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Home My WebLink About217-0411. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Development Exploratory 3. Address: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 9,799 feet See Schematic feet true vertical 9,702 feet 4,595 (fish)feet Effective Depth measured 3,650 feet 5,566 feet true vertical 3,632 feet 5,523 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A 5,566 MD Packers and SSSV (type, measured and true vertical depth)Swell Packer 5,523 TVD SSSV N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: 1,511' TVD 4,790psi 7,500psi 5,210psi 6,890psi 8,430psi 1,511'1,506' Burst Collapse 2,480psi measured Packer Plugs Junk measured Length measured true vertical Production Liner 6,090' 9,799' Casing Structural 6,040' 9,702' 6,090' 9,799' 120'Conductor Surface STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 217-041 50-133-20662-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEE A028142 Kenai Gas Field / Sterling Pool 3 KU 11-07X Gas-Mcf MD 0 Size 120' 0 00 0 00 0 7-5/8" 4-1/2" Intermediate 16" 10-3/4" 120' Stefan Reed, Operations Engineer 325-137 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A stefan.reed@hilcorp.com 206-518-0400 Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 9:05 am, May 07, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.05.06 17:01:17 - 08'00' Noel Nocas (4361) BJM 6/26/25 RBDMS JSB 051525 DSR-5/8/25 Page 1/1 Well Name: KEU KU 11-07X Report Printed: 5/2/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20662-00-00 Field Name:Kenai Gas Field State/Province:Alaska Permit to Drill (PTD) #:217-041 Sundry #:325-137 Rig Name/No: Jobs Actual Start Date:3/14/2025 End Date: Report Number 1 Report Start Date 3/29/2025 Report End Date 3/30/2025 Last 24hr Summary PJSM, Crew travel to location, Spot in & rig up, Pick up lube & tool string (1 x wt bar, GPT, Junk Basket, GR (3.75"), Pressure test 250/2000-good, Spot in & rig up Scorpion N2, Pressure test lines 3500 psi, Run in hole with run #1 (1 x wt bar, 1 x GPT, 1 x junk basket, 1 x GR (3.75"), Tag @ 3866', Fluid level @ 3656', Pull out of hole, Pressure test N2 line to 3500 psi-good, Pressure up with N2 to 280 psi-no build, Run in hole with run #2 (1 x wt bar, 1 x gpt, 1 x baker 10, 1 x plug (3.5"), No fluid found, Correlate, Set plug 3820', tag & log off, Pull out of hole, Pick up run #3 (3" x 30' bailer), Run in hole, Bail 8 gal cmt f/ 3820'-t/3807', Pull out of hole, Pick up run #4 (3" x 30' bailer), Run in hole, Bail 8 gal cmt f/ 3807'-t/ 3795' (16 gal total), Pull out of hole, Rig down & release YJ eline, Pressure up on tubing while monitoring Tubing (2953 psi) & IA (56 psi), OA (75 psi) @ 2030 pm, (witness waived by Jim Regg), Secure well, Rig down & release Scorpion Oilfield Services Report Number 2 Report Start Date 4/2/2025 Report End Date 4/3/2025 Last 24hr Summary AOGCC notice sent for tag and pt. WItness wiaved by JIm Regg. 72 hour plug test completed. PASSED. RU pollard slickline . PT 250/2500 psi. RIH with 3.75" GR and tag top of cement at 3801' KB. POOH RDMO. Report Number 3 Report Start Date 4/4/2025 Report End Date 4/5/2025 Last 24hr Summary PTW/PJSM, SITP 950psi, R/u YJ EL and Fox N2 pump. PT 250-2500psi. Pressure up on tbg to1750psi with N2, RIH w/1 11/16" Gamma Gun, Shock Sub, 20' x 2- 3/4" 6spf gun, send correlation log to town, no adjustment needed. Corrected tag depth 3795'MD showing 25' of cement on plug, perf P3_A11 (3744’-3764’MD) with 2 3/4" Guns, SITP fell to 550psi, Flow test, SDFN. Report Number 4 Report Start Date 4/5/2025 Report End Date 4/6/2025 Last 24hr Summary PTW/PJSM. SITP 0 psi. Run GPT - fluid level at 2,450', tag fill at 3,758'. PT N2 lines to 2500psi. Pump 48,125 scf N2, pressure broke over at 1,000 psi. Shut down with 670 psi. Run GPT - no fluid, tag fill at 3,749'. Set CIBP at 3,735'. Pressure up on well to 1,735 psi with 40,820 scf N2. Perforate P3_A10L Sand from 3,684' - 3,701'. SDFN and turn well over to Production to flow test. Report Number 5 Report Start Date 4/7/2025 Report End Date 4/7/2025 Last 24hr Summary PTW, JSA with crew. Make up GPT. Ops pressured up tubing with 680 psi natural gas pressure. RIH found fluid level 3015' correlated depth. Tag fill/sand at 3656'. POOH. Wait on N2 crew coming in from offsore. Fox N2 jump on permit. Tailgate meeting with all involved. Rig up N2. Cool down, PT N2 iron to 250/3500 psi. Online with N2 at 1000 scf/min. Well pressured up to 3000 psi with no break over. Previous fluid push with N2 break over was 1100 psi. SHut down N2 and hold 3K whp. Make up weight bar and GPT with YJES. RIH found fluid level remains at 3015'. Tagged fill/sand at 3655'. POOH discuss with town. 58,000 scf pumped (625 gals) N2. Bleed tubing down to open top tank removing all nitrogen. Make up CIBP. RIH and send correlation log to town. Set CIBP at 3650'. POOH to surface. RDMO to 24-06 RD. Plan forward: Swab water above CIBP with slick line. Report Number 6 Report Start Date 4/16/2025 Report End Date 4/16/2025 Last 24hr Summary PTW/PJSM, PT 250/2500. Swab fluid from 3010' - 3650', last 2 runs no FL observed, no measurable fluid returned. Recovered 9.2 of the 9.6 BBLS calculated. RDMO Report Number 7 Report Start Date 4/17/2025 Report End Date 4/18/2025 Last 24hr Summary PTW/PJSM, PT 250/2500. Perforate Sterling P3_A8 from 3584'-3604'. Flow tested well. Ran CCL & WB, tagged @ 3604', wire & tools wet. Report Number 8 Report Start Date 4/21/2025 Report End Date 4/22/2025 Last 24hr Summary PERFORMED PASSING MIT-IA 2170PSI. g, , Bail 8 gal cmt f/ 3807'-t/ 3795' ,gp , , Bail 8 gal cmt f/ 3820'-t/3807', ,p erforate P3_A10L Sand from 3,684' - 3,70 ,,g , Set CIBP at 3,735'. Perforate Sterling P3_A8 from 3584'-3604'. pg Set plug 3820', tagg Set CIBP at 3650 ,, erf P3_A11 (3744’-3764’MD) Updated by DMA 04-24-25 SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PBTD = 4,122’ MD / 4,099’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4"Surf. Csg 45.5 L-80 Buttress 9.95”Surf 1,511’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2"Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth (MD)ID Item 1 18’4.276”Tubing Hanger 2 3,650’CIBP (4/6/25) 3 3,735’CIBP (4/5/25) 4 3,820’CIBP w/ 25’ cement ToC = 3,795’ MD (4/4/25) 5 4,150’CIBP with 28’ cement: ToC = 4,122’ MD (4/20/22) 6 4,700’CIBP with 25’ cement: ToC = 4,675’ MD (4/11/22) 7 5,045’CIBP 8 5,566’4.276”10 ft Swell Packer (Water Swell) 9 5,780’CIBP with 25’ cement: ToC = 5755’ MD (2/9/22) 10 6,206’3.25”Permanent Owen X-span patch from 6206’ – 6243’ MD (11/10/21) 11 6,294’3.25”Permanent Owen X-span patch from 6294’ – 6309’ MD (11/8/21) 12 8,970’Expandable plug with 25’ cement: ToC = 8945’ MD (2/8/22) 13 9,420’3.958”CIBP set on 8/25/17 14 9,455’3.958”CIBP Set on 8/17/17 15 9,500’3.958”CIBP Set on 8/1/17 16 9,540’3.958”CIBP Set on 7/15/17 17 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 8 9 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’14 13 15 16 17 D-3B D-2 D-1 LB3 LB3B LB4C LB1B LB1C 10 11 7-5/8” TOC @ 2,500’ MB 6 12 Logged ToC in IA: 3115’ MD 3/7/22 See Punches :OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job. 4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2” 6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6044’. Intermittent bands of cement to 5,200’ MD. Solid cement band from 5,448’ to 5,562’ above Swellable packer. 4-1/2”7-5/8” annulus: 51 bbls 15.3# class G cement @ 3 bpm. CBL solid cement at 3,115’. PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments P3_A8 3,584’3,604’3,566’3,586’20’Sterling 3 4/17/25 Open P3_A10_L 3,684’3,701’3,683’3,701’17 Sterling 3 4/5/25 Isolated P3_A11 3,744’3,764’3,725’3,745’20’Sterling 3 4/4/25 Isolated P4_B1 3,828’3,836’3,809’3,817’8 Sterling 4 4/21/22 Isolated P4_B2_U 3,884’3,889’3,864’3,869’5 Sterling 4 4/21/22 Isolated P4_B2_L 3,904’3,907’3,884’3,887’3 Sterling 4 4/21/22 Isolated P5.2_B5 4,177’4,182’4,154’4,158’5 Sterling 5.2 4/11/22 Isolated P5.2_B5 4,177’4,182’4,154’4,158’5 Sterling 5.2 4/18/22 Isolated UB1X 4,735’4,745’4,704’4,714’10 Beluga/Up Ty 3/17/22 Isolated UB1 4,819’4,826’4,787’4,794’7 Beluga/Up Ty 3/17/22 Isolated N/A 4,879’4,882’4,846’4,849’3 N/A 2/18/22 Punches UB3 4,879’4,889’4,846’4,856’10 Beluga/Up Ty 3/20/22 Isolated UB4 4,941’4,951’4,907’4,917’10 Beluga/Up Ty 3/20/22 Isolated PERFORATION DETAIL (ISOLATED PERFS) on Following Page UB7 6 4 P5 P4 FISH DETAIL @ 4,595’ 4/15/22 -20.75’ Long, 2.5” HC Perf Gun 5 3 2 A8 A10 A11 P3 Updated by DMA 04-24-25 SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PERFORATION DETAIL (ISOLATED PERFS) Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments N/A 5,055’ 5,058’ 5,020’ 5,023’ 3 N/A 2/18/22 Punches UB5 5,055’ 5,060’ 5,020’ 5,025’ 5 Beluga/Up Ty 3/8/22 Plugged (3/17/22) UB5A 5,077’ 5,088’ 5,042’ 5,052’ 11 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,088’ 5,091’ 5,052’ 5,055’ 3 N/A 2/18/22 Punches N/A 5,119’ 5,129’ 5,083’ 5,093’ 10 N/A 2/16/22 Punches UB5B 5,128’ 5,141’ 5,092’ 5,105’ 13 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,168’ 5,173’ 5,131’ 5,136’ 5 N/A 2/15/22 Punches UB7 5,170’ 5,184’ 5,133’ 5,147’ 14 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,184’ 5,187’ 5,147’ 5,150’ 3 N/A 2/15/22 Punches UB7A 5,215’ 5,223’ 5,178’ 5,185’ 8 Beluga/Up Ty 3/8/22 Plugged (3/17/22) MB 6 Mid 1 5,810’ 5,818' 5,764’ 5,772' 8’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) MB 6 Mid 2 5,836' 5,846' 5,790 5,800' 10’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) LB1B 6,210’ 6,240’ 6,159’ 6,189’ 30' Blga/Upr Ty 9/27/21 Patched 11/10/21 LB1C 6,299’ 6,307’ 6,246’ 6,254’ 8' Blga/Upr Ty 9/27/21 Patched 11/8/21 LB3 6,707’ 6,726’ 6,650’ 6,669’ 19’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB3B 6,754’ 6,771’ 6,697’ 6,713’ 17’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB4C 7,007 7,018’ 6,947’ 6,957’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) 7,024’ 7,035’ 6,963’ 6,974’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) D-1 8,856’ 8,876’ 8,773’ 8,793’ 20’ Blga/Upr Ty 7/29/21 Plugged (2/9/22) D-2 8,983’ 9,036’ 8,899’ 8,951’ 53’ Ty Gas Pool #1 1/21/20 Plugged (2/8/22) D-3B 9,274’ 9,305’ 9,186’ 9,216’ 31’ Ty Gas Pool #1 8/25/17 Plugged (2/8/22) 9,313’ 9,323’ 9,224’ 9,234’ 10‘ Ty Gas Pool #1 7/8/21 Plugged (2/8/22) D-4A 9,431 9,445' 9,340’ 9,354’ 14’ Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’ 9,476’ 9,370’ 9,385’ 15’ Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’ 9,535’ 9,419’ 9,443’ 24’ Ty Gas Pool #1 7/17/17 Plugged 9,546’ 9,569’ 9,454’ 9,476’ 23’ Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600' 9,502’ 9,507’ 5’ Ty Gas Pool #1 6/12/17 Plugged 9,600 9,620' 9,507’ 9,526’ 25’ Ty Gas Pool #1 6/9/17 Plugged From:McLellan, Bryan J (OGC) To:Stefan Reed Cc:Donna Ambruz Subject:RE: [EXTERNAL] RE: KU 11-07X (PTD# 217-041) N2 Test Date:Friday, April 4, 2025 2:29:00 PM Attachments:image003.png Sounds good. Thank you for the update. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Friday, April 4, 2025 12:58 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KU 11-07X (PTD# 217-041) N2 Test Bryan, Our corrected TOC w/ eline is 3795’ which is where we expected based on calculations and gives us 25’ of cement above the CIBP set at 3820’. We are proceeding with the perforations per the sundry. Let me know if you have any questions. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, April 3, 2025 4:03 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Subject: [EXTERNAL] RE: KU 11-07X (PTD# 217-041) N2 Test Stefan, Just for clarity, is the blue curve the tubing pressure and the red curve the IA pressure? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Stefan Reed <Stefan.Reed@hilcorp.com> Sent: Thursday, April 3, 2025 2:25 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: KU 11-07X (PTD# 217-041) N2 Test Bryan, Attached is the crystal gauge recording for the plug verification using N2 on KU 11-07X (PTD# 217-041). We started the 72 hour test @ 05:21 on 30-Mar-2025 and T/I/O = 2934.5/55.9/75 psi and ended on 2-April-2025 T/I/O = 2924.3/56.8/75 psi. Slickline tagged TOC @ 3,801’ KB on 2- April 2025. Using the slickline correction only gives a 19’ cement top column (plug set @3,820’ELM). We will confirm TOC w/ eline. Let me know if you have any questions. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis 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: N2 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): 9,799'N/A Casing Collapse Structural Conductor Surface 2,480psi Intermediate 4,790psi Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other 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 Swell Packer ; N/A 5,566'MD / 5,523'TVD ; N/A. 9,702'9,420'9,330' Kenai Sterling Pool 4 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 11-07XCO 510C Sterling Pool 3 9,702'4-1/2" ~638psi 9,799' See Schematic Length March 24, 2025 N/A 9,799' Perforation Depth MD (ft): 6,090' See Attached Schematic 6,890psi 5,210psi 120' 6,040' 120' 1,511' Size 120' 7-5/8"6,090' 1,511' MD Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 8,430psi 1,506' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE A028142 217-041 50-133-20662-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Stefan Reed, Operations Engineer AOGCC USE ONLY Tubing Grade: stefan.reed@hilcorp.com 206-518-0400 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: m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:26 pm, Mar 11, 2025 325-137 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.03.11 11:17:41 - 08'00' Noel Nocas (4361) A.Dewhurst 13MAR25 X Perforate New Pool P DSR-3/24/25 Sterling Pool 3 10-404 BJM 3/13/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.26 08:26:58 -08'00'03/26/25 RBDMS JSB 032725 Adperf Rev. 1 Well: KU 11-07x Date:3/7/2025 Well Name: KU 11-07X API Number: 50-133-20662-00-00 Current Status: Gas Producer Permit to Drill Number: 217-041 First Call Engineer: Stefan Reed (907) 777-8433 (o) (206) 518-0400 (c) Second Call Engineer: Chad Helgeson (907) 777-8405 (o) (907) 229-4824 (c) Max Expected BHP: ~1005psi @ 3691’MD/367 3’TVD Maximum Expected Surface Pressure: ~638psi (using 0.1psi/ft gradient) Applicable Frac Gradient: 0.65psi/ft using FIT done 4/22/2017 Shallowest Perf Depth: 638psi/(0.65-0.1) = 1160’ TVD Pool Tops Per CO 510C: Sterling Pool 3 Top: 3,565’ MD / 3,548’ TVD Well Summary KU 11-07X was a steady Tyonek Gas Pool #1 producer. In 2021 Hilcorp added perforations in the Beluga/Upper Tyonek Pool that were unsuccessful, patches were installed, and coil tubing completed an N2 lift without any success removing water from the well and no sustained gas rate. The Tyonek Gas pool #1 was plugged back, and a non-rig recomplete was performed which included, pumping a cement packer/annulus, the cement was drilled out and new sands in the Beluga/Upper Tyonek Pool were added. In 2022 the Beluga/Upper Tyonek perforations were isolated and Sterling Pool 5.2 perforations were added but came in wet. The Sterling Pool 5.2 were then isolated and perforations were added in Sterling Pool 4. The well produced at ~900mscfd on a steady decline. Currently the well is on production making ~50mscfd. The purpose of this work/sundry is to isolate the Sterling Pool 4 perfs and perforate the Sterling Pool 3 sands. Notes Regarding Wellbore Condition x Max Inclination = 11 degrees at 6308’ MD x Slickline drifted w/ 3.25” GR to 3914’ 7/8/2024. Eline Procedure 1. MIRU Eline unit and N2 pump 2. PT PCE 3. Drift w/ 3.75” GR. Run GR/CCL for correlation 4. Run GPT to confirm fluid level push away w/ N2 as needed. 5. RIH w/ 4-1/2” CIBP and set at ~3,820’. The plug must be within 50’ of top perforation. 6. Dump bail 25’ of cement (~16gals) on top of plug. 7. RIH tag TOC and pressure test w/ nitrogen to 2500psi a. Using a chart recorder or digital crystal gauge monitor the pressure for a minimum of 72hrs. b. Criteria for a passing test being a time of 72 hours showing stabilization and less than 2% drop of the maximum test pressure over the 72 hour test period. c. IA pressure must be monitored over the duration of the test period. d. 72-hr test will start once pressure stabilizes. e. Provide minimum 24hr notice to AOGCC to witness tag and test. 8. Perforate proposed interval bottoms up per table below: a. Make correlation pass and send log to OE/RE/GEO b. Record initial and 5/10/15 minute tubing pressures after firing c. Test each zone after perforating. Reperf any zones per RE/GEO discretion d. Perfs will be shot in the Sterling Pool 3 governed by CO 510C Adperf Rev. 1 Well: KU 11-07x Date:3/7/2025 Pool Sand Perforation Top (MD) Perforation Bottom (MD) Total Footage (MD) Sterling 3 P3_A8 ±3,569’ ±3,604’ ±35’ Sterling 3 P3_A10_U ±3,654’ ±3,673’ ±19’ Sterling 3 P3_A10_L ±3,684’ ±3,701’ ±17’ Sterling 3 P3_A11 ±3,744’ ±3,764’ ±20’ Eline Procedure (Contingency) If any zone produces sand and/or water or needs to be isolated: 1. MIRU Eline. PT PCE 2. Run GPT to find fluid level 3. Use N2 or gas to push fluid below perfs as needed. (Verify fluid depth w/ GPT) 4. Set CIBP to isolate zone. Post-Perf MIT-IA 1. Perform MIT-IA to 2000psi once job is complete. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Updated by DMA 03-12-24 SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PBTD = 4,122’ MD / 4,099’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4"Surf. Csg 45.5 L-80 Buttress 9.95”Surf 1,511’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2"Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth (MD)ID Item 1 18’4.276”Tubing Hanger 1A 4,150’CIBP with 28’ cement: ToC = 4,122’ MD (4/20/22) 1B 4,700’CIBP with 25’ cement: ToC = 4,675’ MD (4/11/22) 2 5,045’CIBP 3 5,566’4.276”10 ft Swell Packer (Water Swell) 4 5,780’CIBP with 25’ cement: ToC = 5755’ MD (2/9/22) 5 6,206’3.25”Permanent Owen X-span patch from 6206’ – 6243’ MD (11/10/21) 6 6,294’3.25”Permanent Owen X-span patch from 6294’ – 6309’ MD (11/8/21) 7 8,970’Expandable plug with 25’ cement: ToC = 8945’ MD (2/8/22) 8 9,420’3.958”CIBP set on 8/25/17 9 9,455’3.958”CIBP Set on 8/17/17 10 9,500’3.958”CIBP Set on 8/1/17 11 9,540’3.958”CIBP Set on 7/15/17 12 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 3 4 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’9 8 10 11 12 D-3B D-2 D-1 LB3 LB3B LB4C LB1B LB1C 5 6 7-5/8” TOC @2,500’ MB 6 7 Logged ToC in IA: 3115’MD 3/7/22 See Punches : OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job. 4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2” 6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6044’. Intermittent bands of cement to 5,200’ MD. Solid cement band from 5,448’ to 5,562’ above Swellable packer. 4-1/2”7-5/8” annulus: 51 bbls 15.3# class G cement @ 3 bpm. CBL solid cement at 3,115’. PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments P4_B1 3,828’3,836’3,809’3,817’8 Sterling 4 4/21/22 Open P4_B2_U 3,884’3,889’3,864’3,869’5 Sterling4 4/21/22 Open P4_B2_L 3,904’3,907’3,884’3,887’3 Sterling 4 4/21/22 Open P5.2_B5 4,177’4,182’4,154’4,158’5 Sterling 5.2 4/11/22 Isolated P5.2_B5 4,177’4,182’4,154’4,158’5 Sterling 5.2 4/18/22 Isolated UB1X 4,735’4,745’4,704’4,714’10 Beluga/Up Ty 3/17/22 Isolated UB1 4,819’4,826’4,787’4,794’7 Beluga/Up Ty 3/17/22 Isolated N/A 4,879’4,882’4,846’4,849’3 N/A 2/18/22 Punches UB3 4,879’4,889’4,846’4,856’10 Beluga/Up Ty 3/20/22 Isolated UB4 4,941’4,951’4,907’4,917’10 Beluga/Up Ty 3/20/22 Isolated PERFORATION DETAIL (ISOLATED PERFS) on Following Page UB2 1B 1A P5 P4 FISH DETAIL @ 4,595’ 4/15/22 -20.75’ Long, 2.5” HC Perf Gun Updated by DMA 03-12-24 SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PERFORATION DETAIL (ISOLATED PERFS) Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments N/A 5,055’ 5,058’ 5,020’ 5,023’ 3 N/A 2/18/22 Punches UB5 5,055’ 5,060’ 5,020’ 5,025’ 5 Beluga/Up Ty 3/8/22 Plugged (3/17/22) UB5A 5,077’ 5,088’ 5,042’ 5,052’ 11 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,088’ 5,091’ 5,052’ 5,055’ 3 N/A 2/18/22 Punches N/A 5,119’ 5,129’ 5,083’ 5,093’ 10 N/A 2/16/22 Punches UB5B 5,128’ 5,141’ 5,092’ 5,105’ 13 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,168’ 5,173’ 5,131’ 5,136’ 5 N/A 2/15/22 Punches UB7 5,170’ 5,184’ 5,133’ 5,147’ 14 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,184’ 5,187’ 5,147’ 5,150’ 3 N/A 2/15/22 Punches UB7A 5,215’ 5,223’ 5,178’ 5,185’ 8 Beluga/Up Ty 3/8/22 Plugged (3/17/22) MB 6 Mid 1 5,810’ 5,818' 5,764’ 5,772' 8’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) MB 6 Mid 2 5,836' 5,846' 5,790 5,800' 10’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) LB1B 6,210’ 6,240’ 6,159’ 6,189’ 30' Blga/Upr Ty 9/27/21 Patched 11/10/21 LB1C 6,299’ 6,307’ 6,246’ 6,254’ 8' Blga/Upr Ty 9/27/21 Patched 11/8/21 LB3 6,707’ 6,726’ 6,650’ 6,669’ 19’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB3B 6,754’ 6,771’ 6,697’ 6,713’ 17’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB4C 7,007 7,018’ 6,947’ 6,957’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) 7,024’ 7,035’ 6,963’ 6,974’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) D-1 8,856’ 8,876’ 8,773’ 8,793’ 20’ Blga/Upr Ty 7/29/21 Plugged (2/9/22) D-2 8,983’ 9,036’ 8,899’ 8,951’ 53’ Ty Gas Pool #1 1/21/20 Plugged (2/8/22) D-3B 9,274’ 9,305’ 9,186’ 9,216’ 31’ Ty Gas Pool #1 8/25/17 Plugged (2/8/22) 9,313’ 9,323’ 9,224’ 9,234’ 10‘ Ty Gas Pool #1 7/8/21 Plugged (2/8/22) D-4A 9,431 9,445' 9,340’ 9,354’ 14’ Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’ 9,476’ 9,370’ 9,385’ 15’ Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’ 9,535’ 9,419’ 9,443’ 24’ Ty Gas Pool #1 7/17/17 Plugged 9,546’ 9,569’ 9,454’ 9,476’ 23’ Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600' 9,502’ 9,507’ 5’ Ty Gas Pool #1 6/12/17 Plugged 9,600 9,620' 9,507’ 9,526’ 25’ Ty Gas Pool #1 6/9/17 Plugged Updated by SAR 03-04-2025 PROPOSED Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PBTD = 4,122’ MD / 4,099’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4"Surf. Csg 45.5 L-80 Buttress 9.95”Surf 1,511’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2"Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth (MD)ID Item 1 18’4.276”Tubing Hanger 1A ~3,820’CIBP w/ 25’ cement 1B 4,150’CIBP with 28’ cement: ToC = 4,122’ MD (4/20/22) 1C 4,700’CIBP with 25’ cement: ToC = 4,675’ MD (4/11/22) 2 5,045’CIBP 3 5,566’4.276”10 ft Swell Packer (Water Swell) 4 5,780’CIBP with 25’ cement: ToC = 5755’ MD (2/9/22) 5 6,206’3.25”Permanent Owen X-span patch from 6206’ – 6243’ MD (11/10/21) 6 6,294’3.25”Permanent Owen X-span patch from 6294’ – 6309’ MD (11/8/21) 7 8,970’Expandable plug with 25’ cement: ToC = 8945’ MD (2/8/22) 8 9,420’3.958”CIBP set on 8/25/17 9 9,455’3.958”CIBP Set on 8/17/17 10 9,500’3.958”CIBP Set on 8/1/17 11 9,540’3.958”CIBP Set on 7/15/17 12 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 3 4 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’9 8 10 11 12 D-3B D-2 D-1 LB3 LB3B LB4C LB1B LB1C 5 6 7-5/8” TOC @ 2,500’ MB 6 7 Logged ToC in IA: 3115’ MD 3/7/22 See Punches : OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job. 4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2” 6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6044’. Intermittent bands of cement to 5,200’ MD. Solid cement band from 5,448’ to 5,562’ above Swellable packer. 4-1/2”7-5/8” annulus: 51 bbls 15.3# class G cement @ 3 bpm. CBL solid cement at 3,115’. PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments P3_A8 ±3569’±3,604’±3,551’±3,586’±35 Sterling 3 TBD TBD P3_A10_U ±3,654’±3,673’±3,636’±3,655’±19 Sterling 3 TBD TBD P3_A10_L ±3,684’±3,701’±3,683’±3,701’±17 Sterling 3 TBD TBD P3_A11 ±3,744’±3,764’±3,725’±3,745’±20’Sterling 3 TBD TBD P4_B1 3,828’3,836’3,809’3,817’8 Sterling 4 4/21/22 Isolated P4_B2_U 3,884’3,889’3,864’3,869’5 Sterling 4 4/21/22 Isolated P4_B2_L 3,904’3,907’3,884’3,887’3 Sterling 4 4/21/22 Isolated P5.2_B5 4,177’4,182’4,154’4,158’5 Sterling 5.2 4/11/22 Isolated P5.2_B5 4,177’4,182’4,154’4,158’5 Sterling 5.2 4/18/22 Isolated UB1X 4,735’4,745’4,704’4,714’10 Beluga/Up Ty 3/17/22 Isolated UB1 4,819’4,826’4,787’4,794’7 Beluga/Up Ty 3/17/22 Isolated N/A 4,879’4,882’4,846’4,849’3 N/A 2/18/22 Punches UB3 4,879’4,889’4,846’4,856’10 Beluga/Up Ty 3/20/22 Isolated UB4 4,941’4,951’4,907’4,917’10 Beluga/Up Ty 3/20/22 Isolated PERFORATION DETAIL (ISOLATED PERFS) on Following Page UB2 1C 1A P5 P4 FISH DETAIL @ 4,595’ 4/15/22 -20.75’ Long, 2.5” HC Perf Gun 1B Updated by SAR 03-04-25 SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PERFORATION DETAIL (ISOLATED PERFS) Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments N/A 5,055’ 5,058’ 5,020’ 5,023’ 3 N/A 2/18/22 Punches UB5 5,055’ 5,060’ 5,020’ 5,025’ 5 Beluga/Up Ty 3/8/22 Plugged (3/17/22) UB5A 5,077’ 5,088’ 5,042’ 5,052’ 11 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,088’ 5,091’ 5,052’ 5,055’ 3 N/A 2/18/22 Punches N/A 5,119’ 5,129’ 5,083’ 5,093’ 10 N/A 2/16/22 Punches UB5B 5,128’ 5,141’ 5,092’ 5,105’ 13 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,168’ 5,173’ 5,131’ 5,136’ 5 N/A 2/15/22 Punches UB7 5,170’ 5,184’ 5,133’ 5,147’ 14 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,184’ 5,187’ 5,147’ 5,150’ 3 N/A 2/15/22 Punches UB7A 5,215’ 5,223’ 5,178’ 5,185’ 8 Beluga/Up Ty 3/8/22 Plugged (3/17/22) MB 6 Mid 1 5,810’ 5,818' 5,764’ 5,772' 8’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) MB 6 Mid 2 5,836' 5,846' 5,790 5,800' 10’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) LB1B 6,210’ 6,240’ 6,159’ 6,189’ 30' Blga/Upr Ty 9/27/21 Patched 11/10/21 LB1C 6,299’ 6,307’ 6,246’ 6,254’ 8' Blga/Upr Ty 9/27/21 Patched 11/8/21 LB3 6,707’ 6,726’ 6,650’ 6,669’ 19’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB3B 6,754’ 6,771’ 6,697’ 6,713’ 17’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB4C 7,007 7,018’ 6,947’ 6,957’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) 7,024’ 7,035’ 6,963’ 6,974’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) D-1 8,856’ 8,876’ 8,773’ 8,793’ 20’ Blga/Upr Ty 7/29/21 Plugged (2/9/22) D-2 8,983’ 9,036’ 8,899’ 8,951’ 53’ Ty Gas Pool #1 1/21/20 Plugged (2/8/22) D-3B 9,274’ 9,305’ 9,186’ 9,216’ 31’ Ty Gas Pool #1 8/25/17 Plugged (2/8/22) 9,313’ 9,323’ 9,224’ 9,234’ 10‘ Ty Gas Pool #1 7/8/21 Plugged (2/8/22) D-4A 9,431 9,445' 9,340’ 9,354’ 14’ Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’ 9,476’ 9,370’ 9,385’ 15’ Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’ 9,535’ 9,419’ 9,443’ 24’ Ty Gas Pool #1 7/17/17 Plugged 9,546’ 9,569’ 9,454’ 9,476’ 23’ Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600' 9,502’ 9,507’ 5’ Ty Gas Pool #1 6/12/17 Plugged 9,600 9,620' 9,507’ 9,526’ 25’ Ty Gas Pool #1 6/9/17 Plugged STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, June 10, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 11-07X KENAI UNIT 11-07X Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/10/2022 11-07X 50-133-20662-00-00 217-041-0 N SPT2170410 2000 34 34 34 34 50 50 50 50 OTHER P Brian Bixby 5/6/2022 MITIA as per SUNDRY # 322-177. This is a producer and the the orignal packer is cemented off. TOC in the IA is 3107' TVD. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KENAI UNIT 11-07X Inspection Date: Tubing OA Packer Depth 310 2190 2157 2133IA 34 50 45 Min 2122 60 Min Rel Insp Num: Insp Num:mitBDB220508154140 BBL Pumped:0.6 BBL Returned:0.6 Friday, June 10, 2022 Page 1 of 1 9 9 9 9 9 9 *DVSURGXFHU TOC in the IA is 3107' TVD.MITIA as per SUNDRY # 322-177. James B. Regg Digitally signed by James B. Regg Date: 2022.06.10 15:20:01 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 5/16/2022 To: Department of Natural Resources Resource Evaluation 550 W 7th Ave, Suite 1100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) CIBP 4/11/2022 GPT/PERF 4/18/2022 Please include current contact information if different from above. PTD:217-041 T36616 T36617 Kayla Junke Digitally signed by Kayla Junke Date: 2022.05.17 09:28:09 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 5/09/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) Plug Cement 04/20/2022 Please include current contact information if different from above. PTD:217-041 T36571 Kayla Junke Digitally signed by Kayla Junke Date: 2022.05.10 09:48:26 -08'00' 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 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 9,799 feet See Schematic feet true vertical 9,702 feet None feet Effective Depth measured 9,420 feet 5,566 feet true vertical 9,330 feet 5,523 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A 5,566 MD Packers and SSSV (type, measured and true vertical depth)Swell Packer 5,523 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: 4,790psi 7,500psi 5,210psi 6,890psi 8,430psi Burst Collapse 2,480psi 120' 1,506' 6,040' 9,702' 6,090' 9,799'4-1/2" measuredPlugs Junk measured N/A Length 120' 1,511' Size Conductor Surface Intermediate 16" 10-3/4" 7-5/8" Production Liner 6,090' 9,799' Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 217-041 50-133-20662-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEE A028142 Kenai Gas Field / Tyonek Gas Pool 1 & Beluga/Upper Tyonek Pool 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: KU 11-07X Hilcorp Alaska, LLC Other: Cement Packer / N2 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0 02 0 695 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 120' 1,511' N/A 100 Structural TVD 322-037 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 11 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 165 Ryan Rupert ryan.rupert@hilcorp.com 907 777-8503Dan Marlowe - Operations Manager t Fra O 6. A PG , R Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Meredith Guhl at 2:29 pm, Mar 29, 2022 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2022.03.29 11:54:44 -08'00' Dan Marlowe (1267) Rig Start Date End Date 2/8/22 3/22/22 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 PTW, JSA. Gather items for fluid pump. Load supply tank with 400 bbls of fresh water. MIRU YJOS fluid pump. Rig up field triplex to IA. AK E-line on location rigging up. Pressure test IA to 2100 psi for 10 minutes. Test not recorded. Good test. Stabbed on well with AK E-line. PT lubricator 250/3000 psi. Fill tubing to catch fluid. 27 bbls pumped. Perform MIT on 4.5" production tubing to 3000 psi for 10 minutes. RIH with AK E-line. Log and tie into Halliburton 11-07X CBL 16 May 17. 18.6' from ccl to top shot. Park CCL depth 5165.4. Tubing 950 psi, IA 0 psi open to return tank , OA 250 psi. Fire tubing punches from 5184'-5187'. (1540 hrs). Tubing pressure bounced around from 950 to 890 psi. POOH to surface. Pop off E line and install night cap. All punches fired. Line up fluid pump down tubing taking returns up IA. Pressure up to 4500 psi. Small stream to return tank. Watch pressure. 250 psi drop in 30 minutes. Call town to discuss. AK E-line rigging up second tubing punch. Make up second tubing punch. Stab on well. RIH and Correlate depth to CBL log. Pressure up tubing to 1520 psi. IA open to return tank OA 250 psi. Fire second shots from 5168'-5173'. No flow at return tank. Tubing dropped from 1520 psi to 1480 psi. POOH with E-line. Online down tubing attempt to circulate 2.5 bbls/min pressure climbed to 4500 psi. No returns to tank. Monitor pressure. Shut in Tubing with 4486 psi SITP. Close IA valve. Leave tubing pressured up over night. Rig down AK E line. Location secure. 02/15/2022 - Tuesday 02/09/2022 - Wednesday PTW, JSA with AK E-line crew. Warm up equipment. Pick up lubricator assembly and make up CIBP for 4.5" production tubing. Stab on well. PT stack 250/3000 psi. Tubing 0 psi. RIH with CIBP. Log interval and correlate depth. CCL to middle element 7.6'. Pull into position and stop CCL at 5772.4'. Set CIBP at 5780'. (10:30 AM). Weight dropped from 954 lbs to 643 lbs. Good set. Pick up 50' and tag plug. POOH to surface. Break down setting tools and make up 2.5"x30' cement dump bailer. Mix and load cement. Stab on well. RIH with cement dump run # 1. Lightly tag top of CIBP at 5780'. Pick up 10' and dump cement at 1300 hrs. POOH to surface. Mix and load 2nd. 2.5"x30' cement dump bailer. Stab on well. RIH to 5770'. and dump cement. POOH to surface. Mix and load 3rd and final. 2.5"x30' cement dump bailer. Stab on well. RIH to 5763' and dump cement (1600 hrs.) giving a calculated 25' of cement on top of CIBP. POOH to surface. Close master and swab. Estimated fluid level in well is 2390'. TOC 5,755'. Rig down AK-Eline unit. Well site secure. Depart location. E-line will return for tubing punch when pump truck and cementing services are ready to continue the intervention. Daily Operations: 02/08/2022 - Tuesday PTW, JSA with crew. Rig up AK E-line. Make up 3" OD magna rand bridge plug from Owen oil tools. Stab on well. Pressure test 250/3000 psi. Open swab valve. RIH with FN, Weight bar, Gun Gamma, MSSST setting tool , and 3" OD magna range bridge plug. Perform correlation pass (use tie in log KU 11-07X _CBL_16 May_17) 13.9' ccl to middle element. CCL stop depth 8956.1'. Set plug at 8970'. PU 50' RIH and tag plug. Good set. POOH to surface. Lay down Tool string and swap for 2.5" cement bailer. Load 2.5"x30' cement bailer. Stab on well. RIH for cement dump run #1. Tag plug 8970'. Pick up 10' and dump cement. POOH to surface. Mix up cement Run #2. Stab on well. RIH to 8955' and dump cement. POOH to surface. Mix cement run #3. RIH and dump cement 8945' and dump final cement. POOH to surface. 25' of cement placed on Magna range BP. TOC 8945. At surface. Close well. Lay down lubricator. Location secure. SDFN. Rig Start Date End Date 2/8/22 3/22/22 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 Daily Operations: AKEL crew arrives at facility and obtains permit, TGSM. MIRU eline equipment and pressure test lubricator to 250 psi low / 3000 psi high. Hammer up pump line and IA returns line. 2900 psi on tubing. Open IA and get approximately 1/2 bbl of returns. Pressure up on tubing to 4800 psi and monitor for returns. No fluid to returns tank. Bleed pressure down to 2000 psi. Arm and RIH with 2" tubing puncher, 3' loaded at 6 SPF. Correlate CCL to HES CBL log dated May 2017. Punch from 5088-5091'. No change in tubing pressure. POOH. Lay down puncher, all shots fired. Pressure up on tubing to 4800 psi an monitor IA for flow. Trickle of flow at returns tank. Bleed down and pressure up to 4800 psi 3 times with no increase in returns rate. Arm and RIH with 2" tubing puncher, 3' loaded at 6 SPF. With 3000 psi on tubing punch from 5055-5058'. No change in tubing pressure. POOH. Lay down puncher, all shots fired. Pressure up on tubing to 4800 psi an monitor IA for flow. Trickle of flow at returns tank. Bleed down and pressure up to 4800 psi 10 times with no increase in returns rate. Arm and RIH with 2" tubing puncher, 3' loaded at 6 SPF. With 3000 psi on tubing punch from 4879-4882'. No change in tubing pressure. POOH. Lay down puncher, all shots fired. Pressure up on tubing to 4800 psi an monitor IA for flow. Trickle of flow steadily increases and tubing pressure bleeds down to 1000 psi. Come online with pump and begin circulating at 4.5 BPM. RDMO eline. Circulate 250 bbls total, returns are clean for last 60 bbls. Line up to reverse and pump 70 bbls down IA taking returns from tubing. Returns look clean the whole time. Freeze protect pump and lines. Vac truck taking returns to GNI. Secure location and SDFN. 02/20/2022 - Sunday Halliburton cementing crew arrives at facility and obtains permit, TGSM. Rig up cementing equipment lining out to pump down the tubing taking returns from the IA. Pressure test treating lines 250 psi low / 3000 psi high. Establish circulation and check returns, full returns. Perform CMIT TxIA to 3000 psi, good test. Mix up 15.3 ppg cement blend and get sample. Pump 51 bbls of 15.3 ppg cement at 3 BPM. Drop ball and displace cement with 73 bbls lease water. Shut in IA and tubing, Final lift pressure: 510 psi. Calculated TOC: 3000'. Under displaced cement by 85'. Cement in tubing calculated at 4794'. Wash up cementers and RDMO. 02/16/2022 - Wednesday Arrive on location. 