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Home My WebLink About215-217Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/21/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260121 Well API # PTD # Log Date Log Company Log Type AOGCC E-Set# BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF T41253 BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf T41254 BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf T41255 BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf T41256 BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf T41257 BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf T41258 BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf T41259 BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun T41259 GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf T41260 IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf T41261 IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug T41261 IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf T41261 KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf T41262 KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF T41263 KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun T41264 LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf T41265 MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL T41266 MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL T41267 MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL T41268 MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut T41268 MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL T41269 NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug T41270 NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT T41271 NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT T41272 NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug T41272 NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf T41272 NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF T41273 OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch T41274 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:35 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275 SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276 SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277 SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278 TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279 TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280 TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280 TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281 Please include current contact information if different from above. SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.21 13:56:51 -09'00' 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:McLellan, Bryan J (OGC) To:Ryan Lemay Cc:Donna Ambruz Subject:RE: SCU 322C-04 / 90 Day No Flow Timeline Clarification Date:Wednesday, January 21, 2026 3:28:00 PM Ryan, The 90-day flow test period begins the first day the well is flowing, 1/16/26 according to your email below. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Lemay <ryan.lemay@hilcorp.com> Sent: Wednesday, January 21, 2026 1:17 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: SCU 322C-04 / 90 Day No Flow Timeline Clarification Good afternoon Bryan, I was hoping to get quick clarification on the start date of the 90 day clock for needing to perform no-flow test on well SCU 322C-04. We recently performed sundried work and submitted the 10-404 on 1/12/2026. At that time, we had spent a couple weeks working to kick the well off and get it lifting / producing. At the time of 1/12/26 we hadn’t achieved production out of the well yet but wanted to ensure we submitted the 10-404 within the 30 days since the wellwork had been completed. On 1/16/26 the well finally came around and started producing fluid / oil marking the 1st day of returning it to production. Just wanted to clarify with you if the 90 day clock to perform no flow test starts on 1/12/26 (the day we submitted the 10-404) or 1/16/26 (the 1st day we were successful in producing the well). Thanks, Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com 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 the onward 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. 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: Tubing Punch 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): 11,525' N/A Casing Collapse Structural Conductor Surface 1,130psi Intermediate Production 3,830psi Liner 7,500psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan LeMay, Operations Engineer Contact Email:ryan.lemay@hilcorp.com Contact Phone: 661-487-0871 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng See Attached Schematic 7,509' N/A Length Model "D" Permanent Packer ; N/A 11,075' MD, 10,228' TVD ; N/A 10,531' 11,355' 10,415' 20" 13-3/8" Soldotna Creek Unit (SCU) 322C-04CO 123A & CO 123B Same 7,507'7" ~1,500psi Swanson River Hemlock Oil November 18, 2025 11,524'4,737' See Attached Schematic 10,529' 7,509' Perforation Depth MD (ft): 4-1/2" See Attached Schematic 2,730psi 30'30' 3,005' Size 30' 3,005' MD See Attached Schematic TVD Burst 11,081' 6,340psi 3,005' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028997 215-217 50-133-10104-01-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY 8,430psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: Noel Nocas, Operations Manager 907-564-5278 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 m n P s t h N 66 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 9:08 am, Nov 12, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.11.10 18:08:56 - 09'00' Noel Nocas (4361) 325-691 A.Dewhurst 12NOV25 DSR-11/13/25BJM 11/13/25 10-404 If No Flow Test fails, an plug must be set below the tubing punches or a patch set across tubing punches within 30 days of the failed NFT. JLC 11/13/2025 11/13/25 Well Prognosis Well: SCU 322C-04 Well Name: SCU 322C-04 API Number: 50-133-10104-01-00 Current Status: Shut in Oil & Gas Producer Permit to Drill Number: 215-217 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Ryan LeMay (661) 487-0871 (M) Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506 (O) Static BHP = 970 psi from PT survey ran in 2022 South Gas Lift Pressure = PSV set at 1400 psi Brief Well Summary: SCU 322C-04 was drilled in 2015 as a Hemlock gas flood injector. The well injected gas until the summer 2021 when it was converted to a producer. The well flowed back gas and oil until September of 2022. The purpose of this Sundry is to perform a tubing punch above the production packer to gas lift and return the well to production. Notes Regarding Wellbore Condition: Min ID = 1.875 at 11,090 MD (X-nipple) Sail angle of 48 degrees from 8900 MD to TD. Current Well Status: Shut in with a PX plug set in the X Landing Nipple at 11,090 Procedure: 1. Perform MIT-IA to a minimum of 1500 psi for 30 min. a. Provide AOGCC 24 hours notice to witness MIT-IA b. Provide BLM 48 hours notice for commencement of operations c. Use a chart recorder or digital crystal gauge to record MIT-IA pressure test 2. MIRU E-line unit. PT lubricator 250 psi low / 2500 psi high. 3. RIH and shoot tubing punch at + 11,055. 4. RDMO E-line unit. 5. Gas lift fluid out of IA and tubing. a. Slickline swab fluid off well if and as necessary. 6. MIRU slickline. PT lubricator 250 psi / 2500 psi high. 7. RIH and retrieve PX plug currently set in X Landing nipple at 11,090 8. RDMO slickline 9. Turn well over to production to gas lift and return well to production. Post Well Work Procedure: 1. Hilcorp requests a 90-day period to flow and test production on the well using gas lift through tubing punch hole(s). After the 90-day period a No Flow Test will be performed. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Updated by RPL 10-24-25 SCHEMATIC Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 TD = 11,525 MD / 10,531 TVD PBTD = 11,355 MD / 10,415 TVD Max Deviation = 49°@ 11,247 GL: 145 AMSL KB 18 TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2Tubing 9.3 L-80 8rd EUE 2.992Surf 331 2-7/8Tubing 6.5 L-80 8rd EUE 2.441 331 7,150 2-3/8Tubing 4.7 L-80 SuperMax 1.995 7,150 11,081 10 9 8 5 H-2 H-1 CASING DETAIL Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20Conductor ---Surf.30-Yes Surf. 13-Surface 54.5 J-55 8RD Surf.1,50017-½ 3,005 1,100 sx Surf. DV Collar 1,5001,503 13-Surface 54.5 J-55 8RD 1,5033,005600 sx 2,290 Calc 7 Production 29 N-80 BTC Surf.303 9- 11,040650 sx 5,720 CBL 726 3031,296 723 1,2964,793 726 4,7936,306 729 6,3067,509 DV Collar 7,5097,511 4-1/2Liner 12.6 L-80 DWC/C 7,19811,5246 11,525309 sx 7,198 Volume 20 30 13-3/8 3,005 4-1/2 CBL TOC 5,720 7 DV Collar 7,509 JEWELRY DETAIL NO. Depth ID OD Item 1 19.292.9007.0003-1/2 Tubing Hanger 2 3202.8134.53-1/2 X Landing Nipple 3 3302.441-3-1/2 x 2-7/8 Crossover 4 7,150 1.995-2-7/8 x 2-3/8 Crossover 5 7,198 7 X 4-1/2 ZXP liner hanger 6 11,074-11,081 1.995 2.688 Anchor Latch Seal Assembly - 6.17 Stung into Packer/SBE 7 11,075 2.688 4.500 4-1/2 x 2-3/8 Model D Perm Packer 8 11,077 2.688Seal Bore Extension 9 11,090 1.875 3.080 X Landing Nipple (PX plug installed) 10 11,099 1.995 3.100WL Entry Guide 1 X PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225 11,265 10,329 10,35502/05/16 3-3/8 6spf 60 deg H-2 11,281 11,310 10,365 10,38502/04/16 3-3/8 6spf 60 deg H-3 11,328 11,345 10,397 10,40802/04/16 3-3/8 6spf 60 deg H-5 11,362 11,387 10,420 10,43702/20/18 Isolated 03/28/18 2 3 4 X 67 TOC 11,355 03/28/18 RA Tag 10,910 RA Tag 11,058 RA Tag 11,202 RA Tag 11,361H-5 H-3 Updated by RPL 11-4-2025 Schematic PROPOSED Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01-00 TD = 11,525 MD / 10,531 TVD PBTD = 11,355 MD / 10,415 TVD Max Deviation = 49°@ 11,247 GL: 145 AMSL KB 18 TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2Tubing 9.3 L-80 8rd EUE 2.992Surf 331 2-7/8Tubing 6.5 L-80 8rd EUE 2.441 331 7,150 2-3/8Tubing 4.7 L-80 SuperMax 1.995 7,150 11,081 10 98 5 H-2 H-1 CASING DETAIL Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20Conductor ---Surf.30-Yes Surf. 13-Surface 54.5 J-55 8RD Surf.1,50017-½ 3,005 1,100 sx Surf. DV Collar 1,5001,503 13-Surface 54.5 J-55 8RD 1,5033,005600 sx 2,290 Calc 7 Production 29 N-80 BTC Surf.303 9- 11,040650 sx 5,720 CBL 726 3031,296 723 1,2964,793 726 4,7936,306 729 6,3067,509 DV Collar 7,5097,511 4-1/2Liner 12.6 L-80 DWC/C 7,19811,5246 11,525309 sx 7,198 Volume 20 30 13-3/8 3,005 4-1/2 CBL TOC 5,720 7 DV Collar 7,509 JEWELRY DETAIL NO. Depth ID OD Item 1 19.292.9007.0003-1/2 Tubing Hanger 2 3202.8134.53-1/2 X Landing Nipple 3 3302.441-3-1/2 x 2-7/8 Crossover 4 7,1501.995-2-7/8 x 2-3/8 Crossover 5 7,198 7 X 4-1/2 ZXP liner hanger 6 11,074-11,081 1.995 2.688 Anchor Latch Seal Assembly - 6.17 Stung into Packer/SBE 7 11,075 2.688 4.500 4-1/2 x 2-3/8 Model D Perm Packer 8 11,077 2.688Seal Bore Extension 9 11,090 1.875 3.080 X Landing Nipple 10 11,099 1.995 3.100WL Entry Guide 1 X PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225 11,265 10,329 10,35502/05/16 3-3/8 6spf 60 deg H-2 11,281 11,310 10,365 10,38502/04/16 3-3/8 6spf 60 deg H-3 11,328 11,345 10,397 10,40802/04/16 3-3/8 6spf 60 deg H-5 11,362 11,387 10,420 10,43702/20/18 Isolated 03/28/18 2 3 4 X 67 TOC @ 11,355 03/28/18 RA Tag 10,910 RA Tag 11,058 RA Tag 11,202 RA Tag 11,361 H-3 H-5 Tbg Punch ±11,055 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: Convert to Producer 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 11,525 feet N/A feet true vertical 10,531 feet N/A feet Effective Depth measured 11,355 feet 11,075 feet true vertical 10,415 feet 10,228 feet Perforation depth Measured depth 11,225-11,387 feet True Vertical depth 10,329 - 10,437 feet Tubing (size, grade, measured and true vertical depth)See Schematic 11,075 (MD) Packers and SSSV (type, measured and true vertical depth)Model D Pkr 10,228 (TVD) SSSV: N/A 12. Stimulation or cement squeeze summary: 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:Contact Phone: 3,830psi 2,730psi 6,340psi Burst Collapse 1,130psi 30' 3,005' 7,507' 4-1/2" 7,509' 11,524' 10,529' 7" measuredPlugs Junk measured N/A Length 30' 3,005' Size Conductor Surface Intermediate 20" 13-3/8" Production Liner 7,509' 4,737' Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-217 50-133-10104-01-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028997 Swanson River Field / Hemlock Oil Pool Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Soldotna Creek Unit 322C-04 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0211,473 0 63 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 30' 3,005' N/A 4,109 Structural TVD 321-398 Sr Pet Eng: 7,500psi Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 14,200 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 622 8,430psi Ryan Rupert ryan.rupert@hilcorp.com (907) 777-8503Dan Marlowe, Operations Manager L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 12:45 pm, Nov 23, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.11.23 11:07:15 -09'00' Dan Marlowe (1267) BJM 12/1/21 RBDMS HEW 11/24/2021 SFD 11/29/2021 DSR-11/23/21 Updated by JLL 11/22/21 SCHEMATIC Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 TD = 11,525’ MD / 10,531’ TVD PBTD = 11,355’ MD / 10,415’ TVD Max Deviation = 49° @ 11,247’ GL: 145’ AMSL KB – 18’ TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2” Tubing 9.3 L-80 8rd EUE 2.992” Surf 331’ 2-7/8” Tubing 6.5 L-80 8rd EUE 2.441” 331’ 7,150’ 2-3/8” Tubing 4.7 L-80 SuperMax 1.995” 7,150’ 11,081’ 10 9 8 5 H-2 H-1 CASING DETAIL Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20” Conductor - - - Surf. 30’ - Yes Surf. 13-д” Surface 54.5 J-55 8RD Surf. 1,500’17-½” 3,005’ 1,100 sx Surf.DV Collar 1,500’ 1,503’ 13-д” Surface 54.5 J-55 8RD 1,503’ 3,005’ 600 sx 2,290’ Calc 7” Production 29 N-80 BTC Surf. 303’ 9-и” 11,040’650 sx 5,720’ CBL 7” 26 303’ 1,296’ 7” 23 1,296’ 4,793’ 7” 26 4,793’ 6,306’ 7” 29 6,306’ 7,509’ DV Collar 7,509’ 7,511’ 4-1/2” Liner 12.6 L-80 DWC/C 7,198’ 11,524’ 6” 11,525’309 sx 7,198’ Volume 20” 30’ 13-3/8” 3,005’ 4-1/2” CBL TOC 5,720’ 7” DV Collar 7,509’ JEWELRY DETAIL NO. Depth ID OD Item 1 19.29’ 2.900” 7.000” 3-1/2” Tubing Hanger 2 320’ 2.813” 4.5” 3-1/2” X – Landing Nipple 3 330’ 2.441” - 3-1/2” x 2-7/8” Crossover 4 7,150’ 1.995” - 2-7/8” x 2-3/8” Crossover 5 7,198’ 7” X 4-1/2” ZXP liner hanger 6 11,074’-11,081’ 1.995” 2.688” Anchor Latch Seal Assembly - 6.17’ Stung into Packer/SBE 7 11,075’ 2.688” 4.500” 4-1/2” x 2-3/8” Model D Perm Packer 8 11,077’ 2.688” Seal Bore Extension 9 11,090’ 1.875” 3.080” X – Landing Nipple 10 11,099’ 1.995” 3.100” WL Entry Guide 1 X PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225’ 11,265’ 10,329’ 10,355’ 02/05/16 3-3/8” 6spf 60 deg H-2 11,281’ 11,310’ 10,365’ 10,385’ 02/04/16 3-3/8” 6spf 60 deg H-3 11,328’ 11,345’ 10,397’ 10,408’ 02/04/16 3-3/8” 6spf 60 deg H-5 11,362’ 11,387’ 10,420’ 10,437’ 02/20/18 Isolated 03/28/18 2 3 4 X 67 TOC 11,355’ 03/28/18 RA Tag 10,910’ RA Tag 11,058’ RA Tag 11,202’ RA Tag 11,361’H-5 H-3 Rig Start Date End Date 8/12/21 11/1/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SCU 322C-04 50-133-10104-01-00 215-217 08/12/2021 - Thursday Gas flood injection SI. Begin conversion to producer. 08/18/2021 - Wednesday MOB FROM 344-33. RIG UP W/L - PT LUB - 250/2,500 PSI - GOOD. RIH W/ 2.81" GAUGE RING TO 320'KB TAG TOP OF MCX - POOH - W/ GR COVERED IN SAND/GREASE. RIH W/ 3 1/2" GR W/ XX EQUALIZING PRONG TO 320'KB WT TO EQUALIZE - NO PRESSURE. CHANGE - STANDBY TO INJECT GAS DOWN TUBING TO ENSURE MCX IS EQUALIZED. PRESSURE STABILIZES AT 2,850 PSI - WT - COME FREE - POOH - OOH W/ MCX VALVE. RIG DOWN W/L - MOB TO 23B-22. Temporary hardline production piping with SSV installed. 08/26/2021- Thursday 08/31/2021 - Tuesrday Approval obtained. Bring online as producer. 11/01/2021 - Monday Well still hanging in there at >1MM as a producer. Talked to reservoir engineer, and no further evaluation. needed. Can stay a producer for now. SSV tested and passed (State notification given, but no witness). 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Convert Inj to Prod 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): 11,525'N/A Casing Collapse Structural Conductor Surface 1,130psi Intermediate Production 3,830psi Liner 7,500psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 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 todd.sidoti@hilcorp.com 10,531'11,355'10,415'1,267 N/A Model "D" Permanent Packer ; N/A 11,075' MD, 10,228' TVD ; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: 8,430psi Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028997 215-217 50-133-10104-01-00 Soldotna Creek Unit (SCU) 322C-04 Swanson River Field / Hemlock Oil Pool Length Size N/A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY See Attached Schematic TVD Burst 11,081' 6,340psi MD 2,730psi 30' 3,005' 30' 3,005' 7,507'7" 20" 13-3/8" 30' 3,005' 7,509' Perforation Depth MD (ft): See Attached Schematic 7,509' 4-1/2" 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. Authorized Signature: Contingent 11,524'4,737' See Attached Schematic 10,529' eeeeee d ed ss No ss No Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:03 am, Aug 13, 2021 321-398 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.12 13:29:33 -08'00' Taylor Wellman (2143) BJM 8/25/21 Convert Inj to Prod 10-404 DSR-8/16/21SFD 8/13/2021 Contingent JLC 8/26/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.26 11:36:49 -08'00' RBDMS HEW 8/27/2021 Well Prognosis Well: SCU 322C-04 Date: 08/11/2021 1 Well Name: SCU 322C-04 API Number: 50-133-10104-01-00 Current Status: Gas Injector Leg: N/A Estimated Start Date: Contingent Rig: Slickline Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-217 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: 2,300 psi @ 10,329’ TVD (Based on Offset Well) Max. Possible Surface Pressure (MPSP) 1267 psi (BHP - 0.1psi/ft gradient) Brief Well Summary SCU 322C-04 is a gas flood injector currently online. The purpose of this work is to have a contingency plan in place to temporarily convert SUC 322C-04 into a producer. This contingency would be executed to provide stabile gas to market in the event of an unforeseen shortage due to mechanical failure in the system. Procedure: 1. RU temporary flowback equipment including horizontal SSV and choke. 2. MIRU SL and pressure test Lubricator to 250 psi low / 2,000 psi high. 3. RIH W/ Retrieving tool and pull Injection Valve from X-nipple @ 320’. RDMO SL. 4. Flow Well through high pressure header to Tank Setting 3-4. Test SSV within 5 days (Notify AOGCC 24 hours in advance to give them the opportunity to witness). Attachments: 1. Surface Configuration 2. Actual Schematic 3. Proposed Schematic gj y p o temporarily convert SUC 322C-04 into a producer. gyp s contingency would be executed to provide stabile gas to market in the event of an unforeseen shortage d Ensure SSV test procedure is modified as needed for the temporary piping setup. bjm. Updated by DMA 02-08-18 SCHEMATIC Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 TD = 11,525’ MD / 10,531’ TVD PBTD = 11,355’ MD / 10,415’ TVD Max Deviation = 49° @ 11,247’ GL: 145’ AMSL KB – 18’ TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2” Tubing 9.3 L-80 8rd EUE 2.992” Surf 331’ 2-7/8” Tubing 6.5 L-80 8rd EUE 2.441” 331’ 7,150’ 2-3/8” Tubing 4.7 L-80 SuperMax 1.995” 7,150’ 11,081’ 10 9 8 5 H-2 H-1 CASING DETAIL Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20” Conductor - - - Surf. 30’ - Yes Surf. 13-д” Surface 54.5 J-55 8RD Surf. 1,500’ 17-½” 3,005’ 1,100 sx Surf. DV Collar 1,500’ 1,503’ 13-д” Surface 54.5 J-55 8RD 1,503’ 3,005’ 600 sx 2,290’ Calc 7” Production 29 N-80 BTC Surf. 303’ 9-и” 11,040’ 650 sx 5,720’ CBL 7” 26 303’ 1,296’ 7” 23 1,296’ 4,793’ 7” 26 4,793’ 6,306’ 7” 29 6,306’ 7,509’ DV Collar 7,509’ 7,511’ 4-1/2” Liner 12.6 L-80 DWC/C 7,198’ 11,524’ 6” 11,525’ 309 sx 7,198’ Volume 20” 30’ 13-3/8” 3,005’ 4-1/2” CBL TOC 5,720’ 7” DV Collar 7,509’ JEWELRY DETAIL NO. Depth ID OD Item 1 19.29’ 2.900” 7.000” 3-1/2” Tubing Hanger 2 320’ 2.813” 4.5” 3-1/2” X – Landing Nipple (injection valve) 3 330’ 2.441” - 3-1/2” x 2-7/8” Crossover 4 7,150’ 1.995” - 2-7/8” x 2-3/8” Crossover 5 7,198’ 7” X 4-1/2” ZXP liner hanger 6 11,074’-11,081’ 1.995” 2.688” Anchor Latch Seal Assembly - 6.17’ Stung into Packer/SBE 7 11,075’ 2.688” 4.500” 4-1/2” x 2-3/8” Model D Perm Packer 8 11,077’ 2.688” Seal Bore Extension 9 11,090’ 1.875” 3.080” X – Landing Nipple 10 11,099’ 1.995” 3.100” WL Entry Guide 1 X PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225’ 11,265’ 10,329’ 10,355’ 02/05/16 3-3/8” 6spf 60 deg H-2 11,281’ 11,310’ 10,365’ 10,385’ 02/04/16 3-3/8” 6spf 60 deg H-3 11,328’ 11,345’ 10,397’ 10,408’ 02/04/16 3-3/8” 6spf 60 deg H-5 11,362’ 11,387’ 10,420’ 10,437’ 02/20/18 Isolated 03/28/18 2 3 4 X 6 7 TOC 11,355’ 03/28/18 RA Tag 10,910’ RA Tag 11,058’ RA Tag 11,202’ RA Tag 11,361’ H-5 H-3 Updated by TCS 01-12-21 PROPOSED SCHEMATIC Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 TD = 11,525’ MD / 10,531’ TVD PBTD = 11,355’ MD / 10,415’ TVD Max Deviation = 49° @ 11,247’ GL: 145’ AMSL KB – 18’ TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2” Tubing 9.3 L-80 8rd EUE 2.992” Surf 331’ 2-7/8” Tubing 6.5 L-80 8rd EUE 2.441” 331’ 7,150’ 2-3/8” Tubing 4.7 L-80 SuperMax 1.995” 7,150’ 11,081’ 10 9 8 5 H-2 H-1 CASING DETAIL Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20” Conductor - - - Surf. 30’ - Yes Surf. 13-д” Surface 54.5 J-55 8RD Surf. 1,500’ 17-½” 3,005’ 1,100 sx Surf. DV Collar 1,500’ 1,503’ 13-д” Surface 54.5 J-55 8RD 1,503’ 3,005’ 600 sx 2,290’ Calc 7” Production 29 N-80 BTC Surf. 303’ 9-и” 11,040’ 650 sx 5,720’ CBL 7” 26 303’ 1,296’ 7” 23 1,296’ 4,793’ 7” 26 4,793’ 6,306’ 7” 29 6,306’ 7,509’ DV Collar 7,509’ 7,511’ 4-1/2” Liner 12.6 L-80 DWC/C 7,198’ 11,524’ 6” 11,525’ 309 sx 7,198’ Volume 20” 30’ 13-3/8” 3,005’ 4-1/2” CBL TOC 5,720’ 7” DV Collar 7,509’ JEWELRY DETAIL NO. Depth ID OD Item 1 19.29’ 2.900” 7.000” 3-1/2” Tubing Hanger 2 320’ 2.813” 4.5” 3-1/2” X – Landing Nipple 3 330’ 2.441” - 3-1/2” x 2-7/8” Crossover 4 7,150’ 1.995” - 2-7/8” x 2-3/8” Crossover 5 7,198’ 7” X 4-1/2” ZXP liner hanger 6 11,074’-11,081’ 1.995” 2.688” Anchor Latch Seal Assembly - 6.17’ Stung into Packer/SBE 7 11,075’ 2.688” 4.500” 4-1/2” x 2-3/8” Model D Perm Packer 8 11,077’ 2.688” Seal Bore Extension 9 11,090’ 1.875” 3.080” X – Landing Nipple 10 11,099’ 1.995” 3.100” WL Entry Guide 1 X PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225’ 11,265’ 10,329’ 10,355’ 02/05/16 3-3/8” 6spf 60 deg H-2 11,281’ 11,310’ 10,365’ 10,385’ 02/04/16 3-3/8” 6spf 60 deg H-3 11,328’ 11,345’ 10,397’ 10,408’ 02/04/16 3-3/8” 6spf 60 deg H-5 11,362’ 11,387’ 10,420’ 10,437’ 02/20/18 Isolated 03/28/18 2 3 4 X 6 7 TOC 11,355’ 03/28/18 RA Tag 10,910’ RA Tag 11,058’ RA Tag 11,202’ RA Tag 11,361’ H-5 H-3 SCU 332-04 Surface Hole Location SEC. 33 SEC. 4 8N9W 7N9W S w a n s o n R i v e r SROP 8 SR-G 16SWANSON RIVER FIELD SCU 34-33 Pad SCU 41-04 Pad U S FISH & WILDLIFE U S FISH & WILDLIFE 1-4 TS Electronics Shop Plant 10 / LEX PM Plant CIGGS Bldg Main Flare Plant Office/Control Room 150°51'20"W150°51'30"W150°51'40"W150°51'50"W 60°44'5"N60°44'0"N60°44'0"N60°43'55"N60°43'55"N60°43'50"N60°43'50"N60°43'45"N60°43'45"N60°43'40"N60°43'40"NSwanson River Field SCU 41-04 Pad SCU 322-04 SHL - 660 ft Radius 0 100 200 300 400 Feet Legend SCU 322-04 SHL - 660 ft Radius Surface Well Location Well Pads Existing Pipelines Cook Inlet Oil and Gas Units SRF Field Overview Project Area 1 inch = 200 feet Map Date: 8/23/2021 Document Path: O:\Alaska\GIS\cook_inlet\fields\SRF\MXDs\SRF_Proposed_2021\mxds\SRF_SCU-322C-04_Well_SHL_660ftBuffer_11x17P_TSidoti_v01.mxd Swanson River SCU 322C-04 Current 02/11/2016 Casing head, Shaffer KD, 13 5/8 3M X 13 3/8 SOW, w/ 2- 2'’ LPO, 7'’ casing hung of with KD slips and packoff assy Tubing head, Shaffer T55-L1, 13 5/8 5M X 7 1/16 5M, w/ 2- 2 1/16 5M SSO, 7'’ Type 1 secondary seal in head Completion spool, Seaboard-S, 7 1/16 5M FE X 7 1/16 5M FE, no outlets on head Adapter, CW, 7 1/16 5M X 3 1/8 5M, w/ 5 ½ seal pocket, 2- 1'’ NPT control line exits Valve, CIW-F, 2 1/16 5M FE, HWO, AA Qty 2 Valve, plug, 2'’ LPO, HWO, AA Tubing hanger, CW-C-EN- CCL, 7 X 3 1/2 EUE 8rd lift and 3 1/2 EUE susp, w/ 3'’ type H BPV profile, 5 ½ EN, Alloy material Swanson River SCU 322C-04 13 3/8 X 7 X 2 7/8 BHTA, Bowen, 3 1/8 5M FE X 3'’ Bowen top Valve, master, FMC-120, 3 1/8 5M FE, HWO, DD trim Valve, swab, FMC-120, 3 1/8 5M FE, HWO, DD trim Valve, master, FMC-120, 3 1/8 5M FE, HWO, DD trim Valve, Wing, FMC-120, 3 1/8 5M FE, HWO, DD trim Valve, Wing, CIW-FC, 3 1/8 5M FE, HWO, DD trim 1 Carlisle, Samantha J (CED) From:Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Sent:Wednesday, August 25, 2021 3:30 PM To:McLellan, Bryan J (CED) Subject:RE: [EXTERNAL] SCU 322C-04 (PTD 215-217) Map Attachments:SCU 322C-04 Current wellhead drawing.pdf HiBryan, Thewellheaddiagramisattached.Canyoupleaseletmeknowwhatmoredetailyouarewantingforthetreeotherthan thesurfacedrawingIsent. Thisisourtemporaryflowlineplan: x Flowbackironhydrotesteduponinstallationto5000psi. x Bollardserectedaroundflowbacklinestoprotectfromcollision. x SSVtestedonwellsideforlowpressuretrip. x Contromaticsafetyvalvetestedatmanifoldbuildingforhighpressuretrip. x Dailyoperatorchecks. Weflowedback12Ͳ15alllastwinterinasimilarfashion.Idonotanticipatethiswellflowingforverylong,morelike weeksthanmonths. Thanks, Todd From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Monday,August23,20216:23PM To:ToddSidotiͲ(C)<Todd.Sidoti@hilcorp.com> Subject:RE:[EXTERNAL]SCU322CͲ04(PTD215Ͳ217)Map Todd, Pleasealsosendawellhead/treediagram,includingtheSSV. Howlongwouldyouflowthisthroughatemporaryflowline? Thanks BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:ToddSidotiͲ(C)<Todd.Sidoti@hilcorp.com> Sent:Monday,August23,202112:19PM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Subject:RE:[EXTERNAL]SCU322CͲ04(PTD215Ͳ217)Map 2 HereyougoBryansorrythisslippedthroughthecracks. Thank, Todd From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Tuesday,August17,20214:37PM To:ToddSidotiͲ(C)<Todd.Sidoti@hilcorp.com> Subject:[EXTERNAL]SCU322CͲ04(PTD215Ͳ217)Map Todd, Canyousendmeanaerialphotoshowingthe660’radiusaroundthiswelltoverifyitsabilitytoproducewithoutaSSSV? BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified 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 the onward 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified 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 the onward 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. 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Convert Injector to Producer 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): 11,525'N/A Casing Collapse Structural Conductor Surface 1,130psi Intermediate Production 3,830psi Liner 7,500psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 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 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. Authorized Signature: February 15, 2021 11,524'4,737' See Attached Schematic 10,529' 7,509' Perforation Depth MD (ft): See Attached Schematic 7,509' 4-1/2" 7,507'7" 20" 13-3/8" 30' 3,005'2,730psi 30' 3,005' 30' 3,005' See Attached Schematic TVD Burst 11,081' 6,340psi MDLength Size N/A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028997 215-217 50-133-10104-01-00 Soldotna Creek Unit (SCU) 322C-04 Swanson River Field / Hemlock Oil Pool COMMISSION USE ONLY Authorized Name: 8,430psi Tubing Grade: Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com 10,531'11,355'10,415'1,267 N/A Model "D" Permanent Packer ; N/A 11,075' MD, 10,228' TVD ; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:40 pm, Jan 15, 2021 321-032 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.15 13:29:50 -09'00' Taylor Wellman * Email notification to AOGCC when conversion is completed. * 24 hour man watch required while flowing. * Sundry valid for 6 months from date of approval. GAS DSR-1/19/21 Development Convert Injector to Producer 10-404 GLS 2/1/21 SFD 1/19/2021C on Required? Yes 2/1/21 dts 2/1/2021 JLC 2/1/2021 RBDMS HEW 2/2/2021 Well Prognosis Well: SCU 322C-04 Date: 01/12/2021 1 Well Name: SCU 322C-04 API Number: 50-133-10104-01-00 Current Status: Gas Injector Leg: N/A Estimated Start Date: Contingent Rig: Slickline Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-217 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: 2,300 psi @ 10,329’ TVD (Based on Offset Well) Max. Possible Surface Pressure (MPSP) 1267 psi (BHP - 0.1psi/ft gradient) Brief Well Summary SCU 322C-04 is a gas flood injector currently online. The purpose of this work is to have a contingency plan in place to temporarily convert SUC 322C-04 into a producer. This contingency would be executed to provide stabile gas to market in the event of an unforeseen shortage due to mechanical failure in the system. Procedure: 1. RU temporary flowback equipment including horizontal SSV and choke. 2. MIRU SL and pressure test Lubricator to 250 psi low / 2,000 psi high. 3. RIH W/ Retrieving tool and pull Injection Valve from X-nipple @ 320’. RDMO SL. 4. Flow Well to Tank Setting. Test SSV within 5 days (Notify AOGCC 24 hours in advance to give them the opportunity to witness). Attachments: 1. Actual Schematic 2. Proposed Schematic (see attached surface rig up diagram... hardline in place) place to temporarily convert SUC 322C-04 into a producer. Note : 24 hour man watch required purpose of this work is to have a contingency plan in (Contingency Plan) Updated by DMA 02-08-18 SCHEMATIC Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 TD = 11,525’ MD / 10,531’ TVD PBTD = 11,355’ MD / 10,415’ TVD Max Deviation = 49° @ 11,247’ GL: 145’ AMSL KB – 18’ TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2” Tubing 9.3 L-80 8rd EUE 2.992” Surf 331’ 2-7/8” Tubing 6.5 L-80 8rd EUE 2.441” 331’ 7,150’ 2-3/8” Tubing 4.7 L-80 SuperMax 1.995” 7,150’ 11,081’ 10 9 8 5 H-2 H-1 CASING DETAIL Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20” Conductor - - - Surf. 30’ - Yes Surf. 13-д” Surface 54.5 J-55 8RD Surf. 1,500’ 17-½” 3,005’ 1,100 sx Surf. DV Collar 1,500’ 1,503’ 13-д” Surface 54.5 J-55 8RD 1,503’ 3,005’ 600 sx 2,290’ Calc 7” Production 29 N-80 BTC Surf. 303’ 9-и” 11,040’ 650 sx 5,720’ CBL 7” 26 303’ 1,296’ 7” 23 1,296’ 4,793’ 7” 26 4,793’ 6,306’ 7” 29 6,306’ 7,509’ DV Collar 7,509’ 7,511’ 4-1/2” Liner 12.6 L-80 DWC/C 7,198’ 11,524’ 6” 11,525’ 309 sx 7,198’ Volume 20” 30’ 13-3/8” 3,005’ 4-1/2” CBL TOC 5,720’ 7” DV Collar 7,509’ JEWELRY DETAIL NO. Depth ID OD Item 1 19.29’ 2.900” 7.000” 3-1/2” Tubing Hanger 2 320’ 2.813” 4.5” 3-1/2” X – Landing Nipple (injection valve) 3 330’ 2.441” - 3-1/2” x 2-7/8” Crossover 4 7,150’ 1.995” - 2-7/8” x 2-3/8” Crossover 5 7,198’ 7” X 4-1/2” ZXP liner hanger 6 11,074’-11,081’ 1.995” 2.688” Anchor Latch Seal Assembly - 6.17’ Stung into Packer/SBE 7 11,075’ 2.688” 4.500” 4-1/2” x 2-3/8” Model D Perm Packer 8 11,077’ 2.688” Seal Bore Extension 9 11,090’ 1.875” 3.080” X – Landing Nipple 10 11,099’ 1.995” 3.100” WL Entry Guide 1 X PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225’ 11,265’ 10,329’ 10,355’ 02/05/16 3-3/8” 6spf 60 deg H-2 11,281’ 11,310’ 10,365’ 10,385’ 02/04/16 3-3/8” 6spf 60 deg H-3 11,328’ 11,345’ 10,397’ 10,408’ 02/04/16 3-3/8” 6spf 60 deg H-5 11,362’ 11,387’ 10,420’ 10,437’ 02/20/18 Isolated 03/28/18 2 3 4 X 6 7 TOC 11,355’ 03/28/18 RA Tag 10,910’ RA Tag 11,058’ RA Tag 11,202’ RA Tag 11,361’ H-5 H-3 INJ valve Updated by TCS 01-12-21 PROPOSED SCHEMATIC Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 TD = 11,525’ MD / 10,531’ TVD PBTD = 11,355’ MD / 10,415’ TVD Max Deviation = 49° @ 11,247’ GL: 145’ AMSL KB – 18’ TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2” Tubing 9.3 L-80 8rd EUE 2.992” Surf 331’ 2-7/8” Tubing 6.5 L-80 8rd EUE 2.441” 331’ 7,150’ 2-3/8” Tubing 4.7 L-80 SuperMax 1.995” 7,150’ 11,081’ 10 9 8 5 H-2 H-1 CASING DETAIL Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20” Conductor - - - Surf. 30’ - Yes Surf. 13-д” Surface 54.5 J-55 8RD Surf. 1,500’ 17-½” 3,005’ 1,100 sx Surf. DV Collar 1,500’ 1,503’ 13-д” Surface 54.5 J-55 8RD 1,503’ 3,005’ 600 sx 2,290’ Calc 7” Production 29 N-80 BTC Surf. 303’ 9-и” 11,040’ 650 sx 5,720’ CBL 7” 26 303’ 1,296’ 7” 23 1,296’ 4,793’ 7” 26 4,793’ 6,306’ 7” 29 6,306’ 7,509’ DV Collar 7,509’ 7,511’ 4-1/2” Liner 12.6 L-80 DWC/C 7,198’ 11,524’ 6” 11,525’ 309 sx 7,198’ Volume 20” 30’ 13-3/8” 3,005’ 4-1/2” CBL TOC 5,720’ 7” DV Collar 7,509’ JEWELRY DETAIL NO. Depth ID OD Item 1 19.29’ 2.900” 7.000” 3-1/2” Tubing Hanger 2 320’ 2.813” 4.5” 3-1/2” X – Landing Nipple 3 330’ 2.441” - 3-1/2” x 2-7/8” Crossover 4 7,150’ 1.995” - 2-7/8” x 2-3/8” Crossover 5 7,198’ 7” X 4-1/2” ZXP liner hanger 6 11,074’-11,081’ 1.995” 2.688” Anchor Latch Seal Assembly - 6.17’ Stung into Packer/SBE 7 11,075’ 2.688” 4.500” 4-1/2” x 2-3/8” Model D Perm Packer 8 11,077’ 2.688” Seal Bore Extension 9 11,090’ 1.875” 3.080” X – Landing Nipple 10 11,099’ 1.995” 3.100” WL Entry Guide 1 X PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225’ 11,265’ 10,329’ 10,355’ 02/05/16 3-3/8” 6spf 60 deg H-2 11,281’ 11,310’ 10,365’ 10,385’ 02/04/16 3-3/8” 6spf 60 deg H-3 11,328’ 11,345’ 10,397’ 10,408’ 02/04/16 3-3/8” 6spf 60 deg H-5 11,362’ 11,387’ 10,420’ 10,437’ 02/20/18 Isolated 03/28/18 2 3 4 X 6 7 TOC 11,355’ 03/28/18 RA Tag 10,910’ RA Tag 11,058’ RA Tag 11,202’ RA Tag 11,361’ H-5 H-3 1 Carlisle, Samantha J (CED) From:Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Sent:Thursday, January 28, 2021 1:28 PM To:Schwartz, Guy L (CED) Subject:RE: [EXTERNAL] SCU 322C-04 (PTD 215-217) Attachments:Surface Layout.pdf Guy, Diagramattached.Pleaseletmeknowifyouhavequestions. Thanks, Todd From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Wednesday,January27,202111:45AM To:ToddSidotiͲ(C)<Todd.Sidoti@hilcorp.com> Subject:[EXTERNAL]SCU322CͲ04(PTD215Ͳ217) Todd, Canyouprovideasketchofthelayoutofthesurfaceequipmentfortheflowback?Irealizethisisacontingencyonly. AOGCCwilllikelyonlyallowthissundrytobevalidfor4months(forthiswinterseason).Youmayneveractuallydothe conversion. GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified 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 the onward 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. MEMORANDUM State of Alaska abing4230 4119 4223 Alaska Oil and Cas Conservation Commission TO: Jim Regg C{,/ P.1. Supervisor I { I Z-��Ij.� DATE: Thursday, April 9, 2020 SUBJECT: Mechanical Integrity Tests 2606 Hilcorp Alaska, LLC OA 322C-04 FROM: Jeff Jones sOLDOTNA CK UNIT 322C-04 Petroleum Inspector Src: Inspector Reviewed By::56z— .f P.J. Supry J � NON -CONFIDENTIAL NON-CONFIDENTIAL Comm Well Name SOLDOTNA CK UNIT 322C-04 API Well Number 50-133-10104-01-00 Inspector Name: Jeff Jones Insp Num: mitD200406095557 Permit Number: 215-217-0 Inspection Date: 4/32020 Rel Insp Num: Packer Depth Well 322C-04 ' Typelnj c TVD 10230 PTD 215'-170 'Type Test' svr 'Test psi 2558 BBL Pumped: 2._ BBL Returned: 2 Interval 4YRTST P/F P Notes: I well inspected, no exceptions noted Pretest Initial 15 Min 30 Min 45 Min 60 Min abing4230 4119 4223 4233 IA 457 2607 2606 2606 OA 49 50 50 49 MT>I- d� .31 Sl 17� ti � 4 I Itzo '& 460- G,4-,C,l Thursday, April 9,2020 Pa6C I of I STATE OF ALASKA RECEN ACA OIL AND GAS CONSERVATION COIOSION REPORT OF SUNDRY WELL OPERATIONS MAY 14 2018 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing U 0 pfr iii::'s• 'd '7U Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑ Exploratory E 215-217 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic❑ Service ❑✓ 6.API Number: AK 99503 50-133-10104-01-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028997 Soldotna Creek Unit(SCU)322C-04 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil Pool 11.Present Well Condition Summary: Total Depth measured 11,525 feet Plugs measured N/A feet true vertical 10,531 feet Junk measured N/A feet Effective Depth measured 11,355 feet Packer measured 11,075 feet true vertical 10,415 feet true vertical 10,228 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 30' 20" 30' 30' Surface 3,005' 13-3/8" 3,005' 3,005' 2,730psi 1,130psi Intermediate 1 Production 7,509' 7" 7,509' 7,507' 6,340psi 3,830psi Liner 4,737' 4-1/2" 11,524' 10,529' 17,693psi 16,769psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic ^� � 3-1/2" *MEV JY 3 Pi 331'TVD Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.5#/L-80 7,150'MD 7,148'TVD 2-3/8" 4.7#/L-80 11,081'MD 10,232'TVD Packers and SSSV(type,measured and true vertical depth) Model D Pkr;N/A 11,075'MD 10,288'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 19,408(injected) 0 726 4265 Subsequent to operation: 0 14,115(injected) 0 980 4109 74.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑l Exploratory Development Service ❑ Stratigraphic E Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑Q SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 318-107 Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcorp.com Authorized Signature: � �� Date: 5AY/A? Contact Phone: 777-8420 Form 10-404 Revised 4/2017 RBDMSaMMAY 2 5 2018 7r/6 Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 322C-04 E-Line 50-133-10104-01 215-217 3/25/18 3/28/18 �ailfOperations Q 't 03/25/2018-Sunday Meet at office-work permit.Arrive on location -JSA-Spot equipment. Sand work area. Rig up equipment and cement equipment. PT low 250 psi, high 2500 psi. RIH with 2 - 1 11/16" WB, 1 11/16" CCL and 30' of 1 11/16" dump bailer. Tagged at 11417' (correlated to perforating pass dated 2/20/2018 ). Dumped at 11412' POOH. OOH - Rebuilt cement pump. Mixed up cement. RIH with 2 - 1 11/16" WB, 1 11/16" CCL and 30' of 1 11/16" dump bailer. Dumped at 11408' POOH. OOH - Mixed up cement. RIH with 2 - 1 11/16" WB, 1 11/16" CCL and 30' of 1 11/16" dump bailer. Dumped at 11403' POOH. POOH - Mixed up cement. RIH with 2 - 1 11/16" WB, 1 11/16" CCL and 30' of 1 11/16" dump bailer. (y Dumped at 11399' POOH. OOH - Rig down for the night. Leave location. 03/26/2018- Monday PTW and JSA. RIH w/1-11/16" Dump bailer full of cement, correlated with yesterday log and tagged at 11,392'. Pick up and dump cement. Made 6 more runs with dump bailer full of cement. Dump cement from 11,392' to est 11,364' depending on how much the perk will take. Bailer holds approx. 3 gals. Rig down for the night. 03/27/2018-Tuesday PTW and JSA. Rig up lubricator. PT to 250 psi low and 2500 psi high. RIH w/1-11/16"x30' bailer full of cement (approx. 3 gal), tie into yesterday log and tag at 11,377'. Pick up and dump cement. Made 3 more bailer runs with cement. Est TO,57 to be 11,360'. Will check tomorrow. Rig down lubricator and WOC. 03/28/2018-Wednesday Meet at office -obtain work permit and hold PJSM.Arrive on location - Rig equipment- mix up cement. RIH with 2 - 1- 11/16" WB, 1-11/16" CCL and 30' of 1-11/16" dump bailer. Set down twice at 11,309' (correlated). Worked through and tagged 15 times top of cement at 11,351'. Sent CCL log to town and verified cement top at 11,355' with CCL and perf✓ readings. POOH. OOH. RD and move to SCU 41B-04. Rig up containment and equipment on well. Sign out and leave Swanson office. . Swanson River Field H 0 SCHEMATIC well: scu 322C-04 PTD: 215-217 Hilcorp Alaska,LLC API: 50-133-10104-01 GL:145'AMSL CASING DETAIL l<B-18' Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 1 20" Conductor - - - Surf. 30' - Yes Surf. 20 13-3" Surface 54.5 J-55 8RD Surf. 1,500' 30' DV Collar 1,500' 1,503' 3,005' 1,100 sx Surf. 2 el 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,290'Calc • 7" 29 Surf. 303' 7" 26 303' 1,296' 3 7" Production 23 N 80 BTC 1,296' 4,793' 9-3/4" 650 sx 5,720' 3,005' *s 7" 26 4,793' 6,306' 11,040' CBL 7" 29 1 6,306' 7,509' DV Collar 7,509' 7,511' 4-1/2" Liner 12.6 L-80 DWC/C 7,198' 11,524' 11,525' 309 sx Vo u9me CBL TOC f4., , ,F 5,720' 0 .Y00 TUBING DETAIL Y',i l'i; • * Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf 331' 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" 331' 7,150' »� „ 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,150' 11,081' JEWELRY DETAIL gloht 4 li 5 NO. Depth ID OD Item 1 19.29' 2.900" 7.000" 3-1/2"Tubing Hanger 2 320' 2.813" 4.5" 3-1/2"X-Landing Nipple(injection valve) 3 330' 2.441" - 3-1/2"x 2-7/8"Crossover y�g' 4 7,150' 1.995" - 2-7/8"x 2-3/8"Crossover 7"DV rte' 5 7,198' 7"X 4-1/2"ZXP liner hanger ', Collar _l . 14. 2.688"Anchor Latch Seal Assembly6.17' 7,509' ", e 6 11,074'-11,081' 1.995" Stung into Packer/SBE 7 11,075' 2.688" 4.500" 4-1/2"x 2-3/8"Model D Perm Packer 1 ' 8 11,077' 2.688" Seal Bore Extension 9 11,090' 1.875" 3.080" X-Landing Nipple 10 11,099' 1.995" 3.100" WL Entry Guide . PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes i -,` ''I H-1 11,225' 11,265' 10,329' 10,355' 02/05/16 3-3/8"6spf 60 deg RA Tag . .''- H-2 11,281' 11,310' 10,365' 10,385' 02/04/16 3-3/8"6spf 60 deg 10,910' 37 6 -_. H-3 11,328' 11,345' 10,397' 10,408' 02/04/16 3-3/8"6spf 60 deg H-5 11,362' 11,387' 10,420' 10,437' 02/20/18 Isolated 03/28/18 LZ Ei 9 ,g RA Tag J. f �_` 11,058' 1i -:` H-1 RA Tag '. H-7 11,202' ,°` 0 RA Tag '; + ' TOC 11,361' . WitH-3 p 11,355' a1 .; H-5 03/28/18 4-1/2" �� .t TD=11,355'MD/10,415'TVD PBTD=11,438'MD/10,471'TVD Max Deviation=49°@ 11,247' Updated byDMA 05-09-18 P Vor 77. \\\�/7� ap � THE STATP • � i Alaska Oil and Gas ti��'►"�'��iA� nf ALAsKA Conservation Commission 'WA�etz 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 oFALAS�P Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC SGAH 3 800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 322C-04 Permit to Drill Number: 215-217 Sundry Number: 318-107 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this 21 day of March, 2018. RECEIVED • • STATE OF ALASKAAR01$ ALASKA OIL AND GAS CONSERVATION COMMISSION 6) 3 APPLICATION FOR SUNDRY APPROVALS At' 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations Q ' Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate 0 Other Stimulate 0 Pull Tubing ❑ Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing ❑ Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development El 215-217 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service g ' 6.API Number: Anchorage Alaska 99503 50-133-10104-01-.ac, r,A 7.If perforating: 8.Well Name and Number: g l`}:/,. What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes 0 No 2Soldotna Creek Unit(SCU)322C-04 9.Property Designation(Lease Number): 10. Field/Pool(s): FEDA028997- Swanson River Field/Hemlock Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 11,525' ' 10,531' ' 11,438' 10,471' —4,100 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 30' 20" 30' 30' Surface 3,005' 13-3/8" 3,005' 3,005' 2,730psi 1,130psi Intermediate Production 7,509' 7" 7,509' 7,507' 6,340psi 3,830psi Liner 4,737' 4-1/2" 11,524' 10,529' 17,693psi 16,769psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory 0 Stratigraphic ❑ Development 0 Service ❑✓ " 14. Estimated Date for 15.Well Status after proposed work: March 21,2018 Commencing Operations: OIL ❑ WINJ ❑ WDSPL 0 Suspended ❑ 16.Verbal Approval: Date: GAS D WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑D " Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcorn.com .///70,-- ----- Contact Phone: 777-8420 /Authorized Signature: �' 'l� Date: 3/J3 t' COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 1,3 - (b� Plug Integrity 0 BOP Test ❑ Mechanical Integrity Test 0 Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No E Spacing Exception Required? Yes ElNo i/ Subsequent Form Required: /0'-- L(©11 RBDMS AR 2 1 2018 APPROVED BY Approved by: fN**''' '..---- COMMISSIONER THE COMMISSION Date: ' 'I ` It it sss�� Submit Form and ti Form 10-403 Revi d 4/2017 Approved a lic io is li or m h the date of approval. Attachments in Duplicate • . Well Prognosis Well: SCU 322C-04 Hilcorp Alaska,LU Date:3/13/2018 Well Name: SCU 322C-04 API Number: 50-133-10104-01 Current Status: Gas Injector Leg: N/A Estimated Start Date: Rig: E-line 3/21/2018 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-217 First Call Engineer: Ted Kramer (907)777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(C) AFE Number: Maximum Expected BHP: —4,100 psi. Injection Pressure Max. Potential Surface Pressure: —4,100 psi @ surface (Based on Current Injection Pressure) Brief Well Summary SCU 322C-04 is a gas injection well supporting the Swanson Hemlock gas flood. Injection in this well was 14 MMSCFD at 4,100 psi.With the Hemlock Benches 1, 2, and 3 open and injecting. Once the Hemlock Bench#5 was perforated in February 2018, injection increased to 19 MMSCFD at 4,100 psi. Unfortunately, no gas or oil was observed in the offset producers. Objective: The purpose of this work is to shut off the Hemlock Bench#5 perforations by placing 78'of cement in the bottom of the well bore to cover the Hemlock Bench#5 perforations shutting them off. E-Line Procedure: 1. MIRU E-line unit. 2. MU Lubricator. Pressure test same to 250 low/4,500 psi high. 3. PU RIH WI GR and tag bottom of well. (Note: Last tag was 11,416'on 2/20/2018). 