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Home My WebLink About219-170MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, April 12, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC M-23 MILNE PT UNIT M-23 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/12/2024 M-23 50-029-23659-00-00 219-170-0 W SPT 3795 2191700 1500 698 699 698 696 4YRTST P Bob Noble 3/25/2024 Mono Bore well. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT M-23 Inspection Date: Tubing OA Packer Depth 106 1755 1675 1648IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN240325164708 BBL Pumped:2.7 BBL Returned:2.7 Friday, April 12, 2024 Page 1 of 1            DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23659-00-00Well Name/No. MILNE PT UNIT M-23Completion Status1WINJCompletion Date2/14/2020Permit to Drill2191700Operator Hilcorp Alaska, LLCMD14300TVD3539Current Status1WINJ4/14/2020UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, DGR, AGR, ABG, ADR, EWR MD and TVD / PB1NoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleC3/25/202090 14300 Electronic Data Set, Filename: MPU M-23 LWD Final.las32301EDDigital DataC3/25/20205020 14262 Electronic Data Set, Filename: MPU M-23 ADR Quadrants All Curves.las32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 LWD Final MD.cgm32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 LWD Final TVD.cgm32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 and plugback surveys.xlsx32301EDDigital DataC3/25/2020 Electronic File: MPU M-23i_Definitive Survey Report.pdf32301EDDigital DataC3/25/2020 Electronic File: MPU M-23i_Plan.pdf32301EDDigital DataC3/25/2020 Electronic File: MPU M-23i_VSec.pdf32301EDDigital DataC3/25/2020 Electronic File: MPU M-23_Definitive survey report.txt32301EDDigital DataC3/25/2020 Electronic File: MPU M-23_GIS.txt32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 LWD Final MD.emf32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 LWD Final TVD.emf32301EDDigital DataC3/25/2020 Electronic File: MPU_M-23_Geosteering.dlis32301EDDigital DataC3/25/2020 Electronic File: MPU_M-23_Geosteering.ver32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 LWD Final MD.pdf32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 LWD Final TVD.pdf32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 LWD Final MD.tif32301EDDigital DataC3/25/2020 Electronic File: MPU M-23 LWD Final TVD.tif32301EDDigital DataTuesday, April 14, 2020AOGCCPage 1 of 3PB1~MPU M-23 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23659-00-00Well Name/No. MILNE PT UNIT M-23Completion Status1WINJCompletion Date2/14/2020Permit to Drill2191700Operator Hilcorp Alaska, LLCMD14300TVD3539Current Status1WINJ4/14/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVED0 0 2191700 MILNE PT UNIT M-23 LOG HEADERS32301LogLog Header ScansC3/27/202090 14260 Electronic Data Set, Filename: MPU M-23PB1 LWD Final.las32302EDDigital DataC3/27/20205020 14222 Electronic Data Set, Filename: MPU M-23PB1 ADR Quadrants All Curves.las32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1 LWD Final MD.cgm32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1 LWD Final TVD.cgm32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1_Definitive Survey Report.pdf32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1_Definitive survey report.txt32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1_GIS.txt32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1 LWD Final MD.emf32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1 LWD Final TVD.emf32302EDDigital DataC3/27/2020 Electronic File: MPU_M-23PB1_Geosteering.dlis32302EDDigital DataC3/27/2020 Electronic File: MPU_M-23PB1_Geosteering.ver32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1 LWD Final MD.pdf32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1 LWD Final TVD.pdf32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1 LWD Final MD.tif32302EDDigital DataC3/27/2020 Electronic File: MPU M-23PB1 LWD Final TVD.tif32302EDDigital Data0 0 2191700 MILNE PT UNIT M-23 PB1 LOG HEADERS32302LogLog Header ScansTuesday, April 14, 2020AOGCCPage 2 of 3MPU M-23PB1 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23659-00-00Well Name/No. MILNE PT UNIT M-23Completion Status1WINJCompletion Date2/14/2020Permit to Drill2191700Operator Hilcorp Alaska, LLCMD14300TVD3539Current Status1WINJ4/14/2020UICYesCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 2/14/2020Release Date:12/9/2019Tuesday, April 14, 2020AOGCCPage 3 of 3M. Guhl4/14/2020 DATE 03/23/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To, Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 MPU M-23 (219-170 MPU M-23PB1 Halliburton LWD FINAL 7 FEB 2020 MPU M-23 & MPU M-23 PB1 RECElV"� '" MAR 2 5 2020 AOv`� at,,J,r CGM _ 2/'13/2020413PM Filefolder Definitive Survey 211' 20204:23 PM File folder EMF 2/13/20204:23 PM Fi[efodder EAS 2/13/20204:23 PM Filefolder PDF Y13f20204:23PIM File folder TIFF 2f13/20204:23PM Fi[efolder Please include current contact information if different from above. 2 19 17 0 323© 1 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 DATE 03/23/2020 21 91 1 0 Debra Oudean Hilcorp Alaska, LLC a p p� GeoTech 3800 Centerpoint Drive, Suite 1400 2 J lD Anchorage, AK 99503 Tele: 907 777-8337 E-mail: doudean@hilcorp.com To: Alaska oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU M-23 (219-170 MPU M-23PB1� Halliburton LWD FINAL 7 FEB 2020 MPU M-23 & MPU M-23 PB1 CGM Definitive Survey EMF LAS PDF TIFF 2,1"20204;23 PM u 1"L02C 4:23 PM 2113!20204;23 PM 2.13,"_' 020 4;23 Pfv1 2.'13 ;2020 4:23 PIA 4i 13, _^?C 4:23 PDA Please include current contact information if different from above. RECEI�"�' MAR 2 5 2020 AOGC File folder Fife folder File folder File folder File fckder File folder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DSR-4/14/2020 GDLB 04/14/2020 THE STATE �4� 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-23 Permit to Drill Number: 219-170 Sundry Number: 320-033 Dear Mr. Helgeson: Alaska Oil and Gas Conservati®n Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for 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, �np J re y U YPrJice C Ir DATED this/,/,)day of January, 2020. IBDMS (14J AN 2 4 2920 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 JAN; 21 it0 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program Q Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Run Completion Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service Q 219-170 r 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23659-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 r Will planned perforations require a spacing exception? Yes ❑ No ❑� MPU M-23 9. Property Designation (Lease Nymber): 10. Field/Pool(s): ADL025514, ADL355023 Milne Point Field / Schrader Bluff oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 14,170' 3,518' 14,170' 3,518' 1,299 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 82' 20" 82' 82' N/A N/A Surface 5,014' 9-5/8" 5,046' 3,814' 5,750psi 3,090psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary LJ Wellbore schematic 1,/1 13. Well Class after proposed work: Detailed Operations Program ❑✓ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑ Service ❑Q 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 2/1/2020 OIL ❑ WINJ ❑✓ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson Contact Name: Ian Toomey' Authorized Title: Operations Manager Contact Email: Itoome hiIcor .corn i' Contact Phone: 777-8434 Authorized Signature: Date: 1/17/2020 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test [d Mechanical Integrity Test Location Clearance ❑ Other: S —T;—( — BDMS«/� IAN 2 4 2020 Post Initial Injection MIT Req'd? Yes ❑V No❑ 6j. .L' •Spacing '" (bo h' C��f Exception Required? Yes ❑ Nod Subsequent Form Required: � APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: bU /-X1.3 - 2 ., .5o,��l, ll Submit Form and Form 10-403 Revise 4/ t Approved application is valid for 12 months from theOdate of I I.� Attachments in Duplicate I U Hilcorp Alaska, LLQ Original Completion Well: MPU M-23 Date: 01-20-2020 Well Name: MPU M-23 API Number: 50-029-23659-00 Current Status: Surface casing drilled Pad: M -Pad Estimated Start Date: February 1, 2020 Rig: Innovation Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 219-170 First Call Engineer: Ian Toomey (907) 777-8434 (0) (907) 903-3987 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: 1915942C Job Type: Original Completion Current Bottom Hole Pressure: Lateral yet to be drilled Maximum Expected BHP: 1,681 psi @ 3,821' TVD MPSP: 985 psi Gas Column Gradient (0.1 psi/ft) Brief Well Summary: M -23's 12-1/4" surface hole section was drilled by Doyon 14 in December 2019 to TD at 5,053' MD (3,813' TVD) in the Schrader Bluff OA -1 sand. The well was cased with 9-5/8" surface casing and cemented back to surface. A 3-1/2" kill string was run and Doyon 14 RDMO. The 8-1/2" production hole will be drilled with the Innovation Rig on PTD #219-170. A separate sundry was requested for the injection liner and completion to address the close approach with well SL32-14. Objective: • The injection liner will be run with a solid liner section and swell packers to isolate standoff from near approach to P&A'd well SL32-14. • Run upper 3-1/2" injection completion. / Completion Procedure: To be inserted and replace section 17 & 18 in the approved MPU M-23 PTD #219- 170). Testing of the BOP's and stack configuration are covered under PTD #219-170. 17.0 Run 4-1/2" Injection Liner 17.1 Well control preparedness: In the event of an influx of formation fluids while running the 4-1/2" liner with ICD and swell packers, the following well control response procedure will be followed: • With ICD across the BOP: PU & MU the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2" handling joint above TIW). This joint shall be fully MU and available prior to running the first joint of 4- 1/2" liner. • With 4-1/2" solid joint across BOP: Slack off and position the 4-1/2" solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2" solid joint. Close TIW valve. 17.2 Confirm VBR have been tested on 3-1/2" and 5" test joints to 250 psi low/3,000 psi high. N . H 13ilcorp Alaska, LLI Original Completion Well: MPU M-23 Date: 01-20-2020 17.3 RU 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and MU to FOSV. • Ensure the liner 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 RU casing tools. • Record and confirm OD's, ID's, lengths, SN's of all components with vendor & model info. 17.4 Run 4-1/2" injection liner. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only with paint brush. Wipe off excess. Thread compound can plug the ICDs. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Use lift nubbins and stabbing guides for the liner run. • Fill 4-1/2" liner with new brine (to keep from plugging ICDs with solids) • Install solid liner section with swell packers ±400' above and ±400' below close approach section of well SL32-14. Plot below depicts the planned wellpath and close approach area to well SL32-14. • Install ICDs and swell packers as per the Running Order • (From Completion Engineer post TD) • Do not place tongs or slips on swell packer elements or ICDs • ICD and swell packer placement ±40' • The ICD connection is 4-1/2" 13.5# Hydril 625 . H IIilcorR Alaska, LU Original Completion Well: MPU M-23 Date: 01-20-2020 • Remove protective packaging on swell packers just prior to picking up • If liner length exceeds surface casing length, ensure centralizers are placed 1 per joint for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. Stop rings to be installed with no lock downs. • Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2" 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5" 8,000 ft -lbs 9,600 ft -lbs 12,800 ft -lbs For the latest performance data, always visit our website: www.tenarls.com Wedge 625®? Outside Diameter 4.508 ,. Wa8 Thickness 0290 s. Grade LBO Type t' Min. wall 87.V... Thickness connection OD REGULAR Option Drift API Standard Type Casing 12104F,2017 (•) Grade LBO 4.714 A. Type 1 3.849 �. COUPLING PIPE BODY Body: Red 1st Band: Red 1st Band: Brown 2" Band: 2nd Band:- Broem 3rd Rand:- 3rd Sand 4th Band_ - i. GEOMETRY Nominal OD 4,500 in. Norrdnalweighl 13.503Jft Drat 3.795 as. Non:nal ID 3.920 in. VW Thickness 0290 n. Rain End weight 13.05 t. R Chi ToSerance API i PERFORMANCE Body Y 4d 9trengin 307 x 10M Ills Inoemaf Yield 9020 psi SMYS 80000 ps: Ca1L>Fse 8540 Ps; Connection OD 4.714 A. Connecaen ID 3.849 �. Make-up Lass 4.830 u^. Threads Per in 3.59 Ca oton OD Opt. REGULAR PERFORMANCE Tension Eftiency 910% Joint Yeld Strength 279.370 x 1000 Internal Pressure Capacity 9020.000,-i Ins Conip—cion E'fi—,cy 9i5 % Compression Stmngth 290.115 x10M Max Ai'a wable Bending 73.7 11100 R lbs External Pressure Capawy 9540.000 psi MAKE-UP TORQUES Minimum 9000'-Pos Cptimum 98008 -lbs Maximunn 12800' -lbs OPERATION LIMIT TORQUES Cperamg Torque 12800'4bs Yield Torque 15000 flans Notes For further information on concepts indicated in this datasheet, download the Datasheet Manual from www.tenans.com Original Completion Well: MPU M-23 I ilcorp Alaska, LL Date: 01-20-2020 17.6 Ensure that the liner top packer is set — 150' MD above the 9-5/8" shoe. AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8" connection. 17.7 Before picking up Baker SLZXP liner hanger/packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.8 PU and MU Baker SLZXP liner hanger/packer to 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 17.9 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.10 RIH with liner on DP while taking care to watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 17.11 The solid liner will prevent the DP from auto filling until enough ICD's are in the well. Fill DP every 5 stands, more frequently if SOW trend indicates. 17.12 Slow in and out of slips. Ensure accurate slack off data is gathered during TIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.13 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 17.14 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 17.15 Rig up to pump down the work string with the rig pumps. 17.16 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. If there are issues encountered that prevent the liner from making it to setting depth, do not set liner hanger and consult OE and Geologist for further discussion to ensure area around SL32-14 are properly isolated. y 17.17 Drop setting ball down the DP 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. 17.18 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. SO 20K on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,100 psi to neutralize and release running tools. 0 Original Completion Well: MPU M-23 Ililcorp Alaska, LL Date: 01-20-2020 17.19 Bleed DP pressure to zero, PU to expose rotating dog sub and set down 50K without pulling sleeve packoff. PU without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50K again to ensure the liner top packer is set. 17.20 PU to neutral weight, close BOP and test IA to 1,500 psi for 10 minutes charted. 17.21 Bleed pressure to 0 psi and open BOPE. PU 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. 17.22 Displace landing string x Liner, pump 1-2 circulations. 17.23 POOH laying down DP then rack back enough 5" DP for the liner top cleanout run. LD and inspect running tools. Once running tools are LD, swap to completion AFE. 17.24 Makeup 3-1/2" wash tool and RIH on 5" DP to the liner top. 17.25 Flush liner top at max rate while displacing out well to clean brine. 