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Home My WebLink About216-151MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, October 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-32 MILNE PT UNIT B-32 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/22/2025 B-32 50-029-23570-00-00 216-151-0 N SPT 4394 2161510 1500 173 177 174 172 518 1615 1590 1591 OTHER P Josh Hunt 9/12/2025 This was a solid test, there was some pressure fluctuation near the end of the test. This 2-year MIT-OA is required by CO 808 and sundry 323-462; tested to 1500 psi per email approval from Mel Rixse 9/22/23. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT B-32 Inspection Date: Tubing OA Packer Depth 2048 2061 2032 2042IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH250912122956 BBL Pumped:0.8 BBL Returned:0.8 Wednesday, October 22, 2025 Page 1 of 1          1-OIL jet pump completion    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: Conductor Retrofit 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): 10,265' N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi Liner N/A 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 PT UNIT B-32 MILNE POINT SCHRADER BLUFF OIL N/A 4,251' 6,541' 4,367' 993 6,541' Subsequent Form Required: 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 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 4/1/2024 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL047438 / ADL047437 216-151 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23570-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 107' 107' 12.6 / L-80 / EUE 8rd TVD Burst 5,400' MD N/A N/A 5,750psi 6,890psi 4,396' 4,394' 4,253' 5,606' 5,416' 107' 20" 9-5/8" 7-5/8" 5,606' 4-1/2"4,386' 5,416' Perforation Depth MD (ft): 10,223' See Schematic See Schematic 4-1/2" D&L Hyd Perm., BOT SLZP LTP & Tendeka Swell (2) and N/A Ryan Thompson ryan.thompson@hilcorp.com 907-564-5280 5,066 MD/ 4,304 TVD, 5,413 MD/ 4,393 TVD, 5,705 MD/ 4,390 TVD & 5,778 MD/ 4,384 TVD and N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.03.01 15:23:56 - 09'00' Taylor Wellman (2143) By Grace Christianson at 9:03 am, Mar 04, 2024 SFD 3/4/2024 10-404 DSR-3/4/24MGR20MAR24JLC 3/20/2024 Wellhead Retrofit Well: MPU B-32 Well Name:MPU B-32 API Number:50-029-23570-00 Current Status:Operable RC JP Pad:B-Pad Estimated Start Date:4/1/2024 Rig:WSS Reg. Approval Reqd?Yes Date Reg. Approval Recvd: Regulatory Contact:Tom Fouts Permit to Drill Number:216-151 First Call Engineer:Ryan Thompson (907) 564-5005 (O) (907) 301-1240 (M) Second Call Engineer:Scott Pessetto (907) 564-4373 (O) (801) 822-2203 (M) AFE Number:Job Type:Wellhead Repair Current Bottom Hole Pressure: 1,418 psi @ 4,251 TVD Gauge B-28 9-2-22, 6.4 PPGE Maximum Expected BHP: 1,418 psi @ 4,251 TVD Gauge B-28 9-2-22, 6.4 PPGE MPSP: 993 psi (0.1 psi/ft gas gradient) Min ID: 3.725 ID 4-1/2 XN Nip at 5,117 MD Max Dev: 96° @ 6,990 MD Brief Well Summary: The Milne Point B-32 was drilled and cased as a Schrader Bluff production well in March 2017 & a RWO performed in Sept 2023 to convert from a GL producer to JP producer. The wells surface casing was fully cemented during drilling with a 2 stage cement job and hung off a slip style casing hanger as part of a conductor supported wellhead system. The system has since been identified as having the potential to cause wellhead movement in the event of conductor subsidence. In order to fully tie well load back to the single 9-5/8 casing string, the conductor will be cut and a reverse acting slip style hanger assembly will be installed. Notes Regarding Wellbore Condition MIT-IA passed to 3,000 psi on 9/26/2023. MIT-OA passed to 1500 psi on 9/25/2023. Well is currently online and producing. XN nipple @ 5,117 is @ ~70°. SL pulled the RHC plug body from 5,117 on 9/28/23 prior to setting the JP. Objective: Cut conductor bell nipple below starting head and install Seaboard Reverse Slip Loc assembly to ensure fully supported by surface casing. Procedure: Pre-Sundry Work Slickline & Fullbore 1. MIRU SL unit. 2. Pull 13B jet pump from 4,908 MD. 3. Set XX plug in XN nipple @ 5,117 MD. 4. Circulate PF into IA/T to fluid pack. 5. Pump 104 bbls Freeze Protect into IA & U-Tube. 6. CMIT-TxI to 1500 psi. 7. MIT-OA to 1500 psi. 8. RDMO Wellhead Retrofit Well: MPU B-32 Prep Work 9. Disconnect flowline and instrumentation. 10. Verify tubing, IA & OA pressures have been bled to 0 psi. 11. 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. 12. Vac out gravel from well cellar down to cellar liner to remove residual hydrocarbons. 13. Install fire blankets around well to prevent hot debris from falling downhole. Sundry Work (Approval required to proceed) Surface Casing Support Retrofit Note: Photo Document Repair Work on a Daily Project Timeline. 14. 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. 15. Flush conductor with water from the conductor starting head valve and while taking fluid returns from the cement return line bull plug. Flush with hot diesel until clean returns are observed. 16. Move in and rig up Well Support Structure. Place rig mats as needed to level out support structure legs. 17. Install BPV and nipple down tree at master valve or tubing head adapter as needed to makeup Wellhead Support Structure adapter flange. 18. Prepare to transfer load to the Well Support Structure. Pretension load cells according to operating manual. 19. Pull 8,000 lbs (Wellhead Weight) gradually building up load in 1,000 lb increments. a. Monitor the wellhead for any signs of movement and discontinue increasing tension if movement observed. 20. Increase weight up to 60,000 lbs (50 K preloading) 21. 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, 4 ½ tubing, 7 5/8 tieback and wellhead load = 12.6#*5400 + 29.7#*5413 + 8K = 237K b. Maintain constant vertical displacement while well support structure is loaded by well. 22. Proceed to cut conductor bell nipple below the starting head and then remove conductor bell nipple section. a. Ensure minimum of 12 of clearance between bottom of starting head and top of conductor. b. Record Well Support Structure Load in WSR once conductor fully loaded. 23. Leave remaining bell nipple section engaged in starting head. Bevel as needed to ensure smooth entry of slip assembly. 24. Place each half of Reverse Slip Loc assembly around surface casing, bolt halves together. 25. Install energizing plate halves at 90 degree offset from slip assembly such that joint between halves are perpendicular to slips. 26. Lift Reverse Slip Loc up inside conductor starting head. 27. In a crisscross 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. 28. Mark casing at the bottom of the Reverse Slip Loc 29. Release tension, observe for any slippage. If slipping occurs, retension and tighten bolts to 150 ft-lbs. 30. Once load is released to Reverse Slip Loc, conduct MIT-OA to 1,500 psi to confirm integrity is unchanged. 31. Unbolt and remove the adapter flange. Wellhead Retrofit Well: MPU B-32 32. Reinstall 5K production tree. 33. Remove BPV and install TWC. Pressure test tree to 5,000 psi. 34. Re-install flowline and instrumentation. 35. Weld centralizer/landing ring onto top of conductor. 36. Reinstall well house and backfill gravel over cellar liner. 37. Install Corrosion Inhibitor in SC by Conductor Annulus up to the conductor top. Slickline 38. MIRU SL unit. 39. RIH and pull XX plug from 5,117 MD. 40. Set new JP (sizing per OE). 41. Turn well back over to operations. Attachments: 1. Wellbore Schematic Wellhead Retrofit Well: MPU B-32 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/30/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231130 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 11/13/2023 YELLOW JACKET GPT BCU 13 50133205250000 203138 10/5/2023 YELLOW JACKET PERF KBU 13-08 50133203040000 177029 10/16/2023 YELLOW JACKET CALIPER KU 12-17 50133205770000 208089 10/4/2023 YELLOW JACKET CALIPER/TEMP KU 24-7RD 50133203520100 205099 10/4/2023 YELLOW JACKET CALIPER MPU B-32 50029235700000 216151 9/20/2023 YELLOW JACKET RCT MPU L-47 50029235500000 215117 10/25/2023 YELLOW JACKET CUT NS-05 50029232440000 205009 9/9/2023 YELLOW JACKET PERF NS-16A 50029230960100 206141 9/12/2023 YELLOW JACKET PERF NS-20 50029231180000 202188 9/11/2023 YELLOW JACKET PERF NS-24 50029231110000 202164 9/10/2023 YELLOW JACKET PATCH PTM P1-13 50029223720000 193074 10/24/2023 YELLOW JACKET PL Please include current contact information if different from above. T38164 T38164 T38165 T38166 T38167 T38168 T38169 T38170 T38171 T38172 T38173 T38174 12/1/2023 YELLOW MPU B-32 50029235700000 216151 9/20/2023 JACKET RCT Kayla Junke Digitally signed by Kayla Junke Date: 2023.12.01 10:42:44 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Replace 7-5/8" Tieback Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:Convert to Rev.Circ Jet pump Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,265 feet N/A feet true vertical 4,251 feet N/A feet Effective Depth measured 6,541 feet feet true vertical 4,367 feet feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / L-80 / EUE 8rd 5,400' 4,392' D&L Hyd. Perm BOT SLZXP LTP Packers and SSSV (type, measured and true vertical depth)Tendeka Swell (2)N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Scott Pessetto Contact Email:scott.pessetto@hilcorp.com Authorized Title: Wells Manager Contact Phone: 907-564-4373 Length 4,386' Casing Conductor 4,253'10,223' 5,413' 5,606'Surface Tieback Liner 20" 9-5/8" 7-5/8" 107' 5,606' N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL047438 / ADL047437 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT B-32 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 216-151 50-029-23570-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC 206 189 measured TVD 4-1/2" Plugs Junk measured N/A 5,750psi 6,890psi N/A 5,413' 4,393' Burst N/A 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 396 Gas-Mcf MD 107' 690 Size 107' 4,396' 178 2580235 194 192 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure Collapse N/A 3,090psi 4,790psi 5,066, 5,413, 5,705 & 5,778 4,304, 4,393, 4,390 & 4,384 323-462 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 18 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 2:43 pm, Oct 30, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.10.30 12:49:11 - 08'00' Taylor Wellman (2143) DSR-11/2/23 RBDMS JSB 110823 WCB 4-26-2024 _____________________________________________________________________________________ Revised By: TDF 10/27/2023 SCHEMATIC Milne Point Unit Well: MPU B-32 Last Completed: 6/21/2018 PTD: 216-151 TD =10,265’ (MD) / TD =4,251’(TVD) 20” Orig. KB Elev.: 49.4’/ GL Elev.: 22.9’ RKB –THF: 23.13’ (Innovation) 7-5/8” 6 109-5/8” 1 2 PBTD =10,259’ (MD) / TD = 4,251’(TVD) 9-5/8” ‘ES’ Cementer @ 2,011’ 7 4-1/2” Shoe @ 10,265’ 8 & 9 14 15 4-1/2” 3 5 11 13 Min ID 3.725” Perf 5,730’- 5,736’ 4 12 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34” Conductor (Insulated) 78.6 / A-53 / Weld N/A Surface 106.5’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.835” Surface 5,606’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Vam STL 6.875” Surface 5,413' 0.0459 4-1/2” Liner (250ђ Screens) 13.5 / 13Cr-110 / Vam Top HT 3.920” 5,837’ 10,223’ 0.0149 TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / EUE 8rd 3.958” Surface 5,400’ 0.0152 OPEN HOLE / CEMENT DETAIL 42” 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4” 1st stage 590 sx 11.7# Extenda, 210 sx 15.8# SwiftCEM 12-1/4” 2nd stage 311 sx 10.7# Perm L, 280 sx 15.8# SwiftCEM 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 264’ Max Hole Angle = 60.33 deg. @ XN profile Max Hole Angle = 85.98 deg. @ Tubing tail Max Hole Angle = 95.75 deg. @ 6,990’ 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. JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 17’ Tubing Hanger (3-1/2” EUE Top & Btm) 3.958 2 4,908’ Sliding Sleeve w/ Blanked Port for Tech Wire 3.958 3 4,963’ 4-1/2” X Nipple 3.813 4 5,013’ BHP Gauge 3.958 5 5,066’ 7-5/8” x 4-1/2” D&L Hyd. Perm Packer 3.958 6 5,117 4-1/2” XN-Nipple w/ RHC Installed –Min ID 3.725”3.725 7 5,539’ WLEG – Btm @ 5,400’ 3.958 Lower Completion 8 5,403’ 7-5/8” Tieback Assy. (8.25” OD No-Go @ 5,404’) 6.151” 9 5,413’ BOT SLZXP Liner Top Packer w/BD Slips 7” x 9-5/8” 6.160” 10 5,438’ 7” Hydril 563 x 4-1/2” Hydril 521 L-80 XO 3.900” 11 5,705’ 5-1/2” 17# Tendeka Swell Packer, Hybrid (10.88’ Long) 4.767” 12 5,778’ 5-1/2” 17# Tendeka Swell Packer, Hybrid (10.90’ Long) 4.767” 13 5,837’ 4-1/2” Weatherford MaxFlo 316L 250 Micron RTD Screens (117 jts) 3.795” 14 10,230’ 4-1/2” Drillable Packoff Sub 2.400” 15 10,259’ WIV Valve LTC BxB (1.5” Ball on Seat/Closed;Btm @ 10,265’)- NOTE: Perf holes at 5,730’-5,736’ shot with 2-3/8” 5 spf/60 deg GeoDynamics Razor Cement Squeeze #1: 30 bbl 15.8 ppg w/ minimal squeeze pressure Cement Squeeze #2: 30 bbl 15.8 ppg w/ cement entering 4-1/2” liner GENERAL WELL INFO API: 50-029-23570-00-00 Drilled, Cased & Completed by Innovation – 3/10/2017 Coil Cement Squeeze – 4/24/2018 Cement Clean-out – 2/25/2018 Convert to Rev. Circ. Jet Pump and R&R Tieback by ASR – 9/28/2023 Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 ASR 50-029-23570-00-00 216-151 9/17/2023 9/28/2023 Pump 400 BBL down TBG 3BPM @ 120 psi. Started getting gas/ crude back. Take returns to flowback tank. Continued pumping. until reached 2X B/U. Shut down pumps and monitor well. TBG and IA on vac. TBG went static and IA continued to be on vacuum. Pull Hanger to floor and lay down. Perform derrick inspection. POOH W/ 3-1/2" EUE GLM completion. F/ 5421' T/ 3,972' Tubing showing extensive corrosion & holes in pipe F/ JT # 68 - 41. AT JT # 40 tubing parted leaving 1,351' of pipe left in the hole. 123 joints recovered & 3 GLM. Top of parted tubing depth = 4,072.58'. Mobilize fishing tools and E-line to location. SimOps. Fill hole with 70 BBLs. Obtain static lose rate. Hole losing 111 BPH. Rack and tally workstring joints. Pump down OA , pump 20 bbls of 8.4 ppg source water at 1 BPM at 35 psi. Fill pits, change handling equip. for fishing run. Wait on tools for town. P/U & M/U overshot fishing BHA. OS, BS, OJ, & 8 4.75" DC. XO to 2-7/8" IF workstring. T/ 284'. Service rig, check equip. fluid levels. RIH w/ overshot fishing BHA. F/ 284' T/ 4,072' Pump double displacement for pipe tripped in. No operations to report. 9/16/2023 - Saturday Spot rig on mud boat and level out. Continue to move equipment from C-pad to B-bad. Torque up BOPs Spot in change house and Co. man office. Spot in catwalk. Rig up flow spool and riser spools. Rig up tong rack and tongs. Spot in pipe sheds. Function test BOPs. take on fresh water for testing. Prep for BOP test. During Shell test found wellhead gland nut leaking. Wellhead hands tightened all gland nuts & proceeded with testing. Test BOPE as per approved sundry. Test T/ 250 psi low & 2500 psi high f/ 5/5 charted mins. AOGCC waived witness of test. Preformed accumulator drawdown. Monitor well with IA open during all testing. (well on a vacuum). B/D test lines & R/D. Service rig. Check equip. fluid levels. Change elevators to slip type 3-1/2". Inspect & ID handling equip. Changed out service loop cover. Run TD up & down, ensure fitment. P/U tee bar & pull CTS. Well on a vacuum. Pull BPV. L/D tee bar. P/U 3-1/2" EUE landing Jt & engage into hanger. Stab TIW & M/U circ. equip on top of landing JT. P/U to release PKR. P/U wt = 135k total before PKR released. Shut annular & begin pumping bottoms up at 3 BPM W/ 120 psi 9/19/2023 - Tuesday 9/17/2023 - Sunday On B-pad spot in mud boat. Begin MIRU. On C-pad. N/U tree & torque. Perform final checks. Test 500 psi low & 5000 psi high F/ 5/10 min test (good test) Pressure under BPV, plan to lubricate out, moblizie equip. Remove matting boards. Rig down pits & road to B-pad. Secure C pad. On B-pad. Spot in crane. Fly cellar over BOPE. Fly Floor onto cellar, Spot in pits. 9/18/2023 - Monday 9/15/2023 - Friday No operations to report. 9/13/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 9/14/2023 - Thursday No operations to report. POOH W/ 3-1/2" EUE GLM completion Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 ASR 50-029-23570-00-00 216-151 9/17/2023 9/28/2023 9/22/2023 - Friday Cont. RIH w/ 7-5/8" test PKR F/ 3,818' T/ 5,260'. Pump double displacement for pipe tripped in. Set down 10k. P/U & line up to pump. Wash down F/ 5,260' T/ 5,400' at 3 BPM w/ 300 psi. Set test PKR at 5,400'. Attempt to pressure test 7-5/8" casing. Pressure not holding & OA pressure increasing. Pump down IA returning through OA to flush out FP. Perform a CMIT on 9-5/8" X 7-5/8" annulus. Pressure up to 1500 psi. Hold for 30 charted mins. (good test on 9-5/8" casing). Service rig, check equip. fluid levels. B/D test lines. Pump out F/ 5,400' T/ 5,180' at 3 bpm w/ 300 psi. POOH w/ 7-5/8" test PKR F/ 5,180' T/ 17' Pump double displacement for pipe tripped out. L/D Test PKR & inspect. All components intact. Pump 20 bbls down well. Shut blinds & lock in. Bleed down accumulator. Change top rams to 7-5/8" solid bodies. Spot crane. Fly 7-5/8" elevators to floor & handling equip. Remove rig tongs f/ rig floor. P/U 7-5/8" test joint. M/U test plug. Pump 10 bbls down well. Open IA, set test plug. Perform shell test. Good. Shut rams & attempt to pressure test. 7-5/8" ram pressure test not holding. Cycle rams shut 6x attempt test, Cycle & flush stack. Look over ram locks. Pressure visual & audibly leaking through rams. Bleed off & blowdown stack. Remove test jt & plug. Pump 10 bbls down well. Shut blinds & lock in. Bleed of accumulator, Open rams. No visual damage on rubbers. Change ram rubbers with new vendor supply. Shut ram doors & pressure up accumulator. P/U 7-5/8" test Jt. Set test plug. Fill stack. 9/20/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Install pups for space out on workstring, Continue down to 4,072'. establish parameters. P/U 51K, S/O 30K ,R/T 40K. Engage fish @ 4,072' and swallow 2' pull up to 15K over. Connection 1' below floor. Swivel off fish. lay down 2 joints install another 5' pup. RIH and engage fish. 3' of swallow. P/U 15 K over set slips. R/U E-line W/ RCT cutter. Begin RIH. RIH t/ 4981' Correlate with tally. Stop depth = 4961.7' CCL to cutter = 17.3' Putting the cut at 4,979'. Anchor & cut tubing. Had overpull. Pulled Free. POOH w/ E-line. On surface L/D tools. RCT fired. P/U string. Pull up to 67K. Free P/U wt = 60K. Tubing is cut. Pull 2 JTs & space out pups. Stop for rig service. Rig service. Check equip. fluid levels. POOH w/ overshot BHA & tubing fish. F/ 4,979' T/ 284'. Pump double displacement for pipe tripped out. L/D Over shot BHA. Recovered 27 JTs of 3-1/2" EUE & 4.2' cut pup. Indicating cut at 4,981'. Remove 3-1/2" tubing from shed. Remove fished joint from overshot & change grapple in overshot. Load drill collars in shed. P/U & M/U overshot fishing BHA # 2. OS, BS, OJ, & 8 x 4.75" DC. XO to 2-7/8" IF workstring. T/ 284'. Service rig, Check equip. fluid levels. RIH w/ overshot fishing BHA #2. F/ 284' T/ 4,983' Pump double displacement for pipe tripped in. 9/21/2023 - Thursday Swallow over tubing stub to 4,987' P/U to 140 K set in slips. Allow jars to fire. P/U out of slips PKR free. P/U wt = 72K - 90K P{KR dragging. Pump down tubing. Tubing plugged. Pressure up to 2,000 psi. P/U hole swabbing. Work pipe with PKR. 20' stroke attempt to fully release PKR. Fill backside. Cont. to pressure up tubing to 2500 psi. Tubing becoming clear. No longer swabbing while picking up string. PKR fully released. Circ at 3 BPM w/ 350 psi. Pump a total of 380 bbls. Monitor well. Service rig. Check equip. fluid levels. Monitor well. R/D pump line & B/D. POOH w/ overshot BHA & PKR fish. F/ 4987' T/ 284' Pump double displacement for pipe tripped out. L/D Over shot BHA # 2. ACC jar, 8x 4.75" DC, HYD jar, BS, OS & fish. L/D ovshot with PKR. Recovered 13 JTs of 3-1/2" EUE XN, PKR & cut pup. All 3-1/2" completion recovered. All joints showing sign of corrosion, pitting & holes. P/U overshot & attempt to break out fish. Unsuccessful, ship to town for removal. P/U & M/U 7-5/8" test PKR. Inspect. Rack & tally work string. RIH w/ 7-5/8" test PKR T/ 420'. Set PKR & fill backside. Proof test PKR to 1,000 psi. (Good test). Service rig. Check equip. fluid levels. Monitor well. RIH w/ 7-5/8" test PKR F/ 420' T/ 3,000'. Fill backside & set PKR. Test casing to 1500 psi f/ 30 charted mins. (good test). B/D lines. Cont. RIH w/ 7-5/8" test PKR F/ 3,000' T/ 3,818'. Pump double displacement for pipe tripped in. Indicating cut at 4,981'. Recovered 27 JTs of 3-1/2" EUE & 4.2' cut pup Putting the cut at 4,979'. Anchor & cut tubing All 3-1/2" completion recovered. Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 ASR 50-029-23570-00-00 216-151 9/17/2023 9/28/2023 Hilcorp Alaska, LLC Weekly Operations Summary Test 7-5/8" solid body rams w/ new rubbers t/ 250 psi low & 2500 psi high F/ 5/5 charted mins. (good test). B/O spacer & flow spools. Fly off rig floor. Fly casing jacks & R/U CSG equip. Install hyd hoses to CSG jacks. Function test CSG jacks,. P/U pack off retrieval tool. Pull Pack off w/ 12k. L/D packoff. Screw landing JT in CSG hanger. Service rig, check equip. fluid levels. BOLDS. w/ CSG jacks, jack out hanger w/ 154K P/U wt. NO overpull observed. W/ CSG jacks. Jack out of hole. F/ 5,424' T/ 5,016' No overpull observed. Pump double displacement. POOH on elevators F/ 5,016' T/ 3,610' No overpull observed. Pump double displacement. Service rig, check equip. fluid levels. POOH on elevators F/ 5,016' T/ 2,200' No overpull observed. Pump double displacement. 9/23/2023 - Saturday Cont. to wash down F/ 5,120' T/ 5,365' Pumping down 7-5/8" at 1.5 BPM w/ 44 psi. No returns to surface. P/U wt = 160K S/O wt = 93K. Attempt to engage seals in to tieback. Mule shoe tagging on LT. Rotate pipe & pump dw w/ 1.5 BPM w/ 45-65 psi. P/U wt = 165K S/O wt = 92K. Nogo on locator x2. Make mark and space out. Pull jts #134 -133. P/U space out pups M/U casing hanger & land. Pressure up backside to 1500 psi, pressure holding. Bleed off t/ 250 psi. P/U until ports are exposed & pressure bleeds off. Space out correct. Keep seal assy. above tieback. R/U to pump CI KCL & FP w/ LR pump truck. Pump 100 bbls 1% KCL w CI. Followed by 40 bbls of FP diesel. Pump down back side taking returns up 7-5/8" to tiger tank. Returned 65 bbls. Bled off OA. Engage seals into tieback, land CSG hanger w/ 75K SO wt due to seal drag. Free SO wt = 92K. End of seal at 5,410'. Remove landing jt. P/U pack off running tool. Set pack off w/ 8k down. RILDS. Pump plastic to engage inner seals as per seaboard wellhead. Test void to 500 psi low & 5000 psi high f/ 5/10 mins. Good test. Test 9-5/8" x 7-5/8" annulus "OA" to 1,500 psi f/ 30 charted mins. Good test. Prep for crane work, B?D choke & kill lines. R/D CSG equipment. R/D casing jacks. W/ crane fly CSG equip. off floor & CSG jacks off floor. W/ crane Fly rig tongs & tong rack to floor & R/U. Fly flow/spacer spools to floor & floor plate. Torque up spools. C/O pipe rams to 2-7/8" x 5" variables. Simops. R/U hydraulic lines to tongs. R/U elevators to set test plug. P/U test tools. 9/24/2023 - Sunday POOH on elevators F/ 2,200' T/ surface No overpull observed. Pump double displacement. L/D seal assy. Prep to RIH. Strap & tally 7-5/8" STL to be rerun. P/U new tieback seals. Service rig, check equip fluid levels. RIH on elevators T/ 2,859' Pump double displacement. XO to HYD 521 29.7#. P/U wt = 74K S/O wt = 58K. RIH on elevators F/ 2,859' T/ 4,407' Pump double displacement. P/U wt = 120K S/O wt = 86K. Service rig, check equip fluid levels. RIH on elevators F/ 4,407' T/ 5,108' Pump double displacement. P/U wt = 140K S/O wt = 88K. Tag obstruction at 5,108' Setting down 50k. Free P/U wt = 140K no overpull. S/O = 93K. Set down higher at 5,106'. Pick up & attempt to S/O set down mark becoming higher. Pump 26 bbls down backside. S/O to previous set down mark. S/O weight increasing back to previous. Able to RIH T/ 5,120' Cont. to wash down. 9/25/2023 - Monday Pull Pack off w/ 12k. L/D packoff. Screw landing JT in CSG hanger. Service rig, check equip. fluid levels. BOLDS. w/ CSG jacks, jack out hanger w/ 154K P/U wt Engage seals into tieback, land CSG hanger w/ 75K SO wt due to seal drag POOH on elevators F/ 2,200' T/ surface No overpull observed. Pump double displacement. L/D seal assy. Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 ASR 50-029-23570-00-00 216-151 9/17/2023 9/28/2023 Hilcorp Alaska, LLC Weekly Operations Summary Test 2-7/8" x 5" rams w/ 4-1/2" Test joint. t/ 250 psi low & 2500 psi high f/ 5/5 charted mins. P/U Tec line sheave & clamps. Rack& tally completion jewelry & 4-1/2" 12.6# EZGO TBG. M/U WLEG, 7 JTS of 4-1/2" 12.6# EZGO, XN, 1 JT, 7-5/8" x 4-1/2" perm PKR, JT, BPH gauge (attach TEC line), JT, X NIP, JT, & SS. T/ 500'. Service rig. Check Equip. Fluid Levels. RIH W/ 4-1/2" Jet pump completion. T/ 600' Gauge rep. notified clmaps not compatible w/ size line. POOH to replace clamps dw to BHP gauge. POOH W/ 4-1/2" Jet pump completion. T/ 387' Reinstall correct clamps as per BHP gauge Rep. RIH W/ 4-1/2" Jet pump completion. F/ 387' T/ 4,633' Pumping over double displacement. P/U wt = 58K S/O wt = 28K. Service rig. Check Equip. Fluid Levels. RIH W/ 4-1/2" Jet pump completion. F/ 387' T/ 4,633' Pumping over double displacement. Tag obstruction at 5,367' Setting down 5k. Free P/U wt = 63K no overpull. S/O = 35K. Pick up & attempt to S/O, set down mark becoming higher by 3' Line up to wash down. Wash down f/ 5,367' t/ 5,415' Pumping down 4-1/2" at 1.5 BPM w/ 74 psi. No returns to surface. P/U wt = 63K S/O wt = 33K. Tag XO (3.958" ID) in lower completion. P/U to space out. POOH 3 joints. Install Pup, M/U JT # 158. P/U hanger. P/U wt 63K. M/U landing jt. Line up to reverse CI brine. Final check on gauge (good) before terminating TEC line through hanger. 9/26/2023 - Tuesday W/ 4-1/2" Jet pump completion. Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 WH & Slickline 50-029-23570-00-00 216-151 9/17/2023 9/28/2023 No operations to report. No operations to report. 9/30/2023 - Saturday No operations to report. 10/3/2023 - Tuesday 10/1/2023 - Sunday No operations to report. 10/2/2023 - Monday 9/29/2023 - Friday No operations to report. 9/27/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Land TBG hanger w/ 35K, P/U WT =63K. RILDS.; Reverse in 80 bbls CI 1% KCL brine. Followed by 52 bbls of 8.4ppg source water.; Drop ball & rod. Pressure up to 4000 psi set PKR.; MIT- T at 4000 psi hold for 30 charted min (good test) Bled TBG off to 1500 psi. MIT- IA pressure up to 3,000 psi hold for 30 charted mins. (good test); P/U Tee bar & set BPV. R/D rig floor equipment of completion Equip. Rig released f/ B-32 at 12:00 9-27-23. 9/28/2023 - Thursday WELLHEAD: MU LJ TC11 4 1/2" to Tbg Hgr , land to RKB, RILDS . Set CTS Bpv with Dry rod. ND BOP stack, clean hgr void install CTS plug and R54 gasket.. PU tree/adapter and run tech line through adapter CL port while landing. Torque to spec, and tesy tbg hgr void to 500/5000 (PASS) Test tree, pull CTS plug and 4" Bpv( NO Pressure) Install tree cap, all valves in closed position. WEL S/I ON ARRIVAL PRESSURE TEST PCE TO 3,000 PSI (pass). RAN KJ, 5' x 1-7/8", 4-1/2" 42 BO (keys down), SD @4,947' SLM (4,920' MD), SHIFTED SLIDING SLEEVE OPEN. RAN 2" JU, PULLED BALL & ROD FROM 5100'MD. RAN 4-1/2" GR PULLED RHC PLUG BODY. RAN 4-1/2" X-LINE W/13B JET PUMP. WELL S/I ON DEPARTURE, LOCATION INSPECTED, DSO NOTIFIED, CLOSE PERMIT. MIT- IA pressure up to 3,000 psi hold for 30 charted mins. (good test); Land TBG hanger w/ 35K, P/U WT =63K. RILDS.; Reverse in 80 bbls CI 1% KCL brine. Followed by 52 bbls of 8.4ppg source water.; Drop ball & rod. Pressure up to 4000 psi set PKR.; MIT- T at 4000 psi hold for 30 charted min (good test) Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/04/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231004 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# IRU 41-01 50283200880000 192109 9/17/2023 HALLIBURTON Coilflag KBU 32-06 50133206580000 216137 9/8/2023 HALLIBURTON PPROF LRU C-02 50283201900000 223057 9/13/2023 HALLIBURTON RBT MPU E-37 50029236160000 218158 9/24/2023 READ Caliper Survey MPU F-53A 50029225780100 213136 9/27/2023 READ Caliper Survey MPU F-79 50029228130000 197180 9/26/2023 READ Caliper Survey MPU L-57 50029236090000 218072 9/26/2023 READ Caliper Survey MPU S-06 50029231630000 203109 9/29/2023 READ Caliper Survey MPU B-32 50029235700000 216151 9/12/2023 HALLIBURTON Perf TBU K-09 50733201100000 1068038 10/1/2023 READ Caliper Survey Please include current contact information if different from above. T38028 T38029 T38030 T38031 T38032 T38033 T38034 T38035 T38036 T38037 10/4/2023 MPU B-32 50029235700000 216151 9/12/2023 HALLIBURTON Perf Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.04 13:03:04 -08'00' 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:Convert to Rev.Circ Jet pump 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): 10,265'N/A Casing Collapse Conductor N/A Surface 3,090psi Tieback 4,790psi Liner N/A 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: Brian Glasheen Contact Email: Contact Phone: Authorized Title: 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 SCHRADER BLUFF OIL N/A 4,251' 6,541' 4,367' 993 6,541' 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 B-32 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 8/28/2023 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL047438 / ADL047437 216-151 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23570-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 107' 107' 9.3 / L-80 / EUE 8rd TVD Burst 5,422' MILNE POINT MD N/A N/A 5,750psi 6,890psi 4,396' 4,394' 4,253' 5,606' 5,416' 107' 20" 9-5/8" 7-5/8" 5,606' 4-1/2"4,386' 5,416' 7-5/8" Tri-Point DLH & BOT SLZXP and N/A 4,985 MD/ 4,270 TVD & 5,416 MD/ 4,394 TVD and N/A Brian.Glasheen@hilcorp.com 907-564-5277 Perforation Depth MD (ft): 10,223' See Schematic See Schematic 3-1/2" No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Wells Manager By Grace Christianson at 4:01 pm, Aug 14, 2023 323-462 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.08.14 14:31:03 - 08'00' Taylor Wellman (2143) SFD 8/25/2023MGR18AUG23 * BOPE pressure test to 2500 psi. Annular to 2500 psi. * Approved for reverse circulating jet pump. * 30 minute charted CMIT-IA or MIT-IA to 3000 psi. * 30 minute charted pressure test on OA to 1500 psi. * Fluid filled OA pressure monitoring. *IA SSV high pressure trip pressure not to exceed 3000 psi. IA low pressure trip pressure to be no lower than 50% of maximum header injection pressure. * Tubing SSV low pressure trip not to be lower than 75 psi. * SSV closure on IA will initiate closure within 2 minutes on SSV on tubing and visa versa. * Biennial MIT-OA to maximum header injection pressure. 993 DSR-8/14/23 10-404 *&: 08/28/23Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2023.08.28 16:22:01 -08'00' RBDMS JSB 082923 Convert to Reverse Circulating JP Well: MPB-32 PTD: 216-151 Well Name:MPU B-32 API Number:50-029-23570-00-00 Current Status:GL producer Rig:ASR 1 Estimated Start Date:8/28/ 2023 Estimated Duration:5days Reg.Approval Req’d? Yes Date Reg. Approval Rec’vd:TBD Regulatory Contact:Tom Fouts Permit to Drill Number:216-151 First Call Engineer:Brian Glasheen 907-545-1144 (M) Second Call Engineer:Taylor Wellman 907-947-9533 AFE Number:232-00929 Current Bottom Hole Pressure:1418 psi @ 4251’ TVD 6.4 PPGE | Gauge B-28 09-2-22 Maximum Expected BHP:1418 psi @ 4251’ TVD 6.4 PPGE Max. Anticipated Surface Pressure:993 psi Gas Column Gradient (0.1 psi/ft) Min ID:2.75” @ 5031’ XN Nipple Brief Well Summary MPU B-32 was drilled and completed in the Schrader Bluff N-sands in 2018. The well was completed as a single lateral with 250-micron screens and a gas lift completion. The well recently failed a MIT-OA and will require a RWO to fix the casing leak. The well will be converted to a reverse circulating JP completion after the casing repair to add additional drawdown to the well. Objective The primary objective of the RWO is to pull tubing and casing, replace casing below lowest GLM and complete as a reverse circulating Jet pump producer. Planned SSV Pilot Settings x Power fluid SSV high pressure trip will not exceed 3000 psi x Power fluid SSV low pressure trip will be set to 50 percent of header pressure x Production SSV high pressure trip not to exceed 650 psi x Production SSV low pressure trip not to be below 75 psi Non-Sundried Work: Pre-Rig Procedure: Slickline- 1) Displace TBG to hot fluid. 2) Run Tubing Caliper to assess tubing condition. 3) Pull st 1 GLV for circulation during RWO 4) Pull TTP from XN Well Support- 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 3. Pressure test lines to 3,000 psi. 4. Circulate at least one wellbore volume with 8.4 ppg produced water or source water down tubing, taking returns up casing to 500 bbl returns tank. Heat fluids to help with thick crude prior to circulating. a. If returns are not seen, after attempting circulation down the tubing, bullhead and load the tubing, IA and OA. 5. RD Little Red Services and reverse out skid. SFD 8/251/2023 Convert to Reverse Circulating JP Well: MPB-32 PTD: 216-151 6. RU crane. Set CTS BPV. ND Tree. NU BOPE. RD Crane. 7. NU BOPE house. Spot mud boat. Brief RWO Procedure Sundry work: 8. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines. 9. Check for pressure. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/ 8.4 produced water/ Source water prior to setting CTS Plug. Set CTS Plug. 10. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR rams on 3-1/2’’ test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 11. Contingency: (If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Mel Rixse (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 12. Bleed any pressure off tubing and casing to the returns tank. Pull CTS, lubricate if pressure expected. Kill well as needed. 13. MU landing joint or spear and BOLDS. 14. Well is a live well and hole fill needs to be managed the entire job. If well will hold a column of fluid establish hole fill rate to see fluid at surface at all times, If well will not surface fluid due to low bottom hole pressure maintain a hole fill and double pipe displacement when POOH. 15. Attempt to pull tubing. a. PU weight 2021 RWO was 80k SO was 62K b. Do not exceed 80 percent of 3-1/2” tubing. c. Tri point packer is straight pull to release at 46 klbs, pick up and release packer per vendor recommendations. d. Once packer releases stop and wait for 30 minutes to allow packer elements to relax. While waiting on packer elements, circulate at max rate down the tubing taking returns up the annulus a min of 2 bottoms up and expect packer gas to return. Close annular during this time taking returns to pits. If no returns are seen at surface while pumping continue to pump 2 bottoms up and allow the gas to migrate to surface. Wait 2-4 hours while maintaining hole fill down the tubing to allow gas to migrate to surface before POOH. 16. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 17. POOH and lay down the 3-1/2’’ tubing. Rig up spooler for TEC cable. Convert to Reverse Circulating JP Well: MPB-32 PTD: 216-151 a. Inspect the Tubing and place good joints into inventory. Review caliper and ask OE joints to keep. b. Plan to keep all equipment above station 4 GLM c. Make sure to account for all clamps below: i. 151 OTC clamps ii. 10 mid joint clamps 18. MU 7-5/8’’ test packer and RIH to 3000’ MD and test casing to 1500 psi. Notify OE of test results. All indication are the casing leak is below 3000’MD. 19. RIH with 7-5/8’’ Test packer to 5405’ MD and test casing to 1500 psi. If fails roll in to a CMIT- 7-5/8’’ X 9-5/8’’ and test to 1500 psi. 20. Change out handling equipment, install casing crew tongs, and upper rams for handling 7- 5/8” casing. 21. Perform BOP test on the 7-5/8” pipe rams on 7-5/8” test joint to 500/2,500psi. 22. Install casing jacks on top of BOP stack and function test. 23. Utilize casing jacks to unseat and pull 7-5/8” casing. a. PU weight during the 2018 installation of the 7-5/8” casing was 162k lbs. b. Use casing jacks until comfortably under the pulling limitations of the ASR and swap over to using the ASR elevators. c. All joints above 3000’ MD will be run back in hole assuming the test packer pressure test above 3000’ MD passed. d. All joints below 3000’ MD need to be set aside and sent out for inspection. Discard any joints that do not pass a visual inspection. e. Inspect the 7” bullet seals on the bottom of the 7-5/8” casing for potential use on the test packer run later. 24. Contingency- a. If the pressure test at 5405’ failed, procced with below plan. If passed skip to running 7-5/8’’ casing. b. Swap pipe rams to 2-7/8” x 5” rams and test 3 ½’’ test joint to 500/2,500psi. c. PU 7” Bullet seal assembly with 9-5/8” test packer above and TIH to ±5,405’ MD. Sting bullet seals into SLZXP, load well and PT 9-5/8” casing to 1,500psi. d. PUH as needed to determine competent 9-5/8” casing depth. Contact OE to discuss depth of passing test. e. If leak is found in the 9-5/8" casing the leak will be straddled by the bullet seals and a 9-5/8’ by 7’’ packer to isolate the leak. f. Swap pipe rams to 7-5/8” rams and test 7-5/8’’ test joint to 500/2,500psi. 25. Run 7-5/8” casing w/ bullet seal assembly. RIH until the limitation of ASR are reached and swap to casing via casing jacks for the remainder of the run. Space out and PU to circulate in 1% KCl w/ corrosion inhibitor with a diesel freeze protect into the 7-5/8”x9-5/8” annulus. Land 7-5/8” casing and pressure test to 1,500psi. a. 2,100’ of diesel freeze protection: 35 bbls b. 7-5/8”x9-5/8” annulus to 5405’ md: 90 bbls 26. Swap pipe rams to 2-7/8” x 5” rams and test 4-1/2’’ test joint to 500/2,500psi. 27. PU new 4-1/2’’ Jet Pump Completion and RIH. Colors indicate assemblies to be bucked up prior to RWO. Nom. Size ~Length Item Lb/ft Material Notes 30 minute charted. -mgr Convert to Reverse Circulating JP Well: MPB-32 PTD: 216-151 4-1/2''10'WLEG/ Mule shoe 12.6 L-80 Place WLEG in Tieback at 5405' MD 4-1/2''Joints 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''3'4 1/2'' XN Nip with RHC 12.6 L-80 ~5100 MD 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''40 1 joint 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2'' 7”-5/8 X 4-1/2” Packer 12.6 L-80 Tri point packer ~Set ~5040' MD 4-1/2''10'Pup Joint 12.6 L-80 4-1/2'' 40 1 joint 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''BHP Gauge 12.6 L-80 ~4980 MD 4-1/2''10'Pup Joint 12.6 L-80 4-1/2'' 40 1 joint 12.6 L-80 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''Hal Sliding sleeve with one section of ports blanked off for tech wire 12.6 L-80 ~4920 MD 4-1/2''10'Pup Joint 12.6 L-80 4-1/2''Joints 12.6 L-80 4-1/2''Space out PUPS 12.6 L-80 4-1/2'' 1 joint 12.6 L-80 4-1/2''PUP 12.6 L-80 4-1/2''Tubing Hanger 12.6 L-80 28. Space out and land the hanger. a. Use caution not to Damage BHPG Cable while landing the hanger. b. Note PU (Pick Up) and SO (Slack Off) weights on tally. 29. RILDS. Lay down landing joint. 30. Pump 80 bbls 1% KCL with 1% by volume Corrosion inhibitor down the IA. Taking returns up TBG. a. This is to protect the area between the packer and Sliding Sleeve. While taking returns up the TBG 31. WSL discretion to pump FP. Pump 52 bbls of diesel freeze protect down the IA to land inhibitor between Sliding Sleeve and the packer while taking returns up the TBG. 32. Swap to pumping down the TBG taking to formation and Pump 30 bbls of FP. 33. Drop ball and rod and complete loading tubing with FP and hydraulically set the packer as per Vendor setting procedure. 