4. PU dump bailer,fill with cement and RIH to depth placing cement in the bottom of the well. Repeat until calculated top of cement reaches 11,361'(approx. 50 gals.). POOH. WOC. 5. PU GR, RIH and tag TOC(TOC needs to be above 11,361'). RDMO E-line Unit. 6. Turn well back to Injection. Attachments: 1. Current Schematic 2. Proposed Schematic 1 • • Swanson River Field • IR Well: SCU 322C-04 SCHEMATIC PTD: 215-217 Ililcorp Alaeka,IA.(: API: 50-133-10104-01 GL:145'AMSL CASING DETAIL KB-18' Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 1rI 20" Conductor - - - Surf. 30' - Yes Surf. 20" °;' 13-%" Surface 54.5 J-55 8RD Surf. 1,500 30' DV Collar 1,500 1,503' 17-%" 1,100 sx Surf. ,005' .`' 2 X Ir 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,290'Calc 7" 29 Surf. 303' 7" 26 303' 1,296' 3 ro 7" Production 23 N-80 BTC 1,296' 4,793' 9-%" 5,720' 13-3/8" ,, 7" 26 4,793' 650 sx 6,306' _ 11,040' CBL 3,005' 7" 29 6,306' 7,509' DV Collar 7,509' 7,511' 4-1/2" Liner 12.6 L-80 DWC/C 7,198' 11,524' 11,525' 309 sx Vo u9me CBL TOC ° 5,720' f, i TUBING DETAIL ' IP Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf 331' 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" 331' 7,150' 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,150' 11,081' r , 1 JEWELRY DETAIL 4\ / 5 NO. Depth ID OD Item , k, 1 19.29' 2.900" 7.000" 3-1/2"Tubing Hanger :a 2 320' 2.813" 4.5" 3-1/2"X-Landing Nipple(injection valve) 3 330' 2.441" 3-1/2"x 2-7/8"Crossover 7"DV r 4 7,150' 1.995" - 2-7/8"x 2-3/8"Crossover Collar , 5 7,198' 7"X 4-1/2"ZXP liner hanger 7,509' 6 11,074'-11,081' 1.995" 2.688"Anchor Latch Seal Assembly-6.17' Stung into Packer/SBE 7 11,075' 2.688" 4.500" 4-1/2"x 2-3/8"Model D Perm Packer 8 11,077' 2.688" Seal Bore Extension `F. 9 11,090' 1.875" 3.080" X-Landing Nipple k', 10 11,099' 1.995" 3.100" WL Entry Guide .. ��" PERFORATIONS . '` ; Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225' 11,265' 10,329' 10,355' 02/05/16 3-3/8"6spf 60 deg RA Tag ';i, III' H-2 11,281' 11,310' 10,365' 10,385' 02/04/16 3-3/8"6spf 60 deg 10,910' ,_ , H-3 11,328' 11,345' 10,397' 10,408' 02/04/16 3-3/8"6spf 60 deg �. 7 6 H-5 11,362' 11,387' 10,420' 10,437' 02/20/18 Open 8- ,Tli 19 ,;r ® , RA Tag 11,058' ski 1� ---0" H-1 RA Tag a L, AI H-2 11,202' RA Tag n L H-3 11,361' iiiE H-5 4-1/2" +,L, - "; �' TD=11,525'MD/10,531'ND PBTD=11,438'MD/10,471'ND Max Deviation=49°@ 11,247' Updated by DMA 02-21-18 Swanson River Field ' Well: SCU 322C-04 PROPOSED SCHEMATIC PTD: 215-217 iiiileorp Alaska,LLC API: 50-133-10104-01 GL:145'AMSL CASING DETAIL KB-18' Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 1 20" Conductor Surf. 30' Yes Surf. 20" 13-%" Surface 54.5 J-55 8RD Surf. 1,500' 30' DV Collar 1,500' 1,503' 17-'/ 1,100 sx Surf. I 2 X 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 3,005' ' i 600 sx 2,290'Calc 7" 29 Surf. 303' 7" 26 303' 1,296' 3 j 7" Production 23 N-80 BTC 1,296' 4,793' 9-'h" 5,720' 13-3/8", 650 sx J 7" 26 4,793' 6,306' 11,040' CBL 3,005' 7" 29 6,306' 7,509' DV Collar 7,509' 7,511' 4-1/2" Liner 12.6 L-80 DWC/C 7,198' 11,524' 11,525' 309 sx Volu9me CBL TOC - °i 5,720' " !3I TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf 331' 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" 331' 7,150' 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,150' 11,081' ,�; JEWELRY DETAIL 4L' 5 NO. Depth ID OD Item 1 19.29' 2.900" 7.000" 3-1/2"Tubing Hanger 2 320' 2.813" 4.5" 3-1/2"X-Landing Nipple(injection valve) 3 330' 2.441" - 3-1/2"x 2-7/8"Crossover I" 4 7,150' 1.995" - 2-7/8"x 2-3/8"Crossover 7"DV or ' 5 7,198' 7"X 4-1/2"ZXP liner hanger Collar 2.688"Anchor Latch Seal Assembly-6.17' 7,509' 6 11,074'-11,081' 1.995" Stung into Packer/SBE 7 11,075' 2.688" 4.500" 4-1/2"x 2-3/8"Model D Perm Packer 8 11,077' 2.688" Seal Bore Extension 9 11,090' 1.875" 3.080" X-Landing Nipple • 10 11,099' 1.995" 3.100" WL Entry Guide ' PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 11,225' 11,265' 10,329' 10,355' 02/05/16 3-3/8"6spf 60 deg RA Tag III H-2 11,281' 11,310' 10,365' 10,385' 02/04/16 3-3/8"6spf 60 deg 10,910' , H-3 11,328' 11,345' 10,397' 10,408' 02/04/16 3-3/8"6spf 60 deg 7 6 H-5 11,362' 11,387' 10,420' 10,437' 02/20/18 Open :_ 8 9 RA Tag -.. Ali 11,058' 1 -' Ar H-1 RA Tag . TOC 11,202' _ H-2 ±11,361 / RA Tag : ' r 11,361' i ; -r-,..--- H-3 (_ .. ,'1 # H-5 f ' 4-1/2" - ,, TD=11,525'MD/10,531'TVD PBTD=11,438'MD/10,471'TVD Max Deviation=49°@ 11,247' Updated by DMA 03-13-18 llLjtIVL STATE OF ALASKA j'� . AL.OIL AND GAS CONSERVATION COMI SION 379 ? $ 2018 REPORT OF SUNDRY WELL OPERATIONS . 1.Operations Abandon U Plug Perforations U Fracture Stimulate L] Pull Tubing U Operations shutdown U Performed: Suspend El Perforate El Other Stimulate El Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well El Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑ Exploratory El 215-217 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic❑ Service ❑✓ 6.API Number: • AK 99503 50-133-10104-01-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028997 Soldotna Creek Unit(SCU)322C-04 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil Pool 11.Present Well Condition Summary: Total Depth measured 11,937 feet Plugs measured N/A feet true vertical 10781 feet Junk measured N/A feet Effective Depth measured 11,867 feet Packer measured 11,075 feet true vertical 10,735 feet true vertical 10,228 feet Casing Length Size MD TVD Burst Collapse Structural Conductor Surface Intermediate �g • /•i r Production SCAB_ t' Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 3-1/2" 9.3#/L-80 331'MD 331'TVD Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.5#&4.7#/L-80 7,150'&11,081'MD 7,148'&10,232'TVD Packers and SSSV(type,measured and true vertical depth) Model D Pkr;N/A 11,075'MD 10,288'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 14,799(injected) 0 625 4100 Subsequent to operation: 0 19,408(injected) 0 726 4265 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑., Exploratory❑ Development[ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run El 16.Well Status after work: Oil ❑-� Gas El WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG GINJ Q SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. S er or N/A if C.O.Exempt: 318-058 Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkrameranhilcorq.com Authorized Signature: �� Date:Z/14I( ' Contact Phone: 777-8420 Form 10-404 Revised 4/2017 Ra"" iV:3 EL, : `"l8 �, .2-'- $ f((/4 8, Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 322C-04 E-Line 50-133-10104-01 215-217 2/19/18 2/20/18 Daily Operations: 02/19/2018 - Monday Arrive @ shop get tools and crew head to SR. Arrive @ SR JSA/TGSM rig up PT 5,000 psi (good) shut in well. RIH w/2.84" G-ring to 327' KB. Tag POOH. RIH w/3" GS w/prong to 327' KB wit latch and pull mcx valve. POOH. RIH w/ 1-3/4" DD bailer to 11,419' KB. POOH. RIH w/20' 1-5/8" spent dummy guns to 11,410' KB no tag. POOH. OOH. Rig down. Head to shop. Arrive back @ shop. 02/20/2018 -Tuesday Sign in, Mobe to Location, PTW,JSA, Spot equip and make up lubricator. Shut well in. PT lubricator to 250 psi low and 4,200 psi high. RIH w/ 1.69" x 20' Razor HC, 6 spf, 60 degree, decentralized perf gun, tie into CBL and tag fill at 11,416'. Run correlation log and send to town. Get ok to shot from 11,367' to 11,387'. Spotted and fired gun with 1,275 psi on tubing& 340 psi CP. After 5 min TP - 1,280 psi, CO - 340 psi. 10 min -TP- 1,300 psi, CP - 340 psi. 15 min -TP - 1,310 psi, CP- 340 psi. POOH. All shots fired. RIH w/ 1.69" x 20' Razor HC, 6 spf, 60 degree, decentralized perf gun, tie into CBL. Run correlation log and send to town. Get ok to shot from 11,362' to 11,382'. Spotted and fired gun with 1,445 psi on tubing & 340 psi CP. After 5 min TP - 1,490 psi, CO - 320 psi. 10 min -TP - 1,470 psi, CP - 350 psi. 15 min -TP - 1,490 psi, CP - 350 psi. POOH. All shots fired. RIH w/ 1.69" x 20' Razor HC, 6 spf, 60 degree, decentralized perf gun, tie into CBL. Run correlation log and send to town. Get ok to shot from 11,364.5'to 11,384.5'. Spotted and fired gun with 1510 psi on tubing & 240 psi CP. After 5 min TP- 1,510 psi, CO - 240 psi. 10 min -TP- 1,510 psi, CP - 240 psi. 15 min -TP- 1,510 psi, CP-240 psi. POOH. All shots fired. Rig down lubricator, secure the well and turn well over to field. . . H 0 . Swanson River Field Well: SCU 322C-04 SCHEMATIC PTD: 215-217 Ilileorp 1la,ka.LLC API: 50-133-10104-01 GL:145'AMSL CASING DETAIL KB-1s' Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 1 f a 20" Conductor Surf. 30' Yes Surf. 20" * 13-%" Surface 54.5 J-55 8RD Surf. 1,500' iii 30' -` DV Collar 1,500' 1,503' 17-%:" 1,100 sx Surf. ., 2 x `p,, 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 3,005' 600 sx 2,290'Calc 7" 29 Surf. 303' 7" 26 303' 1,296' `? 3 7" Production 23 N-80 BTC 1,296' 4,793' 9-%" 5,720' 13-3/8"ifit IV 7" 26 4,793' 6,306' 11,040' 650 sx CBL 3,005' 7" 29 6,306' 7,509' DV Collar 7,509' 7,511' 4-1/2" Liner 12.6 L-80 DWC/C 7,198' 11,524' 11,525' 309 sx Voluroe CBL TOC ' t 5,720' x,«' TUBING DETAIL . l'..,- j� Size Type Wt Grade Conn ID Top Btm .fi . ' itlh1 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf 331' 4 ''• 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" 331' 7,150' 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,150' 11,081' JEWELRY DETAIL t,' 4 5 1. OM r ; NO. Depth ID OD Item ra; 1 19.29' 2.900" 7.000" 3-1/2"Tubing Hanger 4 'I 2 320' 2.813" 4.5" 3-1/2"X-Landing Nipple(injection valve) - 3 330' 2.441" - 3-1/2"x 2-7/8"Crossover 7"DV 4 7,150' 1.995" - 2-7/8"x 2-3/8"Crossover Collar . '` I 5 7,198' 7"X 4-1/2"ZXP liner hanger 2.688"Anchor Latch Seal Assembly-6.17' 7,509' 6 11,074'-11,081' 1.995" Stung into Packer/SBE 7 11,075' 2.688" 4.500" 4-1/2"x 2-3/8"Model D Perm Packer 8 11,077' 2.688" Seal Bore Extension 9 11,090' 1.875" 3.080" X-Landing Nipple k 10 11,099' 1.995" 3.100" WL Entry Guide c laV PERFORATIONS '," Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes • H-1 11,225' 11,265' 10,329' 10,355' 02/05/16 3-3/8"6spf 60 deg RA Tag . H-2 11,281' 11,310' 10,365' 10,385' 02/04/16 3-3/8"6spf 60 deg 10,910' , . H-3 11,328' 11,345' 10,397' 10,408' 02/04/16 3-3/8"6spf 60 deg 7 6 ui H-5 11,362' 11,387' 10,420' 10,437' 02/20/18 Open 8 9 RA Tag rzi i. - 11,058' -` H-1 3 RA Tag =., , 11,202' ' H-2 RA Tag r. - 11,361' H-3 H-5*' 4_1/2" .L _ - TD=11,525'MD/10,531'TVD PBTD=11,438'MD/10,471'TVD Max Deviation=49'@ 11,247' Updated by DMA 02-21-18 • . ti OF T�� •\\ i�j, ,s, THE STATE Alaska Oil and Gas �� 0,f T L Conservation Commission - = _ � 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Op Main: 907.279.1433 LAs� Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson 3 Operations Manager SC, 2 NE® t R 2018 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 322C-04 Permit to Drill Number: 215-217 Sundry Number: 318-058 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, /a 1 Cathy . Foerster Commissioner 44— DATED this 1 1 day of February, 2018. RE 1T 't S V- FEB -i.M X18 • pp YFEB OS 2018 , STATE OF ALASKA DT .( I '7 S Z ALASKA OIL AND GAS CONSERVATION COMMISSION ;Si C C APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown 0 Suspend 0 Perforate Q . Other Stimulate 0 Pull Tubing D Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well ❑ Alter Casing 0 Other ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory 0 Development ❑ 215-217 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑• 6.API Number: ❑ Service ✓ Anchorage Alaska 99503 50-133-10104-01 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 123B,Rule 5 • Will planned perforations require a spacing exception? Yes 0 No Q Soldotna Creek Unit(SCU)322C-04 9. Property Designation(Lease Number): 10.Field/Pool(s): FEDA028997 • Swanson River Field/Hemlock Oil Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): if..491i-5- 3/ if,,{:3 /v 4'7i >.u*867' /•5j 1833"' -4,100 psi N/A N/A Casing fry fg Length Size ! ,v1°Y,' MD TVD Burst Collapse Structural Conductor 30' 20" 30' 30' Surface 3,005' 13-3/8" 3,005' 3,005' 2,730psi 1,130psi Intermediate Production 7,509' 7" 7,509' 7,507' 6,340psi 3,830psi Liner 4,737' 4-1/2" 11,937' 10,781' 17,693psi 16,769psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development❑ Service ❑✓ 14. Estimated Date for 15.Well Status after proposed work: Commencing Operations: February 23,2018 OIL 0 WINJ ❑ WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS 0 WAG 0 GSTOR D SPLUG ❑ Commission Representative: GINJ ❑✓ • Op Shutdown 0 Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Mana er Contact Email: tkramerehilcorp.com Authorized Signature: 7� Date: 219/05. Contact Phone: 777-8420 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 316- 058 Plug Integrity 0 BOP Test ❑ Mechanical Integrity Test 0 Location Clearance 0 Other: Post Initial Injection MIT Req'd? Yes 0 No 0 Spacing Exception Required? Yes 0 No ©'' Subsequent Form Required: /Q -- 4i 011 R.P f ')."s � Fr5 ., J x �.� _�r A18 APPROVED BY Approved by:A, 4,....._ ,_ COMMISSIONER THE COMMISSION Date: Z—� c��`E 13-/S) I n ,e ,/, � ,k 2 tZ i Submit Form and Form 10-403 Revised 4/ 17 Approved application R o 1 t s cli ate of approval. ,//y Attachments in Duplicate Well Prognosis Well: SCU 322C-04 IIilcurp Alaska,LL Date: 2/9/2018 Well Name: SCU 322C-04 API Number: 50-133-10104-01 Current Status: Gas Injector Leg: N/A Estimated Start Date: 2/23/2018 Rig: Moncla 401 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-217 First Call Engineer: Ted Kramer (907) 777-8420(0) (985) 867-0665 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: Maximum Expected BHP: —4,100 psi. Injection Pressure Max. Potential Surface Pressure: —4,100 psi @ surface (Based on Current Injection Pressure) Maximum Expected BHP of Hemlock Bench 5 —2,200 psi (Based on surrounding Well pressures) • Brief Well Summary SCU 322C-04 is a gas injection well supporting the Swanson Hemlock gas flood. Current injection in this well is approximately 14 MMSCFD at 4,100 psi. into Hemlock Benches 1, 2, and 3. Objective: Hilcorp would like to add the Hemlock Bench#5 to this well. The Hemlock Bench#5 is currently open in offset producer SCU 31-04. Adding this bench to the injector is the first step in pressuring up this interval so that it can be added in other offset producers at a later date. In support of this Sundry Hilcorp has conducted an area review of all wells in a 1/4 mile radius of SCU 322C-04 to confirm that all wells have sufficient containment to be injecting into the Hemlock Bench#5. These wells are listed in the table below: Well Hole Size Casing Cement Top CBL Cement Bond Drilled Size /Hemlock Top Ran across Bench#5 Across Across (Yes �''_ h. (Good G, Fair F, - vat Bench 5 Bench #5 or No) Poor P) 'sf, rr.. , sc cc,. 3 2,24.--• 41140(21C-04 • 6-1/8" 4-1/2" 10,384/ 11,366 Y . G A(44 SCU 22B-04 - 6" 4-1/2" 10,280/10,789 Y G .306'n1e SCU 31-04 . 6-1/8" 4-1/2" 9,273/11,141 Y ' G /bSZ)'11( SCU 12A-04 • 6" 5" ,.8,597/10,374 Y G act; Slickline Pre-work 1. Pull injection valve at 320'. 2. RIH W/GR sand tag bottom for fill. E-Line Procedure: 1. MIRU E-line unit. 2. MU Lubricator. Pressure test same to 250 low/4,200 psi high. 3. RIH and perforate the following intervals: 1 • • Well Prognosis Well: SCU 322C-04 IIilcorp Alaska,LL Date:2/9/2018 Zone Sand Top(MD) Btm(MD) SPF Status Hemlock H5 ±11,362' ±11,455' 6 Proposed a. Proposed perf interval shown on the proposed schematic. b. Final perfs tie-in sheet will be provided to the field for exact perf intervals. c. Correlate using Cement Bond Log (pending Tie-in log). d. Use Gamma/CCL to correlate. e. All perforations in table above are located in the Hemlock Pool based on Conservation Order No. 1238 Rule 5 f. Re-install down-hole injection valve and test within 5 days of re-install. (Note: Notify AOGCC 24 hours prior to testing to provide opportunity to witness). Attachments: 1. Current Schematic 2. Proposed Schematic 3. Map Showing Wells within'A mile radius. 2 • Swanson River Field • II Well: SCU 322C-04 SCHEMATIC PTD: 215-217 Nikon)Alaska,LL( API: 50-133-10104-01 GL:145'AMSL CASING DETAIL KB-18' Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 1 " 4ry 20" Conductor - Surf. 30' - Yes Surf. 20" .,e' 1 13-%" Surface 54.5 J-55 8RD Surf. 1,500' 17-'/:" 1,100 sx Surf. 30' «'" 40* DV Collar 1,500' 1,503' ,, 2 X ., 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 3,005' 600 sx 2,290'Calc 7" 29 Surf. 303' 7" 26 303' 1,296' - 3 Production 23 N-80 BTC 1,296' 4,793' 9-'''h" 5,720' 13-3/8"4`+, 650 sx 3,005' 7" 26 4,793' 6,306' 11,040' CBL 7" 29 6,306' 7,509' DV Collar 7,509' 7,511' 4-1/2" Liner 12.6 L-80 DWC/C 7,198' 11,524' 11,525' 309 sx Vo u9me CBL TOC 5,720' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf 331' 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" 331' 7,150' 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,150' 11,081' 4�J 5 • JEWELRY DETAIL NO. Depth ID OD Item ) +". 1 19.29' 2.900" 7.000" 3-1/2"Tubing Hanger «�a 2 320' 2.813" 4.5" 3-1/2"X-Landing Nipple(injection valve) 3 330' 2.441" 3-1/2"x 2-7/8"Crossover r 4 7,150' 1.995" - 2-7/8"x 2-3/8"Crossover 7"DV tj. Collar IF 5 7,198' 7"X 4-1/2"ZXP liner hanger 7,509' 6 11,074'-11,081' 1.995" 2.688"Anchor Latch Seal Assembly-6.17' -• Stung into Packer/SBE 7 11,075' 2.688" 4.500" 4-1/2"x 2-3/8"Model D Perm Packer 8 11,077' 2.688" Seal Bore Extension ` 9 11,090' 1.875" 3.080" X-Landing Nipple '' 10 11,099' 1.995" 3.100" WL Entry Guide a jFi ti.. PERFORATIONS rev Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes ,°•' H-1 11,225' 11,265' 10,329' 10,355' 3-3/8"6spf 60 deg RA Tag „ . H-2 11,281' 11,310' 10,365' 10,385' 3-3/8"6spf 60 deg 10,910' 7 6 H-3 11,328' 11,345' 10,397' 10,408' 3-3/8"6spf 60 deg - a' , g "ti 9 144., RA Tag >. 11,058' . i 1 ,,#yi S H-1 RA Tag , 11,202' '• H-2 RA Tag . H-3 11,361' r 4-1/2" ,v -- °' TD=11,525'MD/10,531'TVD PBTD=11,438'MD/10,471'ND Max Deviation=49°@ 11,247' Updated by DMA 03-03-16 • • II Swanson River Field Well: SCU 322C-04 PROPOSED SCHEMATIC PTD: 215-217 Hilcorp Alaska,LLC API: 50-133-10104-01 GL:145'AMSL CASING DETAIL KB-18' Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 4 1 20" Conductor Surf. 30' Yes Surf. 20" 13-%" Surface 54.5 J-55 8RD Surf. 1,500' 30' j* DV Collar 1,500' 1,503' 17-%" 1,100 sx Surf. 3,005' 2 a: 13-%" Surface 54.5 1-55 8RD 1,503' 3,005' 600 sx 2,290'Calc 1111 7" 29 Surf. 303' it 0 7" 26 303' 1,296' 3 7" Production 23 N-80 BTC 1,296' 4,793' 9�" 650 sx 5,720' 3,005' 7" 26 4,793' 6,306' 11,040' CBL 7" 29 6,306' 7,509' DV Collar 7,509' 7,511' 4-1/2" Liner 12.6 L-80 DWC/C 7,198' 11,524' 11,525' 309 sx Volu9me CBL TOC 5,720' TUBING DETAIL 14, Size Type Wt Grade Conn ID Top Btm T 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf 331' 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" 331' 7,150' ' �., 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,150' 11,081' tit? N JEWELRY DETAIL 4 i 5 NO. Depth ID OD Item y 7 r 1 19.29' 2.900" 7.000" 3-1/2"Tubing Hanger ' IV2 320' 2.813" 4.5" 3-1/2"X-Landing Nipple(injection valve) IV 3 330' 2.441" - 3-1/2"x 2-7/8"Crossover : ° :48logrig, 4 7,150' 1.995" 2-7/8"x 2-3/r Crossover 7"DV - r,....* P.4q 5 7,198' 7"X 4 1/2"ZXP liner hanger Collar l - 2.688"Anchor Latch Seal Assembly-6.17' 7,509' e 6 11,074'-11,081' 1.995" Stung into Packer/SBE v' 7 11,075' 2.688" 4.500" 4-1/2"x 2-3/8"Model D Perm Packer trT44 11,4 ' 8 11,077' 2.688" Seal Bore Extension 9 11,090' 1.875" 3.080" X-Landing Nipple NO 10 11,099' 1.995" 3.100" WL Entry Guide PERFORATIONS i eel '"', Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes i; a"„ H-1 11,225' 11,265' 10,329' 10,355' 02/05/16 3-3/8"6spf 60 deg RA Tag H-2 11,281' 11,310' 10,365' 10,385' 02/04/16 3-3/8"6spf 60 deg 10,910' H-3 11,328' 11,345' 10,397' 10,408' 02/04/16 3-3/8"6spf 60 deg 7 6 " , H-5 ±11,362' ±11,455' ±10,420' ±10,483' Proposed TBD ti .� ' . 8■ Aar II 9 107. RA Tag - 11,058' 4 1e. t H-1 - a RA Tag ,- 11,202' 're- y H-2 A Tag lei'i `'� RH-3 11,361' t H-5 te',< r {` 4-1/2" )(e/ t, ta,4 TD=11,525'MD/10,531'TVD PBTD=11,438'MD/10,471'TVD Max Deviation=49°@ 11,247' Updated by DMA 02-08-18 • • ' i r SCU 33-33_ ��■ 14A-33 Q\ 14-33 DAOD l / •,a, 0goo $ jl A0300'."--------.'.� • 3 SCU SCU_44B- / SCU 34-• 33 SCU_44-33 1 SCU,�41=05 $RU_24-33 7 SCU_41B-04 SCU - 04,. 4—— ®��, SC 31 B-04 0 \-05 0 o'oo / o. SCU_41B-04PB;' a N SCU :• _-I4 , 04 SCU 41A i?-050\SCU_42-05 rB Cu04 SC _ B 0 i' 1 U. - SC U 12 \ ,,' la SCU 12A I o�CU_ 1 04 SCU_1 -12A-03 f off i \- `l SCU42 04 ' - 42B-05' ii 1, 31-04 Hilcorp Alaska \ S.0 _12-04 g` 4 ¢• I .ra, Swanson River /5P8_ _ ' SCU_322C ' `a S _332 04 SCU 322G041rgedion Map — �in SCU <-04 ss7w 05 \ — ` D POSTEWELL DATA t__ y r SCU_323�0 SCU_43 04WCb ED Lahr v ,1/ \ \o U_2•-� •\\ ER CONTOURS 05 1 \ SR_N_1 ReUHC TIIIREE BCS.CRD { T SCU_43A-p SCU 22-04P- -Corker &15M.5) Ii skeSRTN.UIOY 100 43-05 1 1516 Rads by BiGrimm a I SCU31 SC -04 bandticmeal SYMBOLS\ 11.; — ' Abandoned (1_34-05- T S o�,Hole if bonbon V01 • / Jerked Oil show '0,o0 p' Wrkea • a Well + Rugged and Abandoned U 21A-09 ; ,•L Plugged And Abandoned Oil and Ws well - / Plugged&Aband H Oil Wel C U 41 A-08 ▪ srrn+n Well ® uanawn siaw \\ REMARKS 1-8-2018 U 341-08BY:Ban B,� • 31-08 — SC_ 1-09 • 0 750 1.500 . FEET , li 1 _ o FebnaY a.2018 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2152170 Well Name/No. SOLDOTNA CK UNIT 322C-04 MD 11525 TVD 10531 REQUIRED INFORMATION Operator HILCORP ALASKA LLC API No. 50-133-10104-01-00 Completion Date 2/27/2016 Completion Status 1GINQJ Current Status 1GINJ UIC No Lj Mud Log J 5' �, Vj Samples Directional Survey Yes f DATA INFORMATION J Types Electric or Other Logs Run: ROP/DGR/EWR/ALD/CTN, Formation log, Gas Ration log, LWD comb (data taken from Logs Portion of Master Well Data Maint) Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name ED C 26877 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C Log C Log C 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Digital Data 26877 Log Header Scans 26878 Log Header Scans Log Log Run Interval OH / Scale Media_ No Start Stop CH Received Comments 7370 11525 3/8/2016 Electronic Data Set, Filename: SCU 322C-04 TC.las 3/8/2016 Electronic File: SCU 322C-04 TC MD.cgm' 3/8/2016 Electronic File: SCU 322C-04 TC TVD.cgm ' 3/8/2016 Electronic File: SCU 322C-04 - Definitive . Survey.pdf 3/8/2016 Electronic File: SCU 322C-04.txt 3/8/2016 Electronic File: SCU 322C-04 TC.dlis- 3/8/2016 Electronic File: SCU 322C-04 TC.ver ' 3/8/2016 Electronic File: SCU 322C-04 TC MD.emf . 3/8/2016 Electronic File: SCU 322C-04 TC TVD.emf . Q 3/8/2016 Electronic File: SCU 322C-04 TC MD.pdf P 3/8/2016 Electronic File: SCU 322C-04 TC TVD.pdf 3/8/2016 Electronic File: SCU 322C-04 TC MD.tif , 3/8/2016 Electronic File: SCU 322C-04 TC TVD.tif ' 0 0 2152170 SOLDOTNA CK UNIT 322C-04 LOG HEADERS 0 0 2152170 SOLDOTNA CK UNIT 322C-04ioW LOG HEADERS AOGCC Page I of 5 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/1912017 Permit to Drill 2152170 Well Name/No. SOLDOTNA CK UNIT 322C-04 MD 11525 TVD 10531 Completion Date 2/27/2016 C 26878 Mud Log 25 Operator HILCORP ALASKA LLC Completion Status 1GINJ Current Status 1GINJ 7394 11525 3/8/2016 ED C 26878 Digital Data 7300 11600 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 ED C 26878 Digital Data 3/8/2016 API No. 50-133-10104-01-00 UIC No Final Well Report 2" MD/TVD Gas Ratio Log 2" MD/TVD Drilling Dynamics Log 2" MD/TVD LWD Combo Log 2" MD/TVD Formation Log 5" MD/TVD Formation Log Electronic Data Set, Filename: SCU322C-04.las Electronic File: SCU 322C-04.dbf Electronic File: SCU 322C-04.mdx Electronic File: SCU 322C-04 SCL.DBF. Electronic File: SCU 322C-04 SCL.MDX . Electronic File: SCU-322C-04 tvd.dbf Electronic File: SCU 322C-04 tvd.mdx Electronic File: scu 322c-04.hdr Electronic File: scu 322c-04r.dbf i Electronic File: scu 322c-04r.mdx - Electronic File: AM Report 1-15-2016.pdf Electronic File: AM Report 1-16-2016.pdf Electronic File: AM Report 1-17-2016.pdf Electronic File: AM Report 1-18-2016.pdf Electronic File: AM Report 1-19-2016.pdf Electronic File: AM Report 1-20-2016.pdf Electronic File: AM Report 1-21-2016.pdf Electronic File: AM Report 1-22-2016.pdf Electronic File: AM Report 1-23-2016.pdf Electronic File: AM Report 1-24-2016.pdf Electronic File: AM Report 1-25-2016.pdf Electronic File: AM Report 1-26-2016.pdf Electronic File: AM Report 1-27-2016.pdf Electronic File: AM Report 1-28-2016.pdf AOGCC Page 2 of 5 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/1912017 Permit to Drill 2152170 Well Name/No. SOLDOTNA CK UNIT 322C-04 Operator HILCORP ALASKA LLC API No. 50-133-10104-01-00 MD 11525 TVD 10531 Completion Date 2/27/2016 Completion Status 1GINJ Current Status 1GINJ UIC No ED C 26878 Digital Data 3/8/2016 Electronic File: AM Report 1-29-2016.pdf ED C 26878 Digital Data 3/8/2016 I Electronic File: AM Report 1-30-2016.pdf ED C 26878 Digital Data 3/8/2016 1 Electronic File: AM Report 1-31-2016.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: 2015_ Lithology(1).As ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - Final Well- Report.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 EOW Report.docx ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - 5in Formation . Log MD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - 5in Formation Log TVD.pdf ED C 26878 Digital Data P 3/8/2016 Electronic File: SCU 322C-04 - Drilling Dynamics - Log MD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - Drilling Dynamics p f Log TVD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - Formation Log - P MD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - Formation Log- TVD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - Gas Ratio Log - MD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - Gas Ratio Log TVD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - LWD Combo Log P MD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - LWD Combo Log TVD.pdf ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - 5in Formation . Log MD.tiff ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - 5in Formation Log TVD.tiff ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - Drilling Dynamics , Log MD.tiff ED C 26878 Digital Data 3/8/2016 Electronic File: SCU 322C-04 - Drilling Dynamics Log TVD.tiff AOGCC Page 3 of 5 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2152170 Well Name/No. SOLDOTNA CK UNIT 322C-04 Operator HILCORP ALASKA LLC MD 11525 TVD 10531 ED C 26878 Digital Data ED C 26878 Digital Data ED C 26878 Digital Data ED C 26878 Digital Data ED C 26878 Digital Data ED C 26878 Digital Data Well Cores/Samples Information: Name Cuttings INFORMATION RECEIVED Completion Report rr Production Test Information Y //fVA) Geologic Markers/Tops 0) COMPLIANCE HISTORY Completion Date: 2/27/2016 Release Date: 12/21/2015 Description Comments: Completion Date 2/27/2016 Interval Start Stop 7394 11525 API No. 50-133-10104-01-00 Completion Status 1GINJ Current Status 1GINJ UIC No 3/8/2016 Electronic File: SCU 322C-04 - Formation Log MD.tiff 3/8/2016 Electronic File: SCU 322C-04 - Formation Log ' TVD.tiff 3/8/2016 Electronic File: SCU 322C-04 - Gas Ratio Log MD.tiff 3/8/2016 Electronic File: SCU 322C-04 - Gas Ratio Log TVD.tiff 3/8/2016 Electronic File: SCU 322C-04 - LWD Combo Log , MD.tiff 3/8/2016 Electronic File: SCU 322C-04 - LWD Combo Log TVD.tiff Directional / Inclination Data Mechanical Integrity Test Information Yv/ 1�A Daily Operations Summary rYi Date Comments Sent Received 3/30/2016 Sample Set Number Comments 1580 Mud Logs, Image Files, Digital Dato NA Composite Logs, Image, Data Files Cuttings Samples DY NA Core Chips Y NA Core Photographs Y/ A Laboratory Analyses Y/ A AOGCC Page 4 of 5 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2152170 Well Name/No. SOLDOTNA CK UNIT 322C-04 MD 11525 TVD 10531 Completion Date 2/27/2016 Compliance Reviewed By: Operator HILCORP ALASKA LLC API No. 50-133-10104-01-00 Completion Status 1GINJ Current Status 1GINJ UIC No Date: v _ AOGCC Page 5 45 Thursday, January 19, 2017 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND,,L , .: , 1 a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 20AAC 25.105 20AAC 25.11v GINJ Q WINJ ❑ WAG[–] WDSPL ❑ No. of Completions: 1 1 b. Well Class: Development ❑ Exploratory ❑ Service Q • Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband 2/27/2016 14. Permit to Drill Number/ Sundry: • 215-217 / 316-047 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: January 18, 2016 ' 15. API Number: 50-133-10104-01-00 ' 4a. Location of Well (Governmental Section): Surface: 823' FSL, 780' FWL, Sec 4, T7N, R9W, SM, AK • Top of Productive Interval: (Top Injection Pert) 2345' FNL, 1877' FWL, Sec 4, T7N, R9W, SM, AK Total Depth: 2150' FNL, 1939' FWL, Sec 4, T7N, R9W, SM, AK 8. Date TD Reached: January 27, 2016 • 16. Well Name and Number: SCU 322C-04 ' 9. Ref Elevations: KB: 163' GL: 145' BF: 143' 17. Field / Pool(s): Swanson River Field / Hemlock Oil Pool 10. Plug Back Depth MD/TVD: . 11,438' MD / 10,471' TVD 18. Property Designation: A028997 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 343081 y- 2456758 ' Zone- 4 TPI: x- 344199 y- 2458861 Zone- 4 Total Depth: x- 344264 y- 2459056 Zone- 4 11. Total Depth MD/TVD: 11,525' MD / 10,531' TVD 19. Land Use Permit: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 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) I 21. Re-drill/Lateral Top Window MD/TVD: . 7,394' MD / 7,392' TVD . 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 2"/5" ROP-DGR-EWR-ALD-CTN MD, 2"/5" DGR-EWR-ALD-CTN TVD, 2" FORMATION LOG MD, 2" FORMATION LOG TVD, 5" FORMATION LOG MD 5" FORMATION LOG MD, 2" DRILLING DYNAMICS MD, 2" DRILLING DYNAMICS TVD, 2" GAS RATIO MD, 2" GAS RATIO TVD, 2" LWD COMBO MD 2" LWD COMBO TVD, FINAL WELL REPORT 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT. TOP BOTTOM TOP BOTTOM PULLED 4-1/2" 12.6# L-80 7,198' 11,524' 7,196' 10,530' 6" L - 64.4 bbls / T - 30 bbls 6 bbls 24. Open to production or injection? Yes Q . No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): 1. 11,225'- 11,265' MD / 10,329'- 10,355' TVD COMPLETION2. 11,281'- 11,310' MD / 10,365'- 10,385' TVD 3. 11,328'- 11,345' MD / 10,397'- 10,408' TVD C)ATF. 2 6 SPF, 3-3/8" __.Z_i �Jlo VFRIFIEI_ i 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 3-1/2" / 2-7/8" / 2-3/8" 11,081' MD 11,075' MD 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: Hours Tested: Production for Test Period —00. Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas Oil Ratio: Flow Tubing Press. Casing Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Form 10-407 Revised 11/2015 CONTINUED ON PAGE Submit ORIGINIAL onl RBDMS 0- MAR 0 9 2016 . o" 28. CORE DATA Conventional Core(s): Yes ❑ No Q . Sidewall Cores: Yes ❑ No 0 . 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 N/A N/A Permafrost - Base N/A N/A Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 11,225' 10,329' information, including reports, per 20 AAC 25.071. Tyonek G 11,062' 10,220' Tyonek G2 11,088' 10,237' SR H1 11,231' 10,333' SR H2 11,275' 10,362' SR H3 11,330' 10,399' SR H3L 11,368' 10,424' ST H4 11,452' 10,480' Formation at total depth: Hemlock 31. List of Attachments: Wellbore Schematic, Drilling and Completion Composite Reports, Days vs Depth, MW vs Depth Curve, Definitive Directional Surveys, 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: Monty Myers Email: mm erS hllCof .com Printed Name: Monty Myers Title: Drilling Engineer Signature: '� Phone: 777-8431 Date: —5,8. 6 INSTRUCTIONS General: This form and the required atta hr» 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 Hilcoru Alaska, LLC 20" 30' GL: 145' AMSL KB -18' 13-3/8" 3,005' CBLTOC 5,720' 7" DV Collar 7,509' RA Tag 10,910' ' SCHEMATIC CASIN(; r)FTAII Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20" Conductor - - Surf. 30' Btm Yes Surf. 13-%" Surface 54.5 J-55 I 8RD Surf. 1,500' 17-W' 3,005' 1,100 sx Surf. DV Collar 1,500' 1,503' 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,290' Calc 7" 29 26 Production 23 26 29 N-80 BTC Surf. 303' 9-%" 11,040' 650 sx 5,720' CBL 7" 303' 1,296' 7" 1,296' 4,793' 7" 4,793' 6,306' 7" 6,306' 7,509' DV Collar 2.688" 7,509' 7,511' 4-1/2" Liner 12.6 L-80 DWC/C 7,198' 11,524' 11 525' 309 sx Vo u9me TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd ELIE 2.992" Surf 331' 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" 331' 7,150' 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,150' 11,081' RA Tag z. -a 11,058' H-1 RA Tag '� 11,202' g H-2 RA Tag a H-3 11,361' 4-1/2 TD = 11,525' MD / 10,531' TVD PBTD =11,438' MD / 10,471' TVD Max Deviation = 49° @ 11,247' JEWELRY DETAIL NO. Depth ID OD Item 1 19.29' 2.900" 7.000" 3-1/2" Tubing Hanger 2 320' 2.813" 4.5" 3-1/2" X- Landing Nipple (injection valve) 3 330' 2.441" - 3-1/2" x 2-7/8" Crossover 4 7,150' 1.995" 2-7/8" x 2-3/8" Crossover 5 7,198' 7" X 4-1/2" ZXP liner hanger 6 11,074'-11,081' 1.995" 2.688" Anchor Latch Seal Assembly - 6.17' Stung into Packer/SBE 7 11,075' 2.688" 4.500" 4-1/2" x 2-3/8" Model D Perm Packer 8 11,077' 2.688" Seal Bore Extension 9 11,090' 1.875" 3.080" X - Landing Nipple 10 11,099' 1.995" 3.100" WL Entry Guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-1 11,225' 11,265' 10,329' 10,355' 3-3/8" 6spf 60 deg H-2 11,281' 11,310' 10,365' 10,385' 3-3/8" 6spf 60 deg H-3 11,328' 1 11,345' 10,397' 10,408' 3-3/8" 6spf 60 deg Updated by DMA 03-03-16 Hilcorp Energy Company Composite Report Well Name: SRF SCU 322C-04 (SCU 314-04 ST) Field: Swanson River County/State: , AK i (LAT/LONG): evation (RKB): API #: 50-133-10104-01 Spud Date: Job Name: 1512837P SCU 322C-04 (SCU 314-04 ST) PreDrill Contractor AFE #: 1512837P AFE $: Activity Date Ops Summary 12/17/2015 Slickline job.,Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. Pressure test lubricator to 250 psi low and 2,500 psi high. MU 2-3/8" chemical cutter.,RIH w/ 2-3/8" chemical cutter and tie into schematic. Make a correlation pass and figure out what depth the jewelry is. Figured if we make cut at 10,124' (per Baker instruction) that it would be in the Baker packer mandrel where it susposed to be cut. Spotted shot and severed mandrel in packer at 10,124'. Ran an after cut log and showed a good cut.,Tools hung up around 10,100' but worked them free without much trouble. POOH. Cutter looked good.Well on a slight blow. Sent before and after cut logs to town., Rig down lubricator and turn well back over to field. 1/11/2016 Hilcorp Swanson Orientation and bear training with all daylight personnel.,Work on rig acceptance checklist. Troubleshoot Iron Roughneck. Repair #2 shaker. PT surface lines to lower IBOP (1,600 psi / test good). Set popoffs to 4K. Finish installing ground rods throughout rig and camp. Continue work on steam lines, test rig ESD's. Continue hauling water to rig and pits. Continue Pason upgrade.,R/U to kill well. Fill gas buster. 0 psi or flow when opening up well. Bring pumps on @ 2.6 BPM w/ no pressure. Pumped away 127 bbis before seeing significant pressure increase and returns. Circulated hole volume with minimum losses @ 4 BPM / 474 psi. 5-10 total bbis oil w/ slight gas back to surface, skimmed and hauled 45 bbls off for disposal. Lost a total of 198 bbis to well for entire circulation., install BPV (NOS -James Craycroft). Nipple down production tree. Install blanking sub over BPV in hanger. Modify cellar grating to accommodate 11" 5M flange diameter w/ DSA. Install 2' spool and set stack. Tighten flanges and begin hooking up flowlines and Koomey lines. 1/12/2016 Continue to nipple up BOPS. MU choke and kill line flanges. RU accumulator lines to BOP stack and function test. Get stack measurements. Start to RU equip for BOP test. Pason hand got most all of the new updated equip installed., Finish RU to test BOPS. Perform pre-test to ensure everything would test for BLM in morning. Test w/ 3-1/2". Test annular to 250 psi for 10 min and 2,500 psi for 10 min. Test all other BOP equip 250 psi for 10 min and 3500 psi for 10 min. Change out testjt to 4-1/2" and do same tests on annular and upper rams. Built containment for mud products trailers on 22-4 Pad.,RD 4-1/2" test equip and rig back up to test with 3-1/2".,Cumulative losses to well 198 bbls. 1/13/2016 Continue w/ housekeeping pad and storage pad organization and snow removal.,Start #1 BOPE test and wait on BLM inspector (no show). Contact BLM and inquire about witness. BLM Amanda Eagle waived witness on 1-13-16 at 9:58 AM. Inform AOGCC of BLM witness waived.,Continue testing BOPE while waiting on AOGCC response. Mr. Regg w/ AGOCC confirmed there decision of waive of witness of BOPE test at 12:46., Continued testing BOPE as per regulations on 3- 1/2" and 4" test jts 250/3,500 psi 10/10 combining pre-BOPE test charts and retest of gas detection system.,RD test equipment and blow down lines and equipment.,Muster both new crews at office for Swanson River orientation and wildlife refresher., Hold PJSM and breakdown test jt. Sand Iocation.,RU line from valve to choke manifold. Pull BPV. MU landing jt and RU to circ down tbg.,Circ at 2.5 BPM and 180 psi. Hole took 20 bbls to fill. Got back about 1 bbl oil and it 4; cleaned up. Circ 75 bbis and shut down.,Shut in and blow down line. Back out LDS. Open valve. Pull 120K to unseat hanger and 145K to pull packer free. Attempt to slack off but pkr wouldn't go down. PU until hanger was above the table w/ a constant up wt of 88K. Up wt when packer was landed was 80K so it is dragging 8K.,Close annular and circ taking returns through choke and poorboy degasser. Circulating at 2.5 BPM at 165 psi. RU Weatherford equip while circ. Shut down and establish loss rate at 4.5 BPH.,Have PJSM. Lay down landing jt and hanger. Blow down all TD and choke manifold., Started to lay down tbg and it started flowing back. RU and circ tbg vol.,Blow down TD and POOH laying down 3-1/2" tbg.,Daily losses to well 20 bbls. Total losses to well 218 bbls. 1/14/2016 Continue POOH laying down 3-1/2" gas lift completion f/ 9,300' t/ 5,000' w/ pipe in good shape.,Service rig, grease traveling equipment, check brakes and change filters in HPU while monitoring well w/ 1 BPH static loss rate.,Continue POOH laying down 3-1/2" gas lift completion pipe still good shape both OD & ID and 10 bbls over cal fiil.,Continue POOH laying down 3-1/2" gas lift completion w/ complete recovery. Last GLM was open. Pipe still in good shape both OD & ID . Hole took 14.7 bbls over cal fill for complete trip and no NORM detected above background.,RD Weatherford. Clear and clean rig floor. Load out all completion tools and clear location for E -line equip. Install 6-7/16" wear bushing. Static loss during this time was .9 BPH.,Hold PJSM and RU Pollard E -line. Flange on end of 7" lubricator was 12-1/4" so we had to make up a 3-1/2" tbg lubricator to set below upper rams. Run #1, run 6" GR to 10,175'. Didn't tag anything. POOH. MU running tool for CIBP. Run #2, RIH w/ 7" CIBP.,Daily losses to well 15 bbls. Total losses to well 233 bbls. 1/15/2016 Continue RIH w/ E -line run #2 w/ 7" CIBP and pull tie in pass f/ 10,175' t/ 9,800' and set top of CIBP @ 10,157' (mid jt). Good indication of set and weight loss of 60# wait 5 min and log off (ok). RIH and set back down and confirm set @ 10,157' WLM RKB.,POOH loss rate fell to zero inspect running tool (ok).,Pressure test 7" csg & CIBP @ 10,157't/ 1,700 psi w/ 102 gals on chart for 30 min w/ no loss (good test) bleed off w/ 102 gals back.,E-line run #3 and #4 w/ 5" dump bailer w/ total 55 gals of NEO Super Slurry System 17ppg class "H" gray lid expanding cmt system for total cal footage of 35'.,E -line RIH #5 w/ 6" GR tie into CCL log of CIBP set and tag. TOC started taking weight on green cmt @ 10,116' w/ full set down @ 10,128' WLM RKB. POOH.,E-line RIH #6 w/ 7" CIBP and pull tie in pass log on depth and set top of CIBP @ 7,413'( 5' above collar of 44' jt ). Good indication of set and weight loss of 55# wait 5 min and log off (ok). RIH and set back down and confirm set @ 7,413' WLM RKB. POOH RD E-Iine.,RU and test 7" csg to CIBP at 7,413' to 3,500 psi for 30 min on a chart. Took 153 gal to pressure up and bled back 151 gal. Good test with no bleed off. RD and blow down test equip. Started shimming the TD while testing.,Note: 48 hr notice given of pressure test of csg witness waived by BLM Petroleum Engineer Mutasim Elganzoory and 24 hr notice given of cmt operations and tag of P&A cmt plug witness waived by AOGCC Jim Regg.,Finish shimming. TD while moving E -line equip and bringing tubulars on location. Get ODs, IDs, and lengths of BHA.,MU BHA and get first 2 jts of HWDP picked up.,Jack and level derrick. Check torque on TD, iron roughneck, and tongs.,Continue RIH. PU HWDP and DP. Had to steam out HWDP due to ice in tube and it wouldn't drift. Continue RIH PU DP. Putting 20 jts at a time on pipe racks and strapping them.,Daily losses to well 2 bbls. Total losses to well 235 bbls. 1/16/2016 RIH with whipstock mills. PU 4-1/2" DP to 7,413' and tag CIBP.,Check crown saver and rig smart. POOH standing back DP to 3,020'.,Service rig. Change out a couple hyd fittings on the TD. Set drilling torque at 14K. Strap DP.,RIH PU 4-1/2" DP to CIBP at 7,413'.,Circ bottoms up. Running #1 mud pump to make sure everything was working good, then swapping to #2 to check it out, #2 pump not pressuring up. Swap back to #1 and finish circ. Work on #2 pump and get it running good. Attempted to POOH but it was flowing back. MU TD circ and mix salt pill.,Daily losses to well 0 bbis. Total losses to well 235 bbis. Finished mixing all our 6% KCL PHPA 9.8 ppg mud. 7/2016 Continue circ build and pump dry job.,( ,i f/ 7,413' w/ cal displacement.,Service rig and open TG' act box chk contacts., PU and move up BHA #2 BOT one trip whipstock window milling assy w/ gyro data UBHO sub and scribe same (verify scribe, bolt and sheer screws).,RIH slow w/ BHA #2 (one trip whip stock and window milling assy) filling pipe every 30 stds.,Tag CIBP at 7,413'w/ 5K. Lay down 1 sng and PU a 15' pup. Set pipe in slips 1-1/2' off of CIBP. Hold PJSM w/ e - line and gyro hands.,RU a -line and warm up gyro tools. RIH w/ gyro taking check shots every 1,000'. Latch into UBO sub and make 3 check shots, 213.30°, 210.72°, 210.74°. Turned pipe to the right 1/2 turn and took another check shot of 38.54°. Bumped the pipe back to the left and worked the pipe . Took another shot 24.71' and 24.58°. Took 2 more shots to check and they were 24.62° and 24.21'.,Set down 5K and took one last check shot of 24.28°.,POOH w/ gyro. leaving wireline rigged up we picked up a 10' pup. Up wt 39K down wt 39K. Set down and shear bottom trip anchor at 125K. PU to 150K to ensure set. Set back down to 110K and shear bolt. PU and we lost 5K and whipstock was set.,RD wireline and get equip off pad. Stage vac trucks and dragon tank in prep for displacing. LD pups and PU stand.,Displace produced water with 9.8 ppg 6 % KCL polymer, taking produced water returns to skim pit. Pumped at 6.5 BPM and a final press of 1,219 psi.,Mill window f/ 7,394' t/7,402'. Pumping 6.5 BPM, 1,221 psi, 80 RPM, 6 to 8K torque, 1 to 2 WOB. Avg �CP 2 FPH. Recovered 75 lbs metal.,Daily losses to well 0 bbis. Total losses to well 235 bbls. This is the last report on the predrill portion AFE. ,n—n . kk 1.12 %VV �'jI Z✓V- Hilcorp Energy Company Composite Report Well Name: SRF SCU 322C-04 (SCU 314-04 ST) Field: Swanson River County/State: , AK i (LAT/LONG): evation (RKB): 18 API #: Spud Date: 1/18/2016 Job Name: 1512837D SCU 322C-04 (SCU 314-04 ST) Drilling Contractor AFE #: 1512837D AFE $: Activity Date Ops Summary 1/18/2016 Continue mill window f/ 7402't/ 7404' while back reaming pipe torqued up and hung pipe 2' off btm work torque out. Work pipe 50k over & 201k under w/ no movement slump pipe twice and free same.;Pump 20 bbl high vis sweep and circ around w/ no increase 2 @ 450 gpm @ 2300 psi.;Continue milling window and formation f/ 7404't/ 7427'@ 252 GPM @ 1236 psi w/ 5k WOB @ 80 rpm w/ 6k TQ.;pipe torqued up and hung pipe on btm @ 7408' twice able to pull free @ +- 60k over. Recovered total of 170 lbs good metal shavings.;Work mills thru window with and without rotation and pump (good smooth< 2k ) had good indication of cmt and formation appears to be silt stone, sand stone & tuffs TOW = 7394' BOW = 7407' TD= 7427';Circ btm up chk for even mud @ 9.8 ppg and flow chk (ok).;Shut in and Preform F.I.T w/ 9.8 ppg MW and applied pressure of 1050 psi w/ 35 gal @ TVD 7392' w/ no bleed off for 10 min = EMW of 12.53 ppo.;R/dn test equipment chk flow (ok) Pooh to chk mill OD. Upper mill was worn on bottom but was still in gauge.;Clear floor of tools. Pull wear ring. Flush stack. RU test jt and test equip. Purge system & perform shell test to 3500 psi. Total Safety calibrated and tested all gas alarms per Guy Cook w/ AOGCC.;Test BOPS Test equip to 250 low and 3500 psi high holding each test for 10 min each. Test hydril to 250 low and 2500 psi high. We are about 80% done testing at report time.;Total downhole losses=235 bbis Total class II fluid hauled to G&1=90 bbis (rs Total cuttings hauled to G&1=0 bbls 1/19/2016 Cont testing BOPE, tested annular, inside choke, and TIW. Test plug leaked. Re -set test plug and re -tested ok at 250 low, 2500 high. Performed koomey draw- down test, tested blinds, CMV's;7-10-12-inside kill, auto choke, manual choke, and lower pipe rams. PVT's and flow show alarms. Testing witnessed by AOGCC Rep Guy Cook.;Pulled test plug, installed 6 7/16" wear ring, blew down choke manifold. RD test equipment, LD test jnt, staged BHA for PU.;Held PJSM with rig crew, Halliburton and Gyro Data Reps. MU Varel V613 jetted w/6x10's, motor bend 1.5 deg, MU DM collar, Slim Phase collar, ALD collar, CTN collar, PWD and TM collars.;MU UBHO sub and oriented same (RFO = 95.05 deg). Downloaded MWD, shallow pulse tested (OK), held PJSM and loaded RA sources. PU flex DC and installed corrosion ring, cont TIH with HWDP;and jars to 976'. CONT TIH on 4 1/2" DP from 976' to 2000'.;Cont TIH with directional BHA (#3) to 7373'. Filling pipe every 2500' on the way in the hole.;Circ bottoms up. Hold PJSM with E -line and Gyro hands while circulating.; Blow do TD. PU 15' pup. RU wireline sheaves. MU T pup, XO, wire line entry sub, and XO. PU about 30' and pull gyro tools up to floor with wireline. Lower tools into DP.;Lower subs and MU on DP. RIH with Gyro to UBHO sub taking check shots every 1000'.;Latch into UBHO sub 3 times taking check shots. 