 bbl to rock washer until we got 10.4+ back. Take back to pits.,Pumped a total of 1800 bats. Got a 60 bbl slug of peanut butter looking mud, possibly from bottoms up at flow check. Dump to rock washer. Shut down to flow, check. Well flowing at 20-30 BPH. Let flow back 7 bbl. Circulate & condition keeping 10.5 ppg mud going in.,Starting to lose to formation at 5 BPM. Slow to 4 BPM with 20% losses. Circulate & condition clearing bottoms up. Gas breaking out but mud in good shape and looking good.,Consult with town engineer and decide to add bromide to bring weight up to 10.7 ppg as we BROOH 1009. BROOH at 5 min/stand pulling speed F/ 15405' T/ 14456'. Well flowing on connections. Torque increased and stalled out at 15149. Worked through slow without issue. 24K TO @ 100 RPM. Circulating at 160 GPM.,CBU loosing 20% at 4 BPM = 490 psi, 100 RPM = 20K ft -lbs torque and working pipe 90'. Did not see any increase in gas at bottoms up. Continue to keep 10.7 ppg going in. Add Lubes. Build batch of 10.7 ppg in pit S.,BROOH from 14456'to 12098' at 5 min/stand, 4 BPM = 480 psi, 100 RPM = 20-26K ft -lbs torque. Observed 10-15K drag from 13980' to 13890'. Dropped back down and came back up slowly with no drag.,CBU at 4 BPM = 480 psi, 100 RPM = 16.18K ft -lbs torque and working pipe 99. SimOps: Build 180 bbls of 10.7 ppg mud.,BROOH from 12096 to 11905' at 5 min/stand, 4 BPM = 480 psi, 100 RPM = 17-21 K ft -lbs torque.,Hauled 250 bbls H2O from L -Pad lake for total = 10880 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 780 bbls cuttings/liquids to MPU G&I for total = 18557 bbls,Rig Fuel (gallons): OH = 6480, Used = 2615 & Rec = 0 1/12/2019 BROOH F/ 12095' T/11775'. 4 BPM, 120 RPM. Pull tight with no torque increase.,Work up into tight spot attempting to back ream. Over pull into itworking wt F/ 5-50K over pull. Not getting much tq increase. Play with parameters with RPM, pumps & over pulls. Looks like we were making hole a couple feet up. Tryto strait pull with no success. Jars firing on the up stroke so we let them bleed off before over pulling.,Pull up to 75K over with rotation. RIH one stand T/ 11895. Back ream out slowto 11775'. 8 bpm. Losing 30-60 BPH while pumping. Flowing on connections 30 BPH„Slow RPM to 20 & pull into tight spot. Wt fell off and we made 10' up stroke. Pulled tight. Would not go back down. Try to hammer down playing with RPM & pumps. Try jarring light and hammering down. No luck. Continue to hammer down on bumper sub. Shutdown and perform derrick inspection as needed for jarring.,Spot lube pill at the bit and pump out at.5 BPM. Shut down pumps and hammer down for 10 min. Pump another couple bbis and hammer down for 10 min. Do this cycle until sweep is past BHA. Two hm of hammering down. Put Geopilot at 100% deflection and 400 gpm and hammer down. No luck. Losing 1.5 BPM while at the higher rates. Flowing when pumps are off at .5 bpm.,Start jarring up working over pull up to 125K over. Jars working good and BHA showing G force from jarring. Perform Derrick inspection.,Hammer down at 4 BPM = 480100 RPM = 12K ft -lbs torque.,Warm up the jars and jar at 340K (170K Over on Jars) with straight pull up to 375K. Perform derrick inspections.,Turn on the rotary at 50 RPM, 4 BPM = 480 psi and jar at 225K with straight pull to 375K. Made 2' and lost rotary. Attempt regain rotary but unable too. Continue to jar at 315K with straight pull to 375K.,Break out a double and lay down a single. Continue tojar at 315Kwith straight pull to 375K at 4 BPM = 480 psi. On the fourth jar hit the pipe was free. POOH to 11775' on elevators (PU = 150K).,BROOH from 11775' to 11227' at 4.5 BPM = 550 psi, 100 RPM= 12K ft -lbs torque.,At 11227' pulled tight and stalled out. Unable to go down and unable to fire the jars. Work the pipe up to 250K and down to SOK at 5 BPM = 600 psi. Trap 20K ft -lbs torque at 120K up weight, hammer down to 50K and pipe broke free.,SO 60' and BROOH from 11287' to 11215' at 8 BPM = 1200 psi, 100 RPM =141(ft-lbs torque.,Continue to BROOH from 11215' to 9715' working through cutting beds at 9 BPM = 1240 psi, 100 RPM= 10 -201<11 -lbs torque.,Hauled 150 bbis H2O from L -Pad lake for total = 11030 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 256 bbls cuttings/liquids to MPU G&I for total = 18813 bbls,Rig Fuel (gallons): OH = 10910, Used = 2550 & Rec = 6980 1 /1 312 01 9 Back Ream out of the hole F/ 9715' T19515'. 388 GPM, 5-10 Min per stand.,Pump tandem 40 bbl weighted high vis/ Low vis sweep around at 480 GPM, 120 RPM. Did not see any increase in cuttings only safe Garb with lots of oil in it. Looked clean. Sweep came back on time.,Back ream out of the hole F/ 9515'T/ 6650' (Shoe) 5-10 Min per stand slowing as tq would increase or over pull. 388 GPM, 120 RPM. No issues. Wipe back trough over pulls. Cleaned up good.,Circ btm until clean. Got very fine silt & oily safe carbs back.,Wt up to 11.0 PPH. Monitor well & well flowing at 14 BPH.,PJSM. Install FOSV and hang the blocks. Slip and cut 92' of drilling line. Service the draw works. SimOps: Continue to observe the well and flow rate was down to 6 BPH. Begin to circulate and weight up the well to 11.2 ppg.,Continue to weight up the well from 11.0 to 11.2 ppg at 9 BPM = 900 psi, 80 RPM working the pipe 90', ECD=11.58.,Lay down the FOSV and blow down the top drive. Observe the well. Initially the well was flowing at 3 BPH but it reduced to 1 BPH in 2.5 hours. SimOps: Off load 11.2 ppg mud to a truck to make room for weighting up.,Weight up the well from 11.2 ppg to 11.4 ppg at 9 BPM = 900 psi, 80 RPM working the pipe 90', ECD = 11.71.,Observe the well for flow and the well is on a slight vac. Establish static loss rate of 4 BPH.,TOOH from 6594'to 3003'. Loosing 1-2 bbls over displacement every 5 stands.,Hauled 175 bbls H2O from L -Pad lake for total =11205 bbis Hauled 0 bbls heated H2O from G&I = 1130 Hauled 206 bbis cuttings/liquids to MPU G&I for total = 19019 bbis Rig Fuel (gallons): OH = 8160, Used = 2750 & Rec = 0 Vac truck glycol line failed spilling 8 gallons into containment and 1 gallon to the gravel pad. 1/14/2019 POOH laying down DP from 3003'to 273'.,Lay down 5” HWDP, combo jars, 5" HWDP and three flex collars. Pull up and inspect the bit. Bit grade = 2-2-BT-T-X- 1-CT-TD.,Attempt to download MWD data but having computer issues. Monitor the well on the trip tank with loses at 5 BPH. SimOps: Prep to change rams, test BOPE and flush the stack.,Lay down remaining BHA components„PU and MU the stack wash tool, jet the stack and lay down the stack wash tool. Pull the wear ring and install the test plug. Pull both mouse holes.,PJSM. Change the upper pipe rams to 4-1/2"x 7” VBR's.,RU to lest ROPE. Attempt to shell test but unable to build pressure. Test plug was installed upside down. Reinstall test plug and shell test good.,Conduct biweekly BOPE test to 25013000 psi: Lower pipe rams (2-7/8" x 5" VBR's) with 3-1/2 and 5" test joints, upper pipe rams (4-1/2" x 7" VBR's) with 5" and 7" test joints, annular with 3-1/2" and 7" test joints to 25012500 psi, accumulator drawdown test and test gas alarms. The states right to witness was waived by AOGCC inspector Lou Laubenstein via email on 1/14/19 at 16:15 hours.,Tests: 1.UPR with 5" test joint, 3" Demco kill, lower IBOP, choke valves 12,13 & 14 (passed)2.HCR kill, upper IBOP, choke valves 9 & 11 (passed)3.Manual kill, 5" FOSV #1, choke valves 5, 8 & 10 (passed)4.5" FOSV #2, choke valves 4, 6 & 7 (passed) 5.5" dart valve, choke valve 1 & 2 (passed)6.HCR choke (passed) 7.LPR with 5" test joint (passed).,Accumulator Test: System pressure = 2950 psi Pressure after closure = 1600 psi 200 psi attained in 50 seconds Full pressure attained in 207 seconds Nitrogen Bottles - 6 at 2000 psi.,Tests: 8.Annular to 2500 psi with 3-112" test joint (passed) 91PR with 3-1/2" test joint (passed) 10.UPR with 7" test joint, manual choke (passed) 11.Annular to 2500 psi with 7" test joint (passed) 12.Blind rams, choke valve 3 (passed) 13.Hydraulic super choke (passed) 14.Manual adjustable choke (passed).,RD BOPE testing equipment. Pull the test plug and install the wear ring. Blow down the choke manifold. Blow down the choke and kill Iines.,Hauled 1335 bbis H2O from L -Pad lake for total = 12540 bbis Hauled 0 bbls heated H2O from G&I = 1130 Hauled 665 bbis cuttings/liquids to MPU G&I for total = 19684 bbis Rig Fuel (gallons): OH = 11540, Used = 1488 & Rec = 4868 1/15/2019 PU and MU BHA#4 - cleanout assembly: 8-1/2" NOV PDC bit, bit sleeve, Geo -Pilot, LWD and MWD, flex collars, roller reamer, HWDP, Hydra -Jar, HWOP.,Upload to MWD tools.,Continue to PU and MU BHA#4 - cleanout assembly:3 flex collars, roller reamer, HWDP, Hydra -Jar, HWDP. Total BHA length = 280.11'.,TIH with BHA #4 from 280' to 6606' (PU = 125K and SO = 100K) filling DP every 20 stands.,Break circulation and CBU at 200 GPM = 420 psi and 40 RPM = 4K ft -lbs torque. Obtain slow pump rates: MP #1 - 2 BPM = 100 psi, 3 BPM = 140 psi MP #2 - 2 BPM = 100 psi, 3 BPM = 160 psi.,Blow down the top drive. Grease the IBOP and swivel.,Continue to trip in open hole on elevators from 6606'to 10853', started taking weight at 10820' filling DP every 1000'.,Wash down from 10853' to 11513' at 3 BPM = 270 psi without any issues.,Wash and ream from 11513' to 11732' at 350 GPM =1080 psi, 100 RPM= 14K ft -lbs torque. Work fight spots washing, reaming and back reaming from 11732'to 117751. Work from 11702' to 11796' several times. Wash and ream from 11796'to 11985'. Work from 11985' to 11890' working the roller reamer from 11605 to 11710'.,Wash down from 11985' to hard tag at 12100' at 3 BPM = 260 psi.,Attempt to work past but are being deflected up. PU to 12085, orientate down, attempt to work past but still being deflected up. It appear that the well bore sloughed in. Consult with DD from the I-rig.,Hauled 525 bbis H2O from L -Pad lake for total = 13065 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 927 bbls cuttings/liquids to MPU G&I for total = 20611 bbis Rig Fuel (gallons): OH = 9445, Used - 2095 & Rec = 0 1 /1 612 01 9 Due to well sloughing in at 12095', decision made to sidetrack, continue with drilling AFE @ 06:00 HRS. Refer to drilling report. 121/2019 Continue to BROOH from 8655'to 6832', pull W/O rotating to 6648' inside 95/8" casing pulling 5 min/stand, 400 GPM = 1680 psi, 100 RPM = 15K ft-lbs torque, PU = 170K, SO = 70K and ROT = 120K. Continues to flow back at connections with 6BPH loses with pumps on. 47 bbl losses BROOH.,Pump 30 bbl 11.9 ppg weighted sweep around 400 gpm, 1350 psi, 80 rpm, 7k torque, reciprocate pipe f/ 6648 to 6600', no increase at sweep returns. Rack 1 stand back, WU FOSV, 5' pup and TO. PJSM for weighting up and slip and cut drlg Iine.,Parked at 6612' Circulate 6 bpm, 520 psi weight up from 10.7 ppg to 10.8 ppg MW. SimOps: Slip and cut 86drilling line and service the top drive.,Continue to weight up from 10.8 ppg to 11.4 ppg in/out at 6 BPM = 700 psi, rotating at 45 RPM and slowly working the pipe 90'. SimOps: PT 3-1/2" IF FOSV and dart valve to 250/3000 psi for 5 minutes each (good tests).,Obsome the well for flow. The well flowing at 1 BPH slowing down to 0.25 BPH. PU 90' and the well was swabbing. SO 90' and the well was surging. SimOps: Blow down the top drive. Inspect the saver sub for wear (all good).,Weight up from 11.4 ppg to 11.5 ppg at 7 BPM = 850 psi, rotating at 45 RPM and slowly working the pipe 99. 11.5 ppg inlout with vis in/out = 54/59.,Obsewe the well for flow. The well flowing at 0.25 BPH to static. PU 90' and the well was swabbing. SO 90' and the well was surging.,Pump out of hole laying down DP from 6648! to 6042'.,Hauled 100 bbls H2O from L-Pad lake for total = 14660 bbls Hauled 0 bible heated H2O from G&I = 1130 Hauled 171 bbls cuttings/liquids to MPU G&I for total = 22101 bbis Rig Fuel (gallons): OH = 7950, Used = 2610 & Rec = 0 1222019 Continue to Pump out of hole 5 bpm, 440 psi laying down 5" DP from 6042'to 5600'.,P/U 60', swabbing, S/O 60', surging, BD top drive, monitor well slight flow, reducing to static in 15 minutes.,Continue to Pump out of hole 5 bpm, 440 psi laying down 5" DP from 5600'to 2201'. Every 1000' pulled flow check well, swab and surge at 5500', 4500' & 3500'. Swab only at 2509.,Service rig.,Continue to pump out of the hole f/ 2201' V 1886'w/ 5 BPM, 400 PSI.,Observe well, no swab or surge. POOH on elevators f/ 1886' it 289. Perform 20 min. flow check, dropping slightly at 2.25 BPH.,UD BHA#4 from 280'. Roller reamer in good condition. 100% data read from MWD tools. 1/2" wide, 1/8" deep groove wore around in-line stabilizer. Bit graded 2-4-BT-N-X-1-CT-TD. BHA clean with no balling. 2.7 bible lost during 1.5 hours reading MWD tools. Clear rig floor of BHA components. 87 bbis lost total while pumping/tipping out.,L/D 66 joints of 5" drill pipe from the derrick in the mousehole. Monitor well with hole fill pump, 8.5 bbis lost over 3 hours.,Hauled 50 bible H2O from L-Pad lake for total = 14710 bbis Hauled 0 bbis heated H2O from G&I = 1130 Hauled 57 blots cudings/liquids to MPU G&I for total = 22158 bbls 186.3 bbis daily losses, 1377.3 bbis cumulative Iosses.,Rig fuel (gallons): On hand = 11125, Used = 2250, Recd = 5425 1/23/2019 L/D 12 joints of 5" drill pipe from the derrick in the mouse hole. Move 5 stands of 5" drill pipe from DS to ODS of derrick. Monitor well with hole fill pump, Monitor well, static loss rate 2.5 bph.,Load 5" HWDP into pipe shed, PJSM for PIU HW in mouse hole.,Drift and P/U 159 its 5" HWDP using mouse hole racking back 53 stands in derrick. Static loss rate continues at 2.5 bph.,PJSM. R/U to run 6-5/8" pre-drilled liner. R/U Doyon casing 85/8" double stack power tongs, 6-5/8" HYC elevators and hand slips. M/U Hydril 563 Wedge safety joint: 6-5/8" H563 pin x 4-12" IF box XO, V' drill pipe joint, 4-1/2" IF FOSV, 6-5/6'H563 box x 4-12" IF pin XO.,P/U 4-1/2" float shoe, WIV, 4-1/2" joint of liner, drillable Pac-Off sub, 4-1/2" pup joint & 4-1/2" BTC pin x 6-5/8" Hydril 563 box XO. M/U 6-5/8" 20# L-80 Hydril 563 Wedge pre-drilled liner to 491', joint #11 in the hole and joint #12 hanging. Torque connections to 7,100 Polbs. Install 6-5/8"x8-1/7' rigid straight vane centralizers on each joint.,injury to foot on rig floor. Notify Milne Point security & request medical personnel. Stabilize injured person & transportto Milne Point clinic. Perform investigation w/ Doyon safety. Doyon field superintendent inspect pipe skate area where incident occurred. Milne Point foreman gave permission to return to work. Hilcorp DSMs had discussions with both rig crews.,Conduct thorough PJSM, hazard recognition and mitigation with the new crew. Monitor well on trip tank, 1.1 bbl lost over 3 hours.,Continue to run 6-5/V'20# L-80 Hydril 563 Wedge pre-drilled liner from 491'to 2974'. Torque connections to 7,100 ft/lbs. Install 65/8"x8-12" rigid straight vane centralizers on each joint.,Hauled 75 bbis H2O from L-Pad lake for total = 14785 bbis Hauled 0 bbls heated H2O from G&I = 1130 Hauled 57 bbis cuttings/liquids to MPU G&I for total = 22215 bbls 41.9 bbis daily losses, 1419.20 bbis cumulative Iosses.,Rig fuel (gallons): On hand = 9720, Used = 1855, Rei d = 0 1242019 Continue to run 6-5/8" 20# L-80 Hydril 563 Wedge pre-drilled liner from 2974'to 6618' atjt 162 just above 9 5/8" shoe, get parameters before continuing in open hole, PU 127K, SO 87K. Continue running casing to 6739', 165 its. Torque connections to 7,100 ft/lbs. Install 6-5/8"x8-1/2" rigid straight vane centralizers on each joint. 2 BPH loss rate over calculated displacement.,Continue to run 65/8" 20# L-80 Hydril 563 Wedge pre-drilled liner from 6739! to 85691, ( 210 its total ran) Note: last 3jts ran solid liner. Torque connections to 7,100 ft/lbs. Install 6-5/8"x8-1/2" rigid straight vane centralizers on each joint, ( 210 total centralizers ran ) 2 BPH loss rate over calculated displacement for 42 bbl total losses running liner. PU 140, SO 80K.,Monitor well with trip tank. PJSM for rigging up to run 3-12" inner string, review well control plan using safety jt. R/U False table and handling equipment, ready 5" jt of DP with triple connect, XOs, and FOSV. 1 bbl lost while rigging up.,PJSM for running 3-1/2" inner string. PN 2-3/8" slick stinger, XO coupling, circ sub (5 shear screws - 4690 PSI shear), XO sub & 3-12" pup joint. Run 3-1/2" 9.3# L-80 EUE tubing inner string to 2342'. Torque to 2800 ft/lbs with Doyon casing double stack tongs. Replace joint #56, 31.26' out, 31.22' in. Losses at 1 SPH.,Run 3-1/2" 9.3# L-80 EUE tubing inner string from 2342'to 5508'. Torque to 2800 ft/lbs with Doyon casing double stack tongs. Losses at 1 BPH.,Hauled 75 bbis H2O from L-Pad lake for total = 14860 bbis Hauled 0 bbis heated H2O from G&I = 1130 Hauled 149 bbis cuttings/liquids to MPU G&I for total = 22364 bbis 51.3 bbis daily losses, 1470.50 bole cumulative Iosses.,Rig fuel (gallons): On hand = 7560, Used = 2160, Rec'd = 0 125/2019 Run 3-1/2" 9.3# L-80 EUE tubing inner string from 5508'to 8526. (276 jts) M/U tag jts #277 and 278, nogo 35' in @ 8559.95', UD tag jts, PU 85K, SO 55K. Torque to 2800 fVlbs with Doyon casing double stack tongs. 18 bbl losses TIH w/ tbg.,Space out inner string as per BOT rep using 4 - 31/2" tbg pups= 8.30', 8.15', 6.09', 4.10' putting inner string 6.15' off nogo @ 8553.8', Swap to 5" elevators„ P/U M/U 7 X 9 518 SLZXP LTP assy to 3 1/2" tbg, C/O power tongs, M/U packer assy TO 6 5/8 stump. ( packer set to shear @ 2648 psi, with 8 screws ) RID power tongs. Monitor well with trip tank, static loss rate 1 bph.,Aftempt to free liner @ 8569' pulling up to 375k„ slacking off to 40k, M/U TD, break circulation, full returns at 2 bpm, continue to work pipe free pulling up to 400k with no movement. Increase pump to 3.5 bpm, 650 psi, 18 bbl losses in 30 min attempting to free pipe, slow pump to 1 bpm and continue to work pipe.,Hold detailed PJSM for UD LTP assy. Breakout and BD TD, R'U 6 5/8 power tongs, breakout pup above solid It, P/U same, R/U false table, BO 31/2" tbg, UD LTP assy. M/U triple connect w/ jt 5" DP on tbg using swivel, M/U 6 5/8" to stump, M/U TD.,Work on freeing liner string. Establish circulation at 1 BPM, 290 PSI w/ 70% losses. Work pipe w/ 7K TO up to 390K & down to 50K. (391 K is 80% of liner yield). 13' of stretch / compression to pipe. 2-1/2 turns before top drive stalls. Build 120 bbis of 11.5 ppg mud & add to system. Increase flow to 3 BPM, 590 PSI w/ 36% losses. Continue to work pipe w/ 1 OK TO 7K TO up to 390K & down to 50K.,Returns improved. Increase to 5 BPM, 1010 PSI w/ 8% losses & work pipe w/ 1 OK TO up to 390K & down to 50K. Increase to 5.5 BPM, 1050 PSI w/ 3% losses & work pipe w/ 14K TO up to 390K & down to 40K. 13' of stretch / compression to pipe. 4-1/2 turns before top drive stalls. Pipe moved down 1' from original position. Discuss lube pill w/ day DSM, begin mixing pilI.,Discuss progress with Hilcorp drilling manager & increase TO to 24K. Work pipe w/ 13' of stretch / compression to pipe. 6 turns before top drive stalls. Pipe moved down 1.5' from original position. Limit pickup to 305K with 24K trapped torque. Pump 45 bbl 11.5 ppg lube pill w/ 8% lube (5.2% Lo-Torq and 2.8% 776 Lube). Spot pill outside shoe at 8569'.,Allow lube pill to soak. Perform derrick inspection - no issues. Perform rig semice.,Continue to work stuck liner. Work pipe w/ up to 24K torque. 305K PUW with torque & 390K PUW w/ reduced torque. Attempt 5.5 BPM, but experiencing 45% losses. Pump 3.5 BPM, 550 PSI w/ 7% losses. Pipe moved down 2' from original position to 8571'. Assembly pulled free while picking up. PUW dropped from 200K to 180K.,Work from 8571'to 8528' while circulating a bottoms up. 4 BPM, 650 PSI. Pull 30K over at 8528' and taking weight at 8571'. 175K PUW, 93K SOW, 130K ROT.,Attempt to work past 8571', take weight and stall rotary at 8571'. Over pull at 8528'. Pumping 4 BPM, 630 PSI. Occasional rotating 20 RPM, 10K TO. 175K PUW, 93K SOW, 130K ROT.,Hauled 75 bbls H2O from L-Pad lake for total = 14935 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 114 bbls cuttings/liquids to MPU G&I for total = 22478 blots 134.3 bbls daily losses, 1604.8 bbis cumulative Iosses.,Rig fuel (gallons): On hand = 5312, Used = 2249, Rec'd = 0 1/26/2019 Attempt to work past 8571', take weight and stall rotary at 8571'. Over pull at 8528'. Pumping 4 BPM, 630 PSI. Occasional rotating 20 RPM, 1O TO. Slow pump to 1 bpm, beat down stacking to 40k, P/U 40' gradually increasing to 50k overpull @ 250k , after several attempts string pulled free on up stroke. Able to $/O to 8600' pipe free both ways. 175K PUW, 93K SOW, 130K ROT.,Work liner, P/U to 8511', S/O to 8600' pumping 5 bpm, 880 psi 1-3 rpm 10k torque. CBU x 1.5 times, PJSM for M/U LTP and connecting inner string w/ triple connect.,Set liner in slips. BO single it DP, BD TD. M/U single, BO TD, B/O triple connect 6 5/8 connection, R/U false table, BO 3 1/2" tbg f/ triple connect, UD jt DP and XOs, M/U LTP/ hanger assy as per BOT rep, inspect same, fill with Zanplex, drift and RIH 1 stand, M/U TD, pump 5 bbis 5 bpm, 400 psi to ensure clear flow path. BD TD.,Drift and RIH 15 stds 5" NC50 DP w/ 6 5/8" liner conveyed on DP If 8667' to 10112'30 fpm, RIH w/ stds 5" HWDP f/ 101 12'V 14831' no faster than 25-30 fpm to keep from surging wellbore. Note: Pipe filled on its own. Record PA1 S/0 wts every stand. 315K PUW 11 OOK SOW. Wash down f/ 14831't/ 15082'w/ 2 BPM, 810 PSI. Tag bottom on depth w/ 10K. P/U to 200K to place string in tension. 33.4 bbis lost while tripping.,PJSM with Doyon, Peak, M-1 and Hilcorp DSM for displacement. Stage pumps up to 4 BPM, 970 PSI.,Pump 35 bbl 11.4 ppg high viscosity spacer. Displace well to new 11.4 ppg FLOPRO NT mud. 4.3 BPM, 1350 PSI. Good mud returns to surface at 10654 stks, 322 bbls beyond calculated. 14273 sties total pumped, 2x surface to surface. 51.6 bbis lost of 1492 bbis pumped, 3% Iosses.,Drop 1.25" ball to close WIV. Pump 4.3 BPM, 1330 PSI. Slow to 3.1 BPM, 930 PSI. On seat @ 1236 stks, 1445 stks cede. Pressure up to 2750 PSI, not holding Pressure up to 2900, 3000 PSI w/ same results. Attempt 3500 PSI, but only reached 3250 PSI @ 2.5 BPM. Attempt 4000 PSI, but only reached 2750 PSI @ 3.2 BPM. Suspect drillable pack-off leaking. Had removed slick stinger mulfiple times from pack-off working stuck Iiner.,Drop 1.75" ball, pump 3.0 BPM, 1620 PSI initial, 1140 PSI final. Ball on circulating sub seat at 1260 stks. Pressure up to 2800 then 3000 PSI & observe packer set. Pressure up to 3600 PSI w/ rig pumps. Continue to pressure up w/ test pump to 4000 PSI. Bleed off, pick up to 305K -not released. Slack off to 90K - neutral weight & verify packer set. Pressure up to 4000 PSI. Verify release w/ 260K PUW, 55K less string weight.,Blow down top drive & rig up to test packer. Open kill line & close 412"x7" VBR top rams. Pressure up to 1500 PSI to test the 6-516'4b/8" liner top. Hold test for 10 minutes and chart. Bleed off & open rams. Pick up 20'. Pressure up to shear out the circulating sub with 4850 PSI. Pump 3 BPM, 790 PSI to verify circulating sub open.,Hauled 150 bbis H2O from L-Pad lake for total =15085 bbis Hauled 0 bbis heated H2O from G&I = 1130 Hauled 387 bbis cuttings/liquids to MPU G&I for total = 22865 bbis 131.6 bbis daily losses, 1736.4 blots cumulative Iosses.,Rig fuel (gallons): On hand = 8979, Used = 2316, Recd = 5983 1/27/2019 TOL @ 6486.27', Blow down choke and kill line, R/D test equipment, monitor well with trip tank, well is static.,Parked at 15002', PJSM, M/U FOSV, Slip and cut 86' drilling line, inspect saver sub and draworks, service top drive, monitor well with trip tank, static. Submit 24 hr BOP test notification to AOGCC @ 08:15 am,PJSM, POOH UD 5" HWDP to shed f/ 15002' to 14445' pulling wet, pump 20 bbl dry job. BD TD, continue to TOOH UD HW f/ 14445'to 10097', 159jts total, TOOH racking 16 stds 5" DP to 8591' at running tool. Pulling wet despite dryjob. 7.7 bbls losses during trip.,PJSM for laying down liner running tool, rigging up 3 12" handling equipment and laying down 3-12" tubing. UD Baker liner running tool and pup joints if 8591' V 8525'. C/O elevators to 3-1/2". Install XO sub on safety valve.,UD 3-12" 9.3# L-80 EUE inner string tubing f/ 8525' V 6524'.,Circulate 20 bbis at 2.5 BPM, 390 PSI. UD 2 joints 3-1/2" tubing to 6462' to get above liner top. Circulate 467 bbl surface to surface volume at 7 BPM, 1040 PSI. Slow to 2 BPM, 270 PSI to maintain 11.4 ppg weight. 11.2 ppg MW out observed with no safe carb stripped at the shakers. Increase to 5 BPM, 540 PSI. Monitor well for 5 min. - static.,UD 3-1 /2" 9.3# L-80 EUE inner string tubing f/ 6462'V 6277'. Rack back stands of 3-1/2" tubing in the derrick V 6277'to 2711'.,Hauled 365 blols H2O from L-Pad lake fortotal = 15450 bbls Hauled 0 bbis heated H2O from G&I = 1130 Hauled 1289 bbls cuftingsAiquids to MPU G&I for total = 24154 bbis 8 bbis daily losses, 1744.4 bbis cumulative Iosses.,Rig fuel (gallons): On hand = 7028, Used = 1951, Recd = 0 1/28/2019 TOOH 2711' to surface racking back total of 68 stands of 3-12" tubing in the derrick, inspect and UD slick stinger, no damage. 12.3 bbl losses over calculated displacement on TOOH.,Clear and clean rig floor, RID power tongs. C/O to 5" handling equipment. Monitor well, static.,M/U 3 %" perforated stinger with 85116" OD NO-GO, XO= 32.71', TIH with 68 stands 5" DP to 6443', M/U stand 69 and TD, Break circulation. 15 bbl losses TIH.,Wash down 2 bpm, 250 psi entering TOL with stinger @ 6486', wash down slow to 6518' tagging out on no-go at TOL on depth at 6486', P/U 4', increase to 4 bpm, working perforated stinger 3 times flushing seal bore, pump 20 bbls, P/U above TOL @ 6470', CBU 10 bpm, 640 psi. 28.7 bbls lost while circulating.,Flow check well, BD TD, TOOH f/ 6470' UD 5" DP (216 joints total), good displacement.,Dmin BOP stack, Flush BOP stack with water with 3-1/2" perforated stinger. UD 3-1/2" perforated stinger and no-go. Pull wear bushing. Perform dummy run with 7" tie-back liner hanger with Hilcorp wellhead representative. PN safety joint & break down 3-112" EUE x 6-5/8" H563 x 4-1/2" IF triple connect.,Install lower test plug, 7" test joint and R/U test equipment. Fill BOP stack and choke manifold with fresh water. Perform BOP shell pressure test to 3500 PSI -good test.,Clear rig floor of unneeded equipment and tools. Service top drive and blocks. Replace #2 charge pump 6" line. Load pipe shed with 3-1/2" 9.3# L-80 EUE tubing.,Test BOP equipment as per PTD and AOGCC requirements. AOGCC inspector Jeff Jones on location to witness test. Utilize 7" test joint and perform testing with fresh water. All tests performed to 250 PSI low/ 3500 PSI high, held for 5 min. and charted. Test upper 4-1/2"x7" VBR, upper & lower IBOP, hydraulic & manual kill and choke, choke valves 1, 2, 4-14 & 20. FOSV & dart valve. BOP testing continues into the next report.,Hauled 290 table H2O from L-Pad lake for total = 15740 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 235 bbls cuttings/liquids to MPU G&I for total = 24389 bbis 56 bbis daily losses, 1800.40 bbls cumulative Iosses.,Rig fuel (gallons): On Hand = 5413, Used = 1615. Recd = 0 1/29/2019 Continue to test BOPS w/ AOGCC inspector Jeff Jones. Test annular on 3-1/2" & 7" test joint to 250 PSI low 12500 PSI high. Perform accumulator drawdown test: initial 2950 PSI after closure 1800 PSI, 200 PSI attained in 41 sec, full PSI in 171 sec, 6 N2 bottle average 2054 PSI. Test blind rams, choke valve #3, hydraulic & manual chokes and lower 2-7/8"x5" VBR on 3-112" & 4" test joints to 250 PSI low 13500 PSI high.,All tests performed with fresh water, held for 5 min. and charted.,R/D test equipment. UD test joint and pull test plug. Blow down top drive, choke and kill lines. R/U to run 7" liner tie-back with Doyon casing. PIU Baker Bullet seals, locator sub, XO and pup joint to 18'. Run T' 26# L-80 TXP BTC SR liner tie-back f/ 18't/ 1638', joint #40. Torque connections to 14,750 fUlbs with double stack tongs. Mud running out of the pipe last 12' of joint.,Pump 25 bbl 12.4# dry job, 3 BPM, 140 PSI.,Run T' 26# L-80 TXP BTC SR liner tie-back f11638' and tag no-go at 6494.71' on joint#161. Torque connections to 14,750 ft/lbs with double stack tongs. Mud still running out of the pipe last 12' ofjoint due to 8.25" no-go in 8.835" I.D. casing. Good displacement while running Iiner.,UD joints #161, 160 & 159. WU 9.85'& 14.81' pup joints. Replace joint #159 (original 40.55' with 39.21'). M/U casing hanger and landing joint and land at 6493.50'- 1.21' above no-go. Close annular & pressure test bullet seals (7"x9-5/8" annulus) to 500 psi.,Hauled 50 bbis H2O from L-Pad lake for total = 15790 bbis Hauled 0 bbis heated H2O from G&I = 1130 Hauled 110 bbis cuttings/liquids to MPU G&I for total = 24499 bbis 10 bbls daily losses, 1810.4 bbls cumulative Iosses.,Rig fuel (gallons): 3638 On Hand, 1775 Used, 0 Recd 1/30/2019 R/U to circ. P/U 7.5'. PJSM for displacing & freeze protecting the 7" X 9-5/8" annulus.,Line up on spacer and pressured up to 800 PSI. Check line up and blow through cmt line. All clear. P/U 1' more. Line up and pump 2 bbls down 7" and saw slight pressure increase on the annulus. Line up and pump 40 bbl 11.4 high vis spacer and chase with 120 bbl 9.8 brine with 1.3% Conqor 303A corrosion inhibitor. Shut down and LRS pumped 70 bbi diesel. Final circ pressure 650 psi.,Land hanger. Bleed down LRS & open annular. Suck back Diesel with LRS. Well flowing out the 7" at 1.25 BPM with slight increase. Monitor for 30 min.,Line up and bullhead 20 bbl 11.4 Mud down the 7" at i BPM = 270 PSi, 2 BPM = 400 PSi. Shut down and monitor pressure. Bled down to 270 psi in 10 min. Bleed off and bleed back 17 bbl. Flow steady slowing down to slight trickle. R/D circ equipment. Back out landing joint & UD same.,M/U pack off to 5" joint and land out pack off. Verify on depth with wellhead reps. RILDS. UD pack off running tool.,Test pack off void to 500/5000 psi as per Wellhead Specialist for 10 minutes each (good tests).,LRS test 9-5/8" X T' to 1200 psi for 30 min. Bled down 40 psi in the first 15 and held steady for 20 more. Bleed down 1 bbl back to LRS.,Install wear ring (ID = 6-15/16').,Mobilize and RU 4" handling equipment.,PJSM. PU, MU mule shoe pup joint and RIH on 4" DP to 952'.,TOOH standing back 4" DP and lay down mule shoe pup joint.,PU, MU and RIH with 4" DP to 5648'. SimOps: PT the 4" FOSV and 4" dart valve to 250/3000 psi for 5 minutes each (good tests).,TOOH standing back 4" DP from 5648' to surface.,PU 7" landing joint and break out 5" IF x 7" BTC crossover.,RU 3-1/2" handling equipment.,PJSM. PU and TIH with 3-1/2" perforated stinger on 3-1/2" EUE Sid tubing to 3729.,Hauled 75 bbis H2O from L-Pad lake for total = 15865 bbls Hauled 0 bbis heated H2O from G&I = 1130 Hauled 84 bbls cuttings/liquids to MPU G&I for total = 24583 bbls Rig Fuel (gallons): OH = 8254, Used = 2339 & Roe = 6955 1/31/2019 TIH with 3-1/2" perforated stinger on 3-1/2" EUE 8rd tubing from 3725'to 6310'.,PJSM. RIH with 3-1/2" perforated stinger on 3-12" tubing from the pipe shed from 6310'to 8561' (PU = 90K and SO= 58K).,Change handling equipment to 4". RD power tubing tongs.,MU crossover 4" HT-38 box X 3-1/2" EUE Brit pin. TIH with 3-1/2" perforated stinger on 4" DP from 8561'to 11756' and lost all down weight. SimOps: Prep the pits for displacement.,Confinue to TIH with 4" DP rotating each joint down at 10 RPM= 3K ft-lbs torque from 11 756'to tag at 15051' (PU = 150K, SO= OK and ROT= 50K). Lay down the top single. SimOps: Prep the pits for displacement.,Continue to prep the pits for the displacement.,PJSM with rig crew and all truck drivers on the displacement.,Pump 40 bbl hi-vis seawater sweep at 3 BPM = 1290 psi followed by 40 bbl hi-vis 12.0 ppg sweep at 3 BPM = 1090 psi. Pump 200 bbls seawater SAPP pill at 4 BPM = 1600 psi followed by 170 bbis of seawater at 4 BPM = 1510 psi. Rotating and reciprocating the DP 60' at 20 RPM = 4K ft-lbs. 450 bbls pumped with 325 bbls returned.,Shut down the pumps. Close the annular and close the FOSV for bull heading operation. Monitor the pressures. SIDP = 825 psi and SICP = 0 psi.,Open the FOSV and bullhead 230 bbis of seawater down the DP at 3 BPM = 1330 psi. Shutdown the pumps. Monitor the pressures. SIDP = 930 psi and SICP = 300 psi. Open the choke and the well is flowing 2 BPM. Open the annular.,Circulate 460 bbis of seawater at 4 BPM; ICP = 1530 psi and FCP = 860 psi getting 8.8 ppg returns.,Close the FOSV, break out the lop drive, load the dart, MU the top drive and open the FOSV to launch the dart. Pump the dart to seat but did not seat on strokes. Work the DP and got the dart to seat at 1175 strokes (calculated 700 strokes). Pressure up to 2442 psi to open the circulation sub.,Pump 40 bbl hi-vis seawater sweep at 4 BPM = 450 psi followed by 11.4 ppg brine at 5 BPM = 450 psi. Pumped a total of 392 bbis of 11.4 ppg brine getting 10.7 ppg at surface when we ran out of fluid. Observed the well for flow and the well is losing fluid. 