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Home My WebLink About217-151MEMORANDUM 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-51 MILNE PT UNIT L-51 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/26/2023 L-51 50-029-23587-00-00 217-151-0 W SPT 3940 2171510 1500 100 101 101 102 378 563 557 555 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-51 Inspection Date: Tubing OA Packer Depth 746 1684 1646 1638IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSAM221212181754 BBL Pumped:0.9 BBL Returned:0.9 Thursday, January 26, 2023 Page 1 of 1        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. 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D@0 E 0 O. D 0 Oo aa Qpw 00 _ IL O _ m a 2 WW J 3 z U a 0 0 o e 10 0 i k'I= 1ifCu SE B c 1 2018 STATE OF ALASKA IIII ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT ANDfi°€44Sc 1 C la.Well Status: Oil E 4 Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1 b.Well Class: 20AAC 25.105 20AAC 25.110 Development Q , Exploratory ❑ GINJ ❑ WINJ E 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.: 12/22/2017 , 217-151 ' 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 November 28,2017 • 50-029-23587-00-00 4a.Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 3776'FSL,5126'FEL,Sec 8,T13N, R10E, UM,AK December 12,2017 i MPU L-51 ' Top of Productive Interval: 9. Ref Elevations: KB: 42.5' 17. Field/Pool(s):Milne Point Field 587'FNL,2073'FEL,Sec 18,T13N, R10E, UM,AK GL:16' BF:16' Schrader Bluff Oil Pool ' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 2377'FNL, 1820'FWL,Sec 19,T13N,R10E, UM,AK 13,510'MD/3,711'TVD . ADL025509(SHL)/ADL025515(TPH/BHL) ` 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MDlTVD: 19. DNR Approval Number: Surface: x- 544656 y- 6031906 Zone- 4 13,874'MD/3,733'TVD - LONS 83-085 TPI: x- 542565 y- 6027588 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 541303 y- 6020511 Zone- 4 N/A 2,306'MD/1,846'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 DGR ABG EWR ADR Horizontal Presentation MD DGR ABG EWR ADR Revert Section TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 16" 164# A-53 Surface 107' Surface 107' Cond 270 ft3 Stg 1 L-480 sx/T-390 sx 37 bbls 9-5/8" 40# L-80 Surface 6,600' Surface 3,988' 12-1/4" Stg 2 L-394 sx/T-270 sx 252 bbls 7-5/8" 29.7# L-80 Surface 6,453' Surface 3,940' Tieback Tieback Assembly 4-1/2" 12.6# L-80 6,450' 13,515' 3,939' 3,710' 8-1/2" Cementless Screen 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(MDITVD) Size and Number; Date Perfd): 2-7/8" 4,985' N/A 4-1/2"13.5#Hyd 625 Excluder 2000 Screens 6,657'-13,428'MD/3,936'-3,716'TVD 26.ACID, FRACTURE,CEMENT SQUEEZE,ETC. Was hydraulic fracturing used during completion? Yes❑ No Q 1-1.../2.2-1)b Per 20 AAC 25.283(i)(2)attach electronic and printed information DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 12/27/2017 ESP Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 1/27/2018 24 Test Period .....4 785 0 0 N/A N/A Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 257 340 24-Hour Rate 785 0 0 13.3 Form 10-407 Revised� 5/2017 /fit. ?1 /8 CQNTINUED ON PAGE 2 RE3D�S t„,__ .y FEB i ic,�submit ORIGINIAL o5 • • 28.CORE DATA Conventional Core(s): Yes ❑ No 0 Sidewall Cores: Yes ❑ No El If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips, photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑., Permafrost-Top If yes, list intervals and formations tested, briefly summarizing test results. Permafrost-Base 2,306' 1,846' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval Schrader Bluff 6,657' 3,936' information, including reports, per 20 AAC 25.071. SV5 1,585' 1,425' SV1 2,771' 2,119' UGNU LA3 5,047' 3,439' Schrader NA 6,213' 3,911' Schrader NB 6,427' 3,937' 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: Monty Myers Contact Name: Cody Dinger Authorized Title:Drilling Manager Contact Email: cc'Inger(p7hiICOr-.COCi1 Authorized Contact Phone: 777-8389 Signature: '— - Date: 2 - 1 - I INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 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 H . III Milne Point Unit Well: MPU L-51 SCHEMATIC Last Completed: 12/22/2017 thlcorp Alaska,LLC PTD: 217-151 Orig.KBElev.:26.5'(Innovation) TREE&WELLHEAD _ Tree 5K FMC 2-9/16" c r Wellhead FMC Gen 5 16' !" r, Ig CEMENT DETAIL 1 'd 16" 270 cf of cement in a 36"Hole Stage 1:Lead 480 sx(211.2 bbls)of 11.7#Extends Cem Dual .,,',4' Tail 390 sx(79.9 bbls)of 15.8#Swift Cem 3/8"SS 9-5/8" Stage 2: Lead 394 sx(303.5 bbls)of 10.7#Permafrost L CernCapstrir Tail 270 sx(55.8 bbls)of 15.8#Swift CernCASING DETAIL il Size Type Wt/Grade/Conn ID Top Btm ES Cementer '` 16" Conductor 164/A-53/Welded N/A Surface 107' @2586' 9-5/8" Surface 40/L-80/DWC625 8.3.875835 Sur6face4506,13600515' 04 7-5/8" Tieback 29.7 12.6/L-80L-80//Hyd VAM STL 6.875 Surface 6,453' 4-1/2" Liner / , ' , ' k �;r TUBING DETAIL Min ID= W 2 4 it 2-7/8" Tubing 6.5/L-80/EUE 8rd 2.441 Surface 4,985' 2.205"@ 1 3/8" Dual Capstring SS N/A Surface 4,983' 4,702' is t 3 i, 4 mi 7 WELL INCLINATION DETAIL v 5&6 .* KOP @ 43' 4' Max Hole Angle=93.9 deg.@ 13,458' k; 8&9 0 JEWELRY DETAIL No Depth Item 71, 10 0 1 131' Sta#2:GLM-1"Side Pocket KBMM w/Orifice 2 4,745' Sta#1:GLM-1"w/Dummy te 3 4,855' 2-7/8"XN-Nipple(2.205 No-go ID) 11 4 4,897' Discharge Head:FPDIS at, 12 + 5 4,898' Upper Tandem Pump:134 STG FLEX 17.5 _ 6 4,921' Lower Tandem Pump:134 STG FLEX 17.5 7-5/8 7 4,944' Gas Separator:GRS FER N AR 8 4,948' Upper Tandem Seal:GSB3DBUTSB/SB PFSA ,,, 9 4,955' Lower Tandem Seal:GSB3DBUTSB/SB PFSA 4®®® OM/13 10 4,961' Motor:XP—300hp/2090V/88A 9-5/8" allig14 11 4,981' Sensor,Phoenix XT150 N. 12 4,983' Centralizer:Bottom @ 4,985' 13 6,450' BOT SLZXP Liner Top Pkr w/BD Slips,7"x 9 5/8" III 14 6,484' Crossover Sub,7"H563 x 4.5"Hyd 625 15 13,510' WIV Valve with Ball on Seat 16 13,513' Round Nose Float Shoe:Bottom @ 13,515 IIIbGENERAL WELL INFO 1I I I I API:50-029-23587-00-00 Drilled,Cased and Completed by Innovation -12/22/2017 VIII VIII, ;1111$ III 15&16 TD=13,874'(MD)/TD=3,733'(TVD) PBTD=13,510'(MD)/PBTD=3,711'(TVD) Edited By:CD 12/27/2017 • • Hilcorp Energy Company Composite Report Well Name: MP L-51 Field: Milne Point County/State: ,Alaska (LAT/LONG): evation(RKB): API#: Spud Date: 11/28/2017 Job Name: 1713436D MPL-51 Drilling Contractor AFE#: AFE$: 11/26/2017 Continue to prep rig for move to MPL-51.Trucks on location @ 08:00 hrs.Separate Modules and stage on Pad.Back Sub off of L-53.Set sub down on Mats.;Clear and clean around L-53.Prep L-51 slot for mats and liner.Lay liner and set rig Mats.Walk Sub over MPL-51.;PJSM with oncoming crew.Set down sub and shim same,stage diverter line,set catwalk,set mud module,set pipe shed and motor module,R/U interconnects.Get steam circulating on rig.;Submit 24 hr diverter test notification to AOGCC @ 18:00.Release trucks at 23:30.;Spot break shack and enviro-vac.Plug in rig and put generator on line.Lower stairs on landings,Set and lower outriggers,turn on rig air.Perform derrick inspection,scope derrick up.Bridal down.;Perform full derrick inspection after scope up.Get water circulatina throuahout ria.Lay oit liner for cuttinas box. 11/27/2017 Assist welder w/Modify Landing rig height.Had to add 6"to to conductor.Rebulid Stand Pipe Demco Valve,button up MP's,Pull unneeded rig mats.Spot cuttings tank and berm up same.;Ready shed for DP.Process HWDP.House keep PAD.Prep for NU. Rig on Shore Power @ 10:30 hrs.;Continue to weld out Landing ring on conductor.Mechanic C/O oil seal on#2 Centrifuge feed pump.;Begin MU Diverter System.M/U starting head on conductor as per wellhead rep. M/U diverter Tee,set stack in place,start M/U knife valve.;M/U 16"diverter line and align same.Place containment at end of diverter,set barricades for exclusion zone,place diverter warning sign.M/U annular and knife valve koomey lines.;lnstall riser and catch pan,Install turn buckles. Install hoses on drain pans,torque all bolts.Close 4"conductor valves.Simops: Load strap and tally 5"DS50 DP in shed-;C/O seal on#2 centrifuge pump,Test PVT sys, lines in pits and centrifugal pumps.Un-pin and Pump thru pop off valves on mud pumps.Work on rig acceptance checklist.;Inspect, service,R/U Hawk Jaw on floor.Finish strap and tally on 5"DP in shed.Install short mouse hole.P/U first jt 5"DP,Function diverter,12 sec to close annular,4 sec to open knife valve;Drift and P/U 5"DS50 DP and rack stds in derrick(254 jts total)Load BHA tools into pipe sheaiawarm ufs,stock hopper room with products for spud mud. Note:tag depth @ 100'.;Accept rig on L-51 @ 06:00.;Hauled 0 bbls cuttings to MP G&I for total=0 bbls Hauled 340 bbls H2O from 6 mile lake for total=340 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls 11/28/2017 Continue to Drift and P/U 5"DS50 DP and rack stds in derrick while W/O AOGCC to witness Diverter Test.Accept Rig on MPL-51 @ 06:00 hrs.;Test Diverter System on 5"DP 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.Test.Test Gas alarms and PV f System.;Added an additional 20'section of 16"Vent Line as per AOGCC Rep Bob Noble.;Continue to Drift and P/U 5"DS50 DP and rack stds in derrick(224 Jts Total).PU and rack back 17 jts HWDP w/Jars.Rd Hawk Jaw.Clean and clear rig floor.;Slip and cut 70'drill Iine.;Service Rig.;PT Mud line/Demco to 2500 psi.Blow down and fill conductor and diverter stack with water.Air boot leaking.Pull Bell Nipple to access air boot.Pull air boot.;Bring tools to rig floor.;PJSM,M/U 12.25"PDC drillout assy with 1.5°mtr(non ported float). Bit,Mtr and XO=34.99'length. RIH on 5"HWDP. Tag @ 100'. Flood lines and stack with fresh water(no leaks).;Drill 12.25"surface hole F/100'-T/219'MD. Displace from fresh water to spud mud @ 106'(est btm conductor). 400 gpm, 520 psi,70%flow,20 rpm,1.7k tq. Mostly pea gravel with some clay.;Plugged flowline once @ 115'MD. Picked up,jetted flowline clear then continued drilling ahead.;POOH F/219'-T/surface. M/U remaining 12.25"directional drilling assy MWD/LWD 8"tools as per DD/MWD. Scribe and download. RFO= 251.51°.;Wash down and continue drilling 12.25"surface hole F/219'-T/267'MD. 400 gpm,660 psi,64%flow,40 rpm,1.9k tq.;Attempt to gyro @ 267'MD. Unable to get centralizers to pass ID of drill pipe. Re-dress Gyro tool with smaller bow springs and add additional wt bar. No issues after that.;Drill 12.25"surface hole F/267'-T/360'MD.93'total-62'AROP 3-5k wob,40 rpm,2k tq 400 gpm,720 psi,62%flow KOP @ 267 MD directional plan WP07A.;Hauled 171 bbls cuttings to G&I for total=171 bbls Hauled 390 bbls H2O from 6 mile lake for total=730 bbls Total metal last 24 hrs 0 lbs for total=0 lbs 11/29/2017 Drill ahead and Gyro Survey every stand Fl 360'T/719'and obtain clean MWD Survey.Drill to Survey depth of 846'obtain 3 additional clean MWD surveys and release Gyro.;400/480 GPM,850/1020 PSI,40 RPM,2-3K TQ,2-8K WOB,PU/SO/ROT 73/72/71.;Drill ahead F/846'T/1265'(419'),Av 120 FPH 550 GPM, 1325 PSI,WOB 5-10K,RPM 80,TQ 3-5K MW in/out 9.0+ppg,vis 219,9.7 ECD,8 bgg.PU/SO/ROT 78/75k/74k.;Last Survey @ 1226'MD,12.19 Inc,208.58 Azm,5.31'high,10.97'right.Distance to plan 12.19'.;Drill ahead F/1265'-T/1768'MD. 503'total=84'AROP 8k WOB,80 rpm,5k tq 550 gpm,1540 psi,62% flow,85k up,74k dn,80k rot 70 BGG w/9.9 ECD(9.15 MW/200 vis). EOB @ 1614'MD.;Drill ahead F/1768'-T/2271'MD. 503'total=84'AROP 10k WOB, 80 rpm,6.1k tq 550 gpm,1620 psi,62%flow,93k up,73k dn,82k rot 20 BGG w/10.1 ECD(9.2 MW/200 vis).;Screened up from 80's to 100's both shakers. Stg up water from 30 BPH to 60 BPH and run shakers wet to help manage unwanted increase in mud wt.Continue dump and dilute.Inc centrifuge rates.;Last survey @ 2043'MD=3.5'high and 2.2'left of well plan 07A.;Hauled 798 bbls cuttings to G&I for total=969 bbls Hauled 490 bbls H2O from 6 mile lake for total=1220 bbls 11/30/2017 Drill ahead Fl 2271'-T/2900'MD. 629'total=114.4'AROP 2-8k WOB,70 rpm,5.8k tq 550 gpm,1575 psi,104k up,71k dn,82k rot 20 BGG w/9.7 ECD(9.2+ MW/150 vis).;Logged base of permafrost @ 2306'.Drilled 200'below permafrost lowering visc to 130-150 range.Screen up to 120's on both shakers @ 2840'. Both Centrifuges on Line.;Having to fight shaker after screening up.Mud Check showed Sand content @ 2%and Mud Wt @ 9.2+.Could not keep mud on shakers @ 450 gpm.;Rack Back 1 std to 2831'.CBU x 2 staging pump from 400 to 600 gpm,rotating 75 rpm,until mud staying on shakers with shaker decks at low setting.Circulate 1 additional bottoms up @ 600 gpm.;Sand Content down f/2%to.75%,MW down f/9.2+to 9.1. Drilled ahead with no further issues at shakers.;Drill ahead F/2900'-T/3500'MD. 600'total=109'AROP 2-8k WOB,70 rpm,8-9k tq 550 gpm,1850 psi,118k up,79k dn,89k rot 20 BGG w/10.1 ECD(9.1+MW/120 vis).Max Gas @ 450u.;Drill ahead F/3500'-T/4031'MD. 531'total=89'AROP 2-8k WOB,70 rpm,10.7k tq 550 gpm,1700 psi,138k up, 81k dn,103k rot 100 BGG w/9.8 ECD(9.1+MW/120 vis).Max Gas @ 345u.;Drill ahead F/4031'-TI 4597'MD.566'total=95'AROP 6-8k WOB,70 rpm, 11.8k tq 550 gpm,1810 psi,147k up,83k dn,106k rot 100 BGG w/9.9 ECD(9.1+MW/120 vis).Max Gas @ 165u.;Backream full stands @ connections. Control drilled with min wt on bit(2-4k)@ 200 ft/hr to minimize loading hole with cuttings. Saw significant drop tendency with BHA(1.5-3°/100')until 4120' MD.;Saw formation change w/bit wt at 4120'MD. Started seeing slight build tendencies w/right hand walk after that. Continue running water @ 40 BPH to control wt/vis.Inc avg ROP 250 max ft/hr.;Last survey @ 4307'MD,56.57°Inc,209.73°Az=4.6'high and 3.8'right of well plan 07A.;Hauled 1197 bbls cuttings to G&I for total=2166 bbls Hauled 1500 bbls H2O from 6 mile lake for total=2720 bbls all 12/1/2017 Drill ahead F/4597'-TI 4847'MD.250'total=100'AROP 6-8k WOB,70 rpm,9-14k tq 575 gpm,1 si,152k up,82k dn,108k rot 100 BGG WI 10.0 ECD (9.1+MW/135 vis).Max Gas @ 165u.;Rack back 1 stand and pump clean up cycle @ 600 gpm/70 rpm.Hole unloaded @ BUS for 80-90 bbls.ECD down from 10.4 to 9.9.;Drill ahead F/4847'-T/4950'MD.103'total=103'AROP 2-8k WOB,70 rpm,9-14k tq,550 gpm,1945 psi, Pump 30 bbl Tandem Lo Vis/Hi Vis Sweep.;Finish circulate sweep out of hole.While change out piston on#1 MP.Sweep came back strung out due to loss of MP#1.Minimal change at shakers.;Drill ahead F/4950'-T/5414'MD.464'total=103'AROP 6-8k WOB,70 rpm,14-16k tq 575 gpm,2115 psi,173k up,83k dn,112k rot 100 BGG w/ 10.3 ECD(9.1+MW/148 vis).;Pump tandem sweep clean up cycle before starting turn and build section @ 5448'.ECD down from 10.1 to 9.9.Hole unloaded 310 bbls into circulation w/200%increase, and cleaned up after 124 bbls;Drill ahead F/5414'-T/5763'MD.349'total=54'AROP 20k WOB,80 rpm,17.8k tq 550 gpm,1940 psi,183k up,81k dn,115k rot 25 BGG w/9.7 ECD(9.2+MW/100 vis).;Start build and turn @ 5448'MD. Slow drilling due to hard streak and slide percentage. Saw the same thing drilling L-53 at relative depths.;Drill ahead F/5763'-T/5892'MD. 129'total=22'AROP 30k WOB,80 rpm,18k tq 550 gpm,2000 psi,190k up,83k dn,119k rot 30 BGG WI 9.7 ECD(9.2+MW/100 vis).;Continue running water @ 40-50 BPH to help manage wt/vis.;Last survey @ 5753'MD,67.24°Inc,202.15°Az=8.4'high and 14.8'right of well plan 07A.;Hauled 1130 bbls cuttings to G&I for total=3296 bbls Hauled 1070 bbls H2O from 6 mile lake for total=3790 bbls No losses to formation noted. 12/2/2017 Drill ahead F/5892'-T/5990'MD. 98'total=16.5'AROP 30k WOB,60-80 rpm,13-18k tq 550 gpm,2015 psi,181k up,80k dn,117k rot 30 BGG wI 9.5 ECD (9.2+MW/100 vis).;Pump 25 bbls Condent/Nut Plug Sweep.Had slight ROP increase and WOB decrease when sweep at the bit.Adjust parameters as needed to minimize slip stick.;Drill ahead F/5990'-T/6043'MD. 53'total=35'AROP. Survey @ 5941'showed 10 deg DL.Racked back 1 stand to 5980'.;Orient TF to Low Side and Wash up/down and attempt to reduce 10 deg DL.Re shoot survey w/9.89.;Drill ahead F/6043'-T/6165'MD. 122'total=61'AROP 30k WOB,60- 80 rpm,13-18k tq 550 gpm,2175 psi,182k up,78k dn,115k rot 30 BGG w/9.7 ECD(9.2+MW/120 vis).;At 6140'start to see crude @ surface.;Drill ahead Ff 6165'to TD @ 6610'MD. 445'total=56 AROP 25k WOB,60-80 rpm,18k tq 550 gpm,2100 psi,185k up,73k dn,112k rot 130 BGG w/9.7 ECD(9.2+MW/ 90 vis).;Landed TD in middle of structure(5'from top)NB sand. Projected to bit @ 6610'MD/3938'ND,93.98°Inc,193.89°Az=1.8'low,5.9'right of well plan 07A.;Obtain final svy @ TD. Rack back 3x stds and circulate 4x Btms up. 600 gpm,2090 psi,68%flow,70 rpm,17.2k tq,50 bgg. ECD's went from 9.8 to 9.6 EMW.;Reduce vis from 100 to 75,reduce YP from 36 to 28. Pump tandem sweep(25 bbls lo vis/wt followed by 25 bbls hi vis/wt). Sweep came back 500 stks late w/no significant increase in cuttings.;Hauled 706 bbls cuttings to G&I for total=4002 bbls Hauled 950 bbls H2O from 6 mile lake for total=4740 bbls No losses to formation noted for surface;Attempt to go back on hi-line. Saw power fluctuation. Go back on rig power and troubleshoot. 12/3/2017 Continue to circulate and condition mud lowering vis to 60-70 range and YP 24,MW 9.2.Wash 3 stands back to bottom with no issues.Pumping 600 gpm/70 rpm.;BROOH from 6610'to 4156'Pulling 30-35 fpm,600 gpm 70 rpm.See increase in cuttings at shaker.Attempt to continue BROOH @ 8-10 fpm to allow hole to clean up.Shakers loaded up.;Note:Back ream x 3 through 9.9,8.4,and 9.3 DL intervals with no issues.;CBU from 4156'staging pump up from 450 to 600 gpm.Getting mostly fine sands back and cleaned up shortly after BUS.;Continue to BROOH from 4156'to 2585'(280'below base of permafrost)Hole unloading and fighting shakers.;CBU x 2 from 2585"staged pump up from 400 to 600 gpm.Mostly fines back on 1st BU and larger clays/fine sands back on 2nd BU.;Continue to BROOH from 2585'to 1453'MD.No issues back reaming through permafrost.;Continue BROOH Fl 1453'-T/640'MD. Slowed pulling speed to 10 fpm @ 1300'-1000'due to hole unloading. Reduced rpm's from 70 to 30 once in lower inclination part of hole.;No notable overpulls w/only slight bobbles while pulling through build section in upper part of hole. 450-600 gpm,930 psi.;Monitor well @ HWDP(static). Pull on elevators F/640'-surface without issue. Racked back HWDP w/jars.;Download MWD. B/O and laydown all 8"tools. Flush,drain motor and B/O bit.LID same.Bit grade-1,3,CT,T,X,I,WT,TD. No damage on BHA. Had moderate balling on mtr stab/Bit.;Clear and clean rig floor from BHA components. Bring Casing equipment to rig floor.;Service TDS, Blocks,handling equipment and crown.;R/U Weatherford Casing equipment-R/U CRT,Power tongs,250 Ton side doors on bail extensions. Count 9-5/8"in shed(160 jts+ES cmtr). Visually inspect shoe track w/flashlight(good).;PJSM,M/U 9-5/8",DWC/C,40#,L-80 shoe track to 33k tq. Bakerlok shoe track jts. Check floats(good). Circulate through shoe track on jt#5,6 BPM,25 psi. Isolate on pit#4 for casing run.;Run 9-5/8"surface casing from surface to 697'MD. Fill on the fly.;Hauled 1088 bbls cuttings to G&I for total=5090 bbls Hauled 1190 bbls H2O from 6 mile lake for total=5930 bbls No losses to formation noted for surface 1214/2017 Continue to run casing from 697'to 3088',break and establish circulation back to pits every 15 Jts.No hole issues running to 3088'.Did notice improper displacement.;CBU from 3088'working pipe slowly @ 6 bpm/125psi,PU Wt 150,Dn Wt 85K,No Losses on circulation.Clean suction chambers on both MP's.;Continue to run casing f/3088't/3900'and PU ESCMTR w/no issues.Run to 5383'.(Just above Turn/Build section)Adjust running speed accordingly to mitigate surging well.;CBU X 2 and condition mud before running through Turn/Build section.Stage pump to 6 bpm/190 ICP,Up wt 265K,Dn Wt 96K.See 20K over pulls©times when working pipe.;Continue run 9-5/8"casing F/5283'-T/6602'MD. Break circulation every 15 jts.92K dn,310k up. Replaced damaged cup on CRT @ 6402'MD.;Circulate and condition mud reducing YP and MW to 9.2 ppg 121 YP. Stage pumps up to 6 BPM,205 psi,46%flow. Reciprocate pipe full jt. Circulated a total of lx btms up then rigged up cmt line.;Continue conditioning mud thru cmt line. 6 BPM,390 psi,46%flow. 312k up,92k dn.;PJSM, 1 stg surface cmt job as follows reciprocating pipe w/2-4 rpm on down strokes,20k tq.Clear cmt line to cmt units. Flood lines w/5 bbls water. PIT lines 1000/4400 psi(good).;60 bbls-10.5#Tuned Spacer III w/4#red dye first 10 bbls,5 BPM,427 psi Drop bypass plug 212 bbls 11.7#lead extendacem cmt,5 BPM, 406 psi 80 bbls 15.8#tail cement.2.7 BPM,320 psi.;Drop top plug Displacement-20 bbls fresh water @ 5.5 BPM,300 psi Turnover to rig for mud displacement w/rig mud pump#2(.062 bps pump output)Displacing WI 9.3 spud mud at time of report.;Hauled 285 bbls cuttings to G&l for total=5375 bbls Hauled 260 bbls H2O from 6 mile lake for total=6190 bbls losses to formation 20 bbls for total=20 bbls;See full casing and cement details on report 12/6/2017 212 /1. ' Pq F6 bb) - 4-12‘,4/ ag 12/5/2017 Continue 1st stage surface cmt job.Complete details as follows:Floof' es 5 bbls fresh water P/T lines 1000/4400 psi(good)60 bbls 10.5#Tuned S er III w/ 4#red dye first 10 bbls,5 BPM,427 psi;Drop bypass plug 212 bbls"I 1.7#lead extendacem cmt,2.465 yld,480 sxs,5 BPM,406 psi 80 bbls 15.8# it SwiftCem cement,1.155 yld,390 sxs,2.7 BPM,320 psi.;Drop top plug Displacement-HES-20 bbls fresh water @ 5.5 BPM,300 psi Turnover�o n'g for mud displacement w/rig mud pump#2(.062 bps pump output)234.6 bbls 9.3#spud mud,6 BPM,220 psi.;HES-80 bbls 8.3#fresh water,5.3 BPM,590 psi Rig-159.3 bbls 9.3# spud mud,6 BPM(Actual 394 bbls/Calc 391.2 bbls)Reduce rate to 3 bpm,735 FCP(bumped 6354 stks).;CIP @ 07:10 hrs Psi up to 1235 psi w/5 min hold. Check floats(held).Bled back 1 bbl.Psi up/open stage tool @ 2730 psi. Establish good circulation via stage tool.;Rot and reciprocated pipe @ 2-5 rpm,20k tq, 312k up,92k dn during cmt job started losing dn wt @ 3980 stks into displacement. Park on depth in tension. Full returns throughout job.;Displace through ES cmt tool @ 2586'@ 4 BPM 215 PSI.Stage up pumps to 5 BPM @ 295 PSI.@ 114 bbl away saw spacer and @ 155 bbl saw green CMT.Circ total 2 btm up. 37 1bbl cmt returned to surface.;Shut down and flush all surface equipment with black water. Break out volant tool and flush same.;Circ and condition @ 3.5 BPM 125 stip PSI. Prep for second stage cmt job.Load shed with 5"dp.Work on housekeeping. Prep for N/D BOPs.;PJSM, Batch up for second stage cmt job. Pump 60 bbl 10.5 PPG Tunned III spacer with Red Die in first 10 bbls.Mix and pump 303 bbl (394 sx) 10.7 PPG Perm L Lead cmt.;Saw contaminated spacer back @ 218 .30 4 bbl.Good 10.5 spacer back @ 303 bbl.Swap to tail. Got cmt back lust after swapping to tail.;Shut down and clean out mixer throat as per plan.Mix and pump SI {{7� a55.8 BBL(270 sx)15.8 PPG Premium G cmt. Drop Closing plug.Chase with 20 H2O to clear lines from HES.;Swap to RIG for displacement. Displace with rig @ 5 bpm.Slow pump to 2 bpm last 10 bbl. Bump plug on ES CMT tool @ 198.8 bbl.Calculated @ 196.5 FCP @ 545 @ 2 BPM. Bring up PSI to 2000 psi.;Saw ES cmt tool shift @ 1450 psi. Hold 2000 psi for 5 min.Bleed down and check for flow.No flow.Bleed back 1.25 BBL. CIP @ 6:27 hrs.252 bbl cmt returned to surfacer Full returns throughout job;R/D cmt lines and clear same. B/O and laydown CRT to cradle. R/U side door 9-5/8"elevators. Blow down TDS. 1)y LID remaining Weatherford handling equipment and release casing crew 08:00 hrs.;N/D diverter system. Un flange 16"diverter line and remove from cellar. N1 Disconnect koomey lines from knife valve. Flush BOP stack w/black water(function annular decrease to 500 psi)and Iines.;Remove drip pan. N/D stack and lift ffsame.;Vac out mud inside landing jt. Ctr 9-5/8"casing in wellhead. Install casing"E"slips. 100k string wt on slips as per wellhead rep(Johnny Morrow).;Mark Xy landing jt. Make rough cut @ 25.65'RKB/Cut. L/D same. Set stack and hot flange to wellhead. M/U Johnny Whacker and flush stack. Raise up stack.;Sym ��€,Ops-offload excess spud mud. Strip shaker screens and clean pits. Prep for production hole section.;Hauled 1753 bbls cuttings to G&I for total=7128 bbls wa Hauled 760 bbls H2O from 6 mile lake for total=6950 bbls V x8 losses to formation 20 bbls for total=20 bbls;AOGCC BOP notification sent @ 12!51201710:00 AM. Witnessed waived by AOGCC rep Guy Cook via email. <Aa 12/6/2017 Remove diverter Tee and starting head from cellar.Prep casing stump for cut. Make final cut on 9 5/8 casing.Cut 1.4'.;Install landing ring with assist of welder and well head specials as per FMC procedure. Continue pit cleaning, Change out saver sub&Grabber dies.;Wrap up well head&let wellhead cool. R/U DP elevators. @ 0845 rig blacked out.Production breaker problem. Prep floor for BHA.Rig back on high line @ 1300.Run one cat as contingency until 1600.;Test welds on wellhead to 1000 psi for 15 min good. Test to 80%of collapse with a derating for 450 deg=1000 psi as per FMC procedure. Perform Derrick inspection. Wellhead temp @ 375 degiTest choke manifold 250/3000 psi. Good. Test witness waived by Guy Cook With AOGCC @ 163612-5-2017.;Continue to wait on wellhead to cool. Prep pits for new mud.Continue housekeeping.Wellhead temp @ 220 DEG @ 1800.;Continue waiting for wellhead to cool. Temp 150°@ 22:00 hrs. Decision made to N/U wellhead and BOP equipment as per wellhead rep following FMC wellhead install procedure.;PJSM,Nipple up FMC 5M,11"multibowl wellhead. Re-test transition nipple w/nitrogen to 1400 psi w/15 min hold(good).Test metal/metal seal for nipple to slip on WH w/nitrogen 1000 psi(good).;N/U 13-5/8"5M BOP's w/11"x13-5/8"DSA. 4 point and center stack. Hook up all koomey lines. Tq and mark service connections on stuchi fittings.Make up kill and choke Iines.;Obtain RKB measurements,Install pitcher nipple,Install drip pan. Install Mousehole. Charge koomey system.;Set lower test plug w/5"test joint. R/U test subs wl(2x)5"TIW's,5"dart and test equipment. Flood stack and choke. Troubleshoot small leak on upper lockdowns.;Hauled 425 bbls cuttings to G&I for total=7553 bbls Hauled 500 bbls H2O from 6 mile lake for total=7450 bbls losses to formation 20 bbls for total=7 bbls 12/7/2017 Test bops as per AOGCC.Pipe rams and Annular tested on 5"test joint. All test 250/3000 psi. Had one fail pass on the super choke. R/D testing equiprr t. 