233, 233, & 234 degrees. MU TD and start pump. Tighten wire line packoff and clamp line. Orientate pipe at 28 degrees.;Set pup in slips and MU std. Slide do to 7410'and put Gyro computer in steering mode. Start sliding do slow reaming out of gage hole at 7411'. Gyro computer kept locking up when we turned the pumps on;Tried several times to get gyro's equip running in steering mode but it would only run 1 min and there computer would lock up. They changed computers, power sources, and several other settings but;seemed to help. we did get reamed down through the under gauge hole f/ 7411' t/ 7418' in the short times the tools were working.;Called town and decided to attempt to drill in compass or sng shot mode. Ream 2' and shut down pumps to get sng shot. Reamed in this mode f/ 7418't/ 7425' in this mode.;Sng shots have been showing 55 degrees w/ pumps off.;Total downhole losses=235 bbls Total class II fluid hauled to G&1=90 bbls Total cuttings hauled to G&1=0 bbls 1/20/2016 Cont reaming under gauge hole slowly, from 7425' to 7427' (previous TD with window milling assembly) at 161 gpm, 1-2K wob, taking gyro check shots every 2'. At 7427' increased to 250 gpm-2022 psi,;2 to 13K wob, taking gyro check shots every 5', drilled to 7447' (MWD tool switched to gravity tool face at 7441' showing 3.17° Inc).;HSE Rep John Coston stopped by and did a walk through of the rig. Found one eye wash station was low on water. That was the only issue.;Pulled up hole one stand and racked back same, cont pull up hole making soft breaks on side entry sub assembly. Broke off assembly and pulled gyro tool to surface. LD gyro tool and side entry sub;assembly. TIH one stand, MU second stand. At 7441' MWD tool switched to gravity tool face with a 3.17 deg Inc;Resumed directional drilling 6" hole from 7447' to 7493'. Rotating wob 2K, 253 gpm-1789 psi, 20 rpm -4900 ft/lbs on bott torque, ROP 6 to 30 ft/hr. At 7471' we had an Inc of 3.84 deg. Released; Pollard a -line crew and Gyro Data Reps. Sliding wob 13K, 253 gpm-2068 psi, 300 psi diff, 6 to 15 ft/hr ROP sliding. MW 9.8ppg/vis 45, ECD's at 11.2ppg, BGG 14 units.;Drilling 6" hole f/ 7493't/ 7543. 252 GPM, 2150 Psi, 250 to 350 Diff., 60 RPM, 6324 Tq, 15 to 24 WOB. High for gas179 units. Avg ROP 11 FPH. Up wt 138, Dn Wt 133, Rt wt 136.;Slide drill f/ 7543 t/ 7558'. 252 GPM. 2243 Psi. 220 Diff. 25k WOB. High for gas 100 units. Avg ROP 7.5 FPH. Off bottom pressure 1870 psi.;Drilling 6" hole f/ 7558'V 7565'. 252 GPM. 2130 Psi. 265 Diff. We had a increase in ROP and worked the pipe assuming it was a coal.;Had a abrupt increase inflow from 25% to 33% and a jump f/ 100 units to 1186 units. Driller picked up and shut the well in. We monitored pressure on the choke and it remained at 0 psi.;DP pressure red 110 psi but it was trapped pressure. We opened up the choke and circ bottoms up through the gas buster w/ a max of 827 units and no pit increase. 80% coal cuttings to surface.;When the gas came down and leveled off at 500 units we shut do and checked the flow at the gas buster. No flow. Opened the Annular and well was static. Decided to wt up 1 tenth to 9.9 ppg;Went back to drilling while dusting the wt up. We did have another gas spike of 1346 units when we went back to drilling but no flow or pit gain increase. Drill f/ 7565't/ 7607'w/ a avg of 160 units;Slide drill f/ 7607 t/ 7621. WOB 15, GPM 252, 2100 psi, Diff 240 psi. Sent AOGCC and BLM a notice of BOP closure.;Total downhole losses=235 bbls Class II fluid hauled to G&1=90 bbls, Total= 180 bbls Cuttings hauled to G&1=0 bbls. Total =0 bbls;Distance to plan = 8.53' We are 8.44' high & 1.23' Right of plan. 1/21/2016 Cont directional drilling 6" hole from 76. .o 7859'. Rotating wob 7 to 20K, 23 gpm-1957 psi, 60 rpm .0 ft/lbs on bott torque, 10 to 50 ft/hr ROP. Sliding wob 21K, 252 gpm-2265 psi, 212 psi diff,;10 ft/hr ROP. MW 9.9ppg/vis 44, ECD's at 11.3 ppg, BGG 112 units, conn gas +/-300 units, with an occasional 500 unit spike after drilling through coals.;Cont directional drilling 6° hole f/ 7859't/ 7870'.;Circ bottoms up with one gas spike of 300+ units. avg background gas 160 units. Shut do pump and check flow. Well flowing at 3.9 BPH.;MU TD and circ while weighting up a couple tenths. Bring wt up from 9.95 to 10.2 ppg. Had a gas spike of 832 units on bottoms up. 10.2 ppg all the way around w/ background gas at 85 units.;Shut down and check flow. Well still flowing 2.1 BPH. Circ bottoms up and start wt up to 10.4. Had a high of 990 units of gas on bottoms w/ no increase in chlorides. Finish wt up.;Shut down and check flow. Well static. LD on sng and POH to just under the bottom of the window at 7425'. Pulled 10k to 15k over at 7645', 7605', 7546', & 7471'.;MU TD and orientate tool. Shut do and check flow. Well still static. Pump pill, Pull up through window with no drag. Bottom of window at 7407' and top at 7394'. Blow down TD.;POH f/ 73760 500'. Hole took 1.1 bbls over calculated vol for trip out so far.;Class II fluid hauled to G&1=73 bbls, Total=253 bbls Cuttings hauled to G&1=17 bbls. Total =17 bbls;Distance to plan = 21.09' We are 12.96' high & 16.63' Right of plan. 1/22/2016 Cont POOH from 1500' to 112', flush smart tools with water, PJSM, removed RA sources and upload MWD. LD smart iron assembly, flush and drain motor. Bit in good condition but 3 plugged jets. Graded bit; 1-1 -PN-N-X-I-ER-PR. Hole took a total of 3.7 bbls over calculated for entire trip off bottom. Well static during flow check at HWDP and once out of hole.;PU 4 1/2" test joint, remove wear ring, set test plug, RU test equipment and purge air. Tested annular at 250/2500 psi for 10 minutes each, tested auto choke at 1500 psi for 5 minutes. Good tests.;(tested due to previous BOP closure) About the time we set test plug well started to flow out the annulus valve. Slowly increased and stabilized at 1 bph. RD test equipment, set wear ring.;MU directional BHA as follows: 6" HDBS MM55 PDC, jetted with 5x1 Vs, Sperry motor with 1.5 deg bend, float sub, DM collar, new Slim Phase 4 collar, ALD collar, CTN collar, PWD and TM collar.;Made numerous to upload Slim Phase 4 collar but could not read the tool (changed due to battery life of 15.8 amp hours). Decision made to re -run previous tool due to well flowing 1 bph.;LD SP tool, PU previous tool and MU same. No issues uploading MWD. Shallow pulse test (ok), PJSM and load RA sources. RFO = 353.29 degrees.;Cont TIH with NM flex DC, HWDP and jars to 976'.;RIH to 2534'.;Fill pipe and circ bottoms up w/ a high of 55 units of gas.;RIH to 5109'.;Fill pipe and circ bottoms up w/ a high of 1346 units of gas. Gas fell right back do to 78 units. Mud was gas cut f/ 10.4 t/ 9.7 ppg but there was no water influx.;RIH to just above window at 7375'. Hole has given us 12.6 extra bbls of mud up to this point.;Fill pipe and circ bottoms up w/ a high of 2604 units of gas. Got a shot of watered back mud where the chlorides had dropped do 10,000, and mud wt was cut to 9.7 ppg.;Circ until mud wts evened out at 10.4 ppg.;Orientate and set tool at 27 degrees. Went through window and didn't see anything. Continue to RIH and sat down 15k at 7629'. Attempted to work through but wouldn't go.;Wash and ream f/ 7620'V 7649'. Tag another tight spot at 7816'. Wash and ream f/ 7811' U 7825'. RIH and tag fill at 7855'. 15' of fill. Clean out fill to Bottom at 7870'.;Circ bottoms up w/ a high gas of 1422 units. Total water gain to pits from time we left bottom to when got back in and drilling is 26 bbls. (27 hrs from bottom back to bottom]; Directional drill 6" hole V 7870't/ 7995'. 250 GPM, 2045 psi., 205 Diff, 60 RPM, 6500 Tq, avg gas 190 units. Had spikes up to 1400 units while drilling.;Class II fluid hauled to G&I=80 bbls, Total=333 bbls Cuttings hauled to G&1=17 bbls. Total =17 bbls;Distance to plan = 21.09' We are 12.96' high & 16.63' Right of plan. 1/23/2016 Cont directional drilling 6" hole from 7995' to 8467', rotating wob 4K, 250 gpm-2200 psi, 65 rpm -6500 ft/Ibs on bott torque, 80 to 100 ft/hr ROP. Sliding wob 4 to 9K, 250 gpm-2229 psi, 150 to 300 psi;diff. MW 10.4+ppg/vis 41, ECD's at 11.9ppg, BGG 200 units, conn gas +/- 700 to 1300 units. +/- 1 bph gain while drilling. Start dusting MW up from 10.4 to 10.5 ppg while drilling.;SPR's at 8115'= #1 46 stks @ 796 psi, #2 48 stk s@ 783 psi with 10.5 ppg mud. Up wt 158K, dwn wt 140K, rot wt 150K.;Cont directional drilling 6" hole f/ 8467' t/ 8640'. 253 GPM, 2206 psi, 225 Diff, WOB 5 to 10, 60 RPM, 7000 Tq, Back ground gas 170 units w/ 10.5 ppg mud. Connection gas 823 units.;Flow on connections 7 BPH. Dusting mud wt up to 10.6 ppg.;Cont directional drilling 6" hole f/ 8640't/ 8805'. 248 GPM, 2424 psi, 230 Diff, WOB 5, 60 RPM, 7000 Tq, Back ground gas 130 units w/ 10.6 ppg mud. Connection gas 768 units.;At 1:28 we had a 7.1 earth quake that shook everything up good. Did a inspection of rig to make sure nothing got damaged or started leaking. Mud did splash up through the grating on the pits,;but none went over on to the mats. No other issues found.;Class II fluid hauled to G&1=69 bbls, Total=402 bbls Cuttings hauled to G&1=21 bbls. Total =38 bbls;Distance to plan = 1.99' We are 1.55' low & 1.25' Right of plan. 7.14 rotating, 10.19 sliding 1/24/2016 Cont drilling 6" hole from 8805' to 8862'. Rotating wob 3K, 250 gpm-2460 psi, 60 rpm -6500 ft/lbs on bott torque, MW 10.6 ppg/vis 42, BGG 112 units. Obtain survey and CBU 1 X.;Pull up hole from 8862' to 7497'. Flow check shows 4.8 bph after first 5 stands. Pulled with no issues at all. Calculated hole fill = 8.6 bbls, actual hole fill = 2.84 bbls, hole took 5.22 bbls under.;MU topdrive and CBU 1 X to clear well bore of any gas. 249 gpm-2054 psi. Had 931 units max gas at bottoms up. With gas back down to 120 units pumped a 15 bbl 12.5 ppg hi -vis pill and spotted;7 bbls outside bit, left 8 bbls in pipe.;Cont to pull up hole from 7497' to 7375', getting BHA inside casing. No issues pulling BHA through window. Held BOP drill. Put well on trip tank and blew down topdrive/mudlines. 3.5 bph flow.;RU, cut and slipped 90' drill line and serviced rig. Found a broken turnbuckle on torque tube. Checked crown saver.;TIH with no issue exiting window. Tagged up and washed/reamed 7495' to 7505', 7596' to 7617', 8513' to 8554', 8760' to 8862' (bottom). Mostly transitions from sand to claystone or coal .;CBU to remove gas and water from wellbore. Circ at 250 gpm-2100 psi, 60 rpm -8000 ft/lbs off bott torque. Had a max of 1377 units at bottoms up. Dumped a total of 47 bbls weighing 9.3 ppg.;Orient toolface and resume drilling 6" hole from 8862' to 8879', sliding wob 15K, 253 gpm-2238 psi, 155 psi diff, 40 ft/hr ROP.;Cont drilling 6" hole from 8879' to 8949' where we finished our build and turn. 12k wob, 252 gpm, 2190 psi, 31% flow, 50 rpm, 6.4k tq on, 5.9k tq off, 150 avg units bgg.;Continue drilling 6" hole in tangent section F/ 8949'- T/ 9362'. Maintenance slides as needed to adhere to WP 04. 8-11 k wob, increased RPM due to stick slip (helped) 80 rpm, 8.3k tq on, 253 gpm;2290 spp, 31 % flow, 140 avg bgg, 550-700 avg connection gas, 12.22 ECD's. 7-10 BPH static flow rate between connections w/ 1/2 to 1 BPH water flow while drilling ahead.;Hauled 20 bbls cuttings to KGF G&I for total = 58 bbls Hauled 160 bbls class II junk fluid to KGF G&I for total = 562 bbls Hauled 0 bbls cement to KGF G&I for total = 0 bbls;last svy showed .33' low / 2.57' left = 2.59' distance to plan 1/25/2016 Cont drilling 6" hole from 9362' to 9854'. Rotating wob 5 to 10K, 249 gpm-2569 psi, 40 to 80 rpm -8900 ft/lbs on bott torque, MW 10.6ppg/vis 47, ECD's 12.4 ppg, BGG +/- 112 units,;connection gas +/- 900 units. Driller reduces pump rate on down stroke while working pipe, to keep ECD's down. From 9714' to 9717' had very slow drilling, 1 to 3 ft/hr. Samples were loose sand grains.;Obtain survey at 9854', obtained SPR's and pumped 15 bbl hi -vis sweep at 249 gpm-2457 psi, rotating 45 rpm -6900 ft/lbs off bott torque. 20% increase in cuttings 8 bbls Iate.;Pulled up hole clean from 9854' on elevators to 8750', up wt 190K, dwn wt 140K. LD one single to alternate breaks during trip. Flowcheck after first 5 stds w/ 8.6 BPH flowrate. 16 bbl gain for trip;Rig service. Changed out lower air boot on riser during rig service. Also changed mechanical seal on pump 2 charge pump during trip.;Trip in hole with no issues F/ 8750'- T/ 9854' MD. No fill. Fill pipe. 8 bbl gain for trip in.;Work pipe and pump to unplug string. Took several times but able to establish circulation w/ no issue. CBU w/ 1410 max gas. Dumped 39 bbls watered back mud w/ 10 ppg MW due to water influx.;Cont drilling 6" hole from 9854' to 10047'. Rotating wob 5 to 10K, 249 gpm-2460 psi, 80 rpm -8900 ft/lbs on bott torque, MW 10.6ppg/vis 47, ECD's 12.3 ppg, BGG +/- 90 units,;Flow rate between connection 7-10 BPH w/ 1-2 BPH while drilling ahead.;Cont drilling 6" hole from 10047' to 10,394'. Rotating wob 5 to 10K, 246 gpm-2602 psi, 80 rpm -9000 ft/lbs on bott torque, MW 10.6ppg/vis 46, ECD's 12.4 ppg, BGG +/- 119 units,;Getting a 1.5 to 2 bph gain while drilling, well flows at +/- 20 bph on connections. Last survey at 10,313'md, 46.83 deg Inc, 25.31 deg Azi, 9708'tvd puts us 2' high and 2' left of the Iine.;Hauled 29 bbls cuttings to G&I for total = 87 bbls. Hauled 151 bbls class 11 junk fluid to G&I for total = 713 bbls 1/26/2016 Cont drilling 6" hole from 10,394' to 10,. - , rotating wob 10K, 247 gpm-2530 psi, 80 rpm -9000 ft/Ibs oott torque, MW 10.6ppg/vis 46, ECD's at 12.4 ppg, BGG 74 units. Pumped 15 bbl hi -vis sweep;while drilling down last of stand. Received 273 sx lead and 127 sx tail cement.; Circulate sweep around at 217 gpm-1932 psi 50 rpm -9150 ft/lbs off bott torque. Had 20% increase in cuttings to surface. Circ shakers clean. Obtained SPR's and survey.;LD single and pulled up hole from 10,850' to 9824' on elevators with no issues. Up wt 210K. Flow chack after 5 stands = 13 bph. Flow check at 9824'= 13 bph. Trip was 10 bbls under on hole fill.;Service rig and topdrive. Replaced crown saver actuator on drawworks.;TIH on elevators from 9824' to 10,820' with no issues. Down wt 148K.;CBU 30' off bottom at 252 gpm-2285 psi to clear wellbore of gas and water. Had a max of 1418 units at bottoms up. Dumped 103 bbls watered back mud weighing 9.3 to 10.3 ppg.;Cont drilling 6" hole from 10,850' to 11,221'. Rotating wob 10K, 247 gpm-2600 psi, 80 rpm -9800 ft/lbs on bott torque, MW 10.6ppg/vis 46, ECD's at 12.4 ppg,;Hauled 37 bbis cuttings to G&I for total = 124 bbls. Hauled 233 bbls class II junk fluid to G&I for total = 946 bbls;Last survey at 11,060' MD, 46.83 deg Inc, 25.31 deg Azi, 10,218' tvd puts us 4' high and 5' left of the 1/27/2016 Cont drilling 6" hole from 11,221'to TD at 11,525'. Rotating wob 7K, 250 gpm-2796 psi, 80 rpm -11,000 ft/lbs on bott torque, 10 to 80 ft/hr ROP, BGG 154 units. Pumped a hi -vis sweep;just prior to stand drilled to TD. Well flowing at 13 bph on connections. TD'd well in sand with slight tuffaceous claystone and siltstone.;Circ sweep to surface with a 10% increase in cuttings. Circ hole clean. Obtain survey on bottom and SPR's.;Pumped first stand up hole from 11,525' idling pump, no rotation, no issues. 2nd stand we pulled to 270K and did not come loose. MU topdrive, idled pump and rotated to break free.;Pulled second stand with no pump or rotation at 212K up wt. 3rd stand we pulled to 270K and came free. Pulled 2 more stands with no problem. 5 stands out flow checked at 11 bph.;Appears to be some seepage/differential sticking in the Hemlock zone.;Cont pulling wiper trip to inside 7" casing with no issues in open hole or pulling BHA through window at 7394'. Parked string with bit at 7369'. Flow check at 7 bph initially. Crew change.;Flow check at 10 bph. TIH from 7369' to 11,475' with no issue exiting window at 7394'. Filled pipe every 2000'. No hole issues encountered. 30.7 bbls over disp with on trip in.;M/U top drive. Fill pipe. Wash and ream to bottom (11,525') @ 222 GPM/1880 psi, 80 RPM. Had 5' of fill.;CBU + at 222 GPM/1880 psi while rotating and reciprocating. Had sand and coal fines cuttings. Dumped 201 bbls with low weight of 8.8 ppg. 1427 units of gas.;Circulate 20 bbl Hi -vis sweep at 222 GPM/1880 psi while rotating and reciprocating. Had 50% increase in cuttings (pea sized coal, sand and clay). Sweep came back 12 bbls Iate.;Pumped first stand up hole from 11,525' idling pump, no rotation, no issues. 2nd stand had to break free with rotation. Pumped out next three stands without issue.;Flow checked with 10 stands pulled at 10 BPH. POOH to 7370' without issue.;Spot 25 bbl 13.0 ppg pill at shoe.;Hauled 26 bbls cuttings to G&I for total = 150 bbls. Hauled 424 bbls class II junk fluid to G&I for total = 1370 bbls 1/28/2016 Flow check 7 BPH. Blow down top drive after spotting 25 bbl -13 ppg pill just above window (bit at 7370').;Cont POOH racking DP in derrick, from 7370' to 5488'. Flow check now at 1/4 bph. Cont POOH to 4890' LD DP, well flowing 9 bph. Notify Drilling Engineer. Decision made to spot 2nd pill.;Begin building 25 bbl -14 ppg pill. Idle pump at 48 spm -673 psi, 20 rpm -3800 ft/Ibs torque and circ/condition hole. Pump 20 bbls 14 ppg mud and had 1218 units gas which dropped to 80;units at bottoms up. With pill in place gas down to 46 units.;Cont POOH LD excess 4 1/2" DP from 4890' to HWDP at 976'. Peak wiping inside pipe with vac unit and nerf balls. Rack back 9 stands HWDP, LD jars and excess HWDP. PJSM and remove sources.;Upload MWD data, LD Sperry smart iron and motor. Bit graded at 2 -4 -BT -S -X -1 -CT -TD. **Shut well in at 2040 hrs to monitor Psi build.;Rig up to run 4 1/2" 12.6# DWC/C liner. **Casing pressure build to 530 psi in 1 hour.;Casing pressure built to 588 psi. Bleed off to 0 psi with less than 7 bbls returned. Open blind rams. Flowing at 10 BPH.;Make up shoe track. Check floats. RIH picking up 4 1/2" 12.6# DWC/C liner to 1392'. Flow check 12 BPH. Gas at +-550 units.;CBU at 1392'. Max gas of 1720 units. Continue circulating until down to 300 units. 10.6 ppg in/out. Flow check 8.5 BPH.;Continue RIH picking up 4 1/2" liner from 1392' to 2052'. Flow check 8.6 BPH. Gas at +-550 units;CBU at 2052'. Max gas of 1581 units. Continue circulating until down to 900 units. 10.6 ppg in/out. Flow check 10 BPH.;Continue RIH picking up 4 1/2" liner from 2052' to 2838'. Well began flowing at 8%. Gas at +-815 units; Hauled 0 bbls cuttings to G&I for total = 150 bbls. Hauled 150 bbls class II junk fluid to G&I for total = 1520 bbls (Cont to circ 4 1/2" liner at 2838'. 3 bpm 177 psi, gas increased to 1400 units and held there. Increased pump rate to 5 bpm and gas started dropping to 777 units. Built a 25 bbl -14 ppg pill and;spotted same outside liner in hopes of reducing flow. Blew down topdrive, flow at 15 bph.;Cont to PU and single in with 4 1/2" -12.6 # DWC/C liner from 2838' to 4290'. Gas and flow increasing. MU XO and topdrive.; Perform one full circulation at 5 bpm -374 psi, with a max of 1185 units gas at bots up. Dumped 20 bbls of watered back mud. With 10.5 ppg mud to surface and gas down to 680 units, shut down pump.;PU and MU Baker "HRDE" ZXPN Flex Lock liner top packer and hanger assembly. Mix and pour "PAL" mix and allow to set while RD and release Weatherford. Mix 2nd weighted pill in pill pit.;TIH one stand HWDP and MU topdrive. Pump the 25 bbls-14 ppg pill and spot at 4389'. Had a max of 1571 units at bottoms up, gas down to 231 units at shut down. Up wt 53K, dwn wt 53K.;Cont TIH a total of 9 stands HWDP, followed with 4 1/2" DP at 1 minute per stand. Drifted stands in derrick. Filled pipe every 10 stands. Stopped just above 7" casing window with shoe;at 7389'. MU topdrive.;Circulate at 5 bpm -555 psi and a max of 1467 units gas. Circulated until good 10.6 all the way around and gas down to 50 units. Dumped 177 bbls watered back mud.;Obtained rotating parameters at 10-20-30 rpm's. 10 rpm=4000 ft/lbs, 20 rpm=4300 ft/lbs, 30 rpm=4550 ft/lbs torque. Up wt 103K, dwn wt 103K, Rot 105K.;Run in open hole with liner assembly on elevators 7394' to 8090'. Encountered tight spot. Wash down 8090'- 8128' with several set downs of 20K.;Circulate hole clean at 8 BPM/820 psi. At bottoms up had 2" of cuttings (sand, coal) across shakers. Dumped 48 bbls water cut mud.;Continue washing in hole at 2.7 BPM. Encountered tight spots: 8270' -8313, 8513', 8646'- 8683', 8958' and were stuck at 8825' before being able to work free with 50K over pull and slow circulation.;Continue washing in the hole from 8958' to 9043'. Attempt to work through down to 9060' with pump and rotating at 30 RPM/5500 ft/lbs torque.;Hauled 0 bbls cuttings to G&I for total = 150 bbls. Hauled 405 bbls class II junk fluid to G&I for total = 1925 bbls Cont to wash liner down from 9043' to 10,980'. CBU at 9336' due to packoff issues under the liner hanger. 160 gpm-750 psi and worked string 10' strokes. Had 10 20% increase in fine sand and coal at;shakers on bottoms up. Most severe tight spots at 9500', 9528', 9542' and 9738'. Continuously worked string with pump on and off at tight spots. Did no rotation of string.;Washed down with pump at 3 bpm -575, then increased to 5 bpm -900 psi and worked full length of stand once washed down, prior to making connections. At 10,200' hole conditions improved greatly.;Cont washing 4 1/2" liner down from 10,980' to 11,521' without issue.; Circulate and condition mud with 10.6 ppg mud in/out at 4 BPM/850 psi. Reciprocate full stand during circulation.; Pick up cement head and continue circulating while rigging up Schlumberger cementers. Tag bottom at 11,525' and reciprocated string +-20'.;Hold PJSM with all to be involved in cement operation. SLB pump 5 bbls to flush, 10 bbls to fill lines. Test lines at 275 U5500 H.;Rig pump 24.6 bbls 12.0 ppg Mud Push II at 2.5 BPM/540 psi. SLB pump 64.4 bbls 13.0 ppg Class "G" lead cement at 3 BPM/100 psi followed with 30 bbls 15.3 ppg EasyBlok tail cement with full returns.;Baker dropped dart, then SLB displaced with 10.6 ppg 6% KCL mud at 5 BPM/1210 psi ICP. Slowed to 3 BPM with 83 bbls displaced and saw dart latch wiper plug 92 bbls into displacement.;with 10 bbls to go, reduced rate to 2 BPM/1000 psi and bumped plug/landing collar at 157.2 bbts (calculated at 160 bbls). FCP 1000 psi. Increased to and held 1500 psi for 3 minutes.;Bled back .75 bbis to truck. Floats held. CIP at 04:15 on 1-31-16.;Slack off on blocks from 140K to 70 K giving good indication hanger was set. SLB increased to 4500 psi then bled off as per Baker. Pumped a total of 124 bbls with a total of 105.5 bbls returned.;Lost 18.5 bbls during displacement. P/U 5' to clear dogs from hanger top and had good indication of release from liner string. S/O to 60 K to set packer with good indication of shear.;P/U, rotated at 20 RPM 5200 ft/lbs torque. S/O and set down to 80K to insure weight transfer to set packer. Top of liner hanger at 7297', top of landing collar at 11,438'.;Closed annular, pressured up on annulus to 1179 psi and held 5 minutes. Good indication that HRD-E ZXPN liner top packer set. Bled pressure to 0 psi. Open bag. Lay down;SLB hardline and Baker cement head. M/U top drive. Pressure up to 500 psi on drill string and pick up 17'. Once psi dropped began pumping and did one full circulation at 318 gpm/1137psi.;Dumped 62 bbls of cement contaminated mud with cemnet at shakers (had no indication of cement or MudPush), then started taking returns to pits again.;Hauled 0 bbls cuttings to G&I for total = 150 bbls. Hauled 170 bbls class 11 junk fluid to G&I for total = 2095 bbls 1/31/2016 Inserted wiper ball in drill string, MU toF. ,e. Performed 2nd circulation at 352 gpm-1291 psi, then L. down topdrive.;Cut and slip 100' drill line, service rig and topdrive. Adjust drawworks brakes and charge topdrive compensators.; POOH with 4 1/2" DP and Baker HRDE running tool, from 7173'. Iron roughneck broke down but crew able to cont POOH with rig tongs and pipe spinners.;LD run tool, PU Baker cement head and break off XO's and pups, LD same.;Pull wear ring, set test plug. Start lower ram change. Have to remove ram bonnets to allow for door opening enough to change the ram blocks.;Test BOPE. Test equip to 250 low and 3500 psi high holding each test for 10 min each. Test hydril to 250 low and 2500 psi high. Test with 2 3/8", 2 7/8" and 4 1/2" joints.;Test is 90% complete. Witness of test was waived by AOGCC and BLM. Pit cleaning is 90% complete.; Hauled 0 bbls cuttings to G&I for total = 150 bbls. Hauled 320 bbls class II junk fluid to G&I for total = 2415 bbls Hilcorp Energy Company Composite Report Well Name: SRF SCU 322C-04 (SCU 314-04 ST) Field: Swanson River County/State: , AK i (LAT/LONG): evation (RKB): API #: 50-133-10104-01 Spud Date: Job Name: 1512837C SCU 322C-04 (SCU 314-04 ST) Completion Contractor AFE #: 1512837C AFE $ Activity Date Ops Summary 2/1/2016 Cont performing full BOP test at 250 low, 3,500 high. Total test time 11.5 hours with one fail pass (kill HCR). Rack and tally 2-7/8" work string and jewelry.,RD test equipment, set wear ring, blow down surface lines and topdrive.,Finish up rack and tally 2-7/8" workstring, install elevators, stage lift nubbins and slips, C/O rams/dies on iron roughneck for 2-7/8" pipe, PJSM.,MU 3-3/4" bit, scraper for 4-1/2" liner, XO. PU single in hole with 2-7/8" SLH-90 workstring to 3,400' .,Cont PU single in hole remaining 2-7/8" workstring (total 136 joints) to 4,250'.,C/0 handling equipment, swap iron roughneck jaws back for running 4-1/2" pipe, MU XO's and 1st 7" scraper.,RIH with scraper assembly to 7,160'. P/U 91 K, S/0 89K.,CBU at 5 BPM/ 1,910 psi to condition mud. Blow down top drive.,RIH with casing scraper assembly to +- 9,344'. **Did not see TOL at 7,198'. Had bad pin on 3-1/2" IF cross-over to top scraper. Change out same.,CBU at 5 BPM/2,350 psi to condition mud. Blow down top drive.,RIH with casing scraper assembly and tag landing collar at 11,442'. P/U 165 K, S/0 132 K.,Circulate and condition mud while reciprocating pipe at 5 BPM/ 2,850 psi.,Hauled 0 bbis cuttings to G&I for total = 150 bbis. Hauled 320 bbls class II junk fluid to G&I for total = 2,415 bbls. 2/2/2016 Finish circulating and conditioning drilling mud.,Pump 400 vis/ 25 bbl sweep and displace well with fresh water at 5 BPM/2,500 psi.,Test casing at 3,500 psi on chart for 30 minutes. RID test equipment.,Short trip 11,440' to 7,882' to wipe 4-1/2" and 7" casing.,Circulate well with fresh water. Pump chemical train and displace well with 6% KCL at 5 BPM/2,300 psi while reciprocating pipe. P/U 170, S/0 140.,Pump slug with corrosion inhibitor and add same to trip tank.,P00H laying down 4-1/2" drill pipe to 8,729'.,Service rig.,Continue POOH laying down 4-1/2" drill pipe and 2-7/8" work string from 8,729' to 4,596'., Hauled 0 bbis cuttings to G&I for total = 150 bbls. Hauled 750 bbis class II junk fluid to G&I for total = 3,350 bbis. 2/3/2016 POOH laying down 2-7/8" work string 4,600' to 4,248'.,Change out cylinder on iron roughneck for 2-7/8" drill pipe.,Lay down 2-7/8" drill pipe from 4,248' to surface and bit/casing scraper.,Remove catch can and bell nipple. Install shooting flange on annular preventer. Had to clean and chase threads for bolts for shooting flange.,Rig up SLB lubricator and a -line equipment. Pulse neutron detectors did not stabilize on power up. Change out tools. Retest okay.,Test lubricator at 1,600 psi for 10 minutes.,SLB E -line run #1: CBUBDL pulse neutron porosity log from PBTD (11,438' WLM) to above TOL at 7,140'. POOH with logging tools.,Hauled 0 bbis cuttings to G&I for total = 150 bbls. Hauled 680 bbis class II junk fluid to G&I for total = 4,030 bbls. 2/4/2016 Continue POOH w/ SLB CBL/VDUpulse neutron log.,LD logging tools, PU test gun tool string, PJSM, PU arm 3-3/8" 6 spf 22.7 gram HMX Connex 20' gun, down loaded t/ 17'w/.47 entrance hole.,RIH w/ SLB gun run #1 tag PBTD @ 11,438' WLM, pull log U 10,890' to cover all perf intervals and catch (3) RA tags and tie in to LWD log, place gun on depth and send log to town for confirmation of tie in. J Dunston confirm gun on depth and ok to perf.,While circ across top w/ charge pump and monitoring fluid fired gun w/ good indication of detonation and perf H3 interval f/ 11,328't/ 11,345', log off depth and caught 3 collars and POOH, LD check gun, all shots fired and at minimal loss rate, LD gun #1 & PU and arm gun #2.,RIH w/ gun run #2 w/ 3-3/8" 20' gun load w/ 6 spf w/ same charges as above while tie in to LWD log, hung gun in perfs @ 11,328' work gun free and place gun on depth, sent tie in log to town, J Ewing confirmed gun on depth and ok to perf.,While circ across top w/ charge pump and monitoring fluid, fired gun w/ good indication of detonation and perf H2 interval f/ 11,290' U 11,310', log off depth and caught 3 collars and POOH LD check gun, all shots fired and at minimal to no loss rate LD gun #2 & PU and arm gun #3 and chg out shooting gama ray.,RIH w/ gun run #3 w/ 3-3/8" 10' gun down loaded t/ 9'@ 6 spf w/ same charges as above. Correlate guns on depth 11,281'- 11,290'. Confirmation from town. No good indication of detonation. POOH. Guns did not fire.,Check tools. Determined to be faulty detonator. RIH w/ gun RR run #3 w/ 3-3/8" 10' gun do loaded t/ 9'@ 6 spf w/ same charges as before. Correlate guns on depth 11,281'- 11,290'. Confirmation from town. Fire guns with good indication of detonation at 01:05 hrs. No fluid loss observed. POOH. All shots fired.,RIH w/ gun run #4 w/ 3-3/8" 20' gun loaded t/ 20'@ 6 spf w/ same charges as before. Correlate guns on depth 11,245'- 11,265'. Confirmation from town. Fire guns with good indication of detonation at 04:15 hrs. No fluid loss observed. POOH. All shots fired.,RIH w/ gun run #5 w/ 3-3/8" 20' gun loaded t/ 20'@ 6 spf w/ same charges as before. Will perf 11,225'- 11,245' interval., Hauled 0 bbis cuttings to G&I for total = 150 bbls. Hauled 680 bbis class II junk fluid to G&I for total = 4,030 bbls. 2/5/2016 RIH w/ gun run #5 w/ 3-3/8" 20' gun loaded t/ 20'@ 6 spf w/ same charges as before. Correlate guns on depth 11,226- 11,245'. Confirmation from town. Fire guns with good indication of detonation at 0740 hrs. No fluid loss observed. POOH. All shots fired.,Udn spent gun and remove perf equipment form cat walk load cat walk w/ prk and tail pipe assy.,M/up Tri -point 4-1/2" 9.5-13.5# model "D" permanent Prk assy w/ tail pipe w/ PX plug and prong installed w/ 1.37" FN total bha = = 31.22' P/up same Rih on SLB E -line @ 100 fpm and correlate on depth and confirmation from town and set top of pkr @ 11075' wlm w/ good indication of set (12' from collar and 150' from top of perfs ) and WLRG @ 11 100'and log off and pooh inspect running tool ok setting had full stroke,R/dn SLB E- line equipment,Flood lines and choke manifold close blinds and test 4-1/2" prk, csg and plug w/ 3 bbls t/ 3800 w/ psi for 30 min on chart w/ no bleed off good test bleed off 3 bbls.,Remove shooting flange, blow do lines and choke manifold. install flow box, flow nipple, flow line and hole fill line. Remove wear ring and clear rig floor.,R/up casers, ready floor to p/up run gas injection completion string. Hold PJSM.,Make up seal assembly. RIH picking up 2 3/8" 4.7# L-80 Supermax tubing to 3939'.,Change out handling equipment. Install 2 3/8" x 2 78" crossover. Pipe displacement matches calculated.,RIH picking up 2 7/8" 6.5# L-80 EUE tubing completion string to 5978'.,Hauled 0 bbis cuttings to G&I for total = 150 bbis. Hauled 680 bbls class II junk fluid to G&I for total = 4,030 bbis. 2/6/2016 Continue RIH picking up 2 7/8" 6.5# L-80 EUE tubing completion string F/5978' t/10987' as per drillers running tally w/ calculated tbg displacement,R/up to circ do w/ test pump,circ do two jts w/ test pump to locate first seal engagement f/ 10987'V 11090' tubing measurement Udn two jts.,M/U space out pups and hanger and p/up landing jt and pump corrosion inhibitor and 84 gals diesel for annulus freeze protect and chase w/ 60 bbis 6% kcl and drain stack.,Pipe only up wt @ 48k do wt @ 44k Stab seals, land hanger and latch anchor over pull 15k to verify latch good and re -land hanger. RILDS.,R/up and test tbg and seals U 4600 psi w/ 40 gals w/ annulus open for 30 min on chart Good test. Bleed off 31 gals.,Rig up and test annulus at 3500 psi on chart for 30 minutes. Test failed first time due to ruptured sensator diaphragm. Retest good. Pumped 155 gals with 147 gallons bleed off.,R/D test equipment. B/O and lay down landing joint. Install BPV. Rig down Weatherford equipment. Blow down choke manifold, choke and kill lines. Change lower pipe rams to 2 7/8" x 5" VBR's.,Nipple down choke and kill lines. Rig down flow line, bell nipple, flow box and accumulator lines. Nipple down BOP. Total safety rigged down equipment., Nipple up tree. Pull BPV. Set two-way check. Test void, hanger neck seals and tree at 150 U5000 H for 10 minutes each. Pull two-way check. Freeze protect well 20' and shut in tree.,Organize and clean up cellar area. Prepare for rig move.,Hauled 0 bbis cuttings to G&I for total = 150 bbls. Hauled 135 bbis class 11 junk fluid to G&I for total = 4165 bbls. 2/13/2016 ARRIVE AT 322C-04 RIG UP RIH W/ 2 7/8 SWAB CUPS recovered approximately 3 BBLS of PW, 3.5" tbg free of fluids, fluid @ 320' LAY DOWN FOR DAY HEAD TO SHOP 2/14/2016 ARRIVE AT SWANSON PERMIT,JSA ARRIVE AT LOCATION WARM UP EQUIPMENT RIG UP,RIH W/ 2 2 7/8 MULTI RIDGE CUP SAT DOWN @ 314' XOVER POOH RIH W/ 2" SB TO PULL PRONG @ 11104WL W/T PULL PRONG POOH W/PRONG RIH W/ 2 3/8 GS TO 11104WL W/T PULL PLUG POOH W/PLUG RIH W/ 2 7/8 SWABMANDREL 0 bbls water recovery RIH TO 1100WL TRY TO SMOOTH WIRE OOH RIG DOWN 2/26/2016 Arrive on location, PJSM, open permit RU equipment, shut in well RIH, bring on injection log as per procedure, SI well POOH, confirm good data, RDMO. 2/27/2016 Arrive at SRF. Perform JSA. Arrive on pad, rig up. RIH with MCX Injection Valve to 318' WLM, Set plug in x -nipple. POOH. Test valve from surface. Good test. Rig down. Hilcorp Energy Company Soldotna CK Unit Soldotna CK Unit SCU 322C-04 501331010401 501331010401 Sperry Drilling Definitive Survey Report 02 February, 2016 HA1. L IBURTON Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Soldotna CK Unit 314-4 Project: Soldotna CK Unit TVD Reference: SCU 322C-04 @ 163.14usft Site: Soldotna CK Unit MD Reference: SCU 322C-04 @ 163.14usft Well: Soldotna CK Unit 314-4 North Reference: True Wellbore: SCU 322C-04 Survey Calculation Method: Minimum Curvature Design: SCU 322C-04 Database: Sperry EDM - NORTH US + CANADA Project Soldotna CK Unit, Swanson River Field 11,486.66 MWD+SC+SAG (SCU 322C-04) MWD+SC+sag Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) 0.00 Using Well Reference Point Map Zone: Alaska Zone 04 0.00 0.00 2,456,758.86 343,081.91 0.00 0.00 UNDEFINED Well Soldotna CK Unit 314-4 185.90 103.13 Well Position +N/ -S 0.00 usft Northing: 2,456,758.86 usft Latitude: 60'43' 18.068 N 343,081.82 +EI -W 0.00 usft Easting: 343,081.91 usft Longitude: 150° 52'34.940 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 145.13 usft Wellbore SCU 322C-04 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) V) (nT) BGGM2015 1/15/2016 16.43 73.68 55,501 Design SCU 322C-04 Audit Notes: From To Map Version: 1.0 Phase: ACTUAL Tie On Depth: 7,303.14 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction 7,303.14 SCU 314-4 (SCU 314-4) (usft) (usft) (usft) (°) 7,394.00 18.00 0.00 0.00 26.47 Survey Program Date 2/2/2016 From To Map Map (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 103.14 7,303.14 SCU 314-4 (SCU 314-4) CB -Gyro -SS Fixed:v2:Camera based gyro single shot 12/11/2013 7,394.00 7,584.95 MWD_Interp Azi+sag (SCU 322C-04) MWD_Interp Azi+sag Fixed:v2:std dec with interpolated azimuth + sag 01/22/2016 7,647.71 11,486.66 MWD+SC+SAG (SCU 322C-04) MWD+SC+sag Fixed:v2:standard dec & axial correction + sag 01/22/2016 2WO16 2:21:44PM Page 2 COMPASS 5000.1 Build 73 Map Map Vertical MD Inc Azl TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 18.00 0.00 0.00 18.00 -145.13 0.00 0.00 2,456,758.86 343,081.91 0.00 0.00 UNDEFINED 103.14 1.13 185.90 103.13 -60.01 -0.84 -0.09 2,456,758.03 343,081.82 1.33 -0.79 CB -Gyro -SS (1) 203.14 1.50 181.29 203.11 39.97 -3.12 -0.22 2,456,755.74 343,081.66 0.38 -2.89 CB -Gyro -SS (1) 303.14 0.92 184.00 303.09 139.95 -5.23 -0.30 2,456,753.63 343,081.54 0.58 -4.82 CB -Gyro -SS (1) 403.14 0.61 180.16 403.08 239.94 -6.57 -0.36 2,456,752.30 343,081.47 0.31 -6.04 CB -Gyro -SS (1) 503.14 0.43 175.72 503.07 339.93 -7.47 -0.33 2,456,751.39 343,081.48 0.18 -6.84 CB -Gyro -SS (1) 603.14 0.25 174.20 603.07 439.93 -8.06 -0.28 2,456,750.80 343,081.52 0.18 -7.35 CB -Gyro -SS (1) 703.14 0.26 171.56 703.07 539.93 -8.51 -0.23 2,456,750.36 343,081.57 0.02 -7.72 CB -Gyro -SS (1) 803.14 0.22 172.14 803.07 639.93 -8.92 -0.17 2,456,749.95 343,081.63 0.04 -8.06 CB -Gyro -SS (1) 903.14 0.23 165.78 903.07 739.93 -9.31 -0.09 2,456,749.56 343,081.70 0.03 -8.37 CB-Gyro-SS(1) 1,003.14 0.26 123.58 1,003.07 839.93 -9.63 0.15 2,456,749.24 343,081.93 0.18 -8.55 CB-Gyro-SS(1) 1,103.14 0.28 120.44 1,103.07 939.93 -9.87 0.54 2,456,748.98 343,082.33 0.02 -8.60 CB -Gyro -SS (1) 2WO16 2:21:44PM Page 2 COMPASS 5000.1 Build 73 Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 314-4 Wellbore: SCU 322C-04 Design: SCU 322C-04 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Soldotna CK Unit 314-4 SCU 322C-04 @ 163.14usft SCU 322C-04 @ 163.14usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Survey MD Inc Azi TVD TVDSS +N/ -S +E/ -W Map Northing Map Easting DLS Vertical Section (usft) (1) (') (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Too[ Name 1,203.14 0.36 93.10 1,203.06 1,039.92 10.02 1.07 2,456,748.83 343,082.85 0.17 -8.49 CB -Gyro -SS (1) 1,303.14 0.42 77.52 1,303.06 1,139.92 -9.95 1.74 2,456,748.89 343,083.52 0.12 -8.13 CB -Gyro -SS (1) 1,403.14 0.42 75.70 1,403.06 1,239.92 -9.78 2.45 2,456,749.05 343,084.24 0.01 -7.66 CB -Gyro -SS (1) 1,503.14 0.46 71.18 1,503.06 1,339.92 -9.56 3.19 2,456,749.26 343,084.98 0.05 -7.14 CB -Gyro -SS (1) 1,603.14 0.46 69.49 1,603.05 1,439.91 -9.29 3.94 2,456,749.52 343,085.73 0.01 -6.56 CB -Gyro -SS (1) 1,703.14 0.47 68.84 1,703.05 1,539.91 -9.00 4.70 2,456,749.80 343,086.50 0.01 -5.96 CB -Gyro -SS (1) 1,803.14 0.44 58.01 1,803.05 1,639.91 -8.65 5.41 2,456,750.14 343,087.21 0.09 -5.33 CB -Gyro -SS (1) 1,903.14 0.45 59.10 1,903.04 1,739.90 -8.25 6.07 2,456,750.53 343,087.88 0.01 -4.68 CB-Gyro-SS(1) 2,003.14 0.45 56.41 2,003.04 1,839.90 -7.83 6.74 2,456,750.94 343,088.55 0.02 -4.01 CB-Gyro-SS(1) 2,103.14 0.37 62.48 2,103.04 1,939.90 -7.46 7.35 2,456,751.30 343,089.17 0.09 -3.40 CB-Gyro-SS(1) 2,203.14 0.39 62.11 2,203.04 2,039.90 -7.15 7.94 2,456,751.60 343,089.76 0.02 -2.87 CB-Gyro-SS(1) 2,303.14 0.37 66.23 2,303.03 2,139.89 -6.87 8.54 2,456,751.88 343,090.36 0.03 -2.34 CB-Gyro-SS(1) 2,403.14 0.38 63.59 2,403.03 2,239.89 -6.59 9.13 2,456,752.15 343,090.95 0.02 -1.83 CB-Gyro-SS(1) 2,503.14 0.44 59.14 2,503.03 2,339.89 -6.24 9.75 2,456,752.49 343,091.58 0.07 -1.24 CB -Gyro -SS (1) 2,603.14 0.43 55.25 2,603.03 2,439.89 -5.83 10.39 2,456,752.89 343,092.23 0.03 -0.59 CB -Gyro -SS (1) 2,703.14 0.44 49.09 2,703.02 2,539.88 -5.37 10.99 2,456,753.35 343,092.83 0.05 0.09 CB -Gyro -SS (1) 2,803.14 0.47 45.51 2,803.02 2,639.88 -4.83 11.57 2,456,753.88 343,093.42 0.04 0.84 CB-Gyro-SS(1) 2,903.14 0.53 41.70 2,903.02 2,739.88 -1.20 12.17 2,456,754.51 343,094.03 0.07 1.67 CB -Gyro -SS (1) 3,003.14 0.53 42.24 3,003.01 2,839.87 -3.51 12.79 2,456,755.19 343,094.66 0.00 2.56 CB -Gyro -SS (1) 3,103.14 0.57 33.59 3,103.01 2,939.87 -2.75 13.38 2,456,755.93 343,095.25 0.09 3.50 CB -Gyro -SS (1) 3,203.14 0.61 35.39 3,203.00 3,039.86 -1.90 13.96 2,456,756.77 343,095.85 0.04 4.52 CB -Gyro -SS (1) 3,303.14 0.59 34.43 3,303.00 3,139.86 -1.04 14.56 2,456,757.62 343,096.46 0.02 5.56 CB -Gyro -SS (1) 3,403.14 0.56 16.14 3,402.99 3,239.85 -0.15 14.99 2,456,758.51 343,096.90 0.19 6.55 CS -Gyro -SS (1) 3,503.14 0.52 4.75 3,502.99 3,339.85 0.77 15.16 2,456,759.43 343,097.08 0.11 7.45 CB -Gyro -SS (1) 3,603.14 0.53 355.46 3,602.98 3,439.84 1.69 15.16 2,456,760.35 343,097.10 0.09 8.27 CB -Gyro -SS (1) 3,703.14 0.56 358.31 3,702.98 3,539.84 2.63 15.11 2,456,761.30 343,097.06 0.04 9.09 CB -Gyro -SS (1) 3,803.14 0.85 8.99 3,802.97 3,639.83 3.86 15.21 2,456,762.52 343,097.18 0.32 10.23 CB -Gyro -SS (1) 3,903.14 1.06 15.94 3,902.96 3,739.82 5.48 15.58 2,456,764.13 343,097.57 0.24 11.85 CB-Gyro-SS(1) 4,003.14 1.17 14.36 4,002.94 3,839.80 7.36 16.09 2,456,766.00 343,098.10 0.11 13.76 CB -Gyro -SS (1) 4,103.14 1.21 13.57 4,102.92 3,939.78 9.37 16.59 2,456,768.01 343,098.63 0.04 15.78 CB -Gyro -SS (1) 4,203.14 1.21 11.80 4,202.89 4,039.75 11.43 17.05 2,456,770.07 343,099.12 0.04 17.83 CB -Gyro -SS (1) 4,303.14 1.23 12.68 4,302.87 4,139.73 13.51 17.51 2,456,772.14 343,099.60 0.03 19.90 CB -Gyro -SS (1) 4,403.14 1.26 14.26 4,402.85 4,239.71 15.62 18.01 2,456,774.25 343,100.13 0.05 22.02 CB-Gyro-SS(1) 4,503.14 1.15 23.69 4,502.83 4,339.69 17.61 18.69 2,456,776.22 343,100.83 0.23 24.09 CB -Gyro -SS (1) 4,603.14 1.09 27.47 4,602.81 4,439.67 19.37 19.53 2,456,777.97 343,101.70 0.10 26.05 CB -Gyro -SS (1) 4,703.14 1.09 28.93 4,702.79 4,539.65 21.05 20.43 2,456,779.64 343,102.62 0.03 27.95 CB -Gyro -SS (1) 4,803.14 0.99 43.36 4,802.77 4,639.63 22.51 21.48 2,456,781.08 343,103.69 0.28 29.72 CB-Gyro-SS(1) 4,903.14 1.02 44.64 4,902.76 4,739.62 23.77 22.70 2,456,782.33 343,104.93 0.04 31.40 CB-Gyro-SS(1) 5,003.14 1.06 48.49 5,002.74 4,839.60 25.02 24.02 2,456,783.56 343,106.26 0.08 33.10 CB -Gyro -SS (1) 5,103.14 1.12 51.43 5,102.72 4,939.58 26.24 25.47 2,456,784.76 343,107.74 0.08 34.84 CB-Gyro-SS(1) 2/22016 2.21:44PM Page 3 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well Soldotna CK Unit 314-4 Project: Soldotna CK Unit TVD Reference: SCU 322C-04 @ 163.14usft Site: Soldotna CK Unit MD Reference: SCU 322C-04 @ 163.14usft Well: Soldotna CK Unit 314-4 North Reference: True Wellbore: SCU 322C-04 Survey Calculation Method: Minimum Curvature Design: SCU 322C-04 Database: Sperry EDM - NORTH US + CANADA Survey MD Inc Azi TVD TVDSS +N/ -S +E/ -W Map Northing Map Easting DLS Vertical Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 5,203.14 1.29 52.42 5,202.70 5,039.56 27.54 27.13 2,456,786.03 343,109.41 0.17 36.74 CB -Gyro -SS (1) 5,303.14 1.50 55.18 5,302.67 5,139.53 28.97 29.10 2,456,787.44 343,111.39 0.22 38.90 CB -Gyro -SS (1) 5,403.14 1.94 62.38 5,402.63 5,239.49 30.50 31.67 2,456,788.94 343,113.99 0.49 41.42 CB-Gyro-SS(1) 5,503.14 2.03 62.82 5,502.57 5,339.43 32.09 34.75 2,456,790.49 343,117.09 0.09 44.22 CB -Gyro -SS (1) 5,603.14 2.21 62.94 5,602.50 5,439.36 33.78 38.04 2,456,792.13 343,120.40 0.18 47.19 CB -Gyro -SS (1) 5,703.14 2.26 62.50 5,702.42 5,539.28 