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215-157
STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT J-28 JBR 09/22/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 2 7/8" & 3 1/2" Test joints. Good test. Test Results TEST DATA Rig Rep:C. Greub/M. SamOperator:Hilcorp Alaska, LLC Operator Rep:CA Dmoski/R. Gallen Rig Owner/Rig No.:Hilcorp ASR 1 PTD#:2151570 DATE:8/5/2025 Type Operation:WRKOV Annular: 250/2000Type Test:INIT Valves: 250/2000 Rams: 250/2000 Test Pressures:Inspection No:bopAGE250808091911 Inspector Adam Earl Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5.5 MASP: 649 Sundry No: 325-403 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 0 NA Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 16 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2 7/8 x 5"P #2 Rams 1 Blind P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16"P HCR Valves 1 2 1/16"P Kill Line Valves 3 2 1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1900 200 PSI Attained P18 Full Pressure Attained P55 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2400 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P13 #1 Rams P6 #2 Rams P6 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill NA0 9 9 9 9 9 9999 9 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,627'N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi Tieback 4,790psi Liner 11,170psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Wells Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng MILNE POINT SCHRADER BLUFF OIL N/A 3,560' 12,622' 3,559' 649 N/A Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT J-28 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 7/20/2025 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025517 / ADL0025906 215-157 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23558-00-00 Hilcorp Alaska LLC C.O 477.005 Length Size Proposed Pools: 110' 110' 6.5# / L-80 / EUE 8rd TVD Burst 7,467' 10,570psi MD N/A 6,890psi 5,750psi 6,890psi 3,594' 3,186' 3,606' 8,819' 6,884' 114' 20" 9-5/8" 7-5/8" 8,819' 7-5/8"1,524' 6,884' 8,408' See Schematic 4,202' See Schematic 2-7/8' 3,560'4-1/2" BOT SLZXP LTP and N/A 8,402 MD / 3,606 TVD and N/A Todd Sidoti todd.sidoti@hilcorp.com 777-8443 12,627' Perforation Depth MD (ft): No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:52 pm, Jul 07, 2025 Digitally signed by Scott Pessetto (9864) DN: cn=Scott Pessetto (9864) Date: 2025.07.07 13:54:58 - 08'00' Scott Pessetto (9864) 325-403 A.Dewhurst 14JUL25 DSR-7/7/25 10-404 * BOPE pressure test to 2000 psi. MGR14JULY25JLC 7/14/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.15 07:54:44 -08'00'07/15/25 RBDMS JSB 071525 ESP Change-Out Well: MPU J-28 Well Name: MPU J-28 API Number: 50-029-23558-00 Current Status: Shut-in ESP Producer Pad: J-Pad Estimated Start Date: July 20th 2024 Rig: ASR Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 215-157 First Call Engineer: Todd Sidoti (907)-777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (O) (907) 947-9553 (M) AFE Number: Current Bottom Hole Pressure: 1049 psi @ 4000’ TVD Calculated from FL shot 5/29/25 – 5.1 PPG MPSP: 649 psi Gas Column Gradient (0.1 psi/ft) 70° Inclination ~2200’ MD Brief Well Summary: MPU J-28 was drilled and completed as a Schrader producer in 2016. The initial ESP installation ran for 9 years and recently died (grounded downhole and unbalanced). The purpose of this procedure is to swap out the ESP and get the well back online. Notes Regarding Wellbore Condition x MIT-OA to 1,500 psi on 9/9/2016. Non- Sundried work Slickline: 1. Pull top GLV and dummy off. 2. Run caliper log from top of discharge head @ 7390’ to surface. Fullbore: 3. Perform MIT-OA to 1500 psi charted for 30 minutes. Sundried Procedure (Approval Required to Proceed) Fullbore: 1. RU FB and PT lines to 3,000 psi. 2. Pump hot diesel spear followed by 500 bbls KWF (source water) down the tubing, through the ESP taking returns up the IA. a. Bullhead additional fluid if necessary. 3. Confirm well is dead. 4. RD FB. 5. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. RU crane. Set BPV. ND Tree. Inspect the tubing hanger lift thread and note any damage. 8. NU BOPE. RD Crane. 9. Spot mud boat. RWO Procedure: ESP Change-Out Well: MPU J-28 10. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to returns tank. 11. If needed, bleed off any residual pressure off the IA. Check for pressure and if 0 psi, pull BPV. If needed, kill well with KWF prior to pulling BPV. 12. Set TWC. 13. Test BOPE to 250 psi Low/ 2,000 psi High, annular to 250 psi Low/ 2,000 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “ASR 1 BOP Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 14. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ KWF as needed. 15. Rig up spoolers for ESP cable and 3/8” capillary string. 16. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. PUW was 94k and SO was 75k during installation. 17. Lay down tubing hanger. 18. POOH and lay down the 2-7/8” tubing while spooling ESP cable and cap string. Cut and trash heat trace as it is removed. Lay down ESP and motor. a. Inspect the connections, plan to wash and inspect tubing pending caliper results. b. Note any sand or scale inside or on the outside of the ESP in WSR. c. The completion has the following number of clamps: i. 168 Cross Collar Clamps ii. 481 5’ Heat Trace Clamps iii. 4 SS bands iv. 8 Pump/Seal Clamps 19. PU new ESP and RIH on 2-7/8” 6.5# EUE 8RD tubing. Set base of ESP assembly at ± 7472’ MD. a. Check ESP cable conductivity every 2,000’ Proposed Running Order a. Base of ESP centralizer @ ±7472’ MD b. Motor gauge c. Motor 562 d. Gas Separator e. 400 Pumps f. Downhole gauge for discharge temperature and pressure. g. 1 joint of 2-7/8” h. Lower 2-7/8” GLM with Dummy GLV on pups i. ± XXX joints 2-7/8” j. GLM, 2-7/8”, DPSOV installed on pups (setting depth +/- 200’ MD). k. +/- XXX joints, 2-7/8” ESP Change-Out Well: MPU J-28 20. PU and MU the 2-7/8” tubing hanger with landing joint. Make the final splice of the ESP cable to the penetrator. Plug off any additional control line ports if present. 21. Land the tubing hanger and RILDS (Caution do not damage the Cable when landing). Lay down landing joint. Note Pick-up and slack-off weights on tally. 22. Set TWC. 23. RDMO ASR. Post-Rig Procedure: 24. RD mud boat. RD BOPE house. Move to next well location. 25. RU crane. ND BOPE. 26. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 27. Pull TWC. 28. RD crane. Move returns tank and rig mats to next well location. 29. Replace gauge(s) if removed. 30. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOP Schematic _____________________________________________________________________________________ Revised By: TDF 8/23/2019 SCHEMATIC Milne Point Unit Well: MPU J-28 Last Completed: 6/11/2016 PTD: 215-157 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"Conductor 78.6 / A-53 / Weld N/A Surface 110’N/A 9-5/8"Surface 40 / L-80 / TC II 8.525 Surface 8,819’0.0758 7-5/8”Tieback 29.7 / L-80 / Vam STL 6.750 Surface 6,884’0.0459 7-5/8”Tieback 29.7 / L-80 / SLIJ II 6.750 6,884’8,408’0.0459 4-1/2”Liner 13.5 / L-80 / HTTC 3.795 8,425’12,627’0.0149 TUBING DETAIL 2-7/8"Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 7,476’0.0058 OPEN HOLE / CEMENT DETAIL 20"Conductor 12-1/4" ES Cmt w/ 405 sx PF 11.1 ppg, 287 sx Class “G” in 12-1/4” Hole; Cmt to Surface (69 bbl) 12-1/4” Shoe Cmt w/ 940 sx 12.0 ppg, 390 sx Class “G” in 12-1/4” Hole 8-1/2”Uncemented Sand Screen Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 357’ 76.3 deg. @ 2,270’ MD Max Hole Angle = 95.2 deg. @ 8,737’ MD TREE & WELLHEAD Tree Seaboard 3 1/8" 5M Wellhead Seaboard 16 3/4" 3M x 11" 5M Multibowl w/11" x 3 1/2" EUE Top and Bottom with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. GENERAL WELL INFO API: 50-029-23558-00-00 Drilled and Cased by Doyon 14 - 6/11/2016 JEWELRY DETAIL No.Depth Item ID Upper Completion 1 30’Tubing Hanger 2.441” 2 172’ST 2:Patco SPMO-1 GLM BK-2 Latch, 1” OGLV 2.441” 3 2,802’ST 1:Patco SPMO-1 GLM BK-2 Latch, 1” DGLV 2.441” 4 3,210’Heat Trace (3,412’ spool)N/A 5 7,379’2-7/8” XN Profile (2.205” No-Go Packing Bore ID)2.205” 6 7,390’Discharge Head - 7 7,391’Centrilift ESP: Tandem FLEX17.5 134 Stages - 8 7,438’Gas Separator - 9 7,441’Tandem Seal Section - 10 7,455’Single ESP Motor (210 HP)- 11 7,472’Phoenix XT150 Sensor w 6 fin Centralizer – Btm @ 7,476’- Lower Completion 12 8,402’BOT SLZXP Liner Top Packer w/BD Slips 9-5/8” x 7”6.200” 13 8,400’7-5/8” Tieback Assy. No-Go (Btm @ 8,410’)6.151” 14 8,425’7” H563 x 4.5” HTTC L-80 XO 3.900” 15 8,798’4-1/2” 300P Screen, WTF MaxFlo 13.5# 13Cr-110 Vam Top – Btm @ 12,214’3.920” 16 12,590’4-1/2” Drillable Packoff Sub 2.400” 17 12,622’WIV Valve LTC BxB (1.5” Ball on Seat/Closed) & Shoe – Btm @ 12,627’- SAFETY NOTE Seaboard conductor supported wellhead. Retrofit reverse acting slip style hanger installed Sep 2019 _____________________________________________________________________________________ Revised By: TDF 6/26/2025 PROPOSED Milne Point Unit Well: MPU J-28 Last Completed: 6/11/2016 PTD: 215-157 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"Conductor 78.6 / A-53 / Weld N/A Surface 110’N/A 9-5/8"Surface 40 / L-80 / TC II 8.525 Surface 8,819’0.0758 7-5/8”Tieback 29.7 / L-80 / Vam STL 6.750 Surface 6,884’0.0459 7-5/8”Tieback 29.7 / L-80 / SLIJ II 6.750 6,884’8,408’0.0459 4-1/2”Liner 13.5 / L-80 / HTTC 3.795 8,425’12,627’0.0149 TUBING DETAIL 2-7/8"Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface ±X,XXX’0.0058 OPEN HOLE / CEMENT DETAIL 20"Conductor 12-1/4" ES Cmt w/ 405 sx PF 11.1 ppg, 287 sx Class “G” in 12-1/4” Hole; Cmt to Surface (69 bbl) 12-1/4” Shoe Cmt w/ 940 sx 12.0 ppg, 390 sx Class “G” in 12-1/4” Hole 8-1/2”Uncemented Sand Screen Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 357’ 76.3 deg. @ 2,270’ MD Max Hole Angle = 95.2 deg. @ 8,737’ MD TREE & WELLHEAD Tree Seaboard 3 1/8" 5M Wellhead Seaboard 16 3/4" 3M x 11" 5M Multibowl w/11" x 3 1/2" EUE Top and Bottom with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. GENERAL WELL INFO API: 50-029-23558-00-00 Drilled and Cased by Doyon 14 - 6/11/2016 JEWELRY DETAIL No.Depth Item ID Upper Completion 1 XX’Tubing Hanger 2.441” 2 XX’GLM #2:2.441” 3 ±X,XXX’GLM #1:2.441” 4 ±X,XXX’Discharge Head 2.205” 5 ±X,XXX’Centrilift ESP: Tandem FLEX17.5 134 Stages - 6 ±X,XXX’Gas Separator - 7 ±X,XXX’Tandem Seal Section - 8 ±X,XXX’Single ESP Motor (210 HP)- 9 ±X,XXX’Phoenix XT150 Sensor w 6 fin Centralizer – Btm @ ±X,XXX’- Lower Completion 10 8,402’BOT SLZXP Liner Top Packer w/BD Slips 9-5/8” x 7”6.200” 11 8,400’7-5/8” Tieback Assy. No-Go (Btm @ 8,410’)6.151” 12 8,425’7” H563 x 4.5” HTTC L-80 XO 3.900” 13 8,798’4-1/2” 300P Screen, WTF MaxFlo 13.5# 13Cr-110 Vam Top – Btm @ 12,214’3.920” 14 12,590’4-1/2” Drillable Packoff Sub 2.400” 15 12,622’WIV Valve LTC BxB (1.5” Ball on Seat/Closed) & Shoe – Btm @ 12,627’- SAFETY NOTE Seaboard conductor supported wellhead. Retrofit reverse acting slip style hanger installed Sep 2019 Milne Point ASR Rig 1 BOPE 2023 11” BOPE 4.48' 4.54' 2.00' CIW-U 4.30' Hydril GK 11" - 5000 VBR or Pipe Rams Blind11'’- 5000 DSA, 11 5M X 7 1/16 5M (If Needed) 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManualHCR Stripping Head 2-7/8” x 5” VBR MEMORANDUM TO: Jim Regg PA. Supervisor FROM: Adam Earl Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, June 8, 2021 SUBJECT: Mechanical Integrity Tests ConowPhdlips Alaska, Inc. 30-16B KUPARUK RN UNIT 30-160 Ste: Inspector Reviewed By: P.I. Supry �.10L� Comm Well Name KUPARUK RIV UNIT 30-16B API Well Number 50-029-21796-02-00 Inspector Name: Adam Earl Permit Number: 215-057-0 Inspection Date: 6/3/2021 — Insp Num: mitAGE210607105513 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 30-1613 Type Inj w • TVD 6357 Tubing 2450 2450 2450 2450 " PTD 1 2150570 Type Test I sPT ITest psi 1589 IA 860 1810 1730 1730 ' BBL Pumped: 0.9 "BBL Returned: 0.7 OA 180 lso - 18 - 150 Interval - 4YRTST P/l,P - Notes: MIT IA Tuesday, June 8, 2021 Page 1 of I STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS f 1. Operations Abandon Ll Plug Perforations Ll Fracture-StimulatLi Pull Tubing Ll Operations shutdown Li Performed: Suspend ❑ Perforate ❑ Other Stimulat] Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair We❑ Re-enter Susto Well ❑ Other: Install Rev. Slip Loc ❑ 2. Operator Hilcorp Alaska LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑� Exploratory ❑ 215-157 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6. API Number: AK 99503 50-029-23558-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0025517 / ADL0025906 MILNE PT UNIT J-28 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10, Field/Pool(s): N/A MILNE POINT/ SCHRADER BLUFF OIL 11. Present Well Condition Summary: Total Depth measured 12,627 feet Plugs measured N/A feet true vertical 3,560 feet Junk measured N/A feet Effective Depth measured 12,622 feet Packer measured 8,402 feet true vertical 3,559 feet true vertical 3,606 feet Casing Length Size MD TVD Burst Collapse Conductor 114' 20" 110' 110' N/A N/A Surface 8,819' 9-5/8" 8,819' 3,594' 5,750psi 3,090psi Tieback 6,884' 7-5/8" 6,884' 3,186' 6,890psi 4,790psi Tieback 1,524' 7-5/8" 8,408' 3,606' 6,890psi 4,790psi Liner 4,202' 4-1/2" 12,627' 3,560' 10,570psi 11,170psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8' 6.5# / L-80 / EUE 8rd 7,467' 3,365' Packers and SSSV (type, measured and true vertical depth) BOT SLZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 374 34 62 320 269 Subsequent to operation: 260 30 69 200 269 14. Attachments (required per2o AAC 25.070, 25.071, s 25.283) 15. Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Q Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-392 Authorized Name: Chad Helgeson Contact Name: Wyatt Rivard Authorized Title: Operations Manager Contact Email: WrlyBrdtC7l.hilcorn.com Authorized Signature: / l ,r Date: 912412019 Contact Phone: 777-8547 Farm 10-404 Revised 4/2017 Ott /I � RBDMS� OCT o 2 tots Submit Original Only Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPJ-281Slickline 50-029-23558-00-00 215-157 9/12/2019 1 9/17/2019 9/11/2019- Wednesday No operations to report. 9/12/2019 - Thursday. Shut in well and bleed tubing and IA down to Opsi. 9/13/2019 - Friday WELL S/I UPON ARRIVAL, NOTIFY PAD-OP, PT PCE: 300L/ 1,SOOH. RUN 2.30" GUAGE RING, TAG XN-NIP @ 7,382' SLM/ 7,379' MD, WHILE LRS DISPLACED TBG WITH 50bbls OF DIESEL. SET 2-7/8" P-XN PLUG BODY IN XN-NIP @ 7,382' SLM/ 7,379' MD. SET PRONG IN P-XN PLUG BODY @ 7,375' SLM. 9/14/2019-Saturday WELL S/I UPON ARRIVAL, NOTIFY PAD-OP, PT PCE: 300L/ 1,500H. SET P-XN PLUG IN XN-NIP @ 7379' MD. WELL S/I UPON DEPARTURE. 9/15/2019-Sunday PJSM / Sign off on Hot Work and Regulated CSE permits /Zero tare weight and then PU well into tension to 60K / Cut out Seaboard bell nipple between casing head and 20" conductor using Air Arc and Oxygen/Acetylene while constant monitoring of atmosphere in cellar for LEL — 02-CO and H2s / Remove bell nipple in two pieces/ Final tension weight = 86k / Neck of bell nipple retained inside bottom of casing head / Dress off entry in bottom of casing head for ease of entry with the Reverse Slip-Lock assembly / Dress off top of 20" conductor / Install Reverse Slip-Lock assembly as per procedure and tighten bottom flange bolts to 125 ft/lbs / Release tension and no slippage of Slip-Lock observed / MIT-OA to 1,OOOpsi passed. Pressured up OA to 1,020psi with —3.5 bbls diesel —IAP = Opsi / MIT-OA lost 10psi in 1st 15 minutes and Opsi in 2nd 15 minutes for a total of 10psi loss in 30 minutes / Bled back —3.5 bbls / Final pressures = Opsi IA/ Opsi OA / tubing has BPV / Remove top plate and cross from WSS / Install and NU tree / Reconnect chemical injection line / Pull BPV and set TWC / PT tree to S,OOOpsi —good / Pull TWC / TH Void test to 5,000psi —good / Prep WSS for travel mode 9/16/2019 - Monday WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE: 300L/ 1,500H. PULL PRONG FROM P-XN PLUG BODY @ 7,375' SLM PULL P-XN PLUG BODY FROM XN-NIP 7,379' MD, MISSING ONE 5/16"x1/4" BRASS NUBBIN FROM PLUG, SEE LOG. WELL S/I UPON DEPARTURE. 9/17/2019-Tuesday MPU Well Support rigged down Maximus and Rehooked well. PT'd surface lines and no issues. MPJ -28 Seaboard Retrofit 9/12/2019 Shut in well and bleed tubing and IA down to 0 psi 9/13/2019 SET 2-7/8"" P-XN PLUG BODY IN XN-NIP @ 7382' SLM/ 7379' MD 9/14/2019 SET PRONG IN P-XN PLUG BODY @ 7375' SLM / I&E disconnect / Isolate ESP cables / Pull Wellhouse / Demobe flowlines / Prep and level pad for WSS / MIRU WSS over well / Flush bell nipple out with water / ND tree at 11" THA flange and pull / Stab cross through the WSS and NU to 11" THA flange / Install top plate over cross / Weight of cross and top plate = 20k 9/15/19 PJSM / Sign off on Hot Work and Regulated CSE permits / Zero tare weight and then PU well into tension to 60K / Cut out Seaboard bell nipple between casing head and 20" conductor using Air Arc and Oxygen/Acetylene while constant monitoring of atmosphere in cellar for LEL - 02 -CO and H2s / Remove bell nipple in two pieces/ Final tension weight = 86k / Neck of bell nipple retained inside bottom of casing head / Dress off entry in bottom of casing head for ease of entry with the Reverse Slip -Lock assembly / Dress off top of 20" conductor / Install Reverse Slip -Lock assembly as per procedure and tighten bottom flange bolts to 125 ft/lbs / Release tension and no slippage of Slip -Lock observed / MIT -OA to 1000 psi passed. Pressured up OA to 1020 psi with -3.5 bbls diesel - IAP = 0 psi / MIT -OA lost 10 psi in 15Y 15 minutes and 0 psi in 2"d 15 minutes for a total of 10 psi loss in 30 minutes / Bled back -3.5 bbls / Final pressures = 0 psi IA / 0 psi OA / tubing has BPV / Remove top plate and cross from WSS / Install and NU tree / Reconnect chemical injection line / Pull BPV and set TWC / PT tree to 5000 psi - good / Pull TWC / TH Void test to 5000 psi -good / Prep WSS for travel mode 4 9/16/2019 Load out WWS and accompanying equipment and truck back to Prudhoe / Install Wellhouse, flowlines and PT same / Reconnect I&E / Pull plug from tubing with slickline / Well ready to POP THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Chad Helgeson Operations Manager Hilcorp Alaska, Inc. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU J-28 Permit to Drill Number: 215-157 Sundry Number: 319-392 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. a 0g cc. of aska.go v Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioners DATED this T day of September, 2019. -AgDMSL1-6 SEP 0 5 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS � rn� GJ.LOU 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Reddll El Perforate New Pool ❑ Re-enter Susp Well EJ Alter Casing EJ Other: Install Rev. Slip Loc Assy. ❑ 2. Operator Name: Well Class: 5. Permit to Drill Number: :urmnt Hilcorp Alaska LLC ry ❑ Development Q 215-157 3. Address: 3800 Centerpoint Dr, Suite 1400 hic ❑ Service ❑ 6. API Number: Anchorage Alaska 99503 50-029-23558-00-00 ' I. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O 477.05 Will planned perforations require a spacing exception? Yes ❑ No ❑� MILNE PT UNIT J-28 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0025517 / ADL0025906 MILNE POINT/ SCHRADER BLUFF OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs 12,627' 3,560' 12,622' 3,559' 671 Casing Length Size MD TVD Burst Collapse Conductor 114' 20^ 110' 110' N/A WA Surface 8,819' 9-5/8" 8,819' 3,594' 5,750psi 3,090psi Tieback 6,884' 7-5/8" 6,884' 3,186' 6,890psi 4,790psi Tieback 1,524' 7-5/8" 08'3,6 6,890psi 4,790psi Liner 41202' 4-1/2" 12,627' 3,560' 10,570psi 11,170psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 2-7/8' 6.5# / L-80 / EUE 8rd 7,467' Packers and SSSV Type: Packers and SSSV MD (tt) and TVD (ft): BOT SLZXP LTP and N/A 8,402 MD / 3,606 TVD and N/A 12. Attachments: Proposal Summary Wellbore schematic EJ 13. Well Class after proposed work: Detailed Operations Program ❑r BOP Sketch ❑ Exploratory ❑ Strati ra hic 9 P ❑ Development 0 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/20/2019 OIL ❑� WINJ ❑ WDSPL ❑ ❑ Suspended 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG El 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: Wyatt Rivard Operations Manager Contact Email: Wrlvard hilcor .COMContact Phone: 777-8547 Signature: Date: 8/28/2019COMMISSION FAuthoriz;edTitle: USE ONLY ns of approval: Notify Commission so that a representative may witness Sundry Number:31q-3g2grity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: l✓e_" H -p , " ��.,...f" Iryz, a-rrC. 01 �"// # /-/� '& ZBDMS[� FP 0 5 2019 Post Initial Injection MIT Req'd? Yes 0 NoY/! Spacing Exception Required? Yes El No Subsequent Form Required: la — L1 OLj Approved by: APPROVED BY 7/ 4h COMMISSIONER THE COMMISSION Date: / ORIGINAL TVJ;FJ ,a-ava rtevisea 4rzur r r -Approved applicatioins, Valid for 12 months from the date of approval F..,. and PP Attachments in Duplicate U llil.0 Alaska. UU Well Prognosis Well: MPU J-28 Date: 8/20/2019 Current Bottom Hole Pressure: 1071psi @ 4000 TVD (Based on current pressure gage BHP Reading) Maximum Expected BHP: 1071psi @ 4000 TVD (Based on current pressure gage BHP Reading) MPSP: 671 psi (0.1 psi/ft gas gradient) Recent SI Tubing Pressure 221 psi (Taken 8/21/19) Min ID: 2.205" ID 2-7/8" XN Nip at 7379' MD Brief Well Summary: The Milne Point 1-28 well is a recently drilled Schrader Bluff ESP well. The well's surface casing was fully cemented and hung off a slip style casing hanger as part of a conductor supported wellhead system. The system has since been identified has having the potential to cause wellhead movement in the event of conductor subsidence. In order to fully tie well load back to the surface casing conductor will be cut and a reverse acting slip style hanger assembly will be Installed. Notes Regarding Wellbore Condition • 7-5/8" x 9-5/8"annulus tested good to 1500 psi passed on 6/10/16 Objective: Cut conductor bell nipple below starting head and install Reverse Slip Loc assembly to ensure fully supported by surface casing. Procedure: Pre -Sundry Work !s Slickline r' -44c 1. MIRU SL unit. 2. Pressure test to 300psi low and at least 1500 psi high. 3. RIH and set 2-7/8" XN at 7379' MD. a. Drawdown tubing pressure to "'0 psi and confirm holding 4. RDMO Prep Work 5. Disconnect flowline and instrumentation. 6. Verify tubing, IA and OA pressures have been bled to Opsi. 7. Sniff cellar and adjacent area with multi -gas meter for LEL, CO, H2S and 02• Ensure confined space, egress and ventilation is adequate for operations 8. Vac out gravel from well cellar down to cellar liner to remove residual hydrocarbons. 9. Install fire blankets around the conductor landing ring to protect surface casing holes from hot machining debris. MPJ -28 API Number: 50-029-23558-00-00 tatus: ESP Pad: J -Pad Start Date: September 20th, 2019 Rig: WSS WWellName:e: oval Req'd? Yes Date Reg. Approval Rec'vd: Contact: Tom Fouts Permit to Drill Number: 215-157 Engineer: ll Engineer: Wyatt Rivard Taylor Wellman (907) 777-8547 (0) (907) 777-8449 (0) (509) 670-8001 (M) (907) 947-9533 (M) Current Bottom Hole Pressure: 1071psi @ 4000 TVD (Based on current pressure gage BHP Reading) Maximum Expected BHP: 1071psi @ 4000 TVD (Based on current pressure gage BHP Reading) MPSP: 671 psi (0.1 psi/ft gas gradient) Recent SI Tubing Pressure 221 psi (Taken 8/21/19) Min ID: 2.205" ID 2-7/8" XN Nip at 7379' MD Brief Well Summary: The Milne Point 1-28 well is a recently drilled Schrader Bluff ESP well. The well's surface casing was fully cemented and hung off a slip style casing hanger as part of a conductor supported wellhead system. The system has since been identified has having the potential to cause wellhead movement in the event of conductor subsidence. In order to fully tie well load back to the surface casing conductor will be cut and a reverse acting slip style hanger assembly will be Installed. Notes Regarding Wellbore Condition • 7-5/8" x 9-5/8"annulus tested good to 1500 psi passed on 6/10/16 Objective: Cut conductor bell nipple below starting head and install Reverse Slip Loc assembly to ensure fully supported by surface casing. Procedure: Pre -Sundry Work !s Slickline r' -44c 1. MIRU SL unit. 2. Pressure test to 300psi low and at least 1500 psi high. 3. RIH and set 2-7/8" XN at 7379' MD. a. Drawdown tubing pressure to "'0 psi and confirm holding 4. RDMO Prep Work 5. Disconnect flowline and instrumentation. 6. Verify tubing, IA and OA pressures have been bled to Opsi. 7. Sniff cellar and adjacent area with multi -gas meter for LEL, CO, H2S and 02• Ensure confined space, egress and ventilation is adequate for operations 8. Vac out gravel from well cellar down to cellar liner to remove residual hydrocarbons. 9. Install fire blankets around the conductor landing ring to protect surface casing holes from hot machining debris. 0 Hilsorp Alaska, LU Well Prognosis Well: MPU J-28 Date: 8/20/2019 Sundry Work (Approval required to proceed) Surface Casing Support Retrofit 10. Sniff cellar and adjacent area with mutli-gas meter for LEL, CO, H2S and 02• Ensure confined space, egress and ventilation is adequate for operations 11. Flush conductor with water from the conductor starting head valve and while taking fluid returns from the cement return line bull plug. Flush until clean returns are observed. 12. Move in and rig up Well Support Structure. Place rig mats as needed to level out support structure legs. 13. Install BPV and nipple down tree at master valve or tubing head adapter as needed to makeup Wellhead Support Structure adapter flange. 14. Prepare to transfer load to the Well Support Structure. Pretension load cells according to operating manual. 15. Pull 8000 lbs (Wellhead Weight) gradually building up load in 1000 b increments. a. Monitor the wellhead for any signs of movement and discontinue increasing tension if movement observed. 16. Increase weight up to 60,000 lbs (50 K preloading) 17. Once pre loaded, begin cutting conductor horizontally at bottom of conductor bell nipple using air arc cutter. a. Monitor load on Well Support Structure in addition to wellhead vertical displacement during cutting operations. a. Maximum dry production casing, tubing and wellhead load= 29#*8400'+6.5#*7450'+8K = 304K b. Maintain constant vertical displacement while well support structure is loaded by well. 18. Proceed to cut conductor bell nipple below the starting head then remove conductor bell nipple section. a. Ensure minimum of 12" of clearance between botto starting head and top of conductor. b. Record Well Support Structure Load in WSR ctor once onduull loadpd. 'r Ccs 19. Leave remaining bell nipple section engaged in starting head. Bevel as needed to ensuY7e smooth entry of slip assembly. 20. Place each half of Reverse Slip Loc assembly around surface casing bolt halve, tngpthpr 21. Install energizing plate halves at 90 degree offset from slip assembly such that joint between halves are perpendicular to slips. 22. Lift Reverse Slip Loc up inside conductor starting head. 23. In a criss cross pattern, begin to tighten bolts on energizing plates initially to 50 ft -lbs on first pass then to a final torque of 100-125 ft -lbs on second pass. 24. Mark casing at the bottom of the Reverse Slip Lac 25. Release tension, observe for any slippage. If slipping occurs, retension and tighten bolts to 150 ft -lbs. 26. Once load is released to Reverse Slip Loc, conduct MIT -OA to 1000 psi to confirm SC integrity. 27. Unbolt and remove the adapter flange 28. Reinstall 5K production tree. 29. Remove BPV and install TWC. Pressure test tree to 5000psi. 30. Re -install flowline and instrumentation 31. Weld centralizer/landing ring onto top of conductor. 32. Reinstall well house and backfill gravel over cellar liner. 33. Install Corrosion Inhibitor in SC by Conductor Annulus up to the conductor top. Slickline 34. MIRU SL unit. 35. Pressure test to 300psi low and at least 1500 psi high. H Ililwrn Alaska, LL - 36. RIH and pull 2-7/8" XN at 7379' MD. 37. RDMO 38. Turn well back over to production Attachments: -Wellbore Schematic Well Prognosis Well: MPU 1-28 Date: 8/20/2019 K Hilcorp Alaska. LLC Ori& KB Elev.: 67.1'/ Ori& GL Elev.: 33.4' T0=12,627 (ND) /TD =3,560'(TVD) PBTD=12,627' (ND) / PBTD= 3,559'MM) SCHEMATIC Milne Point Unit Well: MPU J-28 Last Completed: 6/11/2016 PTD: 215-157 SAFETY NOTE Seaboard conductor supported wellhead. 