'fest gas alarms and PVT.Good.;Perform Accumulator test, Starting pressure-3025 Final Pressure 1550 200 Psi Increase 25 SEC Full Pressure 78 sec.N2 @ 6 btls 2300.;Service rig.;Set 10"ID Wear bushing. M/U Clean out BHA,8.5 Hughes VM-3 used bit,1.22 Bent motor,2 NMFC,6 Jts 5"HWDP,Jars,11 Jts 5"HW DP. 641'.;PIU DP F/641'T/2558'.;Drill ES cmter on depth F/2584'T/2589'. Work through good.;PIU 5"DP Fl 2589'T/6106'.RIH from Derrick F/6106'T/ 6415'.;Circ btm&condition mud for cmt job. 500 GPM 1150 PSi.;Conduct rig evac drill. All hands accounted for in under 10 min other than the two Geologist that were not on location.Will discuss lessons learned in PTSM.;R/U test equipment. Flood lines. Test casing to 3000 psi against upper pipe,�!�rams. Good test. 5 bbls pumped/bled back 5 bbls. Chart and record same.;Wash down F/6418'-T/6459'MD. Drill cmt from 6459'to tag depth 6473'MD(CSI-L). Drill shoe track F/6473'-T/6610'MD. Float equip on depth.500 gpm,1310 psi,60%,30 rpm,3-5k wob,16.8k tq;Trip shoe track without pump or rotary clean.BFL adap 6473'Float Collar 6514'Float Shoe 6598'.;Drill new formation F/6610'-T/6630'MD 500 gpm,1050 psi,60%,5k wob. While drilling displace 9.3#spud mud out of hole on the fly w/9#Baradril"N"at full drilling rate.;P/U to 6603'MD. B/D TDS. R/U test equipment. Perform 12#FIT(good). 1 bbl pumped/bled back 1 bbl. B/D lines and RID same. FIT plot in"0"drive.;Monitor well(static). PJSM,POOH F/6603'-T/BHA. Rack back HWDP w/jars and Flex DC's.;Hauled 706 bbls cuttings to G&I for total=8259 bbls Hauled 270 bbls H2O from 6 mile lake for total=7720 bbls losses to formation 0 bbls for total=20 bbls Phase II conditions on Milne Pads 12/8/2017 LAD BHA,Drain motor,L/D Bit&Motor.Bit Grade.1-1-WT-A-E-1-NO-BHA. Clean and clear the rig floor. Prep BHA#3.;PJSM,P/U BHA#3, P/U Geo Pilot,M/U Near bit stab and 8.5 SKFX 616M,J1 D PDC bit. DGR,Stab,PWD,ADR,DM,TM,FS,2-NMFC,2 Jts HWDP,Jars,&one HWDP. Up Load MWD.;RIH T/ 1000'&Shallow pulse test.Had trouble getting ABI working.ROT @ 40 RPM&get 3 good readings. Also troubleshoot MP problem.Could not get pressure. Add fluid to pits,Isolate Geo Span.;Never found a problem but we got pressure. Test same.Good.;RIH F/1000'T/3400'.Fill pipe and test MWD.Good. RIH T! 6546'.;Shut down operation due to crew change out. Crews changing out at airport.Night crew needed rest. Rig tool pusher,Rig electrician and Rig mechanic monitor well and rig while waiting on new crew.;PTSM,Wash down F/6546'-T/6630'MD. Drill ahead F/6630'-T/6925'MD.450 gpm,1050 psi,57%flow 7k wob,120 rpm,17k.;1148 max units gas,200 bgg. 10 ECD.;Drill 8.5"production hole FI 6630'-T/7336'.706'total= 118'AROP 7k wob,120 rpm,15.5k tq 500 gpm,1300 psi,61%flow 198 bgg,9.9 ECD's.;Pumped tandem sweep @ 7180'MD. 25 bbls 8.6 ppg/35 vis then 9.5 ppg/300+vis. Came back on time w/ significant increase in sand.;Last svy @ 7106'MD, 92.66°Inc,196.95°Az=0'up/dn, 5.9'left to well plan 07A Drilled out of low side of zone @ 6860'and back in zone @ 6952'MD(92').Targeting 92.5°as per geo to match dip.;5 concretions,32'total thickness(4.5%)have been drilled so far.;Hauled 171 bbls cuttings to G&I for total=8430 bbls Hauled 130 bbls H2O from 6 mile lake for total=7850 bbls losses to formation 0 bbls for total=20 bbls Daily 10 lbs metal=10 lbs total 12/9/2017 Drilling 8.5 Lateral Fl 7336'T/7760' 424'@ 70 PFH average. 120 RPM,17K TQ 500 GPM,1250 P 5-10K WOB UP/DN 176/63.;MW 9.0 ECD 10.1 Pumped Tandem sweep @ 7745'50%Increase&400 Strokes late. Shut in L-50 Injector @ 7600'.Changed out swab on#2 MP#4 cylinder Screen u to 170s on all shakers.;Drilling 8.5 Lateral F/7760'T/8170' 410'@ 68 PFH average.120 RPM,17K TQ 350-500 GPM,780-1450 PSI 2-12K WOB UP/DN 175/58.;Reduce RPM-60&GPM-350 to control housing slip.Having trouble maintaining 93 Deg as per Geo.MW 9.0 ECD 9.8 Begin processing 7 5/8 Casing.;Drilling 8.5 Lateral Ff 8170'T/8312'MD. 142'total @ 57'AROP.95 RPM,17.3K TQ 450 GPM,1210 PSI,57%flow 4-7K WOB UP/DN 175/58.;9 ppg MW w/9.9 ECD's @ 450 gpm.Saw 3300 units gas while drilling @ 8284'MD.500 bgg.;Made connection @ 8312'MD. Geo-Pilot was not responding. Troubleshoot issue with Sperry Tech and onsite personnel. Attempt re-set,mode switch and cycling pumps(no go).;Pulled 1 std and performed hard re-set on tool. Tool responded and started working correctly. Inform drilling engineer of findings. Decision made to continue drilling ahead.;Drill 8.5"production hole F/8312'-T/8496'MD.Various parameters to mitigate housing roll on Geo-Pilot.;120 RPM,17.6K TQ 350-500 GPM,780-1450 PSI 2-12K WOB UP/DN/ROT 178/52,105.;Assy continued to show significant drop and housing roll until drilling @ 375 gpm,100 rpm,350+/-ROP.Had 2-5k WOB @ high ROP 300+fph.Mitigated much of the housing roll with these parameters.;Drilling 8.5 Lateral F/8496'T/ 906'MD.569'total @ 95'AROP.100 RPM,18.5K TQ 375 gpm w/max ROP 375'.Held parameters until assy was headed back to plan @ 8850'MD w/desired INC/Az as per Geo.;lncrease flow to 400 gpm @ 8850'with good steerability 4-7K WOB UP/DN/ROT 187/51/105.;Backream 2x at max flow 550 gpm between connecitons. ECDs @ 10.3 EMW w/550 flow rate.;Most connections showed1100 to 1500 units connection gas. Very slight flow @ connection then tapering off to 0 flow. Running 20-25 BPH water to maintain mud volume and keep MW @ 9-9.1 ppg.;Tandem sweep @ 8308'MD,500 stks late WI 0%Inc Tandem sweep @ 8748'MD,600 stks late w1100%Inc.;Last svy @ 8678'MD, 92.53°Inc,188.98°Az =20'up,77'right of well plan 07A Targeting 92.5°as per geo to match dip.;18 concretions,73'total thickness(3.1%)have been drilled so far.;Hauled 399 bbls cuttings to G&I for total=8829 bbls Hauled 780 bbls H2O from 6 mile lake for total=8630 bbls losses to formation 0 bbls for total=20 bbls Daily 10 lbs metal=20 lbs total 12/10/2017 Drilling 8.5 Lateral F/9065'T/ 9350'MD. 285' @ 47'AROP.Drilled 30'Concretion @ 9088-9118'.100 RPM,18.5K TQ 400 GPM, 1200 PSI 5-20K WOB.;After drilling 30' concretion drilling went back to normal without Housing role problems. Sweep back 700 stks late with 100%increase in cuttings. Back reaming 2-3 times. 10.2 ECD.;Drilling 8.5 Lateral F/9350'T/9943'MD. 593' @ 98'.250 FPH max 120 RPM,21K TO 500 GPM, 1200PSI 5K WOB.;Lost slack off wt @ 9568'. Backreaming once. Sweep @ 9503 Came back late with a 100%increase in cuttings.MW 9.0 ECD 12.2.;Drilling 8.5"Geosteering lateral F/9943'-T/ 10480'MD. AROP 537'@ 90'AROP 120 RPM,21.5K TQ 500 GPM, 1610 PSI 5K WOB.;Tandem sweep @ 10050'MD,68 bbls late w/50%increase in cuttings Cont Backream lx between connections. 10.4 ECD w/9#MW.;Drilling 8.5"Geosteering lateral F/10480'TI 10951'MD. 471'@ 79' 105 RPM,21.6K TQ 540 GPM, 1785PSI 7K WOB.;Losing 8-10 BPH to formation while drilling Last svy @ 10627'MD, 91.11°Inc,192.29°Az =33'up,7'left of well plan 07A Targeting 91.5°as per geo to match dip.;22 concretions,119'total thickness(2.8%)have been drilled so far.Continue seeing heavy oil back @ shakers.;Hauled 627 bbls cuttings to G&I for total=9456 bbls Hauled 700 bbls H2O from 6 mile lake for total=9330 bbls 11 lbs metal for total=26 lbs for lateral 12/11/2017 Circ and condition to reduce ECDs.Pump sweep,came back 1800 stks late with no increase in cuttings. 550 GPM @ 120 RPM. ECDS dropped from 10.8 to 10.4.;Drilling ahead F/10951'T/11011'. 500 GPM,1520 PSI 100 RPM,22.7 TQ 1500 Max gas.;Decision made to pull to shoe&wait on weather. Pull one stand F/11011'T/10951'. Circ btm up @ 550 gpm. ECDs 10.3.;Back ream out Ft 10951'T/8434' 500 GPM,120 RPM, Lots of oil on the shakers. Weather better.Decision made to resume drilling.;Circ&condition while pulling slow to get good btm up before returning to btm.F/8434'TI 8310'. 550 GPM,120 RPM. Lots of oil on shakers. Cuttings Cleaned up good. Fine sands.;RIH F/8310'on elevators T/10276'. Out of wt. Wash&Ream F/10276'TI 11011'400 GPM, 100 RPM MW 9.0.;Drilling ahead Fl 11011'-T/11550'. 539'@ 90 ft/min AROP 500 GPM,1675 PSI 100 RPM,22.7 TQ,7k WOB 500 bgg,10.7 ECD w/9.1 MW.;Drilling ahead F/11550'-T/12104'. 554'@ 93 ft/min AROP 530 GPM,1790 PSI 95 RPM,23.8K TQ,7k WOB 550 bgg,10.7 ECD w/9.1 MW Max gas 2001 units.;Tandem sweep 11556'w/no increase in cuttings.Last svy @ 10627'MD, 91.11°Inc,192.29°Az =33'up,7'left of well plan 07A Targeting 91.5°as per geo to match dip.;22 concretions,119'total thickness(2.2%)have been drilled so far.204 bbls loss to formation for total=369 bbls;Hauled 228 bbls cuttings to G&I for total=9684 bbls Hauled 520 bbls H2O from 6 mile lake for total=9850 bbls 7 the mortal fnr total=44 the 12/12/2017 Drilling 8 1/2"hole F/12104'-T/12645'. 541'@ 90.2 ft/min AROP 450 GPM,1550 PSI 100 RPM,25.4K TQ,10k WOB 575 bgg,10.8 ECD w/9.1 MW Max gas 2450 units.;12022'tandem sweep back 3000 stks late w/100%increase,Pump tandem sweep @ 12647, sweep back 3600 stks late w/300%increase all sand.Note:heavy crude oil seen @ shakers.;Losses 10-12 bph. Flow check at 13088';well bore breathing 4min to static.;Drilling ahead F/12645'-T/13088'. 443'@ 74 ft/min AROP 550 GPM,2000 PSI 120 RPM,26.4K TQ,7-9k WOB 560 bgg,10.9 ECD w/9.1 MW Max gas 1643 units.;Drilling ahead F/13088'-T/ 13277. 189'@ 95 ft/min AROP. 450 GPM,1540 PSI 100 RPM,26K TO,6-9k WOB 10.9 ECD w/9.1 MW max gas 603 units.;Losses 10-12 bph. Flow check at 13088';well bore breathing 4min to static.;Pump tandem sweep at 13170'and circulate out of the hole.100%increase in cuttings,217 bbls late;ECD's 10.5 ppg after.;Drilling ahead F/13277'-T/13465'. 188'@ 63 ft/min AROP 550 GPM,1990 PSI 130 RPM,28K TQ,7-11k WOB 30 bgg,10.7 ECD w/9.1 MW Max gas 1568 units.;Drilling ahead F/13465'-T/13874'. 409'@ 90 ft/min AROP 530 GPM,2000 PSI 130 RPM,28K TQ,7-11k WOB 30 bgg,10.7 ECD w/9.1 MW Max gas 1320 units.;Pump tandem sweep at 13655',50%increase,235 bbls late. Begin increasing lube concentration at 13650'to 4%by TD.;Exited top of sand at 13429'MD/3716'TVD,re-entered top at 1370573714',exited base of sand at 13808'/3725'TVD.;Flow check well;25 minutes to static. BROOH from 13874'to 13657 540 gpm/1890 psi,100 rpms.;267 bbls loss to formation for total=636 bbls;Hauled 760 bbls cuttings to G&I for total=10444 bbls Hauled 670 bbls H2O from 6 mile lake for total=10520 bbls 8 lbs metal for total=41 lbs • Hilcorp Energy Company Composite Report Well Name: MP L-51 Field: Milne Point County/State: ,Alaska (LAT/LONG): evation(RKB): API#: Spud Date: 11/28/2017 Job Name: 1713436D MPL-51 Drilling Contractor AFE#: AFE$: ,�c t3at� ,..::.. ,.,.........:........... I'.., MM.:BM © s Summar 11/26/2017 Continue to prep rig for move to MPL-51.Trucks on location @ 08:00 hrs.Separate Modules and stage on Pad.Back Sub off of L-53.Set sub down on Mats.;Clear and clean around L-53.Prep L-51 slot for mats and liner.Lay liner and set rig Mats.Walk Sub over MPL-51.;PJSM with oncoming crew.Set down sub and shim same,stage diverter line,set catwalk,set mud module,set pipe shed and motor module,R/U interconnects.Get steam circulating on rig.;Submit 24 hr diverter test notification to AOGCC @ 18:00.Release trucks at 23:30.;Spot break shack and enviro-vac.Plug in rig and put generator on line.Lower stairs on landings,Set and lower outriggers,turn on rig air.Perform derrick inspection,scope derrick up.Bridal down.;Perform full derrick inspection after scope up.Get water circulating throuahout ria.Lay nit liner for cuttinas box 11/27/2017 Assist welder w/Modify Landing rig height.Had to add 6"to to conductor.Rebulid Stand Pipe Demco Valve,button up MP's,Pull unneeded rig mats.Spot cuttings tank and berm up same.;Ready shed for DP.Process HWDP.House keep PAD.Prep for NU. Rig on Shore Power @ 10:30 hrs.;Continue to weld out Landing ring on conductor.Mechanic C/O oil seal on#2 Centrifuge feed pump.;Begin MU Diverter System.M/U starting head on conductor as per wellhead rep. M/U diverter Tee,set stack in place,start M/U knife valve.;M/U 16"diverter line and align same.Place containment at end of diverter,set barricades for exclusion zone,place diverter warning sign.M/U annular and knife valve koomey lines.;lnstall riser and catch pan,Install turn buckles. Install hoses on drain pans,torque all bolts.Close 4"conductor valves.Simops: Load strap and tally 5"DS50 DP in shed-;CIO seal on#2 centrifuge pump,Test PVT sys, lines in pits and centrifugal pumps.Un-pin and Pump thru pop off valves on mud pumps.Work on rig acceptance checklist.;lnspect, service,R/U Hawk Jaw on floor.Finish strap and tally on 5"DP in shed.Install short mouse hole.P/U first jt 5"DP,Function diverter,12 sec to close annular,4 sec to open knife valve;Drift and P/U 5"DS50 DP and rack stds in derrick(254 jts total)Load BHA tools into pipe shed to warm up,stock hopper room with products for spud mud. Note:tag depth @ 100'.;Accept rig on L-51 ©06:00.;Hauled 0 bbls cuttings to MP G&I for total=0 bbls Hauled 340 bbls H2O from 6 mile lake for total=340 bbls Hauled 0 bbls H2O from L-Pad for total=0 bbls 11/28/2017 Continue to Drift and P/U 5"DS50 DP and rack stds in derrick while W/O AOGCC to witness Diverter Test.Accept Rig on MPL-51 @ 06:00 hrs.;Test Diverter System on 5"DP 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.Test.Test Gas alarms and PVT System.;Added an additional 20'section of 16"Vent Line as per AOGCC Rep Bob Noble.;Continue to Drift and P/U 5"DS50 DP and rack stds in derrick(224 Jts Total).PU and rack back 17 jts HWDP w/Jars.Rd Hawk Jaw.Clean and clear rig floor.;Slip and cut 70'drill line.;Service Rig.;PT Mud line/Demco to 2500 psi.Blow down and fill conductor and diverter stack with water.Air boot leaking.Pull Bell Nipple to access air boot.Pull air boot.;Bring tools to rig floor.;PJSM,M/U 12.25"PDC drillout assy with 1.5°mtr(non ported float). Bit,Mtr and XO=34.99'length. RIH on 5"HWDP. Tag @ 100'. Flood lines and stack with fresh water(no leaks).;Drill 12.25"surface hole F/100'-T/219'MD. Displace from fresh water to spud mud @ 106'(est btm conductor). 400 gpm, 520 psi,70%flow,20 rpm,1.7k tq. Mostly pea gravel with some clay.;Plugged flowline once @ 115'MD. Picked up,jetted flowline clear then continued drilling ahead.;POOH F/219'-T/surface. M/U remaining 12.25"directional drilling assy MWD/LWD 8"tools as per DD/MWD. Scribe and download. RFO= 251.51°.;Wash down and continue drilling 12.25"surface hole F/219'-TI 267'MD. 400 gpm,660 psi,64%flow,40 rpm,1.9k tq.;Attempt to gyro @ 267'MD. Unable to get centralizers to pass ID of drill pipe. Re-dress Gyro tool with smaller bow springs and add additional wt bar. No issues after that.;Drill 12.25"surface hole F/267'-T/360'MD.93'total-62'AROP 3-5k wob,40 rpm,2k tq 400 gpm,720 psi,62%flow KOP @ 267'MD directional plan WP07A.;Hauled 171 bbls cuttings to G&I for total=171 bbls Hauled 390 bbls H2O from 6 mile lake for total=730 bbls Total metal last 24 hrs 0 lbs for total=0 lbs 11/29/2017 Drill ahead and Gyro Survey every stand Ff 360'T/719'and obtain clean MWD Survey.Drill to Survey depth of 846'obtain 3 additional clean MWD surveys and release Gyro.;400/480 GPM,850/1020 PSI,40 RPM,2-3K TQ,2-8K WOB,PU/SO/ROT 73/72/71.;Drill ahead F/846'T/1265'(419'),Av 120 FPH 550 GPM, 1325 PSI,WOB 5-10K,RPM 80,TQ 3-5K MW in/out 9.0+ppg,vis 219,9.7 ECD,8 bgg.PU/SO/ROT 78/75k/74k.;Last Survey @ 1226'MD,12.19 Inc,208.58 Azm,5.31'high,10.97'right.Distance to plan 12.19'.;Drill ahead Fl 1265'-T/1768'MD. 503'total=84'AROP 8k WOB,80 rpm,5k tq 550 gpm,1540 psi,62% flow,85k up,74k dn,80k rot 70 BGG w/9.9 ECD(9.15 MW/200 vis). EOB @ 1614'MD.;Drill ahead F/1768'-T/2271'MD. 503'total=84'AROP 10k WOB, 80 rpm,6.1k tq 550 gpm,1620 psi,62%flow,93k up,73k dn,82k rot 20 BGG w/10.1 ECD(9.2 MW/200 vis).;Screened up from 80's to 100's both shakers. Stg up water from 30 BPH to 60 BPH and run shakers wet to help manage unwanted increase in mud wt.Continue dump and dilute.Inc centrifuge rates.;Last survey @ 2043'MD=3.5'high and 2.2'left of well plan 07A.;Hauled 798 bbls cuttings to G&I for total=969 bbls Hauled 490 bbls H2O from 6 mile lake for total=1220 bbls 11/30/2017 Drill ahead F/2271'-T/2900'MD. 629'total=114.4'AROP 2-8k WOB,70 rpm,5.8k tq 550 gpm,1575 psi,104k up,71k dn,82k rot 20 BGG WI 9.7 ECD(9.2+ MW/150 vis).;Logged base of permafrost @ 2306'.Drilled 200'below permafrost lowering visc to 130-150 range.Screen up to 120's on both shakers @ 2840'. Both Centrifuges on Line.;Having to fight shaker after screening up.Mud Check showed Sand content @ 2%and Mud Wt @ 9.2+.Could not keep mud on shakers @ 450 gpm.;Rack Back 1 std to 2831'.CBU x 2 staging pump from 400 to 600 gpm,rotating 75 rpm,until mud staying on shakers with shaker decks at low setting.Circulate 1 additional bottoms up @ 600 gpm.;Sand Content down f/2%to.75%,MW down f/9.2+to 9.1. Drilled ahead with no further issues at shakers.;Drill ahead F/2900'-TI 3500'MD. 600'total=109'AROP 2-8k WOB,70 rpm,8-9k tq 550 gpm,1850 psi,118k up,79k dn,89k rot 20 BGG w/10.1 ECD(9.1+MW/120 vis).Max Gas @ 450u.;Drill ahead F/3500'-T/4031'MD. 531'total=89'AROP 2-8k WOB,70 rpm,10.7k tq 550 gpm,1700 psi,138k up, 81k dn,103k rot 100 BGG w/9.8 ECD(9.1+MW/120 vis).Max Gas @ 345u.;Drill ahead F/4031'-T/4597'MD.566'total=95'AROP 6-8k WOB,70 rpm, 11.8k tq 550 gpm,1810 psi,147k up,83k dn,106k rot 100 BGG w/9.9 ECD(9.1+MW/120 vis).Max Gas @ 165u.;Backream full stands @ connections. Control drilled with min wt on bit(2-4k)@ 200 ft/hr to minimize loading hole with cuttings. Saw significant drop tendency with BHA(1.5-3°/100')until 4120' MD.;Saw formation change w/bit wt at 4120'MD. Started seeing slight build tendencies w/right hand walk after that. Continue running water @ 40 BPH to control wt/vis.Inc avg ROP 250 max ft/hr.;Last survey @ 4307'MD,56.5T Inc,209.73°Az=4.6'high and 3.8'right of well plan 07A.;Hauled 1197 bbls cuttings to G&I for total=2166 bbls Hauled 1500 bbls H2O from 6 mile lake for total=2720 bbls • 12/1/2017 Drill ahead F/4597'-Tl 4847'MD.250'total=100'AROP 6-8k WOB,70 rpm,9-14k tq 575 gpm,1780 psi,152k up.82k dn,108k rot 100 BGG w/10.0 ECD (9.1+MW/135 vis).Max Gas @ 165u.;Rack back 1 stand and pump clean up cycle @ 600 gpm/70 rpm.Hole unloaded @ BUS for 80-90 bbls.ECD down from 10.4 to 9.9.;Drill ahead F/4847'-T!4950'MD.103'total=103'AROP 2-8k WOB,70 rpm,9-14k tq,550 gpm,1945 psi, Pump 30 bbl Tandem Lo Vis/Hi Vis Sweep.;Finish circulate sweep out of hole.While change out piston on#1 MP.Sweep came back strung out due to loss of MP#1.Minimal change at shakers.;Drill ahead F/4950'-T/5414'MD.464'total=103'AROP 6-8k WOB,70 rpm,14-16k tq 575 gpm,2115 psi,173k up,83k dn,112k rot 100 BGG w/ 10.3 ECD(9.1+MW/148 vis).;Pump tandem sweep clean up cycle before starting turn and build section @ 5448'.ECD down from 10.1 to 9.9.Hole unloaded 310 bbls into circulation w/200%increase, and cleaned up after 124 bbls;Drill ahead F/5414'-T/5763'MD.349'total=54'AROP 20k WOB,80 rpm,17.8k tq 550 gpm,1940 psi,183k up,81k dn,115k rot 25 BGG w/9.7 ECD(9.2+MW 1100 vis).;Start build and turn @ 5448'MD. Slow drilling due to hard streak and slide percentage. Saw the same thing drilling L-53 at relative depths.;Drill ahead F/5763'-T/5892'MD. 129'total=22'AROP 30k WOB,80 rpm,18k tq 550 gpm,2000 psi,190k up,83k dn,119k rot 30 BGG w/9.7 ECD(9.2+MW/100 vis).;Continue running water @ 40-50 BPH to help manage wtivis.;Last survey @ 5753'MD,67.24°Inc,202.15°Az=8.4'high and 14.8'right of well plan 07A.;Hauled 1130 bbls cuttings to G&I for total=3296 bbls Hauled 1070 bbls H2O from 6 mile lake for total=3790 bbls No losses to formation noted. 12/2/2017 Drill ahead F/5892'-T/5990'MD. 98'total=16.5'AROP 30k WOB,60-80 rpm,13-18k tq 550 gpm,2015 psi,181k up,80k dn,117k rot 30 BGG w/9.5 ECD (9.2+MW/100 vis).;Pump 25 bbls Condent/Nut Plug Sweep.Had slight ROP increase and WOB decrease when sweep at the bit.Adjust parameters as needed to minimize slip stick.;Drill ahead F/5990'-T/6043'MD. 53'total=35'AROP. Survey @ 5941'showed 10 deg DL.Racked back 1 stand to 5980'.;Orient TF to Low Side and Wash up/down and attempt to reduce 10 deg DL.Re shoot survey w/9.89.;Drill ahead F/6043'-T/6165'MD. 122'total=61'AROP 30k WOB,60- 80 rpm,13-18k tq 550 gpm,2175 psi,182k up,78k dn,115k rot 30 BGG w/9.7 ECD(9.2+MW/120 vis).;At 6140'start to see crude @ surface.;Drill ahead Ff 6165'to TD @ 6610'MD. 445'total=56'AROP 25k WOB,60-80 rpm,18k tq 550 gpm,2100 psi,185k up,73k dn,112k rot 130 BGG w/9.7 ECD(9.2+MW/ 90 vis).;Landed TD in middle of structure(5'from top)NB sand. Projected to bit @ 6610'MD/3938'ND,93.98°Inc,193.89°Az=1.8'low,5.9'right of well plan 07A.;Obtain final svy @ TD. Rack back 3x stds and circulate 4x Btms up. 600 gpm,2090 psi,68%flow,70 rpm,17.2k tq,50 bgg. ECD's went from 9.8 to 9.6 EMW.;Reduce vis from 100 to 75,reduce YP from 36 to 28. Pump tandem sweep(25 bbls lo vis/wt followed by 25 bbls hi vis/wt). Sweep came back 500 stks late w/no significant increase in cuttings.;Hauled 706 bbls cuttings to G&I for total=4002 bbls Hauled 950 bbls H2O from 6 mile lake for total=4740 bbls No losses to formation noted for surface;Attempt to go back on hi-line. Saw power fluctuation. Go back on rig power and troubleshoot. 12/3/2017 Continue to circulate and condition mud lowering vis to 60-70 range and YP 24,MW 9.2.Wash 3 stands back to bottom with no issues.Pumping 600 gpm/70 rpm.;BROOH from 6610'to 4156'Pulling 30-35 fpm,600 gpm 70 rpm.See increase in cuttings at shaker.Attempt to continue BROOH @ 8-10 fpm to allow hole to clean up.Shakers loaded up.;Note:Back ream x 3 through 9.9,8.4,and 9.3 DL intervals with no issues.;CBU from 4156'staging pump up from 450 to 600 gpm.Getting mostly fine sands back and cleaned up shortly after BUS.;Continue to BROOH from 4156'to 2585'(280'below base of permafrost)Hole unloading and fighting shakers.;CBU x 2 from 2585"staged pump up from 400 to 600 gpm.Mostly fines back on 1st BU and larger clays/fine sands back on 2nd BU.;Continue to BROOH from 2585'to 1453'MD.No issues back reaming through permafrost.;Continue BROOH F/1453'-T/640'MD. Slowed pulling speed to 10 fpm @ 1300'-1000'due to hole unloading. Reduced rpm's from 70 to 30 once in lower inclination part of hole.;No notable overpulls WI only slight bobbles while pulling through build section in upper part of hole. 450-600 gpm,930 psi.;Monitor well @ HWDP(static). Pull on elevators F/640'-surface without issue. Racked back HWDP wljars.;Download MWD. B/O and laydown all 8"tools. Flush,drain motor and 8/0 bit.L/D same.Bit grade-1,3,CT,T,X,I,WT,TD. No damage on BHA. Had moderate balling on mtr stab/Bit.;Clear and clean rig floor from BHA components. Bring Casing equipment to rig floor.;Service TDS, Blocks,handling equipment and crown.;R/U Weatherford Casing equipment-R/U CRT,Power tongs,250 Ton side doors on bail extensions. Count 9-518"in shed(160 jts+ES cmtr). Visually inspect shoe track wl flashlight(good).;PJSM,M/U 9-5/8",DWC/C,40#,L-80 shoe track to 33k tq. Bakerlok shoe track jts. Check floats(good). Circulate through shoe track on jt#5,6 BPM,25 psi. Isolate on pit#4 for casing run.;Run 9-5/8"surface casing from surface to 697'MD. Fill on the fly.;Hauled 1088 bbls cuttings to G&I for total=5090 bbls Hauled 1190 bbls H2O from 6 mile lake for total=5930 bbls No losses to formation noted for surface 12/4/2017 Continue to run casing from 697'to 3088',break and establish circulation back to pits every 15 Jts.No hole issues running to 3088'.Did notice improper displacement.;CBU from 3088'working pipe slowly @ 6 bpm/125psi,PU Wt 150,Dn Wt 85K,No Losses on circulation.Clean suction chambers on both MP's.;Continue to run casing f/3088'V 3900'and PU ESCMTR w/no issues.Run to 5383'.(Just above Turn/Build section)Adjust running speed accordingly to mitigate surging well.;CBU X 2 and condition mud before running through Turn/Build section.Stage pump to 6 bpm/190 ICP,Up wt 265K,Dn Wt 96K.See 20K over pulls @ times when working pipe.;Continue run 9-5/8"casing F/5283'-TI 6602'MD. Break circulation every 15 jts.92K dn,310k up. Replaced damaged cup on CRT @ 6402'MD.;Circulate and condition mud reducing YP and MW to 9.2 ppg/21 YP. Stage pumps up to 6 BPM,205 psi,46%flow. Reciprocate pipe full jt. Circulated a total of lx btms up then rigged up cmt line.;Continue conditioning mud thru cmt line. 6 BPM,390 psi,46%flow. 312k up,92k dn.;PJSM, 1 stg surface cmt job as follows reciprocating pipe WI 2-4 rpm on down strokes,20k tq.Clear cmt line to cmt units. Flood lines w/5 bbls water. PIT lines 1000/4400 psi(good).;60 bbls 10.5#Tuned Spacer III w/4#red dye first 10 bbls,5 BPM,427 psi Drop bypass plug 212 bbls 11.7#lead extendacem cmt,5 BPM, 406 psi 80 bbls 15.8#tail cement,2.7 BPM,320 psi.;Drop top plug Displacement-20 bbls fresh water @ 5.5 BPM,300 psi Turnover to rig for mud displacement w/rig mud pump#2(.062 bps pump output)Displacing w/9.3 spud mud at time of report.;Hauled 285 bbls cuttings to G&I for total=5375 bbls Hauled 260 bbls H2O from 6 mile lake for total=6190 bbls losses to formation 20 bbls for total=20 bbls;See full casing and cement details on report 12/6/2017 • 12/5/2017 Continue 1st stage surface cmt job.Complete details as follows:Flood lines 5 bbls fresh water P/T line 1000/4400 psi(good)60 bbls 10.5#Tuned Spacer III w/ 4#red dye first 10 bbls,5 BPM,427 psi;Drop bypass plug 212 bbls 11.7#lead extendacem cmt,2.465 yld,480 sxs,5 BPM,406 psi 80 bbls 15.8#tail SwiftCem cement,1.155 yld,390 sxs,2.7 BPM,320 psi.;Drop top plug Displacement-HES-20 bbls fresh water @ 5.5 BPM,300 psi Turnover to rig for mud displacement w/rig mud pump#2(.062 bps pump output)234.6 bbls 9.3#spud mud,6 BPM,220 psi.;HES-80 bbls 8.3#fresh water,5.3 BPM,590 psi Rig-159.3 bbls 9.3# spud mud,6 BPM(Actual 394 bbls I Calc 391.2 bbls)Reduce rate to 3 bpm,735 FCP(bumped 6354 stks).;CIP @ 07:10 hrs Psi up to 1235 psi w/5 min hold. Check floats(held).Bled back 1 bbl.Psi up/open stage tool @ 2730 psi. Establish good circulation via stage tool.;Rot and reciprocated pipe @ 2-5 rpm,20k tq, 312k up,92k dn during cmt job started losing dn wt @ 3980 stks into displacement. Park on depth in tension. Full returns throughout job.;Displace through ES cmt tool @ 2586'@ 4 BPM 215 PSI.Stage up pumps to 5 BPM @ 295 PSI.