2/112019 Monitor well & blend brines to make 10.5 ppg. Losses over 35 bph. Blow down TO & Prep to UD 4" DP.,UD 4" DP from 15038' to 88562'. 210 Joints total. Started getting over pulls at 9065'. Seeing every 30' the 3-1/2" collars hanging up on 7" seal assembly. Having to work pipe back down to get by at a higher rate. Pulling 30-60K over fast.,Change handling equipment to 3-1/2'. UD 3-12" EUE tubing seeing over pulls every 30'. Collars are flat and sharp. Working past. UD 73 joints from 8562' to 6310'. Filling the hole with 10.5 ppg brine. Lose rate = 4 BPH.,TOOH standing back 3-1/2" tubing from 6310' to surface. Lay down the perforated stinger.,Lay down remaining stand of 4" DP in the derrick. Pull the wear ring. Mobilize spooling unitwith Tec wire, SLB job box and cannon clamps to the rig floor. Hang sheave and RU spooling unit. RU to run completion. Static loss rate = 3.5 BPH.,PJSM. PU and RIH with mule shoe on 6 stands of 3-12" EUE 8rd tubing. PU and MU XN nipple, packer assembly, X nipple and gauge assembly to 726'.,Splice Tec wire to the gauge assembly. PT connection to 5000 psi for 15 minutes (good test).,Continue to TIH with jet pump completion per tally on 3-12" EUE 8rd tubing from the derrick from 726'to 2430'spooling Tec wire.,Hauled 120 bbls H2O from L-Pad lake for total = 16080 bible Hauled 0 bbis heated H2O from G&I = 1130 Hauled 1080 bbis cuttings/liquids to MPU G&I for total = 25763 bbls Rig Fuel (gallons): OH = 4113, Used = 1950 & Rec = 0 Continue to RIH with 3-1/2" EUE 8rd jet pump completion from 2430'to 6488'. Install one cannon clamp on each joint ran. 188 Cannon clamps, 5 half clamps, and 1 stand off clamp Installed.,Change handling equipment to 5". M/U hanger, landing joint and crossover. Land hanger and RILDS. PU/DN 85/65 with 40K block weight.,SLB Terminate Tec gauge cable in to hanger. Test to 5000 psi (good test).,Land the tubing hanger and RILDS. UPON 85/65 with Blocks at 40K. Drop the ball & rod on rollers. RU circulating equipment to the tubing and IA.,Pump down tubing to get ball on seat. Took 3 BPM & 5 bbl to land on seat. Pressure up to 3500 psi to set the packer. Hold for 30 minutes (good test). Bleed pressure to 2000 psi on tubing. Pressure up on annulus to 3500 psi. Tubing tracked annulus at 3500 psi. Bleed down tubing to 2000 psi again and annulus bled down also.,Pressure up on annulus to 3500 psi and hold for 30 min. Tubing also pressured up to 3500 psi. CMIT-T x IA for 30 minutes (good test). Bleed off tubing fast and both sides bled off. Line up and pump both ways at 2 BPM with good returns.,RD circulating equipment for the landing joint and lay down the landing joint. Install the 3" H BPV. Pressure up on the IA to 500 psi to testthe BPV from below in the direction of flow for 5 minutes (good test). SimOps: Blow down the choke, kill and hole fill Iines.,PJSM. ND the BOP stack, set back on the stump and secure for transport. SimOps: Clean mud pits.,Clean up the tubing hanger neck. Mobilize the tree and tubing head adapter to the cellar. Remove the wing valve to reorient to proper alignment.,NU the tubing head adapter and tree.,Terminate the Tec wire. MU the Tec wire gauge housing and test the gauge (good test). PT the tubing hanger void to 500/5000 psi (good test). SimOps: Move the rock washer and shakes. Continue to clean the mud pits.,NU the wing valve in proper alignment.,PJSM. Pull the BPV and install the TWC with dry rod.,RU to test the tree. Purge the lines with diesel. Install gauge on tree cap. PT the tree to 250/5000 psi for 5 minutes each (good tests). RD testing equipment.,Pull the TWC and install the 3" H BPV. RU to freeze protect the well.,LRS PT lines to 3500 psi (good test). Circulate 89 bbls of diesel down the tubing taking returns up the IA to pit 1 at 2 BPM = 720 psi.,RD LRS. Blow down return line and RD. Clean and suck out the cellar box. Empty and clean pit 1. Rig released at 02:30 hOurs.,RDMO to M-12. See M-12 drilling report for details.,Hauled 60 bbls H2O from L -Pad lake for total= 16140 bbls Hauled 0 bbls heated H2O from G&I = 1130 Hauled 1115 bbls cuttings/liquids to MPU G&I for total = 26878 bbls Fuel (gallons): OH = 4558, Used = 1934 & Ree = 2379 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10 MPU M-10 500292361700 Sperry Drilling Definitive Survey Report 25 January, 2019 HALLIBURTON Sperry Drilling Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10 Design: MPU M-10 Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU NI -10 TVD Reference: M-10 Actual RKB @ 58.93usft MD Reference: M-10 Actual RKB @ 58.93usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA project Milne Point, ACT, MILNE POINT dap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Aap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-10 Well Position +N/.S +E/ -W Position Uncertainty Wellbore MPU M-10 Magnetics Model Name 0.00 usft Northing: 6,027,889.65 usfl 0.00 usft Easting: 534,113.80 usfl 0.00 usft Wellhead Elevation: 24.90 usfl Sample Date Declination (1) BGGM2018 1/16/2019 16,82 Design MPU M-10 Audit Notes: Version: 1.0 Phase: ACTUAL Vertical Section: Depth From (TVD) +N/ -S (usft) (usft) 34.03 0.00 Latitude: 70° 29' 13.990 N Longitude: 149° 43'16.219 W Ground Level: 24.90 usft Dip Angle Field Strength (°) (nT) 80.97 57,438.64165436 Tie On Depth: 11,426.89 +E/ -W Direction (usft) V) 0.00 124.94 Survey Program Date 1/25/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 170.94 6,619.48 MPU M-10PB1 MWD+IFR2+MS+Sag(1)2MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 12/19/2018 6,710.78 11,426.89 MPU M -10P61 MWD+IFR+MS+Sag (2) (2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 01/03/2019 11,433.00 15,012.58 MPU M-10 MWD+IFR2+MS+Sag (MPU 12_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 01/16/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +FJ -W Northing Easting DLS Section (usft) (1 (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 34.03 0.00 0.00 34.03 -24.90 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 UNDEFINED 170.94 0.38 142.01 170.94 112.01 -0.36 0.28 6,027,889.29 534,114.08 0.28 0.43 2_MWD+IFR2+MS+Sag(1) 227.67 0.33 142.01 227.67 168.74 -0.63 0.50 6,027,889.02 534,114.30 0.09 0.77 2_MWD+IFR2+MS+Sag(1) 322.96 0.92 100.77 322.95 264.02 -0.99 1.42 6,027,888.66 534,115.22 0.74 1.73 2_MWD+IFR2+MS+Sag(1) 416.60 3.07 37.93 416.54 357.61 0.84 3.70 6,027,890.51 534,117.49 2.96 2.55 2_MWD+IFR2+MS+Sag(1) 510.06 5.78 30.62 509.71 450.78 6.87 7.63 6,027,896.55 534,121.40 2.96 2.32 2_MWD+IFR2+MS+Sag(1) 603.55 8.51 42.95 602.47 543.54 15.99 14.75 6,027,905.70 534,128.47 3.33 M 2.93 2_WD+IFR2+MS+Sag(1) 696.41 11.70 55.78 693.89 634.96 26.31 27.22 6,027,916.09 534,140.89 4.18 7.24 2_MWD+IFR2+MS+Sag(1) 790.33 12.74 69.53 785.70 726.77 35.29 44.80 6,027,925.14 534,158.43 3.28 16.51 2_MWD+IFR2+MS+Sag(1) 884.81 16.79 76.07 877.05 818.12 42.22 67.81 6,027,932.18 534,181.41 4.63 31.41 2_MWD+IFR2+MS+Sag(1) 980.75 19.90 78.90 968.10 909.17 48.71 97.29 6,027,938.80 534,210.86 3.37 51.86 2_MWD+IFR2+MS+Sag(1) 1,074.92 24.60 80.13 1,055.24 996.31 55.15 132.35 6,027,945.41 534,245.88 5.02 76.91 2_MWD+IFR2+MS+Sag(1) 1/252019 1:05:36PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-10 Project: Milne Point TVD Reference: M-10 Actual RKB @ 58.93usft Site: M Pt Moose Pad MD Reference: M-10 Actual RKB @ 58.93usft Well: MPU M-10 North Reference: True Wellbore: MPU M-10 Survey Calculation Method: Minimum Curvature Design: MPU M-10 Database: NORTH US+CANADA Survey MD Inc (usft) V) 1,168.88 29.58 1,263.59 33.20 1,357.77 34.99 1,452.25 36.90 1,546.61 42.91 1,641.35 44.25 1,735.11 47.49 1,828.09 52.45 1,923.77 53.56 2,018.36 53.75 2,112.50 55.83 2,206.42 55.37 2,301.32 55.95 2,395.66 55.16 2,490.05 55.11 2,584.59 54.94 2,678.80 54.32 2,772.66 53.54 2,866.86 53.54 2,961.80 55.61 3,056.37 55.34 3,150.85 55.06 3,245.49 56.28 3,339.53 55.32 3,434.32 52.70 3,528.95 55.54 3,622.79 55.21 3,717.12 55.62 3,811.72 56.26 3,906.17 56.78 4,000.61 56.23 4,094.86 57.19 4,188.60 57.20 Azi 79.82 79.91 80.99 82.00 82.25 82.77 82.20 82.90 85.11 84.02 84.03 85.07 85.50 85.09 84.88 85.05 85.48 86.76 87.13 85.32 85.58 85.44 85.15 82.43 83.06 83.16 83.76 84.06 84.55 84.34 84.29 84.76 84.54 4,282.89 54.71 85.79 4,377.33 53.48 87.26 4,470.79 52.59 84.94 4,565.71 54.33 85.03 4,660.04 53.38 84.52 4,755.01 54.57 84.42 4,848.09 55.02 84.74 TVD TVDSS (usft) (usft) 1,138.86 1,079.93 1,219.70 1,160.77 1,297.69 1,238.76 1,374.17 1,446.52 1,515.15 1,580.43 1,640.21 1,697.79 1,753.85 1,808.13 1,861.19 1,914.72 1,968.08 2,022.04 2,076.23 2,130.77 2,186.03 2,242.01 2,297.04 2,350.64 2,404.56 2,457.93 2,510.80 2,566.50 2,621.95 2,675.27 2,728.82 2,781.80 2,833.90 2,886.02 2,937.75 2,988.54 3,041.32 3,096.71 3,152.91 3,209.42 3,265.06 3,320.92 3,374.58 +N1 -S (usft) 62.61 71.29 80.03 1,315.24 88.23 1,387.59 96.51 1,456.22 105.02 1,521.50 113.83 1,581.28 123.04 1,638.86 1,694.92 1,749.20 1,802.26 1,855.79 1,909.15 1,963.11 2,017.30 2,071.84 2,127.10 2,183.08 2,238.11 2,291.71 2,345.63 2,399.00 2,451.87 2,507.57 2,563.02 2,616.34 2,669.89 2,722.87 2,774.97 2,827.09 2,878.82 2,929.61 2,982.39 3,037.78 3,093.98 3,150.49 3,206.13 3,261.99 3,315.65 131.01 138.23 146.23 153.59 160.03 166.41 173.18 179.98 18632 191.46 195.50 200.61 206.79 212.86 219.28 227.68 237.37 246.56 255.36 263.60 271.37 279.00 286.80 294.32 301.66 308.26 312.90 317.97 324.64 331.57 338.98 346.16 Map +E/ -W Northing (usft) (ft) 174.47 6,027,953.05 223.02 6,027,961.95 275.08 6,027,970.94 329.93 6,027,979.38 389.87 6,027,987.93 454.62 6,027,996.74 521.33 6,028,005.85 591.90 6,028,015.39 667.90 6,028,023.71 743.74 6,028,031.27 820.23 6,028,039.63 897.38 6,028,047.34 975.47 6,028,054.14 1,053.01 6,028,060.87 1,130.16 6,028,068.00 1,207.32 6,028,075.15 1,283.88 6,028,081.84 1,359.57 6,028,087.33 1,435.23 6,028,091.71 1,512.41 6,028,097.17 1,590.08 6,028,103.71 1,667.42 6,028,110.14 1,745.31 6,028,116.91 1,822.62 6,028,125.66 1,898.70 6,028,135.70 1,974.81 6,028,145.25 2,051.53 6,028,154.39 2,128.75 6,028,162.98 2,206.73 6,028,171.12 2,285.14 6,028,179.10 2,363.51 6,028,187.26 2,441.93 6,028,195.14 2,520.38 6,028,202.84 2,598.22 6,028,209.79 2,674.57 6,028,214.79 2,749.06 6,028,220.20 2,825.03 6,028,227.21 2,900.89 6,028,234.49 2,977.34 6,028,242.25 3,053.05 6,028,249.77 Map Easting DLS (ft) (-/100-) 534,287.96 5.30 534,336.47 3.82 534,388.49 2.01 534,443.29 2.12 534,503.18 6.37 534,567.89 1.46 534,634.55 3.48 534,705.07 5.37 534,781.02 2.18 534,856.82 0.95 534,933.27 2.21 535,010.37 1.04 535,088.43 0.72 535,165.93 0.91 535,243.04 0.19 535,320.17 0.23 535,396.69 0.76 535,472.35 1.38 535,547.97 0.32 535,625.13 2.68 535,702.76 0.36 535,780.07 0.32 535,857.92 1.31 535,935.18 2.60 536,011.20 2.82 536,087.26 3.00 536,163.93 0.63 536,241.11 0.51 536,319.05 0.80 536,397.41 0.58 536,475.74 0.58 536,554.12 1.10 536,632.52 0.20 536,710.32 2.86 536,786.64 1.81 536,861.11 2.20 536,937.03 1.83 537,012.85 1.10 537,089.26 1.26 537,164.93 0.56 Vertical Section (ft) Survey Tool Name 107.16 2_MWD+IFR2+MS+Sag(1) 142.00 2_MWD+IFR2+MS+Sag(1) 179.66 2_MWD+IFR2+MS+Sag(1) 219.93 2_MWD+IFR2+MS+Sag(1) 264.32 2_MWD+IFR2+MS+Sag(1) 312.53 2_MWD+IFR2+MS+Sag (1) 362.17 2_MWD+IFR2+MS+Sag(1) 414.75 2_MWD+IFR2+MS+Sag(1) 472.48 2_MWD+IFR2+MS+Sag (1)M 530.52 2_WD+IFR2+MS+Sag(1) 588.64 2_MWD+IFR2+MS+Sag(1) 647.66 2_MWD+IFR2+MS+Sag (1) 707.99 2_MWD+IFR2+MS+Sag(1) 767.90 2_MWD+IFR2+MS+Sag(1) 827.26 2_MWD+IFR2+MS+Sag(1) 886.63 2_MWD+IFR2+MS+Sag(1) 945.75 2_MWD+IFR2+MS+Sag(1) 1,004.86 2_MWD+IFR2+MS+Sag(1) 1,064.56 2_MWD+IFR2+MS+Sag(1) 1,124.91 2_MWD+IFR2+MS+Sag (1) 1,185.04 2_MWD+IFR2+MS+Sag(1) 1,244.96 2_MWD+IFR2+MS+Sag(1) 1,305.14 2_MWD+IFR2+MS+Sag(1) 1,363.71 2_MWD+IFR2+MS+Sag (1) 1,420.52 2_MWD+IFR2+MS+Sag(1) 1,477.64 2_MWD+IFR2+MS+Sag(1) 1,535.49 2_MWD+IFR2+MS+Sag(1) 1,594.08 2_MWD+IFR2+MS+Sag(1) 1,653.55 2_MWD+IFR2+MS+Sag(1)M 1,713.46 2_WD+IFR2+MS+Sag(1) 1,773.24 2_MWD+IFR2+MS+Sag(1) 1,833.22 2_MWD+IFR2+MS+Sag(1) 1,893.32 2_MWD+IFR2+MS+Sag(1) 1,953.35 2_MWD+IFR2+MS+Sag(1)M 2,013.28 2_WD+IFR2+MS+Sag(1) 2,071.44 2_MWD+IFR2+MS+Sag(1) 2,129.90 2_MWD+IFR2+MS+Sag(1) 2,188.11 2_MWD+IFR2+MS+Sag (1) 2,246.54 2_MWD+IFR2+MS+Sag(1) 2,304.49 2_MWD+IFR2+MS+Sag(1) 1252019 1:05.36PM Page 3 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10 Design: MPU M-10 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU MI -10 M-10 Actual RKB @ 58.93usft M-10 Actual RKB @ 58.93usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 4,942.85 56.65 85.24 3,427.79 3,368.86 353.00 3,131.16 6,028,256.98 537,243.00 1.77 2,364.60 2_MWD+IFR2+MS+Sag(1) 5,037.22 55.01 83.92 3,480.79 3,421.86 360.37 3,208.88 6,028,264.70 537,320.68 2.09 2,424.10 2_MWD+IFR2+MS+Sag(1) 5,131.28 55.40 84.84 3,534.47 3,475.54 367.93 3,285.75 6,028,272.61 537,397.51 0.90 2,482.78 2_MWD+IFR2+MS+Sag(1) 5,226.52 57.90 89.67 3,586.84 3,527.91 371.69 3,365.18 6,028,276.74 537,476.90 4.98 2,545.74 2_MWD+IFR2+MS+Sag(1) 5,321.09 57.71 94.91 3,637.26 3,578.33 368.50 3,445.10 6,028,273.91 537,556.83 4.69 2,613.08 2_MWD+IFR2+MS+Sag(1) 5,415.62 58.70 97.70 3,687.07 3,628.14 359.67 3,524.94 6,028,265.45 537,636.71 2.72 2,683.59 2_MWD+IFR2+MS+Sag(1) 5,507.35 60.77 101.27 3,733.31 3,674.38 346.59 3,603.06 6,028,252.73 537,714.87 4.05 2,755.12 2_MWD+IFR2+MS+Sag(1) 5,603.63 65.21 105.15 3,777.04 3,718.11 326.94 3,686.51 6,028,233.46 537,798.41 5.84 2,834.78 2_MWD+IFR2+MS+Sag(1) 5,697.88 66.83 106.69 3,815.34 3,756.41 303.32 3,769.31 6,028,210.22 537,881.31 2.28 2,916.19 2_MWD+IFR2+MS+Sag(1) 5,792.62 69.52 109.49 3,850.57 3,791.64 275.99 3,852.89 6,028,183.28 537,965.01 3.95 3,000.35 2_MWD+IFR2+MS+Sag(1) 5,887.15 72.45 111.97 3,881.37 3,822.44 244.35 3,936.45 6,028,152.03 538,048.70 3.97 3,086.97 2_MWD+IFR2+MS+Sag(1) 5,980.93 74.91 113.39 3,907.72 3,848.79 209.64 4,019.48 6,028,117.71 538,131.88 3.00 3,174.92 2_MWD+IFR2+MS+Sag(1) 6,075.24 81.07 116.75 3,927.34 3,868.41 170.55 4,102.97 6,028,079.00 538,215.54 7.40 3,265.74 2_MWD+IFR2+MS+Sag(1) 6,170.20 82.69 118.19 3,940.75 3,881.82 127.19 4,186.38 6,028,036.03 538,299.14 2.27 3,358.95 2_MWD+IFR2+MS+Sag(1) 6,263.30 81.71 120.62 3,953.39 3,894.46 81.91 4,266.73 6,027,991.12 538,379.68 2.79 3,450.75 2_MWD+IFR2+MS+Sag(1) 6,355.51 82.27 122.51 3,966.24 3,907.31 34.11 4,344.52 6,027,943.68 538,457.69 2.12 3,541.90 2_MWD+IFR2+MS+Sag(1) 6,450.48 81.41 122.29 3,979.72 3,920.79 -16.26 4,423.90 6,027,893.68 538,537.29 0.93 3,635.81 2_MWD+IFR2+MS+Sag(1) 6,547.05 84.99 123.73 3,991.15 3,932.22 -68.49 4,504.29 6,027,041.82 538,617.91 3.99 3,731.63 2_MWD+IFR2+MS+Sag(1) 6,619.48 86.01 124.83 3,996.83 3,937.90 -109.16 4,563.95 6,027,801.43 538,677.75 2.07 3,803.83 2_MWD+IFR2+MS+Sag(1) 6,710.78 87.54 122.43 4,001.97 3,943.04 -159.64 4,639.84 6,027,751.31 538,753.87 3.11 3,894.95 2_MWD+IFR2+MS+Sag(2) 6,803.73 88.04 122.44 4,005.56 3,946.63 -209.46 4,718.23 6,027,701.86 538,832.48 0.54 3,987.74 2_MWD+IFR2+MS+Sag(2) 6,899.01 88.53 123.08 4,008.41 3,949.48 -260.99 4,798.32 6,027,650.70 538,912.80 0.85 4,082.91 2_MWD+IFR2+MS+Sag (2) 6,993.63 90.14 123.89 4,009.51 3,950.58 -313.19 4,877.23 6,027,598.87 538,991.93 1.90 4,177.49 2_MWD+IFR2+MS+Sag(2) 7,088.02 88.83 124.21 4,010.35 3,951.42 -366.04 4,955.43 6,027,546.38 539,070.37 1.43 4,271.86 2_MWD+IFR2+MS+Sag(2) 7,183.49 89.27 126.35 4,011.94 3,953.01 421.17 5,033.35 6,027,491.62 539,148.53 2.29 4,367.31 2 MWD+IFR2+MS+Sag(2) 7,277.24 88.96 126.41 4,013.39 3,954.46 -476.77 5,108.82 6,027,436.37 539,224.25 0.34 4,461.02 2 MWD+IFR2+MS+Sag (2) 7,368.80 88.34 125.45 4,015.54 3,956.61 -530.48 5,182.94 6,027,383.00 539,298.61 1.25 4,552.54 2_MWD+IFR2+MS+Sag (2) 7,465.47 89.15 128.18 4,017.66 3,958.73 -588.39 5,260.30 6,027,325.46 539,376.23 2.95 4,649.12 2_MWD+IFR2+MS+Sag (2) 7,560.90 89.27 131.55 4,018.98 3,960.05 -649.54 5,333.53 6,027,264.64 539,449.73 3.53 4,744.18 2_MWD+IFR2+MS+Sag (2) 7,655.20 88.96 131.56 4,020.43 3,961.50 -712.09 5,404.09 6,027,202.43 539,520.57 0.33 4,837.84 2_MWD+IFR2+MS+Sag(2) 7,749.31 87.10 130.56 4,023.67 3,964.74 -773.86 5,475.01 6,027,140.98 539,591.76 2.24 4,931.35 2_MWD+IFR2+MS+Sag(2) 7,843.56 86.80 128.35 4,028.68 3,969.75 -833.67 5,547.67 6,027,081.52 539,664.69 2.36 5,025.17 2_MWD+IFR2+MS+Sag(2) 7,937.86 87.17 126.18 4,033.64 3,974.71 -890.68 5,622.61 6,027,024.85 539,739.88 2.33 5,119.26 2_MWD+IFR2+MS+Sag (2) 8,032.41 88.22 125.59 4,037.45 3,978.52 -946.06 5,699.15 6,026,969.84 539,816.67 1.27 5,213.72 2_MWD+IFR2+MS+Sag (2) 8,126.73 89.76 124.94 4,039.11 3,980.18 -1,000.44 5,776.20 6,026,915.82 539,893.95 1.82 5,308.02 2_MWD+IFR2+MS+Sag (2) 8,218.97 88.53 122.97 4,040.49 3,981.56 -1,051.88 5,852.74 6,026,864.73 539,970.72 2.43 5,400.23 2_MWD+IFR2+MS+Sag(2) 8,315.28 88.90 122.36 4,042.65 3,983.72 -1,103.85 5,933.80 6,026,813.14 540,052.01 0.74 5,496.44 2_MWD+IFR2+MS+Sag(2) 8,410.15 88.84 121.93 4,044.52 3,985.59 -1,154.32 6,014.11 6,026,763.04 540,132.54 0.46 5,591.17 2_MWD+IFR2+MS+Sag(2) 8,504.74 91.37 124.02 4,044.34 3,985.41 -1,205.79 6,093.45 6,026,711.94 540,212.11 3.47 5,685.70 2_MWD+IFR2+MS+Sag (2) 8,599.26 90.07 123.61 4,043.16 3,984.23 .1,258.39 6,171.97 6,026,659.71 540,290.87 1.44 5,780.19 2_MWD+IFR2+MS+Sag (2) 1252019 1:05.36PM Page 4 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10 Design: MPU M-10 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) 8,693.57 89.70 124.19 4,043.34 3,984.41 -1,310.99 6,250.25 6,026,607.47 8,786.66 90.63 124.64 4,043.08 3,984.15 -1,363.60 6,327.04 6,026,555.22 8,881.35 90.01 124.08 4,042.55 3,983.62 -1,417.04 6,405.21 6,026,502.14 8,973.62 89.14 123.99 4,043.23 3,984.30 -1,468.68 6,481.67 6,026,450.86 9,069.68 89.52 125.49 4,044.36 3,985.43 -1,523.42 6,560.60 6,026,396.49 9,163.54 91.00 125.56 4,043.93 3,985.00 -1,577.95 6,636.98 6,026,342.31 9,255.80 92.73 125.17 4,040.93 3,982.00 -1,631.32 6,712.18 6,026,289.29 9,350.05 91.80 125.05 4,037.20 3,978.27 -1,685.49 6,789.22 6,026,235.49 9,446.02 91.80 125.44 4,034.19 3,975.26 -1,740.84 6,867.56 6,026,180.50 9,540.33 90.75 125.43 4,032.09 3,973.16 -1,795.50 6,944.38 6,026,126.19 9,634.89 91.24 125.88 4,030.45 3,971.52 -1,850.62 7,021.20 6,026,071.44 9,729.57 89.76 125.42 4,029.62 3,970.69 -1,905.79 7,098.13 6,026,016.62 9,824.36 90.38 124.26 4,029.51 3,970.58 -1,959.95 7,175.93 6,025,962.83 9,918.91 89.45 123.39 4,029.65 3,970.72 -2,012.58 7,254.47 6,025,910.57 10,013.67 88.65 121.18 4,031.22 3,972.29 -2,063.18 7,334.57 6,025,860.34 10,108.03 89.27 120.03 4,032.93 3,974.00 -2,111.21 7,415.77 6,025,812.68 10,202.55 89.76 120.19 4,033.73 3,974.80 -2,158.63 7,497.53 6,025,765.65 10,295.06 90.26 119.63 4,033.71 3,974.78 -2,204.76 7,577.72 6,025,719.89 Well MPU M-10 M-10 Actual RKB @ 58.93usft M-10 Actual RKB @ 58.93usft True Minimum Curvature NORTH US+CANADA Map Vertical Easting DLS Section (ft) (^1100•) (ft) Survey Tool Name 540,369.38 0.73 5,874.48 2_MWD+IFR2+MS+Sag(2) 540,446.41 1.11 5,967.57 2_MWD+IFR2+MS+Sag(2) 540,524.81 0.88 6,062.25 2 MWD+IFR2+MS+Sag (2) 540,601.50 540,680.67 540,757.30 540,832.73 540,910.01 540,988.59 541,065.66 541,142.72 541,219.90 541,297.93 541,376.71 541,457.03 541,538.44 541,620.41 541,700.80 10,391.23 90.20 119.76 4,033.33 3,974.40 -2,252.40 7,661.26 6,025,672.64 541,784.55 10,485.18 90.13 121.84 4,033.06 3,974.13 -2,300.50 7,741.95 6,025,624.91 541,865.46 10,579.42 89.58 123.48 4,033.30 3,974.37 -2,351.35 7,821.29 6,025,574.43 541,945.02 10,672.41 89.21 124.61 4,034.28 3,975.35 -2,403.41 7,898.33 6,025,522.73 542,022.29 10,768.36 87.60 124.86 4,036.95 3,978.02 -2,458.06 7,977.15 6,025,468.45 542,101.36 10,862.22 87.72 125.43 4,040.78 3,981.85 -2,512.04 8,053.84 6,025,414.82 542,178.28 10,957.32 86.92 125.70 4,045.23 3,986.30 -2,567.29 8,131.11 6,025,359.93 542,255.80 11,051.90 87.05 126.93 4,050.20 3,991.27 -2,623.23 8,207.21 6,025,304.35 542,332.15 11,144.00 87.85 127.41 4,054.30 3,995.37 -2,678.82 8,280.53 6,025,249.10 542,405.71 11,240.68 87.91 127.34 4,057.88 3,998.95 -2,737.47 8,357.31 6,025,190.82 542,482.75 11,335.09 88.10 128.17 4,061.16 4,002.23 -2,795.24 8,431.91 6,025,133.39 542,557.61 11,426.89 88.78 128.44 4,063.66 4,004.73 -2,852.12 8,503.92 6,025,076.85 542,629.87 11,433.00 88.86 128.46 4,063.79 4,004.86 -2,855.91 8,508.70 6,025,073.07 542,634.67 11,531.66 87.29 130.48 4,067.10 4,008.17 -2,918.59 8,584.81 6,025,010.75 542,711.06 11,626.30 89.02 131.85 4,070.15 4,011.22 -2,980.85 8,656.02 6,024,948.83 542,782.54 11,720.14 90.32 132.84 4,070.69 4,011.76 -3,044.06 8,725.37 6,024,885.95 542,852.18 11,814.04 88.40 131.06 4,071.74 4,012.81 -3,106.82 8,795.20 6,024,823.51 542,922.29 11,908.16 90.57 129.94 4,072.58 4,013.65 -3,167.94 8,866.76 6,024,762.73 542,994.12 12,002.67 91.55 128.68 4,070.84 4,011.91 -3,227.80 8,939.87 6,024,703.21 543,067.50 12,097.45 91.43 127.39 4,068.37 4,009.44 -3,286.17 9,014.49 6,024,645.18 543,142.38 12,191.75 91.12 127.32 4,066.27 4,007.34 -3,343.38 9,089.43 6,024,588.33 543,217.57 12,285.55 89.57 124.99 4,065.71 4,006.78 -3,398.71 9,165.16 6,024,533.35 543,293.55 0.95 6,154.50 2_MWD+IFR2+MS+Sag(2) 1.61 6,250.55 2_MWD+IFR2+MS+Sag(2) 1.58 6,344.41 2_MWD+IFR2+MS+Sag(2) 1.92 6,436.61 2_MWD+IFR2+MS+Sag (2) 0.99 6,530.79 2 MWD+IFR2+MS+Sag (2) 0.41 6,626.71 2_MWD+IFR2+MS+Sag (2) 1.11 6,720.99 2_MWD+IFR2+MS+Sag (2) 0.70 6,815.53 2_MWD+IFR2+MS+Sag(2) 1.64 6,910.19 2_MWD+IFR2+MS+Sag(2) 1.39 7,004.98 2_MWD+IFR2+MS+Sag(2) 1.35 7,099.51 2_MWD+IFR2+MS+Sag(2) 2.48 7,194.15 2_MWD+IFR2+MS+Sag(2) 1.38 7,288.22 2_MWD+IFR2+MS+Sag(2) 0.55 7,382.40 2_MWD+IFR2+MS+Sag (2) 0.81 7,474.55 2_MWD+IFR2+MS+Sag (2) 0.15 7,570.32 2 MWD+IFR2+MS+Sag (2) 2.22 7,664.02 2_MWD+IFR2+MS+Sag (2) 1.84 7,758.18 2_MWD+IFR2+MS+Sag (2) 1.28 7,851.15 2_MWD+IFR2+MS+Sag (2) 1.70 7,947.06 2_MWD+IFR2+MS+Sag (2) 0.62 8,040.84 2_MWD+IFR2+MS+Sag(2) 0.89 8,135.83 2_MWD+IFR2+MS+Sa9(2) 1.31 8,230.25 2_MWD+IFR2+MS+Sag(2) 1.01 8,322.19 2_MWD+IFR2+MS+Sag (2) 0.10 8,418.72 2_MWD+IFR2+MS+Sag (2) 0.90 8,512.96 2_MWD+IFR2+MS+Sag(2) 0.80 8,604.56 2_MWD+IFR2+MS+Sag(2) 1.35 8,610.66 2_MWD+IFR2+MS+Sag(3) 2.59 8,708.95 2_MWD+IFR2+MS+Sag (3) 2.33 8,802.98 2_MWD+IFR2+MS+Sag (3) 1.74 8,896.03 2_MWD+IFR2+MS+Sag (3) 2.79 8,989.21 2 MWD+IFR2+MS+Sag (3) 2.59 9,082.88 2_MWD+IFR2+MS+Sag(3) 1.69 9,177.09 2_MWD+IFR2+MS+Sag(3) 1.37 9,271.70 2_MWD+IFR2+MS+Sag(3) 0.34 9,365.90 2_MWD+IFR2+MS+Sag(3) 2.98 9,459.66 2_MWD+IFR2+MS+Sag (3) 1/252019 1:05:36PM Page 5 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10 Design: MPU M-10 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map MD Inc Azi TVD TVDSS +NIS +EI -W Northing (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) 12,380.86 91.12 123.69 4,065.13 4,006.20 -3,452.47 9,243.85 6,024,479.95 12,474.36 91.74 122.42 4,062.80 4,003.87 -3,503.45 9,322.19 6,024,429.34 12,566.21 90.69 121.76 4,060.85 4,001.92 -3,552.24 9,399.99 6,024,380.92 12,661.20 89.58 120.59 4,060.63 4,001.70 -3,601.41 9,481.26 6,024,332.12 12,757.59 89.64 121.30 4,061.29 4,002.36 -3,650.97 9,563.93 6,024,282.95 12,852.16 88.71 122.14 4,062.65 003.72 -3,700.68 9,644.36 6,024,233.60 12,945.80 87.47 121.88 4,065.77 4,006.84 -3,750.29 9,723.72 6,024,184.37 13,040.62 86.17 122.15 4,071.03 4,012.10 -3,800.48 9,803.99 6,024,134.55 13,135.03 87.35 122.66 4,076.36 4,017.43 -3,850.99 9,883.57 6,024,084.41 13,229.08 87.79 124.23 4,080.35 4,021.42 -3,902.78 9,961.97 6,024,032.99 13,323.62 87.54 125.03 4,084.20 4,025.27 -3,956.46 10,039.70 6,023,979.67 13,417.94 90.51 125.98 4,085.81 4,026.88 4,011.22 10,116.46 6,023,925.26 13,512.63 90.75 126.82 4,084.77 4,025.84 4,067.41 10,192.67 6,023,869.43 13,606.46 90.26 126.86 4,083.94 4,025.01 -4,123.67 10,267.76 6,023,813.53 13,701.47 89.89 125.97 4,083.82 4,024.89 -4,180.07 10,344.22 6,023,757.48 13,794.45 88.65 125.87 4,085.00 4,026.07 -4,234.61 10,419.51 6,023,703.29 13,889.33 90.32 125.25 4,085.85 4,026.92 -4,289.78 10,496.69 6,023,648.48 13,983.80 92.36 123.24 4,083.64 4,024.71 -4,342.92 10,574.75 6,023,595.70 14,078.27 92.17 121.93 4,079.91 4,020.98 -4,393.76 10,654.29 6,023,545.24 14,173.03 93.16 121.63 4,075.50 4,016.57 4,443.61 10,734.75 6,023,495.76 14,267.27 93.35 121.27 4,070.15 4,011.22 -4,492.70 10,815.02 6,023,447.04 14,361.79 92.29 120.94 4,065.50 4,006.57 -4,541.47 10,895.85 6,023,398.65 14,456.49 92.11 120.88 4,061.87 4,002.94 4,590.08 10,977.04 6,023,350.42 14,550.77 91.68 121.52 4,058.75 3,999.82 4,638.90 11,057.64 6,023,301.98 14,645.09 91.55 123.36 4,056.09 3,997.16 4,689.47 11,137.21 6,023,251.78 14,739.54 91.74 126.30 4,053.38 3,994.45 -4,743.38 11,214.70 6,023,198.22 14,833.18 91.24 127.43 4,050.94 3,992.01 -4,799.54 11,289.59 6,023,142.41 14,926.69 91.06 128.42 4,049.07 3,990.14 4,857.00 11,363.33 6,023,085.30 15,012.58 90.50 129.32 4,047.90 3,988.97 -4,910.90 11,430.20 6,023,031.71 15,082.00 90.50 129.32 4,047.29 3,988.36 -4,954.88 11,483.90 6,022,987.98 Well MPU M-10 M-10 Actual RKB @ 58.93usft M-10 Actual RKB @ 58.93usft True Minimum Curvature NORTH US+CANADA Map Vertical Easting DLS Section (ft) ('/100') (ft) Survey Tool Name 543,372.48 2.12 9,554.96 2_MWD+IFR2+MS+Sag (3) 543,451.04 1.51 9,648.38 2_MWD+IFR2+MS+Sag (3) 543,529.06 1.35 9,740.09 2_MWD+IFR2+MS+Sag (3) 543,610.54 1.70 9,834.88 2_MWD+IFR2+MS+Sag (3) 543,693.43 0.74 9,931.03 2_MWD+IFR2+MS+Sag (3) 543,774.08 1.33 10,025.44 2_MWD+IFR2+MS+Sag (3) 543,853.66 1.35 10,118.90 2_MWD+IFR2+MS+Sag (3) 543,934.15 1.40 10,213.45 2_MWD+IFR2+MS+Sag (3) 544,013.95 1.36 10,307.61 2_MWD+IFR2+MS+Sag (3) 544,092.59 1.73 10,401.54 2_MWD+IFR2+MS+Sag(3) 544,170.55 0.89 10,496.00 2_MWD+IFR2+MS+Sag(3) 544,247.56 3.31 10,590.29 2 MWD+IFR2+MS+Sag (3) 544,324.01 0.92 10,684.95 2_MWD+IFR2+MS+Sag (3) 544,399.35 0.52 10,778.72 2_MWD+IFR2+MS+Sag (3) 544,47&&6 1.01 10,873.70 2_MWD+IFR2+MS+Sag (3) 544,551.60 1.34 10,966.66 2_MWD+IFR2+MS+Sag(3) 544,629.02 1.88 11,061.52 2_MWD+IFR2+MS+Sag(3) 544,707.32 3.03 11,155.95 2_MWD+IFR2+MS+Sag (3) 544,787.08 1.40 11,250.26 2_MWD+IFR2+MS+Sag (3) 544,867.76 1.09 11,344.78 2_MWD+IFR2+MS+Sag (3) 544,948.24 0.43 11,438.69 2_MWD+IFR2+MS+Sag (3) 545,029.29 1.17 11,532.88 2_MWD+IFR2+MS+Sag (3) 545,110.69 0.20 11,627.28 2_MWD+IFR2+MS+Sag (3) 545,191.51 0.82 11,721.31 2_MWD+IFR2+MS+Sag (3) 545,271.30 1.95 11,815.49 2_MWD+IFR2+MS+Sag(3) 545,349.03 3.12 11,909.89 2_MWD+IFR2+MS+Sag(3) 545,424.17 1.32 12,003.45 2_MWD+IFR2+MS+Sag(3) 545,498.17 1.08 12,096.81 2_MWD+IFR2+MS+Sag (3) 545,565.27 1.23 12,182.49 2_MWD+IFR2+MS+Sag (3) 545,619.17 0.00 12,251.70 PROJECTED to TD M1WrvAFOw�vnp vrw�r� Checked By: Chelsea Wright Approved By: Mitch Laird L ate^ W Date: 1-25-2019 1252019 1:05.36PM Page 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10 PB1 MPU M-10 PB1 500292361770 P61 Sperry Drilling Definitive Survey Report 14 January, 2019 HALLIBURTON Sperry Drilling Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10 Pat Design: MPU M-10PB1 Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU Mt -10 TVD Reference: M-10 Actual RKB @ 58.93usft MD Reference: M-10 Actual RKB @ 58.93usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA *reject Milne Point, ACT, MILNE POINT Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Wap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-10 Well Position +N/ -S +E/ -W Position Uncertainty Wellbore MPU M-10 P81 Magnetics Model Name 0.00 usft Northing: 6,027,889.65 usfl 0.00 usft Easting: 534,113.80 usfl 0.00 usft Wellhead Elevation: 24.90 usfl Sample Date Declination (I BGGM2018 10/1/2018 16.98 Design MPU M-10PB1 Audit Notes: Version: 1.0 Vertical Section: Phase: ACTUAL Depth From (ND) +N/ -S (usft) (usft) 34.03 0.00 Latitude: 70° 29'13.990 N Longitude: 149° 43' 16.219 W Ground Level: 24.90 usfl Dip Angle Field Strength (°) (nT) 80.98 57,449.91575736 Tie On Depth: 34.03 +EI -W Direction (usft) (°) 0.00 124.94 Survey Program Date 1/7/2019 From To (usft) lush) Survey (Wellbore) Tool Name Description Survey Date 170.94 6,619.48 MPU M-10PB1 MWD+IFR2+MS+Sag (1) 2_MWD+IFR2+MS+Sag A013Mb: IFR dec & multi -station analysis +sa 12/19/2018 6,710.78 12,559.71 MPU M-10PB1 MWD+IFR+MS+Sag (2) (2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 01/03/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (I (I (usft) (usft) (usft) (usft) (ft) (ft) 01001) (ft) Survey Tool Name 34.03 0.00 0.00 34.03 -24.90 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 UNDEFINED 170.94 0.38 142.01 170.94 112.01 -0.36 0.28 6,027,889.29 534,114.08 0.28 0.43 2_MWD+IFR2+MS+Sag(1) 227.67 0.33 142.01 227.67 168.74 -0.63 0.50 6,027,889.02 534,114.30 0.09 0.77 2_MWD+IFR2+MS+Sag(1) 322.96 0.92 100.77 322.95 264.02 -0.99 1.42 6,027,888.66 534,115.22 0.74 1.73 2_MWD+IFR2+MS+Sag(1) 416.60 3.07 37.93 416.54 357.61 0.84 3.70 6,027,890.51 534,117.49 2.96 2.55 2_MWD+IFR2+MS+Sag(1) 510.06 5.78 30.62 509.71 450.78 