17.26 POOH LD remaining 5" DP. ff I ilcorp Alaska, LLI 18.0 Run 3-1/2" Upper Completion Original Completion Well: MPU M-23 Date: 01-20-2020 18.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivard@hilcorp.com for submission to AOGCC. 18.2 MU injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. • Ensure wear bushing is pulled. • Ensure 3-1/2" EUE 8RD x NC -50 crossover is on rig floor and MU to FOSV. • Ensure all tubing has been drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed before running. • Keep hole covered while RU casing tools. • Record OD's, ID's, lengths and SN's of all components with vendor & model info. • Monitor displacement from wellbore while RIH. 3-1/2" 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3-1/2" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs 3-1/2" Upper Completion Running Order • 3-1/2" Baker Ported Bullet Nose seal (stung into the tie back receptacle) • 3 joints (minimum, more as needed) 3-1/2" 9.3#, L-80 EUE 8RD tubing • Gauge Mandrel (pressure gauge installed) with 10' handling pump above and below • X joints 3-1/2" 9.3#, L-80 EUE 8RD tubing • 2.813" 'XN' nipple (2.75" no-go) at deepest point possible (less than 65* deviation) with 10' handling pump above and below • X joints 3-1/2" 9.3#, L-80 EUE 8RD tubing • 2.813"'X' nipple at TBD MD with 10' handling pump above and below • X joints 3-1/2" 9.3#, L-80 EUE 8RD tubing • Space out pups (as needed) 3-1/2" 9.3#, L-80 EUE 8RD • 1 joint 3-1/2" 9.3#, L-80 EUE 8RD tubing • Tubing hanger with 3-1/2" EUE 8RD pin down 0 IIilcorp Alaska. LL, Original Completion Well: MPU M-23 Date: 01-20-2020 18.3 Locate and no-go out the seal assembly. Close annular and pressure up to 500 psi to confirm seals engaged. 18.4 Bleed pressure and open annular. Space out the completion (± 1' to 2' above No -Go). Place all space out pups below the first full joint of the completion. 18.5 MU the tubing hanger and landing joint. 18.6 RIH. Close annular and pressure up to 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 18.7 Reverse circulate the IA to 1% corrosion inhibited brine. 18.8 Freeze protect the IA to —2,100' TVD (based on actual well deviation) with diesel. 18.9 Land hanger and RILDS. — k.)k 18.10 PT the IA to 2,500 psi and for 30 minutes charted. i. Note this test must be witnessed by the AOGCC representative. 18.11 Set BPV, ensure new body seals are installed. 18.12 ND BOPE, install the plug off tool into the BPV. 18.13 NU the tubing head adapter and tree. 18.14 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.15 Pull the plug off tool from BPV. 18.16 Bullhead diesel down the tubing to ^'2,100' TVD. 18.17 Install all tree gauges. Secure the tree and cellar. Release the rig 18.18 RDMO Innovation Rig 18.19 Turn well over to production via handover form. RU well house and flowlines. 1. Proposed Schematic ffilcorp Alaska, LLC Orig. KB Elev.: 58.8'/ GL Elev.: 24.9' TD =14,120' MD / 3,637 TVD PBTD =14,115' MD / 3,637 TVD PROPOSED TREE & WELLHEAD Milne Point Unit Well: MP M-23 Last Completed: Future PTD: 219 - 170 Tree Cameron 3 1/8" 5M Wellhead FMC 11" 5M TC -1A w/11" x 4 1/2" TC -II Top and Bottom Tubing 9-5/8" 2nd stage Hanger with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20" x 34" 270 ft3 Cement to surface in a 42" hole 9-5/8" 1st stage L — 275 sx / T — 400 sx in a 12-1/4" hole 9-5/8" 2nd stage L — 536 sx / T — 270 sx in a 12-1/4" hole 6-5/8"" Cementless Slotted Liner in 8-1/2" hole CASING DETAIL Type Wt/ Grade/ Conn ID Top Btm BPF Conductor (Insulated) 215 / X-42 / Weld N/A Surface 80' N/A Surface 40 / L-80 / TXP SR 8.835" Surface 5,046' 0.0758 Liner 13.5/ L-80 / Hyd 623 3.920" ±4,866 ±14,170' 0.0149 TUBING DETAIL Tubing 12.6 / L-80 / HYD521 2.992" 1 ±Surface 1 ±4,827 0.0087 WELL INCLINATION DETAIL KOP @ 550' JEWELRY DETAIL No. Top MD Item 1 ±2,500' 3.5" X Nipple (2.813" Packing Bore) 2 ±4,500' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) 3 ±4,550' 3.5" Gauge Mandrel SGM-XPQG w/ X" Wire 4 ±4,610' 8.26" No Go Locater w/ 7.375" Seal Assembly 5 ±4,620' 7.375" Tieback above the SLZXP Liner Top Packer 6 ±4,620' ZXP Liner Top Packer 7 ±13,961' WIV (Ball on Seat/ Closed) Depth MD ICD/Swell Packer Detail TBD Water Swell Packer TBD ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge ±5,100' Water Swell Packer ±5,500' SL32-14 close approach top ±6,500' SL32-14 close approach bottom ±6,900' Water Swell Packer TBD ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge TBD Water Swell Packer TBD ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge TBD Water Swell Packer TBD ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge GENERAL WELL INFO API: 50-029-23659-00-00 Drilled, Cased by Innovation — In Progress Revised By: TDF 12/4/2019 THE STATE JALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-23 Hilcorp Alaska, Inc. Permit to Drill Number: 219-170 Surface Location: 5039' FSL, 651' FEL, SEC. 14, T13N, R9E, UM, AK Bottomhole Location: 536' FSL, 2206' FEL, SEC. 23, T13N, R9E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced service well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Wce DATED this T day of December, 2019. STATE OF ALASKA ALr,_KA OIL AND GAS CONSERVATION COMM16,,ON PERMIT TO DRILL 20 AAC 25.005 NOV 21 2019 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service Disp ❑ 1 c. if i w I is o osed for: Drill 21 Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj Q 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-23 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 14,170' TVD: 3,518' Milne Point Field Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 5039' FSL, 651' FEL, Sec 14, T13N, R9E, UM, AK ADL025514, ADL355023 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 767' FNL, 1523' FEL, Sec 14, T13N, R9E, UM, AK LONS 16-004 12/5/2019 Total Depth: 9. Acres in Propertv: 14. Distance to Nearest Propertv: 536' FSL, 2206' FEL, Sec 23, T13N, R9E, UM, AK 5815 767' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 59.0' 15. Distance to Nearest Well Open Surface: x- 533604 y- 6027890 Zone -4 GL / BF Elevation above MSL (ft): 25.0' to Same Pool: 800' to MPU M-22 16. Deviated wells: Kickoff depth: 550 feet 17. Maximum Potentia Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 102 degrees Downhole: 1681 Surface: 1299 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 20" 215# X-42 Weld 82 Surface Surface 82 82 351 ft3 12-1/4" 9-5/8" 40# L-80 TXP SR 4,866' Surface Surface 4,866' 3,822' Stg 1 L- 556 ft3 / T - 458 ft3 Stg 2 L - 1937 ft3 / T - 314 ft3 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 9,304' 4,866' 3,822' 14,170' 3,518' 1 Cementless injection Linerw/ICDs Tieback 1 3-1/2" 9.3# L-80 EUE 8RD 1 4,716' 1 Surface ISurface I 4,716' 3,808' Tieback 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 ❑ BOP Sketch Diverter Sketch Drilling Program ❑✓ Seabed Report ❑ Time v. Depth Plot Shallow Hazard Analysis Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hIICOr .COrTI Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: ' Date: Commission Use Only Permit to Drill ,r I Number: Permit Approval cover letter for other Number. % / �,ee Date: IZ 11 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: �Q 6o •4- Samples req'd: Yes ❑ No[� Mud log req'd: Yes❑ No[l� �S HzS measures: Yes ❑ N,§/,Directional svy req'd: Yes WNo❑ �r?�4 Spacing exception req'd: Yes ❑ No l �' Inclination -only svy req'd: Yes ❑ �Pdo V Post initial inject n MIT req'd: Yes IrJ/ No ❑ j „ �j r./l j ; �(� a APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: f 2171 / ✓ Submit Fore and Form 10-4101' f ppper Revis This permit is valid approval r 20 AAC 25.005(g) Attachments in Duplicate r .off lltf� o. o vYo m r L o m E s CL c m o c oo - o c p p a Q � L u i> E= x v p Q a m y v Q E m 3 0 v z a. N en 'm �' v$ E v N o c u c E N O a+ 3 0 D o v oo E m c 00 a 3 m c w o N a iv +L' m u aci v v nu v IA 4 Li o n e m c a Q n OS v J L C 0) v o 0 o m u c J E N N N O C o ti E o c _� _ m o m N O O O m U r, Q UJ U C C0 m LL E N O C u L Y v U 00 U- oo v c o v 3 m e S i0 E E u y 3 > u v a o v E a t o C o v Y 00 (D •3 v _O u O . _ E o000 o �° v v E N aci Q 2 >i � vi a O �o v 0 00 3 ..�a O Q a ^ 'q c u c�a a a u 0 O v u v E m c o Ln m c v m E Qom o E m a N f0 v u m ¢ o '@ n r `O am+ f`6 Q U N ac 7 0 N N `~ O O) c Ln t 00 OZf 00 C U C Q dam' H N C O p N N fp! N N Y O O CA O t U U U N pCL u 00 U E > m � 4�rH J (.0M v � 1/► p ,r 0 d G a) m oN `N° ° E g t 00 f.D W o J dN M N l0 m v v co - N > m ^ 00 C~ Q m m mro m �- O vmi in c p C LO Ln N W 0 v m m o H u H U >� O a N Q Q a a O m o N m �} Q N O �Y ` N N m -j -j 0 0 CD 0 0 0 0 0 0 a Ln�t � m N m N a L o O m m O 0 N i N N N Ol Q1 Ql Cj) N O N O N O nJ O OO O O Ln L(1 Ln Lf1 -I c -I O ct' N Ln p) 0 0 a 0 00 1-1-1 w N UD N r -i \ KUPARUK RIVER UNIT "00- 1 s 'II M-11 L-3 _ �11-23 wp05 M-2 �V I �. M-13 L�2Uii�� I I 32-'14 ; � X21 I � ` '� \ ��I '2k � \\ L-36 ; M-14 1 / \ V I 32-14A II \ M-15,, fill, 10 _---- .. /M�01 LIVIANO 1 if I 1 , LIVIANIQ 1A Ij I HILCORP ALASKA LLC ' /r `' MILNE POINT FIELD AOR MAP I I I /r M-23 hiedar(Proposed) 0 1000 2,000 FEET WELL SYMBOLS • Active Od DaA ® ad3 Well (Wale Food) X P&A Od / Irdecbr Loc0on REMARKS KUPARUK RIVER UNIT ` wens bots at top of Schrader Bluff OA Sand Black dash circle = 1320' radius fan OA sand in feel and foe d proposed M-23 drill well NovpnEer 7. 2019 Hilcorp Alaska, LLC Milne Point Unit (MPU) M-23 Drilling Program Version 1 11/18/2019 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 R/U and Preparatory Work.........................................................................................................11 10.0 N/U 21-1/4" 2M Diverter System.................................................................................................12 11.0 Drill 12-1/4" Hole Section.............................................................................................................14 12.0 Run 9-5/8" Surface Casing...........................................................................................................17 13.0 Cement 9-5/8" Surface Casing.....................................................................................................22 14.0 N/D Diverter, N/U Wellhead, Run Killstring, RDMO...............................................................27 15.0 MIRU Innovation, BOP N/U and Test, Pull Killstring..............................................................28 16.0 Drill 8-1/2" Hole Section...............................................................................................................29 17.0 Run 4-1/2" Injection Liner...........................................................................................................34 18.0 Run 3-1/2" Upper Completion.....................................................................................................39 19.0 Doyon 14 Diverter Schematic.......................................................................................................41 20.0 Doyon 14 BOP Schematic.............................................................................................................42 21.0 Innovation BOP Schematic..........................................................................................................43 22.0 Wellhead Schematic......................................................................................................................44 23.0 Days Vs Depth...............................................................................................................................45 24.0 Formation Tops & Information...................................................................................................46 25.0 Anticipated Drilling Hazards.......................................................................................................47 26.0 Doyon 14 Layout............................................................................................................................50 27.0 Innovation Rig Layout..................................................................................................................51 28.0 FIT Procedure...............................................................................................................................52 29.0 Doyon 14 Choke Manifold Schematic.........................................................................................53 30.0 Innovation Choke Manifold.........................................................................................................54 31.0 Casing Design................................................................................................................................55 32.0 8-1/2" Hole Section MASP............................................................................................................56 33.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................57 34.0 Surface Plat (As Built) (NAD 27).................................................................................................58 35.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................59 ff Hilcorp Energy C—pwy 1.0 Well Summary Milne Point Unit M-23 SB Injector Drilling Procedure ��J0 /c Well MPU M-23 Pad Milne Point "M" Pad Planned Completion Tye 3-1/2 Injection Tubing Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 14,170' MD / 3,518' TVD PBTD, MD / TVD 14,170' MD / 3,518' TVD Surface Location (Governmental) 241' FNL, 561' FEL, Sec 14, T13N, R9E, UM, AK Surface Location (NAD 27) X= 533603.9, Y= 6027889.6 Top of Productive Horizon (Governmental) 767' FNL, 1523' FEL, Sec 14, T13N, R9E, UM, AK TPH Location (NAD 27) X= 532644 Y= 6027359 BHL (Governmental) 536' FSL, 2206' FEL, Sec 23, T13N, R9E, UM, AK BHL (NAD 27) X= 532010, Y= 6018100 AFE Number AFE Drilling Days 19 AFE Completion Days 3 AFE Drilling Amount $4,179,730 AFE Completion Amount $1,585,308 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1299 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1681 psig Work String 5" 19.5# 5-135 NC 50 D14 KB Elevation above MSL: 33.7 ft + 25.0 ft = 58.7 ft Innovation KB above MSL: 26.5 ft + 25.0 ft = 51.6 ft GL Elevation above MSL: 25.0 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 ff Hilcorp Energy Company 2.0 Milne Point Unit M-23 SB Injector Drilling Procedure Management of Change Information 11 Hilcorp Alaska, LLC HilcoT_ Changes to Approved Permit to grill Date: 1111812019 Subject: Changes to Approved Permit to Drill for MPU M-23 File #: MPU M-23 Drilling and Completion Program Any modifications to MPU M-23 Drilling & Completion Program will be documented and approved belolk Changes to an approved APD Mll be approved in advance to the AOGCC. Sec Page Date Procedure Change Approved By -Approved By Approval: Drilling Manager Date Prepared: Drilling Engineer Page 3 3.0 Tubular Program: Milne Point Unit M-23 SB Injector Drilling Procedure Hale Section OD (in) ID (in) I Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tensilon (k -lbs) Cond 20" 19.25" - - - X-52 _ Weld (min) Max(k-lbs) 12-1/4" 9-5/8" 8.835" 8.679" 10.625" 40 L-80 TXP 5,750 3,090 916 8-1/2" 4-1/2" 3.96" 3.795" 4.714" 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2" 2.992" 2.867" 4.500" 9.3 L-80 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hole ID (in) TJ ID TJ OD Wt Gracie Conn M/U MIU Tension Section in in (in)(#/ft)_ (min) Max(k-lbs) Surface & 5" 4.276" 3.25" 6.625" 19.5 S-135 DS50 36,100 43,100 560klb Production 5" 4.276" 3.25" 6.625" 19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 4 5.0 Internal Reporting Requirements Milne Point Unit M-23 SB Injector Drilling Procedure 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 pmazzolini2hilcorp.com, mmyers e,hilc9M jengel@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 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 mmyersphilcorp,com jengel a,hilcorp.com and cdin er o,hilcorp.