50-80 Klbs max compressive load. TREE & WELLHEAD Tree Seaboard 31/8" SM 12-1/4" ES Seaboard 163/4" 3M x 11" SM Multibowl w/11" x 31/2" EUE Top and Wellhead Bottom with 3" CIW "H" BPV profile. Zea 3/8" NPT control lines. OPEN HOLE / CEMENT DETAIL 20" Conductor 12-1/4" ES Cmt w/ 405 sx PF 11.1 ppg, 287 sx Class "G" in 12-1/4" Hole; Cmt to Surface (69 bbl) 12-1/4" Shoe Cmt w/ 940 sx 12.0 ppg, 390 sx Class "Fin 12-1/4" Hole 8-1/2" Uncemented Sand Screen Liner In 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6/A-53/Weld N/A 2.441" 110' N/A 9-5/8" Surface 40 / L-80 / TC II 8.525 i 7,379' 8,819' 0.0758 7-5/8" Tieback 29.7 / L-80 / Vam STL 6.750 t6,884' 6,884' 0.0459 7-5/8" Tieback 29.7/ L-80 /SLID II 6.750 - 8,408' 0.0459 4-1/2" Liner 13.5 / L-80 / HTTC 3.795 12,627' 0.0149 TUBING DETAIL 2-7/8" 1 Tubing 1 6.5 / L-80 / EUE 8rd 1 2.441 1 Surface 1 7,476' 1 0.0058 WELL INCLINATION DETAIL KOP @ 357' 76.3 deg. @ 2,270' MD Max Hole Angle =95.2 deg. @ 8,737' MD JEWELRY DETAIL D. Depth Item ID Upper Completion L 30' Tubing Hanger 2441" 172' ST 2: Patco SPMO-1 GLM BK -2 Latch, 1" OGLV 2.441" 3 2,802' ST 1: Patco SPMO-1 GLM BK -2 Latch, V DGLV 2.441" t 3,210' Heat Trace (3,412' spool) N/A i 7,379' 2-7/8" XN Profile (2.205" No -Go Packing Bore ID) 2.205" 5 7,390' Discharge Head - 7 7,39V Centrilift ESP: Tandem FLEX17.5134 Stages 3 7,438' Gas Separator - 37,441' Tandem Seal Section - 0 7,455' Single ESP Motor (210 HP) - 1 7,472' Phoenix XT3S0 Sensor w 6 fn Centralizer— Btm@7,476' - Lower Completion 2 8,402' BOTSLZXP Liner Top Packer w/BD Slips 9-5/8"x7" 6.200" 3 8,400' 7-5/8" Tieback Assy. No -Go (Btm @ 8,410') 6.151" 4 8,425' 7" H563 4.5" HTTC L-80 XO 3.900" 5 8,798' 4-1/2" 300 Screen, WTF Maxi'lo 13.5# 13Cr-110 Vam Top —Bim @ 12,214' 3.920" 6 12,590' 4-1/2" Drillable Packoff Sub 2.400" 7 12,622' WIV Valve LTC BxB (1.5" Ball on Seat/Closed) & Shoe —Btm @ 12,627' GENERAL WELL INFO API: 50-029-23558-00-00 Drilled and Cased by Doyon 14 - 6/11/2016 Revised By: TDF 8/23/2019 Confidential Business Information As Per 18 AAC 83.165 WEIR PRESSURE CONTROL 9-5/8 Reverse Slip -Lock Assembly (Split) Installation Operation CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information In this manual is Proprietary and Confidential and the exclusive property of 02013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied is forbidden without the expressed written permission of Weir Oil 8 Gas or its authonud agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 Rev: 0 Page: 1 of 12 Installation Operation Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: WEIR PRESSURE CONTROL 9-5/8 Reverse Slip -Lock Assembly (Split) Installation Operation CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information In this manual is Proprietary and Confidential and the exclusive property of 02013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied is forbidden without the expressed written permission of Weir Oil 8 Gas or its authonud agent(s). Confidential Business Information As Per 18 AAC 83.165 Reviewed by Thinh Nguyen Engineer Approved by Josh Douglas Engineering Manager CONTROLLED DOCUMENT Any Printed Copies Are Considered Unoontrolled. All information in this manual is Proprietary and Confidential and the exclusive properly of ® 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied Is forbidden without the expressed written permission of Weir Oil & Gas or its authonzed agent(s). 9-5/8" Reverse Slip -Lock (Split) P-27476 Installation Operation Rev: 0 Page: 2 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: Reviewed by Thinh Nguyen Engineer Approved by Josh Douglas Engineering Manager CONTROLLED DOCUMENT Any Printed Copies Are Considered Unoontrolled. All information in this manual is Proprietary and Confidential and the exclusive properly of ® 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied Is forbidden without the expressed written permission of Weir Oil & Gas or its authonzed agent(s). Confidential Business Information As Per 18 AAC 83.165 REVISION AND HISTORY PAGE Rev Description Release Date 0 Initial Release 10/05/2018 CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in this manual is Propnetaryam Confidential and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures. or instructions, either expressed or implied, is forbidden without the expressed written permission of Weir Oil & Gas or its authodz d agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 Rev: 0 Page: 3 of 12 Installation Operation Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: REVISION AND HISTORY PAGE Rev Description Release Date 0 Initial Release 10/05/2018 CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in this manual is Propnetaryam Confidential and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures. or instructions, either expressed or implied, is forbidden without the expressed written permission of Weir Oil & Gas or its authodz d agent(s). Confidential Business Information As Per 18 AAC 83.165 TABLE OF CONTENTS 1.0 EQUIPMENT OVERVIEW............................................................................................................ 5 2.0 CASING CUT-OFF......................................................................................................................... 5 3.0 INSTALLATION OF REVERSE SLIP LOCK.............................................................................. 8 TABLE OF FIGURES Figure1: Original Configuration................................................................................................................ 6 Figure2: Cut Made..................................................................................................................................... 7 Figure3: Install Split Halves...................................................................................................................... 9 Figure 4: Install Lower Halves and Install................................................................................................ 10 Figure5: Final Installation........................................................................................................................ 12 CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive property of 020135eaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or Implied, Is forbidden without the expressed written permission of Weir Oil 8 Gas or Its au horized agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 Rev: 0 Page: 4 of 12 Installation Operation Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: TABLE OF CONTENTS 1.0 EQUIPMENT OVERVIEW............................................................................................................ 5 2.0 CASING CUT-OFF......................................................................................................................... 5 3.0 INSTALLATION OF REVERSE SLIP LOCK.............................................................................. 8 TABLE OF FIGURES Figure1: Original Configuration................................................................................................................ 6 Figure2: Cut Made..................................................................................................................................... 7 Figure3: Install Split Halves...................................................................................................................... 9 Figure 4: Install Lower Halves and Install................................................................................................ 10 Figure5: Final Installation........................................................................................................................ 12 CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive property of 020135eaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or Implied, Is forbidden without the expressed written permission of Weir Oil 8 Gas or Its au horized agent(s). Confidential Business Information As Per IS AA(. AR 1R -r, 9-5/8" F- 1.0 EQUIPMENT OVERVIEW The Reverse Slip -Lock (W20932-001) is designed as a retrofit component to an existing well. It will divert the load of the wellhead from the surface casing/conductor and reload it to the intermediate string. 2.0 CASING CUT-OFF 2.1 The original tree configuration should be as shown in Figure 1. For installation of the Reverse Slip -Loc the bell nipple will be removed and the 9-5/8 casing exposed. 2.2 Pull tree (n tension then do casing cut-off with minimum 12.0" clearance between the bottom of the casing head and 20" conductor. See figure 2. 2.3 The slip loc design requires that the remaining bell nipple remain in the bottom of the SOW prep. If the bell nipple is not welded at the top retain this piece for further use. 2.4 Bevel prep as required to ensure a smooth entry. CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and ConfMemtal and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, Procedures, or instructions, either expressed or implied, is forbidden without the expressed written permission of Weir Oil & Gas or its authedzed agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 5 of 12 Reviewed By: Thinb Nguyen Approved By: Josh Douglas Date Approved: 1.0 EQUIPMENT OVERVIEW The Reverse Slip -Lock (W20932-001) is designed as a retrofit component to an existing well. It will divert the load of the wellhead from the surface casing/conductor and reload it to the intermediate string. 2.0 CASING CUT-OFF 2.1 The original tree configuration should be as shown in Figure 1. For installation of the Reverse Slip -Loc the bell nipple will be removed and the 9-5/8 casing exposed. 2.2 Pull tree (n tension then do casing cut-off with minimum 12.0" clearance between the bottom of the casing head and 20" conductor. See figure 2. 2.3 The slip loc design requires that the remaining bell nipple remain in the bottom of the SOW prep. If the bell nipple is not welded at the top retain this piece for further use. 2.4 Bevel prep as required to ensure a smooth entry. CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and ConfMemtal and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproduction or use of the calculations, drawings, photographs, Procedures, or instructions, either expressed or implied, is forbidden without the expressed written permission of Weir Oil & Gas or its authedzed agent(s). Confidential Business Information As Per 18 AAC 83.165 9-5/8" Reverse Slip -Lock (Split) P-21476 IMMENE nstallation Operation Rev: 0 Page: 6 of 12 Reviewed BjThinhguyen Approved By: Josh Douglas Date Approved: CASING HAI 13-5/8 X 9- 13-3/8 SO 20 CASING 9-5/8 CA —5/8 5M Figure I: Original Configuration CONTROLLED DOCUMENT Any printed Copies Are Considered Uncontrolled. All information in this manual is proprietary and Confidential and the exclusive property of ® 2013 Sealxx3rd Holdings Inc. Any reproduction or use of the calculations, tlrewings, photographs, procedures, or instructions, either..pressed or implied, is f.Midden without the expressed written permission of Weir Oil & Gas or Its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 CASING HAI c 13-5/8 X 9 - CAS 20 CASING 9-5/8 CF FIGURE 1 Figure 2: Cut Made CONTROLLED DOCUMENT 3-5/8 5M Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive pmpeny o(® 2013 5eabomd Holdings Inc. Any reproduction or use of the calculations, drevMgs, photographs, procedures. or Instmctions, either expressed or Implied, is forbidden without the expressed written permission of Weir Oil & Gas or its authorized agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 7 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: CASING HAI c 13-5/8 X 9 - CAS 20 CASING 9-5/8 CF FIGURE 1 Figure 2: Cut Made CONTROLLED DOCUMENT 3-5/8 5M Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive pmpeny o(® 2013 5eabomd Holdings Inc. Any reproduction or use of the calculations, drevMgs, photographs, procedures. or Instmctions, either expressed or Implied, is forbidden without the expressed written permission of Weir Oil & Gas or its authorized agent(s). Confidential Business Information As Per 18 AA(. Al I F."; 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 18 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: 3.0 INSTALLATION OF REVERSE SLIP LOCK 3.1 Visually inspect the Slip Set thread for any damage. 3.2 Place a board or plate over the 20" casing to provide a work area. 0 WARNING - SAFETY ALERT ! Each half of the Reverse slip-loc is approximately 50lbs, utilize proper lifting methods using provided .500-13UNC lift holes. 3.3 Using proper lifting equipment place each half around the 9-5/8 casing. 3.4 Bolt the two halves together. CONTROLLED DOCUMENT My Printed Ccples Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive property of ® 2013 Seaboard Holdings Inc. My reproducuon or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied, i$ forbidden without the expressed written permission of Weir Oil 8 Gas or its authorized agent(s). Confidential Business Information As Per 18 AAC 83.165 Figure 3: Install Split Halves T CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information m this manual is Proprietary and Confidential and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproducWn or use of the calculations, dravdngs, photographs, procedures, or instructions, either expressed or implied, Is forbidden without the expressed written permission of Weir Oil & Gas or its authodied agenhii). 9-5/8" Reverse Slip -Lock (Split) P-21476 :Review:edBy::Thinh Installation Operation Rev: 0 Page: 9 of 12 yen Approved By: Josh Douglas Date Approved: Figure 3: Install Split Halves T CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information m this manual is Proprietary and Confidential and the exclusive property of ® 2013 Seaboard Holdings Inc. Any reproducWn or use of the calculations, dravdngs, photographs, procedures, or instructions, either expressed or implied, Is forbidden without the expressed written permission of Weir Oil & Gas or its authodied agenhii). Confidential Business Information As Per 18 AAC 83.165 Figure 4: Install Lower Halves and Install CONTROLLED DOCUMENT My Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and Neexdusivepropertyof®2013 seaboard Holdings lno. Any reproduction or use of the calculations, drawngs, photogrzphs, procedures, or Instructions, either expressed or implied Is forbidden without the expressed e,mllen permission of Weir Oil 8 Gas 01 its authorized agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 10 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: Figure 4: Install Lower Halves and Install CONTROLLED DOCUMENT My Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and Neexdusivepropertyof®2013 seaboard Holdings lno. Any reproduction or use of the calculations, drawngs, photogrzphs, procedures, or Instructions, either expressed or implied Is forbidden without the expressed e,mllen permission of Weir Oil 8 Gas 01 its authorized agent(s). Confidential Business Information As Per 1 R AAr R'1 1 FR 3.5 MR 3.7 D Install bottom plate (2X) 90 degrees from each other such that the splits do not align. Install nuts hand tight. Using appropriate lifting equipment insert the Reverse slip-loc into the bottom of the casing head. See Figure 3. © WARNING — SAFETY ALERT To properly function the Reverse slip loc must fit inside the casing head. If the bell nipple from Section 2.0 was removed utilize it when installing the Reverse slip loc to ensure a tight fit. The bolts are not designed to hold the two halves together under 3.8 Loosen the bolt and nut keeping the two halves together, but do not remove. 3.9 Remove cap screws retaining the slip segments. 3.10 Pull final tension required. i IU The Reverse Slip Loc is designed to a maximum of 50% of casing plain end yield. 3.11 In an alternating criss-cross pattern tighten the bolt pattern to 50 ft -lbs in the first pass, and to the final torque of 100-125 ft -lbs in the final pass. 3.12 Make a mark on the casing at the bottom of the reverse slip lock. 3.13 Release tension and observe for any slippage. If slippage has occurred re-pull tension and apply up to 150 ft -lbs of torque on the bolting. If slippage still occurs, contact engineering. CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive property of C 2013 Seaboard Holding. Inc. Any repooduction or use of the calculations, drawings, photographs, Procedures, or instructions, either expressed or implied is forbidden without the expressed written permission of Weir Oil 8 Gas or Its au0rodzed agent(s). 9-5/8" Reverse Slip -Lock (Split) P-21476 Installation Operation Rev: 0 Page: 11 of 12 Reviewed By: Thinh Nguyen Approved By: Josh Douglas Date Approved: 3.5 MR 3.7 D Install bottom plate (2X) 90 degrees from each other such that the splits do not align. Install nuts hand tight. Using appropriate lifting equipment insert the Reverse slip-loc into the bottom of the casing head. See Figure 3. © WARNING — SAFETY ALERT To properly function the Reverse slip loc must fit inside the casing head. If the bell nipple from Section 2.0 was removed utilize it when installing the Reverse slip loc to ensure a tight fit. The bolts are not designed to hold the two halves together under 3.8 Loosen the bolt and nut keeping the two halves together, but do not remove. 3.9 Remove cap screws retaining the slip segments. 3.10 Pull final tension required. i IU The Reverse Slip Loc is designed to a maximum of 50% of casing plain end yield. 3.11 In an alternating criss-cross pattern tighten the bolt pattern to 50 ft -lbs in the first pass, and to the final torque of 100-125 ft -lbs in the final pass. 3.12 Make a mark on the casing at the bottom of the reverse slip lock. 3.13 Release tension and observe for any slippage. If slippage has occurred re-pull tension and apply up to 150 ft -lbs of torque on the bolting. If slippage still occurs, contact engineering. CONTROLLED DOCUMENT Any Printed Copies Are Considered Uncontrolled. All information in this manual is Proprietary and Confidential and the exclusive property of C 2013 Seaboard Holding. Inc. Any repooduction or use of the calculations, drawings, photographs, Procedures, or instructions, either expressed or implied is forbidden without the expressed written permission of Weir Oil 8 Gas or Its au0rodzed agent(s). Confidential Business Information As Per 18 AAC 83.165 CASING HAI 13-5/8 X 9- 20 CASING 9-5/8 CA Figure 5: Final Installation CONTROLLED DOCUMENT Any Pm,hw Copies Are Considered Uncontrolled. 5/8 5M All information in this manual is Proprietaryand Confidential end the exdusive property of ® 2013 SeelHoldings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied, Is forEidden without the expressed written permission of Weir Oil 8 Gas or its authcd d agent(.). 9-5/8" Reverse Slip -Lock (Split) P-21476 [ReviewedApproved Installation Operation Rev: 0 Page: 12 of 12 By: Josh Douglas Date Approved: CASING HAI 13-5/8 X 9- 20 CASING 9-5/8 CA Figure 5: Final Installation CONTROLLED DOCUMENT Any Pm,hw Copies Are Considered Uncontrolled. 5/8 5M All information in this manual is Proprietaryand Confidential end the exdusive property of ® 2013 SeelHoldings Inc. Any reproduction or use of the calculations, drawings, photographs, procedures, or instructions, either expressed or implied, Is forEidden without the expressed written permission of Weir Oil 8 Gas or its authcd d agent(.). • Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Phone: 907/777-8547 SCOW p JUN 07 Dp i June 5, 2018 RECEIVED Mr. Guy Schwartz Alaska Oil and Gas Conservation Commission JUN 06 2018 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 AOGCC Re: Conductor Annulus Corrosion Inhibitor Treatments 4/20/18-5/12/18 Dear Mr. Schwartz, Enclosed please find multiple copies of a spreadsheet with a list of wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water "grease-like" filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, PTD and API numbers, treatment volumes and treatment dates. This treatment campaign represents primarily new Milne Point HAK drill wells along with two Northstar wells which previously had excavations and external surface casing leak repairs. If you have any additional questions,please contact me at 777-8547 or wrivard@hilcorp.com. Sincerely, Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC • ! � (.0 U) U)U) U) (1) Cl) U) U) U) U) U) U) U) c c c c c c ccc c cc •J J J J J J J J J J •J J J O O Q C C C C c c c L L L L L L L L L. L L O L U U ° O O = D O D 7 U) U) U) Cl) U) U) U) U) U) U) U) U) Nwry O- 0- wwwce c c c c cc c c c c c c c L L c Cl) U) U) (1) U) Cl) U) U) U) U) U) N U) O O E E E E E E E E E E E E E U U Cl) U) U) U) a) U) () U) U) a) U) U) m D D U U O O O O U O O O O O O 13 Q Q Q Q Q Q Q Q Q Q Q Q < V V O Q asU Q Ta U j L U) O O _ O O 0 0 LO 10 LO O Ln co Lf) E r N N o O O ' — N V M o N = co CO co 00 CO CO CO co 00 CO CO Co 0 CO CO 2d m o 0 0 0 0 0 0 0 0 0 0 0 x— 0 0 LO E N N N N N N N N N N N N N N N 0 Cl 0 0 r N N N N co co co M L- LD N N N N N N N N NN N U 0 0 0 0 0 0 0 0 0 0 0 0 00 0 c N- U) M d a) M N- CO O a) N co • D N U) Ln CC) M U) U) M N a) co L N 0 — O O N c I— 0 COO CO CO CO O Ln Ln CO Ln Ln Ln ti NN O O c N N N N N N N N N N N N N N N L O U 73 O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O U O 0 0 0 0 0 0 0 0 0 0 0 0 0 O O 0 0 0 0 0 0 0 0 0 0 0 0 0 O O co d) N- 00 N- N Ln U) CO M CO >+ CD ti N- ti CO U) Ln CO Ln Ln CO N- N iL LC) LC) L() U) U) Ln Ln Ln Ln L() Ln Lf) Ln 0 U Q cc?,, M M M M M M M M M M c4) C4) Cr) C�) N N N N N N N N c.c. N N N N N a) 0) 0) a) a) a) a) a) a) a) a) a) a) a) a) N N N N N N N N N N N N NNN 0 0 Co O 0 0 0 0 Co O 0 0 0 0 0 O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Ln U) a 0- 0- 0- 0- 0- 0- 0- 0- 0- 0- 00- W (/) ii 2 2 2 2 2 2 2 2 2 2 2 2 2 z z co a) O N Cr) Nr ti 00 d- 00 a) O M N N N M M M M N N d N1• LC) Ln Ts) mm m m CO m —J '� Y J J J J a a a a a a_ a a_ a. a a. a a co 2 2 2 2 2 2 2 2 2 2 2 2 2 z z DATA SUBMITTAL COMPLIANCE REPORT 4/18/2017 Permit to Drill 2151570 Well Name/No. MILNE PT UNIT J-28 Operator HILCORP ALASKA LLC API No. 50-029-23558-00-00 MD 12627 TVD 3560 Completion Date 6/11/2016 Completion Status 1-0I1- Current Status 1-0I1- UIC No REQUIRED INFORMATION Mud Log Nov/ / `� Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: DGR-EWR-ADR-ROP-HORIZONTAL PRES 21N MD, DGR-EWR-ADR (data taken from Logs Portion of Master Well Data Maint) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments ED C 27307 Digital Data 100 12628 6/16/2016 Electronic Data Set, Filename: MPU J- 28_DGR_EW R_ADR_FI NAL.las ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J-28 DGR_EWR_ADR , MD.cgm ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J-28 DGR_EWR_ADR TVD.cgm ED C 27307 Digital Data 6/16/2016 Electronic File: MPJ -28 Definitive Survey.pdf ED C 27307 Digital Data 6/16/2016 Electronic File: MPJ-28.txt ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J-28 DGR_EWR_ADR MD.emf ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J-28 DGR_EWR_ADR TVD.emf ED C 27307 Digital Data 6/16/2016 Electronic File: MPU_J- 28_Geosteering_and_lmages.dlis ' ED C 27307 Digital Data 6/16/2016 Electronic File: MPU_J- 28_Geosteering_and_lmages.ver ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J- 28 DGR EWR ADR FINAL.dlis ' ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J- 28 DGR EWR ADR FINAL.ver ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J-28 DGR_EWR_ADR• MD.pdf ' ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J-28 DGR_EWR_ADR P TVD.pdf ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J-28 DGR_EWR_ADR - MD.tif AOGCC Page 1 of Tuesday, April 18, 2017 DATA SUBMITTAL COMPLIANCE REPORT 4/18/2017 Permit to Drill 2151570 Well Name/No. MILNE PT UNIT J-28 Operator HILCORP ALASKA LLC API No. 50-029-23558-00-00 MD 12627 TVD 3560 Completion Date 6/11/2016 Completion Status 1 -OIL Current Status 1 -OIL UIC No ED C 27307 Digital Data 6/16/2016 Electronic File: MPU J-28 DGR EWR ADR TVD.tif Log C 27307 Log Header Scans 0 0 2151570 MILNE PT UNIT SB J-28 LOG HEADERS Well Cores/Samples Information: Name INFORMATION RECEIVED Completion Report n Comments: Compliance Reviewed By: Interval Start Stop Directional / Inclination Data Mechanical Integrity Test Information Y NA Daily Operations Summary 0 Date Comments Sample Set Sent Received Number Comments Mud Logs, Image Files, Digital Data Y( 9 S NA Core Chips Y Composite Logs, Image, Data Files Y Core Photographs Y / A Cuttings Samples Y /SIA / Laboratory Analyses Y NA - -- 1, r I_ J Date: AOGCC Page 2 of 2 Tuesday, April 18, 2017 Production Test Informatio Y / NA Geologic Markers/Tops Y COMPLIANCE HISTORY Completion Date: 6/11/2016 Release Date: 9/18/2015 Description Comments: Compliance Reviewed By: Interval Start Stop Directional / Inclination Data Mechanical Integrity Test Information Y NA Daily Operations Summary 0 Date Comments Sample Set Sent Received Number Comments Mud Logs, Image Files, Digital Data Y( 9 S NA Core Chips Y Composite Logs, Image, Data Files Y Core Photographs Y / A Cuttings Samples Y /SIA / Laboratory Analyses Y NA - -- 1, r I_ J Date: AOGCC Page 2 of 2 Tuesday, April 18, 2017 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RECEIVED JUL_ 11 7016 WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil 0 Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG[] WDSPL ❑ No. of Completions: _ 1 1b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 6/11/2016 14. Permit to Drill Number / Sundry: 215-157 ' 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: May 24, 2016 15. API Number: 50-029-23558-00-00 4a. Location of Well (Governmental Section): Surface: 2209' FSL, 3132' FEL, Sec 28, T1 3N, R1 OE, UM, AK Top of Productive Interval: 2241' FSL, 243' FWL, Sec 29, T13N, R10E, UM, AK Total Depth: 2157' FSL, 1676' FWL, Sec 30, T1 3N, R1 OE, UM, AK 8. Date TD Reached: June 4, 2016 16. Well Name and Number: MPU J-28 9. Ref Elevations: KB: 67.1' GL: 33.4' BF: 33.4' 17. Field / Pool(s): Milne Point Unit / Schrader Bluff Oil Pool . 10. Plug Back Depth MD/TVD: 12,622' MD / 3,559' TVD 18. Property Designation: (SHL) ADL025906 / (TPH/BHL) ADL025517 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 552189 y- 6014608 Zone- 4 TPI: x- 545004 y- 6014592 Zone- 4 Total Depth: x- 541191 y- 6014487 Zone- 4 11. Total Depth MD/TVD: 12,627' MD / 3,560' TVD ` 19. Land Use Permit: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,510' MD / 1,940' TVD 5. Directional or Inclination Survey: Yes ❑✓ (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary DGR-EWR-ADR-ROP-HORIZONTAL PRES 21N MD, DGR-EWR-ADR-INV/REV 21N TVD 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 20" 78.6# A-53 Surface Surface 110' 110' 42" 60 bbls 15.6 ppg Permafrost 9-5/8" 40# L-80 Surface 8,819' Surface 3,594' 12-1/4" Stg 1 L-408 bbls / T- 76 bbis Stg 2 L-315 bbls / T- 56 bbls 77 bbls 69 bbls 7-5/8" 29.7# L-80 Surface 8,408' Surface 3,605' Tieback N/A 4-1/2" 13.5# L-80 8,425' 12;627' 3,607' 3,560' 8-1/2" Uncemented Screen Liner 24. Open to production or injection? Yes 7 No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): 4-1/2" 300 Screen, WTF MaxFlo 13.5# 13Cr-110 Vam Top Screen Liner: 8,797'- 12,214' MD / 3,595'- 3,539' TVD COMPLETION t �D�AT/E�(p `JERIFIEG� L� 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" 7,476' N/A 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No ❑✓ Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 6/16/2016 Method of Operation (Flowing, gas lift, etc.): ESP Date of Test: 6/20/2016 Hours Tested: 24 Production for Test Period --Oo. Oil -Bbl: 375 Gas -MCF: 63 Water -Bbl: 15 Choke Size: N/A Gas -Oil Ratio: 167.8 Flow Tubing Press. 325 Casing Press: 70 Calculated 24 -Hour Rate __Op� Oil -Bbl: 375 Gas -MCF: 63 Water -Bbl: 15 Oil Gravity - API (corr): 19 Form 10-407 Revised 11/2015 CONTINUED ON PAGE 2 Submit ORIGINIAL onl RBDMS L� !I!�. 12 2016 7 28. CORE DATA Conventional Core(s): Yes ❑ No ❑✓ Sidewall Cores: Yes ❑ No If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Q If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,510' 1,940' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 8,797' 3,595' information, including reports, per 20 AAC 25.071. Sv1 3,305' 2,154' Ugnu MA 8,026' 3,533' Schrader Bluff NB 8,236' 3,582' Formation at total depth: Schrader 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Days vs Depth, MW vs Depth, Casing and Cement Report. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Cody Dinger Email: cdin er hIICOr .colli Printed Name: Cody DinRe Title: Drilling Tech Signature Phone: 777-8389 Date: 7/11/2016 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 11/2015 Submit ORIGINAL Only Hileorp Alaska, LLC ff Orig. KB Elev.: 67.1'/ Orig. GL Elev.: 33.4' TD =12,627 (MD) / TD = 3,560'(TVD) PBTD =12,622' (MD) / PBTD = 3,55Y(TVD) SCHEMATIC Milne Point Unit Well: MPU J-28 Last Completed: 6/11/2016 PTD: 215-157 TREE & WELLHEAD Tree Seaboard 3 1/8" 5M Wellhead Seaboard 16 3/4" 3M x 11" 5M Multibowl w/11" x 3 1/2" EUE Top and Bottom with 3" CIW "H" BPV profile. 