6.87 7.63 6,027,896.55 534,121.40 2.96 2.32 2_MWD+IFR2+MS+Sag(1) 603.55 8.51 42.95 602.47 543.54 15.99 14.75 6,027,905.70 534,128.47 3.33 2.93 2_MWD+IFR2+MS+Sag(1) 696.41 11.70 55.78 693.89 634.96 26.31 27.22 6,027,916.09 534,140.89 4.18 7.24 2_MWD+IFR2+MS+Sag(1) 790.33 12.74 69.53 785.70 726.77 35.29 44.80 6,027,925.14 534,158.43 3.28 16.51 2_MWD+IFR2+MS+Sag(1) 884.81 16.79 76.07 877.05 818.12 42.22 67.81 6,027,932.18 534,181.41 4.63 31.41 2_MWD+IFR2+MS+Sag(1) 980.75 19.90 78.90 968.10 909.17 48.71 97.29 6,027,938.80 534,210.86 3.37 51.86 2_MWD+IFR2+MS+Sag(1) 1,074.92 24.60 80.13 1,055.24 996.31 55.15 132.35 6,027,945.41 534,245.88 5.02 76.91 2_MWD+IFR2+MS+Sag(1) 1,168.88 29.58 79.82 1,138.86 1,079.93 62.61 174.47 6,027,953.05 534,287.96 5.30 107.16 2_MWD+IFR2+MS+Sag(1) 1/14/2019 6.40:59PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU Mt -10 Project: Milne Point TVD Reference: M-10 Actual RKB @ 58.93usft Site: M Pt Moose Pad MD Reference: M-10 Actual RKB @ 58.93usft Well: MPU M-10 North Reference: True Wellbore: MPU M-10 PB1 Survey Calculation Method: Minimum Curvature Design: MPU M-10PB1 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +El -W Northing Easting DLS Section (usft) (°) r) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 1,263.59 33.20 79.91 1,219.70 1,160.77 71.29 223.02 6,027,961.95 534,336.47 3.82 142.00 2_MWD+IFR2+MS+Sag(1) 1,357.77 34.99 80.99 1,297.69 1,238.76 80.03 275.08 6,027,970.94 534,388.49 2.01 179.66 2_MWD+IFR2+MS+Sag(1) 1,452.25 36.90 82.00 1,374.17 1,315.24 88.23 329.93 6,027,979.38 534,443.29 2.12 219.93 2_MWD+IFR2+MS+Sag(1) 1,546.61 42.91 82.25 1,446.52 1,387.59 96.51 389.87 6,027,987.93 534,503.18 6.37 264.32 2 MWD+IFR2+MS+Sag (1) 1,641.35 44.25 82.77 1,515.15 1,456.22 105.02 454.62 6,027,996.74 534,567.89 1.46 312.53 2_MWD+IFR2+MS+Sag (1) 1,735.11 47.49 82.20 1,580.43 1,521.50 113.83 521.33 6,028,005.85 534,634.55 3.48 362.17 2_MWD+IFR2+MS+Sag(1) 1,828.09 52.45 82.90 1,640.21 1,581.28 123.04 591.90 6,028,015.39 534,705.07 5.37 414.75 2_MWD+IFR2+MS+Sag(1) 1,923.77 53.56 85.11 1,697.79 1,638.86 131.01 667.90 6,028,023.71 534,781.02 2.18 472.48 2_MWD+IFR2+MS+Sag (1) 2,018.36 53.75 84.02 1,753.85 1,694.92 138.23 743.74 6,028,031.27 534,856.82 0.95 530.52 2 MWD+IFR2+MS+Sag (1) 2,112.50 55.83 84.03 1,808.13 1,749.20 146.23 820.23 6,028,039.63 534,933.27 2.21 588.64 2_MWD+IFR2+MS+Sag (1) 2,206.42 55.37 85.07 1,861.19 1,802.26 153.59 897.38 6,028,047.34 535,010.37 1.04 647.66 2_MWD+IFR2+MS+Sag (1) 2,301.32 55.95 85.50 1,914.72 1,855.79 160.03 975.47 6,028,054.14 535,088.43 0.72 707.99 2_MWD+IFR2+MS+Sag(1) 2,395.66 55.16 85.09 1,968.08 1,909.15 166.41 1,053.01 6,028,060.87 535,165.93 0.91 767.90 2_MWD+IFR2+MS+Sag (1) 2,490.05 55.11 84.88 2,022.04 1,963.11 173.18 1,130.16 6,028,068.00 535,243.04 0.19 827.26 2_MWD+IFR2+MS+Sag(1) 2,584.59 54.94 85.05 2,076.23 2,017.30 179.98 1,207.32 6,028,075.15 535,320.17 0.23 886.63 2_MWD+IFR2+MS+Sag(1) 2,678.80 54.32 85.48 2,130.77 2,071.84 186.32 1,283.88 6,028,081.84 535,396.69 0.76 945.75 2_MWD+IFR2+MS+Sag(1) 2,772.66 53.54 86.76 2,186.03 2,127.10 191.46 1,359.57 6,028,087.33 535,472.35 1.38 1,004.86 2_MWD+IFR2+MS+Sag(1) 2,866.86 53.54 87.13 2,242.01 2,183.08 195.50 1,435.23 6,028,091.71 535,547.97 0.32 1,064.56 2_MWD+IFR2+MS+Sag(1) 2,961.80 55.61 85.32 2,297.04 2,238.11 200.61 1,512.41 6,028,097.17 535,625.13 2.68 1,124.91 2_MWD+IFR2+MS+Sag(1) 3,056.37 55.34 85.58 2,350.64 2,291.71 206.79 1,590.08 6,028,103.71 535,702.76 0.36 1,185.04 2_MWD+IFR2+MS+Sag(1) 3,150.85 55.06 85.44 2,404.56 2,345.63 212.86 1,667.42 6,028,110.14 535,780.07 0.32 1,244.96 2_MWD+IFR2+MS+Sag(1) 3,245.49 56.28 85.15 2,457.93 2,399.00 219.28 1,745.31 6,028,116.91 535,857.92 1.31 1,305.14 2_MWD+IFR2+MS+Sag(1) 3,339.53 55.32 82.43 2,510.80 2,451.87 227.68 1,822.62 6,028,125.66 535,935.18 2.60 1,363.71 2_MWD+IFR2+MS+Sag(1) 3,434.32 52.70 83.06 2,566.50 2,507.57 237.37 1,898.70 6,028,135.70 536,011.20 2.82 1,420.52 2_MWD+IFR2+MS+Sag(1) 3,528.95 55.54 83.16 2,621.95 2,563.02 246.56 1,974.81 6,028,145.25 536,087.26 3.00 1,477.64 2_MWD+IFR2+MS+Sag(1) 3,622.79 55.21 83.76 2,675.27 2,616.34 255.36 2,051.53 6,028,154.39 536,163.93 0.63 1,535.49 2_MWD+IFR2+MS+Sag(1) 3,717.12 55.62 84.06 2,728.82 2,669.89 263.60 2,128.75 6,028,162.98 536,241.11 0.51 1,594.08 2_MWD+IFR2+MS+Sag(1) 3,811.72 56.26 84.55 2,781.80 2,722.87 271.37 2,206.73 6,028,171.12 536,319.05 0.80 1,653.55 2_MWD+IFR2+MS+Sag(1) 3,906.17 56.78 84.34 2,833.90 2,774.97 279.00 2,285.14 6,028,179.10 536,397.41 0.58 1,713.46 2_MWD+IFR2+MS+Sag(1) 4,000.61 56.23 84.29 2,886.02 2,827.09 286.80 2,363.51 6,028,187.26 536,475.74 0.58 1,773.24 2_MWD+IFR2+MS+Sag(1) 4,094.86 57.19 84.76 2,937.75 2,878.82 294.32 2,441.93 6,028,195.14 536,554.12 1.10 1,833.22 2_MWD+IFR2+MS+Sag(1) 4,188.60 57.20 84.54 2,988.54 2,929.61 301.66 2,520.38 6,028,202.84 536,632.52 0.20 1,893.32 2_MWD+IFR2+MS+Sag(1) 4,282.89 54.71 85.79 3,041.32 2,982.39 308.26 2,598.22 6,028,209.79 536,710.32 2.86 1,953.35 2_MWD+IFR2+MS+Sag(1) 4,377.33 53.48 87.26 3,096.71 3,037.78 312.90 2,674.57 6,028,214.79 536,786.64 1.81 2,013.28 2_MWD+IFR2+MS+Sag(1) 4,470.79 52.59 84.94 3,152.91 3,093.98 317.97 2,749.06 6,028,220.20 536,861.11 2.20 2,071.44 2 MWD+IFR2+MS+Sag(1) 4,565.71 54.33 85.03 3,209.42 3,150.49 324.64 2,825.03 6,028,227.21 536,937.03 1.83 2,129.90 2_MWD+IFR2+MS+Sag(1) 4,660.04 53.38 84.52 3,265.06 3,206.13 331.57 2,900.89 6,028,234.49 537,012.85 1.10 2,188.11 2_MWD+IFR2+MS+Sag(1) 4,755.01 54.57 84.42 3,320.92 3,261.99 338.98 2,977.34 6,028,242.25 537,089.26 1.26 2,246.54 2_MWD+IFR2+MS+Sag(1) 4,848.09 55.02 84.74 3,374.58 3,315.65 346.16 3,053.05 6,028,249.77 537,164.93 0.56 2,304.49 2_MWD+IFR2+MS+Sag(1) 4,942.85 56.65 85.24 3,427.79 3,368.86 353.00 3,131.16 6,028,256.98 537,243.00 1.77 2,364.60 2_MWD+IFR2+MS+Sag(1) 1/142019 6:40:59PM Page 3 COMPASS 5000.15 Build 91 Company: Hiicorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10 PB1 Design: MPU M-10PB1 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing (usft) (1 (1) (usft) (usft) (usft) (usft) (ft) 5,037.22 55.01 83.92 3,480.79 3,421.86 360.37 3,208.88 6,028,264.70 5,131.28 55.40 84.84 3,534.47 3,475.54 367.93 3,285.75 6,028,272.61 5,226.52 57.90 89.67 3,586.84 3,527.91 371.69 3,365.18 6,028,276.74 5,321.09 57.71 94.91 3,637.26 3,578.33 368.50 3,445.10 6,028,273.91 5,415.62 58.70 97.70 3,687.07 3,628.14 359.67 3,524.94 6,028,265.45 5,507.35 60.77 101.27 3,733.31 3,674.38 346.59 3,603.06 6,028,252.73 5,603.63 65.21 105.15 3,777.04 3,718.11 326.94 3,686.51 6,028,233.46 5,697.88 66.83 106.69 3,815.34 3,756.41 303.32 3,769.31 6,028,210.22 5,792.62 69.52 109.49 3,850.57 3,791.64 275.99 3,852.89 6,028,183.28 5,887.15 72.45 111.97 3,881.37 3,822.44 244.35 3,936.45 6,028,152.03 5,980.93 74.91 113.39 3,907.72 3,848.79 209.64 4,019.48 6,028,117.71 6,075.24 81.07 116.75 3,927.34 3,868.41 170.55 4,102.97 6,028,079.00 6,170.20 82.69 118.19 3,940.75 3,881.82 127.19 4,186.38 6,028,036.03 6,263.30 81.71 120.62 3,953.39 3,894.46 81.91 4,266.73 6,027,991.12 6,355.51 82.27 122.51 3,966.24 3,907.31 34.11 4,344.52 6,027,943.68 6,450.48 81.41 122.29 3,979.72 3,920.79 -16.26 4,423.90 6,027,893.68 6,547.05 84.99 123.73 3,991.15 3,932.22 -68.49 4,504.29 6,027,841.82 6,619.48 86.01 124.83 3,996.83 3,937.90 -109.16 4,563.95 6,027,801.43 6,710.78 87.54 122.43 4,001.97 3,943.04 -159.64 4,639.84 6,027,751.31 6,803.73 88.04 122.44 4,005.56 3,946.63 -209.46 4,718.23 6,027,701.86 6,899.01 88.53 123.08 4,008.41 3,949.48 -260.99 4,798.32 6,027,650.70 6,993.63 90.14 123.89 4,009.51 3,950.58 -313.19 4,877.23 6,027,598.87 7,088.02 88.83 124.21 4,010.35 3,951.42 -366.04 4,955.43 6,027,546.38 7,183.49 89.27 126.35 4,011.94 3,953.01 -421.17 5,033.35 6,027,491.62 7,277.24 88.96 126.41 4,013.39 3,954.46 476.77 5,108.82 6,027,436.37 7,368.80 88.34 125.45 4,015.54 3,956.61 -530.48 5,182.94 6,027,383.00 7,465.47 89.15 128.18 4,017.66 3,958.73 -588.39 5,260.30 6,027,325.46 7,560.90 89.27 131.55 4,018.98 3,960.05 -649.54 5,333.53 6,027,264.64 7,655.20 88.96 131.56 4,020.43 3,961.50 -712.09 5,404.09 6,027,202.43 7,749.31 87.10 130.56 4,023.67 3,964.74 -773.86 5,475.01 6,027,140.98 7,843.56 86.80 128.35 4,028.68 3,969.75 -833.67 5,547.67 6,027,081.52 7,937.86 87.17 126.18 4,033.64 3,974.71 -890.68 5,622.61 6,027,024.85 8,032.41 88.22 125.59 4,037.45 3,978.52 -946.06 5,699.15 6,026,969.84 8,126.73 89.76 124.84 4,039.11 3,980.18 -1,000.44 5,776.20 6,026,915.82 8,218.97 88.53 122.97 4,040.49 3,981.56 -1,051.88 5,852.74 6,026,864.73 8,315.28 88.90 122.36 4,042.65 3,983.72 -1,103.85 5,933.80 6,026,813.14 8,410.15 88.84 121.93 4,044.52 3,985.59 -1,154.32 6,014.11 6,026,763.04 8,504.74 91.37 124.02 4,044.34 3,985.41 -1,205.79 6,093.45 6,026,711.94 8,599.26 90.07 123.61 4,043.16 3,984.23 -1,258.39 6,171.97 6,026,659.71 8,693.57 89.70 124.19 4,043.34 3,984.41 -1,310.99 6,250.25 6,026,607.47 Well MPU M-10 M-10 Actual RKB @ 58.93usft M-10 Actual RKB @ 58.93usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) ("1100') (ft) Survey Tool Name 537,320.68 2.09 2,424.10 2_MWD+IFR2+MS+Sag (1) 537,397.51 0.90 2,482.78 2_MWD+IFR2+MS+Sag (1) 537,476.90 4.98 2,545.74 2_MWD+IFR2+MS+Sag(1) 537,556.83 4.69 2,613.08 2_MWD+IFR2+MS+Sag(1) 537,636.71 2.72 2,683.59 2_MWD+IFR2+MS+Sag(1) 537,714.87 4.05 2,755.12 2_MWD+IFR2+MS+Sag (1) 537,798.41 5.84 2,834.78 2_MWD+IFR2+MS+Sag(1) 537,881.31 2.28 2,916.19 2_MWD+IFR2+MS+Sag(1) 537,965.01 3.95 3,000.35 2_MWD+IFR2+MS+Sag(1) 538,048.70 3.97 3,086.97 2_MWD+IFR2+MS+Sag(1) 538,131.88 3.00 3,174.92 2_MWD+IFR2+MS+Sag(1) 538,215.54 7.40 3,265.74 2_MWD+IFR2+MS+Sag(1) 538,299.14 2.27 3,358.95 2_MWD+IFR2+MS+Sag(1) 538,379.68 2.79 3,450.75 2_MWD+IFR2+MS+Sag(1) 538,457.69 2.12 3,541.90 2_MWD+IFR2+MS+Sag(1) 538,537.29 0.93 3,635.81 2_MWD+IFR2+MS+Sag(1) 538,617.91 3.99 3,731.63 2_MWD+IFR2+MS+Sag(1) 538,677.75 2.07 3,803.83 2 MWD+IFR2+MS+Sag(1) 538,753.87 3.11 3,894.95 2_MWD+IFR2+MS+Sag(2) 538,832.48 0.54 3,987.74 2_MWD+IFR2+MS+Sag(2) 538,912.80 0.85 4,082.91 2_MWD+IFR2+MS+Sag(2) 538,991.93 1.90 4,177.49 2_MWD+IFR2+MS+Sag(2) 539,070.37 1.43 4,271.86 2_MWD+IFR2+MS+Sag(2) 539,148.53 2.29 4,367.31 2_MWD+IFR2+MS+Sag(2) 539,224.25 0.34 4,461.02 2_MWD+IFR2+MS+Sag(2) 539,298.61 1.25 4,552.54 2_MWD+IFR2+MS+Sag (2) 539,376.23 2.95 4,649.12 2_MWD+IFR2+MS+Sag (2) 539,449.73 3.53 4,744.18 2_MWD+IFR2+MS+Sag (2) 539,520.57 0.33 4,837.84 2_MWD+IFR2+MS+Sag(2) 539,591.76 2.24 4,931.35 2 MWD+IFR2+MS+Sag(2) 539,664.69 2.36 5,025.17 2_MWD+IFR2+MS+Sag(2) 539,739.88 2.33 5,119.26 2_MWD+IFR2+MS+Sag(2) 539,816.67 1.27 5,213.72 2_MWD+IFR2+MS+Sag(2) 539,893.95 1.82 5,308.02 2_MWD+IFR2+MS+Sag (2) 539,970.72 2.43 5,400.23 2_MWD+IFR2+MS+Sag (2) 540,052.01 0.74 5,496.44 2_MWD+IFR2+MS+Sag (2) 540,132.54 0.46 5,591.17 2_MWD+IFR2+MS+Sag (2) 540,212.11 3.47 5,685.70 2_MWD+IFR2+MS+Sag(2) 540,290.87 1.44 5,780.19 2_MWD+IFR2+MS+Sag(2) 540,369.38 0.73 5,874.48 2_MWD+IFR2+MS+Sag (2) 1/142019 6:40:59PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hiicorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10 MPU M-10 PB1 MPU M-10PB1 Local Co-ordinate Reference: Well MPU M-10 TVD Reference: M-10 Actual RKB @ 58.93usft MD Reference: M-10 Actual RKB @ 58.93usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azl TVD TVDSS +Nl-S 4E/ -W Northing Easting DLS Section (usft) (') (`) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,786.66 90.63 124.64 4,043.08 3,984.15 -1,363.60 6,327.04 6,026,555.22 540,446.41 1.11 5,967.57 2_MWD+IFR2+MS+Sag(2) 8,881.35 90.01 124.08 4,042.55 3,983.62 -1,417.04 6,405.21 6,026,502.14 540,524.81 0.88 6,062.25 2_MWD+IFR2+MS+Sag(2) 8,973.62 89.14 123.99 4,043.23 3,984.30 -1,468.68 6,481.67 6,026,450.86 540,601.50 0.95 6,154.50 2_MWD+IFR2+MS+Sag(2) 9,069.68 89.52 125.49 4,044.36 3,985.43 -1,523.42 6,560.60 6,026,396.49 540,680.67 1.61 6,250.55 2_MWD+IFR2+MS+Sag(2) 9,163.54 91.00 125.56 4,043.93 3,985.00 -1,577.95 6,636.98 6,026,342.31 540,757.30 1.58 6,344.41 2_MWD+IFR2+MS+Sag(2) 9,255.80 92.73 125.17 4,040.93 3,982.00 -1,631.32 6,712.18 6,026,289.29 540,832.73 1.92 6,436.61 2 MWD+IFR2+MS+Sag (2) 9,350.05 91.80 125.05 4,037.20 3,978.27 -1,685.49 6,789.22 6,026,235.49 540,910.01 0.99 6,530.79 2_MWD+IFR2+MS+Sag (2) 9,446.02 91.80 125.44 4,034.19 3,975.26 -1,740.84 6,867.56 6,026,180.50 540,988.59 0.41 6,626.71 2_MWD+IFR2+MS+Sag (2) 9,540.33 90.75 125.43 4,032.09 3,973.16 -1,795.50 6,944.38 6,026,126.19 541,065.66 1.11 6,720.99 2_MWD+IFR2+MS+Sag (2) 9,634.89 91.24 125.88 4,030.45 3,971.52 -1,850.62 7,021.20 6,026,071.44 541,142.72 0.70 6,815.53 2_MWD+IFR2+MS+Sag (2) 9,729.57 89.76 125.42 4,029.62 3,970.69 -1,905.79 7,098.13 6,026,016.62 541,219.90 1.64 6,910.19 2_MWD+IFR2+MS+Sag (2) 9,824.36 90.38 124.26 4,029.51 3,970.58 -1,959.95 7,175.93 6,025,962.83 541,297.93 1.39 7,004.98 2_MWD+IFR2+MS+Sag(2) 9,918.91 89.45 123.39 4,029.65 3,970.72 -2,012.58 7,254.47 6,025,910.57 541,376.71 1.35 7,099.51 2_MWD+IFR2+MS+Sag (2) 10,013.67 88.65 121.18 4,031.22 3,972.29 -2,063.18 7,334.57 6,025,860.34 541,457.03 2.48 7,194.15 2_MWD+IFR2+MS+Sag (2) 10,108.03 89.27 120.03 4,032.93 3,974.00 -2,111.21 7,415.77 6,025,812.68 541,538.44 1.38 7,288.22 2_MWD+IFR2+MS+Sag(2) 10,202.55 89.76 120.19 4,033.73 3,974.80 -2,158.63 7,497.53 6,025,765.65 541,620.41 0.55 7,382.40 2 MWD+IFR2+MS+Sag(2) 10,295.06 90.26 119.63 4,033.71 3,974.78 -2,204.76 7,577.72 6,025,719.89 541,700.80 0.81 7,474.55 2_MWD+IFR2+MS+Sag(2) 10,391.23 90.20 119.76 4,033.33 3,974.40 -2,252.40 7,661.26 6,025,672.64 541,784.55 0.15 7,570.32 2 MWD+IFR2+MS+Sag(2) 10,485.18 90.13 121.84 4,033.06 3,974.13 -2,300.50 7,741.95 6,025,624.91 541,865.46 2.22 7,664.02 2_MWD+IFR2+MS+Sag(2) 10,579.42 89.58 123.48 4,033.30 3,974.37 -2,351.35 7,821.29 6,025,574.43 541,945.02 1.84 7,758.18 2_MWD+IFR2+MS+Sag(2) 10,672.41 89.21 124.61 4,034.28 3,975.35 -2,403.41 7,898.33 6,025,522.73 542,022.29 1.28 7,851.15 2_MWD+IFR2+MS+Sag(2) 10,768.36 87.60 124.86 4,036.95 3,978.02 -2,458.06 7,977.15 6,025,468.45 542,101.36 1.70 7,947.06 2_MWD+IFR2+MS+Sag(2) 10,862.22 87.72 125.43 4,040.78 3,981.85 -2,512.04 8,053.84 6,025,414.82 542,178.28 0.62 8,040.84 2_MWD+IFR2+MS+Sag(2) 10,957.32 86.92 125.70 4,045.23 3,986.30 -2,567.29 8,131.11 6,025,359.93 542,255.80 0.89 8,135.83 2_MWD+IFR2+MS+Sag(2) 11,051.90 87.05 126.93 4,050.20 3,991.27 -2,623.23 8,207.21 6,025,304.35 542,332.15 1.31 8,230.25 2_MWD+IFR2+MS+Sag(2) 11,144.00 87.85 127.41 4,054.30 3,995.37 -2,678.82 8,280.53 6,025,249.10 542,405.71 1.01 8,322.19 2_MWD+IFR2+MS+Sag(2) 11,240.68 87.91 127.34 4,057.88 3,998.95 -2,737.47 8,357.31 6,025,190.82 542,482.75 0.10 8,418.72 2_MWD+IFR2+MS+Sag(2) 11,335.09 88.10 128.17 4,061.16 4,002.23 -2,795.24 8,431.91 6,025,133.39 542,557.61 0.90 8,512.96 2_MWD+IFR2+MS+Sag(2) 11,426.89 88.78 128.44 4,063.66 4,004.73 -2,852.12 8,503.92 6,025,076.85 542,629.87 0.80 8,604.56 2_MWD+IFR2+MS+Sag(2) 11,523.56 90.01 128.71 4,064.68 4,005.75 -2,912.39 8,579.49 6,025,016.93 542,705.71 1.30 8,701.03 2_MWD+IFR2+MS+Sag(2) 11,617.45 89.58 127.61 4,065.02 4,006.09 -2,970.40 8,653.31 6,024,959.27 542,779.79 1.26 8,794.77 2_M4VD+IFR2+MS+Sag(2) 11,713.11 87.53 126.05 4,067.43 4,008.50 -3,027.72 8,729.85 6,024,902.30 542,856.58 2.69 8,890.34 2_MWD+IFR2+MS+Sag(2) 11,805.67 88.47 125.24 4,070.66 4,011.73 -3,081.62 8,805.02 6,024,848.75 542,931.99 1.34 8,982.84 2_MWD+IFR2+MS+Sag(2) 11,899.13 87.10 124.79 4,074.27 4,015.34 -3,135.21 8,881.50 6,024,795.52 543,008.71 1.54 9,076.22 2_MWD+IFR2+MS+Sag(2) 11,992.86 86.73 125.42 4,079.32 4,020.39 -3,189.03 8,958.07 6,024,742.05 543,085.52 0.78 9,169.82 2_MWD+IFR2+MS+Sag (2) 12,087.77 86.36 125.99 4,085.04 4,026.11 -3,244.32 9,035.00 6,024,687.12 543,162.69 0.72 9,264.54 2_MWD+IFR2+MS+Sag (2) 12,182.75 88.35 127.78 4,089.42 4,030.49 -3,301.27 9,110.88 6,024,630.53 543,238.83 2.82 9,359.36 2_MWD+IFR2+MS+Sag (2) 12,276.77 91.87 130.12 4,089.24 4,030.31 -3,360.36 9,183.98 6,024,571.78 543,312.19 4.50 9,453.13 2_MWD+IFR2+MS+Sag (2) 12,370.84 91.99 129.51 4,086.07 4,027.14 -3,420.56 9,256.20 6,024,511.92 543,384.68 0.66 9,546.80 2_MWD+IFR2+MS+Sag (2) 12,465.47 92.61 127.93 4,082.27 4,023.34 -3,479.70 9,329.97 6,024,453.12 543,468.71 1.79 9,641.15 2_MWD+IFR2+MS+Sag(2) 1/142019 6:40:59PM Page 5 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10 Pat Design: MPU M-10PB1 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU M-10 TVD Reference: M-10 Actual RKB @ 58.93usft MD Reference: M-10 Actual RKB @ 58.93usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Checked By: Chelsea Wright�Y Approved By: Mitch Laird Date: 01-14-2019 1/142019 6:40:59PM Page 6 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (`1100') (ft) Survey Tool Name 12,559.71 92.48 127.17 4,078.09 4,019.16 -3,537.08 9,404.61 6,024,396.09 543,533.60 0.82 9,735.20 2_MWD+IFR2+MS+Sag(2) 12,630.00 92.48 127.17 4,075.05 4,016.12 -3,579.51 9,460.57 6,024,353.93 543,589.75 0.00 9,805.37 PROJECTED to TD Checked By: Chelsea Wright�Y Approved By: Mitch Laird Date: 01-14-2019 1/142019 6:40:59PM Page 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10PB2 500292361771 Sperry Drilling Definitive Survey Report 14 January, 2019 I &V-6 co HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-10 Project: Milne Point TVD Reference: M-10 Actual RKB @ 58.93usft Site: M Pt Moose Pad MD Reference: M-10 Actual RKB @ 58.93usft Well: MPU M-10 North Reference: True Wellbore: MPU M-10PB2 Survey Calculation Method: Minimum Curvature Design: MPU M-10PB2 Database: NORTH US+CANADA Iroject Milne Point, ACT, MILNE POINT Asp System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Clap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-10 Well Position +NI -S +EI -W Position Uncertainty Wellbore MPU M-10PB2 Magnetics Model Name 0.00 usft Northing: 6,027,889.65 usfl 0.00 usft Easting: 534,113.80 usfl 0.00 usft Wellhead Elevation: 24.90 usfl Sample Date Declination (1) BGGM2018 1/7/2019 16.83 Design MPU M-10PB2 Audit Notes: Version: 1.0 Phase: ACTUAL Vertical Section: Depth From (TVD) +N/ -S (usft) (usft) 34.03 0.00 Latitude: 70° 29'13.990 N Longitude: 149° 43' 16.219 W Ground Level: 24.90 usft Dip Angle Field Strength (°) (nT) 80.97 57,439.56345820 Tie On Depth: +E/ -W (usft) 0.00 12,276.77 Direction (I 124.94 Survey Program Date 1/7/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 170.94 6,619.48 MPU M-10PB1 MWD+IFR2+MS+Sag(1)2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 12/1912018 6,710.78 12,276.77 MPU M-10PB1 MWD+IFR+MS+Sag (2) (2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 01/03/2019 12,287.00 12,750.57 MPU M-10PB2 MWD+IFR2+MS+Sag (3) 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis + sa 01/07/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 34.03 0.00 0.00 34.03 -24.90 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 UNDEFINED 170.94 0.38 142.01 170.94 112.01 -0.36 0.28 6,027,889.29 534,114.08 0.28 0.43 2_MWD+IFR2+MS+Sag(1) 227.67 0.33 142.01 227.67 168.74 -0.63 0.50 6,027,889.02 534,114.30 0.09 0.77 2_MWD+IFR2+MS+Sag(1) 322.96 0.92 100.77 322.95 264.02 -0.99 1.42 6,027,888.66 534,115.22 0.74 1.73 2_MWD+IFR2+MS+Sag(1) 416.60 3.07 37.93 416.54 357.61 0.84 3.70 6,027,890.51 534,117.49 2.96 2.55 2_MWD+IFR2+MS+Sag(1) 510.06 5.78 30.62 509.71 450.78 6.87 7.63 6,027,896.55 534,121.40 2.96 2.32 2_MWD+IFR2+MS+Sag(1) 603.55 8.51 42.95 602.47 543.54 15.99 14.75 6,027,905.70 534,128.47 3.33 2.93 2_MWD+IFR2+MS+Sag(1) 696.41 11.70 55.78 693.89 634.96 26.31 27.22 6,027,916.09 534,140.89 4.18 7.24 2_MWD+IFR2+MS+Sag(1) 790.33 12.74 69.53 785.70 726.77 35.29 44.80 6,027,925.14 534,158.43 3.28 16.51 2_MWD+IFR2+MS+Sag(1) 884.81 16.79 76.07 877.05 818.12 42.22 67.81 6,027,932.18 534,181.41 4.63 31.41 2 MWD+IFR2+MS+Sag(1) 980.75 19.90 78.90 968.10 909.17 48.71 97.29 6,027,938.80 534,210.86 3.37 51.86 2_MWD+IFR2+MS+Sag(1) 1,074.92 24.60 80.13 1,055.24 996.31 55.15 132.35 6,027,945.41 534,245.88 5.02 76.91 2_MWD+IFR2+MS+Sag(1) 1/142019 6.41:44PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M10 Project: Milne Point TVD Reference: M-10 Actual RKB @ 58.93usfi Site: M Pt Moose Pad MD Reference: M-10 Actual RKB @ 58.93usft Well: MPU M-10 North Reference: True Wellbore: MPU M-10PB2 Survey Calculation Method: Minimum Curvature Design: MPU M-10PB2 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting DIS Section (usft) (') (') (usft) (usft) (usft) (usft) (ft) (ft) ('NOo-) (ft) Survey Tool Name 1,168.88 29.58 79.82 1,138.86 1,079.93 62.61 174.47 6,027,953.05 534,287.96 5.30 107.16 2_MWD+IFR2+MS+Sag(1) 1,253.59 33.20 79.91 1,219.70 1,160.77 71.29 223.02 6,027,961.95 534,336.47 3.82 142.00 2_MWD+IFR2+MS+Sag (1) 1,357.77 34.99 80.99 1,297.69 1,238.76 80.03 275.08 6,027,970.94 534,388.49 2.01 179.66 2_MWD+IFR2+MS+Sag(1) 1,452.25 36.90 82.00 1,374.17 1,315.24 88.23 329.93 6,027,979.38 534,443.29 2.12 219.93 2_MWD+IFR2+MS+Sag(1) 1,546.61 42.91 82.25 1,446.52 1,387.59 96.51 389.87 6,027,987.93 534,503.18 6.37 264.32 2_MWD+IFR2+MS+Sag(1) 1,641.35 44.25 82.77 1,515.15 1,456.22 105.02 454.62 6,027,996.74 534,567.89 1.46 312.53 2_MWD+IFR2+MS+Sag(1) 1,735.11 47.49 82.20 1,580.43 1,521.50 113.83 521.33 6,028,005.85 534,634.55 3.48 362.17 2_MWD+IFR2+MS+Sag(1) 1,828.09 52.45 82.90 1,640.21 1,581.28 123.04 591.90 6,028,015.39 534,705.07 5.37 414.75 2_MWD+IFR2+MS+Sag(1) 1,923.77 53.56 85.11 1,697.79 1,638.86 131.01 667.90 6,028,023.71 534,781.02 2.18 472.48 2 MWD+IFR2+MS+Sag(1) 2,018.36 53.75 84.02 1,753.85 1,694.92 138.23 743.74 6,028,031.27 534,856.82 0.95 530.52 2_MWD+IFR2+MS+Sag(1) 2,112.50 55.83 84.03 1,808.13 1,749.20 146.23 820.23 6,028,039.63 534,933.27 2.21 588.64 2_MWD+IFR2+MS+Sag(1) 2,206.42 55.37 85.07 1,861.19 1,802.26 153.59 897.38 6,028,047.34 535,010.37 1.04 647.66 2_MWD+IFR2+MS+Sag(1) 2,301.32 55.95 85.50 1,914.72 1,855.79 160.03 975.47 6,028,054.14 535,088.43 0.72 707.99 2_MWD+IFR2+MS+Sag(1) 2,395.66 55.16 85.09 1,968.08 1,909.15 166.41 1,053.01 6,028,060.87 535,165.93 0.91 767.90 2_MWD+IFR2+MS+Sag(1) 2,490.05 55.11 84.88 2,022.04 1,963.11 173.18 1,130.16 6,028,068.00 535,243.04 0.19 827.26 2_MWD+IFR2+MS+Sag(1) 2,584.59 54.94 85.05 2,076.23 2,017.30 179.98 1,207.32 6,028,075.15 535,320.17 0.23 886.63 2_MWD+IFR2+MS+Sag(1) 2,678.80 54.32 85.48 2,130.77 2,071.84 186.32 1,283.88 6,028,081.84 535,396.69 0.76 945.75 2_MWD+IFR2+MS+Sag(1) 2,772.66 53.54 86.76 2,186.03 2,127.10 191.46 1,359.57 6,028,087.33 535,472.35 1.38 1,004.86 2_MWD+IFR2+MS+Sag(1) 2,866.86 53.54 87.13 2,242.01 2,183.08 195.50 1,435.23 6,028,091.71 535,547.97 0.32 1,064.56 2_MWD+IFR2+MS+Sag(1) 2,961.80 55.61 85.32 2,297.04 2,238.11 200.61 1,512.41 6,028,097.17 535,625.13 2.68 1,124.91 2_MWD+IFR2+MS+Sag(1) 3,056.37 55.34 85.58 2,350.64 2,291.71 206.79 1,590.08 6,028,103.71 535,702.76 0.36 1,185.04 2_MWD+IFR2+MS+Sag (1) 3,150.85 55.06 85.44 2,404.56 2,345.63 212.86 1,667.42 6,028,110.14 535,780.07 0.32 1,244.96 2_MWD+IFR2+MS+Sag(1) 3,245.49 56.28 85.15 2,457.93 2,399.00 219.28 1,745.31 6,028,116.91 535,857.92 1.31 1,305.14 2_MWD+IFR2+MS+Sag(1) 3,339.53 55.32 82.43 2,510.80 2,451.87 227.68 1,822.62 6,028,125.66 535,935.18 2.60 1,363.71 2_MWD+IFR2+MS+Sag(1) 3,434.32 52.70 83.06 2,566.50 2,507.57 237.37 1,898.70 6,028,135.70 536,011.20 2.82 1,420.52 2_MWD+IFR2+MS+Sag(1) 3,528.95 55.54 83.16 2,621.95 2,563.02 246.56 1,974.81 6,028,145.25 536,087.26 3.00 1,477.64 2_MWD+IFR2+MS+Sag(1) 3,622.79 55.21 83.76 2,675.27 2,616.34 255.36 2,051.53 6,028154.39 536,163.93 0.63 1,535.49 2_MWD+IFR2+MS+Sag(1) 3,717.12 55.62 84.06 2,728.82 2,669.89 263.60 2,128.75 6,028,162.98 536,241.11 0.51 1,594.08 2 MWD+IFR2+MS+Sag(1) 3,811.72 56.26 84.55 2,781.80 2,722.87 271.37 2,206.73 6,028,171.12 536,319.05 0.80 1,653.55 2_MWD+IFR2+MS+Sag(1) 3,906.17 56.78 84.34 2,833.90 2,774.97 279.00 2,285.14 6,028,179.10 536,397.41 0.58 1,713.46 2_MWD+IFR2+MS+Sag(1) 4,000.61 56.23 84.29 2,886.02 2,827.09 286.80 2,363.51 6,028,187.26 536,475.74 0.58 1,773.24 2_MWD+IFR2+MS+Sag(1) 4,094.86 57.19 84.76 2,937.75 2,878.82 294.32 2,441.93 6,028,195.14 536,554.12 1.10 1,833.22 2_MWD+IFR2+MS+Sag(1) 4,188.60 57.20 84.54 2,988.54 2,929.61 301.66 2,520.38 6,028,202.84 536,632.52 0.20 1,893.32 2_MWD+IFR2+MS+Sag(1) 4,282.89 54.71 85.79 3,041.32 2,982.39 308.26 2,598.22 6,028,209.79 536,710.32 2.86 1,953.35 2_MWD+IFR2+MS+Sag(1) 4,377.33 53.48 87.26 3,096.71 3,037.78 312.90 2,674.57 6,028,214.79 536,786.64 1.81 2,013.28 2_MWD+IFR2+MS+Sag(1) 4,470.79 52.59 84.94 3,152.91 3,093.98 317.97 2,749.06 6,028,220.20 536,861.11 2.20 2,071.44 2_MWD+IFR2+MS+Sag(1) 4,565.71 54.33 85.03 3,209.42 3,150.49 324.64 2,825.03 6,028,227.21 536,937.03 1.83 2,129.90 2_MWD+IFR2+MS+Sag(1) 4,660.04 53.38 84.52 3,265.06 3,206.13 331.57 2,900.89 6,028,234.49 537,012.85 1.10 2,188.11 2_MWD+IFR2+MS+Sag(1) 4,755.01 54.57 84.42 3,320.92 3,261.99 338.98 2,977.34 6,028,242.25 537,089.26 1.26 2,246.54 2_MWD+IFR2+MS+Sag(1) 4,848.09 55.02 84.74 3,374.58 3,315.65 346.16 3,053.05 6,028,249.77 537,164.93 0.56 2,304.49 2_MWD+IFR2+MS+Sag(1) 1/142019 6:41:44PM Page 3 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10PB2 Design: MPU M-10PB2 Survey Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-10 M-10 Actual RKB @ 58.93usft M-10 Actual RKB @ 58.93usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD NDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 4,942.85 56.65 85.24 3,427.79 3,368.86 353.00 3,131.16 6,028,256.98 537,243.00 1.77 2,364.60 2_MW0+IFR2+MS+Sag(1) 5,037.22 55.01 83.92 3,480.79 3,421.86 360.37 3,208.88 6,028,264.70 537,320.68 2.09 2,424.10 2_MWD+IFR2+MS+Sag (1) 5,131.28 55.40 84.84 3,534.47 3,475.54 367.93 3,285.75 6,028,272.61 537,397.51 0.90 2,482.78 2_MWD+IFR2+MS+Sag (1) 5,226.52 57.90 89.67 3,586.84 3,527.91 371.69 3,365.18 6,028,276.74 537,476.90 4.98 2,545.74 2_MWD+IFR2+MS+Sag(1) 5,321.09 57.71 94.91 3,637.26 3,578.33 368.50 3,445.10 6,028,273.91 537,556.83 4.69 2,613.08 2_MWD+IFR2+MS+Sag(1) 5,415.62 58.70 97.70 3,687.07 3,628.14 359.67 3,524.94 6,028,265.45 537,636.71 2.72 2,683.59 2_MWD+IFR2+MS+Sag(1) 5,507.35 60.77 101.27 3,733.31 3,674.38 346.59 3,603.06 6,028,252.73 537,714.87 4.05 2,755.12 2_MWD+IFR2+MS+Sag(1) 5,603.63 65.21 105.15 3,777.04 3,718.11 326.94 3,686.51 6,028,233.46 537,798.41 5.84 2,834.78 2_MWD+IFR2+MS+Sag(1) 5,697.88 66.83 106.69 3,815.34 3,756.41 303.32 3,769.31 6,028,210.22 537,881.31 2.28 2,916.19 2_MWD+IFR2+MS+Sag(1) 5,792.62 69.52 109.49 3,850.57 3,791.64 275.99 3,852.89 6,028,183.28 537,965.01 3.95 3,000.35 2_MWD+IFR2+MS+Sag(1) 5,887.15 72.45 111.97 3,881.37 3,822.44 244.35 3,936.45 6,028,152.03 538,048.70 3.97 3,086.97 2_MWD+IFR2+MS+Sag(1) 5,980.93 74.91 113.39 3,907.72 3,848.79 209.64 4,019.48 6,028,117.71 538,131.88 3.00 3,174.92 2_MWD+IFR2+MS+Sag(1) 6,075.24 81.07 116.75 3,927.34 3,868.41 170.55 4,102.97 6,028,079.00 538,215.54 7.40 3,265.74 2_MWD+IFR2+MS+Sag(1) 6,170.20 82.69 118.19 3,940.75 3,881.82 127.19 4,186.38 6,028,036.03 538,299.14 2.27 3,358.95 2_MWD+IFR2+MS+Sag(1) 6,263.30 81.71 120.62 3,953.39 3,894.46 81.91 4,266.73 6,027,991.12 538,379.68 2.79 3,450.75 2_MWD+IFR2+MS+Sag(1) 6,355.51 82.27 122.51 3,966.24 3,907.31 34.11 4,344.52 6,027,943.68 538,457.69 2.12 3,541.90 2_MWD+IFR2+MS+Sag(1) 6,450.48 81.41 122.29 3,979.72 3,920.79 -16.26 4,423.90 6,027,893.68 538,537.29 0.93 3,635.81 2_MWD+IFR2+MS+Sag(1) 6,547.05 84.99 123.73 3,991.15 3,932.22 -68.49 4,504.29 6,027,841.82 538,617.91 3.99 3,731.63 2_MWD+IFR2+MS+Sag(1) 6,619.48 86.01 124.83 3,996.83 3,937.90 -109.16 4,563.95 6,027,801.43 538,677.75 2.07 3,803.83 2_MWD+IFR2+MS+Sag(1) 6,710.78 87.54 122.43 4,001.97 3,943.04 -159.64 4,639.84 6,027,751.31 538,753.87 3.11 3,894.95 2_MWD+IFR2+MS+Sag (2) 6,803.73 88.04 122.44 4,005.56 3,946.63 -209.46 4,718.23 6,027,701.86 538,832.48 0.54 3,987.74 2_MWD+IFR2+MS+Sag (2) 6,899.01 88.53 123.08 4,008.41 3,949.48 -260.99 4,798.32 6,027,650.70 538,912.80 0.85 4,082.91 2_MWD+IFR2+MS+Sag(2) 6,993.63 90.14 123.89 4,009.51 3,950.58 -313.19 4,877.23 6,027,598.87 538,991.93 1.90 4,177.49 2_MWD+IFR2+MS+Sag (2) 7,088.02 88.83 124.21 4,010.35 3,951.42 -366.04 4,955.43 6,027,546.38 539,070.37 1.43 4,271.86 2_MWD+IFR2+MS+Sag(2) 7,183.49 89.27 126.35 4,011.94 3,953.01 421.17 5,033.35 6,027,491.62 539,148.53 2.29 4,367.31 2_MWD+IFR2+MS+Sag(2) 7,277.24 88.96 126.41 4,013.39 3,954.46 -476.77 5,108.82 6,027,436.37 539,224.25 0.34 4,461.02 2_MWD+IFR2+MS+Sag(2) 7,368.80 88.34 125.45 4,015.54 3,956.61 -530.48 5,182.94 6,027,383.00 539,298.61 1.25 4,552.54 2_MWD+IFR2+MS+Sag (2) 7,465.47 89.15 128.18 4,017.66 3,958.73 -588.39 5,260.30 6,027,325.46 539,376.23 2.95 4,649.12 2_MWD+IFR2+MS+Sag (2) 7,560.90 89.27 131.55 4,018.98 3,960.05 -649.54 5,333.53 6,027,264.64 539,449.73 3.53 4,744.18 2_MWD+IFR2+MS+Sag (2) 7,655.20 88.96 131.56 4,020.43 3,961.50 -712.09 5,404.09 6,027,202.43 539,520.57 0.33 4,837.84 2_MWD+IFR2+MS+Sag (2) 7,749.31 87.10 130.56 4,023.67 3,964.74 -773.86 5,475.01 6,027,140.98 539,591.76 2.24 4,931.35 2_MWD+IFR2+MS+Sag(2) 7,843.56 86.80 128.35 4,028.68 3,969.75 -833.67 5,547.67 6,027,081.52 539,664.69 2.36 5,025.17 2_MWD+IFR2+MS+Sag(2) 7,937.86 87.17 126.18 4,033.64 3,974.71 -890.68 5,622.61 6,027,024.85 539,739.88 2.33 5,119.26 2_MWD+IFR2+MS+Sag(2) 8,032.41 88.22 125.59 4,037.45 3,978.52 -946.06 5,699.15 6,026,969.84 539,816.67 1.27 5,213.72 2_MWD+IFR2+MS+Sag(2) 8,126.73 89.76 124.84 4,039.11 3,980.18 -1,000.44 5,776.20 6,026,915.82 539,893.95 1.82 5,308.02 2_MWD+IFR2+MS+Sag(2) 8,218.97 88.53 122.97 4,040.49 3,981.56 -1,051.88 5,852.74 6,026,864.73 539,970.72 2.43 5,400.23 2_MWD+IFR2+MS+Sag (2) 8,315.28 88.90 122.36 4,042.65 3,983.72 -1,103.85 5,933.80 6,026,813.14 540,052.01 0.74 5,496.44 2_MWD+IFR2+MS+Sag(2) 8,410.15 88.84 121.93 4,044.52 3,985.59 -1,154.32 6,014.11 6,026,763.04 540,132.54 0.46 5,591.17 2_MWD+IFR2+MS+Sag(2) 8,504.74 91.37 124.02 4,044.34 3,985.41 -1,205.79 6,093.45 6,026,711.94 540,212.11 3.47 5,685.70 2_MWD+IFR2+MS+Sag(2) 8,599.26 90.07 123.61 4,043.16 3,984.23 -1,258.39 6,171.97 6,026,659.71 540,290.87 1.44 5,780.19 2_MWD+IFR2+MS+Sag(2) 1/142019 6:41:44PM Page 4 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10PB2 Design: MPU M-10PB2 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU M-10 M-10 Actual RKB @ 58.93usfl M-10 Actual RKB @ 58.93usfl True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (') (') (usft) (usft) (usft) (usft) (ft) (ft) (1/100') (ft) Survey Tool Name 8,693.57 89.70 124.19 4,043.34 3,984.41 -1,310.99 6,250.25 6,026,607.47 540,369.38 0.73 5,874.48 2_MWD+IFR2+MS+Sag(2) 8,786.66 90.63 124.64 4,043.08 3,984.15 -1,363.60 6,327.04 6,026,555.22 540,446.41 1.11 5,967.57 2_MWD+IFR2+MS+Sag(2) 8,881.35 90.01 124.08 4,042.55 3,983.62 -1,417.04 6,405.21 6,026,502.14 540,524.81 0.88 6,062.25 2_MWD+IFR2+MS+Sag(2) 8,973.62 89.14 123.99 4,043.23 3,984.30 -1,468.68 6,481.67 6,026,450.86 540,601.50 0.95 6,154.50 2 MWD+IFR2+MS+Sag (2) 9,069.68 89.52 125.49 4,044.36 3,985.43 -1,523.42 6,560.60 6,026,396.49 540,680.67 1.61 6,250.55 2_MWD+IFR2+MS+Sag (2) 9,163.54 91.00 125.56 4,043.93 3,985.00 -1,577.95 6,636.98 6,026,342.31 540,757.30 1.58 6,344.41 