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215-132
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Not Operable: MPL-50 (PTD# 2151320) - Shut in, no sustained injectivity Date:Thursday, May 1, 2025 10:56:18 AM From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Thursday, May 1, 2025 9:57 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: Not Operable: MPL-50 (PTD# 2151320) - Shut in, no sustained injectivity Mr. Wallace, After making MPL-50 (PTD# 2151320) operable on 4/28/25 we attempted to bring the well on injection but were unable to sustain injectivity into formation. The well was freeze protected and shut in on 4/30/25. The well was not online long enough to submit for a stabilized online witnessed MIT-IA. The well will now be re-classified back to Not Operable. A witnessed MIT-IA will be scheduled the next time the well is returned to injection after cleanout options are reviewed. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Monday, April 28, 2025 2:38 PM To: 'Wallace, Chris D (OGC)' <chris.wallace@alaska.gov>; 'Regg, James B (OGC)' <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: OPERABLE: MPL-50 (PTD# 2151320) - Return to Injection Mr. Wallace, PWI well MPL-50 (PTD# 2151320) will be returned to injection and is now classified as Operable. An AOGCC witnessed MIT-IA will be performed once the well is on stable injection. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Tuesday, December 17, 2024 10:01 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: NOT OPERABLE: MPL-50 (PTD# 2151320) - Shut in for 4 year AOGCC MIT-IA Mr. Wallace – PWI well MPL-50 (PTD# 2151320) is currently shut in and will not be brought online for its scheduled 4 year MIT-IA due this month. The well is now classified as NOT OPERABLE and will remain shut in. A witnessed MIT-IA will be scheduled once the well is returned to injection. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: OPERABLE: MPL-50 (PTD# 2151320) - Return to Injection Date:Monday, April 28, 2025 4:24:44 PM From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Monday, April 28, 2025 2:38 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: OPERABLE: MPL-50 (PTD# 2151320) - Return to Injection Mr. Wallace, PWI well MPL-50 (PTD# 2151320) will be returned to injection and is now classified as Operable. An AOGCC witnessed MIT-IA will be performed once the well is on stable injection. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 From: Ryan Thompson Sent: Tuesday, December 17, 2024 10:01 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: NOT OPERABLE: MPL-50 (PTD# 2151320) - Shut in for 4 year AOGCC MIT-IA Mr. Wallace – PWI well MPL-50 (PTD# 2151320) is currently shut in and will not be brought online for its scheduled 4 year MIT-IA due this month. The well is now classified as NOT OPERABLE and will remain shut in. A witnessed MIT-IA will be scheduled once the well is returned to injection. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NOT OPERABLE: MPL-50 (PTD# 2151320) - Shut in for 4 year AOGCC MIT-IA Date:Tuesday, January 7, 2025 4:20:37 PM From: Ryan Thompson <Ryan.Thompson@hilcorp.com> Sent: Tuesday, December 17, 2024 10:01 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com> Subject: NOT OPERABLE: MPL-50 (PTD# 2151320) - Shut in for 4 year AOGCC MIT-IA Mr. Wallace – PWI well MPL-50 (PTD# 2151320) is currently shut in and will not be brought online for its scheduled 4 year MIT-IA due this month. The well is now classified as NOT OPERABLE and will remain shut in. A witnessed MIT-IA will be scheduled once the well is returned to injection. Please respond with any questions. Thank you, Ryan Thompson Milne / Islands / WNS Well Integrity Engineer 907-564-5005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:MBE Conformance Treatment Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 13,519 feet N/A feet true vertical 4,125 feet N/A feet Effective Depth measured 13,165 feet feet true vertical 4,143 feet 4,024 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 / Supermax 8,137' 4,027' Packers and SSSV (type, measured and true vertical depth)7” Liner Top N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: 8,115' 324-238 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 80' 0 Size 80' 4,047' 000 0 00 0 measured TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-132 50-029-23555-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025509 & ADL0025515 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT L-50 Plugs Junk measured LengthCasing Conductor 5,055' 8,358'Surface Liner 20" 9-5/8" 4-1/2" 80' 8,358'5,750psi 9,020psi13,170' 4,144' Burst N/A Collapse N/A 3,090psi 8,540psi Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 2:15 pm, Jul 23, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.07.23 12:51:41 - 08'00' Taylor Wellman (2143) DSR-7/29/24WCB 11-7-2024 _____________________________________________________________________________________ TDF 7/18/2024 SCHEMATIC Milne Point Unit Well: MPU L-50 PTD: 215-132 TD =13,519’ (MD) / TD =4,125’(TVD) 20” KB Elev above MSL: 50.8’ 4-1/2” 9-5/8” 1 2/3 5 See ICD & Swell Packer Detail PBTD =13,165’ (MD) / PBTD =4,143’(TVD) 9-5/8” ‘ES’ Cementer @ 2,601’ 4-1/2” 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80’ 0.3553 9-5/8" Surface 40 / L-80 / DWC/C 8.75” Surface 8,358’ 0.0758 4-1/2” Liner 13.5 / L-80 / HTTC 3.75” 8,115’ 13,170’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 3.833” Surf 8,137’ 0.0152 JEWELRY DETAIL No Depth Item ID 1 7,310’ XN Nipple profile: 3.725” No Go / 3.813 Packing Bore 2 8,126’ No-Go Locater on Tieback Assy ([4] - 1” Ported Seal Stem) 6.320 3 8,137’ Tieback Shoe 6.100 4 8,115’ 7” Liner Top Packer 6.180 5 13,165’ WIV (Ball on Seat/ Closed) PBTD - OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" Cmt from shoe to surface, 2 stages 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 100’ Max Hole Angle = 95.5 TREE & WELLHEAD Tree Seaboard 4 1/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Seaboard, 16 ¾” 3M x 11” 5M, standard wellhead. 9 5/8” 3M slip type hanger, w/ 11 x 4 ½ EUE Top and bottom Tbg Hgr, w/ 4” CIW “H” BPV. 2ea 3/8” NPT control lines. 4 ½” Supermax x EUE crossover GENERAL WELL INFO API#: 50-029-23555-00-00 Completed by Doyon 14 11-6-16 Depth ICD Detail Status 8,606’ #1 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,272’ #2 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,909’ #3 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Cemented 10,619’ #4 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,214’ #5 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,757’ #6 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,230’ #7 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,766’ #8 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 13,075’ #9 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open Depth Swell Packer Detail 8,752’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 10,266’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 11,440’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,334’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,694’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr Well Name Rig API Number Well Permit Number Start Date End Date MP L-50 Fullbore 50-029-23555-00-00 215-132 6/20/2024 6/20/2024 No operations to report. No operations to report. 6/22/2024 - Saturday No operations to report. 6/25/2024 - Tuesday 6/23/2024 - Sunday No operations to report. 6/24/2024 - Monday 6/21/2024 - Friday No operations to report. 6/19/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 6/20/2024 - Thursday GOING OVER JSA WITH HALLIBURTON PERSONEL. RU IRON. 1000 PSI LOW EKO TEST/ 3000 PSI HIGH TEST. EQUISEAL FULLBORE PUMP JOB. LOAD WELL W/ 1% KCL. ACHIEVE 850psi WHP - JOB CANCELLED. FWHP's T/I/O=516/100/0. 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:MBE Conformance Treatment 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): 13,519'N/A Casing Collapse Conductor N/A Surface 3,090psi Liner 8,540psi 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 SCHRADER BLUFF OIL N/A 4,125' 13,165' 4,143' 755 N/A Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MILNE PT UNIT L-50 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): April 29,2024 Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 215-132 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23555-00-00 Hilcorp Alaska LLC C.O. 477.05 Length Size Proposed Pools: 80' 80' 12.6# / L-80 / Supermax TVD Burst 8,137' MILNE POINT MD N/A 5,750psi 9,020psi 4,047' 4,144' 8,358' 13,170' 80' 20" 9-5/8" 4-1/2" 8,358' 5,055' 7” Liner Top Packer and N/A 8,115 MD/ 4,024 TVD and N/A Ryan Lewis ryan.lewis@hilcorp.com 303-906-5178 Perforation Depth MD (ft): See Schematic See Schematic 4-1/2" No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:47 am, Apr 22, 2024 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.04.19 13:27:39 - 08'00' Taylor Wellman (2143) 324-238 SFD 4/22/2024 10-404 MGR22APR24 DSR-4/23/24*&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.25 10:30:18 -08'00'04/25/24 RBDMS JSB 042524 MPL-50 MBE treatment Well Name:MPL-50 API Number: 50-029-23555-00-00 Current Status:Not Operable – Shut in Rig:Cement pump / Coil Estimated Start Date:April 2024 Estimated Duration:1 day each Regulatory Contact:Tom Fouts Permit to Drill Number:215-132 First Call Engineer:Ryan Lewis 303-906-5178 Second Call Engineer:Taylor Wellman 907-777-8449 AFE Number: Job Type:MBE treatment Current Bottom Hole Pressure:1,155 psi @ 3,803’ TVD Based off offset producer M-10 Shut in (Oct ’22) Max. Possible Surface Pressure:755 psi (Based on 0.1 psi/ft. gas gradient) Max Deviation: 92° @ 11,043’ MD Within Logging Interval Max Dogleg:9.9°/100ft @ 7,866’ MD Min ID:3.725” ID @ 7,310’ MD XN Nipple Brief Well Summary: L-50 is a Schrader OA injector supporting M-10 and L-47 producers. The injector experienced an MBE to M-10 on 9/1/2021 while shut in and confirmed with a red dye test at five hours lag time. On 9/13, an IPROF was run indicating 60% of the water injection rate was entering the uppermost three ICDs with ICD #3 @ 9,909’ MD taking >30% of the flow. On 9/14, ICDs #1-4 were closed with a short duration success of isolating the MBE between M-10 and L-47. Within hours, the water in L-50 had found a new path to the MBE conduit and as a result all four ICDs were reopened. Multiple attempts of placing H2Zero and cement have been completed in ICD #2-4 and all resulted in failure to remediate the MBE. The well has been shut in since. Objective: Pump and Equiseal job to heal the MBE. Wellbore Volume to MBE: Pipe Capacity Top Depth Bottom Depth Volume 4-1/2” Tubing .0152 bbl/ft 0 8,137’ 123.7 bbl 4-1/2” liner .0152 bbl/ft 8,137’ 8,606’ 7.1 bbl Wellbore Volume to 8,606’ 130.8 bbl x Frac gradient = 0.65 psi/ft x Top ICD 8,606’ MD = 4,015’ TVD x Est BHT = 100 deg F x Current fluid level (3/8/24) 5,780’, vol.=87.8 bbls MPL-50 MBE treatment Procedure: Fullbore – Job simulation to verify flush volume (Non-sundried work) 1. MIRU Little Red Services (LRS). 2. Pressure test lines to 3,000 psi. 3. Shoot at Tubing Fluid level. 4. Pump 43 bbls of water followed by 45 bbls diesel, Freeze Protect. 5. RD LRS. 6. Shoot a fluid level at 3 hours and again 6 hours after pumping is complete. 7. Email all fluid level data to Ryan Lewis. Fullbore - (Sundried work) 1. RU Halliburton cementer. Pressure test lines to 3,000 psi. 2. Load well with 200bbl of 1%KCl or source water at 2 bpm. Watch M-10, L-47 and F-109 BHP gauge looking for an MBE. 3. Prior to pumping gel treatment, ensure M-10, L-47 and F-109 are shut in to prevent pumping the gel directly to the producer. 4. Pump the following gel treatment down the tubing at 2bpm keeping pressure below 850psi. Estimated pump time ~1 hr. a. 50 bbl of Equiseal – catch a sample of the gel in a bottle and leave in the wellhouse. b. 5 bbl base brine c. 33 bbl of diesel i. With a bottomhole pressure of 1400psi and a full column of diesel, the fluid level should settle out around 5,780’ (87.8 bbl). The displacement volume is 33 bbl to under-displace by 5 bbl and account for the 87.8 bbl of fluid falling out. 5. At 78 bbl away, slow rate to 1.5 bpm. 6. At 83 bbl away, slow rate to 0.75 bpm. 7. Shutdown at 88 bbl away. 8. Leave Halliburton rigged up. 9. RU SL to tag fluid level. 10. 3 hours after pumping is complete, RIH with SL to tag fluid level and Equiseal level. 11. Call Ryan Lewis 303-906-5178 with the results and we will pump additional fluid to place the Equiseal on depth. The goal is to spot the top of the Equiseal at 8,277’ MD (5 bbls short of the top ICD). We have in the range of 3-6 hours before the crosslinker starts to build viscosity. Operations - 12. Prior to RTP M-10, L-47 and F-109 allow gel to set up 12 hours minimum. RTP draw the well down no more than 50-100 psi at a day. Operations - 13. Prior to POL of L-50. Let gel set up for 3 days. 14. Put a 1-2 bbl neat methanol spear in the well. a. Methanol will prevent water from slushing up when it touches cold diesel. 15. Attempt to put well on injection at target rate of 1500 bwpd but no more than 700 psi, by walking rate up in 500 bwpd increments for 15 minutes each. a. There is a chance the Equiseal has formed a plug in the liner and will need to be jetted out with coil. b. If well locks up, the diesel displacement from the gel treatment should swap out with any water and leave the well freeze protected. MPL-50 MBE treatment Coil – Cleanout if desired injection rate not achieved. Check out the gel in the sample bottle. It does not have compressive strength and should be removed with jetting action. 16. RIH with JSN and jet through the Equiseal with 1% KCl or source water. Make sure the nozzle has good up jets for getting back through Equiseal. a. Deepest Equiseal depth is 11,900’ if all 50bbl stayed in the wellbore. MPL-50 MBE treatment Wellbore Schematic MPL-50 MBE treatment Wellbore Schematic 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:MBE Conformance Treatment 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 13,519'N/A Casing Collapse Conductor N/A Surface 3,090psi Liner 8,540psi 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: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 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: AOGCC USE ONLY twellman@hilcorp.com 777-8449 Taylor Wellman STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 215-132 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23555-00-00 Hilcorp Alaska LLC SCHRADER BLUFF OIL N/A C.O. 477.05 MILNE PT UNIT L-50 Length Size Proposed Pools: 80' 80' TVD Burst PRESENT WELL CONDITION SUMMARY 4,125' 13,165' 4,143' 755 N/A 80' 20" MILNE POINT MD N/A 5,750psi 9,020psi 4,047' 4,144' 8,358' 13,170' 8,358' 5,055' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: 9-5/8" 4-1/2" Tubing Grade: Tubing MD (ft): 12.6# / L-80 / Supermax 8,137' 12/26/2022 7” Liner Top Packer and N/A 8,115 MD/ 4,024 TVD and N/A See Schematic See Schematic 4-1/2" Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Anne Prysunka at 12:21 pm, Dec 09, 2022 322-695 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2022.12.09 10:11:52 -09'00' David Haakinson (3533) 10-404X DLB 12/09/2022 DSR-12/9/22MGR12DEC22GCW 12/20/22 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.12.20 13:48:08 -09'00' RBDMS JSB 122222 MBE Treatment Well: MPU L-50 Date: 11/07/2022 Well Name:MPU L-50 API Number:50-029-23555-00 Current Status:Shut in – MBE Pad:L-Pad Estimated Start Date:12/1/2022 Rig:Pump Truck Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:215-132 First Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) 2nd Call Engineer:Brian Glasheen (907) 564-5277 (O) (907) 545-1144 (M) AFE Number: Job Type:MBE Conformance Treatment Current Bottom Hole Pressure: 1,155 psi @ 3,803’ TVD Based off offset producer M-10 Shut in (Oct ’22) MPSP:755 psi (0.1psi/ft gas gradient) Last Depth Reached:13,100’ MD 2” CT IPROF Lock-up depth (9/22/2017) Max Deviation:92° @ 11,043’ MD Within Logging Interval Max Dogleg:9.9°/100ft @ 7,866’ MD Min ID:3.725” ID @ 7,310’ MD XN Nipple Brief Well Summary: L-50 is a Schrader OA injector supporting M-10 and L-47 producers. The injector experienced an MBE to M-10 on 9/1/2021 while shut in and confirmed with a red dye test at five hours lag time. On 9/13, an IPROF was run indicating 60% of the water injection rate was entering the uppermost three ICDs with ICD #3 @ 9,909’ MD taking >30% of the flow. On 9/14, ICDs #1-4 were closed with a short duration success of isolating the MBE between M-10 and L-47. Within hours, the water in L-50 had found a new path to the MBE conduit and as a result all four ICDs were reopened. Multiple attempts of placing H2Zero and cement have been completed in ICD #2-4 and all resulted in failure to remediate the MBE. Objective: 1) Pump MBE Conformance Treatment to remediate MBE between L-50i and M-10 (should result in lower injection pressures observed). Risks x Exceeding fracture pressure. o Assuming a 0.66 psi/ft fracture gradient, try to reduce surface pressure as much as possible. x Early returns of Maraseal/H2Zero/Conformance gel seen in M-10 producer. Wellbore Volume to MBE: Pipe Capacity Top Depth Bottom Depth Volume 4-1/2” Tubing (12.6#) 0.0152 bpf 0 8,137’ 123.7 bbl 4-1/2” liner (13.5#) 0.149 bpf 8,137’ 9,272’ (ICD #2) 16.9 bbl 4-1/2” liner (13.5#) 0.149 bpf 9,272’ 10,619’ (ICD #4) 20.1 bbl 4-1/2” liner (13.5#) 0.149 bpf 10,619’ 13,075’ (ICD #9) 36.6 bbl Wellbore Volume to 10,619’ (ICD #4) 160.7 bbl -00 DLB MBE Treatment Well: MPU L-50 Date: 11/07/2022 Procedure: Pumping: 1. MIRU and pressure test HP pumping lines to 250psi low / 3,000psi high. 2. Load well w/ 250 bbls of source water (response in M-10 should be visible). a. Ensure that sampling monitoring is set up on M-10 to take continuous samples in case gel returns are observed. 3. Pump the following treatment at 0.35 bpm (~500bpd), not to exceed 750psi (Contact OE if rate cannot be achieved due to gas head in tbg at low injection rates). Stage Stage Volume (bbls) Total Volume (bbls) Product 1 90 90 Source Water w/ Blue Dye 2 180 270 Viscous Polymer w/ Green Dye 3 90 360 Conformance Gel w/ Purple Dye Lead 4 180 540 Conformance Gel w/ Viscous Polymer #1 5 90 630 Conformance Gel w/ Viscous Polymer #2 6 120 750 Conformance Gel w/ Viscous Polymer #3 7 60 810 Conformance Gel w/ Viscous Polymer #4 8 160 970 Viscous Polymer Flush a. Final volumes and viscosities to be determined by conformance gel company. b. Expected to see increasing injection pressure as viscous polymer and gel stages are placed in reservoir. c. Previous diagnostics have shown WC changes w/in hours of L-50 online but no observed red dye after 1,200 bbls injected into L-50 from M-10. d. Samples to be pulled from M-10 every 20 minutes to check for signs of gel. 4. Pump final diesel (no methanol) Freeze Protect as needed or monitor for fluid dropping to determine final volume needed. L-50 to be kept shut in for a minimum of 5 days to allow gel to set up. 5. Spear in w/ MeOH and follow with source water at a rate of 500bwpd. Monitor BHP on M-10 for signs of interaction. After ~120 bwpd away or once satisfied that well will take injection, swap over to normal injection systems and RD pumping unit. Contingency (If injectivity is reduced below 1,000 bwpd) 6. MIRU and pressure test HP pumping lines to 250psi low / 3,000psi high. 7. Pump 80bbl bleach solvent pill followed by 90bbls of source water and 30bbls of diesel freeze protect. 8. Allow to soak for 12-24hrs and bring back on injection. Attachment: 1. Schematic _____________________________________________________________________________________ TDF 11/9/2022 SCHEMATIC Milne Point Unit Well: MPU L-50 PTD: 215-132 TD =13,519’ (MD) / TD =4,125’(TVD) 20” KB Elev above MSL: 50.8’ 4-1/2” 9-5/8” 1 2/3 5 See ICD & Swell Packer Detail PBTD =13,165’ (MD) / PBTD =4,143’(TVD) 9-5/8” ‘ES’ Cementer @ 2,601’ 4-1/2” 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80’ 0.3553 9-5/8" Surface 40 / L-80 / DWC/C 8.75” Surface 8,358’ 0.0758 4-1/2” Liner 13.5 / L-80 / HTTC 3.75” 8,115’ 13,170’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 3.833” Surf 8,137’ 0.0152 JEWELRY DETAIL No Depth Item ID 1 7,310’ XN Nipple profile: 3.725” No Go / 3.813 Packing Bore 2 8,126’ No-Go Locater on Tieback Assy ([4] - 1” Ported Seal Stem) 6.320 3 8,137’ Tieback Shoe 6.100 4 8,115’ 7” Liner Top Packer 6.180 5 13,165’ WIV (Ball on Seat/ Closed) PBTD - OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" Cmt from shoe to surface, 2 stages 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 100’ Max Hole Angle = 95.5 TREE & WELLHEAD Tree Seaboard 4 1/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Seaboard, 16 ¾” 3M x 11” 5M, standard wellhead. 9 5/8” 3M slip type hanger, w/ 11 x 4 ½ EUE Top and bottom Tbg Hgr, w/ 4” CIW “H” BPV. 2ea 3/8” NPT control lines. 4 ½” Supermax x EUE crossover GENERAL WELL INFO API#: 50-029-23555-00-00 Completed by Doyon 14 11-6-16 Depth ICD Detail Status 8,606’ #1 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,272’ #2 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,909’ #3 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Cemented 10,619’ #4 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,214’ #5 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,757’ #6 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,230’ #7 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,766’ #8 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 13,075’ #9 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open Depth Swell Packer Detail 8,752’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 10,266’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 11,440’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,334’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,694’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-50 (PTD 215-132) Injection Profile 10/27/2021 Please include current contact information if different from above. PTD: 2151320 E-Set: 35954 11/17/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/20/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-50 (PTD 215-132) Coil Flag 10/07/2021 Please include current contact information if different from above. PTD: 2151320 E-Set: 35855 10/25/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-50 (PTD 215-132) Injection Profile 09/13/2021 Please include current contact information if different from above. PTD: 2151320 E-Set: 35822 10/19/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Conductor Retrofit Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 13,519 feet N/A feet true vertical 4,125 feet N/A feet Effective Depth measured 13,165 feet feet true vertical 4,143 feet 4,024 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2"12.6# / L-80 8,137' 4,027' Packers and SSSV (type, measured and true vertical depth)N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Operations Manager Contact Phone: 8,115' plus 5 more 7" LTP + 5 swell packers Collapse N/A 3,090psi 8,540psi measured true vertical Packer 20" Surface Liner 9-5/8" 4-1/2" measuredPlugs Junk measured N/A Length 80' 8,358' 5,055' Size 5,750psi 9,020psi Burst N/A N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025509 / ADL0025515 MILNE POINT / SCHRADER BLUFF OIL Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: MILNE PT UNIT L-50 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-132 50-029-23555-00-00 0 0 N/A 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 0 Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MD 80' 8,358' 13,170' Conductor TVD 80' N/A Casing 4,047' 4,144' WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 440 N/A Taylor Wellman twellman@hilcorp.com 777-8449 486 0 321-537 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations Taylor Wellman for David Haakinson By Samantha Carlisle at 8:51 am, Nov 04, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.11.03 15:59:27 -08'00' Taylor Wellman (2143) SFD 11/4/2021 RBDMS HEW 11/5/2021 DSR-11/4/21MGR27DEC2021 Well Name Rig API Number Well Permit Number Start Date End Date MP L-50 WSS 50-029-23555-00-00 215-132 10/14/2021 10/21/2021 10/20/2021 - Wednesday Seaboard retrofit - Rig down WSS with Worley crane after successful cut Bell housing of seaboard wellhead and install of inverted slips. Prep WSS with travel bolts, dismantle Iron cross, Bonnet and electrical. Travel with WSS using Worley crane (Manitowoc 2250) on Pad to next well. Seaboard retrofit - Pull 20 kps on wellhead. Start Air Arc of wellhead with NES welders of seaboard connection. Removed 14" of bell housing and conductor. Lost 3 kps during cut. Reduce overpull on wellhead to 7 kps total and install inverted retrofit slips with wellhead crew in wellhead. Lower WSS to neutral and disconnect vertical support x knuckle flange. Shutdown due to high winds (40 mph +) from further lifting and manlift use. Seaboard retrofit - Remove 2 9/16" travel bolts using pigging crew. (Needed hytorq due to corroded studs/nuts) Test rotation, platforms A,C & D operate. Platform B has power but no movement. Apply heater to Splitter box and electric pump. All platforms working properly after 1 hour heat and thaw ice. Rotation correct. Raise WSS to 6". Worley crane fly in vertical support and nipple up to Knuckle joint. Raise WSS to 6". Worley crane fly in vertical support and nipple up to knuckle joint. Raise WSS a additional 3 1/4" to touch Vert support. Worley crane fly in bonnet and tighten. Tare weight cells. 10/19/2021 - Tuesday 10/17/2021 - Sunday Seaboard retrofit - Worley moved in with WSS and flew over well using Manitowoc 2250. Set WSS using designed rig mats. Pull tree to THA (Well has two mechanical barriers) with Wellhead crew, Install 11" knuckle joint. Use MP Roads& Pads loader to move in SCT, Bonnet and Vertical support member. Remove 1 1/4" vertical travel bolts, Missing 2 9/16" custom deepwell socket for main travel bolts. Use ASRC electricians to wire up SCT to 125KW 3ph 400 amp generator (Unable to check polarity due to travel bolts) SCT had complete disconnect of all wiring harness' Measure and adjust vertical support from 9' 4" to 12' even. (Vertical support had some damaged adjustment bolts). 10/18/2021 - Monday 10/15/2021 - Friday Freeze Protect (Pre RWO) (Pressure test surface lines 250/3300 psi) Pumped 3 bbls 60/40 down Inj line. Tags hung. Hilcorp Alaska, LLC Weekly Operations Summary 10/14/2021 - Thursday WELL SHUT-IN ON ARRIVAL, PT PCE 300L / 3000H. RAN TANDEM 3.0" SWORF MAGNETS FROM SURFACE TO 7,400' SLM (recovered 12 cups sworf). SET 4-1/2" PXN PLUG BODY, P-PRONG IN XN NIPPLE AT 7,310' MD. PERFORM PASSING DRAW DOWN TEST (bled tubing from 650psi - 450psi) - HOLDING. WELL SHUT-IN ON DEPARTURE, NOTIFIED PAD OP. Well Name Rig API Number Well Permit Number Start Date End Date MP L-50 WSS 50-029-23555-00-00 215-132 10/14/2021 10/21/2021 Hilcorp Alaska, LLC Weekly Operations Summary 10/21/2021 - Thursday WELL S/I ON ARRIVAL, OPEN PERMIT W/PAD-OP, PT PCE 250L/2000H. PULL PRONG FROM 7300' SLM IN 4-1/2 PXN-PLUG IN XN-NIP AT 7310' MD. PULL 4-1/2 PXN-PLUG FROM XN-NIP AT 7305' SLM/7310' MD. RDMO, CLOSE PERMIT W/PAD-OP. Well Support Techs R/D knuckle and installed TBG hanger and tree. re-connect flowlines and set well house. Pressure tested tree to 5k and flowlines to 4000 psi. Wellhead: Pressure test hanger void 500/5 5K/10 Good test. Sting into 4" BPV find gas, bleed to zero and pull BPV. Secure well. _____________________________________________________________________________________ DH 11/3/2021 SCHEMATIC Milne Point Unit Well: MPU L-50 PTD: 215-132 TD =13,519’ (MD) / TD =4,125’(TVD) 20” KB Elev above MSL: 50.8’ 4-1/2” 9-5/8” 1 2/3 5 See ICD & Swell Packer Detail PBTD =13,165’ (MD) / PBTD =4,143’(TVD) 9-5/8” ‘ES’ Cementer @ 2,601’ 4-1/2” 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80’ 0.3553 9-5/8" Surface 40 / L-80 / DWC/C 8.75” Surface 8,358’ 0.0758 4-1/2” Liner 13.5 / L-80 / HTTC 3.75” 8,115’ 13,170’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 3.833” Surf 8,137’ 0.0152 JEWELRY DETAIL No Depth Item ID 1 7,310’ XN Nipple profile: 3.725” No Go / 3.813 Packing Bore 2 8,126’ No-Go Locater on Tieback Assy ([4] - 1” Ported Seal Stem) 6.320 3 8,137’ Tieback Shoe 6.100 4 8,115’ 7” Liner Top Packer 6.180 5 13,165’ WIV (Ball on Seat/ Closed) PBTD - OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" Cmt from shoe to surface, 2 stages 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 100’ Max Hole Angle = 95.5 TREE & WELLHEAD Tree Seaboard 4 1/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Seaboard, 16 ¾” 3M x 11” 5M, standard wellhead. 9 5/8” 3M slip type hanger, w/ 11 x 4 ½ EUE Top and bottom Tbg Hgr, w/ 4” CIW “H” BPV. 2ea 3/8” NPT control lines. 4 ½” Supermax x EUE crossover GENERAL WELL INFO API#: 50-029-23555-00-00 Completed by Doyon 14 11-6-16 Depth ICD Detail Status 8,606’ #1 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,272’ #2 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,909’ #3 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Cemented 10,619’ #4 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,214’ #5 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,757’ #6 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,230’ #7 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,766’ #8 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 13,075’ #9 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open Depth Swell Packer Detail 8,752’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 10,266’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 11,440’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,334’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,694’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/20/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-50 (PTD 215-132) Coil Flag 10/07/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/25/2021 By Abby Bell at 12:14 pm, Oct 25, 2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-50 (PTD 215-132) Injection Profile 09/13/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/19/2021 By Abby Bell at 11:34 am, Oct 19, 2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Conductor Retrofit 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 13,519'N/A Casing Collapse Conductor N/A Surface 3,090psi Liner 8,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Gorm Operations Manager Contact Email: Contact Phone: 777-8333 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng dgorm@hilcorp.com COMMISSION USE ONLY Authorized Name: Authorized Signature: Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 4,125'13,165' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 215-132 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23555-00-00 Hilcorp Alaska LLC 4,143' 1,834 N/A MILNE POINT / SCHRADER BLUFF OIL 80' 80' 12.6# / L-80 / Supermax TVD Burst 8,137' MD N/A 5,750psi 9,020psi 4,047' 4,144' See Schematic 80' 20" 9-5/8" 4-1/2" 8,358' 5,055' 10/18/2021 4-1/2" Perforation Depth MD (ft): See Schematic MILNE PT UNIT L-50 C.O. 477.05 7” Liner Top Packer and N/A 8,115 MD/ 4,024 TVD and N/A 8,358' 13,170' ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 12:49 pm, Oct 12, 2021 321-537 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.09.30 15:47:38 -08'00' David Haakinson (3533) DSR-10/12/21SFD 10/12/2021 10-404 MGR13OCT2021 dts 10/13/2021 JLC 10/13/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.13 11:10:31 -08'00' RBDMS HEW 10/13/2021 Wellhead Retrofit Well: MPU L-50 Date: 9/29/2021 Well Name:MPU L-50 API Number:50-029-23555-00-00 Current Status:Injector Pad:L-Pad Estimated Start Date:10/18/2021 Rig:WSS Reg. Approval Req’d? Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:2151320 First Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) Second Call Engineer:Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number:Job Type:Wellhead Repair Current Bottom Hole Pressure: 2214 psi @ 3803’ TVD (SBHPS taken on 7/28/18 EMW - 11.2 PPG) Maximum Expected BHP:2214 psi @ 3803’ TVD (SBHPS taken on 7/28/18 EMW - 11.2 PPG) MPSP:1834 psi (0.1 psi/ft gas gradient) Min ID:3.725” ID 4-1/2 XN Nip at 7,310’ MD Max Dev:70.0 Deg at XN profile at 7,310’ MD Brief Well Summary: The Milne Point L-50 was drilled and cased as a Schrader Bluff injection well in 2016. The well’s surface casing was fully cemented and hung off a slip style casing hanger as part of a conductor supported wellhead system. The system has since been identified has having the potential to cause wellhead movement in the event of conductor subsidence. In order to fully tie well load back to the single 9-5/8” casing string, conductor will be cut and a reverse acting slip style hanger assembly will be installed. Notes Regarding Wellbore Condition x MIT-IA passed to 1,656 psi on 12/19/2020 confirming tubing and casing integrity. Objective: Cut conductor bell nipple below starting head and install Seaboard Reverse Slip Loc assembly to ensure fully supported by surface casing. Procedure: Pre-Sundry Work Sline 1. MIRU SL unit. 2. Pressure test to 300 psi low and at least 2,000 psi high. 3. MU plug setting toolstring and set 4-1/2” XN at 7,310’ MD. a. Bleed down the tubing pressure to confirm set. 4. RDMO Prep Work 5. Disconnect flowline and instrumentation. 6. Verify tubing and IA pressures have been bled to 0psi. 7. Sniff cellar and adjacent area with multi-gas meter for LEL, CO, H2S and 02. Ensure confined space, egress and ventilation is adequate for operations 8. Vac out gravel from well cellar down to cellar liner to remove residual hydrocarbons. 9. Install fire blankets around well to prevent hot debris from falling downhole. Wellhead Retrofit Well: MPU L-50 Date: 9/29/2021 Sundry Work (Approval required to proceed) Surface Casing Support Retrofit – Note: Photo Document Repair Work on a Daily Project Timeline. 10. Sniff cellar and adjacent area with multi-gas meter for LEL, CO, H2S and 02. Ensure confined space, egress and ventilation is adequate for operations. 11. Flush conductor with water from the conductor starting head valve and while taking fluid returns from the cement return line bull plug. Flush with hot diesel until clean returns are observed. 12. Move in and rig up Well Support Structure. Place rig mats as needed to level out support structure legs. 13. Install BPV and nipple down tree at master valve or tubing head adapter as needed to makeup Wellhead Support Structure adapter flange. 14. Prepare to transfer load to the Well Support Structure. Pretension load cells according to operating manual. 15. Pull 8000 lbs (Wellhead Weight) gradually building up load in 1000 lb increments. a. Monitor the wellhead for any signs of movement and discontinue increasing tension if movement observed. 16. Increase weight up to 38,000 lbs (30 K preloading) 17. Once pre loaded, begin cutting conductor horizontally at bottom of conductor bell nipple using air arc cutter. a. Monitor load on Well Support Structure in addition to wellhead vertical displacement during cutting operations. a. Maximum dry, tubing and wellhead load = 12.6#*8137’ + 8K = 111K b. Maintain constant vertical displacement while well support structure is loaded by well. 18. Proceed to cut conductor bell nipple below the starting head then remove conductor bell nipple section. a. Ensure minimum of 12” of clearance between bottom of starting head and top of conductor. b. Record Well Support Structure Load in WSR once conductor fully loaded. 19. Leave remaining bell nipple section engaged in starting head. Bevel as needed to ensure smooth entry of slip assembly. 20. Place each half of Reverse Slip Loc assembly around surface casing, bolt halves together. 21. Install energizing plate halves at 90 degree offset from slip assembly such that joint between halves are perpendicular to slips. 22. Lift Reverse Slip Loc up inside conductor starting head. 23. In a criss cross pattern, begin to tighten bolts on energizing plates initially to 50 ft-lbs on first pass then to a final torque of 100-125 ft-lbs on second pass. 24. Mark casing at the bottom of the Reverse Slip Loc 25. Release tension, observe for any slippage. If slipping occurs, retension and tighten bolts to 150 ft-lbs. 26. Once load is released to Reverse Slip Loc, conduct MIT-IA to at least 1500 psi to confirm casing and packer integrity unchanged. a. Notify AOGCC at least 24 hrs prior to pressure testing injector Inner Annulus. b. Provide test results to Darci Horner (dhorner@hilcorp.com or 907-777-8406) for submission to AOGCC. 27. Unbolt and remove the adapter flange 28. Reinstall 5K injection tree. 29. Remove BPV and install TWC. Pressure test tree to 5000psi. 30. Re-install flowline and instrumentation 31. Weld centralizer/landing ring onto top of conductor. 32. Reinstall well house and backfill gravel over cellar liner. Pull TWC. Wellhead Retrofit Well: MPU L-50 Date: 9/29/2021 33. Install Corrosion Inhibitor in SC by Conductor Annulus up to the conductor top. Slickline 34. MIRU SL unit. 35. Pressure test to 300 psi low and at least 2,000 psi high. 36. RIH and pull 4-1/2” XN at 7,310’ MD. 37. RDMO. 38. Turn well back over to operations. Attachments: -Wellbore Schematic _____________________________________________________________________________________ TDF 9/15/2021 SCHEMATIC Milne Point Unit Well: MPU L-50 PTD: 215-132 TD =13,519’ (MD) / TD =4,125’(TVD) 20” KB Elev above MSL: 50.8’ 4-1/2” 9-5/8” 1 2/3 5 See ICD & Swell Packer Detail PBTD =13,165’ (MD) / PBTD =4,143’(TVD) 9-5/8” ‘ES’ Cementer @ 2,601’ 4-1/2” 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80’ 0.3553 9-5/8" Surface 40 / L-80 / DWC/C 8.75” Surface 8,358’ 0.0758 4-1/2” Liner 13.5 / L-80 / HTTC 3.75” 8,115’ 13,170’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 3.833” Surf 8,137’ 0.0152 JEWELRY DETAIL No Depth Item ID 1 7,310’ XN Nipple profile: 3.725” No Go / 3.813 Packing Bore 2 8,126’ No-Go Locater on Tieback Assy ([4] - 1” Ported Seal Stem) 6.320 3 8,137’ Tieback Shoe 6.100 4 8,115’ 7” Liner Top Packer 6.180 5 13,165’ WIV (Ball on Seat/ Closed) PBTD - OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" Cmt from shoe to surface, 2 stages 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 100’ Max Hole Angle = 95.5 TREE & WELLHEAD Tree Seaboard 4 1/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Seaboard, 16 ¾” 3M x 11” 5M, standard wellhead. 9 5/8” 3M slip type hanger, w/ 11 x 4 ½ EUE Top and bottom Tbg Hgr, w/ 4” CIW “H” BPV. 2ea 3/8” NPT control lines. 4 ½” Supermax x EUE crossover GENERAL WELL INFO API#: 50-029-23555-00-00 Completed by Doyon 14 11-6-16 SAFETY NOTE Seaboard conductor supported wellhead. 50-80 Klbs max compressive load. Depth ICD Detail Status 8,606’ #1 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,272’ #2 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,909’ #3 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 10,619’ #4 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,214’ #5 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,757’ #6 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,230’ #7 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,766’ #8 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 13,075’ #9 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open Depth Swell Packer Detail 8,752’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 10,266’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 11,440’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,334’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,694’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 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: Conformance Treatment 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 13,519'N/A Casing Collapse Conductor N/A Surface 3,090psi Liner 8,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: Operations Manager Contact Email:dhaakinson@hilcorp.com Contact Phone: 777-8343 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng David Haakinson COMMISSION USE ONLY Authorized Name: Authorized Signature: Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size 4,125'13,165' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 & ADL0025515 215-132 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23555-00-00 Hilcorp Alaska LLC 4,143' 1,834 N/A MILNE POINT / SCHRADER BLUFF OIL 80' 80' 12.6# / L-80 / Supermax TVD Burst 8,137' MD N/A 5,750psi 9,020psi 4,047' 4,144' See Schematic 80' 20" 9-5/8" 4-1/2" 8,358' 5,055' 9/21/2021 4-1/2" Perforation Depth MD (ft): See Schematic MILNE PT UNIT L-50 C.O. 477.05 7” Liner Top Packer and N/A 8,115 MD/ 4,024 TVD and N/A 8,358' 13,170' ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. For C.Helgeson By Meredith Guhl at 2:32 pm, Sep 15, 2021 321-475 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.09.15 14:23:13 -08'00' David Haakinson (3533) 10-404 DSR-9/15/21MGR16SEP2021SFD 9/16/2021 dts 9/16/2021 JLC 9/16/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.16 15:43:56 -08'00' RBDMS HEW 9/17/2021 MBE Diagnostics Well: MPU L-50 Date: 9/15/2021 Well Name:MPU L-50 API Number:50-029-23621-00 Current Status:Shut in – MBE Pad:L-Pad Estimated Start Date:9/21/2021 Rig:CTU Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:219-010 First Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) AFE Number: Job Type:MBE Cement Remediation Current Bottom Hole Pressure: 2,214 psi @ 3,803’ TVD SBHP (7/28/18): Pressure Anticipated Lower MPSP:1,834 psi (0.1psi/ft gas gradient) Last Depth Reached:13,100’ MD 2” CT IPROF Lock-up depth (9/22/2017) Max Deviation:92° @ 11,043’ MD Within Logging Interval Max Dogleg:9.9°/100ft @ 7,866’ MD Min ID:3.725” ID @ 7,310’ MD XN Nipple Brief Well Summary: L-50 is a Schrader OA injector supporting M-10 and L-47 producers. The injector experienced an MBE to M-10 on 9/1/2021 while shut in and confirmed with a red dye test at five hours lag time. On 9/13, an IPROF was run indicating 60% of the water injection rate was entering the uppermost three ICDs with ICD #3 @ 9,909’ MD taking >30% of the flow. On 9/14, ICDs #1-4 were closed with a short duration success of isolating the MBE between M-10 and L-47. Within hours, the water in L-50 had found a new path to the MBE conduit and as a result all four ICDs were reopened. Objective: 1) Pump Cement Conformance Treatment to remediate MBE between L-50i and M-10. Risks x Exceeding fracture pressure. o Assuming a 0.66 psi/ft fracture gradient, try to reduce surface pressure as much as possible. x Early Setup of cement causing stuck coiled tubing. o The use of a treatment packer should reduce risk of cement setup in coiled tubing annular space. o If the treatment packer becomes stuck, pump a ball to disconnect and leave downhole. x Early Release of Treatment Packers o It is important to maintain consistent temperatures throughout the job (source water, cement) to avoid early release of the treatment packers. x Cement Production in producer o Producer M-10 should be shut-in as the cement is in the coiled tubing approaching the formation. MBE Diagnostics Well: MPU L-50 Date: 9/15/2021 Procedure: CTU: 1. MIRU Coiled Tubing Unit and spot auxiliary equipment. 2. Pressure test BOPE to 3,500 psi Hi 250 Low, 10 min High, 5 min Low each test. a. If BOPE test has not been completed in last 7 days, test BPE to 250 psig low / 2,500 psig high. b. No AOGCC notification required. c. Record BOPE test results on 10-424 form. d. If within the standard 7-day test BOPE test period for Milne Point, a full body test and function test of the rams is sufficient to meet weekly BOPE test requirement. e. Each subsequent test of the lubricator will be to 3,500 psi Hi 250 Low to confirm no leaks. 3. Ensure Producer M-10 has been online for 48 hours and is ready to be shut in as cement enters the formation. 4. RU cement mixing pumping equipment. 5. Establish site control and a separate radio channel for crews so that a proper and clear communication can exist through the job. 6. MU CT, CTC, DBCV, carrier and memory GR/CCL for tie-in with 2” nozzle. 7. RIH to ~2,000’ MD. Displace well freeze protect to tanks. 8. RIH to below ICD #3 @ 9,909’ MD to 10,000’ MD. 9. Pull up to ICD #3 @ 9,909’ MD at 40 FPM. 10. Flag Pipe. 11. POOH to surface for BHA change. 12. Review GR/CCL data for tie-in. Plan to set the lower treatment packer (mid-element) at 5’ below the ICD connection at 9,923’ MD. 13. MU treatment BHA with CT, CTC, and Baker Hughes dual treatment packer BHA. 14. RIH to ~10,000’ MD. POOH to tie into the flagged pipe and correct depth based on the log. 15. Confirm with pumping crew that they are ready to mix cement for pumping. 16. Once on depth, plan to set bottom element at 9,923’ MD. 17. Pump 0.5” ball to set the lowermost treatment packer. 18. Slack off weight slightly to confirm the lower packer is set. 19. Continue to pressure up in 500 psig stages until the burst disc pops at ~2,500 psig. The upper treatment packer should be set. 20. Begin injecting source water down the CT for baseline injectivity. a. Target 700 psig CT pressure. Inject for a minimum 30 minutes to establish a baseline. b. DNE 700 psig coiled tubing injection pressure. 21. Contact engineering with injectivity results. This testing is meant to confirm that we have injectivity through the ICD. 22. Mix 7.5 bbls of 12.0 PPG cement and pump cement to formation. a. Volume assumptions: MBE is predicted to be near ICD #3 and between ICD #2 and #3. i. 0.05 bbl/ft annular hole volume for 8.5” hole and 4.5” Liner. ii. There is a large resistivity change on the open-hole drilling logs from the 2015 drilling at ~9,750’ MD. MBE Diagnostics Well: MPU L-50 Date: 9/15/2021 iii. 32 bbls of annular hole volume between ICD #2 and ICD #3. 23. Pump cement as slow as possible to reduce fracture potential and allow for the cement to take the path of least resistance into the MBE feature.DNE 0.4 BPM. 24. Flush cement with source water spacer. 25. Displace water 1 bbl past ICD into formation to clear the wellbore. a. If cement treatment screens out early, PU to release packers and begin contaminating cement. Cement likely cannot be circulated out to surface. 26. After displacement of the cement, reduce fluid injection into the well as much as possible. 27. PU 5,500 lb-force to release the packers.Allow the elastomers to relax prior to pulling up-hole. 28. POOH to 2,000’ MD. Freeze protect well, circulating fluid in at 1:1 returns while accounting for pipe displacement. 29. Allow L-50’s cement product to setup for 3 days prior to returning the well to injection. 30. RDMO Coiled Tubing Attachment: 1 Schematic 2 Proposed Schematic 3 BOPE Schematic _____________________________________________________________________________________ TDF 9/15/2021 SCHEMATIC Milne Point Unit Well: MPU L-50 PTD: 215-132 TD =13,519’ (MD) / TD =4,125’(TVD) 20” KB Elev above MSL: 50.8’ 4-1/2” 9-5/8” 1 2/3 5 See ICD & Swell Packer Detail PBTD =13,165’ (MD) / PBTD =4,143’(TVD) 9-5/8” ‘ES’ Cementer @ 2,601’ 4-1/2” 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80’ 0.3553 9-5/8" Surface 40 / L-80 / DWC/C 8.75” Surface 8,358’ 0.0758 4-1/2” Liner 13.5 / L-80 / HTTC 3.75” 8,115’ 13,170’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 3.833” Surf 8,137’ 0.0152 JEWELRY DETAIL No Depth Item ID 1 7,310’ XN Nipple profile: 3.725” No Go / 3.813 Packing Bore 2 8,126’ No-Go Locater on Tieback Assy ([4] - 1” Ported Seal Stem) 6.320 3 8,137’ Tieback Shoe 6.100 4 8,115’ 7” Liner Top Packer 6.180 5 13,165’ WIV (Ball on Seat/ Closed) PBTD - OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" Cmt from shoe to surface, 2 stages 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 100’ Max Hole Angle = 95.5 TREE & WELLHEAD Tree Seaboard 4 1/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Seaboard, 16 ¾” 3M x 11” 5M, standard wellhead. 9 5/8” 3M slip type hanger, w/ 11 x 4 ½ EUE Top and bottom Tbg Hgr, w/ 4” CIW “H” BPV. 2ea 3/8” NPT control lines. 4 ½” Supermax x EUE crossover GENERAL WELL INFO API#: 50-029-23555-00-00 Completed by Doyon 14 11-6-16 SAFETY NOTE Seaboard conductor supported wellhead. 50-80 Klbs max compressive load. Depth ICD Detail Status 8,606’ #1 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,272’ #2 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,909’ #3 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 10,619’ #4 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,214’ #5 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,757’ #6 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,230’ #7 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,766’ #8 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 13,075’ #9 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open Depth Swell Packer Detail 8,752’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 10,266’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 11,440’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,334’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,694’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr _____________________________________________________________________________________ TDF 9/15/2021 PROPOSED Milne Point Unit Well: MPU L-50 PTD: 215-132 TD =13,519’ (MD) / TD =4,125’(TVD) 20” KB Elev above MSL: 50.8’ 4-1/2” 9-5/8” 1 2/3 5 See ICD & Swell Packer Detail PBTD =13,165’ (MD) / PBTD =4,143’(TVD) 9-5/8” ‘ES’ Cementer @ 2,601’ 4-1/2” 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80’ 0.3553 9-5/8" Surface 40 / L-80 / DWC/C 8.75” Surface 8,358’ 0.0758 4-1/2” Liner 13.5 / L-80 / HTTC 3.75” 8,115’ 13,170’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 3.833” Surf 8,137’ 0.0152 JEWELRY DETAIL No Depth Item ID 1 7,310’ XN Nipple profile: 3.725” No Go / 3.813 Packing Bore 2 8,126’ No-Go Locater on Tieback Assy ([4] - 1” Ported Seal Stem) 6.320 3 8,137’ Tieback Shoe 6.100 4 8,115’ 7” Liner Top Packer 6.180 5 13,165’ WIV (Ball on Seat/ Closed) PBTD - OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" Cmt from shoe to surface, 2 stages 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 100’ Max Hole Angle = 95.5 TREE & WELLHEAD Tree Seaboard 4 1/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Seaboard, 16 ¾” 3M x 11” 5M, standard wellhead. 9 5/8” 3M slip type hanger, w/ 11 x 4 ½ EUE Top and bottom Tbg Hgr, w/ 4” CIW “H” BPV. 2ea 3/8” NPT control lines. 4 ½” Supermax x EUE crossover GENERAL WELL INFO API#: 50-029-23555-00-00 Completed by Doyon 14 11-6-16 Depth ICD Detail Status 8,606’ #1 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,272’ #2 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 9,909’ #3 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Cemented 10,619’ #4 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,214’ #5 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 11,757’ #6 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,230’ #7 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 12,766’ #8 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open 13,075’ #9 4-½” 12.6#/Ft Hydril 521 bxp, Halliburton ICD Open Depth Swell Packer Detail 8,752’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 10,266’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 11,440’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,334’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,694’ 5-½” 17#/ft L-80 DWC/C Tendeka Water Swell Pkr SAFETY NOTE Seaboard conductor supported wellhead. 50-80 Klbs max compressive load. MILNE POINT UNIT MPU L-50 9/15/2021 COIL BOPE Valve, Swab, WKM-M, 3 1/8 5M FE Valve, Upper Master, Baker, 3 1/8 5M FE, w/ Hydraulic MPU M-10 20 X 9 з X 7 X 3 ½ Coil Tubing BOP Valve, Lower Master, WKM-M, 3 1/8 5M FE Blind/Shear Blind/Shear Lubricator to injection head 4 1/16 10M Slip Slip Blind/Shear Blind/Shear Pipe Pipe Manual Gate 2 1/8 5M 2.00" Single Stripper Crossover spool 4 1/16 10M X 4 1/16 5M Manual Gate 2 1/8 5M Tubing Adapter, 3 1/8 5M Pump-In Sub 4 1/16 5M 1502 Union Crossover spool 4 1/16 5M X 3 1/8 5M MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Thursday, December 24, 2020 P.I. Supervisor 1 Z i Zc2� SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC L-50 FROM: Adam Earl MILNE PT UNIT L-50 Petroleum Inspector Sre: Inspector Reviewed By: P.1. Supry . NON -CONFIDENTIAL Comm [Well Name MILNE PT UNIT L-50 Insp Num: mitAGE201220121419 Rel Insp Num: API Well Number 50-029-23555-00-00 Inspector Name: Adam Earl Permit Number: 215-132-0 Inspection Date: 12/19/2020 Packer Depth Well L-50 Type Inj w TVD 4024 PTD 2151320 Type Test I SPT Test psi 1500 BBL Pumped: 26 - IBBL Returned: 26 Interval) 4YPTST IPIF P Notes: MIT [A Pretest Initial 15 Min 30 Min 45 Min 60 Min Tubing 751 '' 752. 751 • 1 750 IA 294 1707 16671656 - OA 2 2 3 3 Thursday, December 24, 2020 Page 1 of 1 • ( 15- 132 • Hilcorp Alaska,LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Phone: 907/777-8547 swap JUN 07N18 June 5, 2018 RECEIVED Mr. Guy Schwartz Alaska Oil and Gas Conservation Commission JUN as 2018 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 AOGCC Re: Conductor Annulus Corrosion Inhibitor Treatments 4/20/18-5/12/18 Dear Mr. Schwartz, Enclosed please find multiple copies of a spreadsheet with a list of wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water "grease-like" filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, PTD and API numbers, treatment volumes and treatment dates. This treatment campaign represents primarily new Milne Point HAK drill wells along with two Northstar wells which previously had excavations and external surface casing leak repairs. If you have any additional questions,please contact me at 777-8547 or wrivard@hilcorp.com. Sincerely, Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC • • a`1) ami m (1) m a) (1) a) a) a) (1) m a) a) a) 0 0 c c C c C c cc C C C C C 2 2 J J J J J J J J J J J Jc d c c c C c c c c c c c c C a= OO = OOOOOOOLOOOOaU U a) a) a) a) a) a) a) a) a) a) a) a) a) Q- Q rx w e m y cc wee c c C C C c c c c c c C C c c L L c a) a) a) a) a) a) (1) a) Cl) (1) a) a) a) O O ii E EEEEEEEEEEEEIS a) a) a) a) a) a) a) a) a) a) a) (1) (1) D U U O O O O O O O U U O O c N � � O CIS U C) U LL a) O O O O 0 0 LU In Ln O Ln Lf) LU L E N N6 66 N :O N C CO CO 0 CO CO CO 0 CO CO CO CO CO 0 CO CO .l12 N CD NN N 0 0 E N NN NN N N N N 0 Of p O O — NNN N CO C') CO j N N -(6 � i N N N N N N N N N N N N 0 1— d' N• t d' Lo to U 0 0 0 0 0 0 0 0 O O O 0 00 0 Cl) ti _O CO N 0) CO N- CO 0 0) N d O LU O CO CO CON N•L() LU N a) LU N O — O — — O N C d CO O CO CO CO O LO LU CO LU O LO !— N N c N N NNNNNNNNNNNNN L O U..r 1 O 0 0 0 0 0 0 0 0 0 0 0 0 0 O C O 0 0 0 0 0 0 0 0 0 0 0 0 0 O U O 0 0 0 0 0 0 0 0 0 0 0 0 0 O O O _O O O O O O 0 0 0 0 0 0 O >+ co GAO N- ON- co co LU L N-CO LN LU CO0CO CO iZ LO LU LU LU LO LO LO LU LO Lf) LO LO LU O U Q M () M M M (Y) () M M M c�) c)) (Y) (I) ) N N N N N N N N N N N N N N N a) 0) a) 0) 0) 0) 0) a) 0) a) a) 0) 0) a) a) N N NNNNNNNNNNNNN O 0 0 0 0 0 0 0 0 0 0 0 0 0 O O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 LO In LU Ln Ln LU LU LU Ln Ln Lf) Lf) L ) LU Lo d d Q D_ d d O 0_ O- 0_ d 0_ CL 0 C/) it 2 2 2 2 2 2 2 2 2 2 2 2 Z Z co a) O N CO "Cr N- CO N• CO 0) O C) N N N M M M M N N r O O 15 15 m m m m m m - - Y J a_ a_ a_ a_ a. o_ a_ D.. d a a_ d a_ (n fn 2 2 2 2 2 2 2 2 2 2 2 2 2 Z • 215132 28667 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Te : 907 777-8337 Hilrn.p Alaska,1.0 RECEIVED Fax 907 777-8510 DATA LOGGED O E-mail: doudean@hilcorp.com /21317 BENDER OCT 2 4 2017 DATE 10/23/2017 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU L-50 215-132 Memory Injection Profile GR/CCL/PRES/TEMP/SPINNERS CD 1 : MPL-50 Hilcorp_MPL-50 IPROF 23SEP17_FINAL 10/2/2017 2:51 PM File folder SOWED Eb 2 8 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received Bym Date: • 0 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Wednesday,December 07,2016 P.I.Supervisor 1`g f C I z1 7(i cc SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC L-50 FROM: Bob Noble MILNE PT UNIT SB L-50 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry J e'e" NON-CONFIDENTIAL Comm Well Name MILNE PT UNIT SB L-50 API Well Number 50-029-23555-00-00 Inspector Name: Bob Noble Permit Number: 215-132-0 Inspection Date: 12/2/2016 InsP Num: mitRCN161202152012 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min 4024 680 680 , Well' L-50 . Type InI % �' TVD Tubing 680 . 679 , PTDI 2151320 'Type Test1SPT Test psi 1500 _ IA 145 1990 1940 1930 - INITAL I Interval P/F P ✓ OA 0 * 0 1 0 0 - Notes: Initial MIT SOWED APR 2 7 2017. Wednesday,December 07,2016 Page 1 of 1 DATA SUBMITTAL COMPLIANCE REPORT 2/17/2017 Permit to Drill 2151320 Well Name/No. MILNE PT UNIT L-50 Operator HILCORP ALASKA LLC API No. 50-029-23555-00-00 MD 13519 TVD 4125 Completion Date 11/6/2016 Completion Status 1WINJ Current Status 1WINJ UIC No REQUIRED INFORMATION Mud Log No \/ Samples No ✓ Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: ROP DGR ABG EWR ADR Horizontal Presentation MD, DGR ABG E (data taken from Logs Portion of Master Well Data Maint) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments ED C 27772 Digital Data 110 13519 11/22/2016 Electronic Data Set, Filename: MPU L-50 FS+ADR FINAL.Ias ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 FS MD.cgm ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 FS TVD.cgm ' ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 - Definitive Surveys.pdf ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 - Definitive Surveys.txt•' ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 FS MD.emf ' ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 FS TVD.emf ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 _ Geosteering+lmages.dlis ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 ' Geosteering+lmages.ver ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 FS MD.pdf ED C 27772 Digital Data ?11/22/2016 Electronic File: MPU L-50 FS TVD.pdf ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 FS MD.tif ED C 27772 Digital Data 11/22/2016 Electronic File: MPU L-50 FS TVD.tif Log C 27772 Log Header Scans 0 0 2151320 MILNE PT UNIT SB L-50 LOG HEADERS ED C 27773 Digital Data 11/22/2016 Electronic File: MPU L-50 EOWR.pdf ED C 27773 Digital Data 11/22/2016 Electronic File: MPU L-50 Post well ' Summary.pptx ED C 27773 Digital Data 11/22/2016 Electronic File: MPU L-50 recorded.emf . ED C 27773 Digital Data 11/22/2016 Electronic File: MPU L-50 recorded.pdf AOGCC Page I of 2 Friday, February 17, 2017 COMPLIANCE HISTORY Completion Date: 11/6/2016 Release Date: Description Date Comments Comments: Compliance Reviewed By: Date: AOGCC Page 2 of 2 Friday, February 17, 2017 DATA SUBMITTAL COMPLIANCE REPORT 2/17/2017 Permit to Drill 2151320 Well Name/No. MILNE PT UNIT L-50 Operator HILCORP ALASKA LLC API No. 50-029-23555-00-00 MD 13519 TVD 4125 Completion Date 11/6/2016 Completion Status 1WINJ Current Status 1WINJ UIC No ED C 27773 Digital Data 11/22/2016 Electronic File: MPU L-50 recorded.tif ED C 27773 Digital Data 11/22/2016 Electronic File: MPU L-50.emf• /IQ� ED C 27773 Digital Data 11/22/2016 Electronic File: MPU L-50.pdf. N0 Q ED C 27773 Digital Data l� 11/22/2016 Electronic File: MPU L-50.tif . �J Log C 27773 Log Header Scans 0 0 2151320 MILNE PT UNIT SB L-50 LOG HEADERS Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion ReportY Directional / Inclination Data Mud Logs, Image Files, Digital Data YY Z IA Core Chips Y YMA ) Production Test Information Y /` A Mechanical Integrity Test Information Y10 Composite Logs, Image, Data Files (Y ►��J Core Photographs Y //'e)� Geologic Markers/Tops ,NA) Laboratory Analyses Y/ NA l Daily Operations Summary o Cuttings Samples Y/ 6) COMPLIANCE HISTORY Completion Date: 11/6/2016 Release Date: Description Date Comments Comments: Compliance Reviewed By: Date: AOGCC Page 2 of 2 Friday, February 17, 2017 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ WAG[:] WDSPL ❑ No. of Completions: 1 1 b. Well Class: Development ❑ Exploratory ❑ Service [�] • Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 11/6/2016 14. Permit to Drill Number / Sundry: 215-132 ,< 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: October 18, 2016 15. API Number: 50-029-23555-00-00 ' 4a. Location of Well (Governmental Section): Surface: 3272' FSL, 4783' FEL, Sec 8, T13N, R10E, UM, AK Top of Productive Interval: 2497' FNL, 1489' FEL, Sec 18, T13N, R10E, UM, AK Total Depth: 57' FNL, 251 1'FWL, Sec 20, T13N, R10E, UM, AK 8. Date TD Reached: November 1, 2016 16. Well Name and Number: MPU L-50 i 9. Ref Elevations: KB: 50.8 GL: 17.8 BF: 17.8 17. Field / Pool(s): Milne Point Field / Schrader Bluff Oil Pool . 10. Plug Back Depth MD/TVD: 13,165' MD / 4,143' TVD • 18. Property Designation: (SHL) ADL025509 / (TPH/BHL) ADL025515 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 545097 y- 6031462 Zone- 4 TPI: x- 543166 y- 6025683 Zone- 4 Total Depth: x- 547194 y- 6022867 Zone- 4 11. Total Depth MD/TVD: 13,519' MD / 4,125' TVD 19. Land Use Permit: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 2,490' MD / 1,851' TVD 5. Directional or Inclination Survey: Yes (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP DGR ABG EWR ADR Horizontal Presentation MD DGR ABG EWR ADR Invert / Revert Sections TVD 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 78.6# A-53 Surface 80' Surface 80' Driven 9-5/8" 40# L-80 Surface 8,358' Surface 4,047' 12-1/4" Stg 1 L-395 bbls / T-83 bbls 95 bbls Stg 2 L-300 bbls / T-67.5 bbls 224.5 bbls 4-1/2" 13.5# L-80 8,115' 1 13,170' 4,029' 4,143' 8-1/2" Cementless Inj. Linerw/ICDs 24. Open to production or injection? Yes 0 No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): (5) Water Swell Packers COMPLETION (9) Injection Control Devices DATE `See attached Wellbore Schematic for further detail' - ALO LO'hk_ VERIFIED L� 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) N/A 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No ❑� Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: N/A Hours Tested: N/A Production for Test Period Oil -Bbl: N/A Gas -MCF: N/A Water -Bbl: N/A Choke Size: N/A Gas -Oil Ratio: IN/A Flow Tubing Press. N/A Casing Press: N/A Calculated 24 -Hour Rate --op. Oil -Bbl: N/A Gas -MCF: N/A Water -Bbl: N/A Oil Gravity - API (corr): N/A Form 10-407 Revised 11/2915 %Z `i � CONTINUED ON PAGE 2 Submit ORIGINIAL onl ,6 � /z 7. 