©114 bbl away saw spacer and @ 155 bbl saw green CMT.Circ total 2 btm up. 37 bbl cmt returned to surface.;Shut down and flush all surface equipment with black water. Break out volant tool and flush same.;Circ and condition @ 3.5 BPM 125 PSI. Prep for second stage cmt job.Load shed with 5"dp.Work on housekeeping. Prep for N/D BOPs.;PJSM, Batch up for second stage cmt job. Pump 60 bbl 10.5 PPG Tunned III spacer with Red Die in first 10 bbls.Mix and pump 303 bbl (394 sx) 10.7 PPG Perm L Lead cmt.;Saw contaminated spacer back @ 218 bbl.Good 10.5 spacer back @ 303 bbl.Swap to tail. Got cmt back just after swapping to tail.;Shut down and clean out mixer throat as per plan.Mix and pump 55.8 BBL(270 sx)15.8 PPG Premium G Tail cmt. Drop Closing plug.Chase with 20 H2O to clear lines from HES.;Swap to RIG for displacement. Displace with rig @ 5 bpm.Slow pump to 2 bpm last 10 bbl. Bump plug on ES CMT tool©198.8 bbl.Calculated @ 196.5 FCP @ 545 @ 2 BPM. Bring up PSI to 2000 psi.;Saw ES cmt tool shift @ 1450 psi. Hold 2000 psi for 5 min.Bleed down and check for flow.No flow.Bleed back 1.25 BBL. CIP @ 6:27 hrs.252 bbl cmt returned to surface. Full returns throughout job;R/D cmt lines and clear same. B/O and laydown CRT to cradle. R/U side door 9-5/8"elevators. Blow down TDS. L/D remaining Weatherford handling equipment and release casing crew 08:00 hrs.;N/D diverter system. Un flange 16"diverter line and remove from cellar. Disconnect koomey lines from knife valve. Flush BOP stack w/black water(function annular decrease to 500 psi)and Iines.;Remove drip pan. N/D stack and lift same.;Vac out mud inside landing jt. Ctr 9-5/8"casing in wellhead. Install casing"E"slips. 100k string wt on slips as per wellhead rep(Johnny Morrow).;Mark landing jt. Make rough cut©25.65'RKB/Cut. L/D same. Set stack and hot flange to wellhead. M/U Johnny Whacker and flush stack. Raise up stack.;Sym Ops-offload excess spud mud. Strip shaker screens and clean pits. Prep for production hole section.;Hauled 1753 bbls cuttings to G&I for total=7128 bbls Hauled 760 bbls H2O from 6 mile lake for total=6950 bbls losses to formation 20 bbls for total=20 bbls;AOGCC BOP notification sent @ 12/5/2017 10:00 AM. Witnessed waived by AOGCC rep Guy Cook via email. 12/6/2017 Remove diverter Tee and starting head from cellar.Prep casing stump for cut. Make final cut on 9 5/8 casing.Cut 1.4'.;Install landing ring with assist of welder and well head specials as per FMC procedure. Continue pit cleaning, Change out saver sub&Grabber dies.;Wrap up well head&let wellhead cool. R/U DP elevators. @ 0845 rig blacked out.Production breaker problem. Prep floor for BHA.Rig back on high line @ 1300.Run one cat as contingency until I600.;Test welds on wellhead to 1000 psi for 15 min good. Test to 80%of collapse with a derating for 450 deg=1000 psi as per FMC procedure. Perform Derrick inspection. Wellhead temp @ 375 deg.;Test choke manifold 250/3000 psi. Good. Test witness waived by Guy Cook With AOGCC @ 163612-5-2017.;Continue to wait on wellhead to cool. Prep pits for new mud.Continue housekeeping.Wellhead temp @ 220 DEG @ 1800.;Continue waiting for wellhead to cool. Temp 150°@ 22:00 hrs. Decision made to N/U wellhead and BOP equipment as per wellhead rep following FMC wellhead install procedure.;PJSM,Nipple up FMC 5M,11"multibowl wellhead. Re-test transition nipple w/nitrogen to 1400 psi w/15 min hold(good).Test metal/metal seal for nipple to slip on WH w/nitrogen 1000 psi(good).;N/U 13-5/8"5M BOP's w/11"x13-5/8"DSA. 4 point and center stack. Hook up all koomey lines. Tq and mark service connections on stuchi fittings.Make up kill and choke Iines.;Obtain RKB measurements,Install pitcher nipple,Install drip pan. Install Mousehole. Charge koomey system.;Set lower test plug w/5"test joint. R/U test subs wI(2x)5"TIW's,5"dart and test equipment. Flood stack and choke. Troubleshoot small leak on upper lockdowns.;Hauled 425 bbls cuttings to G&I for total=7553 bbls Hauled 500 bbls H2O from 6 mile lake for total=7450 bbls losses to formation 20 bbls for total=20 bbls 12/7/2017 Test bops as per AOGCC.Pipe rams and Annular tested on 5"test joint. All test 250/3000 psi. Had one fail pass on the super choke. R/D testing equipment. Test gas alarms and PVT.Good.;Perform Accumulator test, Starting pressure-3025 Final Pressure 1550 200 Psi Increase 25 SEC Full Pressure 78 sec.N2 @ 6 btls 2300.;Service rig.;Set 10"ID Wear bushing. M/U Clean out BHA,8.5 Hughes VM-3 used bit,1.22 Bent motor,2 NMFC,6 Jts 5"HWDP,Jars,11 Jts 5"HW DP. 641'.;P/U DP F/641'T/2558'.;Drill ES cmter on depth F/2584'T/2589'. Work through good.;P/U 5"DP F/2589'T/6106'.RIH from Derrick FI 6106'T/ 6415'.;Circ btm&condition mud for cmt job. 500 GPM 1150 PSi.;Conductrig evac drill. All hands accounted for in under 10 min other than the two Geologist that were not on location.Will discuss lessons learned in PTSM.;R/U test equipment. Flood lines. Test casing to 3000 psi against upper pipe rams. Good test. 5 bbls pumped/bled back 5 bbls. Chart and record same.;Wash down F/6418'-TI 6459'MD. Drill cmt from 6459'to tag depth 6473'MD(BFL). Drill shoe track F/6473'-T/6610'MD. Float equip on depth.500 gpm,1310 psi,60%,30 rpm,3-5k wob,16.8k tq;Trip shoe track without pump or rotary clean.BFL adap 6473'Float Collar 6514'Float Shoe 6598'.;Drill new formation F/6610'-T/6630'MD 500 gpm,1050 psi,60%,5k wob. While drilling displace 9.3#spud mud out of hole on the fly w/9#Baradril"N"at full drilling rate.;P/U to 6603'MD. B/D TDS. R/U test equipment. Perform 12#FIT(good). 1 bbl pumped/bled back 1 bbl. B/D lines and R/D same. FIT plot in"0"drive.;Monitor well(static). PJSM,POOH F/6603'-T/BHA. Rack back HWDP w/jars and Flex DC's.;Hauled 706 bbls cuttings to G&I for total=8259 bbls Hauled 270 bbls H2O from 6 mile lake for total=7720 bbls losses to formation 0 bbls for total=20 bbls Phase II conditions on Milne Pads 12/8/2017 UD BHA,Drain motor,LID Bit&Motor.Bit Grade.1-1-WT-A-E-1-NO-BHA. Clean and clear the rig floor. Prep BHA#3.;PJSM,P/U BHA#3, P/U Geo Pilot,M/U Near bit stab and 8.5 SKFX 616M,J1 D PDC bit. DGR,Stab,PWD,ADR,DM,TM,FS,2-NMFC,2 Jts HWDP,Jars,&one HWDP. Up Load MWD.;RIH T/ 1000'&Shallow pulse test.Had trouble getting ABI working.ROT @ 40 RPM&get 3 good readings. Also troubleshoot MP problem.Could not get pressure. Add fluid to pits,Isolate Geo Span.;Never found a problem but we got pressure. Test same.Good.;RIH Fl 1000'T/3400'.Fill pipe and test MWD.Good. RIH T/ 6546'.;Shut down operation due to crew change out. Crews changing out at airport.Night crew needed rest. Rig tool pusher,Rig electrician and Rig mechanic monitor well and rig while waiting on new crew.;PTSM,Wash down F/6546'-T/6630'MD. Drill ahead F/6630'-T/6925'MD.450 gpm,1050 psi,57%flow 7k wob,120 rpm,17k.;1148 max units gas,200 bgg. 10 ECD.;Drill 8.5"production hole Fl 6630'-T/7336'.706'total= 118'AROP 7k wob,120 rpm,15.5k tq 500 gpm,1300 psi,61%flow 198 bgg,9.9 ECD's.;Pumped tandem sweep @ 7180'MD. 25 bbls 8.6 ppg/35 vis then 9.5 ppg/300+vis. Came back on time wI significant increase in sand.;Last svy @ 7106'MD, 92.66°Inc,196.95°Az=0'up/dn, 5.9'left to well plan 07A Drilled out of low side of zone @ 6860'and back in zone @ 6952'MD(92').Targeting 92.5°as per geo to match dip.;5 concretions,32'total thickness(4.5%)have been drilled so far.;Hauled 171 bbls cuttings to G&I for total=8430 bbls Hauled 130 bbls H2O from 6 mile lake for total=7850 bbls losses to formation 0 bbls for total=20 bbls Daily 10 lbs metal=10 lbs total • 12/9/2017 Drilling 8.5 Lateral Fl 7336'T/7760' 4@ 70 PFH average. 120 RPM,17K TQ 500 GPM,1250 S-10K WOB UP/DN 176/63.;MW 9.0 ECD 10.1 Pumped Tandem sweep @ 7745'50%Increase&400 Strokes late. Shut in L-50 Injector @ 7600'.Changed out swab on#2 MP#4 cylinder Screen u to 170s on all shakers.;Drilling 8.5 Lateral F/7760'T/8170' 410'@ 68 PFH average.120 RPM,17K TQ 350-500 GPM,780-1450 PSI 2-12K WOB UP/DN 175/58.;Reduce RPM-60&GPM-350 to control housing slip.Having trouble maintaining 93 Deg as per Geo.MW 9.0 ECD 9.8 Begin processing 7 5/8 Casing.;Drilling 8.5 Lateral Fl 8170'T/8312'MD. 142'total @ 57'AROP.95 RPM,17.3K TQ 450 GPM,1210 PSI,57%flow 4-7K WOB UP/DN 175/58.;9 ppg MW w/9.9 ECD's @ 450 gpm.Saw 3300 units gas while drilling @ 8284'MD.500 bgg.;Made connection @ 8312'MD. Geo-Pilot was not responding. Troubleshoot issue with Sperry Tech and onsite personnel. Attempt re-set,mode switch and cycling pumps(no go).;Pulled 1 std and performed hard re-set on tool. Tool responded and started working correctly. Inform drilling engineer of findings. Decision made to continue drilling ahead.;Drill 8.5"production hole F/8312'-T/8496'MD.Various parameters to mitigate housing roll on Geo-Pilot.;120 RPM,17.6K TQ 350-500 GPM,780-1450 PSI 2-12K WOB UP/DN/ROT 178/52,105.;Assy continued to show significant drop and housing roll until drilling @ 375 gpm,100 rpm,350+1-ROP.Had 2-5k WOB @ high ROP 300+fph.Mitigated much of the housing roll with these parameters.;Drilling 8.5 Lateral Fl 8496'T/ 906'MD.569'total @ 95'AROP.100 RPM,18.5K TQ 375 gpm w/max ROP 375'.Held parameters until assy was headed back to plan @ 8850'MD w/desired INC/Az as per Geo.;Increase flow to 400 gpm @ 8850'with good steerability 4-7K WOB UP/DN/ROT 187/51/105.;Backream 2x at max flow 550 gpm between connecitons. ECDs @ 10.3 EMW w/550 flow rate.;Most connections showed1100 to 1500 units • connection gas. Very slight flow @ connection then tapering off to 0 flow. Running 20-25 BPH water to maintain mud volume and keep MW @ 9-9.1 ppg.;Tandem sweep @ 8308'MD,500 stks late w/0%Inc Tandem sweep @ 8748'MD,600 stks late w/100%Inc.;Last svy @ 8678'MD, 92.53°Inc,188.98°Az =20'up,77'right of well plan 07A Targeting 92.5°as per geo to match dip.;18 concretions,73'total thickness(3.1%)have been drilled so far.;Hauled 399 bbls cuttings to G&I for total=8829 bbls Hauled 780 bbls H2O from 6 mile lake for total=8630 bbls losses to formation 0 bbls for total=20 bbls Daily 10 lbs metal=20 lbs total 12/10/2017 Drilling 8.5 Lateral F/9065'T/ 9350'MD. 285' @ 47'AROP.Drilled 30'Concretion @ 9088-9118'.100 RPM,18.5K TQ 400 GPM, 1200 PSI 5-20K WOB.;After drilling 30' concretion drilling went back to normal without Housing role problems. Sweep back 700 stks late with 100%increase in cuttings. Back reaming 2-3 times. 10.2 ECD.;Drilling 8.5 Lateral F/9350'T/9943'MD. 593' @ 98'.250 FPH max 120 RPM,21K TQ 500 GPM, 1200PSI 5K WOB.;Lost slack off wt @ 9568'. Backreaming once. Sweep @ 9503 Came back late with a 100%increase in cuttings.MW 9.0 ECD 12.2.;Drilling 8.5"Geosteering lateral F/9943'-T/ 10480'MD. AROP 537'@ 90'AROP 120 RPM,21.5K TQ 500 GPM, 1610 PSI 5K WOB.;Tandem sweep @ 10050'MD,68 bbls late w/50%increase in cuttings Cont Backream lx between connections. 10.4 ECD w/9#MW.;Drilling 8.5"Geosteering lateral F/10480'T/10951'MD. 471'@ 79' 105 RPM,21.6K TQ 540 GPM, 1785PSI 7K WOB.;Losing 8-10 BPH to formation while drilling Last svy @ 10627'MD, 91.11°Inc,192.29°Az =33'up,7'left of well plan 07A Targeting 91.5°as per geo to match dip.;22 concretions,119'total thickness(2.8%)have been drilled so far.Continue seeing heavy oil back @ shakers.;Hauled 627 bbls cuttings to G&I for total=9456 bbls Hauled 700 bbls H2O from 6 mile lake for total=9330 bbls 11 lbs metal for total=26 lbs for lateral 12/11/2017 Circ and condition to reduce ECDs.Pump sweep,came back 1800 stks late with no increase in cuttings. 550 GPM©120 RPM. ECDS dropped from 10.8 to 10.4.;Drilling ahead F/10951'T/11011'. 500 GPM,1520 PSI 100 RPM,22.7 TQ 1500 Max gas.;Decision made to pull to shoe&wait on weather. Pull one stand F/11011'T/10951'. Circ btm up @ 550 gpm. ECDs 10.3.;Back ream out Ff 10951'Tf 8434' 500 GPM,120 RPM, Lots of oil on the shakers. Weather better.Decision made to resume drilling.;Circ&condition while pulling slow to get good btm up before returning to btm.F/8434'T/8310'. 550 GPM,120 RPM. Lots of oil on shakers. Cuttings Cleaned up good. Fine sands.;RIH F/8310'on elevators T/10276'. Out of wt. Wash&Ream F/10276'T/11011'400 GPM, 100 RPM MW 9.0.;Drilling ahead F/11011'-T/11550'. 539'@ 90 ft/min AROP 500 GPM,1675 PSI 100 RPM,22.7 TQ,7k WOB 500 bgg,10.7 ECD w/9.1 MW.;Drilling ahead F/11550'-T/12104'. 554'@ 93 ft/min AROP 530 GPM,1790 PSI 95 RPM,23.8K TQ,7k WOB 550 bgg,10.7 ECD w/9.1 MW Max gas 2001 units.;Tandem sweep 11556'w/no increase in cuttings.Last svy @ 10627'MD, 91.11°Inc,192.29°Az =33'up,7'left of well plan 07A Targeting 91.5°as per geo to match dip.;22 concretions,119'total thickness(2.2%)have been drilled so far.204 bbls loss to formation for total=369 bbls;Hauled 228 bbls cuttings to G&I for total=9684 bbls Hauled 520 bbls H2O from 6 mile lake for total=9850 bbls 7 the mafal fnr Ental='' the 12/12/2017 Drilling 81/2"hole F/12104'-T/12645'. 541'@ 90.2 ft/min AROP 450 GPM,1550 PSI 100 RPM,25.4K TQ,10k WOB 575 bgg,10.8 ECD w/9.1 MW Max gas 2450 units.;12022'tandem sweep back 3000 stks late w/100%increase,Pump tandem sweep @ 12647', sweep back 3600 stks late w/300%increase all sand.Note:heavy crude oil seen @ shakers.;Losses 10-12 bph. Flow check at 13088';well bore breathing 4min to static.;Drilling ahead F/12645'-T/13088'. 443'@ 74 ft/min AROP 550 GPM,2000 PSI 120 RPM,26.4K TQ,7-9k WOB 560 bgg,10.9 ECD w/9.1 MW Max gas 1643 units.;Drilling ahead F/13088'-T/ 13277'. 189'@ 95 ft/min AROP. 450 GPM,1540 PSI 100 RPM,26K TQ,6-9k WOB 10.9 ECD w/9.1 MW max gas 603 units.;Losses 10-12 bph. Flow check at 13088';well bore breathing 4min to static.;Pump tandem sweep at 13170'and circulate out of the hole.100%increase in cuttings,217 bbls late;ECD's 10.5 ppg after.;Drilling ahead F/13277'-T/13465'. 188'@ 63 ft/min AROP 550 GPM,1990 PSI 130 RPM,28K TQ,7-11k WOB 30 bgg,10.7 ECD w/9.1 MW Max gas 1568 units.;Drilling ahead Ff 13465'-T/13874'. 409'@ 90 ft/min AROP 530 GPM,2000 PSI 130 RPM,28K TQ,7-11k WOB 30 bgg,10.7 ECD w/9.1 MW Max gas 1320 units.;Pump tandem sweep at 13655',50%increase,235 bbls late. Begin increasing lube concentration at 13650'to 4%by TD.;Exited top of sand at 13429'MD/3716'TVD,re-entered top at 1370573714',exited base of sand at 1380873725'TVD.;Flow check well;25 minutes to static. BROOH from 13874'to 13657'540 gpm/1890 psi,100 rpms.;267 bbls loss to formation for total=636 bbls;Hauled 760 bbls cuttings to G&I for total=10444 bbls Hauled 670 bbls H2O from 6 mile lake for total=10520 bbls 8 lbs metal for total=41 lbs s • Hilcorp Energy Company Composite Report Well Name: MP L-51 Field: Milne Point County/State: ,Alaska 1(LAT/LONG): evation(RKB): 26.04 API#: Spud Date: 11/28/2017 Job Name: 1713436C MPL-51 Completion Contractor AFE#: AFE$: Activity Date a Ty , Ops Summary 12/13/2017 Continue to BROOH f/13657'to 13429'pumping 540 gpm/1890 psi,100 rpms.,Circulate and condition wellbore f/13429'f/PSTs per procedure,pump tandem sweep 500 gpm,1590 psi,120 rpm,25k tq,reciprocate 60', sweep back 220 bbls late w/50%increase at shakers,circulate 6 bttms up,perform passing PST under shaker and fluid going down hole,Reduce flow rate and rpm to to 350 gpm,970 psi,40 rpm,Continue to circulate and condition for PST(16:00 hrs Milne point went to phase 2 weather conditions,convoy travel only) Continue to drift strap and tally lower completion. 76 bbl losses while circulating Loss rate 10 bph.,Continue to circulate at 350 gpm,970 psi with 40 rpms. Perform passing PST(9.3 sec,9.5 sec,9.53 sec). Pump additional annular volume and collect second passing PST test(9.47 sec,9.81 sec,10.15 sec),Flow check well-still observing well bore breathing with flow slowing down and static after 15 minutes.,Back ream out of hole from 13468'to 12084'500 gpm/1526 psi, 100 rpms/22.7Kft-lbs,ECD's ranging from 10.4 ppg to 10.2 ppg.,Continue to BROOH from 12084'to 10322 at 500 gpm/1450 psi,100rpms/20KFt-lbs ECD's 10.1 ppg with 9.15 ppg mud. Loss rate 7-8 bph.,150bbls loss to formation for total=786 bbls,Hauled 171 bbls cuttings to G&I for total=10615 bbls Hauled 390 bbls H2O from 6 mile lake for total=10910 bbls 6 lbs metal for total=47 lbs 12/14/2017 Continue to BROOH 5 min per std f/10322'U 9100'500 gpm,1290 psi 100 rpm,encounter some packing off w/200 psi increase and 8k overpull,slow pump down to 250 gpm,increase to 150 rpm,ream and cleanup concretion drilled f/9089'to 9115',increase pump to 500 gpm and lower rpm back to 100, continue to BROOH 5 min std f/9115'to 8170' Loss rate continues 7-8 bph,Continue to BROOH f/8170'to 8010' with slight packing off,reduce pump rate to 250 gpm,increase to 150 rpm,work thru easily and cleanup same,work thru again 500 gpm,100 rpm,no issues,continue to BROOH f/8010'to 6940'with 15k overpull,Pulling tight in transition f/sand to shale drilled f/6830'to 6970',attempt several times to backream f/6940'w/no progress,work up to 6920'with no rotary w/up to 35k overpulls making a few feet ea.time and reaming down until clean.L/D top single off std 107 for working room.,Continue working thru tight hole up to 6903'past tight area.Ream f/ 6900'to 6940',backream to 6900'.Work 1 time down to 6940'and back up to 6900',clean. Note:Reduced f/phase 2 to phase 1 weather conditions©17:00,Continue BROOH 5 min std f/6900'to 6833'pumping 500 gpm,1250 psi,100 rpm. 168 bbl losses BROOH.Max gas 272u,Continue to BROOH 5 min/stand from 6833'to 6600',500 gpm,100 rpms torque from 12,000 ft-lbs to 16,000 ft-lbs. Tight at 6996'(15K over),work up thru tight spot at 60 rpm. Slack off back through with no rotary with no issues.,Pump high vis sweep(no increase in cuttings)and circulate hole clean 2x annular volume after sweep. 500 gpm/1390 psi,100 rpms/11.7Kft-lbs reciprocating pipe.,PJSM.Displace to brine.Pump high vis spacer followed by 9.1 ppg brine,290 gpm/400psi, 100 rpms/10KFt-lbs reciprocating pipe. Flow check-static. Drop drift.,Service rig,grease drawworks,top drive and blocks.,POOH racking stands in derrick to 4475',continue POOH laying down NC50 drill pipe to 268'. Hole took 14 bbls over calculated displacement.,Flow check well,static loss rate 6 bph.,Continue to POOH laying down HWDP and jars to 146'.,184 bbls loss to formation for total=970 bbls,Hauled 511 bbls cuttings to G&I for total=11126 bbls Hauled 520 bbls H2O from 6 mile lake for total=11430 bbls 4 lbs metal for total=51 lbs 12/15/2017 Continue to L/D BHA 3 f/146',upload MWD data,finish L/D BHA,bit grade=2/4/CT/T/XII/ER/TD,18 cutters chipped on taper,3 cutters chipped on nose,found piece of cmt wedged between blades. Bit sleeve looked good,blades on ILS worn 4"from top of blade and 2"from bottom of blade,3/16"under gauge.Blades on geo-pilot lower stabilizer worn 2" above and below blades. TOOH f/shoe, 184 bbl losses,Clear rig floor.M/U 5"safety jt w/FOSV and XOs and stage on ODS catwalk.Load equipment to rig floor. R/U 4 1/2"handling equipment and power tongs. Monitor well w/trip tank,static loss rate 1.6 bph„PJSM with all parties involved,discuss plan for well control with screens across BOP.M/U and RIH with lower screen completion as per tally,P/U fit shoe assy,WIV w/1”ID ball seat,xo, 4 1/2"drillable packoff sub,xo pup jt.solid jt 4 1/2"13.5#L80 hydril 625 liner,P/U and RIM w/4 1/2"13.5#hydril Excluder 2000 screens from 86'to 4710',(113 screens ran),M/U to optimum tq @ 9600 ft/lbs,utilize dog collar clamp on every jt,use BOL 2000 pipe dope.Install 1 straight blade centralizer on pin end of ea.screen next to stop collar on screens 1-61 Current loss rate 1 bph,Continue to RIH with 4 1/2"13 5#Hydril Excluder 2000 screens from 4710'to 7024'(164 total screens,4 total joints of solid body),13.5# L-80 Hydril 625. 1 spiral glide centralizer on screens 62-164.,using BOL 2000 pipe dope and torqueing to 9600#. PUW 123K,SOW 73K. Calculated displacement for screens 32,4 bbls,actual 30.1 bbls,Make up safety joint for inner string and screens. Rig up false rotary table,C/O power tong dies,C/O Elevators. Check remaining screen and solid body joints. Set max top drive torque to 9600 ft-lbs.,M/U slick stinger. P/U and RIH with 2-3/8"PH6 inner string to 6999'and tag out on packoff no-go on depth setting 5K down. Lay down 1 joint. C/O pipe handling equipment. Pick up swivel for space out(slick stinger will be 8'into packoff),Calculated displacement 15.2 bbls. Actual displacement 7.6 bbls for a loss of 7.6 bbls. Milne point went to Phase 2 weather conditions at 05:30,34 bbls loss to formation for total=1004 bbls,Hauled 57 bbls cuttings to G&I for total=11183 bbls Hauled 260 bbls H2O from 6 mile lake for total=11690 bbls 0 lbs metal for total=51 lbs • i 12/16/2017 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.M/U top drive,remove false table."Break circulation,displace 9.1 brine w/437 bbls 9.1 ppg mud f/7029'@ end of mule shoe below packoff staging pump to 5 bpm,2500 psi. While circulating load 27 6 1/4"drill collars and 48 jts HWDP into pipe shed,strap and tally same.,While displacing 10 bbl losses.,Monitor well with trip tank, static.PJSM,"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"ZXP LTP/Flex lock liner hanger,44,100 lbs shear force,2500 psi set. C/O power tongs and M/U XO to stump M/U Hydril 625 connection,verify 9 shear screws installed in hyd setting tool set @ 2979 psi.Mix and fill liner tie back sleeve w/XAN PLEX.,M/U 1 std 5"DP.RIH to 7138',PU/SO 160k/93k M/U top drive,circulate 2 3/8"inner string volume 27 bbls 130 gpm,1140 psi to ensure clear flow path,w/top drive TQ set @ 9.8k,rotate 7 rpm 8600 ft/lbs TQ,blow down top drive.,RIH with lower completion conveyed on 5"drill pipe f/7138'at 1.5 min a std,easy in and out of slips being careful not to rotate pipe when in slips.Fill pipe on the fly and top off every 5 stds.Record P/U and S/O every 500'ran.RIH with 33 stds drifted pipe f/derrick to 9149',drift remaining stands in derrick,RIH to std#58 @ 10722' Note:Loss rate 1 bph TIH.,Continue to RIH with lower completion recording weights every 500',easy in and out of slips fill pipe on the fly. Drift and pick up drill collars from 10722'to 11554'15-20 fpm slowing to 10-15fpm at 11,100'to minimize buckling.,Continue to RIH with stands from the derrick,drifting pipe,from 11554'to 12057',set down at 11650'and 11791'work pipe slowly trying to minimize buckling,continue to RIH to 11820',set down.,attempt to work down,unable to get weight. Make up top drive and establish circulation 2.5 bpm 965 psi,with top drive torque set at 9600 ft-lbs(max on Hydril 625=12800 ft-lbs)establish rotary 2-3 rpms. Continue to work pipe down at 2fpm to 11860',top drive stalling out in down stroke 2-3 rpms in up stroke,working pipe as needed. Increase pump rate to 3 bpm/1200 psi and max torque to 11,800 ft-lbs and continue to work pipe down at 4-6 fpm 1-2 rpms.,Continue to wash and ream with liner on HWDP from 12,057'to 12850';picking up and drifting from shed and making up stands in the mousehole. 3 bpm 1260 psi, 1-2 rpms/11800ft-lbs working pipe as rotary stalls and weight is lost. 3-5 fpm. PUW 240K,Loss rate while pumping 3 bpm;2-3 bph.,22 bbls loss to formation for total=1026 bbis,Hauled 560 bbls fluid to G&I for total=11743 bbls Hauled 0 bbls H2O from 6 mile lake for total=11690 bbls 0 lbs metal for total=51 lbs 12/17/2017 Continue to wash and ream with liner on HWDP from 12850'to 13481'picking up and drifting 46 jts HW from shed and making up stands in the mousehole. 3 bpm 1260 psi, 1-2 rpms/11800ft-lbs working pipe as rotary stalls and weight is lost. 3-5 fpm. M/U single jt DP w/15'Pup jt.Wash to 13515'on depth for shpe. P/U 228k. Loss rate washing down 1 bph.22 bbl losses washing screens to bttm.,With string in tension parked @ 13515',PJSM,displace well over to 9.1 ppg brine pumping 3.2 bpm,1450 psi,dump mud returns.Pumped 870 bbls total,65 bbls over calculated displacement. Collect passing PST at end of displacement.,Drop closing ball for wellbore isolation valve. Pump down at 2 bpm,slowing to 1 bpm at 700 stokes,observe land on seat at 1100 strokes. Pressure up to-'SW psi to shut valve,continue to pressure up to 2600 to set liner hanger. Slack off and confirm liner hanger set. Continue to Pressure up to 3500 psi,observe indication of packer setting at 2900 psi.•Hold 3500 psi for 5 minutes. ytiwap to test pump and pressure up,to 4300 psi to neutralize and release liner running tool. Pick up 5'to expose dog subs. Slack off and stack 60K,pick up and rotate 10 rpms,rotate wt 167K,slack off to 100K. Pick up to neutral weight. Top of Liner set at 6450.35';liner shoe at 13515',Close top rams and line up to test back side. Test liner top to 1500 psi for 10 minutes-good. Rig down,blow down. L/D 4 joints of HWDP and monitor well. 30 minute loss rate=36 bph.,Slip and cut 69'of drilling Iine.,Service rig:top drive,crown and draw works. Perform a derrick inspection,POOH laying down DP,HWDP,and drill collars from 13388'to 9716'. Loss rate 30 bph.,123 bbls loss to formation for total=1149 bbls,Hauled 1546 bbls fluid to GSI for total=13289 bbls Hauled 260 bbls H2O from 6 mile lake for total=11950 bbls 0 lbs metal for total=51 lbs 12/18/2017 Continue to POOH L/D 5"DS50 DP f/9716'to 8330',POOH f/8330'to 7060'@ LRT racking 20 stds in derrick.,Inspect and L/D LRT and XOs,M/U safety jt for 2 3/8"inner string.R/D Hawk jaw,R/U 2 3/8"handling equipment,PJSM,POOH L/D 2 3/8"inner string f/6982'to surface.(224 jts)L/D stinger.Note:Rinse 2 3/8"w/fresh water,dope pin and box end before installing thread protectors. 