34. Pressure up and test the tubing to 3000 psi for MIT-T. Bleed off the tubing. Test the IA to 3000 psi for MIT-IA (B Pad power fluid header pressure 2600 psi) . Record and notate all pressure tests (30 minutes) on chart. 35. Set CTS. 36. RDMO ASR. Post-Rig Procedure: 1. RD mud boat. RD BOPE house. Move to next well location. Convert to Reverse Circulating JP Well: MPB-32 PTD: 216-151 2. RU crane. ND BOPE. 3. NU tree and tubing head adapter. 4. Test both tree and tubing hanger void to 500psi low/5,000psi high. 5. Pull CTS. 6. RD crane. Move 500 bbl returns tank and rig mats to next well location. 7. Replace gauge(s) if removed. 8. Turn well over to production. RU well house and flowlines for a Jet Pump completion. Post Rig Work Slickline 1. Spot Slickline unit and RU. 2. Pressure test lubricator to 300psi low and 2,800psi high. 3. Pull Ball and rod 4. Pull RHC profile 5. Shift Sliding Sleeve open 6. Set 13B Jet pump in Sliding sleeve. Attachments: 1. Well Schematic Current 2. Well schematic Proposed 3. BOP Drawing _____________________________________________________________________________________ Revised By: TDF 8/11/2023 SCHEMATIC Milne Point Unit Well: MPU B-32 Last Completed: 6/21/2018 PTD: 216-151 TD =10,265’ (MD) / TD =4,251’(TVD) 20” Orig. KB Elev.: 49.4’/ GL Elev.: 22.9’ RKB –THF: 23.13’ (Innovation) 7-5/8” 5 9 109-5/8” 1 2 8 PBTD =10,259’ (MD) / TD = 4,251’(TVD) 9-5/8” ‘ES’ Cementer @ 2,011’ 6 4-1/2” Shoe @ 10,265’ 12 11 14 13 17 18 3-1/2” 3 4 15 16 9-5/8”88 Min ID 2.750” Perf 5,730’-5,736’ Squeeze Cement 7 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34” Conductor (Insulated) 78.6 / A-53 / Weld N/A Surface 106.5’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.835” Surface 5,606’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Vam STL 6.875” Surface 5,416' 0.0459 4-1/2” Liner (250ђ Screens) 13.5 / 13Cr-110 / Vam Top HT 3.920” 5,837’ 10,223’ 0.0149 TUBING DETAIL 3-1/2” Tubing 9.3 / L-80 / EUE 8rd 2.992” Surf 5,422’ 0.0087 OPEN HOLE / CEMENT DETAIL 42” 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4” 1st stage 590 sx 11.7# Extenda, 210 sx 15.8# SwiftCEM 12-1/4” 2nd stage 311 sx 10.7# Perm L, 280 sx 15.8# SwiftCEM 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 264’ Max Hole Angle = 60.33 deg. @ XN profile Max Hole Angle = 85.98 deg. @ Tubing tail Max Hole Angle = 95.75 deg. @ 6,990’ 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. JEWELRY DETAIL No. Top MD Item Drift ID Upper Completion 1 23’ Tubing Hanger (3-1/2” EUE Top & Btm) 2.867” 2 2,228’STA 6: PATCO GLM #6 (12/64”, 1231 psi TRO) 1.5" RK 2.867” 3 3,225’STA 5: PATCO GLM #5 (16/64”, 1263 psi TRO) 1.5" RK 2.867” 4 3,729’STA 4: PATCO GLM #4 (20/64”, orifice) 1.5" RK 2.867” 5 4,237’STA 3: PATCO GLM #3 (dummy valve installed ) 1.5" RK 2.867” 6 4,661’STA 2: PATCO GLM #2 (dummy valve installed ) 1.5" RK 2.867” 7 4,931’STA 1: PATCO GLM #1 (dummy valve installed ) 1.5" RK 2.867” 8 4,985’ 7-5/8" Tri-Point DLH Packer 2.813” 9 5,031’ XN NIPPLE -Min ID= 2.750"2.885” 10 5,416’ Mule Shoe -Btm @ 5,422’2.750” Lower Completion 11 5,405’ 7-5/8” Tieback Assy. (8.25” OD No-Go @ 5,404’) 6.151” 12 5,416’ BOT SLZXP Liner Top Packer w/BD Slips 7” x 9-5/8” 6.200” 13 5,438’ 7” Hydril 563 x 4-1/2” Hydril 521 L-80 XO 3.900” 14 5,705’ 5-1/2” 17# Tendeka Swell Packer, Hybrid (10.88’ Long) 4.767” 15 5,778’ 5-1/2” 17# Tendeka Swell Packer, Hybrid (10.90’ Long) 4.767” 16 5,837’ 4-1/2” Weatherford MaxFlo 316L 250 Micron RTD Screens (117 jts) 3.795” 17 10,230’ 4-1/2” Drillable Packoff Sub 2.400” 18 10,259’ WIV Valve LTC BxB (1.5” Ball on Seat/Closed;Btm @ 10,265’)- NOTE: Perf holes at 5,730’-5,736’ shot with 2-3/8” 5 spf/60 deg GeoDynamics Razor Cement Squeeze #1: 30 bbl 15.8 ppg w/ minimal squeeze pressure Cement Squeeze #2: 30 bbl 15.8 ppg w/ cement entering 4-1/2” liner _____________________________________________________________________________________ Revised By: TDF 8/11/2023 SCHEMATIC Milne Point Unit Well: MPU B-32 Last Completed: 6/21/2018 PTD: 216-151 TD =10,265’ (MD) / TD =4,251’(TVD) 20” Orig. KB Elev.: 49.4’/ GL Elev.: 22.9’ RKB – THF: 23.13’ (Innovation) 7-5/8” 5 9 99-5/8” 1 2 8 PBTD =10,259’ (MD) / TD = 4,251’(TVD) 9-5/8” ‘ES’ Cementer @ 2,011’ 6 4-1/2” Shoe @ 10,265’ 7 11 10 8 13 14 4-1/2” 3 4 11 12 9-5/8” Min ID 2.750” Perf 5,730’- 5,736’ Squeeze Cement 7 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"x34” Conductor (Insulated) 78.6 / A-53 / Weld N/A Surface 106.5’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.835” Surface 5,606’ 0.0758 7-5/8” Tieback 29.7 / L-80 / Vam STL 6.875” Surface 5,416' 0.0459 4-1/2” Liner (250ђ Screens) 13.5 / 13Cr-110 / Vam Top HT 3.920” 5,837’ 10,223’ 0.0149 TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / EUE 8rd 3.958” Surface ±5,405’ 0.0152 OPEN HOLE / CEMENT DETAIL 42” 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4” 1st stage 590 sx 11.7# Extenda, 210 sx 15.8# SwiftCEM 12-1/4” 2nd stage 311 sx 10.7# Perm L, 280 sx 15.8# SwiftCEM 8-1/2” Cementless Screens Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 264’ Max Hole Angle = 60.33 deg. @ XN profile Max Hole Angle = 85.98 deg. @ Tubing tail Max Hole Angle = 95.75 deg. @ 6,990’ 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. JEWELRY DETAIL No. Top MD Item ID Upper Completion 1 ±23’ Tubing Hanger (3-1/2” EUE Top & Btm) 2 ±4,920’ HAL Sliding Sleeve w/ Blanked Port for Tech Wire 3 ±4,980’ BHP Gauge 4 ±5,040’ 7-5/8” x 4-1/2” Packer 5 ±5,100 4-1/2” XN-Nipple 6 ±5,403’ WLEG – Btm @ ±5,405’ Lower Completion 7 5,405’ 7-5/8” Tieback Assy. (8.25” OD No-Go @ 5,404’) 6.151” 8 5,416’ BOT SLZXP Liner Top Packer w/BD Slips 7” x 9-5/8” 6.200” 9 5,438’ 7” Hydril 563 x 4-1/2” Hydril 521 L-80 XO 3.900” 10 5,705’ 5-1/2” 17# Tendeka Swell Packer, Hybrid (10.88’ Long) 4.767” 11 5,778’ 5-1/2” 17# Tendeka Swell Packer, Hybrid (10.90’ Long) 4.767” 12 5,837’ 4-1/2” Weatherford MaxFlo 316L 250 Micron RTD Screens (117 jts) 3.795” 13 10,230’ 4-1/2” Drillable Packoff Sub 2.400” 14 10,259’ WIV Valve LTC BxB (1.5” Ball on Seat/Closed;Btm @ 10,265’)- NOTE: Perf holes at 5,730’-5,736’ shot with 2-3/8” 5 spf/60 deg GeoDynamics Razor Cement Squeeze #1: 30 bbl 15.8 ppg w/ minimal squeeze pressure Cement Squeeze #2: 30 bbl 15.8 ppg w/ cement entering 4-1/2” liner Updated 8/11/2020 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 Aftt. 13,32_ • W • Pris aI4(6(o Regg, James B (DOA) From: Cody Rymut - (C) <crymut@hilcorp.com> Sent: Sunday,June 17, 2018 9:10 PM 1\41 6(t t(l- To: DOA AOGCC Prudhoe Bay Cc: Stan Porhola; Larry Imm - (C); Mark O'Malley;John Menke Subject: RE: B-32 Reporting of BOPE Use to Prevent the Flow of Fluids from a Well Attachments: BOPE Use to Prevent the Flow of Fluids From Wellbore on B-32.docx Please see revision. I forgot to note in the Actions Taken/To Be Taken that the BOPE was tested on 6/16/18 Thanks! Cody Rymut WSM, ASR#1 C: 907-230-3594 SEWED JUN 212218 crymut@hilcarp.com From: Cody Rymut- (C) Sent:Sunday,June 17, 2018 9:04 PM To: DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bay@alaska.gov> Cc:Stan Porhola <sporhola@hilcorp.com>; Larry Imm - (C) <limm@hilcorp.com>; Mark O'Malley <momalley@hilcorp.com>;John Menke <jmenke@hilcorp.com> Subject: B-32 Reporting of BOPE Use to Prevent the Flow of Fluids from a Well Please see attached report for B-32. Don't hesitate to contact me if you have any questions. Thanks! Cody Rymut WSM, ASR#1 C: 907-230-3594 crymut@hilcorp.com 1 . • Date,Time of BOPE Use:June 17, 2018 at 7:30am Well/Location/PTD Number: B-32/ Milne Point/216-151 Rig Name: ASR# 1 Operation Summary, including events leading up to BOPE use: The rig crew was in the process of tripping into well B-32 with a 4.5" x 2-7/8" work string after completing a BOPE test and picking up another"2050'md of 2-7/8" DP in addition to the 2800'md we already had in the hole. Rig crews had just completed change out, had tripped back to bottom, and were getting back to where they left off milling cement out of the wells 4.5" lateral section.The rig crew swiveled up to our 4.5" work string which was on top of the 2-7/8" DP and began to lightly ream/wash down to where they left off.After washing and reaming down to 8220'md the crews stopped to pick up another joint of 4.5" work string. When the pumps shut down, the well continued to flow.The pit watcher called out on the radio to ensure the pumps had been turned off,and then when assured they were off, called myself and our tool pusher to notify of the situation and proceeded with shutting the well in.The well was shut in by stabbing an open TIW into the 4.5"TBG stump, closing the TIW, and then shutting the 2-7/8" x 5"VBR's around the pipe. Choke valve# 1 and Choke valve#2(HCR)were then opened up to the choke manifold to closed Choke valves#C5, C9, and C10.The remote choke was then closed and the pressure on the IA was recorded. Pressure initially climbed to 50 psi and continued to steadily climb up to 150psi. The rig crew lined up to pump down the TBG and take returns through the super choke and mud gas separato (MGS).They initially opened C10 and cracked open the super choke to allow the pressure to bleed off into the MGS, and to see if the pressure would continue to rise. It did not. Crews then began circulating a surface to surface volume (265bb1s) of 8.4ppg fluid. Once circulation was complete, the pumps were shut off and the wellbore was monitored. Well was stable. BOPE Used: 2-7/8" x 5" Variable Bore Rams, Choke Valves#5, 9, and 10, and the TIW. Reason for BOPE Use: Fastest way to shut in the flowing wellbore and monitor pressure. Action Taken/To Be Taken: Rig crews will pull out of hole up to the 2-7/8" x 4.5"crossover on their work string, P/U the test plug, M/U the 2-7/8" DP to the bottom of the test plug, land test plug, and test the VBR's w/a 4.5"test joint and a 2-7/8" test joint as well as choke valves#C5, C9, and C10, and the TIW. The BOPE was last tested on June 16, 2018. • S i(a - IS1 Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Phone: 907/777-8547 SCANS JUN U 7'202 June 5, 2018 RECEWED Mr. Guy Schwartz Alaska Oil and Gas Conservation Commission JUN 0 6 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 • Cl) Cl) (1) (1) a) (1) m a) a) (1) (1) a) (1) (1) (1) m a) _ _ C C CCCCCC C C CCC J J J J J J J J J J J J J 00 • C C CC CCCCC C C C C O O O O O O O O O O O O OLju (I) a) (1) (1) (I) (1) a) a) a) a) a) a) a) O- Q w w wry c c CC C C C C C C C C C C C L L • a) a) Cl) a) a) a) a) a) a) a) a) a) a) O O E E E E E E E E E E E E E U U a) a) a) a) a) a) () a) a) (1) (1) a) a) 0 0 C.) 0 0 000 0 0 0 00 -0 Q < Q Q Q Q Q Q Q Q Q Q Q U V L6 V a) O O _ O 0 0 0 Lo LU Ln ow) Lo Lc) O L LL c) r c- N N O O O N V C •( C CO CO CO CO CO CO CO CO CO CO CO 00 CO CO CO 2 ' N p lC N N N N N N O NNNN NNN ( ++ 0 RiD 0 O ' NNN N M CO CO S N N N N N N N N N N N N N N • 7 U 0 0 0 0 0 0 0 0 0 0 o 0 0 0 O co N- LO M 0) M N- CO 0 O N M 2 N r- LO LO co co Lo Lo M N O) CO LO N I— 0 0 — O — O — — o N EL co 0 co co co co co co co co co to N- NN N N N N N N N NNN N N N NNNN O U 0 0 0 0 0 0 0 0 (3 0 0 0 0 0 0 C O 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 0 O 0 0 0 0 0 0 0 0 0 0 0 0 0 O M '— O co 0) ti CO ti N LO LC) CO M CO Mco N- N- ti co co co co co 1- co 00 N- N F_ Lo Lo Lo Lo Lf) Lo Lo Lo Lo Lo Lo Lo Lo O U Q M M co co co M co M co co co co M co co N N NNNNNNNNNNNNN O O) C)) O) a) 0) O a) 0) O) O) O O O a) N N NNNNNNNNNNNNN 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 LO LO U) LO LO LO LC) Lf) LO LO LO LO LO LC) U) a) 0. a. a 0_ a a. a. 0_ a a. a. CL a cn cn ii 2 2 2 2 2 2 2 2 2 2 2 2 z z 00 0) O N M - N- 00 "• CO 0) O CO N N M M M CM N N d- co co Lo N m m cam m m - Y J J J J a s a_ a s a. a_ a_ a a. a EL CL cn en' 2 2 2 2 2 2 2 2 2 2 z z H or TbF • c„ifr,\�yy, , THE STA" Alaska Oil and Gas 14) � 0 A ,[� Sl T Conservation Commission L 1 K 1 , :-t- _ 333 West Seventh Avenue y, GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ALASMain: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaskO.gov Bo York `I Q1 Operations Manager �U Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-32 Permit to Drill Number: 216-151 Sundry Number: 318-224 Dear Mr. York: 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, (62 Hollis S. French c, Chair J DATED this day of June, 2018. RBDM� JuN 0 4 20X • • peECENED STATE OF ALASKA 2, RG) ALASKA OIL AND GAS CONSERVATION COMMISSION 0 '�' APPLICATION FOR SUNDRY APPROVALS G / V JI& S''' 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Prog}am❑., • Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Cement Cleanout❑., 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q • 216-151 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23570-00-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No ❑., MILNE PT UNIT B-32 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL047438/ADL047437 • 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(MD): Junk(MD): 10,265' • 4,251' • 6,541' 4,367' 1,264 6,541' N/A Casing Length Size MD TVD Burst Collapse Conductor 107' 20" 107' 107' N/A N/A' Surface 5,606' 9-5/8" 5,606' 4,396' 5,750psi 3,090psi Tieback 5,416' 7-5/8" 5,416' 4,394' 6,890psi 4,790psi Liner 4,386' 4-1/2" 10,223' 4,253' N/A N/Ai Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic See Schematic 3-1/2" 9.3/L-80/EUE 8rd 5,450' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 7-5/8"PHL&BOT SLZXP and N/A 4,858 MD/4,208 TVD& 5,416 MD/4,393 TVD and N/A 12.Attachments: Proposal Summary Q 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: 6/7/2018 Commencing Operations: OIL Q • WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 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: Bo York Contact Name: Stan Porhola SI f Authorized Title: Operations Manager Contact Email: sporhola(G�hilcorp.com Contact Phone: 777-8412 Authorized Signature: /774,---- Date: 5/30/2018 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: - /vim 1 ^2 zq Plug Integrity ❑ BOP Test [' Mechanical Integrity Test ❑ Location Clearance CI Other: $ 25 !J /aSc L_Jp e ,r-�1 ---/-7„1-- Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: /o-Li 041 APPROVED BY / / 1 Approved by: 62_,C5-1------ COMMISSIONER THE COMMISSION Date: �P (y Ie 1 31S--3/415 R G I N AL A0itl 5-30.ife • Submit Form and Form 10-403 Revised 4/2017 Approved applic yam- mopptt�� JUn U M f�yoV titre of approval. Attachments in Duplicate • • Well Prognosis Well: MPU B-32 Hilcora Alaska,LLI Date:5/30/2018 Well Name: MPU B-32 API Number: 50-029-23570-00 Current Status: SI Oil Well [Gaslift] Pad: B-Pad Estimated Start Date: June 7th, 2018 Rig: ASR 1 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 216-151 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907)947-9533 (M) Second Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228 (M) AFE Number: Job Type: Cement Cleanout, Current Bottom Hole Pressure: 1,664 psi @ 4,000' TVD (SBHPS 5/01/2018/8.01 ppg EMW) Maximum Expected BHP: 1,664 psi @ 4,000' TVD (No new perfs being added) MPSP: 1,264 psi (0.1 psi/ft gas gradient) Brief Well Summary: The Milne Point MPU B-32 was drilled in 2017 using Hilcorp's Innovation Rig #1 and completed as a horizontal gaslifted producer in the Schrader Bluff NC sand. The well was shut-in in August 2017 due to high water production and solids production. Indications are that the water and solids are coming from the Ugnu sands above the 9-5/8" casing shoe. The liner was perforated and cement squeezed in March 2018. Based on the pressure response of losing 200 psi, it appears that the isolation was successful. However, cement ended up inside the 4-1/2" liner and almost 600' of the cement was removed using coil tubing.The ASR rig attempte to pull the retrievable completion in mid-May 2018, however cement was discovered on the backside of th completion and the tubing had to be cut and the packer fished out of the well. Cement was cleaned ou inside the 7-5/8" and into the top of the 4-1/2" liner before the crews suspended operations and left a - 1/2" kill string installed and left the rig on location. Notes Regarding Wellbore Condition • Tubing last tested to 3,800 psi for 30 min down to 4,916'on 3/10/2017. • Casing IA(3-1/2"x 7-5/8") last tested to 3,000 psi for 30 min down to 4,858' on 3/10/2017. • Casing OA(7-5/8" x 9-5/8")tested to 1,000 psi for 30 min down to 5,416' on 8/16/2017. • Max angle 87.5° @ 5,417' at the tubing tail. Lateral max angle is 95.75° @ 6,990' • Min ID is 2.750"thru XN profile at 4,916' MD below the PHL Packer at 4,858' MD. • Cement under-reamed from 5,945'—6,541'. Estimate cement exists to+/-7,825'. • 3-1/2" Kill string ran to 3,000' MD. Objective: The purpose of this work is to pull the 3-1/2" kill string, mill out the remaining cement inside the 4-1/2" liner and re-run a 3-1/2" completion. Brief RWO Procedure: 1. MIRU Rig Crews and support equipment. Re-activate rig equipment. 2. Test BOPE to 250 psi Low/2,500 psi High, annular to 250 psi Low/2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. • • Well Prognosis Well: MPU B-32 llilcorp Alaska,LL1 Date:5/30/2018 b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" and 4-1/2"test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. ontinge cy (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV ofile_is efoded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer(Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr.Jim Regg (AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure (floor valves,gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/ penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.5 ppg viscosified produced water as needed. Pump cleaning pill w/ heated seawater to flush tubing of residual oil. 5. MU landing joint and PU on the tubing hanger. a. The kill string is 3,000' long of 3-1/2" workstring. b. If needed, circulate pill (forward or reverse)with cleaning surfactant prior to laying down the tubing hanger. 6. Recover the tubing hanger. Contingency(If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. 1 `LL 7. POOH and lay down the 3-1/2" workstring. 8. RIH with 3-3/4" mill tooth bit BHA and RIH on 2-7/8"x 3-1/2" workstring to"'5,747' MD (top of cement). Circulate the well clean with 8.5 ppg viscosified produced water. Mill cement and RIH to +/-8,000'. Contingency(If cement milling is slow and/or hole cleaning issues are evident): PU 3-3/4" bit BHA and RIH on 2-7/8"x 4-1/2"workstring to continue milling out cement. RIH to +/-8,000'. 9. POOH and LD 2-7/8" x 3-1/2" workstring and BHA. 10. RIH with 7-5/8" casing scraper BHA and RIH on 3-1/2" or 4-1/2" workstring to—5,398' MD (XO in 7- 5/8"tieback). Circulate the well clean with 8.5 ppg viscosified produced water.Swap over to clean 8.5 ppg completion brine. 11. POOH and LD 3-1/2" or 4-1/2" workstring and BHA. 12. PU completion and RIH on 3-1/2" tubing. a. Tubing is 3-1/2" 9.3# L-80 EUE (Range 2) b. Gaslift Mandrels Spaced Out Per Proposed Schematic • Well Prognosis Well: MPU B-32 Hik+orp Alaska,LL Date:5/30/2018 c. Downhole Gauge @ ±5,000' MD d. Packer @ ±5,060' MD e. 3-1/2" XN (2.75" No-Go) @ ±5,115' MD [Pre-load RHC plug body] f. 3-1/2" WLEG @ ±5,450' MD 13. Space out the tubing tail to land below the liner top at±5,405' MD. Land hanger. RILDS. 14. Circ inhibited 8.5 ppg Seawater packer fluid and freeze protect fluid. 15. Drop ball and rod. Pressure up and set Packer(start 1,500 psi/final 3,500 psi). 16. Pressure test tubing to 3,500 psi for 30 min and chart. Bleed tubing to 1,500 psi. 17. Test inner annulus to 3,000 psi for 30 min and chart. Monitor tubing for packer leak! 18. Bleed tubing to 0 psi. Pop shear valve from annulus to tubing (2,000 psi differential).., 19. Freeze protect annulus and tubing. 20. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off) weights on tally. 21. Set BPV. Rig down ASR. Post-Rig Procedure: 22. RD mud boat. RD BOPE house. Move to next well location. 23. RU crane. ND BOPE. 24. NU existing 3-1/8" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000p si high. Pull BPV. 25. RD crane. Move 500 bbl returns tank and rig mats to next well location. 26. Replace gauge(s) if removed. 27. Turn well over to production. RU well house and flowlines. Attachments: 1. Proposed Schematic 2. BOPE Schematic • ini 110 • Milne Point Unit Well: MPU B-32 PROPOSED Last Completed: Proposed Ilileorp Alaska,LLC PTD: 216-151 Orig.KBEIev.:49.4'/GLEIev.:22.9' TREE&WELLHEAD � -RKB—THF:23.13' Innovation) Tree Seaboard 3 1/8" 5M 'l x'+ 1 v i i i Wellhead 20" k.1 Bottom with 3"CIW"H"BPVp rofile.2ea 3/8"NPT control lines. 4 „ OPEN HOLE/CEMENT DETAIL 42" 50 bbls(10 Yards Pilecrete dumped down backside) 12-1/4"1st stage 590 sx 11.78 Extenda,210 sx 15.88 SwiftCEM t. 3-1/2' a+ 12-1/4"2nd stage 311 sx 10.78 Perm L,280 sx 15.8#SwiftCEM q i, 8-1/2" Cementless Screens Liner in 8-1/2"hole 01 0j 2 )a CASING DETAIL a a a Size Type Wt/Grade/Conn Drift ID Top Btm BPF r 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A e a 1;,: 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,606' 0.0758 3 0 7-5/8" Tieback 29.7/L-80/Vam STL 6.750" Surface 5,416' 0.0459 9-5/ 'ES' 1.,. 'w Cementer @ { ),y, 4-1/2" Liner(2501.1 Screens) 13.5/13Cr-110/Vam Top HT 3.795" 5,837' 10,223' 0.0149 2,011 , ) TUBING DETAIL 4 V.' 3-1/2" Tubing 9.3/L-80/EUE 8rd 2.867" Surf +/-5,450' 0.0087 WELL INCLINATION DETAIL KOP @ 264' 10 P 5 Max Hole Angle=60.33 deg.@ XN profile Max Hole Angle=85.98 deg.@ Tubing tail Max Hole Angle=95.75 deg.@ 6,990'MD 1 6 JEWELRY DETAIL 41 No. Top MD Item Drift ID <. Upper Completion 0. 1 +/-23' Tubing Hanger(3-1/2"EUE Top&Btm) 2.867" 2 +/-2,344' 3.5"GLM SPMO-1.OM 1.5" 2.867" ,i,11 ; 7tfr. 3 +/-3,222' 3.5"GLM SPMO-1.0M 1.5" 2.867" 4z 4 +/-3,773' 3.5"GLM SPMO-1.0M 1.5" 2.867" 5 +/-4,227' 3.5"GLM SPMO-1.0M 1.5" 2.867" 06 +/-4,648' 3.5"GLM SPMO-1.0M 1.5" 2.867 0% $ 7 +/-4,950' 3.5"GLM SPMO-1.0M 1.5" 2.867" 7-5/8"--t4"--0 8 +/-5,000' 3.5"ROC Gauge Mandrel w/1/0"TEC Wire 2.813" 0 la 9 +/-5,060' 7-5/8"Halliburton PHL Packer(45k Release) 2.885" i 9 ' 10 +/-5,115' 3.5"XN Nipple,Min ID=2.750"No-Go,2.813"Packing Bore 2.750" 12 r 11 +/-5,417' 3-1/2"Jt w/Mule Shoe(Btm @ 5,450') 2.867" 110 Lower Completion Mn ID �. i=13 12 5,405' 7-5/8"Tieback Assy.(8.25"OD No-Go @ 5,404') 6.151" 2.750 r` �,1 r*ss.f, 14 9..SI8" 13 5,416' BOT SLZXP Liner Top Packer w/BD Slips 7"x 9-5/8" 6.200" " . 11 14 5,438' 7"Hydril 563 x 4-1/2"Hydril 521 L-80 X0 3.900" Perf 0.-- =..t 15 15 5,705' 5-1/2"17#Tendeka Swell Packer,Hybrid(10.88'Long) 4.767" 1 O 0, 16 5,778' 5-1/2"17#Tendeka Swell Packer,Hybrid(10.90'Long) 4.767" 5,730'-5,736 — ►—+ 16 17 5,837' 4-1/2"Weatherford MaxFlo 316L 250 Micron RTD Screens(117 jts) 3.795" Squeeze 18 10,230' 4-1/2"Drillable Packoff Sub 2.400" Cement 19 10,259' WIV Valve LTC BxB(1.5"Ball on Seat/Closed;Btm @ 10,265')I17 It NOTE: Perf holes at 5,730'-5,736'shot with 2-3/8"5 spf/60 deg GeoDynamics Razor 4-1/2' Cement Squeeze#1:30 bbl 15.8 ppg w/minimal squeeze pressure Shoe @ f. 18 Cement Squeeze#2:30 bbl 15.8 ppg w/cement entering 4-1/2"liner 10,265' ` 19 TD=10,265'(MD)/TD=4,251'(TVD) PBTD=10,259'(MD)/TD=4,251'(TVD) Revised By:STP 5/30/2018 ^ r II 0 ae Point ASR Rig 1 BOPE Hitrmp Ala*Ita,I I 2018 11" BOPE / Stripping Head r 1 4.48' / drily1 11" - 5000 mr Ill i LIIIi ( iiii III 111111 III III 4.54' °--"ill ® L! _: VBRorPipeRams - ta 11''- 5000 (mp H Blind no lEZ PIP \ 11lf In l 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves --I--u 11'i1P11P1 1'Ill 2.00' r ii 11.15:1 11'.111.11111 1.111' _ �4 1:i Manual Manual Manual HCR Updated 1/05/2018 111111111111111111 Or T11.� • I%%y,4A THE SSE Alaska Oil and Gas �,�► ��►,.�� ofA /� SKA Conservation Commission Ln J 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OFQ. Main: 907.279.1433 ALAS� Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager Hilcorp Alaska, LLCscow 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-32 Permit to Drill Number: 216-151 Sundry Number: 318-188 Dear Mr. York: Enclosed is the approved application for 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, Hollis S. French Chair r DATED this .3 day of May, 2018. D a RBDMs► a� 2018 • 0RECEWED STATE OF ALASKA MAY 0 2 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION 0 i S s/3//e APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Q • Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Cement Clean-out❑., 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development ❑✓ • 216-151 - 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23570-00-00 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No ❑., MILNE PT UNIT B-32 • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0474387 ADL047437 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(MD): Junk(MD): 10,265' ` 4,251' • 6,541' 4,367' 1,264 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 107' 20" 107' 107' N/A N/A Surface 5,606' 9-5/8" 5,606' 4,396' 5,750psi 3,090psi Tieback 5,416' 7-5/8" 5,416' 4,394' 6,890psi 4,790psi Liner 4,386' 4-1/2" 10,223' 4,253' N/A N/A Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic See Schematic 3-1/2" 9.3/L-80/EUE 8rd 5,450' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 7-5/8"PHL&BOT SLZXP and N/A 4,858 MD/4,208 TVD& 5,416 MD/4,393 TVD and N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑Q Exploratory ❑ Stratigraphic❑ Development❑✓ • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 5/15/2018 Commencing Operations: OIL Q • WINJ ❑ WDSPL El Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 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: Bo York Contact Name: Stan Porhola '5- Authorized Title: Operations Manager Contact Email: sporhola4hiICOrp.Com Contact Phone: 777-8412 Authorized Signature: Date: 5/1/2018 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 311 - ill Plug Integrity ❑ BOP Test [ Mechanical Integrity Test ❑ Location Clearance ❑ Other: - ,2'_SCO 66 B MAY 0 8 2019 Post Initial Injection MIT Req'd? Yes El No ❑ RD11 Spacing Exception Required? p g p Yes ❑ No � Subsequent Form Required: 1 0"�yC (411.100_,,,,/\ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Z �; ,� s , ! D . f/'/l�'/ �} 5 /r (� GI Sint Form ane 7 Form 10-403 Revised 4/2017 Approved applic o i I 1 the date of approval. Attachments in Duplicate • Well Prognosis Well: MPU B-32 Mbar')Alaska,Lb Date: 5/01/2018 Well Name: MPU B-32 API Number: 50-029-23570-00 Current Status: SI Oil Well [Gaslift] Pad: B-Pad Estimated Start Date: May 15th, 2018 Rig: ASR 1 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 216-151 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) A F E Number, = Job Type = °' Cement Cleanout Current Bottom Hole Pressure: 1,664 psi @ 4,000' TVD (SBHPS 5/01/2018/8.01 ppg EMW) Maximum Expected BHP: 1,664 psi @ 4,000' TVD (No new perfs being added) MPSP: 1,264 psi (0.1 psi/ft gas gradient) Brief Well Summary: The Milne Point MPU B-32 was drilled in 2017 using Hilcorp's Innovation Rig #1 and completed as a horizontal gaslifted producer in the Schrader Bluff NC sand. The well was shut-in in August 2017 due to high water production and solids production. Indications are that the water and solids are coming from the Ugnu sands above the 9-5/8" casing shoe. The liner was perforated and cement squeezed in March 2018. Based on the pressure response of losing 200 psi, it appears that the isolation was successful. However, cement ended up inside the 4-1/2" liner and almost 600' of the cement was removed using coil tubing. Notes Regarding Wellbore Condition • Tubing last tested to 3,800 psi for 30 min down to 4,916' on 3/10/2017. • Casing IA(3-1/2"x 7-5/8") last tested to 3,000 psi for 30 min down to 4,858' on 3/10/2017. • Casing OA(7-5/8" x 9-5/8")tested to 1,000 psi for 30 min down to 5,416' on 8/16/2017. • Max angle 87.5° @ 5,417' at the tubing tail. Lateral max angle is 95.75° @ 6,990' • Min ID is 2.750"thru XN profile at 4,916' MD below the PHL Packer at 4,858' D.,,.._ • Cement under-reamed from 5,945'—6,541'. Estimate cement exists to -7,825'. Objective: The purpose of this work is to pull the existing 3-1/2" completion, mill out the remaining cement inside the 4- 1/2" liner and re-run a 3-1/2" completion. Pre-Rig Procedure: 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate at least one wellbore volume with 8.5 ppg seawater down tubing,taking returns up casing to 500 bbl returns tank. Utilize surfactant pill to clean tubulars. 6. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 7. RD Little Red Services and reverse out skid. II • • Well Prognosis Well: MPU B-32 Ililean)Alaska,LLi Date: 5/01/2018 8. RU crane. Set BPV. ND Tree. NU 11" BOPE. RD Crane. 9. NU BOPE house. Spot mud boat. Brief RWO Procedure: 10. MIRU Hilcorp ASR#1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 11. Check for pressure and if 0 psi pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/8.5 ppg seawater prior to pulling BPV. Set TWC. 12. Test BOPE to 250 psi Low/2,500 psi High, annular to 250 psi Low/2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. �, b. Notify AOGCC 24 hours in advance of BOP test. 7(- c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" and 3-1/2"test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 13. Conliuge q: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer(Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr.Jim Regg (AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record theum in rate and pressure. p p g e. Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/ penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 14. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/8.5 ppg seawater as needed. Pump cleaning pill w/heated seawater to flush tubing of residual oil. 15. MU landing joint or spear and PU on the tubing hanger. rf‘1'" a. The PU weight during the 2017 completion was estimated at 85K lbs (block weight of 35k). AA - b. Packer is set to release at 45k overpull. `w c. If needed, circulate pill (forward or reverse) with cleaning surfactant prior to laying down the tubing hanger. 16. Recover the tubing hanger. Contingency(If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. 17. POOH and lay down the 3-1/2" tubing. Number all joints. Tubing will be cleaned for inspection. Lay down pulled jewelry. a. Keep all joints of tubing for cleaning and inspection. • • Well Prognosis Well: MPU B-32 Ililcor')Alaska,LL Date:5/01/2018 b. Jewelry will be sent to appropriate vendors for re-servicing and put back into inventory. c. Note any sand or scale inside or on the outside of the tubing/jewelry on the morning report. d. Look for over-torqued connections from initial tubing run. 18. RIH with 3-3/4" mill tooth bit BHA and RIH on 2-7/8" drillpipe/workstring to"'5,945' MD (top of cement). Circulate the well clean with 8.5 ppg seawater. Mill cement and RIH to PBTD._ —.> 16, ' cfriD Contingency(If cement milling is slow): PU 3-3/4" bit and motor BHA and RIH on 2-7/8" drillpipe/workstring to continue milling out cement. RIH to PBTD. 19. POOH and LD 2-7/8" drillpipe/workstring and BHA. 20. RIH with 7-5/8" casing scraper BHA and RIH on 2-7/8" drillpipe/workstring to^'5,398' MD (XO in 7- 5/8"tieback). Circulate the well clean with 8.5 ppg seawater. 21. POOH and LD 2-7/8" drillpipe/workstring and BHA. 22. PU completion and RIH on 3-1/2"tubing. a. Tubing is 3-1/2" 9.3# L-80 EUE (Range 2) b. Sliding Sleeve @ ±4,950' MD c. Downhole Gauge @ ±5,000' MD d. Packer @ ±5,060' MD e. 3-1/2" XN (2.75" No-Go) ±5,115' MD [Pre-load RHC plug body] f. 3-1/2" WLEG @ ±5,450' MD 23. Space out the tubing tail to land below the liner top at±5,405' MD. Land hanger. RILDS. 24. Circ inhibited 8.5 ppg Seawater packer fluid and freeze protect fluid. 25. Drop ball and rod. Pressure up and set Packer(start 1,500 psi/final 3,500 psi). rA. ( 26. Pressure test tubing to 3,5OILpsi for 30 min and chart. Bleed tubing to 1,500 psi. ((' i 27. Test inner annulus to 3,O�si for 30 min and chart. Monitor tubing for packer leak. 28. Bleed tubing to 0 psi. Pop shear valve from annulus to tubing(2,000 psi differential). 29. Freeze protect annulus and tubing. 30. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off)weights on tally. 31. Set BPV. Rig down ASR. Post-Rig Procedure: 32. RD mud boat. RD BOPE house. Move to next well location. 33. RU crane. ND BOPE. 34. NU existing 3-1/8" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 35. RD crane. Move 500 bbl returns tank and rig mats to next well location. 36. Replace gauge(s) if removed. 37. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic • • Well Pro nosis Well: MP B-32 Hilcorp Alaska,LLI Date:5/0 /2018 4. Existing Tree/Wellhead 5. Blank RWO MOC Form I 14 • • Milne Point Unit Well: MPU B-32 SCHEMATIC Last Completed: 3/10/2017 Hilcarp Alaska,LLC PTD: 216-151 Orig.KBEIev.:49.4'/GLEIev.:22.9' TREE&WELLHEAD TRKB—THF:23.13' Innovation) Tree Seaboard 3 1/8" 5M Itil C 1 C^ Seaboard 16 3/4"3M x 11"5M Multibowl w/11"x 3 1/2"EUE Top and airWellhead 20' , Bottom with 3"CIW"H"BPV profile.2ea 3/8"NPT control lines. L., OPEN HOLE/CEMENT DETAIL v 42" 50 bbls(10 Yards Pilecrete dumped down backside) t 12-1/4"1st stage 590 sx 11.7#Extends,210 sx 15.8#SwiftCEM f" 2 i.* 1 12- 4"2nd stage 311 sx 10.7#Perm L,280 sx 1 #SwiftCEM 3-1/2' y` —► 9 / g5 8 S ftCEM `gra • 8-1/2" Cementless Screens Liner in 8-1/2"hole il s1�4 3 CASING DETAIL f,' Size Type Wt/Grade/Conn Drift ID Top Btm BPF `; II20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A i" 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,606' 0.0758 4 517-5/8" Tieback 29.7/L-80/Vam STL 6.750" Surface 5,416' 0.0459 Cerra ES' 4-1/2" Liner(250µScreens) 13.5/13Cr-110/Vam Top HT 3.795" 5,837' 10,223' 0.0149 Cementer @ 1*: 2,011 TUBING DETAIL Aiii5 3-1/2" Tubing 9.3/L-80/EUE 8rd 2.867" Surf 5,450' 0.0087 4' WELL INCLINATION DETAIL (+ a KOP @ 264' 6 Max Hole Angle=60.33 deg.@ XN profile Max Hole Angle=85.98 deg.@ Tubing tail Max Hole Angle=95.75 deg.@ 6,990'MD 7 -,L JEWELRY DETAIL kV No. Top MD Item Drift ID Upper Completion 0,0• 8 1 23' Tubing Hanger(3-1/2"EUE Top&Btm) 2.867" ;4 2 1,963' 3.5"X Nipple Assembly,2.813"Packing Bore 2.813" r 3 2,344' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,273)w/RK Latch(Set 3/12/17) 2.867" 7-5/8' - 9 �i", 4 3,222' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,264)w/RK Latch(Set 3/12/17) 2.867" 5 3,773' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,213)w/RK Latch(Set 6/26/17) 2.867" r .� 10 6 4,227 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,199)w/RK Latch(Set 6/26/17) 2.867" s "' ®"e 7 4,648' 3.5"GLM SPMO-1.0M 1.5"(20/64 Orifice)w/RK Latch (Set 6/26/17) 2.867" �+ 8 4,743' 3.5"XD Sliding Sleeve,X profile,2.813"seal bore 2.813" Mn ID 1 11 9 4,801' 3.5"ROC Gauge Mandrel w/'/<"TEC Wire 2.813" 2.750" 1 10 4,858' 7-5/8"Halliburton PHL Packer(45k Release) 2.885" 13 11 4,916' 3.5"XN Nipple,Min ID=2.750"No-Go,2.813"Packing Bore 2.750" 14 12 5,417' 3-1/2"Jt w/Mule Shoe(Btm @ 5,450') 2.867" 15 Lower Completion g5/g µ*; �ilt 13 5,405' 7-5/8"Tieback Assy.(8.25"OD No-Go @ 5,404') 6.151" 1 14 5,416' BOT SLZXP Liner Top Packer w/BD Slips 7"x 9-5/8" 6.200" 12 Peri ,bix va--,:--..;, 16 15 5,438' 7"Hydril 563 x 4-1/2"Hydril 521 L-SO XO 3.900" k' � 5,730'-5,736 �' "' 17 16 5,705' 57_"1F1/2y 1/2"17#Tendeka Swell Packer,Hybrid(10.88'Long) 4.767" 17 5,778' 5-1/2"17#Tendeka Swell Packer,Hybrid(10.90'Long) 4.767" 18 5,837' 4-1/2"Weatherford MaxFlo 316L 250 Micron RTD Screens(117 jts) 3.795" t . ‘11" Squeeze Cement 19 10,230' 4-1/2"Drillable Packoff Sub 2.400" UR Cement', �.°; 20 10,259' WIV Valve LTC BxB(1.5"Ball on Seat/Closed;Btm @ 10,265') 5,945'to 18 6,541' w NOTE: Cement Perf holes at 5,730'-5,736'shot with 2-3/8"5 spf/60 deg GeoDynamics Razor in Liner Cement Squeeze#1:30 bbl 15.8 ppg w/minimal squeeze pressure 6,541' : Cement Squeeze#2:30 bbl 15.8 ppg w/cement entering 4-1/2"liner Est End 4-1/2" Shoe @ of Cement19 7,825' 10,265' ..�J,r 20 TD=10,265'(MD)/TO=4,251'(TVD) PBTD=10,259'(MD)/TD=4,251'(TVD) Revised By:STP 4/30/2018 Milne Point Unit • • Well: MPU B-32 II PROPOSED Last Completed: Proposed Hi!cora Alaska,LLC PTD: 216-151 Orig.KB Elev.:49.4'/GL Elev.:22.9' TREE&WELLHEAD TRKB-THF:23.13' Innovation) Tree Seaboard 3 1/8" 5M s+ 1 v 14Seaboard16 3/4"3M x 11"5M Multibowl w/11"x 3 1/2"EUE Top and 20' 4 Wellhead Bottom with 3"CIW"H"BPV profile.2ea 3/8"NPT control lines. kr e" OPEN HOLE/CEMENT DETAIL 42" 50 bbls(10 Yards Pilecrete dumped down backside) e" ' 12-1/4"1st stage 590 sx 11.7#Extenda,210 sx 15.8#SwiftCEM i 2 °: 12-1/4"2nd stage 311 sx 10.7#Perm L,280 sx 15.8#SwiftCEM 3-1/2 ;' 0 ;a 8-1/2" Cementless Screens Liner in 8-1/2"hole A r 3 CASING DETAIL il Size Type Wt/Grade/Conn Drift ID Top Btm BPF 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A 1,a, Surface 40/L-80/DWC/C 8.679" Surface 5,606' 0.0758 4 f 7-5/8" Tieback 29.7/L-80/Vam STL 6.750" Surface 5,416' 0.0459 9-5/8"ES `!a + Cementer@ 4-1/2" Liner(250µScreens) 13.5/13Cr-110/Vam Top HT 3.795" 5,837' 10,223' 0.0149 2,011' TUBING DETAIL 5 `i 3-1/2" Tubing 9.3/L-80/EUE 8rd 2.867" Surf I +/-5,450' 0.0087 ,t) WELL INCLINATION DETAIL KOP @ 264' r 6 Max Hole Angle=60.33 deg.@ XN profile +1 Fi Max Hole Angle=85.98 deg.@ Tubing tail Max Hole Angle=95.75 deg.@ 6,990'MD se: JEWELRY DETAIL 4No. Top MD Item Drift ID Upper Completion i 1 +/-23' Tubing Hanger(3-1/2"EUE Top&Btm) 2.867" 8 • 2 +/-1,963' 3.5"X Nipple Assembly,2.813"Packing Bore 2.813" 3 +/-2,344' 3.5"GLM SPMO-1.0M 1.5" 2.867" 4 +/-3,222' 3.5"GLM SPMO-1.OM 1.5" 2.867" t•)e 5 +/-3,773' 3.5"GLM SPMO-1.0M 1.5" 2.867" s 6 +/-4,227' 3.5"GLM SPMO-1.0M 1.5" 2.867" F` 10 7 +/-4,648' 3.5"GLM SPMO-1.0M 1.5" 2.867" 7-5/8"--4--II' }4 8 +/-4,848' 3.5"GLM SPMO-1.0M 1.5" 2.867" 4 ' (,,a;: 9 +/-4,943' 3.5"XD Sliding Sleeve,X profile,2.813"seal bore 2.813" ®k ►'� 11 10 +/-5,001' 3.5"ROC Gauge Mandrel w/1/4"TEC Wire 2.813" r 14 11 +/-5,058' 7-5/8"Halliburton PHL Packer(45k Release) 2.885" 12 +/-5,116' 3.5"XN Nipple,Min ID=2.750"No-Go,2.813"Packing Bore 2.750" Nin ID �-• 7 *15 r 11111 111 « 16 13 +/-5,41T 3-1/2"Jt w/Mule Shoe(Btm @ 5,450') 2.867"' 2' " "4i7,*.,,, Lower Completion 95/C ` "t y �"; 11 LAN-144k11 13 14 5,405' 7-5/8"Tieback Assy.(8.25"OD No-Go @ 5,404') 6.151" t►-_o ►_- .c. 17 15 5,416' BOT SLZXP Liner Top Packer w/BD Slips 7"x 9-5/8" 6.200" Perf aa , 5,730-5,736' —� `— 18 17 5,43T 7"Hyri10 5,705' 5.1/2"17#6 endeka Swell Packer,Hx 4-1/r Hydri1521 L-80 ybrid(10.88'Long) 4.767" 18 5,778 5-1/r 17#T ndeka Swell Packer,Hybrid(10 90'L ng) 4.767" squeeze 19 5,837' 4-1/2"Weatherford MaxFlo 316L 250 Micron RTD Screens(117 jts) 3.795" 20 10,230' 4-1/2"Drillable Packoff Sub 2.400" _ 19 21 10,259' WIV Valve LTC BxB(1.5"Ball on Seat/Closed;Btm @ 10,265') e II NOTE: Perf holes at 5,730'-5,736'shot with 2-3/8"5 spf/60 deg GeoDynamics Razor 4-1/2" Cement Squeeze#1:30 bbl 15.8 ppg w/minimal squeeze pressure Shoe @ int20 Cement Squeeze#2:30 bbl 15.8 ppg w/cement entering 4-1/2"liner 10,265' Ale 21 TD=10,265'(MD)/TD=4,251'(TVD) PBTD=10,259'(MD)/1D=4,251'(R/D) Revised By:STP 5/01/201ii i • /Iilne Point ASR Rig 1 BOPE 2018 Hikorp \1.14,1 t.i.t: 11" BOPE , , Stripping Head ( , 1 4.48' 'W P • dril6 : 4 v 11 - 5000 iii iii iii Ill Iii 7 1111=11111 III III 1Il III III / \ _ �� C I —U • 4.54' ® —.° VBR or Pipe Rams on ®moi= .,ted11"- 5000 1.10m: Blind -,lllllll- A® ow arninfam 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves \__ _ —____/ I Ii'I I'II I'I!I'I I it' - 2.00' �l• At �,��• C 1 . -tt F.14°Al 7N °H _ _ _ _ F � h°`11ii 1 • fIIII.III.I I11 I\I1I - i'lb I. i i Manual Manual s Manual HCR Updated 1/05/2018 H . • EXISTING TREE/WELLHEAD MPU 11-32Wellhead/Tree Esin�rp Alaska,Ilk Milne Point Unit 11 Tree Cap ,„ ar „I, Tree Valve 3-1/8" 5M r.,i° 1 'o0 n•' F E Tree Cross 3-1/8" 5M 1111 D 0 op! Tree Valve 3-1/8" 5M M F SSV 3-1/8" 5M LC: 4,0111111— O Tree Valve 3-1/8" 5M -, :0 o 0,:.. Tubing AdapterI Tubing Head „i I.