71( RBDMS L -L- DEC - 8 2016 28. CORE DATA Conventional C. s): Yes ❑ No ❑� Sidewall Cores. . es ❑ No Q 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 2,490' 1,851' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 8,606' 4,066' information, including reports, per 20 AAC 25.071. Sv1 3,151' 2,121' Ugnu LA3 6,290' 3,420' Schrader Bluff NA 7,469' 3,876' Schrader Bluff OA 8,471' 4,054' Formation at total depth: Schrader Bluff 31. List of Attachments: Wellbore Schematic, Daily Drilling and Completion Reports, Definitive Directional Surveys, Days vs Depth, MW vs Depth, Casing and Cement Report Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Cody Dinger Email: Cdinger(_hIIC9rp.00M Printed Name: Cody Wger Title: Drilling Tech Signature:, Aa�Phone: 777-8389 Date: /z Z INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 11/2015 Submit ORIGINAL Only Hilcorp Alaska, LLC KB Elev above MSL: 50.8' TD =13,519' (MD) / TD = 4,125(TVD) PBTD =13,165' (MD) / PBTD = 4,143'(TVD) SCHEMATIC Milne Point Unit Well: MPU L-50 PTD: 215-132 TREE & WELLHEAD Tree I Seaboard 41/16" 5M w/4-1/16" 5M Cameron Wing Seaboard, 16 %" 3M x 11" 5M, standard wellhead. 9 5/8" 3M slip type hanger, w/ 11 x 4 % EUE Top and bottom Tbg Hgr, Wellhead w/ 4" CIW "H" BPV. Zea 3/8" NPT control lines. 4'/:" Supermax x EUE crossover OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" 526i:from shoe to surface, 2 stages 8-1/2" 1 Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 20" Conductor 78.6 / A-53 / Weld N/A Surface 80' 9-5/8" Surface 40 / L-80 / DWC/C 8.75" Surface 8,358' 4-1/2" Liner 13.5 / L-80 / HTTC 3.75" 8,115' 13,170' TUBING DETAIL 4-1/2" Tubing 12.6/L-80/Supermax 1 3.833" 1 Surf 1 8,137' WELL INCLINATION DETAIL KOP @ 100' Max Hole Angle = 95.5' JEWELRY DETAIL No Depth Item ID 1 7,310' XN Nipple profile: 3.725" No Go / 3.813 Packing Bore 2 8,126' No -Go Locater on Tieback Assy ([4] - 1" Ported Seal Stem) 6.320 3 8,137' Tieback Shoe 6.100 4 8,115' 7" Liner Top Packer 6.180 5 13,165' WIV (Ball on Seat/ Closed) PBTD - Depth ICD Detail 8,606' 4-%" 12.69/Ft Hydril 521 bxp, Halliburton ICD 9,272' 4-%" 12.6#/Ft Hydril 521 bxp, Halliburton ICD 9,909' 4-%" 12.6#/Ft Hydril 521 bxp, Halliburton ICD 10,619' 4-%" 12.6#/Ft Hydril 521 bxp, Halliburton ICD 11,214' 4-%" 12.6#/Ft Hydril 521 bxp, Halliburton ICD 11,757' 4-'/z" 12.69/Ft Hydril 521 bxp, Halliburton ICD 12,230' 4-%" 12.69/Ft Hydril 521 bxp, Halliburton ICD 12,766' 4-%" 12.6#/Ft Hydril 521 bxp, Halliburton ICD 13,075' 4-'/a" 12.64/Ft Hydril 521 bxp, Halliburton ICD Depth Swell Packer Detail 8,752' S-'/" 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 10,266' S-%" 17#/11 L-80 DWC/C Tendeka Water Swell Pkr 11,440' S -Y" 179/ft L-80 DWC/C Tendeka Water Swell Pkr 12,334' S -'/z" 17#/ft L-80 DWC/C Tendeka Water Swell Pkr 12,694' S-%" 17#/ft L-80 DWC/C Tendeka Water Swell Pkr GENERAL WELL INFO API#: 50-029-23555-00-00 Completed by Doyon 14 11-6-16 CJD 11/15/2016 Hilcorp Energy Company Composite Report Well Name: MP L-50 Field: North Slope County/State: , Alaska i (LAT/LONG): evation (RKB): API #: Spud Date: 10/18/2016 Job Name: 1511128D MP L-50 Drilling Contractor Doyon 14 AFE #: AFE $: Activity Date Ops Summary 10/17/2016 Continue to prep pad for move. Move off L-46 and spot over L-50. Attempt to spot in to install wellhouse on L-48. Unable to install well house with diverter line rigged up.;Sit down and shim up rig.;Skid rig floor into place. Rig up floor service lines. Install test plug. Nipple up diverter. Spot in MWD, Geo, and Mud engineer shack. Begin loading pipe shed.;Continue loading and strapping 5" drill pipe. Install riser, prep koomey for diverter bag/knife valve. Dress shakers with screens. Take on spud mud. Pick up 5" pipe handling equipment. Spot rock;washer and hook up lines. Load BHA in pipe shed.;Pick up and rack back 51 stands of 5" DS 50 drill pipe, Continue on hooking up koomey lines to diverter ba /knife valve. 10/18/2016 Finish P/U 96 stands of 5" dp & stand back on ODS. Stand back three stands HWDP with jars. Note: AOGCC rep Chuck Schieve waived witness on Diverter function test 9 .449 am, 10/17/16.,R/U Gyro wire line. Pull Test plug. Set Spot fresh water upright tank. Rig up Gaitronic's in MWD, Mud Shack & Geo. Install coms same. Bring tools to rig floor for bha #1. PJSM, Spud Well.,M/U 12.25 HBDS QHC 1 GRC used bit, 8" Motor, & One stand of HWDP. RIH & Tag @ 43'. Break circ & flood test stack. Good. Test HP lines to 3500 psi.;Drilling out ICE in conductor F/ 43'T/ 115' @300- 450 gpm. Displace to spud mud on the fly. Drill ahead F/ 114' T/125'.,Top drive gripper not releasing all the way. Mousehole a single. Troubleshoot gripper.;Continue to inspect & troubleshoot gripper issues. Found the wrong head had been installed in back gripper block.; Drilling ahead F/ 125' T/219'. ;Circulate hole clean 400 gpm, 380 psi while POH. Run back in with pumps off, no issues.,POH, rack 2 stds HWDP in derrick, UD bottleneck XO, BD top drive, pull and inspect mud motor, UD cleanout bit.,PJSM. M/U Directional BHA #1, Varel 12 1/4" PDC bit, 8" 1.5 deg mud motor w/ 12.062" stab. DM, DGR, EWR-P4, PWD, HCIM, TM collars, Scribe same w/ 53.71 deg offset. M/U and orient UBHO sub to motor.;Download MWD data, pulser not reading, side stab at TM x HCIM connection. C/O hard connector. Attempt to download, string err, troubleshoot same, C/O faulty cable, finish MWD download. Re -orient UBHO.;M/U 3 NM Flex collars, BN XO, 1 stand HWDP. M/U top drive.;Break circulation, drilling 12 1/4" hole from 219' to 264'.;Gyro survey @ 100' ( inc 0.52) (Az 29.36) and 168' ( inc 1.03 ) (Az 47.95 ).;Drilling from 264' to 355'.;Gyro survey @ 258' ( inc 1.55) (Az 87.34) rack 1 std HWDP back, M/U jars and 2 jts HWDP.;Drill from 355' to 450'.;Gyro survey @ 349' ( inc 3.35) (Az 125.08).; Drilling from 450' to 546', pumping 400 gpm, 990 psi, 6-7k wob, 2k torque, average ROP 123 fph, running water 20 bph.;Gyro survey @ 446'( inc 3.96) ( 136.69 ).;Hauled 150 bbls from L -pad lake, total= 150 bbls. Hauled 0 bbls to MP G&I, total= 0 bbls. Hauled 0 bbls to B-50, total 0 bbls. No losses. 10/19/2016 Drilling ahead F/546' T/ 923' . Taking Gyro surveys every stand down. Got three good surveys for MWD & Sperry called good. R/D Gyro & release. MW, 9.0 vis 150-200, Drilling @ 200-500 FPH.;Trying to maintain 200 dif. Tools reacting good. Getting 5.7 -6.3 DL. Sliding 80- 100% of each stand.,Drill ahead F/ 923'T/ 1300'. 377' @ 125' FPH Average. Taking surveys with MWD sliding 60-80%. UP/DN 87/80 MW 9.0 WOB 5-10, PP off, 1160 Slide 200 dif. Sweep @ 1179', 25% Inc.;Drill ahead F/ 1300'T/ 2025'. 725' @ 121' FPH Average. Taking surveys with MWD sliding 60-80%. UP/DN 87/80 MW 9.0 WOB 5-10, PP off, 1260 Slide 200 dif. Sweep @ 1179', 25% Inc.;Drill ahead F/ 2025'T/ 2778'. 753' @ 125' FPH Average. Taking surveys with MWD, EOB 2150', maint 65 inc. UP/DN 110/80 MW 9.2 WOB 2-7, PP off, 1030 Slide 150 dif. Sweep @ 2150', 75 % Inc.;Note: base of permafrost 2490' MD.;Drill ahead F/ 2778'T/ 3376'. 598' @ 100' FPH Average. Taking surveys with MWD, maint 65 inc. UP/DN/RoU 112/80/93 MW 9.2+, ECD 10.1 WOB 2-7, PP off, 1180 Slide 150 dif. Sweep @ 3185',Note: hole unloaded on last sweep at 3185' with 250% increase, large amount of silt with some clay. Adjust pump and ROP so shakers can handle flow rate. Currently 15.5' above the line, 10' right;Hauled 1426 bbls to MPU G & I, total =1426 bbls Hauled 1420 bbls from L -pad lake, total 1570 bbls. Hauled 0 bbls to B-50, total= 0 bbls No losses. 10/20/2016 Circ & Condition btm up. Bring GPM. 400 to 550. Screen up to 140s. Drop vis from 150 in to 100., 1 ahead F/ 3465'T/ 3875' 410' AV ROP 91 FPH. Staging pumps from 500 to 550. Limiting ROP to 200. Screen up to 140s. 550 GPM 1750 psi. UP/DN 120/90 TQ 6-8, 80 RPM;Sweep @ 3700 505 increase. WOB 5-10; Back reaming full stands. Ratty through slide areas. Slight packing off. Sliding 30' per stand to maintain 65 deg. Pumping sweeps every 500'.; Drill ahead F/ 3875'T/ 4508' 633' AV ROP 105 FPH. Limiting ROP to 250. 550 GPM 1650 psi. UP/DN/ROT 135/84/103 TQ 6-8, 80 RPM;Sweep @ 4170 Hole unloaded with the extra ROP. ECD 10, WOB 5-10;Drill ahead F/ 4508' T/ 5075' 567' AV ROP 95 FPH. Limiting ROP to 250. 550 GPM 1760 psi. MW 9.3 ECD 10 UP/DN/ROT 135/78/105 WOB 5-8, TQ 9-12, 80 RPM;Sweep @ 4642', sweep back 700 stks early, hole unloaded w/300 % increase, mostly sand, clay, silt. Note: Haliburton delivered 400 sx type L cement f/ 2nd stage.,Top UG coal 3 @ 4687' (13) / Top UG coal 2 @ 4933' (37').;Drill ahead F/ 5075'T/ 5640' 565' AV ROP 94 FPH. Limiting ROP to 250. 550 GPM 1730 psi. MW 9.2 ECD 10.1 UP/DN/ROT 165/80/107 WOB 5-8, TQ 12-15, 80 RPM;Sweep @ 5203', sweep back 1000 stks early, hole unloaded for 1600 stks with mostly sand, clay, silt with some small pieces of coal. Top UG coal 1 @5394'(56') Currently 5.5' above the line, 9' right.; Hauled 1539 bbls to MPU G & I, total =2965 bbls Hauled 1600 bbls from L -pad lake, total =3170 bbls. Hauled 0 bbls to B-50, total= 0 bbls No losses. 10/21/2016 Drill ahead F/ 5640'T/ 5923' 283 ' AV ROP 113 FPH. Limiting ROP to 250. 550 GPM 1730 psi. MW 9.2 ECD 10.1 UP/DN/ROT 175/80/110 WOB 5-8, TQ 12-15, 80 RPM VIS, 107 IN 190 OUT;Back ream stand & stalled out @ 5840'. It was a hard spot while drilling. Work free with minimal effort. Back ream clean. Work back through to check. Good. 80 RPM, 550, UP/DN/ROT 190/80/110,Drill ahead F/ 5923'T/ 6290' 367 'AV ROP 122 FPH. Limiting ROP to 300. 550 GPM 1730 psi. UP/DN/ROT 175/80/110 WOB 5-8, TQ 12-15, 80 RPM MW 9.2+ IN, 9.3+ OUT. ECD 10.1 VIS, 107 IN 190 OUT;Drill ahead F/ 6290'T/ 6786' 496 'AV ROP 82 FPH. Limiting ROP to 250. 500-550 GPM 1950 psi. UP/DN/ROT 190/80/120 WOB 5-8, TO 14-16, 80 RPM MW 9.3 IN, 9.3+ OUT. ECD 10.1 VIS, 107 IN 190 OUT;Hitting hard spots. Hard to slide through hard spots. Motor stalls. Started our turn 6206' sliding 90 L. Getting gas spikes, Fine silt. Blinding shakers off. Reduce GPM to keep from loosing mud.;Sliding 60 % every stand,Drill ahead F/ 6786'T/ 7244' 458 'AV ROP 76 FPH. Limiting ROP to 250. 500-550 GPM 2150 psi. UP/DN/ROT 204/76/125 WOB 10-12, TO 18-21, 80 RPM MW 9.3 IN, 9.3 OUT. ECD 10.2 VIS, 98 IN 109 OUT;Sweep @ 6839', sweep back 1000 stks early, 100% increase, mostly sand.;Drill ahead F/ 7244'T/ 7716' 472' AV ROP 79 FPH. Limiting ROP to 250. 500-550 GPM 2110 psi. UP/DN/ROT 215/80/128 WOB 12-15, TO 19-21, 80 RPM MW 9.3 IN, 9.3+ OUT. ECD 10.1 VIS, 112 IN 192 OUT;Sweep @ 7324', sweep back 1700 stks early, 100% increase mostly sand. Note: top Schrader bluff N sand @ 7470' Currently 11.30' above the line, 36.40' right, formations coming in 5-10' high;Seeing traces of oil @ shakers. 10/22/2016 Circ sweep around @ 600 gpm 100 rpm to clean hole from sliding 80% last 1000'. Sweep did not increase cuttings. Pump pressure came down 100 psi. Sweep came back 100 bbl early. MW 9.3 vis 100.;Drill ahead F/ 7716'T/ 8363'@ TD 647' AV ROP 108 FPH. Limit ROP to 300. 550 GPM 2150 psi. UP/DN/ROT 220/70/125 WOB 12-15, TQ 19-22, 80 RPM MW 9.3 IN, 9.3+ OUT. ECD 9.9 VIS, 112 IN 192 OUT;Start lowing yield point to 34. Landed casing shoe in the Schrader 2 above the OA sand. Circ sweep around @ 600 gpm 80 RPM. 1.5 btm up. Shakers cleaned up good. 9.3+ in vis 85 YP 34.;Pump out of the hole @ 500 gpm F/ 8363'T/ 7250'. Cleaning up last DL & slides. Keep tool face high side.,Pump out of the hole @ 500 gpm, 1650 psi F/ 7250'T/ 3850'. Keep tool face high side.;Pump out of the hole @ 500 gpm, 1650 psi F/ 3850' , 10k over pull @ 3766' @ UG4 coal, tight @ 3178', back ream f/ 3144' to 3122', 3064' to 3035', tight @ 3010', 20k over pull,;work thru easily, see increase in sand @ shakers. Back ream from 2671' to 2621', 2610' to 2568', packing off @ 2405', work stand and pull thru easily. 10k over pull Packing off @ 2122',,Back ream from 2122' to 2107', 1815' to 1775', 1693 to 1630' Note: Pump min rate when working pipe down .,Hauled 1155 bbls to MPU G & I, total =5508 bbls Hauled 1200 bbis from L -pad lake, total =5570 bbls. Hauled 0 bbls to B-50, total= 0 bbls 10/23/2016 Backream F/ 1630'T/ 737'. 400 gpm . pm. Pulling slow 5k tq. 5k over pulls. Cleaning up good after ning. Attempt to just pump and pull but over pulling over 20K. Continue back reaming.;POH on elevators F/ 737' T/ HWDP. UD 6 joints HWDP. Stand back stand with jars. Pump freshwater through BHA. No losses to the hole for the trip.;LJD BHA to MWD. Download MWD. UD same. Break bit from motor. Bit Grade 2 -3 -CT -T -X -1 -BT -TD See pics in 0 Drive. Insert bushing lock came off & fell down hole.;Clean & clear floor. Pull wear bushing. UD bushing & puller.;R/U to run 9 5/8" casing with Weatherford.; Conduct PJSM to P/U 9 5/8" casing. M/U shoe track, Weatherford backup strap tong egged FC it while M/U Baffle adaptor it with power tongs. Back out same, clean off baker Ioc.;UD damaged it. P/U spare FC joint, while M/U using rig tongs for backup on collar, torqued early, shut down, casing and collar slightly egged on shoe jt, back out FC, clean and inspect FC threads.; L/D FC and shoe its. Decision made to use Weatherford double stack tongs, mobilize tongs from Deadhorse. R/D power tongs. Send in shoe and FC its to Baker to be recut and new collars installed.;Double stack tongs on location @ 22:00 hrs, load tongs to rig floor, R/U same. Use spare it to test power tongs before M/U FE, test ok.;lnstall 2 centralizers over stop collars 10' from ea. end on new shoe it. Verify no debris in shoe track before M/U.;Baker loc and M/U shoe track, install 1 centralizer over stop collar 10' from pin end on FC it. Ensure float operation. M/U and RIH w/ 9 5/8" DWC/C , L-80, Use BOL 2000 pipe dope.,M/U to optimum torq @ 32000 ft/lbs, utilize dog collar clamp on 1st 10 its ran, fill on the fly and every 10 jts ran, install centralizers every other it ran to it #20. RIH to 1572'w/ set down.;Wash casing f/ 1572' to 1582' pumping 2 bpm 100 psi, attempting to wash past 1582'.;Hauled 984 bbls to MPU G & I, total =6492 bbls Hauled 750 bbls from L -pad lake, total =6320 bbls. Hauled 0 bbls to B-50, total= 0 bbls No losses. 10/24/2016 Wash & ream F/ 1582'T/2110'. Reaming @20 RPM 8-10 K210 GPM. Reaming out @ 5-8 WOB.,RIH with 9 5/8 casing F/ 2110' T/ 4510'. Tag up. Cant break over.;Break circ & stage up pumps to 6 bpm 200 psi, Pull 325K no movement. Rot @ 25K & work pipe start to get minimal RPM & getting 10' of movement before pulling 300. Rot down past tight spot stalling.;Work pipe past tight spot F/ 4510 T/ 4570'. Circ btm up before shutting down pumps. Minimal sand at the shakers. MW 9.4 Good circulation with no losses @ 6 bpm.;RIH on elevators F/ 4570'T/ 5592' floating pipe in. Having to get a run at it to keep it moving. Install 1 centralizer ea on 5 its below ESC to 5753', ensure ESC has 6 pins to shear 3300 psi.;Check for debris in ESC jt, Baker loc and M/U same (placing top ESC @ 2602') Install 1 centralizer ea on 5 its above ESC to 5958', continue RIH on elevators, floating in f/5958' to 6000'.,CBU staging pump from 2 bpm, 100 psi to 6 bpm, 260 psi, slacking off slowly and able to turn pipe applying 20k torq, f/ 6000' to 6120' M/U pipe as we go.16 bbl losses during B/U. Minimal increase of sand @ shakers.,RIH on elevators floating pipe in f/ 6120' to 6602' w/ differential sticking on connections., RIH on elevators floating pipe in f/ 6602' to 7171' w/ differential sticking on connections.; Unable to float down on elevators, no down weight, pump 2-3 bpm, able to get some rotation with torq set @ 25k, work casing down with slow progress f/ 7171' to 7787' ( 188 its ).;P/U to 250k up wt several times ea joint to avoid packing off.;Hauled 0 bbls to MPU G & I, total =6492 bbls Hauled 285 bbls from L -pad lake, total =6605 bbls. } Hauled 0 bbls to B-50, total= 0 bbls Daily losses to formation 6 bbls, total= 6 bbls 10/25/2016 Continue RIH with 9 5/8 surface casing f/ 7787' 8658'on deoth oWmoina 5japm, 320 psi, 25k torq on string with slight rotation. S/O 50-75k. Unable to obtain P/U wt.;Condition mud for cement job, Stage pump to 6 bpm, 250 psi CBU 1 1/2 times, final MW 9.4 ppg, 53 vis, 19 YP. R/D Power tongs and remove from rig floor. Cementers ares otted and R/U.'R/D Volant running tool, DSM witness loading plug in cement head. R/U cement head and lines. Clean rock washer pit.;Circulate 6 bpm, 320 psi, empty pits 2 & 4 to make room for displacement volume.;PJSM with Halliburton Cementers.;Perform cmtjob as follows: Pump 10 bbls FW, Pressure test lines to 4000 psi, Pump 48 bbls of spacer at 10.5 ppg @ 5 BPM, Drop by pass plug w/last 2 bbls spacer. �p f Shut down and load shut off plug.;Mix and pumg,935 sxs (395 bbls) of class G Lead Cement, at 11.7 ppy. Mix and pump 400 sxs (83 bbls) of class G Tail Cement at 15.8 ppq. Drop Shut off Plug.,Displace cmt w/ 20 bbis FW f/ Cmt Unit, turn over to rig, Pump 370 bbls, 9.3 ppg mud 80 bbls FW 5 � ✓ , l p! 158.5 bbls 9.3 ppg mud. Total Displacement @ 628.5 bbls.;Bump plug with 500 psi over final circulating pressure. Bleed off pressure with 3 bbls back. Floats held. `0 CIP @ 17:50. Load Closing Plug.;Using rig pump, stage pressure up 2870 psi to open ES Cementer. Circulate Btm Up bringinc 50 bbls spacer and 95 bbls cement udL1 st Stage Details: 90% returns through out job. Pump Cement @ 5 BPM Average. Pump Displacement @ 5.5 BPM Average. Calculated Displacement 627 bbl, Actual Displacement 628.5 bbl.;Final circulation pressure 880 psi @ 3 bpm. Lost estimated 52 bbls during job. CIP @ 17:50 hrs.;Continue circulate through ES Cementer while prepping for 2nd stage Cement job, Clean rock washer pit, flush riser and flow line with black water, condition mud for 2nd stage. Empty pits 1-2;DSM witness closing plug installed. Drain stack, flush diverter with fresh water. Vac trucks unloading @ G & I . Fuel cement unit. W/O cement.;PJSM, with cementers and crews;Mix & pump 60 bbl of Tuned Spacer III 10.5 PPG. Swap to Lead Mix & Pump 300 bbl @ 10 7 oog Lead 39Q Sx Mi d push observed at the shakers. Divert to rock washer pits.;Swap to tail, Mix & pum 6� -7.5 bbls of 15.8 ppq 325 sx.DrQp closing plug, pump 2 bbl on top of plug & chase with 20 bbl of 1-12o. Swap to rig & displace with 9.3 ppg mud @ 5 bpm.;Slow down pump to 3 bpm @ 157 bbl & bump plug @ 174.6 bbl away. (2.6 bbl early) e Final lift psi @ 640 psi @ 3 bpm. Pressure up to 1660 psi & shift ES cmt tool. Hold for 5 min. Bleed off 1.25 bbl.;No flow. Good. Total cmt returned to surface 224.5 bbl + 60 bbl spacer. 640 Final lift presure. 10/26/2016 R/D diverter line, continue to clean pits.,Raise up diverter stack, prep and set emergency slips with 150k on slips, slack off -Welder make casing rough cut and remove cut it, pull riser. L/D bell nipple, R/D diverter, tee and Knife valve.;Prep 9 5/8" casing and make final cut, total cut jt= (37.91') Install spool and adaptor spool, continue cleaning pits.;Mobilize equip to rig floor, Geo steer unit test plug / wear bushing.L/D surface riser, P/U BOP stack riser;R/U and test packoff per Wellhead rep to 500 psi low for 5 min, 2500 psi for 10 min, good test. Start loading pits w/ new 8.8 ppg BaraDrill-N drlg mud.,N/U 13 5/8" 5M dressed with 2 7/8 x 5 VBR in upper and lower cavity, blind ram in middle cavity.,Remove diverter and diverter tee from cellar, set tree in cellar. Continue Loading 5" drill pipe into pipe shed;R/U test equipment. Function test BOP components. Install test plug with 2 7/8" testjt.;PJSM, flood stack, lines and gas buster with fresh water, shell test BOPE to 3000 psi, good. Note: AOGCC rep Brian Bixby waived to witness BOP test on 10/26/16 @ 19:00 hrs.,Test BOPE using 2 7/8, 4 1/2' and 5" test its, test upper and lower VBR, annular, upper and lower IBOP, mud cross valves, choke man valves, 2 FOSV, 2 dart valves, blind ram;to 250 psi low, 3000 psi high 5 min ea. charted. Perform accumulator drawdown test, Perform hyd and manual choke bleed test. No failures., Hauled 1060 bbls to MPU G & I, total =8987 bbls Hauled 450 bbls from L -pad lake, total =7660 bbls. Hauled 0 bbls to B-50, total= 0 bbls Daily losses to formation 0 bbls total= 58 bbls 10/27/2016 Continue to test BOPE on 5" Pipe size -rform accumulator test. Test Gas Alarms. No failures on test., w down and rig down test equipment. Set 10" ID wear bushing.;PJSM. M/U C/O BHA: 8.5" VM -3 Tricone Bit, 7" Mud Mtr w/1.22 bend, Float Sub, 3 ea NMFC, 1 ea HWDP, Jars, 1 ea HWDP. Total BHA Length = 216.75;TIH from 216' to 21 00'picking up 5" NC -50 DP.;CBU and condition mud @ 7 bpm/450 psi/30 rpm/3-4 Tq/PUW 88K/SOW 70K/Rot 80K.;Blow down Top Drive, PJSM, Slip and cut 75" Drill Line, Service Top Drive and Blocks.;lnspect saver sub, Calibrate Top Drive.;Continue to single in w/ 5" DP f/ 2100' to 2571'.;Wash down pumping 450 gpm, 510 psi, f/ 2571' to 2602' setting down 10k tag closing plug. PU/SO/ROT 103/70/85, 50 RPM, 3-5K TQ.;Drill closing plug and ESC f/ 2602' to 2608', work thru ESC 3 times pumping and rotating, pass thru clean w/ pumps off.;Close annular, pressure test casing to 2700 psi to ensure integrity of ESC. Bleed off pressure, open annular.; Continue to single in w/ 5" DP f/ 2608' to 5304' RIH w/ stds from 5304' to 7945'. Filling pipe every 2500'. Note: P/U 120 jts 5" NC -50 DP then 42 jts DS-50.;Wash from 7945' pumping 150 gpm 500 psi tag TOC @ 8137'( 134' above BA) PU/SO/ROT 225/60/110, Note: considerable drag PU hole. Rack 1 std back for working room.;CBU @ 8130', Circulate out thick clabbered mud while reciprocating pipe slowly. seeing soft cmt @ shakers. Stage pumps f/ 150 gpm to 400 gpm 1200 psi;Rack 1 stand back parking @ 8039', blow down top drive, R/U head pin, close upper VBR, test 9 5/8 casing to 3000 psi for 30 min charted. Good test.;Bleed off pressure slowly, open upper VBR. 7 bbls pumped, 7 bbls bled back. Blow down choke manifold and line .;M/U 2 stands, wash and ream pumping 500 gpm, 1450 psi, 50 rpm, 20-22k TQ cleaning up cement stringers f/ 8137' to 8271', drill BA f/ 8271' to 8733'.; ill cement f/ 8273' to 8313', drill float collar @ 8313', drill cement f/ 8315' to 8356' drill shoe @ 8356' Note: seeing plug rubber @ shakers.;Hauled 164 bbls to MPU G & I, total =9151 bbls .� Hauled from 225 bbls L -pad lake, total =7885 bbls. Hauled 0 bbls to B-50, total= 0 bbls Daily losses to formation 0 bbls, total= 58 bbls 10/28/2016 Drl FE & Cmt to 8363'. Drl 20' of new hole to 8383'w/450 GPM/1320 PSI/60 RPM/18-20K Tq/ 5-10 WOB.;CBU @ 450 GPM/1320 PSI/60 RPM/19-21 Tq. Displace Spud Mud with 8.8 ppg Baradrilt system. Continue circulate 8.8 in/out.; Perform FIT Test to 12.0 ppq EMW with 675 psi surface pressure and 8.8 MW @ 4046' Shoe TVD. Pump 2.1 bbls with 1 bbl back. Good Test. Blow down and rig down test equipment.;Get SPR, Flow check well, no flow. Pump Slug, blow down Top Drive, line up on trip tank.;POOH on elevators from 8322' to 215'. Work BHA, lay down Mud Mtr and Bit, grade= 2/2/WT/A/E/1/BHA Correct displacement on trip out.;Clear rig floor, mobilize tools to rig floor.;M/U BHA #3, 8 1/2" HYC SK616M-J1 D bit, Geopilot, DGR, PWD, ILS, ADR, DM, download MWD data, M/U TM, FS, 3 NMFCs, 1 HWDP, jars, 1 HWDP= 273.32',;Shallow test Geo -pilot, good test, blow down top drive.;TIH f/ 273' to 2140', fill pipe, test Geo -pilot, good test. Blow down top drive. TIH f/ 2140' to 3920', no issues passing ESC @ 2601'.;TIH f/ 3920' to 8285' above casing shoe filling pipe every 2500' Note: correct displacement on trip in the hole;Break circulation, test Geo -pilot, good. CBU pumping 450 gpm, 1130 psi. PU 235K, SO 70K, ROT 125K, SPR 496 gpm, 1340 psi, 60 rpm 19K TQ.;Ream shoe track due to under gauge C/O bit, wash and ream f/ 8358' to bttm @ 8383', no fill.;Drilling 8 1/2" hole f/ 8383' to 8443' 80' AROP 45 FPH 550 gpm, 1500 psi, 80 rpm 17-19K TQ. MW 9.7+, VIS 40, ECD 9.8;Hauled 1056 bbls to MPU G & I, total =10207 bbls Hauled 300 bbls from L -pad lake, total =8185 bbls. Hauled 0 bbls to B-50, total= 0 bbls Daily losses to formation 0 bbls, total= 58 bbls 10/29/2016 Drilling 8 1/2" hole f/ 8443' to 9038' (595') AROP 99.2 FPH 550 gpm, 1620 psi, 80 rpm 18-20K TQ. MW 8.8+, VIS 40, ECD 10.5 WOB 10-12K;Pump to vis sweep at 8940' with no change in cuttings at shaker. Max Gas 8330', increase MW to 9 ppg.;Drilling 8 1/2" hole f/ 9038' to 9605' (567') AROP 95 FPH, drill concretions f/ 9175' to 9183' 550 gpm, 1620 psi, 80 rpm 18-20K TQ. MW 8.8+, VIS 40, ECD 10.5 WOB 10-12K;Pump to vis sweep at 9511', back @ calc stks with 10% increase at shaker.; Drilling 8 1/2" hole f/ 9605' to 10005' (400') AROP 67 FPH, Max gas 9069u @ 10234' 560 gpm, 1900 psi, 80 rpm 20-22K TQ. MW 8.9+, VIS 42, ECD 10.3 WOB 8-12K;Current BHL appears to be about 7-8' TVD below the OA3 top - estimated local formation dip is about 89.2°, currently aiming for 89.50 Drill concretions 9712'- 9720', 9829'- 9846', 9958'-9963'; Drilling 8 1/2" hole f/ 10005' to 10300' (295') AROP 49 FPH, 560 gpm, 1900 psi, 100 rpm 23-25K TQ. PU/SO/ROT 300/75/123 MW 9, VIS 41, ECD 10.3 WOB 8-12K;Drill concretions 10005'-10010', 10082'-10087', 10261'- 10271' Pump Io vis sweep at 10070', back @ calc stks with 10% increase at shakers. 25.2' below the line, 18.6' Ieft.;Note: concretion @ 10261' stalled top drive while drilling w/ 20K over to pull free.;Hauled 171 bbls to MPU G & I, total =10378 bbls Hauled 450 bbls from L -pad lake, total =8635 Wis. Hauled 0 bbls to B-50, total= 0 bbls Daily losses to formation 0 bbls, total= 58 bbls 10/30/2016 Drilling 8 1/2" hole f/ 10300' to 10547' (247') AROP 41 FPH, 560 gpm, 1850 psi, 80-100 rpm 23-25K TQ. PU/SO/ROT 290/0/121 MW 9, VIS 41, ECD 10.4 WOB 8-12K; Concretions @ 10005 to 10010/10082 to 10087/10233 to 10239/10399 to 10408/10496 to 10475 Pump low vis sweep @ 10075 w/10% increase @ shakers. Adjust parameters as needed to drill concretions.; Drilling 8 1/2" hole f/ 10547' to 11000' (453') AROP 75 FPH, 560 gpm, 1850 psi, 80-100 rpm 23-25K TQ. PU/SO/ROT 300/0/115 MW 9, VIS 42, ECD 10.4 WOB 8-12K; Drilling 8 1/2" hole f/ 11 000'to 11540' (540') AROP 90 FPH, 555 gpm, 1950 psi, 80-100 rpm 23-25K TQ. PU/SO/ROT 300/0/115 MW 9, VIS 41, ECD 10.69 WOB 8-12K;Concretions @ 11416-11423', 11463'-11467', 11516-11522' Pump low vis sweep @ 11019' w/10% increase @ shakers, mostly sand. Pump low vis sweep @ 11489'w/no increase @ shakers Max gas 9875u @ 11202';Ddiling 8 1/2" hole f/ 11540' to 12050' (510') AROP 85 FPH, 555 gpm, 1980 psi, 80-100 rpm 25-28K TQ. PU/SO/ROT 313/0/115 MW 9+, VIS 41, ECD 10.8 WOB 8-12K;Pump low vis sweep @ 11962'.;Current BHL appears to be about 7-8' TVD below the OA3 top - est local formation dip is about 90.7° - aiming f/ 90.5° Concretions @ 11581'-11587', 11670'- 11675'. 4.5' below the line, 5.7' Ieft;Hauled 461 bbls to MPU G & I, total =10839 bbls Hauled 750 bbls from L -pad lake, total =9285 bbls. Hauled 0 bbls to B-50, total= 0 bbls Daily losses to formation 28 bbls, total= 86 bbls 10/31/2016 Drilling 8 1/2" hole f/ 12050' to 12434 .4') AROP 64 FPH, 550 gpm, 2150 psi, 80-100 rpm 25-29K TQ. PU/SO/ROT 320/40/116 MW 9+, VIS 41, ECD 10.8 WOB 8-12K;Start adding 2% EZ Glide lubes @ 12150'. PUW dropped from 320K to 200K, Tq fell from 28-29K to 23-24K. Continue to maintain 2% lube while Encountered 71" Downthrown Fault @ 1237674080' TVD.; Pump 30 bbls Lo -Vis 9.0 ppg sweep @ 11 957'with 50% increase @ shakers. Mostly fine sands. Max gas 9866u @ 12410';Drilling 8 1/2" hole f/ 12434' to 12811' (377') AROP 62.8 FPH, 500 gpm, 1950 psi, 80-100 rpm 22-23K TQ. PU/SO/ROT 190 /60/110 MW 9.1, VIS 41, ECD 11.0 WOB 8-12K;Reaquire OA3 sand @ 12715' (Drilled 338' out of zone). Maintain 2% lube while drilling. Lost 6K Tq/130K PUW/and Obtained 60K SOW. PUW 190/SOW 60/TQ 23K @ 80-100 RPM; Drilling 8 1/2" hole f/ 12811' to 13167' (356') AROP 29.6 FPH, 550 gpm, 2230 psi, 80-100 rpm 22-23K TQ. PU/SO/ROT 190 /0/118 MW 9.1, VIS 42, ECD 11.0 WOB 8-12K;Concretions @ 12957-12965', 13010'-13028', 13047'-13055', 13095'-13139', 13155'-13167' Pump low vis sweep @ 12996', back on time w/ 15% increase @ shakers.; Drilling 8 1/2" hole f/ 13167' to 13472' (305') AROP 50.8 FPH, 450 gpm, 1690 psi, 80-100 rpm 22-23K TQ. PU/SO/ROT 190 /0/118 MW 9.1+, VIS 41, ECD 10.9 WOB 8-12K; Note: Crossed fault at 13352'MD/4139'TVD. Throw unknown at present but -30' downthrown is expected. Concretions, 13181'-13198', 13212'-13230', 13247'-13266' Currently 5.56' below the line, 28.1' Ieft.;Hauled 446 bbls to MPU G & 1, total =11285 bbls Hauled 750 bbls from L -pad lake, total =10035 bbls. Hauled 0 bbls to B-50, total= 0 bbls Daily losses to formation 0 bbls, total= 86 bbls 11/1/2016 Drilling 8 1/2" hole f/ 13472' to 13519' (47') AROP 50.8 FPH Section TD. 450 gpm, 1690 psi, 80-100 rpm 22-23K TQ. PU/SO/ROT 190 /0/118 MW 9.1+, VIS 41, ECD 10.9 WOB 8-12K; Encountered 49' downthrown fault @ 13352'/4139' TVD, which put the base of OA3 @ 8' TVD above the top of OA1. Continued to drill in attempt to reacquire formation.;Geologist Called TD @ 13519'/4125' TVD as the downthrown fault is likely in a different fault block to the adjacent Producer.;MD INC AZI TVD 13449.85 95.50 129.35 4131.79 Last actual Survey 13519.00 95.50 129.35 4125.16 Projection to TD. 10.79' High 23.55' Left at TD;CBU from 13519'. Pump Lo -Vis sweep to surface working pipe. 600 gpm/2530 psi/100 rpm/21 K Tq. Continue to circulate hole clean while changing screens to 200's.; Pump 30 bbls Hi -Vis Sweep and follow with 30 bbls Lo -Vis sweep @ 600 gpm /2500 psi/150 rpm/23K Tq. Sweeps back on time, Hi Vis w/20% Lo Vis/very little change.; Circulate additional bottoms up while maintain 2.5% lubes. Flow check well, Well static.;Pump out of the hole from 13519' to 13,074'. 400gpm/1250 psi/21 OK PUW. Encountering 30K over pulls.;Back Ream out of hole from 13074' to 8,750' MD. 600 gpm/2440 psi/80 rpm/18 Tq. Saw slight increase in psi (200 psi) indicating packing off or hole loading up while backreaming.;Circulate and condition hole @ 8,756' MD. Pump @ 600 gpm, w/ 2150 ICP and 1950 FCP. 10.4 ECD prior to cleanup cycle and 10.1 ECD after. 