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218-109
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Convert to Gas Lift 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,079'N/A Casing Collapse Conductor N/A Surface 3,090psi Intermediate 5,410psi Liner 7,500psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Wells Manager Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Dual Packer w/ Vent Valve, 4.5" x 7" AHC & LTP Packers and N/A 2,931 MD/ 2,229 TVD, 11,139 MD/ 6,594 TVD & 11,273 MD / 6,719 TVD and N/A Scott Pessetto scott.pessetto@hilcorp.com 907-564-4373 Perforation Depth MD (ft): 12.6# / L-80 / EUE 8rd 11,031' 12,034' See Schematic See Schematic 4-1/2" 80' 20" 9-5/8" 7" 8,406' 4-1/2"761' 11,432' MD N/A 8,430psi 5,750psi 7,240psi 4,759' 6,899' 7,438' 8,440' 11,464' Length Size Proposed Pools: 80' 80' TVD Burst MILNE POINT STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509 & ADL355017 218-109 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23612-00-00 Hilcorp Alaska LLC C.O. 432E AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 8/15/2023 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT L-55 KUPARUK RIVER OIL N/A 7,481' 11,907' 7,318' 1,593 N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:59 pm, Aug 04, 2023 323-445 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.08.04 09:39:14 - 08'00' Taylor Wellman (2143) 8/15/2023 10-404 1,593 MGR04AUG23 SFD 8/9/2023 DSR-8/7/23GCW 08/09/2023JLC 8/9/2023 08/09/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.09 15:43:03 -08'00' RBDMS JSB 081123 Well: MPU L-55 Scope: Convert to Gas Lift Date: 07/24/2023 Well Name:MPU L-55 API Number:50-029-23612-00-00 Current Status:Producer [Shut in ESP]Pad:L-Pad Estimated Start Date:August 15th, 2023 Rig:Slickline Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:N/A Regulatory Contact:Tom Fouts Permit to Drill Number:218-109 First Call Engineer:Scott Pessetto (907) 564-4373 (801) 822-2203 Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) AFE Number:Job Type:Convert to Gas Lift Current Bottom Hole Pressure: 2,230 psi @ 6,369’ TVD Downhole Gauge |6.73 PPGE Maximum Hole Pressure:2,230 psi @ 6,369’ TVD Downhole Gauge |6.73 PPGE MPSP:1,593 psi (0.1psi/ft gas gradient) Max Deviation:63° @ 2,767’ MD (~61 deg sail starts at 2,100’ MD) Max Dogleg:6.5°/100ft @ 974’ MD Min ID:2.205” ID @ 10,895’ MD 2-7/8” XN-Nipple Brief Well Summary: Milne Point L-55 was drilled a Kuparuk reservoir producer in November 2018. The well was fracture stimulated and then converted to ESP artificial lift. The ESP failed in 2020 and the well has remained shut-in since. Hilcorp requests to convert the artificial lift status of MPU L-55 from ESP to gas lift. MPU L-55 has a vent packer and gas lift mandrel (GLM) above the packer. Objective: Convert MPL-55 from ESP lift to gas lift. Lift with gas lift from GLM at 2,867’ MD. Notes Regarding the Well & Design x Weatherford Hydro II Vent packer at 2,931’ MD. x 2-7/8” x 1” KBMG at 2,867’ MD. x 7” casing was tested to 3,500 psi on November 15, 2018 x Lift gas header pressure will operate at approximately 1,300 psi. o Fuel gas header 12-month maximum pressure was 1,349 psi on 8/20/22. Slickline (Non Sundried Work) 1. MIRU. PT PCE to 250 psi low / 3,000 psi high. 2. Close vent valve. PT IA to 1,500 psi for 30 minutes. 3. Pull dummy valve from GLM at 10,837’ MD. Leave open. 4. Pull dummy valve from GLM at 2,867’ MD. Install 3/16” orifice valve. 5. RDMO Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic _____________________________________________________________________________________ Revised By: TDF 12/26/2018 SCHEMATIC Milne Point Unit Well: MP L-55 Last Completed: 12/20/18 PTD: 218-109 TD = 12,079’ (MD) / TD =7,481’ (TVD) 20” Orig. KB Elev.: 33.7’ / GL Elev.: 16.0’ 7” 7 16 9-5/8” 1 Tbg Cut @ 11,094’ md 4 5 17 PBTD =11,907’ (MD) / PBTD =7,318’(TVD) 6 4-1/2” Shoe @ 12,034’ 8 ES Cementer @2,765’ 9 10 12 14 15 16&17 2 3 11 13 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 164 / A53B / Weld N/A Surface 80’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 8,440’ 0.0758 7” Intermediate 26 / L-80 / TXP 6.276 Surface 11,464’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP 3.958 11,273’ 12,034’ 0.0152 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 11,031’ 0.0058 OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 1 1,853 ft3/464 ft3, Stg 2 316 ft3, Top Job 650 ft3 9-7/8”x 8-1/2” 207 ft3 6-1/8” 112 ft3 WELL INCLINATION DETAIL KOP @ 300’ Max Hole Angle 58 deg TREE & WELLHEAD Tree 5M 4-1/16” Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23612-00-00 Cased by Doyon 14: 11/13/2018 ESP Completion by ASR – 12/20/2018 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk A2 11,795’ 11,801’ 7,211’ 7,217’ 6 3-1/8” 11/29/18 0pen Ref Log: 11/12/2018 Halliburton MWD JEWELRY DETAIL No. Top MD Item 12,867’ST 3: Camco 2-7/8” X 1'' Side pocket, DUMMY 2 2,931’ Dual Packer w/ Vent valve,Weatherford Hydro II 32,982’ST 2: Camco 2 7/8 X 1'' Side pocket GLM, DPSO 4 10,837’ST 1:Camco 2-7/8” X 1'' Side pocket, DUMMY 5 10,895’ 2-7/8” XN-Nipple – Min ID= 2.205” No Go 6 10,947.6’ Discharge Head: GPDIS 2 7/8" EUE 8Rd 7 10,948’ Pump 1: 134FLEX17.5 SXD 8 10,972’ Pump 2: 134FLEX17.5 SXD 9 10,995’ Gas Separator: GRS FER N AR 10 10,998’ Upper Tandem Seal: GSB3DBUT SB/SB PFSA 11 11,005’ Lower Tandem Seal: GSB3DBUT SB/SB PFSA 12 11,012’ Motor: XP, 200HP/ 3,635V/ 34 AMP 13 11,026’ Sensor: Zeneth E7 175C & Centralizer:Bottom @ 11,031’ 14 11,139’ 4-1/2” x 7” AHC Packer (Cut to Release) 15 11,144’ 4-1/2” XN Nipple -No-go = 3.725" 16 11,272’ Mule Shoe –Bottom @ 11,281’ 17 11,273’ Liner Top Packer WELL STIMULATION DETAIL Frac Well 12/7/2018 – Est. 200,852 lbs RCP 16-20 Carbobond Propant behind pipe. _____________________________________________________________________________________ Revised By: TDF 7/25/2023 PROPOSED Milne Point Unit Well: MP L-55 Last Completed: 12/20/18 PTD: 218-109 TD =12,079’(MD) /TD =7,481’ (TVD) 20” Orig. KB Elev.: 33.7’ / GL Elev.: 16.0’ 7” 7 16 9-5/8” 1 Tbg Cut @ 11,094’ md 4 5 17 PBTD =11,907’ (MD) /PBTD =7,318’(TVD) 6 4-1/2” Shoe @ 12,034’ 8 ES Cementer @2,765’ 9 10 12 14 15 16&17 2 3 11 13 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 164 / A53B / Weld N/A Surface 114’ N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 8,440’ 0.0758 7” Intermediate 26 / L-80 / TXP 6.276 Surface 11,464’ 0.0383 4-1/2” Liner 12.6 / L-80 / TXP 3.958 11,273’ 12,034’ 0.0152 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface 11,031’ 0.0058 OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 1 1,853 ft3/464 ft3, Stg 2 316 ft3, Top Job 650 ft3 9-7/8”x 8-1/2” 207 ft3 6-1/8” 112 ft3 WELL INCLINATION DETAIL KOP @ 300’ Max Hole Angle 58 deg TREE & WELLHEAD Tree 5M 4-1/16” Wellhead 5M FMC Gen IV GENERAL WELL INFO API: 50-029-23612-00-00 Cased by Doyon 14: 11/13/2018 ESP Completion by ASR – 12/20/2018 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk A2 11,795’ 11,801’ 7,211’ 7,217’ 6 3-1/8” 11/29/18 0pen Ref Log: 11/12/2018 Halliburton MWD JEWELRY DETAIL No. Top MD Item 1 2,867’ST 3: Camco 2-7/8” X 1'' GLM w/ Orifice Valve 2 2,931’ Dual Packer w/ Vent valve,Weatherford Hydro II 3 2,982’ST 2: Camco 2 7/8 X 1'' GLM, Orifice set 1/19/19 4 10,837’ST 1: Camco 2-7/8” X 1'' GLM, Open 5 10,895’ 2-7/8” XN-Nipple – Min ID= 2.205” No Go 6 10,947.6’ Discharge Head: GPDIS 2 7/8" EUE 8Rd 7 10,948’ Pump 1: 134FLEX17.5 SXD 8 10,972’ Pump 2: 134FLEX17.5 SXD 9 10,995’ Gas Separator: GRS FER N AR 10 10,998’ Upper Tandem Seal: GSB3DBUT SB/SB PFSA 11 11,005’ Lower Tandem Seal: GSB3DBUT SB/SB PFSA 12 11,012’ Motor: XP, 200HP/ 3,635V/ 34 AMP 13 11,026’ Sensor: Zeneth E7 175C & Centralizer:Bottom @ 11,031’ 14 11,139’ 4-1/2” x 7” AHC Packer (Cut to Release) 15 11,144’ 4-1/2” XN Nipple -No-go = 3.725" 16 11,272’ Mule Shoe –Bottom @ 11,281’ 17 11,273’ Liner Top Packer WELL STIMULATION DETAIL Frac Well 12/7/2018 – Est. 200,852 lbs RCP 16-20 Carbobond Propant behind pipe. David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchrage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE 09/10/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-55 (218-109) POLLARD SECTOR RADIAL CEMENT BOND LOG 11-21-2018 MPU L-55 Please include current contact information if different from above. Received by the AOGCC 09/10/2020 PTD: 2181090 E-Set: 33821 Abby Bell 09/10/2020 Debra Oudean 8Alaska, LLC 300 C GeoTech 3800 enterpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 rrarv, p,u,.A.J.ts: E-mail: doudean@hilcorp.com DATE 03/23/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 RECEIVED MAR 2 5 2020 AOGCC Halliburton LWD FINAL 20 DEC 2018 MPU L-55 _Log Viewers 12120/2018 5:37 PM File folder CGM 12120/2018 5:37 PM File folder Definitive Survey 17/20/2018 5:37 PM File folder EMF 12/2012018 5:37 PM File folder LAS 12/20/2018 5:37 PM Fite folder PDF 12/2012018 5:37 PM File folder TIFF 12/20/2018 5:37 P41 File folder Please include current contact information if different from above. 213109 32254 9 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 DATA SUBMITTAL COMPLIANCE REPORT 3/29/2019 Permit to Drill 2181090 Well Name/No. MILNE PT UNIT L•55 MD 12079 TVD 7841 REQUIRED INFORMATION Operator HILCORP ALASKA LLC Completion Date 12/19/2018 Completion Status 1 -OIL Current Status 1 -OIL Mud Log No Samples No DATA INFORMATION List of Logs Obtained: ROP-DGR-EWR-Phase 4-CTN-ALD MD, DGR-EWR-Phase 4-CTN-ALD TVD, CBL Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval Type Med/Frmt Number Name Scale Media No Start Stop ED C 30044 Digital Data 90 12080 ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data ED C 30044 Digital Data Log C 30044 Log Header Scans ED C 30214 Digital Data IED C 30214 Digital Data 0 0 10252 11896 11052 11891 OHI CH Received API No. 50-D29-23612-00-00 UIC No Directional Survey Yes (from Master Well Data/Logs) 11/23/2018 Electronic Data Set, Filename: MPU L-55 DGR ABG EWR.Ias F 11/23/2018 Electronic File: MPU L-55 LWD Final MD.cgm 11/23/2018 Electronic File: MPU L-55 LWD Final TVD.cgm 11/23/2018 Electronic File: MPU L-55—Definitive Survey Report.pdf 11/23/2018 Electronic File: MPU L-55—Definitive Survey Report.txt 11/23/2018 Electronic File: MPU L-55 GIS. 11/23/2018 Electronic File: MPU L-55 LWD Final MD.emf 11/23/2018 Electronic File: MPU L-55 LWD Final TVD.emf 11/23/2018 Electronic File: MPU L-55 LWD Final MO.pdf 11/23/2018 Electronic File: MPU L-55 LWD Final TVD.pdf 11/23/2018 Electronic File: MPU L-55 LWD Final MD.tif 11/23/2018 Electronic File: MPU L-55 LWD Final TVD.tif 11/23/2018 Electronic File: EMFView3_1.zip 11/23/2018 Electronic File: Readme.bd 2181090 MILNE PT UNIT L-55 LOG HEADERS 1/8/2019 Electronic Data Set, Filename: Hilcorp_MPU_L- 55_SCMT_28Nov2018_ConCu_Main500PSl.las 1/8/2019 Electronic Data Set, Filename: Hilcorp_MPU_L- 55_SCMT_28Nov2018_ConCu_Repeat3000PS1.1 as AOGCC Page 1 of 3 Friday, March 29, 2019 ri DATA SUBMITTAL COMPLIANCE REPORT 3129/2019 Permit to Drill 2151090 Well Name/No. MILNE PT UNIT L-55 Operator HILCORP ALASKA LLC API No. 50-029-23612-00-00 MD 12079 TVD 7841 Completion Date 12/19/2018 Completion Status 1-011- Current Status 1-0I1- UIC No ED C 30214 Digital Data 11196 11896 1/8/2019 Electronic Data Set, Filename: Hilcorp_MPU_L- 55_SCMT_28Nov2018_ConCu_Repeat500PSl.la s ED C 30214 Digital Data 1/8/2019 Electronic File: Hilcorp_MPUL- 55 SCMT 28Nov2018 ConEu Main500PSI.dlis ED C 30214 Digital Data 1/8/2019 Electronic File: Hilcorp_MPU_L- 55_SCMT_28Nov2018_ConCu_Repeat3000PS1. dlis ED C 30214 Digital Data 1/8/2019 Electronic File: Hilcorp_MPU_L- 55_SCMT_28Nov2018_ConCu_Repeat500PS I.dli s ED C 30214 Digital Data 1/8/2019 Electronic File: Hilcorp_MPU_L- 55_SCMT_28Nov2018_FI NAL.pdf Log C 30214 Log Header Scans 0 0 2181090 MILNE PT UNIT L-55 LOG HEADERS Well Cores/Samples Information Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion Report 0.,, Production Test InformatioNA Geologic Markers/Tops COMPLIANCE HISTORY Completion Date: 12/19/2018 Release Date: 9/17/2018 Description Directional / Inclination Data D Mud Logs, Image Files, Digital Data Y / I`& Core Chips Y 16 Mechanical Integrity Test Information jjYY/�/ NA Composite Logs, Image, Data Files 0 Core Photographs Y / 1� Daily Operations Summary LY/ Cuttings Samples Y / R Laboratory Analyses Y /4�) Date Comments AOGCC Page 2 of 3 Friday, March 29, 2019 DATA SUBMITTAL COMPLIANCE REPORT 3/29/2019 Permit to Drill 2151090 Well Name/No. MILNE PT UNIT L-55 Operator HILCORP ALASKA LLC MD 12079 TVD 7841 Completion Date 12/19/2018 Completion Status 1-0I1- Current Status 1-0I1. Comments: Compliance Reviewed By: API No. 50.029-23612.00.00 UIC No AOGCC Page 3 of 3 Friday, March 29, 2019 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, January 30, 2019 3:18 PM To: 'Taylor Wellman' Subject: RE: MP L-55 (PTD #218-109) Operation with a Vent Packer Installed Taylor, You have approval to vent through the packer as proposed below. The IA vent line has a SSV that is tied into the SVS. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal low. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 1 or (Guv schwartz@alaska.aov). From: Taylor Wellman <twellman@hilcorp.com> Sent: Tuesday, January 29, 2019 1:51 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: MP L-55 (PTD #218-109) Operation with a Vent Packer Installed Guy, Sorry it took so long to get the piping schematic. Enclosed is the redlined drawing for what we plan to install for the shutdown of the annular vent line. There is a solenoid that will receive the shut in signal from the shutdown panel (the same one that will be sent to shut in the SSV) and then shut in a valve to close the vent line from the IA. Let me know if you have any further questions on the proposed diagram. Thanks, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcoro.com From: Taylor Wellman Sent: Sunday, January 27, 2019 2:44 PM To: 'Schwartz, Guy L (DOA)' Subject: MP L-55 (PTD #218-109) Operation with a Vent Packer Installed Guy, Milne Point well L-55 (PTD #218-109) was drilled, hydraulically fracture stimulated and then completed with an ESP. During the time of the completion we had differing pieces of information about what the true reservoir pressure was in the Kuparuk A sands (above or below 8.55ppg). We elected to run the ESP packer into the completion. Now that we have produced the well for a while we have taken a new BHP and found the reservoir pressure to be —1,850psi @ 6,487' and (5.5ppg). With the reservoir pressure well below the 8.55ppg requirement for an ESP packer in accordance with CO 390 and be in line with 20 AAC 25.200(d), we would request to operate the well with the vent valve in the open position. We would also not perform the drawdown test of the annular space above the packer during the bi-yearly SVS testing. If this is acceptable or if you have any questions/would like any further information please let me know. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman(a)hilcorp.com tl IW n M/4 „ 9M N �' 168 lVY 1 M WT M InYFA0Y911R/0 MAS 1WM OP MLL flAM MJIM 1. .1 N.1NS PSI 9,[/11T1�11}jM` Ago, AM _ _ I- _ I I I I I I I�II•n lnlnYR _ _ K. I I I t*• I I � 11 t 1 u � >H• no /r—I L^� vAa ml I DIM Mflna Yr rm1m rv® X. I me1t --- n I— — \I 1J I I I I I I I I I I I C YnLv � i; ' rvl° m i gmsn•� ' i i i � ��� 91 NPBM 9 py 9 9 �Q I I n I I I n I I Irq B I I x I 1:• lbw 66} n I '• NYM as L — •wa — ? f I Mij NM � Lam' � � � � • � I n : yr L I LL..•- uxass I-- -- Ic ` aw uo¢vuvrc69sA1usuimNM" ma ®vNlmnoa B CON, "'7 .._.�I.i o OuPly ST 71. DSGN/CNA L 1 •. _ W1 F�, ����mmmmwm=� OMMOM � STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JAN 15 2019 WELL COMPLETION OR RECOMPLETION REPORT AN 1a. Well Status: Oil [2] Gas SPLUG ❑ Other ❑ Abandoned ❑ Suspended 20AAC 25.105 20A C 25.110 GINJ ❑ WINJ ❑ WAG[—] WDSPL ❑ No. of Completions: _ 1 1b. Well Class: rA... k -'F Development Q Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Abend.: 12/19/2018 14. Permit to Drill Number/ Sundry: 218-109 / 318-483 / 318-518 / 318-545 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: October 19, 2018 15. API Number: 50-029-23612-00-00 4a. Location of Well (Governmental Section): Surface: 3610' FSL, 5024' FEL, Sec 8, T13N, R10E, UM, AK Top of Productive Interval: 889' FSL, 1523' FEL, Sec 32, T14N, R10E, UM, AK Total Depth: 967' FSL, 1506' FEL, Sec 32, T14N, R10E, UM, AK 8. Date TO Reached: November 10, 2018 16. Well Name and Number: , MPU L-55 9. Ref Elevations: KB: 49.7' GL:16' BF:16' 17. Field / Pool(s): Milne Point Field Kuparuk Oil Pool 10. Plug Back Depth MD1TVD: 11,907' MD / 7,318' TVD 18. Property Designation: ADL025509 / ADL355017 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 544853 y- 6031799 Zone- 4 TPI: x- 548279 y- 6039659 Zone- 4 Total Depth: x- 548295 y- 6039736 Zone- 4 11. Total Depth MD1TVD: 12,079' MD / 7,481' TVD 19. DNR Approval Number: LONS 88-002 12. SSSV Depth MD1TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,538' MD / 1,886' TVD 5. Directional or Inclination Survey: Yes � (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD1TVD: 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 EWR-Phase 4, CTN, ALD MD, DGR, EWR-Phase 4, CTN, ALD TVD, CBL CASING, LINER AND CEMENTING RECORD WT. PER GRADE CASING FT SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 20" 164# A53B Surface 117' Surface 117' Driven N/A 9-5/8" 40# L-80 Surface 8,440' Surface 4,759' 12-1/4" Stg 1 L- 785 sx / T 00 sx k p j-4 Stg 2 L - 270 sx - 150 sx 7" 26# L-80 Surface 11,464' Surface 6,899' 9-7/8" 180 sx 4-1/2" 12.6# L-80 11,273' 12,034' 6,720' 7,439' 6-1/8" 145 sx 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 11,795' - 11,801' MD / 7,211' - 7,217' TVD 6 SPF, 22.7 gram, 11/29/18 COMPLETION DATE tt 9I lid I-- — VERIFIED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" 11,031' 2,931' MD / 2,070' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No Per 20 AAC 25.283 (1)(2) attach electronic and printed information DEPTH INTERVAL (MD) 1AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: 1/4/2019 Method of Operation (Flowing, gas lift, etc.): ESP Date of Test: 1/9/2019 Hours Tested: ',?-y MCa Production for Test Period Oil -Bbl: 614 Gas -MCF: 161 Water -Bbl: 35.7 Choke Size: N/A Gas -Oil Ratio: 262.2 Flow Tubing Press. 250 Casing Press: 1060 Calculated 24 -Hour Rate _-J� Oil -Bbl: 614 Gas -MCF: 161 Water -Bbl: 35.7 Oil Gravity - API (corr): 26 Form 10-407 Revised 5/2017 ( _ COQ INUED ON PAGE 2 RBDMS M(I JAN I G' 2C19 Submit ORIGINAL on(�` a.�at�lq Il���l 28. CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cares: Yes ❑ No ❑� If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑✓ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 2,538' 1,886' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 11,795' Kup A 7,211' information, including reports, per 20 AAC 25.071. Ugnu 3,763' 2,486' Schrader 7,200' 4,157' HRZ 11,361' 6,803' Kuparuk C 11,679' 7,102' KuparukA 11,771' 7,188' Formation at total depth: jMiluveach 31. List of Attachments: Wellbore Schematic, Drilling, Completion and Frac Reports, Definitive Directional Surveys, Csg and Cmt Reports, Frac Focus & Vendor Frac Summary/Plots. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manag9f Contact Email: Cdin of hIICOf .00t71 Authorized on/r Contact Phone: 777-8389 Signature: Date: y rS' 10(q IN TRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: 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 K Hacoro Alaska. LLC Ong. KB Elev.: 33.7 / GL Hey.: 16.0' ES Cementer @2,765' Pp�K-ER- aa31'p.p 2 ' a r 4� Tbg Cur @ 11,094' and13 �rA� 5r r, _JT SCHEMATIC Milne Point Unit Well: MP L-55 Last Completed: 12/20/18 PTD: 218-109 TREE & WELLHEAD Tree 5M 4-1/16" Wellhead li SM FMC Gen 1V OPEN HOLE / CEMENT DETAIL Conductor a 12-1/4" Stg 11,853 ft3/464 ft3, Stg 2 316 ft3, Top Job 650 ft3 9-7/8"x 8-1/2" 207 ft3 6-1/8" 5 Conductor 164/A53B/Weld N/A Surface 114' s 9-5/8" Surface 7 8.835 Surface 1 8 0.0758 7" 9 26/L-80/TXP 6.276 10 11,464' 0.0383 11 Liner 4� Tbg Cur @ 11,094' and13 �rA� 5r r, _JT SCHEMATIC Milne Point Unit Well: MP L-55 Last Completed: 12/20/18 PTD: 218-109 TREE & WELLHEAD Tree 5M 4-1/16" Wellhead li SM FMC Gen 1V OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 11,853 ft3/464 ft3, Stg 2 316 ft3, Top Job 650 ft3 9-7/8"x 8-1/2" 207 ft3 6-1/8" 112 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 114' N/A 9-5/8" Surface 40/L-80/TXP 8.835 Surface 1 8,440' 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface 11,464' 0.0383 4-1/2" Liner 12.6 / L-80 / TXP 3.958 11,273' 12,034' 0.0152 TUBING DETAIL 2-7/8" Tubing 6.5/L-80/EUE8rd 1 2.441 1 Surface 11,031' 0.0058 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle 58 deg JEWELRY DETAIL No. Top MD Item 1 2,867' ST 3: Camco 2-7/8" X 1" GLM, SHR VLV 2500# IA to TBG 2 2,931' Dual Packer w/ Vent valve,Weatherford Hydro II 3 2,982' ST 2: Camco 2 7/8 X 1" GLM, DUMMY 1-3-19 4 10,837' ST 1: Camco 2-7/8" X 1" GLM, DUMMY 5 10,895' 2-7/8" XN-Nipple - Min I1)=2.205"No Go 6 10,947.6' Discharge Head: GPDIS 2 7/8" EUE 8Rd 7 10,948' Pump 1: 134FLEX17.5 SXD 8 10,972' 1 Pump 2: 134FLEX17.5 SXD 9 10,995' Gas Separator: GRS FER N AR 10 10,998' Upper Tandem Sea]: GSB3DBUTSB/SB PFSA 11 11,005' Lower Tandem Seal: GSB3DBUT SB/SB PFSA 12 11,012' Motor: XP, 200HP/ 3,635V/ 34 AMP 13 11,026' Sensor: Zeneth E7 175C & Centmlizer: Bottom @ 11,031' 14 11,139' 4-1/2" x 7" AHC Packer (Cut to Release) 15 11,144' 4-1/2"XN Nipple -No -o=3.725" 16 11,272' Mule Shoe - Bottom @11,281' 17 11,273' Liner Top Packer WELL STIMULATION DETAIL Frac Well 12/7/2018 -Est. 200,852lbs RCP 16-20 Carbobond Propant behind pipe. PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Kuparuk A2 11,795' 11,801' 7,211' 7,217' 6 3-1/8" 11/29/18 qopnS Ref Log: 11/12/2018 Halllburton MWD 4-1/7'moi.'. Shoe @ 12,034' 1 TD=12,079' (MD) /TD= 7,481' (TVD) PBTD =11,907 (MD) / PBTD = 7,318' (TVD) GENERAL WELL INFO A P I: 50-029-23612-00-00 Cased by Doyon 14:11/13/2018 ESP Completion by ASR -12/20/2018 Revised By: TDF 12/26/2018 nHilcorp Energy Company Composite Report Well Name: MP L-55 Field: Milne Point Unit County/State: Prudhoe Bay, Alaska i (LAT/LONG): avation (RKB): 33.67 API #: Spud Date: 1 0/1 912 01 8 Job Name: 1813265D MPL-55 DRILLING Contractor AFE #: 1813265D AFE $: $4,746.573 Activity Da ie s. Summary 10/17/2018 See L-41 report for details.;RD and prep to skid the rig floor.; Skid the rig Floor into moving position.Move the rig off of well L-41 ;Move the rig around the pad to L-55.;Spot the rig over well L-55.;PJSM. Skid the rig Floor into drilling posftion.;RU the rig Floor. RU the diverter pipe on the off drillers side. Set rig mats for the rock washer. Sini Turn the power off on the entire rig and change out the highline breaker.;Continue to RU the diverter pipe. Work on rig acceptance checklist. 10/18/2018 Continue work on rig acceptance checklist. Changeout mud manifold. Attempt to put the rig on highline but new breaker not working. Pull the breaker and repair.;Load, strap and tally 246 joints of 5" DS -50 DP. Continue work on rig acceptance checklist. Rig accepted at 12:00 houm.;Continue to process S DP. Continue to repair highline breaker. Load, strap, drift and tally 95/8" casing. Spot and RU mud man and MWD shacks. Clear ice buildup on the derrick. Torque surface annular and diverter tee. Rig on highline at 13:00 hours.;PU and MU 67 stands of 5" DS -50 DP. Sini Spot the upright water tank with the crane and spot the pump house. Load the pits with spud mud.;Hydmulic leak on the ST -80 iron roughneck. Changeout hose and stainless steel line. SimOps: Add 20" tee to the diverter line and realign. Function test the diverter system and MU 15 stands of 5" DS -50 DP.;PU and MU 5 stands of 5" HWDP. PU and MU 1 stand of 5" HWOP with drilling jar;Slip and cut 60' (9 wraps) drilling line. 10/19/2018 Continue to process 9-5/8" Casing. Walk location with AOGCC inspector Guy Cook an take measurements of diverter line. Decide two more extensions are needed to keep 75' away from end of vent to Vac trucks loading. Call out another 16" diverter extension. Take rig off high line as per Milne Point.;Perform Qdiverter test & accumulator draw down. Good. Knife valve opened in 12 sec. Annular closed in 26 sec. Test gas alarms and PVT. Good. Install 40' extension on end of vent line. Wait for another to arrive.;Crew change with new crew. Install another 40' extension on end of vent line. Take measurements to closest ignition source. 79' from vac truck while loading. Total Vent line Length 216', Vent from Sub structure 209'. Move all items from edge of pad in vent path.;Send pictures of vent line and request to proceed to the state. We got a verbal to proceed at 16:15 hours. M/U 12-1/4" Kymera bit & motor to stand of HWDP & prep to spud'Attemo[to put rig back on high line and had issues closing breaker. Trouble shoot and recheck. Good. Rig back on high line at 16:15 hours.;Spud well at 1700, 400 GPM 20 RPM. Tagged bottom at 118'. Drilled to 129'& displaced to 8.8 ppg spud mud. Had 2.5 bbl spill to rig mats and cellar due to 3" trip tank fill up line unhooked for MPD. Notified ACS and pad operator.;Drill ahead from 129' to 219' at 450 GPM = 630 psi, 40 RPM = 1-4K ft -lbs torque.;TOOH. PU and MU MWD/LWD tools. Scribe line and obtain offset to UBHO.;RU Pollard E -line with Halliburton (Scientific Drilling) gyro. Simi Upload MWD tools.;Finish PU and MU directional drilling assembly to 176'.;Ream to bottom at 2191. Drill 12- 1/4" surface hole from 219'to 389. Stand stand back, MU jar stand and RIH. Drill from 380' to 544' (543' TVD). Taking gyro surveys every stand. Started build section at 300' (3'/100).;450 GPM = 800 psi, 40 RPM = 0-1 K ft4bs torque, WOB = 10K, MW = 9.2 ppg, Vis = 241, ECD = 9.8 ppg, Max gas = 0 units PU = 65K, SO = 70K, ROT = 69K.;Hauled 75 bbls H2O from L -Pad lake for total= 75 bible Hauled 48 bbls cuttings/liquids to MPU G&I for total= 48 bbls;Last survey at 349' MD, 349' TVD, 3.26° Inc, 36.76° Az. Distance to Well Plan #17 = 5.59'(4.39 high and 1.43' left). 1020/2018 Drill ahead 12.25 Hole F/ 544'T/ 628'475 GP 1100 PSI, 5-10 WOB Sliding 90 %. Take last Gyro survey at 628' ;Drill ahead 12.25 Hole F/ 628' T/ 1043'. Continue build 4°1100. 500 GPM, 1260 PSI, 5-10 WOB MW 9.1 Vis 189, ECD 10.1 50 RPM 2-5K TO. Released Scientific gyro after three clean surveys at 919'.;Drill 12-1/4" surface hole from 1043'to 1676 (1429' TVD), AROP = 105.5 FPH. Continue build 5'/100 473 GPM = 1230 psi, 60 RPM= 2-4Kft-lbs torque, WOB = 5K, MW = 9.2 ppg, Vis = 145, ECD = 10.6 ppg, Max gas = 29 units PU = 96K, SO = 84K, ROT = 85K.;Drill 12-1/4" surface hole from 1676' to 2205' (1725' TVD), AROP = 88.2 FPH. Continue build 5°/100 to 1710'then maintain 60" inclination. 483 GPM = 1460 psi, 60 RPM = 3-5K ft -lbs torque, WOB = 5K, MW = 9.2 ppg, Vis = 188, ECD = 10.7 ppg, Max gas = 51 units PU = 105K, SO = 80K, ROT = 85K.;Drill 12-114" surface hole from 2205' to 2995' (2101' TVD), AROP = 131.7 FPH. Maintaining 60" inclination. Estimated base of permafrost= 2450'.490 GPM = 1390 psi, 50 RPM= 8-10K ft -lbs torque, WOB = 5K, MW = 9.3 ppg, Vis = 144, ECD = 10.2 ppg, Max gas = 80 units PU = 110K, SO = 85K, ROT = 88K.;Hauled 1170 bbls H2O from L -Pad lake for total= 1245 bbls Hauled 1158 bbls cuttings/liquids to MPU G&I for total= 1206 bbls;Last survey at 2579' MD, 1905 TVD, 61.89° Inc, 23.32° Az. Distance to Well Plan #17 = 2.76' 1.30' low and 2.43' ri h 10/21/2018 Drill 12-1/4" Surface hole F12995' T/ 3747', 752' with AROP of 125 FPH. Maintaining 60" inclination. 475 GPM = 1890 psi, 50 RPM = 8-10K ft -lbs torque, WOB = 5K, MW = 9.2+ ppg, Vis = 144, ECD =10.3 ppg, Max gas = 105 units PU = 130K, SO = 85K, ROT = 105K.;Pump a hi vis sweep at 3465' with 50% increase in cuttmg.;Drill 12-1/4" Surface hole F/3747' T/ 4317', 567' with AROP of 114 FPH. Maintaining 609 inclination. 475 GPM = 1890 psi, 50 RPM = 8- 10K ft -lbs torque, WOB = 5K, MW = 9.2 ppg, Vis = 144, ECD = 10.0 ppg, Max gas = 123 units PU = 130K, SO = 85K, ROT = 105K.;Pump a hi vis sweep at 4034' wfth 20% increase in cuthng.;The top drive would not breakout of the connection (gripper dies slipping). Breakout with tongs from the top drive and changeout the top drive gripper dies. Saver sub showing signs of extreme wear (very sharp).;Stand back stand that was over torqued. MU head pin with cement line and circulate at 2 BPM while changing the saver sub on the top drive.;Drill 12-1/4" surface hole from 4317' to 4503' (2849' TVD), 186with AROP of 93 FPH. Maintaining 60° inclination. 577 GPM = 1870 psi, 80 RPM = 6-9K ft -lbs torque, WOB = 2-4K, MW = 9.3+ ppg, Vis = 161, ECD =10.0 ppg, Max gas = 33 units. PU = 147K, SO = 92K, ROT = 101 12-1/4" surface hole from 4503' to 4587' (2883' TVD), 84' with AROP of 84 FPH. Maintaining 60" inclination. 577 GPM = 1870 psi, 80 RPM = 6.9K ft -lbs torque, WOB = 24K, MW = 9.3+ ppg, Vis = 161, ECD = 9.9 ppg, Max gas = 58 units PU = 147K, SO = 92K. ROT = 106K.;Drag chain to the rock washer fell of the sprocket. Reinstall the drag chain ;Drill 12-1/4" surface hole from 4587' to 5164 (3164' TVD), 577' with AROP of 128.2 FPH. Maintaining 60" inclination. 585 GPM = 2250 psi, 80 RPM = 10-12K ft -lbs torque, WOB = 10-20K, MW = 9.2 ppg, Vis = 131, ECD = 10.4 ppg, Max gas = 75 units PU = 160K, SO = 95K, ROT = 120K.;Pump a hi vis sweep at 4975' with 10% increase in cutting.;Hauled 1035 bbl$ H2O from L -Pad lake for total= 2280 bbis Hauled 1100 bbls cuttings/liquids to MPU G&I for total= 2306 bbls;Last survey at 4937' MD, 3051' TVD, 61.97° Inc, 22.85° Az. Distance to Well Plan #17= 8.07'(1.09 high and 8.07' right). 10222018 Drill 12-1/4" Surface Hole F/ 5164'T/ 5630 , 466' AVFPH @ 77 FPH. Maintaining 60" inclination. 585 GPM = 2250 psi, 80 RPM= 10-12K ft-lbs torque, WOB = 10-20K, MW = 9.2 ppg, Vis = 131, ECD = 10.3 ppg, Max gas = 125 units PU = 160K, SO = 95K, ROT = 120K.;Drill 12-1/4" Surface Hole F/ 5630'T/ 5720, 90' AVFPH @ 90 FPH. Maintaining 60° inclination. 585 GPM = 2300 psi, 80 RPM = 10-12K ft-lbs torque, WOB = 10-20K, MW = 9.2 ppg, Vis = 131, ECD = 10.3 ppg, Max gas = 75 units PU = 160K, SO = 95K, ROT = 120K.;Lost swab on #1 Pump #3 Cylinder. Replace same. Circ at 1.5 bpm while changing swab.;Drill 12-1/4" Surface Hole F/ 5720'T/ 6111 , 391' @ 86.9 FPH. Maintaining 60° inclination. 585 GPM = 2300 psi, 80 RPM = 10-12K ft-lbs torque, WOB = 10-20K, MW = 9.2 ppg, Vis = 131, ECD = 10.3 ppg, Max gas = 87 units PU = 160K, SO = 95K, ROT = 120K.;Pumped weighted hi vis sweep with 3 sacks of walnut at 6016' with 40% increase in cuttings.;DnII 12-1/4" surface hole from 611 V to 6603' (3864' TVD), 492' wfth AROP of 82 FPH. Maintaining 60" inclination. 525 GPM = 1740 psi, 80 RPM =16K ft-lbs torque, WOB = 12K, MW = 9.2 ppg, Vis = 131, ECD = 9.5 ppg, Max gas = 123 units PU = 200K, SO = 95K, ROT = 130K.;At 6230' oil started blinding off the shakers. Slowed the pump rate to 500 GPM and treated with ScreenKleen.;Drill 12-1/4" surface hole from 6603' to 7052'(4086 TVD), 449' with AROP of 74.8 FPH. Maintaining 60° inclination. 587 GPM = 2270 psi, 80 RPM= 17-201(ft-lbs torque, WOB = 10- 15K, MW = 9.1 ppg, Vis = 118, ECD = 10.2 ppg, Max gas = 35 units PU = 205K, SO = 95K, ROT = 125K.;Hauled 1465 bbis H2O from L-Pad lake for total= 3745 bbis Hauled 1795 bbis cuftings/liquids to MPU G&I for total= 4101 bbls;Last survey at 6825' MD, 3975' TVD, 60.72' Inc, 25.19° Az. Distance to Well Plan #17 = 1023/2018 Drill 12-1/4" surface hole from 7052' to 7429' (4269' TVD), 377' with AROP of 62.8 FPH. Maintaining 60" inclination. 586 GPM = 2330 psi, 80 RPM = 17- 20K ft-lbs torque, WOB = 15-17K, MW = 9.1+ ppg, Vis = 112, ECD = 10.3 ppg, Max gas = 55 units PU = 225K, SO = 90K, ROT = 146K.;Pump 30 bbl hi vis sweep w/ 5 ppb nut plug @ 7140', sweep back on time with 10% increase.;Drill 12-1/4" surface hole from 7429' to 781 0'(4436' TVD), 381' with AROP of 63.5 FPH. Maintaining 60° inclination. 586 GPM = 2430 psi, 80 RPM = 18-22K ft-lbs torque, WOB = 20-22K, MW = 9.2+ ppg, Vis = 92, ECD = 10.1 ppg, Max gas = 123 units PU = 230K, SO = 97K, ROT = 137K.;Drill 12-114" surface hole from 781 Vie 8157' (4638' TVD), 347' with AROP of 57.6 FPH. Maintaining 60" inclination. 585 GPM = 2520 psi, 80 RPM = 19-23K ft-lbs torque, WOB = 23K, MW = 9.2 ppg, Vis = 77, ECD = 10.2ppg, Max gas = 101 units PU = 240K, SO = 95K, ROT = 140K.;Drill 12-1/4" surface hole from 8157'to 8302' (4695' TVD), 145' with AROP of 24.2 FPH. Maintaining 60° inclination. 595 GPM = 2447 psi, 80 RPM =16-21K ft-lbs torque, WOB =20K, MW = 9.1 + ppg, Vis = 82, ECD = 9.8 ppg, Max gas =112 units PU=240K, SO=95K, ROT= 140K.;Hauled 1820 bbis H2O from L-Pad lake for total= 5565 bbis Hauled 1,264 bbis cuttings/liquids to MPU G&I for total= 5,365 bbls;Last survey at 8241' MD, 4665' TVD, 61.23° Inc, 23.92° Az. Distance to Well Plan #17= 6.18' (5.87' low and 1.90' left). 10/24/2018 Drill 12-1/4" surface hole from 8302' to 8374' (4727' TVD), 72' with AROP of 12 FPH. Maintaining 60° inclination. 592 GPM = 2580 psi, 80 RPM = 18-23K ft- Ibs torque, WOB = 20-32K, MW = 9.1+ ppg, Vis = 78, ECD = 9.6 ppg, Max gas = 74 units PU = 247K, SO = 99K, ROT = 156K.;At 8304' Pump 30 bbl hi vis sweep w/ 5 PPB nut plug, back on time with no increase.;Drill 12-1/4" surface hole from 8374'to 8450' (4764' TVD), 76' with AROP of 19 FPH. Maintaining 60" inclination, 600 GPM = 2500 psi, 80 RPM = 18-23K ft-lbs torque, WOB = 20-32K, MW = 9.1 ppg, Vis =100, ECD = 9.6 ppg, Max gas = 70 units PU = 245K, SO= 105K, ROT= 150K.;TD surface section. Take final survey. Flow check well, static. Last survey at 8410' MD, 4745' TVD, 62.35" Inc, 23.37" Az. Distance to Well Plan #17 = 1.25' (1.11' low and 0.58' left).;BROOH at 600 GPM = 2350 psi, 80 RPM from 8450' to 8261' racking 2 stds back.;Pump tandem 30 bbl to vis sweep followed with 30 bbi hi vis 10.6 ppg, 5 ppb nut plug sweep pumping 600 GPM = 2350 psi, 80 RPM, reciprocate 90'. Circulate the sweep outwith 5% increase in cuttings. Circulate and condition the mud lowering the yield point to 25.;Observe the well for flow and the well is static. TIH from 826l'to TO at 8450'.;BROOH at 5 min per stand, 600 GPM, 80 RPM from 8450' to 5064'.;Hauled 1780 bbls H2O from L-Pad lake for total= 7,345 bbls Hauled 1,757 bbis cuftings/liquids to MPU G&I for total= 7,122 bbis 10/25/2018 Continue to BROOH at 5 min per stand, 600 GPM, 1750 psi, 80 RPM, 10-11 k tq from 5064'to 3173'. Treat mud while BROOH.;Continue to BROOH at 5 min per stand, 600 GPM, 1650 psi, 80 RPM, 4-8k tq from 3173', some slight packing off at 2413' at a correction slide area, no issues cleaning up, hole started unloading @ 1750'.;Circulate hole clean @ 1750' pumping 600 gpm, 1550 psi, 80 rpm, working pipe slow. Mostly sand with some clay.;Continue BROOH at 5 min per stand, 600 GPM, 80 RPM from 1750'to 732' (HW DP).;POOH on elevators from 732' to 546. At 545' observed a 30K overpull. SO to 600', MU the top drive and BROOH at 5 min per stand, 600 GPM, 80 RPM from 600'to 392'. POOH on elevators from 392' to 176.;Lay down 3 non mag flex collars. Download MWD data. Lay down remainder of the drilling assembly. Bit and stabilizer balled with clay. Bit grade= 3-5-LT-A-E-1/16-BT-TD.;Clean and clear the rig floor. Offload equipment from the rig floor.;Mobilize casing equipment to the rig floor. RU Doyon casing running tool (CRT). RU 8' bail extensions and 9-5/8" elevators. RU 9-5/8" air slips. Monitor the well on the trip tank. 4 BPH static Ioss.;PJSM for PU and running 9-5/8" casing.;PU and MU the shoe track; baker lok each connection and torque to 20960 ft-lbs. Check the float (good).;Hauled 1,480 bbis H2O from L-Pad lake for total= 8,825 bbis Hauled 1,445 bbis cuftings/liquids to MPU G&I for total= 8,567 bbls 10262018 RIH 9-5/8" 40# L-80 UP casing f/ 157' T/ 2076', RIH 10-15 fpm to keep from pushing fluid away. Torque connections to 20,960 ft/Ibs. Fill on the fly & top off Tv-e77 en cacu ate 10 bbis. Note: Install centralizers on every It to It 22, then every other to jt 114. Static loss rate 6-7 bph RIH.;Continue to RIH 9-5/8" casing f/ 2076' T/ 3380' at 81 jts. RIH 10-15 fpm to keep from pushing fluid away. Fill on the fly & top off every 10 then circulate 10 bbls. Static loss rate continues at 6-7 bph RIH, losses at 58 bible total. Install centralizer every other joint.;CBU @ 3380' Staging pumps to 3.5 BPM, 190 psi working pipe slow. Lost 7 bbis during the circulation ;Continue to RIH 9-5/8" casing from 3380'to 5550', RIH 10-15 FPM to keep from pushing fluid away. Fill on the fly & top off every 10 then circulate 10 bbis. Install centralizer every other joint to #114.;CBU staging the pumps up to 3.5 BPM = 300 psi reciprocating slowly from 5530' to 5550'. Lost 16 bbis during the circulation.;Continue to RIH with 9-5/8" casing from 5550'to 5648' at 10-15 FPM to prevent pushing fluid away. Fill on the fly, top off every 5 joints and circulate 10 bbis every 10 joint. PU and MU ESIPC to 5688' per Halliburton representative. Install 1 centralizer on joints #135 to #138.;Continue to RIH with 95/8" casing from 5688' to 6940' at 10-15 FPM to prevent pushing fluid away. Fill on the fly, top off every 5 joints and circulate 10 bbis every 10 joint. Install 1 centralizer on joints #138 to #147. Then every other joint to #203. Loss rate= 2 BPH.;Hauled 0 bbis H2O from L-Pad lake for total= 8,825 bbls Hauled 420 bbis Heated H2O from G&I for total= 420 bbis Hauled 366 bbis cuttings/liquids to MPU G&I for total= 8,933 bbls;Daily losses to the formation = 141 bbis 10/27/2018 Break circulation and appear to have slight pack off. Stage the pumps up to 3 BPM = 560 psi and work the pipe from 6940' to 6904'. Pumped 80 bbis and regained full circulation. Lost 8 bbis during the circulation.;Continue to RIH with 9-5/8" casing from 6940'to 8300' (203jts) at 10-15 FPM to prevent pushing fluid away. Fill on the fly, top off every 5 joints and circulate 10 bbis every 10 joint. Continue to install 1 centralizer every other joint to #203. Loss rate continues at 2 BPH.;M/U jt 204, wash down last 3 jts f/ 8300' to 8440' (PU = 365K & SO = 90K) staging pump to 2 bpm, 580 psi ( 206 jts ran, includes cut jt. ) 116 solid bow spring centralizers). Total losses TIH and circulating= 168 bbis.;Condftion mud prior to cementjob. Stage pump slowly to 6 BPM, 340 PSI, reciprocate pipe 20', MW 9.4 PPG, 62 vis in 19.4 ppg, 200 vis out. Add water 30/50 bph, reduce mud MW to 9.2 ppg with 47 vis, YP @ 23. Rotate string slow after BU, currently 4.3 bph loss rate, 24 bbls total.;Shut off MP, Blow down top drive, close lower IBOP. R/U cement hose, continue to circulate 6 bpm, reciprocate and rotate pipe. Finish off loading 290 blols f/ pits.;PJSM for pumping 1st stage cement. Flood the lines with 5 bbis of fresh water and PT lines to 1000/4500 psi for 5 minutes each (good test). Submitted 24 hr BOPE test notification to AOGCC @ 19:35 hrs.;Pump first stage cement job. Pump 60 bbls of 0.0 VING cleans aver. Mix and pump329 bbis of 12.0 ppq lead cement at 6 BPM = 500 Psi. Rotated & reciprocated casing until away. Place the casing on depth. Mix and pump 82 bbis of 15.8 ppg tail cement at 2 BPM = 300 psi ;Attempt to release the CRT but were unable to. Attempt multiple times without success. The connection below the top drive kept breaking out. Notify town engineer while continuing to attempt to release the CRT. While discussing options and making a plan forward the CRT released.;Drop the shut off plug and pump 22 bbis of fresh water. Displace with the rig with 608 bbis of mud at 9 BPM = 400 psi to 1900 strokes where caught up with the cement. Slowed the pumps to 3 BPM = psi and slowly bring the rate to S BPM = 1050 psi to 3900 strokes.;Slowed the pump to 6 BPM = 1160 psi to 5800 strokes. Slowed the pumps to 3 BPM = 1000 psi until the shutoff plug bumped at 6015'strokes (607.5 bbis). Lost 114 bbls while displacing.;Pressure up to 1500 psi and hold for 5 minutes. Bleed the pressure off, check the floats and the floats are holding. Pressure up to 2100 psi and hold for 5 minutes. Bring the pressure up to 2300 psi and hold for 5 minutes.;While bring the pressure up to 2600 psi, at 2550 psi the pressure dropped to 950 psi but did not see return. Attempt to establish return but unable to after 33.3 bbis pumped.;Discuss option with HES expert in Houston. Notify HAK town engineer and discuss options.;Pump 50 bbis at 3 BPM = 1030 psi with no returns. Shut down the pumps and 5 minutes later returns were observed. Pump 10 bbls at 3 BPM = 950 psi wfth no returns. Shutdown the pumps and 3 minutes later returns were observed. Pump 6 blots at 0.5 BPM = 400 psi with no returns.;Shut down the pumps and returns were observed. Pumped 66 bbls and lost 51 bbls.;Discuss options with town engineer.;Drop contingency free fall opening plug and pump down at 8 BPM, ICP = 2900 psi and FCP = 2550 psi. Slowed the pumps to 5 BPM =1500 but no indication of the plug seating. Pumped 212 bbis (2.3 bbls over calculated displacement).;Shut down the pumps and observed returns. Total of 54 bbis returned. Monitored the well and the well was static.;Continue to monitor the well and wait on cement. 10/28/2018 Monitor well and WOC. Discuss options with town team on plan forward. Decision made to split stack, install 9 5/8" casing slips, cut casing, flange diverter back up, then M/U 5" stinger, TIH with 5" DP and push ESIIPC opening bomb on seat. RIH with cmt retainer.;Drain the riser and vac out the 9-5/8" casing to ground level. Release the CRT. Review with town team not to run cement retainer, unable to locate 9 5/8" 2nd stage bottom plug.;Review with town team not to run cement retainer, unable to locate 9 5/8" 2nd stage bottom plug. Discuss new plan forward. SimOps: Service the top drive and draw works. Build 200 bbis of spud mud.;PJSM. Cut the 9-518" casing 2' above the rotary table. Lay down the cut joint and RD the CRT.;PJSM. RU 3-1/2" handling equipment. Load, p, drift and tally 100 joints 3-1/2" EUE 8rd Mod tubing in the pipe shed.;PJSM. PU and MU the stack wash tool with crossovers. RIH with assembly on 3- '1(1V(/ /2" tubing from surface to tag of free fall opening plug at 2765.23' with 10K down per Halliburton. Did not see any indication of pushing the plug downhole at anytime while RIH.;POOH laying down 3-1/2" tubing from 2765.23'to surface. Lay down crossovers and stack wash tool.;Hauled 150 bbis H2O from L-Pad \ lake for total= 8,975 bbis Hauled 300 bbls Heated H2O from G&I for total= 960 bbis Hauled 563 bbls cutflngs/liquids to MPU G&I for total= 9,843bbis;Daily losses to the formation = 206 bbis Total losses to the formation = 534 bbl 10/29/2018 RID 31/2" Handling equipment and power tong. R/U Volant tool and set in 9 5/8 casing stump M/U same.;Pump thru Volantto confirm ESICP tool is in open positron, Pump staging from 1 BPM =460 psi to 8 BPM= 2350 psi with no returns, 100 bbis pumped, shut pump off, pressure bled to 250 psi. No returns observed. Bleed off pressure, BD Imes.;W/O decision from town team for plan forward. Decision made to pump 10 bbl water spacer followed with 56 bbis 15.8 ppg tail, drop closing plug,+ displace cmt and close ESICP tool. Perform cement top job.;R/U cementers, load 50 jts 1 1/4" CSH and mule shoe jt into pipe shed.;PJSM, pump 10 bbl fresh water, PT lines to 4000 psi. Mix and pump 56 bbis 15.8 ppg premium tail cement (270 sx, 5.091 gps, 1.166 YP) 2 bpm, 560 psi, drop closing plug, pump 20 bbis water 4 bpm, 840 psi, with rig pump displace w/ 190 bbis 9.2+ ppg mud 4 bpm, 720 intial psi building. No returns.;1200 psi, 180 bbis away, slow pump to 2 bpm, 840 psi. bump closing plug @ 190 bbis pumped at calculated, pressure to 2140 psi and shift cementer tool closed, hold pressure for 5 min, good, bleed off pressure, no flow. BD lines. CIP @ 13:50 hrs.;R/D Volant tool. R/U 1.66" handling equipment and power tongs. strap and tally CSH. Submit plan for top rob to AOGCC. State rep Adam. Earl will witness tag depth.;PJSM. RIH with 1.66" OD CS Hydril work string to 607! Attempt to rotate and wash down without success. Lay down joint #20 and end of the pipe is at 589' ;MU the head pin and circulating equipment. Circulate and condition the mud at 2 BPM = 550 psi.;PJSM. Pump 10 bbls of fresh P water. PT lines to 1000/3000 psi for 5 minutes each (good test). Begin pumping 10.7 ppg cement taking returns to the pits. At 69 bbis away a PH spike was `u ^ �v observed in the returns and returns were diverted to the cellar.;At 108 bbis away good cement at surface; 11.0 ppg verified on pressurized mud scale. Pumped remaining cement that was mixed for a total of 115 bbls.;Wash upthe cemen truc an cemen ine. Blow down the cementers.;POOH laying down 1.66" OD x �IVh CS Hydril work string from 589'to surtace.;RD the false table and 1.66" handling equipment. Clean the floor. Suck out the 9-5/8" joint to the wellhead.;Flush .—J surface stack and work annular three times with black water pill.;Remove the turn buckles from the riser. Remove the bolts from the knife valve and diverter tee. Break the bolts below the diverter tee.;Split the stack and lift. Install the 9-5/8" casing slips and land the casing with 100K on the slips.;Cut the casing and pull the cutjoint from the stack. Dress the stump. Release the CRT and lay down.;Set the stack down. Pull the riser, ND the knife valve, NO the diverter tee, ND the DSA and ND the annular. Remove the diverter equipment from the cellar.;Hauled 245 bbls H2O from L-Pad lake for total= 9,220 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbis Hauled 92 bbis cuttings/liquids to MPU G&I for total= 9,935bbis 10/30/2018 Clear rig floor, Clean and clear cellar. Make final cut and dress 9 5/8" casing slum .;Install wellhead and orient same as per well head rgp. Install tbg spool. Test slip lock seal to 2475 psi @ 80�578"36>f' - co apse pressure.;N/U ROPE, turn buckles, kill line . Torque tubing spool and BOP flange bolts.;R/U and rotate MPD head, N/U same, R/U MPD lines. Install trip nipple. Install mouse holes.;lnstall test plug & test joint. Fill BOP stack, choke and kill lines. Perform / a body test - good.;Test BOP equipment as per PTD & AOGCC requirements. Upper 2-7/8"x5" VBR tested on 4" & 5" test joints. Lower 4-1/2"x7" VBR tested on 5" & 7" test joints. Test 14 choke valves, upper & lower SOP, manual & HCR kill valves. Test 4-1/2" IF FOSV & dart valves. Test XT-39 FOSV & dart 'J valves.pnnular tested to 250 PSI low 12500 PSI high on 4" & 7" test joints. All other tests to 250 PSI low 14000 PSI high. Atl tests held for 5 min. & charted. d) it Accumulator test: Start 3000 psi, after close 1700 psi, Build 200 psi 32 sec, Full recovery in 177 sec. Six nitrogen bottles @ 2075 psi avg.;Test gas, PVT & flow Test 19:47 27 Oct. AOGCC inspector Adam Earl the tests. Sim-ops: load 7" into the \ alarms. notification sent on witnessed clean mud pits and casing pipe shed.;R/D test joint, blow down choke lines and manifold.;Puil trip nipple & install MPD test cap. Pump through MPD equipment. Pressure test MPD equipment to 250/1500 PSI. Remove MPD test cap & install trip nipple. Fill stack & check for leaks - none. Remove test plug & install wear bushing.;Mobilize 8-1/2" cleanout BHA components to the rig floor. Adjust mud motor bend to 1.22°.;Hauled 175 bbis H2O from L-Pad lake for total= 9,395 bbls Hauled 0 bbis Heated H2O from G&I for total= 960 bbis Hauled 962 bbls cuttings/liquids to MPU G&I for total= 10,879bbls 10/31/2018 Finish M/U BHA 2, 81/2" VM3 MTB, 1.22 motor, flt sub w/ non ported plunger, 6 stands HWDP with jars= 586.78'.;Drift, P/U and single in with 42 jts 5" NC50 DP f/ 586' to 1890', Single in with 5" DS50 DP to 2715' just above ESICP. Fill pipe.;Wash down pumping 7 bpm 420 psi, 30 rpm 3k tq V 2715' to 2760', drill plugs and cementer tool. 2-8K wob, 30-50 rpm, 2-4k tq. f/ 2760' to 2763', ream 2 times and then pass thru with pump off. Note: plug rubber and small amounts of fiberglass from opening bomb seen at shakem.;Continue to drift, P/U and single in with 5" DS50 DP f/ 2763' to 4236 ( 75 jts total DS50 DP ) Continue TIH on stds 1/ 4236' to 8033' filling pipe @ 5000' and 7000'.;Wash down 2 bpm, 350 psi V 8033' to 8295' setting down 5k on good cement 20' above the baffle adaptor, TOOH to 8221' racking 1 std back. P/U 265K, S/O 85K.;Slip and cut 66' of drilling line. Service top drive and inspect saver sub - good.;R/U to pressure test casing. Pressure test 9-5/8" casing to 2500 PSI for 30 minutes - good test. 6.2 bbis pumped and 6.2 bats bled back. RID test equipment and blow down all Iines.;30 bbis mud leaked from pit #3 to #4. Mud pump #1 suction valve in pit#3 failed. Transfer mud out of pit 03. Attempted to pump with #1 pump, but was sucking air. Decision to continue ahead with only #2 mud pump while repairing suction valve.;Drill cement from 8295' then baffle adapter 8308'to 8310'. Drill float collar from 8346' to 8347'. Drill shoe from 8431' to 8432'. Shoe track averaged 8' higher than the tally. Cleanout rathole from 8432' to 8450'. 