= 131 11" 5M Top x 11" 5M Bt �� k••Zi Ic" 0rØ.'. .1 A ail r� ' 7� Casing Head - mit CI„,4„..,40„,„ ,, . �{ 11" 5M Top x 11" 5M Btm �i1,i1°0� �� Ili �� ►� am ' d 4ll 1�1• lit ,. yy r • . 0 - 0 /5.2 IX g 2 6 0 ,_ > / / \ � . § g « a a E 0 o R -a a) a) E > - = § < 2- / a 0. .- « m 7 / 1 / 2 22 % 2 � � o 92 « �.:0_ o5 = a) - al @ CO % 2 ■ 2 \ R $ % C• o k � CD ¥ 4 - W kL o al CIS > & o O. m ocp__ / ti k a � i. fd 2 ao 0 % f § W 2 E G 0- ] G Q O 2 / 'K § ± / � a S\ / t. c �/co c - co Et § — 1 \ . > a C § � E § Q rs O $ § a e 0co % cc 0 u) k a ■ / 7 o o § al Q & m . . . o = CI 0 a) ■ e ■ (4 CO k CO / / CO 0. 0. o � @ 2 » a u 0 ' . ' � % $ ° > % 2 > E 0 k 2 Cl) CO co < a • • Schwartz, Guy L (DOA) .� From: Stan Porhola <sporhola@hilcorp.com> Sent: Wednesday, May 02, 2018 1:39 PM To: Schwartz,Guy L(DOA) Subject: Re: B-32 cement sqz PTD 216-151(sundry 318-030) Yes, Cement bypassed the swell packers. Likely had a washed out section of the hole around those swell packers from day 1 and they never swelled enough to cover that gap. Probably not able to flow at this time, but I have a downhole gauge and can trend the BHP to see if we have some seepage to the reservoir. But once we get the rest of the cement out of the liner,hope is we will still have the lower portion of the screens that are open to the reservoir. Stan Porhola Operations Engineer On May 2,2018,at 12:56 PM,Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov<mailto:guy.schwartz@alaska.gov» wrote: Stan, Thanks for the clarification. So the cement bypassed the swell packer at 5778'moved downhole then reentered the liner at 6234' ? So much for sealing swell packers... Is well able to flow at all now? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793- 1226)or(Guy.schwartz@alaska.gov<mailto:Guy.schwartz@alaska.gov>). From:Stan Porhola<sporhola@hilcorp.com<mailto:sporhola@hilcorp.com» Sent:Wednesday, May 02,2018 12:00 PM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov<mailto:guy.schwartz@alaska.gov» Subject: RE: B-32 cement sqz PTD 216-151(sundry 318-030) Guy, It appears that the during the 2nd cement squeeze,we had some cement go on the outside of the 4-1/2" liner and head toward the toe of the well and enter through a suspected hole in the 4-1/2" screens(we have seen solids that average 490 microns, larger than the 250 micron screens). Estimated entry point is+/-6,234', based on a production log we did that showed a significant fluid entry point. 1 • • The cement then ended up inside the 4-1/2" liner.Total length of+/-30 bbl of cement inside the 4-1/2" (minus a few barrels on the outside,so assuming 28 bbl inside the liner)would be 1,879'of cement. Coil has milled up 596', so 1,28 V left of cement possible in the 4-1/2". The good thing is it looks like the isolation of the water was successful because the BHP has dropped by over 200 psi a d is tracking the estimated reservoir pressure that we would expect from the other offset producer B-28 in the same N- sands of the Schrader Bluff. Stan From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Wednesday, May 02,2018 10:52 AM To:Stan Porhola<sporhola@hilcorp.cam<mailto:sporhola@hilcorp.com» Subject: B-32 cement sqz PTD 216-151( sundry 318-030) Stan, I was reviewing the sundry report.. not sure I understand what happened to the cement. Doesn't look like job went as planned. Do you know what happened? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information ma, violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at(907-793- 1226)or(Guy.schwartz@alaska.gov<mailto:Guy.schwartz@alaska.gov>). 2 STATE OF ALASKA OSKA OIL AND GAS CONSERVATION CCOISSION REPORT OF SUNDRY WELL OPERATIONS MAY 1 1 2018 1.Operations Abandon LI Plug Perforations U Fracture StimulateL Pull Tubing U 4.ak f n U Performed: Suspend ❑ Perforate ❑ Other Stimulate❑ Alter Casing ❑ Cha .= -11F4MctrroYm ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well❑ Re-enter Susp Well ❑ Other: Coil Cement Squeeze ❑✓ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska LLC Development ❑✓ Exploratory ❑ 216-151 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic III Service ❑ 6.API Number: AK 99503 50-029-23570-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL047438/ADL047437 MILNE PT UNIT B-32 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 10,265 feet Plugs measured 6,541 feet true vertical 4,251 feet Junk measured N/A feet Effective Depth measured 6,541 feet Packer measured 4,858&5,416 feet true vertical 4,367 feet true vertical 4,208&4,393 feet Casing Length Size MD TVD Burst Collapse Conductor 107' 20" 107' 107' N/A N/A Surface 5,606' 9-5/8" 5,606' 4,396' 5,750psi 3,090psi Tieback 5,416' 7-5/8" 5,416' 4,394' 6,890psi 4,790psi Liner 4,386' 4-1/2" 10,223' 4,253' N/A N/A Perforation depth Measured depth See Schematic feet SCANNED s True Vertical depth See Schematic feet Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3/L-80/EUE 8rd 5,450' 4,397' 7-5/8"PHL Packers and SSSV(type,measured and true vertical depth) BOT SLZXP 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: 0 0 0 960 0 Subsequent to operation: 0 0 0 900 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑., Exploratory III Development❑l Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑✓ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 318-030 Authorized Name: Contact Name: Stan Porhola� Bo York Authorized Title: Operations Manager Contact Email: sporhola@hilcorp.com Authorized Signature: r7--------------""-- Date 5/1/2018 Contact Phone: 777-8412 ,/,..d„.. , RBDMSJ`' MAY 012018 Form 10-404 Revised 4/2017 Submit Original Only 11 • • Milne Point Unit Well: MPU B-32 SCHEMATIC Last Copleted: 3/10/2017 Hii!carp Alaska,LLC PTD: 216-151m Orig.KB Elev.:49.4'!GL Elev.:22.9' TREE&WELLHEAD TRKB—THF:23.13' Innovation) Tree Seaboard 3 1/8" 5M L 1 k. Seaboard 16 3/4"3M x 11"5M Multibowl w/11"x 3 1/2"EUE Top and 20' Wellhead Bottom with 3"CIW"H"BPV profile.2ea 3/8"NPT control lines. ,`$ OPEN HOLE/CEMENT DETAIL - 42" 50 bbls(10 Yards Pilecrete dumped down backside) "° t: 12-1/4"1st stage 590 sx 11.7#Extenda,210 sx 15.8#SwiftCEM 3-1/T i 4 2 12-1/4"2nd stage 311 sx 10.7#Perm L,280 sx 15.8#SwiftCEM ;. 8-1/2" Cementless Screens Liner in 8-1/2"hole 3 CASING DETAIL 'r1 Size Type Wt/Grade/Conn Drift ID Top Btm BPF ' 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,606' 0.0758 4 rit 7-5/8" Tieback 29.7/L-80/yam STL 6.750" Surface 5,416' 0.0459 358'`ES 4,'... 4-1/2" Liner(250µScreens) 13.5/13Cr-110/Vam Top HT 3.795" 5,837' 10,223' 0.0149 Cementer @ s 2,011' )' TUBING DETAIL i -----.... 5 3 1/2" Tubing 9.3/L-80/EUE 8rd 2.867" Surf 5,450' 0.0087 '141' '_ WELL INCLINATION DETAIL .sPe ts KOP @ 264' 6 Max Hole Angle=60.33 deg.@ XN profile «" Max Hole Angle=85.98 deg.@ Tubing tail i 11 Max Hole Angle=95.75 deg.@ 6,990'MD 7 JEWELRY DETAIL No. Top MD Item Drift ID .. . Upper Completion k ••• 8 .` 1 23' Tubing Hanger(3-1/2"EUE Top&Btm) 2.867" 'A 2 1,963' 3.5"X Nipple Assembly,2.813"Packing Bore 2.813" M li, 3 2,344' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,273)w/RK Latch(Set 3/12/17) 2.867" 7-5/8" - 9 4 3,222' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,264)w/RK Latch(Set 3/12/17) 2.867" 1.1 i,4 5 3,773' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,213)w/RK Latch(Set 6/26/17) 2.867" t� ,�® ®- 10 +^ 6 4,227' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,199)w/RK Latch(Set 6/26/17) 2.867 "7 7 4,648' 3.5"GLM SPMO-1.OM 1.5"(20/64 Orifice)w/RK Latch (Set 6/26/17) 2.867" )N 8 4,743' 3.5"XD Sliding Sleeve,X profile,2.813"seal bore 2.813" Mn ID 11 l; 9 4,801' 3.5"ROC Gauge Mandrel w/'A"TEC Wire 2.813" 2350" :i' 10 4,858' 7-5/8"Halliburton PHL Packer(45k Release) 2.885"' 13 11 4,916' 3.5"XN Nipple,Min ID=2.750"No-Go,2.813"Packing Bore 2.750" 114 12 5,417' 3-1/2"Jt w/Mule Shoe(Btm @ 5,450') 2.867" , -ASA Al 4111171;1 MI `'7,!..:1,,,-„'. 15 Lower Completion 13 5,405' 7-5/8"Tieback Assy.(8.25"OD No-Go @ 5,404') 6.151" 9-5/8"qI , 12 14 5,416' BOT SLZXP Liner Top Packer w/BD Slips 7"x 9-5/8" 6.200" ..---L..-_---...., 16 15 5,438' 7"Hydril 563 x 4-1/2"Hydril 521 L-80 XO 3.900" Pert ^� 16 5,705' 5-1/2"174Tendeka Swell Packer,Hybrid(10.88'Long) 4.767" 5,730'-5,736 =' "-MN.. -1 17 111765 7 5,778' S-1/2"17#Tendeka Swell Packer,Hybrid(10.90'Long) 4.767" , Squeeze 18 5,837' 4-1/2"Weatherford MaxFlo 316L 250 Micron RTD Screens(117 jts) 3.795" Cement 19 10,230' 4-1/2"Drillable Packoff Sub 2.400" UR Cement ti',* 20 10,259' WIV Valve LTC BxB(1.5"Ball on Seat/Closed;Btm @ 10,265') 5,945'to '� r 18 6,541' ,ye - „„,s, NOTE: Cement iii Perf holes at 5,730'-5,736'shot with 2-3/8”5 spf/60 deg GeoDynamics Razor in Liner Cement Squeeze#1:30 bbl 15.8 ppg w/minimal squeeze pressure 6,541' Cement Squeeze#2:30 bbl 15.8 ppg w/cement entering 4-1/2"liner Est End 4-1/2" of Cement Shoe @ 19 7,825' 10,265' ,. 20 i TD=10,265'(MD)/TD=4,251'(ND) PBTD=10,259'(MD)/TD=4,251'(TVD) Revised By:STP 4/30/2018 • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 Coil 50-029-23570-00-00 216-15 3/13/18 4/24/18 Daily Operations: 3/7/2018-Wednesday No activity to report. 3/8/2018-Thursday No activity to report. 3/9/2018- Friday No activity to report. 3/10/2018-Saturday No activity to report. 3/11/2018-Sunday No activity to report. 3/12/2018- Monday No activity to report. 3/13/2018-Tuesday MIRU SLB CTU #6 with 2" coil. Pressure test BOPE to 250 psi low for 5 minutes. Pressure test BOPE to 3,500 psi high for 10 minutes. No failures in BOPE test.;SDFN. Spot uprights and MU surface lines. Load uprights with SLK 1% KCI with 0.6% NXS. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 Coil 50-029-23570-00-00 216-15 3/14/18 4/24/18 Daily Operations: , I' 3/14/2018-Wednesday PU injector, 11' of lubricator, and BOPE. Run coil down and MU BHA#1-2" OD int dimple connector, 2.13" OD DBPV, 2.13" Disconnect(5/8" ball to release), PDS logging string, XO, 2.25" OD JSN. OAL= 15.35'. EOP to CCL is 11.25'. Stab on well. NU BOPE. Open SSV, install fusible cap. P/T to 250psi low and 3,500psi high. Pressure test surface lines the same. Open well and RIH w/BHA#1 while pumping at 1.5 bpm while taking returns to the tank. Encounter major solids from 8,000'to 9,000'.Tag bottom at 10, 175' ctmd (compression) and 10,170' ctmd (tension). Circulate hole clean by pumping 1.5 times BU volume. POH while logging from 10,170' MD at 66 fpm while circulating at 2 BPM. PowerVis is at nozzle at 7,800'. Slow pump rate to 1 BPM. Continue to POH at 66 fpm. Lay in 30 Bbls PowerVis pill from 7,800'to 5,800'. Flag pipe at 5,700'. Continue logging while POH to 5,400'. POH to surface. FP well and surface lines and coil tubing. Shut down for the night. Return tomorrow to set IBP, MIT, and displace to 9.4 ppg brine. 3/15/2018-Thursday SLB CTU#6 with 14,495' of 2" CT. CV=41.3 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU BHA#2- 2" OD int dimple connector, 2.13" OD DBPV, 2.13" Disconnect(5/8" ball to release),XO, 2.13" Inflation Valve, 2.13"Sceen Sub, 2.13" Running Tool, 2.13" Retrievable IBP. OAL= 20.27'. EOP to IBP Mid Element is 16.37'. Stab on well. NU BOPE. Fusible Cap is installed on SSV. P/T to 250psi low and 3,500psi high. P/T surface lines the same. Open well and RIH w/BHA#2 while taking coil displacement to the tank. WHP =120psi. Stop at flag at 5,700' ctmd. Make depth correction from yesterdays GR/CCL log. EOP at flag is 5,743'. Length of BHA from EOP to Mid Element is 16.37'. Flag puts mid element of IBP at 5,759'. Adjust depth accordingly. RIH to 5,825' and launch 1/2" ball. See good indication of ball on seat. Wait for temperature z)%.-- stabilization. )✓stabilization. Increase pressure to 500psi for 1 minute. Increase pressure to 1,000psi for 1 minute. Increase pressure to tra ; 1,500psi for 1 minute. Increase pressure to 2,000psi for 1 minute. Increase pressure to 2,100psi and shear. Sheared off and P/U off IBP.Test liner,tubing,and IBP to 1,250psi for 30 charted minutes. Lost 12psi during the first 15 minutes. Lost 4psi the last 15 minutes.Test is a pass. RBIH to top of IBP and lay in 1.5 bbls of PowerVis followed by 9.4 ppg NaCI brine to surface. Getting 1:1 returns. Good indication IBP is holding. FP tree and coil. Blow down surface lines. Prepare for tomorrow's operations.SDFN. Perf/Injectivity test/Cement squeeze tomorrow. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 Coil 50-029-23570-00-00 216-15 3/14/18 4/24/18 Daily Operations: 3/16/2018 Friday SLB CTU #6 with 14,908' of 2" CT. CV=41.3 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU BHA#3-2" OD int dimple connector, 2.11" OD DBPV,CBF Firing Head (1/2" ball), Spacer Gun,xo, 5.8' of 2-3/8" GeoDynamics gun with Razor charge 6 spf, Bottomnose. OAL= 16.07'. EOP to top shot=9.52'. Pressure test firing heads. Stab on well. NU BOPE. Fusible Cap is installed on SSV. P/T to 250psi low and 3,500psi high. P/T surface lines the same. Open well and RIH w/BHA#3 (perf gun). WHP=200psi. Stop at flag at 5,800' ctmd. Make depth correction based on GR/CCL log. EOP at flag is 5,800'. Length of BHA from EOP to top shot is 9.5'. Flag puts top shot at 5,809.5'. Adjust depth accordingly. POH to 5730' and launch 1/2" ball. See good indication of ball on seat at 37.5 bbls away. Perforate from 5,730 to 5,735.8'. Good indication of shots fired. WHP dropped 100psi. POH to 5,700' Perform injectivity test. 1BPM @ 297psi. 1.5 BPM @ 460psi. 2 BPM @ 610psi. 3 BPM @ 905psi. POH to surface with spent guns. WHP =185psi. Break and L/D BHA#3 and M/U BHA#4: 2" CTC, 2.11" MBT, 2.11" MBT, 2" xo, 2.25"JSN. OAL=9.42'. RIH w/BHA#4 to flag. Correct depth to 5,809.4'. Circulate in 9.4 ppg brine at 1.7 bpm at 2,270psi while taking returns to the tank. Rig up cementers. Perform injectivity test, 2 BPM @ 580psi. Cement wet at 15:30. Pump 5 Bbls Fresh Water, 30.5 bbls 15.8 ppg Class G Cement, 15 bbls fresh water, 15 bbls Power Vis at 2 BPM. Slow pump rate to 1 BPM when cement is 10 bbls away from nozzle. Cement at nozzle. At 15 bbls of cement behind pipe,WHP has increased to 345psi. Not seeing the desired build in WHP. Cement away behind pipe. At 30 bbls behind pipe,WHP increased to 400psi. Very little squeeze pressure built. RIH to above IBP and lay in 2 bbls of Power Vis gel to contaminate any possible cement. Open well and start taking returns Circulate 13 more bbls of PoweVis while chasing Powervis pill to surface. FP well from 500' and FP tree and surface lines.At surface. Close swab and secure well. SDFN. Repeat job tomorrow. 3/17/2018-Saturday SLB CTU #6 with 14,908' of 2" CT. CV=41.3 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU BHA#5- 2" CTC, 2.11" MBT, 2.11" MBT, 2" xo, 2.25"JSN. OAL=9.42'. Stab on well. NU BOPE. Fusible Cap is installed on SSV. P/T to 250psi low and 3,500psi high. P/T surface lines the same. Open well and RIH w/BHA#5 (cement nozzle). WHP=10psi. Stop at flag at 5,800' ctmd. Make depth correction based on GR/CCL log. EOP at flag is 5,800'. Length of BHA from EOP to top shot is 9.5'. Flag puts top shot at 5,809.42'.Adjust depth accordingly. POH to 5,700'. Circulate in 9.4 ppg brine at 1.7 bpm at 2300psi while taking returns to the tank. Rig up cementers. Perform injectivity test. 1BPM @ 250psi. 1.5 BPM @ 300psi. 2 BPM @ 315psi. Cement wet at 11:40. Pump 5 Bbls Fresh Water, 30.4 bbls 15.8 ppg Class G Cement, 15 bbls fresh water, 15 bbls Power Vis at 2 BPM.Slow pump rate to 1 BPM when cement is 10 bbls away from nozzle. WHP =360psi. Cement at nozzle. WHP=386psi At 15 bbls of cement behind pipe,WHP has increased to 490psi. Cement away behind pipe. At 30 bbls behind pipe, WHP increased to 550psi. Shut down pumps.WHP bled from 550psi to 500psi in 10 minutes. RIH to above IBP and lay in 2 bbls of Power Vis gel to contaminate any possible cement. Circulate 13 more bbls of PoweVis while chasing Powervis pill to surface while taking returns to the tank. FP well from 500' and FP tree and surface lines. At surface. Close swab and secure well. SDFN. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-32 Coil 50-029-23570-00-00 216-15 3/14/18 4/24/18 y p 3/18/2018DailOerations:Sunday SLB CTU #6 with 14,908' of 2" CT. CV=41.3 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU BHA#6-2" CTC, 2.13" DBPV, 2.25"Jar, 2.13"TJ Disconnect, 2.13" Dual Circ Valve (1/2" ball), 2.13"Xtreme Motor, 2.63" DB Underreamer. OAL= 22.7'. Coil tubing connector failed pressure test. Send for new CTC at Baker shop. Stab on well. NU BOPE. Fusible Cap is installed on SSV. P/T to 250psi low and 3,500psi high. P/T surface lines the same. Open well and RIH w/ BHA#6(underreamer). WHP=120psi. RIH and tag IBP at 5,822' Paint flag. PU to 5420'. Circulate 41 bbls of 60/40 McOH out of coil at 0.5 BPM. RIH and underream at 1.5 BPM and 1600psi to 5821'. No indication of cement. Drop 0.5" ball and open circ sub. Circ sub opens at 3000psi. POH w/BHA#7 to surface while circulating 60/40 McOH into coil. Break and L/D BHA#7 and M/U BHA#8: 2" CTC, 2.13" DBPV, 2.25"Jar, 2.13"TJ Disconnect, 2" Rupture Sub, 2.13" Centralizer, 2.18" XO, 2.63" Overshot. OAL= 15.24'. M/U lubricator to tree. P/T 250 low and 3,500 high. RIH w/BHA#8 (Overshot)to IBP. Obtain P/U weight at 5,700' of 14k-lbs.Tag and latch IBP at 5822' . P/U and overpull 7k-lbs. IBP is free. Let element relax prior to pulling out of hole. POH w/IBP to surface. NO over pulls as POH. Freeze protect well from 500'.At surface. FP tree. Close Swab valve. SDFN. 3/19/2018-Monday MIRU SLB CTU #6 with 15,150' of 2" CT. CV=41.3 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU BHA #1-2" OD int dimple connector, 2.13" OD DBPV, 2.11" Disconnect, 2.11" MBT, 2.11" MBT,XO, 2.25" OD JSN. OAL= 12.44'. Stab on well. NU BOPE. Open SSV,fusible cap installed. P/T to 250psi low and 3,500psi high. Open well and RIH w/nozzle while pumping at 0.5 bpm while taking returns to the tank. WHP= 65psi. Tag at 5,945'. P/U weight=5.9k-lbs. Consult town. Decision made to pick up Underreamer. POH w/nozzle to surface. Wait for Underreamer BHA. Injection test down well at 3 BPM and 380psi. 2" CTC, 2.13" DBPV, 2.25"Jar, 2.13"TJ Disconnect, 2.13" Dual Circ Valve (1/2" ball), 2.13" Xtreme Motor, 2.63" DB Underreamer. OAL=22.7'. Stab on well. P/T to 250psi low and 3,500psi high. RIH w/underreamer to 5,930' . n Circulate 60/40 McOH out of coil at max rate of 0.5 BPM while taking returns to the tank. Free spin at 1.5 BPM at 1,450psi. Mill cement from 5,945'to 6,115'. Drop ball to open circ sub and slowly POH from 6,115'to 5,475'. Circ sub open. POH to surface with underreamer. At surface. Close Swab. L/D Underreamer. Underreamer to be inspected and have knives replaced. FP Tree and blow down surface lines.SDFN 3/20/2018-Tuesday SLB CTU #6 with 15,150' of 2" CT. CV=41.3 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU 2" CTC, 2.13" DBPV, 2.25"Jar, 2.13"TJ Disconnect, 2.13" Dual Circ Valve (1/2" ball), 2.13" Xtreme Motor, 2.63" DB Underreamer. OAL=22.7'.Stab on well. NU BOPE. Open SSV,fusible cap installed. P/T to 250psi low and 3,500psi high. Open well and RIH w/nozzle while pumping at 0.5 bpm while taking returns to the tank. WHP= 100psi. Circulate out 60/40 McOH at 0.5 bpm at 5,700'.Tag at 6,144' (Corrected depth using flag to correct). P/U weight= 15k-lbs. Free spin at 1.5 BPM at 1,400psi. Begin milling cement from 6,144' at 1.5 BPM and 1,450psi. Milled to 6,232'. Drop ball to open circ sub and slowly POH from 6,232' to 5,475'. Circ sub open. POH to surface with underreamer. FP well from 2,500'with 60/40 McOH.At surface. Close Swab. L/D Underreamer. FP Tree and blow down surface lines. RDMO CTU 6 to Deadhorse for Maintenance. Return with Unit 4 tomorrow to go to MPL-20. Return to MPB-32 in a few days. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Ili MP B-32 Coil 50-029-23570-00-00 216-15 3/14/18 4/24/18 Daily Operations: 4/18/2018-Wednesday No activity to report. 4/19/2018-Thursday No activity to report. 4/20/2018- Friday No activity to report. 4/21/2018-Saturday No activity to report. 4/22/2018-Sunday MIRU SLB CTU#6 with 16,725' of 1.75" CT. CV=33.6 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU 2.25" CTC, 2.13" DBPV, 2.13"Jar, 2.13"TJ Disconnect, 2.13" Dual Circ Valve (1/2" ball), 2.13"Xtreme Motor, 2.63" 5 Bladed Junk Mill. OAL=24.36'. Stab on well. NU BOPE. Open SSV,fusible cap installed. P/T to 250psi low and 3,500psi high. Open well and RIH w/nozzle while pumping at 0.3 bpm to displace McOH while taking returns to the tank. WHP= 100psi Tag at 6232'. Fr,eespin at 1.5 BPM is 1800psi. Mill from 6,232'to 6,305'. Send 5 bbl NVis gel sweeps as needed.Working fluid is 1% slk KCL with 0.6% NXS. POH to surface. FP well, coil, surface lines. Stand back injector. SDFN. 4/23/2018- Monday SLB CTU #6 with 16,725' of 1.75" CT. CV=33.6 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU 2.25" CTC, 2.13" DBPV, 2.13"Jar, 2.13"TJ Disconnect, 2.13" Dual Circ Valve (1/2" ball), 2.13"Xtreme Motor, 2.63" Underreamer with 3.87" expansion knives, 2.7" 5 Bladed Junk Mill. OAL=24.36'. Stab on well. NU BOPE. Open SSV, fusible cap installed. P/T to 250psi low and 3,500psi high.;Open well and RIH while pumping at 0.3 bpm to displace McOH while taking returns to the tank. WHP= 100psi.TagOpen well and RIH while pumping at 0.3 bpm to displace McOH while taking returns to the tank. WHP = 100psi Tag at 6,305'. P/U weight= 14k-lbs. Freespin at 1.5 BPM is 2,000psi. Mill from 6,305'to 6,450' at 1.5 BPM with circulation pressures ranging from 2,100psi to 2,400psi. Send 5 bbl gel pills as needed. Circulate 10 bbl gel sweep followed by 50 bbls of 1% KCL and 34 Bbls of 60/40 McOH. POH to surface. Shut down pumps.At surface. FP well and tree. SDFN. 4/24/2018-Tuesday SLB CTU#6 with 16,725' of 1.75" CT. CV=33.6 bbls. PU injector, 11' of lubricator, and BOPE. Run coil down and MU 2.25" CTC, 2.13" DBPV, 2.13"Jar, 2.13"Ti Disconnect, 2.13" Dual Circ Valve (1/2" ball), 2.13"Xtreme Motor, 2.63" Underreamer with 3.87" expansion knives, 2.7" 5 Bladed Junk Mill. OAL= 24.36'. Stab on well. NU BOPE. Open SSV,fusible cap installed. P/T to 250psi low and 3,500psi high. Open well and RIH while pumping at 0.3 bpm to displace McOH while taking returns to the tank. WHP= 100psi Tag at 6,450'. P/U weight= 14k-lbs. Free spin at 1.5 BPM at 2000psi. Mill from 6,450'to 6,541' while circulating at 1.5 BPM with 1%$ KCL with 0.6% NXS. Send 5 bbl gel sweeps as needed. Circulate 10 bbl gel sweep followed by 10 bbls of 1% KCL and drop ball for circ sub. POH to surface while circulating at 2 BPM. Shut down pumps. At surface. FP well to 2,500' and tree. Close Swab. Remove Fusible. L/D BHA. Cut pipe. RDMO. • • Schwartz, Guy L (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Wednesday, May 02,2018 12:00 PM To: Schwartz, Guy L(DOA) Subject: RE: B-32 cement sqz PTD 216-151(sundry 318-030) li Guy, It appears that the during the 2^d cement squeeze,we had some cement go on the outside of the 4-1/2" liner and hea toward the toe of the well and enter through a suspected hole in the 4-1/2" screens (we have seen solids that average 490 microns, larger than the 250 micron screens). Estimated entry point is+/-6,234', based on a production log we di that showed a significant fluid entry point. The cement then ended up inside the 4-1/2" liner.Total length of+/- 30 bbl of cement inside the 4-1/2" (minus a few barrels on the outside, so assuming 28 bbl inside the liner)would be 1,879' of cement. Coil has milled up 596', so 1,283' left of cement possible in the 4-1/2". The good thing is it looks like the isolation of the water was successful because the BHP has dropped by over 200 psi and is tracking the estimated reservoir pressure that we would expect from the other offset producer B-28 in the same N- sands of the Schrader Bluff. Stan From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Wednesday, May 02,2018 10:52 AM To:Stan Porhola<sporhola@hilcorp.com> Subject: B-32 cement sqz PTD 216-151(sundry 318-030) Stan, I was reviewing the sundry report.. not sure I understand what happened to the cement. Doesn't look like job went as planned. Do you know what happened? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it tb you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). 1 III SII vOF 71i, • • THE STATE Alaska Oil and Gas °fALA J( 1 Conservation Commission __ ------ t 333 West Seventh Avenue F GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 °A' Q, Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager Hilcorp Alaska, LLC SCANNED ,-7E13 2 2014. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-32 Permit to Drill Number: 216-151 Sundry Number: 318-030 Dear Mr. York: Enclosed is the approved application for 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, 62c:cr Hollis S. French Chair DATED this 3 t day of January, 2018. RCD! LL- L2). - 1 2C18 RECEIVED JAN 14018 // STATE OF ALASKA OTSi'3 lc ALASKA OIL AND GAS CONSERVATION COMMISSION AOGC APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Repair Well 0 Operations shutdown Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other. Coil Cement Squeeze0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Hilcorp Alaska LLC Exploratory 0 Development 0 ^ 216-151 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service 0 6.API Number. Anchorage Alaska 99503 50-029-23570-00-00• 7.If perforating: 8,Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 • Will planned perforations require a spacing exception? Yes 0 No 0 • MILNE PT UNIT 6-32 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL047438/ADL047437 • 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(MD): Junk(MD): 10,265 a 4,251' . 10,259' • • 4,251' 1,462 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 107' 20" 107' 107' N/A N/A Surface 5,606' 9-5/8" 5,606' 4,396' 5,750psi 3,090psi Tieback 5,416' 7-5/8" 5,416' 4,394' 6,890psi 4,790psi Liner 4,386' 4-1/2" 10,223' 4,253' N/A N/A Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic • See Schematic 3-1/2" 9.3/L-80/EUE 8rd 5,450' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 7-5/8"PHL&BOT SLZXP and N/A 4,858 MD/4,208 TVD& 5,416 MD/4,393 TVD and N/A 12.Attachments: Proposal Summary 0 Wellbore schematic ❑s 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch L"]'. Exploratory 0 Stratigraphic 0 Development • Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 2/6/2018 OIL CI , WINJ 0 WDSPL ❑ Suspended 0 16.Verbal Approval: Date: GAS 0 WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown 0 Abandoned 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 519 Authorized Name: Bo York Contact Name: Stan Porhola Authorized Title: Operations Manager Contact Email: Sporhola CAhilcorp.com u • Ica Contact Phone: 777-8412 Authorized Signatur . Date: 1 COMMISSION USE ONLY Conditions of approval: ify Commission so that a representative may witness Sundry Number:316-03O Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: Post Initial Injection MIT Req'd? Yes 0 No 0 1 q q Spacing Exception Required? Yes No Subsequent Form Required: r RETm°- 0.— l `s ' 1 L(J IS H pp y Cr 1 APPROVED BY t 11! IK Approved b : Q1O�J : �..," COMMISSIONER THE COMMISSION SSION Date: P4 iIzylii 1- &.7) -/ f3 74._ ,s,te (14i0,4/9 n r,), i r", 1 NA .„, , k I 8,0, i Submit Form and Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate • • Well Prognosis Well: MPU B-32 Hilcorp Alaska,Lb Date: 1/24/2018 Well Name: MPU B-32 API Number: 50-029-23570-00 Current Status: SI Oil Well [Gaslift] Pad: B-Pad Estimated Start Date: February 06th, 2018 Rig: Coil Tubing Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 216-151 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Paul Chan (907) 777-8333 (0) (907)444-2881 (M) AFEN, umber 17 , 4 Ih1yh S �iter • • ShLi Current Bottom Hole Pressure: 1,862 psi @ 4,000' TVD (SBHPS 1/03/2018 /8.96 ppg EMW) Maximum Expected BHP: 1,862 psi @ 4,000' TVD (No new perfs being added) MPSP: 1,462 psi (0.1 psi/ft gas gradient) Brief Well Summary: The Milne Point MPU B-32 was drilled in 2017 using Hilcorp's Innovation Rig #1 and completed as a horizontal gaslifted producer in the Schrader Bluff NC sand. The well was shut-in in August 2017 due to high water production and solids production. Indications are that the water and solids are coming from the Ugnu sands above the 9-5/8" casing shoe. Notes Regarding Wellbore Condition • Tubing last tested to 3,800 psi for 30 min down to 4,916'on 3/10/2017. • Casing IA(3-1/2" x 7-5/8") last tested to 3,000 psi for 30 min down to 4,858' on 3/10/2017. • Casing OA(7-5/8" x 9-5/8")tested to 1,000 psi for 30 min down to 5,416' on 8/16/2017. • Max angle 87.5° @ 5,417' at the tubing tail. Lateral max angle is 95.75° @ 6,990' • Min ID is 2.750" thru XN profile at 4,916' MD below the PHL Packer at 4,858' MD. Objective: The purpose of this work is to punch holes with coil tubing below the 9-5/8" casing shoe and squeeze off the shoe with cement to isolate the water production. • Work Procedure: Coiled Tubing Procedure: 1. MIRU Coiled Tubing Unit and spot ancillary equipment. Fill source tank w/9.4 ppg NaCI/KCI brine. 2. Pressure test BOPE to 3,500 psi Hi 250 Low, 10 min Hi, 5 min Low each test. a. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. b. No AOGCC notification required. c. Record BOPE test results on 10-424 form. 3. RIH w/2.00" coil and cleanout to end of screens at+/- 10,223' MD, drift thru 2.75" min ID. POOH. 4. MU GR/CCL. RIH w/2.00" coil and log from end of screens at+/- 10,223' MD to liner top packer at+/- 5,400' MD. POOH. 5. MU inflatable bridge plug. RIH and set in the 4-1/2" liner just above the screens at+/-5,837'. Approx. set depth is+/-5,825'. S Well Prognosis Well: MPU B-32 Hilcora Alaska,LL, Date: 1/24/2018 6. Test liner and inflatable plug to 1,000 psi for 30 min. POOH. 7. RIH w/2.00" coil and spot a light-weight viscosified plug (weight to be less than 8.0 ppg due to well c„,, angle going uphill at this part of the wellbor o a ow it to float above 9.4 ppg brine in the rest of the ` well) above the inflatable bridge plug at+/- 5,825' [hole angle 930]. Est.volume is+/- 1.5 bbl (100 ft 0, U length) [4-1/2" capacity=0.01522 bbl/ft]. POOH. a. Note:light-weight plug used to protect inflatable plug fishing neck from getting covered in cement. Well angle at 93°-94°(going uphill)starting at 5,574'MD. 8. PU to just below upper Swell Packer at+/-5,710' and circulate the well clean. POOH. 9. MU 5'tubing ppnch/perf gun. RIH w/2.00" coil and spot punch/guns just below upper Swell Packer at +/-5,710'. Punch/perf holes with top shot at+/-5,725. r w 10. Perform injectivity test into holes, ramping up to 4.0 bpm or 1,500 psi above circulating pressure, whichever occurs first. POOH. a. Contingency: If unable to establish injectivity, repeat steps#9-#10 (re-punch/perf). b. Make top shot at+/- 5,720' (5' below previous). 11. MU squeeze BHA w/inflatable bridge plug. RIH w/2.00" coil to+/-5,675' (+/-50' above punch/perf holes). 12. Set inflatable bridge plug and perform injectivity test into holes, ramping up to 4.0 bpm or 1,500 psi above circulating pressure,whichever occurs first. e. 13. Mix and pump +/- 30 bbl of 15.8 ppg cement and squeeze into punch/perf holes,_Do not exceed , 5 pressure of prior injectivity test. 14. Unset inflatable bridge plug, pumping cement retarding additives to the end of coil. 15. POOH w/inflatable bridge plug. 16. Wait on cement 24 hours. 17. MU milling BHA. RIH w/2.00" coil to+/-5,675'. Mill cement and circ out weighted barite plug down to MwL/ inflatable bridge plug at+/-5,825'. POOH. r 18. MU retrieval tool. RIH w/2.00" coil to inflatable bridge plug at+/-5,825'. 19. Pressure test cement squeeze to 1,000 psi for 5 a. Contingency: If unable to pressure up against squeeze perfs, repeat steps#11 -#19 (re-squeeze). 20. Retrieve inflatable bridge plug. POOH. 21. RIH w/2.00" coil and cleanout to end of screens at+/- 10,223' MD, drift thru 2.75" min ID. 22. PU to 2,500' and freeze protect well. POOH w/coil. 23. RD Coiled Tubing and ancillary equipment. 24. Turn well over to production. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Coil BOPE Schematic • Milne o • Well: MPPintU B-32Unit SCHEMATIC Last Completed: 3/10/2017 iHilcorp Alaska,LLC PTD: 216-151 Orig.KBEIev.:49.4'/GLEIev.:22.9' TREE&WELLHEAD TRKB—THF:23.13' Innovation) Tree Seaboard 3 1/8" 5M i ° 1 Seaboard 16 3/4"3M x 11"5M Multibowl w/11"x 3 1/2"EUE Top and 20„ 0 I� c u Wellhead Bottom with 3"CIW"H"BPV profile.2ea 3/8"NPT control lines. OPEN HOLE/CEMENT DETAIL 42" 50 bbls(10 Yards Pilecrete dumped down backside) 12-1/4"1st stage 590 sx 11.74 Extenda,210 sx 15.84 SwiftCEM # 2 )' 12-1/4"2nd stage 311 sx 10.74 Perm L,280 sx 15.84 SwiftCEM 3-1/2" ''l : « 8-1/2" Cementless Screens Liner in 8-1/2"hole 3 ' CASING DETAIL t', 0 Size Type Wt/Grade/Conn Drift ID Top Btm BPF to : 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,606' 0.0758 4 7-5/8" Tieback 29.7/L-80/Vam STL 6.750" Surface 5,416' 0.0459 g � i''. 4-1/2" Liner(2S0µScreens) 13.5/13Cr-110/Vam Top HT 3.795" 5,837' 10,223' 0.0149 Cementiii 2,011' @ TUBING DETAIL -,,, 1 5 3-1/2" Tubing 9.3/L-80/EUE 8rd 2.867" Surf 5,450' 0.0087 '� 4 WELL INCLINATION DETAIL w �1 KOP @ 264' t 6 V Max Hole Angle=60.33 deg.@ XN profile i Max Hole Angle=85.98 deg.@ Tubing tail Max Hole Angle=95.75 deg.@ 6,990'MD 4. 7g JEWELRY DETAIL No. Top MD Item Drift ID 111 L4 Upper Completion e) ai, 1 23' Tubing Hanger(3-1/2"EUE Top&Btm) 2.867" 2 1,963' 3.5"X Nipple Assembly,2.813"Packing Bore 2.813" TO 3 2,344' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,273)w/RK Latch(Set 3/12/17) 2.867" 7-5/8"--00--• , 9 , 4 3,222' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,264)w/RK Latch(Set 3/12/17) 2.867" 5 3,773' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,213)w/RK Latch(Set 6/26/17) 2.867" 4. 10 6 4,227' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,199)w/RK Latch(Set 6/26/17) 2.867" s 7 4,648' 3.5"GLM SPMO-1.0M 1.5"(20/64 Orifice)w/RK Latch (Set 6/26/17) 2.867" �4—^ 8 4,743' 3.5"XD Sliding Sleeve,X profile,2.813"seal bore 2.813" Mn IDy, ,..--►4i,j 11 (,�: 6l`'t 9 4,801' 3.5"ROC Gauge Mandrel w/'A"TEC Wire 2.813" 2.750" L. .1 . . watt— 10 4,858' 7-5/8"Halliburton PHL Packer(45k Release) 2.885" 13 M 11 4,916' 3.5"XN Nipple,Min ID=2.750"No-Go,2.813"Packing Bore 2.750" iil _ 12 5,417' 3-1/2"it w/Mule Shoe(Btm @ S,450') 2.867" ` - - , •41 Lower Completion 9-5/8 15 13 5,405' 7-5/8"Tieback Assy.(8.25"OD No-Go @ 5,404') 6.151" 1 I 11 14 5,416' BOT SLZXP Liner Top Packer w/BD Slips 7"x 9-5/8" 6.200" — I — 165'705, 15 5,438' 7"Hydril 563 x 4-1/2"Hydril 521 L-80 XO 3.900" "•_ —, 175 77e, 16 5,705' 5-1/2"174 Tendeka Swell Packer,Hybrid(10.88'Long) 4.767" ,� 17 5,778' 5-1/2"174 Tendeka Swell Packer,Hybrid(10.90'Long) 4.767"i,Vii SS.3 74 18 5,837' 4-1/2"Weatherford MaxFlo 316L 250 Micron RTD Screens(117 jts) 3.795" _' 19 _ 10,230' 4-1/2"Drillable Packoff Sub 2.400" I. a` 20 10,259' WIV Valve LTC BxB(1.5"Ball on Seat/Closed;Btm @ 10,265')0. - 18 bit zit . D� 11 Z_' 4-1/2" Shoe @-: t 19 10,265' ':a 20 TD=10,265'(MD)/TD=4,251'(TVD) PBTD=10,259'(MD)/TD=4,251'(TVD) Revised By:TDF 8/25/2017 II • • Milnll:e MPU PoinB-32 t Unit We PROPOSED Last Completed: 3/10/2017 11licorp Alaska.LLC PTD: 216-151 Orig.KB Elev.:49.4'/GL Elev.:22.9' TREE&WELLHEAD TRKB—THF:23.13' Innovation) Tree Seaboard 3 1/8" 5M (. ii° Seaboard 16 3/4"3M x 11"SM Multibowl w/11"x 3 1/2"EUE Top and 20" ` 1 Wellhead Bottom with 3"CIW"H"BPV profile.2ea 3/8"NPT control lines. i OPEN HOLE/CEMENT DETAIL 1 it 42" 50 bbls(10 Yards Pilecrete dumped down backside) '° ' 12-1/4"1st stage 590 sx 11.7#Extenda,210 sx 15.84 SwiftCEM a9 ` 2 31/2„ a4 —► 12-1/4"2nd stage 311 sx 10.74 Perm L,280 sx 15.84 SwiftCEM 8-1/2" Cementless Screens Liner in 8-1/2"hole 3ili CASING DETAIL # Fto. Size Type Wt/Grade/Conn Drift ID Top Btm BPF P 1111 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A ci 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,606' 0.0758 il 4 7-5/8" Tieback 29.7/L-80/Vam STL 6.750" Surface 5,416' 0.0459 198'ES' 4-1/2" Liner 250 Screens) 13.5 13Cr-110 Vam TopHT 3.795" 5,837' 10,223' 0.0149 Cementer @ a ( µ / / 2,011 P TUBING DETAIL )t 5 3-1/2" Tubing 9.3/L-80/EUE 8rd 2.867" Surf 5,450' 0.0087 '�01t 01 WELL INCLINATION DETAIL il s KOP@264' F 6 Max Hole Angle=60.33 deg.@ XN profile Max Hole Angle=85.98 deg.@ Tubing tail Max Hole Angle=95.75 deg.@ 6,990'MD 44 7 V JEWELRY DETAIL g No. Top MD Item Drift ID Upper Completion oi- ••• a 1 23' Tubing Hanger(3-1/2"EUE Top&Btm) 2.867" $ 2 1,963' 3.5"X Nipple Assembly,2.813"Packing Bore 2.813" 3 2,344' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,273)w/RK Latch(Set 3/12/17) 2.867" 7-5/8"—1 --) - 9 ''. 4 3,222' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,264)w/RK Latch(Set 3/12/17) 2.867" 5 3,773' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,213)w/RK Latch(Set 6/26/17) 2.867" r`, `®. 10 6 4,227' 3.5"GLM SPMO-1.0M 1.5"GLV(12/64 TRO 1,199)w/RK Latch(Set 6/26/17) 2.867" + 7 4,648' 3.5"GLM SPMO-1.0M 1.5"(20/64 Orifice)w/RK Latch (Set 6/26/17) 2.867" $`s 4j 8 4,743' 3.5"XD Sliding Sleeve,X profile,2.813"seal bore 2.813" Nin ID....4. ....--1. y c{11 14 9 4,801' 3.5"ROC Gauge Mandrel w/'A"TEC Wire 2.813" 2,750 3 10 4,858' 7-5/8"Halliburton PHL Packer(45k Release) 2.885" y' 13 "„ 11 4,916' 3.5"XN Nipple,Min ID=2.750"No-Go,2.813"Packing Bore 2.750" 12 5,417' 3-1/2"Jt w/Mule Shoe(Btm @ 5,450') 2.867" 14 Lower Completion �• �r^ra��rs• � 15 g5/g 1 13 5,405' 7-5/8"Tieback Assy.(8.25"OD No-Go @ 5,404') 6.151" wiliiVi 12 14 5,416' BOT SLZXP Liner Top Packer w/BD Slips 7"x 9-5/8" 6.200" =�. ►_-�. 16 15 5,438 7"Hydril 563 x 4-1/2"Hydril 521 1-80 XO 3.900" s 17 16 5,705' S-1/2"17#Tendeka Swell Packer,Hybrid(10.88'Long) 4.767" 17 5,778' 557":11H//22y -1/2"17#Tendeka Swell Packer,Hybrid(10.90'Long) 4.767" Proposed18 5,837' 4-1/2"Weatherford MaxFlo 316L 250 Micron RTD Screens(117 jts) 3.795" Squeeze Punch/Pert 19 10,230' 4-1/2"Drillable Packoff Sub 2.400" +/-5,725' merrt 20 10,259' WIV Valve LTC BxB(1.5"Ball on Seat/Closed;Btm @ 10,265') _ _ 18 i.rt.'-''' 4-1/2"1/ Shoe @ Iii:,_, 19 10,265' 20 TD=10,265'(MD)/TD=4,251'(TVD) PBTD=10,259'(MD)/TD=4,251'(TVD) Revised By:STP 1/23/2018 • • II COIL BOPS MILNE POINT UNIT MPU B-32 Hilcorp Alaska,LLC 10/20/2017 MPU B-32 20X9% X7% X 3% Coil Tubing BOP r Lubricator to injection head o (ill 11112.00"Single Stripper L I 1lit MI, 1/1610 -Blind/ShearBlind/Shear- = ,l■'" IIIBlind/Shear!_ allir® "`Blind/Shear�111I.1Ili' MIN nit 01111 Slip i® ® 11111— Slip I1011 1 I lain Pipe - ....._ =® Pipe ,l,'.: iii iei Crossover spool i� sew 4 1/16 10M X 4 1/16 5M i__._._ i• ; Pump-In Sub i i; :JII .. 