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mm. ers o,hilcorp.com jengel(2hilcorp.com and cdinger(2hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.947.9533 twellman@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Milne Point Unit M-23 SB Injector Hilco Drilling Procedure E"�W"u 6.0 Planned Wellbore Schematic 3.5Ef SS Grmm,, D-sw ke TD= 14,1 ! [MDEITD= 3,821 PM) F617D= 24,170 (MC} j PMD= 3,$21' IPM) Page 6 rvl ne Paint Unit Proposed Schematic PTD: TBD ,.Pi: TSD TREE & WELLHEAD Tree I Cameron 3- 8 5K4 w/ 4-1/161M Cameron Wing V,+ellheed I Cameron ii" 5K x Ki lock bottom w1 {21 2-1116'59 outs OPEN HOLE/ CEME14T DETAIL 42" 1 5ohb'sfie yards Mecretedurnpeddoarnbackside) -�4• Stg1-L-556 3 T-458 Stg 2- L-1937 ft3 / T-314 ft3 8.1/2" 1 Cementless injection Liner in 8-1/7' hole size Type MW Grade/ Conn Drift ID Ta- 4 -CC 3.5 XN Nipple 12.813 Packing Bore; 2.75 N3 -Go, -75? BPF —20,1x34" Con d uctcr 1insuateCI 215.5 X-42 Mle IFA 106 NaA 9.5 8 Surtace 40/ L -BD TXP 8:679 5-1ace 4,13M' 0-0758 4-1/2 LrW 13.5 L,80 7 W 573 3795 Tr-Tr 14,170 C.0149 TUBING DETAIL RE 3-112" TtAxng 9.31L-8D1EUE8RD 1 2-1367" Surf 1 4,71£ C.L47C WELL INCLINATION DETAIL KOP @ 55C+ - h ole Angle @ XN = TBD hale Angle @ Liner Top = TBD Max Mole Angle = TBD JEWELRY DETAIL No Top MD Item L. Upper Completion i 2 ECC 3.5 X Ni.2.813 Pa[ rgWe Z.B _ 4 -CC 3.5 XN Nipple 12.813 Packing Bore; 2.75 N3 -Go, -75? - 4,550' 3.5` Gatge Mandrel SGM-XPQG wl 14" :Vire 2.895 4,510 S.W No Go Wcater w 7.375 Seal A4sem 2.992 5 4,520 7.37VIleback above ttte SLZXP Liner Top Packer 2.992: Lmver CampFetion 6 4,520 Dip UnerTap Packer - 13,961` 1 WV (Ball on Seat/ CSosed) - GENERAL WELL INFO kPf� Corr;.ieted b� L^^s:?tion Rig. SL 3 2- -/L-1 ,, w. k` 006 Hilcorp 7.0 Drilling / Completion Summary Milne Point Unit M-23 SB Injector Drilling Procedure MPU M-23 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-23 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 4-1/2" injection ICD liner will be run in the open hole section. The M-23 directional plan has the surface hole crossing the unity boundary to the north, in to KRU, and then returning to MPU before landing in the target zone. M-23 will not be producing hydorcarbons from KRU and no pay zone will be open with 500 feet of the MPU boundary, in compliance with AOGCC regulations. A wellbore easement application has been approved. The Doyon 14 will be used to drill the surface hole. Once surface hole is cased and cemented, D14 will run a killstring, freeze protect the well, and RDMO. Innovation rig will then MIRU, drill the lateral and complete the wellbore. Drilling operations are expected to commence approximately December 5, 2019, pending rig schedule. Surface casing will be run to 4,866' MD / 3,821' 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 wellhead, run kill string, freeze protect. RDMO Doyon 14. 5. MIRU Innovation Rig. NU 13-5/8" 5M BOP & Test, pull kill string 6. Drill 8-1/2" lateral to well TD. Run 4-1/2" injection liner 7. Run Upper Completion 8. N/D BOP, N/U Tree, RDMO Innovation 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-23 SB Injector Hilco Drilling Procedure acw �� 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-23. 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: No variances are requested at this time. See note in Section 7 regarding wellbore easement application. Page 8 Milne Point Unit M-23 SB Injector Hilcorp Drilling Procedure i Energy Company Summary of Doyon 14 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12 1/4" • 21-1/4" 2M Diverter w/ 16" Diverter Line Function Test Only i Initial Test: 250/3000 • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate N/A o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 13-5/8" x 5M Control Technology Single ram For Reference • 13-5/8" x 5M Hydril MPL Single ram Subsequent Tests: • 3-1/8" x 5M Choke Line N/A • 3-1/8" x 5M Kill line • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure(psi) For Reference 13-5/8" 5M CTI Annular BOP w/ 16" diverter line N/A • 13-5/8" x 5M Control Technology Inc Annular BOP • 13-5/8" x 5M Control Technology Inc Double Gate Initial Test: 250/3000 o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 13-5/8" x 5M Control Technology Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Page 9 Milne Point Unit M-23 SB Injector Drilling Procedure 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,galaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria. loeppgalaska. gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixsegalaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotifhtm] Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 9.0 9.1 9.2 9.3 9.4 9.5 9.6 Milne Point Unit M-23 SB Injector Drilling Procedure RX and Preparatory Work M-23 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. Ensure PTD and drilling program are posted in the rig office and on the rig floor. Install landing ring. Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. Level pad and ensure enough room for layout of rig footprint and R/U. 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 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 11 ff Hilcrp E—gy c2, 10.0 NX 21-1/4" 2M Diverter System Milne Point Unit M-23 SB Injector Drilling Procedure 10.1 N/U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 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. Page 12 Hilcorp Energy Company 10.4 Rig & Diverter Orientation: • May change on location M-58 a M-22 ..0 -m % W M-17 �JLi Vol'. M--23 � II 75` Radius Clear of Ignition Sources -ppm-- Diverter line • s � Page 13 Milne Point Unit M-23 SB Injector Drilling Procedure " Drawing Not To Scale Diverter Line May Be Oriented Different On Location 11.0 Drill 12-1/4" Hole Section 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# 5-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. • Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 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 j ets hooked up and be ready to j et 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. NO Page 14 Milne Point Unit M-23 SB Injector Hilco � C-� Drilling Procedure 11.0 Drill 12-1/4" Hole Section 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# 5-135. • Run a solid float in the surface hole section. 11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. • Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 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 j ets hooked up and be ready to j et 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. NO Page 14 Milne Point Unit M-23 SB Injector Hilcorp Drilling Procedure Energy Company • 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: • 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 • 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. • Surface Hole AC: • There are no wells with a clearance factor of <1.0 11.4 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 (ppg) Surface — Base Permafrost 8.9 Base Permafrost - TD 9. (For Hydrates if need based on offset wells) MW can be cut once —500' below hydrate zone aNV = 's'LtcP • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. Page 15 Milne Point Unit M-23 SB Injector Drilling Procedure • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 - 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section 1 Density Viscosity Plastic Viscosi Yield Point API FL pH I Tem Surface 8.8 - 9,8 1 75-175 20-40 25-45 <10 8.5-9.0 1 <- 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 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 1 55 1 gal dm 1 0.5 11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.6 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, adjust as dictated by hole conditions • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 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 Milne Point Unit — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring M-23 SB Injector Float Collar w/ Stage Cementer Bypass Baffle `Top Hat' Hilco � ��P 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, 1 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 17 Milne Point Unit M-23 SB Injector Hilcorp Drilling Procedure E -W Com 12.5 Float equipment and Stage tool equipment drawings: IA Type H ES Cementer Part No. SO No_ 0 0 E �- A Closing Sleeve No. Shear Pins Opening Sleeve C No. Shear Pins ES Cementer R Depth Baffle Adapter (if used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe AT Depth Hole TD "Reference Casing Sales Manual Section 5 Page 18 "A Overall Lenjii B him. ID After Dsillout C Max. T, -,Dl OD D open„g "seat ID E Closing,- Seat IID Plug Set Part No. Sig No - closing Plug OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD a Hikorp ES41 Running Order ES41 Cementer 7-7 Shut On Flog Baffle Adapter � r az By -Pass Plug By Pass Baffle Float Collar Float Shoe a Milne Point Unit M-23 SB Injector 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 everyjoint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ugnu) • Verify depth of lowest Ugnu 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 5 '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. 9-5/8" 40# 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 19 Hilcorp E -W Company TXP BTC Outside Diameter 9.625:in. Wali Thickness 0-395 in. Grade L60Type 1' Min. Wail 87.6% Thickness connection oD REGULAR Option Drift API Standard Type Casing Milne Point Unit M-23 SB Injector Drilling Procedure --- 1VOW 016 (") Grade LOD 5 Type 1 REGULAR COUPLiftG PIPE BODY Body: Red 1st?�ar.d: Red tst Bard: Brows) 2rc Band: 2nd Bard: - Brown 3rd Sand: - 3rd =an,-',: - 49+ Eand: - GEOMETRY Nominal CSD 9.625 in. NDminal IN'sight 40 Ibs,`ft Drift .5.679 in Nominal ID 8.83.5 in. 'AlallThinknes 0.355 fir., Plain End VVeight 35.97 Ibs:1t CID Toisrxrce API PERFORMANCE Body Yip St ergIh 916 x1 ODD ids nnema '',si 5750 pa shlys SDEW psi Go?apse 3090 psi Ccnr..ect,on OC 10.625 in. rg -s-;,.h 10.825 as,. Gcnneciion ID 8.823 in. N'—a-up Loss 1.559 in. Thraaus per in 5 Connection C>D Option REGULAR PERFORMANCE Tension Effcienc^y 100.0% C'irt yeo Stmnglh 916.000 x1000 internal Pressure Capacai III 5750.000 psi Its Compression Eirziency 100'. compression Sirenglh 916.000 x.1000 Max. Allowable Bending 35 `6100 ft Ibs Extemal Pr-swe Capacity 3090.000 ps MAKE-UP TORQUES I h4>^imum 18860 ft-tl Optimum 20960 fi-lbs Maximum 23%0 rt -lbs OPERATION LIMIT TORQUES --� Dperst-gTo€cu- 356001[=�s Yield Torque 43400 Nos Notes This connection is fully interchangeable with: TXP@ BTC - 9.625 in. - 36. 43.5 i 47153.5 i 58.4 lbsift i1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5C3 J 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 total Tenaris technical sales representative. Page 20 Milne Point Unit M-23 SB Injector Hilco}rp Drilling Procedure Energy Company 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 21 ff Hilcorp Energy Company 13.0 Cement 9-5/8" Surface Casing Milne Point Unit M-23 SB Injector 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/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1St stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. .5 (?-, Estimated 1St Stage Total Cement Volume: Page 22 Section Calculation Vol (bbl) Vol (ft3) 12-1/4" OH x 9-5/8" (3,866'- 2500') x .0558 bpf x 1.3 = 99.1 556.3 JCasing Total Lead 99.1 556.3 12-1/4" OH x 9-5/8" (4,866'- 3,866') x .0558 bpf x 1.3 = 72.5 407 Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Ta i I 81.6 458 Page 22 Milne Point Unit M-23 SB Injector Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. 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: 4746' x .0758 bpf = 359.7 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 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 Page 23 Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System Density 11.7 Ib/gal 15.8 Ib/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: 4746' x .0758 bpf = 359.7 bbls 80 bbls of tuned spacer to be left behind stage tool 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 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 Page 23 Hilcorp E—W Company Milne Point Unit M-23 SB Injector Drilling Procedure 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 staae 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 24 Second Stage Surface Cement Job: Milne Point Unit M-23 SB Injector Drilling Procedure 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2"d stage is ready. Hold pre -job safety meeting. • Past wells have seen pressure increase while circulating through stage tool after reduced rate 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. Estimated god Stage Total Cement Volume: Page 25 Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM TM System (Hal Cem) 20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 J 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" Casing (2500' - 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Page 25 Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L SwiftCEM TM System (Hal Cem) Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Hilcorp E—Sy Company Milne Point Unit M-23 SB Injector Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x .0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 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. -71f 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 �y • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration ,i 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'e� ngei hilcorp. com and cdinger ,hilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 26 Milne Point Unit M-23 SB Injector Drilling Procedure 14.0 N/D Diverter, N/U Wellhead, Run Killstring, RDMO 14.1 N/D the diverter T, knife gate, diverter line & N/ J 11" x 13-5/8" 5M casing spool. 14.2 RIH w/ 3.5" Killstring to 2,500' TVD 14.3 Land tubing hanger. 14.4 RILDS and test hanger. LD landing joint. 14.5 Install BPV. 14.6 N/U tree / adapter and tree. Test tubing hanger void to 500 psi low / 5000 psi high. 14.7 Freeze protect well. 14.8 Set BPV dart. Test tree to 250 psi low / 5000 psi high. Pull BPV dart and BPV 14.9 RDMO Doyon 14 tv C Page 27 Milne Point Unit M-23 SB Injector Drilling Procedure 15.0 MIRU Innovation, BOP NX and Test, Pull Killstring 15.1 MIRU Innovation Rig - — eNOTE DIFFERENCE IN RKB for surface casing equipment depths 15.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" 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 15.3 RU MPD RCD and related equipment 15.4 Run 5" BOP test plug 15.5 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Test 5" test joints Q• 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 15.6 R/D BOP test equipment 15.7 R/U circ lines and circulate out diesel freeze protect 15.8 POOH, L/D killstring 15.9 Mix 8.9 ppg FloPro fluid for production hole. 15.10 Set wearbushing in wellhead. 15.11 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 15.12 Ensure 5" liners in mud pumps. Page 28 i Hilcorp Energy C..p-y Milne Point Unit M-23 SB Injector Drilling Procedure 16.0 Drill 8-1/2" Hole Section 16.