35.57 41.51 2,456,793.87 343,123.89 0.05 50.34 CB -Gyro -SS (1) 5,803.14 2.22 62.01 5,802.34 5,639.20 37.39 44.96 2,456,795.65 343,127.37 0.04 53.51 CB -Gyro -SS (1) 5,903.14 2.23 61.64 5,902.27 5,739.13 39.22 48.39 2,456,797.44 343,130.82 0.02 56.68 CB -Gyro -SS (1) 6,003.14 1.89 58.24 6,002.20 5,839.06 41.01 51.50 2,456,799.19 343,133.96 0.36 59.67 CB-Gyro-SS(1) 6,103.14 1.78 59.10 6,102.15 5,939.01 42.68 54.24 2,456,800.81 343,136.71 0.11 62.38 CB-Gyro-SS(1) 6,203.14 1.83 58.91 6,202.10 6,038.96 44.30 56.94 2,456,802.40 343,139.44 0.05 65.03 CB-Gyro-SS(1) 6,303.14 1.84 60.81 6,302.05 6,138.91 45.91 59.70 2,456,803.97 343,142.23 0.06 67.71 CB -Gyro -SS (1) 6,403.14 1.91 60.36 6,402.00 6,238.86 47.52 62.55 2,456,805.54 343,145.10 0.07 70.42 CB-Gyro-SS(1) 6,503.14 2.50 70.86 6,501.92 6,338.78 49.05 66.06 2,456,807.03 343,148.63 0.71 73.36 CB -Gyro -SS (1) 6,603.14 2.65 73.07 6,601.82 6,438.68 50.44 70.34 2,456,808.36 343,152.92 0.18 76.50 CB-Gyro-SS(1) 6,703.14 2.64 75.79 6,701.72 6,538.58 51.68 74.78 2,456,809.54 343,157.38 0.13 79.59 CB-Gyro-SS(1) 6,803.14 2.44 82.58 6,801.62 6,638.48 52.52 79.12 2,456,810.32 343,161.73 0.36 82.28 CB-Gyro-SS(1) 6,903.14 2.44 83.72 6,901.53 6,738.39 53.03 83.35 2,456,810.78 343,165.96 0.05 84.62 CB-Gyro-SS(1) 7,003.14 2.05 91.32 7,001.45 6,838.31 53.22 87.25 2,456,810.92 343,169.87 0.49 86.53 CB-Gyro-SS(1) 7,103.14 1.81 96.46 7,101.39 6,938.25 53.00 90.61 2,456,810.65 343,173.22 0.30 87.83 CB -Gyro -SS (1) 7,203.14 1.64 92.82 7,201.35 7,038.21 52.75 93.61 2,456,810.36 343,176.22 0.20 88.95 CB-Gyro-SS(1) 7,303.14 1.66 93.62 7,301.31 7,138.17 52.59 96.48 2,456,810.16 343,179.09 0.03 90.08 CB-Gyro-SS(1) 7,394.00 1.55 93.84 7,392.13 7,228.99 52.43 99.02 2,456,809.96 343,181.63 0.12 91.07 MWD _InterpAzi+sag (2) 7,462.05 5.53 63.51 7,460.04 7,296.90 53.83 102.88 2,456,811.31 343,185.50 6.27 94.04 MWD_InterpAzi+sag(2) 7,523.64 7.56 57.96 7,521.23 7,358.09 57.30 108.97 2,456,814.71 343,191.64 3.45 99.86 MWD_InterpAzi+sag (2) 7,584.95 10.27 54.68 7,581.79 7,418.65 62.60 116.85 2,456,819.90 343,199.59 4.50 108.12 MWD_Interp Azi+sag (2) 7,647.71 11.12 52.39 7,643.46 7,480.32 69.53 126.21 2,456,826.70 343,209.04 1.51 118.49 MWD+SC+sag (3) 7,710.53 11.79 45.22 7,705.03 7,541.89 77.75 135.56 2,456,834.80 343,218.50 2.50 130.02 MWD+SC+sag (3) 7,772.39 12.67 35.46 7,765.50 7,602.36 87.73 143.99 2,456,844.66 343,227.06 3.63 142.71 MWD+SC+sag (3) 7,833.10 14.02 28.39 7,824.57 7,661.43 99.62 151.35 2,456,856.46 343,234.58 3.48 156.63 MWD+SC+sag (3) 7,892.75 15,23 25.99 7,882.29 7,719.15 113.02 158.22 2,456,869.76 343,241.62 2.27 171.69 MWD+SC+sag (3) 7,956.51 15.77 23.47 7,943.73 7,780.59 128.50 165.34 2,456,885.14 343,248.95 1.35 188.72 MWD+SC+sag (3) 8,018.49 17.22 22.53 8,003.16 7,840.02 144.70 172.21 2,456,901.25 343,256.04 2.38 206.28 MWD+SC+sag (3) 8,080.36 18.59 23.97 8,062.03 7,898.89 162.17 179.72 2,456,918.62 343,263.78 2.33 225.27 MWD+SC+sag (3) 8,142.71 20.72 22.74 8,120.74 7,957.60 181.42 188.02 2,456,937.76 343,272.34 3.48 246.21 MWD+SC+sag (3) 8,205.10 22.81 21.43 8,178.68 8,015.54 202.86 196.71 2,456,959.08 343,281.31 3.44 269.27 MWD+SC+sag (3) 8,267.20 25.14 21.45 8,235.42 8,072.28 226.35 205.93 2,456,982.44 343,290.85 3.75 294.41 MWD+SC+sag (3) 8,329.52 27.72 23.04 8,291.22 8,128.08 252.01 216.45 2,457,007.97 343,301.71 4.29 322.07 MWD+SC+sag (3) 8,390.98 29.96 22.49 8,345.06 8,181.92 279.35 227.91 2,457,035.15 343,313.54 3.67 351.65 MWD+SC+sag (3) 8,452.80 32.06 23.46 8,398.04 8,234.90 308.67 240.35 2,457,064.29 343,326.36 3.49 383.44 MWD+SC+sag (3) 2/2/2016 2:21:44PM Page 4 COMPASS 5000.1 Build 73 Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 314-4 Wellbore: SCU 322C-04 Design: SCU 322C-04 Survey MD Inc (usft) (1) 8,515.06 34.51 8,576.80 35.81 8,639.23 37.72 8,701.47 40.11 8,762.84 41.50 8,824.53 43.93 8,885.76 45.61 8,949.04 47.15 9,011.29 47.41 9,073.94 46.70 9,135.62 46.47 9,195.93 46.11 9,257.91 46.97 9,321.57 46.76 9,383.03 46.94 9,445.19 46.13 9,507.46 46.89 9,569.51 46.62 9,631.74 46.20 9,693.10 47.05 9,755.51 47.08 9,817.30 47.71 9,878.66 48.05 9,941.74 47.86 10,003.12 48.35 10,066.14 46.96 10,127.91 47.36 10,189.58 46.22 10,251.42 46.59 10,313.32 46.83 10,376.46 45.51 10,438.34 44.83 10,500.93 44.88 10,563.52 45.81 10,625.05 46.65 10,687.40 48.23 10,749.16 48.31 10,808.24 48.07 10,871.94 48.21 10,935.74 48.18 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Soldotna CK Unit 314-4 SCU 322C-04 @ 163.14usft SCU 322C-04 @ 163.14usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Azi TVD TVDSS +N/ -S +E/ -W Map Northing Map Easting DLS Vertical Section °) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 24.46 8,450.08 8,286.94 339.88 254.24 2,457,095.32 343,340.66 4.03 417.57 MWD+SC+sag (3) 26.76 8,500.56 8,337.42 371.93 269.61 2,457,127.17 343,356.46 3.01 453.11 MWD+SC+sag (3) 26.60 8,550.57 8,387.43 405.32 286.39 2,457,160.33 343,373.68 3.06 490.48 MWD+SC+sag (3) 26.99 8,598.99 8,435.85 440.21 304.01 2,457,194.98 343,391.77 3.86 529.57 MWD+SC+sag (3) 26.24 8,645.44 8,482.30 476.07 321.98 2,457,230.59 343,410.21 2.40 569.67 MWD+SC+sag (3) 25.34 8,690.77 8,527.63 513.75 340.17 2,457,268.03 343,428.91 4.06 611.51 MWD+SC+sag (3) 25.70 8,734.23 8,571.09 552.66 358.75 2,457,306.69 343,448.01 2.77 654.63 MWD+SC+sag(3) 25.15 8,777.89 8,614.75 594.03 378.42 2,457,347.80 343,468.22 2.51 700.43 MWD+SC+sag (3) 24.94 8,820.12 8,656.98 635.47 397.78 2,457,388.97 343,488.14 0.49 746.15 MWD+SC+sag (3) 25.04 8,862.80 8,699.66 677.03 417.15 2,457,430.27 343,508.06 1.14 791.99 MWD+SC+sag (3) 24.50 8,905.19 8,742.05 717.72 435.92 2,457,470.70 343,527.38 0.74 836.78 MWD+SC+sag (3) 24.03 8,946.87 8,783.73 757.46 453.84 2,457,510.20 343,545.82 0.82 880.34 MWD+SC+sag (3) 25.16 8,989.50 8,826.36 798.36 472.57 2,457,550.85 343,565.09 1.92 925.30 MWD+SC+sag (3) 24.83 9,033.03 8,869.89 840.47 492.20 2,457,592.69 343,585.28 0.50 971.74 MWD+SC+sag (3) 25.31 9,075.06 8,911.92 881.08 511.20 2,457,633.05 343,604.82 0.64 1,016.57 MWD+SC+sag (3) 24.81 9,117.82 8,954.68 921.95 530.31 2,457,673.65 343,624.47 1.43 1,061.67 MWD+SC+sag (3) 25.83 9,160.68 8,997.54 962.78 549.63 2,457,714.23 343,644.34 1.70 1,106.84 MWD+SC+sag (3) 25.67 9,203.19 9,040.05 1,003.49 569.27 2,457,754.67 343,664.52 0.47 1,152.03 MWD+SC+sag (3) 24.89 9,246.10 9,082.96 1,044.25 588.51 2,457,795.17 343,684.31 1.13 1,197.09 MWD+SC+sag (3) 26.17 9,288.24 9,125.10 1,084.49 607.74 2,457,835.15 343,704.07 2.05 1,241.69 MWD+SC+sag (3) 26.12 9,330.75 9,167.61 1,125.51 627.87 2,457,875.89 343,724.75 0.08 1,287.38 MWD+SC+sag (3) 26.10 9,372.58 9,209.44 1,166.35 647.89 2,457,916.46 343,745.31 1.02 1,332.86 MWD+SC+sag (3) 25.79 9,413.73 9,250.59 1,207.27 667.80 2,457,957.12 343,765.76 0.67 1,378.37 MWD+SC+sag (3) 24.93 9,455.98 9,292.84 1,249.60 687.86 2,457,999.18 343,786.39 1.06 1,425.20 MWD+SC+sag (3) 24.32 9,496.96 9,333.82 1,291.14 706.90 2,458,040.45 343,805.98 1.09 1,470.87 MWD+SC+sag (3) 25.80 9,539.41 9,376.27 1,333.33 726.62 2,458,082.38 343,826.26 2.81 1,517.43 MWD+SC+sag (3) 25.89 9,581.41 9,418.27 1,374.09 746.37 2,458,122.87 343,846.55 0.66 1,562.72 MWD+SC+sag (3) 25.75 9,623.64 9,460.50 1,414.55 765.94 2,458,163.07 343,866.66 1.86 1,607.66 MWD+SC+sag (3) 25.49 9,666.28 9,503.14 1,454.94 785.31 2,458,203.19 343,886.56 0.67 1,652.44 MWD+SC+sag (3) 25.31 9,708.72 9,545.58 1,495.64 804.64 2,458,243.63 343,906.43 0.44 1,697.49 MWD+SC+sag (3) 26.15 9,752.45 9,589.31 1,536.67 824.41 2,458,284.40 343,926.75 2.30 1,743.04 MWD+SC+sag (3) 25.71 9,796.08 9,632.94 1,576.14 843.60 2,458,323.60 343,946.46 1.21 1,786.92 MWD+SC+sag (3) 25.38 9,840.44 9,677.30 1,615.97 862.63 2,458,363.18 343,966.03 0.38 1,831.06 MWD+SC+sag (3) 25.57 9,884.43 9,721.29 1,656.16 881.78 2,458,403.11 343,985.71 1.50 1,875.58 MWD+SC+sag (3) 24.69 9,927.00 9,763.86 1,696.39 900.65 2,458,443.08 344,005.12 1.71 1,919.99 MWD+SC+sag (3) 25.20 9,969.17 9,806.03 1,738.02 920.02 2,458,484.46 344,025.04 2.60 1,965.90 MWD+SC+sag (3) 24.57 10,010.28 9,847.14 1,779.84 939.41 2,458,526.01 344,044.99 0.77 2,011.97 MWD+SC+sag (3) 23.94 10,049.66 9,886.52 1,819.98 957.50 2,458,565.91 344,063.62 0.89 2,055.98 MWD+SC+sag (3) 24.59 10,092.17 9,929.03 1,863.23 977.00 2,458,608.90 344,083.69 0.79 2,103.38 MWD+SC+sag (3) 25.10 10,134.70 9,971.56 1,906.39 996.98 2,458,651.78 344,104.24 0.60 2,150.92 MWD+SC+sag (3) 2/2/2016 2:21:44PM Page 5 COMPASS 5000.1 Build 73 Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 314-4 Wellbore: SCU 322C-04 Design: SCU 322C-04 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well Soldotna CK Unit 314-4 SCU 322C-04 @ 163.14usft SCU 322C-04 @ 163.14usft True Minimum Curvature Sperry EDM - NORTH US + CANADA MD Inc Azi TVD TVDSS +N/ -SE/ +Map -W Northing Map Easting DLS Vertical Section (usft) 0 (o) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 10,998.21 48.07 25.94 10,176.40 10,013.26 1,948.37 1,017.02 2,458,693.49 344,124.84 1.02 2,197.43 MWD+SC+sag(3) 11,060.23 47.49 24.35 10,218.08 10,054.94 1,989.94 1,036.54 2,458,734.80 344,144.91 2.12 2,243.35 MWD+SC+sag (3) 11,123.66 47.25 22.98 10,261.04 10,097.90 2,032.68 1,055.27 2,458,777.28 344,164.21 1.63 2,289.96 MWD+SC+sag (3) 11,184.85 47.80 21.88 10,302.36 10,139.22 2,074.40 1,072.49 2,458,818.77 344,181.99 1.60 2,334.97 MWD+SC+sag (3) 11,247.17 48.89 21.67 10,343.78 10,180.64 2,117.64 1,089.76 2,458,861.77 344,199.83 1.77 2,381.38 MWD+SC+sag (3) 11,309.94 48.49 19.60 10,385.22 10,222.08 2,161.76 1,106.38 2,458,905.67 344,217.04 2.56 2,428.28 MWD+SC+sag (3) 11,372.74 47.70 17.08 10,427.17 10,264.03 2,206.11 1,121.09 2,458,949.82 344,232.34 3.24 2,474.54 MWD+SC+sag (3) 11,433.44 47.25 16.33 10,468.19 10,305.05 2,248.96 1,133.95 2,458,992.49 344,245.77 1.17 2,518.63 MWD+SC+sag (3) 11,486.66 46.52 15.10 10,504.57 10,341.43 2,286.35 1,144.47 2,459,029.75 344,256.79 2.17 2,556.80 MWD+SC+sag (3) 11,525.00 46.52 15.10 10,530.95 10,367.81 2,313.21 1,151.72 2,459,056.51 344,264.40 0.00 2,584.07 PROJECTED to TD Checked B brian.wheeler@halliburton. w�^ --�� Y: com Approved By: cay.taylor@ha0murton.com�n»wanaw�� Date: wn:xoieozie��:uaemw 2/2/2016 2.21:44PM Page 6 COMPASS 5000.1 Build 73 5 10 151 20( 25( 30C 35C 400 450 500 55011 CL 600( v 650( v L 700( v 750C 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 SCU 322C-04 Days vs Depth FINAL 0 )0 --SCU 322C-04 )0 Actual SCU 322C-04 Plan )0 )0 10 110 0 0 o' 1 I 0 5 10 15 20 25 30 Days 3/7/20162:46 PM 10 20( 30( 400 500 M s C 0 600( v L H lu 700( 8000 9000 10000 11000 12000 SCU 322C-04 MW vs Depth 0 --SCU 322C-04 Plan 30 --SCU 322C-04 Actual )0 10 0 1 0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density (ppg) Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No, Density (ppg) Tail Slurry 13 Volume Pumped BBLs P P ( ) 64.4 Mixing /pumping Rate (bpm): w Type: Easy Blok County 15.6 Volume pumped (BBLs) 30 Mixing /Pumping Rate (bpm): N z Type: SRF SCU 322C-04 Date Run 30 -Jan -16 Rate (bpm): (P ) Volume: Type: Displacement CCP (psi): Density (ppg) 10.6 Rate (bpm): 5 Volume (actual / calculated): State AK Supv. R Pederson / R Brumley No Reciprocated? X X Yes Yes No % Returns during job 98 Cement In Place At: _ No Spacer returns? 4:15 Date: CASING RECORD 1/31/2016 Method Used To Determine TOC Volume Estimated TOC: 7198 _ TDUner 11,525.00 Shoe Depth: 11,524.00 PBTD: No. its. Delivered 125 No. its. Run 10_ 6 11,438.00 _ No its. Returned Fig. Delivered Ftg. Run Length Measurements W/O Threads Ftg. Cut Jt. Fig. Balance Fig. Returned RKB 18.00 RKB to BHF RKB to CHF RKB to THF Casing (Or Liner) Detail its. Component Size Wt. Grade THD Make Setting Depths 1 Shoe 41/2 DWC/C Weatherford Length 1.50 Bottom Top 1 Shoe Joint 41/2 12.6 L-80 DWC/C VAM 11,524.00 11,522.50 1 Float Collar 41/2 DWC/C Weatherford 40.45 11,522.50 11,482.05 1 Float Collar Joint 412 / 12.6 L-80 DWC/C VAM 1.35 11,482.05 11,480.70 1 Landing Collar q 1/2 1VAMs 40.83 11,480.70 11,439.87 1 Landing Collar Joint 41/2 12.6 L-80 DWC/C 1.11 11,439.87 11,438.76 1 RA Marker Joint 412 / 12.6 L-80 DWC/C VAM 38.19 11,438.76 11,400.57 3 Liner 41/2 12.6 L-80 DWC/C VAM 38.75 11,400.57 11,361.82 1 RA Marker Joint 412 / 12.6 L-80 DWC/C VAM 120.19 11,361.82 11,241.63 3 Liner 41/2 12.6 L-80 DWC/C VAM 38.76 11,241.63 11,202.87 1 RA Marker Joint 41/2 12.6 L-80 DWC/C VAM 114.04 11,202.87 11,088.83 3 Liner 41/2 12.6 L-80 DWC/C VAM 30.73 11,088.83 11,058.10 1 RA Marker Joint 412 / 12.6 L-80 DWC/C VAM 118.20 11,058.10 10,939.90 4 Liner 41/2 12.6 L-80 DWC/C VAM 29.78 10,939.90 10,910.12 t Liner Pup Joint q 1 2 / 12.6 L-80 DWC/C VAM7.45 3,676.77 10,910.12 7,233.35 Liner Hanger/Packer 7 DWC/C 7,233.35 7,225.90 Baker 27.63 7,225.90 7,198.27 Csg Wt. On Hook: 133,899 Type Float Collar: Weatherford Model #402E No. Hrs to Run: Csg Wt. On Slips: Type of Shoe: Weatherford Model #303 24 Rotate Csg Yes X Casing Crew: Weatherford _ No Recip Csg X Yes No -20 Ft. Min. 10.6 PPC Fluid Description: 6% KCL Mud Liner hanger Info (Make/Model): Baker HRDE ZXPN, Flex -Lock Liner hanger test pressure:1179 Liner top Packer?: X Yes No Floats Held Centralizer Placement: One bowspring every joint first 15 joints, then one bowspring every otherjoint up to window at 7394' X Yes _ No CEMENTING REPORT Shoe @ 11524 FC @ 11,438.76 Preflush (Spacer) Top of Liner 7198.2 Type: Mud Push II Density (ppg) 12 Lead Slurry Volume pumped (BBLs) 24.6 Type: Lead Density (ppg) Tail Slurry 13 Volume Pumped BBLs P P ( ) 64.4 Mixing /pumping Rate (bpm): w Type: Easy Blok F Density (ppg) F Post Flush (Spacer) 15.6 Volume pumped (BBLs) 30 Mixing /Pumping Rate (bpm): N z Type: LL Displacement: Density (ppg) Rate (bpm): (P ) Volume: Type: Displacement CCP (psi): Density (ppg) 10.6 Rate (bpm): 5 Volume (actual / calculated): 1000 Casing Rotated? Pump used for disp: SLB _ Yes X 157 Bump Plug? X Yes No Bump press Cement returns to surface? No Reciprocated? X X Yes Yes No % Returns during job 98 Cement In Place At: _ No Spacer returns? 4:15 Date: X Yes No Vol to Surf '- 6 1/31/2016 Method Used To Determine TOC Volume Estimated TOC: 7198 _ Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: 94.4 Cmt returned to surface: 6 Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual %Washout: Make WELLHEAD Type Serial No. Size W P Test head to PSIG MIN OK Remarks: www.weliez.net WellEz Information Management LLC ver 3 4 Seth Nolan GeoTech lid�•��ri+ tL,<R;�. Lia DATE 03/29/2016 Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 Fax: 907 777-8510 E-mail: snolan@hilcorp.com To: Alaska Oil & Gas Conservation Commission Meredith Guhl Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 4 boxes: Dry Cuttings Transmitted herewith are cuttings from SCU 322C-04 WELL SAMPLE INTERVAL SCU 322C-04 7394-8410 8410 SCU 322C-04 8410 —9280 SCU 322C-04 9280 — 10510 SCU 322C-04 10510 —11525 Please include current contact information if different from above. aJ5 2!"�' RECEIVED MAR 3 0 2016 A®GG Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 xeceiv7,",,, Date: 21 52 1 7 Seth Nolan Hilcorp Alaska, LLC 26 G 87-7 GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 26 8 7 8 Tele: 907 777-8308 Ifilenrl, Ahoku. JAA, Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATA LOGGED 3 / g /2014 M. K. BENDER DATE 03/04/16 I To: Alaska Oil & Gas Conservation Commission MAR ®$ 2015Makana Bender Natural Resource Technician II t�++ 333 W 7th Ave Ste 100 4,0GOC Anchorage, AK 99501 710 IR Z nm M, SCU 322C-04 Elog and Mudlog prints and digital data Prints: 2"/5" ROP-DGR-EWR-ALD-CTN MD 2"/5" DGR-EWR-ALD-CTN TVD 2" FORMATION LOG MD 2" FORMATION LOG TVD 5" FORMATION LOG MD 5" FORMATION LOG MD 2" DRILLING DYNAMICS MD CD1: Elog digital data CGM Definitive Survey DLIS+LAS EMF PDF TIFF CD2: Mudlog digital data Daily Reports DML Data Final Well Report LAS Data Log PDFs Log TIFFS 2" DRILLING DYNAMICS TVD 2" GAS RATIO MD 2" GAS RATIO TVD 2" LWD COMBO MD 2" LWD COMBO TVD FINAL WELL REPORT 2'3/2016 8:59 AM 2/3/2016 8:59 AM 2.x'3/2016 8:59 AM 2/3:/2016 8:59 AM 2,1312016 8:59 AM 2,/3/2016 8:59 AM 2,x79/201611:12 AM 2+'1.9x`201611:12 AM 2/191201611:12 AM 2{19,'201611:12 AM 2x19/201611;12 AM 2;`19x`201611:12 AM Please include current contact information if different from above. Filefclder Filefclder File folder Filefclder Filefclder Filefclder Filefolder Filefclder Filefclder Filefclder Filefclder File folder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: ,. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, March 15, 2016 TO: Jim Regg Q<� , 7 (lam' P.I. Supervisor l SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 322C-04 FROM: Jeff Jones SOLDOTNA CK UNIT 322C-04 Petroleum Inspector Src: Inspector Reviewed P.I. Supry ..J'— NON-CONFIDENTIAL Comm Well Name SOLDOTNA CK UNIT 322C-04 API Well Number 50-133-10104-01-00 Inspector Name: JeffJones Insp Num: mitJJ 1 603 1 1 1 7093 8 Permit Number: 215-217-0 Inspection Date: 3/5/2016 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 322C-oa Type Inj ��TV>� loz3o Tubing 3700 3800 385t3850 PTD 2152I70 Type Test SPT Test psi 2558 IA 865 2850 28402835 -- Interval INITAL p/F P OA 110 110 110 110 Notes: Initial MIT -IA. As soon as the pump started to pressure up the inner annulus I observed bubbling fluid in the well cellar which slowly decreased until by the end of the 30 minute test period it had totally ceased. Tuesday, March 15, 2016 Page 1 of 1 20' 30 13--- 3,0 CBL 5, 7" Cc 7` 11ilcorp Alaska, 1-L(' GL: 145' AMSL KB -18' TD = 11,525' MD / 10,531' TVD PBTD = 11,438' MD / 10,471' TVD Max Deviation = 49° @ 11,247' L. k-�C'CC --FA5� I AAS{�� 1603 jlt 3b, Swanson River Field Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 Size Type Wt Grade Conn Tap Btm Hole Cmt CmtTop 20" Conductor Surf. 30' 3-1/2" Yes Surf. 13-%" Surface E54.5 J-55 8RD Surf. 1,500' 17-% 3,005' 1,100 sx Surf. DV Collar 1,500' 1,503' 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,290' Calc 7" Production 29 26 23 N-80 26 29 BTC Surf. 303' 9-31." 11,040' 650 sx 5,720' CBL 7" 303' 1,296' 7" 1,296' 4,793' 7" 4,793' 6,306' 7" 6,306' 7,509' DV Collar 2.688" 7,509' 7,511' 4-1/2" Liner 12.6 L-80 DWC/C 7,198' 11,524' 11 525' 309 sx 7,198' Volume TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf 331' 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" 331' 7,150' 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,150' 11,081' JEWELRY DETAIL NO. Depth ID OD Item 1 19.29' 2.900" 7.000" 3-1/2" Tubing Hanger 2 320' 2.813" 4.5" 3-1/2" X — Landing Nipple �inj ctirw valve) 3 330' 2.441" - 3-1/2" x 2-7/8" Crossover 4 7,150' 1.995" - 2-7/8" x 2-3/8" Crossover 5 7,198' 7" X 4-1/2" ZXP liner hanger 6 11,074'-11,081' 1.995" 2.688" Anchor Latch Seal Assembly - 6.17' Stung into Packer/SBE 7 11,075' 2.688" 4.500" 4-1/2" x 2-3/8" Model D Perm Packer 8 11,077' 2.688" Seal Bore Extension 9 11,090' 1.875" 3.080" X—Landing Nipple 10 11,099' 1.995" 3.100" WL Entry Guide • Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-1 11,225' 11,265 10,329' 10,355' 3-3/8" 6spf 60 deg H-2 11,281' 11,310' 10,365' 10,385' 3-3/8" 6spf 60 deg H-3 11,328' 11,345' 1 10,397' 10,408' 3-3/8" 6spf 60 deg Updated by DMA 03-03-16 Wallace, Chris D (DOA) From: Larry Greenstein <Igreenstein@hilcorp.com> Sent: Tuesday, February 09, 2016 9:18 AM To: Wallace, Chris D (DOA) Cc: Joe Kaiser; Bruce Hershberger; Joey Hensley; Chad Helgeson Subject: Restart of a pilot gas flood at SRF in SCU 322C-04 (PTD 2152170) Attachments: SCU 322C-04 Proposed Schematic 1-29-2016.pdf Hi Chris As we discussed, this e-mail will serve as the 10 day notice of a restart of a small, targeted gas flood at SRF in the SCU 322C-04 gas injection well. AIO 13A authorizes this type of Hemlock EOR project and full field gas flooding was successfully done in the past when gas was more plentiful. The side track operations on the SCU 314-04 well were successful and the new sidetrack has passed all pre-injection pressure tests (see MIT -IA attached). After injection starts up and the well stabilizes, AOGCC will be notified for an initial MIT -IA that the field will request through the web -based notification system. Attached is the proposed schematic for the SCU 322C-04 well, as the final schematic has not been finalized yet. The `as - installed' schematic will be included with the 10-407 reporting to AOGCC in the near future. If there is any other info you need, please let me know. Thank you Larry Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, January 29, 2016 4:33 PM To: 'Joe Kaiser' Cc: Chad Helgeson Subject: RE: 215-217 Sundry 316-047 SCU 322C-04 H3 Perforations Joe, The proposed perf intervals fall within the approved sundry 316-047 TVD window. Approval granted to perforate well as proposed below. Please update the MOC form with this info. Will document this by placing email in our well file. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal 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@alas ka.gov). From: Joe Kaiser [mailto:ikaiser@hilcorp.com] Sent: Friday, January 29, 2016 3:58 PM To: Schwartz, Guy L (DOA) Cc: Chad Helgeson Subject: PTD: 215-217 Sundry 316-047 SCU 322C-04 H3 Perforations Guy, Per our phone conversation. Please see attached Proposed Schematic dated 1/29/2016. In the approved sundry we requested perforating the intervals for H-1 and H-2 as being from 10,227'— 10,359'TVD and 10,359'— 10,561'TVD. Based on the open hole logs on the well, the Geologist determined the H-1, H-2, and H-3 as 10,320'— 10,356'TVD, 10,366'— 10,385'TVD, and 10,297'— 10,409' respectively. We are within the approved TVD range in the sundry, however we would like to clarify and request to perforate in the H3 sand. If you have any questions, please let me know. Joe Kaiser KEN Operations Engineer Swanson River Field ikaiser@hilcorp. com 907-777-8393 Office 907-952-8897 Cell 20 30 13-3 3,01 CBL 5,-i 7" Col 7,51 0 Ililvotp AI:I-ka. LLC G1:145' AMSL KB -18' TD =11,525' PBTD =11,481' Max Deviation = 48.35 deg @ 10,003' PROPOSED SCHEMATIC Swanson River Unit Well: SCU 322C-04 PTD: 215-217 API: 50-133-10104-01 Existing Casing Detail ze Type Wt Grade Conn Top Btm Hole Cmt CmtTop " Conductor F - L-80 8rd EUE Surf. 30' -300 Yes Surf. '/." Surface 54.5 J-55 8RD Surf. 1,500' ,005' 3,005' 1,100 sx Surf. DV Collar 1,500' 1,503' 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,29(Y Calc 7" Production 29 N-80 BTC Surf. 303' 9-y"650 11,040' sx 5,720' CBL 7" 26 303' 1,296' 7" 23 1,296' 4,793' 7" 26 4,793' 6,306' 7" 29 6,306' 7,509' DV Collar 7,509' 7,511' 4-1/2" 1 Liner 12.6 L-80 DWC/C 7,200 11,937' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf -300 2-7/8" Tubing 6.4 L-80 8rd EUE 2.441" -300 7,200' 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" 7,200' -11,100' PROPOSED JEWELRY DETAIL NO. Depth ID OD Item 1 20' 2.992" 4.5" 3-1/2" Tubing Hanger 2 -300' 2.813" 4.5" 3-1/2-X- Landing Nipple (injection valve) 3 ^310' 2.441" ±10,409` 3-1/2" x 2-7/8" Crossover 4 7,150' 1.995" - 2-7/8" x 2-3/8" Crossover 5 7,200' 7" X 4-1/2" ZXP liner hanger 6 11,000' 2.688" 3.75" 4-1/2" x 2-3/8" Model D Perm Packer w/ anchor latch assembly w/ 5' seals I S n n- x. 7.;741'C'7 'e41) 7 11,008' 1.875" 3.063" X - Landing Nipple 8 11,038 1.995" 3.063" WL Entry Guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-1 ±11,225' ±11,265' ±10,329' ±10,356' 3-3/8" 6spf 60 deg H-2 ±11,281' ±11,310' ±10,366' ±10,385' 3-3/8" 6spf 60 deg 21,326` ±11,345 1-10,397' ±10,409` 3-3/8' dee, Updated by DMA 01-29-16 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, January 29, 2016 11:04 AM To: 'Joe Kaiser' Cc: Chad Helgeson; Donna Ambruz; mmyers@hilcorp.com Subject: RE: 215-217 - SCU 322C-04 Completion Change (sundry 316-047) Joe, As per our phone call you have Approval to modify the sundry with a permanent Eline set packer (vs Hydraulic set) and change the procedure steps as outlined in your updated documents. Make sure you update the MOC form on the sundry packet as required. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: Joe Kaiser [mailto:jkaiser@hilcorp.com] Sent: Thursday, January 28, 2016 1:44 PM To: Schwartz, Guy L (DOA) Cc: Chad Helgeson; Donna Ambruz Subject: PTD: 215-217 - SCU 322C-04 Completion Change Guy: Hilcorp doesn't have the approved sundry in hand, so the sundry number is not in the subject line. Per our conversation on the phone, please see attached change in procedures and schematic for PTD: 215-217 - SCU 322C-04 Initial Completion. We recalculated the tubing movement and stress on the hydraulic packer and was too close to the unseat pressure. So we have decided to set a permanent packer on a -line instead. The attached procedures reflect this change. If you have any further questions, please don't hesitate to contact me. -Joe Kaiser KEN Operations Engineer IIilcory Alaska, LL Well Prognosis Well: SCU 322C-04 Date:1/28/2016 Well Name: SCU 322C-04 API Number: 50-133-10104-01 Current Status: Drilling in progress Leg: N/A Estimated Start Date: ..13G/16 Rig: Saxon 169 Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-217 First Call Engineer: Joe Kaiser (907) 777-8393 (0) (907) 952-8897 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: 1512837C Maximum Expected BHP: — 1,100 psi @ 10,400' TVD (Based on offset well PTA 1/6/2016) Max. Potential Surface Pressure: — 100 psi (Based on 0.1 psi/ft gradient to surface) Max. Gas Injection Pressure (post well work): 4,600 psi @ surface (Based on max compressor discharge) Brief Well Summary SCU 322C-04 is a gas injection well currently being sidetracked from SCU 314-04 to target H1/H2 gas injection in an effort to sweep production in this fault block. Based on recent drilling results, this zone does not appear to have been swept with the original gas flooding in Swanson River. The other producer in this zone and fault block (SCU 21C-04), does not have support (water flood, water driver, or gas injection) to accomplish maximum oil recovery. Objective: Perforate in the Hemlock formation (H1/H2) and run gas injection completion. Notes Regarding Wellbore Condition °� • Saxon 169 rigged up on well and currently drilling. " �~ • Pressure test 4-1/2" x 7" casing to 3,500 psig will be completed. • Continue BOP testing frequency from Drilling Program (PTD 215-217) through completion. • Well full of 6% KCL fluid. • Step 17.2 of the drilling procedure may include drilling 40-60 ft of the 120' shoe track. E -Line Procedure: 1. ** Continue from SCU 322C-04 (PTD 215-217) Drilling Program Step 18.1 2. MIRU E -line on drilling rig. 3. RI H and run Cement Bond Log from PBTD to 7200' MD (top of 4.5" liner). POOH. LD CBL tool. a. Send logs to town for correlation log. b. Final perf depths will be based on CBL results. 4. ND bell nipple and NU lubricator on top of BOP Annular preventer flange. PT lubricator to 1,500 psig for 10 min. 5. RU 3-3/8" 6spf wireline guns. 6. RIH and perforate the following intervals: IIilcorp Alaska, LL g. 3-1/2" x 2-7/8" crossover h. 3-1/2" X -Landing Nipple i. 3-1/2" Tubing Hanger 17. Land tubing in hanger. Close the lockdown pins. Well Prognosis Well: SCU 322C-04 Date: 1/28/2016 22. Test tubing to 4,600psi for 30min with chart. 23. Test casing to 3,500 psig for 30 min with chart. 24. LD landing joint. Set BPV. ND BOPE. NU Tree. Pull BPV 25. Set TWC. Test hanger to 250/5,000 psi. Test Tree to 250/5,000 psi. Pull TWC. 26. RD Saxon #169 Drill Rig. 27. Turn well over to Hilcorp Operations. .„6. ***A 10 -day notification must be made to AOGCC before gas injection into this well. *** 29. RU Slickli )k: 30. RIH and pull plug rrom 2-3/8" x-ianding nipple. POGH. LD plug. ball and Fed. RDslieldine. 31. iiiu injec[ion valve. RIH and set injection valve in 3-1/2" x -landing nipple. POOH. RD slickline. Attachments: 1. Actual Schematic 2. Proposed Schematic (new dated 1/28/2016) 3. BOPE Schematic 4. Current Wellhead Schematic S. Blank RWO Procedure Change Form fc? • ... 22. Test tubing to 4,600psi for 30min with chart. 23. Test casing to 3,500 psig for 30 min with chart. 24. LD landing joint. Set BPV. ND BOPE. NU Tree. Pull BPV 25. Set TWC. Test hanger to 250/5,000 psi. Test Tree to 250/5,000 psi. Pull TWC. 26. RD Saxon #169 Drill Rig. 27. Turn well over to Hilcorp Operations. .„6. ***A 10 -day notification must be made to AOGCC before gas injection into this well. *** 29. RU Slickli )k: 30. RIH and pull plug rrom 2-3/8" x-ianding nipple. POGH. LD plug. ball and Fed. RDslieldine. 31. iiiu injec[ion valve. RIH and set injection valve in 3-1/2" x -landing nipple. POOH. RD slickline. Attachments: 1. Actual Schematic 2. Proposed Schematic (new dated 1/28/2016) 3. BOPE Schematic 4. Current Wellhead Schematic S. Blank RWO Procedure Change Form fc? IIileorU Alaska, LL Well Prognosis Well: SCU 322C-04 Date: 1/28/2016 Zone Sand Top Btm (MD) Top Btm (TVD) SPF Status (MD) (TVD) Hemlock H1 -11,100' 11,300' 10,227' 10,359' 6 Proposed Hemlock H2 -11,300' 11,600' 10,359' 10,561' 6 Proposed a. Proposed perf interval shown on the proposed schematic. b. Final perfs tie-in sheet will be provided to the field for exact perf intervals. c. Correlate using Cement Bond Log (pending Tie-in log). d. Use Gamma/CCL to correlate. e. All perforations in table above are located in the Hemlock Pool based on Conservation Order No. 123B Rule S. 7. RU 4-1/2" Permanent Packer assembly. RIH w/ packer assembly and set packer at 11,000. Ensure Packer is set a minimum of 5' from collar. (Packer must be set within 200' of the open perforations per AOGCC regulations. ) Permanent Packer Assembly is as follows: a. WL entry guide b. X- Landing nipple (plug body loaded with plug) c. 4-1/2" Packer R. POOH 9. RD E -line. ure Test casir?u to 'I 940n ncia fear q� niirt i ith ch-Irt !I. MeAiteF flUi& iA well bE)Fe with eehemeteF a4eF peFfffatiRg @Ad while NU be" Ripple tG Rig flGeF. 12. Install necessary BOP equipment for running the completion and test (if not previously installed). a. Double ram should be dressed with 2-3/8" x 5" VBR in top cavity, blind ram in btm cavity. b. Single ram should be dressed with 2-3/8" x 5" VBR. c. Test any new BOP components (VBRs) to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min w/ 2-3/8" test joint and 4-1/2" as necessary. d. Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened. 13. LD BOP test equipment. 14. GentiRue tE) MeRiteF flUid level with eehemeteF and eASUFe well is stable, if fluid level is not stable fOF at least I hF With Fie gas to 0 �1 ateF. I 15. PU 4 1T2" hydFawlie pa (eF and completion jewelry and RIH w/ completion on new 6-i/2" 8RD EUE tubing, 2-7/8" 8rd EUE tubing and 2-3/8" supermax tubing. Minimize excess pipe dope when running completion.-Irculate with field produced water prior to anchoring completion in packer to clean tubing and casing. Ensure clean returns to surface. Circulate 6% KCI to surface , w/ inhibited fluid to be left on backside. Space out tubing. Set down completion into 4-1/2" permanent packer. Completion jewelry per proposed schematic: a. WL eet;Yguide b. X nipple (RHCP plug body leaded) e. 4 V2" Packel: d. Anchor Latch Assembly w/5' seals e. 2-7/8" x 2-3/8" crossover f. 7 7/8" Tubing LJa..gel: 2 Hileorp Alaska, LLC GL: 145' AMSL KB -18' 1 20" 30' 2 x �� 13-3/8" 3,005' CBLTOC Swanson River Unit Well: SCU 322C-04 PROPOSED SCHEMATIC PTD: 215-217 API: 50-133-10104-01 Existina Casine Detail Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20" Conductor - L-80 8rd EUE Surf. 30' —300 Yes Surf. 13-%" Surface 54.5 1-55 8RD Surf. 1,500' 31005' 1,100 sx Surf. DV Collar 1,500' 1,503' 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,290' Calc 7" Production 29 N-80 BTC Surf. 303' 9-%" 11,040' 650 sx 5,720' CBL 7" 26 303' 1,296' 7" 23 1,296' 4,793' 7" 26 4,793' 6,306' 7" 29 6,306' 7,509' DV Collar ' 7,509' 7,511' 4-1/2" 1 Liner 12.6 L-80 DWC/C 7,200 11,937' � 5,720' n; Type Wt Grade Conn ID Top Btm 3-1/2" r 9.3 L-80 8rd EUE 2.992' Surf —300 2-7/8" Tubing 6.4 L-80 8rd EUE 2.441" —300 —7,200' 2-3/8" Tubing 4.7 L-80 SuperMax x —7,200' 4 2.688" 5 4-1/2" x 2-3/8" Model D Perm Packer w/ anchor latch assembly w/ 5' seals t 2 0' above HI) 7 11,008' 1.875" 3.063" X— Landing Nipple 8 11,038 1.995" 3.063" WL Entry Guide a, r 7" DV Collar ' 7,509' � .a is x 1 , 6 0. 7 x.. 8 .l I H-1 H-2 4-1/2' 44 TD =11,937' PBTD =11,841' Max Deviation = 50 deg @ 9,102' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992' Surf —300 2-7/8" Tubing 6.4 L-80 8rd EUE 2.441" —300 —7,200' 2-3/8" Tubing 4.7 L-80 SuperMax 1.995" —7,200' `11,100' PROPOSED JEWELRY DETAIL NO. Depth ID OD Item 1 20' 2.992" 4.5" 3-1/2" Tubing Hanger 2 —300' 2.813" 4.5" 3-1/2" X— Landing Nipple (injection valve) 3 —310' 2.441" 3-1/2" x 2-7/8" Crossover 4 7,150' 1.995" - 2-7/8" x2-3/8" Crossover 5 7,200' 7" X 4-1/2" ZXP liner hanger 6 11,000' 2.688" 3.75" 4-1/2" x 2-3/8" Model D Perm Packer w/ anchor latch assembly w/ 5' seals t 2 0' above HI) 7 11,008' 1.875" 3.063" X— Landing Nipple 8 11,038 1.995" 3.063" WL Entry Guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-1 11,100' 11,300' 10,227' 10,359' 3-3/8" 6spf 60 deg H-2 11,300' 11,600' 10,359'10,561' 3-3/8" 6spf 60 deg Revised By CAH 1/28/16 THE STATE VI _ GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 322C-04 Permit to Drill Number: 215-217 Sundry Number: 316-047 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A— DATED this 28 day of January, 2016. Sincerely, Cathy P. oerster Chair RBDMS LL- JAN 2 9 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 07S i4i l 6 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: Completion/ Initial Perfs Q 2. Operator Name: Hilcorp Alaska, LLC 4. Current Well Class: 5. Permit to Drill Number: Exploratory ❑ Development ❑ Stratigraphic ❑ Service Q 215-217 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-133-10104-01 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 1238. Rule 5 Will planned perforations require a spacing exception? Yes ❑ No PI Creek Unit (SCU) 322G04 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028997 Swanson River Field ! Hemlock Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 11,937' 10,781' 11,867' 10,735' 100' N/A NIA Casing Length Size MD TVD Burst Collapse Structural Conductor 30' 20" 30' 30' Surface 3,005' 13-3/8" 3,005' 3,005' 2,730psi 1,130psi Intermediate Production 7,509' 7" 7,509' 7,507' 6,340psi 3,830psi Production 4,737' 4-1/2" 11,937' 10,781' 17,693psi 16,769psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A NIA NIA Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A N/A 12. Attachments: Proposal Summary Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch © Exploratory ❑ Stratigraphic ❑ Development ❑ Service Q 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: February 4, 2016 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑✓ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Joe Kaiser - 777-8393 Email tnasse hiicor .com Printed Name Chad Helgeson Title Operations Manager Signature Phone 907-777-8405 Date / Z(11 (� COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. /1 Plug Integrity El BOP Test T� Mechanical Integrity Test Location Clearance El Other: e 3 5-0 0 � — �F-�n.4Z50)(' , l/ Post Initial Injection MIT Req'd? Yes ❑ No ❑ / (,� Spacing Exception Required? Yes ❑ No Subsequent Form Required: /0— ` L) (�.t RBDMS LLJAN 2 9 2016 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Z8_� Submit Form and Form 10-403 R vised 11/2015N+& 1/2015+li O .lid for 12 mont from the date of approval. Attachments in Duplicate 5) Hilcorp Alaska, LLQ Well Prognosis Well: SCU 322C-04 Date: 1/21/2016 Well Name: SCU 322C-04 API Number: 50-133-10104-01 Current Status: Drilling in progress Leg: N/A Estimated Start Date: Upon Drilling TD Rig: Saxon 169 Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-217 First Call Engineer: Joe Kaiser (907) 777-8393 (0) (907) 952-8897 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: 1512837C Maximum Expected BHP: — 1,100 psi @ 10,400' TVD (Based on offsetwell PTA 1/6/2016) Max. Potential Surface Pressure: — 100 psi (Based on 0.1 psi/ft gradient to surface) Max. Gas Injection Pressure (post well work): 4,600 psi @ surface (Based on max compressor discharge) Brief Well Summary SCU 322C-04 is a gas injection well currently being sidetracked from SCU 314-04 to target H1/H2 gas injection in an effort to sweep production in this fault block. Based on recent drilling results, this zone does not appear to have been swept with the original gas flooding in Swanson River. The other producer in this zone and fault block (SCU 21C-04), does not have support (water flood, water driver, or gas injection) to accomplish maximum oil recovery. Objective: Perforate in the Hemlock formation (H1/H2) and run gas injection completion. Notes Regarding Wellbore Condition • Saxon 169 rigged up on well and currently drilling. C. • Pressure test 4-1/2" x 7" casing to 3,500 psig_will be completed. • Continue BOP testing frequency from Drilling Program (PTD 215-217) through completion. • Well full of 6% KCL fluid. • Step 17.2 of the drilling procedure may include drilling 40-60 ft of the 120' shoe track. OI - E -Line Procedure: 1. ** Continue from SCU 322C-04 (PTD 215-217) Drilling Program Step 18.1 2. MIRU E -line on drilling rig. 3. RIH and run Cement Bond Log from PBTD to —7200' MD (top of 45' liner . POOH. LD CBL tool. a. Send logs to town for correlation log. b. Final perf depths will be based on CBL results. 4. ND bell nipple and NU lubricator on top of BOP Annular preventer flange. PT lubricator to 1,500 psig for 10 min. 5. RU 3-3/8" 6spf wireline guns. 6. RIH and perforate the following intervals: IIilcorp Alaska, M Well Prognosis Well: SCU 322C-04 Date: 1/21/2016 Zone Sand (Mp) Btm (MD) (TVD) Top Btm (TVD) SPF Status Hemlock H1 —11,100' 11,300' 10,227' 10,359' 6 Proposed Hemlock H2 —11,300' 11,600' 10,359' 10,561' 6 Proposed a. Proposed perf interval shown on the proposed schematic. b. Final perfs tie-in sheet will be provided to the field for exact perf intervals. e� c. Correlate using Cement Bond Log (pending Tie-in log). d. Use Gamma/CCL to correlate. e. All perforations in table above are located in the Hemlock Pool based on Conservation Order No. 1238 Rule 5. 7. RD E -line. 8. Monitor fluids in well bore with echometer after perforating and while NU bell nipple to Rig floor. 9. Install necessary BOP equipment for running the completion and test (if not previously installed). a. Double ram should be dressed with 2-3/8" x 5" VBR in top cavity, blind ram in btm cavity. b. Single ram should be dressed with 2-3/8" x 5" VBR. c. Test any new BOP components (VBRs) to 250/3500 psi for10/10 min. Test annular to J �- 250/2500 psi for 10/10 min w/ 2-3/8" test joint and 4-1/2" as necessary. j d. Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened. 10. LD BOP test equipment. 11. Continue to monitor fluid level with echometer and ensure well is stable, if fluid level is not stable for at least 1 hr with no gas to surface, fill hole as necessary with filtered 6% KCL or field produced water. 12. PU 4-1/2" hydraulic packer and completion jewelry and RIH w/ completion on new 2-7/8" 8rd EUE tubing and 2-3/8" tubing. Minimize excess pipe dope wen running completion. Completion jewelry IJ� per proposed schematic: a. WL entry guide b. X -nipple (RHCP plug body loaded) c. 4-1/2" Packer ( << r `C_ d. 2-7/8 x 2-3/8 crossover s '5 r �� e. 2-7/8" Tubing Hanger 13. Space out packer at -11,000 ensuring packer is set a minimum of 5' from a collar. (Packer must be set within 200' of the open perforations per AOGCC regulations). re Zir Ate-- Z . q I Z C b� 14. Land tubing In hanger. Close the lockdown pinsZ 15. RU Slickline. L -P> 16. If well is full, attempt to reverse circulate well. 17. RIH and set RHCP ball and rod in loaded X -nipple. POOH. a. If well does not circulate, fill tubing w/ 6% filtered KCI. 18. Pressure up tubing to 3,000psi and set hydraulic packer. (fill casing with 6% inhibited fluid if hole is not full when packer is set) 19. Test tubing to 4,600psi for 30min with chart. nom' 20. Test casing to 3.500 psig for_30 min with chart. fi 2 Hilcorp Alaska, LL, Well Prognosis Well: SCU 322C-04 Date: 1/21/2016 21. RIH and pull ball and rod. RD slickline. 22. LD landing joint. Set BPV. ND BOPE. NU Tree. Pull BPV 23. Set TWC. Test hanger to 250/5,000 psi. Test Tree to 250/5,000 psi. Pull TWC. 24. RD Saxon #169 Drill Rig. 25. Turn well over to Hilcorp Operations. 26. ***A 10 -day notification must be made to AOGCC before gas injection into this well. *** Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Current Wellhead Schematic S. Blank RWO Procedure Change Form Ie- "E; V/S 3 Hileorp Alaska, LLC GL: 145' AMSL KB -18' 20" 30' 13-3/8" J-4 I a 3,005' I L CBLTOC 5,720' �; ►�. ACTUAL SCHEMATIC Swanson River Unit Well: SCU 322C-04 PTD: 160-021 API: 50-133-10104-00 Existing Casing nptail Type Wt Grade Conn Top Btm Hole Cmt Cmt Top Conductor - F20 Surf. 30' 3 7,200'— 11,937' Yes Surf. " Surface 54.5 1-55 8RD Surf. 1,500' 17-%" 3,005' 1,100 sx Surf. DV Collar 1,500' 1,503' 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,290' Calc 7" Production 29 N-80 BTC Surf. 303' 9-y"650 11,040 sx 5,720' CBL 7" 26 303' 1,296' 7" 23 1,296' 4,793' 7" 26 4,793' 6,306' 7" 29 6,306' 7,509' DV Collar 7,509' 7,511' PROPOSED JEWELRY DETAIL NO. Depth ID OD Item 1 7,200' 7" X 4-1/2" ZXP liner hanger 2 7,400' KOP 3 7,200'— 11,937' 4-1/2" 12.6# L-80 DWC/C k] 4-1/2" TD = 11,937' PBTD = 11,841' Max Deviation = 50 deg @ 9,102' Revised By MMM 10/29/15 '"w 1 "* 2 - KOP 7,400' above 7" DV collar T" DV ' :_� , r: Collar 7,509' ry*� a, r .ti k] 4-1/2" TD = 11,937' PBTD = 11,841' Max Deviation = 50 deg @ 9,102' Revised By MMM 10/29/15 Ilihrorp Ala..-ka. LLA: GL: 14V AMSL KB -18' 20" ++ 30' •' 13-3/8" 3,005' CBL TOC 5,720' ` �9 1, f ,•r 7" DV r Collar 7,509' ' H-1 ,mp h " H-2 4-1/2' it TO =11,937' PBTD =11,841' Max Deviation = 50 deg @ 9,102' Swanson River Unit Well: SCU 322C-04 PROPOSED SCHEMATIC PTD: 215-217 API: 50-133-10104-01 Existing Casing Detail Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20" Conductor - L-80 8rd EUE Surf. 30' ^300 Yes Surf. 13-%" Surface 54.5 J-55 8RD Surf. 1,500' 1700" 3,005' 1,100 sx Surf. DV Collar 1,500' 1,503' 13-%" Surface 11,100' J-55 8RD 1,503' 3,005' 600 sx 2,290' Calc 7" ProductionN-80 BTC Surf. 303' 9-�" 11,040 650 sx 5,720' CBL 7" M29 303' 1,296' 7" 1,296' 4,793' 7" 4,793' 6,306' 7" 6,306' 7,509' DV Collar 7,509' 7,511' 44/2" 1 Liner 12.6 L-80 DWC/C 7,200 11,937' L -7- TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 3-1/2" Tubing 9.3 L-80 8rd EUE 2.992" Surf ^300 2-7/8" Tubing 6.5 L-80 8rd EUE 2.441" "300 7,200' 2-3/8" Tubing 4.7 L-80 8rd EUE 1.995" 7,200' 11,100' PROPOSED JEWELRY DETAIL NO. Depth ID OD Item 1 20' - 3-1/2" Tubing Hanger 2 '"300' 2.813" 3-1/2" X- Landing Nipple -`A 3 `310' - 3-1/2" x 2-7/8" Crossover 4 7,150' - 2-7/8" x 2-3/8" Crossover 5 7,200' 7" X 4-1/2" ZXP liner hanger 6 11,000' 1.94" - 4-1/2" x 2-3/8" Hydraulic Packer (set max. 200' above ,d ) 7 11,008' 1.875" 3.063" X - Landing Nipple 8 11,038 1.995" 3.063" WL Entry Guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-1 11,100' 11,300' 10,227' 10,359' 3-3/8" 6spf 60 deg H-2 11,300' 11,600' 10,359' 10,561' 3-3/8" 6spf 60 deg Revised By JEK 1/26/16 20' 30' 13-3 3,0( CBL 5,7 7" 1 Col 7,51 Hilcoru Alaska, LLC GL: 145' AMSL KB -18' Swanson River Unit Well: SCU 322C-04 PROPOSED SCHEMATIC PTD: 215-217 API: 50-133-10104-01 Existine Casinh Detail Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20" Conductor - 1.94" - 4-1/2" x 2-3/8" Hydraulic Packer (set max. 200' above Hl) G `� 11,008' Surf. 30' 1.995" 3.063" WL Entry Guide Yes Surf. 13-%" Surface 54.5 J-55 8RD Surf. 1,500' 17-W' 3,005' 1,100 sx Surf. DV Collar 1,500' 1,503' 13-%" Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,290' Calc 7" Production 29 N-8 Z BTC Surf. 303' 9-%" 11,040' 650 sx 5,720 CBL 7" 26 303' 1,296' 7" 23 1,296' 4,793' 7" 26 4,793' 6,306' 7" 29 6,306' 7,509' DV Collar 1 7,509' 7,511' 4-1/2" 1 Li er X2.6 L-80 I DWC/C 7,200 11,937' F' TD = 11,937' PBTD = 11,841' Max Deviation = 50 deg @ 9,102' PROPOSED TUBING JEWELRY DETAIL Depth TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 2-7/8" Tubing 6.5 L-80 8rd ELIE 2.441" Surf 7,200' 2-3/8" Tubing 4.7 L-80 8rd EUE 1.995" 7,200' 11,100' TD = 11,937' PBTD = 11,841' Max Deviation = 50 deg @ 9,102' PROPOSED TUBING JEWELRY DETAIL Depth ID OD Item 20' 2-7/8" Tubing Hanger 7,150' 2-7/8" x 2-3/8" Crossover 7,200' 7" X 4-1/2" ZXP liner hanger 11,000' 1.94" - 4-1/2" x 2-3/8" Hydraulic Packer (set max. 200' above Hl) G `� 11,008' 1.875" 3.063" X - Landing Nipple 11,038 1.995" 3.063" WL Entry Guide PERFORATIONS v1 D) Btm(MD) Top(TVD) Btm(TVD) Notes )0' 11,300' 10,227' 10,359' 3-3/8" 6spf 60 deg )0' 11,600' 10,359' 10,561' 3-3/8" 6spf 60 deg Revised By JEK 1/21/16 Swanson River Unit BOPE SCHEMATIC SCU 322C-04BOP n�i.-.,��, v...►... i.t.�. 