411,� F�,!',1 °r • - •�9'® �� 1502 Union r.4 : I. i i le; Manual Gate Manual Gate Crossover spool 2 1/8 5M 2 1/8 5M 4 1/16 5M X 3 1/8 5M Valve,Swab,WKM-M, 3 1/8 5M FE �`°,J "r• ��n�O<Pfk Th. P 111111:114 N KO IC({(;t O ' i Valve,Upper Master,Baker, 3 1/8 5M FE,w/Hydraulic 0 1111D, Ain Valve,Lower Master,WKM-M, itz,: 3 1/8 5M FE Tubing Adapter,3 1/8 5M , ,( lip • • Schwartz, Guy L (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Tuesday, January 30, 2018 1:13 PM To: Schwartz, Guy L(DOA) Subject: RE: B-32 CT sqz. (PTD 216-151) Attachments: Tendeka Hybrid Swell Chart (MPU B-32).pdf Guy, When we brought this well online, we assumed the initial water was drilling fluids, but after 2 weeks and larger water volumes and rapidly dropping oil rates made it clear that if was water influx. We ran a production log on 8/22/17 on coil tubing, and found a colder fluid entry at 6,234' MD. Normal BHT= 85F. The temperature drop was not dramatic but was a clear 1 degree drop. In review of our cement job for the 9-5/8" surface casing,the job was textbook and 263 bbl of 11.7 ppg lead cement and 43 bbl of 15.8 ppg tail cement were pumped with full returns while reciprocating the pipe, bumping the plug and the floats held. A FIT test to 12.0 ppg was conducted on 2/27/17. No CBL was ran. We believe that a wet Ugnu sand at 5,115'-5,135' is the most likely candidate to be contributing water to the well, since the logs found no water in any of the N-sands drilled in this well and the well is not located next to an oil-water contact. This Ugnu sand would be contributing thru a small micro-annulus that ran from the sand at 5,115'-5,135' MD (Hole angle 70 deg) to the shoe at 5,606' MD (Hole angle 93 deg). It is possible that with some minor washout,the swell packers were swelling and holding back the majority of the water but were progressively flow cut over time and eventually allowed excessive water from the Ugnu to reach the screens.There were also some solids production noticed before it was shut-in. Here is a quick history on this well: 3/06/17: Ran 4-1/2" liner w/swell packers 3/16/17: Bring well on production (gaslift), swell packers at 10 days of swell (See attached info on the Tendeka Swell Packers) Date Oil Rate Water Rate 3/16/2017 2000 50 3/31/2017 1300 350 4/15/2017 850 430 5/15/2017 750 430 5/29/2017 430 1140 6/29/2017 248 989 7/28/2017 229 644 7/30/2017 146 2952 8/3/2017 214 2394 8/7/2017 216 2104 1 8/07/17:Well shut-in due to solids • • 8/27/17: Ran production log on coil Stan From:Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday,January 29, 2018 4:15 PM To:Stan Porhola <sporhola@hilcorp.com> Subject: B-32 CT sqz. (PTD 216-151) Stan, I am curious was led you to think the water was coming from the Ugnu? Wouldn't the two upper swell packers (if working properly) keep the water/solids from getting down to the screens and thus getting produced. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). 2 MEL • • SwellRightTM Packer TENDEKA 5.500"x 8.130"x 10 ft long Hybrid Swell Packer(THC) Our Ref.:U51180 Ver.1 Product Number: 001-05500-00-XXX November 8 201(01) Customer Data Packer Specifications Customer/Location Hilcorp/Alaska Pipe Diameter 5.500" 139.7 mm Project/Well Name Pipe Weight 17.00 lb/ft 25.3 kg/m Bottleneck ID 8.500" 215.9 mm Pipe Connection/Grade Tenaris 625/L-80 Hole Size 8.500" 215.9 mm Element OD 8.125" 206.4 mm Bottom Hole Temperature 75 deg F 24 deg C End Ring OD 8.130" 206.5 mm Required AP Rating @ 8.500"OH 10000 psi 68.9 MPa Pipe Length 18'0" 5486 mm Swell Fluid Type 1.0%(RIH)/1.0%(g/100cc) Element Length 10'0" 3048 mm Handling Room-Top 5'0" 1524 mm Performance Summary Handling Room-Bottom 2'6" 762 mm Hole Size Contact Time Set Time AP Swelling Compound/Fluid THC- (6100 ppm Cl-) (inches) (mm) (days) (days) (psi) (Mpa) 8.243 209.4 0.5 - - - 8.250 209.6 0.6 3.8 10,000 68.9 8.375 212.7 2.2 7.2 10,000 68.9 8.500 215.9 5.0 11.8 10,000 68.9 8.625 219.1 8.9 17.4 10,000 68.9 8.750 222.3 13.9 24.2 10,000 68.9 8.875 225.4 20.0 32.1 10,000 68.9 9.000 228.6 27.2 41.1 10,000 68.9 9.125 231.8 35.6 51.2 9,600 66.2 9.250 235.0 45.0 62.5 9,300 64.1 Time to Contact(TTC), Required Pressure(TTRP)and Full Pressure(TTFP) 9.625 - 9.375 --- -. 60" L 9.125 W ", 8.875 I 8.625 TTC 1 \ 3" .w�.wTTRP , , 8.375 g T _.._.... ._ TTFP 8.125 , .._ 0.0 20.0 40.0 60.0 80.0 100.0 Swell Time(days) 216" 120" Differential Pressure Rating versus Hole Size 12000 10000 - 4 0000 4 ► 3.. a 6000 .. C 4000 --- - - I ..--0preq e 2000 - _ __.. AP Max 30" 0 __ __ l 8.125 8.375 8.625 8.875 9.125 9.375 9.625 Hole Size(inch) The above results are obtained using proven engineering practices&calculations in conjunction with laboratory test data.Tendeka however cannot and does not make any warranty, expressed or implied to the ultimate accuracy of this data due to the numerous variable conditions that these products can ultimately be exposed to. CO 2014 Tendeka B.V.All rights reserved. • • 216151 Debra Oudean Hilcorp Alaska, LLC 6 1 5 [� GeoTech \'C 3800 Centerpoint Drive, Suite 1400 Anch , AK RECEI 11 ED Tele:orage907 777-833995037 Fax: 907 777-8510 SEP 21 2017 E-mail: doudean@hilcorp.com Da /GAG ((��((��`` M.K.BENDER DATE 09/21/2017 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-32 Prints: Memory Production Profile GR/CCL/PRESS/TEMP/SPINNERS CD's HILCORP MPB-32 PPROF 22AUG17 FINAL Please include current contact information if different from above. 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Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC ' Aband.: 3/10/2017 216-151 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 February 16,2017 50-029-23570-00-00 • 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 56'FSL,4321'FEL,Sec 18,T13N, R11 E, UM,AK March 3,2017 MPU B-32 • Top of Productive Interval: 9. Ref Elevations: KB: 49.4 17. Field/Pool(s):Milne Point Unit 140'FSL,2058'FEL,Sec 13,T13N, R10E, UM,AK GL:22.9' BF:22.9' Schrader Bluff Oil Pool = Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 2385'FNL, 196'FEL, Sec 14,T13N, R10E, UM,AK 10,259'MD/4,250'TVD ' ADL047438/ADL047437 • 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 571970 y- 6023179 Zone- 4 10,265'MD/4,250'TVD . N/A TPI: x- 569020 y- 6023235 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MDITVD: Total Depth: x- 565576 y- 6025958 Zone- 4 N/A 1,688'MD/1,564'TVD 5. Directional or Inclination Survey: Yes Q(attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and,pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to: mud log,spontaneous potential, gamma ray,caliper, resistivity,porosity,magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary ROP-DGR-ADR-EWR 21N MD, DGR-ADR-EWR 21N TVD EC R EIVED APR 0 7 2017 23. CASING, LINER AND CEMENTING RECOD C WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 20" 78.6# A-53 Surface 106.5' Surface 106.5' 42" 50 bbls of Pilecrete poured Stg 1 L-590 sx/T-210 sx 20 bbls 9-5/8" 40# L-80 Surface 5,606' Surface 4,395' 12-1/4" Stg 2 L-311 sx/T-280 sx 144 bbls 7-5/8" 29.7# L-80 Surface 5,416' Surface 4,394' Tieback Tieback 4-1/2" 13.5# L-80 5,416' 10,265' 4,394' 4,250' 8-1/2" Cementless Screens Liner 24.Open to production or injection? Yes Q No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 3-1/2' 5,450' 4,858'MD/4,208'TVD 4-1/2"Liner Screens F/5,837'-10,223'(250p Screens) 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 416 16 1I DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED Li- 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 3/18/2017 Gas Lift Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 3/22/2017 24 Test Period . 0..1813 0 165 N/A 0 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 297 1119 24-Hour Rate — 1813 0 165 19.6 Form 10-407 Revi ed 1/2015 /10z6 CONTINUED ON PAGE 2 Submit ORIGINIAL oly,�, j2K3 41Z311� 6,24-1- ,,,i_ ,24-1 RBDMS '.°-, APR 1 0 2017 ��,1 28.CORE DATA Conventional e(s): Yes ❑ No Q 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 ❑., Permafrost-Top If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base 1,688' 1,564' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval 5,837' 4,380 information,including reports,per 20 AAC 25.071. SV3 2326' 2117' Ugnu UG4 3165' 2845' Ugnu LA3 4400' 3908' Schrader NA 5184' 4346' Schrader NC 5353' 4386' 5chravec (2jlo- C Formation at total depth: Schrader Bluff 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Days vs Depth,MW vs Depth,Csg and Cmt Reports, Definitive Directional Surveys. 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. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Cody Dinger Email: cdinger(a�hilcorp.com Printed Name: Cody Dinger Title: Drilling Tech 41/ / d7 Signature: /Lib,'p.y Phone: 777-8431 Date: p INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing,Ground Level,and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 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 111 • • Milne PointMPU UnitB-32 Well: SCHEMATIC Last Completed: 3/10/2017 Hilcorp Alaska,LLC PTD: 216-151 Orig.KBEIev.:49.4'/GLEIev.:22.9' TREE&WELLHEAD RKB—THF:23.13' Innovation) Tree Seaboard 3 1/8" 5M I," 1 "1 Seaboard 16 3/4"3M x 11"5M Multibowl w/11"x 3 1/2"EUE Top and 20" r k+ It Wellhead Bottom with 3"CIW"H"BPV profile.2ea 3/8"NPT control lines. P, F. I OPEN HOLE/CEMENT DETAIL 0 4. * 42" _ 50 bbls(10 Yards Pilecrete dumped down backside) { 2 !' 12-1/4"1st stage 590 sx 11.7#Extenda,210 sx 15.8#SwiftCEM 3 1/2" s) 12-1/4"2nd stage 311 sx 10.7#Perm L,280 sx 15.8#SwiftCEM a! ? 1 8-1/2" Cementless Screens Liner in 8-1/2"hole rfq• 3 P A Ill V CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm BPF ' 4 20"x34" Conductor(Insulated) 78.6/A-53/Weld N/A Surface 106.5' N/A 9-5/8"'ES *- 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,606' 0.0758 Cementer @ e' 2,011' 7-5/8" Tieback 29.7/L-80/Vam STL 6.750" Surface 5,416' 0.0459 I; 5 1 4-1/2" Liner(250µScreens) 13.5/13Cr-110/Vam Top HT 3.795" 5,837' 10,223' 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3/L-80/EUE 8rd 2.867" Surf 5,450' 0.0087 61 r,' 6 r ik 4= il WELL INCLINATION DETAIL s' 7 t KOP @ 264' Max Hole Angle=60.33 deg.@ XN profile '4' 0 0 0 8 Max Hole Angle=85.98 deg.@ Tubing tail `A ,..."ii Max Hole Angle=95.75 deg.@ 6,990'MD 7 5/8" til 0 9 'i 1 JEWELRY DETAIL v10 No. Top MD Item Drift ID II �� Upper Completion W? Ci 1 23' Tubing Hanger(3-1/2"EUE Top&Btm) 2.867" yg Nin ID ‘41.411 1 2 1,963' 3.5"X Nipple Assembly,2.813"Packing Bore 2.813" 2.750" f 3 2,344' 3.5"GLM SPMO-1.OM 1.5"GLV(12/64 TRO 1,273)w/RK Latch(Set 3/12/17) 2.867" 4. 4 4 3,222' 3.5"GLM SPMO-1.OM 1.5"GLV(12/64 TRO 1,264)w/RK Latch(Set 3/12/17) 2.867" 13 ` 5 3,773' _ 3.5"GLM SPMO-1.OM 1.5"GLV(16/64 Orifice)w/RK Latch (Set 3/12/17) 2.867" �® aE. . ®��►',14 6 4,227' 3.5"GLM SPMO-1.0M 1.5"Dummy w/RK Latch(Set 3/10/17) 2.867" Ifu 9-5/8" 15 12 41 7 4,648' 3.5"GLM SPMO-1.OM 1.5"Dummy w/RK Latch(Set 3/10/17) 2.867" „ 8 4,743' 3.5"XD Sliding Sleeve,X profile,2.813"seal bore 2.813" 16f,.' 9 4,801' 3.5"ROC Gauge Mandrel w/'/<"TEC Wire 2.813" — .1 N.„-_— 17 10 4,858' 7-5/8"Halliburton PHL Packer(45k Release) 2.885" 11 4,916' 3.5"XN Nipple,Min ID=2.750"No-Go,2.813"Packing Bore 2.750" __ 12 5,417' 3-1/2"1t w/Mule Shoe(Btm @ 5,450') 2.867" Lower Completion 13 5,405' 7-5/8"Tieback Assy.(8.25"OD No-Go @ 5,404') 6.151" 14 5,416' BOT SLZXP Liner Top Packer w/BD Slips 7"x 9-5/8" 6.200" 1\(> ,9> 18 15 5,438' 7"Hydril 563 x 4-1/2"Hydril 521 L-80 XO 3.900" l" a '16 5,705' 5-1/2"17#Tendeka Swell Packer,Hybrid(10.88'Long) 4.767" S /�' - 17 5,778' 5-1/2"17#Tendeka Swell Packer,Hybrid(10.90'Long) 4.767" J 18 5,837' 4-1/2"Weatherford MaxFlo 316L 250 Micron RTD Screens(117 jts) 3.795" -—__ 19 10,230' 4-1/2"Drillable Packoff Sub 2.400" 41/2" 7 20 10,259' WIV Valve LTC BxB(1.5"Ball on Seat/Closed;Btm @ 10,265') - Shoe @" 19 1Q265' , "'( 20 r TD=10,265'(MD)/TD=4,250'(11/D) PBTD=10,265'(MD)/TD=4,250'(TVD) 1 Revised By:STP 3/17/2017 • • Hilcorp Energy Company Composite Report Well Name: MP B-32 Field: Milne Point County/State: ,Alaska (LAT/LONG): vation(RKB): 26.4 API#: Spud Date: 2/16/2017 Job Name: 1612655D MPB-32 Drilling Contractor AFE#: 1612655D AFE$: 9/20/2016 Drill 42"hole. Run 80',34"x 20",78.64,A-53 insulated conductor. Dump 50 bbls of"Pilecrete"cement from cement truck. 2/13/2017 Working on B-34 Report.;Clean cellar.Continue cleaning pits.PJSM,Prep Derrick.Scope down derrick. Blow down water on rig.;Blow down steam system, vac out fluid in mud pit sumps.Air up sub module tires.Disconnect steam and air lines,warm up cold start engines.;R/U and move generator module,pump, pit and catwalk modules on other side of pad and stage by 9-32,move pipe shad module out of the way,clear rig mats from in front of sub base.;Install yoke, jack up sub,pull off 13-34 with SAL and dozer.;Move sub to other side of pad.Remove rig mats from around B-34,stage wellhead equipment behind B-32, align and spot sub over well.;Lay rig matts for catwalk,spot cat walk module,lay rig mats and spot pipeshed. 2/14/2017 Spot pit and motor modules,set up exterior stairways.Install sub base outriggers,R/U power and utility lines between modules.Insulate rig.;Swap to main rig power,get steam and water circulating throughout rig,charge air system,dress mud pumps,R/U interconnect lines.CIO suction valve and seat#2 MP.;Clean pipe shed in preparation to load pipe shed.R/U containment and spot cuttings box,take on fuel and water to rig. Replace 0-rings on rig floor hydraulic manifold.;Submit 24 hr notification to AOGCC for diverter function test p 1802_,switch to high line power @ 16:30 hrs.;R/U and remove 10"flow line from mezzanine.Cut out 12"hole in flow box for new 12"flow line,Fab and weld 12"flow line.Cut out 14"dump going in pit 1,install 16"dump.;Clean in pipe shed.Load 5"drill pipe into pipe shed.Clean in hopper room and mezzanine.Check accumulator bottle pre-charge.Cleanup around B-34.;Continue to fab and weld 12"flow line at D-pad shop,bring new flow line f/D-pad to rig and install same.Clean pump room and boiler room. Scope up derrick.;Work on rig acceptance checklist. Currently 60%rigged up;Hauled 0 bbls to GPB G&I for total=0 bbls Hauled 0 bbls to G&I for total=0 bbls Hai Mori Rnn hhlc, to,Inc/ milo!aka fro.fntal—Rr l hhle 2/15/2017 Assist welder with flow line modifications.Plumb in flow line jets and pipe rack drains.Un bridle blocks.Change saver sub to DS-50.Perform Derrick inspection.;Begin installing splash guards on back of shakers.Continue loading in 5"DS-50 DP.Begin N/U Diverter system.RID scaffold used for flow line mods.Install 5"Elevators on TDS.Hang rig tongs.;Hang rig tongs.N/U BOP and Tq Tee and BOP Flanges to spec.Install Knife valve and diverter line sections.Put 1 load of mud in pits and bring vis up.Work on rig acceptance checklist.;Continue to bolt up and tighten diverter knife valve and diverter flanges.Remove unused accumulator hyd lines from stack,install riser and flowline.Set diverter signs in place. Accept rig @ 18:00;Finish offloading 580 bbls total 8.8 ppg spud mud into pits.;PJSM,install 12.375"ID wear bushing.Drift and P/U 5"DS 50 drill pipe and rack 25 stands in derrick. Continue working on rig acceptance checklist.;Perform Diverter function test per AOGCC requirements,Annular closed in 9 sec,knife valve opened in 4 sec. sys pressure 2925 psi,after closure 2000 psi,200 psi attained in 15 sec.;Full pressure attained in 49 sec.6 N2 bottles,avg 2391 psi.Test trip tank and mud pit pvt alarms,test flowline alarm,no failures.AOGCC rep Lou Grimaldi waived witness @ 18:29 hrs on 2/15/2017.;Continue to drift and P/U 5"DS 50 drill pipe and rack 56 stands in derrick.;Hang blocks,cut and slip 80'of drilling line,reset crown saver.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 10 bbls to G&I for total=10 bbls Hauled 0 bbls water F/6 mile lake for total=800 bbls 2/16/2017 Continue to P/U and rack back 96 stands of DS-50 DP,drifted with 3.15"drift.;P/U conductor C/0 BHA with 12 1/4"RR Hughes VDM-3 Tri cone Bit,8" Sperry Mtr,Xo and 1 Jt HWDP.Fill stack and test Mud Line to 2000 psi.;Perform flow rate test on flow line system,staging pumps up to 740 GPM with 150 viscosity spud mud.No issues with flow line or shakers @ 740 GPM.Increase Mud Viscosity to 180.;C/O conductor to 108'.Spud well and Drill to 130'@ 400 GPM,550 PSI,2-4 WOB,40 RPM,2.2 Tq,42K RWT.No issues with flow line returns until gravels were encountered.Flow line packed off.;Pull up into conductor.Jet and clean out gravels from flow line to shakers.Establish circulation, staging pumps up to 600 GPM with 200 viscosity Spud Mud inside conductor.;Drill to 135'@ 450 GPM 200 viscosity.Encounter same problems with flow line and gravels settling out in flow line.Pull back up into conductor. Jet and clean out gravels from flow line to shakers.;Increase viscosity to 300+.Establish circulation @ 450-500 GPM inside conductor.Tag bottom,PUH into conductor,CBU with same issues as before.Gravels settling out in flow line.;Consult with drilling Team.Jet and clean up flow line staging up to 500 GPM, 330 viscosity.Then POOH and stand back BHA,and prep to install internal flow line jet.;Flush out flowline pumping down bleeder to 45 on flowline.Flush out flowline with water.Fab 1"x 38' piece of pipe with 1/8"hole drilled in it that will go into flowline 45 to possum belly.;While working on flowline-Weld kicker plate on drwkrs drum.Take apart mud pumps and inspect same.Clean suction pots.Weld gusset on dump valve going into pit#1;RIH with 12 114"C/O BHA to 103'inside conductor,establish flow rates,staging up f/300 gpm to 400 gpm,580 psi.able to handle flow rate,40 rpm,2k tq,drill 5'to 140',;Fflowline continues packing off with gravel,P/U into conductor 96',clear out flowline,;Daily fluid Isses to formation 0 bbls,total=0 bbls.;Hauled 0 bbls to B-50 for total =0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 71 bbls to G&I for total=1050 bbls 2/17/2017 Continue to jet and clean out flow line after attempting to circulate flow line using internal 1"jetted line with no success.;POOH laying down 1 jt HWDP.Blow down TDS.Rack Back BHA with MTR and Bit.Jet and clean out flow lines.Consult with Drilling Team on forward plan.;TBIH to flow test flow line system while by passing shakers to the drag chain.Tag up(D 143'(7'high).Wash down to 150'and drill to 151'.@ 300 GPM take returns thru 8"dump to drag chain.;We were able to circulate longer period but slowly packed off with settling gravels.POOH laying down 1 jt HWDP.Blow down TDS.Rack Back BHA with MTR and Bit.;Clean and jet flow lines.Prep for flow line modification to install a flow trough behind shakers and that will dump into the top of the possum bellies;rather than the enclosed 10"lines in the bottom of the shakers.;R/D flowline and jet plumbing.Load spud mud from pits to vac trucks,prep pit area for flowline and possum belly modifications.;Wait on welders and materials for mods,continue to clean pit area,Drift and P/U 18 stds 5"DP and 3 stds 5" HWDP,remove 10"knife valves @ possum belly.;Assist welders with flowline and possum belly modifications.;Continue to assist welders on possum belly modifications.Clean and organize on rig.;Continue to assist welders on possum belly modifications.Clean and organize on rig.Service MP damper,Load 9 5/8"csg in pipe shed.;Daily fluid Isses to formation 0 bbls,total=0 bbls.;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 57 bbls to G&I for total=138 bbls Hauled 225 bbls water F/6 mile lake for total=1275 bbls • • 2/18/2017 Continue to assist welders,modify possum belly and flowline.Re-install modified flowline, modify flowline saddle brackets.Continue to prep 9 5/8"csg. Clean on rig.;Continue to work and assist welders on modifications to possum belly,install angle iron on cellar box for grating,continue to prep 9 5/8" csg.;Continue to work and assist welders on modifications to possum belly,modify possum belly dump,install angle iron on cellar box for grating and paint same.;Install grating,continue to prep 9 5/8"csg.Cleanup around and under shakers,Clean in pits from modifications.Fill pill pit#1 with water.;Modifications to possum belly and flowline completed,off rig repair time @ 00:00,;Flood and check surface lines with water,good.Off load spud mud into pits,make final equipment checks.Blow down lines.;P/U 12 1/4"bit and motor w/1 jt HWDP and 1 std HWDP from derrick,RIH to 104',establish pump rates while still in conductor up to 650 gpm with 55%flow,good.;Pump 84 gpm 40 rpm,RIH and tag @ 148'with 2'of fill,PU 3',increase pump to 450 gpm, 1060 psi,40 rpm,3k tq,cleanup fill tagging bttm @ 150'.;Drill 12 1/4"hole f/150'to 188',450 gpm,1060 psi,40 rpm,2.5-3k tq.3-5k wob,with flowline jets on,65%flow,no issues with handling flow rate.;POOH pumping 5 bpm,500 psi to 123',rack 1 std back,pull into conductor,circulate hole clean,rack std back,blow down top drive,POOH UD single HWDP and bit.;PJSM,M/U BHA#1,12 1/4"PDC bit,8"1.5 deg mud motor,P/U jars and jt HW,rack in drk. M/U DM,scribe MWD to motor w/84.15 deg offset,M/U DGR,EWR-P4,PWD,HCI M,TM collar,UBHO sub,R/U Gyro;Daily losses to formation 0 bbls, total=0 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 0 bbls to G&I for total=138 bbls LJn1In.1 7F hl-le,a.-Wow CIL mil,-.InLc few hnhnl-1 Z<•.n Rhin 2/19/2017 Continue to MU BHA,MU UBHO Sub.Pflug in and Up load MWD.Rig up GYRO while Uploading tools.PU NMDC's,RIH take Wt @ 144'(40'fill).UD top NMDC. MU Top Drive.;Break Circulation @ 400 gpm/920 psi,55K Up/Dn/Rot,40 rpm/3.2 Tq,Wash f/144'to 188'.Drill to 212'w/2-3K WOB.Blow Dn and Run GYRO.Set back 1 std HWDP,P/U and RIH with top NMDC,Grab std HWDP.;Drill 12 1/4"f/212'to 365'w/400 gpm/1115psi,40 rpm/2K Tq,2-5K WOB.See fill when pumps off and wash back to btm when needed.CBU and GYRO every 60'.;Had to fight flow line issues while drilling heavy gravels. Mostly at the flow box below rotary.10"flow line to shakers and flow trough had no issues.;Pump out of hole 2 stds HWDP and grab Jars.Wash Dn to 359', Re run Gyro.;Drill 12 1/4"hole f/369'to 597'.CBU and run GYRO every 60'. Increase flow rate to 450 gpm @ 400'.Seeing less gravels and some sand clays.;Slide Depths:241'-296',303'-336',364'-385',425-474',487'-534',550'-600'.;Drill 12 1/4"hole f/597'to 613',CBU,blow down top drive,make final gyro survey @ 515',continue drlg f/613'to 1053'AROP 73.3'fph(440') 484 gpm, 1590 psi,5-7k wob,40 rpm,3k tq.;Keep gyro on standby for 2 more stds drilled to 741',MWD surveys clean.RID gyro. MW in/out 9.15 ppg vis 240,ECD 9.5 PU/SO/ROT 77/76/73.;Drilling U1053.to 1619'AROP 94.3'fph(566) 500 gpm,1738 psi,5-7k wob,60 rpm,3.5-4.8k tq. MW in/out 9.1+ppg vis 210,ECD 9.6 PU/SO/ROT 78/78/75;Running water 40 bph,both centrifuges running. 2.32'above the line, 1.64'right of the line. 4.44 slide hrs,4.51 rotate hrs.;Daily losses to formation 0 bbls,total=0 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 570 bbls to G&I for total=748 bbls 2/20/2017 Drilling f/1619'to 2300'(648')AROP 108'fph 500 gpm, 1750 psi,5-10k wob,60 rpm,5k tq. MW in/out 9.1+ppg vis 210,ECD 10.1 PU/SO/ROT 89/77/79.;Drilling f/2300'to 2500")200')AROP 100'fph 500 gpm, 1750 psi,5-10k wob,60 rpm,5.5k tq. MW in/out 9.1+ppg vis 210,ECD 10.1 PU/SO/ROT 105/82/88.;Attempt to circulate clean up cycle @ 2375',observed 4200 units gas.Continued drilling at reduced flow rate to 2506.Gas continually falling to 500 units.;Circulate clean up cycle @ 600 gpm/2350 psi/Rot 60 rpm working pipe 60'.Hole unloaded with 100%increase in cuttings at shakers.;Drilling f/2500'to 2836'(336')AROP 168'fph 500 gpm,1750 psi,5-10k wob,60 rpm,5.5k tq. MW in/out 9.1+ppg vis 210,ECD 10.1 PU/SO/ROT 105/82/88.;Drilling f/2836'to 3382'(546')AROP 91'fph 500 gpm,1750 psi,5-10k wob,60 rpm,7-8.5k tq. MW in/out 9.2 ppg vis 160,ECD 10.2 PU/SO/ROT 130/95/108.;Drilling f/3382'to 3920'(536)AROP 89.6'fph 600 gpm,2170 psi,5-10k wob,60 rpm,7-8k tq. MW in/out 9.2 ppg vis 160,ECD 10.3 PU/SO/ROT 134/100/110.;Running water 35 bph,both centrifuges running 1.84'above the line,3.6'right of the line. 2.38 slide hrs,11.26 rotate hrs.;Daily losses to formation 0 bbls,total=0 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 741 bbls to G&I for total=1489 bbls ami ilcrl 1nnn hhle,uafcr cia mile la4c few 1,1-al-7onn hhle 2/21/2017 Drilling f/3920'to 4445'(525')AROP 87.7'fph 600 gpm,2380 psi,8-14k wob,60 rpm,8-10k tq. MW in/out 9.2 ppg vis 160,ECD 10.3 PU/SO/ROT 143/101/114.Start Build section @ 4200'.;Continue to drill ahead from 4445 to 4677'w/same parameters. ROP @ 80-100 fph while sliding for build section.;PU off btm and CBU @ 600 gpm/2350 psi.;Service Top Drive,Grease Traveling Block/RT Equipment.;Drilling f/4677'to 4870'(193')AROP 96.5'fph 600 gpm,2450 psi,5-15k wob,60 rpm, 11.12k tq. MW in/out 9.2 ppg vis 150,ECD 10.3 PU/SO/ROT 156/104/121.;SLIDE DEPTHS;4136-4371,4199'- 4227',4266-4308',4325-4317',4386-4434',4451'-4487',4514'-4558',4577'-4613',4646-4677',4706-4744',4766-4800',4830'-4849'.;Drilling ff 4870'to 5206'(336')AROP 56 fph 550 gpm,2150 psi,5-15k wob,60 rpm,12-13k tq. MW in/out 9.2 ppg vis 150,ECD 10.1 PU/SO/ROT 165/103/123.;Drilling f/ 5206'to 5520'(314')AROP 52'fph, 550 gpm,2150 psi,5-15k wob,60 rpm,12-13k tq.MW in/out 9.2 ppg vis 150,ECD 10.2 PU/SO/ROT 157/103/125.;Both centrifuges running,adding water 30 bph.Max gas @ 5457'(1181 u)Note:5310'seeing some oil @ shakers. 8.57'above the line,13.33' left of the line.8.2 slide hrs,5.9 rotate hrs.;Note:Currently in NC sand building f/82 deg inc to 92 deg inc.-The Schrader Bluff sands came in 21'higher than anticipated.;Daily losses to formation 0 bbls,total=0 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 570 bbls to G&I for total=2059 bbls U-,,dcrl lnnn hhlcuahcr CIF milo[min fnr hnhml-9onn hhlc 2/22/2017 Drilling f!5520'to 5612'(92')AROP23'fph,,,(SECTION TD)in NC sands 550 gpm,2170 psi,5-15k wob,60 rpm, 12-13k tq.PU/SO/ROT 158/102/122.MW in/out 9.4 ppg vis 140,ECD 10.2;Encounter Concretion @ 5592'.Adjust parameters as needed to drill concretion.Final Survey @ 5574.1 MD93.43 INC, 303.26 AZM4397.92 TVD 15.85'Distance to the plan,1'below the line,14.72'left.;Circulate and condition hole.CBU x 3 lowering viscosity to 100,@ 600 gpm/2300psi,80 rpm/14 Tq,PU 165K,SO 95K,RT 122K.Reposition DP in Derrick to make room on rig floor for running casing.;Back ream out of hole from 5612'to 3950'.(Base of Tangent)w/60 RPM12/14K Tq,450-500 GPM/2150 PSI.See occasional Stalls/Pack offs.Seeing shakers stating to load up.;CBU from 3950'@ 600 GPM/2150 PSI,70 RPM/12K Tq.Hole unloaded for 250 bbls before cleaning up.;Continua to BROOH from 3950'to 3690'with same parameters.;Continue to BROOH from 3690'to 3069',pumping 500 gpm, 1650 psi,40 rpm,hole unloading @ 3069'.;CBU from 3069'@ 550 GPM/1750 PSI, 60 RPM/10K Tq.Hole clean @ BU,mostly clay.;Continue to BROOH from 3069'to 2563'with same parameters,pulling @ 15 fpm,due to packing off from clays.;Pump cleanup cycle 600 gpm 1850 psi,70 rpm,P/U @ 60 fph,477 bbls hole cleaned up.orient high side.Blow down top drive.;P/U 118k,S/O 89K, Attempt to POOH on elevators from 2503'to 2440'with 10-15k overpull,Continue to backream out f/2440'to 2090',hole unloading,mostly clay BR 14 fpm due to TQ and packing off.;Pump cleanup cycle 550 gpm 1550 psi,60 rpm,P/U @ 60 fph,421 bbls hole cleaned up.;Continue to BROOH from 2060'to 1748'slow 5-10 fph due to packing off, pumping 500 gpm,1280 psi,40 rpm,8k tq,hole unloading mostly clay. Note:unable to pumpout @ 2017'w/up to 15k overpull;CBU 600 gpm 1250 psi,60 rpm cleaning up hole before pulling thru base of permafrost @ 1700', orient high side.;Attempt to POOH on elevators from 1728', 10k overpull,pump out 300 gpm,560 psi from 1728'to 950'with 15k overpull,work past 950', cannot work past 867'.;BROOH 500 gpm,1200 psi,40 rpm,3k tq from 867'to 489'@ HWDP.;Daily losses to formation 0 bbls,total=0 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 456 bbls to G&I for total=2515 bbls Hauled 825 bbls water F/6 mile lake for total=4725 bbls • • 2/23/2017 BROOH from 850'to 500',POOH on elevators from 500'to BHA.;Work BHA,Down Load MWD,L/D BHA.Bit grade=1/5/BT/S/X/I/CT/TD.;Pull Wear bushing.Clean and Clear rig floor of BHA.Remove Elevator Hyd hoses from TDS,Install 9 5/8"table bushings.R/D Elevators&short bails,PU&MU WOT i, Volant tool.;PU&install long bails/single joint elevators. R/U Weatherford 1450 double stack tongs for high tq connections.;PJSM on running casing with all �/ GSv parties involved. Verify bfl bypass plate installed(Glen Fisher).;M/U 80'shoe track(bakerlock). Flashlight float equipment prior to makeup. Check floats \ $ (ok). Adjust double stack backups to pipe size.Tq 9-5/8"DWC/C connection to 32k.;Run 9 5/8 casing per DSM's running talley F/80'to 500'.Pipe taking wt and floating in.Break circulation staging pump up slowly to 5 BPM.Very thick 250+visc mud coming back over shakers.;Continue to circulate STS until good mud back at surface. Run casing to 1120'.Work and wash past 1120'.Mud at top of hole very clabbered up.CBU again with same thick mud coming back.;Run casing to 1385'washing down slowly.Encounter tight spot and pack off issues.Started losing returns.Work pipe and attempt to establish returns.Very thick mud at top of hole again.;Attempt to L/D 2 jts to previous point of circulation.Able to work and L/D 1 jt. 1345'.Work pipe rotating 10-25 RP with 15-19K,staging pump up f/1 BPM.;Slowly gained full returns,staging pump to 5 BPM,with thick mud/Clays and sand..Come down on pump and able to work full jt with no issues.Had to L/D 2nd jt due to gauled box.;Continue to run casing from 1385'to 1509'(40 jts)washing down 3 bpm,83 psi.;M/U jt 41,CBU 3 BPM,85 psi runing jt 41 in slowly to 1551',circulating out clabbered mud until 75 vis @ returns.;Continue to run casing from 1551'to 1937'(51 jts)washing down 3 bpm,85 psi.wash and work thru tight hole f/1937'to 1951'.;CBU 4 BPM,90 psi reciprocating jt slowly,circulating out clabbered mud until 75 vis @ returns.;Continue to run casing from 1951'to 2362'(61 jts)washing down 3 bpm,85 psi.;Daily losses to formation=73 bbls,total=73 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 513 bbls to G&I for total=3028 bbls Hauled 200 bbls water F/6 mile lake for total=4925 bbls 2/24/2017 CBU,Circulate and condition mud @ 2403'pumping 3 bpm 180 psi staging pump to 6 bpm,225 psi until thick mud circulated out.PU/SO 125/80.;Continue RIH w/9 5/8"casing from 2403'to 3265'wash 4.5 bpm,200 psi,packing off,rotate to obtain returns while washing down.;CBU @3265'staging pump to 7 bpm,215 psi,reciprocating and rotating pipe to avoid packing off issues,several stalls w/20k TQ, 30 rpm,18k tq csg rotates free.Pump 208 bbls. PU/SO/ROT 175/93/122.:Continue running casing washing down 5 bpm,425 psi f/3265'to 4210'.;CBU @ 4210'staging pump to 7 bpm,475 psi,reciprocate pipe slowly.PU/SO 192/97.;Continue running casing washing down 6 bpm,655 psi f/4210'to 5200'.PU/SO 215/102.;CBU @ 5200'staging pump to 8 bpm, 450 psi,reciprocate pipe slowly.;Continue running casing washing down 6 bpm,410 psi f/5200'to 5607'no fill,verify pipe count(137 jts ran)(13 jts left out). PU/SO 240/110.;18 centralizers ran,1 ea 10'f/ea.end of shoe jt over stop collars,1 ea mid jt on FC and BA jts over stop collars,one centralizer on every other jt to 4900',3 centralizers above and 3 below ESC.;Circulate and condition mud for cement lob pumping 8 bpm,420 psi,reciprocate pipe slowly, reduce YP f/30 to 19,vis f/200 to 57 over 3.5 circulations,dump 150 bbls mud. C-PA- Note:full returns.:Park casing @ 5606',R/D volante tool,DSM witness loading plug in cement head,M/U cement head and lines.;Circulate 8 bpm,550 psi, '(,S 7 reciprocate casing.PJSM with all parties involved for pumping 1st stage cement job.;W ith cementers,pump 5 bbls water,pressure test lines to 800 psi low, $ 4000 psi high for 5 min ea,good.Pump 60 bbls 10.5 ppg tunned spacer with red dye 5 bpm 138 psi.;Drop bypass plug,load closing plug,04:52 hrs,mix and pump 263 bbls 11.7 ppg Extenda Cern lead cement 5 bpm,460 psi,batch 43 bbls 15.8 ppg Swift Cern tail cement.;Note:reciprocate casing 30'while pumping.Full returns.:Daily losses to formation=32 bbls,total=105 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 228 bbls to G&I for total=3256 bbls Hauled 400 bbls water F/6 mile lake for total=5325 bbls 2/25/2017 Mix and pump 590 sxs(263 bbls)Etenda Cern Lead Cement at 11.7 ppg. Mix and pump 210 sxs(43 bbls)Swift CemTail Cement at 15.8 ppg.Drop Shut off Plug.;Displace cmt w/20 bbls FW f/Cmt Unit.Rig Pump 206.3 bbls,9.2 ppg mud.Cmt Unit 80 bbls FIN.Rig Pump 112 :"-%772 ppg mud. Total Displacement @ 418.3 bbls.;Bump plug with 500 psi over final circulating pressure.Check Floats. Floats held.CIP @ 07:50.Load Closing Plug.Using rig pump,stage pressure up 2900 psi to open ES Cementer.;CBU through Stage tool staging up to 4 bpm,bringing 60 bbls Spacer and 20 bbls green CMT to surface.Bottoms up 20 bbls late.Over boarded Total of 263 bbls contaminated Mud.;1st Stage Details:Full returns through out job. Pump Cement @ 5 BPM Average.Pump Disp @ 5.5 BPM Average.Calculated Disp 419 bbl,Actual Disp 418 bbl.FCP 880 psi @ 2 BPM;Continue to circulate through ESCMTER while prepping for 2nd stage Cement.Called out for additional 150 sx(115 bbls)Lead CMT.;Blow down cement line,Flush all surface equipment 0with black water.:Continue to circulate through ESCMTR while prepping for 2nd stage and wait on delivery of additional cmt f/Halliburton.CMT on location zQ @ 15:30.Blow into CMT into Silos.:Mix&pump 60 bbl 10.5 ppg.Mix and pump 311 sxs(230 bbls)Perm L Lead Cement at 10 7 ooq Mix and pump 280 _ v` sxs(57.6 bbls)Swift CemTail Cement at 15.8 ppg.Drop Shut off Plug.;Pumped Lead until Clean spacer at surface.Spacer back to surface at calculated bbls.Pumped tail with contaminated Lead to surface at end of tail.;Displace cmt w/20 bbls FW f/Cmt Unit.Rig Pump 132 bbls,9.2 ppg mud.Total Displacement @ 152 bbls.Bump Plug @ 350 psi FCP @ 2 bpm.Pressure up to 1570 psi&close ESCMTR.Hold for 5 min.;Lost returns 12 bbls away from bumping plug.Brought 57 bbls spacer,100 bbls contaminated cmt,&40 bbls Green cmt to surface.Pump Lead @ 6 bpm average. Pump Tail @ 4 bpm average.;Pump Displacement @ 5 bpm average.Calculated Displacement 152 bbls.Actual Displacement 152 bbls. CIP @ 19:00 hrs.;Blow down cement line,Flush stack and all surface equipment with black water,R/D cement head and cementers.Fill stack w/blackwater and soak.Center up csg in wellhead.:Empty and clean pits,4 bolt diverter stack and diverter line.Prep to open BOP ram doors for cleaning and inspection.;Drain black water from stack,R/D diverter line and knife valve,open BOP ram doors,clean and inspect same.close ram doors,P/U stack.Continue to clean in pits.;Center up casing in wellhead, install 9 5/8"emergency slips with 100k on slips per wellhead rep.Welder cut casing off with 1'stub above slips,LID same.Remove diverter tee,set BOP on stump.;Qress 9 5/8"stump,install multi bowl per wellhead rep. Note:cutoff 9 5/8"casing=28.81';Daily losses to formation=0 bbls,total=105 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 1533 bbls to G&I for total=4789 bbls Hauled 1050 bbls water F/6 mile lake for total=6375 bbls 2/26/2017 Continue N/U Multibowl Well Head.Test Pack off to 3000 psi for 10 minutes.Good Test.;R/D long bails,and elevators. Install short bails&DP Elevators.UD Bell Nipple.P/U Long Bell Nipple.R/U TD Hydraulic hoses.Land and N/U 13 5/8"BOP Stack.M/U Choke/Kill Lines.Land Flow nipple.:Secure Stack.RU Koomey Hoses.Button up cellar.Continue with pit cleaning and C/O drag chain Paddles.;Service Rig;Build Test Joint.Land Test Plug.Function test BOPE. Test BOPE to 3000 psi as per AOGCC PTD.Test Gas alarms.;Set 10"ID Wear bushing.;Trouble shoot TD Lube Oil Issue.Prep Floor and pipe shed for picking up BHA and singling in the hole.;PU Clean out BHA 2-8.5"tricone bit,1.15 deg mud mtr,3 NMFCs,2 jts HWDP,jars,1 jt HWDP=245.56'.;Drift and P/U 5"DS50 DP RIH f/245'setting down 3k @ 1979'on jt#50.;M/U top drive,pump 300 gpm,420 psi,wash down to 1992'tag cmt,drill cement 20 rpm,7k tq,drill cmt f1 1992'to 2012,tagging ESC.PU/SO/ROT 89/76/82.;Drill plug and ESC f/2012'to 2014'pumping 300 gpm,480 psi,20 rpm,5k tq,wob 4-5k, pass thru ESC 2 times, Note:plug rubber seen @ shakers.;Shut in bag,pump thru kill line and DP, pressure up 9 5/8"casing to 3000 psi for 5 min,testing ESC integrity,good,bleed off pressure,open bag.;Blow down top dive top drive,continue to drift and single in with 5"DP f/2032'to 2571',(68 jts total)RIH �; with stds f/2571'to 5485'tagging above baffle adaptor,81 stds.;Rack 1 std back,circulate BU pumping 450 gpm,350 psi,prep for casing test.;Blow down (r top drive,R/U FOSV,head pin,flood choke lines,troubleshoot to get pumps primed.;Close bag,pump down kill line and DP,test 9 5/8"casing to 3000 psi f/ 30 min charted.;Daily losses to formation=0 bbls,total=105 bbls;Hauled 0 bbls to B-50 for total=0 bbls Hauled 0 bbls to ORT for total=0 bbls Hauled 1036 bbls to G&I for total=5825 bbls Hauled 850 bbls water F/6 mile lake for total=7225 bbls • 2/27/2017 Continue testing 9 5/8"casing @ 5465 on chart for 30 minutes.Test Good.Bleed back 4.6 bbls.Rig down test equipment.;MU Top Drive,Break circulation @ 450 gpm/1195 psi,PU 165K/SO 95K/RT 124K.Drill CMT/FE from 5485 to 5612'.Drill 20'new formation f/5612'to 5632.Tagged all FE on depth as per tally.;CBU,Pump spacer and displace hole to new 8.8 Mud System.;Perform FIT Test to 12.0 ppg EMW with 730 psi surface pressure and 8.8 MW a 4395' Shoe TVD.Pump 2.1 bbls with.5 bbl back.Good Test. Blow down and rig down test equipment.;Service rig.Pump 30 bbls Slug,Blow down TD.;TOH from 5587'to 431'(BHA).;LID 7 jts wt pipe. Rack back remaining HWDP,Jars,DC's. Drain mtr,B/O bit and L/D same.;Clean and clear rig floor. Attempt to pp install mousehole. Unable to install due to rig mat not set back far enough from wellhead to clear mousehole. L/D mousehole.;M/U Geo-Pilot lateral assy w/ (2 1 1 8.4"bit sleeve. M/U 8.5"Hyc Long Gauge PDC. P/U full service MWD package. Upload MWD. Install corrosion ring between top flex DC and hwdp.BHA =269.45';TIH picking up 5"(NC-50)DP Fl 269'-T/1023'MD. Drift=3.15";Attempt to psi test Geo-skid and pulse test MWD. Unable to gain psi w/mud pumps. Troubleshoot pumps w/little success.;Continue TIH out of shed F/1023'-T/1211'(total 30 jts). Continue RIH out of derrick F/1211'-T/2469'MD. Sym ops-Tear down MP#1,found valve and seats had pebble and debris.;Note:Kick while tripping drill @ 2469'MD(1 min 30 sec response time for well secure).;Service rig. Grease crown,blocks,top drive,swivel packing,drawworks,spinners,elevators. Inspect drilling line,winch lines.;Cont working on mud pump#1. C/O valves and seats on pod#4.;Circulate vis pill through surface lines in pits to remove debris. PIT geo skid(ok),shallow test MWD(ok). 400 gpm,530 psi.;Continue TIH F/2469'-T/5073'MD.;Hauled 756 bbls to G&I for total=6581 bbls Hauled 350 bbl H2O from 6 mile lake for total=7575 bbls Daily losses to formation 0 bbls for total=105 bbls 2/28/2017 Continue TIH F/5,073'-T/5,553'MD. Continue to troubleshoot lube oil pump on top drive. Cold oil.;Wash down F/5553'-T/5632'MD. 450 gpm,875 psi. 162k up,65k dn, 110k rot(40 rpm,12k tq). Drill 8.5"production hole w/geo-pilot rotary steerable F/5,632-T/6,725'MD.;Increase mud wt while drilling ahead. Increase MW F/8.8 ppg to 9.1 ppg due to high background gas(5650 units). 