500 GPM, 1500 PSI, 50 RPM, 20K TO, 5K WOB.;Drill 6-1/2" hole from 8450'to 8470'. 600 GPM, 2200 PSI, 50 RPM, 21 K TO, 22K WOB. 285K PUW, 85K SOW, 137K ROT.;Pump 30 bbl 9.5 ppg high viscosity spacer. Displace wellbore from 9.2 ppg spud mud to 9.5 ppg LSND mud. 7 BPM, 630 PSI ICP, 7 BPM, 585 PSI FCP.;Hauled 180 bbis H2O from L-Pad lake for total= 9,575 bbis Hauled 0 bbis Heated H2O from G&I for total= 960 bbis Hauled 241 bbis cuftingslliquids to MPU G&I for total= 11,120 bbis 11/1/2018 Clean shakers and line up returns to mud pits. Perform flow check- static. Obtain slow pump rates with new mud. POOH racking back 1 std parking in the 9 518" casing at 8412'. Blow down top drive.P/U 240K, SIO 103K. Perform 12.5 pea FIT 0.8440' MD / 4759' TVD with 9.5 nog LSND mud. Pressure up to 743 PSI. Pumped 1.8 bbls and bled back 1.5 bals. Closed upper pipe rams and pumped down the drill pipe and kill line. Rig down equipment and blow down Iines.;Flow check well, static. TOOH on elevators If 8412'to 586 at the HWDP. UD 6 jts HWDP. rack back 4 stds HWDP w/jars. UD motor and bit. Grade= 1, 1,WT,A,E,I,NO,BHA. Note w/ lubes in mud casing drag almost diminished. Correct displacement on trip out.;Clear and clean rig floor, Load BHA components to the rig floor, PJSM.;M/U RSS/UR BHA #3 w/ 8.5" SK616MJ1 D PDC bit, Geo-Pilot W/ STB, DM, DGR, ILS, EWR-P4, PWD, HCIM, TM, FS NP plunger, PC, UR, FS NP flapper, PC, FS NP flapper, IBS, 6-HWDP, Jars, 5-HWDP. = 511.10'. (Bit to UR = 111.26). Download MWD and shallow pulse test - good, C/O Jars due to hm.;TIH from 51 V to 2396'. Break-in Geo-Pilot seals and function test MWD Geo-Span downlink. TIH from 2396'to 8402', filling pipe every 2000'. Obtain slow pump rates then wash down from 8402'to 8470'. 195K PUW, 103K SOW.;Drill 8-1/2" hole from 8479to 8591' (80.7 AROP). 500 GPM, 1760 PSI, 60 RPM, 15-16K TO, 15K WOB. 9.5 MW in, 9.5 MW out, 46 vis in, 47 vis out. 10.45 ECD. 17u max gas. 190K PUW, 103K SOW, 141 K ROT.;Obtain baseline values at 350 GPM, 1010 PSI & 500 GPM, 1750 PSI, 1750 pusler RPM. Drop 1-3/8" reamer activation ball & pump down with 350 GPM, 1010 PSI. Observe ball on seat @ 897 stks with pressure drop to 940 PSI. Increase to 500 GPM observed 1600 PSI and 2500 pulser RPM. Observe SK torque inc.;Ream from 857l'to 8591'. Stop rotary and verify blades open with 10K overpull at 8571'.;Dri118-1/2"x9-7/8" hole from 8591' to 8856' (75.7 AROP). 600 GPM, 2200 PSI, 120 RPM, 17-18K TO 15K WOB. 9.5 MW in, 9.5 MW out, 41 vis in, 43 vis out. 10.5 ECD. 34u max gas. 195K PUW, 95K SOW, 142K ROT.;Last survey @ 8779.50' MD / 4922.90' TVD, 59.95' inc., 24.91' azm., 4.34' from plan, 0.86' high and 4.25' Ieft.;Hauled 305 bbls H2O from L-Pad lake for total= 9,880 bbls Hauled 0 bbis Heated H2O from G&I for total= 960 bbls Hauled 985 bbis cuttings/liquids to MPU G&I for total= 12,105 bbls 11/2/2018 Drill 8-112"x9-7/8" hole from 8856' to 9376' (86.6 AROP) 520' maintain 60 deg inc 600 GPM, 2310 PSI, 140 RPM, 17-19K TO, 15K WOB. MW in/out 9.5/9.6, vis irdout 39/43 ECD 10.67, max gas 53u PU/SO/ROT 2101104/147.;Pump 30 bbl hi vis sweep at 9085', sweep back 40 bbis early w/ 20% increase at shakers.;Drill 8-1/2"x9-7/8" hole from 9376'to 9818'(73.7 AROP) 442' maintain 60 deg inc to 9409', start drop 3 deg/100'to 20 deg inc. 595 GPM, 2530 PSI, 140 RPM, 19K TQ, 18K WOB. MW in/out 9.5/9.6, vis in/out 38/40. ECD 10.97, max gas 53u PU/SO/ROT 225/110/155.;Pump 30 bbl hi vis sweep at 9560', sweep back 20 bbls w/ no increase.;Drill 8-1/2"x9-718" hole from 9818'to 10227' (68.2 AROP) 409' dropping 3°/100'. 600 GPM, 2620 PSI, 140 RPM, 18K TQ, 16-18K WOB. MW in/out 9.5/9.6, vis in/out 42/52. ECD 10.90, max gas 33u. PU/SO/ROT 214/116/156.;Mud properties were climbing despite adding 50 BPH of treated brine dilution. Yield point climbed to 30, MBT to 15 and LGS were at 6%. Ordered 290 bbis of 9.5 ppg 14 YP LSND mud to perform dituflon.;Drill 8- 1/2"x9-718" hole from 10227'to 10621' (65.7 AROP) 394' dropping 3°/100'. 600 GPM, 2560 PSI, 140 RPM, 18K TO 18K WOB. MW in/out 9.519.55, vis in/out 38/40. EC 10.68, max gas 55u. PU/SO/ROT 2501125/1 72.;Began 290 bbl dump and dilute at 10541'to lower yield point and LGS. Survey at 10573.49 MD / 6067.31' TVD, 25.79° inc., 16.54° mm., 5.0' from plan, 3.1' low, 3.85' Ieft.;Hauled 650 bbis H2O from L-Pad lake for total= 10,530 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 1068 bbis cuttings/liquids to MPU G&I for total= 13,173 bbis 11/3/2018 Drill 8-1/74-7/8" hole from 10621' to 10885'@ 500' above HRZ (58.6 AROP) 264', drop 3°/100' to 10791', then maintain 20' inc, 12° az. 600 GPM, 2800 PSI, 140 RPM, 22-27K TO, 18K WOB. MW in/out 9.5/9.5+, vis in/out 37/42. EC 10.77, max gas 54u. PU/SO/ROT 240/130/175.;Start adding black product at 10850', seen an increase in torque when spike fluid at bit, 22-27k ft/lbs, Increase lubes to 1 %.;Circulate 2.5 BU Pumping 600 gpm, 2650 psi, reciprocate pipe 60 rpm, continue adding total of 215 bbls 9.5 ppg black product spike fluid. Increase mud system to 8% black product. Continue to increase lubes to I% adding 4 drums 776, PJSM.;Pull a double to 10820' Shut down pumps and monftor well. Static. Breakout double. Pull trip nipple. R/U MPD head on stand and install etement.;Perform all checks on MPD system taking returns through MPD to flow line - good. Work parameters up to 600 GPM with 100 psi line friction from MPD. Maintain 11.3 ppg ECD with 9.5 ppg MW with MPD backpressure.;Drill 8-1 /2"x9-7/8" hole from 1 0885'to 11105' (48.9 AROP) 220', maintain 20 deg inc, 12 deg az. 600 GPM, 2870 PSI, 130 RPM, 21-22K TO, 20-21K WOB. MW in/out 9.6/9.6, vis in/out 37/36. EC 11.33, max gas 26u. PU/SO/ROT 255/131/180.;Hold back pressure drag and connections to maintain 11.3 ECD, 345 psi drilling, able to hold 550 psi on connections. Deal with aired mud starting at 10955', run degasser and screen clean to get mud back in shape, good. Slowly let mud wt increase to 9.7 ppg.;Drill 8-1/2"x9-7/8" hole from 11105' to 11474' (56.8 AROP) 369', TD of the intermediate hole section. 600 GPM, 2910 PSI, 135 RPM, 19-20K TO, 22K WOB. MW in/out 9.7/9.7, vis in/out 37/38. ECD 11.33, max gas 36u. PU/SO/ROT 245/140/184.;Hotd back pressure drlg and connections to maintain 11.3 ECD, 150-250 psi drilling and 530 psi on connections. HRZ at 11363' MD, Kalubik at 11389' and Kalubik GR marker @ 1140r. Last survey @ 11443.90' MD, 6879.95' TVD, 19.43' inc., 12.79° azm. 3.01' from plan, 0.1 Thigh and 3.01' right.;Obtain final MWD survey. Pump down 1-718" reamer de-activation ball at 350 GPM, 1530 PSI, 30 RPM, 14-16K TO. Slow to 100 GPM, 750 PSI, 30 RPM, 15-17K TQ. At 1089 all saw ball on seat, pressured up to 2650 PSI then shifted ctosed.;Pump 25 bbl high vis sweep. Circulate hole clean at 600 GPM, 2990 PSI, 120 RPM, 17K TO. No increase from the sweep was observed at the shakers. Circulated 32400 strokes, 5x bottoms up. Max gas 127u. -Note: Daylight savings time. 1 additional hour during this time period."";Shut down pumps & lineup #1 MP on the injection line. Pump across the top ofthe hole to maintain 11.3 ppg EMW. 575 PSI static and 650 PSI dynamic back pressure. POOH from 11474'to 11093'_ 275K PUW, 135K SOW. RIH from 11093' to 11434', took 10K weight.;Pump 2 BPM, 840 PSI. Wash down to bottom. Took 10K weight at 11434' and 11465'. No fill observed.;Begin weighting up the mud system from 9.7 to 10.5 ppg in 0.3 ppg increments with spike fluid. 600 GPM, 3135 PSI, 120 RPM, 15K TO. Maintain 11.3 ppg EMW With MPD, 250 PSI while circulafing.;Hauled 490 bbis H2O from L-Pad lake for total= 11,020 bbis Hauled 0 bbis Heated H2O from G&I for total= 960 bbls Hauled 1539 bbis cuttings/liquids to MPU G&1 for total= 14,712 bbis C_- 11/4/2018 Weight up the mud system from 9.7 to 10.5 ppg in 0.3 ppg increments with spike fluid. 600 GPM, 3135 PSI, 120 RPM, 15K TO. 4.4 full circulations 10.5 ppg inlout, vis in/out 37/40, Get SPRs. Maintain 11.3 ppg EMW with MPD, 250 PSI while circulating. PU/SO/ROT 285/125/195.;Shut off pump, Let well balance out V20 minutes thru MPD equipment, well flowing 10 gpm. Open MPD drain line, flow receding to 3.3 gpm in 35 minutes. Shut in MPD drain line. Rotate pipe every 10 min. Decision made to TOOH w/ MPD and spot a weighted pill at 9 5/8" shoe.;Pump and spot 30 bbl 6 ppb Asphasol, 6 ppb Resinex and 2% 776 lube casing running pill at 11474' pumping 325 gpm, 1150 psi. Maintain 11.3 EMW holding 70 psi back pressure, with pill out of bit shut down pump. BD TD, lineup on MPD injection Iine.;TOOH on elevators pulling 5 min std following MPD trip schedule f/ 11474'to 8433', maintain 11.2-11.3 EMW, 290 psi static pressure, 330-360 psi dynamic pressure.;Circulate 2 bottoms up at 325 GPM, 1015 PSI, 80 RPM, 8-10K TO while reciprocating the drillstring, overlapping tool joints.;Shut off pump, Let well balance out f/ 20 minutes thru MPD equipment, well flowing 7 gpm. Open MPD drain line, flow receding to 4.0 gpm in 45 minutes. Shut in MPD drain line. Pressure built to 72 PSI in 10 minutes.;Pump 33 bbls (volume short of planned 40 bbls) 15.0 ppg LSND mud at 150 GPM, 370 PSI. Chase and spot outside the bit at 300 GPM, 740 PSI. Pill in casing = 435' of coverage, 20T of TVD for 48 PSI additional hydrostatic pressure.;Pull above the 15.0 ppg pill from 8433' to 7998' at 3 min/stand holding 240 PSI static and 300-320 PSI dynamic.;Pump 38 bbls (remainder of mud in the pit) 15.0 ppg LSND mud at 130 GPM, 370 PSI. Chase and spot outside the bit at 200 GPM, 350 PSI. Pill in casing = 501' of coverage, 247' TVD for 58 PSI additional hydrostatic pressure. 106 PSI combined between both pills.;Pull above the 15.0 ppg pill from 799V to 7395' at 3 min/stand holding 11.3 ppg EMW with MPD. 160 PSI static and 220 PSI dynamic.;Shut off pump, Let well balance out f/ 15 minutes thru MPD equipment, well flowing 4 gpm. Open MPD drain line, flow receding to 0.9 gpm after 90 minutes and still slowing.;POOH from 7395'to 2675' at 1-3 min/stand while maintaining 11.3 ppg EMW with MPD. 140-150 PSI static and 170-230 PSI dynamic.;Hauled 200 bible H2O from L-Pad lake for total= 11,220 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 620 bible cuttings/liquids to MPU G&I for total= 15,332 bbls 38 bbls daily losses, 38 bbls cumulative losses for interval. 11/5/2018 POOH from 2675'to 607' just before HWDP at 1-3 min/stand while maintaining 11.3 ppg EMW with MPD. 140-150 PSI static and 150-230 PSI dynamic.;Shut off pump, Let well balance out f/30 minutes thru MPD equipment, well flowing 3.6 bph. Open MPD drain line, flow receding to .43 bph in 120 minutes and continues to recede. PJSM.;Remove MPD RCD bearing, strip off pipe. Install MPD riser. Fill and check riser for leaks, BD MPD llnes.;TOOH f/ 511' racking back HWDP and jars, upload the MWD, UD RSS/UR BHA#3, pull floats. Inspect UR, 1/1 on the blades, stabilizes in gauge, geo-pilot no wear. Bit grade= ii 1/1/NO/A/X/I/NO/TD. Note: fill displacement w/ 11.5 ppg mud from trip tank.;Monitor the well, the well is static, clear and clean rig floor. Pull the 9" ID wear /\ bushing. Make hanger dummy run as per wellhead rep, 32.50';R/U to run 7" casing, R/U Volant tool and handling equipment.;PJSM, Baker lock and WU 7" shoe jt to jt #2 using rig longs as backup torque to 14750 ff/lbs. Backup tongs slightly egged casing under collar damaging shoe jt.;Breakout and UD damaged shoe jt. strap and flashlight backup shoe jt. PIU, Baker lock and M1U 7" shoe track. Torque to 14750 !tubs, check float, good.;RIH 7" 26# L-80 TXP casing f/ 124' T/ 4125', RIH 2030 fpm to keep from pushing fluid away. Torque connections to 14750 fl/Ibs. Fill on the fly & top off every 10 then circulate 10 bbls.;Note: Two centralizers on shoe joint then on every jt to it 13 and on joints 72-74. 17 Centek 7x8-1/2" centralizers and 8 stop rings installed on casing.;RIH T' 26# L- 80 TXP casing F/ 4125' T/ 6792', RIH 2O-30 fpm to keep from pushing fluid away. Torque connections to 147501UIbs. Fill on the fly & top off every 10 then circulate 10 bbls.;Hauled 50 bbls H2O from L-Pad lake for total= 11,270 bible Hauled 0 bbls Heated H2O from G&I for total= 960 bible Hauled 57 bbls cuttings/liquids to MPU G&I for total= 15,389 bbls 9.5 bbls daily losses, 47.5 bbls cumulative losses for interval. 11/6/2018 RIH w/7" 26# L-80 TXP casing F/ 6792' T/ 7350', RIH 2O-30 fpm to keep from pushing fluid away. RIH 10 fpm f/ 7350'T/ 7805' thru 15 ppg weighted pill section, losing displacement returns. Torque connections to 14750 fi/Ibs. Fill on the fly & top off every 10 then circulate 10 bbls.;Circulate 1 bpm, 220 psi, pumped 12 bbls, 6.5 bbl losses with minimal returns.;Continue to RIH w/ T' 26# L-80 TXP casing at 10 fpm F/ 7805' T/ 8435' just above the 9 5/8" shoe. Pump 10 bbls at 1bpm, 250 psi, 7.2 BBL losses, minimal returns. Torque connections to 1475011/ Fill on the fly & top off every 10. PU/SO 181 K/111 K.;Continue to RIH w/ 7" 26# L-80 TXP casing at 10 fpm F/ 8435'T/ 11346, Fill on the fly & top off every 10. Began with losing 9 bph in the open hole and increased to // complete Iosses.;Wash two joints down F/ 11346 T/ 11429' at 1 BPM, 450 PSI. MN 7" casing hanger and landing joint. Wash down F/ 11429'T/ 11464'. Land t, casing on mandrel hanger with 90K on hanger. 265K PUW, 130K SOW.*** 80 bbls total lost while running casing '**.;Blow down top drive. R!U cement lines. PJSM with all parties involved.;Pump 5 bbls 8.34 ppg water at 1 BPM, 440 PSI. Pressure test lines to 1000 PSI low for 1 min. /4080 PSI high for 5 min. -good p test. Mix 8 pump 40 bible 10.5 npp Clean Spacer III. 1.27 ftA3/sk yield at 3 BPM. 575 PSI. Cleared ice from the derrick before loading the bottom plug. Load /I bottom plus ;Mix & pump 37 bbls 15.8 ppo Premium G cement 1.154 ftA3/sk vield 180 sks at 2 BPM 450-500 PSI Load top plug. Pump 20 bbls 8.34 ooa C water at l BPM, 450 PSI. Switch to rig pumps for displacement. 90 bbls lost of 102 bbls pumped, 88% Iosses.;Displace cement with 10.5 ppg LSND. 5 BPM, 460-480 PSI. Cement exited the shoe at 3750 stks, 480 PSI. At s s, S , t e pressure again to c imb rapidly to 1800 PSI. Slowed pump to 1 BPM, 2300 PSI. Pressure climbed to a max of 2560 PSI at 3920 silks then fell to 1950 @ 4020 stks.;Pressure slowly climbed to 2090 PSI before bumping the plug at 4111 silks of 4118 calculated. CIP @ 02:27 Pressure up to 2600 PSI & hold for 5 min. Bled off pressure with 4.7 bbls back. Floats holding. Observed 1.8 bbls from annulus before pack-off set. 391 bbls lost of 415.2 bbls pumped, 94% Iosses.;Lift was difficult to calculate due to the pressure increase, 140 PSI for the last 19 bbis. Still observed slight returns even while experiencing the pressure increase.;L/D landing joint, UD volant running tool, R/D cement equipment and clear rig floor of casing equipment.;Install 7" pack-off as per Hilcorp wellhead representative. Pressure test to 350 PSI for 5 min. then 5000 PSI for 10 min. - good tests.;Install T' I.D. upper wear bushing. Install mouse hole in the rotary table. Clear ice buildup from the derrick.;Hauled 0 bbls H2O from L-Pad lake for total= 11,270 bbls Hauled 100 bbls H2O from B-Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 91 bbls cuftings/liquids to MPU G&I for total= 15,480 bbls 575 bbls daily losses, 622.5 cumulative losses for interval. 111712018 PJSM, UD 5" DP f/ derrick using mouse hole in rotary table. Simi PJSM, R/U LRS on the O/A. Test line to 1500 psi, Freeze protect 9 5/8" x T'annulus w/ 75 bbls diesel to 2700' pumping 1 bpm, ICP 26 psi, FCP 685 psi. RD LRS. Clean mud pits.;LRS: Freeze protect OA- Pump 75 bbls Dal down 01 TD, Blocks and draworks. OA pressure 600 PSI.;Continue to UD 5" DP f/ derrick using mouse hole in rotary table. 363 jts total. SimOps: Finish cleaning pits, Load 4" DP into the shed.;Remove mouse hole & clear rig floor. Remove ice from derrick.;Pull upper wear bushing. Install upper test plug. Change lower rams from 4- 112"'x7" VBR to 2-7/8"x5" VBR. Change saver sub on top drive to XT-39. Had to remove 4" MPD line to open BOP doors to change rams.;Test lower 2-7/8"x5" VBR on 4" & 4-1/2" test joints. Test upper 2-7/8"x5" VBR rams on 4-1/2" test joint. 250 PSI low / 4000 PSI high test, hold for 5 min. each and chart. Test MPD lines to 250/1500 PSI for 5 min. each. R/D test equipment & solid master bushings.;Derrick inspection / Remove ice from derrick OA pressure 500 PSI.;MPD riser leaking. Remove & replace o-ring, still leaking. Found crack in weld leaking. Remove and sent to shop for weld repair.;Install 7" I.D. upper wear bushing and UD running tool. Install repaired MPD riser and fill stack - no Ieaks.;Mobilize XO & 4" handling equipment. MA7 stack washer on bottom of drill pipe. Single in the hole with 48 joints of 4" drill pipe. POOH and rack back 16 stands of 4" drill pipe. UD stack washer.;MAI BHA #4, Sperry 6-1/8" rotary steerable assembly to 92'. Kymera bit, 5200 Geo-Plot, DM hang-off collar, SP4, CTN, ALD and PWD.;Hauled 115 bible H2O from L-Pad lake for total= 11,385 bbls Hauled 0 bbls H2O from B-Pad creek for total= 100 bbls Hauled 0 bbis Heated H2O from G&I for total= 960 bbls Hauled 388 bbls cuttings/liquids to MPU G&I for total= 15,868 bbls 0 daily losses, 622.5 cumulative losses for interval. 11/8/2018 Continue to M/U BHA #4, M/U MWD/LWD tools, upload tools. P/U flex collars, PJSM, load sources, M/U fit sub, XO, 1 jt HWDP, attempt to shallow test tools, P/U remaining HW and jars to 755.31'.;Orift, P/U and single in w/ 4" XT -39 DP f/ 755'to 2621'.;M/U TD, fill pipe, Test MWD/LWD tools. PWD sensors reading low pressure, troubleshoot tools. Break in Geo -pilot seals, unable to downlink tools to read ECD. BD TD.;TOOH It 262V to 755', Rack back HWDP and jars. PJSM, remove sources. Upload tools. Pull BHA to the PWD. C/O the PWD, new BHA= 755.56'. Download tools. Install sources. TIH wl HWDP and jars. TIH U 2621'. Test MWD, good PWD readings & able to downlink to tools. 225 GPM, 1010 PSI. 80K PUW, 65K SOW.;Single in the hole with 4" XT -39 drill pipe from the pipe shed from 2621' to 9943'. Drift on pipe skate with 2.35" drift. Fill pipe every 2500'.;Hauled 50 bbls H2O from L -Pad lake for total= 11,435 bbls Hauled 0 blols H2O from B -Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 0 blols cuttings/liquids to MPU G&I for total= 15,868 blols 11/912018 Single in the hole with 4" XT -39 drill pipe from the pipe shed from 9943' to 11100'. ( 330 jts total ) Fill pipe. BO TD. Drift on pipe skate with 2.35" drift.;Perform derrick ice inspection, remove ice buildup from derrick.;PJSM, Slip and cut 99' drilling line. Recalibrate block height.;Wash down pumping 2 bpm 620 psi If 11100' to 11350' lagging top cri PIU, SIO 225K/951C.;Rack 1 std back parking at 11283', BD TD, R/U and test casing to 3700 psi for 30 charted min. 5.4 alis pumped, 5.4 bbls bled back, good test. BD lines. RID test equipment. M/U std and TD.'Drill cmtN 113501 to 11378' S bpm, 1670 psi, 30 rpm, 12-13k TO, WOB \ 4-9K, Drill plugs and FC f/ 11378'to 11380% ream 3 times, pass thru w/ no rotation. Drill cr to 11462'. Exit shoe @ 11464' and cleanout rat hole to ,f 11474'.;Clean draw works brake bands.;Drill 20' new formation from 11474' to 11494'(20 AROP). 215 GPM, 1770 PSI, 40 RPM, 14K TO, 4-15K WOB. PU/SO/ROT 245/215/135.;Pump 35 bbl 10.5 high viscosity spacer. Displace to new 10.5 ppg LSND mud with 1% 776 tube. 240 to 190 GPM, 2090 to 1610 \ PSI, 40 RPM, 14K TO. Lower flow rate to reduced ECD from 11.88 to 11.68 ppg.;Blow down top drive. Remove ice from the derrick.;P/U to 11384'. R/U test equipment. Perform FIT to 14.0 ppg. Pressure up to 1258 PSI at 6908' TVD with 10.5 ppg LSND mud= 14.0 ppg. Pumped 3.4 bbls and bled off 1.5 bbls. RID test equipment.;PJSM for installing MPD. Remove trip nipple and install MPD bearing assembly. Flood all lines then simulate a connection while holding 360 PSI for 11.5 ppg EMW. 35 PSI line restriction at 190 GPM.;Drill f/ 11494't/ 11564'(15.6 AROP). Maintain 20° inc, 12° mm. 190 GPM, 1650 PSI, 80 RPM, 6K TO, 21 WOB. 11.76 ECD w/ chokes wide open. MW in/out 10.45/10.5 Vis in/out 46/45. PU/SO/ROT 245/125/135.;Hauled 55 bbls H2O from L -Pad lake for total= 11,490 bbls Hauled 0 blots H2O from &Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 653 bbls cuttings/liquids to MPU G&I for total= 16,521 blots 11/10/2018 Drill f/ 11564'V 11650'(14.3 AROP) 86'. Maintain 20' inc. 190 GPM, 1660 PSI, 140 RPM, 6-8K TO, 10-15K WOB. MW in/out 10.2+110.3+ Vis in/out 46/46. PU/SO/ROT 1801100/134 Maintain 11.74 ECD w/ chokes wide open, hold 520 psi back pressure at connections.;At 11605' Start lowering mud wtV 10.5 to 10.2 to decreace ECD f/ 11.8 with MPD chokes fully open, then increase flow rate to 230 gpm. Kuparuk D @ 11551' MD / 6981' TVD.;Drill It 11650' t/ 11833' (30.5 AROP) 183'. Maintain 20° inc. 230 GPM, 2000 PSI, 140 RPM, 6-8K TO, 10-15K WOB. MW inlout 10.2/10.2 Vis in/out 42/41. PU/SO/ROT 1751110/136. Max gas 9u. Maintain 11.70 ECD w/ chokes wide open, hold 525 psi back pressure at connections.;Kup C @ 11679' MD / 7099' TVD, Kup B7 @ 11701' MD / 7122' TVD, Kup A3 @ 11766' MD / 7183' TVD. Kup A2 @ 11792' MD / 7208' TVD, Kup Al @ 11819 MD / 7233' TVD OA 500 PSI @ 12:30.;Drill V 11833't/ 1202T (32.3 AROP) 194'. Maintain 20' inc. 225 GPM, 1940 PSI, 140 RPM, 7-81K TO, 19-20K WOB. MW in/out 10.2/10.2 Vis in/out 40/40. PU/SO/ROT 177/110/140. Max gas Su.;Drill f/ 12027't(12079'(48 AROP) 72'. TD of production hole section 220 GPM, 1900 PSI, 140 RPM, 7K TO, 15-18K WOB. MW in/out 10.2110.25 Vis irdout 39/40. PU/SO/ROT 181/110/137. Max gas 10u. Projection to TD, 15.82' from plan, 11.41' low, 10.96' right.;Circulate 3 bottoms up. 230-245 GPM. 1940-2040 PSI, 120 RPM, 6.SK TO. Reciprocate f/ 12079't/ 12035'. Lineup MP #1 for MPD backpressure. Blow down top drive. Hold 510 PSI for dynamic flow check for 5 min ;Trip from 12079'to 11384'. Pull 4 min./stand holding 660 PSI dynamic, 510 static to maintain 11.5 ppg EMW. Pull on elevators to 11 898'where pulled 25K over. Work through wl a max of 40K over pull. Pulled up toll884' pulled 40K over, could not work through.;Attempt to lubricate through w/ 2 BPM, 980 PSI, could not get past 11884'. Ream from 11900' to 11843' with 4.5 BPM, 1610 PSI, 80 RPM, 6K TO. Ream down then pull through with no issues. Pulled tight at 11835'. Ream from 11843! to 11800'. Ream down then pull through with 15-201(drag to 11756.;Hauled 130 blols H2O from L -Pad lake for total= 11,490 bels Hauled 0 blols H2O from B -Pad creek for total= 100 abls Hauled 0 blols Heated H2O from G&I for total= 960 bbls Hauled 386 bbls cuttings/liquids to MPU G&I for total= 16,907 bbls 0 daily losses, 0 cumulative losses for interval. 11/1112018 Continue wl short trip on elevators from 11 756'to 11446'. Pull 4 min./stand holding 660 PSI dynamic, 510 static psi to maintain 11.5 ppg EMW. PU/SO 185K/100K.;Circulate a bottoms up inside the 7" shoe, reciprocate from 11446'to 11384'. 240 GPM, 1920 PSI, 80 RPM, 7K TO, 11.67 ECD.;BD TD, TIH on elevators 4 min std f/ 11446to 12035', wash to TO @ 12079', Maintain 11.5 ppg EMW w/ MPD. 365 PSI Dynamic, 510 psi static. No issues on trip in.;Circulate and increase MW f/ 10.2 to 11.5 ppg with 225 bbls 14.1 ppg spike fluid, start 240 gpm, 2020 psi, 120 rpm, 4-61K TO. reciprocate pipe. 100 gpm, 810 psi final rate, Maintain 11.5 EMW until chokes fully opened, calculated 12.3 ppg EMW while circulating 11.5 ppg mud at 100 gpm.;Began to see 11.5 ppg mud out at 19300, then got heavy. Good 11.5 ppg MW in/out at 20368 strokes. Shut down, blow down top drive and perform 10 min. Flow check - static. OA pressure @ 12:30 = 500 PSI.;POOH f/ 12079't/ 11384' @ 5 min Jstand. 200K PUW, 110K SOW. Counter swab with 175 PSI backpressure via MPD while pulling, zero backpressure on connections. Perform 10 min. flow check at shoe- static. Drop 2.35" drift on stand #113.;POOH f/ 11384' U 846' at 3 min./stand with 220 PSI increasing to 1 min/stand with 175-45 PSI ;Perform 15 min. flow check -static. PJSM with Beyond Energy and Doyon. Remove MPD head and install trip nipple.;Hauled 80 bbls H2O from L -Pad lake for total= 11,570 bbls Hauled 0 blols H2O from B -Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 300 blols cuttings/liquids to MPU G&I for total= 17,207 blots 0 bels daily losses, 0 blots cumulative losses for interval. 11/12/2018 Trip out of the hole from 846' to 759, rack back HWDP and jars, recover drift on wire. L/D 3 FCs. PJSM, remove sources, download MWD, LID remaining BHA #4. bit grade= 111/WT/A/ENNO/TD. Bottom geo-pilot lock ring backed off, stabs in gauge.;Clean and clear rig floor, load tools to rig floor.;RU power tong. Mobilize handling equipment to the rig floor and RU. MU crossovers to the FOSV.;PJSM. Baker lock and MU float shoe, Float collar and landing collar. Fill the shoe track, check the floats (good). RIH with 4-1/2". 12.6#. L-80, TXP liner torqued to 6170 ft -lbs installing centralizers on every joint to 724'. OA pressure at 12:30 = 500 PSI.;CIO elevators. PU and MU the liner hanger/LTP. Fill be back sleeve w/zanplex. MU DP crossover and 1 stand of 4" XT -39 DP. RIH to 864', circulate liner volume 3.5 BPM, 120 psi. -Notified AOGCC of upcoming BOP test at 14:14, est. test 15:30 on 13 Nov 2018 "';TIH with drifted stands of 4" DP, 2-3 min/std running speed f/ 864' to 11399.;Circulate a bottoms up at the 7" shoe. Stage up from 1/2 BPM, 400 PSI to 2 BPM, 610 PSI in 1/2 bbl increments.2 BPM = 12.62 ECD per Beyond Energy's modeling. 12.0 ppg mud observed at shakers, circulate out heavy mud. Maintain mud at 11.5 ppg.;Hauled 120bbis H2O from L -Pad lake for total= 12,965 bbls Hauled 0 bbls H2O from B -Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 blols Hauled 48 blots cuttings/liquids to MPU G&I for total= 17,255 bbls 11/13/2018 Get parameters before entering open hole, 10, 20 and 30 rpm 5.5k torque. PU/SO/ROT 185K/100K/125K. Spot and R/U cementers.;TIH with drifted stands of 4" DP, 2 min/std running speed f/ 11399'to 11960'. Drift and M/U 15' pup jt, wash down 1 bpm, 450 psi to 12039', P/U 185K, S/O 100K.;L/D single for space out. WU cement head and lines. Park @ 12039' Pump 3 open hole BU at 1 bpm, 380 psi.;PJSM, pump 5 bbls fresh water, PT lines to 4000 psi. good. Pump 15 Wall 3.5 ppg Tuned Spacer, Pump 20 bbls/15.8 ppg Class G Cmt w/40% excess OH Vol. Shut down, drop Plug. HES Pump 20 bbl fresh water spacer. Swap to rig pump, displace cement @ 2 bbl @ 530 psi.;Calculated latch 94 bbl, 933 strokes, no indication of shear, cont pumping. Calculated bump 103 bbl, 1023 strokes, no bump cont pumping 2 bbl @ 750 FCP. At 110 bbl, 1089 stokes, pressured up to 1500 psi held 2 min. bled off pressure checked floats, holding. CIP @ 11:45.;LD TD Head, MU single from string. Attempt to pressure up on DP, 5 bbl pumped pressure sheared off @ 1600 psi. Apparently we thought were bumped but actually had just latched plugs. Pump 7 bbl and bump plugs increase pressure to 2900 psi. Slack off to load hanger, not taking wt.;Worked pressure up to 4000 psi slacked off 60k on hanger. Pulled up to over pull on double grip hanger, not biting. slacked off again to 70k on hanger, PU still no over pull. Slacked off 70k on hanger bled off pressure to 500 psi. Attempt to release running tool, hanger released instead ;Pressured back up on DP 4000 psi reset hanger. After several attempts could not get running tool released. Mechanically release tool w left hand rotation, torque string to the right w 8k pressured up to 500 psi pulled up 7' slacked off 60k on dog sub. No indication of ZXP setting,;PU slack off while rotating 15 rpm no indication of shear stop rotating pull up slowly release pack off circ 1 bpm while pulling up. At base of TBS increase rate to 5 bpm @ 1340 psi. Pull 10' above TOL.;Hauled 1201ob1s H2O from L -Pad lake for total= 13,085 bbls Hauled 0 bbls H2O from B -Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 211 bbls cuttings/liquids to MPU G&I for total= 17,466 bible n Well Name: MP L-55 Field: Milne Point Unit County/State: Prudhoe Bay, Alaska (LAT/LONG): avation (RKB): API #: Hilcorp Energy Company Composite Report Spud Date: 10/19/2018 Job Name: 1813265C MPL-55 COMPLETION Contractor AFE #: AFE $: Activity Date Ops Summary S. , 11/13/2018 CBU x 2 at 9 BPM = 2510 psi. Overboard 80 bbl of contaminated mud to the rock washer., Observe the well for flow and the well is static. Blow down the top drive. Lay down 15' pup joint. TOOH with the HRD-E running tool from 11192' to 9500'. Appear to be swabbing a llttle.,CBU at 8 BPM = 1720 psi. Observed some thick fluid at bottoms up.,Continue to TOOH with the HRD-E running tool from 9500'to surface.,Break down and lay down the HRD-E running tool.,Drain the BOP stack. Pull the wear ring and install the test plug.,RU BOPE testing equipment. Purge the lines and flood the choke manifold with fresh water. MU crossovers to the FOSVs.,Shell test the BOP stack to 250/4000 psi (good test).,Conduct biweekly BOPE test to 250/4000 psi: Lower pipe rams (2-7/8" x 5" VBR's) with 2-7/8" and 4-1/2" test joints, upper pipe rams (2-7/8" x S" VBR's) with 2-7/8" and 4-1/2" test joints, annular with 2-7/8" and 4-1/2" test joints to 250/2500 psi, accumulator drawdown test and test gas alarms. The states right to witness was waived by AOGCC inspector Austin McLeod via email on 11/13/18 at 10:15 hours.,Tests: 1.UPR with 2-7/8" test joint, 3" Demco kill, choke valves 1, 12, 13 & 14 (passed) 2.HCR kill, upper IBOP, choke valves 9 & 11 (passed) 3.Manual kill, lower IBOP, choke valves 5, 8 & 10 (passed) 4.choke valves 4, 6 & 7 (passed) 5.4" dart valve, choke valve 2 (passed) 6.4" TIW, HCR choke (passed) 7.Manual choke (passed) B.Annular to 2500 psi with 2-7/8" test joint (passed),91PR with 2-7/8" test joint (faillpassed; had to cycle the LPR) 10 Blind rams (passed). 11/14/2018 Continue conducting biweekly BOPE test to 250/4000 psi. The states right to witness was waived by AOGCC inspector Austin McLeod via email on 11/13/18 at 10:15 hours. ll.Hydraulic super choke and manual adjustable choke (passed) 12. UPR with 4-1/2" test joint (passed) 131PR with 4-1/2" test joint (fail/passed; cleanout debris) 14. Annular to 2500 psi with 4-1/2" test joint (fail/passed; had to bleed air out).,Accumulator Test: System pressure = 3000 psi Pressure after closure = 1700 psi 200 psi attained in 44 seconds Full pressure attained in 180 seconds Nitrogen Bottles - 6 at 2095 psi.,RD BOPE testing equipment.,M/U stack washing tool and jet BOP stack.,Blow down lines, pull the test plug and install the wear ring.,RD remaining MPD equipment from BOP stack. Remove all MPD components from the rig and make ready to ship.,RU and attempt to PT the casing to 3500 psi. Pressure up to 5DO psi and hold for 5 minutes with no bleed off. Pressure up to 1000 psi and hold for 5 min with no bleed off. Attempt reach 1500 psi but started pumping fluid away at 1470 psi. Shut down pump, well bled down to 1300 psi before opening the bleeder.,Blow down lines. RD pressure testing equipment. Change air boot on the riser.,PJSM. PU and MU pack-off/dog subassembly with 5 stands of 4" HWDP to 483'.,TIH with pack-off/dog subassembly on 4" DP from 48T to tag at 11273' (PU = 200K and SO= 95K).,Set down 45K to set the ZXP liner top packer and observed the dog shear. PU to up weight and RU to test the IA. PT the ZXP liner top packer and 7" casing to 3500 psi for 30 minutes (good test)., Lay down a single. RU the head pin and cement line. PT the 4-112" liner to 3500 psi for 10 minutes (good test). RD the cement line and head pin. MU a single., Blow down the cement line. TOOH with pack-off/dog subassembly from 11264' to 7914'.,Rig Fuel (gallons): OH = 6260, Used = 1037 & Rae = 0 Daily losses to the formation = 0 bbls Total losses to the formation = 0 bbls,Hauled 230 bbls H2O from L -Pad lake for total= 13,315 bbls Hauled 0 bbls H2O from &Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 378 bbls cuttings/liquids to MPU G&I for total= 17,844 bbls 11/15/2018 Continue to TOOH with pack-off/dog subassembly from 7914to 483'.,Lay down 5 stands of 4" HWDP and pack-off/dog subassembly. RIH with jar stand from the derrick. Lay down 2 joints of HWDP and the jars.,Clean and clear the floor. Mobilize 2-718" handling equipment to the rig floor and power tubing tongs.,PJSM. RU to run 2-7/8" HT Pac work string.,PU and MU Baker X-treme motor with 3.875" 4 bladed junk mill. RIH with mill/motor assembly on 2-7/8" HT Pac work string to 810'.,PU and MU crossover from 2-7/8" HT Pee to 4" XT -39. RD 2-7/8" handling equipment and RU 4" handling equipment.,TIH with mill/motor assembly on 4" DP from 810' to 1282'. The top drive grabber dies were not grabbing the DP to MU the top drive.,Change out the top drive grabber dies while monitoring the well on the trip tank.,Continue to TIH with mill/motor assembly on 4" DP from 1282' to 11065' filling the DP on the fly and topping off every 20 stands.,PJSM. Slip and cut 63' of drilling line. Change out ram side top drive grabber head to 3-112". Service the top drive and calibrate the blocks -Continue to TIH with mill/motor assembly on 4" DP from 11065' to 11251'. Go easy through the liner top with no issues. PU = 190K and SO = 90K. TIH from 11251' to tag at 11905' with 5K down. PU toll877' and MU 4.52' pup joint below the top joint., Bring the pumps up to 2.5 BPM = 1240 psi and wash down from 11877to 11907'. PU to 11877', turn the pumps off and RIH to tag at 11907'.,Break the connection and drop 3/4" steel ball. Pump ball down at 2.5 BPM = 1160 psi, at 830 strokes the pressure dropped to 860 psi continue to pump to calculated 1228 strokes with no pressure increase.,Increase the pump rate to 5 BPM = 1700 psi. Continue to CBU and the pressure dropped to 700 psi due to mud getting aired up.,Continue to circulate at 5 BPM until aired up mud is out of the hole.,Obsewe the well for flow and the well is static. Lay down the 4.52' pup. Blow down the top drive.,TOOH with mill/motor assembly from 1187T to 3426'.,Rig Fuel (gallons): OH = 8998, Used = 1312 & Rae = 4050 Daily losses to the formation = 0 bbls Total losses to the formation = 0 bbls,Hauled 40 bbls H2O from L -Pad lake for total= 13,355 bbls Hauled 0 bbls H2O from B -Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbls Hauled 48 bbls cuttings/liquids to MPU G&I for total= 17,892 bbls 11/16;2018 Continue to TOOH with mill/motor assembly from 3426' to 810'.,Change handling equipment to 2-7/8". RU power tubing tongs. MU crossovers to TIW.,POOH laying down 2-7/8" HT Pae work string. Lay down Baker X-trema motor with 3.875" 4 bladed junk mill.,Clean and clear the floor., PU and MU 4-1/2" casing scraper with 3.75" tri cone bit. RIH with 21 joints of 2-718"HT Pac work string to 669'.,Change handling equipment to 4". MU 7" casing scraper with crossover back to 4" XT-39 from 669' to 682'.,TIH with dual scraper assembly on 4" XT-39 DP from 682' to 11216'.,Continue to TIH (did not seethe top of the liner at 11272') to 11873'. Wash down from 11873' to tag at 11907' with 5K down at 5 BPM = 2000 psi (PU = 204K and SO= 94K).,PJSM. Pump 28 bbl hi vis sweep and displace the well from 11.4 ppg LSND mud to 9.8 ppg NaCl with 2% KCI at 5.5 BPM.,Observe the well for flow and the well is static. Blow down the top drive. PJSM for laying down DP.,POOH laying down 4" XT-39 DP from 11873' to 10213'.,Repair hydraulic line on the iron roughneck.,Continue to POOH laying down 4" XT-39 DP from 10213'to 962'.,TIH with remaining 7 stands in the derrick from 962' to 1591'.,Continue to POOH laying down 4" XT-39 DP from 1591' to 682'., Lay down 7" casing scraper. RU 2-7/8" handling equipment and power tubing tongs.,Rig Fuel (gallons): OH = 8540, Used = 458 &Rec =0 Daily losses to the formation = 0 bible Total losses to the formation = 0 bbls,Hauled 70 bbis H2O from L-Pad lake for total= 13,425 bbls Hauled 0 bbis H2O from B-Pad creek for total= 100 bbls Hauled 0 bbls Heated H2O from G&I for total= 960 bbis Hauled 718 bbis cultin s/li uids to MPU G&I for total= 18.610 bbl 11/17/2018 Continue to POOH !/665 to surface laying down 2 7/8" HT-PAC DP and 4 1/2° Scraper.,Clean and clear the floor., RU to run 4-1/2" frac string completion..Pull the wear ring and change out rotary bushing.,PJSM. PU and MU tail pipe and packer assembly as per tally. RIH with packer assembly on 4-112", 12.6#, L-80 TXP tubing to 11252' (PU = 145K and SO = 90K).,Continue to RIH, tag top of the liner at 11273' and no-go at 11284'.,Lay down joint # 277-275. PU and MU space out pups 7.84', 7.92', 9.85, and 9.89'. MU joint #275. MU the landing joint to the tubing hanger (TWC installed) and MU the tubing hanger to the string. Land the tubing hanger and RI LDS. End of the mule shoe at 11281'. Lay down the landing joint.,PJSM for ND of the BOP stack., Blow down the hole fill, choke manifold, kill line and choke line. Pull the riser., ND the BOP stack, set back on the stump and secure for tmnsport.,NU the tubing head adapter and NU the tree., PT the tubing hanger void to 500/5000 psi for 10 minutes each (good test).,Power went out on the rig and L pad. Start up the rig generators and the camp generatom.,Fill the tree with diesel and RU to test. PT the tree to 25015000 psi for 5 minutes each (good test).,Pull the TWC. RU circulating lines for freeze protecting and u-tube. PJSM for pumping freeze protect.,Rig Fuel (gallons): OH = 7815, Used = 725 & Rae = 0 Daily losses to the formation = 0 bbls Total losses to the formation = 0 bbis, Hauled 85 bible H2O from L-Pad lake for total= 13,510 bbls Hauled 0 bbls H2O from B-Pad creek for total= 100 bbis Hauled 0 bbls Heated H2O from G&I for total= 960 bbis Hauled 0 bible cuttingsfliquids to MPU G&I for total= 18,610 bbls 11/1812018 PT all circulating lines to 250/5000 psi (good test). Pump 88 bbis of diesel down the IA taking return up the tubing at 2 BPM = 400 psi.,Place the IA and tubing in communication allowing the diesel to u-tube and equalize., Drop the ball & rod with rollers and allow time for it to fall to seat. Pressure up 2500 psi to set the HES packer. Bleed the tubing to 1500 psi and PT the IA to 3500 psi for 30 minutes (good test). Bleed the IA to 1500 psi and PT the tubing 105000 psi for 30 minutes. Bleed the tubing off to 1500 psi. Bleed both off to 0 psi.,LRS suck back lines. RD all circulating Iines.,Secure the tree and cellar. Release the rig from L-55 at 12:30 hours.,See L-20 report for details., Hauled 70 bible H2O from L-Pad lake for total= 13,580 bbis Hauled 0 bbls H2O from B-Pad creek for total= 100 bbis Hauled 0 bbis Heated H2O from G&I for total= 960 bible Hauled 410 bible cuttings/liquids to MPU G&I for total= 19,020 bbis 11/20/2018 MIRU Alaska E-Line. PT to 250 / 2500 psi. RIH with CCL, CBL, GR (3 centralizers). Tag PBTD at -11,860' uncorrected depth. Make several attempts to get a valid CBL with no success. Unable to get repeat-ability. Attempted passes with 700 psi, 1000psi, and 3000 psi. Decision made to POOH and try different CBL tool tomorrow. Bleed off tubing pressure. POOH and L/D lubricator and tools. Nicht cap BOPE. 11/27/2018 IMIRU Schlumberger E-Line for Repeat CBL. 11/28/2018 Press T1110 was 0/0/0, PT PCE 300/3000 psi; Logged CBL Slim Cement Mapping Tool from TD 11868 to 10350 at 500 psi and 3000 psi.,Dayll ht operation 11129/2018 MIRU Alaska E line perforators. Initial pressure T/I/O 0/0/350 psi,Pick up Gun 1. PT 250/ 2500 psi.. Run in hole.,lnitial perforate Kuparuk A2 sands 11795- 11801, G, 65 f 60 dep Phasing, 22.7q Razor charges, Deep penetrating.,on surface all shots fired. RD Secure well Com lated operations 11/30/2018 Prep for frac. RU Frac Line 12/1/2018 Frac RU 12/2/2018 Frac RU and Prep 12/32018 Frac Prep and RU 12/4/2018 Continue to Attempt to RU for Frac. Blender problems 12/5;2018 On standby with equipment on location Waiting on Schlumberger POD 12/6/2018 Wait on Schluberger POD repairs 12/7/2018 Complete POD repairs. Safety stand down in Field,RU remaining Frac equipment. Given approval to proceede.,Run IA up to 2480 psi3OA went to 562 psi. PT Treating Line. 2000/ 4000 and 8000 psi.,Safety and operational meeting. Stressed Safety of operations and awareness. pumping data Frac. Initial rate 35 BPM. 4650 psi. Nt P step down with 3 stages. Shu[ut down for analysis.,Pump Fracture of Kuparuk A2 sands Started up on Pad with 30# xLinked gel. Start Ramp of 16-20 RCP. Carbo Prop. Due to realtime data interpretation, Extend 2 # stage. Extend 4 # stage, Reduce Gel to 25#. Reduce rate to 30 bpm Extend 5 % proppant stage. Extend 8 # stage Reduce rate to 25 bpm,. Complete frac at 8ppg proppant. Pumped full flush. Pumped 30 bible of diesel for freeze protect.,Frac completed Pumped 202000# of Proppant. Estimated 200852# of 16-20 Carbo Resin coated Prop placed behind pipe. Rates varied from 35 to 25 bpm during operation. Pumped 2317 bbis of fluid during the job. RD Tree aver. Start RD of frac a ui ment 12/9/2018 RU CTU6. Perform BOP test.,Make up BHA. 2"CTC Dual Checks 2.125'2 each 4' stingers, 2.75" Jet swirl nozzle with 8 each.125 inch ports. Estimated HHP is 103 at 3 bbis/min. Continue Making modifications for Test Separator to tie into. PT CT and PCE to 300/3970 psi. Start displacing CT with slick 1 % KCL water at .5 bpm, RIH with Jet Swirl Nozzle.,SD pump. Dry tag top of proppant At 11581 CTM Start pumps back up. Increase rate to 2.8 bpm at 2600 psi. First Gel sweep exiting nozzle. 10 for 1 returns. RIH jetting proppant. to 1168TPUH for short trip to 11577. RIH to 11780. Gel at nozzle, Puh for short trip to 11513',RIH to 11680' CTM. Allowed last of gel to exit nozzle. Start POH with slick water exiting the nozzle. 2.9 bpm at 2400 psi,Continue to POH. Slow running speed at 1000 ft. POH at 50 fpm WHP increasing. Seeing Proppant at choke in samples. Hint of crude in sample.,On surface.. Switch to 60/40 M/w. RIH to freeze protect top 1000' of well. SD Pumps. Back on surface .,Secure well for the night. Rack back Coiled tubing. 12/10/2018 CTU Crew on Iocation.,Make up and PT CTU PCE and CT 300/4000 psi. PT Halite N2 lines. 