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM) 16.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 16.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 16.4 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. 16.5 Drill out shoe track and 20' of new formation. 16.6 CBU and condition mud for FIT. 16.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 16.8 POOH & LD Cleanout BHA 16.9 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# 5-135 DS50 & NC50. • Run a ported float in the production hole section. 16.10 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. • 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 Page 29 Hilcorp Energy Company Milne Point Unit M-23 SB Injector Drilling Procedure 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) for 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 Baradrill N drilling fluid Properties: V/ Interval nsit PV YP LSYP Total Solids MBT I HPHT I Hardness Production 8.9-9. 15-25 - ALAP 15-30 4-6 <10% <8 <1 1.0 <100 System Formulation: Product Concentration Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N -VIS 1.0 — 1.5 ppb DEXTRID LT 5 ppb BARACARB 5 4 ppb BARACARB 25 4 ppb BARACARB 50 2 ppb BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.015 ppb 16.11 TIH with 8-1/2" directional assembly to bottom 16.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid Page 30 Hilcorp E_W C_P1r" Milne Point Unit M-23 SB Injector Drilling Procedure 16.13 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 16.14 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 OA1 & 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% • Offset injection and abnormal pressure has been seen on M-10, -11, -12. MPD will be utilized to monitor pressure build up on connections. • 8.5" Lateral A/C: • There are no wells with a clearance factor < 1.0 16.15 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. Page 31 INA Hilcorp E Milne Point Unit M-23 SB Injector Drilling Procedure 16.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed • Record S/O, PX weights and rotating torque in report. • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary • If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 16.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 16.18 Displace 1.5 OH + Liner volume with viscosified brine. • Proposed brine blend (same as used on M-16, aiming for an 8 on the 6rpm reading) - KCI: 7.1bbp for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo -Vis Plus: 1.25ppb • Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. • Record S/O, P/U weights and rotating torque to compare to pre -brine values in report. 16.19 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (less if losses are seen, 350 gpm min). • Rotate at maximum rpm that can be sustained. Pulling speed 5 — 10 min/std (slip to slip time, not including connections), adjust as dictated by hole conditions If backreaming operations are commenced, continue backreaming to the shoe 16.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. Page 32 Hilcorp Energy Company Milne Point Unit M-23 SB Injector Drilling Procedure 16.21 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 16.22 Monitor well for flow / monitor for pressure build up with MPD. Increase fluid 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 16.23 POOH and LD BHA. 16.24 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 33 Hilcorp E—Ky Company 17.0 Run 4-1/2" Injection Liner 17.1 Well control preparedness: In the event of an i 1/2" liner with ICD and swell packers, the follom followed: • With ICD across the BOP: P/U & M/U the 5' bottom, TIW valve in open position on top, 4 shall be fully M/U and available prior to rune • With 4-1/2" solid joint across BOP: Slack off TIW valve. Shut in ram or annular on 4-1/2" 17.2 Confirm VBR have been tested on 3-1/2" and 5" Milne Point Unit M-23 SB Injector Drilling Procedure o� G ux of formatiolt fluids while running the 4 - well control response procedure will be safety joint (with 4-1/2" crossover installed on 1/2" handling joint above TIW). This joint ng the first joint of 4-1/2" liner. and position the 4-1/2" solid joint to MU the olid joint. Close TIW valve. joints to 250 psi low/3000 psi high. 17.3 Well control preparedness: In the event o an in u of formation fluids while running the 2- 3/8" inner string inside the 4-1/2" liner: • P/U & M/U the 5" safety joint (with 4-1/2' - /8" tri le connect crossover installed on bottom, TIW valve in open position on top, /8" handling joint above TIW). M/U 2-3/8" and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers and available prior to running the first joint • 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. 17.4 R/U 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure the liner 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. 17.5 Run 4-1/2" injection liner. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the ICDs. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Use lift nubbins and stabbing guides for the liner run. • Fill 4-'/2" liner with new brine (to keep from plugging ICDs with solids) • Install ICDs and swell packers as per the Running Order • (From Completion Engineer post TD). • Do not place tongs or slips on swell packer elements or ICDs. • ICD and swell packer placement ±40' • The ICD connection is 4-1/2" 13.5# Hydril 625 • Remove protective packaging on swell packers just prior to picking up • If liner length exceeds surface casing length, ensure centralizers are placed I Jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. Stop rings to be installed with no lock downs. Page 34 Hilcorp E -,Sy Company Milne Point Unit M-23 SB Injector Drilling Procedure Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2" 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5" 8,000 ft -lbs 9,600 ft -lbs 12,800 ft -lbs Page 3 5 Hilcorp Energy Compmy For the latest Performance data. always visit our website., www.tenaris.com Wedge 625® Outside Diameter 4.500 M. ii Thickness 0.290 im Grade LBO Type i' EOMIETRY Min. wall 87.5`.1 Thickness Connection OD REGULAR Option Drift AN Standard Type Casing Milne Point Unit M-23 SB Injector Drilling Procedure - 1210112013 (11 Grade LBO"' 4SO0 sr Nomnai Wood 13.50 tsR Drill 3.795 s,. Type 1 3.920 at. Wall Thickness 0.290 in. Flain End Weight 13.05 ftt COUPLING PIPE BODY Body: Red Is,, Band: Red 1st Band: brown 2nd Band: 2nd Band:.- Brown 3 -rd Band: - 3rd land: - 41h Band: - Nominal UD 4SO0 sr Nomnai Wood 13.50 tsR Drill 3.795 s,. Norrxnai ID 3.920 at. Wall Thickness 0.290 in. Flain End Weight 13.05 ftt COTberanee API PERFORMANCE 3.59 Body'r*1d Streno 307 x1Lkx0 lbs Internal 'a field 9020 psi rMys 80000 psi Collapse 6540 psi Connect,on OD 4.714 in, Connection ID 3.349 in. Make-up Loss 4.630 fir. Threads W in 3.59 Conrecton 00 Opton REGULAR. PERFORMANCE Tension C-lricier�.y 91,0% Joint Yield Strength 279.370 x1000 internal Pressure Capacity 9020.000 psi lbs Corrpression Elise emy 94.5 % Conipressaon Strength 290.115 YICW hl x Aavrrable Bending 73.7'7l,10 R lbs External Pressure Capacity 6540.00 is+ MAKE-UP TOR)UES Mininvirn 80001't -lbs Comm 960014& Maximum MOO tabs OPERATION LIMIT TORQUES Operativ Torque 12800114bs Yield Tcrque 150DO Robs Notes For further information on concepts indicated in this datasheet, download the Datasheet Manual from www.tenaris.com 17.6 Ensure that the liner top packer is set — 150' MD above the 9-5/8" shoe. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8" connection. 17.7 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. Page 36 Milne Point Unit M-23 SB Injector Drilling Procedure 17.8 M/U Baker SLZXP liner top packer to 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 17.9 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.10 RIH w/ liner on DP while taking care to watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 17.11 The solid liner will prevent the DP from auto filling until enough ICD's are in the well. Fill DP every 5 stands, more frequently if SOW trend indicates. 17.12 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. 17.13 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 17.14 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 17.15 Rig up to pump down the work string with the rig pumps. 17.16 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 17.17 Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 17.18 Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 17.19 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, 17.20 PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 17.21 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. Page 37 ff Hilcorp E -W Company Milne Point Unit M-23 SB Injector Drilling Procedure 17.22 Displace landing string x Liner, pump 1-2 circulations. 17.23 POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. Rack back enough 5" drill pipe for liner top clean out run 17.24 Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top. 17.25 Flush liner top at max rate while displacing out well to clean brine. 17.26 POOH LD Remaining 5" DP. 17.27 Once running tools are L/D, Swap to Completion AFE. Page 3 8 18.0 Run 3-1/2" Upper Completion Milne Point Unit M-23 SB Injector Drilling Procedure 18.1 Noti the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivardghilcorp.com for submission to AOGCC. 18.2 18.3 18.4 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. • Ensure wear bushing is pulled. • Ensure 3-'/2" EUE 8RD x NC -50 crossover is on rig floor and M/U to FOSV. • Ensure all tubing has been drifted in the pipe shed prior to running. • Be sure to count the total # of joints in the pipe shed 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. • Monitor displacement from wellbore while RIH. 3-1/2" 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5" 2,350 ft -lbs 3,130 ft -lbs 3,910 ft -lbs 3-V2" Upper Completion Running Order • 3-1/2" Baker Ported Bullet Nose seal (stung into the tie back receptacle) • 3 joints (minimum, more as needed) 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • 3-1/2" "XN" nipple at deepest point possible (less than 65 deg deviation). • 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • 3—%2" "X" nipple at TBD MD • 3-1/2" 9.3#/ft, L-80 EUE 8RD space out pups • 1 joint 3-1/2" 9.3#/ft, L-80 EUE 8RD tubing • Tubing hanger with 3-1/2" EUE 8RD pin down Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. Bleed pressure and open annular. Space out the completion (+/- 1' to 2' above No -Go). Place all space out pups below the first full joint of the completion. Page 39 Milne Point Unit M-23 SB Injector Drilling Procedure 18.5 Makeup the tubing hanger and landing joint. 18.6 RIH. Close annular and test to 400 — 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 18.7 Reverse circulate the well with brine and I% corrosion inhibitor. 18.8 Freeze protect the tubing and IA to 2100' TVD with ±TBD bbl (based on actual well deviation) of diesel. 18.9 Land hanger. RILDs and test hanger. 18.10 Continue pressurizing the annulus to 2500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. 18.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 18.12 Pull BPV. Set TWC. Test tree to 5000 psi. 18.13 Pull TWC. Set BPV. Bullhead tubing freeze protect. 18.14 Secure the tree and cellar. 18.15 RDMO Innovation Rig Page 40 19.0 Doyon 14 Diverter Schematic 21.114' 2M Riser -- 21.1+4' zee— Diverter'r 21-1r4' 2h Spacer S'NX 36.314' 3Af i 21.14' VA DSA Page 41 Milne Point Unit M-23 SB Injector Drilling Procedure —16' Full OpottiN Kndo V.,Ove `--15' Dw rtcr LFne Hilcorp Energy Company 20.0 Doyon 14 BOP Schematic Page 42 Milne Point Unit M-23 SB Injector Drilling Procedure 2-7/81" x 5" VBR Blind Rams x SM HCR al Gate Val 2-7/8"" x 5" VBR Milne Point Unit M-23 SB Injector Hilco Drilling Procedure E-WC.m� 21.0 3-1/8" Kill Innovation BOP Schematic Page 43 Casing Hanger S-22 13-5/8" NOM 9-5/8" BTC Btm x 10.5" -4 SA Pin Top W/ Primary Seal 13-5/8" 5M Control Technology Annular BOP ------13-5/8"5M Control I Technology Double Ram 3-1/8" Choke Line `""�---13-5/8" 5M Control Technology Single Ram —13-5/8" x 5M 11"x5M S �2-1/16" x 5M 13-5/8" x 5M \\-2-1/16" x 5M 9-5/8" Casing 22.0 Wellhead Schematic 11" 5K MBS CAMERON A Schlumberger Company 4-1/16" 5K 11" 5K _'-1/16" 5K 37-34" 21-25" it 1/?" Control Lines" 24.ST' Note: Dimer—wnilmformitw—flezted on thi: drawinzam estimated m�. t: only. 44 Milne Point Unit M-23 SB Injector HilczT Fncw Drilling Procedure 22.0 Wellhead Schematic 11" 5K MBS CAMERON A Schlumberger Company 4-1/16" 5K 11" 5K _'-1/16" 5K 37-34" 21-25" it 1/?" Control Lines" 24.ST' Note: Dimer—wnilmformitw—flezted on thi: drawinzam estimated m�. t: only. 44 Hilcorp Energy Company 23.0 Days Vs Depth 0 BONN 6000 a v 8000 v 10000 12000 14000 16000 Page 45 Milne Point Unit M-23 SB Injector Drilling Procedure MPU M-23 SB OA Injector Days vs Depth 0 5 10 15 20 25 Days Hilcorp Energy Company 24.0 Formation Tops & Information Milne Point Unit M-23 SB Injector Drilling Procedure MPU M-23 Formations (wp05a) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Base Permafrost 1996 -1798 1856 816.64 8.46 LA3 3422 -3090 3148 1385.12 8.46 Schrader Bluff NA 4170 1 -3600 3658 1609.52 8.46 Schrader Bluff OA 4878 1 -3764 1 3822 1681.68 8.46 L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad) GENERALIZED GEOLOGICAL FORECAST___ _., SS GEOLOGICAL TVD FM LITH DESCRIPTION COMMENTS ♦a G.� NOTE: Soo individual Well Program for Tw"a-- Gubik specific casing design, depths, sizes, 0.100" 60 weights, grades and connections. c Unconsolidated coarse to medium sand and small gravel with man« alitstdx o. 1,000 IF SIGNIFICANT AMOUNTS OF GRAVEL ARE ENCOUNTERED WHEN DRILLING THE ♦� SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. +Iso• Base permafrost hterbods of sand, clays and slitstones with occasional 20001 show of coal. Watch possible sidetracking while washingtreaming. W3 8 L•15. saga rktok o*tr No hydrates encountered on L -Pad wells drilled to date. Contirwod In terbeds of sand. clays and siitstones with occasional shows of coal. Traces of pyT its at N- 3100 it 3,000' Interval at .f- 3400 ft can be sticky and tight (1-41). Gay Interbeds between 3000 and 4500 it C 3472•- L A 3657' k eanW v UGNU: Series of coarsonirg upward sands which aro (-ke,C,D) r made up of: (from top to bottom) coarse sand, fine sand, silty shales BeOor developed Intorven Ing stales as you UGNU progress Into the Land M (deeper). Ugnu and Schrader Bluff; Possible hydrocarbons limited L-aa^6i to S W comer of Milre, dowlopment Northern area is (•ke) downistructure and wet. '3739• Nsand+ (•kB.C) �a000• (KA) Schrader Bluff Sands: 4,000' Hsam. (-&u,c.o, Continued layering coarsening upward sands as above -4*— Schrader Bluff: Possible lost circulation E.r) except more condensed and with occasional coal. Zone while swilling long strings and running •4170• o sane. Clay rich shale interval 4300 to 4600 ft ugnu and Schrader slum. Possible hydrocarbons limited casing. Recommend deep setting surface (OA) (.A8,C, to SW corner of Milne development L37 and L-45 are casing for Kuparuk long strings. Also, the p,E.F) comploled in the Schrader Bluff sand. Northam area of Schrader Bluff sands are a potential Schrader L -Pad is dtowrpstru taxa and wet. differential stuck pipe interval if left un -cased Bluff C Surface casing point In shale below for Kuparuk long strings. Sands: Schrader Bluff 08 sand for longer roach wolb. I [ Page 46 Hilcorp Energy C..P-y 25.0 Anticipated Drilling Hazards Milne Point Unit M-23 SB Injector 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 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 no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. 