500 gpm,1100 psi,61%flow,120 rpm,13k tq,6-12k wob,9.9 ECD's.;Drilled 3'upthrown fault @ 5,705'MD. Stayed in zone with no losses or other issues drilling ahead. Background gas 1500 units(10k scale). Observed slight residual oil @ shakers.;Rotary Steerable drilling.8.5"hole.Fr 6725'to 7061'.GPM 500,SPP 1335 off, 1550 psi on,RPM 100,WOB 8-15k, TQ 15k,160k UP,70k DN,118k Rot weights,Max gas 6600.Increase MW to 9.3 ppg.;Note:6650'logging depth the"at bit gamma"sensor readings and the DGR gamma readings began to depart from each other.By 7000'MD the readings were 30 to 40 API units apart.DGR reading higher.;Circulate bottoms up. Decided to come back up the hole to a known depth where both gamma sensors matched.Determining which tool to rely on for further GeoSteering.;Back reamed out from stand 108 to 103.Tight @ 7000'MD 15k over pull.Ream out fr 7000'to 6748'.GPM 500,RPM 60,PP 1350,Mad pass fr 6748'to 6695. Determine the DGR gamma to be 40 units high.;Wash and ream back to bottom.Work the last stand to assist in dropping angle to avoid going out of zone. 7000'to 7061'.GPM 500,SPP 1350 psi,RPM 80,TQ 13.5k;Rotary steerable drill from 7061'to 7409'MD.GPM 500,RPM 100,SPP 1400 psi,Up Wt=160k, Dn Wt=75k,Rot Wt=115k,TQ=13.5k,Back ground gas 1200 units. MW=9.3,ECD=10.1.;Hauled 200 bbls to G&I for total=6781 bbls Hauled 550 bbl H2O from 6 mile lake for total=8125 bbls Daily losses to formation 0 bbls for total=105 bbls 3/1/2017 Drill ahead F/7409'-T/7876'MD. 500 gpm, 1530 psi,105 rpm, 17k tq,10-15k wob. 165k up,68k dn, 110k rot. Added.5%lubes to active to reduce tq.;Drill ahead F/7876'-T/8003'MD. 500 gpm,1550 psi, 105 rpm,17k tq,10-15k wob. 172k up,58k dn,108k rot. Pump 25 bbl wt'd sweep @ 8003'(bk on time w/50%inc).;Crossed 6'downthrow fault @ 7515'and back in zone @ 7772'MD(257'out of zone). Crossed another fault @ 7942'MD. Out of zone 7942 to 8003'MD. Stopped drilling @ 8003'and discuss options.;CBU @ 8003'MD. 500 gpm,1500 psi,61%flow. Obtain SPR @ 8003'MD. Monitor well (static).;POOH on elevators F/8003'-T/7315'MD to sidetrack lateral. Hole took calculated fill. 188k up,69k dn.:Trough @ 160R toolface @ 90-100 ft/hr control drill Fl 7315'-T/7383'MD. Saw 1.5°change in ABI @ 7345'MD. Kicked off for sidetrack @ 7345'MD. Confirm with checkshot.;Directional drilled from 7383'to 7627'MD.Negotiated the fault seen @ 7515',stayed low and in zone.Numerous concretions on the down thrown side.Pumped weighted sweep @ 7588'.75%increase in cut;GPM 500,RPM 100,SPP 1550 psi,WOB 8-15k,TO 16-19k,Up 172k,Dn 63K Rot 112k.ECD=10.2,MW=9.3 ppg. 120'/hr rop when in sand. 12'/hr on the concretions.;Directional drilled from 7627'to 7817'MD.GPM 520,RPM 60-100,SPP 1550 psi,WOB 8-15k,TQ 16- 19k,Up 172k,Dn 63k,Rot 112k.ECD=10.2,MW=9.3 ppg.;7680'MD.Pumped low vis pill 12 bbls followed by weighted pill 24 bbls.50%increase in cuttings load.Drilled numerous"concretions"with corresponding slow ROP's,and high torque/stick slip.;Wellbore position:35'high, 11'left.Seeing more metal filings on the magnets in the possum belly.Cleaned every 6 hours and full again each time.;Hauled 285 bbls to G&I for total=7066 bbls Hauled 500 bbl H2O from 6 mile lake for total=8625 bbls Daily losses to formation 0 bbls for total=105 bbls 3/2/2017 Directional Drill 8.5"lateral F/7817'-T/8075'MD.550 gpm, 1745 psi on/off,65%flow,110-150 rpm, 17k/18k tq. 305 bgg. 177k up,57k dn,109k rot. 14.5 lbs metal from magnets.;Did not see fault @ 7942'MD. Increased lubes to 1%by volume.;Directional Drill 8.5"lateral F/8075'-T/ 8400'MD.550 gpm, 1775 psi on/off,63%flow, 110-150 rpm, 17k/18k tq. 400 bgg. 182k up,53k dn,108k rot. 5 lbs metal from magnets.;Directional Drill 8.5"lateral F/8400'-TI 8678'MD.550 gpm,1775 psi on/off,65%flow,70-110rpm,17k/21 k tq. 400 bgg. 182k up,35k dn, 108k rot. 4 lbs metal from magnets.10.3 ECD,9.35 MW.:23:43 hrs error message on drilling console:"Draw works park brake failed to hold torque from traction motor".Traction motor remained on to hold string weight.Troubleshoot message with Tech from:ACE,the contracted top drive experts.Regain control of draw works and top drive.A procedure will be created to address this particular error message.;Directional Drill 8.5"lateral.Drilled concretion FI 8678'-T/ 8682'MD.550 gpm, 1775 psi on/off,65%flow, 70-110rpm, 17k/21ktq. 400 bgg. 182k up,35k dn,108k rot.;Pumped a sweep @ 8679'.Four 10 barrel slugs. 1)10 bbls low vis,2)10 bbls weighted,3)10 bbls low vis,4)10 bbls weighted.total of 40 bbls.;Directional Drill 8.5"lateral.Drilled F/8682'-T/8740'MD.550 gpm,1775 psi on/off,65%flow,70- 110rpm,17k/21k tq. 400 bgg. 182k up,35k dn,108k rot.;Wellbore position:47'to plan.44'high, 17'left. In the target sand.;Hauled 456 bbls to G&I for total =7522 bbls Hauled 450 bbl H2O from 6 mile lake for total=9075 bbls fl-,I,,In,-,- to fnrm-.tion fl hhlc fnr tnt-1-A nc hhlo 3/3/2017 Directional Drill 8.5"lateral.Drilled Fl 8740'-T/9124'MD.550 gpm,1915 psi on/off,65%flow,70-110rpm,19k/22k tq. 600 bgg. 183k up,48k dn,106k rot.;lncreased lube concentration to 1.5%to better manage rising tq and minimize casing wear. Last 6 hrs 6 lbs metal on ditch magnets. Phase II conditions for Milne Point Field.;Drilled fault @ 8810'MD. 4'down throw. Back in zone @ 8925'MD(115'out of zone).;Directional Drill 8.5"lateral.Drilled F/9124'-T/ 9435'MD.550 gpm, 1950 psi on/off,65%flow,70-110rpm, 19k/22k tq. 400 bgg. 183k up,36k dn, 108k rot.;Directional Drill 8.5"lateral.Drilled F/9435'-T/ 9911'MD.550 gpm, 1975 psi on/off,65%flow,70-110rpm, 19k/22k tq. 600 bgg. 185k up,35k dn, 108k rot.;Drilled fault @ 9,471'MD w/5'up throw. Stayed in zone.Deflected off concretion @ 9895'MD w/17 DLS abi.;Wash and ream to reduce high DLS encountered @ 9895'due to deflection off concretion. Reduce 17"DLS to 9°DLS. Continue drilling ahead.;Directional Drill 8.5"lateral F/9911'-T/ 10,265'MD/4250'TVD(TD).550 gpm,2050 psi on/off,65%flow,70-110rpm,20k/22k tq. 700 bgg. 186k up,36k dn,108k rot.;TD called @ 10265'MD as per Geo. Screen up shakers last 300'to reduce low grave prior to upcoming liner run.;Hauled 285 bbls to G&I for total=7807 bbls Hauled 300 bbl H2O from 6 mile lake for total=9375 bbls Daily losses to formation 0 bbls for total=105 bbls;Last svy @ 10074'MD/4255'TVD put us 16'Left The highest gas in the past 24hrs was 4,660 units. 28 concretions have been logged for a total thickness of 215'(4.68%of the lateral) 3/4/2017 Circ and condition 2.5 btm up @ 120 RPM 550 GPM 2100 psi.;Mix and pump low vis weighted sweep around with 10%increase in cuttings.Circ 4 btm up total. Monitor well.Static.;Back Ream out @ 80 RPM 500 gpm F/10265'T/9300'clean. Started getting ratty @ 9300'. back ream slow to clean up F/9300' T/8800'. Continue back reaming at normal rates F/8800'T/8200'.;Started pumping a little fluid away. Slowed pumps down to 450 gpm 80 RPM.F/8200'T/ 7564'.;Continue BROOH F/7564'MD to above sidetrack depth of 7300'(15'above sidetrack depth). TIH past sidetrack to 7,624'MD. Ensure no obstructions past sidetrack point.;Obtain check shot survey to confirm new hole @ 7556'MD(good). POOH on elevators F/7624'-T/7300'MD.Continue back reaming F/7300'- T/5741'MD. BROOH @ 450 gpm,1300 spp,90 rpm,12k tq.;No rot when pulling into shoe w/BHA F/5741'-T/5649'MD. Tight spot @ 5649'MD. Made several attempts to straight pull w/max overpull 30k(no go).;Rot @ 20 rpm,and continue BROOH F/5649'T/5553'MD;CBU 3x @ 5553'MD. Rot/Recip pipe @ max gpm 650,2050 psi,67%flow,120 rpm, 11k tq w/10.1 ECD's. 65 bgg. Saw significant coarse sand @ 2nd btms up.;Shut down and monitor well(static). Pump dry job. Blow down TDS,manifold,and geospan.;PJSM,Cut and slip 93'drilling line.;Service rig-Grease crown,top drive.Check hydraulic connections. Grease drawworks,spinners.;Pull out of hole on elevators F/5553'-T/ 2948'MD. Drop 2.39"drift on wire @ 5049' MD.;Hauled 456 bbls to G&I for total=8263 bbls Hauled 750 bbl H2O from 6 mile lake for total=10125 bbls fl-.ilv Inr•rne}n fnrmntinn n hhlc fnr fnt.l-illc,hhlc i i 3/5/2017 POOH on 5"Dp F/2694' T/265 on elevators. Recover 2.39 Drift on wire.7.5 bbl over calculated displacement.;Monitor well.Static.PJSM L/D BHA.Pump 12 bbl fresh water through BHA. Recover corrosion ring on collars. Plug in to MWD&Down load same. UD MWD&Break off bit and Collar.;Bit Grade-3- 4-BT-A-X-CT-TD Bit was in gauge.See pics in 0 Drive. Geo Pilot had damage on the housing.See Pics in 0 Drive.;Working on Completion Report. • Hilcorp Energy Company Composite Report Well Name: MP B-32 Field: Milne Point County/State: Alaska (LAT/LONG): Ovation(RKB): API#: Spud Date: Job Name: 1612655C MPB-32 Completion Contractor AFE#: 1612655C AFE$: $1,935,400 sommisessonsassomemessmommensseemmogogaNiownweiiiiiiiimeammegaisson!iiilim ?; ; `fin:::.;:;. 3/5/2017 Working on Drilling report.Swap to Completion report @ 1230.,PJSM,R/U to run Liner. M/U 5"Safety joint crossed over to Vam top&UD same.Clear rig floor while bringing up handling equipment. R/U Weatherford 4.5 equipment.R/U line.,Bring up shoe track and first Screen. M/U&check connection.Not made up all the way. Inspect screens and find out they are Vam Top HT and they will not make up to Vam Top. Call town and discuss options. Decide to Xo the shoe track to the first screen with TC-II. Also do the same with the last screen. Send in 3-4.5 Vam top Screens,2-Blank Joints,and the shoe track to baker to get cut.,UD shoe track and remove all screens and blank pipe to UD Dp while waiting on Xo joints from baker. Well loosing 1.5 BPH Static.,M/U johnny whacker and trip in hole out of derrick from driller side w/55 stds(3410'MD). Pull out of hole laying down drill pipe F/3410'-T/surface. Hole took 10 bbls over disp. Clean pits offline.,Crossovers arrived on location for 4.5"Liner. Load 4.5"liner in shed. Process liner and jewelry. R/U Weatherford Casing for 4.5".,Service Rig,Hauled 342 bbls to G&I for total=8505 bbls Hauled 300 bbl H2O from 6 mile lake for total=10425 bbls Daily losses to formation 0 bbls for total=105 bbls 3/6/2017 Service rig,Verify pipe count and tally.Count pipe.,P/U shoe track with WIV&Flapper valve.Baker loc the TC-II connection to the first screen. P/U 117 4.5 Vam Top HT Maxflow250 micron WTF screens total with the XO Screen to TC-II. 1-4.5 Vam Top Blank joint, 1-5.5 X 8.5 Tendeka Swell packer 1-4.5 Vam Top Blank joint 1-5.5 X 8.5 Tendeka Swell packer 6-4.5 Vam Top Blank joints. Set liner in tension to run 2 3/8 Inner string.,Change handling equipment.R/U false table and 2 3/8 equipment. M/U 2 3/8 slick stick with 14.73 of polish to no go. RIH with 2 3/8 inner string T/ 4801' Tag up No go out 4,801'w/5k set dn.Space out. 59k up,53k dn.,M/U 4ea pups(154 jts 2-3/8"dp,26.43'pups w/swivel) and M/U P/U BOT SLZXP LTP with BD slips. Inner string @ 4795(6'off no go). 14.2 bbls loss for trip w/2-3/8"dp. Confirm 9 shear screws on both the ZXP and LRT w/5%brass.,R/D WOT tongs. C/O elevators and handling equipment. RIH w/1 std DP out of derrick and circ 1.5 inner string vol @ 2 bpm/610 psi.,B/D TDS. RIH w/11 stds total out of derrick to 5552'MD.,Obtain parameters @ 5552'(shoe @ 5606'MD). Attempt to rotate but stalled out @ max 6k tq. Could establish 4-6 rpm if picking up or slacking off slowly. 145k up, 100k dn w/no pumps. CBU @ 5552'MD,3 bpm/1290 psi/29%flow. B/D TDS.,Continue RIH w/4.5"liner F/5552'-T/ 6370'MD. RIH F/6370'-T/6520'picking up 5"HWDP out of shed.,Hauled 0 bbls to G&I for total=8505 bbls Hauled 300 bbl H2O from 6 mile lake for total=10725 bbls Daily losses to formation 22 bbls for total=127 bbls 3/7/2017 18 Joints 5"HWDP T/6926'. UP/DN 168/98.,RIH F/6926'T/10195' with 5"Dp From Derrick filling on the fly&topping off every 10 stands. Float in from 9600'T/10195'.,Wash down last stand F/10195'T/10265. 2.5 BPM 1290 psi.UP/DN 206K/46K. Tag btm&work pipe back up.Install 5 Pup under last joint. RIH T/10265&Put pipe in up wt.,Start displacement @ 3 bpm 1460 psi.Pump High vis spacer Displace to 9.3 brine.Circ 1000 bbl total. STS+1.5 btm up dumping all dirty brine until clean.,Drop 1.25"ball, &Pump down @ 2.5 bpm 1067 psi.,Set packer as per baker. Ball on seat @ 77.5 bbl.Pressure up to 3800&stage test pump to 4800 psi setting packer,set dwn to 41k,verify packer set,bleed off pressure. Packer set depth 5438',shoe @ 10265'.LT @ 5415.79'.,P/U to 170k and verify released from liner. B/O top drive and blow down same.Close bag, pressure test annulus to 1500 psi for 30 charted min,good,bleed off pressure,open bag.,M/U top drive,pressure to 500 psi,Pulling slick stick above seals, displace w/493 bbls clean 9.3 ppg brine pumping 5 bpm,3500 psi. Blow down top drive and choke.,POOH UD 5"DP from 10207'to 6934'(106 jts)UD 18 Jts 5"HWDP to 6377', continue UD 5"DP to above TOL @ 5338'.,Daily losses to formation 0 bbls for total=127 bbls,Hauled 1606 bbls to G&I for total=- 10111 10111 bbls Hauled 0 bbls H2O from 6 mile lake for total=10725 bbls Hauled 260 bbls to B-50 for total=260 3/8/2017 Circ&Condition Pump sweep&Circ 1.3 bmt up @ 5 bpm 3400 psi. Monitor well. Slight lossos.,L/D DP Fl 5415'T/4894'.LID 18 joints 5"HWDP.Finish L/D 5"Dp. Change handling equipment to 2 3/8. Inspect baker running tool.Good.UD 2 3/8 pipe F/4890'T/surface.UD slick stick.,Clear floor.Change handling equipment T/5".M/U Wash tool as mule shoe&RIH with 5"DP from derrick.T/1900'.,POOH F/1900'UD 62 jts 5"DP,R/U and pull 10" ID wear bushing.,P/U and breakout XOs on safety jt and UD same,clear rig floor.,Close blind rams,C/O upper pipe rams to 7 5/8"casing rams,open blind rams, R/U 7 5/8"test jt,test casing rams to 250/3000 psi 5 min ea.charted,R/D test equip.,M/U hanger and landing jt, dummy run hanger per wellhead rep,RKB to load shoulder 24.85',R/D same. Note:static loss rate 4.5 bph,R/U 7 5/8"handling equip.Ready 7 5/8"XO on FOSV. PJSM.,MIU ported tie back seal assy with 8.25"no go locator per Baker rep,P/U and RIH w/ 7 5/8"29.7#L-80 VAM STL casing per tally,use jet lube seal guard premium pipe dope,M/U to optimum torque @ 5400 ft/lbs,utilize dog collar clamp on every jt.RIH to 2803',(70 jts ran).,Conduct valve drill while running casing,well secure in 54 seconds.,Daily losses to formation 68 bbls for total =195 bbls,Hauled 483 bbls to G&I for total=10594 bbls Hauled 775 bbls H2O from 6 mile lake for total=11500 bbls Hauled 290 bbls to B-50 for total=550 bbls • • 4 ') b �t Gs 3/9/2017 P/U,7 5/8 STL 29.7#L-80 F/2947'TI 5411'. Torque all connections to 5500#. up/DN 162/122.,R/U bale extensions.P/U 136 Joints &Kelly up with drive sub.Wash down @ 3 bpm 65 psi.and engage seals&Close port @ 5414'.Bleed off pressure and land out on No go 5425. POOH&pump down again to verify. Good. Space out. UD three joints of 7 5/8. P/U 7.84&9.88'pups. M/U Joint 134.P/U Hanger and landing joint with buttress drive sub.Kelly up and wash down&Engage seals close port.P/U&Open port.,Back down Pressure&Close annular.Reverse circ Corrosion inhibited 9.3 brine @ 3 bpm with 1.5% Baricor 100 mix. 67 bbl.Chase to rig floor with fresh brine to clear pumps. Line up LRS&pump 40 bbl Diesel 2bpm 700 psi. Strip through annular 2'.Bleed pressure and open annular. RIH&Land hanger. 90'off of no go. Land hanger with 84k on hanger.UP/DN 162/122K.,Back out landing joint,vac out stack with vac truck through annulus. Pull landing joint and M/U Packoff.RIH&Land same.RILD.,Test Void to 500/3000 psi.Good. RID Weatherford&UD bale extensions. R/U LRS.,PJSM,with LRS, Pressure test 9 5/8"x 7 5/8"OA with diesel to 1000 psi for 30 min charted,good.bleed off pressure.R/D LRS.,Close blind rams,remove 7 5/8"casing rams,install 2 7/8"x 5 1/2"VBR in upper ram cavity,R/U 3 1/2"test jt,test upper VBR and annular to 250/3000 psi ea, charted,R/D test equip.,R/U 3 1/2"handling equip,load tools to rig floor, R/U TEC spool.Ready XO on FOSV.Hang sheave in derrick,run TEC cable thru sheave. Note:static loss rate 4.5 bph.,PJSM w/haliburton,weatherford,rig crew,discuss well control plan for TEC cable across BOP, Drift, P/U and RIH with 3 1/2"L- 80,9.3#EUE upper completion/jewelry per tally use BOL seal gaurd pipe dope,torq tbg to 2500 ft/Ibs.,RIH with mule shoe and 15 jts,M/U XN nipple w/pups- RHC ball catcher(2.75"nogo)jt 17,3 1/2 X 7 5/8 PHL pkr with pups,jt 18,ROC gauge mandrel w/pups,M/U gauge to mandrel. Note:while M/U gauge static loss rate increased to 15 bph.,Pressure test seals, RIH 100 fpm installing canon clamps on TEC cable,M/U jt 19,sliding sleeve assy,jts 21,22,M/U GLM#1 w/dummy valve and pups,continue RIH per tally from 811'to 2690'monitor cable signal.,Note:use continuous hole fill while RIH.,Daily losses to formation 102 bbls for total=297 bbls,Hauled 114 bbls to G&I for total=10998 bbls Hauled 150 bbls H2O from 6 mile lake for total=11650 bbls Hauled 0 bbls to B-50 for total=550 bbls 3/10/2017 P/U 3.5 EUE Tubing F/2825'T/5467'. RIH 90 FPM, UP/DN 80/62.Tag 2K.On depth. L/D Joint 160&159.,M/U XO&Head pin on Joint 159 for landing joint.P/U hanger and M/U Landing joint. R/U Circ hose and equipment.R/U all lines to pump and take returns down both sides. M/U Hanger to stump. Terminate Gauge wire through hanger.,RIH&Put hanger below annular.Close annular and Reverse circulate 130 bbl Corrosion inhibitor taking returns up the tubing @ 2-4 bpm. Pressure climbing steadily to 600 psi and returns slowing. Acting like tubing plugging off. Shut down and check equipment.good Start back up&chase inhibitor in place with 9.3 Brine to 2350'56 bbl. Shut down and monitor well. We lost 70-80%Returns.Final rev psi 140 @ 2 bpm.,Total 3 1/2"tbg Ran=158 jts.Total clamps ran=151 OTC clamps/10 mid jt clamps,Open Annular and land hanger.RILDS. Pump 2 bbl down tubing to clear ball seat. Drop 1 5/16 ball and rod. R/U to test.,Pressure up tubing to 3500 psi with the mud pumps. Seen packer start to set @ 2200 psi. Pressure up to 3800 psi with test pump and chart tubing for 30 min. Final pressure.3710. Good.Bleed pressure to 1700 psi on tubing.Pressure up on annulus to 3000 psi for 30 min monitoring both sides. Bleed down tubing F/2300 psi T/0.DCK Did not shear.,Pressure up annulus to 3500 psi with tubing open.Still no shear. Pressure up on tubing T/1700&bleed down fast.Still no shear. Bleed down annulus and pressure back up to 3100 psi.No shear.Consult completion engineer and decide to let Slick line pull the DCK after the rig moves. R/D Landing joint and circ lines.Set BPV.,R/D elevators and bail extensions,clean in pits,open both centrifuges and clean same.Pressure wash in pipe shed.,Flush mud pumps,blow down lines.PJSM,N/D BOPE,rack BOP on stump, N/D DSA flange,lnstall dryhole tree per Wellhead rep,Terminate I-wire per HES rep,final reading=2031.2 psi,80.26 deg,good.Test hanger void to 500 psi for 5 min and 5000 psi for 15 min,good,Remove 1502 from annulus and install blind flange.Fill dry hole tree w/diesel and secure same.Clear and clean cellar and rig floor,prep to bridal up for scope down.Continue cleaning in pits and pipe shed.Blow down water lines,Daily losses to formation 255 bbls for total=552 bbls,Hauled 114 bbls to G&I for total=11112 bbls Hauled 300 bbls H2O from 6 mile lake for total=11950 bbls Hauled 300 bbls to B-50 for total=850 bbls 0 Hilcorp Energy Company • CASING&CEMENTING REPORT Lease&Well No. MP B-32 Date Run 23-Feb-17 County State Alaska Supv. J.Lott/D.Yessak CASING RECORD Surface V TD 5,612.00 Shoe Depth: 5,606.00 PBTD: 5,522.27 Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 95/8 40.0 L-80 DWC/C WOT _ 1.66 5,606.00 5,604.34 1 Shoe Jt 9 5/8 40.0 L-80 DWC/C 38.50 5,604.34 5,565.84 Float Collar 9 5/8 40.0 L-80 DWC/C WOT 1.72 5,565.84 5,564.12 2 Float Jt 9 5/8 40.0 L-80 DWC/C 40.04 5,564.12 5,524.08 Baffle Adapter 9 5/8 40.0 L-80 DWC/C HES 1.81 5,524.08 5,522.27 86 Casing 9 5/8 40.0 L-80 DWC/C 3,507.92 5,522.27 _ 2,014.35 5 ,,-.--"7 Stage Tool 95/8 40.0 L-80 DWC/C HES 3.09 2,014.35 2,011.26 i 48 Casing 9 5/8 40.0 L-80 DWC/C 1,973.60 2,011.26 37.66 CUT JT 95/8 40.0 L-80 DWC/C 11.90 37.66 25.76 1 RKB 25.76 25.76 0 Csg Wt.On Hook: 240 Type Float Collar: No.Hrs to Run: Csg Wt.On Slips: 100 Type of Shoe: Casing Crew: WOT Rotate Csg Yes X No Recip Csg X Yes_ No Ft.Min. 9.2 PPG Fluid Description: Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes _No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: 18 centralizers ran,1 ea 10'f/ea.end of shoe jt over stop collars,1 ea mid jt on FC and BA jts over stop collars,one centralizer on every other jt to 4900', 3 centralizers above and 3 below ESC CEMENTING REPORT Shoe @ 5606 FC @ 5,604.34 Top of Liner Preflush(Spacer) Type: Tunned III Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry Type: Extenda Cern Sacks: 590 Yield: 2.47 Density(ppg) 11.7 Volume pumped(BBLs) 263 Mixing/Pumping Rate(bpm): 5 151- Tail Slurry Ali V w Type: Swift CEM Sacks: 210 Yield: 1.16o �� Density(ppg) 15.8 Volume pumped(BBLs) 43 Mixing/Pumping Rate(bpm): 5 `n Post Flush(Spacer) 1- fn Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: Mud Density(ppg) 9.2 Rate(bpm): 5 Volume(actual/calculated): 418/419 FCP(psi): 880 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1380 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: 20 Cement In Place At: 7:50 Date: 2/25/2017 Estimated TOC: 2,011 Method Used To Determine TOC: Stage Tool @ 2011' Stage Collar @ 2011 Type H ES Closure OK y Preflush(Spacer) Type: Tunned III Density(ppg) 10.7 Volume pumped(BBLs) 60 Lead Slurry Type: Perm L Sacks: 311 Yield: 4.33 Density(ppg) 10.7 Volume pumped(BBLs) 230 -,, Mixing/Pumping Rate(bpm): 5 Tail Slurry 0 Type: Swift Cern Sacks: 280 Yield: 1.16 to N Density(ppg) 15.8 Volume pumped(BBLs) 57 / Mixing/Pumping Rate(bpm): 4 - z Post Flush(Spacer) o Type: Density(ppg) Rate(bpm): Volume: �� w y Displacement: Type: MUD Density(ppg) 9.2 Rate(bpm): 5 Volume(actual/calculated): 152/152 FCP(psi): 350 Pump used for disp: Rig Bump Plug? X Yes No Bump press 850 Casing Rotated? Yes X No Reciprocated? _Yes X No %Returns during job 90 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 144 Cement In Place At: 19:00 Date: 2/25/2017 Estimated TOC: 0 Method Used To Determine TOC: CMT to surface Post Job Calculations: Calculated Cmt Vol @ 0%excess: 341 Total Volume cmt Pumped: 593 Cmt returned to surface: 160 Calculated cement left in wellbore: 433 OH volume Calculated: 308 OH volume actual: 398 Actual%Washout: 30 www.wellez.net WellEz Information Management LLC ver_102716bf • • Hilcorp Alaska, LLC Milne Point M Pt B Pad MPU B-32 50-029-23570-00-00 Sperry Drilling; Definitive Survey Report 08 March, 2017 HALLIBURTDN Sperry Drilling • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual @ 49.30usft Well: MPU B-32 North Reference: True Wellbore: MPU B-32 Survey Calculation Method: Minimum Curvature Design: MPU B-32 Database: 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 MPU B-32 , Well Position +N/-S 0.00 usft Northing: 6,023,179.57 usft Latitude: 70°28'25.010 N III +El-W 0.00 usft Easting: 571,970.48 usft Longitude: 149°24'43.701 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 22.90 usft Wellbore MPU B-32 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 2/20/2017 17.89 81.06 57,560 Design MPU B-32 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 7,305.07 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.40 0.00 0.00 294.00 Survey Program Date 3/8/2017 From (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 75.00 515.00 MPU B-32 PB1 SRG-SS(MPU B-32 PB1 SRG-SS Surface readout gyro single shot 02/14/2017 574.59 5,574.10 MPU B-32 PB1 MWD+IFR2+MS+sag(1) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/20/2017 5,668.72 7,305.07 MPU B-32 PB1 MWD+IFR2+MS+sag(2) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/28/2017 7,315.00 10,194.76 MPU B-32 MWD+IFR2+MS+sag(MPU B MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 03/01/2017 Survey ) Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.40 0.00 0.00 26.40 -22.90 0.00 0.00 6,023,179.57 571,970.48 0.00 0.00 UNDEFINED 75.00 0.26 141.20 75.00 25.70 -0.09 0.07 6,023,179.48 571,970.55 0.53 -0.10 SRG-SS(1) 112.00 0.11 277.81 112.00 62.70 -0.15 0.09 6,023,179.42 571,970.57 0.94 -0.14 SRG-SS(1) 141.00 0.38 170.02 141.00 91.70 -0.24 0.08 6,023,179.33 571,970.56 1.47 -0.17 SRG-SS(1) 202.00 0.39 130.37 202.00 152.70 -0.57 0.27 6,023,179.00 571,970.75 0.43 -0.48 SRG-SS(1) 264.00 1.78 228.63 263.99 214.69 -1.34 -0.29 6,023,178.22 571,970.20 3.03 -0.28 SRG-SS(1) 323.00 3.73 241.74 322.92 273.62 -2.86 -2.67 6,023,176.69 571,967.84 3.45 1.28 SRG-SS(1) 384.00 4.35 240.46 383.77 334.47 -4.94 -6.43 6,023,174.57 571,964.10 1.03 3.87 SRG-SS(1) 448.00 5.92 243.07 447.51 398.21 -7.63 -11.49 6,023,171.83 571,959.07 2.48 7.39 SRG-SS(1) 515.00 8.53 248.25 513.97 464.67 -11.04 -19.18 6,023,168.35 571,951.41 4.01 13.04 SRG-SS(1) 574.59 10.73 249.50 572.72 523.42 -14.62 -28.49 6,023,164.68 571,942.14 3.71 20.08 MWD+IFR2+MS+sag(2) 3/8/2017 6:05:59PM Page 2 COMPASS 5000.1 Build 81 II III Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual @ 49.30usft Well: MPU 0-32 North Reference: True Wellbore: MPU B-32 Survey Calculation Method: Minimum Curvature Design: MPU B-32 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1-S +E/-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 637.60 12.69 248.71 634.41 585.11 -19.19 -40.43 6,023,160.00 571,930.24 3.12 29.13 MWD+IFR2+MS+sag(2) 700.60 16.19 246.99 695.41 646.11 -25.13 -54.97 6,023,153.91 571,915.77 5.60 39.99 MWD+IFR2+MS+sag(2) 763.13 19.69 245.36 754.89 705.59 -32.93 -72.57 6,023,145.94 571,898.24 5.65 52.90 MWD+IFR2+MS+sag(2) 825.96 23.26 245.54 813.35 764.05 -42.49 -93.49 8,023,136.18 571,877.41 5.68 68.13 MWD+IFR2+MS+sag(2) 889.19 27.94 245.92 870.36 821.06 -53.71 -118.39 6,023,124.73 571,852.62 7.41 86.31 MWD+IFR2+MS+sag(2) 952.11 28.84 246.07 925.71 876.41 -65.88 -145.72 6,023,112.29 571,825.42 1.43 106.33 MWD+IFR2+MS+sag(2) 1,014.47 28.54 244.78 980.42 931.12 -78.33 -172.95 6,023,099.58 571,798.32 1.10 126.14 MWD+IFR2+MS+sag(2) 1,077.96 30.06 244.64 1,035.78 986.48 -91.60 -201.04 6,023,086.04 571,770.36 2.40 146.40 MWD+IFR2+MS+sag(2) 1,141.08 30.67 244.53 1,090.19 1,040.89 -105.33 -229.94 6,023,072.03 571,741.59 1.29 167.22 MWD+IFR2+MS+sag(2) 1,203.56 31.51 244.61 1,143.64 1,094.34 -119.23 -259.16 6,023,057.85 571,712.50 1.03 188.26 MWD+IFR2+MS+sag(2) 1,266.72 31.63 245.09 1,197.45 1,148.15 -133.28 -289.10 6,023,043.51 571,682.71 0.44 209.89 MWD+IFR2+MS+sag(2) 1,329.60 30.55 245.95 1,251.30 1,202.00 -146.74 -318.65 6,023,029.77 571,653.30 1.86 231.41 MWD+IFR2+MS+sag(2) 1,392.59 31.23 246.55 1,305.35 1,256.05 -159.76 -348.25 6,023,016.46 571,623.83 1.19 253.16 MWD+IFR2+MS+sag(2) 1,455.66 28.98 246.82 1,359.91 1,310.61 -172.28 -377.29 6,023,003.66 571,594.90 3.57 274.60 MWD+IFR2+MS+sag(2) 1,518.35 28.29 245.96 1,414.93 1,365.63 -184.31 -404.82 6,022,991.37 571,567.50 1.28 294.86 MWD+IFR2+MS+sag(2) 1,580.02 28.82 244.41 1,469.10 1,419.80 -196.69 -431.58 6,022,978.74 571,540.87 1.48 314.26 MWD+IFR2+MS+sag(2) 1,644.18 28.87 244.80 1,525.30 1,476.00 -209.96 -459.54 6,022,965.19 571,513.04 0.30 334.41 MWD+IFR2+MS+sag(2) 1,706.75 29.06 245.34 1,580.04 1,530.74 -222.73 -487.02 6,022,952.16 571,485.69 0.52 354.32 MWD+IFR2+MS+sag(2) 1,769.49 28.82 246.05 1,634.95 1,585.65 -235.23 -514.68 6,022,939.40 571,458.14 0.67 374.51 MWD+IFR2+MS+sag(2) 1,832.28 29.57 243.62 1,689.76 1,640.46 -248.26 -542.40 6,022,926.10 571,430.56 2.23 394.53 MWD+IFR2+MS+sag(2) 1,895.57 28.66 243.97 1,745.05 1,695.75 -261.86 -570.03 6,022,912.23 571,403.06 1.43 414.24 MWD+IFR2+MS+sag(2) 1,958.17 28.42 243.61 1,600.04 1,750.74 -275.07 -596.87 6,022,898.76 571,376.35 0.50 433.39 MWD+IFR2+MS+sag(2) 2,021.21 30.11 242.97 1,855.03 1,805.73 -288.93 -624.40 6,022,884.64 571,348.96 2.73 452.90 MWD+IFR2+MS+sag(2) 2,084.10 30.30 242.39 1,909.38 1,860.08 -303.45 -652.51 6,022,869.85 571,321.00 0.55 472.67 MWD+IFR2+MS+sag(2) 2,146.82 29.15 243.24 1,963.85 1,914.55 -317.66 -680.17 6,022,855.38 571,293.48 1.95 492.16 MWD+IFR2+MS+sag(2) 2,209.88 31.35 243.92 2,018.32 1,969.02 -331.79 -708.62 6,022,840.97 571,265.17 3.53 512.41 MWD+IFR2+MS+sag(2) 2,272.56 32.16 244.44 2,071.62 2,022.32 -346.16 -738.32 6,022,826.32 571,235.62 1.36 533.69 MWD+IFR2+MS+sag(2) 2,335.53 31.24 245.53 2,125.19 2,075.89 -360.15 -768.30 6,022,812.04 571,205.77 1.72 555.39 MWD+IFR2+MS+sag(2) 2,398.78 30.73 244.99 2,179.42 2,130.12 -373.78 -797.87 6,022,798.13 571,176.34 0.92 576.86 MWD+IFR2+MS+sag(2) 2,461.74 30.68 246.51 2,233.55 2,184.25 -386.98 -827.18 6,022,784.65 571,147.16 1.24 598.27 MWD+IFR2+MS+sag(2) 2,524.85 29.41 247.45 2,288.18 2,238.88 -399.34 -856.26 6,022,772.01 571,118.20 2.15 619.81 MWD+IFR2+MS+sag(2) 2,587.56 28,67 247.08 2,343.01 2,293.71 -411.10 -884.33 6,022,759.97 571,090.24 1.21 640.67 MWD+IFR2+MS+sag(2) 2,650.39 28.96 250.45 2,398.06 2,348.76 -422.06 -912.55 6,022,748.74 571,062.14 2.63 661.99 MWD+IFR2+MS+sag(2) 2,713.13 29.99 253.43 2,452.68 2,403.38 -431.62 -941.90 6,022,738.90 571,032.89 2.86 684.91 MWD+IFR2+MS+sag(2) 2,776.16 30.70 256.45 2,507.08 2,457.78 -439.88 -972.64 6,022,730.34 571,002.23 2.67 709.64 MWD+IFR2+MS+sag(2) 2,839.78 29.05 259.72 2,562.25 2,512.95 -446.45 -1,003.63 6,022,723.48 570,971.31 3.64 735.28 MWD+IFR2+MS+sag(2) 2,902.66 29.13 261.91 2,617.20 2,567.90 -451.32 -1,033.81 6,022,718.31 570,941.18 1.70 760.86 MWD+IFR2+MS+sag(2) 2,965.65 29.54 266.38 2,672.12 2,622.82 -454.46 -1,064.49 6,022,714.88 570,910.54 3.54 787.61 MWD+IFR2+MS+sag(2) 3,028.42 29.63 267.37 2,726.70 2,677.40 -456.15 -1,095.43 6,022,712.89 570,879.62 0.79 815.19 MWD+IFR2+MS+sag(2) 3,091.77 29.91 267.72 2,781.69 2,732.39 -457.50 -1,126.85 6,022,711.24 570,848.21 0.52 843.35 MWD+IFR2+MS+sag(2) 3/8/2017 6:05:59PM Page 3 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual @ 49.30usft Well: MPU B-32 North Reference: True Wellbore: MPU B-32 Survey Calculation Method: Minimum Curvature Design: MPU B-32 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,154.25 29.63 268.78 2,835.93 2,786.63 -458.45 -1,157.86 6,022,709.99 570,817.21 0.95 871.29 MWD+IFR2+MS+sag(2) 3,217.30 28.90 266.56 2,890.93 2,841.63 -459.69 -1,188.65 6,022,708.45 570,786.44 2.07 898.92 MWD+IFR2+MS+sag(2) 3,280.51 29.67 266.84 2,946.06 2,896.76 -461.47 -1,219.52 6,022,706.37 570,755.59 1.24 926.39 MWD+IFR2+MS+sag(2) 3,343.23 29.47 267.44 3,000.61 2,951.31 -463.02 -1,250.43 6,022,704.53 570,724.70 0.57 954.00 MWD+IFR2+MS+sag(2) 3,406.17 29.57 267.71 3,055.38 3,006.08 -464.33 -1,281.42 6,022,702.92 570,693.73 0.26 981.77 MWD+IFR2+MS+sag(2) 3,468.96 29.02 268.55 3,110.14 3,060.84 -465.33 -1,312.12 6,022,701.62 570,663.04 1.09 1,009.42 MWD+IFR2+MS+sag(2) 3,531.86 28.74 267.53 3,165.22 3,115.92 -466.37 -1,342.49 6,022,700.28 570,632.69 0.90 1,036.73 MWD+IFR2+MS+sag(2) 3,595.16 28.71 268.69 3,220.73 3,171.43 -467.37 -1,372.89 6,022,698.99 570,602.30 0.88 1,064.10 MWD+IFR2+MS+sag(2) 3,657.43 29.11 267.35 3,275.24 3,225.94 -468.42 -1,402.97 6,022,697.65 570,572.23 1.22 1,091.16 MWD+IFR2+MS+sag(2) 3,720.90 28.98 267.19 3,330.73 3,281.43 -469.88 -1,433.75 6,022,695.89 570,541.47 0.24 1,118.68 MWD+IFR2+MS+sag(2) 3,782.61 29.38 268.65 3,384.61 3,335.31 -470.97 -1,463.82 6,022,694.51 570,511.42 1.32 1,145.70 MWD+IFR2+MS+sag(2) 3,846.30 30.47 265.05 3,439.81 3,390.51 -472.74 -1,495.53 6,022,692.44 570,479.73 3.30 1,173.95 MWD+IFR2+MS+sag(2) 3,908.68 30.69 264.11 3,493.51 3,444.21 -475.73 -1,527.12 6,022,689.14 570,448.17 0.84 1,201.60 MWD+IFR2+MS+sag(2) 3,972.02 31.24 263.91 3,547.83 3,498.53 -479.13 -1,559.53 6,022,685.42 570,415.80 0.88 1,229.82 MWD+IFR2+MS+sag(2) 4,034.95 31.46 264.40 3,601.57 3,552.27 -482.47 -1,592.10 6,022,681.77 570,383.27 0.54 1,258.22 MWD+IFR2+MS+sag(2) 4,097.94 31.89 264.42 3,655.18 3,605.88 -485.69 -1,625.02 6,022,678.24 570,350.38 0.68 1,286.98 MWD+IFR2+MS+sag(2) 4,160.76 31.34 266.55 3,708.68 3,659.38 -488.29 -1,657.64 6,022,675.32 570,317.59 1.98 1,315.91 MWD+IFR2+MS+sag(2) 4,223.62 31.43 269.03 3,762.34 3,713.04 -489.55 -1,690.55 6,022,673.74 570,284.90 2.06 1,345.28 MWD+IFR2+MS+sag(2) 4,286.44 32.47 274.07 3,815.65 3,766.35 -488.63 -1,723.75 6,022,674.34 570,251.69 4.56 1,375.98 MWD+IFR2+MS+sag(2) 4,349.43 35.01 276.90 3,868.03 3,818.73 -485.26 -1,758.57 6,022,677.38 570,216.85 4.74 1,409.16 MWD+IFR2+MS+sag(2) 4,412.38 38.42 279.54 3,918.49 3,869.19 -479.84 -1,795.79 6,022,682.43 570,179.58 5.97 1,445.37 MWD+IFR2+MS+sag(2) 4,475.68 40.99 281.52 3,967.19 3,917.89 -472.44 -1,835.54 6,022,689.45 570,139.77 4.52 1,484.69 MWD+IFR2+MS+sag(2) 4,538.13 44.35 283.04 4,013.10 3,963.80 -463.42 -1,876.89 6,022,698.07 570,098.34 5.63 1,526.13 MWD+IFR2+MS+sag(2) 4,600.99 47.44 283.81 4,056.84 4,007.54 -452.93 -1,920.78 6,022,708.13 570,054.35 4.99 1,570.50 MWD+IFR2+MS+sag(2) 4,667.70 50.10 284.51 4,100.81 4,051.51 -440.65 -1,969.42 6,022,719.93 570,005.59 4.06 1,619.93 MWD+IFR2+MS+sag(2) 4,726.75 54.18 286.66 4,137.04 4,087.74 -428.11 -2,014.31 6,022,732.04 569,960.59 7.48 1,666.04 MWD+IFR2+MS+sag(2) 4,789.48 57.44 288.96 4,172.29 4,122.99 -412.22 -2,063.69 6,022,747.45 569,911.06 6.02 1,717.61 MWD+IFR2+MS+sag(2) 4,852.94 59.76 290.39 4,205.35 4,156.05 -393.98 -2,114.69 6,022,765.20 569,859.90 4.13 1,771.62 MWD+IFR2+MS+sag(2) 4,916.05 60.33 292.22 4,236.87 4,187.57 -374.11 -2,165.63 6,022,784.57 569,808.78 2.67 1,826.23 MWD+IFR2+MS+sag(2) 4,979.02 62.29 294.09 4,267.10 4,217.80 -352.39 -2,216.41 6,022,805.80 569,757.79 4.06 1,881.46 MWD+IFR2+MS+sag(2) 5,041.70 65.13 293.26 4,294.86 4,245.56 -329.83 -2,267.87 6,022,827.86 569,706.12 4.68 1,937.65 MWD+IFR2+MS+sag(2) 5,104.24 68.41 294.36 4,319.52 4,270.22 -306.62 -2,320.44 6,022,850.55 569,653.33 5.49 1,995.11 MWD+IFR2+MS+sag(2) 5,167.18 71.59 296.56 4,341.05 4,291.75 -281.19 -2,373.82 6,022,875.46 569,599.71 6.03 2,054.22 MWD+IFR2+MS+sag(2) 5,230.37 73.96 296.63 4,359.76 4,310.46 -254.18 -2,427.79 6,022,901.96 569,545.49 3.75 2,114.51 MWD+IFR2+MS+sag(2) 5,293.37 77.81 296.67 4,375.12 4,325.82 -226.68 -2,482.34 6,022,928.92 569,490.68 6.12 2,175.53 MWD+IFR2+MS+sag(2) 5,356.52 81.38 299.67 4,386.53 4,337.23 -197.26 -2,537.02 6,022,957.80 569,435.72 7.14 2,237.45 MWD+IFR2+MS+sag(2) 5,418.98 84.50 299.77 4,394.20 4,344.90 -166.54 -2,590.85 6,022,988.01 569,381.61 5.00 2,299.12 MWD+IFR2+MS+sag(2) 5,481.99 87.46 300.03 4,398.62 4,349.32 -135.21 -2,645.33 6,023,018.80 569,326.83 4.72 2,361.64 MWD+IFR2+MS+sag(2) 5,574.10 93.43 303.26 4,397.90 4,348.60 -86.91 -2,723.70 6,023,066.34 569,248.01 7.37 2,452.87 MWD+IFR2+MS+sag(2) 5,668.72 93.52 308.00 4,392.17 4,342.87 -31.91 -2,800.44 6,023,120.59 569,170.74 5.00 2,545.35 MWD+IFR2+MS+sag(3) 3/8/2017 6:05:59PM Page 4 COMPASS 5000.1 Build 81 • 4110 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual©49.30usft Well: MPU B-32 North Reference: True Wellbore: MPU B-32 Survey Calculation Method: Minimum Curvature Design: MPU B-32 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,732.13 94.82 308.50 4,387.55 4,338.25 7.24 -2,850.10 6,023,159.25 569,120.71 2.2D 2,606.65 MWD+IFR2+MS+sag(3) 5,794.89 93.02 307.83 4,383.26 4,333.96 45.93 -2,899.33 6,023,197.46 569,071.11 3.06 2,667.35 MWD+IFR2+MS+sag(3) 5,858.11 93.09 306.32 4,379.89 4,330.59 83.99 -2,949.70 6,023,235.03 569,020.39 2.39 2,728.84 MWD+IFR2+MS+sag(3) 5,921.00 92.41 304.25 4,376.88 4,327.58 120.27 -3,000.97 6,023,270.81 568,968.77 3.46 2,790.44 MWD+IFR2+MS+sag(3) 5,983.95 92.16 301.62 4,374.37 4,325.07 154.47 -3,053.76 6,023,304.49 568,915.66 4.19 2,852.58 MWD+IFR2+MS+sag(3) 6,046.02 91.42 301.35 4,372.43 4,323.13 186.87 -3,106.66 6,023,336.37 568,862.45 1.27 2,914.09 MWD+IFR2+MS+sag(3) 6,108.92 90.37 298.91 4,371.45 4,322.15 218.44 -3,161.05 6,023,367.41 568,807.76 4.22 2,976.61 MWD+IFR2+MS+sag(3) 6,171.86 90.31 296.23 4,371.07 4,321.77 247.56 -3,216.84 6,023,395.99 568,751.70 4.26 3,039.42 MWD+IFR2+MS+sag(3) 6,234.72 90.19 297.68 4,370.80 4,321.50 276.06 -3,272.87 6,023,423.94 568,695.40 2.31 3,102.20 MWD+IFR2+MS+sag(3) 6,297.92 89.88 299.56 4,370.76 4,321.46 306.33 -3,328.35 6,023,453.67 568,639.64 3.01 3,165.19 MWD+IFR2+MS+sag(3) 6,360.93 90.62 301.53 4,370.48 4,321.18 338.35 -3,382.61 6,023,485.16 568,585.08 3.34 3,227.78 MWD+IFR2+MS+sag(3) 6,424.05 90.62 303.90 4,369.80 4,320.50 372.46 -3,435.71 6,023,518.75 568,531.65 3.75 3,290.17 MWD+IFR2+MS+sag(3) 6,487.00 91.54 306.33 4,368.61 4,319.31 408.66 -3,487.19 6,023,554.45 568,479.83 4.13 3,351.92 MWD+IFR2+MS+sag(3) 6,549.76 91.98 308.64 4,366.69 4,317.39 446.83 -3,536.96 6,023,592.14 568,429.70 3.75 3,412.92 MWD+IFR2+MS+sag(3) 6,612.77 93.21 309.31 4,363.83 4,314.53 486.42 -3,585.90 6,023,631.25 568,380.39 2.22 3,473.72 MWD+IFR2+MS+sag(3) 6,676.45 93.21 308.78 4,360.27 4,310.97 526.47 -3,635.28 6,023,670.82 568,330.63 0.83 3,535.12 MWD+IFR2+MS+sag(3) 6,739.01 92.10 308.23 4,357.37 4,308.07 565.38 -3,684.18 6,023,709.24 568,281.35 1.98 3,595.62 MWD+IFR2+MS+sag(3) 6,802.11 91.79 302.28 4,355.23 4,305.93 601.76 -3,735.65 6,023,745.13 568,229.54 9.44 3,657.45 MWD+IFR2+MS+sag(3) 6,864.82 94.01 306.23 4,352.05 4,302.75 637.00 -3,787.41 6,023,779.86 568,177.45 7.22 3,719.06 MWD+IFR2+MS+sag(3) 6,928.14 95.00 305.79 4,347.08 4,297.78 674.12 -3,838.47 6,023,816.48 568,126.04 1.71 3,780.80 MWD+IFR2+MS+sag(3) 6,989.68 95.75 305.93 4,341.31 4,292.01 710.01 -3,888.12 6,023,851.88 568,076.04 1.24 3,840.76 MWD+IFR2+MS+sag(3) 7,053.43 94.82 305.20 4,335.44 4,286.14 746.93 -3,939.76 6,023,888.30 568,024.05 1.85 3,902.95 MWD+IFR2+MS+sag(3) 7,116.80 92.96 304.45 4,331.14 4,281.84 783.03 -3,991.66 6,023,923.89 567,971.81 3.16 3,965.05 MWD+IFR2+MS+sag(3) 7,179.81 91.36 304.99 4,328.77 4,279.47 818.89 -4,043.41 6,023,959.25 567,919.72 2.68 4,026.91 MWD+IFR2+MS+sag(3) 7,242.86 90.62 305.32 4,327.68 4,278.38 855.19 -4,094.95 6,023,995.05 567,867.84 1.29 4,088.76 MWD+IFR2+MS+sag(3) 7,305.07 90.86 305.94 4,326.88 4,277.58 891.43 -4,145.51 6,024,030.79 567,816.93 1.07 4,149.69 MWD+IFR2+MS+sag(3) 7,315.00 91.10 306.25 4,326.71 4,277.41 897.28 -4,153.53 6,024,036.56 567,808.86 3.95 4,159.40 MWD+IFR2+MS+sag(4) 7,367.93 89.01 308.30 4,326.66 4,277.36 929.33 -4,195.65 6,024,068.20 567,766.44 5.53 4,210.91 MWD+IFR2+MS+sag(4) 7,431.03 89.51 311.02 4,327.47 4,278.17 969.60 -4,244.22 6,024,107.99 567,717.49 4.38 4,271.65 MWD+IFR2+MS+sag(4) 7,493.78 90.06 310.96 4,327.71 4,278.41 1,010.75 -4,291.58 6,024,148.69 567,669.73 0.88 4,331.66 MWD+IFR2+MS+sag(4) 7,556.01 91.67 313.99 4,326.77 4,277.47 1,052.76 -4,337.47 6,024,190.25 567,623.44 5.51 4,390.67 MWD+IFR2+MS+sag(4) 7,616.61 91.36 313.33 4,325.16 4,275.86 1,094.59 -4,381.29 6,024,231.64 567,579.22 1.20 4,447.72 MWD+IFR2+MS+sag(4) 7,674.22 92.47 313.79 4,323.24 4,273.94 1,134.26 -4,423.02 6,024,270.91 567,537.12 2.09 4,501.97 MWD+IFR2+MS+sag(4) 7,741.74 92.22 313.21 4,320.48 4,271.18 1,180.70 -4,471.95 6,024,316.87 567,487.74 0.93 4,565.57 MWD+IFR2+MS+sag(4) 7,807.39 91.79 311.27 4,318.18 4,268.88 1,224.81 -4,520.52 6,024,360.49 567,438.75 3.03 4,627.88 MWD+IFR2+MS+sag(4) 7,868.74 91.23 308.09 4,316.56 4,267.26 1,263.96 -4,567.72 6,024,399.18 567,391.18 5.26 4,686.92 MWD+IFR2+MS+sag(4) 7,932.86 91.17 307.10 4,315.22 4,265.92 1,303.07 -4,618.51 6,024,437.80 567,340.02 1.55 4,749.22 MWD+IFR2+MS+sag(4) 7,996.17 90.00 306.77 4,314.57 4,265.27 1,341.11 -4,669.11 6,024,475.34 567,289.06 1.92 4,810.92 MWD+IFR2+MS+sag(4) 8,057.72 91.30 308.84 4,313.87 4,264.57 1,378.83 -4,717.74 6,024,512.59 567,240.08 3.97 4,870.69 MWD+IFR2+MS+sag(4) 8,121.86 92.90 310.22 4,311.52 4,262.22 1,419.63 -4,767.17 6,024,552.90 567,190.25 3.29 4,932.44 MWD+IFR2+MS+sag(4) 3/8/2017 6:05:59PM Page 5 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual @ 49.30usft Well: MPU B-32 North Reference: True Wellbore: MPU B-32 Survey Calculation Method: Minimum Curvature Design: MPU B-32 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,184.90 94.02 309.85 4,307.72 4,258.42 1,460.10 -4,815.35 6,024,592.91 567,141.69 1.87 4,992.92 MWD+IFR2+MS+sag(4) 8,247.86 94.14 309.97 4,303.24 4,253.94 1,500.39 -4,863.52 6,024,632.73 567,093.14 0.27 5,053.31 MWD+IFR2+MS+sag(4) 8,311.14 92.96 310.72 4,299.32 4,250.02 1,541.28 -4,911.66 6,024,673.14 567,044.61 2.21 5,113.92 MWD+IFR2+MS+sag(4) 8,373.55 93.02 311.37 4,296.07 4,246.77 1,582.21 -4,958.66 6,024,713.61 566,997.22 1.04 5,173.50 MWD+IFR2+MS+sag(4) 8,436.21 91.17 310.36 4,293.78 4,244.48 1,623.17 -5,006.01 6,024,754.11 566,949.48 3.36 5,233.42 MWD+IFR2+MS+sag(4) 8,499.11 90.62 310.43 4,292.79 4,243.49 1,663.93 -5,053.91 6,024,794.40 566,901.19 0.86 5,293.76 MWD+IFR2+MS+sag(4) 8,562.00 90.56 311.23 4,292.15 4,242.85 1,705.05 -5,101.49 6,024,835.05 566,853.22 1.28 5,353.95 MWD+IFR2+MS+sag(4) 8,625.88 89.82 313.16 4,291.93 4,242.63 1,747.95 -5,148.82 6,024,877.49 566,805.49 3.24 5,414.63 MWD+IFR2+MS+sag(4) 8,688.40 89.57 313.83 4,292.27 4,242.97 1,790.98 -5,194.17 6,024,920.08 566,759.72 1.14 5,473.57 MWD+IFR2+MS+sag(4) 8,751.34 91.60 315.63 4,291.62 4,242.32 1,835.27 -5,238.88 6,024,963.93 566,714.59 4.31 5,532.43 MWD+IFR2+MS+sag(4) 8,814.39 90.80 315.12 4,290.30 4,241.00 1,880.13 -5,283.16 6,025,008.35 566,669.89 1.50 5,591.12 MWD+IFR2+MS+sag(4) 