80 rpm, 8k tq. Hole unloaded 300% @ btms up (fine sand).;Hole unloaded for estimated 50 bbls. Saw max gas @ btm's up 5450 units. Circulated 1.5x btm's up.;Continue BROOH from 8,756' MD to 8373' MD. Reduce rotary to 40 rpm inside casing w/ BHA, 7k tq, 600 gpm, 1970 psi, 34% flow.;Circulate and condition mud @ 8,373' MD. Rotate and reciprocate pipe from 8,373' and to 8,300' MD. 600 gpm, 1920 psi, 40 rpm, 7k tq. Pulled clean into shoe.;Pump 24 bbl hi vis sweep then 30 bbl to vis sweep. Saw 200% increase @ sweep return w/ max gas @ 895 units (fine sand). Monitor well (static).; Pump dry job and drop rabbit on wire (2.3" OD). Blowdown top drive. Pull out of hole on elevators from 8,300' to 6,021' MD.; Continue trip out of hole on elevators from 6,021' to 273' MD. Hole took 15 bbls for trip.;UD HWDP, Jars and NM Flex DC's. Download MWD. Continue UD MWD and Geo -Pilot. B/O bit and UD same. Bit grade= 1,3,BT, N,X,I,WT,TD;Hauled 632 bbls to MPU G&I for total =11917 Hauled 0 bbls to B50 for total 0 bbls Hauled 450 bbls from L -Pad Lake for total = 10485 Daily losses to formation = 0 bbls for total 86 bbls Hilcorp Energy Company Composite Report Well Name: MP L-50 Field: North Slope County/State: , Alaska i (LAT/LONG): evation (RKB): API #: Spud Date: Job Name: 1511128C MP L-50 Completion Contractor AFE #: AFE $: Activity Date I Ops Summary 11/1/2016 Finish laying out tools from BHA and clear rig floor.,Make up 5" mule shoe and trip in hole from surface to 6424' with excess drill pipe out of derrick.,Circulate and condition mud @ 6424' MD. 600 gpm, 770 psi, 60 rpm, 4-6k tq. 140k up, 90k dn, 110k rot. Blowdown topdrive.,Continue trip in hole picking up single jts 5" HWDP out of shed from 6424' to 7915' MD. Drift HWDP w/ 2.35" rabbit.,Circulate string volume @ 7915' MD. 600 gpm, 1390 psi. Flowcheck (static). Pump dry job. Blowdown topdrive.,Pull out of hole racking back 16 stds of 5" HWDP in derrick from 7915' to 6424' MD.,Pull out of hole laying 5" drill pipe from 6424' to 188' MD. Sym ops - Continue load, prep and strap Iiner.,Cut and slip drilling line. Service TDS, Blocks. Inspect anchor, saver sub and drawworks.,Pull out of hole from 188' and laydown remaining drill pipe and mule shoe.,Clean and clear rig floor. Bring Weatherford casing tools to floor and rig up same. Prep for 4.5" liner run. M/U FOSV w/ XO.,PJSM, Run 4.5", 13.5#, HTTC, L-80 production liner as per detail from surface to 5055' MD. Fill pipe w/ brine while tripping in. Inpsect ICD's and swell packers (water swell) while running. Halliburton (Don Potter) and BOT (Briant Hacking) rep onsite during run. See details in "0" drive, tallys. Fill pipe w/ brine and tighten up shakers to 230's for trip in. hauled off excess mud and prep for upcoming displacement., Rig Fuel - 3000 gal, Fuel used - 600 gal, Fuel Rec'd - 0 gal Water - 375 bbls, Water used - 145 bbls, water rec'd - 0 bbls,Hauled 171 bbls to MPU G&I for total = 12088 bbls Hauled 0 bbls to 850 for total = 0 bbls Hauled 100 bbls from L -Pad Lake for total = 10585 bbls Daily losses to formation 10 bbls for total = 96 bbls 11/2/2016 Finish laying out tools from BHA. Clear rig floor.,Make up 5" mule shoe and trip in hole from surface to 6424' with excess drill pipe out of derrick.,Circulate and condition mud @ 6424' MD. 600 gpm, 770 psi, 60 rpm, 4-6k tq. 140k up, 90k dn, 110k rot. Blowdown topdrive.,Continue trip in hole picking up single jts 5" HWDP out of shed from 6424' to 7915' MD. Drift HWDP w/ 2.35" rabbit.,Circulate 1x string volume @ 7915' MD. 600 gpm, 1390 psi. Flowcheck (static). Pump dry job. Blowdown topdrive.,Pull out of hole from 7915' to 6424' MD racking back 16 stds 5" HWDP.,Trip out of hole from 6424' to 188' laying down 5" drill pipe. Sym ops - continue to prep, load and tally Iiner.,Cut and slip drilling line. Service TDS and blocks. Inspect anchor, saver sub and drawworks.,Conti nue pull out of hole laying down 5" drill pipe from 188' to surface.,Clean and clear rig floor. Bring WOT power tongs and handling equipment to rig floor. R/U same. M/U FOSV w/ XO. Verify running order and pipe count with BOT and Halliburton reps onsite.,PJSM. M/U shoe assy and run 4.5", 13.5# HTTC L-80 nroductiQnlipflr aner detail from surface to 5,012' MD (see "0" drive, Tallys). 8500 ft/lbs; make up tq. Fill pipe every 10 jts w/ brine during trip. Tighten shakers to 230's. Hauled offr� excess mud and prep for upcoming displacement., Rig Fuel - 3000 gal, Fuel used - 600 gal, Fuel rec'd - 0 gal Lv Water - 375 bbls, water used - 145 bbls, water rec'd - 0 bbls,Hauled 171 bbls to MPU G&I for total - 12088 bbls Hauled 0 bbls to B50 for total - 0 bbls Hauled 100 bbls from L -Pad lake for total - 10585 bbls Dailly losses to formation 10 bbls for total - 96 bbls. 11/3/2016 Ri down 4 1/2" Liner handling equipnment. Stage2 3/8 inner string tools an_d e uq ipment on rig floor, MU Triple connect with FOSV and 2 3/8" handling pup. Rig up 2 3/8" handling equipment.,Run 2 3/8" inner string. M/U slick stick. Run 162 jts 2-3/8" dp an 10.1' pup jt.,Make space out tag. Space out inner string. MU M/U Liner Baker HRD-E ZXPN LINER TOP PKR/HGR.,Wait on BOT rep for redress PPIT tool. Tool appeared to be partially shifted. Redressed for precautionary reasons prior to running PKR/HGR in hole.,M/U PKR/HGR w/ redressed PPIT tool. Verify 4 pins (1750 psi) liner hgr, 5 pins zxp (3287 psi), 11 pins for HR liner running tool (3700 psi). Neutral tool @ 4057 psi.,RIH F/ 5065' (total liner w/ running assy) to 8250' MD. Fill pipe every 10 (brine). 90 f /min max running speed. Pass ES cmtr clean w/ PKR/HGR.,Obtain parameters @ 8,250' MD. 1 bpm - 110 psi, 1.5 bpm- 130 psi, 2 bpm- 150 psi, 2.5 bpm - 220 psi, 3 bpm - 300 psi. 10 rpm -8k tq, 20 rpm -7k tq, 30 rpm -8k tq. 160k up, 94k dn.,Continue running 4.5" liner to final set depth of 13,170' MD. (70 stds dp, 16 stds HWDP + 16' on single). 90k dn, 240k up before displacement. Slack off past set depth and pull back up to set depth, leaving liner in tension.,PJSM, R/U and break circulation. Displace mud w/ 9.1 ppg 3% KCL brine. Lead w/ 40 bbl hi vis sweep. Follow w/ 3x 40 bbl sapp pills. Circulate on depth @ 4 bpm, 2250 psi, 17% flow.,Hauled 0 bbls to MPU G&I for total - 12088 bbls Hauled 0 bbls to B50 for total - 0 bbls Hauled 250 bbls from L -Pad Lake for total - 10835 bbls Daily losses to formation 9 bbls for total - 105 bbls,Rig Fuel - 5000 gal, Fuel Used - 800 gal, Fuel Recd - 2800 gal Rig Water - 400 bbls, Water Used - 75 bbls, Water Rec'd - 100 bbls Kick while tripping drill - 86 secs response for well secure 11/4/2016 Continue to Displace mud w/ 9.1 ppg ;,. ..CL brine. Bringing 40 bbl hi vis sweep and 3) 40 bbl sat., , As to surface. Increased flow rate to 4.5 bpm/3000 psi when 3rd SAPP out of OH annulus. 1 st pill brought back some wall cake and mostly fine sands. 2nd pill no wall cake with very little fines. Saw nothing on 3rd pill. Loss rate @ 28 bph while circulating., Drpn snd chase 1 '', ,ball on seat with 115 bbls A 3bpm/1600 psi Walk pressure up to 3670 psi. Hold 3670 psi for 5 , minutes. Step pressure up and hold 4200psi, hold 5 minutes. Bleed off pressure, slack off to 45K, PUH with break over @ 205K to verify release. ( Pumped total of 1,425 bbls 9.1 Brine on wellbore clean up cycle.),Rig up to test Liner top PKR. Line up kill line, close annular, pressure up to 1500 psi and test annulus to TOL PKR for 15 min, charted, good test.,P/U 15' and unsting from Pack off, bring on pump on @ 3 bpm, PUH washing 40', placing the 4" inner string cup assembly in the 9 5/8" casing just above liner top. Load tandem 20 bbl Hi Vis sweeps in pipe, increase pump rate to 5 bpm/4000 psi. Sweeps brought back trace wall cake and mostly fine sands. Continue to circulate until clean. (Pumped 810 bbls total on liner displacement), POOH from 13,091' to 5159' MD racking back 5" drill pipe. 3 bbl loss for trip. Perform kick while tripping drill (59 sec response for well secure).,R/U WOT double stack power tongs and handling equipment. Bring triple connect to floor and breakdown for xo's. M/U XO's w/ 5" safety jt and stage in pipe shed.,Pullout of hole laying down 2-3/8", 5.95# PH6 inner string F/ 5,159' to surface. Good indicators of setting tool properly shifting. B/O and laydown slick stick as per BOT.,R/U handling equipment for 5" drill pipe. TIH w15" mule shoe on 5" drill pipe from surface to 2156' MD. .,Hauled 1890 bbls to MPU G&I for total - 13978 bbls Hauled 0 bbis to B50 for total - 0 bbls Hauled 100 bbls from L -Pad Lake for total - 10935 bbls Daily losses to formation 0 bbls for total - 105 bbls 11/5/2016 Continue TIH w/ 5" mule shoe on 5" drill pipe from 2156' to 8094'. (20' above TOL),Break circulation, load 40 bbls Hi Vis Sweep in pipe, increase pump rate to 14 bpm/1350 psi, work pipe 90' rotating 80 rpm/12-15K Tq. Getting sands and clumps of wall cake back ahead of sweep. Sweep brought back large clumps and sands. Continue to circulate while mixing 2nd sweep @ 14 bpm with very little fines over shakers. Pump 2nd 40 bbl hi vis sweep @ 14 bpm working pipe. 2nd Sweep back with little to nothing back.,Pull out of hole laying down 5" drill pipe F/ 8094' to 5264' MD.,Trip in hole with remaining stands of drill pipe out of derrick from 5264' to 6395' MD. Pull out of hole laying down drill pipe from 6395' to surface.,Drain stack and pull wear bushing. Stage WOT for R/U.,Service drawworks, blocks and TDS.,R/U WOT handling equipment, double stack power tongs and prep pipe shed for tbg run. Verify pipe count (262 total jts).,PJSM, Attempt to start running tbg. Hardline on power tongs failed and developed a leak. Isolate power tongs and repair.,M/U seal assy (7.3" OD). Run 4.5", supermax, L-80, 12.6# tbg to 5997 ' MD. 3900 ft/lbs tq. Note: Daylight savings time adjustment (0:00 to 06:00 actually 7 hrs).,Hauled 57 bbls to MPU G&I for total = 13978' MD Hauled 0 bbls to 650 for total - 0 bbis Hauled 100 bbls from L -Pad Lake for total = 11035 bbls Dailly losses 32 bbls for total = 137 bbls Report time loss rate = 1 bph +/- 11/6/2016 rm x L-80, 12.6# tba from 5997'. Tag TOL with No -Go Sub @ 8128' w/20K Dn. Mule shoe depth @ 8138'. (Tagged TOL w/No-Go 20.50' in on Jt # 256. TOL 13' deep w/ Tbg Tally vs DP Tally),Close annular and pressure up to 500 psi to ensure No -Go seal engagement. Bleed off, open bag. Lay down jts 256,255,254. M/U 12.08' pups, P/U joint 254, M/U tubing hanger. XO tubing hanger to DP landing jt. Drain stack. Slack off on string, placing mule shoe and 1st and 2nd set of seals in SBR. Pump Dn Tbg to 200 psi. Make shut off Mark at floor, PUH until pressure dumped, exposing the ports on seal assembly to the IA.,Rig up to reverse circulate. Establish reverse circulation with fluid from mud pits through ported seal assembly @ 3 bpm, 100 psi. Line up on and pump 290 bbls Corrosion inhibited 9.1 ppg KCL and chase with 165 bbls DSL @ 4.5 bpm. FCP @ 490 psi. Pumps off with 250 psi. Strip in hole 4' to shut off mark .'Bleed off IA through choke, open bag, drain stack and flush pump lines via Vac Truck. Land out Tubing hanger @ 31.52 RKB placing Tie back seals 1.50' off no go. RILDS.,R/U injection line to IA. PT 9 5/8 x 4 1/2" IA to 3000 psi. Chart same,; Back out, break down and UD 5" DP landing joint. Set 4"'H' th BPV.,Blowdown choke, kill and hole fill lines. Drain stack. R/D lines from wellhead. Bleed down koomey. UD mousehole. PJSM, N/D BOP equipment, set back and secure for rig move.,N/U production tree. Test void 5k. Had leak on gland nut. Re-tq gland nuts and re -test. Test void 5k/10min (ok). Remove BPV. Install TWC and test tree 500 psi w/ 5 min hold, 5000 high w/ 10 min hold. Remove TWC.,Pre-heat diesel 90° (LRS). R/U LRS on tree. Freeze protect 4.5" tubing via bullhead @ 1.5 bpm, 700 ICP, 280 FCP with a total of 45 bbls pumped. R/D pump equipment and release LRS. Close all valves on wellhead and secure.,R/D utility lines and skid rig floor. Separate rockwasher from rig and stage on pad. R/D and remove 3rd party shacks. Notify Pad Operator of rig move off L-50 well. PJSM, Move rig off well and stage to mob down road. Rig released @ 06:00 hrs.,Hauled 404 bbls to MPU G&I for total = 14382 bbls Hauled 540 bbls to B50 for total = 540 bbls Hauled 0 bbls from L -Pad Lake for total = 11035 bbls Daily losses to formation 47 bbls for total = 184 bbls Rig/Camp went off Hi -line @ 15:00 hrs. Hilcorp Energy Company Milne Point MPtLPad MPL-50 50-029-23555-00-00 50-029-23555-00-00 Sperry Drilling Definitive Survey Report 07 November, 2016 HAlL.LIBURTON Sperry Drilling Company: Hilcorp Energy Company Project: Milne Point Site: M Pt L Pad Well: MPL-50 Wellbore: MPL-50 Design: MPL-50 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPL-50 MPL-50 @ 51.50usft (Doyon 14) MPL-50 @ 51.50usft (Doyon 14) True Minimum Curvature Sperry EDM - NORTH US + CANADA Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Design MPL-50 Audit Notes: 6,031,462.90 usft Latitude: 545,097.84 usft Longitude: usft Ground Level: Declination 18.05 Dip Angle (°) 81.06 70° 29'48.559 N 149° 37'52.3819 W 17.80 usft Field Strength (nT) 57,561 Version: 1.0 Well MPL-50, BP MPL-38 Slot ACTUAL Well Position +N/ -S 0.00 usft Northing: Vertical Section: +E/ -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore MPL-50 Magnetics Model Name Sample Date BGGM2016 10/15/2016 Design MPL-50 Audit Notes: 6,031,462.90 usft Latitude: 545,097.84 usft Longitude: usft Ground Level: Declination 18.05 Dip Angle (°) 81.06 70° 29'48.559 N 149° 37'52.3819 W 17.80 usft Field Strength (nT) 57,561 Version: 1.0 Phase: ACTUAL Tie On Depth: 33.70 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 33.70 0.00 0.00 165.00 Survey Program - - Date 11/7/2016 - --� From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 635.00 L-50 Gyro (MPL-50) SRG-SS Surface readout gyro single shot 10/07/2016 696.73 8,323.67 L-50 MWD+IFR2+MS+sag (1) (MPL-50) MWD+IFR2+MS+sag Fixed:v2:IIFR dec & 3 -axis correction + sag 10/19/2016 8,400.65 13,449.85 L-50 MWD+IFR2+MS+sag (2) (MPL-50) MWD+IFR2+MS+sag Fixed:v2:IIFR dec & 3 -axis correction + sag 10/30/2016 Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (I (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 33.70 0.00 0.00 33.70 -17.80 0.00 0.00 6,031,462.90 545,097.84 0.00 0.00 UNDEFINED 100.00 0.52 29.36 100.00 48.50 0.26 0.15 6,031,463.16 545,097.99 0.78 -0.22 SRG-SS (1) 168.00 1.03 47.95 167.99 116.49 0.94 0.75 6,031,463.84 545,098.59 0.83 -0.71 SRG-SS (1) 258.00 1.55 87.34 257.97 206.47 1.54 2.57 6,031,464.45 545,100.40 1.11 -0.82 SRG-SS (1) 349.00 3.35 125.08 348.89 297.39 0.07 5.97 6,031,463.00 545,103.81 2.56 1.48 SRG-SS(1) 446.00 3.96 136.69 445.69 394.19 -4.00 10.59 6,031,458.97 545,108.45 0.99 6.60 SRG-SS (1) 543.00 2.99 148.18 542.51 491.01 -8.59 14.22 6,031,454.40 545,112.11 1.23 11.97 SRG-SS (1) 635.00 7.59 177.43 634.11 582.61 -16.70 15.76 6,031,446.30 545,113.70 5.64 20.21 SRG-SS(1) 696.73 10.47 182.70 695.07 643.57 -26.38 15.68 6,031,436.62 545,113.68 4.85 29.54 MWD+IFR2+MS+sag (2) 790.97 15.07 189.97 786.96 735.46 -47.01 13.15 6,031,415.98 545,111.28 5.16 48.81 MWD+IFR2+MS+sag (2) 19.59 195.14 877.04 825.54 -74.38 6.89 6,031,388.57 545,105.18 5.05 73.63 MWD+IFR2+MS+sag (2) L885.35 979.97 23.64 - 200.16 964.99 913.49 -107.52 -3.79 6,031,355.37 545,094.70 4.70 102.87 MWD+IFR2+MS+sag (2) 1117/2016 5:46.-45PM Page 2 COMPASS 5000.1 Build 81 Company: Hilcorp Energy Company Project: Milne Point Site: M Pt L Pad Well: MPL-50 Wellbore: MPL-50 Design: MPL-50 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPL-50 MPL-50 @ 51.50usft (Doyon 14) MPL-50 @ 51.50usft (Doyon 14) True Minimum Curvature Sperry EDM - NORTH US + CANADA 11/7/2016 5:46:45PM Page 3 COMPASS 5000.1 Build 81 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) 0 (usft) (usft) (usft) (usft) (ft) (ft) (-/100') (ft) Survey Tool Name 1,074.38 27.37 207.18 1,050.21 998.71 -144.61 -20.24 6,031,318.18 545,078.48 5.08 134.45 MWD+IFR2+MS+sag (2) 1,168.37 32.09 211.65 1,131.81 1,080.31 -185.11 -43.22 6,031,277.54 545,055.74 5.54 167.62 MWD+IFR2+MS+sag (2) 1,262.87 35.69 212.20 1,210.25 1,158.75 -229.82 -71.09 6,031,232.67 545,028.15 3.82 203.59 MWD+IFR2+MS+sag (2) 1,357.10 41.48 213.22 1,283.87 1,232.37 -279.23 -102.86 6,031,183.08 544,996.68 6.18 243.09 MWD+IFR2+MS+sag (2) 1,451.36 46.36 213.74 1,351.75 1,300.25 -333.74 -138.93 6,031,128.35 544,960.95 5.19 286.41 MWD+IFR2+MS+sag (2) 1,545.64 50.26 213.05 1,414.44 1,362.94 -392.52 -177.67 6,031,069.35 544,922.58 4.17 333.16 MWD+IFR2+MS+sag (2) 1,640.26 54.45 213.42 1,472.22 1,420.72 -455.17 -218.72 6,031,006.46 544,881.90 4.44 383.05 MWD+IFR2+MS+sag (2) 1,734.13 57.70 213.01 1,524.60 1,473.10 -520.33 -261.38 6,030,941.05 544,839.65 3.48 434.95 MWD+IFR2+MS+sag (2) 1,828.68 63.06 212.30 1,571.32 1,519.82 -589.51 -305.70 6,030,871.60 544,795.75 5.71 490.30 MWD+IFR2+MS+sag (2) 1,923.26 62.81 213.56 1,614.35 1,562.85 -660.20 -351.49 6,030,800.65 544,750.40 1.22 546.73 MWD+IFR2+MS+sag (2) 2,017.86 64.05 213.07 1,656.67 1,605.17 -730.90 -397.95 6,030,729.67 544,704.37 1.39 603.00 MWD+IFR2+MS+sag(2) 2,111.57 65.92 212.87 1,696.29 1,644.79 -802.14 -444.16 6,030,658.15 544,658.59 2.00 659.85 MWD+IFR2+MS+sag (2) 2,205.52 64.94 212.99 1,735.36 1,683.86 -873.86 490.61 6,030,586.17 544,612.59 1.05 717.10 MWD+IFR2+MS+sag (2) 2,298.25 66.92 213.88 1,773.17 1,721.67 -944.51 -537.26 6,030,515.24 544,566.37 2.31 773.27 MWD+IFR2+MS+sag (2) 2,394.28 66.15 214.06 1,811.41 1,759.91 -1,017.56 -586.48 6,030,441.90 544,517.60 0.82 831.10 MWD+IFR2+MS+sag (2) 2,488.62 64.53 214.64 1,850.77 1,799.27 -1,088.34 -634.86 6,030,370.83 544,469.66 1.81 886.95 MWD+IFR2+MS+sag (2) 2,582.78 64.79 214.17 1,891.07 1,839.57 -1,158.56 -682.94 6,030,300.33 544,422.01 0.53 942.32 MWD+IFR2+MS+sag (2) 2,677.71 67.58 212.48 1,929.40 1,877.90 -1,231.12 -730.63 6,030,227.49 544,374.76 3.36 1,000.07 MWD+IFR2+MS+sag (2) 2,772.14 66.07 212.56 1,966.56 1,915.06 -1,304.32 -777.30 6,030,154.02 544,328.54 1.60 1,058.69 MWD+IFR2+MS+sag (2) 2,865.90 65.57 212.81 2,004.97 1,953.47 -1,376.31 -823.49 6,030,081.76 544,282.79 0.59 1,116.28 MWD+IFR2+MS+sag (2) 2,960.68 66.91 213.15 2,043.15 1,991.65 -1,449.07 -870.71 6,030,008.71 544,236.02 1.45 1,174.34 MWD+IFR2+MS+sag (2) 3,054.65 64.60 213.03 2,081.74 2,030.24 -1,520.85 -917.49 6,029,936.66 544,189.69 2.46 1,231.57 MWD+IFR2+MS+sag (2) 3,149.03 66.72 212.22 2,120.64 2,069.14 -1,593.27 -963.84 6,029,863.96 544,143.78 2.38 1,289.52 MWD+IFR2+MS+sag (2) 3,242.59 65.29 212.77 2,158.68 2,107.18 -1,665.37 -1,009.76 6,029,791.60 544,098.30 1.62 1,347.28 MWD+IFR2+MS+sag (2) 3,336.92 64.72 212.90 2,198.54 2,147.04 -1,737.20 -1,056.11 6,029,719.49 544,052.39 0.62 1,404.67 MWD+IFR2+MS+sag (2) 3,431.98 65.02 213.16 2,238.91 2,187.41 -1,809.36 -1,103.02 6,029,647.06 544,005.92 0.40 1,462.22 MWD+IFR2+MS+sag (2) 3,525.91 62.80 212.63 2,280.22 2,228.72 -1,880.18 -1,148.84 6,029,575.97 543,960.54 2.42 1,518.77 MWD+IFR2+MS+sag (2) 3,620.73 63.08 212.85 2,323.35 2,271.85 -1,951.21 -1,194.51 6,029,504.67 543,915.31 0.36 1,575.56 MWD+IFR2+MS+sag (2) 3,714.71 64.73 212.18 2,364.69 2,313.19 -2,022.38 -1,239.87 6,029,433.24 543,870.38 1.87 1,632.56 MWD+IFR2+MS+sag (2) 3,809.62 65.17 212.87 2,404.88 2,353.38 -2,094.87 -1,286.10 6,029,360.47 543,824.60 0.81 1,690.62 MWD+IFR2+MS+sag (2) 3,902.23 65.53 212.06 2,443.50 2,392.00 -2,165.89 -1,331.28 6,029,289.19 543,779.85 0.88 1,747.53 MWD+IFR2+MS+sag (2) 3,997.67 66.88 212.59 2,482.01 2,430.51 -2,239.68 -1,377.98 6,029,215.12 543,733.61 1.50 1,806.72 MWD+IFR2+MS+sag (2) 4,092.07 64.90 213.35 2,520.57 2,469.07 -2,311.97 -1,424.86 6,029,142.56 543,687.17 2.22 1,864.41 MWD+IFR2+MS+sag (2) 4,186.32 66.07 213.16 2,559.67 2,508.17 -2,383.67 -1,471.88 6,029,070.57 543,640.59 1.25 1,921.50 MWD+IFR2+MS+sag (2) 4,281.09 65.85 213.23 2,598.28 2,546.78 -2,456.10 -1,519.27 6,028,997.87 543,593.65 0.24 1,979.20 MWD+IFR2+MS+sag (2) 4,375.09 65.60 213.33 2,636.93 2,585.43 -2,527.74 -1,566.29 6,028,925.95 543,547.07 0.28 2,036.22 MWD+IFR2+MS+sag (2) 4,469.02 64.26 214.48 2,676.73 2,625.23 -2,598.35 -1,613.74 6,028,855.06 543,500.05 1.81 2,092.15 MWD+IFR2+MS+sag (2) 4,563.63 65.37 214.54 2,716.99 2,665.49 -2,668.90 -1,662.25 6,028,784.23 543,451.98 1.17 2,147.74 MWD+IFR2+MS+sag (2) 4,657.74 66.89 213.58 2,755.07 2,703.57 -2,740.19 -1,710.44 6,028,712.65 543,404.22 1.87 2,204.13 MWD+IFR2+MS+sag (2) 4,752.24 67.90 211.49 2,791.40 2,739.90 -2,813.74 -1,757.35 6,028,638.82 543,357.76 2.30 2,263.03 MWD+IFR2+MS+sag (2) 11/7/2016 5:46:45PM Page 3 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-50 Project: Milne Point TVD Reference: MPL-50 @ 51.50usft (Doyon 14) Site: M Pt L Pad MD Reference: MPL-50 @ 51.50usft (Doyon 14) Well: MPL-50 North Reference: True Wellbore: MPL-50 Survey Calculation Method: Minimum Curvature Design: MPL-50 Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +WS +E1 -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 4,846.97 65.31 212.53 2,829.01 2,777.51 -2,887.46 -1,803.42 6,028,564.83 543,312.14 2.91 2,322.31 MWD+IFR2+MS+sag (2) 4,941.49 65.88 212.70 2,868.06 2,816.56 -2,959.96 -1,849.82 6,028,492.06 543,266.19 0.62 2,380.34 MWD+IFR2+MS+sag (2) 5,035.23 65.86 213.27 2,906.38 2,654.88 -3,031.72 -1,896.39 6,028,420.03 543,220.06 0.56 2,437.59 MWD+IFR2+MS+sag (2) 5,130.30 64.54 214.14 2,946.26 2,894.76 -3,103.52 -1,944.28 6,028,347.95 543,172.62 1.62 2,494.55 MWD+IFR2+MS+sag (2) 5,224.74 66.32 213.31 2,985.53 2,934.03 -3,174.95 -1,991.96 6,028,276.24 543,125.37 2.05 2,551.21 MWD+IFR2+MS+sag (2) 5,319.39 64.71 213.51 3,024.76 2,973.26 -3,246.85 -2,039.39 6,028,204.05 543,078.39 1.71 2,608.39 MWD+IFR2+MS+sag (2) 5,413.38 65.93 214.37 3,064.00 3,012.50 -3,317.70 -2,087.07 6,028,132.92 543,031.14 1.54 2,664.48 MWD+IFR2+MS+sag (2) 5,507.45 65.95 215.06 3,102.35 3,050.85 -3,388.31 -2,135.99 6,028,062.03 542,982.66 0.67 2,720.02 MWD+IFR2+MS+sag (2) 5,602.18 66.54 213.01 3,140.52 3,089.02 -3,460.15 -2,184.51 6,027,989.89 542,934.58 2.08 2,776.86 MWD+IFR2+MS+sag (2) 5,696.64 66.55 211.08 3,178.12 3,126.62 -3,533.60 -2,230.48 6,027,916.18 542,889.05 1.87 2,835.91 MWD+IFR2+MS+sag (2) 5,790.64 64.94 212.28 3,216.73 3,165.23 -3,606.53 -2,275.49 6,027,842.98 542,844.50 2.07 2,894.70 MWD+IFR2+MS+sag (2) 5,885.16 66.14 212.47 3,255.87 3,204.37 -3,679.19 -2,321.55 6,027,770.05 542,798.88 1.28 2,952.97 MWD+IFR2+MS+sag (2) 5,979.56 65.72 213.27 3,294.37 3,242.87 -3,751.59 -2,368.33 6,027,697.38 542,752.54 0.89 3,010.79 MWD+IFR2+MS+sag (2) 6,073.58 65.73 213.92 3,333.02 3,281.52 -3,822.98 -2,415.75 6,027,625.71 542,705.56 0.63 3,067.47 MWD+IFR2+MS+sag (2) 6,167.48 65.53 214.47 3,371.77 3,320.27 -3,893.72 -2,463.83 6,027,554.68 542,657.92 0.57 3,123.36 MWD+IFR2+MS+sag (2) 6,262.38 67.38 214.09 3,409.68 3,358.18 -3,965.61 -2,512.82 6,027,482.51 542,609.37 1.98 3,180.12 MWD+IFR2+MS+sag (2) 6,355.22 66.16 211.61 3,446.30 3,394.80 4,037.27 -2,559.10 6,027,410.58 542,563.53 2.78 3,237.36 MWD+IFR2+MS+sag (2) 6,451.03 66.69 208.32 3,484.63 3,433.13 4,113.33 -2,602.95 6,027,334.25 542,520.15 3.20 3,299.48 MWD+IFR2+MS+sag (2) 6,545.00 65.60 205.29 3,522.64 3,471.14 -4,190.02 -2,641.71 6,027,257.34 542,481.86 3.17 3,363.53 MWD+IFR2+MS+sag (2) 6,638.74 66.45 203.18 3,560.73 3,509.23 4,268.12 -2,676.86 6,027,179.04 542,447.19 2.25 3,429.87 MWD+IFR2+MS+sag (2) 6,734.08 66.00 199.36 3,599.18 3,547.68 4,349.40 -2,708.51 6,027,097.57 542,416.03 3.70 3,500.19 MWD+IFR2+MS+sag (2) 6,828.23 67.40 195.26 3,636.43 3,584.93 4,431.94 -2,734.21 6,027,014.89 542,390.83 4.27 3,573.26 MWD+IFR2+MS+sag (2) 6,922.62 67.47 190.62 3,672.67 3,621.17 -4,516.86 -2,753.72 6,026,929.86 542,371.84 4.54 3,650.24 MWD+IFR2+MS+sag (2) 7,017.22 65.67 187.35 3,710.29 3,658.79 4,602.57 -2,767.29 6,026,844.07 542,358.79 3.70 3,729.52 MWD+IFR2+MS+sag (2) 7,111.59 67.00 182.77 3,748.19 3,696.69 4,688.64 -2,774.90 6,026,757.97 542,351.71 4.66 3,810.68 MWD+IFR2+MS+sag (2) 7,205.71 68.57 176.94 3,783.80 3,732.30 4,775.72 -2,774.65 6,026,670.90 542,352.48 5.97 3,894.66 MWD+IFR2+MS+sag (2) 7,299.91 67.56 173.03 3,819.00 3,767.50 4,862.75 -2,767.02 6,026,583.93 542,360.64 4.00 3,980.89 MWD+IFR2+MS+sag (2) 7,395.24 70.55 167.84 3,853.09 3,801.59 4,950.49 -2,752.20 6,026,496.29 542,375.99 5.97 4,069.48 MWD+IFR2+MS+sag (2) 7,489.35 72.86 161.24 3,882.66 3,831.16 -5,036.53 -2,728.36 6,026,410.40 542,400.35 7.10 4,158.77 MWD+IFR2+MS+sag (2) 7,583.47 73.12 154.48 3,910.22 3,858.72 -5,119.84 -2,694.46 6,026,327.31 542,434.75 6.87 4,248.01 MWD+IFR2+MS+sag (2) 7,678.27 72.75 150.31 3,938.05 3,886.55 -5,200.13 -2,652.48 6,026,247.28 542,477.21 4.22 4,336.43 MWD+IFR2+MS+sag (2) 7,772.28 76.21 146.60 3,963.21 3,911.71 -5,277.29 -2,605.09 6,026,170.42 542,525.07 5.29 4,423.22 MWD+IFR2+MS+sag (2) 7,866.25 78.30 137.29 3,983.99 3,932.49 -5,349.35 -2,548.64 6,026,098.71 542,581.95 9.91 4,507.44 MWD+IFR2+MS+sag (2) 7,961.41 79.66 131.32 4,002.19 3,950.69 -5,414.55 -2,481.82 6,026,033.92 542,649.15 6.32 4,587.71 MWD+IFR2+MS+sag (2) 8,055.78 81.941 26.39 4,017.29 3,965.79 -5,472.96 -2,409.30 6,025,975.96 542,722.02 5.69 4,662.90 MWD+IFR2+MS+sag (2) 8,149.57 84.14 123.68 4,028.66 3,977.16 -5,526.39 -2,333.08 6,025,923.00 542,798.56 3.71 4,734.24 MWD+IFR2+MS+sag (2) 8,244.40 83.62 123.47 4,038.77 3,987.27 -5,578.54 -2,254.52 6,025,871.33 542,877.42 0.59 4,804.94 MWD+IFR2+MS+sag (2) 8,323.67 87.46 124.60 4,044.93 3,993.43 -5,622.76 -2,189.04 6,025,827.51 542,943.16 5.05 4,864.61 MWD+IFR2+MS+sag (2) 8,400.65 86.79 122.28 4,048.79 3,997.29 -5,665.13 -2,124.89 6,025,785.54 543,007.56 3.13 4,922.13 MWD+IFR2+MS+sag (3) 8,494.59 84.31 123.38 4,056.08 4,004.58 -5,715.90 -2,046.20 6,025,735.25 543,086.55 2.89 4,991.54 MWD+IFR2+MS+sag (3) 11/7/2016 5:46:45PM Page 4 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPL-50 Project: Milne Point TVD Reference: MPL-50 @ 51.50usft (Doyon 14) Site: M Pt L Pad MD Reference: MPL-50 @ 51.50usft (Doyon 14) Well: MPL-50 North Reference: True Wellbore: MPL-50 Survey Calculation Method: Minimum Curvature Design: MPL-50 Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 8,590.66 85.12 123.41 4,064.93 4,013.43 -5,768.55 -1,966.33 6,025,683.09 543,166.73 0.84 5,063.07 MWD+IFR2+MS+sag (3) 8,685.69 86.67 124.59 4,071.73 4,020.23 -5,821.55 -1,887.76 6,025,630.57 543,245.62 2.05 5,134.60 MWD+IFR2+MS+sag (3) 8,780.25 87.22 124.78 4,076.77 4,025.27 -5,875.29 -1,810.11 6,025,577.32 543,323.58 0.62 5,206.60 MWD+IFR2+MS+sag (3) 8,874.14 87.41 124.37 4,081.17 4,029.67 -5,928.51 -1,732.89 6,025,524.57 543,401.12 0.48 5,277.99 MWD+IFR2+MS+sag (3) 8,967.71 87.59 124.40 4,085.25 4,033.75 -5,981.30 -1,655.74 6,025,472.25 543,478.58 0.20 5,348.96 MWD+IFR2+MS+sag (3) 9,062.62 89.07 125.23 4,088.02 4,036.52 -6,035.46 -1,577.86 6,025,418.57 543,556.78 1.79 5,421.43 MWD+IFR2+MS+sag (3) 9,157.08 89.20 125.52 4,089.44 4,037.94 -6,090.14 -1,500.85 6,025,364.36 543,634.12 0.34 5,494.18 MWD+IFR2+MS+sag (3) 9,251.52 89.08 125.70 4,090.86 4,039.36 -6,145.13 -1,424.07 6,025,309.85 543,711.21 0.23 5,567.16 MWD+IFR2+MS+sag (3) 9,344.99 88.15 125.55 4,093.12 4,041.62 -6,199.55 -1,348.12 6,025,255.89 543,787.49 1.01 5,639.39 MWD+IFR2+MS+sag (3) 9,439.40 88.40 127.17 4,095.96 4,044.46 -6,255.50 -1,272.13 6,025,200.41 543,863.81 1.74 5,713.10 MWD+IFR2+MS+sag (3) 9,532.90 89.75 128.39 4,097.47 4,045.97 -6,312.77 -1,198.24 6,025,143.60 543,938.03 1.95 5,787.54 MWD+IFR2+MS+sag (3) 9,628.65 89.14 127.97 4,098.40 4,046.90 -6,371.95 -1,122.98 6,025,084.88 544,013.65 0.77 5,864.18 MWD+IFR2+MS+sag (3) 9,723.35 88.89 126.91 4,100.03 4,048.53 -6,429.51 -1,047.80 6,025,027.78 544,089.17 1.15 5,939.24 MWD+IFR2+MS+sag (3) 9,817.58 88.71 125.69 4,102.00 4,050.50 -6,48529 -971.88 6,024,972.47 544,165.42 1.31 6,012.76 MWD+IFR2+MS+sag (3) 9,911.88 88.40 123.35 4,104.38 4,052.88 -6,538.70 -894.21 6,024,919.53 544,243.40 2.50 6,084.46 MWD+IFR2+MS+sag (3) 10,006.42 89.57 122.19 4,106.05 4,054.55 -6,589.87 -814.73 6,024,868.86 544,323.18 1.74 6,154.45 MWD+IFR2+MS+sag (3) 10,100.26 89.69 120.74 4,106.66 4,055.16 -6,638.85 -734.69 6,024,820.37 544,403.51 1.55 6,222.48 MWD+IFR2+MS+sag (3) 10,193.73 89.75 121.84 4,107.11 4,055.61 -6,687.39 -654.82 6,024,772.31 544,483.66 1.18 6,290.04 MWD+IFR2+MS+sag (3) 10,288.41 90.74 125.26 4,106.71 4,055.21 -6,739.71 -575.93 6,024,720.48 544,562.87 3.76 6,361.00 MWD+IFR2+MS+sag (3) 10,382.75 89.57 125.86 4,106.45 4,054.95 -6,794.57 499.18 6,024,666.09 544,639.93 1.39 6,433.85 MWD+IFR2+MS+sag (3) 10,476.98 88.77 125.75 4,107.82 4,056.32 -6,849.69 -422.77 6,024,611.44 544,716.67 0.86 6,506.87 MWD+IFR2+MS+sag (3) 10,572.08 88.46 126.01 4,110.12 4,058.62 -6,905.41 -345.74 6,024,556.19 544,794.03 0.43 6,580.63 MWD+IFR2+MS+sag (3) 10,667.29 88.77 125.84 4,112.42 4,060.92 -6,961.26 -268.66 6,024,500.82 544,871.44 0.37 6,654.52 MWD+IFR2+MS+sag (3) 10,761.12 91.36 126.02 4,112.31 4,060.81 -7,016.31 -192.69 6,024,446.23 544,947.74 2.77 6,727.36 MWD+IFR2+MS+sag (3) 10,855.49 92.22 127.36 4,109.36 4,057.86 -7,072.67 -117.06 6,024,390.34 545,023.70 1.69 6,801.37 MWD+IFR2+MS+sag (3) 10,950.08 91.85 128.49 4,106.01 4,054.51 -7,130.77 -42.49 6,024,332.70 545,098.61 1.26 6,876.79 MWD+IFR2+MS+sag (3) 11,043.84 92.04 130.29 4,102.82 4,051.32 -7,190.23 29.93 6,024,273.69 545,171.38 1.93 6,952.97 MWD+IFR2+MS+sag (3) 11,138.14 91.67 129.82 4,099.77 4,048.27 -7,250.88 102.07 6,024,213.48 545,243.88 0.63 7,030.23 MWD+IFR2+MS+sag (3) 11,232.60 91.48 126.90 4,097.17 4,045.67 -7,309.47 176.10 6,024,155.34 545,318.26 3.10 7,105.99 MWD+IFR2+MS+sag (3) 11,326.91 90.93 124.85 4,095.19 4,043.69 -7,364.73 252.50 6,024,100.56 545,394.99 2.25 7,179.13 MWD+IFR2+MS+sag (3) 11,421.13 91.79 125.19 4,092.95 4,041.45 -7,418.78 329.64 6,024,046.98 545,472.45 0.98 7,251.31 MWD+IFR2+MS+sag (3) 11,515.84 91.73 125.85 4,090.05 4,038.55 -7,473.78 406.69 6,023,992.46 545,549.82 0.70 7,324.37 MWD+IFR2+MS+sag (3) 11,609.70 91.36 125.70 4,087.51 4,036.01 -7,528.63 482.81 6,023,938.07 545,626.27 0.43 7,397.06 MWD+IFR2+MS+sag (3) 11,704.49 90.49 124.36 4,085.98 4,034.48 -7,583.03 560.42 6,023,884.15 545,704.19 1.69 7,469.69 MWD+IFR2+MS+sag (3) 11,798.60 91.23 124.23 4,084.57 4,033.07 -7,636.05 638.15 6,023,831.61 545,782.25 0.80 7,541.03 MWD+IFR2+MS+sag (3) 11,893.15 90.43 123.69 4,083.20 4,031.70 -7,688.86 716.57 6,023,779.28 545,860.97 1.02 7,612.33 MWD+IFR2+MS+sag (3) 11,986.64 90.49 125.45 4,082.45 4,030.95 -7,741.91 793.55 6,023,726.71 545,938.26 1.88 7,683.49 MWD+IFR2+MS+sag (3) 12,081.70 90.43 124.77 4,081.69 4,030.19 -7,796.58 871.31 6,023,672.51 546,016.34 0.72 7,756.43 MWD+IFR2+MS+sag (3) 12,175.34 88.58 119.05 4,082.50 4,031.00 -7,846.05 950.76 6,023,623.53 546,096.08 6.42 7,824.78 MWD+IFR2+MS+sag (3) 12,269.61 90.25 117.41 4,083.46 4,031.96 -7,890.64 1,033.80 6,023,579.45 546,179.39 2.48 7,889.34 MWD+IFR2+MS+sag (3) 11/7/2016 5 46:45PM Page 5 COMPASS 5000.1 Build 81 Company: Hilcorp Energy Company Project: Milne Point Site: M Pt L Pad Well: MPL-50 Wellbore: MPL-50 Design: MPL-50 Survey Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPL-50 MPL-50 @ 51.50usft (Doyon 14) MPL-50 @ 51.50usft (Doyon 14) True Minimum Curvature Sperry EDM - NORTH US + CANADA 13,519.00 95.50 129.35 4,125.16 4,073.66 -8,608.99 2,044.85 6,022,867.31 547,194.68 0.00 Vertical Section (ft) Survey Tool Name 7,952.21 MWD+IFR2+MS+sag (3) 8,017.11 MWD+IFR2+MS+sag (3) 8,081.87 MWD+IFR2+MS+sag (3) 8,148.30 MWD+IFR2+MS+sag (3) 8,217.48 MWD+IFR2+MS+sag (3) 8,289.69 MWD+IFR2+MS+sag (3) 8,363.58 MWD+IFR2+MS+sag (3) 8,440.45 MWD+IFR2+MS+sag (3) 8,518.99 MWD+IFR2+MS+sag (3) 8,597.15 MWD+IFR2+MS+sag (3) 8,674.44 MWD+IFR2+MS+sag (3) 8,750.99 MWD+IFR2+MS+sag (3) 8,788.96 MWD+IFR2+MS+sag (3) 8,844.89 PROJECTED to TD Mitch Laird r °oc tliw,P tmoa-iQO,;;un benjamin.hand@haliiburtoo.com Checked By: S -et Manager -- _ _ Approved By: 2016.11.0716:45:29-09'W Date: 11/712016 5:46:45PM Page 6 COMPASS 5000.1 Build 81 Map Map MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS (usft)(*) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') 12,363.05 89.69 117.17 4,083.51 4,032.01 -7,933.48 1,116.84 6,023,537.12 546,262.68 0.65 12,459.28 86.42 117.72 4,086.78 4,035.28 -7,977.80 1,202.18 6,023,493.32 546,348.28 3.45 12,553.69 82.57 119.43 4,095.83 4,044.33 -8,022.73 1,284.69 6,023,448.89 546,431.05 4.46 12,647.97 80.58 121.43 4,109.65 4,058.15 -8,069.96 1,365.10 6,023,402.16 546,511.74 2.98 12,742.28 83.38 124.18 4,122.80 4,071.30 -8,120.55 1,443.58 6,023,352.05 546,590.51 4.14 12,836.96 84.44 126.01 4,132.85 4,081.35 -8,174.68 1,520.60 6,023,298.40 546,667.86 2.22 12,931.19 86.67 127.72 4,140.15 4,088.65 -8,231.03 1,595.75 6,023,242.50 546,743.34 2.98 13,025.76 89.57 131.15 4,143.26 4,091.76 -8,291.06 1,668.73 6,023,182.93 546,816.68 4.75 13,120.04 89.88 131.68 4,143.71 4,092.21 -8,353.43 1,739.44 6,023,121.00 546,887.75 0.65 13,214.47 90.06 130.05 4,143.76 4,092.26 -8,415.21 1,810.85 6,023,059.66 546,959.53 1.74 13,308.81 92.65 130.03 4,141.53 4,090.03 -8,475.88 1,883.05 6,022,999.43 547,032.09 2.75 13,402.90 94.32 129.18 4,135.81 4,084.31 -8,535.74 1,955.40 6,022,940.01 547,104.80 1.99 13,449.85 95.50 129.35 4,131.79 4,080.29 -8,565.35 1,991.62 6,022,910.63 547,141.19 2.54 13,519.00 95.50 129.35 4,125.16 4,073.66 -8,608.99 2,044.85 6,022,867.31 547,194.68 0.00 Vertical Section (ft) Survey Tool Name 7,952.21 MWD+IFR2+MS+sag (3) 8,017.11 MWD+IFR2+MS+sag (3) 8,081.87 MWD+IFR2+MS+sag (3) 8,148.30 MWD+IFR2+MS+sag (3) 8,217.48 MWD+IFR2+MS+sag (3) 8,289.69 MWD+IFR2+MS+sag (3) 8,363.58 MWD+IFR2+MS+sag (3) 8,440.45 MWD+IFR2+MS+sag (3) 8,518.99 MWD+IFR2+MS+sag (3) 8,597.15 MWD+IFR2+MS+sag (3) 8,674.44 MWD+IFR2+MS+sag (3) 8,750.99 MWD+IFR2+MS+sag (3) 8,788.96 MWD+IFR2+MS+sag (3) 8,844.89 PROJECTED to TD Mitch Laird r °oc tliw,P tmoa-iQO,;;un benjamin.hand@haliiburtoo.com Checked By: S -et Manager -- _ _ Approved By: 2016.11.0716:45:29-09'W Date: 11/712016 5:46:45PM Page 6 COMPASS 5000.1 Build 81 MPL-50 FINAL Days vs Depth 0 500 1000 1500 2000 IM MPL-50 Actual MPL-50 Plan MPL-50 Stretch -- 2500 3000 3500 4000 _ ..._.. _ 4500 5000 ., 5500 6000 6500 L 7000 p. w 7500 M N L 8000 m � 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 0 5 10 15 20 25 30 Days MPL-50 MW vs Depth 0 MPL-50 Plan 1000 MPL-50 Actual 2000 3000 4000 5000 6000 _ r CL a, 7000 a m a� 8000 9000 10000 11000 12000 13000 -- 14000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density (ppg) Lease & Well No. County TD 8,363.00 Hilcorp Energy Company CASING S CEMENTING REPORT MP L-50 State Alaska CASING RECORD Surface Shoe Depth: 8,358.53 No. Jts. Delivered 223 No. As. Run Lenath Measurements W/O Threads Fta. Delivered 9.037.13 Fto. Run Date Run 25 -Oct -16 Supv. S. Sunderland / D. Yessak _ PBTD: 8,271.29 206 No. Jts. Returned 8.355.42 Fto Returned Csg Wt. On Hook: 343 Type Float Collar: HES No. Hrs to Run: 40 Csg Wt. On Slips: 100 Type of Shoe: HES Casing Crew: WOT Rotate Csg X Yes No Recip Csg Yes X No Ft. Min. 9.4 PPG Fluid Description: Drilling Mud Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: 2 each on shoe jt 10' from pin and box. 1 ea 10' from pin end on baffle joint. (9 ea) 1 every other joint to 7546'. 