2ea 3/8" NPT control lines. OPEN HOLE/ CEMENT DETAIL 20" Conductor 12-1/4" ES Cmt w/ 405 sx PF 11.1 ppg, 287 sx Class "G" in 12-1/4" Hole; Cmt to Surface (69 bbl) 12-1/4" Shoe Cmt w/ 940 sx 12.0 ppg, 390 sx Class "G" in 12-1/4" Hole 8-1/2" Uncemented Sand Screen Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 114' N/A 9-5/8" Surface 40 / L-80 / TC II 8.525 Surface 8,819' 0.0758 7-5/8" Tieback 29.7 / L-80 / Vam STL 6.750 Surface 6,884' 0.0459 7-5/8" Tieback 29.7 / L-80 / SLIJ II 6.750 6,884' 8,408' 0.0459 4-1/2" Liner 13.5 / L-80 / HTTC 3.795 8,425' 12,627' 0.0149 TUBING DETAIL 2-7/8" 1 Tubing 1 6.5 / L-80 / EUE 8rd 1 2.441 1 Surface 1 7,476' 0.0058 WELL INCLINATION DETAIL KOP @ 357' 76.3 deg. @ 2,270' MD Max Hole Angle = 95.2 deg. @ 8,737' MD JEWELRY DETAIL No. Depth Item ID Upper Completion 1 30' Tubing Hanger 2.441" 2 172' ST 2: Patco SPMO-1 GLM BK -2 Latch, 1" OGLV 2.441" 3 2,802' ST 1: Patco SPMO-1 GLM BK -2 Latch, 1" DGLV 2.441" 4 3,210' Heat Trace (3,412' spool) N/A 5 7,379' 2-7/8" XN Profile (2.205" No -Go Packing Bore ID) 2.205" 6 7,390' Discharge Head - 7 7,391' Centrilift ESP: Tandem FLEX17.5 134 Stages 8 7,438' Gas Separator 9 7,441' Tandem Seal Section 10 7,455' Single ESP Motor (210 HP) 11 7,472' Phoenix XT150 Sensor w 6 fin Centralizer— Btm @ 7,476' - Lower Completion 12 8,402' BOT SLZXP Liner Top Packer w/BD Slips 9-5/8" x 7" 6.200" 13 8,400' 7-5/8" Tieback Assy. No -Go (Btm @ 8,410') 6.151" 14 8,425' 7" H563 x 4.5" HTTC L-80 XO 3.900" 15 8,798' 4-1/2" 300µ Screen, WTF MaxFlo 13.5# 13Cr-110 Vam Top — Btm @ 12,214' 3.920" 16 12,590' 4-1/2" Drillable Packoff5ub 2.400" 17 12,622' WIV Valve LTC BxB (1.5" Ball on Seat/Closed) & Shoe — Btm @ 12,627' - GENERAL WELL INFO API: 50-029-23558-00-00 Drilled and Cased by Doyon 14 - 6/11/2016 Revised By: STP 6/29/2016 Hilcorp Energy Company Composite kcport Well Name: MP J-28 Field: Milne Point County/State: North Slope, Alaska (LAT/LONG): ;vation (RKB): API #: Spud Date: 5/24/2016 Job Name: 1511627D MPJ -28 DRILLING Contractor Doyon 14 AFE #: AFE $: Activity Date Ops Summary 5/23/2016 Move rig off J-27 and spot over J-28. Skid rig floor into drilling position. Rig accepted on J-28 @ 1200 hrs. AOGCC notified for diverter test (5/23/16 (� 16:42) via email.;Re-orient 20" Surface stack to align Diverter outlet to side door exit. C/O Saver sub. Lay mat boards around rig perimeter for support shacks. Note: Production working on tie in of J-27.;Calibrate rig gas alarms, GYRO rig up, locate and mark North orientation on rig floor. N/U 20" Surface Riser, load and tally 5" DS -50 DP in pipe shed.; Pick up 5", 19.5# S-135, DS -50 drill pipe (32 stands) and rack back in derrick. 2.125" drift. Set and R/U 3rd party shacks. Load pits w/ Spud mud and dress shakers.; Continue picking up 5" drill pipe for a total of 94 stds. Rack back same. 575 bbis spud mud on location. Continue R/U peripheral equipment around rig, 5/24/2016 M/U 2 stands of 5" HWDP with Jars. RIH & tag up @ 37'. M/U & Install Wear bushing. Hang blocks, Slip & Cut Drilling line. Service Toprive.;Install diverter line, Rig up circulating line, Spot matts & Rockwasher. Spot cuttings tank. Stage matts for highline..;Perform diverter test. Knive valve opened in 24 sec, Annular closed in 25 sec. Diverter test whitness waived by Chuck Scheve. @ 1120 AM,Work on pre spud check list, Bring vis in mud to 200+. R/U Gyro & Hang sheave in the derrick. Conduct pre spud meeting with all personnel. Bring BHA #1 to the floor.,M/U BHA #1, 12.25 bit, Motor, HWDP. RIH & tag @ 37'.;Drill ICE @ 40 rpm, 400 GPM, 3-5K WOB. F/ 37'T/ 105. Drill CMT F/ 105'T/ 114'. Displace to Spud mud on the fly. Back ream to conductor & clean up well before shutting down pumps for connection.; Drill ahead 350 GPM F/ 114' T/ 219'. Staging up pumps to 400 gpm, 4-6 WOB, 40 RPM. Lots of Pea gravel under the shoe. Cleaned up good.; Back ream F/ 219' - T/ 125' MD. 20 rpm, 405 gpm, 570 psi, 38% flow, 3 BGG. Shut do pumps / rot. Trip back to 219' w/ no fill. Pull on elevators F/ 219 to surface. Pulled clean w/ no issues.;M/U BHA #1 w/ MWD tools. RFO = 81.23°, Download MWD. Continue M/U BHA w/ UBHO sub. Orientate UBHO (Verified by Gyro, DD, MWD and DSM). P/U NM Flex DC's,M/U 1 std of HWDP and Tag up @ 215' (4' fill). 1.5° motor bend.;Wash do from 215' to 219' and continue drilling ahead. Drill ahead F/ 219'- T/ 644' MD . Drilled at 400 gpm until 445' MD. Increased flow to 450 gpm, 1123 psi, 42% flow, 40 rpm, 1k tq on/off.;Gyro @ connections. Running 25 bph H2O to treat mud. Sym Ops - Process 9-5/8" casing for surface job. Last svy 452' MD = 2' Low, 1' Right of line (WP06).,Daily losses to formation 0 bbls for total = 0 bbis Hauled 0 bbis to MP G&I for total = 57 bbis Hauled 580 bbis from Vern Lake for total = 580 bbls Hauled 360 bbis from 6 Mile Lake for total = 360 bbl 5/25/2016 Drill 12.25 Hole F/ 644' T/830'. 186'@ 62' FPH Average. Taking Gyro Surveys every 90'. 500 GPM, 1250 psi, 65 RPM, Sliding 50-75%. MW. 9.0, Vis 280;Drill 12.25 Hole F/ 830'T/ 1440'. 610'@ 68' FPH Average. 518 GPM, 1380 psi, 70 RPM, 6K TQ, Sliding 50-75%. MW. 9.1, Vis 280;Got three clean surveys after 830'. Release & R/D Gyro after 1140'.,Drill 12.25 Hole F/ 1440'T/ 1934'. 494'@ 83' FPH Average. 490 GPM, 1590 psi, 67 RPM,8.86K TQ, Sliding 75-90%. MW. 9.1, Vis 220 Pump 35 bbl hi vis sweep @ 1825'w/ 100% inc (on time),Drill 12.25 Hole F/ 1934'T/ 2270'. 336'@ 112' FPH Average. Landed in tangent @ 2270' MD 550 GPM, 1770 psi, 65 RPM, 8.96K TQ, Sliding 75-90%. MW. 9.1, Vis 220;Drill 12.25 Tangent hole section F/ 2270'T/2635'. 365' @ 122' FPH Average. 550 GPM, 1750 psi, 65 RPM, 8.96K TO, Sliding 5-10%. MW. 9.2, Vis 220 Pump 35 bbl hi vis sweep @ 2537'. 300% inc-on time; Projected formation tops are coming in 4-5' low as per onsite Geo Last Svy @ 2460' = 40' low and 19' right. Base of Permafrost 2 2,510' MD. Daily loss to formation 0 bbls for total = 0 bbl Hauled 1499 bbis to MP G&I for total = 1556 bbis Hauled 290 bbis from Vern Lake for total = 870 bbis Hauled 1525 bbls from 6 Mile Lake for total = 1885 bbls 5/26/2016 Drill 12.25 Tangent hole section F/ 2635'T/3014'. 379'@ 126' FPH Average. 600 GPM, 1850 psi, 80 RPM, 9K TO, Sliding 0%. MW. 9.3, Vis 220;Circ hole clean with high vis nut Plug sweep. Came back on time with 100% increase in cuttings. Circ @ 550 gpm 60 rpm.;Monitor well. Static. POOH F/ 3014'T/ 570 Pumping 500 gpm. 5-10 K bobbles. Pulled slow through high slide areas holding high side. Clean hole.; POOH on elevators F/ 570'T/ BHA. Clean. Stand back DC & HWDP. UD UBHO.;Clean clay from stabs & bit. Break off bit. Bit Grade- 3-4-WT-A-E- I-CT-BHA;Shaliow pulse test. Good. RIH with DC, HWDP & stands to 462'. Set down. Rot pipe 1/2 turn. Work through with no problem. RIH on elevators T/ 2215'. Set down.;Attempt to work through on elevators. Making hole but still stacking out. Kelly up and fill pipe. Shut down pump. Work through dog leg with little trouble. RIH to 2905'.;Kelly up. Fill pipe. Stage up pumps to 450 gpm. Wash & ream to btm F/ 2905' T/3015'. Had correct hole fill on the trip in and out.;Drill 12.25 Tangent hole section F/ 3014' T/3684'. 670' @ 134' FPH Average. 550 GPM, 1700 psi, 80 RPM, 7.5K TQ, Sliding 35%. MW. 9.3, Vis 165; Drill 12.25 Tangent hole section F/ 3684' T/4370'. 686' @ 116' FPH Average. 600 GPM, 2000 psi, 80 RPM, 8K TQ, Sliding 35%. MW. 9.3, Vis 165 Pump 30 bbl hi vis sweep @ 3797'w/ 250% inc-on time;Last svy @ 4155'- 3' low and 3' right of line - WP06 Daily loss to formation 0 bbis for total = 0 bbis Sym Ops: Rioaina uo to flowback J-27. Continually dewatering location. Prep 9-5/8" casing.; Hauled 1695 bbis to MP G&I for total= 3251 bbis Hauled 0 bbis from Vern Lake for total = 870 bbis Hauled 1450 bbis from 6 Mile Lake for total = 3335 bbis 5/27/2016 Drill 12.25 Tangent hole section F/ 4370' T 5. 1745'@ 145' FPH Average. 550-600 GPM, 2100 psi, 60-80 RPM, 15K .hiding 35%. MW. 9.3, Vis 165.;Pump 30 bbl hi vis sweep, 445' w/ 100% inc-on time 5040'w/ 150% inc-on time 5664'w/ 150% inc-on time;Control drill 12.25" hole F/ 6115' to T/ 6599' MD due to high ECD's. Backream 90' slowly @ connections. Reduce ECD's F/ 11.48 - T/ 10.4.;575 gpm, 2400 psi, 39% F/O, 80 rpm, 14k tq, Sliding 35%, MW 9.3, Vis 165;G&I B-50 well plugged off. Circulate and condition hole while developing new plan for handling cuttings. Pump 30 bbl hi vis sweep w/ 100% inc (on time);Circulate and condition @ 550 psi, 2080 psi, 40 rpm, 18k tq while reciprocating pipe.;Drill 12.25 Tangent hole section F/ 6599'T/ 7523'. 924'@ 132' FPH Average. 580 GPM, 2340 psi, 80 RPM, 17K TQ, Sliding 0%. MW. 9.3, Vis 165 30 bbl hi vis sweep @ 7194', 100% inc (on time);Last svy @ 7364' = 2.5' High and 3' Left Daily losses 0 bbls for total = 0; Hauled 1656 bbls to MP G&I for total = 4907 bbls Hauled 57 bbls to GPB G&I for total 57 bbls Hauled 0 bbls F/ Vern Lake for total = 870 bbls Hauled 1800 bbls F/ 6 Mile Lake for total = 5135 bbls 5/28/2016 Drill 12.25 Tan ent hole section F/ 7523'T/8060' . 37'@ 107' FPH Average. 580 GPM, 2320 psi, 80 RPM, 19K TQ, Sliding 10%%. MW. 9.5, Vis 145 30 bbl hi vis sweep @ 7800', 100% inc (on time);Drill 12.25 Heal hole section F/ 8060'T/ 8475. 415'@ 92 ' FPH Average. 580 GPM, 2320 psi, 65 RPM, 19K TQ, Sliding 50%%. MW. 9.5, Vis 145 30 bbl hi vis sweep @ 7800', 100% inc (on time);We started building our Heel @ after 8000'. Building Inc from 73 to 88 deg We crossed the planned fault with 220' of through. 20' High TVD. Shut down & discussed with Geologist plan forward;Circ & condition working pipe high side while discussing plan forward. Decide to drill ahead building INC F/ 88 deg to 95 deg to get back in to the NB sand.;Looks like we missed the NA sand and crossed the NB @ 8310' MD.;Drill 12.25 Heel hole section F/ 8475' T/ 8820' MD. 240' @ 115' FPH Avg. TD called @ 8,820 MD / 3,594' TVD as per onsite Geo. 580 GPM, 2320 psi, 65 RPM, 19K TQ, Sliding 50%. MW. 9.5, Vis 145;Rot/Recip pipe, Circ 3x BU. 620 gpm, 2380 psi, 36% F/O, 80 rpm, 17k tq. Initial ECD's 10.6 @ 550 gpm, Final ECD's 10.05 @ 620 gpm. 95 bgg @ final. Add 1% lube to system. 210k up, 81k dn, 115k rot;Pumped 30 bbl tandem high vis sweeps @ TD (1st sweep 50%, 2nd sweep 20% inc(both on time);Obtain final svy. Monitor well (static). B/R out of hole F/ 8820' to 6100' MD. 500 gpm, 1800 psi, 40 rpm, 15-20k tq. 20-40 ft/min pulling speed. No issues observed.; Projected @ bit = Base of NB Sand and 12' left of plan Daily losses to formation 0 bbis for total = 0 bbls;Hauled 0 bbis to MP G&I for total = 4907 bbls Hauled 57 bbls to GPB G&I for total = 114 bbls Hauled 1559 bbls to KRU DS -1 B for total = 1559 bbls Hauled 0 bbls from Vern Lake for total = 870 bbls;Hauled 1500 bbls from 6 Mile Lake for total = 6635 bbls 5/29/2016 Back Ream out of the hole F/ 6100' T/ 4500' @ 500-550 GPM. 40 RPM. Pulling 20-30 FPM. Pulling 5-10 K over pulls. Pull slow & let clean up.;Pump out of the hole F/ 4500' T/ 2830' @ 500-550 GPM. Over Pulls. 4250'-4150', 3600'-3400', 30- 40 k over. Pulled through & worked back through clean.; Pump out of the hole F/ 2830'T/ 1290' reduced pump rate to 350 GPM to pull through permafrost. Slight packing off @ 2240'. Pulled tight @ 1600. Worked through clean after.;Pump out of the hole pulling through tight spots 1290'T/ 1200'. Work back through no pumps & pulled clean after. Shut down pump & pull on elevators F/ 900'T/ BHA.;Stand back 1 stand HWDP. Jars inner brass ring and seals came out of jars. See pits in O drive. UD 2 Jts HWDP & jars. Let jars hang to make sure they don't fire. Clean floor. HWDP balled up.;UD 8" NM Flex DC's. Plug in download MWD (45 min), Continue laying down remaining MWD components. Drain mtr, B/O bit and UD same. Bit grade = 2-3-CT-A-X-1-WT-TD.;Bit had significant damage to back cutters and associated gauge. Worn do estimated 1/4-3/8" for first 2" of gauge (possible DBR). See pics in "O" drive;Clean and clear rig floor. Pull wear bushing. UD 8" tools from floor and associated handling equipment.;R/U to run 9-5/8" surface casing w/ DDI casing crew. R/U double stack UHT Eckel's, M/U Volant internal grap CRT. Size rig tongs, slips and safety clamp for 9-5/8". Pipe count = 227 total.;lnstall bail extensions w/9-518" 250T side door elevators.;PJSM, Make up Shoe track w/ bfl in float collar (verified). Bakerlok shoe track. Check floats (ok). Flashlighted float shoe and collar (ok). RIH w/ 9-5/8" DWC/C, 40#, L-80 casing F/ 0 to 1570' MD;Hauled 0 bbls to MP G&I for total = 4907 bbls Hauled 0 bbls to GPB G&I for total = 114 bbls Hauled 0 bbls to B-50 for total = 0 bbls Hauled 1259 bbls to KRU DS -1 B for total = 2818 bbls;Hauled - bbls from Vern Lake for total = 870 bbls Hauled 700 bbls from 6 Mile Lake for total = 7335 bbls 5/30/2016 Tag up @ 1570'. Wash down F/1570' MD T/ 1725'@ 6 bpm 120 psi. Unable to work through without pumps. Work pass tight spots. Clean after working past.;RIH on elevators floating in through tight spots F/ 1725'T/ 2200'. Filling pipe on the fly & topping off every 10 joints.; RIH F/ 2200' T/ 2970'.;Circ & Condition staging pumps up to 6 BPM @ 200 psi. Work pipe 45'.;RIH on elevators F/2970' T/ 4872'. Tag up. Wash down F/ 4872' T/ 4924'. RIH F/ 4924' T/ 5650'. Floating in. Filling every 10 or as needed for wt.;RIH F/ 5650' and tag @ 5680' MD. Saw packing off and differentially sticking. Establish circulation and wash down past obstruction. Had to continue washing down every 5 jts to continue TIH;RIH F/ 5680' to 6790' MD.;Continue RIH (washing as needed) F/6790'- T/ 7994'w/ no string wt (float casing). ES cementer made up as per Hal Cmt rep (Bakerlok connection). 6 pins verified for hydraulic shear (3200 psi).; Wash do and establish circulation a average of every 5-7 jts. Stage pumps up to 5 bpm, 620 psi on up stroke and 1.5 bpm, 390 on do stk.;Daily losses 56 bbls to formation for total = 56 bbls;Hauled 0 bbls to MP G&I for total = 4907 bbls Hauled 0 bbls to GPB G&I for total = 114 bbls Hauled 394 bbls to KRU DS -1 B for total = 3212 bbls;Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 450 bbls from B Pad Creek for total = 450 bbls 5/31/2016 Circ & condition working pipe 45'@ 5 BPM. Up/DN 310-340/ 75-90.;RIH On elevators F/ 7994' T/ 8551'. Filling pipe every 5 joints for WT. Down wt 90-0. Floafina 'n. -Wash down F/ 8551'T/ 8820'. 5 BPM @ 540 PSI. RIH Slow. MW 9.3 in 9.4 OUT, Vis 80 IN 250 out.;Circ & Condition while rigging up Halliburton CMT unit. Stage up pumps to 6 bpm. Slow down pumps to 3 bpm on the way down. Much smoother. 490 psi.;Conduct PJSM for CMT Job. MW IN & OUT. 9.3/9.4 Vis 53/120 Empty pits for displacement. Mix citric water for retarder. Load pill pit & TT.;Line up to CMT Unit. pumped 5 bbls water, test lines to 4250 psi for 5 min. Pump 53 bbls 11 ppg tuned spacer, Drop Bypass plug.;Mix & pump 408 bbl 12 ppg Lead (940 sx cmt, 270 bbls mix water), 76 BBL 15.8 ppg Tail (390 sx cmt, 47 bbls mix water) Drop closing Plug. Pump 20 bbl H2O to clear Iines.;Line up to Rig. Displace with 375 bbl 9.3 ppg mud, 80 BBL H2O, 163 bbl 9.3 ppg Mud @ 6-8 BPM, Slow down pumps to 6 BPM after catching Pressure. Slow pumps to 2 BPM for last 20 bbl.;Worked pipe until spacer rounded the corner @ 50-75k DN & { r/ 350-375 up. Unable to work pipe pulling 400K after starting displament.;FCP 1190 psi, 658 bbls displaced, Plug bumped @ calculated stks, CIP @ 23:08 hrs. Pressure up 500 psi over FCP to 1660 psi, bleed off pressure, floats held, pressure to 3100 psi open ES cementer tool.;62 bbl losses while displacing cement.; Pump 5 bpm, 500 psi, slowing down to 2-3 bpm, 400-600 psi, 90 bbl into displacement see cement returns, circulate out thick clabbered mud, condition mud for 2nd stage cement job.;Note: 53 bbls spacer and 77 bbls cement returned to surface. W/O Trucks to return from injection sites and water truck to return w/ final load of cement water.;Hauled 318 bbls to MP G&I for total = 5225 bbls Hauled 0 bbls to GPB G&I for total = 114 bbls Hauled 632 bbls to KRU DS -1 B for total = 3844 bbls;Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls;Hauled 900 bbls from L Pad Lake for total = 900 bbls Daily losses to formation 62 bbls for total= 118 bbls 6/1/2016 Circ & condition @ 4-6 bpm while waiting trucks back from DS -1 B. Fill water tanks with 70 deg w All trucks on location. Conduct PJSM with HES. MW IN & Out 9.3; Pump 2nd stage cmt job, er plan. Mix 60 bbl, 11 PPG Tuned Spacer 315 KU11 1 ppg- 12—af-st I I ead GMT 405 RX �µ' o 56 bbl 15.8ppg Swift Cem tail CMT;Drop Closing Plug pump 20 bbl H2O to Clear Lines (%w Displace with Rig with 224 bbl H2O. Bumped plug with a final lift pressure of 740 psi.; Pressure up to 1600 psi & tool shifted. Pressure up to 2040 psi & hold for 5 min. Bled down & checked for flow. CIP @ 1127. We got Mud push back @ 35 bbl away with displacement.; We got good cmt back @ 165 bbl away with displacement. Total good cmt to surface 69 bbl.;R/D Halliburton. Flush black water through all lines & equipment. N/D & P/U diverter system. Set 9 5/8 emergency slips with 125k on the slips. Drain pipe. Cut 9 5/8 pipe. L/D cut joint. 7' LG. 4Break down 20" annular, Diverter, Riser & remove from cellar.;Make final cut on 9 5/8. Dress stump. Install Multi Bowl. Test Hanger void to 250 psi f/ 5 min, 3000 psi f/ 15 min. Good.;N/U BOP stack, install riser. Rig electrician operate rig ESD system.;R/U test equipment, Install test plug and 5" test jt, fill stack and lines with water, perform BOP body test to 3000 psi, g000.;Test BOPE, Test witness waived by AOGCC rep Jeff Jones on 6/1/16 @ 19:00 hrs. Test Annular to 250 psi low and 3000 psi high 5 min ea. Test upper and lower 2 7/8" x 5" VBR rams, Blind ram,;mud cross valves, choke man valves, upper and lower IBOP, 2 FOSVs to 250 psi low and 3000 psi high 5 min ea, chart all tests. Perform accumulator drawdown test, hyd and manual choke bleed test.;Rig electrician calibrate and test gas alarms. No failures;Hauled 775 bbls to MP G&I for total = 6000 bbls Hauled 57 bbls to GPB G&I for total = 171 bbls Hauled 741 bbls to KRU DS -1 B for total = 4585 bbls;Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls 1 Hauled 0 bbls from B Pad Creek for total = 450 bbls;Hauled 975 bbls from L Pad Lake for total = 1875 bbls �e7 Hauled 270 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 0 bbls for total= 118 bbls 6/2/2016 R/D Testing Equipment. Install Wear Bushing. Blow down all surface Iines.,Bring BHA #3 tools to the floor. PJSM P/U BHA. T/ 272'. 8.5 Bit NOV SK 616M long Gauge. Geopilot, DGR, PWD, ADR, DM,TM,NMFS,3 NMDC. Test MWD & Geo pilot. Good.;P/U 5" DP F/ 272'T/ 2976'. Wash down F/ 2900'& tag cmt @ 2976'.;Drill cmt F/ 2976'T/ 2999'. Tag HES curt plug. Drill plug & Cmter F/ 2999'T/ 3003' with 40 RPM 500 GPM 5-10 WOB. Ream and cleanup ESC, pass thru easily with pumps off.;Continue to RIH P/U singles f/ 3035' to 4042', RIH with stds f/ derrick to 6000';CBU pumping 500 gpm, 1280 psi, circulate out thick mud.;Continue RIH with stds f/ 6000' to 8476', wash last 2 stds and double tagging just above baffle adapter @ 8722', P/U 225K, ROT 137K, cannot S/O w/o rotating. Correct displacement on trip in.; Position tool jt above table, open kill line, purge air. Close upper pipe ram, test 9 5/8" casing to 3000 psi f/ 30 min charted. Good. 7.7 bbls pumped, 7.7 bbls bled back, open ram. Blow down choke; Drill plug / baffle adaptor, cmt and FE f/ 8722' to 8813' just above shoe pumping 400 gpm, 1100 psi, 2-14k wob, 40 rpm 18k torque.;Pump 30 bbl hi vis spacer, displace to new 8.8 ppg BARADRIL-N drilling mud., Hauled 220 bbls to MP G&I for total = 6220 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 404 bbls to KRU DS -1 B for total = 4989 bbls,Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls,Hauled 325 bbls from L Pad Lake for total = 2200 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 0 bbls for total= 118 bbls 6/3/2016 Displace to 8.8 ppg Baradril-N @ 200-250 GPM while working pipe.;Shut down. Monitor well. Good. Slip & cut drilling line. Inspect saver sub. Service rig.;Drill cmt, Shoe & 20' New hole T/ 8840'.;POOH & Ream Through shoe. Clean unable to work pipe down without rotary. Perform FIT to 12 PPG EMW. 598 psi. Held for 10 minuets. Bled down to 579 psi.;Drill ahead 8 1/2 hole, F/ 8840'T/ 9000'. Having to drop angle from 93 deg to 89 deg. Drilling fast. Having to hold back to 50' fph to drop angle. Ream out F/ 8983' T/ 8945 to drop angle.;Drill ahead limiting ROP 50-100 fph. Drop angle From 90 deg to 87 deg. Drilling F/ 9000' to 9060'. Ream stand @ 50' fph as per geologist. Showing the top fo the NB @ 9000'.;Drill ahead 8 1/2 hole, F/ 9060' T/9202, 142'@ 95 fph average. 500 gpm, @ 1300 psi 125 rpm, 19k tq on, 2-5 wob Max gas @ 2700 units. MW 8.8 in and out;Drill ahead 8 1/2 hole, F/ 9202'T/ 9703', 501'@ 84 fph ay. 500 gpm, @ 1400 psi 80-100 rpm, 19k tq on, 8-12 wob MW 8.8 in /8.9 out, ECD 10.21. Pump tandem 30 bbl to vis / 30 bbl 9.8 ppg weighted sweep @ 9390', sweep back on time w/ 50% increase @ shakers. Hi gas @ 9360'-4402u, 9520'-4625u; Drill ahead 8 1/2 hole, F/ 9703'T/ 10174', 471'@ 79 fph ay. 500 gpm, @ 1400 psi 80-100 rpm, 20k tq on, 5-12 wob MW 8.9 in / out, ECD 10.21 Note: @ 10,080' heavy oil blinding off shaker screens, reduce pump rate to 400 gpm, 910 psi, ROP to 150 fph until shaker can handle returns, continue to blind off, C/O screens to #140 mesh,;Last survey 10,008.957 89.75 incl 261.21 az. 11.11' above the line, 6.52' right of the Iine.;Hauled 1545 bbls to MP G&I for total = 7765 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 0 bbls to KRU DS -1 B for total = 4989 bbls;Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls,Hauled 525 bbls from L Pad Lake for total = 2752 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 0 bbls for total= 118 bbls 6/4/2016 Drill ahead 8 1/2 hole, F/10174' T/ 10455' @ 140 fph ay. 425 gpm, @ 1000 psi 80-100 rpm, 20k tq on, 5-12 wob MW 8.9 in / out, ECD 10.16;Circ & Condition 218 GPM while ROT & working pipe 75 RPM. Change scalper screens to 100s.;Drill ahead 8 1/2 hole, F/ 10455' T/ 11484' 1029'@ 121 fph ay. 434 gpm, @ 1067 psi 80-100 rpm, 20k tq on, 5-12 wob MW 8.9 in /out, ECD 10.23;Pumped weighted Sweep @ 10700'. Came back on time with 50% increase in cuttings.;Drill ahead 8 1/2 hole, F/ 11484' T/ 12300'. 816' @ 136 fph ay. 430 gpm, @ 1080 psi 80-100 rpm, 20k tq on, 4-8 wob MW 8.9 in /out, ECD 10.39;Drill ahead 8 1/2 hole, F/ 12300' T/ 12627' TD. 327' @ 52 fph ay. 500 gpm, @ 1750 psi 80-100 rpm, 24k tq on, 20-25 wob MW 9.1 in / out, ECD 10.42;Crossed fault @ 12262' MD. Currently dropping inc to 85 deg coming down section to find sand again. Broke through in to sand @ 85 deg @ 12548' EST. Started to Bring INC up from 85-87 deg.; Looks like NC sand. Calling TD @ 12627'; Last survey @ 12368.64' MD 88.58 deg inc, 273.92 deg AZ 20.24' above the line, 2.06' left of the Iine.;Hauled 713 bbls to MP G&I for total = 8478 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 699 bbls to KRU DS-1 B for total = 5658 bbls;Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls;Hauled 1350 bbls from L Pad Lake for total = 4075 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 0 bbls for total= 118 bbls 6/5/2016 Circ & condition mud. Pump 30 BBI high vis sweep around. Pump 2.5% by volume in to mud and circ two circulations. Not getting cuttings back. Hole clean. Monitor well. Static.;After pumping NSX Lube around Torque dropped by less than half 10K. Up wt down 20K & we are able to move pipe down with 65K no ROT.; Back ream out of the hole @ 500 gpm 100 rpm F/ 12627' T/ 11400'. Screens blinding off bad. Slow rate to 350 gpm. Power wash screens. Transfer mud with vac truck back in to pits.;Continue back reaming out of the hole F/ 11400 T/ 8760'. Shakers still blinding off. Slow rate to 250 gpm.;Shut down & Monitor well. Slight seepage. 1 bph. Change shaker screens to 200 flats.; Pump sweep. 30 bbl High vis. Fight shaker screens blinding off with grease like substance. NSX lube mixed with crude, circulate out sweep, no increase.;Stage pumps up f/ 100 gpm to 200 bpm, final @ 300 gpm without running over shakers. Flowcheck well, static.;POH on elevators racking stds in derrick f/ 8760' to 270'@ HWDP, correct displacement on trip out.;Flush BHA w/ water, UD BHA #3, 2 jts HWDP, jars, recover drift, UD 3 NMFCs, float sub. Upload data, UD directional tools and bit, grade= 1-2-CT-A-X-1-NO-TD.,Note: ILS had severe step wear on bottom and top of blades, also found 3" x 3 1/2" flat piece of alum wedged in Geo-pilot seal assembly from FE. Could not break bit from stabilizer sleeve, UD M/U.;Monitor well, Clear rig floor, load out BHA from pipeshed.,R/U to run 4 1/2" lower production. Mobilize tools to rig floor, load pipeshed w/ solid 4 1/2" liner. ready 5" safety jt w/ XOs and FOSV. Hold PJSM.;M/U and RIH w/ 4 1/2" production screen lower completion per tally, M/U shoe, WIV valve, XO, 4 1/2" Packoff, XO and 1st solid jt liner. check float operation, torque 13.5# HTTC liner to 8130 ft/lbs;9 jts solid liner, M/U XO, P/U and RIH w/ 4 1/2", 13CR, 13.5# Vam top max flow screens to 786' Use seal guard pipe dope. torque 13CR to 5000 fUlbs.;Hauled 498 bbls to MP G&I for total = 8976 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 0 bbls to KRU DS-1 B for total = 5658 bbls,Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls; Hauled 690 bbls from L Pad Lake for total = 4765 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 0 bbls for total= 118 bbls Hilcorp Energy Company Composite keport Well Name: MP J-28 Field: Milne Point County/State: North Slope, Alaska i (LAT/LONG): avation (RKB): 33.73 API #: Spud Date: 5/24/2016 Job Name: 1511627C MPJ -28 COMPLETION Contractor AFE #: AFE $: Activity Date Ops Summary 6/6/2016 P/U and RIH w/ 4 1/2", 13CR, 13.5# Vam top max flow screens to F/786' T/ 3828', P/U 9 Joints of 4.5 Blank HTTC for liner top space out. Up/DN 95/80 Use seal guard pipe dope. torque 13CR to 5000 ft/lbs.,Verify 4 1/2" liner count, R/U false bowl & 2 318 equipment. P/U Slick stick & 2 3/8 T/ 4178'. Tag up .5' in in joint 136. I/D joint 135 & 136. M/U space out pups & place no go 6' off packoff.,Change handling equipment. P/U Baker SLZXP Linertop Packer, 5" Swivel assembly. M/U to inner string & 4.5 liner. 9 pins for SLZXP for 44100 lbs, add PAL mix per baker rep. P/U wt 115K, S/O 95K,L/D swivel and pup, M/U 1 std 5" DP and top drive, circulate 1 tbg volume staging pumps f/ 1 bpm -220 psi, 2 bpm -490 psi, 3 bpm -800 psi,RIH with 4 112"lower completion conveyed on 5" DP f/ 4331' to 8761', 48 stands, slow in out of slips, 1.5 min std running speed. Fill pipe @ 7615', Correct displacement RIH to shoe.,M/U top drive, fill pipe, 2 bpm- 500 psi, 2.7 bpm- 820 psi, P/U 155K, S/O 110 psi.,TIH 1.5 min std f/ 8761' to 10766', fill pipe, 2.5 bpm 760 psi. P/U 170K, S/O 97K, continue TIH f/ 10766' to 12535', wash last std to bttm @ 12627', M/U single for working jt. P/U 180K, S/O 94K. No issues RIH, correct displacement on trip in,Parked @ 12627', circulate 3 bpm, 1000 psi. Prep pits and trucks for displacement. Displace well w/ 8.9 ppg 3% KCL brine pumping 3.2 bpm, 1050 psi.,Rif fuel= 7800 gal, used=400 gal. rec= 0 gal POB= 50,Hauled 300 bbls to MP G&I for total = 9276 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 0 bbls to KRU DS -1 B for total = 5658 bbls,Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls,Hauled 200 bbls from L Pad Lake for total = 4965 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 15 bbls for total= 133 bbls 6/7/2016 Parked @ 12627'w/ 4 1/2" lower completion, pump 1 st stage displacement to 8.9 ppg 3% KCL brine, 811 bbls pumped.,Flow check well, static. Break out single, drop 1.25" setting ball, M/U single, pump 3 bpm, 1150 psi @ 80 bbl away slow pump to 2 bpm, 640 psi, 120 bbls away slow pump to 1.5 bpm, 400 psi, 130 bbls pumped ball on seat. Perform LTP setting sequence per BOT rep.,Pressure to 1500 psi and hold 5 min. Pressure to 2700 psi, at 2090 psi seen indication of sheer, step pressure up to 2700 psi and hold f/ 5 min. Step pressure up and hold 4200 psi for 5 min. Bleed off pressure, slackoff to nogo, PUH and confirm release. Set @ 12627' wffOL @ 8402'. P/U 160K.,R/U to test LTP, line up kill line, close annular, pump 4.2 bbls , pressure up to 1500 psi, test annulus to LTP for 10 charted minutes, good test. bleed off pressure, open annular.,P/U 15' and unsting from packoff, pump 3 bpm 1070 psi, slowly pulling tools clear while circulating, rack 1 std in derrick.,Parked @ 12509' Pump 2nd 8.9 ppg brine displacement displacing production screen ID @ 4 bpm, 2100 psi. Flow check well for 10 min, BDTD and kill Iine.,POH on elevators racking 5" DP in derrick f/ 12509' to 8358'. Continue POH UD singles 5" DP f/ 8358' to 4200'. Note: pump 20 bbl dry job @ 80007 10 bbls over calculated displacement on trip out w/ 5" DP.,L/D XOs, running tool, R/U 2 3/8" handling equip. POH and UD 2 3/8" inner string f/ 4147' to 3885'.,Service blocks and drawworks. Inspect drawworks brakes and Iinkage.,Continue POH UD 2 3/8" inner work string f/ 3885' to surface, UD slick stick and XO.,R/D 2 3/8" handling equip. Load out same. R/U for 5" DP.,Rif fuel= 7500 gal, used=300 gal. rec= 0 gal POB= 50,Hauled 2050 bbls to MP G&I for total = 11326 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 109 bbls to KRU DS -1 B for total = 5767 bbls,Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls,Hauled 200 bbls from L Pad Lake for total = 5165 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 0 bbls for total= 133 bbls 6/8/2016 MU Mule Shoe on 5" DP. TIH to 8309' to circulate 9 5/8" casing clean.,Obtain parameters: PUW 150K/SOW 114K/Rot 130K, Wash down @ 12 bpm/750 psi to 8394'w/80 RPM/3K Tq. Circulate bottoms up, returns had stringers with the consistency of Oil/grease. Pump 30 bbls hi vis sweep to surface and circulate additional hole volume before cleaning up. Sweep brought back 50% increase in debris. Flow check well, well static.,Hang blocks, Slip and cut drill Line. Service Top Drive Blocks and Draw works. Inspect saver sub.,Pump dry job, POOH laying down 5" DP from 8309' to surface, UD XO and mule shoe. Note: 29 bbls over calculated hole fill on trip out.,R/U and pull 10" ID wear bushing, R/U fill line on I/A, install test plug. Install 7 5/8" casing ram in upper BOP, Note: Static loss rate @ 5 bph. / use continuous hole fill on I/A while C/O and testing rams.,R/U 7 5/8" test jt. Test casing ram to 250 low psi and 3000 psi hi 5 min ea. charted, R/D test equip and fill Iine.,Drain stack, Make hanger dummy run per wellhead rep.,R/U 7 5/8" handling equip. PJSM for running tie back string. P/U seal assy, no go locator, pup jt, M/U 7 5/8" STL x 7" BTC XO, P/U and RIH with 7 5/8", 29.7#, L-80, SLIJ II Casing, RIH to 900' Note: use BOL pipe dope, torq SLIJ II to 11400 ft/lbs. Utilize collar clamp on 1st 10 jts ran. Hole taking 8-10 bph.,Rig fuel= 7200 gal, used=300 gal. rec= 0 gal POB= 46,Hauled 365 bbls to MP G&I for total = 11682 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 0 bbls to KRU DS -1 B for total = 5767 bbls,Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls,Hauled 225 bbls from L Pad Lake for total = 5390 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 85 bbls for total= 218 bbls 6/9/2016 Continue to P/U and RIH with 7 5/8". 