3340 psi on 4.5" tubing. Hammer up pump lines and returns lines. Tubing 3340 psi. IA 130 psi, OA 250 psi. Open IA valve to return tank. Bleed off pressure. Open pump line to 4.5" production tubing. Online with fluid pump. Shut down pump at 4700 psi. No returns from IA. Monitor pressure. 5/10/15 no change and no flow to return tank. Call out AK E-line. RIg up AK E-line with 10' tubing punch. Stab on well. PT 250/3000 psi. RIH. Correlate to Halliburton CBL log 16 May 2017. CCL to top shot 10.2'. Pull into position and park CCL at 5108.8'. Online down tubing. 1238 psi SITP. IA open to return tank, shoot tubing punches from 5119'-5129'. Pressure dropped from 1238 psi to 1187 psi. No returns from AI. POOH to surface. E-line install night cap. Attempt to circulate well. Online down 4.5" tubing taking returns up IA. Pressure up to 4700 psi. No returns to surface. Attempt 3 more times at different pump rates. Rig iron to pump down IA and take returns up production tubing. NO communication. Rig back up to Tubing and return up IA. Pressure up to 4700 psi SITP. AK E-line rigged down. Freeze protect fluid pump. Secure location. SDFN. 02/18/2022- Friday Rig Start Date End Date 2/8/22 3/22/22 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 Daily Operations: 02/25/2022- Friday Fox coiled tubing arrive on location. Conduct JSA and approve PTW. Remove wellhouse from well and NU Flow cross and Combi BOP's. RU choke skid from flow cross to return tank. Haul source water to fill supply tank. Jim Regg with AOGCC waived witness on 09:23 on 2/24/22 via e-mail. Function test BOP rams. Test Equalizing ports, fully body, blind/shear rams, pipe slip rams, choke skid valves to 250 psi low / 3500 psi high. Perform accumulator test recording pressure and times. Install night cap on BOP's. Spot N2 unit. SDFN. 02/26/2022 - Saturday Fox N2 arrive location. Conduct JSA and approve PTW. Drift milling BHA and confirm dimensions. MU connector and pull test to 20k. Load coil with water, PT connector and MHA. Milling BHA: 2.88" x 0.71' CTC, 2.88" x 1.25' DFCV, 2.88" x 6.5' jars, 2.88" x 2.13' disco, 2.88" x 1.43' circ sub, 2.88" x 12.2' motor, 3.77" x 1.08' junk mill. PT lubricator, stripper, and inner reel valve to 250 psi low / 3500 psi high. Open well and RIH. Dry tag at 4153'. Online with pump. 1.5 bpm at 4300 psi. RIH to 4210'. Cannot get anymore rate without hitting max pressure of 5k. Seeing very little or no motor work. replace pop-off on pump and change out 5k hoses. Pressure test iron and pump to 8k. Online with pump. Pump at 2.3 bpm at 7350 psi. Attempt to mill at 4210'. Very little or no motor work. Set down 5k and cannot get a stall. Continue to set down making ~ 0.5' per minute. Stop at 4253' and POOH. At surface with milling BHA. Motor not working properly, can turn by hand. Mill has some cement residue on face and very little indication of wear or work. Cool down N2 unit and blowdown reel. Lay down lubricator and set injector on back deck. SDFN. Rig Start Date End Date 2/8/22 3/22/22 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 Daily Operations: Fox coiled tubing meet at office. Conduct JSA and approve PTW. Pickup lubricator joints and MU MHA/jars. Load coil with water and PT connector, jars, and MHA. MU mill and motor and go to the well. PT lubricator to 3500 psi. Milling BHA: 2.88" x 0.71' CTC, 2.88" x 1.25' DFCV, 2.88" x 6.5' jars, 2.88" x 2.13' disco, 2.88" x 1.43' circ sub, 2.88" x 12.2' motor, 3.77" x 1.08' junk mill. Open well and RIH. Tubing pressure = 0 psi. IA = 0 psi. Slipstream friction reducer (Baroid CFS 520) into fluid while running in hole to displace non-treated water. Online with pump at 1.90 bpm and 5400 psi. Set down at 4257'. Attempt to mill, but no motor work. Set down in increments to 8k, no indication of motor work or stalls. Pick up and attempt to RIH at 30 fpm and tag, still no stall. Reach depth of 4260'. POOH. Coil at surface. Nothing obvious wrong with motor, cannot turn by hand. Remove mill/motor and PT again to verify no leaks. No leaks. Laydown BHA and cut off connector. Stack down lubricator. Cool down N2 unit and blowdown reel. Set injector on back deck. Install night cap on BOP's. SDFN. 02/27/2022 - Sunday 03/04/2022- Friday Fox coiled tubing arrive from Kalotsa. Conduct JSA and approve PTW. MIRU. NU Flowcross/BOP's and RU hardline to choke manifold. Jim Regg with AOGCC verbally waived witness to test BOPE. Function test BOP rams. Test full body, blind/shear rams, pipe/slip rams, choke skid to 250 psi low / 3500 psi high. Circulate water supply tank while adding friction reducer. Use 0.033% DR204 friction reducer. SDFN. 03/05/2022 - Saturday Fox Coil and Quadco arrive at location. Conduct JSA and approve PTW. MU CTC and pull test to 35k lbs. PT MHA and jars to 3500 psi. MU motor/mill and go to the well. PT lubricator to 250/3500 psi. BHA: 2.88" x 1.62" CTC, 2.88" x 1.41' DFCV, 2.88" x 3.82" hailey jar, 2.88" x 1.29" disco, 2.88" x 1.57' circ sub, 2.88" x 13.7' Titan motor, 3.80" x 0.94' junk mill. Open well and RIH. Tag at 4274' (m). Up wt = 13k. Free spin = 2.3 bpm @ 3050 psi. Start milling, set down ~ 4k. Circ pressure increases to ~ 3150 psi. Good motor work. Hard milling,. Mix more friction reducer in water. Haul off returns. Continue milling at 2.1 bpm @ 2850 psi. Getting ~ 100-150 psi motor work. Mill down to 4400'. Stop for the night. POOH. Laydown milling BHA. Blowdown coil with N2. Stack down lubricator and set injector on back deck. Secure well with night cap on BOPs. SDFN. Rig Start Date End Date 2/8/22 3/22/22 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 Daily Operations: Fox coiled tubing and Quadco on location. Conduct JSA and approve PTW. Get heater for frozen tank valves and pump valves. MU Quadco milling BHA. BHA: 2.88" x 1.62" CTC, 2.88" x 1.41' DFCV, 2.88" x 3.82" hailey jar, 2.88" x 1.29" disco, 2.88" x 1.57' circ sub, 2.88" x 13.7' Titan motor, 3.80" x 0.94' junk mill. Go to the well and PT lubricator 250/3500 psi. Open well and RIH. Tag at 4400' ctmd. Pump down coil and get free spin of motor. Free spin = 2.2 bpm @ 3000 psi. Start milling at 2.2 bpm @ 3150 psi. Mill to 4650' (ROP ~ 100' hr). Pump at 2.2 bpm @ 3250 psi. Mill to 4800' (ROP ~ 150' hr). Pump at 2.2 bpm @ 330 psi. Mill to 4972', then no more cement. Continue RIH freely while pumping at 2.2 bpm. Tag at 5761'. Continue pumping at 2.2 bpm while POOH to chase all cement fines to surface. Coil at surface. Shut in swab. Laydown milling BHA and MU cold roll with nozzle. MIT-IA to 2000 psi for 30 minutes. Starting pressure = 2100 psi, ending pressure = 2000 psi. Stab back on well and blow coil reel dry with N2. Set injector on back deck. SDFN. 03/07/2022 - Monday YellowJacket E-line arrive on location. Conduct JSA and approve PTW. MU 2.75" Titan CBL Toolstring. PT lubricator to 250 psi low/3000 psi high. Open well and RIH. Tag at 5762' (uncorrected). Log up ~ 500' for repeat pass. RIH back to TD. Log up at 45 ft/min from TD to 2950'. Determine TOC = 3116'. POOH and laydown toolstring, lubricator. RDMO. Pick coil injector and MU lubricator. MU 1.75" connector, 1.75" DFCV, 1.75" straight bar, 1.75" nozzle. Go to the well and PT lubricator to 250 psi low / 3500 psi high. Open well and RIH. Start pumping N2 at 2000' ctmd, taking returns to surface. N2 pump rate = 1000 scfm. Tag at 5764'. Pick up a few feet and pump N2 while on bottom for 5 minutes. POOH. Recover 85 bbls of fluid. Shut in choke and pressure up well with N2 while POOH. Coil at surface. Final wellhead pressure = 1350 psi. RDMO. 03/06/2022 - Sunday Rig Start Date End Date 2/8/22 3/22/22 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 Daily Operations: 03/08/2022 - Tuesday YellowJacket E-line arrive on location. Conduct JSA and approve PTW. MIRU. MU 2-7/8" perf guns with switch to shoot different zones. MU lubricator and PT 250 psi low / 3000 psi high. Open well and RIH with 8' and 14' x 2-7/8" perf guns with switches. GR/CCL to top shot 1st gun = 24'. GR/CCL to top shot 2nd gun = 8.5'. Send correlation data to REO/GEO. On depth. Perf UB7A 5215-5223'. Tubing pressure = 857 psi. Pressure = 858 psi after shooting. Perf UB7 5170-5184'. Tubing pressure = 859 psi. Pressure = 860 psi after shooting. POOH. Confirm all shots fired. Gun is wet. RIH with 13' x 2-7/8" gun. GR/CCL to top shot = 10.5'. Send correlation data to RE/GEO. Confirm on depth. Perforate UB 5B 5128-5141'. Initial press = 858 psi. 5 min = 857 psi. 10 min = 856 psi. 15 min = 856 psi. Shots fired. Gun is dry. MU & RIH with 11' and 5' x 2-7/8" perf guns with switches. Perf UB5 5055-5060'. Tubing pressures not obtained. Perf UB-5A 5077-5088'. Tubing pressure = 574 psi, 5 min = 571 psi, 10 min = 565 psi, 15 min = 562 psi. shots fired. Gun has small amount of water in bull plug. RDMO. Rig Start Date End Date 2/8/22 3/22/22 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 Daily Operations: Yellowjacket meet at KGF, PJSM and sign permit. On location, rig up on well. MU GPT and 4-1/2" CIBP. CCL to mid-element is 15'. Wait on man-lift. Pressure test to 250 psi / 3000 psi. Open well and RIH. Logging with GPT. Found fluid level at 2790'. Cool down N2 pump and pressure test N2 hardline 250 psi / 3000 psi. Begin pumping N2 at 1000 scfm. Pressure up WHP to 1800 psi. RIH to find fluid level, fluid level @4650'. Pump additional N2, fluid level @ 4920'. Pump additional N2, fluid level below set depth of 5,045'. 771 gallons N2 pumped. Set CIBP @ 5045'. POOH. Lay down GPT and setting tool. Check fire, MU 10' and 7' 2-7/8" guns. 20' CCL to top shot of 7' gun and 8.5' CCL to top shot of 10' gun. Open well and RIH. Pull correlation log from 4920' to 4645'. Send to town, on depth. Shoot UB1 Lower from 4,819' to 4,826'. Pressure data: Initial - 501 psi. 5 min - 502 psi. 10 min - 504 psi. 15 min -507 psi. Shoot the UB 1 X from 4,735' to 4,745'. Did not see good indication of fire. Pressure data: POOH. 7' gun - all shots fired, gun was dry. 10' gun did not fire. Check fire, MU 10' 2-7/8" gun. 9.5' CCL to top shot. RIH. Pull correlation log from 4,870' to 4,645'. Send to town, Shoot the UB 1 X from 4,735' to 4,745'. Good indication of fire. POOH. Pressure data: Initial - 522 psi. 5 min - 524 psi. 10 min - 523 psi. 15 min - 522 psi. Lay down 10' gun. All shots fired, gun was dry. Install tree cap. RDMO. 03/17/2022 - Thursday Rig Start Date End Date 2/8/22 3/22/22 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 Daily Operations: 03/22/2022 - Tuesday Given no flow from adperfs, and no IA pressure build, the final MIT-IA was not performed. Well never sustained flow. 03/20/2022 - Sunday Yellowjacket at KGF office and fill out permit. At location, PJSM. Rig up on well. Check fire. MU 2 - 10' 2-7/8" carrier guns. Stab on well. PT 250 psi / 3000 psi. Good PT. CCL to top shots, 11' to gun #2, 22.5' to gun #1. WHP - 53 psi. RIH. Found fluid level at 2246'. Pull correlation log from 5010' to 4700'. Log sent to town, on depth. Shoot the UB4 from 4,941' to 4,951'. Good indication of fire.;Pressure data: Initial - 58 psi 5 min - 58 psi 10 min - 59 psi 15 min - 60 psi Shoot the UB3 from 4,879' to 4,889'. Good indication of fire. Pressure data: Initial - 60 psi 5 min - 62 psi 10 min - 62 psi 15 min - 63 psi POOH. Lay down guns. All shots fired. Gun was wet. Tree cap on. RDMO. Updated by DMA 03-22-22 SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PBTD = 5,755’ MD / 5,710’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4"Surf. Csg 45.5 L-80 Buttress 9.95”Surf 1,511’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2"Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth (MD)ID Item 1 18’4.276”Tubing Hanger 2 5,045’CIBP 3 5,566’4.276”10 ft Swell Packer (Water Swell) 4 5,780’CIBP with 25’ cement: ToC = 5755’ MD (2/9/22) 5 6,206’3.25”Permanent Owen X-span patch from 6206’ – 6243’ MD (11/10/21) 6 6,294’3.25”Permanent Owen X-span patch from 6294’ – 6309’ MD (11/8/21) 7 8,970’Expandable plug with 25’ cement: ToC = 8945’ MD (2/8/22) 8 9,420’3.958”CIBP set on 8/25/17 9 9,455’3.958”CIBP Set on 8/17/17 10 9,500’3.958”CIBP Set on 8/1/17 11 9,540’3.958”CIBP Set on 7/15/17 12 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 3 4 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’9 8 10 11 12 D-3B D-2 D-1 LB3 LB3B LB4C LB1B LB1C 5 6 7-5/8” TOC @2,500’ MB 6 7 Logged ToC in IA: 3115’MD 3/7/22 See Punches : OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job. 4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2” 6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6044’. Intermittent bands of cement to 5,200’ MD. Solid cement band from 5,448’ to 5,562’ above Swellable packer. 4-1/2”7-5/8” annulus: 51 bbls 15.3# class G cement @ 3 bpm. CBL solid cement at 3,115’. PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments UB1X 4,735’4,745’4,704’4,714’10 Beluga/Up Ty 3/17/22 Open UB1 4,819’4,826’4,787’4,794’7 Beluga/Up Ty 3/17/22 Open N/A 4,879’4,882’4,846’4,849’3 N/A 2/18/22 Punches UB3 4,879’4,889’4,846’4,856’10 Beluga/Up Ty 3/20/22 Open UB4 4,941’4,951’4,907’4,917’10 Beluga/Up Ty 3/20/22 Open N/A 5,055’5,058’5,020’5,023’3 N/A 2/18/22 Punches UB5 5,055’5,060’5,020’5,025’5 Beluga/Up Ty 3/8/22 Plugged (3/17/22) UB5A 5,077’5,088’5,042’5,052’11 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,088’5,091’5,052’5,055’3 N/A 2/18/22 Punches N/A 5,119’5,129’5,083’5,093’10 N/A 2/16/22 Punches UB5B 5,128’5,141’5,092’5,105’13 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,168’5,173’5,131’5,136’5 N/A 2/15/22 Punches UB7 5,170’5,184’5,133’5,147’14 Beluga/Up Ty 3/8/22 Plugged (3/17/22) N/A 5,184’5,187’5,147’5,150’3 N/A 2/15/22 Punches UB7A 5,215’5,223’5,178’5,185’8 Beluga/Up Ty 3/8/22 Plugged (3/17/22) PERFORATION DETAIL (ISOLATED PERFS) on Following Page UB 2 Updated by DMA 03-22-22 SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PERFORATION DETAIL (ISOLATED PERFS) Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments MB 6 Mid 1 5,810’ 5,818' 5,764’ 5,772' 8’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) MB 6 Mid 2 5,836' 5,846' 5,790 5,800' 10’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) LB1B 6,210’ 6,240’ 6,159’ 6,189’ 30' Blga/Upr Ty 9/27/21 Patched 11/10/21 LB1C 6,299’ 6,307’ 6,246’ 6,254’ 8' Blga/Upr Ty 9/27/21 Patched 11/8/21 LB3 6,707’ 6,726’ 6,650’ 6,669’ 19’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB3B 6,754’ 6,771’ 6,697’ 6,713’ 17’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB4C 7,007 7,018’ 6,947’ 6,957’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) 7,024’ 7,035’ 6,963’ 6,974’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) D-1 8,856’ 8,876’ 8,773’ 8,793’ 20’ Blga/Upr Ty 7/29/21 Plugged (2/9/22) D-2 8,983’ 9,036’ 8,899’ 8,951’ 53’ Ty Gas Pool #1 1/21/20 Plugged (2/8/22) D-3B 9,274’ 9,305’ 9,186’ 9,216’ 31’ Ty Gas Pool #1 8/25/17 Plugged (2/8/22) 9,313’ 9,323’ 9,224’ 9,234’ 10‘ Ty Gas Pool #1 7/8/21 Plugged (2/8/22) D-4A 9,431 9,445' 9,340’ 9,354’ 14’ Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’ 9,476’ 9,370’ 9,385’ 15’ Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’ 9,535’ 9,419’ 9,443’ 24’ Ty Gas Pool #1 7/17/17 Plugged 9,546’ 9,569’ 9,454’ 9,476’ 23’ Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600' 9,502’ 9,507’ 5’ Ty Gas Pool #1 6/12/17 Plugged 9,600 9,620' 9,507’ 9,526’ 25’ Ty Gas Pool #1 6/9/17 Plugged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Ă͘ZĞŐƵůĂƚŝŽŶƐĐĂůůĨŽƌƉůƵŐƚŽďĞƐĞƚǁŝƚŚŝŶϱϬ͛ŽĨ^ƚĞƌůŝŶŐ'ĂƐWŽŽůϰƉĞƌĨƐ;Εϯ͕ϴϮϴ͛ DͿ ϮϮ͘Z/,ĂŶĚĚƵŵƉďĂŝůϮϱ͛ŽĨĐĞŵĞŶƚŽŶƚŽƉŽĨƉůƵŐ;ĞƐƚdŽцϯ͕ϴϬϯ͛DͿ Ϯϯ͘Z/,ĂŶĚƉĞƌĨŽƌĂƚĞ<ĞŶĂŝ^ƚĞƌůŝŶŐ'ĂƐWŽŽůϯƐĂŶĚƐ 7DJ &,%3 WR FRQILUP WKDW LW LV VHW EMP 7DJ 7R& WR FRQILUP GHSWK EMP tĞůů͗<hϭϭͲϬϳǆ ĂƚĞ͗ϯͬϮϴͬϮϮ WŽŽů ^ĂŶĚ WĞƌĨŽƌĂƚŝŽŶ dŽƉ;DͿ WĞƌĨŽƌĂƚŝŽŶ ŽƚƚŽŵ;DͿ dŽƚĂů&ŽŽƚĂŐĞ ;DͿ ^ƚĞƌůŝŶŐϯWϯͺϭϬͺhцϯ͕ϲϱϰ͛цϯ͕ϲϳϯ͛цϭϵ ^ƚĞƌůŝŶŐϯWϯͺϭϬͺ>цϯ͕ϲϴϰ͛цϯ͕ϳϬϭцϭϳ WŽƐƚͲWĞƌĨD/dͲ/ Ϯϰ͘WĞƌĨŽƌŵD/dͲ/ƚŽϮϬϬϬƉƐŝŽŶĐĞũŽďŝƐĐŽŵƉůĞƚĞĂŶĚǁĞůůŚĂƐďĞĞŶďƌŽƵŐŚƚŽŶůŝŶĞǁŝƚŚŝŶϯϬĚĂǇƐ͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƵƌƌĞŶƚƐĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘^ƚĂŶĚĂƌĚtĞůůƉƌŽĐĞĚƵƌĞʹEϮKƉĞƌĂƚŝŽŶƐ Ϯϰ͘WĞƌĨŽƌŵD/dͲ/ƚŽϮϬϬϬƉƐŝŽŶĐĞũŽďŝƐĐŽŵƉůĞƚĞĂŶĚǁĞůůŚĂƐďĞĞŶďƌŽƵŐŚƚŽŶůŝŶĞǁŝƚŚŝŶϯϬĚĂǇƐ͘ hƉĚĂƚĞĚďǇD ϬϯͲϮϮͲϮϮ ^,Dd/ tĞůů͗<h ϭϭͲϬϳy Wd͗ϮϭϳͲϬϰϭ W/͗ϱϬͲϭϯϯͲϮϬϲϲϮͲϬϬͲϬϬ Wdс ϱ͕ϳϱϱ͛ D ͬ ϱ͕ϳϭϬ͛ds dсϵ͕ϳϵϵ͛ Dͬϵ͕ϳϬϮ͛ ds <сϭϴ͛^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘/dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϭϬϵ yͲϱϲ tĞůĚ ϭϱ͟^ƵƌĨ ϭϮϬΖ ϭϬͲϯͬϰΗ ^ƵƌĨ͘ƐŐ ϰϱ͘ϱ >ͲϴϬ ƵƚƚƌĞƐƐ ϵ͘ϵϱ͟^ƵƌĨ ϭ͕ϱϭϭ͛ ϳͲϱͬϴΗ /ŶƚĞƌŵĞĚŝĂƚĞϮϵ͘ϳ >ͲϴϬ dϲ͘ϴϳϱΗ ^ƵƌĨ ϲ͕ϬϵϬ͛ ϰͲϭͬϮΗ WƌŽĚƵĐƚŝŽŶ ϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟^ƵƌĨ ϵ͕ϳϵϵ͛ ϭϭϲ͟ ϭϬͲϯͬϰ͟ ͲϭͬϮ͟ :t>Zzd/> EŽ͘ĞƉƚŚ ;DͿ //ƚĞŵ ϭ ϭϴ͛ϰ͘Ϯϳϲ͟dƵďŝŶŐ,ĂŶŐĞƌ Ϯ ϱ͕Ϭϰϱ͛/W ϯ ϱ͕ϱϲϲ͛ϰ͘Ϯϳϲ͟ϭϬ Ĩƚ ^ǁĞůůWĂĐŬĞƌ ;tĂƚĞƌ^ǁĞůůͿ ϰ ϱ͕ϳϴϬ͛/W ǁŝƚŚϮϱ͛ ĐĞŵĞŶƚ͗dŽсϱϳϱϱ͛ D ;ϮͬϵͬϮϮͿ ϱ ϲ͕ϮϬϲ͛ϯ͘Ϯϱ͟WĞƌŵĂŶĞŶƚKǁĞŶyͲƐƉĂŶƉĂƚĐŚ ĨƌŽŵϲϮϬϲ͛ ʹ ϲϮϰϯ͛ D ;ϭϭͬϭϬͬϮϭͿ ϲ ϲ͕Ϯϵϰ͛ϯ͘Ϯϱ͟WĞƌŵĂŶĞŶƚKǁĞŶyͲƐƉĂŶƉĂƚĐŚ ĨƌŽŵϲϮϵϰ͛ ʹ ϲϯϬϵ͛ D ;ϭϭͬϴͬϮϭͿ ϳ ϴ͕ϵϳϬ͛ǆƉĂŶĚĂďůĞ ƉůƵŐǁŝƚŚϮϱ͛ ĐĞŵĞŶƚ͗dŽсϴϵϰϱ͛ D ;ϮͬϴͬϮϮͿ ϴ ϵ͕ϰϮϬ͛ϯ͘ϵϱϴ͟/WƐĞƚŽŶϴͬϮϱͬϭϳ ϵ ϵ͕ϰϱϱ͛ϯ͘ϵϱϴ͟/W^ĞƚŽŶϴͬϭϳͬϭϳ ϭϬ ϵ͕ϱϬϬ͛ϯ͘ϵϱϴ͟/W^ĞƚŽŶϴͬϭͬϭϳ ϭϭ ϵ͕ϱϰϬ͛ϯ͘ϵϱϴ͟/W^ĞƚŽŶϳͬϭϱͬϭϳ ϭϮ ϵ͕ϱϵϭ͛ϯ͘ϵϱϴ͟/W ^Ğƚǁͬ ϭϬ͛ĐĞŵĞŶƚ;ƚĂŐϵ͕ϱϳϭͿŽŶϲͬϮϭͬϭϳ ϳͲϱͬϴ͟ ϯ ϰ ZͲ ϳ͕ϯϵϭ͛ ZͲ ϳ͕ϵϮϰ͛ ZͲ ϴ͕ϵϭϰ͛ ZͲ ϵ͕ϰϬϱ͛ϵ ϴ ϭϬ ϭϭ ϭϮ Ͳϯ ͲϮ Ͳϭ >ϯ >ϯ >ϰ >ϭ >ϭ ϱ ϲ ϳͲϱͬϴ͟ dK ΛϮ͕ϱϬϬ͛ D ϲ ϳ /RJJHG7R& LQ ,$¶0' 6HH 3XQFKHV KWE,K>ͬDEdd/> ϭϬͲϯͬϰ͟ϭϯͲϭͬϮ͟ ,ŽůĞ͗ϭϰϭďďůƐϭϮηĐůĂƐƐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϲϭďďůƐŽĨϭϱ͘ϰηůĂƐƐƚĂŝů ĐĞŵĞŶƚ͘ &ƵůůƌĞƚƵƌŶƐƚŚƌŽƵŐŚŽƵƚ ũŽď͘ϳϴďďůƐĐĞŵĞŶƚďĂĐŬ ƚŽ^ƵƌĨĂĐĞ ϳͲϱͬϴΗ ϵͲϳͬϴ͟ ,ŽůĞ͗ϭϯϴďďůƐϭϮ͘ϱηĐůĂƐƐ' ůĞĂĚ ĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϯϴďďůƐŽĨϭϱ͘ϴηůĂƐƐ ' ƚĂŝů ĐĞŵĞŶƚ͘ϮϱďďůƐ ůŽƐƚƚŚƌŽƵŐŚŽƵƚũŽď͘ϰͬϯϬͬϭϳ > ;<>Ϳ ƌĞƉŽƌƚĞĚĂdŽŽĨϮϱϬϬ͛ D͘ ϰͲϭͬϮ͟ ϲͲϯͬϰ͟,ŽůĞ͗ϭϭϰďďůƐϭϱ͘ϯη ĐůĂƐƐ ĐĞŵĞŶƚ͘EŽ ůŽƐƐĞƐ ƚŚƌŽƵŐŚŽƵƚũŽď͘ ϱͬϭϲͬϭϳ ZĂĚŝĂů > ƐŚŽǁƐ ƐŽůŝĚ ĐĞŵĞŶƚƵƉƚŽϲϬϰϰ͛͘/ŶƚĞƌŵŝƚƚĞŶƚ ďĂŶĚƐŽĨĐĞŵĞŶƚ ƚŽϱ͕ϮϬϬ͛D͘ ^ŽůŝĚĐĞŵĞŶƚ ďĂŶĚĨƌŽŵϱ͕ϰϰϴ͛ ƚŽϱ͕ϱϲϮ͛ ĂďŽǀĞ^ǁĞůůĂďůĞƉĂĐŬĞƌ͘ ϰͲϭͬϮ͟ϳͲϱͬϴ͟ ĂŶŶƵůƵƐ͗ϱϭďďůƐϭϱ͘ϯηĐůĂƐƐ'ĐĞŵĞŶƚ ΛϯďƉŵ͘>ƐŽůŝĚĐĞŵĞŶƚĂƚϯ͕ϭϭϱ͛͘ WZ&KZd/KEd/> ŽŶĞ dŽƉDƚŵ DdŽƉdsƚŵdsŵƚ WŽŽů ĂƚĞ ŽŵŵĞŶƚƐ hϭy ϰ͕ϳϯϱ͛ϰ͕ϳϰϱ͛ϰ͕ϳϬϰ͛ϰ͕ϳϭϰ͛ϭϬ ĞůƵŐĂͬhƉdǇ ϯͬϭϳͬϮϮ KƉĞŶ hϭ ϰ͕ϴϭϵ͛ϰ͕ϴϮϲ͛ϰ͕ϳϴϳ͛ϰ͕ϳϵϰ͛ϳ ĞůƵŐĂͬhƉdǇ ϯͬϭϳͬϮϮ KƉĞŶ Eͬϰ͕ϴϳϵ͛ϰ͕ϴϴϮ͛ϰ͕ϴϰϲ͛ϰ͕ϴϰϵ͛ϯ EͬϮͬϭϴͬϮϮ WƵŶĐŚĞƐ hϯ ϰ͕ϴϳϵ͛ϰ͕ϴϴϵ͛ϰ͕ϴϰϲ͛ϰ͕ϴϱϲ͛ϭϬ ĞůƵŐĂͬhƉdǇ ϯͬϮϬͬϮϮ KƉĞŶ hϰ ϰ͕ϵϰϭ͛ϰ͕ϵϱϭ͛ϰ͕ϵϬϳ͛ϰ͕ϵϭϳ͛ϭϬ ĞůƵŐĂͬhƉdǇ ϯͬϮϬͬϮϮ KƉĞŶ Eͬϱ͕Ϭϱϱ͛ϱ͕Ϭϱϴ͛ϱ͕ϬϮϬ͛ϱ͕ϬϮϯ͛ϯ EͬϮͬϭϴͬϮϮ WƵŶĐŚĞƐ hϱ ϱ͕Ϭϱϱ͛ϱ͕ϬϲϬ͛ϱ͕ϬϮϬ͛ϱ͕ϬϮϱ͛ϱ ĞůƵŐĂͬhƉdǇ ϯͬϴͬϮϮ WůƵŐŐĞĚ ;ϯͬϭϳͬϮϮͿ hϱϱ͕Ϭϳϳ͛ϱ͕Ϭϴϴ͛ϱ͕ϬϰϮ͛ϱ͕ϬϱϮ͛ϭϭ ĞůƵŐĂͬhƉdǇ ϯͬϴͬϮϮ WůƵŐŐĞĚ ;ϯͬϭϳͬϮϮͿ Eͬϱ͕Ϭϴϴ͛ϱ͕Ϭϵϭ͛ϱ͕ϬϱϮ͛ϱ͕Ϭϱϱ͛ϯ EͬϮͬϭϴͬϮϮ WƵŶĐŚĞƐ Eͬϱ͕ϭϭϵ͛ϱ͕ϭϮϵ͛ϱ͕Ϭϴϯ͛ϱ͕Ϭϵϯ͛ϭϬ EͬϮͬϭϲͬϮϮ WƵŶĐŚĞƐ hϱϱ͕ϭϮϴ͛ϱ͕ϭϰϭ͛ϱ͕ϬϵϮ͛ϱ͕ϭϬϱ͛ϭϯ ĞůƵŐĂͬhƉdǇ ϯͬϴͬϮϮ WůƵŐŐĞĚ ;ϯͬϭϳͬϮϮͿ Eͬϱ͕ϭϲϴ͛ϱ͕ϭϳϯ͛ϱ͕ϭϯϭ͛ϱ͕ϭϯϲ͛ϱ EͬϮͬϭϱͬϮϮ WƵŶĐŚĞƐ hϳ ϱ͕ϭϳϬ͛ϱ͕ϭϴϰ͛ϱ͕ϭϯϯ͛ϱ͕ϭϰϳ͛ϭϰ ĞůƵŐĂͬhƉdǇ ϯͬϴͬϮϮ WůƵŐŐĞĚ ;ϯͬϭϳͬϮϮͿ Eͬϱ͕ϭϴϰ͛ϱ͕ϭϴϳ͛ϱ͕ϭϰϳ͛ϱ͕ϭϱϬ͛ϯ EͬϮͬϭϱͬϮϮ WƵŶĐŚĞƐ hϳϱ͕Ϯϭϱ͛ϱ͕ϮϮϯ͛ϱ͕ϭϳϴ͛ϱ͕ϭϴϱ͛ϴ ĞůƵŐĂͬhƉdǇ ϯͬϴͬϮϮ WůƵŐŐĞĚ ;ϯͬϭϳͬϮϮͿ WZ&KZd/KEd/> ;/^K>dWZ&^Ϳ ŽŶ&ŽůůŽǁŝŶŐWĂŐĞ h Ϯ hƉĚĂƚĞĚďǇDϬϯͲϮϮͲϮϮ ^,Dd/ tĞůů͗<hϭϭͲϬϳy Wd͗ϮϭϳͲϬϰϭ W/͗ϱϬͲϭϯϯͲϮϬϲϲϮͲϬϬͲϬϬ WZ&KZd/KEd/>;/^K>dWZ&^Ϳ ŽŶĞdŽƉDƚŵDdŽƉdsƚŵdsŵƚWŽŽůĂƚĞŽŵŵĞŶƚƐ DϲDŝĚϭϱ͕ϴϭϬ͛ϱ͕ϴϭϴΖϱ͕ϳϲϰ͛ϱ͕ϳϳϮΖϴ͛ůŐĂͬhƉƌdǇϭͬϭϯͬϮϮWůƵŐŐĞĚ;ϮͬϵͬϮϮͿ DϲDŝĚϮϱ͕ϴϯϲΖϱ͕ϴϰϲΖϱ͕ϳϵϬϱ͕ϴϬϬΖϭϬ͛ůŐĂͬhƉƌdǇϭͬϭϯͬϮϮWůƵŐŐĞĚ;ϮͬϵͬϮϮͿ >ϭϲ͕ϮϭϬ͛ϲ͕ϮϰϬ͛ϲ͕ϭϱϵ͛ϲ͕ϭϴϵ͛ϯϬΖůŐĂͬhƉƌdǇϵͬϮϳͬϮϭWĂƚĐŚĞĚϭϭͬϭϬͬϮϭ >ϭϲ͕Ϯϵϵ͛ϲ͕ϯϬϳ͛ϲ͕Ϯϰϲ͛ϲ͕Ϯϱϰ͛ϴΖůŐĂͬhƉƌdǇϵͬϮϳͬϮϭWĂƚĐŚĞĚϭϭͬϴͬϮϭ >ϯϲ͕ϳϬϳ͛ϲ͕ϳϮϲ͛ϲ͕ϲϱϬ͛ϲ͕ϲϲϵ͛ϭϵ͛ůŐĂͬhƉƌdǇϴͬϮϱͬϮϭWůƵŐŐĞĚ;ϮͬϵͬϮϮͿ >ϯϲ͕ϳϱϰ͛ϲ͕ϳϳϭ͛ϲ͕ϲϵϳ͛ϲ͕ϳϭϯ͛ϭϳ͛ůŐĂͬhƉƌdǇϴͬϮϱͬϮϭWůƵŐŐĞĚ;ϮͬϵͬϮϮͿ >ϰϳ͕ϬϬϳϳ͕Ϭϭϴ͛ϲ͕ϵϰϳ͛ϲ͕ϵϱϳ͛ϭϭ͛ůŐĂͬhƉƌdǇϴͬϮϱͬϮϭWůƵŐŐĞĚ;ϮͬϵͬϮϮͿ ϳ͕ϬϮϰ͛ϳ͕Ϭϯϱ͛ϲ͕ϵϲϯ͛ϲ͕ϵϳϰ͛ϭϭ͛ůŐĂͬhƉƌdǇϴͬϮϱͬϮϭWůƵŐŐĞĚ;ϮͬϵͬϮϮͿ Ͳϭϴ͕ϴϱϲ͛ϴ͕ϴϳϲ͛ϴ͕ϳϳϯ͛ϴ͕ϳϵϯ͛ϮϬ͛ůŐĂͬhƉƌdǇϳͬϮϵͬϮϭWůƵŐŐĞĚ;ϮͬϵͬϮϮͿ ͲϮϴ͕ϵϴϯ͛ϵ͕Ϭϯϲ͛ϴ͕ϴϵϵ͛ϴ͕ϵϱϭ͛ϱϯ͛dǇ'ĂƐWŽŽůηϭϭͬϮϭͬϮϬWůƵŐŐĞĚ;ϮͬϴͬϮϮͿ Ͳϯϵ͕Ϯϳϰ͛ϵ͕ϯϬϱ͛ϵ͕ϭϴϲ͛ϵ͕Ϯϭϲ͛ϯϭ͛dǇ'ĂƐWŽŽůηϭϴͬϮϱͬϭϳWůƵŐŐĞĚ;ϮͬϴͬϮϮͿ ϵ͕ϯϭϯ͛ϵ͕ϯϮϯ͛ϵ͕ϮϮϰ͛ϵ͕Ϯϯϰ͛ϭϬ͚dǇ'ĂƐWŽŽůηϭϳͬϴͬϮϭWůƵŐŐĞĚ;ϮͬϴͬϮϮͿ Ͳϰϵ͕ϰϯϭϵ͕ϰϰϱΖϵ͕ϯϰϬ͛ϵ͕ϯϱϰ͛ϭϰ͛dǇ'ĂƐWŽŽůηϭϴͬϭϴͬϭϳWůƵŐŐĞĚ Ͳϰϵ͕ϰϲϭ͛ϵ͕ϰϳϲ͛ϵ͕ϯϳϬ͛ϵ͕ϯϴϱ͛ϭϱ͛dǇ'ĂƐWŽŽůηϭϴͬϭͬϭϳWůƵŐŐĞĚ Ͳϰϵ͕ϱϭϭ͛ϵ͕ϱϯϱ͛ϵ͕ϰϭϵ͛ϵ͕ϰϰϯ͛Ϯϰ͛dǇ'ĂƐWŽŽůηϭϳͬϭϳͬϭϳWůƵŐŐĞĚ ϵ͕ϱϰϲ͛ϵ͕ϱϲϵ͛ϵ͕ϰϱϰ͛ϵ͕ϰϳϲ͛Ϯϯ͛dǇ'ĂƐWŽŽůηϭϲͬϮϯͬϭϳWůƵŐŐĞĚ Ͳϱϵ͕ϱϵϱϵ͕ϲϬϬΖϵ͕ϱϬϮ͛ϵ͕ϱϬϳ͛ϱ͛dǇ'ĂƐWŽŽůηϭϲͬϭϮͬϭϳWůƵŐŐĞĚ ϵ͕ϲϬϬϵ͕ϲϮϬΖϵ͕ϱϬϳ͛ϵ͕ϱϮϲ͛Ϯϱ͛dǇ'ĂƐWŽŽůηϭϲͬϵͬϭϳWůƵŐŐĞĚ hƉĚĂƚĞĚďǇ, ϬϯͲϮϴͲϮϮ WZKWK^ tĞůů͗<h ϭϭͲϬϳy Wd͗ϮϭϳͲϬϰϭ W/͗ϱϬͲϭϯϯͲϮϬϲϲϮͲϬϬͲϬϬ Wdс ϱ͕ϳϱϱ͛ D ͬ ϱ͕ϳϭϬ͛ds dсϵ͕ϳϵϵ͛ Dͬϵ͕ϳϬϮ͛ ds <сϭϴ͛^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘/dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϭϬϵ yͲϱϲ tĞůĚ ϭϱ͟^ƵƌĨ ϭϮϬΖ ϭϬͲϯͬϰΗ ^ƵƌĨ͘ƐŐ ϰϱ͘ϱ >ͲϴϬ ƵƚƚƌĞƐƐ ϵ͘ϵϱ͟^ƵƌĨ ϭ͕ϱϭϭ͛ ϳͲϱͬϴΗ /ŶƚĞƌŵĞĚŝĂƚĞϮϵ͘ϳ >ͲϴϬ dϲ͘ϴϳϱΗ ^ƵƌĨ ϲ͕ϬϵϬ͛ ϰͲϭͬϮΗ WƌŽĚƵĐƚŝŽŶϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟^ƵƌĨ ϵ͕ϳϵϵ͛ ϭϭϲ͟ ϭϬͲϯͬϰ͟ ͲϭͬϮ͟ :t>Zzd/> EŽ͘ĞƉƚŚ ;DͿ //ƚĞŵ ϭ ϭϴ͛ϰ͘Ϯϳϲ͟dƵďŝŶŐ,ĂŶŐĞƌ цϰ͕ϳϬϬ͛/WǁŝƚŚϮϱ͛ ĐĞŵĞŶƚ͗dŽсϰ͕ϲϳϱ͛ D Ϯ ϱ͕Ϭϰϱ͛/W ϯ ϱ͕ϱϲϲ͛ϰ͘Ϯϳϲ͟ϭϬ Ĩƚ ^ǁĞůůWĂĐŬĞƌ ;tĂƚĞƌ^ǁĞůůͿ ϰ ϱ͕ϳϴϬ͛/W ǁŝƚŚϮϱ͛ ĐĞŵĞŶƚ͗dŽсϱϳϱϱ͛ D ;ϮͬϵͬϮϮͿ ϱ ϲ͕ϮϬϲ͛ϯ͘Ϯϱ͟WĞƌŵĂŶĞŶƚKǁĞŶyͲƐƉĂŶƉĂƚĐŚ ĨƌŽŵϲϮϬϲ͛ ʹ ϲϮϰϯ͛ D ;ϭϭͬϭϬͬϮϭͿ ϲ ϲ͕Ϯϵϰ͛ϯ͘Ϯϱ͟WĞƌŵĂŶĞŶƚKǁĞŶyͲƐƉĂŶƉĂƚĐŚ ĨƌŽŵϲϮϵϰ͛ ʹ ϲϯϬϵ͛ D ;ϭϭͬϴͬϮϭͿ ϳ ϴ͕ϵϳϬ͛ǆƉĂŶĚĂďůĞ ƉůƵŐǁŝƚŚϮϱ͛ ĐĞŵĞŶƚ͗dŽсϴϵϰϱ͛ D ;ϮͬϴͬϮϮͿ ϴ ϵ͕ϰϮϬ͛ϯ͘ϵϱϴ͟/WƐĞƚŽŶϴͬϮϱͬϭϳ ϵ ϵ͕ϰϱϱ͛ϯ͘ϵϱϴ͟/W^ĞƚŽŶϴͬϭϳͬϭϳ ϭϬ ϵ͕ϱϬϬ͛ϯ͘ϵϱϴ͟/W^ĞƚŽŶϴͬϭͬϭϳ ϭϭ ϵ͕ϱϰϬ͛ϯ͘ϵϱϴ͟/W^ĞƚŽŶϳͬϭϱͬϭϳ ͬͬͬ ϳͲϱͬϴ͟ ϯ ϰ ZͲ ϳ͕ϯϵϭ͛ ZͲ ϳ͕ϵϮϰ͛ ZͲ ϴ͕ϵϭϰ͛ ZͲ ϵ͕ϰϬϱ͛ϵ ϴ ϭϬ ϭϭ ϭϮ Ͳϯ ͲϮ Ͳϭ >ϯ >ϯ >ϰ >ϭ >ϭ ϱ ϲ ϳͲϱͬϴ͟ dK ΛϮ͕ϱϬϬ͛ D ϲ ϳ /RJJHG7R& LQ ,$¶0' 6HH 3XQFKHV KWE,K>ͬDEdd/> ϭϬͲϯͬϰ͟ϭϯͲϭͬϮ͟ ,ŽůĞ͗ϭϰϭďďůƐϭϮηĐůĂƐƐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϲϭďďůƐŽĨϭϱ͘ϰηůĂƐƐƚĂŝů ĐĞŵĞŶƚ͘ &ƵůůƌĞƚƵƌŶƐƚŚƌŽƵŐŚŽƵƚ ũŽď͘ϳϴďďůƐĐĞŵĞŶƚďĂĐŬ ƚŽ^ƵƌĨĂĐĞ ϳͲϱͬϴΗ ϵͲϳͬϴ͟ ,ŽůĞ͗ϭϯϴďďůƐϭϮ͘ϱηĐůĂƐƐ' ůĞĂĚ ĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϯϴďďůƐŽĨϭϱ͘ϴηůĂƐƐ ' ƚĂŝů ĐĞŵĞŶƚ͘ϮϱďďůƐ ůŽƐƚƚŚƌŽƵŐŚŽƵƚũŽď͘ϰͬϯϬͬϭϳ > ;<>Ϳ ƌĞƉŽƌƚĞĚĂdŽŽĨϮϱϬϬ͛ D͘ ϰͲϭͬϮ͟ ϲͲϯͬϰ͟,ŽůĞ͗ϭϭϰďďůƐϭϱ͘ϯη ĐůĂƐƐ ĐĞŵĞŶƚ͘EŽ ůŽƐƐĞƐ ƚŚƌŽƵŐŚŽƵƚũŽď͘ ϱͬϭϲͬϭϳ ZĂĚŝĂů > ƐŚŽǁƐ ƐŽůŝĚ ĐĞŵĞŶƚƵƉƚŽϲϬϰϰ͛͘/ŶƚĞƌŵŝƚƚĞŶƚ ďĂŶĚƐŽĨĐĞŵĞŶƚ ƚŽϱ͕ϮϬϬ͛D͘ ^ŽůŝĚĐĞŵĞŶƚ ďĂŶĚĨƌŽŵϱ͕ϰϰϴ͛ ƚŽϱ͕ϱϲϮ͛ ĂďŽǀĞ^ǁĞůůĂďůĞƉĂĐŬĞƌ͘ ϰͲϭͬϮ͟ϳͲϱͬϴ͟ ĂŶŶƵůƵƐ͗ϱϭďďůƐϭϱ͘ϯηĐůĂƐƐ'ĐĞŵĞŶƚ ΛϯďƉŵ͘>ƐŽůŝĚĐĞŵĞŶƚĂƚϯ͕ϭϭϱ͛͘ WZ&KZd/KEd/> ŽŶĞ dŽƉDƚŵ DdŽƉdsƚŵdsŵƚ WŽŽů ĂƚĞ ŽŵŵĞŶƚƐ WϯͺϭϬͺh цϯ͕ϲϱϰ͛цϯ͕ϲϳϯ͛цϯ͕ϲϯϲ͛цϯ͕ϲϱϱ͛цϭϵ ^ƚĞƌůŝŶŐϯ WƌŽƉŽƐĞĚ d WϯͺϭϬͺ>цϯ͕ϲϴϰ͛цϯ͕ϳϬϭ цϯ͕ϲϲϲ͛цϯ͕ϲϴϯ͛цϭϳ ^ƚĞƌůŝŶŐϯ WƌŽƉŽƐĞĚ d Wϰͺϭ цϯ͕ϴϮϴ͛цϯ͕ϴϯϲ͛цϯ͕ϴϬϵ͛цϯ͕ϴϭϳ͛цϴ ^ƚĞƌůŝŶŐϰ WƌŽƉŽƐĞĚ d WϰͺϮͺh цϯ͕ϴϴϰ͛цϯ͕ϴϴϵ͛цϯ͕ϴϲϰ͛цϯ͕ϴϲϵ͛цϱ ^ƚĞƌůŝŶŐϰ WƌŽƉŽƐĞĚ d WϰͺϮͺ>цϯ͕ϵϬϰ͛цϯ͕ϵϬϳ͛цϯ͕ϴϴϰ͛цϯ͕ϴϴϳ͛цϯ ^ƚĞƌůŝŶŐϰ WƌŽƉŽƐĞĚ d Wϱ͘Ϯͺϱ цϰ͕ϭϳϳ͛цϰ͕ϭϴϮ͛цϰ͕ϭϱϰ͛цϰ͕ϭϱϴ͛цϱ ^ƚĞƌůŝŶŐϱ͘Ϯ WƌŽƉŽƐĞĚ d hϭy ϰ͕ϳϯϱ͛ϰ͕ϳϰϱ͛ϰ͕ϳϬϰ͛ϰ͕ϳϭϰ͛ϭϬ ĞůƵŐĂͬhƉdǇ ϯͬϭϳͬϮϮ /ƐŽůĂƚĞĚ hϭ ϰ͕ϴϭϵ͛ϰ͕ϴϮϲ͛ϰ͕ϳϴϳ͛ϰ͕ϳϵϰ͛ϳ ĞůƵŐĂͬhƉdǇ ϯͬϭϳͬϮϮ /ƐŽůĂƚĞĚ Eͬϰ͕ϴϳϵ͛ϰ͕ϴϴϮ͛ϰ͕ϴϰϲ͛ϰ͕ϴϰϵ͛ϯ EͬϮͬϭϴͬϮϮ WƵŶĐŚĞƐ hϯ ϰ͕ϴϳϵ͛ϰ͕ϴϴϵ͛ϰ͕ϴϰϲ͛ϰ͕ϴϱϲ͛ϭϬ ĞůƵŐĂͬhƉdǇ ϯͬϮϬͬϮϮ /ƐŽůĂƚĞĚ hϰ ϰ͕ϵϰϭ͛ϰ͕ϵϱϭ͛ϰ͕ϵϬϳ͛ϰ͕ϵϭϳ͛ϭϬ ĞůƵŐĂͬhƉdǇ ϯͬϮϬͬϮϮ /ƐŽůĂƚĞĚ WZ&KZd/KEd/> ;/^K>dWZ&^Ϳ ŽŶ&ŽůůŽǁŝŶŐWĂŐĞ hϮ hƉĚĂƚĞĚďǇDϬϯͲϮϮͲϮϮ ^,Dd/ tĞůů͗<hϭϭͲϬϳy Wd͗ϮϭϳͲϬϰϭ W/͗ϱϬͲϭϯϯͲϮϬϲϲϮͲϬϬͲϬϬ WZ&KZd/KEd/>;/^K>dWZ&^Ϳ 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KŶĐĞǇŽƵŚĂǀĞĐŽŶĨŝƌŵĞĚůŝŶĞƐĂƌĞďůĞĚĚŽǁŶ͕ŶŽƚƌĂƉƉĞĚƉƌĞƐƐƵƌĞĞǆŝƐƚƐ͕ĂŶĚŶŽŶŝƚƌŽŐĞŶŚĂƐ ĂĐĐƵŵƵůĂƚĞĚďĞŐŝŶƌŝŐĚŽǁŶŽĨůŝŶĞƐĨƌŽŵƚŚĞEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚ͘ ϭϳ͘Ϳ &ŝŶĂůŝǌĞũŽďůŽŐĂŶĚĚŝƐĐƵƐƐŽƉĞƌĂƚŝŽŶƐǁŝƚŚtĞůůƐŝƚĞDĂŶĂŐĞƌ͘ŽĐƵŵĞŶƚĂŶǇůĞƐƐŽŶƐůĞĂƌŶĞĚ ĂŶĚĐŽŶĨŝƌŵĨŝŶĂůƌĂƚĞƐͬƉƌĞƐƐƵƌĞͬǀŽůƵŵĞƐŽĨƚŚĞũŽďĂŶĚƌĞŵĂŝŶŝŶŐŶŝƚƌŽŐĞŶŝŶƚŚĞƚƌĂŶƐƉŽƌƚ͘ ϭϴ͘Ϳ ZDKEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘ Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 03/24/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) PLUG PERF 03/16/2022 PERF-GPT 03/20/2022 217-041 T36427 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.03.29 09:46:02 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: PERF 03/08/2022 CBL 03/07/2022 Please include current contact information if different from above. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 03/03/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) Puncher 02/16/2022 Please include current contact information if different from above. 217-041 T36418 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.03.15 14:31:31 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 3/08/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) Plug Setting Record 2/08/2022 Plug Setting Record 2/09/2022 Tubing Punch Record 2/18/2022 Please include current contact information if different from above. 217-041 T36406 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.03.08 14:00:50 -09'00' From:McLellan, Bryan J (OGC) To:Ryan Rupert Cc:Rixse, Melvin G (OGC); Dan Marlowe; Donna Ambruz; Brad Gathman - (C) Subject:RE: [EXTERNAL] FW: KU 11-07X (PTD#217-041) Date:Tuesday, March 8, 2022 8:59:00 AM Ryan, The Cement looks good and I agree with your TOC assessment of 3115’ MD. You have approval to proceed with perforating per Sundry 322-037. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Tuesday, March 8, 2022 8:32 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Dan Marlowe <dmarlowe@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Subject: RE: [EXTERNAL] FW: KU 11-07X (PTD#217-041) Ryan Rupert 907-301-1736 -------- Original message -------- From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Date: 3/7/22 2:59 PM (GMT-09:00) To: "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov> Cc: "Rixse, Melvin G (OGC)" <melvin.rixse@alaska.gov>, Dan Marlowe <dmarlowe@hilcorp.com>, Donna Ambruz <dambruz@hilcorp.com>, "Brad Gathman - (C)" <Brad.Gathman@hilcorp.com> Subject: RE: [EXTERNAL] FW: KU 11-07X (PTD#217-041) Great timing! Shallowest punches ended up being 4879’ – 4882’ MD Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Ryan Rupert Sent: Monday, March 7, 2022 2:44 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: 'Rixse, Melvin G (OGC)' <melvin.rixse@alaska.gov>; Dan Marlowe <dmarlowe@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Brad Gathman - (C) <Brad.Gathman@hilcorp.com> Subject: RE: [EXTERNAL] FW: KU 11-07X (PTD#217-041) Bryan- This CBL was acquired this morning and qualitatively looks as expected from what I’ve heard. I’ll be sending it over this afternoon once the vendor gets it to me. Our aim is to start perforating tomorrow morning once we have your approval. Just a heads up. Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Thursday, February 17, 2022 5:00 PM To: Ryan Rupert <ryan.rupert@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] FW: KU 11-07X (PTD#217-041) Ryan, Hilcorp is approved to proceed as per your plan below. Hilcorp should try to obtain TxIA circulation as deep as possible. Hilcorp is not to approved to perforate any shallower than 4700’ MD without additional consultation with AOGCC. Mel Rixse 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. Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Thursday, February 17, 2022 3:22 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: KU 11-07X (PTD#217-041) Mel- Per our conversation, please see attached for approved sundry on KU 11-07X. The attached schematic is reflective of the well’s current condition. I have exhausted all sundried tubing punch intervals and still can not establish circulation from tubing to IA (see below, likely settled out mud back there in IA). Hilcorp is asking approval to continue uphole not to go above 4700’ MD (4693’ TVD) attempting punches and/or cuts to establish circulation. Although not penetrating formation, this depth limit would keep us all within the Beluga/Upper Tyonek Pool. We’ll attempt to punch as low as possible for maximum ultimate cement volume in the IA. Not sur how far uphole we’ll have to come. Please let me know if this is acceptable. I’d like to move EL back in tomorrow Fri 2/18 for additional punches, if that’s ok? 4-1/2” x 7-5/8” annulus has 20.5bbl 12ppg mud push Remainder is 11.2ppg drilling mud 3 tubing punches executed, no circulation yet: 2/16/22: Arrive on location. 3340 psi on 4.5" tubing. Hammer up pump lines and returns lines. Tubing 3340 psi. IA 130 psi, OA 250 psi. Open IA valve to return tank. Bleed off pressure. Open pump line to 4.5" production tubing. Online with fluid pump. Shut down pump at 4700 psi. No returns from IA. Monitor pressure. 5/10/15 no change and no flow to return tank. Call out AK E-line. Rig up AK E-line with 10' tubing punch . Stab on well. PT 250/3000 psi. RIH. Correlate to Halliburton CBL log 16 May 2017. CCL to top shot 10.2'. Pull into position and park CCL at 5108.8'. Online down tubing. 1238 psi SITP. IA open to return tank. shoot tubing punches from 5119'-5129'. Pressure dropped from 1238 psi to 1187 psi. No returns from AI. POOH to surface. E-line install night cap. Attempt to circulate well. Online down 4.5" tubing taking returns up IA. Pressure up to 4700 psi. No returns to surface. Attempt 3 more times at different pump rates . Rig iron to pump down IA and take returns up production tubing. NO communication. Rig back up to Tubing and return up IA. Pressure up to 4700 psi SITP. AK E-line rigged down. Freeze protect fluid pump. Secure location. SDFN. 2/15/22: PTW, JSA. Gather items for fluid pump. Load supply tank with 400 bbls of fresh water. MIRU YJOS fluid pump. Rig up field triplex to IA. AK E-line on location rigging up. Pressure test IA to 2100 psi for 10 minutes. Test not recorded. Good test. Stabbed on well with AK E-line. PT lubricator 250/3000 psi. Fill tubing to catch fluid. 27 bbls pumped. Perform MIT on 4.5" production tubing to 3000 psi for 10 minutes. RIH with AK E-line. Log and tie into Halliburton 11-07X CBL 16 May 17. 18.6' from ccl to top shot. Park CCL depth 5165.4. Tubing 950 psi, IA 0 psi open to return tank , OA 250 psi. Fire tubing punches from 5184'-5187'. (1540 hrs.). Tubing pressure bounced around from 950 to 890 psi. POOH to surface. Pop off E line and install night cap. All punches fired. Line up fluid pump down tubing taking returns up IA. Pressure up to 4500 psi. Small stream to return tank. Watch pressure. 250 psi drop in 30 minutes. Call down to discuss. AK E-line rigging up second tubing punch. Make up second tubing punch. Stab on well. RIH and Correlate depth to CBL log. Pressure up tubing to 1520 psi. IA open to return tank OA 250 psi. Fire second shots from 5168'-5173'. No flow at return tank. Tubing dropped from 1520 psi to 1480 psi. POOH with E-line. Online down tubing attempt to circulate 2.5 bbls/min pressure climbed to 4500 psi. No returns to tank. Monitor pressure. Shut in Tubing with 4486 psi SITP. Close IA valve. Leave tubing pressured up overnight. Rig down AK E line. Location secure. 2/9/22: PTW, JSA with AK E-line crew. Warm up equipment. Pick up lubricator assembly and make up CIBP for 4.5" production tubing. Stab on well. PT stack 250/3000 psi. Tubing 0 psi. RIH with CIBP. Log interval and correlate depth. CCL to middle element 7.6'. Pull into position and stop CCL at 5772.4'. Set CIBP at 5780'. (10:30 AM). Weight dropped from 954 lbs. to 643 lbs. Good set. Pick up 50' and tag plug. POOH to surface. Break down setting tools and make up 2.5"x30' cement dump bailer. Mix and load cement. Stab on well. RIH with cement dump run # 1. Lightly tag top of CIBP at 5780'. Pick up 10' and dump cement at 1300 hrs. POOH to surface. Mix and load 2nd. 2.5"x30' cement dump bailer. Stab on well. RIH to 5770'. and dump cement. POOH to surface. Mix and load 3rd and final. 2.5"x30' cement dump bailer. Stab on well. RIH to 5763' and dump cement (1600 hrs.) giving a calculated 25' of cement on top of CIBP. POOH to surface. Close master and swab. Estimated fluid level in well is 2390'. TOC 5,755'. Rig down AK-Eline unit. Well site secure. Depart location. E-line will return for tubing punch when pump truck and cementing services are ready to continue the intervention. 2/8/22: PTW, JSA with crew. Rig up AK E-line. Make up 3" OD magna rand bridge plug from Owen oil tools. Stab on well. Pressure test 250/3000 psi. Open swab valve. RIH with FN, Weight bar, Gun Gamma, MSSST setting tool , and 3" OD magna range bridge plug. Perform correlation pass (use tie in log KU 11-07X _CBL_16 May_17) 13.9' ccl to middle element. CCL stop depth 8956.1' . Set plug at 8970'. PU 50' RIH and tag plug. Good set. POOH to surface. Lay down Tool string and swap for 2.5" cement bailer. Load 2.5"x30' cement bailer. Stab on well. RIH for cement dump run #1 . Tag plug 8970'. Pick up 10' and dump cement. POOH to surface. Mix up cement Run #2 . Stab on well. RIH to 8955' and dump cement. POOH to surface. Mix cement run #3. RIH and dump cement 8945' and dump final cement. POOH to surface. 25' of cement placed on Magna range BP. TOC 8945. At surface. Close well. Lay down lubricator. Location secure. SDFN. Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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 herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. 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:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220217 1650 APPROVAL TO PERFORATE TUBING SHALLOWER PTD217-041 KU 11-07X Date:Thursday, February 17, 2022 5:01:56 PM Attachments:KU 11-07X AOGCC 10-403 322-037 PTD 217-041 Approved 02-03-22.pdf KU 11-07X_Schematic(02-17-22).doc From: Rixse, Melvin G (OGC) Sent: Thursday, February 17, 2022 5:00 PM To: ryan.rupert@hilcorp.com; Donna Ambruz <dambruz@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: FW: KU 11-07X (PTD#217-041) Ryan, Hilcorp is approved to proceed as per your plan below. Hilcorp should try to obtain TxIA circulation as deep as possible. Hilcorp is not to approved to perforate any shallower than 4700’ MD without additional consultation with AOGCC. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Thursday, February 17, 2022 3:22 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: KU 11-07X (PTD#217-041) Mel- Per our conversation, please see attached for approved sundry on KU 11-07X. The attached schematic is reflective of the well’s current condition. I have exhausted all sundried tubing punch intervals and still can not establish circulation from tubing to IA (see below, likely settled out mud back there in IA). Hilcorp is asking approval to continue uphole not to go above 4700’ MD (4693’ TVD) attempting punches and/or cuts to establish circulation. Although not penetrating formation, this depth limit would keep us all within the Beluga/Upper Tyonek Pool. We’ll attempt to punch as low as possible for maximum ultimate cement volume in the IA. Not sur how far uphole we’ll have to come. Please let me know if this is acceptable. I’d like to move EL back in tomorrow Fri 2/18 for additional punches, if that’s ok? 4-1/2” x 7-5/8” annulus has 20.5bbl 12ppg mud push Remainder is 11.2ppg drilling mud 3 tubing punches executed, no circulation yet: 2/16/22: Arrive on location. 