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217-144
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, January 26, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Austin McLeod P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC L-53 MILNE PT UNIT L-53 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/26/2023 L-53 50-029-23586-00-00 217-144-0 W SPT 3897 2171440 1500 270 270 269 269 126 423 415 410 4YRTST P Austin McLeod 12/11/2022 MITIA 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 L-53 Inspection Date: Tubing OA Packer Depth 155 1680 1627 1612IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSAM221212182034 BBL Pumped:1.8 BBL Returned:1.8 Thursday, January 26, 2023 Page 1 of 1 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Conductor Retrofit 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 14,800 feet N/A feet true vertical 3,668 feet N/A feet Effective Depth measured 14,795 feet 7,291 & 7,340 feet true vertical 3,668 feet 3,891 & 3,898 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3/ L-80/ EUE 8rd 7,383' 3,908' HES PHL Retrievable Packers and SSSV (type, measured and true vertical depth)BOT SLZXP LTP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 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: Contact Name: Contact Email: Authorized Title: Operations Manager Contact Phone: Collapse N/A 3,090psi 4,790psi Casing 3,918' 3,899' 3,668'14,800' Surface Production Liner 16" 9-5/8" 7-5/8" 4-1/2"7,460' measuredPlugs Junk measured N/A Length 80' 7,546' 7,324' Size N/A 5,750psi 6,890psi N/A Burst N/A N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025509, ADL025514 & ADL025515 MILNE POINT / SCHRADER BLUFF OIL Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: MILNE PT UNIT L-53 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 217-144 50-029-23586-00-00 0 0 314 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 190 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MD 107' 7,572' 7,349' Conductor TVD 107' WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 828 354 David Gorm dgorm@hilcorp.com 907-777-8333 1,124 200 321-538 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 2:24 pm, Nov 10, 2021 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.11.10 14:17:29 -09'00' David Haakinson (3533) RBDMS HEW 11/12/2021 SFD 11/15/2021 DSR-11/10/21MGR28DEC2021 Schematic drawing not attached. SFD 11/15/2021 Well Name Rig API Number Well Permit Number Start Date End Date MP L-53 WSS 50-029-23586-00-00 217-144 10/17/2021 10/25/2021 Seaboard retrofit - Hilcorp wellhead crew install BPV. Use Worley manitowoc 2250 crane to pull tree and THA. Install 11" knuckle joint onto THA with wellhead crew. Roads & Pads leveled front and back. Ready for WSS. No operations to report. 10/16/2021 - Saturday WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,000H. SET 3-1/2" XX-PLUG IN X-NIP AT 3,488' SLM/3,506' MD (OAL=23"). BLEED TBG FROM 400psi TO 0psi AND WATCH FOR 10min (no pressure gain). RDMO, CLOSE PERMIT W/PAD-OP. 10/19/2021 - Tuesday 10/17/2021 - Sunday Freeze protect for Optimus prime work (Pressure test surface lines 250/2,500 psi) Pumped 36 bbls diesel down FL/TBG from polymer skid. Bled to 0 psi.Tags hung. 10/18/2021 - Monday 10/15/2021 - Friday No operations to report. 10/13/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 10/14/2021 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP L-53 WSS 50-029-23586-00-00 217-144 10/17/2021 10/25/2021 10/22/2021 - Friday Seaboard retrofit - Pull 5kps over neutral weight. Wellhead crew Install machined slips into wellhead and torque to 120 ft/lbs. Ease off weight with no indication of movement. Use Worley crane to rig down Bonnet and vertical support. Raise WSS to clear damaged and disconnected jack. Remove jack and lower WSS, ready to install travel bolts. 10/20/2021 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Seaboard retrofit - MIRU WSS with Worley crane over wellhead. Pad not completely level. Fly WSS over well, Move in SCT and electrical. All electrical working. Fly in Iron cross after adjusting height and nipple up to previously installed Knuckle. Start to raise WSS, at 7" lift, C platform inside jack apparently seized and sheared the upper 5 1/8" top nut on screw jack stem. Dismantled jack screw from lifting lug on "C" leg. (Note: Jack screw is dry, others checked on Platform D were greased. Discuss way forward with Wells foreman. Decision made to continue with job. Rig up and torque bonnet. Tare encoders. 10/21/2021 - Thursday Seaboard retrofit - Cut Bell housing from seaboard wellhead using NES welders, Air Arc and holding neutral weight on WSS. Once cut free, weight was indicated at 107 kps. Lower WSS to neutral weight with 7/8" of lowering travel. Using Milne point wellhead crew, try to install retrofit inverted slips. No joy. Calipered ID of wellhead at 12-5/16", and OD of slips at 12-9/16" at full open. Send slips to Northern solutions for machining of .250" (This should allow us .125" clearance for install) LDFN. No operations to report. Seaboard retrofit - Install travel bolts, ensure all ready for lift and travel. Disconnect electrical. Use Worley crane to lift WSS and stage at edge of pad. Worley to demobe all WSS items to PBU. Well Support Techs pulled knuckle off of THA and assisted the wellhead techs of installing the THA and tree. Well head tech performed passing pack off test on the tubing hanger and pulled BPV. Support Techs installed foundation, flowlines and well house. Pressure tested injection line to 3,600 psi. 10/23/2021 - Saturday WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2,000H. EQUALIZE & PULL 3-1/2 XX-PLUG FROM X-NIP AT 3,488' SLM/3,506' MD (recovered all packing). RDMO, CLOSE PERMIT W/PAD-OP. 10/26/2021 - Tuesday 10/24/2021 - Sunday No operations to report. 10/25/2021 - Monday 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? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 14,800'N/A Casing Collapse Conductor N/a Surface 3,090psi Production 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 Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Gorm Operations Manager Contact Email: Contact Phone: 777-8333 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Tubing Grade:Tubing MD (ft): dgorm@hilcorp.com COMMISSION USE ONLY Authorized Name: Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509, ADL025514 & ADL025515 217-144 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23586-00-00 Hilcorp Alaska LLC Length Size 3,668' 14,795' 3,668' 930 N/A MILNE POINT / SCHRADER BLUFF OIL 107' 107' 9.3/ L-80/ EUE 8rd TVD Burst 7,383' MD N/A N/A7,460' 7,324' 5,750psi 6,890psi 3,918' 3,899' 3,668' 7,572' 7,349' 3-1/2" Perforation Depth MD (ft): See Schematic See Schematic 80' 16" 9-5/8" 7-5/8" 7,546' 4-1/2" MILNE PT UNIT L-53 C.O. 477.05 HES PHL Retrievable & BOT SLZXP LTP and N/A 7,291 MD/ 3,891 TVD & 7,340 MD/ 3,898 TGVD and N/A Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 14,800' Authorized Signature: 10/21/2021 ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 12:49 pm, Oct 12, 2021 321-538 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.09.30 15:49:05 -08'00' David Haakinson (3533) DSR-10/12/21 10-404 SFD 10/12/2021MGR13OCT2021 JLC 10/14/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.14 12:27:41 -08'00' RBDMS HEW 10/19/2021 Wellhead Retrofit Well: MPU L-53 Date: 9/29/2021 Well Name:MPU L-53 API Number:50-029-23586-00-00 Current Status:Injector Online Pad:L-Pad Estimated Start Date:10/21/2021 Rig:WSS Reg. Approval Req’d? Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:2171140 First Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) Second Call Engineer:Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number:Job Type:Wellhead Repair Current Bottom Hole Pressure: 1330 psi @ 4000’ TVD (SBHPS taken on 9/8/18 EMW – 6.4 PPG) Maximum Expected BHP:1330 psi @ 4000’ TVD (SBHPS taken on 9/8/18 EMW – 6.4 PPG) MPSP:930 psi (0.1 psi/ft gas gradient) Min ID:2.813 ID 3-1/2 X Nip at 3506’ MD Max Dev:62 Deg at X profile at 3506’ MD Brief Well Summary: The Milne Point L-50 was drilled and cased as a Schrader Bluff producer in 2017 before being converted to water injection in 2018. The well’s surface casing was fully cemented and hung off a slip style casing hanger as part of a conductor supported wellhead system. The system has since been identified has having the potential to cause wellhead movement in the event of conductor subsidence. In order to fully tie well load back to the 9- 5/8” surface casing string, conductor will be cut and a reverse acting slip style hanger assembly will be installed. Notes Regarding Wellbore Condition x MIT-IA passed to 2000 psi on 12/9/2018 confirming tubing and casing integrity. x MIT-OA passed to 1650 psi on 8/31/18 confirming surface casing integrity. 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 Sline 1. MIRU SL unit. 2. Pressure test to 300 psi low and at least 1,800 psi high. 3. MU plug setting toolstring and set 3-1/2” X profile at 3,506’ MD. a. Bleed down the tubing pressure to confirm set. 4. RDMO Prep Work 5. Disconnect flowline and instrumentation. 6. Verify tubing, IA and OA pressures have been bled to 0psi. 7. Sniff cellar and adjacent area with multi-gas meter for LEL, CO, H2S and 02. Ensure confined space, egress and ventilation is adequate for operations 8. Vac out gravel from well cellar down to cellar liner to remove residual hydrocarbons. 9. Install fire blankets around well to prevent hot debris from falling downhole. 500 psi pressure test against plug for 10 minutes. Wellhead Retrofit Well: MPU L-53 Date: 9/29/2021 Sundry Work (Approval required to proceed) Surface Casing Support Retrofit – Note: Photo Document Repair Work on a Daily Project Timeline. 10. 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. 11. 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. 12. Move in and rig up Well Support Structure. Place rig mats as needed to level out support structure legs. 13. Install BPV and nipple down tree at master valve or tubing head adapter as needed to makeup Wellhead Support Structure adapter flange. 14. Prepare to transfer load to the Well Support Structure. Pretension load cells according to operating manual. 15. Pull 8,000 lbs (Wellhead Weight) gradually building up load in 1000 lb increments. a. Monitor the wellhead for any signs of movement and discontinue increasing tension if movement observed. 16. Increase weight up to 68,000 lbs (60 K preloading) 17. Once pre-loaded, begin cutting conductor horizontally at bottom of conductor bell nipple using air arc cutter. a. Monitor load on Well Support Structure in addition to wellhead vertical displacement during cutting operations. a. Maximum dry, tubing, casing and wellhead load = 9.3#*7383’ + 29.7#*7349’+8K = 295K b. Maintain constant vertical displacement while well support structure is loaded by well. 18. Proceed to cut conductor bell nipple below the starting head then remove conductor bell nipple section. a. Ensure minimum of 12” of clearance between bottom of starting head and top of conductor. b. Record Well Support Structure Load in WSR once conductor fully loaded. 19. Leave remaining bell nipple section engaged in starting head. Bevel as needed to ensure smooth entry of slip assembly. 20. Place each half of Reverse Slip Loc assembly around surface casing, bolt halves together. 21. Install energizing plate halves at 90 degree offset from slip assembly such that joint between halves are perpendicular to slips. 22. Lift Reverse Slip Loc up inside conductor starting head. 23. In a criss cross pattern, begin to tighten bolts on energizing plates initially to 50 ft-lbs on first pass then to a final torque of 100-125 ft-lbs on second pass. 24. Mark casing at the bottom of the Reverse Slip Loc 25. Release tension, observe for any slippage. If slipping occurs, re-tension and tighten bolts to 150 ft-lbs. 26. Once load is released to Reverse Slip Loc, conduct MIT-IA and OA to at least 1,500 psi to confirm tubing, casing, and packer integrity unchanged. a. Notify AOGCC at least 24 hrs prior to pressure testing injector Inner Annulus. b. Provide test results to Darci Horner (dhorner@hilcorp.com or 907-777-8406) for submission to AOGCC. 27. Unbolt and remove the adapter flange 28. Reinstall 5K injection tree. 29. Remove BPV and install TWC. Pressure test tree to 5000psi. 30. Re-install flowline and instrumentation 31. Weld centralizer/landing ring onto top of conductor. 32. Reinstall well house and backfill gravel over cellar liner. 33. Install Corrosion Inhibitor in SC by Conductor Annulus up to the conductor top. Wellhead Retrofit Well: MPU L-53 Date: 9/29/2021 Slickline 34. MIRU SL unit. 35. Pressure test to 300psi low and at least 1,800 psi high. 36. RIH and pull plug from 3-1/2” X profile at 3,506’ MD. 37. RDMO. 38. Turn well back over to operations. Attachments: -Wellbore Schematic _____________________________________________________________________________________ Revised By: TDF 9/6/2018 SCHEMATIC Milne Point Unit Well: MPU L-53 Last Completed: 8/25/2018 PTD: 217-144 TD = 14,800’ (MD) / TD = 3,668’(TVD) 16” Orig. KB Elev.: 26.5’(Innovation) 7-5/8” 3 and 4 5 9-5/8” 1 2 PBTD = 14,795’(MD) / PBTD = 3,668’(TVD) 7 ES Cementer @ 2,855’ Min ID= 2.813” @ 3,506’ 6 8 & 9 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 164 / A-53 / Welded N/A Surface 107' 9-5/8" Surface 40 / L-80 / DWC 8.835 Surface 7,572’ 7-5/8" Production 29.7 / L-80 / STL SMLS 6.875 Surface 7,349’ 4-1/2” Liner 13.5 / L-80 / HTTC- Hy563 3.875 7,340’ 14,800’ TUBING DETAIL 3-1/2" Tubing 9.3/L-80/EUE 8rd Mod 2.992 Surface 7,383’ JEWELRY DETAIL No Depth Item 1 3,506’ 3-1/2” X-Nipple (ID=2.813”) 2 7,291’ 7-5/8”x3-1/2” HES PHL Retrievable Packer 3 7,304’ 3-1/2” Autofill Sub 4 7,313’ 3-1/2” Mirage Plug 5 7,340’ BOT SLZXP Liner Top Pkr w/BD Slips, 7" x 9 5/8" 6 7,362’ Crossover Sub, 7" H563 x 4.5" HTTC L-80 7 7,383’ 3-1/2” WLEG 8 14,795’ WIV Valve with Ball Seat 3-1/2” WLEG 9 14,798’ Round Nose Float Shoe: Bottom @ 14,800 WELL INCLINATION DETAIL KOP @ 43’ Max Hole Angle = 94.1 deg. @ 14,719’ GENERAL WELL INFO API: 50-029-23586-00-00 Drilled, Cased and Completed by Innovation - 11/25/2017 Convert to injector by Doyon 14 - 8/25/2018 TREE & WELLHEAD Tree 5M Seaboard 2-9/16” Wellhead Seaboard MB-22 5M CEMENT DETAIL 16" 270 cf of cement in a 36” Hole 9-5/8" Stage 1: Lead 620 sx(271.2 bbls) of 11.7# Extenda Cem Tail 390 sx (79.3 bbls) of 15.8# Swift Cem Stage 2: Lead 453 sx (349 bbls) of 10.7# Permafrost L Cem Tail 270 sx (56.1 bbls) of 15.8# Type I/II Cem SAFETY NOTE Seaboard conductor supported wellhead. 50-80 Klbs max compressive load. SCREEN DETAIL 7,616’ to 14,714’ 4-½” 13.5#/Ft Hydril 563 HAL Petroguard Mesh Screen 250 Micron THE STATE 01ALASKA GOVERNOR MIKE DUNLEAVY April 3, 2019 Mr. Bo York Operations Manager Hilcorp Alaska LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.ac gcc.aloska.gov RE: Docket No.OTH-18-016 Request for approval of well testing procedures for Milne Point Unit Schrader Bluff Oil Pool wells L-51 (PTD 217-151) and L-53 (PTD 217-144) Dear Mr. York: By letter dated February 6, 2018, Hilcorp Alaska LLC (Hilcorp) requested approval of well testing procedures for two Schrader Bluff Oil Pool Wells L-51 and L-53 on the basis that normal well testing procedures employed at the Milne Point Unit (MPU) do not provide accurate results for the wells because of their low API gravity and high viscosity. Hilcorp's request is hereby GRANTED under the conditions below. The MPU L-53 well came online in November 2017 and the MPU L-51 well came online in December 2017. The oil produced from these wells has a higher viscosity than was anticipated and is like shaving foam at surface conditions, which makes maintaining fluid levels in the test separator nearly impossible, causing liquid carryover into the gas stream coming off the test separator, and resulting in inaccurate well test results. Hilcorp attempted to blend the production from the wells with diesel to dilute the viscous oil, which improved test results but there was still liquid carryover into the gas stream so the overall results were still unacceptable. Hilcorp also attempted to blend warm produced water with the well's production stream but this also provided unacceptable results due to liquid carryover in the gas leg. Hilcorp then attempted to piggy back the wells with a warmer and gassier Kuparuk producer, MPU L -28A, and was able to get acceptable results. In brief the proposed test procedure is to conduct a test on the MPU L -28A well, then commingle its production with that of MPU L-51 or MPU L-53 and test the combined flow stream, take a sample of the combined flow stream to determine shrinkage factor, and then determine the flow attributable to MPU L-51 or L-53 by applying the shrinkage factor and taking the difference between the combined stream well test and the MPU L -28A only well test. In order to ensure as accurate of a well test as possible for the MPU L-51 and L-53 wells, Mr. Bo York April 3, 2019 Page 2 of 2 conducting a standalone test of the L-28 well after running a commingled test will ensure the flow profile of that well did not change during the combined flow testing period. Therefore, Hilcorp's proposed well testing procedures for the MPU L-51 and L-53 well are approved with the following conditions. I) Testing must be conducted in accordance with the procedures included with Hilcorp's February 6, 2018, request letter. 2) In addition to the procedures in the letter Hilcorp shall also retest the MPU L -28A well after completion of the combined well test to ensure the performance of the MPU L -28A well did not change while the combined test was taking place. 3) Any changes to the established testing procedures requires pre -approval from the AOGCC. 4) A discussion of the test results for these wells shall be included in the annual surveillance report for Milne Point. DONE at Anchorage, Alaska and dated April 3, 2019. Daniel T. S�ef_tJr. eile Chmielowski Commissioner oner NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bo York 3800 Centerpoint Or Operations Manager Suite 1400 bvork(&Hilcoro conn Anchorage, AK 99503 nmaska,LLC Phone: 907/777-8345 Fax: 907/777-8560 6 February 2018 RECEIVED Mr. David Roby FEB u 9 201$ Alaska Oil & Gas Conservation Commission A�pi 333 West 7th Avenue, Suite 100 � s Anchorage, AK 99501 Re: Milne Point Unit Schrader Bluff Pool Oil L-51 (PTD 217-151) and L-53 (PTD 217-144), Request for Approval of Well Test Procedure Dear Mr. Roby: Milne Point's new Schrader Bluff NB wells, L-51(on ESP production 27 Dec 2017) and L-53 (on ESP production 29 Nov 2017), have proven difficult to obtain a well test after coming online with higher than expected fluid viscosities. At 60 degrees F, L-53 exhibits an API gravity of 12.7 and 21,539 cP and L-51 exhibits an API gravity of 13.3 and 21,933 cP. Samples taken from the production and test headers resemble the consistency of shaving foam. This consistency makes achieving an accurate test difficult. As required by 20 AAC 25.230, Hilcorp has developed a well test procedure that will accurately and reliably measure the produced fluids from L-51 and L-53. Hilcorp requests AOGCC review and approve the proposed well test procedure detailed below. Background and Attempted Tests When attempting a normal well test procedure utilizing the L pad's test separator, the test separator is overwhelmed. The level control is unable to maintain the setpoint of 50%, and will quickly reach the 90% high level shutdown if left unattended. Increasing the backpressure does not provide a remedy. Even before reaching the 90% level, liquid carries over into the gas leg, which affects the accuracy of the test. A variety of methods were utilized to attempt to perform an accurate test. Operations slipstreamed diesel into the flowline while the well was in test attempting to dilute and cut the produced fluid. This resulted in a successful six hour test without shutting down the separator, but liquid carryover was still observed. With careful tracking of the amount of diesel pumped during the test, the total fluids coming from the well were accurately calculated; however, the liquid carryover contributed inaccuracies to the individual water, oil and gas rates. Even though the operator was able to complete the test, it was a struggle to keep the level near the setpoint. Another attempt to achieve an accurate test was made with produced water from the Milne Point facility. Produced water was pumped into the flowline at 180 degrees F in an attempt to help break out the entrained gas, as well as cut the wellbore fluids and allow them to flow through the separator easier. Like the diesel test, the operator was able to complete a six hour test, but still experienced high fluid levels in the separator which led to liquid carry over into the gas leg. Proposed Well Test Procedure for L-51 and L-53 After attempting the above tests with mixed results, the field operations team developed another alternative test plan that did not involve pump trucks or tanks thereby reducing the risk of spills and with the potential to increase the accuracy of the test. The concept was to run L-51 or L-53 into the test header at the same time as another well that had a higher wellbore fluid temperature and some gas production. The Milne automations technicians revised the control logic to allow two wells into the test separator at the same time and the following steps were followed: 1. A standard/normal six hour test is performed on L -28A. L -28A is a Kuparuk producer with 120 degree F produced fluid (1,200 bwpd, —200 bopd and —20 mscfd)). The L -28A choke is manipulated as necessary to mimic the higher back pressure observed when L-51 or L-53 are placed in the test header. This test will not be considered a valid test for L -28A since the back pressure will be artificially higher than normal. 2. Immediately following the L -28A test, the operator selects the Schrader well (i.e., L-51 or L-53) for test. 3. The revised test logic automatically rolls L -28A into the test header prior to L-51 or L-53. L -28A purges the test header for 15 minutes with warm produced fluids. 4. After the 15 minute L -28A only purge, the selected L-51 or L-53 well will automatically roll into the test header along with L -28A for a second 15 minute purge cycle. Once the entire 30 minute purge cycle is completed the test begins. 5. The produced gas and the warm fluid from L -28A mixes with L-51 or L-53 and the extra gas and the extra heat allows for the separator to function as designed. The level control stays at setpoint, the pressure controller maintains the desired differential, and there is no liquid carryover into the gas leg. 6. During the test phase, three individual 100 mL grab samples are taken from the separator. These samples are allowed to separate over 24 hours in order to determine an average shrinkage factor. 7. At the end of the test both wells are diverted from the test header, per normal procedure, and the next well selected will start its test cycle per normal operations. 8. Following the test, the amount of produced fluid from L -28A as determined by the L -28A test immediately prior to the L-51 or L-53 test cycle, is backed out of the L-51 or L-53 well test. The average shrinkage factor determined from the three grab samples is then applied to the L-51 or L-53 test results in order to determine the final approved test result. Based on the above attempts to achieve an accurate well test on L-51 and L-53, Hilcorp requests AOGCC approve the test procedure as detailed in steps 1-8 above. This test procedure would not change or modify any other test procedure for any other well on L pad and would also not adjust or modify production reporting or allocation procedures. Hilcorp believes the proposed procedures will result in an accurate and reliable test per 20 AAC 25.230. If you have questions regarding this communicated intent please feel free to contact me. Sincerely, Hilcorp Alaska, LLC York Operations Manager a{ 4 - 114 • • Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Phone: 907/777-8547 WED JUN 0 7 2018 June 5, 2018 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 • U) a) m a) a) a) a) a) a) a) a) a) a) a) a) a) 2 2 C C C C C C C C C C C C C J J J J J J J J J J J J J L O O Q C LCCCCCCCCCCC2 O n O O z n n O O L U U a) a) a) a) a) a) a) a) a) a) a) a) a) Q C Q Q ccryrywcectw w ec C C CC C C C C C C C C C C C L a) a) Cl) a) (I) (1) () (1) a) (1) a) (I) a) O O ii. 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I d c'° UUw0 O. a E ` 0 a 0 m0 o o E E0d Q 41)p 0 0 0 • ° aa) a a 2 w w F. o a 0 0 O v v RECEIVED • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION OEC 2 7 2017 la.Well Status: ❑ t Gas COMPLETION ❑ 0 Other Abandoned WELL COMPLETG❑ ❑ ❑ Suspended❑ ON OR RECOMPLETION REPORTO ANP{I , lb.Well Class:; $,."'LL.9'C 20AAC 25.105 20AAC 25.110 Development Q, Exploratory ❑ GINJ ❑ WINJ ❑ WAGE WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp.,Susp.,or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 11/25/2017 ' 217-144 • 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 October 29,2017 50-029-23586-00-00" 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 3744'FSL,5235'FEL, Sec 8,T13N, R10E, UM,AK November 13,2017 , MPU L-53 , Top of Productive Interval: 9.Ref Elevations: KB: 42.3 17. Field/Pool(s):Milne Point Field . 729'FSL,576'FWL, Sec 7,T13N, R10E, UM,AK GL: 15.8 BF: 15.8' • Schrader Bluff Oil Pool( m6 Total Depth: 10.Plug Back Depth MD/TVD: 18. Property Designation: 920'FNL, 974'FEL,Sec 24,T13N, R9E, UM,AK 14,795'MD/3,668'TVD ADL 025509,025515,025514 • 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 544641 y- 6031932 Zone- 4 14,800'MD/3,668'TVD ' LONS 88-002 TPI: x- 540015 y- 6028891 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 538501 y- 6021954 Zone- 4 N/A 2,554'MD/1,903'TVD 5. Directional or Inclination Survey: Yes U (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/ABG/DGR/EWR/ADR 2"/5"MD ABG/DGR/EWR/ADR 2"/5"ND 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH ND AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16" 164# A-53 Surface 107' Surface 107' 36" 270 ft3 9-5/8" 40# L-80 Surface 7,572' Surface 3,918' 12-1/4" Stg 1 L-620 sx/T-390 sx Stg 2 L-453 sx/T-270 sx 7-5/8" 29.7# L-80 Surface 7,349' Surface 3,899' Tieback 4-1/2" 12.6# L-80 7,340' 14,800' 3,898' 3,668' 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; Date Perfd): 2-7/8" 4,829' N/A Open Screen 4-1/2"Liner 7,616'MD-14,714'MD/3,919'-3,675'ND 26.ACID, FRACTURE,CEMENT SQUEEZE,ETC. Was hydraulic fracturing used during completion? Yes❑ No 0 "'ZS/LI- Per 20 AAC 25.283(i)(2)attach electronic and printed information tZS/1 I- DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED L 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 12/18/2017 ESP Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 12/22/2017 24 Test Period 1557.8 9.1 0 N/A 5.8 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 253 380 24-Hour Rate � 1557.8 9.1 0 12.7 Form 10-407 Revisgd 5(2_147 fr N INUED ON PAGE 2 a+ 2r,an Submit ORIGINIAL on 13 II ai54` !- r-/8 et ej8, RE3� � �� _ � 0 . 28.CORE DATA Conventional Core(s): Yes ❑ No 2 Sidewall Cores: Yes ❑ No ❑., If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Q Permafrost-Top If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base 2,554' 1,903' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval Schraeder Bluff , 3ctt°t' information, including reports, per 20 AAC 25.071. SV5 1,610' 't' 1,428' Li. SV1 3,023' 2,125' Ugnu LA3 5,702' 3,399' Schrader NA 7,248' 3,884' Schrader NB 7,493' 3,913' Formation at total depth: Schrader Bluff " 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys,Csg and Cmt Report. Information to be attached includes, but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report, production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Paul Mazzolini Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdinger • hiICorp.com Authorized i�� ! Contact Phone: 777-8389 Signature: _ / Date: s A Z 4441/RUCTIONS General: This form and the r, (i7;7‘,11 .4.. quired attach en s pr vide a co p ete 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 la: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing,Ground Level,and Base Flange elevations in feet above Mean Sea Level.Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 19: Report the Division of Oil&Gas/Division of Mining Land and Water:Plan of Operations(LO/Region YY-123), Land Use Permit(LAS 12345), and/or Easement(ADL 123456)number. Item 20: Report measured depth and true vertical thickness of permafrost.Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and,pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26.(Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in, or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including, but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including, but not limited to:core analysis,paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only 14 • • Milne Point Unit Well: MPU L-53 SCHEMATIC Last Completed: 11/25/2017 Hilcorp Alaska,LLC PTD: 217-144 Orig.KBEIev.:26.5'(Innovation) TREE&WELLHEAD Tree 5M Seaboard 2-9/16" 1 161 U Wellhead Seaboard MB-22 5M CEMENT DETAIL 1 Pi 16" 270 cf of cement in a 36"Hole , Stage 1:Lead 620 sx(271.2 bbls)of 11.78 Extenda Cern Dual Tail 390 sx(79.3 bbls)of 15.88 Swift Cern 3/8 SS 9-5/8" Stage 2: Lead 453 sx(349 bbls)of 10.7#Permafrost L Cern Capstring 71.).1 Tail 270 sx(56.1 bbls)of 15.8#Type I/II Cern ' CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm t:' ES Cementer 16" Conductor 164/A-53/Welded N/A Surface 107' @2,855' 9-5/8" Surface 40/L-80/DWC 8.835 Surface 7,572' 7-5/8" Production 29.7/L-80/STL SMLS 6.875 Surface 7,349' 4-1/2" Liner 12.6/L-80/HTTC 3.875 7,340' 14,800 TUBING DETAIL Min ID= 2 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.441 Surface 4,829' 2.20`' 3/8" Capstring x 2 Stainless Steel N/A Surface 4,829' 4,70 3 WELL INCLINATION DETAIL ,,. 1l 14 KOP @ 43' Max Hole Angle=94.1 deg.