29.7 ',0 tie back Casing from 900' to 5598' (138' joint�,Serv' 19. Clear rig floor of thread protectors., Continue to P/U and RIH with 7 5/8", 29.7#, L-80, tie b� using from 5598' to 8366' (209' joints total) Lost 81 bbls rmation while running casing. Static loss rate @ 8-10 bph.,XO Csg to DP, RIH and make space out tag. No Go mule shoe out @ 8410.4'. Locate TOL @ 8401'. L/D 2 jts DP. Install 6.89' space out pup, MU Csg Hgr with pup and Landing Joint. Land out, XO landing jt to DP, MU Top Drive, Close bag and PT Annulus to 500 psi to ensure proper space out and seal engagement. Bleed pressure to 250 psi, strip up hole until pressure dumped, exposing seal ports to annulus.,Establish reverse circulation through ported seals with fluid from rig pits. Line up on and pump 125 bbls Corrosion inhibited 8.9 ppg KCL and chase with 50 bbls DSL. Strip in hole and land out Tie back seals 2.58' off no go. Open bag, Annulus static.,Back out landing joint, MU, Land and test Pack Off to 5000 psi. Test good. Lay down landing joint and running tool.,R/U test equipment. Test 9-5/8" x 7-5/8" annulus to 1500 psi w/ 30 min hold (Ok). Chart and record same. R/D test equipment.,R/U to run ESP upper completion, Load tools to rig floor, R/U power tongs, 2 7/8" handling equip. Spot ESP spooler, hang sheaves. Monitor well, static loss rate 5-6 bph,PJSM, Run 2 7/8 ESP completion per tally. P/U and M/U mtr/pump assy as per detail w/ centralizer and sensor sub. Fill assy w/ oil. tq flanges. M/U Mtr Lead, Test same,Rig fuel= 6800 gal, used=400 gal. rec= 0 gal POB= 46,Hauled 290 bbls to MP G&I for total = 11972 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 0 bbls to KRU DS -1 B for total = 5767 bbls,Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls,Hauled 200 bbls from L Pad Lake for total = 5590 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 60 bbls for total= 278 bbls 6/10/2016 Continue to run 2-7/8 ESP completion from 400', installing Cannon Clamps every other joint. Testing cable every 1000'. Reduce running speed to 500 fph through build section from 1700'-2300'. Resume normal running speed @ 2300', RIH to 4265',String heat trace cable thru sheave. Install Heat trace @ 4265' (3200'from Surface) install 5- 5ft clamps and 1 collar clamp every jt. RIH F/ 4265' to 4656'(140 jts) install GLM with pup jts and dummy valve, Continue to RIH F/ 4683' to 6571' ( 198 jts ) Meg Test cable every 1000', Hole taking 6-8 bph.,Rig fuel= 6500 gal, used=300 gal. rec= 0 gal POB= 46,Hauled 128 bbls to ORT Hauled 0 bbls to MP G&I for total = 11972 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 0 bbls to KRU DS -1 B for total = 5767 bbls,Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls,Hauled 75 bbls from L Pad Lake for total = 5665 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 169 bbls for total= 447 bbls 6/11/2016 Continue to RIH with 2 7/8" Tubing ESP/Heat Trace F/ 6571' to 7440'. Meg Test cable every 1000'„MU tubing Hanger, orient same. Install Penetrators for heat trace, ESP and Control Line. Make Penetrator Splices.,Land hanger @ 29.98' RKB, w/ upper GLM w/ oriface @ 172", lower GLM w/ dummy valve @ 2802', XN nipple @ 7379', EOP @ 7475'. 94K PUW/75K SOW, wt on hanger= 20k, RILDS per wellhead rep. Final Clamp Count: Cannon Clamps= 168, 5' Cross Collar Clamps= 481, SS Bands = 4, Pump Assy Clamps= 8. Losses @ 3-4 bph,lnstall BPV, C/O upper rams from 7 5/8" to 2 7/8” x 5" VBR's. N/D BOP, C/O upper and lower IBOPs on Top Drive. Test hanger void to 500 / 5000 psi 5 min ea. per wellhead rep. Cleaning mud pits, loading trailers, Moving equipment to C-Pad,N/U adapter Flange and tree, pull BPV, install TWC, pressure test Tree to 500/5000 psi 5 min ea, charted, good test. Pull TWC.,R/U LRS, test lines to 250/2500 psi, bullhead 113 bbls diesel down I/A 1.5 bpm 300 psi , 13 bbls down tbg 1.5 bpm, 300 psi - freeze protecting well to 3000'. Prep and skid #2 conveyer, prep rig floor to skid into rig move position.,Rig released from J-28 @ 06:00 hrs.,Rig fuel= 6100 gal, used=400 gal. rec= 0 gal POB= 45,Hauled 0 bbls to ORT for total = 128 bbls Hauled 307 bbls to MP G&I for total = 12279 bbls Hauled 0 bbls to GPB G&I for total = 171 bbls Hauled 0 bbls to KRU DS -1 B for total = 5767 bbls,Hauled 0 bbls from Vern Lake for total = 870 bbls Hauled 0 bbls from 6 Mile Lake for total = 7335 bbls Hauled 0 bbls from B Pad Creek for total = 450 bbls,Hauled 0 bbls from L Pad Lake for total = 5665 bbls Hauled 0 bbls from GPB Pad 3 for total = 270 bbls Daily losses to formation 60 bbls for total= 507 bbls Hilcorp Energy Company Milne Point M Pt J Pad MPJ -28 50-029-23558-00-00 50-029-23558-00-00 Sp®rry Drilling Definitive Survey Report 07 June, 2016 HALLIBURTAN Sperry Drilling Company: Hilcorp Energy Company Project: Milne Point Site: M Pt J Pad Well: MPJ -28 Wellbore: MPJ -28 Design: MPJ -28 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPJ -28 Updated RKB @ 67.10usft (Doyon 14) Updated RKB @ 67.10usft (Doyon 14) True Minimum Curvature Sperry EDM - NORTH US + CANADA 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 ;Well MPJ -28 - Well Position +N/ -S 0.00 usft Northing: 6,014,608.14 usft Latitude: 70° 27'2.328 N +El -W 0.00 usft Easting: 552,189.84 usft Longitude: 149° 34'27.094 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 33.40 usft Wellbore MPJ -28 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2015 5/27/2016 18.53 81.05 57,498 Design MPJ -28 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 269.77 Survey Program Date 6/7/2016 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 830.00 RIG SRG-SS (MPJ -28) SRG-SS Surface readout gyro single shot 05/18/2016 857.68 8,737.58 MWD+IFR2+MS+sag (MPJ -28) MWD+IFR2+MS+sag Fixed:v2:IIFR dec & 3 -axis correction + sag 05/25/2016 8,779.82 12,557.09 MWD +IFR2+MS+sag (2) (MPJ -28) MWD+IFR2+MS+sag Fixed:v2:IIFR dec & 3 -axis correction + sag 06/06/2016 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) C) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 33.70 0.00 0.00 33.70 -33.40 0.00 0.00 6,014,608.14 552,189.84 0.00 0.00 UNDEFINED 100.00 0.25 234.27 100.00 32.90 -0.08 -0.12 6,014,608.05 552,189.72 0.38 0.12 SRG-SS (1) 170.00 0.11 253.10 170.00 102.90 -0.19 -0.31 6,014,607.94 552,189.54 0.21 0.31 SRG-SS (1) 265.00 0.56 251.16 265.00 197.90 -0.37 -0.83 6,014,607.76 552,189.01 0.47 0.83 SRG-SS(1) 357.00 1.75 237.92 356.98 289.88 -1.26 -2.45 6,014,606.86 552,187.40 1.32 2.45 SRG-SS(1) 452.00 3.45 233.69 451.88 384.78 -3.72 -5.98 6,014,604.37 552,183.89 1.80 6.00 SRG-SS(1) 546.00 5.71 237.93 545.57 478.47 -7.88 -12.22 6,014,600.17 552,177.67 2.43 12.25 SRG-SS (1) 640.00 9.96 237.69 638.67 571.57 -14.71 -23.06 6,014,593.27 552,166.88 4.52 23.12 SRG-SS (1) 735.00 12.40 236.99 731.86 664.76 -24.66 -38.56 6,014,583.21 552,151.46 2.57 38.66 SRG-SS (1) 830.00 15.12 236.82 824.13 757.03 -37.00 -57.49 6,014,570.74 552,132.62 2.86 57.63 SRG-SS (1) 857.68 16.14 236.43 850.78 783.68 -41.11 -63.71 6,014,566.59 552,126.42 3.70 63.88 MWD+IFR2+MS+sag (2) 949.01 19.06 237.00 937.83 870.73 -56.25 -86.80 6,014,551.29 552,103.44- - 3.20 87.03 MWD+IFR2+MS+sag (2) 6/7/2016 3:06:43PM Page 2 COMPASS 5000.1 Build 81 Company: Hilcorp Energy Company Project: Milne Point Site: M Pt J Pad Well: MPJ -28 Wellbore: MPJ -28 Design: MPJ -28 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPJ -28 Updated RKB @ 67,10usft (Doyon 14) Updated RKB @ 67.10usft (Doyon 14) True Minimum Curvature Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E1 -W Northing Easting DLS Section (usft) (°) 0 (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,046.65 23.21 238.93 1,028.88 961.78 -74.87 -116.67 6,014,532.46 552,073.71 4.31 116.96 MWD+IFR2+MS+sag (2) 1,140.88 24.63 240.55 1,115.02 1,047.92 -94.11 -149.67 6,014,512.99 552,040.85 1.66 150.05 MWD+IFR2+MS+sag (2) 1,234.96 27.92 243.54 1,199.37 1,132.27 -113.57 -186.47 6,014,493.28 552,004.18 3.77 186.92 MWD+IFR2+MS+sag (2) 1,329.40 33.29 245.90 1,280.63 1,213.53 -134.02 -229.96 6,014,472.53 551,960.85 5.83 230.49 MWD+IFR2+MS+sag (2) 1,423.90 38.94 250.01 1,356.95 1,289.85 -154.78 -281.59 6,014,451.41 551,909.37 6.50 282.20 MWD+IFR2+MS+sag (2) 1,518.28 39.33 253.64 1,430.16 1,363.06 -173.35 -338.17 6,014,432.45 551,852.93 2.46 338.86 MWD+IFR2+MS+sag (2) 1,612.13 39.33 257.32 1,502.77 1,435.67 -188.25 -395.73 6,014,417.14 551,795.48 2.48 396.47 MWD+IFR2+MS+sag (2) 1,706.78 40.30 262.06 1,575.49 1,508.39 -199.07 455.32 6,014,405.91 551,735.97 3.37 456.11 MWD+IFR2+MS+sag (2) 1,801.35 45.08 266.38 1,644.99 1,577.89 -205.41 -519.08 6,014,399.12 551,672.26 5.93 519.89 MWD+IFR2+MS+sag (2) 1,895.40 52.27 268.79 1,707.06 1,639.96 -208.30 -589.59 6,014,395.73 551,601.78 7.88 590.42 MWD+IFR2+MS+sag (2) 1,989.47 54.59 270.14 1,763.11 1,696.01 -209.00 -665.13 6,014,394.51 551,526.25 2.72 665.96 MWD+IFR2+MS+sag (2) 2,083.40 60.61 272.33 1,813.42 1,746.32 -207.24 -744.37 6,014,395.72 551,447.01 6.70 745.19 MWD+IFR2+MS+sag (2) 2,178.30 67.88 274.98 1,854.63 1,787.63 -201.73 -829.60 6,014,400.62 551,361.75 8.08 830.40 MWD+IFR2+MS+sag (2) 2,270.30 76.30 276.51 1,882.90 1,815.80 -192.95 -916.62 6,014,408.79 551,274.68 9.29 917.38 MWD+IFR2+MS+sag (2) 2,366.27 76.48 277.30 1,905.48 1,838.38 -181.74 -1,009.22 6,014,419.36 551,182.02 0.82 1,009.93 MWD+IFR2+MS+sag (2) 2,460.02 76.04 275.97 1,927.75 1,860.65 -171.21 -1,099.67 6,014,429.25 551,091.50 1.46 1,100.34 MWD+IFR2+MS+sag (2) 2,554.26 75.27 273.90 1,951.10 1,884.00 -163.36 -1,190.63 6,014,436.47 551,000.50 2.28 1,191.27 MWD+IFR2+MS+sag (2) 2,649.25 75.15 273.55 1,975.35 1,908.25 -157.39 -1,282.28 6,014,441.79 550,908.82 0.38 1,282.89 MWD+IFR2+MS+sag (2) 2,742.88 75.02 271.39 1,999.45 1,932.35 -153.49 -1,372.66 6,014,445.06 550,818.42 2.23 1,373.26 MWD+IFR2+MS+sag (2) 2,837.56 74.71 271.00 2,024.17 1,957.07 -151.58 -1,464.04 6,014,446.32 550,727.04 0.52 1,464.63 MWD+IFR2+MS+sag (2) 2,931.88 74.38 271.06 2,049.31 1,982.21 -149.95 -1,554.93 6,014,447.32 550,636.15 0.36 1,555.52 MWD+IFR2+MS+sag (2) 3,024.76 74.21 271.53 2,074.45 2,007.35 -147.93 -1,644.32 6,014,448.71 550,546.75 0.52 1,644.90 MWD+IFR2+MS+sag (2) 3,117.50 73.04 272.39 2,100.60 2,033.50 -144.89 -1,733.25 6,014,451.13 550,457.82 1.54 1,733.81 MWD+IFR2+MS+sag (2) 3,211.47 73.42 273.18 2,127.71 2,060.61 -140.52 -1,823.11 6,014,454.87 550,367.93 0.90 1,823.66 MWD+IFR2+MS+sag (2) 3,305.41 73.99 273.36 2,154.07 2,086.97 -135.37 -1,913.13 6,014,459.39 550,277.89 0.63 1,913.66 MWD+IFR2+MS+sag (2) 3,400.18 74.46 273.54 2,179.83 2,112.73 -129.88 -2,004.17 6,014,464.24 550,186.83 0.53 2,004.67 MWD+IFR2+MS+sag (2) 3,494.77 74.71 273.13 2,204.97 2,137.87 -124.58 -2,095.20 6,014,468.90 550,095.77 0.49 2,095.68 MWD+IFR2+MS+sag (2) 3,589.19 74.18 272.28 2,230.29 2,163.19 -120.29 -2,186.06 6,014,472.56 550,004.89 1.03 2,186.52 MWD+IFR2+MS+sag (2) 3,682.67 73.05 271.02 2,256.66 2,189.56 -117.70 -2,275.70 6,014,474.52 549,915.24 1.77 2,276.15 MWD+IFR2+MS+sag (2) 3,777.58 73.04 270.64 2,284.34 2,217.24 -116.39 -2,366.48 6,014,475.20 549,824.47 0.38 2,366.92 MWD+IFR2+MS+sag (2) 3,872.18 74.95 271.30 2,310.42 2,243.32 -114.84 -2,457.39 6,014,476.10 549,733.55 2.13 2,457.83 MWD+IFR2+MS+sag (2) 3,966.53 73.88 270.37 2,335.77 2,268.67 -113.52 -2,548.26 6,014,476.79 549,642.68 1.48 2,548.69 MWD+IFR2+MS+sag (2) 4,060.74 73.42 270.57 2,362.29 2,295.19 -112.78 -2,638.66 6,014,476.90 549,552.29 0.53 2,639.08 MWD+IFR2+MS+sag (2) 4,155.17 71.87 271.50 2,390.46 2,323.36 -111.15 -2,728.77 6,014,477.89 549,462.18 1.89 2,729.19 MWD+IFR2+MS+sag (2) 4,249.07 70.45 273.12 2,420.78 2,353.68 -107.57 -2,817.56 6,014,480.85 549,373.37 2.23 2,817.97 MWD+IFR2+MS+sag (2) 4,344.10 71.95 274.27 2,451.41 2,384.31 -101.77 -2,907.33 6,014,486.02 549,283.58 1.95 2,907.71 MWD+IFR2+MS+sag (2) 4,438.60 72.65 273.81 2,480.14 2,413.04 -95.43 -2,997.13 6,014,491.73 549,193.74 0.87 2,997.49 MWD+IFR2+MS+sag (2) 4,533.01 73.99 273.33 2,507.24 2,440.14 -89.80 -3,087.39 6,014,496.73 549,103.45 1.50 3,087.72 MWD+IFR2+MS+sag (2) 4,627.35 74.25 272.20 2,533.05 2,465.95 -85.43 -3,178.02 6,014,500.47 549,012.80 1.18 3,178.34 MWD+IFR2+MS+sag (2) 4,721.67 73.04 273.25 2,559.61 2,492.51 -81.13 -3,268.42 6,014,504.14 548,922.38 1.67 3,268.72 MWD+IFR2+MS+sag (2) 6/7/2016 3:06:43PM Page 3 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPJ -28 Project: Milne Point TVD Reference: Updated RKB @ 67.10usft (Doyon 14) Site: M Pt J Pad MD Reference: Updated RKB @ 67.10usft (Doyon 14) Well: MPJ -28 North Reference: True Wellbore: MPJ -28 Survey Calculation Method: Minimum Curvature Design: MPJ -28 Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) 0 (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 4,816.22 72.12 273.24 2,587.92 2,520.82 -76.02 -3,358.49 6,014,508.61 548,832.29 0.97 3,358.77 MWD+IFR2+MS+sag (2) 4,910.60 73.80 271.51 2,615.58 2,548.48 -72.29 -3,448.64 6,014,511.71 548,742.12 2.50 3,448.90 MWD+IFR2+MS+sag (2) 5,005.21 74.82 270.53 2,641.16 2,574.06 -70.67 -3,539.71 6,014,512.69 548,651.06 1.47 3,539.96 MWD+IFR2+MS+sag (2) 5,099.88 74.11 270.96 2,666.52 2,599.42 -69.48 -3,630.91 6,014,513.24 548,559.86 0.87 3,631.16 MWD+IFR2+MS+sag (2) 5,194.08 72.56 270.87 2,693.53 2,626.43 -68.04 -3,721.14 6,014,514.05 548,469.63 1.65 3,721.38 MWD+IFR2+MS+sag (2) 5,287.94 71.80 271.19 2,722.25 2,655.15 -66.43 -3,810.48 6,014,515.03 548,380.28 0.87 3,810.72 MWD+IFR2+MS+sag (2) 5,382.33 73.60 271.20 2,750.32 2,683.22 -64.55 -3,900.58 6,014,516.28 548,290.19 1.91 3,900.81 MWD+IFR2+MS+sag (2) 5,477.51 74.75 271.40 2,776.28 2,709.18 -62.48 -3,992.13 6,014,517.72 548,198.64 1.23 3,992.34 MWD+IFR2+MS+sag (2) 5,571.20 74.72 272.10 2,800.94 2,733.84 -59.72 -4,082.47 6,014,519.84 548,108.29 0.72 4,082.67 MWD+IFR2+MS+sag (2) 5,666.04 74.62 272.20 2,826.02 2,758.92 -56.29 -4,173.87 6,014,522.63 548,016.87 0.15 4,174.06 MWD+IFR2+MS+sag (2) 5,760.50 73.29 272.58 2,852.13 2,785.03 -52.50 -4,264.57 6,014,525.78 547,926.16 1.46 4,264.74 MWD+IFR2+MS+sag (2) 5,854.84 72.32 273.85 2,880.02 2,812.92 -47.45 -4,354.55 6,014,530.20 547,836.15 1.65 4,354.70 MWD+IFR2+MS+sag (2) 5,949.40 71.95 274.85 2,909.02 2,841.92 40.62 -4,444.29 6,014,536.40 547,746.38 1.08 4,444.41 MWD+IFR2+MS+sag (2) 6,043.47 71.15 275.27 2,938.80 2,871.70 -32.75 -4,533.17 6,014,543.65 547,657.45 0.95 4,533.27 MWD+IFR2+MS+sag (2) 6,138.08 71.56 274.66 2,969.04 2,901.94 -25.00 -4,622.48 6,014,550.78 547,568.10 0.75 4,622.54 MWD+IFR2+MS+sag (2) 6,232.86 73.56 274.06 2,997.45 2,930.35 -18.12 -4,712.64 6,014,557.02 547,477.90 2.19 4,712.67 MWD+IFR2+MS+sag (2) 6,327.37 73.54 273.82 3,024.21 2,957.11 -11.90 -4,803.06 6,014,562.61 547,387.44 0.24 4,803.07 MWD+IFR2+MS+sag (2) 6,421.44 74.27 272.54 3,050.29 2,983.19 -6.88 -4,893.31 6,014,566.99 547,297.18 1.52 4,893.29 MWD+IFR2+MS+sag (2) 6,515.46 73.23 271.04 3,076.60 3,009.50 -4.06 -4,983.52 6,014,569.18 547,206.95 1.89 4,983.50 MWD+IFR2+MS+sag (2) 6,609.54 72.91 270.88 3,104.00 3,036.90 -2.55 -5,073.51 6,014,570.06 547,116.96 0.38 5,073.48 MWD+IFR2+MS+sag (2) 6,704.29 73.08 271.40 3,131.71 3,064.61 -0.75 -5,164.10 6,014,571.23 547,026.37 0.55 5,164.06 MWD+IFR2+MS+sag (2) 6,798.79 72.50 271.61 3,159.67 3,092.57 1.62 -5,254.34 6,014,572.96 546,936.13 0.65 5,254.29 MWD+IFR2+MS+sag (2) 6,893.21 72.00 272.05 3,188.45 3,121.35 4.49 -5,344.22 6,014,575.21 546,846.24 0.69 5,344.16 MWD+IFR2+MS+sag (2) 6,987.78 71.67 272.83 3,217.94 3,150.84 8.32 -5,433.99 6,014,578.40 546,756.45 0.86 5,433.91 MWD+IFR2+MS+sag (2) 7,082.39 71.88 272.53 3,247.53 3,180.43 12.52 -5,523.76 6,014,581.97 546,666.67 0.37 5,523.66 MWD+IFR2+MS+sag (2) 7,176.28 72.24 272.83 3,276.45 3,209.35 16.69 -5,612.98 6,014,585.53 546,577.42 0.49 5,612.87 MWD+IFR2+MS+sag (2) 7,270.63 71.93 272.90 3,305.47 3,238.37 21.18 -5,702.65 6,014,589.38 546,487.74 0.34 5,702.52 MWD+IFR2+MS+sag (2) 7,364.20 72.34 272.84 3,334.17 3,267.07 25.64 -5,791.59 6,014,593.22 546,398.77 0.44 5,791.44 MWD+IFR2+MS+sag (2) 7,459.14 72.79 272.99 3,362.62 3,295.52 30.25 -5,882.05 6,014,597.19 546,308.29 0.50 5,881.89 MWD+IFR2+MS+sag (2) 7,553.91 71.78 273.16 3,391.46 3,324.36 35.09 -5,972.20 6,014,601.40 546,218.12 1.08 5,972.01 MWD+IFR2+MS+sag (2) 7,648.28 71.74 273.08 3,420.99 3,353.89 39.97 -6,061.69 6,014,605.65 546,128.60 0.09 6,061.49 MWD+IFR2+MS+sag (2) 7,742.76 72.53 273.18 3,449.98 3,382.88 44.88 -6,151.48 6,014,609.93 546,038.79 0.84 6,151.26 MWD+IFR2+MS+sag (2) 7,837.15 71.86 273.71 3,478.84 3,411.74 50.28 -6,241.19 6,014,614.71 545,949.06 0.89 6,240.94 MWD+IFR2+MS+sag (2) 7,931.62 73.79 273.78 3,506.74 3,439.64 56.17 -6,331.25 6,014,619.97 545,858.97 2.04 6,330.98 MWD+IFR2+MS+sag (2) 8,025.81 73.88 273.99 3,532.96 3,465.86 62.30 -6,421.51 6,014,625.47 545,768.68 0.23 6,421.21 MWD+IFR2+MS+sag (2) 8,120.11 76.48 272.35 3,557.08 3,489.98 67.33 -6,512.52 6,014,629.86 545,677.64 3.23 6,512.20 MWD+IFR2+MS+sag (2) 8,213.17 78.26 270.95 3,577.43 3,510.33 69.94 -6,603.28 6,014,631.84 545,586.87 2.41 6,602.95 MWD+IFR2+MS+sag (2) 8,308.52 81.03 270.42 3,594.56 3,527.46 71.06 -6,697.07 6,014,632.30 545,493.09 2.96 6,696.73 MWD+IFR2+MS+sag (2) 8,401.82 85.18 267.09 3,605.76 3,538.66 69.04 -6,789.64 6,014,629.63 545,400.55 5.69 6,789.31 MWD+IFR2+MS+sag (2) 8,497.45 88.95 264.47 3,610.66 3,543.56 62.01 -6,884.85 6,014,621.93 545,305.39 4.60 6,884.55 MWD+IFR2+MS+sag (2) 6/7/2016 3:06:43PM Page 4 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPJ -28 Project: Milne Point TVD Reference: Updated RKB @ 67.10usft (Doyon 14) Site: M Pt J Pad MD Reference: Updated RKB @ 67.10usft (Doyon 14) Well: MPJ -28 North Reference: True Wellbore: MPJ -28 Survey Calculation Method: Minimum Curvature Design: MPJ -28 Database: Sperry EDM - NORTH US + CANADA Survey 6/7/2016 3:06:43PM Page 5 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Azl TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (I (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,592.53 91.91 264.58 3,609.95 3,542.85 52.94 -6,979.49 6,014,612.20 545,210.83 3.12 6,979.22 MWD+IFR2+MS+sag (2) 8,686.93 94.51 264.98 3,604.66 3,537.56 44.37 -7,073.34 6,014,602.97 545,117.05 2.79 7,073.11 MWD+IFR2+MS+sag (2) 8,737.58 95.19 265.25 3,600.38 3,533.28 40.07 -7,123.63 6,014,598.32 545,066.80 1.44 7,123.41 MWD+IFR2+MS+sag (2) 8,779.82 94.32 265.16 3,596.88 3,529.78 36.55 -7,165.57 6,014,594.51 545,024.88 2.07 7,165.37 MWD+IFR2+MS+sag (3) 8,876.09 93.15 264.94 3,590.61 3,523.51 28.26 -7,261.28 6,014,585.55 544,929.25 1.24 7,261.11 MWD+IFR2+MS+sag (3) 8,970.74 90.86 264.91 3,587.30 3,520.20 19.89 -7,355.49 6,014,576.52 544,835.10 2.42 7,355.36 MWD+IFR2+MS+sag (3) 9,065.23 87.34 264.77 3,588.78 3,521.68 11.40 -7,449.57 6,014,567.37 544,741.09 3.73 7,449.47 MWD+IFR2+MS+sag (3) 9,158.31 88.40 265.45 3,592.24 3,525.14 3.47 -7,542.25 6,014,558.79 544,648.48 1.35 7,542.18 MWD+IFR2+MS+sag (3) 9,253.30 88.33 266.32 3,594.95 3,527.85 -3.34 -7,636.95 6,014,551.32 544,553.84 0.92 7,636.91 MWD+IFR2+MS+sag (3) 9,347.07 90.37 267.34 3,596.01 3,528.91 -8.53 -7,730.57 6,014,545.48 544,460.27 2.43 7,730.54 MWD+IFR2+MS+sag (3) 9,442.99 93.46 266.44 3,592.81 3,525.71 -13.73 -7,826.28 6,014,539.61 544,364.60 3.36 7,826.27 MWD+IFR2+MS+sag (3) 9,537.67 92.66 263.46 3,587.75 3,520.65 -22.05 -7,920.45 6,014,530.63 544,270.51 3.25 7,920.47 MWD+IFR2+MS+sag (3) 9,631.32 91.24 262.15 3,584.57 3,517.47 -33.77 -8,013.30 6,014,518.26 544,177.75 2.06 8,013.37 MWD+IFR2+MS+sag (3) 9,726.21 91.73 262.63 3,582.11 3,515.01 -46.34 -8,107.32 6,014,505.04 544,083.82 0.72 8,107.44 MWD+IFR2+MS+sag (3) 9,819.86 90.74 262.15 3,580.09 3,512.99 -58.73 -8,200.13 6,014,491.99 543,991.12 1.17 8,200.30 MWD+IFR2+MS+sag (3) 9,914.46 89.44 260.59 3,579.94 3,512.84 -72.93 -8,293.65 6,014,477.14 543,897.71 2.15 8,293.87 MWD+IFR2+MS+sag (3) 10,008.95 89.75 261.21 3,580.61 3,513.51 -87.87 -8,386.95 6,014,461.55 543,804.53 0.73 8,387.23 MWD+IFR2+MS+sag (3) 10,098.82 90.25 263.06 3,580.61 3,513.51 -100.17 -8,475.97 6,014,448.63 543,715.60 2.13 8,476.30 MWD+IFR2+MS+sag (3) 10,197.61 90.68 264.99 3,579.81 3,512.71 -110.45 -8,574.21 6,014,437.66 543,617.44 2.00 8,574.59 MWD+IFR2+MS+sag (3) 10,292.03 90.25 266.37 3,579.04 3,511.94 -117.56 -8,668.36 6,014,429.89 543,523.36 1.53 8,668.76 MWD+IFR2+MS+sag (3) 10,385.88 90.74 267.69 3,578.23 3,511.13 -122.43 -8,762.08 6,014,424.37 543,429.68 1.50 8,762.50 MWD+IFR2+MS+sag (3) 10,480.90 90.80 269.58 3,576.95 3,509.85 -124.69 -8,857.06 6,014,421.44 543,334.73 1.99 8,857.48 MWD+IFR2+MS+sag (3) 10,575.18 91.60 270.98 3,574.98 3,507.88 -124.23 -8,951.31 6,014,421.24 543,240.48 1.71 8,951.74 MWD+IFR2+MS+sag (3) 10,669.83 91.79 271.90 3,572.18 3,505.08 -121.85 -9,045.89 6,014,422.96 543,145.90 0.99 9,046.30 MWD+IFR2+MS+sag (3) 10,764.25 92.16 272.44 3,568.92 3,501.82 -118.28 -9,140.19 6,014,425.87 543,051.59 0.69 9,140.59 MWD+IFR2+MS+sag (3) 10,858.04 91.11 271.59 3,566.25 3,499.15 -114.98 -9,233.88 6,014,428.51 542,957.89 1.44 9,234.26 MWD+IFR2+MS+sag (3) 10,952.39 91.48 271.10 3,564.12 3,497.02 -112.77 -9,328.18 6,014,430.06 542,863.58 0.65 9,328.55 MWD+IFR2+MS+sag (3) 11,047.02 92.72 271.22 3,560.65 3,493.55 -110.85 -9,422.72 6,014,431.31 542,769.04 1.32 9,423.09 MWD+IFR2+MS+sag (3) 11,141.51 92.22 271.02 3,556.58 3,489.48 -109.01 -9,517.11 6,014,432.50 542,674.65 0.57 9,517.47 MWD+IFR2+MS+sag (3) 11,235.82 92.22 271.04 3,552.92 3,485.82 -107.32 -9,611.33 6,014,433.53 542,580.43 0.02 9,611.68 MWD+IFR2+MS+sag (3) 11,330.33 91.48 272.08 3,549.87 3,482.77 -104.74 -9,705.75 6,014,435.44 542,486.00 1.35 9,706.09 MWD+IFR2+MS+sag (3) 11,424.59 91.42 273.11 3,547.49 3,480.39 -100.48 -9,799.89 6,014,439.05 542,391.85 1.09 9,800.21 MWD+IFR2+MS+sag (3) 11,519.49 90.43 272.94 3,545.95 3,478.85 -95.47 -9,894.64 6,014,443.39 542,297.07 1.06 9,894.94 MWD+IFR2+MS+sag (3) 11,613.61 89.81 272.71 3,545.76 3,478.66 -90.83 -9,988.65 6,014,447.37 542,203.04 0.70 9,988.93 MWD+IFR2+MS+sag (3) 11,708.30 90.99 273.11 3,545.10 3,478.00 -86.02 -10,083.21 6,014,451.52 542,108.46 1.32 10,083.47 MWD+IFR2+MS+say (3) 11,801.79 91.30 272.97 3,543.23 3,476.13 -81.07 -10,176.55 6,014,455.82 542,015.09 0.36 10,176.79 MWD+IFR2+MS+sag(3) 11,896.62 91.17 272.49 3,541.18 3,474.08 -76.55 -10,271.25 6,014,459.67 541,920.37 0.52 10,271.47 MWD+IFR2+MS+sag (3) 11,990.98 90.19 271.95 3,540.06 3,472.96 -72.90 -10,365.53 6,014,462.66 541,826.08 1.19 10,365.74 MWD+IFR2+MS+sag (3) 12,084.71 90.49 273.37 3,539.51 3,472.41 -68.55 -10,459.16 6,014,466.36 541,732.43 1.55 10,459.35 MWD+IFR2+MS+sag (3) 12,178.95 89.81 273.34 3,539.26 3,472.16 -63.03 -10,553.23 6,014,471.21 541,638.33 0.72 10,553.40 MWD+IFR2+MS+sag (3) 6/7/2016 3:06:43PM Page 5 COMPASS 5000.1 Build 81 Company: Hilcorp Energy Company Project: Milne Point Site: M Pt J Pad Well: MPJ -28 Wellbore: MPJ -28 Design: MPJ -28 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPJ -28 Updated RKB @ 67.10usft (Doyon 14) Updated RKB @ 67.10usft (Doyon 14) True Minimum Curvature Sperry EDM - NORTH US + CANADA 6/7/2016 3:06:43PM Page 6 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (1) (") (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 12,273.97 89.88 272.68 3,539.52 3,472.42 -58.04 -10,648.12 6,014,475.54 541,543.42 0.70 10,648.27 MWD+IFR2+MS+sag (3) 12,368.64 88.58 272.92 3,540.79 3,473.69 -53.42 -10,742.67 6,014,479.50 541,448.85 1.40 10,742.79 MWD+IFR2+MS+sag (3) 12,462.80 85.18 272.08 3,545.91 3,478.81 -49.32 -10,836.58 6,014,482.94 541,354.92 3.72 10,836.69 MWD+IFR2+MS+sag (3) 12,557.09 84.93 271.89 3,554.04 3,486.94 -46.06 -10,930.47 6,014,485.54 541,261.02 0.33 10,930.56 MWD+IFR2+MS+sag (3) 12,627.00 84.93 271.89 3,560.22 3,493.12 -43.77 -11,000.06 6,014,487.35 541,191.42 0.00 11,000.15 PROJECTED to TD Checked By: brian.wheeler@halllburt on.comp,a o„z<�� Ca Taylor Approved By: Cary y ° Date: 6/7/2016 3:06:43PM Page 6 COMPASS 5000.1 Build 81 MPJ -28 FINAL Days vs Depth o 500 1000 1500 2000 MPJ -28 Actual MPJ -28 Plan MPJ -28 Stretch Goal ----- 2500 3000 3500 4000 4500 5000 5500 $ 6000 r ..L CL 6500 0 7000 a 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 0 5 10 15 20 25 Days 7/11/2016 1:49 PM MPJ -28 MW vs Depth 0 MPJ -28 Plan 1000 MPJ -28 Actual - 2000 3000 4000 5000 CL 6000 w 0 v a fn 7000 m a 8000 9000 10000 11000 12000 13000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density (ppg) Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No. MP J-28 County North Slope State Alaska CASING RECORD Surface TO 8,820.00 Shoe Depth: 8,819.00 No. As. Delivered 227 No. As. Run Supv. Date Run 31 -May -16 Sloan Sunderland / Shane Barber _ PBTD: 8,727.92 217 No. Jts. Returned 10 Ftg. Delivered 9,216.11 Ftg. Run 8,770.39 Ftg. Returned 445.72 Length Measurements W/O Threads Ftg. Cut Jt. 7.00 Ftg. Balance RKB RKB to BHF RKB to CHF RKB to THF Csg Wt. On Hook: 275,000 Type Float Collar: DHP No. Hrs to Run: 27 Csg Wt. On Slips: 125,000 Type of Shoe: DHP Casing Crew: DOYON Rotate Csg Yes X No Recip Csg X Yes No 15 Ft. Min. 9.3 PPG Fluid Description: SPUD MUD Liner hanger Info (Make/Model): CASING SLIPS Liner top Packer?: _Yes X No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 2 CENTRALIZERS ON SHOE JT 10' FROM EA. END. 1 CENTRALIZER MID TUBE ON FLT COLLAR JT. 1 EVERY OTHER JT ON FIRST 15 JTS RAN, 5 CENTRALIZERS BELOW ESC AND 5 CENTRALIZERS ABOVE ESC ON FIVE JTS. 22 CENTRALIZERS TOTAL. CEMENTING REPORT Shoe @ 8816 FC @ 8,773.00 Top of Liner 33.6 Preflush (Spacer) Type: Tuned 11 Density (ppg) 11 Volume pumped (BBLs) 53 Lead Slurry Type: ExtendaCem Sacks: 940 Yield: 2.44 Density (ppg) 11.7 Volume pumped (BBLs) 408 Mixing / Pumping Rate (bpm): 5 Tail Slurry w Type: SwiftCem Sacks: 390 Yield: 115 FDensity (ppg) 15.8 Volume pumped (BBLs) 76 Mixing / Pumping Rate (bpm): 5 ur Post Flush (Spacer) w Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual / calculated): 658/658 FCP (psi): 1190 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1660 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? X Yes _ No Spacer returns? X Yes _ No Vol to Surf: 7� Cement In Place At: 23:08 Date: 6/1/2016 Estimated TOC: 3,000 Method Used To Determine TOC: ES Cmt Tool Stage Collar @ 3000 Type Haliburton ES Cmt Casing (Or Liner) Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top SHOE 95/8 Sacks: 405 Yield: 3.15 TCII DHP 2.90 8,819.00 8,816.10 1 1T 95/8 40.0 L-80 TCII 41.28 8,816.10 8,774.82 Volume pumped (BBLs) FLT COLLAR 95/8 Post Flush (Spacer) TCII DHP 1.96 8,774.82 8,772.86 2 1T 95/8 40.0 L-80 TCII 37.42 8,772.86 8,735.44 CROSSOVER 95/8 40.0 L-80 TCII X DWC 5.70 8,735.44 8,729.75 Yes _No Spacer returns? BAFFLE 95/8 Cement In Place At: 11:27 Date: 6/1/2016 DWC/C 1.83 8,729.75 8,727.92 143 1T 95/8 40.0 L-80 DWC/C 5,724.70 8,727.92 3,003.24 ES CEMENTER 95/8 DWC/C 3.11 3,003.24 3,000.13 17 217 1T 95/8 47.0 L-80 DWC/C2,973.97 3,000.13 34.00 Csg Wt. On Hook: 275,000 Type Float Collar: DHP No. Hrs to Run: 27 Csg Wt. On Slips: 125,000 Type of Shoe: DHP Casing Crew: DOYON Rotate Csg Yes X No Recip Csg X Yes No 15 Ft. Min. 9.3 PPG Fluid Description: SPUD MUD Liner hanger Info (Make/Model): CASING SLIPS Liner top Packer?: _Yes X No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 2 CENTRALIZERS ON SHOE JT 10' FROM EA. END. 1 CENTRALIZER MID TUBE ON FLT COLLAR JT. 1 EVERY OTHER JT ON FIRST 15 JTS RAN, 5 CENTRALIZERS BELOW ESC AND 5 CENTRALIZERS ABOVE ESC ON FIVE JTS. 22 CENTRALIZERS TOTAL. CEMENTING REPORT Shoe @ 8816 FC @ 8,773.00 Top of Liner 33.6 Preflush (Spacer) Type: Tuned 11 Density (ppg) 11 Volume pumped (BBLs) 53 Lead Slurry Type: ExtendaCem Sacks: 940 Yield: 2.44 Density (ppg) 11.7 Volume pumped (BBLs) 408 Mixing / Pumping Rate (bpm): 5 Tail Slurry w Type: SwiftCem Sacks: 390 Yield: 115 FDensity (ppg) 15.8 Volume pumped (BBLs) 76 Mixing / Pumping Rate (bpm): 5 ur Post Flush (Spacer) w Type: Density (ppg) Rate (bpm): Volume: LL Displacement: Type: Spud Mud Density (ppg) 9.3 Rate (bpm): 6 Volume (actual / calculated): 658/658 FCP (psi): 1190 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1660 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? X Yes _ No Spacer returns? X Yes _ No Vol to Surf: 7� Cement In Place At: 23:08 Date: 6/1/2016 Estimated TOC: 3,000 Method Used To Determine TOC: ES Cmt Tool www.wellez.net WellEz Information Management LLC ver 051316bf Stage Collar @ 3000 Type Haliburton ES Cmt Closure OK Yes Preflush (Spacer) Type: Tuned spacer III Density (ppg) 11 Volume pumped (BBLs) 60 Lead Slurry Type: Permafrost L Sacks: 405 Yield: 3.15 Density (ppg) 11.1 Volume pumped (BBLs) 315 Mixing / Pumping Rate (bpm): 5 Tail Slurry cw9 Type: Swiftchem Sacks: 287 Yield: 1.16 y Density (ppg) 15.8 Volume pumped (BBLs) 56 Mixing / Pumping Rate (bpm): 5 Z Post Flush (Spacer) u Type: Density (ppg) Rate (bpm): Volume: vi Displacement: Type: H2O Density (ppg) 8.3 Rate (bpm): 6 Volume (actual / calculated): 244/244 FCP (psi): 740 Pump used for disp: rig Bump Plug? X Yes No Bump press 1600 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? X Yes _No Spacer returns? X Yes _ No Vol to Surf: 69 Cement In Place At: 11:27 Date: 6/1/2016 Estimated TOC: Surface Method Used To Determine TOC: Visual www.wellez.net WellEz Information Management LLC ver 051316bf 11 RECEIVED liilrnrp Ahtrkm.1.1k, J U N 16 L 11 i U AOGC Date: 6/14/2016 215157 Maile Sweigart 27 3 07 Alaska North Slope Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Ste 1400 1 Anchorage, Alaska 99503 Office: 907.777.8473 msweigart@hilcorp.com To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DGR-EWR-ADR-ROP-HORIZONTAL PRES 2IN MD, DGR-EWR-ADR-INV/REV 21N TVD E log data CD 1 : Final Well Data Name Cate modified Type Files Currently on the Disc (7) CGM 6./8x'20169:29A.M Filefalder Definitive Survey 6,M/2016 4:29 AM File folder EMF 6x'8/°21169:29 AM File folder Geosteering Data 6/8/21316 9:29 AM FilefcIder LAS 6/8x'2116 9:29 AM File folder PDF (V8/20164:29 AM File folder TIFF 6:,`8,/21164:29A1`0 File folder DATA LOGGED (p U 120700 K BENDER Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: . A _ A s , v, I Date: THE STATE 01ALASKA GOVERNOR BILL WALKER Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Alaskaand .' xser—yativi Co -fit 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 J-28 Hilcorp Alaska, LLC Permit No: 215-157 Surface Location: 2209' FSL, 3132' FEL, Sec. 28, TI 3N, RI OE, UM, AK Bottomhole Location: 2159' FSL, 1671' FWL, Sec. 30, T13N, R10E, UM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P. oerster Chair DATED this 3Z d y of September, 2015. STATE OF ALASKA AL :A OIL AND GAS CONSERVATION COMM.. JN PERMIT TO DRILL 20 AAC 25.005 RFC;EIVED SEP 0 2 2015 A,OGOC 1 a. Type of Work: 1b. Proposed Well Class: Development -Oil M Service - Winj ❑ Single Zone ❑✓ 1 c. Specify if well is proposed for: Drill ❑I Lateral ❑ Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑ Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 , MPU J-28 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage AK 99503 MD: 12,725' • TVD: 3,556' Milne Point Unit Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 2209' FSL, 3132' FEL, Sec 28, T1 3N, RI OE, UM, AK (SHL) ADL 025906 / (TPH/BHL) ADL 025517 i AJ,6 t> P I,& Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1953' FSL, 641' FWL, Sec 29, TI 3N, R1 OE, UM, AK N/A 11/15/2015 Total Depth: 3o �jb 9. Acres in Propertv: 14. Distance to Nearest Propertv: 2159' FSL, 1671' FWL, Sec, T13N, R10E, UM, AK 5115 Acres • 5890' to Unit Boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 65 feet 15. Distance to Nearest Well Open Surface: x-552189.84 y- 6014608.14 Zone -4 GL Elevation above MSL: 35 feet to Same Pool: —1,100' from J -23A 16. Deviated wells: Kickoff depth: a 280 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: 1609 psi , Surface: 1250 psi 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 20" 78.6# A-53 Weld 80' 0 0 110' 110' 60 bbls 15.6 ppg permafrost -C Stg 1 Lead - 2159 ft3 / Tail - 445 ft3 12-1/4" 9-5/8" 40# L-80 TC -II 8,500' 0 0 8,500' 3,597' Stg 2 Lead - 1660 ft3 / Tail - 314 ft3 ' 7-5/8" 29.7# L-80 VAM STL 8,400' 0 0 8,400' 3,593' Tieback Assembly x- 8-1/2" 4-1/2" 11.6# L-80 HYD 521 4,325' 1 8,400' 1 3,593' 12,725' 1 3,556' Cmntless Prod Lnr. w/ Wire Screens 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): 20. Attachments: Property Plat ❑✓ BOP Sketch Q Drilling Program Q Time v. Depth Plot ❑✓ Shallow Hazard Analysis El Diverter Sketch Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements❑✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Luke Keller Email Ikeller@hilcorp.com Printed Name uke Keller Title Drilling Engineer Signature Phone 907-777-8395 Date Commission Use Only Permit to Drill ` S ' API Number:Permit d2 Approval L 5 See cover letter for other Number: p2� 50- 6 — S —QCj —O() Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane gas hydrates, or gas contained in shales: Other: 3000 fa .S.