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 47 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 48 Milne Point Unit M-23 SB Injector Hilcorp e,«y com Drilling Procedure 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 48 Hilcorp E..W C—p" 8-1/2" Hole Section: Milne Point Unit M-23 SB Injector Drilling Procedure 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 1-12S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M - Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti -Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Page 49 Hilcorp Energy Company 26.0 Dovon 14 Lavout Page 50 Milne Point Unit M-23 SB Injector Drilling Procedure 27.0 Innovation Rig Layout Page 51 Milne Point Unit M-23 SB Injector Hilcorp E.W C -p -y Drilling Procedure 27.0 Innovation Rig Layout Page 51 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit M-23 SB Injector 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 52 Milne Point Unit M-23 SB Injector Hilco Drilling Procedure 29.0 Doyon 14 Choke Manifold Schematic �N-Z r 4 m w n r7'IZ F Z m N U0 �_ Z A Co Y O c, 3 3 CJ V :E W OD t t O Q D. pp to to �"� tb CL > 3 r v+3D 3 m` 330. n b y � m O G1 n s n ce C w m 0 r v '� va Page 53 Hilcorp E -W Company 30.0 Innovation Choke Manifold Milne Point Unit M-23 SB Injector Drilling Procedure Page 54 31.0 Casing Design Calculation & Casing Design Factors Hilcorp DATE: 11/1812019 WELL: MPU M-23 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1299 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 2199 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 Milne Point Unit Calculation/Specification 1 2 3 4 M-23 SB Injector 9-5/8" Hilco+rp Energy Company Drilling Procedure 31.0 Casing Design Calculation & Casing Design Factors Hilcorp DATE: 11/1812019 WELL: MPU M-23 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size 8-1/2" Hole Size Design Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: Drilling Mode MASP: 1299 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 2199 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 55 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 4-1/2" Top (M D) 0 4,866 Top (TVD) 0 3,821 Bottom (MD) 4,866 14,170 Bottom (TVD) 3,821 3,518 Length 4,866 9,304 Weight (ppf) 40 13.5 Grade L-80 L-80 Connection TXP H625 Weight w/o Bouyancy Factor (lbs) 194,640 125,604 Tension at Top of Section (lbs) 194,640 125,604 Min strength Tension (1000 lbs) 916 279 Worst Case Safety Factor (Tension) 4.71 ✓ 2.22 Collapse Pressure at bottom (Psi) 1,888 1,738 Collapse Resistance w/o tension (Psi) 3,090 8,540 Worst Case Safety Factor (Collapse) 1.64 4.91 ' MASP (psi) 1,299 2,199 Minimum Yield (psi) 5,750 9,020 Worst case safety factor (Burst) 4.43 4.10 Page 55 32.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hill 8-1/2" Hole Section MPU M-23 Milne Point Unit MD TVD Planned Top: 4866 3821 Planned TD: 14170 3518 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 3,821 1681 1 Oil 8.46 0.440 Offset Well Mud Densities Well MW ranEe Ton (TVD) Bottom (TVD) Date L-50 Milne Point Unit Surface M-23 SB Injector Hilcorp Enema Company Drilling Procedure 32.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hill 8-1/2" Hole Section MPU M-23 Milne Point Unit MD TVD Planned Top: 4866 3821 Planned TD: 14170 3518 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 3,821 1681 1 Oil 8.46 0.440 Offset Well Mud Densities Well MW ranEe Ton (TVD) Bottom (TVD) 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 forthe 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3,821 (ft) x 0.78(psi/ft)= 2980 2980(psi) - [0.1(psi/ft)*3821(ft)]= 2598 psi MASP from pore pressure (complete evacuation of wellboc- gas from Schrader Bluff OA sand) 3821 (ft) x 0.44(psi/ft)= 1681 psi 1681(psi) - 0.1(psi/ft)*3821(ft) F1299 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressu of entire wellbore to gas at 0.1 psi/ft. Page 56 Hilcorp E—Sy Company 33.0 Spider Plot (NAD 27) (Governmental Sections) Milne Point Unit M-23 SB Injector Drilling Procedure Sec. 10 Sec. t? 1+ 1 ADL35 23' r i 1 + r � �\ •-5.-ifJ Sec. 12 AD038823% . A,1 -23i SHL to I tmru O>' t Q` MPL; M -23i TFIf y: x.,a o Legend +. ` ri IAPU 169 -234 -SHL X MPU l.4 -23a TPH"- gf --- . "'•mto MPU 1.4-23i EHL + 1' Other Surface Holes (SHL) Sec. 14J i ' 1 Sec. 13 rtP +I 1{, J" Other Bottom Hcres (BHL) t + f �+ I - - - Other SVell Paths to JJ Coastline (USGS 1:53k) a �'t. 1 i Od and Gas Unit Boundary IJ Part Footprint r VINE •� i1O[NT r{ %`. •,=' UNIT t 1 I h ° ADL025513 rr ADLOYS514 1 '.44.3 t yr r't y ( 1 141 r r 1 r f U013N009E RIVER UNIT 1 F J ?C•_.ty d — a. a ♦' a 1 + i� # —.-. +— - t;.'C '1S rl f I 0 1 t r a 1 + ( w f r 1 Sec. 22 Sec. 23 0 1 ; Sec. 21 4 P 1 t e' t E a Ito 1 i 1 t ja c 1 z (3s. 41PU\t 1_BHL { { 1. ..,J Sec: 27 ADL025520< `, ADL025519 St..26 E svt 1 - Sec. 25 Milne Point Unit Alaska State Pane cone 4 NAD 1927 n;r, ..sr a,.ra. MPU M-23 Well 0 750 1,500 tJspoatn 1VI&TC1U wp05a N01NN00E==== Feta Page 57 H Hilcorp Energy Company 34.0 Surface Plat (As Built) (NAD 27) Milne Point Unit M-23 SB Injector Drilling Procedure Page 58 1171 12 THS PROJECT PAD SEC. t2 SEC, 11 Y W-13 14-12 ■ 8 11-14 23 U-20 ■ LANE U-57 0 M-15 M-21 ■ M -Is VICINITY MAP M -5a NTS M-22 ■ ■ M-17 M-18 OF M-24 % .... . ............ .. ..... imathy F had U-03 M-05 1 c00 MOOSE PAD GRAPHIC SCALE 100 200 4W .j... SURVEYOR'S CERTIFICATE IN FEET HERESY CERTIFY THAT I AM PROPERLY RECISTWED, AND L)MM TO PRACTICE LAND SURVEYWv ',,N TME STATE OF ALASKA AND 'THAT TK4 AS -BUILT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT LEGEND: NOTES: SUPERV31ON A.110 THAT ALI AS -BUILT CONDUCTOR AtASKA STATE PLANE CODWINATES ALRNAD27� ZONE 4. 50, DIWEN 'SAND OTHER DE77AJLS ARF CORR ECT AS OF MAY 31, 261 9. 2. GECOM PCSTIOX$ ARE NAD77. m EXS1ING CCNDUCICR 3- EASIS OF HCkZCNTAL AND V" -TICAL CCNTR(X 15 SW_ALCAP SIWI NE & SW-.AttAP Mb SE 4. WPU WI)OSE AVLqGM PM SCALE FACTOR IS: CM9903. 5. DA17E OF SURVEt. WAY 31. 2012. & REFEFiNCE FELD BUX: M.14 -M PG. d"EL LOCATED WI THIN PROTRA^.TED SEC, 14, T, 13 N_ R, 9 E., UWAT MERD?AN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC SECT'ON PAD CELLAR NO. COORDINATES 1COORDINATES POSITION(OMS) POSIT1ON(DJ:,Q) OFFSETS ELEVATION BOX EL M-5 _ Y= 6,027,765.67 N= 1,168,03 70'29'12.805' M4615-8903' 4.916' FSL 24.9' 25�0' X= 533,333.85 E= 1,334.97 149-43'39.185' 149,7275514' 831' FEL Y= 6,027,869,67 N= 1,292.04 70*29'14.013" 70.4872258* 5,039' FSL 25.0' 25.2' X= 533,603.87 E= 1,605.02 149'43'31,224' 149.7253399' 561' FEL Y= 6,027,889-58 N= 1,291.95 70'29'14.016" 70,4872266- 5,034' FSL 25.1' 25.3' X- 533,513.90 - E-1,515.04 149'43'33.871" 149�7260753' 651 FFL. re 11 WK i2 �11ficorp Alaska Tm MPU VOOSE PAD AS -BUILT CONDUCTORS AF -LLS 5, 23 & 24 Uht I- - 2W NZ Q4R 0.11e�, QT Ott Page 58 Hilcorp Energy Company Milne Point Unit M-23 SB Injector Drilling Procedure 35.0 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 10.1 10.3 10.5 0 1 11111 500 1000 1500 2000 w D 2500 3000 3500 4000 4500 Page 59 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 i lcorp Alaska, LLC Milne Point M Pt Moose Pad Plan: MPU M -23i MPU M -23i Plan: MPU M-23 wp05a Standard Proposal Report 11 November, 2019 HALLIBURTON Sperry Drilling Services ❑ m > ❑ F- m N (V W (V lh N m N N N m ❑ N ❑ ❑ N ❑ 0) <V ❑ 0) N ❑ I� ❑ ❑ Np ❑ p ❑ ❑ ❑ ❑�❑ p e+i o O ripe Qpm an ❑Nps p m m n Q❑f0 m m N r nOco � W O W r m m m N 0m O Q!Up iMM(m0 n � V i7 n O � M W N r QpN❑n❑m❑ W❑ m❑N❑ W❑ 0) nm��o^oNooON000m��r�roNo��m��oag�gogmg�gng�g�grn pogo �N MQ�ry�QNWm�m�o �r�c6�r� m- u�- m- �n- 0 �n- 0 'n- � ❑�M �M�M Qevmj W mMevnj O)n��vmjmevmj NemjQM mMM�N�n Mn M OM m MM�MpQpM�MN_M b O N N 0) Om N r M 0 Q f� O N O) M c7 0) p M O W O M p N O Q❑ N O Q O M O- bN voM� mm��o�ro�NNNN�roOi�M� ..0"006 ..o ..� ..6 ....., ..Q ..n . .. 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V 0,111in9 2250 1500 -2250 -3000 O v� -3750 L t 7O C 1 -4500 7 O -75 -9750 -10500 Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Plan: MPU M-23 wp05a WELL DETAILS: Plan: MPU M -23i Ground Level: 25.20 +N/ -S +E/ -W Northing Fasting Latittude longitude 0.00 0.00 6027889.67 533603.87 700 29' 14.013 N 149° 43'31.224 W REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan: MPU M -23i, True North Vertical (TVD) Reference: MPU M-23 Planned RKB @ 58.90usft Measured Depth Reference: MPU M-23 Planned RKB @ 58.90usft Calculation Method Minimum Curvature CASING DETAILS I TVD TVDSS MD Size Name 3821.90 3763.00 4866.14 9-5/8 9 5/8" x 12 1/4" 3518.20 3459.30 14170.37 4-1/2 4 1/2" x 8 1/2" 9 5/8" x 12 1/4 - - - - - - - - - - - - - Y' - - - M-23 ,pO5 Heel_ _ I I M•23 ap05 CPL _ I I I I M-23 rrp05 CP2- - I I I M-23 ep05 CP3 - - I I I I 0 NI O Start Dir 40/100' : 550' MD, 550'TVD O gzy-o 2� O _ Mart Dlr 4.60/100' : 650' MD, 649.92'TVD 3 Start Dir 4.60/100' : 2298.97' MD, 2116.661TVD 777- 1O 3750 1 _ - End Dir : 4696.44' MD, 3.807.11' TVD - - - - End Dir : 4969.7611M, 3827.3' TVD Start Dir 4o/100': 5200.2' MD, 3831.2'TVD End Dir : 5257.91' MD, 3832.68' TVD -Star+Dir 40/100' : 5449.24' MD, 3839.22'TVD End Dir : 5550.59' MD, 3840.73' TVD Start Dir 4'/100'* 5900.59' MD, 3839.2'TVD End Dir : 6193' MD, 3808.22' TVD End Dir : 6551.75' MD, 3749.46' TVD _- - - End _Dir : 6917.4' MD, 3722.63' TVD SfarTDir_40/100' : 7035.01' MD, 3706.3'TVD End Dir : 7153.46' MD, 3694.71' TVD M-23 wp05 CPT - _ Sqr Dlr 40/100' : 7603.46' MD, 3669.2'TVD End Dir : 7704.53' MD, 3667.03' TVD - Start,Dir 40/100' : 7895.72' MD, 3669.68'TVD I End Dir 8003.04' MD, 3667.14' TVD Start Dir 40/100' : 8903.04' MD, 3612.2'TVD 1 End Dir : 9005.41' MD, 3602.31' TVD Start Dir 40/100' : 9120.26' MD, 3587.13'1VD M-23 xpO5 CP5 - - _ _ End Dir : 9247.63' MD, 3575.92' TVD 1 M-23 wp05 CM Start Dir 40/100' : 9447.63' MD, 3567.2'TVD 1 M-23 rp05 CPI - I - _ _ End Dir : 9560.3' MD, 3566.68' TVD - StartDir 40/100' : 9604.32' MD, 3568.2'TVD - - - Start D_ir 40/100' : 9968.67' MD, 3599.92'TVD MPU 500' Buffer - Full End Dir : 10153.74' MD, 3605.41' TVD M-23 np05 CP8- - - SfariD_ir_40/100' : 10503.74' MD, 3593.2'TVD - - _ End Dir : 10604.55' MD, 3593.23' TVD Start f]h,,[ /100': 10799.09' MD, 3600.12'TVD M-23 ep05 CP9 _ _ I - End Dir `10878.63' MD, 360UT TVD - - _ StartDir 40/100' : 11403.63' MD, 3590.2'TVD - - - End Dir : 11490.62' MD, 3585.82' TVD Start�Y 4 /100' : 11642.34' MD, 3573.57'TVD End Dir ` 11754.33' MD, 3568.9' TVD M-23 ep05 CPI0- - - Start Dir 40/100' : 12404.33' MD, 3567.2'TVD 1 _ End Dir : 12510.22' MD, 3570.84' TVD M-23 ,pO5 CPI I ` Start_Dir 4o/100': 12702.84' MD, 3584.56'TVD - - End -Dir : 12804.98' MD, 3588.2' TVD I Start Dir -4 100' : 13004.98' MD, 3588.2'TVD 1 _ _ _End Dir : 13138.57' MD, 3581.98' TVD M-23 r,p05 T. - - Start Dir 4'/100': 13743.12' MD, 3525.71'TVD 4 1/2" x 8 1/2" _ End Dir 13870.37' MD, 3519.51' TVD _ _ _ _ _ _ _ _ MPU M-23 wp05a 3518 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 West( -)/East(+) (1500 usft/in) Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Design: MPU M-23 wp05a Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -23i TVD Reference: MPU M-23 Planned RKB @ 58.90usft MD Reference: MPU M-23 Planned RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site M Pt Moose Pad Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 usft Slot Radius: Well Plan: MPU M -23i, Slot 22 Well Position +N/ -S 0.00 usft Northing: +E/ -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation Wellbore MPU M -23i Magnetics Model Name Sample Date BGGM2018 12/10/2019 Design MPU M-23 wp05a Audit Notes: 6,027,877.65usft Latitude: 533,363.92usft Longitude: 13-3/16" Grid Convergence: 6,027,889.67 usf Latitude: 533,603.87 usf Longitude: 0.00 usf Ground Level: Declination 16.33 Version: Phase: PROTOTYPE Vertical Section: Depth From (TVD) +Nl-S (usft) (usft) 33.70 0.00 Dip Angle 80.94 Tie On Depth: 33.70 +E/ -W Direction (usft) (°) 0.00 184.00 70° 29' 13.905 N 149° 43'38.286 W 0.26 ° 70° 29' 14.013 N 149° 43' 31.224 W 25.20 usft Field Strength (nT) 57,405.08112083 11/11/2019 6:42:37PM Page 2 COMPASS 5000.15 Build 91 Plan Sections Measured Halliburton HALLIGUR T ION TVD Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -23i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-23 Planned RKB @ 58.90usft Project: Milne Point MD Reference: MPU M-23 Planned RKB @ 58.90usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -23i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -23i (°) (°) Design: MPU M-23 wp05a usft (usft) 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 -25.20 0.00 0.00 0.00 0.00 0.00 0.00 550.00 0.00 0.00 550.00 491.10 0.00 0.00 0.00 0.00 0.00 0.00 650.00 4.00 350.00 649.92 591.02 3.44 -0.61 4.00 4.00 0.00 350.00 1,240.69 30.89 329.67 1,208.50 1,149.60 157.50 -82.28 4.60 4.55 -3.44 -22.99 2,298.97 30.89 329.67 2,116.66 2,057.76 626.48 -356.62 0.00 0.00 0.00 0.00 4,696.44 85.00 184.18 3,807.11 3,748.21 -357.77 -950.03 4.60 2.26 -6.07 -143.01 4,866.14 85.00 184.18 3,821.90 3,763.00 -526.38 -962.35 0.00 0.00 0.00 0.00 4,969.76 89.03 185.15 3,827.30 3,768.40 -629.49 -970.77 4.00 3.89 0.94 13.59 5,200.20 89.03 185.15 3,831.20 3,772.30 -858.97 -991.47 0.00 0.00 0.00 0.00 5,257.91 88.04 187.24 3,832.68 3,773.78 -916.32 -997.70 4.00 -1.71 3.62 115.37 5,449.24 88.04 187.24 3,839.22 3,780.32 -1,106.01 -1,021.79 0.00 0.00 0.00 0.00 5,550.59 90.25 183.84 3,840.73 3,781.83 -1,206.86 -1,031.58 4.00 2.18 -3.35 -57.02 5,900.59 90.25 183.84 3,839.20 3,780.30 -1,556.07 -1,055.02 0.00 0.00 0.00 0.00 6,193.00 101.94 183.33 3,808.22 3,749.32 -1,845.75 -1,073.19 4.00 4.00 -0.17 -2.44 6,339.23 101.94 183.33 3,777.98 3,719.08 -1,988.58 -1,081.51 0.00 0.00 0.00 0.00 6,551.75 93.50 184.40 3,749.46 3,690.56 -2,198.50 -1,095.72 4.00 -3.97 0.50 172.79 6,801.75 93.50 184.40 3,734.20 3,675.30 -2,447.30 -1,114.87 0.00 0.00 0.00 0.00 6,917.40 97.98 183.25 3,722.63 3,663.73 -2,562.08 -1,122.55 4.00 3.88 -0.99 -14.25 7,035.01 97.98 183.25 3,706.30 3,647.40 -2,678.37 -1,129.15 0.00 0.00 0.00 0.00 7,153.46 93.25 183.48 3,694.71 3,635.81 -2,796.01 -1,136.07 4.00 -4.00 0.19 177.24 7,603.46 93.25 183.48 3,669.20 3,610.30 -3,244.46 -1,163.35 0.00 0.00 0.00 0.00 7,704.53 89.21 183.48 3,667.03 3,608.13 -3,345.29 -1,169.48 4.00 -4.00 0.00 -179.99 7,895.72 89.21 183.48 3,669.68 3,610.78 -3,536.11 -1,181.08 0.00 0.00 0.00 0.00 8,003.04 93.50 183.48 3,667.14 3,608.24 -3,643.18 -1,187.59 4.00 4.00 0.00 0.01 8,903.04 93.50 183.48 3,612.20 3,553.30 -4,539.84 -1,242.12 0.00 0.00 0.00 0.00 9,005.41 97.59 183.48 3,602.31 3,543.41 -4,641.52 -1,248.30 4.00 4.00 0.00 -0.01 9,120.26 97.59 183.48 3,587.13 3,528.23 -4,755.16 -1,255.21 0.00 0.00 0.00 0.00 9,247.63 92.50 183.48 3,575.92 3,517.02 -4,881.76 -1,262.91 4.00 -4.00 0.00 179.99 9,447.63 92.50 183.48 3,567.20 3,508.30 -5,081.20 -1,275.04 0.00 0.00 0.00 0.00 9,560.30 88.03 184.02 3,566.68 3,507.78 -5,193.60 -1,282.40 4.00 -3.97 0.48 173.14 9,604.32 88.03 184.02 3,568.20 3,509.30 -5,237.48 -1,285.48 0.00 0.00 0.00 0.00 9,690.91 84.60 184.51 3,573.77 3,514.87 -5,323.65 -1,291.91 4.00 -3.96 0.57 171.83 9,968.67 84.60 184.51 3,599.92 3,541.02 -5,599.31 -1,313.66 0.00 0.00 0.00 0.00 10,153.74 92.00 184.45 3,605.41 3,546.51 -5,783.61 -1,328.10 4.00 4.00 -0.03 -0.48 10,503.74 92.00 184.45 3,593.20 3,534.30 -6,132.34 -1,355.24 0.00 0.00 0.00 0.00 10,604.55 87.97 184.39 3,593.23 