8,877.70 88.58 314.11 4,290.65 4,241.35 1,924.59 -5,328.22 6,025,052.37 566,624.40 3.85 5,650.38 MWD+IFR2+MS+sag(4) 8,940.47 88.03 313.33 4,292.50 4,243.20 1,967.96 -5,373.57 6,025,095.29 566,578.64 1.52 5,709.44 MWD+IFR2+MS+sag(4) 9,003.59 90.86 314.26 4,293.11 4,243.81 2,011.63 -5,419.12 6,025,138.52 566,532.67 4.72 5,768.82 MWD+IFR2+MS+sag(4) 9,065.69 91.11 314.26 4,292.05 4,242.75 2,054.97 -5,463.59 6,025,181.42 566,487.79 0.40 5,827.07 MWD+IFR2+MS+sag(4) 9,128.86 92.66 313.29 4,289.97 4,240.67 2,098.65 -5,509.17 6,025,224.65 566,441.79 2.89 5,886.48 MWD+IFR2+MS+sag(4) 9,192.38 91.48 312.41 4,287.67 4,238.37 2,141.82 -5,555.71 6,025,267.36 566,394.84 2.32 5,946.55 MWD+IFR2+MS+sag(4) 9,255.29 92.78 310.82 4,285.34 4,236.04 2,183.56 -5,602.71 6,025,308.65 566,347.45 3.26 6,006.47 MWD+IFR2+MS+sag(4) 9,318.55 91.91 311.90 4,282.75 4,233.45 2,225.33 -5,650.15 6,025,349.95 566,299.61 2.19 6,066.79 MWD+IFR2+MS+sag(4) 9,381.18 91.54 312.32 4,280.86 4,231.56 2,267.31 -5,696.59 6,025,391.48 566,252.77 0.89 6,126.29 MWD+IFR2+MS+sag(4) 9,443.94 91.98 311.37 4,278.93 4,229.63 2,309.16 -5,743.32 6,025,432.87 566,205.64 1.67 6,186.00 MWD+IFR2+MS+sag(4) 9,506.12 91.54 312.00 4,277.02 4,227.72 2,350.49 -5,789.74 6,025,473.74 566,158.83 1.24 6,245.22 MWD+IFR2+MS+sag(4) 9,569.70 92.65 311.73 4,274.70 4,225.40 2,392.89 -5,837.05 6,025,515.68 566,111.11 1.80 6,305.69 MWD+IFR2+MS+sag(4) 9,633.25 89.63 309.08 4,273.44 4,224.14 2,434.07 -5,885.43 6,025,556.39 566,062.35 6.32 6,366.63 MWD+IFR2+MS+sag(4) 9,696.09 90.86 308.83 4,273.17 4,223.87 2,473.57 -5,934.29 6,025,595.41 566,013.11 2.00 6,427.34 MWD+IFR2+MS+sag(4) 9,759.10 90.12 307.30 4,272.63 4,223.33 2,512.42 -5,983.90 6,025,633.78 565,963.13 2.70 6,488.45 MWD+IFR2+MS+sag(4) 9,822.07 90.93 308.55 4,272.05 4,222.75 2,551.12 -6,033.56 6,025,671.99 565,913.10 2.37 6,549.57 MWD+IFR2+MS+sag(4) 9,884.96 91.91 309.83 4,270.49 4,221.19 2,590.85 -6,082.29 6,025,711.24 565,863.99 2.56 6,610.24 MWD+IFR2+MS+sag(4) 9,948.35 92.34 311.32 4,268.14 4,218.84 2,632.05 -6,130.41 6,025,751.97 565,815.49 2.44 6,670.95 MWD+1FR2+MS+sag(4) 10,011.01 93.33 312.62 4,265.04 4,215.74 2,673.90 -6,176.93 6,025,793.37 565,768.56 2.61 6,730.48 MWD+IFR2+MS+sag(4) 10,074.00 93.15 311.86 4,261.48 4,212.18 2,716.17 -6,223.49 6,025,835.19 565,721.60 1.24 6,790.21 MWD+IFR2+MS+sag(4) 10,136.70 94.57 311.12 4,257.26 4,207.96 2,757.62 -6,270.35 6,025,876.17 565,674.35 2.55 6,849.88 MWD+IFR2+MS+sag(4) 10,194.76 92.53 310.33 4,253.67 4,204.37 2,795.42 -6,314.27 6,025,913.54 565,630.07 3.77 6,905.37 MWD+IFR2+MS+sag(4) 10,265.00 92.53 310.33 4,250.57 4,201.27 2,840.84 -6,367.76 6,025,958.43 565,576.15 0.00 6,972.71 PROJECTED to TD mitchell.laird@halliburton.com pe„p,,,m.r,a„e�nn,;M,no,,mm Checked By: 2017.03.0815:1836-09'00' Approved By: ,7 ,soemouson Date: 3/08/17 3/8/2017 6:05:59PM Page 6 COMPASS 5000.1 Build 81 • . Hilcorp Alaska, LLC Milne Point h M Pt B Pad MPU B-32 PBI 50-029-23570-70-00 Sperry Drilling Definitive Survey Report ly 09 March, 2017 It m HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual @ 49.30usft Well: MPU B-32 North Reference: True Wellbore: MPU B-32 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-32 PBI Database: 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 MPU B-32 Well Position +NI-S 0.00 usft Northing: 6,023,179.57 usft Latitude: 70°28'25.010 N +E/-W 0.00 usft Easting: 571,970.48 usft Longitude: 149°24'43.701 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 22.90 usft Wellbore MPU B-32 PB1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 2/20/2017 17.89 81.06 57,560 Design MPU B-32 PB1 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.40 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.40 0.00 0.00 294.00 Survey Program Date 3/3/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 75.00 515.00 MPU 13-32 PB1 SRG-SS(MPU B-32 PB1 SRG-SS Surface readout gyro single shot 02/14/2017 574.59 5,574.10 MPU B-32 PB1 MWD+IFR2+MS+sag(1) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/20/2017 5,668.72 7,932.29 MPU B-32 PB1 MWD+IFR2+MS+sag(2) MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 02/28/2017 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 26.40 0.00 0.00 26.40 -22.90 0.00 0.00 6,023,179.57 571,970.48 0.00 0.00 UNDEFINED 75.00 0.26 141.20 75.00 25.70 -0.09 0.07 6,023,179.48 571,970.55 0.53 -0.10 SRG-SS(1) 112.00 0.11 277.81 112.00 62.70 -0.15 0.09 6,023,179.42 571,970.57 0.94 -0.14 SRG-SS(1) 141.00 0.38 170.02 141.00 91.70 -0.24 0.08 6,023,179.33 571,970.56 1.47 -0.17 SRG-SS(1) 202.00 0.39 130.37 202.00 152.70 -0.57 0.27 6,023,179.00 571,970.75 0.43 -0.48 SRG-SS(1) 264.00 1.78 228.63 263.99 214.69 -1.34 -0.29 6,023,178.22 571,970.20 3.03 -0.28 SRG-SS(1) 323.00 3.73 241.74 322.92 273.62 -2.86 -2.67 6,023,176.69 571,967.84 3.45 1.28 SRG-SS(1) 384.00 4.35 240.46 383.77 334.47 -4.94 -6.43 6,023,174.57 571,964.10 1.03 3.87 SRG-SS(1) 448.00 5.92 243.07 447.51 398.21 -7.63 -11.49 6,023,171.83 571,959.07 2.48 7.39 SRG-SS(1) 515.00 8.53 248.25 513.97 464.67 -11.04 -19.18 6,023,168.35 571,951.41 4.01 13.04 SRG-SS(1) 574.59 10.73 249.50 572.72 523.42 -14.62 -28.49 6,023,164.68 571,942.14 3.71 20.08 MWD+IFR2+MS+sag(2) 637.60 12.69 248.71 634.41 585.11 -19.19 -40.43 6,023,160.00 571,930.24 3.12 29.13 MWD+IFR2+MS+sag(2) 3/9/2017 11:23:28AM Page 2 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual @ 49.30usft Well: MPU B-32 North Reference: True Wellbore: MPU B-32 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-32 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 700.60 16.19 246.99 695.41 646.11 -25.13 -54.97 6,023,153.91 571,915.77 5.60 39.99 MWD+IFR2+MS+sag(2) 763.13 19.69 245.36 754.89 705.59 -32.93 -72.57 6,023,145.94 571,898.24 5.65 52.90 MWD+IFR2+MS+sag(2) 825.96 23.26 245.54 813.35 764.05 -42.49 -93.49 6,023,136.18 571,877.41 5.68 68.13 MWD+IFR2+MS+sag(2) 889.19 27.94 245.92 870.36 821.06 -53.71 -118.39 6,023,124.73 571,852.62 7.41 86.31 MWD+IFR2+MS+sag(2) 952.11 28.84 246.07 925.71 876.41 -65.88 -145.72 6,023,112.29 571,825.42 1.43 106.33 MWD+IFR2+MS+sag(2) 1,014.47 28.54 244.78 980.42 931.12 -78.33 -172.95 6,023,099.58 571,798.32 1.10 126.14 MWD+IFR2+MS+sag(2) 1,077.96 30.06 244.64 1,035.78 986.48 -91.60 -201.04 6,023,086.04 571,770.36 2.40 146.40 MWD+IFR2+MS+sag(2) 1,141.08 30.87 244.53 1,090.19 1,040.89 -105.33 -229.94 6,023,072.03 571,741.59 1.29 167.22 MWD+IFR2+MS+sag(2) 1,203.56 31.51 244.61 1,143.64 1,094.34 -119.23 -259.16 6,023,057.85 571,712.50 1.03 188.26 MWD+IFR2+MS+sag(2) 1,266.72 31.63 245.09 1,197.45 1,148.15 -133.28 -289.10 6,023,043.51 571,682.71 0.44 209.89 MWD+IFR2+MS+sag(2) 1,329.60 30.55 245.95 1,251.30 1,202.00 -146.74 -318.65 6,023,029.77 571,653.30 1.86 231.41 MWD+IFR2+MS+sag(2) 1,392.59 31.23 246.55 1,305.35 1,256.05 -159.76 -348.25 6,023,016.46 571,623.83 1.19 253.16 MWD+IFR2+MS+sag(2) 1,455.66 28.98 246.82 1,359.91 1,310.61 -172.28 -377.29 6,023,003.66 571,594.90 3.57 274.60 MWD+IFR2+MS+sag(2) 1,518.35 28.29 245.96 1,414.93 1,365.63 -184.31 -404.82 6,022,991.37 571,567.50 1.28 294.86 MWD+IFR2+MS+sag(2) 1,580.02 28.82 244.41 1,469.10 1,419.80 -196.69 -431.58 6,022,978.74 571,540.87 1.48 314.26 MWD+IFR2+MS+sag(2) 1,644.18 26.87 244.80 1,525.30 1,476.00 -209.96 -459.54 6,022,965.19 571,513.04 0.30 334.41 MWD+IFR2+MS+sag(2) 1,706.75 29.06 245.34 1,580.04 1,530.74 -222.73 -487.02 6,022,952.16 571,485.69 0.52 354.32 MWD+IFR2+MS+sag(2) 1,769.49 28.82 246.05 1,634.95 1,585.65 -235.23 -514.68 6,022,939.40 571,458.14 0.67 374.51 MWD+IFR2+MS+sag(2) 1,832.28 29.57 243.62 1,689.76 1,640.46 -248.26 -542.40 6,022,926.10 571,430.56 2.23 394.53 MWD+IFR2+MS+sag(2) 1,895.57 28.68 243.97 1,745.05 1,695.75 -261.86 -570.03 6,022,912.23 571,403.06 1.43 414.24 MWD+IFR2+MS+sag(2) 1,958.17 28.42 243.61 1,800.04 1,750.74 -275.07 -596.87 6,022,898.76 571,376.35 0.50 433.39 MWD+IFR2+MS+sag(2) 2,021.21 30.11 242.97 1,855.03 1,805.73 -288.93 -624.40 6,022,884.64 571,348.96 2.73 452.90 MWD+IFR2+MS+sag(2) 2,084.10 30.30 242.39 1,909.38 1,860.08 -303.45 -652.51 6,022,869.85 571,321.00 0.55 472.67 MWD+IFR2+MS+sag(2) 2,146.82 29.15 243.24 1,963.85 1,914.55 -317.66 -680.17 6,022,855.38 571,293.48 1.95 492.16 MWD+IFR2+MS+sag(2) 2,209.88 31.35 243.92 2,018.32 1,969.02 -331.79 -708.62 6,022,840.97 571,265.17 3.53 512.41 MWD+IFR2+MS+sag(2) 2,272.56 32.16 244.44 2,071.62 2,022.32 -346.16 -738.32 6,022,826.32 571,235.62 1.36 533.69 MWD+IFR2+MS+sag(2) 2,335.53 31.24 245.53 2,125.19 2,075.89 -360.15 -768.30 6,022,812.04 571,205.77 1.72 555.39 MWD+IFR2+MS+sag(2) 2,398.78 30.73 244.99 2,179.42 2,130.12 -373.78 -797.87 6,022,798.13 571,176.34 0.92 576.86 MWD+IFR2+MS+sag(2) 2,461.74 30.68 246.51 2,233.55 2,184.25 -386.98 -827.18 6,022,784.65 571,147.16 1.24 598.27 MWD+IFR2+MS+sag(2) 2,524.85 29.41 247.45 2,288.18 2,238.88 -399.34 -856.26 6,022,772.01 571,118.20 2.15 619.81 MWD+IFR2+MS+sag(2) 2,587.56 28.67 247.08 2,343.01 2,293.71 -411.10 -884.33 6,022,759.97 571,090.24 1.21 640.67 MWD+IFR2+MS+sag(2) 2,650.39 28.96 250.45 2,398.06 2,348.76 -422.06 -912.55 6,022,748.74 571,062.14 2.63 661.99 MWD+IFR2+MS+sag(2) 2,713.13 29.99 253.43 2,452.68 2,403.38 -431.62 -941.90 6,022,738.90 571,032.89 2.86 684.91 MWD+IFR2+MS+sag(2) 2,776.16 30.70 256.45 2,507.08 2,457.78 -439.88 -972.64 6,022,730.34 571,002.23 2.67 709.64 MWD+IFR2+MS+sag(2) 2,839.78 29.05 259.72 2,562.25 2,512.95 -446.45 -1,003.63 6,022,723.48 570,971.31 3.64 735.28 MWD+IFR2+MS+sag(2) 2,902.66 29.13 261.91 2,617.20 2,567.90 -451.32 -1,033.81 6,022,718.31 570,941.18 1.70 760.86 MWD+IFR2+MS+sag(2) 2,965.65 29.54 266.38 2,672.12 2,622.82 -454.46 -1,064.49 6,022,714.88 570,910.54 3.54 787.61 MWD+IFR2+MS+sag(2) 3,028.42 29.63 267.37 2,726.70 2,677.40 -456.15 -1,095.43 6,022,712.89 570,879.62 0.79 815.19 MWD+IFR2+MS+sag(2) 3,091.77 29.91 267.72 2,781.69 2,732.39 -457.50 -1,126.85 6,022,711.24 570,848.21 0.52 843.35 MWD+IFR2+MS+sag(2) 3,154.25 29.63 268.78 2,835.93 2,786.63 -458.45 -1,157.86 6,022,709.99 570,817.21 0.95 871.29 MWD+IFR2+MS+sag(2) 3/9,2017 11:23:28AM Page 3 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual @ 49.30usft Well: MPU 8-32 North Reference: True Wellbore: MPU B-32 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-32 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,217.30 28.90 266.56 2,890.93 2,841.63 -459.69 -1,188.65 6,022,708.45 570,786.44 2.07 898.92 MWD+IFR2+MS+sag(2) 3280.51 29.67 266.84 2,946.06 2,896.76 -461.47 -1,219.52 6,022,706.37 570,755.59 1.24 926.39 MWD+IFR2+MS+sag(2) 3,343.23 29.47 267.44 3,000.61 2,951.31 -463.02 -1,250.43 6,022,704.53 570,724.70 0.57 954.00 MWD+IFR2+MS+sag(2) 3,406.17 29.57 267.71 3,055.38 3,006.08 -464.33 -1,281.42 6,022,702.92 570,693.73 0.26 981.77 MWD+IFR2+MS+sag(2) 3,468.96 29.02 268.55 3,110.14 3,060.84 -465.33 -1,312.12 6,022,701.62 570,663.04 1.09 1,009.42 MWD+IFR2+MS+sag(2) 3,531.86 28.74 267.53 3,165.22 3,115.92 -466.37 -1,342.49 6,022,700.28 570,632.69 0.90 1,036.73 MWD+IFR2+MS+sag(2) 3,595.16 28.71 268.69 3,220.73 3,171.43 -467.37 -1,372.89 6,022,698.99 570,602.30 0.88 1,064.10 MWD+IFR2+MS+sag(2) 3,657.43 29.11 267.35 3,275.24 3,225.94 -468.42 -1,402.97 6,022,697.65 570,572.23 1.22 1,091.16 MWD+IFR2+MS+sag(2) 3,720.90 28.98 267.19 3,330.73 3,281.43 -469.88 -1,433.75 6,022,695.89 570,541.47 0.24 1,118.68 MWD+IFR2+MS+sag(2) 3,782.61 29.38 268.65 3,384.61 3,335.31 -470.97 -1,463.82 6,022,694.51 570,511.42 1.32 1,145.70 MWD+IFR2+MS+sag(2) 3,846.30 30.47 265.05 3,439.81 3,390.51 -472.74 -1,495.53 6,022,692.44 570,479.73 3.30 1,173.95 MWD+IFR2+MS+sag(2) 3,908.68 30.69 264.11 3,493.51 3,444.21 -475.73 -1,527.12 6,022,689.14 570,448.17 0.84 1,201.60 MWD+IFR2+MS+sag(2) 3,972.02 31.24 263.91 3,547.83 3,498.53 -479.13 -1,559.53 6,022,685.42 570,415.80 0.88 1,229.82 MWD+IFR2+MS+sag(2) 4,034.95 31.46 264.40 3,601.57 3,552.27 -482.47 -1,592.10 6,022,681.77 570,383.27 0.54 1,258.22 MWD+IFR2+MS+sag(2) 4,097.94 31.89 264.42 3,655.18 3,605.88 -485.69 -1,625.02 6,022,678.24 570,350.38 0.68 1,286.98 MWD+IFR2+MS+sag(2) 4,160.76 31.34 266.55 3,708.68 3,659.38 488.29 -1,657.84 6,022,675.32 570,317.59 1.98 1,315.91 MWD+IFR2+MS+sag(2) 4,223.62 31.43 269.03 3,762.34 3,713.04 -489.55 -1,690.55 6,022,673.74 570,284.90 2.06 1,345.28 MWD+IFR2+MS+sag(2) 4,286.44 32.47 274.07 3,815.65 3,766.35 -488.63 -1,723.75 6,022,674.34 570,251.69 4.56 1,375.98 MWD+IFR2+MS+sag(2) 4,349.43 35.01 276.90 3,868.03 3,818.73 -485.26 -1,758.57 6,022,677.38 570,216.85 4.74 1,409.16 MWD+IFR2+MS+sag(2) 4,412.38 38.42 279.54 3,918.49 3,869.19 -479.84 -1,795.79 6,022,682.43 570,179.58 5.97 1,445.37 MWD+IFR2+MS+sag(2) 4,475.68 40.99 281.52 3,967.19 3,917.89 -472.44 -1,835.54 6,022,689.45 570,139.77 4.52 1,484.69 MWD+IFR2+MS+sag(2) 4,538.13 44.35 283.04 4,013.10 3,963.80 -463.42 -1,876.89 6,022,698.07 570,098.34 5.63 1,526.13 MWD+IFR2+MS+sag(2) 4,600.99 47.44 283.81 4,056.84 4,007.54 -452.93 -1,920.78 6,022,708.13 570,054.35 4.99 1,570.50 MWD+IFR2+MS+sag(2) 4,667.70 50.10 284.51 4,100.81 4,051.51 -440.65 -1,969.42 6,022,719.93 570,005.59 4.06 1,619.93 MWD+IFR2+MS+sag(2) 4,726.75 54.18 286.66 4,137.04 4,087.74 -428.11 -2,014.31 6,022,732.04 569,960.59 7.48 1,666.04 MWD+IFR2+MS+sag(2) 4,789.48 57.44 288.96 4,172.29 4,122.99 -412.22 -2,063.69 6,022,747.45 569,911.06 6.02 1,717.61 MWD+IFR2+MS+sag(2) 4,852.94 59.76 290.39 4,205.35 4,156.05 -393.98 -2,114.69 6,022,765.20 569,859.90 4.13 1,771.62 MWD+IFR2+MS+sag(2) 4,916.05 60.33 292.22 4,236.87 4,187.57 -374.11 -2,165.63 6,022,784.57 569,808.78 2.67 1,826.23 MWD+IFR2+MS+sag(2) 4,979.02 62.29 294.09 4,267.10 4,217.80 -352.39 -2,216.41 6,022,805.80 569,757.79 4.06 1,881.46 MWD+IFR2+MS+sag(2) 5,041.70 65.13 293.26 4,294.86 4,245.56 -329.83 -2,267.87 6,022,827.86 569,706.12 4.68 1,937.65 MWD+IFR2+MS+sag(2) 5,104.24 68.41 294.36 4,319.52 4,270.22 -306.62 -2,320.44 6,022,850.55 569,653.33 5.49 1,995.11 MWD+IFR2+MS+sag(2) 5,167.18 71.59 296.56 4,341.05 4,291.75 -281.19 -2,373.82 6,022,875.46 569,599.71 6.03 2,054.22 MWD+IFR2+MS+sag(2) 5,230.37 73.96 296.63 4,359.76 4,310.46 -254.18 -2,427.79 6,022,901.96 569,545.49 3.75 2,114.51 MWD+IFR2+MS+sag(2) 5,293.37 77.81 296.87 4,375.12 4,325.82 -226.68 -2,482.34 6,022,928.92 569,490.68 6.12 2,175.53 MWD+IFR2+MS+sag(2) 5,356.52 81.38 299.67 4,386.53 4,337.23 -197.26 -2,537.02 6,022,957.80 569,435.72 7.14 2,237.45 MWD+IFR2+MS+sag(2) 5,418.98 84.50 299.77 4,394.20 4,344.90 -166.54 -2,590.85 6,022,988.01 569,381.61 5.00 2,299.12 MWD+IFR2+MS+sag(2) 5,481.99 87.46 300.03 4,398.62 4,349.32 -135.21 -2,645.33 6,023,018.80 569,326.83 4.72 2,361.64 MWD+IFR2+MS+sag(2) 5,574.10 93.43 303.26 4,397.90 4,348.60 -86.91 -2,723.70 6,023,066.34 569,248.01 7.37 2,452.87 MWD+IFR2+MS+sag(2) 5,668.72 93.52 308.00 4,392.17 4,342.87 -31.91 -2,800.44 6,023,120.59 569,170.74 5.00 2,545.35 MWD+IFR2+MS+sag(3) 5,732.13 94.82 308.50 4,387.55 4,338.25 7.24 -2,850.10 6,023,159.25 569,120.71 2.20 2,606.65 MWD+IFR2+MS+sag(3) 319,2017 11:23:28AM Page 4 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-32 Project: Milne Point TVD Reference: Actual @ 49.30usft Site: M Pt B Pad MD Reference: Actual @ 49.30usft Well: MPU B-32 North Reference: True Wellbore: MPU 8-32 PB1 Survey Calculation Method: Minimum Curvature Design: MPU B-32 PB1 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,794.89 93.02 307.83 4,383.26 4,333.96 45.93 -2,899.33 6,023,197.46 569,071.11 3.06 2,667.35 MWD+IFR2+MS+sag(3) 5,856.11 93.09 306.32 4,379.89 4,330.59 83.99 -2,949.70 6,023,235.03 569,020.39 2.39 2,728.84 MWD+IFR2+MS+sag(3) 5,921.00 92.41 304.25 4,376.88 4,327.58 120.27 -3,000.97 6,023,270.81 568,968.77 3.46 2,790.44 MWD+IFR2+MS+sag(3) 5,983.95 92.16 301.62 4,374.37 4,325.07 154.47 -3,053.76 6,023,304.49 568,915.66 4.19 2,852.58 MWD+IFR2+MS+sag(3) 6,046.02 91.42 301.35 4,372.43 4,323.13 186.87 -3,106.66 6,023,336.37 568,862.45 1.27 2,914.09 MWD+IFR2+MS+sag(3) 6,108.92 90.37 298.91 4,371.45 4,322.15 218.44 -3,161.05 6,023,367.41 568,807.76 4.22 2,976.61 MWD+IFR2+MS+sag(3) 6,171.86 90,31 296.23 4,371.07 4,321.77 247.56 -3,216.84 6,023,395.99 568,751.70 4.26 3,039.42 MWD+IFR2+MS+sag(3) 6,234.72 90.19 297.68 4,370.80 4,321.50 276.06 -3,272.87 6,023,423.94 568,695.40 2.31 3,102.20 MWD+IFR2+MS+sag(3) 6,297.92 89.88 299.56 4,370.76 4,321.46 306.33 -3,328.35 6,023,453.67 568,639.64 3.01 3,165.19 MWD+IFR2+MS+sag(3) 6,360.93 90.62 301.53 4,370.48 4,321.18 338.35 -3,382.61 6,023,485.16 568,585.08 3.34 3,227.78 MWD+IFR2+MS+sag(3) 6,424.05 90.62 303.90 4,369.80 4,320.50 372.46 -3,435.71 6,023,518.75 568,531.65 3.75 3,290.17 MWD+IFR2+MS+sag(3) 6,487.00 91.54 306.33 4,368.61 4,319.31 408.66 -3,487.19 6,023,554.45 568,479.83 4.13 3,351.92 MWD+IFR2+MS+sag(3) 6,549.76 91.98 308.64 4,366.69 4,317.39 446.83 -3,536.96 6,023,592.14 568,429.70 3.75 3,412.92 MWD+IFR2+MS+sag(3) 6,612.77 93.21 309.31 4,363.83 4,314.53 486.42 -3,585.90 6,023,631.25 568,380.39 2.22 3,473.72 MWD+IFR2+MS+sag(3) 6,676.45 93.21 308.78 4,360.27 4,310.97 526.47 -3,635.28 6,023,670.82 568,330.63 0.83 3,535.12 MWD+IFR2+MS+sag(3) 6,739.01 92.10 308.23 4,357.37 4,308.07 565.38 -3,684.18 6,023,709.24 568,281.35 1.98 3,595.62 MWD+IFR2+MS+sag(3) 6,802.11 91.79 302.28 4,355.23 4,305.93 601.76 -3,735.65 6,023,745.13 568,229.54 9.44 3,657.45 MWD+IFR2+MS+sag(3) 6,864.82 94.01 306.23 4,352.05 4,302.75 637.00 -3,787.41 6,023,779.86 568,177.45 7.22 3,719.06 MWD+IFR2+MS+sag(3) 6,928.14 95.00 305.79 4,347.08 4,297.78 674.12 -3,838.47 6,023,816.48 568,126.04 1.71 3,780.80 MWD+IFR2+MS+sag(3) 6,989.68 95.75 305.93 4,341,31 4,292.01 710.01 -3,888.12 6,023,851.88 568,076.04 1.24 3,840.76 MWD+IFR2+MS+sa9(3) 7,053.43 94.82 305.20 4,335.44 4,286.14 746.93 -3,939.76 6,023,888.30 568,024.05 1.85 3,902.95 MWD+IFR2+MS+sag(3) 7,116.80 92.96 304.45 4,331.14 4,281.84 783.03 -3,991.66 6,023,923.89 567,971.81 3.16 3,965.05 MWD+IFR2+MS+sag(3) 7,179.81 91.36 304.99 4,328.77 4,279.47 818.89 -4,043.41 6,023,959.25 567,919.72 2.68 4,026.91 MWD+IFR2+MS+sag(3) 7,242.86 90.62 305.32 4,327.68 4,278.38 855.19 -4,094.95 6,023,995.05 567,867.84 1.29 4,088.76 MWD+IFR2+MS+sag(3) 7,305.07 90.86 305.94 4,326.88 4,277.58 891.43 -4,145.51 6,024,030.79 567,816.93 1.07 4,149.69 MWD+IFR2+MS+sag(3) 7,367.50 92.34 307.92 4,325.13 4,275.83 928.92 -4,195.39 6,024,067.79 567,766.70 3.96 4,210.51 MWD+IFR2+MS+sag(3) 7,430.35 91.60 307.59 4,322.97 4,273.67 967.38 -4,245.05 6,024,105.77 567,716.67 1.29 4,271.52 MWD+IFR2+MS+sag(3) 7,493.77 92.59 307.52 4,320.65 4,271.35 1,006.01 -4,295.30 6,024,143.91 567,666.06 1.56 4,333.13 MWD+IFR2+MS+sag(3) 7,556.78 92.10 307.43 4,318.08 4,268.78 1,044.31 -4,345.26 6,024,181.72 567,615.73 0.79 4,394.35 MWD+IFR2+MS+sag(3) 7,619.46 90.12 307.34 4,316.86 4,267.56 1,082.36 -4,395.05 6,024,219.28 567,565.58 3.16 4,455.32 MWD+IFR2+MS+sag(3) 7,681.71 89.63 308.48 4,317.00 4,267.70 1,120.61 -4,444.17 6,024,257.05 567,516.10 1.99 4,515.74 MWD+IFR2+MS+sag(3) 7,744.65 89.82 309.76 4,317.30 4,268.00 1,160.32 -4,492.99 6,024,296.28 567,466.90 2.06 4,576.50 MWD+IFR2+MS+sag(3) 7,807.07 90.25 309.71 4,317,26 4,267.96 1,200.22 -4,541.00 6,024,335.71 567,418.52 0.69 4,636.58 MWD+IFR2+MS+sag(3) 7,870.43 91.54 310.69 4,316.27 4,266.97 1,241.11 -4,589.38 6,024,376.13 567,369.74 2.56 4,697.41 MWD+IFR2+MS+sag(3) 7,932.29 91.42 311.35 4,314.67 4,265.37 1,281.70 -4,636.04 6,024,416.26 567,322.70 1.08 4,756.55 MWD+IFR2+MS+sag(3) 8,003.00 91.42 311.35 4,312.92 4,263.62 1,328.40 -4,689.10 6,024,462.44 567,269.19 0.00 4,824.02 PROJECTED to TD mitchell.lairdehaliiburton.com benjamin.hand@halliburton.com Checked By: 2017.03.0909:40:41-0960' Approved By: 2017.03.09 08 2759-09.00 Date: 3/�9/�7 379/2017 11:23:28AM Page 5 COMPASS 5000.1 Build 81 • • MPB-32 MW vs Depth 0 1000 MPB-32 Plan MPB-32 Actual 2000 3000 4000 5000 • 6000 - s r a 7000 z i 8000 9000 10000 11000 12000 13000 14000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) 4/7/2017 MPB-32 Days vs Depth FINAL 0 _ 500 -MPB-32 Actual 1000 MPB-32 Plan 1500 2000 2500 3000 3500 4000 4500 5000 5500 a v -a 6000 6500 ea7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 0 5 10 15 20 25 30 Days 4/7/2017 • 2161 51 11 Debra Oudean Hilcorp Alaska, LLC 2 p q ® 9 AK_GeoTech 3800 Centerpoint Drive, Suite 100 cy i J RECEIVED Anchorage, AK 99503 2 8 1 8 2 Tele: 907 777-8337 v 11'641rp Anemia'.1,1A. Fax: 907 777-8510 DATA LOGGED 'AR 2 9 2017 E-mail: doudean@hilcorp.com y /Ca/2011 K. BENDER Date: 3/29/2017 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-3' 7— B-3 4 _B-34 Prints: ROP-DGR-ADR-EWR-CTN-ALD 2IN MD, DGR-ADR-EWR-CTN-ALD 2IN TVD E log data CD 1 : Final Well Data A Files Currently on the Disc (7) k. _Log Viewers 3/9/2017 2:57 AM File folder CGM 3/9/2017 2:57 AM File folder Definitive Survey 3/9/2017 2:57 AM File folder EMF 3/9/2017 2:57 AM File folder LAS 3/9/2017 2:57 AM File folder PDF 3/9/2017 2:57 AM File folder TIFF 3/9/2017 2:57 AM File folder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received Date: ti OF Tit • ,o,k•I//7: THE STATE Alaska Oil and Gas of LAsKA Conservation Commission 333 West Seventh Avenue W ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 '� Main: 907.279.1433 O�ALA9v-P` Fax: 907.276.7542 www.aogcc.alaska.gov Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-32 Hilcorp Alaska, LLC Permit to Drill Number: 216-151 Surface Location: 56' FSL, 4321' FEL, Sec. 18, T13N, R11E, UM, AK Bottomhole Location: 2374' FNL, 179' FEL, Sec. 14, 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 . Foerster Chair DATED this f' day of December, 2016. EI E STATE OF ALASKA 0 V 0 .l 015 AICA OIL AND GAS CONSERVATION COMMOIN PERMIT TO DRILL 20 AAC 25.005 AOGCC 1a.Type of Work: 1h.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp ❑ 1c.Specify if well is proposed for: Drill ❑✓ . Lateral 0 Stratigraphic Test 0 Development-Oil D, Service- Winj 0 Single Zone ❑., ' Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry ❑ Exploratory-Oil 0 Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Q • Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC , Bond No. 022035244 • MPU B-32 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 10,352.7' • ND: 4,299.4' s Milne Point Unit • 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Schrader Bluff Oil Pool • Surface: 56'FSL,4321'FEL,Sec 18,T13N,R11 E,UM,AK • (SHL)ADL047438/(TPH/BHL)ADL 047437 Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 120'FNL, 1930'FEL,Sec 24,T13N,R10E,UM,AK N/A 1/21/2017 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 2374'FNL, 179'FEL,Sec 14 T13N,R10E,UM,AK • 4,344 Acres Total + 7,144'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 49.4' + 15.Distance to Nearest Well Open Surface: x-571970 y-6023179 Zone-4 ' GL Elevation above MSL(ft): 22.9' to Same Pool: B-32 100' 16.Deviated wells: Kickoff depth: 264 feet . 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 91.38 degrees . Downhole: 1949 . Surface: 1508 1 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD ND MD ND (including stage data) 42" 20" 78.6# A-53 Weld 80' Surface Surface 80' 80' 50 bbls from Cmt Truck 12-1/4" 9-5/8" 40# L-80 DWC/C 5,769' Surface Surface 5,769' 4,410' Stg 1 237 bbls 10.7#/43.1 bbls 15.8# Stg 2 185 bbls 10.7#/56 bbls 15.8# 8-1/2" 4-1/2" 12.6# L-80 Hyd 521 4752.7' 5,600' 4,405' 10,352.7' 4,299.4' Cementless with slotted liner/swell pkrs - 7-5/8" 29.7# L80 Vam STL 5,600' Surface Surface 5,600' 4,405' Tieback Assembly 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth ND(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth ND(ft): 20. Attachments: Property Plat Q BOP Sketch ❑✓ Drilling Program ❑✓ Time v.Depth Plot Q Shallow Hazard Analysis❑ Diverter Sketch Q Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Email Ikellerphilcorp.com Printed Name uke Keller Title Drilling Engineer Signature ! Phone 777-8395 Date i I A AI 3/ � Commission Use Only Permit to Drill API Number: Permit Approval ' n See cover letter for other Number: 1(0 /S 1 50-00,9—,233-?0 -00-00 Date: i ^ iq I 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 sha[✓C Other: ?� j pct 0:,0C' `cs-( Samples req'd: Yes n No121 Mud log req'd:Ds [�0 H2S measures: Yes IE7 No Directional svy req'd: , s Spacing exception req'd: Yes❑ No Inclination-only svy req'd:Os t--rm-, ` Z ( t Q I 1 Post initial injection MIT req'd:Os a APPROVED BY Approved byQ4 A�� COMMISSIONER THE COMMISSION Date: /2.—(9-4 Kg 100/6, ORil ( AIA 116 ,1 I� V,{► Submn Form ane Form 10-401(Revised 17/2015) p i i v r f onths from the date of approval(20 AAC 25.005(g)) Attachments in Duplicate • Luke Keller Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com Hilcorp Alaka,1,L(. 11/1/2016 Commissioner RECEIVED Alaska Oil &Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 NOV 0 1 2016 Re: MPB-32 AOGCC Dear Commissioner, Enclosed for review and approval is the Permit to Drill for MPB-32 well. MPU B-32 is a grassroots producer planned to be drilled in the Schrader Bluff NC sand. B-32 is part of a (2)well pilot program targeting the NC sand. B-32 will be paired with a grassroots injector, B-33. The directional plan is a catenary welipath build with 9-5/8" surface casing set into the top of the Schrader Bluff NC sand. A lateral section will then be drilled in the reservoir. Production screens will then be run inside the well to limit sand production. A 3-1/2"gas lift completion will then be run to produce the well. Drilling operations are expected to commence approximately January 21st, 2017. The Hilcorp"Innovation"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, Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 S Hilcorp Alaska, LLC Milne Point Unit (MPU) B-32 Drilling Program Version 1 Oct 13th, 2016 • • Milne Point Drilling Procedure Hilcorp Energy Company Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 Casing Inspection 4 6.0 Internal Reporting Requirements 5 7.0 Planned Wellbore Schematic 6 8.0 Drilling/Completion Summary 7 9.0 Mandatory Regulatory Compliance/Notifications 8 10.0 R/U and Preparatory Work 10 11.0 N/U 13-5/8"5M Diverter System 11 12.0 Drill 12-1/4"Hole Section 13 13.0 Run 9-5/8" Surface Casing 18 14.0 Cement 9-5/8" Surface Casing 23 15.0 BOP N/U and Test 28 16.0 Drill 8-1/2"Hole Section 30 17.0 Run 4-1/2"Production Screens 34 18.0 Run 7-5/8"Tieback 38 19.0 Run 3-1/2"Production Tubing(Upper Completion) 40 20.0 RDMO 40 21.0 Diverter Schematic 41 22.0 BOP Schematic 42 23.0 Wellhead Schematic 43 24.0 Days Vs Depth 44 25.0 Formation Tops 45 26.0 Anticipated Drilling Hazards 46 27.0 Innovation Rig Layout 48 28.0 FIT Procedure 49 29.0 Choke Manifold Schematic 50 30.0 Casing Design Information 51 31.0 8-1/2"Hole Section MASP 52 32.0 Spider Plot(NAD 27)(Governmental Sections) 53 33.0 Surface Plat(As Built)(NAD 27) 54 34.0 Offset MW vs TVD Chart 55 35.0 Drill Pipe Information 5" 19.5#S-135 DS-50 56 • • Milne Point Unit B-32 Drilling Procedure Hilcorp Enol Company 1.0 Well Summary Well MPU B-32 Pad Milne Point"B"Pad Planned Completion Type 3-1/2"Gas Lift Target Reservoir(s) Schrader Bluff "NC" Sand Planned Well TD, MD/TVD 10,352.7' MD/4,299.4' TVD PBTD, MD/TVD 10,340' MD/4,300' TVD Surface Location(Governmental) 56' FSL,4,321' FEL, Sec 18, T13N,R11E, UM,AK Surface Location(NAD 27—Zone 4) X=571,970.48 Y=6,023,179.57 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 120'FNL, 1930'FEL, Sec 24, T13N,R10E, UM,AK TPH Location(NAD 27) X=569,150.2, Y=6,022,976.1 TPH Location(NAD 83) BHL(Governmental) 2374'FNL, 179' FEL, Sec 14, T13N, R10E, UM,AK BHL(NAD 27) X=565,592.9, Y=6,025,969.99 BHL(NAD 83) AFE Number 1612655D AFE Drilling Days 14 days AFE Completion Days 8 days AFE Drilling Amount $3,244,300 AFE Completion Amount $1,935,400 AFE Facility Amount $300,000 Maximum Anticipated Pressure (Surface) 1508 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1949 psi Work String 5" 19.5# S-135 DS-50 (Weatherford Rental) KB Elevation above MSL: 26.5 ft+22.9 ft=49.4 ft GL Elevation above MSL: 22.9 ft BOP Equipment 13-5/8"x 5M Annular, (3)ea 13-5/8"x 5M Rams Page 2 Version 1 Oct 2016 • S Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp Emmy foamy Changes to Approved Permit to Drill Date: 10-12-2016 Subject: Changes to Approved Permit to Drill for MPU B-032 File#: MPU B-032 Drilling and Completion Program Any modifications to MPU 6-032 Drilling& Completion Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by the AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 1 Oct 2016 • S Milne Point Unit B-32 Drilling Procedure Hililm 3.0 Tubular Program: Hip e�` Olirr ID (in) Mir. Conn 11114" Grade Co lurst Collapse Tension Section (in) OD (in) (#/ft) (psi) (psi) (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 DWC/C 5,750 3,090 916 8-1/2" 4-1/2" 3.894" 3.75" 5.307" 12.6# L-80 H521 - - 200 7-5/8" 6.875" 6.75" 7.625" 29.7# L-80 VAM 6890 4790 444 STL 4.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section (in) (in) (#/ft) (Min) (Max) (k-lbs) All 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k 5.0 Casing Inspection All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 Oct 2016 • S II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, lkeller@hilcorp.com and cdinger@hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager&Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final"As-Run"Casing tally to lkeller@hilcorp.com and cdinger@hilcorp.com 6.6 Casing and Cmt report • Send casing and cement report for each string of casing to lkeller@hilcorp.com and cdinger@hilcorp.com 6.7 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 Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Coordinator Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 Oct 2016 • Milne Point Unit B-32 II Drilling Procedure Hilcorp Energy Company 7.0 Planned Wellbore Schematic Orig.KB E1er.:49.4'/GL Elev.:22.9' TREE &WELLHEAD Tree Seaboard 3 1/8" 5M --.31 * L Seaboard 16 3/4"3M x 11"5M Multibowl w/ll"x 3 1/2"EUE Top and bvellhead Bottom with 3"CIW"H"BPV profile.2ea 3/8"NPT control lines. OPEN HOLE/CEMENT DETAIL 42" ^'29 bbis(6 Yards dumped down backside) ' .. 12-1/4"1st stage 237 bbl 10.7#ArcticCEM,43.1 bbl 15.8#SwiftCEM 12-1/4"2nd stage 185 bbl 10.7#ArcticCEM,56 bbl 15.8#SwiftCEM 8-1/2" Cementless Screens Liner in 8-1/2"hole ' CASING DETAIL Size Type WtV Grade/Conn Drift ID Top Btm BPF 20" Conductor 78.6/A-53/Weld N/A Surface 106.5' N/A 9-E18 ES 9-5/8' Surface 40/L-80/DWC/C 8.75 Surface 5,769' 0.0758 Cementer@ k: l' 2 . 2.000 7-5/8" Tieback 29.7/L-80/Vam STL 6.75 Surface 5,600' 0.0459 4-1/2" Liner(250µScreens) 12.6/1-80/Hyd 521 3.833 5,600' 10,352.7' 0.0152 al '2 TUBING DETAIL 3-1/2" Tubing 9.3/L-80/EUE 8rd 2.867 Surf 5,615' 0.0087 WELL INCLINATION DETAIL ' KOP @ 264' Max Hole Angle=91.38 deg.@ 5,800'MD Ci!1� 3 `.4 4 JEWELRY DETAIL "d No. l Top MD I Item ID Upper Completion el 1 Tubing Hanger 2.992" f` 2 2,000' 3.5"X Nipple Assembly,2.813"Packing Bore 2.813" 7-5/8" A, • 3 2,200' 3.5"GLM 1"BK Latch 2.962' 4 4,000' 3.5"GLM Dummy valve w 1"BK Latch3-1/2"x 1"Pocket 2.962" ,, '- 5 4,700' 3.5"GIM Dummy valve w 1"BK Latch 3-1/2''x 1"Pocket 2.962" 6 4,800' 3.5"Sliding Sleeve,X profile,2.813"seal bore 2.813" t, t,, 7 4,850' 7-5/8"Haliburton PHL Packer 2.885" k 8 a,1 8 4 900 3.5"XN Nipple w/RHC ball catcher,2.750"No-Go,2.813" 2.992" 1 Packing Bore 1. 9 5,615' 3-1/2"Mule Shoe wjt. 2.992" 11 9 ;? Lower Completion '1 '1 _. '10'' life 10 5,600' BOT SLZXP Liner Top Packer w/BD Slips 7"x 9-5/8" 6.200" �� 95/8 ;� 2 11 5,612' 7-5/8"TiebackAssy.(8.25"OD No-Go @ 5,561') 6.151" 12 5,620' 7"H563 x 4"H521 L-80 X0 3.900" `'- _.......-.• 13 See Below 5-1/2"17#Tendeka Swell Packers 4.982" �. =---it 14 10,340' 4-1/2"Drillable Packoff Sub 2.400" I 15 10,352.7' WIV Valve LTC 8x8(1.5"Ball on Seat/Closed) See Screend SWELL PACKER DETAIL Sdid Liner pdyi Top(MD) Btm(MD) 6,175' 6,186' 6,238' 6,249' 6,878' 6,888' 4-1/2" 13 Shoe@ 10,350't,)! 1E TD=10,352.7'(MD)/ID=4,299.4'(TVD) PBTD=10,340'(MD)/P8TD=4,300'(TVD) Page 6 Version 1 Oct 2016 • • Milne Point Unit B-32 Drilling Procedure Hilcorp Enersr comPany 8.0 Drilling / Completion Summary MPU B-32 is a grassroots producer planned to be drilled in the Schrader Bluff NC sand. B-32 is part of a(2) well pilot program targeting the NC sand. B-32 will be paired with a grassroots injector, B-33. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff NC sand. A lateral section will then be drilled in the reservoir. Production screens will then be run inside the well to limit sand production. A 3-1/2"gas lift completion will then be run to produce the well. Drilling operations are expected to commence approximately January 21st,2017. ./The Hilcorp"Innovation"will be used to drill and complete the wellbore. Surface casing will be run to 5,769' MD/4,410' 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 waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on"B"pad. ,J General sequence of operations: 1. MOB Innovation to well site 2. N/U 13-5/8"Diverter 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 13-5/8"x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 4-1/2"production screens. 6. Run 7-5/8"tieback. 7. Run production tubing. 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 / 2. Production Hole: No mud logging. On site geologist. LWD: GR+ Res i Page 7 Version 1 Oct 2016 • • Milne Point Unit B-32 Drilling Procedure Hilcorp sr Conlin/1y 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at(2)week intervals during the drilling and completion of MPU B-32. 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. • Note use of"safety joint" for well control while running the production liner. This procedure is explained in detail in section 17. There will be no BOP test conducted on the 4-1/2" liner size. Page 8 Version 1 Oct 2016 • S Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12-1/4" • 13-5/8"5M diverter w/16"diverter line Function Test Only • 13-5/8"x 5M Control Technology Inc Annular BOP • 13-5/8"x 5M Control Technology Inc Double Gate Initial Test:250/3000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/3"x 5M side outlets 8-1/2" • 13-5/8"x 5M Control Technology Single ram • 3-1/8"x 5M Choke Line Subsequent Tests: • 3-1/8"x 5M Kill line 250/3000 • 3-1/8"x 5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc Primary closing unit: Control Technology Inc, 6 station, 20 bottle, 3000 psi, 220 gal EHPLC Primary& secondary closing hydraulics are provided by electrically driven triplex pumps. Emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event(BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236 (During normal Business Hours) Notification/Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 1 Oct 2016 • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 10.0 R/U and Preparatory Work 10.1 A new insulated conductor has been set for B-32, the surface location is just south of the current B-30 well on the West side of the pad. 10.2 Dig out and set impermeable cellar. 10.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.4 Install Seaboard slip-on 13-5/8" 5M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 10.5 Insure (2) 3"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off 10.6 Level pad and ensure enough room for layout of rig footprint and R/U. 10.7 Confirm that the rig is over the appropriate well slot. 10.8 MIRU Hilcorp Innovation. 10.9 Mud loggers WILL NOT be used on either hole section. 10.10 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 10.11 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.12 Keep 5" liners in mud pumps. • White Star 1300 HP Quatro mud pumps are rated at 4097 psi, 380 gpm @ 140 spm @ 90% mechanical efficiency & 100%volumetric efficiency. Page 10 Version 1 Oct 2016 • • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 11.0 N/U 13-5/8" 5M Diverter System 11.1 N/U 13-5/8" Control Technology 5M diverter System (Diverter Schematic at Sec 20 at back of program). • N/U 13-5/8" 5M diverter"T". • Install 16"knife gate and 16" diverter line. - • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source. • Place drip berm at the end of diverter line. 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. • Ensure all other Rams and both HCRs are disabled/not connected. The BOP is being used as a diverter, and there should be NO possible way to shut in the well inadvertently. 11.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone"must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 11.4 Set wearbushing in wellhead. Page 11 Version 1 Oct 2016 • • II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 11.5 Rig & Diverter Orientation on "B"pad: /////////104.0043' 444 / B 31 uparuk Producer I r,) (.4 , ; : 312 Sch Producer .... / , /7,8-3, L.11 Injector Na 1F" Diverter line // S.CiIfflAE1nni1,2iMaI1—aMi_.4 2z..-.-ri.crcr--O:,•/oJp 1A_1O) .. . / . ,8—,31 1t1IiII,,I .a•0g Producer B10,01 i I I Page 12 Version 1 Oct 2016 S 410 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 12.0 Drill 12-1/4" Hole Section 12.1 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. • 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. 12.2 12-1/4" BHA (GR + Res LWD and PWD planned in surface hole): COMPONENT DATA iter t Connecion 0D., ti ID Stiff ID Gauge Weight Top Length Total Location Description (in) , (in) (in) (in) (lbpf? (ft) (ft) (ft) Tricone 8.000 3.000 12.250 147.22 P 6-5/8"REG 1.10 ©8"SperryDrill Lobe 4/5-5.3 stg 8.000 5.000 5.000 103.09 B 6-5/8"REG 31.47 32.57 Stabilizer 12.125 4.28 ©Float Sub 8.000 2.880 2.880 149.10 B 6-5/8"REG 2.40 34.97 Stabilizer 8.000 3.000 3.000 10.250 147.22 B 6-5/8"REG 6.00 40.97 35.97 8"DM Collar(Directional) 8.000 3.500 3.544 147.40 B 6-5/8"REG 9.20 50.17 6 8"DGR Collar(Gamma) 8.000 1.920 4.997 142.70 B 6-5/8"REG 4.55 54.72 0 8"EWR-P4 Collar(Resistivity) 8.000 1.985 5.205 151.00 B 6-5/8"REG 12.19 66.91 8 8"PWD(Pressure ECDs) 8.000 1.920 4.760 143.40 B 6-5/8"REG 4,44 71.35 9 8"HCIM Collar(Processor) 8.000 1.920 4.309 149.90 B 6-5/8"REG 4.97 76.32 10 8"POS PULSER(Telemetry) 8.000 4.000 4.257 145.20 B 6-5/8"REG 15.44 91.76 El Orienting Sub UBHO 8.000 2.875 3.000 149.18 B 6-5/8"REG 2.50 94.26 ®NM Flex Collar 8.000 2.813 150.13 B 6-5/8"REG 31.00 125.26 ®NM Flex Collar 8.000 2.813 150.13 B 6-5/8"REG 31.00 156.26 14 NM Flex Collar 8.000 2.813 150.12 B 6-5/8"REG 31.00 187.26 8jts x 5"X 3"HWDP#49.3-NC50(IF) 5.000 3.000 49.30 240.00 427.26 16 Jar 7.500 2.813 2.813 129.38 B 4-1/2"IF 35.00 462.26 12jts x 5"X 3"HWDP#49.3-NC50(IF) 5.000 3.000 49.30 360.00 822.26 Total: 822.26 Page 13 Version 1 Oct 2016 • 0 II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 12.3 Primary Bit: a 12-1 /4 VMD-3 ..� TEEL OOTH hi (311.2 mm) • Ultra-Abrasive Formation Cutting Structure Specifically engineered for ultra-abrasive formations. This steel tooth cutting structure has extra-thick hardfacing to ensure teeth stay sharper longer and deliver extended runs with f improved penetration rates. «/.44 Metal Face Seal&Bearing SystemM motor,W, I Longer bit life in high-RPM, and high-temperature drilling applications,up to 400r • (204°C),with the patented VM metal-to-metal sealing system. 4 •4ttll, lit- XL&LX Hardfacing Features It A patented.strategically placed bead of hardfacing is added to key areas on specific teeth to retard tooth wear and improve tooth strength and durability. '11' • Boss Stabilization System These unique integrated stabilizers provide near six-point contact with the borehole wall for unequaled stability and cutting structure protection. 