1 ea on 5 joints above ES CMTR, 1 each on 5 joints below ES CMTR. 22 total run. CEMENTING REPORT Shoe @ 8358 FC @ 8,724.00 Preflush (Spacer) Type: Tuned Spacer III Density (ppg) Lead Slurry Type: ExtendaCem Density (ppg) 11.7 Volume pumped (BBLs) _ Tail Slurry ui Type: SwiftCem Top of Liner 10.5 Volume pumped (BBLs) 50 395 Sacks: 935 Yield: 2.38 Mixing / Pumping Rate (bpm): 5 Sacks: 400 Yield: 1.15 F Density (ppg) 15.8 Casing (Or Liner) Detail 83 Mixing / Pumping Rate (bpm): 3 Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 95/8 40.0 L-80 TC II WOT 1.66 8,358.53 8,356.87 Shoe Jt 95/8 40.0 L-80 TC II 43.32 8,356.87 8,315.21 Float Collar 95/8 40.0 L-80 TC II 1.72 8,315.21 8,313.49 Float joint 95/8 40.0 L-80 TC II 40.39 8,313.49 8,273.10 Baffle Adapter 95/8 40.0 L-80 TC II 1.80 8,273.10 8,271.29 Baffle Joint 95/8 40.0 L-80 TC 11 40.87 8,271.29 8,230.42 139 Casing 95/8 1 40.0 L-80 TC II 5,625.80 8,230.42 2,604.64 ES CMTR 95/8 40.0 L-80 TC II HES 3.09 2,604.64 2,601.55 63 Casing 95/8 40.0 L-80 TC II 2,546.41 2,601.55 37.91 Casing Cut Joint 95/8 40.0 L-80 TC II 37.91 37.91 Csg Wt. On Hook: 343 Type Float Collar: HES No. Hrs to Run: 40 Csg Wt. On Slips: 100 Type of Shoe: HES Casing Crew: WOT Rotate Csg X Yes No Recip Csg Yes X No Ft. Min. 9.4 PPG Fluid Description: Drilling Mud Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: 2 each on shoe jt 10' from pin and box. 1 ea 10' from pin end on baffle joint. (9 ea) 1 every other joint to 7546'. 1 ea on 5 joints above ES CMTR, 1 each on 5 joints below ES CMTR. 22 total run. CEMENTING REPORT Shoe @ 8358 FC @ 8,724.00 Preflush (Spacer) Type: Tuned Spacer III Density (ppg) Lead Slurry Type: ExtendaCem Density (ppg) 11.7 Volume pumped (BBLs) _ Tail Slurry ui Type: SwiftCem Top of Liner 10.5 Volume pumped (BBLs) 50 395 Sacks: 935 Yield: 2.38 Mixing / Pumping Rate (bpm): 5 Sacks: 400 Yield: 1.15 F Density (ppg) 15.8 Volume pumped (BBLs) 83 Mixing / Pumping Rate (bpm): 3 10 U) Post Flush (Spacer) Ig Type: Density (ppg) Rate (bpm): Volume: U_ Displacement: Type: Drilling Mud Density (ppg) 9.4 Rate (bpm): 6.5 Volume (actual / calculated): 628.5/627 FCP (psi): 880 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1400 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 90 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: C95 Cement In Place At: 17:50 Date: 10/26/2016 Estimated TOC:62 02 Method Used To Determine TOC: ES CMTR Ca) 2602' Calculated Cmt Vol @ 0% excess: Cmt returned to surface: _ OH volume Calculated: Make Seaboard Size 11 Test head to Remarks: 498 Total Volume cmt Pumped: 319 Calculated cement left in wellbore: 492 OH volume actual: 521 Actual % Washout: WELLHEAD Type 16 3/4" 3M x 11" 5M Multib W.P. 5000 PSIG MIN 527 Serial No. OK www.wellez.net WellEz Information Management LLC ver_051316bf 846 Stage Collar @ 2602 Type HES Closure OK Y Preflush (Spacer) Type: Tuned Spacer III Density (ppg) 10.5 Volume pumped (BBLs) 60 Lead Slurry Type: Permafrost L Sacks: 390 Yield: 4.33 Density (ppg) 10.7 Volume pumped (BBLs) 300 Mixing / Pumping Rate (bpm): 5.5 Tail Slurry c�W Type: SwiftCem Sacks: 325 Yield: 1.17 y Density (ppg) 15.8 Volume pumped (BBLs) 67.5 Mixing / Pumping Rate (bpm): 5.5 Post Flush (Spacer) Z Type: Density (ppg) Rate (bpm): Volume: W Displacement: Type: Drilling Mud Density (ppg) 9.4 Rate (bpm): 5.5 Volume (actual / calculated): 194.6/197 FCP (psi): 640 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1660 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 224.5 Cement In Place At: 3:30 Date: 10/26/2016 Estimated TOC: 0 Method Used To Determine TOC: Cement to surface Post Job Calculations: Calculated Cmt Vol @ 0% excess: Cmt returned to surface: _ OH volume Calculated: Make Seaboard Size 11 Test head to Remarks: 498 Total Volume cmt Pumped: 319 Calculated cement left in wellbore: 492 OH volume actual: 521 Actual % Washout: WELLHEAD Type 16 3/4" 3M x 11" 5M Multib W.P. 5000 PSIG MIN 527 Serial No. OK www.wellez.net WellEz Information Management LLC ver_051316bf 846 21 5132 Debra Oudean Hilcorp Alaska, LLC AK_GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 if Te: 907 777-8337hilt„rl, :�l,�atn. I.H. Fax 907 777-8510 27 7 2 NOV 2 2 201J E-mail: doudean@hilcorp.com 27 77 3 1�0G (71 DATE: 11/18/2016 DATA LOGGED K BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 Prints: ROP DGR ABG EWR ADR Horizontal Presentation MD DGR ABG EWR ADR Invert / Revert Sections TVD CD: HALLIBURTON Final Well Data _Log Viewers CGM Definitive Survey EMF Geosteeriing Data LAS PDF TIFF MPU L-50 EOWR pdf [#� MPU L-50 Post well Summary.pptx `] MPU L-50 recorded.emf 0 MPU L-50 recorded.pdf Za MPU L-50 recorded.tif V MPU L-50.emf 1 MPU L-50.pdf L MPU L-50.tif 11/1712016 3:47 PM 11/17/2016 3:47 PM 11/17/2016 3:47 PM 11/'17/2016 3:47 13M 11/17/2016 3:45 PM 11/17/2016 3:45 Pfd 11/17/2016 3:46 RA 11/17/2016 3:46 PM 11/4/2016 7:07 AM PDF Documen 11/3/201612:57 PM Microsoft Pow 11/5/201611:36 A.., EMF File 11/5/201611:56 A... PDF Documen 11/5/201611:59 A... TIFF image 11/1/2016 9:26 AM EMF File 11/1/2016 9:25 AM PDF Documen 11/1/2016 9:27 AM TIFF imacae Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: „ - A 'd . » I Date: Wallace, Chris D (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Friday, November 11, 2016 3:14 PM To: Wallace, Chris D (DOA); Regg, James B (DOA); Alaska NS - Milne - Wellsite Supervisors Cc: Paul Chan Subject: MPL-50 (PTD # 2151320) Ready For Injection All, Water injector MPL-50 (PTD # 2151320) was recently drilled and completed at Milne Point. The well had a passing MIT - IA on the rig to 3000 psi on 11/6/16. The well is ready to put on injection for stabilization and compliance testing. Plan Forward — Operations 1) Place well on injection. Use caution, annuli are fluid packed. 2) AOGCC MIT -IA when well is on injection and thermally stable. Thank You, Wyatt Rivard I Well Integrity Engineer 0: (907) 777-8547 1 C: (509)670-80011 wrivard@hilcorp.com 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 Iilitrorp %he- a. LIA.' THE STATE 0f LASKA GOVERNOR BILL WALKER Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU L-50 Hilcorp Alaska, LLC Permit No: 215-132 Surface Location: 3272' FSL, 4783' FEL, SEC. 8, TI 3N, RI OE, UM, AK Bottomhole Location: 176' FNL, 2318' FEL, SEC. 20, T13N, R10E, UM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced service 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. Foerster Chair DATED this ��"day of August, 2015. STATE OF ALASKA AL. CA OIL AND GAS CONSERVATION COMM 1, ON PERMIT TO DRILL 20 AAC 25.005 RhL;L1 tU JUL 22 2015 a 0� r'0' 1 a. Tyoe of Work: 1 b. Proposed Well Class: Development - Oil ❑ Service - Winj ❑✓ • Single Zone 0, 1 c. Specify if well is, proposed for: Drill % F Lateral ❑ Stratigraphic Test ❑ Development - Ga: ❑ Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 MPU L-50 ° 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 13917.5', TVD: 4027.8' Milne Point Unit - Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 3272' FSL, 4783' FEL, Sec 8, T1 3N, R10E, UM, AK ' ADL 025509 (SHL) ADL 025515 (TPH ,BHQ ° Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 2349' FNL, 1422' FEL, Sec 18, T13N, R10E, UM, AK N/A 9/25/2015 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 176' FNL, 2318' FEL, Sec 20, T1 3N, R10E, UM, AK Total acreage - 5077 " 9357' to Unit Boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 47.8 feet 15. Distance to Nearest Well Open Surface: x- 545097.84 y- 6031462.9 Zone -4 GL Elevation above MSL: 17.8 feet to Same Pool: —15' from L-45 16. Deviated wells: Kickoff depth: '3Np feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: 1800 psi % Surface: 1398 psi ^ 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 78.6# A-53 Weld 80' 0 0 80' 80' 12-1/4" 9-5/8" 40# L-80 TC -ll 8,535' 0 0 8,535' 4,027' Stg 1- Lead 1995 ft3 / Tail - 362.3 ft3 Stg 2 -Lead 1943 ft3 / Tail - 376 ft3 8-1/2" 5-1/2" 17# L-80 DWC/C-HT 5,582.5' 8,335' 4,010' 13,917.5' 4,027.8' Cmntless w/ Swell Packers 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Property Plat ❑✓ BOP Sketct Q Drilling Program 0 Time v. Depth Plot Shallow Hazard Analyss❑ Diverter Sketct Q Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requiremens❑✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Luke Keller Email lKgq r h gor .com Printed Name Luke Kalley Title Drilling Engineer Signature ZZ Phone 907-777-8395 Date 7/22/2015 Commission Use Only _ Permit to DrillAPI Number: ' Permit Approval 1 n See cover letter for other Number: — `� 50- — —( Date: lr requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed meth ne, gas hydrates, or gas contained in sh: Other: t1 DSS Samples req'd: Yes ❑ Nv7 Mud log req'd: Yes❑ [j� -e HZS measures: Yes 9 W 1:1 Directional svy req'd: Yrs[ ❑ y � Spacing / rt 17— — l A I exception req'd: Ys ❑ N� Inclination -only svy req'd: Ys❑ No[✓� Approved APPROVED BY / g—[/per f by: COMMISSIONER HE OMMISSION Date: Submit Form and Form 10-401 (Revised 0/2012) OiRin 6 fNALo-ths from the date f ppr al (20 AAC 25.005(8)) Attachments in Duplicate i4 7/2� Luke Keller Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com Ifilcorp Alaska, LLC July 22nd, 2015 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: MPL-50 Dear Commissioner, Enclosed for review and approval is the Permit to Drill for MPL-50 water injection well. `" JUL 2 2 21'1:1 AOGCC „ MPU _L-50 is a grassroots water ineector planned to be drilled in the Schrader Bluff OA sand. L-50 is part of a (5) well pilot program targeting the OA sand. Each producing lateral will have water injection support on either side. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. A lateral section will then be drilled in the OA sand. An injection liner will then be run with ICDs placed along the wellbore to optimize the water injection strategy. Drilling operations are expected to commence approximately Sept 25th, 2015. 1 Nordic Calista Rig # 3 will be used to drill and complete the wellbore. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page I of 1 Hilcorp Alaska, LLC Milne Point Unit (MPU) L-50 Drilling Program Version 1 July 8t", 2015 Milne Point HilmT Drilling Procedure Energy ComPanY Contents 1.0 Well Summary................................................................................................................................................2 2.0 Management of Change Information............................................................................................................3 3.0 Tubular Program: .......................................................................................................................................... 4 4.0 Drill Pipe Information: .................................................................................................................................. 4 5.0 Internal Reporting Requirements.................................................................................................................5 6.0 Planned Wellbore Schematic.........................................................................................................................6 7.0 Drilling / Completion Summary....................................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................................8 9.0 R/U and Preparatory Work.........................................................................................................................10 10.0 NIU 21-1/4" 2M Diverter System.................................................................................................................10 11.0 Drill 12-1/4" Hole Section............................................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................................17 13.0 Cement 9-5/8" Surface Casing.....................................................................................................................22 14.0 BOP NIU and Test........................................................................................................................................27 15.0 Drill 8-1/2" Hole Section..............................................................................................................................28 16.0 Run 5-1/2" Production Liner.......................................................................................................................32 17.0 Run ESP assy................................................................................................................................................35 18.0 RDMO...........................................................................................................................................................35 19.0 Diverter Schematic.......................................................................................................................................36 20.0 BOP Schematic.............................................................................................................................................37 21.0 Wellhead Schematic.....................................................................................................................................38 22.0 Days Vs Depth...............................................................................................................................................39 23.0 Formation Tops............................................................................................................................................40 24.0 Anticipated Drilling Hazards.......................................................................................................................41 25.0 Nordic #3 Rig Layout (Drillers Side)..........................................................................................................43 26.0 Nordic #3 Rig Layout (Well End & Top View)..........................................................................................44 27.0 FIT Procedure...............................................................................................................................................45 28.0 Choke Manifold Schematic..........................................................................................................................46 29.0 Casing Design Information..........................................................................................................................47 30.0 8-1/2" Hole Section MASP...........................................................................................................................48 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................................49 32.0 Surface Plat (As Built) (NAD 27)................................................................................................................50 33.0 Offset MW vs TVD Chart............................................................................................................................51 34.0 Drill Pipe Information 5" 19.5# 5-135 DS-50.............................................................................................52 1.0 Well Summary Milne Point Unit L-50 Drilling Procedure Well MPU L-50 Pad Milne Point "L" Pad Planned Completion Type 3-1/2" Injection string Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 13,917.5' MD / 4,027.8' TVD PBTD, MD / TVD 13,907' MD / 4,027.8' TVD Surface Location (Governmental) 3,272' FSL, 4,783' FEL, Sec 8, T13N, RI OE, UM, AK Surface Location (NAD 27 — Zone 4) X=545,097.84, Y=6,031,462.90 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 2349' FNL, 1422' FEL, Sec 18, T13N, R10E, UM, AK TPH Location (NAD 27) X=543232.6, Y=6025831.5 TPH Location (NAD 83) BHL (Governmental) 176' FNL, 2318' FEL, Sec 20, T13N, R10E, UM, AK BHL (NAD 27) X=547645.42, Y=6022752.14 BHL (NAD 83) AFE Number 1511128 AFE Drilling Days 15 days AFE Completion Das 4 days AFE Drilling Amount $4,137,342.00 AFE Completion Amount $1,093,100 AFE Facility Amount $431,000.00 Maximum Anticipated Pressure (Surface) 1398 psig° Maximum Anticipated Pressure (Downhole/Reservoir) 1800 psig Work String 5" 19.5# 5-135 DS -50 (Weatherford Rental KB Elevation above MSL: 30 ft + 17.8 ft = 47.8 ft GL Elevation above MSL: 17.8 ft BOP Equipment 11" x 5M Annular, (3) ea 11" x 5M Rams Page 2 Version 1 July, 2015 0 Hilcorp En-" C-PaY 2.0 Management of Change Information Milne Point Unit L-50 Drilling Procedure Hilcorp Alaska, LLC Hilcorp Changes to Approved Permit to Drill Date: Subject: Changes to Approved Permit to Drill for MPU L-50 File #: MPU L-50 Drilling and Completion Program Any modifications to MPU L-50Drilling & Completion Program will be documented and approved below_ Changes to an approved ARD will be communicated to the i3LM and A©GCC. Approval Prepared: Drilling Manager Drilling Engineer ure Date Date Page 3 Version 1 July, 2015 3.0 Tubular Program: Milne Point Unit L-50 Drilling Procedure Hole Section OD (in) ED (in) Drift in Conn OD in(#/ft) Wt Grade Conn Burst (psi) Collapse (psi) Tension (k -lbs) Cond 20" 19.25" - - 78.6 A-53 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 TC -I1 5,750, 3,090 916 8-1/2" 5-1/2" 4.892" 4.767" 6.05" 17 L-80 DWC/C HT 7,740 - 7,100 397 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID in TJ OD in(#/ft) Wt Grade Conn NIX Min NIX Max(k-lbs) Tension All 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp 5.0 Internal Reporting Requirements 17.1 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. 17.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com , Ikeller@hilcorp.com and cdin er(a�hilcorp.com 17.3 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. 17.4 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 17.5 Casing Tally Send final "As -Run" Casing tally to Ikeller@hilcorp.com and cdinger@hilcorp.com 17.6 Casing and Cmt report Send casing and cement report for each string of casing to lkeller(�hilcorp.com and cdinger@hilcorp.com 17.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Luke Keller 907.777.8395 832.247.3785 lkeller@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Keith Elliot 907.777.8355 832.233.5855 kelliott@hilcorp.com Drlg Environmental Coord Julieanna Orczewska 907.777.8444 907.715.7060 jorczewska@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com EHS Field Coordinator Jimmy Watson 907.777.8450 907.744.7376 jiwatson@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp Energy Company 6.0 Planned Wellbore Schematic AFE No. Well llama: KS: 30 ft AGL 1511128 Milne Point Unit (MPU) L-50 GL + RKB 17 ft + 30 ft = 47 ft API TBt1 AFE WELLBORE DESIGN Proposed TO: 13,917.5' MO Permit No. TBD Proposed TVD: 4,027.8' TVD Geologic Inlcrmation Wellbore Information Casing Info? Mud Info Hole Size; Cement Specs SS TVD FM Lithology Conductor Mud v � RKB - Tubing Hanger 20" 129# A-56 driven to 8d BGL N interval: Surface hole Surface Casing Mud Type: E 2 X,9 -SM" 404 L-80 TC41 set at 8535 MD 1402r TVD Fresh WatenNative a Weight Range: 0 o Surface Casing Cernent 8.8-9.2 � 1st stage: 60 bhis 10.5 ppg Tuned spacer III Lead: (30% OH Excess) ARCTICCEM a 10.7 ppg Tail (30% OH Excess) SWIFTCEM 15.8 ppg R Q 0 4v.• s', e E `» 2nd stage: 3* v 60 bbis 10.5 ppg Tuned spacer III c A Lead: (Until returns at surface) ARCTICCEM 10.7 ppg 1750' L t *a Tail SWIFTCEM 15.8 ppg Z Stage Production Utter c a C 5-11W 174 L-60 DWCIC HT liner 13,917.5' MO 14.027.8' TVD i ACollar �p 6 `o t �,�yy, V Injection Tubing p 3-1Y 0.34 L-80 ORD EUE I R - ? U C 'V e Up M o e 0 o m lA D Z t c p c $ o -3500' K -sands o oarse sand, silty r l hale, better Liner Top Pkr: 8335ft Injection ioar Control Devices UGNU loped ^ , rs Interval: Production Hole t -Sands intervening shales ^4000' M -sands N -sands in the L and M Continued layering as o a a o o a Baradril-N Weiaht Range: Schrader in Ugnu, more 4 O q O O O 8.9 - 92 ppg 0 -sands condensed with occ. 4 0 0 0 -4300' coal Injection Packer Swell Pkrs i 5-1/2" Injection Liner Page 6 Version 1 July, 2015 0 Hil=Energy 7.0 Drilling / Completion Summary Milne Point Unit L-50 Drilling Procedure MPU L-50 is a grassroots water injector planned to be drilled in the Schrader Bluff OA sand. L-50 is part of a (5) well pilot program targeting the OA sand. Each producing lateral will have water injection support on either side. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff OA sand. A lateral section will then be drilled in the OA sand. An injection liner will then be run with ICDs placed along the wellbore to optimize the water injection strategy. Drilling operations are expected to commence approximately Sept 25', 2015. Nordic Calista Rig # 3 will be used to drill and complete the wellbore. Surface casing will be run to 8,535' MD / 4,027' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on "B" pad. General sequence of operations: 1. MOB Nordic Rig #3 to well site 2. N/U 21-1/4" conductor and 16" diverter line. 3. Drill 12-1/4" hole to TD of surface hole section. 4. N/D diverter, N/U & test I I" x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 5-1/2" liner. 6. Run Injection string. 7. N/D BOP, N/U temp abandonment cap, RDMO. Run and cmt 9-5/8" surface casing. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 7 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp Energy Company 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU L-50. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12-1/4" • 21-1/4" 2M diverter w/ 16" diverter line Function Test Only • 11" x 5M Hydril Annular BOP • 11" x 5M Shaffer Double Ram Initial Test: 250/3000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/ 3" x 5M side outlets 8-1/2" • 11" x 5M Hydril Single Ram • 3" x 5M Choke Line Subsequent Tests: • 3" x 5M Kill line 250/3000 • 3" x 5M Choke manifold (10M Hydraulic remote Choke (Annular 2500 psi) • Standpipe, floor valves, etc Primary closing unit: Hydril, 165 gal, 6 station accumulator w/ dual electric and air pumps, w/ 1 (ea) electric over hydraulic remote control panel at the driller station. • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Tertiary pressure is provided by air pumps. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: V/ AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.re%Z%Z@alaska.gov Guy Schwartz / Petroleum Engineer/ (0): 907-793-1226 / (C): 907-301-4533 / Email: guy. schwartzkalaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors(cr�,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 July, 2015 Milne Point Unit L-50 Drilling Procedure HilmTEner r 9.0 RX and Preparatory Work 9.1 20" has been pre -driven to 80' below ground level (110' RKB) 9.2 Dig out and set impermeable cellar. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.5 Insure (2) 3" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack -off. 9.6 Level pad and ensure enough room for layout of rig footprint and R/U. 9.7 Confirm that the rig is over the appropriate well slot. 9.8 MIRU Nordic #3. 9.9 Mud loggers WILL NOT be used on either hole section. 9.10 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 9.11 Set test plug in wellhead prior to NIU diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.12 Install 5-1/2" liners in mud pumps. • Continental EMSCO F-1000 mud pumps are rated at 3500 psi (100%) / 354 gpm (120 spm @ 95% eff) with 5-1/2" liners. 10.0 NX 21-1/4" 2M Diverter System 10.1 N/U 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic at Sec 19 at back of program). • NIU 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. Page 10 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilc,=En -v : . 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set 15.375" ID wearbushing in wellhead. Page 11 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp COY Page 12 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp Energy Company 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 12-1/4" BHA (GR + Res LWD and PWD planned in surface hole): COMPONENT DATA Description bpConnection Length Total Location 1 Tricone 8.000 3.000 12.250 147.22 P 6-5/8" REG 1.10 2 8" SperryDrill Lobe 415 - 5.3 stg 8.000 5.000 5.000 103.09 B 6-5/8" REG 31.47 32.57 Stabilizer 12.125 4.28 3 Float Sub 8.000 2.880 2.880 149.10 B 6-5/8" REG 2.40 34.97 4 Stabilizer 8.000 1 3.000 3.000 10.250 1 147.22 B 6-5/8" REG 6.00 1 40.97 35.97 5 8" DM Collar (Directional) 8.000 3.500 3.544 147.40 B 6-5/8" REG 9.20 50.17 6 8" DGR Collar (Gamma) 8.000 1.920 4.997 142.70 B 6-5/8" REG 4.55 54.72 7 8" EWR-P4 Collar (Resistivity) 8.000 1.985 5.205 151.00 B 6-5/8" REG 12.19 66.91 8 8" PWD (Pressure EGDs) 8.000 1.920 1 4.760 143.40 1 B 6-5/8" REG 4.44 71.35 9 8" HCIM Collar (Processor) 8.000 1.920 4.309 149.90 B 6-5/8" REG 4.97 76.32 10 8" POS PULSER (Telemetry) 8.000 4.000 4.257 145.20 B 6-5/8" REG 15.44 91.76 11 Orienting Sub UBHO 8.000 2.875 3.000 149.18 B 6-5/8" REG 2.50 94.26 12 NM Flex Collar 8.000 2.813 150.13 B 6-5/8" REG 31.00 125.26 13 1 NM Flex Collar 8.000 2.813 1 150.13 B 6-5/8" REG 31.00 156.26 14 NM Flex Collar 8.000 2.813 150.12 B 6-5/8" REG 31.00 187.26 15 8jts x 5" X 3" HWDP #49.3 - NC50(IF) 5.000 3.000 49.30 240.00 427.26 16 Jar 7.500 2.813 2.813 129.38 B 4-1/2" IF 35.00 462.26 17 12jts x 5" X 3" HWDP #49.3 - NC50(IF) 5.000 3.000 49.30 360.00 822.26 822.26 Page 13 Version 1 July, 2015 Hi1mTEne�gYP�Y 11.3 11.4 11.5 Primary Bit: PRODUCT SPECIFICATIONS IADC Code 117W Total Tooth Count 67 Gage Row Tooth Count 39 Journal Angle 33, Offset (1/16") 6 Jet Nozzle Types Standard 83244 Extended 302447 Center Jet (If Center Jetted) 501813 T.J. Connection 6-518" (API Reg_) Recommended Make -Up Torque* 28000132000 Ft*lbs. Bit Weight (Boxed) 250 Lbs. (113 Kg.) Bit Breaker (Mat.WLegacyk) 5153531506463 PRODUCT FEATURES * New patented DiamondiN Claw)1 tooth bit design. * Tungsten carbide *surf inserts in gage teeth for added gage protection. * Newly formulated, proprietary hardfacing on cutting structure and gage maximizes carbide and diamond volume for ultimate wear resistance. * Raised tungsten carbide inserts and proprietary hardfacing provides maximum arm protection in abrasive and directional applications while minimizing drill string torque. * QuadPack* Plus Series incorporates its successful 'longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. * Center jet feature to prevent bit balling problems * Dual seal/dual compensation bearing system containing dual seals, dual independent pressure compensators, and a dual grease formulation. * The latest OCP seal technology designed with the highest contact pressures on the outside edges of the seal where it is needed most, helps keep contaminants out extending bearing life. Milne Point Unit L-50 Drilling Procedure Material #740990 *Calculations based on recommcadatiom from AN and tool joint manufacturers_ 0 2014 Halliburton. All rights reserved. Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. 5" Workstring, HWDP, and Jars will come from Weatherford. Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 11.6 Drill 12-1/4" hole section to 8,535' MD / 4,027' TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. Page 14 Version 1 July, 2015 Hilcorp Energy Company Milne Point Unit L-50 Drilling Procedure • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if run through high dog legs. Keep DLS < 6 deg / 100. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 600 - 650 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • Ensure to leave a "Pump Tangent" section that is approx. 300' long in the directional plan. The ESP will need a straight section to sit. This will occur very near TD of the hole section. • Make wiper trips every 2000' unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section just into the Schrader Bluff OA sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. • Take MWD surveys every stand drilled (60' intervals). • Watch returns closely for signs of gas when near the base of the permafrost and circulate out all gas cut mud before continuing to drill. There have been no indications of hydrates on any of the "L" pad wells to date. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. Page 15 Version I July, 2015 Milne Point Unit L-50 Drilling Procedure HilmT 11.7 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. • PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBsBAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 - 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 - 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: De the CDensit�_91scosity Concentration I Plastic Viscosity Yield Point API Fl. H 80-8535' — 9 85-250 1 20-40 25-75 <10 1 8.5 Page 16 System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 - 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 - 9.2 ppg PAC -L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure HilczTF -e'. . 11.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 20" conductor shoe. 11.9 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 — 4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (600 — 700 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.10 TOH with the drilling assy, handle BHA as appropriate. 11.11 No open hole logging program planned. 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull 15.375" wearbushing. 12.2 Make a dummy run with the 9-5/8" casing hanger. 12.3 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" TC -II x DS50 XO on rig floor and M/U to FOSV. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.525" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.4 P/U shoe joint, visually verify no debris inside joint. 12.5 Continue M/U & thread locking shoe track assy consisting of - 0 f• (1) Shoe joint w/ float shoe bucked on (thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end & thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Page 17 Version 1 July, 2015 Hilcorp Enema' Company This end up. Bypass Baffle Milne Point Unit L-50 Drilling Procedure • (1) Joint with Halliburton bypass baffle adapter bucked on pin & threadlocked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 18 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp EnergyPmY 12.6 Float equipment and Stage tool equipment drawings: "A Type H ES Cementer B Part No. Min. ID After Drillout SO No. Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (f used) ID Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe AF Depth Hole TD "Reference Casing Sales Manual Section 5 C Max. Tool OD D Opening Seat ID E Closing Seat ID Page 19 Version 1 July, 2015 Plug Set Part No. SO No. Closing Plug OD Opening PI ODIf 0, OD Shut-off Plug 2 OD Bypass Plug (if used) t. OD Page 19 Version 1 July, 2015 Hikorp E" Running Order ES4I Cementer Shut OH plug Baffle Adapter %,Pass Pkg By Pass Baffle Float Collar Ron shoe Page 19 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp Energy Company 12.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use Jet Lube Seal or BOL 72733 thread compound. Dope pin end only w/ paint brush. • Install (1) centralizer every other joint for the first 15 joints. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cmt returns to surface. 12.8 Install the Halliburton Type H ES -II ige tool so that it is / 2000' TVD. This will position the stage collar comfortably below the permafrost. • Install centralizers over couplings on 3 joints below and above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. There are tool is normally sent with only 4 pins installed. This will allow the tool to ope at 3300 psi. ' 9-5/8" 40# L-80 TC -II Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 11,600 ft -lbs 13,600 ft -lbs 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 PIU casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.12 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 20 Version 1 July, 2015 Hilcorp F-ew Connection Type: TC -II Casing standard Milne Point Unit L-50 Drilling Procedure Technical Specifications Size(O.D.): Weight (Wall): 9-5/8 in 40.00 Ibfft (0.395 in) Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 9.625 Nominal Pipe Body Q.D. (in) 8.835 Nominal Pipe Body I.D.(in) 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight (lbs/ft) 38.97 Plain End Weight (lbs !ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Internal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Performance Properties 916,000 (1) Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 916,000 Compression Rating (lbs) 3,090 Collapse Pressure Rating (psi) 5,750 Internal Pressure Rating (psi) 38.1 Maximum uniaxial bend rating [degrees/100 ft] Recommended Torque Values 11,600 (2) Minimum Final Torque (ft -lbs) 13,600 (2) Maximum Final Torque (ft -lbs) Grade: L-80 lam USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax: 713-478-3234 E-mail. VAMUSAsalestituam-usa.com 12.13 Have emergency slips ready to go in the event we cannot land the hanger. 12.14 R/U circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 12.15 After circulating, lower string and land hanger in wellhead again. Page 21 Version 1 July, 2015 Connection Dimensions 10.235 Connection O.D. (in) 8.835 Connection I.D_ (in) 8.750 Connection Drift Diameter (in) 5.23 Make-up Loss (in) Connection Performance Properties 916,000 (1) Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 916,000 Compression Rating (lbs) 3,090 Collapse Pressure Rating (psi) 5,750 Internal Pressure Rating (psi) 38.1 Maximum uniaxial bend rating [degrees/100 ft] Recommended Torque Values 11,600 (2) Minimum Final Torque (ft -lbs) 13,600 (2) Maximum Final Torque (ft -lbs) Grade: L-80 lam USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax: 713-478-3234 E-mail. VAMUSAsalestituam-usa.com 12.13 Have emergency slips ready to go in the event we cannot land the hanger. 12.14 R/U circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 12.15 After circulating, lower string and land hanger in wellhead again. Page 21 Version 1 July, 2015 0 Hffczp � 13.0 Cement 9-5/8" Surface Casing Milne Point Unit L-50 Drilling Procedure 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 13.4 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 13.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug). Mix and pump cmt per below calculations for the 1 st stage. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. d Estimated Total Cement Volume: z 4 Section: Calculation: Vol (BBLS) Vol (ft3) 12-1/4" OH x 9-5/8" Casing annulus: (7500'- 2600') x .0558 bpf x 1.3 = 355 bbls 1995ft3 Total LEAD: 355 bbls 1995ft3 12-1/4" OH x 9-5/8" Casing annulus: (8535'- 7500') x .0558 bpf x 1.3 = 57.7 bbls 324 ft3 9-5/8" Shoe track: 90 x.0758 bpf = 6.8 bbls 38.3 ft3 Total TAIL: 1 64.5 bbls 362.3 ft3 r�--3-�.F Milne Point Unit L-50 Drilling Procedure Cement Slurry Design (both 1St and 2nd stage cement jobs): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. To operate the stage tool hydraulically, the plug must be bumped. 13.11 +' Displacement calculation: --- �` 8435' x.0758 bpf = 402 bbls mud, 80 bbls water, 157 bbls mud The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not overdisplace by more than 1/2 shoe track volume. Total volume in shoe track is 8.7 bbls. 13.14 If plug is not bumped consult with drilling engineer. Ensure the free fall stere tool opening plug is available if needed. This is the back-up option to open the staget if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Page 23 Version 1 July, 2015 Lead Slurry Tail Slurry System ArcticCEM TM System SwiftCEM T"" System Density 10.7 Ib/gal 15.8 Ib/gal Yield 4.298 ft3/sk 1.16 ft3/sk r Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. To operate the stage tool hydraulically, the plug must be bumped. 13.11 +' Displacement calculation: --- �` 8435' x.0758 bpf = 402 bbls mud, 80 bbls water, 157 bbls mud The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not overdisplace by more than 1/2 shoe track volume. Total volume in shoe track is 8.7 bbls. 13.14 If plug is not bumped consult with drilling engineer. Ensure the free fall stere tool opening plug is available if needed. This is the back-up option to open the staget if the plugs are not bumped. 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Page 23 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure HilmTEnergy Company 13.16 Increase pressure to 33�si to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP < 20 again in preparation for the 2"d stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 24 Version 1 July, 2015 Hilcorp Energy ComPoKY Second Stage: Milne Point UnitL-50 Drilling Procedure 13.18 Prepare for the 2'd stage as necessary. Hold another pre job meeting if crew change has occurred. 13.19 Load ES cementer closing plug in cmt head. 13.20 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 13.21 Pump remaining 55 bbls 10.5 ppg tuned spacer. ks 69L, 13.22 Mix and pump cmt per below recipe for the 2nd stage. 3`� s� g a 13.23 Cement volume based on annular volume + 200% open hole excess. Job will consist of lead & tail, TOC brought to surface. However cmt will continue to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 20" Conductor x 9-5/8" casing annulus: (110') x .27 bpf x 1 = 29.7 bbls 167 ft3 12-1/4" OH x 9-5/8" Casing annulus: (2000'- 110') x .0558 bpf x 3 = 316 bbls 1776 ft3 Total LEAD: 345.7 bbls 1943 113 12-1/4" OH x 9-5/8" Casing annulus: (2600'- 2000') x.0558 bpf x 2 = 67 bbls 376 ft3 Total TAIL: 67 bbls 376 ft 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2600' x.0758 bpf = 197 bbls mud v1 Page 25 Version 1 July, 2015 �5-1sA L- 5K Milne Point Unit L-50 Drilling Procedure Hi1mTEn«gy ComP�Y 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.28 Decide ahead of time what will be done with cmt returns once they are at surface. We should get back approx. 150 bbls of cmt slurry. 13.29 Land closing pluton sta¢P ��>iar and xzressure un to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Back out and L/D landing joint. Flush out wellhead with FW. 13.30 M/U pack -off running tool and pack -off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.31 Lay down landing joint and pack -off running tool. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report to lkellerghilcorp. com and cdinger ,hilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 26 Version 1 July, 2015 14.0 BOP N/U and Test 14.1 N/D the diverter. Milne Point Unit L-50 Drilling Procedure 14.2 N/U Seaboard tubing spool. Install pack -off 9-5/8" P -seals. Test to 3000 psi. 14.3 N/U 11"x 5M BOP as follows: • BOP configuration from Top down: 11" x 5M Hydril annular BOP/11" x 5M Shaffer double ram /11" x 5M mud cross/11" x 5M Hydril single ram • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8" x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 5" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.8 Set 10" ID wearbushing in wellhead. 14.9 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.10 Keep 5-1/2" liners in mud pumps. Page 27 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp En -V C�-wny 15.0 Drill 8-1/2" Hole Section 15.1 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135 • Install ported float above motor. 15.2 8-1/2" BHA (Includes GR+Res+ADR LWD components & PWD) COMPONENT Item DATA Description OD ID Sttff 10 Gauge Weight••Length yp Total Locatiori 1 PDC 6.750 2.500 8.500 105.23 P 4-112" REG 0.80 2 7' SperryDrill Lobe 718 - 6.0 stg 7.000 4.952 4.952 93.13 B 4-112" IF 27.38 28.18 Stabilizer $_375 3.47 3 Float Sub 6.750 2.813 2.813 100.77 P 4-112" IF 2.00 30.18 4 16 314" DM Collar (Directional) 6.750 1 3.125 3.155 1 103.40 P 4-112" IF 920 39.38 5 Inline Stabilizer (ILS) 6.750 1.920 1.920 8.375 112.09 B 4-112" IF 2.00 41.36 40.03 6 6 314" ADR Collar (Resistivity) 6.750 1.920 3.288 109.40 B NC 50 24.34 65.72 7 6 314" DGR Collar (Gamma) 6.750 1.920 4.430 97.80 B 4-112" IF 4.46 70.16 8 6 314" PWD (Pressure ECDs) 6.750 1.905 4.657 1 11224 1 B 4-112" IF 4.44 74.62 9 16 314" HUM (Processor) 6.750 1.920 3.667 112.09 B 4-112" IF 4.97 79.59 10 6 314" TM Pulser (Telemetry) 6.750 3.250 3.551 99.16 B 4-112" IF 15.26 94.85 11 NM Flex Collar 6.750 2.813 100.77 B 4-112" IF 31.00 125.85 12 NM Flex Collar 6.750 2.813 100.77 B 4-112" IF 31.00 156.85 13 NM Flex Collar 6.750 2.813 100.77 B 4-112" IF 31.00 187.85 14 3xJts 5" X 3" HWDP - 4.51F 5.000 3.000 42.83 93.00 280.85 15 Jar 6.250 2.250 2.250 91.01 B 4-112" IF 33°00 313.85 16 14Jts 5" X 3" HWDP - 4.51F 5.000 3.000 42.83 420.00 733.85 �733.85 Page 28 Version 1 July, 2015 im Hilcorp Energy G=WY 15.3 Primary Bit: PRODUCT SPECIFICATIONS Cutter Type X2 - Tough Drilling IADC Code 5424 Body Type STEEL Total Cutter Count 29 Cutter Distribution l3mm 19mm Face 0 19 Gauge 10 0 Number of Large Nozzles 5 Number of Medium Nozzles 0 Number of Small Nozzles 0 Number of Micro Nozzles 0 Number of Ports (Size) 0 Number of Replaceable Pons (Size) 0 Junk Slot Area (sq in) 20.81 Normalized Face Volume 73.86% API Connection 4-1/2 I.F. PIN Recommended Make -Up Torque* 23.743 Ft•lbs. Nominal Dimensions" Make -Up Face to Nose 8.31 in - 211 mm Gauge Length 3 in - 76 mm Sleeve Length 0 in - 0 mm Shank Diameter 6.688 in - 170 mm Break Out Plate (Mat.#/Legacy#) 181960/44073 Approximate Shipping Weight 120Lbs. - 541Cg. SPECIAL FEATURES Anti -Balling Coating, Short Shank. EDL Tool Specific Gage, .084" Dia Step, .126" Dia Step 15.4 8-1/2" hole section mud program summary: Milne Point Unit L-50 Drilling Procedure Material #761417 • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. Page 29 Version 1 July, 2015 r' Hilcorp Ener Company Milne Point Unit L-50 Drilling Procedure • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use water or low vis sweeps. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.2 ppg Baradrill-N drilling fluid / Properties: Depths Densit Plastic Viscosity Yield Point Total Solids MBT HPHT pH 8,535- 13,917 8.9-9. 15-25 15-25 <10% <7 <1 1.0 8.5-9.5 System Formulation: Baradrill-N Product Concentration Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N -VIS 1.0 — 1.5 ppb N-DRIL HT PLUS 5 ppb BARACARB 5 11.5 ppb BARACARB 25 16.8 ppb BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.015 ppb EZ -GLIDE 2.0% 15.5 TIH w/ 8-1/2" directional assy to stage tool. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. Drill out stage tool as follows: • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Because of aggressive nature of PDC bits, drilling with minimal WOB is recommended. Approx 2-5 k is enough. Page 30 Apply weight and allow it to drill off before applying more. After drilling out, chase any remaining debris to bottom with the drill bit. Version 1 July, 2015 X, Milne Point Unit L-50 Drilling Procedure Hilcorp Energy Company 15.6 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.7 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = —3500 psi, but maximum test pressure on L-50 is 3000 psi. 15.8 Drill out shoe track and 20' of new formation. 15.9 CBU and condition mud for FIT. I 15.10 Conduct FIT to 12 ppg EMW. 15.11 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Pump at 500 - 550 gpm. • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump water or other low vis sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips every 1500 — 2000 ft if necessary. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Ideally, we would like to stay in section 100% of the time and DO NOT want to serpentine between the upper and lower lobes. 15.12 Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. • Attempt to lowside in a fast drilling interval where the wellbore is headed up. • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.13 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the 9-5/8" shoe. If backreaming is necessary: • Circulate at full drill rate (500 — 550 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. Page 31 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp En -W C—Mny 15.14 TOH with the drilling assy, stand back BHA if possible. Rabbit DP on TOH. 15.15 No open hole logs are planned for the production hole section. 16.0 Run 5-1/2" Injection Liner 16.1. Install and test 5-1/2" casing ram in top ram cavity. Test to 250/3000 psi. "- 16.2. Re -install wear bushing in wellhead after test. 16.3. R/U 5-1/2" casing running equipment. • Ensure 5-1/2" DWC/C x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.4. Run 5-1/2" production liner per completion tally. • Use "Best O Life 2000" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install swell packers & ICDs as per Operations Engineer guidance. • Ensure all plastic packing is removed from swell pkr elements. • Do not place tongs or slips on pkr elements or ICDs. 5-1/2" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 5.5" 9,800 ft -lbs 11,000 ft -lbs 14,800 ft -lbs Page 32 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight (Wall): Grade: DWC/C-HT Casing 5-1/2 in 17.00 Ib/ft (0.304 in) L-80 standard Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 5.500 Nominal Pipe Body O.D. (in) 4.892 Nominal Pipe Body I.D.(in) 0.304 Nominal Wall Thickness (in) 17.00 Nominal Weight (lbs/ft) 16.69 Plain End Weight (lbs/ft) 4.962 Nominal Pipe Body Area (sq in) Appoximated Field End Torque Values 9,800 Minimum Final Torque (ft -lbs) 11,000 Maximum Final Torque (ft -lbs) 14,800 Connection Yield Torque (ft -lbs) "SAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail_ VAMUSAsalesi�vem-uss.com Page 33 Version 1 July, 2015 Pipe Body Performance Properties 397,000 Minimum Pipe Body Yield Strength (lbs) 6,290 Minimum Collapse Pressure (psi) 7,740 Minimum Internal Yield Pressure (psi) 7,100 Hydrostatic Test Pressure (psi) Appoximated Field End Torque Values 9,800 Minimum Final Torque (ft -lbs) 11,000 Maximum Final Torque (ft -lbs) 14,800 Connection Yield Torque (ft -lbs) "SAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail_ VAMUSAsalesi�vem-uss.com Page 33 Version 1 July, 2015 Connection Dimensions 6.050 Connection O -D. (in) 4.892 Connection I.D. (in) 4.767 Connection Drift Diameter (in) 4.13 Make-up Loss (in) 4.962 Critical Area (sq in) 100.0 Joint Efficiency (%) Appoximated Field End Torque Values 9,800 Minimum Final Torque (ft -lbs) 11,000 Maximum Final Torque (ft -lbs) 14,800 Connection Yield Torque (ft -lbs) "SAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail_ VAMUSAsalesi�vem-uss.com Page 33 Version 1 July, 2015 Connection Performance Properties 397,000 Joint Strength (lbs) 16,680 Reference String Length (ft) 1.4 Design Factor 428,000 API Joint Strength (Ibs) 397,000 Compression Rating (lbs) 6,290 API Collapse Pressure Rating (psi) 7,740 API Internal Pressure Resistance (psi) 66.7 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoximated Field End Torque Values 9,800 Minimum Final Torque (ft -lbs) 11,000 Maximum Final Torque (ft -lbs) 14,800 Connection Yield Torque (ft -lbs) "SAM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston. TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail_ VAMUSAsalesi�vem-uss.com Page 33 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilc01[� En -V comv�r 16.6. Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 16.7. Before picking up Baker ZXP liner hanger/ packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 16.9. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH w/ liner on DP no faster than 1-1/2 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. DP should autofill. 16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.17. Rig up to pump down the work string with the rig pumps. 16.18. Displace entire wellbore to completion fluid (8.9 ppg KCl). Pump at 10-12 bpm. Catch mud for future use if feasible. Once KCl observed at surface shut down pumps. 16.19. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.20. Pressure up to 3000 psi and hold for 5-15 minutes to set SLZXP hanger packer. Continue pressuring up in 500 psi increments holding for 5 min each up to 4000 psi. Page 34 Version 1 July, 2015 HilmTEnergy Company Milne Point UnitL-50 Drilling Procedure ::] 16.21. Bleed DP pressure to zero, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.22. Bleed off pressure and pickup to verify that the HRD setting tool has released. If packer did not test, rotating dob sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.23. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOR 16.24. L/D remaining DP out of derrick. 17.0 Run Injection Assembly 17.1 M/U injection assy and RIH to setting depth. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. 17.2 Land hanger, RILDs and test hanger. 17.3 Circulate freeze protect down IA, allow freeze protect to U-tube down tubing. /k 17.4 Set packer. Test annulus to 3000 psi f/ 30 min. wl -Z�e 17.5 Install BPV and N/D BOP. 17.6 N/U tree adapter and tree. Conduct pressure tests of same to 250/3000 psi. 17.7 Shut in well. 18.0 RDMO Page 35 Version 1 July, 2015 19.0 Milne Point Unit L-50 Drilling Procedure Diverter Schematic Page 36 Version 1 July, 2015 Hilcorp Enew C—P-Y 20.0 BOP Schematic Kill Line D Hydril Annular BOP 11"x5M J Ll Shaffer 11 " x 5ktj L on 00 o0 9-518" DBL D Seal Casing Hanger SMB -22 16-314" NOM 9-518" BTC Btm x 10.5"-4 SA Pin Top W1 Prima Sea Hydril 11" x 5M Milne Point Unit L-50 Drilling Procedure �3` x 5M HCR '--'---Choke Line 3" x 51M Manual Gate Valve —11" x 5M \�2-1116" x 5M --16-314" x 3M \-2-1116" x 5M 20" Casing H--"--9-5/8" Casing Page 37 Version 1 July, 2015 21.0 22.0 Wellhead Schematic Milne Point Unit L-50 Drilling Procedure HILCORP ALASKA, LLC SCHRADER BLUFF WELLS NORTH SLOPE HO -34863 * o�"�°r`+ .r.0 Jnr DUOM 09 PAW YATGMIL LDIM W aM OTM OF SLMV Mw K man ROOM SIM DOU K OMM fm RDuva NAM IM ONLY. Page 3 8 RESTRICTED CONMENTIAL 000ULIENT W M " IPYWAWTAI III M �� Version 1 56000 PSI WELLHEAD 8 TREE ASSEMBLY 20 X 9-5/8 X 3-1/2 RPL 112-O1JUL15.■o ou...a P-20547 5 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp eney Company 23.0 Days Vs Depth A rr• 4000 Z 6000 0ViF4l Bays Vs Depth -Schrader Bluff Well -MP{-1912004; M P4.1S 12011) -MP1-17 (2044} -MPI -15 12042} 0 5 10 15 20 25 30 Days Page 39 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure HilwEnergy w�Y 24.0 Formation Tops Formation TVD (Top) TVD (Bottom) Anticipated Pressure (Psi) SV1 2175 3545 973 Ugnu LAI 3430 3634 1534 Ugnu MB 3635 3882 1626 SB NB Sand Top 3883 4020 1736 SB OA Sand Top 4021 4035 1798 Page 40 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcolp Enemy Company 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of adjacent wells in the vicinity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on `L" pad. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during. drilling operations. Page 41 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure 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. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 500 gpm- Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 1-12S. No H2S events have been documented on drill wells on `L" pad. 1. The AOGCC will be notified within 24 hours if 142S 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 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on "L" pad. Page 42 Version 1 July, 2015 f Milne Point Unit L-50 Drilling Procedure Hilcorp EneW Cmpmy 26.0 Nordic #3 Rig Layout (Drillers Side) 1 ;�7k %7 g IL �0161 �7c RIG NO, 3 Thr L"Ji ' ",h.— Illu drr}ml. u.Fe rr:Eurwr s+rorertY of `iea c• CA.. nd a F --.d 6r U'5..nd i.--i..i . Tpy gf.r In..; l: Dt.ipn a f-..h.c -. ,—C: nx' 1 b.n ith rh:: wh,.a...+r.. u, .b,k Qgsn:.nx am ir,m bzmn h..L ih.ms.rsfx,nmd.m,,.rnr':{.i.irh.h ,;d n[r.E..+.t.ig.. whim. rh. waitrm a�mm... of hindir�Ctlun � Ute;gn may n.r br dia.l,..d sn ama.hcr µmr .rnpr for.he ,F<.ir w.Qa..f., hA k h.. I...p-i&d. Q-= R, M MAIM Page 43 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp Enagy Company 27.0 Nordic #3 Rig Layout (Well End & Top View) TOP VIEW Page 44 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp Energy Company 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures 5 `- Procedure for FIT:w. ' 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 45 Version 1 July, 2015 Hilcorp Energy Ca®pap 29.0 Choke Manifold Schematic tY{}<)<)tb irafa )i)i)a s r > t)a) ) ) e a_<_a_<_s_•_<_t_,_tj� M 1 i<1 is y • rt t t fill I a ; ><ae <a estYt)t><>tyi3:rr><s<>< t><>, a<Yr atJt P 61 Milne Point Unit L-50 Drilling Procedure -IsOlt 1W t3(;;�<'i�i; x"t < t < t • • < < t a > )'Y . . . c > S'!<S `a's`Y Page 46 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure 30.0 Casing Design Information Calculation & Casing Design Factors DATE: 7/8/2015 WELL: MPU L-50 DESIGN BY:Luke Keller Design Criteria: Hole Size 12-1/4" Mud Density: 9.5 ppg Hole Size 8-112" Mud Density: 9.5 ppg Hole Size Mud Density: Drilling Mode MASP: 1398 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 1398 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psilft) and the casing evacuated for the internal stress Page 47 Version 1 July, 2015 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" 5-1/2" Top (MD) 0 8,335 To VD 0 4,028 Bottom MD 8,535 13,918 Bottom TVD 4,028 4,028 Length 8,535 5,583 Wei ht 40 17 Grade L-80 L-80 Connection TC -11 DWC/C HT Weight w/o Bouyancy Factor lbs 341,400 94,903 Tension at Top of Section lbs 341,400 94,903 Min strength Tension 1000 lbs 916 347 Worst Case Safety Factor Tension 2.68 3.66 Collapse Pressure at bottom Psi 1,990 1,990 Collapse Resistance w/o tension (Psi) 3,090 7,100 Worst Case Safety Factor (Collapse) 1.55 3.57 MASP(psi) 1,398 1,398 Minimum Yield (psi) 5,750 71740 Worst case safety factor(Burst) 4.11 1 5.54 Page 47 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure 31.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation HSS A 8-1/2" Hole Section MPU L-50 Milne Point Unit MD TVD Planned Top: 8535 4027 Planned TD: 13917.5 4027.8 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff OA Sand 4,027 1798 1 Oil/Wet 8.6 V 1 0.447 Offset Well Mud Densities Well MW range Top (TVD) Bottom TVD Date L-37 (1998) 8.9 - 9.3 Surface 7,050 1998 L-35 (1997) 8.4-9.2 Surface 5,687 1997 L -34i 1997 8.4-9.4 Surface 5,842 1997 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 4-5/8" shoe considering a full column of gas from shoe to surface: 4027.8 (ft) x 0.78(psi/ft)= 3142 psi 3142(psi) - [0.1(psi/ft)*4027.8(ft))= r2740 psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 4027.8 (ft) x 0.447(psi/ft)= 1800 psi 1800(psi) - 0.1(psi/ft)*4027.8(ft)= 1398 si Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 48 Version 1 July, 2015 Milne Point Unit L-50 Drilling Procedure Hilcorp Energy Company 32.0 Spider Plot (NAD 27) (Governmental Sections) Milne Point Unit MPL-50 Well 0 1,000 2,000 3,000 ,. ,.�.,,, Feet Page 49 Version 1 July, 2015 Hilcorp F --v c-11my 33.0 Surface Plat As Built NAD 2 ) I 5�7 1 X I y r I 1 32 . 33 ■ 1 I 28 ■ 29 ■ I I ' 24 ■ 25 ■ / 20 ■ 21 ■ I —N- 16 ■ 17 ■ 41 ■ 43 ■ / r 48■ I i I I P ,3 ■ ■ N 39 ■ ■ 42 1 ■ ■ 9 314 ■ .4 3 ■ ■ iC I 15 ■ L-47 I 2 ■ ■ 7 I t 2 ■ �^'- �, ■ 49 400 ■■■■■ ■-�■ I 6 35 4 36 5 37 11 048 48 ItI yQ � I I J L—PAD I � I GRAPHIC SCALE p 100 200 400 ( IN rE-t-, ) d F • A 4'4s 1 inch - 200 11. SURVEYOR'S. CERTIFICATE I HEREBY CERTIFY THAT I AM .. PROPERLY REGSTEREC AND LICENSED TO PRACTICE LAND SURVEYING IN .,4 ... ..Uii1. THE STATE OF ALASKA AND THAT THIS AS -BURT REPRESENTS A SURVEY � • R Drd ` e" AUFson MACE BY ME OR UNDER MY DIRECT 106,08 SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF JANUARY 11. 199,9 FOR WELL L-50 AND AS OF JULY !O. 1996 FOR WELL L-47. Milne Point UnitL-50 Drilling Procedure :] 34 31 1 32 I 33 I I I � � I T 14 "13 N 9 F -FA 4- - ----—�— Tm PROJECT r 13 10 1 17 r + I 1 . 1 24 J+ 19 1 20 1 21 1 IRT.S. I QEND - AS -BUILT WELL. CONDUCTOR RENAMED ■ EMSTING CONDUCTOR NOTES: t_ ALASKA STATE PLANE COORDINATES ARE ZONE 4. NAO27, 2. BASIS OF LOCATION IS L -PAD MONUMENTS L-1 NORTH AND L-2 SOUTH. 3. BASIS OF ELEVATION IS MSL. 4. GEODETIC POSIIMS ARE NAD27, S. PAD MEAN SCALE FACTOR IS 0.9999023 6. DATE OF SURVEY: JANUARY 11 & JULY 10, 1996. 1, REFERENCE FIELD BOOKS; MP95-01 PGS. 7-8 8 MPOO-07 PGS, 19-24. a REFERENCE DRAWINGS UPLPADAS WELL L-36 d MPLPADA3 HELL L-44. RENAMED CONDUCTOR REVISM-NOTE WELLS: 47 AND 50 74S AS-M.MT DRAWING IS A REISSUE OF A PREVIOUS AS-BU1L7 DRATANG FOR CONDUCTORS 33 AND 44, RENAMED CONDUCTORS ARE AS FOLLOWS: OLD GOND. NAME NEYJ GOND. NAME L-38 L-50 L-44 L- 47 I nf`AT€11 1MTWIIJ PPnTRArTFTO CFF' R T 11 Ni. R. 10 F. 11MIAT MFRICIIAN. AIC. WELL A.S.P. PLANT GEODETIC GEOQETIC Gpot,t' ! YE';TiON NO. COORDINATES COORDINATES POSITION(DMS)'POSITION(D.00) ELEV_ OFFSETS L-47 Y= 6,031.641.90 N- 1230.03 70'29'50.316" 70.4973100' 16.' 9 3,450' FSL X= 545 157.43 Ew 1509.06 149'37'50.603- 149. 7 31- 4 722' FEL -- L-50 Y-6.031,462.90 N= 1109.80 70'29'48.559" 70.4968219' 178 3,272' FSL X= 545 097.84 E= 1363.65 149'•37'5 , 149.6312192' . 4783' FEL WEI .. -.