500/4200 psi PT LRS Testers Lines 50012000/4000 psi. Vessel to 200/1000 psi Good test, RIH with 2 inch nozzle, Checks and 2 each 4' stem. StartN2 down CT at 500 scfm,Set Nozzle at 3500ft, Wait for N2 to Kick around. Continue in hole lifting at 5000', 8000 and 10000' Stop at 1000' and lifting liquids with n2 going to the LRS test separalor.,Conlinue to N2 lifted to flow. Pumping at 750 and then increasing to 1000scfm. Pumped 685000scf of N2.. Water out on last 200 bbis was between 85 and 75% Rate varying from 160 to 240 bpd according to rate meter. . Test gas rate out was equal to n2 rale going into well.,Out of N2. POH CT. allow well to bleed down. Well would not flow on own. FP testers. FP top of well with 10 bbls m/w,Recovered Net approx 284 bbls (according to straps). Stand back CT for the night. Secure LRS separator . Order out more N2 for morning. Waft on N2 12111/2018 MIRU SLB CTU #6 with 15,014' of 2" CT. CV = 41.8 obis. PU injector, 11' of lubricator, and BOPE. Run coil down and MU BHA 91 - 1.90" OD connector, 2" DFCV, 2x 2.0" Stingers, 2.0" Ball drop nozzle. OAL = 9.788'.,Stab on well. NU BOPE. PIT to 250 psi low and 3,500 psi high.,Open well and RIH w/ BHA#1. WHP = 290 psi .,Wait on N2.,N2 on location. Begin RIH at 30 fpm while bleeding off the N2 cap in the tubing to the flowback tank.,At 3,500' bring N2 online at 1,000 scf/min at 400 psi. Unload from 3,500'. WHP is 100 psi.,RIH at 100 fpm to 7,000' and circulate N2 at 1,000 scf/min at 1,000 psi. WHP is 140 psi.,Park at 7,300' until fluid is unloaded. N2 at 1,000 scf/min at 1,400 psi. WHP is 340 psi. 2,700 BPD and 50% Water Cut.,RIH at 100 fpm to 11,000' and circulate N2 at 1,000 scf/min at 1400 psi. WHP is 400 psi. 1,000 BPD. Park there until 90 minutes left of pumpable N2 volume left. Water cut is 1 %.,POH at 100 fpm. N2 at 1,000 scf/min at 1700 psi. WHP is 500 psi. 1,000 BPD,At 500' cut N2 and monitor well to see if it flows unassisted. Well does not flow.,Pump 38 bbls of 60140 McOH down tubing for freeze protect. Blow down well test Iines.,Close swab. Secure well. Total of 190 bbis of fluid flowed back. 1% Water cut. 12/12/2018 **14hm STANDBY (CREW C/O)** "'CONTINUE JOB ON 12/13118*** 12/13/2018 *`CONTINUE JOB FROM 12/12/18 (E -LINE DRIFT, SBHPS & PRE-RIG) R/U COMPLETE, PIT TO 250/3000, RUN 3.25" CENT, 3'x 1-7/8" STEM, 2.85" CENT, DRIFT TBG FOR E -LINE TO 11750' SLM 111760' MD, (+10' correction from 11119/18) COMPLETE SBHP PER PROCEDURE TO 11561' SLIM 111571' MD (7000' SS), GOOD DATA **4hrs STANDBY FOR TRAVEL TO/FROM PRUDHOE** ***CONTINUE JOB ON 12-14-18*** 12/14/2018 **CONTINUE JOB FROM 12/13/18 (E -LINE DRIFT, SBHPS & PRE-RIG)**FIL @ 2100-- , PIT TO 25013000./ SET 4-1/2" PXN PLUG BODY (4 - 5/16" ports), S/D @ 11097' SLM 111144' MD SET P -PRONG (OAL=96", 1-314" FIN) @ 11093' SLIM **LRS PUMP 32BBLs OF DIESEL DOWN TBG** **2hm STANDBY FOR TRAVEL TO/FROM PRUDHOE" ""CONTINUE JOB ON 12-15-18**',PT 250U2000H Tubing punch 1-9116" x 3', 10 shots depth = 11093'-96' in tubing to circulate drilling fluid to produced fluid. lay down e -line equipment to give well back to slick line. 12/15/2018 **CONTINUE JOB FROM 12/14/18 (E -LINE DRIFT, SBHPS & PRE -RIG)" PIT TO 250/3000. PULL P -PRONG (OAL=96", 1-3/4" FIN) @ 11096' SLIM PULL 4-112" PXN PLUG BODY (4 - 5116" ports, OAL=30") FROM XN-NIPPLE @ 11 104'SLM / 11144' MD, RECOVER ALL PACKING & NUBBINS *'JOB COMPLETE, NOTIFY PAD -OP & LEAVE WELL S/ I Rig up Alaska E -line. PT lube to 100011. Cut to release packer with 3-1/2" Chem cutter. Cut depth 11140.83'.,Monftor well, good Install BPV„Spot Mud boat, Set up crane, set well house, N/D tree, prep hanger & check threads with sub, good, install BOPE, stack up rig floor, lay out accumulator lines, spot pits,Spot Ina. to BOP flange bolts install surface lines, prep & mise mast run Certec lines Wrap1winterize surface lines 12/16/2018 Continue with R/U operations., Fill surface lines, R/u test eq. preform shell test, work through leaks as needed, shell test good 250/3500psi,Test BOPE as per Hilcorp & AOGCC requirements, witness was waived by AOGCC inspector Jeff Jones, test w/2 718" & 4 1/2" TJ 250 low/ 3500 high, 2500 annular, good, test PVT & gas alarms good,R/D test eq. blow down lines, service rig,Pull TWC, M/U landing jt & install, BO IId pins,Pull hanger free @ 88k, cont wk up t/168k, no movement, cont. work pipe,R/D landing jt. change out handling eq & r/u jack, r/u landing jt,Worm up jack, pull & work string up U188k, no movement, continue to work while waiting for E -line 12117/2018 Make up and pick landing joint. Test jacks and pull 230K and hold 1 minute and slack off , pull 230K and hold for 1 minute and slack off (calculated string weight 129,850# - Doyon PIU weight was 105K when set packer), no indication of packer coming loose. Lay down landing joint and R/U aline., RIH w/ aline w/ chemical cutter spaced out to cut at .46 inches above the bottom of 5.8" "cut to release window". Cutting 1.8 inch below initial cut. (initial cut in middle of 5.8" window minus cut area). Attempt to RIH to tag No -Go @ 11,144.3' (3.725 ID) w.th 3.740 gauge cutter. Tagged original cut @ 11,141' and could not work past it. Tools sticking requiring 12001b over pull to get free. POOH,Continue POOH w/ a -line and decision made to cut tubing above packer, leave packer in hole and run completion to top of packer. POOH w chem cutter and redress tool string for tubing cut, Rlh & correlate, cut tubing @ 11133', good indication cutter fired, POOH w/ e-line.,RID a -line, cutter fired, m/u landing jt Pull with jack, PIU wt t/120k, falling off U 108k, land hanger back, RID casing jack, m/u landing jt, pull hanger & I/d, c/o handling eq.,POOH I/d 4 1/2" 12.6# L-80 TXP tubing UD 159 jts, 12/18/2018 Continue POOH w/ 4.5" TXP frac string. Pulled 270 joints 4.5# TXP pipe and 1 - 37cut jt. Leaving top of cut stump @ 11,094'. FISH LEFT IN HOLE (top to bottom): 3' Cut stump of 4.5" 12.6 # L-80 TXP, 1 -jt 4.5" 12.6# L-80 TXP pipe WITH tubing punched holes, 1 -8'x -over pup 4.5" TXP Box x 8rnd EUE, HES AHR Packer, 1'- x -over pup 8 and to TXP, 3 jt*- 4.5" 12.6# TXP (118') and 1- 8' W LEG jt (4.5" TXP),Swap out lifting equipment and prep to P/U ESP,P/U and Service 4" ESP pump ASSY as per Centrilift personal, test cable & cap string/check valve good,RIH w/ESP assy on 2 7/8" EUE 6.5# L-80 Tubing 117136, checking cable & cap strip 1000', first check then every 2000' after 1211912018 Continue R I H w/ 2-7/8" 6.5# L-80 EUE tubing clamping every collar. Pumping single displacement every 15 joints.,P/U Weatherford dual packer with vent valve, terminate ESP power cable, 3/8" chemical injection line, and 3/8" control line for vent valve, pumping single displacement every 45 mins during termination. Necessary to remove packer and tighten lower G/L Mandrel to align "hump' with the offset of dual packer to not over -stress (bend) tubing when going through turn in well bore.,Connect hydraulic control line to packer vent valve, purge air from stainless tubing and connection, witness valve actuation, hold hydraulic pressure for 20 minutes, bleed off pressure, install two clamps on vent valve and tubing to stabilize vent valve,Cont. RIH on 2 7/8" tubing U 10996'„M/U hanger & landing joint, orientate penetrator, test cable & cap lines good, m/u penetrator & cap line hanger penetrations, test penetrator/cable good, Ran 349 jts total,Land hanger, Run in LID pins, placing assembly tail @ 11030', S/o wt 27k, test cable, Good,Drop Ball & rod, r/u to set packer & test tubing, stage pressure up U3500 hold for 30 min setting packer @ 2930', good, Fill annulus test t/2000 hold for 30mni good,Pull landing jt, set BPV,Blow down surface lines & start rig down carriage, suck out pits & prep for move. M t 1 -(A 12/20/2018 Continue to R/D. Both crews on location to complete rig move. Lower rig mast, remove rig carrier from mud boat, remove mud boat. Roads and pads crane and truck on location, remove rig Floor, BOPE. Pick up and M/U production tree. Well head tec James Craycraft on Iocation.,Set TWC in production tree and test void between adapter Flange and wellhead. Test to 250psi low and 5000psi high f/ 15mins. Test good. SIMOPS: continue to R/D on L-Pad and spot equipment on A-pad.,Move rig pits, accumulator trailer, tool sheds, and rig heaters from L-pad to A-pad and spot in place for stack out. Contact well support and let them know location is ready for slick line to R/U. 1/2/2019 MIRU SLB CTU #6. Perform full BOP test to 300/3500 psi. Record on 10-424. MU Quadco motor and 2.2” OD mill. Get on well. PT to 300/3500 psi. Open well to 686/5/379 psi .,RIH. See ice at - 800'. Snub down through ice to 1670' . Turn mill from 1679. Clear of ice at 2050'. Drift down to 5000' ctmd. Run ESP and able to pressure up against closed choke, lift Fluid after opening choke and get Fluid to tank, set choke and speed up pump and see pressure increase, ESP working great. POOH and freeze protect well to 5000' with 29 bbls 60/40, RDMO CTU. Job Complete Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-55 MPU L-55 50-029-23612-00 Sperry Drilling Definitive Survey Report 13 November, 2018 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-55 Project: Milne Point TVD Reference: MPU L-55 Actual RKB @ 49.67usft Site: M Pt L Pad MD Reference: MPU L-55 Actual RKB @ 49.67usft Well: MPU L-55 North Reference: True Wellbore: MPU L-55 Survey Calculation Method: Minimum Curvature Design: MPU L-55 Database: NORTH US + CANADA project Milne Point, ACT, MILNE POINT Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Nap Zone: Alaska Zone 04 Using geodetic scale factor Well MPU L-55 Well Position +N/ -S +E/ -W Position Uncertainty Wellbore MPU L-55 Magnetics Model Name 0.00 usft Northing: 6,031,799.64 usft 0.00 usft Easting: 544,853.40 usft 0.00 usft Wellhead Elevation: 16.00 usft Sample Date Declination (°) BGGM2018 9/15/2018 17.03 Design MPU L-55 Audit Notes: Version: 1.0 Vertical Section: Phase: ACTUAL Depth From (TVD) +N/ -S (usft) (usft) 33.67 0.00 Latitude: 70° 29'51.886 N Longitude: 149° 37'59.525 W Ground Level: 16.00 usft Dip Angle Field Strength (°) (nT) 81.00 57,454.05457164 Tie On Depth: 33.67 +E/ -W Direction (usft) (I 0.00 23.79 Survey Program Date 11/12/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 628.00 MPU L-55 Gyro (MPU L-55) 2Gyro-NS-GC_Drill colk H029Ga: North seeking single shot in drill colla 10/10/2018 689.86 8,409.83 MPU L-55 MWD+IFR2+MS+Sag (MPU L 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +as 10/22/2018 8,496.85 11,443.90 MPU L-55 MWD+IFR2+MS+Sag (2) (MP 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 11/02/2018 11,545.53 12,055.77 MPU L-55 MWD+IFR2+MS+Sag (3) (MP 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis+ sa 11/12/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +FJ -W Northing Easting DLS Section (usft) (I (°) (usft) (usft) (usft) (usft) (ft) (ft) (°I100') (ft) Survey Tool Name 33.67 0.00 0.00 33.67 -16.00 0.00 0.00 6,031,799.64 544,853.40 0.00 0.00 UNDEFINED 100.00 0.43 10.69 100.00 50.33 0.24 0.05 6,031,799.88 544,853.44 0.65 0.24 2_Gyro-NS-GC_Drill collar (1 167.00 0.62 9.05 167.00 117.33 0.85 0.15 6,031,800.49 544,853.54 0.28 0.84 2_Gyro-NS-GC_Dn1l collar (1 257.00 0.89 3.18 256.99 207.32 2.03 0.27 6,031,801.67 544,853.65 0.31 1.96 2_Gyro-NS-GC_Drill collar 349.00 3.25 36.76 348.92 299.25 4.83 1.87 6,031,804.48 544,855.24 2.78 5.17 2_Gyro-NS-GC_Drill collar (I 442.00 6.14 40.41 441.60 391.93 10.73 6.67 6,031,810.41 544,860.00 3.12 12.51 2_Gyro-NS-GC_Dnllcollar(1 535.00 7.73 45.14 533.92 484.25 18.93 14.33 6,031,818.66 544,867.61 1.82 23.10 2_Gyro-NS-GC_Dn1l collar (1 628.00 10.64 42.07 625.72 576.05 29.72 24.52 6,031,829.50 544,877.73 3.17 37.08 2_Gyro-NS-GC_Drill collar (1 689.86 13.10 39.24 686.25 636.58 39.39 32.78 6,031,839.22 544,885.94 4.09 49.26 2_MWD+IFR2+MS+Sag (2) 785.06 16.51 38.68 778.28 728.61 58.31 48.06 6,031,858.23 544,901.10 3.59 72.74 2_MWD+IFR2+MS+Sag (2) 880.15 19.96 40.25 868.58 81&91 81.25 67.00 6,031,881.29 544,919.90 3.66 101.38 2 MWD+IFR2+MS+Sag(2) 11/13/2018 4:18:09PM Page 2 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Project: Site: Well: Wellbore: Design: Hilcorp Alaska, LLC Milne Point M Pt L Pad MPU L-55 MPU L-55 MPU L-55 Local Co-ordinate Reference: Well MPU L-55 TVD Reference: MPU L-55 Actual RKB @ 49.67usft MD Reference: MPU L-55 Actual IRKS @ 49.67usft North Reference: True Survey Calculation Method: Minimum Curvature Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 974.52 25.49 33.48 955.60 905.93 110.51 88.63 6,031,910.67 544,941.35 6.47 136.87 2_MWD+IFR2+MS+Sag (2) 1,064.77 30.91 31.10 1,035.11 985.44 146.58 111.33 6,031,946.88 544,963.83 6.13 179.04 2_MWD+IFR2+MS+Sag (2) 1,160.11 36.79 29.33 1,114.26 1,064.59 192.48 137.99 6,031,992.93 544,990.21 6.25 231.79 2_MWD+IFR2+MS+Sag (2) 1,255.27 41.36 27.07 1,188.12 1,138.45 245.35 166.27 6,032,045.97 545,018.17 5.03 291.58 2_MWD+IFR2+MS+Sag (2) 1,349.95 47.16 25.83 1,255.90 1,206.23 304.50 195.66 6,032,105.29 545,047.20 6.19 357.56 2_MWD+IFR2+MS+Sag(2) 1,444.75 51.96 25.88 1,317.37 1,267.70 369.41 227.11 6,032,170.38 545,078.26 5.06 429.64 2_MWD+IFR2+MS+Sag (2) 1,541.70 53.05 25.33 1,376.39 1,326.72 438.78 260.35 6,032,239.94 545,111.07 1.21 506.52 2_MWD+IFR2+MS+Sag(2) 1,634.71 56.82 23.69 1,429.81 1,380.14 508.04 291.90 6,032,309.38 545,142.20 4.30 582.63 2_MWD+IFR2+MS+Sag(2) 1,725.59 58.70 23.91 1,478.29 1,428.62 578.37 322.92 6,032,379.89 545,172.80 2.08 659.49 2_MWD+IFR2+MS+Sag (2) 1,824.08 55.09 24.54 1,532.08 1,482.41 653.60 356.76 6,032,455.31 545,206.18 3.70 741.98 2_MWD+IFR2+MS+Sag (2) 1,917.85 58.99 24.64 1,583.08 1,533.41 725.12 389.50 6,032,527.03 545,238.47 4.16 820.63 2_MWD+IFR2+MS+Sag (2) 2,012.11 58.94 25.84 1,631.68 1,582.01 798.18 423.93 6,032,600.28 545,272.47 1.09 901.37 2_MWD+IFR2+MS+Sag (2) 2,107.10 61.17 25.31 1,679.10 1,629.43 872.42 459.46 6,032,674.73 545,307.54 2.40 983.63 2_MWD+IFR2+MS+Sag(2) 2,202.01 61.36 24.85 1,724.72 1,675.05 947.80 494.74 6,032,750.31 545,342.36 0.47 1,066.84 2_MWD+IFR2+MS+Sag (2) 2,293.99 60.66 24.62 1,769.30 1,719.63 1,020.87 528.40 6,032,823.58 545,375.58 0.79 1,147.28 2_MWD+IFR2+MS+Sag(2) 2,390.16 61.06 23.90 1,816.13 1,766.46 1,097.45 562.91 6,032,900.36 545,409.63 0.77 1,231.27 2_MWD+IFR2+MS+Sag(2) 2,485.33 62.40 23.68 1,861.21 1,811.54 1,174.14 596.72 6,032,977.25 545,442.97 1.42 1,315.09 2_MWD+IFR2+MS+Sag(2) 2,579.19 61.89 23.32 1,905.06 1,855.39 1,250.25 629.81 6,033,053.54 545,475.60 0.64 1,398.07 2_MWD+IFR2+MS+Sag (2) 2,672.83 62.53 24.36 1,948.72 1,899.05 1,326.01 663.30 6,033,129.50 545,508.62 1.20 1,480.91 2_MWD+IFR2+MS+Sag (2) 2,767.60 62.48 25.07 1,992.47 1,942.80 1,402.38 698.44 6,033,206.07 545,543.30 0.67 1,564.97 2_MWD+IFR2+MS+Sag (2) 2,862.23 61.62 25.34 2,036.83 1,987.16 1,478.01 734.04 6,033,281.91 545,578.44 0.94 1,648.53 2_MWD+IFR2+MS+Sag (2) 2,955.90 60.22 25.54 2,082.35 2,032.68 1,551.93 769.20 6,033,356.04 545,613.15 1.51 1,730.36 2_MWD+IFR2+MS+Sag(2) 3,051.33 58.83 26.17 2,130.75 2,081.08 1,625.95 805.07 6,033,430.26 545,648.56 1.56 1,812.55 2_MWD+IFR2+MS+Sag(2) 3,142.78 59.87 24.22 2,177.37 2,127.70 1,697.13 838.55 6,033,501.64 545,681.61 2.16 1,891.19 2_MWD+IFR2+MS+Sag(2) 3,237.09 61.41 23.39 2,223.61 2,173.94 1,772.34 871.72 6,033,577.03 545,714.33 1.80 1,973.38 2_MWD+IFR2+MS+Sag(2) 3,332.67 60.78 23.83 2,269.81 2,220.14 1,849.00 905.23 6,033,653.89 545,747.37 0.77 2,057.06 2_MWD+IFR2+MS+Sag(2) 3,426.97 60.06 24.28 2,316.36 2,266.69 1,923.89 938.66 6,033,728.97 545,780.34 0.87 2,139.06 2_MWD+IFR2+MS+Sag(2) 3,521.46 59.84 24.56 2,363.68 2,314.01 1,998.36 972.47 6,033,803.64 545,813.70 0.35 2,220.85 2_MWD+IFR2+MS+Sag (2) 3,615.33 58.96 24.69 2,411.46 2,361.79 2,071.81 1,006.14 6,033,877.28 545,846.92 0.95 2,301.64 2_MWD+IFR2+MS+Sag (2) 3,709.80 60.65 23.59 2,458.97 2,409.30 2,146.32 1,039.52 6,033,951.99 545,879.85 2.05 2,383.28 2_MWD+IFR2+MS+Sag (2) 3,804.04 60.00 24.17 2,505.63 2,455.96 2,221.19 1,072.67 6,034,027.05 545,912.54 0.87 2,465.16 2_MWD+IFR2+MS+Sag (2) 3,898.14 61.14 24.50 2,551.87 2,502.20 2,295.87 1,106.44 6,034,101.92 545,945.86 1.25 2,547.11 2_MWD+IFR2+MS+Sag(2) 3,992.48 60.37 24.96 2,597.96 2,548.29 2,370.63 1,140.88 6,034,176.88 545,979.84 0.92 2,629.42 2_MWD+IFR2+MS+Sag(2) 4,087.20 59.51 25.12 2,645.40 2,595.73 2,444.91 1,175.57 6,034,251.36 546,014.08 0.92 2,711.38 2_MWD+IFR2+MS+Sag(2) 4,181.27 61.59 23.71 2,691.65 2,641.98 2,519.49 1,209.42 6,034,326.14 546,047.48 2.57 2,793.28 2_MWD+IFR2+MS+Sag(2) 4,274.86 61.41 24.12 2,736.31 2,686.64 2,594.68 1,242.76 6,034,401.52 546,080.36 0.43 2,875.53 2_MWD+IFR2+MS+Sag (2) 4,369.78 60.41 24.74 2,782.46 2,732.79 2,670.20 1,277.06 6,034,477.24 546,114.20 1.20 2,958.47 2_MWD+IFR2+MS+Sag (2) 4,464.20 62.11 24.32 2,827.86 2,778.19 2,745.51 1,311.43 6,034,552.75 546,148.11 1.84 3,041.25 2_MWD+IFR2+MS+Sag (2) 4,559.16 61.22 24.61 2,872.93 2,823.26 2,821.59 1,346.04 6,034,629.03 546,182.26 0.98 3,124.82 2_MWD+IFR2+MS+Sag (2) 4,653.47 60.73 25.46 2,918.68 2,869.01 2,896.31 1,380.94 6,034,703.95 546,216.70 0.94 3,207.27 2_MWD+IFR2+MS+Sag (2) 11/132018 4:18:09PM Page 3 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: MPU L-55 Wellbore: MPU L-55 Design: MPU L-55 Survey Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map MD Inc Azi TVD TVDSS +N1 -S +E/ -W Northing (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) 4,748.41 61.88 24.71 2,964.27 2,914.60 2,971.73 1,416.24 6,034,779.58 4,842.56 63.23 23.21 3,007.66 2,957.99 3,048.09 1,450.17 6,034,856.12 4,937.25 61.97 22.85 3,051.24 3,001.57 3,125.45 1,483.05 6,034,933.68 5,031.64 60.53 22.71 3,096.64 3,046.97 3,201.75 1,515.10 6,035,010.16 5,122.96 60.12 23.12 3,141.85 3,092.18 3,274.83 1,545.99 6,035,083.42 5,218.52 59.07 23.02 3,190.21 3,140.54 3,350.65 1,578.28 6,035,159.43 5,314.65 61.76 22.93 3,237.67 3,188.00 3,427.61 1,610.91 6,035,236.58 5,407.94 62.68 23.11 3,281.15 3,231.48 3,503.58 1,643.19 6,035,312.73 5,503.36 62.14 22.96 3,325.34 3,275.67 3,581.40 1,676.28 6,035,390.74 5,597.38 62.12 22.95 3,369.29 3,319.62 3,657.94 1,708.70 6,035,467.46 5,690.31 59.98 22.65 3,414.27 3,364.60 3,732.89 1,740.21 6,035,542.60 5,785.00 59.66 23.01 3,461.87 3,412.20 3,808.34 1,771.97 6,035,618.23 5,880.52 60.28 23.05 3,509.68 3,460.01 3,884.44 1,804.32 6,035,694.52 5,974.80 60.21 23.34 3,556.47 3,506.80 3,959.68 1,836.56 6,035,769.94 6,069.22 59.81 23.58 3,603.66 3,553.99 4,034.69 1,869.11 6,035,845.15 6,163.27 60.89 25.42 3,650.19 3,600.52 4,109.06 1,903.01 6,035,919.71 6,257.50 60.73 25.80 3,696.15 3,646.48 4,183.24 1,938.57 6,035,994.10 6,352.17 61.05 26.29 3,742.21 3,692.54 4,257.56 1,974.89 6,036,068.62 6,447.29 61.65 26.62 3,787.81 3,738.14 4,332.29 2,012.07 6,036,143.57 6,540.76 60.33 26.23 3,833.14 3,783.47 4,405.49 2,048.45 6,036,216.98 6,636.59 60.33 24.63 3,880.58 3,830.91 4,480.68 2,084.20 6,036,292.38 6,730.89 58.97 24.83 3,928.23 3,878.56 4,554.59 2,118.25 6,036,366.49 6,825.67 60.72 25.19 3,975.84 3,926.17 4,628.86 2,152.90 6,036,440.95 6,920.31 61.01 25.32 4,021.91 3,972.24 4,703.62 2,188.16 6,036,515.92 7,014.37 61.97 23.72 4,066.81 4,017.14 4,778.82 2,222.46 6,036,591.32 7,108.84 61.14 24.45 4,111.81 4,062.14 4,854.65 2,256.36 6,036,667.35 7,203.12 60.45 24.61 4,157.81 4,108.14 4,929.52 2,290.52 6,036,742.41 7,297.51 60.50 25.12 4,204.33 4,154.66 5,004.04 2,325.06 6,036,817.13 7,391.42 60.45 25.47 4,250.61 4,200.94 5,077.92 2,359.97 6,036,891.21 7,483.76 60.45 24.45 4,296.15 4,246.48 5,150.74 2,393.87 6,036,964.23 7,579.24 59.79 24.39 4,343.71 4,294.04 5,226.13 2,428.09 6,037,039.81 7,673.50 61.16 24.24 4,390.16 4,340.49 5,300.87 2,461.86 6,037,114.75 7,767.69 60.07 24.08 4,436.38 4,386.71 5,375.75 2,495.46 6,037,189.82 7,862.32 61.21 24.04 4,482.78 4,433.11 5,451.06 2,529.08 6,037,265.33 7,956.86 60.35 23.93 4,528.93 4,479.26 5,526.44 2,562.62 6,037,340.90 8,051.08 61.41 23.87 4,574.78 4,525.11 5,601.69 2,595.97 6,037,416.35 8,146.59 61.62 23.47 4,620.33 4,570.66 5,678.58 2,629.67 6,037,493.43 8,241.03 61.17 23.92 4,665.54 4,615.87 5,754.50 2,662.99 6,037,569.54 8,334.61 61.86 24.13 4,710.17 4,660.50 5,829.63 2,696.48 6,037,644.86 8,409.83 62.35 23.37 4,745.37 4,695.70 5,890.48 2,723.25 6,037,705.87 Well MPU L-55 MPU L-55 Actual RKB @ 49.67usft MPU L-55 Actual RKB @ 49.67usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (°1100') (ft) Survey Tool Name 546,251.55 1.40 3,290.52 2_MWD+IFR2+MS+Sag (2) 546,285.01 2.01 3,374.07 2_MWD+IFR2+MS+Sag (2) 546,317.42 1.37 3,458.13 2_MWD+IFR2+MS+Sag(2) 546,349.00 1.53 3,540.87 2_MWD+IFR2+MS+Sag (2) 546,379.45 0.59 3,620.20 2_MWD+IFR2+MS+Sag (2) 546,411.28 1.10 3,702.61 2_MWD+IFR2+MS+Sag(2) 546,443.44 2.80 3,786.19 2_MWD+IFR2+MS+Sag(2) 546,475.26 1.00 3,868.72 2_MWD+IFR2+MS+Sag (2) 546,507.88 0.58 3,953.28 2_MWD+IFR2+MS+Sag(2) 546,539.82 0.02 4,036.39 2_MWD+IFR2+MS+Sag(2) 546,570.88 2.32 4,117.69 2_MWD+IFR2+MS+Sag(2) 546,602.18 0.47 4,199.53 2_MWD+IFR2+MS+Sag(2) 546,634.07 0.65 4,282.22 2_MWD+IFR2+MS+Sag(2) 546,665.85 0.28 4,364.07 2_MWD+IFR2+MS+Sag (2) 546,697.95 0.48 4,445.84 2_MWD+IFR2+MS+Sag (2) 546,731.40 2.05 4,527.57 2_MWD+IFR2+MS+Sag(2) 546,766.50 0.39 4,609.79 2_MWD+IFR2+MS+Sag(2) 546,802.37 0.56 4,692.44 2_MWD+IFR2+MS+Sag (2) 546,839.10 0.70 4,775.82 2_MWD+IFR2+MS+Sag (2) 546,875.03 1.46 4,857.47 2_MWD+IFR2+MS+Sag (2) 546,910.33 1.45 4,940.70 2_MWD+IFR2+MS+Sag (2) 546,943.92 1.45 5,022.07 2 MWD+IFR2+MS+Sag (2) 546,978.11 1.88 5,104.00 2_MWD+IFR2+MS+Sag(2) 547,012.93 0.33 5,106.64 2_MWD+IFR2+MS+Sag(2) 547,046.77 1.81 5,269.28 2_MWD+IFR2+MS+Sag (2) 547,080.20 1.11 5,352.34 2_MWD+IFR2+MS+Sag (2) 547,113.91 0.75 5,434.63 2_MWD+IFR2+MS+Sag (2) 547,147.99 0.47 5,516.75 2_MWD+IFR2+MS+Sag(2) 547,182.46 0.33 5,598.43 2_MWD+IFR2+MS+Sag(2) 547,215.91 0.96 5,678.74 2_MWD+IFR2+MS+Sag (2) 547,249.68 0.69 5,761.53 2_MWD+IFR2+MS+Sag (2) 547,282.99 1.46 5,843.54 2_MWD+IFR2+MS+Sag (2) 547,316.13 1.17 5,925.61 2_MWD+IFR2+MS+Sag(2) 547,349.29 1.21 6,008.08 2_MWD+IFR2+MS+Sag(2) 547,382.38 0.92 6,090.59 2 MWD+IFR2+MS+Sag(2) 547,415.26 1.13 6,172.90 2_MWD+IFR2+MS+Sag (2) 547,448.50 0.43 6,256.85 2_MWD+IFR2+MS+Sag (2) 547,481.36 0.63 6,339.76 2_MWD+IFR2+MS+Sag (2) 547,514.39 0.76 6,422.01 2 MWD+IFR2+MS+Sag(2) 547,540.79 1.11 6,488.49 2_MWD+IFR2+MS+Sag(2) 11/13/1018 4:18.,09PM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-55 Project: Milne Point TVD Reference: MPU L-55 Actual RKB @ 49.67usft Site: M Pt L Pad MD Reference: MPU L-55 Actual RKB @ 49.67usft Well: MPU L-55 North Reference: True Wellbore: MPU L-55 Survey Calculation Method: Minimum Curvature Design: MPU L-55 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting DLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,496.85 62.58 22.89 4,785.60 4,735.93 5,961.44 2,753.56 6,037,777.00 547,570.67 0.56 6,565.65 2_MWD+IFR2+MS+Sag (3) 8,590.93 61.60 23.16 4,829.63 4,779.96 6,037.95 2,786.08 6,037,853.70 547,602.72 1.07 6,648.78 2_MWD+IFR2+MS+Sag(3) 8,684.76 59.97 23.99 4,875.43 4,825.76 6,113.01 2,818.82 6,037,928.95 547,635.01 1.90 6,730.67 2 MWD+IFR2+MS+Sag(3) 8,779.50 59.95 24.91 4,922.86 4,873.19 6,187.67 2,852.77 6,038,003.80 547,668.50 0.84 6,812.67 2_MWD+IFR2+MS+Sag(3) 8,874.66 60.11 25.39 4,970.39 4,920.72 6,262.29 2,887.80 6,038,078.63 547,703.08 0.47 6,895.09 2_MWD+IFR2+MS+Sag(3) 8,968.87 59.68 25.16 5,017.65 4,967.98 6,335.99 2,922.60 6,038,152.53 547,737.43 0.50 6,976.56 2_MWD+IFR2+MS+Sag(3) 9,062.47 59.69 26.01 5,064.89 5,015.22 6,408.86 2,957.49 6,038,225.61 547,771.88 0.78 7,057.32 2_MWD+IFR2+MS+Sag(3) 9,157.19 60.74 25.08 5,111.95 5,062.28 6,483.03 2,992.94 6,038,299.98 547,806.87 1.40 7,139.49 2_MWD+IFR2+MS+Sag (3) 9,252.27 61.96 24.65 5,157.53 5,107.86 6,558.74 3,028.02 6,038,375.89 547,841.50 1.34 7,222.91 2_MWD+IFR2+MS+Sag (3) 9,346.74 62.09 24.61 5,201.85 5,152.18 6,634.58 3,062.79 6,038,451.93 547,875.80 0.14 7,306.33 2_MWD+IFR2+MS+Sag (3) 9,439.96 59.90 24.25 5,247.05 5,197.38 6,708.80 3,096.51 6,038,526.35 547,909.07 2.37 7,387.85 2_MWD+IFR2+MS+Sag(3) 9,535.28 57.14 23.03 5,296.82 5,247.15 6,783.25 3,129.12 6,038,600.99 547,941.22 3.09 7,469.13 2_MWD+IFR2+MS+Sag(3) 9,629.49 53.99 22.88 5,350.08 5,300.41 6,854.79 3,159.42 6,038,672.70 547,971.09 3.35 7,546.81 2_MWD+IFR2+MS+Sag(3) 9,724.29 51.29 22.21 5,407.61 5,357.94 6,924.38 3,188.31 6,038,742.45 547,999.56 2.90 7,622.14 2_MWD+IFR2+MS+Sag(3) 9,819.02 48.51 21.16 5,468.62 5,418.95 6,991.70 3,215.10 6,038,809.92 548,025.94 3.05 7,694.54 2_MWD+IFR2+MS+Sag (3) 9,910.51 46.06 21.20 5,530.68 5,481.01 7,054.37 3,239.38 6,038,872.74 548,049.84 2.68 7,761.69 2 MWD+IFR2+MS+Sag (3) 10,007.31 43.10 20.40 5,599.62 5,549.95 7,117.87 3,263.52 6,038,936.38 548,073.59 3.11 7,829.53 2MWD+IFR2+MS+Sag(3) 10,101.17 39.99 20.32 5,669.86 5,620.19 7,176.23 3,285.17 6,038,994.86 548,094.89 3.31 7,891.66 2_MWD+IFR2+MS+Sag (3) 10,195.97 37.00 19.59 5,744.05 5,694.38 7,231.68 3,305.32 6,039,050.43 548,114.70 3.19 7,950.53 2_MWD+IFR2+MS+Sag(3) 10,289.59 34.00 19.15 5,820.25 5,770.58 7,282.96 3,323.36 6,039,101.81 548,132.43 3.22 8,004.73 2_MWD+IFR2+MS+Sag(3) 10,384.28 30.61 17.90 5,900.28 5,850.61 7,330.92 3,339.46 6,039,149.87 548,148.23 3.65 8,055.11 2_MWD+IFR2+MS+Sag(3) 10,478.60 27.81 17.49 5,982.59 5,932.92 7,374.77 3,353.45 6,039,193.79 548,161.96 2.98 8,100.88 2_MWD+IFR2+MS+Sag(3) 10,573.49 25.79 16.54 6,067.29 6,017.62 7,415.67 3,365.98 6,039,234.76 548,174.25 2.18 8,143.36 2_MWD+IFR2+MS+Sag(3) 10,667.61 23.97 16.82 6,152.67 6,103.00 7,453.60 3,377.34 6,039,272.76 548,185.38 1.94 8,182.65 2_MWD+IFR2+MS+Sag(3) 10,761.83 21.93 15.98 6,239.43 6,189.76 7,488.114 3,387.73 6,039,308.06 548,195.55 2.19 8,219.08 2_MWD+IFR2+MS+Sag (3) 10,855.31 20.18 13.18 6,326.66 6,276.99 7,521.33 3,396.21 6,039,340.59 548,203.83 2.16 8,252.23 2 MWD+IFR2+MS+Sag (3) 10,949.28 19.59 12.35 6,415.03 6,365.36 7,552.50 3,403.28 6,039,371.80 548,210.71 0.70 8,283.60 2_MWD+IFR2+MS+Sag(3) 11,043.35 19.71 14.04 6,503.62 6,453.95 7,583.29 3,410.50 6,039,402.63 548,217.74 0.62 8,314.69 2_MWD+IFR2+MS+Sag(3) 11,137.24 20.03 12.67 6,591.92 6,542.25 7,614.34 3,417.86 6,039,433.72 548,224.92 0.60 8,346.07 2_MWD+IFR2+MS+Sag(3) 11,233.47 20.17 12.11 6,682.29 6,632.62 7,646.64 3,424.96 6,039,466.06 548,231.82 0.25 8,378.49 2_MWD+IFR2+MS+Sag(3) 11,328.80 20.39 12.65 6,771.71 6,722.04 7,678.91 3,432.04 6,039,498.37 548,238.71 0.30 8,410.88 2_MWD+IFR2+MS+Sag (3) 11,421.72 19.65 12.37 6,859.02 6,809.35 7,709.97 3,438.94 6,039,529.47 548,245.42 0.80 8,442.07 2_MWD+IFR2+MS+Sag (3) 11,443.90 19.43 12.79 6,879.92 6,830.25 7,717.21 3,440.55 6,039,536.71 548,246.99 1.18 8,449.35 2_MWD+IFR2+MS+Sag (3) 11,545.53 19.76 19.09 6,975.68 6,926.01 7,749.93 3,449.91 6,039,569.49 548,256.15 2.10 8,483.07 2_MWD+IFR2+MS+Sag (4) 11,639.37 20.15 14.84 7,063.89 7,014.22 7,780.55 3,459.24 6,039,600.16 548,265.29 1.60 8,514.85 2_MWD+IFR2+MS+Sag(4) 11,734.76 18.88 14.72 7,153.80 7,104.13 7,811.36 3,467.37 6,039,631.02 548,273.24 1.33 8,546.32 2_MWD+IFR2+MS+Sag(4) 11,828.97 17.36 11.11 7,243.33 7,193.66 7,839.89 3,473.95 6,039,659.59 548,279.65 2.01 8,575.08 2_MWD+IFR2+MS+Sag (4) 11,922.31 17.83 12.00 7,332.31 7,282.64 7,867.54 3,479.61 6,039,687.26 548,285.13 0.58 8,602.66 2_MWD+IFR2+MS+Sag(4) 12,017.44 19.29 12.22 7,422.49 7,372.82 7,897.14 3,485.96 6,039,716.90 548,291.31 1.54 8,632.31 2_MWD+IFR2+MS+Sag (4) 12,055.77 19.59 14.10 7,458.63 7,408.96 7,909.56 3,488.87 6,039,729.34 548,294.14 1.81 8,644.85 2_MWD+IFR2+MS+Sag (4) 11/132018 4:18:09PM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU L-55 Project: Milne Point TVD Reference: MPU L-55 Actual RKB @ 49.67usft Site: M Pt L Pad MD Reference: MPU L-55 Actual RKB @ 49.67usft Well: MPU L-55 North Reference: True Wellbore: MPU L-55 Survey Calculation Method: Minimum Curvature Design: MPU L-55 Database: NORTH US+CANADA Survey Map Map vertical MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting DLS Section (usft) (°) (") (usft) (usft) (usft) (usft) (ft) (ft) (`1100') (ft) Survey Tool Name 12,079.00 19.59 14.10 7,480.52 7,430.85 7,917.12 3,490.77 6,039,736.90 548,295.99 0.00 8,652.52 PROJECTEDto TO Checked By: Chelsea Wright` '_w Approved By: Mitch Laird 2— Date: 11/13/18 11/132018 4:18:09PM Page 6 COMPASS 5000.15 Build 91 r Hilcwp Energy Company CASING & CEMENTING REPORT Lease 8 W61 No, Cag WL On Hook: 365.000 Type Float Collar: Ceg WL On SIID¢: 100.000 Type of Shoe: Roger Cat X Yea No Redp Ceg Faid Coexists.: Stud Mud Liner hanger Info(MakerMide0: Ibarh... ertestpresave: Centralizer Placemen: MP L55 Cavin Gr Liner Deh1 Data Run 38Ddd8 County PmMoe Be, SIa1e Ahead Supe. Yewk)Twmey M. Gmtla THD Make CASING RECORD Batlom Top 1 Shoa nd Type: ENeMaOem LA0 UP TD 8.450 OD shoe Dept: 8,440.11 6,u9ao Pero: Calling 958 No, Joe. Delivtted us No. Jb, Run 210 No. Am. Re4aned 18 6438.42 FV. Delieered 9.003.81 Pig, Run 8.361.98 PIg. Returned 710,U Lerym Meewremema WlO Threats Fri CN A. NA7 FV. Balance 1lA9 8356.63 RKB 3067 RKB to BHF 95/8 RKB to CHF 1.80 RKB to THE +mac saJ ��? Poet lob Cat lone: CalaOahM Coat VolVd 6g 0%pcess: 326.1 )del stmt Pumped 411 Cm neduretlbaurfece: 0 Calculaledcementleftnwelbore: 411 d"" l � (('- r S Cag WL On Hook: 365.000 Type Float Collar: Ceg WL On SIID¢: 100.000 Type of Shoe: Roger Cat X Yea No Redp Ceg Faid Coexists.: Stud Mud Liner hanger Info(MakerMide0: Ibarh... ertestpresave: Centralizer Placemen: HNI®umen No. Him to Run: 30 AiAelape Casing Crew: Doyon Causing X Ye¢ No 5 FL Min. 92 PPG Imr lop PeUen: Yea No Floats Held X Yea No Cavin Gr Liner Deh1 Lead Blurry Shwa 8440 SettingDidea Top of Liner Jb. Component Be. M. Gmtla THD Make Le Batlom Top 1 Shoa 103/4 Type: ENeMaOem LA0 UP Andante 1.58 8,440.11 8438.42 2 Calling 958 40.0 L-80 W 60.47 6438.42 8357.95 1 Float Collar 1034 Post Flush (Spawr) L-80 TXP Halliburton 1.32 8375.95 8356.63 1 Chain 95/8 40.0 1.80 UP 92 Rale(1hDm): 39.69 8356.63 8316.94 1 baffle Ada tar 1034 Caayg Rotated? Yea LA0 UP Hallibudwn 1.49 8316.94 8315.45 139 Calling958 Data 101)2016 40.0 LA0 UP Calculated 5,524.29 8315.45 2,791.16 1 Pu Joint 958 40.0 LA0 TXP 14.52 2,791.16 2,776.64 1 EMPC 113/4 LA0 TXP Halliburton 11.86 2776.64 2764.78 1 Pu Joint 958 40.0 LA0 TXP 13.58 2764.78 2751.20 0 Cazi 958 40.0 LEO UP X No spat re4mn?_Yes 2,690.66 2751.20 60.54 1 Cut Joint 95/8 40.0 LEO TXP 26.87 60.54 33.67 +mac saJ ��? Poet lob Cat lone: CalaOahM Coat VolVd 6g 0%pcess: 326.1 )del stmt Pumped 411 Cm neduretlbaurfece: 0 Calculaledcementleftnwelbore: 411 d"" l � (('- r S Cag WL On Hook: 365.000 Type Float Collar: Ceg WL On SIID¢: 100.000 Type of Shoe: Roger Cat X Yea No Redp Ceg Faid Coexists.: Stud Mud Liner hanger Info(MakerMide0: Ibarh... ertestpresave: Centralizer Placemen: HNI®umen No. Him to Run: 30 AiAelape Casing Crew: Doyon Causing X Ye¢ No 5 FL Min. 92 PPG Imr lop PeUen: Yea No Floats Held X Yea No CEMENTING REPORT Lead Blurry Shwa 8440 FC64 8.35653 Top of Liner Type: Penn Pmnush(Special Sacks: 150 Yew: Demiy(Ppg) 10.7 Type: Clain Spacer Densh,(ppg) 10 Volume pumped (OBLa) 60 Tail Blurry Lead Suzry Type: Type: ENeMaOem Backs: Yield: Back¢: 785 Yield: 236 o DerW4(11) Density Spill 12 Volume Pumped(BBLs) 3n Mixing l Pumping Rate(hpm): 5 Post Fwah(Spaces" Tail SbmY \ Type: Premium sack.: 400 Yield: 1.16 F TII¢PlaaemerR e Density(ppg) 15.8 Volume pumped (RRCs) 62 M4ng l Pumped Rate(bard: 4 rroe: wn Densly (pvD) Post Flush (Spawr) Volume (actual lcawuNted): - FCPdsh. Pump used or disp: e Type: Demily(WIS Name (bpm): Volume: X No Reciprocated? _Yes LL Displacement Cement reWns toaWatt? X Ym_No Spaurtetm us?_Yes Type: Spud Mud Done",) 92 Rale(1hDm): 6 Volume pcWau mledated): 629.5630.5 Dak: FCP(p): 1160 Pump us ed for ditty Rb Bump Mug? X Yes No Bump press 1500 Visual Caayg Rotated? Yea X No Prolamine? Yes X No %R.Wrredimngjob 82 Cement reMms W worse? _Yea X No BparorrtWm] X Yes No Vd to Sud: 0 Cementln PlaceN 23:30 Data 101)2016 Entitled TOC: 3,285 Mahod Used To Determine TOG Calculated Tan Slurry Type: PremlumG Sects: 270 Yldd: 117 Denefty(ppg) 15.8 Volume pumped SBU) 58 Mixing/Purim Rme(bDm): 3 Post Flush (Spacer) Type: Oendy(ppg) Ramg,m): Vdume: Displacement: Type: Mud Denaily(ppg) 9.2 Role (bpm): 4 Volume (moWel/wlcurreu): 190/190 FCP firs): 1200 Pump lied for tlbp: Rlg Bump Plug? X Yes No Bump press 2140 Caring Rdatatl? _Yes X No Reciprocated? Yes X No %Reams during job 0 Cement reduces W surtace? _Yea X No spat re4mn?_Yes X No Vol to Surf: 0 Camera In Place N: 1490 Date: 10102018 Battered TOC: 0 Me1M1M Used To Determine TOC: +mac saJ ��? Poet lob Cat lone: CalaOahM Coat VolVd 6g 0%pcess: 326.1 )del stmt Pumped 411 Cm neduretlbaurfece: 0 Calculaledcementleftnwelbore: 411 d"" l � (('- r S Type: DenNy(ppgl VOLme WmpeliBBLe) Lead Blurry Type: Penn Sacks: 150 Yew: Demiy(Ppg) 10.7 Volume pumped(BBU) 118 MWrg l stumping Rate(bpm): Tail Blurry Type: Backs: Yield: o DerW4(11) VcIm- pumped(BB") _ MNng l Pumping Earn(bpm): Post Fwah(Spaces" )rye Demly (ppg) Rate(opm): Volume: F TII¢PlaaemerR rroe: wn Densly (pvD) Rate (bDm): Volume (actual lcawuNted): - FCPdsh. Pump used or disp: Bump PLq? _Y.s N. Bump Press Caling Rogers? _Yea X No Reciprocated? _Yes X No %ReWmsdurmijeb P Cement reWns toaWatt? X Ym_No Spaurtetm us?_Yes X No Vdb " O Burl: 0 Cement In Plaee Fe Dak: Eatlmeled T00: 0 MCNod Used To Determine TOC: Visual +mac saJ ��? Poet lob Cat lone: CalaOahM Coat VolVd 6g 0%pcess: 326.1 )del stmt Pumped 411 Cm neduretlbaurfece: 0 Calculaledcementleftnwelbore: 411 d"" l � (('- r S Hilcorp Energy Company CASING 8, CEMENTING REPORT Lease & Well No. MP L-55 County Prudhoe Bay State Alaska Supv CASING RECORD Intermediate b TD 11,474.00 Shoe Depth: 11,464.00 No. Jts. Delivered 292 No. Jts. Run Date Run 5 -Nov -18 Yessak / Demoski PBTD: 278 No. Jts. Returned 14 Csg Wt. On Hook: 90,000 Type Float Collar: Halliburton No. Hrs to Run: 31.5 Csg Wt. On Slips: 90,000 Type of Shoe: Halliburton_ Casing Crew: Doyon Rotate Csg Yes X No Recip Csg _ Yes X No 10 Ft. Min. 10.5 PPG Fluid Description: LSND Liner hanger Info (Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes _ No Centralizer Placement: Two centralizers on shoe joint then on every jt to jt 13 and on joints 72-74. 17 Centek 7x8-1/2" centralizers and 8 stop rings installed on casing. CEMENTING REPORT Shoe @ 11464 Casing (Or Liner) Detail Top of Liner Preflush (Spacer) Setting Depths As. Component Size Wt. Grade THD Make Length Bottom Top 1 Shoe 73/4 Tail Slurry TXP Halliburton 1.55 11,464.31 11,462.76 2 Casing 7 26.0 L-80 TXP Tenaris 81.63 11,462.76 11,381.13 1 Float Collar 73/4 BTC Halliburton 1.33 11,381.13 11,379.80 275 Casing 7 26.0 L-80 TXP Tenaris 11,345.20 11,379.80 34.60 1 Casing Pup Joint 7 26.0 L-80 TXP Tenaris 2.60 34.60 32.00 1 Casing Hanger 10 FMC 0.33 32.00 31.67 Csg Wt. On Hook: 90,000 Type Float Collar: Halliburton No. Hrs to Run: 31.5 Csg Wt. On Slips: 90,000 Type of Shoe: Halliburton_ Casing Crew: Doyon Rotate Csg Yes X No Recip Csg _ Yes X No 10 Ft. Min. 10.5 PPG Fluid Description: LSND Liner hanger Info (Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes _ No Centralizer Placement: Two centralizers on shoe joint then on every jt to jt 13 and on joints 72-74. 17 Centek 7x8-1/2" centralizers and 8 stop rings installed on casing. LSND mud Density (ppg) 10.5 CEMENTING REPORT Shoe @ 11464 FC @ 11,380.00 Top of Liner Preflush (Spacer) Bump Plug? X Yes No Bump press Type: Clean Spacer III Density (ppg) 10.5 Volume pumped (BBLs) 40 Lead Slurry Spacer returns? Yes X No Vol to Surf: Type: ant In Place At: 2:27 Date: Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type: Premium G Cement Sacks: 180 Yield: 1.15 Density (ppg) 15.8 Volume pumped (BBLs) 37 Mixing / Pumping Rate (bpm): 2 Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: LSND mud Density (ppg) 10.5 Rate (bpm): 5 Volume (actual / calculated): 415.2 (psi): 2090 Pump used for disp: Rig Pump #2 Bump Plug? X Yes No Bump press ig Rotated? Yes X No Reciprocated? _Yes X No % Returns during job 6 ant returns to surface? _Yes X No Spacer returns? Yes X No Vol to Surf: 0 ant In Place At: 2:27 Date: 11[7/2018 Estimated TOC: 10,964 od Used To Determine TOC: Calculation Post Job Calculations: Calculated Cmt Vol @ 0% excess: 23.6 Total Volume cmt Pumped: 37 Cmt returned to surface: 0 Calculated cement left in wellbore: 37 OH volume Calculated: 37 OH volume actual: 37 Actual % Washout: 40 www.wellez.net WellEz Information Management LLC ver 04818br Lease & Well No. County TD 12 079 00 Hilcorp Energy Company CASING & CEMENTING REPORT MP L-55 Prudhoe Bay State Alaska Supv. CASING RECORD Liner �!� Shoe Denth: 11.033. R7 PRTn _ Date Run 12 -Nov -18 Yessak / Demoski Csg Wt. On Hook: Type Float Collar: Innovex No. Hrs to Run: Casing (Or Liner) Detail Csg Wt. On Slips: Type of Shoe: Innovex Setting Depths Jls. Component Size Wt. Grade THD Make Length Bottom Top 1 Float She 5 12.6 L-80 TXP Innovex 1.41 12,033.67 12,032.26 1 Liner 41/2 12.6 L-80 TXP 41.12 12,032.26 11,991.14 1 Float Collar 5 12.6 L-80 TXP Innovex 1.31 11,911.14 11,989.83 2 Liner 41/2 12.6 L-80 TXP 81.10 11,989.83 11,908.73 1 Landing Collar 5 12.6 L-80 TXP Baker 1.09 11,908.73 11,907.64 15 Liner 41/2 12.6 L-80 TXP 598.51 11,907.64 11,309.13 1 Pup Joint 41/2 L-80 TXP 1.86 11,309.13 11,307.27 1 Crossover 5 1/2 L-80 HT x TX 1.73 11,307.27 11,305.54 1 x lock Liner Han 5 5/8 L-80 VTHT 9.40 11,305.54 11,296.14 HRD-E ZXP LTP 1 6 L-80 I VTHT 23.34 11,296.14 11,272.80 Csg Wt. On Hook: Type Float Collar: Innovex No. Hrs to Run: Csg Wt. On Slips: Type of Shoe: Innovex Casing Crew: Doyon Casing Rotate Csg Yes X No Recip Csg Yes X No Fl. Min. 11.5 PPG Fluid Description: LSND Liner hanger Info (Make/Model): Liner top Packet?: X Yes No Liner hanger test pressure: 3500 Floats Held _ X Yes No Centralizer Placement: _ Shoe @ 12034 ush (Spacer) Tuned Spacer Slurry sity (ppg) Slurry CEMENTING REPORT FC @ 11,990.00 Density (ppg) 13.5 Volume pumped (BBLs) Top of Liner 11272 Volume pumped (BBLs) 15 Sacks: Yield: Mixing / Pumping Rate (bpm): Type: Class G Sacks: 145 Yield: 1.16 Density (ppg) 15.8 Volume pumped (BBLs) Mixing / Pumping Rate (bpm): 2 Post Flush (Spacer) Density (ppg) Rate (bpm): Volume: LSND Mud Density (ppg) 11.4 Rate (bpm): 2 Volume (actual / calculated): (psi): 750 Pump used for disp: Rig Bump Plug? X Yes No ig Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job ant returns to surface? X Yes —No Spacer retums? X Yes No Vol to Surf: ant In Place At: 11:45 Date: 11/13/2018 Estimated TOC: od Used To Determine TOC: 7 bbl back FTOL Post Job Calculations: Calculated Cart Vol @ 0% excess: Cmt returned to surface: 7 OH volume Calculated: 9.5 13.1 Total Volume cmt Pumped: Calculated cement left in wellbore: 13 OH volume actual: 9.5 Actual % Washout: WellEz Information Management LLC ver Bump press 1500 100 20 11 Hydraulic Fracturing Fluid Product Component Information Disclosure 1w Fracture Date: State: County/Parish API Number: Operator Name: Well Name and Number: Longitude: Latitude: Long/Lat Projection: Production Type: 12/8/2018 Alaska North Slope Borough 50029236120000 Hilcorp Alaska, LLC MPL-55 -149.63320436351 70.4977403821024 True Vertical Depth (TVD): Total Water Volume (gal)*: 7207 85571 Hydraulic Fracturing Fluid Composition i Trade Name Supplier Purpose Ingredients Chemical Abstract i Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass).* Comments YF130FIexD:WF12 O:YF125FIex D:WF130:WF125 Schlumberger Surfactant , Breaker, Gelling Agent, Crosslinker, Clay Control Agent, LTCA, Additive, Bactericide, Propping Agent Water (Including Mix Water Supplied by Client)* CAS Not Assigned 77.28910% Ceramic materials and wares, chemicals 66402-68-4 96.62610% 21.94466% Guar gum 9000-30-0 1.23594% 0.28069% 2-hydroxy-N,N,N- tri methyletha nam i n iu m chloride 67-48-1 0.55778% 0.12668% Methanol 67-56-1 0.33407% 0.07587% Ulexite 1319-33-1 0.31652% 0.07188% Alcohols,c11-15- secondary, ethox lated 68131-40-8 0.21158% 0.04805% Ethylene Glycol 107-21-1 0.18325% 0.04162% Diammonium eroxidisul hate 7727-54-0 0.18067% 0.04103% Propan-2-ol 67-63-0 0.07155% 0.01625% 2-butoxyethanol 111-76-2 0.07155% 0.01625% Ethoxylated C11 Alcohol 34398-01-1 0.06572% 0.01492% Chemical Maximum Maxim Abstract Ingredient Ingredient Trade NameSupplier Purpose Ingredients Service Concentration Concentration Cornmen Number (CAS in Additive in HF Fluid Al toft#) (% by mass)** (% by mass)*j Sodium hydroxide 1310-73-2 0.04623% 0.01050% Ethoxylated Alcohol 68131-39-5 0.03567% 0.00810% Sodium Tetraborate 1303-96-4 0.03498% 0.00795% Decah drate Vinylidene 25038-72-6 0.02780% 0.00631% chloride/methylacrylate copolymer Poly(oxy-1,2- 25322-68-3 0.01114% 0.00253% etha ned iyl ),a-hydro-w- hydroxy- Ethane -1,2 - diol, ethox lated but-2-enedioic acid 110-17-8 0.00833% 0.00189% Undecanol 112-42-5 0.00572% 0.00130% Diatomaceous earth, 91053-39-3 0.00524% 0.00119% calcined Non -crystalline silica 7631-86-9 0.00310% 0.00070% (impurity) Magnesium nitrate 10377-60-3 0.00105% 0.00024% Magnesium silicate 14807-96-6 0.00085% 0.00019% hydrate talc 5 -chloro -2 -methyl -2h- 26172-55-4 0.00056% 0.00013% isothiazolol-3-one Magnesium chloride 7786-30-3 0.00052% 0.00012% Diutan gum 125005-87-0 0.00042% 0.00009% Diutan 595585-15-2 0.00042% 0.00009% poly 9002-84-0 0.00036% 0.00008% tetrafluoroeth lene Acetic acid, potassium 127-08-2 0.00021% 0.00005% salt 2-methyl-2h-isothiazol-3 2682-20-4 0.00017% 0.00004% -one Cristobalite 14464-46-1 0.00010% 0.000020/. Quartz, Crystalline silica 14808-60-7 0.00010%1 0.00002% Acetic acid (impurity) 64-19-7 0.00004%1 0.00001 t Proprietary Technology Total Water Volume sources may include fresh water, produced water, and/or recycled water " Information is based on the maximum potential for concentration and thus the total may be over 100% Report ID: RPT -59130 (Generated on 12/14/2018 1:07 PM) component information listed was obtained from the supplier's Safety Data Sheets (SDS). As such, the Operator is not responsible for inaccurate Vor incomplete information. Any questions regarding the content of the SDS should be directed to the supplier who provided it. The Occupational tety and Health Administration's (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects oprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an SDS is subject to 29 CFR 10.1200(i) and Appendix D. evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information known to GRC-Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. Schlumbepgep FracCAT Treatment Report: Well MPL-55 Field Kuparuk Formation A Sand Well Location 58 County Prudhoe Bay State : Alaska Country United States Prepared for Calibration BH ISIP (psi) Client Hilcorp Alaska LLC Client Rep Almas Aitkulov, Jim Abel Date Prepared December 7, 2018 Prepared by Name Alexander Martinez Division Schlumberger Phone 561-389-5006 Pressure Zones) iAll Initial Wellhead Pressure (psi) 58 Surface Shut in Pressure(psi) 2,803 Calibration Surface ISIP (psi) 2,560 Final Surface [SIP (psi) 2,952 Calibration BH ISIP (psi) 5,687 Final BH ISIP (psi) 6,079 Maximum Treating Pressure (psi) Treatment Totals (All Zones As Per FracCAT) 5,740 Total Slurry Pumped (Water+Adds+proppant) bbls 2318.1 Total YF125FIei Past Wellhead (ti 788.9 Total WF120 Past Wellhead (bbls) 348.0 Total YF130FIexD Past Wellhead (bbls) 741.0 Total WF125 Past Wellhead (bbls) 87.5 Total Freeze Protect Past Wellhead (bbls) 31 Total WF130 Past Wellhead (bbls) Total Chemical Additives Invoiced 89.9 Past WH Total 16120 CarboBond Lite Pumped (lbs.) Invoiced 202,760 Past WH J580 (Ibs) 2675 2600 J604 (gal) 154 154 L071 (gal) 170 170 M002 (Ibs) 97 97 F103 (gal) 96 96 J134(Ibs) 10 0 J475 (Ibs) 330 330 M275 (Ibs) 30 22 J218 (lbs) 110 110 LTCA (gal) 140 140 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability foradvice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of thewell, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well orwells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Schlumberger -Private Schlumberger Job Plots: E Pressure Test — Tr. Press — Annulus Press — Slurry Rate r Client: Hilcorp Alaska Well: MPL-55 formation: Kuparuk A District: Prudhoe Bay Country: United States Hilcorp Alaska MPL-55 07 -Dec -2018 Schlumberger 1994-2016 Time - hh:mm:ss Schlumberger -Private 12 T Schlumberger n. Schlumberger N N d DataFrac — Tr. Press — Annulus Press — Slurry Rate Client: Hilcorp Alaska Well: MPL-55 Formation KuparukA District: Prudhoe Bay Country: United States Hilcorp Alaska MPL-55 07 -Dec -2018 © Schlumberger 1990-2016 Time - hh:mm:ss Schlumberger -Private Q 3 3 Schlumberger -O Schlumberger N d Main Treatment — Tr. Press — Annulus Press — Slurry Rate Client Hilcorp Alaska Well. MPL-55 Formation. KuparukA District Prudhoe Bay Country United States Hilcorp Alaska MPL-55 07 -Dec -2018 aD Schlumberger 1994-2016 Time - hh:mm:ss Schlumberger -Private Q 3 5 Schlumberger n. l/ Schlumberger Data Frac Additives Client: Hilcorp Alaska Well: MPL-55 Formation: Kuparuk A District: Prudhoe Bay Country: United States — SLUR _RATE Hilcorp Alaska — CFLD RATE MPL-55 07 -Dec -2018 — J604_CONC — F103 CONC Q Schlumberger 1999-2016 Time - hh:mm:ss Schlumberger -Private 50 r- Schlumberger Schlumberger 4C 30 10 0 16:50:44 Main Treatment Additives — SLUR—RATE — CFLD_RATE — J604_CONC — U028 CONIC Client: Hilcorp Alaska Well: MPL-55 Formation: Kuparuk A District: Prudhoe Bay Country: United States Hilcorp Alaska MPL-55 07 -Dec -2018 0 Schlumberger 1994-2016 10 9 8 0 17:15:44 17:40:44 18:05:44 18:30:44 Time - hh:mm:ss Schlumberger -Private 100 schkiOmpr — F103_CONC — L071_CONC — LTCA_CONC — J475_CONC — J218_CONC 0 Schlumberger 1994-2016 10 9 8 0 17:15:44 17:40:44 18:05:44 18:30:44 Time - hh:mm:ss Schlumberger -Private 100 schkiOmpr Schlumberger Section 1: As Measured Pump Schedule Client: Hilcorp Alaska Well: MPL-55 Formation: Kuparuk A District: Prudhoe Bay Country. United States Schlumberger -Private As Measured Pump Schedule Step Step Name Slurry Volum (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop ,PPA) Prop Conc (PPA) Prop Mass (Ib) 1 Injection Test 21. 3.6 WF120 895 0 0 0 2 Injection Test 175 28 6.8 WF120 7329 0J61 0 3 Calibration 125 3 3.6 WF120 5261 004 Ste Down 6. 11.3 8 WF120 29 005 Shutdown 0 0 6 W�eS19. 6.1 3.3 WF120 833 007 Shutdown 0 0 0 0 0 008 PAD 90. 24.8 4. WF130 377 009 Shutdown 0 0 0 0 0010 PAD 30 35.1 8.5 YF130FlexD 12600 0011 1.0 PPA 200. 34. 5. YF130FIexD 8071 CarboBond Lite 16/20 1.112 2.0 PPA 13 34. 3. YF130FIexD 524 CarboBond Lite 16/20 27113 3.0 PPA 14 33. 4. YF130FIexD 520 CarboBond Lite 16/20 3.514 4.0 PPA 291 30. 9.6 YF125FIexD 1033 CarboBond Lite 16/20 4.2315 5.0 PPA 244.5 30.1 8.1 YF125FlexD 835 CarboBond Lite 16/20 5.3616 6.0 PPA 12 28.2 4. YF125FlexD 4186 CarboBond Lite 16/20 6.1117 7.0 PPA 7 28.1 2.7 YF125FlexD 2454 CarboBond Lite 16/20 7.72 18 8.0 PPA 186.9 26.4 7.1 YF125FlexD 5860 CarboBond Lite 16/20 8.5 7.4 4338 19 XL Flush 46.2 25.4 1.8 YF125FIexD 1940 0 0 0 20 LG Flush 87. 25. 3. Wirt 25 367 0 0 0 21 Freeze Protect 40.4 20.3 2.1 Freeze Protect 1711 0 0 0 Schlumberger -Private Schlumberger Client: Hilcorp Alaska Well: MPL-55 Formation: Kuparuk A District: Prudhoe Bay Country: United States As r Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal)(Ib) 2318.1 92.0 1 88032 202760 Average Treating Pressure: 4199 psi Stage Pressures i Rates 1105 psi Average Injection Rate: Step R Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Vinumurn Treating Pressure Pressure (psi) (psi) 1 Injection Test B.0 3.2 2794 2873 1681 Injection Test 28.6 31.1 4967 5699 2446 Calibration 36.0 11.0 4267 4642 3009 tep Down 11.3 16.3 2800 3026 1264 Shutdown 5.1 i.4 2776 2852 1106 PAD 4.8 4.6 3807 4261 1105 PAD 5.1 5.3 4413 4523 4216 1.0 PPA 4.7 5.1 4349 4494 4270 .0 PPA 4.7 4.8 4312 4376 4284 10 .0 PPA 3.7 4.7 4354 4436 4241 11 .0 PPA 0.5 2.2 4172 4390 4093 12 .0 PPA 0.1 0.7 4189 4348 3967 13 .0 PPA 8.2 8.4 4008 4039 3987 14 .0 PPA 8.1 8.1 T4022 041 4008 15 .0 PPA 26.4 8.1 921 162 3722 16 LFlush 5.45.6 820 879 1975 710 17 LG Flush 5.2 5.7 870 924 3531 18 Freeze Protect 2G.3 P1.1 681 1241 As r Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal)(Ib) 2318.1 92.0 1 88032 202760 Average Treating Pressure: 4199 psi Maximum Treating Pressure: 5699 psi Minimum Treating Pressure: 1105 psi Average Injection Rate: 30.3 bbl/min Maximum Injection Rate: 41.0 bbl/min Average Horsepower: 3155.8 hhp Maximum Horsepower: 4622.7 hhp Maximum Prop Concentration: 8.5 PPA Schlumberger -Private Schlumberger Section 2: Job Messages Client: Hilcom Alaska Well: MPL-55 Formation: Kuparuk A District Prudhoe Bay Country: United States Schlumberger -Private Message r. # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 Reset Executed Steps a 0A 0.0 0. z Reset Executed Steps a CA 0.0 0. 3 13:12:14 Getting equipmentfired back up a 0A 0.0 0. 4 13:49:26 Priming pumps 116 71 0.1 4.0 0. 5 13:57:09 Mixing 20#gel 91 71 0. 4.5 0. 6 14:11:23 Checking oilier system on pump 5 144 74 0. 0.0 0. 7 14:23:32 Getting lined up to PT 189 74 0A 0.0 0. a 14:30:16 Coming up for high PT 1684 74 0A 0.0 0. 9 14:34:08 Weep hale dripping moving more diesel to warm Iron 31 74 0A 0.0 0. 10 14:54:23 Client approved Pressure test 7834 251 0. 0.0 0. 11 15:22:44 Safety meeting is done 36 245 0. 0.0 0. 12 15:29:11 Priming POD with water 47 243 0. 0.0 0. 13 15:32:08 Matching wellhead pressure 67 243 0. 0. 0. 14 15:35:07 Opening the well 7 244 0. 0.0 0. 15 15:36:28 Started Pumping 1517 258 0. 3.5 0. 16 15:40:14 Start Injection Te Manually 240 266 21. 0.0 0. 17 15:44:05 Freeze protect is displaced 247 266 21. 0.0 0. 1s 15:51:56 Stage at Perfs: Injection To 403 292 191. 31.1 0. 19 15:55:44 Start Step Down Automatically 3173 291 321. 14.4 0. 20 16:32:10 Start Shutdown Manually 1705 267 328. 2.8 0. 21 17:00:08 Start PAD Manuallythen shutdown to check crosslink additives 1105 247 348.0 0.0 0. 22 17:07:07 Start PAD Manually 4319 282 438.4 35.2 0. 23 17:09:15 Stage at Perfs: Calibration 4281 292 513.1 34.9 0. z4 17:09:27 Stage at Perfs: Step Down 4316 291 520.1 35.2 0. 25 17:15:40 Start 1.0 PPA Automatically 4494 293 738.7 35.1 0. 26 17:15:40 Started Pumping Prop 4494 293 738.7 35.1 0. 27 17:21:11 Stage at Perfs: PAD 4275 293 930.1 34.7 1.1 28 17:21:27 Start 2.0 PPA Automatically 4301 294 939.4 34.6 1. 29 17:25:23 Start 3.0 PPA Automatically 4387 293il 1075.8 34.8 2. 30 17:26:58 Stage at Perfs: PAD 4421 293 1130.7 34.7 3. 31 17:29:36 Start 4.0 PPA Automatically 4348 2930 1217.4 32.3 2. 32 17:31:10 Stage at Perfs: 1.0 PPA 4136 2925 1267.2 30.1 4. 33 17:32:09 Activated Extend Stage 4140 2931 1296.7 30.1 4. 34 17:35:52 Stage at Perfs: 2.0 PPA 4154 2937 1408.8 30.3 4. 35 17:39:08 Deactivated Extend Stage 4173 2943 1507.8 30.41 4.1 36 17:39:09 Start 5.0 PPA Automatically 417 2945 1508.3 30.4 4. 37 17:43:00 Activated Extend Stage 4225 2927 1625.0 30.2 5. 35 17:45:28 Stage at Perfs: 3.0 PPA 4259 292 1699.7 30.4 5. 39 17:47:16 Deactivated Extend Stage 3991 288 1752.4 27.9 5. 40 17:47:17 IStart 6.0 PPA Automatically 3991 288 1752.8 27.9 5. 41 17:51:48 tart 7.0 PPA Automatically 4024 293 1880.0 28.0 6. 4217:54:05 tage at Perfs: 4.0 PPA 402 290 1944.1 28.1 6. 43 17:54:33 tart B.O PPAAutomatically 4035 295 1957.2 28.0 7.1 44 17:5622 ctivated Extend Stage 4121 295 2008.1 27.9 S. 45 17:58:45 IStage at Perfs: 5.0 PPA 381 294 2071. 25.01 7. Schlumberger -Private Schlumberger Client Hilcorp Alaska Well: MPL-55 Formation: Kuparuk A District: Prudhoe Bay Country: United States Schlumberger -Private Message Log 9 Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 46 18:01:39 Deactivated Extend Stage 3732 2961 2143.8 25.3 -0.1 47 18:01:39 Start XL Flush Manually 3732 2961 2143.8 25.3 -0.1 48 18:01:46 Stopped Pumping Prop 3775 2982 2146.7 25.0 -0.1 49 18:01:50 Stage at Perfs: 6.0 PPA 3686 2956 2148.4 25.3 0. so 18:03:28 Start LG Flush Manually 38711 296 2190.01 25.7 0. St 18:03:30 Activated Extend Stage 387 296 2190.8 25.5 0. 52 18:06:58 Deactivated Extend Stage 349d 294 2277.8 20.4 0. S3 18:06:58 Start Freeze Protect Manually 349 2940 2277.8 20.4 0. 54 18:07:00 Activated Extend Stage 3528294 2278.4 20.4 0. 55 18:27:05 Well shut in 2747 228 2318.1 0.0 0. 56 18:27:16 Bleeding pressure 2721 220 2318.1 0.1 0. 57 18:27:50 Deactivated Extend Stage 74 195 2318.1 0.0 0. Schlumberger -Private Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Monday, October 29, 2018 1:40 PM To: Joe Engel Cc: Monty Myers; Doug Yessak - (C); Regg, James B (DOA) Qim.regg@alaska.gov) Subject: RE: HAK MPU L-55 (PTD: 218-109) Update Joe, You have verbal approval to pump the class G and close the ESIPC. You must notify an inspector to witness the annulus tag using the 1'/:" tubing string before pumping any cement. As we discussed on the phone attempt to run as many of the 30 its of 1.5" pipe as possible. Also submit a sundry to document the procedure outlined below. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv.schwartz � alasko.aoy). From: Joe Engel <jengel@hilcorp.com> Sent: Monday, October 29, 2018 12:17 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Monty Myers <mmyers@hilcorp.com>; Doug Yessak - (C) <dyessak@hilcorp.com> Subject: HAK MPU L-55 (PTD: 218-109) Update Good Morning Guy— This email is to follow up from our earlier conversation and provide an update on MPU L-55. Over the weekend we successfully ran our 9-5/8" surface casing to 8,440' MD, planned casing point. We performed our first stage cement job (329bbi Lead 82bbl tail), bumping the plug on strokes with returns throughout the job (we had 114 bbl of losses during the first stage job). After bumping the plug, we pressured up to inflate the ESIPC packer element and open the stage tool ports and we saw pressure drop — 500 psi lower than what the tool was pinned for at — 2550 psi, after the pressure drop we were unable to circulate with any returns and an injection rate was established. When the pumps were turned off, we did see partial returns up the annulus. To ensure that the stage tool ports were open, we dropped the freefall opening plug and pushed it on to seat with a 2- 7/8" work string. We attempted to pressure up, open the ports and establish circulation again from surface but were unable to, an injection rate was established again. Below are base permafrost, stage tool and calculated 1" stage TOC numbers. MD TVD Base Permafrost 2538 1886 Stage Tool Depth 2764 1990 TOC 1st Stage Calculated I c705 I 2057 Our plan forward is to pump 56 bbls of our 2" stage tail cement followed by the stage tool closing plug to ensure there is cement behind the stage tool and shift the tool closed to regain 9-5/8" pressure integrity. We will then perform a top job with our Perm L cement, using 1-1/2" tubing ran in the 12-1/4" x 9-5/8" annulus as deep as possible and pump cement to surface. Please let me know if you have any questions or concerns with this plan forward. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 r jjeora Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Ham,rp:U,.4.. UX Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 12/27/2018 To: Alaska Oil & Gas Conservation Commission ��+r Abby Bell %�`&p� U ettW6 333 W 7th Ave Ste 100 JAN 0 7 2019 Anchorage, AK g 99501 OGCC CD: Hilmrp_MPU_L-55_SCMT_28Nov 18 FINAL 11/29/2018 2:42 PM File folder 218109 30214 Please include current contact information if different from above. Please acknowledge ripceipt by signi"d returning one copy of this transmittal or FAX to 907 777.8510 Received By: /-j' // / � y I Date: THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk River Oil Pool, MPU L-55 Permit to Drill Number: 218-109 Sundry Number: 318-545 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. aogcc.a laska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this tZ day of December, 2018. ABDMSILDEC 13 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 i" EGEL V E 2018 j�T 5 t L l 2- l 1. Type of Request: Abandon ❑ Plug Perforations ❑ rFmcture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate V Other Stimulate ❑ (-r'Puullll.Tubing ❑� Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ElRe-enter Suer, Well ElSAIteY Casing ❑ Other: ESP Completion Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q . Stratigraphic ❑ Service ❑ 218-109 - 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23612-00-00 - 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D Will planned perforations require a spacing exception? Yes ❑ No D MPU L-55 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025509 / ADL355017 Milne Point Field/ Kuparuk Oil Pool - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,079' 7,481' 11,907' 7,318' 2,992 NIA N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 60' NIA N/A Surface 8,406' 9-5/8" 8,440' 4,759' 5,750psi 3,090psi Intermediate 11,432' 7" 11,464' 6,899' 7,240psi 5,410psi Liner 761' 4-1/2" 12,034' 7,438' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 4-1/2" 12.6# / L -80I TXP 11,281' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 4.5' x 7• AHC & LTP Packers and N/A 11,139 MD/ 6,594 TVD & 11,273 MD / 6,719 TVD and N/A 12. Attachments: Proposal Summary Q Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch [2] Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 12/12/2018 OIL 0- WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Be York Contact Name: Taylor Wellman Authorized Title: Operations Manager Contact Email: twelInTal-0-hilcorlp.corn Contac[ Phone: 777-8449 C Authorized Signature: r,t r �'c:. Date: 12/6/2018 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: J Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: .*- 57M p Sc kT✓` G 5 i Post Initial Injection MIT Yes ❑ No ❑ `I / /) t�' Spacing Exception Required? Yes No Subsequent Form Required: ❑ U APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: l IWO- t7— tZ 12'_10-" ORIGINAL 4BDMS!DEC 131010 Submit Form and Form 10-403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachmen(s in Duplicate K Hilm A11A1 r.0 ESP Completion Well: MP L-55 Date: 12/05/2018 Well Name: MP L-55 API Number: 50-029-23611-00 Current Status: New Well Pad: L -Pad Estimated Start Date: December 15, 2018 Rig: ASR #1 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 218-104 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907) 947-9533 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Current Bottom Hole Pressure: 3,692 psi @ 7,000' TVD (Estimated reservoir pressure / 10.14 ppg EMW) Maximum Expected BHP: 3,692 psi @ 7,000' TVD (Estimated reservoir pressure / 10.14 ppg EMW) MPSP: 2,992 psi (0.1 psi/ft gas gradient) Brief Well Summary: The Milne Point L-55 well was drilled as a Kuparuk River development well in November 2018 and completed with a 4-1/2" fracture stimulation string. After the fracture stimulation of the Kuparuk A sands, the 4-1/2" tubing string will be replaced by a 2-7/8" permanent ESP completion. The well is cased and cemented. Notes Regarding Wellbore Condition • The 7"x4-1/2" production casing was tested to 3,500 psi for 30 minutes on November 15, 2018. CO 390A: The reservoir pressure is above the 8.55ppg EMW and Hilcorp Alaska will be setting an ESP packer to comply with the order. Objective: Replace the 4-1/2" tubing with a 2-7/8" ESP completion. Pre -Rig Procedure: 1. RU E -line. Test lubricator to 250 psi low/ 3,500 psi high. 2. MU and RIH w/ 5' of 3-1/8" guns and perforate the following interval: J a. Kuparuk B/C: +11 682' —+11 68T Mn b. Note this is the same perf interval was also outlined in the Hydraulic Fracture Sundry. 3. RIH w/ chemical cutter and cut the Halliburton AHC packer mandrel. a. Use the XN nipple at 11,144' and for proper space out. b. There is a small cutting window of the packer mandrel of 5.8". Confirm space out of tools prior to RIH with tools for space out for cut. c. Measured distance from the no-go to the middle of the cut zone is 3.47'. 4. RD E -line. 5. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. RU Little Red Services. RU reverse out skid and 500 bbl returns tank. 8. Pressure test lines to 4,000 psi. 9. Circulate at least one wellbore volume with ±10.3 ppg brine down tubing, taking returns up casing to 500 bbl returns tank. Calculate kill weight fluid and circulate the well dead. Bamro Alaska. I.I. ESP Completion Well: MP L-55 Date: 12/05/2018 10. Confirm well is dead. Freeze protect tubing/casing if needed with 60/40 McOH or diesel. 11. RD Little Red Services and reverse out skid. 12. RU crane. Set BPV. ND Tree. NU 11" BOPE. RD Crane. 13. NU BOPE house. Spot mud boat. Brief RWO Procedure: 14. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 15. Check for pressure and if 0 psi pull BPV. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well with kill weight fluid prior to pulling BPV. Set TWC. 16. Test BOPE to 250 psi Low/ 3,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test Annular, VBR and pipe rams on 2-7/8" and 4-1/2" test joints. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 17. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) ,VA., W" a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness test. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 18. Bleed any pressure off casing to 500 bbl returns tank. Pull TWC. Kill well w/ kill weight fluid as needed. 19. MU landing joint or spear to the tubing hanger. BOLDS. 20. Unseat hanger and release packer. Check for flow to ensure well is dead. Recover the tubing hanger. Contingency (If a rolling test was conducted): MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 21. Contingency: If the packer will not release. a. RU E -line. Test lubricator to 250/3,000 psi. b. RIH w/ cutter. Correlate packer cut depth off of XN nipple at 11,144' and below the packer. c. Make cut across packer mandrel. H IIamro dtseka, LG d. POOH. RD E -line. ESP Completion Well: MP L-55 Date: 12/05/2018 22. POOH and lay down the 4-1/2" tubing and completion jewelry. • Send 4-1/2" 12.6#/ft L-80 TXP-SR tubing in for cleaning and storage with thread protectors. • Junk 4-1/2" Packer. • Send 4-1/2" Jewelry to Halliburton Shop for cleaning and reuse (4-1/2" XN nipple). 23. PU new ESP completion and RIH on 2-7/8" tubing. Set base of ESP at ± 11,150' MD. a. Tubing hanger b. 3 joints of tubing c. Upper GLM @ ± 140' MD w/SO d. 2-7/8" tubing e.SP Packer @ 3,400' MD with vent valve and control line 4- �j f. 2-7/8" tubing g. Lower GLM w/ DGLV h. 2 joints of tubing i. 2-7/8" XN (2.205" No -Go) – Pre -load RHC plug body a. Confirm ball and rod size on plug body. Improper sizing will damage ESP. j. 1 joint of tubing k. Base of ESP centralizer @ ± 11,150' MD 24. Land tubing hanger. RILDS. Lay down landing joint. Note PU (Pick Up) and SO (Slack Off) weights on tally. 25. Freeze protect inner annulus taking returns from the tubing (^'100 bbls). Shut in IA. 26. Drop ball and rod and allow to fall on seat. 27. Pressure up tbg as per Weatherford Supervisor to set the ESP packer. 28. Test tbg to 3,000po30 min (charted). Test the IA to 2,000psi for 30 min (charted). Bleed all pressures to Opsi. �— M, ( f g 29. Set BPV. Test tubing hanger void to 500 psi low/5,000 psi high. v 30. RD Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500bbl returns tank. y� 31. RD mud boat. RD BOPE house. 32. RU crane. ND BOPE. Pull BPV and set TWC. 7 33. ND BOPE and NU 2-9/16" tree. Test tree flange to 500 psi low/5000 psi high. Freeze protect well (may be done post -rig) 34. Replace gauge(s) if removed. 35. Pull TWC. RD Crane. 36. Turn well over to production. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Blank RWO MOC Form .H Hibmry Alaska, I Orig. KB Elev.: 33.7 / GL Elev.: 16.9 TD =12,079' (MD) / TD = 7,481' (TVD) PBTD =11,907' (MD) / PBTD = 7,318' (TVD) SCHEMATIC Milne Point Unit Well: MPL-55 Last Completed: 11/17/18 PTD: 218-109 TREE & WELLHEAD Tree 5M 4-1/16" Wellhead 5M FMCGen IV OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 11,853 ft3/464 ft3, Stg 2 316 ft3, Top Job 650 ft3 9-7/8"x 8-1/2" 207 ft3 6-1/8" 112 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835 Surface 8,440' 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface 11,464' 0.0383 4-1/2" Liner 12.6 / L-80 / TXP 3.958 11,273' 12,034' 0.0152 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TXP 1 3.958 1 Surface 11,281' 0.0152 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle 58 deg JEWELRY DETAIL No. Top MD Item ID 1 11,139' 4-1/2" x 7" AHC Packer (Cut to Release) 3.880 2 11,144' 4-1/2"XN Nipple - No-go = 3.725" 3.725 3 11,272' Mule Shoe— Bottom @ 11,281' 3.958 4 11,273' Liner Top Packer 4.340 GENERAL WELL INFO API: 50-029-23612-00-00 Cased by Doyon 14: 11/13/2018 PERFORATION DETAIL Sands I Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status Kuparuk A2 1 11,795' 11,801' 7,211' 7,217' 6 3-1/8" 11/30/18 Open Ref Log: 11/12/2018 Halliburton M W O jp, w /A{ Ik-o0 Revised By: TTW 12/03/2018 .H ear�R Alaalca,l.LC Orig. KB Elev.: 33.7 / GL Elev.:16.0' PROPOSED Milne Point Unit Well: MP L-55 Last Completed: 11/17/18 PTD: 218-109 TREE & WELLHEAD Tree 5M 4-1/16" Wellhead 5M FMC Gen IV OPEN HOLE/ CEMENT DETAIL Conductor Driven 12-1/4" Stg 11,853 ft3/464 ft3, Stg 2 316 ft3, Top Job 650 ft3 9-7/8"x 8-1/2" 207 ft3 6-1/8" 112 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835 Surface 8,440' 1 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface 11,464' 0.0383 4-1/2" Liner 12.6 / L-80 / TXP 3.958 11,273' 12,034' 0.0152 TUBING DETAIL 2-7/8" Tubing 6.5/ L-80/ EUE 8rd 1 2.441 Surface I ±10,570' 2-7/8" WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle 58 deg JEWELRY DETAIL No. Top MD Rem 1 ±140' ST 2: 2-7/8" GLM 2 ±2,500 ESP PKR 7" X 2-7/8" W/ Weatherford Vent Valve X 3/8" Control 3 ± ST 1: 2-7/8" GLM 4 ± 2-7/8"XN-Nipple — Min ID= 2.205 5 ± Discharge Head 6 ± Pum 7 ± Gas Separator 8 ± Upper Tandem Seal 9 at Lower Tandem Seal 10 ± Motor _ 11 f Sensor & Centralizer — Bottom @±11,150' 12 11,139' 4-1/2" x 7" AHC Packer (Cut to Release) 13 11,273' Liner Top Packer GENERAL WELL INFO API: 50-029-23612-00-00 Cased by Doyon 14: 11/13/2018 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date I Status Ku arukC 11,682' 11,687' S 3-1/8" 1 Future I Future (uparuk A2 11,795' 11,801' 7,211' 7,217' 6 3-1/8" 1 11/30/18 1 Open Ref Log: 11/12/2018 Halliburton MW D TD=12,079' (MD) / TD = 7,481' (TVD) PBT)=11,907 (MD) / PBTD= 7,318' (TVD) Revised By: TDF 12/5/2018 SPoint AR R ASR Rig 1 BOPE 2018 mu.,,� .aa.►.. ta.�: I " BOPE Updated 1/05/2018 1R or Pipe Rams nd UHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Date: December 5, 2018 Subject: Changes to Approved Sundry Procedure for Well MP L-55 Sundry #: xxx-xxx Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first calf' engineer. AOGCC written approval of the change is required before implementing the change. Step I Page I Date Approval: Prepared: Procedure Change Operations Manager Date Operations Engineer Date AOGCC Written Approval Received THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU L-55 Permit to Drill Number: 218-109 Sundry Number: 318-518 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this i2" day of December, 2018. RBDMS L DEC 13 2018 0 t E STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED NOV 21 2018 43rs,{{��i pri/gqr�'a�CVz( AOG i ype of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q - Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redhill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q . Stretigraphic ❑ Service ❑ 218-109 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23612-00-00 . 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D ' Will planned perforations require a spacing exception? Yes ❑ No ❑Q MPU L-55 ' 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025509 / ADL355017 Milne Point Field / Kuparuk Oil Pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,079 7,481' 11,907' 7,318' 3,394 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20' 80' 80' N/A N/A Surface 8,406' 9-5/8" 8,440' 4,759 5,750psi 3,090psi Intermediate 11,432' 7" 11,464' 6,899' 7,240psi 5,410psi Liner 761' 4-112" 12,034' 7,438' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 4-1/2" 12.69 / L-801 TAP 11,281' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 4.5"x 7" AHC & LTP Packers and N/A 11,139 MD/ 6,594 TVD & 11,273 MD /6,719 TVD and N/A 12. Attachments: Proposal Summary Q Wellbore schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑Z Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Dale for 15. Well Status after proposed work: Commencing Operations: 11/30/2018 OIL ❑/ . WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: L 'L 1 Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the forego g is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: So York Contact Name: Taylor Wellman Authorized Title: Operations Manager Contact Email: twellmanCE011corp.com Contact Phone: 777-8449 Z� r��tr LO I g Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: XU Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑✓S Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ s 7 a /` O {' Ll Spacing Exception Required? Yes E]No V Subsequent Form Require d: / — APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: t Z I I l Z CSW 1\I1.7/10(s Form 10-403 Revised 4/2017 z5. fc d �� '� DDMSi DEC 131Q10,,,tFermand Approved applicatio s al o t date of approval. Art hmgnIs in Duplicate �� rx. -3,19 Nf Hilcorp Alaska, LLC November 21, 2018 Hollis S. French, Chair Alaska Oil and Gas Conservation Commission 333 West 70' Avenue, Suite 100 Anchorage, Alaska 99501 RE: Hydraulic Fracturing Application, Milne Point Unit, MP L-55 Dear Commissioner French, Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Paul Chan Senior Operations Engineer (907)777-8333 Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Milne Point Unit, herein submits its application to fracture stimulate MP L-55. Please do not hesitate to contact Taylor Wellman at 907-777-8449 should you have any questions regarding this application. Sincerely, Bo Operations Manager LCORP ALASKA, LLC Enclosures: Form 10-403 Sundry Attachments 20 AAC 25.283 (a)(1) Affidavit Affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided a notice of operations that is in compliance with 20 AAC 25.283 (a)(1) r VERIFICATION OF NOTICE PER 20 AAC 25.283(a) MILNE POINT UNIT MP L-55 I, PAUL CHAN, Hilcorp Alaska, LLC, ("Hilcorp") do hereby verify the following: I am acquainted with Hilcorp Alaska, LLC's application for sundry approval to the Alaska Oil and Gas Conservation Commission to enhance production of the MP L-55 well via hydraulic fracturing. Pursuant to 20 AAC 25.283(a)(1), I assert that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided notice of Hilcorp Alaska, LLC's proposed operations. DATED at Anchorage, Alaska this 0w 2day of >\!0V&WB&7?_ 2018. Paul'Chan, Sr. Operations Engineer Hilcorp Alaska, LLC STATE OF ALAKSA THIRD JUDICIAL DISTRICT SUBSCRIBED TO AND SWORN before me this ZoPl day of 2018 STATE OF ALASKA lkz14/.� NOTARY PUBUC NOTARY PUBLIC IN AND FOR M vwl W. Sdvetz THE STATE OF ALSKA myConrrdeelonEVkeeFab 2,2022 My Commission expires:Fcva„w.yLB,z=zz 20 AAC 25.283 (a)(2) A Plat (A) Showing The Well Location; (B) Identifying each Water Well, if any, Located within a One -Half Mile Radius of the Well's Surface Location; and FbY.'I 11 I \ / I F-73APB1. // /3 F 89/ 1 f / F-5JAPB1 t tIF 1\ j tl I -33{ I F73.1� /) J J /I �Jl�l�lilt, 1A ADL355018 /� J /See . \ t Sec 31 / ) / / L;ia• f / cls -1 t' I 622 I t'l /1 / // ) J U014NO10E ADL355017 ♦� h ( 1� iU L;za /1 // / / ., J / Sec. 3.3?. L -z9 • G -43L1 RHL 1 /•- t F-53POI 1 Yfl / I u L -ss a V1 II F / ✓ Yrac zone , L 16 L41PBI l 0 L-051 v v' 111 1-04 1/ :/ t L 0 � LL -43 iL-�'3 B1 /P106INT Sec. 4 �t1 SrF77 1{ I Sec/5/ / / i L -o5 rsP,uyFo-n UNITY If j \ /J A 1 ADL047434 AD ,.J L025506 \ f y v AI L:69AL d3 A I WELLSYMBOL / \ �1\\-�\f•�. \\�\\�\t. DRY HOLE \ \ —a oz` a-` a { f U013N010E MPL I Q. INJECTOR �{ A j •��� �. b. L71 -55 SHL F-99P9, rFss L-02APa2)L02AriS, � phP U.L'/ I Q PLUG BACK x.01 .0-36 LouLzil-022AUJ a /,.\ _ • OTHER \ Sec! 7 A // ' / Sec 8' • OIL -ACTIVE L-�J \ ) / /\ ./ 9♦ J , � � ens / i\ C -05A ' ,.Legend • MPU L-55 Surface Hole Location 1/2 Mile Radius -Well Bore Oil and Gas Lease -7 ADL315848 ADL315848 • MPU L-55 Top of Frac Zone .i 1/2 Mile Radius -Frac Zone (_ ADL025509 _ ADL355017 f ,®y MPU L-55 Base of Frac Zone Well Trajectory MPL-55 [ . ADL025515 1 ADL355018 Sec: 16 T MPU L-55 Bottom Hole Location Other Well Trajectories I , ADLO47434 Pad Footprint Milne Point Unit Petra Well Database- HAK MPL-55 Well MPL-55 Definitive Survey T\ IpL.w. Do,, xro ee�mmmm S.11. 1'. Plat depicting all Well types 0 1,000 2,000 7 """'°w,AX' W50' within 1/2 mile of MPL-55 Feet Map Dale: 1IMM18 ADL355018 U014NO10E MPUL-5s_I3IIL� Sec. 31 Sec. 32 (622) ADL355017 Sec. 33 L MPU L-55 F izc Zone Legend • MPU L-55 Surface Hole Location • MPU L-55 Top of Frac Zone MPU L-55 Base of Frac Zone MPU L-55 Bottom Hole Location Well Trajectory MPL-55 '���■1/2 Mile Radius from SHL _ Pad Footprint Sec. 6 Sec- 5 Sec. 4 (625) _.,. MPU F Sec.7 (628) MPU L 0 MILNE POINT i UNIT i i ■ ■ Sec.9 Pelta Well Database- HAK Milne Point Unit MPL-55 Definitive Survey ��AA MPL-55 Well No Water Wells Within 1/2 Mile -00cN wnt D,. sena 140 Plat depicting no water wells 0 500 1,000 1,500 N AntBm .AK 99503 oFeet Map DaW: 11MM018 within 1/2 mile of the MPL-55 SHL (C) Identifying for all Well Types each Well Penetration Well API PTD POOL Type Status MPL-01A 50029210680100 2030640 KR 1 -OIL Shut In MPL-02A 50029219980100 2091470 KR 1 -OIL Producing MPL-03 50029219990000 1900070 KR 1 -OIL Producing MPL-04 50029220290000 1900380 KR 1 -OIL Producing MPL-05 50029220300000 1900390 KR 1 -OIL Producing MPL-06 50029220030000 1900100 KR SUSP Suspended MPL-07 50029220280000 1900370 KR 1 -OIL Producing MPL-08 50029220740000 1901000 KR WAG Shut In MPL-09A 50029220750100 2131870 KR WAG Shut In MPL-10 50029220760000 1901020 KR WAG Shut In MPL-11 50029223360000 1930130 KR 1 -OIL Producing MPL-12 50029223340000 1930110 KR 1 -OIL Producing MPL-13 50029223350000 1930120 KR 1 -OIL Shut In MPL-14 50029224790000 1940680 KR 1 -OIL Producing MPL-15 50029224730000 1940620 KR WAG Injecting MPL-16A 50029225660100 1990900 KR WAG Injecting MPL-17 50029225390000 1941690 KR 1 -OIL Shut In MPL-20 50029227900000 1971360 KR 1 -OIL Shut In MPL-21 50029226290000 1951910 KR WAG Shut In MPL-24 50029225600000 1950700 KR WAG Shut In MPL-25 50029226210000 1951800 KR 1 -OIL Producing MPL-28A 50029228590100 1982470 KR 1 -OIL Producing MPL-29 50029225430000 1950090 KR 1 -OIL Producing MPL-32 50029227580000 1970650 KR WAG Shut In MPL-33 50029227740000 1971050 KR WAG Injecting MPL-34 50029227660000 1970800 KR SUSP Suspended MPL-35A 50029227680100 2011090 KR SUSP Sus ended MPL-36 50029227940000 1971480 KR 1 -OIL Producing MPL-37A 50029228640100 1980560 SB 1 -OIL Shut In MPL-39 50029227860000 1971280 KR 1-011. Shut In MPL-40 50029228550000 1980100 KR 1 -OIL Producing MPL-41 50029236110000 2181040 KR 1 -OIL Producing MPL-42 50029228620000 1980180 KR WAG Shut In MPL-43 50029231900000 2032240 KR 1 -OIL Producing MPL-45 50029229130000 1981690 KR P&A P&A MPL-46 50029235510000 2151180 SB 1 -OIL Producing MPL-47 50029235500001 2151170 SB 1 -OIL Producing MPL-48 50029235520000 2151200 SB PWI Injecting MPL-49 50029235450000 2150990 SB PWI Shut In Well API PTD POOL Type Status MPL-50 50029235550000 2151320 SB PWI Injecting MPL-51 50029235870000 2171510 SB PWI Shut In MPL-52 50029235900000 2171740 SB PWI Shut In MPL-53 50029235860000 2171440 SB PWI Shut In MPL-54 50029236070000 2180660 SB 1-OIL Producing MPL-56 50029236040000 2180500 SB 1-OIL Producing MPL-57 50029236090000 2180720 SB 1-OIL Producing 20 AAC 25.283 (a)(3) Identification of Freshwater Aquifers There are no underground sources of drinking water within a one-half mile radius of the current wellbore trajectory. Any and all freshwater aquifers lying below the Milne Point Unit are exempted aquifers under Aquifer Exemption Order 2 (AEO-2). See the Conclusion of AEO-2, which states that "The portions of freshwater aquifers lying directly below Milne Point Unit qualify as exempt freshwater aquifers under 20 AAC 25.440." 20 AAC 25.283 (a)(4) Baseline Water Well Sampling There are no water wells located within one-half mile radius of the current wellbore trajectory. A water sampling program is not required. 20 AAC 25.283 (a)(5) Detailed Casing and Cementing Information 9-5/8" 40#/ft L-80 TXP-SR surface casing set at 8,440' MD with ESIPC (stage tool/ECP) at 2,765' MD. First stage cemented with 785 sxs / 329 bbls of ExtendaCem 12 ppg cement followed by 400 sxs / 82 bbls of 15.8 ppg Class G cement. Squeeze 56 bbls 15.8 ppg Class G cement through stage tool with no returns. Top job perfrmed with 150 sxs / 115 bbls of 10.7 ppg PermaFrost L cement with cement returns to surface. = J-,04- 5'4 up,¢) 31% - 4T? NerC . C,--4 dl— 6aa1-4) ' �/ WkA..fpp p,.- - 7" 26#/ft L-80 TXP-SR production casing shoe set at 11,463' MD and cemented. Pumped 40 bbls Clean si.e b /8 Spacer III followed by 180 sxs / 37 bbls of 15.8 ppg Premium G cement with 88 - 94% losses during the job. Bumped plug and floats held= 4-1/2" 12.6#/ft L-80 TXP-SR production liner shoe set at 12,034' MD and cemented. Pumped 15 bbls 13.5 ppg Tuned Spacer followed by -130 sxs / 20 bbls of 15.8 ppg Premium G cement. Detailed Casing Information Size Type Wt/ Grade/ Conn Pipe Body Yield (Ibs) Collapse Pressure (psi) Internal Yield Pressure (psi) Conductor N/A N/A N/A N/A 9-5/8" Surface 40# / L-80 / TXP-SR 916,000 3,090 5,750 7 Production 26# / L-80 / TXP-SR 604,000 5,410 7,240 4-1/2" Liner 12.6#/L-80/TXP-SR 288,000 7,500 8,430 Detailed Tubing Information 4-1W Tubing 12.6 / L-80 / TXP-SR 288,000 7,500 8,430 20 AAC 25.283 (a)(6) Assessment of Each Casing and Cementing O eration RTrformed to Construct or Repair the Well Cry�'alDy�s9`7r��I The 9-5/8" surface casing was set below the base of the Schrader Bluff sands. The first stage cement job n was started by pumping 60 bbls of 10 ppg Clean Spacer with red dye followed by 785 sxs / 329 bbls of 12 ppg ExtendaCem lead cement and 400 sxs / 82 bbls of 15.8 ppg Premium G tail cement at 2 BPM. Displaced cement by pumping at 9 BPM until caught cement and then reduced rate to 3 BPM at 1900 strokes; Increased pump rate from 3 BPM (1900 strokes) to 8 BPM (3900 strokes); and then reduced rate to 6 BPM at 5800 strokes before bumping plug at 6015 strokes. Lost 114 bbls while displacing cement. Casing was rotated and reciprocated during the first stage cement job until the pipe became sticky 220 bbls into the job. Attempt to inflate the ESIPC and establish circulation without success for the second stage cement job. Squeeze 56 bbls 15.8 ppg Class G cement through stage tool with no returns. Close stage tool at 2,765' MD. Abort planned second stage cement job. RIH with 1.66" "spaghetti" string in the conductor x 9- 5/8" annulus to 589' MD. Performed top job with 150 sxs / 115 bbls of 10.7 ppg PermaFrost L cement i with cement returns to surface. The 9-5/8" casing is adegua ly cemented. The 7" production casing was setAn the Upper Kalubik formation and cemented. Pumped 40 bbls of 10.5 ppg Clean Spacer III followed by 180 sxs / 37 bbls of 15.8 ppg Premium G cement at 5 BPM rate before slowing down to 1 BPM as the pump pressure increased. 88%- 94% loss rate during the cement job. The 7" casing was not rotated or reciprocated during the cement job. Lift pressure may have been seen during cement job but is difficult to calculate due to the pressure increase seen during the cement job. Bumped plug and floats held. The 7" casing is adequately cemented. "? //, ry7V/ i6 12,03 •/ `,vklD The 4-1/2" production liner shoe was sewcross the Kuparuk River formation and cemented with a single stage cement job. A 15 bbls 13.5 ppg Tuned Spacer was followed by —130 sxs / 20.0 bbls of 15.8 ppg Premium G cement at 2 BPM average rate. The liner was not rotated/reciprocated. Floats held. Bumped plug and attempt to set liner hanger. Liner hanger not holding. Mechanically release from liner hanger. No indication liner top packer set. POOH and test liner lap— liner lap did not test. RIH and set liner top packer with rotating dog sub. Pressure tested 4-1/2" liner lap to 3500 psi for 30 minutes. The 4-1/2" CBL/VDL log will be submitted after completing the logging run post -rig. 20 AAC 25.283 (a)(7) Plans to Pressure -Test the Casings and Tubing Installed in the Well The 9-5/8" casing pressure tested to 2500 psi for 30 minutes on October 31, 2018. The 7" casing pressure tested to 3500 psi for 30 minutes on November 15, 2018. The 4-%: " liner pressure tested to 3500 psi for 10 minutes on November 15, 2018. The 4-Y2" tubing was pressure tested to 5000 psi for 30 minutes on November 19, 2018. The 4-1/2" x 7" annulus pressure tested to 3500 psi for 30 minutes on November 19, 2018 20 AAC 25.283 (a)(8) Pressure Ratings and Schematics for the Wellbore, Wellhead, BOPE, and Treating Head Size Weight #/ft Grade API Collapse Pressure (psi) API Internal Yield Pressure (psi) 9-5/8" 40 L-80 3,090 5,750 7" 26 L-80 5,410 7,240 4-1/2" 12.6 L-80 7,500 8,430 Treating Head 15M Wellhead 5M BOPE N/A H HBeorp Almium, LILC Drig. KB Elev.: 33.7 /GL Elev.: 16.0' TD =12,075 (MD) / TD = 7,481' (TVD) PBTD =11,907 (MD) / PBTD = 7,318' (TVD) SCHEMATIC Milne Point Unit Well: MPL-55 Last Completed: 11/17/18 PTD: 218-109 TREE & WELLHEAD Tree 5M 4-1/16" Wellhead SM FMC Gen IV OPEN HOLE/ CEMENT DETAIL Conductor Driven 12-1/4" Stg 11,853 ft3/464 ft3, Stg 2 316 ft3, Top Job 650 ft3 9-7/8"x 8-1/2" 207 ft3 6-1/8" 112 ft3 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 164/A53B/Weld N/A Surface 80' N/A 9-5/8" Surface 40/L-80/TXP 8.835 Surface 8,440' 0.0758 7" Intermediate 26/L-80/TXP 6.276 Surface 11,464' 0.0383 4-1/2" Liner 12.6 / L-80 / TXP 3.958 11,273' 12,034' 0.0152 2 TUBING DETAIL 4-1/2" Tubing 12.6/L-80/TXP 1 1958 Surface 1 11,281' 1 0.0152 WELL INCLINATION DETAIL KCIP @ 300' Max Hole Angle 58 deg JEWELRY DETAIL e, No. Top MD Item ID 1 11,139' 4-1/2" x 7" AHC Packer (Cut to Release) 3.880 2 11,144' 4-1/2"XN Nipple - No-go =3.725" 3.725 3 11,272' Mule Shoe — Bottom @11,281' 3.958 4 11,273' Liner Top Packer 4.340 lc' "r A GENERAL WELL INFO API: 50-029-23612-00-00 Cased by Doyon 14:11/13/2018 / 1713' I (,-I I - l l L S'ZL - 11697 Revised By: TDF 11/20/2018 k'ROPOSAL: P J OIL STATES Casing Isolation Tool Energy Services (Canada) Inc. Maximum Allowable Pumping Rates SIZE ID •E RATE m'/min CSG 1 2.250 1 3.760 1 10 m'/min 31/2" Big Bore 1.760 _2.750 1 6 m'/min 2 718" & 31/2" 1.438 2.360 4 W/min 2318" 1.000 .1.800 2 W/min 31116 & 4 1116 with tapered mandrel 1 2.750 4.000 15 m'/min 41116 X Tool Mandrel 1 3.610 4.760 24 W/min OrEN POSmON pzimwuxmei av��an� CLOSED POSMON 4uoou�nutxq a.oru.wr www.StingerCanada.com 15M Treating Head 20 AAC 25.283 (a)(9) Data for the Fracturing Zone and Confining Zones (A) a lithologic description of each zone; (B) the geological name of each zone; (C) the measured depth and true vertical depth of each zone; (D) the measured thickness and true vertical thickness of each zone; and (E) the estimated fracture pressure for each zone; The Kuparuk formation is a Cretaceous -aged, fine-grained marine sandstone. The productive Kuparuk interval in the L-55 area is made up of 5 sand members, whose top, base and true vertical thickness are listed in the table below. The estimated fracture gradient for the Kuparuk interval is 0.61-0.68 psi/ft. Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-55 KUP_C 11679 -7052 7102 8 Top Kuparuk C L-55 KUP_B6 11688 -7060 7110 78 Top Kuparuk B / Base Kuparuk C L-55 KUP_A3 11771 -7138 7188 19 Top Kuparuk A3 / Base Kuparuk B L-55 KUP _A2 11791 -7157 7207 26 Top Kuparuk A2 / Base Kuparuk A3 L-55 KUP_A1 11818 -7183 7233 55 Top Kuparuk Al / Base Kuparuk A2 L-55 KUP A BASE 1 11876 -7239 7289 Base Kuparuk Al The overlying confining zone consists of 2315' TVT of Kuparuk D, Kalubik, HRZ, and Colville siltstones and shales, whose top, base and true vertical thickness are listed in the table below. The estimated fracture gradient for the overlying confining zone is 0.75-0.82 psi/ft. Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-55 Colville 8499 -4737 4787 2016 Top Colville L-55 HRZ 11361 -6753 6803 18 Top HRZ/ Base Colville L-55 KLB 11381 -6771 6821 160 Top Kalubik/ Base HRZ L-55 KUP D 11551 -6931 6981 121 Top Kuparuk D / Base Kalubik L-55 KUP_C 11679 1 -7052 1 7102 Top Kuparuk C / Base Kuparuk D The underlying confining zone consists of more than 2000 ft TVD of Milluveach shales. The top of the Milluveach shales is 11876' MD / 7289' TVD. The estimated fracture gradient for the Milluveach shales is 0.78-082 psi/ft. 20 AAC 25.283 (a)(10) The Location, the Orientation, and a Report on the Mechanical Condition of Each Well that May Transect the Confining Zones MP L-11: 7" casing set across the Kuparuk sands and cemented with 67 bbls / 302 sxs of 15.8 ppg Class G cement with partial returns during job. Bump plug and floats held. CBL log noted TOC low so the well was perforated and squeeze cemented at 10,992' MD with 135 sxs / 28 bbls of 15.8 ppg Class G cement. MP L-14: 7" casing set across the Kuparuk sands and cemented with 44 bbls / 215 sxs of 15.8 ppg Class G cement with 30% returns during job. Bump plug with 3500 psi. MP L -16A: 4-1/2" liner set across the Kuparuk sands and cemented with 35 bbls of 15.8 ppg Class G cement. Bump plug with 3500 psi. Good cement from 11,900'— 13,345' PBTD from CBL. ✓ MP L-21: 7" casing set across the Kuparuk sands and cemented with 51 bbls / 250 sxs of 15.8 ppg Class G cement with 30% returns during job. Bump plug with 3500 psi. Estimated TOC from CBL is "'12,000' ✓ MD. MP L-41PB: Cemented 4-1/2" liner. Unable to release from 4-1/2" liner. Commence plug back operations. Spot balanced plug inside 7" production casing and tagged at 9,590' MD. Pressure tested 7" casing and cement plug to 2000 psi. Set retainer set at 7,833' MD and tested good to 2000 psi. Cut and pull 7" casing down to 7,667' MD. Spot balanced cement plug from top of retainer at 7,883' MD to 7,267' MD. Note 9-5/8" casing shoe at 7,366' MD. Kick off well at 7,392' MD. MP L-41: 7" casing set across the Kuparuk sands. First stage cement job: 52.7 bbls / 255 sxs of 15.8 ppg Class G cement with 100% losses during the first stage cement job. 590 psi lift pressure observed during cement job. Second stage cement job: 34.1 bbls / 165 sxs of 15.8 ppg Class G cement with 100% losses. 300 psi lift pressure observed during cement job. 20 AAC 25.283 (a)(11) The Location of, Orientation of, and Geological Data for Each Known or Suspected Fault or Fracture that May Transect the Confining Zones / -7,22 11 05 L-41 i 167 -7,220 ® 11 / L-21 -7184 -55 ,138 /* -7, 8- i vA Q7,145 •,, 12 1200 ft L-29 -7,256 19 G The map above shows the structure at the top of the Kuparuk A3 Sand interval. All faults shown are inferred from seismic data. The L-55 well is located at a distance between 610 - 920 ft from nearby faults. Horizontal principal stress from well data indicate that the fracture should propagate approximately NW -SE (SHmax is NW -SE, SHmin is NE -SW). Based on current mapping, the fracture wings should not ' extend into the nearby faults. 20 AAC 25.283 (a)(12) Proposed Hydraulic Fracturing Program c�6 L- 1. RU a -line and PCE. PT to 4000 psi (MPSP is 3394 psi / estimated Kuparuk River reservoir pressure). 2. Perforate the Kuparuk A sand formation from ±11,791-±11,796' MD. Final depths may be adjusted and be in either the Kuparuk A2 or A3 sands. 3. RDMO a -line. 4. MIRU frac fleet. MIRU frac and slop tanks. MIRU all ancillary support equipment. 5. Fill frac tanks with water. Heat water as needed. 6. Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. Monitor 7" x 4-1/2" annulus pressure during DFIT and fracture stimulation. RU flowmeter if performing forced closure on tank return line. 7. RU hardline from 9-5/8" x 7" annulus to tank and shall be left open to atmosphere during the stimulation job. 8. RU 15K tree saver and hard line. 9. Pressure test all high pressure treating lines to 8000 psi. 10. Set the GORV (gas operated relief valve) at ±7300 psi. Set.the staggered pump kickouts between 6800 psi and 6400 psi. 11. Pressurize annulus to 3000 psi. Set annular PRV at 3500 psi. 12. Prepare frac fleet to pump. 13. Pump Kuparuk A sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. ` 14. Fracture stimulate Kuparuk A sand with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. WV �r 15. Displace with freeze protect fluid. Underdispiace by ±3 bbls. Do not over displace. 16. Shut well in. Perform forced closure (optional) 17. RD tree saver. 18. MIRU CTU, portable test separator and associated equipment. 19. RU CTU BOPE and PT to 4000 psi. RIH and cleanout frac sand/frac fluid to PBTD. Flo_wbark well to portable test separator with 2% KCI/NaCl kill weight brine and NZ as needed to clean up frac. ------------- 20. Sand back 4-1/2" liner to ±11,730' MD. 21. RU a -line and PCE. PT to 4000 psi. 22. Perforate the Kuparuk C sand formation from ±11,682 -±11,687' MD. Final depths to be determined from OH logs. 23. RDMO a -line. 24. RU 15K tree saver and hard line. 25. Pressure test all high pressure treating lines to 8000 psi. 26. Set the GORV (gas operated relief valve) at ±7300 psi. Set the staggered pump kickouts between 6800 psi and 6400 psi. 27. Pressurize annulus to 3000 psi. Set annular PRV at 3500 psi. 28. Prepare frac fleet to pump. 29. Pump Kuparuk C sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. (ra,� 30. Fracture stimulate Kuparuk C sand with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. 31. Displace with freeze protect fluid. Underdisplace by±3 bbls. Do not over displace. 32. Shut well in. Perform forced closure (optional) 33. RD tree saver. 34. Contingency (Pending WO rig availability). MIRU CTU, portable test separator and associated equipment. 35. Contingency (Pending WO rig availability). RU CTU BOPE and PT to 3500 psi. RIH and cleanout frac sand/frac fluid to PBTD. Flowback well to portable test separator with 2% KCI/NaCl kill weight brine and NZ as needed to clean up frac. 36. Turn well over to operations. 20 AAC 25.283 (a)(12) (A) Estimated Total Volumes Planned 20 AAC 25.283 (a)(12) (B) Trade Name, Generic Name, and Purpose of each Base Fluid and Additive to be Used; 20 AAC 25.283 (a)(12) (C) Chemical Ingredient Name of, and the Chemical Abstracts Service (CAS) Registry Number Assigned to, each Base Fluid and Additive to be used; 20 AAC 25.283 (a)(12) (D) Estimated Weight or Volume of each Inert Substance, including a Proppant or other Substance injected OneStim... Client: Hilcorp Alaska, LLC Well: MPU L-55 Basin/Field: 1475 State: Alaska County/Parish: North Slope Borough Case: L071 Disclosure Type: Pre -Job Well Completed: 12/4/2018 Date Prepared: 11/16/2018 3:53 PM Report ID: RPT -58499 Name & Volume YF130FIexD,WF130,Y 105,546 Gal F125F1e%D,WF325 Additive F103 AdditiveFluid Description' Surfactant 1.1 Gal/1000 Gal 115.0 Gal 1218 _ Breaker - 1.9 Lb 1000 Gall 200.0 Lb 1475 Breaker 4.7 Lb 1000 Gal 495.0 Lb 1580 Gelling Agent 28.6 Lb 1000 Gal 3,020.0 Lb J604 Crosslinker 2.1 Gal 1000 Gal 225.0 Gal L071 Clay Control Agent 2.1 Gal / 1000 Gal 225.0 Gal LTCA LTCA 1.6 Gal / 1000 Gal 165.0 5181 M002 Additive 1.2 Lb 1000 Gal 125.0 Lb M275 Bactericide 0.5 Lb /1000 Gal 54.0_Lb 5526-1620 Propping Agent varied concentrations 245,200.0 Lb The totoluolume Astedin the tables above represents thesumma6on cf.termrdodditlues. wpterissupplwdbyellent. ' Murwaterasuppliedby thedient. One56m has performed no analysis of the water and cannot pmuide a breakdown efmmponents that may have been added to the water by third-portks. 'The evaluation ofaaached document 6 porf rmed based on the composition of the identified products to the erten that such compositional Information was brown to GPC -Chemicals as fthe dote of the document was produced. Any new updates will not be nefkcted in this dommeut. ® OneSdm 2018. Used by HJkom Alaska, LLC bypermission. Page: 1 / 1 Water (Including Mix Water Supplied by Client)" ^' 17rr- 66402-68-4 66402-68-4 Ceramic materials and wares, chemicals `22 % 9000-30-0 Guar um <1 % 67-48-1 2-hydroxy-N,N,N-trimethylethanaminium chloride <1 % 1319-33-1 Ulexite <0.1 % 67-56-1 Methanol <0.1 % 7727-54-0 Diammonium peroxidisulphate <0.1 % 107-21-1 Ethylene Glycol <0.1 % 68131-40-8 Alcohols,cll-SS-secondary, ethoxylated <0.1 % 67-63-0 Pro an-2-ol <0.1 % 111-76-2 2-butoxyethanol <0.1 % 34398-01-1 Ethoxylated Cal Alcohol <0.1 % 1310-73-2 Sodium hydroxide <0.1 % 1303-96-4 Sodium Tetraborate Decah drate <0.01 % 68131-39-5 Ethotylated Alcohol <0.01 % 25038-72-6 Vinylidene chloride/methylacrylate copolymer <0.01 % 25322-68-3 Pol o-1,2-ethanedi I,a-h dro-w-h drox Ethane -1,2 -diol, ethox lated <0.01 % 91053-39-3 Diatomaceous earth, calcined <0.01 % 110-17-8 but-2-enedioic acid <0.01 % 112-42-5 Un lecanol <0.01 % 7631-86-9 Non -crystalline silica (impurity) <0.001 % 10377-60-3 Magnesium nitrate <0.001 % 26172-55-4 5-chloro-2-methyl-2h-isothiazolol-3-one <0.001 % 7786-30-3 Magnesium chloride <0.001 % 14807-96-6 Magnesium silicate hydrate (talc) <0.001 % 125005-87-0 Diutan gum <0.001 % 595585-15-2 Diutan <0.001 % 9002-84-0 of tetrafluoroeth lene) <0.001 % 2682-20-4 2-methyl-2h-isothiazol-3-one <0.0001 % 14808-60-7 Quartz, Crystalline silica <0.0001 % 14464-46-1 Cristobalite <0.0001 % 127-08-2 Acetic acid, potassium salt <0.0001 % 64-19-7 Acetic acid (impurity) <0.0001 % ' Murwaterasuppliedby thedient. One56m has performed no analysis of the water and cannot pmuide a breakdown efmmponents that may have been added to the water by third-portks. 'The evaluation ofaaached document 6 porf rmed based on the composition of the identified products to the erten that such compositional Information was brown to GPC -Chemicals as fthe dote of the document was produced. Any new updates will not be nefkcted in this dommeut. ® OneSdm 2018. Used by HJkom Alaska, LLC bypermission. Page: 1 / 1 20 AAC 25.283 (a)(12) (E) Maximum Anticipated Treating Pressure and Information Sufficient to Support a Determination that the Well is Appropriately Constructed for the Proposed Hydraulic Fracturing Program. The 4-%: "production tubing tested to 5000 psi for 30 minutes, 4-%: "production liner tested to 3500 psi for 10 minutes, and the 7" production casing tested to 3500 psi for 30 minutes prior to the fracture stimulation. The maximum surface differential pressure the tubing will be subjected to will be 4300 psi (7300 psi GORV maximum pressure setting - 3000 psi of pressure on the casing x tubing annulus). d The calculated maximum treating pressure is 5,335 psi for the Kuparuk A sand and 4,943 psi for the /(TTT Kuparuk C sand fracture stimulations. 20 AAC 25.283 (a)(12) (F) Designed Height And Length Of Each Proposed Fracture (i) the calculated measured depth and true vertical depth of the top of the fracture: Kuparuk A Sand: 11,791' MD / 7,207' TVD BKB Kuparuk C Sand: 11,679' MD / 7,101' TVD BKB (ii) a description of each method and assumption used to determine designed fracture height and length: The MP L-55 fracture stimulation was modeled using the FracCADE program. Kuparuk A Sand propped half length: 359.7' Kuparuk C Sand propped half length: 306.6' Note — The TVD depths in FracCADE are BKB. Schlumberger, FracCADE' STIMULATION PROPOSAL Mark of Schlumberger 0 wnkoer Notice Tom infommtiun is presented in good faith, but no enamoty is given by and ScMlaoberger assumes off hammy for adaice or racoomeotlavum made cowemng resdn m be obtained from Me use of any pmdua or service. The results green are esomases based on calculations produced by corrieatee model armad" Various assvrplimrs on day see4 reservoir and treamrem. The resuhs depend on inpm data provided by be Operator antl esinmes as ho urtnmm dam, and cm he am, mare accumoe Than the nam Me assumptions and such input dam. The mfmmetion presented is Schlumbeger's hes er:*mo of Me erne! reams tlrt ^my be wheved am should be need for caoparoon puryoses raNer than ebwkne values -The qualhy of i�Wmdam, aM henre results. mrybe inpromd Mrough Me Meed ceatan eesaantl pmc�uresaddeh SCM�mVtngercan oasis an selecting. The Operator has superior knowledge of the well, Me reservoir, the, field and conditions affecting Mem 0 the Operamr ie aware of any medians mlromr, a neighboring wet or wells might be stained by Me treatment proposed herein his the Opmetor's me,onsibilhy to ready Me atiner or owmms of Me arab mmmbe acon"IM ly. Prices tested areesunmres only and are good for M days from the dam of issue Actual charges may vary depasa ig upm tire. equepnenl and Material uhi erigh, requiredre pedorm Mew services. nottem Warned- Schlumberger -Private Operator Hilcorp Alaska Well MPL-55 Field Milne Point Formation Kuparuk Ale Well Location Milne Point County North Slope State Alaska Country United States Prepared for Almas Aitkulov Service Point : Prudhoe Bay Proposal No. 2 Business Phone : Date Prepared 11-20-2018 FAX No. Prepared by Gunther Rutzinger Phone 907 273 1788 E -Mail Address grutzinger@slb.com Mark of Schlumberger 0 wnkoer Notice Tom infommtiun is presented in good faith, but no enamoty is given by and ScMlaoberger assumes off hammy for adaice or racoomeotlavum made cowemng resdn m be obtained from Me use of any pmdua or service. The results green are esomases based on calculations produced by corrieatee model armad" Various assvrplimrs on day see4 reservoir and treamrem. The resuhs depend on inpm data provided by be Operator antl esinmes as ho urtnmm dam, and cm he am, mare accumoe Than the nam Me assumptions and such input dam. The mfmmetion presented is Schlumbeger's hes er:*mo of Me erne! reams tlrt ^my be wheved am should be need for caoparoon puryoses raNer than ebwkne values -The qualhy of i�Wmdam, aM henre results. mrybe inpromd Mrough Me Meed ceatan eesaantl pmc�uresaddeh SCM�mVtngercan oasis an selecting. The Operator has superior knowledge of the well, Me reservoir, the, field and conditions affecting Mem 0 the Operamr ie aware of any medians mlromr, a neighboring wet or wells might be stained by Me treatment proposed herein his the Opmetor's me,onsibilhy to ready Me atiner or owmms of Me arab mmmbe acon"IM ly. Prices tested areesunmres only and are good for M days from the dam of issue Actual charges may vary depasa ig upm tire. equepnenl and Material uhi erigh, requiredre pedorm Mew services. nottem Warned- Schlumberger -Private Client Hilcorp Alaska well MPL-55 Fonnation Kuparuk A& C District Prudhoe Bay Country United States Section 1: Zone Data Schlumdcrgcr Schlumberger -Private Formation Mechanical Properties Zone Name Top TVD Ift) Zone Height (ft) Frac Grad. (Psvft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.in0.5) Kalubik 6820.8 160.1 0.784 5410 1.306E+6 0.35 2000 Kup D 6980.9 120.3 0.764 5520 1.847E+6 0.35 2000 Kup C 7101.2 8.5 0.660 4690 1.847E+6 0.25 800 Kup B6 7109.7 9.5 0.640 4553 1.733E+6 0.28 2000 Kup B 7119.1 11.4 0.660 4702 1.733E+6 1 0.28 2000 Kup B 7130.5 18.9 0.700 4998 1.729E+6 0.32 2000 Kup B 7149.4 1 26.5 0.720 1 5157 1.729E+6 0.32 2000 Kup B 7175.9 12.3 0.750 5387 1.729E+6 0.32 2000 Kup A3 7188.2 10.5 0.610 4388 1.729E+6 0.25 2000 Kup A3 7198.7 8.5 0.700 5042 1.729E+6 0.25 2000 Kup A2 7207.2 11.4 0.610 4400 1.729E+6 0.26 2000 Kup A2 7218.6 14.3 0.700 5058 1.729E+6 0.32 2000 Kup Al 7232.9 7.7 0.630 4559 1.729E+6 1.322000Kup 5.0 Al 7240.6 47.7 0.670 4867 1.729E+6 0.32 2000 Miluveach 7288.3 1 100.0 0.780 1 5724 4.494E+6 0.35 1000 Schlumberger -Private Formation ansmissibility Properties Zone Name Top TVD Ift) Net Height (ft) Perm imd) Porosity 1%) Has. Pressure (psi) Gas Sat (%) Oil Sat 1%) Water Sat (%) Kalubik 6820.8 1.0 0.001 1.0 3596 0.0 80.0 20.0 Kup D 6980.9 1.0 0.001 1.0 3681 0.0 80.0 20.0 Kup C 7101.2 8.5 5.000 15.0 3744 0.0 80.0 20.0 Kup B6 7109.7 9.4 30.000 10.0 3749 0.0 80.0 20.0 Kup B 7119.1 9.0 5.000 10.0 3754 0.0 80.0 20.0 Kup B 7130.5 6.0 1.000 10.0 3760 0.0 80.0 20.0 Kup B 7149.4 1 8.0 1.000 1 10.0 3770 1 0.0 80.0 20.0 Kup B 7175.9 5.0 1.000 10.0 3783 0.0 80.0 20.0 Kup A3 7188.2 10.4 40.000 22.0 3790 0.0 80.0 20.0 Kup A3 7198.7 7.0 5.000 22.0 3796 0.0 80.0 20.0 Kup A2 7207.2 11.4 40.000 22.0 3800 0.0 80.0 20.0 Kup A2 7218.6 5.0 1.000 13.0 3806 0.0 80.0 20.0 Kup Al 7232.9 5.7 20.000 13.0 3814 0.0 80.0 20.0 Ku Al 7240.6 15.0 1.000 13.0 3818 0.0 80.0 20.0 Miluveach 7288.3 1.0 0.001 1.0 3643 0.0 80.0 20.0 Schlumberger -Private Cbela Hilcorp Alaska wee MPL-55 Fonrstion KuparukA&c Distrin Prudhoe Bay Country United States Schlumberger Section 2: Propped Fracture Schedule - "A" Frac Purnong Schedule The following is the Pumping Schedule to achieve a propped fracture hag -length (Xn) of 359.7 fl wilt an average conductivity Ill of 7627 and ft Mid Totals 900bbl of YF13Med1 173661 of WF130 Proppant Tatals 12710016 of CadwBard lite IV20 Pad Percentages % PAD Clean 221 %PAD Dirty 192 Schlumberger -Private Job Description Step Name Pump Raw tbbymin) Fhed Name Step fluid Ydume {bbl) Gel Conc. p ag Prop. Type and Mesh Prop. Conc- (PPA) PAD 35.0 YF13ORexD 2WO 30.0 0.00 1-0 PPA 327.0 YF13Nle>m 100.0 30.0 Ca"ard lite IVA 1A0 2.0 PPA 30A YF13ORexD 1000 30.0 CarboBond lite 1re23 200 3.0 PPA 3" W13WemO ion 30.0 CarboBond the IVA 3.00 4.11 PPA 30.0 YF130RexD WILD 30.0 CarboBond lite IVA 4.00 5A PPA 30.0 YF130RmA 100.0 30.0 Ca"Bond Lite IVA 5.00 &0 PPA 30.0 VF130RexD 50A 30.0 CarboSond lire IVA &00 7A PPA 30A YF13DRezD 5" 30.0 CarboBond lite IVA 7.00 6A PPA 30.0 YF13N1esD 5" 30.0 CarboBond lire IVA 6.110 9.0 PPA 30.0 YF13DRexD 25A 30.0 CarboBond Um IVA 9.0101 10.0 PPA 30.0 YF13ORexD 2" 30.0 CmboBond lite IV2D 10.00 Flush 30A WF13D 173.1 30.2 0.00 Mid Totals 900bbl of YF13Med1 173661 of WF130 Proppant Tatals 12710016 of CadwBard lite IV20 Pad Percentages % PAD Clean 221 %PAD Dirty 192 Schlumberger -Private Client Hilcorp Alaska Well MPL-55 Formation Kuparuk A& C District Prudhoe Bay Country United States 3chlumherger Schlumberger -Private Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop Iib) Cum_ Prop. (1b) Avg. Surface Pressure 1 si) Step Time (min) Cum. Time (min) PAD 200.0 200.0 200.0 200.0 0 0 5251 5.7 5.7 1.0 PPA 100.0 300.0 104.6 304.6 42110 4210 5274 3.5 9.2 2.0 PPA 100.0 400.0 109.2 413.8 8400 12600 5220 3.6 12.8 3.0 PPA 100.0 500.0 113.8 527.7 12600 25200 4792 3.8 16.6 4.0 PPA 100.0 600.0 118.4 646.1 16800 42000 4810 3.9 20.6 5.0 PPA 100.0 700.0 123.0 769.1 21000 63000 4847 4.1 24.7 6.0 PPA 50.0 750.0 63.8 833.0 12600 75600 4889 2.1 26.8 7.0 PPA 50.0 800.0 66.1 899.1 14700 90300 4950 2.2 29.0 8.0 PPA 50.0 850.0 68.4 967.5 16800 10710D 5053 2.3 31.3 9.0 PPA 25.0 875.0 35.4 10029 9450 116550 5139 1.2 32.5 10.0 PPA 25.0 900.0 36.5 1039.4 10500 127050 5211 1.2 33.7 Flush 173.1 1073.1 173.1 1212.5 0 127050 4436 5.8 39.5 Schlumberger -Private i Client Hilcorp Alaska Well MPL-55 3chlumherger Fotmatlon KupankASC alstno Prudhoe Bay country : United States Section 3: Propped Fracture Simulation Results — "A" Frac (1) ACL Fracture Profile and Proppant Concentration Plot FmcCADE' - �P nner caWa..a-o W Treating Piot - eoltomhole Pre.re ----- Surface Preevre <aocm � an-auau o. -a nau G1-l:IM2 � 91NM r 5-: B IyR .e-zzlxa � za-261bA3 � a8-29:WM � ay9bR leaoaa�-. Total Inj. Rate ---EOJ 0 10 20 30 00 50 60 70 80 90 Treatment Time -min 5 Schlumberger -Private Client Hilcorp Alaska well MPL-55 Formation Kuparuk A & C District Prudhoe Bay Country United States Section 4: Propped Fracture Simulation — "A" Frac Schlumberger The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Initial Fracture Top TVD_..._7207.2 It Initial Fracture Bottom TVD ................. _ 7218.6 It Propped Fracture Half -Length ........ ,---- - 359.7 It EOJ Hyd Height at Well.- ..... 152.0 If Average Propped Width ....... _......... ------- 0.164 in Net Pressure ..... -.... ___... .......... 930 psi Efficiency-- ........... 0.525 Effective Conductivity ---- ___....... 12390 md.ft Effective Fcd -- _...--------------------- 0.9 Max Surface Pressure ............. 5335 psi Simulation Results by Fracture Segment From Ift) To Ift) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. hb/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 89.9 8.7 0.223 74.8 1.92 303.0 11827 89.9 179.8 6.3 0.198 120.3 1.76 351.1 9758 179.8 269.8 5.6 0.166 107.4 1.48 420.6 75M 269.8 359.7 2.2 0.090 77.5 0.80 610.2 3659 Proppant packed at359ft after 0 bbl in step 6 6 Schlumberger -Private Client Hilcorp Alaska Wen MPL-55 Fomtation KuparukA&C District Prudhoe Bay coup" United States 3chlemderger Schlumberger -Private Fracture Geometry Data Per Zone for Production Prediction Zone Name Top MD 111) Top TO (ft) Gross Height Ift) Net Height Fracture Width lin) Fracture Length (ft) Fracture Conductivuy (md.ft) Kalubik 11381.0 6820.8 160.1 1.0 0.000 .0 0 Kup D 11551.0 696D.9 120.3 1.0 0.000 .0 0 Kup C 11679.0 71011 8.5 8.5 GADO .0 0 Kup B6 11686.0 7109.7 9.5 9.4 0.000 .0 0 Kup B 1169B.0 7119.1 11.4 1 9.0 0.000 1 .0 0 Kup B 11710.0 7130.5 18.9 6.0 O.00D 19.9 0 Kup B 11730.0 7149.4 26.5 8.0 0.013 141.8 651 Kup B 11758.0 7175.9 12.3 5.0 0.078 301A 3671 Kup A3 11771.0 7188.2 10.5 10.4 0.193 340.9 9042 Kup A3 117820 719B.7 8.5 7.0 0.238 358.1 11072 Kup A2 11791.0 7207.2 11.4 11.4 0.267 359.7 12390 Kup A2 118D3.0 7218.6 14.3 5.0 0.223 359.5 10301 Kup Al 11818.0 72329 7J 5.7 0.227 353.5 10465 KuAl 11826.0 7240.6 47.7 15.0 0.149 337.4 6873 Milutreach 11876.0 72BB.3 100.0 1.0 0.020 236.9 974 Schlumberger -Private Client Hilcorp Alaska Well MPL-55 Formation KuparukA&C District Prudhoe Bay Country United States 3chiumhepp Section 5: Propped Fracture Schedule - "C" Frac Pumping Schedule The following is the Pumping Schedule to achieve a propped fracture half-length (X,) of 306.6 ft with an average conductivity (K,w) of 8911 md.ft Fluid Totals 850 bbl of YFIWexD 171 bbl of WF125 Proppant Totals 11870016 of CarboBond Lite 1680 _ Pad Percentages % PAD Clean 17.6 % PAD Dirty 15.3 Job Description Job Execution Step Name Pump Rate (bbVmin) Fluid Name Stop Fluid Volume Ibbl) Gel Cone_ hb/mgal) Prop. Type and Mesh Prop. Cone. IPPA) PAD 35.0 YFI25RexD 150.0 25.0 Cum. Tome (min) 0.00 1.0 PPA 30.0 YFI25RexD 150.0 25.0 Carbol3ond Lite 1M20 1.00 20 PPA 30.0 YFI25RexD 100.0 25.0 CarboBond Lite 16/20 200 3.0 PPA 30.0 YF125FlexD 75.0 25.0 CarboBond Lite 16120 3.00 4.0 PPA 30.0 YFI25RexD 75.0 25.0 Carbo8ond Lite 16/20 4.00 5.0 PPA 30.0 YFI25RexD 75.0 25.0 CartmBond Lite 16120 5.00 6.0 PPA 30.0 YFI25RexD 75.0 25.0 Carbo8ond Lite 16120 6.oD 7.0 PPA 30.0 YF125RexD 75.0 25.0 CarboBond Lite 16/20 7.00 8.0 PPA 30.0 YFI25RexD 75.0 25.0 CarboBond Lite 16M 8M Rush 30.0 WFI25 171.4 25.0 700.0 0.00 Fluid Totals 850 bbl of YFIWexD 171 bbl of WF125 Proppant Totals 11870016 of CarboBond Lite 1680 _ Pad Percentages % PAD Clean 17.6 % PAD Dirty 15.3 Schlumberger -Private Job Execution Step Name Step Fluid Volume (bbl) Cum. Raid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (@) Cum_ Prop. (lb) Avg. Surface Pressure (psi) Step Time (min) Cum. Tome (min) PAD 150.0 150.0 150.0 150.0 0 0 4907 4.3 4.3 1.0 PPA 150.0 300.0 156.9 30&9 6300 63DD 4932 52 95 2.0 PPA 100.0 400.0 1092 416.1 8400 14700 4551 3.6 132 3.0 PPA 75.0 475.0 85.4 W1.5 9450 24150 4402 2.8 16A 4.0 PPA 75.0 550.0 88.8 590.3 12600 WM 4328 3.0 190 5.0 PPA 75.0 625.0 923 6826 15750 52500 4330 3.1 220 6.0 PPA 75.0 700.0 95.7 7783 18900 71400 4362 32 25.2 7.0 PPA 75.0 775.0 992 8T/.5 220.50 93450 4470 33 20.5 8.0 PPA 75.0 850.0 1027 9802 1 25200 118650 4590 3.4 320 Rush 171.4 1021.4 1 171.4 1 1151.6 1 0 118650 4176 5.7 373 Schlumberger -Private Client Hilcorp Alaska Sehluiilhergcr Wen MPL-55 Formation Kuparuk A & C District Prudhoe Bay Coun" United States Section 6: Propped Fracture Simulation Results — "C" Frac (1) ACL Fracture Profile and Proppant Concentration Plot FracCADE' nct rae— vrew. aye vreovam w..ee,la 22. _... was-r •nwr�rwlw-r (2) Treating Plot — Botlomhole Peal ------ surface Pnsure � wna.rem.n Total Ini. Rate ....... EOJ o I 90 I 500 --'- T-__-- - — - — -- 30 I i 400 _� _ - +- - 2D I i I � 300 10 I 0 10 20 30 40 50 60 TD BO 90 100 110 120 130 140 Treatment Time - min 9 Schlumberger -Private Client : Hilcorp Alaska Schl��rger Well MPL-55 Formation KuparukA&C District Prudhoe Bay Country United States Section 7: Propped Fracture Simulation — "C" Frac The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Initial Fracture Top ND______-...... -__ 7101.2 ft Initial Fracture Bottom ND_____.."...... 7109.7 ft Propped Fracture Half -Length_ EOJ Hyd Height at Well............ Average Propped Width____... Net Pressure___".......______ Efficiency ............... Effective Conductivity ..-.-.-._._. Effective Fcd Max Surface Pressure______ --- 306.6 ft 162.6 ft iI 0.220 in 1052 psi 0.573 11086 md.ft 7.2 ....... 4943 psi / Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 76.7 6.6 0.363 121.2 3.21 237.6 16395 76.7 153.3 5.2 0.256 95.3 2.22 322.2 10412 153.3 230.0 4.2 0.205 78.4 1.82 387.1 7504 230.0 306.6 1.6 0.071 62.1 0.58 728.1 2033 Proppant bridged at 299 ft after 74 bbl in step 3 10 Schlumberger -Private Client Hilcorp Alaska Well MPL-55 Formation Kuparuk A8 C District Prudhoe Bay country United States Schiumbopp 11 Schlumberger -Private Fracture Geometry Data Per Zone for Production Prediction Zone Name Top MD (ft) Top TVD Ift) Gross Height (fill Net Neigh Fracture Width (in) Fracture Length ltd Fracture Conductivity (md.ft) Kaluhik 11381.0 6820.8 160.1 lA 0.000 .0 0 Kup D 11551.0 6980.9 12113 19. 0.116 2649 4377 Kup C 11679.0 7101.2 05 Its 0296 306.6 11086 Kup B6 11688.0 7109.7 95 9.4 0387 306.6 14423 Kup B 11698.0 7119.1 11.4 1 99. 0304 306.6 14279 Kup B 11710.0 7130.5 18.9 6A 0.302 306.6 1 11367 Kup B 11730.0 7149.4 265 0.0 0.161 263.7 6602 Kup B 117580 7175.9 123 59. OA60 99.9 2668 Kup A3 11771.0 71002 10S 10.4 0.036 WO 1740 Kup A3 117820 7190.7 85 7A Dim 48A 1221 Kup A2 11791.0 7297.2 11.4 11A 0.000 .0 0 Kup A2 11803.0 7218.6 143 59. OJOW A 0 Kup Al 11818.0 72329 7.7 5.7 OA00 A 0 Kup Al 11826.0 7240.6 41.7 159. 0.000 A 0 Miluveach 11876.0 7288.3 100.0 IA 0A00 _0 0 11 Schlumberger -Private 20 AAC 25.283 (a)(13) Description of the Plan for Post -Fracture Wellbore Cleanup and Fluid Recovery through to Production Operations The well will be cleaned up through a portable separation system before turning the well over to Production. Initial returns will be taken to the permitted Milne Point G&I facility for disposal. Coil Tubing Unit Fluid Flow Diagram Fill Cleanout H ni" MeA.. W: 500 BBL KILL TANK Open �q- PUMP op< I NITROGEN PUMP p„ To Flowline L•�� i•.,••..��...•.•.•. ....�I Op" i� am.a '•..i•.....::.... i oPe� .......................... m .- Choke Manifold NRROGEN TANK 50 BBL FREEZE PROTECTTANK Updated 11/22/15 Coil Tubing Unit Fluid Flow Diagram Cleanout w/ Nitrogen SEAWATER W/ 400 BBL UPRIGHT FOAMER SEAWATER W/ 40088E UPRIGHT FOAMER LEGEND: Fluids Pumped . Fluids Returned Valve Open Valve Closed Gate Valve DG Ball Valve X00 Butterfly Valve W Lo Torq Valve X00 Check Valve N Manual Choke Pressure Gauge 0 STANDARD WELL PROCEDURE I liloorp Ala.ka. LU] NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 Schwartz, Guy L (DOA) From: Seamount, Dan T (DOA) Sent: Sunday, December 2, 2018 5:17 PM To: Schwartz, Guy L (DOA) Cc: Davies, Stephen F (DOA); Wallace, Chris D (DOA) Subject: Re: PTD 218-109 Verval for Frac Sundry Ok Sent from my iPhone On Dec 2, 2018, at 2:49 PM, Schwartz, Guy L (DOA) <Ruy.schwartzPalaska.aov> wrote: Dan, Hilcorp is also ready to frac this well ... brand new Kuparuk well so as usual we are on a short time line. Steve, Chris and I have reviewed the program and data. I talked with Steve this afternoon and we are in agreement that the well is adequately vetted and that it can go ahead. If the office is closed tomorrow it will need a verbal to go ahead. They have been waiting since yesterday. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793- 1226 ) or (Guv.schwartz@alaska.aov). <L-55 Frac PTD 218-109.pdf> U U O y u E E o a Z "' u a o w, a O N N 3 v a� m o •moi o � c � m a° w p C w 3 'n n a v «„ O v � O Y u N i` o e E ' u D o N o£ q=$ $ t E ti '3 o '°8 p E o= E @1 E U 3 s _� e m a E o .e E .ti i ° n '" " .. 3 E Y 3 a«" E E n q @ Q c = n E v m E u v c^ E - i c v E m' E c m' p E Y E u c° 9' m y =Y o o_ m S e E u p `u v m v u v o u o v o M 3 a v E c ;« E v' =$-° �a,a° n v oo `u n mzi _ p F 7 v; N ' y E E u°o n=m2 tY� =pr l _� "�f=__ =�zauO° o �v nO° u « p v u-= E v a o c $ c ' d g e o m a o E 3 m o 1 v E o Y v c u n A m.. m!. o Yi a `u 3 m o E: q A m E c u go u v vi 6 w Y .Y a Y Y V O = E2 � a 3 A p 0 0 a� � a8m — V F z p z z p z e - p p a V ti V N 6 1- ti F P F O 3� ax oy ¢Y 3y ox ay a 3 P $ $ a $ $ e r $ z a 3 ¢ d h 9 9 r U U O Davies, Stephen F (DOA) From: Taylor Wellman <twellman@hilcorp.com> Sent: Saturday, December 1, 2018 2:50 PM To: Davies, Stephen F (DOA); Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL] RE MPU L-55 (PTD 218-409; Sundry 318-518) Attachments: L-55 L-29 section.pdf; L-55 to L-29 distance.pptx; MP L-55 Frac Application - Mechanical Condition of Wells Rev1.docx Steve and Guy, First off, I hope that you and your families are all safe and without damage to your homes. I would have provided this information to you yesterday and stopped by your office to discuss but for good reasons we all had more important matters to look after. Enclosed is the information requested along with a map with distances from each of the zones between wells. L-29 Isolation for the Kuparuk C I'll attempt to write the description here but if it still may require a sit down. If this is insufficient please let me know and I'll will come in at your earliest available time. We currently have crews on standby after rigging up and pressure testing. We will wait before proceeding any further. The maps show the distances between L-55 and L-29 at the tops of the various zones: - Kuparuk C: Production/Frac Zone - Kuparuk D: Confining Zone - Kalubik: Confining Zone - HRZ: Confining Zone - Colville: Confining Zone I highlight this as when the regulations state wells within 1/2 mile radius of the confining zone, these distances will vary upon what is shown as the confining zone on the map. The original Sundry Application showed distances did not differentiate the tops of each of these zones. As you can see, the distance between L-55 and L-29 at the initial confining zone is 2,000'. Even if the frac was to break into the next 2 confining layers the wells are —1,600' apart. Note that the frac modeling for this well indicates that the Kuparuk D will be the confining zone that it will not break through. For these reasons, we feel that the distance between the wells at these confining layers is enough to isolate the Kuparuk C at the L-29 wellbore. MP L-29 These depths of the estimated TOC are based off of a CBL that was run in 1995 when the well was originally completed. Perforations above this were added to this well after this in 1996. 1 cannot comment on the isolation discussions or decisions at this point in time when the well was completed as it was with another operator at the time. WURE11 7" casing with a 2 stage cementjob. Estimated TOC @ 9,361' MD/5,756' TVD. Method used to determine was calculated open hole volumes with a 40% washout from the Stage Collar at 10,439' MD. 2nd Stage: 34.1bbls of 15.8ppg class G cement was pumped, with 300psi lift pressure observed, and plug was bumped on calculated strokes. Increased pressure to 3,100psi to shift cementer closed. Bled off pressure to confirm cementer was closed. While pumping the job there were 100% losses but we believe the loss zone to be at ^'5,100' TVD, based on gamma ray signature, which is above the planned TOC. This description has been added to the MP L-55 Frac Application - Mechanical Condition of Wells Rev1 word document. Thank you and let me know if you have further questions or would like to propose a time to meet. -Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com -----Original Message ----- From: Taylor Wellman Sent: Thursday, November 29, 2018 9:30 PM To: Davies, Stephen F (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL] RE MPU L-55 (PTD 218-409; Sundry 318-518) Steve, In short answer, we believe there is enough distance between their wellbores to isolate the Kuparuk in L-29 from the fracture treatment in L-55. I think it might be best if I was able to bring in a few maps tomorrow to discuss the reasoning tomorrow. As for L-41, I will provide the information first thing in the morning. Thank you, Taylor From: Davies, Stephen F (DOA) [steve.davies@alaska.gov] Sent: Thursday, November 29, 2018 5:36 PM To: Taylor Wellman Cc: Schwartz, Guy L (DOA) Subject: [EXTERNAL] RE MPU L-55 (PTD 218-409; Sundry 318-518) Taylor, For nearby well MPU L-29, Hilcorp's Completion Detail matrix states in part: "Estimated TOC from CBL is 13,430' MD (7,297' TVD)." But the Completion Report for that well filed by the original operator indicates the top of the Kuparuk C sand is at 13,262' MD (7167' TVD). Is the cement adequate in L-29 to isolate the Kuparuk C interval? For nearby well MPU L-41, could Hilcorp please provide estimated footages top of cement (MD and TVD) and the means by which these values were estimated (CBL, calculated, etc.)? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov<mailto:steve.davies@alaska.gov>. From: Taylor Wellman <twellman@hilcorp.com> Sent: Tuesday, November 27, 2018 9:43 AM To: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU L-55 (PTD 218-409; Sundry 318-518) Steve, We have run a CBL that indicates isolation to the confining layer above but the cement across the Kuparuk sands indicate a little lower bond. Please find the attached copy. We are going to run another CBL across this interval with a separate tool to confirm the results. I should have a field print of the CBL tomorrow to be able to send in. MP L-55 7" casing. Estimated TOC @ 10,294' MD/5,824' TVD. Method used to determine was calculated open hole volumes with a 40% washout. 37bbls of 15.8ppg class G cement was pumped, with lift pressures observed, and plug was bumped on calculated strokes. Increased pressure to 2600psi and held. Bled off and confirmed floats holding. While pumping the job there were 90% fosses but we believe the loss zone to be at —5,100' TVD, based on gamma ray signature, which is above the planned TOC. MP L-29 The MP L-29 well is a Kuparuk oil production well completed with an ESP. The 7" casing was last pressure tested and passed to 3,OOOpsi for 30 min on 11/18/2012. The well has shown no indications of a casing leak or any other mechanical integrity problems in recent times. If you have any further questions about any information in this email please let me know and I will provide additional/further information. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com<mailto:tweliman@hilcorp.com> From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, November 26, 2018 2:24 PM To: Taylor Wellman Subject: [EXTERNAL] RE: MPU L-55 (PTD 218-409; Sundry 318-518) Taylor, Additional question: Doesn't MPU L-29 transect the confining zones within %: mile of the MPU L-55 fracturing interval? If so, please provide a report on the mechanical condition of MPU L-29. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov<mailto:steve.davies@alaska.gov>. From: Davies, Stephen F (DOA) Sent: Monday, November 26, 2018 1:58 PM To: 'Taylor Wellman'<twellman@hilcorp.com<mailto:twellman@hilcorp.com>> Subject: MPU L-55 (PTD 218-409; Sundry 318-518) Taylor, When will a field image of the CBL be submitted for 4-1/2" casing? What is Hilcorp's estimated depth (MD and TVDSS) for the top of cement for 7" casing? How was this estimated depth derived? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov<mailto:steve.davies@alaska.gov>. _ ELI No I.M11 MI Mi ICC 1.MIN e0.11111 iC W31.111111 DOWN fid Slim WAe!� ON INA WE NJ M1 E ElIwi 11011111014 IN W10 ®R MAN, m Mai A MIKE 1.� WA 111 MIM] KA ■mall ELI MI mGAG, ma m �r ® W�3 wm i1 im �me m � nor --1 IM IM1111111al Mm miNo 5-0111'M EEO 0 Hilo p Alaska, LL Wells within %: mile Hydraulic Fracturing Well: MP L-55 PTD: 218-109 API: 50-029-23612-00 Well Name PTD Annulus Integrity MP L-55 218-109 MIT -IA on 11/19/18 passed to 3,5000 psi MP L-11 193-013 MIT -IA on 11/12/12 passed to 3,5000 psi MP L-14 194-068 MIT -IA on 03/04/13 passed to 2,5000 psi MP L -16A 199-090 MIT -IA on 05/30/16 passed to 2,000 psi MP L-21 195-191 MIT -IA on 11/11/18 passed to 1,850 psi MP L-29 195-009 MIT -IA on 11/18/12 passed to 3,000 psi MP L-41PB MP L-41 218-104 MIT -IA on 10/18/18 passed to 3,5000 psi Completion Detail API Well No Permit Well Current Zonal isolation (method) Status 218-109 MP L-55 7" casing. Estimated TOC @ 10,294' MD/5,824' TVD. Method used to determine was calculated open hole volumes with a 40% washout. 37bbls of 15.8ppg class G cement was pumped, with lift pressures observed, and Producer plug was bumped on calculated 50-029-23612-00 (ESP) - strokes. Increased pressure to 2600psi and Kuparuk held. Bled off and confirmed floats holding. While pumping the job there were 90% losses but we believe the loss zone to be at ^'5,100' TVD, based on gamma ray signature, which is above the planned TOC. 193-013 MP L-11 7" casing set across the Kuparuk sands and cemented with 67 bbls / 302 sxs of 15.8 ppg Producer Class G cement with partial returns during job. 50-029-22336-00 (ESP) — Bump plug and floats held. CBL log noted TOC Kuparuk low so the well was perforated and squeeze cemented at 10,992' MD with 135 sxs / 28 bbls of 15.8 ppg Class G cement. 194-068 MP L-14 7 casing set across the Kuparuk sands and Producer cemented with 44 bbls / 215 sxs of 15.8 ppg 50-029-22479-00 (ESP) — Class G cement with 30% returns during job. Kuparuk Bump plug with 3500 psi. 199-090 MP L -16A 4-1/2" liner set across the Kuparuk sands and WAG cemented with 35 bbls of 15.8 ppg Class G 50-029-22566-01 Injector - cement. Bump plug with 3500 psi. Good Kuparuk cement from 11,900'— 13,345' PBTD (6,007' — 7,391' TVD) from CBL. 195-191 MP L-21 LTSI Water 7" casing set across the Kuparuk sands and 50-029-22629-00 Injector - cemented with 51 bbls / 250 sxs of 15.8 ppg K Hil,.m Alueko, LL Hydraulic Fracturing Well: MP L-55 PTD: 218-109 API: 50-029-23612-00 Kuparuk Class G cement with 30% returns during job. Bump plug with 3500 psi. Estimated TOC from CBL is —12,000' MD (6,184' TVD). 195-009 MP L-29 7" casing set across the Kuparuk sands and Producer cemented with 61bbls of 15.8ppg Class G 50-029-22543-00 (ESP) — cement. Bump plug with 2,OOOpsi. Pressure Kuparuk test casing to 3,OOOpsi good. Estimated TOC from CBL is 13,430' MD (7,297' TVD). MP L- Cemented 4-1/2" liner. Unable to release 41PB from 4-1/2" liner. Commence plug back operations. Spot balanced plug inside 7" production casing and tagged at 9,590' MD. Pressure tested 7" casing and cement plug to Plugback 2000 psi. Set retainer set at 7,833' MD and tested good to 2000 psi. Cut and pull 7" casing down to 7,667' MD. Spot balanced cement plug from top of retainer at 7,883' MD to 7,267' MD. Note 9-5/8" casing shoe at 7,366' MD. Kick off well at 7,392' MD. 218-104 MP L-41 7" casing set across the Kuparuk sands. First stage cement job: 52.7 bbls / 255 sxs of 15.8 ppg Class G cement with 100% losses during the first stage cement job. 590 psi lift pressure observed during cement job. Second stage cement job: 34.1 bbls / 165 sxs of 15.8 ppg Class G cement with 100% losses. 300 psi lift pressure observed during cement job. 7" casing with a 2 stage cement job. Estimated TOC @ 9,361' MD/5,756' TVD. 50-029-23611-00 Producer (ESP) — Method used to determine was calculated Kuparuk open hole volumes with a 40% washout from the Stage Collar at 10,439' MD. 2nd Stage: 34.1bbls of 15.8ppg class G cement was pumped, with 300psi lift pressure observed, and plug was bumped on calculated strokes. Increased pressure to 3,100psi to shift cementer closed. Bled off pressure to confirm cementer was closed. While pumping the job there were 100% losses but we believe the loss zone to be at ^'5,100' TVD, based on gamma ray signature, which is above the planned TOC. Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-55 Colville 8499 -4737 4787 2016 L-55 HRZ 11361 -6753 6803 18 L-55 KLB 11381 -6771 6821 160 L-55 KUP_D 11551 -6931 6981 121 L-55 KUP C 11679 -7052 7102 Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-29 Colville 7687 -4687 4737 2071 L-29 HRZ 12406 -6758 6808 30 L-29 KLB 12471 -6788 6838 221 L-29 KUP_D 12936 -7009 7059 155 L-29 KUP C 13259 -7164 7214 4M, -0400. -4000 5200 C -5600 511 100 6oDo � iC� nw6 0JP o 1UP_c aexn 640o., 541,6n0 L-55 swop rw,ru6 510000 J200 i I 6037N0 `.1200 ima `zoos `.2400 2s0o 1.3200 3600 Za is `4000 `4400 `.4WD `-5200 •3600 6036000 Y�a,N 6035000 0 500 1000 1500 2000 2SMUS Ytn7� 1:15ers �D distance between the confining zones :olville to Kuparuk D) Aween L-55 and L-29 3D distances Top Colville: 1390 ft Top HRZ: 1597 ft Top Kalubik: 1649 ft Top Kuparuk D: 2000 ft Top Kuparuk C: 2252 ft COMIle 4737 -497 10294 -5774 0 200 40 400 000 INOM5 ItlLti i'W500 KUP_C 29E KUP_D36 716L -7009 3D distance between the confining zones (Colville to Kuparuk D) between L-55 and L-29 Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-55 Colville 8499 -4737 4787 2016 L-55 HRZ 11361 -6753 6803 18 L-55 KLB 11381 -6771 6821 160 L -5S KUP_D 11551 -6931 6981 121 L-55 KUP C 11679 -7052 7102 v v c � Y Y V U L L W W J J F H p po 1� M ei e4 N F n m 00 01 O L m O N oD O L M O M Yf rl v v p p H � N V1 p p c n � v v O p O p a e m N d H rl rl rl � N rl ei 'i p O C c O a p V O N D U = N m 1 = N m 1 I m> p V Y Y Y Q U y Y Y LL LL �4j1 J J 1l1 1l1 V1 d N N N N N J J J 3 J J J J Schwartz, Guy L (DOA) From: Seamount, Dan T (DOA) Sent: Sunday, December 2, 2018 5:17 PM To: Schwartz, Guy L (DOA) Cc: Davies, Stephen F (DOA); Wallace, Chris D (DOA) Subject: Re: PTD 218-109 Verval for Frac Sundry Ok Sent from my iPhone On Dec 2, 2018, at 2:49 PM, Schwartz, Guy L (DOA) <guy.schwartz(@alaska.gov> wrote: Dan, Hilcorp is also ready to frac this well ... brand new Kuparuk well so as usual we are on a short time line. Steve, Chris and I have reviewed the program and data. I talked with Steve this afternoon and we are in agreement that the well is adequately vetted and that it can go ahead. If the office is closed tomorrow it will need a verbal to go ahead. They have been waiting since yesterday. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793- 1226 ) or (Guv.schwartz@olaska aov). <L-55 Frac PTD 218-109.pdf> Schwartz, Guy L (DOA) From: Taylor Wellman <twellman@hilcorp.com> Sent: Saturday, December 1, 2018 2:50 PM To: Davies, Stephen F (DOA); Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL] RE MPU L-55 (PTD 218-409; Sundry 318-518) Attachments: L-55 L-29 section.pdf; L-55 to L-29 distance.pptx,, MP L-55 Frac Application - Mechanical Condition of Wells Revl.docx Steve and Guy, First off, I hope that you and your families are all safe and without damage to your homes. I would have provided this information to you yesterday and stopped by your office to discuss but for good reasons we all had more important matters to look after. Enclosed is the information requested along with a map with distances from each of the zones between wells. L-29 Isolation for the Kuparuk C I'll attempt to write the description here but if it still may require a sit down. If this is insufficient please let me know and I'll will come in at your earliest available time. We currently have crews on standby after rigging up and pressure testing. We will wait before proceeding any further. The maps show the distances between L-55 and L-29 at the tops of the various zones: - Kuparuk C: Production/Frac Zone - Kuparuk D: Confining Zone - Kalubik: Confining Zone - HRZ: Confining Zone - Colville: Confining Zone I highlight this as when the regulations state wells within 1/2 mile radius of the confining zone, these distances will vary upon what is shown as the confining zone on the map. The original Sundry Application showed distances did not differentiate the tops of each of these zones. As you can see, the distance between L-55 and L-29 at the initial confining zone is 2,000'. Even if the frac was to break into the next 2 confining layers the wells are 1,600' apart. Note that the frac modeling for this well indicates that the Kuparuk D will be the confining zone that it will not break through. For these reasons, we feel that the distance between the wells at these confining layers is enough to isolate the Kuparuk C at the L-29 wellbore. MP L-29 These depths of the estimated TOC are based off of a CBL that was run in 1995 when the well was originally completed. Perforations above this were added to this well after this in 1996. 1 cannot comment on the isolation discussions or decisions at this point in time when the well was completed as it was with another operator at the time. MP L-41 7" casing with a 2 stage cement job. Estimated TOC @ 9,361' MD/5,756' TVD. Method used to determine was calculated open hole volumes with a 40% washout from the Stage Collar at 10,439' MD. 2nd Stage: 34.1bbls of 15.8ppg class G cement was pumped, with 300psi lift pressure observed, and plug was bumped on calculated strokes. Increased pressure to 3,100psi to shift cementer closed. Bled off pressure to confirm cementer was closed. While pumping the job there were 100% losses but we believe the loss zone to be at 5,100' TVD, based on gamma ray signature, which is above the planned TOC. This description has been added to the MP L-55 Frac Application - Mechanical Condition of Wells Revl word document. Thank you and let me know if you have further questions or would like to propose a time to meet. Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com -----Original Message ----- From: Taylor Wellman Sent: Thursday, November 29, 2018 9:30 PM To: Davies, Stephen F (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL] RE MPU L-55 (PTD 218-409; Sundry 318-518) Steve, In short answer, we believe there is enough distance between their wellbores to isolate the Kuparuk in L-29 from the fracture treatment in L-55. I think it might be best if I was able to bring in a few maps tomorrow to discuss the reasoning tomorrow. As for L-41, I will provide the information first thing in the morning. Thank you, Taylor From: Davies, Stephen F (DOA) [steve.davies@alaska.gov] Sent: Thursday, November 29, 2018 5:36 PM To: Taylor Wellman Cc: Schwartz, Guy L (DOA) Subject: [EXTERNAL] RE MPU L-55 (PTD 218-409; Sundry 318-518) Taylor, For nearby well MPU L-29, Hilcorp's Completion Detail matrix states in part: "Estimated TOC from CBL is 13,430' MD (7,297' TVD)." But the Completion Report for that well filed by the original operator indicates the top of the Kuparuk C sand is at 13,262' MD (7167' TVD). Is the cement adequate in L-29 to isolate the Kuparuk C interval? For nearby well MPU L-41, could Hilcorp please provide estimated footages top of cement (MD and TVD) and the means by which these values were estimated (CBL, calculated, etc.)? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or Steve.davies@alaska.gov<mailto:steve.davies@alaska.gov>. From: Taylor Wellman <twellman@hilcorp.com> Sent: Tuesday, November 27, 2018 9:43 AM To: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] RE: MPU L-55 (PTD 218-409; Sundry 318-518) Steve, We have run a CBL that indicates isolation to the confining layer above but the cement across the Kuparuk sands indicate a little lower bond. Please find the attached copy. We are going to run another CBL across this interval with a separate tool to confirm the results. I should have a field print of the CBL tomorrow to be able to send in. MP L-55 7" casing. Estimated TOC @ 10,294' MD/5,824' TVD. Method used to determine was calculated open hole volumes with a 40% washout. 37bbls of 15.8ppg class G cement was pumped, with lift pressures observed, and plug was bumped on calculated strokes. Increased pressure to 2600psi and held. Bled off and confirmed floats holding. While pumping the job there were 90% losses but we believe the loss zone to be at ^'5,100' TVD, based on gamma ray signature, which is above the planned TOC. MP L-29 The MP L-29 well is a Kuparuk oil production well completed with an ESP. The 7" casing was last pressure tested and passed to 3,OOOpsi for 30 min on 11/18/2012. The well has shown no indications of a casing leak or any other mechanical integrity problems in recent times. If you have any further questions about any information in this email please let me know and I will provide additional/further information. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com<mailto:twellman@hilcorp.com> From: Davies, Stephen F (DOA)[mailto:steve.davies@alaska.gov] Sent: Monday, November 26, 2018 2:24 PM To: Taylor Wellman Subject: [EXTERNAL] RE: MPU L-55 (PTD 218-409; Sundry 318-518) Taylor, Additional question: Doesn't MPU L-29 transect the confining zones within % mile of the MPU L-55 fracturing interval? If so, please provide a report on the mechanical condition of MPU L-29. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov<mailto:steve.davies@alaska.gov>. From: Davies, Stephen F (DOA) Sent: Monday, November 26, 2018 1:58 PM To:'Taylor Wellman'<twellman@hilcorp.com<mailto:twellman@hilcorp.com>> Subject: MPU L-55 (PTD 218-409; Sundry 318-518) Taylor When will a field image of the CBL be submitted for 4-1/2" casing? What is Hilcorp's estimated depth (MD and TVDSS) for the top of cement for 7" casing? How was this estimated depth derived? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov<mailto:steve.davies@alaska.gov>. U Hil.m Alaska, LU Wells within''/: mile Hydraulic Fracturing Well: MP L-55 PTD: 218-109 API: 50-029-23612-00 Well Name PTD Annulus Integrity MP L-55 218-109 MIT -IA on 11/19/18 passed to 3,5000 psi MP L-11 193-013 MIT -IA on 11/12/12 passed to 3,5000 psi MP L-14 194-068 MIT -IA on 03/04/13 passed to 2,5000 psi MP L -16A 199-090 MIT -IA on 05/30/16 passed to 2,000 psi MP L-21 195-191 MIT -IA on 11/11/18 passed to 1,850 psi MP L-29 195-009 MIT -IA on 11/18/12 passed to 3,000 psi MP L-41PB MP L-41 1 218-104 MIT -IA on 10/18/18 passed to 3,5000 psi Completion Detail API Well No Permit Well Current Zonal isolation (method) Status 218-109 MP L-55 7" casing. Estimated TOC @ 10,294' MD/5,824' TVD. Method used to determine was calculated open hole volumes with a 40% washout. 37bbls of 15.8ppg class G cement was pumped, with lift pressures observed, and 50-029-23612-00 Producer (ESP) - plug was bumped on calculated Kuparuk strokes. Increased pressure to 2600psi and held. Bled off and confirmed floats holding. While pumping the job there were C g� 90% losses but we believe the loss zone to be H! �— at ^'5,100' TVD, based on gamma ray signature, which is above the planned TOC. 193-013 MP L-11 7" casing set across the Kuparuk sands and cemented with 67 bbls / 302 sxs of 15.8 ppg Producer Class G cement with partial returns during job. 50-029-22336-00 (ESP) — Bump plug and floats held. CBL log noted TOC Kuparuk low so the well was perforated and squeeze cemented at 10,992' MD with 135 sxs / 28 bbls of 15.8 ppg Class G cement. 194-068 MP L-14 Producer 7" casing set across the Kuparuk sands and 50-029-22479-00 (ESP) — cemented with 44 bbls / 215 sxs of 15.8 ppg Kuparuk Class G cement with 30% returns during job. - Bump plug with 3500 psi. 199-090 MP L -16A 4-1/2" liner set across the Kuparuk sands and WAG cemented with 35 bbls of 15.8 ppg Class G 50-029-22566-01 Injector - cement. Bump plug with 3500 psi. Good Kuparuk cement from 11,900' —13,345' PBTD (6,007'- 6,007'- 1 7,391' 7,391' TVD) from CBL. 50-029-22629-00 195-191 MP L-21 LTSI Water 7" casing set across the Kuparuk sands and Injector - cemented with 51 bbls / 250 sxs of 15.8 ppg H I ilvara Alaska. LL Hydraulic Fracturing Well: MP L-55 PTD: 218-109 API: 50-029-23612-00 Kuparuk Class G cement with 30% returns during job. Bump plug with 3500 psi. Estimated TOC from CBL is 12,000' MD (6,184' TVD). 195-009 MP L-29 7" casing set across the Kuparuk sands and Producer cemented with 61bbls of 15.8ppg Class G 50-029-22543-00 (ESP) — cement. Bump plug with 2,OOOpsi. Pressure Kuparuk test casing to 3,OOOpsi good. Estimated TOC from CBL is 13,430' MD (7,297' TVD). MP L- Cemented 4-1/2" liner. Unable to release 41PB from 4-1/2" liner. Commence plug back operations. Spot balanced plug inside 7" production casing and tagged at 9,590' MD. Pressure tested 7" casing and cement plug to Plugback 2000 psi. Set retainer set at 7,833' MD and tested good to 2000 psi. Cut and pull 7" casing down to 7,667' MD. Spot balanced cement plug from top of retainer at 7,883' MD to 7,267' MD. Note 9-5/8" casing shoe at 7,366' MD. Kick off well at 7,392' MD. 218-104 MP L-41 7" casing set across the Kuparuk sands. First stage cement job: 52.7 bbls / 255 sxs of 15.8 ppg Class G cement with 100% losses during Producer the first stage cement job. 590 psi lift 50-029-23611-00 P) — (ESP) pressure observed during cement job. Second stage cement job: 34.1 bbls / 165 sxs of 15.8 ppg Class G cement with 100% losses. 300 psi lift pressure observed during cement job. R Hil.m Alaska. LL Wells within % mile Hydraulic Fracturing Well: MP L-55 PTD: 218-109 API: 50-029-23612-00 Well Name PTD Annulus Integrity MP L-55 218-109 MIT -IA on 11/19/18 passed to 3,5000 psi MP L-11 193-013 MIT -IA on 11/12/12 passed to 3,5000 psi MP L-14 194-068 MIT -IA on 03/04/13 passed to 2,5000 psi MP L -16A 199-090 MIT -IA on 05/30/16 passed to 2,000 psi MP L-21 195-191 MIT -IA on 11/11/18 passed to 1,850 psi M - 1 195-009 MIT -IA on 11/18/12 passed to 3,000 psi MP L -41P6 MP L-41 1 218-104 MIT -IA on 10/18/18 passed to 3,5000 psi Completion Detail API Well No Permit Well Current Zonal isolation (method) Status 218-109 MP L-55 7" casing. Estimated TOC @ 10,294' MD/5,824' TVD. Method used to determine was calculated open hole volumes with a 40% washout. 37bbis of 15.8ppg class G cement was pumped, with lift pressures observed, and Producer plug was bumped on calculated 50-029-23612-00 (ESP) - strokes. Increased pressure to 2600psi and Kuparuk held. Bled off and confirmed floats holding. While pumping the job there were 90% losses but we believe the loss zone to be at 5,100' TVD, based on gamma ray signature, which is above the planned TOC. 193-013 MP L-11 7" casing set across the Kuparuk sands and cemented with 67 bbls / 302 sxs of 15.8 ppg Producer Class G cement with partial returns during job. 50-029-22336-00 (ESP) — Bump plug and floats held. CBL log noted TOC Kuparuk low so the well was perforated and squeeze cemented at 10,992' MD with 135 sxs / 28 bbls of 15.8 ppg Class G cement. 194-068 MP L-14 7" casing set across the Kuparuk sands and Producer cemented with 44 bbls / 215 sxs of 15.8 ppg 50-029-22479-00 (ESP) Kuparukk Class G cement with 30% returns during job. Bump plug with 3500 psi. 199-090 MP L -16A 4-1/2" liner set across the Kuparuk sands and WAG cemented with 35 bbls of 15.8 ppg Class G 50-029-22566-01 Injector - cement. Bump plug with 3500 psi. Good Kuparuk cement from 11,900'— 13,345' PBTD (6,007' — 7,391' TVD) from CBL. 50-029-22629-00 195-191 MP L-21 LTSI Water 7" casing set across the Kuparuk sands and Injector - cemented with 51 bbls / 250 sxs of 15.8 ppg n 11&o,, M.A., 1.1: Hydraulic Fracturing Well: MP L-55 PTD: 218-109 API: 50-029-23612-00 Kuparuk Class G cement with 30% returns during job. Bump plug with 3500 psi. Estimated TOC from CBL is "'12,000' MD (6,184' TVD). 195-009 MP L-29 7" casing set across the Kuparuk sands and Producer cemented with 61bbls of 15.8ppg Class G 50-029-22543-00 (ESP) — cement. Bump plug with 2,OOOpsi. Pressure Kuparuk test casing to 3,OOOpsi good. Estimated TOC from CBL is 13,430' MD (7,297' TVD). MP L- Cemented 4-1/2" liner. Unable to release 41PB from 4-1/2" liner. Commence plug back operations. Spot balanced plug inside 7" production casing and tagged at 9,590' MD. Pressure tested 7" casing and cement plug to Plugback 2000 psi. Set retainer set at 7,833' MD and tested good to 2000 psi. Cut and pull 7" casing down to 7,667' MD. Spot balanced cement plug from top of retainer at 7,883' MD to 7,267' MD. Note 9-5/8" casing shoe at 7,366' MD. Kick off well at 7,392' MD. 218-104 MP L-41 7" casing set across the Kuparuk sands. First stage cement job: 52.7 bbis / 255 sxs of 15.8 ppg Class G cement with 100% losses during the first stage cement job. 590 psi lift pressure observed during cement job. Second stage cement job: 34.1 bbls / 165 sxs of 15.8 ppg Class G cement with 100% losses. 300 psi lift pressure observed during cement job. 7" casing with a 2 stage cement job. Estimated TOC @ 9,361' MD/5,756' TVD. Producer Method used to determine was calculated 50-029-23611-00 (ESP) — open hole volumes with a 40% washout from Kuparuk the Stage Collar at 10,439' MD. 2nd Stage: 34.1bbls of 15.8ppg class G cement was pumped, with 300psi lift pressure observed, and plug was bumped on calculated strokes. Increased pressure to 3,100psi to shift cementer closed. Bled off pressure to confirm cementer was closed. While pumping the job there were 100% losses but we believe the loss zone to be at ^'5,100' TVD, based on gamma ray signature, which is above the planned TOC. • I- I8:26:45AM I8:39:39A�` JV�V•• I�v ODate:28 are referenced to toolstring zero Company:Hilcorp Alaska LLC Well:Milne Pt Unit L-55 : SCMT VDL Image Format: Log ( Scmt_VDL_Image) Index Scale: 5 in per 100 It Index Unit: fl Index Type: Measured Depth Creation v-2018 11:02:16 TIME_1900 - Time Marked every 60.00 (s) r CBL Amplitude (CBL).... . Gamma Ray (GR) PSTP-B - - - - 0 gAPI 150 0 mV 10 CCL Transit Time for CBL (TT) CBL Amplitude (CBL) SCMT-CB Discriminate SCMT-CB 0 mV 100 Min Amplitude Max �0000000000 d Amplitude 200 us 400 Good Bond (GOBO) a e (CCPD) PSTP-B 0 V VDL VanableDensity (VDL) Cable Tension (TENS) m 10 SCMT-CB -------------- ........... • CBL Amplitude Mapping Image (0 3 V 1 3000 Ibf 0 : GoodE and From CBL to GOBO': 200 us 1200 100) SCMT-CB 11220 11240 OEM 11260 v 11270 Q1 1128011290i 11301 1110 912, 11 11310 11320 011111 11330 00101 11340 111110 r :11-41- q %, tr 4,-, -fz�L- �l% 11810 11820 11830 9 1184 1 1185 t' 11860 ti 11870 �I I 11880 11890 CCL Gamma Ray (GR) PSTP-B CBL Amplitude (CBL) SCMT-CB Min Amplitude Maxd _ o MR Discriminate 0 mV 10 r n r A r r h n r -. Q •- 0 gAPI 150 d Amplitude VDL VarSCMTensity (VDL) (CCLD) Transit Time for CBL (TT) CBL Amplitude (CBL) SCMT-CB SCMT-CB CBL Amplitude Mapping Image (0 0 mV 100 PSTP-B SCMT-CB 200 us 1200 100) SCMT-CB 3 V -1 200 us 400 Good Bond (GOBO) Cable Tension (TENS) ------------------- 0 mV 10 3000 Ibf 0 to GOBO• ••GoodBond From CBL--------------- TIME_1900 - Time Marked every 60.00 (s) Description: SCMT VDL Image Format: Log ( Scmt_VDL_Image ) Index Scale: 5 in per 100 ft Index Unit: ft Index Type: Measured Depth Creation Date: 28-Nov-201811:02:16 CBL: Parameters Parameter Description Tool Value Unit BHT Bottom Hole Temperature Borehole 178 degF CB3G SCMT C8L 3 it Peak Detection TO Delay and Noise Gate SCMT-CB 232.83 us CBLG CBL Gate Width SCMT-CB 30 us OBRA CBL LOC Reference Amplitude in Free Pipe SCMT-CB Depth Zoned mV DFD Drilling Fluid Density Borehole 9.8 bm/gal DFT_CATEGORY Drilling Fluid Type Borehole Water FPD Elevation of Permanent Datum (PDAT) above Mean Sea WLSESSION 0 R Level GGRD Geothermal Gradient Borehole 1 0.01 degF/ft GOBO CURR Good Bond in Arbitrary Cement SCMT-CB Depth Zoned mV GTSE Generalized Temperature Selection, from Measured or Borehole WrEP computed Temperature MAPG SCMT MAP Peak Detection TO—Delay and Noise Gate SCMT-CB 167 us MATT_CURR Maidmum AnenuaWn in Arbitrary Cement SCMT-CB Depth Zoned dent MCI Minimum Cemented Interval for Isolation Saff-CB Depth Zoned it MM.SA IMP Minimum Snnie Amninude I SCMT-CA I nwmih 7nned I.V Well Formation Depth MD Depth TVD55 Depth TVD True Vertical Thickness L-55 Colville 8499 -4737 4787 2016 L-55 HRZ 11361 -6753 6803 18 L-55 KLB 11381 -6771 6821 160 L-55 KUP_D 11551 -6931 6981 121 L-55 KUP C 11679 -7052 7102 Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-29 Colville 7687 -4687 4737 2071 L-29 HRZ 12406 -6758 6808 30 L-29 KLB 12471 -6788 6838 221 L-29 KUP_D 12936 -7009 7059 155 L-29 KUP C 13259 -7164 7214 aw0 4400, AND i U00 N -5600 300 6000 i� NP D NP c 6400 � L-55 .6800 -7700 -. 6037000 6036000 Y-4xN 6035000 `4200 -IwB moo `.2400 ` 2800 3zo0 `-3500 Z axis ` 4000 `-0400 4Dao `-5200 5600 o soa +000 loo no tsooeus Itl I�:�sus 3D distance between the confining zones -olville to Kuparuk D) etween L-55 and L-29 3D distances Top Colville: 1390 ft Top HRZ: 1597 ft Top Kalubik: 1649 ft Top Kuparuk D: 2000 ft Top Kuparuk C: 2252 ft �*# roc tot% 5774 COMIIe j 8499 / 4737 KUP C 219 KUP D 1936 7166 7009 3D distance between the confining zones (Colville to Kuparuk D) between L-55 and L-29 uomlle /547 Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness 4667 L-55 Colville 8499 -4737 4787 2016 L-55 HRZ 11361 -6753 6803 18 c zoo AGO soc eco mocnus L-55 Ytltli=MMME=ZMMW KLB 11381 -6771 6821 160 L-55 KUP_D 11551 -6931 6981 121 L-55 KUP C 11679 -7052 7102 Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-55 Colville 8499 -4737 4787 2016 L-55 HRZ 11361 -6753 6803 18 L-55 KLB 11381 -6771 6821 160 L-55 KUP_D 11551 -6931 6981 121 L-55 KUP C 11679 -7052 7102 Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-29 Colville 7687 -4687 4737 2071 L-29 HRZ 12406 -6758 6808 30 L-29 KLB 12471 -6788 6838 221 L-29 KUP_D 12936 -7009 7059 155 L-29 KUP C 13259 -7164 7214 Schwartz, Guy L (DOA) From: Taylor Wellman <twellman@hilcorp.com> Sent: Wednesday, November 28, 2018 2:42 PM To: Schwartz, Guy L (DOA) 1 Cit Subject: RE: [EXTERNAL] RE: MPU L-55 (PTD 21809; Sundry 318-518) Attachments: Hilcorp_MPU_L-55_SCMT_28Nov2018_FieldPrint2.pdf; MP L-55 SCHEMATIC 11-20-2018.pdf Guy, Please find the CBL that was run with Schlumberger's SCMT on MP L-55. The re -ran log paints a little different picture of the cement around the 4-1/2" liner. For a description of the cement around the 7" see below. I've also included a copy of the wellbore schematic for your reference. Let me know if you would like any further information prior to approval to move forward or not. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Taylor Wellman Sent: Tuesday, November 27, 2018 5:07 PM To: 'Schwartz, Guy L (DOA)' Subject: FW: [EXTERNAL] RE: MPU L-55 (PTD 218-409; Sundry 318-518) Guy, I'm sorry that I forgot to include you on the response to Steve earlier today. I should have the other CBL tomorrow if you'd like to see that as well. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Taylor Wellman Sent: Tuesday, November 27, 2018 9:43 AM To: 'Davies, Stephen F (DOA)' Subject: RE: [EXTERNAL] RE: MPU L-55 (PTD 218-409; Sundry 318-518) Steve, We have run a CBL that indicates isolation to the confining layer above but the cement across the Kuparuk sands indicate a little lower bond. Please find the attached copy. We are going to run another CBL across this interval with a separate tool to confirm the results. I should have a field print of the CBL tomorrow to be able to send in. MP L-55 7" casing. Estimated TOC @ 10,294' MD/5,824' TVD. Method used to determine was calculated open hole volumes with a 40% washout. 37bbls of 15.8ppg class G cement was pumped, with lift pressures observed, and plug was bumped on calculated strokes. Increased pressure to 2600psi and held. Bled off and confirmed floats holding. While pumping the job there were 90% losses but we believe the loss zone to be at 5,100' TVD, based on gamma ray signature, which is above the planned TOC. MP L-29 The MP L-29 well is a Kuparuk oil production well completed with an ESP. The 7" casing was last pressure tested and passed to 3,000psi for 30 min on 11/18/2012. The well has shown no indications of a casing leak or any other mechanical integrity problems in recent times. If you have any further questions about any information in this email please let me know and I will provide additional/further information. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC — Ops Engineer: Alaska North Slope Team Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Davies, Stephen F (DOA) [mailto:steve.daviest7a alaska.gov] Sent: Monday, November 26, 2018 2:24 PM To: Taylor Wellman Subject: [EXTERNAL] RE: MPU L-55 (PTD 218-409; Sundry 318-518) Taylor, Additional question: Doesn't MPU L-29 transect the confining zones within % mile of the MPU L-55 fracturing interval? If so, please provide a report on the mechanical condition of MPU L-29. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesrvtalaska.gov. From: Davies, Stephen F (DOA) Sent: Monday, November 26, 2018 1:58 PM To:'Taylor Wellman' <twellman@hilcorp.com> Subject: MPU L-55 (PTD 218-409; Sundry 318-518) Taylor, When will a field image of the CBL be submitted for 4-1/2" casing? What is Hilcorp's estimated depth (MD and TVDSS) for the top of cement for 7" casing? How was this estimated depth derived? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. Main To Repeat Main To Repeat Main To Repeat Min Amplitude C O O O O O O p O O O MaxI. Repeat To Repeat To Main Repeat To Main VDL VariableDensity (VDL) SCMT-CB CBL Amplitude Mapping Image (0 Main CCL Discriminate Transit Time for CBL (TT) SCMT-CB CBL Amplitude (CBL) SCMT-CB 0 mV 10 200 us 1200 100) SCMT-CB 200 us 400 To Repeat d AmplitudeMain (CCLD) Main To Repeat PSTP-B Repeat To Main Repeat To Main 3 V -1 Gamma Ray (GR) PSTP-B CBL Amplitude (CBL) SCMT-CB 0 gAPI 150 0 mV 100 Main To Repeat Repeat To Main CBL Amplitude (Fluid Compensated) (CBLF) SCMT-CB ------------------- 0 mV 10 Main To Repeat Repeat To Main Bond Index (BI) SCMT-CB 1 0 Good Bond (GOBO) 0 mV 10 TIME-1900 - Time Marked every 60.00 (s) Description: SCMT VDL Image Format: Log (SCMT_VDL_lmage RA) Index Scale: 5 in per 100 ft Index Unit: ft Index Type: Measured Depth Creation Date: 28-Nov-2018 11:02:19 WIN EVA Ml wo`�� 111A Ml ELI ! i W� E� i i ME WIlEE; �NIisll: lwi as M i� — WINIilE MIS RMI wilsamit'. MES !W E,m_,�iMw i &I Eli wl Eli E h ri�Yt��t7 IF�l mkm W MIA i1 i MAI millonal Of IM ENS i EI IME#1 RAW MEN ROME! Immin H rfa'...