386 bbl losses TOOH.,Monitor well,static loss rate 20 bph,R/D power tongs„C/O handling equipment f/5"DP,clear and clean rig floor. Currently @ 20 bph static loss rate.,M/U 3 1/2"mule shoe w/XOs,RIH w/5"stds of drill pipe to 6413'.PUW 140K,SOW 93K. Loss rate 20 bph,Establish circulation and wash down to 6460'(10'into TOL),circulate 50 bbls at 8 bpm/200 psi,pick up to 6449'. Increase rate to 12 bpm/450psi reciprocating pipe. Circulate shaker clean(3.5x BU),PST pass. Initial loss rate while circulating 80-100 bph,slowing to 0 bph during circulation. Displace well to clean 9.1 ppg brine,pump 40 bbl spacer followed by 500 bbls of brine prior to taking returns back into pit,After passing PST. Flow check well,breathing back becoming static in 30 minutes. Blow down top drive.,POOH laying down drill pipe from 6440'to surface,L/D mule shoe.Loss rate increasing back to 15 bph.,Pull wear bushing. Submit 24 hr notice for BOPE test at 06:00 for 12/20/17,624 bbls loss to formation for total=1773 bbls Hauled 664 bbls fluid to G&I for total=13953 bbls Hauled 260 bbls H2O from 6 mile lake for total=12210 bbls 12/19/2017 Stage Landing Jt and hanger in prep for Drift Run.R/D Hawk Jaw and remove from floor.Drift Run Casing Hanger.,Begin R/U WOT and Change top rams to 7 Monitor well @ 15 bph loss rate.,R/U and test UPR to to 250/3000 psi on 7 5/8"Pipe size with no issues.,R/U to run 7 5/8"casing,M/U crossover to l-OSV, ITJSM with all parties involved,review plan for well control.,P/U and run 7 5/8"tie back per 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/17.0"to 6413'(157 jts ran)M/U tag jt,crossover, 15'drill pipe pup jt.M/U top drive.165k P/U,100k S/O. TQ turn 7 5/8"VAM ST-L 29.7#L-80 csg to optimum @ 5349 ft/lbs 156 bbl losses running tie bask string,Wash down pumping 2 bpm,0 psi.Enter TOL @ 6445',lost returns @ 6446'when circulating ports entered SB.NO-GO out @ 6454',shut down pump,close annular,pressure up backside to 500 psi to verify seal engagement.Bleed off pressure,open annular.,Space out seal assy 1'off NO-GO @ per BOT rep,L/D Tag jt,XO and 15'pup jt.L/D jt 157,M/U 2 spaceout pups=8.79',M/U jt 157,M/U Vam STL x Buttress XO,pup jt w/hanger, M/U landing jt.Land out hanger 25.7'RKB w/locator 1'off liner top,mule shoe depth @ 6453',R/U to reverse circulate.Close annular,pressure up annulus to 500 psi to ensure proper spaceout and seal engagement.Bleed off pressure to 250 psi,strip up hole until pressure dumps 7',exposing seal ports to annulus.,Establish reverse circulation pumping down kill line 3 bpm,40 psi,R/U LRS to pump diesel down annulus,PJSM,LRS test lines to 1600 psi.Line up and pump 76 bbl corrosion inhibited 9.1 ppg brine from Vac truck down kill line,Pump 10 bbls 9.1 brine to clear surface lines,line up LRS,pump 48 bbls 90 deg diesel,2 bpm,38 psi with final @ 2 bpm 230 psi,Shut in LR,Strip in hole and land tie back seals,bleed off pressure and open annular.B/O landing jt,drain stack to cellar,vac out cellar w/vac truck.Pull landing jt,M/U Packoff running tool,install packoff,RILDS,test packoff to 500 psi f/5 min and 5000 psi f/10 min.L/D landing jt. Monitor well,LRS test test 9 7/8"x 7 5/8"annulus to 1000 psi for 30 min charted.R/D LR.,Monitor well with hole fill pump R/U on annulus,static loss rate 20 bph. C6se blind ram,C/O upper 7 5/8"casing ram to 2 7/8"x 5 1/2"VBR„222 bbls loss to formation for total=1995 bbls Hauled 436 bbls fluid to G&I for total=14389 bbls Hauled 0 bbls H2O from 6 mile lake for total=12210 bbls • • 12/20/2017 Finish C/O UPR back to 2 7/8"X 5 1/2"VBR's.Monitor well thru Annulus on trip tank under blind rams @ 14 bph loss rate.,Rig up and Test BOP.Test all components to 250/3000 psi on 2 7/8"Pipe size.Test gas alarms.Perform Accumulator Test:Start 3000,After closure 1600,200 psi build 19 sec,Full Recovery 66 sec.6 bottles @ 2265 psi Ave. Test witnessed by Adam Earl,R/D,Blow Down Test Equipment.,PJSM on Rigging up to run completion.,Rig up to run completion.Stage and secure Cap Line spools on ODS rig floor.PJSM,Hang Sheaves for cap lines,ESP cable and heat trace.Thread ESP cable and heat trace thru sheave to rig floor.Load ESP tools and equipment to rig floor.M/U FOSV to XO,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 separator,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,M/U MLE to mtr and test same,install 18 specialty clamps„Monitor well WI trip tank.Losses @ 20 bph„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,TQ to 2240 ft/lbs,M/U GLM w/dummy,pup jt above and below to 250',P/U and RIH w/2 7/8"ESP completion f/250'to 2033'(62 jts ran) Install canon clamp on every jt ran,Test cable continuity every 1000'and cap lines every 2000'. Loss rate RIH 15 BPH.,Note:highline power went down on L-Pad @ 04:00,put rig on gen power.,,321 bbls loss to formation for total=2316 bbls Hauled 80 bbls fluid to G&I for total=14469 bbls Hauled 0 bbls H2O from 6 mile lake for total=12210 bbls 12/21/2017 Finish test on ESP Cable @ 2000'.Hold PJSM with Crew Change.,RIH with 2 7/8"eue tubing f/2000'to 2709'MD,installing CC Clamps on every jt,using BOL 2000 pipe dope,Tq connections to 2240 ft/Ibs.,Park @ 2709'MD.Stage heat trace clamps on rig floor.Install heat trace on joint#84.(2300'from surface.),Continue to run completion installing ESP/Heat Trace from 2709'to 4000',126 jts ran,attempt to test heat trace,failed test,grounding out,P/U out of slips,found damaged heat trace cable at slips.,Monitor well,static loss rate 15 bph.R/U and splice heat trace cable as per centrilift,test cable,good test.,Continue to run completion installing ESP/Heat Trace from 4000'to 4806'(152 jts) Loss rate 15 bph„314 bbls loss to formation for total=2316 bbls Hauled 0 bbls fluid to G&I for total=14469 bbls Hauled 0 bbls H2O from 6 mile lake for total=12210 bbls 12/22/2017 Continue to run 2 7/8”eue Tubing completion installing ESP/Heat Trace from 4806'to 4957'(156 jts)Clamp Count:5'Clamps 368,Single channel CC Clamps 84,Dual Channel Cannon 76,Steel Bands 2,Specialty clamps on Pump/Mtr Assy 18,MU Tubing Hgr and landing joint.Centrilift splice ESP and Heat Trace. Terminate control lines.Make test on cables.T8st good.Land Hanger,RILDS,UD Landing Joint install BP Bottom of pump @ 4985'.Up Wt 72K w/Blocks, Dn Wt 58K w/Blocks. Start Rigging Down of re m6ving running equipmenffromTRig.,RID Sheaves from Derrick.Cont R/D and UD completion handling equipment.Clear Rig Floor of excess Clamps/Equipment.,Bleed down Koomey,RID Koomey Hoses.Pull Flow Nipple,R/U Cellar Cranes,R/D Turn buckles,. R/D Choke and kill lines and flange together.Hoist stack and set Back.,Centrilift test cable before installing tree. 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 ford min,good.Pull BPV,Install TWC. Flush and R/D choke/kill lines,R/U LRS7test lines,test tree w/diesel to 500 psi low and 5000 psi high,good.Pull TWC.,LRS freeze protect well with diesel to 2500'.Bullhead 14 bbls down tbg 3/4 bpm, 1000 psi,lineup and bullhead 95 bbls down annulus 2 bpm,400 psi.R/D LRS.Centralift make final checks.Secure tree.,Drain liner wash on both mud pumps,disassemble mud pump fluid ends to ensure dry for rig move.vac out cellar box,vac out sumps,cleanup cellar area. PJSM,Bridal up and scope down derrick.Finish cleaning pits,blow down waterlines.Disconnect pit interconnects.Prep pipe shed for move.,Roll up derrick wt bucket line.Flip up roof hatches between modules.Freeze protect laundry room.Cleanout and freeze protect Vac unit.R/D Pit interconnects.Blow down steam lines.Remove cuttings box.,,285 bbls loss to formation for total=2915 bbls Hauled 320 bbls fluid to G&I for total=14789 bbls Hauled 0 bbls H2O from 6 mile lake for total=12210 bbls 12/23/2017 Continue to prep rig for move to MPL-52.Trucks on location @ 08:00 hrs.Separate Modules and stage on Pad.Back Sub off of L-51.Set sub down on Mats. Re-position mat layout for L-52,Perform rig maintenance while W/O Well support to tie in L-51.RID cellar BOP landing,C/O misc steam valves.Rebuild KR valve on accumulator.Cut and remove expanded metal from pipe shed sump to replace w/composite grating.,With crane spot new camp genset.,Set DSA on starting head.Fold down top drive coffin,check and tighten hydraulic fittings.Continue to work on pad house keeping.,Continue with rig maintenance projects while W/O Well support to tie in L-51.Open up electrical junction box on top drive and inspect same,clean.Close J-Box and safety wire same.Finish working on choke room heater.Reposition rollers on rig floor tuggers.Palletize and stage wellhead equipment by rig.,Work on grease zerk manifold for drag chain bearings.Install proximity sensor back on top drive.Crane remove handrails off L-53 well house,move well house back 1'towards well row, Well support finish with L-51 tie in @ 00:00,Crane stairs off sub. Dig out snow and ice and level around L-52 cellar by hand.Lay herculite in place,crane in and set mats around cellar,set mats in front of L-52.Spot wellhead equipment behind cellar box.Walk rig up to L-52 slot,rig is 6"from clearing L-53 well house and being able to center rig over L-52,Well support R/U and pull L-53 well house.Walk sub back and spot over well,Release rig from L-51 @ 06:00„Losses to formation total=2915 bbls Hauled 0 bbls fluid to G&I for total=14789 bbls Hauled 0 bbls H2O from 6 mile lake for total=12210 bbls I Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-51 50-029-23587-00-00 Sperry Drilling Definitive Survey Report 15 December, 2017 $ � HALLIBURTON Sperry Drilling • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU L-51 Project: Milne Point ' TVD Reference: MPU L-53 Actual @ 42.20usft Site: M Pt L Pad MD Reference: MPU L-53 Actual @ 42.20usft Well: MPU L-51 '`North Reference: True Wellbore: MPU L-51 Survey Calculation Method: Minimum Curvature Design: MPU L-51 Database: y Sperry EDM-NORTH US+CANADA 3 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-51 Well Position +N/-S 0.00 usft Northing: 6,031,906.80 usft Latitude: 70°29'52.951 N +E/-W 0.00 usft Easting: 544,656.92 usft Longitude: 149°38'5.291 W Position Uncertainty 0.00 usft Wellhead Elevation: 42.20 usft Ground Level: 15.30 usft Wellbore MPU L-51 „.,, Magnetics Model Name Sample Date DeclinationDip Angle Field Strength BGGM2017 11/16/2017 17.44 81.03 57,494 Design MPU L-51 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.90 Vertical Section: Depth From(TVD) +N/-5 +E/-WDirection t (usft) ; (usft) (usft) ¢' (°) 26.90 0.00 0.00 196.98 Survey Program Date 12/15/2017 i, From To -, .. ;e..-_ - .:a.' (usft) (usft) Survey(Wellbore) I' Tool Name ' Description 1 „ Survey Date 50.00 719.00 SDI NSG Tool-SS(MPU L-51) 2 Gyro-NS-GC_Drill collar H029Ga:North seeking single shot in drill collar 11/22/2017 785.80 6,570.51 MWD(MPU L-51) 2_MWD+IFR2+MS+Sag A013Mb:IIFR dec&multi-station analysis+sag 11/29/2017 6,667.38 13,803.65 MWD(2)(MPU L-51) 2_MWD+IFR2+MS+Sag A013Mb:IIFR dec&multi-station analysis+sag 12/11/2017 Survey Iw a I Map Map Vertical 1'1 ;, MD Inc Azi TVD TVDSS +N/S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.90 0.00 0.00 26.90 -15.30 0.00 0.00 6,031,906.80 544,656.92 0.00 0.00 UNDEFINED 50.00 0.15 131.38 50.00 7.80 -0.02 0.02 6,031,906.78 544,656.94 0.65 0.01 2_Gyro-NS-GC_Drill collar(1) 100.00 0.23 192.14 100.00 57.80 -0.16 0.05 6,031,906.64 544,656.97 0.41 0.14 2_Gyro-NS-GC_Drill collar(1) 161.00 0.23 117.71 161.00 118.80 -0.34 0.13 6,031,906.46 544,657.06 0.46 0.28 2_Gyro-NS-GC_Drill collar(1) 225.00 0.23 190.90 225.00 182.80 -0.52 0.22 6,031,906.28 544,657.15 0.43 0.44 2_Gyro-NS-GC_Drill collar(1) 286,00 1.41 235.71 285.99 243.79 -1.07 -0.42 6,031,905.73 544,656.51 2.06 1.14 2_Gyro-NS-GC_Drill collar(1) 347.00 2.79 241.81 346.95 304.75 -2.19 -2.35 6,031,904.60 544,654.58 2.29 2.78 2_Gyro-NS-GC_Drill collar(1) 408.00 4.08 240.71 407.84 365.64 -3.95 -5.55 6,031,902.81 544,651.39 2.12 5.40 2_Gyro-NS-GC_Drill collar(1) 470.00 4.99 240.50 469.64 427.44 -6.36 -9.82 6,031,900.38 544,647.14 1.47 8.95 2_Gyro-NS-GC_Drill collar(1) 532.00 5.87 235.15 531.37 489.17 -9.50 -14.77 6,031,897.21 544,642.21 1.64 13.40 2_Gyro-NS-GC_Drill collar(1) 593.00 8.62 232.65 591.87 549.67 -14.06 -20.96 6,031,892.62 544,636.04 4.54 19.57 2_Gyro-NS-GC_Drill collar(1) 656.00 12.47 230.79 653.80 611.60 -21.22 -29.99 6,031,885.40 544,627.06 6.13 29.06 2_Gyro-NS-GC_Drill collar(1) 12/15/2017 5:35:05PM Page 2 COMPASS 5000.1 Build 810 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC l Local Co-ordinate Reference: Well MPU L-51 tr Project: Milne Point TVD Reference: MPU L-53 Actual @ 42.20usft Site: M Pt L Pad MD Reference. MPU L-53 Actual @ 42.20usft Well: MPU L-51 North Reference: True Wellbore: MPU L-51iSurvey Calculation Method: Minimum Curvature Design: MPU L-51 Database: . 5, Sperry EDM-NORTH US+CANADA Survey Map Map Vertical :,,,,,,,,,,- MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 719.00 15.63 225.07 714.91 672.71 -31.52 -41.27 6,031,875.03 544,615.84 5.47 42.20 2 Gyro-NS-GC Drill collar(1) 785.80 17.59 220.00 778.92 736.72 -45.61 -54.13 6,031,860.87 544,603.07 3.65 59.43 2_MWD+IFR2+MS+Sag(2) 846.80 18.80 219.93 836.87 794.67 -60.21 -66.37 6,031,846.20 544,590.92 1.98 76.97 2_MWD+IFR2+MS+Sag(2) 911.31 21.33 218.78 897.46 855.26 -77.33 -80.39 6,031,829.00 544,577.00 3.97 97.44 2_MWD+IFR2+MS+Sag(2) 974.30 24.69 212.66 955.44 913.24 -97.34 -94.67 6,031,808.90 544,562.84 6.54 120.75 2_MWD+IFR2+MS+Sag(2) 1,037.08 27.79 209.84 1,011.74 969.54 -121.08 -109.03 6,031,785.08 544,548.63 5.32 147.65 2_MWD+IFR2+MS+Sag(2) 1,099.98 31.33 208.44 1,066.45 1,024.25 -148.19 -124.12 6,031,757.88 544,533.70 5.73 177.98 2_MWD+IFR2+MS+Sag(2) 1,162.70 33.59 208.94 1,119.37 1,077.17 -177.72 -140.29 6,031,728.26 544,517.72 3.63 210.94 2_MWD+IFR2+MS+Sag(2) 1,226.04 35.47 208.58 1,171.55 1,129.35 -209.19 -157.56 6,031,696.69 544,500.64 2.99 246.08 2_MWD+IFR2+MS+Sag(2) 1,286.33 38.39 208.26 1,219.73 1,177.53 -241.05 -174.79 6,031,664.73 544,483.60 4.85 281.59 2_MWD+IFR2+MS+Sag(2) 1,351.58 42.10 207.51 1,269.53 1,227.33 -278.31 -194.50 6,031,627.36 544,464.12 5.73 322.97 2_MWD+IFR2+MS+Sag(2) 1,414.12 46.18 206.25 1,314.40 1,272.20 -317.15 -214.17 6,031,588.40 544,444.68 6.67 365.87 2_MWD+IFR2+MS+Sag(2) 1,477.00 48.76 206.27 1,356.90 1,314.70 -358.70 -234.67 6,031,546.73 544,424.43 4.10 411.60 2_MWD+IFR2+MS+Sag(2) 1,537.92 50.88 207.36 1,396.21 1,354.01 -400.24 -255.67 6,031,505.07 544,403.69 3.74 457.45 2_MWD+IFR2+MS+Sag(2) 1,602.57 54.61 208.09 1,435.34 1,393.14 -445.77 -279.61 6,031,459.40 544,380.02 5.84 508.00 2_MWD+IFR2+MS+Sag(2) 1,665.93 50.73 207.85 1,473.75 1,431.55 -490.26 -303.24 6,031,414.77 544,356.66 6.13 557.45 2_MWD+IFR2+MS+Sag(2) 1,728.69 52.65 208.53 1,512.66 1,470.46 -533.66 -326.50 6,031,371.24 544,333.66 3.18 605.75 2_MWD+IFR2+MS+Sag(2) 1,791.98 55.92 207.31 1,549.60 1,507.40 -579.06 -350.55 6,031,325.70 544,309.89 5.40 656.20 2_MWD+IFR2+MS+Sag(2) 1,854.77 54.89 206.40 1,585.25 1,543.05 -625.18 -373.90 6,031,279.45 544,286.82 2.03 707.12 2_MWD+IFR2+MS+Sag(2) 1,917.48 55.60 207.38 1,621.00 1,578.80 -671.13 -397.21 6,031,233.37 544,263.79 1.71 757.87 2_MWD+IFR2+MS+Sag(2) 1,980.00 56.55 207.53 1,655.89 1,613.69 -717.16 -421.12 6,031,187.19 544,240.15 1.53 808.88 2_MWD+IFR2+MS+Sag(2) 2,043.49 55.76 207.92 1,691.25 1,649.05 -763.84 -445.65 6,031,140.38 544,215.91 1.34 860.69 2_MWD+IFR2+MS+Sag(2) 2,105.98 53.93 208.23 1,727.23 1,685.03 -808.91 -469.70 6,031,095.16 544,192.14 2.96 910.82 2_MWD+IFR2+MS+Sag(2) 2,169.32 54.00 208.49 1,764.49 1,722.29 -853.99 -494.03 6,031,049.94 544,168.08 0.35 961.03 2_MWD+IFR2+MS+Sag(2) 2,232.48 54.29 208.27 1,801.49 1,759.29 -899.03 -518.36 6,031,004.76 544,144.02 0.54 1,011.22 2_MWD+IFR2+MS+Sag(2) 2,295.62 51.70 209.71 1,839.49 1,797.29 -943.13 -542.78 6,030,960.52 544,119.86 4.49 1,060.53 2_MWD+IFR2+MS+Sag(2) 2,358.10 52.96 209.37 1,877.67 1,835.47 -986.16 -567.17 6,030,917.35 544,095.74 2.06 1,108.80 2_MWD+IFR2+MS+Sag(2) 2,421.52 54.02 209.26 1,915.40 1,873.20 -1,030.60 -592.12 6,030,872.76 544,071.06 1.68 1,158.60 2_MWD+IFR2+MS+Sag(2) 2,484.13 54.59 209.17 1,951.93 1,909.73 -1,074.98 -616.94 6,030,828.24 544,046.51 0.92 1,208.29 2_MWD+IFR2+MS+Sag(2) 2,546.35 55.29 208.71 1,987.67 1,945.47 -1,119.55 -641.58 6,030,783.52 544,022.14 1.28 1,258.11 2_MWD+IFR2+MS+Sag(2) 2,610.03 53.71 208.85 2,024.65 1,982.45 -1,164.99 -666.54 6,030,737.94 543,997.45 2.49 1,308.86 2_MWD+IFR2+MS+Sag(2) 2,671.84 54.97 207.76 2,060.69 2,018.49 -1,209.21 -690.35 6,030,693.59 543,973.91 2.49 1,358.10 2_MWD+IFR2+MS+Sag(2) 2,735.46 53.88 207.11 2,097.70 2,055.50 -1,255.13 -714.19 6,030,647.52 543,950.35 1.90 1,408.99 2_MWD+IFR2+MS+Sag(2) 2,798.60 53.84 207.66 2,134.94 2,092.74 -1,300.41 -737.65 6,030,602.11 543,927.17 0.71 1,459.14 2_MWD+IFR2+MS+Sag(2) 2,862.27 54.35 208.24 2,172.27 2,130.07 -1,345.96 -761.82 6,030,556.42 543,903.28 1.09 1,509.77 2_MWD+IFR2+MS+Sag(2) 2,924.25 53.79 207.95 2,208.64 2,166.44 -1,390.23 -785.45 6,030,512.01 543,879.91 0.98 1,559.01 2_MWD+IFR2+MS+Sag(2) 2,987.37 54.81 208.10 2,245.48 2,203.28 -1,435.48 -809.54 6,030,466.62 543,856.10 1.63 1,609.32 2_MWD+IFR2+MS+Sag(2) 3,050.53 55.14 207.48 2,281.73 2,239.53 -1,481.24 -833.65 6,030,420.72 543,832.26 0.96 1,660.12 2_MWD+IFR2+MS+Sag(2) 3,113.37 57.22 208.38 2,316.70 2,274.50 -1,527.36 -858.11 6,030,374.46 543,808.09 3.52 1,711.38 2_MWD+IFR2+MS+Sag(2) 3,176.37 56.85 208.42 2,350.98 2,308.78 -1,573.85 -883.25 6,030,327.82 543,783.23 0.59 1,763.19 2_MWD+IFR2+MS+Sag(2) 12/15/2017 5:35:05PM Page 3 COMPASS 5000.1 Build 81D • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU L-51 Project: Milne Point TVD Reference: MPU L-53 Actual @ 42.20usft Site: M Pt L Pad MD Reference: MPU L-53 Actual @ 42.20usft Well: MPU L-51 North Reference: True )E Wellbore: MPU L-51 Survey Calculation Method: Minimum Curvature Design: MPU L-51 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,239.00 55.74 209.00 2,385.74 2,343.54 -1,619.55 -908.28 6,030,281.98 543,758.48 1.93 1,814.20 2_MWD+IFR2+MS+Sag(2) 3,301.07 55.13 209.29 2,420.95 2,378.75 -1,664.19 -933.17 6,030,237.19 543,733.86 1.06 1,864.17 2_MWD+IFR2+MS+Sag(2) 3,364.57 54.55 209.62 2,457.52 2,415.32 -1,709.40 -958.70 6,030,191.84 543,708.60 1.01 1,914.85 2_MWD+IFR2+MS+Sag(2) 3,427.45 54.28 210.46 2,494.11 2,451.91 -1,753.67 -984.29 6,030,147.42 543,683.28 1.17 1,964.67 2_MWD+IFR2+MS+Sag(2) 3,490.94 53.67 210.93 2,531.45 2,489.25 -1,797.82 -1,010.50 6,030,103.12 543,657.33 1.13 2,014.55 2_MWD+IFR2+MS+Sag(2) 3,552.92 53.36 210.17 2,568.30 2,526.10 -1,840.73 -1,035.83 6,030,060.06 543,632.26 1.11 2,062.99 2_MWD+IFR2+MS+Sag(2) 3,614.52 53.66 208.32 2,604.94 2,562.74 -1,883.94 -1,060.03 6,030,016.71 543,608.33 2.46 2,111.38 2_MWD+IFR2+MS+Sag(2) 3,678.95 52.62 208.70 2,643.59 2,601.39 -1,929.24 -1,084.63 6,029,971.27 543,584.01 1.68 2,161.89 2_MWD+IFR2+MS+Sag(2) 3,741.66 53.17 207.84 2,681.42 2,639.22 -1,973.29 -1,108.32 6,029,927.08 543,560.59 1.40 2,210.94 2_MWD+IFR2+MS+Sag(2) 3,804.78 51.47 208.60 2,720.00 2,677.80 -2,017.31 -1,131.93 6,029,882.93 543,537.24 2.86 2,259.93 2_MWD+IFR2+MS+Sag(2) 3,866.86 53.17 207.85 2,757.94 2,715.74 -2,060.60 -1,155.17 6,029,839.50 543,514.27 2.90 2,308.12 2_MWD+IFR2+MS+Sag(2) 3,929.55 55.13 206.80 2,794.66 2,752.46 -2,105.74 -1,178.48 6,029,794.22 543,491.22 3.41 2,358.11 2_MWD+IFR2+MS+Sag(2) 3,992.50 53.72 207.67 2,831.28 2,789.08 -2,151.26 -1,201.91 6,029,748.56 543,468.07 2.51 2,408.49 2_MWD+IFR2+MS+Sag(2) 4,055.28 54.85 208.04 2,867.93 2,825.73 -2,196.33 -1,225.73 6,029,703.36 543,444.53 1.86 2,458.54 2_MWD+IFR2+MS+Sag(2) 4,117.61 55.54 208.17 2,903.51 2,861.31 -2,241.47 -1,249.84 6,029,658.08 543,420.69 1.12 2,508.76 2_MWD+IFR2+MS+Sag(2) 4,181.21 55.83 208.66 2,939.36 2,897.16 -2,287.67 -1,274.84 6,029,611.73 543,395.98 0.78 2,560.25 2_MWD+IFR2+MS+Sag(2) 4,244.11 56.02 208.58 2,974.60 2,932.40 -2,333.41 -1,299.79 6,029,565.85 543,371.30 0.32 2,611.28 2_MWD+IFR2+MS+Sag(2) 4,307.24 56.57 209.73 3,009.63 2,967.43 -2,379.27 -1,325.38 6,029,519.84 543,345.99 1.75 2,662.61 2_MWD+IFR2+MS+Sag(2) 4,369.89 55.47 207.40 3,044.65 3,002.45 -2,424.89 -1,350.22 6,029,474.08 543,321.42 3.55 2,713.50 2_MWD+IFR2+MS+Sag(2) 4,432.82 54.18 205.91 3,080.90 3,038.70 -2,470.86 -1,373.30 6,029,427.98 543,298.62 2.82 2,764.20 2_MWD+IFR2+MS+Sag(2) 4,495.52 54.34 206.46 3,117.53 3,075.33 -2,516.53 -1,395.76 6,029,382.18 543,276.44 0.76 2,814.44 2_MWD+IFR2+MS+Sag(2) 4,558.66 54.56 206.72 3,154.24 3,112.04 -2,562.46 -1,418.75 6,029,336.11 543,253.73 0.48 2,865.09 2_MWD+IFR2+MS+Sag(2) 4,621.34 53.26 206.99 3,191.16 3,148.96 -2,607.65 -1,441.63 6,029,290.79 543,231.12 2.10 2,914.99 2_MWD+IFR2+MS+Sag(2) 4,684.40 52.41 207.56 3,229.26 3,187.06 -2,652.32 -1,464.66 6,029,245.99 543,208.36 1.53 2,964.43 2_MWD+IFR2+MS+Sag(2) 4,747.28 54.05 207.83 3,266.89 3,224.69 -2,696.91 -1,488.07 6,029,201.26 543,185.23 2.63 3,013.92 2_MWD+IFR2+MS+Sag(2) 4,810.31 54.45 208.32 3,303.72 3,261.52 -2,742.05 -1,512.14 6,029,155.99 543,161.42 0.89 3,064.12 2_MWD+IFR2+MS+Sag(2) 4,873.10 54.84 208.55 3,340.05 3,297.85 -2,787.08 -1,536.53 6,029,110.81 543,137.31 0.69 3,114.31 2_MWD+IFR2+MS+Sag(2) 4,933.79 55.23 209.05 3,374.83 3,332.63 -2,830.66 -1,560.49 6,029,067.09 543,113.62 0.93 3,162.99 2_MWD+IFR2+MS+Sag(2) 4,997.97 55.60 209.65 3,411.26 3,369.06 -2,876.72 -1,586.39 6,029,020.89 543,088.00 0.96 3,214.60 2_MWD+IFR2+MS+Sag(2) 5,061.30 55.33 209.68 3,447.17 3,404.97 -2,922.05 -1,612.21 6,028,975.40 543,062.45 0.43 3,265.49 2_MWD+IFR2+MS+Sag(2) 5,124.22 55.80 210.90 3,482.75 3,440.55 -2,966.86 -1,638.38 6,028,930.44 543,036.55 1.77 3,315.99 2_MWD+IFR2+MS+Sag(2) 5,186.25 55.66 209.75 3,517.68 3,475.48 -3,011.10 -1,664.26 6,028,886.05 543,010.94 1.55 3,365.87 2_MWD+IFR2+MS+Sag(2) 5,249.89 55.43 207.45 3,553.68 3,511.48 -3,057.17 -1,689.38 6,028,839.83 542,986.10 3.00 3,417.26 2_MWD+IFR2+MS+Sag(2) 5,312.66 55.41 207.24 3,589.31 3,547.11 -3,103.08 -1,713.12" 6,028,793.79 542,962.64 0.28 3,468.10 2_MWD+IFR2+MS+Sag(2) 5,375.64 55.76 208.68 3,624.91 3,582.71 -3,148.97 -1,737.48 6,028,747.76 542,938.56 1.97 3,519.10 2_MWD+IFR2+MS+Sag(2) 5,438.35 55.27 208.91 3,660.41 3,618.21 -3,194.26 -1,762.38 6,028,702.32 542,913.93 0.84 3,569.70 2_MWD+IFR2+MS+Sag(2) 5,501.31 57.31 209.18 3,695.35 3,653.15 -3,240.05 -1,787.81 6,028,656.39 542,888.79 3.26 3,620.91 2_MWD+IFR2+MS+Sag(2) 5,564.15 58.36 208.65 3,728.80 3,686.60 -3,286.61 -1,813.53 6,028,609.67 542,863.35 1.82 3,672.96 2_MWD+IFR2+MS+Sag(2) 5,627.25 60.40 208.31 3,760.94 3,718.74 -3,334.34 -1,839.42 6,028,561.80 542,837.75 3.27 3,726.16 2_MWD+IFR2+MS+Sag(2) 5,689.40 62.94 206.59 3,790.43 3,748.23 -3,382.88 -1,864.62 6,028,513.11 542,812.84 4.76 3,779.95 2_MWD+IFR2+MS+Sag(2) 12/15/2017 5:35:05PM Page 4 COMPASS 5000.1 Build 81D • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU L-51 Project: Milne Point TVD Reference: MPU L-53 Actual @ 42.20usft {° Site: M Pt L Pad MD Reference: MPU L-53 Actual @ 42.20usftII Well: MPU L-51 North Reference: True Wellbore: MPU L-51 Survey Calculation Method: Minimum Curvature ;I Design: MPU L-51 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical 44,44444;444-4-4,44.4444-444.4g4-4 MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section 4 4'' •. . ,xs-. (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,752.98 67.24 202.15 3,817.22 3,775.02 -3,435.40 -1,888.37 6,028,460.46 542,789.41 9.26 3,837.11 2_MWD+IFR2+MS+Sag(2) 5,815.66 71.01 198.23 3,839.56 3,797.36 -3,490.35 -1,908.55 6,028,405.39 542,769.56 8.38 3,895.56 2_MWD+IFR2+MS+Sag(2) 5,878.77 73.34 197.09 3,858.88 3,816.68 -3,547.60 -1,926.77 6,028,348.04 542,751.69 4.07 3,955.63 2_MWD+IFR2+MS+Sag(2) 5,943.14 79.16 194.43 3,874.17 3,831.97 -3,607.74 -1,943.73 6,028,287.80 542,735.09 9.89 4,018.11 2_MWD+IFR2+MS+Sag(2) 6,003.05 81.99 194.66 3,883.98 3,841.78 -3,664.94 -1,958.57 6,028,230.51 542,720.60 4.74 4,077.15 2_MWD+IFR2+MS+Sag(2) 6,068.08 82.82 193.42 3,892.58 3,850.38 -3,727.48 -1,974.20 6,028,167.89 542,705.34 2.28 4,141.53 2_MWD+1F552+MS+Sag(2) 6,130.20 82.46 193.85 3,900.53 3,858.33 -3,787.35 -1,988.73 6,028,107.94 542,691.18 0.90 4,203.03 2_MWD+IFR2+MS+Sag(2) 6,192.92 82.93 194.24 3,908.51 3,866.31 -3,847.70 -2,003.83 6,028,047.51 542,676.44 0.97 4265.16 2_MWD+IFR2+MS+Sag(2) 6,256.34 81.99 193.79 3,916.83 3,874.63 -3,908.70 -2,019.05 6,027,986.42 542,661.58 1.64 4,327.94 2_MWD+IFR2+MS+Sag(2) 6,319.21 83.26 193.45 3,924.90 3,882.70 -3,969.29 -2,033.73 6,027,925.75 542,647.27 2.09 4,390.19 2_MWD+IFR2+MS+Sag(2) 6,381.95 83.03 193.25 3,932.39 3,890.19 -4,029.90 -2,048.12 6,027,865.06 542,633.25 0.48 4,452.35 2_MWD+IFR2+MS+Sag(2) 6,445.17 84.98 194.52 3,938.99 3,896.79 -4,090.93 -2,063.20 6,027,803.94 542,618.53 3.67 4,515.13 2_MWD+IFR2+MS+Sag(2) 6,508.13 89.05 195.10 3,942.27 3,900.07 -4,151.71 -2,079.27 6,027,743.08 542,602.83 6.53 4,577.95 2_MWD+IFR2+MS+Sag(2) 6,570.51 93.98 193.89 3,940.62 3,898.42 -4,212.06 -2,094.88 6,027,682.64 542,587.59 8.14 4,640.23 2_MWD+IFR2+MS+Sag(2) 6,667.38 92.53 193.60 3,935.12 3,892.92 -4,306.00 -2,117.86 6,027,588.57 542,565.18 1.53 4,736.78 2_MWD+IFR2+MS+Sag(3) 6,729.93 90.68 195.03 3,933.37 3,891.17 -4,366.58 -2,133.31 6,027,527.91 542,550.09 3.74 4,799.24 2_MWD+IFR2+MS+Sag(3) 6,792.80 88.77 194.22 3,933.67 3,891.47 -4,427.41 -2,149.19 6,027,466.99 542,534.58 3.30 4,862.05 2_MWD+IFR2+MS+Sag(3) 6,855.46 90.62 194.67 3,934.00 3,891.80 -4,488.09 -2,164.82 6,027,406.23 542,519.32 3.04 4,924.64 2_MWD+IFR2+MS+Sag(3) 6,918.16 93.02 195.51 3,932.01 3,889.81 -4,548.59 -2,181.13 6,027,345.63 542,503.37 4.06 4,987.27 2_MWD+IFR2+MS+Sag(3) 6,981.35 92.84 195.48 3,928.78 3,886.58 -4,609.40 -2,197.99 6,027,284.73 542,486.88 0.29 5,050.36 2_MWD+IFR2+MS+Sag(3) 7,044.46 92.47 196.01 3,925.86 3,883.66 -4,670.08 -2,215.10 6,027,223.95 542,470.14 1.02 5,113.39 2_MWD+IFR2+MS+Sag(3) 7,106.61 92.66 196.95 3,923.08 3,880.88 -4,729.61 -2,232.71 6,027,164.32 542,452.88 1.54 5,175.47 2_MWD+IFR2+MS+Sag(3) 7,170.40 92.65 196.34 3,920.12 3,877.92 -4,790.67 -2,250.96 6,027,103.17 542,435.00 0.96 5,239.19 2_MWD+IFR2+MS+Sag(3) 7,232.98 93.40 195.15 3,916.82 3,874.62 -4,850.81 -2,267.92 6,027,042.92 542,418.41 2.25 5,301.67 2_MWD+IFR2+MS+Sag(3) 7,295.93 93.15 194.39 3,913.22 3,871.02 -4,911.58 -2,283.94 6,026,982.06 542,402.75 1.27 5,364.47 2_MWD+IFR2+MS+Sag(3) 7,358.79 91.54 193.77 3,910.65 3,868.45 -4,972.50 -2,299.22 6,026,921.06 542,387.84 2.74 5,427.19 2_MWD+IFR2+MS+Sag(3) 7,421.84 92.41 194.39 3,908.48 3,866.28 -5,033.62 -2,314.55 6,026,859.86 542,372.88 1.69 5,490.12 2_MWD+IFR2+MS+Sag(3) 7,484.37 91.79 194.90 3,906.19 3,863.99 -5,094.08 -2,330.35 6,026,799.31 542,357.45 1.28 5,552.56 2_MWD+IFR2+MS+Sag(3) 7,547.72 91.98 194.35 3,904.10 3,861.90 -5,155.34 -2,346.33 6,026,737.96 542,341.83 0.92 5,615.82 2_MWD+IFR2+MS+Sag(3) 7,610.46 91.17 193.10 3,902.38 3,860.18 -5,216.26 -2,361.21 6,026,676.95 542,327.32 2.37 5,678.43 2_MWD+IFR2+MS+5a9(3) 7,673.70 90.80 191.96 3,901.29 3,859.09 -5,277.99 -2,374.93 6,026,615.16 542,313.97 1.89 5,741.47 2_MWD+IFR2+MS+Sag(3) 7,736.50 91.98 191.71 3,899.77 3,857.57 -5,339.43 -2,387.81 6,026,553.64 542,301.47 1.92 5,804.00 2_MWD+IFR2+MS+Sag(3) 7,798.95 93.34 191.17 3,896.87 3,854.67 -5,400.58 -2,400.18 6,026,492.43 542,289.46 2.34 5,866.09 2_MWD+IFR2+MS+Sag(3) 7,861.87 91.42 191.64 3,894.26 3,852.06 -5,462.20 -2,412.61 6,026,430.74 542,277.40 3.14 5,928.66 2_MWD+IFR2+MS+Sag(3) 7,924.78 92.59 192.96 3,892.06 3,849.86 -5,523.62 -2,426.00 6,026,369.24 542,264.38 2.80 5,991.32 2_MWD+IFR2+MS+Sag(3) 7,987.32 93.89 191.97 3,888.52 3,846.32 -5,584.59 -2,439.48 6,026,308.20 542,251.27 2.61 6,053.56 2_MWD+IFR2+MS+Sag(3) 8,050.58 