3340 psi on 4.5" tubing. Hammer up pump lines and returns lines. Tubing 3340 psi. IA 130 psi, OA 250 psi. Open IA valve to return tank. Bleed off pressure. Open pump line to 4.5" production tubing. Online with fluid pump. Shut down pump at 4700 psi. No returns from IA. Monitor pressure. 5/10/15 no change and no flow to return tank. Call out AK E-line. Rig up AK E-line with 10' tubing punch . Stab on well. PT 250/3000 psi. RIH. Correlate to Halliburton CBL log 16 May 2017. CCL to top shot 10.2'. Pull into position and park CCL at 5108.8'. Online down tubing. 1238 psi SITP. IA open to return tank. shoot tubing punches from 5119'-5129'. Pressure dropped from 1238 psi to 1187 psi. No returns from AI. POOH to surface. E-line install night cap. Attempt to circulate well. Online down 4.5" tubing taking returns up IA. Pressure up to 4700 psi. No returns to surface. Attempt 3 more times at different pump rates . Rig iron to pump down IA and take returns up production tubing. NO communication. Rig back up to Tubing and return up IA. Pressure up to 4700 psi SITP. AK E-line rigged down. Freeze protect fluid pump. Secure location. SDFN. 2/15/22: PTW, JSA. Gather items for fluid pump. Load supply tank with 400 bbls of fresh water. MIRU YJOS fluid pump. Rig up field triplex to IA. AK E-line on location rigging up. Pressure test IA to 2100 psi for 10 minutes. Test not recorded. Good test. Stabbed on well with AK E-line. PT lubricator 250/3000 psi. Fill tubing to catch fluid. 27 bbls pumped. Perform MIT on 4.5" production tubing to 3000 psi for 10 minutes. RIH with AK E-line. Log and tie into Halliburton 11-07X CBL 16 May 17. 18.6' from ccl to top shot. Park CCL depth 5165.4. Tubing 950 psi, IA 0 psi open to return tank , OA 250 psi. Fire tubing punches from 5184'-5187'. (1540 hrs.). Tubing pressure bounced around from 950 to 890 psi. POOH to surface. Pop off E line and install night cap. All punches fired. Line up fluid pump down tubing taking returns up IA. Pressure up to 4500 psi. Small stream to return tank. Watch pressure. 250 psi drop in 30 minutes. Call down to discuss. AK E-line rigging up second tubing punch. Make up second tubing punch. Stab on well. RIH and Correlate depth to CBL log. Pressure up tubing to 1520 psi. IA open to return tank OA 250 psi. Fire second shots from 5168'-5173'. No flow at return tank. Tubing dropped from 1520 psi to 1480 psi. POOH with E-line. Online down tubing attempt to circulate 2.5 bbls/min pressure climbed to 4500 psi. No returns to tank. Monitor pressure. Shut in Tubing with 4486 psi SITP. Close IA valve. Leave tubing pressured up overnight. Rig down AK E line. Location secure. 2/9/22: PTW, JSA with AK E-line crew. Warm up equipment. Pick up lubricator assembly and make up CIBP for 4.5" production tubing. Stab on well. PT stack 250/3000 psi. Tubing 0 psi. RIH with CIBP. Log interval and correlate depth. CCL to middle element 7.6'. Pull into position and stop CCL at 5772.4'. Set CIBP at 5780'. (10:30 AM). Weight dropped from 954 lbs. to 643 lbs. Good set. Pick up 50' and tag plug. POOH to surface. Break down setting tools and make up 2.5"x30' cement dump bailer. Mix and load cement. Stab on well. RIH with cement dump run # 1. Lightly tag top of CIBP at 5780'. Pick up 10' and dump cement at 1300 hrs. POOH to surface. Mix and load 2nd. 2.5"x30' cement dump bailer. Stab on well. RIH to 5770'. and dump cement. POOH to surface. Mix and load 3rd and final. 2.5"x30' cement dump bailer. Stab on well. RIH to 5763' and dump cement (1600 hrs.) giving a calculated 25' of cement on top of CIBP. POOH to surface. Close master and swab. Estimated fluid level in well is 2390'. TOC 5,755'. Rig down AK-Eline unit. Well site secure. Depart location. E-line will return for tubing punch when pump truck and cementing services are ready to continue the intervention. 2/8/22: PTW, JSA with crew. Rig up AK E-line. Make up 3" OD magna rand bridge plug from Owen oil tools. Stab on well. Pressure test 250/3000 psi. Open swab valve. RIH with FN, Weight bar, Gun Gamma, MSSST setting tool , and 3" OD magna range bridge plug. Perform correlation pass (use tie in log KU 11-07X _CBL_16 May_17) 13.9' ccl to middle element. CCL stop depth 8956.1' . Set plug at 8970'. PU 50' RIH and tag plug. Good set. POOH to surface. Lay down Tool string and swap for 2.5" cement bailer. Load 2.5"x30' cement bailer. Stab on well. RIH for cement dump run #1 . Tag plug 8970'. Pick up 10' and dump cement. POOH to surface. Mix up cement Run #2 . Stab on well. RIH to 8955' and dump cement. POOH to surface. Mix cement run #3. RIH and dump cement 8945' and dump final cement. POOH to surface. 25' of cement placed on Magna range BP. TOC 8945. At surface. Close well. Lay down lubricator. Location secure. SDFN. Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) 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. Updated by CRR 02-17-22 SCHEMATIC (2/17/22) Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PBTD = TBD MD / TBD’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 109 X-56 Weld 15” Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95” Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958” Surf 9,799’ 1 16” 10-3/4” 4- JEWELRY DETAIL No. Depth (MD) ID Item 1 18’ 4.276” Tubing Hanger 2 5,566’ 4.276” 10 ft Swell Packer (Water Swell) 3 ±5780’ CIBP with 25’ cement: ToC = 5755’ MD 4 6,206’ 3.25” Permanent Owen X-span patch from 6206’ – 6243’ MD (11/10/21) 5 6,294’ 3.25” Permanent Owen X-span patch from 6294’ – 6309’ MD (11/8/21) 6 8970’ Expandable plug with 25’ cement: ToC = 8945’ MD 7 9,420’ 3.958” CIBP set on 8/25/17 8 9,455’ 3.958” CIBP Set on 8/17/17 9 9,500’ 3.958” CIBP Set on 8/1/17 10 9,540 3.958” CIBP Set on 7/15/17 11 9,591’ 3.958” CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 3 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments Upper Beluga ±4,700’ ±5,225’ ±4,693’ ±5,218’ Blga/Upr Ty Proposed MB 6 Mid 1 5,810’ 5,818' 5,764’ 5,772' 8’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) MB 6 Mid 2 5,836' 5,846' 5,790 5,800' 10’ Blga/Upr Ty 1/13/22 Plugged (2/9/22) LB1B 6,210’ 6,240’ 6,159’ 6,189’ 30' Blga/Upr Ty 9/27/21 Patched 11/10/21 LB1C 6,299’ 6,307’ 6,246’ 6,254’ 8' Blga/Upr Ty 9/27/21 Patched 11/8/21 LB3 6,707’ 6,726’ 6,650’ 6,669’ 19’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB3B 6,754’’ 6,771’ 6,697’ 6,713’ 17’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) LB4C 7,007 7,018’ 6,947’ 6,957’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) 7,024’ 7,035’ 6,963’ 6,974’ 11’ Blga/Upr Ty 8/25/21 Plugged (2/9/22) D-1 8,856’ 8,876’ 8,773’ 8,793’ 20’ Blga/Upr Ty 7/29/21 Plugged (2/9/22) D-2 8,983’ 9,036’ 8,899’ 8,951’ 53’ Ty Gas Pool #1 1/21/20 Plugged (2/8/22) D-3B 9,274’ 9,305’ 9,186’ 9,216’ 31’ Ty Gas Pool #1 8/25/17 Plugged (2/8/22) 9,313’ 9,323’ 9,224’ 9,234’ 10‘ Ty Gas Pool #1 7/8/21 Plugged (2/8/22) D-4A 9,431 9,445' 9,340’ 9,354’ 14’ Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’ 9,476’ 9,370’ 9,385’ 15’ Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’ 9,535’ 9,419’ 9,443’ 24’ Ty Gas Pool #1 7/17/17 Plugged 9,546’ 9,569’ 9,454’ 9,476’ 23’ Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600' 9,502’ 9,507’ 5’ Ty Gas Pool #1 6/12/17 Plugged 9,600 9,620' 9,507’ 9,526’ 25’ Ty Gas Pool #1 6/9/17 Plugged 8 7 9 10 11 D-3B D-2 OPEN HOLE / CEMENT DETAIL 10-3/4” 13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8" 9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job. 4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2” 6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6044’. Intermittent bands of cement to 5,200’ MD. Solid cement band from 5,448’ to 5,562’ above Swellable packer. D-1 LB3 LB3B LB4C LB1B LB1C 4/5 7-5/8” TOC @ 2,500’ MB 6 6 Planned ToC in IA: ±3000’ MD Punches Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 2/04/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) PERF 01/13/2022 Please include current contact information if different from above. 37' (6HW Received By: 02/07/2022 By Abby Bell at 3:54 pm, Feb 04, 2022 7\SHRI5HTXHVW$EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH5HSDLU:HOO 2SHUDWLRQVVKXWGRZQ 6XVSHQG3HUIRUDWH2WKHU6WLPXODWH3XOO7XELQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HHQWHU6XVS:HOO $OWHU&DVLQJ 2WKHUBB&HPHQW3DFNHU1B 2SHUDWRU1DPH&XUUHQW:HOO&ODVV3HUPLWWR'ULOO1XPEHU ([SORUDWRU\'HYHORSPHQW 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WĂǇďĞůŽǁƚŚĞƉĂĐŬĞƌŚĂƐďĞĞŶĞǆŚĂƵƐƚĞĚŝŶ<hϭϭͲϬϳǆ͘dŚĞǁĞůůŝƐŶŽǁƌĞĂĚǇĨŽƌƌĞĐŽŵƉůĞƚĞĂďŽǀĞƚŚĞƐǁĞůů ƉĂĐŬĞƌĂƚϱ͕ϱϲϲ͛D͘dŚŝƐǁŝůůƌĞƋƵŝƌĞĂŶŽŶͲƌŝŐĐĞŵĞŶƚũŽďƚŽƉƌŽǀŝĚĞŝƐŽůĂƚŝŽŶ͕ĂŶĚĞƐƚĂďůŝƐŚĂŚŝŐŚĞƌďĂƌƌŝĞƌ ŝŶƚŚĞϰͲϭͬϮ͟ǆϳͲϱͬϴ͟/͘^ĞǀĞƌĂůŵŝĚĚůĞďĞůƵŐĂƐĂŶĚƐĂƌĞƉƌĞƐĞŶƚƚŽĚĞǀĞůŽƉŝŶƚŚŝƐǁĞůůĂďŽǀĞƚŚĞƐǁĞůů ƉĂĐŬĞƌ͘^ƚĞƌůŝŶŐŝŶƚĞƌǀĂůƐĂƌĞƉƌĞƐĞŶƚĂƐǁĞůů͕ďƵƚƚŚŽƐĞǁŽƵůĚďĞƚŚĞƐƵďũĞĐƚŽĨĂĨƵƚƵƌĞƐƵŶĚƌǇ͘dŚĞǁĞůůŝƐ ĐƵƌƌĞŶƚůǇĐŽŵŝŶŐůĞĚďĞƚǁĞĞŶƚŚĞdǇŽŶĞŬŐĂƐWŽŽůηϭĂŶĚƚŚĞĞůƵŐĂͬhƉƉĞƌdǇŽŶĞŬŐĂƐWŽŽů͘dŚĞdǇŽŶĞŬ'ĂƐ WŽŽůηϭǁŝůůŶĞĞĚƚŽďĞƉƌŽƉĞƌůǇĂďĂŶĚŽŶĞĚďĞĨŽƌĞƐĞƚƚŝŶŐĂĚĚŝƚŝŽŶĂůƉůƵŐƐŝŶƚŚŝƐǁĞůů͘ dŚĞŐŽĂůƐŽĨƚŚŝƐƉƌŽũĞĐƚĂƌĞƚŽƉƌŽƉĞƌůǇĂďĂŶĚŽŶƚŚĞdǇŽŶĞŬ'ĂƐWŽŽůηϭĂŶĚĂůƐŽĐĞŵĞŶƚƚŚĞϰͲϭͬϮ͟ǆϳ͟ĂŶŶƵůƵƐ͘ dŚŝƐǁŝůůĂůůŽǁĨŽƌƌĞĐŽŵƉůĞƚŝŽŶĂŶĚŽĨĨƚĂŬĞĂďŽǀĞƚŚĞĐƵƌƌĞŶƚƉĂĐŬĞƌ͕ǁŚŝůĞƐƚŝůůŵĂŝŶƚĂŝŶŝŶŐĂŶŝƐŽůĂƚĞĚĂŶĚ ŵŽŶŝƚŽƌĂďůĞĂŶŶƵůƵƐ EŽƚĞƐZĞŐĂƌĚŝŶŐtĞůůďŽƌĞŽŶĚŝƚŝŽŶ xDŝŶ/сϯ͘Ϯϱ͟ĂƚϲϮϬϲ͛ĂŶĚϲϮϵϰ͛D;WĞƌŵĂŶĞŶƚyͲƐƉĂŶĐĂƐŝŶŐƉĂƚĐŚĞƐͿ xDĂǆ/ŶĐůŝŶĂƚŝŽŶсϭϭĚĞŐƌĞĞƐĂƚϲϯϬϴ͛D xZĞĐĞŶƚŚŝƐƚŽƌǇ oϭͬϭϯͬϮϮ͗>ŵĂĚĞŝƚĚŽǁŶƚŽϲϬϬϬ͛DǁŝƚŚϮͲϳͬϴ͟ŐƵŶƐ;ŶŽƚĂŐͿ oϭϭͬϭϲͬϮϭ͗dEϮůŝĨƚƚĂŐŐĞĚWdĂƚϵϯϴϮ͛dD;ƉĂƚĐŚĞƐŚĂĚĂůƌĞĂĚǇďĞĞŶƐĞƚͿ dŚĞŐŽĂůƐŽĨƚŚŝƐƉƌŽũĞĐƚĂƌĞƚŽƉƌŽƉĞƌůǇĂďĂŶĚŽŶƚŚĞdǇŽŶĞŬ'ĂƐWŽŽůηϭĂŶĚĂůƐŽĐĞŵĞŶƚƚŚĞϰͲϭͬϮ͟ǆϳ͟ĂŶŶƵůƵƐ͘ tĞůů͗<hϭϭͲϬϳǆ ĂƚĞ͗ϭͬϮϱͬϮϮ Ͳ>ŝŶĞƉƌŽĐĞĚƵƌĞ ϭ͘D/ZhͲůŝŶĞĂŶĚƉƌĞƐƐƵƌĞĐŽŶƚƌŽůĞƋƵŝƉŵĞŶƚ Ϯ͘WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϯ͕ϬϬϬƉƐŝ,ŝŐŚ ϭ͘DhĞǆƉĂŶĚĂďůĞƉůƵŐ Ϯ͘Z/,ĂŶĚƐĞƚϰͲϭͬϮ͟ĞǆƉĂŶĚĂďůĞƉůƵŐĂƚцϴϵϳϬ͛D Ă͘ZĞŐƐĐĂůůĨŽƌƉůƵŐƚŽďĞƐĞƚǁŝƚŚŝŶϱϬ͛ŽĨͲϮƉĞƌĨƐ;ϴϵϴϯ͛DͿ ď͘ͲϮƐĂŶĚŝƐƚŚĞŚŝŐŚĞƐƚŽƉĞŶdǇŽŶĞŬŐĂƐWŽŽůηϭƐĂŶĚ ϯ͘Z/,ĂŶĚĚƵŵƉďĂŝůϮϱ͛ŽĨĐĞŵĞŶƚŽŶƚŽƉŽĨƉůƵŐ;ĞƐƚdŽцϴϵϰϱ͛DͿ ϰ͘Dh/WƚŽŝƐŽůĂƚĞĂůůŽƉĞŶƉĞƌĨƐ ϱ͘>ŽĂĚƚƵďŝŶŐǁŝƚŚƐŽƵƌĐĞͬůĞĂƐĞǁĂƚĞƌƚĂŬŝŶŐƌĞƚƵƌŶƐƚŽĨŽƌŵĂƚŝŽŶ Ă͘Εϭϯϲďďůts ď͘>ŝŬĞůǇǁŽŶ͛ƚŶĞĞĚƚŚĂƚŵƵĐŚŝĨǁĞůůŚĂƐĂ&>ƉƌĞƐĞŶƚĂůƌĞĂĚǇ ϲ͘Z/,ĂŶĚƐĞƚ/WĂƚцϱϳϴϬ͛D͘ ϳ͘DhĂŶĚZ/,ǁŝƚŚƚƵďŝŶŐĐƵƚƚĞƌŽƌƉƵŶĐŚĞƌ ϴ͘,ŽůĚŝŶŐĂƚůĞĂƐƚϵϬϬƉƐŝŽŶƚŚĞƚƵďŝŶŐ͕ĐƵƚͬƉƵŶĐŚĂƚцϱϭϴϰ͛D Ă͘ϰͲϭͬϮ͟ǆϳͲϱͬϴ͟ĂŶŶƵůƵƐŚĂƐϮϬ͘ϱďďůϭϮƉƉŐŵƵĚƉƵƐŚ ď͘ZĞŵĂŝŶĚĞƌŝƐϭϭ͘ϮƉƉŐĚƌŝůůŝŶŐŵƵĚ ϵ͘ƐƚĂďůŝƐŚĐŝƌĐƵůĂƚŝŽŶĨƌŽŵƚƵďŝŶŐƚŽ/͘ ŽŶƚŝŶŐĞŶĐǇ͗ŝĨĐŝƌĐƵůĂƚŝŽŶĐĂŶ͛ƚďĞĞƐƚĂďůŝƐŚĞĚĂƚůĞĂƐƚϮďƉŵĐŽŶƚĂĐƚK͘DĂǇŚĂǀĞƚŽĐŽŵĞƵƉŚŽůĞĂŶĚ ƉƵŶĐŚͬĐƵƚĂŐĂŝŶ͘ĂĐŬƵƉĐƵƚͬƉƵŶĐŚĚĞƉƚŚсцϱϭϰϭ͛D ϭϬ͘KŶĐĞĐŝƌĐƵůĂƚŝŽŶŝƐĞƐƚĂďůŝƐŚĞĚďŽƚŚĚŝƌĞĐƚŝŽŶƐ͕ƐǁĂƉǁĞůůŽǀĞƌƚŽĂůůƐŽƵƌĐĞͬůĞĂƐĞǁĂƚĞƌĂƚŵĂǆƌĂƚĞ ϭϭ͘ZDK>ĂŶĚƉƵŵƉƚƌƵĐŬ ϰͲϭͬϮ͟ǆϳͲϱͬϴ͟/ĞŵĞŶƚŝŶŐWƌŽĐĞĚƵƌĞ ϭ͘ZhĐĞŵĞŶƚƚƌƵĐŬ͕WdůŝŶĞƐƚŽϮϱϬƉƐŝůŽǁͬϯϬϬϬƉƐŝŚŝŐŚ͘ Ϯ͘DŝǆĂŶĚƉƵŵƉϭϱ͘ϯƉƉŐĐĞŵĞŶƚĚŽǁŶƚŚĞƚƵďŝŶŐ͕ƚĂŬŝŶŐƌĞƚƵƌŶƐƵƉƚŚĞϰͲϭͬϮ͟ǆϳͲϱͬϴ͟/ ϯ͘WůĂŶŶĞĚdKŝŶ/ŝƐцϯϬϬϬ͛D͘;цϱϴďďůƐƌĞƋƵŝƌĞĚͿ ϰ͘ŝƐƉůĂĐĞƉĞƌK ϱ͘^/ŵĂƐƚĞƌǀĂůǀĞĂŶĚ/ĂŶĚƚƌĂƉƉƌĞƐƐƵƌĞŽŶƚŚĞƚƵďŝŶŐ ϲ͘ZDKĐĞŵĞŶƚĞƌƐ ĂĐŬƵƉĐƵƚͬƉƵŶĐŚĚĞƉƚŚсцϱϭϰϭ͛D Z/,ĂŶĚƐĞƚ/WĂƚцϱϳϴϬ͛D͘ WůĂŶŶĞĚdKŝŶ/ŝƐцϯϬϬϬ͛D͘;цϱϴďďůƐƌĞƋƵŝƌĞĚͿ 'XPS EDLO RI FHPHQW RQ WRS RI SOXJ EMP ď͘ͲϮƐĂŶĚŝƐƚŚĞŚŝŐŚĞƐƚŽƉĞŶdǇŽŶĞŬŐĂƐWŽŽůηϭƐĂŶĚ tĞůů͗<hϭϭͲϬϳǆ ĂƚĞ͗ϭͬϮϱͬϮϮ dWƌŽĐĞĚƵƌĞ ϭ͘D/Zhdh͕ϮϰŚƌŶŽƚŝĐĞĨŽƌKWƚĞƐƚ Ϯ͘ŽŶĚƵĐƚKWƚĞƐƚƚŽϮϱϬƉƐŝůŽǁͬϯϱϬϬƉƐŝŚŝŐŚ ϯ͘tŽƌŬŝŶŐĨůƵŝĚǁŝůůďĞůĞĂƐĞŽƌƐŽƵƌĐĞǁĂƚĞƌ ϰ͘D/dͲ/ƚŽϮϬϬϬƉƐŝĨŽƌϯϬĐŚĂƌƚĞĚŵŝŶƵƚĞƐ ϱ͘DhdŵŽƚŽƌͬŵŝůůĂƐƐĞŵďůǇ ϲ͘Z/,ĂŶĚŽďƚĂŝŶĚƌǇƚĂŐŽĨdŽ ϳ͘DŝůůƵƉĐĞŵĞŶƚĚŽǁŶƚŽWdĂƚцϱϳϳϬ͛D ϴ͘>ŽŐŵĞŵŽƌǇ>ĨƌŽŵŶĞǁWdƚŽĂďŽǀĞĞǆƉĞĐƚĞĚdŽ ŽŶƚŝŶŐĞŶĐǇ͗DĂǇďƌŝŶŐŝŶ>Žƌ^>ƚŽŽďƚĂŝŶ>ĚĞƉĞŶĚŝŶŐŽŶƚŝŵŝŶŐ͘/ĨƐŽ͕KWƚĞƐƚǁŽƵůĚŽŶůǇŶĞĞĚƚŽďĞƚŽ ϮϱϬͬϮϬϬϬƉƐŝ ϵ͘WKK,ĂŶĚƉƌĞƉĂƌĞĨŽƌŶŝƚƌŽŐĞŶďůŽǁĚŽǁŶŽƉĞƌĂƚŝŽŶƐ ϭϬ͘Z/,ĂŶĚďůŽǁŽƵƚĂůůĨůƵŝĚĨƌŽŵǁĞůůďŽƌĞ͗dƵďŝŶŐǀŽůƵŵĞсϴϴďďůƐ ϭϭ͘dƌĂƉEϮƉƌĞƐƐƵƌĞŽŶƚƵďŝŶŐƉĞƌK ϭϮ͘ZDKd Ͳ>ŝŶĞWĞƌĨƉƌŽĐĞĚƵƌĞ ϭ͘D/ZhͲůŝŶĞĂŶĚƉƌĞƐƐƵƌĞĐŽŶƚƌŽůĞƋƵŝƉŵĞŶƚ Ϯ͘WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϯ͕ϬϬϬƉƐŝ,ŝŐŚ ϯ͘Z/,ĂŶĚƉĞƌĨŽƌĂƚĞhƉƉĞƌĞůƵŐĂƐĂŶĚƐĨƌŽŵцϰ͕ϳϬϬ͛ʹцϱ͕ϮϮϱ͛D;цϰ͕ϲϵϯ͛ʹцϱ͕Ϯϭϴ͛dsͿƉĞƌZͬ'ĞŽ WŽƐƚͲWĞƌĨD/dͲ/ ϭ͘WĞƌĨŽƌŵD/dͲ/ƚŽϮϬϬϬƉƐŝŽŶĐĞũŽďŝƐĐŽŵƉůĞƚĞĂŶĚǁĞůůŚĂƐďĞĞŶďƌŽƵŐŚƚŽŶůŝŶĞǁŝƚŚŝŶϯϬĚĂǇƐ͘ ŽŶƚŝŶŐĞŶĐǇ>WůƵŐŽƌWĂƚĐŚ ϭ͘D/ZhͲůŝŶĞ͕WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϯ͕ϬϬϬƉƐŝŚŝŐŚ Ϯ͘Z/,tͬ'WdƚŽŽůĂŶĚĨŝŶĚĨůƵŝĚůĞǀĞů ϯ͘ZhEŝƚƌŽŐĞŶdƌƵĐŬ Ă͘WƵƐŚǁĂƚĞƌďĂĐŬŝŶƚŽĨŽƌŵĂƚŝŽŶ ď͘hƐĞ'WdƚŽŽůƚŽĐŽŶĨŝƌŵǁĂƚĞƌůĞǀĞůŝƐďĞůŽǁŝŶƚĞƌǀĂůƚŽƉĞƌĨ Đ͘ŽŶƐƵůƚKĨŽƌƉƌĞƐƐƵƌĞƚŽůĞĂǀĞŽŶǁĞůůĨŽƌƉĞƌĨŽƌĂƚŝŶŐ ϰ͘KŶĐĞĨůƵŝĚůĞǀĞůŝƐďĞůŽǁŝŶƚĞƌǀĂůƚŽŝƐŽůĂƚĞ͕DhϰͲϭͬϮ͟ƉĂƚĐŚŽƌƉůƵŐ ϱ͘Z/,ĂŶĚƐĞƚƉůƵŐŽƌƉĂƚĐŚƉĞƌK͘ ϲ͘ZͲ>ŝŶĞhŶŝƚĂŶĚƚƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƵƌƌĞŶƚ^ĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘^ƚĂŶĚĂƌĚtĞůůƉƌŽĐĞĚƵƌĞʹEϮKƉĞƌĂƚŝŽŶƐ 6HQG &%/ ORJ WR $2*&& DQG REWDLQ DSSURYDO EHIRUH SHUIRUDWLQJ EMP 3URYLGH KU QRWLFH IRU $2*&& WR ZLWQHVV 0,7,$ EMP >ŽŐŵĞŵŽƌǇ>ĨƌŽŵŶĞǁWdƚŽĂďŽǀĞĞǆƉĞĐƚĞĚdŽ WĞƌĨŽƌŵD/dͲ/ƚŽϮϬϬϬƉƐŝŽŶĐĞũŽďŝƐĐŽŵƉůĞƚĞĂŶĚǁĞůůŚĂƐďĞĞŶďƌŽƵŐŚƚŽŶůŝŶĞǁŝƚŚŝŶϯϬĚĂǇƐ͘ DŝůůƵƉĐĞŵĞŶƚĚŽǁŶƚŽWdĂƚцϱϳϳϬ͛D ŽŶĚƵĐƚKWƚĞƐƚƚŽϮϱϬƉƐŝůŽǁͬϯϱϬϬƉƐŝŚŝŐŚ ^dEZt>>WZKhZ E/dZK'EKWZd/KE^ ϭϮͬϬϴͬϮϬϭϱ &/E>ǀϭ WĂŐĞϭŽĨϭ ϭ͘Ϳ D/ZhEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘ Ϯ͘Ϳ EŽƚŝĨǇWĂĚKƉĞƌĂƚŽƌŽĨƵƉĐŽŵŝŶŐEŝƚƌŽŐĞŶŽƉĞƌĂƚŝŽŶƐ͘ ϯ͘Ϳ WĞƌĨŽƌŵWƌĞͲ:Žď^ĂĨĞƚǇDĞĞƚŝŶŐ͘ZĞǀŝĞǁEŝƚƌŽŐĞŶǀĞŶĚŽƌƐƚĂŶĚĂƌĚŽƉĞƌĂƚŝŶŐƉƌŽĐĞĚƵƌĞƐĂŶĚ ĂƉƉƌŽƉƌŝĂƚĞ^ĂĨĞƚǇĂƚĂ^ŚĞĞƚƐ;ĨŽƌŵĞƌůǇD^^Ϳ͘ ϰ͘Ϳ ŽĐƵŵĞŶƚ ŚĂǌĂƌĚƐ ĂŶĚ ŵŝƚŝŐĂƚŝŽŶ ŵĞĂƐƵƌĞƐ ĂŶĚ ĐŽŶĨŝƌŵ ĨůŽǁ ƉĂƚŚƐ͘ /ŶĐůƵĚĞ ƌĞǀŝĞǁ ŽŶ ĂƐƉŚǇǆŝĂƚŝŽŶ ĐĂƵƐĞĚ ďǇ ŶŝƚƌŽŐĞŶĚŝƐƉůĂĐŝŶŐŽǆǇŐĞŶ͘DŝƚŝŐĂƚŝŽŶ ŵĞĂƐƵƌĞƐ ŝŶĐůƵĚĞĂƉƉƌŽƉƌŝĂƚĞ ƌŽƵƚŝŶŐŽĨĨůŽǁůŝŶĞƐ͕ĂĚĞƋƵĂƚĞǀĞŶƚŝŶŐĂŶĚĂƚŵŽƐƉŚĞƌŝĐŵŽŶŝƚŽƌŝŶŐ͘ ϱ͘Ϳ ^ƉŽƚWƵŵƉŝŶŐhŶŝƚĂŶĚdƌĂŶƐƉŽƌƚ͘ŽŶĨŝƌŵůŝƋƵŝĚEϮǀŽůƵŵĞƐŝŶƚƌĂŶƐƉŽƌƚ͘ ϲ͘Ϳ ZŝŐƵƉůŝŶĞƐĨƌŽŵƚŚĞEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚƚŽƚŚĞǁĞůůĂŶĚƌĞƚƵƌŶƐƚĂŶŬ͘^ĞĐƵƌĞůŝŶĞƐǁŝƚŚǁŚŝƉ ĐŚĞĐŬƐ͘ ϳ͘Ϳ WůĂĐĞ ƐŝŐŶƐ ĂŶĚ ƉůĂĐĂƌĚƐ ǁĂƌŶŝŶŐ ŽĨ ŚŝŐŚ ƉƌĞƐƐƵƌĞ ĂŶĚ ŶŝƚƌŽŐĞŶ ŽƉĞƌĂƚŝŽŶƐ Ăƚ ĂƌĞĂƐ ǁŚĞƌĞ EŝƚƌŽŐĞŶŵĂǇĂĐĐƵŵƵůĂƚĞŽƌďĞƌĞůĞĂƐĞĚ͘ ϴ͘Ϳ WůĂĐĞƉƌĞƐƐƵƌĞŐĂƵŐĞƐĚŽǁŶƐƚƌĞĂŵŽĨůŝƋƵŝĚĂŶĚŶŝƚƌŽŐĞŶƉƵŵƉƐƚŽĂĚĞƋƵĂƚĞůǇŵĞĂƐƵƌĞƚƵďŝŶŐ ĂŶĚĐĂƐŝŶŐƉƌĞƐƐƵƌĞƐ͘ ϵ͘Ϳ WůĂĐĞƉƌĞƐƐƵƌĞŐĂƵŐĞƐƵƉƐƚƌĞĂŵĂŶĚĚŽǁŶƐƚƌĞĂŵŽĨĂŶǇĐŚĞĐŬǀĂůǀĞƐ͘ ϭϬ͘Ϳ tĞůůƐŝƚĞDĂŶĂŐĞƌƐŚĂůůǁĂůŬĚŽǁŶǀĂůǀĞĂůŝŐŶŵĞŶƚƐĂŶĚĞŶƐƵƌĞǀĂůǀĞƉŽƐŝƚŝŽŶŝƐĐŽƌƌĞĐƚ͘ ϭϭ͘Ϳ ŶƐƵƌĞƉŽƌƚĂďůĞϰͲŐĂƐĚĞƚĞĐƚŝŽŶĞƋƵŝƉŵĞŶƚŝƐŽŶƐŝƚĞ͕ĐĂůŝďƌĂƚĞĚ͕ĂŶĚďƵŵƉƚĞƐƚĞĚƉƌŽƉĞƌůǇƚŽ ĚĞƚĞĐƚ>>ͬ,Ϯ^ͬKϮͬKϮůĞǀĞůƐ͘ŶƐƵƌĞEŝƚƌŽŐĞŶǀĞŶĚŽƌŚĂƐĂǁŽƌŬŝŶŐĂŶĚĐĂůŝďƌĂƚĞĚĚĞƚĞĐƚŽƌĂƐ ǁĞůůƚŚĂƚŵĞĂƐƵƌĞƐKϮůĞǀĞůƐ͘ ϭϮ͘Ϳ WƌĞƐƐƵƌĞƚĞƐƚůŝŶĞƐƵƉƐƚƌĞĂŵŽĨǁĞůůƚŽĂƉƉƌŽǀĞĚƐƵŶĚƌǇƉƌĞƐƐƵƌĞŽƌDW^W;DĂǆŝŵƵŵWŽƚĞŶƚŝĂů ^ƵƌĨĂĐĞWƌĞƐƐƵƌĞͿ͕ǁŚŝĐŚĞǀĞƌŝƐŚŝŐŚĞƌ͘dĞƐƚůŝŶĞƐĚŽǁŶƐƚƌĞĂŵŽĨǁĞůů;ĨƌŽŵǁĞůůƚŽƌĞƚƵƌŶƐƚĂŶŬͿ ƚŽϭ͕ϱϬϬƉƐŝ͘WĞƌĨŽƌŵǀŝƐƵĂůŝŶƐƉĞĐƚŝŽŶĨŽƌĂŶǇůĞĂŬƐ͘ ϭϯ͘Ϳ ůĞĞĚŽĨĨƚĞƐƚƉƌĞƐƐƵƌĞĂŶĚƉƌĞƉĂƌĞĨŽƌƉƵŵƉŝŶŐŶŝƚƌŽŐĞŶ͘ ϭϰ͘Ϳ WƵŵƉŶŝƚƌŽŐĞŶĂƚĚĞƐŝƌĞĚƌĂƚĞ͕ŵŽŶŝƚŽƌŝŶŐƌĂƚĞ;^&DͿĂŶĚƉƌĞƐƐƵƌĞ;W^/Ϳ͘ůůŶŝƚƌŽŐĞŶƌĞƚƵƌŶƐ ĂƌĞƚŽďĞƌŽƵƚĞĚƚŽƚŚĞƌĞƚƵƌŶƐƚĂŶŬ͘ ϭϱ͘Ϳ tŚĞŶĨŝŶĂůŶŝƚƌŽŐĞŶǀŽůƵŵĞŚĂƐďĞĞŶĂĐŚŝĞǀĞĚ͕ŝƐŽůĂƚĞǁĞůůĨƌŽŵEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ ďůĞĞĚĚŽǁŶůŝŶĞƐďĞƚǁĞĞŶǁĞůůĂŶĚEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚ͘ ϭϲ͘Ϳ KŶĐĞǇŽƵŚĂǀĞĐŽŶĨŝƌŵĞĚůŝŶĞƐĂƌĞďůĞĚĚŽǁŶ͕ŶŽƚƌĂƉƉĞĚƉƌĞƐƐƵƌĞĞǆŝƐƚƐ͕ĂŶĚŶŽŶŝƚƌŽŐĞŶŚĂƐ ĂĐĐƵŵƵůĂƚĞĚďĞŐŝŶƌŝŐĚŽǁŶŽĨůŝŶĞƐĨƌŽŵƚŚĞEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚ͘ ϭϳ͘Ϳ &ŝŶĂůŝǌĞũŽďůŽŐĂŶĚĚŝƐĐƵƐƐŽƉĞƌĂƚŝŽŶƐǁŝƚŚtĞůůƐŝƚĞDĂŶĂŐĞƌ͘ŽĐƵŵĞŶƚĂŶǇůĞƐƐŽŶƐůĞĂƌŶĞĚ ĂŶĚĐŽŶĨŝƌŵĨŝŶĂůƌĂƚĞƐͬƉƌĞƐƐƵƌĞͬǀŽůƵŵĞƐŽĨƚŚĞũŽďĂŶĚƌĞŵĂŝŶŝŶŐŶŝƚƌŽŐĞŶŝŶƚŚĞƚƌĂŶƐƉŽƌƚ͘ ϭϴ͘Ϳ ZDKEŝƚƌŽŐĞŶWƵŵƉŝŶŐhŶŝƚĂŶĚ>ŝƋƵŝĚEŝƚƌŽŐĞŶdƌĂŶƐƉŽƌƚ͘ 1 Carlisle, Samantha J (OGC) From:McLellan, Bryan J (OGC) Sent:Tuesday, January 18, 2022 3:05 PM To:Ryan Rupert Cc:Donna Ambruz; Chad Helgeson; Josh Allely - (C); Dan Marlowe; Roby, David S (OGC); Boyer, David L (OGC) Subject:RE: KU 11-07x (PTD#217-041) Sundry 222-003 Ryan, Based on the performance the recent addperfs and the plans to plug the Tyonek Gas Pool #1, you have approval not to run the comingling PLT referenced in Sundry 322‐003. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, January 17, 2022 12:32 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: KU 11‐07x (PTD#217‐041) Sundry 222‐003 Bryan‐ I was pulling together the 404 to close out KU 11‐07x (PTD#217‐041) Sundry 222‐003. The approved sundry calls for a production log to determine splits in this comingled well. The well was already comingled in the Tyonek gas pool #1, and the Beluga/Upper Tyonek gas pools. These new perfs shot on 1/13/22 had minimal effect on production (down slightly, see below image of rate in MCFD). Our proposal now is to close out sundry 322‐003 and submit a new 403 to properly abandon the Tyonek gas pool #1, and then plug off all existing Beluga/Upper Tyonek pool perfs, to be followed with an uphole recomplete for shallower sands. Given this Hilcorp proposed to not run the production log mentioned in sundry #322‐003. Please let us know if that is acceptable. Thank you 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. 2 Ryan Rupert Kenai Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) 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. 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DƵƐƚďĞƌƵŶǁŝƚŚŝŶϯϬĚĂǇƐŽĨĐŽŵŵĞŶĐĞŵĞŶƚŽĨĐŽŵŝŶŐůĞĚƉƌŽĚƵĐƚŝŽŶ͕ĂĨƚĞƌǁĞůůŚĂƐƐƚĂďŝůŝǌĞĚƉĞƌKϱϭϬ͘ ϭ͘Zh>ͬ^>ĂŶĚWdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁͬϮ͕ϱϬϬƉƐŝŚŝŐŚ Ϯ͘Z/,ǁŝƚŚW>důŽŐŐŝŶŐƚŽŽů ϯ͘ĐƋƵŝƌĞĚǇŶĂŵŝĐƉĂƐƐĞĚĂŶĚƐƚŽƉĐŽƵŶƚƐƉĞƌK ϰ͘ŽŶĨŝƌŵŐŽŽĚĚĂƚĂ͕ƚŚĞŶZDK>ͬ^> ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƵƌƌĞŶƚƐĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ 8SGDWHGE\&55 ^,Dd/ tĞůů͗<hϭϭͲϬϳy Wd͗ϮϭϳͲϬϰϭ W/͗ϱϬͲϭϯϯͲϮϬϲϲϮͲϬϬͲϬϬ Wdсϵ͕ϰϮϬ͛Dͬϵ͕ϯϯϬ͛ds dсϵ͕ϳϵϵ͛Dͬϵ͕ϳϬϮ͛ds <сϭϴ͛^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϭϬϵ yͲϱϲ tĞůĚ ϭϱ͟ ^ƵƌĨ ϭϮϬΖ ϭϬͲϯͬϰΗ ^ƵƌĨ͘ƐŐ ϰϱ͘ϱ >ͲϴϬ ƵƚƚƌĞƐƐ ϵ͘ϵϱ͟ ^ƵƌĨ ϭ͕ϱϭϭ͛ ϳͲϱͬϴΗ /ŶƚĞƌŵĞĚŝĂƚĞ Ϯϵ͘ϳ >ͲϴϬ d ϲ͘ϴϳϱΗ ^ƵƌĨ ϲ͕ϬϵϬ͛ ϰͲϭͬϮΗ WƌŽĚƵĐƚŝŽŶ ϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟ ^ƵƌĨ ϵ͕ϳϵϵ͛ ϭϭϲ͟ ϭϬͲϯͬϰ͟ ͲϭͬϮ͟ EŽ͘ĞƉƚŚ ;DͿ / /ƚĞŵ ϭ ϭϴ͛ ϰ͘Ϯϳϲ͟ dƵďŝŶŐ,ĂŶŐĞƌ Ϯ ϱ͕ϱϲϲ͛ ϰ͘Ϯϳϲ͟ ϭϬĨƚ^ǁĞůůWĂĐŬĞƌ;tĂƚĞƌ^ǁĞůůͿ ϯ ϲ͕ϮϬϲ͛ ϯ͘Ϯϱ͟ WĞƌŵĂŶĞŶƚKǁĞŶyͲƐƉĂŶƉĂƚĐŚĨƌŽŵϲϮϬϲ͛ʹϲϮϰϯ͛D;ϭϭͬϭϬͬϮϭͿ ϯ ϲ͕Ϯϵϰ͛ ϯ͘Ϯϱ͟ WĞƌŵĂŶĞŶƚKǁĞŶyͲƐƉĂŶƉĂƚĐŚĨƌŽŵϲϮϵϰ͛ʹϲϯϬϵ͛D;ϭϭͬϴͬϮϭͿ ϰ ϵ͕ϰϮϬ͛ ϯ͘ϵϱϴ͟ /WƐĞƚŽŶϴͬϮϱͬϭϳ ϱ ϵ͕ϰϱϱ͛ ϯ͘ϵϱϴ͟ /W^ĞƚŽŶϴͬϭϳͬϭϳ ϲ ϵ͕ϱϬϬ͛ ϯ͘ϵϱϴ͟ /W^ĞƚŽŶϴͬϭͬϭϳ ϳ ϵ͕ϱϰϬ ϯ͘ϵϱϴ͟ /W^ĞƚŽŶϳͬϭϱͬϭϳ ϴ ϵ͕ϱϵϭ͛ ϯ͘ϵϱϴ͟ /W^ĞƚǁͬϭϬ͛ĐĞŵĞŶƚ;ƚĂŐϵ͕ϱϳϭͿŽŶϲͬϮϭͬϭϳ ϳͲϱͬϴ͟ Ϯ ZͲ ϳ͕ϯϵϭ͛ ZͲ ϳ͕ϵϮϰ͛ ZͲ ϴ͕ϵϭϰ͛ ZͲ ϵ͕ϰϬϱ͛ WZ&KZd/KEd/> ŽŶĞ dŽƉD ƚŵ D dŽƉ ds ƚŵ ds ŵ ƚ WŽŽů ĂƚĞ ŽŵŵĞŶƚƐ >ϭϲ͕ϮϭϬ͛ϲ͕ϮϰϬ͛ϲ͕ϭϱϵ͛ϲ͕ϭϴϵ͛ϯϬΖ ůŐĂͬhƉƌdǇ ϵͬϮϳͬϮϭ WĂƚĐŚĞĚ;ϭϭͬϭϬͬϮϭͿ >ϭϲ͕Ϯϵϵ͛ϲ͕ϯϬϳ͛ϲ͕Ϯϰϲ͛ϲ͕Ϯϱϰ͛ϴΖ ůŐĂͬhƉƌdǇ ϵͬϮϳͬϮϭ WĂƚĐŚĞĚ;ϭϭͬϴͬϮϭͿ >ϯ ϲ͕ϳϬϳ͛ ϲ͕ϳϮϲ͛ ϲ͕ϲϱϬ͛ ϲ͕ϲϲϵ͛ ϭϵ͛ ůŐĂͬhƉƌdǇ ϴͬϮϱͬϮϭ KƉĞŶ >ϯ ϲ͕ϳϱϰ͛͛ ϲ͕ϳϳϭ͛ ϲ͕ϲϵϳ͛ ϲ͕ϳϭϯ͛ ϭϳ͛ ůŐĂͬhƉƌdǇ ϴͬϮϱͬϮϭ KƉĞŶ >ϰϳ͕ϬϬϳ ϳ͕Ϭϭϴ͛ ϲ͕ϵϰϳ͛ ϲ͕ϵϱϳ͛ ϭϭ͛ ůŐĂͬhƉƌdǇ ϴͬϮϱͬϮϭ KƉĞŶ ϳ͕ϬϮϰ͛ ϳ͕Ϭϯϱ͛ ϲ͕ϵϲϯ͛ ϲ͕ϵϳϰ͛ ϭϭ͛ ůŐĂͬhƉƌdǇ ϴͬϮϱͬϮϭ KƉĞŶ Ͳϭ ϴ͕ϴϱϲ͛ ϴ͕ϴϳϲ͛ ϴ͕ϳϳϯ͛ ϴ͕ϳϵϯ͛ ϮϬ͛ ůŐĂͬhƉƌdǇ ϳͬϮϵͬϮϭ KƉĞŶ ͲϮ ϴ͕ϵϴϯ͛ ϵ͕Ϭϯϲ͛ ϴ͕ϴϵϵ͛ ϴ͕ϵϱϭ͛ ϱϯ͛ dǇ'ĂƐWŽŽůηϭ ϭͬϮϭͬϮϬ KƉĞŶ Ͳϯϵ͕Ϯϳϰ͛ ϵ͕ϯϬϱ͛ ϵ͕ϭϴϲ͛ ϵ͕Ϯϭϲ͛ ϯϭ͛ dǇ'ĂƐWŽŽůηϭ ϴͬϮϱͬϭϳ KƉĞŶ ϵ͕ϯϭϯ͛ ϵ͕ϯϮϯ͛ ϵ͕ϮϮϰ͛ ϵ͕Ϯϯϰ͛ ϭϬ͚ dǇ'ĂƐWŽŽůηϭ ϳͬϴͬϮϭ KƉĞŶ Ͳϰϵ͕ϰϯϭ ϵ͕ϰϰϱΖ ϵ͕ϯϰϬ͛ϵ͕ϯϱϰ͛ϭϰ͛dǇ'ĂƐWŽŽůηϭ ϴͬϭϴͬϭϳ WůƵŐŐĞĚ Ͳϰϵ͕ϰϲϭ͛ϵ͕ϰϳϲ͛ϵ͕ϯϳϬ͛ϵ͕ϯϴϱ͛ϭϱ͛dǇ'ĂƐWŽŽůηϭ ϴͬϭͬϭϳ WůƵŐŐĞĚ Ͳϰϵ͕ϱϭϭ͛ϵ͕ϱϯϱ͛ϵ͕ϰϭϵ͛ϵ͕ϰϰϯ͛Ϯϰ͛dǇ'ĂƐWŽŽůηϭ ϳͬϭϳͬϭϳ WůƵŐŐĞĚ ϵ͕ϱϰϲ͛ϵ͕ϱϲϵ͛ϵ͕ϰϱϰ͛ϵ͕ϰϳϲ͛Ϯϯ͛dǇ'ĂƐWŽŽůηϭ ϲͬϮϯͬϭϳ WůƵŐŐĞĚ Ͳϱ ϵ͕ϱϵϱ ϵ͕ϲϬϬΖ ϵ͕ϱϬϮ͛ϵ͕ϱϬϳ͛ϱ͛dǇ'ĂƐWŽŽůηϭ ϲͬϭϮͬϭϳ WůƵŐŐĞĚ ϵ͕ϲϬϬ ϵ͕ϲϮϬΖ ϵ͕ϱϬϳ͛ϵ͕ϱϮϲ͛Ϯϱ͛dǇ'ĂƐWŽŽůηϭ ϲͬϵͬϭϳ WůƵŐŐĞĚ ϱ ϰ ϲ ϳ ϴ Ͳϯ ͲϮ KWE,K>ͬDEdd/> ϭϬͲϯͬϰ͟ϭϯͲϭͬϮ͟,ŽůĞ͗ϭϰϭďďůƐϭϮηĐůĂƐƐůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϲϭďďůƐŽĨϭϱ͘ϰηůĂƐƐƚĂŝůĐĞŵĞŶƚ͘ &ƵůůƌĞƚƵƌŶƐƚŚƌŽƵŐŚŽƵƚũŽď͘ϳϴďďůƐĐĞŵĞŶƚďĂĐŬƚŽ^ƵƌĨĂĐĞ ϳͲϱͬϴΗ ϵͲϳͬϴ͟,ŽůĞ͗ϭϯϴďďůƐϭϮ͘ϱηĐůĂƐƐ'ůĞĂĚĐĞŵĞŶƚĨŽůůŽǁĞĚďǇϯϴďďůƐŽĨϭϱ͘ϴηůĂƐƐ'ƚĂŝů ĐĞŵĞŶƚ͘ϮϱďďůƐůŽƐƚƚŚƌŽƵŐŚŽƵƚũŽď͘ϰͬϯϬͬϭϳ>;<>ͿƌĞƉŽƌƚĞĚĂdŽŽĨϮϱϬϬ͛D͘ ϰͲϭͬϮ͟ϲͲϯͬϰ͟,ŽůĞ͗ϭϭϰďďůƐϭϱ͘ϯηĐůĂƐƐĐĞŵĞŶƚ͘EŽůŽƐƐĞƐƚŚƌŽƵŐŚŽƵƚũŽď͘ϱͬϭϲͬϭϳZĂĚŝĂů> ƐŚŽǁƐƐŽůŝĚĐĞŵĞŶƚƵƉƚŽϲϬϱϬ͛͘dŽŝƐĂƚϱϮϬϬ͛D 1RWH&RPLQJOHGSURGXFWLRQIURP7\RQHNJDV3RRODQG%HOXJD8SSHU7\RQHNSRROV5HTXLUHVDSURGXFWLRQ ORJHDFKFDOHQGDU\HDUDQGQRWPRUHWKDQPRQWKVEHWZHHQORJVSHU&2%/DVWUDQ Ͳϭ >ϯ >ϯ >ϰ >ϭ >ϭϯͬ 8SGDWHGE\&$+ WZKWK^ tĞůů͗<h ϭϭͲϬϳy Wd͗ϮϭϳͲϬϰϭ W/͗ϱϬͲϭϯϯͲϮϬϲϲϮͲϬϬͲϬϬ Wdс ϵ͕ϰϮϬ͛Dͬϵ͕ϯϯϬ͛ds dсϵ͕ϳϵϵ͛Dͬϵ͕ϳϬϮ͛ ds <сϭϴ͛^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘/dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶ ƚŽ^ĞƚĞƉƚŚ ϭϬϵ yͲϱϲ tĞůĚ ϭϱ͟^ƵƌĨ ϭϮϬΖ ϭϬͲϯͬϰΗ ^ƵƌĨ͘ƐŐ ϰϱ͘ϱ >ͲϴϬ ƵƚƚƌĞƐƐ ϵ͘ϵϱ͟ ^ƵƌĨ ϭ͕ϱϭϭ͛ ϳͲϱͬϴΗ /ŶƚĞƌŵĞĚŝĂƚĞ Ϯϵ͘ϳ >ͲϴϬ dϲ͘ϴϳϱΗ ^ƵƌĨ ϲ͕ϬϵϬ͛ ϰͲϭͬϮΗ WƌŽĚƵĐƚŝŽŶ ϭϮ͘ϲ >ͲϴϬ tͬ,d ϯ͘ϵϱϴ͟^ƵƌĨ ϵ͕ϳϵϵ͛ ϭϭϲ͟ ϭϬͲϯͬϰ͟ ͲϭͬϮ͟ EŽ͘ĞƉƚŚ ;DͿ //ƚĞŵ ϭ ϭϴ͛ϰ͘Ϯϳϲ͟dƵďŝŶŐ,ĂŶŐĞƌ Ϯ ϱ͕ϱϲϲ͛ϰ͘Ϯϳϲ͟ϭϬ Ĩƚ ^ǁĞůůWĂĐŬĞƌ ;tĂƚĞƌ^ǁĞůůͿ ϯϲ͕ϮϬϲ͛ϯ͘Ϯϱ͟WĞƌŵĂŶĞŶƚKǁĞŶyͲƐƉĂŶƉĂƚĐŚ ĨƌŽŵϲϮϬϲ͛ ʹ ϲϮϰϯ͛ D ;ϭϭͬϭϬͬϮϭͿ ϯϲ͕Ϯϵϰ͛ϯ͘Ϯϱ͟WĞƌŵĂŶĞŶƚKǁĞŶyͲƐƉĂŶƉĂƚĐŚ ĨƌŽŵϲϮϵϰ͛ ʹ ϲϯϬϵ͛ D ;ϭϭͬϴͬϮϭͿ ϰ ϵ͕ϰϮϬ͛ϯ͘ϵϱϴ͟/WƐĞƚŽŶϴͬϮϱͬϭϳ ϱ ϵ͕ϰϱϱ͛ϯ͘ϵϱϴ͟/W^ĞƚŽŶϴͬϭϳͬϭϳ ϲ ϵ͕ϱϬϬ͛ϯ͘ϵϱϴ͟/W^ĞƚŽŶϴͬϭͬϭϳ ϳ ϵ͕ϱϰϬ ϯ͘ϵϱϴ͟/W^ĞƚŽŶϳͬϭϱͬϭϳ ϴ ϵ͕ϱϵϭ͛ϯ͘ϵϱϴ͟/W^ĞƚǁͬϭϬ͛ĐĞŵĞŶƚ;ƚĂŐϵ͕ϱϳϭͿŽŶϲͬϮϭͬϭϳ ϳͲϱͬϴ͟ Ϯ ZͲ ϳ͕ϯϵϭ͛ ZͲ ϳ͕ϵϮϰ͛ ZͲ ϴ͕ϵϭϰ͛ ZͲ ϵ͕ϰϬϱ͛ WZ&KZd/KEd/> ŽŶĞ dŽƉDƚŵ D dŽƉ ds ƚŵ ds ŵ ƚ WŽŽů ĂƚĞ ŽŵŵĞŶƚƐ Dϲ DŝĚϭ цϱ͕ϴϭϬ͛цϱ͕ϴϭϴΖ цϱ͕ϳϲϰ͛цϱ͕ϳϳϮΖ ϴ͛ůŐĂͬhƉƌdǇ dWƌŽƉŽƐĞĚ Dϲ DŝĚϮ цϱ͕ϴϯϲΖ цϱ͕ϴϰϲΖ цϱ͕ϳϵϬ цϱ͕ϴϬϬΖ ϭϬ͛ůŐĂͬhƉƌdǇ dWƌŽƉŽƐĞĚ >ϭϲ͕ϮϭϬ͛ϲ͕ϮϰϬ͛ϲ͕ϭϱϵ͛ϲ͕ϭϴϵ͛ϯϬΖ ůŐĂͬhƉƌdǇ ϵͬϮϳͬϮϭ WĂƚĐŚĞĚ;ϭϭͬϭϬͬϮϭͿ >ϭϲ͕Ϯϵϵ͛ϲ͕ϯϬϳ͛ϲ͕Ϯϰϲ͛ϲ͕Ϯϱϰ͛ϴΖ ůŐĂͬhƉƌdǇ ϵͬϮϳͬϮϭ WĂƚĐŚĞĚ;ϭϭͬϴͬϮϭͿ >ϯ ϲ͕ϳϬϳ͛ϲ͕ϳϮϲ͛ϲ͕ϲϱϬ͛ϲ͕ϲϲϵ͛ϭϵ͛ůŐĂͬhƉƌdǇ ϴͬϮϱͬϮϭ KƉĞŶ >ϯϲ͕ϳϱϰ͛͛ϲ͕ϳϳϭ͛ϲ͕ϲϵϳ͛ϲ͕ϳϭϯ͛ϭϳ͛ůŐĂͬhƉƌdǇ ϴͬϮϱͬϮϭ KƉĞŶ >ϰϳ͕ϬϬϳ ϳ͕Ϭϭϴ͛ϲ͕ϵϰϳ͛ϲ͕ϵϱϳ͛ϭϭ͛ůŐĂͬhƉƌdǇ ϴͬϮϱͬϮϭ KƉĞŶ 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ƵƉͬĚŽǁŶ͘^ůŽǁůǇŝŶĐƌĞĂƐĞĚƚĞŶƐŝŽŶƵŶƚŝůďƌĞĂŬŝŶŐǁĞĂŬƉŽŝŶƚĂƚϮ͕ϴϳϱη͘WKK,͕ĂƚƐƵƌĨĂĐĞ͕ƐǁĂďƐŚƵƚ͕ďůĞĚŽĨĨůƵďƌŝĐĂƚŽƌ ƉƌĞƐƐƵƌĞ͕ŝŶƐƉĞĐƚĞĚǁŝƌĞĂŶĚƚŽŽůƌĞůĞĂƐĞĚĂƚƌŽƉĞƐŽĐŬĞƚ͘ZDK͘/ϭϬϬηKϮϰϬηdWϲϭηΗ͘ ϭϭͬϬϵͬϮϭͲdƵĞƐĚĂǇ ƌƌŝǀĞŽŶůŽĐĂƚŝŽŶũƐĂƉĞƌŵŝƚ͘ZŝŐƵƉϭϲϬǁŝƌĞƉͬƚƚŽϮϬϬϬƉƐŝŐŽŽĚƚĞƐƚ͘ZŝŚǁͬϮΖΖƌƐǁͬϯ͘ϱϱΖΖďĞůŐƵŝĚĞƚŽϲϮϲϯΖƐůŵ ϲϮϴϭŬďůĂƚĐŚďĞĂƚĚŽǁŶϱƚŝŵĞƐǁŽƵůĚŶŽƚĨĂůů͕ƉƵůůƵƉϭϰϬϬηůŝĐŬĐĂŵĞĨƌĞĞƉŽŽŚƉŝŶƐŚĞĂƌĞĚ͘ZŝŚǁͬϮΖΖũĚĐǁͬϯ͘ϱϱΖΖ ďĞůůŐƵŝĚĞƚŽϲϮϲϯΖƐůŵůĂƚĐŚϰũĂƌůŝĐŬƐƚŽϮϮϬϬηĐĂŵĞĨƌĞĞƉŽŽŚ͘,ĂǀĞĨŝƐŚůĂǇĚŽǁŶůƵď͘ƌĞĂŬŽĨĨĞͲůŝŶĞƚŽŽůƐƚƌŝŶŐƉͬƵ ůƵď͘ZŝŚǁͬϯ͘ϭϮΖΖƐǁĞĚŐĞƚŽϵϯϳϯΖƐůŵϵϯϵϭΖŬďƚĂŐƉŽŽŚŶŽŽďƐƚƌƵĐƚŝŽŶƚŚƌƵƉĂƚĐŚ͘ZŝŐĚŽǁŶƐůŝĐŬůŝŶĞƐĞĐƵƌĞǁĞůůĨŽƌ ƉƌŽĚ͘ ϭϭͬϭϬͬϮϭͲtĞĚŶĞƐĚĂǇ ĞƉĂƌƚͲ>ŝŶĞ^ŚŽƉ͘ƌƌŝǀĞĂƚ,ŝůĐŽƌƉŽĨĨŝĐĞͬ&ŝůůŽƵƚWĞƌŵŝƚ͘ƌƌŝǀĞĂƚtĞůů^ŝƚĞͬZĞƋƵĞƐƚ,ĞĂƚĞƌĨŽƌƌĂŶĞ͕ƚŽŽĐŽůĚƚŽ ƐƚĂƌƚ͘WĞƌŵŝƚ^ŝŐŶĞĚͬ^ĂĨĞƚǇDĞĞƚŝŶŐͬƌĂŶĞ^ƚĂƌƚĞĚ͘DĂŬĞƵƉdŽŽůƐͬZŝŐhƉ͘^ƚĂďŽŶͬWƌĞƐƐƵƌĞdĞƐƚ;>ϱϬϬη͕,ϮϱϬϬηͿ͘ KƉĞŶ^ǁĂďͬZ/,͘WĞƌĨŽƌŵŽƌƌĞůĂƚŝŽŶWĂƐƐϲϮϰϰΖ͘ŵĂŝůĐŽƌƌĞůĂƚŝŽŶƉĂƐƐƚŽƚŽǁŶ͘WĞƌĨŽƌŵ^ŚŽŽƚŝŶŐWĂƐƐͬ^ĞƚWĂƚĐŚ͕ ϮϲϬηǁĞŝŐŚƚůŽƐƐͬ>ͲdŽƉůĞŵĞŶƚсϭϯ͘ϮΖ͕>^ƚŽƉĞƉƚŚсϲϭϵϮ͘ϴΖ͕ dŽƉůĞŵĞŶƚ^ĞƚĂƚϲϮϬϲ͘ϬΖ͕ŽƚƚŽŵůĞŵĞŶƚ^ĞƚĂƚϲϮϰϮ͘ϱΖ͘>ŽŐŽƵƚŽĨWĂƚĐŚ͘dŽŽů^ƚƵĐŬͬtŽƌŬĞĚDƵůƚŝƉůĞƚŝŵĞƐͬ ƉƉĞĂƌƐƚŚĂƚŽůůĞƚŝƐƐƚƵĐŬŝŶƐŝĚĞhƉƉĞƌůĞŵĞŶƚͬdŽŽůhŶĂďůĞƚŽĨĂůůĚŽǁŶŽƌƉƵůůƵƉ͘ŽŶƚŝŶƵĞƚŽǁŽƌŬƚŽĂƚƚĞŵƉƚƚŽ ĨƌĞĞdŽŽů^ƚƵĐŬ͘^ůŽǁůǇŝŶĐƌĞĂƐĞƚĞŶƐŝŽŶƵŶƚŝůďƌĞĂŬŝŶŐǁĞĂŬƉŽŝŶƚĂƚϯϬϲϬη͘WKK,͘ƚ^ƵƌĨĂĐĞͬ^ǁĂď^ŚƵƚͬůĞĞĚŽĨĨ WƌĞƐƐƵƌĞ͘ZŝŐŽǁŶ͘ĞƉĂƌƚtĞůů^ŝƚĞ͘ƌƌŝǀĞĂĐŬĂƚ<Ͳ>ŝŶĞ^ŚŽƉ͘ ƐĞƚƉĂƚĐŚĂďŽǀĞĐŽůůĂƌ;ϲ͕ϯϭϭΖͿǁŝƚŚďŽƚƚŽŵĞůĞŵĞŶƚƐĞƚĂƚϲ͕ϯϬϵΖĂŶĚƚŽƉĞůĞŵĞŶƚĂƚϲ͕ϮϵϰΖ dŽƉůĞŵĞŶƚ^ĞƚĂƚϲϮϬϲ͘ϬΖ͕ŽƚƚŽŵůĞŵĞŶƚ^ĞƚĂƚϲϮϰϮ͘ϱΖ WKK,͕KK,ǁͬWĂƚĐŚ͘ ͬ^ĞƚWĂƚĐŚ͕ ϮϲϬηǁĞŝŐŚƚůŽƐƐͬ>ͲdŽƉůĞŵĞŶƚсϭϯ͘ϮΖ͕>^ƚŽƉĞƉƚŚсϲϭϵϮ͘ϴΖ͕ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ Ͳ>ŝŶĞ ϵͬϮϳͬϮϭ ϭϭͬϭϲͬϮϭ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϭϭͲϬϳy ϱϬͲϭϯϯͲϮϬϲϲϮͲϬϬͲϬϬ ϮϭϳͲϬϰϭ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ϭϭͬϭϭͬϮϭͲdŚƵƌƐĚĂǇ Wdt͕:^͘tŝƚŚ&ŽǆŶĞƌŐǇ͕ƌƵǌŽŶƐƚ͕ĂŶĚ,ŝůĐŽƌƉZĞƉ͘&ŝƌĞĞƋƵŝƉŵĞŶƚ͘^ŚƵĨĨůĞŚĞĂƚĞƌƚŽdhƚƌĂĐƚŽƌ͘dƌĂĐƚŽƌŶŽƚ ƐŚŝĨƚŝŶŐŝŶƚŽWdKŵŽĚĞ͘ƉƉůǇŚĞĂƚ͘WŝĐŬŝŶũĞĐƚŽƌŚĞĂĚ͘ŐƌĂďϭϬΖůƵďƌŝĐĂƚŽƌ͘ƵƚŽĨĨŽůĚĐŽŝůĐŽŶŶĞĐƚŽƌ͘DĂŬĞƵƉ, ϭ͘ϳϱΗĞǆƚƐůŝƉĐŽŝůĐŽŶŶĞĐƚŽƌ͘Ϯ͘ϭϮϱΗK&s͕Ϯ͘ϭϮϱΗDdƐƚŝŶŐĞƌ͕Ϯ͘ϭϮϱΗĂůůĚƌŽƉŶŽǌǌůĞ͘^ƚĂďŽŶǁĞůů͘WdůƵďƌŝĐĂƚŽƌ ϮϱϬͬϯϱϬϬƉƐŝ͘KƉĞŶǁĞůů͘Z/,͘^ƚĂƌƚŝŶŐƉƌĞƐƐƵƌĞƐϭϯϬƉƐŝt,W͕ϳϱ/͕ϭϳϬK͘ƌĂĐŬĐŚŽŬĞĂŶĚďůĞĞĚŐĂƐƚŽĚŝĨƵƐĞƌƚĂŶŬ͘ ϱϬϬϬΖƐƚĂƌƚĐŽŽůŝŶŐĚŽǁŶEϮ͘KŶůŝŶĞǁŝƚŚEϮϴϱϬƐĐĨͬĚŽǁŶϭ͘ϳϱΗdĂƚϲϬϬϬΖ͘^ůŽǁĐŽŝůƐƉĞĞĚĨƌŽŵϲϬĨƚͬŵŝŶƚŽϯϬ ĨƚͬŵŝŶ͘tĂƚĐŚĨŽƌĐŝƌĐƉƌĞƐƐƵƌĞŝŶĐƌĞĂƐĞƚŽƐĞĞǁŚĞŶǁĞĚŝƉŝŶƚŽĨůƵŝĚ͘EŽŐŽŽĚƐŝŐŶŽĨĨůƵŝĚůŝĨƚŝŶŐϳϱϬϬΖ͘ƚϴϬϬϬΖƐƚĂƌƚ WKK,ƚŽĂƚƚĞŵƉƚƚŽĨŝŶĚĨůƵŝĚ͘ZĞƚƵƌŶƐŽŶůǇEϮĂŶĚŶĂƚƵƌĂůŐĂƐ͘ϲϬϬϬΖdDƌƵŶďĂĐŬŝŶŚŽůĞ͕ĚƌŽƉƉĞĚƌĂƚĞϱϬϬƐĐĨͬŵŝŶ t,WĨůŽǁŝŶŐŐĂƐĂŶĚEϮĂƚϭϲϬƉƐŝ͘Z/,ĂŶĚƚĂŐ/WͬWdΛϵϯϴϮΖ͘WĂƌŬŽŶďŽƚƚŽŵƚŽůŝĨƚĨůƵŝĚ͘^ůŝŐŚƚƐůƵŐŽĨĨůƵŝĚ ƌĞƚƵƌŶƐĂƚƐƵƌĨĂĐĞ͘>ŝĨƚĞĚϯďďůƐĨƌŽŵǁĞůůďŽƌĞ͘EŽĚĂƚĂƚƌĞŶĚƐƐŚŽǁŶŽŶĂĐƋƵŝƐŝƚŝŽŶƐǇƐƚĞŵƚŚĂƚǁĞŚĂǀĞĂŶǇŐĂƐ ďĞŝŶŐůŝĨƚĞĚ͘dĂůŬǁŝƚŚĞŶŐŝŶĞĞƌ͘WhƚŽϲϬϬϬΖĂŶĚĂůůŽǁǁĞůůƚŽŝŶĨůŽǁǁŚŝůĞĐŚĂƐŝŶŐĂŶŶƵůƵƐďŽƚƚŽŵƐƵƉƚŽƐƵƌĨ͘Z/, ĂŶĚƚĂŐWd͘WĂƌŬϭΖŽĨĨďŽƚƚŽŵĂŶĚƉƵŵƉEϮĂƚŵŝŶƌĂƚĞϱϬϬƐĐĨͬŵŝŶĨŽƌĂĐĂůĐƵůĂƚĞĚďŽƚƚŽŵƐƵƉ͘EŽĨůƵŝĚƌĞƚƵƌŶƐĂƚ ƐƵƌĨĂĐĞ͘WKK,ƚŽƐƵƌĨĂĐĞ͘ůŽƐĞŝŶĐŚŽŬĞ͘^ǁĂƉEϮĨůŽǁƉĂƚŚĨƌŽŵĐŽŝůƚŽdǆƚƵďŝŶŐĂŶŶƵůƵƐĂŶĚŝŶĐƌĞĂƐĞŶϮƌĂƚĞƚŽ ϭϱϬϬƐĐĨͬŵŝŶǁŚŝůĞWKK,͘WƌĞƐƐƵƌĞŝŶĐƌĞĂƐĞĚĨƌŽŵEϮďƵůůŚĞĂĚƚŽϭϵϬϲƉƐŝƚŚĞŶďƌŽŬĞŽǀĞƌƚŽϵϳϱƉƐŝ͘ĂĨƚĞƌϯϮϬ͕ϲϮϬ ƐĐĨƉƵŵƉĞĚĚƵƌŝŶŐŶϮďƵůůŚĞĂĚ͘KƵƚŽĨEϮ͘ϭϱϬϬΖĨƌŽŵƐƵƌĨĂĐĞ͘t,WƐƚĂďŝůŝǌŝŶŐĂƚϴϮϮƉƐŝ͘dŽƚĂůEϮƉƵŵƉĞĚĨŽƌ ďƵůůŚĞĂĚͬEϮŝŶũĞĐƚŝŽŶϯϰϴ͕ϳϳϵƐĐĨ͘ŽŝůĐŽƵŶƚĞƌŝƐƐƵďƐƚĂŶƚŝĂůůǇŽĨĨĂŐĂŝŶ͘dĂŐŐĞĚƵƉƐŚŽǁŝŶŐͲϭϲϬΖ͘ůŽƐĞŵĂƐƚĞƌĂŶĚ ƐǁĂďǀĂůǀĞ͘^/dWϳϮϬƉƐŝ͘^ƚĂƌƚƌŝŐŐŝŶŐĚŽǁŶEϮ͘EŽƚĞ͗'ĂƐƐŶŝĨĨĞƌĐŽŶƐŝƐƚĞŶƚůǇƐŚŽǁĞĚĂĐŽŵďŝŶĂƚŝŽŶŽĨEϮĂŶĚEĂƚƵƌĂů ŐĂƐǁŝƚŚĨůƵĐƚƵĂƚŝŶŐƉĞƌĐĞŶƚĂŐĞƐĚƵƌŝŶŐƚŚĞĞŶƚŝƌĞEϮůŝĨƚĂƚƚĞŵƉƚ͘/ŶƐƚĂůůǁĞůůŚŽƵƐĞ͘>ŽĐĂƚŝŽŶǁĂůŬĂƌŽƵŶĚĐŽŵƉůĞƚĞĚ͘ DŽǀĞĐŽŝůĞƋƵŝƉŵĞŶƚƚŽĨĂƌĞĚŐĞŽĨƉĂĚƚŽŵĂŬĞƌŽŽŵĨŽƌĐŽŶƐƚƌƵĐƚŝŽŶĐƌĞǁ͘^&E͘ ϭϭͬϭϱͬϮϭͲDŽŶĚĂǇ Wdt͕:^ǁŝƚŚĐƌĞǁ͘D/Zh&ŽǆĞŶĞƌŐǇdhηϴ͘Ϯϰ,ƌKWƚĞƐƚǁŝƚŶĞƐƐŶŽƚŝĨŝĐĂƚŝŽŶƉƌŽǀŝĚĞĚƚŽ^ƚĂƚĞ͘:ŝŵZĞŐŐǁĂŝǀĞĚ ǁŝƚŶĞƐƐ͘^ƚĂƌƚƚĞƐƚŝŶŐKWϮϱϬͬϯϬϬϬƉƐŝ͘ŽŵƉůĞƚĞKWƚĞƐƚ͘ ϭϭͬϭϲͬϮϭͲdƵĞƐĚĂǇ ƌƌŝǀĞĂƚWt>^ƚĂƌƚĂŶĚtĂƌŵƋƵŝƉŵĞŶƚ>ŽĂĚŽƵƚdŽŽůƐĂŶĚĚĚŝƚŝŽŶĂů>ƵďƌŝĐĂƚŽƌ͘ƌƌŝǀĞĂƚ<'&ŽWĞƌŵŝƚĂŶĚ:^ DKƚŽ>ŽĐĂƟŽŶĂŶĚ^ƉŽƚƵƉƚŽǁĞůů͘ZŝŐƵƉ͘ϭϲϬǁŝƌĞĂŶĚWͬdůƵ ďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝůŽǁĂŶĚϮϱϬϬW^/ŚŝͲWĂƐƐ͘Z/,ͬǁϮΗ Z^ͬǁϯ͘ϱϱΗĞůů'ƵŝĚĞƚŽϲϭϱϮΖ^>D;ϲϭϳϬΖZ<ͿͲtͬdͲ>ĂƚĐŚͲtͬdϱƚŝŵĞƐĚŽǁŶƚŚĞŶƐŚĞĂƌŽŶƉŝĐŬƵƉWKK,͘Z/,ͬǁϮΗ :ͬǁϯ͘ϱϱΗĞůů'ƵŝĚĞƚŽϲϭϱϮΖ^>Dǁͬƚ>ĂƚĐŚǁͬƚϴ:ĂƌůŝĐŬƐƵƉƚŽϮϱϬϬ>^ŽŵĞ&ƌĞĞWKK,KK,ͬǁůŝŶĞdŽŽů^ƚƌŝŶŐ ;ŽŵƉůĞƚĞ^ƚƌŝŶŐͿ͘KK,^ƚĂŶĚďǇĨŽƌͲůŝŶĞͲŽŶƌƌŝǀĂůŽd'^DͲĂĚĚ<ͲůŝŶĞƚŽWĞƌŵŝƚĂŶĚ:^͘ZŝŐĚŽǁŶůŝŶĞ&ŝƐŚͲ dŚĞŶWŝĐŬĂĐŬƵƉƚŽZƵŶ^ǁĞĚŐĞ͘Z/,ͬǁϯ͘ϭϮΗ^ǁĞĚŐĞƚŽϵϯϲϵΖ^>D;ϵϯϴϳΖZ<ͿEŽKďƐƚƌƵĐƚŝŽŶƐŝŶƚƵďŝŶŐŽƌƉĂƚĐŚĞƐ ŝŶ,ŽůĞWKK,͘KK,ZŝŐŽǁŶ͘ D/Zh&ŽǆĞŶĞƌŐǇdhηϴ͘Ϯϰ,ƌKWƚĞƐƚǁŝƚŶĞƐƐŶŽƚŝĨŝĐĂƚŝŽŶƉƌŽǀŝĚĞĚƚŽ^ƚĂƚĞ͘ ƚƚĞƐƚŝŶŐKWϮϱϬͬϯϬϬϬƉƐŝ͘ ŽŝůĐŽƵŶƚĞƌŝƐƐƵďƐƚĂŶƚŝĂůůǇŽĨĨĂŐĂŝŶ͘ Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) Patch Setting Record 10/12/2021 Please include current contact information if different from above. 37' (6HW Received By: d 11/17/2021 By Abby Bell at 4:00 pm, Nov 15, 2021 From:McLellan, Bryan J (CED) To:Ryan Rupert Cc:Dan Marlowe; Juanita Lovett; Regg, James B (CED) Subject:RE: KU 11-07X(PTD#217-041) Date:Wednesday, November 10, 2021 5:08:00 PM Ryan, Yes, your proposal to use CT to blow down the well with nitrogen is acceptable with the following conditions: 1. Provide 24 hrs notice to AOGCC to witness CT BOP test to 2500 psi. 2. Provide BOP stack diagram to AOGCC prior to performing BOP test. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Wednesday, November 10, 2021 4:20 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: KU 11-07X(PTD#217-041) Bryan- As you may have seen in the daily ops summaries, we’ve perf’d both sundried intervals in gas producer KU 11-07x(PTD#217-041) from open sundry #321-480. Unfortunately it looks like both are making water, and the well has fallen from ~1100mcfd to below 300mcfd. Per the approved contingency in the sundry we are in progress of patching both zones off. Given that there’s 3000’+ TVD of open wellbore below these 2 zones, Hilcorp would like to ask permission to RU with CT and perform an N2 lift to unload the water below the patches in KU 11- 07x after they’re set. We would follow the standard nitrogen procedure per the approved sundry, and test CT BOP’s to 2500psi per the sundry contingency. Only change would be adding CT instead of bullheading N2. Is this change acceptable to the AOGCC? Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) PERF 08/25/2021 Please include current contact information if different from above. 11/02/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/20/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) Perf 09/27/2021 Please include current contact information if different from above. 37' (6HW Received By: d 10/25/2021 By Abby Bell at 12:21 pm, Oct 25, 2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/20/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) Production Profile 10/04/2021 Report 10/04/2021 Please include current contact information if different from above. 37' (6HW Received By: 10/25/2021 By Abby Bell at 12:19 pm, Oct 25, 2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ___ 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 9,799 feet see schematic feet true vertical 9,702 feet N/A feet Effective Depth measured 9,420 feet 5,566 feet true vertical 9,330 feet 5,523 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 5,566' MD 5,523' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ryan Rupert Authorized Title:Operations Manager Contact Email: Contact Phone:777-8503 WINJ WAG 868 Water-Bbl MD 120' 1,511' 1 Oil-Bbl measured true vertical Packer 4-1/2"9,799' 6,040' 9,702' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field - Tyonek Gas Pool 1N/A measured TVD Tubing Pressure 317 Kenai Unit (KU) 11-07X N/A FEE A028142 6,090' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 217-041 50-133-20662-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-350 45 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 180 Authorized Signature with date: Authorized Name: 220 Casing Pressure Liner 1,148 0 Representative Daily Average Production or Injection Data 120' 1,511' 6,090' 9,799' Conductor Surface Intermediate Production 7,500psi Casing Structural 16" 10-3/4" 7-5/8" Length 6,890psi 5,210psi Collapse 2,480psi 4,790psi ryan.rupert@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 8,430psi 120' 1,506' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 8:08 am, Sep 17, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.16 16:09:38 -08'00' Dan Marlowe (1267) RBDMS HEW 9/17/2021 Perforate New Pool BJM 11/10/21 DSR-9/17/21 SFD 9/20/2021 Updated by DMA 08-27-21 SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PBTD = 9,420’ MD / 9,330’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95” Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 18’ 4.276”11”Tubing Hanger 2 5,566’ 4.276”6.875”10 ft Swell Packer (Water Swell) 3 9,420’3.958”CIBP set on 8/25/17 4 9,455’3.958”CIBP Set on 8/17/17 5 9,500’3.958”CIBP Set on 8/1/17 6 9,540 3.958”CIBP Set on 7/15/17 7 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments LB3 6,707’6,726’6,650’6,669’19’Blga/Upr Ty 8/25/21 Open LB3B 6,754’’6,771’6,697’6,713’17’Blga/Upr Ty 8/25/21 Open LB4C 7,007 7,018’6,947’6,957’11’Blga/Upr Ty 8/25/21 Open 7,024’7,035’6,963’6,974’11’Blga/Upr Ty 8/25/21 Open D-1 8,856’8,876’8,773’8,793’20’Blga/Upr Ty 7/29/21 Open D-2 8,983’9,036’8,899’8,951’53’Ty Gas Pool #1 1/21/20 Open D-3B 9,274’9,305’9,186’9,216’31’Ty Gas Pool #1 8/25/17 Open 9,313’9,323’9,224’9,234’10‘Ty Gas Pool #1 7/8/21 Open D-4A 9,431 9,445'9,340’9,354’14’Ty Gas Pool #1 8/18/17 Plugged Isolated D-4B 9,461’9,476’9,370’9,385’15’Ty Gas Pool #1 8/1/17 Plugged Isolated D-4C 9,511’9,535’9,419’9,443’24’Ty Gas Pool #1 7/17/17 Plugged Isolated 9,546’9,569’9,454’9,476’23’Ty Gas Pool #1 6/23/17 Plugged Isolated D-5 9,595 9,600'9,502’9,507’5’Ty Gas Pool #1 6/12/17 Plugged Isolated 9,600 9,620'9,507’9,526’25’Ty Gas Pool #1 6/9/17 Plugged Isolated 4 3 5 6 7 D-3B D-2 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job. 4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2”6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6050’. ToC is at 5200’ MD Note: Comingled production from Tyonek gas Pool #1 and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B: Last ran: 08/03/21 D-1 LB3 LB3B LB4C LB3 6,707’6,726’6,650’6,669’19’Blga/Upr Ty 8/25/21 Open LB3B 6,754’’6,771’6,697’6,713’17’Blga/Upr Ty 8/25/21 Open LB4C 7,007 7,018’6,947’6,957’11’Blga/Upr Ty 8/25/21 Open 7,024’7,035’6,963’6,974’11’Blga/Upr Ty 8/25/21 Open D-1 8,856’8,876’8,773’8,793’20’Blga/Upr Ty 7/29/21 Open Comingled production from Tyonek gas Pool #1 and Beluga/Upper Tyonek pools. Rig Start Date End Date E-Line 7/29/21 8/25/21 08/25/2021 - Wednesday Spot equipment. PTW, JSA, SIMOPS w/rig 401. Rig up lubricator. PT to250 psi low and 2,500 psi high. FTP - 45/1,025.8 mcf. RIH w/#1 Gas Gun, 2-7/8" x 11' HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Told ok to perf from 7,024' to 7,035' w/FTP39.8 psi/Rate 1,072.7 mcf. Spot and fire gun. After 5 min - 38.2/1,067 mcf, 10 min - 37/979K and 15 min - 52/1,035 mcf. POOH. All shots fired/Gun wet. RIH w/#2 Gas Gun, 2-7/8" x 11' HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 7,007' to 7,018' with FTP 43/1,131mcf. Spotted and fired gun. After 5 min - 44/1,139 mcf, 10 min - 40/1,067 mcf and 15 min - 40/1,055 mcf. POOH. All shots fired/Gun wet. RIH w/#3 Gas Gun, 2-7/8" x 17' HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 6,754' to 6,771' w/FTP 40 psi/1,155 mcf rate. After 5 min - 48/1,222 mcf, 10 min - 49/1,225 mcf and 15 min - 49/1,228 mcf. POOH. All shots fired/Gun wet. RIH w/#4 Gas Gun, 2-7/8" x 17' HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 6,707' to 6,726' with 55ftp/1,288 mcf. After 5 min - 54/1,280mcf, 10 min - 53/1,256mcf and 15 min - 53 ftp/1,245mcf. POOH. All shots fired/Gun Wet. Rig down off tree, put soap launcher on and turn over to field. 08/26/2021 - Thursday No activity to report. 08/27/2021- Friday Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 08/31/2021 - Tuesday No activity to report. 08/28/2021 - Saturday No activity to report. 08/30/2021 - Monday No activity to report. No activity to report. 08/29/2021 - Sunday No activity to report. See attached additional daily logs for perfs from 8856-8876' shot 7/29/21 and Production Log on 8/3/21. bjm perf from 6,754' to 6,771' o perf from 6,707' to 6,726' o perf from 7,007' to 7,018' o perf from 7,024' to 7,035' Rig Start Date End Date Eline 7/29/21 8/25/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 08/03/2021 - Tuesday RU SL unit. PT SL PCE to 2500 psi. RIH w/ 10' 1-3/4" weight bar / 1¾" jars / 7' long spangs / 3.71" gauge ring. Tag @ 9406.6' RKB. POOH. RIH w/ 10' 1-3/4" weight bar /7' long spangs / PL tools. Log up 1st pass 9385' to 8800'. Log down 2nd pass 8800' to 9385'. Log up 3rd pass 9385' to 8800'. Log down 4th pass 8800' to 9385'. Log up 5th pass 9385' to 8800'. Log down 6th pass 8800' to 9385'. 1st stationary stop @ 9375'. 2nd stationary stop @ 9150'. 3rd stationary stop @ 8930'. 4th stationary stop @ 8800'. RIH & tag @ 9406.6' RKB. Jewelery log passed RA tags to 7300'. POOH. DL PL tools. Data Good. FL at 9322'. RD SL. 08/25/2021 - Wednesday Spot equipment. PTW, JSA, SIMOPS w/rig 401. Rig up lubricator. PT to250 psi low and 2,500 psi high. FTP - 45/1,025.8 mcf. RIH w/#1 Gas Gun, 2-7/8" x 11' HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Told ok to perf from 7,024' to 7,035' w/FTP39.8 psi/Rate 1,072.7 mcf. Spot and fire gun. After 5 min - 38.2/1,067 mcf, 10 min - 37/979K and 15 min - 52/1,035 mcf. POOH. All shots fired/Gun wet. RIH w/#2 Gas Gun, 2-7/8" x 11' HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 7,007' to 7,018' with FTP 43/1,131mcf. Spotted and fired gun. After 5 min - 44/1,139 mcf, 10 min - 40/1,067 mcf and 15 min - 40/1,055 mcf. POOH. All shots fired/Gun wet. RIH w/#3 Gas Gun, 2-7/8" x 17' HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 6,754' to 6,771' w/FTP 40 psi/1,155 mcf rate. After 5 min - 48/1,222 mcf, 10 min - 49/1,225 mcf and 15 min - 49/1,228 mcf. POOH. All shots fired/Gun wet. RIH w/#4 Gas Gun, 2-7/8" x 17' HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 6,707' to 6,726' with 55ftp/1,288 mcf. After 5 min - 54/1,280mcf, 10 min - 53/1,256mcf and 15 min - 53 ftp/1,245mcf. POOH. All shots fired/Gun Wet. Rig down off tree, put soap launcher on and turn over to field. 