- 30 e f Samples req'd: Yes ❑ No [✓� Mud log req'd: Yes ❑ No Q" HZS measures: Yes [}/� No ❑ Directional svy req'd: Yes [/] No ❑ Spacing exception req'd: Yes ❑ No [� Inclination -only svy req'd: Yes ❑ No [� APPROVED BY Approved by: COMMISSIONS THE COMMISSION 91 Date: Ckv (' I � - 0/ l� n R.M,f% 1.4AL I1r Submit Form and Form 10-40 (Revised 10/2012) 'vlftnths from the date of approval (0 C 25.005(g)) Attachments it Duplicate Hilcorp En -v Company 9/1/2015 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: MPJ -28 Permit to Drill Dear Commissioner, Luke Keller Hilcorp Alaska, LLC SEP 0 2 2015 Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027O j���1C/� Tel 907 777 8395 Email Ikeller@hilcorp.com J MPU J-28 is a grassroots ESP producer planned to be drilled in the Schrader Bluff NB sand. J-28 is part of a (4) well pilot program targeting the NB sand. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff NA sand. A lateral section will then be drilled. A wire wrapped screen liner will be run in the open hole section and the well produced with an ESP assembly. Drilling operations are expected to commence approximately Dec 7th, 2015. Nordic Calista Rig # 3 will be used to drill and complete the wellbore. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, Z6 Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of i Hilcorp Alaska, LLC Milne Point Unit (MPU) J-28 Drilling Program Version 1 August 27th, 2015 ff HilmTEnergy Company Contents Milne Point Drilling Procedure 1.0 Well Summary................................................................................................................................................2 2.0 Management of Change Information............................................................................................................3 Wellhead Schematic.....................................................................................................................................43 3.0 Tubular Program: .......................................................................................................................................... 4 4.0 Drill Pipe Information: .................................................................................................................................. 4 5.0 Internal Reporting Requirements.................................................................................................................5 Anticipated Drilling Hazards.......................................................................................................................46 6.0 Planned Wellbore Schematic.........................................................................................................................6 Nordic #3 Rig Layout (Drillers Side)..........................................................................................................48 7.0 Drilling / Completion Summary....................................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................................8 9.0 R/U and Preparatory Work.........................................................................................................................10 10.0 N/U 21-1/4112M Diverter System.................................................................................................................11 11.0 Drill 12-1/4" Hole Section............................................................................................................................14 12.0 Run 9-5/8" Surface Casing...........................................................................................................................18 13.0 Cement 9-5/8" Surface Casing.....................................................................................................................24 14.0 BOP N/U and Test........................................................................................................................................29 31.0 15.0 Drill 8-1/2" Hole Section..............................................................................................................................30 32.0 16.0 Run 5-1/2" Production Liner.......................................................................................................................34 33.0 17.0 Run ESP assy................................................................................................................................................39 34.0 18.0 RDMO...........................................................................................................................................................40 19.0 Diverter Schematic.......................................................................................................................................41 20.0 BOP Schematic.............................................................................................................................................42 21.0 Wellhead Schematic.....................................................................................................................................43 22.0 Days Vs Depth...............................................................................................................................................44 23.0 Formation Tops............................................................................................................................................45 24.0 Anticipated Drilling Hazards.......................................................................................................................46 25.0 Nordic #3 Rig Layout (Drillers Side)..........................................................................................................48 26.0 Nordic #3 Rig Layout (Well End & Top View)..........................................................................................49 27.0 FIT Procedure...............................................................................................................................................50 28.0 Choke Manifold Schematic..........................................................................................................................51 29.0 Casing Design Information..........................................................................................................................52 30.0 8-1/2" Hole Section MASP...........................................................................................................................53 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................................54 32.0 Surface Plat (As Built) (NAD 27)................................................................................................................55 33.0 Offset MW vs TVD Chart............................................................................................................................56 34.0 Drill Pipe Information 5" 19.5# 5-135 DS-50.............................................................................................57 0 Hilcorp Energy Company 1.0 Well Summary I Milne Point Unit Producer Drilling Procedure Well MPU J-28 Pad Milne Point "J" Pad Planned Completion Type ESP on 2-7/8" Production Tubing Target Reservoir(s) Schrader Bluff NB Sand Planned Well TD, MD / TVD 12,725' MD / 3,556' TVD PBTD, MD / TVD 12,720' MD / 3,556' TVD Surface Location (Governmental) 2209' FSL, 3132' FEL, Sec 28, T13N, R10E, UM, AK Surface Location (NAD 27) X=552189.84, Y=6014608.14 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 1953' FSL, 641' FWL, Sec 29, TON, R10E, UM, AK TPH Location (NAD 27) X=545406.13, Y=6014307.57 TPH Location (NAD 83) BHL (Governmental) 2159' FSL, 1671' FWL, Sec 30, TON, R10E, UM, AK BHL (NAD 27) X=541185.7, Y=6014489.3 BHL (NAD 83) AFE Number 1511627 AFE Drilling Das 12 days AFE Completion Das 4 days AFE Drilling Amount $3,567,142.00 AFE Completion Amount $2,540,500.00 AFE Facility Amount $381,000.00 Maximum Anticipated Pressure (Surface) 1250 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1609 psi Work String 5" 19.5# S-135 DS -50 (Weatherford Rental) KB Elevation above MSL: 30 ft + 35 ft = 65 ft GL Elevation above MSL: 35 ft BOP Equipment 11" x 5M Annular, (3) ea 11" x 5M Rams Page 2 Version 1 August, 2015 0 Hi1mTEnergy Company 2.0 Management of Change Information Milne Point Unit Producer Drilling Procedure 11 Hileorp Alaska, LLC UIC1 rP Changes to Approved Permit to Drill Date: 9-1-2015 Subject: Changes to Approved Permit to Drill for MPU J-28 File #: MPU J-28 Drilling and Completion Program Any modifications to MPU J-28 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by the AOGCC. Approval_ Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure HilmTEncW Company 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift in Conn OD in(#/ft) Wt Grade Conn Burst (psi) Collapse (psi) Tension (k -lbs) Cond 20" 19.25" - - 78.6 A-53 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 TC -Il 5,750 • 3,090 916 7-5/8" 6.82" 6.75" 7.711" 29.7 L-80 VAM sTL 6,890- 4,790 473 8-1/2" 4-1/2" 3.96 3.875 4.695 11.6 L-80 H52111 7780 " 6350. 267 4.0 Drill Pipe Information: Hole OD (in) Section ID (in) TJ H) in TJ OD in(#/ft) Wt Grade Conn M/U Min M/U Max(k-lbs) Tension All 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 August, 2015 5.0 Internal Reporting Requirements Milne Point Unit Producer Drilling Procedure 18.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to Gam • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. Ensure time entry adds up to 24 hours total. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 18.2 Afternoon Updates • Submit a short operations update each work day to pmazzolinighilcorp.com , lkellerghilcorp.com and cdingerAhilcorp.com 18.3 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. 18.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager & Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 18.5 Casing Tally • Send final "As -Run" Casing tally to Ikellerghilcorp.com and cdingerghilcorp.com 18.6 Casing and Cmt report • Send casing and cement report for each string of casing to Ikeller@hilcorp.com and cdingerghilcorp.com 18.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Luke Keller 907.777.8395 832.247.3785 Ikeller@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Keith Elliot 907.777.8355 832.233.5855 kelliott@hilcorp.com Drlg Environmental Coord Julieanna Orczewska 907.777.8444 907.715.7060 lorczewska@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com EHS Field Coordinator Jimmy Watson 907.777.8450 907.744.7376 jiwatson@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure HilmTEnergy Company 6.0 Planned Wellbore Schematic AFE No. VVee Name: KB: 30 ft AGL 1511627 Wirte Point Unit (MPU) J-28 GL + RKB 35 ft + 30 ft = 65 ft API # TED AFE VVELLBORE DESIGN Proposed TD: 12,725 Permit No, TBD Proposed TVD: 3,556' Geologic Information Wellbore Information Casing Info / Mud Info / Hole Size f Cement Specs RK8 -Tubing Hanger U. s "rO°_ S3 TVD FM LNhology Conductor 34" x 20" conductor (Pre-set) to 80' BGL (110' RKB)IMF rner[a_ ;" Sunxehae Surface Casing E 9-518" 40# L-80 TC -11 set at 8,500' MD 13,597' TVD Fresh W.L—Native W.lahl Range E 8 Surface Casing Cement 0.0.9.2 A 1st Stage: 5 60 MIS 10.5 ppg Tuned spacer III a Lead: (30% OH Excess) ARCTICCEM Q 10.7 ppg a m - Tail: (30% OH Excess) SWIFTCEM 15.8 ppg o M $ 2nd stage: 60 MIS 10.5 ppg Tuned spacer III Lead: (Until returns at surface) ARCTICCEM 10.7 ppg 1750' Tail SWIFTCEM 15-8 ppg Stage Collar k, Production Liner L m 4-112" Screens c/w base pipe: a �_ c a ,t. 11.6# L-60 Hydrll 521 screens @ 12,725' MD 13,558' TVD Y A Tieback 0 Y + D 7-518" 29.7# L-80 VAM STI 8400MD 13,593' TVD -C u ~ u Production Tubing 2-7f8" 6.4# L-80 ORD EUE 3*` a . _ 2 C � v Y c p ESC -3500' u i = Liner Top Packer Wire wrapped screen K-sands parse sand, silty production Liner hale, better \. ' Bullet Seal Asry irnM.m+y= UGNUveloped _ ~! Praducuon mole L -Sands ntenrening shales \, \ Mua Type: 4900' M -sands n the L and M ~` earaan6N N -sands ontinued layering as \ svr�gdtsanrm. Schrader n ugo�e ursed a e - 9 a cag with oa- 9-5/8" Shoe N15 Sip Page 6 Version 1 August, 2015 0 Hilcorp Energy Company 7.0 Drilling / Completion Summary Milne Point Unit Producer Drilling Procedure MPU J-28 is a grassroots ESP producer planned to be drilled in the Schrader Bluff_ NB sand. J-28 is part of a (4) well pilot program targeting the NB sand. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff NA sand. A lateral section will then be drilled. A wire wrapped screen liner will be run in the open hole section and the well produced with an ESP assembly. Drilling operations are expected to commence approximately Dec 7th, 2015. Nordic Calista Rig # 3 will be used to drill and complete the wellbore. Surface casing will be run to 8,500' MD / 3,597' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point "A" pad G&I facility. General sequence of operations: 1. MOB Nordic Rig #3 to well site. 2. N/U 21-1/4" conductor and 16" diverter line. 3. Drill 12-1/4" hole to TD of surface hole section. Run and cmt 9-5/8" surface casing. 4. N/D diverter, N/U & test 11" x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 5-1/2" slotted liner. 6. Run 7-5/8" Tieback. 7. Run ESP assy. 8. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res f 2. Production Hole: No mud logging. On site geologist. LWD. GR + ADR (For geo-steering) Page 7 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU J-28. 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, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Version 1 August, 2015 HilmTEnema Company Milne Point Unit Producer Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12-1/4" • 21-1/4" 2M diverter w/ 16" diverter line Function Test Only • 11" x 5M Hydril Annular BOP • 11" x 5M Shaffer Double Ram Initial Test: 250/3000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/ 3" x 5M side outlets 8-1/2" 11" x 5M Hydril Single Ram • 3" x 5M Choke Line Subsequent Tests: • 3" x 5M Kill line 250/3000 • 3" x 5M Choke manifold (1 OM Hydraulic remote Choke (Annular 2500 psi) • Standpipe, floor valves, etc Primary closing unit: Hydril, 165 gal, 6 station accumulator w/ dual electric and air pumps, w/ 1 (ea) electric over hydraulic remote control panel at the driller station. • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Tertiary pressure is provided by air pumps. 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.regga@alaska.gov Guy Schwartz / Petroleum Engineer/ (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartzgalaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria. loeppgalaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectorskalaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/fonns/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Enerp Company 9.0 R/U and Preparatory Work 9.1 20" conductor has been preset at 80' BGL (110' RKB). 9.2 Dig out and set impermeable cellar. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.5 Insure (2) 3" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack -off. 9.6 Level pad and ensure enough room for layout of rig footprint and R/U. 9.7 Rig mat over footprint of rig. 9.8 Confirm that the rig is over the appropriate well slot. 9.9 MIRU Nordic #3. 9.10 Mud loggers WILL NOT be used on either hole section. 9.11 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 9.12 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.13 Install 5-1/2" liners in mud pumps. • Continental EMSCO F-1000 mud pumps are rated at 3500 psi (100%) / 354 gpm (120 spm @ 95% eff) with 5-1/2" liners. Page 10 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilm7Energy Company 10.0 N/U 21-1/4" 2M Diverter System 10.1 N/TJ 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic at Sec 18 at back of program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/tJ 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 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set 15.375" ID wearbushing in wellhead. Page 11 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company Page 12 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company Page 13 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure Gyro MWD is R/U and operational. Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 12-1/4" BHA (GR + Res LWD and PWD planned in surface hole): COMPONENT 1 HALLIBURTON OD (in) 8.000 (in) 3.000 WELL INFORMATION Connection 1 P 6-518" REG Created On: t 12015 BHA Tally Customer Well Name MPS Engergy Drilistring Job Number -XX- 31.47 Rig Name Nordic 3 [ADC Rig BHA# Field Name Milne Paint Run# 100 Country : USA COMPONENT 1 DATA Description PDC OD (in) 8.000 (in) 3.000 (in) (tbpfy 12.250 147.22 Connection 1 P 6-518" REG (fill 1.10 Length (ft) 1.10 2 8" SperryDrill Lobe 415 - 5.3 stg 8.000 5.000 103.09 B 6-518" REG 31.47 32.57 Stabilizer 12.125 3 Float Sub 8.000 2.880 149.10 B 6-518" REG 2.40 34.97 4 Stabilizer 8.000 3.000 10250 147.22 B 6-518" REG 6.00 40.97 5 8" DM Collar 8.000 3.500 1 147.40 B 6-518" REG 9.20 50.17 6 8" DGR Collar 8.000 1.820 1 142.70 B 6-518" REG 4.55 54.72 7 8" EWR-P4 Collar 8.000 1.985 151.00 B 6-518" REG 12.19 66.91 8 8" HCIM Collar 8.000 1.920 149.90 B 6-518" REG 4.97 71.88 9 8" POS PULSER 8.000 4.000 145.20 B 6-518" REG 15.44 87.32 10 Orienting Sub UBHO 8.000 2.875 149.18 B 6-518" REG 2.50 89.82 11 NM Flex Collar 8.000 2.813 150.13 B 6-518" REG 31.00 120.82 12 NM Flex Collar 8.000 2.813 150.13 B 6-518" REG 31.00 151.82 13 NM Flex Collar 8.000 2.813 150.12 B 6-518" REG 31.00 182.82 14 80 x 5"X 3' HWDP 949.3 - NC50(IF) 5.000 3.000 49.30 240.00 422.82 15 Jar 7.500 2.813 129.38 B 4-112" IF 35.00 457.82 16 12jts x 5" X 3" HWDP #49.3 - NC50 5.000 3.000 49.30 360.00 817.82 j� 617.82 I Page 14 Version 1 August, 2015 i� 0 Hilcorp EneW Company 11.3 11.4 Primary Bit: PRODUCT SPECIFICATIONS IADC Code 117W Total Tooth Count 67 Gage Row Tooth Count 39 Journal Angle 33` Offset (L`16") 6 Jet Nozzle Types Standard 83241 Extended 302411 Center Jet (if Center Jetted) 501813 T.J. Connection 6-5i8" (API Reg.) Recommended Make -Up Torque; 28000/32000 Ft*lbs. Bit Weight (Boxed) 250 Lbs. (113 Kg.) Bit Breaker (Mat.#iLegacy0) 5153531506463 PRODUCT FEATURES . New patented Diamondim C1aw,R tooth bit design. . Tungsten carbide 'surf inserts in gage teeth for added gage protection. • Newly formulated, proprietary hardfacing on cutting structure and gage maximizes carbide and diamond volume for ultimate wear resistance. • Raised tungsten carbide inserts and proprietary hardfacing provides maximum arm protection in abrasive and directional applications while minimizing drill string torque. . QuadPackk Plus Series incorporates its successful "longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. . Centerjet feature to prevent bit balling problems • Dual seal dual compensation bearing system containing dual seals, dual independent pressure compensators, and a dual grease formulation. • The latest OCP seal technology designed with the highest contact pressures on the outside edges of the seal where it is needed most, helps keep contaminants out extending bearing life. Milne Point Unit Producer Drilling Procedure Material #740990 'Calculations based on recommendations from API and tool joint manufaclurers. C'- 2014 Halliburton. All rights reserved. Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. 5" Workstring, HWDP, and Jars will come from Weatherford. 11.5 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 11.6 Drill 12-1/4" hole section to 8,500' MD / 3,597' TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. r 09 Page 15 Version 1 August, 2015 Hilcorp Energy Company Milne Point Unit Producer Drilling Procedure • 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. ESP equipment can be damaged if run through high dog legs. 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 600 - 650 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Ensure to leave a "Pump Tangent" section that is approx. 300' long in the directional plan. The ESP will need a straight section to sit. This will occur very near TD of the hole section. • Make wiper trips every 2000' unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section just into the target sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. • Take MWD surveys every stand drilled (60' intervals). • Watch returns closely for signs of gas when near the base of the permafrost and circulate out all gas cut mud before continuing to drill. There have been no indications of hydrates on any of the "L" pad wells to date. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. Page 16 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 11.7 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.88Dpg. • 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. • 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: Depths DensityViscosi Fresh Water Plastic ViscosityYield Point API FL H 80-8,500' 8.8 — :2 85-250 1 20-40 25-75 <10 85-9.0 Page 17 System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 — 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 — 9.2 ppg PAC -L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Enew Company 11.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 20" conductor shoe. 11.9 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 — 4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (600 — 700 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.10 TOH with the drilling assy, handle BHA as appropriate. 11.11 No open hole logging program planned. 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull 15.375" wearbushing. 12.2 Make a dummy run with the 9-5/8" casing hanger. 12.3 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" TC -II x DS50 XO on rig floor and M/U to FOSV. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.4 P/U shoe joint, visually verify no debris inside joint. 12.5 Continue M/U & thread locking shoe track assy consisting of. • (1) Shoe joint w/ float shoe bucked on (thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end & thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Page 18 Version 1 August, 2015 Hilcorp Energy Company This end up. Bypass Baffle Milne Point Unit Producer Drilling Procedure • (1) Joint with Halliburton bypass baffle adapter bucked on pin & threadlocked. Install (1) centralizer mid tube over a stop collar. Page 19 Ensure proper operation of float equipment while picking up. Ensure to record S/N's of all float equipment and stage tool components. Version 1 August, 2015 Hilcorp Energy Company 12.6 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No. Closing Sleeve No. Shear Pins Opening Sleeve No, Shear Pins ES Cementer Depth Baffle Adapter (ii used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth ATFloat Shoe Depth Hole TD "Reference Casing Sales Manual section 5 "A Overall Length B Men. ID After Drillout C Max. Tool OD D Opening Seat ID E Closing Seat ID Plug Set Part No. SO No. Closing Plug OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD Milne Point Unit Producer Drilling Procedure Page 20 Version 1 August, 2015 Hikorp ESTI Running Order ES4I Cementer SIVA Off Plug Baffle Adapter By-pass plug �r lI By pass Balfle Float [ogar Float Shoe Page 20 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 12.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use Jet Lube Seal or BOL 72733 thread compound. Dope pin end only w/ paint brush. • Install (1) centralizer every other joint for the first 15 joints. • 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 cmt returns to surface. 12.8 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below the permafrost., �,, o • Install centralizers over couplings onl points below and 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. There are 6 holes, the tool is normally sent with only 4 pins installed. This will allow the tool to open at 3300 psi. 9-5/8" 40# L-80 TC -II Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 11,600 ft -lbs 13,600 ft -lbs Page 21 Version 1 August, 2015 Technical Specifications Connection Type: Size(O.D.): Weight (wall): TC -II Casing 9-5/8 in 40.00 lb/ft (0.395 in) standard Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 9.625 Nominal Pipe Body O.D. (in) 8.835 Nominal Pipe Body I.D.(in) 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight (lbs/ft) 38.97 Plain End Weight (lbs !ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Performance Properties 916,000 (1) Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 916,000 Compression Rating (lbs) 3,090 Collapse Pressure Rating (psi) 5,750 Internal Pressure Rating (psi) 38.1 Maximum uniaxial bend rating [degrees/100 ft] Recommended Torque Values 11,600 (2) Minimum Final Torque (ft -lbs) 13,600 (2) Maximum Final Torque (ft -lbs) Milne Point Unit Producer Drilling Procedure Grade: L-80 IAM L1 S A VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Housion, TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail. VAlMUSAsale>avam-use.com Page 22 Version 1 August, 2015 Connection Dimensions 10.235 Connection Q.