@ 14,719' 5&6 i ' JEWELRY DETAIL ilii. 7 No Depth Item 8&9 • 1 131' Sta#2:GLM-1"Side Pocket KBMM w/Orifice 2 4,591' Sta#1:GLM-1"w/Dummy " , 3 4,702' 2-7/8"XN-Nipple(2.205 No-go ID) , I 10 i' 4 4,744' Discharge Head:FPDIS 1:, 5 4,745' Upper Tandem Pump:134 STG FLEX 17.5 w. 6 4,768' Lower Tandem Pump:134 STG FLEX 17.5 Vi (p. Inl 11 ft 7 4,792' Gas Separator:GRS FER N AR �Y 12 * 8 4,795' Upper Tandem Seal:GSB3DBUTSB/SB PFSA 7 5/8" 9 4,802' Lower Tandem Seal:GSB3DBUT SB/SB PFSA 10 4,809' Motor:562 XP—250hp/2,505V/61A 11 4,825' Sensor,Phoenix XT150 12 4,827' Centralizer:Bottom @ 4,829' 9-5/8" 'OM : �.� 13 13 7,340' BOT SLZXP Liner Top Pkr w/BD Slips,7"x 9 5/8" 14 14 7,362' Crossover Sub,7"H563 x 4.5"HTTC L-80 15 14,795' WIV Valve with Ball Seat II I II1 16 14,798' Round Nose Float Shoe:Bottom @ 14,800 IIIII III GENERAL WELLINFO API:50-029-23586-00-00 Drilled,Cased and Completed by Innovation -11/25/2017 111111 III I 15&16 TD=14,800'(MD)/TD=3,668'(TVD) PBTD=14,795'(MD)/PBTD=3,668'(TVD) Edited By:CJD 12/27/2017 • • Hilcorp Energy Company Composite Report Well Name: MP L-53 Field: Milne Point County/State: ,Alaska (LAT/LONG): :vation(RKB): API#: Spud Date: 10/29/2017 Job Name: 1713438D MPL-53 Drilling Contractor Innovation AFE#: 1713438D AFE$: a i `sod:.:::::»<_'. ... a4ctiyr..:.i:3at� . .� €Y.:: „>.,,;:. ,.. ;<:�`�.' � tn'M.. ::,4.;.::::.. t7fis Suti#fxaryr 10/18/2017 R/D off C-45.Finish loading 5"drill pipe into pipe shed.Remove landing off of pipe shed.Remove sub out riggers,blow down steam lines.R/D interconnects on mezzanine,pits and motor module.;lnspect valves and seats on mud pumps.Remove cuttings box,put rig on cold start power.Warm up and function hydraulic system.Jack up motor and pipe shed modules.;lnstall jeep on motor module.Trucks on location @ 04:30,separate pipe shed and motor modules, stage same on pad. 10/19/2017 RDMO C-45,separate modules and stage on pad,orientate modules for rig move, Roads and pads prep route,mat flow line crossings.;PJSM,Mobilize rig modules to L-Pad,cleanup around C-45.;PIace wellhead behind conductor,back and spot sub over L-53,shim sub,lay rig mats and set catwalk,mud and pipe shed modules.;PJSM w/oncoming crew.Set gen module in place.R/U interconnects.Get steam circulating on rig.Fold down roof flaps,safety out roof top. Assist rig electrician with plug board.;Swap to gen power,perform derrick inspection,set sub out riggers.Scope derrick up,Bridal down.Perform full derrick inspection after scope up.Mobilize shop and camp f/C-Pad to L-Pad,spot same.;Re-assemble mud pumps-install valves and seats.Mobilize break room trailer and enviro vac to L-Pad,spot and setup same.Lay herculite-spot cuttings box.Spot cmt upright tank.;Trucks released @ 02:00,R/U tongs,get water circulating throughout rig.Ready pipe shed.Replace centrifuge foot valve.Thaw cellar box.Install test plug,4 bolt diverter tee.;Work on rig acceptance checklist. Currently 80%rigged up. 10/20/2017 Berm in cuttings box. Pump out gear lube from#1 mud pump.Remove gun line in pit#4 and cleanout debris.Clean and organize throughout rig;N/U Diverter system,set BOP on diverter tee,install pipe shed side diverter line and stand.Set up diverter sign.Install turn buckles on stack.Modify flow riser.;Set flow riser, install drain pan.Install knife valve.Get stack measurements.Reinstall pit#4 gun line.Assist welder,modify gate on flow trough. Swap rig to high line power @ 18:00;Assist NOV rep on centrifuge inspection and maintenance.Perform monthly PMs on air compressors and Rig HPU. Continue to clean and organize around rig. Continue to work rig acceptance checklist.;Continue to N/U diverter line and bolt up same.Finish welding up trough on shaker.Pull housings off mix pump 2, charge pumps,trip tank pumps to measure impeller gap.;Remove elevators and bails from top drive for inspection.Open upper VBR and blind ram doors on BOP,clean ram cavities for inspection.;Wire wheel bails,pin pockets on blocks,load bearing welds on on rig floor and pins for MPI inspection.Paint new welds on trough gate under shaker 2. Continue to work on acceptance checklist.;Note:Swap to rig maintenance AFE:1750105 @ 06:00 10/28/2017 Finish painting drum warm up shack.Prep TD for motor lead install.Stage and pressure wash Hawk Jaw.Install guard on vent fan in the pits.R/D steam heat exchanger.Continue plumbing in Vac System.;Continue install weather stripping on pipe shed door.Installed heavier spring on flow paddle.Received Tong Heads for BV Rig Tongs.Received new 16"Ducts for jet heater.;Organize and inventory Drilling Subs(on going),prep interior of drum warmup shack f/paint. Finish prepping air slips for inspection. New TD pigtails and lugs arrived on location @ 20:30.;Rig electrician install new top drive motor leads using kit provided by NOV,plug in and secure leads to top drive.Safety wire bolts on TD. Start to test run TD electric motor.;Troubleshoot TD motor,operate in drill mode,turns slowly in wrong direction w/fault alarm.Switch leads in power house cords,no rotation but torque,in drill mode @ 10k torq,TD will not rotate.;Verify brake not set-turn quill with chain tongs easily.NOV rep change motor ID in program so it will communicate with new TD motor. 10/29/2017 Function Test TD after Motor Lead install.Change out TD lube pump filter.Clean up work area around the Drum Hot Shack after grinding and painting.Install cuttings tank Skirt. Test Gas Alarms.;Pu 26 Jts NC-50 DP.Re-position Kelly hose.Load spud mud in pits.;Test Diverter System:Accumulator Test:Start:3025,After close 2000 psi,200 psi build 12 sec,Full Recovery 46 sec.Ann.Close time 11 sec,Knife Valve Open 6 sec.;Hold Pre Spud Meeting with all parties.;PU Varrell 12 1/4"Bit on 1.5 deg Mud Motor,attempt to make connection and TD would over TQ in connection Mode,and would not stall in connection mode.;Service Rig While W/O NOV Rep to be Transported from Main Camp to Rig.;Trouble Shoot Tq issues.NOV Rep Re-enter parameters into the PLC.No further issues with Top Drive TQ settings.;Continue C/O Conductor to 107'.SPUD WELL:Drill 12 1/4"Hole to 218'.400 gpm/325psi,20 rpm,Up/Dn Rot 45K.Circulate Clean.No notable issues with flow line.Mostly clays slight gravels.;Set Back weight pipe.MU remaining BHA as per sperry,offset @ 108.22 deg.RU Gyro while up load MWD.M/U UBHO,stand of NMFCs,XO,stand of HWDP.C/O Gyro tool.;Gyro survey @ 107',wash down pumping 400 gpm,500 psi,tag bttm @ 218',no fill.;Drill 12 1/4"hole,start build f/218'to 452'(5 stds HWDP) pumping 400 gpm,750 psi,circulate hole clean @ connections,rack 1 std back,M/U jars w/ single HWDP.;Note:Start build early @ 218'MD with a 30'Slide at 330M TF.Continue sliding 30'/stand obtaining Gyro surveys every stand down to 452' MD.:Drill f/452'to 702'with 5 remaining stds of HWDP, stage pump to 480 gpm,900 psi. Slide 30'on ea.std drilled,WOB 3-5K,last gyro survey 452',MWD surveys clean.;Put gyro on stby until needed f/multi shot surveys @ 800'.;Drill ahead F/702'T/1265'MD.563'(93.8 fph)168.5 fph on bttm 480 GPM,1025 PSI,WOB 5-6K,RPM 70,TQ 5.5K MW in/out 9+ppg,vis 185,9.34 ECD,8 bgg.PU/SO/ROT 81 k/79k/78k.;889'RIH with gyro,check shot survey every 60'f/ survey @ 353'to 790',RID and release gyro @ 02:30.Last survey 1038.3 MD/28.87 incl 243.59 Az/1009.76 TVD.;Currently 30.97'above the line,7.24'left 3.36 slide hrs.2.75 rotate hrs.;Hauled 342 bbls cuttings to MP G&I for total=558.5 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from B-Pad for total=0 bbls;Hauled 560 bbls from B-Pad creek for total=1400 bbls Daily losses 0 bbls to formation for total=0 bbls • • 10/30/2017 Drill ahead F/1265'T/1579'MD.314',Av 125.6 FPH 480 GPM,1075 PSI,WOB 5-10K,RPM 80,TQ 5K MW in/out 9.1+ppg,vis 185,10.1 ECD,8 bgg. PU/SO/ROT 83/73k/75k.;Observe ECD spikes to 11.5. Perform Clean up cycle CBUx2 with ECD Decrease to 9.9. Mostly thick Clays some sands observe @ Shakers.;Drill ahead F/1579'TI 2102'MD.523',Av 104.6 FPH 500 GPM,1300 PSI,WOB 5-10K,RPM 80,TQ 6K MW in/out 9.2+ppg,vis 179,10.9 ECD,8 bgg.PU/SO/ROT 83/73k/75k.;Control Drill when Rotate @ -150 FPH.;Attempt to increase drilling rate.Shakers loaded up with deep cuttings.Having to battle shakers.Stop drilling,slow pump rate to 400 gpm and perform clean up cycle CBU x3 staging up to 600 gpm.;Drill ahead F/2102'T/2400'MD.298',Av 99.3 FPH 550 GPM,1520 PSI,WOB 5-9K,RPM 80,TQ 6-7K MW in/out 9.2+ppg,vis 187,10.9 ECD, PU/SO/ROT 98/67k/76k.;Drill ahead F/2400'T/2983'MD. 583',Av 97.2 FPH 550 GPM,1600PSI,WOB 4-9K,RPM 80,TQ 7.5K MW in/out 9.2+ppg,vis 178,9.88 ECD, PU/SO/ROT 105/74/87, Max BGG 188u.;Note:Base of permafrost came in @ 2554'MD.2800'slowly lower vis to 150+-.;Drill ahead F/2983'T/3587'MD.604'Av 100.6 FPH 550 GPM, 1600PSI,WOB 4-10K,RPM 80,TQ 8K MW in/out 9.2+ppg,vis 150,10 ECD,PU/SO/ROT 111/75/90, Max BGG 435u.;Last survey 3360.82'MD/Inc 60.2/ Az 250.78/TVD 2281.97 Currently 4.84'above the line,0.44'left. 5.19 slide hrs,8.2 rotate hrs.;Hauled 1425 bbls cuttings to MP G&I for total=1983.5 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from B-Pad for total=0 bbls;Hauled 1540 bbls from B-Pad creek for total=2940 bbls Daily losses 0 bbls to formation for total=0 bbls 10/31/2017 Drill ahead F/3587'T/4135'MD.548'Av 91.3 FPH 550 GPM,1750PSI,WOB 1-6K,RPM 80,TQ 9-10K MW in/out 9.2+ppg,vis 145,10 ECD,PU/SO/ROT 114/74/86, Max BGG 91 u.;Drill ahead F/4135'T/4640'MD.505'Av 84 FPH 600 GPM,2225PSI,WOB 1-6K,RPM 80,TQ 9-11K MW in/out 9.1+ppg,vis 135,10.2 ECD, PU/SO/ROT 134/76/95, Max BGG 135u.;Drill ahead F/4640'T/5143'MD.503'Av 84 FPH 600 GPM,2240PSI,WOB 2-8K,RPM 80,TQ 10- 13K MW in/out 9.2 ppg,vis 144,10.2 ECD, PU/SO/ROT 154/80/106, Max BGG 251 u.;Drill ahead F/5143'T/5603'MD.460'Av 77 FPH 600 GPM, 2225PSI,WOB 1-6K,RPM 80,TQ 11-14K MW in/out 9.1+ppg,vis 135,10.2 ECD, PU/SO/ROT 157/76/109, Max BGG 118u.;Last survey 5373'MD/Inc 61.58°/Az 248.63°/TVD 3241.93' Currently 5.7'above the line,5.9'right. 3.03 slide hrs,11.38 rotate hrs.;Hauled 969 bbls cuttings to MP G&I for total=2953 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from B-Pad for total=0 bbls;Hauled 1260 bbls from B-Pad creek for total=4200 bbls Daily losses 0 bbls to formation for total=0 bbls 11/1/2017 Drill ahead F/5603'T/5788'MD.185'Av 92.5 FPH 600 GPM,2280PS1,WOB 1-6K,RPM 80,TQ 14-15K MW in/out 9.3+ppg,vis 136,10.3 ECD, PU/SO/ROT 159/77/108, Max BGG 118u.;Circulate bottoms up x2 @ 600 gpm/2250 psi,40 rpm/12-13k TQ.Monitor well.Well static.;BROOH f/5785 to 4785' w/600 gpm/2125 psi,60 rpm/13K Tq..Observe increase in cuttings a shaker.;CBU f/4785',600 gpm/2015 psi,60 rpm/13-14 Tq. Observed continual cuttings throughout the circulation,but no real substantial unloading of cuttings from the well.;Continue to BROOH with same parameters.Observed signs of packoff/Tq Swings through the majority of the slide intervals.Encountered no notable issues on while Back Reaming.;CBU x 1 1/2 from 2700'with significant cuttings through out 1 st bottoms up circulation.Blow down TD,Monitor well for flow,well static.;Service Rig.;While attempting to run top drive up derrick to latch stand. Make up tong line appears to have hung up behind traveling tq frame of top drive. Line was pulled tight then released and dropped tongs;tong's hanging line pulled tight which loaded standoff bracket in derrick for hanging tongs. Failed bolts that anchor bracket to derrick but did not fall due to safety restraint system.;Failed bolts were replaced and tong hanging system inspected. Full inspection of equipment was done along with identifying probable cause and prevention.;Near miss report generated by Kuukpik toolpusher.;B/D TDS. RIH F/2700'-T/5788'MD. Trip was very clean and without issue. Hole took proper displacement. No fill.;Circulate and condition mud @ 5788'MD. Stage pumps up to 500 gpm,2070 psi,71%flow,60 rpm,14k tq. Saw 48 units max gas @ btms up. Dump 250 bbls high wt/solid content mud.;Bleed in 200 bbls new mud during conditioning cycle.;Start drilling build and turn section to land surface. Drill F/5788'-T/6156'MD.590 gpm,2230 psi,65%flow,6-12k wob,35u BGG,9.8 ECDs.;Last survey 6002'MD/Inc 63.15°/Az 240.16°/TVD 3538'. Currently 7.1'above the line,3'right.2.07 slide hrs,2.65 rotate hrs.;Hauled 570 bbls cuttings to MP G&I for total=3523 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 840 bbls from B-Pad creek for total=5040 bbls Daily losses 0 bbls to formation for total=0 bbls 11/2/2017 Drill ahead F/6163'T/6470'MD.307'Av 51.2 FPH 590 GPM,2330 PSI,WOB 2-6K,RPM 70,TQ 17-18K MW in/out 9.1+ppg,vis 136,9.8 ECD, PU/SO/ROT 182/73/114, Max BGG 142u.;Drill on hard spot F/6470'T/6490"MD.20' Av 8 FPH 600 GPM,2250 PSI,WOB 28-30K.Adjust parameters as needed.Slide and rotate through interval.;Drill ahead F/6490'T/6670'MD.180'Av 51.4 FPH 600 GPM,2275 PSI,WOB 5-28K,RPM 70,TQ 16-22K MW in/out 9.2 ppg,vis 130,9.6 ECD, PU/SO/ROT 189/66/112, Max BGG 70u.;Back ream full stands,lowering flow rate on the down to 500 gpm.;Drill ahead F/ 6670'T/6928'MD.258'AROP 43 FPH 600 GPM,2440 PSI,WOB 5-28K,RPM 70,TQ 16-22K MW in/out 9.2 ppg,vis 130,9.6 ECD, PU/SO/ROT 190/68/112, Max BGG 24u.;Drill ahead F/6928'T/7047'MD.119'AROP 20 FPH 600 GPM,2425 PSI,WOB 15-30K,RPM 70,TQ 16-22K MW in/out 9.2 ppg,vis 114,9.7 ECD, PU/SO/ROT 190/68/112, Max BGG 24u.;Started oscillating pipe around 6700'MD to transfer wt to bit. Pumped nut plug/condet sweep @ 7010'MD with no change. Try various parameters to obtain higher ROP but saw very little change.;Last survey 6945'MD/Inc 80.19°/Az 191.42°/ TVD 3831'.Currently 1.5'above the line,17'right.11.95 slide hrs,2.06 rotate hrs.;Hauled 855 bbls cuttings to MP G&I for total=4378 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 980 bbls from B-Pad creek for total=6020 bbls Daily losses 0 bbls to formation for total=0 bbls 11/3/2017 Drill ahead F/7074'T/7305'MD.231'AROP 38.5 FPH 600 GPM,2480 PSI,WOB 10-30K,RPM 70,TQ 16-21K MW in/out 9.2 ppg,vis 125,9.7 ECD, PU/SO/ROT 189/66/110, Max BGG 370u.;Adjust parameters as needed to minimize Slip stick.;Drill ahead Fl 7305'T/7582'MD.277'AROP 55.5 FPH 600 GPM,2570 PSI,WOB 15-30K,RPM 70,TQ 17-20K MW in/out 9.2 ppg,vis 76,9.7 ECD, PU/SO/ROT 188/66/108, Max BGG u.;Geologist call TD @ 7582'.;BROOH 3 stands f/5782'to 7420'.CBU x 2. 600 gpm,2260 psi,62%flow,70 rpm,19k tq,9.6 ECD's. 240u max gas btm's up,60u BGG.;Monitor well (static). RIH F/7420-T/7582'MD. No issues.;BROOH F/7582'-T/6202'MD. 40 rpm,19k tq,600 gpm,2300 psi,62%flow. 23u BGG. Saw lx 26k stall @ 6440'. BROOH @ 5-10 fpm from 6440'to 6202'MD w/slight tq issues thru curve.;Continue BROOH Fl 6202'-T/3904'MD.Tq issues cleaned up @ 6000' MD(Tangent). Increase pulling speed in tangent to max 40 fpm.;Reduce pulling rate from 4735'to 4500'to 10 fpm to allow potential hole unload.Saw no increase in cuttings @ shakers,continue BROOH @ 30-40 fpm w/full drilling rate.;Shakers consistently showed light to moderate fine sand/silt during backreaming operations.;Last survey 7542'MD/Inc 86.51°/Az 183.8°/TVD 3916'.Currently 19'below the line,10'left.Projected formation tops came in 20' low.4.01 slide hrs,3.77 rotate hrs.;Hauled 798 bbls cuttings to MP G&I for total=5176 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 1040 bbls from B-Pad creek for total=7060 bbls Daily losses 0 bbls to formation for total=0 bbls III . oc 7/$ e 91 11/4/2017 Continue to BROOH f/3904'.600 gpm/1850 psi,40 rpm/10-12 Tq Pulling 35 fpm.See increase in cuttings @ 2450'.Slow pulling speed to 20 fpm.@ 2000' see erratic Tq&several 25K Tq stalls.;Limit pulling speed to 10 fpm with substantial amount of cutting @ shakers. BROOH to 700'(HWDP)and attempt to POOH on elevators and observe swabbing.Pump OOH from 700'to 400'.;POOH on elevators f/400'to surface.L/D BHA.Bit Graded 3-3-BT-A-X-2-SD- TD.;Clean and clear Rig Floor.Pull Wear Bushing.;R/D DP handling equipment.RU Volant/CMT Swivel.RU Bail extensions.RU power tongs.PU CSG handling equipment.R/U fill up line.;Note:Replace centrifuge#2 feed pump worm drive.Replace Drag Chain pillow block bearings.Clean both MP suction screen chambers.;PJSM,M/U shoe track(FS,FC,Baffle). Bakerlok shoe track. Check floats(good). RIH wl 9-5/8",L-80,DWC,40#casing F/surface-T/ 1032'MD. Saw slight diminished returns.;HES cmt rep witness makeup of shoe track(Shayne Bitton). Verify pipe count @ 195 in shed prior to start. Flashlight float equipment(good). Isolated on pit#4 for active. Up/Dn wts every 20 jts.;Condition mud @ 1032'MD. Stg up to 6 BPM,56 psi. Dropped return mud vis from 150 to 90 vis. Continue RIH.;Continue RIH w/9-5/8"casing Fl 1032'-T/2883'MD. Running speed 10-30 fpm as hole allows. Saw diminished returns(75%returns for displacement)even with min running speed.;Condition mud @ 2883'MD. Stg up to 6 bpm,105 psi,39%flow with 0 losses. Recip pipe. Mud out was 150 vis,9.5 MW. Circulate lx btms up while treating mud to reduce vis and wt.;Continue RIH w/9-5/8"casing F/2883'-T/3295'MD. Tag @ 2936',wash thru @ 4 bpm. Continue without issue. Fill every 5 and circulate down every 10 jts.;Hauled 465 bbls cuttings to MP G&I for total=5632 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 560 bbls from B-Pad creek for total=7620 bbls Daily losses 0 bbls to formation for total=0 bbls 11/5/2017 Continue Run casing washing down from 3290'to 4635'.4 bpm/125 psi. At 3300'PU/SO/Rot 180K/60K/110 w/4 bpm.At 4635'see 50K over pull.;CBU from 4635'staging up to 6 bpm.Working pipe slowly.No losses on circulation.No change in cuttings.Getting back fine sands.;Attempt to run casing w/o washing down,ran 3 jts and started pushing fluid away,w/set downs.Continued washing down w/rotary @ 7 rpm/20K stalls when not moving pipe.Wash/Ream casing down to 4695'.;.PU ESCMTR thread lock pin end.PU JT on top of CMTR and threads galled half way through MU.Had to LID 2 bad jts and ESCMTR.Made up back up CMTR with no issues.;Continue to wash casing down from 4738'to 5688'. 4 BPM,175 psi.;CBU F/5688'(End of Tangent with no losses or change in cuttings to surface.;Continue wash and ream 9-5/8"casing down F/5688'-T/7169'MD. Inc max tq from 20k to 25k @ 7150'to re-establish rotation while running in. Wash dn @ 4 bpm,350 psi,35%flow,2-5 rpm.;Continue wash down 9-5/8"casing F/7169'-T/7572'MD. Inc pump rate to 5 BPM,390 psi with better pipe movement washing down. 2-5 rpm,23k tq while slacking off. Stall without no up/dn movement.;Circulate and condition mud @ 7572'MD. Unable to break over initially with a max up 420k. Slackoff 54k. At 2000 stks into btms up we were able to break over w/a up wt of 375k/60k dn.;Consistent light to moderate fine sand/silt @ shakers. Circulated a total of 2.5x btms reciprocating pipe 290k up,68k dn(final),6 BPM,420 psi circ thru cmt line.Reduce MW F/ 9.4 to 9.2.;Full returns while circulating. R/D bail extensions,elevators,power tongs and clear equipment from rig floor while circ and condition mud. Blowdown cmt line back to HES trucks.;PJSM,Shut down and turnover to HES cmtrs. Flood lines,P/T lines 1k low/4k high(good),Mix and pumping 10.5#tuned spacer at time of report.;Hauled 285 bbls cuttings to MP G&I for total=5917 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 560 bbls from B-Pad creek for total=8180 bbls / Daily losses 0 bbls to formation for total=0 bbls ®1.6 X G Sd Pe[ 1ZZ- _s s. 11/6/2017 Pump 1st stage CMT: Pump 53.6 bbls 10.5 ppg tunned spacer with red dye 5 bpm/138 psi.Load by pass plug.;Wjix and pump 620 sxs(271.2 bbls)Extenda Cern Lead Cement at 11.7 pkg. Mix and pump 390 sxs(79.3 bbls)Swift CemTail Cement at 15.8 ppg.Load/Drop shut off plug.;Displace cmt w/20 bbls FW f/Cmt Unit.Rig Pump 291 bbls,9.2 ppg mud. Cmt Unit 80 bbls FW. Rig Pump 180 bbls 9.2 ppg mud. Total Displacement @ 571 bbls.Catch cmt @ 270 bbls away.;Bump plug with 500 psi over 775 psi FCP.Hold 1275 psi.Floats held.CIP CD_10:10._Maintain full returns through out job.Using rig pump,stage J pressure up 3000 psi,shear open ES Cementer.;Circulate through Stage tool staging up to 5 bpm,bringing all of Spacer and 64 bbls green CMT to surface. ilfri Over boarded Total of 165 bbls contaminated Mud/64 bbls cmt.Circulate additional bottoms up.;Blow down cement line,Flush all surface equipment with black water.Continue tot circulate through ESCMTER while prepping for 2nd stage Cement.;PJSM for 2nd stage cmt job w/cmtrs,Mud eng,Peak supportand drilling crew. Wet lines w/5 bbls fresh H2O,P/T lines 1k low/4k high(test good).Pump 60 bbls 10.5#Tuned spacer III(2 bpm).;Pump 453 sxs Type"L"permafrost cmt,10.7#,4.33 yld,349 bbls(4.2 bpm).Saw good lead cmt back at surface 325 bbls(50 bbls early).Pun)p 270 sxs class"G"cmt,15.8#,1.166 yld,56.1 bbls (2.3 bpm);Drop ES cmtr closing plug and follow with 20 bbls fresh H2O.Turnover displacement to rig. MP#1,Pump 176.6 bbls 9.2 spud mud @ 5 bpm then V 9 reduce rate to 2 bpm for final 20 bbls. 2 bpm,FCP 770 psi.;Bump @ 196.9 bbls(196.6 bbls calc).Psi up to 2000 psi.Felt good shift close ES stg tool.Hold 5 min @ 2025 psi. Bled back 1.5 bbls with no flow. CIP @ 23:05 hrs. 28.4 bbls lost to formation.;Flush cmt lines and stack w/black water. Blowdown cmt t..y service line to unit. R/D Weatherford casing CRT.;N/D diverter system. Open rams and flush.Close and tighten.N/D flange and lift stack. Ctr casing in 6 i wellhead. Set slips w/150k as per wellhead rep.Cut and dress csg stump. Cut off jt=29.33'.;N/D diverter"T". Flush annular with blac ater,remove riser.;Hauled 1686 bbls cuttings to MP G&I for total=7603 bbls i_ 1,4 5 �- A-.€4 Hauled 0 bbls H2O from 6 mile lake for total=0 bbls �� j3i3 Ls y ,, Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 560 bbls from B-Pad creek for total=8740 bbls 0 (°r te Daily losses 28.4 bbls to formation for total=28.4 bbls p 3s® ,r.,,if L '1 11/7/2017 N/D Diverter,Remove Tee from cellar,Make final cut on stump, 38'Cut joint. N/U Multi Bowl,Set DSA,Set stack.Test void seaallssY@"`5`00/2472 psi.TQ up bA' stack&Multi bowl.M/U Choke and kill lines.;R/U Drip pan,Pitcher nipple&Install Mouse hole.R/U Accumulator lines.Energize stack and function test same. Continue pit cleaning.;R/U elevators and prep rig floor.R/U testing equipment.Set Test plug.Flood stack and found leak in multi bowl.Tighten same. p.R Changed leaking air boot on pitcher nipple.;Perform shell test to 3000 psi good. Wait on state man.Perform derrick inspection.Attempt to shim derrick but jack V would not lift derrick.;Test BOPS as per AOGCC to 250/3000 psi w/5"test jt. Test witnessed by Adam Earl with AOGCC.All test passed. Perform alarm test LS and PVT good.R/D and B/D test equipment.;5 min hold to/hi,chart and record same.Perform Koomey drawdown test-Start psi=3050,Drawdown psi=1525, 200 psi inc=19 secs,full charge=78 secs.6 bottles NO2 avg=2265 psi.;lnstall 10"ID wear bushing. Bring BHA tools to floor. PJSM,M/U 8.5"drillout BHA- 8.5"milltooth,mtr,NM float(ported plunger),UBHO,std NM flex,HWDP w/combo jars=650.52'total Iength;Single in w/30 jts of 5"NC50 drill pipe Fl 650'- T/1591'MD. Drift singles w/2.83"rabbit.;Continue trip in hole out of derrick F/1491'-T/2785'MD.;Fill pipe and wash down F/2785'-T/tag depth of 2844' MD. Drill cmt and ES stage tool F/2844'-T/2858'MD(stg tool on depth). Drill w/350 gpm,480 psi,40 rpm,6.6k tq,2-8k WOB.;Wash and Ream thru ES stage tool 4x w/drilling parameters T/2906'MD. Trip thru 2x with no pump or rotary(clean). Test csg to 2k psi w/5 min hold after drilling out ES cmtr(good). B/D TDS.;Attempt to RIH. Tagged up @ 2906'MD 2x. Attempt to wash past(plugged string). Troubleshoot surface equipment(good). Drain stack verify annular opened correctly(good).;Work pump and string to unplug(no go). Rack back stand. Establish circulation and stage up 350 gpm,480 psi(no issues). M/U std#37 and establish circulation.;Wash down F/2906'-T/2970'without issue. 350 gpm,480 psi,49%flow,40 rpm,6.6k tq. 68k dn,103k up,83k rot.;Continue RIH F/2973'-T/4856'MD.;Single in with DS-50 F/4856'-T/7435'MD.;Hauled 645 bbls cuttings to MP G&I for total=8248 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 700 bbls from B-Pad creek for total=9440 bbls Daily losses 0 bbls to formation for total=28.4 bbls • • �� 11/8/2017 Circ DP Volume,Test casing to 3000 psi,Good test. Blow down surface equipment.;Drill cmt and FE F/7482'T/7582'.Tag on depths. Drill rat hole and 20 of new formation T/7602'. Displace on the fly while drilling new formation.;Pull in to casing and finish displacing to Baradril N 8.9 ppg mud.40 RPM,400-500 GPM,Monitor well.Static.;Perform FIT to 12 ppa.631 psi.Good test. Bled down to 580 in 10 min.;Service rig.;Pump slug.Short trip. F/7558'T/5737'.;Drop Memory Gyro tool.Wait 15 min and pump down @ 2 bpm,95 psi,3 BPM @ 160 PSI. No pressure increase.;RIH F/5737'T/7561'. Kelley up and pump slug @ 7572'.Wash down while pumping T/7602'MD. 6.5 BPM/455 psi.;Turn on memory Gyro. Shoot starting svy @ 7550'(Svy depth). Monitor well(static). B/D TDS. POOH as per Gyro rep F/7602'-T/5294'MD.;Continue POOH F/5294'-T/575'MD as per Gyro. Clean pulling past ES cmtr.;RIH as per Gyro F/ 575'-T/1024'MD. Due to inclination shift and having to overlap svys. Shoot svys as per HES Gyro.;POOH as per Gyro F/1024'-T/650'MD.;UD BHA F/ 650'-T/surface.Rack back HWDP,Jars and NM flex DC's. Drain mtr,B/O bit and LID same. Bit grade-1,1,WT,A,I,E,NO,BHA. Hole took proper displacement for trip.;Clean and clear rig floor. Bring BHA tools to rig floor. Process Gyro surveys and email to well planner.;PJSM,M/U NOV 8.5"PDC w/ HYC near bit stabilizer,Geo pilot,MWD,DM collar,TM collar,NM float. Upload MWD. RIH w/lx std NM flex,lx std HWDP,jars,1 jt HWDP= (270.49'total length).;Shallow pulse test(good). Trip in hole out of derrick with 5"NC50 drill pipe F/270'-T/2450'MD.;Fill pipe and break circulation @ 2450'MD. 453 gpm,630 psi,54%flow. Break in Geo Pilot starting @ 5 rpm,increase every min by 5 rpm with a max rpm 50. Rotate @ 50 rpm 20 mins.;Continue RIH F/ 2450'-T/4135'MD.;Hauled 941 bbls cuttings to MP G&I for total=9188 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 280 bbls from B-Pad creek for total=9720 bbls Daily losses 0 bbls to production formation for total= 0 bbls 11/9/2017 P/U 5"DS 50 F/4162'T/7560'.;Circ&condition.Fill pipe.Prep for slip&cut.;Slip&cut drilling line.;Service rig.;Wait on L-39 Gyro Survey. Rigging up wire line on L-39. Build Gyro tools. Rig Projects.TD PMs,Block PMs,Mud Pump PMS,Scrub Rig Floor,Skate and pit room. Change bearings in drag chain.;Wait on orders @ 7524'due to anti collision issues with offset wells. Gyro offset wells to QC BHL's. Cir @ 300 gpm,500 pis to extend battery life in MWD tools.;Work on housekeeping,painting project throughout rig. Finish install&paint exhaust fan in hopper rm.;Continue wait on orders @ 7524'MD. Cir @ 300 gpm,500 pis to extend battery life in MWD tools. Finish Gyro offset well L-39. Process Gyro information&email to well planner around 3 am.;Work on re planning directional plan to clear offset wells. P/U remaining 7 jts DS-50 from shed. Continue performing preventative maintenance on equipment throughout rig.;Hauled 0 bbls cuttings to MP G&I for total=9188 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 100 bbls from B-Pad creek for total=9820 bbls Daily losses 0 bbls to production formation for total= 0 bbls 11/10/2017 Wait on New directional plan approval for plan#12. Work on 7 518 Casing, Change lube pump relief valve on the TD. Circ&Condition @ 300 GPM to save MWD battery Iife.;Drill ahead Fl 7602'T/7926'324'@ 92 FPH average.500 GPM,120 RPM,16K TQ. 1060 PSI,10 ECD.;Drill ahead F/7926'T/8311'385' @ 64'FPH average.Drilled concretions F/7925'-7940'&8023'T/8026'.540 GPM,120 RPM,17K TQ.MW 9.1,ECD 10.4 Drilled Concretions @ 0 Deflection staging up wt.;Drill ahead using WP12- F/8311'T/8822'511'@ 86'FPH average.Drilled concretions @ 0 deflection. Reduced flow rate to increase assy performance and build to 93°as per Geo.;500 gpm,1390 psi,59%flow,120 rpm,19k tq on,10.3 ECD's,500u Avg BGG. Pumped tandem 25 bbls lo vis&Io wt/hi vis&hi wt sweep @ 8502'MD w/200%increase(1000 stks late/62 bbls).;Take check shot @ L-39 close approach depth 8323'MD w/no magnetic interference. Next close approach L-36 @ 9685'MD.;Drill ahead geosteering F/8822'T/9414'592'@ 99'FPH average.540 gpm,1550 psi,60%flow,140 rpm,20k tq on,10.4 ECD's,500u Avg BGG.;Pumped tandem 25 bbls Io As&to wt/25 bbls hi vis&hi wt sweep @ 9002'MD w/200%increase(1000 stks late /62 bbls).Lost 5/0 wts @ 9128'MD without rotation.8 BPH seepage losses to hole avg.;The highest gas in the past 24hrs was 1,674 units.11 concretions were encountered with a thickness of 45'(2.49%of the lateral).;Last svy @ 9188',91.35°Inc,194.72°Az,3866'TVD.Distance to plan-1'low,5.7'left(WP 12).;Hauled 342 bbls cuttings to MP G&I for total=9530 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 280 bbls from B-Pad creek for total=10100 bbls Daily losses 120 bbls to production formation for total= 120 bbls Ditch magnets 10 lbs metal for day=10 lbs total for well 11/11/2017 Drilling Ahead 8.5 Directional hole Ff 9414'T/9944'530'@ 88 FPH Average.540 GPM @ 1625 PSI. WOB 6.TQ 22.5K @ 130 RPM MW 9.1,ECD 10.6.;Shut in L-36 @ 9400'TI 9800'. Never saw magnetic interference. Brought well back on line.Pumped Tandem Sweep @ 9510'50%Increase in cuttings.;Drilling Ahead 8.5 Directional hole F/9944'T/10437' 493'@ 82 FPH Average.540 GPM @ 1725 PSI. WOB 2-6K.TQ 22.5K @ 130 RPM.MW 9.1, ECD 10.8.Pump Tandem Sweep @ 10020'100%Increase in cuttings.;Drilling Ahead 8.5 Directional hole F/10437'T/11052' 615'@ 103 FPH Avg.540 GPM @ 1725 PSI. WOB 3-7K.TO 23K @ 120 RPM.MW 9.2,ECD 10.9.;Pump Tandem Sweep @ 10504'150%Increase in cuttings(1200 stks late)Pump Tandem Sweep @ 11015'100%Increase in cuttings(1200 stks late)500u BGG avg.;Drilling Ahead 8.5 Directional hole F/11052'T/11645' 593'@ 99 FPH Avg.540 GPM @ 1900 PSI. WOB 3-8K.TO 23K @ 120 RPM.MW 9.2,ECD 10.9.;Pump Tandem Sweep @ 11519'25%Increase in cuttings(1600 stks late).;The highest gas in the past 24hrs was 1,645 units.22 concretions were encountered with a total thickness of 82'(2.08%of the lateral)for well.;Last svy @ 11324',92.09°Inc,190.3°Az,3791'ND.Distance to plan-5'high,20.8'Right(WP 12).;Hauled 456 bbls cuttings to MP G&I for total=9986 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 700 bbls from B-Pad creek for total=10800 bbls Daily losses 18 bbls to production formation for total= 138 bbls Ditch magnets 3 lbs metal for day=13 lbs total for well 11/12/2017 Drilling Ahead 8.5 Directional hole F/11645'T/12025' 380'@ 63.5 FPH Avg Hold back ROP to 150 Back reaming two or three times.540 GPM @ 1930 PSI. WOB 3-8K.TQ 25K @ 120 RPM.MW 9.1,ECD 10.8.;Drilling Ahead 8.5 Directional hole F/12025'T/12400' 395'66@ FPH Avg Hold back ROP to 200 FPH. Back reaming once times. 