-. WMF HOLlAWAY H1lcorpAI ska MIs MPL 02 MPRJ L -PAD RENAUM CONDUCTORS HELLS L-47 & L-50 vu� 1 °` t L7• - 2w Page 50 Version 1 July, 2015 HilmT��v�r 34.0 Offset MW vs TVD Chart MW vs TVD Offsets 0 ttt kit`,di; 9 a 4000 5000 .tart 7000 rrtt Milne Point Unit L-50 Drilling Procedure 8.0 4.0 10.0 11.0 12.0 13.0 14.0 15.0 Mud Weight (PPG) Page 51 Version 1 July, 2015 Hilcorp Energy Company 35.0 Drill Pipe Information 5" 19.5# S-135 DS -50 Drill Pipe Configuration A 1 Pipe Body OD - 5.000 Pipe Body Wall Thickness tri 0.362 Pipe Body Grade S-135 Drill Pipe Length Range2 Connection GPDS50 Tod Joint OD 6.625 Tool Joint ID 3250 Pin Tong 9 Box Tong 12 Milne Point Unit L-50 Drilling Procedure 80 % Inspection Class Nominal Weight Designation 119.50 Drill Pipe Approximate Length sltl 31.5 SmoothEdge Height {Int 3132 Raised Tool Joint SMYS cps4 120 000 Upset Type IEU Max Upset OD (DTE) m+ 5.125 Friction Factor 1.0 Nate: Torp space may Include hwcracir+g. Drill Pipe Performance Drill -Pipe Length Rangel Performance of Drill Pipe with Pipe Bodv at Best Estimates Nominal 80 % Inspection Class ewo-dCoxeml I (.Rh Coburg) (Ibasi -.1e) wooled raalle.to Operational Max Tension Shoulder Information SmoothEdge Height 3132 Raised Drill Pipe Adjusted Weight 0-111 24.11 23.29 0.36 Tri tn4bs? Torque 4ft4bsy obs) 124 Fluid Displacement (g -n) 0.37 Fluid Displacement cault�n 80% Pipe Torsional S1re h Tension only 0 560,800 0.0085 MUT 43,100 aanbmedLoncre39,600 410,500 4vu, 17,105 Fluid Ca (tortl) 0.70 15,638 0.72 Fluid Capacity cBblsmt 0.0169 0.016T 0.0172 36,100 Tension Only 0 560,800 3.125 at+tnfart MUT Drift Size cln+ U6 cant`nad t. -1p 32.100 467.400 Note. OY field bsrcl egLLlis 42 US padlOns. hlafe: Drill pipe assembly values are best estimates and Iruy vary due to pipe body mill toierarc , Interval plastic coatnp, wW olhtr racers. Connection Performance GPD= ( 6.625 (in) OD X 3.250 cni ID ) 120,000 (Pal{ NOW The masimum make- 4xque shmid be applied abm posslt* Note To maalmue connectbn operational lensre. a MUT IT4l - 37 1,00 ihabs? should be apNkd_ Elevator Tod Joint Torsional StrenWh (lwos) 171.800 Pipe Tensile Strength Tod Joint Tensile Strength tett I 1,250.000 H�d 560,800 Shoulder Information SmoothEdge Height 3132 Raised (ft -1- 74.100 Box CID inns 6.812 Elevator Ca aci nx 1,658,000 Tool Joint Dimensions Balanced OO im 6.435 saf.riurn Tool .soft as Aar AFI 5.930 Premium Gass Un AaruiTi Tobi .tarts oo ar 5.93 Comlerbore {In Elevator OD 3132 Raised 6.812 (in) Tool Joint Wom to Bevel Wom to Min TJ OD for OD I Diameter I API Premium Class 5219 Norte: Elevalu caPacny b__,_' m assumed Elevator Bore, w wear factor. and cmtaet stress of 110,10[$51. ( Assumed Elevator Bore Diameter Nott- A rafted efevatof OD Increases elevator capadty -.M-t Iff-fng make -un torque. Pipe Body Slip Crushing Capacity Pipe Body Configuration ( 5 On) OD 0.362 fn) Wall S-135) Nominal 1 80 % Inspection Class I API Premium Class tq[Slip Crushinn Ca (lb -) 1498,300 1396,500 1396,5DO ly/ N➢0o-: Lp foe Ynp Sip otenlrg bad Is calcuafed rAh M SpIOLRtnMd equaaon hom Wry Does Ddl Pipe Assumed SUD Length ml 16.5 Fal+n We Skp AmY MM Oa 7939 nor ne 9p lerp7t aW bansae- kvd run st- and b w reference Transverse Load Factor tKl 14.2 g y p°depeAtle � ard�na"01AI1 m"da°`m".bate°` ,'kr rys, n'al pipe 8a and wok vanauar, and ane tacxrs. Coreul trio IM sap msuraircq Tar adlloed 1•lgrmsllcrl. Pipe Bodv Performance Pipe Body Configuration ( 5 On) OD 0.362 (in) Wall S-135) Page 52 Version 1 July, 2015 Note: NorNnal Bumf cakulated at 57.5% Raw per API. Nominal 80 % Inspection Class API Premium class Pipe Tensile Strength crost 712100 560.8m 560,800 Pipe Torsional S (ft -1- 74.100 58,100 58,100 TJIPlpeBodyTorsional Ratio 0.97 124 1,24 80% Pipe Torsional S1re h cn-Ibtl 59.300 46,500 46,500 Burst 4vu, 17,105 15.638 15,638 Collapse (1-115.672 10,029 10,029 Pipe OD int 5.000 4.855 4.855 Wail Thickness (1-1 0.362 0.290 0.290 Nominal ID lint 4276 4.276 4.276 Cross Sectional Area of Pipe Body un^2i 5275 4,154 4.154 Cross Sectional Area of OD cn+2t 19.635 18.514 18.514 Cross Sectional Area of ID on^2l 14.360 14.360 14.360 Section Modulus in•st 5.708 4.476 4.476 Polar Section Modulus (1..31 111.415 18.953 18.953 Version 1 July, 2015 Note: NorNnal Bumf cakulated at 57.5% Raw per API. Milne Point Unit L-50 Drilling Procedure Hilcorp Bnersy Company operational Limits of Drill Pipe Cannedlon 6PDS50 Tool Joint OD ; 6.625 Tool Joint ID �,. 3.250 Tool Joint Specified Minimum 120 00Q Yield Strength es l Pipe Body F-8 % Inspection Class Pipe Body OD ;,n, 5 Wall Thickness p+362 1 1 Pipe Body Grade S-135 Combined Loading for Drill Pipe at Maximum Make-up Torque= 43,100 kn-Its) Operational Assembly Torque Max Tension m4bs1 Itbs 0 560,800 2,100 560 400 4,200 559.300 6,300 557.500 8,300 555,000 10,400 551,700 12,500 547,600 14,600 542,800 16,700 537.100 18,800 530,600 20,800 523.600 22,900 515,400 25.000 506,200 27,100 496,100 29,200 484,800 31,300 1472,500 33,300 459 600 35,400 444300 37,500 428.400 39,600 410,500 Pipe Body jcwtvrffmFAax Max Tension Tenslm (MsI ilbs! 560,800 11,046,900 560,400 1,046.900 559,300 1,046.900 557,500 1,046,900 555,000 1,046.900 551,700 1,046,900 547,600 11,046.9DO 542,800 1,046:900 537,100 1,046.900 530,600 1.046.900 523,600 1,046.9D0 515,400 1,046,900 506,200 1,046,900 496,100 1,046,900 484,800 1,046.900 472,500 1,046,900 459,600 1,046.900 444,700 1,046,900 428.400 1,046.900 410,500 1,046.900 Operational drilling torque is limited by the Make-up Torque. Min MUT Max MUT Combined Loading for Drill Pipe at Minimum Make-up Torque = 36,100 Labs. Operation Assembly I Torque Max Tension (M-Ibs fibs) 0 560,800 1,700 560,500 3,400 559,800 5,100 15W,600 6,800 556,900 8.400 554.900 10,100 552,200 11,800 549,100 13,500 545,400 15.200 1541.200 16,900 536,500 18,600 531,300 20,300 525,400 22,000 519,000 23,700 512,000 25,300 504,800 27,000 496,600 28.700 487,600 30,400 477,900 32,100 467,400 Ph- auly connechcn Mm Tenaton Max Te Ian {1135 (lhsl 560.800 1,202,500 560.500 1.202,500 559.800 1,202,500 558,600 1,202,500 556,900 1,202,500 554.900 1.202.500 552.200 1,202,500 549.100 1,202,500 545.400 1,202,50+0 541.200 1,202.500 536.500 1,202,500 531,300 1,202,500 525.400 1,202,500 519.000 1,202,500 512.000 1,202,500 504.800 1,202300 496.600 11.202,SN 487.600 1,202,500 477.900 11202.500 467.400 1,202,500 Operational drilling torque is limited by the Make-up Torque_ Connection Flake -up Torque Range Make-up Torque Connection Max n -ria, Tension , 36,100 1,202,500 36,900 1,229,200 37,700 1,243,600 38,400 1,218,100 39,200 1,189,000 40,000 1,159, 800 40,800 1,130,700 41,500 1,105,200 42,300 1,076,100 43,100 1,046,900 Page 53 Version 1 July, 2015 Hilco p Milne Point Unit L-50 Drilling Procedure Connection Wear Table Conntxtion GPDS50Tool Joint OD 6.625 Tool Joint ID ,, y 3.250 Tool Joint Specified Minimum 120,004 Yield Strength ras Connection Wear New OD - - - worn OD Tool Joint OD ray 43,100 Connection Torsional Strength ,;rt-ias 6.625 71,800 6.562 71,800 6.499 71,800 6.435 71,800 6.372 71,200 6.309 68,000 6.246 64,800 6.183 61,700 6.12 58,600 6.056 55,500 5.993 52,600 5.93 49,600 Max MUT Connection Max Tension OW 43,100 1,046,900 43,100 1,034, 900 43,100 1,022,600 43,100 1,009,800 42,700 1,008,100 40,800 1,057,300 38,900 1,104,800 37,000 1,150,400 35,200 1,190,900 33,300 1,232,300 31,500 1,227,200 29,800 1,187,100 Pipe Body Combined Loading Table (Torque -Tension) Min MUT Connection Max Tension �n»esy c�s> 35,900 1,195.900 35,904 1,208.700 35,900 1,222.400 35,900 1,237,540 35,600 1,245,200 34,000 1,207.700 32.400 1,169,600 30,800 1,131.304 29.300 1,096.100 27,800 1,060.840 26,300 1,024.600 24,804 987,900 Pipe Body 1 80 % Inspection Class Pipe Body OD m, 5 Wall Thickness (n 0.362 Pipe Body Grade S-133 Pipe Body Torque 0 5.300 10.600 15.800 21.100 26.400 31,700 37.000 42.300 47.500 52,800 58.100 (114bs) Pepe Body Max560.800 Tension 558.400 551,400 539,600 522,500 499,600 470.000 432.400 384,500 323.100 234,300 12,200 ucs> Page 54 Version 1 July, 2015 Area of Review — Proposed MPL-50 Injection Well Prior to completion of the MPL-50 Schrader Bluff OA injection well, an Area of Review (AOR) must be conducted. This AOR found one other well, MPL-45, that enters the SB OA within mile of MPL-50's proposed lateral. The tables below illustrate the wells within the AOR, the distance from MPL-50, completion details and integrity conditions based on in-depth review of each well. Table 1: Wells within AOR Well Name PTD Distance, Ft. Annulus Integrity MPL-50 TBD 0' 9-5/8 casing to be cemented from injection zone to MPL-45 5-1/2" 7-7/8" 352 surface per drilling program page 22-26. MIT -IA of 3- MPL-47 9-5/8" 12-1/4" "'780.3 1/2" by 9-5/8" annulus to be completed to 1500 psi. MPL-45 198-169 As close as Packerless monobore ESP. 5.5" casing cemented to 15' in OA surface. No known integrity issues. MPL-47-: 215-117 TBD Will submit post completion Table 2: Completion Detail Well Name Casing Size Hole Size Vol Cement (bbls) Schrader Bluff OA Depth (MD) MPL-50 9-5/8" 12-1/4" 832.2 -8,500' MPL-45 5-1/2" 7-7/8" 352 7,808' MPL-47 9-5/8" 12-1/4" "'780.3 7,700' MPL-50 wvE we- wea talc: ae: 30 ft AGL aw aw rw.e raula eer <aa.an LaoRK. 17 ft . 30 ft - 87 ft ins aeo aeaM - 13,917_'5' MD roeaaea Tvo: 9,027.8' TVD ro lam.a,euea races 38 Tvo FY Lkh.W I Co duc �nraM awtnna laanec. 20" 1294 A -M dr6uen W 80' BGL Surface casing rw.00 T1mce nae u,W, sav^.Ma we Tc a.ae a alar ao � rrr aw s mnxua � = roxwmtsee: o E -4q ':. SMAace earinp c—M 4O_a z E. $ T.a1. tao-n ow Eseau swlorcEM i _ e o00 1 •• 1750' � e Tal. swlsTCEM r3awVo p1gRcncc.EM ra.T we Prodactlen Liner -- � e ' 4 calla+ a.arr Tli LiO DWC�C MT 1Yvr ®�a.fM1T.T MIO r �.qT-P Tvo ln,ac*— Tu" ' N:a^ e.aa L- aRn EUE t L S E _c uncr T .kr: aaa3n , \ Iwealen celanol Lx�ca a sanA xmre sand,.ssltY n �e, n.ar•. UGMU sa,aa nr�.ernr,s mak. �•\�'\ eem.s e. aakla.aer P sends mnEni u. �sed!M1 e _ InlccOon aehcr - swell okra -113' �Necr.+on uncr M PL -45 Tree: 2 1/16" 5M Gray MPU L-45 Orig. DF Elev. = 56.61'(N 27E) Wellhead: 7 1/16 " 5M Gray Orig. GL Elev. = 16.70' Tba. Hna: 2 3/8" x 7" Gray w/ 2 3/8" DF csg. hng. = 39.91'(N 27E) eue 8rd T&B / 2" CIW H BPV profile 7" 26#/ft L-80 37' 7"x 5.5"X -Over 20" 91.1 ppf, H-40 115' KOP as 600' Camco 2 3/8" x 1" 170' sidepocket KBMM GLM Max. hole angle = 98 deg.@ 9,140' (ID. 1.945") Hole angle thru perfs 5.5" Port Collar Cementer 1,009' and 2 3/8" 4.70" ppf, J-55, 8 rd EUE tbg.. ( drift ID =1.995 ", cap. = 0.00387 bpf) Camco 2 3/8" x 1" sidepocket KBMM GLM 3 446' (ID. 1.945") 5.5" 15.5 ppf, J-55, Btrc. prod. casing ( drift ID = 4.950", cap. = 0.0238 bpf ; 2-3/8" HES XN-Nipple ( 1.791" id) 3,461 Centrilift heat trace F-3.500' KUDU 10OTP1800 PCP, F7.115' 3.5" 9.3 #/ft slotted liner 7,789' - 9,301' Mid-perf MD = 8545' 90 deg. + at various places from 7,656' to pbtd Mid -pert TVD = 4074' 4053' TVD Baker Float shoe 9,363' DATE REV. BY I COMMENTS MILNE POINT UNIT 09/28/98 KJW Drilled and ESP Completion Nabors 27 WELL L-45 API NO: 50-029-22913 Centrilift flex shaft intake tvd F--37985' Centrilift seal section fstbdbilpfsaflashsn� 7151' Centrilift FMH series, 54 hp motor, 1020 v. / 35 7,163' amps. [ 9:01 Gear Box ] E777174' Centrilift PHD P Baker 5.5" x 3.5" C-2 setting sleeve 7,212 5.5' float collar 7,261' and 5.5" float shoe 7,343' and FFFFTTFFFr Liner Hanger Top TVD = 3982' 3.5" 9.3 #/ft slotted liner 7,789' - 9,301' Mid-perf MD = 8545' 90 deg. + at various places from 7,656' to pbtd Mid -pert TVD = 4074' 4053' TVD Baker Float shoe 9,363' DATE REV. BY I COMMENTS MILNE POINT UNIT 09/28/98 KJW Drilled and ESP Completion Nabors 27 WELL L-45 API NO: 50-029-22913 M PL -47 AFE No. IMM Name: KB: 30 ft AGL 1511125 Uum Point Unit (MPU) L-47 GL + RKB 17 ft + 30 It = 47 ft API TBD AFE WELLBORE DEMN Proposed TO: 13,002 Farrah No. TBD Proposed TVD: 4.067' Geologic Information Wellbore Information Casing Info I Mud Into I Hole Size 1 Cement Specs SS TVD FM Littloktgy Conductor mw ft� T.bl. *°' 13-W Conductor (Pre-set) to SO' SGL (110' RKB) (_. Interval.- c Sufecehoe Surface Casing MudJAe. E 0 9-=" 400 L-60 TC -a set at 7,041' MO 14,066' TVD fmsh Waten'Natiue ir - WeK" Rance: E o Surface Casing Cement 88-92 pa c � � list Stage: � E 60 We 10.5 ppg Tuned spacer III d ° 3 Lead: (30% OH Excess) ARCTICCEM @ 10.7 ppg a *a Tail: (30% OH Excess) SWIFTCEM 15.8 cog a 0 c 2nd stage: o '^ �a 60 D6Is 10.5 ppg Tuned spacer It j %Leatl:lUMi I returns at surface)ARCTICCEM 10 ppg 1750' 1 t Tat: SWIFTCEM 15.8 ppg Stage Collar u '. 25CO' MD / Production Liner c 5 -in- 170 L -W 011111CM HT Skirted Burr @ 13.002' MD 14,O6T TVD _ � m Tieback O Y u } q � 7 -WS- 20-70 L410 SLU-0 @ 7741' MD 14,066' TVD •C D _ Productlon Fullbing > e 8 g 2-7i8- 6:40 L-60 ORD EUE 00 p o S Z o m w r - a n a 5 c � liner Top Packer @ .q - 1 7741' MD -3500' c \ K -sands came sand,siky ale, better �`•� s ESP Iottsral: UGNU L -Sands developed ntervening shales \` �.. \ Bullet Seal Asry Slotted liner Paducliicn Hole Mud Type: -4000' M -sands in the Land M ... -' -- Baradril-N WegM Range: N -sands Continued layering ash Schrader n .�.... in Ugnu, mare condensed with occ. ., --._ — — 89-92ppg L-12 L-42 Prop L-49 Q A Prop_ L 4i rop_L-46 L-37 *000e .ice -47 L -37A/ Prop L-50 '000- HILCORP ALASKA LLC MILNE POINT FIELD AOR MAP Proposed MPL-50 Injector 0 1 139 2270 FEET WELL SYMBOLS • A.I. CAI rLwSnn . REMARKS Well Sym6a at tap U Schrader OA SaM 6.,; Per's In QA saM ngnaa0need Wrk 81a[k [:tlsn Cltcle- 1320'raidi-flan pmpo-14 OA InP 0-0 aM TO {toe) In UPL-50 J*912625 Schrader Bluff OA Map Illustrating AOR i J-18 ® w Hilcorp Energy Company Milne Point M Pt L Pad Plan MPL-50 - Slot 50* MPL-50 (well #5) Plan: MPL-50 wp3 Standard Proposal Report 01 July, 2015 HALLIBURTON Sperry Drilling Services HALLIBURTON Project: Milne Point Site: M Pt L Pad Well: Plan MPL-50 WELL DEM : Plan WI -50 NAD 1927(NADCON CONUS) Alaska? ne 04 Gloved L -d: 1780 +w -S +E/ -W NoWing Emfiq L Litt de LNW& slot sp.�w Or1111ne Wellbore: MPL-50 (well #5) 0.00 0.00 6031464.10 54509650 70.2948.571N 149"3T 52.429W 50" Design: MPL-50 wp3 FORMATION TOP DETAILS . -2000 No formation data is available -1500 -1000- -500 p Start Build 2.00 - - CASING DETAILS TVD TVDSS MD Size N- 500 500 Start DLS 4.00 TFO 56.25 4027.77 3979.97 8535.57 9-5/8 9 5/8" - -- 4027.80 3980.00 13917.57 5-1/2 51/2" Start 4236.44 hold at 2219.65 MD 1000 X000 7 15p0 N 1500 °O Start 500.00 hold 8035.88 MD tL 2000 at N Start DLS 5.50 TFO -94.11 Start DLS 5.00 TFC, 0.27 Start DLS 5.00 TFO -173.19 E O 2500 Start 1223.52 hold at 8839.95 MD', ' Start 500.00 hold at 13417.57 MD 2 ° F 3000 °o Start 3550.00 hold at 9867.57 MD TD at 13917.57 (Oho 3500 io M 000 4000- 4500— 4500 9 5/8" 5 1/2" 5000 5500 6000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 Vertical Section at 164.04° (1250 usft/in) FTM HALLIBURTON Project:Milne Point Site: M Pt L Pad Well: Plan MPLSO Wellbore: MPL-50 (well #5) soo Plan: MPL-50 wp3 start snda z.00 0 ,. SIvtDLS 4.023 TF056.25 Start 4236.44 hold at 2219,65 NO c -3500 �z'0 g 4000—sPo _ _ _ _ _ Stmt DLS 5.50 TFO -94.11 -0500 3750 Stan 500.00 hold et 8(35.88 MD 0 -5000 Start DLS 5.00 TEO 027 `n -5500 , - Stan 1223.52 hold at 8639.95 MD 9 5/8" Start IIS 5.00 TFO -173.19 x(100 - Start 3550.00 hold at 9867.57 MD Stan 5(0.00 11 at 1341.57 MD TD at 1391157 T M AzimuNa to True North Magnetc North: 18.87" Magnetic Field .1t' Strength: 57503.&s T ^� Dip Angle: 81.08° MPL-50 wp3 To -?q Date: 10/13/2015 Model: BGGWO15 5 WELL DETAIIS: Plan MP1,50 Ground Level: 17.80 +NI -S +E/_W Northing Easfing Latittude Longitude Slot 0.00 0.00 6031464.10 545096.50 70° 29' 48.571 N 149-37 52.429 W 50e REFERENCE INFORMATION Co<rdinab (NIE) RaM1rence: -11 11" MPI -50 - Slot 50', Trve Nodh Vedical (TVD) Reference: Plan MPLSO @ -80 -ft (Nordk 3 (1].8' LBE ♦ 30' KB)) Measured Depth Reference: Plan MPL-50 @4] 80 -ft (Nordic 3 (1].S LBE+30' KB1) C.1—tion Method: Minimum Curvatura CASING DETAILS TVD TVDSS MD Size Name 4027.77 3979.97 8535.57 9-5/8 9 5/8" 4027.80 3980.00 13917.57 5-1/2 51/2' -5500 -5000 -4500 4000 -3500 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 West( -)/East(+) (1500 usttln) �i HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Milne Point Site: M Pt L Pad Well: Plan MPL-50 Wellbore: MPL-50 (well #5) Design: MPL-50 wp3 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan MPL-50 - Slot 50* TVD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'N MD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'k North Reference: True Survey Calculation Method: Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Tie On Depth: 30.00 Map Zone: Alaska Zone 04 Using geodetic scale factor +E/ -W Direction (usft) (usft) (usft) (°) Site M Pt L Pad, TR -13-10 0.00 0.00 164.04 Site Position: Northing: 6,029,799.28 usft Latitude: 70° 29'32.230 N From: Map Easting: 544,529.55 usft Longitude: 149° 38'9.412 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.34 ° (usft) usft (usft) (usft) Well Plan MPL-50 - Slot 50*, BP MPL-38 Slot (°/100usft) Well Position +N/ -S 0.00 usft Northing: 6,031,464.10 usft Latitude: 70° 29'48.571 N -17.80 +E/ -W 0.00 usft Easting: 545,096.50 usft Longitude: 1490 37'52.429 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 17.80 usft 0.00 0.00 330.00 28220 Wellbore MPL-50 (well #5) 0.00 0.00 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 160.00 629.45 (I (°) (nT) 5.37 BGGM2015 10/13/2015 18.87 81.08 57,504 Plan Sections Audit Notes: Version: Phase: PLAN Tie On Depth: 30.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) Turn 30.00 0.00 0.00 164.04 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) 30.00 0.00 0.00 30.00 -17.80 0.00 0.00 0.00 0.00 0.00 0.00 330.00 0.00 0.00 330.00 28220 0.00 0.00 0.00 0.00 0.00 0.00 630.00 6.00 160.00 629.45 581.65 -14.75 5.37 2.00 2.00 0.00 160.00 2,219.65 67.02 213.98 1,859.10 1,811.30 -779,76 -419.80 4.00 3.84 3.40 56.25 6,456.09 67.02 213.98 3,513.04 3,465.24 -4,013.79 -2,599.92 0.00 0.00 0.00 0.00 8,035.88 85.00 125.25 3,984.22 3,936.42 -5,334.26 -2,304.99 5.50 1.14 -5.62 -94.11 8,535.88 85.00 125.25 4,027.80 3,980.00 -5,621.74 -1,898.22 0.00 0.00 0.00 0.00 8,639.95 90.20 125.27 4,032.15 3,984.35 -5,681.75 -1,813.35 5.00 5.00 0.02 0.27 9,863.47 90.20 125.27 4,027.81 3,980.01 -6,388.31 -814.48 0.00 0.00 0.00 0.00 9,867.57 90.00 125.25 4,027.80 3,980.00 -6,390.68 -811.13 5.00 -4.96 -0.59 -173.19 13,417.57 90.00 125.25 4,027.80 3,980.00 -8,439.55 2,087.94 0.00 0.00 0.00 0.00 13,917.57 90.00 125.25 4,027.80 3,980.00 -8,728.12 2,496.27 0.00 0.00 0.00 0.00 7/1/2015 2.16.41PM Page 2 COMPASS 5000.1 Build 73 Halliburton H A L L I B U R T O N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan MPL-50 - Slot 50' Company: Hilcorp Energy Company TVD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'P Project: Milne Point MD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'l, Site: M Pt L Pad North Reference: True Well: Plan MPL-50 Survey Calculation Method: Minimum Curvature Wellbore: MPL-50 (well #5) Design: MPL-50 wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N1S +E/ -W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) -17.80 30.00 0.00 0.00 30.00 -17.80 0.00 0.00 6,031,464.10 545,096.50 0.00 0.00 100.00 0.00 0.00 100.00 52.20 0.00 0.00 6,031,464.10 545,096.50 0.00 0.00 200.00 0.00 0.00 200.00 152.20 0.00 0.00 6,031,464.10 545,096.50 0.00 0.00 300.00 0.00 0.00 300.00 252.20 0.00 0.00 6,031,464.10 545,096.50 0.00 0.00 330.00 0.00 0.00 330.00 282.20 0.00 0.00 6,031,464.10 545,096.50 0.00 0.00 400.00 1.40 160.00 399.99 352.19 -0.80 0.29 6,031,463.30 545,096.80 2.00 0.85 500.00 3.40 160.00 499.90 452.10 -4.74 1.72 6,031,459.37 545,098.25 2.00 5.03 600.00 5.40 160.00 599.60 551.80 -11.95 4.35 6,031,452.18 545,100.92 2.00 12.68 630.00 6.00 160.00 629.45 581.65 -14.75 5.37 6,031,449.39 545,101.96 2.00 15.65 700.00 7.90 177.18 698.94 651.14 -22.99 6.86 6,031,441.15 545,103.49 4.00 23.99 800.00 11.29 190.19 797.54 749.74 -39.50 5.46 6,031,424.63 545,102.20 4.00 39.48 900.00 14.98 197.07 894.91 847.11 -61.50 -0.07 6,031,402.61 545,096.81 4.00 59.11 1,000.00 18.79 201.25 990.59 942.79 -88.88 -9.70 6,031,375.18 545,087.34 4.00 82.78 1,100.00 22.67 204.05 1,084.10 1,036.30 -121.50 -23.40 6,031,342.47 545,073.84 4.00 110.38 1,200.00 26.58 206.06 1,174.99 1,127.19 -159.21 -41.09 6,031,304.66 545,056.38 4.00 141.77 1,300.00 30.51 207.59 1,262.81 1,215.01 -201.82 -62.68 6,031,261.92 545,035.05 4.00 176.81 1,400.00 34.46 208.80 1,347.15 1,299.35 -249.13 -88.08 6,031,214.46 545,009.94 4.00 215.31 1,500.00 38.42 209.79 1,427.58 1,379.78 -300.91 -117.16 6,031,162.51 544,981.18 4.00 257.09 1,600.00 42.38 210.62 1,503.72 1,455.92 -356.90 -149.77 6,031,106.33 544,948.91 4.00 301.96 1,700.00 46.35 211.33 1,575.20 1,527.40 -416.83 -185.77 6,031,046.19 544,913.29 4.00 349.68 1,800.00 50.32 211.95 1,641.66 1,593.86 -480.41 -224.96 6,030,982.38 544,874.48 4.00 400.03 1,900.00 54.30 212.51 1,702.79 1,654.99 -547.33 -267.17 6,030,915.21 544,832.69 4.00 452.77 2,000.00 58.28 213.01 1,758.28 1,710.48 -617.26 -312.18 6,030,845.02 544,788.10 4.00 507.63 2,100.00 62.26 213.47 1,807.87 1,760.07 -689.87 -359.78 6,030,772.13 544,740.95 4.00 564.34 2,200.00 66.24 213.90 1,851.31 1,803.51 -764.79 -409.73 6,030,696.91 544,691.46 4.00 622.64 2,219.65 67.02 213.98 1,859.10 1,811.30 -779.76 -419.80 6,030,681.89 544,681.48 4.00 634.26 2,300.00 67.02 213.98 1,890.47 1,842.67 -841.09 -461.15 6,030,620.31 544,640.50 0.00 681.86 2,400.00 67.02 213.98 1,929.51 1,881.71 -917.43 -512.61 6,030,543.67 544,589.51 0.00 741.11 2,500.00 67.02 213.98 1,968.55 1,920.75 -993.77 -564.07 6,030,467.02 544,538.52 0.00 800.35 2,600.00 67.02 213.98 2,007.59 1,959.79 -1,070.11 -615.54 6,030,390.38 544,487.53 0.00 859.60 2,700.00 67.02 213.98 2,046.63 1,998.83 -1,146.45 -667.00 6,030,313.74 544,436.54 0.00 918.84 2,800.00 67.02 213.98 2,085.67 2,037.87 -1,222.78 -718.46 6,030,237.10 544,385.54 0.00 978.09 2,900.00 67.02 213.98 2,124.72 2,076.92 -1,299.12 -769.92 6,030,160.46 544,334.55 0.00 1,037.33 3,000.00 67.02 213.98 2,163.76 2,115.96 -1,375.46 -821.38 6,030,083.81 544,283.56 0.00 1,096.58 3,100.00 67.02 213.98 2,202.80 2,155.00 -1,451.80 -872.84 6,030,007.17 544,232.57 0.00 1,155.82 3,200.00 67.02 213.98 2,241.84 2,194.04 -1,528.14 -924.30 6,029,930.53 544,181.58 0.00 1,215.07 3,300.00 67.02 213.98 2,280.88 2,233.08 -1,604.48 -975.76 6,029,853.89 544,130.58 0.00 1,274.31 3,400.00 67.02 213.98 2,319.92 2,272.12 -1,680.82 -1,027.22 6,029,777.25 544,079.59 0.00 1,333.56 3,500.00 67.02 213.98 2,358.96 2,311.16 -1,757.16 -1,078.69 6,029,700.61 544,028.60 0.00 1,392.80 3,600.00 67.02 213.98 2,398.00 2,350.20 -1,833.49 -1,130.15 6,029,623.96 543,977.61 0.00 1,452.05 3,700.00 67.02 213.98 2,437.04 2,389.24 -1,909.83 -1,181.61 6,029,547.32 543,926.62 0.00 1,511.29 3,800.00 67.02 213.98 2,476.08 2,428.28 -1,986.17 -1,233.07 6,029,470.68 543,875.62 0.00 1,570.54 3,900.00 67.02 213.98 2,515.12 2,467.32 -2,062.51 -1,284.53 6,029,394.04 543,824.63 0.00 1,629.78 4,000.00 67.02 213.98 2,554.16 2,506.36 -2,138.85 -1,335.99 6,029,317.40 543,773.64 0.00 1,689.03 4,100.00 67.02 213.98 2,593.20 2,545.40 -2,215.19 -1,387.45 6,029,240.75 543,722.65 0.00 1,748.27 7/1/2015 2:16:41PM Page 3 COMPASS 5000.1 Build 73 Planned Survey Halliburton H A L L I B U R T O N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan MPL-50 - Slot 50' Company: Hilcorp Energy Company TVD Reference: Pian MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'P Project: Milne Point MD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'P Site: M Pt L Pad North Reference: True Well: Plan MPL-50 Survey Calculation Method: Minimum Curvature Wellbore: MPL-50 (well #5) Depth Inclination Design: MPL-50 wp3 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) V) 0 (usft) usft (usft) (usft) (usft) (usft) 2,584.44 4,200.00 67.02 213.98 2,632.24 2,584.44 -2,291.53 -1,438.91 6,029,164.11 543,671.66 0.00 1,807.52 4,300.00 67.02 213.98 2,671.28 2,623.48 -2,367.86 -1,490.37 6,029,087.47 543,620.66 0.00 1,866.77 4,400.00 67.02 213.98 2,710.32 2,662.52 -2,444.20 -1,541.84 6,029,010.83 543,569.67 0.00 1,926.01 4,500.00 67.02 213.98 2,749.37 2,701.57 -2,520.54 -1,593.30 6,028,934.19 543,518.68 0.00 1,985.26 4,600.00 67.02 213.98 2,788.41 2,740.61 -2,596.88 -1,644.76 6,028,857.54 543,467.69 0.00 2,044.50 4,700.00 67.02 213.98 2,827.45 2,779.65 -2,673.22 -1,696.22 6,028,780.90 543,416.70 0.00 2,103.75 4,800.00 67.02 213.98 2,866.49 2,818.69 -2,749.56 -1,747.68 6,028,704.26 543,365.70 0.00 2,162.99 4,900.00 67.02 213.98 2,905.53 2,857.73 -2,825.90 -1,799.14 6,028,627.62 543,314.71 0.00 2,222.24 5,000.00 67.02 213.98 2,944.57 2,896.77 -2,902.23 -1,850.60 6,028,550.98 543,263.72 0.00 2,281.48 5,100.00 67.02 213.98 2,983.61 2,935.81 -2,978.57 -1,902.06 6,028,474.33 543,212.73 0.00 2,340.73 5,200.00 67.02 213.98 3,022.65 2,974.85 -3,054.91 -1,953.52 6,028,397.69 543,161.73 0.00 2,399.97 5,300.00 67.02 213.98 3,061.69 3,013.89 -3,131.25 -2,004.99 6,028,321.05 543,110.74 0.00 2,459.22 5,400.00 67.02 213.98 3,100.73 3,052.93 -3,207.59 -2,056.45 6,028,244.41 543,059.75 0.00 2,518.46 5,500.00 67.02 213.98 3,139.77 3,091.97 -3,283.93 -2,107.91 6,028,167.77 543,008.76 0.00 2,577.71 5,600.00 67.02 213.98 3,178.81 3,131.01 -3,360.27 -2,159.37 6,028,091.12 542,957.77 0.00 2,636.95 5,700.00 67.02 213.98 3,217.85 3,170.05 -3,436.60 -2,210.83 6,028,014.48 542,906.77 0.00 2,696.20 5,800.00 67.02 213.98 3,256.89 3,209.09 -3,512.94 -2,262.29 6,027,937.84 542,855.78 0.00 2,755.44 5,900.00 67.02 213.98 3,295.93 3,248.13 -3,589.28 -2,313.75 6,027,861.20 542,804.79 0.00 2,814.69 6,000.00 67.02 213.98 3,334.97 3,287.17 -3,665.62 -2,365.21 6,027,784.56 542,753.80 0.00 2,873.93 6,100.00 67.02 213.98 3,374.02 3,326.22 -3,741.96 -2,416.67 6,027,707.91 542,702.81 0.00 2,933.18 6,200.00 67.02 213.98 3,413.06 3,365.26 -3,818.30 -2,468.14 6,027,631.27 542,651.81 0.00 2,992.42 6,300.00 67.02 213.98 3,452.10 3,404.30 -3,894.64 -2,519.60 6,027,554.63 542,600.82 0.00 3,051.67 6,400.00 67.02 213.98 3,491.14 3,443.34 -3,970.97 -2,571.06 6,027,477.99 542,549.83 0.00 3,110.91 6,456.09 67.02 213.98 3,513.04 3,465.24 -4,013.79 -2,599.92 6,027,435.00 542,521.23 0.00 3,144.15 6,500.00 66.87 211.37 3,530.23 3,482.43 -4,047.80 -2,621.73 6,027,400.87 542,499.63 5.50 3,170.84 6,600.00 66.69 205.38 3,569.70 3,521.90 -4,128.61 -2,665.38 6,027,319.80 542,456.47 5.50 3,236.53 6,700.00 66.73 199.39 3,609.27 3,561.47 -4,213.48 -2,700.34 6,027,234.73 542,422.03 5.50 3,308.52 6,800.00 67.00 193.42 3,648.59 3,600.79 -4,301.64 -2,726.30 6,027,146.42 542,396.61 5.50 3,386.15 6,900.00 67.49 187.48 3,687.30 3,639.50 -4,392.28 -2,743.01 6,027,055.69 542,380.46 5.50 3,468.69 7,000.00 68.20 181.59 3,725.03 3,677.23 -4,484.56 -2,750.32 6,026,963.38 542,373.71 5.50 3,555.40 7,100.00 69.12 175.77 3,761.45 3,713.65 -4,577.62 -2,748.16 6,026,870.34 542,376.43 5.50 3,645.48 7,200.00 70.23 170.02 3,796.21 3,748.41 -4,670.62 -2,736.55 6,026,777.42 542,388.60 5.50 3,738.08 7,300.00 71.52 164.36 3,829.00 3,781.20 -4,762.70 -2,715.60 6,026,685.48 542,410.11 5.50 3,832.37 7,400.00 72.97 158.79 3,859.52 3,811.72 -4,853.01 -2,685.50 6,026,595.37 542,440.75 5.50 3,927.47 7,500.00 74.58 153.31 3,887.48 3,839.68 -4,940.71 -2,646.53 6,026,507.91 542,480.25 5.50 4,022.51 7,600.00 76.32 147.92 3,912.62 3,864.82 -5,025.01 -2,599.05 6,026,423.91 542,528.24 5.50 4,116.62 7,700.00 78.17 142.61 3,934.72 3,886.92 -5,105.11 -2,543.49 6,026,344.15 542,584.27 5.50 4,208.91 7,800.00 80.12 137.38 3,953.57 3,905.77 -5,180.30 -2,480.37 6,026,269.35 542,647.84 5.50 4,298.56 7,900.00 82.15 132.20 3,968.99 3,921.19 -5,249.87 -2,410.27 6,026,200.22 542,718.36 5.50 4,384.72 8,000.00 84.24 127.08 3,980.86 3,933.06 -5,313.18 -2,333.83 6,026,137.38 542,795.17 5.50 4,466.61 8,035.88 85.00 125.25 3,984.22 3,936.42 -5,334.26 -2,304.99 6,026,116.47 542,824.14 5.50 4,494.81 8,100.00 85.00 125.25 3,989.81 3,942.01 -5,371.13 -2,252.83 6,026,079.93 542,876.52 0.00 4,544.60 8,200.00 85.00 125.25 3,998.53 3,950.73 -5,428.62 -2,171.48 6,026,022.93 542,958.21 0.00 4,622.25 8,300.00 85.00 125.25 4,007.24 3,959.44 -5,486.12 -2,090.12 6,025,965.94 543,039.90 0.00 4,699.89 8,400.00 85.00 125.25 4,015.96 3,968.16 -5,543.61 -2,008.77 6,025,908.95 543,121.59 0.00 4,777.54 7/1/2015 2:16:41PM Page 4 COMPASS 5000.1 Build 73 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan MPL-50 - Slot 50' Company: Hilcorp Energy Company TVD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'P Project: Milne Point MD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'P Site: M Pt L Pad North Reference: True Well: Pian MPL-50 Survey Calculation Method: Minimum Curvature Wellbore: MPL-50 (well #5) Depth Inclination Design: MPL-50 wp3 TVDss +NlS Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NlS +EI -W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) 3,976.87 8,500.00 85.00 125.25 4,024.67 3,976.87 -5,601.11 -1,927.42 6,025,851.95 543,203.29 0.00 4,855.19 8,535.57 85.00 125.25 4,027.77 3,979.97 -5,621.56 -1,898.48 6,025,831.68 543,232.35 0.00 4,882.81 _ 95/8, 8,535.88 85.00 125.25 4,027.80 3,980.00 -5,621.74 -1,898.22 6,025,831.50 543,232.60 0.00 4,883.05 8,600.00 88.21 125.26 4,031.60 3,983.80 -5,658.68 -1,845.97 6,025,794.88 543,285.08 5.00 4,932.94 8,639.95 90.20 125.27 4,032.15 3,984.35 -5,681.75 -1,813.35 6,025,772.01 543,317.83 5.00 4,964.09 8,700.00 90.20 125.27 4,031.94 3,984.14 -5,716.42 -1,764.33 6,025,737.64 543,367.05 0.00 5,010.91 8,800.00 90.20 125.27 4,031.58 3,983.78 -5,774.17 -1,682.69 6,025,680.39 543,449.03 0.00 5,088.88 8,900.00 90.20 125.27 4,031.23 3,983.43 -5,831.92 -1,601.05 6,025,623.14 543,531.01 0.00 5,166.85 9,000.00 90.20 125.27 4,030.87 3,983.07 -5,889.67 -1,519.41 6,025,565.90 543,612.99 0.00 5,244.82 9,100.00 90.20 125.27 4,030.52 3,982.72 -5,947.42 -1,437.77 6,025,508.65 543,694.97 0.00 5,322.79 9,200.00 90.20 125.27 4,030.16 3,982.36 -6,005.17 -1,356.13 6,025,451.40 543,776.95 0.00 5,400.77 9,300.00 90.20 125.27 4,029.81 3,982.01 -6,062.92 -1,274.49 6,025,394.16 543,858.93 0.00 5,478.74 9,400.00 90.20 125.27 4,029.45 3,981.65 -6,120.66 -1,192.86 6,025,336.91 543,940.91 0.00 5,556.71 9,500.00 90.20 125.27 4,029.10 3,981.30 -6,178.41 -1,111.22 6,025,279.66 544,022.89 0.00 5,634.68 9,600.00 90.20 125.27 4,028.74 3,980.94 -6,236.16 -1,029.58 6,025,222.42 544,104.87 0.00 5,712.65 9,700.00 90.20 125.27 4,028.39 3,980.59 -6,293.91 -947.94 6,025,165.17 544,186.85 0.00 5,790.62 9,800.00 90.20 125.27 4,028.03 3,980.23 -6,351.66 -866.30 6,025,107.92 544,268.83 0.00 5,868.59 9,863.47 90.20 125.27 4,027.81 3,980.01 -6,388.31 -814.48 6,025,071.59 544,320.87 0.00 5,918.09 9,867.57 90.00 125.25 4,027.80 3,980.00 -6,390.68 -811.13 6,025,069.24 544,324.23 5.00 5,921.28 9,900.00 90.00 125.25 4,027.80 3,980.00 -6,409.40 -784.65 6,025,050.69 544,350.82 0.00 5,946.56 10,000.00 90.00 125.25 4,027.80 3,980.00 -6,467.11 -702.99 6,024,993.48 544,432.83 0.00 6,024.50 10,100.00 90.00 125.25 4,027.80 3,980.00 -6,524.83 -621.32 6,024,936.26 544,514.83 0.00 6,102.45 10,200.00 90.00 125.25 4,027.80 3,980.00 -6,582.54 -539.66 6,024,879.05 544,596.84 0.00 6,180.39 10,300.00 90.00 125.25 4,027.80 3,980.00 -6,640.25 -457.99 6,024,821.84 544,678.84 0.00 6,258.34 10,400.00 90.00 125.25 4,027.80 3,980.00 -6,697.97 -376.33 6,024,764.63 544,760.85 0.00 6,336.28 10,500.00 90.00 125.25 4,027.80 3,980.00 -6,755.68 -294.67 6,024,707.41 544,842.85 0.00 6,414.23 10,600.00 90.00 125.25 4,027.80 3,980.00 -6,813.40 -213.00 6,024,650.20 544,924.86 0.00 6,492.18 10,700.00 90.00 125.25 4,027.80 3,980.00 -6,871.11 -131.34 6,024,592.99 545,006.86 0.00 6,570.12 10,800.00 90.00 125.25 4,027.80 3,980.00 -6,928.83 -49.67 6,024,535.78 545,088.87 0.00 6,648.07 10,900.00 90.00 125.25 4,027.80 3,980.00 -6,986.54 31.99 6,024,478.56 545,170.87 0.00 6,726.01 11,000.00 90.00 125.25 4,027.80 3,980.00 -7,044.26 113.65 6,024,421.35 545,252.87 0.00 6,803.96 11,100.00 90.00 125.25 4,027.80 3,980.00 -7,101.97 195.32 6,024,364.14 545,334.88 0.00 6,881.90 11,200.00 90.00 125.25 4,027.80 3,980.00 -7,159.68 276.98 6,024,306.93 545,416.88 0.00 6,959.85 11,300.00 90.00 125.25 4,027.80 3,980.00 -7,217.40 358.65 6,024,249.71 545,498.89 0.00 7,037.79 11,400.00 90.00 125.25 4,027.80 3,980.00 -7,275.11 440.31 6,024,192.50 545,580.89 0.00 7,115.74 11,500.00 90.00 125.25 4,027.80 3,980.00 -7,332.83 521.98 6,024,135.29 545,662.90 0.00 7,193.68 11,600.00 90.00 125.25 4,027.80 3,980.00 -7,390.54 603.64 6,024,078.08 545,744.90 0.00 7,271.63 11,700.00 90.00 125.25 4,027.80 3,980.00 -7,448.26 685.30 6,024,020.86 545,826.91 0.00 7,349.58 11,800.00 90.00 125.25 4,027.80 3,980.00 -7,505.97 766.97 6,023,963.65 545,908.91 0.00 7,427.52 11,900.00 90.00 125.25 4,027.80 3,980.00 -7,563.69 848.63 6,023,906.44 545,990.92 0.00 7,505.47 12,000.00 90.00 125.25 4,027.80 3,980.00 -7,621.40 930.30 6,023,849.23 546,072.92 0.00 7,583.41 12,100.00 90.00 125.25 4,027.80 3,980.00 -7,679.12 1,011.96 6,023,792.01 546,154.93 0.00 7,661.36 12,200.00 90.00 125.25 4,027.80 3,980.00 -7,736.83 1,093.62 6,023,734.80 546,236.93 0.00 7,739.30 12,300.00 90.00 125.25 4,027.80 3,980.00 -7,794.54 1,175.29 6,023,677.59 546,318.94 0.00 7,817.25 7/1/2015 2:16:41PM Page 5 COMPASS 5000.1 Build 73 Halliburton H A L L I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan MPL-50 - Slot 50' Company: Hilcorp Energy Company TVD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30' N Project: Milne Point MD Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30'P Site: M Pt L Pad North Reference: True Well: Plan MPL-50 Survey Calculation Method: Minimum Curvature Wellbore: MPL-50 (well #5) Depth Inclination Design: MPL-50 wp3 TVDss +N/ -S Planned Survey Measured Vertical Target Name Hole Depth Depth Diameter Measured hittmiss target Dip Angle Dip Dir. TVD Vertical +E/ -W Northing Easting Map Map (usft) (usft) Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,980.00 0.00 0.35 4,027.80 12,400.00 90.00 125.25 4,027.80 3,980.00 -7,852.26 1,256.95 6,023,620.38 546,400.94 0.00 7,895.19 12,500.00 90.00 125.25 4,027.80 3,980.00 -7,909.97 1,338.62 6,023,563.17 546,482.95 0.00 7,973.14 12,600.00 90.00 125.25 4,027.80 3,980.00 -7,967.69 1,420.28 6,023,505.95 546,564.95 0.00 8,051.08 12,700.00 90.00 125.25 4,027.80 3,980.00 -8,025.40 1,501.95 6,023,448.74 546,646.96 0.00 8,129.03 12,800.00 90.00 125.25 4,027.80 3,980.00 -8,083.12 1,583.61 6,023,391.53 546,728.96 0.00 8,206.98 12,900.00 90.00 125.25 4,027.80 3,980.00 -8,140.83 1,665.27 6,023,334.32 546,810.97 0.00 8,284.92 13,000.00 90.00 125.25 4,027.80 3,980.00 -8,198.55 1,746.94 6,023,277.10 546,892.97 0.00 8,362.87 13,100.00 90.00 125.25 4,027.80 3,980.00 -8,256.26 1,828.60 6,023,219.89 546,974.98 0.00 8,440.81 13,200.00 90.00 125.25 4,027.80 3,980.00 -8,313.98 1,910.27 6,023,162.68 547,056.98 0.00 8,518.76 13,300.00 90.00 125.25 4,027.80 3,980.00 -8,371.69 1,991.93 6,023,105.47 547,138.99 0.00 8,596.70 13,400.00 90.00 125.25 4,027.80 3,980.00 -8,429.40 2,073.59 6,023,048.25 547,220.99 0.00 8,674.65 13,417.57 90.00 125.25 4,027.80 3,980.00 -8,439.55 2,087.94 6,023,038.20 547,235.40 0.00 8,688.34 13,500.00 90.00 125.25 4,027.80 3,980.00 -8,487.12 2,155.26 6,022,991.04 547,302.99 0.00 8,752.59 13,600.00 90.00 125.25 4,027.80 3,980.00 -8,544.83 2,236.92 6,022,933.83 547,385.00 0.00 8,830.54 13,700.00 90.00 125.25 4,027.80 3,980.00 -8,602.55 2,318.59 6,022,876.62 547,467.00 0.00 8,908.48 13,800.00 90.00 125.25 4,027.80 3,980.00 -8,660.26 2,400.25 6,022,819.40 547,549.01 0.00 8,986.43 13,900.00 90.00 125.25 4,027.80 3,980.00 -8,717.98 2,481.91 6,022,762.19 547,631.01 0.00 9,064.38 13,917.57 90.00 125.25 4,027.80 3,980.00 -8,728.12 2,496.26 6,022,752.14 547,645.42 0.00 9,078.07 5 1/2" Targets Measured Vertical Target Name Hole Depth Depth Diameter Diameter hittmiss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPL-50 wp3 Toe 0.00 0.35 4,027.80 -8,439.55 2,087.94 6,023,038.20 547,235.40 plan hits target center Circle (radius 100.00) MPL-50 wp3 Heel 0.00 0.35 4,027.80 -5,621.74 -1,898.22 6,025,831.50 543,232.60 plan hits target center Circle (radius 100.