92.78 190.98 3,884.84 3,842.64 -5,646.48 -2,452.04 6,026,246.25 542,239.08 2.35 6,116.42 2_MWD+IFR2+MS+Sag(3) 8,112.63 92.41 190.42 3,882.03 3,839.83 -5,707.39 -2,463.55 6,026,185.27 542,227.94 1.08 6,178.03 2_MWD+IFR2+MS+Sag(3) 8,174.77 92.10 188.70 3,879.59 3,837.39 -5,768.61 -2,473.86 6,026,123.99 542,218.00 2.81 6,239.60 2_MWD+IFR2+MS+Sag(3) 8,237.44 91.60 188.80 3,877.56 3,835.36 -5,830.52 -2,483.39 6,026,062.03 542,208.84 0.81 6,301.59 2_MWD+IFR2+MS+Sag(3) 12/15/2017 5:35:05PM Page 5 COMPASS 5000.1 Build 81D • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU L-51 Project: Milne Point TVD Reference: MPU L-53 Actual @ 42.20usft Site: M Pt L Pad MD Reference: MPU L-53 Actual @ 42.20usft Well: MPU L-51 North Reference: True Wellbore: MPU L-51 Survey Calculation Method: Minimum Curvature Design: MPU L-51 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E1-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,298.50 92.72 190.34 3,875.26 3,833.06 -5,890.69 -2,493.54 6,026,001.82 542,199.06 3.12 6,362.10 2-MWD+1FR2+MS+Sag(3) 8,363.43 92.72 189.63 3,872.18 3,829.98 -5,954.56 -2,504.78 6,025,937.88 542,188.20 1.09 6,426.47 2_MWD+IFR2+MS+Sag(3) 8,426.17 92.16 189.66 3,869.51 3,827.31 -6,016.36 -2,515.28 6,025,876.03 542,178.07 0.89 6,488.64 2_MWD+1FR2+MS+Sag(3) 8,489.00 91.67 190.43 3,867.41 3,825.21 -6,078.19 -2,526.24 6,025,814.14 542,167.49 1.45 6,550.98 2_MWD+IFR2+MS+Sag(3) 8,551.88 91.48 189.61 3,865.68 3,823.48 -6,140.09 -2,537.17 6,025,752.18 542,156.93 1.34 6,613.37 2_MWD+IFR2+MS+Sag(3) 8,614.70 93.09 190.14 3,863.18 3,820.98 -6,201.92 -2,547.94 6,025,690.29 542,146.54 2.70 6,675.66 2_MWD+IFR2+MS+Sag(3) 8,677.68 92.53 188.98 3,860.09 3,817.89 -6,263.95 -2,558.38 6,025,628.20 542,136.46 2.04 6,738.03 2_MWD+IFR2+MS+Sag(3) 8,741.19 92.10 188.14 3,857.53 3,815.33 -6,326.70 -2,567.83 6,025,565.40 542,127.40 1.48 6,800.81 2_MWD+IFR2+MS+Sag(3) 8,803.92 91.54 187.26 3,855.53 3,813.33 -6,388.84 -2,576.23 6,025,503.23 542,119.37 1.66 6,862.68 2_MWD+IFR2+MS+Sag(3) 8,867.29 91.85 185.62 3,853.66 3,811.46 -6,451.78 -2,583.33 6,025,440.25 542,112.64 2.63 6,924.95 2_MWD+IFR2+MS+Sag(3) 8,929.78 91.30 184.36 3,851.94 3,809.74 -6,514.00 -2,588.77 6,025,378.00 542,107.59 2.20 6,986.06 2_MWD+IFR2+MS+Sag(3) 8,993.38 91.48 185.15 3,850.40 3,808.20 -6,577.37 -2,594.04 6,025,314.61 542,102.70 1.27 7,048.19 2_MWD+IFR2+MS+Sag(3) 9,056.63 91.30 184.80 3,848.86 3,806.66 -6,640.36 -2,599.52 6,025,251.59 542,097.59 0.62 7,110.04 2_MWD+IFR2+MS+Sag(3) 9,119.64 90.56 184.65 3,847.84 3,805.64 -6,703.15 -2,604.71 6,025,188.78 542,092.78 1.20 7,171.61 2_MWD+IFR2+MS+Sag(3) 9,182.12 90.62 185.07 3,847.20 3,805.00 -6,765.40 -2,610.00 6,025,126.51 542,087.86 0.68 7,232.69 2_MWD+IFR2+MS+Sag(3) 9,245.27 92.53 183.82 3,845.46 3,803.26 -6,828.33 -2,614.90 6,025,063.55 542,083.35 3.61 7,294.31 2_MWD+IFR2+MS+Sag(3) 9,308.34 93.09 185.42 3,842.37 3,800.17 -6,891.12 -2,619.97 6,025,000.74 542,078.65 2.68 7,355.84 2_MWD+IFR2+MS+Sag(3) 9,370.94 93.21 185.15 3,838.93 3,796.73 -6,953.36 -2,625.73 6,024,938.47 542,073.27 0.47 7,417.05 2_MWD+IFR2+MS+Sag(3) 9,433.80 91.98 184.85 3,836.08 3,793.88 -7,015.91 -2,631.20 6,024,875.89 542,068.17 2.01 7,478.48 2_MWD+IFR2+MS+Sag(3) 9,496.31 92.53 184.97 3,833.62 3,791.42 -7,078.14 -2,636.55 6,024,813.64 542,063.20 0.90 7,539.56 2_MWD+IFR2+MS+Sag(3) 9,559.55 92.78 184.90 3,830.70 3,788.50 -7,141.08 -2,641.98 6,024,750.67 542,058.15 0.41 7,601.34 2_MWD+IFR2+MS+Sag(3) 9,622.38 93.03 185.79 3,827.51 3,785.31 -7,203.56 -2,647.83 6,024,688.17 542,052.68 1.47 7,662.80 2_MWD+IFR2+MS+Sag(3) 9,685.29 93.02 186.25 3,824.19 3,781.99 -7,266.03 -2,654.41 6,024,625.66 542,046.46 0.73 7,724.47 2_MWD+IFR2+MS+Sag(3) 9,747.81 92.22 186.33 3,821.33 3,779.13 -7,328.11 -2,661.26 6,024,563.55 542,040.00 1.29 7,785.84 2_MWD+IFR2+MS+Sag(3) 9,810.55 92.53 187.15 3,818.73 3,776.53 -7,390.36 -2,668.61 6,024,501.26 542,033.01 1.40 7,847.53 2_MWD+IFR2+MS+Sag(3) 9,873.19 93.09 189.26 3,815.66 3,773.46 -7,452.28 -2,677.54 6,024,439.29 542,024.46 3.48 7,909.36 2_MWD+IFR2+MS+Sag(3) 9,935.23 91.48 190.17 3,813.19 3,770.99 -7,513.38 -2,688.00 6,024,378.14 542,014.37 2.98 7,970.85 2_MWD+IFR2+MS+Sag(3) 9,998.12 91.23 189.92 3,811.70 3,769.50 -7,575.29 -2,698.97 6,024,316.17 542,003.77 0.56 8,033.26 2_MWD+IFR2+MS+Sag(3) 10,061.13 91.24 190.22 3,810.34 3,768.14 -7,637.32 -2,709.98 6,024,254.09 541,993.13 0.48 8,095.80 2_MWD+IFR2+MS+Sag(3) 10,123.66 91.67 190.55 3,808.76 3,766.56 -7,698.80 -2,721.25 6,024,192.54 541,982.23 0.87 8,157.90 2_MWD+IFR2+MS+Sag(3) 10,186.81 90.25 190.33 3,807.70 3,765.50 -7,760.90 -2,732.69 6,024,130.38 541,971.17 2.28 8,220.62 2_MWD+IFR2+MS+Sag(3) 10,249.41 91.05 191.16 3,806.99 3,764.79 -7,822.39 -2,744.36 6,024,068.82 541,959.87 1.84 8,282.85 2_MWD+IFR2+MS+Sag(3) 10,312.33 91.05 191.15 3,805.83 3,763.63 -7,884.12 -2,756.53 6,024,007.04 541,948.07 0.02 8,345.43 2_MWD+IFR2+MS+Sag(3) 10,375.22 92.04 192.00 3,804.14 3,761.94 -7,945.70 -2,769.15 6,023,945.38 541,935.83 2.07 8,408.02 2_MWD+IFR2+MS+Sag(3) 10,438.00 92.59 193.32 3,801.60 3,759.40 -8,006.90 -2,782.90 6,023,884.10 541,922.45 2.28 8,470.57 2_MWD+IFR2+MS+Sag(3) 10,501.47 91.48 193.56 3,799.35 3,757.15 -8,068.60 -2,797.64 6,023,822.33 541,908.08 1.79 8,533.88 2_MWD+IFR2+MS+Sag(3) 10,564.37 90.49 193.20 3,798.27 3,756.07 -8,129.78 -2,812.19 6,023,761.07 541,893.90 1.67 8,596.64 2_MWD+IFR2+MS+Sag(3) 10,626.83 91.11 192.29 3,797.40 3,755.20 -8,190.69 -2,825.97 6,023,700.08 541,880.49 1.76 8,658.92 2_MWD+IFR2+MS+Sag(3) 10,690.33 91.98 191.63 3,795.68 3,753,48 -8,252.79 -2,839.12 6,023,637.91 541,867.71 1.72 8,722.16 2_MWD+IFR2+MS+Sag(3) 10,753.00 92.84 192.00 3,793.05 3,750.85 -8,314.08 -2,851.94 6,023,576.55 541,855.25 1.49 8,784.52 2_MWD+IFR2+MS+Sag(3) 12/15/2017 5:35:05PM Page 6 COMPASS 5000.1 Build 81D • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU L-51 Project: Milne Point TVD Reference: MPU L-53 Actual @ 42.20usft Site: M Pt L Pad MD Reference: MPU L-53 Actual @ 42.20usft Well: MPU L-51 North Reference: True Wellbore: MPU L-51 Survey Calculation Method: Minimum Curvature Design: MPU L-51 Database: Sperry EDM-NORTH US+CANADA Survey Map Map `,',a,%'ertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section t ''"_.- (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 10,816.00 91.79 192.19 3,790.50 3,748.30 -8,375.63 -2,865.13 6,023,514.93 541,842.44 1.69 8,847.24 2_MWD+IFR2+MS+Sag(3) 10,879.06 90.06 191.86 3,789.49 3,747.29 -8,437.29 -2,878.27 6,023,453.19 541,829.67 2.79 8,910.05 2_MWD+IFR2+MS+Sag(3) 10,941.50 93.71 193.38 3,787.43 3,745.23 -8,498.18 -2,891.90 6,023,392.23 541,816.41 6.33 8,972.26 2_MWD+IFR2+MS+Sag(3) 11,004.39 92.16 194.41 3,784.21 3,742.01 -8,559.15 -2,906.98 6,023,331.18 541,801.69 2.96 9,034.98 2_MWD+IFR2+MS+Sag(3) 11,067.42 92.16 193.98 3,781.84 3,739.64 -8,620.21 -2,922.43 6,023,270.03 541,786.62 0.68 9,097.89 2_MWD+IFR2+MS+Sag(3) 11,130.29 92.47 192.84 3,779.30 3,737.10 -8,681.32 -2,937.00 6,023,208.85 541,772.42 1.88 9,160.58 2_MWD+IFR2+MS+Sag(3) 11,193.33 92.28 190.09 3,776.68 3,734.48 -8,743.04 -2,949.52 6,023,147.05 541,760.27 4.37 9,223.27 2_MWD+IFR2+MS+Sag(3) 11,256.20 91.91 189.52 3,774.39 3,732.19 -8,804.95 -2,960.21 6,023,085.09 541,749.95 1.08 9,285.61 2_MWD+IFR2+MS+Sag(3) 11,318.89 92.22 190.25 3,772.13 3,729.93 -8,866.67 -2,970.97 6,023,023.31 541,739.56 1.26 9,347.78 2_MWD+IFR2+MS+Sag(3) 11,381.92 91.79 189.66 3,769.92 3,727.72 -8,928.71 -2,981.86 6,022,961.21 541,729.05 1.16 9,410.29 2_MWD+IFR2+MS+Sag(3) 11,444.74 92.41 191.00 3,767.62 3,725.42 -8,990.47 -2,993.12 6,022,899.39 541,718.16 2.35 9,472.65 2_MWD+IFR2+MS+Sag(3) 11,507.49 92.59 192.92 3,764.88 3,722.68 -9,051.79 -3,006.11 6,022,837.99 541,705.54 3.07 9,535.09 2_MWD+IFR2+MS+Sag(3) 11,570.66 92.96 193.53 3,761.82 3,719.62 -9,113.22 -3,020.54 6,022,776.49 541,691.48 1.13 9,598.05 2_MWD+IFR2+MS+Sag(3) 11,633.21 92.84 191.30 3,758.66 3,716.46 -9,174.22 -3,033.97 6,022,715.41 541,678.42 3.57 9,660.32 2_MWD+IFR2+MS+Sag(3) 11,696.05 91.67 189.32 3,756.19 3,713.99 -9,236.00 -3,045.21 6,022,653.58 541,667.55 3.66 9,722.68 2_MWD+IFR2+MS+Sag(3) 11,759.22 89.75 186.41 3,755.40 3,713.20 -9,298.56 -3,053.85 6,022,590.97 541,659.29 5.52 9,785.04 2_MWD+IFR2+MS+Sag(3) 11,822.36 89.94 185.22 3,755.57 3,713.37 -9,361.37 -3,060.25 6,022,528.13 541,653.27 1.91 9,846.99 2_MWD+IFR2+MS+Sag(3) 11,884.87 91.17 185.57 3,754.97 3,712.77 -9,423.60 -3,066.12 6,022,465.87 541,647.77 2.05 9,908.22 2_MWD+IFR2+MS+Sag(3) 11,947.98 91.73 186.04 3,753.37 3,711.17 -9,486.37 -3,072.50 6,022,403.07 541,641.76 1.16 9,970.11 2_MWD+IFR2+MS+Sag(3) 12,010.87 91.91 185.92 3,751.37 3,709.17 -9,548.88 -3,079.05 6,022,340.53 541,635.59 0.34 10,031.81 2_MWD+IFR2+MS+Sag(3) 12,074.50 91.79 186.71 3,749.32 3,707.12 -9,612.09 -3,086.05 6,022,277.28 541,628.98 1.26 10,094.31 2_MWD+IFR2+MS+Sag(3) 12,137.29 90.19 186.38 3,748.23 3,706.03 -9,674.46 -3,093.20 6,022,214.88 541,622.20 2.60 10,156.05 2_MWD+IFR2+MS+Sag(3) 12,200.40 90.74 187.96 3,747.72 3,705.52 -9,737.07 -3,101.08 6,022,152.22 541,614.70 2.65 10,218.24 2_MWD+IFR2+MS+Sag(3) 12,263.30 91.73 190.38 3,746.37 3,704.17 -9,799.15 -3,111.10 6,022,090.09 541,605.05 4.16 10,280.53 2_MWD+IFR2+MS+Sag(3) 12,326.05 91.98 190.59 3,744.34 3,702.14 -9,860.82 -3,122.51 6,022,028.36 541,594.01 0.52 10,342.85 2_MWD+IFR2+MS+Sag(3) 12,382.55 91.36 192.03 3,742.69 3,700.49 -9,916.20 -3,133.59 6,021,972.93 541,583.27 2.77 10,399.04 2_MWD+IFR2+MS+Sag(3) 12,452.20 89.32 191.80 3,742.28 3,700.08 -9,984.34 -3,147.97 6,021,904.70 541,569.30 2.95 10,468.42 2_MWD+IFR2+M5+Sag(3) 12,514.93 90.80 192.78 3,742.21 3,700.01 -10,045.63 -3,161.32 6,021,843.34 541,556.32 2.83 10,530.93 2_MWD+IFR2+MS+Sag(3) 12,577.88 90.62 194.12 3,741.43 3,699.23 -10,106.85 -3,175.96 6,021,782.04 541,542.05 2.15 10,593.76 2_MWD+IFR2+MS+Sag(3) 12,640.69 91.30 195.11 3,740.38 3,698.18 -10,167.62 -3,191.81 6,021,721.18 541,526.57 1.91 10,656.51 2_MWD+IFR2+MS+Sag(3) 12,703.61 92.10 194.67 3,738.51 3,696.31 -10,228.40 -3,207.97 6,021,660.32 541,510.77 1.45 10,719.36 2_MWD+IFR2+MS+Sag(3) 12,766.71 91.42 193.50 3,736.57 3,694.37 -10,289.57 -3,223.32 6,021,599.06 541,495.79 2.14 10,782.34 2_MWD+IFR2+MS+Sag(3) 12,829.55 91.23 193.31 3,735.12 3,692.92 -10,350.68 -3,237.88 6,021,537.87 541,481.60 0.43 10,845.04 2_MWD+IFR2+MS+Sag(3) 12,892.44 91.61 193.68 3,733.56 3,691.36 -10,411.82 -3,252.55 6,021,476.65 541,467.30 0.84 10,907.80 2_MWD+IFR2+MS+Sag(3) 12,955.14 93.89 194.52 3,730.55 3,688.35 -10,472.55 -3,267.81 6,021,415.83 541,452.41 3.87 10,970.34 2_MWD+IFR2+MS+Sag(3) 13,018.19 92.84 193.37 3,726.85 3,684.65 -10,533.64 -3,282.97 6,021,354.66 541,437.61 2.47 11,033.19 2_MWD+IFR2+MS+Sag(3) 13,080.87 92.10 192.82 3,724.15 3,681.95 -10,594.63 -3,297.16 6,021,293.59 541,423.79 1.47 11,095.67 2_MWD+IFR2+MS+Sag(3) 13,143.93 90.74 190.87 3,722.59 3,680.39 -10,656.32 -3,310.10 6,021,231.82 541,411.22 3.77 11,158.45 2_MWD+IFR2+MS+Sag(3) 13,206.53 90.56 190.48 3,721.88 3,679.68 -10,717.84 -3,321.70 6,021,170.25 541,400.00 0.69 11,220.67 2_MWD+IFR2+MS+Sag(3) 13,269.34 90.31 191.51 3,721.40 3,679.20 -10,779.49 -3,333.68 6,021,108.53 541,388.39 1.69 11,283.14 2_MWD+IFR2+MS+Sag(3) 12/15/2017 5:35:05PM Page 7 COMPASS 5000.1 Build 81D • 0 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU L-51 Project: Milne Point TVD Reference: MPU L-53 Actual @ 42.20usft Site: M Pt L Pad MD Reference: MPU L-53 Actual @ 42.20usft Well: MPU L-51 North Reference: True Wellbore: MPU L-51 Survey Calculation Method: Minimum Curvature Design: MPU L-51 Database: Sperry EDM-NORTH US+CANADA Survey 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 13,332.36 92.16 191.35 3,720.04 3,677.84 -10,841.24 -3,346.16 6,021,046.71 541,376.28 2.95 11,345.84 2_MWD+IFR2+MS+Sag(3) 13,395.37 92.35 190.67 3,717.56 3,675.36 -10,903.05 -3,358.18 6,020,984.84 541,364.63 1.12 11,408.46 2_MWD+IFR2+MS+Sag(3) 13,458.33 93.96 189.01 3,714.10 3,671.90 -10,964.98 -3,368.93 6,020,922.85 541,354.26 3.67 11,470.84 2_MWD+IFR2+MS+Sag(3) 13,521.06 93.33 188.44 3,710.11 3,667.91 -11,026.86 -3,378.42 6,020,860.92 541,345.13 1.35 11,532.79 2_MWD+IFR2+MS+Sag(3) 13,583.84 90.31 186.99 3,708.12 3,665.92 -11,089.03 -3,386.85 6,020,798.71 541,337.09 5.34 11,594.71 2_MWD+IFR2+MS+Sag(3) 13,647.23 87.41 186.95 3,709.38 3,667.18 -11,151.93 -3,394.54 6,020,735.77 541,329.77 4.58 11,657.12 2_MWD+IFR2+MS+Sag(3) 13,678.81 85.67 186.58 3,711.28 3,669.08 -11,183.23 -3,398.25 6,020,704.44 541,326.25 5.63 11,688.14 2_MWD+IFR2+MS+Sag(3) 13,709.95 84.13 186.24 3,714.05 3,671.85 -11,214.06 -3,401.71 6,020,673.61 541,322.97 5.06 11,718.63 2_MWD+IFR2+MS+Sag(3) 13,741.42 83.07 186.38 3,717.56 3,675.36 -11,245.14 -3,405.15 6,020,642.50 541,319.72 3.40 11,749.36 2_MWD+IFR2+MS+Sag(3) 13,773.01 83.44 186.96 3,721.27 3,679.07 -11,276.30 -3,408.79 6,020,611.33 541,316.27 2.17 11,780.23 2_MWD+IFR2+MS+Sag(3) 13,803.65 83.44 187.85 3,724.77 3,682.57 -11,306.48 -3,412.72 6,020,581.12 541,312.53 2.89 11,810.24 2_MWD+IFR2+MS+Sag(3) 13,874.00 83.44 187.85 3,732.81 3,690.61 -11,375.72 -3,422.26 6,020,511.84 541,303.40 0.00 11,879.24 PROJECTED to TD mitcheil.laird@halliburton.com ` Checked By: 2017.12.1514:36:20-09.00' Approved By: Michael Calkins. Date: 12/15/2017 Dor am,z1n.vsecrnr 12115/2017 5:35:05PM Page 8 COMPASS 5000.1 Build 81D Hilcorp Energy Company 0 CASING&CEMENTING REPORT Lease&Well No. MP L-51 Date Run 4-Dec-17 County State Alaska Supv. J.Lott/S.Barber CASING RECORD Surface t TD 6,610.00 Shoe Depth: 6,600.00 PBTD: 6,473.37 No.Jts.Delivered 160 No.Jts.Run 160 No.Jts.Returned Ftg.Delivered 6,606.00 Ftg.Run 6,600.00 Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. 27.00 Ftg.Balance RKB 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/C HES 2.10 6,600.00 6,597.90 2 Casing 9 5/8 40.0 L-80 DWC/C 81.69 6,597.90 6,516.21 1 Float Collar 103/4 40.0 L-80 DWC/C HES 1.97 6,516.21 6,514.24 1 Casing 9 5/8 40.0 L-80 DWC/C 39.28 6,514.24 6,474.96 1 Baffle Adapter 103/4 40.0 L-80 DWC/C HES 1.59 6,474.96 6,473.37 95 Casing 9 5/8 40.0 L-80 _ DWC/C 3,883.79 6,473.37 2,589.58 1 Stage tool 103/4 40.0 L-80 DWC/C - HES 3.10 2,589.58 2,586.48 Casing 9 5/8 40.0 L-80 DWC/C 2,586.48 27.00 Csg Wt.On Hook: 135,000 Type Float Collar: Conventional No.Hrs to Run: 20 Csg Wt.On Slips: 100,000 Type of Shoe: Conventional Casing Crew: Weatherford Rotate Csg X Yes No Recip Csg X Yes_ No 30 Ft.Min. 9.3 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: CEMENTING REPORT Shoe @ 6600 FC @ 6,516.21 Top of Liner #N/A Preflush(Spacer) Type: Tuneed Spacer Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry Type: ExtendaCem Sacks: 480 Yield: 2.47 Density(ppg) 11.7 Volume pumped(BBLs) 211.2 Mixing/Pumping Rate(bpm): 5 Tail Slurry w Type: SwiftCem Sacks: 390 Yield: 1.15 F Density(ppg) 15.8 Volume pumped(BBLs) 79.9 Mixing/Pumping Rate(bpm): 3.6 N Post Flush(Spacer) &) Type:Fresh Water Density(ppg) 8.3 Rate(bpm): 7.5 Volume: 20 LL Displacement: Type: Spud Mud Density(ppg) 9.3 Rate(bpm): 6 Volume(actual/calculated): 470.7/471.2 FCP(psi): 735 Pump used for disp: Rig MP#2 Bump Plug? X Yes No Bump press 1250 Casing Rotated? X Yes _No Reciprocated? X Yes No %Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 37 Cement In Place At: 7:10 Date: 12/5/2017 Estimated TOC: 2,586 Method Used To Determine TOC: samples at surface Stage Collar @ 2589.58 Type HES ES cementer Closure OK OK Preflush(Spacer) Type: Tuned Spacer III Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry ,/l/ Type: Permafrost"L" Sacks: 394 Yield: 4.33 Density(ppg) 10.7 Volume pumped(BBLs) 303.5 Mixing/Pumping Rate(bpm): 5 Tail Slurry Lu Type: SwiftCem Sacks: 270 v Yield: 1.16 y Density(ppg) 15.8 Volume pumped(BBLs) 55.8 Mixing/Pumping Rate(bpm): 4 z Post Flush(Spacer) u Type: Density(ppg) Rate(bpm): Volume: rrnn Displacement: Type: Spud Mud Density(ppg) 9.3 Rate(bpm): 6 Volume(actual/calculated): 196.1/196 FCP(psi): 545 Pump used for disp: Rig MP#2 Bump Plug? X Yes No Bump press 1450 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 252 Cement In Place At: 18:27 Date: 12/5/2017 Estimated TOC: 0 Method Used To Determine TOC: Samples at surface Post Job Calculations: Calculated Cmt Vol©0%excess: 377.4 Total Volume cmt Pumped: 650.4 1' Cmt returned to surface: 289 Calculated cement left in wellbore: 361.4 OH volume Calculated: 367.8 OH volume actual: 351.8 Actual%Washout: www.wellez.net WellEz Information Management LLC ver_102716bf • • 217151 Debra Oudean Hilcorp Alaska, LLC 29010 AK_GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 : Tele: 907 777-8337 Hilmrr Fax: 907 777-8510 E-mail: doudean@hilcorp.com JAN 3 0 2010 DATE: 01/12/2018 OCC DATA LOGGED To: Alaska Oil & Gas Conservation Commission K %i2oig Makana Bender M..K.BENDER Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-51 Prints: ROP DGR ABG EWR ADR Horizontal Presentation MD DGR ABG EWR ADR Revert Section TVD CD: Final Well Data Log Viewers 12/20/2017 12:11 PM File folder CGM 12/20/2017 12:11 PM File folder . Definitive Survey 12/20/2017 12:11 PM File folder EMF 12/20/2017 12:11 PM File folder LAS 12/20/201712:11 PM File folder PDF 12/20/2017 12:11 PM File folder TIFF 12/20/2017 12:11 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 907 777.8510 Received By: Date: • Link, Liz M (DOA) From: Joe Engel <jengel@hilcorp.com> Sent: Monday, November 13, 2017 3:17 PM To: Link, Liz M (DOA) Cc: Cody Dinger Subject: RE: Location data for MPU L-51 Hello Liz— Thank you for the email. Upon review, the Governmental Section for the Surface Hole Location (Box 4a) provided on the 10-401 for MPU L-51 was incorrect (the SHL for L-54 was accidently provided in its place). The correct Governmental Section for MPU L-51 should be: 3719' FSL, 5219' FEL,Sec 8,T13N, R10E, UM, AK This should also be noted correctly in the submitted drilling program on page 2,and the MPU L-Pad As Built on page 53. I apologize for the error and any confusion it may have caused. Please let me know if this calculates to the correct XY values,and if you have any further questions or if any other documentation needs to be submitted. Thank you for your time. Joe From: Link, Liz M (DOA) [mailto:liz.link@alaska.govj Sent: Monday, November 13, 2017 9:25 AM To:Joe Engel <jengel@hilcorp.com> Subject: Location data for MPU L-51 Hello Joe, I am writing regarding location data provided in a permit application (10-401)for MPU L-51. The calculated XY values obtained from the Governmental Section/PLSS data provided in box 4a for the Surface Location are out of acceptable limits from the provided XY values in box 4b for the Surface Location. Calculated values: X-544750 Y-6031963 Provided Values: X-544656 Y-6031906 Would you be able to look into this and get back to me? Thanks in advance. • 8,or 7,4, �w\�\ 1//7 , THE STATE Alaska Oil and Gas ti��►+i'Q�--�� of® aS J(A Conservation Commission Sit = 333 West Seventh Avenue trimz=-_ GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF nu— jv 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-51 Hilcorp Alaska, LLC Permit to Drill Number: 217-151. a Surface Location: 374' FSL, 51- &' FEL, SEC. 8, T13N, R10E, UM, AK Bottomhole Location: 2014' FNL, 1876' FWL, SEC. 19, T13N, R10E, 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, Hollis S. French Chair DATED this day of November, 2017. STATE OF ALASKA ALF OIL AND GAS CONSERVATION COMMI.N PERMIT TO DRILL 20 AAC 25.005 la.Type of Work: 1 b.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp ❑ 1 c.Specify if well is proposed for: Drill E Lateral ❑ Stratigraphic Test ❑ Development-Oil Q Service- Winj ❑ Single Zone E Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry❑ Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Q Single Well ❑ 11.Well Name and Number: qcs Hilcorp Alaska,LLC Bond No. 022035244 f(A. Ml3L-51 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,St 1400,Anchorage,AK MD: 13,500' TVD: 3,756' Milne Point Field 4a. Location of Well(Governmental Section): LA_ 7.Property Designation: Schrader Bluff Oil Pool Surface: 3774:FSL,512€ FEL,Sec 8,T13N,R10E,UM,AK (SHL)ADL025509/(TPH/BHL)ADL025515 h(g 5,414,) Top of Productive Horizon: 8.DNR Approval Number: 13.Approximate Spud Date: 334'FNL,2012'FEL,Sec 18,T13N,R10E,UM,AK LONS 83-085 11/24/2017 Total Depth: 9.Acres in Property: 14. Distance to Nearest Property: 2014'FNL, 1879'FWL,Sec 19,T13N,R10E,UM,AK 5077 8466'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 42.5' 15. Distance to Nearest Well Open Surface: x-544656 y- 6031906 Zone-4 GL/BF Elevation above MSL(ft): 16' to Same Pool: 260'to L-37A 16.Deviated wells: Kickoff depth: 300 feet 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 91.5 degrees Downhole: . 9 1.7 V S t'''':"' Surface: 1392 '''' 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 114' Surface Surface 114' 114' 270 cf Stg#1 Lead 1182 cf/Tail 445 cf = 12-1/4" 9-5/8" 40# L-80 DWC 6,410' Surface Surface 6,410' 3,932' Stg#2 Lead 1861 cf/Tail 314 cf 7-5/8" 29.7# L-80 STL SMLS 6,210' Surface Surface 6,210 3,914' Tieback Assembly 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 7,290' 6,210' 3,914' 13,500' 3,756' 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 MCT ). 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 ❑✓ 20. Attachments: Property Plat Q BOP Sketch 7 Drilling Program 7 Time v.Depth Plot — Shallow Hazard Analysis— Diverter Sketch 7 Seabed Report Drilling Fluid Program 7 20 AAC 25.050 requirements 7 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: jengel@hiICOrp.COm Authorized Title:Drilling Manager Contact Phone: 777-8395 �/)/j 1°!31 f 2,a,7 Authorized Signature: 72,4452 i �/ Date: ( Commission Use Only Permit to Drill API Number: Permit Approval /J See cover letter for other Number: rit�-— 'S1 50- 0Zi—,2 U7-—do — 60 Date: 11\qI ( I requirements. Conditions of approval: If box is checked,well may of be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: [71 Other: 3000 ,. sC3 ( • ,� Samples req'd: Yes ❑ No Mud log req'd:Yes No[� !!! H2S measures: Yes1.No❑ Directional svy req'd:Yes No❑ Spacing exception req'd: Yes ❑ No 0 Inclination-only svy req'd:Yes❑ No g Post initial injection MIT req'd:Yes❑ No❑ APPROVED BY l I '1-I Approved by: COMMISSIONER THE COMMISSION Datesubmft Form and \ ror iu u <evisea 5ORIr4Iti Tlda penult lb valid fur 24 munUu num gm dale of approval per 20 C 20.005(g) Attachments in Duplicate ....cSt Ikl\P'a4 Ii13 f�--- _ A I .'It/6P ii-P17 Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Hilcorp RECEIVED Anchorage,AK 99524-4027 Tel 907 777 8395 Energy Company Email: jengel@hilcorp.com 10.31.2017 OCT 3 1 2017 AOGCC Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU L-51 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 51. Drilling operations are intended to commence approximately Nov 23, 2017, pending rig schedule. MPU L-51 is a grassroots ESP producer planned to be drilled in the Schrader Bluff NB sand. L-51 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 c?._. Rule 3 requiring an ESP packer if the BHP gradient is greater than 8.55 ppg. The estimated reservoir pressure is 8.65 ppg EMW (1750 psi) at 3890' TVDss, 20 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-51, 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, ,------.. iliP C Joe Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 • • Hilcorp Alaska, LLC Milne Point Unit (MPU) L-51 Drilling Program Version 1 10/31/2017 • Milne Point H11C0pany L-53 SB N Producer it o rp Drilling Procedure EnergyContents 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 16 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 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-51 Producer Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU L-51 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 13,500' MD/3,756' TVD PBTD,MD/TVD 13,490' MD/3,756' TVD Surface Location(Governmental) 3719'FSL, 5219' FEL, Sec 8, T13N,R10E,UM,AK Surface Location(NAD 27) X= 544,656.92,Y=6,031,906.80 Surface Location(NAD 83) X= 1,684,688.03 ,Y=6,031,659.50 Top of Productive Horizon 334'FNL, 2012'FEL, Sec 18, T13N,R10E,UM,AK (Governmental) TPH Location(NAD 27) X=542,624.00,Y=6,027,842 TPH Location(NAD 83) X= 1,682,655.12,Y=6,027,594.52 BHL(Governmental) 2014'FNL, 1879'FWL, Sec 19,T13N,R10E,UM,AK BHL(NAD 27) X=541,360.65,Y=6,020,875.3 BHL(NAD 83) X= 1,681,391.84,Y=6,020,627.68 AFE Number 1713436 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) 1392 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+ 15.7 ft=42.2 ft GL Elevation above MSL: 15.7 ft BOP Equipment 13-5/8"x 5M Annular,(3)ea 13-5/8"x 5M Rams Page 2 Rev 0 October 2017 I i Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp Energy Company Changes to Approved Permit to Drill Date: 10124/17 Subject: Changes to Approved Permit to Drill for MPU L-51 File#: MPU L-51 Drilling and Completion Program Any modifications to MPU L-51 Drilling&Completion Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by the AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Rev 0 October 2017 0 Milne Point Unit II 1-51 Producer Drilling Procedure Hilcorp Energy Company 3.0 Tubular Program: Hole OD Drift C @ Conn Burst t ension .ction ip ' in OD in e si . ",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 YAM STL 6,890 4,790 683 SMLS 8-1/2" 4-1/2" 3.920 3.795 4.714 13.5 L-80 Hydril 9020 8540 279 Screens 625 4.0 Drill Pipe Information: OD ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension bn) (in) ( (Max) (k-lbs) 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 0 October 2017 • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered, and will navigate to another data entry. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 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.com,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 jengel@hilcorp.