1/21/2016 Swanson River SCU 322C-04 Proposed 01/21/2016 Swanson River Tubing hanger, CW-C-EN- SCU 322C-04 CCL, 7 X 3 1/2 EUE 8rd lift 13 3/8 X 7 X 2 7/8 and 3 1/2 EUE susp, w/ 3" type H BPV profile, 5 % EN, Alloy material BHTA, Bowen, 3 1/8 5M FE X 3" Bowen top Valve, swab, FMC -120, 3 1/8 5M FE, HWO, DD � a trim • ® S\ �F . J ya\ ��` NAZI Valve, Wing, CIW-FC, ®, �y\00 Ja�ti\�c� aoQes' 3 1/8 5M FE, HWO, DD 5 X\A trim Valve, master, FMC -120, 3 1/8 5M FE, HWO, DD trim Valve, master, FMC -120, 3 1/8 5M FE, HWO, DD trim Adapter, CW, 7 1/16 5M X 3 1/8 5M, Completion spool, w/ 5 % seal pocket, 2- 1" Seaboard -S, NPT control line exits 7 1/16 5M FE X 7 1/16 5M FE, no outlets on head Tubing head, Shaffer T55 -L1, 13 5/8 5M X 7 1/16 5M, w/ 2- 2 1/16 5M SSO, 7" Type 1 secondary seal in head Valve, CIW-F, 2 1/16 SM FE, w O 2AA (k))H Qty Casing head, Shaffer KD, 13 5/8 3M X 13 3/8 SOW, w/ 2-2" LPO, 7" casing hung of with KD slips and packoff Zr� Valve plug, 2" LPO, HWO, assy r AA Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well SCU 322C-04 (PTD 215-217) Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call" engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date rirst can operations Engineer Date 'Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, January 26, 2016 4:44 PM To: 'Joe Kaiser' Cc: Chad Helgeson Subject: RE: 215-217 SCU 322C-04 Updated Proposed Schematic Joe, The MC valve in the 3 %' Tbg as proposed will work. I think the ID is about 1.38" if you use a Halliburton valve. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guy.schwartz@alaska.aov). From: Joe Kaiser [mailto:jkaiser@hilcoro.com] Sent: Tuesday, January 26, 2016 4:07 PM To: Schwartz, Guy L (DOA) Cc: Chad Helgeson Subject: PTD: 215-217 SCU 322C-04 Updated Proposed Schematic Guy, I appreciate the phone call earlier. Talking with Larry, I oversaw in the regulations that a gas injector needs to have a Sub -surface Safety Valve or Injection valve. I updated the Proposed Schematic to reflect a x -landing nipple for a gas injection valve. Also, will crossover to 3-1/2" tubing at the surface so that we don't have a restriction with the injection valve. If you have any further questions, please don't hesitate to contact me. Joe Kaiser KEN Operations Engineer Swanson River Field ikaiser@hilcorp.com 907-777-8393 Office 907-952-8897 Cell HALLIBURTON MC Injection Valves MC (flapper -type) injection valves are used in injection wells to automatically shut in the tubing string when injection stops or flow reverses. MC injection valves are spring-loaded, wireline -retrievable valves with large bores. The MC injection valves also feature sealing areas that are out of the direct flow path. These valves are designed to be held open by injection pressure for fluid passage. If injection flow becomes static or reverses for any reason, the spring and/or reverse flow causes the valves to close. These valves are designed to remain closed until pressure differential across the valves is equalized and injection is resumed. Applications • Injection wells Features • MC valves have sealing areas that are out of the direct flow path. Benefits • Valves designed to automatically shut in tubing string if injection is stopped or if flow reverses • Installed and retrieved by wireline under pressure • Designed to be set on various Halliburton lock mandrels • Can also be located on large bore intervention packers MC Injection halve MC Injection Valves (Flapper -Type Closure) - Top Sub - Orifice - Housing Flow Tube Flapper Ordering Information Specify: nipple bore and lock profile, service (standard, %H20, %CO2, amines), pressure rating and temperature, flow rate. Part Number Prefix: flapper-type-22MCR, MCX 9-32 Subsurface Safety Equipment owl, s .. ph (Box) in. MM in mm in. mm 11/2 38.10 1.500 X® 1.420 36.07 0.750 19.05 11/8-16 UN 2 50.80 1.875 X 1.760 44.70 0.610 20.57 13/8-14 UN 21/2 63.50 2.313 X 2.180 55.37 1.000 25.40 1 3/4-12 UN 31/2 88.90 2.562 R° 2.310 58.67 1.000 25.40 2-12 SLB 88.90 2.750 X 2.620 66.55 1.380 35.05 2 114-12 SLB 4 101.60 3.313 X 3.270 83.06 1.830 46.48 2 3/4-12 SLB 41/2 114.30 3.688 R 3.430 87.12 1.380 35.05 3 1/16-12 SLB 114.30 3.813 X 3.710 94.23 2.000 50.80 3 1/16-12 SLB 5 127.00 4.125 X 3.880 98.55 2.000 50.80 3 1/4-12 SLB 51/2 139.70 4.562 X 4.420 112.27 2.620 68.55 4-12 SLB 7 1 177.80 5.962 R 5.900 1 149.86 3.500 1 88.90 1 5 1116-8 SLB Ordering Information Specify: nipple bore and lock profile, service (standard, %H20, %CO2, amines), pressure rating and temperature, flow rate. Part Number Prefix: flapper-type-22MCR, MCX 9-32 Subsurface Safety Equipment �Ct 3z2C— 04 016-2170 Regg, James B (DOA) From: Rance Pederson - (C) <rpederson@hilcorp.co > Sent: Saturday, January 23, 2016 12:04 PM v� 4 To: Regg, James B (DOA) `y( Subject: Update on Saxon BOP Closure Jim, we pulled BHA out of hole yesterday for a bit change. Prior to trip back in hole, we did test our annular at 250/2500 psi, and the auto choke at 1500 psi. No issues with either test. Rance Pederson Drilling Foreman Swanson River 907-776-6776 P_"') z45_z47 Regg, James B (DOA) From: Marvin Rogers - (C) <mrogers@hilcorp.com> Sent: Thursday, January 21, 2016 6:26 AM ) Z,I14, To: Regg, James B (DOA) i�g 11 Subject: Saxon 169 notice of BOP Use Attachments: Saxon 169 Notice of BOP Use.docx I 1-lilcorp Alaska, LLC DSM Saxon Rig 169 [907] 776-6776 E -Mail: mrogers@hilcorp.com tu ffihc rrjs LM Notice of BOP Use • Date/Time: 1/21/2016 at 01:00 hrs. • Well: SCU 322C-04 - • Location: Swanson River Field, Pad SCU 14-04 • PTD: 215-217 • Rig Name: Saxon 169 -- • Operator Contact: Marvin Rogers at 907-776-6776 / mrogers@hilcorp.com • Operation Summary: Drilling 6" production hole at 7565' md. Current mud weight was 9.8 ppg, background gas was 100 units. While drilling ahead, Driller noticed increase in gas from 100 units to 1186 units, and flow show from 25% to 33%. Driller then shut down pump and shut in well, while sounding the well control horn. • BOPE Used: Annular and auto choke valve. • Reason For BOPE Use: Flow show increased from 25% to 33% in a matter of seconds and a 1 bbl gain to pits, along with the increase in gas reading at shakers. • Actions Taken: Monitored SICP and SIDP, lined up and circulated one full circ through choke and poorboy degasser vessel to circ out gas. After one full circ at slow pump rate, checked for flow and had no flow. Opened well and circulated to 9.9 ppg mud. After flow check, continued drilling ahead. • Action To Be Taken: At this time, we plan to drill to TD, then test all components used during shut-in, prior to running Production Liner. If for any reason we need to make a bit trip etc, those components will be tested prior to trip in hole with drilling assembly. THE STATE 01ALASKA GOVERNOR BILL WALKER Monty Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil d Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Swanson River Field, Hemlock Oil Pool, SCU 322C-04 Hilcorp Alaska, LLC Permit No: 215-217 Surface Location: 823' FSL, 780' FWL, SEC. 4, T7N, R9W, SM, AK Bottomhole Location: 1856' FNL, 2044' FWL, SEC. 4, T7N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for permit to redrill the above referenced service well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy . Foerster Chair DATED this Zisday of December, 2015. AECENEU STATE OF ALASKA AL (A OIL AND GAS CONSERVATION COMM, )N NOV 2 O 2015 PERMIT TO DRI�� 20 AAC 25.005 r2 -`r 1 a. Type of Work: 1 h. Proposed Well Class: Exploratory - Gas ❑ Service -WAG/ ❑ Service - Disp ❑ 1c. Specify if well is proposed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service Single Zone ❑✓ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑Service -upply ❑ Multiple Zone [I Geothermal El Shale Gas F-1 2. Operator Name: 5. Bond: Blanket Q Single Well ❑ •�Q 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 02 24-�'35Z4/ SCU 322C-04 3. Address: 6. Proposed -Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 11,937'* TVD: 10,800' Swanson River Field Hemlock Oil Pool . 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 823' FSL, 780' FWL, Sec 4, T7N, R9W, SM, AK FEDA028997 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 2343' FNL, 1891' FWL, Sec 4, T7N, R9W, SM, AK N/A 1/1/2016 Total Depth: 9. Acres in Propertv: 14. Distance to Nearest Propertv: 1856' FNL, 2044' FWL, Sec 4, T7N, R9W, SM, AK 2560 4520' from Unit Boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 163 15. Distance to Nearest Well Open Surface: x- 343081.9 y- 2456758.8 , Zone -4 GL Elevation above MSL (ft): 145 - to Same Pool: 737' from SCU 226-04 16. Deviated wells: Kickoff depth: 7400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 49 degrees Downhole: 4863'`2 €?C j7 Surface: 1728 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) 6" 4-1/2" 12.6 L-80 DWC/C 4,737' 7,200' 7,200' 11,937' 10,800' 642.4 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 11,520' 11,520' 10,281' 10,281' 10,281' 10,296' Casing Length Size Cement Volume MD TVD Conductor/Structural 30' 20" Yes 30' 30' Surface 2,988' 13-3/8" 1700 sx 3,005' 3,005' Intermediate Production 11,024' 7" 1300 sx 11,041' 11,041' Liner Perforation Depth MD (ft): See Attached Schematic Perforation Depth TVD (ft): See Attached Schematic 20. Attachments: Property Plat ❑✓ BOP Sketch ❑✓ Drilling Program ❑✓ Time v. Depth Plot ❑' Shallow Hazard Analysis❑✓ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements❑ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Monty Myers Email mm ers hilcor .com Printed Name Monty Myers Title Drilling Engineer Signature Phone 907-777-8431 Date 11/17/2015 Commission Use Only Permit to Drill c �� `� �� 7 API Number: /01n "6 "— Permit Approval 0 I ) I See cover letter for other Number: d 50-/_55 Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Q Other: A- -350D loS " 4361 lm Samples req'd: Yes ❑ No 4 Mud log req'd: Yes ❑ No / Spacing H2S measures: Yes ❑ Nog Directional svy req'd: Yes Q No ❑ exception req'd: Yes E]No[� Inclination -only svy req'd: Yes ❑ Nof Post initial injection MIT req'd: Yes ❑ No❑ —YieUU�w/�Q/- t (� l'{`J� Approved by: APPROVED BY COMMISSIONER THE COMMISSION Date: 1 L'j7 f Submit Form and Form 10-401 (Revised 11/20 OTRT r 1 N f 2 months fro the date of ppceval (20 AAC 25.005(g)) Attach me is in Duplicate L I 0 Hilcorp Energy Company 11/20/2015 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7t" Avenue Anchorage, Alaska 99501 Re: SCU 322C-04 Monty Myers Drilling Engineer Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8431 Email mmyers@hilcorp.com NOV 2 0 2015 Dear Commissioner, / z( SCU 322C-04 is a gas injection well planned to be re -drilled in a North-easterly direction from the existing SCU 314-04 utilizing the existing casing program down to 7400' MD / 7400' TVD. At 7400' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 4537'x 6" open hole section is planned. A 4-1/2" 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 2-7/8 X 2-3/8" production string. Drilling operations are expected to commence approximately January 1st, 2016. If you have any questions, please don't hesitate to contact myself at 777-8431 or Paul Mazzolini at 777-8369. Sincerely, Monty Myers Drilling Engineer Hilcorp Alaska, LLC Page i of 1 SCU 42A-05 \ 42-05 SCU-1 SCU-21A-04 U_41-05 SCU 21C-04 SCU-42-05Y / SCU-42-0 S � 42-05X_vT,/ S 42B � SCU_ 5SC SCU-13-04 o SCU_4**05 SCU 44-05 i '10,784 PL -44A-05 1 0 134-05 �ru� pjG Ste, 12A-04 SCU 21-04 2213-0iSCU-31-04— 0,782 10,902 -04 7'W_22-04PB 10,390 / 10,459 PL_SCU_2*04 (?ST) s SCU 4�1 SCU_41137W SCU SCU 34304-04� 10,229-- 10,304; SCU-243-04 \O HILCORP ALASKA, LLC Swanson River SCU 322C-04 Gas Injector 1/4 Mile Radius Map 0 500 1000 1500 FEET REMARKS Top of Hemlock Bench 1 in blue; base of Hemlock Bench 2 in red. All depths in MD 1-1 SLcA- 32Z C_0 PTD/ Please see below for reason to inject gas over water. The proposed gas flood within the AOR is targeting a combination stratigraphic / fault trap that didn't get effectively swept during the Swanson River gas flood resulting in high residual oil saturations. This area is connected to an extremely weak aquifer with diminishing rock quality going down dip thereby providing minimal energy to sweep the remaining oil. Both gas and water injection were evaluated for secondary recovery efficiency and gas injection was chosen for these reasons: 1) Good analog of historic gas flood at Swanson River resulting in >40% recovery factor in fault blocks with sufficient well density. 2) Technical analysis indicates that the swelling effect from gas contact recovers over 25% more oil than water. 3) Permeability is known to be decreasing down dip & injectivity of water is expected to be low. Gas injection in the lower perm rock will enable injection of sufficient reservoir barrels to support offset producers. 4) High pressure gas injection infrastructure is currently in place on pad resulting in minimal disturbance to the refuge. Area of Review SCU 322C-04 CBL Top of CBL Top of PTD API WELL STATUS Top of H1(MD) Top of H3 (TVD) Base of H2 (MD) Base of H2 (TVD) Cement (MD) Cement (TVD) 1-13/1-12 Status Zonal Isolation CBL TOC . P&A'd &side tracked. 161-001 50-133-10103-00 SCU 12-04 P&A 10345 10343.77 10414 10412.76 7,240 7,239 Perfed & Abandoned New welll SCU 12A-04. Hl, H2, H3, H8 open. G-2 zone open 174-021 50-133-10103-01 SCU 12A-04 Active Producer 10372 10348.42 10448 10422.24 8,500 8,499 Active/open in both perfsat10,284' MD 214-169 50-133-20276-02 SCU 21C-04 Active Producer 11353 10302.72 11476 10385.1 10,384 9,705 Active in both CBL TOC 10,384' on 12-11-2014.981' of good cement above Hl perfs. PB 7/10/14 with cement retainer and 199-083 50-133-10106-01 SCU 22-04 (ST 323-4) P&A 10381 10377.16 10474 10447.16 N/A N/A Never perfed squeezed into H4/5zone toabandon for the side track of SCU 31-4. Cemented from TD of 11,140' MD to 199-083 50-133-10106-01 SCU 22-04PB P&A 10384 10377.55 10480 10440.39 N/A N/A Never perfed Cement Retainer at 9,450' MD with 1.5 bbls cement on top of retainer. Bridge Plug set at 9,162'. No casing. CBLTOC at 10,280' MD. H-7 only open 214-021 50-133-10105-02 SCU 228-04 Active Producer 10782 10327.25 10902 10411.83 10,280 10,009 Neither is perfed perf at 11,254' MD. CBL TOC at 9,273' MD. H-5 open pertat 214-090 50-133-10106-02 SCU 31-04 Active Producer 11120 10331.04 11239 10382.55 9,273 9,271 Neither is perfed 11,444' MD TOC at 9,438'MD bottom 9, 214-090 50-133-10106-02 SCU 31-04PB1 P&A 11200 10335.75 11333 10386.95 N/A N/A Never perfed Cement KO plug on top of abandoned drilling BHA. No Casing. CBL TOC 10,398'. Previous injector, Hemlock 1-12-1-18 open, G2 Sand 161-013 50-133-10106-00-00 SCU 323-04 P&A 10,390 10,389 10,450 10,449 10,398 10,397 Perfed & Abandoned sqeezed and plugged back in 1999 for the SCU 22-04 sidetrack. CBL TOC at 10,342'. P&A'd to surface. 161-024 50-133-10114-00 SCU 41-05 P&A 10908 10637.08 10971 10697.71 10,342 10,104 Only perfed & CIBP at 180' MD (hl penetration Abandoned ned outside of AOR) Area of Review SCU 322C-04 kc,-zl 30-133 iv3iY- >`-f P�`` I CBL Top of PTD API WELL STATUS Top of H1 (MD) Base of H2 (MD) Cement (MD) 1-11/1-12 Status Zonal Isolation 161-001 50-133-10103-00 SCU 12-04 P&A 10345 10414 7,240 Perfed & Abandoned CBL TOC 7,240. P&A'd & side tracked. New well SCU 12A-04. 174-021 + 50-133-10103-01 SCU 12A-04 Active Producer 10372 10448 8,500 Active/open in both H1, H2, H3, H8 open. G-2 zone open perfs at 10,284' MD 214-169 50-133-20276-02 SCU 21C-04 Active Producer 11353 11476 10,384 Active in both CBL TOC 10,384' on 12-11-2014. 981' of good cement above H1 perfs. 199-083 50-133-10106-01 SCU 22-04 (ST 323-4) P&A 10381 10474 N/A Never perfed PB 7/10/14 with cement retainer andsqueezed into H4/5 zone to abandon for the side track of SCU 31-4. Cemented from TD of 11,140' MD to 199-083 50 133 10106 SCU 22-04PB P&A 10384 10480 N/A Never perfed Cement Retainer at 9,450' MD with 1.5 bbls cement on top of retainer. Bridge Plug set at 9,162'. No casing. 214-021 50-133-10105-02 SCU 2213-04 Active Producer 10782 10902 10,280 Neither is perfed CBL TOC at 10,280' MD. H-7 only open perf at 11,254' MD. 214-090 " 50-133-10106-02 SCU 31-04 Active Producer 11120 11239 9,273 Neither is perfed CBL TOC at 9,273' MD. H-5 open perf at 11,444' MD 214-090 50-133-10106- SCU 31-04PB1 P&A 11200 11333 N/A Never perfed TOC at 9,438' MD bottom 9,630'. Cement KO plug on top of abandoned drilling BHA. No Casing. CBL TOC 10,398'. Previous injector, 161-013 50-133-10106-00-00 SCU 323-04 P&A 10,390 10,450 10,398 Perfed & Abandoned Hemlock H2 -H8 open, G2 Sand sgeezed and plugged back in 1999 for the SCU 22-04 sidetrack. CBL TOC at 10,342'. P&A'd to surface. 161-024 50-133-10114-00 SCU 41-05 P&A 10908 10971 10,342 Only H1 perfed & CIBP at 180' MD (h1 penetration Abandoned outside of AOR) kc,-zl 30-133 iv3iY- >`-f P�`` I Hilcorp Alaska, LLC SCU 322_C-0_4 (SCU 314-04 ST) Drilling Program Soldotna Creek ro d by: M My Revision 0 October 28, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ilib-orp ;VaAa, LLC Contents 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program............................................................................................................................4 4.0 Drill Pipe Information.....................................................................................................................4 .......................................................................................................35 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling Summary............................................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................11 10.0 BOP N/U and Test.........................................................................................................................12 11.0 Mud Program and Density Selection Criteria............................................................................13 12.0 Whipstock Running Procedure....................................................................................................14 13.0 Whipstock Setting Procedure.......................................................................................................17 14.0 Drill 6" Hole Section......................................................................................................................19 15.0 Run 4.5" Production Casing.........................................................................................................22 16.0 Cement 4.5" Production Casing...................................................................................................25 17.0 Wellbore Clean Up & Displacement............................................................................................29 18.0 Run Completion Assembly...........................................................................................................30 19.0 RDMO............................................................................................................................................30 20.0 BOP Schematic..............................................................................................................................31 21.0 Wellhead Schematic......................................................................................................................32 22.0 Days vs Depth.................................................................................................................................33 23.0 Geo-Prog.........................................................................................................................................34 24.0 Anticipated Drilling Hazards .......................................................................................................35 25.0 Rig Layout......................................................................................................................................36 26.0 FIT Procedure................................................................................................................................37 27.0 Choke Manifold Schematic...........................................................................................................38 28.0 Casing Design Information...........................................................................................................39 29.0 6" Hole Section MASP..................................................................................................................40 30.0 Plot (NAD 27) (Governmental Sections)......................................................................................41 31.0 Surface Plat (As Built) (NAD 27).................................................................................................42 32.0 Surface Plat (As Built) (NAD 83).................................................................................................43 33.0 Directional Program(P1)..............................................................................................................44 SCU 322C-04 Drilling Procedure Rev 0 Ildvorp.UaAa. LIA: 1.0 Well Summary Well SCU 322C-04 Pad & Old Well Designation Sidetrack of existing well SCU 314-04 (PTD# 160-021) Planned Completion Type 4-1/2" 12.6# L-80 Liner Target Reservoir(s) Hemlock H1 and H2 Injection ' Planned Well TD, MD / TVD 11937' MD / 10800' TVD PBTD, MD / TVD 11867' MD / 10732' TVD Surface Location (Governmental) 823' FSL, 780' FWL, Sec 4, T7N, R9W, SM, AK Surface Location (NAD 27) X=343081.914, Y=2456758.863 Surface Location (NAD 83) X=1483104.600, Y=2456520.128 Top of Productive Horizon (Governmental) 2343' FNL, 1891' FWL, Sec 4, UN, R9W, SM, AK TPH Location (NAD 27) X=344213.8, Y=2458863.9 TPH Location (NAD 83) X=1484236.567, Y=2458625.178 BHL (Governmental) 1856' FNL, 2044' FWL, Sec 4, T7N, R9W, SM, AK BHL (NAD 27) X=344372.78, Y=2459349.69 BHL (NAD 83) X=1484395.562, Y=2459110.971 AFE Number 1512837D AFE Drilling Das 27 AFE Drilling Amount $3.79 MM Work String 4-1/2" 16.6# S-135 CDS-40 RKB — AMSL 18' KB — 163.1' AMSL Ground Elevation 145.1' AMSL BOP Equipment 11" 5M T3 -Energy (Model 7082) Annular BOP 11" 5M T3 -Ener (Model 6011i) Double Ram 11" 5M T3 -Ener (Model 6011i) Single Rain Page 2 Revision 0 October, 2015 2.0 Management of Change Information SCU 322C-04 Drilling Procedure Rev 0 Hilcorp Alaska, LLC Hilcorp Eoagy Compoey Changes to Approved Permit to Drill Date: October 29, 2016 Subject: Changes to Approved Permit to Drill for SCU 322C-04 (SCU 314-04 ST) File #: SCU 322C-04 (SCU 314-04 ST) Drilling Program Any modifications to SCU 322C-04 Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the BLM and AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved Approved By By Approval: Prepared: Drilling Manager Drilling Engineer Date Page 3 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililcorp Alaska, LLC 3.0 Tubular Program Hole Section OD in Wt(#/ft) Cou 1 OD ID in Drift in Grade Conn Top Bottom 6" 4-1/2" 12.6 5.0" 3.918 3.833 L-80 DWC/C 7400 11937 595k 4.0 Drill Pipe Information Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section in in #/ft(psi) (psi) (k -lbs) 6" 4-1/2" 3.826 2-11/16" 5-1/4" 16.6 S-135 CDS-40 17693 16769 595k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Hile—jo .UaAa. LIA: 5.0 Internal Reporting Requirements 19.1 Fill out daily drilling report and cost report on Wellez. i. Report covers operations from 6am to 6am ii. 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. iii. Ensure time entry adds up to 24 hours total. iv. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 19.2 Afternoon Updates i. Submit a short operations update each work day to pmazzolini@hilcorp.com, Ikeller e,hilcorp.com, mmyers@hilcorp.com and cdingerAhilcorp.com 19.3 5am Weekend Update i. Submit a short operations update each weekend and holiday to whoever is assigned weekend or vacation duty. Details will be sent before each weekend or holiday. ii. Copy pmazzolinighilcorp.com, Ikeller e,hilcorp.com and mmyers@hilcorp.com 19.4 EHS Incident Reporting i. Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Mark Tornai: O: (907) 283-1372 C: (907) 748-3299 c. Thad Eby: O: (907) 777-8317 C: (907) 602-5178 2. Spills: Julieanna Orczewska: 0:907-777-8444 C:907-715-7060 ii. Notify Drlg Manager 1. Paul Mazzolini: O: 907-777-8369 C: 907-317-1275 iii. Submit Hilcorp Incident report to contacts above within 24 hrs 19.5 Casing Tally i. Send final "As -Run" Casing tally to mmyersghilcorp.com and cdinger@hilcorp.com 19.6 Casing and Cmt report i. Send casing and cement report for each string of casing to mmyers(cr�hilcorp.com and cdingerghilcorp.com Page 5 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 IIilvorp Alaska, LLC 6.0 Planned Wellbore Schematic Swanson River Unit Well: SCU 3220-04 PROPOSED SCHEMATIC PTD: 160-021 IIik4wp Aln.ki, LLC API: 50-133-10104-00 GL•14S'AMSL Existing Casing Detail KB -18' 20"- 30, 13-3/9', 3.005' CBLTCK 5,720 PROPOSED I EWELRY DETAIL NO. Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Tc 7,200'-11,937' 20` I Conductor Surf. 30' Yes Surf - 13 -if" Surface 54 5 J -s5 SRO sl rr. 1,500 DV' Collar -- 1,503' 17-Y 3,005' 1,100 sx Surf,1,SOOr 13-W Surface 54.5 1 -SS BRD 1,503' 3,005" 600 sm 2,290' C: 7" 29 Start 303' 7" 26 3" 1 . 7" 23 Production N -BO BTC 1,296' 4,793' 9-h" 5,720' 4,793' 6,306' MOW 650 ss CBL 7" 26 7" 29 6,306' 7,509' OAf collar 7509' 7.511' PROPOSED I EWELRY DETAIL NO. Depth ID 00 Item 1 7,200' 7' X 4-1/2" 2XP liner hanger 2 7AW. KOP 3 7,200'-11,937' 4-1/2" 12.611L-8D0WC/C 1 2 - KOP "`7,400" above 7' DV collar .Jro- 6 `{ ©0- 3 TD=11,937' PBM =11,841' P.tax DEviatbon = 50 deg @ 9,102' Page 6 Revision 0 October, 2015 1614-orp nla4a- LLA: RK8: 160'/ GL: 145' AMSL KB -THF: 17.0' 20" 30' ,1 13-3/8-- 3-3/8"•3,005' 3,005' Type Wt Grade CBL TOC Top Btm Hole 5,720' + Cmt Top 20" P ' - �Frrrs,�zi ' Surf. 30' 2-1/4" PowerJet Yes Surf. 13 '%" Surface 54.5 1.55 8R0 Surf- AV 3,005005'' 1 1,100 sx Surf. DV Collar C8L TOC 13-%," Surface 54.5 J-55 9,105' 1,503' 3,005' 600 sx 2,290' Calc 7" Production �px N-80 BTC Surf. 303' 9 11,040' 650 sx 5,720' CBL k 303' 1,296' �r 1,296' 4,793' 7" - 4,793' 6,306' 7" 6,306' 7,509' DV Collar _ _ -- -- 7,509' 7,511' c+r Production Y N-80 BTC 7,511' 7,996' ---- 650sx - --- 9,105' CBL 7" 26 p-110 8RD 7,996' 9,654' CBL TOC 29 9.654' 9,662' 7" 10,122' 9,662' 9,705' 7" 29 '.°acf 8/08/60 H-10 10,588' Tubing Detail 10,588' G-1 67' v CplgCD 3.5" Tubing 7 N-80 / T,%' 3 Surface H-1 ! v,- 3.915" 3.5" H-1 9.3 N-80 8RD H-2 10,141' 2.992" H-3 H-5 H-7 ' H-7 H-10 7' H-10 11,040' ` a TD = 11,520' P8TD = 10,850' Max Deviation = 2.75 deg @ 7,147' Downhole Revised: 6/08/05 Swanson River Unit Well: SCU 314-04 PROPOSED SCHEMATIC Completion Ran: 6/02/2005 PTD: 160-021 API: 50-133-10104-00 Carina nptail Size Type Wt Grade Conn Top Btm Hole Cmt Cmt Top 20" P Conductor - 10,207' 10,256' Surf. 30' 2-1/4" PowerJet Yes Surf. 13 '%" Surface 54.5 1.55 8R0 Surf- 1,500' 3,005005'' 1 1,100 sx Surf. DV Collar 1,500' 1,503' 13-%," Surface 54.5 J-55 8RD 1,503' 3,005' 600 sx 2,290' Calc 7" Production 29 26 23 - 26 29 N-80 BTC Surf. 303' 9 11,040' 650 sx 5,720' CBL 7" 303' 1,296' 7" 1,296' 4,793' 7" - 4,793' 6,306' 7" 6,306' 7,509' DV Collar _ _ -- -- 7,509' 7,511' 7" Production 29 N-80 BTC 7,511' 7,996' ---- 650sx - --- 9,105' CBL 7" 26 p-110 8RD 7,996' 9,654' _7" 29 9.654' 9,662' 7" 26 9,662' 9,705' 7" 29 9,705' 11,040' 8/08/60 H-10 10,588' Tubing Detail 10,588' 10,655' 67' Conn ID CplgCD 3.5" Tubing 9.3 N-80 CS Hyd Surface 9,961' 4 2.920" 3.915" 3.5" Tubing 9.3 N-80 8RD 9,961' 10,141' 2.992" 4.500" JPwplry nptail No. Depth Length ID OD Item 1 i J.1 •' , Cast Iron Bridge Plug (Prcpr)seclj 2 10,281' HES "EZ" Drill Cmt Retainer (Set on wireline 5/31/05) 3 10,296' Junk SAB Packer (Milled and Pushed to depth) Perforation History Date Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments 6/08/05 G-1 10,207' 10,256' 10,207' 10,256' 49' 6 2-1/4" PowerJet 8/10/60 H-1 10,291' 10,297' 10,291' 10,297' 6' 4 8/10/60 H-1 10,302' 10,306' 10,302' 10,306' 4' 4 1/14/00 H-2 10,318' 10,333' 10,318' 10,333' 15' 6 Reperf 1/14/00 8/10/60 H-3 10,354' 10,365' 10,354' 10,365' ill 4 1/14/00 H-5 10,376' 10,432' 10,376' 10,432' 56' 6 Reperf 1/14/00 8/09/60 H-7 10,450' 10,456' 10,450' 10,456' 6' 4 1/14/00 H-7 10,464' 10,545' 10,464' 10,545' 81' 6 Reperf 1/14/00 8/08/60 H-10 10,588' 10,655' 10,588' 10,655' 67' 4 8/07/60 H-10 10,670' 10,674' 10,670' 10,674' 4' 4 Revised By 1EK 11/20/15 SCU 322C-04 Drilling Procedure Rev 0 Ililvorp Alaska. 1.1.1: 7.0 Drilling Summary SCU 322C-04 is a gas injection well planned to be re -drilled in a North-easterly direction from the existing SCU 314-04 utilizing the existing casing program down to 7400' MD / 7400' TVD. At 7400' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 4537' x 6" open hole section is planned. A 4-1/2" 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 2-7/8 X 2-3/8" production string. Drilling operations are expected to commence approximately January 1 st, 2016. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and for running the completion assembly SIS---719- General General sequence of operations pertaining to this approved drilling procedure: 1. MOB Saxon Rig #169 to SCU 314-04. 2. Kill well, Set BPV, ND tree, NU BOPE and test. yds 3. BOLDS, Pull hanger and LD 3-1/2" tubing completion. vv 4. RU E -line to set CIBP. RIH w/ CIBP and set at 7400' (5' above a collar) 5. RD E -line and test casing/CIBP to 3500 psi Opt `, 6. PU 6.059" window milling assembly and DP and cleanout to CIBP 7. POOH standing back, PU Whipstock, and mills and TIH to CIBP 8. Orient whipstock and set at 45 deg azimuth. Mill 6" window an of new torma ion at 74000. 9. Perform FIT to 11.5 ppg ✓ 10. Drill 6" production hole from 7400' to 11937' MD. 11. Perform short trip and condition mud. POOH 12. LD Directional Tools. RIH w 4-1/2" liner. Set liner and cement. Circ wellbore clean. /��t/�/ 13. POOH, laying down DP and liner running tools, 14. PU 4-1/2" casing scraper assembly and TIH to landing collar. 15. Circ casing clean. POOH laying down DP. c e L 16. Run 2-7/8" X 2-3/8" upper completion. Land hanger and test. 17. ND BOPE, NU tree and test void 18. RDMO Page 7 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ildcorp %Ia.Aa. LLC. 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 of SCU 322C-04. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 10/10 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 both AOGCC and BLM approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: • Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16" 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 8 Revision 0 October, 2015 110corp \la,ka.. HA: Summary of BOP Equipment and Test Requirements SCU 322C-04 Drilling Procedure Rev 0 Hole Section Equipment Test Pressure(psi) • I I" x 5M T3 -Energy (Model 7082) Annular BOP • 11" x 5M T3 -Energy Double Ram Initial Test: 250/3500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 6" • 11" x 5M T-3 Energy Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: • 2-1/16" x 5M Kill line 250/3500 • 3-1/8" x 2-1/16" 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. 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. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and cmt operations • 48 hours before BOPE tests • 48 hours before logging, coring, & testing • Any other notifications required in APD. Additional requirements may be stipulated on APD. Page 9 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Hilcorp Alaska, LLC Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector/ (0): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer/ (0): 907-793-1226 / (C): 907-301-4533 / Email: g_uy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: httl2:Hdoa.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) BLM Amanda Eagle / BLM Petroleum Engineer / (0): 907-271-3266 (C): 907-538-2300 Email: aeagleAblm.gov Mutasim Elganzoory / BLM Petroleum Engineer / (0): 907-271-4224 Email: melganzooiy@bltn.gov Use the below email address for BOP notifications to the BLM: BLM AK AKSO EnergySection Notifications@bhn.gov Page 10 Revision 0 October, 2015 9.0 R/U and Preparatory Work SCU 322C-04 Drilling Procedure Rev 0 9.1 A separate sundry will be submitted that will include the following: • P&A lower erfs with a cement plug • Cut tubing jot_" `� 1 9.2 Level pad and ensure enough room for layout of rig footprint and R/U. 9.3 Layout Herculite on pad to extend beyond footprint of rig. 9.4 R/U Saxon Rig #169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.5 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.6 Mix mud for 6" hole section. 9.7 Check wellhead for pressure 9.8 Load well with 8.4 ppg KWF 9.9 Set BPV 9.10 Nipple down tree 9.11 Set test Plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.12 Verify 5" liners installed in mud pumps. • HHF-1000 Pumps are rated at 3457 psi (80%) with 5" liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 6" hole section with (1) mud pump. Page 11 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililrorp Alaska, LLC. 10.0 BOP N/U and Test 10.1 * BOPE was NU and tested on prior decompletion sundry. We will test BOPE on 7 day cycle until the window is milled, at that point we will switch to the 14 day test cycle. Continue on to step 11. 10.2 N/U 11"x 5M BOP as follows: • BOP configuration from Top down: 11" x 5M annular BOP/11" x 5M double ram/1 I" x 5M mud cross/11" x 5M single ram. • Double ram should be dressed with 2-7/8" x 5" VBR in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8" x 5" VBR. • N/U bell nipple, install flowline. 10.3 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. • Ensure to leave `°ion side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened!!! ! • Test VBRs on 4-1/2" test joint. • Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.4 R/D BOP test assy. 10.5 Continue mixing mud for 6" hole section. 10.6 Set wearbushing in wellhead. Ensure ID of wearbushing > 7". Page 12 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 11ilrorp Alaska. 1,1.1: 11.0 Mud Program and Density Selection Criteria 11.1 6" Production hole mud program summary: Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. Pason 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. System Type: 9.5 ppg 6% KCl/PHPA fresh water based drilling fluid. Properties: MD Density Viscosity Plastic Viscosity Yield Point pH AN Fluid Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP Loss 7400' — 1 1937' 9.5-11.5 40-53 15-25 15-25 8.5-9.5 <6.0 System Formulation: 6% KCI / EZ Mud DP Product Concentration Water 0.905 bbl KCI 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb SOLTEX 2 ppb (if needed) BAROID 41 as required for a 9.5 —10.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate 11.2 Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could . require mud weights for hole stabilization. 11.3 A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Page 13 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ilileorp %IaAa, IJ.1: 12.0 Whipstock Running Procedure 12.1 M/U window milling assembly and TIH w/ 4-1/2" DP off of pipe rack. • Use a 6" taper mill and a 6" string mill above to ensure whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. • Drift DP prior to RIH. • Lightly wash and ream any tight spots noted. 12.2 TIH to CIBP (7430' MD). Note that this . a wireline measurement so actual depth tagged may vary slightly. Keep up with the # of joints picked up so we know where we are. 12.3 Pressure test casing to 2500 psi / 30 min. Chart record casing test & keep track of the amount of fluid pumped. Stage up to 2500 psi in 500 psi increments.( > <T" )) 12.4 CBU & circ at least (1) hi -vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the Whipstock. 12.5 TOH. 12.6 Makeup mills on a joint of HWDP. 12.7 RIH & set in slips. 12.8 Make up float sub, install float. 12.9 Make up UBHO sub. 12.10 Orient UBHO to starter mill. 12.11 Leave assembly hanging in the elevators, and stand back on floor. 12.12 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 12.13 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety screws. Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. REMOVE 3 screws for a set down shear of 6,630 x 3 =19,890 lbs. Note: Attach mills to Whipstock with (1) 35k mill shear bolt. Page 14 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililcorp UaAa. LU: 12.14 If needed, open BOP Blinds. 12.15 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 12.16 Release pick up system at this point, Make up mills. 12.17 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 12.18 The assembly can now be picked up to ensure that the shear bolt is tight. 12.19 Remove the handling system. 12.20 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 12.21 Run in hole at 1 I/2 to 2 minutes per stand. 12.22 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. ' z 12.23 Call for Baker Rep. 15 — 10 stands before getting to bottom. 12.24 Orient at least 30' — 45' above the CIBP. Ensure to have gyro personnel and equipment as well as a wireline unit R/U and ready. Page 15 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 WindowMaster G2 System on TorqueMaster BTA 7" 29# Csg — WindowMaster G2 On BTA BHA #1 Connection Length O.D. BOTTOM TRIP ANCHOR 3 % IF -Box X Bottom Guide 3.21' 6.18" WINDOW MASTER WHIPSTOCK Shear Bolt X 3 % IF -Pin 14.6' 6.00" WINDOW MILL -1/2 Reg -Pin X Mill 1.5' 6.63" LOWER WATER MELON MILL -1/2 IF -Box X 3-1/2 Reg -Box 5.5' 6.50" FLEX JOINT -1/2 IF- Box X 3-1/2 IF -Pin 6.6' 4.75" UPPER WATER MELON MILL -1/2 IF- Box X 3-1/2 IF -Pin 5.8' 6.63" 11T HWDP -1/2 IF -Box X 3-1/2 IF -Pin 30' 5.25" MWD Survey Tool -1/2 IF -Box X 3-1/2 IF -Pin 3' 4.75" UBHO -1/2 IF -Box X 3-1/2 IF -Pin 3' 4.75" Bowen Lubricated Bumper Jar 1/2 IF -Box X 3-1/2 IF Pin 15' 4.75" 6 DRILL COLLARS -1/2 IF -Box X 3-1/2 IF -Pin 180' 4.75" 301TS — HWDP -1/2 CDS40 Box X 4-1/2 CDS40-Pin 900' 4.75" CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 16 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililrorp :kh.Aa, IJ.c 13.0 Whipstock Setting Procedure 13.1 With the bottom of the Whipstock 30 — 45' above the CIBP, measure and record P/U and S/O weights. We will orient Whipstock face using Gyrodata. Ensure that UBHO and gyro tool mate up properly before making up UBHO sub. 13.2 Orient Whipstock to desired direction by turning DP in 1/4 round increments. P/U and S/O on DP to work all torque out (Being careful not to set BTA). Whipstock Orientation Diagram: 40 AZI Desired orientation of the Whipstock face is in 10 to 40 degrees azimuth. Hole Angle at window interval (7400' MD) is < 1 deg. The wellbore trajectory is also planned to 25 degrees azimuth. Highside of the casing at 7400' is negligible. 13.3 Once Whipstock is in desired orientation, slack off and tag CIBP to set Bottom Trip Anchor. 13.4 Set down 12-15K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (25k shear value). 13.5 P/U 5-10' above top of Whipstock. 13.6 Displace to 9.5 ppg 6% KC1/PHPA drilling fluid. 13.7 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. 13.8 Install catch trays in shaker underflow chute to help catch iron. 13.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. Page 17 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ilileorp AlaAa. LLC 13.10 Estimated metal cuttings volume from cutting window: 7" 3 Y2 REG -P X MILL 29# N-80 Cuttings Weight Window 3'/ IF -13 X 3 Y2 REG -B 5.5 6.5 FLEX JOINT Length Casing Weight Min (lbs) Avg (lbs) Max (lbs) 13 29.7# 80 110 140 13.11 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.12 Circulate Bottoms Up until MW in = MW out. 13.13 Conduct FIT to 11.5 ppg EMW. • (11.5 — 9.5) * 0.052 * 7400' tvd = 770 psi 13.14 Kick Tolerance • (11.5 -9.5) * (7400/10800) = 1.37 Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 11.5 ppg FIT results in a 1.37 ppg kick tolerance while drilling the interval with a 9.5 ppg fluid density. 13.15 Slug pipe and POOH. Gauge Mills for wear. 13.16 Should a second run be required pick up the following BHA. Back Un Mills CnnnPrfinn I pnnth n n WINDOW MILL 3 Y2 REG -P X MILL 0.98 6.63 NEW LOWER WATERMELON MILL 3'/ IF -13 X 3 Y2 REG -B 5.5 6.5 FLEX JOINT 3 Y2 IF -13 X 3'/ IF -P 6.5 4.75 UPPER WATERMELON MILL 3'h" IF -13 X 3 %" IF -P 5.83 6.63 FLOAT SUB 3 %" IF -13 X 3'/" IF -P 3.00 4.75 XO sub and 30 jts-HWDP 4 Y2" CDS40-B X 3'/2" IF -P 900' 5.25 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY.! Page 18 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ilileorp .Uavka, 1.1.1: 14.0 Drill 6" Hole Section 14.1 P/U 6" directional drilling assy. 14.2 Ensure BHA Components have been inspected previously. 14.3 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 14.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 14.5 Confirm that the bit is dressed with a TFA of 0.46 — 0.56 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 150 - 250 gpm. 14.6 Motor AKO should be set at 1.2 deg. Must keep up with 4 deg/100 DLS in the build section of the wellbore. 14.7 Primary bit will be the HDBS 6" MM55 PDC bit. Ensure to have a back up bit available on location. Page 19 Revision 0 October, 2015 Ililcorp:UaAa, HA: PRODUCT SPECIFICATIONS Cutter Ty pe SelectCutter IADC Code M424 Body Type MATRIX Total Cutter Count 24 Cutter Distribution j Face 14 Gauge 6 Number of Large Nozzles 0 Number of Medium Nozzles 0 '.'dumber of Small Nozzles 5 Ntunber of Micro Nozzles 0 :Number of Ports (Size) 0 Number of Replaceable Ports (Size) 0 Junk Slot Area (sq in) 6.14 Non-nalized Face Volume 30.47% API Connection 3-1F2 REG- PIN Recommended Make -Up Torque's 5,173 — 7,665 Fi lbs. Nominal Dimensions" Make -Up Face to Nose 9.26 in - 235 mm Gauge Length ? in - 51 mm Sleeve Length 0 in - 0 mm Shank Diameter 4.5 in - 114 mm Break Out Plate (Mat*'Legacy-#) 181953144030 Approximate Shipping Weight 80Lbs. - 36Kg. SPECIAL FEATURES 1/32" Relieved Gage SCU 322C-04 Drilling Procedure Rev 0 Material #771781 of ot to of y "Bit specific recommended make-up torque is a function of the bit LD. and actual bit sub O_D_ utilized as specified in API RP7G Section A.S? ."Design dimensions are nominal and may vary slightly on manufactured product_ Halliburton Drill Bits and services models are continuously reviewed and retencd. Product specifications may change without notice_ C 2014 Halliburton_ All rights resen ed. 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. Page 20 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililrorp ANAs, LLC 14.8 TIH to window. Shallow test MWD on trip in. 14.9 TIH through window, ensure Halliburton MWD service rep on rig floor during this operation. • Do not rotate string while bit is across face of Whipstock. 14.10 Drill 6" hole to 11937' MD using motor assembly. - • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize ECD while pumping to minimize waterflow from Tyonek sands • On trips spot weighted pills inside window and hi vis pills at TD to control waterflow • Try to keep waterflow below 10 bph while tripping • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 14.11 Hilcorp Geologists will follow mud log closely to determine exact TD. 14.12 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 14.13 TOH with drilling assembly, handle BHA as appropriate. Page 21 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililvorlo AlaAa, LH: 15.0 Run 4.5" Production Casing 15.1 R/U Weatherford 4.5" casing running equipment. • Ensure 4.5" DWC/C x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 15.2 P/U shoe joint, visually verify no debris inside joint. 15.3 Continue M/U & thread locking shoe track assy consisting of - (1) £(1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • Solid body centralizers will be pre-installed on shoe joint, FC joint, and LC joint. • Install solid body centralizers (Volant), one per joint, and leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe & FC. 15.4 Continue running 4.5" production casing • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. Utilize a collar clamp until weight is sufficient to keep slips set properly. 4.5" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2" 5800 ft -lbs 6500 ft -lbs 7200 ft -lbs Page 22 Revision 0 October, 2015 Connection Type: DWC/C Tubing standard Technical Specifications Size(O.D.): 4-1l2 in Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) SCU 322C-04 Drilling Procedure Rev 0 Weight (Wall): Grade: 12.60 Ib/ft (0.271 in) L-80 Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (Ibs) 7,500 Minimum Collapse Pressure (psi) 8,430 Minimum Internal Yield Pressure (psi) 7,700 Hydrostatic Test Pressure (psi) Pipe Dimensions 4.500 Nominal Pipe Body O.D. (in) 3.958 Nominal Pipe Body I.D.