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter (in) 5.23 Make-up Loss (in) Connection Performance Properties 916,000 (1) Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 916,000 Compression Rating (lbs) 3,090 Collapse Pressure Rating (psi) 5,750 Internal Pressure Rating (psi) 38.1 Maximum uniaxial bend rating [degrees/100 ft] Recommended Torque Values 11,600 (2) Minimum Final Torque (ft -lbs) 13,600 (2) Maximum Final Torque (ft -lbs) Milne Point Unit Producer Drilling Procedure Grade: L-80 IAM L1 S A VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Housion, TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail. VAlMUSAsale>avam-use.com Page 22 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 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 casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.12 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.13 Have emergency slips ready to go in the event we can not land the hanger. 12.14 R/U circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 12.15 After circulating, lower string and land hanger in wellhead again. Page 23 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 13.0 Cement 9-5/8" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. 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 cmt pump or treating iron will not be pumped downhole. 13.4 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 13.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug). Mix and pump cmt per below recipe for the 1 St stage. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 12-1/4" OH x 9-5/8" Casing (7,500'- 2200') x.0558 bpf x 1.3 = 384 bbls 2159 ft3 annulus: Total LEAD: 384 bbls 2159 ft3 12-1/4" OH x 9-5/8" Casing (8500'- 7500') x.0558 bpf x 1.3 = 72.5 bbls 407.3 ft3 annulus: 9-5/8" Shoe track: 90 x .0758 bpf = 6.8 38.3 Total TAIL: 79.3 bbl 445 ft3 Page 24 Version 1 August, 2015 Hi1COIp Energy Company Cement Slurry Design: Milne Point Unit Producer Drilling Procedure 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 13.10 Ensure cement unit is used to displace curt so that volume tracking is more accurate. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: W 8400' x .0758 bpf = 430 bbls mud, 80 bbls water, 127 bbls mud The 80 bbl, of water must be left across stage tool to ensure proper operation once opened. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. Page 25 Version 1 August, 2015 Lead Slurry Tail Slurry System ArcticCEM T"" System SwiftCEM TM System Density 10.7 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. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 13.10 Ensure cement unit is used to displace curt so that volume tracking is more accurate. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: W 8400' x .0758 bpf = 430 bbls mud, 80 bbls water, 127 bbls mud The 80 bbl, of water must be left across stage tool to ensure proper operation once opened. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. Page 25 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 13.13 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. We will over displace first before doing this. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 Increase pressure to 2700 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.16 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 26 Version 1 August, 2015 Hilcorp Energy Company Second Stage: Milne Point Unit Producer Drilling Procedure 13.17 Prepare for the 2nd stage as necessary. Hold another pre job meeting if crew change has occurred. 13.18 Load ES cementer closing plug in cmt head. 13.19 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 13.20 Pump remaining 55 bbls 10.5 ppg tuned spacer. 13.21 Mix and pump cmt per below recipe for the 2nd stage. 13.22 Cement volume based on annular volume + 200% open hole excess. Job will consist of lead & tail, TOC brought to surface. However cmt wi c'tI onti e—to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 20" Conductor x 9-5/8" casing annulus: (110') x.27 bpf x 1 = 29.7 bbls 167 0 12-1/4" OH x 9-5/8" Casing annulus: (1700'- 110') x.0558 bpf x 3 = 266 bbls 1495 ft3 Total LEAD: 295.7 bbls 1660 ft3 12-1/4" OH x 9-5/8" Casing annulus: (2200'- 1600') x.0558 bpf x 2 = 56 314 ft3 Total TAIL: 56 bbls 314 ft3 13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.25 Displacement calculation: 2200' x.0758 bpf = 167 bbls mud �S g `5t1 Page 27 Version 1 August, 2015 ,2 Zz s Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.27 Decide ahead of time what will be done with cmt returns once they are at surface. We should get back approx. 150 bbls of cmt slurry. 13.28 Land closing plug on stage collar and pressure up to 1500 psi above final circulating pressure to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Back out and L/D landing joint. Flush out wellhead with FW. 13.29 M/U pack -off running tool and pack -off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.30 Lay down landing joint and pack -off running tool. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run "casing tally & casing and cement report to lkellerghilcorp. com and cdinger(aAhilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 28 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Enema company 14.0 BOP N/U and Test 14.1 N/D the diverter. 14.2 N/U Seaboard tubing spool. Install pack -off 9-5/8" P -seals. Test to 3000 psi. 14.3 N/U 11" x 5M BOP as follows: • BOP configuration from Top down: 11" x 5M Hydril annular BOP/11" x 5M Shaffer double ram /11" x 5M mud cross/11" x 5M Hydril single ram • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8" x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest tc mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 5" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.8 Set 10" ID wearbushing in wellhead. 14.9 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Install 5" liners in mud pumps. Page 29 Version 1 August, 2015 All Milne Point Unit Producer Drilling Procedure Hilcorp En -V Company 15.0 Drill 8-1/2" Hole Section 15.1 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. • Workstring will be 5" 19.5# S-135. • Run a ported float in the surface hole section. 15.2 8-1/2" BHA (Includes GR+Res+ADR LWD components & PWD):' COMPONENTOATA ROM 0 1 Description serial Number HDBS - FX650 •, (in) 8.400 to (in) 2.500 Gauge (in) 8.500 Weight (ibpf) 172.13 Top Connection P 4-112" REG Length (ft) 1.00 Cumulative Length (ft) 1.00 2 7" SperryDrill Lobe 718 - 6.0 stg 7.000 4.952 93.13 B 4-112" IF 27.38 28.38 Stabilizer 7.750 3 Non Mag Float Sub 6.750 2.750 101.71 B 4-112" IF 3.00 31.38 4 Integral Blade Stabilizer (NM) 6.750 2.813 8.375 100.77 B 4-112' IF 5.00 36.38 5 6 314" DM (Directional) 6.750 3.125 103.40 B 4-112' IF 9.20 45.58 6 6 314" DGR (Gamma) 6.750 1.920 97.80 B 4-112" IF 4.55 50.14 7 6 314' EWR-P4 (Resistivity) 6.750 2.000 104.30 B 4-1;2' IF 12.10 62.24 8 6 314' HC IM (Processor) 6.750 1.920 101.70 8 4-112" IF 4.97 67.21 9 6 314" ALD Collar 175C 30KSI 6.750 1.920 8.250 104.30 P NC 50 14.54 81.75 Stabilizer 8.250 10 6 314' CTN Collar 175C 30KS1 6.750 1.905 102.30 B NC 50 11.84 93.59 11 6 314" TM - HOC (Pulser) 6.900 3.250 103.60 B 4-112" IF 15.59 109.18 12 6-314' Non Mag Flex Drill Collar 6.750 2.813 100.77 B 4-1/2" IF 30.00 139.18 13 6-314" Non Mag Flex Drill Collar 6.750 2.813 100.77 B 4-112" IF 30.00 169.18 14 X -O 4-112" COS 40 Box X 4-112" IF Pin 6.500 2.750 92.85 1 B 4.5" CDS 40 2.75 171_93 15 6 Joints 4-112' CDS 40 HWDP 4.500 2.500 37.47 180.00 351.93 16 X -O 4-112' IF Box X 4-112" CDS 40 Pin 6.500 2.750 92.85 B 4-112" IF 2.75 354.58 17 Weatherford 6-1 4" Jars 6.250 2.250 91.01 B 4-112" IF 30.00 384.68 18 X -O 4-1@' IF Pin X 4-112"CDS 40 Box 6.500 2.750 92.85 B 4.5" CDS 40 2.75 387.43 19 19 Joints 4-112' CDS 40 HWDP 4.500 2.500 37.47 570.00 957.43 Bit Number . Nozzles : 503 Bit Size (in) : 8.500 TFA (int) : 0.6481 Manufacturer Dull Grade In Model Dull Grade Out Serial Number Page 30 Version 1 August, 2015 0 Hilcorp Energy Company 15.3 Primary Bit: PRODUCT SPECIFICATIONS Cutter Type X2 - Tough Drilling IADC Code 5424 Body Type STEEL Total Cutter Count 29 Cutter Distribution 13mm 19mm Face 0 19 Gauge 10 0 Number of Large Nozzles 5 Number of Medium Nozzles 0 Number of Small Nozzles 0 Number of Micro Nozzles 0 Number of Ports (Size) 0 Number of Replaceable Ports (Size) 0 Junk Slot Area (sq in) 20.81 Normalized Face Volume 73.86% API Connection 4-1/2 LF. PIN Recommended Make -Up Torque' 23.743 Ft"lbs. Nominal Dimensions" Make -Up Face to Nose 8.31 in - 211 mm Gauge Length 3 in - 76 mm Sleeve Length 0 in - 0 mm Shank Diameter 6.688 in - 170 mm Break Out Plate (Mat.#/Legacy#) 181960?44073 Approximate Shipping Weight 120Lbs. - 541(g. SPECIAL FEATURES Anti -Balling Coating, Short Shank, EDL Tool Specific Gage -084" Dia Step, .126" Dia Step Milne Point Unit Producer Drilling Procedure Material #761417 L Page 31 Version 1 August, 2015 0 Hilcorp Energy Company 15.4 8-1/2" hole section mud program summary: Milne Point Unit Producer Drilling Procedure • 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 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 water or low vis sweeps. • 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 — 9.2 ppg Baradrill-N drilling fluid / Properties: De the Density Plastic Viscosity Yield Point Total Solids MBT HPHT 8500 - 12725 8.9-9.2 15-25 15-25 <10% <7 <1 1.0 System Formulation: Baradrill-N Product ConcentrationNunction Water Base Fluid Busan 1060 0.4 ppb Biocide Soda Ash 0.25 ppb PH/Hardness Control Flowzan 1.0 ppb Viscosifier/Rheology KCL 21.8 ppb weight/inhibition NaCl Salt 20.Oppb weightrnhibition Poly Pac Sup UL 0.75 ppb API Fluid Loss EMI -2009 2-3% v/v Clay/Shale inhibitor Safe-Carb 40 If needed for weight increase over Conqor 404 9.Oppg Asphasol Supreme Corrosion Mitigation Sack Black 4ppb Shale/Coal Stabilizer 3 b-Gilsonite Shale/Coal Stabilizer Page 32 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 15.5 TIH w/ 8-1/2" directional assy to stage tool. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. Drill out stage tool as follows: • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Because of aggressive nature of PDC bits, drilling with minimal WOB is recommended. Approx 2-5 k is enough. • Apply weight and allow it to drill off before applying more. • After drilling out, chase any remaining debris to bottom with the drill bit. 15.6 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.7 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = —3500 psi, but max test pressure on the well is 3,000 psi. 15.8 Drill out shoe track and 20' of new formation. 15.9 CBU and condition mud for FIT. f t� 15.10 Conduct FIT to 12 ppg EMW. 15.11 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Pump at 500 - 550 gpm. • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump water or other low vis sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips every 1500 — 2000 ft if necessary. • Take MWD surveys every other stand drld. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Ideally, we would like to stay in section 100% of the time and DO NOT want to serpentine between the upper and lower lobes. 15.12 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 33 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 15.13 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the 9-5/8" shoe. If backreaming is necessary: • Circulate at full drill rate (500 — 550 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 15.14 TOH with the drilling assy, stand back BHA if possible. Rabbit DP on TOH. 15.15 No open hole logs are planned for the production hole section. 16.0 Run 4-1/2" Wire Wrapped Screen Production Liner 16.1. A ram change to 4-1/2" screen is not necessary. In the event of a well control situation, the screen assy will be crossed over to 5" DP to position a joint of 5" DP across the BOP stack. 0 ��✓ Then the well can be safely shut in. If there is not enough time to accomplish this, the screen assy will be dropped and well closed in on the blind rams. 16.2. R/U 4-1/2" screen running equipment. • Ensure 4-1/2" Hydril 521 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.3. Run 4-1/2" screen production liner. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound and can plug the screens. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install swell packers as per guidance from Operations Engineer. • Ensure all plastic packing is removed from element. • Do not place tongs or slips on element. • Run packoff and float shoe on bottom. 4-1/2" Hydril 521 torques Casing OD Minimum Maximum Yield Torque 4.5" 3,600 ft -lbs 4,300 ft -lbs 6,300 ft -lbs Page 34 Version 1 August, 2015 Hilcorp Energy Company Milne Point Unit Producer Drilling Procedure Technical Data Sheet EXCLUDER2000TM Premium Standalone Screen Page 35 X 1 Base Pipe 2 End Ring A 3 Shroud 4 Weave 5 Screen Jacket End Ring 2 End Ring 3 Shroud 4 Weave 5 screen Jacket End Ring B Y Material Number H486900063 Base Pipe Size 4-112" Base Pipe Weight 11.6lbift Base Pipe Grade L80 Base Pipe Length API R3 (Min 37ft) (C) Thread Down (Y) BTC Pin Thread Up (X) BTC Box Pore Size Medium 200 pm<d10<300pm Max OD (A) 5.310" Min ID (B) 4.000" Nam_ (3.875" Drift) Upper Handling 48" Length Lower Handling 38" (minimum) Length Number of 318" Total 1638 (approx.) / 78 Holes/ft Base Pipe Holes Dual Filter 16ft each 132ft total Cartridge Length Version 1 August, 2015 Hilcorp Energy Company TenarisHydril Connection: Wedge 5217`"' Casing/Tubing: TUB Milne Point Unit Producer Drilling Procedure Size: 4.500 in. Wall: 0.250 in. Weight: 11.60 lbs/ft Grade: L80.1 Min. Wall Thickness: 87.5 % TORQUES Minimum 3600 ft -lbs Optimum 4300 ft- Ilas Maximum i`--� 6300 ft -lbs OPERATIONAL LIMIT TORQUES Operating Torque 10200 ft -lbs I Yield Torque 15300 ft -lbs Page 36 Version 1 August, 2015 Connection OD Standard Drift Nominal OD 4.500 in. Nominal Weight 11.60 lbs/ft 3.875 in. Critical Section Diameter Special Drift Nominal ID 4.000 in, Wall Thickness 0.250 in. N/A Threads Perin. 3.36 Diameter Plain End Weight 11.36 lbs/ft Area PERFORMANCE Body Yield 267 x 1000 PERFORMANCE Internal Yield 7780 psi SMYS 80000 psi Strength lbs Collapse 6350 psi TORQUES Minimum 3600 ft -lbs Optimum 4300 ft- Ilas Maximum i`--� 6300 ft -lbs OPERATIONAL LIMIT TORQUES Operating Torque 10200 ft -lbs I Yield Torque 15300 ft -lbs Page 36 Version 1 August, 2015 Connection OD 4.645 in, Connection ID 3.460 in. Make -Up Loss 3.620 in. Critical Section 2.141 sq. in. Threads Perin. 3.36 Area PERFORMANCE Internal 171 x 1000 Tension Efficiency 64.2 Rt Joint Yield Strength Pressure 7780 psi lbs Capacity Compression 226 x1000 Compression 84.8 1& Bending 52 0/100 ft Strength lbs Efficiency External Pressure 6350 psi Capacity TORQUES Minimum 3600 ft -lbs Optimum 4300 ft- Ilas Maximum i`--� 6300 ft -lbs OPERATIONAL LIMIT TORQUES Operating Torque 10200 ft -lbs I Yield Torque 15300 ft -lbs Page 36 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 16.7. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. If inner string is to be run, R/U false rotary and run inner string at this time. 16.9. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.10. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/ liner on DP no faster than 1-1/2 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.12. DP should autofill. 16.13. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.18. Rig up to pump down the work string with the rig pumps. 16.19. 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. 16.20. Pressure up to 3000 psi and hold for 5-15 minutes to set SLZXP hanger packer. Continue pressuring up in 500 psi increments holding for 5 min each up to 4000 psi. Page 37 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 16.21. Bleed DP pressure to zero, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.22. Bleed off pressure and pickup to verify that the HRD setting tool has released. If packer did not test, rotating dob sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. P/U above liner top packer and displace well to 8.9 ppg completion fluid. 16.24. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 16.25. RIH w/ remaining DP out of derrick and L/D same. 17.0 Run 7-5/8" Tieback 17.1 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie -back space out calculation. Install and test 7-5/8" casing rams in top ram. 17.2 R/U 7-5/8" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. • Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. 17.3 P/U tieback seal assy and set in rotary. M/U ported collar to top of tieback seal assy, then crossover to 7-5/8". Note that tieback seal assy and ported collar are 7". 17.4 M/U first joint of 7-5/8" to seal assy. 17.5 Run 7-5/8" tieback to position seal assy two joints above tieback sleeve. Record up & down weights. • Following running procedure outlined above. • Install ported collar so it is positioned at 2500' MD when landed out. 17.6 M/tJ 7-5/8" to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assy entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. Page 38 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 17.10 Continue lowering string and land out on no-go. Set down 5 — l Ok lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 P/U string & stand back DP stand, L/D XO. Note P/tJ weight on morning report. 17.12 M/U (or L/D) necessary joints and pup joints to position seal assy 1 ft above "NO-GO DEPTH" when tie -back hanger lands out in wellhead. 17.13 P/U hanger assy and landing joint. Slack off and land hanger. 17.14 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.15 Run in hanger lock downs. 17.16 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. Test void to 3000 psi / 10 min. 17.17 R/D casing running tools. 17.18 Run in hole with 2-7/8" tubing and ported collar opening tool. Shift open ported collar at 8100'. Spot diesel freeze protection from 2500' to surface in 7-5/8" x 9-5/8" annulus. 17.19 Close ported collar. i 17.20 Test 7-5/8" x 9-5/8" production annulus to IWO psi / 30 min. 17.2 POH and stand back 2-7/8" tubing for ESP run. 18.0 Run ESP assy. 18.1 M/U ESP assy and RIH to setting depth. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. 18.2 Land hanger, RILDs and test hanger. 18.3 Install BPV and N/D BOP. Page 39 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 18.4 N/U tree adapter and test tree. Pull BPV. 18.5 Circulate diesel freeze protection down 2-7/8" x 7-5/8" annulus (Volume should equal capacity of tubing to 2500' + tubing annulus to 2500'). Connect IA to tree and allow diesel freeze protect to "U-tube" into position. 18.6 Shut in well and prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 19.0 RDMO 19.1 RDMO Nordic #3. Page 40 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure HiImTEnergy Company 20.0 Diverter Schematic 16" Full Opening Knife Valve 21-114" 2M----- Diverter M------ Diverter "T" 21-114" 2M Spacer Spool Ground Level 16-3/4" 3M x 21-1/4" 2M DSA Seaboard Casinghead, S -22 -AP -8 16" SOW x 16-3/4" 3M; (2) ea 2-1/16" 5M studded outlets Page 41 Version 1 August, 2015 0 HilmTEneW Company 21.0 BOP Schematic Kill Line 9-5/8" DBL D Seal Casing Hanger SMB -22 16-3/4" NOM 9-5/8" BTC Btm x 10.5" -4 SA Pin Top W/ Primary Seas Milne Point Unit Producer Drilling Procedure �3' x SM HCR '1—Choke Line 3" x 5M Manual Gate Valve —11" x 5M \-2-1116" x 5M -20" Casing 9-5/8" Casing Page 42 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp EneW Company 22.0 Wellhead Schematic 1 HILCORP ALASKA j SCHRADER BLUFF WELLS K HO -35449H I 2-9/16 SM HOLD—DOWN FLANGE ADAPTER, ESP-2CL TOADSTOOL 11 x 2-9/15 5M 11 5M TUBING HANGER S-88—ESP N x 2-7/8 SRO TOP x 94.5 API MOD BTM EST F/TAURUS PENEITTATOR 43-217-00 MOT 2-1/16 SM CASING HANGER. SMB -22 11 x 7-5/8 W/"IMARY SEAL 26.0 EST 9-5/8 COL D 2-1/16 5M 16-3/4 3M CASING HANGER SW -22 16 x 9-5/8 W/PRIMARY SEAL 26.8 EST 13-3/8 CASING 9-5/8 CASING 7-5/8 CASING --- I 5,000 P9 ESP WELLHEAD ASSEMBLY NMI 2-7/5 CASING DMOMINS 900 ON THIS DRIIIING ARE TIE SACK SME 13-3/8 x 9-5/8 x 7-5/8 x 2-7/8 ESTIMATES ONLY AND CAN VARY SIGMFTCMNTLY RESTRICTED CONFIDENTIAL DOCWIENT' RAW MATEMA. °y19JUN15t OEPEENDINC ON LENGTNS,ar rr r wrr rr�rar �r. r w SEIM �ac� .I r r �� IS OJA A E OFIIIIN RPL 1:9 mlr•e r NO SAO BECONliSw3 FOR RETMCE PLRP06E'S ONLY. � QD— 00061 g Page 43 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 23.0 Days Vs Depth Days Vs Depth 0 20D0 4000 60M r EL W1 W sow 10000 120DQ 14DD0 0 5 10 15 20 25 30 Days Page 44 Version 1 August, 2015 0 Hilcorp Energy Company 24.0 Formation Tops Milne Point Unit Producer Drilling Procedure Formation TVD (Top) TVD (Bottom) Anticipated Pressure (Psi) SV1 2145 3339 1493 UgnuLA3 3340 3564 1594 SB NA Sand 3565 3596 1608 SB NB Sand 3597 3630 '1623 Page 45 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section 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 DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of wells in the vicinity of J-28. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for 1-12S. No H2S events have been documented on drill wells on `J" pad. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. Page 46 Version 1 August, 2015 Hilcorp Energy Company Milne Point Unit Producer Drilling Procedure 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 500 gpm. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There 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 1-12S events have been documented on drill wells on `J" pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on "J" pad. Page 47 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp EneW Company 26.0 Nordic #3 Rig Layout (Drillers Side) i .ra " gaff p - Calista Services RIG NO. 3 The Ll , jr.-1.Ju%,prci€xmn,. dr—mg—i lIrS m,xrr,. in,. d sgni. i -hl 1-d-- pm�rcy c N-&.- Caliv. and m p—d by LX vd ir,.:.,nimal :npy.id., 1,+a lts Ih.ign u f evhrd w, a...tvdrt,<ial ban. xid, rhe saprc.. aQ:em.m ,Fr.e i w+ll m+ h mid, mm&,r.d, :,gird enr.d- phunpaptrrd. m rcpred.cxd sn a„y rumrr xhvw.,<r.wxh.kmpa.,,ne, any in- hem.hr. bib. .nsm-W rAd-..ia fL6Jig. xidew, the—irt.nagrc.mn d N..di -C.riu,c. rF M.i . —y — br dvk«d,. any w.her part, ...q. F—h, 'r -if.- P'rp°'°' f— xhiri: it by "" pm.idd. Drillers Si a�a wtro• v.ft u.. m aas Page 48 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp Energy Company 27.0 Nordic #3 Rig Layout (Well End & Top View) TCP VIEW Page 49 Version 1 August, 2015 V, Milne Point Unit Producer Drilling Procedure Hilcorp Enmgy Compmy 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 50 Version 1 August, 2015 0 Hilcorp Enew Company 29.0 Choke Manifold Schematic }t a','a'a a"t"t a'<'{ t'o't'<'a e 1 S a <'t a , < > > > > >1>1>1> t'a' ><} s1a1a1, 1, 1>a>a> +><>1a's1 a1 1, > a's1}< a >a>RA>aa of t>a>a s1>tst1s >t}tit><> , Milne Point Unit Producer Drilling Procedure to w W Page 51 Version 1 August, 2015 •� ,+ ttoa Fv' ww 1 Page 51 Version 1 August, 2015 Hilcorp Energy Company Milne Point Unit Producer Drilling Procedure 30.0 Casing Design Information Calculation & Casing Design Factors DATE: 812712015 WELL: MPU J-28 DESIGN BY:Luke Keller Design Criteria: Hole Size 12-114" Mud Density: 9.5 ppg Hole Size 8-1i2- Mud Density: 9.5 ppg Hole Size Mud Density: Drilling Mode MASP: 1250 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1250 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient extemal stress (0.494 psitft) and the casing evacuated for the internal stress 3 Page 52 Version 1 August, 2015 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-518" 4-112' Top MD 0 8,400 To VD 0 3,594 Bottom MD 8,500 12,725 Bottom (TVD) 3,597 3,556 Length 8,500 4,325 Weight 40 11.6 Grade L-80 L-80 Connection TC -II N dril 521 Weight w/o Bouyqncy Factor lbs 340,000 50,170 Tension at Top of Section lbs 340,000 50,170 Min strength Tension 1000 lbs 916 267 Worst Case Safety Factor Tension 2.69 5.32 ✓ Collapse Pressure at bottom(Psi) 1,777 1,757 Collapse Resistance w/o tension (Psi) 3,090 6,350 Worst Case Safety Factor (Collapse) 1.74 3.61 ✓ MASP(psi) 1,250 1,250 Minimum Yield (psi) 1 5,750 7,780 Worst case safety factor Burst 4.60 6.22 Page 52 Version 1 August, 2015 0 HilmEnergy Company 31.0 8-1/2" Hole Section MASP Milne Point Unit Producer Drilling Procedure Maximum Anticipated Surface Pressure Calculation Hilccsr� 8-1/2" Hole Section MPU J-28 Milne Point Unit MD TVD Planned Top: 8500 3597 Planned TD: 12725 3556 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NB Sand 1 3,600 1 1610 1 Oil/Wet 8.6 1 0.447 Offset Well Mud Densities Well MW ranee Too (TVD) Bottom ITVDI Date MPI -19 9 - 9.3 ppg Surface 4,079 2004 MPI -18 9 - 10 ppg Surface 3,848 2011 MPI -17 9 - 9.5 ppg Surface 3,864 2004 MPI -16 9-9.3 ppg Surface 4,101 2004 MPI -15 9 -10.8 ppg Surface 4,042 2002 MPI - 14 9.1- 9.3 ppg Surface 3,979 2004 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3600 (ft) x 0.78(psi/ft)= 2808 2808(psi) - [0.1(psi/ft)•3600(ft))= 2448 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff NB sand) 3600 (ft) x 0.447(psi/ft)= 1609 psi 1609(psi) - 0.1(psi/ft)•3600(ft) 1250 si Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 53 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp EneW Company 32.0 Spider Plot (NAD 27) (Governmental Sections) � Milne Point Unit 0 1,000 2,000 3,000 MW� MPJ -28 Well Feet Page 54 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure HilmTEneW Company 33.0 Surface Plat (As Built) (NAD 27) J-1 NORTH 10 I J-2 SOUTH 10 J—PAD LEGEND + AS -BUILT CONDUCTOR ■ EXISTING CONDUCTOR SURVEY CONTROL MONUMENT i 1 q SEC SECJ12 a 4 29 I 2d4E PADSEC SEC32 33PAD 1 + VICINITY MAP N.T_S. NOTES: 1. STATE PLANE COORDINATES ARE ALASKA ZONE 4, NAD27. 2. GEODETIC COORDINATES ARE NAD -27- 3 MPU J_ PAD FACILITY SCALE FACTOR IS 0.9999031. 4. HORIZONTAL CONTROL BASED ON MPU J—PAD OPERATOR MONUMENTS J-1 AND J-2, 5. ELEVATIONS ARE BPX MILNE POINT DATUM MEAN SEA LEVEL. 6. DATE OF SURVEY: AUGUST 25. 2015- 7. REFERENCE FIELD BOOK: HC15-03 PCS. 19-24. SURVEYORS CERTIFICATE 1 HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING M THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF AUGUST 28, 2015. LOCATED WITHIN PROTRACTED SEC. 28, T. 13 N., R. 10 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC TOP OF BASE SECTION NO. COORDINATES COORDINATES POSITION(OMS) POSITION(D.DD) CELLAR BOX FLANGE EL. OFFSETS J-28 Y= 6014608.14 N= 789.96 70'27'02.328' 70.4506468 33.4' — 2209 FSL X= 552189.84 E= 1170.05 149'34'27,094' 149.5741928 3132 FEL Des Hilcorp Alaska 0/29/15 IN -00 MPU J—PAD "`° AS -BUILT WELL CONDUCTOR 2 WELL MPJ -28 Page 55 Version 1 August, 2015 Hilcorp Energy Company 34.0 Offset MW vs TVD Chart MW vs TVD Offsets 0 1000 2000 v 3000 5000 Milne Point Unit Producer Drilling Procedure 9.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 Mud Weight (PPG) Page 56 Version 1 August, 2015 —MP 1-19 (2004) —MPk-19 (2011) MPI -17 (2004) iMPI-16 (2004) d 1 9.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 Mud Weight (PPG) Page 56 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Hilcorp EneW Gundparry 35.0 Drill Pipe Information 5" 19.5# S-135 DS -50 Drill Pipe Configuration Pipe Body OD 1- 5.000 Pipe Body Wall Thickness tar 0.362 Pipe Body Grade S-135 Drill Pipe Length Rapw Connection GPDS50 Tod Joint OD 6.625 Tod Joint ID (4+' 3.250 Pin Tong 9 EE:� Box Tong m412 80 a% Ins on Class Best Estimates Nominal Weight Designation 19,50 Drill Pipe Approximate Length m) 131.5 SmoothEdge Height nm 3132 Raised Tool Joint SMYS pat 120.000 Upset Type IEU Max Upset OD (DTE) un) 5.125 Friction Factor 1.0 Box OD NoteTong spice may Include hardiaclnq. Drill Pipe Performance Drill -Pipe Length Rangel Performance of Drill Pipe with Pipe Body at ryn Best Estimates Nominal % Inspection Class (Mltlwdfcaft) two caannq) (mast -.w Appaed fAllre-w Operational Max Tension Operational Pipe Torsional Strength Drill Pie Adjusted Weight If-) 24.11 23.29 0.36 tltaaar Torque (n u») (sx) Box OD Fluid Displacement Igatm 0.37 Fluid Displacement 4abisl Elevator Ca ac Tension Only 0 560,800 0.0085 M(IT :43.:100 cm,ar �a o 39 600 410,500 4;ooi 17,105 Fluid Ca aci (ga n 0.70 15,638 0.72 0 0172 4ptl 15,672 FI "d Ca 0 0169 0 0167 10,029 l-ly tea ) _ 36,100 Tension Only 0 560 800 Irran,lan MUT Drrft Size 41ni 3.125 e«nw yed t oadnq 32,100 467,400 Nom- oe rmw baeet equms az us galims. Nate: DMI pipe assernbly values are best estknales and may vary due to pipe body -II lomrarxe. Internal plastic caaiinq and other fa_fus. Connection Performance G'DS50 t 6.625 (at) OD x 3,250 (in) ID ) 120,000 1- -`�"" `- Note: The mauenum make -W Io=o shWd to irmled ARM possla* Nom' To masimge connection operaMonal lensle. a MUT tT4 i - 373084aaasj should be applied. Tod Joint Torsional Strartam 4lwwr 71,800 Tool Joint Tensile Strength (os) 1,250,000 Elevator Shoulder Information 560,800 Pipe Torsional Strength SmoothEdge Height 58,100 3132 Raised TJ/PlpeBody Torsional Ratio 0.97 Box OD slnl 6.812 Elevator Ca ac Elba 1,658,000 46,500 46,500 Tool Joint Dimensions Balanced OD tip 6.435 ufthlrnurn Toa ,ware Do wr APl 5.930 Pramlum Gass lin 160rur nlan Tool Jo" 00 for 5.93 Counterbara Iln Elevator OD 3132 Raised 6.812 (in) Tool Joint Worn to Bevel Wom to Min TJ OD for OD I Diameter I API Premium Class 5219 Note Elevator wpactty flared m assumed Elevator Elora, rw wear tactor. and cmtaet saes of t 14,100psi. ASSUmed Elevator Blom Diameter (- No -.:A ralsed emvawr OD I xreases elevator capac (y vMhoul atfectinp maTke- q torque. Pipe Body Slip Crushing Capacity Pipe Body Configuration ( 5 (In) OD 0.962 a) Wan S-135) Nominal 1 80 e% inspection Class I AS Premium Class ]Slip Crushin g Capacity (-)1498.300 1396,500 1396,5W Nie: Sip G+rNnq. SlIp a .9*W load Is cM LAaled wfh re Spr teMAd equal- fmm Wry Does Orn Pyo ASSumad Sl Length on 16.5 Fai rn Se Sip A2v' World CO, 19M W ft.11P knialh argil barls.