3,534.33 -6,232.83 -1,363.01 4.00 -4.00 -0.06 -179.14 10,799.09 87.97 184.39 3,600.12 3,541.22 -6,426.68 -1,377.89 0.00 0.00 0.00 0.00 10,878.63 91.15 184.40 3,600.74 3,541.84 -6,505.97 -1,383.98 4.00 4.00 0.01 0.19 11,403.63 91.15 184.40 3,590.20 3,531.30 -7,029.32 -1,424.25 0.00 0.00 0.00 0.00 11,490.62 94.63 184.38 3,585.82 3,526.92 -7,115.93 -1,430.91 4.00 4.00 -0.02 -0.28 11,642.34 94.63 184.38 3,573.57 3,514.67 -7,266.71 -1,442.46 0.00 0.00 0.00 0.00 11,754.33 90.15 184.37 3,568.90 3,510.00 -7,378.25 -1,451.00 4.00 -4.00 -0.01 -179.83 12,404.33 90.15 184.37 3,567.20 3,508.30 -8,026.35 -1,500.53 0.00 0.00 0.00 0.00 12,510.22 85.91 184.37 3,570.84 3,511.94 -8,131.86 -1,508.59 4.00 -4.00 0.00 180.00 12,702.84 85.91 184.37 3,584.56 3,525.66 -8,323.42 -1,523.23 0.00 0.00 0.00 0.00 12,804.98 90.00 184.37 3,588.20 3,529.30 -8,425.18 -1,531.01 4.00 4.00 0.00 0.00 13,004.98 90.00 184.37 3,588.20 3,529.30 -8,624.60 -1,546.24 0.00 0.00 0.00 0.00 13,138.57 95.34 184.55 3,581.98 3,523.08 -8,757.59 -1,556.62 4.00 4.00 0.13 1.93 11/11/2019 6:42:37PM Page 3 COMPASS 5000.15 Build 91 -111 M14 IR._0 1.. • 0 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Design: MPU M-23 wp05a 13,743.12 95.34 184.55 3,525.71 3,466.81 13,870.37 90.25 184.55 3,519.51 3,460.61 14,170.37 90.25 184.55 3,518.20 3,459.30 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -23i ND Reference: MPU M-23 Planned RKB @ 58.90usft MD Reference: MPU M-23 Planned RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature -9,357.62 -1,604.37 0.00 0.00 0.00 0.00 -9,484.28 -1,614.45 4.00 -4.00 0.00 -180.00 -9,783.33 -1,638.25 0.00 0.00 0.00 0.00 11/11/2019 6:42:37PM Page 4 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Design: MPU M-23 wp05a Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (°) (°) (usft) usft 33.70 0.00 0.00 33.70 -25.20 100.00 0.00 0.00 100.00 41.10 200.00 0.00 0.00 200.00 141.10 300.00 0.00 0.00 300.00 241.10 400.00 0.00 0.00 400.00 341.10 500.00 0.00 0.00 500.00 441.10 550.00 0.00 0.00 550.00 491.10 Start Dir 40/100' : 550' MD, 550'TVD 533,603.87 600.00 2.00 350.00 599.99 541.09 650.00 4.00 350.00 649.92 591.02 Start Dir 4.60/100' : 650' MD, 649.92'TVD -0.85 700.00 6.18 341.63 699.72 640.82 800.00 10.70 335.36 798.61 739.71 900.00 15.26 332.80 896.03 837.13 1,000.00 19.84 331.39 991.35 932.45 1,100.00 24.43 330.50 1,083.96 1,025.06 1,200.00 29.02 329.88 1,173.25 1,114.35 1,240.69 30.89 329.67 1,208.50 1,149.60 End Dir : 1240.69' MD, 1208.5' TVD 533,531.19 1,300.00 30.89 329.67 1,259.40 1,200.50 1,362.34 30.89 329.67 1,312.90 1,254.00 SV5 533,505.39 0.00 -176.53 211.42 1,400.00 30.89 329.67 1,345.21 1,286.31 1,500.00 30.89 329.67 1,431.03 1,372.13 1,600.00 30.89 329.67 1,516.84 1,457.94 1,700.00 30.89 329.67 1,602.66 1,543.76 1,800.00 30.89 329.67 1,688.47 1,629.57 1,900.00 30.89 329.67 1,774.29 1,715.39 1,996.27 30.89 329.67 1,856.90 1,798.00 BPRF -253.19 6,028,338.15 533,348.67 0.00 2,000.00 30.89 329.67 1,860.10 1,801.20 2,100.00 30.89 329.67 1,945.92 1,887.02 2,200.00 30.89 329.67 2,031.74 1,972.84 2,298.97 30.89 329.67 2,116.67 2,057.77 Start Dir 4.6°/100' : 2298.97' MD, 2116.66'TVD 2,300.00 30.85 329.62 2,117.55 2,058.65 2,400.00 27.31 323.57 2,204.95 2,146.05 2,500.00 24.09 315.97 2,295.07 2,236.17 2,600.00 21.35 306.38 2,387.33 2,328.43 2,700.00 19.30 294.50 2,481.14 2,422.24 2,800.00 18.16 280.58 2,575.89 2,516.99 2,900.00 18.11 265.76 2,670.98 2,612.08 3,000.00 19.16 251.71 2,765.78 2,706.88 3,007.54 19.28 250.72 2,772.90 2,714.00 UG COAL1 -531.08 6,028,642.44 533,069.44 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU M -23i MPU M-23 Planned RKB @ 58.90usft MPU M-23 Planned RKB @ 58.90usft True Minimum Curvature 11/11/2019 6.42:37PM Page 5 COMPASS 5000.15 Build 91 Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) -25.20 0.00 0.00 6,027,889.67 533,603.87 0.00 0.00 0.00 0.00 6,027,889.67 533,603.87 0.00 0.00 0.00 0.00 6,027,889.67 533,603.87 0.00 0.00 0.00 0.00 6,027,889.67 533,603.87 0.00 0.00 0.00 0.00 6,027,889.67 533,603.87 0.00 0.00 0.00 0.00 6,027,889.67 533,603.87 0.00 0.00 0.00 0.00 6,027,889.67 533,603.87 0.00 0.00 0.86 -0.15 6,027,890.53 533,603.71 4.00 -0.85 3.44 -0.61 6,027,893.10 533,603.25 4.00 -3.39 7.71 -1.76 6,027,897.37 533,602.08 4.60 -7.57 21.26 -7.33 6,027,910.90 533,596.45 4.60 -20.70 41.41 -17.22 6,027,931.00 533,586.47 4.60 -40.11 68.03 -31.37 6,027,957.55 533,572.20 4.60 -65.68 100.95 -49.69 6,027,990.38 533,553.73 4.60 -97.24 139.95 -72.05 6,028,029.28 533,531.19 4.60 -134.58 157.51 -82.28 6,028,046.79 533,520.89 4.60 -151.38 183.79 -97.66 6,028,073.00 533,505.39 0.00 -176.53 211.42 -113.82 6,028,100.55 533,489.11 0.00 -202.96 228.10 -123.58 6,028,117.19 533,479.27 0.00 -218.93 272.42 -149.50 6,028,161.38 533,453.15 0.00 -261.33 316.73 -175.43 6,028,205.58 533,427.03 0.00 -303.72 361.05 -201.35 6,028,249.77 533,400.91 0.00 -346.12 405.36 -227.27 6,028,293.96 533,374.79 0.00 -388.52 449.68 -253.19 6,028,338.15 533,348.67 0.00 -430.92 492.34 -278.15 6,028,380.70 533,323.53 0.00 -471.73 493.99 -279.12 6,028,382.35 533,322.55 0.00 -473.32 538.31 -305.04 6,028,426.54 533,296.43 0.00 -515.72 582.62 -330.96 6,028,470.73 533,270.31 0.00 -558.11 626.48 -356.62 6,028,514.47 533,244.46 0.00 -600.08 626.93 -356.88 6,028,514.92 533,244.19 4.62 -600.51 667.53 -383.49 6,028,555.40 533,217.41 4.60 -639.16 700.68 -411.31 6,028,588.42 533,189.44 4.60 -670.28 726.17 -440.17 6,028,613.77 533,160.47 4.60 -693.69 743.83 -469.88 6,028,631.29 533,130.69 4.60 -709.24 753.54 -500.25 6,028,640.87 533,100.27 4.60 -716.81 755.26 -531.08 6,028,642.44 533,069.44 4.60 -716.37 748.95 -562.18 6,028,636.00 533,038.37 4.60 -707.91 748.15 -564.53 6,028,635.19 533,036.02 4.60 -706.95 11/11/2019 6.42:37PM Page 5 COMPASS 5000.15 Build 91 Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -23i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-23 Planned RKB @ 58.90usft Project: Milne Point MD Reference: MPU M-23 Planned RKB @ 58.90usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -23i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -23i Design: MPU M-23 wp05a Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (') (1) (usft) usft (usft) (usft) (usft) (usft) 2,800.79 3,100.00 21.15 239.64 2,859.69 2,800.79 734.68 -593.35 6,028,621.59 533,007.27 4.60 -691.50 3,200.00 23.84 229.86 2,952.11 2,893.21 712.52 -624.38 6,028,599.29 532,976.34 4.60 -667.23 3,300.00 27.02 222.10 3,042.43 2,983.53 682.62 -655.07 6,028,569.26 532,945.78 4.60 -635.26 3,400.00 30.54 215.95 3,130.08 3,071.18 645.18 -685.24 6,028,531.68 532,915.79 4.60 -595.80 3,421.94 31.35 214.77 3,148.90 3,090.00 635.97 -691.76 6,028,522.45 532,909.31 4.60 -586.17 LA3 3,500.00 34.30 210.98 3,214.50 3,155.60 600.43 -714.67 6,028,486.80 532,886.56 4.60 -549.11 3,600.00 38.22 206.91 3,295.13 3,236.23 548.66 -743.19 6,028,434.91 532,858.28 4.60 -495.48 3,700.00 42.26 203.49 3,371.46 3,312.56 490.21 -770.61 6,028,376.34 532,831.13 4.60 -435.26 3,768.35 45.07 201.46 3,420.90 3,362.00 446.60 -788.63 6,028,332.66 532,813.31 4.60 -390.50 UGNU MB 3,800.00 46.38 200.58 3,442.99 3,384.09 425.45 -796.75 6,028,311.47 532,805.28 4.60 -368.83 3,900.00 50.57 198.04 3,509.28 3,450.38 354.80 -821.45 6,028,240.72 532,780.91 4.60 -296.63 4,000.00 54.81 195.79 3,569.88 3,510.98 278.71 -844.54 6,028,164.54 532,758.16 4.60 -219.12 4,100.00 59.09 193.77 3,624.41 3,565.51 197.68 -865.88 6,028,083.42 532,737.19 4.60 -136.80 4,170.27 62.11 192.45 3,658.90 3,600.00 138.07 -879.75 6,028,023.75 532,723.59 4.60 -76.36 SB NA 4,200.00 63.39 191.91 3,672.51 3,613.61 112.23 -885.33 6,027,997.89 532,718.13 4.60 -50.20 4,300.00 67.72 190.20 3,713.89 3,654.99 22.90 -902.76 6,027,908.49 532,701.11 4.60 40.12 4,400.00 72.06 188.59 3,748.26 3,689.36 -69.72 -918.06 6,027,815.81 532,686.22 4.60 133.59 4,500.00 76.42 187.05 3,775.42 3,716.52 -165.04 -931.14 6,027,720.44 532,673.58 4.60 229.59 4,600.00 80.78 185.57 3,795.18 3,736.28 -262.45 -941.90 6,027,623.00 532,663.25 4.60 327.51 4,696.44 85.00 184.18 3,807.11 3,748.21 -357.78 -950.03 6,027,527.64 532,655.56 4.60 423.18 End Dir : 4696.44' MD, 3807.11' TVD 4,700.00 85.00 184.18 3,807.42 3,748.52 -361.31 -950.29 6,027,524.10 532,655.32 0.00 426.72 4,800.00 85.00 184.18 3,816.14 3,757.24 -460.67 -957.55 6,027,424.73 532,648.51 0.00 526.34 4,866.14 85.00 184.18 3,821.90 3,763.00 -526.38 -962.35 6,027,359.00 532,644.00 0.00 592.23 Start Dir 41/100' : 4866.14' MD, 3821.9'TVD - 9 5/8" x 12 1/4" 4,878.17 85.47 184.29 3,822.90 3,764.00 -538.34 -963.24 6,027,347.04 532,643.17 4.00 604.22 SB_OA (Heel) 4,900.00 86.32 184.50 3,824.46 3,765.56 -560.05 -964.91 6,027,325.33 532,641.60 4.00 625.99 4,969.76 89.03 185.15 3,827.30 3,768.40 -629.49 -970.77 6,027,255.86 532,636.05 4.00 695.68 End Dir : 4969.76' MD, 3827.3' TVD 5,000.00 89.03 185.15 3,827.81 3,768.91 -659.61 -973.49 6,027,225.74 532,633.47 0.00 725.91 5,100.00 89.03 185.15 3,829.50 3,770.60 -759.19 -982.47 6,027,126.12 532,624.94 0.00 825.87 5,200.20 89.03 185.15 3,831.20 3,772.30 -858.97 -991.47 6,027,026.31 532,616.39 0.00 926.04 Start Dir 41/100' : 5200.2' MD, 3831.2'TVD 5,257.91 88.04 187.24 3,832.68 3,773.78 -916.32 -997.70 6,026,968.94 532,610.42 4.00 983.68 End Dir : 5257.91' MD, 3832.68' TVD 5,300.00 88.04 187.24 3,834.11 3,775.21 -958.05 -1,003.00 6,026,927.19 532,605.31 0.00 1,025.68 5,400.00 88.04 187.24 3,837.53 3,778.63 -1,057.19 -1,015.59 6,026,828.00 532,593.16 0.00 1,125.46 5,449.24 88.04 187.24 3,839.22 3,780.32 -1,106.01 -1,021.79 6,026,779.16 532,587.18 0.00 1,174.60 Start Dir 41/100' : 5449.24' MD, 3839.22'TVD 5,500.00 89.15 185.54 3,840.46 3,781.56 -1,156.44 -1,027.44 6,026,728.71 532,581.77 4.00 1,225.29 11/11/2019 6:42:37PM Page 6 COMPASS 5000.15 Build 91 Halliburton HALLIB . RTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -23i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-23 Planned RKB @ 58.90usft Project: Milne Point MD Reference: MPU M-23 Planned RKB @ 58.90usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -23i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -23i Design: MPU M-23 wp05a 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) 3,781.83 5,550.59 90.25 183.84 3,840.73 3,781.83 -1,206.86 -1,031.58 6,026,678.28 532,577.86 4.00 1,275.88 End Dir : 5550.59' MD, 3840.73' TVD 5,600.00 90.25 183.84 3,840.51 3,781.61 -1,256.16 -1,034.88 6,026,628.98 532,574.77 0.00 1,325.29 5,700.00 90.25 183.84 3,840.08 3,781.18 -1,355.93 -1,041.58 6,026,529.18 532,568.53 0.00 1,425.28 5,800.00 90.25 183.84 3,839.64 3,780.74 -1,455.71 -1,048.28 6,026,429.39 532,562.28 0.00 1,525.28 5,900.59 90.25 183.84 3,839.20 3,780.30 -1,556.07 -1,055.01 6,026,329.00 532,556.00 0.00 1,625.87 Start Dir 41/100' : 5900.59' MD, 3839.2'TVD 6,000.00 94.22 183.67 3,835.32 3,776.42 -1,655.17 -1,061.52 6,026,229.88 532,549.94 4.00 1,725.19 6,100.00 98.22 183.50 3,824.49 3,765.59 -1,754.37 -1,067.73 6,026,130.67 532,544.18 4.00 1,824.57 6,193.00 101.94 183.33 3,808.22 3,749.32 -1,845.75 -1,073.19 6,026,039.27 532,539.14 4.00 1,916.12 End Dir : 6193' MD, 3808.22' TVD 6,200.00 101.94 183.33 3,806.77 3,747.87 -1,852.59 -1,073.59 6,026,032.43 532,538.77 0.00 1,922.97 6,300.00 101.94 183.33 3,786.09 3,727.19 -1,950.26 -1,079.28 6,025,934.74 532,533.52 0.00 2,020.80 6,339.23 101.94 183.33 3,777.98 3,719.08 -1,988.58 -1,081.51 6,025,896.42 532,531.46 0.00 2,059.18 Start Dir 4°/100' : 6339.23' MD, 3777.98'TVD 6,400.00 99.52 183.64 3,766.66 3,707.76 -2,048.17 -1,085.15 6,025,836.82 532,528.09 4.00 2,118.88 6,500.00 95.55 184.14 3,753.55 3,694.65 -2,147.06 -1,091.88 6,025,737.91 532,521.81 4.00 2,217.99 6,551.75 93.50 184.40 3,749.46 3,690.56 -2,198.50 -1,095.72 6,025,686.46 532,518.20 4.00 2,269.58 End Dir : 6551.75' MD, 3749.46' TVD 6,600.00 93.50 184.40 3,746.52 3,687.62 -2,246.52 -1,099.42 6,025,638.43 532,514.72 0.00 2,317.74 6,700.00 93.50 184.40 3,740.41 3,681.51 -2,346.04 -1,107.08 6,025,538.89 532,507.51 0.00 2,417.55 6,801.75 93.50 184.40 3,734.20 3,675.30 -2,447.30 -1,114.87 6,025,437.60 532,500.18 0.00 2,519.11 Start Dir 41/100' : 6801.75' MD, 3734.2'TVD 6,900.00 97.31 183.43 3,724.95 3,666.05 -2,544.86 -1,121.54 6,025,340.02 532,493.95 4.00 2,616.90 6,917.40 97.98 183.25 3,722.63 3,663.73 -2,562.08 -1,122.55 6,025,322.80 532,493.02 4.00 2,634.14 End Dir : 6917.4' MD, 3722.63' TVD 7,000.00 97.98 183.25 3,711.16 3,652.26 -2,643.75 -1,127.19 6,025,241.12 532,488.75 0.00 2,715.94 7,035.01 97.98 183.25 3,706.30 3,647.40 -2,678.36 -1,129.15 6,025,206.50 532,486.94 0.00 2,750.60 Start Dir 41/100' : 7035.01' MD, 3706.3'TVD 7,100.00 95.39 183.38 3,698.74 3,639.84 -2,742.80 -1,132.89 6,025,142.05 532,483.50 4.00 2,815.14 7,153.46 93.25 183.48 3,694.71 3,635.81 -2,796.01 -1,136.07 6,025,088.83 532,480.55 4.00 2,868.45 End Dir : 7153.46' MD, 3694.71' TVD 7,200.00 93.25 183.48 3,692.07 3,633.17 -2,842.39 -1,138.89 6,025,042.45 532,477.94 0.00 2,914.91 7,300.00 93.25 183.48 3,686.40 3,627.50 -2,942.04 -1,144.95 6,024,942.78 532,472.33 0.00 3,014.74 7,400.00 93.25 183.48 3,680.73 3,621.83 -3,041.70 -1,151.01 6,024,843.10 532,466.72 0.00 3,114.58 7,500.00 93.25 183.48 3,675.07 3,616.17 -3,141.35 -1,157.08 6,024,743.43 532,461.11 0.00 3,214.41 7,603.46 93.25 183.48 3,669.20 3,610.30 -3,244.46 -1,163.35 6,024,640.31 532,455.31 0.00 3,317.70 Start Dir 4°/100' : 7603.46' MD, 3669.2'TVD - Start Dir 41/100' : 7603.46' MD, 3669.2'TVD 7,704.53 89.21 183.48 3,667.03 3,608.13 -3,345.29 -1,169.48 6,024,539.46 532,449.63 4.00 3,418.72 End Dir : 7704.53' MD, 3667.03' TVD 7,800.00 89.21 183.48 3,668.35 3,609.45 -3,440.58 -1,175.27 6,024,444.15 532,444.27 0.00 3,514.18 7,895.72 89.21 183.48 3,669.68 3,610.78 -3,536.11 -1,181.08 6,024,348.60 532,438.90 0.00 3,609.89 Start Dir 4°/100' : 7895.72' MD, 3669.68'TVD 7,900.00 89.38 183.48 3,669.73 3,610.83 -3,540.39 -1,181.34 6,024,344.33 532,438.66 4.00 3,614.17 8,003.04 93.50 183.48 3,667.14 3,608.24 -3,643.18 -1,187.59 6,024,241.52 532,432.87 4.00 3,717.15 End Dir : 8003.04' MD, 3667.14' TVD 11/11/2019 6:42:37PM Page 7 COMPASS 5000.15 Build 91 HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU M -23i Company: Hilcorp Alaska, LLC TVD Reference: MPU M-23 Planned RKB @ 58.90usft Project: Milne Point MD Reference: MPU M-23 Planned RKB @ 58.90usft Site: M Pt Moose Pad North Reference: True Well: Plan: MPU M -23i Survey Calculation Method: Minimum Curvature Wellbore: MPU M -23i Design: MPU M-23 wp05a 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) 3,602.32 8,100.00 93.50 183.48 3,661.22 3,602.32 -3,739.78 -1,193.46 6,024,144.90 532,427.43 0.00 3,813.92 8,200.00 93.50 183.48 3,655.12 3,596.22 -3,839.41 -1,199.52 6,024,045.26 532,421.83 0.00 3,913.73 8,300.00 93.50 183.48 3,649.01 3,590.11 -3,939.04 -1,205.58 6,023,945.61 532,416.22 0.00 4,013.54 8,400.00 93.50 183.48 3,642.91 3,584.01 -4,038.67 -1,211.64 6,023,845.97 532,410.61 0.00 4,113.35 8,500.00 93.50 183.48 3,636.80 3,577.90 -4,138.30 -1,217.70 6,023,746.32 532,405.00 0.00 4,213.16 8,600.00 93.50 183.48 3,630.70 3,571.80 -4,237.93 -1,223.76 6,023,646.67 532,399.39 0.00 4,312.97 8,700.00 93.50 183.48 3,624.60 3,565.70 -4,337.56 -1,229.82 6,023,547.03 532,393.79 0.00 4,412.78 8,800.00 93.50 183.48 3,618.49 3,559.59 -4,437.19 -1,235.87 6,023,447.38 532,388.18 0.00 4,512.59 8,903.04 93.50 183.48 3,612.20 3,553.30 -4,539.85 -1,242.12 6,023,344.71 532,382.40 0.00 4,615.43 Start Dir 4°/100' : 8903.04' MD, 3612.2'TVD 9,005.41 97.59 183.48 3,602.31 3,543.41 -4,641.53 -1,248.30 6,023,243.01 532,376.68 4.00 4,717.30 End Dir : 9005.41' MD, 3602.31' TVD 9,100.00 97.59 183.48 3,589.80 3,530.90 -4,735.11 -1,253.99 