�p ,AL.A.,1.M: DATE 11/20/2018 L,ebra Oudean Hilcorp Alaska, LL� GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: AOGCC Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 CD: HALLIBURTON Final Well Data ROP DGR EWR-Phase 4, CTN, ALD MD DGR, EWR-Phase 4, CTN, ALD TVD _Log Viewers CGI Definitive Survey EMF LAS PDF TIFF RECEIVED NOV 2 3 2018 AOGCC 11/20/2018 2:53 PM File folder 11/20/2018 2:54 PM File folder 11/20/2018 2:52 PM File folder 11/20/2018 2:52 PM File folder 11/20/2018 2:52 PM File folder 11/20/2018 2:52 PM File folder 11/20/2018 2:53 PM File folder 21$109 50044 Please include current contact information if different from above. Please acknowledge %ecej�t by signing nd turning one copy of this transmittal or FAX to 907 777.8510 Received By: / 14A 14 \ ) Date: I, I L� 10V j_ THE SlAfE Alaska Oil and Gas OIALASKA Conservation Commission GOVERNOR BILL WALKER Monty Myers Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Kuparuk Oil Pool, MPU L-55 Permit to Drill Number: 218-109 Sundry Number: 318-483 Dear Mr. Myers: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. DATED this 3 - day of October, 2018. Sincerely, U /Ozac-� Cathy P. goerster Commissioner RBDMS\L NOV 0 1 1010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.290 RrECE1VED OCT 10 2018 D/�'/3 ff � , r+ 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ 1AW6 AMWutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: _Top Out Job ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: 5 LL • Hilcorp Alaska, LLC Exploratory ❑ Development D • Stratigraphic El Service ❑ 218-109 3. Address:6. API Number: 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 50-029-23612-00-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑✓ MPU L-55 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025509 / ADL355017 Milne Point Field / Kuparuk Oil Pool , 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,450' 4,767' 8,450' 4,767' 3394 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 80' 80' Surface 8,440' 9-518" 8,440' 4,762' 5750 3090 Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): NIA N/A N/A NIA N/A Packers and SSSV Type: N/A Packers and SSSV MD (ft) and TVD (ft): N/A 12. Attachments: Proposal Summary Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 10/29/2018 OILWINJ ❑ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: 10/29/2018 Commission Representative: Guy Schwartz GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Monty Myers Contact Name: Joe Engel Authorized Title: Drilling Manager Contact Email: leD el hilcor .Com Contact Phone: 777-8395 It) Authorized Signatu - Data: /0, 7 J � ' � C! COMMISSION USE ONLY Conditions of approval: Notify Commission so that a represen a rve may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ _ L c)-7Spacing Exception Required. Yes E] No D/ Subsequent Form Required: l APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: h9 pP�xa � Tst /'� f7BD' S4Ay *42 �ubmit Fcrmand�� i Form 10-403 Revised 4/2017 ((// Approve a PP lication r4Wrr•n t ate of approval. Attachments in Duplicate MPL-55 Surface Cement Too Job Goal: P/U and run 1'/<" tubing in the 12-1/4" x 9-5/8" annulus as deep as possible and pump cement to ✓ surface. Operations: • M/U 1'/<" mule shoe, P/U and run 1 %" CSH as deep as possible, hoping for 900' +- ( 30 jts ) AOGCC Rep to witness tag depth. • Pump 9.2 ppg mud through every 3 joints ran to ensure no plugging issues. • Circulate bottoms up displacing old mud with clean 9.2 ppg mud. • Swap to cementers, pump 10.7 ppg Permafrost L cement ( 4.33 cuft/sk) ( 21.5 gps water) 1-2 bpm until good cement at surface. • Take returns out conductor valve removing returns from cellar with vac truck. Ensure cement sample is taken. • Shut down pump, monitor annulus for settling. • POOH L/D 1'/<" tubing and mule shoe rinsing off tbg as we pull out. H sora Alaska, LLC Orig. KB Bev.: 33.7/ GL Bev.: 16.d Previous Schematic TREE & WELLHEAD Tree I TBD Wellhead I TBD Milne Point Unit Well: MPL-55 Last Completed: TBD PTD: TBD TD = 8,459 (MD) / TD = 4,767 (ND) GENERAL WELL INFO jiAPI: 50-029-23612-0600 Completion letion Date: TBD Edited By: CJD 10-30-2018 K caro Alaska, LLC Ong. KB Elev.: 33.7' / GL Elev.: 16.9 TD = 8,459 (MJ) /TD = 4,767 (TVD) Milne Point Unit Well: MPL-55 Current Schematic Last Completed: TBD PTD: 218-109 TREE & WELLHEAD Tree TBD Wellhead ji TBD OPEN HOLE / CEMENT DETAIL Conductor DrHen 12-1/4" 5 1411 bbls, Stg 2 56 bbls, Top Job 115 bbis CASING DETAIL I Size Type Wt/Grade/Conn ID Top Btm I. _20" I Conductor I 164/A53B/Wel_ -- I N/A _ Surface _ w 9-5/8" 1 Surface I 40/L-80/TXP 1 8.835 Sufftm 8,449 GENERAL WELL INFO API: 50-029-23612-00-00 Completion Date: TBD Edited By: CJD 10-30-2018 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Monday, October 29, 2018 1:40 PM To: 'Joe Engel' Cc: Monty Myers; Doug Yessak - (C); Regg, James B (DOA) Oim.regg@alaska.gov) Subject: RE: HAK MPU L-55 (PTD: 218-109) Update Joe, You have verbal approval to pump the class G and close the ESIPC. You must notify an inspector to witness the annulus tag using the 1 %" tubing string before pumping any cement. As we discussed on the phone attempt to run as many of the 30 jts of 1.5" pipe as possible. t Also submit a sundry to document the procedure outlined below. �p0 age Guy Schwartz N/ hC r_A Sr. Petroleum Engineer yw°" AOGCC 1 907-301-4533 cell jO%zf J 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ( or (Guv.schwartz@alaska.aov(. From: Joe Engel <jengel@hilcorp.com> Sent: Monday, October 29, 2018 12:17 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Monty Myers <mmyers@hilcorp.com>; Doug Yessak - (C) <dyessak@hilcorp.com> Subject: HAK MPU L-55 (PTD: 218-109) Update Good Morning Guy - This email is to follow up from our earlier conversation and provide an update on MPU L-55. Over the weekend we successfully ran our 9-5/8" surface casing to 8,440' MD, planned casing point. We performed our first stage cementjob (329bbl Lead 82bbl tail), bumping the plug on strokes with returns throughout the job (we had 114 bbl of losses during the first stage job). After bumping the plug, we pressured up to inflate the ESIPC packer element and open the stage tool ports and we saw pressure drop - 500 psi lower than what the tool was pinned for at "' 2550 psi, after the pressure drop we were unable to circulate with any returns and an injection rate was established. When the pumps were turned off, we did see partial returns up the annulus. To ensure that the stage tool ports were open, we dropped the freefall opening plug and pushed it on to seat with a 2- 7/8" work string. We attempted to pressure up, open the ports and establish circulation again from surface but were unable to, an injection rate was established again. Below are base permafrost, stage tool and calculated Vt stage TOC numbers. MD TVD Base Permafrost 2538 1886 Stage Tool Depth 2764 1990 TOC 1st Stage Calculated 1 2905 I 2057 I Our plan forward is to pump 56 bbls of our 2nd stage tail cement followed by the stage tool closing plug to ensure there is cement behind the stage tool and shift the tool closed to regain 9-5/8" pressure integrity. We will then perform a top job with our Perm L cement, using 1-1/2" tubing ran in the 12-1/4" x 9-5/8" annulus as deep as possible and pump cement to surface. Please let me know if you have any questions or concerns with this plan forward. Thank you for your time. ItT Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg ' ,e. l 1116118 DATE: 10/30/18 P. I. Supervisor FROM: Adam Earl SUBJECT: Surface Casing Top Job Petroleum Inspector MPU L-55 Hilcorp Alaska LLC PTD 2181090 10/29/18: 1 traveled out to Doyon Rig 14 at MPU L-55 to witness 1 '/4" Pac pipe to be run in the well — down the outside of the 9 5/8" surface casing and inside the 20" conductor —to perform a remedial cement top job. The drilling crew had a false table set-up on the rig floor and were rigged up to run the small diameter pipe with the blocks. The pipe made it to 607 feet after several attempts to rotate, pump/wash (at 2 bpm), and push it down. Cement was to be pumped @ 589 feet. The crew was i circulating/conditioning mud prior to what was expected to be 4 hours minimum for the cement job so I left location. 10/30/2018: 1 returned to Doyon 14 for the initial BOPE test. Upon arrival, I went straight to the cellar/wellhead area to look at the cement job's finished product. Emergency slips had been set and included a little doughnut cap on top of the slips which enable me to see cement just below the cap. I discussed the cement top job with the Mud Engineer and looked at a sample of the cement returns. I didn't see anything that would indicate problems with this remedial cement job. We proceeded with the BOPE test. Attachments: none [file name] Page 1 of 1 THE STATE °fALASKA GOVERNOR BILI. WALKER Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www,aogcc.alaska.gov Re: Milne Point Field, Kuparuk River Oil Pool, MPU L-55 Hilcorp Alaska, LLC Permit to Drill Number: 218-109 Surface Location: 3610' FSL, 5024' FEL, SEC. 8, TI 3N, RI OE, UM, AK Bottomhole Location: 1064' FSL, 1495' FEL, SEC. 32, T14N, RI OF, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced development well. 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 Hilcorp Alaska, LLC in the attached application, the following well logs are also required for this well: Gamma ray and resistivity logs from top of base of conductor pipe to total depth of well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, ? /�— Cathy P. oerster Commissioner DATED this J day of September, 2018. RECENED STATE OF ALASKA AL, ..,r<A OIL AND GAS CONSERVATION COMMIS, iON PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: 11 Proposed Well Class: Exploratory - Gas Service - WAG LJ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill 0• Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑�• Service -Winj ❑ Single Zone E Coalbed Gas El Gas Hydrates ❑ Reddll❑ Reentry❑ Exploratory - Oil ❑ Development - Gas ❑ Service -Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q . Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 - MPU L-55 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 12,292' TVD: 7,714' Milne Point Field Kuparuk Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 3610' FSL, 5024' FEL, Sec 8, Tl3N, R10E, UM, AK • ADL025509 / ADL355017 Top of Productive Horizon: 8. DNR Approval Number: 13, Approximate Spud Date: _ 799' FSL, 1553' FEL, Sec 32, T14N, R10E, UM, AK LONS 88-002 9/24/2018 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 1064' FSL, 1495' FEL, Sec 32, T14N, R10E, UM, AK 7013 7,961' to the nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 49.7' 15. Distance to Nearest Well Open Surface: x-544853 - y- 6031799, Zone -4 GL / BF Elevation above MSL (ft): 16' to Same Pool: 1250' MPL-11 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 57.6 degrees Downhole: 4165 - Surface: 3394 . 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling I Length MD TVD MD TVD (including stage data) Conductor 20" 164# A53B Weld 80' Surface Surface 80' 80' Driven Sig 1 L - 1833 ft3 / T - 458 ft3 12-1/4" 9-5/8" 40# L-80 TXP 8,000' Surface Surface 8,000' • 4,640' Sig 2 L- 1937 ft3 / T - 314 ft3 9-7/8" x 8-1/2" 7" 26# L-80 TXP 11,252' Surface Surface 11,252' • 6,737' 202 ft3 6-1/8" 4-1/2" 12.6# L-80 TXP 12,292' 11,100' 6,500' 12,292' 7,714' 162 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes No ❑ 20. Attachments: Property Plat O BOP Sketch Drilling Program 4 Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch e Seabed Report Drilling Fluid Program B✓ 20 AAC 25.050 requirements V 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hilcor .Com Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: Date: 30 ZO Commission Use Only Permit to Drill I Number: / �y ��� "alt-�� z-'C-✓�(-� Permit Approval See cover letter for other Number: 50-Q% �Z3 / Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methaann gas hydrates, or gas contained in shales: ,-.,( `F Other: )d L -f ��] �s' l �D Samples req'd: Yes ❑ No(✓J Mud log req'd: YesEJ Nou )o0 1... H,S measures: Yes [9 No[] Directional svy req'd: YesLVJ No �T 5 S I PSc , Spacing exception req'd: Yes ❑ NoIII[J Inclination -only svy req'd: Yes❑ No.R/ f, G „(/d (y j � / / 15-" / � A �� Post initial injection MIT req'd: Yes[ -]Na❑ '[��P �� rLb 01 (•C 0 APPROVED BY — Approved by: COMMISSIONER THE COMMISSION Date: v � , °� rmra tg o�lGIA� A I Submit Form and Form 10-401 Revised 5/2017 T is permit is valid fo 2 t ro h t roval per 20 AAC 25.005(g)� _ p me s in DDuplicat� H Hilcorp e� comer t:ICI11*011 i Commissioner Alaska Oil & Gas Conservation Commission 333 W. 71h Avenue Anchorage, Alaska 99501 Re: Application for Permit to Drill MPU L-55 Dear Commissioner, Joe Engel Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email: jengel@hilcorp.com 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 55. Drilling operations are intended to commence approximately September 24th, 2018, pending rig schedule. MPU L-55 is a grassroots oil production well, targeting the Kuparuk River Pool, located on Milne Point 'L -Pad'. The directional plan is a three string slant well, with the kick off point at ±550' MD/TVD. Maximum hole angle is 60 degrees at ±1,662 MD. Surface casing will be run to below the Schrader Bluff sands and cemented to surface via a two stage primary cement job. �— Intermediate casing will be run to landed in the Upper Kalubik and cemented via a single stage cement job bringing cement to 500' MD (minimum) above shoe depth. Although normal pressure in the Lower Kalubik/Kupuark D is expected, prior wells in MPU have encountered high pressure. Top setting intermediate casing is being done as a precaution. Production liner will be 4.5" 12.6# L-80 cemented liner run to just below Kuparuk A. A 4-1/2" frac string with packer will be run. The Doyon 14 will be used to drill and complete the wellbore. After reviewing the LWD logs obtained while drilling the well, a determination will be made whether or not fracture stimulation will be performed at a later date. The base plan, however, is to fracture stimulate the Kuparuk reservoir. A separate sundry will be submitted for hydraulic fracture stimulation and completion operations. 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-55, 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 Monty Myers at 777-8431 or mmyers@hilcorp.com. Sincerely, Joe Engel Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 6` Hilcorp Alaska, LLC Milne Point Unit (MPU) L-55 Drilling Program Version 1 August 30, 2018 Table of Contents 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 WellSummary.................................................................................................................................2 Management of Change Information............................................................................................3 TubularProgram: ........................................................................................................................... 4 DrillPipe Information: ................................................................................................................... 4 CasingInspection............................................................................................................................4 InternalReporting Requirements..................................................................................................5 PlannedWellbore Schematic..........................................................................................................6 Drilling / Completion Summary ............................... Mandatory Regulatory Compliance / Notifications RXand Preparatory Work..........................................................................................................10 NIU21-1/4" 2M Diverter System.................................................................................................11 Drill 12-1/4" Hole Section........... Run 9-5/8" Surface Casing ........., 13 14.0 Cement 9-5/8" Surface Casing.....................................................................................................21 15.0 BOPE N/U, Test, and Wellhead Installation...............................................................................26 16.0 17.0 18.0 19.0 20.0 21.0 22.0 23.0 24.0 25.0 Drill 8.5" x 9.875" Intermediate Hole Section.............................................................................27 Run7" Intermediate Casing.........................................................................................................31 Cement7" Intermediate Casing...................................................................................................33 Drill 6-1/8" Production Hole Section...........................................................................................35 Run4-1/2" Liner............................................................................................................................38 Cement 4-1/2" Production Liner..................................................................................................41 Perform 4-1/2" Cleanout Run & Displacement..........................................................................43 Run4-1/2" Frac String..................................................................................................................44 Doyon14 Diverter Schematic.......................................................................................................45 Doyon 14 BOP Schematic...... .................46 26.0 Wellhead Schematic......................................................................................................................47 27.0 Days Vs Depth................................................................................................................................48 28.0 Formation Tops & Information...................................................................................................49 29.0 Anticipated Drilling Hazards.......................................................................................................51 30.0 Doyon 14 Layout............................................................................................................................54 31.0 FIT Procedure................................................................................................................................55 32.0 Doyon 14 Choke Manifold Schematic..........................................................................................56 33.0 Casing Design Information...........................................................................................................57 34.0 8-1/2" x 9.875" Hole Section MASP.............................................................................................58 35.0 6-1/8" Hole Section MASP............................................................................................................59 36.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................60 37.0 Surface Plat (As Built) (NAD 27).................................................................................................61 38.0 Drill Pipe Information...................................................................................................................62 n Hilcorp 1.0 Well Summary Milne Point Unit L-55 Drilling Procedure Well MPU L-55 Pad Milne Point "L" Pad Planned Completion Type 4-1/2" Cemented Liner Target Reservoir(s) Ku aruk A Wellplan 14 Planned Well TD, MD / TVD 12,292' MD / 7,714' TVD PBTD, MD / TVD +12,200 MD / 7,627' TVD Surface Location (Governmental) 3610' FSL, 5024' FEL, Sec 8, T13N, RIOE, UM, AK Surface Location AD 27 — Zone 4) X=544,853.40 Y=6,031,799.64 Top of Productive Horizon (Governmental) 799' FSL, 1553' FEL, Sec 32, T14N, R10E, UM, AK TPH Location (NAD 27) X=548,250.62, Y=6,039,569.2 BHL Governmental 1064' FSL, 1495' FEL, Sec 32, T14N, R10E, UM, AK BBL (NAD 27) X=548,305.31, Y=6,039,834.36 ' AFE Number 1813265 AFE Drilling Das 20 Days AFE Completion Days 6 Days AFE Drilling Amount $4,597,573 AFE Completion Amount $2,245,952 AFE Facility Amount $330,000 Maximum Anticipated Pressure (Surface) 3394 psi Maximum Anticipated Pressure (Downhole/Reservoir) 4165 psi Work String 5" 19.5# S-135 NC -50, DS -50 4" 149 S-135 XT -39 / HT38 KB Elevation above MSL: 33.7 ft + 16.0 ft = 49.7 ft GL Elevation above MSL: 16.0 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Version 1 August 2018 H Hilcorp 2.0 Management of Change Information Milne Point Unit L-55 Drilling Procedure 14 Hilcorp Alaska, LLC Hjlcorp Hilt Changes to Approved Permit to Drill Date: 8128118 Subject: Changes to Approved Permit to Drill for MPU L-55 File #: MPU L-55 Drilling and Completion Program Any modifications to MPU L-55 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be communicated to and approved by AOGCC. Approval. Drilling Manager Date Prepared: Drilling Page 3 Version 1 August 2018 Milne Point Unit L-55 n Drilling Procedure Fnap Cwupmy 3.0 Tubular Program: ") cti Cond 20" 19" Dri ' In QA in - (N/fl)si Conn Burst si Iavfts k -lb - - 164 A -106B Weld 5" 4.276" 3.25" 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 TXP 5,750 3,090 916 8-1/2" x 7" 6.276" 9-7/8" 6.151" 7.656" 26 L-80 TXP 7,240 5,410 604 6-1/8" 4-1/2" 3.968 3.833 45.00 12.6 1 L-80 TXP 8430 7500 288 4.0 Drill Pipe Information: Hole AWD See Surface& 5" ID (in) 4.276" TJ ID 3.25" TJ OD ,, 6.625" 19.5 S-135 DS50 36,100 43,100 560 Intermediate 5" 4.276" 3.25" 6.625" 19.5 5-135 NC50 25,900 26,800 560 Production 4" 3.34" 2.5625" 4.875" 14 S-135 XT39 18,500 22,200 403 4" 3.34 2.5625 4.875 14 5-135 HT38 12,200 17,700 403 *Tension Rating Based on Premium Pipe 5.0 Casing Inspection All casing will be new, PSL I (100% mill inspected, 10% inspection upon delivery). Page 4 Version 1 August 2018 Milne Point Unit L-55 Hilcorp Drilling Procedure C—, 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to mmyers@hilcorp.com, nmazzolini@hilcoM.com , ien eg�hilcorp.com and cdin erna hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager & Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final "As -Run" Casing tally to jen eg�hilcoM.com and cdin er hilcorp.com 6.6 Casing and Cement report • Send casing and cement report for each string of casing to iengel@hilcorp.com and cdinger@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcoro.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 iengel@hilcory.com Completion Engineer Paul Chan 907.777.8333 907.444.2881 Dchan@hilcoro.com Geologist Radu Girbacea 907.777.8324 907.230.9490 rairbacea@hilcoro.com Reservoir Engineer Almas Aitkulov 907.777.8475 979.739.3133 aaitkulov@hilcoro.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kflemine@hilcoro.com Safety Manager Chet Starkel 907.777.8344 406.544.7862 cstarkel@hilcoro.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 1 cdin¢er@hilcorn.com Page 5 Version 1 August 2018 H Hilcorp 7.0 Planned Wellbore Schematic Ore. KBEIei.: 337 /Q Etv.:169 TD=+12,297 (MD)/TD=27,710 Owl PBrD-M2W (MD)/PBID=t7,6Z1(Nq Milne Point Unit L-55 Drilling Procedure Proposed Schematic Milne Paint Unit Well: MPL-55 Last Completed: TBD PTD: TBD _________________.._--_--...__-_._____________I JEWELRY DETAR TREE & WELLHEAD No. I Tree TBD 3 n 000 4-1(x" aT• P.ber Wellhead TBD 211,090 1112 XN MPPle 211,100 I Mule shm _-._______________________-.------.. OPEN HOLE/CEMENT DETAIL _ ' Dendu[Mr Driven 12- 4" Stg 11833 ft3(458 }t3,S$21937 R3 14 ft3 S 9-7/9,Ad V2" 202ft3 6.1/8' 1 162 ft3 --------------- ----- - ------ ------------------------------------------------------------ CASING DETAIL Size Type Wt/Graoe/Conn ID Top Btm BPF 20' ConduRa 1641 A5361r N/A Surface HO' 1-9/8" Surface 4D L-80JT%P 8935 Surface 8,000' T Intermediate 26/L-e[I/TXG 6376 1 Surface 11,297 Lift" Dner 12.6/L-W/TKP 1 3.920 1 11,100' 12,292' TUBING DETAIL LS/2"Ew String 12.6 I L-80/T%P 3920 1 Surface 211,100 WELL INCLINATION DETAIL KOP @300 Mae Hale Angle 58 da --_.-.-__________________________I GENERAL WELL INFO API: TBD Co leum Date: TBD Ed- By: CID &29-2M8 Page 6 Version 1 August 2018 _______--..-.__._________________________ _________________.._--_--...__-_._____________I JEWELRY DETAR .i No. I Tw MD I ID 3 n 000 4-1(x" aT• P.ber t" 2 3 211,090 1112 XN MPPle 211,100 I Mule shm 4 31100 1 Une T Packer --_.-.-__________________________I GENERAL WELL INFO API: TBD Co leum Date: TBD Ed- By: CID &29-2M8 Page 6 Version 1 August 2018 Milne Point Unit L-55 Drilling Procedure 8.0 Drilling / Completion Summary MPU L-55 is a grassroots oil production well, targeting the Kuparuk River Pool, located on Milne Point `L - Pad'. The directional plan is a three string slant well, with the kickoff point at ±550'MD/TVD. Maximum hole angle is 60 degrees at ±1,662 MD. Drilling operations are expected to commence approximately September 24h, 2018, pending rig schedule. • y2L � �> y. �:^S Surface casing will be run to 8,000' MD / 41,845' TVD and cemented to surface via a two 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. r Intermediate casing will be run to ±11,252' MD /fi-,96 TVD, landed in the Upper Kalubik and cemented via a single stage cement job bringing cement to 500' MD (minimum) above shoe depth. Although normal pressure in the Lower Kalubik/Kupuark D is expected, prior wells in MPU have encountered high pressure. Top setting intermediate casing is being done as a precaution. Production liner will be 4.5" 12.6# L-80 cemented liner run to 12,291' MD / 7,714' TVD, landed just below Kuparuk A. A 4-1/2" frac string with packer will be run. After reviewing the I" logs obtained while drilling the well, a determination will be made whether or not fracture stimulation will be performed at a later date. The base plan, however, is to fracture stimulate the Kuparuk reservoir. — A separate sundry will be submitted for hydraulic fracture stimulation and completion operations. . All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on `B" pad. General sequence of operations: 1. MIRU Doyon 14 2. N/U 21-1/4"annular and 16" diverter line & Test 3. Drill 12-1/4" hole to TD of surface hole section 4. Run and Cement 9-5/8" surface casing 5. N/D diverter, N/U & test 13-5/8" x 5M BOPE 6. Drill 8-1/2" x 9-7/8" hole to TD 7. Run and cement 7" intermediate casing 8. Drill 6-1/8" hole to TD 9. Run 4-1/2" production liner & Cement 10. Run 4-1/2" Frac String 11. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface Hole: No mud logging. LWD: GR+ Res 2. Intermediate Hole: No mud logging. LWD: GR + Res 3. Production Hole: No mud logging. LWD: GR + Res Page 7 Version 1 August 2018 H Hilcorp Emv c�v.e, 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Milne Point Unit L-55 Drilling Procedure Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU L-55. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 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, Notes AOGCC and test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Version 1 August 2018 U Hilcorp Summary of BOP Equipment and Test Requirements Milne Point Unit L-55 Drilling Procedure Hole Section Equipment Test Pressure(psi) 12 1/4" 21-I/4" 2M Diverter w/ 16' Diverter Line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/4000 o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/4000 • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. 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.reggna alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guv.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 1 August 2018 R Hilcorp 10.0 R/U and Preparatory Work Milne Point Unit L-55 Drilling Procedure 10.1 L-55 will utilizes a 16" conductor with newly set cellar on L Pad. Ensure to review attached surface plat and make sure site is ready to accept rig over conductor. 10.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. . 10.3 Ensure landing ring is installed on conductor. 10.4 Ensure (2) 4" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. 10.5 Level pad and ensure enough room for layout of rig footprint and R/U. 10.6 Ensure rig mats cover entire footprint of rig 10.7 MIRU Doyon 14, Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 10.8 Mud loggers will not be used on L-55 10.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<800F). 10.10 Set test plug prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.11 Ensure 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @110 spm @ 95% volumetric efficiency. Page 10 Version 1 August 2018 H Hilcorp 11.0 N/U 21-1/4" 2M Diverter System Milne Point Unit L-55 Drilling Procedure 11.1 NIU 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic attached to program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. 11.2 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. 11.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 11.4 Set wear bushing in wellhead. Page 11 Version 1 August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure 11.5 Approximate Rig & Diverter Orientation (Drawing not to scale): -- 10 .' IL I ■28■29 ■24 ■25 E 2 ■21 i ■ 16 ■ 17 ■41 ■43 L-55 (---� MPU L -Pad L-55 75' Radius Clear of Ignition Sources — Diverter Line *Drawing Not 7o Scale Page 12 Version l AUgrst2018 U Hilcorp 12.0 Drill 12-1/4" Hole Section Milne Point Unit L-55 Drilling Procedure 12.1 P/U 12-1/4" directional drilling assembly: • Ensure BHA components have been inspected previously. • Drift and caliper all components before MAJ. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill pipe will be 5" 19.5# 5-135 NC50 & DS50 • Run a solid float in the surface hole section. 12.2 5" drill pipe and 5" HWDP will come from Weatherford. 12.3 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 12.4 Drill 12-1/4" hole section to section TD. Confirm this setting depth with the geologist and 1 Drilling Engineer while drilling the well. Target TD approximately 100' TVD through the base of the permafrost. Permafrost base is estimated at 1850' TVD • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 450-600 gpm. Monitor shakers closely to ensure shaker screen and return lines can handle the flow rate • Ensure not to out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Slow in/out of slips and while tripping to keep swab and surge pressures low • Make wiper trips if necessary. • Adjust MW and viscosity as necessary to maintain hole stability. Ensure MW at TD is 9.2 minimum. • Take MWD surveys every stand drilled. • No gas hydrates have been encountered on L Pad wells, however be prepared if hydrates are seen: Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be Page 13 Version 1 August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure reduced to prevent mud from belching over the bell nipple. Consider adding mud products such as Lecithin to allow the gas to break out. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling, packing off or running gravels • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is > 4. • Do not slide for 100' MD above the base of the permafrost or 100' below the base. We want to leave this transition as undisturbed as possible. • Ensure TD of the hole section is — 100' TVD below Schrader Bluff Sands, confirm with Geologist 12.5 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, and Toolpusher office • Rheology: Aquagel and viscosifier 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: POLYPAC SUPREME should be used for filtrate control. Background LCM (5 ppb total) SAFECARB can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of SCREENKLEEN 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 Busan 1060 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 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point AN FL Tem H Surface 8.8-9.5- 75-175 20-40 25-45 <10 <70-F 8.5-9.0 Page 14 Version 1 August 2018 / H Hilcorp P G Pm, System Formulation: Gel + FW spud mud Milne Point Unit L-55 Drilling Procedure Product- Surface hole Size Pkg ppb or (% liquids) M-1 Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 Pol Pac supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 12.6 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 12.7 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 gpm), and maximize rotation. • Pull slowly, 5— 10 ft / minute. 12.8 12.9 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. TOOH and LD BHA No open hole logging program planned. Page 15 Version 1 August 2018 H Hilcorp 13.0 Run 9-5/8" Surface Casing 13.1 R/U and pull wear bushing. Milne Point Unit L-55 Drilling Procedure 13.2 9-5/8" Surface casing will be set with slips to ensure complete circulation and returns during cement job. 13.3 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 13.4 P/U shoe joint, visually verify no debris inside joint. 13.5 Continue M/U & thread locking 120' shoe track assemblv consistine of: 9-5/8" Float Shoe 1 joint — 9-5/8" TXP, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" TXP, 1 Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' I joint — 9-5/8" TXP, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 Version 1 August 2018 n Hilcorp 13.6 Float equipment and Stage tool equipment drawings: "A Overall LMgM Type H ES Cementer Part Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) ID Depth Bypass or Shutoff Baffle to Depth Float Collar Depth Float Shoe Depth Hole TD ' s lerenw Casing Sales Manwl Section 5 B Mn. 10 Affix DriW C Max. tool OD D Opermp Seat ID E CWiN Seat ID Plug Set Part No. SO No closing Plug OD Opening Plug OD OD Shut -0R Plug OD Bypass Plug (d used) OD Milne Point Unit L-55 Drilling Procedure IGIF" ES411ho rant lLler ISnCMrreer 9"Off ply Saeb Adapter V 13, anR y By Dass Sallie Float collar Hoar ince 13.7 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. • Centralization: • 1 centralizer every joint t/ -- 1000' MD from shoe • 1 centralizer every 2 joints to 2,000' above shoe (Top of Ug m) • Verify depth of lowest Ugnu water sand for isolation with Geologist Page 17 Version I August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure • 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. Establish circulation if needed. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 13.8 Install the Halliburton Type H ESIPC 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 10 joints above stage tool • Instal centralizers ''/z joints to base of conductor • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to open at 3000 psi. Reference ESIPC Procedure. 9-5/8" 40# L-80 TXP Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 18,860 ft -lbs 23,060 ft -lbs Page 18 Version 1 August 2018 Milne Point Unit L-55 Hilcorp Drilling Procedure M.M TXP® BTC GEOMETRY Connection OD Dvzvzole Outside Diameter 9.525 in Min. Wall B7.5% 4997 in. Threads pun 5 Cenrwzbcn OD Option REGULAR Thickness ]•]Grade LBO Ten_ion Efficiency 100.0% Jon YxSd Strength Type 1 Internal Pressure Capacity 5750.000 psi Wall Thickness 0.395 is Connection OD REGULAR Ccmpressicn E6xiercy 100% Compression Strength 916.000xl0DD Max. Allowable Bending 38'I100ft Option OdIPLING Prof e00Y External Pressure Capacity 3090.000 psi Body: Red 1st Band: Red Grade LOOT 1' Type Drift API Standard 1st Band: Brown 2nd Band' 2nd Band:- Brown Type Casing 3rd Band:- 3rd Band. - 4th Band - PIPE BODY DATA GEOMETRY Nominal DD 9.525 in. Nominal Weight 401bs�tt Drift 8.679n NorinalO 8,935 in. Wall Thciawss 0.395 in. Plan End Weight 38.97 bN1 OD Tderance API PERFORMANCE Body Yield Strength 915 x10001bs Intemd Yield 5750 psi BUYS 80000 psi Collapse 3090 psi CONNECTION DATA GEOMETRY Connection OD 10.625 in. Coding Length 10.825 in. Connec5cn ID OIL= za. Make-up Loss 4997 in. Threads pun 5 Cenrwzbcn OD Option REGULAR (...PERFORMANCE Ten_ion Efficiency 100.0% Jon YxSd Strength 91B.000x10D0 Internal Pressure Capacity 5750.000 psi lbs Ccmpressicn E6xiercy 100% Compression Strength 916.000xl0DD Max. Allowable Bending 38'I100ft lbs External Pressure Capacity 3090.000 psi MAKE-UP TORQUES 1 Unimum 18800ft4bs Lpt— 20960 ft -lbs ma+ ffn 230601sEs OPERATION LIMIT TORQUES Operabng Torque 35690 ftabs Ytek1 Target 43400 Moe Notes This connection is fully interchangeable with: TXP&' BTC - 9.625 in. - 36143.5147! 53.515B.41bs1R ]1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3API 5C3 ISO 10400 - 2007. Page 19 Version 1 August 2018 H Hilcorp �� C��, Milne Point Unit L-55 Drilling Procedure 13.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.10 Slow in and out of slips. 13.11 Lower casing to setting depth. Confirm measurements. 13.12 Have slips staged in the cellar, along with necessary equipment for the operation. 13.13 R/U circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. 13.14 Reciprocate casing if possible while conditioning mud. Page 20 Version 1 August 2018 n Hilcorp Milne Point Unit L-55 Drilling Procedure 14.0 Cement 9-5/8" Surface Casing 14.1 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 cement 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. • 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. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 14.4 R/U cementing line (if not already done so). Company rep to witness all plug loading to ensure they are done in the correct order. 14.5 Fill surface lines with water and pressure test. 14.6 Pump 60 bbls 10.0 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 151 stage, confirm actual cement volumes with cementer after TD is reached. 14.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail slurry, and TOC will be brought to the stage tool. Estimated I" Stage Total Cement Volume: 'P" Cf, Page 21 Version 1 August 2018 I'tz' S A SII " 12-1/4" OH x 9-5/8" Casing (7000'- 2500') x .0558 bpf x 1.3 = 326.4 1833 J Total Lead 326.4 1833 12-1/4" OH x 9-5/8" (8000'- 1000') x .0558 bpf x 1.3 = 72.5 407 Casing ~ 9-5/8" Shoe Track 120'x .0758 bpf = 9.1 51.09 Total Tail 81.6 458 Page 21 Version 1 August 2018 I'tz' S A SII " H Hilcorp Milne Point Unit L-55 Drilling Procedure Cement Slurry Design (1St stage cement jobs): 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the casing collar depths in mind. If the hole gets "sticky", position casing string at desired depth and continue with cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting spacer across the stage tool. • Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the shutoff plug must be bumped. 14.12 Displacement calculation: (8,000' — 120') x.0758 bpf= 597.3 bbl total 40 bbl of weight space to be left behind stage tool. Confirm spacer is compatible with cement behind stage tool 14.13 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 the any cement seen at surface. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —4.5 bbls before consulting with drilling engineer. 14.15 If the plug is not bumped, consult the drilling engineer. Ensure the firefall stage tool opening plug is available if needed. This is the backup option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Page 22 Version 1 August 2018 Lead Slurry Tail Slurry System ExtendaCEM '" System SwiftCEM '" System (Hal Cem) Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk " Mixed Water 21.13 gal/sk 5.04 gal/sk 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the casing collar depths in mind. If the hole gets "sticky", position casing string at desired depth and continue with cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting spacer across the stage tool. • Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the shutoff plug must be bumped. 14.12 Displacement calculation: (8,000' — 120') x.0758 bpf= 597.3 bbl total 40 bbl of weight space to be left behind stage tool. Confirm spacer is compatible with cement behind stage tool 14.13 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 the any cement seen at surface. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of the shoe track volume, —4.5 bbls before consulting with drilling engineer. 14.15 If the plug is not bumped, consult the drilling engineer. Ensure the firefall stage tool opening plug is available if needed. This is the backup option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. Page 22 Version 1 August 2018 H Hilcorp �y Milne Point Unit L-55 Drilling Procedure 14.17 Increase pressure to 2090 psi to shift ESIPC sleeve and to begin inflating the packer. Inflate packer as per HEC rep. Reference ESIPC procedure. 14.18 Once ESIPC packer is inflated, increase pressure to 3000 psi to open rupture disc/ 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. 14.19 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 Version 1 August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure Second Stage Surface Cement Job: 14.20 Prepare for the 2"d stage as necessary. If ESIPC packer inflates, there is no need to wait on compressive strength of first stage, if there are any issues with the ESIPC, wait until first stage has reached sufficient compressive strength. Hold pre job safety meeting. 14.21 HEC representative to witness the loading of the ESIPC cementer closing plug in the cementing head. 14.22 Fill surface lines with water and pressure test. 14.23 Pump 60 bbls 10.5 ppg tuned spacer. 14.24 Mix and pump cement per below recipe for the 2"d stage. 14.25 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. Based upon first stage volume circulated back to surface and hole gauges sweeps, lead cement excess could be reduced to 150%. Estimated 2"d Staee Total Cement Volume_ Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) SwiftCEM TM System (Hal Cem) 20" Conductor 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 a 12-1/4" OH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 Total Lead 345 1937 12-1/4" OH x 9-5/8" Casing (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): 14.28 Continue pumping lead cement until uncontaminated spacer is seen at surface, then switch to tail. 14.29 After pumping cement, drop ESIPC closing plug and displace cement with rig pumps, using spud mud in mud pits. 14.30 Displacement Calculation: 2500' x .0758 bpf = 190 bbls mud Page 24 Version 1 August 2018 Lead Slurry Tail Slurry System Permafrost L SwiftCEM TM System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk 14.28 Continue pumping lead cement until uncontaminated spacer is seen at surface, then switch to tail. 14.29 After pumping cement, drop ESIPC closing plug and displace cement with rig pumps, using spud mud in mud pits. 14.30 Displacement Calculation: 2500' x .0758 bpf = 190 bbls mud Page 24 Version 1 August 2018 H Hilcorp .grp Milne Point Unit L-55 Drilling Procedure 14.31 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. 14.32 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. 14.33 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 as per wellhead rep. 14.34 Flush out wellhead with FW and BOP stack thoroughly to ensure cement, mud and cuttings are removed. 14.35 M/U pack -off running tool and pack -off to bottom of final joint. Set casing hanger packoff. Inject plastic packing element. Pressure test packoff. 14.36 Lay down cut joint and pack -off running tool. Ensure to report the following on Wel1EZ: • 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 • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • If losses are seen during cement job, note at operation during the cement job they were observed and where the cement was • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • 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 iengelghilcorp com and edingerghilcorn.com This will be included with the EOW documentation that goes to the AOGCC Page 25 Version 1 August 2018 H Hilcorp 15.0 BOPE N/U, Test, and Wellhead Installation Milne Point Unit L-55 Drilling Procedure 15.1 N/D the diverter T, 16" knife gate, 16" diverter line & N/U 11" x 13-5/8" 5M casing spool. 15.2 N/U 13-5/8" x 5M BOP as follows: • BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13- 5/8" x 5M mud cross / 13-5/8" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in bottom cavity. • Single ram can be dressed with 2-7/8" x 5" VBRs • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 15.3 Run 5" BOP test assembly, land out test plug (if not installed previously). 15.4 Test BOP to 250/4000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Confirm test pressures with PTD • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 15.5 R/D BOP test equipment 15.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.7 Mix 9.5 ppp LSND fluid for intermediate hole section. 15.8 Set wear bushing in wellhead. 15.9 If needed, rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 15.10 Ensure 6" liners in mud pumps. Page 26 Version 1 August 2018 H Hilcorp 16.0 Drill 8.5" x 9.875" Intermediate Hole Section 16.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.220 PDM) Milne Point Unit L-55 Drilling Procedure 16.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 16.3 Managed Pressure Drilling will be used on the intermediate and production hole sections. Prior to drilling out the shoe track, verify all rig crew member are familiar with operation. If needed, install RCD bearing element and perform practice connections to familiarize crews with its operations. 16.4 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 16.5 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = 2875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and 0 volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 16.6 Drill out shoe track and 20' of new formation. 16.7 Displace wellbore to 9.5 ppg LSND for FIT ' 16.8 OWFF and pull into casing shoe. 16.9 _Conduct FIT to 12.5 PPR EMW. If 12.5 pm EM W is not obtained call and discuss with Drilling Engineer. 16.10 POOH and LD cleanout BHA 16.11 P/U 8.5" x 9.875" Rotary Steerable Directional Assembly w/ Under Reamer • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill pipe will be 5" 19.5# 5-135, NC50 & DS50. • Run x2 Solid Plunger Floats for MPD Page 27 Version 1 August 2018 H Hilcorp 16.12 8.5" x 9.875" hole section mud program summary: Milne Point Unit L-55 Drilling Procedure • 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. • 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: Ensure 6 rpm is >9.875 (hole diameter) for sufficient hole cleaning, YP as low as possible • Inhibition: 3% KCl will be used for handling clay cuttings. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed • Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. • PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 9.5 — 10.8 ppg 3% KCI Inhibited LSND WBM Properties: Section Density Plastic Viscosityyield Point LGS MBT HPHT pH ntermediate 9.5-10.8• 15-25 15-20 <b% <20 <11.0 9-10 16.13 RIH w/ 8.5" x 9.875" directional assembly on 5" DP from the derrick. • Shallow test MWD to confirm tool communication • Slow string speed when tripping through the stage collar 16.14 Drill — 100' of 8.5" Hole • Enough hole to bury RSS BHA and clear UR blades from casing shoe • RPM: 120+ • Flow Rate: 350-400 gpm • WOB as needed 16.15 Circulate hole clean, drop ball and open under reamer. • Indication of open under reamer will be pump pressure and turbine RPM Page 28 Version 1 August 2018 n Hilcorp Perform pull test to confirm UR is open as well 16.16 Drill 8.5" x 9.875" Hole to — 500' MD above HRZ, 10,032' MD Milne Point Unit L-55 Drilling Procedure • RPM: 120+ • Flow Rate: 600 GPM (200 ft/min Annular Velocity) • Ensure shaker screens are set up to handle this flow rate, shakers running slightly wet to maximize solids removal efficiency. Check for holes on screens on every connection. • WOB as needed • Pump tandem high vise high weight / low vise low weight sweeps to aid in hole cleaning • Take MWD surveys every stand • Monitor hole cleaning indicators: PUW, pump pressure and ECD. Make wiper trips or backream connections if necessary 16.17 CBU x2, perform short trip to shoe if necessary • RPM: 120+ Flow Rate: 600 GPM (200 ft/min Annular Velocity) Alternate reciprocation depths to avoid troughing/ledging 16.18 Increase MW to 10.3 ppg • Increase MW with pre sheared spike fluid, in .3 ppg per circulation, this is to ensure no barite sag or uneven density • Add black products for shale stability as well 16.19 Install MPD Element • Ensure rig crew is familiar with MPD connection operations • Ensure max pressure relief settings are set correction to ensure no wellbore damage is created 16.20 Drill 8.5" x 9.875" hole section to section TD per Geologist and Drilling Engineer in Upper Kalubik (To mitigate trapped injection pressure potential), 11,252' MD • RPM: 120+ • Flow Rate: 600 GPM (200 ft/min Annular Velocity) • WOB as needed • Target ECD: 11.5 ppg EMW • Utilize MPD to maintain CBHP (constant bottom hole pressure) on connections, following ✓ Annular pressure ramp schedule • This will reduce the pumps on/ pumps off pressure cycles on shales • Slow ramp pumps on/off on each connection • Smooth connections are more important that connection time • Pump tandem high vise high weight / low vise low weight sweeps to aid in hole cleaning, monitor ECD effect of sweeps • Take MWD surveys every stand • Monitor hole cleaning indicators: PUW, pump pressure and ECD. Backream connections if necessary Page 29 Version 1 August 2018 H HiIcorp Milne Point Unit L-55 Drilling Procedure 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. 