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 pchan@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 0 October 2017 i 7157PointPdUnit Drilling Procedure Hilcorp Energy Company 6.0 Planned Wellbore Schematic Milne Point Unit Well:MPU L-51 PROPOSED SCHEMATIC LastCompleted:TBD Ila,„r„tb.4u.I,I1. PTD:TBD Or .KB Elev.:26.5/GL Elev.:15.7 TREE&WELLHEAD • il Tree Seaboard 2-9/16”SM sp WellheadSeaboard 16 3/4"3M x 11"5M Multi-bowl w/11"x 2 7/8"EUE Top and 16" ;; Bottom with 2.5"CIW"H"BPV profile.2ea 3/8"NPT control lines. OPEN HOLE/CEMENT DETAIL ,,,is , 16" Conductor r; 12-1/4" Planned Pump Vol:676 bbl 2-7/8" SO 11 8-1/2" Cemgntless Screen Liner in 8-1/2"hole �t i* CASING DETAIL { kiSize Type Wt/Grade/Conn ID Top Btm BPF P III 3 ' 16' ' Conductor 78.6/A-53/Weld N/A Surface 114' N/A 9-5/8" Surface 40/L-80/DWC/C 8.835 Surface - 6,410' 0.0758 „� 7-5/8" Tieback 29.7/1-80/Vats STL SMLS 6.875 Surface 6,210' 0.0459 ass ES M: 4-1/2" Liner&Screens 13.5/1-80/Hydril 625 3.920 6,210' 13,500' .0149 ^arena @ 4; -25T1i; „ TUBING DETAIL I 2-7/8" I Tubing I 6.5/L-80/EUE-8rd I 2.441 I Surface I 5,200 I 0.0058 ¢'A 4 WELL INCLINATION DETAIL KOP @ 300' ,r+° Max Hole Angle=91.58 deg.@ 7,908'MD Vi N JEWELRY DETAIL Lix , - ' No. I Top MD 1 Item I ID ;h Upper Completion T '� 1 Tubing Hanger 2.441" �1�"'='t' !r 2 ±140' ELM BK-2 Latch,1"Packing Bore 2.347" 75/8" 3 ±5,000' GLM BK-2 Latch,T'Packing Bore 2.347" 4 ±5,100' IN Nipple IW 5 ±5,200' ESP Assembly Lower Completion IC It .: 10 ±6,210' BOT SLZXP Liner Top Packer w/BD Slips 7'x 9-5/8" 6.200'" ' {t mu 11 ±6,215' 7-5/8"Tieback Assy. 6.151" (i 12 :6,220' 7"H563 x 4.5"HTTC 1-8030 3.900" i5^ 14 ±13,420' 4-1/2"Drillable Packoff Sub 2.400" '�+ 71 15 ±13,490' WIV Valve LTC BxB(1.5"Ball on Seat/Closed) - 9-5/8'j L 4-1/2"SOLID LINER DETAIL 4-1/2"Screens LINER DETAIL 13 --__. Jts Top(MD) Btm(MD) its Top(MD) Btm(MD) - MD TBD See Sawn( Slid Liner Oda! GENERAL WELL INFO , API:TBD 4-1/2" 14 Completion Date:TBD Stns@ -13504' 15 TD=13,507(MD)/TD=3,755(TVD) PBTD=13,497(MD)/PBTD=3,755(TVD) Page 6 Rev 0 October 2017 • Milne L-51 ProducerPointUnit Drilling Procedure Hilcorp Energy Company 7.0 Drilling / Completion Summary MPU L-51 is a grassroots ESP producer planned to be drilled in the Schrader Bluff NB sand. L-51 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. Drilling operations are expected to commence approximately Nov 24th, 2017. The Innovation Rig will be used to drill and complete the wellbore. Surface casing will be run to 6,400' MD/3,931' 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 casing. 4. N/D diverter,N/U &test 13-5/8" x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 4-1/2"production 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 0 October 2017 • s 111 Milne Point Unit L-51 Producer 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 L-51. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min(annular to 50%rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore,AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: Hilcorp Alaska 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 8.65 ppg EMW(1750 psi) at 3890' TVDss, 20 psi above 8.55 ppg EMW(1730psi). 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. e, Cs e r r.).„,- id w ,vim- cJ't r,2K tg GCS y.„ 1.477 " QUO - F i Ptv�, - �t ''�` 4 Page 8 Rev 0 October 2017 • Milne Point Unit 1-51 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 0 October 2017 Mime PointProducer Unit L- Drilling Procedure Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 L-51 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 0 October 2017 • Milne Point Unit L-51 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 0 October 2017 • • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 10.5 Rig & Diverter Orientation: \ \ 1 � I \ \ I / *Ly5pi 4:E.19 \ AV' j — 1 I i ■334 I l I/ 128 ■29 / I I •24 125 l ■20 ■21 ■16 ■17 ■41 ■43 �^, N +L-53 +L-56 / � / ■45 +L-57 1 +L-54 33 13 ■39■ 75'Radius Clear of Ignition Sources 34■ 3 ■ ■ 10 I 15 ■ ■47 I 2 X •: 7 —Diverter Line I 12 ■ 40■ ■••••M••• •■ I 6 35 4 36 5 37 11 50 i I _ 1 l /- ` I ` MPU L-Pad \ I *Drawing Not To Scale 1 1 Page 12 Rev 0 October 2017 • • Milne Point Unit L-51 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 400-600 gpm. Ensure shaker screens are set up to handle this flowrate. • Ensure to not out drill hole cleaning capacity,perform clean up cycles or reduce ROP if packoffs seen. • 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. • 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 0 October 2017 • • Milne Point Unit L-51 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 Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8-9.2 75-175 20-40 25-45 <10 8.5-9.0 <_70 F Page 14 Rev 0 October 2017 • MilPot Unit L-51 Producerin Drillingne Procedure Hilcorp EnergyCompany P Y III 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 16" 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 (400-600 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft/minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.8 TOOH and LD BHA 11.9 No open hole logging program planned. Page 15 Rev 0 October 2017 4110 Milne L-51 ProducerPointUnit Drilling Procedure Hilcorp Energy Company 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. • 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. OS% (OW • (1) Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. Page 16 Rev 0 October 2017 • 0 II Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. 12.6 Float equipment and Stage tool equipment drawings: ..A f i Overall Length A Type HES Cementer 8 We.No. e.ID After Deillout Iph ._ SQ No. C IIMax.Tool OD i o o i D Hicorp ES-Il Running Order E I Opening Seat ID A I Closing Sleeve No.Shear Pins E ' Closing Seat ID ID Opening Sleeve C 1 i No.Shear Pins Plug Set ' 1 ES-II Cementer ES Cementer Part No. te —B Depth ` ii....)..----1 SO No. MN Closing Plug WGT MEW I Baffle Adapter(if used) OD I i; 1 Stent Off Plug ID A Opening Plug . Depth OD Baffle Adapter OD a LL,I Bypass or Shut-off Baffle ' eefi ;pi ID By-Pass Plug Depth V Shut-off Plug kill Float Collar �T1�'t Depth By Pass Baffle WIIII .1111r MillOD Float Collar nimin Float Shoe Depth V Bypass Plug (if used) T Hole TDFloat Shoe T "Reference Casing ••! OD Sales Manuel : Section 5 Page 17 Rev 0 October 2017 • Milne Point Unit L-51 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 from shoe (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 ES-II age_tool so that it is positioned at least 100' TVD below the permafrost (—2,500' MD). %,(' • Install centralizers over couplings on 5 joints below and above stage tool. V /0 • 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 0 October 2017 �i • Milne Point 1-51 ProducerUnit Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: size(O.D.): Weight(Wall): Grade: DWC/C Casing 9-5/8 in 40.00 lb/ft(0.395 in) L-80 standard Material L-80 Grade 80.000 Minimum Yield Strength (psi) 11111111111111111111111WU 8A 95.000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy.Suite 150 Pipe Dimensions Houston,TX 77041 Phone:713-479-3200 9.625 Nominal Pipe Body O.D. (in) Fax:713-470-3234 8.835 Nominal Pipe Body 1.D.(in) E-magi:VAMUSAsalesu[ vam-usa_com 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight(Ibsift) 38.97 Plain End Weight(Ibs,rft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection Q.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter (in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) • 100.0 Joint Efficiency (%) Connection Performance Properties 916,000 Joint Strength (lbs) 16.360 Reference String Length (ft) 1.4 Design Factor 947.000 API Joint Strength (lbs) 916,000 Structural Compression Rating (lbs) 3,090 API Collapse Pressure Rating (psi) 5,750 API Internal Pressure Resistance (psi) 19.0 Maximum Uniaxial Bend Rating [degrees,/100 ft] • • 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 0 October 2017 • Milne Point Unit L-51 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 0 October 2017 • Milne Point Unit L-51 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: $ �a�� 51-415` Section: Calculation: Vol (BBLS) Vol (ft3) 12-1/4" OH x 9-5/8" Casing (5,400'- 2500') x .0558 bpf x 1.3 = 210 bbls 1182 ft3 annulus: Total LEAD: 210 bbls 1182 ft3 12-1/4" OH x 9-5/8" Casing (6400'- 5400') 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 14Mime PointProducer Unit 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 21.13 gal/sk 5.04 gal/sk Water 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: o 6310' x .0758 bpf=478.3 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 0 October 2017 :% S Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Com 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 0 October 2017 ! ! Milne Point Unit L-51 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: P 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 (2000'- 110') x .0558 bpf x 3 = 316.4 bbls 1778 ft3 annulus: Total LEAD: 331.2 bbls 1861 ft3 12-1/4" OH x 9-5/8" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ft3 annulus: Total TAIL: 55.8 bbls 314 ft3 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 0 October 2017 • Milne Point Unit 1-51 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: r� 2500' x .0758 bpf= 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1000— 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 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.com and cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 25 Rev 0 October 2017 • Milne Point Unit 51 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 0 October 2017 • Milne Point Unit L-51 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 0 October 2017 J i Milne L-51 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 6400- 13500 8.9-9.5 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. 15.5 RAJ and test 9-5/8" 40# casing to 3000 psi/30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst, 5750 /2 =2875 psi= 53% of burst. 15.6 Drill out shoe track and 20' of new formation. 15.7 CBU and condition mud for FIT. rP(S- FI r- 15.8 15.8 Conduct FIT to 12 ppg EMW. Chart Test. 6 14- Z4 " - —_ 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. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations pulsed up real time. Page 28 Rev 0 October 2017 V • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company • 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 0 October 2017 • • Milne Point Unit L-51 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 (500-650 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std(slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least 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 0 October 2017 • i Milne Point Unit L-51 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: • P/U&M/U the 5" safety joint(with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2"handling joint above TIW). This joint shall be fully M/U and / available prior to running the first joint of 4-1/2" screen. ✓ • Slack off and position the 5"DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. • Proceed with well kill operations. 16.2. In the event of an influx of formation fluids while running the 2-3/8" inner string inside the 4- 1/2"production screens: • P/U&M/U the 5" safety joint(with 4-1/2"x 2-3/8"triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8"handling joint above TIW). M/U 2-3/8" and then 4-1/2"to triple connect. • This joint shall be fully M/U with crossovers prior to running the first joint of wash pipe. • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5"DP. Close TIW valve. Proceed with well kill operations. 16.3. R/U 4-1/2" screen running equipment. • Ensure 4-1/2" 13.5 Hydril 625 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 • Screens will be run with solid pipe in a 3:1 ratio: 3 screen joints, followed by 1 solid joint, 3 screen joints, 1 solid joint, etc... • 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 4-1/2" 13.5 # Hydril 625 Torque OD Minimum _ Maximum Yield Torque 4.5" 8,000 ft-lbs 12,800 ft-lbs 15,000 ft-lbs Page 31 Rev 0 October 2017 0 Milne Point Unit 1-51 Producer Drilling Procedure Hilcorp Energy Company Wedge 625® ptm.-10131/2017 Outside Diameter 4.500 in. thin.Wall 87.5% Thickness (')Grade L80 Type 1 Wall Thickness 0.290 in. Connection OD REGULAR COUPLING PIPE BODY Option Body:Red 1st Band:Red Grade L80 Type r Drift API Standard 1st Band:Brown 2nd Band: ..-i--- 2nd Band:- Brown aid Band:- 3rd Band:- Type Casing 4th Band:- GEOMETRY Nominal 00 4.500 in. Nominal Weight 13.50 lbs'ft Drift 3.795 in.. Nominal ID 3.920 in. Wall Thickness 0.290 in. Plain End Weight 13.05 lbs It 00 Tolerance API PERFORMANCE Body Yield Strength 307 a10•30 lbs Internal Yield 9020 psi SPAYS 80000 psi Collapse 8540 psi GEOMETRY � Connection 00 4314 in. Connection ID 3.849 in. Make-up Loss 4.830 in. Threads per in 3.59 Connection OD Option REGULAR PERFORMANCE Tension Etiolency 91.0% Joint Yield Strength 279.370 x1300 Internal Pressure Capacity 9020.000 psi lbs Compression Efficiency 94_5% Compression Strength 290.115 a1030 Max.Allowable Bending 73.7'1100 ft lbs External Pressure Capacity 8540.000 psi MAKE-UP TORQUES Ii Minimum 8000 ft-lbs Optimum 96000-Ibs Maximum 12800 ft-lbs OPERATION LIMIT TORQUES � Operating Torque 12800 ft-lbs 'wield Torque 15000 R-lbs Page 32 Rev 0 October 2017 • IIIMilne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company EXCLUDER2000TM With Dual Filter Cartridges Dimensional Data Drawing 667-810-00 f , 1 1 LC.L0L L Uv 0,� L0 4L. Lan to 11 000000/17101.11.11.10:1=11=11.11.11.11.1:1=11.1000000;0000 Do too o o MCI f oo t • C E Dimensional Data A A Cn`i, Size (Fine) (Coarse) B 1 Medium) Su r Coarse) 2-318 in. 3.170 3.220 1.995 VI di _ 2-7)8 in. 3.670 3.720 2.441 3-1)2 in. 4.300 4.350 2_992 4 in. 4.800 4.850 3.545 4-1/2 in. 5.310 5.360' 4.000 5-112 in. 6.320 6.370' 4.892 6-518 in. 7.460 7.510' _ 6_050 7 in. 7.840 7.890' 6.184 9-5)8 in. 10.540 10.550' 8.681 'Super Coarse'Weave is available in these sizes only Length dimensions shown below are considered standard.Other length combinations are available as a special order. Base pipe Material C D E 81.19 in. 10.25ft 21.0 in. API 13 Chrome 16.0 ft 19.5ft - 21.0 in. 32.Oft 39.0ft 30.0 in 81.19 in. 9.25ft 15.0 in. API L-80 16.Oft 18.5ft 15.0 in. 32.Oft 37.0ft 24_D in. MPU L-51 SB N Lower Completion Draft Detail-10.31.17 Description Est Joints Est Length(ft) Total Length(ft) Est Top(MD) Liner Top Packer&Hanger 1 25 25 6410 Crossover,7"x 4.5" 1 5 30 6435 PupJoint,4.5" 1 5 35 6440 Joints,4.5"Blank 3 120 155 6445 Screens&Blank Pipe(3:1),4.5"13.5#L-80 Hydril 625 Baker Excluder 167 6847 7002 6565 4.5"Packoff Valve 2 7004 13412 Joint,4.5" 41 7045 13414 WIV 3 7048 13455 Shoe 1.5 7049.5 13458 Page 33 Rev 0 October 2017 • • Milne Point Unit L-51 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/IJ 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. 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. Page 34 Rev 0 October 2017 • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 16.19. Break circulation and circulate out the mud. Begin circulating at -4 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 0 October 2017 • Milne Point Unit L-51 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. nA. n1S 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 0 October 2017 • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: ST-L Casing 7-518 in 29.70 lbfft(0.375 in) L-80 STANDARD Material L-80 Grade 80,000 Minimum Yield Strength (psi.) 95,000 Minimum Ultimate Strength (psi.) iSA Pipe Dimensions VAM USA 7.625 Nominal Pipe Body O.D. (in.) 4424 W.Sam Houston Pkwy.Suite 15D BodyI.D. (in.) Houston,Tx 77041 6.875 Nominal Pipe Phone:713-479-3200 0.375 Nominal Wall Thickness(in.) Fax:713-479-3234 E-mail:VAMUSAsalesOvam-usa.corn 29.70 Nominal Weight(lbs./ft.) 29.06 Plain End Weight(Ibs.tft.) 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.) 4.39 Make-up Loss(in.) 5.550 Critical Area(sq. in.) 65.0 Joint Efficiency(%) 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 0 October 2017 • Milne Point Unit L-51 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 0 October 2017 • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 18.0 Run ESP Assembly — Upper Completion 18.1 M/U ESP assembly and RIB to setting depth. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. /1/°1-'1 `' • RIB with ESP assembly and cable clamps as per tally f) � 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 to cover 2000' TVD (Volume should equal capacity of tubing+tubing annulus). 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 0 October 2017 • • 1:1Milne Point Unit 1-51 Producer Drilling Procedure Hilcorp Energy Company 20.0 Innovation Rig Divperter Schematic 13111II110 n■ i _-13.5//8'SM Control Technology Annular BOP E o 1 laill III � T Z1. � x-13-58'SM Control Technology Double Ram +` il_ it P.71 iftik 3-118'Kill Line a r ' " r 14V �`/ h 3.118'Choke Line I l 1 :Ifni ;I: it o=i _ 13.5°8'SM Control- " Technology Single Ram 13.5!8'x 51.4 hir—lid ------"--16'Diverter Line 17. irk 13-518'x 5M 1 Ill' I `2-1116'x 5M 20'Casing Page 40 Rev 0 October 2017 • • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 21.0 Innovation Rig BOP Schematic Lnnrn -----`"--13-5/8"5M Control Technology Annular BOP 1 _1 llt iii Ffi iii 11.:; I -'------------13-518"5M Control . ( ) `� Technology Double Ram i . F� i F.-i lint II T. GG-- T,.. t i [ 1 I I 3-1/8"Kill Line a :M _ " ig, -..----'"-----3 1l8"Choke Line c-i-370 iii i't f o ;,, --13-5I8"5M Control Technology Single Ram 13-5/8"x 5M 11"x5M alith i' -I Di-AO. ' Ali i 9-5/8"DBL D Seal a I`'AO" '''1 2-1/16"x 5M ,.sy ip i 13-5/8"x 5M i. Casing Hanger of I d (r a li r i S-22 , r. ,r► 13-5/8"NOM 9-5/8"BTC Btm x 2-1/16"x 5M 10.5"-4 SA Pin Top WI Primary Seal 20"Casing I 9-5/8"Casing Page 41 Rev 0 October 2017 • • II Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 22.0 Wellhead Schematic I HILCORP ALASKA i SCHRAOER BLUFF WELLS HO-35449H t -t i 2-9/18 SM LT- - J HOLD-DOWN FLANGE ADAPTER, ESP-2CL j TOADSTOGL II X 2-9/16 54 r __ it 5. __ 11. TUBING HANGER '-1 S-ee-ESP lin MEl 11 % 2-7/8BRp TOP X— : WA ,�. ,...- API MOD BTA,�� ' I • , Ara II .EST F/TAURUS PENETRATOR .— ■ S O ` 43-217-00 MO1 'Li ± iI UPI _ .4 - 11 `M 1 CASING HANGER, SMB-22 tom II , imin \--2-1/16 5M / 11 X 7-5/8-- mm. I — W/PRIMARY SEAL i I �"I •j • 2EST 6.0 MEM i ieiN A`i N•, 4 i nil I I, 9-5/8 GBL D j t t■1 T-2_1/16 514 -• �-�. fir: -�: .. 18-3/4 .3M -'i , it CASING HANGER tit um SMB-22 �' 18 % 9-5/$ i. I:.?W/PRMARYSEL E24.15 .I EST ...t 1 13-3/8 CASING 1 9-5/8 CASING— 1116111 7-5/8 CASING....__ 5.000 PSI ESP WELLHEAD ASSEMBLY ELM TIE BACK STAE DIMENSIONS%OWN CN THIS DRAWING ARE 2-7/B CASING....,-........11. 13-3/8 X 9-5/8 X 7-5/B % 2-7/8 ESTIMATES OILY ANO CAN VARY SIGNIFICANTLY RESTRICTED CONFIDENTIAL DOCUMENT DEPENDING CR RAW MATERIAL LENGntS , ..,r...�.,....„w.. 11101 RPL 111" 1.9 r19J1R415 'WV ND GUARANTEE CF STAC%UP IOW IS R4RLIEG. MIA.M WN r rOWw 1.6..10..w a .a DIMENSIONS SIC N SHGULO BE CCNSIEERED �"'4. 7� - alr�n.a FOR REFERENCE PURPC5ES ONLY. 4 °a ...E+'�.+� cm 0D-000619 Page 42 Rev 0 October 2017 Mime PointProducer Unit Drilling Procedure Hilcorp Energy Company 23.0 Days Vs Depth MPU L-51 Days vs Depth 2006 I � , 6000 - ___..__....__,___._...._._.__..__ .4_..______... v 8000 2 _0000 now 14000 1 < 16000 0 5 10 15 20 Days Page 43 Rev 0 October 2017 • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 24.0 Formation Tops & Information SV5 1596' MD/1432'TVD Base I-errnafr-ost 2320' MD/1854'TVD SV1 2306' MD/2137"TVD Ugnu LA3 5002' MD,f 341S"TVD SB `,1A 6084' MD/ 3902' TVD SB NB 6464' MD/ 3935'TVD GENERALIZED GEOLOGICAL FORECAST ss GEOLOGICAL COMMENTS TVD FM LITH DESCRIPTION AU G..l. • NOTE:See individual Well Program for Zits Gublki -; specific casing design,depths,sizes. .:.tae•. &iDQ weights,grades and connections. a $ ': Unconsolidated coarse to medkim sand and small gravel I • with minor siltstone. •.i•.� IF SIGNIFICANT AMOUNTS OF GRAVEL 1,000' o, ARE ENCOUNTERED WHEN DRILLING THE A♦ SURFACE HOLE,THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE 1750 Base permafrost EFFECTIVE HOLE CLEANING. hterbeds of sand.clays and siltstones with occasional 2,000' show of coal. Watch possibb sidetracking while washingfreaming,L-33&L-15. Sagavanirktok 4100.. No hydrates encountered on L-Pad wells drilled to date. Continued Mar beds of sand,clays and sihabnes with occasional shows of cod.Traces of pyrite at.1-3100 ft. 3,000' Interval at.!-3400 ft can be sticky and tight(Lol). Clay hterbeds between 3000 and 4500 ft C 3472'- w L 3657' A Kuna v UGNU:Series of coarsening upward sands which are I-Ae.C,ol 7 made up of: (from top to bottom)coarse sand,fine sand, silty shale. Better developed intervening shales as you UGNU progress into the L and M(deeper). Ugnuand Schrader Bluff: Possible hydrocarbons limited L-sseas to SWcorner of Milne development Northern area is I-ABl downstructure and wet. '3739' M-sends I-AS,CI '4000' 4Nn) Schrader Bluff Sands: ,000' NnS,e.c,o, Continued layering coarsening upward sands as above i Schrader Bluff: Possible lost circulation E,F; except more condensed and with occasional coal. zone while drilling long strings and running Clay rich shale Interval 4300 to 4600 ft '4170' D-Sands Ugnu and Schrader Bluff Possible hydrocarbons limited casing. Recommend deep setting surface (OA) I-AB.C, to SWcornorofMilne development L'37 and L•45 are casing for Kuparuk long strings. Also,the o,E,F: completed In the Schrader Bluff sand. Northern area of Schrader L-Pad Is downstructure and wet. Schrader Bluff sands are a potential differential stuck pipe interval if left un-cased Bluff `+ Surface casing point In shale below for Kuparuk long strings. Sands: Schrader Bluff OB sand for longer reach wells. I I Page 44 Rev 0 October 2017 • Milne Point Unit L-51 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 0 October 2017 Milne Point Unit L-51 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 0 October 2017 s Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 26.0 Innovation Rig Layout r 170'-3 - f - �_ = ,s j i n k: „—� _ .,—. � 1 • r ll 1 — 1 tikr ME+, N, N111"— « 0 I 1L 1 r1 w Il I � ■ r = dna ill ill yr 1 I o ' 1 :t Aii — — . _ ---- 111111.11M1111211 —I ;r Q i= I v'f c v 56'-4" IBM HAK 2 FOOT - Il.ia', p PRINTE �! 05/21/16v. �1E a r • 1 . . M U inrau 113.-113.. UI 36'-13- - ✓' Page 47 Rev 0 October 2017 I • Milne Point Unit L-51 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 0 October 2017 • • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 28.0 Innovation Rig Choke Manifold Schematic II La ! 117b ! ■i—q I Ibq uD—�1^ a-4--)—ti I _ _D b—�1_r".".71-"� _ d a_ DP—i "immix t141.10 --..-.:,),_4 E-- . ..1 ...111ri '---t rjii .. , ..__. ..... .6._ . .. a ; +!� WII 111.... Mt 2.016"5A!BEIM - 2-9"16-5M BB209 - /� Plper Baa ValvesPiper Bab Vas n r""41llr [IrL -ili_ .. _ 1 40 _ 1. \ 111 1.04. 0.....; 1*(9)° 11111.11111111 CR. , ` , , r� 1 ' a C _ C. ' xti C r--------^1 r I Page 49 Rev 0 October 2017 • • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 29.0 Casing Design Calculation & Casing Design Factors DATE: 10/26/2017 WELL: MPU L-51 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: 1392 psi (see attached MASP determination&calculation) MASP: Production Mode MASP: 1392 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 9-5/8" Screens Top(MD) 0 6,410 Top(TVD) 0 3,932 Bottom(MD) 6,410 13,500 Bottom(TVD) 3,932 3,756 Length 6,410 7,090 Weight(ppf) 40 13.5 Grade L-80 L-80 Connection DWC HTTC Weight ido Bouyancy Factor(lbs) 256,400 95,715 Tension at Top of Section(lbs) 256,400 95,715 Min strength Tension(1000 lbs) 916 279 Worst Case Safety Factor(Tension) 3.57.7 2.91 Collapse Pressure at bottom(Psi) 1,942 1,855 Collapse Resistance vhdo tension(Psi) 3,090 8,540 Worst Case Safety Factor(Collapse) 1.59 ✓ * 4.60 MASP(psi) 1,392 1,392 Minimum Yield(psi) 5,750 9,020 Worst case safety factor(Burst) 4.13 ✓ F. 6.48 Page 50 Rev 0 October 2017 • Milne Point Unit 11 L-51 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-51 Milne Point Unit MD TVD Planned Top: 6410 3931 Planned TD: 13500 3756 Anticipated Formations and Pressures: Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NB Sand 3,932 3,890 1768 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: 3932(ft)x 0.78(psi/ft)= 3067 3067(psi)-[0.1(psi/ft)*3932(ft)]= 2674 psi MASP from pore pressure(complete evacuation of wellbore to gas from Schrader Bluff NB sand) 3932(ft)x 0.454(psi/ft)= 1785 psi V 1785(psi)-0.1(psi/ft)*3932(ft) 1392 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 0 October 2017 • • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 31.0 Spider Plot (NAD 27) (Governmental Sections) �\ h / � w 1 , t �p}"�,b_ h MPU L-5l_SHL a,,a., e . .-.39Pa. r ___ .2 ADL025509- 3'..' -+r / .. + '/0 Ih .. ` •SEE. S _ 16231r /r !/ Ih ...DL388235" r •+ , a 11, 1. t r• r r A. //rr /r hI I h • � // b ♦ / /I /rM y r ♦ . r' / y • h h h • rrr ,r II ,g/ h // !I a r ••/r /// h r#`1 h s 4. e !, „ I �` r r L.' ♦ h 3 i ..... /r. IP._:: L-11 7i'11 i .� •.. + L.it PBi / a w rr / , • ee' / / u/ I �\1 ~. h . • ` I \ ' Fss.4001.1 a / , ! `� `+• h h /.-MILNE POINT UNIT/ o / `t h OI ` v. I '� ey-93 ♦. U013N009E '/i/ +h` UD13N010E- $ �. /r .. r // 0° 1 // r o , .` • / 0 1 // Sec.13 ! `. SPC.17 / (63 'r r . / `o ". ! / / o �0 .. `'a , o ! :15 a o . o IADL025514� ADL025515 R♦ a / o a a a 0 a �♦ a / o a 0 o e Legend :.1 , a MPU L-51_SHL - Other Surface Holes(SHLi , 0-.Sec 24 Sec i6t31;� MPU •L S1_TPH a Other Bottom Holes(BHL) 0. g a --- Other Well Paths e° t 1IPU L 51 BHL I � \1:'l' [}}I I- i �Oil and Gas Unit Boundary ' 1 = Pad Footprint riMilne Point Unit MPL-51 Well 0 1.000 2,000 wp_06 Feet Page 52 Rev 0 October 2017 III INIEMilne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 32.0 Surface Plat (As Built) (NAD 27) I 1 36 31 I 37 I 33 I r � -* ---� a I 1 I \ i I I 1. 1 e q 1 w� I I a t + re ma I I `� 3/ >"TL!"AD I 1 32 33 ■28 •29 1Q 7 � I I i,a. >' ■24 ■20 I / ■2G ■2r Tl'IS Pf O E'CT "\ I I /II ■1e ■t7 -=- -- / IR 41 •43 ii - Ill t •45 \._v_ e3 -r In 1 Al 1 IS r-,- f I I --=c,Ili ti 1 I 1 13 • • 8 24 +g 1 ao I r 1 I ' 38 ■ + /� r� • 42 VICINITY MAP 1 • 34 ■ l- A V ■ 9 IL7.l. ■ 14 I OF 2 ■ IN 7 �� pF' 'CE...... �+', • 11 4O is *..4 � F/ ..y�'• r • 4. 6 70 4 36 5 3? 11 50 '7 6 j .• 'L, ° 10200 .. ,,,,,-,,,,,„„„. NOTES: 1 FO ND .' 1 i AIM 1_ ALASKA STATE PLANE COOPCYNAIES ARE ZONE 4, i AS-RUE.T CONDUCTOR SURVEYOR'S.CER TIFICATea NAD27. • EXISTCIG CONDUCTOR 2_ BASIS OF LOCATOR IS L-PAC MONUMENTS L-1 I HEREBY CERTIFY tHAT I AM NORTh AND L-2 SOUTH. PROPERLY REGISTERED AND LICENSED T3. ELEVATION DARN IS MSL GRAPHIC SCALE THE STATE� C Dr LAND ANDTHAT A_ GEODETIC POSITIONS ARE NA027.. 