- road factor steno and ane ndonmce Transverse Load Factor (K) 4.2 h y. Mgyp cm:ra,d m depen LN m the Oil, closer out cp nlw;:oenaent a mcten, loading �aaua. tkno h tis pipe 00 arm wa1'uatL9)IX:. and NF1N 7actas. Ctxeal Ntln d1e sap nuTxaa[t:rcr far addtamai W-ltllcn. Pine Bodv Performance Pipe Body Configuration ( 5 (in) OD 0.362 (in) Wall S-135) Page 57 Version 1 August, 2015 NOW No"llal Burst c ktlhiled at ReW per API. Nominal 80 e% Inspection Class API Premium Class Pipe Tensile Streng MW 712100 560800 560,800 Pipe Torsional Strength (rc4ts1 74,100 58,100 58,100 TJ/PlpeBody Torsional Ratio 0.97 124 1.24 80°% Pipe Torsional Strength (fwtCi 59,300 46,500 46,500 Burst 4;ooi 17,105 15.638 15,638 Collapse 4ptl 15,672 10,029 10,029 Pipe OD tile) 5.000 4.855 4.855 Wall Thickness :IRI 0.362 0.290 0.290 Nominal Pipe ID (1%1 4.276 4.276 4.276 Cross Sectional Area of Pipe Body tin^z) 5275 4.154 4.154 Cross Sectional Area of OD (nazi 19.635 18.514 18.514 Cross Sectional Area of ID (n^ 14.360 14.360 14.360 3edion Modulus to"z; 31 5.708 4.476 14A76 Polar Section Modulus (n^31 11.415 8.953 18.953 Version 1 August, 2015 NOW No"llal Burst c ktlhiled at ReW per API. Hilcorp Energy Company Milne Point Unit Producer Drilling Procedure Operational Limits of Drill Pipe Connection GPD550 Too! Joint OD 01 ns 6.625 Tod Joint ID 3.250 Tool Joint Specified Minimum 120,000 Yield Strength tcs l Pipe Body C % Inspection Class Pipe Body OD „n, 5 Wall Thickness ra, 0.362 Pipe Body Grade S-135 Combined Loading for Drill Pipe at Maximum Make-up Torque = 43,100 )n-ws, Operalional Assembly Torque Max Tension in -lbs) Iibs 0 560,800 2,100 560 400 4,200 559,300 6,300 557,500 8,300 555.000 10,400 551 700 12,500 547,600 14,600 542,800 16,700 537,100 18,800 530,600 20,600 523,600 22,900 515 400 25.000 506,200 27,100 496100 29,200 484,800 31,300 472,500 33,300 459 600 35,400 444,700 37,500 428,400 39,600 1410,500 Pipe Body connection Max Max Tension T-1- Qbs) jimj 560,800 1,046.900 560,400 1.046.900 559,300 1,046,900 557,500 1,046,900 555,000 1,046:900 551,700 1,046,900 547,600 1,046,900 542,800 1.046.900 537,100 11,046.900 530,600 1.046,900 523,600 1,046.900 515,400 1,046,900 506,200 1,046.900 496,100 1,046,900 484,800 11,046,900 472,500 1,046.900 459.600 1,046,900 444,700 1,046,900 428,400 1.046.900 410,500 1,046.900 Operational drilling torque is limited by the Mace -up Torque_ Min MUT Max MUT Combined Loading for Drill Pipe at Minimum Make-up Torque= 36,100 141bs? Operation Assembly I Torque Max Tension ittabs; Ow 0 560,800 1,700 560,500 3,400 559,800 5.100 558,600 6,800 556,900 8,400 554,900 10,100 552,200 11,800 1549,100 13,500 545,400 15200 541,200 16,900 536,500 18.600 531,300 20,300 525,400 22,000 519,000 23,700 512,000 25,300 504.800 27,000 496,600 28,700 487,600 30,400 477,900 32,100 467,400 Pine Body coen _" n Mm, Tei Max Tension 41bv �Ibs) 560.800 1,202,500 560.500 1,202,500 559.800 1,202,500 558,600 1,202,500 556,900 1,202,500 554,900 1,202,500 552.200 1,202,500 549.100 1,202,500 545.400 1,202,500 541.200 1,202,500 536.500 1,202,500 531,300 1,202,500 525.400 1,202,500 519.000 11202,500 512.000 1,202,500 504,800 1,202,500 496,600 1,202,500 487.600 1,202,500 477,900 02,5 487,400 11,2,202,5000 0 Operational drilling torque is limited by the Make-up Torque. Connection Make-up Torque Range Make-up Torque Connection Max m-65 Tension 36,100 1,202, 500 36,900 1,229,200 37,700 1,243,600 38,400 1,218,100 39,200 1,189,000 40,000 1,159,800 40,800 1,130,700 41,500 1,105,200 42,300 1,076,100 43,100 1,046,900 Page 58 Version 1 August, 2015 Milne Point Unit Producer Drilling Procedure Connection Wear Table Connection GPDS50 Tool Joint OD , ; 6.625 Taos Joint ID , } 3250 Tool Joel Specified Minimum 120,000 Yield Strength ,! Connection Wear New OD worts 00 Max MUT In4bV Coemectice Max Tension lit" 43,100 1,046,900 43,100 1,034,900 43,100 11,022,600 43,100 1,009 , ,009, 800 42,700 1,008,100 40,800 1,057,300 38,900 1,104,800 37,000 1,150,400 35,200 1,190,900 33,300 1,232, 300 31,500 1,227,200 29,800 1,187,100 Pipe Body Combined Loading Table (Torque -Tension) Min MUT Connection Max Tension 35,900 1,195.900 35,900 1,208,700 35,900 1,222.400 35,900 1,237.500 35,600 1,245,200 34,000 1,207,700 32,400 1,169,800 30,800 1,131,300 29,300 1,096,100 27,800 1,060.800 26,300 1,024,600 24,800 987,900 PiPe ®otty l 80 % Inspection Class I Pipe Body OD 5 Wall Thsckness ,,, 0.362 Pipe Body Grade S-135 Pipe Body Torque 0 5,300 10.600 15.800 21.100 26400 31.700 37.000 42.300 47.500 52.800 58.100 11ldbs) Pipe Body Max Tension 540 800 558,400 551,400 539,600 522.500 499.600 470.000 432,400 384,500 323,100 234,300 12,200 Obs) Page 59 Version 1 August, 2015 Hilcorp Energy Company Milne Point M Pt J Pad Plan: MPJ -28 MPJ -28 Plan: MPJ -28 wp2 Standard Proposal Report 02 September, 2015 HALLIBURTON Sperry Drilling Services HALLIBURTON Rilcorp Energy Compa ny CASING DETAILS SURVEY PROGRAM WELL DETAILS Plan: MPJ -28 Calcula4on Method: Minimum Curvature MD Name Size Date' 2015-08-247000000 Validated: Yes Version: 8500.00 95/8" 98/8 Ground L-83.40-- 12725.22 51/2' 5-1/2 Depth Fmm Depth To Survey/Plan Tool C 0 Sperry Drilling Error Scan System: ISCWSA Method: Closest Approach 3D +N/ -S *E/ -W Northing E..bng 8601.58 12725.07 MPJ -28 2 Latlttude Langitude _ _ _ Start Dir 3°/100' : 480' MD, 479.84'ND Error Surface: Elliptical Corr, c')500 650 0.00 0.00 8014608.14 552189.84 70°27'2328N 149°34'27.094W t Warning Method: Error Rato ❑ -' - " StartDir 5°/100' : 8601.58' MD, 3601'ND 1300 Project: Milne End Dir : 1919.42' MD, 1734.34' ND , End Dir :7981.58' MD, 3579.36' Nq c� 1y0O _ Point Site: MPtJPad REFERENCE INFORMATION 5°/100' : 7740.16' MD, �3545.78'ND SECTION DETAILS 00 --' End Dir : 3288.92' MD, 2467.14' Well: Plan: MPJ -28 Coordinate (WE) Reference: Well Plan: MPJ -28, True Northac MD Inc A" TVD TVDSS +N/ -S +E/ -W Northing Easting OLeg TF... VS.. Target Wellbore: MPJ -28 Vertical (TVD) Reference: As-BUIft®63.40usft 1 3000 0.00 0.00 30.00 -33.40 0.00 0.00 6014608.14 552189.84 0.00 0.00 0.00 Start Dir 4°/100' : 8725.13' MD, 3599.98'ND , - Measured Depth Reference' As -Built @6340usft 2 280.00 0.00 0.00 28000 216.60 0.00 0.00 6014608.14 552189.84 0.00 0.00 0.00 Design: MPJ -28 wp2 Calwlation Method' Minimum Curvature 3 4 480.00 4.00 1080.00 22.00 233.00 233.00 479.84 416.44 1062.06 998.66 1.20 -5.57 -85.09 -112.92 6014603.90 6014522.27 552184.30 2.00 552077.53 3.00 233.00 5.59 0.00 113.25 5 1919.42 51.06 263.83 1734.34 1670.94 -218.63 -576.40 6014385.50 551615.04 4.00 46.09 577.22 62615.10 5106 263.83 217156 2108.16 -276.77 -1114.38 6014323.60 551077.54 0.00 0.00 1115.42 7 2842.25 60.00 262.00 2300.00 2236.60 -300.00 -1300.00 6014299.07 550892.10 4.00 -10.12 1301.13 8 3288.92 75.98 270.67 2467.14 2403.74 -324.58 -1711.54 6014271.61 550480.78 4.00 28.47 1712.76 -1950 9 10 7740.16 75.98 7981.58 88.00 270.67 271.75 3545.78 3482.38 3579.36 3515.96 -274.00 -6029.82 -268.92 8268.38 6014291.95 6014295.35 546162.67 0.00 545924.10 5.00 0.00 6030.82 5.16 6269.36 11 8601.58 88.00 271.75 3601.00 3537.60 -250.00 £887.72 6014309.94 545304.71 0.00 0.00 6888.62 12 8673.67 91.60 271.70 3601.25 3537.85 -247.83 8959.76 6014311 So 545232.66 5.00 -00 74 6960.65 13 8704.76 91 So 271.70 3600.38 3536.98 -246.90 8990.83 6014312.31 545201.59 0.00 0.00 6991.71 14 8725.13 90.63 272.00 3599.98 3536.58 -246.25 -7011.18 6014312.83 545181.24 500 163.07 7012.06 -1300 15 8748.47 90.67 272.93 3599.72 3536.32 -245.24 -7034.50 6014313.67 545157.91 4o(l 87.70 7035.38 i 6 12724.15 90.67 272,93 3553.41 3490.01 11.83 -11004.70 6014489.25 541186.77 0.00 0.00 11004.78 17 12725.22 90.64 27290 3553.40 3490.00 11.77 -11005.77 6014489.30 541185.70 4.00 -129.67 11005.85 MPJ -28 wp2 toe 850 CASING DETAILS SURVEY PROGRAM TVD 359745 MD Name Size Date' 2015-08-247000000 Validated: Yes Version: 8500.00 95/8" 98/8 3553.40 12725.22 51/2' 5-1/2 Depth Fmm Depth To Survey/Plan Tool C 0 30.00 400.00 MPJ -28 wp2 MWD Intem Azi+eag 400.00 8601.58 MPJ -28 wp2 MYW +IFR2+MS+sag _ _ Start DIr 2°/100' :280' MD, 2B0'ND 8601.58 12725.07 MPJ -28 2 o _ _ _ Start Dir 3°/100' : 480' MD, 479.84'ND FORMATION TOP DETAILS+ c')500 650 _ _ No formation data is available t Start Dir 4°/100' :1080' MD, 1062.06TVD ❑ -' - " StartDir 5°/100' : 8601.58' MD, 3601'ND 1300 End Dir : 1919.42' MD, 1734.34' ND , End Dir :7981.58' MD, 3579.36' Nq c� 1y0O _ Start Dir 4°/100' : 2615.1' MD, 2171.567VD StartDir 5°/100' : 7740.16' MD, �3545.78'ND 2 00 --' End Dir : 3288.92' MD, 2467.14' ND Start Dir 5°/100' : 8601.58' MD, 3601 -TVD ' H 1950 tih --' _- -' O End Dir :8673.67' MD, 3601.25' ND _g" " o o - o 0 0 Start Dir 5°/100' : 8704.76' MD, 3600.38TVD , 2600 e o o h o h o Start Dir 4°/100' : 8725.13' MD, 3599.98'ND , - o Start Dir 4°/100' :12724.15' MD, 3553.41'ND 3250 - - - End Dir : 8748.47' MD, 3599.72' ND l yy N N= -MPJ-26 wp2 95/8..1 0 0 0 0o O O o o Nl MPJ -28 wp2 heel MPJ -28 wp2 toe n 0 650 1300 1950 2600 3250 3900 4550 5200 5850 6500 7150 7800 8450 9100 9750 10400 11050 11700 Vertical Section at 269.78° (1300 usft/in) HALLIBURTONProject: Milne Point COMPANY DETAILS: Hilcorp Energy Company WELL DETAILS: Plan: MPJ -28 Ground Level: 33.40 1 Site: M Pt J Pad Calculation Method: Minimum Curvature st,o.", Well: Plan: MPJ -28 Error System: ISCWSA +W -S +E/ -W Northing E fang Latitude Lon8Rude +N/ -S +E/ -W Wellbore: MPJ -28 Scan Method: Closest Approach 3D Error Surface: Elliptical Conic 000 0.00 6014608.14 552189.84 70° 27 2.328 N 149° 34'27.094 W 7000 Plan: MPJ -28 wp2 Warning Method: Error Ratio REFERENCE INFORMATION C-rdimte (N/E) Reference: Wel Plan: MPJ -2a, T. North 6014608.14 552189.84 0.00 0.00 0.00 Vertical (TVD) Reference: M -Buis @ 63.40usa 6500 216.60 0.00 0.00 Measured Depth Rafennce: M -Buis @ 63,Q ft Cakulation Method: Minimum CunaWre C SURVEY PROGRAM SECTION DETAILS Magnetic North: 18.98° 3000 Sec MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting OLeg TFace VSec Target 1 30.00 0.00 0.00 30.00 -33.40 0.00 0.00 6014608.14 552189.84 0.00 0.00 0.00 2 280.00 0.00 0.00 280.00 216.60 0.00 0.00 6014608.14 552189.84 0.00 0.00 0.00 3 480.00 4.00 233.00 479.84 416.44 3.20 -5.57 6014603.90 552184.30 2.00 233.00 5.59 4 1080.00 22.00 233.00 1062.06 998.66 -85.09 -112.92 6014522.27 552077.53 3.00 0.00 113.25 5 1919.42 51.06 263.63 1734.34 1670.94 -218.63 -576.40 6014385.50 551615.04 4.00 46.09 577.22 6 2615.10 51.06 263.83 2171.56 2108.16 -276.77 -1114.38 6014323.60 551077.54 0.00 0.00 1115.42 7 2842.25 60.00 252.00 2300.00 2236.60 -300.00 -1300.00 6014299.07 550892.10 4.00 -10.12 1301.13 8 3288.92 75.98 270.67 2467.14 2403.74 -324.58 -1711.54 6014271.61 550480.78 4.00 28.47 1712.76 9 7740.16 75.98 270.67 3545.78 3482.38 -274.00 .6029.82 6014291.95 546162.67 0.00 0.00 6030.82 10 7981.58 88.00 271.75 3579.36 3515.96 -268.92 -6268.38 6014295.35 545924.10 5.00 5.16 6269.36 11 8601.58 88.00 271.75 3601.00 3537.60 -250.00 -6887.72 6014309.94 545304.71 0.00 0.00 6888.62 12 8673.67 91.60 271.70 3601.25 3537.85 -247.83 -6959.76 6014311.60 545232.66 5.00 -0.74 6960.65 13 8704.76 91.60 271.70 3600.38 3536.98 -246.90 -6990.83 6014312.31 545201.59 0.00 0.00 6991.71 148725.13 90.63 272.00 3599.98 3536.58 -246.25 -7011.18 6014312.83 545181.24 5.00 163.07 7012.06 15 8748.47 90.67 272.93 3599.72 3536.32 -245.24 -7034.50 6014313.67 545157.91 4.00 87.70 7035.38 16 12724.15 90.67 272.93 3553.41 3490.01 -01.83 -11004.70 6014489.25 541186.77 0.00 0.00 11004.78 17 12725.22 90.64 272.90 3553.40 3490.00 31.77 -11005.77 6014489.30 541185.70 4.00 A29.67 11005.85 MPJ-28wp2loe C SURVEY PROGRAM Magnetic North: 18.98° 3000 Data 2015-08-24TOO:D0:00 Validated: Yes Version: Magnetic Field CASING DETAILS g Depth From Depth To Survey/Plan TVD TVDSS MD Size Name 2500 400.00 MPJ -28 wp2 (MPJ -28) MWD_Interp Azi+sag 3597.45 3534.05 8500.00 9-5/8 9 5/8" 8601.58 MPJ -28 wp2(MPJ-28) MWD+IFR2+MS+sag Model: BGGWO15 3553.40 3490.00 12725.22 5-1/2 51/2" 2000 rV 0 1500 3 0 � l000 500 MPl-2s wp2 to MPl-28 wp2 hee 4 S $ $ S 0 -m; -500 s In° 9 5/8" o$o T M Azimuths to True North SURVEY PROGRAM Magnetic North: 18.98° Data 2015-08-24TOO:D0:00 Validated: Yes Version: Magnetic Field Strength: 57506.0snT Depth From Depth To Survey/Plan Tool Dip Angle: 81.06° 30.00 400.00 MPJ -28 wp2 (MPJ -28) MWD_Interp Azi+sag Date: 8/24/2015 400.00 8601.58 MPJ -28 wp2(MPJ-28) MWD+IFR2+MS+sag Model: BGGWO15 8601.58 12725.07 MPJ -28 wp2 (MPJ -28) MWD+IFR2+MS+sag -13000 -12500 -12000 -11500 -11000 -10500 -10000 -9500 -9000 -8500 -8000 -7500 -7000 -6500 -6000 -5500 -5000 3500 4000 -3500 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 1500 West( -)/East(+) (1500 usfVin) 4+ HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Milne Point Site: M Pt J Pad Well: Plan: MPJ -28 Wellbore: MPJ -28 Design: MPJ -28 wp2 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPJ -28 TVD Reference: As -Built @ 63.40usft MD Reference: As -Built @ 63.40usft 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 J Pad, TR -13-10 Site Position: Northing: 6,013,415.23 usft Latitude: 70° 26' 50.647 N From: Map Easting: 551,435.10usft Longitude: 149° 34'49.503 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.40 ° Well Plan: MPJ -28 Well Position +N/ -S 0.00 usft Northing: 6,014,608.14 usft Latitude: 700 27'2.328 N +E/ -W 0.00 usft Easting: 552,189.84 usft Longitude: 149° 34'27.094 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 33.40 usft Wellbore MPJ -28 Magnetics Model Name Sample Date Declination Dip Angle Field Strength V) V) (nT) BGGM2015 8/24/2015 18.97 81.06 57,506 Design MPJ -28 wp2 Audit Notes: Version: Vertical Section: Phase: PLAN Depth From (TVD) +N/ -S (usft) (usft) 30.00 0.00 Tie On Depth: 30.00 +E/ -W Direction (usft) (") 0.00 269.78 9/2/2015 2:19:37PM Page 2 COMPASS 5000.1 Build 73 i Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPJ -28 Company: Hilcorp Energy Company TVD Reference: As -Built @ 63.40usft Project: Milne Point MD Reference: As -Built @ 63.40usft Site: M Pt J Pad North Reference: True Well: Plan: MPJ -28 Survey Calculation Method: Minimum Curvature Wellbore: MPJ -28 Depth Inclination Design: MPJ -28 wp2 System +N/ -S Plan Sections Measured Vertical TVD Dogleg Build Tum Depth Inclination Azimuth Depth System +N/ -S +E/.W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/loousft) (°/100usft) (1100usft) (°) 30.00 0.00 0.00 30.00 -33.40 0.00 0.00 0.00 0.00 0.00 0.00 280.00 0.00 0.00 280.00 216.60 0.00 0.00 0.00 0.00 0.00 0.00 480.00 4.00 233.00 479.84 416.44 -4.20 -5.57 2.00 2.00 0.00 233.00 1,080.00 22.00 233.00 1,062.06 99866 -85.09 -112.92 3.00 3.00 0.00 0.00 1,919.42 51.06 263.83 1,734.34 1,670.94 -218.63 -576.40 4.00 3.46 3.67 46.09 2,615.10 51.06 263.83 2,171.56 2,108.16 -276.77 -1,114.38 0.00 0.00 0.00 0.00 2,842.25 60.00 262.00 2,300.00 2,236.60 -300.00 -1,300.00 4.00 3.94 -0.81 -10.12 3,288.92 75.98 270.67 2,467.14 2,403.74 -324.58 -1,711.54 4.00 3.58 1.94 28.47 7,740.16 75.98 270.67 3,545.78 3,482.38 -274.00 -6,029.82 0.00 0.00 0.00 0.00 7,981.58 88.00 271.75 3,579.36 3,515.96 -268.92 -6,268.38 5.00 4.98 0.45 5.16 8,601.58 88.00 271.75 3,601.00 3,537.60 -250.00 -6,887.72 0.00 0.00 0.00 0.00 8,673.67 91.60 271.70 3,601.25 3,537.85 -247.83 -6,959.76 5.00 5.00 -0.06 -0.74 8,704.76 91.60 271.70 3,600.38 3,536.98 -246.90 -6,990.83 0.00 0.00 0.00 0.00 8,725.13 90.63 272.00 3,599.98 3,536.58 -246.25 -7,011.18 5.00 -4.78 1.46 163.07 8,748.47 90.67 272.93 3,599.72 3,536.32 -245.24 -7,034.50 4.00 0.16 4.00 87.70 12,724.15 90.67 272.93 3,553.41 3,490.01 -41.83 -11,004.70 0.00 0.00 0.00 0.00 12,725.22 90.64 272.90 3,553.40 3,490.00 -41.77 -11,005.77 4.00 -2.55 -3.08 -129.67 1 9/2/2015 2:19:37PM Page 3 COMPASS 5000.1 Build 73 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPJ -28 Company: Hilcorp Energy Company TVD Reference: As -Built @ 63.40usft Project: Milne Point MD Reference: As -Built @ 63.40usft Site: M Pt J Pad North Reference: True Well: Plan: MPJ -28 Survey Calculation Method: Minimum Curvature Wellbore: MPJ -28 Depth Inclination Design: MPJ -28 wp2 TVDss +N/ -S Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (') V) (usft) usft (usft) (usft) (usft) (usft) -33.40 30.00 0.00 0.00 30.00 -33.40 0.00 0.00 6,014,608.14 552,189.84 0.00 0.00 100.00 0.00 0.00 100.00 36.60 0.00 0.00 6,014,608.14 552,189.84 0.00 0.00 200.00 0.00 0.00 200.00 136.60 0.00 0.00 6,014,608.14 552,189.84 0.00 0.00 280.00 0.00 0.00 280.00 216.60 0.00 0.00 6,014,608.14 552,189.84 0.00 0.00 Start Dir 2°/100' : 280' MD, 280'TVD 300.00 0.40 233.00 300.00 236.60 -0.04 -0.06 6,014,608.10 552,189.78 2.00 0.06 400.00 2.40 233.00 399.96 336.56 -1.51 -2.01 6,014,606.61 552,187.84 2.00 2.01 480.00 4.00 233.00 479.84 416.44 -4.20 -5.57 6,014,603.90 552,184.30 2.00 5.59 Start Dir 3°/100' : 480' MD, 479.84'TVD 500.00 4.60 233.00 499.78 436.38 -5.10 -6.77 6,014,602.99 552,183.11 3.00 6.79 600.00 7.60 233.00 599.20 535.80 -11.50 -15.26 6,014,596.54 552,174.67 3.00 15.30 700.00 10.60 233.00 697.93 634.53 -21.01 -27.89 6,014,586.93 552,162.10 3.00 27.97 800.00 13.60 233.00 795.70 732.30 -33.63 -44.63 6,014,574.20 552,145.46 3.00 44.75 900.00 16.60 233.00 892.24 828.84 -49.30 -65.43 6,014,558.38 552,124.77 3.00 65.61 1,000.00 19.60 233.00 987.28 923.88 -68.00 -90.24 6,014,539.52 552,100.09 3.00 90.49 1,080.00 22.00 233.00 1,062.06 998.66 -85.09 -112.92 6,014,522.27 552,077.53 3.00 113.25 Start Dir 4°/100' : 1080' MD, 1062.06'TVD 1,100.00 22.56 234.50 1,080.57 1,017.17 -89.58 -119.04 6,014,517.74 552,071.44 4.00 119.38 1,200.00 25.55 241.03 1,171.89 1,108.49 -111.17 -153.54 6,014,495.91 552,037.10 4.00 153.96 1,300.00 28.77 246.24 1,260.86 1,197.46 -131.32 -194.45 6,014,475.47 551,996.33 4.00 194.95 1,400.00 32.16 250.45 1,347.05 1,283.65 -149.93 -241.58 6,014,456.53 551,949.34 4.00 242.15 1,500.00 35.66 253.93 1,430.04 1,366.64 -166.92 -294.69 6,014,439.18 551,896.36 4.00 295.32 1,600.00 39.24 256.85 1,509.42 1,446.02 -182.19 -353.52 6,014,423.50 551,837.64 4.00 354.21 1,700.00 42.89 259.36 1,584.81 1,521.41 -195.67 -417.79 6,014,409.57 551,773.47 4.00 418.53 1,800.00 46.58 261.54 1,655.84 1,592.44 -207.30 -487.18 6,014,397.45 551,704.17 4.00 487.96 1,900.00 50.31 263.47 1,722.16 1,658.76 -217.02 -561.36 6,014,387.21 551,630.07 4.00 562.18 1,919.42 51.06 263.83 1,734.34 1,670.94 -218.63 -576.40 6,014,385.50 551,615.04 4.12 577.22 End Dir : 1919.42' MD, 1734.34' TVD 2,000.00 51.06 263.83 1,784.98 1,721.58 -225.37 -638.71 6,014,378.33 551,552.78 0.00 639.56 2,100.00 51.06 263.83 1,847.83 1,784.43 -233.72 -716.05 6,014,369.43 551,475.52 0.00 716.93 2,200.00 51.06 263.83 1,910.68 1,847.28 -242.08 -793.38 6,014,360.53 551,398.25 0.00 794.29 2,300.00 51.06 263.83 1,973.53 1,910.13 -250.44 -870.71 6,014,351.63 551,320.99 0.00 871.65 2,400.00 51.06 263.83 2,036.38 1,972.98 -258.80 -948.04 6,014,342.74 551,243.73 0.00 949.02 2,500.00 51.06 263.83 2,099.23 2,035.83 -267.15 -1,025.37 6,014,333.84 551,166.46 0.00 1,026.38 2,600.00 51.06 263.83 2,162.07 2,098.67 -275.51 -1,102.70 6,014,324.94 551,089.20 0.00 1,103.74 2,615.10 51.06 263.83 2,171.56 2,108.16 -276.77 -1,114.38 6,014,323.60 551,077.54 0.00 1,115.42 Start Dir 4°/100' : 2615.1' MD, 2171.56fVD 2,700.00 54.41 263.10 2,222.97 2,159.57 -284.47 -1,181.50 6,014,315.43 551,010.48 4.00 1,182.57 2,800.00 58.35 262.31 2,278.32 2,214.92 -295.05 -1,264.08 6,014,304.27 550,927.98 4.00 1,265.19 2,842.25 60.00 262.00 2,300.00 2,236.60 -300.00 -1,300.00 6,014,299.07 550,892.10 3.95 1,301.13 2,900.00 62.04 263.25 2,327.98 2,264.58 -306.48 -1,350.10 6,014,292.24 550,842.05 4.00 1,351.25 3,000.00 65.59 265.30 2,372.11 2,308.71 -315.41 -1,439.37 6,014,282.69 550,752.86 4.00 1,440.55 3,100.00 69.17 267.24 2,410.58 2,347.18 -321.39 -1,531.46 6,014,276.06 550,660.82 4.00 1,532.67 3,200.00 72.76 269.09 2,443.19 2,379.79 -324.41 -1,625.92 6,014,272.39 550,566.39 4.00 1,627.14 9/212015 2:19:37PM Page 4 COMPASS 5000.1 Build 73 Planned Survey Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPJ -28 Company: Hilcorp Energy Company TVD Reference: As -Built @ 63.40usft Project: Milne Point MD Reference: As -Built @ 63.40usft Site: M Pt J Pad North Reference: True Well: Plan: MPJ -28 Survey Calculation Method: Minimum Curvature Wellbore: MPJ -28 Depth Inclination Design: MPJ -28 wp2 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) 0 (1) (usft) usft (usft) (usft) (usft) (usft) 2,403.74 3,288.92 75.98 270.67 2,467.14 2,403.74 -324.58 -1,711.54 6,014,271.61 550,480.78 4.00 1,712.76 End Dir : 3288.92' MD, 2467.14' TVD 3,300.00 75.98 270.67 2,469.83 2,406.43 -324.45 -1,722.29 6,014,271.66 550,470.03 0.00 1,723.51 3,400.00 75.98 270.67 2,494.06 2,430.66 -323.32 -1,819.30 6,014,272.12 550,373.02 0.00 1,820.51 3,500.00 75.98 270.67 2,518.29 2,454.89 -322.18 -1,916.31 6,014,272.58 550,276.02 0.00 1,917.52 3,600.00 75.98 270.67 2,542.53 2,479.13 -321.04 -2,013.33 6,014,273.04 550,179.01 0.00 2,014.53 3,700.00 75.98 270.67 2,566.76 2,503.36 -319.91 -2,110.34 6,014,273.49 550,082.00 0.00 2,111.54 3,800.00 75.98 270.67 2,590.99 2,527.59 -318.77 -2,207.35 6,014,273.95 549,984.99 0.00 2,208.55 3,900.00 75.98 270.67 2,615.22 2,551.82 -317.64 -2,304.36 6,014,274.41 549,887.98 0.00 2,305.55 4,000.00 75.98 270.67 2,639.45 2,576.05 -316.50 -2,401.38 6,014,274.86 549,790.97 0.00 2,402.56 4,100.00 75.98 270.67 2,663.69 2,600.29 -315.36 -2,498.39 6,014,275.32 549,693.96 0.00 2,499.57 4,200.00 75.98 270.67 2,687.92 2,624.52 -314.23 -2,595.40 6,014,275.78 549,596.95 0.00 2,596.58 4,300.00 75.98 270.67 2,712.15 2,648.75 -313.09 -2,692.42 6,014,276.23 549,499.94 0.00 2,693.59 4,400.00 75.98 270.67 2,736.38 2,672.98 -311.95 -2,789.43 6,014,276.69 549,402.93 0.00 2,790.59 4,500.00 75.98 270.67 2,760.61 2,697.21 -310.82 -2,886.44 6,014,277.15 549,305.92 0.00 2,887.60 4,600.00 75.98 270.67 2,784.85 2,721.45 -309.68 -2,983.46 6,014,277.60 549,208.92 0.00 2,984.61 4,700.00 75.98 270.67 2,809.08 2,745.68 -308.54 -3,080.47 6,014,278.06 549,111.91 0.00 3,081.62 4,800.00 75.98 270.67 2,833.31 2,769.91 -307.41 -3,177.48 6,014,278.52 549,014.90 0.00 3,178.63 4,900.00 75.98 270.67 2,857.54 2,794.14 -306.27 -3,274.49 6,014,278.97 548,917.89 0.00 3,275.63 5,000.00 75.98 270.67 2,881.78 2,818.38 -305.14 -3,371.51 6,014,279.43 548,820.88 0.00 3,372.64 5,100.00 75.98 270.67 2,906.01 2,842.61 -304.00 -3,468.52 6,014,279.89 548,723.87 0.00 3,469.65 5,200.00 75.98 270.67 2,930.24 2,866.84 -302.86 -3,565.53 6,014,280.35 548,626.86 0.00 3,566.66 5,300.00 75.98 270.67 2,954.47 2,891.07 -301.73 -3,662.55 6,014,280.80 548,529.85 0.00 3,663.66 5,400.00 75.98 270.67 2,978.70 2,915.30 -300.59 -3,759.56 6,014,281.26 548,432.84 0.00 3,760.67 5,500.00 75.98 270.67 3,002.94 2,939.54 -299.45 -3,856.57 6,014,281.72 548,335.83 0.00 3,857.68 5,600.00 75.98 270.67 3,027.17 2,963.77 -298.32 -3,953.58 6,014,282.17 548,238.82 0.00 3,954.69 5,700.00 75.98 270.67 3,051.40 2,988.00 -297.18 -4,050.60 6,014,282.63 548,141.82 0.00 4,051.70 5,800.00 75.98 270.67 3,075.63 3,012.23 -296.04 -4,147.61 6,014,283.09 548,044.81 0.00 4,148.70 5,900.00 75.98 270.67 3,099.86 3,036.46 -294.91 -4,244.62 6,014,283.54 547,947.80 0.00 4,245.71 6,000.00 75.98 270.67 3,124.10 3,060.70 -293.77 -4,341.64 6,014,284.00 547,850.79 0.00 4,342.72 6,100.00 75.98 270.67 3,148.33 3,084.93 -292.64 -4,438.65 6,014,284.46 547,753.78 0.00 4,439.73 6,200.00 75.98 270.67 3,172.56 3,109.16 -291.50 -4,535.66 6,014,284.91 547,656.77 0.00 4,536.74 6,300.00 75.98 270.67 3,196.79 3,133.39 -290.36 -4,632.68 6,014,285.37 547,559.76 0.00 4,633.74 6,400.00 75.98 270.67 3,221.03 3,157.63 -289.23 -4,729.69 6,014,285.83 547,462.75 0.00 4,730.75 6,500.00 75.98 270.67 3,245.26 3,181.86 -288.09 -4,826.70 6,014,286.29 547,365.74 0.00 4,827.76 6,600.00 75.98 270.67 3,269.49 3,206.09 -286.95 -4,923.71 6,014,286.74 547,268.73 0.00 4,924.77 6,700.00 75.98 270.67 3,293.72 3,230.32 -285.82 -5,020.73 6,014,287.20 547,171.72 0.00 5,021.78 6,800.00 75.98 270.67 3,317.95 3,254.55 -284.68 -5,117.74 6,014,287.66 547,074.71 0.00 5,118.78 6,900.00 75.98 270.67 3,342.19 3,278.79 -283.54 -5,214.75 6,014,288.11 546,977.71 0.00 5,215.79 7,000.00 75.98 270.67 3,366.42 3,303.02 -282.41 -5,311.77 6,014,288.57 546,880.70 0.00 5,312.80 7,100.00 75.98 270.67 3,390.65 3,327.25 -281.27 -5,408.78 6,014,289.03 546,783.69 0.00 5,409.81 7,200.00 75.98 270.67 3,414.88 3,351.48 -280.14 -5,505.79 6,014,289.48 546,686.68 0.00 5,506.82 7,300.00 75.98 270.67 3,439.11 3,375.71 -279.00 -5,602.81 6,014,289.94 546,589.67 0.00 5,603.82 7,400.00 75.98 270.67 3,463.35 3,399.95 -277.86 -5,699.82 6,014,290.40 546,492.66 0.00 5,700.83 7,500.00 75.98 270.67 3,487.58 3,424.18 -276.73 -5,796.83 6,014,290.85 546,395.65 0.00 5,797.84 9/212015 2:19:37PM Page 5 COMPASS 5000.1 Build 73 HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPJ -28 Company: Hilcorp Energy Company TVD Reference: As -Built @ 63.40usft Project: Milne Point MD Reference: As -Built @ 63.40usft Site: M Pt J Pad North Reference: True Well: Plan: MPJ -28 Survey Calculation Method: Minimum Curvature Wellbore: MPJ -28 Design: MPJ -28 wp2 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) 3,448.41 7,600.00 75.98 270.67 3,511.81 3,448.41 -275.59 -5,893.84 6,014,291.31 546,298.64 0.00 5,894.85 7,700.00 75.98 270.67 3,536.04 3,472.64 -274.45 -5,990.86 6,014,291.77 546,201.63 0.00 5,991.86 7,740.16 75.98 270.67 3,545.77 3,482.37 -274.00 -6,029.82 6,014,291.95 546,162.67 0.00 6,030.81 Start Dir 5°/100' : 7740.16' MD, 3545.78'TVD 7,800.00 78.96 270.95 3,558.76 3,495.36 -273.17 -6,088.22 6,014,292.37 546,104.27 5.00 6,089.21 7,900.00 83.94 271.39 3,573.63 3,510.23 -271.15 -6,187.05 6,014,293.69 546,005.44 5.00 6,188.04 7,981.58 88.00 271.75 3,579.36 3,515.96 -268.92 -6,268.38 6,014,295.35 545,924.10 5.00 6,269.36 End Dir : 7981.58' MD, 3579.36' TVD 8,000.00 88.00 271.75 3,580.01 3,516.61 -268.36 -6,286.79 6,014,295.79 545,905.70 0.00 6,287.76 8,100.00 88.00 271.75 3,583.50 3,520.10 -265.31 -6,386.68 6,014,298.14 545,805.80 0.00 6,387.64 8,200.00 88.00 271.75 3,586.99 3,523.59 -262.26 -6,486.57 6,014,300.49 545,705.89 0.00 6,487.52 8,300.00 88.00 271.75 3,590.48 3,527.08 -259.20 -6,586.46 6,014,302.84 545,605.99 0.00 6,587.40 8,400.00 88.00 271.75 3,593.97 3,530.57 -256.15 -6,686.35 6,014,305.20 545,506.09 0.00 6,687.28 8,500.00 88.00 271.75 3,597.45 3,534.05 -253.10 -6,786.25 6,014,307.55 545,406.19 0.00 6,787.16 95181, 8,600.00 88.00 271.75 3,600.94 3,537.54 -250.05 -6,886.14 6,014,309.90 545,306.29 0.00 6,887.04 8,601.58 88.00 271.75 3,601.00 3,537.60 -250.00 -6,887.72 6,014,309.94 545,304.71 0.00 6,888.62 Start Dir 5°/100' : 8601.58' MD, 3601'TVD 8,673.67 91.60 271.70 3,601.25 3,537.85 -247.83 -6,959.76 6,014,311.60 545,232.66 5.00 6,960.65 End Dir : 8673.67' MD, 3601.25' TVD 8,700.00 91.60 271.70 3,600.51 3,537.11 -247.05 -6,986.07 6,014,312.20 545,206.35 0.00 6,986.96 8,704.76 91.60 271.70 3,600.38 3,536.98 -246.90 -6,990.83 6,014,312.31 545,201.59 0.00 6,991.71 Start Dir 5'/100': 8704.76' MD, 3600.38'TVD 8,725.13 90.63 272.00 3,599.98 3,536.58 -246.25 -7,011.18 6,014,312.83 545,181.23 5.00 7,012.07 Start Dir 4°/100' : 8725.13' MD, 3599.98'TVD 8,748.47 90.67 272.93 3,599.72 3,536.32 -245.24 -7,034.50 6,014,313.67 545,157.91 4.00 7,035.38 End Dir : 8748.47' MD, 3599.72' TVD 8,800.00 90.67 272.93 3,599.12 3,535.72 -242.61 -7,085.96 6,014,315.94 545,106.44 0.00 7,086.83 8,900.00 90.67 272.93 3,597.95 3,534.55 -237.49 -7,185.82 6,014,320.36 545,006.56 0.00 7,186.67 9,000.00 90.67 272.93 3,596.79 3,533.39 -232.37 -7,285.68 6,014,324.78 544,906.67 0.00 7,286.51 9,100.00 90.67 272.93 3,595.62 3,532.22 -227.26 -7,385.54 6,014,329.19 544,806.78 0.00 7,386.35 9,200.00 90.67 272.93 3,594.46 3,531.06 -222.14 -7,485.41 6,014,333.61 544,706.90 0.00 7,486.20 9,300.00 90.67 272.93 3,593.29 3,529.89 -217.02 -7,585.27 6,014,338.03 544,607.01 0.00 7,586.04 9,400.00 90.67 272.93 3,592.13 3,528.73 -211.91 -7,685.13 6,014,342.44 544,507.13 0.00 7,685.88 9,500.00 90.67 272.93 3,590.96 3,527.56 -206.79 -7,784.99 6,014,346.86 544,407.24 0.00 7,785.72 9,600.00 90.67 272.93 3,589.80 3,526.40 -201.67 -7,884.86 6,014,351.28 544,307.35 0.00 7,885.56 9,700.00 90.67 272.93 3,588.63 3,525.23 -196.56 -7,984.72 6,014,355.69 544,207.47 0.00 7,985.41 9,800.00 90.67 272.93 3,587.47 3,524.07 -191.44 -8,084.58 6,014,360.11 544,107.58 0.00 8,085.25 9,900.00 90.67 272.93 3,586.31 3,522.91 -186.32 -8,184.44 6,014,364.52 544,007.70 0.00 8,185.09 10,000.00 90.67 272.93 3,585.14 3,521.74 -181.21 -8,284.30 6,014,368.94 543,907.81 0.00 8,284.93 10,100.00 90.67 272.93 3,583.98 3,520.58 -176.09 -8,384.17 6,014,373.36 543,807.92 0.00 8,384.77 10,200.00 90.67 272.93 3,582.81 3,519.41 -170.98 -8,484.03 6,014,377.77 543,708.04 0.00 8,484.62 10,300.00 90.67 272.93 3,581.65 3,518.25 -165.86 -8,583.89 6,014,382.19 543,608.15 0.00 8,584.46 10,400.00 90.67 272.93 3,580.48 3,517.08 -160.74 -8,683.75 6,014,386.61 