07/29/2021 - Thursday Sign in. Mobe to location. PTW and JSA. Spot equip and rig up lubricator. PT lubricator to 250 psi low and 2500 psi high. FTP - 30 psi/800K rate. RIH w/ 2-7/8" x 20' HC gas gun, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf (TY_D1) from 8,856' to 8,876'. Spot and fired gun with 800K rate at 30 psi. After 5 min - 1.7mm/88 psi, 10 min - 1.9mm/91 psi and 15 min - 1.9mm/99 psi. POOH. All shots fired/gun wet. Monitor well. Gave up .7 bbl water 30 min after perf and its flowing 2.2mm/120 psi. Rig down equipment and leave field. 1 Winston, Hugh E (CED) From:Juanita Lovett <jlovett@hilcorp.com> Sent:Wednesday, November 10, 2021 1:51 PM To:Ryan Rupert; McLellan, Bryan J (CED) Cc:Dan Marlowe; Chris Kanyer; Daniel Yancey; Chad Helgeson Subject:RE: [EXTERNAL] KU 11-07X (PTD 217-041) 10-404 Attachments:KU 11-07X Well Operations Summary 07-29-21 to 08-25-21.pdf Hello Bryan, Please see the updated well summary attached. Thank you, Juanita From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Tuesday, November 9, 2021 4:08 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Ryan Rupert <Ryan.Rupert@hilcorp.com>; Chris Kanyer <ckanyer@hilcorp.com>; Daniel Yancey <dyancey@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com> Subject: RE: [EXTERNAL] KU 11‐07X (PTD 217‐041) 10‐404 Apologies Bryan. Sorry that was missed on my side. I did check and confirm that all the records from those 2 additional days are correctly documented, and no additional days of work are out there. Juanita can send over the full composite of work done relating to this sundry. Halliburton does the interpretation of the PLT’s and then I QC it before sending over to yall. Specifically in this well’s case, we shot all the intervals after the PLT while flowing, so by difference we could see what each new zone contributed. Ryan Rupert Kenai Ops Engineer (13146) 907-301-1736 (Cell) 907-777-8503 (Office) From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Thursday, November 4, 2021 10:23 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: [EXTERNAL] KU 11‐07X (PTD 217‐041) 10‐404 Ryan, 2 The 10‐404 for Sundry 321‐350 does not include the operation reports for the perfs added on 7/29/21 nor the PLT on 8/3/21. Could you send that information and I’ll add it to the 10‐404? Also, please describe how you will allocate production between pools since the PLT was done before adding the last 4 perf intervals? Do you personally ensure allocation is done correctly according to the PLT splits, or is it someone else? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 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: ___N2 / Patch____ 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): 9,799'none Casing Collapse Structural Conductor Surface 2,480psi Intermediate 4,790psi Production 7,500psi Liner 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: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 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 5,566'MD / 5,523'TVD ; N/A. ryan.rupert @hilcorp.com 9,702'9,420'9,330'~1585psi see schematic Swell Packer ; N/A Tubing Size: 1,511' Tubing Grade: 9,702'8,430psi 5,210psi 6,040'6,890psi 3800 Centerpoint Dr, Suite 1400 6,090' 9,799' COMMISSION USE ONLY Authorized Name: PRESENT WELL CONDITION SUMMARY Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 217-041 50-133-20662-00-00 Hilcorp Alaska, LLC N/A Anchorage Alaska 99503 120' 1,506' KU 11-07X FEE A028142 Kenai Gas Field - Tyonek Gas Pool 1 & Beluga/Upper Tyonek Pool Length Size CO 510B TVD Burst N/A MD 6,090' 1,511' 120' 7-5/8" 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. 120' 4-1/2"9,799' 16" 10-3/4" Authorized Signature: October 2, 2021 N/A Perforation Depth MD (ft): See Attached Schematic Perforation Depth TVD (ft): Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 3:07 pm, Sep 17, 2021 321-480 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.17 15:01:07 -08'00' Dan Marlowe (1267) DLB 09/17/2021BJM 9/23/21 10-404 DSR-9/17/21 X dts 9/24/2021 JLC 9/24/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.24 16:13:51 -08'00' RBDMS HEW 9/27/2021 Well: KU 11-07X Date: 9/17/2021 Well Name:KU 11-07x API Number:50-113-20662-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:217-041 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Max. Expected BHP:~ 2200 psi @ 6,159’ TVD Based on offset RFT from 2017 Max. Potential Surface Pressure ~ 1585 psi Based on 0.1psi/ft to surface Well Summary KU 11-07X is a steady comingled gas production well producing from the Tyonek Gas Pool #1 and the Beluga/Upper Tyonek Pool. It flows at 1000mcfd and <5 bwpd. Given the opportunity uphole in the Beluga/Upper Tyonek Pool, additional perforations are proposed below. CO 510B Rule #5 allows comingling of the Beluga/Upper Tyonek Pool, Tyonek Pool #1, and the Kenai Deep Tyonek Pools, as long as certain post-perf production logging requirements are met. The well was comingled on 7/29/21, and a production log obtained 8/3/21. It will be due for another production log next calendar year, no later than 9/2/22 The goal of this project is to perforate uphole sands in the Beluga/Upper Tyonek Pool, to add production to the well Notes Regarding Wellbore Condition x Min ID = 3.833” (4-1/2” drift ID) x Max Inclination = 11 degrees at 6308’ MD x Drifts o 8/25/21: EL perf’d down to 7035’ MD with 2-7/8” guns as long as 20’. No tight spots. o 7/8/21: EL perf’d down to 9323’ MD with a 10’ x 2-7/8” gun. No tight spots. o 1/21/21: EL shot two perf sets of 27’ x 2-7/8” guns as deep as 9036’ MD. (no tag) o 8/25/17: EL set CIBP at 9420’ MD, then perf’d 31’ above. Nitrogen Risk x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) x Ensure all crews are aware of stop work authority Well: KU 11-07X Date: 9/17/2021 E-Line Perf 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 2,500 psi High. 3. Consult with OE to determine if Nitrogen is needed to pressure up wellbore 4. RU Nitrogen Truck 5. Pressure up wellbore per OE 6. Rig up perf gun (Likely 2-7/8” 4-6 spf) 7. RIH and perforate the sand listed in the table below, per Geo/RE. Sand Perforation Top (MD) Perforation Bottom (MD) Perforation Top (TVD) Perforation Bottom (TVD) Total Footage (MD) LB1B ±6,210’±6,240’±6,159’±6,189’±30' LB1C ±6,299’±6,307’±6,246’±6,254’±8' Consult with OE for what WHP’s to use. May be shot while flowing Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Trudi Hallett (RE): 301-6657 ii. Ben Siks (Geo): 229-0865 d. Above perfs will be shot in the Beluga/Upper Tyonek Pool. This comingling is covered by CO 510B 8. RD E-Line Unit and turn well over to production. Contingency EL Plug or Patch 1. MIRU E-line, PT lubricator to 250 psi low / 2,500 psi high 2. RIH W/ GPT tool and find fluid level 3. RU Nitrogen Truck a. Push water back into formation b. Use GPT tool to confirm water level is below interval to perf c. Consult OE for pressure to leave on well for perforating 4. Once fluid level is below interval to isolate, MU 4-1/2” patch or plug 5. RIH and set plug or patch per OE. a. IF the entirety of the Tyonek Pool #1 is plugged off, 25’ of cement will need to be dump bailed on top of the plug b. Only a plug between the two pools would require cement. 6. RD E-Line Unit and turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Updated by DMA 08-27-21 SCHEMATIC Well: KU 11-07X PTD:217-041 API:50-133-20662-00-00 PBTD = 9,420’ MD / 9,330’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95” Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 18’ 4.276”11”Tubing Hanger 2 5,566’ 4.276”6.875”10 ft Swell Packer (Water Swell) 3 9,420’3.958”CIBP set on 8/25/17 4 9,455’3.958”CIBP Set on 8/17/17 5 9,500’3.958”CIBP Set on 8/1/17 6 9,540 3.958”CIBP Set on 7/15/17 7 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments LB3 6,707’6,726’6,650’6,669’19’Blga/Upr Ty 8/25/21 Open LB3B 6,754’’6,771’6,697’6,713’17’Blga/Upr Ty 8/25/21 Open LB4C 7,007 7,018’6,947’6,957’11’Blga/Upr Ty 8/25/21 Open 7,024’7,035’6,963’6,974’11’Blga/Upr Ty 8/25/21 Open D-1 8,856’8,876’8,773’8,793’20’Blga/Upr Ty 7/29/21 Open D-2 8,983’9,036’8,899’8,951’53’Ty Gas Pool #1 1/21/20 Open D-3B 9,274’9,305’9,186’9,216’31’Ty Gas Pool #1 8/25/17 Open 9,313’9,323’9,224’9,234’10‘Ty Gas Pool #1 7/8/21 Open D-4A 9,431 9,445'9,340’9,354’14’Ty Gas Pool #1 8/18/17 Plugged Isolated D-4B 9,461’9,476’9,370’9,385’15’Ty Gas Pool #1 8/1/17 Plugged Isolated D-4C 9,511’9,535’9,419’9,443’24’Ty Gas Pool #1 7/17/17 Plugged Isolated 9,546’9,569’9,454’9,476’23’Ty Gas Pool #1 6/23/17 Plugged Isolated D-5 9,595 9,600'9,502’9,507’5’Ty Gas Pool #1 6/12/17 Plugged Isolated 9,600 9,620'9,507’9,526’25’Ty Gas Pool #1 6/9/17 Plugged Isolated 4 3 5 6 7 D-3B D-2 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job.4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2”6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6050’. ToC is at 5200’ MD Note: Comingled production from Tyonek gas Pool #1 and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B:Last ran: 08/03/21 D-1 LB3 LB3B LB4C Updated by DMA 08-27-21 PROPOSED SCHEMATIC Well: KU 11-07X PTD:217-041 API:50-133-20662-00-00 PBTD = 9,420’ MD / 9,330’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95” Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 18’ 4.276”11”Tubing Hanger 2 5,566’ 4.276”6.875”10 ft Swell Packer (Water Swell) 3 9,420’3.958”CIBP set on 8/25/17 4 9,455’3.958”CIBP Set on 8/17/17 5 9,500’3.958”CIBP Set on 8/1/17 6 9,540 3.958”CIBP Set on 7/15/17 7 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments LB1B ±6,210’±6,240’±6,159’±6,189’±30'Blga/Upr Ty TBD Proposed LB1C ±6,299’±6,307’±6,246’±6,254’±8'Blga/Upr Ty TBD Proposed LB3 6,707’6,726’6,650’6,669’19’Blga/Upr Ty 8/25/21 Open LB3B 6,754’’6,771’6,697’6,713’17’Blga/Upr Ty 8/25/21 Open LB4C 7,007 7,018’6,947’6,957’11’Blga/Upr Ty 8/25/21 Open 7,024’7,035’6,963’6,974’11’Blga/Upr Ty 8/25/21 Open D-1 8,856’8,876’8,773’8,793’20’Blga/Upr Ty 7/29/21 Open D-2 8,983’9,036’8,899’8,951’53’Ty Gas Pool #1 1/21/20 Open D-3B 9,274’9,305’9,186’9,216’31’Ty Gas Pool #1 8/25/17 Open 9,313’9,323’9,224’9,234’10‘Ty Gas Pool #1 7/8/21 Open D-4A 9,431 9,445'9,340’9,354’14’Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’9,476’9,370’9,385’15’Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’9,535’9,419’9,443’24’Ty Gas Pool #1 7/17/17 Plugged 9,546’9,569’9,454’9,476’23’Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600'9,502’9,507’5’Ty Gas Pool #1 6/12/17 Plugged 9,600 9,620'9,507’9,526’25’Ty Gas Pool #1 6/9/17 Plugged 4 3 5 6 7 D-3B D-2 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job.4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2”6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6050’. ToC is at 5200’ MD Note: Comingled production from Tyonek gas Pool #1 and Beluga/Upper Tyonek pools. Requires a production log each calendar year, and not more than 13 months between logs per CO 510B:Last ran: 08/03/21 D-1 LB3 LB3B LB4C LB1B/C STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/26/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: KU 11-07X (PTD 217-041) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW Received By: 08/30/2021 By Abby Bell at 4:52 pm, Aug 26, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: DATE: 08/10/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X (PTD 217-041) Production Profile 08/03/2021 Please include current contact information if different from above. 37' (6HW Received By: 08/10/2021 By Abby Bell at 3:53 pm, Aug 10, 2021 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/03/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL KU 11-07X (PTD 217-041) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. Received By: 08/03/2021 37' (6HW By Abby Bell at 1:44 pm, Aug 03, 2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___N2 / Patch____ 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): 9,799'none Casing Collapse Structural Conductor Surface 2,480psi Intermediate 4,790psi Production 7,500psi Liner 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: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 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 Signature: July 28, 2021 N/A Perforation Depth MD (ft): See Attached Schematic Perforation Depth TVD (ft): 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. 120' 4-1/2"9,799' 16" 10-3/4" TVD Burst N/A MD 6,090' 1,511' 120' 7-5/8" N/A Anchorage Alaska 99503 120' 1,506' KU 11-07X FEE A028142 Kenai Gas Field - Tyonek Gas Pool 1 & Beluga/Upper Tyonek Pool Length Size CO 510B PRESENT WELL CONDITION SUMMARY Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 217-041 50-133-20662-00-00 Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 6,090' 9,799' COMMISSION USE ONLY Authorized Name: Tubing Grade: 9,702'8,430psi 5,210psi 6,040'6,890psi 5,566'MD / 5,523'TVD ; N/A. ryan.rupert @hilcorp.com 9,702'9,420'9,330'~1200psi see schematic Swell Packer ; N/A Tubing Size: 1,511' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:06 pm, Jul 13, 2021 321-350 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.13 12:39:41 -08'00' Taylor Wellman (2143) DSR-7/13/21BJM 7/21/21 SFD 7/22/2021 10-404 dts 7/22/2021 JLC 7/22/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.22 16:27:22 -08'00' RBDMS HEW 7/26/2021 Well Prognosis Well: KU 11-07X Date: 7/12/2021 Well Name:KU 11-07x API Number:50-113-20662-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:217-041 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) Max. Expected BHP:~ 1200 psi @ 7,635’ TVD (Based on max offset well observed pressure) Max. Potential Surface Pressure ~ 1200 psi (Based on max BHP to surface) Well Summary KU 11-07X is a steady Tyonek Gas Pool #1 producer. It flows at 900mcfd and 2 bwpd. Given the opportunity uphole in the Beluga/Upper Tyonek Pool, additional perforations are proposed below. CO 510B Rule #5 allows comingling of the Beluga/Upper Tyonek Pool, Tyonek Pool #1, and the Kenai Deep Tyonek Pools, as long as certain post-perf production logging requirements are met. This job will comingle the existing Tyonek Gas Pool #1 perfs with proposed perfs in the Beluga/Upper Tyonek Pool. The goal of this project is to perforate uphole sands in the Beluga/Upper Tyonek Pool, to add production to the well Notes Regarding Wellbore Condition x Min ID = 3.833” (4-1/2” drift ID) x Max Inclination = 11 degrees at 6308’ MD x Drifts o 7/8/21: EL perf’d down to 9323’ MD with a 10’ x 2-7/8” gun. No tight spots. o 1/21/21: EL shot two perf sets of 27’ x 2-7/8” guns as deep as 9036’ MD. (no tag) o 8/25/17: EL set CIBP at 9420’ MD, then perf’d 31’ above. Nitrogen Risk x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) x Ensure all crews are aware of stop work authority perforate uphole sands in the Beluga/Upper Tyonek Pool, This job will comingle the existing Tyonek Gas Pool #1 perfs with proposed perfs in the Beluga/Upper Tyonek Pool. CO 510B Rule #5 allows comingling of the Beluga/Upper Tyonek Pool, Tyonek Pool #1,and the Kenai Deep Tyonek Pools, as long as certain post-perf production logging requirements are met. T Well Prognosis Well: KU 11-07X Date: 7/12/2021 E-Line Perf 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 2,500 psi High. 3. Consult with OE to determine if Nitrogen is needed to pressure up wellbore 4. RU Nitrogen Truck 5. Pressure up wellbore per OE 6. Rig up perf gun (Likely 2-7/8” 4-6 spf) 7. RIH and perforate the sand listed in the table below, per Geo/RE. Sand Perforation Top (MD) Perforation Bottom (MD) Perforation Top (TVD) Perforation Bottom (TVD) Total Footage (MD) LB3 ±6,707'±6,726'±6,650'±6,669'19' LB3B ±6,754'±6,771'±6,696'±6,713'17' LB4C ±7,007'±7,018'±6,947'±6,958'11' LB4C ±7,024'±7,035'±6,963'±6,974'11' LB5B ±7,164'±7,173'±7,101'±7,110'9' LB5C ±7,183'±7,195'±7,120'±7,132'12' TY_73_1 ±7,388'±7,408'±7,323'±7,343'20' UT_1A ±7,446'±7,471'±7,381'±7,406'25' TY_D1 ±8,856'±8,876'±8,773'±8,793'20' Consult with OE for what WHP’s to use. May be shot while flowing Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Trudi Hallett (RE): 301-6657 ii. Ben Siks (Geo): 229-0865 d. Above perfs will be shot in the Beluga/Upper Tyonek Pool. This comingling with currently open Tyonek Pool #1 is covered by CO 510B 8. RD E-Line Unit and turn well over to production. Well Prognosis Well: KU 11-07X Date: 7/12/2021 SL/EL Production log: Must be run within 30 days of commencement of comingled production, after well has stabilized per CO 510B 1. RU EL/SL and PT lubricator to 250 psi low / 2,500 psi high 2. RIH with PLT logging tool 3. Acquire dynamic passed and stop counts per OE (dependent on what’s shot) 4. Confirm good data, then RDMO EL/SL Contingency EL Plug or Patch 1. MIRU E-line, PT lubricator to 250 psi low / 2,500 psi high 2. RIH W/ GPT tool and find fluid level 3. RU Nitrogen Truck a. Push water back into formation b. Use GPT tool to confirm water level is below interval to perf c. Consult OE for pressure to leave on well for perforating 4. Once fluid level is below interval to isolate, MU 4-1/2” patch or plug 5. RIH and set plug or patch per OE. a. IF the entirety of the Tyonek Pool #1 is plugged off, 25’ of cement will need to be dump bailed on top of the plug b. Only a plug between the two pools would require cement. 6. RD E-Line Unit and turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations RIH with PLT logging tool Updated by CRR 7/12/2021 SCHEMATIC Kenai Gas Field Well: KU 11-07X PTD:217-041 API:50-133-20662-00-00 PBTD = 9,420’ MD / 9,330’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95”Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 18’ 4.276”11”Tubing Hanger 2 5,566’ 4.276”6.875”10 ft Swell Packer (Water Swell) 3 9,420’3.958”CIBP set on 8/25/17 4 9,455’3.958”CIBP Set on 8/17/17 5 9,500’3.958”CIBP Set on 8/1/17 6 9,540 3.958”CIBP Set on 7/15/17 7 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments D-2 8,983’9,036’8,899’8,951’53’Ty Gas Pool #1 1/21/20 Open D-3B 9,274’9,305’9,186’9,216’31’ Ty Gas Pool #1 8/25/17 Open D-3B 9,313’9,323’9,224’9,234’10‘Ty Gas Pool #1 7/8/21 Open D-4A 9,431 9,445'9,340’9,354’14’Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’9,476’9,370’9,385’15’Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’9,535’9,419’9,443’24’Ty Gas Pool #1 7/17/17 Plugged D-4C 9,546’9,569’9,454’9,476’23’Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600'9,502’9,507’5’Ty Gas Pool #1 6/12/17 Plugged D-5 9,600 9,620'9,507’9,526’25’Ty Gas Pool #1 6/9/17 Plugged 4 3 5 6 7 D-3B D-2 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job.4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2”6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6050’. ToC is at 5200’ MD Updated by CRR 7/12/2021 PROPOSED SCHEMATIC Kenai Gas Field Well: KU 11-07X PTD:217-041 API:50-133-20662-00-00 PBTD = 9,420’ MD / 9,330’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95” Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 18’ 4.276”11”Tubing Hanger 2 5,566’ 4.276”6.875”10 ft Swell Packer (Water Swell) 3 9,420’3.958”CIBP set on 8/25/17 4 9,455’3.958”CIBP Set on 8/17/17 5 9,500’3.958”CIBP Set on 8/1/17 6 9,540 3.958”CIBP Set on 7/15/17 7 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments Proposed perfs per sundry D-2 8,983’9,036’8,899’8,951’53’Ty Gas Pool #1 1/21/20 Open D-3B 9,274’9,305’9,186’9,216’31’Ty Gas Pool #1 8/25/17 Open D-3B 9,313’9,323’9,224’9,234’10‘Ty Gas Pool #1 7/8/21 Open D-4A 9,431 9,445'9,340’9,354’14’Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’9,476’9,370’9,385’15’Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’9,535’9,419’9,443’24’Ty Gas Pool #1 7/17/17 Plugged D-4C 9,546’9,569’9,454’9,476’23’Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600'9,502’9,507’5’Ty Gas Pool #1 6/12/17 Plugged D-5 9,600 9,620'9,507’9,526’25’Ty Gas Pool #1 6/9/17 Plugged 4 3 5 6 7 D-3B D-2 OPEN HOLE / CEMENT DETAIL 10-3/4”13-1/2” Hole: 141bbls 12# class A lead cement followed by 61bbls of 15.4# Class A tail cement. Full returns throughout job. 78bbls cement back to Surface 7-5/8"9-7/8” Hole: 138bbls 12.5# class G lead cement followed by 38bbls of 15.8# Class G tail cement. 25bbls lost throughout job.4/30/17 CBL (AKEL) reported a ToC of 2500’ MD. 4-1/2”6-3/4” Hole: 114bbls 15.3# class A cement. No losses throughout job. 5/16/17 Radial CBL shows solid cement up to 6050’. ToC is at 5200’ MD STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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: _______ 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 9,799 feet See schematic feet true vertical 9,702 feet N/A feet Effective Depth measured 9,420 feet 5,566 feet true vertical 9,330 feet 5,523 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 5,566' MD 5,523' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ryan Rupert Authorized Title:Operations Manager Contact Email: Contact Phone:777-8503 WINJ WAG 836 Water-Bbl MD 120' 1,511' 1 Oil-Bbl measured true vertical Packer 4-1/2"9,799' 6,040' 9,702' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field - Tyonek Gas Pool 1N/A measured TVD Tubing Pressure 353 Kenai Unit (KU) 11-07X N/A FEE A028142 6,090' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 217-041 50-133-20662-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-332 34 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 300 Authorized Signature with date: Authorized Name: 180 Casing Pressure Liner 836 0 Representative Daily Average Production or Injection Data 120' 1,511' 6,090' 9,799' Conductor Surface Intermediate Production 7,500psi Casing Structural 16" 10-3/4" 7-5/8" Length 6,890psi 5,210psi Collapse 2,480psi 4,790psi ryan.rupert@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 8,430psi 120' 1,506' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 8:21 am, Jul 13, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.12 22:55:20 -08'00' Taylor Wellman (2143) SFD 7/16/2021BJM 10/12/21 DSR-7/13/21 RBDMS HEW 7/14/2021 Rig Start Date End Date E-Line 7/8/21 7/8/21 07/13/2021 - Tuesday No activity to report. 07/10/2021 - Saturday No activity to report. 07/12/2021 - Monday No activity to report. No activity to report. 07/11/2021 - Sunday No activity to report. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KU 11-07X 50-133-20662-00-00 217-041 07/07/2021 - Wednesday No activity to report. 07/08/2021 - Thursday Sign in. Mobe to location. PTW and JSA. Rig up equipment and lubricator to 250 psi low and 2,500 psi high. Well flowing 800k/30 psi. RIH w/2-7/8"x10' HC, 6 spf, 60 deg phase gas gun and tie into Las log from town. Send log to town. Get ok to perf from 9,313' to 9,323'. Spot and fired gun with FTP -31 psi/822K. After 5 min - 32.9 psi/861K, 10 min - 31.9 psi/848K and 15min - 32.4 psi/844K. All shots fired/gun was we and bull plug was packed with sand/soap looking stuff. Rig down and turn well over to field. Mobe to KBU 42-06Y to perforate. Had 20-30' of kinked line. Cut off line and put new rope socket on line before going to 42-06Y. 07/09/2021- Friday o perf from 9,313' to 9,323'. Spot and fired gun w Updated by TRH 7/9/2021 SCHEMATIC Kenai Gas Field Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00-00 PBTD = 9,420’ MD / 9,330’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 109 X-56 Weld 15” Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95” Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958” Surf 9,799’ 1 16” 10-3/4” 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11” Tubing Hanger 2 5,566’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 9,420’ 3.958” CIBP set on 8/25/17 4 9,455’ 3.958” CIBP Set on 8/17/17 5 9,500’ 3.958” CIBP Set on 8/1/17 6 9,540 3.958” CIBP Set on 7/15/17 7 9,591’ 3.958” CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments D-2 8,983’ 9,036’ 8,899’ 8,951’ 53’ Ty Gas Pool #1 1/21/20 Open D-3B 9,274’ 9,305’ 9,186’ 9,216’ 31’ Ty Gas Pool #1 8/25/17 Open D-3B 9,313’ 9,323’ 9,224’ 9,234’ 10‘ Ty Gas Pool #1 7/8/21 Open D-4A 9,431 9,445' 9,340’ 9,354’ 14’ Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’ 9,476’ 9,370’ 9,385’ 15’ Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’ 9,535’ 9,419’ 9,443’ 24’ Ty Gas Pool #1 7/17/17 Plugged D-4C 9,546’ 9,569’ 9,454’ 9,476’ 23’ Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600' 9,502’ 9,507’ 5’ Ty Gas Pool #1 6/12/17 Plugged D-5 9,600 9,620' 9,507’ 9,526’ 25’ Ty Gas Pool #1 6/9/17 Plugged 4 3 5 6 7 D-5 D-4C D-4C D-4B D-4A D-3B D-2 D-3B D-3B 9,313’ 9,323’9,224’9,234’10‘Ty Gas Pool #1 7/8/21 Open ,,,,y //p 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: ___N2 / Patch____ 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): 9,799'none Casing Collapse Structural Conductor Surface 2,480psi Intermediate 4,790psi Production 7,500psi Liner 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: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 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 Signature: July 15, 2021 N/A Perforation Depth MD (ft): See Attached Schematic 6,090' 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. 120' 4-1/2"9,799' 16" 10-3/4" 120' 7-5/8" N/A TVD Burst N/A MD 120' 1,506' KU 11-07X FEE A028142 Kenai Gas Field - Tyonek Gas Pool 1 Length Size CO 510B PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 217-041 50-133-20662-00-00 Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic Perforation Depth TVD (ft):Tubing Size: 1,511' 9,702'8,430psi 5,210psi 6,040'6,890psi6,090' 1,511' 9,799' 5,566'MD / 5,523'TVD ; N/A. ryan.rupert@hilcorp.com 9,702'9,420'9,330'~351psi see schematic Swell Packer ; N/A m n P 66 t _ c Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:46 am, Jul 02, 2021 321-332 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.01 16:17:55 -08'00' Taylor Wellman (2143) BJM 7/2/21 SFD 7/2/2021 DSR-7/6/21 dts 7/6/2021 10-404 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.07 13:04:23 -08'00' RBDMS HEW 7/7/2021 Well Prognosis Well: KU 11-07x Date: 7/1/2021 Well Name:KU 11-07x API Number:50-113-20662-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:217-041 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) Maximum Expected BHP:~ 1275 psi @ 9234’ TVD Offset well max observed pressure Max. Potential Surface Pressure:~ 351 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface Well Summary KU 11-07x is an online gas producer making ~800mcfd and 2 bwpd. The goal of this project is to perforate the D3B lobe to add production to the well Notes Regarding Wellbore Condition x Min ID = 3.833” (4-1/2” drift ID) x Max Inclination = 11 degrees at 6308’ MD x Drifts o 1/21/21: EL shot two perf sets of 27’ x 2-7/8” guns as deep as 9036’ MD. (no tag) o 8/25/17: EL set CIBP at 9420’ MD, then perf’d 31’ above. Nitrogen Risk x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) x Ensure all crews are aware of stop work authority Well Prognosis Well: KU 11-07x Date: 7/1/2021 E-Line Perf 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 2,500 psi High. 3. Consult with OE to determine if Nitrogen is needed to pressure up wellbore 4. RU Nitrogen Truck 5. Pressure up wellbore per OE 6. Rig up perf gun (Likely 2-7/8” 4-6 spf) 7. RIH and perforate the sand listed in the table below, per Geo/RE. Sand Perforation Top (MD) Perforation Bottom (MD) Perforation Top (TVD) Perforation Bottom (TVD) Total Footage (MD) D3B ±9,313’±9,323’±9,224’±9,234’10‘ Consult with OE for what WHP to use. May be shot while flowing Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Trudi Hallett (RE): 301-6657 ii. Ben Siks (Geo): 229-0865 8. RD E-Line Unit and turn well over to production. Contingency EL Plug or Patch 1. MIRU E-line, PT lubricator to 250 psi low / 2,500 psi high 2. RIH W/ GPT tool and find fluid level 3. RU Nitrogen Truck a. Push water back into formation b. Use GPT tool to confirm water level is below interval to perf c. Consult OE for pressure to leave on well for perforating 4. Once fluid level is below interval to isolate, MU 4-1/2” patch or plug 5. RIH and set plug or patch per OE. 6. RD E-Line Unit and turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Updated by CRR 6-30-21 SCHEMATIC Kenai Gas Field Well: KU 11-07X PTD:217-041 API:50-133-20662-00 PBTD = 9,420’ MD / 9,330’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95”Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 18’ 4.276”11”Tubing Hanger 2 5,566’ 4.276”6.875”10 ft Swell Packer (Water Swell) 3 9,420’3.958”CIBP set on 8/25/17 4 9,455’3.958”CIBP Set on 8/17/17 5 9,500’3.958”CIBP Set on 8/1/17 6 9,540 3.958”CIBP Set on 7/15/17 7 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments D-2 8,983’9,036’8,899’8,951’53’Ty Gas Pool #1 1/21/20 Open D-3B 9,274’9,305’9,186’9,216’31’ Ty Gas Pool #1 8/25/17 Open D-4A 9,431 9,445'9,340’9,354’14’Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’9,476’9,370’9,385’15’Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’9,535’9,419’9,443’24’Ty Gas Pool #1 7/17/17 Plugged D-4C 9,546’9,569’9,454’9,476’23’Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600'9,502’9,507’5’Ty Gas Pool #1 6/12/17 Plugged D-5 9,600 9,620'9,507’9,526’25’Ty Gas Pool #1 6/9/17 Plugged 4 3 5 6 7 D-5 D-4C D-4C D-4B D-4A D-3B D-2 Updated by CRR 6-30-21 PROPOSED SCHEMATIC Kenai Gas Field Well: KU 11-07X PTD:217-041 API:50-133-20662-00 PBTD = 9,420’ MD / 9,330’ TVD TD = 9,799’ MD / 9,702’ TVD KB = 18’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven to Set Depth 109 X-56 Weld 15”Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95”Surf 1,511’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875"Surf 6,090’ 4-1/2" Production 12.6 L-80 DWC/C HT 3.958”Surf 9,799’ 116” 10-3/4” 4-1/2” JEWELRY DETAIL No.Depth ID OD Item 1 18’ 4.276”11”Tubing Hanger 2 5,566’ 4.276”6.875”10 ft Swell Packer (Water Swell) 3 9,420’3.958”CIBP set on 8/25/17 4 9,455’3.958”CIBP Set on 8/17/17 5 9,500’3.958”CIBP Set on 8/1/17 6 9,540 3.958”CIBP Set on 7/15/17 7 9,591’3.958”CIBP Set w/ 10’ cement (tag 9,571) on 6/21/17 7-5/8” 2 RA-D 7,391’ RA-C 7,924’ RA-B 8,914’ RA-A 9,405’ PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Pool Date Comments D-2 8,983’9,036’8,899’8,951’53’Ty Gas Pool #1 1/21/20 Open D-3B 9,274’9,305’9,186’9,216’31’Ty Gas Pool #1 8/25/17 Open D-3B ±9,313’±9,323’±9,224’±9,234’10‘Ty Gas Pool #1 TBD PROPOSED D-4A 9,431 9,445'9,340’9,354’14’Ty Gas Pool #1 8/18/17 Plugged D-4B 9,461’9,476’9,370’9,385’15’Ty Gas Pool #1 8/1/17 Plugged D-4C 9,511’9,535’9,419’9,443’24’Ty Gas Pool #1 7/17/17 Plugged D-4C 9,546’9,569’9,454’9,476’23’Ty Gas Pool #1 6/23/17 Plugged D-5 9,595 9,600'9,502’9,507’5’Ty Gas Pool #1 6/12/17 Plugged D-5 9,600 9,620'9,507’9,526’25’Ty Gas Pool #1 6/9/17 Plugged 4 3 5 6 7 D-5 D-4C D-4C D-4B D-4A D-3B D-2 D-3B STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS DECEIVE® FEB 2 4 2020 1. Operations Abandon LJ Plug Perforations Fracture Stimulate LJ Pull Tubing U AULeRojGutdown Li Performed: Suspend ❑ Perforate Q Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: N2 Q 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development Q Stratigraphic❑ Exploratory ❑ Service ❑ 217-041 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-133-20662-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEE A028142 Kenai Unit (KU) 11-07X 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kenai Gas Field - Beluga/Upper Tyonek Gas Pool/Tyonek Gas Pool 1 11. Present Well Condition Summary: 9420, 9455, 9500, Total Depth measured 9,799 feet Plugs measured 9540, 9591 feet true vertical 9,702 feet Junk measured N/A feet Effective Depth measured 9,420 feet Packer measured 5,566 feet true vertical 9,330 feet true vertical 5,523 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 120' 16 120' 120' Surface 1,511' 10-3/4" 1,511' 1,506' 5,210psi 2,480psi Intermediate 6,090' 7-5/8" 6,090' 6,040' 6,890psi 4,790psi Production 9,799' 4-1/2" 9,799' 9,702' 8,430psi 7,500psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / L-80 9,799' MD 9,702' TVD Packers and SSSV (type, measured and true vertical depth) Swell Pkr; N/A 5,566'MD 5,523' 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:1 0 1391 2 280 80 Subsequent to operation: 10 1624 2 310 68 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas � WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-560 Authorized Name: Taylor Wellman 777-8449 Contact Name: Ted Kramer Authorized Title: Ope ns Panager Contact Email: 1kramer@hilc0m.wm Authorized Signature: Date: of 1 2-i Contact Phone: 777-8420 Form 10-404 Revised 4/201 -.Z 7-40 RBDMS � FEB 2 4 2020 Submit Original Only �?