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 8,535.57 4,027.77 9 5/8" 9-5/8 12-1/4 13,917.57 4,027.80 51/2" 5-1/2 8-1/2 7/1/2015 2:16:41PM Page 6 COMPASS 5000.1 Build 73 Hilcorp Energy Company Milne Point M Pt L Pad Plan MPL-50 MPL-50 (well #5) MPL-50 wp3 Sperry Drilling Services Clearance Summary Anticollision Report 01 July, 2015 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan MPL-50 - MPL-50 (well #5) - MPL-50 wp3 Well Coordinates: 6,031,464.10 N, 545,096.50 E (70' 29'48.57" N, 149' 37'52.43" W) Datum Height: Plan MPLSO @ 47.80usft (Nordic 3 (17.8' CBE + 30' KB)) Scan Range: 0.00 to 13,917.57 usft. Measured Depth. Scan Radius is 1,588.76 usft . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Grilling Services SURVEY PROGRAM Date: 20154)6-OBT00:00:00 Validated: Y. Version: Depth From Depth Tb Saney/Plao Tool 30.00 800.00 MPG50 wp3 (MPLSO (we11N5))SRGSS 800.00 8535.57 MPI-50 wp3(MPLdO(well#5)) MWD+IFR2+MS+mg 8535.57 13917.57 MPIr50wp3(MPL-50(wdl#5))MWD+IFR2+NE+sag MPL- MPL-0 MPL-0 MPL•1 MPL•1 ' MPL39 MPLJ MPL: 180 Azimuth from North [0] vs Centre to Centre Separation [200 usft/in] Details: Plan MPL-50 NAD 1927 (NADCON CONUS) Alaska Zone 04 Ground Level: 17.80 +ry/S +Fl -W Northing Easting Latihude Longitude Slot 0.00 0.00 6031464.10 545098.50 70129' 48.571 N 149° 37'52.429 W 50 - REFERENCE INFORMATION Coordinate (WE) Reference: Well Plan MPL-50 - Slat 50', True North Vertical (TVD) Reference: Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30' KB)) Secdon (VS) Reference: Slot-50'(O.00N, O.00E) Measured Depth Reference: Plan MPL-50 @ 47.80usR (Nordic 3 (17.8' CBE+ 30' KB)) Calculation Method: Minimum Curvature Hilcorp Energy Company Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 30 Error Surface: Elliptical Conic Warning Method: Error Ratio MPLJ7 cap M From Colour To MD Interpolation Method: MD, interval: 25.00 Depth Range From: 30.00 To 13917.57 Centre Distance: 1588.76 Reference: Plan: MPL50 wp3 (Plan MPL-60/MPLS0 (well #5)) 180 Auim th from North l°) 39 Centro to Centre Separation I -w u t/ial 6 cap 90 U SECTION DETAILS Sec MD Inc Aei TVD +NI -S +EI -W DI49 TF.- VS- Target 1 30.00 0.00 0.00 30.00 ow 0.00 000 000 0.00 2 330.00 O.Do 3 630.00 600 0.00 330.00 0.00 000 0.00 1W00 629.45 -14.]5 5.3] 2.00 0.00 0.00 160.00 15.65 4221995 6).02 213.% 1859.10 -779.76 -419.60 4.00 %.25 63426 5645609 67.02 68035.68 8500 213% 3513.04 -3.79 -259992 0.00 125.25 398422 -5334.26 -2304.% 5.50 0.00 3144.15 -94.11 4494.81 78535.88 8500 125.25 4027.80 -%21.74 -1898.22 000 D.to 4883.05 APL -50 v0 Neel 8863995 90.20 125.27 4032.15 -5681.75 -1813.35 5.00 027 4%I.09 99663.47 90.20 109887.57 %.00 125.27 4027.81 b .31 -014.48 0.00 125.25 4027.80 -68 -811.13 5.00 000 591809 -173.19 592128 111341]57 %.00 1a. 57 %00 125.25 4027.80 -043955 2087.94 0.00 125.25 402780 -5728.12 249827 0.Do 0.00 6668.34 MPL-50 wp3 Tea 000 W78.07 U HALLIBURTON Anticollision Report for Plan MPL-50 - MPL-50 wp3 Hilcorp Energy Company Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan MPL-50 - MPL50 (well #5) - MPLSO wp3 Scan Range: 0.00 to 13,917.57 usft. Measured Depth. Scan Radius is 1,588.76 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-02 - MPL-02 - MPL-02 MPL-02 - MPL-02 - MPL-02 MPL-02 - MPL-02 - MPL-02 MPL-02 - MPL-02A- MPL-02A MPL-02 - MPL-02A- MPL-02A MPL-02 - MPL-02A- MPL-02A MPL-02 - MPL-02AL1 - MPL-02AL1 MPL-02 - MPL-02AL1 - MPL-02AL1 MPL-02 - MPL-02AL1 - MPL-02ALl MPL-02 - MPL-02AL2 - MPL-02AL2 MPL-02 - MPL-02AL2 - MPL-02AL2 MPL-02 - MPL-02AL2 - MPL-02AL2 MPL-02-MPL-02APB1 MPL-02APB1 MPL-02 - MPL-02APB1 - MPL-02APB1 MPL-02 - MPL-02APB1 - MPL-02APB1 MPL-02 - MPL-02APB2 - MPL-02APB2 MPL-02 - MPL-02APB2 - MPL-02APB2 MPL-02 - MPL-02APB2 - MPL-02APB2 MPL-04 - MPL-04 - MPL-04 MPL-04 - MPL-04 - MPL-04 MPL-04 - MPL-04 - MPL-04 MPL-05 - MPL-05 - MPL-O5 MPL-05 - MPL-05 - MPL-05 MPL-05 - MPL-05 - MPL-05 MPL-06 - MPL-06 - MPL-06 MPL-06 - MPL-06 - MPL-06 MPL-07 - MPL-07 - MPL-07 MPL-07 - MPL-07 - MPL-07 1,245.19 247.67 1,245.19 236.52 1,223.56 22.210 Centre Distance Pass - 1,250.00 247.68 1,250.00 236.49 1,227.79 22.134 Ellipse Separation Pass - 1,400.00 259.03 1,400.00 246.66 1,355.68 20.933 Clearance Factor Pass - 1,245.19 247.67 1,245.19 236.80 1,223.56 22.784 Centre Distance Pass - 1,250.00 247.68 1,250.00 236.77 1,227.79 22.705 Ellipse Separation Pass - 1,400.00 259.03 1,400.00 246.94 1,355.68 21.420 Clearance Factor Pass - 1,245.19 247.67 1,245.19 236.82 1,223.56 22.828 Centre Distance Pass - 1,250.00 247.68 1,250.00 236.79 1,227.79 22.748 Ellipse Separation Pass - 1,400.00 259.03 1,400.00 246.96 1,355.68 21.457 Clearance Factor Pass - 1,245.19 247.67 1,245.19 236.52 1,223.56 22.210 Centre Distance Pass - 1,250.00 247.68 1,250.00 236.49 1,227.79 22.134 Ellipse Separation Pass - 1,400.00 259.03 1,400.00 246.66 1,355.68 20.933 Clearance Factor Pass - 1,245.19 247.67 1,245.19 236.52 1,223.56 22.210 Centre Distance Pass - 1,250.00 247.68 1,250.00 236.49 1,227.79 22.134 Ellipse Separation Pass - 1,400.00 259.03 1,400.00 246.66 1,355.68 20.933 Clearance Factor Pass - 1,245.19 247.67 1,245.19 236.52 1,223.56 22.210 Centre Distance Pass - 1,250.00 247.68 1,250.00 236.49 1,227.79 22.134 Ellipse Separation Pass - 1,400.00 259.03 1,400.00 246.66 1,355.68 20.933 Clearance Factor Pass - 30.00 149.40 30.00 148.49 19.00 163.843 Centre Distance Pass - 775.00 152.21 775.00 144.42 753.17 19.552 Ellipse Separation Pass - 900.00 158.12 900.00 149.27 863.57 17.870 Clearance Factor Pass - 30.00 89.80 30.00 88.89 39.00 98.480 Centre Distance Pass - 775.00 92.06 775.00 84.26 779.05 11.795 Ellipse Separation Pass - 875.00 95.88 875.00 87.21 873.52 11.062 Clearance Factor Pass - 1,142.68 122.87 1,142.68 112.51 1,143.36 11.867 Ellipse Separation Pass - 1,150.00 122.94 1,150.00 112.56 1,149.32 11.836 Clearance Factor Pass - 30.00 170.14 30.00 169.23 39.00 186.587 Centre Distance Pass - 300.00 171.99 300.00 168.75 306.51 53.031 Ellipse Separation Pass - Of July, 2015 - 14:26 Page 2 of 7 COMPASS HALLIBURTON Hilcorp Energy Company Milne Point Anticollision Report for Plan MPL-50 - MPL-50 wp3 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: M Pt L Pad - Plan MPL-50 - MPL-50 (well #5) - MPL-50 wp3 Scan Range: 0.00 to 13,917.57 usft. Measured Depth. Scan Radius Is 1,588.76 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-07 - MPL-07 - MPL-07 725.00 215.06 725.00 208.02 705.92 30.542 Clearance Factor Pass - MPL-10 - MPL-10 - MPL-1 0 319.46 208.68 319.46 205.24 327.66 60.587 Centre Distance Pass - MPL-10 - MPL-10 - MPL-10 350.00 208.74 350.00 205.01 358.17 55.954 Ellipse Separation Pass - MPL-10 - MPL-10 - MPL-10 800.00 246.74 800.00 238.95 805.32 31.652 Clearance Factor Pass - MPL-11 - MPL-11 - MPL-11 568.63 23.32 568.63 15.10 572.27 2.837 Centre Distance Pass - MPL-11 - MPL-11 - MPL-11 575.00 23.34 575.00 15.03 578.60 2.809 Ellipse Separation Pass - MPL-11 - MPL-11 - MPL-11 625.00 24.63 625.00 15.61 628.20 2.732 Clearance Factor Pass - MPL-12 - MPL-12 - MPL-12 1,424.44 133.13 1,424.44 119.06 1,417.68 9.464 Centre Distance Pass - MPL-12 - MPL-12 - MPL-12 1,425.00 133.13 1,425.00 119.06 1,418.13 9.463 Clearance Factor Pass - MPL-35 - MPL-35 - MPL-35 1,596.56 85.52 1,596.56 70.61 1,532.75 5.734 Centre Distance Pass - MPL-35 - MPL-35 - MPL-35 1,600.00 85.53 1,600.00 70.57 1,535.90 5.719 Ellipse Separation Pass - MPL-35 - MPL-35 - MPL-35 6,175.00 292.69 6,175.00 177.89 6,326.89 2.550 Clearance Factor Pass - MPL-35 - MPL-35A - MPL-35A 1,596.56 85.52 1,596.56 70.61 1,533.55 5.734 Centre Distance Pass - MPL-35 - MPL-35A- MPL-35A 1,600.00 85.53 1,600.00 70.57 1,536.70 5.719 Ellipse Separation Pass - MPL-35 - MPL-35A - MPL-35A 6,175.00 292.69 6,175.00 177.89 6,327.69 2.550 Clearance Factor Pass - MPL-35 - MPL-35APB1 - MPL-35APB1 1,596.56 85.52 1,596.56 70.61 1,533.55 5.734 Centre Distance Pass - MPL-35 - MPL-35APB1 - MPL-35APB1 1,600.00 85.53 1,600.00 70.57 1,536.70 5.719 Ellipse Separation Pass - MPL-35 - MPL-35APB1 - MPL-35APB1 6,175.00 292.69 6,175.00 177.89 6,327.69 2.550 Clearance Factor Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 1,596.56 85.52 1,596.56 70.61 1,533.55 5.734 Centre Distance Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 1,600.00 85.53 1,600.00 70.57 1,536.70 5.719 Ellipse Separation Pass - MPL-35 - MPL-35APB2 - MPL-35APB2 6,175.00 292.69 6,175.00 177.89 6,327.69 2.550 Clearance Factor Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 1,596.56 85.52 1,596.56 70.61 1,533.55 5.734 Centre Distance Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 1,600.00 85.53 1,600.00 70.57 1,536.70 5.719 Ellipse Separation Pass - MPL-35 - MPL-35APB3 - MPL-35APB3 6,175.00 292.69 6,175.00 177.89 6,327.69 2.550 Clearance Factor Pass- MPL-35-Plan MPL-35B - MPL-35B wpl 1,596.56 85.52 1,596.56 70.78 1,532.75 5.801 Centre Distance Pass - MPL-35 - Plan MPL-35B - MPL-35B wpt 1,600.00 85.53 1,600.00 70.75 1,535.90 5.785 Ellipse Separation Pass - MPL-35 - Plan MPL-35B - MPL-35B wpl 6,175.00 292.69 6,175.00 178.D6 6,326.89 2.553 Clearance Factor Pass - MPL-37 - MPL-37 - MPL-37 1,060.49 44.90 1,060.49 37.58 1,040.68 6.139 Ellipse Separation Pass - MPL-37 - MPL-37 - MPL-37 6,825.00 436.94 6,825.00 300.42 7,233.95 3.201 Clearance Factor Pass - MPL-37 - MPL-37A- MPL-37A 1,060.49 44.90 1,060.49 37.58 1,049.88 6.137 Ellipse Separation Pass - 01 July, 2015 - 14:26 Page 3 of 7 COMPASS HALLIBURTON Hilcorp Energy Company Milne Point Anticollision Report for Plan MPL-50 - MPL-50 wp3 187.80 373.23 184.10 374.53 50.778 Centre Distance Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) 2,225.00 199.13 2,225.00 174.19 2,426.62 7.985 Ellipse Separation Reference Design: M Pt L Pad - Plan MPL-50 - MPL-50 (well #5) - MPL-50 wp3 13,725.00 929.09 13,725.00 673.59 13,002.29 3.636 Clearance Factor Scan Range: 0.00 to 13,917.57 usft. Measured Depth. 325.00 29.92 325.00 26.60 324.20 9.008 Centre Distance Scan Radius is 1,588.76 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited 30.40 450.00 26.02 449.16 6.947 Ellipse Separation Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on 6.042 Clearance Factor Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft 374.20 42.070 Ellipse Separation MPL-37 - MPL-37A - MPL-37A 6,825.00 436.94 6,825.00 300.17 7,243.15 3.195 Clearance Factor Pass - MPL-37 - Plan MPL-37B - MPL-37B WP2 1,060.49 44.90 1,060.49 37.80 1,040.68 6.322 Ellipse Separation Pass - MPL-37 - Plan MPL-37B - MPL-37B WP2 6,950.00 239.49 6,950.00 84.31 7,454.98 1.543 Clearance Factor Pass - MPL40 - MPL40 - MPL40 219.20 266.65 219.20 264.80 210.35 143.771 Centre Distance Pass - MPL40-MPL-40-MPL40 1,225.00 270.48 1,225.00 263.05 1,137.64 36.418 Ellipse Separation Pass - MPL40 - MPL40 - MPL40 1,825.00 372.99 1,825.00 357.43 1,630.94 23.977 Clearance Factor Pass - MPL45-MPL45-MPL45 - MPL45-MPL45-MPL45 - Plan MPL46 - MPL46 (Well #2) - MPL46 wp3 250.00 59.89 250.00 57.26 249.20 22.813 Centre Distance Pass - Plan MPL46 - MPL46 (Well #2) - MPL46 wp3 300.00 60.04 300.00 56.97 298.82 19.582 Ellipse Separation Pass - Plan MPL46 - MPL46 (Well #2) - MPL46 wp3 550.00 68.45 550.00 64.11 544.95 15.776 Clearance Factor Pass - Plan MPL47 - MPL-47 (Well #4) - MPL47 wp3 Plan MPL47 - MPL47 (Well #4) - MPL47 wp3 Plan MPL47 - MPL47 (Well #4) - MPL47 wp3 Plan MPL48 - MPL48 (Well #3) - MPL48 wp3 Plan MPL48 - MPL48 (Well #3) - MPL48 wp3 Plan MPL48 - MPL48 (Well #3) - MPL48 wp3 Plan MPL-49 - MPL49 (Well #1) - MPL-49 wp3 Plan MPL49 - MPL49 (Well #1) - MPL49 wp3 Plan MPL49 - MPL49 (Well #1) - MPL49 wp3 Survey too) oroOra711 From (usft) 30.00 800.00 8,535.57 373.23 187.80 373.23 184.10 374.53 50.778 Centre Distance Pass - 2,225.00 199.13 2,225.00 174.19 2,426.62 7.985 Ellipse Separation Pass - 13,725.00 929.09 13,725.00 673.59 13,002.29 3.636 Clearance Factor Pass - 325.00 29.92 325.00 26.60 324.20 9.008 Centre Distance Pass - 450.00 30.40 450.00 26.02 449.16 6.947 Ellipse Separation Pass - 625.00 35.54 625.00 29.66 623.68 6.042 Clearance Factor Pass - 325.00 157.63 325.00 154.31 324.20 47.457 Centre Distance Pass - 375.00 157.82 375.00 154.07 374.20 42.070 Ellipse Separation Pass - 725.00 176.18 725.00 169.74 722.88 27.326 Clearance Factor Pass - To Survey/Plan Survey Tool (usft) 800.00 MPL-50 wp3 SRG-SS 8,535.57 MPL-50 wp3 MWD+IFR2+MS+sag 13,917.57 MPL-50 wp3 MWD+IFR2+MS+sag 01 July, 2015 - 14:26 Page 4 of 7 COMPASS HALLIBURTON Anticollision Report for Plan MPL-50 - MPL-50 wp3 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Energy Company Milne Point 01 July, 2015 - 14.26 Page 5 of 7 COMPASS HALLIBURTON Anticollision Report for Plan MPL-50 - MPL-50 wp3 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to Plan MPL-50 @ 47.80usft (Nordic 3 (17.8' CBE + 30' KB)). Northing and Easting are relative to Plan MPL-50 - Slot 50'. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is -150,00°, Grid Convergence at Surface is: 0.35 `. 1350- 7 O to C O 2 900_ CU CL O U 450- 0 Ladder Plot ►11'I� a �.�� VFM E',' ��r lI�': s, �. o::J1O V Z,17 a ,► 25005C6 50 7500 %'- 0000 12500 Measured Depth (2500 usft/in) Hilcorp Energy Company Milne Point MPL-02, MPL-02, MPL-02 V1 $ MPL-02,WPL-02A,MPL-02AV0 MPL-02, MPL-02 1,WL-02ALlV0 $ WL-02,MPL-02AL2,MPL-02AL2V0 $ WL-02,WPL-02APBI,MPL-02APB1V0 -X- MPL-02,WPL-02APB2,MPL-02APB2V0 -E- MPL-04,MPL-04,MPL-04 V1 -�- MPL-05,MPL-05,MPL-05V1 $ MPL-06,MPL-06,MPL-06V1 $ MPL-07, MPL-07, MPL-07 V1 $ MPL- 10, MPL-1 0, MPL-1 0 V1 $ MPLA1,MPL-11,MPL-11V1 $ MPL-12, WPLA2, MPL-12 V1 $ MPL-35, MPL-35, MPL35 V6 -iE MPL-05,MPL35A,WPL35AV12 -b- MPL35,WPL35APB1,MPL35APB1V5 -¢- MPL35,WPL-35APB2,WPL35APB2V3 $ WPL35,WPL35APB3,MPL35APB3V5 $ WPL-35,Plan WPL35B,WL35Bv.P1V0 3-• MPL-37,WPL-37,MPL37V3 -W MPL-37,WPL37A,WPL-37AV1 -} MPL-37,Plan MPL37B,WPL37BVVP2V19 �f MPL4O,MPL-40,MPL-0OV4 $ MPLdS, MPL-05, MPL45 V7 VII- $ Plan MPL-06, MPL46 (Well #2), MPL-46 wp3 VO $ Plan MPL-47, MPL-47 (Well #4), MPL-47 wp3 V0 01 July, 2015 - 1426 Page 6 of 7 COMPASS HALLIBURTON Anticollision Report for Plan MPL-50 - MPL-50 wp3 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor c Measured Depth (2500 usfVn) Hilcorp Energy Company Milne Point MPL-02, MPL-02, MPL-02 V1 $ MPL-02,MPL-02A,MPL-02AV0 -�- MPL-02, MPL-02ALI,MPL-02ALlV0 $ MPL-02, MPL-02AL2,MPL-02AL2V0 $ MPL-02,MPL-02APBI,MPL-02APB1V0 -)E- MPL-02,MPL-02APB2,MPL-02APB2V0 -)(- MPL-04, MPL-04, MPL-04 V1 $ MPL-05,MPL-05,MPL-05V1 $ MPL-06,MPL-06,MPL-06 V1 $ MPL-07,MPL-07,MPL-07V1 -0- MPL-1 0, MPL-1 0, MPLA 0 V1 $ MPL-11,MPL-11,MPL-11 V1 $ MPL-12,MPL-12,MPL-12V1 $ MPL-35,MPL35, MPL-35 V6 -W MPL35,MPL-35A,MPL-35AV12 -� MPL-35, MPL-35APB 1, MPL-35APB 1 VS $ MPL-35,MPL35APB2,MPL-35APB2V3 $ MPL-35,1vPL35APB3,MPL35APB3V5 $ MPL-35,Plan MPL35B,MPL-35Bwp1V0 3-- MPL-37,MPL37, MPL-37 V3 -)(- MPL-37,MPL-37A,MPL37A V1 $ MPL-37,Plan MPL37B,MPL37BWP2V19 MPL40,MPL40,MPL40V4 $ MPL-45, MPL-45, MPL-45 V7 $ Plan MPL-46,MPL-46(Well #2),MPL-06 wp3 V0 -rte Plan MPL47,MPL-47(Well #4),MPL-47 wp3 V0 Plan MPL48, MPL48 (Well #3), MPL48 wp3 V0 01 July, 2015 - 14:26 Page 7 of 7 COMPASS Schwartz, Guy L (DOA) From: Paul Chan <pchan@hilcorp.com> Sent: Thursday, August 06, 2015 2:25 PM To: Schwartz, Guy L (DOA) Cc: Keith Elliott; Luke Keller, Kevin Eastham Subject: L-50 PTD (215-132) AOR Attachments: MPL-50 Prop AOR Map_KRE_O.pdf Guy The MPJ -18 was originally completed in the Kuparuk sands. In 2005 the Kuparuk sands were plugged back and the well was re -completed to the Schrader Bluff sands. The MPJ -18 Schrader Bluff interval is outside the AOR for the L-50 well. Thanks Paul Chan Senior Operations Engineer Alaska North Slope Team Hilcorp Alaska LLC (907) 777 — 8333 (w) (907) 444 — 2881 (c) From: Luke Keller Sent: Thursday, August 06, 2015 11:16 AM To: 'Schwartz, Guy L (DOA)' Cc: Keith Elliott; Paul Chan Subject: RE: L-50 PTD (215-132) Guy, J-18 is a Schrader N and O sand well (not Kup). We are looking at some options on this so there is not communication. The field reservoir engineer (Keith Elliot) is out right now, but I'll get some info to you about this ASAP. Luke From: Schwartz, Guy L (DOA)[mailto:guy.schwartz@alaska.gov] Sent: Thursday, August 06, 2015 10:37 AM To: Luke Keller Subject: L-50 PTD (215-132) Luke, Looking at the % plot J-18 is shown on the map with the area. I assume that this Kuparuk completion but please verify wellbore is not impacted. Also, I won't require a CBL on surface casing as long as cementing goes as planned and FIT goes well. Guy Schwartz Senior 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.gov). L-12 L-42 Prop L-49 ; 34 Prop LA IL Prop►_L-46 L-37 *'ll J" L-47 L -37A Prop L-50 ll- 11l7— HILCORP ALASKA LLC ( ' MILNE POINT FIELD AOR MAP Wellbore trajectory of Proposed MPL-50 Injector Kuparuk sands at 7000' TVDss datum (Kup sands 0 1,139 2,278 r plugged back) FEET WELL SYMBOLS h• Activeoil Y D&A INJ Well (Water Flood) Injector Location Producer Location REMARKS Well Symbol at top of Schrader OA Sand Existing perfs in OA sand highlighted pink Black Dash Circle = 1320' radius from proposed OA top (heel) and TD (toe) in MPL-50 July 9, 2015 PETRA 7/9/2015 12:51 17 PM `J-18 J-1 Bettis, Patricia K (DOA) ?7b 2-s r /3�, From: Keith Elliott <kelliott@hilcorp.com> Sent: Wednesday, June 24, 2015 10:18 AM To: Bettis, Patricia K (DOA) Subject: Re: MPU L-49: Permit to Drill Application Sure thing. Economically, pre -production does not work for us b/c of our completion design and added cost of associated workovers. Have a great day as well! Keith Elliott Cell: 832-233-5855 Office: 907-777-8355 Sent from my iPhone On Jun 24, 2015, at 9:07 AM, Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov<maiIto: patricia.bettis@alaska.gov>> wrote: Thank you and have a great day. From: Keith Elliott [mailto:kelliott@hilcorp.com] Sent: Tuesday, June 23, 2015 4:52 PM To: Luke Keller Cc: Bettis, Patricia K (DOA) Subject: RE: MPU L-49: Permit to Drill Application No, we will not pre -produce. From: Luke Keller Sent: Tuesday, June 23, 2015 1:58 PM To: Keith Elliott Cc: 'Bettis, Patricia K (DOA)' Subject: FW: MPU L-49: Permit to Drill Application Keith, Are you planning on pre -producing MPU L-49 prior to injecting water? Luke From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Tuesday, June 23, 2015 1:57 PM To: Luke Keller Subject: MPU L-49: Permit to Drill Application Good afternoon Luke, 1 Does Hilcorp plan to pre -produce MPU L-49, and if so, for what duration? Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793- 1238 or patricia.bettis@alaska.gov<mailto:patricia.bettis@alaska.gov>. Bettis, Patricia K (DOA) From: Luke Keller <lkeller@hilcorp.com> Sent: Tuesday, July 28, 2015 1:52 PM To: Bettis, Patricia K (DOA) Subject: RE: KRU L-50: Permit to Drill Application Patricia, Kickoff depth is 330' MD. Maximum hole angle is 90 degrees. I apologize for not having this filled out on the 10-401 form Luke From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Tuesday, July 28, 2015 1:50 PM To: Luke Keller Subject: KRU L-50: Permit to Drill Application Good afternoon Luke, Please verify the KOP for the planned KRU L-50 well. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7t" Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patriciabettisnala.ska.Zov. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Tuesday, July 28, 2015 1:50 PM To: Luke Keller (Ikeller@hilcorp.com) Subject: KRU L-50: Permit to Drill Application Good afternoon Luke, Please verify the KOP for the planned KRU L-50 well. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AC)GCC), 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 Patricia Bettis at (907) 793-1238 or patricia.bettis(calaska.ov. TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: 05 Development ✓ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD:�� i POOL: Vl_ ,� Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name (_PH) and API number (50- - - -) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging ✓' Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140 Well Name: MILNE PT UNIT SB L-50 Program SER Well bore seg ❑ PTD#: 2151320 Company HILCORP ALASKA LLC _.. Initial Class/Type SER/PEND GeoArea 890 Unit 11328 _ On/Off Shore On Annular Disposal El - Administration Administration 1 Permit fee attached- - - - _ - - - - - - - - - - - - - - - - - - 2 Lease number appropriate - - - - - - - - - - - - - - - - Yes - ADL0025509, Su f;_ADL0025515, Top Prod & TD- _ _ - - - -- 3 Unique well name and number ------------ - Yes -- - - - - - MPU L-50 - - _ - - _ - _ - - - - 4 Well located in_a_defined-pool - - - - - - - - - - - - - - - - - - - - - - Yes _ MILNE POINT, SCHRADER BLFF_ OIL - 525140, governed by Conservation Order No. 477.05 _ _ _ _ _ - 5 Well -located proper distance from drilling unit_boundary----- - - - - - - - - - _ _ _ Yes - - . - _ - CO 477.05 contains no spacing restrictions with -respect to drilling unit_ boundaries, - - _ _ _ _ _ _ _ _ 6 Well located proper distance_ from other wells_ _ - - - - - - - - - - - - - - - _ - - Yes - - - . - _ . CO 477.05 has no interwell spacing restrictions-- - - - - - - - - - - - - - - - - - - - - - _ _ _ _ _ 7 Sufficient acreage -available in_drilling unit - - - - - - - - - - - - - - - - Yes - 8 If-deviated,is_wellboreplat-included _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ - - - - - - - - - _ - - Yes_ - - - - - _ - _ _ _ - _ _ 9 Operator only affected party- - - - - - - - - - - - - - - - - - - - _ - - - - - - Yes - - - - - - Wellbore -will be_more than 500' from an external property line where ownership or landownership_ changes._ 10 Operator has_ appropriate_ bond in force _ - - - _ - Yes - - _ _ - - - - - - - - - - - - - - - - - - - - ----- - . - - - - - - - - - - _ _ - 11 Permit_ can -be issued -without conservation order ____________________________ Yes ------------------------------------------------ -- -----___---------- Appr Date 12 Permit_ can be issued without administrative -approval ________________________ Yes__-_____________________-__-________--_______________________________ 13 _Can permit be approved before 15 -day wait- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - PKB 7/29/2015 14 Well -located within area and -strata authorized by -Injection Order# (pot 10# in -comments) -(For- Yes - - - - - --AIO.10-13 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ _ . 15 All welIs_within 1/4-mile:area-of review identified (For service well only)- - - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ MPU L -45,-L-47 _ - - _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _ . _ _ - _ 16 Pre -produced injector; duration_of pre production less than 3 months_ (For service well only) _ - No_ _ _ - _ - _ _ Keith Elliott (6/24/15) - - - - - - - - - - - - - - - - - - - - - - - - - - - - 117 Nonconven, gas conforms to AS31.05.0300..1_.A),Q.2.A-D) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ - _ - - _ _ _ _ _ _ _ - _ _ _ _ _ _ - - - _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ 18 Conductor string -provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - _ 20" conductor set_ at 80 ft -- - - - - - _ _ - - - - - - - - - _ - _ _ _ . Engineering 19 Surface casing- P-rotects all -known USDWs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ No aquifers..._ permafrost _area_exempt- - _ _ - _ - - _ - - - - - - 20 CMT -vol adequate -to circulate -on conductor _& surf _csg - - - - - - - - - - - - - - - - - - - - - - - Yes _ - _ _ _ _ _ Will -use 2 stages to completely cement -the 9 5/8" casing to surface. - 21 CMT -vol adequate to tie -in -long string to su[f csg_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - _ _ - - - - NA_ _ _ _ _ _ _ _ - - - - - - - - - _ _ _ _ _ _ - - - - - _ - 22 CMT -will coverall known_productive horizons- - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ Lateral_w_ill_have 5 1/7_liner_with swell_ packers_ and ICD's------ 23 Casing desiqns adequate for C, -T, B &-permafrost- - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ BTC calculations are -provided ----------------------- - _ _ . _ _ _ . - - - 24 Adequate -tankage or reserve pit - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ - _ _ - _ _ Rig has steel pits. All waste_to approved disposal wells- _ - - - - - - - -- - -- - - - - - 25 If_a_re-drill, has-at10-403 for abandonment been approved - - - - - - - - - - - - - - - - - - - - - - NA- - _ _ - _ _ _ Grassroots Injection well in Schader_Bluff pool, - - - _ _ _ - _ _ _ _ _ - - - - - - - - 26 Adequate wellbore separation_proposed- - - - - - - - - - - - - - - - - - - - - - - Yes - - - . _ _ _ Close crossing with L-45 in Zone. _(SB fm. J... small risk with know_pressure._ 27 If_diverter required, does it meet_ regulations_ - - - - _ __ _ _ _ _ _ _ _ _ _ _ _ _ - Yes - re - _ - _ _ - Diverter is quired.. Nordic_3_has 16"_line.- Schematic_provided of, ----------------------- Appr Date 28 -Drilling fluid_ program schematic & equip list adequate_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ Max form pressure =1800 psi _( 8.6-ppg EMW) Will drill lateral with 8.9 - 9.2 ppg mud - GLS 8/6/2015 29 BOPEs,_dothey meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - - - - - -- Yes - - - - ---Nordic3has5000psi11"_BODE_ _ _ -- - _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 30 BOPE_press rating appropriate; test to -(put psig in comments)_ - - . - - - - - - - - - - - - - - - Yes - - - - - - - MASP= 1398 psi -Will test BORE to 3000 psi (annular to 2500psi) - - - - - - - - - - - - - - - - _ - - - - - 31 Choke_ manifold complies w/API..RP-53(May 84)____________________________ - Yes --- --- ------ 32 Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - _ _ - _ _ _ _ _ _ _ _ - - - - - _ - _ _ _ - - - _ _ _ _ _ - - 33 Is presence_ of H2S gas probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - H2S on_ pad._ Rig_has senors and alar_m_s--_ _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - _ - _ _ _ _ _ _ _ _ 34 Mechanical_condition of wells within AOR verified (For service well only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ - AOR completed_.., J-18 not wellpath_not in SB in map area. _ _ - _ - _ - - _ - _ _ _ _ _ - - - _ - - - - - - .35 Permit_can be issued w/o hydrogen sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ - - _ _ _ _ - H2S measures required_ _ _ - - - - _ _ _ _ - - - _ _ _ _ _ _ _ - _ - - _ - - _ - - _ - _ - - - - Geology 36 Data -presented on potential overpressure zones_ _ _ _ _ _ - - - - - - - - - _ _ _ - Yes - - - - - - Expected reservoir -pressure is 8.61 ppg EMW; will be drilled using -8.8 to-9.2-ppg mud._ - Appr Date 37 Seismic_analysis_ of shallow gas_zones............... - - - - - _ _ _ - - - - _ _N_A---------------------------------------------------------- PKB 7/29/2015 38 Seabed condition survey -(if off -shore) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ _ _ _ _ - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - 39 Contact name/phone for weekly -progress reports [exploratory only] - - - - - - - - - - - - - - - - NA_ - _ _ Onshore service well to be drilled. _ _ - - - - _ _ _ - - - Geologic Engineering Public Grassroots SB injector. 9 5/8" surface casing set in top of SB formation. GIs Date: Date Date Commissioner: Co fission ��r� Commissioner