540 GPM @ 1950 PSI. WOB 3-8K.TQ 25K @ 120 RPM.MW 9.1,ECD 10.7.;Pumped Tandem Sweep @ 12035'.Minimal increase in cuttings and came back 1000 stks Iate.;Drilling Ahead 8.5 Directional hole F/12400'T/12903' 503' @ 84 FPH Avg.550 GPM @ 1880 PSI. WOB 3-8K.TQ 26K @ 120 RPM.MW 9+,ECD 10.9.;Pumped Tandem Sweep @ 12535'.150%increase in cuttings and came back 1700 stks Iate.;Drilling Ahead 8.5 Directional hole F/12903'T/13471' 568' @ 95 FPH Avg.535 GPM @ 1840 PSI. WOB 3-8K.TQ 27K @ 120 RPM.MW 9+,ECD 10.9.;Pumped Tandem Sweep @ 12966'.100%increase in cuttings and came back 1700 stks Iate.;The highest gas in the past 24hrs was 1,833 units.32 concretions were encountered with a total thickness of 123'(2.13%of the lateral)for Iateral.;Last svy @ 13148',92.65°Inc,192.91°Az,3727'ND.Distance to plan-9.5'high, 11.5'Right(WP 12).;Hauled 627 bbls cuttings to MP G&I for total=10613 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 840 bbls from B-Pad creek for total=11640 bbls Daily losses 115 bbls to production formation for total= 253 bbls Ditch magnets 3 lbs metal for day=15 lbs total for well • • 11/13/2017 Drilling Ahead 8.5 Directional hole Fl 13471'Tl 13783' 312' 52@ FPH Avg.535 GPM @ 1840 PSI. WOB 3-8K.TQ 28K @ 120 RPM.MW 9+,ECD 10.9. Brought lubes up to 2%.;Drilling Ahead 8.5 Directional hole F/13783'T/14160' 377' 62© FPH Avg.535 GPM @ 1920 PSI. WOB 3-10K.TQ 29K @ 120 RPM.MW 9+,ECD 11.Sweeps @ 13510.100%INC&14035 150%inc.;Drilling Ahead 8.5 Directional hole F/14160'T/14591' 431'@ 72 FPH Avg.520 GPM @ 2000 PSI. WOB 3-10K.TQ 28K @ 120 RPM.MW 9+,ECD 11.3.;Pumped tandem sweep @ 14535'w/minimal inc. Came back 2200 stks late(137.5 bbls).Continue increasing lubes to 4%by TD.;Drilling Ahead 8.5 Directional hole F/14591'T/14800'MD(TD). 209' @ 70 FPH Avg.520 GPM @ 2000 PSI. WOB 3-10K.TQ 29K©120 RPM.MW 9+,ECD 11.4.;Pumped Tandem Sweep©14800'. Minimal increase in cuttings and came back 1300 stks late.;Circulate and condition mud©14800'MD(TD). Rot and Recip. 550 gpm,2080 psi,64%flow,130 rpm,25k tq,85 bgg after btms up.Continue increase lubes to 4%. Screen up to 200's.;The highest gas in the past 24hrs was 1,623 units.53 concretions were encountered with a total thickness of 209'(3%of the lateral)for total lateral.;Extrapolation to TD @ 14800',94.13°Inc,193.31°Az,3668'ND.Distance to plan-15'high,3'Right(WP 12).;Hauled 342 bbls cuttings to MP G&I for total=10955 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 700 bbls from B-Pad creek for total=12340 bbls Daily losses 163 bbls to production formation for total= 416 bbls Ditch magnets 8 lbs metal for day=23 lbs total for well 11/14/2017 Circ and condition @ 550 GPM @ 130 RPM 1988 PSI. ECD 11.3-11.5.Lost MP#2 Blow motor.;Circ @ Reduced rate 360 GPM 1127 PSi. Blinded shaker screens off on btm up from shutting the pumps down.Change MP#2 Blower motor.;Circ and condition Staging up pumps to 550 GPM©150 RPM 1988 PSI as shakers would allow. 20 bph Loss.Getting very fine sand and silt back on shakers. Take PST test before and after the shakers.;Slow pump rate to 400 gpm 150 RPM for one circ.Same results.20 BPH losses. Bring pumps back up to 500 GPM 120 RPM&circ&condition.;After 10 BTM up Tests failed on the flow line and past after passing through the shakers. Consult Drilling and completion engineer and decide to circ until 2130 or two passing screen test on btm ups.;Continue to Circ and condition pumping 500 GPM,1800 psi©150 RPM,24k tq w/losses slowing to 5 bph, seeing very fine sand and silt back on shakers. Take PST test before and after the shakers.;1900 hrs,MW in/out 9.1/9.1+,PST results in/out=9.52 sec passing/33.9 plugged @ 950 ML failed 1st test on flow out.;2130 hrs MW in/out 9+/9.1,PST results out=11.18 sec plugged @ 300 ML,failed 2nd test on flow out. 2200 hrs Notify Engineer of test results.Obtain SPRs on both mud pumps.;UD pup jt,rack 1 std back to 14725'.M/U top drive.Circ and condition pumping 500 GPM,1800 psi©150 RPM, 25k tq w/losses 4-5 bph.Continue taking PST tests before and after shakers.;01:00 hrs PST results out=plugged©700 ml through tester on 1st test on flow out(after pulling 1 stand and circulating past bottoms up).;04:00 hrs PST results out=plugged @ 150 ml through tester on 1st test on flow out,continues to pass on flow in.Load,Unpack and prep production screens in pipe shed.;Hauled 171 bbls cuttings to MP G&I for total=11126.25 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 560 bbls from B-Pad creek for total=12900 bbls Daily losses 94 bbls to production formation for total= 510.1 bbls Ditch magnets 11 lbs metal for day=34 lbs total for well 11/15/2017 Circ and condition pumping 500 GPM,1800 psi @ 150 RPM,25k tq w/losses 4-5 bph.Continue taking PST tests before and after shakers.All tests failed from flow line and passed under the shakers.;Pump Tandem High/Low sweep around with no increase in cuttings. Came back 2200 stks late.;Monitor well. While changing Liner in#1 MP. Slight returns with the pumps off tapering off to 0 in 30 min. Continue to circ @ 360 GPM while waiting on MP#1.;Back ream out of the hole @ 500 GPM 100 RPM @ 5 min std as per well Program. F/14800'T/12335'(treat mud POOH)MBTs coming up in the mud.Getting fine solids back.Slow backreaming to treat mud.;Back ream out of the hole @ 500 GPM,1650 psi,100 RPM @ 5 min std as per well Program. F/12335'T/10373' continue to treat mud POOH);Back ream out of the hole @ 500 GPM,1350 psi,100 RPM @ 5 min std F/10373'T/8350' (continue to treat mud POOH)No issues.Loss rate currently©2 bph BROOH.;Hauled 287 bbls cuttings to MP G&I for total=11413.25 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 420 bbls from B-Pad creek for total=13320 bbls Daily losses 92 bbls to production formation for total= 602.1 bbls Ditch magnets 10 lbs metal for day=44 lbs total for well 11/16/2017 Back ream out of the hole Fl 8251'T/7552'. 500 GPM,100 RPM,5 min per stand.;Started getting cuttings back last 200'in to the shoe.Good cuttings in returns while pulling through heal. Silt&sand. Slight pack off Backreaming into the shoe.Work back through with no torque;Pump tandem sweep @ 550 GPM 100 RPM. Getting lots of cuttings through btm up and first sweep brought back 50%increase. Pump second sweep with Minimal cuttings.Cleaned up good.Take PST&passed.;Circ another btm up and second PST past. MW,9.0 vis 43. Clean magnets.20LBS for the last 12 hrs.;Service the rig.Monitor the well.Slight returns tapering off to 0 in 30 Min.Repair ground wire on TD lube pump.;RIH on elevators Fl 7552'T/12146'. Fill pipe @ 10005'&12210. Fill pipe. No more down wt. 2 bbl loss for the trip in.;Wash and ream F/12146'T/14790'@ 260 GPM,750 psi,40 RPM.M/U 15'pup jt,wash and ream tag bottom @ 14800',no fill.No losses reaming in the hole.Pumps on P/U/ROT 158/100.;Pump tandem sweep,30 bbl low vis 8.9 ppg,30 bbl hi vis 10.6 ppg,500 gpm,1840 psi,40 RPM,reciprocate pipe slow 65'.Sweep back 1450 stks late,25%increase of fine sand/silt.BU gas 689u.;Circulate bottoms up,perform PST test from flowline,results out=8.15 sec passing/10.29 sec passing/plugged off at 19.09 sec 500 ML-failed,Circulate another BU,Maintain 4%lubes.;Perform 2nd PST test from flowline,results out=9.5 sec passed/plugged©17.19 sec,500 ML-failed.UD 15'pup jt,flowcheck well,slight returns,tapering off.Notify town engineer of PST results.;Backream out f/14800'to 14500'@ 500 gpm,1750 psi,40 rpm @ 600 fph.;Hauled 228 bbls cuttings to MP G&I for total= 11641.25 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 560 bbls from B-Pad creek for total=13880 bbls Daily losses 50 bbls to production formation for total= 652.1 bbls Ditch magnets 20 lbs metal for day=64 lbs total for well 11/17/2017 Back ream out of hole f/14500'to 7555'pumping 500 gpm,1700 psi,80 rpm.work thru heel section 40 rpm,ream into shoe w/no issues. 46 bbl losses BROOH.;Pump 30 bbl hi vis sweep,circulate 9 5/8"casing clean pumping 550 gpm,1520 psi,100 rpm,reciprocate pipe,Sweep returned 300 stks late w/some small pieces of siltstone and some increase in sand.;Continue circulating until clean returns at shakers-4.5 full circulations total.PJSM,pump 40 bbl hi vis 11 ppg spacer and displace w/615 bbls 9.1 ppg brine 8.5 bpm 670 psi f/7555'.;Top off pits 1 thru 5 with 366 bbls mud,load remaining 300 bbls mud returns onto vac trucks,dump spacer interface,circulate until clean brine @ returns. Note:no losses while circulating.;Blow down top drive,fill trip tank w/brine.Flowcheck well 15 min,static,drop 2.375"drift on wire.(Vac trucks offload 300 bbls of 9 ppg mud into upright tank).;POOH f/7555'to 6964'racking 5"DS50 drill pipe in derrick.Riser boot not holding air,Change out air boot on riser. POOH fl 6964'to 4476'racking 49 stds 5"DS50 drill pipe in derrick.;Continue POOH f/4476'to 3617'UD 5"NC50 drill pipe. Correct displacement on trip so far.;Hauled 342 bbls cuttings to MP G&I for total=11983.25 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 420 bbls from B-Pad creek for total=14300 bbls Daily losses 46 bbls to production formation for total= 698.1 bbls Ditch magnets 20 lbs metal for day=91 lbs total for well • S 11/18/2017 POOH L/D 5"NC50 drill pipe f/3360'to 270'@ BHA,flow check well,static.Cull out 83 jts NC50 for hard banding.2 bbl losses on trip out.;Submit BOP test notification to AOGCC @ 7:04 AM ON 11-18-17.Test witness waived by MR Chuck Scheve with AOGCC @ 07:43 AM, Verbal phone call.;L/D BHA,recover drift on wire. L/D HWDP,jars and NMFCs,Note:missing internal snap ring on jar mandrel.Plug in and upload MWD data.Change to completion AFE: 1713438C ©12:00 HRS;Hauled 0 bbls cuttings to MP G&I for total=11983.25 bbls Hauled 0 bbls H2O from 6 mile lake for total=0 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls;Hauled 0 bbls from B-Pad creek for total=14300 bbls Daily losses 2 bbls to production formation for total= 700.1 bbls Ditch magnets 0 lbs metal for day=91 lbs total for well • Hilcorp Energy Company Composite Report Well Name: MP L-53 Field: Milne Point County/State: ,Alaska (LAT/LONG): :vation(RKB): API#: Spud Date: 10/29/2017 Job Name: 1713438C MPL-53 Completion Contractor AFE#: 1713438C AFE$: Acttvit...L#ate ...............:.................:.:......NE:..........:..:.:.:........................................... ,,...: ««x :. 11/18/2017 Finish uploading MWD,LtD remaining BHA,8 1.2"PDC bit grade=1-3-CT-T-X-I-BT-TD Note:Severe wear on ADR IL stab,also damage to wear band,Clean and clear rig floor,Load out pipe shed.Remove 10"ID wear bushing.,R/U to test BOPE. AOGCC inspector C.Scheve waived test witness @ 07:43 ON 11-18-2017.Install test plug and 5"test jt,flood lines and stack with water.Perform body test to 3000 psi,good.Test annular,upper and lower 2 7/8 x 5 1/2 VBR,upper and lower IBOP,2 FOSVs, Dart valve,choke man valves,mud cross valves,blind ram to 250 psi low,3000 psi high 5 min ea,charted.,Perform accumulator drawdown test,check N2 bottles. Perform electric and manual choke bleed test.No failures.Blow down lines,R/D test equipment. Rig electrician calibrate and test gas alarms,check PVT.,Install 10"ID wear bushing,RI4LDS.Hang blocks,slip and cut 101'drg line,reset and test crown saver.,Ready rig floor for P/U 4 1/2"lower completion.M/U safety jt with FOSV and XOs,stage on short side of shed.R/D hawk jaw and L/D same.,Load Weatherford equipment to rig floor,inspect and R/U Power tongs and handling equipment.Verify pipe count matches 4.5"lower completion tally.,PJSM with all parties involved,cover well control plan for RIH with screens. Discuss torque specs.P/U and run 4.5 completion per tally,P/U shoe track w/float shoe,WIV valve,XO and drillable packoff bushing,XO, M/U 1 jt 13.5 HTTC solid,563 x HTTC XO pup.P/U and RIH with 4 1/2"petroguard mesh screen installing slip on centralizers on every screen.TQ to 7830 ft/lbs,use BOL 4010 pipe dope.,Utilize dog collar clamp on 1st 30 jts ran,RIH to 5264'(124 screens ran) Correct displacement TIH„Hauled 228 bbls cuttings to MP G&I for total=12211.25.25 bbls Hauled 140 bbls H2O from 6 mile lake for total=140 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls,Hauled 140 bbls from B-Pad creek for total=14440 bbls Daily losses 3.5 bbls to production formation for total= 697.5 bbls Ditch magnets 7 lbs metal for day=98 lbs total for well 11/19/2017 711L.Z430' ,P/U 6 Joints of 4.5 13.5#HTTC solid pipe.Set liner in upstroke.107K.,R/D 4/5 handling equipment. R/U 2 3/8 equipment with false bowl. Break down safety joint for screens and M/U safety joint for 2 3/8 inner string.,PJSM with weatherford&baker to P/U 2 3/8 inner string. Drift with 1.773 drift. M/U 2 3/8 slick stinger&RIH with 173 joints T/5350'.,Continue to P/U,drift and RIH w/2 3/8”inner string ff 5350'to 7408'(238 jts)P/U 65K,S/O 45K,M/U jt 239,No go out 4.92'on jt 239,LLD jts 238 and 239.space out,M/U 10',8'and 6'pups=24.40'putting 10'slick stick thru packoff.M/U swivel assy.C/O to 5"elevators.P/U safety jt w/FOSV,Triple connect and swivel.M/U to 2 3/8"work string.MLU top drive,remove false table.,Break circulation,displace 9.1 brine w/516.5 bbls 9.05 ppg mud f/7411'@ end of mule shoe below packoff staging pump to 4.8 bpm,2400 psi. While circulating load 27 6 1/4"drill collars and 48 jts HWDP into pipe shed,strap and tally same.,L/D safety jt,XOs and triple connect.Blow down top drive. P/U Liner tools,M/U swivel on running tool w/7"x 9 5/8"SLZXP LTP,44,100 lbs shear force,M/U to stump.M/U HTTC connection,verify 8 shear screws hyd setting tool set @ 2648 psi.M/U 1 std 5"DP.RIH to 7531', PU/SO 123k/93k,M/U top drive,set top drive tq @ 8k,rotate 6 rpm 7500 ft/lbs,ROT 114k.,Pump 10 bbls at 2 bpm,650 psi to ensure good flow path.Blow down top drive. R/U Hawk Jaw.,RIH f/7534'to 9075'with lower completion conveyed on 5"stds DP @ 60 fpm run speed,easy in and out of slips.Fill every jt on the fly. Record P/U and SIO every 500'.,Hauled 57 bbls cuttings to MP G&I for total=12268.25.25 bbls Hauled 140 bbls H2O from 6 mile lake for total=280 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls,Hauled 0 bbls from B-Pad creek for total=14440 bbls Daily losses 0 bbls to production formation for total= 697.5 bbls Ditch magnets 0 lbs metal for day=98 lbs total for well 11/20/2017 RIH F/9075'Tf 10995'with lower completion conveyed on 5"stds DP @ 60 fpm run speed,easy in and out of slips.Fill every jt on the fly.Record P/U and SIO every 500'.,Change handling equipment to 4"and make up safety joint. P/U 27-6 1/4 Collars. FL 10995'T/11825'. Final do wt 70K.,Change handling equipment back to 5".RIH with 5"DP F/11825'T/12240'.Losing slack off wt. Circ DP Tubing volume @ 1500 PSi max,3 BPM. RIH Ft 12240'T/ 13083'.,P/U HWDP,F/13083'T/13331'. on elevators. NO down wt left. P/U 213.,Continue to P/U HWDP,Wash and ream down F/13331',T/13580'. 2 BPM,830 PSI 10 RPM 10K TQ set. Work down with slight rotation.,Continue to P/U HWDP,wash and ream down F/13580',T/14491'pumping 2 bpm staging to 3 bpm,1350 PSI 10 RPM 10K TQ set. Work down slow with slight rotation.,Continue to P/U HWDP(48 jts HWDP total)wash and ream down pumping 2.75 bpm, 1250 PSI 10 RPM 10K TQ set. Work down slow with slight rotation F/14491',T/14569', Drift and RIH w/stds from derrick f/14569'to 14758',MLU last stand wash and ream tagging bttm on depth @ 14800'.Verify pipe count in derrick. P/U to 225k,tag bttm again.P/U to up weight @ 225k.24 bbl losses running completion to bttm.,Park with string in tension on bttm @ 14800'putting TOL @ 7340',circulate and condition staging pump to 140 gpm, 1700 psi w/shakers clean.,PJSM,Displace to 9.1 brine 145 gpm,1750 psi(pump limit set @ 1750 psi).Gained pressure when brine started into 2 3/8"work string,back stks off on pump to 117 gpm,1700 psi.,Hauled 644 bbls cuttings to MP G&I for total=12912.25.25 bbls Hauled 140 bbls H2O from 6 mile lake for total=420 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls,Hauled 0 bbls from B-Pad creek for total=14440 bbls Daily losses 24 bbls to production formation for total= 721.6 bbls Ditch magnets 0 lbs metal for day=98 lbs total for well • • 11/21/2017 Continue to Displace mud with 9.1 ppg Filtered Brine;over displaced the well(gauged hole)an additional 242,returns thinned out to a 28FV but never became crystal clear.Ran the PST test on the returned fluid and the Production Screen Test Passed Successfully.,Blow down TD Monitor well while transfer Brine from Tank farm to Vac Trucks. Note:Lost facility Power @ 11:00 hrs.Put camp and rig on Generator Power.Static losses @ 2 bph.,Pump additional String Volume.Drop Ball,chase ball on seat @ 3 bpm/1740 psi.Ball on seat @ 99 bbls pumped.Step pressure up to 3900 with MP.Continue with test pump to 5000 psi and hold.Observed no indication of set @ surface.S/O to 40K,PU to 280K w/no free travel. Blow down TD and RU to test casing.,Test Annulus to top of Packer to 1500 psi and chart for 30 minutes.Test Good. Bleed down and line up to pump down Drill string.,Attempt to release from packer,staging MP to 3900 psi and take over with test pump to 5100 psi.5/O to 40K,PU to 280K with no free travel.Start left hand release procedure.Decision made to left hand release.Work to LH Wraps down hole f/40K to 170K x4.PU to 190K w/free travel.PU—10'and pull slick stick out of Pack Off.Well went on vac.,Bring on pump @ 4.5 bpm/3400 psi and pump liner volume x2.Took 44 bbls to fill hole after un stinging from pack off.Lost a total of 173 bbls during course of both the liner volume and annulus displacements.,Monitor well on trip tank with 30 bph static loss rate.POOH and set back 4 stands DP f/14736'to 14553'.,Monitor well on trip tank,30 bph loss rate,POOH w/LRT UD 5"HWDP f/14533'to 14354'.,Monitor well,Mix up 190 bbls 9 ppg brine,pull 290 bbls f/upright and offload into pits.more brine on its way f/mud plant.,POOH UD 5"HWDP f/14354'to 13083'(48 jts HWDP)Continue POOH UD 5"DP to 11825'@ Drill collars,C/O handling equipment.M/U safety jt.PJSM for UD DCs.Static Loss rate continues @ 30 bph.,POOH f/11825'to 10995'UD 27-6 1/4"DCs.Break down DC safety jt.C/O handling J equipment.POOH UD 5"drill pipe f/10995'to 9232',POOH to 7450'racking 28 stds 5"DP in derrick. Monitor well,Static Loss rate reduced f/30 bph.to 18 bph after DCs were UD.,Inspect and UD LRT and X/Os.R/U false table.C/O to 2 3/8"handling equipment.Monitor well,static loss rate 18 bph.,Hauled 2357 cbbls cuttings to MP G&I for total=15269.25.25 bbls X „, auled 140 bbls H2O from 6 mile lake for total=560 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls,Hauled 1400 bbls from B-Pad creek for total=14580 bbls Daily losses 272.2 bbls to production formation for total= 993.8 bbls 11/22/2017 Finish RU Weatherford casing.UD liner running tool. Pusher tool was activated as was the LH Release.LID 2 3/8”inner string f/7411'to surface.UD slick stick.Dope all connections and flush jts with fresh water.,R/D Weatherford,RU Hawk Jaw. Prep rig floor and Pipe shed.,Service TD,Blocks,Crown,Hawk Jaw,and Drawworks. Loss rate at 30 bph.,PU and MU 3 1/2"EUE Stinger and XO's to DP.,TIH with Stinger on 5"DP f/Surface to 7321',116 stds, M/U stand 117,M/U top drive,Loss rate 20 bph TIH lost 32 bbls.,Pump 3 bpm, 18 psi,wash down entering TOL @ 7339.84',wash down pumping 9 ppg brine cleaning up seal bore to 7352',putting end of stinger 12'into seal bore,pump 50 bbls,PUH above TOL @ 7321'while pumping, pump another 20 bbls,14 bpm 630 psi. Rack 1 std back,M/U TD.,Pump 14 bpm,630 psi,reciprocate pipe 60',pump 562 bbls,clean at shakers,perform passing PST.PJSM,Displace well w/515.6 bbls clean 9 ppg filtered brine 10 bpm,330 psi,dump returns until clean brine @ shakers. Perform final passing PST.143 bbl Losses while circulating and displacing.,Blow down top drive,monitor well for 30 minutes,slight flow diminishing to no flow and remaining static.,POOH w/stinger UD 5" drill pipe f/7321'to 1200'.17.5 bbls over calc displacement at this point.,Hauled 228 bbls cuttings to MP G&I for total=15497.25 bbls Hauled 350 bbls H2O from 6 mile lake for total=910 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls,Hauled 70 bbls from B-Pad creek for total=14650 bbls Daily losses 399 bbls to production formation for total= 1392.8 bbls 11/23/2017 POOH w/stinger UD 5"drill pipe f/1200'to surface. UD stinger.Static loss rate @ 15 bph.,Monitor well,drain stack,pull 10"ID wear bushing.R/U hole fill on annulus,observed slight flow with stack drained,fill stack again and visually observed fluid dropping.Well is dead.,Drain stack to blind rams,close blind rams, C/O upper rams,remove VBR and install 7 5/8"casing rams.C/O swivel packing.Clear rig floor.,Open blind ram,R/U and attempt to test casing ram,pull test ,/ plug,C/O seal,re-install test plug,attempt to test again,cycled and flushed mud cross valves,get good test on 7 518"casing rams to 250 psi low and 3000 psi A's' p p high 5 min each,charted. R/D test equipment.,R/U and make hanger dummy run per well head rep, 24.66'RKB.,R/U to run 7 5/8"casing,M/U crossover to \ SV,PJSM with all parties involved,review plan for well control.Note:production lost turbine,put rig on gen power @ 16:30.,P/U and run 7 5/8"tie back per \siv tally,P/U tie back seal assy,8.25"nogo locator,XO and pup,P/U and RIH w/7 5/8"Vam,STL,29.7#L-80 casing f/19.11'to 3497'(88 its ran)Torque turn connections to optimum @ 5349 ft/lbs. Utilize dog collar clamp on every It.use BOL 2000 pipe dope. Loss rate @ 11.5 bph.,Continue to P/U and run 7 5/8"tie back as per tally f/3497'to 7308'(183 jts total)verify pipe count,25 jts left out.M/U jt 184 w/drive sub,X0 and 5'pup,M/U top drive. 141.5 bbl losses RIH \ ,`di w/csg. PU/SO 160/106.,Pump 3 bpm,5 psi,wash down ff 7308'entering TOL @ 7339.85',Locate bottom seal w/increase pump pressure,shut down pump, NO GO out @ 7349.44',P/U to up wt @ 160k,close annular,pressure up backside to 500 psi testing seals,good.Bleed off pressure,Prep to space out 1'off NO GO.,Hauled 567 bbls cuttings to MP G&I for total=16064.25 bbls Hauled 0 bbls H2O from 6 mile lake for total=910 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls,Hauled 0 bbls from B-Pad creek for total=14650 bbls Daily losses 113.9 bbls to production formation for total= 1680.7 bbls 11/24/2017 Space Bullet seals:XO Csg to DP,RIH and make space out tag.No Go mule shoe out @ 7349'. Locate TOL @ 7340'.UD Tag Joint 184&JT 183.Install 11.88'space out pup.PU Jt 183,MU Csg Hgr with pup and Landing Joint.Land out,XO landing jt to DP,MU Top Drive,Close bag and PT Annulus to 500 psi to ensure proper space out and seal engagement.,Bleed pressure to 250 psi,strip up hole until pressure dumped,exposing seal ports to annulus.,Using the Kill Line,Establish reverse circulation through ported seals with fluid from rig pits.Line up on and pump 72 bbls Corrosion inhibited 9.0 ppg KCL,chase surface lines with 10 bbls Brine.Turn over to LRS and pump 60 bbls DSL through middle annulus valve.,Strip in hole and land out Tie back seals Assy 1.47'off no go w/Mule Shoe @ 7348'.,Open bag,drain stack, R/D Reversing equipment,Pull landing joint,Monitor well breathing but continually slowing down.Monitor until static. MU,Land and test pack off to 500/3000 psi.,LRS PT 9 5/8"x 7 5/8"Annulus to 1000 psi on chart for 30 min..R/D LRS.Monitor well for 30 minutes before changing UPR's.Well @ 32 bph loss rate.,Change UPR back to 2 7/8"x 5 1/2"VBR's.RU and test UPR, LPR and Annular to 250/3000psi on 2 7/8"pipe size. All test good.RD Test equipment.,Service Rig,monitor well with trip tank,static loss rate 8 bph.,Clear and clean up rig floor.Prep for completion.Spot ESP Spooler.,RU to run 2 7/8"ESP completion:Load ESP components in pipe shed.RU tubing handling Equipment.PJSM, Hang ESP cable sheave in derrick, string ESP cable thru sheave.Setup capillary spools, 1 on on rig floor,other on spool unit.Ready XOs on FOSV.,PJSM with all parties involved,discuss well control plan with motor and pump across BOP,ESP cable contingency plan for shutting in well.,PU Mtr and build pump assy as per Centrilift Rep,centralizer, phoenix XT sensor,CL5 Mod XP motor,lower and upper tandem seals,gas seperator,Service Mtr,fill and service Seal assy.M/U tandem pumps,discharge head and pup jt. Install check valves on centralizer and M/U 2-3/8"capillary lines.Test cap lines,function check valves @ 1500 psi.bleed off psi,install 4 motor clamps,M/U MLE to mtr,test same.,lnstall 4 seal clamps,1 mtr protectolizer,4 pump clamps„M/U 1 jt 2 7/8”EUE tbg,2.313"XN nipple w/2.205 NO GO, P/U and RIH w/3 jts 2 7/8"6.5#L-80 EUE tbg,M/U GLM w/dummy,pup jt above and below to 248',P/U and RIH w/2 7/8"ESP completion to 1487'(44 jts ran) Install canon clamp on first 10 jts ran,then on every other jt.Test cable continuity and cap lines every 2000'. Monitor well w/trip tank,Losses @ 10 bph, 47 bbl losses RIH.,Hauled 57 bbls cuttings to MP G&I for total=16121.25 bbls Hauled 0 bbls H2O from 6 mile lake for total=910 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls,Hauled 100 bbls from B-Pad creek for total=14750 bbls Daily losses 231.4 bbls to production formation for total= 1912.1 bbls • • 11/25/2017 Continue to run 2 7/8"ESP completion 1755'to 4800'as per Tally.,MU Tubing Hanger.Terminate control lines.Make penetrator splice.Rig down ESP/Tubing handling equipment while making splice. Blow Down Choke and kill lines.RID Sheaves.Land Tbg Hgr.RILDS,Set TWC.PU Wt 69K/SO Wt 50K(Including 35K Block Wt.)Completion landed with 15K on Hanger. Well Losses©10 bph.,N/D BOPE:Pull Bell Nipple,R/D Choke and Kill Hoses and flange together. R/U Bridge Cranes. Bleed Koomey, R/D Koomey Hoses. Pump hot flush thru kelly hose and blow down same.Hoist stack up and set back same.,Remove DSA.Orient and install tree.Torque flange bolts.Terminate capillary lines.Test hanger void as per wellhead rep to 500 psi low for 5 min,5000 psi high for 10 min,good.R/U and test tree with diesel to 250 psi low for 5 min,5000 psi high for 5 min,slight bleed off on high test,no visual leaks,cycle valves,and re-test,good.,Centralift rep make final ESP checks,BHP=1393, Motor temp=59 deg,Balanced @ 2.5 ohms,Meg @ 13.43 G ohms.R/D test equipment,pull TWC.Secure tree.Flush lines in pits,kill line,choke line and choke manifold w/water, Fill tires on catwalk module. Note:production will freeze protect when rig is off well.,Drain liner wash on both mud pumps, disassemble mud pump fluid ends to ensure dry for rig move.Pressure wash tree,vac out cellar box,vac out sumps,cleanup cellar area.PJSM, Bridal up and scope down derrick. Finish cleaning pits,blow down water lines.Disconnect pit interconnects.Prep pipe shed for move.,Rig released f/MP L-53 @ 06:00.,Hauled 456 bbls cuttings to MP G&I for total=16677.25 bbls Hauled 0 bbls H2O from 6 mile lake for total=910 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls,Hauled 0 bbls from B-Pad creek for total=14750 bbls Daily losses 46 bbls to production formation for total= 1958.7 bbls • • Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-53 50-029-23586-00-00 E" Sperry Drilling Definitive Survey Report 15 November, 2017 I IM HALLIBURTON Sperry Drilling • r Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: a Well MPU L-53 Project: Milne Point TVD Reference: MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Site: M Pt L Pad , MD Reference MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Well: MPU L-53 ; North Reference: True Wellbore: MPU L-53 Survey Calculation Method: Minimum Curvature Design: MPU L-53 " Database: -,,,f-,e,;' - 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 L-53 Well Position +N/-S 0.00 usft Northing: 6,031,932.37 usft Latitude: 70°29'53.204 N +EI-W 0.00 usft Easting: 544,641.12 usft Longitude: 149°38'5.751 W Position Uncertainty 0.00 usft Wellhead Elevation: 41.60 usft Ground Level: 15.10 usft Wellbore MPU L-53 Magnetics Model Name Sample Date Declination Dip Angle Field Strength nT BGGM2017 10/9/2017 17.50 81.03 57,497 Design MPU L-53 g Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.50 Vertical Section Yf. ' Depth From(ND) +N/-S +E/-W E < Direction t, (usft) ': (usft) (usft) . rr (°) ,. 26.50 0.00 0.00 211.85 Survey Program Date 11/15/2017 71`" , Fifs ` it From To ,, ,, �� :; . .„ usft (usft) Survey(usft) (Wellbore) Tool Name Description Survey Date 43.00 7,550.00 SDI Drop Gyro(MPU L-53) 2_Gyro-NS-CT Drop H038Ga:Continuous dropped into a drill collar 11/07/2017 7,612.44 14,718.96 MWD+IFR2+MS+sag(Lateral)(MPU L-5 2_MWD+IFR2+MS+Sag A013Mb:IIFR dec&multi-station analysis+sag 11/10/2017 ;., `' - i 444144114.1444 VA:4W,'4,44`44,44-444444144444;44' '4 444L4' Map Map Vertical ' . MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section fAFfitil (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.50 0.00 0.00 26.50 -15.10 0.00 0.00 6,031,932.37 544,641.12 0.00 0.00 UNDEFINED 43.00 0.16 250.10 43.00 1.40 -0.01 -0.02 6,031,932.36 544,641.10 0.97 0.02 2_Gyro-NS-CT_Drop(1) 104.00 0.21 255.92 104.00 62.40 -0.06 -0.21 6,031,932.30 544,640.91 0.09 0.17 2_Gyro-NS-CT_Drop(1) 166.00 0.56 245.06 166.00 124.40 -0.22 -0.60 6,031,932.15 544,640.53 0.57 0.50 2_Gyro-NS-CT_Drop(1) 228.00 1.04 239.65 227.99 186.39 -0.63 -1.36 6,031,931.73 544,639.77 0.78 1.25 2_Gyro-NS-CT_Drop(1) 288.00 2.19 237.62 287.97 246.37 -1.52 -2.79 6,031,930.83 544,638.34 1.92 2.77 2_Gyro-NS-CT_Drop(1) 350.00 3.88 233.99 349.88 308.28 -3.39 -5.49 6,031,928.95 544,635.65 2.74 5.78 2_Gyro-NS-CT_Drop(I) 412.00 5.50 232.82 411.67 370.07 -6.42 -9.56 6,031,925.90 544,631.60 2.62 10.49 2_Gyro-NS-CT_Drop(1) 474.00 7.26 232.13 473.28 431.68 -10.62 -15.02 6,031,921.66 544,626.17 2.84 16.94 2_Gyro-NS-CT_Drop(I) 536.00 8.69 233.30 534.68 493.08 -15.82 -21.86 6,031,916.42 544,619.35 2.32 24.98 2_Gyro-NS-CT_Drop(1) 598.00 10.89 233.25 595.77 554.17 -22.13 -30.31 6,031,910.06 544,610.94 3.55 34.79 2_Gyro-NS-CT_Drop(1) 661.00 12.94 231.36 657.41 615.81 -30.09 -40.59 6,031,902.04 544,600.71 3.31 46.98 2_Gyro-NS-CT_Drop(1) 723.00 14.40 231.43 717.66 676.06 -39.23 -52.04 6,031,892.83 544,589.32 2.35 60.79 2_Gyro-NS-CT_Drop(1) 11/15/2017 75746PM Page 2 COMPASS 5000.1 Build 81D • . Halliburton Definitive Survey Report ,•� .. ..R". >,.Y .d".? h.n,...... -r.bSi�F...'9a33:"`3.S:s «,.,..... �Y `""' '" - ..