16.21 At TD; CBU at full rate and RPM least 4-5 times at maximum circulation and rotation. Alternate reciprocation depths while CBU to reduce risk of troughing and dropping inclination. Under reamer will be open during CBU, to maximize flow and hole cleaning. 16.22 Once hole is cleaned up, drop ball and close under reamer. Indications will be pump pressure and turbine rpm change. 16.23 Perform wiper trip t/ above the HRZ, offsetting swab with MPD 16.24 RIH to bottom Slow string speed to limit surge on shales 16.25 Weight up at TD for shale stability, ±10.8 ppg, maintaining CHBP of 11.5 ppg EMW I • Perform weight up with pre -sheared spike fluid, weighting up with .3 ppg increments 16.26 Observe well for flow 16.27 Spot Casing Running Pill 16.28 TOOH with the drilling assembly t/ 9-5/8" Shoe, Offsetting Swab with MPD • Follow tripping schedule, matching string speed and annular pressure • Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before casing is on bottom. 16.29 If backreaming is necessary: • Circulate at max rate while maintaining drilling ECD's (flow will be less due to 10.8 ppg MW) • Perform CBHP connections • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 —10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 16.30 CBU x2 at 9-5/8" Shoe 16.31 Continue TOOH to HWDP/ BHA, offsetting swab with MPD 16.32 Pull RCD Bearing element 16.33 LD BHA 16.34 No open hole wire line logs are planned. Page 30 Version 1 August 2018 H Hilcorp 17.0 17.1 Milne Point Unit L-55 Drilling Procedure Run 7" Intermediate Casing Change top rams to 7" solid body's for casing run. Test 250/4000 psi. Chart test. 17.2 R/U 7" casing running equipment. • Ensure 7" TXP (BTC Compatible) x NC50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints 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. • R/U CRT w/ cement swivel. 17.3 M/U & threadlock shoe track assy consisting of: • (1) Float shoe joint w/ float shoe bucked on. Install (2) solid body centralizers over a stop ring at 10' from each end. • (1) Baker locked joint. Install (1) solid body centralizer mid joint over a stop ring • (1) Float collar joint w/ float collar bucked on pin end. Install (1) solid body centralizer mid tube over a stop ring. • Ensure proper operation of float shoe and float collar. 17.4 Run 7" 26# L-80 TXP casing. • Fill casing while running using CRT or fill up line. • Use "BOL 2000" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers on every joint to 500' above shoe depth. • Install centralizers across 9-5/8" casing shoe. 17.5 RIH following casing running schedule, keeping surge below max drilling ECD EMW • Circulate BU — 500' above HRZ (11,254' MD) to ensure mud is conditioned prior to RIH • Do not circulate in the middle of the HRZ, can increase possibility of packoffs • Monitor SOW while RIH, circulate BU if needed 17.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 17.7 Lower string to depth. MU hanger and landing joint. Casing will be set on depth with hanger. 17.8 Circulation and condition mud for cement job through CRT. Reduce YP to <20 to help ensure success of cement job. Slowly stage up pump rates, if possible, in 15 min increments .25-.5 bpm at a time. 17.9 After circulating, set string at setting depth. 7" Casing Torque Values Connection MUT (Min) MUT (Opt) MUT (Max) Max Operating ft -lb ft -lb ft -Ib Torque, ft -lb TXP 13,280 14,750 16,230 20,000 ;: [,^itJEC 71C DATA Milne Point Unit L-55 Cannect,on OD 7.6% in Drilling Procedure 10200 in. Hilcorp 8284 in. (fake -up Loss CON in. Threads per in 5 Connecean OD option REGULAR I PERFORMANCE Tension Ef icivicy 100.0% Jon Yield Strength 004.000 xI00U karnal PressureCapecity"I 7240.000 psi TXP® BTC lbs ,,,..-05709/2018 Compression Efte^cy Outside Diameter 7.000 in Nin. Wall 87,5% 52 VIGOR lbs Thickness (y Grade LBO Iwo Type I Wall Thickness 0 362 in. Connection OD REGULAR Option C011Pl1NO PIPE BODY Body: Red 1st Band: Red Grade LBO Type 1' Drift API Standard 1st Band: Brown 2nd Band: 2nd Band: - am" Type Cos" 3rd Band: - 3rd Band: - 4th Band: - 7 i GEOMETRY Nominal OD 7.000 in. Nominal Weight 261bs`H Rift 6.151 in, Nominal ID 6276 in. Wall Thickness 0.362 in. Plater End Weight 25.60InA OD Tderarw AN PERFORMANCE 6.4 Yield SOengih 604 x7000lbs Internal Meld 7240 poi BUYS 90000 psi Collapse 5410 psi ;: [,^itJEC 71C DATA GEOMETRY Cannect,on OD 7.6% in Coupling LerxA 10200 in. Contraction ID 8284 in. (fake -up Loss CON in. Threads per in 5 Connecean OD option REGULAR I PERFORMANCE Tension Ef icivicy 100.0% Jon Yield Strength 004.000 xI00U karnal PressureCapecity"I 7240.000 psi lbs Compression Efte^cy 100% Compression Strergh 604A00x1000 Max.Aebwable Bening 52 VIGOR lbs Edernal pressure Capacity 5410.000 psi MAKE-UP TORQUES I kfmimum 13280 ft -lbs Cpmrxen 147308-Ibs Ma'anwn 10230 R -Es OPERATION IJMIT TORQUES Oferating Tttque 20000 Gabs Yield Ton}se 23400 6 -lbs Notes Tttis connection is fully interchangeable With: TXP& BTC - 7 in. - 23129 / 32135 / 38 IbsFR Page 32 Version 1 August 2018 H Hilcorp 18.0 18.1 18.2 Milne Point Unit L-55 Drilling Procedure Cement 7" Intermediate Casing 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. • How to handle cement returns at surface, regardless of how unlikely it • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cement operation. • Extra hands in the pits to strap during the cement job to identify any losses • Document efficiency of all possible displacement pumps prior to cement job. 7" cement job will be a single stage, single slurry job. 18.3 RU Cement lines to cement swivel on CRT. Plugs will be dropped manually. 18.4 Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. 18.5 Pump remaining 40 bbls 10.5 ppg spacer. 18.6 Drop bottom plug, Mix and pump slurry per below calculations, 40% OH excess volume: Section: Calculation: VolVol (ft3) 9.875" OH x 7" Casing: (11,252'— 10,752') x 0.0471 bpf x 1.4 = 33 185.3 7" Shoe Track: 80' x .038 bpf = 3 16.8 Total Volume: 36 202 Slurry Information 18.7 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: 11,172' x .038 bpf= 424.5 bbls Page 33 Version I August 2018 Cement Slurry System ExpandaCem Density 15.8 lb/gal Yield 1.16 ft3/sk , Mixed Water 4.972 gal/sk 18.7 After pumping cement, drop top plug and displace cement with drilling mud. Use rig pumps for displacement. Ensure to have a good baseline measurement for pump displacement ahead of time. Displacement calcs: 11,172' x .038 bpf= 424.5 bbls Page 33 Version I August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure 18.8 Reciprocate casing during cement job. If at any time pipe movement gets sticky, land casing hanger. 18.9 Monitor returns closely while displacing cement. Ensure pits are strapped every 10 bbls of displacement and communicated with Co Rep. If losses are seen, let DSM know and possibly reduce pump rate. 18.10 Do not over displace by more than'/2 shoe track volume. Total volume in shoe track is 3.5 bbls 18.11 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. If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. 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 • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the successor problems during the cement job Send final "As -Run" casing tally & casing and cement report to ienQel( hilcorp.com and ediner@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.12 R/D cementing equipment. Flush out wellhead with FW. 18.13 Test void to 250/4000 psi for 10 min. 18.14 Freeze protect 9-5/8" x 7" Annulus 18.15 Lay down 5" DP. Page 34 Version 1 August 2018 H Hilcorp U, �,m, 19.0 19.1 Milne Point Unit L-55 Drilling Procedure Drill 6-1/8" Production Hole Section Change upper pipe rams back to 2-7/8" x 5" VBR. Test to 250/4000. Chart Test 19.2 P/U 6-1/8" RSS 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. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. • Workstring will be 4" 14# S-135 HT -38 /XT 39 • Run x2 Solid Plunger Floats for MPD 19.3 6-1/8" hole mud program summary: • Density: Although Kalubik / Kuparuk D pressures are predicted to be normal, past wells in this fault block have seen higher pressure. 11.5 ppg with MPD will be used as a precaution. 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. • 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: Ensure 6 rpm is >6.125 (hole diameter) for sufficient hole cleaning, YP as low as possible • Inhibition: 3% KCl will be used for inhibition. Watch MBT levels, dilute as necessary to maintain. Increase KCl % if needed • Run the centrifuge continuously while drilling the production hole, this will help with solids removal and minimize sand content and LGS to maintain fluid properties and quality of the mud system. • PVT will be used throughout the drilling phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 11.5 — 12.5ppg 3% KCl Inhibited LSND WBM Properties: Section Densi Viscosity Plastic Viscosity Yield Point Total Solids MBT H 6-1/8" kj 11.5-12.5 75-175 15-25 15-25 <10% < \_J Page 35 Version 1 August 2018 n Hilcorp �,m, Milne Point Unit L-55 Drilling Procedure 19.4 TIH w/ 6-1/8" directional assembly on 4" DP to above TOC. Shallow test MWD and LWD on trip in. 19.5 Note depth of TOC on morning report. Circulate bottoms up. 19.6 R/U and test casing to 3650 psi / 30 min. Ensure to record volume /pressure and plot on FIT graph. AOGCC regulation is 50% of burst. 19.7 Ensure even 11.5ppg MW in and out before drilling shoe track 19.8 Drill out shoe track and 20' of new formation. 19.9 CBU and condition mud for FIT. ./ 19.10 Conduct FIT to 14.0 ppg EMW. 19.11 Install MPD Element Ensure rig crew is familiar with MPD connection operations Ensure max pressure relief settings are set correction to ensure no wellbore damage is created 19.12 Drill 6-1/8" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 150-250 gpm (Target 200 ft/min AV) • RPM: 120 — for hole cleaning • WOB as needed •_ Target ECD and CBHP: 12.5 —13.0 ppg EMW (This will be determined by formation fingerprint of Lower Kalubik) • Utilize MPD to maintain CBHP (constant bottom hole pressure) on connections, following Annular pressure ramp schedule • This will reduce the pumps on/ pumps off pressure cycles on shales • Slow ramp pumps on/off on each connection • Smooth connections are more important that connection time • Take MWD surveys every stand drilled. • Once drilled into the Lower Kalubik, perform a buildup test to determine formation pressure and required CBHP. 11 • Kuparuk PP range estimate is 10.3 ppg. 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. • Watch for fluid losses while drilling through Kuparuk. 19.13 At TD; CBU at least 3 times at maximum circulation and rotation • Circulate at full drill rate (150-250 gpm). • Rotate at maximum rpm that can be sustained, target 120 • Perform short trip to 7" shoe if needed after CBU cycles are complete Page 36 Version 1 August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure 19.14 Observe well for flow, weight up to 12.5 ppg (this will be determined by formation fingerprint of Lower Kalubik and by connection monitoring while drilling this hole section) 19.15 TOOH with the drilling assembly t/ 7" Shoe, Offsetting Swab with MPD • Follow tripping schedule, matching string speed and annular pressure • Rack back DP while TOOH, Do not lay down drill pipe. This is to minimize open hole time before liner is on bottom. 19.16 If backreaming is necessary: • Circulate at max rate while maintaining drilling ECD's • Perform CBHP connections • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 19.17 CBU at 7" Shoe 19.18 Continue TOOH to HWDP/ BHA, offsetting swab with MPD • Once inside casing, drop rabbit on remaining drillpipe on TOOH that will be used to run the 4.5" liner. Confirm diameter drift with Baker for setting liner hanger 19.19 Pull RCD Bearing element at HWDP 19.20 L/D 6-1/8" BHA 19.21 No additional logs are planned for the 6-1/8" hole section. Page 37 Version I August 2018 H Hilcorp 20.0 20.1 20.2 Run 4-1/2" Liner Ensure rams have been tested on 4-1/2" test joint prior to running liner. Ensure wear bushing is installed in wellhead. 20.3 R/U 4-1/2" casing running equipment. • Ensure 4-1/2" TXP crossover is on rig floor and M/U to FOSV. Milne Point Unit L-55 Drilling Procedure • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints 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. 20.4 Run 4-1/2" liner per completion tally. • Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Run 1 centralizer per joint for the entire liner 4-1/2" Tenaris TXP Make Up Torques Casing OD Minimum Optimum Maximum 4.5" 5,550 ft -lbs 6,170 ft -lbs 6,790 ft -lbs 4-1/2" Tenaris TXP Operating Limit Torques Casing OD Operating Yield 4.5" 6,790 ft -lbs 8,890 ft -lbs Page 38 Version 1 August 2018 Milne Point Unit L-55 Drilling Procedure H ao..a—1 TXPO BTC .,., -.0810312019 Outside Diameter 4.500 in. Min. Wall 87.54 Thickness (') Grade L80 low Tension Elfrciecticy 100.04 Jumt Yield Strength 266.000x100) kgvnal Pressure Capacity Ili 8430.000 psi Type 1 Wall Thickness 0271 in. Connection OD REGULAR 288.000 x1000 Max. Almable Berang at -100 8 Option COUPLING PIPE BODY Body: Red tot Band: Red Grade L80 Type V Drift API Standard 1 st Bates: Brown 2nd Band: 2nd Band:- Brown Type Casing Std Band: - 3rd Band: - 4th Band :- i PIPE BODY CAT.: GEOMETRY Nominal OD 4.500 in. Nominal Weight 1261brl Dah 3.833, Notrinal ID 1958 in. Wal Thickness 0271 in. Plan End Vill 1225 tsRt OD Td.i API PERFORMANCE Body Yield Strength 288.1000lbs Intemu Yield 8430 psi SMYS 80000 psi Collapse 750D psi CONNECTION DATA GEOMETRY Connection OD 5.000 tn. Coiling Length 6.075 in. Connection ID 3945 n Make-up Loss 4.016 in Threads perp 5 Connection OD Open REGULAR PERFORMANCE Tension Elfrciecticy 100.04 Jumt Yield Strength 266.000x100) kgvnal Pressure Capacity Ili 8430.000 psi Ills Compression EKiciency 100% Compression SOerglh 288.000 x1000 Max. Almable Berang at -100 8 lbs External Pressure Capacity 7500.000 psi L MAKE-UP TORQUES Minimum 55508-ts Optimum 6170 ft4bs Marrrrun 6790 fit OPERATION LIMIT TORQUES Operating Toque 67908x8 Yield Terga 820064bs Notes This connection is fully interchangeable with: TX?® BTC - 4.5 in. - 10.5 111-6 113.5 / 15.1 ItI Page 39 Version 1 August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure 20.5 Ensure to run enough liner to provide for approx 150' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection and the packer should be above the 7" float collar. 20.6 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 20.7 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packof. . Wait 30 min for mixture to set up. 20.8 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 20.9 RIH w/ liner on DP no faster than 1-2 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 20.10 Fill DP with Top drive every 10 stands or as appropriate. Slotted liner should fill while RIH. 20.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every 5 stands. Record torque value if it becomes necessary to rotate the string to bottom. 20.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 20.13 RIH to TD as per running schedule. Monitor run for losses. Page 40 Version 1 August 2018 n Hilcorp E� Cm, 21.0 21.1 Milne Point Unit L-55 Drilling Procedure Cement 4-1/2" Production Liner Circulate and condition mud for cement job Break circulation slowly and stage up rate with reciprocation. Rotate DP slowly if hole condition allows, not exceed max torque or 20 rpms Circulate minimum 3 liner annular volumes to condition hole and mud for cementjob 21.2 Hold pre job safety meeting over upcoming liner cementing operations. Make room in pits for volume gained during cement job. Ensure adequate displacement volume is available. • Cement returns are not expected to surface, but may be seen after setting liner hanger and circulating, discuss how to hand returns if they are seen • Discuss pumps for displacement • Positions and expectations of all personnel involved in cement operations, have one hand in the pits specifically for strapping pits and recording volume returned. 21.3 4-1/2" Liner cement job will be a single stage. 21.4 RU cement head and cementing lines 21.5 Pump 5 bbls fresh water. Pressure test surface cement lines to 4000 psi. 21.6 Pump 60 bbls of 13.5 ppg spacer 21.7 Pump 15.8 ppg Class G Single Stage Slurry as per below calculations, 40% OH Excess: • The entire liner and liner lap is planned to be cemented Ensure cement slurry thickening time accounts for 30 min shutdown time for setting and releasing from liner hanger / packer. And compressive strength sufficient for perforation. Section: Calculation Vol (bbls) Vol ft3 6-1/8" OH x 4.5" Liner: (12,291' — 11252') x.0167 b f X 1.4 — 24.3 136.4 7" x 4.5" Liner 150' x.0 186 6 f — 2.8 15.7 4.5" Shoe Track 40' x .0143 b f — 1.7 9.5 Total Volume 28.8 161.5 21.8 Drop liner wiper plug and displace with drilling mud. Target max displacement rates to not exceed drilling ECDs Slow pumps enough to check for liner wiper plug shear release 21.9 Continue displacing cement until liner wiper plug bumps, or displacement volume has been pump. Pressure up over 1000psi to verify plug has bumped. Page 41 Version 1 August 2018 Cement Slurry System ExpandaCem Density 15.8 ppg Yield 1.16 ft3/sk Mixed Water 4.95 gaUsk 21.8 Drop liner wiper plug and displace with drilling mud. Target max displacement rates to not exceed drilling ECDs Slow pumps enough to check for liner wiper plug shear release 21.9 Continue displacing cement until liner wiper plug bumps, or displacement volume has been pump. Pressure up over 1000psi to verify plug has bumped. Page 41 Version 1 August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure If plug does not bump, do not set the liner top packer, as string will be unsupported by an unset liner hanger. Discuss with Baker Rep. 21.10 Increase drill pipe pressure to set liner hanger, — 2700psi. Slack off to ensure liner hanger is set. 21.11 Increase pressure to release running tool from liner hanger. Pressure up in 500 psi increments holding for 5 min each up to 4000 psi until indication that running tool has released. 21.12 Pickup to expose rotating dog sub, set down on liner and set ZXP liner top packer. 21.13 With packoff on running tool still engaged, bleed DP pressure to zero, close BOP and test 7" x 4" annulus to 3000 psi for 30 min and chart record same. Rotate and set down, if necessary to ensure liner packer is set. Bleed off pressure and open BOPE. 21.14 Pressure up t/ 500 psi, pickup 2-3' to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 21.15 Pick up above liner top. 21.16 CBU x 2, to clean up wellbore and check for any cement returns to surface or above liner top 21.17 POOH, L/D 4" DP and inspect running tools. 21.18 L/D remaining 4" DP out of derrick. 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 • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns duringjob, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the successor problems during the cement job Send final "As -Run" casing taljy & casing and cement report to jen el hilcorp com pchan ,hilcorp com• and cdin e�rghilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 42 Version 1 August 2018 H Hilcorp 22.0 Perform 4-1/2" Cleanout Run & Displacement Milne Point Unit L-55 Drilling Procedure 22.1 If well conditions warrant, a clean out run will be performed prior to running completion tubing 22.2 M/U casing clean out assembly complete with casing scraper assemblies for each size casing in the hole. • 4" x 2-7/8" DP Tapered String • Casing scraper for 7" 26# casing • Casing Scraper & Bit for 4-1/2" Liner 22.3 TIH & clean out well to PBTD, confirm depth with completion engineer • Circulate as needed on trip in if string begins to take weight. • Watch as cleanout string enters liner top • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. 22.4 PT 4-1/2" Liner to 4000 psi f/ 30 min. Chart test. 22.5 Displace well to 10.3ppg 2% KCl NaCl completion brine • Confirm completion fluid with completion engineer and reservoir pressure 22.6 TOOH w/ clean out assembly. Lay down drill pipe on the trip out. Note any abnormal wear on the clean out assy. Page 43 Version 1 August 2018 H Hilcorp 23.0 Run 4-1/2" Frac String Milne Point Unit L-55 Drilling Procedure 23.1 R/U and run 4-1/2" 12.6# L-80 TXP frac string assembly, including nipple profile, production packer and WLEG. • Ensure appropriate well control crossovers on rig floor and ready. 23.2 Makeup the tubing hanger and landing joint. 23.3 Land hanger. RILDs and test hanger (500/5000 psi). Make note of actual weight on hanger on morning rpt. 23.4 Freeze protect IA and Tubing. 23.5 Drop ball and rod and set packer 23.6 Test the tubing to 3500 psi for 30 minutes. Monitor tubing to identify any packer leaks. Record and note all pressure tests on chart. —F—r - L, 23.7 Bullhead diesel freeze protect down 9-5/8" x 7" annulus if not already done so. Do not allow flow back. 23.8 Install BPV 23.9 ND BOPE 23.10 NU Tree & Pressure test to 5000 psi. 23.11 RDMO Doyon 14 A separate sundry will be submitted for hydraulic fracture stimulation and completion operations. Page 44 Version 1 August 2018 H Hilcorp 24.0 Doyon 14 Diverter Schematic Milne Point Unit L-55 Drilling Procedure Page 45 Version 1 August 2018 H Hilcorp 25.0 Doyon 14 BOP Schematic Typical Ram Configuration IW Late—�� Milne Point Unit L-55 Drilling Procedure 2-7/8" x 5" VBR Blind Rams x 5%1 HCR Koko Loo al Gate Valle 2-7/8" x 5" VBR Page 46 Version 1 August 2018 Hileorp �Qwik 26.0 Wellhead Schematic FMC Gen 5 Typical Milne Point Unit L-55 Drilling Procedure_ Page 47 Version 1 August 2018 i1 J_ftF IrI.ILOOMO,)l I I Page 47 Version 1 August 2018 Milne Point Unit L-55 Drilling Procedure H 27.0 Days Vs Depth 0 2000 4000 s 6000 a v 0 v m 8000 v 10000 12000 14000 0 5 MPU L-55 Kuparuk A Producer Days vs Depth 10 15 Days 20 25 30 Page 48 Version 1 August 2018 H Hilcorp Imp Comm 28.0 Formation Tops & Information Milne Point Unit L-55 Drilling Procedure MPU L-55 Formations (wp14) MD (ft) TVDss (ft) TVD (ft) Formation Pressure (psi) EMW (ppg) Ugnu 3641 2398 2448 1101.6 8.65 Schrader Bluff NB 7017 4096 4145 1865.25 8.65 Schrader Bluff OA 7286 4231 4281 1926.45 8.65 Colville 8281 4732 4782 2151.9 8.65 HRZ 11254 6689 6739 3032.55 8.65 Kalubik 11393 6820 6869 3091.05 8.65 Kup D 11540 6957 7007 3783.78 10.38 Kup C h 11595 7010 7059 3811.86 10.38 Kup A 11670 7080 7129 3849.66 10.38 MPU L Pad Data Sheet normal normal normal normal normal normal high high high GENERALIZED GEOLOGICAL FORECAST SS GEOLOGICAL TVD FM LITH DESCRIPTION COMMENTS al seal. NOTE: See individual Well Program for °ole"a',ro Gue1 s,ecfic casing design. depths, sizes, weights, grades and connections. Y unconsolidated coarse to medium sand and small gravel Ewith minor smatone. IF SIGNIFICANT AMOUNTS OF GRAVEL 1,000' n ARE ENCOUNTERED WHEN DRILLING THE .— SURFACE HOLE, THE VISCOSITY OF THE MUD SYSTEM SHOULD IMMEDIATELY BE RAISED TO 150 SEC TO ENSURE EFFECTIVE HOLE CLEANING. 1750• Base permafrost Interstate of sane, clays and s4tsones wife occasional 2,000' Show of coal. Watch possible sidetracking while wasaIngneeming. w3 s L-tS Sagava iffirta -alloil. No hydrates MeourderBd on L -Pad wells drilled to date. Continued tnlenods of sand. clays and.ifalon.s wlln weloml shewa al coal. Tracea brindle at H- 3100 h 3,000' Interval at 11 34110 a oars he addky and 11ghl(L-DI) Clay Intersects between 31100 and 4500 M. C 3472'. L 3657 A Ksaw UGNU: Sed. of eeasenmg upward sands which are IABCA mode up of peom top to bonoml coarse Sana. rine sand. My aisle_ Seller developed Intervening Shalee ea you UGNU progress into the Land M (deeper). and Schrader Bluff: Possible hydrocarbons limited Lomas to to SW darnel of Milne development. Northam site is pASI downetrudureandwel. '3139' Maanas fA6t) •a00o• (NA) Schrader Bluff Sands: 4,000' Nita it's IABc.o, continued layering comaerm, upward sa.Caeaabove ♦M Schrader Bluff: Possible lost circulation Cn except more condensed and was occasional coni. zone while drilling long strings and running '4170• osanm Clay rich shale Intemal 4300 to aide n. Ugnu and Schrader Bluff: Possible hydrocarbons limited casing. Recommend deep setting surface (0A) pAe.C. 1. SW comer cal Milne development W) and L45 era casing for Kuparuk long strings. Also, the DAY, completed In Ne Schrader Bluff send. Northam area of Schrader sands are potential Schrader L -Pad is downstrucmre and wet_ r differential stuck pipe interval if idle un -cased Bluff C barked wing point In Made below for Kuparuk long strings. Sands' Sduade, Sluff OB and for longerrasdh wells. L Page 49 Version 1 August 2018 n Hilcorp •4290' op of Seabee (Colville) Interval: Seabell Y Predominantly interbedded sillstone and clay with beds of sand, shale and occasional seams of coal. The Seabee Is generally uneventful until reaching the HRZ- Expect good penetration rates. Seabee: Continuous clay section from 5900 to i'mo. 6500 It (LUII. Periodic traces of calcite and 10 10 20 % dolomite @ 1- 6700 h (depths for SW 1997 L -Pad wells Is shallower). a100 - A2 -7132- Al Page 50 TKA1 & TKA2: Similar to TKA3. Version I Milne Point Unit L-55 Drilling Procedure LOST f BACK RETURNS 2NBREA THING WHILE DRILLING 1 LONG STRINGS): L, L-08, L-24, AL -36. IL -35A: AVOID SIDETRACKING IN THE __1KALUBIK. L43PBl: 12.0 PPG EN STUCK PIPE INTERVAL!! "D" CAP POSSIBLE OVER -PRESSURE IF DRILLING IN TRACT 22 NEAR THE KRU 30 -PAD OR NEAR ✓ INJECTION WELLS. L-20 and L-32 both required 13.3 ppg mud weight. L-34.-35 and -37 required 11.4. 11.3 and 11.0 ppg mud weights respectively. L-39 (the furthest from KRU 30 Pad required a 10.8 ppg mud wt. LOST RETURNS AND BREATHING BACK WHILE RUNNING, CIRCULATING AND CEMENTING PRODUCTION CASING (MOSTLY 7" LONG STRINGS): L-13, L-11, L-12, L-14, L-15, L-17, L-29, L-25, L-21, L-34, L-33, L-39, AND L-02. August 2018 C6,000' L UNCONFORMITY: Unconformbyatmetapof A the HRZ. Erodes as deep as the Kuparuk B send in some places at L -Ped. •6560' TOP HRZ Y HRZ: Highly Radioactive Zone. Very dark. fissile type HRZ shale. organic, good source rock. HRZ may be truncated out Ia central potion of L -Pad and not present in all wells. '6630' ase H Kalubik Stlale: Good log marker MK19 In the Kalublk (6705 In L-01, 6900 In L-25 and 6270 In L-36)- Kalubi k Uncontormity erodes Kalublk amt Kuparuk D intervals in northern L -Pad sea. T191 "V `(berdwi icl zone possi Neat top of HRZ. Slits within lower Kalubik and Kuparuk "D" •6860' can become over -pressured due to high Injection pressures Into the Kuparuk sands. "D" Shale Kuparuk Interval: The "D" Shale Is the top Kuparuk sediment and '6980' ^ C Is known as the -Cap Rock-. KUPARUK OVERPRESSURE MAY OCCUR IN THE D -SHALE. 76000• LC Kuparuk "C": Sandstone, shales upward, Kuparuk oil bearing target. Very thin sand at L -Pad (4 to 14 R). LCU: Lower Cretaceous Unc"formny B Kuparuk B: Also known as the Laminated Zone, begins below LCU. fine to medium grain sands becoming more shaley with depth. Hydrocarbon bearing. •7050' A3 TKA3: Pine grain sandstone, coarsening upward, relatively low permeatillity. 15-18% porosity. 10 to 100 and permeability. Hydrocarbon bearing. The Kuparuk Al, A2 and A3 are the major production Intervals at L -Pad. a100 - A2 -7132- Al Page 50 TKA1 & TKA2: Similar to TKA3. Version I Milne Point Unit L-55 Drilling Procedure LOST f BACK RETURNS 2NBREA THING WHILE DRILLING 1 LONG STRINGS): L, L-08, L-24, AL -36. IL -35A: AVOID SIDETRACKING IN THE __1KALUBIK. L43PBl: 12.0 PPG EN STUCK PIPE INTERVAL!! "D" CAP POSSIBLE OVER -PRESSURE IF DRILLING IN TRACT 22 NEAR THE KRU 30 -PAD OR NEAR ✓ INJECTION WELLS. L-20 and L-32 both required 13.3 ppg mud weight. L-34.-35 and -37 required 11.4. 11.3 and 11.0 ppg mud weights respectively. L-39 (the furthest from KRU 30 Pad required a 10.8 ppg mud wt. LOST RETURNS AND BREATHING BACK WHILE RUNNING, CIRCULATING AND CEMENTING PRODUCTION CASING (MOSTLY 7" LONG STRINGS): L-13, L-11, L-12, L-14, L-15, L-17, L-29, L-25, L-21, L-34, L-33, L-39, AND L-02. August 2018 n Hilcorp �tll ConPmY 29.0 Anticipated Drilling Hazards Surface Hole Section: Lost Circulation Milne Point Unit L-55 Drilling Procedure Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section efficiently — control ROP and avoid loading the hole with gas. Minimize gas belching by reducing flow rate if necessary. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of adjacent wells in the vicinity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: No 142S events have been documented on drill wells on this pad. Treat every hole section as though it has the potential for H2S. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. Page 51 Version 1 August 2018 H Hilcorp EmV CmoVmY Milne Point Unit L-55 Drilling Procedure 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 52 Version 1 August 2018 H Hilcorp m.vcmw Intermediate & Production Hole Sections: Milne Point Unit L-55 Drilling Procedure Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate with AV of 200 ft/min. Lost Circulation: Lost circulation has been seen in the Colville formation at EMW exceeding — 12.0 ppg. Monitor ECDs during production section to ensure ECDs stay below 12.0. 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. Abnormal Pressures and Temperatures: % Although Kuparuk reservoir pressure is predicted to be normal (.45 psi/ft TVD), a past well in this fault block encountered trapped injection pressure in the Kuparuk D. This is the reason for the 7" top set depth and high 12.5 ppg production hole mud weight. Wellbore Stability: This well will drill through historically trouble shales, HRZ & Kalubik. Maintain sufficient MW for stability and utilize MPD to maintain constant bottom hole pressure to mitigate on/off pressure cycles. Use MPD to offset swab effect while TOOH. Follow tripping in hole schedule to manage surge pressures on shales. Anti -Collision: This well has no close approaches on the planned wellpath. Monitor MWD survey for magnetic interference while drilling ahead. Faulting: There are no known faults in either hole section. H2S: Treat every hole section as though it has the potential for 1-12S. No 112S events have been documented i on drill wells on "L" pad. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 53 Version 1 August 2018 H Hilcorp 30.0 Doyon 14 Layout Milne Point Unit L-55 Drilling Procedure i Page 54 Version 1 August 2018 Milne Point Unit L-55 Drilling Procedure Hilcorp � C_' 31.0 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 55 Version 1 August 2018 H Hilcorp 32.0 Doyon 14 Choke Manifold Schematic Milne Point Unit L-55 Drilling Procedure Page 56 Version 1 August 2018 H Hilcorp 33.0 Casing Design Information 11 Calculation & Casing Design Factors Hilcorp Milne Point Unit DATE: 8.30.2018 WELL: MPU L55 DESIGN BY: Joe Engel Criteria: Hole Size 12-1/4" Hole Size 8-1/2" x 9.875" Hole Size 6-1/8" Mud Density: 9.2 Mud Density: 10.8 Mud Density: 11.5 Drilling Mode MASP(8.5" x 9.875"): 2358 psi (see attached MASP determination & calculation) Production Mode MASP: 3394 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2, 3 Max MW gradient external stress and the casing evacuated for the internal stress Milne Point Unit L-55 Drilling Procedure Page 57 Version 1 August 2018 Cas ng Section Calculation/Specification 1 2 3 Casing OD 95/8" 7" 4-1/2" Top (MD) 0 0 11,252 Top (TVD) 0 0 6,736 Bottom (MD) 8,000 11,252 12,291 Bottom (TVD) 4,640 6,736 7,713 Length 8,000 • 11,252 - 1,039 - Weight (ppf) 40 1 26 12.6 Grade L-80 L-80 L-80 Connection TXP TXP TXP Weight w/o Bouyancy Factor (Ibs) 320,000 292,552 13,091 Tension at Top of Section (Ibs) 320,000 292,552 13,091 Min strength Tension (1000 Ibs) 916 6D4 288 Worst Case Safety Factor (Tension) 2.86 --Y—o6, 22.00 Collapse Pressure at bottom (Psi) 2,320 3,368 3,934 Collapse Resistance w/o tension (Psi) 3,090 1 5,410 7,500 Worst Case Safety Factor (Collapse) 1.33 1.61 1.91 MASP (psi) 1,624 2,358 3,394 Minimum Yield (psi) 5,750 7,240 8,430 Worst case safety factor (Burst) 3.54 3.07 2.48 Page 57 Version 1 August 2018 R Hilcorp 34.0 8-1/2" x 9.875" Hole Section MASP Milne Point Unit L-55 Drilling Procedure Maximum Anticipated Surface Pressure Calculation Hilcorp 8-1/2" x 9.875" Intermediate Hole Section ��, MPU L-55 Milne Point MD TVD Planned Top: 8000 4640 Planned TD: 11252 6736 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Kalubik 6,860 3087 8.7 0.450 Offset Well Mud Densities Well MW Range Top (TVD) Bottom (TVD) Date L-43 9.3-9.8 439 6,745 2004 Assumptions: 1. Fracture gradient at shoe is estimated at 0.7 psi / ft based on field test data. 2. Maximum planned mud density for the 8-1/2" x 9.875" hole section is 11.0 ppg. 3. Calculations assume Kuparuk reservior contains 100% gas (worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 9-5/8" Shoe 8000' MD / 4640' TVD 4640 (ft) x 0. 7(ps i/ft) = 3248 psi 3248 (psi) - [0.1(psi/ft)*4640(ft)]= F 2784 psi Drilling Mode MASP MASP from pore pressure (wellbore completely evacuated to gas) 6736(ft) x 0.45(psi/ft)= 3031 psi 3031(psi)-[0.1(psi/ft)*6736(ft)]= 2357.6 psi Summary: 1. MASP while drilling Intermediate hole is governed by the wellbore completely evacuated togas from the Kuparuk Reservior Page 58 Version 1 August 2018 H Hilcorp Milne Point Unit L-55 Drilling Procedure 35.0 6-1/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 6.125" Production Hole Section Hilco �m �,rp MPU L-55 � Milne Point MD TVD Planned Top: 11252 6736 Planned TD: 12291 7713 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Kuparuk D 7,007 3783 10.4 0.54 KuparukC 7,059 3812 Oil10.4 # 0.54 KuparukA 7,129 3850 Oil 10.4 0.54 Offset Well Mud Densities Well MW Top (TVD) Bottom (TVD) Date L-43 12.5-12.6 6,745 7,483 2004 Assumptions: 1. Fracture gradient at shoe is estimated at 0.7 psi /ft based on field test data. 2. Maximum planned mud densityforthe 6-1/8" hole section is 12.5 ppg. 3. Calculations assume the Kuparuk reservior contains 100% gas (worst case). 4. Calculations assume worst case event is complete evacuation of wellbore togas. Fracture Pressure at 7" shoe considering a full column of gas from shoe to surface: 6736 (ft) x 0.7(psi/ft)= 4715 psi 4715 (psi) - [0.1(psi/ft)*6736(ft))= 4042 psi Drilling Mode MASP MASP from pore pressure (wellbore completely evacuated togas) 7713(ft) x 0.54(psi/ft)= 4165 psi 4165(psi)-[0.1(psi/ft)*7713(ft))= 3394 psi Summary: 1. MASP while drilling 6-1/8" Intermediate hole is governed by wellbore completely evacuated togas from the Kuparuk. Page 59 Version 1 August 2018 Milne Point Unit L-55 Drilling Procedure Hilcorp � O -Nn. 36.0 Spider Plot (NAD 27) (Governmental Sections) I / 0 U014NOt0E r' ' ADL355018 i' / I s" 32/ ADL755017 / Se:_3E L7PX Sec. 31, ' I � Ill 1622) fi o /d , G 5. ° Y A01.047414 11 11 y f o 1 11 I 1 e° se,.S `(625) ; ' r ' MILNE'oPOINT UNIT 1 rl le i ADL025509 /loll 10 .UOi1N010 ` 1 �I 1 I I ♦ I Legend • MPU L35 -SHL Tec.9 1\\\ X MPU L-55_TPH �Sev. l• •��• L { 11 \+•/. ,/ / SeMPU L-55 i628; . 0 Other Surf&e Fides (SHL) \ MPU L SHL Other Boflan Holes (BHL) _--OUa ME]Pains OOa and Gas Unn Boundary t 1 -a _ '.LI [_� Pad FooNerll Milne Point Unit (x) e �..". MPL-55 Well 0 500 1,000 1,500 7 wp14 oFeet Page 60 Version 1 August 2018 Milne Point Unit L-55 Drilling Procedure n B rp=, 37.0 Surface Plat (As Built) (NAD 27) I I I I i I a / I i / u '31 I a i■24 ■25 J1. /■20 •21 L-45 (ABAAOONW) ■IB ■17 SEE■43+L-5513 ■ 39■ L—PAD 111 1435 ■ 2 ■ ,2 40 ■ ■■■■■■■■■■5 35 4 30 5 07 11 5Ol GRAPHIC SCALE a 100 200 400 IN FEET ) and - 200 & ]5 ]I 32 J] I I ] I T114N I- I I s i • I :5� I I L -PAD 7 i t PRD.IECT G.. +e I IT 1e I I ,9 29 :, VICINITY MAP ALTS SURVEYOR'S CERTIFICATE I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED ANO LICENSED TO PRACTICE LAND SURVEYING IN INE STATE OF AUS A AND NAT NIS AS -BUILT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT NOTES; SUPERVISION AND NAY ALL DIMENSIONS AND OVER DETAILS ARE I. AU9(A STATE PLANE COORDINATES ARE ZONE 4. NAD27. CORRECT AS OF .NNE 30.201& 2. BARS OF LOGTION IS L -PAD MCNUMENTS L -I WORTH A.S.P.PLANT AND L-2 SU11H. GEODETIC 3. F VATON ARE MEAN SEA tEV?L CELLAR 4. GEONYC POSITONS ARE NAD27. I FGENQ 5. PAD MEAN SCALE FACTOR IS 0.9999020 COORDINATES S. DATE OF SURVEY: ,UNE 1. 2015 a A1NE 30. ZOM + AE -BUILT CONDUCTOR T RFSERENCE FIELD B00N: NCIB-02 PFS. 30-]2 . EMSDNG CONDUCTOR HCIB-02 PG, W ABANDONED CCNDVCTOR B. KILL CONDUCTOR NPL -45 PLUGGED AND ABANDONED 70.29'51.886" BELOW TUNDRA MAX. POSITION WAS APPRO%MATELY SFT NCRTN OF NEW WELL CONDUCTOR APL -50. L-55 LOCATED WITHIN PROTRACTED SEC. S. T. 13 N.. R. 10 E.. UMIAT MERIDIAN. AN. WELL A.S.P.PLANT GEODETIC GEODETIC CELLAR SECTION NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D_00) BOX ELEV. OFFSETS Y=6.0.31,799.64114=1.524.94_1 70.29'51.886" 1 70.4977461' 3.610' FSL L-55 X= 544.853.40' E= 1.334.80' 149'37'59.525" 149.6332014' 16 0' 5,024' FEL Hflcorp Alaska MILNE POINT. ALASKA MP L—PAD. WELL L-55 CONDUCTOR AS—BUILT Page 61 Version 7 August 2018 H Hilcorp 38.0 Drill Pipe Information 5" 19.59 S-135 NC -50 Milne Point Unit L-55 Drilling Procedure 500204050016200 Weatherford 5" 19.50 Ib/ft S-135 W/ NC 50 6-5/8" OD x 3.1/4" ID Tool Joint DRILL PIPE SPECIFICATIONS Outside Diameter Grade S-135 Connection NC 50 Interchangeable With 5- XH & 4-1/2' 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 3-118' 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 Loadrfensile Strength 712,000 lbs 560,800 lbs Slip Crushing / 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 galift 0.726 US gaVft Displacement W/ Tool Joint 0.353 US al/ft 0.322 US qalift 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 62 Version 1 August 2018 H Hilcorp emna C, 5" 19.5# S-135 DS -50 w..xov.v,n: Drill Pipe Configuration 1 I JI Pipe Body OD ins 5.000 Plpe Body Wag Tnionness rot 0.302 Pipe Body Grade 5135 Orin Pipe L.VM Ranne2 Connection GPDS50 Tod Jo'saou 0.025 Tad Joint ID imp. 3250 Pm Tap 9 Bar Ton9 Im12 Drill Pipe Performance Lw,+ --143,100 ..mem 36,100 Connection Performance Milne Point Unit L-55 Drilling Procedure Drill Pipe Performance Sheet BD % lnspec5on Cuss Nomnal WeioN tnesip.a 1930 DNI PVe Appmv w Lzr m 31.5 Snrodh HeipM pt 3A2 Rased Tool Joimwys su112t1300 U T JEU 61as U set oD IDT ) Fdd Fada 11.0 •.m Tme-v+v<vrvmur+esusn0 Dnn-Pbe Len(61 Ranae2 of Drib Pipe wth Pipe Body at Best E80me1es RNOftMl%Ins ection Class "°+'f1.1""°°'°'01 Dr1PFe WeyaRub Din lacement 580.80D Ruk Dis lacement pe.n .01n.aa0 10.500 Fu CepadN r 10.71 0.70 Tiono* 05tm 800 03169 03107 Drill Sm. um 3.125 cvnae,mra+a•v 32,100 07,400 :wv+nes �w,a: vnl vve+vswa anv.v vm va•em:s+evm..r..yusmceeewr.,n ue.,ve mumu uv=+naso. aaem+rarx.. GPDs5D ( 6.625 w OD X 3.250 w ID ) 120.D00 m+n Twl Joint Dimensions Balarlcetl W in) 8.43.5 wm. c�.uercoo u.,vllnt 5.930 unmv.v.m+an:wb 5.93 C+rnurwrt Int Elevator Shoulder Information Boa 00 ElevDCa0acilY i.,mi Assumed ElevaW Bore Diamete Pipe Body Slip Crushing Capacity ®T® AT7 API Premium Clens xovw l+++ :r.e.wn cry +xavp+muu+xey ^..w.t nve. PpeltadycolRpraScn( + 5-1 OD 0.3621m Wall S-135) PiDe Bodv Performance F+ BodyCoftp ( 5 1n OD 0.362" Wall S-135) wz:.ena r:s san GsbrrerCma 04242013 Page 63 Version 1 August 2018 Nominal 80 % inspection Class API Premien Class Pile Teo 3mwffi pat ]12,100 Maw 500,800 Pipe Tomas lBrenna roau 4,100 58.1c0 58,100 TLPgeBody T.RaSo 0.97 1.24 124 e0% Pee TmimA 3aerptll pmst 59300 6C.5W 48,5W Bum mm 17100 15,839 15338 Cdlapse lmu 153]2 13.01E 10.02E Rpe oo r 5300 4.855 4M5 Wa11 'W2 0293 0.29D NomisW RpeID Im 4276 42T6 4.276 Cross 4AM 4154 Cross Sectional Area of OD pnA 19.036 18.514 18.514 Cmsa SettArval Area of iD p•A I4AW 14 a00 14.300 Sed'on Fbdulus nnn 8768 4478 4.4]0 Polar Secec modulus m•v i1.4i5 3[63 9.03 wz:.ena r:s san GsbrrerCma 04242013 Page 63 Version 1 August 2018 H Hilcorp Eiiin mvmr 4" 14# S-135 XT -39 Milne Point Unit L-55 Drilling Procedure Pipe Body Specification Cmnttli % 394975'x256Y(120x51Wni Pi[Oon Factor ID P, 4 0' OD 0330' VA1 T16 .s S 1351 lnipex6an Gass Pipe Body OD In 4A) Pipe Body WallThickness-Nominal Weighs 0.3Win-1416/R Pipe Body Grade 5-135 Drill Pipe Length Range 2 -M. n 32.0 -Min it 31.0 Type or Upset IU Max Upset 00 In 4.188 - Assumed Transverse Load Factor 00 61M 396500 Pipe Body Performance Cmnttli % 394975'x256Y(120x51Wni Pi[Oon Factor ID P, 4 0' OD 0330' VA1 T16 .s S 1351 lnipex6an Gass At Max MUTr222Wft.Ibs) Connection Type and Size At Min MUT (185W ft -lbs) AN Premium 8096 Inspection Clan Burst Pressure • vn 0 4035M 17.800 Collapse Pressurel 069 403400 13,830 Slip Crushing Capadty• lb, 3100 4017(0 30%400 - Assumed Slip Length In 16.5 - Assumed Transverse Load Factor 00 61M 396500 42 Adjusted Weight" R,A 16.73 Fluid Displacement" USgaI,R earn 026 0006t Fluid Capacity •' USgaIM Bash 0.42 0.0101 me,..Iwaswn a,eme-sw.a,....a,u+w rill Pipe Performance Sheet 111111111111111111�11201 Combined Loading for DI ill Pipe Cmnttli % 394975'x256Y(120x51Wni Pi[Oon Factor ID P, 4 0' OD 0330' VA1 T16 .s S 1351 lnipex6an Gass At Max MUTr222Wft.Ibs) Connection Type and Size At Min MUT (185W ft -lbs) Operational Annual Max Torque(ft-lbs) Tensionilbs) Operational Assembly Max Torquerit-lbs) Tensionitbs) 0 4035M 0 403303 1000 403300 069 403400 2000 402000 I.M 403000 3100 4017(0 2900 402400 41M 400,100 3200 401600 Sim 3%il 4000 400500 61M 396500 4900 399000 7100 393900 5700 39)400 aim 391000 6500 395500 9X10 382300 7300 393400 10200 383500 aim 391000 11200 379200 8900 3M300 12200 374500 9700 305400 13300 Wax 10000 382X1 14M 363000 11300 378700 15300 356890 121M 16300 330009 ---r1734( 12900 3426Ar 1380018300 33470019300 3X5009 15400 Tool Joint Specification Max Make -Up Torque (Recommended) O Its Connection Type and Size Min Make -Up Torque XT -39 Benchmark Min TJ Do (API Premium) GPmzrk^ SmoothEdge^Heightperskie In WA Tool Joint SM1'S Pu 1H," Connection OD In 4.875 Connection ID In 2563 Pin Tong Length In 12.0 Box Tong Length In 17.0 Thread Compound Friction Factor 4711 1.0 Tool Joint Performance Max Make -Up Torque (Recommended) O Its 22,200 Min Make -Up Torque ft -Ib, 18,500 Min TJ Do (API Premium) In 4,653 M1nU0Dfor Conmerbore In 4.653 Drift Size 21400 2438 �. ms. w u'w•.. . a..Pol,w.r^..am6. 21000 U500 Advisories and Warnings for Drill Pipe A sones: -o...e,mn.,rvsa>,aw....e4awea..cwa�. ee.aw.>°i�ama.