�---�"�'�' Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KU 11-07X E -Line 50-133-20662-00 1 217-041 1/21/20 1 1/21/20 Daily Operations: 01/21/2020 -Tuesday Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 3,500 psi high. Well was shut in at 0630 hrs. RIH w/ 2-7/8" x 26' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to pert from 9,010' to 9,036' with 252.5 psi. Spotted and fired gun. Pressure went to 253.4 psi when shot. After 5 min - 247.9 psi, 10 min - 243.4 psi and 15 min - 239.3 psi. POOH. All shots fired and gun was dry. RIH w/ 2-7/8" x 27' HC Razor, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 8.983' to 9.010' with 239.2 psi. Spotted and fired gun. Pressure went to 239.9 psi when shot. After 5 min - 237.8 psi, 10 min - 236.3 psi and 15 min - 235.0 psi. POOH. All shots fired and gun was dry. Rig down off Well and turn over to field. Kenai Gas Field SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00 nrP Al -U. LIA: KB=18' 1G" P 1 10-3/4" V 2 7-5/8" RA -D 7,391' RA -C 7,924' e RA -B 8,914' RA -A 9,405' W D-2 i'M D -3B 1 3 E D -4A i 4 llaD-48 , 5 ED -4C 6 ED -4C 7 PBTD = 9,420' MD / 9,330' TVD TD = 9,799' MD / 9,702' TVD CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16" Conductor -Driven to Set Depth 109 X-56 Weld 15" Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95" Surf 1,511' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 6,090' 4-1/2" Production 12.6 L-80 DWC/C HT 3.958" Surf 9,799' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.276" 11" Tubing Hanger 2 5,566' 4.276" 6.875" 10 ft Swell Packer (Water Swell) 3 9,420' 3.958" D-313 CIBP set on 8/25/17 4 9,455' 3.958" 6 CIBP Seton 8/17/17 5 9,500' 3.958" 9,431 CIBP Set on 8/1/17 6 9,540 3.958" 14' CIBP Seton 7/15/17 7 9,591' 3.958" 9,476' CIBP Set w/ 10' cement (tag 9,571) on 6/21/17 PERFORATION DATA Zone Top MD Btm MD Top TVD Btm TVD SPF Amt Date Comments D-2 8,983' 9,036' 8,899' 8,951' 6 53' 1/21/20 Open D-313 9,274' 9,305' 9,186' 9,216' 6 31' 8/25/17 2 -7/8- D -4A 9,431 9,445' 9,340' 9,354' 6 14' .8/18/17 Plugged D-48 9,461' 9,476' 9,370' 9,385' 6 15' 8/1/17 Plugged D -4C 9,511' 9,535' 9,419' 9,443' 6 24' 7/17/17 Plugged D -4C 9,546' 9,569' 9,454' 9,476' 6 23' 6/23/17 Plugged D-5 9,595 9,600' 9,502' 9,507' 6 5' 6/12/17 Plugged D-5 9,600 9,620' 9,507' 9,526' 6 25' 6/9/17 Plugged Updated by DMA 01-29-20 THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Cas Conservation Commission Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool/Tyonek Gas Pool Permit to Drill Number: 217-041 Sundry Number: 319-560 Dear Mr. York: 333 Wesf Sevenfh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. a o g c c. a l a s k a. g o v Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, gy DATED this\n day of December, 2019. IBDWIS DEC 19 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 nor 25 oan RECEWED DEC 11 2019 Orf /Z/J3/1J AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well 0 Operations shutdown ❑ Suspend © Perforate I] Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: N2 ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 217-041 ` 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20662-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510A Will planned perforations require a spacing exception? YesQ No ❑✓ KU 11-7X 9. Property Designation (Lease Number): 10. Field/Pool(s): FEE A028142 Kenai Gas Field - Beluga/Upper Tyonek Gas Pool/Tyonek Gas Pool 1 11. PRESENT WELL CONDITION SUMMARY Total DeptJMD(ft): Total Depth TVD (ft): EffectiveDepth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,7 9,702' 9,420' 9,330' —685 N/A N/A CaLength Size MD TVD Burst Collapse StruCond 120' 16" 120' 120' Sur1,511' 10-3/4" 1,511' 1,506' 5,210psi 2,480psi Interm6,090' 7-5/8" 6,090' 6,040' 6,890psi 4,790psi Production 9,799' 4-1/2" 9,799' 9,702' 1 8,430psi 7,500psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6# / L-80 9,799' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A;Swell Pkr N/A; 5,566'MD/5,523TVD 12. Attachments: Proposal Summary Wellbore schematic r 13. Well Class after proposed work: Detailed Operations Program BOP Sketch I] Exploratory ❑ Stratigraphic ❑ Development [a Service 14. Estimated Date for 15. Well Status after proposed work: December 20th, 2019 Commencing Operations: ❑ WINJ ❑ WDSPL OIL ❑ Suspended ❑ GAS ❑� WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Christina Twogood Authorized Title: Operations Manager Contact Email: ctWO Ood hllcor .com Contact Phone: 777-8443 Authorized Signature: Date: 16 Vtc U COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 - Plug Integrity ❑ BOP Test 13Mechanical Integrity Test ElLocation Clearance Q Other: RBDMS 96-IDEC 19 2019 Post Initial Injection MIT Req'd? Yes I] No ❑ u Spacing Exception Required? Yes No Subsequent Form Required: /0 APPROVED BY \ Approved by: COMMISSIONER THE COMMISSION Date: Ix -,z-IT Submft Form and Fo 4 e tl o1 Approved appli i I' 1 g rom the date of a roval. �J' PP Attachments in Duplicate R Ilileoro Alaska, LL Well Prognosis Well: KU 11-07X Date:12/9/2019 Well Name: KU 11-07X API Number: 50-133-20662-00-00 Current Status: Gas Producer Leg: N/A Estimated Start Date: December 2&, 2019 Rig: E -Line Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 217-041 First Call Engineer: Christina Twogood (907) 777-8443 (907) 378-7323 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (985) 867-0665 (C) AFE Number: Max. Expected BHP: Max. Potential Surface Pressure: Brief Well Summary "' 1,606 psi @ 9,216' TVD "' 685 psi (Based on offset well RFT data from 04/04/2017) (Based on expected BHP and gas gradient to surface (0.10psi/ft)) In 2017, KU 11-07X was drilled and completed in the Tyonek D by Hilcorp. It was perforated and produced from the D313 only. The purpose of this work/sundry is to add perforations in the Tyonek D2 sands. Notes Regarding Wellbore Condition K • The well is currently producing 1400 MCFD, 3 BWPD. • Current completion is within the Tyonek Gas Sands (TYONEK Pool 1). • Minimum ID is 3.958" • Last tag @ 9,450' KB w/ 2" DD bailer on 8/21/2017. Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast (venting nitrogen during this job). • Ensure all crews are aware of stop job authority. E -Line Procedure 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low/ 3,500 psi High. 2. RIH with GPT tool and find fluid level. If fluid is over the depth of the new perfs, discuss using Nitrogen with the Operations Engineer. 3. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4. RU pert guns. Well Prognosis Well: KU 11-07X tia.o.0 niaak., a Date: 12/9/2019 5. RIH and perforate the following interval: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Tyonek D-2 +8,983' +9,036' +8,899' 1 +8,951' +53' a. Well may be shot flowing. b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. e. Use Gamma/CCL to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. All perforations in table above are located in the Tyonek Gas Pool 1 based on Conservation Order No. 510A. rim ff •10TO. 7. RD a -line. 8. Turn well over to production. (Test SSV with -in 5 days of stable production on well — notify AOGCC 24hrs before testing) E -line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low/ 3,500 psi High. 3. RIH and set 4-1/2" Casing Patch or set 4-1/2" CIBP above the zone and dump 35' of cement on top of the plug. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure — N2 Operations Kenai Gas Field SCHEMATIC Well: KU 11-07X 11 PTD: 217-041 ourP Alo=kn. LIA, API: 50-133-20662-00 KB=18' 6" Q •I � 1 1 1;�� ' r n$ 2 7-5/8" RA -D 7,391' RA -C 7,924' RA -B 8,914' RA -A 9,405' 3 E D -4A 1, q 1iiD-4B 5 ED -4C 6 1= -D -4C ! 7 4-1/2" PBTD = 9,420' MD / 9,330' TVD TD = 9,799' MD / 9,702' TVD CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16" Conductor -Driven to Set Depth 109 X-56 Weld 15" Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95" Surf 1,511' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 6,090' 4-1/2" Production 12.6 L-80 DWC/CHT 3.958" Surf 9,799' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.276" 11" Tubing Hanger 2 5,566' 4.276" 6.875" 10 k Swell Packer (Water Swell) 3 9,420' 3.958" D -4A CIBP set on 8/25/17 4 9,455' 3.958" 6 CIBP Set on 8/17/17 5 9,500' 3.958" 9,461' CIBP Set on 8/1/17 6 9,540 3.958" 15' CIBP Set on 7/15/17 7 9,591' 3.958" 9,535' CIBP Set w/ 10' cement (tag 9,571) on 6/21/17 PFRF()RATIrIrd r)ATA Zone Top VID Btm VID Top TVD Btm TVD SPP Amt Date Comments D-313 9,274' 9,305' 9,186' 9,216' 6 31' 8/25/17 2-7/8" D -4A 9,431 9,445' 9,340' 9,354' 6 14' 8/18/17 Plugged D-413 9,461' 9,476' 9,370' 9,385' 6 15' 8/1/17 Plugged D -4C 9,511' 9,535' 9,419' 9,443' 6 24' 7/17/17 Plugged D -4C 91546' 9,569' 9,454' 91476' 6 23' 6/23/17 Plugged D-5 9,595 9,600' 9,502' 9,507' 6 5' 6/12/17 Plugged D-5 9,600 9,620' 9,507' 9,526' 6 25' 6/9/17 Plugged Updated by CMT 12-9-19 Flilaocp Alnnkn. LLG KB=18' 16" 1 w 10-3/4" PROPOSED SCHEMATIC 9 or,J 6RA-D 7,391' � RA -C 7,924' FRA--B8,91,V] RA -A 9,405' 4-1/2" 3� D-2 D-38 3 D -4A 4 3-4B 5 )-4C 6 )AC 7 PBTD = 9,420' MD / 9,330' TVD TD = 9,799' MD / 9,702' TVD Kenai Gas Field Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16" Conductor - Driven to Set Depth 109 X-56 Weld 15" Surf 120' 10-3/4" Surf. Csg 45.5 L-80 Buttress 9.95" Surf 1,511' 7-5/8" Intermediate. 29.7 L-80 BTC 6.875" Surf 6,090' 4-1/2" Production 12.6 L-80 DWC/C HT 3.958" Surf 9,799' JEWELRY DETAIL No. Depth ID 00 Item 1 18' 4.276" 11" Tubing Hanger 2 5,566' 4.276" 6.875" 10 k Swell Packer (Water Swell) 3 9,420' 3.958" 0-3B CIBP set on 8/25/17 4 9,455' 3.958" 6 CIBP Set on 8/17/17 5 9,500' 3.958" 9,431 CIBP Seton 8/1/17 6 9,540 3.958" 14' CIBP Set on 7/15/17 7 9,591' 3.958" 9,476' CIBP Set w/ 10' cement (tag 9,571) on 6/21/17 PFRPOPATIOKI r1ATA Zone Top MD Btm MD Top TVD Btm TVD SPF Amt Date Comments D-2 ±8,983' ±9,036' ±8,899' ±8,951' 6 ±53' Proposed TBD 0-3B 9,274' 9,305' 9,186' 9,216' 6 31' 8/25/17 2-7/8" D -4A 9,431 9,445' 9,340' 9,354' 6 14' 8/18/17 Plugged D -4B 9,461' 9,476' 9,370' 9,385' 6 15' 8/1/17 Plugged D -4C 9,511' 9,535' 9,419' 9,443' 6 24' 7/17/17 Plugged D -4C 9,546' 9,569' 9,454' 9,476' 6 23' 6/23/17 Plugged D-5 9,595 9,600' 9,502' 9,507' 6 5' 6/12/17 Plugged D-5 9,600 9,620' 9,507' 9,526' 6 25' 6/9/17 Plugged Updated by CMT 12-9-19 STANDARD WELL PROCEDURE flih•xp Alaska, LIT NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) 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Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By:j/� Date: " /J im ' `44, • • 2 -1-0 4 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 777-8308 Tele: 907 1ary, Alaska,iau: RECEIVED Fax: 907 777-8510 E-mail: snolan@hilcorp.com SEP 19 2017 DATE 09/18/17 AOGCC DATA LOGGED feg/2o11 M. K.BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X Core Data CD1: 50X 9/18/2017 8:38 AM File folder 200X 9/18/2017 8:38 AM File folder Hilcorp Energ KU 11-07X CEC Final Data H... 7/11/2017 12:22 PM Microsoft Excel War... 28 KB F ';Hilcorp KU 11-07X HH-94985 Rotary Core An... 7/11/2017 12:22 PM Microsoft Excel Wor... 93 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Date: Received By: / KhUhlliblj • STATE OF ALASKA • SEP 12 2017p ALASKA OIL AND GAS CONSERVATION COMMISSION A WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil ❑ Gas 0 • SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1 b.Well Class: 20AAC 25.105 20AAC 25.110 Development 2 • Exploratory ❑ GINJ ❑ WINJ ❑ WAGE] WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp.,Susp.,or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 8/25/2017 217-041 /317-193 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 April 17,2017 50-133-20662-00-00 • 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 203'FSL, 1003'FWL,Sec 6,T4N, R11 W,SM,AK • May 3,2017 KU 11-07X • Top of Productive Interval: 9. Ref Elevations: KB: 81.6 . 17. Field/Pool(s): Kenai Gas Field 667'FNL,937'FWL, Sec 7,T4N, R11 W,SM,AK • GL:63.6 BF:63.6 • Tyonek Gas Pool 1 Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 720'FNL, 1013'FWL, Sec 7 T4N, R11 W,SM,AK • 9,420'MD/9,330'TVD • FEE A028142 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 271914 • y- 2362258 • Zone- 4 • 9,799'MD/9,701'TVD• , N/A TPI: x- 271916 y- 2361290 Zone- 4 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 271991 y- 2361235 Zone- 4 N/A N/A 5. Directional or Inclination Survey: Yes IA (attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MDITVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include,but are not limited to:mud log,spontaneous potential, gamma ray,caliper, resistivity, porosity,magnetic resonance,dipmeter,formation tester,temperature, cement evaluation,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary HNGS-GR 04/27/2017; ECS-GR 04/27/2017; HNGS—GR 05/06/2017; ECS-GR 05/06/2017 Radial Cement Bond Log • L{//a" c 79. Formation Log 2"/5"MD/TVD; Formation Log 2"MD/TVD; LWD Combo MD/TVD;Gas Ratio MDITVD; Drilling Dynamics MD/TVD . ROP-DGR-GM-ADR-ALD-CTN 2"/5"MD; DGR-GM-ADR-ALD-CTN 2"/5"ND 6,,,,,L._. ,s• $�,, a l,q,1,.. — 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16" 109 X-56 Surface 120' Surface 120' Driven Driven 10-3/4" 45.5 L-80 Surface 1,511' Surface 1,506' 13-1/2" L-327 sx/T-280 sx 78.5 bbls 7-5/8" 29.7 L-80 Surface 6,090' Surface 6,040' 9-7/8" L-134 sx/T-169 sx 4-1/2" 12.6 L-80 Surface 9,779' Surface 9,682' 06 L-650 sx ti; 24.Open to production or injection? Yes Q • No ❑ 25.TUBIG RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number; Date Perfd): N/A **See attached schematic for detail** ',,)1,;d-'LL-.. 1(tlV26.ACID, FRACTURE,CEMENT SQUEEZE,ETC. - •.' Was hydraulic fracturing used during completion? Yes❑ No D. q.,/251/1-- Per 20 AAC 25.283(i)(2)attach electronic and printed information ''`:RIFIEn DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED L'- 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 8/9/2017 Flowing Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 9/2/2017 24 Test Period .0.•0 1881 0 N/A N/A Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 640 235 24-Hour Rate .—p 0 1881 0 N/A Form 10-407 Revised 5/2017 y 3--l ES CONTI Dept RBDMS '.- m SEP 2 1 207bmit ORIGINIAL only • • 28.CORE DATA Conventional Core(s): Yes ❑ No 2 • Sidewall Cores: Yes Q No ❑ If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. Will submit when analysis is complete. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑✓ • Permafrost-Top If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval 9,274'Tyonek D3B 9,186' information, including reports,per 20 AAC 25.071. Tyonek D2 8,984 8,900 Tyonek D3B 9,271 9,183 Tyonek D4A 9,485 9,394 Upper Beluga 4,716 4,685 Lower Beluga 6,131 6,081 Tyonek 1B 7,469 7,403 Formation at total depth: Tyonek 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys,Casing and Cement reports, Surveillance Data. Information to be attached includes, but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report, production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Paul Mazzolini Contact Name: Cody Dinger Authorized Title:Drilling Manager Contact Email: cdinger C(1�hilcorp.com Authorized .� C61/ .7Contact Phone: 777_8389 Signature: Date: 7 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC,no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated.Each segregated pool is a completion. Item 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing,Ground Level,and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 19: Report the Division of Oil&Gas/Division of Mining Land and Water: Plan of Operations(LO/Region YY-123), Land Use Permit(LAS 12345), and/or Easement(ADL 123456)number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26.(Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including,but not limited to: porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including,but not limited to:core analysis,paleontological report,production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only • • Kenai Gas Field II SCHEMATIC Well: KU 11-07X PTD: 217-041 API: 50-133-20662-00 Hllrarp Alaska,LLC KB=18' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 16" !J 16„ Conductor-Driven 109 X-56 Weld 15" Surf 120' 1 %'" to Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.95" Surf 1,511' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 6,090' 4-1/2" Production 12.6 L-80 DWC/C HT 3.958" Surf 9,779' 10-3/4" G I s.1l' JEWELRY DETAIL 4 No. Depth ID OD Item 1 18' 4.276" 11" Tubing Hanger 2 5,566' 4.276" 6.875" 10 ft Swell Packer(Water Swell) 1 3 9,420' 3.958" CIBP set on 8/25/17 r 4 9,455' 3.958" CIBP Set on 8/17/17 y " 5 9,500' 3.958" CIBP Set on 8/1/17 6 9,540 3.958" CIBP Set on 7/15/17 7 9,591' 3.958" CIBP Set w/10'cement(tag 9,571)on 6/21/17 1 PERFORATION DATA 45i' ^ Zone Top MD Btm MD Top TVD Btm TVD SPF Amt Date Comments C,-, * , + , D-3B 9,274' 9,305' 9,186' 9,216' 6 31' 8/25/17 2-7/8" /'C� t.a D-4A 9,431 9,445' 9,340' 9,354' 6 14' 8/18/17 Plugged .$7j)1. t* 'c 2 0-4B 9,461' 9,476' 9,370' 9,385' 6 15' 8/1/17 Plugged r a D-4C 9,511' 9,535' 9,419' 9,443' 6 24' 7/17/17 Plugged 7-5/8" ! 0-4C 9,546' 9,569' 9,454' 9,476' 6 23' 6/23/17 Plugged D-5 9,595 9,600' 9,502' 9,507' 6 5' 6/12/17 Plugged v RA-D 7,391' D-5 9,600 9,620' 9,507' 9,526' 6 25' 6/9/17 Plugged RA-C 7,924' • . RA-B 8,914' A• I♦b �' "1 N 5 RA-A 9,405' fry Lir.. 41 6 7 k' 4-1/2" .:A iii PBTD=9,420' MD/9,330'TVD TD=9,799' MD/9,702'TVD Updated by CJD 09-12-17 • • Hilcorp Energy Company Composite Report .14 Well Name: KEU KU 11-07X Field: Kenai Gas Field County/State: ,Alaska l(LAT/LONG): ovation(RKB): 18 API#: 50-133-20662-00-00 Spud Date: 4/18/2017 Job Name: 1711232D KU 11-07X Drilling Contractor SLR 169 AFE#: AFE$: 4/15/2017 Continue disconnected electrical lines. Work on KGF 14-6 pad entrance road. Move generator#3 module,and rig water tank.Load derrick,draw works skid on trailer. Haul miscellaneous support equip.;Move sub base. Haul pony walls and substructure to KGF 14-6 pad. Set and center pony walls/substructure. Set water tank/doghouse. move HPU unit,mud pumps,and pits to KU 11-07X.;Set HPU unit. Set derrick. Spot doghouse and water tank.;Set iron roughneck on rig floor,Run electrical lines,steam lines,air,water,Pason lines.Set Herculite for cat walk,set catwalk.Hook up all ground lines to each module.Locate lines with Prod.;lnstall two grounding rods for rig.Fill boiler,reset pits 9/10 module for correct spacing.Set Gen 3.Hook up electrical interconnects,power up rig.Install hand rails on rig floor.Set gas buster.;Prepare derrick for raising. Hook up new iron roughneck.Hook all steam lines up.Continue to re-connect all interconnects between modules.SIMOPS:Remove old herculite/felt lay out on;KU 14-05,and place debris in C&D dumpsters.Seam seal herculite containment on KU 11- 07X.Continue to hook up mud lines between mud pits.Load water into rig bulk water tank from water well.;Raise derrick.Hook up lines to the dog house,hook up dead man,spool up drilling line.Prepare to scope derrick up.Mobilize and stage service shack's.MWD/Mud Man/Mud logger. 4/16/2017 Continue rigging up over KU 11-07X. Continue hooking electrical and water lines. Slip and cut 133'of drilling line. Prep and scope derrick up,install torque tube,stand pipe. Set up Handy-Berm.;Set rig floor wind walls. Set water tank and cement silos. Continue moving auxiliary equipment from KGF 41-7 pad to 14- 6 pad. Rig down office trailers and mobilize. Set office trailers.;Function test new iron roughneck. Mob top drive to rig floor and begin rigging up top drive.Install ground rod for office trailers.;Hook up all whip checks on steam lines.Fill mud tanks with 237 bbl water.Put 70 mesh screens on shakers.Function test top drive, test mud pumps,bring handling tools to floor,install new saver sub;Bring to rig floor the,sub racks,subs,TIW,dart valve,install new wash pipe in TD.Install bails,elevators.Work on rig acceptance checklist.Adjust Kelly hose suspension angle.;Remove stabbing board.Install guides in tuggers on rig floor.Repair valve in trio tank.ffill valve) Accent ria 0 0600 hrs 4/17/2017 Stage riser,DSA,and spacer spools in cellar,and N/U same. Install flow line,fill up line,and bleeder. Run Pason lines to service shacks.;Set pit wind walls. Strapped and tallied BHA components. Change out grabber box on top drive. Total safety on site to rig up and tested all gas alarms.Install 4"valves.;Secure riser to sub base. Flood stack and check for leaks. PT surface lines,Kelly hose and top drive. Test ESD system.;Install wear bushing. Rack and tally 17 joints of HWDP,jars. P/U and rack back HWDP.;Strap and tally 60 joints DP.RE-adjust Kelly hose suspension angle.;Pick up and stand back 30 stands of 4.5"CDS 40 DP.;Pick up and hang new 4 foot tongs.Mobilize all BHA components to the cat walk,skate area.Check all straps,tally,lengths,OD's ID's,#'s,Prepare floor equipment for working BHA.;Pick up BHA#1.13.5"HDBS bit,Sperry MM,MWD.Orient.TF0=54°.;Spud well.Drill with 450 GPM,60 RPM,3 to 10 WOB,300 PSI PP.Bury 5 stands of HWDP to make room for monels,and jars.340'.Final PP 900 psi©450 GPM.20k UP/DN/ROT,Run 30 bph water.;Pump out of hole @ 340'MD.One pump in idle.Hole in good shape.200+viscosity.Keep running 35 bph water to build volume back to 250 bbls.;Rack back 5 stands of HWDP. Prepare to Pick up 2-8"monel collars,and 2-6.75"monel flex collars.Crew change.;Hauled xx bbls solids to G&I,Cum xx bbls Hauled xx bbls fluid to G&I,Cum xx bbls Hauled x bbls cement G&I,Cum x bbls Daily losses downhole x bbls,Cum x bbls 1 4/18/2017 Pick up and RIH with drill collars,HWDP and Jars to 340'no issues.;Continue drilling 13.5"hole from 340'to 1522':sliding as needed to maintain WP 09. KOP 600'. Sliding parameters ROP 200-250 fph,WOB 5-15K,500 gpm/1250 psi.;Rotating Parameters:150-250 fph,WOB 5-18K,80 rpms/7500 ft-lbs,500 1 gpm/1368 psi. Distance to Plan:9.55',Hugh 9.1'/Left 2.89';Circ&cond for wiper trip.;POOH from 1522'to 270'with no issues.RIH to 1522'with no issues&no fill.;Pump sweep&circ&cond.;POOH from 1522'to 175'(Racked back HWDP&jars);UD 13 1/2"surface BHA(Racked back flex collars)Bit Grade= 2,2,WT,A,E,I,BU,TD;Clean&clear rig floor.Pull wear ring.;R/U casing bails,elevators.Dummy run hanger.R/U slips&power tongs.;M/U 10 3/4",45.5#,L-80, BTC casing shoe track.;Hauled 343 bbls solids to G&I,Cum 343 bbls Hauled 308 bbls fluid to G&I,Cum 308 bbls Hauled 0 bbls cement G&I,Cum 0 bbls IlaiIv Inc os down hnla r)hhls Cum 0 hhls 4/19/2017 M/U shoe track,and check floats-good. Baker lock to 4th joint. RIH with 10-3/4"casing,M/U hanger and landing joint and land casing at 1511'with no issues. PUW 70K,SOW 58K.;PJSM rig up cement head and manifold.;Circulate and condition hole staging pumps up to 260 gpm/245 psi reciprocating casing. Continue to rig up SLB cementers.;MU plug launcher and hardline,SLB loaded lines with 5 bbls water and checked for leaks.SLB pressure tested lines at 1500 islelow 2500 high,good tests.Rig pumped 20.5 bbls 10 ppg MudPush II at 3.3 bpm,;68 psi,and shut down.SLB dropped bottom plug and pumped 141 bbls(327 :" 51 sx)12.0 ppg Class A lead cement at 5.7 bpm 322 psi,followed by 61 bbls(280sx)15.4 ppg Class A tail cement at 4.6 bpm 320 psi;SLB dropped top plug,then (f' displaced with 10 bbls water followed by 128.5 bbls 9 ppg Spud Mud at 5 bpm,640 psi.Slowed to 3 bpm with 8.5 bbl to go.Bumped the plug and held 1250 psi et (FCP of 650 psi);for 5 minutes,bled off and floats held.Bled back 2.5 bbls to truck.Had 20.5 bbls MudPush II return to surface and 78.5 bbls of 12.0 ppg lead_„ 34` cement to surface.Cemnet was added to both lead;and tail cement at'A ppb.Mix water temp at 75 deg.Pumped 100%excess on lead and tail.Reciprocated the ) string throughout the job.Had no losses.CIP at 15:54 hrs,4/19/17.;BIow back cement lines/manifold/standpipe. Rig down cement equipment. Clean up cellar. Rig down casing elevators and bails.;Clean riser&UD landing joint.Install pack off&test.;N/D riser,flow line&hole fill line.;N/U well head&test void 500/3000 psi(good).;N/U spacer spool,BOPE,HCR Choke&kill lines.N/U koomy Iines.;Hauled 43 bbls solids to G&I,Cum 386 bbls Hauled 417 bbls fluid to G&I,Cum 725 bbls Hauled 78 bbls cement G&I,Cum 78 bbls Daily losses down hole 0 bbls,Cum 0 bbls • • 4/20/2017 Continue N/U BOPE,install choke and kill lines,install accumulator lines. Function rams.;Rig up to test BOPE,rig up test chart. Set test plug. Fill stack and flush lines.;Test BOPE's 250/3500 psi(annular 250/2500 psi)on 4.5"test joint. AOGCC Matt Herrera witness test. Total safety tested all gas alarms. Flange between spacer spool and single gate leaking,tighten;up flange x2. F/P HCR manual,rebuild and test good. Flange between spacer spool and single gate leaking again during blind test. Retighten and test blinds-good.;Test manual&electric choke(good).;Pull test plug&set 10"ID wear ring.;Stage 140 jts drill pipe &strap.Pick up&rack back in derrick 120 jts 41/2"DP.;Hauled 0 bbls solids to G&I,Cum 386 bbls Hauled 0 bbls fluid to G&I,Cum 725 bbls Hauled 0 bbls cement G&1,Cum 78 bbls Daily losses down hole 0 bbls,Cum 0 bbls 4/21/2017 Continue to P/U and rack back drill pipe,total of 90 stands in derrick.;Rig up and test casing to 2600 psi for 30 minutes-good test. Blow down lines and rig down.;Make up 9-7/8"directional BHA,Varel VM516 PDC bit,7"Sperry motor with 1.5°bend(0.3 rev/gal),measure RFO(MWD-MTR 211.43°). Upload tools, shallow pulse test-good. Load sources.;RIH with HWDP and jars to 732'. Single in the hole to 1356'.;Wash down from 1356'to 1419'400 gpm/1200psi 30 rpms tag up on cement Drill out shoe,track.observe top plug at 1424',float collar at 1426'and shoe at 1511'(all on depth).;Drill FE with 3-10K WOB,400 gpm/1200 psi100-250 psi of differential,30 rpms 5500-6500 ft-lbs of torque.Drill rat hole to 1522'.;Drill 20'new hole from 1522'to 1542'.;Displace spud mud to 8.9ppg 6%KCL PHPA.;Clean out shaker beds&possum belly.;Circ&cond mud for FIT.8.9 ppg in/out.;R/U testing equipment.FIT to 12.5 ppg.(285 psi with 8.9 ppg mud)R/D testing equipment.;Drill ahead from 1542'to 2351'sliding as needed,500 gpm 11500 psi,PU wt 58 k,So wt 56 k,ROT wt 58 k,58 rpm,5/7 k ft lbs trq,ECD 9.37 ppg w/8.95 ppg mud wt.;Distance to plan;10.33',High 5.46'/Left 8.77'.;Hauled 22 bbls solids to G&I,Cum 408 bbls Hauled 388 bbls fluid to G&I,Cum 1113 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 0 bbls,Cum 0 bbls 4/22/2017 Continue drilling 9-7/8"hole from 2351'to 3033',sliding as needed to maintain WP 09,Mad Pass all slides. BHA has a neutral assembly requiring minimal sliding.;Sliding Parameters:WOB 3-5K,ROP 200 fph,480gpm/1300 psi with 100 psi differential. Rotating parameters:WOB 3-5K,ROP 180 fph,480 gpm/1300 psi,80rpms/7500 ft-lbs.;Pump sweep and circulate hole clean,480 gpm/1200 psi rotating 80 rpms. Monitor hole,static.;Wiper trip to surface casing shoe from 3033'to 1487'. No issues.;Service rig:grease/inspect blocks,drawworks,brake linkage.;RIH from 1487'to 3033'with no issues,washing last stand to bottom.;Continue drilling 9-7/8"hole from 3033'to 3157'. Pump sweep once on bottom 100%increase in cuttings. Slide as needed,MAD pass all slides.;Drill ahead from 3157'to 4027'sliding as needed,500 gpm/1400 psi,PU wt 90 k,So wt 84 k,ROT wt 86 k,70 rpm,6/9 k ft lbs trq,ECD 9.33 ppg w/8.95 ppg mud wt.;Pump sweep&circ hole clean for wiper trip.;Wiper trip from 4027'to 3905';Distance to plan;7.2',High 5.22'/Right 4.96';Hauled 168 bbls solids to G&I,Cum 576 bbls Hauled 422 bbls fluid to G&I,Cum 1535 bbls Hauled 0 bbls cement G&I,Cum 78 bbls IlaiIv loccpc dnwn hnlp n hhls (-AIM n hhls 4/23/2017 Continue with wiper trip from 3905'to 3030'with no issues,hole fill took 2.21 bbls over calculated displacement.;Service rig while monitoring hole on trip tank took hole took 0.7 bbls for 1.4 bph loss rate.;RIH from 3030'to 4027'with no issues Wash last stand to bottom;8'of fill observed.;Continue drilling from 4027'to 4774'. Pump sweep once on bottom with 50%increase in cuttings,came back on time.;Slide as needed to maintain WP 09,MAD passing all slides. Sliding parameters: ROP 130fph,WOB 5-10K,490gpm/1675psi with 162 diff.;Rotating parameters:140-190fph,WOB 5-10K,500 gpm/1800 psi,80 rpms/8800 ft-lbs,ECD's 9.48 ppg with 9.1 ppg mud.;Drill ahead from 4774'to 5023'sliding as needed WP 09,MAD passing all slides,500 gpm/1750 psi,PU wt 106 k,SO wt 98 k,ROT wt 101 k,80 rpm,6/10 k ft lbs trq,ECD 9.42 ppg w/9.0 ppg mud wt.;Pump sweep&circ hole clean for wiper trip.;Wiper trip from 5023'to 3967'(no issues)RIH from 3967 to 5023'(no issues&no fill).;Drill ahead from 5023'to 5461'sliding as needed WP 09,MAD passing all slides,500 gpm/1750 psi,PU wt 110 k,SO wt 98 k,ROT wt 105 k,70 rpm,7/10 k ft lbs trq,ECD 9.5 ppg w/9 ppg mud wt.;Distance to plan;1.67',High 0.62'/Right 1.55'.;Hauled 120 bbls solids to G&I,Cum 696 bbls Hauled 280 bbls fluid to G&I,Cum 1815 bbls Hauled 0 bbls cement G&I,Cum 78 bbls hail,Inscps dnwn hnla 41 hhlc Crim 4' hhls 4/24/2017 Continue drilling 9-7/8"hole from 5461'to 6100'(casing point). Slide as needed to maintain WP 09.MAD pass all slides.Slide parameters:ROP 80-100 fph, WOB 5K,507 gpm/1900 psi with 200 psi diff.;Rotating parameters:ROP 130-180 fph,WOB 5-8K,505 gpm/2040 psi,80 rpms/10100 ft-lbs. ECD's 9.55 with 9.1 ppg MW.;Pump sweep and circulate hole clean. Sweep came back on time with 10%increase in cuttings. Circulate additional 2 x annular volume after sweep y exits. 505 gpm/1800 psi with 80 rpms. Flow check;well-static. Obtain SPR's.(Observed seals on top drive leaking,shut down to investigate.);POOH from 6100' ' 1 ' to 172'with no issues.(20K tight spot @ 4656).Racked back HWDP&jars.;PJSM on sources.Up-load MWD tools&remove sources.UD BHA.Bit Grade=1-3- CT-G-X-I-PN-TD.;R/D top drive&UD for repair.Lower swivel seals need to be replaced.;R/U SLB E-line.;Hauled 92 bbls solids to G&I,Cum 788 bbls Hauled 273 bbls fluid to G&I,Cum 2088 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 24 bbls,Cum 67 bbls 4/25/2017 Continue to riq up E-Line and make up drift run tools.;RIH with drift run tools to 5920',set down. Pick up with no overpull. Work down to 5963'and set down again,no overpull. POOH with drift run.;Make up XPT tool to collect pressures on E-Line and RIH to 5896'with no issues. POOH collecting pressures from 5896'to 5218'with a total of 30 samples taken at 18:00 hrs.Well on trip tank taking;1.8 bph with 9.1 ppg mud wt.Mechanic replacing gearbox seal on topdrive, crew changing swabs/liners to 5"on mud pumps.;Cont.to POOH with E-Line logging assembly.Collect a total of 70 pressure samples from 35 stations.Monitor plc, well on trip tank average 1.6 bbls/hr.;Work on PM's.Cont.with top drive repair.Cont with change out mud pump lines to 5".;UD XPT tools&M/U Gamma Neutron Vvotool.;RIH with E-Line Gamma neutron tool to 5950'.;Hauled 1 bbls solids to G&I,Cum 789 bbls Hauled 19 bbls fluid to G&I,Cum 2107 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 49 bbls,Cum 92 bbls 4/26/2017 SLB e-line RIH with ECS-HNGS tool string to 5920'with no issues.Began logging up hole from 5913'to surface casing shoe at 1511'.Had one-1K over pull at 5880'(3 small coal seams in this area).;POOH for SWC tool string.Halliburton delivered 345 sx lead cement into silo.Rig crew changed oil in mud pump and floor motor.Well taking just over 1 bph on trip tank.Removed RA source&LD tools.;SLB M/U SWC assembly&RIH to 5900'.POOH collecting 27 out of 35 side wall cores.RID SLB E-Line.;Re-install top drive after seal assembly repair.;Hauled 0 bbls solids to G&I,Cum 789 bbls Hauled 0 bbls fluid to G&I,Cum 2107 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 37.6 bbls,Cum 129.6 bbls 1111 0 4/27/2017 Installed topdrive,filled gear box with oil,MU IBOP and saver sub,installed Kelly hose and bails.;MU BHA#3(cleanout assembly)as follows:re-run 9 7/8"PDC, bit sub,XO,IL stab,DGR-PWD-ADR collars, flex DC's x 2,XO,HWDP x 2,XO,jars,XO,HWDP x 15.At 164'ran pumps then tested Kelly hose;connection (good).Cont TIH filling pipe every 25 stands.At 5938'set down twice 20K.PU to 5916'and MU topdrive.Up wt 124K,dwn wt 98K.Claystone formation at 5938'.;Washed and reamed from 5916'to bottom at 6100'.371 gpm-817 psi,55 rpm-6700 to 10,000 ft/lbs off bott torque.Had rig visit with Environmental Coordinator Keegan Fleming.;Pumped 20 bbl hi-vis nutplug sweep around at 462 gpm-1216 psi,55 rpm-6700 ft/lbs off bott torque.Did two full circulations.Had a max of 55 units gas at bottoms up,10%increase in cuttings to surf.;POOH on elevators from 6100'to 5730'at 350-360 ft/hr.No pump,no rotation,to log open hole.Up wt 124K coming off bottom.;Cont POOH slow on elevators from 5730'to 3087'@ 350 ft/hr MADD passing.;Hauled 3 bbls solids to G&I,Cum 792 bbls Hauled 52 bbls fluid to G&I,Cum 2159 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 19.3 bbls,Cum 148.9 bbls 4/28/2017 Cont POOH with cleanout assembly from 3087'.Racked back HWDP.LD MWD tools,NM flex DC's,XO"s and bit.No change in bit grade of 1-3.;Drain BOP stack,pull wear ring,set test plug,closed blinds.CO upper rams from 4 1/2"to 7 5/8"and buttoned up stack.;lnstalled 7 5/8"test joint and flooded stack.Shell tested stack(ok),tested upper rams at 250/3500 psi,tested annular at 250/2500 psi.Good tests.RD test equipment and pulled test plug.;CO to long bails,RU casing tongs and elevators,dummy ran hanger/landing joint.;Held PJSM with rig crew and Weatherford crew.PU and MU 7 5/8"shoe track.Filled pipe and r( checked float equipment(ok).Cont PU RIH with 7 5/8"29.7#,L-80 BTC casing to 2060',filling on the fly.;Cont PU RIH 7 5/8"casing from 2060'&land on hanger / 4 @ 6090',filling on the fly,top filling every 10 joints.;Observed tight hole @ 6058'and not able to work thru without pumping Washed last 32'to bottom with 5 bpm @ 450 psi.;Circ&cond mud for cement job with 5 bpm©ICP 450&FCP 290 psi.;R/U cement head&cement hoses.Break circulation with 3 bpm and conduct PJSM.HES loaded lines with 4 bbls water and checked for leaks.HES pressure tested lines at 600 low and 4000 high,good tests.;HES pumped 40 bbls 10 ppg MudPush II at 4 bpm 350 psi,and shut down.HES dropped bottom plug and loaded top plug.HES pumped 138 bbls(355 sx)12.5 ppg Class G Extended lead cement at 5 bpm 300 psi,;followed by 38 bbls(169 sx)15.8 ppg Class G tail cement at 3bpm 150 psi.HES dropped top plug,then displaced with 20 bbls water,;HES 200 bbls into mud displacement with 6 bpm @ 900 psi at report time.;Hauled 1 bbls solids to G&I,Cum 790 bbls Hauled 4 bbls fluid to G&I,Cum 2111 bbls C.,M' Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 36 bbls,Cum 184.9 bbls 4/29/2017 Continue displacement.Pumped total of 258 bbls 9.2 ppg 6%KCUPHPA mud at 6 bpm,900 psi.Slowed to 3 bpm with 18 bbls to go.Held hanger 2'off seat throughout the job,landed hanger with 260;bbls away.Bumped the plug with 278 bbls away and held 1700 psi(FCP of 1200 psi)for 5 minutes,bled off and floats held.Bled back 2.5 bbls to truck.WellLife 1094 was added to both lead and tail;cement at 1/2ppb.Mix water temp at 73 degrees.Pumped 25%excess on `C both lead and tail.CIP at 6:30 hrs,4/29/17.Could not reciprocate string due to hanger snagging in BOP stack;(10%"OD hanger/11"BOP).Had returns o _n j/throughout the job,but had a loss of 25 bbls at time of shut down.Calculated bbls to bump=276,actual=278 bbls.;RD,cleaned up and released HES )- ‘7.1 cementers.Drained BOP stack and cleaned out cellar box with vac truck.;Pulled landing joint,flushed out BOP stack,NOS Rep MU packoff assembly to landing joint and landed same.Verified landed,RILD's.Packed packoff seals to energize 7000 psi.Pressure tested packoff;at 500 psi for 5 min(good),then at 5000 psi for 15 min(good).Bled off and RD.;CO long bails to short bails and 41/2"DP elevators.Hung blocks and replaced brake bands on draw-works,CO 7 5/8"rams back to 4%"and buttoned up stack,cut and slipped 155'drill line.;Weighted up surface volume from 9.2 to 10.0 ppg.Total Safety on location at 16:30 and tested gas detection equipment,then calibrated same.No issues.Racked and tallied 20 jnts 4 1/2"DP.;LD excess HWDP from derrick,racked back 2 stnds NM flex DC's.AOGCC Rep Jim Regg waived witness of BOP test at 15:30 hrs on 4-29-17,via telephone.Set test plug and test jnt.;Flooded stack and worked air out of surface lines.Test BOPE 250/3500 psi&chart for 5 min,250/2500 psi for annular&chart for 5 min(good).R/D testing equipment.;lnstall 91/16 ID wear ring.;Strap&tally DP.P/U&rack back 30 stands DP in derrick.;R/U Pollard E-Line on location 05:30 hrs.Stage truck&prep tools&equipment to be rigged up on rig floor.;Hauled 5 bbls solids to G&I,Cum 795 bbls Hauled 85 bbls fluid to G&I,Cum 2196 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 31 bbls,Cum 215.9 bbls 4/30/2017 Finish racking back 4 1/2"DP in derrick.Pollard e-line on location.;RU Pollard e-line and RIH with CBL tool string.Tagged up at 5932'WLM.Pulled up hole performing CBL to 2185'.Top of cement at 2500'.POOH RD and released Pollard.;Stage BHA at catwalk,PU and MU 6 3/4"HDBS FX55 PDC,4 3/4"motor w/1.5 deg bend,PCDC,ADR,ALD,CTN,PWD and TM collars to 121'.RFO=89.06 deg.;MU topdrive and pumped through tools,plugged into upload MWD. Had trouble uploading to tool.Located computer to doghouse and ran shorter cord to tool.Pumped through tools again and downloaded ok.;Shallow pulse tested ok,PJSM and loaded RA sources.;Cont PU and MU NM flex DC's HWDP and jars to 552.91',then PU RIH with 32 joints 4 1/2"DP to 1553'.;Cont TIH from derrick,from 1553'to 5909 filling pipe every 20 stands.;R/U testing equipment.Test casing to 3500 psi&chart for 30 min(good).R/D testing equipment.;Wash& eam from 5909'to TOC 5995'.Drill out float equipment,shoe track&rat hole to 6100'.;(Float collar&shoe tagged 6'higher than actual run tally)Float collar / � V tagged @ 6006'&shoe tagged @ 6083').;Drill 20'new formation from 6100'to 6120'.;Displace mud from 9.2 ppg to 10.0 ppg 6%KCL PHPA with 212 gpm/ V `7 1200 psi.;R/U testing equipment.FIT to 12.5 ppq,785 psi with 10.0 ppg mud.R/D testing equipment.;Drill ahead from 6120'to 6222'.250 gpm,1700 psi,100 ° ft/hr,5 k wob,50 rpm,7 k trq,PU wt 120 k,SO wt 100 k,ROT wt 106 k,ECD 11.06 ppg with 10.0 ppg mud wt.;Hauled 0 bbls solids to G&I,Cum 795 bbls Hauled 0 bbls fluid to G&I,Cum 2196 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 0 bbls,Cum 215.9 bbls 5/1/2017 Cont drilling 6 V;'hole from 6222'to 7127',rotating wob 5 to 6K,284 gpm-2512 psi,80 rpm-8900 ft/lbs on bott torque,100 to 150 ft/hr ROP,MW 10.2/vis 51, ECD's at 11.5 ppg,BGG 81 units.;Sliding wob 2K,301 gpm-2470 psi,292 psi diff,67 ft/hr ROP.;Pumped a 20 bbl hi-vis nutplug sweep at 6654'with a 50% increase in cuttings to surface.Racked and drifted 80 jnts 4 W casing.;Drill ahead from 7127'to 7214',sliding as needed to maintain well plan.290 gpm,2000 psi,100-150 ft/hr,5 k wob,50-70 rpm,7-8 k ft/lbs trq.;PU wt 138 k,SO wt 108 k,ROT wt 120 k,ECD 11.4 ppg with 10.3 ppg mud wt.;Pump sweep and circ hole clean for wiper trip.20%increase in cuttings with sweep.;POOH wiper trip from 7214'to 6462'.Various tight spots with 25-35 k over pull.drop down and work thru once.Pull back thru clean.Not able to pull past 6462'due to tight hole.;Drop down to 6469'.BROOH from 6469'to 6090',290 gpm 2000-2200 psi,50 rpm,7-8 k ft/lbs trq.Significant amount of cuttings across shakers.;Circ hole clean prior to pulling BHA into 7 5/8"shoe.PULL 1 stand into shoe from 6090'to 6035'.;Service rig.Grease draw works,top drive,iron roughneck&crown.Check brakes.;RIH from 6035'to TD of 7124'(no issues&no fill).;Drill ahead from 7214'to 7525',sliding as needed to maintain well plan.290 gpm,2300 psi,100-150 ft/hr,5 k wob,50-70 rpm,7-9 k ft/lbs trq.;PU wt 140 k,SO wt 110 k,ROT wt 118 k,ECD 11.5 ppg with 10.3 ppg mud wt.;Distance to Plan:2.45'(1.43'Low/1.98'Left).;Hauled 54 bbls solids to G&I,Cum 849 bbls Hauled 126 bbls fluid to G&I,Cum 2322 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 0 bbls,Cum 215.9 bbls • s 5/2/2017 Cont directionally drilling 6 3/4"hole from 7525'to 8400',Rotating wob 6K,307 gpm-2833 psi,60 rpm-9800 ft/lbs on bott torque,150 to 160 ft/hr ROP.Sliding wob 5K,283 gpm-2613 psi,164 psi diff;20 to 40 ft/hr ROP.Pumped a hi-vis sweep at 7836'with a 25%increase in cuttings to surface.Increased MW from 10.3 to 10.7 over last 12 hours.Seeing an increase in connection gas up to 900 units.;Obtained SPR's with MW at 10.4 and 10.7.Cont to rack and tally 4 1/2" casing.;Cont directionally drilling 6 3/4"hole from 8400'to 8459',pumping a 20 bbl hi-vis nutplug sweep prior to stand drilled down.Monitor well for 5 mins.slight flow.;Cont to circulate hi-vis sweep around at 294 gpm-2450 psi,rotated and reciprocated pipe.60 rpm-8500 ft/lbs off bolt torque.Weight up to 11 ppg from 10.8 ppg.;Monitor well.15 mins.Static,dropped 3 inches.Prejob,prepare to trip.;Pump out 5 stands,one pump in idle.Encounter coal bed UT 4D-1,30 foot thick. slight pack off pulled 20k over.Begin backreaming.280 GPM,50 RPM,2240 PP,24%flow.12.1 PPG ECD.;Circulate @ 7800'MD.Gas spike 1586 units from flow check,Max gas 1778 units from Coal UT 4d-1,flow increase from 24 to 37%.Circulate out gas peaks.Large(1"to 1.5"),thin pieces of coal seen.;Ream out from 7800'to 7214'MD.Hole in good shape.Shakers cleaned up.Back ground gas 100 units.;Monitor well on trip tank.Service rig.Check all fluids,grease and service top drive.Change out grabber dies.Adjust brake band.Lost.6 barrel in half hour.;Trip in the hole on tip tank.Correct displacement.;Turn elevators around.Fill pipe.correct displacement.Wash to bottom with 260 Gpm,2200 PP.3 feet of fill on bottom.;Drill 6.75"production hole.From 8459'to 8681'.Slide 20 feet.50'/hr.270 Gpm,2654 PP.400 psi differential.2579 units trip gas.MW in 11.05 ppg,10.3 ppg non pressured.12.2 ppg ECD.;Up 166k,Dn,120k,Rot 144k. TQ 9500 ft/lbs on 8000 ft/lbs off.Pumped sweep on top of second stand and circulated out.50%increase in cuttings.;Hauled 90 bbls solids to G&I,Cum 939 bbls Hauled 270 bbls fluid to G&l,Cum 2592 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 0 bbls,Cum 215.9 bbls;Wellbore position:7.3'to plan;7'low,1.6'right. 