2_MWD+IFR2+MS+Sag (2) 9,255.80 92.73 125.17 4,040.93 3,982.00 -1,631.32 6,712.18 6,026,289.29 540,832.73 1.92 6,436.61 2_MWD+IFR2+MS+Sag (2) 9,350.05 91.80 125.05 4,037.20 3,978.27 -1,685.49 6,789.22 6,026,235.49 540,910.01 0.99 6,530.79 2_MWD+IFR2+MS+Sag (2) 9,446.02 91.80 125.44 4,034.19 3,975.26 -1,740.84 6,867.56 6,026,180.50 540,988.59 0.41 6,626.71 2_MWD+IFR2+MS+Sag (2) 9,540.33 90.75 125.43 4,032.09 3,973.16 -1,795.50 6,944.38 6,026,126.19 541,065.66 1.11 6,720.99 2_MWD+IFR2+MS+Sag(2) 9,634.89 91.24 125.88 4,030.45 3,971.52 -1,850.62 7,021.20 6,026,071.44 541,142.72 0.70 6,815.53 2_MWD+IFR2+MS+Sag(2) 9,729.57 89.76 125.42 4,029.62 3,970.69 -1,905.79 7,098.13 6,026,016.62 541,219.90 1.64 6,910.19 2_MWD+IFR2+MS+Sag(2) 9,824.36 90.38 124.26 4,029.51 3,970.58 -1,959.95 7,175.93 6,025,962.83 541,297.93 1.39 7,004.98 2_MWD+IFR2+MS+Sag(2) 9,918.91 89.45 123.39 4,029.65 3,970.72 -2,012.58 7,254.47 6,025,910.57 541,376.71 1.35 7,099.51 2 MWD+IFR2+MS+Sag(2) 10,013.67 88.65 121.18 4,031.22 3,972.29 -2,063.18 7,334.57 6,025,860.34 541,457.03 2.48 7,194.15 2_MWD+IFR2+MS+Sag(2) 10,108.03 89.27 120.03 4,032.93 3,974.00 -2,111.21 7,415.77 6,025,812.68 541,538.44 1.38 7,288.22 2_MWD+IFR2+MS+Sag(2) 10,202.55 89.76 120.19 4,033.73 3,974.80 -2,158.63 7,497.53 6,025,765.65 541,620.41 0.55 7,382.40 2_MWD+IFR2+MS+Sag(2) 10,295.06 90.26 119.63 4,033.71 3,974.78 -2,204.76 7,577.72 6,025,719.89 541,700.80 0.81 7,474.55 2_MWD+IFR2+MS+Sag(2) 10,391.23 90.20 119.76 4,033.33 3,974.40 -2,252.40 7,661.26 6,025,672.64 541,784.55 0.15 7,570.32 2_MWD+IFR2+MS+Sag(2) 10,485.18 90.13 121.84 4,033.06 3,974.13 -2,300.50 7,741.95 6,025,624.91 541,865.46 2.22 7,664.02 2_MWD+IFR2+MS+Sag(2) 10,579.42 89.58 123.48 4,033.30 3,974.37 -2,351.35 7,821.29 6,025,574.43 541,945.02 1.84 7,758.18 2_MWD+IFR2+MS+Sag(2) 10,672.41 89.21 124.61 4,034.28 3,975.35 -2,403.41 7,898.33 6,025,522.73 542,022.29 1.28 7,851.15 2_MWD+IFR2+MS+Sag(2) 10,768.36 87.60 124.86 4,036.95 3,978.02 -2,458.06 7,977.15 6,025,468.45 542,101.36 1.70 7,947.06 2_MWD+IFR2+MS+Sag(2) 10,862.22 87.72 125.43 4,040.78 3,981.85 -2,512.04 8,053.84 6,025,414.82 542,178.28 0.62 8,040.84 2_MWD+IFR2+MS+Sag(2) 10,957.32 86.92 125.70 4,045.23 3,986.30 -2,567.29 8,131.11 6,025,359.93 542,255.80 0.89 8,135.83 2_MWD+IFR2+MS+Sag(2) 11,051.90 87.05 126.93 4,050.20 3,991.27 -2,623.23 8,207.21 6,025,304.35 542,332.15 1.31 8,230.25 2_MWD+IFR2+MS+Sag(2) 11,144.00 87.85 127.41 4,054.30 3,995.37 -2,678.82 8,280.53 6,025,249.10 542,405.71 1.01 8,322.19 2_MWD+IFR2+MS+Sag(2) 11,240.68 87.91 127.34 4,057.88 3,998.95 -2,737.47 8,357.31 6,025,190.82 542,482.75 0.10 8,418.72 2_MWD+IFR2+MS+Sag(2) 11,335.09 88.10 128.17 4,061.16 4,002.23 -2,795.24 8,431.91 6,025,133.39 542,557.61 0.90 8,512.96 2_MWD+IFR2+MS+Sag(2) 11,426.89 88.78 128.44 4,063.66 4,004.73 -2,852.12 8,503.92 6,025,076.85 542,629.87 0.80 8,604.56 2_MWD+IFR2+MS+Sag(2) 11,523.56 90.01 128.71 4,064.68 4,005.75 -2,912.39 8,579.49 6,025,016.93 542,705.71 1.30 8,701.03 2_MWD+IFR2+MS+Sag(2) 11,617.45 89.58 127.61 4,065.02 4,006.09 -2,970.40 8,653.31 6,024,959.27 542,779.79 1.26 8,794.77 2_MWD+IFR2+MS+Sag(2) 11,713.11 87.53 126.05 4,067.43 4,008.50 -3,027.72 8,729.85 6,024,902.30 542,856.58 2.69 8,890.34 2_MWD+IFR2+MS+Sag(2) 11,805.67 88.47 125.24 4,070.66 4,011.73 -3,081.62 8,805.02 6,024,848.75 542,931.99 1.34 8,982.84 2_MWD+IFR2+MS+Sag(2) 11,899.13 87.10 124.79 4,074.27 4,015.34 -3,135.21 8,881.50 6,024,795.52 543,008.71 1.54 9,076.22 2_MWD+IFR2+MS+Sag(2) 11,992.86 86.73 125.42 4,079.32 4,020.39 -3,189.03 8,958.07 6,024,742.05 543,085.52 0.78 9,169.82 2_MWD+IFR2+MS+Sag (2) 12,087.77 86.36 125.99 4,085.04 4,026.11 -3,244.32 9,035.00 6,024,687.12 543,162.69 0.72 9,264.54 2_MWD+IFR2+MS+Sag (2) 12,182.75 88.35 127.78 4,089.42 4,030.49 -3,301.27 9,110.88 6,024,630.53 543,238.83 2.82 9,359.36 2_MWD+IFR2+MS+Sag(2) 12,276.77 91.87 130.12 4,089.24 4,030.31 -3,360.36 9,183.98 6,024,571.78 543,312.19 4.50 9,453.13 2_MWD+IFR2+MS+Sag(2) 12,287.00 91.88 130.05 4,088.90 4,029.97 -3,366.94 9,191.80 6,024,565.24 543,320.04 0.69 9,463.31 2 MWD+IFR2+MS+Sag(3) 1/142019 6:41:44PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10 MPU M-10PB2 MPU M-10PB2 Local Co-ordinate Reference: Well MPU K10 TVD Reference: M-10 Actual RKB @ 58.93usft MD Reference: M-10 Actual RKB @ 58.93usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map vertical MD Inc Azi TVD TVDSS +NI -S +EI -W Northing Easting DLS Section (usft) V) (1) (usft) (usft) (usft) (usft) (ft) (ft) ('1100') (ft) Survey Tool Name 12,372.77 88.71 129.63 4,088.46 4,029.53 -3,421.88 9,257.65 6,024,510.60 543,386.14 3.73 9,548.76 2_MWD+IFR2+MS+Sag (3) 12,466.98 87.29 127.84 4,091.75 4,032.82 -3,480.79 9,331.09 6,024,452.04 543,459.84 2.42 9,642.70 2_MWD+IFR2+MS+Sag (3) 12,562.21 86.86 127.31 4,096.61 4,037.68 -3,538.79 9,406.47 6,024,394.39 543,535.47 0.72 9,737.70 2_MWD+IFR2+MS+Sag (3) 12,656.89 87.11 126.26 4,101.59 4,042.66 -3,595.40 9,482.19 6,024,338.13 543,611.44 1.14 9,832.20 2_MWD+IFR2+MS+Sag(3) 12,750.57 87.29 124.00 4,106.17 4,047.24 -3,649.24 9,558.71 6,024,284.65 543,688.20 2.42 9,925.76 2_MWD+IFR2+MS+Sag(3) 12,820.00 87.29 124.00 4,109.45 4,050.52 -3,688.02 9,616.20 6,024,246.14 543,745.87 0.00 9,995.10 PROJECTED to TD Checked By: Chelsea Wright. %� Approved By: Mitch Laird -- Date: 01-14-2019 1/142019 6:41:44PM Page 6 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10PB3 MPU M-10PB3 500292361772 Sperry Drilling Definitive Survey Report 25 January, 2019 C63 S`Llas' a�� HALLIBURTON 5porry Drilling Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: MPU M-10PB3 Design: MPU M-10PB3 Halliburton Definitive Survey Report Local Co-ordinate Reference: Well MPU M-10 TVD Reference: M-10 Actual RKB @ 58.93usft MD Reference: M-10 Actual RKB @ 58.93usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA >roject Milne Point, ACT, MILNE POINT dap System: US Slate Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point dap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU M-10 Well Position +N/S 0.00 usft Northing: 6,027,889.65 usft Latitude: 70.487 +EI -W 0.00 usft Easting: 534,113.80 usft Longitude: -149.721 Position Uncertainty 0.00 usft Wellhead Elevation: 24.90 usft Ground Level: 24.90 usft Wellbore MPU M-10PB3 Azi TVD TVDSS +NIS Magnetics Model Name Sample Date Declination Section Dip Angle Field Strength V) (1) (usft) (usft) (usft) (nT) (ft) BGGM2018 1/7/2019 (ft) Survey Tool Name 16.83 80.97 57,439.56345820 Design MPU M-10PB3 -24.90 0.00 0.00 6,027,889.65 Audit Notes: 0.00 0.00 UNDEFINED 170.94 0.38 142.01 Version: 1.0 Phase: ACTUAL Tie On Depth: 12,182.75 Vertical Section: 0.28 Depth From (TVD) +N/ -S +E/ -W Direction 227.67 168.74 (usft) (usft) (usft) (1) 0.09 0.77 2_MWD+IFR2+MS+Sag(1) 34.03 0.00 0.00 124.94 Survey Program Date 1/16/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 170.94 6,619.48 MPU M-10PB1 MWD+IFR2+MS+Sag(1)2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 12/19/2018 6,710.78 12,182.75 MPU M-10PB1 MWD+IFR+MS+Sag (2) (2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis+ sa 01/0312019 12,210.00 15,336.15 MPU M-10PB3 MWD+IFR2+MS+Sag (M 2_MWD+IFR2+MS+Sag AW31\415: IIFR dec & multi -station analysis +sa 01/07/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) V) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 34.03 0.00 0.00 34.03 -24.90 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 UNDEFINED 170.94 0.38 142.01 170.94 112.01 -0.36 0.28 6,027,889.29 534,114.08 0.28 0.43 2_MWD+IFR2+MS+Sag (1) 227.67 0.33 142.01 227.67 168.74 -0.63 0.50 6,027,889.02 534,114.30 0.09 0.77 2_MWD+IFR2+MS+Sag(1) 322.96 0.92 100.77 322.95 264.02 -0.99 1.42 6,027,888.66 534,115.22 0.74 1.73 2_MWD+IFR2+MS+Sag(1) 416.60 3.07 37.93 416.54 357.61 0.84 3.70 6,027,890.51 534,117.49 2.96 2.55 2 MWD+IFR2+MS+Sag(1) 510.06 5.78 30.62 509.71 450.78 6.87 7.63 6,027,896.55 534,121.40 2.96 2.32 2_MWD+IFR2+MS+Sag(1) 603.55 8.51 42.95 602.47 543.54 15.99 14.75 6,027,905.70 534,128.47 3.33 2.93 2 MWD+IFR2+MS+Sag(1) 696.41 11.70 55.78 693.89 634.96 26.31 27.22 6,027,916.09 534,140.89 4.18 7.24 2_MWD+IFR2+MS+Sag(1) 790.33 12.74 69.53 785.70 726.77 35.29 44.80 6,027,925.14 534,158.43 3.28 16.51 2_MWD+IFR2+MS+Sag(1) 884.81 16.79 76.07 877.05 818.12 42.22 67.81 6,027,932.18 534,181.41 4.63 31.41 2_MWD+IFR2+MS+Sag(1) 980.75 19.90 78.90 968.10 909.17 48.71 97.29 6,027,938.80 534,210.86 3.37 51.86 2_MWD+IFR2+MS+Sag(1) 1,074.92 24.60 80.13 1,055.24 996.31 55.15 132.35 6,027,945.41 534,245.88 5.02 76.91 2_MWD+IFR2+MS+Sag(1) 1252019 11:25.50AM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-10 Project: Milne Point TVD Reference: M-10 Actual RKB @ 58.93usft She: M Pt Moose Pad MD Reference: M-10 Actual RKB @ 58.93usft Well: MPU M-10 North Reference: True Wellbore: MPU M-10PB3 Survey Calculation Method: Minimum Curvature Design: MPU M-10PB3 Database: NORTH US+CANADA Survey Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing (use) (1) (1) (usft) (usft) (usft) (usft) (ft) 1,168.88 29.58 79.82 1,138.86 1,079.93 62.61 174.47 6,027,953.05 1,263.59 33.20 79.91 1,219.70 1,160.77 71.29 223.02 6,027,961.95 1,357.77 34.99 80.99 1,297.69 1,238.76 80.03 275.08 6,027,970.94 1,452.25 36.90 82.00 1,374.17 1,315.24 88.23 329.93 6,027,979.38 1,546.61 42.91 82.25 1,446.52 1,387.59 96.51 389.87 6,027,987.93 1,641.35 44.25 82.77 1,515.15 1,456.22 105.02 454.62 6,027,996.74 1,735.11 47.49 82.20 1,580.43 1,521.50 113.83 521.33 6,028,005.85 1,828.09 52.45 82.90 1,640.21 1,581.28 123.04 591.90 6,028,015.39 1,923.77 53.56 85.11 1,697.79 1,638.86 131.01 667.90 6,028,023.71 2,018.36 53.75 84.02 1,753.85 1,694.92 138.23 743.74 6,028,031.27 2,112.50 55.83 84.03 1,808.13 1,749.20 146.23 820.23 6,028,039.63 2,206.42 55.37 85.07 1,861.19 1,802.26 153.59 897.38 6,028,047.34 2,301.32 55.95 85.50 1,914.72 1,855.79 160.03 975.47 6,028,054.14 2,395.66 55.16 85.09 1,968.08 1,909.15 166.41 1,053.01 6,028,060.87 2,490.05 55.11 84.88 2,022.04 1,963.11 173.18 1,130.16 6,028,068.00 2,584.59 54.94 85.05 2,076.23 2,017.30 179.98 1,207.32 6,028,075.15 2,678.80 54.32 85.48 2,130.77 2,071.84 186.32 1,283.88 6,028,081.84 2,772.66 53.54 86.76 2,186.03 2,127.10 191.46 1,359.57 6,028,087.33 2,866.86 53.54 87.13 2,242.01 2,183.08 195.50 1,435.23 6,028,091.71 2,961.80 55.61 85.32 2,297.04 2,238.11 200.61 1,512.41 6,028,097.17 3,056.37 55.34 85.58 2,350.64 2,291.71 206.79 1,590.08 6,028,103.71 3,150.85 55.06 85.44 2,404.56 2,345.63 212.86 1,667.42 6,028,110.14 3,245.49 56.28 85.15 2,457.93 2,399.00 219.28 1,745.31 6,028,116.91 3,339.53 55.32 82.43 2,510.80 2,451.87 227.68 1,822.62 6,028,125.66 3,434.32 52.70 83.06 2,566.50 2,507.57 237.37 1,898.70 6,028,135.70 3,528.95 55.54 83.16 2,621.95 2,563.02 246.56 1,974.81 6,028,145.25 3,622.79 55.21 83.76 2,675.27 2,616.34 255.36 2,051.53 6,028,154.39 3,717.12 55.62 84.06 2,728.82 2,669.89 263.60 2,128.75 6,028,162.98 3,811.72 56.26 84.55 2,781.80 2,722.87 271.37 2,206.73 6,028,171.12 3,906.17 56.78 84.34 2,833.90 2,774.97 279.00 2,285.14 6,028,179.10 4,000.61 56.23 84.29 2,886.02 2,827.09 286.80 2,363.51 6,028,187.26 4,094.86 57.19 84.76 2,937.75 2,878.82 294.32 2,441.93 6,028,195.14 4,188.60 57.20 84.54 2,988.54 2,929.61 301.66 2,520.38 6,028,202.84 4,282.89 54.71 85.79 3,041.32 2,982.39 308.26 2,598.22 6,028,209.79 4,377.33 53.48 87.26 3,096.71 3,037.78 312.90 2,674.57 6,028,214.79 4,470.79 52.59 84.94 3,152.91 3,093.98 317.97 2,749.06 6,028,220.20 4,565.71 54.33 85.03 3,209.42 3,150.49 324.64 2,825.03 6,028,227.21 4,660.04 53.38 84.52 3,265.06 3,206.13 331.57 2,900.89 6,028,234.49 4,755.01 54.57 84.42 3,320.92 3,261.99 338.98 2,977.34 6,028,242.25 4,848.09 55.02 84.74 3,374.58 3,315.65 346.16 3,053.05 6,028,249.77 1252019 11:25:50AM Page 3 Map Easting DLS (ft) (°7100') 534,287.96 5.30 534,336.47 3.82 534,388.49 2.01 534,443.29 2.12 534,503.18 6.37 534,567.89 1.46 534,634.55 3.48 534,705.07 5.37 534,781.02 2.18 534,856.82 0.95 534,933.27 2.21 535,010.37 1.04 535,088.43 0.72 535,165.93 0.91 535,243.04 0.19 535,320.17 0.23 535,396.69 0.76 535,472.35 1.38 535,547.97 0.32 535,625.13 2.68 535,702.76 0.36 535,780.07 0.32 535,857.92 1.31 535,935.18 2.60 536,011.20 2.82 536,087.26 3.00 536,163.93 0.63 536,241.11 0.51 536,319.05 0.80 536,397.41 0.58 536,475.74 0.58 536,554.12 1.10 536,632.52 0.20 536,710.32 2.86 536,786.64 1.81 536,861.11 2.20 536,937.03 1.83 537,012.85 1.10 537,089.26 1.26 537,164.93 0.56 Vertical Section (ft) Survey Tool Name 107.16 2_MWD+IFR2+MS+Sag(1) 142.00 2_MWD+IFR2+MS+Sag(1) 179.66 2_MWD+IFR2+MS+Sag(1) 219.93 2_MWD+IFR2+MS+Sag (1) 264.32 2_MWD+IFR2+MS+Sag(1) 312.53 2_MWD+IFR2+MS+Sag(1) 362.17 2_MWD+IFR2+MS+Sag(1) 414.75 2_MWD+IFR2+MS+Sag(1) 472.48 2_MWD+IFR2+MS+Sag (1) 530.52 2_MWD+IFR2+MS+Sag(1) 588.64 2_MWD+IFR2+MS+Sag (1) 647.66 2_MWD+IFR2+MS+Sag(1) 707.99 2_MWD+IFR2+MS+Sag(1) 767.90 2_MWD+IFR2+MS+Sag(1) 827.26 2_MWD+IFR2+MS+Sag(1) 886.63 2_MWD+IFR2+MS+Sag(1) 945.75 2_MWD+IFR2+MS+Sag(1) 1,004.86 2_MWD+IFR2+MS+Sag(1) 1,064.56 2_MWD+IFR2+MS+Sag(1) 1,124.91 2_MWD+IFR2+MS+Sag (1) 1,185.04 2_MWD+IFR2+MS+Sag(1) 1,244.96 2_MWD+IFR2+MS+Sag (1) 1,305.14 2_MWD+IFR2+MS+Sag(1) 1,363.71 2_MWD+IFR2+MS+Sag (1) 1,420.52 2_MWD+IFR2+MS+Sag(1) 1,477.64 2_MWD+IFR2+MS+Sag(1) 1,535.49 2_MWD+IFR2+MS+Sag(1) 1,594.08 2_MWD+IFR2+MS+Sag(1) 1,653.55 2_MWD+IFR2+MS+Sag(1) 1,713.46 2_MWD+IFR2+MS+Sag(1) 1,773.24 2 MWD+IFR2+MS+Sag(1) 1,833.22 2_MWD+IFR2+MS+Sag(1) 1,893.32 2_MWD+IFR2+MS+Sag(1) 1,953.35 2_MWD+IFR2+MS+Sag(1) 2,013.28 2_MWD+IFR2+MS+Sag(1) 2,071.44 2_MWD+IFR2+MS+Sag(1) 2,129.90 2_MWD+IFR2+MS+Sag(1) 2,188.11 2_MWD+IFR2+MS+Sag (1) 2,246.54 2_MWD+IFR2+MS+Sag(1) 2,304.49 2_MWD+IFR2+MS+Sag(1) COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10 MPU M-10PB3 MPU M-10PB3 Local Coordinate Reference: Well MPU M-10 TVD Reference: M-10 Actual RKB @ 58.93usft MD Reference: M-10 Actual RKB @ 58.93usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (`) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 4,942.85 56.65 85.24 3,427.79 3,368.86 353.00 3,131.16 6,028,256.98 537,243.00 1.77 2,364.60 2_MWD+IFR2+MS+Sag(1) 5,037.22 55.01 83.92 3,480.79 3,421.86 360.37 3,208.88 6,028,264.70 537,320.68 2.09 2,424.10 2_MWD+IFR2+MS+Sag(1) 5,131.28 55.40 84.84 3,534.47 3,475.54 367.93 3,285.75 6,028,272.61 537,397.51 0.90 2,482.78 2_MWD+IFR2+MS+Sag(1) 5,226.52 57.90 89.67 3,586.84 3,527.91 371.69 3,365.18 6,028,276.74 537,476.90 4.98 2,545.74 2_MWD+IFR2+MS+Sag(1) 5,321.09 57.71 94.91 3,637.26 3,578.33 368.50 3,445.10 6,028,273.91 537,556.83 4.69 2,613.06 2_MWD+IFR2+MS+Sag(1) 5,415.62 58.70 97.70 3,687.07 3,628.14 359.67 3,524.94 6,028,265.45 537,636.71 2.72 2,683.59 2_MWD+IFR2+MS+Sag(1) 5,507.35 60.77 101.27 3,733.31 3,674.38 346.59 3,603.06 6,028,252.73 537,714.87 4.05 2,755.12 2_MWD+IFR2+MS+Sag(1) 5,603.63 65.21 105.15 3,777.04 3,718.11 326.94 3,686.51 6,028,233.46 537,798.41 5.84 2,834.78 2_MWD+IFR2+MS+Sag(1) 5,697.88 66.83 106.69 3,815.34 3,756.41 303.32 3,769.31 6,028,210.22 537,881.31 2.28 2,916.19 2_MWD+IFR2+MS+Sag(1) 5,792.62 69.52 109.49 3,850.57 3,791.64 275.99 3,852.89 6,028,183.28 537,965.01 3.95 3,000.35 2_MWD+IFR2+MS+Sag(1) 5,887.15 72.45 111.97 3,881.37 3,822.44 244.35 3,936.45 6,028,152.03 538,048.70 3.97 3,086.97 2_MWD+IFR2+MS+Sag(1) 5,980.93 74.91 113.39 3,907.72 3,848.79 209.64 4,019.48 6,028,117.71 538,131.88 3.00 3,174.92 2 MWD+IFR2+MS+Sag(1) 6,075.24 81.07 116.75 3,927.34 3,868.41 170.55 4,102.97 6,028,079.00 538,215.54 7.40 3,265.74 2_MWD+IFR2+MS+Sag(1) 6,170.20 82.69 118.19 3,940.75 3,881.82 127.19 4,186.38 6,028,036.03 538,299.14 2.27 3,358.95 2_MWD+IFR2+MS+Sag(1) 6,263.30 81.71 120.62 3,953.39 3,894.46 81.91 4,266.73 6,027,991.12 538,379.68 2.79 3,450.75 2_MWD+IFR2+MS+Sag(1) 6,355.51 82.27 122.51 3,966.24 3,907.31 34.11 4,344.52 6,027,943.68 538,457.69 2.12 3,541.90 2_MWD+IFR2+MS+Sag(1) 6,450.48 81.41 122.29 3,979.72 3,920.79 -16.26 4,423.90 6,027,893.68 538,537.29 0.93 3,635.81 2_MWD+IFR2+MS+Sag (1) 6,547.05 84.99 123.73 3,991.15 3,932.22 -68.49 4,504.29 6,027,841.82 538,617.91 3.99 3,731.63 2_MWD+IFR2+MS+Sag (1) 6,619.48 86.01 124.83 3,996.83 3,937.90 -109.16 4,563.95 6,027,801.43 538,677.75 2.07 3,803.83 2 MWD+IFR2+MS+Sag(1) 6,710.78 87.54 122.43 4,001.97 3,943.04 -159.64 4,639.84 6,027,751.31 538,753.87 3.11 3,894.95 2_MWD+IFR2+MS+Sag (2) 6,803.73 88.04 122.44 4,005.56 3,946.63 -209.46 4,718.23 6,027,701.86 538,832.48 0.54 3,987.74 2_MWD+IFR2+MS+Sag (2) 6,899.01 88.53 123.08 4,008.41 3,949.48 -260.99 4,798.32 6,027,650.70 538,912.80 0.85 4,082.91 2_MWD+IFR2+MS+Sag (2) 6,993.63 90.14 123.89 4,009.51 3,950.58 -313.19 4,877.23 6,027,598.87 538,991.93 1.90 4,177.49 2_MWD+IFR2+MS+Sag (2) 7,088.02 88.83 124.21 4,010.35 3,951.42 -366.04 4,955.43 6,027,546.38 539,070.37 1.43 4,271.86 2_MWD+IFR2+MS+Sag (2) 7,183.49 89.27 126.35 4,011.94 3,953.01 421.17 5,033.35 6,027,491.62 539,148.53 2.29 4,367.31 2_MWD+IFR2+MS+Sag (2) 7,277.24 88.96 126.41 4,013.39 3,954.46 -476.77 5,108.82 6,027,436.37 539,224.25 0.34 4,461.02 2_MWD+IFR2+MS+Sag (2) 7,368.80 88.34 125.45 4,015.54 3,956.61 -530.48 5,182.94 6,027,383.00 539,298.61 1.25 4,552.54 2_MWD+IFR2+MS+Sag (2) 7,465.47 89.15 128.18 4,017.66 3,958.73 -588.39 5,260.30 6,027,325.46 539,376.23 2.95 4,649.12 2_MWD+IFR2+MS+Sag (2) 7,560.90 89.27 131.55 4,018.98 3,960.05 -649.54 5,333.53 6,027,264.64 539,449.73 3.53 4,744.18 2_MWD+IFR2+MS+Sag (2) 7,655.20 88.96 131.56 4,020.43 3,961.50 -712.09 5,404.09 6,027,202.43 539,520.57 0.33 4,837.84 2_MWD+IFR2+MS+Sag(2) 7,749.31 87.10 130.56 4,023.67 3,964.74 -773.86 5,475.01 6,027,140.98 539,591.76 2.24 4,931.35 2_MWD+IFR2+MS+Sag(2) 7,843.56 86.80 128.35 4,028.68 3,969.75 -833.67 5,547.67 6,027,081.52 539,664.69 2.36 5,025.17 2_MWD+IFR2+MS+Sag(2) 7,937.86 87.17 126.18 4,033.64 3,974.71 -890.68 5,622.61 6,027,024.85 539,739.88 2.33 5,119.26 2_MWD+IFR2+MS+Sag(2) 8,032.41 88.22 125.59 4,037.45 3,978.52 -946.06 5,699.15 6,026,969.84 539,816.67 1.27 5,213.72 2_MWD+IFR2+MS+Sag(2) 8,126.73 89.76 124.84 4,039.11 3,980.18 -1,000.44 5,776.20 6,026,915.82 539,893.95 1.82 5,308.02 2_MWD+IFR2+MS+Sag(2) 8,218.97 88.53 122.97 4,040.49 3,981.56 -1,051.88 5,852.74 6,026,864.73 539,970.72 2.43 5,400.23 2_MWD+IFR2+MS+Sag(2) 8,315.28 88.90 122.36 4,042.65 3,983.72 -1,103.85 5,933.80 6,026,813.14 540,052.01 0.74 5,496.44 2_MWD+IFR2+MS+Sag(2) 8,410.15 88.84 121.93 4,044.52 3,985.59 -1,154.32 6,014.11 6,026,763.04 540,132.54 0.46 5,591.17 2_MWD+IFR2+MS+Sag(2) 8,504.74 91.37 124.02 4,044.34 3,985.41 -1,205.79 6,093.45 6,026,711.94 540,212.11 3.47 5,685.70 2_MWD+IFR2+MS+Sag(2) 8,599.26 90.07 123.61 4,043.16 3,984.23 -1,258.39 6,171.97 6,026,659.71 540,290.87 1.44 5,780.19 2_MWD+IFR2+MS+Sag (2) 1!15/1019 11:25:50AM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-10 Project: Milne Paint TVD Reference: M-10 Actual RKB @ 58.93usft Site: M Pt Moose Pad MD Reference: M-10 Actual RKB @ 58.93usfl Well: MPU M-10 North Reference: True Wellbore: MPU M-10PB3 Survey Calculation Method: Minimum Curvature Design: MPU M-10PB3 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) r) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,693.57 89.70 124.19 4,043.34 3,984.41 AX0.99 6,250.25 6,026,607.47 540,369.38 0.73 5,874.48 2_MWD+IFR2+MS+Sa9(2) 8,786.66 90.63 124.64 4,043.08 3,984.15 -1,363.60 6,327.04 6,026,555.22 540,446.41 1.11 5,967.57 2_MWD+IFR2+MS+Sag (2) 8,881.35 90.01 124.08 4,042.55 3,983.62 -1,417.04 6,405.21 6,026,502.14 540,524.81 0.88 6,062.25 2_MWD+IFR2+MS+Sag (2) 8,973.62 89.14 123.99 4,043.23 3,984.30 -1,468.68 6,481.67 6,026,450.86 540,601.50 0.95 6,154.50 2_MWD+IFR2+MS+Sag (2) 9,069.68 89.52 125.49 4,044.36 3,985.43 -1,523.42 6,560.60 6,026,396.49 540,680.67 1.61 6,250.55 2_MWD+IFR2+MS+Sag (2) 9,163.54 91.00 125.56 4,043.93 3,985.00 -1,577.95 6,636.98 6,026,342.31 540,757.30 1.58 6,344.41 2_MWD+IFR2+MS+Sag(2) 9,255.80 92.73 125.17 4,040.93 3,982.00 .1,631.32 6,712.18 6,026,289.29 540,832.73 1.92 6,436.61 2_MWD+IFR2+MS+Sag(2) 9,350.05 91.80 125.05 4,037.20 3,978.27 -1,685.49 6,789.22 6,026,235.49 540,910.01 0.99 6,530.79 2_MWD+IFR2+MS+Sag(2) 9,446.02 91.80 125.44 4,034.19 3,975.26 -1,740.84 6,867.56 6,026,180.50 540,988.59 0.41 6,626.71 2_MWD+IFR2+MS+Sag(2) 9,540.33 90.75 125.43 4,032.09 3,973.16 -1,795.50 6,944.38 6,026,126.19 541,065.66 1.11 6,720.99 2_MWD+IFR2+MS+Sag(2) 9,634.89 91.24 125.88 4,030.45 3,971.52 -1,850.62 7,021.20 6,026,071.44 541,142.72 0.70 6,815.53 2_MWD+IFR2+MS+Sag(2) 9,729.57 89.76 125.42 4,029.62 3,970.69 -1,905.79 7,098.13 6,026,016.62 541,219.90 1.64 6,910.19 2_MWD+IFR2+MS+Sag(2) 9,824.36 90.38 124.26 4,029.51 3,970.58 -1,959.95 7,175.93 6,025,962.83 541,297.93 1.39 7,004.98 2_MWD+IFR2+MS+Sag (2) 9,918.91 89.45 123.39 4,029.65 3,970.72 -2,012.58 7,254.47 6,025,910.57 541,376.71 1.35 7,099.51 2_MWD+IFR2+MS+Sag (2) 10,013.67 88.65 121.18 4,031.22 3,972.29 -2,063.18 7,334.57 6,025,860.34 541,457.03 2.48 7,194.15 2_MWD+IFR2+MS+Sag (2) 10,108.03 89.27 120.03 4,032.93 3,974.00 -2,111.21 7,415.77 6,025,812.68 541,538.44 1.38 7,288.22 2_MWD+IFR2+MS+Sag (2) 10,202.55 89.76 120.19 4,033.73 3,974.80 -2,158.63 7,497.53 6,025,765.65 541,620.41 0.55 7,382.40 2_MWD+IFR2+MS+Sag (2) 10,295.06 90.26 119.63 4,033.71 3,974.78 -2,204.76 7,577.72 6,025,719.89 541,700.80 0.81 7,474.55 2_MWD+IFR2+MS+Sag (2) 10,391.23 90.20 119.76 4,033.33 3,974.40 -2,252.40 7,661.26 6,025,672.64 541,784.55 0.15 7,570.32 2_MWD+IFR2+MS+Sa9 (2) 10,485.18 90.13 121.84 4,033.06 3,974.13 -2,300.50 7,741.95 6,025,624.91 541,865.46 2.22 7,664.02 2_MWD+IFR2+MS+Sag (2) 10,579.42 89.58 123.48 4,033.30 3,974.37 -2,351.35 7,821.29 6,025,574.43 541,945.02 1.84 7,758.18 2_MWD+IFR2+MS+Sag (2) 10,672.41 89.21 124.61 4,034.28 3,975.35 -2,403.41 7,898.33 6,025,522.73 542,022.29 1.28 7,851.15 2_MWD+IFR2+MS+Sag (2) 10,768.36 87.60 124.86 4,036.95 3,978.02 -2,458.06 7,977.15 6,025,468.45 542,101.36 1.70 7,947.06 2_MWD+IFR2+MS+Sag (2) 10,862.22 87.72 125.43 4,040.78 3,981.85 -2,512.04 8,053.84 6,025,414.82 542,178.28 0.62 8,040.84 2_MWD+IFR2+MS+Sag(2) 10,957.32 86.92 125.70 4,045.23 3,986.30 -2,567.29 8,131.11 6,025,359.93 542,255.80 0.89 8,135.83 2_MWD+IFR2+MS+Sag(2) 11,051.90 87.05 126.93 4,050.20 3,991.27 -2,623.23 8,207.21 6,025,304.35 542,332.15 1.31 8,230.25 2_MWD+IFR2+MS+Sag(2) 11,144.00 87.85 127.41 4,054.30 3,995.37 -2,678.82 8,280.53 6,025,249.10 542,405.71 1.01 8,322.19 2_MWD+IFR2+MS+Sag(2) 11,240.68 87.91 127.34 4,057.88 3,998.95 -2,737.47 8,357.31 6,025,190.82 542,482.75 0.10 8,418.72 2_MWD+IFR2+MS+Sag(2) 11,335.09 88.10 128.17 4,061.16 4,002.23 -2,795.24 8,431.91 6,025,133.39 542,557.61 0.90 8,512.96 2_MWD+IFR2+MS+Sag(2) 11,426.89 88.78 128.44 4,063.66 4,004.73 -2,852.12 8,503.92 6,025,076.85 542,629.87 0.80 8,604.56 2_MWD+IFR2+MS+Sag(2) 11,523.56 90.01 128.71 4,064.68 4,005.75 -2,912.39 8,579.49 6,025,016.93 542,705.71 1.30 8,701.03 2_MWD+IFR2+MS+Sa9(2) 11,617.45 89.58 127.61 4,065.02 4,006.09 -2,970.40 8,653.31 6,024,959.27 542,779.79 1.26 8,794.77 2_MWD+IFR2+MS+Sag(2) 11,713.11 87.53 126.05 4,067.43 4,008.50 -3,027.72 8,729.85 6,024,902.30 542,856.58 2.69 8,890.34 2_MWD+IFR2+MS+Sag (2) 11,805.67 88.47 125.24 4,070.66 4,011.73 -3,081.62 8,805.02 6,024,848.75 542,931.99 1.34 8,982.84 2_MWD+IFR2+MS+Sa9 (2) 11,899.13 87.10 124.79 4,074.27 4,015.34 -3,135.21 8,881.50 6,024,795.52 543,008.71 1.54 9,076.22 2_MWD+IFR2+MS+Sag(2) 11,992.86 86.73 125.42 4,079.32 4,020.39 -3,189.03 8,958.07 6,024,742.05 543,085.52 0.78 9,169.82 2_MWD+IFR2+MS+Sag(2) 12,087.77 86.36 125.99 4,085.04 4,026.11 -3,244.32 9,035.00 6,024,687.12 543,162.69 0.72 9,264.54 2_MWD+IFR2+MS+Sag (2) 12,182.75 88.35 127.78 4,089.42 4,030.49 -3,301.27 9,110.88 6,024,630.53 543,238.83 2.82 9,359.36 2_MWD+IFR2+MS+Sag (2) 12,210.00 89.37 128.46 4,089.96 4,031.03 -3,318.08 9,132.31 6,024,613.81 543,260.33 4.50 9,386.56 2_MWD+IFR2+MS+Sag(3) 12,278.03 87.97 126.39 4,091.54 4,032.61 -3,359.41 9,186.32 6,024,572.74 543,314.53 3.67 9,454.50 2_MWD+IFR2+MS+Sag(3) 1252019 11:25:50AM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU M-10 Project: Milne Point TVD Reference: M-10 Actual RKB @ 58.93usft Site: M Pt Moose Pad MD Reference: M-10 Actual RKB @ 58.93usft Well: MPU M-10 North Reference: True Wellbore: MPU M-10PB3 Survey Calculation Method: Minimum Curvature Design: MPU M-10PB3 Database: NORTH US + CANADA Survey Map Map Vertical MD (usft) Inc (°) Azi (°) TVD (usft) TVDSS (usft) +N/ -S (usft) +E/ -W (usft) Northing (ft) Easting DLS (ft) (°1100') Section (ft) Survey Tool Name 12,373.44 92.12 126.41 4,091.47 4,032.54 -3,416.02 9,263.10 6,024,516.49 543,391.55 4.35 9,549.86 2_MWD+IFR2+MS+Sag(3) 12,467.89 92.67 125.71 4,087.52 4,028.59 -3,471.57 9,339.38 6,024,461.30 543,468.09 0.94 9,644.21 2_MWD+IFR2+MS+Sag(3) 12,562.31 92.79 128.84 4,083.02 4,024.09 -3,527.37 9,415.42 6,024,405.85 543,544.37 1.20 9,738.50 2_MWD+IFR2+MS+Sag(3) 12,657.32 92.11 126.09 4,078.96 4,020.03 -3,583.78 9,491.76 6,024,349.79 543,620.96 1.07 9,833.38 2_MWD+IFR2+MS+Sag(3) 12,750.92 91.80 124.73 4,075.77 4,016.84 -3,637.98 9,568.00 6,024,295.95 543,697.44 1.49 9,926.92 2_MWD+IFR2+MS+Sag(3) 12,846.10 91.18 123.12 4,073.29 4,014.36 -3,691.08 9,646.94 6,024,243.22 543,776.62 1.81 10,022.05 2_MWD+IFR2+MS+Sag(3) 12,940.23 91.62 121.87 4,070.99 4,012.06 -3,741.64 9,726.31 6,024,193.03 543,856.21 1.41 10,116.07 2_MWD+IFR2+MS+Sag(3) 13,034.48 91.80 120.95 4,068.18 4,009.25 -3,790.73 9,806.71 6,024,144.31 543,936.83 0.99 10,210.10 2_MWD+IFR2+MS+Sag(3) 13,128.04 89.51 120.51 4,067.11 4,008.18 -3,838.53 9,887.12 6,024,096.88 544,017.45 2.49 10,303.39 2_MWD+IFR2+MS+Sag(3) 13,222.66 87.91 120.71 4,069.24 4,010.31 -3,886.70 9,968.54 6,024,049.10 544,099.07 1.70 10,397.71 2_MWD+IFR2+MS+Sag(3) 13,316.53 89.02 121.82 4,071.76 4,012.83 -3,935.40 10,048.74 6,024,000.77 544,179.50 1.67 10,491.35 2_MWD+IFR2+MS+Sag(3) 13,410.85 90.13 122.45 4,072.45 4,013.52 -3,985.57 10,128.61 6,023,950.97 544,259.58 1.35 10,585.56 2_MWD+IFR2+MS+Sag(3) 13,505.32 90.13 122.30 4,072.24 4,013.31 -4,036.15 10,208.39 6,023,900.76 544,339.59 0.16 10,679.93 2_MWD+IFR2+MS+Sag(3) 13,599.61 89.82 122.88 4,072.28 4,013.35 .4,086.94 10,287.84 6,023,850.34 544,419.26 0.70 10,774.14 2_MWD+IFR2+MS+Sag(3) 13,694.31 90.20 124.44 4,072.27 4,013.34 -4,139.43 10,366.66 6,023,798.22 544,498.31 1.70 10,868.82 2_MWD+IFR2+MS+Sag(3) 13,788.19 89.89 126.05 4,072.19 4,013.26 -4,193.60 10,443.33 6,023,744.41 544,575.22 1.75 10,962.69 2_MWD+IFR2+MS+Sag(3) 13,882.36 87.66 126.47 4,074.20 4,015.27 -4,249.28 10,519.24 6,023,689.08 544,651.38 2.41 11,056.81 2_MWD+IFR2+MS+Sag(3) 13,977.64 86.43 125.36 4,079.12 4,020.19 .4,305.09 10,596.30 6,023,633.63 544,728.69 1.74 11,151.94 2_MWD+IFR2+MS+Sag (3) 14,068.15 87.11 126.86 4,084.22 4,025.29 -4,358.35 10,669.30 6,023,580.71 544,801.93 1.82 11,242.29 2_MWD+IFR2+MS+Sag(3) 14,164.54 88.78 127.70 4,087.67 4,028.74 -4,416.69 10,745.94 6,023,522.73 544,878.83 1.94 11,338.53 2_MWD+IFR2+MS+Sag (3) 14,258.80 90.63 127.01 4,088.16 4,029.23 -4,473.88 10,820.87 6,023,465.89 544,954.00 2.09 11,432.70 2_MWD+IFR2+MS+Sag(3) 14,353.81 90.01 126.21 4,087.63 4,028.70 4,530.54 10,897.13 6,023,409.58 545,030.52 1.07 11,527.67 2_MWD+IFR2+MS+Sag(3) 14,447.72 91.12 124.90 4,086.70 4,027.77 -4,585.14 10,973.52 6,023,355.34 545,107.16 1.83 11,621.57 2_MWD+IFR2+MS+Sag(3) 14,542.47 91.80 125.71 4,084.29 4,025.36 4,639.88 11,050.82 6,023,300.96 545,184.70 1.12 11,716.28 2_MWD+IFR2+MS+Sag(3) 14,637.74 92.17 126.58 4,080.99 4,022.06 4,696.04 11,127.71 6,023,245.16 545,261.83 0.99 11,811.47 2_MWD+IFR2+MS+Sag(3) 14,730.46 91.12 126.24 4,078.33 4,019.40 4,751.05 11,202.30 6,023,190.49 545,336.66 1.19 11,904.12 2_MWD+IFR2+MS+Sag(3) 14,825.32 91.25 125.80 4,076.36 4,017.43 4,806.83 11,279.00 6,023,135.08 545,413.62 0.48 11,998.95 2_MWD+IFR2+MS+Sag(3) 14,919.81 90.87 125.95 4,074.62 4,015.69 4,862.19 11,355.55 6,023,080.07 545,490.42 0.43 12,093.41 2_MWD+IFR2+MS+Sag(3) 15,014.36 90.93 125.22 4,073.13 4,014.20 4,917.20 11,432.44 6,023,025.42 545,567.54 0.77 12,187.94 2_MWD+IFR2+MS+Sag(3) 15,108.70 91.37 124.66 4,071.24 4,012.31 4,971.22 11,509.76 6,022,971.76 545,645.10 0.75 12,282.26 2_MWD+IFR2+MS+Sag(3) 15,202.59 91.86 124.68 4,068.59 4,009.66 -5,024.61 11,586.95 6,022,918.73 545,722.53 0.52 12,376.11 2_MWD+IFR2+MS+Sag(3) 15,297.44 91.00 125.01 4,066.22 4,007.29 5,078.78 11,664.76 6,022,864.92 545,800.58 0.97 12,470.93 2_MWD+IFR2+MS+Sag(3) 15,336.15 90.87 124.92 4,065.59 4,006.66 -5,100.97 11,696.48 6,022,842.89 545,832.40 0.41 12,509.63 2_MWD+IFR2+MS+Sag(3) 15,405.00 90.87 124.92 4,064.55 4,005.62 -5,140.37 11,752.93 6,022,803.74 545,889.02 0.00 12,578.48 PROJECTEDto TD °°""`�" Checked By: Chelsea Wrlght'�..,°.._.�,:.,m Approved By: Mitch Laird w Date: 1-25-2019 1/252019 11:25:50AM Page 6 COMPASS 5000.15 Build 91 Lease & Well No. County Hilcorp Energy Company CASING & CEMENTING REPORT MP M-10 Date Run 29 -Deo -18 State Alaska Sup, Yessak I Destined CASING RECORD Surface w TO 666000 Shoe Deoth: 6.650.18 PBTD: Csg Wt. On Hook: 250,000 Type Float Collar. Antelope No. His to Run: 20 Csg Wt, On Slips: 100,000 Type of Shoe: Antelope Casing Crew: Doyon Rotate Csg X Yes No Recip CSg X Yes_ No 30 FL Min. 9.3 PPG Fluid Description'. Spud Mud Liner hanger Info(Make del): Liner top Packers: Yes _No Liner hanger test pressure: Floats Held X Yes _ No Centralizer Placement 9-SAIN12-114" Centek centralizer placement (77 centralizer and 12 atop rings ran): 2 each w/4 stop rings on shoe pint. 1 each wgh 2 each stop rings on spacer joint, goat ooilarjoinl and baffle adapter joint. 1 each wt 1 stop ring each on pup joint above and below ESICC. leach on joints #5-26. Every otherjoint #2814. 1 on each joint #102-116. Every otherjoint #118-164. CEMENTING REPORT Shoe @ 6550 FC @ 6,567.94 ush (Spacer) Density(ppg) 10 Volume pumped(BBLs) I Slurry .. Edenda Cern Sacks: 525 Yield: uty(ppg) 12 Volume pumped(BBLs) 220 Mixing I Pumping Rate (bpm): Slurry J) 15.8 Volume pumped(BBLs) (Spacer) 400 Yield: Pumping Rate (bpm): Dens'dy(ppg) Rate(bpm): Volume: Casing (Or Liner) Debil Setting Depths its. Component Size Wt. Grace THD Make Length Bottom Top 1 Shoe 103/4 X Yes No Vol to Sun: 0 TXP Antelope 1.59 6,650.00 6,648.41 2 Casing 95/8 40.0 L-80 TXP Tenaris 79.16 6,648.41 6,569.25 1 Float Collar 103/4 TXP Halliburton 1.31 6,569.25 6,567.94 1 Casing 95/8 40.0 L-80 TXP Tenaris 39.76 6,567.94 6,528.18 1 Baffle Adapter 103/4 TXP Halliburton 1.49 6,528.18 6,526.69 103 Casing 95/8 40.0 L-80 TXP Tenaris 4,042.72 6,526.69 2,483.97 1 Casing Pup Joint 95/8 40.0 L-80 TXP 12.00 2,483.97 2,471.97 1 ESICP 103/4 TXP HES 11.90 2,471.97 21460A7 1 Casing Pup Joint 95/8 40.0 L-80 TXP 12.52 2,460.07 2,447.55 61 Casin 95/8 40.0 L-80 T XP Tenaris 2,397.62 2,447.55 49.93 I Cu[Casin Joint 95/8 40.0 L-80 TXP 18.81 49.93 31.12 Csg Wt. On Hook: 250,000 Type Float Collar. Antelope No. His to Run: 20 Csg Wt, On Slips: 100,000 Type of Shoe: Antelope Casing Crew: Doyon Rotate Csg X Yes No Recip CSg X Yes_ No 30 FL Min. 9.3 PPG Fluid Description'. Spud Mud Liner hanger Info(Make del): Liner top Packers: Yes _No Liner hanger test pressure: Floats Held X Yes _ No Centralizer Placement 9-SAIN12-114" Centek centralizer placement (77 centralizer and 12 atop rings ran): 2 each w/4 stop rings on shoe pint. 1 each wgh 2 each stop rings on spacer joint, goat ooilarjoinl and baffle adapter joint. 