0 ID) 7C0 Opp THIS AS-BUtT REPRESENTS A SURVEY 5_ RAO MEAN SCALE FACTOR t4: 0.9899023 r I MADE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL 0. DATE OF SURVEY: OCTOBER 8, 2017. (IN FEET) DeMENSIGNS AND OTHER DETAILS ARE 7. REFERENCE FIELD 9O0K HC17-05 PGS, 49-54. 1 Inde-200 P. CORRECT AS CF OCTOBER 6. 2017 LOCATED WITHIN PROTRACTED SEC. 8. T. 13 N.. R. 10 E.. MCAT MERIDIAN, AI(. WELL A.S.P. PLANT GECOET1C GEOGE11C CELLAR SECTIO PAD NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D.OD) BOX ELEV. OFFSETS ELEV. L-53 Y=6031932.37' N=1750.02' N70'29'53.203 " N70.49811216 151. 3744' FSL 15.8' X=544641.12' E=1225.10' W149'38'05.7512" W149.63493088 5235' FEL L-52 Y=6031919.76' N=1735.18' N70'29'53.0793" N70.49807758 15.1' 3732' FSL 15.7' X=544648.93' E=1225.04' W149'38'05.5235" W149,63486764 5227' FEL Y=603`906.80' N=1719.96' N70'29'52.9514" N70.49804205 3719' FEL L-51 15.3` 15.7' X=544656.92' E=1224.94' W149'38'05.2909" W149.6,3480301__ 5219 FEL Y=6031990.50' N=1749.75' N7029'53.7700" N70.49826947 3802' FSL 1 L-56 15.2' 15.7' X=544734.66' F=1335.24' W149'38'02.9871" W149.63416308 5141' FEL L-57 Y=6031977.71' N=1734.93' N70'29'53.6435" N70.49823438 15.3' 3789' FSL 15.7' r X=54474215' E=1334.81' W149•38'02?689' W149.63410246 - 5134' FEL L-54 V=6031965.09' N=1719.80' N70'29'53.5191" N70.49819976 t5.4' 3776' FSL 15.6' X..544750.50' 1=1335.21' _W149138'02.5253" W149.63403480 5125' FEL T- l�iteorp Alaska T_IT ._. h..01 ,ati, o�r. _ ,rE 02 MPU L-PAA ('"x` scAa AS-BUILT CONDt1CTt)R e5 IA/AAII0 IMO PM Mf 4MgY G[CCt 1 or' 1'"200• /YELLS 51-54, 56 do 57 .,, n.4, raw.. Jrr,0. I ['age 53 Rev 0 October 2017 • • Milne Point Unit L-51 Producer Drilling Procedure Hilcorp Energy Company 33.0 Schrader Bluff NB Sand Offset MW vs TVD Chart MPU L-51 SB NB Offset MW vs TVD EMW,ppg 85 95 10.5 11.5 12.5 0 I I 500 1000 � I 1500 I ; F— 2500 3000 _-- i 3500 4000 1 4500 -- J-27(2015)TVD J-28 (2015)TVD Page 54 Rev 0 October 2017 III • Milne Point Unit L-51 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 60°5 Inspection Class PipeBody Wail Thickness an)0.362 Nominal Weight Designationnation 19.50 Pipe Body Grade S-135 Drill Pipe Approximaae Length ,-s 31.5 1 Drill Pipe Length Range2 SrnoothEdge Height amil3f32 Raised Connection GPDS50 Tool Joint SMYS •p=u 120.000 Tool Joint OD 6.625 Upset Type ,IEU Tool Joint ID I a:3250 Max Upset OD (DTE) tr5.125 Pin Tong 9 Friction Factor i1.0 Box Tong ia: 12 Nc2e:Tong space Tay trance narreacirg. Drill Pipe Performance Drill-Pipe Length Range2 Performance of Drill Pipe with Pipe Body at Best Estimates I Nominal 80%Inspection Class (st"' ' " �' I 'least xn at°' - dxleanuke. Operational Max Tension Drill Pipe Adjusted Weight t�snrl 24.11 23.29 T0""1G t1 s> Torque m-lbs) Mrs) Fluid Displacement (PaPfi 0.37 0.36 Meir *43,104 Tension Only 0 560,800 Fluid Displacement obi nl0 0088 0.0085 attmkxrr_d Loagnp 39,600 410,500 Fluid Capacity ?gat�ta 0.71 0.70 0.72 Fluid Capacity ?Bbls'ro 0.0169 0.0167 0.0172 Marlt,adn MUT 36,104 Tension Only 0 .560,800 Drift Size ?Inl 3.125 0�1 Lam 32,100 467,400 Note.Dil'tele barrel equals 42 US goecos. Note:DMI ppe assembly.aWez am best esnrnates and nay tiny du_ID pipe body nIll tolerance,Internal plank oza1ing and other parlors. Connection Performance GPDS50 ( 6.625 rn) OD X 3.250 on; ID ) 120.000 rps'i �is Applled Malte-up Tension al Snoulle' Tension s Connector Tool Joint Dimensions Topge Seaaratwn Yeld ill-bs) abs; ?bsi Balanced OD ;lot 6.435 Maximum Make-up Torque 43,100 Tensile Limited 1,046.900 Mlrrrnu.nr Toni Joni CO sat API 5,930 Minimum Make-up Torque 36,100 1202.500 1,250.000 P ^"""°ass In. • -"Ncre The maximum Inake..-0lrg4e shtrld be applied.ben Posse,* Mlnrnun Tal Joni CO Inc 5,'93 �o�nterbpre tint Mete Tc maigTrze connectxn oberanenal tens le.a MUT!Tal'3'r,1TO dt-lbs;should be applk'd. Tool Joint Torsional Strength trtatral 71,800 Tool Joint Tensile Strength fin) 1,250,000 Elevator Shoulder Information Elevator OD 3132 Raised 6.812 71 Smooth Edge Height Nominal Tool Joint Worn to Bevel Worn to Mn TJ 0D for r3/32 Raised OD Diameter API Premium Class Box OD ,6.812 6.625 6.063 5.930 Elevator Capacity uhsl 1,658,000 1.440,200 823.600 685,600 5219 Nate Elevates moaner.based en assumed Elevaane Bore,no'Arat ratite,and ccnlacl stress o1 110,10Ct10 Assumed Elevator Bore Diameter rn Nole:A raised eleeanor OD Increases elevalcr capladty'athctl atfeciho rake-up torque. Pipe Body Slip Crushing Capacity Pipe Baty Conf+guration( 5 ttrr OD 0.362 cm Wall S-135) Nominal 80%Inspection Class API Premium Class • I t�7 [Slip Crushing Capacity cos;498.300 396.500 396.500 1:117 SII I// Nie:Sip-Dsishirp 9p rni7vrg Pad is cLcwMC pith Pe`bpr.Aaeodd egwtke horn VAN Coes Dell Pye Assumed Slip Length rn)16.5 Fat Mire Sip Area-Abed CO,1959 kir the slip emir transverse bad fader 9hoila ane a Sr rereleme Transverse Load Factor(K) 4.2 0"' st°`N� gS ntod,ca the sip m gnandda n.�e,t tent«l ea leadenlg a Irnee sips aylptmOD andxar lanblal,and di.'acres conchxdn thesb manors:Lees axaacrra4 r ea-rnt cin. Pipe Body Performance Pipe Body Configuration( 5 rn> OD 0.362 at^r Wall S-135) Nominal 80%Inspection Class API Premium Class Pipe Tensile Strength ?Ions 712.100 560;600 560,800 Pipe Torsional Strengtnn t= 74.100 58.100 56,100 TJlPipeBody Torsional Ratio 0.97 1.24 1.24 80%Pipe Torsional Strength owe.'59.3^•0 46,500 46.500 Burst i Xh 17.105 15,638 15,638 Nate:Nominal Bursa Collapse (nu)15.672 10.029 10,029 to cowledmersts RBA, API. Pipe OD a uan 5.OD0 4.855 4.855 Wall Thickness nt 0.362 0.290 0.290 Nominal Pipe ID loss 4276 4.276 _4276 Cross Sectional Area of Pipe Body on-zi 5275 4.154 4.154 Cross Sectional Area of OD ch.^xr 19.635 18-514 18.514 Cross Sectional Area of ID nn^al 14.360 14.360 14.360 Section Modulus cin^3}5.708 4.476 4.476 14f y Polar Section Modulus an^ori 11.415 8.953 8.953 Gr1,nt Page 55 Rev 0 October 2017 • • Milne Point Unit L-51 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 6-518' Inside Diameter 3-114' 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 gal/ft 0.726 US galtft Displacement W/Tool Joint _ 0.353 US gal/ft 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 0 October 2017 • • Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-51 MPU L-51 Plan: MPU L-51 WP07 Standard Proposal Report 24 October, 2017 Ili' II HALLIBURTON Sperry Drilling Services • • HALLIBURTON n r REFERENCE INFORMATION WELL DETAILS:Plan:MPU L-51tlilc )1l u Co-ordinate(NW)Reference:Well Plan:MPU L-51,True North Ground Level: 15.30 Sperry Orrlter r Vertical(TVD)Reference:MPU L-51 As-Built @ 41.80usn +N/-S •E/-W Northing Easting Letittude Longitude Measured Depth Reference: MPU L-51 As-Built @ 41.80usft 0.00 0.00 6031906.80 544656.92 70°29'52.951 N 149°38'5.291 W ----- Calculation Method:Minimum Curvature Project: Milne Point Site: M Pt L Pad SECTION DETAILS Well: Plan:MPU L-51 Sec MD Inc Azi TVD -rN/-S +E/-W Oleg TFace VSect Target Annotation Wellbore: MPU L-51 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 Design: MPU L-51 WP07 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3°/100':300'MD,3007VD 9 3 500.00 6.00 235.00 499.83 -6.00 -8.57 3.00 235.00 8.24 Start Dir 3.92°/100':500'MD,499.63'TVD Hilcorp Alaska,LLC 4 1000.00 25.00 212.00 979.54 -111.62 -86.73 3.92 -29.48 132.09 Start Dir 5°/100':1000'MD,979.54'TVD 5 1588.47 54.34 208.38 1427.61 -434.55 -270.32 5.00 -5.99 494.55 End Dir:1588.47'MD,1427.61'TVD Calculation Method:Minimum Curvature 6 5448.82 54.34 208.38 3677.90 -3194.19 -1761.25 0.00 0.00 3589.30 Start Dir 5°/100':5448.82'MD,3677.9'TVD Error System:ISCWSA 7 6109.67 85.00 195.00 3905.65 -3764.23 -1980.16 5.00 -25.01 4178.43 End Dir:8109.67'MD,3905.65'TVD Scan Method:Closest Approach 3D 8 6409.67 85.00 195.00 3931.80 -4052.91 -2057.51 0.00 0.00 4477.11 MPL-51 Heel wp2 Start Dir 4°/100':6409.67'MD,3931.8'TVD Error Surface:Elliptical Conic 9 6572.17 91.50 195.00 3936.76 -4209.71 -2099.52 4.00 0.00 4639.35 End Dir:6572.17'MD,3936.76'TVD Warning Method:Error Ratio 10 7532.21 91.50 195.00 3911.63 -5138.73 -2347.92 0.00 0.00 5598.49 Start Dir 4°/100':7532.21'MD,3911.83'TVD _ 11 7669.66 91.50 189.50 3908.03 -5270.95 -2377.06 4.00 -89.93 5735.37 End Dir:7869.66'MD,3908.03'TVD _ 12 7800.00 91.50 189.50 3904.82 -5399.46 -2398.56 0.00 0.00 5864.58 Start Dir 4°/100':7800'MD,3904.62'ND 13 7908.59 91.58 185.16 3901.70 -5507.10 -2412.41 4.00 -88.91 5971.55 End Dir:7908.59'MD,3901.7'ND 14 8685.78 91.58 185.16 3880.29 -6280.85 -2482.22 0.00 0.00 6731.96 Start Dir 4°/100':8685.78'MD,3880.297VD -1500- 15 8822.37 91.48 190.62 3876.64 -6416.05 -2500.95 4.00 90.96 6886.73 End Dir:8822.37'MD,3876.64'TVD 16 12881.67 91.48 190.62 3771.80-10404.49 -3248.80 0.00 0.00 10899.70 MPL-51 Toe wp2 - _ 17 13500.00 91.48 190.62 3755.83-11012.02 -3382.72 0.00 0.00 11514.01 Total Depth:13500'MD,3755.83'TVD -750- _ SURVEY PROGRAM Date:2017-10-06T00:00:00 Validated:Yes Version: _ Start Dir 3°/100':300 MD,300'TVD Depth From Depth To Survey/Plan Tool - 28.50 050.00 MPU L-51 WPO] SRG-SS D 850.00 8410.00 MPU L5MWp 1 WP07 r17RWM5♦seg C __ -'Start Dir 3.92°/100':500'MD,499.63'WD 6410.00 19800.00 MPU L-51 WPO] MW19rI7192•MShseg - 500 Start Dir 5./100':1000'MD,979.54'TVD CASING DETAILS O 750- ND MD Name Size ,1090- End Dir:1588.47'MD,1427.61'ND 3930.96 6400.00 95/8"x 12 1/4" 9-5/8 L _ ,p ,-- 3755.83 13500.00 4 12'x 8 1/2' 4-12 O • 1 500 e r,{P 1 40 O N - 'Y �p�'L�0 1 04 0,5.0 �O �+CjO d'-' N7' _A 2250- °p .e) ,0''� 40.5 10 34".Ory '49.h 1�0 P,C' F i c .`0^e0 ,,.!4E Ery^140.1,,,,"i:. , Ace \^.19.0.,0,84 10c.{' , sss 3000- et '� ' �,5 ,'�ta1,K;00 \^00'��0)'4d5\`.% o.?f" $7' Total Depth:13500'MD,3755.83'TVD - o f ,yvA� ,,5� �O`p ' S�nCO ,e°�'e .00'17'. _ ,4i • oC- y�° y,,,O` i MPU L-51 WP07 3750- '8, , ,' ,„ , ,.,c - _ 95/8"x121/4"-- , - o S S 8 8 N N --"a--"a- MPL-51 Heel wp2 0 0 0 0 o 0 0 0 0 0 4 12"x 8 12" 4500- MPL-51 Toe wp2 5250- 6000- ' I riiiiiilllllllllllllll llllllllllllllll llllllllliiiiiillllllllllllilliiil iiiiiilii llllliiiiiiii -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 Vertical Section at 196.98°(1500 usft/in) • • HALLIBURTON Project: Milne Point WELL DETAILS: Plan:MPU L-51 Site: M Pt L Pad Ground Level: 15.30 Ar 'Pry o lm r Well: Plan: MPU L-51 +N/-S +E/-W Northing Easting Latittude Longitude Wellbore: MPU L-51 0.00 0.00 6031906.80 544656.92 70°29'52.951 N 149°38'5.291 W 11 p� Plan: MPU L-51 WP07 REFERENCE INFORMATION Com`Y Co-ordinate(N/E)Reference:Well Plan:MPU L-51,True North Vertical(TVD)Reference:MPU L-51 As-Built 41.80usft - - — Measured Depth Reference: MPU L-51 As-Built 41.80usft CASING DETAILS Calculation Method:Minimum Curvature TVD TVDSS MD Size Name 3930.96 3889.16 6400.00 9-5/8 9 5/8"x 12 1/4" 3755.83 3714.03 13500.00 4-1/2 4 1/2"x 8 1/2" a 0=-- - __Start Dir 3°/100':300'MD,300TVD - �ftr -Start Dir 3.92°/100':500'MD,499.63'TVD /?s0 Start Dir 5°/100':1000'MD,979.54TVD 7s00 -750— End Dir:1588.47'MD,1427.61'TVD /750 ?000 -1500— ??so ?soo -2250— ?iso 3000 3?s0 -3000— 33.60 37,60 Start Dir 5°/100':5448.82'MD,3677.9'TVD -3750— 9 5/8"x 12 1/4" - ;1,•__ End Dir:6109.67'MD,3905.65'TVD MPT-51 Heel wp2 ---- -' - Start Dir 4°/100':6409.67'MD,3931.8'TVD • -4500— End Dir:6572.17'MD,3936.76'TVD 0 -Start Dir 4°/100':7532.21'MD,3911.63'TVD -5250— + -End •Dir:7669.66'MD,3908.03'TVD .Start Dir 4°/100':7800'MD,3904.62'TVD 4), _ End Dir:7908.59'MD,3901.7'TVD -6000— - Start Dir 4°/100':8685.78'MD,3880.29'TVD O -6750— End Dir:8822.37'MD,3876.64'TVD -7500— -8250- -9000- -9750— MPL-51 Toe wp2 -10500- 4 1/2"x 8 1/2" MPUL.51 WP07 -11250— 3756 Total Depth:13500'MD,3755.83'TVD -12000— I 1 1 1 1 1 I I I I 1 1 I 1 I II II 1 1 1 1 1 I 1 1 I 1 1 1 1 I 1 1 1 1 I I 1 1 1 I 1 1 I I I 1 1 1 1 t -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 West(-)/East(+)(1500 usft/in) i s Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU L-51 Company: Hilcorp Alaska,LLC TVD Reference: MPU L-51 As-Built @ 41.80usft Project: Milne Point MD Reference: MPU L-51 As-Built @ 41.80usft titi iii Site: M Pt L Pad North Reference: True Well: Plan:MPU L-51Survey Calculation Method: Minimum Curvature Wellbore: MPU L-51 ly; ix Design: MPU L-51 WP07 u 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 ii M Pt L Pad,TR-13-10 Site Position: Northing: 6,029,799.28 usft Latitude: 70°29'32.230 N ''I 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-51 Well Position +NI-S 0.00 usft Northing: 6,031,906.80 usft Latitude: 70°29'52.951 N +E/-W 0.00 usft Easting: 544,656.92 usft Longitude: 149°38'5.291 W Position Uncertainty 0.00 usft Wellhead Elevation: 41.80 usft Ground Level: 15.30 usft Wellb MPU L-51 Model Name Sample Date Declination' Dip Angle Field Strength -; nT BGGM2017 10/6/2017 17.50 81.03 57.498 Iown MPU L-51 WP07 � .. ,.....,.. x,.. , � «>.��.- .<.., E.w, a. <>�-YZk✓ } a ,.,. Y..., .,au..,.-,.x.::SG u. ..,. = a. ""».. aK4 ,3z � �3n.a,�"wi�3 Audit Notes: 1 Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section: ;:,%.:144-i- Depth From(TVD) i'-iii:'' (usft) 26.50 0.00 0.00 196.98 10/24/2017 12:33:19PM 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-51 Company: Hilcorp Alaska,LLC TVD Reference: MPU L-51 As-Built @ 41.80usft Project: Milne Point MD Reference: MPU L-51 As-Built @ 41.80usft P Site: M Pt L Pad North Reference: '-',',,:':.G True Well: Plan:MPU L-51 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-51 ( Design: MPU L-51 WP07 - Plan Sections Measured Vertical TVD -,, Dogleg Build Turnor Depth Inclination Azimuth Depth System +N/S ., +E1-W ' Rate Rate Rate rn :: (usft) (°) (°) (usft) f. usft (usft) , (usft) (°/100usft) (°/100usft) (°/100usft) 26.50 0.00 0.00 26.50 -15.30 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 258.20 0.00 0.00 0.00 0.00 0.00 0.00 500.00 6.00 235.00 499.63 457.83 -6.00 -8.57 3.00 3.00 0.00 235.00 1,000.00 25.00 212.00 979.54 937.74 -111.62 -86.73 3.92 3.80 -4.60 -29.48 1,588.47 54.34 208.38 1,427.61 1,385.81 -434.55 -270.32 5.00 4.99 -0.62 -5.99 5,448.82 54.34 208.38 3,677.90 3,636.10 -3,194.19 -1,761.25 0.00 0.00 0.00 0.00 6,109.67 85.00 195.00 3,905.65 3,863.85 -3,764.23 -1,980.16 5.00 4.64 -2.02 -25.01 6,409.67 85.00 195.00 3,931.80 3,890.00 -4,052.91 -2,057.51 0.00 0.00 0.00 0.00 6,572.17 91.50 195.00 3,936.76 3,894.96 -4,209.71 -2,099.52 4.00 4.00 0.00 0.00 7,532.21 91.50 195.00 3,911.63 3,869.83 -5,136.73 -2,347.92 0.00 0.00 0.00 0.00 7,669.66 91.50 189.50 3,908.03 3,866.23 -5,270.95 -2,377.06 4.00 0.00 -4.00 -89.93 7,800.00 91.50 189.50 3,904.62 3,862.82 -5,399.46 -2,398.56 0.00 0.00 0.00 0.00 7,908.59 91.58 185.16 3,901.70 3,859.90 -5,507.10 -2,412.41 4.00 0.07 -4.00 -88.91 8,685.78 91.58 185.16 3,880.29 3,838.49 -6,280.85 -2,482.22 0.00 0.00 0.00 0.00 8,822.37 91.48 190.62 3,876.64 3,834.84 -6,416.05 -2,500.95 4.00 -0.07 4.00 90.96 12,881.67 91.48 190.62 3,771.80 3,730.00 -10,404.49 -3,248.80 0.00 0.00 0.00 0.00 13,500.00 91.48 190.62 3,755.83 3,714.03 -11,012.02 -3,362.72 0.00 0.00 0.00 0.00 10/24/2017 12:33:19PM Page 3 COMPASS 5000.1 Build 81D • • Halliburton HALLIBLIRTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU L-51 Company: Hilcorp Alaska,LLC TVD Reference: --„,-- MPU L-51 As-Built @ 41.80usft Project: Milne Point MD Reference: MPU L-51 As-Built @ 41.80usft Site: M Pt L Pad North Reference: " ,- True Well: Plan:MPU L-51 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-51 Design: MPU L-51 WP07 ,, x Planned Survey `Ix. , : : .t'. } MeasuredVertical y" Map 14Vesr, Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W- :,Northing „:Easting s DLS Vert Section S(usft) (°) (°) (usft) usft (usft) (usft) ' . ; (usft) (usft) i -15.30 26.50 0.00 0.00 26.50 -15.30 0.00 0.00 6,031,906.80 544,656.92 0.00 0.00 100.00 0.00 0.00 100.00 58.20 0.00 0.00 6,031,906.80 544,656.92 0.00 0.00 200.00 0.00 0.00 200.00 158.20 0.00 0.00 6,031,906.80 544,656.92 0.00 0.00 300.00 0.00 0.00 300.00 258.20 0.00 0.00 6,031,906.80 544,656.92 0.00 0.00 Start Dir 3°/100':300'MD,300'TVD 400.00 3.00 235.00 399.95 358.15 -1.50 -2.14 6,031,905.29 544,654.79 3.00 2.06 500.00 6.00 235.00 499.63 457.83 -6.00 -8.57 6,031,900.75 544,648.39 3.00 8.24 Start Dir 3.92°/100':500'MD,499.63'TVD 600.00 9.61 223.37 598.70 556.90 -15.07 -18.59 6,031,891.62 544,638.43 3.92 19.84 700.00 13.39 218.15 696.67 654.87 -30.25 -31.48 6,031,876.36 544,625.63 3.92 38.13 800.00 17.24 215.21 793.11 751.31 -51.47 -47.18 6,031,855.05 544,610.05 3.92 63.01 900.00 21.11 213.32 887.54 845.74 -78.64 -65.63 6,031,827.77 544,591.77 3.92 94.38 1,000.00 25.00 212.00 979.54 937.74 -111.62 -86.73 6,031,794.67 544,570.87 3.92 132.09 Start Dir 5°/100':1000'MD,979.54'TVD 1,100.00 29.98 210.96 1,068.22 1,026.42 -150.99 -110.79 6,031,755.16 544,547.05 5.00 176.77 1,200.00 34.96 210.19 1,152.56 1,110.76 -197.21 -138.07 6,031,708.78 544,520.05 5.00 228.93 1,300.00 39.95 209.59 1,231.92 1,190.12 -249.93 -168.34 6,031,655.89 544,490.10 5.00 288.19 1,400.00 44.94 209.10 1,305.69 1,263.89 -308.74 -201.39 6,031,596.89 544,457.41 5.00 354.09 1,500.00 49.93 208.69 1,373.32 1,331.52 -373.20 -236.96 6,031,532.22 544,422.23 5.00 426.13 1,588.47 54.34 208.38 1,427.61 1,385.81 -434.54 -270.32 6,031,470.68 544,389.25 5.00 494.54 End Dir :1588.47'MD,1427.61'TVD 1,600.00 54.34 208.38 1,434.33 1,392.53 -442.79 -274.77 6,031,462.41 544,384.84 0.00 503.73 1,700.00 54.34 208.38 1,492.62 1,450.82 -514.27 -313.39 6,031,390.70 544,346.66 0.00 583.38 1,800.00 54.34 208.38 1,550.92 1,509.12 -585.76 -352.01 6,031,318.99 544,308.47 0.00 663.03 1,900.00 54.34 208.38 1,609.21 1,567.41 -657.25 -390.63 6,031,247.28 544,270.28 0.00 742.68 2,000.00 54.34 208.38 1,667.50 1,625.70 -728.73 -429.25 6,031,175.57 544,232.09 0.00 822.33 2,100.00 54.34 208.38 1,725.79 1,683.99 -800.22 -467.88 6,031,103.86 544,193.91 0.00 901.98 2,200.00 54.34 208.38 1,784.09 1,742.29 -871.71 -506.50 6,031,032.15 544,155.72 0.00 981.63 2,300.00 54.34 208.38 1,842.38 1,800.58 -943.19 -545.12 6,030,960.44 544,117.53 0.00 1,061.28 2,400.00 54.34 208.38 1,900.67 1,858.87 -1,014.68 -583.74 6,030,888.73 544,079.34 0.00 1,140.93 2,500.00 54.34 208.38 1,958.96 1,917.16 -1,086.17 -622.36 6,030,817.02 544,041.15 0.00 1,220.58 2,600.00 54.34 208.38 2,017.25 1,975.45 -1,157.66 -660.98 6,030,745.31 544,002.97 0.00 1,300.22 2,700.00 54.34 208.38 2,075.55 2,033.75 -1,229.14 -699.61 6,030,673.60 543,964.78 0.00 1,379.87 2,800.00 54.34 208.38 2,133.84 2,092.04 -1,300.63 -738.23 6,030,601.89 543,926.59 0.00 1,459.52 2,900.00 54.34 208.38 2,192.13 2,150.33 -1,372.12 -776.85 6,030,530.18 543,888.40 0.00 1,539.17 3,000.00 54.34 208.38 2,250.42 2,208.62 -1,443.60 -815.47 6,030,458.47 543,850.22 0.00 1,618.82 3,100.00 54.34 208.38 2,308.72 2,266.92 -1,515.09 -854.09 6,030,386.75 543,812.03 0.00 1,698.47 3,200.00 54.34 208.38 2,367.01 2,325.21 -1,586.58 -892.71 6,030,315.04 543,773.84 0.00 1,778.12 3,300.00 54.34 208.38 2,425.30 2,383.50 -1,658.06 -931.34 6,030,243.33 543,735.65 0.00 1,857.77 3,400.00 54.34 208.38 2,483.59 2,441.79 -1,729.55 -969.96 6,030,171.62 543,697.46 0.00 1,937.42 3,500.00 54.34 208.38 2,541.89 2,500.09 -1,801.04 -1,008.58 6,030,099.91 543,659.28 0.00 2,017.07 3,600.00 54.34 208.38 2,600.18 2,558.38 -1,872.52 -1,047.20 6,030,028.20 543,621.09 0.00 2,096.72 3,700.00 54.34 208.38 2,658.47 2,616.67 -1,944.01 -1,085.82 6,029,956.49 543,582.90 0.00 2,176.37 3,800.00 54.34 208.38 2,716.76 2,674.96 -2,015.50 -1,124.44 6,029,884.78 543,544.71 0.00 2,256.02 3,900.00 54.34 208.38 2,775.05 2,733.25 -2,086.98 -1,163.07 6,029,813.07 543,506.53 0.00 2,335.67 10/24/201712:33:19PM Page 4 COMPASS 5000.1 Build 810 • • Halliburton HALLIBURTON Standard Proposal Report Database Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU L-51 Company: Hilcorp Alaska,LLC TVD Reference: MPU L-51 As-Built @ 41.80usft Project: Milne Point MD Reference: :TMPU L-51 As-Built @ 41.80usft Site: M Pt L Pad North Reference:' ' True Well: Plan:MPU L-51 Survey Calculation Method: Minimum Curvature Wellbore : MPU L-51 Design: MPU L-51 WP07 T Planned Survey .. . �e w. 'ups,, i.`, ' �.;: .:.'',„,,-ri,w" - " ' , .,. k<. Measured Vertical `4 q, Map X Map ' ' ' .. Depth Inclination Azimuth Depth TVDss +NI-S +EI-W Northing ,,Easting DLS Vert Section." (usft) usft (usft) G(usft) '"" ,.} (usft) (usft) a 2,791.55 .... 4,000.00 54.34 208.38 2,833.35 2,791.55 -2,158.47 -1,201.69 6,029,741.36 543,468.34 0.00 2,415.32 4,100.00 54.34 208.38 2,891.64 2,849.84 -2,229.96 -1,240.31 6,029,669.65 543,430.15 0.00 2,494.97 4,200.00 54.34 208.38 2,949.93 2,908.13 -2,301.45 -1,278.93 6,029,597.94 543,391.96 0.00 2,574.62 4,300.00 54.34 208.38 3,008.22 2,966.42 -2,372.93 -1,317.55 6,029,526.23 543,353.78 0.00 2,654.27 4,400.00 54.34 208.38 3,066.52 3,024.72 -2,444.42 -1,356.17 6,029,454.52 543,315.59 0.00 2,733.92 4,500.00 54.34 208.38 3,124.81 3,083.01 -2,515.91 -1,394.80 6,029,382.81 543,277.40 0.00 2,813.57 4,600.00 54.34 208.38 3,183.10 3,141.30 -2,587.39 -1,433.42 6,029,311.10 543,239.21 0.00 2,893.22 4,700.00 54.34 208.38 3,241.39 3,199.59 -2,658.88 -1,472.04 6,029,239.38 543,201.02 0.00 2,972.87 4,800.00 54.34 208.38 3,299.68 3,257.88 -2,730.37 -1,510.66 6,029,167.67 543,162.84 0.00 3,052.52 4,900.00 54.34 208.38 3,357.98 3,316.18 -2,801.85 -1,549.28 6,029,095.96 543,124.65 0.00 3,132.17 5,000.00 54.34 208.38 3,416.27 3,374.47 -2,873.34 -1,587.91 6,029,024.25 543,086.46 0.00 3,211.82 5,100.00 54.34 208.38 3,474.56 3,432.76 -2,944.83 -1,626.53 6,028,952.54 543,048.27 0.00 3,291.47 5,200.00 54.34 208.38 3,532.85 3,491.05 -3,016.31 -1,665.15 6,028,880.83 543,010.09 0.00 3,371.12 5,300.00 54.34 208.38 3,591.15 3,549.35 -3,087.80 -1,703.77 6,028,809.12 542,971.90 0.00 3,450.77 5,400.00 54.34 208.38 3,649.44 3,607.64 -3,159.29 -1,742.39 6,028,737.41 542,933.71 0.00 3,530.42 5,448.82 54.34 208.38 3,677.90 3,636.10 -3,194.19 -1,761.25 6,028,702.40 542,915.07 0.00 3,569.30 Start Dir 5°/100':5448.82'MD,3677.9'TVD 5,500.00 56.67 207.09 3,706.88 3,665.08 -3,231.52 -1,780.87 6,028,664.95 542,895.67 5.00 3,610.74 5,600.00 61.25 204.74 3,758.44 3,716.64 -3,308.58 -1,818.26 6,028,587.68 542,858.75 5.00 3,695.36 5,700.00 65.87 202.60 3,802.96 3,761.16 -3,390.57 -1,854.17 6,028,505.49 542,823.34 5.00 3,784.26 5,800.00 70.51 200.60 3,840.10 3,798.30 -3,476.87 -1,888.31 6,028,418.99 542,789.72 5.00 3,876.77 5,900.00 75.18 198.72 3,869.60 3,827.80 -3,566.83 -1,920.43 6,028,328.85 542,758.14 5.00 3,972.18 6,000.00 79.86 196.92 3,891.21 3,849.41 -3,659.75 -1,950.29 6,028,235.76 542,728.84 5.00 4,069.78 6,109.67 85.00 195.00 3,905.65 3,863.85 -3,764.24 -1,980.16 6,028,131.10 542,699.61 5.00 4,178.43 End Dir :6109.67'MD,3905.65'TVD 6,200.00 85.00 195.00 3,913.53 3,871.73 -3,851.16 -2,003.45 6,028,044.05 542,676.84 0.00 4,268.36 6,300.00 85.00 195.00 3,922.24 3,880.44 -3,947.38 -2,029.23 6,027,947.68 542,651.64 0.00 4,367.92 6,400.00 85.00 195.00 3,930.96 3,889.16 -4,043.61 -2,055.01 6,027,851.31 542,626.44 0.00 4,467.48 9 518"x 12 114" 6,409.67 85.00 195.00 3,931.80 3,890.00 -4,052.91 -2,057.51 6,027,842.00 542,624.00 0.00 4,477.11 Start Dir 4°1100':6409.67'MD,3931.8'TVD-Schrader Bluff NB 6,500.00 88.61 195.00 3,936.83 3,895.03 -4,140,02 -2,080.85 6,027,754.76 542,601.19 4.00 4,567.23 6,572.17 91.50 195.00 3,936.76 3,894.96 -4,209.72 -2,099.52 6,027,684.96 542,582.93 4.00 4,639.35 End Dir :6572.17'MD,3936.76'TVD 6,600.00 91.50 195.00 3,936.03 3,894.23 -4,236.59 -2,106.72 6,027,658.04 542,575.89 0.00 4,667.15 6,700.00 91.50 195.00 3,933.41 3,891.61 -4,333.15 -2,132.60 6,027,561.34 542,550.60 0.00 4,767.06 6,800.00 91.50 195.00 3,930.80 3,889.00 -4,429.71 -2,158.47 6,027,464.64 542,525.31 0.00 4,866.97 6,900.00 91.50 195.00 3,928.18 3,886.38 -4,526.27 -2,184.34 6,027,367.93 542,500.02 0.00 4,966.87 7,000.00 91.50 195.00 3,925.56 3,883.76 -4,622.83 -2,210.22 6,027,271.23 542,474.73 0.00 5,066.78 7,100.00 91.50 195.00 3,922.94 3,881.14 -4,719.39 -2,236.09 6,027,174.52 542,449.44 0.00 5,166.69 7,200.00 91.50 195.00 3,920.33 3,878.53 -4,815.95 -2,261.96 6,027,077.82 542,424.15 0.00 5,266.59 7,300.00 91.50 195.00 3,917.71 3,875.91 -4,912.51 -2,287.84 6,026,981.12 542,398.86 0.00 5,366.50 7,400.00 91.50 195.00 3,915.09 3,873.29 -5,009.07 -2,313.71 6,026,884.41 542,373.57 0.00 5,466.40 7,500.00 91.50 195.00 3,912.47 3,870.67 -5,105.63 -2,339.58 6,026,787.71 542,348.28 0.00 5,566.31 10/24/2017 12:33:19PM Page 5 COMPASS 5000.1 Build 810 0 0 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU L-51 Company: Hilcorp Alaska,LLC TVD Reference: `MPU L-51 As-Built @ 41.80usft Project: Milne Point MD Reference: .MPU L-51 As-Built @ 41.80usft Site: M Pt L Pad North Reference: a True Well: Plan:MPU L-51 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-51 Design: MPU L-51 WP07 , '„ r� ;} Planned Survey c } '_ 0.,••,,,,I, ~ Measured VerticalMap ' Map : w Depth Inclination Azimuth Depth TVDss +N/-S +E/W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft ` (usft) (usft) ` (usft) (usft) • 3,869.83 7,532.21 91.50 195.00 3,911.63 3,869.83 -5,136.73 -2,347.92 6,026,756.56 542,340.14 0.00 5,598.49 Start Dir 4°I100':7532.21'MD,3911.63'TVD 7,600.00 91.50 192.29 3,909.85 3,868.05 -5,202.58 -2,363.90 6,026,690.62 542,324.55 4.00 5,666.13 7,669.66 91.50 189.50 3,908.03 3,866.23 -5,270.95 -2,377.06 6,026,622.18 542,311.80 4.00 5,735.37 End Dir :7669.66'MD,3908.03'TVD 7,700.00 91.50 189.50 3,907.23 3,865.43 -5,300.86 -2,382.06 6,026,592.24 542,306.98 0.00 5,765.44 1 7,800.00 91.50 189.50 3,904.62 3,862.82 -5,399.46 -2,398.56 6,026,493.56 542,291.07 0.00 5,864.56 Start Dir 4°/100':7800'MD,3904.62'TVD 7,908.59 91.58 185.16 3,901.70 3,859.90 -5,507.10 -2,412.40 6,026,385.85 542,277.88 4.00 5,971.55 End Dir :7908.59'MD,3901.7'TVD 8,000.00 91.58 185.16 3,899.18 3,857.38 -5,598.10 -2,420.62 6,026,294.80 542,270.22 0.00 6,060.98 8,100.00 91.58 185.16 3,896.43 3,854.63 -5,697.66 -2,429.60 6,026,195.20 542,261.83 0.00 6,158.82 8,200.00 91.58 185.16 3,893.67 3,851.87 -5,797.22 -2,438.58 6,026,095.60 542,253.45 0.00 6,256.66 8,300.00 91.58 185.16 3,890.92 3,849.12 -5,896.78 -2,447.56 6,025,996.00 542,245.07 0.00 6,354.50 8,400.00 91.58 185.16 3,888.16 3,846.36 -5,996.33 -2,456.55 6,025,896.40 542,236.68 0.00 6,452.34 8,500.00 91.58 185.16 3,885.41 3,843.61 -6,095.89 -2,465.53 6,025,796.80 542,228.30 0.00 6,550.19 8,600.00 91.58 185.16 3,882.65 3,840.85 -6,195.45 -2,474.51 6,025,697.20 542,219.92 0.00 6,648.03 8,685.78 91.58 185.16 3,880.29 3,838.49 -6,280.85 -2,482.22 6,025,611.76 542,212.73 0.00 6,731.95 Start Dir 4°/100':8685.78'MD,3880.29'TVD 8,700.00 91.57 185.72 3,879.90 3,838.10 -6,295.00 -2,483.56 6,025,597.61 542,211.46 4.00 6,745.88 8,800.00 91.50 189.73 3,877.22 3,835.42 -6,394.04 -2,497.00 6,025,498.50 542,198.63 4.00 6,844.52 8,822.37 91.48 190.62 3,876.64 3,834.84 -6,416.05 -2,500.95 6,025,476.47 542,194.81 4.00 6,866.73 End Dir :8822.37'MD,3876.64'TVD 8,900.00 91.48 190.62 3,874.64 3,832.84 -6,492.32 -2,515.25 6,025,400.12 542,180.97 0.00 6,943.85 9,000.00 91.48 190.62 3,872.06 3,830.26 -6,590.58 -2,533.67 6,025,301.76 542,163.14 0.00 7,043.21 9,100.00 91.48 190.62 3,869.47 3,827.67 -6,688.83 -2,552.09 6,025,203.41 542,145.31 0.00 7,142.56 9,200.00 91.48 190.62 3,866.89 3,825.09 -6,787.09 -2,570.52 6,025,105.06 542,127.47 0.00 7,241.91 9,300.00 91.48 190.62 3,864.31 3,822.51 -6,885.34 -2,588.94 6,025,006.70 542,109.64 0.00 7,341.26 9,400.00 91.48 190.62 3,861.72 3,819.92 -6,983.59 -2,607.36 6,024,908.35 542,091.81 0.00 7,440.61 9,500.00 91.48 190.62 3,859.14 3,817.34 -7,081.85 -2,625.79 6,024,810.00 542,073.98 0.00 7,539.96 9,600.00 91.48 190.62 3,856.56 3,814.76 -7,180.10 -2,644.21 6,024,711.64 542,056.15 0.00 7,639.31 9,700.00 91.48 190.62 3,853.98 3,812.18 -7,278.36 -2,662.63 6,024,613.29 542,038.32 0.00 7,738.66 9,800.00 91.48 190.62 3,851.39 3,809.59 -7,376.61 -2,681.06 6,024,514.94 542,020.49 0.00 7,838.02 9,900.00 91.48 190.62 3,848.81 3,807.01 -7,474.87 -2,699.48 6,024,416.58 542,002.66 0.00 7,937.37 10,000.00 91.48 190.62 3,846.23 3,804.43 -7,573.12 -2,717.90 6,024,318.23 541,984.83 0.00 8,036.72 10,100.00 91.48 190.62 3,843.64 3,801.84 -7,671.37 -2,736.33 6,024,219.87 541,967.00 0.00 8,136.07 10,200.00 91.48 190.62 3,841.06 3,799.26 -7,769.63 -2,754.75 6,024,121.52 541,949.17 0.00 8,235.42 10,300.00 91.48 190.62 3,838.48 3,796.68 -7,867.88 -2,773.17 6,024,023.17 541,931.33 0.00 8,334.77 10,400.00 91.48 190.62 3,835.90 3,794.10 -7,966.14 -2,791.60 6,023,924.81 541,913.50 0.00 8,434.12 10,500.00 91.48 190.62 3,833.31 3,791.51 -8,064.39 -2,810.02 6,023,826.46 541,895.67 0.00 8,533.47 10,600.00 91.48 190.62 3,830.73 3,788.93 -8,162.65 -2,828.44 6,023,728.11 541,877.84 0.00 8,632.83 10,700.00 91.48 190.62 3,828.15 3,786.35 -8,260.90 -2,846.87 6,023,629.75 541,860.01 0.00 8,732.18 10,800.00 91.48 190.62 3,825.57 3,783.77 -8,359.16 -2,865.29 6,023,531.40 541,842.18 0.00 8,831.53 10,900.00 91.48 190.62 3,822.98 3,781.18 -8,457.41 -2,883.71 6,023,433.05 541,824.35 0.00 8,930.88 11,000.00 91.48 190.62 3,820.40 3,778.60 -8,555.66 -2,902.14 6,023,334.69 541,806.52 0.00 9,030.23 10/24/2017 12:33:19PM Page 6 COMPASS 5000.1 Build 81D • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPU L-51 Company: Hilcorp Alaska,LLC TVD Reference: .'