6,023,149.41 532,371.41 0.00 4,811.05 9,120.26 97.59 183.48 3,587.13 3,528.23 -4,755.16 -1,255.21 6,023,129.36 532,370.28 0.00 4,831.14 Start Dir 4°1100' : 9120.26' MD, 3587.13'TVD 9,200.00 94.41 183.48 3,578.79 3,519.89 -4,834.31 -1,260.02 6,023,050.20 532,365.83 4.00 4,910.43 9,247.63 92.50 183.48 3,575.92 3,517.02 -4,881.76 -1,262.91 6,023,002.74 532,363.16 4.00 4,957.96 End Dir : 9247.63' MD, 3575.92' TVD 9,300.00 92.50 183.48 3,573.64 3,514.74 -4,933.98 -1,266.08 6,022,950.50 532,360.22 0.00 5,010.28 9,400.00 92.50 183.48 3,569.28 3,510.38 -5,033.70 -1,272.15 6,022,850.77 532,354.60 0.00 5,110.18 9,447.63 92.50 183.48 3,567.20 3,508.30 -5,081.20 -1,275.04 6,022,803.26 532,351.93 0.00 5,157.77 Start Dir 411100' : 9447.63' MD, 3567.2'TVD 9,500.00 90.42 183.73 3,565.87 3,506.97 -5,133.45 -1,278.33 6,022,751.01 532,348.87 4.00 5,210.11 9,560.30 88.03 184.02 3,566.68 3,507.78 -5,193.60 -1,282.40 6,022,690.84 532,345.07 4.00 5,270.40 End Dir : 9560.3' MD, 3566.68' TVD 9,604.32 88.03 184.02 3,568.20 3,509.30 -5,237.49 -1,285.48 6,022,646.95 532,342.19 0.00 5,314.40 Start Dir 41/100' : 9604.32' MD, 3568.2'TVD 9,690.91 84.60 184.51 3,573.77 3,514.87 -5,323.64 -1,291.91 6,022,560.77 532,336.16 4.00 5,400.80 End Dir : 9690.91' MD, 3573.77' TVD 9,700.00 84.60 184.51 3,574.63 3,515.73 -5,332.67 -1,292.62 6,022,551.74 532,335.48 0.00 5,409.84 9,800.00 84.60 184.51 3,584.04 3,525.14 -5,431.91 -1,300.45 6,022,452.47 532,328.10 0.00 5,509.40 9,900.00 84.60 184.51 3,593.46 3,534.56 -5,531.16 -1,308.28 6,022,353.20 532,320.72 0.00 5,608.95 9,968.67 84.60 184.51 3,599.92 3,541.02 -5,599.31 -1,313.66 6,022,285.03 532,315.65 0.00 5,677.31 Start Dir 411100' : 9968.67' MD, 3599.92'TVD 10,000.00 85.85 184.50 3,602.53 3,543.63 -5,630.44 -1,316.11 6,022,253.90 532,313.34 4.00 5,708.53 10,100.00 89.85 184.47 3,606.28 3,547.38 -5,730.04 -1,323.93 6,022,154.27 532,305.98 4.00 5,808.44 10,153.74 92.00 184.45 3,605.41 3,546.51 -5,783.61 -1,328.10 6,022,100.69 532,302.04 4.00 5,862.16 End Dir : 10153.74' MD, 3605.41' TVD 10,200.00 92.00 184.45 3,603.80 3,544.90 -5,829.70 -1,331.69 6,022,054.59 532,298.66 0.00 5,908.39 10,300.00 92.00 184.45 3,600.31 3,541.41 -5,929.34 -1,339.44 6,021,954.93 532,291.36 0.00 6,008.33 10,400.00 92.00 184.45 3,596.82 3,537.92 -6,028.98 -1,347.20 6,021,855.26 532,284.06 0.00 6,108.27 10,503.74 92.00 184.45 3,593.20 3,534.30 -6,132.34 -1,355.24 6,021,751.87 532,276.48 0.00 6,211.94 Start Dir 40/100' : 10503.74' MD, 3593.2'TVD 10,604.55 87.97 184.39 3,593.23 3,534.33 -6,232.83 -1,363.01 6,021,651.36 532,269.17 4.00 6,312.73 End Dir : 10604.55' MD, 3593.23' TVD 11/11/2019 6:42:37PM Page 8 COMPASS 5000.15 Build 91 ZnTA IR IR I =1w1=11 0 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Design: MPU M-23 wp05a Planned Survey Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Measured 532,247.89 0.00 Vertical 6,021,257.14 532,240.67 0.00 Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W (usft) (°) (°) (usft) usft (usft) (usft) 10,700.00 87.97 184.39 3,596.61 3,537.71 -6,327.94 -1,370.31 10,799.09 87.97 184.39 3,600.12 3,541.22 -6,426.68 -1,377.89 Start Dir 41/100' : 10799.09' MD, 3600.12'TVD 6,020,617.23 532,194.40 10,878.63 91.15 184.40 3,600.74 3,541.84 -6,505.97 -1,383.98 End Dir : 10878.63' MD, 3600.74' TVD 7,461.49 6,020,460.12 532,183.09 10,900.00 91.15 184.40 3,600.31 3,541.41 -6,527.27 -1,385.62 11,000.00 91.15 184.40 3,598.30 3,539.40 -6,626.96 -1,393.29 11,100.00 91.15 184.40 3,596.29 3,537.39 -6,726.64 -1,400.96 11,200.00 91.15 184.40 3,594.29 3,535.39 -6,826.33 -1,408.63 11,300.00 91.15 184.40 3,592.28 3,533.38 -6,926.01 -1,416.30 11,403.63 91.15 184.40 3,590.20 3,531.30 -7,029.32 -1,424.25 Start Dir 4°/100' :11403.63' MD, 3590.2'TVD 4.00 8,511.46 6,019,363.72 11,490.62 94.63 184.38 3,585.82 3,526.92 -7,115.93 -1,430.91 End Dir : 11490.62' MD, 3585.82' TVD 4.00 8,806.40 6,019,126.00 11,500.00 94.63 184.38 3,585.06 3,526.16 -7,125.25 -1,431.62 11,600.00 94.63 184.38 3,576.99 3,518.09 -7,224.63 -1,439.24 11,642.34 94.63 184.38 3,573.57 3,514.67 -7,266.71 -1,442.46 Start Dir 41/100' : 11642.34' MD, 3573.57'TVD 11,700.00 92.32 184.38 3,570.07 3,511.17 -7,324.09 -1,446.86 11,754.33 90.15 184.37 3,568.90 3,510.00 -7,378.25 -1,451.00 End Dir : 11754.33' MD, 3568.9' TVD 11,800.00 90.15 184.37 3,568.78 3,509.88 -7,423.79 -1,454.48 11,900.00 90.15 184.37 3,568.52 3,509.62 -7,523.50 -1,462.10 12,000.00 90.15 184.37 3,568.26 3,509.36 -7,623.20 -1,469.72 12,100.00 90.15 184.37 3,568.00 3,509.10 -7,722.91 -1,477.34 12,200.00 90.15 184.37 3,567.73 3,508.83 -7,822.62 -1,484.96 12,300.00 90.15 184.37 3,567.47 3,508.57 -7,922.33 -1,492.58 12,404.33 90.15 184.37 3,567.20 3,508.30 -8,026.36 -1,500.53 Start Dir 41/100' : 12404.33' MD, 3567.2'TVD 12,500.00 86.32 184.37 3,570.14 3,511.24 -8,121.69 -1,507.81 12,510.22 85.91 184.37 3,570.84 3,511.94 -8,131.85 -1,508.59 End Dir : 12510.22' MD, 3570.84' TVD 12,600.00 85.91 184.37 3,577.23 3,518.33 -8,221.15 -1,515.41 12,702.84 85.91 184.37 3,584.56 3,525.66 -8,323.43 -1,523.23 Start Dir 40/100' : 12702.84' MD, 3584.56'TVD 12,804.98 90.00 184.37 3,588.20 3,529.30 -8,425.18 -1,531.01 End Dir : 12804.98' MD, 3588.2' TVD 12,900.00 90.00 184.37 3,588.20 3,529.30 -8,519.93 -1,538.25 13,004.98 90.00 184.37 3,588.20 3,529.30 -8,624.60 -1,546.24 Start Dir 40/100' : 13004.98' MD, 3588.2'TVD 13,100.00 93.80 184.50 3,585.05 3,526.15 -8,719.27 -1,553.59 13,138.57 95.34 184.55 3,581.98 3,523.08 -8,757.59 -1,556.62 End Dir : 13138.57' MD, 3581.98' TVD 13,200.00 95.34 184.55 3,576.26 3,517.36 -8,818.56 -1,561.47 13,300.00 95.34 184.55 3,566.95 3,508.05 -8,917.82 -1,569.37 Halliburton Standard Proposal Report Well Plan: MPU M -23i MPU M-23 Planned RKB @ 58.90usft MPU M-23 Planned RKB @ 58.90usft True Minimum Curvature Map Northing (usft) 6,021,556.23 6,021,457.47 Map Easting (usft) 532,262.30 532,255.17 6,021,378.15 532,249.43 DLS Vert Section 3,537.71 0.00 6,408.11 0.00 6,507.14 4.00 6,586.66 6,021,356.85 532,247.89 0.00 6,608.03 6,021,257.14 532,240.67 0.00 6,708.01 6,021,157.43 532,233.45 0.00 6,807.98 6,021,057.72 532,226.23 0.00 6,907.96 6,020,958.01 532,219.01 0.00 7,007.94 6,020,854.68 532,211.53 0.00 7,111.55 6,020,768.05 532,205.27 4.00 7,198.41 6,020,758.73 532,204.60 0.00 7,207.76 6,020,659.32 532,197.43 0.00 7,307.43 6,020,617.23 532,194.40 0.00 7,349.63 6,020,559.84 532,190.26 4.00 7,407.18 6,020,505.67 532,186.36 4.00 7,461.49 6,020,460.12 532,183.09 0.00 7,507.16 6,020,360.39 532,175.92 0.00 7,607.16 6,020,260.66 532,168.75 0.00 7,707.16 6,020,160.92 532,161.59 0.00 7,807.15 6,020,061.19 532,154.42 0.00 7,907.15 6,019,961.46 532,147.25 0.00 8,007.15 6,019,857.41 532,139.77 0.00 8,111.48 6,019,762.06 532,132.92 4.00 8,207.08 6,019,751.89 532,132.19 4.00 8,217.28 6,019,662.57 532,125.77 0.00 8,306.83 6,019,560.27 532,118.41 0.00 8,409.41 6,019,458.49 532,111.10 4.00 8,511.46 6,019,363.72 532,104.29 0.00 8,606.47 6,019,259.02 532,096.76 0.00 8,711.45 6,019,164.33 532,089.85 4.00 8,806.40 6,019,126.00 532,086.99 4.00 8,844.84 6,019,065.01 532,082.41 0.00 8,906.01 6,018,965.73 532,074.96 0.00 9,005.57 11/11/2019 6:42:37PM Page 9 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Design: MPU M-23 wp05a Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -23i TVD Reference: MPU M-23 Planned RKB @ 58.90usft MD Reference: MPU M-23 Planned RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Map Vertical Northing Easting DLS Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W (usft) (°) (°) (usft) usft (usft) (usft) 13,400.00 95.34 184.55 3,557.65 3,498.75 -9,017.07 -1,577.27 13,500.00 95.34 184.55 3,548.34 3,489.44 -9,116.32 -1,585.17 13,600.00 95.34 184.55 3,539.03 3,480.13 -9,215.57 -1,593.07 13,700.00 95.34 184.55 3,529.73 3,470.83 -9,314.82 -1,600.97 13,743.12 95.34 184.55 3,525.71 3,466.81 -9,357.62 -1,604.37 Start Dir 40/100' : 13743.12' MD, 3525.71'TVD 13,800.00 93.06 184.55 3,521.54 3,462.64 -9,414.17 -1,608.87 13,870.37 90.25 184.55 3,519.51 3,460.61 -9,484.28 -1,614.45 End Dir : 13870.37' MD, 3519.51' TVD 13,900.00 90.25 184.55 3,519.38 3,460.48 -9,513.81 -1,616.80 14,000.00 90.25 184.55 3,518.94 3,460.04 -9,613.50 -1,624.73 14,100.00 90.25 184.55 3,518.51 3,459.61 -9,713.18 -1,632.67 14,170.37 90.25 184.55 3,518.20 3,459.30 -9,783.33 -1,638.25 Total Depth : 14170.37' MD, 3518.2' TVD - 4 112" x 8 1/2" Map Map Northing Easting DLS Vert Section (usft) (usft) 3,498.75 6,018,866.46 532,067.51 0.00 9,105.13 6,018,767.18 532,060.06 0.00 9,204.69 6,018,667.90 532,052.61 0.00 9,304.25 6,018,568.63 532,045.16 0.00 9,403.81 6,018,525.82 532,041.95 0.00 9,446.74 6,018,469.26 532,037.71 4.00 9,503.46 6,018,399.13 532,032.45 4.00 9,573.79 6,018,369.59 532,030.23 0.00 9,603.42 6,018,269.88 532,022.75 0.00 9,703.42 6,018,170.17 532,015.27 0.00 9,803.41 6,018,100.00 532,010.00 0.00 9,873.78 11/11/2019 6:42:37PM Page 10 COMPASS 5000.15 Build 91 HALL BURTON Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Design: MPU M-23 wp05a Targets Target Name hit/miss target Dip Angle Dip Dir. Shape (1) V) M-23 wp05 CP1 0.00 0.0 plan hits target center Point M-2.3 wp05 Heel 0.00 0.0 plan hits target center Circle (radius 30.00) M-23 wp05 CP2 0.00 0.0 plan hits target center Point M-23 wp05 CP3 0.00 0.0 plan hits target center Point M-23 wp05 CP9 0.00 0.0 plan hits target center Point M-23 wp05 CP7 0.00 0.0 plan hits target center Point M-23 wp05 CP8 0.00 0.0 plan hits target center Point M-23 wp05 CP5 0.00 0.00 plan hits target center Point M-23 wp05 CP4 0.00 plan hits target center Point M-23 wp05 CP11 0.00 0.00 plan hits target center Point M-23 wp05 Toe 0.00 0.0 plan hits target center Point M-23 wp05 CP6 0.00 0.00 plan hits target center Point M-23 wp05 CP 10 0.00 0.00 plan hits target center Point Casing Points Measured Vertical Depth Depth (usft) (usft) 14,170.37 3,518.20 4 1/2" x 8 1/2" 4,866.14 3,821.90 9 5/8" x 12 1/4" Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -23i TVD Reference: MPU M-23 Planned RKB @ 58.90usft MD Reference: MPU M-23 Planned RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature TVD 0 0 0 0 0 +N/ -S +E/ -W Northing (usft) (usft) (usft) (usft) 0 3,831.20 -858.97 -991.47 6,027,026.31 0 3,821.90 -526.38 -962.35 6,027,359.00 3,839.20 -1,556.07 -1,055.02 6,026,329.00 3,734.20 -2,447.30 -1,114.87 6,025,437.60 3,590.20 -7,029.32 -1,424.25 6,020,854.68 3,568.20 -5,237.48 -1,285.48 6,022,646.95 3,593.20 -6,132.34 -1,355.24 6,021,751.87 3,612.20 -4,539.84 -1,242.12 6,023,344.71 Easting (usft) 532,616.39 532,644.00 532,556.00 532,500.18 532,211.53 532,342.19 532,276.48 532,382.40 0.00 3,669.20 -3,244.46 -1,163.35 6,024,640.31 532,455.31 3,588.20 0 -8,624.60 -1,546.24 6,019,259.02 3,518.20 -9,783.33 -1,638.25 6,018,100.00 3,567.20 -5,081.20 -1,275.04 6,022,803.26 3,567.20 -8,026.35 -1,500.53 6,019,857.41 Casing Hole Diameter Diameter Name 4-1/2 8-1/2 9-5/8 12-1/4 532,096.76 532,010.00 532,351.93 532,139.77 11/11/2019 6:42:37PM Page 11 COMPASS 5000.15 Build 91 Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Design: MPU M-23 wp05a Formations Measured Vertical Vertical Depth Depth Depth SS (usft) (usft) 4,170.27 3,658.90 1,362.34 1,312.90 3,421.94 3,148.90 4,878.17 3,822.90 1,996.27 1,856.90 3,768.35 3,420.90 3,007.54 2,772.90 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU M -23i TVD Reference: MPU M-23 Planned RKB @ 58.90usft MD Reference: MPU M-23 Planned RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature SB_NA SV5 LA3 SB_OA (Heel) BPRF UGNU MB UG_COAL1 Name Dip Dip Direction Lithology (I (I 11/11/2019 6:42:37PM Page 12 COMPASS 5000.15 Build 91 Halliburton ALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Company: HilcorpAlaska, LLC Project: Milne Point Site: M Pt Moose Pad Well: Plan: MPU M -23i Wellbore: MPU M -23i Design: MPU M-23 wp05a Plan Annotations Local Co-ordinate Reference: Well Plan: MPU M -23i TVD Reference: MPU M-23 Planned RKB @ 58.90usft MD Reference: MPU M-23 Planned RKB @ 58.90usft North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 550.00 550.00 0.00 0.00 Start Dir 40/100' : 550' MD, 550'TVD 650.00 649.92 3.44 -0.61 Start Dir 4.60/100': 650' MD, 649.92'TVD 1,240.69 1,208.50 157.51 -82.28 End Dir : 1240.69' MD, 1208.5' TVD 2,298.97 2,116.67 626.48 -356.62 Start Dir 4.60/100' : 2298.97' MD, 2116.66'TVD 4,696.44 3,807.11 -357.78 -950.03 End Dir : 4696.44' MD, 3807.11' TVD 4,866.14 3,821.90 -526.38 -962.35 Start Dir 40/100' : 4866.14' MD, 3821.9'TVD 4,969.76 3,827.30 -629.49 -970.77 End Dir : 4969.76' MD, 3827.3' TVD 5,200.20 3,831.20 -858.97 -991.47 Start Dir 40/100': 5200.2' MD, 3831.2'TVD 5,257.91 3,832.68 -916.32 -997.70 End Dir : 5257.91' MD, 3832.68' TVD 5,449.24 3,839.22 -1,106.01 -1,021.79 Start Dir 40/100' : 5449.24' MD, 3839.22'TVD 5,550.59 3,840.73 -1,206.86 -1,031.58 End Dir : 5550.59' MD, 3840.73' TVD 5,900.59 3,839.20 -1,556.07 -1,055.01 Start Dir 40/100' : 5900.59' MD, 3839.2'TVD 6,193.00 3,808.22 -1,845.75 -1,073.19 End Dir : 6193' MD, 3808.22' TVD 6,339.23 3,777.98 -1,988.58 -1,081.51 Start Dir 40/100' : 6339.23' MD, 3777.98'TVD 6,551.75 3,749.46 -2,198.50 -1,095.72 End Dir : 6551.75' MD, 3749.46' TVD 6,801.75 3,734.20 -2,447.30 -1,114.87 Start Dir 40/100' : 6801.75' MD, 3734.2'TVD 6,917.40 3,722.63 -2,562.08 -1,122.55 End Dir : 6917.4' MD, 3722.63' TVD 7,035.01 3,706.30 -2,678.36 -1,129.15 Start Dir 40/100' : 7035.01' MD, 3706.3'TVD 7,153.46 3,694.71 -2,796.01 -1,136.07 End Dir : 7153.46' MD, 3694.71' TVD 7,603.46 3,669.20 -3,244.46 -1,163.35 Start Dir 40/100' : 7603.46' MD, 3669.2'TVD 7,603.46 3,669.20 -3,244.46 -1,163.35 Start Dir 41/100' : 7603.46' MD, 3669.2'TVD 7,704.53 3,667.03 -3,345.29 -1,169.48 End Dir : 7704.53' MD, 3667.03' TVD 7,895.72 3,669.68 -3,536.11 -1,181.08 Start Dir 41/100' : 7895.72' MD, 3669.68'TVD 8,003.04 3,667.14 -3,643.18 -1,187.59 End Dir : 8003.04' MD, 3667.14' TVD 8,903.04 3,612.20 -4,539.85 -1,242.12 Start Dir 40/100' : 8903.04' MD, 3612.2'TVD 9,005.41 3,602.31 -4,641.53 -1,248.30 End Dir : 9005.41' MD, 3602.31' TVD 9,120.26 3,587.13 -4,755.16 -1,255.21 Start Dir 40/100' : 9120.26' MD, 3587.13'TVD 9,247.63 3,575.92 -4,881.76 -1,262.91 End Dir : 9247.63' MD, 3575.92' TVD 9,447.63 3,567.20 -5,081.20 -1,275.04 Start Dir4°/100' : 9447.63' MD, 3567.2'TVD 9,560.30 3,566.68 -5,193.60 -1,282.40 End Dir : 9560.3' MD, 3566.68' TVD 9,604.32 3,568.20 -5,237.49 -1,285.48 Start Dir 40/100' : 9604.32' MD, 3568.2'TVD 9,690.91 3,573.77 -5,323.64 -1,291.91 End Dir : 9690.91' MD, 3573.77' TVD 9,968.67 3,599.92 -5,599.31 -1,313.66 Start Dir 40/100' : 9968.67' MD, 3599.92'TVD 10,153.74 3,605.41 -5,783.61 -1,328.10 End Dir : 10153.74' MD, 3605.41' TVD 10,503.74 3,593.20 -6,132.34 -1,355.24 Start Dir 40/100' : 10503.74' MD, 3593.2'TVD 10,604.55 3,593.23 -6,232.83 -1,363.01 End Dir : 10604.55' MD, 3593.23' TVD 10,799.09 3,600.12 -6,426.68 -1,377.89 Start Dir 41/100' : 10799.09' MD, 3600.12'TVD 10,878.63 3,600.74 -6,505.97 -1,383.98 End Dir : 10878.63' MD, 3600.74' TVD 11,403.63 3,590.20 -7,029.32 -1,424.25 Start Dir 4°/100' : 11403.63' MD, 3590.2'TVD 11,490.62 3,585.82 -7,115.93 -1,430.91 End Dir : 11490.62' MD, 3585.82' TVD 11,642.34 3,573.57 -7,266.71 -1,442.46 Start Dir 40/100' : 11642.34' MD, 3573.57'TVD 11,754.33 3,568.90 -7,378.25 -1,451.00 End Dir : 11754.33' MD, 3568.9' TVD 12,404.33 3,567.20 -8,026.36 -1,500.53 Start Dir 41/100' : 12404.33' MD, 3567.2'TVD 12,510.22 3,570.84 -8,131.85 -1,508.59 End Dir : 12510.22' MD, 3570.84' TVD 12,702.84 3,584.56 -8,323.43 -1,523.23 Start Dir 40/100' : 12702.84' MD, 3584.56'TVD 12,804.98 3,588.20 -8,425.18 -1,531.01 End Dir : 12804.98' MD, 3588.2' TVD 13,004.98 3,588.20 -8,624.60 -1,546.24 Start Dir 40/100' : 13004.98' MD, 3588.2'TVD 13,138.57 3,581.98 -8,757.59 -1,556.62 End Dir : 13138.57' MD, 3581.98' TVD 13,743.12 3,525.71 -9,357.62 -1,604.37 Start Dir 40/100' : 13743.12' MD, 3525.7l'TVD 13,870.37 3,519.51 -9,484.28 -1,614.45 End Dir : 13870.37' MD, 3519.51' TVD 14,170.37 3,518.20 -9,783.33 -1,638.25 Total Depth : 14170.37' MD, 3518.2' TVD 11/11/2019 6:42:37PM Page 13 COMPASS 5000.15 Build 91 m U L m c 'L 0 L L Q M N 7 O O O N C O LO 0 fL0 U C r rrr 3 a V M N N N d _ N M O d e7 O _a W O X M C) MO M OC� 0 � 2 Z + y O O O d cli � ❑ � c J C z N N t N 3 O N CL a o w. am rrlrtCD m co D m a W rn n M rrrr A/ v CO 10�' $ 3 i r. 