1 each wt 1 stop ring each on pup joint above and below ESICC. leach on joints #5-26. Every otherjoint #2814. 1 on each joint #102-116. Every otherjoint #118-164. CEMENTING REPORT Shoe @ 6550 FC @ 6,567.94 ush (Spacer) Density(ppg) 10 Volume pumped(BBLs) I Slurry .. Edenda Cern Sacks: 525 Yield: uty(ppg) 12 Volume pumped(BBLs) 220 Mixing I Pumping Rate (bpm): Slurry J) 15.8 Volume pumped(BBLs) (Spacer) 400 Yield: Pumping Rate (bpm): Stage Collar@ 2460.07 Type ESIPC Closure OK V 're0ush (Spacer) ypeClean Spacer Density(ppg) t0 Volume pumped(BBLs) I Pon L lead Sacks: 410 Yield. sity(ppg) 10.7 Volume pumped(BBLs) 316.25 Mising I Pumping Rate (bpm): Slurry I Premium Sacks: 270 Yield: sity(ppg) 15.8 Volume pumped(BBLs) 56 Mixing/ Pumping Rate(bpm)'. t Flush [Spacer) Dens'dy(ppg) Rate(bpm): Volume: lacement: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual I calculated): 488.84/494.1 (psi): 790 Pump used for disp: Rig 91 Bump Plug? X YesNo Bump press 12 ig Rotated? X Yes _No Reciprocated? X Yes _No % Retums during job 78.52 ant returns to surface? X No Spacer returns? X Yes No Vol to Sun: 0 _Yes ant In Place At: 20:05 Dale: 121312018 Estimatetl TOC 2,460 on Used To Determine TOC: Cement circulated out w surface Stage Collar@ 2460.07 Type ESIPC Closure OK V 're0ush (Spacer) ypeClean Spacer Density(ppg) t0 Volume pumped(BBLs) I Pon L lead Sacks: 410 Yield. sity(ppg) 10.7 Volume pumped(BBLs) 316.25 Mising I Pumping Rate (bpm): Slurry I Premium Sacks: 270 Yield: sity(ppg) 15.8 Volume pumped(BBLs) 56 Mixing/ Pumping Rate(bpm)'. t Flush [Spacer) Call returned to surface: OH volume Calculated: >. 394.35 Total Volume cmt Pumped: 139 Calculated cement left in wellbore: 535.25 ..t 71 OH volume adust 50561 Actual % Washout : 674.25 39 Density(ppg) Rate (bpm): Volume: lacement: Spud Mud Density (ppg) 9.3 Rate (bpm): 7 Volume (actual I calculated): 164.02/167. (psi): 520 Pump used for disp: Rig Bump Plug? X Yes -No Bump press 11 ig Rotaled? X No Reciprocated? X No % Returns during jab 100 _Yes ant returns to surface? X Yes _Yes Spacerretums? X Vas No Vol to Sud: 139 ant In Place At: 7:32 _No Oate, 12/312018 Estimated TOC: 32 od Used To Determine TOC: Returns w surface Call returned to surface: OH volume Calculated: >. 394.35 Total Volume cmt Pumped: 139 Calculated cement left in wellbore: 535.25 ..t 71 OH volume adust 50561 Actual % Washout : 674.25 39 I THE STAT) °fALASKA. GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-10 Permit to Drill Number: 218-165 Sundry Number: 319-078 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Pax: 907.276.7542 v✓ W w.aog cc. a loska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Z4--Z�-O' Daniel T. Seamount, Jr. Commissioner v DATED thisay of February, 2019. RBDMS"dR 0 5 1019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 90 AAC 25.280 FEB 2 0 2019 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: CT Fill Clean-out w/ N2 ❑� 2. Operator Name: 4. Current Well Class: . 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 218-165 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23617-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No 10 r MILNE PT UNIT M-10 9. Property Designation (ease Number): •. 10. Field/Pool(s): ADL025514, ADL388235, ADL025515 I MILNE POINTY SCHRADER BLUFF OIL ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): 15,082' 4,047' 15,082' 4,04T 1,800 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 106' 20" 106' 106' N/A N/A Surface 6,650' 9-5/8" 6,650' 3,999' 5,750psi 3,090psi Production 6,493' 7" 6,493' 3,985' 7,240psi 5,410psi Liner 8,596' 6-5/8" 15,082' 4,047' N/A N/A Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade:Tubing MD (ft): See Schematic See Schematic 3-1/2" 9.3# I L-80 / EUE 6,520' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7" x 3.5" HES PHIL and N/A 5,885' MD/ 3,881' ND, and N/A 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 2/26/2018 OIL ❑Q WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Stan Porhola Authorized Title: Operations Manager Contact Email: S orhola hllcor .corn Contact Phone: 777-8412 Authorized Signature: Date: 2/19/2019 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No E�r Subsequent Form Required: APPROVED BY n p/ / pr by: COMMISSIONER THE COM Date L'Q ` Il ,Approvedti � c, ^ 1 ^ � ...........�L. Iftnn U J LUIJ �1y1�\ �' Z ( l �.l_p�/yf , ` Q R Submit Form and v Form 10-403 R 4Y1017 Approved appli� the date of approval. Attachments in Duplicate �� "ew/� P. 4:!.8. Z/zZ(t9 K 110e Alaska, LU Well Prognosis Well: MP M-10 Date: 2/19/2019 Well Name: MPU M-10 API Number: 50-029-23617-00-00 Current Status: Oil Well [Jet Pump] Pad: Milne Point M -Pad Estimated Start Date: February 26th, 2019 Rig: Coil Tubing Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218-165 First Call Engineer: Stan Porhola (907) 777-8412 (907) 331-8228 (C) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: 1813837C Job Type: Coil Foam Cleanout Current Bottom Hole Pressure: 2,200 psi @ 4,000' TVD (Last BHP measured 2/17/2019) Maximum Expected BHP: 2,200 psi @ 4,000' TVD (No new perfs being added) MPSP: 1,800 psi (Based on 0.10 psi/ft gas gradient) Brief Well Summary MPU M-10 was drilled in 2019 using Doyon 14 and completed as a single -lateral in the Schrader Bluff OA sand with a Jet Pump completion. The 6-5/8" liner was left with drilling mud due to high pressure encountered by offset injectors L-50 and F-110. Notes Regarding Wellbore Condition • Deviation down to jet pump section is 70°. • Casing last tested to 3,500 psi for 30 min down to 5,885' on 2/17/2019. Objective: The purpose of this work/sundry is to perform a N2 foam cleanout of the lateral. Work Procedure: Coiled Tubing Procedure:[�— V01- 1. MIRU Coiled Tubing Unit and spot ancillary equipment. Fill source tank w/ 8.5 ppg 1% KCI. 2. Pressure test BOPE to 3,500 psi Hi 250 Low, 10 min Hi, 5 min Low each test. a. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. b. No AOGCC notification required. c. Record BOPE test results on 10-424 form. 3. RIH w/ 2.00" coil w/ 2.5" to 2.70" max OD wash nozzle and extended reach cleanout BHA and cleanout to PBTD at+/- 15,082' MD. POOH. / a. Circulate out fill using 8.5 ppg 1% KCI w/ friction reducer. Pump 5-10 bbl Gel Sweeps to help remove solids from the liner. b. Contingency: If unable to wash down with nozzle, RIH w/ 2.5" to 2.70" mill and extended reach cleanout BHA and cleanout to PBTD at +/- 15,082' MD. POOH. 4. RIH w/ 2.00" coil w/ 2.5" to 2.70" max OD wash nozzle and extended reach cleanout BHA and cleanout to PBTD at+/- 15,082' MD. POOH. H Hilmn, Alaska, LU Mr' Z / (, L 61 Well Prognosis Well: MP M-10 Date: 2/19/2019 a. Circulate out fill using 8.5 ppg 1% KCI w/liquid foamer and mix with Nitrogen (see Nitrogen procedure,and diagram). Utilize defoamer for returns in Kill Tank. ontinge : If unable to wash down with nozzle, RIH w/ 2.5" to 2.70" mill and extended reach anout BHA and cleanout to PBTD at +/-15,082' MD using 8.5 ppg 1% KCI w/liquid foamer and mix with Nitrogen. POOH. 5. PU to 2,500' and freeze protect well. POOH w/ coil. 6. RD Coiled Tubing and ancillary equipment. Turn well over to production. Attachments: 1. As -built Schematic 2. Coil BOPE Schematic 3. Nitrogen Operations Procedure 4. Nitrogen & Foam Flow Diagram n Hileora Alaska, LLC Orig. KB Elev.: 58.6/ GL Elev.: 24.9' RKB—THF: 28.98' D n 14 2a' 1 35'8 "'ES Csrenter@ ': 2460' 2 3 1/2` 3 7" SCHEMATIC TREE & WELLHEAD Milne Point Unit Well: MPU Moose Pad M-10 Last Completed: 2/02/2019 PTD: 218-165 Tree Cameron 31/8" 5M Wellhead FMC 11" 5M TC -3A w/11" x 3 1/2" TC -II Top and Bottom Tubing 12-1/4" 2nd stage Hanger with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 42" 50 bbls (10 yards Pilecrete dumped down backside) 12-1/4" 1st stage 525 sx 12.0# Extenda, 400 sx 15.8# SwiftCEM 12-1/4" 2nd stage 410 sx 10.7# Perm L, 270 sx 15.8# SwiftCEM 8-1/2" Cementless Pre -Drilled Liner in 8-1/2" hole CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm BPF 20'.34" Conductor (insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A 9-5/8" Surface 40/L-80/TXP 8.679" Surface 6,654 0.0758 7" Tieback 26/L-80/TXP 6.151" Surface 6,493' 0.0383 6-5/8" Liner (Pre -Drilled) 20/L-80/Hydril 563 1 5.924" 6,486' 15,082' 1 0.0355 3-1/2" 1 4 5 k 6 7 Nin_>I 1 e 2.750'o' 10 12 9 35/8' • • 13 • • • • • 65/8" • 8-1/2' Shoe @ • Hole 1508Z • 14 ... .................... .. TD= 15,09Z (MD) /TD = 4,04'YOVD) PBTD=15,087 (MD) /TD=4,041(TVD) 9.3/L-80/EUE 1 2.867" 1 Surf I 6,520' 1 0.0087 WELL INCLINATION DETAIL KOP @ 350' Max Hole Angle = 70.00 deg. @ Jet Pump Max Hole Angle = 74.00 deg. @ XN profile Max Hole Angle = 84.00 deg. @ Tubing tail Max Hole Angle = 90.00 deg. @ 6,994' MD JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 29' Tubing Hanger (3-1/2" TC -II Top & Btm) w/ Blast Rings on hanger pup 2.867" 2 2,534' 3.5" GLM W/ 1.5" Shear Out Valve (2,000 psi) 2.867" 3 5,791' 3.5" Discharge Pressure Gauge Mandrel (Discharge Gauge) 2.875" 4 5,802' 3.5" XD Sliding Sleeve 2.813" Packing Bore; 3,854'TVD; 70 deg Hole Angle 2.813" 5 5,810' 3.5" Gauge Mandrel w/ Y"" Wire (intake Gauge) 2.875" 6 5,832' 3.5" X Nipple (2.813" Packing Bore) 2.813" 7 5,885' 7" x 3.5" PHL Retrievable Packer (50k Shear Release) 2.885" 8 5,942' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) Min ID = 2.750" RHC -P set 2.750" 9 1 6,519' 1 3.5" WLEG (Btm @ 6,520') 2.867" Lower Completion 10 6,486' BOT SLZXP Liner Top Packer w/BD Slips 7-5/8"x9-5/8"(11.33' Tieback Sleeve) 6.170" 11 6,493' 7" Tieback Assy. (8.25" OD No -Go @ 6,483') 6.151" 12 6,508' 7-5/8"" Hydril 563 L-80 x 6-5/8" Hydril 625 L-80 XO 5.924" 13 6,628' 6-5/8" Pre -Drilled Liner (78 ea 3/8" holes per ft) w/ 1 straight -vane centlzr per it 5.924" 14 15,082' Shoe; Btm @ 15,082') GENERAL WELL INFO API: 50-029-23617-00-00 Drilled and Completed by Doyon 14-2-02-2019 Revised By: STP 2/11/2019 LLC COIL BOPE MPU M-10 20 X9%X 7X 3Y: Coil Tubing BOP Lubricator to injection head 2.00" Single Stripper 1/1610 Blind/Shear. FBIW/Sheu ar — Blind/Shear OI • Shp I Pipe I Crossover spool 4 1/1610M X 41/16 SM Pump -In Sub 41/16 5M Crossover spool 4 1/16 5M X 3 1/8 5M Valve, Swab, WKM-M, 3 1/8 SM FE Valve, Upper Master, Baker, 3 1/8 SM FE, w/ Hydraulic Valve, Lower Master, WKM-M, 3 1/8 5M FE Tubing Adapter, 3 1/8 SM Pipe lanual Gate Manual Gate 2 1/8 SM 2 1/8 5M Slypn Cts' Ja�eigl�a MILNE POINT UNIT MPU M-10 1502 Union 0 STANDARD WELL PROCEDURE Ililcorp Alaska, LII: NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 30.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 O m V W z d V W 2 w Y o3aouo e3aouo T z 43 a o> G x H C O O O W Y N 2 � � r G m ~ O K N p n W s 0 t c P a a a c 0 T z 43 a o> G x H C O O O W Y N 2 � � r G m ~ O K N p i "APIA M -(L) Pro z131L--�so Regg, James B (DOA) From: Sloan Sunderland <ssunderland@hilcorp.com> Sent: Friday, January 11, 2019 3:28 PM To: DOA AOGCC Prudhoe Bay Cc: Monty Myers; Joe Engel; Stan Porhola Subject: Doyon 14 BOP Usage Date and Time of BOP usage- 1-10-2019 @ 11:25 & on 1-10-2019 @ 17:34 Well, M-10, Location, Milne Point Moose Pad, PTD # 218-165 Rig Name- Doyon 14 Operator Contact- Hilcorp Sloan Sunderland- 907-670-3090 Operation Summery- After drilline M-10 to TD at 15405 the well was circulated clean and back reaming was commenced with flow on connections. Well was determined it was flowing due to two injectors still on while drilling. Both wells were shut in. We back reamed F/ 15405'T/ 14425'. We circulated btm up and got gas cut mud and well was flowing on connections. Wash and ream back to btm & circ & condition while waiting on new mud to arrive on location with no gains or losses. Displace the well with 1300 bbl 10.5 still getting 10.0 PPG in returns. Out of mud. Shut down and well was flowing at 60 BPH. Took back 10 bbl to trip tank while monitoring. Returning mud has lots of oil breaking out. Shut in on 1-10- 2019 @ 11:25. Pressure built to 85 psi on the annulus in 4 hrs. Bump float & SIDP 90 psi. Build 180 bbl 10.5 Flow Pro mud while waiting on mud from the Mud plant. Open up choke taking back 4 bbl to trip tank. Open Top rams. Pump at 5 bpm 180 bbl still getting old mud back. Shut down and shut in well on 1-10-2019 @ 17:34 with top VBR rams against a closed choke and kill. on 5" DP with full open safety valve installed. Initial SICP is 55 psi. Pressure dropped to 36 Psi in 12 hrs. After New Kill wt mud on location we Open up choke taking back 2 bbl to trip tank. Open HCR & Top rams. Resumed circulation and isplacing the well to 10.5 in and out. Monitor well with slight flow on connections. We are currently back reaming to the shoe to spot a mud cap and POOH for liner. Reason for BOP Usage- Stop well from flowing Our Last BOP test was on 1-1-2019 and we plan on performing a full BOP test when out of the hole. We will submit a 24 hr notice for BOP test as required. , Sloan Sunderland Hilcorp Drilling Foreman Office- 907-670-3090 Cell- 907-715-0591 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99501 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-10 Hilcorp Alaska, LLC Permit to Drill Number: 218-165 Surface Location: 5037' FSL, 51' FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 237' FNL, 1376' FWL, SEC. 20, T13N, R10E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Hollis S. French Chair DATED this day of December, 2018. a°QED STATE OF ALASKA � El e `� E� ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: tb. Proposed Well Class: Exploratory - Gas LJ Service- WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑� Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑� Service- Winj ❑ Single Zone ❑� Coalbed'Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 • MPU M-10 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 15,614' TVD: 3,994' Milne Point Field Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: r I Surface: 5037' FSL, 51' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL388235, ADL025515 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 289' FNL, 876' FEL, Sec 13, T13N, R9E, UM, AK LONS 16-008 12/16/2018 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 237' FNL, 1376' FWL, Sec 20, T13N, R1 OE, UM, AK 7024 4413' to the nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (1 58.6 15. Distance to Nearest Well Open Surface: x- 534113 y- 6027889 Zone -4 GL / BF Elevation above MSL (ft): 24.9 0 to Same Pool: 560' to F-110 16. Deviated wells: Kickoff depth: 354 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92 degrees Downhole: 1760 Surface: 1359 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) Cond 20" - X52 Weld 107' Surface Surface 107' 107 ±270 ft3 12-1/4" 9-5/8" 40# L-80 TXP 6,498' Surface Surface 6,498' Sig 1 -L-1404 ft3/T-458 ft3 3,999' Stg 2 - L - 1937 ft3 / T - 314 113 Tieback 7" 26# L-80 TXP 6,348' Surface Surface 6,348' 3,982' Tieback Assy. 8-1/2" 6-5/8" 20# L-80 Hyd 563 9,265' 6,348 3,982' 15,613' 3,994' PreDrilled Liner 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 Q 20. Attachments: Property Plat O BOP Sketch v Drilling Program a Time v. Depth Plot v Shallow Hazard Analysis B e Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements8 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en t?I hilCOf .COfTI Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: Date: z -� o • j m Commission Use Only Permit to Drill API Number:Permit Approval See cover letter for other Number: p`,I $-'�6'S 50-aa1-23GIV-oo-ao Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: [� Other: 3L-40 O S . & P •T„� Samples req'd: Yes ❑ No[q' Mud log req'd: Yes L]No[?' / , tr�.� HzS measures: Yes ❑ No[!I' Directional svy req'd: Yes ['a' No ❑ Spacing exception req'd: Yes ❑ No [ ' Inclination -only svy req'd: Yes ❑ NO2' .� /� / /�� s' 3 �/ Ck Post initial injection MIT req'd: Yes ❑ No ❑ ylfC ``�P2i ZO /4,4GZ5:ZbSca)(I� APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: t L (1 le j Submit Form and Form 10-401 Revisetl 5rzo17 This permit is valid f ryq�1 d of approval per 20 AAC 5.005(8) Attachments i Duplicate un f L- -[` _/ Y R V 1 I Y� L �iJ/i�� B. �zlrr%� U Hilcor 12.10.2018 Commissioner Alaska Oil & Gas Conservation Commission 333 W. Th Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU M-10 Dear Commissioner, Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point'M' Pad, well slot 10. Drilling operations are intended to commence approximately Dec 16th, 2018, pending rig schedule. MPU M-10 is a grassroots jet pump producer planned to be drilled in the Schrader Bluff OA sand. M- 10 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" pre -drilled liner will be run in the open hole section and the well produced with a jet pump assembly. The Doyon 14 will be used to drill and complete the wellbore. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU M-10, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself (Joe Engel) at 777-8395 orjengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, Joe Engel/ Drilling E Hilcorp Alaska, LLC Page 1 of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) M-10 Drilling Program Version 1 12/7/2018 Table of Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 RX and Preparatory Work..........................................................................................................10 10.0 NX 21-1/4" 2M Diverter System.................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP NIU and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 6-5/8" Production Pre -Drilled Liner...................................................................................31 17.0 Run 7" Tieback..............................................................................................................................36 18.0 Run Jet Pump Completion...........................................................................................................39 19.0 RDMO............................................................................................................................................39 20.0 Doyon 14 Diverter Schematic.......................................................................................................40 21.0 Doyon 14 BOP Schematic.............................................................................................................41 22.0 Wellhead Schematic......................................................................................................................42 23.0 Days Vs Depth................................................................................................................................43 24.0 Formation Tops & Information...................................................................................................44 25.0 Anticipated Drilling Hazards.......................................................................................................45 26.0 Doyon 14 Layout............................................................................................................................47 27.0 FIT Procedure................................................................................................................................48 28.0 Doyon 14 Choke Manifold Schematic..........................................................................................49 29.0 Casing Design.................................................................................................................................50 30.0 8-1/2" Hole Section MASP............................................................................................................51 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................52 32.0 Surface Plat (As Built) (NAD 27).................................................................................................53 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................54 34.0 Drill Pipe Information 5" 19.5# 5-135 DS -50 & NC50...............................................................55 Milne Point Unit M-10 SB Producer Ailcoi Drilling Procedure 1.0 Well Summary Well MPU M-10 Pad Milne Point "M" Pad Planned Completion Type Jet Pump on 3-1/2" Production Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 15,613' MD / 3,994' TVD PBTD, MD / TVD 15,608' MD / 3,994' TVD Surface Location Govemmental) 5037' FSL, 51' FEL, Sec 14, TON, R9E, UM, AK Surface Location (NAD 27) X= 534,113.8, Y= 6,027,889.65 Top of Productive Horizon (Governmental) 289' FNL, 876' FEL, Sec 13, T 13N, R9E, UM, AK TPH Location (NAD 27) X= 538,568.21 Y= 6,027,865.16 BHL Govemmental 237' FNL, 1376' FWL, Sec 20, T13N, R10E, UM, AK BHL AD 27 X= 546,06 1.00, Y=6,022,681.0 AFE Number 1813837 AFE Drilling Days 18 days AFE Completion Das 8 days AFE Drilling Amount $4,229,855 AFE Completion Amount $2,279145 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1359 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1760 psig Work String 5" 19.5# S-135 DS -50 & NC 50 KB Elevation above MSL: 33.7 ft + 24.9 ft = 58.6 ft GL Elevation above MSL: 24.9 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure U —w., 2.0 Management of Change Information H Hilcorp Alaska, LLC E i - p ilCrp Changes to Approved Permit to Drill Date: 12/612018 Subject: Changes to Approved Permit to Drill for MPU M-10 File #: MPU M-10 Drilling and Completion Program Any modifications to MPU M-10 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC. Approval: Manager Prepared: Drilling Engineer Date Page 3 H Me F.m C22 3.0 Tubular Program: Milne Point Unit M-10 SB Producer Drilling Procedure 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 OD. 19.25" X-52 Weld Cond 20" 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 Tieback 7" 6.276" 6.151" 7.656 26 L-80 TXP 7,240 5410 604 8-1/2" 6-5/8"6.049 Pre -drilled 5.924 7.390 20 L-80 Hydril563 6,090 3,470 459 4.0 Drill Pipe Information: All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 Milne Point Unit M-10 SB Producer 2 Hil 2Drilling Procedure it Cmopmy 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorP, jengel@hilcolp.com and cdinizer@hileorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to mmyers@hilcorp,com jeneel@hilcorp.com and cdinger@hilcoM.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers&hilcorp.com jeneel@hilcorp.com and cdinger@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmvers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 ienael@hilcorp.com Completion Engineer Stan Porhola 907.777.8412 907.331.8228 sporhola@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kflemina@hilcorp.com EHS Manager Carl Jones 907.777.8327 1 907.382.4336 1 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdineer@hilcorp.com Page 5 ff Hilcorp E, C22 6.0 Planned Wellbore Schematic brig KBEIar_ 586'/ Q Ely.: 249 ____.._7D -1+r 614'(&0)/TD- 3,9W(NCI PWD=15,609 W /7D-3,994'(IW) Page 6 PROPOSED SCHEMATIC TREE & WELLHEAD Milne Point Unit M-10 SB Producer Drilling Procedure Milne Point Unit Well: MPU Moose Pad M-10 Last Completed: Proposed PTD: TBD Tree I Seaboard 8" SM 12.1/4 Lar sop Seaboard M3/4"3Ma 1Y5M wf11"x31/Y EM ropand Wellheatl BdOoDr A 3'OW"H"BPV k.2ea38"NPT comrcl Brea. OPEN HOLE /CEMENT DETAIL 4Y SOjIBS1(30 YaMsg�gtg dumped erwn bacitside) 12.1/4 Lar sop 1404 R3111983te" 458 fUl Mlg jX 12-1/4"20 urge 1337R3 1070 Penn L, 314 ft315.01ao*SS 611Y fdnK MP Criilee Ucer in 6.1/Y hale CASING DETAIL Size Type JW Grade/ Conn Drift ID Top $SID I BPF 20'x34" Conckicmr(fmulatad) 78-6/A-53/WNd N/A Sreface 106.5' N/A 9.5/8' Surface 40/!. 0/TI(PSR &679" Surface ±6,436' 0.0758 T Tieback 26/L-W/TXP 6.151" 11"'oe *5,348' 0.0383 65/8" Ger(Pre)nllee) 20/L-90/Ij1563 5924" *5,346' ±15,614' 0.0355 TUBING DETAIL WELL INCLINATION DETAIL .10l M XOP @350' Max Hole Angle=67 oo reg. @lex Pump q Max Hole Mgle=]2.W deg.@ XN profle 1f Max Hole Angle=84.00 deg.@Tubing tail Max Hole Angle= 90.00 dq. @ 6,560' MD .I I� 11' JEWELRY DETAIL No. Top MD hem Drill ID Upper ccerple9 1 }29' Tobin 4anger(3-1/2' EUE-MOD Tpp& BZW2867 2 ±2,500 39"GU4 w/1.5'DGLV .1 RK Laxch 2857 3 ±3700 3.5" Eocemal Pressure Gauge V.rdrl(Otslu,W Gauge) 1813" 4 +5,755' 3.5' Jet Pump Cavity, Forward S)U Mt Pump M, w Armulus). 3,850' TVD 2913" 5 ±S8W 3.5'Gauge Mandrel w/ W Wirelmake Gauge) 2933- 6 ±3850 7x35'PHZ Retrievable Packer 2913' 7 ±59=r 1V Nipple, Mn ID=Z7 h1 .1813"Padang Bare 2.750" 8 26,249' 35"WLEG(ftm@6,250') 2.862' LauverC rroetlan 9 '_6,245' ]-5/8- Tieback A w. 8.25' OD Nc,Go @ 6,235'1 6.151" 10 26,250 607 SlZ liner Top Packer w/8D slips 7-5/r x 9-5/rj=S'1De1,xk Straka 6.200" 11 _6,270 ]-5/8""dgd0I5fi3 L-60x6-5/8'&W(525L-80XO 5924" 12 26,400' 65 "Pro-Orilledi;L 5924' 13 15,613' S,.; Rg&@15,614') Rerisc[ Pv CJD 12/10/2019 H Hilcrp �� -22 7.0 Drilling / Completion Summary Milne Point Unit M-10 SB Producer Drilling Procedure MPU M-10 is a grassroots jet pump producer planned to be drilled in the Schrader Bluff OA sand. M-10 is part of a multi well program targeting the Schrader Bluff sand on M -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 6-5/8" pre -drilled liner will be run in the open hole section and the well produced with a jet pump assembly. The Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately Dec 16, 2018, pending rig schedule. Surface casing will be run to 6,498' MD / 3,998' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations: 1. MIRU Doyon 14 to well site 2. N/U & Test 21-1/4" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing 4. N/D diverter, N/U & test 13-5/8" x 5M BOP 5. Drill 8-1/2" lateral to well TD. Run 6-5/8" production liner 6. Run 7" tieback 7. Run completion - ;Jr�l' P-&" 8. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR+Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 7 Milne Point unit M-10 SB Producer Hilcorp Drilling Procedure MITT T 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-10. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: Hilcorp Alaska LLC respectfully requests a variance to 20 AAC 25.265 (c)(1), requiring the surface safety valve be located in the vertical run of the well tree. Due to the jet pump production method and horizontal tree configuration, Hilcorp Alaska proposes that the surface safety valve be installed horizontally. Page 8 H Hilcorp EM .2,7 Milne Point Unit M-10 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applica,bKAOGCC regulations, specific regulations are listed below. If additional clarity orguidance is re red on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling T • BOPs shall be tested at (2) week intervals during the drilling completion of MPU M-10. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initi est of BOP equipment will 1pre 000 p & subsequent tests of the BOP equipment will be to 25 000 psi for 5/5 min (an% r ed WP, 2500 psi on the high test for initial and subsequent t s). Confirm that thures match those specified on the APD. • IftheBOPisusedtosh inonthewl control situation or control fluid flowfrom the well bore, AOGCCis to be tifiedantest all BOP components utilized for well control prior to the next trip into the llbore.sure test will be charted same as the 14 day BDP test. • All AOGCC regulations within 20 and drilling fluid system". • All AOGCC regulations within 0 AAC 25.035 completion: blowout preventi equipment and c "Primary well control for drilling: drilling fluid program idary well control for primary drilling and requirements". o Ensure th/diverter nt line is at least 75' away fr potential ignition sources Ensure AOGdrilling permit is posted on the n floor and in Co Man office. AOGCC Regulace Requests:Hilcorp Alaska L request any variances at this time. W �O ry 5 S I% Page 8 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure(psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP Initial Test: 250/4,Mr • 13-5/8" x 5M Hydril MPL Double Gate 3044 o Blind ram in him cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 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 250/4600" j�+on • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg(cr7alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartznaalaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorsna alaska.gov Test/Inspection notification standardization format: hitp://doa.alaska.goy/ogc/forfns/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 H Hilcorp U 9.0 R/U and Preparatory Work Milne Point Unit M-10 SB Producer Drilling Procedure 9.1 M-10 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. Page 10 H Hilcorp .� w 10.0 NX 21-1/4" 2M Diverter System Milne Point Unit M-10 SB Producer Drilling Procedure 10.1 N/U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • NIU 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. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking A prohibition on ignition sources or running equipment A prohibition on staged equipment or materials Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 11 H Hilcorp Envy ZrIp 10.5 Rig & Diverter Orientation: • May change on location Milne Point Unit M-10 SB Producer Drilling Procedure 75' Radius Clear of Ignition Sources Diverter Line MPU M -Pad *Drawing Not To Scale Page 12 H Hilcorp U� 11.0 Drill 12-1/4" Hole Section Milne Point Unit M-10 SB Producer Drilling Procedure 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside 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 for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 5" Drill string, HWDP, and Jars will come from Weatherford. 11.3 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4" hole section to section TD in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. • Gas hydrates have not been seen on M -Pad. However, be prepared for them. In MPU they have been encountered typically around 2100-2400' TVD (just below permafrost). Be prepared for hydrates: Page 13 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Past wells on E pad have increased MW to 9.8 ppg and added 1-1.5ppb of Lecithin & .5% lube. After drilling through hydrate sands, MW was cut back to normal • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. 