` .."� -> '^T °a3'25's'i:A €_.,P..d5.. .Cf„£:.,� e..s^.ti+vw:.5. *4'•.�^Y� Company: Hilcorp Alaska,LLC ; Local Co-ordinate Reference: Well MPU L-53 Project: Milne Point . TVD Reference: ,` MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Site: M Pt L Pad MD Reference: _ . ' + MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Well: MPU L-53 = North Reference: True Wellbore: MPU L-53 Survey Calculation Method: Minimum Curvature Design: MPU L-53 y Database: ., Sperry EDM-NORTH US+CANADA Survey Map Map Verticals MD Inc Azi TVD TVDSS +N/-S +El-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name )' 786.00 17.19 232.85 778.27 736.67 -49.74 -65.59 6,031,882.24 544,575.84 4.47 76.86 2_Gyro-NS-CT_Drop(1) 849.00 20.78 234.79 837.84 796.24 -61.81 -82.15 6,031,870.07 544,559.35 5.79 95.85 2_Gyro-NS-CT_Drop(1) 911.00 23.86 240.77 895.19 853.59 -74.28 -102.08 6,031,857.48 544,539.49 6.17 116.97 2_Gyro-NS-CT_Drop(1) 974.00 26.29 242.25 952.25 910.65 -87.00 -125.55 6,031,844.62 544,516.10 3.98 140.16 2_Gyro-NS-CT_Drop(1) 1,037.00 28.99 243.88 1,008.06 966.46 -100.22 -151.61 6,031,831.25 544,490.13 4.45 165.14 2_Gyro-NS-CT_Drop(1) 1,099.00 32.13 246.25 1,061.44 1,019.84 -113.48 -180.20 6,031,817.82 544,461.62 5.42 191.49 2_Gyro-NS-CT_Drop(1) 1,162.00 35.62 249.94 1,113.74 1,072.14 -126.53 -212.78 6,031,804.58 544,429.12 6.43 219.76 2_Gyro-NS-CT_Drop(1) 1,225.00 38.04 252.04 1,164.17 1,122.57 -138.81 -248.49 6,031,792.09 544,393.49 4.33 249.03 2_Gyro-NS-CT_Drop(1) 1,287.00 41.05 253.73 1,211.97 1,170.37 -150.40 -286.21 6,031,780.27 544,355.84 5.16 278.79 2_Gyro-NS-CT_Drop(1) 1,350.00 43.51 254.09 1,258.58 1,216.98 -162.15 -326.93 6,031,768.28 544,315.20 3.92 310.25 2_Gyro-NS-CT_Drop(1) 1,413.00 46.17 253.54 1,303.25 1,261.65 -174.53 -369.59 6,031,755.64 544,272.62 4.27 343.28 2_Gyro-NS-CT_Drop(1) 1,475.00 48.76 252.26 1,345.16 1,303.56 -187.97 -413.25 6,031,741.94 544,229.05 4.45 377.74 2_Gyro-NS-CT_Drop(1) 1,537.00 51.35 251.07 1,384.97 1,343.37 -202.93 -458.36 6,031,726.71 544,184.03 4.43 414.25 2_Gyro-NS-CT_Drop(1) 1,602.00 54.37 248.99 1,424.21 1,382.61 -220.64 -507.04 6,031,708.71 544,135.46 5.30 454.99 2_Gyro-NS-CT_Drop(1) 1,665.00 56.36 248.76 1,460.01 1,418.41 -239.33 -555.39 6,031,689.74 544,087.23 3.17 496.37 2_Gyro-NS-CT_Drop(1) 1,728.00 57.60 249.38 1,494.34 1,452.74 -258.19 -604.73 6,031,670.57 544,038.01 2.13 538.43 2_Gyro-NS-CT_Drop(1) 1,790.00 60.58 250.44 1,526.19 1,484.59 -276.46 -654.68 6,031,652.01 543,988.17 5.03 580.31 2_Gyro-NS-CT_Drop(1) 1,853.00 62.07 251.14 1,556.42 1,514.82 -294.64 -706.88 6,031,633.52 543,936.09 2.56 623.29 2_Gyro-NS-CT_Drop(1) 1,916.00 61.75 251.31 1,586.08 1,544.48 -312.53 -759.50 6,031,615.32 543,883.59 0.56 666.26 2_Gyro-NS-CT_Drop(1) 1,979.00 60.29 250.50 1,616.61 1,575.01 -330.55 -811.58 6,031,596.98 543,831.62 2.58 709.05 2_Gyro-NS-CT_Drop(1) 2,041.00 59.81 249.97 1,647.56 1,605.96 -348.72 -862.13 6,031,578.51 543,781.18 1.07 751.16 2_Gyro-NS-CT_Drop(1) 2,105.00 59.85 250.40 1,679.72 1,638.12 -367.48 -914.19 6,031,559.45 543,729.25 0.58 794.56 2_Gyro-NS-CT_Drop(1) 2,167.00 59.65 250.89 1,710.96 1,669.36 -385.23 -964.72 6,031,541.40 543,678.83 0.76 836.30 2_Gyro-NS-CT_Drop(1) 2,230.00 59.86 250.76 1,742.69 1,701.09 -403.10 -1,016.12 6,031,523.21 543,627.54 0.38 878.61 2_Gyro-NS-CT_Drop(1) 2,293.00 61.02 250.54 1,773.77 1,732.17 -421.26 -1,067.83 6,031,504.75 543,575.95 1.87 921.32 2_Gyro-NS-CT_Drop(1) 2,356.00 61.86 250.41 1,803.89 1,762.29 -439.75 -1,119.98 6,031,485.94 543,523.91 1.35 964.55 2_Gyro-NS-CT_Drop(1) 2,419.00 59.36 250.61 1,834.80 1,793.20 -458.07 -1,171.72 6,031,467.32 543,472.29 3.98 1,007.41 2_Gyro-NS-CT_Drop(1) 2,481.00 59.36 250.53 1,866.40 1,824.80 -475.81 -1,222.03 6,031,449.27 543,422.09 0.11 1,049.03 2_Gyro-NS-CT_Drop(1) 2,544.00 59.95 250.49 1,898.23 1,856.63 -493.95 -1,273.28 6,031,430.83 543,370.96 0.94 1,091.48 2_Gyro-NS-CT_Drop(1) 2,607.00 60.14 250.04 1,929.69 1,888.09 -512.38 -1,324.66 6,031,412.09 543,319.69 0.69 1,134.25 2_Gyro-NS-CT_Drop(1) 2,670.00 61.03 249.47 1,960.63 1,919.03 -531.37 -1,376.14 6,031,392.79 543,268.33 1.62 1,177.55 2_Gyro-NS-CT_Drop(1) 2,733.00 62.38 249.13 1,990.49 1,948.89 -550.98 -1,428.03 6,031,372.88 543,216.56 2.19 1,221.59 2_Gyro-NS-CT_Drop(1) 2,795.00 62.48 249.13 2,019.18 1,977.58 -570.56 -1,479.39 6,031,352.99 543,165.33 0.16 1,265.32 2_Gyro-NS-CT_Drop(1) 2,858.00 62.24 249.12 2,048.41 2,006.81 -590.45 -1,531.53 6,031,332.79 543,113.31 0.38 1,309.73 2_Gyro-NS-CT_Drop(1) 2,921.00 62.09 248.52 2,077.83 2,036.23 -610.58 -1,583.48 6,031,312.35 543,061.49 0.88 1,354.24 2_Gyro-NS-CT_Drop(1) 2,983.00 63.58 247.91 2,106.13 2,064.53 -631.05 -1,634.70 6,031,291.58 543,010.40 2.56 1,398.66 2_Gyro-NS-CT_Drop(1) 3,046.00 62.03 248.26 2,134.93 2,093.33 -651.96 -1,686.69 6,031,270.35 542,958.55 2.51 1,443.86 2_Gyro-NS-CT_Drop(1) 3,109.00 61.33 248.66 2,164.81 2,123.21 -672.33 -1,738.27 6,031,249.68 542,907.09 1.24 1,488.38 2_Gyro-NS-CT_Drop(1) 3,172.00 61.68 248.84 2,194.87 2,153.27 -692.39 -1,789.87 6,031,229.31 542,855.61 0.61 1,532.65 2_Gyro-NS-CT_Drop(1) 3,234.00 61.98 249.15 2,224.14 2,182.54 -711.99 -1,840.90 6,031,209.41 542,804.71 0.65 1,576.22 2_Gyro-NS-CT_Drop(1) 11/15/2017 7:57:46PM Page 3 COMPASS 5000.1 Build 81D • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU L-53 Project: Milne Point TVD Reference: MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Site: M Pt L Pad MD Reference: ''• MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Well: MPU L-53 ' North Reference: True ;ZZWellbore: MPU L-53 Survey Calculation Method: Minimum Curvature Design: MPU L-53 ! Database: Sperry EDM-NORTH US+CANADA 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 3,297.00 61.83 249.65 2,253.81 2,212.21 -731.54 -1,892.92 6,031,189.55 542,752.81 0.74 1,620.28 2_Gyro-NS-CT_Drop(1) 3,360.00 60.44 250.18 2,284.22 2,242.62 -750.49 -1,944.74 6,031,170.29 542,701.12 2.33 1,663.72 2_Gyro-NS-CT_Drop(1) 3,423.00 60.83 250.45 2,315.11 2,273.51 -768.98 -1,996.43 6,031,151.49 542,649.54 0.72 1,706.71 2_Gyro-NS-CT_Drop(1) 3,485.00 62.31 249.84 2,344.63 2,303.03 -787.50 -2,047.71 6,031,132.66 542,598.37 2.54 1,749.50 2_Gyro-NS-CT_Drop(1) 3,548.00 62.03 250.18 2,374.04 2,332.44 -806.55 -2,100.07 6,031,113.30 542,546.14 0.65 1,793.31 2_Gyro-NS-CT_Drop(1) 3,611.00 60.69 250.79 2,404.24 2,362.64 -825.02 -2,152.18 6,031,094.52 542,494.14 2.29 1,836.50 2_Gyro-NS-CT_Drop(1) 3,674.00 61.32 249.89 2,434.78 2,393.18 -843.56 -2,204.07 6,031,075.67 542,442.37 1.60 1,879.63 2_Gyro-NS-CT_Drop(1) 3,737.00 61.17 249.95 2,465.08 2,423.48 -862.52 -2,255.95 6,031,056.40 542,390.62 0.25 1,923.11 2_Gyro-NS-CT_Drop(1) 3,800.00 61.52 248.88 2,495.29 2,453.69 -881.96 -2,307.70 6,031,036.65 542,338.99 1.59 1,966.93 2_Gyro-NS-CT_Drop(1) 3,862.00 61.40 249.31 2,524.92 2,483.32 -901.39 -2,358.58 6,031,016.92 542,288.23 0.64 2,010.29 2_Gyro-NS-CT_Drop(1) 3,926.00 59.74 249.59 2,556.36 2,514.76 -920.96 -2,410.77 6,030,997.04 542,236.16 2.62 2,054.45 2_Gyro-NS-CT_Drop(1) 3,988.00 61.10 249.33 2,586.97 2,545.37 -939.88 -2,461.26 6,030,977.82 542,185.79 2.22 2,097.16 2_Gyro-NS-CT_Drop(1) 4,051.00 60.93 249.23 2,617.50 2,575.90 -959.38 -2,512.81 6,030,958.01 542,134.37 0.30 2,140.93 2_Gyro-NS-CT_Drop(1) 4,114.00 59.80 249.61 2,648.65 2,607.05 -978.63 -2,564.07 6,030,938.46 542,083.23 1.87 2,184.33 2_Gyro-NS-CT_Drop(1) 4,176.00 60.25 249.94 2,679.62 2,638.02 -997.19 -2,614.46 6,030,919.59 542,032.95 0.86 2,226.69 2_Gyro-NS-CT_Drop(1) 4,239.00 60.84 249.98 2,710.60 2,669.00 -1,015.99 -2,666.00 6,030,900.49 541,981.53 0.94 2,269.86 2_Gyro-NS-CT_Drop(1) 4,302.00 61.90 249.83 2,740.79 2,699.19 -1,034.99 -2,717.93 6,030,881.18 541,929.72 1.70 2,313.40 2_Gyro-NS-CT_Drop(1) 4,365.00 59.29 250.39 2,771.72 2,730.12 -1,053.66 -2,769.53 6,030,862.20 541,878.24 4.21 2,356.49 2_Gyro-NS-CT_Drop(1) 4,427.00 61.18 250.46 2,802.50 2,760.90 -1,071.69 -2,820.24 6,030,843.86 541,827.64 3.05 2,398.57 2_Gyro-NS-CT_Drop(1) 4,490.00 61.68 250.48 2,832.62 2,791.02 -1,090.19 -2,872.39 6,030,825.06 541,775.61 0.79 2,441.79 2_Gyro-NS-CT_Drop(1) 4,553.00 63.31 249.27 2,861.72 2,820.12 -1,109.42 -2,924.85 6,030,805.51 541,723.27 3.10 2,485.81 2_Gyro-NS-CT_Drop(1) 4,616.00 62.52 249.16 2,890.40 2,848.80 -1,129.32 -2,977.29 6,030,785.30 541,670.96 1.26 2,530.39 2_Gyro-NS-CT_Drop(1) 4,679.00 61.58 249.71 2,919.93 2,878.33 -1,148.87 -3,029.39 6,030,765.44 541,618.98 1.68 2,574.49 2_Gyro-NS-CT_Drop(1) 4,742.00 61.29 250.01 2,950.06 2,908.46 -1,167.93 -3,081.34 6,030,746.07 541,567.15 0.62 2,618.09 2_Gyro-NS-CT_Drop(1) 4,804.00 61.64 250.29 2,979.67 2,938.07 -1,186.42 -3,132.57 6,030,727.27 541,516.04 0.69 2,660.83 2_Gyro-NS-CT_Drop(1) 4,867.00 62.09 250.06 3,009.38 2,967.78 -1,205.26 -3,184.84 6,030,708.12 541,463.89 0.78 2,704.42 2_Gyro-NS-CT_Drop(1) 4,930.00 63.84 249.90 3,038.02 2,996.42 -1,224.47 -3,237.56 6,030,688.60 541,411.29 2.79 2,748.56 2_Gyro-NS-CT_Drop(1) 4,993.00 63.73 249.92 3,065.84 3,024.24 -1,243.89 -3,290.64 6,030,668.86 541,358.33 0.18 2,793.06 2_Gyro-NS-CT_Drop(1) 5,056.00 63.08 250.74 3,094.05 3,052.45 -1,262.85 -3,343.68 6,030,649.58 541,305.41 1.56 2,837.16 2_Gyro-NS-CT_Drap(1) 5,119.00 62.67 251.37 3,122.77 3,081.17 -1,281.05 -3,396.72 6,030,631.06 541,252.49 1.10 2,880.61 2_Gyro-NS-CT_Drop(1) 5,182.00 62.49 250.22 3,151.79 3,110.19 -1,299.45 -3,449.53 6,030,612.35 541,199.80 1.65 2,924.10 2_Gyro-NS-CT_Drop(1) 5,245.00 61.99 248.60 3,181.13 3,139.53 -1,319.05 -3,501.71 6,030,592.44 541,147.73 2.41 2,968.29 2_Gyro-NS-CT_Drop(1) 5,308.00 61.81 247.11 3,210.81 3,169.21 -1,340.00 -3,553.19 6,030,571.19 541,096.39 2.11 3,013.25 2_Gyro-NS-CT_Drop(1) 5,370.00 61.62 247.08 3,240.18 3,198.58 -1,361.25 -3,603.48 6,030,549.64 541,046.23 0.31 3,057.83 2_Gyro-NS-CT_Drop(1) 5,433.00 61.35 247.70 3,270.26 3,228.66 -1,382.53 -3,654.58 6,030,528.05 540,995.27 0.97 3,102.88 2_Gyro-NS-CT_Drop(1) 5,496.00 60.56 248.14 3,300.85 3,259.25 -1,403.24 -3,705.62 6,030,507.04 540,944.36 1.39 3,147.40 2_Gyro-NS-CT_Drop(1) 5,559.00 61.52 248.23 3,331.35 3,289.75 -1,423.72 -3,756.79 6,030,486.25 540,893.31 1.53 3,191.80 2_Gyro-NS-CT_Drop(1) 5,622.00 61.63 248.70 3,361.34 3,319.74 -1,444.06 -3,808.33 6,030,465.61 540,841.91 0.68 3,236.27 2_Gyro-NS-CT_Drop(1) 5,685.00 61.82 249.11 3,391.18 3,349.58 -1,464.03 -3,860.09 6,030,445.33 540,790.27 0.65 3,280.55 2_Gyro-NS-CT_Drop(1) 5,748.00 60.83 249.52 3,421.41 3,379.81 -1,483.55 -3,911.80 6,030,425.50 540,738.68 1.67 3,324.42 2_Gyro-NS-CT_Drop(1) 11/15/2017 7:57:46PM Page 4 COMPASS 5000.1 Build 81D • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC , Local Co-ordinate Reference: Well MPU L-53 Project: Milne Point "TVD Reference: MPU L-53 As-Built @ 41.60usft(I-Rig KBE) 14 Site: M Pt L Pad ' MD Reference: ., MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Well: MPU L-53 c North Reference: True t Wellbore: MPU L-53 Survey Calculation Method: Minimum Curvature 41 Design: MPU L-53 Database: s_ z ` Sperry EDM-NORTH US+CANADA 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 5,811.00 61.84 248.58 3,451.63 3,410.03 -1,503.32 -3,963.42 6,030,405.42 540,687.18 2.07 3,368.45 2_Gyro-NS-CT_Drop(1) 5,874.00 63.00 245.97 3,480.80 3,439.20 -1,524.89 -4,014.92 6,030,383.54 540,635.82 4.11 3,413.96 2_Gyro-NS-CT_Drop(1) 5,937.00 64.09 243.00 3,508.88 3,467.28 -1,549.19 -4,065.81 6,030,358.94 540,585.08 4.56 3,461.45 2_Gyro-NS-CT_Drop(1) 5,999.00 62.95 239.46 3,536.53 3,494.93 -1,575.89 -4,114.45 6,030,331.96 540,536.61 5.43 3,509.79 2_Gyro-NS-CT_Drop(I) 6,062.00 64.16 235.71 3,564.59 3,522.99 -1,606.12 -4,162.05 6,030,301.44 540,489.20 5.66 3,560.60 2_Gyro-NS-CT_Drop(I) 6,125.00 66.16 232.02 3,591.06 3,549.46 -1,639.84 -4,208.20 6,030,267.45 540,443.25 6.19 3,613.59 2_Gyro-NS-CT_Drop(1) 6,188.00 66.37 229.56 3,616.42 3,574.82 -1,676.29 -4,252.88 6,030,230.73 540,398.80 3.59 3,668.13 2_Gyro-NS-CT_Drop(1) 6,251.00 65.54 226.82 3,642.10 3,600.50 -1,714.64 -4,295.76 6,030,192.13 540,356.15 4.18 3,723.33 2_Gyro-NS-CT_Drop(1) 6,314.00 66.52 223.65 3,667.70 3,626.10 -1,755.18 -4,336.62 6,030,151.35 540,315.54 4.85 3,779.33 2_Gyro-NS-CT_Drop(1) 6,377.00 69.81 219.57 3,691.13 3,649.53 -1,798.90 -4,375.42 6,030,107.40 540,277.01 7.96 3,836.94 2_Gyro-NS-CT_Drop(1) 6,439.00 71.38 216.43 3,711.74 3,670.14 -1,844.98 -4,411.41 6,030,061.11 540,241.30 5.41 3,895.07 2_Gyro-NS-CT_Drop(1) 6,502.00 71.77 213.68 3,731.65 3,690.05 -1,893.90 -4,445.74 6,030,011.99 540,207.27 4.19 3,954.74 2_Gyro-NS-CT_Drop(1) 6,565.00 73.64 210.63 3,750.38 3,708.78 -1,944.82 -4,477.74 6,029,960.88 540,175.58 5.49 4,014.88 2_Gyro-NS-CT_Drop(1) 6,628.00 77.16 206.61 3,766.27 3,724.67 -1,998.32 -4,506.91 6,029,907.21 540,146.73 8.33 4,075.73 2_Gyro-NS-CT_Drop(1) 6,691.00 78.03 202.23 3,779.81 3,738.21 -2,054.33 -4,532.34 6,029,851.05 540,121.64 6.93 4,136.72 2_Gyro-NS-CT_Drop(1) 6,754.00 78.47 200.74 3,792.64 3,751.04 -2,111.73 -4,554.93 6,029,793.53 540,099.40 2.42 4,197.39 2_Gyro-14S-CT_Drop(1) 6,817.00 77.48 198.00 3,805.77 3,764.17 -2,169.85 -4,575.37 6,029,735.29 540,079.31 4.53 4,257.55 2_Gyro-NS-CT_Drop(1) 6,880.00 78.17 194.23 3,819.06 3,777.46 -2,229.00 -4,592.45 6,029,676.05 540,062.58 5.95 4,316.81 2_Gyro-NS-CT_Drop(I) 6,943.00 80.05 190.59 3,830.96 3,789.36 -2,289.41 -4,605.74 6,029,615.57 540,049.66 6.41 4,375.13 2_Gyro-NS-CT_Drop(1) 7,006.00 79.29 186.15 3,842.27 3,800.67 -2,350.71 -4,614.76 6,029,554.22 540,041.01 7.04 4,431.97 2_Gyro-NS-CT_Drop(1) 7,069.00 79.78 181.94 3,853.71 3,812.11 -2,412.49 -4,619.13 6,029,492.42 540,037.01 6.62 4,486.75 2_Gyro-NS-CT_3rop(1) 7,132.00 79.83 181.26 3,864.86 3,823.26 -2,474.47 -4,620.86 6,029,430.43 540,035.65 1.07 4,540.31 2_Gyro-NS-CT_Drop(1) 7,194.00 80.78 181.25 3,875.30 3,833.70 -2,535.57 -4,622.20 6,029,369.33 540,034.68 1.53 4,592.92 2_Gyro-NS-CT_Drop(1) 7,257.00 79.93 181.28 3,885.86 3,844.26 -2,597.67 -4,623.57 6,029,307.24 540,033.69 1.35 4,646.39 2_Gyro-NS-CT_Drop(1) 7,320.00 82.58 181.75 3,895.44 3,853.84 -2,659.91 -4,625.22 6,029,244.99 540,032.41 4.27 4,700.13 2_Gyro-NS-CT_Drop(1) 7,383.00 84.43 181.74 3,902.56 3,860.96 -2,722.47 -4,627.12 6,029,182.43 540,030.88 2.94 4,754.28 2_Gyro-NS-CT_Drop(1) 7,446.00 84.26 181.94 3,908.77 3,867.17 -2,785.13 -4,629.14 6,029,119.76 540,029.25 0.42 4,808.56 2_Gyro-NS-CT_Drop(1) 7,520.00 85.49 182.99 3,915.38 3,873.78 -2,858.77 -4,632.31 6,029,046.12 540,026.52 2.18 4,872.78 2_Gyro-NS-CT_Drop(I) 7,550.00 87.18 183.80 3,917.30 3,875.70 -2,888.65 -4,634.08 6,029,016.22 540,024.92 6.24 4,899.10 2_Gyro-NS-CT_Drop(1) 7,612.44 89.13 185.26 3,919.31 3,877.71 -2,950.86 -4,639.01 6,028,953.99 540,020.37 3.90 4,954.55 2_MWD+IFR2+MS+Sag(2) 7,675.01 90.80 184.97 3,919.35 3,877.75 -3,013.18 -4,644.59 6,028,891.65 540,015.17 2.71 5,010.43 2_MWD+IFR2+MS+Sag(2) 7,736.94 92.77 185.49 3,917.42 3,875.82 -3,074.82 -4,650.23 6,028,829.98 540,009.89 3.29 5,065.76 2_MWD+IFR2+MS+Sag(2) 7,800.71 93.02 185.33 3,914.20 3,872.60 -3,138.22 -4,656.23 6,028,766.55 540,004.27 0.47 5,122.79 2_MWD+IFR2+MS+Sag(2) 7,863.64 92.65 184.07 3,911.09 3,869.49 -3,200.86 -4,661.38 6,028,703.89 539,999.50 2.08 5,178.71 2_MWD+IFR2+MS+Sag(2) 7,927.74 92.40 182.61 3,908.26 3,866.66 -3,264.79 -4,665.11 6,028,639.94 539,996.15 2.31 5,234.99 2_MWD+IFR2+MS+Sag(2) 7,990.36 92.03 181.31 3,905.84 3,864.24 -3,327.32 -4,667.25 6,028,577.40 539,994.39 2.16 5,289.23 2_MWD+IFR2+MS+Sag(2) 8,053.53 91.66 181.32 3,903.81 3,862.21 -3,390.44 -4,668.70 6,028,514.28 539,993.32 0.59 5,343.62 2_MWD+IFR2+MS+Sag(2) 8,116.60 91.41 181.42 3,902.12 3,860.52 -3,453.47 -4,670.21 6,028,451.25 539,992.19 0.43 5,397.95 2_MWD+IFR2+MS+Sag(2) 8,179.64 91.47 182.30 3,900.53 3,858.93 -3,516.46 -4,672.26 6,028,388.26 539,990.52 1.40 5,452.53 2_MWD+IFR2+MS+Sag(2) 8,243.07 91.04 183.32 3,899.14 3,857.54 -3,579.80 -4,675.37 6,028,324.91 539,987.79 1.74 5,507.97 2_MWD+IFR2+MS+Sag(2) 11/15/2017 75746PM Page 5 COMPASS 5000.1 Build 810 • 0 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU L-53 ii Project: Milne Point TVD Reference: MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Site: s,>,M Pt L Pad MD Reference: = MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Well: MPU L-53 North Reference: f True Wellbore: MPU L-53 Survey Calculation Method: Minimum Curvature Design: MPU L-53 Database: `,: Sperry EDM-NORTH US+CANADA Survey I Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +El-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,305.61 90.67 182.38 3,898.21 3,856.61 -3,642.25 -4,678.47 6,028,262.44 539,985.06 1.62 5,562.67 2_MWD+IFR2+MS+Sag(2) 8,368.56 90.43 181.24 3,897.61 3,856.01 -3,705.17 -4,680.46 6,028,199.52 539,983.45 1.85 5,617.16 2_MWD+IFR2+MS+Sag(2) 8,431.70 91.66 181.69 3,896.46 3,854.66 -3,768.27 -4,682.08 6,028,136.41 539,982.22 2.07 5,671.61 2_MWD+IFR2+MS+Sag(2) 8,491.85 90.98 182.93 3,895.07 3,853.47 -3,828.36 -4,684.50 6,028,076.32 539,980.15 2.35 5,723.93 2_MWD+IFR2+MS+Sag(2) 8,551.98 91.72 185.19 3,893.65 3,852.05 -3,888.32 -4,688.76 6,028,016.35 539,976.26 3.95 5,777.11 2_MWD+IFR2+MS+Sag(2) 8,612.92 92.09 187.44 3,891.63 3,850.03 -3,948.85 -4,695.45 6,027,955.78 539,969.92 3.74 5,832.06 2_MWD+IFR2+MS+Sag(2) 8,675.92 92.09 188.97 3,889.33 3,847.73 -4,011.16 -4,704.44 6,027,893.42 539,961.31 2.43 5,889.73 2_MWD+IFR2+MS+Sag(2) 8,736.69 91.72 190.91 3,887.24 3,845.64 -4,072.95 -4,715.27 6,027,831.57 539,950.86 3.14 5,947.93 2_MWD+IFR2+MS+Sag(2) 8,801.61 91.84 193.12 3,885.29 3,843.69 -4,134.46 -4,728.36 6,027,769.99 539,938.14 3.52 6,007.09 2_MWD+IFR2+MS+Sag(2) 8,864.50 92.34 194.61 3,882.99 3,841.39 -4,195.47 -4,743.42 6,027,708.89 539,923.45 2.50 6,066.86 2_MWD+IFR2+MS+Sag(2) 8,927.43 93.02 195.45 3,880.05 3,838.45 -4,256.18 -4,759.72 6,027,648.09 539,907.51 1.72 6,127.03 2_MWD+IFR2+MS+Sag(2) 8,990.27 93.64 196.01 3,876.40 3,834.80 -4,316.57 -4,776.73 6,027,587.62 539,890.87 1.33 6,187.30 2_MWD+IFR2+MS+Sag(2) 9,054.20 93.94 196.09 3,872.18 3,830.58 -4,377.87 -4,794.36 6,027,526.21 539,873.60 0.49 6,248.68 2_MWD+IFR2+MS+Sag(2) 9,117.73 92.96 196.14 3,868.35 3,826.75 -4,438.79 -4,811.97 6,027,465.19 539,856.37 1.54 6,309.72 2_MWD+IFR2+MS+Sag(2) 9,187.58 91.35 194.72 3,865.73 3,824.13 -4,506.07 -4,830.54 6,027,397.81 539,838.21 3.07 6,376.67 2_MWD+IFR2+MS+Sag(2) 9,249.02 92.59 194.29 3,863.61 3,822.01 -4,565.52 -4,845.91 6,027,338.28 539,823.19 2.14 6,435.28 2_MWD+IFR2+MS+Sag(2) 9,311.77 92.15 192.68 3,861.02 3,819.42 -4,626.49 -4,860.53 6,027,277.23 539,808.93 2.66 6,494.78 2_MWD+IFR2+MS+Sag(2) 9,375.34 91.60 191.71 3,858.94 3,817.34 -4,688.59 -4,873.96 6,027,215.06 539,795.89 1.75 6,554.61 2_MWD+IFR2+MS+Sag(2) 9,438.41 91.04 193.48 3,857.49 3,815.89 -4,750.12 -4,887.70 6,027,153.45 539,782.51 2.94 6,614.13 2_MWD+IFR2+MS+Sag(2) 9,501.52 90.55 193.93 3,856.61 3,815.01 -4,811.43 -4,902.65 6,027,092.06 539,767.93 1.05 6,674.10 2_MWD+IFR2+MS+Sag(2) 9,564.52 91.54 193.56 3,855.46 3,813.86 -4,872.61 -4,917.62 6,027,030.79 539,753.33 1.68 6,733.97 2_MWD+IFR2+MS+Sag(2) 9,627.10 91.47 193.36 3,853.82 3,812.22 -4,933.45 -4,932.18 6,026,969.87 539,739.14 0.34 6,793.33 2_MWD+IFR2+MS+Sag(2) 9,690.40 91.91 194.20 3,851.95 3,810.35 -4,994.90 -4,947.25 6,026,908.33 539,724.44 1.50 6,853.48 2_MWD+IFR2+MS+Sag(2) 9,752.61 92.90 193.67 3,849.34 3,807.74 -5,055.23 -4,962.22 6,026,847.93 539,709.83 1.80 6,912.62 2_MWD+IFR2+MS+Sag(2) 9,815.15 92.96 193.68 3,846.14 3,804.54 -5,115.91 -4,976.99 6,026,787.16 539,695.43 0.10 6,971.97 2_MWD+IFR2+MS+Sag(2) 9,878.49 92.34 194.37 3,843.22 3,801.62 -5,177.30 -4,992.32 6,026,725.69 539,680.47 1.46 7,032.20 2_MWD+IFR2+MS+Sag(2) 9,940.97 91.66 194.60 3,841.03 3,799.43 -5,237.76 -5,007.94 6,026,665.14 539,665.22 1.15 7,091.80 2_MWD+IFR2+MS+Sag(2) 10,003.63 92.40 195.37 3,838.81 3,797.21 -5,298.25 -5,024.13 6,026,604.56 539,649.39 1.70 7,151.72 2_MWD+IFR2+MS+Sag(2) 10,066.29 91.85 195.90 3,836.49 3,794.89 -5,358.55 -5,041.01 6,026,544.17 539,632.88 1.22 7,211.85 2_MWD+IFR2+MS+Sag(2) 10,129.32 92.52 196.59 3,834.09 3,792.49 -5,419.02 -5,058.63 6,026,483.60 539,615.62 1.53 7,272.51 2_MWD+IFR2+MS+Sag(2) 10,192.49 92.03 197.19 3,831.58 3,789.98 -5,479.41 -5,076.96 6,026,423.10 539,597.65 1.23 7,333.49 2_MWD+IFR2+MS+Sag(2) 10,255.26 91.78 196.89 3,829.49 3,787.89 -5,539.39 -5,095.35 6,026,363.02 539,579.63 0.62 7,394.14 2_MWD+IFR2+MS+Sag(2) 10,317.43 92.15 196.34 3,827.36 3,785.76 -5,598.93 -5,113.11 6,026,303.38 539,562.22 1.07 7,454.09 2_MWD+IFR2+MS+Sag(2) 10,379.86 91.91 196.44 3,825.15 3,783.55 -5,658.79 -5,130.72 6,026,243.42 539,544.98 0.42 7,514.22 2_MWD+IFR2+MS+Sag(2) 10,443.20 92.52 196.87 3,822.70 3,781.10 -5,719.42 -5,148.86 6,026,182.69 539,527.21 1.18 7,575.30 2_MWD+IFR2+MS+Sag(2) 10,506.07 90.98 196.43 3,820.78 3,779.18 -5,779.63 -5,166.86 6,026,122.38 539,509.56 2.55 7,635.94 2_MWD+IFR2+MS+Sag(2) 10,568.74 91.47 196.09 3,819.44 3,777.84 -5,839.78 -5,184.41 6,026,062.13 539,492.38 0.95 7,696.30 2_MWD+IFR2+MS+Sag(2) 10,630.93 90.98 195.45 3,818.11 3,776.51 -5,899.61 -5,201.31 6,026,002.20 539,475.85 1.30 7,756.04 2_MWD+IFR2+MS+Sag(2) 10,694.85 90.18 195.07 3,817.47 3,775.87 -5,961.28 -5,218.13 6,025,940.45 539,459.40 1.39 7,817.29 2_MWD+IFR2+MS+Sag(2) 10,758.27 91.29 195.26 3,816.65 3,775.05 -6,022.48 -5,234.72 6,025,879.15 539,443.18 1.78 7,878.04 2_MWD+IFR2+MS+Sag(2) 11/15/2017 7:57:46PM Page 6 COMPASS 5000.1 Build 81D • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC _ Local Co-ordinate Reference: Well MPU L-53It Project: Milne Point ' TVD Reference: MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Site: M Pt L Pad MD Reference: MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Well: MPU L-53 North Reference: True P Wellbore: MPU L-53 Survey Calculation Method: Minimum Curvature Design: MPU L-53 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) (911001 (ft) Survey Tool Name 10,820.16 93.02 196.03 3,814.33 3,772.73 -6,082.03 -5,251.39 6,025,819.50 539,426.86 3.06 7,937.42 2_MWD+IFR2+MS+Sag(2) 10,884.01 92.40 195.02 3,811.31 3,769.71 -6,143.48 -5,268.46 6,025,757.96 539,410.16 1.85 7,998.63 2_MWD+IFR2+MS+Sag(2) 10,946.86 92.77 195.36 3,808.47 3,766.87 -6,204.08 -5,284.92 6,025,697.27 539,394.08 0.80 8,058.78 2_MWD+IFR2+MS+Sag(2) 11,009.58 93.64 195.55 3,804.97 3,763.37 -6,264.43 -5,301.60 6,025,636.82 539,377.75 1.42 8,118.85 2_MWD+IFR2+MS+Sag(2) 11,072.07 93.45 195.96 3,801.10 3,759.50 -6,324.46 -5,318.54 6,025,576.70 539,361.18 0.72 8,178.78 2_MWD+IFR2+MS+Sag(2) 11,135.13 92.21 194.10 3,797.99 3,756.39 -6,385.28 -5,334.87 6,025,515.79 539,345.22 3.54 8,239.06 2_MWD+IFR2+MS+Sag(2) 11,198.37 92.52 192.62 3,795.38 3,753.78 -6,446.76 -5,349.47 6,025,454.23 539,330.99 2.39 8,298.99 2_MWD+IFR2+MS+Sag(2) 11,260.64 91.78 191.52 3,793.04 3,751.44 -6,507.61 -5,362.48 6,025,393.31 539,318.34 2.13 8,357.54 2_MWD+IFR2+MS+Sag(2) 11,324.04 92.09 190.30 3,790.90 3,749.30 -6,569.83 -5,374.47 6,025,331.03 539,306.72 1.98 8,416.72 2_MWD+IFR2+MS+Sag(2) 11,387.23 93.02 189.79 3,788.08 3,746.48 -6,631.98 -5,385.48 6,025,268.81 539,296.09 1.68 8,475.33 2_MWD+IFR2+MS+Sag(2) 11,450.20 93.33 189.82 3,784.60 3,743.00 -6,693.94 -5,396.19 6,025,206.80 539,285.75 0.49 8,533.61 2_MWD+IFR2+MS+Sag(2) 11,513.16 92.15 190.79 3,781.59 3,739.99 -6,755.81 -5,407.44 6,025,144.87 539,274.88 2.43 8,592.10 2_MWD+IFR2+MS+Sag(2) 11,576.56 91.54 192.04 3,779.55 3,737.95 -6,817.92 -5,419.98 6,025,082.69 539,262.71 2.19 8,651.48 2_MWD+IFR2+MS+Sag(2) 11,639.33 91.17 192.02 3,778.06 3,736.46 -6,879.30 -5,433.06 6,025,021.24 539,250.00 0.59 8,710.51 2_MWD+IFR2+MS+Sag(2) 11,701.93 90.49 192.31 3,777.15 3,735.55 -6,940.48 -5,446.25 6,024,959.98 539,237.18 1.18 8,769.45 2_MWD+IFR2+MS+Sag(2) 11,765.45 91.60 193.12 3,776.00 3,734.40 -7,002.44 -5,460.23 6,024,897.95 539,223.58 2.16 8,829.44 2_MWD+IFR2+MS+Sag(2) 11,828.45 91.97 193.09 3,774.03 3,732.43 -7,063.76 -5,474.51 6,024,836.55 539,209.67 0.59 8,889.07 2_MWD+IFR2+MS+Sag(2) 11,890.92 91.84 192.55 3,771.96 3,730.36 -7,124.64 -5,488.36 6,024,775.59 539,196.18 0.89 8,948.10 2_MWD+IFR2+MS+Sag(2) 11,953.67 91.10 193.04 3,770.35 3,728.75 -7,185.81 -5,502.25 6,024,714.34 539,182.66 1.41 9,007.39 2_MWD+IFR2+MS+Sag(2) 12,016.49 92.15 194.39 3,768.57 3,726.97 -7,246.82 -5,517.14 6,024,653.26 539,168.14 2.72 9,067.06 2_MWD+IFR2+MS+Sag(2) 12,079.87 91.10 195.14 3,766.77 3,725.17 -7,308.08 -5,533.29 6,024,591.91 539,152.36 2.04 9,127.62 2_MWD+IFR2+MS+Sag(2) 12,142.69 90.30 195.30 3,766.00 3,724.40 -7,368.69 -5,549.78 6,024,531.20 539,136.24 1.30 9,187.81 2_MWD+IFR2+MS+Sag(2) 12,205.56 91.79 194.95 3,764.85 3,723.25 -7,429.37 -5,566.18 6,024,470.43 539,120.20 2.43 9,248.00 2_MWD+IFR2+MS+Sag(2) 12,268.60 93.45 195.57 3,761.97 3,720.37 -7,490.12 -5,582.75 6,024,409.59 539,104.00 2.81 9,308.36 2_MWD+IFR2+MS+Sag(2) 12,330.83 92.21 196.25 3,758.90 3,717.30 -7,549.89 -5,599.79 6,024,349.72 539,087.32 2.27 9,368.12 2_MWD+IFR2+MS+Sag(2) 12,394.02 93.15 195.91 3,755.95 3,714.35 -7,610.54 -5,617.27 6,024,288.97 539,070.20 1.58 9,428.86 2_MWD+IFR2+MS+Sag(2) 12,456.72 93.09 194.97 3,752.53 3,710.93 -7,670.89 5,633.94 6,024,228.53 539,053.90 1.50 9,488.92 2_MWD+IFR2+MS+Sag(2) 12,519.31 91.23 194.37 3,750.17 3,708.57 -7,731.39 -5,649.78 6,024,167.94 539,038.43 3.12 9,548.67 2_MWD+IFR2+MS+Sag(2) 12,582.09 90.24 194.08 3,749.37 3,707.77 -7,792.24 -5,665.20 6,024,107.01 539,023.37 1.64 9,608.50 2_MWD+IFR2+MS+Sag(2) 12,645.19 91.17 194.15 3,748.59 3,706.99 -7,853.43 -5,680.59 6,024,045.73 539,008.35 1.48 9,668.59 2_MWD+IFR2+MS+Sag(2) 12,708.12 90.98 194.30 3,747.41 3,705.81 -7,914.42 -5,696.05 6,023,984.66 538,993.26 0.38 9,728.56 2_MWD+IFR2+MS+Sag(2) 12,770.63 92.46 194.72 3,745.54 3,703.94 -7,974.91 -5,711.71 6,023,924.08 538,977.97 2.46 9,788.20 2_MWD+IFR2+MS+Sag(2) 12,833.81 92.22 195.60 3,742.96 3,701.36 -8,035.84 -5,728.22 6,023,863.06 538,961.83 1.44 9,848.67 2_MWD+IFR2+MS+Sag(2) 12,897.24 93.14 196.23 3,739.99 3,698.39 -8,096.77 -5,745.59 6,023,802.03 538,944.82 1.76 9,909.59 2_MWD+IFR2+MS+Sag(2) 12,959.76 94.07 195.37 3,736.06 3,694.46 -8,156.81 -5,762.58 6,023,741.90 538,928.20 2.02 9,969.55 2_MWD+IFR2+MS+Sag(2) 13,022.83 92.53 193.95 3,732.43 3,690.83 -8,217.72 -5,778.51 6,023,680.90 538,912.63 3.32 10,029.70 2_MWD+IFR2+MS+Sag(2) 13,085.49 92.15 193.65 3,729.87 3,688.27 -8,278.52 -5,793.45 6,023,620.01 538,898.06 0.77 10,089.23 2_MWD+IFR2+MS+Sag(2) 13,148.28 92.65 192.91 3,727.24 3,685.64 -8,339.58 -5,807.86 6,023,558.88 538,884.02 1.42 10,148.70 2_MWD+IFR2+MS+Sag(2) 13,211.09 92.59 192.26 3,724.37 3,682.77 -8,400.81 -5,821.53 6,023,497.57 538,870.72 1.04 10,207.93 2_MWD+IFR2+MS+Sag(2) 13,273.39 93.39 191.75 3,721.12 3,679.52 -8,461.67 -5,834.47 6,023,436.64 538,858.14 1.52 10,266.45 2_MWD+IFR2+MS+Sag(2) 11/15/2017 7:57:46PM Page 7 COMPASS 5000.1 Build 81D i • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC t Local Co-ordinate Reference: Well MPU L-53 Project: Milne Point si TVD Reference: MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Site: M Pt L Pad ii MD Reference: MPU L-53 As-Built @ 41.60usft(I-Rig KBE) Well: MPU L-53 ="North Reference: True Wellbore: MPU L-53 1 Survey Calculation Method: Minimum Curvature Design: MPU L-53 Database: Sperry EDM-NORTH US+CANADA Survey .ii MD Inc Azi TVD TVDSS N . Vertical .z -' " '1,--4r- Map Map�� � "� ' + /-S +E/-W Northing Easting DLS Section ')' (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 13,335.65 93.27 191.35 3,717.50 3,675.90 -8,522.56 -5,846.91 6,023,375.68 538,846.07 0.67 10,324.74 2_MWD+IFR2+MS+Sag(2) 13,399.56 93.33 191.83 3,713.82 3,672.22 -8,585.07 -5,859.73 6,023,313.11 538,833.62 0.76 10,384.60 2_MWD+IFR2+MS+Sag(2) 13,462.81 91.85 190.89 3,710.97 3,669.37 -8,647.01 -5,872.18 6,023,251.09 538,821.55 2.77 10,443.78 2_MWD+IFR2+MS+Sag(2) 13,525.68 93.14 191.35 3,708.23 3,666.63 -8,708.64 -5,884.29 6,023,189.40 538,809.81 2.18 10,502.53 2_MWD+IFR2+MS+Sag(2) 13,588.33 92.34 193.09 3,705.23 3,663.63 -8,769.80 -5,897.54 6,023,128.17 538,796.93 3.05 10,561.47 2_MWD+IFR2+MS+Sag(2) 13,652.26 91.66 194.06 3,703.00 3,661.40 -8,831.90 -5,912.53 6,023,065.98 538,782.31 1.85 10,622.13 2_MWD+IFR2+MS+Sag(2) 13,714.20 92.03 193.61 3,701.01 3,659.41 -8,892.02 -5,927.34 6,023,005.79 538,767.87 0.94 10,681.01 2_MWD+IFR2+MS+Sag(2) 13,777.05 91.41 194.29 3,699.12 3,657.52 -8,952.98 -5,942.48 6,022,944.73 538,753.10 1.46 10,740.79 2_MWD+IFR2+MS+Sag(2) 13,839.94 90.98 194.76 3,697.81 3,656.21 -9,013.85 -5,958.25 6,022,883.78 538,737.69 1.01 10,800.81 2_MWD+IFR2+MS+Sag(2) 13,902.83 89.87 194.86 3,697.34 3,655.74 -9,074.65 -5,974.33 6,022,822.89 538,721.99 1.77 10,860.94 2_MWD+IFR2+MS+Sag(2) 13,966.23 90.86 194.97 3,696.94 3,655.34 -9,135.91 -5,990.64 6,022,761.54 538,706.04 1.57 10,921.58 2_MWD+IFR2+MS+Sag(2) 14,029.12 91.10 195.53 3,695.86 3,654.26 -9,196.58 -6,007.18 6,022,700.78 538,689.86 0.97 10,981.84 2_MWD+IFR2+MS+Sag(2) 14,091.47 90.05 196.11 3,695.24 3,653.64 -9,256.56 -6,024.18 6,022,640.70 538,673.23 1.92 11,041.77 2_MWD+IFR2+MS+Sag(2) 14,153.97 90.80 194.99 3,694.78 3,653.18 -9,316.77 -6,040.93 6,022,580.40 538,656.84 2.16 11,101.75 2_MWD+IFR2+MS+Sag(2) 14,216.16 91.17 194.81 3,693.71 3,652.11 -9,376.86 -6,056.92 6,022,520.22 538,641.21 0.66 11,161.23 2_MWD+IFR2+MS+Sag(2) 14,279.66 91.35 194.55 3,692.31 3,650.71 -9,438.27 -6,073.01 6,022,458.72 538,625.50 0.50 11,221.89 2_MWD+IFR2+MS+Sag(2) 14,342.31 91.23 194.37 3,690.90 3,649.30 -9,498.92 -6,088.65 6,022,397.98 538,610.22 0.35 11,281.66 2_MWD+IFR2+MS+Sag(2) 14,405.53 91.97 194.54 3,689.13 3,647.53 -9,560.12 -6,104.42 6,022,336.70 538,594.82 1.20 11,341.96 2_MWD+IFR2+MS+Sag(2) 14,468.45 90.30 194.46 3,687.89 3,646.29 -9,621.02 -6,120.17 6,022,275.71 538,579.43 2.66 11,402.01 2_MWD+IFR2+MS+Sag(2) 14,529.77 91.72 194.91 3,686.81 3,645.21 -9,680.32 -6,135.72 6,022,216.32 538,564.25 2.43 11,460.58 2_MWD+1FR2+MS+Sag(2) 14,592.45 94.07 194.40 3,683.64 3,642.04 -9,740.88 -6,151.55 6,022,155.67 538,548.78 3.84 11,520.38 2_MWD+IFR2+MS+Sag(2) 14,656.13 94.38 193.78 3,678.95 3,637.35 -9,802.48 -6,167.01 6,022,093.99 538,533.69 1.09 11,580.86 2_MWD+IFR2+MS+Sag(2) 14,718.96 94.13 193.31 3,674.29 3,632.69 -9,863.39 -6,181.69 6,022,032.99 538,519.38 0.85 11,640.35 2_MWD+IFR2+MS+Sag(2) 14,800.00 94.13 193.31 3,668.45 3,626.85 -9,942.05 -6,200.30 6,021,954.23 538,501.25 0.00 11,716.98 PROJECTED to TD mitchelliaird@halliburton.com Michael Calkins Checked By: 2017.11.1517:0026--09'00' Approved By: ''.17---7,1.7--z---- Date: 11/15/2017 11/15/2017 7:57:46PM Page 8 COMPASS 5000.1 Build 81D • Hilcorp Energy Company 411 CASING&CEMENTING REPORT Lease&Well No. MP L-53 Date Run 5-Nov-17 County State Alaska Supv. J.Lott/S.Barber CASING RECORD Surface ;r' TD 7,582.00 Shoe Depth: 7,572.00 PBTD: 7,484.68 No.Jts.Delivered 184 No.Jts.Run 184 No.Jts.Returned Ftg.Delivered 7,572.00 Ftg.Run 7,572.00 Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. Ftg.Balance RKB 26.70 RKB to BHF RKB to CHF RKB to THF Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 Float Shoe 10 3/4 40.0 L-80 DWC Antelope 1.59 7,572.00 7,570.41 1 Casing 9 5/8 40.0 L-80 DWC Valourec 41.59 7,570.41 7,528.82 1 Float Collar 10 3/4 40.0 L-80 DWC Antelope 1.30 7,528.82 7,527.52 1 Casing 9 5/8 40.0 L-80 DWC Valourec 41.25 7,527.52 7,486.27 1 Baffle Collar 103/4 40.0 L-80 DWC HES 1.59 7,486.27 7,484.68 113 Casing 9 5/8 40.0 L-80 DWC Valourec 4,626.78 7,484.68 2,857.90 / 1 ES stage Tool 10 3/4 40.0 L-80 DWC HES 3.10 2,857.90 2,854.80 t/ 70 Casing 9 5/8 40.0 L-80 DWC Valourec 2,854.80 2,854.80 0 Csg Wt.On Hook: 185,000 Type Float Collar: Conventional No.Hrs to Run: 32 Csg Wt.On Slips: 150,000 Type of Shoe: Conventional Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _Yes X No 10 Ft.Min. 9.2 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: 37 bow spring centralizer(12-1/4"OD) F/shoe up to 5634'MD. 3 bow spring centralizers on either side of ES cementer. Total of 43 bow spring centralizer in hole. CEMENTING REPORT Shoe @ 7572 FC @ 7,527.52 Top of Liner Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 10.5 Volume pumped(BBLs) 53.6 Lead Slurry Type: Extenda Sacks: 620 Yield: 2.45 Density(ppg) 11.7 Volume pumped(BBLs) 271.2 Mixing/Pumping Rate(bpm): 4 Tail Slurry w Type: Swift Cem Sacks: 390 Yield: 1.14 �' I ¢ Density(ppg) 15.8 Volume pumped(BBLs) 79.3 Mixing/Pumping Rate(bpm): 4 w Post Flush(Spacer) z Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: Spud mud Density(ppg) 9.2 Rate(bpm): 6 Volume(actual/calculated): 571/567.8 FCP(psi): 775 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1275 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: 64 ' Cement In Place At: 10:10 Date: 11/6/2017 Estimated TOC: 2,855 Method Used To Determine TOC: Cmt samples Stage Collar @ 2854.8 Type HES ES cmtr Closure OK OK Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry Type: Permafrost"L" Sacks: 453 Yield: 4.33 Density(ppg) 10.7 Volume pumped(BBLs) 349 Mixing/Pumping Rate(bpm): 4.2 Tail Slurry , es*/ 1.0 Type: Type I/11 Sacks: 270 Yield: 1.16 a(� y Density(ppg) 15.8 Volume pumped(BBLs) 56.1 Mixing/Pumping Rate(bpm): 2.3 L E Post Flush(Spacer) 8 Type: Density(ppg) Rate(bpm): Volume: Ito' Displacement: Type: Spud Mud Density(ppg) 9.2 Rate(bpm): 5 Volume(actual/calculated): 196.9/196.6 FCP(psi): 770 Pump used for disp: Rig MP#1 Bump Plug? X Yes No Bump press 2000 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: 276.6 Cement In Place At: 23:05 Date: 11/6/2017 Estimated TOC: 0 Method Used To Determine TOC: Surface samples Post Job Calculations: Calculated Cmt Vol @ 0%excess: 423 Total Volume cmt Pumped: 755.6 Cmt returned to surface: 340.6 Calculated cement left in wellbore: 415 OH volume Calculated: 423 OH volume actual: 414.6 Actual%Washout: www.wellez.net WellEz Information Management LIC ver_102716bf • a 217144 Seth Nolan Hilcorp Alaska, LLC 2 8 8 7 GeoTech \� 3800 Centerpoint Drive, Suite 100 8 RECEI 1� E , Anchorage, AK 99503 Tele: 907 777 8308 HilenrralnAL.1.I.