(in) 0.271 Nominal Wall Thickness (in) 12.60 Nominal Weight (lbs/ft) 12.25 Plain End Weight (lbs/ft) 3.600 Nominal Pipe Body Area (sq in) SCU 322C-04 Drilling Procedure Rev 0 Weight (Wall): Grade: 12.60 Ib/ft (0.271 in) L-80 Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (Ibs) 7,500 Minimum Collapse Pressure (psi) 8,430 Minimum Internal Yield Pressure (psi) 7,700 Hydrostatic Test Pressure (psi) USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713479-3200 Fax: 713479-234 E-mail: VAMUSAsalesdtvarn4m.com Page 23 Revision 0 October, 2015 Connection Dimensions 5.000 Connection O.D. (in) 3.958 Connection I.D. (in) 3.833 Connection Drift Diameter (in) 3.94 Make-up Loss (in) 3.600 Critical Area (sq in) 100.0 Joint Efficiency (%) USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713479-3200 Fax: 713479-234 E-mail: VAMUSAsalesdtvarn4m.com Page 23 Revision 0 October, 2015 Connection Performance Properties 288,000 Joint Strength (Ibs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (Ibs) 288,000 Compression Rating (Ibs) 7,500 API Collapse Pressure Rating (psi) 8,430 API Internal Pressure Resistance (psi) 81.5 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoximated Field End Torque Values 5,800 Minimum Final Torque (ft-Ibs) 6,500 Maximum Final Torque (ft-Ibs) 7,200 Connection Yield Torque (ft -lbs) USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713479-3200 Fax: 713479-234 E-mail: VAMUSAsalesdtvarn4m.com Page 23 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililetwp Alaska.. LI.I: 15.7 Ensure to run enough liner to provide for approx 200' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection. 15.8 Before picking up Baker ZXP liner hanger / packer assy, count the 4 of joints on the pipe deck to make sure it coincides with the pipe tally. 15.9 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. 15.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 15.11 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 15.12 M/U top drive and fill pipe while lowering string every 10 stands. 15.13 Set slowly in and pull slowly out of slips. 15.14 Circulate 1-1/2 drill pipe and liner volume at 7" window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 15.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, A 20, & 30 rpm. 15.16 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15.17 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 15.18 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 15.19 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 24 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililcorp Alaska, LLC 16.0 Cement 4.5" Production Casing • Cement will be mixed using batch mixer to ensure consistent density 16.1 Hold a pre job safety meeting over the upcoming cmt operations. 16.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky. 16.3 Pump 5 bbls 12.5 ppg MUDPUSH II spacer. 16.4 Test surface cmt lines to 4500 psi. 16.5 Pump remaining 10 bbls 12.5 ppg MUDPUSH II spacer. 16.6 Mix and pump 114 bbls of 15.3 ppg class "G" cmt per below recipe with 2 lbs/bbl of Cemnet or equivalent loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to give 500' of cement inside window in annulus between 7" casing and 4-1/2" casing. Est TOC 7200' TMD. 16.7 Displacement fluid will be produced water. —169 bbls of displacement fluid Cement Calculations 7" x 4-1/2 DP" Overlap: (7200' — 6900') x 0.017 = 5.1 bbls 7" x 4-1/2" Liner Overlap: (7400' — 7200') x 0.017 = 3.4 bbls 6" OH x 4-1/2" Liner: (11937' — 7400') x 0.0153 x 1.5 = 104.1 bbls . Shoe Track: 80' x 0.01522 = 1.8 bbls Total Volume (bbls): 5.1 + 3.4 + 104.1 + 1.8 = 114.4 bbls Total Volume (ft3): 114.4 bbls x 5.615 ft3/bbl = 642.4 ft3 Total Volume (sx): 642.4 ft3 / 1.35 ft3/sk = 476 sx MA Page 25 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ilih-orp Alaska, LLC Slurry Information: System Easy BLOK Density 15.3 lb/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Be at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 16.8 Drop DP dart and displace with 8.6 ppg produced water. 16.9 Pump cement at max rate of 8 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point 16.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 16.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 16.12 Slack off total liner weight plus 30k to confirm hanger is set. 16.13 Do not overdisplace by more than 1/2 shoe track (-1 bbls). Shoe track volume is 1.8 bbls. 16.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner Page 26 Revision 0 October, 2015 16.15 Bleed pressure to zero to check float equipment. SCU 322C-04 Drilling Procedure Rev 0 16.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 16.17 Rotate slowly and slack off 50k downhole to set ZXPN. 16.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 16.20 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 16.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 16.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: / 16.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 16.24 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 16.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 27 Revision 0 October, 2015 llilrorp Alaska.. LLC SCU 322C-04 Drilling Procedure Rev 0 Ensure to report the following on Wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping ofjob. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + "As -Run" liner tally to mmyers(&hilcorn.com / Page 28 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililq) kla,ka.. LLC 17.0 Wellbore Clean Up & Displacement 17.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3-3/4" bit or mill • Casing scraper & brush for 4-1/2" 12.6# casing (MI Swaco - Multiback) • +/- 4740' 2-3/8" workstring. • Casing scraper & brush for 7" 29# casing (Ml Swaco - Multiback) • (2000') 4-1/2" DP • Casing scraper & brush for 7" 29# casing (MI Swaco - Multiback) • 4-1/2" DP to surface. 17.2 TIH & clean out well to landing collar (+/- 11,812' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. • Ensure 3-3/4" bit is worked down to the landing collar. • Space out the cleanout BHA so that the 3-3/4" bit reaches the 4-1/2" landing collar when crossover is +/- 30' above the 4-1/2" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. 17.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 3500 psi / 30 min. Ensure to chart record casing test._ -- 17.4 Displace drilling fluid in wellbore with a hi -vis pill followed by fresh water. • Catch drilling fluid in rain -for -rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7" multi -back assy to surface. • RIH again & tag landing collar w/ 3-3/4" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by 6% KCl completion fluid. 17.5 TOH w/ clean out assy. LDDP on the trip out. L/D the 2-3/8" work string Page 29 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ililrorp Alaska, LLC 18.0 Run Completion Assembly 19.1 Run 2-7/8" X 2-3/8" tubing as per separate Approved Completion Sundry r 7 6c� 19.0 RDMO �6 r�� f! zfl, 19.1 Install BPV in wellhead. RILDs.iY-T✓l, ' I �-�- 19.2 ND BOPS, NU tree, test void 19.3 RDMO Cg� e - Page 30 Revision 0 October, 2015 20.0 BOP Schematic SCU 322C-04 Drilling Procedure Rev 0 Page 31 Revision 0 October, 2015 21.0 Wellhead Schematic BHTA, Bowen, 3 118 5M FE Valve, swab, VG -M, 3 118 5M FE, HWO Valve, Wing, VG -M. 2 1116 5M FE, HWO Valve, upper roaster, VG -M, 3 V8 5M FE, HWO Valve, master, VG -M, 3 118 5M FE, HWO Tbg head, Seaboard, S-8, 135183MX 7 1116"5M, M 2- 2 1116 5M SSO Valve, Wing, VG -M, 3 118 5M FE, HWO Oly 2 SCU 322C-04 Drilling Procedure Rev 0 Valve, Wing, SSV' VG -M, 3 118 5M FE w1 Halliburton Hydraulic operator Adapter, Seaboard SM-E-CLN 7 V 16 5M stdd X 3 V8 5M stdd top, wl 14 npt control line exit Valve, Seaboard, 2 1116 5M FE, HWO, Qty 2 Page 32 Revision 0 October, 2015 Ililcorp Al;,Aa. LLC 22.0 Days vs Depth Ent rrr 6000 t V 7 a woo I . •Ivy Page 33 0 SCU 322C-04 Drilling Procedure Rev 0 Days Vs Depth SCU 322C 4 (SCU 314- ST) 5 10 15 Days Revision 0 20 October, 2015 25 11ilcorp Alaska, LLA: 23.0 Geo-Prog GEOLOGICAL PROGNOSIS WELL NAME: SCU 322C-04 (SCU 314-04 ST) FIELD: SURFACE X: 343081.91 STATE: SURFACE Y. 2456758.86 BOTTOMHOLEX: 344371.80 TVD REF DATUM BOTTOMHOLE Y' 2459346.17 TVD REF ELEV COORD REF. SYSTEM NAD27 GROUND ELEV SCU 322C-04 Drilling Procedure Rev 0 Drill a Sidetrackwell out ofthe SCU 314-4 well and complete it as an H1 and H2 Gas Injector. This is the gas injector associated with the 2015 1-11-2 Gas Flood project. Based on subsurface evaluation 60 FT Gradient 0.2 0.2 0.2 0.2 0.3 0.3 0.3 MWD Gamma Resistivity only/ Mad Pass w/ Porositytools if hole conditions permit COMPLETION TYPE Injection Well ANTICIPATED6 MMscf/d Injection ARTIFICIAL LIFT EQUIPMENTOD TUBING SIZE 2-3/8" X 2-7/8" Injection String; Packer to be set in accordance with AOGCC regs for injection wells Page 34 Revision 0 October, 2015 EXPECTED Formation FORMATION FLUID MD TVD Est Pressure EMW KOP 7400 7398 SR HIST Oil Sand Oil / Water 11266 10361 1600 3.0 ' SR 1-12ST Oil Sand Oil / Water 11300 10384 1600 3.0 SR_H2SB 11349 10416 SR_H3ST Oil Sand Gassy Water / Oil 11373 10432 1600 2.9 SR_H3L_ST Oil Sand Gassy Water / Oil 11415 10460 1600 2.9 SR_H3SB 11446 10479 SR H5ST Sand Water / Oil 11493 10510 2800 5.1 SR_H5SB 11610 10587 SR H7ST Sand Oil 11679 10632 2800 5.1 SR_H7SB 11764 10687 SR H8ST Sand Water / Oil 11768 10690 2800 5.0 SR H8SB 11841 10737 v _ _ 60 FT Gradient 0.2 0.2 0.2 0.2 0.3 0.3 0.3 MWD Gamma Resistivity only/ Mad Pass w/ Porositytools if hole conditions permit COMPLETION TYPE Injection Well ANTICIPATED6 MMscf/d Injection ARTIFICIAL LIFT EQUIPMENTOD TUBING SIZE 2-3/8" X 2-7/8" Injection String; Packer to be set in accordance with AOGCC regs for injection wells Page 34 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 llilvorp :%IaAa. LIA.: 24.0 Anticipated Drilling Hazards / Water Flow: The Tyonek water sands will be open. Ensure to -treat the initial flow as gas. After we are confident we .are only dealing with water from the sands we will drill the interval while the well is flowing water. Utilize MW and ECD to keep the well dead will drilling. During trips we will use heavy pills and viscous pills to control the flow and trip in and out of the well. Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual -composition carbon -based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. • Minimize swab and surge pressures • Minimize back reaming through coals when possible H2S: 1-12S is not present in this hole section. No abnormal temperatures or pressures are present in this hole section. Page 35 Revision 0 October, 2015 25.0 Rig Layout SCU 322C-04 Drilling Procedure Rev 0 Page 36 Revision 0 October, 2015 0 Ilileurp Alaska. 1.1.1: 26.0 FIT Procedure Procedure for FIT: SCU 322C-04 Drilling Procedure Rev 0 Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures 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 37 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ildvorp Alaska.. LII: 27.0 Choke Manifold Schematic r r - i. utnur wnN R cwKM Page 38 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 28.0 Casing Design Information Calculation & Casing Coign Factors Swenson River unit DATE: 1 V94015 WELL: S+CU 3220-04 {SCU 314-04 ST) FIELD: "dotna Crack Unit DESIGN BY., Monty M Myers Design Criteria: Hole Size Mud Density.- Hole ensity.Hole Sixes 6 Mud Density: 10.5 ;4 g Hole Sive Mud Density,. . Drilling Made MASP: 1720 esn (a4s.- ailachcd LIASP dc1mminralian 8 calculalinn) Production Mode MASP- 2027 psr (Sues attached HASP delerminabon & calculation) Collapse Calculation: Section Ca4culatiien 1,2 formal gr ant external stress JO 40fi i;*Rtj and the casing evacuated for the infernal stress Calculatkan/Specification Casing 00 Top iIVID) Top jVD) 0atiom (MD) Batlami (TV❑i LeNlh We t (ppfI Grade Connection Wevght wilo Bcuyancy Factor jibs) Tension at Top est Seclion (lbs) Min sirerglh Tension (1000 ) Worst Case Safety Favor (TensicnI Callapse Pressure M butlom (Ni) Collapse Realstmoe Wo temon 1Psi) Wow Case Safety Factor (Cole) MASP (Pr4l Minimum Yield (5i) ir'r'ow case safety tactor 4eurst) 1 4 -VT 7.70 7-M 11,91!7 10,800 4,T37 12.6 L-00 DW C C 5!3,666 58,686 298 4.03 4.W y`b9alAi� 7 all-zi 1.720 0,430 4.88 _ Casing Section 2 3 4 / %6. J Y l0 gDJ � . G S]Z'/`q^yy/f Yw•e.✓ Page 39 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 29.0 61' Hole Section MASP Maximum Anticipated Surface Pressure Calculation Hiicor 6" Hole Section SCU 322C-04 Kenai, Alaska MD TVD Planned Top: 0 0 Planned TD: 11937 10800 Antirinatpd Fnrmatinnc and Prpccnrpc- Formation TVD Est Pressure Oil/Gas/Wet PPG Grad SR_H1ST 10,361 1600 Oil/Water 3.0 0.154 SR_H2ST 10,384 1600 Oil /Water 3.0 0.154 SR_H2SB 10,416 1600 3.0 0.154 SR_H3ST 10,432 1600 Gassy Water/Oil 2.9 0.153 SIR _H3L_ST 10,460 1600 Gassy Water/ Oil 2.9 0.153 SR_H3SB 10,479 2800 5.1 0.267 SR_H5ST 10,510 2800 Water/ Oil 5.1 0.266 SR_H5SB 10,587 2800 5.1 0.264 SR_H7ST 10,632 2800 Oil 5.1 0.263 SR_H7SB 10,687 2800 5.0 0.262 SR_H8ST 10,690 2800 Water/ Oil 5.0 0.262 SR_H8SB 10,737 2800__._ 5.0 0.261 TD 10,800 2800 OIL 5.0 0.259 Offset Well Mud Densities Well MW ranee Ton (TVD) Rnttnm (TVD) Datp SCU 4405 9.8 -10ppg 9,400 10,925 2014 SCU 21-4 12 ppg 0 10,965 1961 SCU 4433 11.3 - 12.5 ppg 9,216 10,747 2013 SCU 41A-4 11.2 ppg 9,300 10,807 2013 Assumptions: 1. Maximum planned mud density for the 6" hole section is 10.5 ppg. 2. Calculations assume reservoirs contain 100% gas (worst case). 3. Calculations assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 8600' TVD =12.5 ppg EMW Fracture Pressure at 6" window considering a full column of gas from window to surface: 7400 (ft) x 0.65(psi/ft)= 4810 4810(psi)-[0.1(psi/ft)*7400(ft)]= F 4070 psi MASP from pore pressure; entire wellbore evacuated to gas from TD 10800 (ft) x 0.26(psi/ft)= 2808 psi 2808(psi) - [0.1(psi/ft)*10800 (ft)]= 1728 si Summary: 1. MASP while drilling 6-1/8" production hole is governed by SIBHP minus entire wellbore evacuated to gas from TD. - -� - 2. MASP during production mode is governed by SIBHP minus entire wellbore evacuated to gas from TD. Page 40 Revision 0 October, 2015 SCU 322C-04 Drilling Procedure Rev 0 Ilil.•orp AlaAa, LL1: 30.0 Plot (NAD 27) (Governmental Sections) S008N009W A028398 JB A028399 SRU 24-33 BHL# A028990 •.-' 1 SCU_34.33 BHI -a..,' r �• t - - SCU-418-04 BHLI SCU 41-05 BHLO r' SCU 21-04 BH l 1 SCU-21A-404 8IL�SCU l J&4M SCU 341-04 BHL.!,,' R{61 SCU S BHL -- SCU-21C-04 BHI 04 L� SCU 42A-05 BHLO SCU 31-04 q`H* 41A SCU_42-03 %&l.1_4; M1r. I D BaiL, f rSCU 3220-04 BHL - r'" SCu 42 BHLO CU_3'l0t5 BHLs Scu SCU 322C -W Bashi B U1 _-0 _2A-04 BHL f SCa BKO � 04U32A-05 SCU 226-"a _TPH -r SCU 3?2XC` 04 SCu_332-04 EHL i SCU_42B-05a © SC22.04 Btu SCU 42-05Y�U42-0 BHL m 1. i SCU 426.05PBB4q P •.t •.,. e SCU-33-05 BHL*--is", - 34481 W8T4t1� ILOS _3?3-04 BHL* a SC LJ SCU_ -05 Btu. tl A028996a e° A028997 P _I S007N009W sCU_2 A tib 6HL Sf U_44-0 BHL. PL-SCU 24-04 (QST) BFIIItt -- SCU_314-04 _ 9CU_34C56HL� ISCUSHL Scu 34.048HL! (J _0 NV SCU41A M BHL• .a SCU-21A-09 BM&-_ _ _ _ Legend ! SCU_321-098HI* • SCU 322C-04 SHL X SCU 322C-04 TPH T SCU 322C-04 BHL SCU-3"S B" CJ Other Surface Well Locations SCU 12B-09 BHL* • Other Bottom Hole Locations �Sg132WBFiL y' ---- Well Paths r! C3 Oil and Gas Unit Boundary aLA. _-4 1rw Eft Soldotna Creek Unit SCU 322C-04 Ilih .. %I—k.- i IA Page 41 Revision 0 1,000 2,000 Feet v Maska State Plane Zone 4, NAD27 Map Date: 1 (W29,12015 October, 2015 Ililrorp Alaska, LLC 31.0 Surface Plat (As Built) (NAD 27) I I SCU 314-04 ASBUILT SURFACE LO( NAD 27 ASP ZONE 4 N:2456758.863 E:343081.914 LAT: 60°43'1$.068"N LON: 150`52'34.940'W I 780' FWL 823'FSL ELEV: 145.135' NAVD88 I FAIT I �w Z J Z I � U w Cn SECS i I SECTION COR ICOIPUTEDI I N.2456946g16 E:342292.398 4 SECTION LINE SCU 322C-04 Drilling Procedure Rev 0 NOTES 1. BASIS OF HORIZONTAL, NAD83 US FEET POSITION (EPOCH 2O1M AND VERTICAL CONTROL (NAV088) IS AN OPUS SOLUTION FROM NGS STATIONS TBON• TSEA AND ANC2 TO ESTABLISH CP -2. THE ALASKA STATE PLANE COORDINATES NAD &3 ZONE 4 IN FEET ARE: N = 2458364.578 E = 148MI59.444 ELEV. a 212.690 (NAVDBB) 2. SECTION LINES SHOWN WERE ESTABLISHED FROM SURVEY TIES TO ORIGINAL GLO MONUMF„ NTATION (1987) 3. DATUM TRANSFORMATIONS (NA083 ASPZ4 TO NAD27 ASPZ41 WERE DONE USING CORPSCON SOFTWARE VERSION 6.0.1. 823 ALI'\ SCALE 0 705 46'0 FEET I �• �Y� 7lA.R.TiI�AAn.... � E t STAp A. YgANL i 4837-5 I� •b16 RD str " ~1SWANSON rg="- HILLCORP ALASKA, LLG Wl'm_* RIVER FIELD Crsultiny Inc WELL SCU 314-04 '"•`' °" ' AS BUILT SURFACE LOCATION fMr.N F0" iN1PPN:: U,a.iYM:i NAD 27 11 Y6 ex> 13 v16 r> SECTION. 04 T07N R09W "F cua f.�N',Hi�Y ,>F<a;,�,;., Ililrurll Alaska. I.IX SEWARD MERIDIAN, ALASKA Page 42 Revision 0 October, 2015 11ilcorp Alaska, IJ.I: 32.0 Surface Plat (As Built) (NAD 83) ' SCU 314-04 ASBUILT SURFACE LOCATION I NAD 83 ASP ZONE 4 N:2456520.128 E:1483104,600 LAT: 60°43'16.038"N r LON: 15W52'42.931' VV 780' FWL r 823' FSL I ELEV: 145.135' NAVD88 a a yea o w Z_ I _J Z W SEC 4 T7N R9W 1123' SECTION COR iCCMPUTEO. I N: 1151701,161 E: I<1i3 t Lc U t 8 5 4 SECTION UNE NOTES 1. BASIS OF HORIZONTAL, NADB3 US FEET POSITION (EPOCH 201M AND VERTICAL CONTROL (NAVO68) IS AN OPUS SOLUTION FROM NGS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2, THE ALASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: N = 24583B4.578 E = 14&'3869 444 ELEV. - 212.690 (NAVDBB) SECTION LINES SHOWN WERE ESTABLISHED FROM SURVEY =S TO ORIGINAL GLO MONUMENTATION (1987) SCU 322C-04 Drilling Procedure Rev 0 Ah��' SCALE 20) aw IAT oe.-�rct HILLCORP ALASKA, LLC ^,rlra h . SWANSON RIVER FIELD 6snsdting Inc WELL SCU 314-04 AS BUILT SURFACE LOCATION NAD 83 :IYI:KFK.K) MYPFMi:::Jlk.Fr N: iFtN', SECTION. 04 T07N R09W ..F YtYC. ,Ka 311+]id cox nr,auia� Ilik-orp Alaska, 1,1.4. �E 1 SEWARD MERIDIAN, ALAS" Page 43 Revision 0 October, 2015 33.0 Directional Program (P1) SCU 322C-04 Drilling Procedure Rev 0 Page 44 Revision 0 October, 2015 Hilcorp Energy Company Soldotna CK Unit Soldotna CK Unit Soldotna CK Unit 314-4 SCU 322C-04 Plan: SCU 322C-04 WP4 Standard Proposal Report 09 November, 2015 HALLIBURTON Sperry Drilling Services �B21;71-11 3600 9000 3500 Project: Soldotna CK Unit WELL DETAILS: Soldotna CK Unit 314-4 NAD 1927(NADCON CONUS) Alaska Zone 04 HALLIBURTON w Site: Soldotna CK Unit Ground Leveh 145.13 4500 Well: Soldotna CK Unit 314-4 +N/ -S +E/ -W Northing Easting Latittude Longitude Slot sve�v orur.,�3 Wellbore: SCU 322C-04 0.00 0.00 2456758.86 343081.91 60.7216856 -150.8763723 v Plan: SCU 322C-04 WP4 aC 5400 REFERENCE INFORMATION -1200 5500 Co-ordinate (WE) Reference: Well Soldotna CK Unit 3144, True North E 6000 Vertical (TVD) Reference: SCU 11-04 (d1163.14usfi 6000 Measured Depth Reference: SCU 11-04 (d 163.14us11 ? 6600 6500 Calculation Method: Minimum Curvature -600 7000 7200 FORMATION TOP DETAILS J� / 7500 7800 TVDPath MDPath Formation 0 400 8400- 10360.51 11265.81 SR 111ST 10383.73 11300.37 SR_H2ST 10416.05 11349.46 SR H2SB 10431.79 11373.37 SR_H3ST 600 500 10459.61 11415.70 SR RK ST 10479.34 11445.74 SR H3SB 10510.12 11492.71 SR_H5ST 1000 10586.82 11610.30 SR H5SB 1200 10631.90 11679.52 SR_H7ST 10686.99 11764.10 SR H7SB 10689.50 11767.96 SR_HSST 1500 10737.01 11840.90 SR H8SB 1800- 2000 2400 2500 �B21;71-11 3600 9000 3500 4000 4200 w 4500 0 C:) 4800 v 5000 aC 5400 5500 m E 6000 6000 ? 6600 6500 H 7000 7200 J� / 7500 7800 8pp0 400 8400- 9000 00 00 00 O ^O O SR_WST O SR H1ST ^Oh SR_H2ST O /;SR. H2ST ^00 SR_H7ST 10200-SR_H2SB ^ _-SR_H3ST- ____ Ile -;SR H3L ST- 050 -- -SR H3S8_ ^^ 10800-;1'11 --,-SR -- - - SCU 322C-04 TD �H5SB \ SR H5ST t . SR H7SB 11400 \SR_II75T SCU 322C-04 WP4 SR H8ST 12000 SR_H8SB -3600 -3000 -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 Vertical Section at 25.73° (1500 usfUin) HALLIBURTON Sperry ONlllnp S�Icea WELL DETAILS: Soldotna CK Unit 3144 Ground Level: 145.13 +N/ -S +E/ -W Northing Ewting Latittude Longitude Slot 0.00 0.00 2456758.86 343081.91 60.7216856 -150.8763723 REFERENCE INFORMATION Co-.,dinate (N/E) Rafaren-- Wall Rnldnlna C.K [Ina qlAd Tnia Nn.h -1000 -800 -600 -400 -200 0 200 400 600 800 1000 1200 1400 1600 1800 West( -)/Fast(+) (400 usft/in) Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 314-4 Wellbore: SCU 322C-04 Plan: SCU 322C-04 WP3 WELL DETAILS: Soldotna CK Unit 3144 Ground Level: 145.13 +N/ -S +E/ -W Northing Ewting Latittude Longitude Slot 0.00 0.00 2456758.86 343081.91 60.7216856 -150.8763723 REFERENCE INFORMATION Co-.,dinate (N/E) Rafaren-- Wall Rnldnlna C.K [Ina qlAd Tnia Nn.h -1000 -800 -600 -400 -200 0 200 400 600 800 1000 1200 1400 1600 1800 West( -)/Fast(+) (400 usft/in) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 314-4 Wellbore: SCU 322C-04 Design: SCU 322C-04 WP4 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Soldotna CK Unit 314-4 SCU 11-04 @ 163.14usft - SCU 11-04 @ 163.14usft True Minimum Curvature Project Soldotna CK Unit, Swanson River Field 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 Vertical TVD Dogleg Site Soldotna CK Unit Depth Site Position: Northing: 2,460,278.17 usft Latitude: 60.7313645 From: Map Easting: 344,519.07 usft Longitude: -150.8686069 Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -0.76 ° (I (usft) usft (usft) Well Soldotna CK Unit 314-4 (°/100usft) (°/100usft) Well Position +N/ -S 0.00 usft Northing: 2,456,758.86 usft t Latitude: 60.7216856 7,398.13 +E/ -W 0.00 usft Easting: 343,081.91 usft Longitude: -150.8763723 Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 145.13 usft 8,943.97 46.87 25.40 8,773.34 Wellbore SCU 322C-04 376.92 3.00 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 46.87 25.40 (°) (°) (nT) 2,098.92 BGGM2015 8/6/2015 16.58 73.68 55,514 Design SCU 322C-04 WP4 Audit Notes: Version: Phase: PLAN Tie On Depth: 7,400.00 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (°) 14.86 0.00 0.00 25.73 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (I (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 7,400.00 1.54 93.85 7,398.13 7,234.99 52.42 99.19 0.00 0.00 0.00 0.00 8,943.97 46.87 25.40 8,773.34 8,610.20 589.51 376.92 3.00 2.94 -4.43 -69.81 11,233.62 46.87 25.40 10,338.70 10,175.56 2,098.92 1,093.75 0.00 0.00 0.00 0.00 11,265.26 47.81 25.22 10,360.14 10,197.00 2,119.95 1,103.70 3.00 2.97 -0.58 -8.24 11,274.90 47.21 25.24 10,366.65 10,203.51 2,126.38 1,106.73 6.16 -6.16 0.17 178.83 11,277.84 47.21 25.24 10,368.65 10,205.51 2,128.33 1,107.65 0.00 0.00 0.00 0.00 11,301.00 48.80 25.19 10,384.14 10,221.00 2,143.90 1,114.98 6.85 6.85 -0.19 -1.18 11,562.37 49.36 14.84 10,555.60 10,392.46 2,329.03 1,182.34 3.00 0.21 -3.96 -89.32 11,679.89 49.36 14.84 10,632.14 10,469.00 2,415.23 1,205.17 0.00 0.00 0.00 0.00 11,937.62 49.36 14.84 10,800.00 10,636.86 2,604.28 1,255.25 0.00 0.00 0.00 0.00 11/9/2015 2:57:11 PM Page 2 COMPASS 5000.1 Build 73 Planned Survey 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 Soldotna CK Unit 314-4 Company: Hilcorp Energy Company TVD Reference: SCU 11-04 @ 163.14usft Project: Soldotna CK Unit MD Reference: SCU 11-04 @ 163.14usft Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 314-4 Survey Calculation Method: Minimum Curvature Wellbore: SCU 322C-04 Depth Inclination Design: SCU 322C-04 WP4 Depth TVDss Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) 7,234.99 7,400.00 1.54 93.85 7,398.13 7,234.99 52.42 99.19 2,456,809.95 343,181.79 0.00 90.28 Start Dir 3°/100' : 7400' MD, 7398.13'TVD : 69.81° LT TF 7,500.00 3.82 46.32 7,498.02 7,334.88 54.63 102.94 2,456,812.11 343,185.57 3.00 93.90 7,600.00 6.69 36.50 7,597.59 7,434.45 61.61 108.81 2,456,819.02 343,191.54 3.00 102.75 7,700.00 9.64 32.61 7,696.57 7,533.43 73.35 116.79 2,456,830.65 343,199.67 3.00 116.79 7,800.00 12.61 30.54 7,794.68 7,631.54 89.81 126.86 2,456,846.98 343,209.96 3.00 135.99 7,900.00 15.60 29.24 7,891.65 7,728.51 110.95 138.97 2,456,867.95 343,222.36 3.00 160.29 8,000.00 18.59 28.36 7,987.23 7,824.09 136.72 153.12 2,456,893.52 343,236.84 3.00 189.64 8,100.00 21.58 27.71 8,081.13 7,917.99 167.03 169.24 2,456,923.62 343,253.37 3.00 223.95 8,200.00 24.57 27.22 8,173.12 8,009.98 201.81 187.31 2,456,958.15 343,271.90 3.00 263.12 8,300.00 27.57 26.82 8,262.94 8,099.80 240.96 207.26 2,456,997.03 343,292.37 3.00 307.05 8,400.00 30.56 26.50 8,350.33 8,187.19 284.37 229.05 2,457,040.15 343,314.74 3.00 355.62 8,500.00 33.56 26.23 8,435.07 8,271.93 331.93 252.62 2,457,087.39 343,338.94 3.00 408.69 8,600.00 36.56 26.00 8,516.92 8,353.78 383.50 277.90 2,457,138.62 343,364.91 3.00 466.13 8,700.00 39.56 25.80 8,595.65 8,432.51 438.95 304.82 2,457,193.71 343,392.56 3.00 527.77 8,800.00 42.55 25.62 8,671.05 8,507.91 498.12 333.31 2,457,252.49 343,421.84 3.00 593.43 8,900.00 45.55 25.47 8,742.91 8,579.77 560.85 363.29 2,457,314.81 343,452.65 3.00 662.96 8,943.97 46.87 25.40 8,773.34 8,610.20 589.51 376.92 2,457,343.29 343,466.67 3.00 694.70 End Dir : 8943.97' MD, 8773.34' TVD 9,000.00 46.87 25.40 8,811.65 8,648.51 626.45 394.46 2,457,379.99 343,484.70 0.00 735.59 9,100.00 46.87 25.40 8,880.01 8,716.87 692.37 425.77 2,457,445.49 343,516.88 0.00 808.56 9,200.00 46.87 25.40 8,948.38 8,785.24 758.29 457.08 2,457,510.99 343,549.07 0.00 881.54 9,300.00 46.87 25.40 9,016.75 8,853.61 824.21 488.38 2,457,576.49 343,581.25 0.00 954.52 9,400.00 46.87 25.40 9,085.11 8,921.97 890.14 519.69 2,457,641.99 343,613.43 0.00 1,027.50 9,500.00 46.87 25.40 9,153.48 8,990.34 956.06 551.00 2,457,707.49 343,645.62 0.00 1,100.48 9,600.00 46.87 25.40 9,221.85 9,058.71 1,021.98 582.31 2,457,772.99 343,677.80 0.00 1,173.46 9,700.00 46.87 25.40 9,290.21 9,127.07 1,087.91 613.61 2,457,838.49 343,709.99 0.00 1,246.43 9,800.00 46.87 25.40 9,358.58 9,195.44 1,153.83 644.92 2,457,903.99 343,742.17 0.00 1,319.41 9,900.00 46.87 25.40 9,426.95 9,263.81 1,219.75 676.23 2,457,969.49 343,774.36 0.00 1,392.39 10,000.00 46.87 25.40 9,495.31 9,332.17 1,285.68 707.54 2,458,034.98 343,806.54 0.00 1,465.37 10,100.00 46.87 25.40 9,563.68 9,400.54 1,351.60 738.84 2,458,100.48 343,838.72 0.00 1,538.35 10,200.00 46.87 25.40 9,632.05 9,468.91 1,417.52 770.15 2,458,165.98 343,870.91 0.00 1,611.33 10,300.00 46.87 25.40 9,700.41 9,537.27 1,483.45 801.46 2,458,231.48 343,903.09 0.00 1,684.30 10,400.00 46.87 25.40 9,768.78 9,605.64 1,549.37 832.77 2,458,296.98 343,935.28 0.00 1,757.28 10,500.00 46.87 25.40 9,837.15 9,674.01 1,615.29 864.07 2,458,362.48 343,967.46 0.00 1,830.26 10,600.00 46.87 25.40 9,905.51 9,742.37 1,681.21 895.38 2,458,427.98 343,999.65 0.00 1,903.24 10,700.00 46.87 25.40 9,973.88 9,810.74 1,747.14 926.69 2,458,493.48 344,031.83 0.00 1,976.22 10,800.00 46.87 25.40 10,042.25 9,879.11 1,813.06 958.00 2,458,558.98 344,064.01 0.00 2,049.20 10,900.00 46.87 25.40 10,110.61 9,947.47 1,878.98 989.30 2,458,624.48 344,096.20 0.00 2,122.17 11,000.00 46.87 25.40 10,178.98 10,015.84 1,944.91 1,020.61 2,458,689.98 344,128.38 0.00 2,195.15 11,100.00 46.87 25.40 10,247.35 10,084.21 2,010.83 1,051.92 2,458,755.48 344,160.57 0.00 2,268.13 11,200.00 46.87 25.40 10,315.71 10,152.57 2,076.75 1,083.23 2,458,820.98 344,192.75 0.00 2,341.11 11,233.62 46.87 25.40 10,338.70 10,175.56 2,098.92 1,093.75 2,458,843.00 344,203.57 0.00 2,365.65 Start Dir 3°/100' : 11233.62' MD, 10338.7'TVD 1119/2015 2:57:11PM Page 3 COMPASS 5000.1 Build 73 Halliburton H A LL I B U R TO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Soldotna CK Unit 314-4 Company: Hilcorp Energy Company TVD Reference: SCU 11-04 @ 163.14usft Project: Soldotna CK Unit MD Reference: SCU 11-04 @ 163.14usft Site: Soldotna CK Unit North Reference: True Well: Soldotna CK Unit 314-4 Survey Calculation Method: Minimum Curvature Wellbore: SCU 322C-04 Depth Inclination Design: SCU 322C-04 WP4 TVDss +N/ -S Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (^) (_) (usft) usft (usft) (usft) (usft) (usft) 10,197.00 11,265.26 47.81 25.22 10,360.14 10,197.00 2,119.95 1,103.70 2,458,863.90 344,213.80 3.00 2,388.91 Start Dir 6.16°/100' : 11265.26' MD, 10360.14'TVD 11,265.81 47.78 25.22 10,360.51 10,197.37 2,120.32 1,103.87 2,458,864.26 344,213.98 6.16 2,389.32 SR -HIST 11,274.90 47.21 25.24 10,366.65 10,203.51 2,126.38 1,106.73 2,458,870.29 344,216.92 6.16 2,396.02 End Dir : 11274.9' MD, 10366.65' TVD 11,277.84 47.21 25.24 10,368.65 10,205.51 2,128.33 1,107.65 2,458,872.23 344,217.86 0.00 2,398.18 Start Dir 6.85°/100' : 11277.84' MD, 10368.65'TVD 11,300.00 48.73 25.19 10,383.48 10,220.34 2,143.22 1,114.66 2,458,887.02 344,225.07 6.85 2,414.64 11,300.37 48.76 25.19 10,383.73 10,220.59 2,143.48 1,114.78 2,458,887.28 344,225.19 6.85 2,414.92 SR_H2ST 11,301.00 48.80 25.19 10,384.14 10,221.00 2,143.90 1,114.98 2,458,887.70 344,225.40 6.85 2,415.39 Start Dir 3°/100' : 11301' MD, 10384.14'TVD 11,349.46 48.83 23.26 10,416.05 10,252.91 2,177.16 1,129.95 2,458,920.75 344,240.81 3.00 2,451.84 SR_H2SB 11,373.37 48.86 22.31 10,431.79 10,268.65 2,193.76 1,136.92 2,458,937.26 344,248.00 3.00 2,469.83 SR_H3ST 11,400.00 48.90 21.25 10,449.30 10,286.16 2,212.39 1,144.36 2,458,955.79 344,255.69 3.00 2,489.84 11,415.70 48.93 20.63 10,459.61 10,296.47 2,223.44 1,148.59 2,458,966.78 344,260.07 3.00 2,501.63 SR_H3L_ST 11,445.74 49.00 19.44 10,479.34 10,316.20 2,244.73 1,156.35 2,458,987.97 344,268.11 3.00 2,524.18 SR_H3SB 11,492.71 49.12 17.58 10,510.12 10,346.98 2,278.37 1,167.61 2,459,021.46 344,279.82 3.00 2,559.37 SR_H5ST 11,500.00 49.14 17.29 10,514.89 10,351.75 2,283.63 1,169.27 2,459,026.69 344,281.54 3.00 2,564.83 11,562.37 49.36 14.84 10,555.60 10,392.46 2,329.03 1,182.34 2,459,071.91 344,295.22 3.00 2,611.40 End Dir : 11562.37' MD, 10555.6' TVD 11,600.00 49.36 14.84 10,580.11 10,416.97 2,356.63 1,189.65 2,459,099.41 344,302.90 0.00 2,639.44 11,610.30 49.36 14.84 10,586.82 10,423.68 2,364.19 1,191.65 2,459,106.94 344,305.00 0.00 2,647.11 SR_H5SB 11,679.52 49.36 14.84 10,631.90 10,468.76 2,414.96 1,205.10 2,459,157.53 344,319.12 0.00 2,698.69 SR_H7ST 11,679.89 49.36 14.84 10,632.14 10,469.00 2,415.23 1,205.17 2,459,157.80 344,319.20 0.00 2,698.96 11,700.00 49.36 14.84 10,645.24 10,482.10 2,429.99 1,209.08 2,459,172.50 344,323.30 0.00 2,713.95 11,764.10 49.36 14.84 10,686.99 10,523.85 2,477.01 1,221.53 2,459,219.35 344,336.39 0.00 2,761.72 SR_H7SB 11,767.96 49.36 14.84 10,689.50 10,526.36 2,479.83 1,222.28 2,459,222.17 344,337.17 0.00 2,764.59 SR_H8ST 11,800.00 49.36 14.84 10,710.37 10,547.23 2,503.34 1,228.51 2,459,245.59 344,343.71 0.00 2,788.47 11,840.90 49.36 14.84 10,737.01 10,573.87 2,533.34 1,236.46 2,459,275.48 344,352.06 0.00 2,818.94 SR_H8SB 11,900.00 49.36 14.84 10,775.50 10,612.36 2,576.69 1,247.94 2,459,318.67 344,364.12 0.00 2,862.98 11,937.62 49.36 14.84 10,800.00 10,636.86 , 2,604.28 1,255.25 2,459,346.17 344,371.80 0.00 2,891.01 TD at 10800' TVD 11/9/2015 2:57:11PM Page 4 COMPASS 5000.1 Build 73 HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Company: Hilcorp Energy Company TVD Reference: Project: Soldotna CK Unit MD Reference: Site: Soldotna CK Unit North Reference: Well: Soldotna CK Unit 314-4 Survey Calculation Method: Wellbore: SCU 322C-04 1,147.65 Design: SCU 322C-04 WP4 plan misses target center by 22.38usft at 11495.84usft MD (10512.16 TVD, 2280.63 N, 1168.33 E) Halliburton Standard Proposal Report Well Soldotna CK Unit 314-4 SCU 11-04 @ 163.14usft SCU 11-04 @ 163.14usft True Minimum Curvature Targets Measured Target Name Vertical Dip Depth Depth hittmiss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) SR_H5ST 0.00 0.00 10,510.14 2,288.95 1,147.65 2,459,032.30 344,260.00 plan misses target center by 22.38usft at 11495.84usft MD (10512.16 TVD, 2280.63 N, 1168.33 E) 11,300.37 10,383.73 SR_H2ST Circle (radius 50.00) 10,686.99 SIR H7SB 11,373.37 SR_1-13ST 0.00 0.00 10,432.14 2,193.52 1,138.32 2,458,937.00 344,249.40 plan misses target center by 1.39usft at 11373.83usft MD (10432.09 TVD, 2194.08 N, 1137.05 E) 11, 610.30 10,586.82 SIR H5SB Circle (radius 50.00) 10,479.34 SR H3SB 11,492.71 SR_H8SB 0.00 0.00 10,737.14 2,524.20 1,254.92 2,459,266.10 344,370.40 plan misses target center by 20.38usft at 11837.87usft MD (10735.04 TVD, 2531.12 N, 1235.87 E) 11,679.52 10,631.90 SR H7ST Circle (radius 50.00) SR_H2ST 0.00 0.00 10,384.14 2,143.90 1,114.98 2,458,887.70 344,225.40 plan hits target center Circle (radius 50.00) SCU 322C-04 TD 0.00 0.00 10,800.00 2,592.85 1,286.21 2,459,334.32 344,402.60 plan misses target center by 32.92usft at 11935.24usft MD (10798.45 TVD, 2602.54 N, 1254.79 E) Circle (radius 50.00) SR_H3l__ST 0.00 0.00 10,459.14 2,222.20 1,151.84 2,458,965.50 344,263.30 plan misses target center by 3.49usft at 11415.39usft MD (10459.41 TVD, 2223.22 N, 1148.51 E) Circle (radius 50.00) SR_H1ST 0.00 0.00 10,360.14 2,119.95 1,103.70 2,458,863.90 344,213.80 plan hits target center Circle (radius 50.00) SR_1-18ST 0.00 0.00 10,632.14 2,475.00 1,232.47 2,459,217.20 344,347.30 plan misses target center by 43.62usft at 11729.03usft MD (10664.15 TVD, 2451.28 N, 1214.72 E) Circle (radius 50.00) SR_H7ST 0.00 0.00 10,632.14 2,415.23 1,205.17 2,459,157.80 344,319.20 plan hits target center Circle (radius 50.00) Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (°) (°) 11,265.81 10,360.51 SIR _H 1ST 11, 767.96 10, 689.50 S R_H8ST 11, 349.46 10,416.05 SR H2SI3 11,300.37 10,383.73 SR_H2ST 11, 764.10 10,686.99 SIR H7SB 11,373.37 10,431.79 SR_H3ST 11,415.70 10,459.61 SIR HK _ST 11, 610.30 10,586.82 SIR H5SB 11,445.74 10,479.34 SR H3SB 11,492.71 10,510.12 SIR 1-15ST 11,840.90 10,737.01 SR_H8SB 11,679.52 10,631.90 SR H7ST 11/9/2015 2:57.•11PM Page 5 COMPASS 5000.1 Build 73 HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Soldotna CK Unit Site: Soldotna CK Unit Well: Soldotna CK Unit 314-4 Wellbore: SCU 322C-04 Design: SCU 322C-04 WP4 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Soldotna CK Unit 314-4 SCU 11-04 @ 163.14usft SCU 11-04 @ 163.14usft True Minimum Curvature Pian Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 7,400.00 7,398.13 52.42 99.19 Start Dir 31/100' : 7400' MD, 7398.13'TVD : 69.81° LT TF 8,943.97 8,773.34 589.51 376.92 End Dir : 8943.97' MD, 8773.34' TVD 11,233.62 10,338.70 2,098.92 1,093.75 Start Dir 31/100' : 11233.62' MD, 10338.7'TVD 11,265.26 10,360.14 2,119.95 1,103.70 Start Dir 6.161/100' : 11265.26' MD, 10360.14'TVD 11,274.90 10,366.65 2,126.38 1,106.73 End Dir : 11274.9' MD, 10366.65' TVD 11,277.84 10,368.65 2,128.33 1,107.65 Start Dir 6.851/100' . 11277.84' MD, 10368.65'TVD 11,301.00 10,384.14 2,143.90 1,114.98 Start Dir 31/100' : 11301' MD, 10384.14'TVD 11,562.37 10,555.60 2,329.03 1,182.34 End Dir : 11562.37' MD, 10555.6' TVD 11,937.62 10,800.00 2,604.28 1,255.25 TD at 10800' TVD 11/9/2015 2:57:11PM Page 6 COMPASS 5000.1 Build 73 Hilcorp Energy Company Soldotna CK Unit Soldotna CK Unit Soldotna CK Unit 314-4 SCU 322C-04 SCU 322C-04 WN Sperry Drilling Services Clearance Summary Anticollision Report 09 November, 2015 Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Soldotna CK Unit-Soldotna CK Unit 314.4 -SCU 322C-04 - SCU 322C-04 WP4 Well Coordinates: 2,456,758.86 N, 343,081.91 E (60° 43' 18.07" N, 150' 52' 34.94" W) Datum Height: SCU 11-04 @ 163.14usft Scan Range: 0.00 to 11,937.62 usft. Measured Depth. Scan Radius is 1,391.96 usft . Clearance Factor cutoff Is Unlimited, Max Ellipse Separation is Unlimited Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Soldotna CK Unit 314-4 - SCU 322C-04 WN Hilcorp Energy Company Soldotna CK Unit Closest Approach 3D Proximity Scan on Current Survey Data (North Reference) Reference Design: Soldotna CK Unit • Soldotna CK Unit 3141- SCU 322C-04 - SCU 322C-04 WP4 Scan Range: 0.00 to 11,937.62 usft. Measured Depth. Scan Radius is 1,391.96 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 Soldotna CK Unit Soldotna CK Unit 12-3 - Plan: SCU 31B-04 - Plan: SCU 11,937.62 1,121.68 11,937.62 1,023.97 12,167.00 11.480 Clearance Factor Pass - Soldotna CK Unit 121- SCU 121- SCU 121 10,991.26 1,184.12 10,991.26 1,084.88 10,212.09 11.932 Centre Distance Pass - Soldotna CK Unit 121- SCU 121- SCU 121 11,075.00 1,185.70 11,075.00 1,083.85 10,269.34 11.642 Ellipse Separation Pass - Soldotna CK Unit 121- SCU 121- SCU 121 11,825.00 1,287.28 11,825.00 1,165.86 10,765.80 10.602 Clearance Factor Pass - Soldolna CK Unit 211- SCU 211- SCU 211 11,937.62 1,300.27 11,937.62 1,247.64 10,375.00 24.706 Clearance Factor Pass - Soldotna CK Unit 211 - SCU 21A1 - SCU 21A1 11,937.62 1,143.56 11,937.62 1,082.42 11,015.00 18.704 Clearance Factor Pass - Soldotna CK Unit 211- SCU 2213-04 - SCU 22B-04 11,764.54 96.13 11,764.54 5.64 11,298.40 1.062 Clearance Factor Pass - Soldotne CK Unit 3141 - SCU 3141- SCU 314-4 Soldotna CK Unit 3141- SCU 3141- SCU 314-4 - - ■ Soldotna CK Unit 323-04 - SCU 22-04 - SCU 22-04 11,380.30 448.56 11,380.30 365.19 11,140.00 5.380 Ellipse Separation Pass - Soldotna CK Unit 323-04 - SCU 22-04 - SCU 22-04 11,400.00 449.10 11,400.00 365.52 11,140.00 5.374 Clearance Factor Pass - Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 11,398.95 563.34 11,398.95 476.09 11,142.19 6.457 Centre Distance Pass - Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 11,400.00 563.34 11,400.00 476.08 11,142.98 6.456 Ellipse Separation Pass - Soldotna CK Unit 323-04 - SCU 22-04PB1 - SCU 22-0 11,475.00 566.78 11,475.00 478.34 11,211.21 6.408 Clearance Factor Pass - Soldotna CK Unit 323-04 - SCU 31-04 - SCU 31-04 10,466.52 626.73 10,466.52 566.88 9,716.47 10.472 Centre Distance Pass - Soldotna CK Unit 323-04 - SCU 31-04 - SCU 31-04 10,600.00 628.69 10,600.00 564.26 9,828.60 9.758 Ellipse Separation Pass - Soldotna CK Unit 323-04 - SCU 31-04 - SCU 31-04 10,900.00 644.79 10,900.00 576.96 10,096.09 9.506 Clearance Factor Pass - Soldotna CK Unit 323-04 - SCU 31-04 P61 - SCU 31-0 10,721.92 608.51 10,721.92 547.25 9,968.60 9.932 Centre Distance Pass - Soldotna CK Unit 323-04 - SCU 31-04 PBI - SCU 31-0 10,750.00 608.70 10,750.00 547.14 9,989.28 9.889 Ellipse Separation Pass - Soldotna CK Unit 323-04 - SCU 31-04 PB1 - SCU 31-0 10,900.00 615.22 10,900.00 552.41 10,114.20 9.795 Clearance Factor Pass - Soldotna CK Unit 323-04 - SCU 323-04 - SCU 323-04 10,401.62 591.67 10,401.62 530.99 9,774.59 9.751 Centre Distance Pass - Soldotna CK Unit 323-04 - SCU 323-04 - SCU 323-04 10,425.00 591.92 10,425.00 530.67 9,790.58 9.664 Ellipse Separation Pass - Soldotna CK Unit 323-04 - SCU 323-04 - SCU 323-04 10,600.00 609.13 10,600.00 544.04 9,910.22 9.358 Clearance Factor Pass - Soldotna CK Unit 33-05 - SCU 21 C-04 - SCU 21 C-04 11,937.62 747.85 11,937.62 636.62 12,011.74 6.724 Clearance Factor Pass - Soldoma CK Unit 332-04 - SCU 332-04 - SCU 332-04 11,926.81 1,288.20 11,926.81 968.18 11,103.35 4.025 Centre Distance Pass - Soldotna CK Unit 332-04 - SCU 332-04 - SCU 332-04 11,937.62 1,288.24 11,937.62 967.78 11,108.18 4.020 Clearance Factor Pass - 09 November, 2015 - 14:56 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Soldotna CK Unit 314-4 - SCU 322C-04 WP4 Survey tool nroaram From To Survey/Plan Survey Tool (usft) (usft) 103.14 7,400.00 CB -Gyro -SS 7,400.00 11,937.62 SCU 322C-04 WP4 MWD+SC*sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Energy Company Soldotna CK Unit 09 November, 2015 - 14:56 Page 3 of 5 COMPASS HALLIBURTON Anticollision Report for Soldotna CK Unit 314-4 - SCU 322C-04 WN Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to SCU 11-04 aQ 163.14usft. Northing and Easting are relative to Soldotna CK Unit 314-4. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is -150.00°, Grid Convergence at Surface is: -0.76 °. Hilcorp Energy Company Soldotna CK Unit ----- Ladder Plot ------------, ---------- 'u') 12 LEGEND 0 d' - ---- SoldotnaCKUnitl2-3,Plan:SCU31B-04,Plan:SCU31 V ----i -- -- -` - i ---- ----i - ----- ------ -- -- - --- SoldolnaCKUnit 124,SCU 124,S(X1124V0 O Soldotrla CK 1.1021-4, SCU 214, SCU 214 V0 Soldotna CK UnR214, SCU 21A4, SCU21A4 V0 Q Soldotna CK Uni[21 A, SCU 22B-04, SCU 22B-04 V0 Soldotna CK Unit3144, SCU3144, SCU 3144 Vo --- --__ - - - _i - -__ - - - _i - -__ - - - _i - - -- - --------i--- SoldoinaCKUnd323-04,SCU22-04.SCU22-04V0 SoldohaCKL)nk323-04,SCU22-04PBI,SCU22.04PB1 V C Soldot aCKUnit323-04,SCU31-04,SCU31-04V0 400 Soldoina CK Unit323 04,SCU31-04 PBI,SCU31-04 PB1 Soldotia CK Unit323-04, SCU 323-04, SCU323-04 V0 Soldotna CK UnR33-05,SCU 21C-04, SCU 21 C-04 V0 - ---L- - -- --- i -- _-- - - - - - i_ ______-'__-- SoldotrlaCKUnR332-04,SCU332-04,SCU 332-04V0 U SCU322C-04 WP4 0 5000 7500 10000 12500 0 2500 Measured Depth (2500 usfUin) 09 November, 2015 - 14:56 Page 4 of 5 COMPASS HALLIBURTON Anticollision Report for Soldotna CK Unit 314-4 - SCU 322C-04 WP4 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor Hilcorp Energy Company Soldotna CK Unit 10.00 8.75 LEGEND 7.50 5 Soldoha CK Unit12-3, Plan:SCU 31 B-04, Plan:SCU 31 B-04 V gj Soldotna CK Unit 12-4, SCU 12-4, SCU 124 VO `= 6.25 - Soldoha CKUnit214,SCU214,SCU214VO o U Soldotna CK Unit21-4, SCU 21A-4, SCU 21 A-0 VO N LL Soldotna CK Und214, SCU 22B-04, SCU 226-04 VO C 5.00 Soldotna CK Unit 3144, SCU 3144, SCU 3144 V0 d -- Soldotna CK Und323-04,SCU22-04,SCU 22-04 VO 430, Soldotna CKUnH323-04,SCU 22-04PBI,SCU22-04PB1VO to 3.75 Soldotna CKUnit323-04,SCU31-04,SCU31-04VO SoMohaCKUn@323-04,SCU31-04PBI,SCU31-04PB1 VO 2.50 -- 19- Soldotna CK Unit323-04, SCU 323-04, SCU 323-04 VO Ar Soldotna CK Unit33-05, SCU 21 C-04, SCU 21 C-04 VO Collision Avoidance Req Soldotna CK Unit332-04,SCU332-04,SCU332-04 VO 1.25 oho Zone - Stop Drillin SCU322C-04 WP4 0.00 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 0 Measued Depth (2n us f in) 09 November, 2015 - 14:56 Page 5 o/5 COMPASS Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Wednesday, December 16, 2015 4:50 PM To: Davies, Stephen F (DOA) Subject: RE: SCU 322C-04 (PTD #215-217) Questions Attachments: SCU 322C-04 AOR geology.pdf Good evening Steve, Here is the response to your questions from our geologist Jacob Dunstan. Please let us know if you have any additional questions or need anyadditional info. /�� / /[✓ , /\> Thank you! 6 �— Monty M Myers> Drilling Engineer4e< Hilcorp Alaska Office: 907.777.8431,,,, Cell: 907.538.1168 From: Davies, Stephen F (DOA) [mailto:stevec.d9�av-i�eZalFad6vI __. /� i7 /S� Sent: Monday, December 14, 2015 1:30 PM To: Monty Myers Subject: SCU 322C-04 (PTD #215-217) Questions Monty, I'm reviewing the application for Hilcorp's planned SCU 322C-04 gas -injection well, which will be a redrill of existing well SCU 314-04. Please provide a lithologic description of the top seal for the pool, its thickness, its lateral extent, and an explanation as to why that seal will prevent migration of injected gas from the Hemlock Oil Pool. Are there any known faults that occur within the Area of Review (AOR) surrounding the planned well? If so, please provide a structure map on the top of the Hemlock Oil Pool that depicts: • all known faults within the AOR, • the complete paths of any wells that pass through the AOR, • the intercepts of these wells with the faults and with the top of the Hemlock Oil Pool, and • governmental section lines. For each fault, please provide: • the vertical displacement for the fault, • how that displacement was determined, • the true vertical subsea depths for the shallowest and deepest extents of that fault plane (How shallow does it go? How deep does it go?), • each well that penetrates the fault with MD, TVDSS of all intercept points, • any occurrences of lost circulation recorded while drilling, and • a structure cross-section that depicts each known fault and the wells that intercept that fault within the AOR. Thank you, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 CONFIDENTIALITYNOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies alaska. ov. 1) Please provide a lithologic description of the top seal for the pool, its thickness, its lateral extent, and an explanation as to why that seal will prevent migration of injected gas from the Hemlock Oil Pool. - The top seal for the pool in question represents the upper seal for the entirety of the Swanson River Field Hemlock accumulation. It is made up of a —5- 10' thick shale above the Hemlock Bench 1 sand. This seal is considered competent for the prevention of vertical hydrocarbon migration by both the presence of the accumulation itself, as well as prior gas injection EOR projects conducted in wells listed in Table 1. v 2) Are there any known faults that occur within the Area of Review (AOR) surrounding the planned well? - Yes, there is a north dipping, normal fault on the northern part of the AOR. 3) If so, please provide a structure map on the top of the Y Hemlock Oil Pool that depicts: a. all known faults within the AOR, b. the complete paths of any wells that pass through the AOR, c. the intercepts of these wells with the faults and with the top of the Hemlock Oil Pool, and d. governmental section lines. TABLE 1 Well Completion Date SCU 21A- 04 August -94 SCU 312-09 November -62 SCU 314-03 April -89 SCU 314-04 May -66 SCU 321-09 April -84 SCU 323-04 August -68 SCU 323-09 December -73 SCU 332-04 December -67 SCU 341-04 December -62 SCU 341-08 March -63 SCU 343-33 June -66 SRU 234- 15 November -72 SRU 314- 27 March -66 SRU 32-15 May -66 SRU 331- 27 August -71 SRU 412- 22 May -66 Table 2 Well Displacement MD SSTVD SCU 12-04 100 9562 -9359 SCU 22B-04 180 10356 -9871 SCU 323-04 50 8001 -7834 SCU 41-05 j 250 j 11186 j -10690 - See attached structure map, governmental sections lines are shown in light blue on the map. 4) For each fault, please provide: a. The vertical displacement for the fault, - The known vertical displacement for the fault ranges between 0-250'. b. How that displacement was determined, - The displacement was determined by correlating the adjacent wells and determining the amount of missing section from each well at the location of intersection with the fault. c. The true vertical subsea depths for the shallowest and deepest extents of that fault plane (How C1fsr shallow does it go? How deep does it go?), -'�/� ��/ -`�/ - The shallowest know occurrence of the fault is - 4792 TVDSS and the deepest know extent is -12435 TVDSS. d. Each well that penetrates the fault with MD, TVDSS of all intercept points, - Wells, displacement, and depths are listed in Table 2 e. Any occurrences of lost circulation recorded while drilling, - SCU 12-4 (1961) — Fault crossed at 9,562' MD. Past drilling records do not indicate any losses during drilling. 