11.5 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW ) Surface — Base Permafrost 8.9+ Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells) MW can be cut once —500' below hydrate zone • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Cc Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBsBAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 NWST 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. Page 14 H Hilcorp Milne Point Unit M-10 58 Producer Drilling Procedure Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 — 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud ProDerties: Section Densit Viscosity Plastic Viscosity Yield Point AN FL pH Tem Surface 11 8.8 - 9.8 A 75-175 20-40 25-45 <10 8.5 - 9.0 <- 70 F System Formulation: Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M -I Gel 50 lb sx 25 Soda Ash 50 Ib sx 0.25 Pol Pac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.6 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.7 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.8 TOOH and LD BHA 11.9 No open hole logging program planned. Page 15 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assembly consisting of: 9-5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, I Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. This end up. Bypass Baffle • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 H Hilcorp E� C—P�y 12.5 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve 40. Shear Pins ES Cementer Depth Baffle Adapter (d used) ID Depth Bypass or Shutoff Baffle ID Depth Float Collar Depth Float Shoe AT Depth Hole TD "Reference Casing ZsManuel Iris 5 Page 17 "A Overall LengN B 6hn. 10 After Drilloua C Mas. T.1 OD D Opening Seat ID E Clo-sing Seat ID Plug Set Part No. Opening Plug OD OD Shutoff Plug OD Bypass Plug (if used) OD Milne Point Unit M-10 SB Producer Drilling Procedure RBcaP FSB gunning Order ESll Cementer QShia Of Plug Baffle Adapter V By -ft. Plug 1 By Pass Raffle Float C•IWr Fbrt Shoe H Hilcorp E.v C: nT- Milne Point Unit M-10 SB Producer Drilling Procedure 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: • 1 centralizer every joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to --2,000' above shoe (Top of Ugnu) • Verify epth of lowest Uenu water sand for isolation with Geologist • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). (Halliburton ESIPC with packer element may be used). • Install centralizers over couplings on 5 joints below and 10 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. • ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at — 3000 psi. Reference ESIPC Procedure. 9-5/81140# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,960 ft -lbs 23,060 ft -lbs Page 18 GEOMETRY Threads per in 5 connection 00 Oplion REGULAR PERFORMANCE Milne Point Unit 9.825 in. 8.935 in. Nam -al Weight WaWThickness 40@sft 0.3956. Orin PLsin End VRight 8679 in 33 97 M-10 SB Producer Ail=Drilling it Compression susrgth 916.000 x1000 Max. Allowable Gentling 38 `:100 ft Procedure caw x TXP® BTC ..e..,11106/2018 Outside Diameter 9 625:n. Nm. Wall Thickness 87.5°6 r Lm low Type 1 Type Wall Thickness 0.395-. Connection OD REGULAR CODPL0IO PIPE BODY Option eody: Red 1st Band Red I Grade LBO Type 1• Drift API Standard 1st Band: Broom 2nd Sand'. 2nd Band: - Brown Type casing 3rd Sand', - 3m sand: - 4M Band. - GEOMETRY Threads per in 5 connection 00 Oplion REGULAR PERFORMANCE Nmunal OD Nceenal 10 9.825 in. 8.935 in. Nam -al Weight WaWThickness 40@sft 0.3956. Orin PLsin End VRight 8679 in 33 97 OD T+1eraece API PERFORMANCE Body Y*V Soenglh 916 x100D IDs 1r4emalyied 5750 psi sldYs BOODD psi cPra{se 3090 psi GEOMETRY Civndectbn DD 10.825 in. coupling LeWh 10.825 w. connection ID &823,n MaIaup Loss 4.891 in. Threads per in 5 connection 00 Oplion REGULAR PERFORMANCE T�'Sion Effnienry 1DO.0% Joon Yieid stranplh 9160000000 Interns) Pressure Capacity In 5750000 psi lbs Compression Efibiency 100% Compression susrgth 916.000 x1000 Max. Allowable Gentling 38 `:100 ft Its Exiemal Presw*e capacity 3090.000 ps. MAKE-UPTORQUES 0tm:mum 16860 ft -9s Optimum 2096011 -lbs Mamnum 230SO h4hs OPERATION LIMIT TORQUES Opmf%Tpque 35600 ftaba Yield Torque 43400 Nibs Notes This connection is fully interchangeable with: TXPO BTC - 9.625 in. - 36 143.5 147 153.5 158.4 IbsR [1] 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. Page 19 n Hilcorp Evnp C.wpu) Milne Point Unit M-10 SB Producer Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 n Hilcorp �r 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-10 SB Producer Drilling Procedure 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/1J cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1St stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 11t Stage Total Cement Volume: Page 21 I&/' 3 zc s� / 3ZK sx 12-1/4" OH x 9-5/8" 65 (5,948'- 2500') x .0558 bpf x 1.3 = 250.1 1404.3 Ci Casing Total Lead 250.1 1404.3 12-1/4" OH x 9-5/8" (6,498'- 5,948') x .0558 bpf x 1.3 = 72.5 407 Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 I&/' 3 zc s� / 3ZK sx n Hilc . c®,.o,orp Milne Point Unit M-10 SB Producer Drilling Procedure Cement Slurry Design (V Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: , ' x .0758 bpf =�bbls �f " a p 40 bbls of weighted spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Page 22 Lead Slurry Tail Slurry System ExtendaCEM "" System SwiftCEM'm System Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: , ' x .0758 bpf =�bbls �f " a p 40 bbls of weighted spacer to be left behind stage tool, confirm spacer is compatible with cement behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. Page 22 n Hilcorp U�—. Milne Point Unit M-10 SB Producer Drilling Procedure 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 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. If ESIPC is ran, Increase pressure to 2090 psi to shift ESIPC sleeve and to begin inflating the packer. Inflate packer as per HEC rep. Reference ESIPC procedure. Once ESIPC packer is inflated, increase pressure to 3000 psi to open rupture disc / circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. (If ESIPC is used and packer element inflated, CBU xl minimum before pumping second stage). Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2"d stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. NLS Estimated 2"d Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) Milne Point Unit 20" Conductor 9-5/8" Casing (110') x.26 bpf x 1= 28.6 M-10 SB Producer ru a Hilco�P � � Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. (If ESIPC is used and packer element inflated, CBU xl minimum before pumping second stage). Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2"d stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. NLS Estimated 2"d Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM "" System (Hal Cem) 20" Conductor 9-5/8" Casing (110') x.26 bpf x 1= 28.6 161 ru a 12-1/4" OH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-5/8" Casin (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 Lead Slurry Tail Slurry System Permafrost L SwiftCEM "" 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 Page 24 n Hilcorp Milne Point Unit M-10 SB Producer Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x.0758 bpf = 190 bbls mud 6� 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run" casing tally & casing and cement report to jewel@hilcorp.com and cdin er ,hilcoW. com This will be included with the EOW documentation that goes to the AOGCC. Page 25 H Hilcorp 14.0 14.1 14.2 14.3 Milne Point Unit M-10 SB Producer Drilling Procedure BOP N/U and Test N/D the diverter T, knife gate, diverter line & N/U 11" x 13-5/8" 5M casing spool. 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" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & 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 HRC outside of the manual valve Run 5" BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg F1oPro fluid for production hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6" liners in mud pumps. Page 26 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure �r 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool or ESIPC. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every'/4 bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = —2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 15.8 POOH & LD Cleanout BHA 15.9 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 8-1/2" hole section mud program summary: Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Use appropriate SAFECARB blend on this well Page 27 n Hilcorp Milne Point Unit M-10 SB Producer Drilling Procedure • 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. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.5 ppg FloPro drilling fluid Prnnarties Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15-30 4-6 <10% 1 <8 1 <11.0 <100 System Formulation: Product- production Size g ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gaU100 bbls) 55 gal dm 0.2 FLONIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify) 50 lb sx 10 SAFE-CARB 20 (verify) 50 lb sx 10 Soda Ash 50 lb sx os 15.11 TIH with 8-1/2" directional assembly to bottom Page 28 H Hilcorp 15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid Milne Point Unit M-10 SB Producer Drilling Procedure 15.13 Begin drilling 8.5" hole section, on -bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations • If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Reservoir plan is to undulate between Schrader OAl & OA3 lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes • Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. • Target ROP is as fast as we can clean the hole without having to backream connections • Schrader Bluff OA Concretions: 5-10% of lateral L-47:6%, L-50 9.5% F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1% 15.15 Reference: Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed Page 29 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure U -LT Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary Ensure mud has necessary lube % for running liner If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm max). • 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 15.18 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.19 Monitor well for flow. Increase mud weight if necessary Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.20 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.21 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 30 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure � 22 16.0 Run 6-5/8" Production Pre -Drilled Liner 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 6- 5/8" pre drilled liner, the following well control response procedure will be followed: • P/U & M/U the 5" safety joint (with 6-5/8" crossover installed on bottom, TIW valve in open position on top, 6-5/8" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 6-5/8" Predrilled liner. • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. • Proceed with well kill operations. 16.2. Well control preparedness: In the event of an influx of formation fluids while running the 3- 1/2" inner string inside the 6-5/8" pre drilled liner: • P/U & M/U the 5" safety joint (with 6-5/8" x 3-1/2" triple connect crossover installed on bottom, TIW valve in open position on top, 3-1/2" handling joint above TIW). M/U 3-1/2" and then 6-5/8" to triple connect. • This joint shall be fully M/U with crossovers prior to running the first joint of wash pipe. • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.3. R/U 6-5/8" pre -drilled liner running equipment. • Ensure 6-5/8" 20# Hydril 563 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.4. Run 6-5/8" pre -drilled production liner • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run packoff and float shoe on bottom. • 6-5/8" pre -drilled liner will auto —fill • 6-5/8" Liner will be centralized with I/joint free floating • If needed, install swell packers as per the lower completion tally. • Remove protective packaging on swell packers just prior to picking up • Do not place tongs or slips on the packer element 6-5/81120 # H dril 563 To OD Minimum Optimum Maximum Yield Tor ue 6-5/8 5,900 ft -lbs 7,100 ft -lbs 10,300 ft -lbs 36,000 ft -lbs Page 31 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure E� rp Wedge 563® r...,... i l.W20119 84 S'a 0950,.. Mln. Vda 49tsde Lvmmner 8-823 n. Thickness PERFORMANCE Typo 1 Lo^^ect�Pn P� Wall Thlckri,,- 9.288 n. PliB li. lbn Eecwncl cnit'.w Es..sy ExlvrNlErOstum C.09111 Bony Red Cation Gmde LBO Type l Bn8 MAKEJIP TORQUES 2rd Batt • ?rx r...,... i l.W20119 84 S'a 0950,.. Th.,Win 3.39 Gann.d. DG C{nen REGULAR PERFORMANCE Typo 1 REGULAR CO UNG PliB li. lbn Eecwncl cnit'.w Es..sy ExlvrNlErOstum C.09111 Bony Red 1st Banc Red APd Standard 1st Bard: Bans. Zed Bard: MAKEJIP TORQUES 2rd Batt • Br9sm easing 3rd Bane . 3d Bard. Mn,mum 9900 M1 -Gs ata Band PIPE BODY DATA, GEOMETRY NaminalGD 9.M,n, dldmHul'NNpnf 20"I.In Din 9921 tn. Npminaill 9919,n. WaIITai:knnss 9.MSi t in End m ym 1951 I0Vm OG T.I..e API PERFORMANCE e[Or tela slro�ll, 159.1 00106 Haemal rima cpravp a1T0 P" CONNECTION DATA GEOMETRY 9990 WI EWE C.rrncw Cc T.300,n. ..nurlrg -s,n9w — 9999 PA Ma\cuP Lccs 0950,.. Th.,Win 3.39 Gann.d. DG C{nen REGULAR PERFORMANCE li. lbn Eecwncl cnit'.w Es..sy ExlvrNlErOstum C.09111 99.7A 19W'A Nim -000 P. JNnl raw eV 01 cirri, tlnskrvrgn CavPlp4 Fact/ L.ad 119203 x1CU] fns 939.000x1901 IG: 3111M9 S TnX Prerspm eap.tp 9 Ar .ba aa,dr'q 9990.009 V. 535'f109fl MAKEJIP TORQUES Mn,mum 9900 M1 -Gs Orllmum 7190%-b Maximum 19109 e.ms OPERATION LIMIT TORQUES o".ng Tmom a19991I.Ns T mTm. 39908'.1.6 BUCK -0N 5lplmum 19900 fl.1tis Wrimum 11390 ft 0 Notes This connection is fully interchangeable with: Wedge 5635 - 6.625 in. - 24.128132 Ibsift Connections with Dopelesse Technology are fully compatible Milhl the same connection in its Standard version Page 32 Milne Point Unit M-10 SB Producer Hilcorp El C�yy Drilling Procedure 6-5/8" Lower Completion Running Order 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8" connection. 16.7. R/U false rotary and run 3-1/2" 9# Inner String • Ensure inner string is drifted for WIV closing ball OD 16.8. Before picking up Baker ZXP liner hanger/ packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.9. M/U Baker ZXP liner top packer to inner string and 6-5/8" liner. Fill liner tieback sleeve with "Xanplex", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note PUW, SOW, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11 RIH w/ liner on 5" HWDP no faster than 30 ft/min —this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The inner string will prevent the DP from auto filling. Fill DP with mud every 5 stands, more frequently if SOW trend in cates. 16.13. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 rpm 16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.17. Rig up to pump down the work string with the rig pumps. Page 33 Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure Energy Compevy NOTE: The wellbore will be swapped over to brine after the liner has reached TD to remove mud cake from the well bore. Mud cake will cause facility upsets. 16.18 Rrvak circulation and circulate out the mud. egin circulating at —1 RPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. Displace well to brine (-9.2 ppg KCl/NaCI). , over displace well by at least 100+ bbl. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. 16.19. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the swell packers (if run). Do not exceed 1,600 psi while circulating as noted above. Note all losses. Confirm all pressures with Baker. 16.20. Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 16.21. Displace 1.5 OH + Liner volume. 16.22. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.23. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.24. Continue pressuring up to 2700 psi to set the ZXPN liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the Flexlock liner hanger to ensure the HRDE setting tool is in compression for release from the ZXPN liner hanger/packer. Continue pressuring up 4500 psi to activate the hydraulic pusher tool to set the ZXPN packer. This will also release the HRDE running tool. 16.25. Bleed DP pressure to zero. Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, `` r 16.26. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.27. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.28. P/U pulling 3-1/2" out of the pack off & displace out liner with two volumes at max rate. Note: Flexlock Liner Hanger & separate packer will be run on M-10, with a hydraulic running tool with exposed ports that may inhibit circulation through the toe of the 3-1/2". Page 34 H Hilcorp � X22 Milne Point Unit M-10 SB Producer Drilling Procedure 16.29. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOR L/D 3-1/2" inner string. Leave enough 5" DP racked back to trip back to 9- 5/8" shoe. 16.30. M/U 3.5" wash tool & RIH w/ remaining DP out of derrick to liner top. 16.31. Wash through liner top at max rate & circulate hole clean. Pump sweeps around. Displace well to clean filtered brine after no solids are returned. 16.32. POOH & L/D remaining 5" HWDP & Inner string 16.33. Once inner strin¢ is L/D, swap to the completion AFE Page 35 Hilcox En Cmpmy Milne Point Unit M-10 SB Producer Drilling Procedure 17.0 17.1 Run 7" Tieback 111 Cyt.+ J 4: G� � RIH with mule shoe on 5" DP to Liner Topq(d circulation Liner T� d SBE clean. POOH. 17.2 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7" (250/3000 nsi) solid body casing rams. 17.2 R/U 7' casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. Rig up computer torque monitoring service. String should stay full while running, r/u fill up line and check as appropriate. 17.3 PIU tieback seal assembly and set in rotary table. Ensure 7" seal assembly has x4 1" holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7" annulus. 17.4 M/U first joint of 7" to seal assy. 17.5 Run 7" 26# TXP tieback to position seal assembly two joints above tieback sleeve. Record up & down weights. • Following running procedure outlined above. Page 36 OD Tch rause AN PERFORMANCE- Body ERFORMANCEBody Yield Streni 604 xi000lbs ImenWYeld 7240 psi SINS 00000 psi Collapse 5410psi CONNECTION DATA GEOMETRY Connection OD 7.650 in_ Comping Ler4h 10.200 n Connection ID 0.254 ie. L4ake-up Loss 4.579 in. Threads per in 5 Ccnnechon O(3Ophon REGULAR Milne Point Unit Tension ElOciercy M-10 SB Producer Java Yreld Smenglh Hilco X02 Yaermil Pressra Capacity"1 7240.000 psi Drilling Procedure to Compression Ei6cnsncy fog% Compression Strength 604.000xl" Max. Akraable Bening 52 MG) It TXPO BTC INS 12/06!2016 Outside Diameter 7.000 in Min. Wall Thickness 67.5% (7 Grade LBO aw Type 1 Wall Thickness 0.362 in. Connection 00 Option REGULAR COUPLING PIPE LOGY Body:Red 1st Band: Red I Grade LBO Type V Drift API Standard 1st Bard: Bmwn 2nd Band: 2nd Band:- Brown Type Casing 3rd Band:- 3rd Band.-- 4th Band. - PIPE BODY DATA GEOMETRY Nonnnal OD 7.000 in. Nominal AiMftt 26 bi Orm 6.151 t. Normal ID 6.776 in. Wall T1rcGmess 0.302 in. Plain Erd Ae ght 25.69 teff OD Tch rause AN PERFORMANCE- Body ERFORMANCEBody Yield Streni 604 xi000lbs ImenWYeld 7240 psi SINS 00000 psi Collapse 5410psi CONNECTION DATA GEOMETRY Connection OD 7.650 in_ Comping Ler4h 10.200 n Connection ID 0.254 ie. L4ake-up Loss 4.579 in. Threads per in 5 Ccnnechon O(3Ophon REGULAR PERFORMANCE Tension ElOciercy 100.0% Java Yreld Smenglh 604-DOOx10W Yaermil Pressra Capacity"1 7240.000 psi to Compression Ei6cnsncy fog% Compression Strength 604.000xl" Max. Akraable Bening 52 MG) It INS denial pressure Capacity $410.000 psi MAKE-UP TORQUES --- Iinimum 1328D Raba Cp[mum 147500 -lbs Na:aTrn IBMhita OPERATION LIMIT TORQUES Operai Toque 20000 Nos Yield Tai 234000 os Notes This connection is fully interchangeable With: TXPA BTC - 7 in. - 23 1291 32135 1 39 IWIF: [1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resisiance as per section 10.3 API 5C3 ! ISO 10400 - 2007. Page 37 H Hilcorp M� 17.6 M/U 7" to DP crossover. Milne Point Unit M-10 SB Producer Drilling Procedure 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — l Ok lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 P/U string & remove unnecessary 7" joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7" x 9-5/8" annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent casing collapse of 7", verify collapse pressure of 7" tie back. 17.16 Slack off and land hanger. 17.17 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. RILDS. Test void to 3000 psi / 10 min. 17.19 R/D casing running tools. [I'17.20 Test 7" x 9-5/8" production annulus to 1000 psi / 30 min 17.3 Set test plug and change top rams from 7" to 2-7/8" x 5-1/2" VBR. Test annular and lower rams to 2-7/8"test joint, 250 low / 3000 psi high. CIO Page 38 H Milne PointUnit M-10 SB Producer Hilcorp Drilling Procedure 18.0 Run Jet Pump Completion 18.1 Change upper pipe rams back to 2-7/8" x 5" VBR. Test same. Verify the Jet pump components. 18.2 Run the 3-1/2" Jet Pump Completion as noted by completion engineer. 18.3 M/U Jet Pump assembly and RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. 18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.5 MU tubing hanger and landing joint. Terminate control lines. 18.6 Land tubing hanger. 18.7 Drop ball and rod, pressure up to 1,700 psi to start setting of PBL packer. 18.8 Continue to pressure up to 3,000 psi to set packer. 18.9 Pressure up to 3,500 psi to test tubing for 30 minutes and chart. 18.10 Bleed tubing to 2,000 psi. 18.11 Pressure up annulus to 3,500 psi to test casing/packer for 30 minutes and chart. 18.12 Bleed tubing to 0 psi. Pop shear valve from annulus to tubing (2,500 psi differential). 18.13 RILDS and test hanger. LD landing joint. 18.14 Install BPV. Pressure up on 3-1/2" x 7" annulus to 500psi, to test BPV from below. 5 min. 18.15 N/D BOP. 18.16 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. Terminate the cap strings. 18.17 Circulate diesel freeze protection down 3-1/2" x 7" annulus (Volume should equal capacity of tubing to 2500' +tubing annulus to 2500'). Connect IA to tree and allow diesel freeze protect to "U-tube" into position. Note — this may be done post -rig. 18.18 Pull BPV. Set TWC. Test tree to 250 psi low / 5000 psi high. Pull TWC. Set BPV. 18.19 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.20 Notify AOGCC of SVS testier Test SVS on horizontal run of tree within 5 days of the start of production Set low pressure trip below 275 psi Moose Pad header & separator pressure. 19.0 RDMO 19.1 RDMO Doyon 14 Page 39 H Hilcorp E. 4r 18.0 Run Jet Pump Completion Milne Point Unit M-10 SB Producer Drilling Procedure 18.1 Verify the Jet pump components. 18.2 Run the 3-1/2" Jet Pump Completion as noted by completion engineer. 18.3 M/U Jet Pump assembly and RIH to setting depth. i. Ensure appropriate well control crossovers on rig floor and ready. ii. Monitor displacement from wellbore while RIH. 18.4 Record PU and O weights before landing hanger. Note PU and band/clamp su 18.5 MU tubing hanger aN landing joint. Terminate control 18.6 Land tubing hanger. 18.7 RILDS and test hanger. L andinl 18.8 Install PV d N/D BOP. 18.9 N/Ut�adapter and tree. Test to the cap strings. 18.10 Circulate diesel freeze protection do tubing to 2500' + tubing annulus to "U-tube" into position. Note — this 18.11 Pull BPV. Set TWC. Test tree to 2 1� 8F✓ 18.12 Prepare to hand over well to produ with valve alignment as per oper7 19.0 RDMO 19.1 RDMO Doyon 14 Page 39 on tally along with joint.��' S ? hanger v/6id to 500 psi low/ 5000 psi high. Terminate I - / ' x 7" annulus (Volume should equal capacity of et IA to tree and allow diesel freeze protect to y e do �+ .lq q/ 00 psiir1 r TWC. Set BPV. i. Ensure nec sa `s filled out and well handed over personnel. ... ........ Y. r Date: 12/14/18 3-1/8" 11 Rig: Doyon 14 1.00 Manual valve � Well Number: MPM-10 0 1.56 Power Fluid11 _„_ .92 3-1/8" Actuated valve ---� O 1.56 3 -1/8 - Manual valve 4-1/16" 4-1/16" Actuated valve Manual valve Production A 11"-5K Flg. 1.56 0.72 0 2-1/16" rmanual valve FMC t I �d(o)..� 1 �] 2.25 O w 101 is Is. Manual valve 2.20 i; -- 0 H HiIC07 �VC®P�^9 20.0 Doyon 14 Diverter Schematic 21-44'2M Rm — 21 A;4' 2M- D"'r 21-114' 9 spa , Spa 16.3'4' JM 21-114'2M DS Page 40 Milne Point Unit M-10 SB Producer Drilling Procedure -16- fall Ope ng K" VAW �16'DNv Ll e H Hilcm 21.0 Doyon 14 BOP Schematic Kill Line�J Page 41 Milne Point Unit M-10 5B Producer Drilling Procedure 2-7/8" x 5" VBR Blind Rams x 5U HCR hoke Lme rl Gale Valve 2-7/8" x 5" VBR Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure U-= 22.0 Wellhead Schematic P w i 4 l.9 W 5 6G MC( H � P F.Ol*0O1wl -i ce - �Io(.izv .av- acI(r. ,:5,- `-�,_ `•�I rLL;j__-I�--Z �%rIY"Q I SI JL ry [P Y %lc R"ICC I 14 - l6:pL'r - o.wo uo.'•. ' F iLK[f f @Up015ll[-' 6bl)rPn I fTTrl E - . —Z.5: 3608Gx' I 1 5(3 S [ b'I I ry 66b+ i 'rt MO.EJ6'l5 r 4 .A l4 Y � M1IIC K eiOC. i0Y3 !IV f! f1 Si BOK r r B ..) eilroniiiiu u_ra u .r e( "r .n 9YG 0.1 6 5!. B!Y FL° 600 WC, 1{(. 101. aec D -:1 Ben'. b I'D 5EI) 5 SLIH HOLE Page 42 - l6:pL'r - F iLK[f f @Up015ll[-' rO IItih'. " 'k1H of ...._. -.._ k Itl4. rx5 rWS `" w�.Y6_A:30fJF➢_fL'rSa j 11r^_F,I. i M1r r,.. F F wr wlxer rF Ix r�YesPx. - C. rdzlt�l'� illf: 10-25 [ M116 _. - - — writs [a vi arum �� ..rxr �w.xo rFFwr x ICr-ZSIi Y:• . ... o.. ... r. � J. [EFit C-21 `�= Q6•1�OO277UO�s [-ll i —__ —cPF.P,mr L.rwo-.xr Page 42 H HHCOTU� 23.0 Days Vs Depth 0 male •m ME a MPU M-10 SB OA Producer Days vs Depth J N A a 10000 12000 Page 43 Milne Point Unit M-10 SB Producer Drilling Procedure 71 0 5 10 15 20 25 30 Days n Hilcorp E—d C^.2 24.0 Formation Tops & Information Milne Point Unit M-10 SB Producer Drilling Procedure MPU M-10 Formations (wp07) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 2623 2028 2087 918.28 8.46 SV1 2675 2059 2118 931.92 8.46 LA3 4827 3321 3380 1487.2 8.46 Schrader Bluff NA 5758 3793 3852 1694.88 8.46 Schrader Bluff OA 6515 3941 1 40M 1760 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORECAST D DESCRIPTION COMMENTS T Pit LITH u Oeet NOTE: Seo indwidual well Program for yaks Gulek spocKc casing design. depths. stem. •i.tes 600 weights, grafts and connections. o ' 1lncorso0blm coares m nwamm und and small parol w9T rNnarslibtone. IF SIGNIFICANT AMOUNTS OF GRAVEL 1,000• a° ARE ENCOUNTERE D WHE N DRIL LING THE �a SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. 17w' Base permafrost hbroeb of Baro, ckya aro Yltsmrss m ho¢asional 2,000 Now of coal. watch possiblealddrackiN wtele aasNnpre.min . L43 S Lt 5. s.g.r dna -eillIe. No hydrates encountered on L -Pad wells drilled to date. r :cedeoruea IdOmm of same cbys and uuamma wan s'l anova of coY. Tracoa of %*Ion at'(. 3100 It 3,000• hmnal at,/- Sem It can be sticky and light(LUI). pay hleroods belwotn 3000 and 4500 fl. C U72 - L A 3657 kun6LION Y U:Sono. ol.carumN lRward sands wmich are . 1 &C.0' mock, up d: (Rom lop m Eelmm) mann sera lioa sena. LQyshalo BeQer bralapea ldervenllg slulos sayw UGNU vmgnss mono tine Lam M(deeper). ugmandscnrader1110f Poss,blo nydroca.bom limited L^a^� m SWcomor of Milne dewlnpment Nmmm ane is I+aBI ftxmumcluro am wet. -3719' wenn bM it •4000' INA) Schrader Bluff Sands: 4,0 4,000 tabs. . ♦a Schrader Bluff: Possiblelostcirculation crept Lot E',n mos endorsed an! ilh ocrosandaal tion musionacoal. lone while drilling long strings and running vno' os^e. 0, ri.h7reoonbaeaand It tlay and ScoIWorva1tt. Possible hydrocarbons 119ru and scnnm7 elWr. vesslao Marocarboro umilaa casing. Recommend deep setting surface 1wJ Iae.aILC mswcomerof Munub.olopmont L4]andl.a5am rasing for Kupamk long strings. Also, the pa.sl esmplemam me smnbr BlWnam. Nonmmaroaa Schrader Bluff sands area potential SchraderL.Pad l.awalm we am tel. differential stuck pipe interval if left un -cased Bluff $ I i i..IN Wrt h smle mlow for Kuparuk long strings. Sands: sonracer Bl Wt Oe sand ler longer each work. I Page 44 n Hilcorp U— w. 25.0 Anticipated Drilling Hazards Milne Point Unit M-10 SB Producer Drilling Procedure 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates If Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: 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 45 Milne Point Unit M-10 SB Producer Drilling Procedure 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 142S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 142S. No 112S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 112S 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 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on this pad. Page 46 26.0 Dovon 14 i o 1 Io I 1111 Page 47 Milne Point Unit M-10 SB Producer Hilco Drilling Procedure 26.0 Dovon 14 i o 1 Io I 1111 Page 47 n Hilcorp F, C2p7 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-10 SB Producer Drilling Procedure 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 48 H HilMT- E^n®fmiW^Y 28.0 Doyon 14 Choke Manifold Schematic Milne Point Unit M-10 SB Producer Drilling Procedure Page 49 Milne Point Unit M-10 SB Producer Drilling Procedure 29.0 Casing Design 11 MR= ..e Calculation & Casing Design Factors DATE: 12/10/2018 WELL: MPU M-10 DESIGN BY: Joe Engel Criteria: Hole Size 12-1/4" Mud Density: 9.2 ppg Hole Size 8-1/2" Mud Density: 9.2 ppg Hole Size Mud Density: Drilling Mode MASP: 1359 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1359 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Page 50 Casing Section Calculation/Specification 1 2 3 4 Casing OD 95/8" 65/8" Top (MD) 0 6,498 Top (TVD) 0 3,998 Bottom (MD) 6,498 15,613 Bottom (TVD) 3,998 3,993 Length 6,498 9,115 Weight (ppi) 40 20 Grade L-80 L-60 Connection TV H563 Weight w/o Bouyancy Factor (lbs) 259792 182,300 Tension at Top of Section (lbs) 259,920 182,300 Min strength Tension (1000 lbs) 916 459 Worst Case Safety Factor (Tension) 3.52 2.i2 - Collapse Pressure at bottom (Psi) 1,975 1,973 Collapse Resistance w/o tension (Psi) 3,090 3,470 Worst Case Safety Factor (Collapse)1.56 1.76 MASP (psi) 11,359 1,359 Minimum Yield (psi) 5,750 1 6,090 Worst case safety factor (Burst) 4.23 4.48.' Page 50 n Hilcorp . r.p 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hilcoip 8-1/2" Hole Section `®'°' MPU M-10 Milne Point Unit MD TVD Planned Top: 6498 3998 Planned TD: 15613 3993 Milne Point Unit M-10 SB Producer Drilling Procedure Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 1 3,998 1 3,941 1 1759 1 Oil 8.46 0.440 Offset Well Mud Densities Well MW ranee° Too ITVDI Bottom fTVDI Date L-50 8.8-9.1 Surface 4125 2015 L-49 9.0-9.2 Surface 4196 2015 L-48 8.9-9.2 Surface 4147 2015 L-47 8.8-9.0 Surface 4158 2015 L-46 9.0-9.3 Surface 4177 2015 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore togas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,998 (ft) x 0.78(psi/ft)= 3118.4 3119(psi) - [0.1(psi/ft)*3998(ft)]= 2719 psi MASP from pore pressure (complete evacuation of wellbore togas from Schrader Bluff OA sand) 3998 (ft) x 0.44(psi/ft)= 1759 psi 1759(psi) - 0.1(psi/ft)*3998(ft) 1359.3 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 51 ti� K Hilcorp a. Wrp 31.0 Spider Plot (NAD 27) (Governmental Sections) Milne Point Unit M-10 SB Producer Drilling Procedure ItMilne Point Unit Alaska State Plane Zone4 NAD 1927 MPU M-10 Well 0 1,000 2,000 wp-07 wmmmnE== Feet Page 52 -14 `~'�1.