?.-„. MPU L-51 As-Built @ 41.80usft Project: Milne Point MD Reference: MPU L-51 As-Built @ 41.80usft Site: M Pt L Pad North Reference: True Well: Plan:MPU L-51 y Survey Calculation Method: Minimum Curvature Wellbore: MPU L-51 Design: MPU L-51 WP07 ` Planned Survey Measured Vertical Map - Map ., Depth Inclination Azimuth Depth TVDss +N/-S +E/-WNorthing -Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) - „ (usft) (usft) = 3,776,02 11,100.00 91.48 190.62 3,817.82 3,776.02 -8,653.92 -2,920.56 6,023,236.34 541,788.69 0.00 9,129.58 11,200.00 91.48 190.62 3,815.23 3,773.43 -8,752.17 -2,938.98 6,023,137.98 541,770.86 0.00 9,228.93 11,300.00 91.48 190.62 3,812.65 3,770.85 -8,850.43 -2,957.41 6,023,039.63 541,753.03 0.00 9,328.29 11,400.00 91.48 190.62 3,810.07 3,768.27 -8,948.68 -2,975.83 6,022,941.28 541,735.19 0.00 9,427.64 11,500.00 91.48 190.62 3,807.49 3,765.69 -9,046.94 -2,994.25 6,022,842.92 541,717.36 0.00 9,526.99 11,600.00 91.48 190.62 3,804.90 3,763.10 -9,145.19 -3,012.68 6,022,744.57 541,699.53 0.00 9,626.34 11,700.00 91.48 190.62 3,802.32 3,760.52 -9,243.44 -3,031.10 6,022,646.22 541,681.70 0.00 9,725.69 11,800.00 91.48 190.62 3,799.74 3,757.94 -9,341.70 -3,049.52 6,022,547.86 541,663.87 0.00 9,825.04 11,900.00 91.48 190.62 3,797.15 3,755.35 -9,439.95 -3,067.95 6,022,449.51 541,646.04 0.00 9,924.39 12,000.00 91.48 190.62 3,794.57 3,752.77 -9,538.21 -3,086.37 6,022,351.16 541,628.21 0.00 10,023.74 12,100.00 91.48 190.62 3,791.99 3,750.19 -9,636.46 -3,104.79 6,022,252.80 541,610.38 0.00 10,123.10 12,200.00 91.48 190.62 3,789.41 3,747.61 -9,734.72 -3,123.22 6,022,154.45 541,592.55 0.00 10,222.45 12,300.00 91.48 190.62 3,786.82 3,745.02 -9,832.97 -3,141.64 6,022,056.09 541,574.72 0.00 10,321.80 12,400.00 91.48 190.62 3,784.24 3,742.44 -9,931.22 -3,160.06 6,021,957.74 541,556.89 0.00 10,421.15 12,500.00 91.48 190.62 3,781.66 3,739.86 -10,029.48 -3,178.49 6,021,859.39 541,539.06 0.00 10,520.50 12,600.00 91.48 190.62 3,779.07 3,737.27 -10,127.73 -3,196.91 6,021,761.03 541,521.22 0.00 10,619.85 12,700.00 91.48 190.62 3,776.49 3,734.69 -10,225.99 -3,215.33 6,021,662.68 541,503.39 0.00 10,719.20 12,800.00 91.48 190.62 3,773.91 3,732.11 -10,324.24 -3,233.76 6,021,564.33 541,485.56 0.00 10,818.55 12,881.67 91.48 190.62 3,771.80 3,730.00 -10,404.49 -3,248.80 6,021,484.00 541,471.00 0.00 10,899.70 12,900.00 91.48 190.62 3,771.33 3,729.53 -10,422.50 -3,252.18 6,021,465.97 541,467.73 0.00 10,917.91 13,000.00 91.48 190.62 3,768.74 3,726.94 -10,520.75 -3,270.60 6,021,367.62 541,449.90 0.00 11,017.26 13,100.00 91.48 190.62 3,766.16 3,724.36 -10,619.00 -3,289.03 6,021,269.27 541,432.07 0.00 11,116.61 13,200.00 91.48 190.62 3,763.58 3,721.78 -10,717.26 -3,307.45 6,021,170.91 541,414.24 0.00 11,215.96 13,300.00 91.48 190.62 3,761.00 3,719.20 -10,815.51 -3,325.87 6,021,072.56 541,396.41 0.00 11,315.31 13,400.00 91.48 190.62 3,758.41 3,716.61 -10,913.77 -3,344.30 6,020,974.20 541,378.58 0.00 11,414.66 13,500.00 91.48 190.62 3,755.83 3,714.03 -11,012.02 -3,362.72 6,020,875.85 541,360.75 0.00 11,514.01 Total Depth:13500'MD,3755.83'TVD-4 1/2"x 8 1/2" Targets �°` , �� 1: :«�6spa Target Name W. .` `" , k -hit/miss target Dip Angle Dip Dir. TVD +N/-S Northing Easting -Shape (°) (°) (usft) (usft) - (usft) (usft) MPL-51 Heel wp2 0.00 0.00 3,931.80 -4,052.91 -2,057.51 6,027,842.00 542,624.00 -plan hits target center -Circle(radius 50.00) MPL-51 Toe wp2 0.00 0.00 3,771.80 -10,404.49 -3,248.80 6,021,484.00 541,471.00 -plan hits target center -Point 10/24/2017 12:33:19PM Page 7 COMPASS 5000.1 Build 81D 0 • Halliburton IIALLIBURTON Standard Proposal Report ,!.',-.1..- atabase Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: fr '. Well Plan:MPU L-51 Company: Hilcorp Alaska,LLC TVD Reference: MPU L-51 As-Built @ 41.80usft Project: Milne Point MD Reference: _ _ t,till tt,Vit4 MPU L-51 As-Built @ 41.80usft it Site: j M Pt L Pad North Reference: `` True Well: Plan:MPU L-51 Survey Calculation Method: Minimum Curvature { Wellbore: a MPU L-51 t3sts Design: MPU L-51 WP07 Casing Points Measured Vertical Hole ttitittiDepth Depth ® - i:. Diameter " (usft) (usft) 44?-3-i3Ottaitttt,,,t1tftKttititeittt44;;Strt.t'i-- (") 1 6,400.00 3,930.96 9 5/8"x 12 1/4 9-5/8 12-1/4 13,500.00 3,755.83 4 1/2"x 8 1/2" 4-1/2 8-1/2 Formations _- pt ` Measured Vertical Vertical Di " Depth ' Depth Depth SS` ® Direction (usft) (usft) ,.. (") a� 6,409.67 3,931.80 Schrader Bluff NB 0.00 Plan Annotations .. ._ F. rte, k. Measured Vertical Local Coordinates a Depth Depth +N/-S +E/.W .,t= tit- h . (usft) (usft) (usft) (usft) Comment t is 300.00 300.00 0.00 0.00 Start Dir 3°/100':300'MD,300'TVD 500.00 499.63 -6.00 -8.57 Start Dir 3.92°/100':500'MD,499.63'TVD 1,000.00 979.54 -111.62 -86.73 Start Dir 5°/100':1000'MD,979.54'TVD 1,588.47 1,427.61 -434.54 -270.32 End Dir :1588.47'MD,1427.61'TVD 5,448.82 3,677.90 -3,194.19 -1,761.25 Start Dir 5°/100':5448.82'MD,3677.9'TVD 6,109.67 3,905.65 -3,764.24 -1,980.16 End Dir :6109.67'MD,3905.65'TVD 6,409.67 3,931.80 -4,052.91 -2,057.51 Start Dir 4°/100':6409.67'MD,3931.8'TVD 6,572.17 3,936.76 -4,209.72 -2,099.52 End Dir :6572.17'MD,3936.76'TVD 7,532.21 3,911.63 -5,136.73 -2,347.92 Start Dir 4°/100':7532.21'MD,3911.63'TVD 7,669.66 3,908.03 -5,270.95 -2,377.06 End Dir :7669.66'MD,3908.03'TVD 7,800.00 3,904.62 -5,399.46 -2,398.56 Start Dir 4°/100':7800'MD,3904.62'TVD 7,908.59 3,901.70 -5,507.10 -2,412.40 End Dir :7908.59'MD,3901.7'TVD 8,685.78 3,880.29 -6,280.85 -2,482.22 Start Dir 4°/100':8685.78'MD,3880.29'TVD 8,822.37 3,876.64 -6,416.05 -2,500.95 End Dir :8822.37'MD,3876.64'TVD 13,500.00 3,755.83 -11,012.02 -3,362.72 Total Depth:13500'MD,3755.83'TVD 10/24/2017 12:33:19PM Page 8 COMPASS 5000.1 Build 81D Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-51 MPU L-51 MPU L-51 WP07 Sperry Drilling Services Clearance Summary Anticollision Report 24 October,2017 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt L Pad•Plan:MPU L-51-MPU L-51•MPU L-51 WP07 Well Coordinates: 6,031,906.80 N,544,656.92 E(70°29'52.95"N,149°38'05.29"W) Datum Height: MPU L-51 As-Built @ 41.80059 Scan Range:0.00 to 13,500.85 usS.Measured Depth. Scan Radius is 1,500.00 usft.Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build:81D Scan Type: ;•GLOBAL FILTER:Using user defined selection&filtering criteria • Scan Type: 25.00 MEM HALLIBURTON Sperry Drilling Services • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU L-51 -MPU L-51 WP07 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan:MPU L-51-MPU L-51-MPU L-51 WP07 Scan Range: 0.00 to 13,500.85 usft.Measured Depth. Scan Radius is 1,500.00 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-01-MPL-01-MPL-01 1,305.05 311.76 1,305.05 280.09 1,249.97 9.842 Ellipse Separation Pass- MPL-01-MPL-01-MPL-01 1,325.00 312.02 1,325.00 280.26 1,265.00 9.823 Clearance Factor Pass- MPL-01-MPL-01A-MPL-01A 1,305.05 311.76 1,305.05 280.09 1,249.97 9.842 Ellipse Separation Pass- MPL-01-MPL-01A-MPL-01A 1,325.00 312.02 1,325.00 280.26 1,265.00 9.823 Clearance Factor Pass- MPL-03-MPL-03-MPL-03 1,517.25 192.56 1,517.25 178.46 1,497.47 13.656 Ellipse Separation Pass- MPL-03-MPL-03-MPL-03 1,525.00 192.67 1,525.00 178.54 1,502.57 13.633 Clearance Factor Pass- MPL-13-MPL-13-MPL-13 1,233.75 163.80 1,233.75 149.54 1,229.46 11.491 Ellipse Separation Pass- MPL-13-MPL-13-MPL-13 1,300.00 171.72 1,300.00 156.09 1,275.39 10.987 Clearance Factor Pass- MPL-16-MPL-16-MPL-16 631.76 126.99 631.76 120.50 625.93 19.566 Centre Distance Pass- MPL-16-MPL-16-MPL-16 650.00 127.09 650.00 120.40 643.25 19.007 Ellipse Separation Pass- MPL-16-MPL-16-MPL-16 775.00 136.71 775.00 128.66 756.61 16.984 Clearance Factor Pass- MPL-16-MPL-16A-MPL-16A 631.76 126.99 631.76 120.50 625.93 19.566 Centre Distance Pass- MPL-16-MPL-16A-MPL-16A 650.00 127.09 650.00 120.40 643.25 19.007 Ellipse Separation Pass- MPL-16-MPL-16A-MPL-16A 775.00 136.71 775.00 128.66 756.61 16.984 Clearance Factor Pass- MPL-17-MPL-17-MPL-17 317.34 172.30 317.34 169.71 327.47 66.565 Centre Distance Pass- MPL-17-MPL-17-MPL-17 325.00 172.31 325.00 169.68 335.02 65.400 Ellipse Separation Pass- MPL-17-MPL-17-MPL-17 875.00 228.38 875.00 221.97 872.25 35.623 Clearance Factor Pass- MPL-20-MPL-20-MPL-20 1,053.90 84.40 1,053.90 74.06 1,049.57 8.159 Ellipse Separation Pass- MPL-20-MPL-20-MPL-20 1,100.00 85.07 1,100.00 74.53 1,095.64 8.072 Clearance Factor Pass- MPL-21-MPL-21-MPL-21 26.50 152.35 26.50 151.44 30.90 166.411 Centre Distance Pass- MPL-21-MPL-21-MPL-21 325.00 152.75 325.00 149.27 329.22 43.851 Ellipse Separation Pass- MPL-21-MPL-21-MPL-21 800.00 209.28 800.00 201.16 786.31 25.749 Clearance Factor Pass- MPL-24-MPL-24-MPL-24 26.50 75.08 26.50 74.27 34.00 93.361 Centre Distance Pass- MPL-24-MPL-24-MPL-24 450.00 76.01 450.00 72.71 457.15 23.076 Ellipse Separation Pass- MPL-24-MPL-24-MPL-24 750.00 84.71 750.00 79.22 753.17 15.429 Clearance Factor Pass- MPL-25-MPL-25-MPL-25 26.50 133.16 26.50 132.25 20.70 145.821 Centre Distance Pass- MPL-25-MPL-25-MPL-25 325.00 133.29 325.00 130.73 319.41 52.019 Ellipse Separation Pass- MPL-25-MPL-25-MPL-25 775.00 182.80 775.00 177.22 762.79 32.770 Clearance Factor Pass- 24 October,2017-12:52 Pegs 2 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU L-51 -MPU L-51 WP07 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan:MPU L-51-MPU L-51-MPU L-51 WP07 Scan Range: 0.00 to 13,500.85 usft.Measured Depth. Scan Radius is 1,500.00 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-28-MPL-28 473.26 43.28 473.26 38.39 482.18 8.850 Centre Distance Pass- MPL-28-MPL-28-MPL-28 525.00 43.57 525.00 38.18 533.83 8.089 Ellipse Separation Pass- MPL-28-MPL-28-MPL-28 650.00 48.39 650.00 41.76 657.67 7.305 Clearance Factor Pass- MPL-28-MPL-28A-MPL-28A 473.26 43.28 473.26 38.50 482.18 9.053 Centre Distance Pass- MPL-28-MPL-28A-MPL-28A 525.00 43.57 525.00 38.29 533.83 8.257 Ellipse Separation Pass- MPL-28-MPL-28A-MPL-28A 650.00 48.39 650.00 41.87 657.67 7.427 Clearance Factor Pass- MPL-29-MPL-29-MPL-29 50.00 119.36 50.00 118.39 60.11 122.355 Centre Distance Pass- MPL-29-MPL-29-MPL-29 75.00 11911 75.00 118.35 84.83 112.495 Ellipse Separation Pass- MPL-29-MPL-29-MPL-29 675.00 162.60 675.00 157.76 674.52 33.541 Clearance Factor Pass- MPL-32-MPL-32-MPL-32 26.50 14.81 26.50 13.90 21.35 16.173 Centre Distance Pass- MPL-32-MPL-32-MPL-32 675.00 18.29 675.00 11.29 669.49 2.614 Ellipse Separation Pass- MPL-32-MPL-32-MPL-32 700.00 18.59 700.00 11.34 694.43 2.564 Clearance Factor Pass- MPL-33-MPL-33-MPL-33 100.00 111.43 100.00 110.26 107.00 95.573 Centre Distance Pass- MPL-33-MPL-33-MPL-33 300.00 111.89 300.00 109.38 306.80 44.588 Ellipse Separation Pass- MPL-33-MPL-33-MPL-33 750.00 159.40 750.00 153.99 758.19 29.508 Clearance Factor Pass- MPL-34-MPL-34-MPL-34 1,364.88 328.90 1,364.88 315.81 1,282.74 25.110 Centre Distance Pass- MPL-34-MPL-34-MPL-34 1,375.00 328.96 1,375.00 315.76 1,290.78 24.921 Ellipse Separation Pass- MPL-34-MPL-34-MPL-34 5,225.00 607.09 5,225.00 522.44 5,597.48 7.172 Clearance Factor Pass- MPL-35-MPL-35-MPL-35 4,425.00 278.22 4,425.00 210.74 4,488.21 4.123 Clearance Factor Pass- MPL-35-MPL-35-MPL-35 4,442.59 278.11 4,442.59 210.71 4,503.95 4.126 Ellipse Separation Pass- MPL-35-MPL-35A-MPL-35A 4,425.00 278.22 4,425.00 210.74 4,489.01 4.123 Clearance Factor Pass- MPL-35-MPL-35A-MPL-35A 4,442.59 278.11 4,442.59 210.71 4,504.75 4.126 Ellipse Separation Pass- MPL-35-MPL-35APB1-MPL-35APB1 4,425.00 278.22 4,425.00 210.74 4,489.01 4.123 Clearance Factor Pass- MPL-35-MPL-35APB1-MPL-35APB1 4,442.59 278.11 4,442.59 210.71 4,504.75 4.126 Ellipse Separation Pass- MPL-35-MPL-35APB2-MPL-35APB2 4,425.00 278.22 4,425.00 210,74 4,489.01 4.123 Clearance Factor Pass- MPL-35-MPL-35APB2-MPL-35APB2 4,442.59 278.11 4,442.59 210.71 4,504.75 4.126 Ellipse Separation Pass- MPL-35-MPL-35APB3-MPL-35APB3 4,425.00 278.22 4,425.00 210.74 4,489.01 4.123 Clearance Factor Pass- MPL-35-MPL-35APB3-MPL-35APB3 4,442.59 278.11 4,442.59 210.71 4,504.75 4.126 Ellipse Separation Pass- MPL-36-MPL-36-MPL-36 3,896.89 316.72 3,896.89 267.57 4,167.67 6.443 Centre Distance Pass- MPL-36-MPL-36-MPL-36 3,950.00 318.10 3,950.00 265.72 4,211.48 6.073 Ellipse Separation Pass- MPL-36-MPL-36-MPL-36 4,125.00 340.87 4,125.00 279.97 4,357.90 5.597 Clearance Factor Pass- 24 October,2017-12:52 Page 3 of 8 COMPASS • • Hilcorp Alaska,LLC HALLI B U RTO N Milne Point Anticollision Report for Plan: MPU L-51 -MPU L-51 WP07 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt L Pad-Plan:MPU L-51-MPU L-51-MPU L-51 WP07 Scan Range:0.00 to 13,500.85 usft.Measured Depth. Scan Radius is 1,500.00 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-MPL-36L1-MPL-36L1 3,896.89 316.72 3,896.89 267.85 4,167.67 6.480 Centre Distance Pass- MPL-36-MPL-36L1•MPL-36L1 3,950.00 318.10 3,950.00 266.00 4,211.48 6.106 Ellipse Separation Pass- MPL-36-MPL-36L1-MPL-36L1 4,150.00 346.11 4,150.00 284.56 4,379.16 5.623 Clearance Factor Pass- MPL-36-MPL-36L1 PBI-MPL-36L1 PBI 3,896.89 316.72 3,896.89 267.78 4,167.67 6.471 Centre Distance Pass- MPL-36-MPL-36L1 PB1-MPL-36L1 PBI 3,950.00 318.10 3,950.00 265.93 4,211.48 6.098 Ellipse Separation Pass- MPL-36-MPL-36L1 PB1-MPL-36L1 PB1 4,125.00 340.87 4,125.00 280.18 4,357.90 5.817 Clearance Factor Pass- MPL-36-MPL-36PB1-MPL-36PB1 3,896.89 316.72 3,896.89 267.57 4,167.67 6.443 Centre Distance Pass- MPL-36-MPL-36PB1-MPL-36PB1 3,950.00 318.10 3,950.00 265.72 4,211.48 6.073 Ellipse Separation Pass- MPL-36-MPL-36PB1•MPL-36PB1 4,125.00 340.87 4,125.00 279.97 4,357.90 5.597 Clearance Factor Pass- MPL-37-MPL-37-MPL-37 6,382.32 186.65 6,382.32 108.31 6,590.38 2.383 Centre Distance Pass- MPL-37-MPL-37-MPL-37 6,700.00 210.92 6,700.00 46.74 6,884.78 1.285 Ellipse Separation Pass- MPL-37-MPL-37-MPL-37 6,725.00 215.71 6,725.00 47.40 6,907.42 1.282 Clearance Factor Pass- MPL-37-MPL-37A-MPL-37A 6,382.32 186.65 6,382.32 108.20 6,599.58 2.379 Centre Distance Pass- MPL-37-MPL-37A-MPL-37A 6,700.00 210.92 6,700.00 46.61 6,893.98 1.284 Ellipse Separation Pass- MPL-37-MPL-37A-MPL-37A 6,725.00 215.71 6,725.00 47.26 6,916.62 1.281 Clearance Factor Pass- MPL-39-MPL-39-MPL-39 1,581.80 193.12 1,581.80 179.27 1,496.93 13.939 Ellipse Separation Pass- MPL-39-MPL-39-MPL-39 3,975.00 745.50 3,975.00 657.35 3,953.68 8.457 Clearance Factor Pass- MPL-40-MPL-40-MPL-40 1,759.63 347.22 1,759.63 332.67 1,662.72 23.860 Ellipse Separation Pass- MPL-40-MPL-40-MPL-40 4,300.00 1,377.64 4,300.00 1,293.87 4,016.93 16.447 Clearance Factor Pass- MPL-43-MPL-43-MPL-43 26.50 198.36 26.50 197.65 35.50 282.196 Centre Distance Pass- MPL-43-MPL-43-MPL-43 225.00 198.80 225.00 196.53 232.63 87.688 Ellipse Separation Pass- MPL-43-MPL-43-MPL-43 800.00 260.66 800.00 254.59 777.59 42.972 Clearance Factor Pass- MPL-43-MPL-43PB1-MPL-43PB1 26.50 198.36 26.50 197.44 35.50 216.441 Centre Distance Pass- MPL-43-MPL-43PB1-MPL-43PB1 225.00 198.80 225.00 196.32 232.63 80.139 Ellipse Separation Pass- MPL-43-MPL-43PB1-MPL-43PB1 800.00 260.66 800.00 254.38 777.59 41.512 Clearance Factor Pass- MPL-45-MPL-45-MPL-45 449.01 190.25 449.01 187.05 457.32 59.389 Centre Distance Pass- MPL45-MPL-45-MPL-45 800.00 190.79 800.00 184.80 795.83 31.814 Ellipse Separation Pass- MPL45-MPL-45-MPL-45 5,100.00 1,498.62 5,100.00 1,362.76 5,150.15 11.030 Clearance Factor Pass- MPL-47-MPL-47-MPL-47 6,359.45 401.37 6,359.45 307.68 6,294.36 4.284 Centre Distance Pass- MPL-47-MPL-47-MPL-47 6,425.00 402.50 6,425.00 306.13 6,350.35 4.176 Ellipse Separation Pass- 24 October,2017-12:52 Page 4 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU L-51 -MPU L-51 WP07 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design:M Pt L Pad-Plan:MPU L-51-MPU L-51-MPU L-51 WP07 Scan Range: 0.00 to 13,500.85 usft.Measured Depth. Scan Radius is 1,500.00 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-47-MPL-47-MPL-47 6,525.00 407.58 6,525.00 308.42 6,428.31 4.110 Clearance Factor Pass- MPL-47-MPL-47 PBI-MPL-47 PB1 6,359.45 401.37 6,359.45 307.51 6,294.36 4.276 Centre Distance Pass- MPL-47-MPL-47 PB1-MPL-47 PB1 6,425.00 402.50 6,425.00 305.95 6,350.35 4.169 Ellipse Separation Pass- MPL-47-MPL-47 PB1-MPL-47 PBI 6,525.00 407.58 6,525.00 308.25 6,428.31 4.103 Clearance Factor Pass- MPL-48-MPL-48-MPL-48 5,080.57 244.06 5,080.57 212.46 5,264.70 7.723 Centre Distance Pass- MPL-48-MPL-48-MPL-48 5,175.00 246.78 5,175.00 210.06 5,347.11 6.720 Ellipse Separation Pass- MPL-48-MPL-48-MPL-48 5,450.00 294.55 5,450.00 240.76 5,573.11 5.476 Clearance Factor Pass- MPL-48-MPL-48PB1-MPL-48PB1 5,120.13 176.28 5,120.13 146.79 5,305.34 5.977 Centre Distance Pass- MPL-48-MPL-48PB1-MPL-48PB1 5,200.00 179.11 5,200.00 145.17 5,375.24 5.276 Ellipse Separation Pass- MPL-48-MPL-48PB1-MPL-48PB1 5,400.00 217.26 5,400.00 167.93 5,537.98 4.405 Clearance Factor Pass- MPL-48-MPL-48PB2-MPL-48PB2 5,153.39 172.88 5,153.39 143.58 5,339.71 5.901 Centre Distance Pass- MPL-48-MPL-48PB2-MPL-48PB2 5,200.00 174.39 5,200.00 142.43 5,377.17 5.456 Ellipse Separation Pass- MPL-48-MPL-48PB2-MPL-48PB2 5,375.00 210.16 5,375.00 165.45 5,507.52 4.700 Clearance Factor Pass- MPL-48-MPL-48PB3-MPL-48 PB3 5,080.57 244.06 5,080.57 212.29 5,264.70 7.682 Centre Distance Pass- MPL-48-MPL-48PB3-MPL-48 PB3 5,175.00 246.78 5,175.00 209.89 5,347.11 6.688 Ellipse Separation Pass- MPL-48-MPL-48PB3-MPL-48 PB3 5,450.00 294.55 5,450.00 240.59 5,573.11 5.459 Clearance Factor Pass- MPL-50-MPL-50-MPL-50 7,767.81 103.02 7,767.81 8.81 7,375.00 1.094 Centre Distance Pass- MPL-50-MPL-50-MPL-50 7,825.00 107.83 7,825.00 7.44 7,419.40 1.074 Clearance Factor Pass- Plan:MPU L-52-MPU L-52-MPU L-52 WP09 300.00 15.05 300.00 11.94 299.80 4.842 Centre Distance Pass- Plan:MPU L-52-MPU L-52-MPU L-52 WP09 375.00 15.21 375.00 11.45 374.78 4.045 Ellipse Separation Pass- Plan:MPU L-52-MPU L-52-MPU L-52 WP09 450.00 16.50 450.00 12.09 449.65 3.741 Clearance Factor Pass- Plan:MPU L-54-MPU L-54-MPU L-54 WP06 358.08 109.87 358.08 106.31 361.52 30.867 Centre Distance Pass- Plan:MPU L-54-MPU L-54-MPU L-54 WPO6 400.00 110.01 400.00 106.12 405.11 28.246 Ellipse Separation Pass- Plan:MPU L-54-MPU L-54-MPU L-54 WPO6 12,965.30 707.78 12,965.30 438.23 13,060.39 2.626 Clearance Factor Pass- Plan:MPU L-56-MPU L-56-MPU L-56 WP04 300.00 114.24 300.00 111.14 299.90 36.748 Centre Distance Pass- Plan:MPU L-56-MPU L-56-MPU L-56 WP04 325.00 114.40 325.00 111.08 324.90 34.394 Ellipse Separation Pass- Plan:MPU L-56-MPU L-56-MPU L-56 WP04 625.00 142.49 625.00 136.59 621.70. 24.144 Clearance Factor Pass- Plan:MPU L-57-MPU L-57-MPU L-57 WP04 253.93 110.88 253.93 108.20 253.93 41.349 Centre Distance Pass- Plan:MPU L-57-MPU L-57-MPU L-57 WP04 300.00 110.99 300.00 107.89 299.09 35.820 Ellipse Separation Pass- Plan:MPU L-57-MPU L-57-MPU L-57 WP04 550.00 139.30 550.00 134.17 537.45 27.153 Clearance Factor Pass- 24 October,2017-12:52 Page 5 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU L-51 -MPU L-51 WP07 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: M Pt L Pad-Plan:MPU L-51-MPU L-51-MPU L-51 WP07 Scan Range: 0.00 to 13,500.85 usft.Measured Depth. Scan Radius is 1,500.00 usft.Clearance Factor cutoff is Unlimited.Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Slte Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft RIG:MPU L-53-MPU L-53-MPU L-53 WP05 300.00 30.06 300.00 26.95 299.80 9.671 Centre Distance Pass- RIG:MPU L-53-MPU L-53-MPU L-53 WP05 500.00 30.69 500.00 25.97 500.10 6.494 Ellipse Separation Pass- RIG:MPU L-53-MPU L-53-MPU L-53 WP05 725.00 40.18 725.00 33.10 726.24 5.679 Clearance Factor Pass- Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 26.50 850.00 MPU L-51 WP07 SRG-SS 850.00 6,410.00 MPU L-51 WP07 MWD+IFR2+MS+sag 6,410.00 13,500.00 MPU L-51 WP07 MWD+IFR2+MS+sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles I(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 24 October,2017- 12:52 Page 6 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU L-51 -MPU L-51 WP07 Direction and Coordinates are relative to True North Reference. Vertical Depths am relative to MPU L-51 As-Built @ 41.80usft. Northing and Easting are relative to Plan:MPU L-51. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150.00",Grid Convergence at Surface is: 0.34°. -b- MNL-21,MNL-21,Mf'L-21 V4 Ladder Plot f MPL-24,MPL-24,MPL-24 V1 -4- MPL-25,MPL-25,MPL-25 V1 MPL-28,MPL-28,MPL-28 V14 r r r i i t O i i i i $ MPL-28,MPL-28A,MPL-28A V2 C I,r ._ ..`i, a____..q -e- MPL-29,MPL-29,MPL-29 V1 13 I !l'1 r i� :�' f� MPL-32,MPL-32,MPL-32 V9 "�t .i ��gi a r $ MPL-33,MPL-33,MPL-33 V4 O 11 J ,II $ MPL-34,MPL-34,MPL-34 V10 In I Aj 7, I ,ri' r� ° ii�l % $ MPL-35,MPL-35,MPL-35V6 r CO U ♦ -I- MPL-35,MPL-35A,MPL-35AV12 -� ! � �,�y 1 ;%I $ MPL-35,MPL-35APB1,MPL-35APB1 V5 900 f Lff If i $ MPL-35,MPL-35APB2,MPL-35APB2V3 c0 // 4 s d p E. 1/// I z ' ` -f- MPL-35,MPL-35APB3,MPL-35APB3V5 Cfl p Af �q } � BI - - MPL36,MPL-36,MPL-36V7fi 4' A 1.f: ' $ MPL-36,MPL-36L1,MPL-36L1 VO ,. C 1 1a,�I V'i' ial �„Iw" -I- MPL-36,MPL-36L1 PBI,MPL-36L1 P81 VO 1/ //b� l -� MPL-36,MPL36PB1,MPL-36PB1V3 v 450 Illlllil� 9/�%rd � �, ��itl;4��r s � !� � $ MPL-37,MPL-37,MPL-37 V3 EL2 / / „d�1 $ , G' $ MPL-37,MPL-37A,MPL-37AV1 f r •� oz* -3- MPL-39,MPL-39,MPL-39 V3 o _ '- t�i , -A- MPL-40,MPL-40,IhPL-40V4 � "'1 i $- MPL-43,MPL-43,M°L-43 V3 41- MPL-43,ruPL-43PB1,MPL-43PB1V5 0 2500 5000 7500 10000 12500 $ MPL-45,MPL-45,MPL-45W Measured Depth(2500 usft/in) $ MPL-47,MPL47,MPL47VO -9- MPL-47,MPL-47PB1,NPL-47PB1 V0 24 October,2017- 12:52 Page 7 of 8 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU L-51 -MPU L-51 WP07 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor .... ... I -. .._. -e- MPL-21,MPL-21,MPL-21 V4 ...... MPL-24,MPL-24,MPL-24 V1 10.00- ..!- • Ii } 9- -. ........ ......... ... -1MPL-25,MPL-25,MPL-25V1 � _. I I -N- MPL-28,MPL-28,MPL-28V14 I R^ $ MPL-28,MPL-28A,MPL-28AV2 8.75 ---- -- - ----- ------ -- -- $ MPL-29,MPL-29,MPL-29 V1 I \\Ili � i' e,.... , if- MPL-32,MPL-32,MPL-32 V9 + � $ MEEEI° 750---. .-...... a .......... M _ 1 le\ i r ., M N L;�89 ,'I r _..... Il N. ......__ -3- MPL-35,MPL-35A,MPL-35AV12 6.25- ...... _._._. ., Ua �j, �;''A-- I ��®.. � � $ MPL�5,MPL�5AP81,MPL�5APB1V5 0 LL i. °' ,.:;, II $ MPL-35,MPL-35AP82,MPL-35APB2V3 c 5.00- -- ----. -- - t ♦(- MPL-35,MPL-35APB3,MPL-35APB3V5 7:2 i pl - MPL-36,MPL-36,MPL-36 V7 n II. �! I. -� MPL-36,MPL-36LI,MPL-36L1 VO CO 3.75 - ---- ---- s 1 -- a: .....:_ ...... ......... _ ......... ......__ -4- MPL-36,MPL36L1 PB1,MPL-36L1 PB1 V0 _....,i, -tr. MPL-36,MPL-36PB1,MPL-36PB1 V3 _...... ,.. irI -e- MPL-37,MPL-37,MPL-37 V3 2.50 -_......... ......... ._...... - ,/ ... .. III ---- .....__._ -......__ _..._ -...._._._ ._....... $ MPL-37,MPL-37A,MPL37AV1 �► _—Collision Avoidance Req ` nJ ♦- MPL-39,MPL-39,MPL-39 V3 —No-Go Zone-Stop Dulling 1.25-.........__..------..__ ....................................................'..._c..........:.:.. -h- MPL-40, -40 V4 -40- MPL-43,MPL-43,MPL-43 V3 _.... -N- MPL-43,MPL-43PB1,MPL-43PB1 V5 0.00 a 1 1 I i i I i i i i i a a a a -'e- MPL45,MPL45,MPL45 V7 0 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 $ MPL-47,MPL-47,MPL-47V0 MeasuedDepth(25COusftfin) $ MPL47,MPL47PB1,MPL47PB1VO 24 October,2017-12:52 Page 8 of 8 COMPASS • • TRANSMITTAL LETTER CHECKLIST WELL NAME: 11 1 L. L'S PTD: 0217- - 1S V Development Service Exploratory Stratigraphic Test _Non-Conventional FIELD: 7)/1/M... AA1F POOL: in I '/ O v1/ 1 &ir /J: rj Check Box for Appropriate Letter I 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 v 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. 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