9-7/8" hole was drilled to 10,974' MD and 7" casing run to 10,969'. Cement pumped with full circulation throughout entire job. - SCU 2213-04 (2014) — Fault crossed at 10,356' MD. Did not observe any immediate losses after drilling through fault. Due to water flow into the wellbore, MW was increased to 11.3 ppg which resulted in losses of 50 bph. LCM was pumped which resulted in partially healing losses to 13 bph. LCM then fully treated losses and the well was flowing water. —24 hours. SCU 323-04 (1961) — Fault crossed at 8,001' MD. Past drilling records do not indicate any losses during drilling. 10-5/8" hole was drilled to 10,375' and 7-5/8" casing was run to 10,375. Two stage cement job was conducted with full circulation for both stages. SCU 41-05 (1961) — Fault crossed at 11,186' MD. Past records do not indicate any losses to the fault zone while drilling. 10-5/8" hole was drilled to 111450'. 7" casing was cemented in place at 11,444' in 2 stages. Full circulation during both stages. f. A structure cross-section that depicts each known fault and the wells that intercept that fault within the AOR. Four wells within the AOR penetrate the fault. See attached cross-section (fault intersection is shown with red dashed line) to see the depth of the intersection. Cnnklnlet Master S S S Sf S S SF G_ SCU 12-04 4 SCU_41-05 4 I I I I I I I I I I I I I I I I I _J SCU_1 3-04 t I I I I I I i I I I I I I I I I ..CU 22B-04 � T NK _ NK NK TY 4K NK _TY 4K _TY K SRF R EM _C AR ER S Ht S H2 S _H3 C Nd. S _H5 _H7 ?119 TD[ JW ] JW ] S] W ]_ I I I I I I I S]— -- 14 [J Sl— [JFC [JM] _ _ J S ]cli t S] _ _ S] WS] ] Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Wednesday, December 16, 2015 4:31 PM To: Davies, Stephen F (DOA) Subject: RE: SCU 322C-04 (PTD #215-217) Questions Hello Steve, Here are my responses for these questions. Jacob Dunston has just finished up the responses for your prior questions regarding the injection portion and I will send that to you shortly. • Will SCU 322-04 encounter those over -pressured water sands? o We will definitely encounter the HP Tyonek H2O sand • If so, at what depth? o The top is at approximately 8920' TVD (9181' TMD), bottom is at ^'9120' TVD (9445' TMD) • What is the expected pressure within the sands? o Ranges from 11.5 ppg to 12.5ppg EMWZ� • Is the proposed mud program adequate to handle this pressure? o The mud program weights are adequate to handle the flow. We normally weight up to 11.3-11.5 ppg and kill the flow with ECD while pumping. Before tripping we spot heavy pills to stop the flow.��r��. /— • Are these sands discussed in the Anticipated Drilling Hazards notification that will be posted on the rig and discussed with the drilling crew?� o The Tyonek water sands have been discussed in the drilling program in section 24 and the same crews that have handled these flows in the past will be the same crews on this well. • Will mitigation measures be provided to, and discussed with, the crew? o All flows will be treated as gas flows until we are certain that it is in fact NOT gas. • Will the well be mud logged? o Mud loggers will be present on the well from the time we dig new dirt to TD, watching for gas shows and taking samples. • If not, what measures will be taken to monitor the mud system and pressure during drilling operations? o We will also have our gas detection unit rigged up monitoring for gas, and a gas buster rigged up in case of gas shows. Let me know if this is sufficient or if you have any other questions. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Davies, Stephen F (DOA)[mailto:steve.davies@alaska.gov] Sent: Wednesday, December 16, 2015 9:42 AM To: Monty Myers Subject: RE: SCU 322C-04 (PTD #215-217) Questions Monty, Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Wednesday, December 16, 2015 9:42 AM To: Monty Myers (mmyers@hilcorp.com) Subject: RE: SCU 322C-04 (PTD #215-217) Questions Monty, In addition to the questions below, I noticed that Hilcorp's geologic prognosis for SCU 322C-04 didn't mention the Tyonek water sands. • Will SCU 322-04 encounter those over -pressured water sands? • If so, at what depth? • What is the expected pressure within the sands? • Is the proposed mud program adequate to handle this pressure? • Are these sands discussed in the Anticipated Drilling Hazards notification that will be posted on the rig and discussed with the drilling crew? • Will mitigation measures be provided to, and discussed with, the crew? • Will the well be mud logged? • If not, what measures will be taken to monitor the mud system and pressure during drilling operations? Thank you again, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 CONFIDENTIALITYNOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Davies, Stephen F (DOA) Sent: Monday, December 14, 2015 1:30 PM To: Monty Myers (mmyers(ci)hilcorD-com) Subject: SCU 322C-04 (PTD #215-217) Questions Monty, I'm reviewing the application for Hilcorp's planned SCU 322C-04 gas -injection well, which will be a redrill of existing well SCU 314-04. Please provide a lithologic description of the top seal for the pool, its thickness, its lateral extent, and an explanation as to why that seal will prevent migration of injected gas from the Hemlock Oil Pool. Are there any known faults that occur within the Area of Review (AOR) surrounding the planned well? If so, please provide a structure map on the top of the Hemlock Oil Pool that depicts: • all known faults within the AOR, • the complete paths of any wells that pass through the AOR, • the intercepts of these wells with the faults and with the top of the Hemlock Oil Pool, and • governmental section lines. For each fault, please provide: • the vertical displacement for the fault, • how that displacement was determined, • the true vertical subsea depths for the shallowest and deepest extents of that fault plane (How shallow does it go? How deep does it go?), • each well that penetrates the fault with MD, TVDSS of all intercept points, • any occurrences of lost circulation recorded while drilling, and • a structure cross-section that depicts each known fault and the wells that intercept that fault within the AOR. Thank you, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies2alaska.gov. TRANSMITTAL LETTER CHECKLIST WELL NAME: , _� (2 (— ':5 ZZ C �� 7 PTD: �� _ 1 -7 Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: U -W POOL: Sj& f-�C) 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 (If last two digits No. , API No. 50- - - - 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 onpermit). 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 SWANSON RIVER, HEMLOCK OIL - 772100 -- – – - – — Well Name: SOLDOTNA CK UNIT 32.2C-04 __– _Program SER Well bore seg El— PTD#: 2152170 Company HILCORP_ALASKA LLC —__ -- _ – — Initial Class/Type —SER / PEND GeoArea 820_-- --__– Unit 51950 On/Off Shore On Annular Disposal ❑ Administration 1 Perm it- fee attached NA 2 Lease number appropriate_ Yes Entire well within former -Federal Lease (now Hilcorp Fee Lease) FEDA028997. 3 Unique well name and number Yes 4 Well located in_a_defined_pool Yes This gas injection -well will_open Swanson_ River, Hemlock Oil Pool - 772100 governed by 5 Welllocatedproper distance from drilling unit boundary- - Yes CO 123B. CO 123B, Rule -5: There shall be no restrictions_ as to the well spacing within_ 6 Well located proper distance from other wells_ Yes the Hemlock Oil Pool except that no wellbore may be open to test or regular production 7 Sufficient acreage_ available in drilling unit Yes in_ a well within 500' of the external property line -of the Affected_ Area [of CO 1236] 8 If deviated, is wellbore plat -included Yes where the owners and landowners are not the same on both sides of the line. 9 Operator only affected party_ - - Yes - As planned, this well conforms to spacing requirements._ 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 SFD 12/17/2015 114 Well located within area and strata authorized by Injection Order # (put 10# in comments)(For Yes This _ _AIO 13A. well -will open Swanson River, Hemlock OilPool - 772100 governed by 15 All wells within _1/4 -mile area of review identified (For service well only) Yes - SCU 323-04, SCU 22-04, SCU-22-04PB1, SCU-32C-04,-SCU 12-04, SCU 12A-04, SCU 21C-04,_ - 16 Pre -produced injector: duration of pre production less than 3 months -(For _service well only) Yes SCU 2213-04, SCU 31-04, SCU 31-04 P131, SCU 21-04, SCU 21A-04. _ - - - 17 Nonconven. gas conforms to AS31,05.0300.1.A),Q.2.A-D) NA 18 Conductor string_ provided - - - NA Conductor set in parent well 314-04 Engineering 19 i20 Surface casing protects all known USDWs - NA surface casing set CMT vol adequate to circulate on conductor & surf _csg NA Surface casing is fully cemented 21 CMT vol_ adequate to tie-in -long string to -surf csg- NA Production casing set 22 CMT will cover -all known_ productive horizons- Yes - - - 4.5"- liner will be -fully cemented... window at 7400 ft in 7" casing ._ 23 Casing designs adequate for C, T, B &_ permafrost Yes BTC calculations provided and meet acceptable_ industry_ standards. - - - - 24 Adequate tankage or reserve pit - - - Yes Rig has steel pits.. All waste to approved disposal well. 25 If -a re -drill, has a 10-403 for abandonment been approved - Yes P & A sundry 315-718 26 Adequate wellbore separation_ proposed- Yes wellbore diverges from motherbore well 314-04. 127 If diverter required, does it meet_ regulations NA_ - Wellhead in place.. BOPE will be used. Appr Date 28 _Drilling fluid_ program schematic _&_ equip -list adequate Y_es Max pressure= 2808_psi_(5.0 ppg EMW) Tyonek Water flow may have higher BHP 9-10 ppg . GLS 12/17/2015 '29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to -(put psig in comments) Yes MASP= 1728 psi _(will test -BOPE _to 3500 psi) - - - - - - - - - 31 Chokemanifoldcomplies w/API_ RP -53 (May 84) Yes 32 Work will occur without operation shutdown_ Yes - Sundry required for completion and perforating. 133 Is presence_ of H2S gas probable - - - No H2S not expected in well. Rig has sensors and alarms. 134 Mechanical condition of wells within AOR verified (For service well only) Yes 1/4 mile review completed. All wells- in area have proper mechanical integtrety. 35 Permit -can be issued w/o hydrogen_ sulfide measures Yes - None anticipated based on offset wells.- Geology 36 Data presented on potential overpressure zones Yes Underpressured reservoir (2.9 to 5.1 ppg EMW)_expected; will be drilled_ using 9.5 - 11.5ppg mud.._ Appr Date 37 Seismic_ analysis of shallow gas -zones . - - - - NA_ - - - - - - - - - - - - SFD 12/14/2015 138 Seabed condition survey (if off -shore) - NA 39 Contact name/phone for weekly progress reports [exploratory only] NA - - - - - - Geologic Date Engineering Public GAS INJECTION WELL. Although breached by a N-dipping,175' normal fault about 1,200' north of the injection point, the top seal Date: Date Commissioner: Commissioner: Commissioner for the Hemlock Oil Pool remains intact (as evidenced by the existence of the oil accumulation), so the fault likely won't provide a 43 pathway for out -of -pool gas migration. However, careful surveillance of injection operations is recommended. SFD 12/17/15 Swanson River SCU 322C-04 50-133-10104-01-00 Soldotna Creek Unit Kenai Peninsula Borough, Alaska January 18, 2016 – January 27, 2016 Provided by: Approved by: Jacob Dunston Compiled by: Donna New Ralph Winkelman Distribution Date: February 17, 2016 TD Date: 1/27/2016 SCU 322C-04 1 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ................................................................................................ 2 1.1 Equipment Summary ...................................................................................................................... 2 1.2 Crew................................................................................................................................................ 2 2 GENERAL WELL DETAILS ................................................................................................................... 3 2.1 Well Objectives ............................................................................................................................... 3 2.2 Hole Data ........................................................................................................................................ 4 2.3 Daily Activity Summary ................................................................................................................... 1 3 GEOLOGICAL DATA ............................................................................................................................. 3 3.1 Lithostratigraphy ............................................................................................................................. 3 3.2 Lithology Details.............................................................................................................................. 4 3.3 Sampling Program ........................................................................................................................ 11 4 DRILLING DATA .................................................................................................................................. 12 4.1 Surveys ......................................................................................................................................... 12 4.2 Bit Record ..................................................................................................................................... 16 4.3 Mud Record .................................................................................................................................. 17 4.4. Drilling Progress ........................................................................................................................... 18 5 SHOW REPORTS ............................................................................................................................... 19 6 DAILY REPORTS ................................................................................................................................ 20 Enclosures 2” / 100’ Formation Log (MD/TVD) 5” / 100’ Formation Log (MD/TVD) 2” / 100’ LWD Combo Log (MD/TVD) 2” / 100’ Drilling Dynamics Log (MD/TVD) 2” / 100’ Gas Ratio Log (MD/TVD) Final Data CD SCU 322C-04 2 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type /Position Total Downtime Comments Computers – Surface Logging (3) Rigwatch Server, Rigwatch Remote DML, LWD WITS, Rigwatch Remote 0 Ditch gas QGM gas trap; Flame ionization total gas & chromatography. Hook Load / Weight on bit WITS from Pason 0 Mud Flow In Calculated value derived from Strokes/Minute and Pump Output 0 Mud Flow Out WITS from Pason 0 Pit Volumes, Pit Gain/Loss WITS from Pason 0 Pump Pressure WITS from Pason 0 Pump Stroke Counters (2) WITS from Pason 0 Rate of Penetration Calculated from Pason 0 RPM WITS from Pason 0 Torque WITS from Pason 0 WITS To/ From Pason Rigwatch Remote (HP Compaq) 0 1.2 Crew Mud Logging Unit Type: Arctic Mud Logging Unit Number: ML030 Logging Geologists Years1 Days2 Sample Catchers Years Days2 Donna New 9 14 Paul Webster 36 1/15 Ralph Winkelman 25 1/15 Barbara Delaney 8 13 *1 Years experience as Mudlogger *2 Days at wellsite between rig up and rig down of logging unit. SCU 322C-04 3 2 GENERAL WELL DETAILS 2.1 Well Objectives SCU 322C-04 is a gas injection well planned to be re-drilled in a North-easterly direction from the existing SCU 314-04 utilizing the existing casing program down to 7400’MD/ 7400’TVD. At 7400’MD the parent wellbore will be sidetracked and a new wellbore drilled penetrating several Hemlock targets. A 4537’ x 6” open hole section is planned. Operator: HILCORP ALASKA, LLC Well Name: SCU 322C-04 Field: Swanson River Field County: Kenai Peninsula Borough State: Alaska Company Representatives: Rance Pederson, Shane Hauck, Shane Barber, Marvin Rogers Location: Surface Coordinates 823’ FSL, 780’ FWL, Sec 4, T7N, R9W, SM, AK Ground ( Pad ) Elevation 145’ AMSL Rotary Table Elevation 163’ AMSL Classification: Single Zone Gas Service API #: 50-133-10104-01-00 Permit #: 215-217 Rig Name/Type: Saxon 169 / Land / Double Spud Date January 18, 2016 Total Depth Date: January 27, 2016 Total Depth 11525’ MD / 10530.95’ TVD Primary Targets Hemlock H1, H2 Primary Target Depths H1 11266’ MD/ 10361’ TVD, H2 11300’MD/ 10384’TVD Total Depth Formation: Hemlock Completion Status: 4 1/2” Casing LWD-MWD Services. Halliburton / Sperry Drilling Services Directional Drilling Halliburton / Sperry Drilling Services Drilling Fluids Service Halliburton / Baroid Wireline Logging Service SCU 322C-04 4 2.2 Hole Data Hole Section Max Depth TD Formation MW ppg Dev oinc Csg Dia Shoe Depth LOT ppg MD (ft) TVD (ft) MD (ft) TVD (ft) Window Tyonek 6” 7407 7407 12.5 6” 11525’ 10531’ Hemlock 10.6 46.52 4 1/2” 11524’ 10530’ SCU 322C-04 1 2.3 Daily Activity Summary 1/15/2016 Rig up e-line, POOH and P/U CIBP, run in hole and set CIBP @10157'; POOH and test casing; RIH with E-line and cement with 57 gals cement on top of CIBP; Pooh w/ e-line; pooh; RIH and tag cement; POOH and pick up second CIBP; RIH and set same @ 7413'. POOH with e-line. Test casing at 3500 psi- good. Rig down e-line and begin BHA and HWDP. Picking up pipe at report time. 1/16/2016 Continued to pick up drill pipe. POOH racking back drill pipe. Return to picking up drill pipe 1/17/2016 Continued to pick up drill pipe to trip in to 7413'; rig service - grease draw works, crown, and blocks; pick up and make up whipstock; Trip in hole with whipstock filling every thirty stands; tag cast iron bridge plug; rig up wire line; run in hole with gyro; orient whip stock; pull out of hole with gyro. 1/18/2016 Continue to mill window to 7427' circulate bottoms up and check for flow; rig up for and perform F.I.T. to 12.5ppg. and held 10 min.; 36 gals returned at bleed off; check flow- static; and begin POOH; (170 pound of metal returned during milling operations.) Pull out of hole; pull wear bushing; flush stack with Johnny Whacker; blow down mud lines; rinse stack. Set test plug and test joint; make up TIW to test joint; purge air from stack, choke, manifold, and test lines. Max Gas 19 units. 1/19/2016 Continue to test BOPs; check PVTs , flow meters, and alarms, pull test plug, install wear bush and blow down; prep rig floor for BHA; p/u and m/u BHA; download tool, load sources, p/u HWDP; RIH to 2000'; tour change; continue to trip in hole; to 7372' filling pipe; testing MWD, and blowing down every 2500'; pump out trip tank; circulate above window; SM with company man, directional, wireline and gyro; rig up wireline, make up side entry sub, install gyro in string; and run in with gyro; Trip Gas = 526 units. 1/20/2016: Drilled ahead 1/21/2016 Drill ahead to 7870’; circulate bottoms up, check flow, flowing at 3.9 bbls/hr.; circulate bottoms up with 990 units gas; continue to circulate and build mud from 9.8+ to 10.1 ppg.; check flow , flowing at 2.1 BPH; circulate another bottoms up with 1100 units gas circulated out; continue circulating and weighting up from 10.1 ppg to 10.4 ppg. Pull out of hole from 7870’ to 7390’ 1/22/2016: Pull out of hole from 1450' to 112'; lay down BHA and Remove source and down load; pull wear bushing; well started flowing;@ 1.33 C at 10am; install test plug and rig up test equipment; flood CM; test annular and install choke; test electrical choke; rig down test equipment; blow down manual choke; install wear bushing;; pick up and make up BHA and down load; well flowing at 1.3 BPH; Tool not communicating; lay down “Slim Phaze” and pick up new shallow pulse test @ 112'; load sources; well flowing at1BPH; Load sources in directional tools and start tripping in. 1/23/2016: Drill from 7870' to 8640' 1/24/2016: Drill ahead from 8640’ to 8862' ; circulate bottoms up and clean hole with 883 units gas returned; POOH and check flow (4.4BPH) hole fill 5.2 bbls under theoretical; circulate bottoms up and pump 15 bbls high viscosity sweep 12.5ppg pill at 7499'; POOH to 7375' ; floe 4.0BPH; Slip and cut 90' drill line; grease equipment - draw works, top drive, crown blocks, check brakes driveline; trip in to 8760' and encountered tight spots @ 7495 and 7596' and 8513' ream down as needed. Continue to slide and rotate as per directional plan. 1/25/2016: Drill ahead to 9854'; pump 15 barrel high viscosity sweep; 20% cuttings; POOH out of hole to 8728'; hole flowing 8.6 barrels per hour; perform rig service; return to bottom and circulate bottoms up. Increase in cuttings 300% and 1410 units of wiper gas returned; 39 barrels of water cut mud dumped lowest cut by water was 10ppg. Resume drilling ahead to 10049'. SCU 322C-04 2 1/26/2016: Drill ahead from 10049' to 10850'; circulate and condition mud; pull out of hole for wiper trip from 10850' to 9750' on elevators with no issues; lay down one joint and pull on singles; check on flow with well flowing 13 BPH; hole took 10 barrels under calculated hole fill; grease equipment- draw works, blocks, and crown, check brakes. Trip back to bottom and resume drilling ahead. Max gas today 1418 units at bottoms up after wiper trip. 1/27/2016: Continued drilling ahead to TD @ 11,525'. Pumped 15 bbl Hi-Vis sweep- 10% increase in cuttings and came back 12 bbl late. Pulled 5 stands and flow-checked well- 11.3 bph flow. Continued POOH on wiper trip T/7,369'. RIH and washed last stand down. Cut weight (10.0+ ppg) mud showed at surface after 1000 strokes. Dumped 201 bbls water and gas cut mud- lowest MW was 8.8 ppg. Due to interface w/ water B/U cuttings slipped and showed up at shakers 32 bbls late. 200% increase in cuttings mostly sand and fine coals. Circulated shakers clean and pumped Hi-vis (300) sweep. Circulating sweep out of hole at time of report. 1/28/2016: Pump and circulate sweep out of hole (50% increase in cuttings. Check flow before POOH (10 bbls/hr); POOH form 11525’ to 7370’; backreamed first 4 stands; pumped out fifth stands; POOH on elevators to window (32.8 barrels under calculated hole fill for trip to 7370’; flow check at window = 9.3 bbls/hr; spot 20 bbl weighted pill at window; POOH from 7370’ to 5488’; blow down topdrive, flow check = 7.2 bbls/hr. POOH, laying down drill pipe to 4890’; circulate bottoms up, spot 26 barrel heavy weight pill at 4890’ (Max Gas = 1218u). POOH, laying down drill pipe to 970’. Rack back heavyweight drill pipe, flow check at 10 bbls/hr. Lay down and handle BHA. 100 barrel net gain over last 12 hours. Rig up floor equipment and Weatherford to run liner. Run 4.5” liner. 1/29/2016: Pick up and run 4.5” liner. Circulate bottoms up at 1392’ (Max Gas = 1725u), at 2052’ (Max Gas = 1591u), at 2838’ (Max Gas = 1640u), RIH with 4.5” liner from 2838’ to 4288’. Circulate bottoms up with 3 separate gas peaks (Max Gas = 1317u), dump 20 bbls watered- down mud. Make up hangar assembly, rig down Weatherford power tongs. Spot 23 bbls 14.3 ppg pill at 4288’ (Max Gas = 1617u). RIH with 4.5” liner on drill pipe from 4288’ to 7390’, filling pipe about 10 stands (start overboard with displacement at 6710’). Circulate until gas values low (Max Gas = 1475u) with 177 bbls watered-up mud overboarded to cuttings bin. RIH to about 8005’, fill pipe. RIH to about 8092’; pipe stopped going in; circulate until gas values low (Max Gas = 1589u). Run 2 stands (pipe stopped). Wash into hole from about 8267’ to about 8750’ with gas peaks of 798u, 1190u, and 1229u. 1/30/2016: Wash into hole with 4.5” liner on drill pipe from about 8750’ to 8893’ with gas peaks of 557u, 1341u. RIH on elevators from 8893’ to 9043’. Wash/Ream down to about 9063’’ (Max Gases = 1029u, 666u, 577u, 683u); RIH on elevators to 9246’. Wash from 9246’ to Bottom’ (Max Gases = 979u, 846u, 972u, 1002u, 1037u, 1015u,975u at various spots in section). Circulate liner before cement job. 1/31/2016: Circulate liner before cement job. Do cement job. Canrig Mudloggers released at 04:15 hours. SCU 322C-04 3 3 GEOLOGICAL DATA 3.1 Lithostratigraphy Tops picked by Hilcorp Geo, Jacob Dunston FORMATION PROGNOSED ACTUAL MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) SR H1ST 11266 10361 ‐10198 11227 10330 ‐10167 SR H2ST 11300 10384 ‐10221 11275 10362 ‐10199 SCU 322C-04 4 3.2 Lithology Details As per Hilcorp direction, a Canrig-provided full service mudlogging program, with lithology descriptions of interval-collected rock cuttings samples in the Tyonek and Hemlock Formations, was initiated at the window milled at (7413’’ MD / 7412.5’ TVD). The Kenai Group formations of Alaska’s Cook Inlet Basin, which include the Sterling, Beluga, and Tyonek were deposited in a variable-energy fluvial system within a large closed fore-arc basin. The stratigraphic column consists of very dominant thin to massive sections of sandstone and claystone-siltstone, which are interrupted by extensively-distributed thinner zones of coal and carbonaceous rocks, locally to generally abundant thin layers of original and re-deposited volcanic ash, and minor beds of basal or modal conglomerate. Gradational upward-fining sequences and bi-modal zones are abundant within the sandstones. Stratovolcanoes, perpetually forming along the fore-arc’s margins; produced abundant widely-distributed deposits of vitric air fall volcanic ash; which became a major directly-derived source, and/or a consistent lithogenic influence, for all Tertiary soft-sediment rocks in the Cook Inlet Basin. Note that the special modifying term “tuffaceous” in Canrig Lithology Descriptions was created to address the diversity of volcanic-origin rocks in the Cook Inlet basin, and its use may include everything from discernible micro-shard concentrations of disaggregated volcanic glass to rare layers of vitric ignimbrite. Tuffaceous Sandstone/ Sand (7450' ‐ 7550') = very light gray to grayish white with light to medium gray secondary hues; soft to fragile and crunchy; irregular shaped; non to very calcareous; ash matrix supports loose sand grains; clear to translucent quartz and volcanic glass; very fine upper to medium lower; angular to sub angular; quartz frame work; trace to moderate argillaceous component; interstices moderately to moderately well filled; trace to >1% dark lithics; massive structure with trace specimens showing very thin interbedded laminae of carbonaceous material. Conglomeratic Sandstone (7550' - 7610') = very pale gray to whitish gray with rare medium gray; framework mostly quartz in tuffaceous matrix; fine to coarse grained with occasional upper very coarse; soft; very calcareous/ argillaceous cementation; grain supported; interstices well filled; structure massive; grading to tuffaceous siltstone; thinly interbedded with thin coals and occasional thin tuffaceous claystones. Tuffaceous Siltstone (7610' - 7680') = pale gray to medium gray; soft to crumbly tenacity, earthy fracture; cuttings habit wedge like; luster dull; texture silty; structure massive. Tuffaceous Sandstone/ Sand (7680' - 7750') = very light gray with a mottled appearance from abundant dark secondary hues fragile to pulverulent; crunchy; irregular with trace PDC bit action shaped cuttings; gritty texture; sparkling luster form abundant glass shards; non calcareous; ashy matrix supports loose sand grains; dominantly clear to translucent quartz and volcanic glass, trace medium to dark gray; very fine upper to trace very coarse upper, dominantly fine upper to medium upper; angular to subangular; moderately well sorted; friable; loosely consolidated in ashy matrix; non to very calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (7750' - 7820') = medium to medium light gray with light brownish gray secondary hues; soft to slightly firm; irregular to trace PDC bit action shaped cuttings; silty to clayey texture; dull to earthy luster; moderately soluble and expansive; poor to fair cohesiveness and adhesiveness; non calcareous; trace dark brown to black carbonaceous laminations and inclusions. SCU 322C-04 5 Coal (7820' - 7870') = black with grayish black secondary hues; very firm to hard and brittle; blocky to platy; planar fracture dominant; smooth texture; resinous luster; abundant, prolonged outgassing bubbles present. Sandstone/ Sand (7870’ - 7960’) = medium light gray to light gray w/ common salt and pepper specimens; very fine to fine grains with occasional medium grained specimens; moderately well sorted; subangular to sub rounded; soft to easily friable; trace to moderate tuffaceous matrix material; predominantly grain supported interstices moderately well filled; occasional thin laminae of carbonaceous material; common dark gray lithic clasts. Tuffaceous Siltstone (7960' - 8080') = medium gray to medium light gray; crumbly to firm earthy tenacity; fracture hackly to sub planar with occasional irregular; cuttings habit wedge like to occasional sub planar; luster dull; texture silty; structure massive to very thinly laminated; occasional very thin wavy laminae of carbonaceous material; trace mica accessory. associated with thinly bedded coals and commonly graded from tuffaceous sandstones. Coal (8050' - 8080') = black to blackish brown; crunchy tenacity; fracture conchoidal to blocky; cuttings habit wedge like to flakey and occasional sub tabular to sub blocky; luster vitreous; texture smooth; structure thinly laminated. Tuffaceous Claystone/ Tuffaceous Siltstone (8080' - 8140') = medium to medium light gray with light olive gray and light brownish gray secondary hues; soft to slightly firm; irregular with PDC bit action shaped common; silty to clayey texture; dull to earthy luster; slight to moderately soluble and expansive; poor to fair cohesiveness; poor adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Tuffaceous Sandstone/ Sand (8140' - 8200') = very light gray to grayish white with darker gray and brown secondary hues; fragile; crunchy; ashy matrix acts as supporting matrix for loose sand grains; dominantly clear to translucent quartz and volcanic glass, trace light to medium gray and light greenish gray; very fine upper to medium lower, dominantly fine; angular to subangular; fair to good sorting; unconsolidated; trace to common thin coal beds throughout interval. Tuffaceous Claystone/ Tuffaceous Siltstone (8200' - 8270') = medium to medium light gray with light olive gray and light brownish gray secondary hues; soft to slightly firm; irregular with PDC bit action shaped common; silty to clayey texture; dull to earthy luster; slight to moderately soluble; hydrophilic; slightly expansive; non calcareous; trace to common dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Sandstone/ Sand/ Tuffaceous Sandstone (8270' - 8360') = light gray overall with a moderate to strong salt and pepper appearance, individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray and black; very fine upper to trace coarse lower, dominantly fine upper to medium lower; angular to subangular; fair to good sorting; non calcareous cement; moderately hard to brittle at times; trace ashy matrix supported grains; dirty white; fragile to pulverulent; non calcareous; present as minor component in dominantly tuffaceous claystone/ siltstone formation; trace thin coals. Tuffaceous Sandstone/ Sand (8360' - 8420') = very light gray to grayish white with darker gray and brown secondary hues; fragile; crunchy; ashy matrix acts as supporting matrix for loose sand grains; dominantly clear to translucent quartz and volcanic glass, trace light to medium gray and light greenish gray; very fine upper to medium lower, dominantly fine; angular to subangular; fair to good sorting; unconsolidated; scattered sandstone salt and pepper appearance; moderately hard; non calcareous. SCU 322C-04 6 Tuffaceous Sandstone/ Sand (8420' - 8500') = very light gray to grayish white with darker gray and brown secondary hues; fragile; crunchy; ashy matrix acts as supporting matrix for loose sand grains; dominantly clear to translucent quartz and volcanic glass, trace light to medium gray and light greenish gray; very fine upper to trace very coarse upper; dominantly fine upper to medium upper; angular to subangular; moderately well sorted; very loosely supported by ashy matrix; non calcareous. Tuffaceous Claystone/ Tuffaceous Siltstone (8500' - 8550') = medium to medium light gray with light olive gray and light brownish gray secondary hues; soft to slightly firm; irregular with PDC bit action shaped common; silty to clayey texture; dull to earthy luster; slight to moderately soluble and expansive; poor to fair cohesiveness; poor adhesiveness; non calcareous. Tuffaceous Sandstone (8550' - 8640') = very light gray to light grayish white with occasional specimens showing a salt and pepper appearance; very fine grained to upper medium grains with occasional inclusions of course to very coarse grains; well sorted within individual specimens; sub angular to angular; easily friable to soft with common loose grains and very small aggregates of grains; matrix abundant in the finer grained specimens; the medium grained specimens showed trace to no matrix material and was grain supported w/ long contact fabric; trace thin laminar carbonaceous material evident in rare samples; up to 5% dark gray to black sedimentary lithic clasts. Tuffaceous Siltstone (8640' - 8700') = light medium gray to medium gray with trace brownish gray; tenacity slightly soft to firmly crumbly; fracture irregular to slightly hackly; cuttings habit wedge like to sun tabular; luster dull to earthy; texture silty to very slightly gritty; structure massive. Coal (8680' - 8710') = black to trace brownish black; tenacity predominantly crunchy to occasional slightly crumbly in the least developed brownish black specimens; fracture conchoidal with occasional planar to sub planar; cuttings habit blocky to wedge like; structure thinly laminated; thinly interbedded with tuffaceous siltstones; and tuffaceous sandstones. Tuffaceous Sandstone (8710' - 8000') = very pale grayish white to pale whitish gray with occasional darker light gray and trace very pale yellowish gray; very fine to fine grained w/ occasional lower medium and trace coarse; well sorted to occasionally poorly sorted; soft; abundant tuffaceous matrix; interstices well filled; bedding massive; trace thinly laminated carbonaceous material. Tuffaceous Siltstone (8810' - 8860') = light medium gray to light gray with occasional medium gray; tenacity soft to moderately crumbly with trace slightly crunchy; fracture sub planar to slightly irregular; cuttings habit wedge like to sub tabular ; luster dull; texture silty; structure massive with trace thin laminae carbonaceous material. Tuffaceous Siltstone/ Tuffaceous Claystone (8860' - 8930') = medium light to light gray; soft to slightly firm; irregular shaped cuttings; silty to clayey texture; dull to earthy luster; slightly soluble; non expansive; poor adhesiveness; poor to fair cohesiveness; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Coal (8930' - 8980') = black to dark brownish black; moderately crunchy to easily crunchy tenacity; fracture occasionally conchoidal to occasionally sub tabular or sub blocky; cuttings habit slightly blocky, slightly tabular, slightly wedge like and occasionally flakey; luster vitreous to slightly resinous; texture smooth; structure very thinly laminated; very thinly interbedded with tuffaceous siltstones and tuffaceous sandstones; trace very slow outgassing. Tuffaceous Siltstone (8980' - 9050') = medium gray to light medium gray with trace slightly darker gray; tenacity firmly crumbly to moderately soft ; fracture slightly hackly to slightly earthy; cuttings habit mostly wedge like with occasional tabular; dull luster; texture silty; structure massive. SCU 322C-04 7 Coal (9050' - 9160') = black to brownish black; tenacity easily crunched to firm crunchy with occasional less well developed specimens approaching slightly crumbly; fracture sub planar to irregular; cuttings habit flakey to sub tabular; luster resinous to slightly dull with occasional slightly vitreous; texture smooth to very slightly silty; structure very thinly laminated; thinly interbedded with tuffaceous sandstones and tuffaceous siltstones. Conglomeratic Tuffaceous Sandstone (9070' - 9130') = very pale gray to whitish gray; very fine grained to lower medium grained with common inclusions of very coarse grains; predominantly poorly sorted; angular to sub angular with the very coarse grains exhibiting fresh breaks across the grains; hardness soft to moderately easily friable trace firmly friable in specimens showing sparse to no matrix material; most specimens have abundant matrix material and are matrix supported; interstices well filled and bedding massive. thinly interbedded with thin coals and thin tuffaceous claystone. Tuffaceous Sandstone (9130' - 9250') = whitish gray to very pale gray; very fine to fine with only trace of very coarse grains as in previous intervals; moderately well sorted; soft to easily friable; interstices well filled, matrix supported; bedding massive; only trace coal and tuffaceous claystone in tray. Carbonaceous Shale (9250' - 9280') = brown to very dark brown with occasional blackish brown; slightly crunchy to easily crunched; fracture sub planar; cuttings habit flakey to sub tabular; luster slight resinous to dull; texture smooth; structure thinly laminated; thinly interbedded with tuffaceous sandstone. Tuffaceous Siltstone (9280' - 9340') = light medium gray to medium gray with occasional white to light pinkish gray specimens; tenacity soft to firmly crumbly; fracture irregular to slightly hackly; cuttings habit massive to slight wedge like; luster dull; texture silty; structure massive. Tuffaceous Sandstone (9340' - 9420') = medium gray to light gray with trace brownish gray specimens; fine to lower medium grained; moderately well sorted to occasional poorly sorted; sub angular to sub rounded; sphericity moderately high; firmly friable to soft and slightly crumbly; sparse matrix material with both grain supported and matrix supported specimens evident; interstices moderately well filled; bedding massive, occasional thin laminae of carbonaceous material. Tuffaceous Claystone/ Tuffaceous Siltstone (9420' - 9500') = medium light gray with light brownish gray and light olive gray secondary hues; soft to fragile; irregular to sub discoidal with trace PDC bit action shaped cuttings; silty to clayey texture; dull, earthy luster; slight to moderately soluble and expansive; poor to fair cohesiveness; poor adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Tuffaceous Sandstone/ Sand (9500' - 9580') = very light gray to grayish white with mottled appearance from light brown and light gray secondary hues; very fragile and pulverulent; crunchy; non calcareous ashy matrix supports loose sand grains; clear to translucent quartz and volcanic glass, trace light green to greenish gray, light to medium gray and black; very fine upper to trace very coarse upper, dominantly fine upper to medium lower; angular to subangular; moderately well sorted; loosely consolidated in ash matrix to disaggregated. Tuffaceous Claystone/ Tuffaceous Siltstone (9580' - 9650') = medium light gray with light brownish gray and light olive gray secondary hues; soft to fragile; irregular to wedgelike with trace PDC bit action shaped cuttings; silty to clayey texture; dull, earthy luster; slight to moderately soluble and expansive; poor to fair cohesiveness; poor adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds throughout interval. SCU 322C-04 8 Sand (9650' - 9720') = very light gray overall with abundant multicolored liths dominantly clear to translucent quartz and volcanic glass, trace amounts of light to dark gray, black, light greenish gray and pale rose; very fine upper to coarse upper, dominantly fine upper to medium upper; angular to subangular; poor to fair sorting; disaggregated with trace ash matrix supported grains; dirty white very fragile; non calcareous; trace thin coal beds. Tuffaceous Sandstone/ Sand (9720' - 9790') = medium light gray to grayish white with mottled appearance from light brown and light gray secondary hues; very fragile and pulverulent; crunchy; non calcareous ashy matrix supports loose sand grains; clear to translucent quartz and volcanic glass, trace light green to greenish gray, light to medium gray and black; very fine upper to very coarse upper, dominantly fine upper to medium upper; angular to subangular; poor to fair sorting; very loosely consolidated in ashy matrix to disaggregated; non calcareous. Tuffaceous Sandstone/ Sand (9790' - 9850') = medium light gray to grayish white with mottled appearance; very fragile and pulverulent; crunchy; non calcareous ashy matrix supports loose sand grains; clear to translucent quartz and volcanic glass, trace light green to greenish gray, light to medium gray and black; very fine upper to very coarse upper, dominantly fine upper to medium upper; angular to subangular; poor to fair sorting; very loosely consolidated. Carbonaceous Shale (9850' - 9970') = very dark grayish black to black; crunchy to easily crunched; fracture irregular to sub planar; habit wedge like to sub tabular; luster dull to resinous; structure thinly laminated; no outgassing observed. Tuffaceous Sandstone/ Sand (9880' - 10000') = whitish gray to very pale gray; fine to lower medium grained; moderately well sorted; sub angular to sub round; sphericity moderately high; soft to barely crunchy; fairly abundant matrix material with most specimens matrix supported; interstices well to moderately well filled; bedding predominantly massive w/ occasional specimens showing very thin, closely stacked, laminae of black carbonaceous material; less than 3% dark gray to black; soft; dull; reworked sedimentary lithic fragments. Tuffaceous Sandstone (10000' - 10030') = white to whitish gray with trace pale yellowish gray; medium grained with trace upper coarse grains included; well to moderately sorted sub angular to sub rounded; sphericity moderately high soft to easily friable with trace firmly friable; variable amounts of tuffaceous matrix with most specimens having moderate to abundant amount of matrix and commonly matrix supported; also common specimens up to 25% showing sparse matrix material an grain supported; interstices moderately well filled to occasional interstitial void readily evident; trace carbonaceous laminae; bedding predominantly massive; dark gray, soft , re-worked sedimentary lithic clasts ( > 5%). Commonly associated with thinly interbedded tuffaceous siltstones. Tuffaceous Siltstone (10030' - 10180') = light medium gray medium gray with occasional pale brownish hued grays; mostly soft to crumbly with occasional slightly to moderately crunchy; fracture earthy to slightly hackly to occasional sub planar; cuttings habit predominantly wedge like with common sub tabular and trace massive rounded; PDC imbrication is fairly common; luster dull to earthy; texture silty; structure massive. Tuffaceous Sandstone (10180' - 10270') = very light gray to whitish gray; upper fine to medium grains with common coarse to very coarse grain inclusions; poorly to moderately poorly