°ate - Sm 1 A `,., SY E ,I ' 42- .:� \ ' l- f � ♦ r - Ire` 7. - /x'16251'•. Irr .. IT `r• Or �.• ."% '\♦ _ r Pea / U013N009EMILNE, I r A I Sec 17, '1 POINT/ ADL384235 ` 1 -0>. 'e' --t Sec. 13 Sm.16 rUNITV ° , AD `Sec'7i�i Sec. 11 Sec. 12, ` �, .-'Tq\� SE, 6 KUPARUK / , RIVER UNIT ADL355023 ` � `1j meq\ 11., r r r`• I r f r "Y ♦/ r 1 � r � r U013NOt0E ItMilne Point Unit Alaska State Plane Zone4 NAD 1927 MPU M-10 Well 0 1,000 2,000 wp-07 wmmmnE== Feet Page 52 -14 `r• �.• ."% '\♦ _ r Pea / U013N009EMILNE, I r A I Sec 17, '1 POINT/ Sec 14 Sec. 13 Sm.16 rUNITV , (630) r \ / , ADL025515 r f I` r e � r � r U013NOt0E I /I ADCO25514 //� ' ,19 Legend Sec 23 Say. 24 S (633) * K10 SHE / 1 X rh10_TPH / r I + 6410_BHL vu• / / MINE SITE - Other Surface Holes (SHL; avrez uan Other eoawn Hiles {BMLI •.______ ± -___ Olher Well Palls =QQIU,AE — Coastline (USGS 1:63k) .�. AAL KUPARUK Sec 26 I Sec. 25 RIVER UNR Sec. 30 Q 0a all Gas Unit Boundary _ ADL025519 A _ _ _ .(636) - • _ - _ - Pod Footpnrd ItMilne Point Unit Alaska State Plane Zone4 NAD 1927 MPU M-10 Well 0 1,000 2,000 wp-07 wmmmnE== Feet Page 52 Milne Point Unit M-10 SB Producer Hilco2 Drilling Procedure Eoe,67 �W^7 32.0 Surface Plat (As Built) (NAD 27) MC ISE PAD II I M-04 M-03 I I MPU MOOSE PAD NOTE& I I 1.A A STATE PUNS G"G. RDHAM AIS KAD27, ZOW 4. 2 MCOVC Po9 S APE KA 7. J. BARS OF HOROORAL AND VLAOGL CONTROL IS MOOSE PAD NO URENT M. 4. MW MDDSE PAD SYAE FACRM IS 0.11NI M. S. DATE OF SURAEn. SIPIOISFR 26. 2018. 0. RF)ERENCE Fob RNL MCi6-U PP. ] 3, Page 53 GRAPHIC SCALE 0 IOp S00 AOO (N/EET) 1 Intl =?W K ml ,SURVEYOR'S CERTIFICATE I `ERFAY CEIIIIPY THAT I AM 10 OPIRAACCTQ l AIRY NO IN THE STATE OF AL% ANO 1HAT M" BY Mf OR l" YY DFECT "M" " AND THAT ALL DIMENSIONS AND OTNER OVALS ARE CORRECT AS OF '3-PTEABfR 26. MO. e onnTosrTm cFr u T It N W 4 F.. IIMIAT MFRIGIAN_ ALASKA WELL 8E6 3 I GEODETIC SECTION CELLAR SEC. u COORDINATES POSITION DMS M M-10 BOX EL Y- 6,027,889.71 70'29-14.024" M-11 FSL I M-03 X- 533,363.90 149'43'3&285" 149.7273014' M-12 Y= 6.027,889.58 70'29'14.021" 70.4872281' I I M-04 23 149'43'37.405" 149.7270569' I ILEGEND, I+ AS -&TILT CONDUCTOR I 70'29'13.990" DUSTING CONDUCTOR f II I M-04 M-03 I I MPU MOOSE PAD NOTE& I I 1.A A STATE PUNS G"G. RDHAM AIS KAD27, ZOW 4. 2 MCOVC Po9 S APE KA 7. J. BARS OF HOROORAL AND VLAOGL CONTROL IS MOOSE PAD NO URENT M. 4. MW MDDSE PAD SYAE FACRM IS 0.11NI M. S. DATE OF SURAEn. SIPIOISFR 26. 2018. 0. RF)ERENCE Fob RNL MCi6-U PP. ] 3, Page 53 GRAPHIC SCALE 0 IOp S00 AOO (N/EET) 1 Intl =?W K ml ,SURVEYOR'S CERTIFICATE I `ERFAY CEIIIIPY THAT I AM 10 OPIRAACCTQ l AIRY NO IN THE STATE OF AL% ANO 1HAT M" BY Mf OR l" YY DFECT "M" " AND THAT ALL DIMENSIONS AND OTNER OVALS ARE CORRECT AS OF '3-PTEABfR 26. MO. e onnTosrTm cFr u T It N W 4 F.. IIMIAT MFRIGIAN_ ALASKA WELL A.S.P. GEODETIC GEODETIC SECTION CELLAR NO. COORDINATES POSITION DMS POSITION D.00 OFFSETS BOX EL Y- 6,027,889.71 70'29-14.024" 70.4872289'5.040' FSL 25.0' M-03 X- 533,363.90 149'43'3&285" 149.7273014' 801' FEL Y= 6.027,889.58 70'29'14.021" 70.4872281' 5,G40' FSL 25.0' M-04 X= 533,393.80 149'43'37.405" 149.7270569' 771' FEL Y= 8.027,889.65 70'29'13.990" 70.4872194' 5,037- FSL 24.9' 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= 534,023.88 149'43'18.865" 149.7219069' 141' FEL Y- 6,027.889.80 1 70'29'13.999" 70,4872219' 5.037- FSL 25.0' M-12 X- 533,933.89 1 149'43'21.513" 1 149.7226425' 1 231' FEL a Y�„�MLNE PONT, ALASKA __..PANT, ALASKA __.. MOOSE PAD, EEPOI T. T. 04, 10, f1, 12 1 R t ==MN T soo CONDUCTOR AS-BIXT Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure �-22 33.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs TVD MW, ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.110.310.5 0 A [TIT] m m 1500 2000 3= 2500 e 3500 WIN 4500 Page 54 —MPU L-46 (2015) —MPU L-47 (2015) —MPU L-48 (2015) . MPU L-49 (2015) —MPU L-50 (2015) —MPU F-106 (2017) —MPU F-107 (2017) —MPU F-108 (2017) —MPU F-109 (2017) —MPU F-110 (2017) H Hilcotp E ZT- Milne Point Unit M-10 SB Producer Drilling Procedure 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50 Drill Pipe Configuration Pipe Body OD - 5.000 Pipe Body Wall TNdmess on: 0.362 Pipe Body Grade S-135 Mill Pipe Length Tool Joint SMYS Connection GPDS50 Tod Joint OD 6.625 Tod Joint to 325D Pit Tong 9 Boz Tong m: 12 v Drill Pipe Performance . r Connection Performance 80 % Inson Class Nominal Weight Designation 79.50 Drill Pipe Approximate Length m131-5 SmoothEdge Height (-, r 2 Raised Tool Joint SMYS ow,120.000 Upset Type IEU Man Upset OD (DTE) riot 5.125 Friction Factor t.0 Nor'. Tarq:w==mJ, moon.. n" o, Drill -Pipe Length Range2 Nominal (re-xc W 2329 0.36 0.0085 0.72 00172 Tension Only 10 560.800 Orin Siu _ 1-13.125 cv„w,ea �en¢32, 100 467,400 Nor. on nNaomrem,..lz a2 xsealmz wr: onn ax.:zernNr vawez a,e mea eaernaes ane rtvY ✓�'( auc b uPe war n+n menrs.lrnernil rleXrmet-p onn -trier hcrr:. GPDS50 ( 6.625 m1 OD X 3.250 (-) to ) 120.000 (mn xon To-.nl-¢ee.o�e-oe, opernmm rnzr.aw.n rrul•ar.ue;n+ez;zw-z e. anon: Nominal Tod Jdnt Torsional Strength Tod Joint Tensile Strength W ) 171,800 i-rl 712.100 125D.ODD Elevator Shoulder Information SmoothEdge Helgh 3132 Raised wo-1 74.100 58,100 Box OD Ila 6.812 Elevator Ca ad 'u-11,658.0130 124 Assumed Elevator Bore Diameter r-: 5219 We Tool Joint Dimensions Belanred OO on 6.435 z�ren,n, T -N Jrn,l an -r MI 5.930 PfHnYm CIe55 full serrnun TON+mm oo m 5.93 771 canxvomm mol ITIX r7r7F�'. M to bevel I Won to Min TJ OD for Diameter AN Premium Clams ". EICiTV e�x-'.---m Ele.lone, ro'.ear feeler,.M con�act..e art xne: w n,lzm oo inc.Nlz[s<lC.uir w .aM elan.¢ Ra ,. .,- Pipe Pipe Body Slip Crushing Capacity Pipe B-ey Configuration r 5 (-1 OD 0.362 ( Wag S-135) Nominal 180 % Inspection Class I API Premium Class ter r9 Slio Crushing Capacity (-x)498.300 396.500 _ 396,500 roar voo- so.. .1.¢�m.m r.:�r,Rmaeem xr:•nan+naeazmleox Ass mad S11 L th (-116.5 vmmre]mairxru c. isavme vo mrgn ]mm,e,ers mamazwnwaa,re liTransverse Load Factor I Kl 14.2 1., rNzi°ea°'ieo+o'meso°6°z'm�em.a:n�memn"`lmzc"mrv''m". oe rawwarl.]w],,mvmnrumvs rawlv�oeaelvu¢ave"v ¢axes mmivoa,. Pipe Bodv Performance c.r Page 55 Pipe Body Configuration r 5 m1 OD 0.362 (-( Wall S-135) NIX°: NO nal Runt [Yarrtl e161.]X REW Nominal 80 % Inspection Class AN Premium Class Pipe Tensile Strep i-rl 712.100 560.800 550.800 Pipe Torworial strength wo-1 74.100 58,100 58,100 TXRpeBody Torsional Ratio 0.97 124 124 80% Pipe Torsional Strength o -mol 59.300 46 ,500 46,500 Burst 17,105 15,638 15,638 Collapse lovl 15.672 10,029 10.029 Pipe Do 4w 5.000 4.855 4.855 Wall Thickness e�10.362 0290 0290 Naninal Pipe ID tr 4276 4.276 4276 Cross Sectorial Area M Pi Bod l -al 5275 4.154 4.154 Cross Sectional Area of OD m•21 19.635 18.514 18.514 Cross Sectorial Area of ID l-^=1 14.360 114.360 14.360 Section Moduhe (r•315,708 14A76 4.476 Polar Section Modulus nn•3l 11.415 8.953 8.953 NIX°: NO nal Runt [Yarrtl e161.]X REW Milne Point Unit M-10 SB Producer Hilcorp Drilling Procedure E� �,�, 500204050016200 Weatherford 5" 19.50 lb1ft S-135 wl NC 50 6-518" OD x 3-114" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection NC 50 Interchangeable With 5" XH & 4-12" IF Upset Type IEU Nominal Weight per Foot 19.50 lbs Adjusted Weight With Tool Joint per Foot 23.08 IUs TOOL JOINT DATA Outside Diameter 6-5/8' Inside Diameter 3-1/4' API Drift 3-1/8' Rabbit OD. Suggested 3-1116" Minimum Make-up Torque 25.900 ft -lbs Maximum Recommend Make-up Torque 26.800 ft -lbs Torsional Yield Stren th 51,700 ft -lbs Tensile Strength 1,269.000 lbs TUBE DATA New Premium Outside Diameter 5.000" 4.855' Inside Diameter 4.276" 4.276' Wall Thickness 0.362" 0.290" Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook Load/Tensile Strength 712.000 lbs 560.800 lbs Slip Crushing /Slip Type (SDXL) 572,100 Itis 453,500 lbs Burst PresAth 17,100 psi 16.100 psi Collapse Pres 15,700 psi 10.000 psi Torsional Yield Stre 74 100 ft-Ibs 58.100 ft -IUs Ca aci W1 Tool 0.726 US auft 0.726 US aleft 0.353 US oatift 0.322 US gaVft Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss, damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 56 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10 M-10 Plan: M-10 wp07 Standard Proposal Report 05 December, 2018 HALLIBURTON Sperry Drilling Services HALLIBURTON Sperry Drilling Sec MD Inc Azi ND +N/ -S +EI -W Dleg TFace VSect Target 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 2 353.90 0.00 0.00 353.90 0.00 0.00 0.00 0.00 0.00 3 703.90 10.50 87.00 701.94 1.67 31.94 3.00 87.00 28.54 4 1794.61 54.10 83.25 1601.84 61.74 597.49 4.00 -4.40 521.67 5 5087.06 54.10 83.25 3532.35 375.25 3246.09 0.00 0.00. 2818.07 6 6298.52 84.00 124.91 3977.69 69.75 4290.37 4.00 62.04 3896.78 7 6498.52 84.00 124.91 3998.60 -44.08 4453.48 0.00 0.00 4091.97 Chamberlain Heel wp03 8 6686.39 89.64 124.94 4009.02 -151.43 4607.22 3.00 0.33 4275.97 912880.26 89.64 124.94 4048.36 -3698.89 9684.43 0.00 0.0010353.36 Chamberlain CP1 wp04 1012931.14 91.16 124.94 4048.01 -3728.03 9726.13 3.00 -0.0110403.28 11 15613.32 91.16 124.94 3993.60 -5263.92 11924.36 0.00 0.0013034.54 Chamberlain toe wp04 WELL DETAILS: MPU M-10 Ground Level: 24.90 +N/ -S +E/ -W Longitude Northing 4113. g 13.990 N 0.00 0.00 6027889.85 534113.80 70° 29' 13.990 N 149° 43' 16.219 W Annotation Start Dir 3°/100' : 353.9' MD, 353.97VD Start Dir 4°/100' : 703.9' MD, 701.94'ND End Dir : 1794.61' MD, 1601.84' ND Start Dir 4°/100' : 5087.06' MD, 3532.35'1VD End Dir : 6296.52' MD, 3977.69' ND Start Dir 3°/100' : 6498.52' MD, 3998.6'ND End Dir : 6686.39' MD, 4009.02' ND Start Dir 3°/100' : 12880.26' MD, 4048.36'ND End Dir : 12931.14' MD, 4048.01' ND Total Depth : 15613.32' MD, 3993.6' TVD Project., Milne Point Site: M pptt Mo9o�see Pad MPU M-10 Well: Ueslgn: nn ,p ""Pvr � Wellbore: M-10 SURVEY PROGRAM CASING DETAILS Ueslgn: nn ,p ""Pvr � Dete:2018-10-01TD0:00:OD Velideted:Yes Version: ND NDSS MD Size NameJ - 3998.55 3939.95 6498.00 9-5/8 9 5/8" x 12 1/4"�] - Depth From Depth To Survey/Plan Tool 3993.60 3935.00 15613.32 6-5/8 6 5/8" x 8 1/2' 33.70 6498.00 M-10 spO7 (M -1D) 2_MWD+IFR2+MS+Sag Hllco p Alaska, LLC 6498.00 15613.25 M-10 wp07(M-10) 2_MWD+IFR2+MS+Sag -- Calculation Method: Minimum Curvature Error System: ISCWSA REFERENCE INFORMATION Scan Methotl: Closest Approach 3D Error Surface: Pedal Curve Co-ordinate (NIE) Reference: Weil MPU M-00, True North Warning Method: Error Ratio Vortical (ND) Reference: M-10 IRKS @ 58.60usfl Measured Depth Reference: M-10 RKB @ 58.60ustl FORMATION TOP DETAILS Calculation Method: Minimum Curvature -750 No brmatbn tlata Is available 0 Start Dir 3°/100' : 353.9' MD, 353.9'TVD O 500 Start Dir 4°/100' : 703.9' MD, 701.94'ND 750 _1p0o HEndDir 0 :1794.61' MD, 1601.84' ND 0 0 m -6 �o 5 _ - M o $ o D 1500 N O m n O o -�VO o m °+ m �ry ro 0 2250 ADO o N �b o) v m yoo b > O D m m 3000 ay0 n n O a 3750 O O O O O O O O u) O ro oA n m m m ce N O r- 6 5/8" x 8 1/2" 9 5/8" x 12 1/4" 0 0 0 0 o w M-10 wp07 4500 Chamberlain Heel wp03 Chamberlain CP1 wpO4 Chamberlain toe wp04 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 Vertical Section at 113.82° (1500 usft/in) i 30001 HALLIBLIRTON CASING DETAILS Project: Milne Point TVD TVDSS MD Si:. Name Site: M Pt Moose Pad sRenry onnns 3998.55 3939.95 6498.00 9-5/8 95/R"x121/4" Well: MPU M-10 3993.60 3935.00 15613.32 6-5/8 6 5/8^ x R ur' Wellbore: M-10 ® Plan: M-10 wp07 Stan Dir 3•/100':353.9' MD, 353.97VD Slaty Dir 4"/ID0': 5087.06'MD, 3532.35TVD F,tM Dir : 6298.52' MD, 3977.69' TVD 9 5/8" x 12 1/4" WELL DFrAILS: MPU M-10 +N/ -S +Fl -W O hnd Level: 24.90 0.00 0,00 Noshing Easfing Iatiltude Longitude 6D27889.65 534113.80 70° 29' 13.990 N 14V 43' 16.219 W Stan Dir 3"/100': 6498.52' MD, 3998,6TVD Gd Dir : 6686.39'MD,4009.02'TVD REFERENCE INFORMATION Qo-ci4rate (NIE) Reference: Well MPU M-ia Tme NOM Ve, ical (TVD) Reference: M-10 RKB @ M.60ua0 MeesuM Depth Reference: M-10 RKB @ N,60usX Calcula8on Method: Minimum Cumhum 1 C1Mn5crbm Heel wp03 ChanlSedam CPI Sud Dir 3°/IDD' : 12880.26' MD, 4D48.36 -WD End Dir : 12931.IP MD, 404801'TVD Total Dcpth : 15613.32'141. 3993.6 TVD 6 5/8" x 8 In" M-10 WP07 C'Itvtbedain trc up04 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 West( -)/East(+) (1500 usft/in) HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: M-10 Design: M-10 wp07 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well MPU M-10 TVD Reference: M-10 RKB @ 58.60usft MD Reference: M-10 RKB @ 58.60usft North Reference: True Survey Calculation Method: Minimum Curvature 'roject 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: Northing: 6,027,877.65 usft Latitude: 70' 29'13.905 N From: Map Easting: 533,363.92usft Longitude: 149'43'38.286 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: 0.26 ° Well MPU M-10 Well Position +NI -S 0.00 usft Northing: 6,027,889.65 usfl Latitude: 70° 29' 13.990 N +E/ -W 0.00 usft Easting: 534,113.80 usft Longitude: 149° 43' 16.219 W Position Uncertainty 0.00 usft Wellhead Elevation: 24.90 usfl Ground Level: 24.90 usft Wellbore M-10 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (1 (nT) BGGM2018 10/1/2018 16.98 80.98 57,449.91575736 Design M-10 wp07 Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +NIS +E/ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 113.82 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 33.70 0.00 0.00 33.70 -24.90 0.00 0.00 0.00 0.00 0.00 0.00 353.90 0.00 0.00 353.90 29530 0.00 0.00 0.00 0.00 0.00 0.00 703.90 10.50 87.00 701.94 643.34 1.67 31.94 3.00 3.00 0.00 87.00 1,794.61 54.10 83.25 1,601.84 1,543.24 61.74 597.49 4.00 4.00 -0.34 -4.40 5,087.06 54.10 83.25 3,532.35 3,473.75 375.25 3,246.09 0.00 0.00 0.00 0.00 6,298.52 84.00 124.91 3,977.69 3,919.09 69.75 4,290.37 4.00 2.47 3.44 62.04 6,498.52 84.00 124.91 3,998.60 3,940.00 44.08 4,453.48 0.00 0.00 0.00 0.00 6,686.39 89.64 124.94 4,009.02 3,950.42 -151.43 4,607.22 3.00 3.00 0.02 0.33 12,880.26 89.64 124.94 4,048.36 3.989.76 -3,698.89 9,684.43 0.00 0.00 0.00 0.00 12,931.14 91.16 124.94 4,048.01 3,989.41 -3,728.03 9,726.13 3.00 3.00 0.00 -0.01 15,613.32 91.16 124.94 3,993.60 3,935.00 -5,263.92 11,924.36 0.00 0.00 0.00 0.00 12152018 6:21.09PM Page 2 COMPASS 5000.15 Build 91 Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Coordinate Reference: Well MPU M-10 Company: Hilcorp Alaska, LLC TVD Reference: M-10 RKB @ 58.60usft Project: Milne Point MD Reference: M-10 RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: MPU M-10 Survey Calculation Method: Minimum Curvature Wellbore: M-10 Design: M-10 wp07 Planned Survey _ Measured Vertical Map Map Depth Inclination Azimuth Depth NDss +NIS +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -24.90 33.70 0.00 0.00 33.70 -24.90 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 100.00 0.00 0.00 100.00 41.40 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 200.00 0.00 0.00 200.00 141.40 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 300.00 0.00 0.00 300.00 241.40 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 353.90 0.00 0.00 353.90 295.30 0.00 0.00 6,027,889.65 534,113.80 0.00 0.00 Start Dir 71100' : 353.9' MD, 353.9'TVD 400.00 1.38 87.00 400.00 341.40 0.03 0.56 6,027,889.68 534,114.36 3.00 0.50 500.00 4.38 87.00 499.86 441.26 0.29 5.58 6,027,889.97 534,119.38 3.00 4.98 600.00 7.38 87.00 599.32 540.72 0.83 15.81 6,027,890.55 534,129.61 3.00 14.13 700.00 10.38 87.00 698.11 639.51 1.64 31.23 6,027,891.43 534,145.02 3.00 27.91 703.90 10.50 87.00 701.94 643.34 1.67 31.94 6,027,891.47 534,145.73 3.00 28.54 Start Dir 4°1100' : 703.9' MD, 701.94'TVD 800.00 14.34 85.81 795.78 737.18 3.00 52.55 6,027,892.89 534,166.34 4.00 46.87 900.00 18.33 85.09 891.72 833.12 5.25 80.58 6,027,895.27 534,194.35 4.00 71.60 1,000.00 22.33 84.62 985.48 926.88 8.38 115.17 6,027,898.56 534,228.92 4.00 101.98 1,100.00 26.33 84.29 1,076.58 1,017.98 12.37 156.16 6,027,902.73 534,269.89 4.00 137.87 1,200.00 30.32 84.04 1,164.59 1,105.99 17.20 203.35 6,027,907.78 534,317.05 4.00 179.09 1,300.00 34.32 83.84 1,249.08 1,190.48 22.85 256.51 6,027,913.67 534,370.18 4.00 225.44 1,400.00 38.32 83.68 1,329.63 1,271.03 29.28 315.38 6,027,920.38 534,429.01 4.00 276.69 1,500.00 42.32 83.55 1,405.86 1,347.26 36.48 379.67 6,027,927.87 534,493.26 4.00 332.60 1,600.00 46.32 83.43 1,477.39 1,418.79 44.40 449.07 6,027,936.10 534,562.62 4.00 392.89 1,700.00 50.32 83.33 1,543.88 1,485.28 53.00 523.25 6,027,945.05 534,636.75 4.00 457.28 1,794.61 54.10 83.25 1,601.84 1,543.24 61.74 597.49 6,027,954.12 534,710.94 4.00 521.67 End Dir : 1794.61' MD, 1601.84' ND 1,800.00 54.10 83.25 1,605.00 1,546.40 62.25 601.82 6,027,954.65 534,715.27 0.00 525.43 1,900.00 54.10 83.25 1,663.63 1,605.03 71.77 682.27 6,027,964.54 534,795.66 0.00 595.17 2,000.00 54.10 83.25 1,722.27 1,663.67 81.29 762.71 6,027,974.43 534,876.06 0.00 664.92 2,100.00 54.10 83.25 1,780.90 1,722.30 90.82 843.16 6,027,984.32 534,956.45 0.00 734.67 2,200.00 54.10 83.25 1,839.54 1,780.94 100.34 923.60 6,027,994.21 535,036.84 0.00 804.42 2,300.00 54.10 83.25 1,898.17 1,839.57 109.86 1,004.05 6,028,004.10 535,117.23 0.00 874.16 2,400.00 54.10 83.25 1,956.81 1,898.21 119.38 1,084.49 6,028,013.99 535,197.63 0.00 943.91 2,500.00 54.10 83.25 2,015.44 1,956.84 128.91 1,164.94 6,028,023.88 535,278.02 0.00 1,013.66 2,600.00 54.10 83.25 2,074.07 2,015.47 138.43 1,245.38 6,028,033.77 535,358.41 0.00 1,083.41 2,700.00 54.10 83.25 2,132.71 2,074.11 147.95 1,325.83 6,028,043.67 535,438.80 0.00 1,153.15 2,800.00 54.10 83.25 2,191.34 2,132.74 157.47 1,406.27 6,028,053.56 535,519.19 0.00 1,222.90 2,900.00 54.10 83.25 2,249.98 2,191.38 166.99 1,486.71 6,028,063.45 535,599.59 0.00 1,292.65 3,000.00 54.10 83.25 2,308.61 2,250.01 176.52 1,567.16 6,028,073.34 535,679.98 0.00 1,362.40 3,100.00 54.10 83.25 2,367.25 2,308.65 186.04 1,647.60 6,028,083.23 535,760.37 0.00 1,432.14 3,200.00 54.10 83.25 2,425.88 2,367.28 195.56 1,728.05 6,028,093.12 535,840.76 0.00 1,501.89 3,300.00 54.10 83.25 2,484.51 2,425.91 205.08 1,808.49 6,028,103.01 535,921.15 0.00 1,571.64 3,400.00 54.10 83.25 2,543.15 2,484.55 214.61 1,888.94 6,028,112.90 536,001.55 0.00 1,641.39 3,500.00 54.10 83.25 2,601.78 2,543.18 224.13 1,969.38 6,028,122.79 536,081.94 0.00 1,711.13 3,600.00 54.10 83.25 2,660.42 2,601.82 233.65 2,049.83 6,028,132.68 536,162.33 0.00 1,780.88 3,700.00 54.10 83.25 2,719.05 2,660.45 243.17 2,130.27 6,028,142.57 536,242.72 0.00 1,850.63 3,800.00 54.10 83.25 2,777.69 2,719.09 252.70 2,210.72 6,028,152.46 536,323.12 0.00 1,920.38 12/52018 6:21.09PM Page 3 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well MPU M-10 Company: Hilcorp Alaska, LLC ND Reference: M-10 RKB @ 58.60usft Project: Milne Point MD Reference: M-10 IRKS @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: MPU M-10 Survey Calculation Method: Minimum Curvature Wellbore: M-10 TVDss +N/ -S Design: M-10 wp07 Northing 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) 2,777.72 3,900.00 54.10 83.25 2,836.32 2,777.72 262.22 2,291.16 6,028,162.35 536,403.51 0.00 1,990.12 4,000.00 54.10 83.25 2,894.96 2,836.36 271.74 2,371.61 6,028,172.24 536,483.90 0.00 2,059.87 4,100.00 54.10 83.25 2,953.59 2,894.99 281.26 2,452.05 6,028,182.13 536,564.29 0.00 2,129.62 4,200.00 54.10 83.25 3,012.22 2,953.62 290.78 2,532.49 6,028,192.02 536,644.68 0.00 2,199.37 4,300.00 54.10 83.25 3,070.86 3,012.26 300.31 2,612.94 6,028,201.91 536,725.08 0.00 2,269.11 4,400.00 54.10 83.25 3,129.49 3,070.89 309.83 2,693.38 6,028,211.80 536,805.47 0.00 2,338.86 4,500.00 54.10 83.25 3,188.13 3,129.53 319.35 2,773.83 6,028,221.69 536,885.86 0.00 2,408.61 4,600.00 54.10 83.25 3,246.76 3,188.16 328.87 2,854.27 6,028,231.58 536,966.25 0.00 2,478.36 4,700.00 54.10 83.25 3,305.40 3,246.80 338.40 2,934.72 6,028,241.47 537,046.65 0.00 2,548.10 4,800.00 54.10 83.25 3,364.03 3,305.43 347.92 3,015.16 6,028,251.36 537,127.04 0.00 2,617.85 4,900.00 54.10 83.25 3,422.66 3,364.06 357.44 3,095.61 6,028,261.25 537,207.43 0.00 2,687.60 5,000.00 54.10 83.25 3,481.30 3,422.70 366.96 3,176.05 6,028,271.14 537,287.82 0.00 2,757.35 5,087.06 54.10 83.25 3,532.35 3,473.75 375.25 3,246.09 6,028,279.75 537,357.81 0.00 2,818.07 Start Dir 4°1100' : 5087.06' MD, 3532.357VD 5,100.00 54.35 83.81 3,539.91 3,481.31 376.44 3,256.52 6,028,280.98 537,368.24 4.00 2,827.13 5,200.00 56.32 88.04 3,596.81 3,538.21 382.24 3,338.52 6,028,287.16 537,450.21 4.00 2,899.81 5,300.00 58.42 92.08 3,650.74 3,592.14 382.11 3,422.71 6,028,287.42 537,534.38 4.00 2,976.88 5,400.00 60.65 95.94 3,701.45 3,642.85 376.05 3,508.66 6,028,281.75 537,620.36 4.00 3,057.96 5,500.00 62.99 99.62 3,748.68 3,690.08 364.10 3,595.97 6,028,270.20 537,707.71 4.00 3,142.66 5,600.00 65.42 103.15 3,792.20 3,733.60 346.30 3,684.20 6,028,252.81 537,796.01 4.00 3,230.56 5,700.00 67.92 106.55 3,831.81 3,773.21 322.75 3,772.93 6,028,229.67 537,884.84 4.00 3,321.24 5,800.00 70.50 109.82 3,867.31 3,808.71 293.56 3,861.72 6,028,200.89 537,973.75 4.00 3,414.26 5,900.00 73.13 112.99 3,898.53 3,839.93 258.87 3,950.14 6,028,166.61 538,062.32 4.00 3,509.15 6,000.00 75.81 116.08 3,925.31 3,866.71 218.85 4,037.76 6,028,127.00 538,150.11 4.00 3,605.47 6,100.00 78.52 119.09 3,947.52 3,888.92 173.70 4,124.15 6,028,082.25 538,236.71 4.00 3,702.74 6,200.00 81.27 122.04 3,965.07 3,906.47 123.64 4,208.90 6,028,032.58 538,321.67 4.00 3,800.49 6,298.52 84.00 124.91 3,977.69 3,919.09 69.75 4,290.38 6,027,979.07 538,403.39 4.00 3,896.79 End Dir : 6298.52' MD, 3977.69' TVD 6,300.00 84.00 124.91 3,977.85 3,919.25 68.90 4,291.58 6,027,978.23 538,404.60 0.00 3,898.23 6,400.00 84.00 124.91 3,988.30 3,929.70 11.99 4,373.14 6,027,921.70 538,486.41 0.00 3,995.83 6,498.00 84.00 124.91 3,998.55 3,939.95 43.79 4,453.06 6,027,866.29 538,566.58 0.00 4,091.47 9 518" x 12 114" 6,498.52 84.00 124.91 3,998.60 3,940.00 44.08 4,453.49 6,027,866.00 538,567.00 0.00 4,091.98 Start Dir 3-1100': 6496.52' MD, 3998.6'TVD 6,500.00 84.04 124.91 3,998.75 3,940.15 44.93 4,454.70 6,027,865.16 538,56821 3.01 4,093.42 6,600.00 87.04 124.93 4,006.52 3,947.92 -101.99 4,536.43 6,027,808.48 538,650.21 3.00 4,191.24 6,686.39 89.64 124.94 4,009.02 3,950.42 -151.43 4,607.22 6,027,759.36 538,721.21 3.00 4,275.97 End Dir : 6686.39' MD, 4009.02' TVD 6,700.00 89.64 124.94 4,009.11 3,950.51 -159.23 4,618.38 6,027,751.62 538,732.40 0.00 4,289.32 6,800.00 89.64 124.94 4,009.75 3,951.15 -216.50 4,700.35 6,027,694.73 538,814.63 0.00 4,387.44 6,900.00 89.64 124.94 4,010.38 3,951.78 -273.78 4,782.32 6,027,637.84 538,896.85 0.00 4,485.55 7,000.00 89.64 124.94 4,011.02 3,952.42 -331.05 4,864.29 6,027,580.95 538,979.08 0.00 4,583.68 7,100.00 89.64 124.94 4,011.65 3,953.05 -388.32 4,946.26 6,027,524.06 539,061.30 0.00 4,681.80 7,200.00 89.64 124.94 4,012.29 3,953.69 -445.60 5,028.24 6,027,467.16 539,143.53 0.00 4,779.92 7,300.00 89.64 124.94 4,012.92 3,954.32 -502.87 5,110.21 6,027,410.27 539,225.76 0.00 4,878.04 12/52018 6:21: 09PM Page 4 COMPASS 5000.15 Build 91 Planned Survey Measured Halliburton H A LL I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well MPU K10 Company: Hilcorp Alaska, LLC TVD Reference: M-10 RKB @ 58.60usft Project: Milne Point MD Reference: M-10 RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: MPU M-10 Survey Calculation Method: Minimum Curvature Wellbore: M-10 TVDss +Nl-S Design: M-10 wp07 +E/ -W Northing Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +Nl-S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,954.96 7,400.00 89.64 124.94 4,013.56 3,954.96 -560.14 5,192.18 6,027,353.38 539,307.98 0.00 4,976.16 7,500.00 89.64 124.94 4,014.19 3,955.59 -617.42 5,274.15 6,027,296.49 539,390.21 0.00 5,074.28 7,600.00 89.64 124.94 4,014.83 3,956.23 -674.69 5,356.12 6,027,239.60 539,472.43 0.00 5,172.40 7,700.00 89.64 124.94 4,015.46 3,956.86 -731.97 5,438.09 6,027,182.71 539,554.66 0.00 5,270.52 7,800.00 89.64 124.94 4,016.10 3,957.50 -789.24 5,520.06 6,027,125.82 539,636.88 0.00 5,368.64 7,900.00 89.64 124.94 4,016.73 3,958.13 -846.51 5,602.04 6,027,068.92 539,719.11 0.00 5,466.76 8,000.00 89.64 124.94 4,017.37 3,958.77 -903.79 5,684.01 6,027,012.03 539,801.33 0.00 5,564.88 8,100.00 89.64 124.94 4,018.00 3,959.40 -961.06 5,765.98 6,026,955.14 539,883.56 0.00 5,663.00 8,200.00 89.64 124.94 4,018.64 3,960.04 -1,018.33 5,847.95 6,026,898.25 539,965.78 0.00 5,761.12 8,300.00 89.64 124.94 4,019.27 3,960.67 -1,075.61 5,929.92 6,026,841.36 540,048.01 0.00 5,859.24 8,400.00 89.64 124.94 4,019.91 3,961.31 -1,132.88 6,011.89 6,026,784.47 540,130.23 0.00 5,957.36 8,500.00 89.64 124.94 4,020.54 3,961.94 -1,190.15 6,093.86 6,026,727.58 540,212.46 0.00 6,055.47 8,600.00 89.64 124.94 4,021.18 3,962.58 -1,247.43 6,175.84 6,026,670.68 540,294.68 0.00 6,153.59 8,700.00 89.64 124.94 4,021.81 3,963.21 -1,304.70 6,257.81 6,026,613.79 540,376.91 0.00 6,251.71 8,800.00 89.64 124.94 4,022.45 3,963.85 -1,361.98 6,339.78 6,026,556.90 540,459.13 0.00 6,349.83 8,900.00 89.64 124.94 4,023.08 3,964.48 -1,419.25 6,421.75 6,026,500.01 540,541.36 0.00 6,447.95 9,000.00 89.64 124.94 4,023.72 3,965.12 -1,476.52 6,503.72 6,026,443.12 540,623.58 0.00 6,546.07 9,100.00 89.64 124.94 4,024.35 3,965.75 -1,533.80 6,585.69 6,026,386.23 540,705.81 0.00 6,644.19 9,200.00 89.64 124.94 4,024.99 3,966.39 -1,591.07 6,667.67 6,026,329.34 540,788.03 0.00 6,742.31 9,300.00 89.64 124.94 4,025.62 3,967.02 -1,648.34 6,749.64 6,026,272.44 540,870.26 0.00 6,840.43 9,400.00 89.64 124.94 4,026.26 3,967.66 -1,705.62 6,831.61 6,026,215.55 540,952.49 0.00 6,938.55 9,500.00 89.64 124.94 4,026.89 3,968.29 -1,762.89 6,913.58 6,026,158.66 541,034.71 0.00 7,036.67 9,600.00 89.64 124.94 4,027.53 3,968.93 -1,820.17 6,995.55 6,026,101.77 541,116.94 0.00 7,134.79 9,700.00 89.64 124.94 4,028.16 3,969.56 -1,877.44 7,077.52 6,026,044.88 541,199.16 0.00 7,232.91 9,800.00 89.64 124.94 4,028.80 3,970.20 -1,934.71 7,159.49 6,025,987.99 541,281.39 0.00 7,331.03 9,900.00 89.64 124.94 4,029.43 3,970.83 -1,991.99 7,241.47 6,025,931.10 541,363.61 0.00 7,429.15 10,000.00 89.64 124.94 4,030.07 3,971.47 -2,049.26 7,323.44 6,025,874.20 541,445.84 0.00 7,527.27 10,100.00 89.64 124.94 4,030.70 3,972.10 -2,106.53 7,405.41 6,025,817.31 541,528.06 0.00 7,625.39 10,200.00 89.64 124.94 4,031.34 3,972.74 -2,163.81 7,487.38 6,025,760.42 541,610.29 0.00 7,723.50 10,300.00 89.64 124.94 4,031.97 3,973.37 -2,221.08 7,569.35 6,025,703.53 541,692.51 0.00 7,821.62 10,400.00 89.64 124.94 4,032.61 3,974.01 -2,278.35 7,651.32 6,025,646.64 541,774.74 0.00 7,919.74 10,500.00 89.64 124.94 4,033.24 3,974.64 -2,335.63 7,733.29 6,025,589.75 541,856.96 0.00 8,017.86 10,600.00 89.64 124.94 4,033.88 3,975.28 -2,392.90 7,815.27 6,025,532.85 541,939.19 0.00 8,115.98 10,700.00 89.64 124.94 4,034.51 3,975.91 -2,450.18 7,897.24 6,025,475.96 542,021.41 0.00 8,214.10 10,800.00 89.64 124.94 4,035.15 3,976.55 -2,507.45 7,979.21 6,025,419.07 542,103.64 0.00 8,312.22 10,900.00 89.64 124.94 4,035.78 3,977.18 -2,564.72 8,061.18 6,025,362.18 542,185.86 0.00 8,410.34 11,000.00 89.64 124.94 4,036.42 3,977.82 -2,622.00 8,143.15 6,025,305.29 542,268.09 0.00 8,508.46 11,100.00 89.64 124.94 4,037.05 3,978.45 -2,679.27 8,225.12 6,025,248.40 542,350.31 0.00 8,606.58 11,200.00 89.64 124.94 4,037.69 3,979.09 -2,736.54 8,307.09 6,025,191.51 542,432.54 0.00 8,704.70 11,300.00 89.64 124.94 4,038.32 3,979.72 -2,793.82 8,389.07 6,025,134.61 542,514.76 0.00 8,802.82 11,400.00 89.64 124.94 4,038.96 3,980.36 -2,851.09 8,471.04 6,025,077.72 542,596.99 0.00 8,900.94 11,500.00 89.64 124.94 4,039.59 3,980.99 -2,908.36 8,553.01 6,025,020.83 542,679.21 0.00 8,999.06 11,600.00 89.64 124.94 4,040.23 3,981.63 -2,965.64 8,634.98 6,024,963.94 542,761.44 0.00 9,097.18 11,700.00 89.64 124.94 4,040.86 3,982.26 -3,022.91 8,716.95 6,024,907.05 542,843.67 0.00 9,195.30 11,800.00 89.64 124.94 4,041.50 3,982.90 -3,080.19 8,798.92 6,024,850.16 542,925.89 0.00 9,293.42 12/52018 6:21:09PM Page 5 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well MPU M1-10 Company: Hilcorp Alaska, LLC TVD Reference: M-10 RKB @ 58.60usft Project: Milne Point MD Reference: M-10 RKB @ 58.60usft Site: M Pt Moose Pad North Reference: True Well: MPU M-10 Survey Calculation Method: Minimum Curvature Wellbore: M-10 Design: M-10 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +Nl-S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3,983.53 11,900.00 89.64 124.94 4,042.13 3,983.53 -3,137.46 8,880.90 6,024,793.27 543,008.12 0.00 9,391.53 12,000.00 89.64 124.94 4,042.77 3,984.17 -3,194.73 8,962.87 6,024,736.37 543,090.34 0.00 9,489.65 12,100.00 89.64 124.94 4,043.40 3,984.80 -3,252.01 9,044.84 6,024,679.48 543,172.57 0.00 9,587.77 12,200.00 89.64 124.94 4,044.04 3,985.44 -3,309.28 9,126.81 6,024,622.59 543,254.79 0.00 9,685.89 12,300.00 89.64 124.94 4,044.67 3,986.07 -3,366.55 9,208.78 6,024,565.70 543,337.02 0.00 9,784.01 12,400.00 89.64 124.94 4,045.31 3,986.71 -3,423.83 9,290.75 6,024,508.81 543,419.24 0.00 9,882.13 12,500.00 89.64 124.94 4,045.95 3,987.35 -3,481.10 9,372.72 6,024,451.92 543,501.47 0.00 9,980.25 12,600.00 89.64 124.94 4,046.58 3,987.98 -3,538.37 9,454.70 6,024,395.03 543,583.69 0.00 10,078.37 12,700.00 89.64 124.94 4,047.22 3,988.62 -3,595.65 9,536.67 6,024,338.13 543,665.92 0.00 10,176.49 12,800.00 89.64 124.94 4,047.85 3,989.25 -3,652.92 9,618.64 6,024,281.24 543,748.14 0.00 10,274.61 12,880.26 89.64 124.94 4,048.36 3,989.76 -3,698.89 9,684.43 6,024,235.58 543,814.14 0.00 10,353.36 Start Dir 3-1100' : 12880.26' MD, 4048.36'TVD 12,900.00 90.23 124.94 4,048.38 3,989.78 -3,710.20 9,700.61 6,024,224.35 543,830.37 3.00 10,372.73 12,931.14 91.16 124.94 4,048.01 3,989.41 -3,728.03 9,726.13 6,024,206.64 543,855.97 3.00 10,403.28 End Dir : 12931.14' MD, 4048.01' TVD 13,000.00 91.16 124.94 4,046.61 3,988.01 -3,767.46 9,782.57 6,024,167.47 543,912.58 0.00 10,470.83 13,100.00 91.16 124.94 4,044.58 3,985.98 -3,824.72 9,864.53 6,024,110.59 543,994.79 0.00 10,568.94 13,200.00 91.16 124.94 4,042.55 3,983.95 -3,881.99 9,946.48 6,024,053.71 544,077.00 0.00 10,667.04 13,300.00 91.16 124.94 4,040.52 3,981.92 -3,939.25 10,028.44 6,023,996.83 544,159.21 0.00 10,765.14 13,400.00 91.16 124.94 4,038.50 3,979.90 -3,996.51 10,110.40 6,023,939.95 544,241.42 0.00 10,863.24 13,500.00 91.16 124.94 4,036.47 3,977.87 -4,053.77 10,192.35 6,023,883.07 544,323.63 0.00 10,961.34 13,600.00 91.16 124.94 4,034.44 3,975.84 -4,111.04 10,274.31 6,023,826.19 544,405.84 0.00 11,059.44 13,700.00 91.16 124.94 4,032.41 3,973.81 -4,168.30 10,356.27 6,023,769.31 544,488.05 0.00 11,157.54 13,800.00 91.16 124.94 4,030.38 3,971.78 -4,225.56 10,438.22 6,023,712.43 544,570.26 0.00 11,255.64 13,900.00 91.16 124.94 4,028.35 3,969.75 -4,282.82 10,520.18 6,023,655.55 544,652.47 0.00 11,353.75 14,000.00 91.16 124.94 4,026.32 3,967.72 -4,340.09 10,602.14 6,023,598.66 544,734.68 0.00 11,451.85 14,100.00 91.16 124.94 4,024.30 3,965.70 -4,397.35 10,684.09 6,023,541.78 544,816.89 0.00 11,549.95 14,200.00 91.16 124.94 4,022.27 3,963.67 -4,454.61 10,766.05 6,023,484.90 544,899.10 0.00 11,648.05 14,300.00 91.16 124.94 4,020.24 3,961.64 -4,511.87 10,848.01 6,023,428.02 544,981.31 0.00 11,746.15 14,400.00 91.16 124.94 4,018.21 3,959.61 -4,569.14 10,929.96 6,023,371.14 545,063.53 0.00 11,844.25 14,500.00 91.16 124.94 4,016.18 3,957.58 -4,626.40 11,011.92 6,023,314.26 545,145.74 0.00 11,942.35 14,600.00 91.16 124.94 4,014.15 3,955.55 -4,683.66 11,093.88 6,023,257.38 545,227.95 0.00 12,040.46 14,700.00 91.16 124.94 4,012.13 3,953.53 -4,740.93 11,175.83 6,023,200.50 545,310.16 0.00 12,138.56 14,800.00 91.16 124.94 4,010.10 3,951.50 -4,798.19 11,257.79 6,023,143.62 545,392.37 0.00 12,236.66 14,900.00 91.16 124.94 4,008.07 3,949.47 -4,855.45 11,339.74 6,023,086.74 545,474.58 0.00 12,334.76 15,000.00 91.16 124.94 4,006.04 3,947.44 -4,912.71 11,421.70 6,023,029.86 545,556.79 0.00 12,432.86 15,100.00 91.16 124.94 4,004.01 3,945.41 -4,969.98 11,503.66 6,022,972.98 545,639.00 0.00 12,530.96 15,200.00 91.16 124.94 4,001.98 3,943.38 -5,027.24 11,585.61 6,022,916.10 545,721.21 0.00 12,629.06 15,300.00 91.16 124.94 3,999.96 3,941.36 -5,084.50 11,667.57 6,022,859.22 545,803.42 0.00 12,727.16 15,400.00 91.16 124.94 3,997.93 3,939.33 -5,141.76 11,749.53 6,022,802.34 545,885.63 0.00 12,825.27 15,500.00 91.16 124.94 3,995.90 3,937.30 -5,199.03 11,831.48 6,022,745.46 545,967.84 0.00 12,923.37 15,600.00 91.16 124.94 3,993.87 3,935.27 -5,256.29 11,913.44 6,022,688.58 546,050.05 0.00 13,021.47 15,613.32 91.16 124.94 3,993.60 3,935.00 -5,263.92 11,924.36 6,022,681.00 546,061.00 0.00 13,034.54 Total Depth : 15613.32' MD, 3993.6' TVD - 6 518" x 8112" 12/52018 6:21:09PM Page 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: MPU M-10 Wellbore: M-10 Design: M-10 wp07 Targets Target Name - hit/miss target - Shape Chamberlain CPI wp04 - plan hits target center - Point Chamberlain Heel wp03 - plan hits target center - Point Chamberlain toe wli - plan hits target center - Point Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well MPU M-10 M-10 RKB @ 58.60usft M-10 RKB @ 58.60usft True Minimum Curvature Dip Angle Dip Dir. TVD +Nl-S +E/ -W Northing Easting (`) (I (usft) (usft) (usft) (usft) (usft) 0.00 0.00 4,048.36 -3,698.89 9,684.43 6,024,235.58 543,814.14 0.00 0.00 3,998.60 44.08 4,453.48 6,027,866.00 538,567.00 0.00 0.00 3,993.60 -5,263.92 11,924.36 6,022,681.00 546,061.00 9-5/8 12-1/4 6-5/8 8-1/2 Comment Start Dir 30/100': 353.9' MD, 353.9'TVD Start Dir 4°/100' : 703.9' MD, 701.94'TVD End Dir : 1794.61' MD, 1601.84' TVD Start Dir 4°/100' : 5087.06' MD, 3532.35'TVD End Dir : 6298.52' MD, 3977.69' ND Start Dir 3°/100' : 6498.52' MD, 3998.6'TVD End Dir : 6686.39' MD, 4009.02' TVD Start Dir 3°/100' : 12880.26' MD, 4048.36'TVD End Dir : 12931.14' MD, 4048.01' TVD Total Depth : 15613.32' MD, 391 12/52018 6:21:09PM Page 7 COMPASS 5000.15 Build 91 6,498.00 3,998.55 9 5/8" x 12 1/4" 15,613.32 3,993.60 6 5/8" x 8 1/2" Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) 353.90 353.90 0.00 0.00 703.90 701.94 1.67 31.94 1,794.61 1,601.84 61.74 597.49 5,087.06 3,532.35 375.25 3,246.09 6,298.52 3,977.69 69.75 4,290.38 6,498.52 3,998.60 -44.08 4,453.49 6,686.39 4,009.02 -151.43 4,607.22 12,880.26 4,048.36 -3,698.89 9,684.43 12,931.14 4,048.01 -3,728.03 9,726.13 15,613.32 3,993.60 -5,263.92 11,924.36 9-5/8 12-1/4 6-5/8 8-1/2 Comment Start Dir 30/100': 353.9' MD, 353.9'TVD Start Dir 4°/100' : 703.9' MD, 701.94'TVD End Dir : 1794.61' MD, 1601.84' TVD Start Dir 4°/100' : 5087.06' MD, 3532.35'TVD End Dir : 6298.52' MD, 3977.69' ND Start Dir 3°/100' : 6498.52' MD, 3998.6'TVD End Dir : 6686.39' MD, 4009.02' TVD Start Dir 3°/100' : 12880.26' MD, 4048.36'TVD End Dir : 12931.14' MD, 4048.01' TVD Total Depth : 15613.32' MD, 391 12/52018 6:21:09PM Page 7 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10 M-10 M-10 wp07 Sperry Drilling Services Clearance Summary Anticollision Report 05 December, 2018 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-10 - M-10 - M-10 wp07 Well Coordinates: 6,027,889.65 N, 534,113.80E (70' 29' 13.99" N, 149" 43' 16.22" W) Datum Height: M-10 RKB @ 58.60usft Scan Range: 33.70 to 6,498.