{; Fax: 907 777-8510 E-mail: snolan@hilcorp.com DEC 15 2017 DATA LOGGED AOGCC M K. 8 .BEND6ENDER DATE 12/08/2017 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-53 Prints: ROP/ABG/DGR/EWR/ADR 2"/5" MD ABG/DGR/EWR/ADR 2"/5"TVD CD _Log Viewers 12/5/2017 3:27 PM File folder CGM 12/5/2017 3:27 PM File folder Definitive Survey 12/5/2017 3:27 PM File folder EMF 12/5/2017 3:27 PM File folder LAS 12/5/2017 3:27 PM File folder PDF 12/5/2017 3:27 PM File folder TIFF 12/5/2017 3:27 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: ;r /Date: I VOF T� 4)/.. �Iy777cv THE STATE Alaska Oil and Gas �;-s�� of LASKA Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 \Th � GOVERNOR BILL WALKER g Main: 907.279.1433 ALAS' Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manger Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU L-53 Permit to Drill Number: 217-144 Sundry Number: 317-571 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, da:(E Hollis S. French Chair 2 J DATED this day of December, 2017. RBD,,!s 1"- ELL' 1 1 2017 • 0 RECEIVED DEC 0 7 2017 STATE OF ALASKA 07 S )'2,1(3 / 7 ALASKA OIL AND GAS CONSERVATION COMMISSION AOGCC APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well O , Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing O . Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ESP Change-out 0- 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development E, 217-144 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23586-00-00 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 ❑✓ ✓ MPU L-53 • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL025509,ADL025514 &ADL025515 , Milne Point Unit/Schrader Bluff Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 14,800' s 3,668' 14,795' , 3,668' % 1,300 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 16" 107' 107' N/A N/a Surface 7,546' 9-5/8" 7,572' 3,918' 5,750psi 3,090psi Production 7,324' 7-5/8" 7,349' 3,899' 6,890psi 4,790psi Liner 7,460' 4-1/2" 14,800' 3,668' N/A N/A Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic , See Schematic 2-7/8" 6.5#/L-80/EUE 8rd 4,829' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): BOT SLZXP Liner Top Packer and N/A , 7,340 MD/3,898 TVD and N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic❑ Development 0 , Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 12/22/2017 Commencing Operations: OIL ❑✓ • 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: Paul Chan Authorized Title: Operations Manager Contact Email: pCh8r1ahIICOrp.001t1 Contact Phone: 777-8333 Authorized Signature: /7-7(77Date: 12/5/2017 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 311. 5 1 I Plug Integrity 0 BOP Test ' Mechanical Integrity Test ❑ Location Clearance ❑ Other: * 5co 15 66t 7"-j-i- Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDt S L-EC 1 (,. 2017 Spacing Exception Required? Yes EDNo {Zr Subsequent Form Required: 1 0 10 -1u APPROVED BY Approved by: dcar--\ COMMISSIONER THE COMMISSION Date: t7.. I 3 1 1- , 4( „ Pica '471/ - ('47 /2 CC-/`7 Submit Form and \�` Form 10-403 Revised 4/2017 Approved application is valid fooRtllsGnitA froyal. Attachments in Duplicate i Well Prognosis Well: MPU L-53 Hilcorp Alaska,LL) Date:12/04/2017 Well Name: MPU L-53 API Number: 50-029-23586-00 Current Status: Oil Well Pad: L-Pad Estimated Start Date: December 22"d, 2017 Rig: ASR 1 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 217-144 First Call Engineer: Paul Chan (907) 777-8333 (0) (907)444-2881 (M) Second Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) AFE Number: Job Type: ! ESP Repair Current Bottom Hole Pressure: 1,680 psi @ 3,800'TVD (Estimated Reservoir Pressure,8.5 ppg EMW) Maximum Expected BHP: 1,680 psi @ 3,800'TVD (No new perfs being added) MPSP: 1,300 psi (0.1 psi/ft gas gradient) Brief Well Summary: MPU L-53 was drilled and completed in November 2017 as a Schrader Bluff horizontal ESP producer. ESP installation history: November 2017 (initial). The ESP has a phase to ground imbalance in the power cable. Notes Regarding Wellbore Condition • CO 390A: Hilcorp Alaska respectfully requests that a packer not be required on this ESP completion as the estimated reservoir pressure is less than 8.55 ppg EMW. > Objective: IL- /(—/7 Replace failing ESP power cable. V 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 sea water down tubing,taking returns up casing to 500 bbl returns tank. 6. Confirm well is dead. Calculate KWF and circulate well dead if needed. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 7. RD Little Red Services and reverse out skid. 8. RU crane. Set BPV. ND Tree. NU BOPE. RD Crane. 9. NU BOPE house. Spot mud boat. --- • s Well Prognosis Well: MPU L-53 z1aC„r„Alaska.LLIDate:12/04/2017 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/KWF prior to pulling BPV. Set TWC. 12. Test BOPE to_250psi Low/2,500 psi High, annular to 250 psi Low/_2,50Opsi 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. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram on 2-7/8" test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 13. 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. 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 Cot � x c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor G 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. 14. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/KWF as needed. 15. MU landing joint or spear and PU on the tubing hanger. a. The PU weight during the 2017 ESP install was 69K lbs. (includes 35K block weight) b. If needed, circulate (long or reverse) pill with lubricant 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 2-7/8"tubing. Number all joints. Tubing will be re-used. Lay down ESP. a. Replace bad joints of tubing as necessary and note on tally new tubing run. b. Note any sand or scale inside or on the outside of the ESP on the morning report. 18. PU new ESP and RIH on 2-7/8" tubing. Set base of ESP assembly at±4,829' MD. a. Upper GLM @ ± 131' MD w/SO b. Lower GLM @ ±4,591' MD w/DGLV c. 2-7/8" XN (2.205" No-Go) @ ±4,701' MD • • Well Prognosis Well: MPU L-53 Hiicoru Alaska,LL Date:12/04/2017 d. Base of ESP centralizer @ ±4,829' MD 19. Land tubing hanger. RILDS. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off)weights on tally. 20. Set BPV. Post-Rig Procedure: 21. RD mud boat. RD BOPE house. Move to next well location. 22. RU crane. ND BOPE. 23. NU existing 2-9/16" 5,000#tree/adapter flange. Test tubing hanger void to 500 psi low/5,000 psi high. Pull BPV. 24. RD crane. Move 500 bbl returns tank and rig mats to next well location. 25. Replace gauge(s) if removed. 26. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Existing Tree/Wellhead 5. Blank RWO MOC Form • II • Milne Point Unit Well: MPU L-53 SCHEMATIC Last Completed: 11/25/2017 Hi"carp Alaska,LLC PTD: 217-144 Orig.KB Elev.:26.5'(Innovation) TREE&WELLHEAD Tree 5M Seaboard 2-9/16" i - fWellhead Seaboard MB-22 5M 20 i CEMENT DETAIL 1 16" 270 cf of cement in a 36"Hole Stage 1:Lead 620 sx(271.2 bbls)of 11.7#Extenda Cern Dual Tail 390 sx(79.3 bbls)of 15.8#Swift Cern 3/8 SS 9-5/8" Stage 2: Lead 453 sx(349 bbls)of 10.7#Permafrost L Cern Capstring ' Tail 270 sx(56.1 bbls)of 15.8#Type I/II Cem CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm ES Cementer`' 20" Conductor 164/A-53/Welded N/A Surface 107' @2855' 9-5/8" Surface 40/L-80/DWC 8.835 Surface 7,572' 7-5/8" Production 29.7/L-80/STL SMLS 6.875 Surface 7,349' 4-1/2 Liner 12.6/L-80/HTTC 3.875 7,340' 14,800 TUBING DETAIL Mn ID 2 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.441 Surface 4,829' 2.205"C ' 3/8" Capstring x 2 Stainless Steel N/A Surface 4,829" 4,70 t. 3 WELL INCLINATION DETAIL -'4 KOP@43' Max Hole Angle=94.1 deg.@ 14,719' 5&6 JEWELRY DETAIL li a: 7 No Depth Item l' 8&9 1 131' Sta#2:GLM-1"Side Pocket KBMM w/Orifice 2 4,591' Sta#1:GLM-1"w/Dummy 3 4,702' 2-7/8"XN-Nipple(2.205 No-go ID) 110 4 4,744' Discharge Head:FPDIS 5 4,745' Upper Tandem Pump:134 STG FLEX 17.5 i 11 6 4,768' Lower Tandem Pump:134 STG FLEX 17.5 ■�R 7 4,792' Gas Separator:GRS FER N AR 12 8 4,795' Upper Tandem Seal:GSB3DBUTSB/SB PFSA 7-5/8 9 4,802' Lower Tandem Seal:GSB3DBUT SB/SB PFSA 10 4,809' Motor:562 XP—250hp/2,505V/61A 11 4,825' Sensor,Phoenix XT150 12 4,827' Centralizer:Bottom @ 4,829' "�, _ ,,1 =13 9-5/8' 13 7,340' BOT SLZXP Liner Top Pkr w/BD Slips,7"x 9 5/8" 14 14 7,362' Crossover Sub,7"H563 x 4.5"HTTC L-80 Or 15 14,795' WIV Valve with Ball Seat 16 14,798' Round Nose Float Shoe:Bottom @ 14,800 ( GENERAL WELL INFO API:50-029-23586-00-00 Drilled,Cased and Completed by Innovation -11/25/2017 : 1 15&16 TD=14,800'(MD)/TD=3,668'(TVD) PBTD=14,795'(MD)/PBTD=3,668'(TVD) Created By:TDF 12/4/2017 H • • Milne Point Unit Well: MPU L-53 PROPOSED Last Completed: 11/25/2017 Hilcorp Alaska,LLC PTD: 217-144 Orig.KB Elev.:26.5'(Innovation) TREE&WELLHEAD Tree 5M Seaboard 2-9/16" Wellhead Seaboard MB-22 5M 20' s CEMENT DETAIL 1 pti 16" 270 cf of cement in a 36"Hole I t Stage 1:Lead 620 sx(271.2 bbls)of 11.78 Extenda Cern 3/8 t' 9-5/8" Tail 390 sx(79.3 bbls)of 15.88 Swift Cern Capsti ! Stage 2: Lead 453 sx(349 bbls)of 10.7#Permafrost L Cem if Tail 270 sx(56.1 bbls)of 15.8#Type I/II Cern CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm ES Cementer 20" Conductor 164/A-53/Welded N/A Surface 107' @2,855' k 9 -5/8" Surface 40/L-80/DWC 8.835 Surface 7,572' 7-5/8" Production 29.7/L-80/STL SMLS 6.875 Surface 7,349' 4-1/2 Liner 12.6/L-80/HTTC 3.875 7,340' 14,800 TUBING DETAIL N6n IC. 1 2 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.441 Surface 4,829' 2.205"@+f' 3/8" Cap String Stainless Steel N/A Surface 4,829" 4,702' 7 i M 3 WELL INCLINATION DETAIL }iq 4 , KOP @ 43' Max Hole Angle=94.1 deg.@ 14,719' 5&6 sr a. JEWELRY DETAIL III 7 '#st, ii No Depth Item il IN 8&9 1 1 ±131' Sta#2:GLM-1"Side Pocket KBMM w/Orifice r1; 2 ±4,591' Sta#1:GLM-1"w/Dummy ' 3 ±4,701' 2-7/8"XN-Nipple(2.205 No-go ID) 10II z 4 ±4,744' Discharge Head 5 ±4,745' Upper Tandem Pump 11 6 ±4,768' Lower Tandem Pump 7 ±4,792' Gas Separator 12 8 ±4,795' Upper Tandem Seal 7-5/8" 9 ±4,802' Lower Tandem Seal 10 ±4,809' Motor ti 4 11 ±4,825' WeIILift MGU I _ 12 ±4,827' Centralizer:Bottom @±4,829' 9-5/8'; , 13 13 7,340' BOT SLZXP Liner Top Pkr w/BD Slips,7"x 9 5/8" 14 14 7,362' Crossover Sub,7"H563 x 4.5"HTTC L-80 15 14,795' WIV Valve with Ball Seat • 16 14,798' Round Nose Float Shoe:Bottom @ 14,800 Iii GENERAL WELL INFO VIII API:50-029-23586-00-00 Drilled,Cased and Completed by Innovation -11/25/2017 11111_ '1111I 1111 :11111! 1111 lull, 15&16 TD=14,800'(MD)/TD=3,668'(TVD) PBTD=14,795'(MD)/PBTD=3,668'(TVD) Created By:TDF 12/4/2017 • • • Hilr+.rp Ala ka,;i.: Milne Point ASR Rig 1 BOPE 2017 11" BOPE Stripping Head 4.48' J-IydriI GK 11" - 5000 I#1 111fi 1 11Mil MEM III JIM! III III ClU (� �= VBR or Pipe Rams 4.54b---N —N i ° EME " 11 - 5000 H H Blind III III lit III I 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves 2.00' : . -- Man , IIII■III■III.IItt.li1 Manual ' Manual Manual HCR Updated 11/20/2017 • • WELL MPL-53 Tree Cap.Otis style,5 f" ACME 2 9/16"5K,FE,DD L-U 11-25-17 PN B15753-000 DATE SN .-,— ...... AI Swab valve Seaboard • '} Model 510, 2 9/16"5K, 0 FE,DD L-U ball= PN 564650-081 SN I Q {4,43 .` z 1 A J' L i_• Wing valve Seaboard Model 6^ 510,2 9/16"5K,FE,DD 1..-U g PN 564650-DB1 o u o e 6 SN 000 Tbg Hgr,Seaboard SM- •-- - E-CL 11 x 2 7/8" EUE _`-�J BOX top and bottom,2 i., SSV valve Seaboard Model 1/2" "H" BPV,Iea ESP, z 'To -�'-1 510, 2 9/16"5K,FE,DD L-U ported for 2 ea 3/8" 0 Control line,w/3' pup PN 353799-000 L-U,DD-NL, N 4 SN PN W12128-001 r, SN H455844 _i_ Master valve Seaboard Model Tbg Hd Adpt- � __i510,2 9/16 5K,FE,DD L-U tri= -- 4— Sea r Seaboard ESP-2CL �-14. �� � PN 564650-DB1SN 11 x 2 9/16" 5K, ill " ported for lea. ESP ._ API 11" 5K and HT, offset. ' E.-1,-- Ported - Ported for 2ea 3/ �� s 8" control lines Jim:: i,.. `''-' PN W12166-001 I�n jj ' % API 16 " 3K 9 5/8" Csg Hgr, "1 Seaboard ,° SM-B-2211 x 10.5-4 a .I � � Stub Acme top x 9 5/8" DWC BOX bottom,w/ 3'pup ( ' • LU,DD-NL PN W11840-001 I f SN I 'r 11. i • • _ a> ., y > as > Ce ts � c Oca Q ° . E Q ad E E 0) o .� -a co CD li a) Y > 47. = a) 10_— > CO E Q �, -o a) c L D O • a) 0 0 y > Y m — Q = I d () L) d A m U d a) Q Q C a� o L- t.) -0 n. 0 a) (� > a) a) Q.. c co .."00 = - 0 a) (o0 M o 0 20 o Gam) L E a o o m p 'rn (1)L o -Q 0 O a = = -a c ( " u. L L lJ 1�1 ) N. N 0 > C 0 N co 0 >o a) C a Q. U) 0 cY (0 W L w L V! 0 4 a' w o o c U Q .0 a) w co 0 E c c '�' co to o o a) aa) c 0 > a O 0. O 0 F '" O = o m x U ,_., vmcU E > L 0. o n U o in in Q ° 0 Q %, 0FTfJ • 4,4"' y/ms''s. THE STATE Alaska Oil and Gas ) - . , of e LA Conservation Commission 333 West Seventh Avenue Off, de GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ALAS, Fax: 907.276.7542 www.aogcc.alaska.gov Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU L-53 Hilcorp Alaska, LLC Permit to Drill Number: 217-144 Surface Location: 1536' FNL, 44' FWL, SEC. 8, T13N, R10E, UM, AK Bottomhole Location: 710' FNL, 946' FEL, SEC. 24, T13N, R9E, UM, AK Dear Mr. Mazzolini: Enclosed is the approved application for permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B)and Regulation 20 AAC 25.071,composite curves for well logs run must be submitted to the AOGCC within 90 days after completion,suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition,the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20,Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05,Title 20,Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P./ . oerster Commissioner DATED this 40 day of October, 2017. x -• 4 .a , me. STATE OF ALASKA ALA IL AND GAS CONSERVATION COMMIS I '). "'Ft PERMIT TO DRILL 20 AAC 25.005 ' Jt . k...., _A 1 a.Type of Work: 1 b.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp ID 1 c.Specify i well is proposed for: Drill 0• Lateral ❑ Stratigraphic Test ❑ Development-Oil 0' Service- Winj El Single Zone 0, Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry❑ Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas 0 2.Operator Name: 5. Bond: Blanket 0 Single Well❑ 11.Well Name and Number: Hilcorp Alaska,LLC , Bond No. 22035244 MPU L-53 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage AK 99503 MD: 14,617, TVD: , 3,692 Milne Point Unit • 4a. Location of Well(Governmental Section): 7.Property Designation: (SHL&TPH)ADL025509 Schrader Bluff Oil Pool. Surface: 1536'FNL,44'FWL,Sec 8,T13N,R10E,UM,AK (Lateral&BHL)ADL025514&ADL025515 . Top of Productive Horizon: 8.DNR Approval Number: 13.Approximate Spud Date: 1380'FSL,515'FWL,Sec 7,T13N,R10E,UM,AK LONS 88-002 10/22/2017 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 710'FNL,946'FEL,Sec 24,T13N,R9E,UM,AK 7637 ' 5795' 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 42.4• 15.Distance to Nearest Well Open Surface: x-544641.04 y- 6,031,932.30 Zone-4 . GL/BF Elevation above MSL(ft): 15.9 • to Same Pool: 2645'-MPU L-37A 16.Deviated wells: Kickoff depth: 5 d MD feet 3,o 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 91.66 degrees• Downhole: 1750 • Surface: 1378 ' 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 16" 164# A-53 Weld 80' 0 0 110' 110' -270 cf 12-1/4" 9-5/8" 40# L-80 DWC 7,440' 0 0 7,440' 3892' Stg#1 Lead 1523 cf/Tail 445 cf Stg#2 Lead 2047 cf/Tail 314 7-5/8" 29.7# L-80 STL SMLS 7,240' 0 0 7,240' 3,875' Tieback Assembly 8-1/2" 4-1/2" 12.6# L-80 HTTC 7,372' 7,240' 3,875' 14,612' 3,692' Cementless Screen Liner 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Hydraulic Fracture planned? Yes❑ No 0 20. Attachments: Property Plat 0 BOP Sketch 0 Drilling Program 0 Time v.Depth Plot 0 Shallow Hazard Analysis Diverter Sketch 0 Seabed Report ❑ Drilling Fluid Program 0 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 Name: Joe Engel Authorized Name: Paul Mazzolini Contact Email: iengel(p7.hilcorp.Com Authorized Title: Drilling Manager Contact Phone: 907-777-8395 1 Authorized Signature:? / / Date: 10/15/2017 ((((( Commission Use Only Permit to Drill API Number: q? // Permit Approval See cover letter for other Number: rQ I.?- i 1&I 50-093-cusstn-Go - Date: 1,0I a3(] requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: Ii( Other: L Soo es- d t-c `/ ,f. Samples req'd: Yes❑ No' Mud log req'd:Yes❑ No( ' t� yd H2S measures: Yes Er Non Directional svy req'd:Yes No❑' i(- 2 S US /5(: Afr it-X-4"1- ' S Spacing exception req'd: Yes❑ No' Inclination-only svy req'd:Yes❑ No511 4U Post initial injection MIT req'd:Yes❑ Non APPROVED BY Approved by: 62 , t i"�-- COMMISSIONER THE COMMISSION Date: /0 -2.3-/7 I/9lI � £--/d,..23./.7-- Submit Form and Form 10-401 Revise /201 This permit is valid for 24 m•nth ori 1G� t a o}al per 20 25.005(g) Attachments in Duplicate ,41 /49,4V7 VV 1 V' 6. • Joe Engel •Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 HilcorpAnchorage,AK 99524-4027 Energy Company Tl 907 777 8395 Email: jengel@hilcorp.com 10.13.2017 Commissioner Alaska Oil &Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU L-53 Dear Commissioner, Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore production well at Milne Point`L' Pad, well slot 53. Drilling operations are intended to commence approximately Oct 22, 2017, pending rig schedule. MPU L-53 is a grassroots ESP producer planned to be drilled in the Schrader Bluff NB sand. L-53 is part of a six well program targeting the NB sand. The directional plan is a catenary wellpath build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff NB sand. An 8.5" lateral section will then be drilled. A 4.5" screen liner will be run in the open hole section and the well produced with an ESP assembly. Regarding the planned ESP completion, Hilcorp Alaska respectfully asks for a variance to CO 390A Rule 3 requiring an ESP packer if the BHP gradient is greater than 8.55 ppg. The estimated reservoir pressure is 8.74 ppg EMW (1750 psi) at 3852' TVDss, 38 psi above 8.55 ppg EMW. Hilcorp calculates that the near wellbore bottom hole pressure will be below the 8.55 ppg gradient within one week of putting the well on production as calculated by a CMG reservoir model. The Innovation Rig will be used to drill and complete the wellbore. Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the drilling program for MPU L-53, which includes information required by 20 AAC 25.005 (c). If you have any questions, or require further information, please do not hesitate to contact myself(Joe Engel) at 777-8395 or jengel@hilcorp.com or Paul Mazzolini at 777-8369 or pmazzolini@hilcorp.com. Sincerely, Joe Eng el Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 • • Hilcorp Alaska, LLC Milne Point Unit (MPU) L-53 Drilling Program Version 1 10/16/2017 S Milne Point L-53 SB N Producer Hilcorp Drilling Procedure 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 Internal Reporting Requirements 5 6.0 Planned Wellbore Schematic 6 7.0 Drilling/Completion Summary 7 8.0 Mandatory Regulatory Compliance/Notifications 8 9.0 R/U and Preparatory Work 10 10.0 N/U 13-5/8"5M Diverter Configuration 11 11.0 Drill 12-1/4"Hole Section 13 12.0 Run 9-5/8" Surface Casing 15 13.0 Cement 9-5/8" Surface Casing 21 14.0 BOP N/U and Test 26 15.0 Drill 8-1/2"Hole Section 27 16.0 Run 4-1/2"Production Screen Liner(Lower Completion) 31 17.0 Run 7-5/8" Tieback 36 18.0 Run ESP Assembly-Upper Completion 39 19.0 RDMO 39 20.0 Innovation Rig Diverter Schematic 40 21.0 Innovation Rig BOP Schematic 41 22.0 Wellhead Schematic 42 23.0 Days Vs Depth 43 24.0 Formation Tops & Information 44 25.0 Anticipated Drilling Hazards 45 26.0 Innovation Rig Layout / 47 27.0 FIT Procedure 48 28.0 Innovation Rig Choke Manifold Schematic 49 29.0 Casing Design Information 50 30.0 8-1/2"Hole Section MASP 51 31.0 Spider Plot(NAD 27) (Governmental Sections) 52 32.0 Surface Plat(As Built) (NAD 27) 53 33.0 Schrader Bluff NB Sand Offset MW vs TVD Chart 54 34.0 Drill Pipe Information 5" 19.5# S-135 DS-50 & NC50 55 Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU L-53 Pad Milne Point"L"Pad Planned Completion Type ESP on 2-7/8"Production Tubing Target Reservoir(s) Schrader Bluff N Sand Planned Well TD,MD/TVD 14,617' MD/3,692' TVD PBTD,MD/TVD 14,607' MD/3,692' TVD Surface Location(Governmental) 1536'FNL, 44'FWL, Sec 8, T13N, R10E,UM,AK Surface Location(NAD 27) X= 544,641.04,Y=6,031,932.3 Surface Location(NAD 83) X= 1,684,672.14,Y=6,031,684.94 Top of Productive Horizon (Governmental) 1380'FSL, 515'FWL, Sec 7, T13N,R10E,UM,AK TPH Location(NAD 27) X=539,950.03,Y=6,029,541.68 TPH Location(NAD 83) X= 1,679,981.12,Y=6,029,294.19 BHL(Governmental) 710'FNL, 946'FEL, Sec 24, T13N, R9E,UM,AK BHL(NAD 27) X=538,528.00,Y=6,022,164.99 BHL(NAD 83) X= 1,678,559.16,Y=6,021,917.34 AFE Number 1713438 AFE Drilling Days 18 days AFE Completion Days 6 days AFE Drilling Amount $3,799,350 AFE Completion Amount $2,435,968 ' AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1378 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1750 psig Work String 5" 19.5# S-135 DS-50 &NC 50 (Weatherford Rental) KB Elevation above MSL: 26.5 ft+ 15.9 ft=42.4 ft GL Elevation above MSL: 15.9 ft BOP Equipment 13-5/8"x 5M Annular, (3)ea 13-5/8"x 5M Rams Page 2 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp [now Company Changes to Approved Permit to Drill Date: 10-10-2017 Subject: Changes to Approved Permit to Drill for MPU 1-53 File#: MPU L-53 Drilling and Completion Program Any modifications to tv1PU L-53 Drilling &Completion Program will be documented and approved below. Changes to an approved PTD 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 Rev 1 October 2017 s • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section Aik, (� r., .... ...m . k-lbs) Cond 16" 15.25" - - - A-53 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 DWC 5,750 3,090 916 Tieback 7-5/8" 6.875" 6.75" 7.625 29.7 L-80 vAM SMLsTLS 6,890 4,790 683 8-1/2" 4-1/2" 3.96 3.875 4.695 12.6 L-80 HTTC 8430 7500 288 Screens 4.0 Drill Pipe Information: ole i° 1 (in) TJ ID TJ OD Wt Grade Conn Section (in) Surface& 5" 4.276" 3.25"' 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k1b Production 5" 4.276" 3.25" 6.625" 19.5 S-135 NC50 31,032 34,136 560k1b All casing will be new,PSL 1 (100%mill inspected, 10%inspection upon delivery to TSA in Fairbanks). Page 4 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wel]Ez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Detailed Daily Plan Forwards • Distributed to jengel@hilcop.com and pmazzolini@hilcop.com 5.3 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.4 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. 5.5 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drilling Manager&Drilling Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 5.6 Casing Tally • Send final "As-Run"Casing tally to pmazzolini@hilcorp.com1 jengel@hilcorp.com and cdinger@hilcorp.com 5.7 Casing and Cmt report • Send casing and cement report for each string of casing to pmazzolini@hilcorp.com, jengel@hilcorp.com and cdinger@hilcorp.com 5.8 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 Joe Engel 907.777.8395 805.235.6265 iengel@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan(a@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Rev 1 October 2017 • Milne Point Unit lirL-53 Producer Drilling Procedure Hilcorp Energy Company 6.0 Planned Wellbore Schematic 11 Milne Point Unit Well:MPU L-53 PROPOSED S C H E M ATI C Last Completed:TBD Ifilrnre.11nrla.L.L11 PTD:TBD Ong.KBElm.:26.S'/GLElev.:15.9' TREES WELLHEAD Tree Seaboard 2-9/16"5M 1 i W'elhead Seaboard 16 3/4`3M x11'SM Muhi-bowt w/11'x 2 7/6'EUE Top acrd 16" Bottom with 2.5"COW'H'BPV profile.Zea 3/8"NPT Control lines. 1, 2 t OPEN HOLE/CEMENT DETAIL e- 16' Conductor ft >' 12-114' 415 be;Gauge Hole Volume,Planned Pump Vol:763 bb 2-7/8' • 6-1/2' CementSess screens Liner is 8-1/2"hole y CASING DETAIL L; Size -'r p- Wt/Grade/Conn Drift 0 Top Etm BPF k.,� 1' 16" Conductor 78.6/4.53/Weld Ni A Surface 114' N/A 3 9-5/8" Surface 40/1-B0(dwc 8.525 Surface 7,440' 0.0756 i' 11 7-5/8" Tieback 29 7/L-80 j Vam STL SM LS 6.750 Surface 7,240' 0.0459 11 4-1/2" Blank Pipe Liter12.6/L-BO/HTfC 3.833 7,240' 7,440' 0.0152 4M8 IS - ' 4-1/2" Liner&Screens 12.6/L-80/HTTC 3.795 7,440' 14.612' 0.0152 OP/WNW e-yea TUBING DETAIL 2-7/8" I Tubing I 6.5/L-801 WE Brd I 2.441 I Surface I 6,200' I 0.0058 ElWELL I'ICLINAT Oh.CET±_ �I - i i.. POP�550' Le Max Hole Angle=91.66 deg.rz 7579'MD ate/1 )4 / JEWELRY DETAIL 1 4 •� *1 NNo. I -0.�1.1 I item I is t upper Completion T 6 --..1 -u Ong Hanger 2.441" 1. 1 :140 GLM BK-2 Latch,1'Packing Bore 2.347" 7.5% Vim—: 3 26,100' GLM BK-2 Latch,1'Packing Bore 2.347" 2 2-6140' 5N Nipple 12 5 26 200' ESP Assembly Lower Completion 10 -±7,240' BOT Sl2)(P Liner Top Packer w/BD Slips 7^x 9-5/8' 6.200" IA11 `_7245' 7-5/6"Tieback Assy. 6.151" 12 1-7250' 7"H563 x 43'HTTC 1-80 50 3.900" ` 14 _14,532' 4-1/2"Drillable Packoff Sub 2.400" .+ 11 15 _15,612' W'.'Valve LTC 8013(1.5'Ball on Seat;Closed; - 4 Sir 1 t2 fl 4-1/2"SOLID LINER CETA 4-1/2'Screens LINER DETAIL T•3 MD'MD: Ito^(MD1 its Top{MD) Btm{MD) 5 7,210 7,440' 170 7,440' 14,530' See 51(O tk 2 14,532 14,612 So wd said 46• GENERAL WELL INFO API:no 4-1/2' e ) 14 Completion Date:T80 Shoe fa "1/b17 15 • ID-14,517(MD)/TO-3,697'(1VD} PBTD-14,612'(MD)/PIBTD-3,697'(W D( Created By WE 30.13.2017 Page 6 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 7.0 Drilling / Completion Summary MPU L-53 is a grassroots ESP producer planned to be drilled in the Schrader Bluff NB sand. J-53 is part of a six well program targeting the NB sand. The directional plan is a catenary wellpath build, 12.25"hole with 9-5/8" surface casing set into the top of the Schrader Bluff NB sand. An 8.5"lateral section will then be drilled. A 4.5"wire wrapped screen liner will be run in the open hole section and the well produced with an ESP assembly. Drilling operations are expected to commence approximately Oct 22,2017. The Innovation Rig will be used to drill and complete the wellbore. Surface casing will be run to 7,440' MD/3,892' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, a Temp log will be run between 6— 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All cuttings&mud generated during drilling operations will be hauled to the Milne Point"B"pad G&I facility. General sequence of operations: 1. MIRU Innovation to well site 2. N/U& Test 13-5/8" Diverter and 16" diverter line 3. Drill 12-1/4"hole to TD of surface hole section. Run and cement 9-5/8" surface cglsing. 4. N/D diverter,N/U &test 13-5/8" x 5M BOP. 1 s . 