5/3/2017 Cont drilling 6 3/4"production hole from 8681'to 9380'.Rotating wob 6 to 8K,279 gpm-2958 psi,65 rpm-10,100 ft/lbs on bolt torque,100 to 150 ft/hr ROP. Sliding wob 10K,279 gpm-2773 psi,250 psi;diff,29 ft/hr ROP.MW 11.3/vis 52,ECD's at 12.4 ppg,BGG 19 units.Pumped a 20 bbl hi-vis nutplug sweep at 8968'with a 25%increase in cuttings to surface.Received hanger and pup jnt.;Cont drilling 6 3/4"production hole from 9380'to 9645.Rotating wob 6 to 8K,275 gpm-3015 psi,W/350 diff.75 rpm-10,500 ft/lbs on bolt torque,45 to 135 ft/hr ROP.;MW 11.3 ppg,ECD 12.65 ppg.Pumped 20 bbl hi-vis sweep @ 9550'MD, 20%increase in cuttings.Back ground gas remained low,25 units.;Cont drilling 6 3/4"production hole from 9645' to 9799'MD.Rotating wob 6 to 10K,275 gpm- 3055 psi,W/350 diff.75 rpm-10,500 ft/lbs on bott torque,25 to 135 ft/hr ROP.11.3 MW.12.6 ECD.;Pump sweep,Hi-Vis with 3 sxs medium nut plug.280 Gpm, 80 Rpm,2800 psi PP,198k up,140k Dn,158k Rot.11.3 MW,12.56 ECD.20 units BGG.;Hauled 80 bbls solids to G&I,Cum 1019 bbls Hauled 280 bbls fluid to G&I,Cum 2872 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 0 bbls,Cum 215.9 bbls;Wellbore position:61'from plan.36'high,48'left of plan.Target given=100'radius. 5/4/2017 Cont to circ hi-vis nutplug sweep around at 281 gpm-2743 psi,80 rpm-10,526 ft/lbs off bolt torque.Had 25%increase in cuttings to surface.Cont to circ one more bottoms up.MW 11.3/vis 50,BBG 17;units.Obtained SPR's and survey.Monitored well 15 minutes with a slight drop of fluid in wellbore.;Pulled up hole on elevators from 9799'to inside intermediate casing,parking at 6064'.Up wt coming off bottom 216K.From 9170'to 8870'had 6 tight spots we worked on elevators one time and cleaned;up.From 6990'to shoe at 6090'we had numerous overpulls of 15 to 25K.Did not pump or rotate entire trip.Area Op's Manager Chad Helgeson and Production Foreman Pete Iverson stopped by for rig visit;Serviced rig and topdrive.Tool Push had welder here and repaired shaker#2 screen basket(ledge screen rests on).Well on trip tank took just under 1/2 bbl over 1 hour.Hole fill 8 bbls over calc.;TIH on elevators from 6064'to 8854'and set down solid.MU topdrive,filled pipe and washed/reamed down to 8863'and saw nothing.Set down again at 8900'.Washed/reamed down to 8927',then cont TIH;on elevators to 9736'.MU topdrive on last stand,filled pipe and washed to bottom with no fill.Had three other tight spots we worked on elevators with no issue farther up hole.;Pumped hi-vis nutplug sweep around at 270 gpm-2800 psi,60 rpm-9598 ftlbs off bolt torque.At 2227 strokes we had a max of 2176 units gas.Cont to circ and increased MW to 11.5 from 11.3.;With MW @ 11.5ppg in/out obtained SPR's and flow check.Fluid slowly dropping in wellbore over15 minutes. Dropped 4 inches.;POOH from 9799'to 6085'.6340'saw some differential sticking,and the hole tried to swab.Pulled slower into casing.Actual hole fill 33.3 bbls, calculated 23.6 bbls.;Circulate bottoms up inside casing.280 GPM,30 RPM,26%flow,2359 PP,6300 ft/lbs TO.14 units BGG at calculated strokes.Shakers showed 50%increase in cuttings.;Monitor wellbore.15 mins.Dropped 6 inches.Pump 2 pounds over 22 bbl dry job.NOTE:(Wellbore lost 35 bbls over last 24 hours).;POOH on elevators from 6085'to 553,constant hole fill on trip tank.Caught up to dry job in 10 stands.Hole fill 2.5 bbls per 5 stands.(Calculated is 2) Wellbore appears to be drinking 1 bbl/hour.;Monitor well @ HWDP.Taking fluid,1 BPH loss rate recorded over 15 mins.;Trip out to collars.Monitor well.Lay down BHA#4.;Hauled 0 bbls solids to G&I,Cum 1019 bbls Hauled 0 bbls fluid to G&I,Cum 2872 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 35.1 bbls,Cum 251 bbls;Wellbore position:62'from plan,37'high,50'left. 5/5/2017 PJSM,removed RA sources,plugged in and uploaded MWD data.Cont LD BHA.Bit graded 3-4-BT-G-X-2-DL-TD.;Cleaned and cleared rig floor,PU single jnt, torqued up 6 3/4"roller cone bit,bit sub and stab for cleanout run later.LD single.SLB e-line crew on location at 08:30.;Held PJSM with SLB crew,RU sheaves and PU 4 1/2"OD drift for dummy run.Well on trip tank taking 1/2 to 1 bph.;RIH on e-line with no issues.Set down at 9769'(30'off bottom)twice but pulling off clean.POOH and LD drift assembly.PU 44.34'of XPT assembly,3 7/8"OD.;RIH with XPT assembly to 9700'.Did have to work through rough spot at 7550'with / little trouble(claystone and sand).Received lead cement in silo.Rig crew doing PM's on gens and loader.;Began RFT at 9558',up to 6827'.35 stations gathered nby midnight.Pulled tight coming up through coal beds from 8200 to 8100'.1500 lbs over.Differentially stuck @ 7139'.Pulled 6500 over.;Complete RFT logging run by 03:00 hrs.12 pressure readings gathered after midnight,47 total for the run.POOH,and lay down the tools.pick up Neutron formation analysis tool string.;PJSM.Time,distance and shielding.Pick up Neutron based formation analysis tool string.(HNGS tool),TIH. Begin logging @ 9700'MD.500'/hr logging speed.(Wellbore taking.5 bbl/hr.);On the way down Eline sat down @ 7550',8300,8600',9160',9598'.Able to work through each time by picking up and dropping back down.;SIMOPS:Shaker bed rubber change out complete.Rig crew prepare for rig move.Box up un-needed canvass wind walls,steam hoses. Peak crew loading out spud mud trailers,and excess DP for Kalotsa.;Weight up mud stored in pit 10 from 10.7 ppg to 11.5 ppg.140 bbls of additional mud for clean out run ready to go.General housekeeping and prep for move.Halliburton loaded 690 sxs 15.3 cmt in silo;Hauled 18 bbls solids to G&I,Cum 1037 bbls Hauled 72 bbls fluid to G&I,Cum 2944 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 12 bbls,Cum 263 bbls • • 5/6/2017 Cont logging open hole on e-line from 9700'up to 8350',with HNGS/ECS tool string at 500 ft/hr.At 8350'tool hung up in tuffaceous claystone/siltstone/coal.Had to jar tool free with two licks,;second time while pulling max of 12K over.Tool free'd up but upper HNGS portion stopped working(delicate).Cont pulling up hole at 650 ft/hr and notified Drilling Geo.Decision made to;cancel SWC run,but continue logging open hole with ECS.Had one more 8K overpull at 8250'and from there to shoe was decent.Cont POOH,RD and released SLB crew.Hole taking 1/2 bph on trip tank.;MU 6 3/4"cleanout assembly as follows:6'/1'roller cone,bit sub w/float,6'/"IBS stab,NM flex DC,XO,HWDP,jars and HWDP to 440'.Cont TIH on 4 1/2"DP from 440'to 6048',filled every 20 stands.;At 6048'MU topdrive and CBU 1 time,had a max of 2970 units at bottoms up.;Cut and slipped 106'drill line while cont circ drill string at idle.Checked and adjusted brakes.;Cont TIH on elevators from 6048'to 9370'MD.Set down with 30k.Same spot as last trip.Pick up and ream out slow.Dropped down.It was gone.TIH on elevators to 9655'MD.;Calculated trip volume 65 bbls.Actual 75 bbls.10 bbl long.;Circulate and condition mud.Circulate gas out.Max 3360 units.Large quantities of clay,sand and some coal came out with the gas.25 minute shoulder of gas seen,due to the logging ops.;Ream last two stands to bottom.Pump sweep.282 GPM,80 RPM,10k TQ,1535 PP,26%flow,run water at 10 BPH.MW in/out 11.6+ppg.BGG 25 units.50%increase in cuttings seen with sweep.;Record SPR's.Prejob for TOOH.Lay down working joint.Monitor well.Static.POOH on elevators from 9779'to 9529'MD.Hole swabbing.Took.3 bbl, calculated=l.6 bbls.Trip back to bottom.;Circulate bottoms up.282 GPM,80 RPM,10k TQ,1535 PP,26%flow.Water off.MW in/out 11.6 ppg.Max gas 30 units.Monitor well.Static.;Pump out first 5 stands,to 9455'MD.One pump in idle. 48 spm,116 GPM,440 PP.Monitor well.Static.Tried to pull on elevators,still swabbing,go back to pumping out with 1 pump in idle.118 gpm.;Pump out From 9455'to 9159.Due to swabbing Up WT=190k,Dn WT=135k,Rot WT=150k. 48 spm,118 gpm.;Hauled 0 bbls solids to G&I,Cum 1037 bbls Hauled 0 bbls fluid to G&I,Cum 2944 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 15 bbls,Cum 278 bbls 5/7/2017 Cont to POOH from 9070',pumped at idle up to 8588',then POOH on elevators with no issues just inside casing shoe at 6037'.No issues in open hole.Hole fill 2.5 bbls over calculated.;MU topdrive and CBU one time,208 gpm-637 psi.Had a max of 21 units at bottoms up.10 minute flow check=static,pumped 10 bbl dry job.;Cont to POOH LD 41/2"DP from 6037'to 3060'.Vac wiper ball through each joint on pipe rack with vac truck.;Replace hyd hose on iron roughneck and catwalk.;Cont POOH LD 4 1/2"DP from 3060'to HWDP at 440'.Hole fill at this point was 11.6 bbls over calculated.;TIH with 4 1/2"DP from derrick.440'to 4179'.;MU topdrive at 4179'and CBU one time.Flow check=static,pumped 10 bbl dry job.MW in/out 11.6 ppg.;Continue to lay down 4.5"DP singles.POOH 0from 4179'to 440'MD.Lay down BHA#5.6.75"bit,(Graded 1-1-WT-A-E-I-NO-TD),bit sub,stab,2 flex collars,11 HWDP,Jars.Clean and clear rig floor.;Lay down BHA#5.6.75"bit,(Graded 1-1-WT-A-E-I-NO-TD),bit sub,stab,2 flex collars,11 HWDP,Jars.Clean and clear rig floor.;Drain stack,flush stack.Pull wear $\ bushing.Dummy run hanger.Rig up Weatherford casing equipment.Bring 89 centralizers to rig floor,plus 2 pre-installed.91 total.;Prejob.running 4.5"DWC/C 12.6#L-80 casing.(Pinch points and communication.)Baker lock to the pin end of joint#4.Check floats.Good.Run casing from#1 to#37,1606'MD.Torque ��IV 6,200 ft/Ibs.;Fill on the fly,top off every 10 joints.;Hauled 22 bbls solids to G&I,Cum 1059 bbls '� f^Hauled 113 bbls fluid to G&I,Cum 3057 bbls a7uled 0 bbls cement G&I,Cum 78 bbls wily losses down hole 13 bbls,Cum 291 bbls 5/8/2017 Cont to PU single in hole with 4 1/2"casing from 1606'to 5366'.Weatherford hydraulic hose to casing tongs leaking.;Cleaned up rig floor,replaced hydraulic hose from power pack to casing tongs.;Cont PU single in hole with 4 1/2"casing from 5366'to 6061',just above intermediate shoe.Up wt 65K,dwn wt 65K.MU circ swedge and hose.;Break circ with pump at idle while changing to long bails.Pumped at 114 gpm-299 psi with a max of 1333 units at bottoms up.Built 160 bbls 6%KCL brine on vac trucks for cement displacement later.;Cont ease in hole from 6061'to 9305'filling on the fly,top filling every 10 joints.At 8600'started to see some differential sticking after MU joints,but broke over fairly easy and no issues once;moving.Initially took 40K to break loose,then down to 10-15K.Had three joints with no sticking,then at 9305'could not move after making up joint#223.41/2"shoe is 496'from bottom.;At time of sticking,up wt was 100K,dwn wt was 85K.Started working pipe at 180K up,then setting down hard at 40K with no movement.Notified Drilling Engineer.LD Joint#223 and MU circ;swedge in top,PU and MU joint,then MU topdrive.Broke circ with no problem getting returns immediately.Running centrifuge and water to drop MW from 11.6 to 11.2 ppg. Circ at 216 gpm-772 psi,;lncrease up wt to 190K and parked string while dropping MW.Had a max of 2404 units prior to bottoms up which dropped down to 20 units.With 11.2 in/out started pulling to 200 to 240K and power down;at 40K.Had Halliburton Mud Engineer order out Black Magic product and Tool Push order out diesel to build pill.Built 20 bbl NXS lube pill with nutplug(1 drum lube-4 sks nutplug)and pumped around;while working pipe.95 spm-231 gpm-712 psi, BGG 9 units.Still not free.Shut down 30 minutes to cool brakes and allow for gas influx.Slight flow initially but reduced to nothing,11.2 MW in hole.;Resumed pumping at previous rate and working pipe.Had a max of 120 units gas after sitting 30 min.Pump 2nd sweep with NP 4 sxs,and 1 drum NXS lube.Slow to idle when sweep exited shoe.No change.;Diesel truck arrive.Load 672 gallons,16 bbls straight into pill pit.Black Magic had arrived around 2200 hrs.Continue to work pipe to 240k up 40k down,pumping 210 gpm,580 PP.;Build Black Magic pill.20 bbls pumpable in pit.Pill weight equal to mud weight @ 11.2 ppg.PIII ready and blended @ 0100 hrs.Spot pill in open hole with 2500 strokes.Pill in place©01:45 AM.;Allow pill to soak 30 mins. Inspect derrick,keepers,pins. Check all fluids on engines.Service draw works.;Working stuck casing.Pick up to 200 to 265k,and come down to 40k.Pump off.Monitor well on trip tank. Wellbore static.MW=11.2 ppg.Inspect derrick,and brakes every hour.No change.;Hauled 21 bbls solids to G&I,Cum 1080 bbls Hauled 69 bbls fluid to G&I,Cum 3126 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 12 bbls,Cum 303 bbls 5/9/2017 Continue to work pipe with up to 165K overpull and slacking off 70K under slack off with Black Magic pill soaking(9304'to--8575). Torque pipe up to 7200 ft-lbs while working pipe-no progress.;Pump 25 bbls to move Black Magic pill up 1000'(7575'to 8575')and let soak while working pipe. Vary parameters with up to 165K over pull and 75K under slack off. Working up to 8200 ft-lbs of;torque. Allow brakes to cool intermittently. Hold 165K over while brakes cool. Slack off and put 7800 ft-lbs of torque,observe it took 1 more wrap than before(2.5 wraps vs I.5);Slack off,broke over at 60K. Work pipe PUW 113K,SOW 85K. Prep to RIH with 4-1/2"DWC. Break out circulating swedge.;RIH with 4-1/2"DWC from 9303'to 9799',observe some differential taking up to 25K slack off to break over. Make up landing joint and land hanger. Hanger was getting caught in BOPE stack and had to;use tugger to pull over and center hanger.;Make up circulating head pin and hose. Circulate out Black Magic pill,over board pill,114 gpm/640 psi while rigging up cementers.Max gas 2264 units.;Circulate through landing joint.Fully landed.Unable to reciprocate due to size of stack and OD of Seaboard hanger.GPM 256,PP 1055,24%flow.Shut down pump.;PJSM.Load plugs in Qlauncher.Rig up cement head with Halliburton crew.;MU plug launcher and hardline,Halliburton loaded lines with 5 bbls water and checked for leaks.Halliburton ("y pressure tested lines at_1100 low 4600 high,good tests.Halliburton pumped 20.5 bbls;12 ppg Mud Push at 2 bpm,416 psi,and shut down.HAL dropped bottom plug and pumped 144 bbls(650 sx)15.3 ppg Class A lead cement at 5 bpm,388 psi.HAL dropped top plug,then displaced with;10 bbls water,and 17.5 bbls_8.75 ppg brine 5 bpm,2000 psi.Slowed to 2.6 bpm with 10 bbl to go.Bumped the plug and held 3800 psi(FCP of 3500 psi)for 5 minutes, bled off and floats held;Bled back 1.75 bbls to truck.Had_0 bbls Mud Push return to surface and 0 bbls of lead cement to surface. LCM was added to cement at.5 ppb.Mix water temp at 73 deg.Pumped 50%excess.;Did not reciprocate.No losses.Up wt 125K,dwn wt 83K at time of landing hanger.CIP at 22:40 hrs,5/9/2017.Using the FCP of 3500 psi TOC=5300'MD;3500psi/15.3ppg/.052=4400' 9700'-4400'=5300',or 790 feet inside the intermediate shoe which is 6090;MD.RD cleaned up and released Halliburton.01:30 5/10/17;Drain stack.Remove landing joint.Make up packoff with Wellhead hand.Install Seaboard packoff.Lay down LJ.Load up all well head tools in Well Head hands truck.signed ticket released.;Rig down top drive,remove bales,rig down rig floor in preparation of RDMO.clean mud tanks.Haul mud to G&I.Mud Logger rigged down.;Empty boiler,rig down Gen 3,take down flow line,catch can,bell nipple,install travel beam in cellar.;Hauled 3 bbls solids to G&I,Cum 1083 bbls Hauled 222 bbls fluid to G&I,Cum 3348 bbls Hauled 0 bbls cement G&I,Cum 78 bbls Daily losses down hole 12 bbls,Cum 303 bbls 5/10/2017 Continue to wait on cement to test production casing. Haul off mud and clean pits. Remove T-bar on torque tube. Clean up and clear rig floor. Roll up sub base tarps. Disconnect pason lines. L/D;fingers on board. RID centrifuge and misc.electrical lines.;Pull wind walls off rig floor and pits. Continue rigging down electrical lines. Pull water upright and cement silo away from rig. RID and move third party shacks. R/D torque tube and scope derrick;down. Haul drill pipe, mud product and misc.load to Bart pad.;lnstall BPV.Pressure down&R/D Koomey.N/D BOPE.Finish cleaning mud pits.Lower V-door.Prep mud pumps&pits for rig move.;NIU production tree.Pack void&test void&tree 250/5000 psi(good).Pull BPV&set TWC.Test tree 300/5000 psi(good)/Pull TWC&test casing 3500 psi&chart for 30 min(good);R/D testing equipment.Close master valve.Well secure @ 3:00 hrs;Cont.to rig down&prep for rig move.Unspool drill line. Prep derrick to be laid over.R/D lights.Release rig @ 6:00 hrs. • • 14 Hilcorp EnergyCompany Composite Report Well Name: KEU KU 11-07X Field: Kenai Gas Field County/State: ,Alaska I(LAT/LONG): ovation(RKB): API#: 50-133-20662-00-00 Spud Date: Job Name: 1711232C KU 11-07X Completion Contractor AFE#: CitY AFE$: :: ::.::;:y.::y,.tai:.,.: Y;:::R:3::..::::3::,:,3..H.:.f.o:.::;..: um aty .. ;. . ,:,. et at office.PTW and JSA.Mobe to location.Rig up Lubricator and CBL tool.PT to 250 psi low and 2500 psi high.,RIH th e 5/16/2017 into Halliburton LWD Log and tag at 9660'.Ran CBL from 9660'to 5000'.Looked like good cement all the way to 5200'.POOH.IHalliburton Rigdown E-lie. Use Hall Halliburton crane to put tree on well. James with Northern Oil Solutions put the tree on.Tree needs to be tested. 6/6/201*Obtain PTW. Hold safety meeting. Discuss job procedure and review SLB JSA.,MIRU SLB CTU 13. Fluid back with field tripes on the IA(7-5/8"x 4-1/2") ./1 ii .Pressure up IA to 2.665psi for 30 minutes Ending pressure 2597 psi. 68 psi loss. 2.5%.,Start BOPE test. 24 hr witness notification sent 6/5/17 @ 1412. N\ waived by Jim Regq 6/5/17 el422. Test complete.,Make up Coil connector pull test 25k. Clean up unit. SDFN. 6/7/2017 Obtain PTW. Hold safety meeting. Discuss job procedure and review JSA.,Fire equipment. Pick inj head, Make up 10'lubricator, make up reverse out BHA, Stab on well. PT stack 250/4500 psi. Bleed down open master swab 23.5 turns. RIH Cool down N2. 3500'CTMD. Online with N2 down back side. 800 scf/min. Bleed down IA to tank to ensure all air is out. Tag PBTD @ 9675'CTMD. PU clean 28k. parked at 9652'CTMD. Inc rease rate to 1500 scf/min.,continue lifting. WHP and return flow rate increasing. N2 at surface after 177,000 scf pumped. Tank strap shows 155 bbls returned.,1567 whp. Close ' choke and POOH to surface 155 bbls returned. Continue pumping while pooh. At surface. Close master and swab SITP 2530 psi.,Start rigging down SLB. C.J Swap out SLB acquisition and instal Grystal gauge.,Start IA PT. 2576 psi. End pressure 2541 psi.35 psi loss over 30 minutes but pressure drop did not taper / ,f off. Swap out sib acquisition for HAK crystal guage. Increase pressure on IA to 2746 @ 16:45 hrs. Monitor throughout the night. SLB rigged down and off l� location. 155 bbls returned. 975 nnn srf nurnnad for inh nr 7q5'nallnns 6/8/2017 PTW and JSA.Mobe to location.Rig up lubricator.Put 25 gals of methanol and water in Halliburton test pump.Pressure test to 250 psi low and 3500 psi high. Tubing pressure 2340 psi.,RIH w/Halliburton press/temp tool and tag at 9675'correlated with tie in log.Found fluid level at 9669'.POOH.,RIH w/3-3/8"(3-1/8 charges)x20'HC,6 spf,60 degree phase,perf gun and tie in to Digital Perf Log sent from town.Ran correlation log and send to town.Get ok to perf from 9600'to 9620'.Spotted shot and fired gun with 2399.3 psi on tubing.Did not see any pressure change.After shot the gun was stuck.Worked tools up hole approx.6' (� pulling to 2000 lbs(HLD safe pull out zone).Line up wt is 1350 lbs.Called town and,discussed.HLD call their people.Bled well down from 2399 psi to 2010 psi at 100 psi increments with tool weight at 2000 lbs and worked tools.Tools were still stuck.Decision was made to pull out of rope socket.Pulled line wt up to 2100 lbs.Pulled line wt to 2150 lbs and looked like line pulled out of rope socket.Line wt was 900 lbs coming out of hole.Wire line became stuck at 68'.Wouldn't down or up.Pull to 1100,Ibs and still didn't come free. It acted like line was stuck in the grease head flow tube.Called town and discussed. Closed wire line valve and attempted to bleed lubricator.Wouldn't bleed down all the way.After discussion with HLD operations management decision was made to cut wire with swab valve and fish line and gun in the morning.Closed swab and cut wire.Closed bottom master to make sure line had fallen down,hole. Bottom master closed so wire line did fall.,Rig down lubricator.Found out that we had a high strand that kept line from going thru flow tubes in grease head.TP-1995.4 psi 6/9/2017 PTW and JSA.Rig up lubricator.Pressure test to 250 psi low and 3500 psi high.,RIH w/Wire finder and 2.83" 3 prong wire grab Sitting down at 150'WLM. RIH to 400'. POOH. Catching binds. No wire,R1H w/Wire finder and 3 prong wire grab. Sat down at 6042' POOH Fall to 6175' POOH &Stop Continue down hole to 9572' WLM. Pull bind and Shear off bait sub. RIH w/4 1/2 GS. Latch bait sub @ 9568' POOH with Wire grabs OOH w/wire. Pinched end from swab and armorless end from pull out. 32'wireline out of hole.,RIH w/3.70"Lead Impression Block. S/D 9573'WLM Impression of a clean fish neck RIH w/3.69 Bait Sub.3.69"Bell guide, JD Pulling tool Latch up @ 9575'WLM . Jar 7 times. Gun moves and comes free. POOH,OOH w/e-line toolstring and guns.Break off E-line tools.Strap gun upright in cellar to wireline valve cage while running bailer. RIH w/3.50"x 10'DD Bailer. Tag @ 9654'WLM Drive bailer to 9656'. No issues through perfs. Did not see fluid level. OOH w/tools. Bailer has several cups of sample. Give to Applewhite Black sandy material and clay. 2 gallons fluid,Rig down tools,lay spent gun down and lubricator..Note#1:Gun had burrs sticking past OD on every hole and rub spots on gun.Will see gun better when laid down. Note#2:Foreman looked at gun in the AM and gun was bent and rub spots on lower end of the 20'gun. 6/12/2017 PTW and JSA.Rig up lubricator.Pressure test to 250 psi low and 3500 psi high.Arm gun.TP-1876 psi.,RIH w/2-718"x10'(loaded w/5'charges)Connex HC,6 spf,60 degree phase,perf gun and tie in to Digital Perf Log sent from town.Ran correlation log and send to town.Get ok to pert from 9595'to 9600'.Spotted shot and fired gun with 1876 psi on tubing.After 5 min had 1876.5 psi on tubing.POOH.All shots fired.Gun was dry.,Rig down lubricator and a-line.Turn well over to field.TP-1866 psi 6/21/2017 PTW and JSA.Mobe to location.MU 3.50"OD CIBP.Rig up lubricator.Pressure test to 250 psi low and 3500 psi high,RIH w/3-1/2"OD GEO Plug to 9100'and computer system went down.Engineer made calls and finally got it back up and running.Tied into HLB pert correlation log dated 6-8-17.Spotted top of plug at 9591'and plug element at 9592'.Lost 120 lbs of line wt when plug set.Picked up 30'and went back down and tagged plug lightly.Looked like a good set.TP was 60 psi when plug was set.POOH and setting sleeve was missing.,Called town and discussed.Decision to leave sleeve on top of plug and dump cement. Sleeve is 3.5"x10"with 2.5"ID.thru sleeve.,Mixed and filled 3.5"x20'bailer w/NEO 17 ppg cement(7.5 gals).RIH with bailer,tagged plug/sleeve and dumped 10' of cement on top of plug and setting sleeve at 9591'.POOH.Good dump.Est TOC at 9581'and CIP at 1400 hrs.,Rig off well and wait on cement.Plan is to pressure well up tomorrow afternoon w/N2 if available and pelf Friday morning. • • 6/22/2017 Check on cement sample.Notify SLB N2 that its a go to pressure up well at 1400 hrs.Round up 1502 flange.Wait on 24 hr cement cure.,PTW and JSA.Mobe to location and rig up SLB N2 pump truck.PT hard lines to 4000 psi.Pumped 2300 gals N/2 at 2200 scf per min and pressured well up to 3400 psi and closed masters.Will have night check pressure couple times tonight and in the morning around 4 am.Halliburton will be on location at 0700 hrs in morning to perf.,Rig down N2 pump truck and lines.TP-3390 psi. 6/23/2017 PTW and JSA.Mobe to location..Rig up lubricator.Pressure test to 250 psi low and 4500 psi high.,RIH w/2-7/8"x5'HC,1 spf,60 deg phase and tie into perf correlation log dated 6-8-17.Tag top of cement at 9570.5'.Est TOC was 9581'.Run correlation log and send to town.Get ok to perf.Spotted gun from 9546'to 9551'and fired gun with 3313 psi on tubing.After five min TP was 3310 psi.POOH.All shots fired.This gun was to equalize pressure if we were too underbalance.,RIH w/3-3/8"x20'(3-1/8"charges)HC,6 spf,60 deg phase and tie into perf correlation log dated 6-8-17. Broke thru cement stringer and tagged at 9577'.Ran correlation log and sent to town.Get ok to pert from 9549'to 9569'.Fired gun with 3256 psi on tubing.After 5 min TP was 3252 psi.Had to pull 200 lbs over to start moving tools.POOH.All shots fired.Had to lay lubricator down to put gun in because of wt.,of the pert gun.That is what took longer for this run.,RIH w/3-3/8"x10'(3'loaded w/3-1/8"charges)HC,6 spf,60 deg phase and tie into pert correlation log dated 6-8-17.Ran correlation log.Spotted gun from 9546'to 9549'.Fired gun w/3008 psi on tubing.After 5 min TP was 2954 psi.POOH.All shots fired.TP was falling before we fired this gun.1650 hrs-3196 psi; 1727 hrs-3167 psi;1802 hrs-3008 psi(Fired shot);1807 hrs-2954 psi;,1830 hrs-2741 psi and 1900 hrs-2478 psi,Rig down lubricator and turn well over to field. NOTE:The 3-3/8"guns didn't look bent but still pulls a couple hundred pounds over tool wt on both runs to get started out of hole.All per,charges were C;an Cnnnay rharnas 7/5/2017 SLB and Cruz waiting for road permits.,On location. Hold safety meeting, Rig down SLB CTU 13. Cruz Vac truck hauling fluids to G&I.,Arrive at KGF KU 11- 07X. RU CTU 13 with 2.375"CT. SDFN. location secure. 7/6/2017 PTW. Hold safety meeting.,Fire equipment. Fluid pack for BOPE test.,24 hr BOPE test witness notification sent 7/5/17 @ 0751. Witness waived by Jim Regg 7/5/17 @ 1523. Start BOPE test. Accumulator draw down test. Test Combi BOPE rams and pressure control valves to 250/4000 psi. BOPE test complete.,Pick inj head. Stab 10'lubricator. Pull test 2.375"Dimple connector to 30k. Make up 2.375"DFCV,2.375"stinger,2.375"jet swirl nozzle. BHA length 8.5'. Zero BHA at bottom of lubricator. Stab on well. CT zero to tubing hanger 13'. RKB 18'. Correct CT zero to 5'. PT stack 250/4000 psi. Bleed down to choke. CT reel full of 41.8 bbls from previous job. Cool down N2 and blow reel dry.,Open master swab 23.5 turns. Initial WHP 0 psi. RIH. choke open. 5200'online 800 scf/min down CT. WT chk 5100'18k, RIH wt 4k. RIH 65 ft/min to PBTD. Tagged 9561'CTMD. PU WT 32k. 1567 circ pressure Increase rate to 1000 scf/min. Returns to surface. Max circ pressure to lift column of fluid 1578 psi.,Continue to lift wellbore. Pick up above pert to 9500'. Run back in to PBTD. Tag depth 9594'CTMD. 33'deeper. Did not notice counter slipping. Fluid unloaded returns dry only N2. Shut down N2 pump. Let well bleed down and monitor for LEL. WHP 325 psi on shut down 979 circ. First blow down returned 64 bbls.,Last Fluid level depth from previous slick line swab was 5750'. Leaving 3844'of fluid in well or a remaining 59 bbls. N2 blow down returned 64 bbls of fluid on first lift. indicating wellbore had 4160'of fluid column putting pre CT N2 lift fluid depth at 5410'. 325'of fluid influx between jobs. Or 5.2 bbl increase.. start seeing 20%LEL 75 WHP,678 circ. . 11 psi WHP 100%LEL.,Called town to discuss plan forward. WHP 0 psi. Well died. CTU choke was wide open. Plan forward is to come online and see what influx of water entered tubing while attempting to flow well for 1.5 hrs. Online 1000 scf/min. Fluid at surface briefly and wellbore blowing dry. Shut down N2. Strap return tank. Additional 4 bbls returned to surface on 2nd N2 lift. 273 psi WHP 1322 circ. 20-60%LEL readings,Report results to town engineer. CTxtubing is 102'/bbl. 4 bbl influx increase hydrostatic fluid level 408'. Bleed well down until 100%LEL. 100%lel shown on gas monitor. Shut in choke 58 psi WHP. Monitor SITP for 1 hr. 16:30-17:30. WHP increased from 58 psi to 354 psi. Leave well shut in overnight to see if it continues to build.,POOH to surface. WHP slowly dropping due to CT void when POOH. At surface. Close master swab 23.5 turns. SITP 318 psi.,Pop off well and rack back injector head. SLB crew will start at 0900. Either RDMO and let production flow test well, or bullhead N2 to 2000 psi or break over pressure to keep fluid back. E-line to set plug. FLUIDS: 1st lift 64 bbls 2nd lift 4 bbls Total n2 pumped 204,480 scf,or 2195 gallons. 1600 gallons of N2 remaining. 7/7/2017 Arrive on location. Production flowing well. SITP was 432 @ 0917am. Production flowing. Hold safety meeting with CT crews.,Start rigging down CTU 13. well died and quit producing at 10:50 with 17 psi on tubing pressure. Called town to discuss plan forward. Move in N2 unit and rig up to BOPE pump sub. Production isolating flow line.,N2 rigged up. PT n2 lines to 250/4000 psi. Open swab. 1400 gallons of N2 on board. Online down tubing at 1500 scf/min. WHP 210 psi. slowly climbing. increase rate to 2500 scf/min. Pressure still climbing. Note: we are looking for break over and injection. This will be difficult to see with pumping a gas which compresses. Getting low on n2. Walk pressure up to 2500 psi.,lnstalled HAK crystal guage on Flow line. Opened flow line and blocked SSV. Out of N2. 2500 psi SITP. Crystal gauge file is labeled as 11-07X nitrogen bullhead.. Did not see break over pressure while pumping. Shut in swab with crystal gauge installed so production and SCADA can monitor bleed down. When SITP pressure flat lines that is the injection pressure. 124,132 scf pumped. or 1331 gallons of N2.,SLB rigging down BOPE. Crews moving to middle pad to unload 2.375"CT and load 1.75"pipe. Coil unit will return to SLB shop for gripper block,pack off,and BOPE swap to 1.75"CT. Check with production at 1700 hrs. WHP 2260 psi. 240 psi loss over 3.5 hours. This could be pressure/N2 injecting into formation. 50-100 psi loss is normal for nitrogen once it cools. Crews off lease. 7/9/2017 Sign in.MOBE to location.PTW and JSA.Spot equipment and rig up lubricator.MU 3-1/2"CIBP w/3.75"setting sleeve.PT lubricator to 250 psi low and 4500 psi high. TP-2180.,RIH w/CIBP and tie into Digital Pell Log sent from town.Plug set down at 9534'.Got as rough as we felt good about and didn't get thru obstruction.Called town and discussed.POOH.FL-2340',RIH w/3.6"GR/JB and tie into Digital Perf Log sent from town.GR set down at same depth 9534'. Spudded on obstruction and got a couple of 300 lb over pulls but didn't make any headway.Called town and got slickline truck headed out.POOH.Had a couple ieces of contaminated cement/mud on bottom of GR.,Rig up slickline.PT 250 psi low and 4500 psi high.,RIH w/3-1/2"x10'bailer and tag fill at 9539'KB(3' deeper than eline tag).Bailed on obstruction to 9540'K and POOH to see what we had.Bailer full of water.Real sticky on bottom.,RIH w/2-1/2"x10'bailer to 9544' KB.Bailed to 9547'.POOH and had clay/cement in bailer(2').Rig down lubricator and secure well.SDFN. 7/10/2017 Sign in.MOBE to location.PTW and JSA. Rig up lubricator. PT lubricator to 250 psi low and 4500 psi high. TP-2081 psi.,RIH w/2-1/2"x10'DD bailer and tag fill at 9544'KB.Bailed to 9547'KB.Very sticky.had spang and jar up to 2800 lbs.POOH and had about couple cup full of the same formation mud.Slickline KB is about 3'deeper than E-line correlated.,RIH w/3"x10'DD bailer and tag fill at 9542', Bail on fill from 9542'to 9543'.It was very sticky with 3"bailer also.POOH and bailer was full of water.Called town and discussed.Town will decide on a different game plan.FL is 7100',Rig down slickline lubricator off well.Move eauipment out of the way. • • 7/15/2017 Obtain PTW. Hold safety meeting. Review JSA and job procedure.,Flre equipment. Prepare for BOPE test.,24 BOPE test witness notification send 7/14/17@ 1614. Witness waived by Jim Regg 7/14/17 @ 1836 hrs. Test all rams and valves 250/4000 psi.,Plck inj. stab 10'lubricator. Make up BHA. 2.125"OD Slip coil connector,2.125"OD DFCV,2.125"Hyd disc, 2.125"OD x over,1.69"OD Jet Blaster. BHA length 8.5' Pull tested connector to 25k. PT MHA 250/3500 psi. Stab on well. PT stack 250/4000 psi. Bleed down.,Open master swab 23.5 turns. Initial WHP 2030 psi.