+aasn�sm.ww• Warnalps KOloohnologlel 3 _ Connection Weal Table conredic,X 394875' x 2553'1120 Y [ SMr) Cricxm Fan, o T"IJOnt OD(in) Max MUT(ft-Ibs) Min MUTIFt-Ibs) 4975 22200 18500 Amass 216[(1 10201) 4.035 21400 17900 4,814 21000 U500 4.7W 20200 17100 4774 203M 16900 4754 19900 16600 4711 19500 16300 4714 192M 1(000 4693 18890 1576040) 46Ii 19400 15 4653 16100 15100 Elevator Capacity Blexatar Bore Dbmetee 41817 Beasa 5ray5110,100 Pat em Taper Argue 18 dry Connntcn: x1'•39 4.0.033W we11 W 2135 Tool Joint OD 6n.) Elevator HOW Capa ity(ling Ho Wear 113r Wear factor 4875 469700 4(0 4855 451900 443600 4135 4300 426590 4914 41961)0 409400 4X4 4020Ip 3927W 4,774 3855W 376200 4,714 369000 3597M 4.734 352600 363300 4114 3362M 30000 4.693 319200 3099ap 4673 303000 2937M 4653 AX00 277600 Page 64 Version 1 August 2018 R Hilcorp 4" 14# S-135 HT -38 Milne Point Unit L-55 Drilling Procedure 400204138036211 Weatherford 4" 14.00 Ib/ft Internal Coating S-135 w/ HT 38 4-718" OD x 2-9/16" ID w/ X 7000 Hard Banding Tool Joint DRILL PIPE SPECIFICATIONS Grade S-135 Connection HT 38 Interchangeable With 2-7/16' UpsetType, IU Internal Coating TK 34 XT Nominal Weight per Foot 14.00 lbs Adjusted Weight With Too[ Joint per Foot 15.65 IDs TOOL JOINT DATA Outside Diameter 4.7/8' Inside Diameter 2-9/16' API Drift 2-7/16' Rabbit OD, Suggested 2-3/8' Hard Band X 7000 Minimum Make-up Torque 12,200 ft -lbs Maximum Recommend Make-up Torque 17,700 ft -lbs Torsional Yield Strength 29.500 ft -lbs Tensile Strength 649.200 lbs TUBE DATA New Premium Outside Diameter 4.000' 3.868'___ Inside Diameter 3.340' 3.340' Wall Thickness _ 0.330' 0.264' Cross Sectional Area 3.805 sq In 2.989 sq In Maximum Hook Load/Tensile Strength 513.600 lbs 403.500 lbs __§Ilp Crushing SOXL 431.900 lbs 341,300 IDs Burst Pressure 19.500 psi _ 18,400 psi _ Collapse Pressure _ 20.100 psl _ 13,800 sl Torsional Yield Siren th 41.900 ft -lbs 32 800 ft -lbs Capadty W/ Tool Joint _ 0.442 US a0ft 0.442 US aVft Disylacement W/ Tool Joint _ 0.240 US gauft _ _0.223 US al/R 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 65 Version 1 August 2018 Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-55 MPU L-55 Plan: MPU L-55 wp14 Standard Proposal Report 29 August, 2018 HALLIBURTON Sperry Drilling Services HALLIBURTON 6perrry Drilling Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-55 Wellbore: MPU L-55 Design: MPU L-55 wp14 0 1od" Stan Dir 301100': 300' MD, 300 -TVD Start Dir 40/100': 550'MD, 549.29 51750 Start Dir 50/100': 800'MD, 793.05' - I REFERENCE INFORMATION WELL DETAILS: Plan: MPU L-55 Co-ordinate (NIE) Reference: Well Plan: MPU 1-55. True North Ground Level: 16.00 Vertical (ND) Referenon: MPU L-55 wpll IRKS Q 49.70usflN/-g aE/_W Northing Eaeting LetiButle Longitude Measured Depth Reference: MPU L55 wp11 RKB @49.70usfl .00 0.00 6031799.64 544853.40 70'29'51,886 N 149'3r 59.525 W g Entl Dir : 1661.57' MD, 1451.92' TVD 1500 k 0 BPRF o0 4 2250 SV7 n 0 C UG4 >$ 3000 0 N p 3750 U d 4500 m 1 - UPDATED FORMATION TOP DETAILS Calculation Method : Minimum Curvature 6000 49.70 18DO.00 2452.34 BPRF 7713.54 12291.67 41/2"x61/8" 4-112 63.37 2113.67 3075.92 SVt SECTION DETAILS 2398.33 Sac MD Inc Azl TVD +N/ -S +E/ -W Dleg TFace VSecl Target Annotation 1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00 SO CA 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, 300 -TVD 3 550.00 7.50 40.00 549.29 12.52 10.50 3.00 40.00 15.67 Start Dir 4°/100' : 550' MD, 549.297VD 4 800.00 17.50 40A0 793.05 53.91 45.24 4.00 0.00 67.52 Start Dir 50/100' : 800' MD, 793.05'TVD 5 1661.57 59.80 24.70 1451.92 513.24 296.01 5.00 -19.51 588.82 Eno Dir : 1661.57' MD, 1451.92' TVD 6 8281.97 59.80 24.70 4782.12 5711.59 2686.98 0.00 0.00 6309.60 Start Dir 3°/100' : 8281.97' MD, 47B2.12'TVD 7 8349.83 60.30 22.42 4816.00 5765.48 2710.48 3.00 -76.37 6368.39 Eno Dir : 8349.83' MD, 4816' ND 8 9583.95 60.30 22.42 5427.47 6756.43 3119.37 0.00 0.00 7440.16 Start Dir Y/100': 9583.95' MD, 5427.47'TVD 910941.67 20.00 12.00 6444.96 7562.89 3404.68 3.OD -174.56 8293.40 Eno Dir : 10941.67' MD, 6444.96' TVD 1011791.67 20.00 12.00 7243.70 7847.25 3465.12 0.00 0.00 8578.18 MPU L-55 wp10 Tgt2 11 12291.67 20.00 12.00 7713.55 8014.52 3500.68 0.00 0.00 8745.70 Total Depth : 12291.67' MD, 7713.55' TVD g Entl Dir : 1661.57' MD, 1451.92' TVD 1500 k 0 BPRF o0 4 2250 SV7 n 0 C UG4 >$ 3000 0 N p 3750 U d 4500 m 1 - yy& LA3 yoo 0 SB_NA - $ SB_NB SB_0A SB_OB SO -BASE 9 518"x 12 1/4" Start D10-1100-:8281.97' MD, 4782.127VO End Dir : 8349.83' MD, 4818' TVD o " UPDATED FORMATION TOP DETAILS DPath TVDssPelh MDPaIh Formation 6000 49.70 18DO.00 2452.34 BPRF 7713.54 12291.67 41/2"x61/8" 4-112 63.37 2113.67 3075.92 SVt 4603 2398.33 364182 UG4 11252.00 NPU L-55"14(MPU L-55) 2_NNJD+IFR2+M5+Sag 3 4&2B 3498.58 5829.11 LA3 Hilmrp Alaska, LLC 4 11.80 41162.10 69419.38 SB NA 6750 4 4583 4096.13 7017.03 Be NB 81.31 4231.61 728637 SO CA Warning Method: Error Ratio 24.19 4324.49 7471.01 SB OB 33.31 4683.61 8184.94 SB BASE 30D1 6689.31 11254.59 HRZ 69.93 6820.23 11393.92 KLB 7500 02.45 6852.75 11428.52 KLGM 7 07.31 6957.61 11540.11 KUP D 59.70 7010.00 11595.87 KUP_C 88]0 705D.00 11538.43 KU07 29.70 7DBD.00 11670.36 KUP A3 8250 44.70 TD95.00 11686.32 KUP_A2 69.70 7120.00 11712.93 KUP At 7188.70 7239.00 11839.56 KUP N Bi 0 750 1500 2250 3( yy& LA3 yoo 0 SB_NA - $ SB_NB SB_0A SB_OB SO -BASE 9 518"x 12 1/4" Start D10-1100-:8281.97' MD, 4782.127VO End Dir : 8349.83' MD, 4818' TVD o " Start OIr 30/100' : 9583.95' MD, 5427.47'ND ^p6� End Dir : 10941.67' MD, 6444,96- TVD 7"x8112" KLB_ G KLGM KUP D- 115p0 MPU L-55xg10Tg12 KUP C- __' KUP B7' _ KUP5 12000 KUP_A2 KUP_A'1 ` 12?92 - - - - _ _ _ -Total Depth :12291.67' MD, 7713.55' TVD +- KUP A Base 412"x61/8" MPU L55 wp14 ,.I I I II i i iI I i - i. i. I.. I i i i i 1 -F-F-T-T-Tri-T l-T-T-T-F-f-rrT F -Ft r--T-F-T-T-rT,--T-m-7 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 Vertical Section at 23.60' (1500 usft/in) I CASING DETAILS TVD MD Name Size 4640.28 8000,00 9 518' x 12 1/4" 9-5/8 6736.57 11252.00 7" x 8 12" 7 7713.54 12291.67 41/2"x61/8" 4-112 SURVEY PROGRAM [D.11N From Depth To SurvaylPlan Tool33.70 90D.00 NWU L55 w914(MPU L55) 2 GymSR-GSS Mas on Nouns NPU L-55 wpl4 (MPU L55) 2 MWn+IFR2+MS+Sag 000.00 11252.00 NPU L-55"14(MPU L-55) 2_NNJD+IFR2+M5+Sag 1252.00 12291.67 MPU L55 "14 MPU L-55) 2 MND+IFR2+MS+Sag Hilmrp Alaska, LLC Calculation Methotl: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D Error Surface: Elliptical Conic Warning Method: Error Ratio Start OIr 30/100' : 9583.95' MD, 5427.47'ND ^p6� End Dir : 10941.67' MD, 6444,96- TVD 7"x8112" KLB_ G KLGM KUP D- 115p0 MPU L-55xg10Tg12 KUP C- __' KUP B7' _ KUP5 12000 KUP_A2 KUP_A'1 ` 12?92 - - - - _ _ _ -Total Depth :12291.67' MD, 7713.55' TVD +- KUP A Base 412"x61/8" MPU L55 wp14 ,.I I I II i i iI I i - i. i. I.. I i i i i 1 -F-F-T-T-Tri-T l-T-T-T-F-f-rrT F -Ft r--T-F-T-T-rT,--T-m-7 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 Vertical Section at 23.60' (1500 usft/in) I MALLIBURTON 8,.", DHIIIn9 8000 7500— Project: Milne Point Site: M Pt L Pad Well: Plan' MPU L-55 Wellbore: MPU L-55 Plan: MPU L-55 wpl4 MPu MFU-KU -Fau11 116 7.8 wu l,55 4In" x6IM" - -It ---Tonal Ml : 1229167' MD, 7713.55' TVD End Dir 1094L6TMD,6444.96'TVD West( -)/Fat(+) (1000 usft/in) CASING DETAILS TVD TVDSS MD Size Name 4640.28 4590.58 8000.00 9-5/8 95/8"x121/4" 6736.57 6686.87 11252.00 7 7" x 8 1/2" 7713.54 7663.84 12291.67 4-1/2 41/2"x61/8" MPu MFU-KU -Fau11 116 7.8 wu l,55 4In" x6IM" - -It ---Tonal Ml : 1229167' MD, 7713.55' TVD End Dir 1094L6TMD,6444.96'TVD West( -)/Fat(+) (1000 usft/in) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-55 Wellbore: MPU L-55 Design: MPU L-55 wp14 Halliburton Standard Proposal Report Local Coordinate Reference: Well Plan: MPU L-55 TVD Reference: MPU L-55 wp11 RKB @ 49.70usft MD Reference: MPU L-55 wpl1 RKB @ 49.70usft North Reference: True Survey Calculation Method: Minimum Curvature 'roject Milne Point, ACT, MILNE POINT lap System: US State Plane 1927 (Exact solution) . System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) • Using Well Reference Point lap Zone: Alaska Zone 04 . Using geodetic scale factor Site M Pt L Pad, TR -13-10 MPU L-55 wp14 Site Position: Northing: 6,029,799.28 usft Latitude: 70" 29'32.230 N From: Map Easting: 544,529.55usft Longitude: 149° 38'9.412 W Position Uncertainty: 0.00 usft Slot Radius: 0.. Grid Convergence: 0.34 ° Well Plan: MPU L-55 Version: Well Position +NIS 0.00 usft Northing: 6,031,799.64 usfl Latitude: 70° 29'51.886 N +E/ -W 0.00 usft Easting: 544,853.40 usft. Longitude: 149° 37'59.525 W Position Uncertainty 0.00 usft Wellhead Elevation: 16.00 usft Ground Level: 16.00 usft Wellbore MPU L-55 - Depth From (TVD) -- _ Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2018 9/15/2018 17.03 81.00 57,454 Design MPU L-55 wp14 -, Audit Notes: Version: Phase: PLAN Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +N/.S +El -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 23.60 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (1) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) ('1100usft) (°) 33.70 0.00 0.00 33.70 -16.00 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 250.30 0.00 0.00 0.00 0.00 0.00 0.00 550.00 7.50 40.00 549.29 499.59 12.52 10.50 3.00 3.00 0.00 40.00 800.00 17.50 40.00 793.05 743.35 53.91 45.24 4.00 4.00 0.00 0.00 1,661.57 59.80 24.70 1,451.92 1,402.22 513.24 296.01 5.00 4.91 -1.78 -19.51 8,281.97 59.80 24.70 4,782.12 4,732.42 5,711.59 2,686.98 0.00 0.00 0.00 0.00 8,349.83 60.30 22.42 4,816.00 4,766.30 5,765.48 2,710.48 3.00 0.74 -3.36 -76.37 9,583.95 60.30 22.42 5,427.47 5,377.77 6,756.43 3,119.37 0.00 0.00 0.00 0.00 10,941.67 20.00 12.00 6,444.96 6,395.26 7,562.89 3,404.68 3.00 -2.97 -0.77 -174.56 11,791.67 20.00 12.00 7,243.70 7,194.00 7,847,25 3,465.12 0.00 0.00 0.00 0.00 12,291.67 20.00 12.00 7,713.55 7,663.85 8,014.52 3,500.68 0.00 0.00 0.00 0.00 8292018 11:24:30AM Page 2 COMPASS 5000.1 Build 81E HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU L-55 Company: Hilcorp Alaska, LLC TVD Reference: MPU L-55 wp11 RKB @ 49.70usft Project: Milne Point MD Reference: MPU L-55 wp11 IRKS @ 49.70usft Site: M Pt L Pad North Reference: True Well: Plan: MPU L-55 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-55 Design: MPU L-55 wp14 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -16.00 33.70 0.00 0.00 33.70 -16.00 0.00 0.00 6,031,799.64 544,853.40 0.00 0.00 100.00 0.00 0.00 100.00 50.30 0.00 0.00 6,031,799.64 544,853.40 0.00 0.00 200.00 0.00 0.00 200.00 150.30 0.00 0.00 6,031,799.64 544,853.40 0.00 0.00 300.00 0.00 0.00 300.00 250.30 0.00 0.00 6,031,799.64 544,853.40 0.00 0.00 Start Dir 3"/100' : 300' MD, 300'TVD 400.00 3.00 40.00 399.95 350.25 2.01 1.68 6,031,801.65 544,855.07 3.00 2.51 500.00 6.00 40.00 499.63 449.93 8.01 6.73 6,031,807.69 544,860.08 3.00 10.04 550.00 7.50 40.00 549.29 499.59 12.52 10.50 6,031,812.22 544,863.83 3.00 15.67 Start Dir 4°1100' : 550' MD, 549.29'7VD 600.00 9.50 40.00 598.73 549.03 18.18 15.25 6,031,817.91 544,868.54 4.00 22.76 700.00 13.50 40.00 696.71 647.01 33.45 28.07 6,031,833.25 544,881.26 4.00 41.88 800.00 17.50 40.00 793.05 743.35 53.91 45.24 6,031,853.82 544,898.31 4.00 67.52 Start Dir 5°/100' : 800' MD, 793.05'TVD 900.00 22.27 35.60 887.07 837.37 80.86 65.95 6,031,880.89 544,918.85 5.00 100.50 1,000.00 27.13 32.69 977.89 928.19 115.48 89.31 6,031,915.64 644,942.00 5.00 141.57 1,100.00 32.02 30.62 1,064.84 1,015.14 157.50 115.14 6,031,957.82 544,967.58 5.00 190.42 1,200.00 36.94 29.05 1,147.25 1,097.55 206.62 143.25 6,032,007.10 544,995.39 5.00 246.69 1,300.00 41.88 27.80 1,224.49 1,174.79 262.45 173.42 6,032,063.11 545,025.22 5.00 309.93 1,400.00 46.83 26.77 1,295.97 1,246.27 324.57 205.43 6,032,125.42 545,056.85 5.00 379.67 1,500.00 51.78 25.89 1,361.16 1,311.46 392.51 239.03 6,032,193.55 545,090.03 5.00 455.37 1,600.00 56.74 25.13 1,419.55 1,369.85 465.75 273.96 6,032,266.99 545,124.51 5.00 536.47 1,661.57 59.80 24.70 1,451.93 1,402.23 513.25 296.01 6,032,314.61 545,146.28 5.00 588.82 End Dir : 1661.57' MD, 1451.92' TVD 1,700.00 59.80 24.70 1,471.26 1,421.56 543.42 309.89 6,032,344.87 545,159.98 0.00 622.03 1,800.00 59.80 24.70 1,521.56 1,471.86 621.94 346.01 6,032,423.60 545,195.61 0.00 708.44 1,900.00 59.80 24.70 1,571.86 1,522.16 700.46 382.12 6,032,502.33 545,231.25 0.00 794.85 2,000.00 59.80 24.70 1,622.16 1,572.46 778.98 418.24 6,032,581.05 545,266.89 0.00 881.26 2,100.00 59.80 24.70 1,672.46 1,622.76 857.50 454.35 6,032,659.78 545,302.52 0.00 967.67 2,200.00 59.80 24.70 1,722.77 1,673.07 936.02 490.47 6,032,738.51 545,338.16 0.00 1,054.09 2,300.00 59.80 24.70 1,773.07 1,723.37 1,014.54 526.58 6,032,817.24 545,373.80 0.00 1,140.50 2,400.00 59.80 24.70 1,823.37 1,773.67 1,093.06 562.70 6,032,895.97 545,409.44 0.00 1,226.91 2,452.34 59.80 24.70 1,849.70 1,800.00 1,134.16 581.60 6,032,937.18 545,428.09 0.00 1,272.14 BPRF 2,500.00 59.80 24.70 1,873.67 1,823.97 1,171.58 598.81 6,032,974.70 545,445.07 0.00 1,313.32 2,600.00 59.80 24.70 1,923.97 1,874.27 1,250.10 634.93 6,033,053.43 545,480.71 0.00 1,399.73 2,700.00 59.80 24.70 1,974.28 1,924.58 1,328.62 671.04 6,033,132.16 545,516.35 0.00 1,486.14 2,800.00 59.80 24.70 2,024.58 1,974.88 1,407.14 707.16 6,033,210.89 545,551.98 0.00 1,572.55 2,900.00 59.80 24.70 2,074.88 2,025.18 1,485.66 743.27 6,033,289.61 545,587.62 0.00 1,658.97 3,000.00 59.80 24.70 2,125.18 2,075.48 1,564.18 779.39 6,033,368.34 545,623.26 0.00 1,745.38 3,075.92 59.80 24.70 2,163.37 2,113.67 1,623.79 806.81 6,033,428.11 545,650.31 0.00 1,810.98 SV7 3,100.00 59.80 24.70 2,175.48 2,125.78 1,642.70 815.50 6,033,447.07 545,658.90 0.00 1,831.79 3,200.00 59.80 24.70 2,225.79 2,176.09 1,721.22 851.62 6,033,525.80 545,694.53 0.00 1,918.20 3,300.00 59.80 24.70 2,276.09 2,226.39 1,799.74 887.73 6,033,604.53 545,730.17 0.00 2,004.61 3,400.00 59.80 24.70 2,326.39 2,276.69 1,878.26 923.85 6,033,683.26 545,765.81 0.00 2,091.02 8292018 11:24:30AM Page 3 COMPASS 5000.1 Build 81E Halliburton H ALLI B U RTO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU L-55 Company: Hilcorp Alaska, LLC TVD Reference: MPU L-55 wpl1 RKB @ 49.70usfl Project: Milne Point MD Reference: MPU L-55 wpl1 RKB @ 49.70usf1 Site: M Pt L Pad North Reference: True Well: Plan: MPU L-55 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-55 Depth Inclination Azimuth Depth Design: MPU L-55 wp14 +EI -W Northing Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +EI -W Northing Easting DLS Vert Section (usft) (°) (1) (usft) usft (usft) (usft) (usft) (usft) 2,326.99 3,500.00 59.80 24.70 2,376.69 2,326.99 1,956.78 959.96 6,033,761.99 545,801.45 0.00 2,177.43 3,600.00 59.80 24.70 2,426.99 2,377.29 2,035.30 996.08 6,033,840.72 545,837.08 0.00 2,263.85 3,641.82 59.80 24.70 2,448.03 2,398.33 2,068.14 1,011.18 6,033,873.64 545,851.99 0.00 2,299.98 UG4 3,700.00 59.80 24.70 2,477.30 2,427.60 2,113.82 1,032.19 6,033,919.45 545,872.72 0.00 2,350.26 3,800.00 59.80 24.70 2,527.60 2,477.90 2,192.34 1,068.31 6,033,998.17 545,908.36 0.00 2,436.67 3,900.00 59.80 24.70 2,577.90 2,528.20 2,270.86 1,104.42 6,034,076.90 545,943.99 0.00 2,523.08 4,000.00 59.80 24.70 2,628.20 2,578.50 2,349.38 1,140.54 6,034,155.63 545,979.63 0.00 2,609.49 4,100.00 59.80 24.70 2,678.50 2,628.80 2,427.90 1,176.65 6,034,234.36 546,015.27 0.00 2,695.90 4,200.00 59.80 24.70 2,728.81 2,679.11 2,506.42 1,212.77 6,034,313.09 546,050.91 0.00 2,782.31 4,300.00 59.80 24.70 2,779.11 2,729.41 2,584.94 1,248.89 6,034,391.82 546,086.54 0.00 2,868.73 4,400.00 59.80 24.70 2,829.41 2,779.71 2,663.46 1,285.00 6,034,470.55 546,122.18 0.00 2,955.14 4,500.00 59.80 24.70 2,879.71 2,830.01 2,741.98 1,321.12 6,034,549.28 546,157.82 0.00 3,041.55 4,600.00 59.80 24.70 2,930.01 2,880.31 2,820.50 1,357.23 6,034,628.01 546,193.45 0.00 3,127.96 4,700.00 59.80 24.70 2,980.32 2,930.62 2,899.02 1,393.35 6,034,706.73 546,229.09 0.00 3,214.37 4,800.00 59.80 24.70 3,030.62 2,980.92 2,977.54 1,429.46 6,034,785.46 546,264.73 0.00 3,300.78 4,900.00 59.80 24.70 3,080.92 3,031.22 3,056.06 1,465.58 6,034,864.19 546,300.37 0.00 3,387.19 5,000.00 59.80 24.70 3,131.22 3,081.52 3,134.58 1,501.69 6,034,942.92 546,336.00 0.00 3,473.61 5,100.00 59.80 24.70 3,181.52 3,131.82 3,213.10 1,537.81 6,035,021.65 546,371.64 0.00 3,560.02 5,200.00 59.80 24.70 3,231.83 3,182.13 3,291.62 1,573.92 6,035,100.38 546,407.28 0.00 3,646.43 5,300.00 59.80 24.70 3,282.13 3,232.43 3,370.14 1,610.04 6,035,179.11 546,442.92 0.00 3,732.84 5,400.00 59.80 24.70 3,332.43 3,282.73 3,448.66 1,646.15 6,035,257.84 546,478.55 0.00 3,819.25 5,500.00 59.80 24.70 3,382.73 3,333.03 3,527.18 1,682.27 6,035,336.57 546,514.19 0.00 3,905.66 5,600.00 59.80 24.70 3,433.03 3,383.33 3,605.70 1,718.38 6,035,415.29 546,549.83 0.00 3,992.07 5,700.00 59.80 24.70 3,483.34 3,433.64 3,684.22 1,754.50 6,035,494.02 546,585.46 0.00 4,078.49 5,800.00 59.80 24.70 3,533.64 3,483.94 3,762.74 1,790.61 6,035,572.75 546,621.10 0.00 4,164.90 5,829.11 59.80 24.70 3,548.28 3,498.58 3,785.60 1,801.13 6,035,595.67 546,631.47 0.00 4,190.05 LA3 5,900.00 59.80 24.70 3,583.94 3,534.24 3,841.26 1,826.73 6,035,651.48 546,656.74 0.00 4,251.31 6,000.00 59.80 24.70 3,634.24 3,584.54 3,919.78 1,862.84 6,035,730.21 546,692.38 0.00 4,337.72 6,100.00 59.80 24.70 3,684.54 3,634.84 3,998.30 1,898.96 6,035,808.94 546,728.01 0.00 4,424.13 6,200.00 59.80 24.70 3,734.85 3,685.15 4,076.82 1,935.07 6,035,887.67 546,763.65 0.00 4,510.54 6,300.00 59.80 24.70 3,785.15 3,735.45 4,155.34 1,971.19 6,035,966.40 546,799.29 0.00 4,596.95 6,400.00 59.80 24.70 3,835.45 3,785.75 4,233.86 2,007.30 6,036,045.13 546,834.92 0.00 4,683.37 6,500.00 59.80 24.70 3,885.75 3,836.05 4,312.38 2,043.42 6,036,123.85 546,870.56 0.00 4,769.78 6,600.00 59.80 24.70 3,936.05 3,886.35 4,390.90 2,079.53 6,036,202.58 546,906.20 0.00 4,856.19 6,700.00 59.80 24.70 3,986.36 3,936.66 4,469.42 2,115.65 6,036,281.31 546,941.84 0.00 4,942.60 6,800.00 59.80 24.70 4,036.66 3,986.96 4,547.94 2,151.77 6,036,360.04 546,977.47 0.00 5,029.01 6,900.00 59.80 24.70 4,086.96 4,037.26 4,626.46 2,187.88 6,036,438.77 547,013.11 0.00 5,115.42 6,949.38 59.80 24.70 4,111.80 4,062.10 4,665.24 2,205.71 6,036,477.65 547,030.71 0.00 5,158.09 SB NA 7,000.00 59.80 24.70 4,137.26 4,087.56 4,704.98 2,224.00 6,036,517.50 547,048.75 0.00 5,201.83 7,017.03 59.80 24.70 4,145.83 4,096.13 4,718.36 2,230.15 6,036,530.91 547,054.82 0.00 5,216.55 SB NB 7,100.00 59.80 24.70 4,187.56 4,137.86 4,783.50 2,260.11 6,036,596.23 547,084.39 0.00 5,288.25 8/292018 11:24:30AM Page 4 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-55 Wellbore: MPU L-55 Design: MPU L-55 wp 14 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (") (1) (usft) usft 7,200.00 59.80 24.70 4,237.87 4,188.17 7,286.37 59.80 24.70 4,281.31 4,231.61 SB OA 2,327.42 6,036,742.95 547,150.80 0.00 7,300.00 59.80 24.70 4,288.17 4,238.47 7,400.00 59.80 24.70 4,338.47 4,288.77 7,471.01 59.80 24.70 4,374.19 4,324.49 SB OB 547,216.60 0.00 5,608.84 5,097.58 7,500.00 59.80 24.70 4,388.77 4,339.07 7,600.00 59.80 24.70 4,439.07 4,389.37 7,700.00 59.80 24.70 4,489.38 4,439.68 7,800.00 59.80 24.70 4,539.68 4,489.98 7,900.00 59.80 24.70 4,589.98 4,540.28 8,000.00 • 59.80 24.70 4,640.28 4,590.58 9 518" x 12 1/4" 547,405.12 0.00 6,065.95 8,100.00 59.80 24.70 4,690.58 4.W.88 8,184.94 59.80 24.70 4,733.31 4,683.61 SB BASE 6,225.76 5,647.23 2,657.38 8,200.00 59.80 24.70 4,740.89 4,691.19 8,281.97 59.80 24.70 4,782.12 4,732.42 Start Dir 3-1100': 8281.97' MD, 4782.12'TVD 8,300.00 59.93 24.09 4,791.17 4,741.47 8,349.83 60.30 22.42 4,816.00 4,766.30 End Dir : 8349.83' MD, 4816' TVD 547,545.15 8,400.00 60.30 22.42 4,840.86 4,791.16 8,500.00 60.30 22.42 4,890.41 4,840.71 8,600.00 60.30 22.42 4,939.95 4,890.25 8,700.00 60.30 22.42 4,989.50 4,939.80 8,800.00 60.30 22.42 5,039.05 4,989.35 8,900.00 60.30 22.42 5,088.59 5,038.89 9,000.00 60.30 22.42 5,138.14 5,088.44 9,100.00 60.30 22.42 5,187.69 5,137.99 9,200.00 60.30 22.42 5,237.23 5,187.53 9,300.00 60.30 22.42 5,286.78 5,237.08 9,400.00 60.30 22.42 5,336.33 5,286.63 9,500.00 60.30 22.42 5,385.87 5,336.17 9,583.95 60.30 22.42 5,427.47 5,377.77 Start Dir 3°/100' : 9583.95' MD, 5427.47TVD 9,600.00 59.82 22.37 5,435.48 5,385.78 9,700.00 56.83 22.03 5,487.98 5,438.28 9,800.00 53.85 21.66 5,544.84 5,495.14 9,900.00 50.87 21.27 5,605.91 5,556.21 10,000.00 47.88 20.84 5,671.01 5,621.31 10,100.00 44.90 20.37 5,739.98 5,690.28 10,200.00 41.92 19.84 5,812.61 5,762.91 10,300.00 38.95 19.26 5,888.71 5,839.01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan: MPU L-55 MPU L-55 wpl1 RKB @ 49.70usft MPU L-55 wp11 RKB @ 49.70usft True Minimum Curvature 8/29/2018 11:24:30AM Page 5 COMPASS 5000.1 Build 81E Map Map +N/,S +E/ -W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 4,188.17 4,862.02 2,296.23 6,036,674.96 547,120.02 0.00 5,374.66 4,929.84 2,327.42 6,036,742.95 547,150.80 0.00 5,449.29 4,940.54 2,332.34 6,036,753.69 547,155.66 0.00 5,461.07 5,019.06 2,368.46 6,036,832.41 547,191.30 0.00 5,547.48 5,074.82 2,394.10 6,036,888.32 547,216.60 0.00 5,608.84 5,097.58 2,404.57 6,036,911.14 547,226.93 0.00 5,633.89 5,176.10 2,440.69 6,036,989.87 547,262.57 0.00 5,720.30 5,254.63 2,476.80 6,037,068.60 547,298.21 0.00 5,806.71 5,333.15 2,512.92 6,037,147.33 547,333.85 0.00 5,893.13 5,411.67 2,549.03 6,037,226.06 547,369.48 0.00 5,979.54 5,490.19 2,585.15 6,037,304.79 547,405.12 0.00 6,065.95 5,568.71 2,621.26 6,037,383.52 547,440.76 0.00 6,152.36 5,635.40 2,651.94 6,037,450.39 547,471.03 0.00 6,225.76 5,647.23 2,657.38 6,037,462.25 547,476.39 0.00 6,238.77 5,711.59 2,686.98 6,037,526.78 547,505.61 0.00 6,309.60 5,725.79 2,693.42 6,037,541.02 547,511.96 3.00 6,325.19 5,765.48 2,710.48 6,037,580.81 547,528.78 3.00 6,368.39 5,805.76 2,727.10 6,037,621.19 547,545.15 0.00 6,411.96 5,886.06 2,760.23 6,037,701.67 547,577.80 0.00 6,498.81 5,966.36 2,793.37 6,037,782.16 547,610.44 0.00 6,585.65 6,046.65 2,826.50 6,037,862.65 547,643.08 0.00 6,672.50 6,126.95 2,859.63 6,037,943.13 547,675.73 0.00 6,759.34 6,207.24 2,892.76 6,038,023.62 547,708.37 0.00 6,846.19 6,287.54 2,925.89 6,038,104.10 547,741.01 0.00 6,933.03 6,367.83 2,959.02 6,038,184.59 547,773.66 0.00 7,019.88 6,448.13 2,992.16 6,038,265.08 547,806.30 0.00 7,106.72 6,528.43 3,025.29 6,038,345.56 547,838.95 0.00 7,193.56 6,608.72 3,058.42 6,038,426.05 547,871.59 0.00 7,280.41 6,689.02 3,091.55 6,038,506.54 547,904.23 0.00 7,367.25 6,756.42 3,119.37 6,038,574.10 547,931.64 0.00 7,440.16 6,769.28 3,124.67 6,038,586.99 547,936.86 3.00 7,454.06 6,848.07 3,156.82 6,038,665.97 547,968.53 3.00 7,539.13 6,924.41 3,187.43 6,038,742.48 547,998.68 3.00 7,621.34 6,998.09 3,216.41 6,038,816.33 548,027.21 3.00 7,700.46 7,068.91 3,243.68 6,038,887.30 548,054.05 3.00 7,776.28 7,136.68 3,269.16 6,038,955.22 548,079.12 3.00 7,848.58 7,201.21 3,292.79 6,039,019.88 548,102.36 3.00 7,917.17 7,262.32 3,314.50 6,039,081.11 548,123.70 3.00 7,981.86 8/29/2018 11:24:30AM Page 5 COMPASS 5000.1 Build 81E Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Coordinate Reference: Well Plan: MPU L-55 Company: Hiicorp Alaska, LLC TVD Reference: MPU L-55 wp11 RKB @ 49.70usft Project: Milne Point MD Reference: MPU L-55 wp11 IRKS @ 49.70usft Site: M Pt L Pad North Reference: True Well: Plan: MPU L-55 Survey Calculation Method: Minimum Curvature Wellbore: MPU L-55 (usft) (1) Design: MPU L-55 wp14 usft (usft) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1 (usft) usft (usft) (usft) (usft) (usft) 5,918.38 10,400.00 35.98 18.59 5,968.08 5,918.38 7,319.84 3,334.23 6,039,138.75 548,143.08 3.00 8,042.48 10,500.00 33.01 17.82 6,050.49 6,000.79 7,373.63 3,351.93 6,039,192.64 548,160.45 3.00 8,098.85 10,600.00 30.05 16.91 6,135.72 6,086.02 7,423.52 3,367.55 6,039,242.62 548,175.77 3.00 8,150.83 10,700.00 27.09 15.83 6,223.54 6,173.84 7,469.39 3,381.05 6,039,288.57 548,188.98 3.00 8,198.26 10,800.00 24.15 14.50 6,313.70 6,264.00 7,511.11 3,392.38 6,039,330.35 548,200.06 3.00 8,241.03 10,900.00 21.22 12.83 6,405.95 6,356.25 7,548.56 3,401.52 6,039,367.85 548,208.98 3.00 8,279.01 10,941.67 20.00 12.00 6,444.96 6,395.26 7,562.89 3,404.68 6,039,382.19 548,212.05 3.00 8,293.40 End Dir : 10941.67' MD, 6444.96' TVD 11,000.00 20.00 12.00 6,499.77 6,450.07 7,582.40 3,408.83 6,039,401.73 548,216.08 0.00 8,312.94 11,100.00 20.00 12.00 6,593.74 63544.04 7,615.85 3,415.94 6,039,435.22 5483222.99 0.00 8,346.45 11,200.00 20.00 12.00 6,687.71 6,638.01 7,649.31 3,423.05 6,039,468.72 548,229.90 0.00 8,379.95 11,252.00 20.00 12.00 6,736.57. 6,686.87 7,666.70 3,426.75 6,039,486.13 548,233.49 0.00 8,397.37 7" x 81 /2" 11,254.59 20.00 12.00 6,739.01 6,689.31 7,667.57 3,426.93 6,039,487.00 548,233.67 0.00 8,398.24 HRZ 11,300.00 20.00 12.00 6,781.68 6,731.98 7,682.76 3,430.16 6,039,502.21 548,236.80 0.00 8,413.45 11,393.92 20.00 12.00 6,869.93 6,820.23 7,714.18 33436.84 6,039,533.67 548,243.29 0.00 8,444.92 KLB 11,400.00 20.00 12.00 6,875.65 6,825.95 7,716.22 3,437.27 6,039,535.70 5483243.71 0.00 8,446.96 11,428.52 20.00 12.00 6,902.45 6,852.75 7,725.76 3,439.30 6,039,545.26 548,245.68 0.00 83456.51 KLGM 11,500.00 20.00 12.00 6,969.62 6,919.92 7,749.67 3,444.38 6,039,569.20 548,250.62 0.00 8,480.46 11,640.11 20.00 12.00 7,007.31 6,957.61 7,763.09 3,447.23 6,039,582.63 548,253.39 0.00 8,493.90 KUP_D 11,595.87 20.00 12.00 7,059.70 7,010.00 7,781.74 3,451.20 6,039,601.31 5483257.24 0.00 8,512.58 KUP_C 11,600.00 20.00 12.00 7,063.58 7,013.88 7,783.13 3,451.49 6,039,602.69 548,257.53 0.00 8,513.97 11,638.43 20.00 12.00 7,099.70 7,050.00 7,795.98 3,454.23 6,039,615.56 548,260.18 0.00 8,526.84 KUP_87 11,670.36 20.00 12.00 73129.70 7,080.00 7,806.67 3,456.50 6,039,626.26 548,262.39 0.00 8,537.54 KUP_A3 11,686.32 20.00 12.00 7,144.70 7,095.00 7,812.01 3,457.63 6,039,631.60 548,263.49 0.00 8,542.89 KUP_A2 11,700.00 20.00 12.00 7,157.55 7,107.85 7,816.58 3,458.60 6,039,636.18 548,264.44 0.00 8,547.47 11,712.93 20.00 12.00 7,169.70 7,120.00 7,820.91 3,459.52 6,039,640.51 5483265.33 0.00 8,551.80 KUP_A1 11,791.67 20.00 12.00 7,243.70 7,194.00 7,847.25 3,465.12 6,039,666.89 548,270.77 0.00 8,578.18 11,800.00 20.00 12.00 7,251.52 7,201.82 7,850.04 3,465.71 6,039,669.68 548,271.35 0.00 8,580.97 11,839.56 20.00 12.00 7,288.70 7,239.00 73863.27 3,468.53 6,039,682.93 548,274.08 0.00 8,594.23 KUP_A_Base 11,900.00 20.00 12.00 7,345.49 7,295.79 7,883.49 3,472.83 6,039,703.17 5483278.25 0.00 8,614.48 12,000.00 20.00 12.00 7,439.46 7,389.76 7,916.95 3,479.94 6,039,736.67 548,285.16 0.00 8,647.98 12,100.00 20.00 12.00 7,533.43 7,483.73 7,950.40 3,487.05 6,039,770.16 548,292.07 0.00 8,681.49 12,200.00 20.00 12.00 7,627.40 7,577.70 7,983.85 3,494.16 6,039,803.65 548,298.98 0.00 83714.99 12,291.67 . 20.00 12.00 73713.54 • 7,663.84 8,014.52 3,500.68 6,039,834.36 548,305.31 0.00 8,745.70 Total Depth : 12291.67' MD, 7713.55' TVD -41/2"x6 1/8" 8292018 11:24:30AM Page 6 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Company: Hilcorp Alaska, LLC TVD Reference: Project: Milne Point MD Reference: Site: M Pt L Pad North Reference: Well: Plan: MPU L-55 Survey Calculation Method: Wellbore: MPU L-55 7"x81/2" Design: MPU L-55 wp14 12,291.67 7,713.54 Targets 4-1/2 6-1/8 Target Name - hit/miss target Dip Angle Dip Dir. TVD +N/ -S -Shape (") (1) (usft) (usft) Halliburton Standard Proposal Report Well Plan: MPU L-55 MPU L-55 wpl1 RKB @ 49.701 MPU L-55 wpl 1 RKB @ 49.70usft True Minimum Curvature +E/ -W (usft) MPU L-55 wp10 Tgt2 0.00 0.00 7,243.70 7,847.25 3,465.12 - plan hits target center - Circle (radius 200.00) MPU L-55 wp10 Tgtt 0.00 0.00 7,035.40 7,753.81 3,388.78 - plan misses target center by 62.66usft at 11559.25usft MD (7025.29 TVD, 7769.49 N, 3448.59 E) Point Casing Points Northing Easting (usft) (usft) 6,039,666.89 548,270.77 6,039,573.00 548,195.00 Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 8,000.00 4,640.28 9 5/8" x 12 1/4" 9-5/8 12-1/4 11,252.00 6,736.57 7"x81/2" 7 8-1/2 12,291.67 7,713.54 41/2"x61/8" 4-1/2 6-1/8 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology 5,829.11 3,548.28 LA3 11,595.87 7,059.70 KUP_C 3,641.82 2,448.03 UG4 3,075.92 2,163.37 SV1 11,428.52 6,902.45 KLGM 2,452.34 1,849.70 BPRF 6,949.38 4,111.80 SB—NA 11,540.11 7,007.31 KUP_D 7,017.03 4,145.83 SB—NB 11,839.56 7,288.70 KUP_A_Base 7,286.37 4,281.31 SB—OA 8,184.94 4,733.31 SB—BASE 11,254.59 6,739.01 HRZ 11,638.43 7,099.70 KUP_37 11,670.36 7,129.70 KUP_A3 7,471.01 4,374.19 SB OB 11,712.93 7,169.70 KUP_Al 11,393.92 6,869.93 KLB 11,686.32 7,144.70 KUP A2 8292018 11:24.30AM Page 7 COMPASS 5000.1 Build 81E HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt L Pad Well: Plan: MPU L-55 Wellbore: MPU L-55 Design: MPU L-55 wp14 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 300.00 300.00 550.00 549.29 800.00 793.05 1,661.57 1,451.93 8,281.97 4,782.12 8,349.83 4,816.00 9,583.95 5,427.47 10,941.67 6,444.96 12,291.67 7,713.54 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU L-55 TVD Reference: MPU L-55 wpl1 RKB @ 49.70usft MD Reference: MPU L-55 wpl1 RKB @ 49.70usft North Reference: True Survey Calculation Method: Minimum Curvature Local Coordinates +NIS +E/ -W (usft) (usft) Comment 0.00 0.00 Start Dir 311100': 300' MD, 300'TVD 12.52 10.50 Start Dir 40/100' : 550' MD, 549.29'TVD 53.91 45.24 Start Dir 5°/100' : 800' MD, 793.05'TVD 513.25 296.01 End Dir : 1661.57' MD, 1451.92' TVD 5,711.59 2,686.98 Start Dir 30/100': 8281.97' MD, 4782.12'TVD 5,765.48 2,710.48 End Dir : 8349.83' MD, 4816' TVD 6,756.42 3,119.37 Start Dir 301100' : 9583.95' MD, 5427.47'TVD 7,562.89 3,404.68 End Dir : 10941.67' MD, 6444.96' TVD 8,014.52 3,500.68 Total Depth : 12291.67' MD, 7713.55' TVD 8292018 11:24.:30AM Page 8 COMPASS 5000.1 Build 81E Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-55 MPU L-55 MPU L-55 wp14 Sperry Drilling Services Clearance Summary Anticollision Report 29 August, 2018 Closest Approach 313 Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-55 - MPU L-55 - MPU L-55 wp14 Well Coordinates: 6,031,799.64 N, 544,853.40 E (70° 29.51.89" N, 149° 37'59.53" W) Datum Height: MPU L-55 wp11 RKB @ 49.70usft Scan Range: 33.70 to 8,000.00 usft. Measured Depth. Scan Radius fs 1,500.00 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation Is Unlimited Geode0c Scale Factor Applied Version: 5000.1 Build: 81E Scan Type: • • -ME Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Hileorp Alaska, LLC Milne Point Anticollision Report for Plan: MPU L-55 - MPU L-55 wp14 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-55 - MPU L-55 - MPU L-55 wp14 Scan Range: 33.70 to 8,000.00 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-08 - MPL-08 - MPL-08 932.88 187.46 932.88 175.72 924.47 15.977 Centre Distance Pass - MPL-08 - MPL-08 - MPL-08 933.70 187.46 933.70 175.72 925.25 15.967 Ellipse Separation Pass - MPL-08 - MPL-08 - MPL-08 1,008.70 190.52 1,008.70 178.18 995.22 15.440 Clearance Factor Pass - MPL-09 - MPL-09 - MPL-09 855.80 252.91 855.80 242.13 851.33 23.456 Centre Distance Pass - MPL-09 - MPL-09 - MPL-09 883.70 253.20 883.70 242.03 877.52 22.679 Ellipse Separation Pass - MPL-09 - MPL-09 - MPL-09 1,008.70 262.99 1,008.70 250.72 991.37 21.429 Clearance Factor Pass - MPL-09 - MPL-09A - MPL-09A 855.80 252.91 855.80 242.13 851.33 23.456 Centre Distance Pass - MPL-09 - MPL-09A - MPL-09A 883.70 253.20 883.70 242.03 877.52 22.679 Ellipse Separation Pass - MPL-09 - MPL-09A - MPL-09A 1,008.70 262.99 1,008.70 250.72 991.37 21.429 Clearance Factor Pass - MPL-09 - MPL-09APB1 - MPL-09APB1 855.80 252.91 855.80 242.13 851.33 23.456 Centre Distance Pass - MPL-09 - MPL-09APB1 - MPL-09APB1 883.70 253.20 883.70 242.03 877.52 22.679 Ellipse Separation Pass - MPL-09 - MPL-09APB1 - MPL-09APB1 1,008.70 262.99 1,008.70 250.72 991.37 21.429 Clearance Factor Pass- MPL-11 - MPL-11 - MPL-11 308.70 414.60 308.70 410.75 310.54 107.514 Centre Distance Pass - MPL-11 - MPL-11 - MPL-11 408.70 415.25 408.70 410.15 412.48 81.511 Ellipse Separation Pass - MPL-11 - MPL-11 - MPL-11 8,000.00 1,302.82 8,000.00 1,136.94 8,284.45 7.854 Clearance Factor Pass - MPL-14 - MPL-14 - MPL-14 1,224.60 251.04 1,224.60 235.68 1,233.00 16.349 Centre Distance Pass - MPL-14 - MPL-14 - MPL-14 1,233.70 251.06 1,233.70 235.65 1,242.21 16.289 Ellipse Separation Pass - MPL-14 - MPL-14 - MPL-14 8,000.00 1,415.78 8,000.00 1,190.59 8,020.06 6.287 Clearance Factor Pass - MPL-16 - MPL-16 - MPL-16 33.70 124.68 33.70 123.77 35.72 136.503 Centre Distance Pass - MPL-16 - MPL-16 - MPL-16 333.70 125.36 333.70 120.72 335.60 27.036 Ellipse Separation Pass - MPL-I6-MPL-I6-MPL-16 3,983.70 645.10 3,983.70 584.12 4,116.02 10.578 Clearance Factor Pass - MPL-16 - MPL-16A - MPL-16A 33.70 124.68 33.70 123.77 29.93 136.503 Centre Distance Pass - MPL-16 - MPL-16A - MPL-16A 333.70 125.36 333.70 120.72 329.81 27.036 Ellipse Separation Pass - MPL-I6-MPL-i6A-MPL-i6A 3,983.70 645.10 3,983.70 584.12 4,110.23 10.578 Clearance Factor Pass - MPL-17 - MPL-17 - MPL-17 613.11 55.49 613.11 47.95 614.94 7.362 Centre Distance Pass - MPL-17 - MPL-17 - MPL-17 633.70 55.67 633.70 47.87 635.14 7.141 Ellipse Separation Pass - MPL-17-MPL-17-MPL-17 683.70 57.86 683.70 49.44 683.91 6.870 Clearance Factor Pass - MPL-20 - MPL-20 - MPL-20 240.58 141.13 240.58 137.79 228.08 42.277 Centre Distance Pass - 29 August, 2018 - 11:30 Page 2 of 7 COMPASS Hileorp Alaska, LLC HALLIBURT®N Milne Point Anticollision Report for Plan: MPU L-55 - MPU L-55 wp14 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L55 - MPU L-55 - MPU L55 wp14 Scan Range: 33.70 to 8,000.00 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-20 - MPL-20 - MPL-20 333.70 141.60 333.70 136.97 320.02 30.563 Ellipse Separation Pass - MPL-20 - MPL-20 - MPL-20 683.70 179.73 683.70 170.24 653.57 18.939 Clearance Factor Pass - - MPL-21 - MPL-21 - MPL-21 704.80 80.93 704.80 71.06 700.55 8.200 Centre Distance Pass - MPL-21 - MPL-21 - MPL-21 733.70 81.17 733.70 70.87 728.94 7.884 Ellipse Separation Pass - MPL-21 - MPL-21 - MPL-21 8,000.00 578.76 8,000.00 485.15 8,697.04 6.163 Clearance Factor Pass - MPL-24 - MPL-24 - MPL-24 323.15 161.81 323.15 157.20 323.55 35.125 Centre Distance Pass - MPL-24 - MPL-24 - MPL-24 383.70 162.16 383.70 156.71 384.34 29.736 Ellipse Separation Pass - MPL-24 - MPL-24 - MPL-24 883.70 214.46 883.70 201.96 872.06 17.156 Clearance Factor Pass - MPL-25 - MPL-25 - MPL-25 33.70 119.89 33.70 118.97 30.00 131.348 Centre Distance Pass - MPL-25 - MPL-25 - MPL-25 608.70 120.41 608.70 112.97 599.98 16.168 Ellipse Separation Pass - MPL-25 - MPL-25 - MPL-25 6,408.70 1,499.57 6,408.70 1,297.46 6,623.13 7.419 Clearance Factor Pass - MPL-28 - MPL-28 - MPL-28 318.06 184.71 318.06 180.18 318.79 40.733 Centre Distance Pass - MPL-28 - MPL-28 - MPL-28 383.70 185.21 383.70 179.76 383.43 34.008 Ellipse Separation Pass - MPL-28 - MPL-28 - MPL-28 883.70 243.64 883.70 231.15 860.42 19.514 Clearance Factor Pass - MPL-28 - MPL-28A - MPL-28A 318.06 184.71 318.06 180.18 318.79 40.733 Centre Distance Pass - MPL-28 - MPL-28A - MPL-28A 383.70 185.21 383.70 179.76 383.43 34.008 Ellipse Separation Pass - MPL-28 - MPL-28A - MPL-28A 883.70 243.64 883.70 231.15 860.42 19.514 Clearance Factor Pass - MPL-29 - MPL-29 - MPL-29 788.26 134.50 788.26 124.65 785.83 13.652 Centre Distance Pass - MPL-29 - MPL-29 - MPL-29 858.70 135.09 858.70 124.26 854.88 12.480 Ellipse Separation Pass - -- MPL-29 - MPL-29 - MPL-29 8,000.00 569.26 8,000.00 404.25 8,383.12 3.450 Clearance Factor Pass - MPL-32 - MPL-32 - MPL-32 308.70 210.31 308.70 205.90 309.64 47.775 Centre Distance Pass - MPL-32 - MPL-32 - MPL-32 358.70 210.61 358.70 205.52 358.59 41.340 Ellipse Separation Pass - MPL-32 - MPL-32 - MPL-32 833.70 271.16 833.70 259.55 794.95 23.355 Clearance Factor Pass - MPL-33 - MPL-33 - MPL-33 550.96 178.98 550.96 171.22 545.76 23.051 Centre Distance Pass - MPL-33 - MPL-33 - MPL-33 608.70 179.18 608.70 170.61 600.45 20.897 Ellipse Separation Pass - MPL-33 - MPL-33 - MPL-33 908.70 203.90 908.70 191.03 875.22 15.840 Clearance Factor Pass - MPL42 - MPL42 - MPL-42 758.41 231.53 758.41 222.04 741.34 24.391 Centre Distance Pass - MPL-42-MPL42-MPL-42 783.70 231.72 783.70 221.89 764.29 23.571 Ellipse Separation Pass - MPL-42 - MPL42 - MPL42 933.70 245.12 933.70 233.40 898.67 20.921 Clearance Factor Pass - MPL-43 - MPL-43 - MPL43 674.23 25.18 674.23 16.70 673.43 2.971 Centre Distance Pass - 29 August, 2018 - 11:30 Page 3 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-55 - MPU L-55 wp14 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-55 - MPU L-55 - MPU L-55 wp14 Scan Range: 33.70 to 8,000.00 usft. Measured Depth. Scan Radius is 1,500.00 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Hilcorp Alaska, LLC Milne Point 29 August, 2018 - 11:30 Page 4 of 7 COMPASS 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-43 - MPL-43 - MPL-43 708.70 25.53 708.70 16.60 707.45 2.859 Ellipse Separation Pass - MPL-43 - MPL-43 - MPL-43 733.70 26.23 733.70 16.97 732.15 2.831 Clearance Factor Pass - -. MPL-43 - MPL-43PB1 - MPL-43PB1 674.23 25.18 674.23 16.70 673.43 2.971 Centre Distance Pass - MPL-43 - MPL-43PBI - MPL-43PB1 708.70 25.53 708.70 16.60 707.45 2.859 Ellipse Separation Pass - MPL-43 - MPL-43PB1 - MPL-43PB1 733.70 26.23 733.70 16.97 732.15 2.831 Clearance Factor Pass - MPL-45 - MPL-45 - MPL-45 311.55 108.82 311.55 105.26 313.04 30.563 Centre Distance Pass - MPL-45 - MPL-45 - MPL-45 333.70 108.96 333.70 105.13 334.95 28.434 Ellipse Separation Pass - MPL-45 - MPL-45 - MPL-45 658.70 145.25 658.70 137.49 653.19 18.721 Clearance Factor Pass - MPU L-51 - MPU L-51 - MPU L-51 238.61 223.37 238.61 220.16 231.11 69.424 Centre Distance Pass - MPU L-51 - MPU L-51 - MPU L-51 308.70 223.86 308.70 219.75 298.02 54.456 Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-51 783.70 285.85 783.70 275.77 723.80 28.360 Clearance Factor Pass - MPU L-52 - MPU L-52 - MPU L-52 412.93 233.75 412.93 228.31 408.24 42.962 Centre Distance Pass - MPU L-52 - MPU L-52 - MPU L-52 458.70 234.06 458.70 228.04 452.04 38.839 Ellipse Separation Pass - MPU L-52 - MPU L-52 - MPU L-52 833.70 280.45 833.70 269.85 782.20 26.467 Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-54 742.02 174.75 742.02 164.93 748.23 17.796 Centre Distance Pass - MPU L-54 - MPU L-54 - MPU L-54 758.70 174.83 758.70 164.79 764.67 17.403 Ellipse Separation Pass - MPU L-54 - MPU L-54 - MPU L-54 908.70 185.28 908.70 173.25 905.79 15.402 Clearance Factor Pass - MPU L-56 - MPU L-56 - MPU L-56 201.80 224.67 201.80 221.40 201.48 68.873 Centre Distance Pass - MPU L-56 - MPU L-56 - MPU L-56 358.70 226.01 358.70 220.05 354.00 37.903 Ellipse Separation Pass - -- MPU L-56 - MPU L-56 - MPU L-56 783.70 255.42 783.70 242.42 734.31 19.650 Clearance Factor Pass - MPU L-57 - MPU L-57 - MPU L-57 640.90 203.47 640.90 195.14 632.80 24.435 Centre Distance Pass - MPU L-57 - MPU L-57 - MPU L-57 658.70 203.58 658.70 195.03 648.05 23.804 Ellipse Separation Pass - MPU L-57 - MPU L-57 - MPU L-57 833.70 222.86 833.70 212.28 788.00 21.053 Clearance Factor Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 640.90 203.47 640.90 195.14 632.80 24.435 Centre Distance Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 658.70 203.58 658.70 195.03 648.05 23.804 Ellipse Separation Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1 833.70 222.86 833.70 212.28 788.00 21.053 Clearance Factor Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp04 612.04 112.39 612.04 101.82 633.06 10.634 Centre Distance Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp04 733.70 113.46 733.70 100.80 762.31 8.962 Ellipse Separation Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp04 883.70 118.26 883.70 103.70 921.75 8.124 Clearance Factor Pass - Rig: MPU L-41 - MPU L-41 - MPU L-41 85.51 113.73 85.51 112.48 66.01 90.991 Ellipse Separation Pass - 29 August, 2018 - 11:30 Page 4 of 7 COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-55 - MPU L-55 wp14 Hileorp Alaska, LLC Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-55 - MPU L-55 - MPU L-55 wp14 Scan Range: 33.70 to 8,000.00 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 Rig: MPU L-41 - MPU L-41 - MPU L-41 208.70 157.67 208.70 153.33 100.00 36.379 Clearance Factor Pass - Rig: MPV L-41 - MPU L-41 - MPU L-41 wp10 283.70 113.73 283.70 109.03 284.20 24.195 Centre Distance Pass - Rig: MPU L-41 - MPU L-41 - MPU L-41 wp10 333.70 113.98 333.70 108.40 334.20 20.451 Ellipse Separation Pass - Rig: MPU L-41 - MPU L-41 - MPU L-41 wp10 7,908.70 1,214.84 7,908.70 1,084.50 8,137.26 9.321 Clearance Factor Pass - Survey tool program From To Survey/Plan SurveyTool (usft) (usft) 33.70 900.00 MPU L-55 wp14 2_Gyro-SR-GSS 900.00 8,000.00 MPU L-55 wp14 2_MWD+IFR2+MS+Sag 8,000.00 11,252.00 MPU L-55 wp14 2_MWD+IFR2+MS+Sag 11,252.00 12,291.67 MPU L-55 wp14 2_MWD+IFR2+MS+Sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles /(Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 29 August, 2018 - 11:30 Page 5 of 7 COMPASS HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELLDETAILS:PIuo:MPU455 NADI927(NADCONCONUS) M.A.Zone04 Site: M Pt L Pad £ipenry 0HIling Well: Plan: MPU L-55 Wellbore: MPU L-55 Coot rn (WE) Reference: Wag Plan: MPU L-55, Tam Norm Verical(TVD) Reference: MPU L45 wp11 RKO Q 49]Oaaft Measured Di Reference: MPU L55 Wn RK13 @ 49.7 ustt calculation Method: Minimum con-awro Ground lavel: 16,00 +N/ -S +E/ -W Neoling Easlin6 larinnde lunyAude 0.00 0.00 6031799,64 544853.40 70' 29'5 1 X86 N 149' 37'59.525 W Plan: MPU L-55 wp14 SURVEY PROGRAM GLOBAL FILTER'. Using user defined selection 8 filtering criteria EM Ladder/S.F. Plots(1 of 2) Depth From Depth To Survey/Plan Tool 33.70 900.00 MPU L-55 wp14(MPU L-55) 2_Gyro-SR-GSS 33.70 To 8000.00 CASING DETAILS TVD TVDSS MD Siee Name 4640.28 4590.58 8000.00 9-5/8 95/8"x121/4" 6736.57 6686.87 11252.00 7 7"x81/2" Surface Hole Only 900.00 8000.00 MPU L55 u,p14(MPU L-55) 2 MD+IFR2+M$+Sag 8000.00 11252.00 MPUL55wp14(MPUL55) 2 MWD+IFR2+MS+S.9 11252.00 12291.67 MPU L55 wpl4(MPU 455) 2MWD+IFR2+MS+Sag 7713.54 7663.84 12291.67 4-1/2 41/2"x61/8" MPL- .......... L41 wpl( �MPL-2 l --MPL c150.00 --1I% 42 MPL-2 o MPL-2 0 � M L -16A 0 MPLA I m 90.00 - N 60.00 MPL-211- MPL-17 MIL -17 m U j MPLA3Ps1 0 30.00 MPL-43 MPL-43 - c Lj-MPL-43 0.00 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550 Measured Depth (900 usfYin) 4.50 O 3.00 LL I c o n U) 1.50 Collision Risk Procedures Rec. Collision Avoidance Req. � No -Go Zone - Stop Drilling 0.00- 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 Measured Depth (900 usfUin) Hilcorp Alaska, LLC Milne Point M Pt L Pad Plan: MPU L-55 MPU L-55 MPU L-55 wp14 Sperry Drilling Services Clearance Summary Anticollision Report 29 August, 2018 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-55 - MPU L-55 - MPU L-55 wp14 Well Coordinates: 6,031,799.64 N, 544,853.40 E (701 29'51.89" N, 149° 37.59.53" W) Datum Height: MPU L-55 wp11 RKB @ 49.70usft Scan Range: 8,000.00 to 12,291.67 usft. 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: 81E Scan Type: • •' _ Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURT®N Anticollision Report for Plan: MPU L-55 - MPU L-55 wp14 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan: MPU L-55 - MPU L-55 - MPU L-55 wp14 Scan Range: 8,000.00 to 12,291.67 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 Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPtLPad MPL-11 - MPL-11 - MPL-11 MPL-11 - MPL-11 - MPL-11 MPL-11 - MPL-11 - MPL-11 MPL-14 - MPL-14 - MPL-14 MPL-14 - MPL-14 - MPL-14 MPL-21 - MPL-21 - MPL-21 MPL-21 - MPL-21 - MPL-21 MPL-29 - MPL-29 - MPL-29 MPL-29 - MPL-29 - MPL-29 MPL-29 - MPL-29 - MPL-29 Rig: MPU L-41 - MPU L-41 - MPU L-41 wp10 From (usft) 33.70 900.00 8,000.00 11,252.00 11, 755.39 1,007.32 11, 755.39 MPU L-55 wp14 11,775.00 MPU L-55 wp14 1,007.51 MPU L-55 wp14 11,775.00 MPU L-55 wp14 11, 800.00 Pass - 1,008.31 11, 800.00 8,000.00 Clearance Factor 1,415.78 1,190.59 6,000.00 8,020.06 8,375.00 6.287 1,496.20 Pass - 8,375.00 10,198.68 328.06 Clearance Factor 10,198.68 118.45 10,225.00 10,817.37 328.26 1.565 10,225.00 Pass - 8,000.00 569.26 8,000.00 Clearance Factor 8,350.00 404.26 577.22 8,383.12 8,350.00 3.450 10,450.00 Pass - 746.80 10,450.00 8,000.00 1,225.84 8,000.00 To (usft) 900.00 MPU L-55 wp14 6,000.00 MPU L-55 wp14 11,252.00 MPU L-55 wp14 12,291.67 MPU L-55 wp14 Survey/Plan Hileorp Alaska, LLC Milne Point Separation Warning 661.36 11,630.00 2.912 Centre Distance Pass - 661.14 11,630.00 2.909 Ellipse Separation Pass - 661.60 11,630.00 2.908 Clearance Factor Pass - 1,190.59 8,020.06 6.287 Ellipse Separation Pass - 1,246.76 8,488.25 5.998 Clearance Factor Pass - 118.45 10,817.37 1.565 Centre Distance Pass - 118.40 10,840.75 1.564 Clearance Factor Pass - 404.26 8,383.12 3.450 Centre Distance Pass - 392.80 8,722.50 3.130 Ellipse Separation Pass - 446.66 10,771.21 2.488 Clearance Factor Pass - 1,094.32 8,227.74 9.321 Clearance Factor Pass - Survey Tool 2_Gyro-SR-GSS 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 2_MWD+IFR2+MS+Sag 29 August, 2018 - 11:36 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Plan: MPU L-55 - MPU L-55 wp14 Ellipse error terms are correlated across survey tool tie -or points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Milne Point 29 August, 2018 - 11:36 Page 3 of 5 COMPASS MALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DElAILSTIan: MPU L-55 NAD 1927(NADCON CONUS) Alaska Zone 04 CoaNlrele(WE) Reference: Well Plan: WU L55, Tme North Vertical nVD) Retarence'. MPU L-55"11 RKB®49IDusa Measured OeplM1 Reference: MPU L-55 wp11 RKB®49,70usn Calculation MalhM Minlmam O=rtum Gmnnd Level: 16.08 ♦W --S +E/ -W Nordin, Eeiin Isfilludc longiwde 0.00 0.00 6DJI799.64 54485)40 ]0°29'SLRRfiN 149°3]'59525W Site: MPtL Pad Sperry Or111Ing Well: Plan: MPU L-55 Wellbore: MPU L-55 Plan: MPU L-55 wp14 SURVEY PROGRAM GLOBAL FILTER: Using user defined selection & filtering Criteria Em 8000.00 To 12291.67 Ladder/S.F. Plots(2 of 2) Depth From Depth To Survey/Plan Tool 33.70 900.00 MPU L-55 wp14 (MPU L-55) 2_GymSR-GSS CASING DETAILS TVD TVDSS MD Size Name 4690.2R 4590.56 R000.00 9-5/8 95/8"x121/4" 6736.57 6686.87 11252.00 7 7" x B 1/2" INT & Prod Hole 900.00 8000.00 MPU L-55 wp14 (MPU L-55) 2_MW D+IFR2+MS+Seq 8000.00 11252.00 MPU L-55 p14 MPU L-55) 2 MWO+IFR2+MSiSag 11252.00 12291.67 MPU L-55 wp14(MPU L-55) 2_MW otIFR2+Ms+Seg 7713.54 7663.84 12291.67 4-1/2 41/2"x61/8" X150.00 _.... - ...._........._ _- r ....T.--'-- _ 0 p120.00 c 0 m a rn d C) 0 I m 30.00 U _ 0.00 7200 7500 7800 8100 8400 8700 9000 9300 9600 9900 10200 10500 10800 11100 11400 11700 12000 12300 12600 Measured Depth (600 usft/in) .50 4.5G - ___.. I L3.00 --- LLLm 3.00 --- - - _ C o- D) 1.50 Collision Risk Procedures Req. Collision Avoidance Req. No -Go Zone - Stop Drilling 0.00 7000 7350 7700 8050 8400 8750 9100 9450 9800 10150 10500 10850 11200 11550 11900 12250 12600 Measured Depth (600 usfUin) TRANSMITTAL LETTER CHECKLIST WELL NAME: /(/t fi /'- 5 - PTD: 2-45 'ZLC!!Z t/ Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: /� l(l �l;f POOL: %u/JLeiyLC� �Lt / Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- _- (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50-_ -� from records, data and logs acquired for well name on ermit). 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 Igp4e b-e run. In addition to the well logging program proposed by om any Na e) in the attached application, the following well logs are Well Logging for this well: / Requirements e_"14ej� Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 lie, WELL PERMIT CHECKLIST Field & Pool MILNE POINT, KUPARUK RIVER OIL - 525100 PTD#:2181090 Company .HILCORP ALASKA LLC Initial Class/Type Well Name: MILNE PT UNIT L-55 Program DEV _____ Well bore seg DEV/PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal Administration '17 Nonconven. gas conforms to AS31.05.030Q. 1.A),0 2.A-D) _ _ _ _ ..... _ _ NA Comm's ' ner: ` Date Commissioner Date 917? 1 Permit fee attached ........... . .......................... . No___......_..____......... ...... ........ ....._....__.. 2 Lease number appropriate... _ _ _Yes ... Surface location in ADL 025509; top prod interval and TO in ADL 355017, ;3 Un(que well. name and number .. Yes . _ _ Milne Point, Kuparuk River Oil Pool, _govemed by Conservation Order No.. 432D 14 Well located in.a defined pool _ Yes _ _ _ _ _ Conservation Order No. 432D contains no spacing restrictions with respect. to drilling unit boundaries. 5 Well located proper distance from drilling unit. boundary _ Yes _ _ Conservation Order No. 432D has no interwell, spacing restrictions, 6 Well located proper distance from other wells. _ _ _ . Yes Wellbore.will be. more than 500' from an external property line where ownership or landownership.. 7 Sufficient acreage. available in. drilling unit _ Yes changes.. Well will conform to spacing requirements. _ 8 If deviated, is wellbore plat included _ _ _ _ _ _ Yes 9 Operator only affected party .... _ _ Yes 10 Operator has. appropriate bond in force _ _ _ _ _ _ _ _ _ _ Yes _ Appr Date 11 Permit can be issued without conservation order... _ _ Yes 12 Permit can be issued without administrative. approval Yes SFD 9/4/2018 13 Can permit be approved before 15-day wait. _ _ _ _ _ _ _ _ Yes _ 14 Well located within area andstrata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 114 mile area of review identified (For service well only). _ _ _ _ _ _ _ _ . NA.... ... ..... . 16 Pre-produced injector: duration of pre production less than 3 months. (For service well only) . NA 18 Conductor string. provided......................................... Yes _ _ _ _ _ 20 inch_setat 80 It Engineering 19 Surface casing protects all.known USDWs _ _ _ . ................. . NA _ _ _ _ _ No auquifers. _Permafrost area. 20 CMT vol adequate to circulate on conductor & surf. csg _ _ . . . . ......... . . . Yes _ 9 5/8" surface casing will be set at 8000 ft and (4500 It TVD) and fully cemented, 21 CMT. vol adequate to tie-in long string to surf csg. _ _ _ _ _ _ _ _ _ ----- ----- No. 7" inch will be cemented. with 500 ft.. 22 CMT will cover all known productive horizons _ _ Yes 23 Casing designs adequate for C,. T, B & permafrost ........................... Yes _ BTC calc provided._ 24 Adequate tankage or reserve pit ... - Yes Doyon 14 has steel tanks. 25 If.a re-drill, has a 10.403 for abandonment been approved .... ... NA.. _ _ Grassroots well, 26 Adequate wellbore separation proposed _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ No issues with close crossings, 27 If i iverter required, does it meet regulations _ .. _ _ _ _ _ _ _ _ Yes . Diverther supplied.. 16" tine__ Appr Dale 28 Drilling fluid program Schematic.& equip list adequate.. . . ... . ..... . . . Yes _ Max formation press= 4165 psi (10.4 ppg_EMW) drilling with MPD for shale stalbilly, control. 1'1.5r12.5 ppg GLS 9/11/2018 29 BOPEs,.do they meet regulation _ _ _ _ _ _ _ _ _ _ . . .. . ....... . . Yes Doyon 14 has 13 5/8" DOPE _5000 psi WP. 30 DOPE. press rating appropriate; test to (put psig in comments)_ _ _ _ _ .... _ Yes _ MASP = 3394 psi Will. TEST DOPE to 4000 psi. (annular to 2500 psi) 31 Cboke manifold complies WAPI RP-53 (May 84).. _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 32 Work will occur without operation shutdown.. _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Sundry. required to frac well, C13L required_ 33 Is presence. of H2S gas probable _ _ _ _ _ _ _ _ _ _ .. ........ ...... Yes H2$ in area. Rig has sensors and alarms... _. 34 .Moebanical.condition of wells within AOR verified (For service well only) .. _ _ _ .. NA ............................. can be issued w/o hydrogen sulfide measures ....... .......... . . . . .. No _ _ H2S measures required. Potential exists to encounter H2S in this mature reservoir. . Geology resented on potential overpressure zones .. Yes _ _ Potential exists to encounter gas hydrates while. drilling. Mitigation measures. discussed on p. 51. Appr Date c analysis of shallow gas. zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ L38Seabed NA _ _ _ _ _ _ Expected pressure is-8.65 ppg EMU until I(alubik Shale, then expected to rise to.-10.4 ppg EMW. SFD 9/4/2018 condition survey(if off-shore) ..................... .. NA Mud weight supplemented withManagedPressure Drilling Technique (MPDT) willbe used to controlt name/phone for weekly progress reports [exploratory only] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No _ _ _ _ _ expected_ pressures and unstable shale. intervals.......... Geologic Engineering Public using Doyon 14... MPD will be used for shale stability control. Fracturer stimulation is planned for well. GIs Commissioner: 'QTS Date: Comm's ' ner: ` Date Commissioner Date 917? 171 /S-'