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A Inc. SIMPSON LAGOON 32-14A r1XIAl AUAMIlInki QVW'POU 'AD -ILE 32-4A AbwConmen'. Marker Cosmq Perno�ed IT Seo. (-,o:!e TQC of 3 -?' Bel:. Grade W. 68 75 #Pt. ^iode 8 of 80 MU Cerie,ter to :U-forq Sirfoce Pug F,ori 20 ',o Su,f::ce (Permof—st aside 7' & ?" v 13-31/8' A,nAus .n'- F.b 0/11. Grzide 8 v 498' V -D Cemented To Sirface ETOC 7' . :3-3/5* AwiL,.us of 610' 107) 13-318', 68 v #' 'ft. K -t5 at 7650' MD to 7,urfc-., PL, #3 orn 2550' YD to 4348' MD (Clos5 1-?etarler at 4148' Y:) Cement P,g #2 From 4346' iq[) !0 4505' 641) (Gloss 'G') Store % at +398' MC, FT04- Plug .01 Gt 5541' U0 (Goss Ret -,per, et 8691' MD -/55 s- 010SE 'G' squeezed below 'P, #/f(, '03 Mm Slatted -irer Trip at 8716* Q 29 gifirt. P -0/N-80 of 8800, MD cenjejtej !o M(' - Section Milled From HOC' MCI to 88513' MD end Wel: RECEIVED JUN - 11992 Alaska 0,1 a Gas Cons. L:, jnl,: Amhorarm 5" Slotted Iner Bottom of 9295' UD TV a! 9100' w) PROPOSED SCHEMATIC Hileorp Alaska. LLC SinVF= Lagoon 32-14 210 s Class I 43.76 bbl 13-3/8" Shoe @ 2,650 J. Sands u Top Z 7211 NU Casing Cit L 3.72 bbl KOP 2;9W WD j Sands 3,255- MD ler Sands ND Est TOC 1,000 sX 7,166 MD Class G 251/6 CH Excess 206.37 bbl 9-5/r 12-1/4" Shoe @ Hole 10,050' PBTD 9,953' MD TD =10,050' MD Milne Point Unit Revised By: STP 8/31/2018 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 711 Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF Hilcorp Alaska, LLC. for disposal of Class II oil field wastes by underground injection in the Ugnu Formation in up to four wells located on the Moose Pad in the northwest portion of the Milne Point Unit Sections 12, 13, 14, 23, 24, T13N, R9E, and Sections 7, 18, 19, T13N, R10E S.M. IT APPEARING THAT: Disposal Injection Order No. 42 Docket No. DIO-18-001 Ugnu Formation, Undefined Waste Disposal Pool Milne Point Unit October 24, 2018 1. Hilcorp Alaska, LLC (Hilcorp) requested authorization for underground disposal of Class II oil field waste fluids into up to four yet to be drilled wells (Class II wells) on the Moose Pad in the northwest portion of the Milne Point Unit (MPU). Hilcorp's Application for Disposal Injection Order (DIO) was received by the Alaska Oil and Gas Conservation Commission (AOGCC) on July 20, 2018. 2. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing for September 5, 2018. On July 24, 2018, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On July 25, 2018, the notice was published in the ANCHORAGE DAILY NEWS. At the September 5, 2018 hearing Hilcorp provided testimony and presented evidence in support of its Application. The record was closed at the end of the hearing. 4. The information submitted by Hilcorp and public records for MPU wells are the basis for this order. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) There are no active wells within the '/4 -mile area of review surrounding the disposal intervals for the proposed Class II wells. The plugged and abandoned Simpson Lagoon 32-14 well lies within '/4 mile of one proposed Class II well in the disposal interval. Future production and injection wells drilled from the Moose Pad may pass within '/4 mile of the proposed Class II disposal wells. Disposal Injection Order 42 October 24, 2018 Page 3 of 7 7. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) The proposed casing program is 10 -3/4 -inch surface casing set at 2,100' TVD and cemented to surface. A formation Integrity Test will be performed to 12.5 ppg equivalent and the production hole drilled. Production 7 -5/8 -inch casing will be set to 3,300' TVD and cemented to approximately 2,100' TVD and tested to 2,500 psi. A cement bond log will be run to confirm the cement top and that casing strings have adequate cement to prevent vertical migration of disposal fluids. Hilcorp requests packers be located more than 200' MD above the top of the disposal perforations. This will allow through -tubing access to the entire requested disposal zone. Tubing or other equipment will be designed and installed in accordance with 20 AAC 25.412. A casing mechanical integrity test will be performed in accordance with 20 AAC 25.412 prior to initiation of disposal operations. Hilcorp will perform mechanical integrity tests of the tubing and tubing -casing annulus (including packer) as part of the operations before disposal injection commences. Additional baseline assessments and subsequent evaluations may be necessary to confirm the wells have the proper mechanical integrity for disposal injection as proposed. Hilcorp will monitor the 7 -5/8 -inch casing by 5 -1/2 -inch tubing annulus pressure daily and report the results on the Monthly Injection Report. 8. Disposal Fluid Type, Composition, Source, Volume, and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) Hilcorp requests approval to dispose of drilling, production, completion, workover wastes, and other associated wastes that are intrinsically derived from primary field operations. Hilcorp expects daily injection volumes of a maximum of 36,000 barrels for the first well, up to a cumulative 72,000 barrels with the proposed two wells. Over the expected 17 -year life of the project, Hilcorp expects to dispose of approximately 355 million barrels of liquids. This equates approximately to a plume of about 1,880' assuming a 300 -foot thickness, radial flow, and 100% pore -space displacement around each of the two planned disposal wells. Injected fluids are expected to be compatible with the lithology and in-situ formation water of the proposed disposal injection zone based on operating experience and past performance of MPU Class I disposal wells B-24, B-34 and B-50 (e.g., pressures, rates, and volumes). No compatibility issues have been reported associated with disposal injection into the Ugnu at Milne Point or other fields on the North Slope. 9. Estimated Injection Pressures (20 AAC 25.252(c)(8)) Hilcorp estimates average surface injection pressure will range from 2,000 to 2,300 psig while injecting 27,000 barrels per day per well for two wells. Maximum surface injection pressure could reach 2,500 psig if sporadic plugging of perforations or fracture -flow channels occurs. Accordingly, Hilcorp requested 2,500 psig as maximum allowed surface injection pressure. Disposal Injection Order 42 October 24, 2018 Page 5 of 7 12. Hilcorp estimates a plume radius of about 1,880' for each disposal well over the 17 -year expected project life. 13. Future wells within 1/2 -mile of the proposed injection interval in each of the disposal wells must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 14. The proposed Ugnu disposal interval is not isolated by cement from the underlying Schrader Bluff in the Simpson Lagoon 32-14 well. No disposal well should be drilled within 3,000' of Simpson Lagoon 32-14 until Hilcorp demonstrates confinement and well integrity issues have been resolved. NOW, THEREFORE, IT IS ORDERED THAT the following rules, in addition to statewide requirements under AS 31.05 and 20 AAC 25 (to the extent not superseded by these rules), govern Class II disposal injection operations into the Ugnu within up to four wells drilled from MPU Moose Pad: RULE 1: Infection Strata for Disposal Underground disposal of Class II oil field waste fluids is permitted into the Ugnu Formation in the interval that is common to, and correlative with, the interval from 3,282' to 3,912' MD (-2,714' to -3,187' TVDSS) in well MPU M-01. RULE 2: Authorized Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production, workover, or abandonment operations, including: Drilling fluids; drill cuttings; well workover fluids; stimulation fluids and solids; produced water; rig wash water; formation materials; naturally occurring radioactive materials; scale; tracer materials; glycol dehydration; reserve pit fluids; chemicals used in the well or for production processing at the surface (in direct contact with produced fluids); and precipitation accumulating in drilling and production impoundment areas. The eligibility of other fluids for Class II waste disposal injection will be considered by the AOGCC on a case-by-case basis upon application by the operator. AOGCC approval is required prior to initiating commercial Class II disposal injection. RULE 3: Injection Rate and Pressure Injection rates and pressures must be maintained such that the injected fluids will not initiate or propagate fractures through the confining intervals or migrate out of the approved injection stratum. Disposal injection is authorized at rates that do not exceed 35,000 BPD per well and wellhead injection pressures that do not exceed 2,500 psig. RULE 4: Demonstration of Mechanical Integrity An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in the well, to be scheduled when injection conditions (temperature, pressure, Disposal Injection Order 42 October 24, 2018 Page 7 of 7 RULE 7: Notification of Improper Class II Infection Injection of fluids other than those listed in Rule 2 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification or other legal requirements of any other State or Federal agency remain the operator's responsibility. RULE 8: Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater or outside of the authorized injection zone. DONE at Anchorage, Alaska, and dated October 24, 2018. OIL,u.�G g //signature on file// //signature on file// //signature on file// Hollis S. French Daniel T. Seamount, Jr. Cathy P. Foerster 0 Chair, Commissioner Commissioner Commissioner 9TIUN t,O' RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Transform Points Source coordinate system _ arget coordinate system State Plane 1927 - Alaska Zone 4 Albers Equal Area (-154) Datum: Datum: NAD 1927 - North America Datum of 1927 (Mean) NAD 1927 - North America Datum of 1927 (Mean) yv pe alues into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to opy and Ctd+Vto paste. Then click on the appropriate arrow button to transform the paints to the desired coordinate system. T < Back Finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: //'hoa- /Iq " Z PTD: - -)-l7 - / 7Z:) — Development zservice _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: �//' (rte �� POOL: Check Box for Appropriate Letter / Paragraphs to be Included in T PTIONS CHECK!between ransmittal Letter TEXT FOR APPROVAL LETTER TThe permit is fora new wellbore segment of existing wellRAL No. API No. 50-t two digits Production should continue to be reported as a function of the original I number are API number stated above. 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs Pilot Hole acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number- - - ) from records, data and logs acquired for well name on rmit . The permit is approved subject to full compliance with 20 AAC 25.055. Spacing Exception Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (Comnanv Name) Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where Sam les are first caught and 10' sam le intervals throu target zones. Please note the following special condition of this permit: Non -Conventional production or production testing of coal bed methane is not allowed for (name of well) until after (Comnan Name) has Well designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Namel must contact the AOGCC to obtain advance a royal 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 Nm -e) 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 da s after com letion, su rasion or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Engineering _Well Name: MILNE PT UNIT M-23 Program SER — Well bore seg ❑ PTD#:2191700 Company Hilcorp Alaska LLC Initial Class/Type SER / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration i 11 Permit _fee attached _ NA 2 Lease number appropriate_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - Yes 3 Unique well name and number Yes 4 Well located in a_defined pool _ Yes 15 Well located proper distance from drilling unit boundary - Yes 6 Well located proper distance from other wells_ Yes 7 Sufficient acreage available in drilling unit Yes - 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes _DLB 11/26/2019 13 Can permit be approved before 15 -day wait - - Yes 14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes AIO No. 10-B applies. 15 All wells within 1/4 -mil -e area of review identified (For service well only) Yes 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) Yes M-23 will not be pre -produced. 17 Nonconven. gas conforms to AS31.05.030(j.1-.A),(j.2.A-D) - NA_ 18 Conductor string provided Yes 20" conductor set at 82 ft. Engineering 19 Surface casing protects all known USDWs NA No freshwater in area. 20 CMT vol adequate to circulate on conductor & surf csg Yes 9 5/8" casing will have 2 stage cement. ES at 2500 ft 21 CMT vol adequate to tie-in long string to surf csg Yes 22 CMT will cover all known productive horizons_ Yes lateral will have ICD and swell packers. 23 Casing designs adequate for C, T, B &_ permafrost_ Yes BTC talcs supplied_ . 24 Adequate tankage or reserve pit Yes Rigs have steel tanks. 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes No issuese with collision. 27 If_diverter required, does it _meet_ regulations_ Yes Doyon 14 drilling surface hole. Innovation will drill lateral. Appr Date 28 Drilling fluid program schematic _& equip list adequate Yes Max form_ pressure =_ 1681_ psi (8.6_ ppg EMW) will drill with 8.8-9.2 ppg mud GLS 12/9/2019 29 BOPEs, do they meet regulation Yes Innovation has 13 5/8" 5000 psi WP BOPS I30 BOPE press rating appropriate; test to _(put psig in comments)_ Yes MASP = 1299 -psi_ ._ Will test BOPE to 3000 psi - - 31 Choke_manifold complies w/API_RP-53 (May 84) Yes Innovation choke skid 32 Work will occur without operation shutdown No Batch_ drilling surface hole with Doyon_ 14 . 33 Is presence_ of H2S gas_ probable No 34 Mechanical condition of wells within AOR verified (For service well only) Yes 1/4 Mile review shows well SL32-14 has open Ugnu and Schrader perfs.. Need Completion mods to accommodate 35 Permit -can be issued w/o hydrogen_ sulfide measuresYes H2S not anticipated from drilling of offset wells; however, rig will have H2S sensors and alarms, Geology 36 Data presented on potential overpressure zones Yes Appr Date I37 Seismic analysis of shallow gas zones NA DLB 11/26/2019 I38 Seabed condition survey (if off -shore) NA I39 Contact name/phone for weekly progress reports_ [exploratory only] - - - - - NA Geologic Date: Engineering Public Date Approving PTD up to running 4 1/2" injection liner. SL 32-14 (PTD 169-052) is within 200 ft of planned wellbore. Will need to Dat e Commissioner: Commissioner: Commissioner modify liner configuration to accommodate the open SB perfs (sundry required to complete well) . GIs p�-s