1 • STL Hardfacing .' Increased bit life and reliability with a precisely controlled application of patented,highly wear- resistant STL'"hardfacing that covers the entire shirttail and leg areas for superior protection from the potentially damaging effects of hole-wall contact • Center Jet(C) A fourth jet is positioned in the center of the bit and utilized to prevent bit balling and the associated reduction in penetration rate. • Clean Sweep Hydraulics(CS2) Biased nozzle configuration directs fluid toward areas where bit balling occurs.The Clean Sweep high-velocity core strikes heel and adjacent heel area on the backside of the cone. PRODUCT SPECIFICATIONS: IADC: 137 Bearing/Seal Package: Journal I Metal Cutting Structure: Inner Row: ST Heel Row: ST Gauge Row: ST Gauge Trimmers: Nth Tooth Hardfacing: XL1LX OD Hardfacing: STL Nozzle Type: Standard Center Jet Display: FK or VK Makeup Torque: 28.0-32.0 klbf-ft(38.0-43.4 kNrn) Connection: 6-5/8 REG API Approx. Shipping Weight: 235 lb(106.6 kg) Reference Part Number: H2187000 OPERATING RECOMMENDATIONS: * Weight On Brt: 20-50.0 kib(9-22 to or kdaN) Rotation Speed: For High Speed Rotary/Motor Applications Page 14 Version 1 Oct 2016 • • II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 12.4 5" Workstring, HWDP, and Jars will come from Weatherford. 12.5 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.6 Drill 12-1/4" hole section to TD per geologist and drilling engineer. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 600 - 650 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • For producer wells only: • 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. • 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. • 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(95' 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 "B"pad wells to date. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is>4. • Do not slide for 100' MD above the base of the permafrost(1700' TVD) or 100' below the base. We want to leave this transition as undisturbed as possible. • Plan a bit trip (if necessary) before penetrating the UGNU LA3 sand. This interval caused an unintentional sidetrack on L-48. Page 15 Version 1 Oct 2016 • • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 12.7 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 8.8 ppg. • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office. • 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: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Surface 8.8-9.2 85-250 20-40 25-75 <10 8.5-9.0 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 Page 16 Version 1 Oct 2016 • • tir Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 12.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 20" conductor shoe. 12.9 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. 12.10 TOH with the drilling assy, handle BHA as appropriate. 12.11 No open hole logging program planned. Page 17 Version 1 Oct 2016 • • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 13.0 Run 9-5/8" Surface Casing 13.1 R/U and pull wearbushing. 13.2 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8"DWC/C x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 13.3 P/U shoe joint, visually verify no debris inside joint. 13.4 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. Bypass Baffle This end up. ..................> 114111k 01110l� C_ I • (1) Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 18 Version 1 Oct 2016 1 i • 1111 Milne Point Unit B-32 ' Drilling Procedure s 1 Hilcorp Energy Company 13.5 Float equipment and Stage tool equipment drawings: "A _ -IP Type H ES Cementer B _ Part No. Min.ID Agar Ddbut Ullii" Sc)No. C ° Max.Tool OD ' D Hi!tarp ES-II Running Order Opening Seat ID AClosing Sleeve _ IIII No.Shear Pins E Cfoeirp Seat ID it a �1 Shear PinOpening s Plug Set 1 ES Cementer 1 111.111111 ES CementerME �j Part No. Depth -Ls". JSO No. l \ ) cios ng Plug " f/ III 6 a�a Adapter(ii used) .:\N=rL" UD Shut Off Plug ili Baffle Adapter O Openingg I ap-r OD �jfR� OD LJ Bypass or Shut-off Baffle ID By-Pass Plug Depth Shut-off Plug ' � Float Collar r Depth IN By Pass Baffle OD Float Collar Float Shoe Depth Bypass Plug (if used) lid Hole TD Float Shoe "Reference Casing OD Sales Manual Section 5 Page 19 Version 1 Oct 2016 • • 14 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 13.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • 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. 13.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at 2000' MD/ 1819' TVD. This will position the stage collar comfortably below the permafrost. • Install centralizers over couplings on 3 joints 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 DWC/C Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 29,800 ft-lbs 34,800 ft-lbs Page 20 Version 1 Oct 2016 • Milne Point Unit B-32 II Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Slze(O.D.): Weight(Wall): Grade: DWCIC Casing 9-5/8 in 40.00 Ib/ft(0.395 in) L-80 standard Material L-80 GradedeIIIIAPIF 80.000 Minimum Yield Strength (psi) 111111111111WIIIIIM U SA 95.000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX 77041 Phone 713-479-3200 9.625 Nominal Pipe Body O.D. (in) Fax:713-479-3234 8.835 Nominal Pipe Body I.D.(in) E-ward:VAMUSArsaiest vara-usa_oom 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) r r Pipe Body Performance Properties ' t 916,000 Minimum Pipe Body Yield Strength (ibs) 3.090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter (in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 916.000 Joint Strength (lbs) 16.360 Reference String Length (ft) 1.4 Design Factor 947,000 API Joint Strength (lbs) 916.000 Structural Compression Rating (lbs) 3,090 API Collapse Pressure Rating (psi) 5.750 API Internal Pressure Resistance (psi) 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoxlmated Field End Torque Values 29,800 Minimum Final Torque (ft-lbs) 34.800 Maximum Final Torque (ft-lbs) 39.800 Connection Yield Torque (ft-lbs) Page 21 Version 1 Oct 2016 • • li Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 13.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.9 Slow in and out of slips. 13.10 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 13.11 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 13.12 Have emergency slips ready to go in the event we cannot land the hanger. 13.13 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. 13.14 After circulating, lower string and land hanger in wellhead again. Page 22 Version 1 Oct 2016 • 4110 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 14.0 Cement 9-5/8" Surface Casing 14.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud&water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 14.4 R!U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug(flexible bypass plug). Mix and pump cmt per below calculations for the 1St stage. 14.8 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 (5269'- 2000') x .0558 bpf x 1.3 = 237 bbls 1331 ft3 annulus: Total LEAD: 237 bbls 1331 ft3 3 i° s' 12-1/4" OH x 9-5/8" Casing (5769'- 5269') x .0558 bpf x 1.3 = 36.3 bbls 203 ft3 annulus: 9-5/8" Shoe track: 90 x .0758 bpf = 6.8 bbls 38.3 ft3 Total TAIL: 43.1 bbls 242 ft3 01 S;r: • S Milne Point Unit B-32 Drilling Procedure Hilcorp Energy cnwor Cement Slurry Design (both 1st and 2nd stage cement jobs): Lead Slurry Tail Slurry System ArcticCEM TM System SwiftCEM TM System Density 10.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed 21.13 gal/sk 5.04 gal/sk Water 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 14.11 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. To operate the stage tool hydraulically, the plug must be bumped. 14.12 Displacement calculation: 5482' x .0758 bpf= 416 bbls total (216 bbl mud+ 80 bbl water+ 119 bbl mud) The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 10 bbls before consulting with drilling engineer. 14.15 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. 14.16 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. Page 24 Version 1 Oct 2016 S Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 14.17 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP <20 again in preparation for the 2' stage of the cement job. 14.18 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 25 Version 1 Oct 2016 • - Milne Point Unit B-32 Drilling Procedure Hilcorp Enemy Company Second Stage: 14.19 Prepare for the 2nd stage as necessary. Hold another pre job meeting if crew change has occurred. 14.20 Load ES cementer closing plug in cmt head. 14.21 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.22 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.23 Mix and pump cmt per below recipe for the 2„d stage. 14.24 Cement volume based on annular volume+200% open hole excess. Job will consist of lead& tail, TOC brought to surface. However cmt will continue to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: nP Sc Section: Calculation: Vol(BBLS) Vol(ft3) 20" Conductor x 9-5/8" (106.5') x .27 bpf x 1 = 29 bbls 164 ft3 casing annulus: 12-1/4" OH x 9-5/8" Casing (1500'- 106.5')x .0558 bpf x 2 = 156 bbls 876 ft3 annulus: Total LEAD: 185 bbls 1039 ft3 11 12-1/4" OH x 9-5/8" Casing (2000'- 1500')x .0558 bpf x 2 = 56 bbls 314 ft3 annulus: Total TAIL: 56 bbls 314 ft3 `v-lo>' 14.25 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 14.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 14.27 Displacement calculation: 2100' x .0758 bpf= 160 bbls mud Page 26 Version 1 Oct 2016 S ill Milne Point Unit B-32 II Drilling Procedure Hilcorp Energy Company 14.28 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.29 Decide ahead of time what will be done with cmt returns once they are at surface. We should get back approx. 130 bbls of cmt slurry. 14.30 Land closing plug on stage collar and pressure up to 1000— 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Back out and L/D landing joint. Flush out wellhead with FW. 14.31 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 14.32 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 lkeller@hilcorp.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 27 Version 1 Oct 2016 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 15.0 BOP N/U and Test 15.1 N/D the diverter"T" &N/U 11" 5M tubing spool and DSA to 13-5/8" 5M. 15.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from Top down: 13-5/8"x 5M annular/ 13-5/8"x 5M Double gate / 13- 5/8" x 5M mud cross/ 13-5/8" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 5" Fixed rams • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 15.3 Run 5" BOP test assy, land out test plug(if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes at some point in the well: 5" (for 5" DP workstring). 3-1/2" (for 3-1/2"tubing). 7-5/8" before running tieback 15.4 R/D BOP test assy. 15.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 15.7 Set 10" ID wearbushing in wellhead. 15.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 15.9 Keep 5" liners in mud pumps. 15.10 P/U used 8-1/2" Baker Hughes mill tooth bit and clean out BHA and TIH to TOC. This trip may be omitted if cmt job goes as planned and there is not excessive cement left inside casing. 15.11 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. • Drilling with minimal WOB is recommended. Approx 2-5 k is enough. Page 28 Version 1 Oct 2016 'Mime Point Unit B-32 Drilling Procedure Hilcorp Energy Company • Apply weight and allow it to drill off before applying more. • After drilling out, chase any remaining debris to bottom with the drill bit. 15.12 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.13 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= 5750/2 =—2875 psi, but maximum test pressure on the well is 3000 psi. 15.14 Drill out shoe track and 20' of new formation. 15.15 CBU and condition mud for FIT. ©w ✓ 15.16 Conduct FIT to 12 ppg EMW. 0cv7,c re`s' 15.17 TOH with clean out assy for lateral drilling assy. Page 29 Version 1 Oct 2016 ID I Milne Point Unit B-32 i Drilling Procedure ii Hilcorp Energy Company 16.0 Drill 8-1/2" Hole Section 16.1 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 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 . • Install ported float in the BHA. 16.2 8-1/2" Rotary Steerable (Includes at bit GR, at bit incl, ADR for geosteering, PWD): COMPONENT 1111.1111 Item OD ID Gauge Weight Top Length Cumulative # Description` , ria!Number (in) Connection (ft) Length {1t) (in) (in) (lbpl) 9 1 PDC-Long Gauge 6.360 2.250 8.500 94.72 P 4-112"REG 2.19 2.19 Stabilizer 8.469 _--- 2 Geo-Pilot 7600 XL 25KSI 7.625 1.490 8.375 113.00 B 4-112"IF 20.16 22.35 Ref Housing Stabilizer 8.375 -IIIIIIIIIM� 3 6-314'DnIIDOC(WOB/TOB) 7.100 2.000 108.41 B 4-112"IF 7.10 29.45 4 6-3/4"DGR(Gamma) 6.750 1.920 97.80 B 4-112"IF 8.43 37.88 5 6-3/4'PWD(Pressure) 6.750 1.920 96.30 B 4-112"IF 4.40 42.28 6 Inline Stabilizer(ILS) 6.750 1.920 8.250 112.09 B 4-1/2"IF 2.25 44.53 7 6-314"ADR Collar(Resistivity) 6.750 1.920 109.40 B 4-112"IF 24.30 68.83 8 6-3/4"DM Collar(Directional) 6.750 3.125 103.40 B 4-112"IF 9.20 78.03 6-3/4"TM Collar(Mud Pulse 6.750 3.250 103.60 B 4-112"IF 10.00 88.03 Telemet 10 6-314"Float Sub 6.750 2.250 ® 108.40 B4-1/2"IF 2.00 90.03 11 NMDC Stick 6.750 2.813 100.77 B 4-112"IF 31.00 121.03 11131 NMDC Slick 6.750 2.813 100.77 EOM 31.00 152.03 13 NMDC Slick 6.750 2.813 100.77 B 4-1/2"IF 31.00 183.03 In lit x 5"X 3"HWDP#49.3-4.51F 5000 3.000 49.30 31.00 214.03 15 Weatherford 6.25"Jar 6.250 2.250 91.01 B 4-112"IF 30.00 244.03 16 ljt x 5"X 3"HWDP#49.3-4.5IF - 5000 3.000 49.30 ® 31.00 275.03 17 5'X 4.276'-19.5#6-518"X 2-314"- -■ 5.000 4.276 22.60 31.00 306.03 4.51F Tom :;{; 306.03 Page 30 Version 1 Oct 2016 S II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 16.3 Primary Bit: KeYWellbore Technologies Design Specifications „40 Make up Length(ft): .92 Shank Bore(ins): 2.300 ' Shank Diam(ins): 6.400 Connection std: Y � Connection Size(ins): 4.500 ' . Connection Type: Apr Reg Pin e4�r m "» Make up Torque(ft-lbs): 20000 n .n,' IADC Code: M422 Diameter:(ins) 8 l.2' Body Material: Matrix HDK 8 1/2" SK616M-J 1 D F '(i ): 18.660 Face Volume:(in') 71.66 Normalised Face vol: 53.26% Design Features of this bit Seeker"'Directional Drill Bits Seeker*""directional drill bits are designed to overcome directional drilling challenges for both motor or RSS tools in a wide range of directional applications. Blade Oty: 6 Gauge Length:(ins) 4.000 Helios""Inferno""Cutters-Specialized cutter technology engineered for specific applications that may require increased thermal resistance.increased abrasion resistance or increased toughness. Gauge Geometry: Spiral-Trailing Each Helios'"Inferno"'cutter has a unique cutter index value indicating performance characteristics. Gauge Profile: SmoothSteer SmoothhTorque"Torque Control Components-SmoothTorque torque control components are Gauge Protection: TSP Tiled inserts placed between primary cutters to provide a predictable torque response to applied weight-on-bit and reduction in torque variance. Bit Profile: snout Taper-Shaba./cone SmoothSteer'M Gauges SmoothSteer"gauges deliver maximum gauge contact.lowering resistance to steer by reducing torque.and leading to improved ROP and extended bit and tool life. Recommended Operating TSP Gauge Protection-Thermally stable product(TSP)tiles and welded hardmetal gauge Parameters protection give both a highly durable and ultra-smooth gauge. Max Operating WOB(klbs):38 Spiral Gauge-Stability is improved by increasing the circumferential contact of the bit gauge. Min TFA(in2): 0.2946 Improved stability enhances steerability and ROP. Max TFA(in2): 2.2272 Max Flow(gpm): 934 This bit/unit can accommodate BlackBoxT.'HD drilling recorder. HSI: 2-7 This bodied PDC bit features computer aided cutter placement and hydraulics optimized by nozzle location to deliver high performance and longer bit life. Bit Breaker: Thick 1W St some app"caiWtS fits ort Jr run succe,rttMy beyond these parameters.Contact your NOV ReedHyrabp RepreseMJrhe Mr recommended operating parameters in your appNoabon.NOV ReedHycabg reserves the giant to teethe these specifications,based On advances and anprovemerns to technology. This report is sed for 30 days from 02-Sep-2015 Cutting Structure Nozzles& Ports Type Qty Location Diameter Shape Oty Type aim Primary 31 FACE 16 mm CYLINDER 6 TNZ VARIABLE Primary 12 GAGE 13 mm CYLINDER Primary 6 BACK-ANGLE 13 mm CYLINDER TCC 6 FACE 11 mm DOME TOPPED Page 31 Version 1 Oct 2016 S • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 16.4 8-1/2"hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1)ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid 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: Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT pH Production 8.9-9.2 15-25 15-25 <10% <7 <11.0 8.5-9.5 System Formulation: Baradrill-N Product Concentration Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N-VIS 1.0— 1.5 ppb N-DRIL HT PLUS 5 ppb BARACARB 5 4 ppb BARACARB 25 4 ppb BARACARB 50 2 ppg BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.015 ppb Page 32 Version 1 Oct 2016 40 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 16.5 TIH w/ 8-1/2" directional assy. 16.6 On-bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations pulsed up real time. • If BHA begins to show excessive vibrations/whirl /stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. 16.7 Drill 8-1/2"hole section to section TD per Geologist and Drilling Engineer. • Pump at 550 - 650 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 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. • Limit maximum instantaneous ROP to <200 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. 16.8 Concretion drilling strategy: • Past experience has shown that no two hard streaks are the same. WOB and RPM may have to be constantly changed to drill effectively. • When a hard streak is encountered, first attempt to drill through it with low WOB (5k WOB, 150 RPMs at the bit). Gradually increase one or the other or both. Allow enough time to elapse after a parameter adjustment to make note of increased or decreased drilling efficiency. • DO NOT backream through concretions. This practice has been attributed to cutter damage in the past. • Normal backreaming can be done through soft/high ROP drilling areas. • Make all attempts at prolonging bit life when working through concretion intervals. Once the shoulder row of cutters has been chipped or damaged, the steerability and ROP will be significantly reduced. 16.9 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. Page 33 Version 1 Oct 2016 O • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company • 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. 16.10 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the 9-5/8" shoe. If backreaming is necessary: • Circulate at full drill rate (600—650 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 16.11 Circulate and condition mud. Perform"Screen Plugging Test" on return mud samples. Continue to circulate and condition mud as needed to pass "Screen Plugging Test". If unable to pass test, the hole may have to be swapped over to a new solids free mud system prior to POOH. 16.12 TOH with the drilling assembly to the 9-5/8" casing shoe. Swap over to clean filtered brine in preparation for running screens. Rotate and reciprocate as needed to ensure the mud is removed from the 9-5/8" casing. Continue to POH and stand back BHA if possible. Rabbit DP on TOH. 16.13 Only LWD open hole logs are planned for the hole section(GR+Res). There will not be any additional logging runs conducted. 17.0 Run 4-1/2" Production Screens 17.1 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2"production screens, the following well control response procedure will be followed: • P/U & M/U the 5" safety joint(with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2"handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" screen. • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. • Proceed with well kill operations. 17.2 In the event of an influx of formation fluids while running the 2-3/8" inner string inside the 4- 1/2"production screens: • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8"triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8"handling joint above TIW). M/U 2-3/8" and then 4-1/2"to triple connect. Page 34 Version 1 Oct 2016 • II 14 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Cly • This joint shall be fully M/U with crossovers and available prior to running the first joint of wash pipe. • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. • Proceed with well kill operations. 17.3 R/U 4-1/2" screen handling equipment. • Ensure 4-1/2" Hydril 521 x NC-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. 17.4 Run 4-1/2"production liner per lower completion tally. • Use API Modified thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Handle screens with care, the wire mesh can easily be damaged which then allows formation solids to enter the completion. • Install swell packers are per the lower completion tally. • Remove protective packaging on swell packers just prior to picking up • Do not place tongs or slips on the packer element 4-1/2" Hydril 521 M/U torques Casing OD Minimum Maximum Yield Torque 4.5" 3,900 ft-lbs 6,800 ft-lbs 15,300 ft-lbs Page 35 Version 1 Oct 2016 • 1111 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company PIPE BODY DATA GEOMETRY a, Standard Drift Nominal 00 4.500 in. Nominal Weight 12.60 Ibs/ft 3.833 in. Diameter Special Drift Nominal ID 3.958 in. Wall Thickness 0.271 in. N/A Diameter Plain End Weight 12.25 lbs/ft PERFORMANCE Body Yield 288 x 1000 lbs Internal Yeed 8430 psi SMYs 80000 psi Strength Collapse 7500 psi WEDGE 521^' CONNECTION DATA GEOMETRY Connection OD 4.729 in. Connection ID 3.918 in. Make-Up Loss 3.620 in. Critical Section 2.393 sq. in. Threads per in. 3.36 Area PERFORMANCE 192 x 1000 Internal Pressure Tension Efficiency 66.5% Joint Yield Strength 8430 psi lbs Capacity Compression Compression 248 x 1000 lbs 86.0% Bending 54*/100 ft Strength Efficiency External Pressure 7500 psi Capacity MAKE-UP TORQUES Minimum 3900 ft-lbs Optimum 4700 ft-lbs Maximum CI 6800 ft-lbs OPERATIONAL LIMIT TORQUES Operating Torque 10200 ft-lbs Yield Torque 15300 ft-lbs BLANKING DIMENSIONS Blanking Dimensions 17.4 Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8"connection. 17.5 R/U false rotary and run inner string. 17.6 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. Page 36 Version 1 Oct 2016 S Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 17.7 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. 17.8 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.9 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. 17.10 DP should autofill. 17.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth+ S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 17.13 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 17.14 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 17.15 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 17.16 Rig up to pump down the work string with the rig pumps. NOTE: The purpose of the extended wellbore cleanup is to ensure that as much of the mud in the open hole is removed from the wellbore in attempt to minimize the amount of mud that would be produced back through the screens. 17.17 Break circulation and begin displacing wellbore to 8.9 ppg 2% KC1/NaC1 brine. Adjust brine weight to equal mud weight. Note the large OD on the swell packers. Begin circulating at -1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. 17.18 Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the swell packers. Note all losses. Catch mud for future use if feasible. Page 37 Version 1 Oct 2016 Milne Point Unit B-32 11 Drilling Procedure Hilcorp Energy Company 17.19 Displace entire wellbore to brine at 300 FPM annular velocity if possible (approximately 15 BPM). Monitor the returned fluids to ensure as much mud has been removed from the wellbore as possible. 17.20 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. 17.21 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. 17.22 Bleed DP pressure to zero, close BOP and test annulus to 1500 psi for.30 min and chart record same. 17.23 Bleed off pressure and pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 17.24 POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 17.25 L/D remaining DP out of derrick. 18.0 Run 7-5/8" Tieback 18.1 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" (250/3000 psi) casing rams ,�- in top ram. 18.2 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. 18.3 P/U ported tieback seal assy and set in rotary. 18.4 M/U first joint of 7-5/8"to seal assy. 18.5 Run 7-5/8" STL tieback string. 18.6 Ensure appropriate well control crossover is ready on rig floor, M/U to FOSV in the open position. 18.7 Run 7-5/8" tieback to position seal assy two joints above tieback sleeve. Record up & down weights. Page 38 Version 1 Oct 2016 • • Milne Point Unit B-32 11 Drilling Procedure Hilcorp Energy Company • Following running procedure outlined above. 18.8 M/U 7-5/8" STL to DP crossover. 18.9 M/U stand of DP to string, and M/U top drive. 18.10 Break circulation at 1 bpm and begin lowering string. 18.11 Note seal assy entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 18.12 Continue lowering string and land out on no-go. Set down 5 — 10k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 18.13 P/U string& stand back DP stand, L/D XO. 18.14 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. 18.15 P/U hanger assy. Ensure crossover is available to allow circulation down the string. 18.16 R/U to circulate down 7-5/8" x 9-5/8" annulus,taking returns up the 7-5/8" casing. 18.17 Close annular on landing joint—ensure hanger is not across the annular when closing. 18.18 Pump 64.3 bbls 10.2 ppg NaCl/NaBr brine followed by 40.2 bbls 6.7 ppg diesel. This will balance to 8.9 ppg EMW and will put leading edge of diesel freeze protect at 2014' MD/2000' TVD. Check these calculations with actual well profile and brine/diesel weights. 18.19 Open annular, slowly slack off and stab seal assy into polished bore receptacle. If there is any U- tube flow occurring, it will stop as soon as seal assy enters PBR. If there is U-tube flow occurring, DO NOT fill backside or 7-5/8", this will only make it worse. Continue slacking off and land hanger in wellhead. • NOTE: If wellbore geometry allows, the heavy brine may be omitted. Alternative freeze protect placement is possible leaving annular closed, with seals engaged, seal assy port exposed, then circulating diesel freeze protect down backside. • After placement—must leave annular closed, lower string and isolate seal assy port, continue slacking off to land out hanger in wellhead. 18.20 Confirm hanger has seated properly in wellhead. Should be approx. 130k lb on hanger when landed. Make note of actual weight on hanger on morning rpt. 18.21 Run in hanger lock downs. Page 39 Version 1 Oct 2016 • • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 18.22 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. 18.23 R/D casing running tools and test 7-5/8"x 9-5/8" annulus to 1000 psi/30 min. 19.0 Run 3-1/2" Production Tubing (Upper Completion) ,w1 �' y3 '6,4' µ 19.1 M/U wireline re-entry guide and packer assy as per the running order. RIH to setting depth on 3-"IN 1/2"production tubing. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while TIH. • Install WLEG, X nipples, sliding sleeve, and GLMs per tally supplied by completion engineer. • Packer set depth will be 4900' MD but is subject to change due to hole inclination or gas lift design. 19.2 Makeup the tubing hanger and landing joint. 19.3 Land hanger. RILDs and test hanger. 19.4 Continue pressurizing the tubing and set the packer. Test the tubing to 3500 psi for 30 minutes. Bleed off the tubing pressure to 1500— 1700 psi. Test the annulus to 3,000 psi for 30 min. 19.5 Bleed off the tubing pressure to zero and shear the DCK valve 19.6 Circulate freeze protect down IA, allow freeze protect to U-tube down tubing. 19.7 Install BPV and N/D BOP. 19.8 N/U tree adapter and tree. Conduct pressure test of same to 500/5000 psi. 19.9 Shut in well. 20.0 RDMO Page 40 Version 1 Oct 2016 • • II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 21.0 Diverter Schematic rn FIT-11 17111\1 Ili _--13-5/8"5M Control Technology Annular BOP r=iT..... E_ __d iil 2I • „Th.c, ., II . �`"-,-13-5/8"5M Control ' 4vicTs) Technology Double Ram I.11/. Rei ... 3 1i8" Kill Line /-6---a-1 ■r .7%/4= e..T� � lik i l' I--.*fz0 —3-118"Choke Line Kiy [1 b 3y —' 13-5/8" 5M Control—" Technology Single Ram It 13-5/8" 13-5/8"x 5M € - [I— E i R____6 .___ -----------------16''Diverter Line i,%\ // ,. 13-518"x 5M \-2-11116"x5M 20"Casing Page 41 Version 1 Oct 2016 • • 11 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 22.0 BOP Schematic fra ,, 111111' 11 111 111 11 '111111 ------''`----13-518"5M Control Technology Annular BOP EN_' . ■1 C•5i °ate ■ ._ ' �molai •'?" iffmii,' i ' --''x-13-5/8" 5M Control Ey IN I Technology Double Ram IMP: Vi . i 1 .._..________� , U-; ,aa,� —1 _-_ 3-1/8"Kill Linea ~ �r l r`.. 44 ~"``�-3-1/8"Choke Line Miiiir�'IN 'Q' -----------___13-5/8" 5M Control Technology Single Ram 13-5/8"x 5M 11"x5M tf 1, t ,) j _ 1 .P. r1 9-5/8" DBL D Seal— • i111 .1„, ' Ill � —2-1/16"x 5M CasingHanger �� ir,�h, %� 13-5/8"x 5M S 22 _"IM sI I14 . �� 13-518'" NOM ii, 9-5/8" BTC Btm x 2-1/16"x 5M 10.5"-4 SA Pin Top W/Primary Seal 20"Casing 9-5/8°Casing Page 42 Version 1 Oct 2016 • • II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 23.0 Wellhead Schematic HILCORP ALASKA, LLC 0 MQ—392 I-I m 1 47.3 " - "r EST 3-1/8 5M "�tA OO O 4-71971trea* ,/ i) O ffill.. ,o O, :I -I 1 /OO'L�r105.2 `i' � OO / EST �_ / - 3-1/8 5My '•' \\ ..�/// HYDRAUUC ACTUATED u V O OO O o O O O 50.3 EST n w MI n. 3-1/8 5M iplgti O J0o O ADAPTER, TUBING HEAD `� 168.7 SM-E-2CH .-741, �� 11 5M X 3-1/8 5M (SPECIAL) EST WITH TWO(2) 3/8 CL •._•. } +j8 5M 7.611111111111. EST 11 SM ,_.. - s I p_ � TUBING HANGER, SM-E-2CL IMO i 11 X 3-1/2 EU 8R0 BOX TOP ,. Ell 1O1, 17.2 X 3-1/2 00 API MOD BOX BTM 1 \ EST WITH TWO(2) 3/8 LP PORTS ■ L,■il+ • :r. ` l.... 115M- ��_ i ��®��l CASING HANGER, SMB-22 1\I' 1 I I 11�1 \ 2-1/'6 .`.1d11 x 7-5/8 '- 29.7/L-80 ST-L BOX BTMI 0 25.63.5 ESTE STUB ACME-2G-LH PIN TOP ■ !IL_®• _ iEST ISII .• W/SEAL ASSEMBLY 1.1 9-5/8 DBL IPS -.01. .10, �� 2-t/76 5M 13-5/8 5M r " h 1.. 2-1/16 5M CASING HANGER, S-22 u! III ail,., ISI zos 13-5/8 x s-s/a Lj EST •'�T.II l : :]i ... I .I Conductor 9-5/8 CASING 7-5/8 CASING MR 3-1/2 TUBING - 5,000 PSI WELLHEAD ASSEMBLY NOTE: 13-3/8 X 9-5/8 X 7-5/8 X 3-1/2 DIMENSIONS SHOWN ON THIS DRAWING ARE RESTRICTED CONFIDENTIAL DOCUMENT ESTIMATES ONLY AND CAN VARY SIGNIFICANTLY ,,,,p,,,,,,a,,,,,o,�„„ >,7,"' ,t5 n" 1-10 1`10/14/16 •n DEPENDING ON RAW MATERIAL LENGTHS. mum X2"'MC MO AN r M NO GUARANTEE CE STAMP HEIGHT IS IMPLIED. " am ov«a..i oMANN,TO*PAM nlg.*MUM MO 0006‘04.l.11%O., tot MCIPIOrt Kw. MAIM N° DIMENSIONS SHORN SHOULD BE CONSIDERED2 FOR REFERENCE PURPOSES ONLY. c4M01,1 Ott Of anal m Y..wet:+i.,:+n c"'°"`"'tl1'�"O' x�- P-21574 Page 43 Version 1 Oct 2016 • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 24.0 Days Vs Depth Days Vs Depth 0 —s-032 —B-28 —B-29 2000 4000 6000 a a 0 v N rts8000 10000 12000 14000 0 5 10 15 20 25 Days Page 44 Version 1 Oct 2016 • 0 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 25.0 Formation Tops MPU B-32 Projected Formation Tops Formation Top TVD Bottom TVD SV1 2607 2627 Ugnu LA3 3900 3930 Schrader Bluff NA 4386 4400 Schrader Bluff ND 4410 4430 GENERALIZED GEOLOGICAL ,____.__FOR.ECAST SS GEOLOGICAL TVD FM LITH DESCRIPTION SUGGESTED MUD WT. All Geol. 8 5 94 9 5 MUD 1 -0PPG 10.5 Depths Gubik Unconsolidated coarse to medium Tolerance ' ° sand and small gravel with minor +:-low 600 °• a Q , , -• siltstone. Note:This is . Heavy gravel conglomerate to 1400'. a generic mud +000' E •-.:° Wood fragments throughout tem- - -weight chart. a • `'. permafrost zone. See individual well plan for 1700' •° Base permafrost specific mud weights. 2,000' C • _ _ Sagavanirktok L .. 9.2 to 9.3 . • A Predominantly clay to♦1-3000' with interbeds of sand.clays and silt- a ,.my stones with occasional shows of coal , • � around 2700'. Pebbley gravel(up to 50%)down to 2700'. 3,000' Continued interbeds of sand,clays and - - - siltstones with heavy coal sectionsinomm JD0 2800-3200. KA: 3800- K-sands 3900 f-A e C D) UGNU: Series of coarsening upward UGNU L-sands sands which are made up of: (from top MA: I-A-13) to bottom)coarse sand,fine sand,silty 4070- M-sands shale and some coal. Better developed 4140 I-A•e•C) intervening shales as you progress into memou the L and M(deeper). 4,000' hydrocarbu, - NA: Schrader Bluff Sands 4300- N-Sands Continued layered coarsening upward sands as 4600' (-A,B,C,D, above except more condensed. frussrbie E•F) hydrocarbon ring and potentially productive OA: o-sands in the"0"and 'N"sands. Tend to be water wet 4550- I p,e.c. more than a mile to the east. 4800' D.E.F) l `' - -. jimiL - ---- 1 Primarily clay with some silty sandstone Page 45 Version 1 Oct 2016 4111 Milne Point Unit B-32 II Drilling Procedure Hilcorp Energy Company 26.0 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 adjacent wells in the vicinity. 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 H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. Page 46 Version 1 Oct 2016 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. 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 H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on this pad. Page 47 Version 1 Oct 2016 0 • 11 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 27.0 Innovation Rig Layout II 170'-3'" I — I -- esm..1ev .ansa z —, - ► IIt :MEL Iv !♦II 71 II 11 IH NO ! CA o i .I i; - I N ! © cel li 1 IDw T I II© Cil 11 i i, CU I ILE I rr7 1,1 II E,`� I �Il In ci Ali Il—IIM I �� '' ICI ll--- 111111 III -,0_ cm 111-1111 4.0 i Ili -------- _,_-.11E.l= , �",� . 1 111Fri7;"--.-'7 )..i,ill 7 — !Wilt ilL• 1•ftU•U 1101111111111111111'n,usSIII!ill 113'-11 " !1■�w I (♦ 36'-1 i" — Page 48 Version 1 Oct 2016 Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 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 49 Version 1 Oct 2016 • • II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 29.0 Choke Manifold Schematic 77 ~7 II IIMJ I 7.7 `rY 1 I I I — A Ri l ;,:in ;Irl. __I_ d El 1Q z_ .,,. ,____ ,,,,, .+I h 1J b, -J ____ a a tlIfi * . : r R I v1 - 2 Vl e"5M 88209 - 2A119'5M BB209 � �. P per Ball Valves - Piper Ball Valves ��'.C," 7- 111111111 1 V b� aaT 'II Il 'I`` TLa J 1 .k_i 4 I..„1,1 t } I-4— (E3 ) ci_ . �e..e_._._,... r � I baa — I av as vv ao Page 50 Version 1 Oct 2016 • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 30.0 Casing Design Information Calculation & Casing Design Factors DATE: 10/13/2016 WELL: MPU B-32 DESIGN BY:Luke Keller Design Criteria: Hole Size 8-1/2" Mud Density: 9.5 ppg Hole Size Mud Density: Hole Size Mud Density: Drilling Mode MASP: 1508 psi(see attached MASP determination &calculation) MASP: Production Mode MASP: 1508 psi(see attached MASP determination&calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress(0.494 psi/ft)and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8' 4112" Top(MD) 0 5,600 Top(TVD) 0 4.406 Bottom (MD) 5,769 10,353 Bottom (TVD) 4,410 4,299 Length _ 5,769 4.753 Weight(ppf) 40 12.6 Grade L-80 L-80 Connection DWC/C H521 Weight w/o Bouyancy Factor(lbs) 230,760 59,884 Tension at Top of Section(lbs) 230.760 59,884 Min strength Tension (1000 lbs) 916 200 Worst Case Safety Factor(Tension) 3.97 3.34 Collapse Pressure at bottom (Psi) 2,179 2.124 Collapse Resistance w/o tension(Psi) 3,090 screen Worst Case Safety Factor(Collapse) 1.42 screen MASP(psi) 1,508 1.508 Minimum Yield (psi) 5,750 screen Worst case safety factor(Burst) 3.81 screen Page 51 Version 1 Oct 2016 • • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 31.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation fw 84/2" Hole Section 1 lcorp MPU B-32 Milne Point Unit MD TVD Planned Top: 5769 4410 Planned TD: 10352.7 4299.4 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff ND Sand I 4,410 1949 Oil/Wet 8.5 I 0.442 Offset Well Mud Densities Well MW range Top(TVD) Bottom{TVD) Date MPB-11 9.5-9.6 Surface 4,500 1985 MPB-12 9.0-9.8 Surface 4,500 1985 MPB-13 9.5-9.6 Surface 4,500 1985 MPB-14 9.1-9.4 Surface 4,500 1985 MPB-15 8.6-9.8 Surface 4,500 1985 MPB-16 8.9-9.6 Surface 4,500 1985 MPB-17 8.6-9.7 Surface 4,500 1985 MPB-19 9.2-9.7 Surface 4,500 1985 MPB-21 9.3-10.1 Surface 4,500 1986 MPB-25 8.3-9.4 Surface 4,500 1997 MPB-28 9.0-9.4 Surface 4,435 2016 MPB-29 8.8-9.2 Surface 4,400 2016 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: 4410(ft)x 0.78{psi/ft)= 3439 psi 3439(psi)-[0.1(psi/ft)'4410(ft)]= 2998 psi MASP from pore pressure(complete evacuation of wellbore to gas from Schrader Bluff sand) 4410(ft)x 0.442(psi/ft)= 1949 psi 1949(psi)-0.1(psi/ft)*4410(ft)= 1508 psi Summary: 1. MASP while drilling 8-1/2"production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 52 Version 1 Oct 2016 0 • II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 32.0 Spider Plot (NAD 27) (Governmental Sections) ocri moo / 1 ' Sec 7 ADL047433 Sec 11 r 1 ADL392703 628) ' 1 r`(1;902, 1 + 1 -08 4 * r�. : B-28 Bill, s , / / 1 / Q� a;lIPO MP13/;_ BM ♦i • !P B. niPcoe Sec 14ec • • Sec 13 S(630)8 ,�/"F'• - ♦". ♦ .-"J+ .«.n ♦ + ,I, '•{ MPen.t. 1 ,b .v...A .".MP8-18:` ♦ I p e. "PC u MILNE POINT UNIT U013N010E ` : �`/ ,iU013N011E ✓1 y\11'13 12 SIll. ADL04•7,437 \1143 __ "l 1'l l l ,"•: _ -- 4 �_/''+ w'AD�L047438 --_ .°" "MP6'23 - -- - // I 1 * `\ 2- .IPE / , 4 \\\ li A 1 ,' /+Mk — 4 ligr44 4 v\ 1r Sec.19 , . i ,' o f 1APCFP-02 (633) , \ (r�X#R/ , r solei , , I �,�n V Y * ,Y, f / -y' l MP8-15 / ,. z "..- _..- _.._ L'.r1.A 1 - - L1PB'4 ♦•♦♦ I MP8-21P8•I� • Legend s .,‘ • , //e' �:MPB- MPB-32 SHL Other Surface Holes(SHL) \♦ \��` + /MPB-2z�- '"' __ AA4 MP`22A '�7� Y MPB•32_TPH ' Other Bottom Holes(BHL) ___m_P4-3.2-; =: s - r 3 Other Well Paths 25 MP8 22AP6�MPE2\A _`;=_ AD..028231 ( 3) + MPB-32_BHL Q 'E t5' II 1 ♦•.. �z Oil and Gas Unit Boundary Pad Footprint 1 1 �� _ I , 11 Milne Point Unit " "''"''tit MPB-32 Well 0 1,000 2,000 Map Dot*10/13/201a momo Feet Page 53 Version 1 Oct 2016 • • Milne Point Unit B-32 II Drilling Procedure Hilcorp Energy Compny 33.0 Surface Plat (As Built) (NAD 27) -I /s 2800-}- T. 1 `° - 1a,, f 13 td t'l 9-PAD 0. 2O• D .21 _.. A"UPIID►�Cr t'� 186 •ija A-PAD - - Be •I2 .�•,1d r�. 2 r 24 19 I 7• •14 1 110 •13 TO GRAVEL SITE ,,.0 '�''• Y ff (`'- IA.. '', ;,t\E-PAD 1a _ 230 A1 25 t 30 �. 38; •2z VICINITY MAP `8-32 USA N.T.S. ii LEGEND:.■3 f SEC I8� sit18 ' -AS.•BUILT CONDUCTOR 281• :r °. — • EBSTTNG CONDUCTOR W O ___.._..............._. _...,_. +N 1000 `rte Q� '•qS,�/ • • / B-PAD te . f/ ` -�isrro. o • i r.•.) thy F. Barnhart 3= ' 10200 NOTES: 1. ALASKA STATE PLANE COORDINATES ARE ZONE 4 NA027. SURVEYOR'S CERTIFICATE 2. GEODETIC COOROINATES ARE NAD27. I HEREBY CERTIFY NAT I AM 3. HORIZONTAL AND VERTICAL CONTROL ARE BASED ON MP B-PAD PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN OPERATOR MONUMENTS 8-1 AND 8-2. THE STATE OF ALASKA AND THAT 4. ELEVATIONS ARE MP 8-PAD DATUM, MEAN SEA LEVEL(M.S.I.). THIS AS-81ALT REPRESENTS A SURVEY MADE BY ME OR UNOER MY DIRECT 5. MEAN PAL) SCALE FACTOR IS: 0.999905887 SUPERN80N AND THAT ALL 6. DATE OF SURVEY: SEPTEMBER 27-28, 2016. DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF SEPTEMBER 28, 2016. 