543,508.27 0.00 8,684.30 10,500.00 90.67 272.93 3,579.32 3,515.92 -155.63 -8,783.62 6,014,391.02 543,408.38 0.00 8,784.14 9/2/2015 2:19:37PM Page 6 COMPASS 5000.1 Build 73 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPJ -28 Company: Hilcorp Energy Company TVD Reference: As -Built @ 63.40usft Project: Milne Point MD Reference: As -Built @ 63.40usft Site: M Pt J Pad North Reference: True Well: Plan: MPJ -28 Survey Calculation Method: Minimum Curvature Wellbore: MPJ -28 Depth Inclination Design: MPJ -28 wp2 TVDss +N/ -S Planned Survey Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Measured Shape (°) (°) (usft) (usft) (usft) Vertical (usft) MPJ -28 wp2 heel 0.00 0.00 3,598.40 0.09 -6,887.78 Map Map plan misses target center by 249.99usft at 8609.17usft MD (3601.24 TVD, -249.77 N, -6895.30 E) Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,514.75 10,600.00 90.67 272.93 3,578.15 3,514.75 -150.51 -8,883.48 6,014,395.44 543,308.49 0.00 8,883.99 10,700.00 90.67 272.93 3,576.99 3,513.59 -145.39 -8,983.34 6,014,399.86 543,208.61 0.00 8,983.83 10,800.00 90.67 272.93 3,575.82 3,512.42 -140.28 -9,083.20 6,014,404.27 543,108.72 0.00 9,083.67 10,900.00 90.67 272.93 3,574.66 3,511.26 -135.16 -9,183.06 6,014,408.69 543,008.84 0.00 9,183.51 11,000.00 90.67 272.93 3,573.49 3,510.09 -130.04 -9,282.93 6,014,413.11 542,908.95 0.00 9,283.35 11,100.00 90.67 272.93 3,572.33 3,508.93 -124.93 -9,382.79 6,014,417.52 542,809.06 0.00 9,383.20 11,200.00 90.67 272.93 3,571.16 3,507.76 -119.81 -9,482.65 6,014,421.94 542,709.18 0.00 9,483.04 11,300.00 90.67 272.93 3,570.00 3,506.60 -114.69 -9,582.51 6,014,426.36 542,609.29 0.00 9,582.88 11,400.00 90.67 272.93 3,568.83 3,505.43 -109.58 -9,682.38 6,014,430.77 542,509.41 0.00 9,682.72 11,500.00 90.67 272.93 3,567.67 3,504.27 -104.46 -9,782.24 6,014,435.19 542,409.52 0.00 9,782.56 11,600.00 90.67 272.93 3,566.51 3,503.11 -99.35 -9,882.10 6,014,439.61 542,309.64 0.00 9,882.41 11,700.00 90.67 272.93 3,565.34 3,501.94 -94.23 -9,981.96 6,014,444.02 542,209.75 0.00 9,982.25 11,800.00 90.67 272.93 3,564.18 3,500.78 -89.11 -10,081.82 6,014,448.44 542,109.86 0.00 10,082.09 11,900.00 90.67 272.93 3,563.01 3,499.61 -84.00 -10,181.69 6,014,452.85 542,009.98 0.00 10,181.93 12,000.00 90.67 272.93 3,561.85 3,498.45 -78.88 -10,281.55 6,014,457.27 541,910.09 0.00 10,281.77 12,100.00 90.67 272.93 3,560.68 3,497.28 -73.76 -10,381.41 6,014,461.69 541,810.21 0.00 10,381.62 12,200.00 90.67 272.93 3,559.52 3,496.12 -68.65 -10,481.27 6,014,466.10 541,710.32 0.00 10,481.46 12,300.00 90.67 272.93 3,558.35 3,494.95 -63.53 -10,581.14 6,014,470.52 541,610.43 0.00 10,581.30 12,400.00 90.67 272.93 3,557.19 3,493.79 -58.41 -10,681.00 6,014,474.94 541,510.55 0.00 10,681.14 12,500.00 90.67 272.93 3,556.02 3,492.62 -53.30 -10,780.86 6,014,479.35 541,410.66 0.00 10,780.99 12,600.00 90.67 272.93 3,554.86 3,491.46 -48.18 -10,880.72 6,014,483.77 541,310.78 0.00 10,880.83 12,700.00 90.67 272.93 3,553.69 3,490.29 -43.06 -10,980.59 6,014,488.19 541,210.89 0.00 10,980.67 12,724.15 90.67 272.93 3,553.41 3,490.01 -41.83 -11,004.70 6,014,489.25 541,186.77 0.00 11,004.78 Start Dir 4°/100' : 12724.15' MD, 3553.41'TVD 12,725.22 90.64 272.90 3,553.40 3,490.00 -41.77 -11,005.77 6,014,489.30 541,185.70 4.01 11,005.85 TD at 12725.22 Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPJ -28 wp2 heel 0.00 0.00 3,598.40 0.09 -6,887.78 6,014,560.00 545,302.90 plan misses target center by 249.99usft at 8609.17usft MD (3601.24 TVD, -249.77 N, -6895.30 E) Point MPJ -28 wp2 toe 0.00 0.00 3,553.40 -41.77 -11,005.77 6,014,489.30 541,185.70 plan hits target center Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (') (") 8,500.00 3,597.45 9 5/8" 9-5/8 12-1/2 12,725.22 3,553.40 51/2" 5-1/2 6 9/2/2015 2:19:37PM Page 7 COMPASS 5000.1 Build 73 HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Milne Point Site: M Pt J Pad Well: Plan: MPJ -28 Wellbore: MPJ -28 Design: MPJ -28 wp2 Plan Annotations Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well Plan: MPJ -28 As -Built @ 63.40usft As -Built @ 63.40usft True Minimum Curvature Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 280.00 280.00 0.00 0.00 Start Dir 2°/100' : 280' MD, 280'TVD 480.00 479.84 -4.20 -5.57 Start Dir 30/100' : 480' MD, 479.84'TVD 1,080.00 1,062.06 -85.09 -112.92 Start Dir 41/100' : 1080' MD, 1062.06'TVD 1,919.42 1,734.34 -218.63 -576.40 End Dir : 1919.42' MD, 1734.34' TVD 2,615.10 2,171.56 -276.77 -1,114.38 Start Dir 4°/100' : 2615.1' MD, 2171.56'TVD 3,288.92 2,467.14 -324.58 -1,711.54 End Dir : 3288.92' MD, 2467.14' TVD 7,740.16 3,545.77 -274.00 -6,029.82 Start Dir 51/100' : 7740.16' MD, 3545.78'TVD 7,981.58 3,579.36 -268.92 -6,268.38 End Dir : 7981.58' MD, 3579.36' TVD 8,601.58 3,601.00 -250.00 -6,887.72 Start Dir 51/100' : 8601.58' MD, 36017VD 8,673.67 3,601.25 -247.83 -6,959.76 End Dir : 8673.67' MD, 3601.25' TVD 8,704.76 3,600.38 -246.90 -6,990.83 Start Dir 51/100' : 8704.76' MD, 3600.38'TVD 8,725.13 3,599.98 -246.25 -7,011.18 Start Dir 4°/100' : 8725.13' MD, 3599.98'TVD 8,748.47 3,599.72 -245.24 -7,034.50 End Dir : 8748.47' MD, 3599.72' TVD 12,724.15 3,553.41 -41.83 -11,004.70 Start Dir 4°/100' : 12724.15' MD, 3553.41'TVD 12,725.22 3,553.40 41.77 -11,005.77 TD at 12725.22 Halliburton Standard Proposal Report 9/2/2015 2:19:37PM Page 8 COMPASS 5000.1 Build 73 Hilcorp Energy Company Milne Point M Pt J Pad Plan: MPJ -28 MPJ -28 MPJ -28 wp2 Sperry Drilling Services Clearance Summary Anticollision Report 02 September, 2015 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt J Pad - Plan: MPJ -28 - MPJ -28 - MPJ -28 wp2 Well Coordinates: 6,014,608.14 N, 552,189.84 E (700 27'02.33" N, 149' 34' 27.09" W) Datum Height: As -Built @ 63.40usft Scan Range: 0.00 to 12,725.22 usft. Measured Depth. Scan Radius is 1,469.52 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPJ -28 - MPJ -28 wp2 Hilcorp Energy Company Milne Point Closest Approach 313 Proximity Scan on Current Survey Data (North Reference) 7,447.97 854.55 7,447.97 Reference Design: M Pt J Pad - Plan: MPJ -28 - MPJ -28 - MPJ -28 wp2 9,863.00 4.362 Centre Distance Pass - Scan Range: 0.00 to 12,725.22 usft. Measured Depth. 7,450.00 854.55 7,450.00 Scan Radius is 1,469.52 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited 4.362 Ellipse Separation Pass - Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) lush) (usft) usft M Pt 1 Pad MPI -14 - MPI -14 - MPI -14 7,447.97 854.55 7,447.97 658.66 9,863.00 4.362 Centre Distance Pass - MPI -14 - MPI -14 - MPI -14 7,450.00 854.55 7,450.00 658.63 9,863.00 4.362 Ellipse Separation Pass - MPI -14 - MPI -14 - MPI -14 7,500.00 856.13 7,500.00 659.44 9,863.00 4.353 Clearance Factor Pass - MPI -I4 -MPI -14L1 -MPI -141-1 7,418.84 765.61 7,418.84 573.28 9,910.00 3.981 Centre Distance Pass - MPI -I4 -MPI -141 -1 -MPI -141-1 7,425.00 765.63 7,425.00 573.21 9,910.00 3.979 Ellipse Separation Pass - MPI -14 - MPI -141-1 - MPI -141-1 7,475.00 767.66 7,475.00 574.48 9,910.00 3.974 Clearance Factor Pass - MPI -14 - MPI -141-2 - MPI -141-2 7,444.50 780.85 7,444.50 550.29 9,768.00 3.387 Centre Distance Pass - MPI -14 - MPI -141-2 - MPI -141-2 7,450.00 780.87 7,450.00 550.21 9,768.00 3.385 Ellipse Separation Pass - MPI -14 - MPI -141-2 - MPI -141-2 7,500.00 782.82 7,500.00 551.26 9,768.00 3.381 Clearance Factor Pass - MPI -14 - MPI -141-21382 - MPI-14L2PB2 7,464.50 932.66 7,464.50 690.07 9,594.00 3.845 Centre Distance Pass - MPI -14 - MPI-14L2PB2 - MPI-14L2PB2 7,475.00 932.71 7,475.00 689.93 9,594.00 3.842 Ellipse Separation Pass - MPI -14 - MPI-14L2PB2 - MPI-141-2PB2 7,525.00 934.62 7,525.00 690.90 9,594.00 3.835 Clearance Factor Pass - M Pt J Pad MPJ -03 -MPJ -03 -MPJ -03 1,525.00 254.26 1,525.00 237.13 1,633.32 14.842 Clearance Factor Pass - MPJ -03 - MPJ -03 - MPJ -03 1,563.96 253.05 1,563.96 236.16 1,666.09 14.984 Ellipse Separation Pass - MPJ -05 - MPJ -05 - MPJ -05 318.53 89.26 318.53 84.89 325.64 20.418 Centre Distance Pass - MPJ -05 - MPJ -05 - MPJ -05 475.00 90.81 475.00 80.09 481.65 8.471 Ellipse Separation Pass - MPJ -05 - MPJ -05 - MPJ -05 600.00 95.69 600.00 83.79 606.18 8.038 Clearance Factor Pass - MPJ -06 - MPJ -06 - MPJ -06 342.93 208.99 342.93 205.11 346.60 53.785 Centre Distance Pass - MPJ -06 - MPJ -06 - MPJ -06 475.00 210.04 475.00 200.97 477.87 23.148 Ellipse Separation Pass - / MPJ -06 - MPJ -06 - MPJ -06 750.00 222.65 750.00 212.28 749.84 21.471 Clearance Factor Pass - MPJ -07 - MPJ -07 - MPJ -07 30.00 29.58 30.00 28.65 36.79 31.926 Centre Distance Pass - MPJ -07 - MPJ -07 - MPJ -07 275.00 31.32 275.00 23.05 281.53 3.785 Ellipse Separation Pass - MPJ -07 - MPJ -07 - MPJ -07 475.00 36.55 475.00 25.54 480.83 3.320 Clearance Factor Pass - MPJ -09 - MPJ -09 - MPJ -09 362.33 148.34 362.33 143.81 354.07 32.790 Centre Distance Pass - MPJ -09 - MPJ -09 - MPJ -09 475.00 149.26 475.00 139.99 466.27 16.111 Ellipse Separation Pass - MPJ -09 - MPJ -09 - MPJ -09 625.00 154.48 625.00 144.41 613.73 15.339 Clearance Factor Pass - 02 September, 2015 - 14:18 Page 2 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPJ -28 - MPJ -28 wp2 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Pass - 16.111 Ellipse Separation Pass - 15.339 Clearance Factor Reference Design: M Pt J Pad - Plan: MPJ -28 - MPJ -28 - MPJ -28 wp2 194.147 Centre Distance Pass - 23.840 Ellipse Separation Pass - 19.377 Clearance Factor Scan Range: 0.00 to 12,725.22 usft. Measured Depth. 30.982 Centre Distance Pass - 28.915 Ellipse Separation Pass - 21.467 Clearance Factor Scan Radius is 1,469.52 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Pass - 16.874 Ellipse Separation Pass - Measured Minimum @Measured Ellipse @Measured Site Name Depth Distance Depth Separation Depth Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usff MPJ -09 -MPJ -09A -MPJ -09A 362.33 148.34 362.33 143.81 365.39 MPJ -09 - MPJ -09A- MPJ -09A 475.00 149.26 475.00 139.99 477.59 MPJ -09 -MPJ -09A -MPJ -09A 625.00 154.48 625.00 144.41 625.05 MPJ -12 - MPJ -12 - MPJ -12 30.00 179.40 30.00 178.48 31.59 MPJ -12 - MPJ -12 - MPJ -12 275.00 180.31 275.00 172.75 275.06 MPJ -12 - MPJ -12 - MPJ -12 650.00 194.01 650.00 184.00 642.81 MPJ -13 - MPJ -13 - MPJ -13 30.00 119.73 30.00 118.65 31.60 MPJ -13 - MPJ -13 - MPJ -13 275.00 119.95 275.00 112.37 276.22 MPJ -13 - MPJ -13 - MPJ -13 600.00 128.58 600.00 118.66 598.26 MPJ -16 - MPJ -16 - MPJ -16 742.45 219.99 742.45 212.91 729.21 MPJ -16 - MPJ -16 - MPJ -16 775.00 220.23 775.00 212.83 758.58 MPJ -16 - MPJ -16 - MPJ -16 1,025.00 245.60 1,025.00 235.71 971.34 MPJ -16 - MPJ -16A Plan - MPJ -16A Wp 3.0 742.45 219.99 742.45 213.02 734.81 MPJ -16 - MPJ -16A Plan - MPJ -16A Wp 3.0 775.00 220.23 775.00 212.94 764.18 MPJ -16 - MPJ -16A Plan - MPJ -16A Wp 3.0 1,025.00 245.60 1,025.00 235.81 976.94 MPJ -17 - MPJ -17 - MPJ -17 184.45 209.10 184.45 205.60 185.75 MPJ -17 - MPJ -17 - MPJ -17 300.00 210.01 300.00 202.46 297.10 MPJ -17 -MPJ -17 -MPJ -17 5,725.00 1,277.98 5,725.00 1,091.14 5,415.93 MPJ -18 - MPJ -18 - MPJ -18 690.35 179.45 690.35 173.66 666.41 MPJ -18 - MPJ -18 - MPJ -18 725.00 179.68 725.00 173.46 698.35 MPJ -18 -MPJ -I8 -MPJ -18 1,025.00 212.05 1,025.00 202.17 963.31 MPJ -19 - MPJ -19 - MPJ -19 836.94 154.06 836.94 145.51 817.02 MPJ -19 - MPJ -19 - MPJ -19 875.00 154.47 875.00 145.32 851.35 MPJ -I9 -MPJ -I9 -MPJ -19 1,875.00 279.85 1,875.00 257.63 1,785.13 MPJ -19 - MPJ -19A- MPJ -19A 836.94 154.06 836.94 145.51 817.02 MPJ -19 - MPJ -19A- MPJ -19A 875.00 154.47 875.00 145.32 851.35 MPJ -19 -MPJ -19A -MPJ -19A 1,875.00 279.85 1,875.00 257.63 1,785.13 MPJ -20 - MPJ -20 - MPJ -20 945.44 142.39 945.44 136.56 851.83 MPJ -20 - MPJ -20 - MPJ -20 975.00 142.58 975.00 136.31 878.97 MPJ -20 -MPJ -20 -MPJ -20 7,175.00 448.94 7,175.00 163.30 7,101.10 Hilcorp Energy Company Milne Point Clearance Summary Based on Factor Minimum Separation Warning 32.790 Centre Distance Pass - 16.111 Ellipse Separation Pass - 15.339 Clearance Factor Pass - 194.147 Centre Distance Pass - 23.840 Ellipse Separation Pass - 19.377 Clearance Factor Pass - 110.831 Centre Distance Pass - 15.830 Ellipse Separation Pass - 12.956 Clearance Factor Pass - 31.063 Centre Distance Pass - 29.755 Ellipse Separation Pass - 24.815 Clearance Factor Pass - 31.550 Centre Distance Pass - 30.201 Ellipse Separation Pass - 25.091 Clearance Factor Pass - 59.761 Centre Distance Pass - 27.821 Ellipse Separation Pass - 6.840 Clearance Factor Pass - 30.982 Centre Distance Pass - 28.915 Ellipse Separation Pass - 21.467 Clearance Factor Pass - 18.012 Centre Distance Pass - 16.874 Ellipse Separation Pass - 12.597 Clearance Factor Pass - 18.012 Centre Distance Pass - 16.874 Ellipse Separation Pass - 12.597 Clearance Factor Pass - 24.437 Centre Distance Pass - 22.755 Ellipse Separation Pass - 1.572 Clearance Factor Pass - 02 September. 2015 - 14:18 Page 3 of 8 COMPASS HALLIBURTON Hilcorp Energy Company Milne Point Anticollision Report for Plan: MPJ -28 - MPJ -28 wp2 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt J Pad - Plan: MPJ -28 - MPJ -28 - MPJ -28 wp2 Scan Range: 0.00 to 12,725.22 usft. Measured Depth. Scan Radius is 1,469.52 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Welfbore Name - Design (usft) (usft) (usft) (usft) usft MPJ -20 - MPJ -20A- MPJ -20A 945.44 142.39 945.44 136.56 916.05 24.433 Centre Distance Pass - MPJ -20 - MPJ -20A- MPJ -20A 975.00 142.58 975.00 136.31 943.19 22.751 Ellipse Separation Pass - MPJ -20 - MPJ -20A- MPJ -20A 6,850.00 456.52 6,850.00 246.05 6,860.25 2.169 Clearance Factor Pass - MPJ -21 - MPJ -21 - MPJ -21 1,485.98 103.51 1,485.98 87.29 1,435.17 6.382 Centre Distance Pass - MPJ -21 - MPJ -21 - MPJ -21 1,525.00 103.78 1,525.00 86.75 1,472.75 6.096 Ellipse Separation Pass - MPJ -21 - MPJ -21 - MPJ -21 4,325.00 353.61 4,325.00 255.87 4,398.08 3.618 Clearance Factor Pass - MPJ -22 - MPJ -22 - MPJ -22 1,287.23 43.07 1,287.23 30.87 1,280.33 3.530 Centre Distance Pass - MPJ -22 - MPJ -22 - MPJ -22 1,300.00 43.22 1,300.00 30.65 1,292.41 3.439 Ellipse Separation Pass - MPJ -22 - MPJ -22 - MPJ -22 1,325.00 44.37 1,325.00 31.25 1,316.12 3.381 Clearance Factor Pass - MPJ -23 - MPJ -23 - MPJ -23 253.05 541.70 253.05 534.57 251.95 75.921 Centre Distance Pass - MPJ -23 - MPJ -23 - MPJ -23 12,375.00 841.92 12,375.00 346.58 12,062.00 1.700 Ellipse Separation Pass - MPJ -23 - MPJ -23 - MPJ -23 12,400.00 842.40 12,400.00 346.77 12,062.00 1.700 Clearance Factor Pass - MPJ -23 - MPJ -23L1 - MPJ -231-1 253.05 541.70 253.05 535.21 251.95 83.476 Centre Distance Pass - MPJ -23 - MPJ -23L1 - MPJ -231-1 12,450.00 871.37 12,450.00 406.66 12,127.00 1.875 Clearance Factor Pass - MPJ -23 - Plan: MPJ -23A - MPJ -23A wp3 253.05 541.70 253.05 535.11 255.65 82.157 Centre Distance Pass - MPJ -23 -Plan: MPJ -23A -MPJ -23A wp3 275.00 541.74 275.00 534.13 275.72 71.206 Ellipse Separation Pass - MPJ -23 -Plan: MPJ -23A -MPJ -23A wp3 12,725.22 1,030.35 12,725.22 606.84 12,453.65 2.433 Clearance Factor Pass - MPJ -26 - MPJ -26 - MPJ -26 916.03 123.55 916.03 117.96 886.12 22.129 Centre Distance Pass - MPJ -26 - MPJ -26 - MPJ -26 2,650.00 139.05 2,650.00 84.17 2,532.38 2.534 Ellipse Separation Pass - MPJ -26 - MPJ -26 - MPJ -26 2,725.00 142.60 2,725.00 85.58 2,606.48 2.501 Clearance Factor Pass - / MPJ -26 - MPJ -261-1 - MPJ -26L1 916.03 123.55 916.03 117.96 886.12 22.129 Centre Distance Pass - MPJ -26 - MPJ -261-1 - MPJ -26L1 2,650.00 139.05 2,650.00 84.17 2,532.38 2.534 Ellipse Separation Pass - MPJ -26 - MPJ -261-1 - MPJ -261-1 2,725.00 142.60 2,725.00 85.58 2,606.48 2.501 Clearance Factor Pass - MPJ -26 - MPJ -26L2 - MPJ -261-2 916.03 123.55 916.03 117.96 886.12 22.129 Centre Distance Pass - MPJ -26 - MPJ -26L2 - MPJ -261-2 2,650.00 139.05 2,650.00 84.17 2,532.38 2.534 Ellipse Separation Pass - MPJ -26 - MPJ -261-2 - MPJ -261-2 2,725.00 142.60 2,725.00 85.58 2,606.48 2.501 Clearance Factor Pass - MPJ -26 - MPJ-26PB1 - MPJ-26PB1 916.03 123.55 916.03 117.96 886.12 22.129 Centre Distance Pass - MPJ-26-MPJ-26PB1-MPJ-26PB1 2,650.00 139.05 2,650.00 84.17 2,532.38 2.534 Ellipse Separation Pass - MPJ -26 - MPJ-26PB1 - MPJ-26PB1 2,725.00 142.60 2,725.00 85.58 2,606.48 2.501 Clearance Factor Pass - MPJ -26 - MPJ-26PB2 - MPJ-26PB2 916.03 123.55 916.03 117.96 886.12 22.129 Centre Distance Pass - 02 September, 2015 - 14:18 Page 4 of 8 COMPASS Hilcorp Energy Company HALLIBURTON Mine Pont Anticollision Report for Plan: MPJ -28 - MPJ -28 wp2 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt J Pad - Plan: MPJ -28 - MPJ -28 - MPJ -28 wp2 Scan Range: 0.00 to 12,725.22 usit. Measured Depth. Scan Radius is 1,469.52 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name DepthDistance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPJ -26 - MPJ-26PB2 - MPJ-26PB2 2,650.00 139.05 2,650.00 84.17 2,532.38 2.534 Ellipse Separation Pass - MPJ -26 - MPJ-26PB2 - MPJ-26PB2 2,725.00 142.60 2,725.00 85.58 2,606.48 2.501 Clearance Factor Pass - Plan: MPJ -27 - MPJ -27 - MPJ -27 WP3 275.00 60.43 275.00 52.80 277.60 7.915 Centre Distance Pass - Plan: MPJ -27 - MPJ -27 - MPJ -27 WP3 275.01 60.43 275.01 52.80 277.61 7.915 Ellipse Separation Pass - Plan: MPJ -27 - MPJ -27 - MPJ -27 WP3 500.00 66.93 500.00 57.29 500.00 6.944 Clearance Factor Pass - M Pt N Pad MPN-01 - MPN-01 - MPN-01 10,592.55 592.82 10,592.55 424.81 3,570.83 3.528 Centre Distance Pass - MPN-01 - MPN-01 - MPN-01 10,600.00 59287 10,600.00 424.79 3,570.71 3.527 Clearance Factor Pass - MPN-01 - MPN-01A- MPN-01A 10,470.68 231.17 10,470.68 93.71 3,803.96 1.682 Centre Distance Pass - MPN-0I-MPN-01A-MPN-01A 10,500.00 232.95 10,500.00 92.99 3,798.03 1.664 Clearance Factor Pass- MPN-01 - MPN-018 - MPN-01B 10,775.00 327.83 10,775.00 173.96 3,788.26 2.131 Clearance Factor Pass - MPN-01 - MPN-01B - MPN-01B 10,800.00 326.22 10,800.00 173.86 3,795.97 2.141 Ellipse Separation Pass - MPN-01 - MPN-016 - MPN-01B 10,810.62 326.07 10,810.62 174.37 3,799.27 2.149 Centre Distance Pass - SUNBV tool proOram From To Su"eylPlan Survey Tool (usft) (usft) 30.00 400.00 MPJ -28 wp2 MWD _Interp Azi+sag 400.00 8,601.58 MPJ -28 wp2 MWD+IFR2+MS+sag 8,601.58 12,725.07 MPJ -28 wp2 MWD+IFR2+MS+sag 02 September, 2015 - 14:18 Page 5 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPJ -28 - MPJ -28 wp2 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Energy Company Milne Point 02 September, 2015 - 14.:16 Page 6 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPJ -28 - MPJ -28 wp2 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to As -Built @ 63.40usft. Northing and Easting are relative to Plan: MPJ -28. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is -150,00°, Grid Convergence at Surface is: 0.40 °. Hilcorp Energy Company Milne Point Ladder - -- - T -- -- -- - - i -- - - i -- - - -- -- - - - -i - - -- - - - - -i- - - MPI -14, MPI14L2PI32, L2P82V1 PJ -03 MPJ-03,MPJ-03V1 �(- MPJ -05, MPJ -05, MPJ -05 V 1 $ MPJ -06, MPJ -06, MPJ -06 V1 - - - - - - - - - - MPJ-07,MPJ-07,MPJ-07V1 I i I X13 i I -��- MPJ -09, MP,! -09, MPJ -09 V1 $ MPJ-09,MPJ-09A,PJ-09AV2 p $ MPJ-12,MPJ-12,MRL12V1 -------- -- - --- - -- - - ----- -- - - - - -- $ MPJ -1 3.MRN3,MPJ-13V1 $ MPJ -1 6, MPJ -1 6, MPJ -1 6 V1 p i i YA I $ PJ-16,PJ-16APlan, P.116AWp3.OV12 m 900 $ MP.1-17,MPJ-17,MPJ•17V1 � i i t1 i $ MPJ18,MPJ-18,MP.!-18V2 ) i $ MP.LI9,MP.EI9,MPJ-19V1 - - -- ----- - -I---- ----------�--- $ MP,! - 19, MP.P19A, MPJ -19A VO $MPJ20,MPJ20,MPF20V1 U 4510 $ MPJ -20, PJ -20A, MPJ -20A V8 O $ -MPJ -21V3 $ MPJ -22, PJ -22, MPJ -22 V4 - MPJ-23,PJ-23,MPJ-23 V2 C - - --------L------------------I----------�---- $ PJ-23,PJ-23L1,PJ-23L1V2 U -� MPJ -23, Plan: MPJ-23A,PJ-23Awp3 V0 $ MPJ -26, MPJ -26, MPJ -26 V5 12500 0 2500 5000 7500 10000 $ MP,-26,MR126L1,PJ-26L1V3 3- MPJ -26, MPJ -26L2, PJ -261_2 V4 Measured Depth (2500 usfdin) -¢ MP.L26,PJ-26PB1,PJ-26PB1 V3 02 September. 2015 - 14:18 Paye 7 of 8 COMPASS HALLIBURTON Anticollision Report for Plan: MPJ -28 - MPJ -28 wp2 Clearance Factor Plot: Measured Depth versus Separation(Clearance) Factor Hilcorp Energy Company Milne Point $ MPLI4,MPL14L2PB2,MPL14L2PB2V1 -4- MPJ -03, MPJ -03, MPJ -03 V1 $ MPJ-05,MPJ-05,MPJ-05VII $ MPJ -06, MPJ -06, MPJ -06 V1 -0- MPJ-07,MPJ-07,MPJ-07V1 -I- MPJ -09, MPJ -09, MPJ -09 V 1 MPJ -09, MPJ -09A, MPJ -09A V2 $ MPJ-12,MPJ-12,MPJ-12V1 $ MPJ-13,MP,LI3,MP,L13V1 -0- MPJ-16,MPJ-16,MPJ-16V1 $ MPJ-16.MPJ-16A Plan, MRL16AWp3.0V12 $ MPJ-17,MPJ-17,MPJ-17V1 MPJ-18,MPJ-18,MPJ-18V2 -� MPJ-19,MRL19,MP.L19V1 -W MPJ -19, MP l -19A, MPJ -19A V0 $ MPJ-20,MPJ-20,MPJ-20VII $ MPJ-20,MPJ-20A,MPJ-20AV8 $ MPJ-21,MP.F21,MPJ-21 V3 ♦f MPJ -22, MPJ -22, MPJ -22 V4 -)(- MPJ-23,MRY23,MPJ-23V2 $ MPJ-23,MPJ-231-1,MPJ-231-1V2 -� MPJ -23, Plan: MPJ-23A,MPJ-23Awp3V0 -)(- MPJ-26,MPJ-26,MPJ-26V5 $ MPJ-26,MPJ-261-1,MPJ-26L1V3 } MPJ -26, MPJ -26L2, MPJ -261-2 V4 MPJ26,MPJ-26PB1,MPJ-26PB1 V3 02 September, 2015 - 14.:18 Page 8 o/8 COMPASS „ II�I11111 !�Il�l��i�■i:,, �i1 "„ ►1 °•�:,,�III!!■�I■[I ■■1 I���'II��I1� ` ISOIrmoMIN! , �'■�`1 � 11�1�'■�11 I■I�■■ I■ "MEn `'`•MI � Y,Collision Avoidance Re ■■■�■■■■■■■' ----------------------------------- Hilcorp Energy Company Milne Point $ MPLI4,MPL14L2PB2,MPL14L2PB2V1 -4- MPJ -03, MPJ -03, MPJ -03 V1 $ MPJ-05,MPJ-05,MPJ-05VII $ MPJ -06, MPJ -06, MPJ -06 V1 -0- MPJ-07,MPJ-07,MPJ-07V1 -I- MPJ -09, MPJ -09, MPJ -09 V 1 MPJ -09, MPJ -09A, MPJ -09A V2 $ MPJ-12,MPJ-12,MPJ-12V1 $ MPJ-13,MP,LI3,MP,L13V1 -0- MPJ-16,MPJ-16,MPJ-16V1 $ MPJ-16.MPJ-16A Plan, MRL16AWp3.0V12 $ MPJ-17,MPJ-17,MPJ-17V1 MPJ-18,MPJ-18,MPJ-18V2 -� MPJ-19,MRL19,MP.L19V1 -W MPJ -19, MP l -19A, MPJ -19A V0 $ MPJ-20,MPJ-20,MPJ-20VII $ MPJ-20,MPJ-20A,MPJ-20AV8 $ MPJ-21,MP.F21,MPJ-21 V3 ♦f MPJ -22, MPJ -22, MPJ -22 V4 -)(- MPJ-23,MRY23,MPJ-23V2 $ MPJ-23,MPJ-231-1,MPJ-231-1V2 -� MPJ -23, Plan: MPJ-23A,MPJ-23Awp3V0 -)(- MPJ-26,MPJ-26,MPJ-26V5 $ MPJ-26,MPJ-261-1,MPJ-26L1V3 } MPJ -26, MPJ -26L2, MPJ -261-2 V4 MPJ26,MPJ-26PB1,MPJ-26PB1 V3 02 September, 2015 - 14.:18 Page 8 o/8 COMPASS TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: 0215 Development _ Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: 46i_ oin,�_ POOL: Ahit-Q01v- S '( A!"ZlJ 04 Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - function (If last two digits Production should continue to be reported as a of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -) from records, data and logs acquired for well (name onpen-nit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where sam les are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Well Name: MILNE PT UNIT SB J-28 _ Program DEV_ _ _ Well bore seg ❑ PTD#:2151570 Company HILCORP ALASKA LLC Initial Class/Type DEV / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal El - Administration Administration 17 Nonconven, gas conforms to AS31,05.030Q.1_.AW.2.A-D) NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - -- - - - - 1 Permit fee attached _NA_ _ - - - - - - - - - - - - - - - - - - 2 Lease number appropriate Yes --- ADL0025906, Surf Loc; ADL0025517,Top Prod-IMerv. & TD._ - . - _ - --------- 3 Unique well name and number - - - - -- - -- --- - - - - - Yes - --- ---MPUJ-28---- - ---- --- - -- - - - - - - - - - - -- --- - - -- - - - - - - - -- - - - - 4 Well located in_a_defined _pool Yes _ MILNE POINT, SCHRADER BLFF- OIL - 525140, governed by Conservation Order No. 477.05 5 Well located proper distance from drilling unit -boundary_ ..... Yes - .. - _ - CO 477.05 contains no spacing restrictions with respect to drilling unit_ boundaries, - - 6 Well located proper distance_ from other wells- Yes CO 477.05 has no interwell spacing restrictions._ I7 Sufficient acreage_ available in -drilling unit _ - _ - _ . Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 8 If deviated, is wellboreplat_included ---- --__ Yes. ----------- --------------------------- 9 Operator only affected party_ Yes - - - - - - We] -lb -ore -will be_more than 500' from an external property line_ where_ ownership or landowners hip_ changes._ _ 110 Operator has -appropriate- bond in force - - - - - - - - - - - - - - - - - - - - - - ----- Yes - - - _ _ _ _ _ _ _ _ - - - - - - _ - _ - - - - - - - - - - - - - - - - - - - - - - - . - . - . _ - - _ - - - - - Appr Date i11 Permit_can be issued without conservation order_ - - - - _ - _ _ - - - - - - - - - . Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - -- 12 Permit -can beissuedwithoutadministrativ_e_appr_oval- - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - --- - - -- _ _ - - _ _ - - - - - - _ - - - - - - _ . - - - - - -- _ _ _ _ _ - - - - - PKB 9/4/2015 13 Can permit be approved before 15-daywait---------------- - - Yes_ - - _ _ _ - - - - - _ - - - - - _ - - - - - - - - - _ - _ - - - - - - - - - - - - - - - - - 114 Well located within area and strata authorized by Injection Order # (put_ 10# in. comments)_ (For_ NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - -- - - - - - - - 15 All wells -within -114 milearea_of review identified (For service well only) - - - - - - _ - - - - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 16 Pre -produced injector: duration -of pre production less than 3 months- (For service well only) - NA_ _ - - _ - - - - . - - - . 18 Conductor string- provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - _ _ _ _ _ _ 20" conductor set -at 80 ft - - - - _ _ - - - _ - - - - - _ .. - - - - - . - - - - - - - . - - - _ - Engineering 19 Surface casing -protects all_known USDWs - _ _ _ ----------- NA_ _ - - - - - _ No Aquifers.. Permafrost area._ _ _ _ - - _ . - - 20 CMT_ vol adequate_ to circulate -on conductor & surf_csg - - - - - - - - - - - - - - -- - Yes _ - _ - _ _ _ 9 5/8" casing will be fully cemented. 2_stage cunt job. _ _ _ - - _ _ _ _ _ - - _ _ _ - - - - - 21 CMT_vol adequate to tie -in -long string to -surf csg---------------- - -- Yes _ - _ _ _ _ _ surface -casing will be set in- Schrader Bluff_ NB sand._And 7.5/8" tieback casing run_for_IA._ 22 _C_MT_will coverall -known -productive horizons_ _ _ _ _ _ _ - - - . _ No_ _ _ _ _ _ _ . horizontal Lateral with wire -wrap screen liner set__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 23 Casing designs adequate for CJ, B &_ permafrost- - - - - - - - - - - - - - - - - - - - . Yes _ _ _ _ _ _ _ BTC calculations provided. - - - - _ - - - - - - - _ - - - - - - - - - - - - - - - . - - - - . - _ _ - _ - - - - - - 24 Adequate tankage or reserve pit - - - - - - - _ - - - _ - - - - Yes - - - - - - - Rig has steel pits.. All waste to -approved disposal well. 25 If_a_ re -drill, has_ a 10-403 for abandonment been approved - - - - - - - - - - - - - - NA_ - - - - - - - grassroots well._ 4 well pilot -program for NB sand 26 Adequate wellbore separation _proposed _ _ _ _ _ _ _ - - Yes - - - - - - - Proximity analysis performed. No issues- - - - - - - - - - - - - - - - - - - - - - 27 If_ diverterrequired,doesitmeetregulations- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes_ - - - __Diverteris16"_.._Mapoflayoutprovided-- - _ - - - - - _ - - _ - - - - - - - - - - _ _ - - - - - - - - - - - - Appr Date 28 Drilling fluid_ program schematic_& equip list adequate_ _ - - - - - _ - - _Yes _ - - - _ _ _Max formation_ pressure =_1609 psi (8,6_ppg EMW) Will drill with 8.8-9.2_ ppg mud _ _ _ - _ _ GLS 9/16/2015 29 BOPEs,_do they meet regulation _ .. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - Yes - - _ - - - Nordic 3 has 11" 5000_psi-BOPE_ 3 ram 1 annular _ - _ _ _ - - - 30 13 -0 -PE -press rating appropriate; test to -(put prig in comments)- - - - - - - - - - - - - - - - - - - Yes - - - - - - MASP= 1250 psi Will test -ROPE -to 3000 psi (annular to- 2500 psi)_ - - - _ 31 Choke_ manifold complies w/API_ RP -53 (May 84)- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 32 Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ -- - - - _ - - - _ _ _ - - - - - - - - - - _ _ - - - _ - - - _ _ - - - - - - - - - - - - - - - - - - - - - - - - - 33 Is presence of H2S gas probable - - - - - --------------------------- Yes _ _ _ - - _ _ H2S on pad. Rig -has sensors and_alarms._ - - - _ - - - - - .------------------- 34 -Mechanical-condition of wells within AOR verified (For service well only) - - - - - - - - - - - - - - -NA_ - _ - - - - - - - - - - - - - - - - - - - _ _ _ - - - - _ - - - - - - - - - _ - - - - - - - - - - - - - _ _ _ - - - - - - - - - - - 35 Permit can be issued w/o hydrogen_ sulfide measures - - - - - - - - - - - - - - - - - - - - - - - - No_ - _ _ - - - - H2S measures required- _ _ - - - - _ - - - - - - - - - - - - - - _ _ _ _ _ - _ - - - - - - - - _ - _ - - Geology 36 -Data-presented on potential overpressure zones - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - _ - _ _ - - Expected reservoir pressure is B_6_ppg EMW; will_be drilled using 8.8 to -9.2 ppg mud. - - - - - Appr Date 37 Seismic -analysis of shallow gas -zones- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - PKB 9/4/2015 38 Seabed condition survey -(if off -shore) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA- - - - - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 39 Contact-name/phone for weekly -progress reports_ [exploratory only] - - - - - - - - - - - - - - - - - NA_ Onshore development to be drilled. - - - _ - - - - - - - - - - - - - - - - - - - - - - - _ - - - - - - - - - - - - - - - Geologic Engineering Public Horizontal lateral in NB sand using wire wrapped screens. 1 of 4 pilot wells to determine If NB are viable zone in Schrader bluff. Commissioner: Date: Commissioner: Date Commissioner Date GIs