sorted; sub angular to angular; sphericity moderate to moderately high on medium grains and lower on the coarse and very coarse broken grains; moderate to sparse matrix material; grain supported; interstices moderately filled; bedding massive; abundant loose grains; occasional dark gray lithic clasts. Tuffaceous Sandstone (10270' - 10330') = very light gray to whitish gray with lightly peppered appearance; medium with occasional very coarse quartz grains; poorly to moderately poorly sorted; angular to sub angular; sphericity moderately low; moderately soft to moderately crumbly; down ward SCU 322C-04 9 fining sequence; plentiful matrix material decreasing with depth; matrix supported at top of sand and grain supported by 10330'; interstices well filled; bedding massive; only very small traces of carbonaceous shale and tuffaceous siltstone. Coal/ Carbonaceous Shale (10330' - 10360') = very dark grayish black to black with common brownish black; firmly crunchy to easily crunched; fracture sub planar to slightly conchoidal; cuttings habit wedge like to sub tabular and common platy; luster dull to vitreous in the better developed specimens; texture smooth; structure thinly bedded; interbedded w/ thin tuffaceous siltstones and tuffaceous sandstones; Tuffaceous Siltstone (10360' - 10450') = light medium gray to medium gray; tenacity soft to crumbly; fracture earthy; cuttings habit massive to slightly wedge like; luster dull to earthy; texture silty; structure massive. Tuffaceous Sandstone (10450' - 10480') = very pale gray to whitish gray; very fine to fine with occasional medium grains; well sorted; sub angular to sub round; sphericity high; soft to very easily friable; abundant matrix support; interstices well filled; bedding massive. Tuffaceous Sandstone/ Sand (10480' - 10580') = very light gray to grayish white mottled appearance; very fragile and pulverulent; crunchy; non calcareous ashy matrix supports loose sand grains; clear to translucent quartz and volcanic glass, trace light green to greenish gray, light to medium gray and black; very fine upper to medium lower, dominantly fine; angular to subangular; fair to good sorting; loose grains supported by ashy matrix; very calcareous; sand is also unconsolidated; trace tuff; very light gray to white; fragile to pulverulent; sparkly luster from glass shards; very calcareous. Tuffaceous Sandstone/ Conglomeratic Sand/ Sandstone (10580' - 10660') = very light gray to dirty white with abundant very light secondary hues, individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray, light green to light greenish gray and pale rose; very fine upper to very coarse upper, dominantly fine upper to coarse lower; angular to subangular; poorly sorted; very loosely consolidated with ashy matrix; non calcareous. Tuffaceous Sandstone/ Sand (10660' - 10730') = very light gray to dirty white, irregular shaped cuttings; very fragile, pulverulent; crunchy; non calcareous ashy matrix supports loose sand grains; clear to translucent quartz and volcanic glass, trace light green to greenish gray, light to medium gray and black; very fine upper to coarse lower, dominantly fine; angular to subangular; fair to good sorting; loose grains supported by ashy matrix; non calcareous; trace thin coal beds throughout interval; black, very firm to hard; flaky; planar fracture dominant; no outgassing bubbles. Tuffaceous Claystone/ Tuffaceous Siltstone (10730' - 10820') = light gray to very light gray to light olive gray with light brownish gray secondary hues; soft to slightly firm; irregular to trace PDC bit action shaped cuttings; silty to clayey texture; dull to earthy luster; slight to moderately soluble and expansive; poor adhesiveness; fair cohesiveness non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds. Tuffaceous Sandstone/ Sand (10820' - 10850') = very light gray to dirty white, irregular shaped cuttings; very fragile, pulverulent; crunchy; non calcareous ashy matrix supports loose sand grains. Tuffaceous Sandstone (10850'-10990') = lightly peppered salt and pepper appearance to whitish gray to very light gray with trace very pale yellowish brown hues; very fine to upper fine grained; well sorted; subangular to angular; sphericity moderate to low with common flat prismoidal grains; soft to easily friable; mostly moderate to sparse tuffaceous matrix but occasionally abundant tuffaceous/ argillaceous matrix; matrix non to very slightly calcareous; predominantly grain supported; fabric long contact; bedding massive; dark gray to black, soft, fine grained re-worked sedimentary lithic clasts; trace volcanic glass grains. SCU 322C-04 10 Tuffaceous Siltstone (10990' - 11080') = medium gray to light medium gray; tenacity crumbly to slightly crunchy; fracture sub planar to slightly hackly; cuttings habit wedge like to slightly platy or sub tabular; luster dull to earthy; texture silty; structure massive; grades to fine to very fine tuffaceous sandstone; associated with and thinly interbedded with tuffaceous sandstone, thin carbonaceous shales, and very thin coals. Tuffaceous Sandstone (11080' - 11110') = whitish gray to very pale gray with trace pale yellowish brown hues; very fine grained to fine grained; very well sorted; sub round to sub angular; sphericity high to moderately high; easily friable to soft; sparse to moderate amount of tuffaceous matrix material; both grain supported and matrix supported specimens are represented; interstices mostly well filled; bedding massive; associated with and thinly interbedded with thin tuffaceous siltstones and thin carbonaceous shales. Conglomeratic Sand (11140' - 11200') = whitish gray to very pale gray; fine grained to medium grained with occasional upper very coarse; poorly sorted; sub rounded to very angular; soft to unconsolidated; varying amounts of matrix material but most is very clean; associated with and thinly interbedded with tuffaceous siltstone. Tuffaceous Sandstone (11160' - 11200') = very pale gray to whitish gray; very fine to occasional very coarse; poorly sorted; sub angular to angular; abundant tuffaceous matrix material in this interval; very soft; cutting very small, interstices well filled, bedding massive. Tuffaceous Sandstone (11200' - 11290') = very pale gray to whitish gray; very fine to upper fine with trace coarse grains; moderately to poorly sorted; sub angular to angular; moderately soft to very soft with abundant loose grains; decreasing matrix and grading to a clean conglomeratic sand; thin carbonaceous shales, trace mineral fluorescence in interval; no cut. Carbonaceous Shale (11260' - 11290') = very dark grayish brown to dark gray with occasional black; crunchy easily crunched; fracture planar; cuttings habit wedgelike to platy. Tuffaceous Sandstone/ Conglomeratic Sand/ Sand (11290' - 11360') = very light gray to grayish white, individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray, black, dusky red and light green to light greenish gray; very fine upper to very coarse upper, dominantly fine upper to coarse lower; angular to subangular; poorly sorted; very loosely supported by ashy matrix; very fragile and pulverulent; non calcareous; no odor, staining or free oil, no cut fluorescence. Sand/ Conglomerate/ Tuffaceous Sandstone (11360' - 11440') = light to very light gray overall with a weak salt and pepper appearance, individual grains dominantly clear to translucent quartz and volcanic glass with abundant multicolored liths, light to dark gray, black, dusky red, orange and light green; very fine upper to very coarse upper; dominantly medium lower to coarse lower; angular to subangular; poorly sorted; dominantly unconsolidated with scattered ashy matrix supported grains; very fragile to pulverulent; non calcareous; no show. Sand/ Conglomerate (11440' - 11525') = very light gray with individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray, white, black, trace orange, dusky red and light green; very fine upper to very coarse upper with pebble fragments 4mm, dominantly medium lower to coarse lower; angular to subrounded, dominantly subangular; poorly sorted; dominantly disaggregated with trace salt and pepper sandstone; very fine to medium; hard; non calcareous cement; trace mineral fluorescence, no cut or cut fluorescence, no odor, stain or free oil. SCU 322C-04 11 3.3 Sampling Program Set Type and Purpose Interval Frequency Distribution A Washed and Dried Reference 7394’ – 8410’ 8410’ – 9280’ 9280’ – 10510’ 10510’ – 11525’ 30’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 B Washed and Dried Reference 7394’ – 8410’ 8410’ – 9280’ 9280’ – 10510’ 10510’ – 11525’ 30’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 SCU 322C-04 12 4 DRILLING DATA 4.1 Surveys Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 103.14 1.13 185.90 103.13 ‐0.84 ‐0.09 ‐0.79 1.33 203.14 1.50 181.29 203.11 ‐3.12 ‐0.22 ‐2.91 0.38 303.14 0.92 184.00 303.09 ‐5.23 ‐0.30 ‐4.85 0.58 403.14 0.61 180.16 403.08 ‐6.57 ‐0.36 ‐6.07 0.31 503.14 0.43 175.72 503.07 ‐7.47 ‐0.33 ‐6.88 0.18 603.14 0.25 174.20 603.07 ‐8.06 ‐0.28 ‐7.39 0.18 703.14 0.26 171.56 703.07 ‐8.51 ‐0.23 ‐7.76 0.02 803.14 0.22 172.14 803.07 ‐8.92 ‐0.17 ‐8.11 0.04 903.14 0.23 165.78 903.07 ‐9.31 ‐0.09 ‐8.42 0.03 1003.14 0.26 123.58 1003.07 ‐9.63 0.15 ‐8.61 0.18 1103.14 0.28 120.44 1103.07 ‐9.87 0.54 ‐8.66 0.02 1203.14 0.36 93.10 1203.06 ‐10.02 1.07 ‐8.56 0.17 1303.14 0.42 77.52 1303.06 ‐9.95 1.74 ‐8.21 0.12 1403.14 0.42 75.70 1403.06 ‐9.78 2.45 ‐7.75 0.01 1503.14 0.46 71.18 1503.06 ‐9.56 3.19 ‐7.23 0.05 1603.14 0.46 69.49 1603.05 ‐9.29 3.94 ‐6.66 0.01 1703.14 0.47 68.84 1703.05 ‐9.00 4.70 ‐6.07 0.01 1803.14 0.44 58.01 1803.05 ‐8.65 5.41 ‐5.45 0.09 1903.14 0.45 59.10 1903.04 ‐8.25 6.07 ‐4.79 0.01 2003.14 0.45 56.41 2003.04 ‐7.83 6.74 ‐4.13 0.02 2103.14 0.37 62.48 2103.04 ‐7.46 7.35 ‐3.53 0.09 2203.14 0.39 62.11 2203.04 ‐7.15 7.94 ‐3.00 0.02 2303.14 0.37 66.23 2303.03 ‐6.87 8.54 ‐2.48 0.03 2403.14 0.38 63.59 2403.03 ‐6.59 9.13 ‐1.97 0.02 2503.14 0.44 59.14 2503.03 ‐6.24 9.75 ‐1.39 0.07 2603.14 0.43 55.25 2603.03 ‐5.83 10.39 ‐0.74 0.03 2703.14 0.44 49.09 2703.02 ‐5.37 10.99 ‐0.06 0.05 2803.14 0.47 45.51 2803.02 ‐4.83 11.57 0.67 0.04 2903.14 0.53 41.70 2903.02 ‐4.20 12.17 1.51 0.07 3003.14 0.53 42.24 3003.01 ‐3.51 12.79 2.39 0.00 3103.14 0.57 33.59 3103.01 ‐2.75 13.38 3.33 0.09 3203.14 0.61 35.39 3203.00 ‐1.90 13.96 4.35 0.04 3303.14 0.59 34.43 3303.00 ‐1.04 14.56 5.38 0.02 SCU 322C-04 13 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 3403.14 0.56 16.14 3402.99 ‐0.15 14.99 6.37 0.19 3503.14 0.52 4.75 3502.99 0.77 15.16 7.28 0.11 3603.14 0.53 355.46 3602.98 1.69 15.16 8.10 0.09 3703.14 0.56 358.31 3702.98 2.63 15.11 8.93 0.04 3803.14 0.85 8.99 3802.97 3.86 15.21 10.08 0.32 3903.14 1.06 15.94 3902.96 5.48 15.58 11.70 0.24 4003.14 1.17 14.36 4002.94 7.36 16.09 13.61 0.11 4103.14 1.21 13.57 4102.92 9.37 16.59 15.65 0.04 4203.14 1.21 11.80 4202.89 11.43 17.05 17.70 0.04 4303.14 1.23 12.68 4302.87 13.51 17.51 19.77 0.03 4403.14 1.26 14.26 4402.85 15.62 18.01 21.90 0.05 4503.14 1.15 23.69 4502.83 17.61 18.69 23.98 0.23 4603.14 1.09 27.47 4602.81 19.37 19.53 25.93 0.10 4703.14 1.09 28.93 4702.79 21.05 20.43 27.83 0.03 4803.14 0.99 43.36 4802.77 22.51 21.48 29.60 0.28 4903.14 1.02 44.64 4902.76 23.77 22.70 31.27 0.04 5003.14 1.06 48.49 5002.74 25.02 24.02 32.96 0.08 5103.14 1.12 51.43 5102.72 26.24 25.47 34.70 0.08 5203.14 1.29 52.42 5202.70 27.54 27.13 36.58 0.17 5303.14 1.50 55.18 5302.67 28.97 29.10 38.73 0.22 5403.14 1.94 62.38 5402.63 30.50 31.67 41.23 0.49 5503.14 2.03 62.82 5502.57 32.09 34.75 44.00 0.09 5603.14 2.21 62.94 5602.50 33.78 38.04 46.95 0.18 5703.14 2.26 62.50 5702.42 35.57 41.51 50.06 0.05 5803.14 2.22 62.01 5802.34 37.39 44.96 53.20 0.04 5903.14 2.23 61.64 5902.27 39.22 48.39 56.34 0.02 6003.14 1.89 58.24 6002.20 41.01 51.50 59.30 0.36 6103.14 1.78 59.10 6102.15 42.68 54.24 61.99 0.11 6203.14 1.83 58.91 6202.10 44.30 56.94 64.63 0.05 6303.14 1.84 60.81 6302.05 45.91 59.70 67.28 0.06 6403.14 1.91 60.36 6402.00 47.52 62.55 69.96 0.07 6503.14 2.50 70.86 6501.92 49.05 66.06 72.87 0.71 6603.14 2.65 73.07 6601.82 50.44 70.34 75.98 0.18 6703.14 2.64 75.79 6701.72 51.68 74.78 79.02 0.13 6803.14 2.44 82.58 6801.62 52.52 79.12 81.66 0.36 6903.14 2.44 83.72 6901.53 53.03 83.35 83.96 0.05 7003.14 2.05 91.32 7001.45 53.22 87.25 85.82 0.49 7103.14 1.81 96.46 7101.39 53.00 90.61 87.08 0.30 7203.14 1.64 92.82 7201.35 52.75 93.61 88.16 0.20 SCU 322C-04 14 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 7303.14 1.66 93.62 7301.31 52.59 96.48 89.26 0.03 7394.00 1.55 93.84 7392.13 52.43 99.02 90.22 0.12 7462.05 5.53 63.51 7460.04 53.83 102.88 93.15 6.27 7523.64 7.56 57.96 7521.23 57.30 108.97 98.93 3.45 7584.95 10.27 54.68 7581.79 62.60 116.85 107.12 4.50 7647.71 11.12 52.39 7643.46 69.53 126.21 117.43 1.51 7710.53 11.79 45.22 7705.03 77.75 135.56 128.89 2.50 7772.39 12.67 35.46 7765.50 87.72 143.98 141.53 3.62 7833.10 14.02 28.39 7824.57 99.61 151.34 155.44 3.49 7892.75 15.23 25.99 7882.29 113.02 158.21 170.50 2.27 7956.51 15.77 23.47 7943.73 128.50 165.33 187.53 1.35 8018.49 17.22 22.53 8003.16 144.70 172.20 205.11 2.36 8080.36 18.59 23.97 8062.03 162.17 179.72 224.11 2.33 8142.71 20.72 22.74 8120.74 181.42 188.02 245.06 3.49 8205.10 22.81 21.43 8178.68 202.86 196.71 268.15 3.43 8267.20 25.14 21.45 8235.42 226.35 205.93 293.31 3.76 8329.52 27.72 23.04 8291.22 252.02 216.44 320.99 4.29 8390.98 29.96 22.49 8345.05 279.36 227.91 350.60 3.67 8452.80 32.06 23.46 8398.03 308.67 240.35 382.41 3.49 8515.06 34.51 24.46 8450.07 339.89 254.23 416.56 4.04 8576.80 35.81 26.76 8500.55 371.94 269.61 452.11 3.01 8639.23 37.72 26.60 8550.56 405.33 286.39 489.47 3.06 8701.47 40.11 26.99 8598.98 440.23 304.01 528.56 3.85 8762.84 41.50 26.24 8645.44 476.08 321.98 568.66 2.40 8824.53 43.93 25.34 8690.76 513.76 340.18 610.50 4.07 8885.76 45.61 25.70 8734.23 552.67 358.76 653.62 2.77 8949.04 47.15 25.15 8777.88 594.04 378.42 699.43 2.52 9011.29 47.41 24.94 8820.11 635.48 397.78 745.16 0.48 9073.94 46.70 25.04 8862.79 677.04 417.16 791.01 1.13 9135.62 46.47 24.50 8905.19 717.72 435.93 835.81 0.74 9195.93 46.11 24.03 8946.87 757.47 453.84 879.39 0.82 9257.91 46.97 25.16 8989.50 798.37 472.57 924.37 1.92 9321.57 46.76 24.83 9033.03 840.47 492.20 970.81 0.50 9383.03 46.94 25.31 9075.06 881.08 511.20 1015.65 0.65 9445.19 46.13 24.81 9117.82 921.95 530.31 1060.77 1.43 9507.46 46.89 25.83 9160.68 962.79 549.63 1105.94 1.70 9569.51 46.62 25.67 9203.19 1003.50 569.27 1151.14 0.48 9631.74 46.20 24.89 9246.10 1044.25 588.52 1196.21 1.14 9693.10 47.05 26.17 9288.24 1084.49 607.74 1240.80 2.07 SCU 322C-04 15 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (Incr) (ft) Dogleg Rate (o/100ft) 9755.51 47.08 26.12 9330.75 1125.51 627.88 1286.50 0.07 9817.30 47.71 26.10 9372.58 1166.35 647.89 1331.97 1.03 9878.66 48.05 25.79 9413.73 1207.28 667.81 1377.49 0.67 9941.74 47.86 24.93 9455.97 1249.60 687.87 1424.33 1.06 10003.12 48.35 24.32 9496.96 1291.14 706.91 1470.02 1.09 10066.14 46.96 25.80 9539.40 1333.34 726.63 1516.59 2.81 10127.91 47.36 25.89 9581.41 1374.10 746.38 1561.88 0.65 10189.58 46.22 25.75 9623.63 1414.56 765.95 1606.83 1.85 10251.42 46.59 25.49 9666.27 1454.94 785.32 1651.62 0.67 10313.32 46.83 25.31 9708.71 1495.64 804.64 1696.67 0.44 10376.46 45.51 26.15 9752.45 1536.68 824.42 1742.22 2.31 10438.34 44.83 25.71 9796.08 1576.14 843.61 1786.10 1.21 10500.93 44.88 25.38 9840.45 1615.97 862.64 1830.24 0.38 10563.52 45.81 25.57 9884.44 1656.16 881.79 1874.76 1.50 10625.05 46.65 24.69 9927.00 1696.38 900.65 1919.19 1.72 10687.40 48.23 25.20 9969.18 1738.02 920.02 1965.11 2.60 10749.16 48.31 24.57 10010.29 1779.83 939.41 2011.19 0.76 10808.24 48.07 23.94 10049.68 1819.98 957.51 2055.21 0.89 10871.94 48.21 24.59 10092.18 1863.23 977.00 2102.63 0.78 10935.74 48.18 25.10 10134.71 1906.39 996.98 2150.19 0.60 10998.21 48.07 25.94 10176.41 1948.36 1017.02 2196.70 1.02 11060.23 47.49 24.35 10218.09 1989.94 1036.54 2242.63 2.12 11123.66 47.25 22.98 10261.04 2032.68 1055.27 2289.26 1.63 11184.85 47.80 21.88 10302.37 2074.40 1072.49 2334.32 1.59 11247.17 48.89 21.67 10343.78 2117.64 1089.76 2380.77 1.77 11309.94 48.49 19.60 10385.22 2161.76 1106.38 2427.73 2.55 11372.74 47.70 17.08 10427.17 2206.11 1121.08 2474.07 3.25 11433.44 47.25 16.33 10468.20 2248.96 1133.94 2518.26 1.17 11486.66 46.52 15.10 10504.57 2286.36 1144.47 2556.51 2.17 SCU 322C-04 16 4.2 Bit Record BIT NO. SIZE TYPE S/N JETS/ TFA IN OUT Feet Drilled HRS AVE ROP (Ft/HR)CONDITION Mills 6” 7394’ 7427’ 33 7.35 4.49 1 6” Varel V613DUX 4008358 6x10 7427’ 7870’ 443’ 27.95 15.85 1-1-PN-N-X-I-E-PR 2 6” HDBS MM55 12401235 5x11 7870’ 11525’ 3655’ 63.43 57.6 2-4-BT-S-X-1-CT-TD SCU 322C-04 17 4.3 Mud Record Contractor: M.I. Swaco Date Depth MW (ppg) VIS (s/qt) PV YP Gels FL (cc) FC Sols (%) O/W Ratio Sd (%) MBT pH Cl (mg/l) Ca (mg/l) MD (ft) TVD (ft) SPUD MUD 1/15/2016 7413 7413 9.40 54 10 16 7/10/11 4.5 1/2 3.8 0/93.5 - - 9.6 33000 360 1/16/2016 7413 7413 9.70 51 10 19 9/12/14 3.8 1/2 5.2 0/92.1 - - 9.3 33000 360 1/17/2016 7413 7413 9.78 50 9 18 8/10/13 3.8 1/2 5.5 0/91.9 - - 9.4 33000 360 1/18/2016 7427 7427 9.80 45 9 20 8/10/13 4.5 1/2 5.6 0/91.8 - - 9.9 32500 100 1/19/2016 7427 7427 9.80 46 10 20 8/10/13 4.6 1/2 6.0 0/91.5- - 10.5 31000 80 1/20/2016 7535 7534 9.80 45 9 20 8/10/13 4.5 1/2 6.1 0/91.6 - .5 10.2 30000 40 1/21/2016 7870 7861 10.30 45 12 21 6/8/11 4.0 1/2 8.0 0/89.7 - .5 10.2 30000 40 1/22/2016 7870 7861 10.40 47 12 20 7/8/10 3.8 1/2 8.6 0/89.0 - .5 10.1 31000 40 1/23/2016 8639 8559 10.60 45 14 20 6/7/10 3.9 1/2 9.3 0/88.5 .5 10.4 29000 40 1/24/2016 8965 8788 10.60 45 13 19 5/7/10 4.0 1/2 9.3 0/88.3 0.10 1.5 9.8 31000 40 1/25/2016 9918 9440 10.60 47 15 17 5/7/10 4.0 1/2 9.5 0/88.0 0.10 3.0 9.9 33000 40 1/26/2016 10945 10141 10.60 47 16 18 5/7/10 3.6 1/2 10.5 0/87.1 0.10 4.5 10.4 31500 40 1/27/2016 11525 10532 10.60 49 17 19 5/7/10 3.4 1/2 10.6 0/87.0 0.10 4.5 10.2 32000 40 1/28/2016 11525 10532 10.60 52 14 19 4/6/10 3.6 1/2 10.6 0/87.0 0.10 4.5 9.8 31500 40 1/29/2016 11525 10532 10.50 48 12 18 4/6/9 4.0 1/2 10.5 0/87.5 0.10 4.5 9.8 26000 40 1/30/2016 11525 10532 10.55 45 12 16 4/6/9 4.8 1/2 10.9 0/87.1 0.10 4.5 9.8 26000 80 Abbreviations: MW = Mud Weight VIS = Funnel Viscosity PV = Plastic Viscosity YP = Yield Point Gels = Gel Strength FL = Water or Filtrate Loss FC = Filter Cake O/W = Oil to Water ratio Sols = Solids Sd = Sand content MBT = Methylene Blue Alk, Pm = Alkalinity, Mud pH = Acidity Cl = Chlorides Ca = Hardness Calcium nr = Not Recorded SCU 322C-04 18 4.4. Drilling Progress SCU 322C-04 - Days vs Depth70007500800085009000950010000105001100011500120001/15/20161/16/20161/17/20161/18/20161/19/20161/20/20161/21/20161/22/20161/23/20161/24/20161/25/20161/26/20161/27/20161/28/20161/29/20161/30/20161/31/20162/1/2016Depth (ft) 'MD SCU 322C-04 19 5 SHOW REPORTS SCU 322C-04 20 6 DAILY REPORTS Hilcorp Alaska, LLC Kenai Borough, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE 1/15/2016 DEPTH 7200 PRESENT OPERATION picking up pipe TIME 23:59 pm YESTERDAY 7200 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@9662' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7413/7413 MW 9.4 VIS 54 PV 10 YP 16 FL 4.5 Gels 7/10/11 CL- 33000 FC 1/2 SOL 3.8 SD -- OIL 0.0/93.5 MBT -- pH 9.6 Ca+ 360 Alk 0.10 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Rig up e-line, POOH and P/U CIBP, run in hole and set CIBP @10157'; POOH and test casing; RIH with E-line and cement with 57 gals cement on top of CIBP; Pooh w/ e-line; pooh; RIH and tag cement; POOH and pick up second CIBP; RIH and set same @ 7413'. POOH with e-line. test casing at 3500 psi- good. Rig down e-line and and begin BHA and HWDP. Picking up pipe at report time. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3125.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE 1/16/2016 DEPTH 7413 PRESENT OPERATION Picking up pipe TIME 23:59 pm YESTERDAY 7413 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@9662' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7413/7413 MW 9.7 VIS 51 PV 10 YP 19 FL 3.8 Gels 9/12/14 CL- 33000 FC 1/2 SOL 5.2 SD -- OIL 0.0/92.1 MBT -- pH 9.3 Ca+ 360 Alk 0.10 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continued to pick up drill pipe. POOH racking back drill pipe. Return to picking up drill pipe. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE 1/17/2016 DEPTH 7413 PRESENT OPERATION Setting whipstock TIME 23:59 pm YESTERDAY 7413 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7413/7413 MW 9.78 VIS 50 PV 9 YP 18 FL 3.8 Gels 8/10/13 CL- 33000 FC 1/2 SOL 5.5 SD -- OIL 0.0/91.9 MBT -- pH 9.4 Ca+ 360 Alk MWD SUMMARY INTERVAL 7413 TO 7413 TOOLS Gyro to set whipstock GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continued to pick up drill pipe to trip in to 7413'; rig service - grease draw works, crown, and blocks; pick up and make up whipstock; Trip in hole with whipstock filling every thirty stands; tag cast iron bridge plug; rig up wire line; run in hole with gyro; orient whip stock; pull out of hole with gyro. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Marvin and Shane DATE Jan 18, 2016 DEPTH 7426 PRESENT OPERATION Testing BOPs TIME 23:59 pm YESTERDAY 7396 24 HOUR FOOTAGE 30 CASING INFORMATION 7" @ 7413 SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 18.4 @ 7417 1.5 @ 7403 5.9 8.13 FT/HR SURFACE TORQUE 8278 @ 7398 5742 @ 7413 6544.0 6079.99 FT-LBS WEIGHT ON BIT 23 @ 7409 1 @ 7396 6.6 8.30 KLBS ROTARY RPM 77 @ 7403 3 @ 7408 76.8 77.04 RPM PUMP PRESSURE 1293 @ 7403 972 @ 7411 1227.2 1204.35 PSI DRILLING MUD REPORT DEPTH 7427/7427 MW 9.80 VIS 45 PV 9 YP 20 FL 4.5 Gels 8/10/13 CL- 32500 FC 1/2 SOL 5.6 SD -- OIL 0.0/91.8 MBT -- pH 9.9 Ca+ 100 Alk 0.20 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 19 @ 7416 7 @ 7396 13.7 TRIP GAS -- CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 2564 @ 7404 954 @ 7415 1472.2 CONNECTION GAS HIGH - ETHANE (C-2) 21 @ 7421 4 @ 7416 5.0 AVG - PROPANE (C-3) 0 @ 7426 0 @ 7426 0.0 CURRENT - BUTANE (C-4) 0 @ 7426 0 @ 7426 0.0 CURRENT BACKGROUND/AVG 0 / 14 PENTANE (C-5) 0 @ 7426 0 @ 7426 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue to mill window to 7427' circulate bottoms up and check for flow; rig up for and perform F.I.T. to 12.5ppg. and held 10 min.; 36 gals returned at bleed off; check flow- static; and begin POOH; ( 170 pound of metal returned during milling operations.) Pull out of hole; pull wear bushing; flush stack with Johnny Whacker; blow down mud lines; rinse stack. set test plug and test joint; make up TIW to test joint; purge air from stack, choke, mainfold, and test lines. Max Gas 19 units CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Marvin and Shane DATE Jan 19, 2016 DEPTH 7426 PRESENT OPERATION Running in hole with wireline TIME 23:59 pm YESTERDAY 7396 24 HOUR FOOTAGE 30 CASING INFORMATION 7" @ 7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 6" Varel V613 DUX PDC 4008358 6x10 7426 (7426) 0 0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7427/7427 MW 9.80 VIS 48 PV 10 YP 20 FL 8/10/13 Gels 8/10/13 CL- 31000 FC 1/2 SOL 6.0 SD -- OIL 0.0/91.5 MBT -- pH 10.5 Ca+ 80 Alk 0.30 MWD SUMMARY INTERVAL 7426 TO 7426 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 526 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 14 / - PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY Sand 30%; Tuffaceous Claystone 40%; TuffaceousSiltstone 30%. DAILY ACTIVITY SUMMARY Continue to test BOPs; check PVTs , flow meters, and alarms, pull test plug, install wear bush and blow down; prep rig floor for BHA; p/u and m/u BHA; download tool, load sources, p/u HWDP; RIH to 2000'; tour change; continue to trip in hole; to 7372' filling pipe; testing MWD, and blowing down every 2500'; pump out trip tank; circulate above window; SM with company man, directional, wireline and gyro; rig up wireline, make up side entry sub, instaqll gyro in string; and run in with gyro. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC Kenai Borough, Alaska DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Rance Pederson / Marvin Rogers DATE Jan 20, 2016 DEPTH 7553 PRESENT OPERATION Drilling ahead TIME 11:59:00 YESTERDAY 7427 24 HOUR FOOTAGE 126 CASING INFORMATION 7"@7413" SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 122.4 @ 7528 1.0 @ 7435 17.1 10.69 FT/HR SURFACE TORQUE 5918 @ 7540 2613 @ 7482 3251.7 0.00 FT-LBS WEIGHT ON BIT 25 @ 7550 0 @ 7448 14.2 25.06 KLBS ROTARY RPM 61 @ 7541 5 @ 7482 24.3 0.00 RPM PUMP PRESSURE 2325 @ 7543 1122 @ 7428 2035.4 2245.87 PSI DRILLING MUD REPORT DEPTH 7535/7534 MW 9.8 VIS 45 PV 9 YP 20 FL 4.5 Gels 8/10/13 CL- 30000 FC 1/2 SOL 6.1 SD -- OIL 0.0/91.6 MBT -- pH 10.2 Ca+ 40 Alk 0.35 MWD SUMMARY INTERVAL 7427 TO 7553 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 178 @ 7528 8 @ 7434 45.7 TRIP GAS 526 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 32847 @ 7528 808 @ 7434 7869.5 CONNECTION GAS HIGH 0 ETHANE (C-2) 151 @ 7528 0 @ 7430 38.7 AVG 0 PROPANE (C-3) 0 @ 7553 0 @ 7553 0.0 CURRENT 0 BUTANE (C-4) 0 @ 7553 0 @ 7553 0.0 CURRENT BACKGROUND/AVG 90 / 46 PENTANE (C-5) 0 @ 7553 0 @ 7553 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek PRESENT LITHOLOGY Sand 30%; Sandstone 20%; Tuffaceous Siltstone 30% ; Tuffaceous Claystone 10%; Coal 10%; DAILY ACTIVITY SUMMARY Drilled ahead CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 21, 2016 DEPTH 7870 PRESENT OPERATION POOH FOR BIT TIME 23:59 pm YESTERDAY 7553 24 HOUR FOOTAGE 317 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7584.95 10.27 54.68 7581.79 7647.71 11.12 52.39 7643.46 7710.53 11.79 45.22 7705.03 7772.39 12.67 35.46 7765.5 7833.10 14.02 28.39 7824.57 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 6" varel V613 DUX PDC 4008358 6x10 7426 7870 444 28 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 100.5 @ 7707 1.5 @ 7604 33.5 12.00 FT/HR SURFACE TORQUE 6841 @ 7764 1031 @ 7820 4620.4 5705.00 FT-LBS WEIGHT ON BIT 26 @ 7556 1 @ 7825 14.2 24.00 KLBS ROTARY RPM 61 @ 7606 1 @ 7812 47.7 61.72 RPM PUMP PRESSURE 2508 @ 7865 1769 @ 7683 2122.3 2102.92 PSI DRILLING MUD REPORT DEPTH Weighting up System MW 10.40 VIS 44 PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL 7426 TO 7870 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1346 @ 7566 82 @ 7733 169.9 TRIP GAS 0 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 263521 @ 7566 16797 @ 7733 33295.3 CONNECTION GAS HIGH 680 ETHANE (C-2) 876 @ 7566 1 @ 7655 84.0 AVG 526 PROPANE (C-3) 64 @ 7566 0 @ 7616 3.5 CURRENT 372 BUTANE (C-4) 9 @ 7827 0 @ 7833 0.1 CURRENT BACKGROUND/AVG 31/ 170 PENTANE (C-5) 0 @ 7870 0 @ 7870 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TYONEK PRESENT LITHOLOGY Sand 50% / Sandstone10% / Tuffaceous Claystone 20% / Tuffaceous Siltstone 20% DAILY ACTIVITY SUMMARY Drill ahead to 7870’. Circulate bottoms up, check flow, flowing at 3.9 bbls/hr.; circulate bottoms up with 990 units gas; continue to circulate and build mud from 9.8+ to 10.1 ppg.; check flow , flowing at 2.1 BPH; circulate another bottoms up with 1100 units gas circulated out; continue circulating and weighting up from 10.1 ppg to 10.4 ppg. Pull out of hole from 7870’ to 7390’. High gas of the day was 1346 units just after returning to drilling following the well control measures at 7565'. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 22, 2016 DEPTH 7870 PRESENT OPERATION TIH w/New Bit TIME 23:59 pm YESTERDAY 7870 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7584.95 10.27 54.68 7581.79 7647.71 11.12 52.39 7643.46 7710.53 11.79 45.22 7705.03 7772.39 12.67 35.46 7765.5 7833.10 14.02 28.39 7824.57 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6 HDBS MM55 12401235 5x11 7870 (7870) 0 0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 7870/7861 MW 10.40 VIS 47 PV 12 YP 20 FL 3.8 Gels 7/8/10 CL- 31000 FC 1/2 SOL 8.6 SD -- OIL 0.0/89.0 MBT 0.5 pH 10.1 Ca+ 40 Alk 0.30 MWD SUMMARY INTERVAL 7426 TO 7870 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS -- CUTTING GAS @ @ WIPER GAS 1346@5095' BU CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) @ @ CONNECTION GAS HIGH -- ETHANE (C-2) @ @ AVG -- PROPANE (C-3) @ @ CURRENT -- BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 16.4 / 0 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY TYONEK PRESENT LITHOLOGY Sand 50% / Sandstone10% / Tuffaceous Claystone 20% / Tuffaceous Siltstone 20% DAILY ACTIVITY SUMMARY Pull out of hole from 1450' to 112'; lay down BHA and Remove source and down load; pull wear bushing; well started flowing;@ 1.33 bph at 10am; install test plug and rig up test equipment; flood CM; test annular and install choke; test electrical choke;rig down test equipment; blow down manual choke; install wear bushing;; pick up and make up BHA and down load; well flowing at 1.3 bph; Tool not communicating; lay down slim Phaze and pick up new shallow pulse test @ 112'; load sources; well flowing at1BPH; Load sources in directional tools and start tripping in. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 23, 2016 DEPTH 8640 PRESENT OPERATION Drilling ahead TIME 23:59:45 YESTERDAY 7870 24 HOUR FOOTAGE 770 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8080.36 18.59 23.97 8062.03 8142.71 20.72 22.74 8120.74 8205.10 22.81 21.43 8178.68 8267.20 25.14 21.45 8235.42 8329.52 27.72 23.04 8291.22 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" HDBS MM55 12401235 5x11 7870 (8640) 770 14 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 451.5 @ 7994 1.8 @ 8334 71.4 92.56 FT/HR SURFACE TORQUE 7137 @ 8579 307 @ 8074 3933.2 6966.11 FT-LBS WEIGHT ON BIT 24 @ 7870 0 @ 8159 4.9 2.96 KLBS ROTARY RPM 17575 @ 8306 0 @ 8636 60.2 58.90 RPM PUMP PRESSURE 2429 @ 8199 1826 @ 7940 2211.4 2367.82 PSI DRILLING MUD REPORT DEPTH 7870 / 7861 MW 10.60 VIS 45 PV 14 YP 20 FL 3.9 Gels 6/7/10 CL- 29000 FC 1/2 SOL 9.3 SD -- OIL 0.0/88.5 MBT 0.5 pH 10.4 Ca+ 40 Alk 0.60 MWD SUMMARY INTERVAL 7870 TO 8640 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 751 @ 7904 10 @ 8141 238.3 TRIP GAS 2604 CUTTING GAS @ @ WIPER GAS -- CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 143862 @ 7904 1984 @ 8141 44686.5 CONNECTION GAS HIGH 1087 ETHANE (C-2) 662 @ 8214 2 @ 8008 119.0 AVG 842 PROPANE (C-3) 4667 @ 8614 0 @ 7901 116.3 CURRENT 643 BUTANE (C-4) 15 @ 8212 0 @ 8228 0.2 CURRENT BACKGROUND/AVG 139 / 238 PENTANE (C-5) 0 @ 8640 0 @ 8640 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyoneck PRESENT LITHOLOGY Tuffaceous siltstone 60% Tuffaceous sandstone 40% DAILY ACTIVITY SUMMARY Drill from 7870' to 8640' ; CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 24, 2016 DEPTH 9048 PRESENT OPERATION Drilling ahead TIME 23:59 YESTERDAY 8640 24 HOUR FOOTAGE 408 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8576.80 35.81 26.76 8500.55 8639.23 37.72 26.60 8550.56 8701.47 40.11 26.99 8598.98 8762.84 41.50 26.24 8645.44 8824.53 43.93 25.34 8690.76 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" HDBS MM55 12401235 5x11 7870 (9048) 1178 25.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 165.8 @ 8987 0.6 @ 8678 65.6 80.27 FT/HR SURFACE TORQUE 7884 @ 8987 413 @ 8866 5347.7 7156.70 FT-LBS WEIGHT ON BIT 20 @ 8962 0 @ 8831 7.0 7.49 KLBS ROTARY RPM 2109 @ 8866 0 @ 8698 52.0 69.09 RPM PUMP PRESSURE 2654 @ 8833 2101 @ 8875 2386.5 2277.20 PSI DRILLING MUD REPORT DEPTH 8965/8788 MW 10.60 VIS 45 PV 13 YP 19 FL 4.0 Gels 5/7/10 CL- 31000 FC 1/2 SOL 9.3 SD 0.10 OIL 0.0/88.3 MBT 1.5 pH 9.8 Ca+ 40 Alk 0.40 MWD SUMMARY INTERVAL 7870 TO 9048 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 813 @ 9048 89 @ 8990 166.0 TRIP GAS -- CUTTING GAS @ @ WIPER GAS 1377 CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 167565 @ 9048 11176 @ 8863 29842.4 CONNECTION GAS HIGH 1246 ETHANE (C-2) 718 @ 9048 3 @ 8758 91.4 AVG 777 PROPANE (C-3) 57 @ 9048 0 @ 8758 11.4 CURRENT 1067 BUTANE (C-4) 50 @ 8861 0 @ 9025 1.6 CURRENT BACKGROUND/AVG 107 / 166 PENTANE (C-5) 14 @ 8861 0 @ 8829 0.4 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek PRESENT LITHOLOGY Tuffaceous siltstone 80% and Tuffaceous sandstone 20% DAILY ACTIVITY SUMMARY Drill ahead to 8862' ; circulate bottoms up and clean hole with 883 units gas returned; POOH and check flow (4.4BPH); hole fill 5.2 bbls under theoretical; circulate bottoms up and pump 15 bbl high viscosity sweep 12.5ppg pill at 7499'; POOH to 7375' ; floe 4.0BPH; Slip and cut 90' drill line; greaswe equipment - draw works, top drive, crown blocks, check brakes driveline; trip in to 8760' and encountered tight spots @ 7495 and 7596' and 8513' ream down from 8760' to 8862'. Circulate hole dumping 47 bbls water with fluid cut at cuttings box 9.3ppg; drill ahead rotating and sliding as needed.continue to slide and rotate as per directional plan CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 25, 2016 DEPTH 10049 PRESENT OPERATION Drilling ahead TIME 23:59 YESTERDAY 9048 24 HOUR FOOTAGE 1001 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9569.51 46.62 25.67 9203.19 9631.74 46.20 24.89 9246.10 9693.10 47.05 26.17 9288.24 9755.51 47.08 26.12 9330.75 9817.30 47.71 26.10 9372.58 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" HDBS MM55 12401235 5x11 7870 (10049) 2179 39.4 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 150.8 @ 9473 1.7 @ 9545 80.7 61.84 FT/HR SURFACE TORQUE 9192 @ 9988 304 @ 9689 7557.3 2779.14 FT-LBS WEIGHT ON BIT 19 @ 9857 1 @ 10042 5.9 3.03 KLBS ROTARY RPM 81 @ 9504 0 @ 9248 72.0 2.20 RPM PUMP PRESSURE 2736 @ 9693 629 @ 9238 2459.4 2686. PSI DRILLING MUD REPORT DEPTH 9918/9440 MW 10.60 VIS 47 PV 15 YP 17 FL 4.0 Gels 5/7/10 CL- 33000 FC 1/2 SOL 9.5 SD 0.10 OIL 0.0/88.0 MBT 3.0 pH 9.9 Ca+ 40 Alk MWD SUMMARY INTERVAL 7870 TO 10049 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 10469 @ 9857 50 @ 10045 161.4 TRIP GAS -- CUTTING GAS @ @ WIPER GAS 1410 CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 2050099 @ 9857 9929 @ 10045 29741.9 CONNECTION GAS HIGH 1195 ETHANE (C-2) 9305 @ 9857 2 @ 9239 118.0 AVG 726 PROPANE (C-3) 1364 @ 9857 0 @ 9239 16.6 CURRENT 460 BUTANE (C-4) 28 @ 9167 0 @ 9239 1.9 CURRENT BACKGROUND/AVG 129 / 161 PENTANE (C-5) 0 @ 10049 0 @ 10049 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek PRESENT LITHOLOGY @10030' = 100% tuffaceous sandstone with trace only coal and tuffaceous siltstone DAILY ACTIVITY SUMMARY Drill ahead to 9854'; pump 15 barrel high viscosity sweep; 20% cuttings; POOH out of hole to 8728' ; hole flowing 8.6 barrels per hour; perform rig service; return to bottom and circulate bottoms up. Increase in cuttings 300% and 1410 units of wiper gas returned; 39 barrels of water cut mud dumped lowest cut by water was 10ppg. Resumed drilling and drilled ahead to 10049'. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 26, 2016 DEPTH 10975 PRESENT OPERATION Drilling ahead TIME 23:59 YESTERDAY 10049 24 HOUR FOOTAGE 926 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10563.52 45.81 25.57 9884.44 10625.05 46.65 24.69 9927.00 10687.40 48.23 25.20 9969.18 10749.16 48.31 24.57 10010.29 10808.24 48.07 23.94 10049.68 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" HDBS MM55 12401235 5x11 7870 (10975) 1927 53.0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 411.4 @ 10865 2.0 @ 10763 82.2 24.32 FT/HR SURFACE TORQUE 10808 @ 10865 1434 @ 10180 7916.4 0.00 FT-LBS WEIGHT ON BIT 15 @ 10959 0 @ 10167 5.4 3.39 KLBS ROTARY RPM 80 @ 10136 0 @ 10551 67.0 0.00 RPM PUMP PRESSURE 2753 @ 10090 2245 @ 10352 2545.8 2311.94 PSI DRILLING MUD REPORT DEPTH 10945/10141 MW 10.60 VIS 47 PV 16 YP 18 FL 3.6 Gels 5/7/10 CL- 31500 FC 1/2 SOL 10.5 SD 0.10 OIL 0.0/87.1 MBT 4.5 pH 10.4 Ca+ 40 Alk 0.60 MWD SUMMARY INTERVAL 7870 TO 10975 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1418 @ 10850 63 @ 10481 122.3 TRIP GAS 1418 CUTTING GAS @ @ WIPER GAS 1418 CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 245834 @ 10850 9837 @ 10736 23529.9 CONNECTION GAS HIGH 1010 ETHANE (C-2) 818 @ 10911 1 @ 10851 109.7 AVG 722 PROPANE (C-3) 182 @ 10911 0 @ 10167 8.7 CURRENT 661 BUTANE (C-4) 0 @ 10975 0 @ 10975 0.0 CURRENT BACKGROUND/AVG 127 / 122 PENTANE (C-5) 0 @ 10975 0 @ 10975 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tyonek PRESENT LITHOLOGY @ 10960' = Tuffaceous Sandstone 90% and Tuffaceous Siltstone 10% DAILY ACTIVITY SUMMARY Drill ahead from 10049' to 10850'; circulate and condition mud; pull out of hole for wiper trip from 10850' to 9750' on elevators with no issues; lay down one joint and pull on singles; check on flow with well flowing 13 BPH; hole took 10 barrels under calculated hole fill; grease equipment- draw works, blocks, and crown, check brakes. trip back to bottom and resume drilling ahead. Max gas today 1418 units at bottoms up after wiper trip. CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna New Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 27, 2016 DEPTH 11525 PRESENT OPERATION POOH TIME 23:58 YESTERDAY 10975 24 HOUR FOOTAGE 550 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11184.85 47.80 21.88 10302.37 11247.17 48.89 21.67 10343.78 11309.94 48.49 19.60 10385.22 11372.74 47.70 17.08 10427.17 11433.44 47.25 16.33 10468.20 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" HDBS MM55 12401235 5x11 7870 11525 3655 63.43 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 652.3 @ 11036 1.6 @ 11429 73.2 27.39 FT/HR SURFACE TORQUE 12264 @ 11229 2951 @ 10993 9956.1 10249.67 FT-LBS WEIGHT ON BIT 15 @ 11221 0 @ 11248 7.3 6.59 KLBS ROTARY RPM 80 @ 11036 10 @ 10996 69.1 56.71 RPM PUMP PRESSURE 2972 @ 11510 2274 @ 10992 2708.7 2861.79 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL 7870 TO 11525 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 1345 @ 11098 93 @ 11504 206.2 TRIP GAS 1427 CUTTING GAS @ @ WIPER GAS 1427 CHROMATOGRAPHY (ppm) SURVEY -- METHANE (C-1) 195981 @ 11097 11751 @ 11357 30661.2 CONNECTION GAS HIGH 1208 ETHANE (C-2) 6185 @ 11098 87 @ 10988 837.8 AVG 777.9 PROPANE (C-3) 4695 @ 11098 13 @ 10978 671.4 CURRENT 931 BUTANE (C-4) 3117 @ 11466 0 @ 10976 411.7 CURRENT BACKGROUND/AVG 84 / 206 PENTANE (C-5) 1137 @ 11466 1 @ 11060 128.2 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Hemlock PRESENT LITHOLOGY Conglomeratic Sand 10%; Conglomeratic Sandstone 10%; Sand 40%; Sandstone10%; Tuffaceous Claystone 10% ;Tuffaceous siltstone 10%; Tuffaceous siltsone 10% DAILY ACTIVITY SUMMARY Drill ahead to 11525'; puimp 15 barrel high vis sweep to clean hole for wiper trip;pump out of hole from 11525' to 11412' due to 40k over pull; POOH to 7375 on elevators flow check = 11.2 barrels per hour; and 37.5 bbls under calculated for hole fill;; service draw works; wash last 80' to bottom; 5' of fill; CBU; dump light mud; max gas 1427 units gas CANRIG PERSONNEL ON BOARD 4 DAILY COST $3430.00 REPORT BY Donna.New Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 28, 2016 DEPTH 11525 PRESENT OPERATION Running 4.5" Liner TIME 24:00 YESTERDAY 11525 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11184.85 47.80 21.88 10302.37 11247.17 48.89 21.67 10343.78 11309.94 48.49 19.60 10385.22 11372.74 47.70 17.08 10427.17 11433.44 47.25 16.33 10468.20 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" HDBS MM55 12401235 5x11 7870 11525 3655 63.43 2-4-BT-S-X-1-CT-TD TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW 10.60 VIS 52 PV 14 YP 19 FL 3.6 Gels 4/6/10 CL- 31500 FC 1/2 SOL 10.6 SD 0.10 OIL 0 MBT 4.5 pH 9.8 Ca+ 40 Alk 0.50 MWD SUMMARY INTERVAL 7870 TO 11525 TOOLS MWD and Directional GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 927 @ 7370', 1218 @ 4890' CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 59/100 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Hemlock PRESENT LITHOLOGY Conglomeratic Sand 10%; Conglomeratic Sandstone 10%; Sand 40%; Sandstone10%; Tuffaceous Claystone 10% ;Tuffaceous siltstone 10%; Tuffaceous siltsone 10% DAILY ACTIVITY SUMMARY Pump and circulate sweep out of hole (50% increase in cuttings. Check flow before POOH (10 bbls/hr); POOH form 11525’ to 7370’; backreamed first 4 stands; pumped out fifth stands; POOH on elevators to window (32.8 barrels under calculated hole fill for trip to 7370’; flow check at window = 9.3 bbls/hr; spot 20 bbl weighted pill at window; POOH from 7370’ to 5488’; blow down topdrive, flow check = 7.2 bbls/hr. POOH, laying down drill pipe to 4890’; circulate bottoms up, spot 26 barrel heavy weight pill at 4890’ (Max Gas = 1218u). POOH, laying down drill pipe to 970’. Rack back heavyweight drill pipe, flow check at 10 bbls/hr. Lay down and handle BHA. 100 barrel net gain over last 12 hours. Rig up floor equipment and Weatherford to run liner. Run 4.5” liner. CANRIG PERSONNEL ON BOARD 2 DAILY COST $3430.00 REPORT BY Paul Webster Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 29, 2016 DEPTH 11525 PRESENT OPERATION Running 4.5" Liner TIME 24:00 YESTERDAY 11525 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11184.85 47.80 21.88 10302.37 11247.17 48.89 21.67 10343.78 11309.94 48.49 19.60 10385.22 11372.74 47.70 17.08 10427.17 11433.44 47.25 16.33 10468.20 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" HDBS MM55 12401235 5x11 7870 11525 3655 63.43 2-4-BT-S-X-1-CT-TD TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 11525' MW 10.50 VIS 48 PV 12 YP 18 FL 4.0 Gels 4/6/9 CL- 26000 FC 1/2 SOL 10.5 SD 0.10 OIL 0 MBT 4.5 pH 9.8 Ca+ 40 Alk 0.45 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS See Remarks CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Hemlock PRESENT LITHOLOGY Conglomeratic Sand 10%; Conglomeratic Sandstone 10%; Sand 40%; Sandstone10%; Tuffaceous Claystone 10% ;Tuffaceous siltstone 10%; Tuffaceous siltsone 10% DAILY ACTIVITY SUMMARY Pick up and run 4.5” liner. Circulate bottoms up at 1392’ (Max Gas = 1725u), at 2052’ (Max Gas = 1591u), at 2838’ (Max Gas = 1640u), RIH with 4.5” liner from 2838’ to 4288’. Circulate bottoms up with 3 separate gas peaks (Max Gas = 1317u), dump 20 bbls watered-down mud. Make up hangar assembly, rig down Weatherford power tongs. Spot 23 bbls 14.3 ppg pill at 4288’ (Max Gas = 1617u). RIH with 4.5” liner on drill pipe from 4288’ to 7390’, filling pipe about 10 stands (start overboard with displacement at 6710’). Circulate until gas values low (Max Gas = 1475u) with 177 bbls watered-up mud overboarded to cuttings bin. RIH to about 8005’, fill pipe. RIH to about 8092’; pipe stopped going in; circulate until gas values low (Max Gas = 1589u). Run 2 stands (pipe stopped). Wash into hole from about 8267’ to about 8750’ with gas peaks of 798u, 1190u, and 1229u. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2300.00 REPORT BY Paul Webster Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 30, 2016 DEPTH 11525 PRESENT OPERATION Circulating 4.5" Liner TIME 24:00 YESTERDAY 11525 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11184.85 47.80 21.88 10302.37 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 11525' MW 10.55 VIS 45 PV 12 YP 16 FL 4.8 Gels 4/6/9 CL- 26000 FC 1/2 SOL 10.9 SD 0.10 OIL 0 MBT 4.5 pH 9.8 Ca+ 80 Alk 0.30 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS TG Liner = 573u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Hemlock PRESENT LITHOLOGY Conglomeratic Sand 10%; Conglomeratic Sandstone 10%; Sand 40%; Sandstone10%; Tuffaceous Claystone 10% ;Tuffaceous siltstone 10%; Tuffaceous siltsone 10% DAILY ACTIVITY SUMMARY Wash into hole with 4.5” liner on drill pipe from about 8750’ to 8893’ with gas peaks of 557u, 1341u. RIH on elevators from 8893’ to 9043’. Wash/Ream down to about 9063’’ (Max Gases = 1029u, 666u, 577u, 683u); RIH on elevators to 9246’. Wash from 9246’ to Bottom’ (Max Gases = 979u, 846u, 972u, 1002u, 1037u, 1015u,975u at various spots in section). Circulate liner before cement job. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2300.00 REPORT BY Paul Webster Hilcorp Alaska, LLC KENAI BOROUGH, AK DAILY WELLSITE REPORT SCU 322C-04 REPORT FOR Hilcorp Alaska, LLC DATE Jan 31, 2016 DEPTH 11525 PRESENT OPERATION CIP @ 04:15 Hours TIME 24:00 YESTERDAY 11525 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@7413' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 11184.85 47.80 21.88 10302.37 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBT pH Ca+ Alk MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS TG2 Liner = 1383u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH ETHANE (C-2) @ @ AVG PROPANE (C-3) @ @ CURRENT BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Hemlock PRESENT LITHOLOGY Conglomeratic Sand 10%; Conglomeratic Sandstone 10%; Sand 40%; Sandstone10%; Tuffaceous Claystone 10% ;Tuffaceous siltstone 10%; Tuffaceous siltsone 10% DAILY ACTIVITY SUMMARY Circulate liner before cement job. Do cement job (Max Gas = 1115u). CIP at 04:15 hours. CANRIG PERSONNEL ON BOARD 2 DAILY COST $2300.00 REPORT BY Paul Webster