5. Drill 8-1/2" lateral to well TD. Run 4-1/2"production screen liner 6. Run 7-5/8"tieback. 7. Run production tubing. 8. N/D BOP,N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR+Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+ADR(For geo-steering)/ Page 7 Rev 1 October 2017 • Milne L-53 ProducerPointUnit Drilling Procedure Hilcorp Energy Company 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at(2) week intervals during the drilling and completion of MPU Valk Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. 3 ac • The initial test of BOP equipment will be to 250psi & subsequent tests of the BOP equipment will be to 250//A0O' si for 5/5 min(annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tget� Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore,AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: LA)w c'''- Hilcorp Hilcorp Alaska respectfully asks for a vslxrlice to CO 390A Rule 3 requiring an ESP packer if the BHP gradient is greater than 8.55 ppg. The estimated reservoir pressure is 8.74 ppg EMW (1750 psi) at 3852' TVDss, 38 psi above 8.55 ppg EMW. Hilcorp calculates that the near wellbore bottom hole pressure will be below the 8.55 ppg gradient within one week of putting the well on production as calculated by a CMG reservoir model. it WeLz at-4" v r et-4i-a-fi fr e rv% ; 1-/-i, 6-37' i) pik ES p e- o /-e-4 e'LS ''''' p i"c- , A.to - Flaw . rt.,,,(6Al'' . 4-.. : 6 tv s I pro ,i r., . it .z 3. /y Page 8 Rev 1 October 2017 • Milne Point Unit L-53 Producer 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 CTI Annular BOP 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 • Mud cross w/3"x 5M side outlets 8-1/2" • 13-5/8"x 5M Control Technology Single ram • 3-1/8"x 5M Choke Line Subsequent Tests: • 3-1/8"x 5M Kill line 250/3000 • 3-1/8"x 5M Choke manifold • Standpipe,floor valves,etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. 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 Rev 1 October 2017 • Milne L-53 ProducerPointUnit Drilling Procedure Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 L-53 will utilize a newly set 16" conductor on L Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Dig out and set impermeable cellar inside of existing cellar. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Install Seaboard slip-on 16-3/4" 3M"A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.5 Insure (2) 3"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off. 9.6 Level pad and ensure enough room for layout of rig footprint and R/U. 9.7 Rig mat over footprint of rig. 9.8 Confirm that the rig is over the appropriate well slot. 9.9 MIRU Innovation Rig 9.10 Mud loggers WILL NOT be used on either hole section. 9.11 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 9.12 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.13 Ensure 5" liners in mud pumps. • White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @ 96.5%volumetric efficiency. Page 10 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 10.0 N/U 13-5/8" 5M Diverter Configuration 10.1 N/U 13-5/8" CTI BOP stack in diverter configuration(Diverter Schematic in Sec 21 of program). • N/U 16" SOW • N/U 13 5/8", 5M diverter"T". • NU Knife gate & 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source ✓ • Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone"must include: • A prohibition on vehicle parking • A prohibition on ignition sources or running equipment • A prohibition on staged equipment or materials • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. Page 11 Rev 1 October 2017 H • •• Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 10.5 Rig & Diverter Orientation: Ay/, \ \ I \ \ I / +L-g52 +L-_g57 I \ i i -7254 13351 I — — .-�— I \ I / 8128 ■L9 I 1 I •24 ■25 I \ •20 1112i•'11 ■17 I ■41 ■43 L-53 + L-56 // ■45 \--a---- + L-52 + L-57 + L-54 + L-51 X32 .33 I / 13 ■ ■ 8 A 39 ■ ■ 42 1 ■ ■ 9 34 ■ • 14 3 ■ ■ 10 15 ■ ■ 47 2 ■ ■ 7 • 12 ■ 40 ■ • • • • • • • • • • • 6 35 4 36 5 37 11 50 o Li 0, cox_ i _ 0 I _ ss ) \ I MPU L-Pad \ I *Drawing Not To Scale 1 Page 12 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure Gyro MWD is R/U and operational. Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 5" Drill string, HWDP, and Jars will come from Weatherford. 11.3 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4" hole section to TD as 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. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if run through high dog legs. Keep DLS < 6 deg/ 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning,mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 600 - 650 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Ensure to leave a"Pump Tangent" section that is approx. 300' long in the directional plan. The ESP will need a straight section to sit. This will occur very near TD of the hole section. • Make wiper trips every 2000' unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability, ensure MW is at a 9.2 at TD. • TD the hole section just into the Schrader Bluff sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. • Take MWD surveys every stand drilled (60' intervals). Page 13 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company • Watch returns closely for signs of gas when near the base of the permafrost and circulate out all gas cut mud before continuing to drill. There have been no indications of hydrates on any of the "L"pad wells to date. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. 11.5 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 and TD with 9.2+ppg. • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system - with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM(10 ppb total)BARACARBsBAROFIBRE/STEELSEALs can be used in the system while drilling • the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the . high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5-9.0 range with caustic soda. Daily additions of ALDACIDE G/X- CIDE 207 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 i y Viscosity Plastic Viscosity Yield Point API FL pH Surface 8.8-9.2 )85-250 20-40 25-75 <10 8.5-9.0 Page 14 Rev 1 October 2017 I • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 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 11.6 At TD; pump sweeps, CBU, and POOH to the 20" conductor shoe. 11.7 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 —4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (600—700 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft/minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.8 TOOH and LD BHA 11.9 No open hole logging program planned. 12.0 Run 9-5/8" Surface Casing / 12.1 R/U and pull wearbushing. 12.2 Make a dummy run with the 9-5/8" casing hanger. 12.3 R/U Weatherford 9-5/8" casing running equipment(CRT& Tongs) • Ensure 9-5/8"DWC x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. Page 15 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 12.4 P/U shoe joint, visually verify no debris inside joint. 12.5 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1)Joint with float collar bucked on pin end&thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. OM* 14M • (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 16 Rev 1 October 2017 • • IIMilne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 12.6 Float equipment and Stage tool equipment drawings: "A Overall Length 1 Type H ES Cementer B Part No. lra.ID After D',!louc ,MIT 1 SO No. C relax.-0:-DI::D Mint 1 Hilcorp ES-II Idxmk+g Order D Opening Seat ID AM Closing Sleeve No.Shear Pins = I E Closing Seat ID Ia ! Opening Sleeve 1 No.Shear Pins Plug Set ES-II Cementer 1111111111.11.M ES Cementer Part No. _ Depth SO No. r Closing Plug 11111 ....H ammommi li= Bae Adapter(if used) OD ' fflShut Off lug El Opening Plug r Depth OD sank 1rI Bypass or Shut-off Baffle , I F ID il By-Pass Plug Depth Shut-off Plug ' tr,I. Float Collar a 111_11 :i Depth 1111 By pass Bank millal t--- OD Rost Collar lirl Float Shoe DeRth Bypass Plug (ifused) Milli INN Hole TD Root Shoe ''Reference Casing OD Sales Manual Section 5 Page 17 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 12.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/paint brush. • Install (1) centralizer every joint—2000' MD (Top of Ugnu) • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.8 Install the Halliburton Type H EII Stage tool so that it is positioned at least 100' TVD below the permafrost (—2,700' MD). • Install centralizers over couplings on 5 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. This will allow the tool to open at 3300 psi. 9-5/8" 40# L-80 DWC 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 18 Rev 1 October 2017 11, Milne Point Unit r-411 L-53 Producer Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Slze(O.D.): Weight(Wall): Grade: DWC/C Casing 9-5/8 in 40.00113/11(0.395 in) L-80 standard 1RM Material L-80 Grade 80,000 Minimum Yield Strength (psi) 111111111111 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 Q.D. (in) Fax:713-479-3234 8.835 Nominal Pipe Body I.D.(in) E-mail:VAMUSAsalesevam-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) -$ wry Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection 0.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter(in) 4.81 Make-up Loss (in) y1 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] Appoximated 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 19 Rev 1 October 2017 • S Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at(1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to <20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 13.0 Cement 9-5/8" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud&water can be delivered to the cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which 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 cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug)—HEC rep to witness. Mix and pump cement per below calculations for the Pt stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume+ 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated Total Cement Volume: 54 91-44"" Section: Calculation: Vol (BBLS) Vol(ft3) 12-1/4" OH x 9-5/8" Casing (6,440'- 2700')x .0558 bpf x 1.3 = 271 bbls 1523 ft3 annulus: Total LEAD: 271 bbls 1523 ft3 12-1/4" OH x 9-5/8" Casing (7440'- 6440')x .0558 bpf x 1.3 = 72.5 bbls 407.3 ft3 annulus: 9-5/8" Shoe track: 90 x .0758 bpf 6.8 38.3 Total 15.8 ppg TAIL: 79.3 bbl 445 ft3 • i Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company Cement Slurry Design: Lead Slurry Tail Slurry System ExtendaCEM TM System SwiftCEM TM System Density 12.0 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5"liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: / �rpt`- - c 7350' x .0758 bpf= 557 bbls 80 bbls of water must be left across stage tool to ensure proper operation once opened. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±3.4 bbls before consulting with Drilling Engineer. Page 22 Rev 1 October 2017 Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold,pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP <20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until 1 stage reaches sufficient compressive strength. Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume+ open hole excess (200% for lead and 100% for tail). Job will consist of lead &tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: (-X- Section: Calculation: Vol (BBLS) Vol (ft3) 16" Conductor x 9-5/8" (110') x .135 bpf x 1 = 14.8 bbls 83.6 ft3 casing annulus: 12-1/4" OH x 9-5/8" Casing (2200'- 110') x .0558 bpf x 3 = 350 bbls 1964 ft3 , �� sA. annulus: Total LEAD: 364.8 bbls 2047 ft3 12-1/4" OH x 9-5/8" Casing (2700'- 2200') x .0558 bpf x 2 = 55.8 314 ft3 annulus: Total TAIL: 55.8 bbls 314 ft3 2 7L- >• Cement Slurry Design (2nd stage cement job): Lead Slurry Tail Slurry System Permafrost L Type I/II Density 11.1 lb/gal 14.5 lb/gal Yield 4.3279 ft3/sk 1.39 ft3/sk Mixed Water 21.405 gal/sk 6.8 gal/sk Page 24 Rev 1 October 2017 • 4111 Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2700' x .0758 bpf=205 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000— 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips and L/D landing joint. 13.30 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. Pressure test packoff. 13.31 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 jengel@hilcorp.corn and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 14.0 BOP N/U and Test 14.1 N/D the diverter T, 16"knife gate, 16" diverter line &N/U 11"x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8"x 5M CTI BOP as follows: • BOP configuration from top down: 13-5/8"x 5M annular/ 13-5/8"x 5M double gate / 13- 5/8"x 5M mud cross/ 13-5/8"x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5.5" VBRs in top cavity, blind ram in bottom cavity. • Single ram should be dressed with 2-7/8" x 5.5" VBRs ✓ • N/U bell nipple, install flowline. • Install (1) manual valve &HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1)manual valve &HCR valve on choke side of mud cross. (manual valve closest to mud cross) 14.3 Run 5"BOP test assembly, 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. • Confirm test pressures with PTD • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.4 R/D BOP test equipment 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.7 Set 10" ID wearbushing in wellhead. 14.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.9 Install 5" liners in mud pumps. Page 26 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 15.0 Drill 8-1/2" Hole Section 15.1 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135 DS50 &NC50. • Run a ported float in the surface hole section. 15.2 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 tandem sweeps. Ensure 6 rpm is> 8.5 (hole diameter) for sufficient hole cleaning • Run the centrifuge continuously while drilling the production hole,this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. Page 27 Rev 1 October 2017 O II Milne L-53 ProducerPointUnit Drilling Procedure Hilcorp Energy Company System Type: 8.9—9.5 ppg Baradrill-N drilling fluid Properties: Depths Density Plastic Viscosity Yield Point Total Solids MBT HPHT 7440- 14617 8.9-9. 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Product Concentration/Function 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 BARASCAV D 0.5 ppb X-CIDE 207 0.15 b 15.3 TIH w/ 8-1/2" directional assy to stage tool. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. Drill out stage tool as follows: • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Because of aggressive nature of PDC bits, drilling with minimal WOB is recommended. Approx 2-5 k is enough. • Apply weight and allow it to drill off before applying more. • After drilling out, chase any remaining debris to bottom with the drill bit. 15.4 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. r''. o 15.5 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= 65ig/2 =—3500 psi, but max test pressure on the well is 3,000 psi. q /,�a 7- -o P Ott /' C 364 ga-rte'/ 15.6 Drill out shoe track and 20' of new formation. 15.7 CBU and condition mud for FIT. 15.8 Conduct FIT to 12 ppg EMW. Chart Test. 15.9 TIH w/ 8-1/2" directional assembly to bottom. 15.10 On-bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. Page 28 Rev 1 October 2017 Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company • 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. 15.8 Drill 8-1/2"hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 500 - 650 gpm. • RPM: 120+ • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Keep swab and surge pressures low when tripping. • Make wiper trips every 1500—2000 ft, if necessary. • Take MWD surveys every stand. • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD trends for hole cleaning indication • Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. 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. • No concretions are expected in the Schrader Bluff N Sand. 15.9 Reference: Open hole sidetracking practice: • If a known fault is coming up,put a slight"kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.10 At TD, CBU at least 4 times at maximum circulation and rotation. Pump tandem sweeps if needed 15.11 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU, Perform production screen test(PST). The mud has been properly conditioned when the mud will pass the production screen test(3 one liter samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure • Circulate and condition mud as much as needed to pass the production screen test • If unable to pass test,the hole may have to be swapped over to a new solids free mud system prior to POOH Page 29 Rev 1 October 2017 Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 15.12 TOH/BROOH with the drilling assembly to the 9-5/8" casing shoe. If backreaming is necessary: • Circulate at full drill rate (550-600 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 2 b/u once at the shoe. 15.13 Swap over to clean filtered brine in preparation for running screens, (brine weight equal to mud weight at TD) 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, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section(GR+Res). There will not be any additional logging runs conducted. Page 30 Rev 1 October 2017 • I, IIMilne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 16.0 Run 4-1/2" Production Screen Liner (Lower Completion) 16.1. 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: i I v • 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. (tel • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close " TIW valve. • Proceed with well kill operations. 16.2. In the event of an influx of formation fluids while running the 2-3/8" inner string inside the 4- 0 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. 3(0' • This joint shall be fully M/U with crossovers and available prior to running the first joint of 7- wash pipe. • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.3. R/U 4-1/2" screen running equipment. • Ensure 4-1/2"Vam HTTC x DS-50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 16.4. Run 4-1/2" screen production liner—Reference screen handling and running procedure. ' • Use API Modified or"Best 0 Life 2000 AG"thread compound. Dope pin end only w/paint brush. Wipe off excess. Thread compound and can plug the screens. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run packoff and float shoe on bottom. • 4-1/2" Screen Liner should auto—fill, top off with completion brine • If needed, install swell packers as per the lower completion tally. • Remove protective packaging on swell packers just prior to picking up • Do not place tongs or slips on the packer element • Swell packers placement±40' 4-1/2" DWC-HTTC torques Casing OD Minimum Maximum Yield Torque 4.5" 6,660 ft-lbs 9,000 ft-lbs 11,900 ft-lbs Page 31 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 1110111101111 , titrilti CxrnecUan Oab 811eek OD Weight Wall Th. Grade API Drift Connection 4112 in. 12:60Ihift 0.271 in. L80 3.833 in. VAL%HTTC C ECTCIPRCPERIES Na+_dnai 00 4.500 In. Connectlnn Type Prerrton TBC NYrJnal 0 3.959 In. Conneinon CC•ino nI 4.936 In. Naninal Cross Section Area 3.600 roe. Connection ID mom', 3.973 In. Grade Type API SCT tdxIn-ro`_oat 4_291 In. Mn.Yield 0tergtn 90 kJ Coup n0 Length 9.719 In. Max.IMO Stoic/. 95 P. Crtical'.ra.5 Section 3.501:Alf. Pan.Utmate TenVle OtrerOlr 95 kJ Taman ErtfCeroy 100%oc'pipe Tensile Yle'a Strength 25951 Structral.Compression E.1Cency 100 15 or pipe Menai rod Pressum 9:33 ps:. Carves:on E!kimryrt0515Q'API Seaaahy 90%o'pipe Collapse Pressure 7530 ps Internal Frnsur Ei"Cency 100%o`pipe Enterra Press re Elio ero: 100%o'pipe 1=to.0 TORQUE VALUES Tengle Yield SSmnpth 295 PIt L .Make-up Maim 5550 fit Shxaral Compression Reninlnere 358 kb Oct.klaker-p acrWx .7330'St Co"xress0n Restxnce with ISOJA 1 Sealablity 230 kb Mae.Make-up tangpe 9000 BM Internal Veld Pressire 9430 psi Marmum Torque wan Snail:,Ity 11902 Itt External Prra.re ReUstsice 7502 51.. Mar.Torsional Value 13900 iLt Max.053d on CC•.CIPO Face 0 kb WARS MTC'.Is a Threaded S CCupred'TIC)premium connection peering YAM'HTIC"•YME Performance Envelope extreme 1119h torque capacity cc.--..a1nlrlq sealatlIty f reliability as per API RPSCE291 T CAE to. co -"- _.__________-. .... TO '• s, Oannacllae Vent 7 SO 101n.13ByS 1431‘rare rvx E a.. L.tti 1Une t sa[6slrkc as .sra 110 IIO0%AP15C3 - -ISO -1te _171 0 23 10) LO Axial Wadi%PeYn') 1173-nor rite MO 111haat yn ..� f}uoun.rl puna,1.pnslur'-N onen.'ro otoknown t'A6'r iIn Von �,y��.'t��L.��� 2 .1 '''ir61w1MIA.a 10,1 ,**3rw.RAadlOnOr..MIuhra42v.11•11 sVR?MY. trade at ArkbMbY. on, dubvi nwrAsk.A.../ntvi asoueverle`oocust Mllp]Ovotifyakitantat 100n vl0/110,4.0.61100.1ca tem ..t7.0. lra012la..iaMo>•CCM bra terrlalmtt.wlni axon .1 0.1111 I.nef.6nwve..:vr ayrak{ioardwelilwb cm Wee 1*3 V AMPEk Yp.c*1V10 mdl.bk mor dr6d.550 leu ttla SIM Aat»Wtw Ctw C rne000n G sre Sheet are asnlabe at mos wanner/.:['..teen ` Vallourec Group 1011 vallourec Page 32 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company HALLIBURTON Cott.e 11,2017 Engineering Data Sheet EQUIPMENT MATERIAL NO.: 102682578 PGM DUAL SHRD SCR N.4.500-12.60.250 MIC PART NUMBER: 281JCR45016-A DESIGN SPECIFICATIONS MAX OD 5.312 inch MIN ID 3.804 inch DRIFT BAR OD 3.833 inch LENGTH 490.0 inch BASE PIPE SIZE 4.500 INCH BASE PIPE WEIGHT 12.60 LBS,FT MAX LENGTH 511.0 inch BASE PIPE MATERIAL HAL GRADE L-80 LOW ALLOY STEEL BASE PIPE MATERIAL YIELD STRENGTH MIN 80000.0 psi BASE PIPE MATERIAL(REMARKS) CHARPY TEST PERFORMED FOR ARCTIC SERVICE BASE PIPE PERFORATION HOLE SIZE 318 BASE PIPE NUMBER OF HOLES PER FOOT 74 HOLES PER FOOT TOP THREAD 4 112-12.60 VAMHTTC BOTTOM THREAD 4 112-12.60 VAMHTTC CONNECTION TYPE BOX-PIN COUPLING OD 4.906 inch HANDLING LENGTH-TOP 61.0 inch HANDLING LENGTH-BOTTOM 37.0 inch TENSILE STRENGTH(CALCJ1000) 289 lb MAX TORQUE THROUGH ASSEMBLY 25000.0 ft.lb MAX BEND RADIUS PER 100 FEET 40.0 degree SCREEN CONSTRUCTION TYPE MESH MESH SCREEN GAUGE 250.0 micron SCREEN JACKET MAX OD 5.312 inch SCREENED LENGTH 334.0 inch SCREEN MATERIAL 316L STAINLESS STEEL SCREEN MATERIAL(REMARKS) 304L STAINLESS STEEL OUTER SHROUD,304L STAINLESS STEEL INNER SHROUD,316L STAINLESS STEEL MESH SCREEN BURST PRESSURE 1237.0 psi • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 16.6. Ensure to run enough liner to provide for approx 150' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 16.7. R/U false rotary and run 2-3/8" 6.5 #Inner String 16.8. Once inner string in run and set inside packoff, displace 9-5/8" casing back to PST passed drilling mud with lubes added. 16.9. Before picking up Baker ZXP liner hanger/packer assy, count the# of joints on the pipe deck to . make sure it coincides with the pipe tally. 16.10. M/U Baker ZXP liner top packer to inner string and 4-1/2" liner. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.11. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.12. RIH w/liner on DP no faster than 30 ft/min—this is to prevent buckilng the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.13. The screens and inner string will prevent the DP from auto filling. Fill DP with PST passed mud every 5 stands, more frequently if SOW trend indicates. 16.14. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth+ S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.15. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, &20 rpm 16.16. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.17. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.18. Rig up to pump down the work string with the rig pumps. Page 34 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company NOTE: The wellbore will be swapped over to brine after the liner has reached TD to keep from plugging the screens with solids. The success of this well depends upon the screens not becoming plugged with solids. 16.19. Break circulation and circulate out the mud. Begin circulating at—1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. Do not exceed 1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. 16.20. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the swell packers (if run). Do not exceed 1,600 psi while circulating as noted above. Note all losses. Confirm all pressures with Baker. 16.21. Monitor the returned fluids carefully while circulating out the mud. Perform production screen test(PST). The wellbore has been properly conditioned when the return fluid will pass the production screen test(3 one liter samples passing through the screen in the same amount of time which will indicate no plugging of the screen). 16.22. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.23. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.24. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SLZXP to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 16.25. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k#without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again, 16.26. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.27. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dob sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.28. P/U above liner top packer and displace well to completion fluid. 16.29. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. 16.30. RIH w/remaining DP out of derrick and L/D same. Page 35 Rev 1 October 2017 i • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 17.0 Run 7-5/8" Tieback 17.1 If necessary, RIH with mule shoe on 5" DP to Liner Top and circulation Liner Top and SBE clean. 17.2 R/U and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. Install and test 7-5/8" (250/3000 psi) solid body casing rams. 17.2 R/U 7-5/8" casing handling equipment. • Ensure XO to DP made up to FOSV and ready on rig floor. • Rig up computer torque monitoring service. • String should stay full while running, r/u fill up line and check as appropriate. 17.3 P/U tieback seal assembly and set in rotary table. Ensure 7-5/8" seal assembly has x4 1"holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8" x 7-5/8" annulus. 17.4 M/U first joint of 7-5/8"to seal assy. 17.5 Run 7-5/8" 29.7#VAM STL SMLS tieback to position seal assy two joints above tieback sleeve. Record up & down weights. • Following running procedure outlined above. Page 36 Rev 1 October 2017 w • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: ST-L Casing 7-518 in 29.70 Ib?ft(0.375 in) L-80 STANDARD Material L-80 Grade 80,000 Minimum Yield Strength (psi.) 95,000 Minimum Ultimate Strength (psi.) - U SA Pipe Dimensions YAM USA 7.625 Nominal Pipe Body O.D. (in.) 4424 W.Sam Houston Pkwy.Suite 150 6.875 Nominal Pipe Body I.D. (in.) 77041 Phone Houston, 3X479-32D0 0.375 Nominal Wall Thickness(in.) Fax:713-479-3234 29.70 Nominal Weight(Ibs.lft.) E-mail:VAMUSAsalesebvam-usa.com 29.06 Plain End Weight(lbs./ft.) 8.541 Nominal Pipe Body Area (sq. in.) Pipe Body Performance Properties 683,000 Minimum Pipe Body Yield Strength(lbs.) 4,790 Minimum Collapse Pressure(psi.) 6,890 Minimum Internal Yield Pressure(psi.) 6,300 Hydrostatic Test Pressure(psi.) Connection Dimensions 7.625 Connection O.D. (in.) 6.782 Connection I.D. (in.) 6.750 Connection Drift Diameter(in.) Y) 4.39 Make-up Loss(in.) 5.550 Critical Area (sq. in.) 65.0 Joint Efficiency (°%o) Connection Performance Properties 444.000 (1)Joint Strength (lbs.) 527,000 (2) Reference Minimum Parting Load (lbs.) 10,910 Reference String Length(ft) 1.4 Design Factor 266,000 Compression Rating(lbs.) 4,790 Collapse Pressure Rating (psi.) 6,890 Internal Pressure Rating (psi.) 18.8 Maximum Uniaxial Bend Rating [degrees/100 ft] Recommended Torque Values 4,600 (3) Minimum Final Torque(ft.-lbs.) 6,000(3) Maximum Final Torque (ft.-lbs.) Page 37 Rev 1 October 2017 I Milne Point Unit 111 L-53 Producer Drilling Procedure Hilcorp Energy Company 17.6 M/U 7-5/8"to DP crossover. 17.7 M/U stand of DP to string, and M/U top drive. 17.8 Break circulation at 1 bpm and begin lowering string. 17.9 Note seal assembly entering tieback sleeve with a pressure increase, Stop pumping and bleed off pressure, leave standpipe bleed off valve open. 17.10 Continue lowering string and land out on no-go. Set down 5 — 10k lbs. Mark the pipe at this depth as "NO-GO DEPTH". 17.11 P/U string &remove unnecessary 7-5/8"joints. 17.12 P/U hanger assembly and space out. M/U (or L/D) necessary joints and pup joints to position seal assembly 1 ft above "NO-GO DEPTH"when tie-back hanger lands out in wellhead. 17.13 Ensure circulation is possible through 7-5/8" string. 17.14 RU and circulation corrosion inhibited brine in the 9-5/8" x 7-5/8" annulus. 17.15 With seals stabbed into SBE, Spot diesel freeze protection from 2500' to surface in 7-5/8"x 9- 5/8" annulus by reverse circulating through the holes in the seal assembly. 17.16 Slack off and land hanger. 17.17 Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning rpt. 17.18 Run in hanger lock downs. 17.19 Back out landing joint. M/U packoff running tool and install packoff on bottom of landing joint. Set tubing hanger pack off. Test void to 3000 psi/ 10 min. 17.20 R/D casing running tools. 17.21 Test 7-5/8"x 9-5/8" production annulus to 1000 psi/30 min. 17.3 POOH and stand back 2-7/8"tubing for ESP run. Page 38 Rev 1 October 2017 • i Milne Point Unit L-53 Producer Drilling Procedure b Ecor gy 18.0 Run ESP Assembly — Upper Completion 18.1 M/U ESP assy and RIH to setting depth. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. • RIH with ESP assembly and cable clamps as per tally 18.2 Land hanger, RILDs and test hanger.Note PU and SO weights on tally, along with clamp summary. 18.3 Install BPV and N/D BOP. 18.4 N/U tree adapter and test tree. Pull BPV. 18.5 Circulate diesel freeze protection down 2-7/8"x 7-5/8" annulus (Volume should equal capacity of tubing to 2500' +tubing annulus to 2500'). Connect IA to tree and allow diesel freeze protect to "U-tube" into position. 18.6 Set BPV. Fill tree with diesel. 