7. REFERENCE FIELD BOOK: HC16-03,PGS. 24-33. LOCATED WITHIN PROTRACTED SEC. 18. T. 13 N., R. 11 E.. UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC TOP OF SECTION BASE FLANGE NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D.DD) CELLAR BOX OFFSETS ELEVATION 8-32 Y-6,023,179.57 N 1,529.38 70'28'25.010" 70.4736138' 22 9' 56' FSL NA X= 571,970.48 E 599.96 149'24'43.701" 149.4121393' 4,321' FEL u,« KLEN TO �""`� Hilcorp Alaska ' wlt AS-BUILT POINT 8-PAD MT. CONDUCTOR LOCATION 1100.131/1&1111.1131ra.salMAna .4 .N :jizeiN:1100*m--/3toPel"021 ,•-wy WELL 8--32 1 a 1 Ii, Mi 01.903+ l+OR. Page 54 Version 1 Oct 2016 • II II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 34.0 Offset MW vs TVD Chart 0 -6-21 (1986) -6-25 (1997) =6 12 (1985) 1000 1 �� -B-11 (1985) 1 -8-15 (1985) B-14(1985) 2000 B-13 (1985) -B-17(1985) B-19 (1985) 3000 I -,B-16 (1985) V '4\ ! p4000 . \ illIC\4;'1 , 5000 % r 6000 \\\H1111111111kii:I\I41IIIIIIiiiik‘lkkS ! 141 \ $141,0v 7000 pp L'k, 8000 -- 8.0 9.0 10.0 11.0 12.0 Mud Weight (PPG) Page 55 Version 1 Oct 2016 • • II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company 35.0 Drill Pipe Information 5" 19.5# S-135 DS-50 Drill Pipe Configuration Pipe Body ODn,5.000 80?:6 Inspection Class ] Pipe Body Wall Thickness I n:05.362 Pipe Body Grade Drill Pipe Length Nominal Weight Designation 19 50 5-135 Drill Pipe Approximate Length - 31.5 Rangel SrnoothEdge Height 'm13132 Raised Connection GPDS50 Tool Joint SPAYS 120.000 Tool Joint CD Tool Joint ID 6.625 Upset Type IEU n,3.250 Max Upset OD (DTE) dr,5.125 Pin Tong 9 Friction Factor ]1.@ Box T=rg n,12 Ncce Torg sc]Ce m.�y nciI.4-narcraclro Drill Pipe Performance Drill-Pipe Length Rangel 1 Best Estimates Nominal 1 Performance of Drill Pipe with Pipe Body at q M„_,;,,_43105 w4',Coaling I ilea::accurate i 80%Ins action Class ,vogo.,+ate-.p P Operational Max Tensio^ Drill Pipe Adjusted Weight olbs,'nI 24.11 23.29 TOr61e trt4bsd Torque m-nt. bo Fluid Disi'acement wt'nt 0.37 0.36 Tension Only Q 560.800 Fluid Displacement eblartu 0.0085 rsaxkm� MUT 43,100 Fluidaaettr 0.71 0.70 0.72 cnndnee�wr%rq 39.600 410,500 Capacity Fluid Capacity abl:ll)0.0169 0.0167 0.0172 38,100 Tension Only 0 560,800 Mlrarnum h,UT y 32.100 467+400 Drift Size ,Ir 3.125 c«ndrred I.wanu Nate:ON Ile barrel equals 42 U8 galienss. Note Orli ppe assembly valJr are best estimates and may vary doe to ppe body Chill toCr r+Ce.IMenvl Nash.000109 3011 other railkws. Connection Performance GPDS50 ( 6.625 OD X 3.250 i° ID ) 120,000 050 Aople4 rtpke.44 Teruo'at Sw.401., Te,,I_^a�c o oec:or Tool Joint Dimensions To•U.+a Scaar:-:•.or Yeld rt-or. ttb�st (Irsi Balanced 00 ur.,6.435 9 Maximum Make-up Torque 43,100 Tensile Limited 1,046,900 Rants„Tool Joni oo rar API 5.930 Minimum Make-up Torque 36,100 1202.500 1,250.000 Premium Cerro gni 00 - Note The rraxl'nom make-40 war,should he=Wed*hen cassette R<Inm�rn 1001 JinnifOr 5.93 Note To max Pn.-te canned.,.».rarycral tensle a NUT 1741-37,3(N]tirtJhsj should be appfle11. ,!I Tool Joint Torsional Strength mai.) 71,800 Tool Joint Tensile Strength bri 1.250,000 va4rAerthare ;Ir: Elevator Shoulder Information Elevator OD 3132 Raised 6.812 r,a; El SmoothEdge Height Nominal Tool Joint Worn to Bevel Worn to Min TJ OD for 3132 Raised OD Diameter API Premium Class Box OD Ir.,6.812 6.625 _6.063 5.930 Elevator Capacity it,,1,658,000 1,440200 823.600 685,600 . +, 5219 I NOW Ele0alc,capanty based on assumed elevaw0 8000+no,Maar Gxlor,and contact stress of t 10.10001 Assumed Elevator Bore Diameter Note-A rafted.+avatar OO Increases elevator capadty'0000011 affecting rnake-up torque. Pipe Body Slip Crushing Capacity Pipe Body Configuration( 5 t.,, OD 0.362,,, Wall S-135) Nominal 80%Inspection Class API Premium Class r� [slip Crushing Capacity[ tet!498.300 396.500 396,500 �l! true_sip Crasnm 001l0 rn• +rne load it cNkn M cu3045 to 4 ir-Renw evuatla+Porn V.Mr Coes Ent°1e Assumed Slip Length nJ 16-5 Fal m d•e sip Arca'Anda CA.1979 sx Meng lengrt an . 13 d bans...bud 0,shoart a,dis tr reference Transverse Load Factor 1K 4.2 r arty SI P o n;saen.rderl40'00010 deign and card bar.corelclent of Mann loading conanarrs.time In ps L r011 Nal.4•L`101•J11-rrer•01100 C1^691 man lite 510IrS41aC.Kr roe mono-0 rrn•-nal if Pine Body Performance Pipe Body Confguration( 5,o, OD 0.362 on) Wall S-135) Nominal 80 Inspection Class API Premium Class Pipe Tensile Strength oil 712,100 560.800 560,800 P Pipe Torsioral Strengthrt 74.100 58.100 58.100 • TJiPipeBody Torsional Ratio 0.97 1.24 t24 80%Pipe Torsional Strength fl_it-,,,59 300 46.500 46.500 Burst pro,17,1@5 15.638 15,638 Nue:Nu11014 Hurst j Collapse (1oIl 15.672 10.029 10,029camulaled at 07 Y.a ROW I per API. I Pipe OD tear 5.000 4.855 4.855 Wall Thickness lir)0.362 ,,0.290 0290 Nominal Pipe ID till 4276 4.276 4.276 Cross Sectional Area of Pipe Body tM^xl 5275 4.154 4.154 Cross Sectional Area of OD tn•zi,19.635 18.514 18.514 Cross Sectional Area of ID pa021 14.360 14.360 14.360 Section Modulus can)5. 4.476 4.476 glahPolar Section Modulusulus ,r,^31 11.41.41 5 8-953 8.953 Page 56 Version 1 Oct 2016 • • Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company • • • • Operational Limits of Drill Pipe1 Connection GPDS50 Tool Joint 00 ,,16.625 Tool Joint ID „n,3.250 Tc.i Joint Specified Minimum 120,000 Yield Strength iPsii Pipe Body %Inspection Class Pipe Body OD ,,.,, 5 wall Thickness „r„0.362 Pipe Body Grade S-135 Combined Loading for Drill Pipe at Combined Loading for Drill Pipe at Maximum Make-up Torque= 43,100 In.io Minimum Make-up Torque= 36.100 b: Operational Assembly Pipe Body connection Mao Operations Assembly F'iae Bray c,r-,ccaon i Torque Max Tension Tension I Torque Max Tension !aa.Terrwn Max Tension q Max Tension ie-1001 lbs: (len, ilea: f1Jbni +lbnI {Ids 0:•51 0 560,800 560,800 1.046.900 0 560.800 560.800 1202.50: 2,100 560.400 560.400 1.046.900 1,700 560.500 560.500 1,202,500 4,200 559.300 559,300 1.046.900 3.400 559.800 559.800 500 6,300 557.500 557,500 1,046,900 5.100 558.600 558.600 1.202,600 8,300 555.000 555.000 1.046.900 6.800 556.900 556.900 1.202.500 10,400 551.700 551,700 1.046.900 8.400 554.900 554.900 1,202.500 547,600 1.046.900 10.100 552.200 552.200 1.202.500 12,500 547,600 , 14,600 542.800 542,800 1,046.900 11.800 549.100 549.100 1.202,504 16.700 537.100 537,100 1.046.900 13.500 545.400 545.400 1.202,500 18,800 530,600 530,600 1.046.900 15.200 541.200 541.000 1,202504 20,800 523.600 523,600 1.046.900 16.900 536.500 536.500 t 202.500 22,900 515,400 515,400 1.046.900 18.600 531.300 531.300 1,202,504 25.000 506.200 5016,200 1.046.900 20.300 525.400 525.400 1.202.500 27.100 496.100 496,100 1.046.900 22.000 519.000 519.000 1.202.500 29,200 484.800 484,800 1.046.900 23.700 512.000 522,000 1.202.500 31,300 472.500 472.500 1,046.900 25.300 504.800 504.800 1.202.500 33,300 459,600 459,600 1.046.900 27.000 496.600 496.800 1.202,500 35,400 444,700 444,700 1,046.900 28.700 487.600 487,600 1,202,500 37.500 428.400 428,400 1.046.900 30.400 477.900 477.900 1.202.500 39,600 410.500 410,500 1.046.900 32.100 467.400 467.400 1.202.500 Operational drilling torque is limited by the Make-up Torque. Operational drilling torque is limited by the Make-up Torque. Connection Make-up Torque Range Make-up Torque Connection Max ,i_r,s,Tension ,r., Min MUT 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 Max MUT 43,100 1,046,900 Page 57 Version 1 Oct 2016 • . II Milne Point Unit B-32 Drilling Procedure Hilcorp Energy Company Connection Wear Table Connection GPDS50 Tool joint 00 ,,,16.6625 Tool Joint ID ,,,,;l3250 Tool Joint Specified Minimum 120.000 Yield Strength (P'il, Connection Wear TOOT eonnectton Max Connection Max Min MUT Connection Max BOO Joint OD Torsional MUT Tension Tension Strength frt,bsi tet-16.:> Mrs; M-Ms) b.r IIT, 6.625 71,800 43,100 1,046,900 35,900 1,195.900 6.562 71,800 43,100 1,034,900 35.900 1208.700 6.499 71,600 43,100 1,022,600 35,900 1,222,400 6.435 71,800 43,100 1,009,800 35.900 1.237.500 6.372 71,200 42,700 1,008,100 35.600 1.245.200 6.309 68,000 40,800 1,057,300 34.000 1.207.700 6.246 64,800 38,900 1,104,800 32,400 1.169.800 6.183 61,700 37,000 1,150,400 30.800 1.131.300 lill! 6.12 58,600 35,200 1,190,900 29,300 1.096,100 `- 6.056 55,500 33,300 1,232,300 27,800 1.060.800 Worn 00 5.993 52,600 31,500 1,227,200 26.300 1.024.600 5.93 49,600 29,800 1,187,100 24.800 987.900 Pipe Body Combined Loading Table(Torque-Tension) Pipe Body 80%Inspection Class Pipe Body OD .1vl5 Wall Thickness ,;n;0.362 Pipe Body Grade IS-135 Pipe Body Torque 0 5,300 10.600 15.800 21.100 26.400 31.700 37.000 42.300 47.500 52.800 58.100 1 :..bsi 1 1 Pipe Body Max Tension 560,800 558.400 551.300 539600 522.500 499.600 470.000 432.400 384.500 323,100 234.300 12200 n Page 58 Version 1 Oct 2016 411/ Hilcorp Energy Company Milne Point M Pt B Pad Plan: MPB-32 Prod MPB-32 NC Prod Plan: MPB-32 wp02 Standard Proposal Report 13 October, 2016 HALLIBURTON Sperry Drilling Services • III HALLIBURTONREFERENCE INFORMATION WELL DETAILS:Plan:MPB-32 Prod I Ii Ic�rh Co-ordinate(WE)Reference:Well Plan:MPB-32 Prod,True North Ground Level: 22.90 ON/-S +E/-W No Ve tical(TVD)Reference:As.-Built Plan 49.40usR(Innovation) rthing Easting Latittude Longitude Sperry Drilling _ Measured Depth Reference:As-Built Plan @ 49.40usf(Innovation) 0.00 0.00 6023179.57 571970.48 70°28'25.010 N 149°24'43.701 W Calculation Method Minimum Curvature Project: Milne Point Hilcorp Energy Company Site: M Pt B Pad Calculation Method:Minimum Curvature SECTION DETAILS Well: Plan:MPB-32 Prod Error System:ISCWSA Sec MD Inc Azi ND «N/-S +E/-W Dieu TFace VSect Target Annotation Wellbore: MPB-32 NC Prod Scan Method:Closest Approach 3D 9 Error Surface:Elliptical Conic 1 26.50 0.00 0.00 28.50 0.00 0.00 0.00 0.00 0.00 Design: MPB-32 wp02 Warning Method:Error Ratio 2 264.00 0.00 0.00 264.00 0.00 0.00 0.00 0.00 0.00 Start Dir 31100':264'MD,2647VD 3 464.00 6.00 245.00 46363 -4.42 -9.48 3.00 245.00 6.86 Start Dir 51100':464'MD,463.63TVD - 4 971.80 31.38 245.00 940.55 -72.80 -155.70 5.00 0.00 112.71 End Dir:971.6'MD,940.55'ND 5 2700.00 31.38 245.00 2416.14 -452.96 -971.37 0.00 0.00 703.16 Start Dir 51100':2700'MD,2416.14TVD DDI= 6.440 6 2798.78 31.38 254.49 2500.52 -470.72 -1019.50 5.00 94.01 739.90 End Dir:2798.78'MD,2500.52'ND •1875- 7 4174.34 31.38 254.49 3674.84 -662.25 -1709.78 0.00 0.00 1292.59 Start Dir 5°/100':4174.34'MD,3674.847VC - 8 5601.42 88.00 310.64 4405.91 -241.29 -2746.54 5.00 61.16 2410.95 End Dir:5601.42'MD,4405.91'TVD 9 5701.42 88.00 310.64 4409.40 -176.20 -2822.38 0.00 0.00 2506.70 NC heel Start Dir 51100':5701.42'MD,4409.4'TVD - 10 5769.02 91.38 310.64 4409.77 -132.19 -2873.67 5.00 0.00 2571.46 End Dir:5769.02'MD,4409.77'TVD 11 10352.70 91.38 310.64 4299.40 2852.24 6350.90 0.00 0.00 6961.94 BHL NC Toe Total Depth:10352.7'MD,4299.4'ND -1250- - CASING DETAILS SURVEY PROGRAM TVD MD Name Size Date:2016-05-19T00:00:00 Validated:Yes Version: 4409.40 5701.42 9 5/8" 9-5/8 -625- 4299.40 10352.70 41/2' 4-1/2 Depth From Depth To Survey/Plan Tool 28.50 5701.00 MPB-32 wp02 MWD+IFRI+MS+sag "(� 5701.00 10352.70 MPB-32 wp02 MWD*IFR2«MS+sag 0 - . 264 I' •.264.'61 0- 0113 i1p0 46365 -_"Sta •h6A 5O. FORMATION TOP DETAILS - 600 --Stall D\fS"j1p0 �D 715DPao NDeaPath 2.0 1701054 Base Permafrost 625- 94065 2606.40 2557.00 2922.81 SV1 - •_ • •y11.6 MDQ 3899.40 3850.00 4449.72 Ugnu LA3 o - 1� E1,d 011 0 M 0416;(4' 4216.40 4167.00 4934.95 Ugnu MD2 N - j0() D' 4385.40 433600 5411.78 Schrader NA L 1250- 150p S��Dt1000, 1409.40 4360.00 5701.42 Schrader NC C1875-_ Base Permafrost0000 E71d D\t.•0'196�8 MD a co 2500- 0 sop0 41143N tAll j4��0 sw g��- pN 5 110 ', 3125_ S5p0 5601',42 MD,4405' SI 5101' p1 p2 op, 4409 4�D - he.., end Daa5°j1� 1T1VD D 3750- Ugnu LA3 AypO 5160 071 a169.02. 169 02 ppD,4409 10352��otoz99-4 4 -• o .grad totalOeP�. _ Ugnu MD2 ,g o, ,-- MPB-32 wp02 4375 -Schrader NA- - - _ - _ - _ - -;----1 - - .:- .: _ - - - - is 0 ua o o - o ate-; .._ - Sohrader NC - o 0 o 8 o 0 0 g ca 9 5/8" 4 1/2" • 5000- NC heel BHL NC Toe I I I I l I I I , l F I I I l I I I I I I I I , l I . I I ' F I I I I I I I I I I I I I I , , , , l I I I I I : , I I l F: - IIIIIIIIIIII , 1 1 1 1 1IIIIIIIIIIIIII , , -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 Vertical Section at 294.00°(1500 usft/in) • HALLIBURTON Project: Milne Point COMPANY DETAILS:Hilcore Energy Company WELL DETAILS:Plan:MPB-32 Pmd I lileorp Site: M Pt B Pad Calculation Method:Minimum Curvature Ground Levet 22.90 Sperry Orlpine f� Well: Plan:MPB-32 Prod Error System:ISCWSA AN/-S +0/-W Northing Fasting LatSude Longitude Wellbore: MPB-32 NC Prod Scan Method:Closest Approach 3D 0.00 0.00 6023179.57 571970.48 70.28'25.010 N 149°24'43.701(N Error Surface:Elliptical Conic 4050— Plan: MPB-32 wp02 Warning Method.Error Ratio REFERENCE INFORMATION Coordinate(N/E)Reference:Well Plan:MPS-32 Prod,True North Vertical(TVD)Reference:As-Built Plan @ 40.00.n(Innovation) Measured Depth Reference:As-Buie Plan®49.40usf1(Innovation) 3600— Calculation Medved:Minimum Curvature SURVEY PROGRAM MPB32 wp02 Date:2016-05-19T00:00:00 Validated:Yes Version: 3150— _ I r _BHL NC Toel Depth From Depot TO SurvMPB-32 lan Tool W 28.50 5701.00 MPB-32 wp02 MWD+IFRI+MS+sag 5701.00 10352.70 MPB-32 wp02 MWD+IFR2+MS+sag 2700— 412" CASING DETAILS 2.230— TVD TVDSS MD Size Name 4409.40 4360.00 5701.42 9-5/8 9 5/8" 4299.40 4250.00 10352.70 4-1/2 4 1/2" - Total Depth:10352.7 MD,4299.4'TVD 1800— a I 8 1350— 0 900— 0 cm 450— INCheelI i1 A=, 0— 9515" Uo$\, Start Du 31100':264'MD,264TVD End Dir 5769.02'MD,4409.77 TVD -- -,- g q o 430— b N $ - $ Start Dir 5°/100':464'MD,463.63'WD - Start Dir 51100' 5701.42'MD,4409.4'TVD - End Dir:5601.42'MD,4405.91'TVD - o End Dir:971.6'MD,940.55'TVD -900— -- Start Dir 50100':4174.34'MD,3674.84'VD - End Du:2798.78'MD,2500.52'TVD -1350— Start Dir 51100:2700'MD,2416.14TVD -1800— -6750 -6300 -5850 -5400 -4950 -4500 -4050 -3600 -3150 -2700 -2250 -1800 -1350 -900 -450 0 430 900 1350 West(-)Bast(+)(900 usft/in) • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-32 Prod Company: Hilcorp Energy Company TVD Reference: As-Built Plan @ 49.40usft(Innovation) Project: Milne Point MD Reference: As-Built Plan @ 49.40usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-32 Prod Survey Calculation Method: Minimum Curvature Wellbore: MPB-32 NC Prod Design: MPB-32 wp02 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 B Pad,TR-13-11 Site Position: Northing: 6,021,548.49 usft Latitude: 70°28'8.986 N From: Map Easting: 571,775.55 usft Longitude: 149°24'49.895 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.55 ° Well Plan:MPB-32 Prod Well Position +NI-S 0.00 usft Northing: 6,023,179.57 usft Latitude: 70°28'25.010 N +El-W 0.00 usft Easting: 571,970.48 usft Longitude: 149°24'43.701 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 22.90 usft 1 Wellbore MPB-32 NC Prod Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 5/19/2016 18.34 81.07 57,570 Design MPB-32 wp02 Audit Notes: Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.50 0.00 0.00 294.00 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +NIS +El-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°1100usft) (°/100usft) (°/100usft) (°) 26.50 0.00 0.00 26.50 -22.90 0.00 0.00 0.00 0.00 0.00 0.00 264.00 0.00 0.00 264.00 214.60 0.00 0.00 0.00 0.00 0.00 0.00 464.00 6.00 245.00 463.63 414.23 -4.42 -9.48 3.00 3.00 0.00 245.00 971.60 31.38 245.00 940.55 891.15 -72.60 -155.70 5.00 5.00 0.00 0.00 2,700.00 31.38 245.00 2,416.14 2,366.74 -452.96 -971.37 0.00 0.00 0.00 0.00 2,798.78 31.38 254.49 2,500.52 2,451.12 -470.72 -1,019.50 5.00 0.00 9.61 94.01 4,174.34 31.38 254.49 3,674.84 3,625.44 -662.25 -1,709.76 0.00 0.00 0.00 0.00 5,601.42 88.00 310.64 4,405.91 4,356.51 -241.29 -2,746.54 5.00 3.97 3.93 61.16 5,701.42 88.00 310.64 4,409.40 4,360.00 -176.20 -2,822.38 0.00 0.00 0.00 0.00 5,769.02 91.38 310.64 4,409.77 4,360.37 -132.19 -2,873.67 5.00 5.00 0.00 0.00 10,352.70 91.38 310.64 4,299.40 4,250.00 2,852.24 -6,350.90 0.00 0.00 0.00 0.00 10/13/2016 1:35:27PM Page 2 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-32 Prod Company: Hilcorp Energy Company TVD Reference: As-Built Plan @ 49.40usft(Innovation) Project: Milne Point MD Reference: As-Built Plan @ 49.40usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-32 Prod Survey Calculation Method: Minimum Curvature Wellbore: MPB-32 NC Prod Design: MPB-32 wp02 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +EJ-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -22.90 26.50 0.00 0.00 26.50 -22.90 0.00 0.00 6,023,179.57 571,970.48 0.00 0.00 100.00 0.00 0.00 100.00 50.60 0.00 0.00 6,023,179.57 571,970.48 0.00 0.00 200.00 0.00 0.00 200.00 150.60 0.00 0.00 6,023,179.57 571,970.48 0.00 0.00 264.00 0.00 0.00 264.00 214.60 0.00 0.00 6,023,179.57 571,970.48 0.00 0.00 Start Dir 3°1100':264'MD,264'TVD 300.00 1.08 245.00 300.00 250.60 -0.14 -0.31 6,023,179.42 571,970.17 3.00 0.22 400.00 4.08 245.00 399.89 350.49 -2.05 -4.39 6,023,177.48 571,966.11 3.00 3.18 464.00 6.00 245.00 463.63 414.23 -4.42 -9.48 6,023,175.06 571,961.04 3.00 6.86 Start Dir 5°/100':464'MD,463.63'TVD 500.00 7.80 245.00 499.37 449.97 -6.25 -13.40 6,023,173.19 571,957.14 5.00 9.70 600.00 12.80 245.00 597.73 548.33 -13.80 -29.60 6,023,165.48 571,941.02 5.00 21.43 700.00 17.80 245.00 694.15 644.75 -24.95 -53.51 6,023,154.10 571,917.22 5.00 38.73 800.00 22.80 245.00 787.91 738.51 -39.61 -84.94 6,023,139.15 571,885.93 5.00 61.49 900.00 27.80 245.00 878.29 828.89 -57.66 -123.66 6,023,120.72 571,847.39 5.00 89.52 971.60 31.38 245.00 940.55 891.15 -72.60 -155.70 6,023,105.47 571,815.50 5.00 112.71 End Dir :971.6'MD,940.55'TVD 1,000.00 31.38 245.00 964.79 915.39 -78.85 -169.10 6,023,099.09 571,802.16 0.00 122.41 1,100.00 31.38 245.00 1,050.16 1,000.76 -100.86 -216.29 6,023,076.63 571,755.19 0.00 156.57 1,200.00 31.38 245.00 1,135.54 1,086.14 -122.87 -263.49 6,023,054.17 571,708.22 0.00 190.73 1,300.00 31.38 245.00 1,220.91 1,171.51 -144.87 -310.68 6,023,031.71 571,661.25 0.00 224.89 1,400.00 31.38 245.00 1,306.28 1,256.88 -166.88 -357.87 6,023,009.25 571,614.27 0.00 259.06 1,500.00 31.38 245.00 1,391.66 1,342.26 -188.88 -405.06 6,022,986.80 571,567.30 0.00 293.22 1,600.00 31.38 245.00 1,477.03 1,427.63 -210.89 -452.26 6,022,964.34 571,520.33 0.00 327.38 1,700.00 31.38 245.00 1,562.40 1,513.00 -232.90 -499.45 6,022,941.88 571,473.35 0.00 361.54 1,710.54 31.38 245.00 1,571.40 1,522.00 -235.22 -504.42 6,022,939.51 571,468.40 0.00 365.14 Base Permafrost 1,800.00 31.38 245.00 1,647.78 1,598.38 -254.90 -546.64 6,022,919.42 571,426.38 0.00 395.70 1,900.00 31.38 245.00 1,733.15 1,683.75 -276.91 -593.83 6,022,896.96 571,379.41 0.00 429.87 2,000.00 31.38 245.00 1,818.52 1,769.12 -298.92 -641.03 6,022,874.50 571,332.43 0.00 464.03 2,100.00 31.38 245.00 1,903.90 1,854.50 -320.92 -688.22 6,022,852.04 571,285.46 0.00 498.19 2,200.00 31.38 245.00 1,989.27 1,939.87 -342.93 -735.41 6,022,829.58 571,238.49 0.00 532.35 2,300.00 31.38 245.00 2,074.64 2,025.24 -364.93 -782.60 6,022,807.12 571,191.51 0.00 566.51 2,400.00 31.38 245.00 2,160.02 2,110.62 -386.94 -829.80 6,022,784.66 571,144.54 0.00 600.67 2,500.00 31.38 245.00 2,245.39 2,195.99 -408.95 -876.99 6,022,762.20 571,097.57 0.00 634.84 2,600.00 31.38 245.00 2,330.76 2,281.36 -430.95 -924.18 6,022,739.74 571,050.60 0.00 669.00 2,700.00 31.38 245.00 2,416.14 2,366.74 -452.96 -971.37 6,022,717.28 571,003.62 0.00 703.16 Start Dir 5°/100':2700'MD,2416.14'TVD 2,798.78 31.38 254.49 2,500.52 2,451.12 -470.72 -1,019.50 6,022,699.06 570,955.68 5.00 739.90 End Dir :2798.78'MD,2500.52'TVD 2,800.00 31.38 254.49 2,501.56 2,452.16 -470.89 -1,020.11 6,022,698.89 570,955.07 0.00 740.39 2,900.00 31.38 254.49 2,586.93 2,537.53 -484.81 -1,070.29 6,022,684.48 570,905.03 0.00 780.57 2,922.81 31.38 254.49 2,606.40 2,557.00 -487.99 -1,081.73 6,022,681.19 570,893.62 0.00 789.73 SV1 3,000.00 31.38 254.49 2,672.30 2,622.90 -498.73 -1,120.47 6,022,670.07 570,854.99 0.00 820.75 3,100.00 31.38 254.49 2,757.67 2,708.27 -512.66 -1,170.65 6,022,655.67 570,804.95 0.00 860.93 10/13/2016 1:35:27PM Page 3 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-32 Prod Company: Hilcorp Energy Company TVD Reference: As-Built Plan @ 49.40usft(Innovation) Project: Milne Point MD Reference: As-Built Plan @ 49.40usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-32 Prod Survey Calculation Method: Minimum Curvature Wellbore: MPB-32 NC Prod Design: MPB-32 wp02 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +W-S +E/-W Northing Easting DLS Vert Section (usft) (°) (') (usft) usft (usft) (usft) (usft) (usft) 2,793.64 3,200.00 31.38 254.49 2,843.04 2,793.64 -526.58 -1,220.83 6,022,641.26 570,754.91 0.00 901.11 3,300.00 31.38 254.49 2,928.41 2,879.01 -540.50 -1,271.01 6,022,626.85 570,704.87 0.00 941.29 3,400.00 31.38 254.49 3,013.78 2,964.38 -554.43 -1,321.19 6,022,612.45 570,654.83 0.00 981.46 3,500.00 31.38 254.49 3,099.15 3,049.75 -568.35 -1,371.37 6,022,598.04 570,604.79 0.00 1,021.64 3,600.00 31.38 254.49 3,184.52 3,135.12 -582.28 -1,421.56 6,022,583.63 570,554.76 0.00 1,061.82 3,700.00 31.38 254.49 3,269.89 3,220.49 -596.20 -1,471.74 6,022,569.22 570,504.72 0.00 1,102.00 3,800.00 31.38 254.49 3,355.26 3,305.86 -610.12 -1,521.92 6,022,554.82 570,454.68 0.00 1,142.18 3,900.00 31.38 254.49 3,440.63 3,391.23 -624.05 -1,572.10 6,022,540.41 570,404.64 0.00 1,182.36 4,000.00 31.38 254.49 3,526.00 3,476.60 -637.97 -1,622.28 6,022,526.00 570,354.60 0.00 1,222.54 4,100.00 31.38 254.49 3,611.37 3,561.97 -651.89 -1,672.46 6,022,511.60 570,304.56 0.00 1,262.72 4,174.34 31.38 254.49 3,674.83 3,625.43 -662.25 -1,709.76 6,022,500.89 570,267.36 0.00 1,292.59 Start Dir 5°1100':4174.34'MD,3674.84'TVD 4,200.00 32.02 256.61 3,696.67 3,647.27 -665.61 -1,722.82 6,022,497.40 570,254.34 5.00 1,303.15 4,300.00 34.81 264.16 3,780.17 3,730.77 -674.66 -1,777.04 6,022,487.83 570,200.22 5.00 1,349.00 4,400.00 38.00 270.66 3,860.67 3,811.27 -677.21 -1,836.25 6,022,484.70 570,141.04 5.00 1,402.05 4,449.72 39.70 273.54 3,899.40 3,850.00 -676.05 -1,867.41 6,022,485.56 570,109.87 5.00 1,430.99 Ugnu LA3 4,500.00 41.49 276.25 3,937.57 3,888.17 -673.25 -1,900.00 6,022,488.05 570,077.26 5.00 1,461.90 4,600.00 45.23 281.10 4,010.29 3,960.89 -662.80 -1,967.80 6,022,497.83 570,009.36 5.00 1,528.09 4,700.00 49.14 285.34 4,078.25 4,028.85 -645.95 -2,039.15 6,022,513.99 569,937.87 5.00 1,600.12 4,800.00 53.19 289.11 4,140.96 4,091.56 -622.82 -2,113.49 6,022,536.40 569,863.31 5.00 1,677.44 4,900.00 57.35 292.49 4,197.93 4,148.53 -593.60 -2,190.26 6,022,564.88 569,786.27 5.00 1,759.47 4,934.95 58.82 293.60 4,216.40 4,167.00 -581.98 -2,217.56 6,022,576.23 569,758.86 5.00 1,789.13 Ugnu MD2 5,000.00 61.59 295.57 4,248.72 4,199.32 -558.49 -2,268.88 6,022,599.22 569,707.32 5.00 1,845.57 5,100.00 65.90 298.41 4,292.96 4,243.56 -517.77 -2,348.75 6,022,639.16 569,627.07 5.00 1,935.09 5,200.00 70.25 301.06 4,330.30 4,280.90 -471.75 -2,429.26 6,022,684.39 569,546.13 5.00 2,027.36 5,300.00 74.64 303.57 4,360.46 4,311.06 -420.78 -2,509.79 6,022,734.58 569,465.11 5.00 2,121.66 5,400.00 79.06 305.98 4,383.22 4,333.82 -365.25 -2,589.74 6,022,789.33 569,384.63 5.00 2,217.29 5,411.78 79.58 306.25 4,385.40 4,336.00 -358.43 -2,599.10 6,022,796.06 569,375.21 5.00 2,228.61 Schrader NA 5,500.00 83.49 308.31 4,398.39 4,348.99 -305.58 -2,668.50 6,022,848.23 569,305.31 5.00 2,313.51 5,600.00 87.94 310.61 4,405.86 4,356.46 -242.22 -2,745.47 6,022,910.84 569,227.74 5.00 2,409.59 5,601.42 88.00 310.64 4,405.91 4,356.51 -241.30 -2,746.54 6,022,911.75 569,226.66 5.00 2,410.95 End Dir :5601.42'MD,4405.91'TVD 5,700.00 88.00 310.64 4,409.35 4,359.95 -177.13 -2,821.30 6,022,975.18 569,151.29 0.00 2,505.34 5,701.42 88.00 310.64 4,409.40 4,360.00 -176.21 -2,822.38 6,022,976.10 569,150.20 0.00 2,506.70 Start Dir 5°1100':5701.42'MD,4409.4'TVD-Schrader NC-9 518" 5,769.02 91.38 310.64 4,409.77 4,360.37 -132.19 -2,873.67 6,023,019.62 569,098.50 5.00 2,571.46 End Dir :5769.02'MD,4409.77'TVD 5,800.00 91.38 310.64 4,409.02 4,359.62 -112.02 -2,897.17 6,023,039.56 569,074.80 0.00 2,601.14 5,900.00 91.38 310.64 4,406.61 4,357.21 -46.91 -2,973.03 6,023,103.92 568,998.32 0.00 2,696.92 6,000.00 91.38 310.64 4,404.20 4,354.80 18.20 -3,048.89 6,023,168.29 568,921.84 0.00 2,792.71 6,100.00 91.38 310.64 4,401.80 4,352.40 83.31 -3,124.75 6,023,232.66 568,845.36 0.00 2,888.49 6,200.00 91.38 310.64 4,399.39 4,349.99 148.42 -3,200.61 6,023,297.03 568,768.88 0.00 2,984.28 10/13/2016 1:35:27PM Page 4 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference; Well Plan:MPB-32 Prod Company: Hilcorp Energy Company TVD Reference: As-Built Plan @ 49.40usft(Innovation) Project: Milne Point MD Reference: As-Built Plan @ 49.40usft(Innovation) Site: M Pt B Pad North Reference: ` -;r„•,r" True Well: Plan:MPB-32 Prod Survey Calculation Method: Minimum Curvature Wellbore: MPB-32 NC Prod Design: MPB-32 wp02 + k o 41 xu^_ Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/S +EI-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 4,347.58 6,300.00 91.38 310.64 4,396.98 4,347.58 213.53 -3,276.48 6,023,361.39 568,692.40 0.00 3,080.06 6,400.00 91.38 310.64 4,394.57 4,345.17 278.64 -3,352.34 6,023,425.76 568,615.92 0.00 3,175.85 6,500.00 91.38 310.64 4,392.17 4,342.77 343.75 -3,428.20 6,023,490.13 568,539.44 0.00 3,271.63 6,600.00 91.38 310.64 4,389.76 4,340.36 408.86 -3,504.06 6,023,554.49 568,462.96 0.00 3,367.42 6,700.00 91.38 310.64 4,387.35 4,337.95 473.97 -3,579.92 6,023,618.86 568,386.48 0.00 3,463.20 6,800.00 91.38 310.64 4,384.94 4,335.54 539.08 -3,655.78 6,023,683.23 568,310.00 0.00 3,558.99 6,900.00 91.38 310.64 4,382.53 4,333.13 604.19 -3,731.64 6,023,747.60 568,233.52 0.00 3,654.77 7,000.00 91.38 310.64 4,380.13 4,330.73 669.30 -3,807.50 6,023,811.96 568,157.04 0.00 3,750.56 7,100.00 91.38 310.64 4,377.72 4,328.32 734.41 -3,883.36 6,023,876.33 568,080.56 0.00 3,846.34 7,200.00 91.38 310.64 4,375.31 4,325.91 799.52 -3,959.23 6,023,940.70 568,004.08 0.00 3,942.13 7,300.00 91.38 310.64 4,372.90 4,323.50 864.63 -4,035.09 6,024,005.06 567,927.60 0.00 4,037.91 7,400.00 91.38 310.64 4,370.50 4,321.10 929.74 -4,110.95 6,024,069.43 567,851.12 0.00 4,133.70 7,500.00 91.38 310.64 4,368.09 4,318.69 994.85 -4,186.81 6,024,133.80 567,774.64 0.00 4,229.48 7,600.00 91.38 310.64 4,365.68 4,316.28 1,059.96 -4,262.67 6,024,198.17 567,698.16 0.00 4,325.27 7,700.00 91.38 310.64 4,363.27 4,313.87 1,125.07 -4,338.53 6,024,262.53 567,621.68 0.00 4,421.05 7,800.00 91.38 310.64 4,360.86 4,311.46 1,190.18 -4,414.39 6,024,326.90 567,545.20 0.00 4,516.84 7,900.00 91.38 310.64 4,358.46 4,309.06 1,255.29 -4,490.25 6,024,391.27 567,468.72 0.00 4,612.62 8,000.00 91.38 310.64 4,356.05 4,306.65 1,320.40 -4,566.11 6,024,455.64 567,392.24 0.00 4,708.41 8,100.00 91.38 310.64 4,353.64 4,304.24 1,385.51 -4,641.97 6,024,520.00 567,315.76 0.00 4,804.19 8,200.00 91.38 310.64 4,351.23 4,301.83 1,450.62 -4,717.84 6,024,584.37 567,239.28 0.00 4,899.98 8,300.00 91.38 310.64 4,348.82 4,299.42 1,515.73 -4,793.70 6,024,648.74 567,162.80 0.00 4,995.76 8,400.00 91.38 310.64 4,346.42 4,297.02 1,580.84 -4,869.56 6,024,713.10 567,086.32 0.00 5,091.55 8,500.00 91.38 310.64 4,344.01 4,294.61 1,645.95 -4,945.42 6,024,777.47 567,009.84 0.00 5,187.33 8,600.00 91.38 310.64 4,341.60 4,292.20 1,711.06 -5,021.28 6,024,841.84 566,933.36 0.00 5,283.12 8,700.00 91.38 310.64 4,339.19 4,289.79 1,776.17 -5,097.14 6,024,906.21 566,856.88 0.00 5,378.90 8,800.00 91.38 310.64 4,336.79 4,287.39 1,841.28 -5,173.00 6,024,970.57 566,780.40 0.00 5,474.69 8,900.00 91.38 310.64 4,334.38 4,284.98 1,906.39 -5,248.86 6,025,034.94 566,703.92 0.00 5,570.47 9,000.00 91.38 310.64 4,331.97 4,282.57 1,971.50 -5,324.72 6,025,099.31 566,627.44 0.00 5,666.26 9,100.00 91.38 310.64 4,329.56 4,280.16 2,036.61 -5,400.59 6,025,163.67 566,550.96 0.00 5,762.04 9,200.00 91.38 310.64 4,327.15 4,277.75 2,101.72 -5,476.45 6,025,228.04 566,474.48 0.00 5,857.83 9,300.00 91.38 310.64 4,324.75 4,275.35 2,166.83 -5,552.31 6,025,292.41 566,398.00 0.00 5,953.62 9,400.00 91.38 310.64 4,322.34 4,272.94 2,231.94 -5,628.17 6,025,356.78 566,321.52 0.00 6,049.40 9,500.00 91.38 310.64 4,319.93 4,270.53 2,297.05 -5,704.03 6,025,421.14 566,245.04 0.00 6,145.19 9,600.00 91.38 310.64 4,317.52 4,268.12 2,362.16 -5,779.89 6,025,485.51 566,168.56 0.00 6,240.97 9,700.00 91.38 310.64 4,315.12 4,265.72 2,427.27 -5,855.75 6,025,549.88 566,092.08 0.00 6,336.76 9,800.00 91.38 310.64 4,312.71 4,263.31 2,492.38 -5,931.61 6,025,614.24 566,015.60 0.00 6,432.54 9,900.00 91.38 310.64 4,310.30 4,260.90 2,557.49 -6,007.47 6,025,678.61 565,939.12 0.00 6,528.33 10,000.00 91.38 310.64 4,307.89 4,258.49 2,622.60 -6,083.34 6,025,742.98 565,862.64 0.00 6524.11 10,100.00 91.38 310.64 4,305.48 4,256.08 2,687.71 -6,159.20 6,025,807.35 565,786.16 0.00 6,719.90 10,200.00 91.38 310.64 4,303.08 4,253.68 2,752.82 -6,235.06 6,025,871.71 565,709.68 0.00 6,815.68 10,300.00 91.38 310.64 4,300.67 4,251.27 2,817.93 -6,310.92 6,025,936.08 565,633.20 0.00 6,911.47 10,352.70 91.38 310.64 4,299.40 4,250.00 2,852.24 -6,350.90 6,025,970.00 565,592.90 0.00 6,961.94 Total Depth:10352.7'MD,4299.4'TVD 10/13/2016 1:35:27PM Page 5 COMPASS 5000.1 Build 81 • • Halliburton .LL I B U RTO N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-32 Prod Company: Hilcorp Energy Company TVD Reference: As-Built Plan @ 49.40usft(Innovation) Project: Milne Point MD Reference: As-Built Plan @ 49.40usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-32 Prod Survey Calculation Method: Minimum Curvature Wellbore: MPB-32 NC Prod Design: MPB-32 wp02 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +El-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) BHL NC Toe 0.00 0.00 4,299.40 2,852.24 -6,350.90 6,025,970.00 565,592.90 -plan hits target center -Circle(radius 50.00) NC heel 0.00 0.00 4,409.40 -176.20 -2,822.38 6,022,976.10 569,150.20 -plan hits target center -Circle(radius 50.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 5,701.42 4,409.40 9 5/8" 9-5/8 12-1/4 10,352.70 4,299.40 41/2" 4-1/2 8-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (°) (°) 5,701.42 4,409.40 Schrader NC 0.00 4,449.72 3,899.40 Ugnu LA3 0.00 4,934.95 4,216.40 Ugnu MD2 0.00 2,922.81 2,606.40 SV1 0.00 5,411.78 4,385.40 Schrader NA 0.00 1,710.54 1,571.40 Base Permafrost 0.00 i_ Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 264.00 264.00 0.00 0.00 Start Dir 3°/100':264'MD,264'TVD 464.00 463.63 -4.42 -9.48 Start Dir 5°/100':464'MD,463.63'TVD 971.60 940.55 -72.60 -155.70 End Dir :971.6'MD,940.55'TVD 2,700.00 2,416.14 -452.96 -971.37 Start Dir 5°/100':2700'MD,2416.14'TVD 2,798.78 2,500.52 -470.72 -1,019.50 End Dir :2798.78'MD,2500.52'TVD 4,174.34 3,674.83 -662.25 -1,709.76 Start Dir 5°/100':4174.34'MD,3674.84'TVD 5,601.42 4,405.91 -241.30 -2,746.54 End Dir :5601.42'MD,4405.91'TVD 5,701.42 4,409.40 -176.21 -2,822.38 Start Dir 5°/100':5701.42'MD,4409.4'TVD 5,769.02 4,409.77 -132.19 -2,873.67 End Dir :5769.02'MD,4409.77'TVD 10,352.70 4,299.40 2,852.24 -6,350.90 Total Depth:10352.7'MD,4299.4'TVD 10/13/2016 1:35:27PM Page 6 COMPASS 5000.1 Build 81 1111, • Hilcorp Energy Company Milne Point M Pt B Pad Plan: MPB-32 Prod MPB-32 NC Prod MPB-32 wp02 Sperry Drilling Services Clearance Summary Anticollision Report 13 October,2016 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-32 Prod-MPB-32 NC Prod-MPB-32 wp02 Well Coordinates: 6,023,179.57 N,571,970.48 E(70°28'25.01"N,149°24'43.70"W) Datum Height: As-Built Plan @ 49.40usft(Innovation) Scan Range: 0.00 to 10,352.70 usft.Measured Depth. Scan Radius is 1,232.62 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build:81 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 ° MINIM HALLIBURTON Sperry Drilling Services • • HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DETAILS:PImc MPH-32 Prod NAD 1927(NADCON CONUS) Alaska Zone 04 Site: M Pt B Pad Coordinate(N/E)Reference:Well Plan:MPS-32 Prod.True North Ground Level: 22.90 Well: Plan:MPB-32 Prod Vertical(TVD)Reference:As-Built Plana 49.40uea(Innovation) -144/4 +6I-w Northing Pasting Latitlude Longitude Sperry Drilling Measured Depth Reference:Ae-Built Plan@ 49.40usft(Innovation) 0.00 0.00 6023179.57 571970.48 70.2625.010N 149924143.701W Wellbore: MPB-32 NC Prod Calculation Method:Minimum Curvature Plan: MPB-32 wp02 SURVEY PROGRAM GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference 26.50 To 10352.70 ri "I'(e(►r,) _ Date:2016-05-19700.00:00 Validated:Yes Version. Ladder/S.F. Plots Depth Frorn Depth To Survey/Plan Tool CASING DETAILS 26.50 5701.00 MPB-32 wp02 MWD+IFR1+MS+sag 5701.00 10352.70 MPB-32 wp02 MWD+IFR2+MS+sag TVD TVDSS MD Size Name 4409.40 4360.00 5701.42 9-5/8 9 5/8" 4299.40 4250.00 10352.70 4-1/2 4 1/2" 115000 _u _a-,41,411123 1111111 II I�111 i, 1lU 0120.00 I I 1 C 90.00 ...�.l.a.I��111111111111111! •e. I Ilm�I�IIf __ ��11III i��IIUI I 60.00ID - ""' -23j r. - MPB-O2A wpO3 8 30.00 �� B-33 w.r2 1111 ` 'I I� III IJ,, - li U 1 0.00 1111 111111111 1111 rill 1111 1111 III ] 1111 111 r I 1 1111 11111 1111 1 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 Measured Depth(1500 usft/in) ::: X11 M111 '� I 0 R r c - ,,,,,„4„, R 3.00—_. m 8Iiiik ,0 N cn i A _ Collision Avoidance Rec. \ 1.50 —No-Go Zone-Stop Drillhiy 0.00 1111 ; 1111 ` 1111 1111 1111 1111 ' 1111 1111 1111 1111 ilii 1111 1111 1111 ' 1111 1111 Illi 1111 1111 1 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 Measured Depth 0 • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-32 Prod-MPB-32 wp02 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-32 Prod-MPB-32 NC Prod-MPB-32 wp02 Scan Range: 0.00 to 10,352.70 usft.Measured Depth. Scan Radius is 1,232.62 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-Wellbore Name-Design (usft) (usft) (usft) (usft) usft M Pt B Pad MPB-02-MPB-02-MPB-02 26.50 61.09 26.50 60.29 23.10 75.984 Centre Distance Pass- MPB-02-MPB-02-MPB-02 450.00 61.67 450.00 58.07 446.12 17.098 Ellipse Separation Pass- MPB-02-MPB-02-MPB-02 625.00 7024 625.00 65.21 618.24 13.976 Clearance Factor Pass- MPB-02-Plan MPB-02A-MPB-02Awp03 481.92 59.49 481.92 57.43 478.94 28.815 Ellipse Separation Pass- MPB-02-Plan MPB-02A-MPB-02A wp03 575.00 62.99 575.00 60.62 569.28 26.544 Clearance Factor Pass- MPB-05-MPB-05-MPB-05 275.00 217.75 275.00 214.39 284.95 64.720 Ellipse Separation Pass- MPB-05-MPB-05-MPB-05 750.00 289.97 750.00 282.11 739.43 36.895 Clearance Factor Pass- MPB-05-MPB-05A-MPB-05A 275.00 217.75 275.00 214.39 284.95 64.720 Ellipse Separation Pass- MPB-05-MPB-05A-MPB-05A 750.00 289.97 750.00 282.11 739.43 36.895 Clearance Factor Pass- MPB-06-MPB-06-MPB-06 237.35 60.42 237,35 57.73 246.95 22.518 Centre Distance Pass- MPB-06-MPB-06-MPB-06 325.00 60.86 325.00 57.38 334.33 17.454 Ellipse Separation Pass- MPB-06-MPB-06-MPB-06 4,125.00 1,185.30 4,125.00 1,033.72 4,013.23 7.819 Clearance Factor Pass- MPB-07-MPB-07-MPB-07 3,883.21 277.49 3,883.21 106.26 4,100.80 1.621 Centre Distance Pass- MPB-07-MPB-07-MPB-07 3,900.00 277.61 3,900.00 106.16 4,115.11 1.619 Clearance Factor Pass- MPB-09-MPB-09-MPB-09 3,089.72 154.65 3,089.72 65.43 3,250.32 1.733 Centre Distance Pass- MPB-09-MPB-09-MPB-09 3,250.00 164.70 3,250.00 51.05 3,402.02 1.449 Ellipse Separation Pass- MPB-09-MPB-09-MPB-09 3,300.00 171.37 3,300.00 52.30 3,449.49 1.439 Clearance Factor Pass- MPB-10-MPB-10-MPB-10 90.43 180.63 90.43 179,64 100.03 183.634 Centre Distance Pass- MPB-10-MPB-10-MPB-10 275.00 181.28 275.00 179.19 283.37 86.982 Ellipse Separation Pass- MPB-10-MPB-10-MPB-10 6,425.00 947.26 6,425.00 863.77 5,609.54 11.345 Clearance Factor Pass- MPB-17-MPB-17-MPB-17 588.17 167.79 588.17 161.70 591.26 27.541 Centre Distance Pass- MPB-17-MPB-17-MPB-17 625.00 167.99 625.00 161.48 627.32 25.815 Ellipse Separation Pass- MPB-17-MPB-17-MPB-17 4,600.00 785.65 4,600.00 638.07 4,791.52 5.324 Clearance Factor Pass- I MP8-18-MPB-18-MPB-18 7,250.00 498.78 7,250.00 149.85 6,279.81 1.429 Clearance Factor Pass- MPB-18-MPB-18-MPB-18 7,275.00 492.86 7,275.00 148.53 6,294.56 1.431 Ellipse Separation Pass- MPB-18-MPB-18-MPB-18 7,458.85 472.13 7.458.85 181.84 6,412.24 1.626 Centre Distance Pass- MPB-22-MPB-22-MPB-22 250.00 215.19 250.00 212.06 259.60 68.895 Centre Distance Pass- MPB-22-MPB-22-MPB-22 275.00 215.22 275.00 211.85 284.60 63.808 Ellipse Separation Pass- 13 October,2016- 13:27 Page 2 of 6 COMPASS • w Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-32 Prod -MPB-32 wp02 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-32 Prod-MPB-32 NC Prod-MPB-32 wp02 Scan Range: 0.00 to 10,352.70 usft.Measured Depth. Scan Radius is 1,232.62 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-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPB-22-MPB-22-MPB-22 4,125.00 1,228.50 4,125.00 1,071.06 4,029.35 7.803 Clearance Factor Pass- MPB-22-MPB-22A-MPB-22A 250.00 215.19 250.00 212.06 259.60 68.895 Centre Distance Pass- MPB-22-MPB-22A-MPB-22A 275.00 215.22 275.00 211.85 284.80 63.808 Ellipse Separation Pass- MPB-22-MPB-22A-MPB-22A 4,125.00 1,228.50 4,125.00 1,071.06 4,029.35 7.803 Clearance Factor Pass- MPB-22-MPB-22APB1-MPB-22APB1 250.00 215.19 250.00 212.06 259.60 68.895 Centre Distance Pass- I MPB-22-MPB-22APB1-MPB-22APB1 275.00 215.22 275.00 211.85 284.60 63.808 Ellipse Separation Pass- MPB-22-MPB-22APB1-MPB-22APB1 4,125.00 1,228.50 4,125.00 1,071.06 4,029.35 7.803 Clearance Factor Pass- MPB-23-MPB-23-MPB-23 26.50 122.48 26.50 121.41 30.89 114.384 Centre Distance Pass- MPB-23-MPB-23-MPB-23 5,950.01 5,950.00 jan IIII r 0.805 Clearance Factor FAIL- MPB-23-MPB-23-MPB-23 iiiiiiiN511 11111111111. Ilk 5,976.00 ,, MINRIM 0.812 Ellipse Separation FAIL- MPB-25-MPB-25-MPB-25 2,400.13 101.65 2,400.13 64.67 2,485.36 2.749 Centre Distance Pass- MPB-25-MPB-25-MPB-25 2,475.00 104.72 2,475.00 60.44 2,556.43 2.365 Ellipse Separation Pass- MPB-25-MPB-25-MPB-25 2,525.00 110.26 2,525.00 62.39 2,603.68 2.303 Clearance Factor Pass- MPB-27-MPB-27-MPB-27 100.00 91.50 100.00 89.74 107.50 51.811 Centre Distance Pass- MPB-27-MPB-27-MPB-27 525.00 91.73 525.00 87.41 533.61 21.249 Ellipse Separation Pass- MPB-27-MPB-27-MPB-27 625.00 95.87 625.00 91.17 630.29 20.410 Clearance Factor Pass- MPB-26-MPB-28-MPB-28 =MI - - IIIIIIIIIM FAL• MPB-29-MPB-29-MPB-29 756.18 128.63 756.18 120.95 765.93 16.735 Centre Distance Pass- MPB-29-MPB-29-MPB-29 775.00 128.78 775.00 120.93 783.89 16.420 Ellipse Separation Pass- MPB-29-MPB-29-MPB-29 850.00 132.65 850.00 124.39 855.05 16.059 Clearance Factor Pass- Plan:MPB-33 Inj-MPB-33 NC In)-MPB-33 wp02 250.00 30.70 250.00 28.50 249.00 13.983 Centre Distance Pass- Plan:MPB-33 In)-MPB-33 NC In)-MPB-33 wp02 325.00 30.90 325.00 28.24 323.65 11.597 Ellipse Separation Pass- Plan:MP8-33 In)-MPB-33 NC In)-MPB-33 wp02 425.00 33.36 425.00 30.12 422.55 10.282 Clearance Factor Pass- 13 October,2016- 13:27 Page 3 of 6 COMPASS • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-32 Prod-MPB-32 wp02 Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 26.50 5,701.00 MPB-32wp02 MWD+IFR1+MS+sag 5,701.00 10,352.70 MPB-32 wp02 MWD+IFR2+MS+sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 13 October,2016- 13:27 Page 4 of 6 COMPASS • • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. • S TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: oC/( — /S Development _Service _Exploratory _Stratigraphic Test _Non-Conventional FIELD: M1/ALPOOL: i'I/14.. 1`rl/, scA ,EJ 3/J-- Check 3 J 1Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (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 samples 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 • 0 co , , , , , , , co O , , , , , Q) a N N sa c6 c , o c to , Q , , a i , . , to a , C , C �* 00, d y , , , o , -c , , L, as a , , , , W , O, •C, t N �, O C �� 4 E O Z' oa o, 2 a) w. O, CO C j , d,4 a LO3 0 3, , 0, w M � O `, C' >, a �� a • a CO , J. ;, tb 0' ar 0, O' a -; �, O `, y. 0 > ' a co' F- d J. v. C �, dr y, O. , a a0 a j OJ, 0 , , , i-, a 2 a cai oa; v .0 co 3 3, co �, �, z� C, �, a � 3 .� 1° ti g, 4 •w c, a c, c, E a0 U) ' 0 , c, 0. w , (2 0 , E 112 f6 . °c, �0, 0) c . c, Cl) (1)' co E a) co, coi _C 3 V) C, E. N' Oy y COm0, p Z oO. m, Lu t r, , O, 7, U, Of -g. 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