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation Is 3,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Hileorp Alaska, LLC Milne Point Anticollision Report for MPU M-10 - M-10 wpU Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-10 - M-10 - M-10 wp07 Scan Range: 33.70 to 6,498.00 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is 3,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Alternate Close Approach Scenarios M Pt F Pad M Pt L Pad MPL-20 - MPL-20 - MPL-20 6,498.00 626.32 6,498.00 468.38 9,119.00 3.965 Clearance Factor Pass - MPL-32 - MPL-32 - MPL-32 6,300.92 188.97 6,300.92 125.63 9,423.34 2.983 Centre Distance Pass - MPL-32 - MPL-32 - MPL-32 6,383.70 204.69 6,383.70 101.25 9,395.66 1.979 Ellipse Separation Pass - MPL-32 - MPL-32 - MPL-32 6,433.70 226.98 6,433.70 104.86 9,378.81 1.859 Clearance Factor Pass - MPL-36 - MPL-36 - MPL-36 6,498.00 1,444.94 6,498.00 1,287.76 9,321.76 9.193 Clearance Factor Pass - MPL-36 - MPL-361-1 - MPL-361-1 6,498.00 1,444.94 6,498.00 1,287.76 9,321.76 9.193 Clearance Factor Pass - MPL-36-MPL-361-1 PB1-MPL-36LI PBI 6,498.00 1,444.94 6,498.00 1,287.76 9,321.76 9.193 Clearance Factor Pass - MPL-36-MPL-36PB1-MPL-36PB1 6,498.00 1,444.94 6,498.00 1,287.76 9,321.76 9.193 Clearance Factor Pass - MPL-39 - MPL-39 - MPL-39 6,498.00 687.75 6,498.00 587.87 9,075.00 6.886 Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-53 6,498.00 1,354.95 6,498.00 1,274.43 9,075.01 16.827 Clearance Factor Pass - M Pt Moose Pad MPU M-11 - M-11 - M-11 wp04 333.70 89.93 333.70 86.82 333.80 28.921 Centre Distance Pass - MPU M-11 - M-11 - M-11 wp04 1,233.70 92.63 1,233.70 83.25 1,283.22 9.877 Ellipse Separation Pass - MPU M-11 - M-11 - M-11 wp04 6,498.00 844.68 6,498.00 699.86 6,697.83 5.832 Clearance Factor Pass - MPU M-12 - M-12 - M-12 wp04 333.70 179.93 333.70 176.82 333.80 57.864 Centre Distance Pass - MPU M-12 - M-12 - M-12 wp04 358.70 179.93 358.70 176.65 358.80 54.718 Ellipse Separation Pass - MPU M-12 - M-12 - M-12 wp04 6,498.00 1,664.81 6,498.00 1,518.56 6,928.92 11.383 Clearance Factor Pass - MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 333.70 164.09 333.70 160.99 329.80 53.014 Centre Distance Pass - MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 383.70 164.27 383.70 160.82 379.80 47.592 Ellipse Separation Pass - MPU M-13 - M-13 - M-13 (Stonewall Inj) wp02 1,358.70 340.68 1,358.70 329.02 1,382.04 29.225 Clearance Factor Pass - MPU M-14 - M-14 - M-14 (McCllan Prod) wp02 333.70 237.92 333.70 234.96 329.80 80.347 Centre Distance Pass - MPU M-14 - M-14 - M-14 (McCllan Prod) wp02 358.70 237.92 358.70 234.78 354.80 75.771 Ellipse Separation Pass - MPU M-14 - M-14 - M-14 (McCllan Prod) wp02 1,158.70 392.87 1,158.70 383.55 1,144.49 42.147 Clearance Factor Pass - 05 December, 2018 - 18:22 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for MPU M-10 - M-10 wp07 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-10 - M-10 - M-10 wp07 Scan Range: 33.70 to 6,498.00 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is 3,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance SummaryBased on Site Name Depth Distance Depth Separation Depth Factor Minimum Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Milne Point Exploration From To (usft) (usft) 33.70 6,498.00 M-10 wp07 6,498.00 15,613.25 M-10 wp07 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Survey/Plan 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 Hileorp Alaska, LLC Milne Point Separation Warning 05 December, 2018 - 18:22 Page 3 of5 COMPASS HALLIBURTON Project: Milne Point Site: MPt Moose Pad 6perry Drilling Well: MPU M-10 Wellbore: M-10 REFERENCE INFORMATION WELLDErML6:MPUM-10 NAD1927(NADCONCONUS) Alnsks 7>rne 04 Co-0Nlnate(NIE) Reference: Well MPU M -f 0, True Nonh Ver4Wl(TVo) Reference:*10 IRKS @NMI Meesuai Depth Reference: WID RKS@58.60usX Calculation MelI Minimum Cumuum Ground Level 2490 +W9 +Pl-W Nwhin8 Easting Lafinudc Langitudc 1).00 0.00 6027889.65 534113.81) 70°29'13.990N 149°43'1621 Plan: M-10 wp07 SURVEY PROGRAM GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Date: 2018-10-OiT00:00:00 Validated; Yes Version: 33.70 To 15613.32 CASING DETAILS Ladder/S.F. Plots DepN Flom Depth To Sumay/Plan Tool 33.70 6498.00 M-10wp07(M-10) 2 MWD+IFR2+MS+Sag TVD TVDSS MD Smu Name 3998.55 3939.95 6498.00 9-5/8 95/8"x121/4" SH (1 of 2) 6488.00 15613.25 M -10"07(M-10) 2_MWD+IFR2+MS+Sag 7993.60 3935.00 15613.32 6-5/8 6 5/8" z 8 1/2" X750.00 —13414omwaIWnl wp02--- ---- as � 0 I 0 p120.00 m _ M-11 wIP04 c 0 0.00 90.00- — -------- ta a d N 1560.00--- 0.00 0) 0 U o � � 30.00 C 0 U 0.00 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 Measured Depth (700 usft/in) ash— i �---- — ---- - - - -- i— i - _— _... o` .00 it3.00-- to to a Q) 1.50 r Collision Risk Procedures Re Collision Avoidance Req. . I No -Go Zone - Stop Drilling I I 0.00 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 Measured Depth (700 usfUin) Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-10 M-10 M-10 wp07 Sperry Drilling Services Clearance Summary Anticollision Report 05 December, 2018 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad -MPU M-10 -M-10 - M-10 wp07 Well Coordinates: 6,027,889.65 N, 534,113.80E (70° 29' 13.99" N, 149" 43' 16.22" W) Datum Height: M-10 RKB @ 58.60usft Scan Range: 6,498.00 to 15,613.32 usft. Measured Depth. Scan Radius Is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 3,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURT®Iv Anticollision Report for MPU M-10 - M-10 wpO7 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-10 - M-10 - M-10 wp07 Scan Range: 6,498.00 to 15,613.32 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 3,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Comparison Well Name -Wellbore Name - Design (usft) (usft) (usft) (usft) usft Alternate Close Approach Scenarios MPL-34 GyrolnDrillPipe- GyrolnDP- GyrolnDP MPL-34 GyrolnDrillPipe - GyrolnDP - GyrolnDP MPL-34 GyrolnDrillPipe - GyrolnDP - GyrolnDP MPL-34 MWD - MWD - MWD MPL-34 MWD - MWD - MWD MPL-34 MWD - MWD - MWD MPtFPad MPU F-109 - MPU F-109(OA Producer) - MPU F-109 MPU F-110 - MPU F-1101 - MPU F-110 MPU F-110 - MPU F -110i - MPU F-110 M Pt L Pad MPL-20 - MPL-20 - MPL-20 MPL-20 - MPL-20 - MPL-20 MPL-20 - MPL-20 - MPL-20 MPL-32 - MPL-32 - MPL-32 MPL-34 - MPL-34 - MPL-34 MPL-34 - MPL-34 - MPL-34 MPL-34 - MPL-34 - MPL-34 MPL-35 - MPL-35 - MPL-35 MPL-35 - MPL-35 - MPL-35 MPL-35 - MPL-35 - MPL-35 MPL-35 - MPL-35A- MPL-35A MPL-35 - MPL-35A - MPL-35A MPL-35 - MPL-35A- MPL-35A MPL-35 - MPL-35APB1 - MPL-35APB1 MPL-35 - MPL-35APB1 - MPL-35APB1 Hileorp Alaska, LLC Milne Point Separation Warning 8,301.77 330.91 306.21 204.39 8,301.77 2.615 203.87 Pass - 9,126.85 288.22 2.992 Centre Distance Pass - 8,348.00 Ellipse Separation 309.63 7,094.13 8,348.00 7,094.13 199.62 8,947.90 9,121.18 Centre Distance 2.814 Ellipse Separation Pass - 8,448.00 127.85 338.88 1.930 8,448.00 Pass - 212.02 324.70 9,109.48 276.19 2.671 Clearance Factor Pass - 8,367.70 8,373.00 290.41 8,373.00 8,367.70 9,130.01 212.22 Ellipse Separation 9,118.59 8,548.00 3.714 Centre Distance Pass - 8,548.00 4.112 341.17 Pass - 8,548.00 168.53 147.90 59.96 9,097.22 1.552 1.765 Ellipse Separation Pass - 8,623.00 9,548.00 385.48 8,580.29 8,623.00 Ellipse Separation 157.61 9,614.97 9,087.68 9,614.97 1.692 Clearance Factor Pass - 10,906.74 Pass - 1,175.31 168.53 10,906.74 59.96 909.54 1.552 12,380.00 Pass - 4.422 Clearance Factor Pass - 10,098.00 8,581.09 566.65 Ellipse Separation 10,098.00 9,614.97 349.48 9,614.97 11,550.00 8,581.36 2.609 Clearance Factor Pass - 10,111.30 168.53 566.49 59.96 10,111.30 1.552 349.52 Pass - 11,550.00 156.30 2.611 Centre Distance Pass - 6,898.00 330.91 6,898.00 204.39 9,006.00 2.615 Clearance Factor Pass - 6,998.00 288.22 6,998.00 185.39 8,976.27 2.803 Ellipse Separation Pass - 7,094.13 273.34 7,094.13 196.84 8,947.90 3.573 Centre Distance Pass - 6,498.00 265.34 6,498.00 127.85 9,357.00 1.930 Clearance Factor Pass - 8,288.95 324.70 8,288.95 276.19 9,140.60 6.694 Centre Distance Pass - 8,373.00 335.22 8,373.00 268.87 9,130.01 5.052 Ellipse Separation Pass - 8,548.00 414.03 8,548.00 313.34 9,107.99 4.112 Clearance Factor Pass - 9,523.00 168.53 9,523.00 59.96 8,580.19 1.552 Clearance Factor Pass - 9,548.00 156.30 9,548.00 55.73 8,580.29 1.554 Ellipse Separation Pass - 9,614.97 141.23 9,614.97 63.77 8,580.56 1.823 Centre Distance Pass - 9,523.00 168.53 9,523.00 59.96 8,580.99 1.552 Clearance Factor Pass - 9,548.00 156.30 9,548.00 55.73 8,581.09 1.554 Ellipse Separation Pass - 9,614.97 141.23 9,614.97 63.77 8,581.36 1.823 Centre Distance Pass - 9,523.00 168.53 9,523.00 59.96 8,580.99 1.552 Clearance Factor Pass - 9,548.00 156.30 9,548.00 55.73 8,581.09 1.554 Ellipse Separation Pass - 05 December, 2018 - 18:23 Page 2 of COMPASS HALLIBURT®N Anticollision Report for MPU M-10 - M-10 wp07 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-10 -M-10 - M-10 wp07 Scan Range: 6,498.00 to 15,613.32 usft. Measured Depth. Scan Radius Is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 3,000.00 usft Hileorp Alaska, LLC Milne Point MPL-39 - MPL-39 - MPL-39 Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Pass - Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 3.059 Clearance Factor Pass - MPL-35 - MPL-35APB1 - MPL-35APB1 9,614.97 141.23 9,614.97 63.77 8,581.36 1.823 Centre Distance Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 9,523.00 168.53 9,523.00 59.95 8,580.99 1.552 Clearance Factor Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 9,548.00 156.30 9,548.00 55.73 8,581.09 1.554 Ellipse Separation Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 9,614.97 141.23 9,614.97 63.76 8,581,36 1.823 Centre Distance Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 9,523.00 168.53 9,523.00 59.96 8,580.99 1.552 Clearance Factor Pass - MPL-35 - MPL-35AP83 - MPL-35APB3 9,548.00 156.30 9,548.00 55.73 8,581.09 1.554 Ellipse Separation Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 9,614.97 141.23 9,614.97 63.77 8,581.36 1.823 Centre Distance Pass - MPL-36 - MPL-36 - MPL-36 7,823.00 265.81 7,823.00 151.14 8,988.22 2.318 Clearance Factor Pass - MPL-36 - MPL-36 - MPL-36 7,898.00 234.69 7,898.00 142.01 8,970.42 2.532 Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-36 7,970.44 223.89 7,970.44 153.03 8,952.99 3.160 Centre Distance Pass - MPL-36 - MPL-361-1 - MPL-361-1 7,823.00 265.81 7,823.00 151.14 8,988.22 2.318 Clearance Factor Pass - MPL-36 - MPL-361-1 - MPL-361-1 7,898.00 234.69 7,898.00 142.01 8,970.42 2.532 Ellipse Separation Pass - MPL-36-MPL-361-1-MPL-361-1 7,970.44 223.89 7,970.44 153.03 8,952.99 3.160 Centre Distance Pass - MPL-36 - MPL-361-1 PB1 - MPL-361-1 PB1 7,823.00 265.81 7,823.00 151.14 8,988.22 2.318 Clearance Factor Pass - MPL-36 - MPL-361-1 PB1 -MPL-361-1 PB1 7,898.00 234.69 7,898.00 142.01 8,970.42 2.532 Ellipse Separation Pass - MPL-36 - MPL-361-1 PB1 - MPL-361-1 PB1 7,970.44 223.89 7,970.44 153.03 8,952.99 3.160 Centre Distance Pass - MPL-36 - MPL36PB1 - MPL-36PB1 7,823.00 265.81 7,823.00 151.14 8,988.22 2.318 Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 7,898.00 234.69 7,898.00 142.01 8,970.42 2.532 Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1 7,970.44 223.89 7,970.44 153.03 8,952.99 3.160 Centre Distance Pass - MPL-37 - MPL-37 - MPL-37 9,766.49 324.25 9,766.49 259.91 8,912.03 5.039 Centre Distance Pass - MPL-37 - MPL-37 - MPL-37 9,823.00 329.13 9,823.00 256.00 8,910.25 4.501 Ellipse Separation Pass - MPL-37 - MPL-37 - MPL-37 9,998.00 398.36 9,998.00 291.23 8,905.00 3.719 Clearance Factor Pass - MPL-37 - MPL-37A- MPL-37A 9,766.49 324.25 9,766.49 259.91 8,921.23 5.039 Centre Distance Pass - MPL-37 - MPL-37A - MPL-37A 9,823.00 329.13 9,823.00 256.00 8,919.45 4.501 Ellipse Separation Pass - MPL-37 - MPL-37A - MPL-37A 9,998.00 398.36 9,998.00 291.23 8,914.20 3.719 Clearance Factor Pass - MPL-39 - MPL-39 - MPL-39 7,092.47 364.28 7,092.47 269.00 8,949.46 3.823 Centre Distance Pass - MPL-39 - MPL-39 - MPL-39 7,173.00 372.50 7,173.00 259.44 8,929.02 3.295 Ellipse Separation Pass - MPL-39 - MPL-39 - MPL-39 7,298.00 414.87 7,298.00 279.24 8,896.72 3.059 Clearance Factor Pass - MPL-45 - MPL-45 - MPL-45 12,673.00 594.85 12,673.00 258.06 9,365.00 1.766 Clearance Factor Pass - MPL-45 - MPL-45 - MPL-45 12,723.00 583.61 12,723.00 255.00 9,365.00 1.776 Ellipse Separation Pass - MPL-45 - MPL-45 - MPL-45 12,830.47 573.63 12,830.47 270.83 9,365.00 1.894 Centre Distance Pass - 05 December, 2018 - 18:23 Page 3 of 7 COMPASS HALLIBURTON Anticollision Report for MPU M-10 - M-10 wp07 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-10 - M40 - M-10 wp07 Scan Range: 6,498.00 to 15,613.32 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 3,000.00 usft Hilcorp Alaska, LLC Milne Point M Pt Moose Pad MPU M-11 - M-11 - M-11 wp04 15,613.32 803.36 15,613.32 291.15 15,618.71 1.568 Clearance Factor Pass - MPU M-12 - M-12 - M-12 wp04 15,613.32 1,642.24 15,613.32 1,119.47 16,043.10 3.141 Clearance Factor Pass - Milne Point Exploration 05 December, 2018 - 18:23 Page 4 of 7 COMPASS Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPL-50 - MPL-50 - MPL-50 14,584.66 790.19 14,584.66 480.18 11,655.73 2.549 Centre Distance Pass - MPL-50 - MPL-50 - MPL-50 15,073.00 795.72 15,073.00 464.17 12,112.58 2.400 Ellipse Separation Pass - MPL-50 - MPL-50 - MPL-50 15,123.00 798.44 15,123.00 465.48 12,139.22 2.398 Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51 10,648.00 214.56 10,648.00 118.33 8,813.47 2.230 Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51 10,723.00 180.02 10,723.00 105.31 8,847.07 2.409 Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-51 10,803.57 165.81 10,803.57 113.89 8,886.08 3.194 Centre Distance Pass - MPU L-52 - MPU L-52 - MPU L-52 9,323.00 176.33 9,323.00 96.05 9,133.77 2.197 Clearance Factor Pass - MPU L-52 - MPU L-52 - MPU L-52 9,373.00 153.62 9,373.00 90.38 9,150.24 2.429 Ellipse Separation Pass - MPU L-52 - MPU L-52 - MPU L-52 9,432.35 143.07 9,432.35 95.84 9,169.74 3.029 Centre Distance Pass - MPU L-53 - MPU L-53 - MPU L-53 7,942.79 144.18 7,942.79 77.01 9,547.67 2.147 Centre Distance Pass - MPU L-53 - MPU L-53 - MPU L-53 7,948.00 144.26 7,948.00 76.80 9,549.50 2.138 Ellipse Separation Pass - MPU L-53 - MPU L-53 - MPU L-53 7,973.00 146.92 7,973.00 77.64 9,558.28 2.121 Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-54 11,698.00 194.54 11,698.00 91.64 9,268.68 1.891 Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-54 11,748.00 169.76 11,748.00 84.02 9,288.11 1.980 Ellipse Separation Pass - MPU L-54 - MPU L-54 - MPU L-54 11,829.32 152.35 11,829.32 95.71 9,319.42 2.690 Centre Distance Pass - MPU L-56 - MPU L-56 - MPU L-56 8,623.00 184.83 8,623.00 97.57 9,264.90 2.118 Clearance Factor Pass - MPU L-56 - MPU L-56 - MPU L-56 8,673.00 158.03 8,673.00 87.08 9,279.01 2.227 Ellipse Separation Pass - MPU L-56 - MPU L-56 - MPU L-56 8,747.80 140.77 8,747.80 92.40 9,299.97 2.911 Centre Distance Pass - MPU L-57 - MPU L-57 - MPU L-57 9,923.00 209.76 9,923.00 121.12 8,950.00 2.367 Clearance Factor Pass - MPU L-57 - MPU L-57 - MPU L-57 9,998.00 175.15 9,998.00 107.84 8,981.41 2.602 Ellipse Separation Pass - MPU L-57 - MPU L-57 - MPU L-57 10,068.00 163.18 10,068.00 113.11 9,010.92 3.259 Centre Distance Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 9,923.00 209.76 9,923.00 121.12 8,950.00 2.367 Clearance Factor Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 9,998.00 175.15 9,998.00 107.84 8,981.41 2.602 Ellipse Separation Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 10,068.00 163.18 10,068.00 113.11 9,010.92 3.259 Centre Distance Pass - M Pt Moose Pad MPU M-11 - M-11 - M-11 wp04 15,613.32 803.36 15,613.32 291.15 15,618.71 1.568 Clearance Factor Pass - MPU M-12 - M-12 - M-12 wp04 15,613.32 1,642.24 15,613.32 1,119.47 16,043.10 3.141 Clearance Factor Pass - Milne Point Exploration 05 December, 2018 - 18:23 Page 4 of 7 COMPASS HALLIBURT®N Anticollision Report for MPU M-10 - M-10 wp07 Hileorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt Moose Pad - MPU M-10 - M-10 - M-10 wp07 Scan Range: 6,498.00 to 15,613.32 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 3,000.00 usft Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft Pesado-01 - PESADO-01 - Pesado-01 8,626.40 239.11 8,626.40 126.91 4,023.05 2.131 Centre Distance Pass - Pesado-01 - PESADO-01 - Pesado-01 8,673.00 243.47 8,673.00 123.05 4,031.10 2.022 Ellipse Separation Pass - Pesado-01 - PESADO-01 - Pesado-01 8,698.00 249.28 8,698.00 125.96 4,035.40 2.021 Clearance Factor Pass - Pesado-01 - PESADO-01A - Pesado-01A 8,571.94 141.47 8,571.94 29.48 4,049.02 1.263 Centre Distance Pass - Pesado-01 - PESADO-01A- Pesado-01A 8,598.00 143.84 8,590.00 24.82 4,050.64 1.209 Clearance Factor Pass - From To Survey/Plan Survey Tool (usft) (usft) 33.70 6,498.00 M-10 wp07 2_MWD+IFR2+MS+Sag 6,498.00 15,613.25 M-10 wp07 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 05 December, 2018 - 18:23 Page 5 of 7 COMPASS HALLI BURTON Project: Milne Point Site: MPt Moose Pad 9pemy O�Illing Well: MPU M -1D Wellbore: MPU REFERENCE INFORMATION WELL DETAILS:MPU M-10 NAD 1927(NADCON CONIIS) Alaska]une 04 Co ordinate TVD) Reference: Wee MPU @M-10.58 Tura NodM1 V¢tlical DVD)Reference: M -0O RBB �SB.BDnsN Measured Dept Reference: thio RKa@50.60usn Calculation Metol Minimum canter Durand Level: 11.90 +N/ -S +F) -W Iafinudc IamgduJc O.DO 0.00 Northing Fasting 70.29'13.990N 149°43'16.21 W 6027899.65 534113.80 URVEY PRO RAM GLOBAL FILTER APPLIED: AN wellpaths within 200'+ 100/1000 of reference 33.70 To 15613.32 Plan: M-10 wp07 Ladder/S.F. Plots PH (2 of 2) DaW:2018-10-DiT00:00:00 Velidatad: Yes Vereion: Dept From Depth TO Survey/Plan Tool 33.70 6498.00 M-10 wp0] (M-10) 2_MWD+IFR2+MS+Sa9 6498.00 15613.25 M -f0 wp0](M-10) 2_MW D+IFR2+MS+Sa9 CASING DEALS ND TVDSS MD 5/8 Name 3998.55 3939.95 6498.00 9-5/8 9 5/8" x 12 1/4" 3993.60 3935.00 ISfi13.32 6-5/8 65/9"x812" F150.00 I N 3 0 o p120.00 — 0 9o.oD o m d I � U 0 � � 30.00 c d U kill 0.00 6800 7200 7600 8000 8400 8800 9200 9600 10000 10400 10800 11200 11600 12000 12400 12800 13200 13600 1400D Measured Depth (800 usf /in) 4.50-- - N 3.00 U- C O Collision Risk Procedures Req. n C% 1.50 - Collision Avoidance Req No -I o Zone - Stop Drilling 0.00 6750 7200 7650 8100 8550 9000 9450 9900 10350 10800 11250 11700 12150 12600 13050 13500 13950 Measured Depth (800 usft/in) Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, December 14, 2018 9:22 AM To: Joe Engel; Stan Porhola Subject: M-10 Jet pump Completion (PTD 218-165) Stan/Joe, Just wanted to follow-up with an email on the PTD application. 1. The well will require variance on the SSV placement. Add that to page 9 on application. 2. As we discussed the completion procedure needs tweaking on page 39 to include MIT -IA, packer setting, BPV test etc. 3. Need complete schematic of wellhead and tree showing SSV placement. 4. Provide a written procedure for the performance testing of the SSV (due within 5 days of placing on production) I would update these two pages (9 and 39) and send all documents to me by email. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENIIAWY 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.aovl. Transform Points Source coordinate system State Plane 1927 - Alaska Zone 4 P (A M — Datum: NAD 1927 - North America Datum of 1927 (Mean) X Target coordinate system Albers Equal Asea 050) Datum: NAD 1927 - North Amenca Datum of 1927 (Mean) _ _ _ ----- ce values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to ypopy and Ctd+V to paste. Then dick on the appropriate arrow button to transform the points to the desired coordinate system. t Back Finish Cancel Help From: Cody Dinaer To: Davies Steohen F (DOA); Boyer. David L (DOA) Subject: MPU M-10 Directional Plan Date: Monday, December 10, 2018 11:41:00 AM Attachments: M-10 wo07 GEO.TXT M-10 wo07 GIs.TXT M-10 wo07.txt Steve, Attached is the directional plan for MPU M-10. Will deliver the permit to drill this afternoon. Thanks, Cody Dinger Hilcorp Alaska, LLC Drilling Technician cdinaerPh lcorD com Direct: 907-777-8389 TRANSMITTAL LETTER CHECKLIST WELL NAME: h�1 P^ice M ` PTD: a, ✓Development —Service —Exploratory _ Stratigraphic Test —Non -Conventional FIELD: M t t In P POT 1 h POOL: Sc. � rd.4 t k- B f usg; Check Box for ADoroariate 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 (If last two digits No. 'API No. 50-_- _ 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 andlogs 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 ermit). 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. (ComDanV 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 throujgh 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 (ComWy Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program, Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by / (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 5/2013 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Well Name: MILNE_FT UNIT -M -1 -0 -Program DEV Well bore seg ❑ PTD#:2181650 Company HILCORP ALASKA LLC Initial Class/Type DEV / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven, gas conforms to AS31.05.030([.1.A),0,2.A-D) ____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ Well bore conforms to spacing requirements.... _ .............. 1 Permit fee attached---- - -- - - - - - - - - - - - - - - - - - - - - - - - - - - --- NA 2 Lease number appropriate .... ................ Yes.. _..... _..._.. 3 Unique well nameand number ---------- ...............Yes _-------------___------------------------- __. 4 Well located in a. defined pool __________________ .. 5 Well located proper distance from drilling unit boundary. _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ . ..... . ... . ................................................... 6 Well located proper distance from other wells . . . . . . . . . ....... . . .. . . . .... . Yes .. 7 Sufficient acreage available in drilling unit........ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ .. ..... ........ . ............ . ....... 8 If deviated, is wellbore plat included _ _ _ _ _ _ _ _ _ _ _ _ _ _____________ _ _ _ _ Yes 9 Operator nly affected party - - - - - - - - _ _ _ .. Yes 10 Operator has appropriate bond in force - - - - - - - - _ _ _ - - - - - - Yes ... _ ------------------ - - - - - - - - - - - - - - - - - - - - - - - - - ........ - - - - Appr Date 11 Permit can be issued without conservation order .. .. _ _ _ _ _ _ _ _ Yes 12 Permit can be issued without administrative approval _ _ _ _ .......... Yes OLS 12/11/2018 13 Can permit be approved before 15 -day wait...... _ _ _ _ _ _ Yes 14 Well located within area and. strata authorized by. Injection Order # (put. 10# In. comments) (For NA _ . Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05 ..... .. 15 All wells -within 1/4.mile area of review identified (For service well only) ............... NA _ _ _ CO 477.05_ specifies:_ "There are no restrictions as to well spacing except that no pay shall- - - - - - - 16 Pre -produced injector: duration of pre production less than 3 months (For service well only) NA .. be. opened.in a well closerthan.500 feet from the exterior boundary of the. affected area." ..... . 18 Conductor stringprovided_ _ _ _ _ _ _ _ _ _ _ _ _ ________ _ ___ _ _ _ _ _ _ __ _ _ _ _ _ Yes - - _ _ 20 "-conductor set at -107 ft._ cemented................................. Engineering 19 Surface casing protects all known USDWs _ ............. NA_ _ _ No aquifers.., permafrost area 20 CMT vol adequate to circulate on conductor & surf_csg _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ Yes _ _ _ 9 5/8" casing will be fully cemented ..._ 2 stages planned, 21 CMT vol. adequate to tie-in long string to surf os9- - - - - - - - - - - - - - - - - - - - - Yes 22 CMT. will coverall known productive horizons _ _ .. _ ... - Yes _ _ _ _ _ 6 5/8" pre perfed liner .... horizontal lateral... 23 Casing designs adequate for C, T, BA permafrost_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Yes _ _ BTC supplied.. 24 Adequate tankage -or reserve pit . . . . . . . . . ............. . Yes . Doyon 14 has steak pits.. All waste will be transported to approved disposal well. - 25 If a -re -drill, has.a 10-403 for abandonment been approved _____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ _ _ _ Grassroots well_.., Normal flow lat Pump completion. planned, .... . 26 Adequate wellbore separation proposed . . . . . . . . . . . . .... . .......... Yes _ No issues with close crossing.. 27 If diverter required, does it meet regulations_ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ ... Diyerter layout provided. Appr Date 28 Drilling fluid, program schematic & equip list adequate .... _ _ _ _ _ _ _ Yes - _ Max form pressure= 1760 -psi -(8.46 ppg EMW) Will drill with 9t.2 ppg.mud, GLS 12/14/2018 29 BOPEs-do they meet regulation . . . . . . ................. . . . . . Yes _ _ _ Doyon 14 has -135/8" 5000 psi WP BOPE.. 30 BOPE_press rating appropriate; test to.(put prig in comments)_ _ _ _ _ .... Yes _ _ _ _ _ MASP = 1359 - psi _ will test BOPE to 3000 psi 31 Choke. manifold complies w/API-RP-53 (May 84)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 32 .Work will occur without operation shutdown . . . . .................... . . . . . Yes 33 Is presence of HIS gas probable _ _ _ _ _ _ _ _ _ _ . _ ..... Yes - HIS is likely -in Kuparuk sands... -Rig has sensors and alarms, 34 Mechanical condition of wells within AOR verified (For service well only) .............. NA..... 35 Permit can be issued w/o hydrogen, sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes HIS not anticipated from drilling of offset wells; however, rig will have HIS sensors and alarms. Geology 36 Datapresented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ ... _ _ ....... ............ Appr Date 37 Seismic analysis of shallow gas. zones. _ . . . ................... NA.. DLB 12/11/2018 38 Seabed condition survey.(if off. -shore) . . . . . . . . . . . . . . . . ............ . NA. 39 Contact name/phone for weekly progress reports [exploratory only] _ _ _ _ _ _ _ _ _ _ __ _ NA..... .... ... .... .. ... .. Geologic Engineering Publ' First Moose Pad well will be a "normal Flow " jet pump completion. SSV is in horizontal outlet. 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