18.7 Shut in well and prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 19.0 RDMO 19.1 RDMO Innovation Rig Page 39 Rev 1 October 2017 • 0 Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 20.0 Innovation Rig Diverter Schematic x IP 11111 1T111111 _-----13-518.5M Control Technology Annular SOP I I LI1 . Et it c4, ---Z .c= V.. I ® —13-518'5M Control c= 'o Technology Double Ram gi) 2 IP gifs IiiiIIII .-- 1— lila 3118'K Line i'\ —1 �I irl l:% �" .it:hj,' via ---------3-1/8-Choke Line ! f — —i Ii _t o - Lo 13-518'SM Control—/' Technology Single Ram 13518'x 5M IL —16'Diverter Line 111 11111 13-5,8'x5M A I I 11,„ . -2-1116'x 5M 20'Casing Page 40 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 21.0 Innovation Rig BOP Schematic fpim, 1111111 11 111 111 ill 1111111 _''`' --13-518"5M Control Technology Annular BOP , � l c�'aT ■� MOM (774," K — ■g iii • v F ■ ■ -, �� �,l :; �it =fix c; ' }�`"'- —13-518"5M Control ■ ■Filir � 6 L i 0 Technology Double Ram R MN f=1 1111111111111111 i=i a 0474 3-1/8"Kill Line . V- . ' ■II r y®�I ------------V V 3-1/8"Choke Line Ic=)' � ,,, �c■C VA �` �----13-5/8"5M Control Technology Single Ram _ 13-518"x5M 11"x5M .4E1 1r r ii I r . ri► 9-5/8"DBL D Seal ... —UL _E�� ii'J —,111.1— mo � 21116"x5M CasingHanger U�■��"', ou 13-5/8"x 5M S-22r .'_1 f-[# 3]['II 13-5/8"NOM I w' w Li 9-5/8"BTC Btm x 2-1/15"x 5M 10.5"-4 SA Pin Top W/Primary Seal 20"Casing 1 9-5/8"Casing Page 41 Rev 1 October 2017 • S Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 22.0 Wellhead Schematic I HILCORP ALASKA i SCHRADER BLUFF WELLS H0-35449H i 2-9/16 5M 1 -........3 1-0.D-00'A4N FLANGE ADAPTER. ESP-2CL TOADSTOOL 11 X 2-9/16 5a — \Ml 1. ■ ® til I ._..,_,111 =,., TUBING HANGER S-Be-ESP ii a ini N X 2-7/8 ArSAOD BTM •11" itlinilaill4111~1 ,� EST F/TAURUS PENETRATORg4.5 = —/ --% 1�i •'�- I! 43-217-00 MGI - illl -' 1! I- 11 =u 2-185 5M CASING HANGER. 5MB-22 IMP am 11x7-5/8 W/PRIMARY SEAL p If '. I�,, 26.0 i • iiil:o3 " l : i . EST nil I I MMiil[4. • ,ai .1 .4110 ' 9-5/8 OBL 0 j i 1i1 2_1/18 5M q:II ' 16-3/4 3M 71.1 CASING HANGER 1N1 II lil SLAB-22.___..---- 16 �r18 X 9-5/8 W/PReMARY SEAL - - 4 •28.8 �1 ■1 G .` r, •■. .I EST 1111°111.1111111"1: • la r 11 EotiD 13-3/8 CASING 51.E e 9-5/8 CASING IiUEiII (r "'I1`"�'7(• 5/8 CASING— OIL 4,GAS BM. 5,000 PSESP'WELLHEAD ASSEMBLY DoaQ1510NS 518704 ON TNS DRAWING IAF I'' 2-7/B CASING 9-5/8TIE BACK STYLE ESTIMATES D/(Y ANO CAN VARY 9ON1FtCAN T 13-3/8 X X 7-5/8 X 2-7/8 RESTRICTED CONFIDENTIAL DOCUMENT ------- UPENJING ON RAW MATERNA.LENGT4t5. „�' NO COMM OF STACKUP 4f1GNT IS RIFLED. ""�""" �L 1-9 �19.R1N15 wc+ icus,i rro o+"s r.+nN ra�wr EIIIENSICNS 310WN SHGIA0 BE CGN5EER1D 'ro�i...."'i41`w,7 'C" "r +� MIMIC•a, '",w11ver<"= ,� -- QD-000619 FCR REFERENCE PLRPOSES CNIY. ,.0r s yam„ a„k„a Page 42 Rev 1 October 2017 i Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 23.0 Days Vs Depth MPU L-53 Days vs Depth 0 - L-53 SB N Producer 2000 4000 6000 CD- CO a 8000 10000 12000 14000 0 5 10 15 20 25 Days Page 43 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 24.0 Formation Tops & Information Formation MD TVD SV5 1633' 1445' Base Permafrost 2471' 1847' SV1 3104' 2147' Ugnu LA3 (Top Lower Ugnu) 5745' 3402' SB_NA(Top Shrader Bluff) 7098' 3863' SB_NB (Top Target Sand) 7459' 3894' GENERALIZED GEOLOGICAL FORECAST SS GEOLOGICAL COMMENTS TVD FM LITH DESCRIPTION All o. NOTE:See individual Well Program for °o°'"° Gubik specific casing design,depths.sizes, Tolerance s iro'. 6 • • weights-grades and connections. A Unconsolidated coarse to medium sand and small gravel •••••• with minor siltst one. 0.4%4 IF SIGNIFICANT AMOUNTS OF GRAVEL 1,000' ARE ENCOUNTERED WHEN DRILLING THE „♦ SURFACE HOLE,THE VISCOSITY OF THE :rc MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. 1750' Base permafrost Interbeds of sand,clays and siltstones with occasional 2,000' show of coal. Watch possible sidetracking while washingireaming.L.33 A.L-15. Sagavapirktok .♦ No hydrates encountered on L-Pad wells drilled to date. Continued Interbeds of sand,clays and siltstones with occasional shows of Coal.Traces of pyrite at+1-3100 ft 3,000' interval at+f-3400 ft can be sticky and tight(L-01). Clay nterbeds between 3W0 and 4500ft C 3472'- ' L 3657' A Kaands Y UGNU:Series of coarsening upward sands which are f-AB,c,ol made up of: (from top to bottom)coarse sand,fine sand, silty shale. Better developed intervening sissies as you UGNU progress Into the Land M(deeper). Ugnu and Schrader Bluff: Possible hydrocarbons limited t-sanda to SWcomer of Milne development Northern area Is 1-ABi downstructure and wet. '373g' M-sends I-AS.CI •4010' (NA) Schrader Bluff Sands: 4,000' I-An,c,D, Continued layering coarsening upward sands m above . Schrader Bluff: Possible lost circulation E,El except more condensed and with occasional coal. Clay rich shale interval 4300 to 4600 ft. zone while drilling long strings and running '4170' o-Sands Ugnu and Schrader Bluff: Possible hydrocarbons limited casing. Recommend deep setting surface (OA) i-Aec. to SWcomer of Milne development L-37 and L-45 are casing for Kuparuk long strings. Also,the D,E,F) completed In the Schrader Bluff sand. Northern area of Schrader L-Pad is downstmcture and wet. Schrader Bluff sands are a potential differential stuck pipe interval if left un-case[: Bluff Surface casing point In shale below for Kuparuk long strings. Sands: Schrader Bluff OB sand for longer reach wells. Page 44 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Historically, no gas hydrates have been seen on `L' Pad. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0—2.0 ppb DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore,pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 45 Rev 1 October 2017 S Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 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. 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 46 Rev 1 October 2017 • S IIMilne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 26.0 Innovation Rig Layout 0'-3 ' , 17 I - may► 7 r""""" 1 {!''11 LI I 1 11611-- IMP 11 a illf//-��L , M lir 11 i . 'E' -i!lr' I! , 4 i il i ' 11.M 1 um -p 1 ii=i !.. ~ I , i - c Si v _ � v ss r 56 d" �7 I t 1!1 . N HAK 2 FOOT 11::x:11. .sr r.' PRINT 05 21 16 -------- iL± L: r"."..a,' --- / / :, 1� Iran.uu 91 l 113•-11i" • • • 36•-1i" Page 47 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 27.0 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 48 Rev 1 October 2017 i Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 28.0 Innovation Rig Choke Manifold Schematic rif 177 _ (_ _) ___Ef±L.. _-_`:,"--0,_a a1 i II 4 0-41 _ �-13' Q q—d D-0 U Q_ Jr " o iiiirl (AA Ili giE L 41 * 1 -P_ 11111 - ?-6+16"SM B6209110Mt 2-4'16'3M BB209 Paper BallVNwPOW s - - PyBag Vela*" JOIE lia Ill 17 ill r 6,7:111.741 Ilii . � II q a ` • 11.41 _ ; ; I I ' ♦ d ' NW Page 49 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 29.0 Casing Design Information Calculation & Casing Design Factors DATE: 1011612015 WELL: MPU L-53 DESIGN BY: Joe Engel Design Criteria: Hole Size 1214" Mud Density: 9.5 ppg Hole Size 812" Mud Density: 9.5 ppg Hole Size Mud Density: Drilling Mode MASP: 1378 psi (see attached MASP determination&calculation) MASP: Production Mode MASP: 1378 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 4-1'2" Casing OD 9-518" Screens Top(MD) 0 7,240 d e e Top(TVD) 0 3,875 Bottom(MD) 7,440 14,612 d 8 d Bottom(TVD) 3,892 3,692 Length 7,440 7,372 Weight(ppf) 40 12.6 Grade L-80 L-80 Connection DWC HTTC Weight wio Bouyancy Factor(lbs) 297,600 92,887 d d d i d Tension at Top of Section(lbs) 297,600 92,887 Min strength Tension(1000 lbs) 916 288 �a e Worst Case Safety Factor(Tension) 3.00 .,- 3.10 Collapse Pressure at bottom(Psi) 1,923 1,824 d d Collapse Resistance v,110 tension(Psi) 3,090 7,500 Worst Case Safety Factor(Collapse) 1.61 4.11 ' MASP(psi) 1,378 1,378 Minimum Yield(psi) 5,750 8,430 Worst case safety factor(Burst) 4.17 '` 612 !' d Page 50 Rev 1 October 2017 r S Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 8-1/2"Hole Section Hilcorp MPU L-53 Milne Point Unit MD TVD Planned Top: 7440 3892 Planned TD: 14617 3692 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NB Sand 3,892 3,852 1750 Oil 8.74 0.454 Offset Well Mud Densities Well MW range Top(TVD) Bottom(TVD) Date MPU J-27 9-9.3 Surface 3666 2015 MPU J-28 9-9.3 Surface 3617 2015 MPI- 19 9-9.3 ppg Surface 4,079 2004 MPI-18 9-10 ppg Surface 3,848 2011 MPI-17 9-9.5 ppg Surface 3,864 2004 MPI-16 9-9.3 ppg Surface 4,101 2004 MPI- 15 9-10.8 ppg Surface 4,042 2002 MPI-14 9.1-9.3 ppg Surface 3,979 2004 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2"hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8"shoe considering a full column of gas from shoe to surface: 3892(ft)x 0.78(psi/ft)= 3035.8 3035.7(psi)-[0.1(psi/ft)*3892(ft)]= 2646.6 psi MASP from pore pressure(complete evacuation of wellbore to gas from Schrader Bluff NB sand) 3892(ft)x 0.454(psi/ft)= 1767 psi 1780(psi)-0.1(psi/ft)*3892(ft) 1378 psi Summary: 1. MASP while drilling 8-1/2"production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 51 Rev 1 October 2017 0 • II Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 31.0 Spider Plot (NAD 27) (Governmental Sections) • fy vs -C:v.E:-. )47,',I ,, Lri --33.9' �]'•=e 1- Y I (1d�.' y, V4,.....- 4,w 10.060000 },!I °000 ''''±-:'' f t / -3! 4 000 - ]_3L' IY'/ ,� 00 ,-S � 0000 S /I 8 0006000 - // • , , ` •, 000 / t • ADL0253°09_-- `I" /,/ ', see 2 Sec.12 -di - Ig`_ • , ,,/,7.I'', t , +�ti ADL388235 / ,/ r 1j r' 0 / 6 / / 4;c YY / % I ° MPH L-53 1PH -, / ' y r `i, T ♦ , J " r r/, I€ 0 .;' • t; 0 , .L I'. p ▪,. I....E I t ' ,r >� I oo A / /I o ., o ♦/ // •/ • O / `♦ ///MILN POIN /UNIT `,'�' , l', U013Nt)09E 'ES,LOI / U013N010E c:= _2 q /01: / 0 ° / Sec.ld Sec,i' :: ' ' o /'o /0 / P. ADL025514. : f ADL025515 TL'` ' 0 • , / 0 / • O / ' 0 I 0 ' ' • • 0 / O ° Legend ° e MPU L-53_SHL • Other Surface Holes(SHL) or MPU L53_TPH + Other Bottom Holes{BHL) // :L°L . 3_3H1 ---Other well Paths _ec 24.,' -t• MPU L-53_BHL I=Oil and Gas Unit Boundary ......1.,L1..14,: I Pad Footprint not / es y,t-Ai..711 t w.._. El Milne Point Unit MPL-53 Well 0 1,000 2,000 777 -ac Cate,_I:__,- wp_03 Feet Page 52 Rev 1 October 2017 • • II Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 32.0 Surface Plat (As Built) (NAD 27) 36 31 I 32 33 IJi- \ �r41 g 1 I �'<!: T11N 1 i \ \\ ` ( ICAO � 7 .4 FPAD I I \V 1 / +L- +L-5 n - - I L-. 33 \ ■76 • I '2 79L-PAD I y r } / ■24 ■75 I -I�- I 1 / 1 ■20 ■2, I THIS PROJECT -� a I ■,5 •17 - - - - 1 -- I // ' ■45 ■11 .-_. --� '3 to I 17 16 I f - -- ---- - - 4 /' / 11 ■ • 8 I _ .34 ■ 42 VICINITY MArr- I 1 ■ • 9 N.T.S. 34 • ■ 14 3 ■ ■10 JFGFND 15 ■ ■ 47 2 • •: 7 + AS-STAKED CONDUCT'c1K ■ 6XISTMC CONDUCTI R 12 • 40U ■■■■ ■ ■■■■ ■■;{� 35 4 36 5 1/ 11 5D l=F NOTES: nu, m 4 y 1 ALASKA STATE PLANE COORDINATES ARE ZONE 4,NA027. 2 BASIS OF LOCATION IS L-PAD MONUMENTS L-1 NORTH t - AND L-2 SOUTH. 3. BASIS OF ELEVATION IS 1,15L I 4. GEODETIC P05111065 ARE NA027. N 5, PAD MEAN SCALE FACTO:IS, 0,9999023 I 1 L_PAD a. DATE OF 5LR'vEY: SEPTEMBER 21&22, 2017. 1 I I lJ 7 REFERENCE FELD SOCK: HC17-01 PGS.60-62 I I I GRAPHIC SCALE 0 1151 2DD (IN FEET} 1 inch=200 ft. LOCATED WITHIN PROTRACTED SEC. 6, T. 13 N., R. IC) E., UTAIAT MERIDIAN, AK. WELL A.S.P, PLANT GEODETIC GEODETIC GRAVEL SECTION NO, COORDINATES COORDINATES POSITION(DMS) POSITION(D.DD) PAD ELEV. OFFSETS Y=6031932.31' 5=1750.00' N70'29'53.2032" 570.49811200 3744' FSL L-53 X=544641.05' E=1225.00' W149'38'05.7533" W149.63493146 1`''' 5235' FEL 4 Y=6031919.59 ' 5=1735.00' N70'29'53.0776" 570.49807712 3731' FSL L-.•2 X=544648.99' E='225.00' W149'38'05.5217" W149.63486:715 15'9' 5228' FEL L-54 Y=6031906.87' '4=1720.00' N70'29'52.9521" 570.40804224 15.7' 3719' FSL X=544656.94' E=1225.00' V1149'38'05.2900" AI49.63480277 5219 FEL L-56 Y=6731990,59' '4=1750.00' N70'29'53.7709" 570.498269703802' FSL X=5,44734.32' E=1335.00' W149'38'02.9971" W149.63416586 16'0 5142' FEL L_-.7 Y=6031977,87' 5=1735,00' N7029'53.6453" 570.49823481 tE.O, 3789' FSL X=544742.27' E=1335,00' Y7149'38'02.7653" 'W149,63410147 5134' FEL 1=6031965,15' '4=1720.00' N70'29'53.5197" 570.49819993 3776' FSL L- X=544750.22' E=1335.00' 8149'38'02.5335" W149.63403709 16.0 5126' FEL '41.h SA:ML17.1! HE 1E'NµsS Hilcorp Alaska - 8 aE asl7-/n ---- F Uig APL 02 MPU L-PAD "moi AS-STAKED CONDUCT::: IIE - ':'.7/fit 87.E7 IL,14,..x.117.4 Ka ee =2pg• WELL 5'-54, 56 k 57 r or 'E.I'1"•: ,q '14, Page 53 Rev 1 October 2017 • • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 33.0 Schrader Bluff NB Sand Offset MW vs TVD Chart MPU L-53 SB NB Offset MW vs TVD EMW, ppg 85 95 10.5 11.5 12.5 0 500 1000 1500 —.__._._._ __ ._ 9____.__._.._._ 1 I ? 1 s E ,„ 2000 2500 { 3000 3500 4000 4500 —J-27(2015)TVD --J-28 (2015)TVD Page 54 Rev 1 October 2017 I II Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 34.0 Drill Pipe Information 5" 19.5# S-135 DS-50 & NC50 Drill Pipe Configuration Pipe Body OD In:5.000 Pipe Body Wall Thickness in:0.362 Pipe Body Grade 60`: Inspection Class Nominal Weight Designation 19.50 S-135 Dill Pipe Approximate Length 31.5 Drill Pipe Length Rangel SmoothEdge Height tmlI3J32 Raised Connection GPD550 Tool Joint S69YS R=11 120.000 Tool Joint OD Tool Joint ID 6.625 Upset Type IEU on;3.250 Max Upset OD (DTE) on,5.125 Pin Tong 9 Friction Factor ]1.4 Box Tong In'12 Nora Tone space maty Include hart tadng. Drill Pipe Performance Drill-Pipe Length Rangel Performance of Drill Pipe with Pipe Body at Best Estimates Nominal $0 1/:0,1:0,s.pectIon CIasSpMUsanO�Ngltwint canna) leastxauralc>1, Axeednuko-wOperational Uax TensionDrillPipe Adjns)ed Weight Ibr.'rtl 24.1123.29 Toniae to-le:sTorque trt-ahs FluidDist acement =�''fl0,370.36 non Dnly0560.800Fluid Displacement eRlanlp 00880.0085 MakrnurnMUT43.100 I.oad.na 39,600 410,500 Fluid Capacity tvauR)0.71 0.70 0.72 - Fluid Capacity tearym 0.0169 0.0167 0.0172 I 36,100 Tension Only 0 560,800 Drift Size ^)3.125 ,I Mir MUT Combined Loading 32,100 467,400 Note:Oh Mld barrel equals 42 US gallons. _,/ - Hole:Drill pipe assrmNy values am tress esemates and may vary due to ripe body mill toxrarxe,Internal ptas.`,1[.cgatMaand other lactars. Connection Performance GPDS50 ( 6.625 r,r) OD X 3.250 ID ) 120,000 ) Aap'ted Make-up Tens on al SnouldC TenZlon at CanrM:ar Tool00 Joint Dimensions To•quc Scaara::ur Vold In- sy ,IRs; 0,sl Balanced un;6.435 Maximum Make-up Torque 43,100 Tensile Limited 1.046,900 hemm�m Toa Jont CO w API 5.930 Minimum Make-up Torque 36,100 1.202,504 1.250.000 PrcmlJln Clan, ars -- -'Note The maximum make-to to•a[e should he applied alien possbx4 . Annml.m Toil Jam CO aur 5.93 COLnlertdre ;Ir; Bete To maMlT�de connect.,Jairananal lend.,a MUT nn4)-3250,000 should be applied Tool Joint Torsional Strength to tem) 71,800 Tool Joint Tensile Strength te.; 1.250.000 Elevator Shoulder Information Elevator OD 3/32 Raised 6.812 SmoothEdge Height Nominal Tool Joint Worn to Bevel Worn to Min TJ OD for y 332 Raised OD Diameter API Premium Class Box OD loi 6.812 6.625 6.063 5.930 Elevator Capacity thti i 1,658,000 1.440,200 823.600 685,600 n'�5.219 Note Elevator caoserty Razed on assumed Elevator Bore,no wear racier,and contact stress or 110,t0fos'. Assumed Elevator Bore Diameter Note:A raised elvaior OD Increases elevator capacity%M nou!anectlU make-up torque. Pipe Body Slip Crushing Capacity Pipe Body Configuration( 5 On) OD 0.362 t0) Wall S-135) _ Nominal 80°o Inspection Class API Premium Class ' ''!(7 Slip Crushing Capacity0>498.300 396.500 396.500 [� Mote:app tsr.y Sip eructing bad Is eskWikd*0 R a 00' erhdld eql irlor:ham-Why Coes oil Roe Assumed Slip Length tri)16.5 Fal In 7e Ste Area Word Cd.1919'or the eo enor,and tans.erst dad fader shown and rs sir retererco Transverse Load Factor(Kl 4.2 4 aSy_Sip crushing S deaendent or the sip des-n and'axe Sir,=aelkenl of hkien.Wane oarMa's trine r sips,3-c 00 aid vol,analote,add cOrer Sanas Cc-cnutelthe sumr tartrerforad'amnv rmnnabsrr. Pioe Body Performance Pipe Body Configuration( 5 t") OD 0.362 101 Wall S-135) Nominal 80%Inspection Class API Premium Class Pipe Tensile Strength ow 712,100 560.800 560,800 Pipe Torsional Strength n_irsl 74.100 58 '00 58.100 TJ/PipeBody Torsional Ratio 0.97 1.24 1.24 80%Pipe Torsional Strength n-mil 59,300 46.500 46,500 Burst inn)17,105 15,638 15.638 Note:Namwl Burst Collapse nasi;15.672 10.029 10.029 a <vuled m 07.5%Rew per API. Pipe OD on 5.000 4.855 4.855 Wall Thickness ^I 0.362 0.290 0.290 Nominal Pipe ID on 4.276 4.276 4.276 Cross Sectional Area of Pipe Body .:m^21 5.275 4.154 4.154 Cross Sectional Area of OD tm°o 19.635 18.514 18.514 Cross Sectional Area of ID on^2l 14.360 14.360 14.360 Section Modulus tin^31 5.708 4.476 4.476 daPolar Section Modulus lln^3i 11.415 8.953 8.953 Page 55 Rev 1 October 2017 • Milne Point Unit L-53 Producer Drilling Procedure Hilcorp Energy Company 500204050016200 Weatherford 5" 19.50 lb/ft S-135 w/ NC 50 6-5/8" OD x 3-1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection NC 50 Interchangeable With 5" XH &4-112" IF Upset Type IEU Nominal Weight per Foot 19.50 lbs Adjusted Weight With Tool Joint per Foot 23.08 lbs TOOL JOINT DATA Outside Diameter 6-5/8" Inside Diameter 3-1/4" API Drift 3-1/8' Rabbit OD. Suggested 3-1/16" Minimum Make-up Torque 25.900 ft-lbs Maximum Recommend Make-up Torque 26.800 ft-lbs Torsional Yield Strength 51.700 ft-lbs Tensile Strength 1.269,000 lbs TUBE DATA New Premium Outside Diameter 5.000" 4.855' Inside Diameter 4.276" 4.276" Wall Thickness 0.362" 0.290' Cross Sectional Area 5.275 sq in 4.154 sq in Maximum Hook Load/Tensile Strength 712,000 lbs 560,800 lbs Slip Crushing 1 Slip Type (SDXL) 572.100 lbs 453,500 lbs Burst Pressure 17,100 psi 16,100 psi Collapse Pressure 15,700 psi 10,000 psi Torsional Yield Strength , 74,100 ft-lbs 58.100 ft-lbs Capacity W/Tool Joint 0.726 US gaUft 0.726 US gal/ft Displacement W/Tool Joint ,_ 0.353 US gaUft 0.322 US gal/ft - Excessive heat or pulling when tube is torqued can cause the maximum pull to decrease. Where possible all figures are obtained from OEM data source. NOTE: Weatherford in no way assumes responsibility or liability for any loss. damage or injury resulting from the use of the information listed above. All applications are for guidelines and the data described are at the user's own risk and are the user's responsibility. Page 56 Rev 1 October 2017 • • Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-53 MPU L-53 Plan: MPU L-53 WP03 Standard Proposal Report 09 October, 2017 HALLIBURTON Sperry Drilling Services 0 0 HALLIBURTON 7 REFERENCE INFORMATION WELL DETAILS:Plan:MPU L-53 -lilcO1.1, Co-ordinate(N/E)Reference:Well Plan MPU L-53,True North Ground Level: 15.90 Sperry Drilling Vertical(TVD)Reference:MPL-53 As-Staked Update @ 42.40usft +N/-S +E/-W NorthingEesting Latittude Longitude Measured Depth Reference:MPL-53 As-Staked Update @ 42.40usft 0.00 0.00 6031932.31 544641.05 70°29'53.203 N 149'38 5.753 W Calculation Method:Minimum Curvature Project: Milne Point Site: M Pt L Pad SECTION DETAILS Well: Plan:MPU L-53 Sec MD Inc Azi TVD +N/-S +E/-W DIeg TFace VSect Target Annotation Wellbore: MPU L-53 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 2 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3e/100':350'MD,3501VD Design: MPU L-53 WP03 3 550.00 8.00 235.00 549.63 -6.00 -8.57 3.00 235.00 10.23 Start Dir 41100':550'MD,549.63'TVD 4 750.00 14.00 235.00 746.44 -25.90 -37.00 4.00 0.00 44.15 Start Dir 51100':750'MD,746.44'TVD Hilcorp Alaska,LLC 5 1713.71 61.65 249.88 1486.97 -253.60 -561.44 5.00 17.41 567.57 End Dir:1713.71'MD,1486.97'TVD ' 6 5928.45 61.65 249.68 3488.43 -1541.61 -4039.83 0.00 0.00 3876.20 Start Dir 51100':5928.45'MD,3488.43TVD Calculation Method:Minimum Curvature 7 7144.37 85.00 190.30 3866.25 -2405.95 -4714.38 5.00 -79.15 4968.70 End Dir:7144.37'MD,3866.25'ND Error System:ISCWSA 8 7444.37 85.00 190.30 3892.40 -2699.99 -4767.82 0.00 0.00 5220.73 MPL-53 wp02 NB Heel Start Din 51100':7444.37'MD,3892.4'TVD Scan Method:Closest Approach 3D 9 7579.08 91.66 191.30 3896.32 -2832.18 -4793.04 5.00 8.59 5334.85 End Dir:7579.08'MD,3896.32'ND Error SurfMethod:Elliptical Conic 10 14617.73 91.68 191.30 3692.40 -9731.37 -8172.21 0.00 0.00 11333.58 MPL-53 w 2 NB Toe Total Depth:14617.73'MD,3692.4'TVD Warning Method:Error Ratio PD pt • -1500- _ SURVEY PROGRAM Date:2018-05-03TDU0:00 Validated:Yes Version: -750- Depth From Depth To Survey/Plan Tool 26.50 600.00 MPU L-t3 WP03 SRGSS 600.00 7500.00 MPU L-53 WP03 MWD+IFR2+Ms«sag - ja 7500.00 19617.73 MPU L-53 WP03 MWD+IFR2+19s+aag 0-- /- OASStart Dir 3°/100':350'MD,350TVD CASING DETAILS - -- Start Dir 4°/100':550'MD,549.637VD ND MD Name Size 2.02 744000 9 5/6'x 12 1/4" 9-5/8 509- 3892.40 14617.73 4 VT 0812' 4-1/2 p - Start DIr 5°/100':750'MD.746.44'TVD o 750- 7 - .,000 End Dir:1713.71'MD,1486.97'TVD - n CI 1500- 0 4a,� c! - e� 'v Opo �V' �V O N 9 h tithb5 6�S R`� y2250- °' o •ye �0 ,5ga'k. ,yryS>D 2 - o0 0 �0a 4'. 49- BOy. 49 - o sea` / 1° ,AeA°' Opo Total Depth:14617.73'MD,3692.4'TVD 3000- ,h y4 �apaN 05550° Ah1 ', 04 - J. g ' 9`a .t� 41/Y'x812" 'MPU L-53 WP03 3750- ' A0 0 8 S o 0 0 0 0 0 0 m - 9 5/8"x 12 1/4" 0 0 MPL-53 wp02 NB Heel MPL-53 wp02 NB Toe 4500- 5250- 6000- I i I I I 1 i I I I I i I I I I i I I I I i I I I I i I I I I i I I I I I I I I I i r r / 1111111 1 I I 1 i I I I I I I I I i 1 1 I I i I I I I i i I I I i I I I I i I I I I i 1 I I I i I I I I -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 Vertical Section at 222.81°(1500 usft/in) I r HALLIBUPTON Project: Milne Point WELL DETAILS: Plan:MPU L-53 Site: M Pt L Pad Ground Level: 15.90 Sparry Drilling Well: Plan: MPU L-53 +N/-S +E/-W Northing Easting Latittude Longitude Wellbore: MPU L-53 0.00 0.00 6031932.31 544641.05 70°29'53.203 N 149°38'5.753W Plan: MPU L-53 WP03 REFERENCE INFORMATION Hiicorp Co-ordinate(N/E)Reference:Well Plan:MPU L-53,True North Vertical(TVD)Reference:MPL-53 As-Staked Update©42.40usft Measured Depth Reference:MPL-53 As-Staked Update 42.40usft CASING DETAILS Calculation Method:Minimum Curvature TVD TVDSS MD Size Name 3892.02 3849.62 7440.00 9-5/8 9 5/8"x 12 1/4" 3692.40 3650.00 14617.73 4-1/2 4 1/2"x 8 1/2" 750- 0— ' .250 Start-Dir 3°/100':350'MD,350TVD -750— N $ �\ Start‘pir4°/100':550'MD,549.63TVD - o � Start Dir 5°/100':750'MD,746.44TVD -1500— End Dir:1713.71'MD,1486.97'TVD 35.50 -2250— Start Dir 5°/100':5928.45'MD,3488.43TVD 9 5/8"x 12 1/4" _ End Dir:7144.37'MD,3866.25'TVD MPL-53 wp02 NB Heel '- C -3000— Start Dir 5°/100':7444.37 MD,3892.4TVD End Dir:7579.08'MD,3896.32'TVD o - s- -3750— + ye -4500— o - rn -5250- -6000— -6750— -7500- -8250- -9000— 4 1/2"x 8 1/2" 9750— AUL-33 w.03 MPL-53 wp02 NB Toe 3692 --__ Total Depth:14617.73'MD,3692.4'TVD -10500— I I I I I I I l I l I I l i t l I l i l I I l l l I I l l l l I l l I l I l l l I I I l l 1 I l l I l I I l l l I l l l l I I 1 1 1 1 1 1 1 I -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 West(-)/East(+)(1500 usft/in) 0 • Halliburton HALLI B U RTO N Standard Proposal Report Datab Sperry EDM-NORTH US+CANADA Well Plan:MPU L-53 Comps Hilcorp Alaska,LLC o ,,r r` MPL-53 As-Staked Update @ 42.40usft/ .Projec Milne Point /% i14 $ MPL-53 As-Staked Update @ 42.40usft Site: M Pt L Pad 't True Well Plan:MPU L-53 . 1 a i. ` i e Minimum Curvature 'Wellbore MPU L-53 go' Design: MPU L-53 WP03 w t,--.7--,,-- 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 L Pad,TR-13-10 Site Position: Northing: 6,029,799.28 usft Latitude: 70°29'32.230 N From: Map Easting: 544,529.55 usft Longitude: 149°38'9.412 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.34° Well Plan:MPU L-53 Well Position +N/-S 0.00 usft Northing: 6,031,932.31 usft Latitude: 70°29'53.203 N +El-W 0.00 usft Easting: 544,641.05 usft Longitude: 149°38'5.753 W Position Uncertainty 0.00 usft Wellhead Elevation: 42.40 usft Ground Level: 15.90 usft Wellbore MPU L-53 Magnetics Model Name Sample Date Declination Dip Angle.; Field Strength (°) (1 Angle-M44, BGGM2017 10/9/2017 17.50 81.03 57,497 44-444, Design MPU L-53 WP03 Audit Notes: Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section Depth From Trig. +N/-S N +E-W •' (usft) (usft) (usft) 26.50 0.00 0.00 222.81 Plan Sections Measured Vertical TVD x"" ` '' Dogleg Build 'Turn,'",. Depth Inclination Azimuth Depth System +N/-S +El-W Rate Rate Rate 4,,, Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°1100usft) (°1100usft) ;_+(°) 26.50 0.00 0.00 26.50 -15.90 0.00 0.00 0.00 0.00 0.00 0.00 350.00 0.00 0.00 350.00 307.60 0.00 0.00 0.00 0.00 0.00 0.00 550.00 6.00 235.00 549.63 507.23 -6.00 -8.57 3.00 3.00 0.00 235.00 750.00 14.00 235.00 746.44 704.04 -25.90 -37.00 4.00 4.00 0.00 0.00 1,713.71 61.65 249.68 1,486.97 1,444.57 -253.60 -561.44 5.00 4.94 1.52 17.41 5,928.45 61.65 249.68 3,488.43 3,446.03 -1,541.61 -4,039.83 0.00 0.00 0.00 0.00 7,144.37 85.00 190.30 3,866.25 3,823.85 -2,405.95 -4,714.38 5.00 1.92 -4.88 -79.15 7,444.37 85.00 190.30 3,892.40 3,850.00 -2,699.99 -4,767.82 0.00 0.00 0.00 0.00 7,579.08 91.66 191.30 3,896.32 3,853.92 -2,832.18 -4,793.04 5.00 4.94 0.75 8.59 14,617.73 91.66 191.30 3,692.40 3,650.00 -9,731.37 -6,172.21 0.00 0.00 0.00 0.00 10/9/2017 5:39:58PM Page 2 COMPASS 5000.1 Build 81D • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU L-53 ' Company: Hilcorp Alaska,LLC ND Reference: MPL-53 As-Staked Update©42.40usft Project: Milne Point MD Reference: ,; MPL-53 As-Staked Update @ 42.40usft Site: M Pt L Pad North Reference: -/ True Well: Plan:MPU L-53 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-53 Design: MPU L-53 WP03 p Planned Survey Measured Vertical J Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W - Northing Easting DLS Vert Section" (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -15.90 26.50 0.00 0.00 26.50 -15.90 0.00 0.00 6,031,932.31 544,641.05 0.00 0.00 100.00 0.00 0.00 100.00 57.60 0.00 0.00 6,031,932.31 544,641.05 0.00 0.00 200.00 0.00 0.00 200.00 157.60 0.00 0.00 6,031,932.31 544,641.05 0.00 0.00 300.00 0.00 0.00 300.00 257.60 0.00 0.00 6,031,932.31 544,641.05 0.00 0.00 350.00 0.00 0.00 350.00 307.60 0.00 0.00 6,031,932.31 544,641.05 0.00 0.00 Start Dir 3°1100':350'MD,350'TVD 400.00 1.50 235.00 399.99 357.59 -0.38 -0.54 6,031,931.93 544,640.52 3.00 0.64 500.00 4.50 235.00 499.85 457.45 -3.38 -4.82 6,031,928.90 544,636.25 3.00 5.75 550.00 6.00 235.00 549.63 507.23 -6.00 -8.57 6,031,926.26 544,632.52 3.00 10.23 Start Dir 4°/100':550'MD,549.63'TVD 600.00 8.00 235.00 599.26 556.86 -9.50 -13.56 6,031,922.73 544,627.55 4.00 16.18 700.00 12.00 235.00 697.72 655.32 -19.45 -27.78 6,031,912.69 544,613.39 4.00 33.15 750.00 14.00 235.00 746.44 704.04 -25.90 -37.00 6,031,906.19 544,604.21 4.00 44.15 Start Dir 5°I100':750'MD,746.44'TVD 800.00 16.40 237.65 794.68 752.28 -33.15 -47.92 6,031,898.87 544,593.34 5.00 56.88 900.00 21.27 241.18 889.30 846.90 -49.46 -75.75 6,031,882.40 544,565.60 5.00 87.77 1,000.00 26.19 243.44 980.82 938.42 -68.09 -111.41 6,031,863.56 544,530.06 5.00 125.66 1,100.00 31.13 245.02 1,068.54 1,026.14 -88.88 -154.61 6,031,842.51 544,486.99 5.00 170.27 1,200.00 36.09 246.21 1,151.80 1,109.40 -111.69 -205.02 6,031,819.40 544,436.72 5.00 221.26 1,300.00 41.06 247.15 1,229.96 1,187.56 -136.34 -262.27 6,031,794.41 544,379.63 5.00 278.25 1,400.00 46.03 247.91 1,302.42 1,260.02 -162.65 -325.92 6,031,767.72 544,316.15 5.00 340.80 1,500.00 51.00 248.56 1,368.64 1,326.24 -190.40 -395.47 6,031,739.55 544,246.77 5.00 408.43 1,600.00 55.98 249.12 1,428.11 1,385.71 -219.40 -470.41 6,031,710.11 544,172.01 5.00 480.62 1,700.00 60.97 249.62 1,480.39 1,437.99 -249.42 -550.16 6,031,679.62 544,092.45 5.00 556.84 1,713.71 61.65 249.68 1,486.97 1,444.57 -253.60 -561.44 6,031,675.37 544,081.20 5.00 567.57 End Dir :1713.71'MD,1486.97'ND 1,800.00 61.65 249.68 1,527.94 1,485.54 -279.97 -632.65 6,031,648.57 544,010.15 0.00 635.31 1,900.00 61.65 249.68 1,575.43 1,533.03 -310.53 -715.18 6,031,617.52 543,927.82 0.00 713.81 2,000.00 61.65 249.68 1,622.92 1,580.52 -341.09 -797.71 6,031,586.47 543,845.48 0.00 792.31 2,100.00 61.65 249.68 1,670.41 1,628.01 -371.65 -880.24 6,031,555.42 543,763.14 0.00 870.81 2,200.00 61.65 249.68 1,717.89 1,675.49 -402.21 -962.77 6,031,524.37 543,680.81 0.00 949.31 2,300.00 61.65 249.68 1,765.38 1,722.98 -432.77 -1,045.30 6,031,493.31 543,598.47 0.00 1,027.82 2,400.00 61.65 249.68 1,812.87 1,770.47 -463.33 -1,127.83 6,031,462.26 543,516.14 0.00 1,106.32 2,500.00 61.65 249.68 1,860.36 1,817.96 -493.89 -1,210.36 6,031,431.21 543,433.80 0.00 1,184.82 2,600.00 61.65 249.68 1,907.84 1,865.44 -524.45 -1,292.89 6,031,400.16 543,351.46 0.00 1,263.32 2,700.00 61.65 249.68 1,955.33 1,912.93 -555.01 -1,375.42 6,031,369.11 543,269.13 0.00 1,341.82 2,800.00 61.65 249.68 2,002.82 1,960.42 -585.57 -1,457.95 6,031,338.06 543,186.79 0.00 1,420.32 2,900.00 61.65 249.68 2,050.30 2,007.90 -616.13 -1,540.47 6,031,307.00 543,104.45 0.00 1,498.82 3,000.00 61.65 249.68 2,097.79 2,055.39 -646.69 -1,623.00 6,031,275.95 543,022.12 0.00 1,577.33 3,100.00 61.65 249.68 2,145.28 2,102.88 -677.24 -1,705.53 6,031,244.90 542,939.78 0.00 1,655.83 3,200.00 61.65 249.68 2,192.77 2,150.37 -707.80 -1,788.06 6,031,213.85 542,857.45 0.00 1,734.33 3,300.00 61.65 249.68 2,240.25 2,197.85 -738.36 -1,870.59 6,031,182.80 542,775.11 0.00 1,812.83 3,400.00 61.65 249.68 2,287.74 2,245.34 -768.92 -1,953.12 6,031,151.75 542,692.77 0.00 1,891.33 3,500.00 61.65 249.68 2,335.23 2,292.83 -799.48 -2,035.65 6,031,120.69 542,610.44 0.00 1,969.83 3,600.00 61.65 249.68 2,382.71 2,340.31 -830.04 -2,118.18 6,031,089.64 542,528.10 0.00 2,048.33 10/9/2017 5:39:58PM Page 3 COMPASS 5000.1 Build 810 I • Halliburton HALLIBURTON Standard Proposal Report •Database ti;‘-``Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU L-53 Company: Hilcorp Alaska,LLC TVD Reference: MPL-53 As-Staked Update @ 42.40usft Project: Milne Point MD Reference: . MPL-53 As-Staked Update @ 42.40usft Site: M Pt L Pad North Reference: True Well: ' Plan:MPU L-53 Survey Calculation Method: Minimum Curvature Wellbore ,• MPU L-53 .: • Design MPU L-53 WP03 pl 3 _. , s Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W,, Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) ' , (usft) (usft) 2,387.80 3,700.00 61.65 249.68 2,430.20 2,387.80 -860.60 -2,200.71 6,031,058.59 542,445.76 0.00 2,126.84 3,800.00 61.65 249.68 2,477.69 2,435.29 -891.16 -2,283.24 6,031,027.54 542,363.43 0.00 2,205.34 3,900.00 61.65 249.68 2,525.18 2,482.78 -921.72 -2,365.77 6,030,996.49 542,281.09 0.00 2,283.84 4,000.00 61.65 249.68 2,572.66 2,530.26 -952.28 -2,448.30 6,030,965.44 542,198.76 0.00 2,362.34 4,100.00 61.65 249.68 2,620.15 2,577.75 -982.84 -2,530.83 6,030,934.38 542,116.42 0.00 2,440.84 4,200.00 61.65 249.68 2,667.64 2,625.24 -1,013.40 -2,613.36 6,030,903.33 542,034.08 0.00 2,519.34 4,300.00 61.65 249.68 2,715.12 2,672.72 -1,043.96 -2,695.88 6,030,872.28 541,951.75 0.00 2,597.84 4,400.00 61.65 249.68 2,762.61 2,720.21 -1,074.52 -2,778.41 6,030,841.23 541,869.41 0.00 2,676.35 4,500.00 61.65 249.68 2,810.10 2,767.70 -1,105.08 -2,860.94 6,030,810.18 541,787.07 0.00 2,754.85 4,600.00 61.65 249.68 2,857.59 2,815.19 -1,135.64 -2,943.47 6,030,779.13 541,704.74 0.00 2,833.35 4,700.00 61.65 249.68 2,905.07 2,862.67 -1,166.20 -3,026.00 6,030,748.07 541,622.40 0.00 2,911.85 4,800.00 61.65 249.68 2,952.56 2,910.16 -1,196.76 -3,108.53 6,030,717.02 541,540.07 0.00 2,990.35 4,900.00 61.65 249.68 3,000.05 2,957.65 -1,227.32 -3,191.06 6,030,685.97 541,457.73 0.00 3,068.85 5,000.00 61.65 249.68 3,047.53 3,005.13 -1,257.88 -3,273.59 6,030,654.92 541,375.39 0.00 3,147.35 5,100.00 61.65 249.68 3,095.02 3,052.62 -1,288.44 -3,356.12 6,030,623.87 541,293.06 0.00 3,225.86 5,200.00 61.65 249.68 3,142.51 3,100.11 -1,318.99 -3,438.65 6,030,592.82 541,210.72 0.00 3,304.36 5,300.00 61.65 249.68 3,190.00 3,147.60 -1,349.55 -3,521.18 6,030,561.77 541,128.39 0.00 3,382.86 5,400.00 61.65 249.68 3,237.48 3,195.08 -1,380.11 -3,603.71 6,030,530.71 541,046.05 0.00 3,461.36 5,500.00 61.65 249.68 3,284.97 3,242.57 -1,410.67 -3,686.24 6,030,499.66 540,963.71 0.00 3,539.86 5,600.00 61.65 249.68 3,332.46 3,290.06 -1,441.23 -3,768.77 6,030,468.61 540,881.38 0.00 3,618.36 5,700.00 61.65 249.68 3,379.94 3,337.54 -1,471.79 -3,851.29 6,030,437.56 540,799.04 0.00 3,696.87 5,800.00 61.65 249.68 3,427.43 3,385.03 -1,502.35 -3,933.82 6,030,406.51 540,716.70 0.00 3,775.37 5,900.00 61.65 249.68 3,474.92 3,432.52 -1,532.91 -4,016.35 6,030,375.46 540,634.37 0.00 3,853.87 5,928.45 61.65 249.68 3,488.43 3,446.03 -1,541.61 -4,039.83 6,030,366.62 540,610.94 0.00 3,876.20 Start Dir 5°/100':5928.45'MD,3488.43'TVD 6,000.00 62.38 245.71 3,522.01 3,479.61 -1,565.58 -4,098.27 6,030,342.30 540,552.66 5.00 3,933.50 6,100.00 63.59 240.27 3,567.47 3,525.07 -1,606.04 -4,177.59 6,030,301.37 540,473.59 5.00 4,017.08 6,200.00 64.99 234.94 3,610.87 3,568.47 -1,654.31 -4,253.61 6,030,252.65 540,397.87 5.00 4,104.15 6,300.00 66.59 229.74 3,651.90 3,609.50 -1,710.02 -4,325.76 6,030,196.51 540,326.06 5.00 4,194.06 6,400.00 68.35 224.68 3,690.25 3,647.85 -1,772.75 -4,393.50 6,030,133.38 540,258.71 5.00 4,286.11 6,500.00 70.26 219.74 3,725.61 3,683.21 -1,842.03 -4,456.30 6,030,063.73 540,196.33 5.00 4,379.61 6,600.00 72.30 214.92 3,757.72 3,715.32 -1,917.32 -4,513.68 6,029,988.10 540,139.40 5.00 4,473.84 6,700.00 74.46 210.21 3,786.34 3,743.94 -1,998.06 -4,565.22 6,029,907.06 540,088.36 5.00 4,568.10 6,800.00 76.71 205.60 3,811.25 3,768.85 -2,083.63 -4,610.52 6,029,821.23 540,043.58 5.00 4,661.65 6,900.00 79.05 201.08 3,832.26 3,789.86 -2,173.37 -4,649.22 6,029,731.27 540,005.42 5.00 4,753.79 7,000.00 81.45 196.63 3,849.20 3,806.80 -2,266.61 -4,681.05 6,029,637.85 539,974.15 5.00 4,843.83 7,100.00 83.90 192.24 3,861.96 3,819.56 -2,362.64 -4,705.75 6,029,541.69 539,950.03 5.00 4,931.06 7,144.37 85.00 190.30 3,866.25 3,823.85 -2,405.94 -4,714.38 6,029,498.33 539,941.66 5.00 4,968.70 End Dir :7144.37'MD,3866.25'TVD 7,200.00 85.00 190.30 3,871.10 3,828.70 -2,460.47 -4,724.29 6,029,443.75 539,932.08 0.00 5,015.43 7,300.00 85.00 190.30 3,879.82 3,837.42 -2,558.48 -4,742.10 6,029,345.64 539,914.86 0.00 5,099.44 7,400.00 85.00 190.30 3,888.53 3,846.13 -2,656.50 -4,759.91 6,029,247.53 539,897.64 0.00 5,183.45 7,440.00 85.00 190.30 3,892.02 3,849.62 -2,695.70 -4,767.04 6,029,208.29 539,890.75 0.00 5,217.06 9518"x121/4" 10/9/2017 5:39:58PM Page 4 COMPASS 5000.1 Build 810 s 0 Halliburton HALLIBURTON Standard Proposal Report m Database: Sperry EDM-NORTH US+CANADALocal Co-ordinate Reference: Well Plan:MPU L-53 „_... x Company: Hilcorp Alaska,LLC TVD Reference: '''-''z MPL-53 As-Staked Update @ 42.40usft Project: Milne Point MD Reference: h MPL-53 As-Staked Update @ 42.40usft Site: M Pt L Pad North Reference: True Well: Plan:MPU L-53 Survey Calculation Method: Minimum Curvature il Wellbore: MPU L-53 Design: MPU L-53 WP03 Planned Survey MeasuredVertical ;, Map ' Map . Depth Inclination Azimuth Depth TVDss +N/-S +E/-W;.. Northing 'Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft)t_ (usft) (usft) 3,850.00 7,444.37 85.00 190.30 3,892.40 3,850.00 -2,699.99 -4,767.82 6,029,204.00 539,890.00 0.00 5,220.73 Start Dir 5°/100':7444.37'MD,3892.4'TVD 7,500.00 87.75 190.72 3,895.92 3,853.52 -2,754.57 -4,777.94 6,029,149.37 539,880.21 5.00 5,267.65 7,579.08 91.66 191.30 3,896.32 3,853.92 -2,832.18 -4,793.04 6,029,071.68 539,865.57 5.00 5,334.85 End Dir :7579.08'MD,3896.32'TVD 7,600.00 91.66 191.30 3,895.72 3,853.32 -2,852.68 -4,797.14 6,029,051.15 539,861.60 0.00 5,352.68 7,700.00 91.66 191.30 3,892.82 3,850.42 -2,950.70 -4,816.73 6,028,953.02 539,842.59 0.00 5,437.90 7,800.00 91.66 191.30 3,889.92 3,847.52 -3,048.72 -4,836.33 6,028,854.90 539,823.59 0.00 5,523.13 7,900.00 91.66 191.30 3,887.03 3,844.63 -3,146.74 -4,855.92 6,028,756.77 539,804.59 0.00 5,608.36 8,000.00 91.66 191.30 3,884.13 3,841.73 -3,244.76 -4,875.52 6,028,658.65 539,785.58 0.00 5,693.58 8,100.00 91.66 191.30 3,881.23 3,838.83 -3,342.78 -4,895.11 6,028,560.52 539,766.58 0.00 5,778.81 8,200.00 91.66 191.30 3,878.33 3,835.93 -3,440.79 -4,914.70 6,028,462.40 539,747.58 0.00 5,864.03 8,300.00 91.66 191.30 3,875.44 3,833.04 -3,538.81 -4,934.30 6,028,364.27 539,728.57 0.00 5,949.26 8,400.00 91.66 191.30 3,872.54 3,830.14 -3,636.83 -4,953.89 6,028,266.15 539,709.57 0.00 6,034.48 8,500.00 91.66 191.30 3,869.64 3,827.24 -3,734.85 -4,973.49 6,028,168.02 539,690.57 0.00 6,119.71 8,600.00 91.66 191.30 3,866.75 3,824.35 -3,832.87 -4,993.08 6,028,069.90 539,671.56 0.00 6,204.94 8,700.00 91.66 191.30 3,863.85 3,821.45 -3,930.89 -5,012.68 6,027,971.77 539,652.56 0.00 6,290.16 8,800.00 91.66 191.30 3,860.95 3,818.55 -4,028.91 -5,032.27 6,027,873.65 539,633.56 0.00 6,375.39 8,900.00 91.66 191.30 3,858.05 3,815.65 -4,126.93 -5,051.86 6,027,775.52 539,614.56 0.00 6,460.61 9,000.00 91.66 191.30 3,855.16 3,812.76 -4,224.94 -5,071.46 6,027,677.40 539,595.55 0.00 6,545.84 9,100.00 91.66 191.30 3,852.26 3,809.86 -4,322.96 -5,091.05 6,027,579.27 539,576.55 0.00 6,631.06 9,200.00 91.66 191.30 3,849.36 3,806.96 -4,420.98 -5,110.65 6,027,481.15 539,557.55 0.00 6,716.29 9,300.00 91.66 191.30 3,846.46 3,804.06 -4,519.00 -5,130.24 6,027,383.02 539,538.54 0.00 6,801.51 9,400.00 91.66 191.30 3,843.57 3,801.17 -4,617.02 -5,149.84 6,027,284.90 539,519.54 0.00 6,886.74 9,500.00 91.66 191.30 3,840.67 3,798.27 -4,715.04 -5,169.43 6,027,186.77 539,500.54 0.00 6,971.97 9,600.00 91.66 191.30 3,837.77 3,795.37 -4,813.06 -5,189.02 6,027,088.65 539,481.53 0.00 7,057.19 9,700.00 91.66 191.30 3,834.88 3,792.48 -4,911.08 -5,208.62 6,026,990.52 539,462.53 0.00 7,142.42 9,800.00 91.66 191.30 3,831.98 3,789.58 -5,009.09 -5,228.21 6,026,892.40 539,443.53 0.00 7,227.64 9,900.00 91.66 191.30 3,829.08 3,786.68 -5,107.11 -5,247.81 6,026,794.27 539,424.52 0.00 7,312.87 10,000.00 91.66 191.30 3,826.18 3,783.78 -5,205.13 -5,267.40 6,026,696.15 539,405.52 0.00 7,398.09 10,100.00 91.66 191.30 3,823.29 3,780.89 -5,303.15 -5,286.99 6,026,598.02 539,386.52 0.00 7,483.32 10,200.00 91.66 191.30 3,820.39 3,777.99 -5,401.17 -5,306.59 6,026,499.90 539,367.51 0.00 7,568.54 10,300.00 91.66 191.30 3,817.49 3,775.09 -5,499.19 -5,326.18 6,026,401.77 539,348.51 0.00 7,653.77 10,400.00 91.66 191.30 3,814.60 3,772.20 -5,597.21 -5,345.78 6,026,303.65 539,329.51 0.00 7,739.00 10,500.00 91.66 191.30 3,811.70 3,769.30 -5,695.23 -5,365.37 6,026,205.52 539,310.50 0.00 7,824.22 10,600.00 91.66 191.30 3,808.80 3,766.40 -5,793.24 -5,384.97 6,026,107.40 539,291.50 0.00 7,909.45 10,700.00 91.66 191.30 3,805.90 3,763.50 -5,891.26 -5,404.56 6,026,009.27 539,272.50 0.00 7,994.67 10,800.00 91.66 191.30 3,803.01 3,760.61 -5,989.28 -5,424.15 6,025,911.15 539,253.49 0.00 8,079.90 10,900.00 91.66 191.30 3,800.11 3,757.71 -6,087.30 -5,443.75 6,025,813.02 539,234.49 0.00 8,165.12 11,000.00 91.66 191.30 3,797.21 3,754.81 -6,185.32 -5,463.34 6,025,714.90 539,215.49 0.00 8,250.35 11,100.00 91.66 191.30 3,794.32 3,751.92 -6,283.34 -5,482.94 6,025,616.77 539,196.48 0.00 8,335.57 11,200.00 91.66 191.30 3,791.42 3,749.02 -6,381.36 -5,502.53 6,025,518.65 539,177.48 0.00 8,420.80 11,300.00 91.66 191.30 3,788.52 3,746.12 -6,479.38 -5,522.13 6,025,420.52 539,158.48 0.00 8,506.03 11,400.00 91.66 191.30 3,785.62 3,743.22 -6,577.39 -5,541.72 6,025,322.40 539,139.47 0.00 8,591.25 11,500.00 91.66 191.30 3,782.73 3,740.33 -6,675.41 -5,561.31 6,025,224.27 539,120.47 0.00 8,676.48 10,9/2017 5:39:58PM Page 5 COMPASS 5000.1 Build 81D Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU L-53 Company: Hilcorp Alaska,LLC TVD Reference: MPL-53 As-Staked Update @ 42.40usft Project: Milne Point MD Reference: MPL-53 As-Staked Update @ 42.40usft Site: M Pt L Pad North Reference: , True Well: Plan:MPU L-53 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-53 Design: MPU L-53 WP03 1'1-- , Planned Survey Measured Vertical ,` Map Map Depth Inclination Azimuth Depth TVDss +N/-S ,+E/-W: 'Northing• . ` ' Easting DLS Vert Section (usft) (°) t. (°) (usft) usft ' (usft) ' (usft)"' (usft) (usft) 3,737.43 11,600.00 91.66 191.30 3,779.83 3,737.43 -6,773.43 -5,580.91 6,025,126.15 539,101.47 0.00 8,761.70 11,700.00 91.66 191.30 3,776.93 3,734.53 -6,871.45 -5,600.50 6,025,028.02 539,082.46 0.00 8,846.93 11,800.00 91.66 191.30 3,774.04 3,731.64 -6,969.47 -5,620.10 6,024,929.90 539,063.46 0.00 8,932.15 11,900.00 91.66 191.30 3,771.14 3,728.74 -7,067.49 -5,639.69 6,024,831.77 539,044.46 0.00 9,017.38 12,000.00 91.66 191.30 3,768.24 3,725.84 -7,165.51 -5,659.28 6,024,733.65 539,025.45 0.00 9,102.60 12,100.00 91.66 191.30 3,765.34 3,722.94 -7,263.53 -5,678.88 6,024,635.52 539,006.45 0.00 9,187.83 12,200.00 91.66 191.30 3,762.45 3,720.05 -7,361.54 -5,698.47 6,024,537.40 538,987.45 0.00 9,273.06 12,300.00 91.66 191.30 3,759.55 3,717.15 -7,459.56 -5,718.07 6,024,439.27 538,968.44 0.00 9,358.28 12,400.00 91.66 191.30 3,756.65 3,714.25 -7,557.58 -5,737.66 6,024,341.15 538,949.44 0.00 9,443.51 12,500.00 91.66 191.30 3,753.75 3,711.35 -7,655.60 -5,757.26 6,024,243.02 538,930.44 0.00 9,528.73 12,600.00 91.66 191.30 3,750.86 3,708.46 -7,753.62 -5,776.85 6,024,144.90 538,911.43 0.00 9,613.96 12,700.00 91.66 191.30 3,747.96 3,705.56 -7,851.64 -5,796.44 6,024,046.77 538,892.43 0.00 9,699.18 12,800.00 91.66 191.30 3,745.06 3,702.66 -7,949.66 -5,816.04 6,023,948.64 538,873.43 0.00 9,784.41 12,900.00 91.66 191.30 3,742.17 3,699.77 -8,047.68 -5,835.63 6,023,850.52 538,854.42 0.00 9,869.63 13,000.00 91.66 191.30 3,739.27 3,696.87 -8,145.69 -5,855.23 6,023,752.39 538,835.42 0.00 9,954.86 13,100.00 91.66 191.30 3,736.37 3,693.97 -8,243.71 -5,874.82 6,023,654.27 538,816.42 0.00 10,040.09 13,200.00 91.66 191.30 3,733.47 3,691.07 -8,341.73 -5,894.42 6,023,556.14 538,797.41 0.00 10,125.31 13,300.00 91.66 191.30 3,730.58 3,688.18 -8,439.75 -5,914.01 6,023,458.02 538,778.41 0.00 10,210.54 13,400.00 91.66 191.30 3,727.68 3,685.28 -8,537.77 -5,933.60 6,023,359.89 538,759.41 0.00 10,295.76 13,500.00 91.66 191.30 3,724.78 3,682.38 -8,635.79 -5,953.20 6,023,261.77 538,740.40 0.00 10,380.99 13,600.00 91.66 191.30 3,721.89 3,679.49 -8,733.81 -5,972.79 6,023,163.64 538,721.40 0.00 10,466.21 13,700.00 91.66 191.30 3,718.99 3,676.59 -8,831.83 -5,992.39 6,023,065.52 538,702.40 0.00 10,551.44 13,800.00 91.66 191.30 3,716.09 3,673.69 -8,929.84 -6,011.98 6,022,967.39 538,683.39 0.00 10,636.66 13,900.00 91.66 191.30 3,713.19 3,670.79 -9,027.86 -6,031.57 6,022,869.27 538,664.39 0.00 10,721.89 14,000.00 91.66 191.30 3,710.30 3,667.90 -9,125.88 -6,051.17 6,022,771.14 538,645.39 0.00 10,807.12 14,100.00 91.66 191.30 3,707.40 3,665.00 -9,223.90 -6,070.76 6,022,673.02 538,626.38 0.00 10,892.34 14,200.00 91.66 191.30 3,704.50 3,662.10 -9,321.92 -6,090.36 6,022,574.89 538,607.38 0.00 10,977.57 14,300.00 91.66 191.30 3,701.61 3,659.21 -9,419.94 -6,109.95 6,022,476.77 538,588.38 0.00 11,062.79 14,400.00 91.66 191.30 3,698.71 3,656.31 -9,517.96 -6,129.55 6,022,378.64 538,569.38 0.00 11,148.02 14,500.00 91.66 191.30 3,695.81 3,653.41 -9,615.98 -6,149.14 6,022,280.52 538,550.37 0.00 11,233.24 14,600.00 91.66 191.30 3,692.91 3,650.51 -9,713.99 -6,168.73 6,022,182.39 538,531.37 0.00 11,318.47 14,617.73 91.66 191.30 3,692.40 3,650.00 -9,731.37 -6,172.21 6,022,165.00 538,528.00 0.00 11,333.58 Total Depth:14617.73'MD,3692.4'TVD Targets Target Name -hit/miss target , Dip Angle Dip Dir. TVD ; +E/-W :: Northing Easting Shape (°) (°) (usft) S__ (usft) ' (usft) (usft) MPL-53 wp02 NB Toe 0.00 0.00 3,692.40 -9,731.37 -6,172.21 6,022,165.00 538,528.00 -plan hits target center -Circle(radius 50.00) MPL-53 wp02 NB Heel 0.00 0.00 3,892.40 -2,699.99 -4,767.82 6,029,204.00 539,890.00 -plan hits target center -Circle(radius 50.00) 10/9/2017 5:39:58PM Page 6 COMPASS 5000.1 Build 810 4110 • Halliburton HALLI B U RTO N Standard Proposal Report ,Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference Well Plan:MPU L-53 Company: Hilcorp Alaska,LLC TVD Reference: MPL-53 As-Staked Update @ 42.40usft Project: Milne Point ;.,MD Referen e 4 ,�, MPL-53 As-Staked Update @ 42.40usft Site: M Pt L Pad True N :Well: Plan:MPU L-53 Minimum Curvature il 'Wellbore: MPU L-53 MPU L-53 WP03 Design: -` Casing Points ..Measures Vertical. Depth Depth', ® . . . : : 7:41470f - (usft) (usft) *17 Name 7,440.00 3,892.02 9 5/8"x 12 1/4" 9-5/8 12-1/4 14,617.73 3,692.40 4 1/2"x 8 1/2" 4-1/2 8-1/2 io,tions easured Vertical - „” M . Depth Depth - +w.s *.l.....:-• SFr YY "1 (usft) (usft) (usft) ...I.'. , .1 (usft) ,ili-. Comment , 350.00 350.00 0.00 0.00 Start Dir 3°/100':350'MD,350'TVD 550.00 549.63 -6.00 -8.57 Start Dir 4°/100':550'MD,549.63'TVD 750.00 746.44 -25.90 -37.00 Start Dir 5°/100':750'MD,746.44'TVD 1,713.71 1,486.97 -253.60 -561.44 End Dir :1713.71'MD,1486.97'TVD 5,928.45 3,488.43 -1,541.61 -4,039.83 Start Dir 5°/100':5928.45'MD,3488.43'TVD 7,144.37 3,866.25 -2,405.94 -4,714.38 End Dir :7144.37'MD,3866.25'TVD 7,444.37 3,892.40 -2,699.99 -4,767.82 Start Dir 5°/100':7444.37'MD,3892.4'TVD 7,579.08 3,896.32 -2,832.18 -4,793.04 End Dir :7579.08'MD,3896.32'TVD 14,617.73 3,692.40 -9,731.37 -6,172.21 Total Depth:14617.73'MD,3692.4'TVD 10/9/2017 5:39:58PM Page 7 COMPASS 5000.1 Build 81D i S Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-53 MPU L-53 NB Prod MPU L-53 WP03 Sperry Drilling Services Clearance Summary Anticollision Report 09 October,2017 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt L Pad-Plan:MPL-53-MPL-53 NB Prod-MPL-53 WP03 Well Coordinates: 6,031,932.31 N,544,641.05 E(70'29'53.20"N,149°38'05.75"W) Datum Height: MPL-53 As-Staked Update @ 42.40usft Scan Range: 0.00 to 14,617.73 usft.Measured Depth. Scan Radius is 1,492.35 usft. Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 81D Scan Type: NO GLOBAL FILTER:Using user defined selection 8 filtering criteria Scan Type: 25.00 HALLIBURTON Sperry Drilling Services • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPL-53-MPL-53 WP03 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan:MPL-53-MPL-53 NB Prod-MPL-53 WP03 Scan Range: 0.00 to 14,617.73 usft.Measured Depth. Scan Radius is 1,492.35 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 L Pad MPL-I3-MPL-13-MPL-13 1,179.09 284.30 1,179.09 271.19 1,237.61 21.689 Centre Distance Pass- MPL-13-MPL-13-MPL-13 1,200.00 284.58 1,200.00 271.13 1,258.57 21.156 Ellipse Separation Pass- MPL-13-MPL-13-MPL-13 1,425.00 329.08 1,425.00 310.77 1,462.42 17.978 Clearance Factor Pass- MPL-16-MPL-16-MPL-16 621.68 156.81 621.68 150.46 618.56 24.694 Centre Distance Pass- MPL-16-MPL-16-MPL-16 650.00 157.01 650.00 150.36 646.15 23.631 Ellipse Separation Pass- MPL-16-MPL-I6-MPL-16 800.00 170.36 800.00 162.14 784.20 20.712 Clearance Factor Pass- MPL-16-MPL-16A-MPL-16A 621.68 156.81 621.68 150.46 618.56 24.694 Centre Distance Pass- MPL-16-MPL-16A-MPL-16A 650.00 157.01 650.00 150.36 646.15 23.631 Ellipse Separation Pass- MPL-16-MPL-I6A-MPL-16A 800.00 170.36 800.00 162.14 784.20 20.712 Clearance Factor Pass- MPL-17-MPL-17-MPL-17 357.67 196.27 357.67 193.41 366.69 68,648 Centre Distance Pass- MPL-17-MPL-17-MPL-17 375.00 196.32 375.00 193.36 383.83 66,271 Ellipse Separation Pass- MPL-17-MPL-17-MPL-17 825.00 244.11 825.00 238.11 823.56 40.681 Clearance Factor Pass- MPL-20-MPL-20-MPL-20 695.15 131.10 695.15 123.98 690.25 18.414 Centre Distance Pass- MPL-20-MPL-20-MPL-20 750.00 131.44 750.00 123.68 744.19 16.939 Ellipse Separation Pass- MPL-20-MPL-20-MPL-20 9,175.00 368.81 9,175.00 230.29 8,528.19 2.663 Clearance Factor Pass- MPL-21-MPL-21-MPL-21 26.50 174.37 26.50 173.45 30.30 190.787 Centre Distance Pass- MPL-21-MPL-21-MPL-21 375.00 174,97 375.00 171.00 377.87 44.082 Ellipse Separation Pass- MPL-21-MPL-21-MPL-21 800.00 225.66 800.00 217.61 787.13 28.047 Clearance Factor Pass- MPL-24-MPL-24-MPL-24 26.50 105.12 26.50 104.32 33.40 130.834 Centre Distance Pass- MPL-24-MPL-24-MPL-24 575.00 106.46 575.00 102.38 581.97 26.061 Ellipse Separation Pass- MPL-24-MPL-24-MPL-24 800.00 117.56 800.00 111.73 804.48 20.136 Clearance Factor Pass- MPL-25-MPL-25-MPL-25 359.84 151.71 359,84 148.90 353.99 54.007 Centre Distance Pass- MPL-25-MPL-25-MPL-25 375.00 151.75 375.00 148.85 369.17 52.264 Ellipse Separation Pass- MPL-25-MPL-25-MPL-25 800.00 195.45 800.00 189.71 790.23 34.055 Clearance Factor Pass- MPL-28-MPL-28-MPL-28 592.52 70.37 592,52 64.32 601.77 11.635 Centre Distance Pass- MPL-28-MPL-28-MPL-28 625.00 70.55 625.00 64.16 634.21 11.048 Ellipse Separation Pass- MPL-28-MPL-28-MPL-28 750.00 76.73 750.00 69.04 757.52 9.984 Clearance Factor Pass- MPL-28-MPL-28A-MPL-28A 592.52 70.37 592.52 64.32 601.77 11.635 Centre Distance Pass- 09 October,2017- 13:53 Page 2 of 8 COMPASS • 0 Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPL-53-MPL-53 WP03 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan:MPL-53-MPL-53 NB Prod-MPL-53 WP03 Scan Range: 0.00 to 14,617.73 usft.Measured Depth. Scan Radius is 1,492.35 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 MPL-28-MPL-28A-MPL-28A 625.00 70.55 625.00 64.16 634.21 11.048 Ellipse Separation Pass- MPL-28-MPL-28A-MPL-28A 750.00 76.73 750.00 69.04 757.52 9.984 Clearance Factor Pass- MPL-29-MPL-29-MPL-29 50.00 133.55 50.00 132.57 59.49 136.998 Centre Distance Pass- MPL-29-MPL-29-MPL-29 75.00 133.60 75.00 132.54 84.14 125.967 Ellipse Separation Pass- MPL-29-MPL-29-MPL-29 700.00 172.88 700.00 167.88 698.72 34.524 Clearance Factor Pass- MPL-32-MPL-32-MPL-32 26.50 44.86 26.50 43.95 20.74 49.058 Centre Distance Pass- MPL-32-MPL-32-MPL-32 - - - MPL-32-MPL-32-MPL-32 - - - MPL-33-MPL-33-MPL-33 100.00 119.07 100.00 117.91 106.40 102.187 Centre Distance Pass- MPL-33-MPL-33-MPL-33 350.00 119.64 350.00 116.80 356.18 42.097 Ellipse Separation Pass- MPL-33-MPL-33-MPL-33 775.00 157.03 775.00 151.45 786.01 28.165 Clearance Factor Pass- MPL-34-MPL-34-MPL-34 938.14 455.69 938.14 446.14 921.28 47.731 Centre Distance Pass- MPL-34-MPL-34-MPL-34 950.00 455.73 950.00 446.11 931.83 47.392 Ellipse Separation Pass- MPL-34-MPL-34-MPL34 9,575.00 776.03 9,575.00 641.16 9,288.73 5.754 Clearance Factor Pass- MPL-35-MPL-35-MPL-35 26.50 641.30 26.50 639.95 34.49 475.728 Centre Distance Pass- MPL-35-MPL-35-MPL-35 225.00 641.71 225.00 639.20 227.87 255.843 Ellipse Separation Pass- MPL-35-MPL-35-MPL-35 12,550,00 1,007.98 12,550.00 832.51 11,331.52 5.744 Clearance Factor Pass- MPL-35-MPL-35A-MPL-35A 26.50 641.30 26.50 639.95 35.29 475.728 Centre Distance Pass- MPL-35-MPL-35A-MPL-35A 225.00 641.71 225.00 639.20 228.67 255.843 Ellipse Separation Pass- MPL-35-MPL-35A-MPL-35A 12,550.00 1,007.98 12,550.00 832.40 11,332.32 5.741 Clearance Factor Pass- MPL-35-MPL-35APB1-MPL-35APB1 26.50 641.30 26.50 639.95 35.29 475.728 Centre Distance Pass- MPL-35-MPL-35APB1-MPL-35APB1 225.00 641.71 225.00 639.20 228.67 255,843 Ellipse Separation Pass- MPL-35-MPL-35APB1-MPL-35APB1 12,550.00 1,007.98 12,550.00 832.40 11,332.32 5.741 Clearance Factor Pass- MPL-35-MPL-35APB2-MPL-35APB2 26,50 641.30 26.50 639.95 35.29 475.728 Centre Distance Pass- MPL-35-MPL-35APB2-MPL-35APB2 225.00 641.71 225.00 639.20 228.67 255.843 Ellipse Separation Pass- MPL-35-MPL-35APB2-MPL-35APB2 12,550.00 1,007.98 12,550.00 832.40 11,332.32 5.741 Clearance Factor Pass- MPL-35-MPL-35APB3-MPL-35APB3 26.50 641.30 26.50 639.95 35.29 475.728 Centre Distance Pass- MPL-35-MPL-35APB3-MPL-35APB3 225.00 641.71 225.00 639.20 228.67 255.843 Ellipse Separation Pass- MPL-35-MPL-35APB3-MPL-35APB3 12,550.00 1,007.98 12,550.00 832.40 11,332.32 5.741 Clearance Factor Pass- MPL-36(Review Needed)-MPL-36-MPL-36 - - - - - - 09 October,2017- 13:53 Page 3 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPL-53-MPL-53 WP03 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan:MPL-53-MPL-53 NB Prod-MPLS3 WP03 Scan Range:0.00 to 14,617.73 usft.Measured Depth. Scan Radius is 1,492.35 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 MPL-36(Review Needed)-MPL-36-MPL-36 - - I; -04M - MPL-38(Review Needed)-MPL-36-MPL-36 Il •: -136.70 t& 1... 1. MPL-36(Review Needed)-MPL-36L1-MPL-36L1&PB WIIIIWI 11111111114-4.24 IlWiligill - MPL-36(Review Needed)-MPL-36L1-MPL-36L1&PB 10,014.21 58.28 10,014.21 25.07 9,432.51 1.755 Centre Distance Pass- MPL-36(Review Needed)-MPL-36PB1-MPL-36PB1 - - -.60 WWI. - MPL-36(Review Needed)-MPL-36PB1-MPL-36PB1 - - W-179.37 . 9,391. MPL-36(Review Needed)-MPL-36PB1-MPL-36PB1 - MPL-37-MPL-37-MPL-37 100.00 644.39 100.00 842.79 95.10 403.028 Centre Distance Pass- MPL-37-MPL-37-MPL-37 275.00 644.72 275.00 642.39 266.02 276.568 Ellipse Separation Pass- MPL-37-MPL-37-MPL-37 11,475.00 1,460.59 11,475.00 1,208.60 10,702.57 5.796 Clearance Factor Pass- MPL-37-MPL-37A-MPL-37A 100.00 644.39 100.00 642.79 104.30 403.028 Centre Distance Pass- MPL-37-MPL-37A-MPL-37A 275.00 644.72 275.00 642.39 275.22 276.567 Ellipse Separation Pass- MPL-37-MPL-37A-MPL-37A 11,425.00 1,472.50 11,425.00 1,218.19 10,669.73 5.790 Clearance Factor Pass- MPL-39-MPL-39-MPL-39 - - 111.1 MPL-39-MPL-39-MPL-39 1.111 MPL-39-MPL-39-MPL-39 8,636.34 134.07 8,636.34 19.58 8,210.99 1.171 Centre Distance Pass- MPL-40-MPL-40-MPL-40 1,132.61 613.10 1,132.61 604.35 1,140.19 70.079 Centre Distance Pass- MPL-40-MPL-40-MPL-40 6,675.00 639.05 6,675.00 562.94 7,124.42 8.396 Ellipse Separation Pass- MPL-40-MPL-40-MPL-40 7,200.00 871.02 7,200.00 704.81 7,427.39 5.241 Clearance Factor Pass- MPL-43-MPL-43-MPL-43 26.50 223.94 26.50 223.24 34.90 319.843 Centre Distance Pass- MPL-43-MPL-43-MPL-43 250.00 224.37 250.00 221.92 256.81 91.589 Ellipse Separation Pass- MPL-43-MPL-43-MPL-43 825.00 287.25 825.00 281.02 805.93 46.119 Clearance Factor Pass- MPL-43-MPL-43PB1-MPL-43P81 26.50 223.94 26.50 223.03 34.90 245.092 Centre Distance Pass- MPL-43-MPL-43PB1-MPL-43PB1 250.00 224.37 250.00 221.71 256.81 84.246 Ellipse Separation Pass- MPL-43-MPL-43PB1-MPL-43PB1 825.00 287.25 825.00 280.81 805.93 44.593 Clearance Factor Pass- MPL-45-MPL-45-MPL-45 451.39 220.39 451.39 217.16 459.05 68.237 Centre Distance Pass- MPL-45-MPL-45-MPL-45 475.00 220.44 475.00 217.07 481.69 65.521 Ellipse Separation Pass- MPL-45-MPL-45-MPL-45 900.00 246.03 900.00 239.53 887.91 37.859 Clearance Factor Pass- Plan:MPL-52-MPL-52 NB In)-MPL-52 wp07 325.00 15.00 325.00 11.65 325.00 4.488 Centre Distance Pass- Plan:MPL-52-MPL-52 NB In)-MPL-52 wp07 375.00 15.21 375.00 11.46 374.86 4.053 Ellipse Separation Pass- Plan:MPL-52-MPL-52 NB In)-MPL-52 wp07 475.00 16.89 475.00 12.39 474.54 3.751 Clearance Factor Pass- 09 October,2017- 13:53 Page 4 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPL-53-MPL-53 WP03 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan:MPL-53-MPL-53 NB Prod-MPL-53 WP03 Scan Range: 0.00 to 14,617.73 usft.Measured Depth. Scan Radius is 1,492.35 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 Plan:MPL-54-MPL-54 NB lnj-MPL-54 wp03 402.12 29.97 402.12 25.94 401.88 7.452 Centre Distance Pass- Plan:MPL-54-MPL-54 NB Inj-MPL-54 wp03 425.00 30.10 425.00 25.90 424.41 7.176 Ellipse Separation Pass- Plan:MPL-54-MPL-54 NB In)-MPL-54 wp03 500.00 32.57 500.00 27.81 498.15 6.840 Clearance Factor Pass- Plan:MPL-56-MPL-56-MPL-56 WP01 329.13 109.99 329.13 106.61 329.23 32.540 Centre Distance Pass- Plan:MPL-56-MPL-56-MPL-56 WP01 350.00 109.99 350.00 106.42 350.00 30.780 Ellipse Separation Pass- Plan:MPL-56-MPL-56-MPL-56 WP01 600.00 133.80 600.00 128.14 591.61 23.608 Clearance Factor Pass- Plan:MPL-57-Wellbore#1-MPL-57 WP01 350.00 111.01 350.00 108.12 350.10 38,449 Ellipse Separation Pass- Plan:MPL-57-Wellbore#1-MPL-57 WP01 675.00 139.51 675.00 134.60 673.32 28.422 Clearance Factor Pass- Plan:MPU L-51-MPU L-51-MPU L-51 wp04 939.27 84.00 939.27 77.15 979.01 12.264 Ellipse Separation Pass- Plan:MPU L-51-MPU L-51-MPU L-51 wp04 975.00 84.18 975.00 77.31 1,016.39 12.246 Clearance Factor Pass- Milne Point Exploration MPU-Liviano-01-Liviano-01-Liviano-01 14,617.73 541.23 14,617.73 463.97 3,750.51 7.005 Clearance Factor Pass- MPU-Liviano-01-Liviano-01A-Liviano-01A 14,617.73 500.34 14,617.73 421.48 3,766.14 6.345 Clearance Factor Pass- Pesado-01-PESADO-01-Pesado-01 9,325.00 1,011.32 9,325.00 913.76 3,739.44 10.366 Clearance Factor Pass- Pesado-01-PESADO-01-Pesado-01 9,675.00 931.29 9,675.00 851.55 3,666.03 11.678 Ellipse Separation Pass- Pesado-01-PESADO-01-Pesado-01 9,733.45 929.56 9,733.45 853.61 3,651.88 12.240 Centre Distance Pass- Pesado-01-PESADO-01A-Pesado-01A 9,375.00 959.84 9,375.00 862.50 3,844.71 9.861 Clearance Factor Pass- Pesado-01-PESADO-01A-Pesado-01A 9,675.00 891.75 9,675.00 809.68 3,811.78 10.865 Ellipse Separation Pass- Pesado-01-PESADO-01A-Pesado-01A 9,737.06 889.55 9,737.06 811.50 3,809.90 11.397 Centre Distance Pass- • Survey tool program From To SurveylPlan Survey Tool (usft) (usft) 26.50 800.00 MPL-53 WP03 SRG-SS 800.00 7,500,00 MPL-53 WP03 MWD+IFR2+MS+sag 7,500.00 14,617.73 MPL-53 WP03 MWD+IFR2+MS+sag 09 October,2017- 13:53 Page 5 of B COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPL-53-MPL-53 WP03 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. 09 October,2017- 13.53 Page 6 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPL-53-MPL-53 WP03 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to MPL-53 As-Staked Update©42.40usft. Northing and Easting are relative to Plan:MPL-53. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150.00°,Grid Convergence at Surface is:0.34°. _13-MPL-20 MPL-20 MPI-20 V4 -II- MPL-21,MPL-21,MPL-21 V4 Ladder Plot - MPL-24,MPL-24,MPL-24V1 -ff- MPL-25,MPL-25,MPL-25 V1 I : -e- MPL-28,MPL-28,MPL-28 V14 C •/SLI,, ;''1 e, , I 1► ,7 0• �4,, -$ MPL-28,MPL-28A -28AV2 < Ilt nll `�� ^ 4 !'III Aj1 • ,� 4 -�«;. 1 :'�' •\ p � !*. -6- MPL-33,MPL33,MPL33V4 in I 1/ 11 �, I/ ? _ \I : I; ! nti- MPL-34,MPL-34,MPL-34 V1 0 11/I// J _.._. ry ry ii, ��► !� yE _, $ MPL-35,MPL35,MPL-35 V6 O 11 41/• II, •`•,p II Ver �\ '` lI /. +►r isit MPL35,MPL35A,N1PL35AV12 r '0.VI w.�, y:. (Q• 900 /L 111 •• /i � ;A ,ry i $ MPL35MPL35APB1,MPL35APB1V5 ,: ,.t/ %op,, � 'F`' •\ � -e- MPL-35MPL-35APB2MPL35APB2V3 \i Il�„ 14 ,`.4MlI '44if , - ``f► �'! -Ar- MPL36(ReviewNeeded),MPL36PB1,MPL36PB1 V3 U ' ��(Ci,'r�l �, MPL37,MPL-37,MPL37V3 •,;;!UAVI:p p,l -e- MPL37,MPL37A,MPL37AV1 •:•',..!!'fiy�� _ __ -14-MPL-39,MPL39,MPL39V3 • _'w ��%'/.I t'' -- el-1► -i- MPL-40,MPL-40,MPL40V4 U .,.1_G3 I -a- MPL-43,MPL-43,MPL-43V3 0 --. MPL-43,MPL43PB1,MPL-43PB1 V5 0 2500 5000 7500 10000 12500 -34- MPL-45,MPL45,MPL-45 V7 -4- Plan:MP L-52,MPL-52 NB hi,MPL52wp07VO Measured Depth(2500usft/in) -4- Plan:MPL-54,MPL-54NBhj,MPL54wp03VO 'ldt I.IVIYL-30,MYL- ,Mr L-00 VVI-U I VU 09 October,2017- 13:53 Page 7 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPL-53-MPL-53 WP03 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor 19 1t 1 /s f )1 i I 4' -t- MPL 21,MPL 21,MPL-21 V4 i 4.4 .... , l ..I f 1.. i MPL24,MPL-24 MPL-24 V1 �E- 10.00 ! `� { _... ._. ' .11 _. ‘til_ AA ... �I '-- .. $ MP L-25,MP L-25,MPL-25 V1 iC„ `11 $ MPL-28,MPL-28,MPL-28V14 A .. ._ .. . $ MPL-28,MPL 22287:1 8A,MPL 28A V2 8.75- @jm, _` 1'! _._ _...... - -A- I I \ /� •\ay I �� MPL 29 MPL-29 MPL-29 V1 t I ,_ . -- 1,,, Ky I :'' - -1- - -e- MPL32,MPL-32, -32V9 "E' 7.50- }. .11 , 1 , i �\. v ,/t'.,,1 .._I-._- _ $ MPL33,MPL-33, -33 V4 �I ,,,,,,,,,_,,,,,,,,"" +, _ , .I - - -a- MPL-34,MPL-34,MPL-34 V10 ,o r/+,l __ _,_,,,,_,I !- A A I //fi $ MPL-35,MPL-35,MPL-35 V6 N 6.25 i --- ---- A ! H, .� r--1 - -2- MPL35,MPL35A,MPL-35, u -�+ 115 r $ MPL35,MPL35APBl,MPL-35APB1 V5 m /. [I I ; ..............___ ___`®�l _ + • - +p 1 I _i ... -e- MPL35,MPL35APB2,MPL-35, 0 5.00 ,A_+ �� .�.._ ___If:............ _-1 / _ -- __. �E- MPL-35,MPL35APB3,MPL35APB3V5 i`i ---I ' 1 'XE- MPL-36(Review Needed),MPL-36,MPL-36 V7 in 3.75 j = 1 t / i t f_- -I- MPL-36(ReviewNeeded),MPL-36L1,MPL36L1&PB V0 0 tt _... } _.._._... ,.,,� _ _ 4 .. l® i. ._ ,. .,,_.,+ - -a- MPL-36(ReviewNeeded),MPL36PB1,MPL-36PB1 V3 ;7.1.l .1.......- 4 1",r; i 1 ) +- $ MPL37,MPL-37,MPL-37 V3 _; .- � �'� ._._...__ k �r11 ....._.._. _ $ MPL37,MPL-37,2.50 .. .__. , i ... ...._.. .`1_. l� !'��� �- .- `11, _ NM 44- MPL39MPL-39, Collision Avoidance Req r ��� ►;��■ 1(,Ir i +�i [H 111 1 NaGo�Zo top Drill ng _ - �_.'.. ._....__ 'u3■�� ,1 to p l �I 1 L. ,,.�- ---' )E• MP L-43, V4 25 MPL-43 V3 , i- MPL�43P B1 V5 I ___...I ti ....I ..1- ----- ---- -- --- wcs,�! I. -X- MP L-45,MP L-45,MP L-45 W 0.00 I I I , III II 1111 i Iii 1111 IIIIIIIIIIIII i 1 i 1 1 III II $ Plan:MP L-52,MP L-52 NB Inj,MPL-52wp07 V0 0 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 $ Plan:MP L-54,MP L-54 NB Inj,MPL-54wp03 V0 Measured Depth(2500usftAn) -e-Plan:MPL-56,MPL-56,MPL56VvP01 VO 09 October,2017- 13:53 Page 8 0/8 COMPASS • • TRANSMITTAL LETTER CHECKLIST WELL NAME: rl 1 IL L -�3 PTD: I 7-- PlY Development Service Exploratory Stratigraphic Test Non-Conventional FIELD: /iIn. Aft POOL: fitlY14 �c, L rackr 3 1 Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (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 E J , , , , , C m o o N Qj co LU coc a ui o O S m. , , E. �, a) iri o c E O . 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