(N2 pressure from previous run) Bleed WHP down to OT tank. RIH. Previous tag depths with E-line 9536'. Tagged with CT @ 9534'CTMD. Pick up 22k to 9500',Load 2x10 bbls of fluid in displacement tanks and star mixing up flo visc gel. Online down CT to start FCO with jet blaster. Caught fluid after 18 bbls pumped. 1.2 BPM @ 3800 circ pressure. circulate at 6500'until returns established at surface. Previous fluid level from SL tag was 7100'. Send 5 bbls of gel down CT. Calculated tubing void is 109 bbls. Returns to surface after 79 bbls pumped.,RIH 10 ft/min washing from 6500' to 9581'. 4k weight stack while RIH cleaning out. Launch gel sweep. Wash up and down from 9581'up to 9525' 4 times. Returns look dark grey like unset cement.,Flnal 8 bbl gel sweep to surface.POOH continue pumping @ 1.2 bpm 4000 psi. 1:1 in/out. shut down fluid pump 300'from surface. Tagged up. Close master swab 23.5 turns. Rig back CTU injector head. PESI on location. Move cruz crane. Spot in PESI. Total Fluid pumped 284 bbls.,PTW and JSA.Rig up lubricator and PT to 250 low and 4000 psi high.,RIH w/3-1/2"CIBP and tie into digital log sent from town. Tag at 9582.5'.Spot and set CIBP at 9540'.Lost 50 lbs on wt indicator when set.Pick up 20'and go back down and tag plug.Good set.POOH and everything look good.,Rig down lubricator and secure well. 7/16/2017 Obtain PTW. Hold safety meeting. Discuss job procedure and review JSA.,Pick inj head. Stab 10'lubricator. Make up BHA 2.125"CC(slip connector), 2"OD stinger,2"OD check valves,2"Stinger,2.125"OD nozzle. BHA length 5.8'. Stab on well. PT stack 250/4000 psi.,Bleed down PT. Open master swab 23.5 turns. RIH choke open. Fluid level must have dropped. prior to setting CIBP last night. @ 2032'CTMD returns to surface. Cooling down N2. Calculated fluid level was 1560' . Online n2 500 scf/min. 952 circ. Returns @.5 bbls/min.,lncrease N2 rate to 1500 scf/min. 7888'CTMD. 1749 circulating pressure, E- line set CIBP @ 9540'. Tagged with CT at 9533'CTMD, RKB puts CT tag at 9538'corrected depth.,Parked CT at 9533'. N2 at surface. WHP 725 psi, When N2 hit out of hole micro motion(flow meter)indicated 153 bbls returned. Circ pressure 2392. Still getting slugs of water. Cont'at 1500 scf/min. OOH MM reads 165. Tank strapped at 156 bbls returned. Mostly N2 at return tank but still some fluid. 42 minutes and still getting mist/drips of fluid. Plug possibly leaking?,Calculated tubing volume from 9533'is 146 bbls. Fluid level was calculated 1560' which is 24 bbls void. . CT reel was full with volume of 35 bbls. 146-24=122+35=157 bbls. Returned tubing volume of 146 bbls as well as reel volume. POOH to surface. Shut in choke and pressure up well. Tagged up at surface. SITP 2215 psi. Close master and swab. Bleed down to OT.,Total N2 pumped for job 271,000 scf or 2910 gallons. SCF pumped for N2 lift 108,000 or 1160 gallons. N2 pumped to pressure well to 2215 psi 163,000 or 1750 gallons. Rig Down SLB CTU 13. Stage on back of pad. Awaiting further instructions. Location secure., 7/17/2017 PTW and JSA.Mobe to location..Rig up lubricator.Pressure test to 250 psi low and 4500 psi high.,RIH w/2-7/8"x5'Razor HC,6 spf,60 deg phase,tie into HLB perf correlation log dated 6-8-17 and tag at 9538'.Run correlation log and get ok to pert.Spotted and fired gun from 9511'to 9516'with 2118.9 psi.After five min pressure was 2117.5 psi.POOH.All shots fired.Gun was wet,RIH w/3-3/8"x14'(3-1/8"charges)Razor HC,6 spf,60 deg phase,tie into HLB perf correlation log dated 6-8-17 and tag at 9538'.Run correlation log and get ok to pelf.Spotted and fired gun from 9521'to 9535'with 2102.2 psi.After 10 min pressure was 2099.9 psi.POOH.All shots fired.Gun was wet,RIH w/3-3/8"x10'(3-1/8"charges)Razor HC,6 spf,60 deg phase,tie into HLB pert correlation log dated 6-8-17 and tag at 9538'.Run correlation log and get ok to perf.Spotted and fired gun from 9511'to 9521'with 2078.9 psi.After 5 min pressure was 2077.4 psi.POOH. All shots fired.Gun was wet Ria down lubricator and turn well over to field 7/24/2017 SLB mobe to gas fields from Kalotsa#4. On location lay pit liner, spot CTU equipment on 7/21/17. Arrive on location. PTW and Safety meeting. Unload equipment from trailers with production fork lift. Waiting on Cruz crane to get permit and mobilize from Kalotsa pad.,RU SLB CTU 13. Cruz crane on location continue to RU.,24 hr BOPE test witness notification sent 7/23/17 @ 11:54am. Witness waived by Jim Regg 7/24/17 @ 0833 am. Start BOPE test. Test all rams and valves 250 low,4000 psi high.,Pick injector head. Stab 10'of lubricator make up wash nozzle assembly for N2 lift. BHA OD 1.75". Length 6.5'. Stab on well. Pt stack 250/4000 psi. Bleed down. Open master and swab 23.5 turns. Initial WHP 167 psi.,RIH. Start cooling down N2. 3000'CTMD come online at 500 scf/min. Tag PBTD @ 9539'CTMD. . Increase N2 rate to 1500 scf/min. Lifted 36 bbls of fluid out of hole before blowing dry. 36 bbls of fluid is 2340'of fluid. This would put fluid level at 7200',Let well flow and stabilize. Well bleeding down. Indications of LEL at surface 20%. Hard to read due to high winds on location. 77,000 scf pumped to get 36 bbls lifted. or 826 gallons. Well bleed down to 17 psi after 1 hour.,Online with n2 at 1800 scf/min. CT depth 9539'. Unloaded 4 additional bbls of fluid from well bore after 1 hr. Online with 13 bbls of neat methanol down CT. Lay in methanol and POOH to surface. Online with N2 down backside of CT at 1200 scf/min to push methanol into formation.,continue POOH. at surface. WHP 1750 psi. Increase rate to 2300 scf/min. WHP climbing. Down on N2. WHP 2517 psi SITP. Close master and swab 23.5 turns.,268,000 scf pumped for job. 40 bbls returned for N2 blow down. 13 bbls of neat methanol injected into formation.2517 SITP. Start rigging down SLB CTU 13. Crews off location for the night. Wellhead secure. 8/1/2017 SLB on location. PTW,safety meeting. RIG up N2 pump. 1587 gallons of N2 on board. Left over N2 from previous job.,Cool down N2. HES E-line on location. PTW and hold SIMOPS safety meeting. Spot equipment. Stand clear sib PT lines to 250/4000 psi.,Online down production tubing, Initial WHP 0 psi. Walk rate up to 1500 scf/min. Keep rate the same throughout the job. Pressure consistently increasing until N2 pump lost prime. Shut in well. SITP 2189 psi. Crystal gauge hooked up to flow line to monitor pressure throughout entire job. Total SCF pumped for job.109,182 scf pumped or 1,171 gallons before losing prime on N2 pump. HES rigging up.,Continue RU HES E-line. Make up Gamma,CCL,setting tool and CIBP. CCL to top of Plug 12', Center element 12.5', Bottom of plug 13.4'. Stab on well. PT stack 250/3500 psi. RIH. Log OOH. Tie into previous correlation pass dated 23 June 2017. Send log to town. On depth. E-line parked at 9488'RKB Set top of plug at 9500'. Wait 5 minutes clean set. Pick up and tag plug. 120 lb loss. POOH.,1845 psi SITP. Make up Gamma/CCL and Pressure Temperature logging tools. Stab on well. RIH. Found fluid level at 7758'RKB. 1717'of fluid. 744 psi of hydrostatic pressure on proposed perforation interval. Parked at bottom of perf interval. Bleed down surface pressure of 1845 psi until bottom hole pressure gague reads 850 psi. Shut in choke. Surface pressure 123 psi. Log again to see if plug is holding,Found fluid level @ 7741'. 17'increase due to 1800 psi being bleed down to 1234 psi or tubing ballooning affect. POOH to surface. BHP gauge reads 849 psi. Tagged up.,Make up 15'of 3.375"GEO Gun with 3.125"razor charges. 6 SPF 60* phasing. RIH Get on depth and send log pass to town. Confirmed on Depth. CCL to top shot 12.6'. Parked at 9448.4'RBK Shoot from 9461'-9476'. WHP 123 psi. Wellhead pressure increased to 126 psi and then stabilized at 124 psi. No increase in WHP. POOH. 315 lb over pull. Possibly perf debris.,POOH to surface. Close master swab. SITP 123 psi. Pop off well. All shots fired. RDMO. Crews off location. • • 8/3/2017 Moved over from CLU-05. Inspect location,lay tarps,spot equipment,PJSM,JSA,rig up.160 Slick line PT lubricator 500/3000psi,PASS RIH w/4-1/2 swab cup,tag fluid @ 5170',begin swabbing Fluid level @—7300'KB Lay down lubricator for the night SWAB REPORT WELLKU11-07X DATE8/4/2017 PULL#FLUID LEVELPULL FROM 1731575154"Startvac 273307575new cupsTorn cups 37 8/4/2017 Office for permit. Inspect location,lay tarps,spot equipment,PJSM,JSA,rig up.160 Slickline PT lubricator 500/3000psi,PASS RIH w/4-1/2 swab cup,tag fluid @ 7660'KB Begin Swabbing RIH w 3.50 cent and sample bailer. Tag Plug @ 9503'KB Fluid @ 7830'KB Continue to swab Fluid @ 8100'KB Lay down lubricator, Secure wellhead. 32 bbls of water to tank. 8/5/2017 Office for permit. Inspect location,PJSM,JSA,rig up.160 Slickline PT lubricator 500/3000psi,PASS RIH w/4-1/2 swab cup,tag fluid 8130',Begin Swabbing RIH w/3.50"cent&1.75"sample bailer,tag TD @ 9508'KB Continue swabbing Fluid @ 8550'KB 28 bbls fluid recovered Lay down lubricator,secure wellhead PULL#FLUID LEVELPULL FROM 181308430 282208550 383008600 484 8/9/2017 Obtain PTW. Hold safety meeting. Review Job procedure.,MIRU SLB N2 float pump. Air liquid transering ligqud N2 to float. Cooling down N2. Rig up 1502" iron to flow cross on tree. N2 cooled and primed. Pressure test N2 lines to 250/4000 psi. Open master swab 23.5 turns. Online N2 down Tubing at 1500 scf/min. Flow line open to acquire data on SCADA. Crystal gauge installed on flow line as well. Was left from previous job.,1500 scf/min pressure steadily climbing. from 509 psi at 0830 until break over at 0940 at 1488 psi. Pressure started dropping from 09:40-10:00 hrs pressure dropped from 1463 psi to 1320 psi. Rate never changed from 1500 scf/min. Total SCF pumped for first stage 128,000 scf or 1374 gallons.,Lined up down tubing with HAK field triples and Neet methanol. 2 totes. took 45 minutes for first 330 gallons or 7.8 bbls. Swap totes. Online with second tote 678 WHP. took 37 minutes to pump 2nd tote of 330 gallons or 7.8 bbls. Pressure after second tote had droppecd to 480 psi at surface.,N2 cooled back down and primed. Online pushing 16 bbls of neat meth to bottom. 1500 scf/min. Starting pressure 830 psi WHP and climbing. Max pressure reached for 2nd stage of N2 1415 psi @ 1500 scf/min. Pressure broke from 1415 to 1400 and continued to drop. Shut down N2 pump Close master swab. Total SCF pumped for 2nd stage on N2 62,000 scf or 665 gallons.,Secure well. Bleed down N2 line. Rig down N2 float. Park on edge of pad. Hook up blow down tank and choke skid to well flow cross. (X chem tanks emptied and will pick up in AM) Loader left on location to assist with empty totes. Total Neet Methanol pumped 16 bbls. Total N2 pumped:193,000 scf or 2,060 Gallons. I calculated worst case scenario for N2 volume factor with 850 psi and fluid to surface.,Estimated volume of N2 need for job procedure was 2200 gallons. Total used volume of 2,060 gallons. This could be to average pressure average temperature differences. Also, fluid level was not at surface. Notify production that well is secure and turn over to flow. 8/17/2017 Mobe to location. PTW,JSA and SIMOPS with HLB and SLB N2..Rig up lubricator and N2 hard lines.Pressure test to 250 psi low and 4500 psi high.,RIH w/Press-Temp tool and tagged fluid level at 7426'.Brought N2 on line and to push fluid into the open perfs at 9461'to 9476'.Brought pressure up to 1000 psi at rate from 300 scf/min starting out and up to 695 scf/min at 900 psi.Pressure was 930 psi on crystal gauges.We followed fluid level down with P/T tool and then picked up to 9455,shut N2 pump down and waited 15 min til pressure dropped to 795 psi and,fluid did not come back in well.Started pumping again at 900 psi and held that pressure while we pulled out of hole.Ran correlation log from 9180'to 9462'. Sent to town and got ok to use log to set plug.,RIH with 3.74"CIBP while pumping at 900 psi at 820 scf/min and tie into Correlation log we just ran.Tool became stuck at 9462'.Shut pump down and let well start to equalize to 830 psi and tool came free.Brought N2 back on line at 900 psi at 944 scf/min and pumped for additional 10 min.Shut down pump and set plug at 9455'w/809 psi on tubing.Lost 150 lbs of line wt when plug set.Picked up 30'and went back,and tagged top of plug at 9455'.POOH.Setting tool looked good.We pumped a total of 2000 gals of N2.Out of hole and TP was 806 psi.SLB N2 crew rigged down their equipment.,Mixed 3.2 gals of cement and loaded bailer.RIH to 300'and CCUGR tool stopped working.Pulled out of hole and dumped cement in a bucket.Mixed another batch of cement and RIH w/3-1/2"x10'bailer filled with 3.2 gals of cement(5'of cement in 4-1/2"tubing)and tagged plug at 9455.Pick up and dumped cement on top of plug.TOC est at 9450'and cement in place at 1730 hrs.,Rig lubricator off the well.Scope crane down and WOC.Will have HLB out here at 9 am in the morning to start rig up if the cement sample is hard enough. TP-800 psi. 8/18/2017 Mobe to location.PTW and JSA.Pressure test to 250 psi low and 4500 psi high.,RIH w/Press/Temp tool and tie into plug log.Tagged TOC at 9450'.Blow TP down to 600 psi BHP.TP was 435 psi on crystal gauges.Found no fluid in well.POOH,RIH w/2-7/8"x14'Razor HC,6 spf,60 deg phase and tie into plug log. Run correlation log and send to town. Log was 2'high.Adjusted and resend to town.Get ok to perf from 9431'to 9445'.Spotted gun and fired with 437.7 psi on tubing. TP was 438.5 psi.POOH.All shots fired and gun was dry.,Rig down lubricator and turn well over to field. • . 8/21/2017 JSA/TGSM RIG UP ON WELL PIT 2500PSI GOOD RIH W/2"DD BAILER TO 9450KB POOH RIH W/SURVEY SEE STOP SHEET OOH W/GOOD DATA RIG DOWN,MOVE OVER TO KU 11-08 8/25/2017 Mobe to location.PTW and JSA.Pressure test to 250 psi low and 3500 psi high.,RIH w13.74"OD CIBP and tie in to HLB Plug set log dated 8-17-17.Run correlation log and send to town.Adjusted log down 2'(we were 2'high),Get ok to set plug.Set plug with 690 psi on tubing at 9420'.POOH.N2 started pressuring up tubing as we are coming out of hole.POOH.Good set.,RIH w/GPT tool while pumping N2.Shut N2 down at 1400 psi and cont in hole with tool. Found fluid level at 9306'.POOH while pumping N2.Pressured up tubing to 2430 psi.Total N/2 pump was 110021 SCF(1700 gals)at 1000 to 1600 scf/min.,RIH w12-7/8"x31'Razor HC,6 spf,60 degree phase and tie into Plug log.Ran correlation log and send to town.Adjusted log down 2'and send back. Town ok to perf from 9274'to 9305'.Spotted and fired gun with 2380 psi on tubing.Pressure starts falling and after 5 mins-2299 psi;10 min-2237.POOH. Gun dry.All shots fired Ria down lubricator and move to KBU 11-08Y. TP-1568 osi • • Hilcorp Alaska, LLC Kenai Gas Field KGF 14-6 Pad KU 11-07X 50-133-20662-00-00 Sperry Drilling Definitive Survey Report 05 May, 2017 3 � ' III 1111 HALL BURTON Sperry Drilling • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well KU 11-07X Project: Kenai Gas Field TVD Reference: KBU 11-07X Ac-Built @ 81.63usft(Saxon 169) Site: KGF 14-6 Pad MD Reference: KBU 11-07XAs-Built @ 81.63usft(Saxon 169) Well: KU 11-07X North Reference: True ' Wellbore: KU 11-07X Survey Calculation Method: Minimum Curvature Design: KU 11-07X Database: Sperry EDM-NORTH US+CANADA Project Kenai Gas 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 Using geodetic scale factor Well KU 11-07X Well Position +N/-S 0.00 usft Northing: 2,362,258.42 usft Latitude: 60°27'36.116 N +E/-W 0.00 usft Easting: 271,914.47 usft Longitude: 151°15'48.963 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 63.63 usft Wellbore KU 11-07X Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (') (nT) BGGM2016 4/13/2017 15.94 73.46 55,349 Design KU 11-07X I Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 18.00 ' Vertical Section: Depth From(TVD) +N/-S +EI-W Direction (usft) (usft) (usft) (°) 18.00 0.00 0.00 178.41 Survey Program Date 5/5/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 181.74 1,484.37 MWD+SC+sag(KU 11-07X) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 04/17/2017 1,568.95 6,064.65 MWD+SC+sag(2)(KU 11-07X) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 04/24/2017 ' 6,120.26 9,760.49 MWD+SC+sag(3)(KU 11-07X) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 05/01/2017 I Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 18.00 0.00 0.00 18.00 -63.63 0.00 0.00 2,362,258.42 271,914.47 0.00 0.00 UNDEFINED 181.74 0.02 192.06 181.74 100.11 -0.03 -0.01 2,362,258.39 271,914.46 0.01 0.03 MWD+SC+sag(1) 241.10 0.24 217.56 241.10 159.47 -0.14 -0.08 2,362,258.29 271,914.38 0.37 0.13 MWD+SC+sag(1) 302.64 0.26 183.06 302.64 221.01 -0.38 -0.17 2,362,258.05 271,914.29 0.24 0.37 MWD+SC+sag(1) 386.78 0.86 233.02 386.78 305.15 -0.95 -0.68 2,362,257.48 271,913.77 0.86 0.93 MWD+SC+sag(1) 446.54 0.84 212.48 446.53 364.90 -1.59 -1.28 2,362,256.86 271,913.16 0.51 1.55 MWD+SC+sag(1) 505.51 1.17 219.62 505.49 423.86 -2.42 -1.89 2,362,256.04 271,912.53 0.60 2.36 MWD+SC+sag(1) 569.32 1.02 211.37 569.29 487.66 -3.40 -2.61 2,362,255.07 271,911.80 0.34 3.33 MWD+SC+sag(1) 630.24 2.84 225.50 630.17 548.54 -4.92 -3.96 2,362,253.57 271,910.41 3.07 4.81 MWD+SC+sag(1) 1 691.35 5.13 240.67 691.13 609.50 -7.32 -7.43 2,362,251.24 271,906.90 4.09 7.11 MWD+SC+sag(1) 753.78 5.81 237.21 753.28 671.65 -10.40 -12.52 2,362,248.26 271,901.76 1.21 10.05 MWD+SC+sag(1) 816.25 6.15 243.90 815.41 733.78 -13.59 -18.18 2,362,245.18 271,896.03 1.24 13.08 MWD+SC+sag(1) 5/5/2017 7:26:42PM Page 2 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well KU 11-07X Project: Kenai Gas Field TVD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Site: KGF 14-6 Pad MD Reference: KBU 11-07XAs-Built @ 81.63usft(Saxon 169) Well: KU 11-07X North Reference: True '' Wellbore: KU 11-07X Survey Calculation Method: Minimum Curvature Design: KU 11-07X Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 877.87 7.30 249.19 876.60 794.97 -16.43 -24.80 2,362,242.47 271,889.36 2.12 15.74 MWD+SC+sag(1) 940.93 6.30 238.03 939.22 857.59 -19.69 -31.48 2,362,239.34 271,882.62 2.62 18.80 MWD+SC+sag(1) 1,003.33 7.13 238.02 1,001.19 919.56 -23.55 -37.67 2,362,235.60 271,876.35 1.33 22.49 MWD+SC+sag(1) 1,065.75 6.05 236.48 1,063.20 981.57 -27.42 -43.70 2,362,231.85 271,870.25 1.75 26.19 MWD+SC+sag(1) 1,128.31 6.46 237.39 1,125.39 1,043.76 -31.13 -49.41 2,362,228.24 271,864.47 0.67 29.75 MWD+SC+sag(1) 1,193.12 5.80 236.28 1,189.83 1,108.20 -34.92 -55.21 2,362,224.57 271,858.60 1.03 33.37 MWD+SC+sag(1) 1,252.62 5.82 238.15 1,249.02 1,167.39 -38.18 -60.27 2,362,221.41 271,853.48 0.32 36.49 MWD+SC+sag(1) 1,315.12 6.72 237.66 1,311.15 1,229.52 -41.81 -66.05 2,362,217.89 271,847.63 1.44 39.96 MWD+SC+sag(1) 1,376.88 6.34 240.22 1,372.51 1,290.88 -45.43 -72.07 2,362,214.38 271,841.55 0.77 43.42 MWD+SC+sag(1) 1,438.86 5.37 242.82 1,434.16 1,352.53 -48.46 -77.62 2,362,211.46 271,835.94 1.62 46.29 MWD+SC+sag(1) 1,484.37 5.50 238.60 1,479.47 1,397.84 -50.57 -81.37 2,362,209.43 271,832.14 0.92 48.29 MWD+SC+sag(1) 1,568.95 6.46 233.66 1,563.59 1,481.96 -55.50 -88.67 2,362,204.63 271,824.76 1.29 53.02 MWD+SC+sag(2) 1,630.22 6.70 232.67 1,624.45 1,542.82 -59.71 -94.28 2,362,200.53 271,819.06 0.43 57.07 MWD+SC+sag(2) 1,692.57 6.58 233.02 1,686.38 1,604.75 -64.06 -100.03 2,362,196.29 271,813.23 0.20 61.26 MWD+SC+sag(2) 1,754.18 7.14 231.95 1,747.55 1,665.92 -68.55 -105.87 2,362,191.92 271,807.31 0.93 65.58 MWD+SC+sag(2) 1,816.61 5.84 235.75 1,809.58 1,727.95 -72.73 -111.55 2,362,187.85 271,801.55 2.19 69.60 MWD+SC+sag(2) 1,879.62 5.74 236.66 1,872.27 1,790.64 -76.26 -116.83 2,362,184.42 271,796.20 0.22 72.99 MWD+SC+sag(2) 1,942.12 5.55 237.13 1,934.47 1,852.84 -79.62 -121.98 2,362,181.16 271,790.99 0.31 76.20 MWD+SC+sag(2) 2,004.81 5.87 236.07 1,996.85 1,915.22 -83.05 -127.18 2,362,177.82 271,785.72 0.54 79.49 MWD+SC+sag(2) 2,066.80 5.48 244.49 2,058.53 1,976.90 -86.10 -132.49 2,362,174.88 271,780.36 1.48 82.39 MWD+SC+sag(2) 2,130.29 5.84 244.19 2,121.71 2,040.08 -88.81 -138.13 2,362,172.28 271,774.67 0.57 84.94 MWD+SC+sag(2) 2,190.91 5.64 244.86 2,182.03 2,100.40 -91.42 -143.60 2,362,169.78 271,769.15 0.35 87.40 MWD+SC+sag(2) 2,254.64 6.16 244.26 2,245.42 2,163.79 -94.23 -149.52 2,362,167.08 271,763.18 0.82 90.05 MWD+SC+sag(2) 2,315.16 6.13 244.51 2,305.59 2,223.96 -97.03 -155.36 2,362,164.39 271,757.28 0.07 92.69 MWD+SC+sag(2) 2,378.28 6.21 244.26 2,368.35 2,286.72 -99.97 -161.48 2,362,161.57 271,751.11 0.13 95.45 MWD+SC+sag(2) 2,442.39 6.52 244.08 2,432.06 2,350.43 -103.06 -167.87 2,362,158.60 271,744.66 0.48 98.37 MWD+SC+sag(2) 2,503.05 6.78 243.45 2,492.31 2,410.68 -106.17 -174.17 2,362,155.61 271,738.30 0.45 101.30 MWD+SC+sag(2) 2,564.71 7.08 243.41 2,553.52 2,471.89 -109.50 -180.83 2,362,152.42 271,731.58 0.49 104.44 MWD+SC+sag(2) 2,626.97 7.00 243.53 2,615.32 2,533.69 -112.91 -187.66 2,362,149.14 271,724.69 0.13 107.66 MWD+SC+sag(2) 2,688.92 6.42 242.32 2,676.84 2,595.21 -116.20 -194.10 2,362,145.97 271,718.18 0.96 110.77 MWD+SC+sag(2) 2,751.01 6.44 241.59 2,738.54 2,656.91 -119.47 -200.24 2,362,142.82 271,711.98 0.14 113.87 MWD+SC+sag(2) 2,813.16 6.52 242.99 2,800.29 2,718.66 -122.73 -206.45 2,362,139.68 271,705.71 0.28 116.95 MWD+SC+sag(2) 2,874.56 6.62 242.78 2,861.29 2,779.66 -125.93 -212.70 2,362,136.60 271,699.40 0.17 119.98 MWD+SC+sag(2) 2,937.18 7.01 241.84 2,923.47 2,841.84 -129.38 -219.28 2,362,133.27 271,692.76 0.65 123.25 MWD+SC+sag(2) 2,999.17 6.96 242.89 2,985.00 2,903.37 -132.88 -225.96 2,362,129.90 271,686.01 0.22 126.56 MWD+SC+sag(2) 3,060.94 6.46 240.25 3,046.34 2,964.71 -136.31 -232.31 2,362,126.60 271,679.60 0.95 129.81 MWD+SC+sag(2) 3,122.77 6.22 239.32 3,107.80 3,026.17 -139.75 -238.21 2,362,123.28 271,673.64 0.42 133.08 MWD+SC+sag(2) 3,185.84 5.83 241.12 3,170.52 3,088.89 -143.04 -243.95 2,362,120.10 271,667.83 0.69 136.21 MWD+SC+sag(2) 3,248.97 5.82 241.90 3,233.32 3,151.69 -146.09 -249.58 2,362,117.15 271,662.14 0.13 139.11 MWD+SC+sag(2) 3,310.81 5.96 241.93 3,294.83 3,213.20 -149.08 -255.18 2,362,114.27 271,656.49 0.23 141.94 MWD+SC+sag(2) 5/5/2017 7:26:42PM Page 3 COMPASS 5000.1 Build 81 i f Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well KU 11-07X Project: Kenai Gas Field TVD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Site: KGF 14-6 Pad MD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Well: KU 11-07X North Reference: True Wellbore: KU 11-07X Survey Calculation Method: Minimum Curvature Design: KU 11-07X Database: Sperry EDM-NORTH US+CANADA Survey j Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,373.30 6.02 242.28 3,356.98 3,275.35 -152.13 -260.94 2,362,111.33 271,650.67 0.11 144.83 MWD+SC+sag(2) 3,435.52 5.97 242.00 3,418.86 3,337.23 -155.17 -266.69 2,362,108.40 271,644.86 0.09 147.71 MWD+SC+sag(2) 3,497.62 6.02 242.64 3,480.62 3,398.99 -158.18 -272.43 2,362,105.50 271,639.06 0.13 150.56 MWD+SC+sag(2) 3,559.49 6.38 242.89 3,542.13 3,460.50 -161.24 -278.37 2,362,102.56 271,633.07 0.58 153.45 MWD+SC+sag(2) 3,621.41 6.71 242.36 3,603.65 3,522.02 -164.48 -284.64 2,362,099.43 271,626.74 0.54 156.52 MWD+SC+sag(2) 3,684.03 6.59 241.68 3,665.85 3,584.22 -167.89 -291.04 2,362,096.16 271,620.27 0.23 159.75 MWD+SC+sag(2) 3,745.78 6.68 237.86 3,727.18 3,645.55 -171.48 -297.20 2,362,092.68 271,614.04 0.73 163.17 MWD+SC+sag(2) 3,807.72 7.22 224.01 3,788.67 3,707.04 -176.19 -302.96 2,362,088.08 271,608.20 2.83 167.72 MWD+SC+sag(2) 3,868.83 8.14 212.63 3,849.24 3,767.61 -182.60 -307.96 2,362,081.77 271,603.07 2.90 173.98 MWD+SC+sag(2) 3,931.42 8.70 200.61 3,911.16 3,829.53 -190.76 -312.02 2,362,073.69 271,598.86 2.94 182.03 MWD+SC+sag(2) 3,993.02 9.20 187.72 3,972.01 3,890.38 -200.00 -314.32 2,362,064.49 271,596.38 3.35 191.21 MWD+SC+sag(2) 4,054.73 9.47 175.30 4,032.91 3,951.28 -209.95 -314.57 2,362,054.55 271,595.95 3.29 201.14 MWD+SC+sag(2) 4,117.11 9.10 170.12 4,094.48 4,012.85 -219.93 -313.30 2,362,044.55 271,597.02 1.46 211.15 MWD+SC+sag(2) 4,179.11 9.78 160.97 4,155.64 4,074.01 -229.74 -310.74 2,362,034.70 271,599.39 2.65 221.03 MWD+SC+sag(2) 4,241.03 9.97 158.37 4,216.64 4,135.01 -239.69 -307.05 2,362,024.67 271,602.89 0.78 231.08 MWD+SC+sag(2) 4,303.42 9.42 154.62 4,278.14 4,196.51 -249.33 -302.87 2,362,014.96 271,606.88 1.34 240.83 MWD+SC+sag(2) 4,365.35 9.83 154.33 4,339.20 4,257.57 -258.67 -298.41 2,362,005.53 271,611.17 0.67 250.29 MWD+SC+sag(2) 4,428.28 9.63 155.67 4,401.22 4,319.59 -268.31 -293.91 2,361,995.81 271,615.48 0.48 260.05 MWD+SC+sag(2) 4,491.29 9.25 154.96 4,463.38 4,381.75 -277.70 -289.60 2,361,986.34 271,619.61 0.63 269.55 MWD+SC+sag(2) 4,553.66 9.34 155.30 4,524.93 4,443.30 -286.84 -285.36 2,361,977.12 271,623.67 0.17 278.81 MWD+SC+sag(2) 4,616.34 9.64 154.84 4,586.75 4,505.12 -296.21 -281.00 2,361,967.67 271,627.85 0.49 288.30 MWD+SC+sag(2) 4,678.35 10.00 154.33 4,647.86 4,566.23 -305.76 -276.46 2,361,958.03 271,632.20 0.60 297.97 MWD+SC+sag(2) 4,740.68 8.53 156.48 4,709.37 4,627.74 -314.88 -272.28 2,361,948.84 271,636.21 2.42 307.20 MWD+SC+sag(2) 4,802.20 8.23 156.65 4,770.23 4,688.60 -323.10 -268.71 2,361,940.55 271,639.62 0.49 315.52 MWD+SC+sag(2) 4,864.52 8.62 156.06 4,831.88 4,750.25 -331.47 -265.05 2,361,932.11 271,643.12 0.64 323.98 MWD+SC+sag(2) 4,926.59 9.05 155.01 4,893.21 4,811.58 -340.14 -261.10 2,361,923.36 271,646.91 0.74 332.77 MWD+SC+sag(2) 4,988.65 9.15 154.86 4,954.49 4,872.86 -349.03 -256.94 2,361,914.39 271,650.69 0.17 341.77 MWD+SC+sag(2) 5,051.91 9.56 155.64 5,016.91 4,935.28 -358.37 -252.63 2,361,904.98 271,655.02 0.68 351.22 MWD+SC+sag(2) 5,113.74 9.72 154.56 5,077.87 4,996.24 -367.76 -248.27 2,361,895.50 271,659.19 0.39 360.73 MWD+SC+sag(2) 5,175.78 10.23 155.00 5,138.97 5,057.34 -377.49 -243.70 2,361,885.70 271,663.59 0.83 370.58 MWD+SC+sag(2) 5,237.32 10.41 155.86 5,199.52 5,117.89 -387.51 -239.11 2,361,875.58 271,667.98 0.38 380.73 MWD+SC+sag(2) 5,300.33 9.65 153.42 5,261.56 5,179.93 -397.43 -234.42 2,361,865.58 271,672.48 1.38 390.77 MWD+SC+sag(2) 5,363.81 9.33 153.34 5,324.17 5,242.54 -406.79 -229.73 2,361,856.13 271,676.98 0.50 400.26 MWD+SC+sag(2) 5,426.40 9.77 153.85 5,385.90 5,304.27 -416.09 -225.12 2,361,846.74 271,681.42 0.72 409.68 MWD+SC+sag(2) 5,488.31 9.66 152.52 5,446.92 5,365.29 -425.41 -220.40 2,361,837.33 271,685.95 0.40 419.13 MWD+SC+sag(2) 5,552.13 10.09 152.70 5,509.79 5,428.16 -435.13 -215.37 2,361,827.52 271,690.80 0.68 428.99 MWD+SC+sag(2) 5,614.27 9.67 155.84 5,571.01 5,489.38 -444.73 -210.74 2,361,817.83 271,695.25 1.10 438.71 MWD+SC+sag(2) 5,674.06 9.22 158.56 5,629.99 5,548.36 -453.77 -206.93 2,361,808.72 271,698.88 1.06 447.85 MWD+SC+sag(2) 5,735.97 9.71 156.99 5,691.06 5,609.43 -463.19 -203.08 2,361,799.23 271,702.55 0.89 457.38 MWD+SC+sag(2) 5,798.22 9.65 157.92 5,752.42 5,670.79 -472.86 -199.06 2,361,789.49 271,706.38 0.27 467.15 MWD+SC+sag(2) 5/5/2017 7:26:42PM Page 4 COMPASS 5000.1 Build 81 i • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well KU 11-07X Project: Kenai Gas Field TVD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Site: KGF 14-6 Pad MD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Well: KU 11-07X North Reference: True Wellbore: KU 11-07X Survey Calculation Method: Minimum Curvature Design: KU 11-07X Database: Sperry EDM-NORTH US+CANADA Survey I Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,860.70 9.80 157.50 5,814.00 5,732.37 -482.62 -195.06 2,361,779.65 271,710.19 0.27 477.02 MWD+SC+sag(2) 5,922.67 8.84 158.88 5,875.16 5,793.53 -491.94 -191.33 2,361,770.26 271,713.75 1.59 486.44 MWD+SC+sag(2) 5,988.17 8.81 158.07 5,939.88 5,858.25 -501.29 -187.64 2,361,760.85 271,717.26 0.20 495.89 MWD+SC+sag(2) 6,064.65 8.89 158.43 6,015.45 5,933.82 -512.21 -183.28 2,361,749.84 271,721.40 0.13 506.93 MWD+SC+sag(2) 6,120.26 9.11 157.75 6,070.37 5,988.74 -520.28 -180.03 2,361,741.71 271,724.50 0.44 515.09 MWD+SC+sag(3) 6,183.37 9.36 157.35 6,132.67 6,051.04 -529.64 -176.16 2,361,732.27 271,728.18 0.41 524.55 MWD+SC+sag(3) 6,245.81 9.86 156.18 6,194.23 6,112.60 -539.22 -172.05 2,361,722.62 271,732.11 0.86 534.24 MWD+SC+sag(3) 6,308.18 10.26 155.76 6,255.64 6,174.01 -549.17 -167.61 2,361,712.59 271,736.36 0.65 544.31 MWD+SC+sag(3) 6,370.23 8.66 152.95 6,316.85 6,235.22 -558.37 -163.22 2,361,703.31 271,740.57 2.68 553.63 MWD+SC+sag(3) 6,430.64 8.33 152.17 6,376.59 6,294.96 -566.29 -159.11 2,361,695.31 271,744.53 0.58 561.66 MWD+SC+sag(3) 6,493.10 8.37 150.85 6,438.39 6,356.76 -574.26 -154.78 2,361,687.26 271,748.71 0.31 569.75 MWD+SC+sag(3) 6,555.03 7.91 159.01 6,499.70 6,418.07 -582.18 -151.06 2,361,679.27 271,752.27 2.01 577.76 MWD+SC+sag(3) 6,617.21 7.94 160.65 6,561.29 6,479.66 -590.23 -148.10 2,361,671.17 271,755.08 0.37 585.89 MWD+SC+sag(3) 6,679.11 8.32 158.55 6,622.56 6,540.93 -598.43 -145.05 2,361,662.91 271,757.97 0.78 594.17 MWD+SC+sag(3) 6,740.91 8.51 157.39 6,683.70 6,602.07 -606.81 -141.66 2,361,654.46 271,761.20 0.41 602.65 MWD+SC+sag(3) 6,803.49 8.86 156.61 6,745.56 6,663.93 -615.51 -137.96 2,361,645.70 271,764.73 0.59 611.44 MWD+SC+sag(3) 6,865.58 8.95 154.57 6,806.90 6,725.27 -624.26 -133.99 2,361,636.87 271,768.53 0.53 620.30 MWD+SC+sag(3) 6,928.03 9.05 154.22 6,868.58 6,786.95 -633.07 -129.77 2,361,627.98 271,772.58 0.18 629.22 MWD+SC+sag(3) 6,989.88 9.29 153.16 6,929.64 6,848.01 -641.90 -125.40 2,361,619.07 271,776.78 0.47 638.18 MWD+SC+sag(3) 7,052.87 9.44 159.65 6,991.79 6,910.16 -651.28 -121.31 2,361,609.61 271,780.69 1.69 647.67 MWD+SC+sag(3) 7,115.77 9.36 159.61 7,053.85 6,972.22 -660.91 -117.73 2,361,599.91 271,784.08 0.13 657.39 MWD+SC+sag(3) 7,178.40 9.71 158.84 7,115.61 7,033.98 -670.61 -114.05 2,361,590.15 271,787.58 0.59 667.19 MWD+SC+sag(3) 7,241.10 8.81 163.89 7,177.50 7,095.87 -680.16 -110.81 2,361,580.54 271,790.64 1.93 676.82 MWD+SC+sag(3) 7,302.83 8.51 164.52 7,238.52 7,156.89 -689.10 -108.28 2,361,571.55 271,792.99 0.51 685.83 MWD+SC+sag(3) 7,364.51 8.46 163.80 7,299.53 7,217.90 -697.86 -105.79 2,361,562.75 271,795.31 0.19 694.65 MWD+SC+sag(3) 7,426.64 8.57 161.49 7,360.97 7,279.34 -706.63 -103.05 2,361,553.92 271,797.89 0.58 703.50 MWD+SC+sag(3) 7,488.28 8.58 161.30 7,421.93 7,340.30 -715.35 -100.12 2,361,545.16 271,800.65 0.05 712.29 MWD+SC+sag(3) 7,550.62 8.55 160.03 7,483.57 7,401.94 -724.11 -97.04 2,361,536.34 271,803.56 0.31 721.13 MWD+SC+sag(3) 7,612.75 8.64 159.64 7,545.00 7,463.37 -732.82 -93.84 2,361,527.56 271,806.59 0.17 729.94 MWD+SC+sag(3) 7,675.37 8.99 157.78 7,606.88 7,525.25 -741.76 -90.36 2,361,518.56 271,809.90 0.72 738.97 MWD+SC+sag(3) 7,738.10 9.31 156.77 7,668.81 7,587.18 -750.96 -86.50 2,361,509.29 271,813.58 0.57 748.27 MWD+SC+sag(3) 7,800.03 9.64 155.79 7,729.90 7,648.27 -760.29 -82.40 2,361,499.88 271,817.50 0.59 757.71 MWD+SC+sag(3) 7,861.93 9.69 154.34 7,790.92 7,709.29 -769.72 -78.02 2,361,490.37 271,821.70 0.40 767.25 MWD+SC+sag(3) 7,925.31 8.74 158.07 7,853.48 7,771.85 -778.99 -73.91 2,361,481.02 271,825.63 1.77 776.64 MWD+SC+sag(3) 7,987.46 8.74 156.85 7,914.91 7,833.28 -787.71 -70.29 2,361,472.23 271,829.08 0.30 785.46 MWD+SC+sag(3) 8,050.72 8.40 154.85 7,977.47 7,895.84 -796.31 -66.44 2,361,463.56 271,832.77 0.71 794.16 MWD+SC+sag(3) 8,112.31 8.15 154.65 8,038.41 7,956,78 -804.33 -62.66 2,361,455.47 271,836.40 0.41 802.28 MWD+SC+sag(3) 8,176.09 8.26 150.14 8,101.54 8,019.91 -812.39 -58.44 2,361,447.33 271,840.46 1.02 810.46 MWD+SC+sag(3) 8,238.04 8.43 157.17 8,162.84 8,081.21 -820.44 -54.46 2,361,439.21 271,844.28 1.67 818.61 MWD+SC+sag(3) 8,298.39 8.52 158.89 8,222.53 8,140.90 -828.68 -51.13 2,361,430.90 271,847.45 0.45 826.95 MWD+SC+sag(3) 5/5/2017 7:26:42PM Page 5 COMPASS 5000.1 Build 81 • . Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well KU 11-07X Project: Kenai Gas Field TVD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Site: KGF 14-6 Pad MD Reference: KBU 11-07XAs-Built @ 81.63usft(Saxon 169) Well: KU 11-07X North Reference: True Wellbore: KU 11-07X Survey Calculation Method: Minimum Curvature Design: KU 11-07X Database: Sperry EDM-NORTH US+CANADA SurveyViitien ,§1V. Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,360.44 8.56 159.87 8,283.89 8,202.26 -837.31 -47.89 2,361,422.22 271,850.53 0.24 835.66 MWD+SC+sag(3) 8,422.73 8.46 160.18 8,345.49 8,263.86 -845.97 -44.74 2,361,413.50 271,853.51 0.18 844.40 MWD+SC+sag(3) 8,484.81 9.37 162.14 8,406.82 8,325.19 -855.08 -41.64 2,361,404.33 271,856.43 1.55 853.59 MWD+SC+sag(3) 8,546,93 9.30 160.67 8,468.12 8,386.49 -864.63 -38.43 2,361,394.73 271,859.46 0.40 863.23 MWD+SC+sag(3) 8,610.28 9.44 159.87 8,530.63 8,449.00 -874.33 -34.95 2,361,384.95 271,862.75 0.30 873.03 MWD+SC+sag(3) 8,673.00 9.41 156.10 8,592.50 8,510.87 -883.85 -31.10 2,361,375.36 271,866.42 0.99 882.65 MWD+SC+sag(3) 8,737.64 9.49 155.43 8,656.26 8,574.63 -893.53 -26.74 2,361,365.61 271,870.59 0.21 892.44 MWD+SC+sag(3) 8,798.26 8.58 158.69 8,716.13 8,634.50 -902.29 -23.02 2,361,356.78 271,874.14 1.72 901.30 MWD+SC+sag(3) 8,860.73 8.53 154.60 8,777.91 8,696.28 -910.81 -19.34 2,361,348.18 271,877.66 0.98 909.93 MWD+SC+sag(3) 8,922.73 8.93 153.05 8,839.19 8,757.56 -919.26 -15.19 2,361,339.66 271,881.65 0.75 918.48 MWD+SC+sag(3) 8,985.59 9.24 149.74 8,901.26 8,819.63 -927.96 -10.43 2,361,330.86 271,886.23 0.97 927.32 MWD+SC+sag(3) 9,045.99 9.53 147.72 8,960.85 8,879.22 -936.38 -5.32 2,361,322.35 271,891.19 0.73 935.87 MWD+SC+sag(3) 9,108.96 9.19 143.78 9,022.98 8,941.35 -944.84 0.44 2,361,313.78 271,896.78 1.15 944.49 MWD+SC+sag(3) 9,170.36 9.48 140.26 9,083.57 9,001.94 -952.69 6.57 2,361,305.82 271,902.75 1.04 952.50 MWD+SC+sag(3) 9,234.03 9.29 136.51 9,146.39 9,064.76 -960.45 13.45 2,361,297.93 271,909.49 1.01 960.45 MWD+SC+sag(3) 9,295.56 9.64 133.38 9,207.08 9,125.45 -967.59 20.62 2,361,290.65 271,916.52 1.01 967.79 MWD+SC+sag(3) 9,359.15 10.02 133.60 9,269.74 9,188.11 -975.06 28.49 2,361,283.03 271,924.25 0.60 975.48 MWD+SC+sag(3) 9,421.27 10.03 131.21 9,330.91 9,249.28 -982.35 36.48 2,361,275.59 271,932.09 0.67 982.99 MWD+SC+sag(3) 9,483.47 10.33 128.36 9,392.13 9,310.50 -989.38 44.92 2,361,268.40 271,940.40 0.94 990.25 MWD+SC+sag(3) 9,545.33 10.67 125.68 9,452.96 9,371.33 -996.16 53.92 2,361,261.44 271,949.27 0.96 997.28 MWD+SC+sag(3) 9,607.70 10.87 123.03 9,514.23 9,432.60 -1,002.74 63.55 2,361,254.69 271,958.76 0.86 1,004.12 MWD+SC+sag(3) 9,669.36 11.33 121.66 9,574.73 9,493.10 -1,009.09 73.57 2,361,248.15 271,968.67 0.86 1,010.74 MWD+SC+sag(3) 9,760.49 11.51 114.76 9,664.06 9,582.43 -1,017.59 89.45 2,361,239.34 271,984.38 1.51 1,019.68 MWD+SC+sag(3) 9,799.00 11.51 114.76 9,701.80 9,620.17 -1,020.81 96.43 2,361,235.99 271,991.29 0.00 1,023.09 PROJECTED to TD mitchell.lairdahalliburton.com Michael Calkins Checked By: 2017.05.0516:30:55-08'00' Approved By: Date: 5/5/2017 5/5/2017 7:26:42PM Page 6 COMPASS 5000.1 Build 81 • • Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. KEU KU 11-07X Date Run 19-Apr-17 County State Alaska Supv. C.Montague/A.Dorr CASING RECORD Surface IP, TD 1,522.00 Shoe Depth: 1,511.63 PBTD: 1,426.25 No.Jts.Delivered 44 No.Jts.Run 36 No.Jts.Returned 8 Ftg.Delivered Ftg.Run 1,490.03 Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. Ftg.Balance RKB 18.00 RKB to BHF 21.80 RKB to CHF RKB to THF 18.40 Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 117/8 BTC Antelope 1.29 1,511.63 1,510.34 2 Casing 10 3/4 45.5 L-80 BTC Tenaris 82.49 1,510.34 1,427.85 Float Collar 11 7/8 BTC Antelope 1.60 1,427.85 1,426.25 34 Casing 10 3/4 45.5 L-80 BTC Tenaris 1,401.61 1,426.25 24.64 Hanger and Pup 10 3/4 BTC 3.04 24.64 21.60 Csg Wt.On Hook: 70,000 Type Float Collar: Antelope No.Hrs to Run: 5.5 Csg Wt.On Slips: 70,000 Type of Shoe: Bullnose Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg X Yes No Ft.Min. 9 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: 2 on joint#1,1 on Joint#3 and Joint#4;every other joint to Joint#29(311') CEMENTING REPORT Shoe @ 1511.63 FC @ 1,426.25 Top of Liner #N/A Preflush(Spacer) Type: MudPush II Density(ppg) 10 Volume pumped(BBLs) 20.5 Lead Slurry Type: A Sacks: 327 Yield: 2.42 Density(ppg) 12 Volume pumped(BBLs) 141 Mixing/Pumping Rate(bpm): 5.7 Tail Slurry Lu Type: A Sacks: 280 Yield: 1.22 FDensity(ppg) 15.4 Volume pumped(BBLs) 61 Mixing/Pumping Rate(bpm): 4.6 ' Post Flush(Spacer) 1— in Type:Water Density(ppg) 8.34 Rate(bpm): 5 Volume: 10 LL Displacement: Type: Spud Mud Density(ppg) 9 Rate(bpm): 5.7 Volume(actual/calculated): 128.5/127.7 FCP(psi): 650 Pump used for disp: SLB cement truck Bump Plug?' X Yes No Bump press 1250 Casing Rotated? Yes X No Reciprocated? X ''Yes No %Returns during job 100 Cement returns to surface? X Yes _No Spacer returns? X Yes No Vol to Surf: 78.5 ' Cement In Place At: 15:54 Date: 4/19/2017 Estimated TOC: 22 Method Used To Determine TOC: Returns to surface Post Job Calculations: Calculated Cmt Vol @ 0%excess: 110.29 Total Volume cmt Pumped: 202 Cmt returned to surface: 78.5 Calculated cement left in wellbore: 123.5 OH volume Calculated: 88.9 OH volume actual: 102 Actual%Washout: 15 www.wellez.net WellEz Information Management LLC ver_102716bf • . Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. KEU KU 11-07X Date Run 28-Apr-17 County State Alaska Supv. R Pederson/A.Dorr CASING RECORD (Intermediate w TD 6,100.00 Shoe Depth: 6,089.95 PBTD: No.Jts.Delivered No.Jts.Run 147 No.Jts.Returned Ftg.Delivered Ftg.Run 6,070.23 Ftg.Returned Length Measurements W/O Threads Ftg.Cut Jt. Ftg.Balance RKB 18.00 RKB to BHF 21.80 RKB to CHF RKB to THF 18.40 Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 8 5/8 BTC CTE 1.47 6,089.95 6,088.48 2 Casing 7 5/8 29.7 L-80 BTC USS 76.80 6,088.48 6,011.68 Float Collar 8 5/8 BTC Antelope 1.31 6,011.68 6,010.37 144 Casing 7 5/8 29.7 L-80 BTC USS 5,937.77 6,010.37 72.60 Pup Jt 7 5/8 29.7 L-80 BTC USS 9.44 72.60 63.16 1 Casing 7 5/8 29.7 L-80 BTC USS 40.59 63.16 22.57 Hanger&Pup 7 5/8 29.7 L-80 BTC Cactus 2.85 22.57 19.72 Csg Wt.On Hook: 140,000 Type Float Collar: Antelope No.Hrs to Run: 11 Csg Wt.On Slips: Type of Shoe: CTE Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg Yes X No Ft.Min. 9.2 PPG Fluid Description: 6%KCL PHPA Liner hanger Info(Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: 59 total centralizers(2 cents on jt#1,1 cent per joint#3&#4,1 cent every other joint#5 thru#113) CEMENTING REPORT Shoe @ 6089.95 FC @ 6,011.68 Top of Liner #N/A Preflush(Spacer) Type: Mud Push II Density(ppg) 10 Volume pumped(BBLs) 40 Lead Slurry 2S Type: Class G Extended Sacks: 7134 Yield: 2.18 Density(ppg) 12.5 Volume pumped(BBLs) 138 Mixing/Pumping Rate(bpm): 5 Tail Slurry w Type: Class G Sacks: 169 Yield: 1.26 F Density(ppg) 15.8 Volume pumped(BBLs) 38 Mixing/Pumping Rate(bpm): 3 1— Post Flush(Spacer) rc Type: H2O Density(ppg) 8.34 Rate(bpm): 6 Volume: 20 LL Displacement: Type: 6%KCL PHPA Density(ppg) 9.2 Rate(bpm): 6 Volume(actual/calculated): 258/256 FCP(psi): 1200 Pump used for disp: HES Bump Plug? X Yes No Bump press 1700 Casing Rotated? Yes X No Reciprocated? _Yes X No %Returns during job 98 Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Surf: 0 Cement In Place At: 6:30 Date: 4/29/2017 Estimated TOC: 2,500 Method Used To Determine TOC: NC Post Job Calculations: Calculated Cmt Vol @ 0%excess: 116 Total Volume cmt Pumped: 176 Cmt returned to surface: 0 Calculated cement left in wellbore: 176 OH volume Calculated: OH volume actual: Actual%Washout: 25 www.wellez.net WellEz Information Management LLC ver_102716bf • Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. KEU KU 11-07X Date Run 8-May-17 County State Alaska Supv. R Pederson/R Wall CASING RECORD Production Vi TD 9,799.00 Shoe Depth: 9,779.24 PBTD: 9,572.00 No.Jts.Delivered 245 No.Jts.Run 237 No.Jts.Returned 8 Ftg.Delivered 10,228.75 Ftg.Run 9,757.47 Ftg.Returned 471.28 Length Measurements W/O Threads Ftg.Cut Jt. Ftg.Balance RKB 18.00 RKB to BHF 21.80 RKB to CHF RKB to THF 18.40 Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 5 12.6 L-80 DWC/C Antelope 1.40 9,779.24 9,777.84 2 Casing 41/2 12.6 L-80 DWC/C Atlas Bradford 82.46 9,777.84 9,695.38 Foat Collar 5 12.6 L-80 DWC/C Antelope 1.30 9,695.38 9,694.08 6 Casing 41/2 12.6 L-80 DWC/C Atlas Bradford 247.45 9,694.08 9,446.63 1 RA it."A" 41/2 12.6 L-80 DWC/C Atlas Bradford 41.69 9,446.63 9,404.94 11 Casing 41/2 12.6 L-80 DWC/C Atlas Bradford 449.14 9,404.94 8,955.80 1 RA Jt."B" 41/2 12.6 L-80 DWC/C Atlas Bradford 41.73 8,955.80 8,914.07 23 Casing 41/2 12.6 L-80 DWC/C Atlas Bradford 949.22 8,914.07 7,964.85 1 RA it."C" 41/2 12.6 L-80 DWC/C Atlas Bradford 40.65 7,964.85 7,924.20 12 Casing 41/2 12.6 L-80 DWC/C Atlas Bradford 491.60 7,924.20 7,432.60 1 RA Jt."D" 41/2 12.6 L-80 DWC/C Atlas Bradford 41.68 7,432.60 7,390.92 44 Casing 41/2 12.6 L-80 DWC/C Atlas Bradford 1,801.26 7,390.92 5,589.66 Swell packer&2 pups 6 5/8 12.6 L-80 DWC/C Baker 32.86 5,589.66 5,556.80 134 Casing 41/2 12.6 L-80 DWC/C Atlas Bradford 5,535.03 5,556.80 21.77 Hanger and pup 10 3/4 45.0 L-80 DWC/C Seaboard 3.12 21.77 18.50 Csg Wt.On Hook: 113,000 Type Float Collar: Antelope No.Firs to Run: 38 Csg Wt.On Slips: 85,000 Type of Shoe: Antelope Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _Yes X No Ft.Min. 11.2 PPG Fluid Description: 6%KCL/PHPA Liner hanger Info(Make/Model): Liner top Packer?: _Yes No Liner hanger test pressure: Floats Held X Yes No Centralizer Placement: CEMENTING REPORT Shoe @ 9779.39 FC @ 9,695.53 Top of Liner Preflush(Spacer) Type: Mud push Density(ppg) 12 Volume pumped(BBLs) 20.5 Lead Slurry Type: Class G Sacks: 650 Yield: 1.25 Density(ppg) 15.3 Volume pumped(BBLs) 143 Mixing/Pumping Rate(bpm): 5 Tail Slurry ui Type: Sacks: Yield: 1 c4 Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): ti Post Flush(Spacer) 1 rt Type: Density(ppg) Rate(bpm): Volume: LL Displacement: Type: 6%KCL Density(ppg) 8.7 Rate(bpm): 6 Volume(actual/calculated): 147.5/147.5 FCP(psi): 3500 Pump used for disp: HAL cement truck Bump Plug? X Yes No Bump press 3500 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job 100 Cement returns to surface? Yes X No Spacer returns?_Yes X No Vol to Surf: 0 Cement In Place At: 22:40 Date: 5/9/2017 Estimated TOC: 4) 0 (4j�cc.` (-64') Method Used To Determine TOC: lift pressure CAL S42F,w% 7-00_ U 5-:2Q".' MA -- 60t,6 v 6':,.;w -.,c-"-_ LL, L u:J Post Job Calculations: ,--3-,T. Calculated Cmt Vol @ 0%excess: 105.13 Total Volume cmt Pumped: 143 Cmt returned to surface: 0 Calculated cement left in wellbore: 143 OH volume Calculated: 136 OH volume actual: 120 Actual%Washout: 30 www.wellez.net WellEz Information Management LLC ver_102716bf • KU 11-07X FINAL Days vs Depth 0 -KU 11-07X Plan 500 1000 -KU 11-07X Actual 1500 2000 2500 3000 3500 4000 4500 s aai 5000 v 5500 H v ij 6000 6500 - 7000 7500 8000 8500 9000 9500 10000 10500 0 5 10 15 20 25 30 Days 9/12/2017 • • 21 7041 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 ��® Anchorage, AK 99503 Tele: 907 777-8308 N lr�irp AlaAkm,1,11.G Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATA LOGGED AUG 09 2017 4s'ts/201, n K BENDER DATE 08/09/17 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X Prints: Perforation Record: 06/23/2017 Perforation Record: 06/12/2017 CD1: PERF_12JUN 17 7/13/2017 2:10 PM File folder PERF_23JUN 17 7/13/2017 2:10 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received 8y„ _ Date: o,at. • • Quick, Michael J (DOA) From: Quick, Michael J (DOA) Sent: Wednesday,July 05, 2017 8:35 AM To: Ted Kramer c7k—C Subject: RE: KU 11-07X PTD 217-041, Sundry# 317-193 Zl' - � Ted— Was the 4-1/2" CBL log submitted to the AOGCC? Was the MIT-IA completed? I do not see a record for either in the well file. The nitrogen clean out with CT is approved, as it would also be necessary to move up to the next perforation interval. Please note this in the sundry change form as you mentioned. Michael Quick Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage,AK 99501 (907)793-1231(phone) (907) 276-7542(fax) mike.quick@alaska.gov 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 Mike Quick at 907-793-1231 or mike.auick@alaska.gov. From:Ted Kramer [mailto:tkramer@hilcorp.com] Sent: Wednesday,July 05, 2017 8:02 AM To:Quick, Michael J (DOA)<michael.quick@alaska.gov> Subject: FW: KU 11-07X PTD 217-041, Sundry If 317-193 Mike, I received an auto- notice from Guy that he is out and you are filling in for him. Please see below and let me know if we are handling this correctly. We plan to rig up today and test BOPS. Will then start nitrogen injection tomorrow. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 1 • From:Ted Kramer n—(- Sent: Wednesday,July 05, 2017 7:57 AM To:Schwartz, Guy L(DOA) (guy.schwartz(a?alaska.gov)<guy.schwartz@alaska.gov> Subject: KU 11-07X PTD 217-041, Sundry#317-193 Guy, We perfed the D-5 interval from 9,600 9620' (20'). We did see an initial puff of gas the well has now loaded up and died. We did get Slickline on the well over the holiday and Swabbed 60 bbls of fluid off of it. We did make some progress on the fluid level but have now decided to rig up with coil and see if we can jet the well in. If we can and get it to flow methane, then we will out it on. If we cannot,then we will immediately pressure up with Nitrogen and set a plug to come up hole. I wanted to confirm that this is allowed since we already cover the use of nitrogen in our sundry(above). If agreeable, I can note this in the Sundry change form. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 2 *Nolan Hilcorp Alaska, LO i D GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 lii1.[,t: Fax: 907 777-8510 RECEIVED E-mail: snolan@hilcorp.com JUN 29/2017 DATE 06/29/17 AOGCC To: AOGCC Meredith Guhl 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X WELL SAMPLE INTERVAL KU 11-07X 1522—3050 KU 11-07X 3050—4430 KU 11-07X 4430—5720 KU 11-07X 5720—6830 KU 11-07X 6830—8000 KU 11-07X 8000—9230 KU 11-07X 9230-9800 Please include current contact information if different from above. Please acknowledge receipt b •fling and returning one copy of this transmittal or FAX to 907 777.8337 Recei By: "Ak,e_ Date: ( ' a/ - • 410 21 7041 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 RECEIVED Anchorage, 79953 Teele:e: 90 907 7777-83088 tt Irnrp AI:eAk L.LIR: Fax: 907 777-8510 JUN 16 2Q17 E-mail: snolan@hilcorp.com DATA LOGGED Q (�('`(� M.K.BENDER AOGCC DATE 06/13/17 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X Production profile and digital data Prints: Formation Log 2"/5" MD/TVD Drilling Dynamics MD/TVD Formation Log 2" MD/TVD ROP-DGR-GM-ADR-ALD-CTN 2"/5" MD LWD Combo MD/TVD DGR-GM-ADR-ALD-CTN 2"/5"TVD Gas Ratio MD/TVD CD1: 2 8 3 0 0 Daily Reports 5/22/2017 5:25 PM File folder DML Data 5/22/2017 5:25 PM File folder Final Well report 5/22/2017 5:25 PM File folder LAS Data 5/22/2017 5:25 PM File folder Log PDFs 5/22/2017 5:25 PM File folder Log TIFFs 5/22/2017 5:25 PM File folder Show Reports 5/22/2017 5:25 PM File folder CD 2: 2 8 3 0 1 Log Viewers 5/13/2017 9:05 AM File folder . CGM 5/13/2017 9:05 AM File folder , Definitive Survey 5/13/2017 9:05 AM File folder EMF 5/13/2017 9:05 AM File folder LAS 5/13/2017 9:05 AM File folder PDF 5/13/2017 9:05 AM File folder TIFF 5/13/2017 9:05 AM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: 7,),) ),,, �Da�te: INIMMOMMININ11111111111MMEN1111111111.11111111111117r1.1111M11111111111111111111111111111=.1 I,OFTit g�•p\��\Iyy,� A THE STATE Alaska Oil and Gas ��►'i�i�vis ALAsKA Conservation Commission �t`'- _ 333 West Seventh Avenue 11 , GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OFA S 'P Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool/Tyonek Gas Pool 1, KU 11-7X Permit to Drill Number: 217-041 Sundry Number: 317-193 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, Cath P Foerster ‘1(-- Y Chair DATED this2'day of May, 2017. RBDMS MAY 2 4 2017 • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 11 2017 APPLICATION FOR SUNDRY APPROVALS S/�2 1i'117 20 AAC 25.280 1�1�a./ 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑./ • Other Stimulate 0 Pull Tubing ❑ Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Coil Tubing Ops 0- 2. •2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: J Z ar;a6--- Hilcorp Alaska,LLC Exploratory ❑ Development Q • 217-041 - 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic 0 Service 0 6.API Number: Anchorage Alaska 99503 50-133-20662-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510A ' KU 11-7X • Will planned perforations require a spacing exception? Yes ❑ No 2 • 9.Property Designation(Lease Number): 10.Field/Pool(s): FEE A028142 • Kenai Gas Field-Beluga/Upper Tyonek Gas Pool/Tyonek Gas Pool 1 • 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): j 2 '71 9,480 ` 7b� Z 9,439' ; 9,349' —3,185 psi N/A N/A Casing ' Length Size MD TVD Burst Collapse Structural Conductor 120' 16" 120' 120' Surface 1,511' 10-3/4" 1,511' 1,506' 5,210psi 2,480psi Intermediate 6,090' 7-5/8" 6,090' 6,040' 6,890psi 4,790psi Production 9,799' 4-1/2" 9,799' 9,702' 8,430psi 7,500psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 9,799' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A; N/A 12.Attachments: Proposal Summary ❑ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑✓ BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for / 15.Well Status after proposed work: May 15,2017 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑r - WAG ❑ GSTOR ❑ SPLUG 0 Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 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: tkrameri hilcoro.com Y ,?�� Contact Phone: 777-8420 Authorized Signature: Date: /J1/T COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity 0BOP Test U Mechanical Integrity Test El1, Location Clearance ❑ -le F 5 I-zz.I,`q -- Other: y®o( I n,, o t'=� c/ -) Post Initial Injection MIT Req'd? Yes ❑ No ❑ (6.,:j r411-472;t.)�� 7 J Spacing Exception Required? Yes 1:1 No d Subsequent Form Required: /16 _YoL RBDMS MAY 2 4 2517 APPROVED BY Approved by:A ,a,) ,...il,... COMMISSIONER THE COMMISSION Date.a a ..../ � 11-1 7 Submit Form a and Form 10-403 Revised 4/2017 is valid`of'r 12 months from the date of approval. Attachments in Du lic to. QRIpeoleN),At i p11,77 • • Well Prognosis • Well: KU 11-07X Hilcurp Alaska,LLQ Date: 5/10/2017 Well Name: KU 11-07X API Number: 50-133-20662-00 Current Status: New Grassroots Well Leg: N/A Estimated Start Date: May 15, 2017 Rig: Coil Unit Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 217-041 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: 1711232C Maximum Expected BHP: -4,130 psi © 9,445' TVD (Based on normal gradient of 0.43 psi/ft and the lowest perforation) Max. Potential Surface Pressure: - 3,185 psi @ 9,445' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KU 11-07X is a grass roots development well targeting gas sands in the Tyonek formation. This new well reached TD on 5/4/17 The purpose of this work/sundry is to evaluate cement,jet the well dry with CT, and perforate. - Notes Regarding Wellbore Condition • Well is filled with filtered 6% KCI. • Slickline tag and make gauge ring run prior to starting work. • E-line will complete CBL prior to starting sundry work. Copy of CBL to be sent to AOGCC. :;r <<' • An MIT-IA (7-5/8" x 4-1/2") will be performed to 2,500 psig for 30 minutes using the coiled tubing ; pumps prior to beginning of sundry work. Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people - could enter. • Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) • Ensure all crews are aware of stop job authority Coiled Tubing Procedure (start of Sundry work) 1. MIRU Coiled Tubing, PT BOPE to 4,000 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. If slickline or eline tags cement shallower than 10,200. Follow steps 2-6&9-11. 2. MU Mill and Motor BHA. 3. RIH and mill cement and cleanout to 9,680' MD. 4. Circulate hole clean with 2 bottoms up, ensure any rubber or cement is free from the hole. 5. RU N2 pumping unit. I�yj• 6. Drop ball and come online with N2 and jet well dry. ? ' • Estimated volume of displaced 6% KCI is 147 bbls. �JPI 'c ob If slickline or eline tags cement deeper than 9,680', Proceed with steps 7-11. r,14 881- 7. RIH w/1-3/4" coiled tubing and 2-1/4"jet nozzle BHA and tag PBTD. Well Prognosis Well: KU 11-07X Iiilcorp Alaska,LU Date: 5/10/2017 8. PU 5ft and displace well fluids with Nitrogen. • Estimated volume of displaced 6% KCI is 163 bbl. 9. Once well is dry,verify desired surface pressure to leave on well with Operations Engineer. 10. POOH w/coil. LD BHA. 11. RD Coiled Tubing. E-Line Procedure 12. MIRU e-line and pressure control equipment. PT lubricator to 3,500 psi Hi 250 Low. Note that the well is pressurized with nitrogen. • If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 13. Perforate the following Tyonek sands with 2-7/8" 6 SPF 60 deg phased perf guns (up to 12 SPF with 2 perf runs) Zone Sands Top (MD) Btm (MD) FT Tyonek D-2A 8,979' 9,038' 59' • Tyonek D-3B 9,270' 9,320' 50' Tyonek D-3D 9,373' 9,393' 20' Com . Y" Tyonek D-4A 9,427 9,480 53' Tyonek D-4 B/C 9,501' 9,570' 69' Tyonek D-5 9,595 9,620 25' a. Proposed perfs also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. f. All perforations in table above are located in the Deep Tyonek or Tyonek Pool based ,/ on Conservation Order No. 510A. 14. POOH. 15. RD e-line. 16. Turn well over to production. (Test SSV with-in 5 days of stable production on well—notify AOGCC 24hrs before testing) E-line Procedure(Contingency): 1. If any zone produces sand and/or water or needs isolated 2. MIRU E-line, PT lubricator to 3,500 psi Hi 250 Low. 3. RIH and set 4-1/2" CIBP at depth above zone. Or 4. RIH and set 4-1/2" Casing Patch across the zone. • Well Prognosis Well: KU 11-07X IIilcorp Alaska,LL Date: 5/10/2017 Attachments: 1. Actual and Proposed Well Schematics 2. Coil BOPE Schematic 3. CT Flow Diagrams (Forward and Reverse Jetting) 4. Wellhead Diagram 5. Blank RWO Change Form 6. Standard Well Procedure—N2 Operations • • Kenai Gas Field . 11SCHEMATIC Well: KU 11-07X • PTD: 217-041 API: 50-133-2062-00 Hilrarp Alaska.LLC KB=18' CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16" 16„ Conductor—Driven 109 X-56 Weld 15" Surf 120' 1 � � to Set Depth 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.95" Surf 1,511' f ' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 6,090' t TUBING 10-3/4" j 4-1/2" Production 12.6 L-80 DWC/C HT 3.958" Surf 9,799' TOC=3000' 'a r , r JEWELRY DETAIL No. Depth ID OD Item , 1 18' 4.276" 11" Tubing Hanger 2 5,566' 4.276" 6.875" 10 ft Swell Packer(Water Swell) :r. r' �, s .,«. _.'',''' .ti e- . ,.. . .. sJ 6, s-_«9 .,. r" 7.5/8„ *'i RA-D 7,391' RA-C 7,924' a LRA-B 8,914' i .,:r to RA-A 9,405' P. roi 44 4-1/2" PBTD=±9,694' MD/±9,599'TVD TD=9,799' MD/9,702'TVD Updated by DMA 05-11-17 • S Kenai Gas Field . 11 PROPOSED SCHEMATIC p DI. 217KU 11-07X -041 API: 50-133-2062-00 Hilcarp Alaeka,LLC KB=18' CASING DETAIL z� Size Type Wt Grade Conn. ID Top Btm 16" It?' 1 16" Conductor-Driven to Set Depth 109 X-56 Weld 15" Surf 120' VI 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.95" Surf 1,511' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 6,090' TUBING 10-3/4" 1.4 4-1/2" Production 12.6 L-80 DWC/C HT 3.958" Surf 9,799' TOC=3000' r' x 'i ' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.276" 11" Tubing Hanger 2 5,566' 4.276" 6.875" 10 ft Swell Packer(Water Swell) ;1/4, PERFORATION DATA Zone Top P MD Btm TVD To TVD Btm TVD SPF Amt Date Comments y D-2A ±8,979' ±9,038' ±8,895' ±8,953' TBD 59' TBD Proposed +. D-3B ±9,270' ±9,320' ±9,182' ±9,231' TBD 50' TBD Proposed IME' 2 D-3D ±9,373' ±9,393' ±9,283' ±9,303' TBD 20' TBD Proposed D-4A ±9,427 ±9,480' ±9,337' ±9,389' TBD 53' TBD Proposed 7-5/8" d D-4 B/C ±9,501' ±9,570' ±9,409' ±9,477' TBD 69' TBD Proposed D-5 ±9,595 ±9,620' ±9,502' ±9,526' TBD 25' TBD Proposed kms+ 4 RA-D 7,391' RA-C 7,924' , RA-B 8,914' D-2A Iie - D-3B D3D RA-A 9,405' ♦ . i D-4A D-4 B/C u4 "4 - , D-5 4-1/2" .81t" PBTD=±9,694' MD/±9,599'TVD TD=9,799' MD/9,702'TVD Updated by DMA 05-11-17 • II Kenai Gas Field KU 11-07X 05/10/2017 IWAror'p Atoka.114: AilleallIsAll'INN\ k r Q _'� . •Ii�= . IU 1111114_1...,Ia_r 6I!II Coiled Tubing HR580 Injector Head&Gooseneck ��_�ti- II_I.��l .�;a Weight=12,850 lbs 1- ILII. 111t T CI '1, -.T.--,7-- • 4 4-1/16"10K Conventional Stripper hill Mil 5K C062 Lubricator Kill Pnrt WH PSI 2"1502 x 2-1/16 10K Flanged Valve 5K C062 x 4-1/16"10K Flange (Manual) 2-1/16 1 OK x2-1/16 - 4-1/16"10K Combi BOP — 10K HangedValve i u■C. .7■��!; 4 Top Set:Blind/Shear ManualSecond Set:Pipe/Slip 4-1/16"10K Flow Cross Manual 2x2 Valve 1:2"1502 x 2-1/16"10K Flange ill101`1014.'110 01[Oil! 4 Manual 2x2 Valve 2:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 3:2-1/16"10K x 2-1/16"10K Flange Manual 2x2 Valve 4:2"1502 x 2-1/16"10K Flange U 4-1/16"10K x Wellhead Adapter Flange III Olt 4)II' 110 Vb.; 4 Wellhead • • ,s, . 8j ....._, , ., D x ! 3 D V 7 m Q = Y ] 0N 9 ,3 z Q m o 1 ,] ozg 1o , C C U LA A-4 ►•4 v w z - u x9 • I N Z �j ►•4 a0 Li 1 E .5 S O d O H lirL_ 0 III ._ _ ismer 0 III IIIIutuu S °j • .. il .. .._ _. ... vU 3 • A Z c v n 0 1- V n • O a A 8 • Y I Oig : I : s 12 v 11 � v, V N o0 ; Z p o ¢ . w. 'IOU ig i • • g & 81 i 0) c., I = F _0 j'Y .7 I— O N Z CO O yiy ' ) I- C -o Q) 0 Z a I] F O p UXI— CC, N = Z " !F DUn s 0 Cr) A v °_ C V a • D A z -I-, D N A WI i V01 • t •t ►•4 —) ♦ J N z N cn Z o c 44ui III IIII -77 iI. 3A3g I��Iltllllll mu III 1111 �'i_')■�h `� .�N H6 a s c v c • Q 0 6 • o A • I IP II °111111 . O e g_ I • .1o V N O Z it 11 0 a1 12 wI, DI M a F 0 • Kenai Gas Field . 11KU 11-07X Current 05/11/2017 Ililmrp %la•La.11.11. Tubing hanger,Seaboard Kenai Gas Field SMB,ported,11 X 41/2" KU 11-07X DWC susp X 5.250-4 stub 16 X 10%X7 5/8 X 4 1/2 acme left hand lift 4"HBPV, 3.998"min bore,7" extended neck BHTA, , FE X 6.5"OtisOtis4 Quick1/16 Union \IsI\c \/40' DC\�dt Valve,Swab,CIW FLS, .. fav ,F�' a��e, �� of 4 1/16 5M FE,HWO,EE trim `'r c �5 `� �' tati '0" 31�$�� oQe r / , , e 'Fp ANV, f 4, 1 . ..........,„,, . ..,„ !..„, ir,.,fp•--- -- / 1,,0 .:. 7' Y V Valve, Upper Master r`.¢E: CIW-FLS,4 1/16 5M FE, _ HWO,EE trim s vv 1 ,, ; Valve,Master,CIW-FLS, v r, 4 1/16 5M FE,HWO,EE trimr ift ial ia8 .3M a3 ,c5j — .imi ass a II r Multibowl Wellhead,SMB-22 i 115MX163/43M,w/ :— E ' 4-2 1/16 5M SSO 1 lii Starting head,S-22-ET 16%3MX16"SOW,w/ :«ema Sa'® ®' 2-2 1/16 5M EFO H Mk ' w ' �114 �` ®l a I 16" 10%" 7 5/8" 4 1/2" 0 110 cu .> k2 e\ a c 2E% o ° o 0 2k ° § / < a E — • c SJ ) 7/7 ƒ / 2 0- * ».§ \ /_0\ X � >ji > = I ) \/ a as / n § § -0 ■ 2 e # s_ 2 %I 03 cn $ CI c 2 �» ; 77 ICe 9 / / CD 4. a \ C a / / Q \ k & 9 � c / $/ Y a 121 g %/ e k / / / � .0\ 1_ E § ) o O 4 k 2 \ C § / a. / § .5.3). � c / 2 : Cl) > 0 C a) ) $ 0 a) o § � o ct0 0./ \ 0 0. u 0 k o 8 03 E 0 w) ct 44C o * a) n0 & 9 n .2 a) ® d ca X .2 0 2 © W / 2 It 2` -Es k 2 \• g a) > 3 co \ / 3 / \ / < E 0 0 \ • • STANDARD WELL PROCEDURE IliIcor!)11a laz.1,1A NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 • • ' Davies, Stephen F (DOA) From: Ted Kramer <tkramer@hilcorp.com> Sent: Thursday, May 18, 2017 10:27 AM To: Davies, Stephen F (DOA) Subject: RE: KU 11-7X(PTD No. 217-041; Sundry No. 317-193) Stephen, I went back and re-checked the Sundry Application. The 9,572' MD is in error. It should be 9,799 MD/9,702 TVD. I apologize for missing that. Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From: Davies, Stephen F(DOA) [mailto:steve.davies@alaska.gov] Sent:Thursday, May 18, 2017 9:04 AM To:Ted Kramer<tkramer@hilcorp.com> Subject: RE: KU 11-7X (PTD No. 217-041; Sundry No. 317-193) Hi Ted, Please let me know the proper TD for KU 11-7X. I'd like to keep AOGCC's records accurate and get this Sundry Application moving again through the AOGCC's approval process. Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@yalaska.gov. From: Davies, Stephen F (DOA) Sent: Friday, May 12, 2017 9:04 AM To:Ted Kramer<tkramer@hilcorp.com> Subject: KU 11-7X(PTD No. 217-041; SundryNo. 317-193) Ted, • • Hilcorp's recent Sundry Application for KU 11-7X includes perforations from 9595' to 9620' measured depth (MD), but the Total Depth (TD) listed on the application form is 9,572' MD (equivalent to 9480'true vertical depth, or TVD). The accompanying schematic diagram lists 9799' MD (9702'TVD) as the TD of the well. Are 9799' MD(9702'TVD)the correct values? Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.daviesPalaska.gov. 2 21 7041 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 Hi7cnrp Alai.ka_to c, RECEIVED Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATA LOGGED MAY 19 20175'2420,7 vl K.BENDER DATE 05/19/17 AOGCC To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 11-07X Production profile and digital data Prints: HNGS - GR 04/27/2017 ECS - GR 04/27/2017 HNGS — GR 05/06/2017 ECS - GR 05/06/2017 Radial Cement Bond Log CD1: 2 220 , HILCORP KU_11-07X XPT-HUGS-ECS 27AP... 4/27/2017 5:00 PM File folder CD2: 2 8 2 2 1 Hilcorp_KLl_11-07X ECS+INGS XPT 06-MAY-2017 5/11/2017 3:51 PM File folder CD3: 28 22 2 KU_11-07X CBL_16MAY17 jog.tiff 5/18/2017 9:51 AM TIFF File 23,957 KB KU_11-07X_CBL_16MAY17.pdf 5/18/2017 9:51 AM PDF Document 7,880 KB KU_11-07X_CBL_16MAY 17_MainPass.las 5118/2017 9:51 AM LAS File 47,290 KB KU_11-07XCBL_16MAY17 RepeatPass.las 5/18/2017 9:51 AM LAS File 3,174 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received is ?5_.en..eét' Date: OF 7•4 I//7„ sv THE STAT Alaska Oil and Gas a Uf T CKA Conservation Commission 333 West Seventh Avenue +1!4''' *c GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ALASFax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool and Tyonek Gas Pool 1, KU 11-07X Hilcorp Alaska, LLC Permit to Drill Number: 217-041 Surface Location: 203' FSL, 1003' FWL, SEC. 6, T4N, RI 1 W, SM, AK Bottomhole Location: 717' FNL, 945' FWL, SEC. 7, T4N, RI 1 W, SM, AK Dear Mr. Myers: Enclosed is the approved application for permit to drill the above referenced development 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, 2147 P9ve.4,41,------ Cathy P. Foerster Chair DATED this S day of April, 2017. :RECEIVED STATE OF/01A OIL AND GAS CONSERVATION COMMiFION "VAR y 7 2017 PERMIT TO DRILL 20 AAC 25.005 L •. 'C la.Type of Work: lb.Proposed Well Class: Exploratory-Gas 0 Service- WAG 0 Service-Disp ❑ lc.Specify if well is proposed for: Drill ❑, • Lateral ❑ Stratigraphic Test ❑ Development-Oil 0 Service- Winj ❑ Single Zone 0 • Coalbed Gas ❑ Gas Hydrates 0 Redrill 0 Reentry 0 Exploratory-Oil ❑ Development-Gas ❑✓ •Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket ❑✓ - Single Well 0 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 • KU 11-07X • 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 9572' • TVD: 9480'• Kenai Gas Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Beluga/Upper Tyonek Gas Pool , Surface: 203'FSL, 1003'FWL,Sec 6,T4N,R11W,SM,AK • FEE A028142 ' Tyonek Gas Pool 1 Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 419'FNL,819'FWL,Sec 7,T4N,R11W,SM,AK N/A 4/17/2017 • Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 717'FNL,945'FWL,Sec 7,T4N,R11W,SM,AK 2494 7418'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 81.6 • 15.Distance to Nearest Well Open Surface: x-271914• y- 2362258 • Zone-4 GL Elevation above MSL(ft): 63.6 . to Same Pool: 1753'to KDU 9 16.Deviated wells: Kickoff depth: 600 feet 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 9.5 degrees Downhole: 2895 • Surface: 2290 • 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Cond 16" 109# X-56 Weld 120' Surface Surface 120' , 120' Driven 13-1/2" 10-3/4" 45.5# L-80 BTC 1,500' Surface Surface 1,500' , 1,495' L-553 ft3/T-322.8 ft3 9-7/8" 7-5/8" 29.7# L-80 BTC 6,100' Surface Surface 6,100' • 6,050' L-696 ft3/T-158 ft3 6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 9,572' Surface Surface 9,572' . 9,479' 801ft3 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat Q BOP Sketch Q Drilling Program Q Time v.Depth Plot Q Shallow Hazard Analysis Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements ✓ 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Email mmyershilcorp.com Printed Name Monty Myers Title Drilling Engineer Signature — - Phone 777-8431 Date 3/17/2017 Commission Use Only Permit to Drill _J / API Number: _ / Permit Approval See cover letter for other Number: /r 7`L-6`f/ 50-/37)- (�� ;Z--- ' �Date: q tj - ("T 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: ❑✓ Other: * 35D 0,S4.. 6 0 P Thr:-.V1- Samples req'd: Yes❑ No El< Mud log req'd:Yes❑ o 2( ff C 2,5 0.3 S CL,jLZ)H2S measures: Yes❑ Nog, Directional svy req'd:Yes 1$111No❑�( Spacing exception req'd: Yes❑ No Inclination-only svy req'd:Yes❑ No['J t C(3L OAT- _FA tAt ,,,-`u - Post initial injection MIT req'd:Yes 0 No❑ APPROVED BY • Approved b A, % -- COMMISSIONER THE COMMISSION Date:4.-.,j_`7 / 3'i' -t1 A Submit Form and Form 10-4"• (Revised 11/2015) �i e t Ia n" Ionths from the date of approval(20 AAC 2 ,� / Attachments in Duplicate • Hilcorp Alaska, LLC • Monty Myers P.O. Box 244027 Anchorage, AK 99524-4027 Drilling Engineer Tel 907 777 8431 Hilcorp Email mmyers@hilcorp.com Energy Company 3/17/2017 Commissioner RECEIVED Alaska Oil & Gas Conservation Commission MAR 17 2017 333 W. 7th Avenue Anchorage, Alaska 99501 AOGCC Re: KU 11-07X Dear Commissioner, Attached is the application for permit to drill of KU 11-07X. KU 11-07X is a 9,572' MD / 9,480' TVD Beluga/Upper Tyonek development well off the 14-06 pad in the Kenai Gas Field. Reservoir analysis and subsurface mapping has identified an undrained area of the Kenai Field that will target reserves in D2, D3B, and D4 sands. Secondary targets include the Lower Beluga-Upper Tyonek. The base plan is a directional wellbore with a kick off point at 600' MD. Maximum hole angle will be 10 deg. Vertical section will be 1008 ft. Drilling operations are expected to commence approximately April 17th, 2017. . The Saxon Rig # 169 will be used to drill and complete the wellbore. The well will be perforated after the rig has departed. 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 1 of 1 • • il Hilcorp Alaska, LLC KU 11-07X Drilling Program Kenai Field Revision 0 March 17, 2017 • KU 11-07X Drilling Procedure 11th orp Alaska,H I' Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 Internal Reporting Requirements 5 6.0 Planned Wellbore Schematic 6 7.0 Drilling/Completion Summary 7 8.0 Mandatory Regulatory Compliance/Notifications 8 9.0 R/U and Preparatory Work 10 10.0 N/U 16-3/4"Conductor Riser 11 11.0 Drill 13-1/2"Hole Section 12 12.0 Run 10-3/4" Surface Casing 16 13.0 Cement 10-3/4" Surface Casing 19 14.0 BOP N/U and Test 22 15.0 Drill 9-7/8"Hole Section 23 16.0 Run 7-5/8"Intermediate Casing 28 17.0 Cement 7-5/8" Cement Procedure 30 18.0 Drill 6-3/4"Hole Section 33 19.0 Run 4-1/2"Production Long String 39 20.0 Cement 4-1/2"Production Long String 42 21.0 RDMO 44 22.0 BOP Schematic 45 23.0 Wellhead Schematic 46 24.0 Days Vs Depth 47 25.0 Geoprog 48 26.0 Anticipated Drilling Hazards 49 27.0 Saxon Rig 169 Layout 52 28.0 FIT Procedure 53 29.0 Choke Manifold Schematic 54 30.0 Casing Design Information 55 31.0 9-7/8"Hole Section MASP 56 32.0 6-3/4"Hole Section MASP 57 33.0 Spider Plot(NAD 27) 58 34.0 Surface Plat(As Built)(NAD 27) 59 35.0 Offset MW vs TVD Chart 60 36.0 Directional Plan (wp09) 61 • KU 11-07X Drilling Procedure 1lilrnr 1 Aln..ka. 1.0 Well Summary Well Kenai Unit 11-07X Pad&Old Well Designation KU 11-07X is a grass roots well on the existing 41-07 pad Planned Completion Type 4-1/2"production longstring Target Reservoir(s) Tyonek/Beluga Planned Well TD,MD/TVD 9,572' MD/9,480' TVD . PBTD, MD/TVD 9,439' MD/9,349' TVD Surface Location(Governmental) 203' FSL, 1003' FWL, Sec 6, T4N,R11W, SM,AK • Surface Location(NAD 27) X=271914.47,Y=2362258.42 • Surface Location(NAD 83) Top of Productive Horizon 419'FNL, 819'FWL, Sec 7, T4N,R11W, SM,AK (Governmental) TPH Location(NAD 27) X=271802.82,Y=2361541.19 TPH Location(NAD 83) BHL(Governmental) 717'FNL,945'FWL, Sec 7, T4N, R11W, SM,AK BHL(NAD 27) X=271923.07,Y=2361240.23 BHL(NAD 83) Maximum Anticipated Pressure in 2895 psig . psig(Downhole) Maximum Anticipated Pressure in 2290 psig psig(Surface) AFE Number 1711232D AFE Drilling Days 27 AFE Completion Days AFE Drilling Amount $4.2MM AFE Completion Amount Work String 4-1/2" 16.6# S-135 CDS-40 (Rental Saxon String) KB Elevation above MSL 81.6 ft • GL Elevation above MSL 63.6 ft BOP Equipment 11" 5M Townsend Annular BOP 11" 5M Townsend Double Ram 11" 5M Townsend Single Ram Page 2 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure IliIvorp Alaska.1.11: 2.0 Management of Change Information _. : Hilcorp Alaska, LLC Hilcorp Ifnrryv emnp., Changes to Approved Permit to Drill Date: March 18,2017 Subject: Changes to Approved Permit to Drill for KU 11-07X File#: KU 11-07X Drilling Program Any modifications to KU 11-07X Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Monty M Myers 3.18.2017 Drilling Engineer Date Page 3 Revision 0 March, 2017 • o KU 11-07X Drilling Procedure 1111.1.1 t_LLC 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Burst Collapse Tension Section (in) OD (in) (#/ft) (psi) (psi) (k-lbs) Cond 16" 15" - - 109 X-56 Weld 13-1/2" 10-3/4" 9.95" 9.875" 11.75" 45.5 L-80 BTC 5210 2480 1040 9-7/8" 7-5/8" 6.875" 6.75" 8.5" 29.7 L-80 BTC 6890 ' 4790 683 6-3/4" 4-1/2" 3.958" 3.833" 5.0" 12.6 L-80 DWC/C HT 8430 '' 7500 288 4.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn urs ".``�8.4'` Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) All 4.5" 3.826 2.6875" 5.25" 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 March,2017 / • • KU 11-07X Drilling Procedure Ililenrp.AIa.Ln,I,Lf. 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com; mmyersahilcorp.com, &cdinger(a,hilcorp.com 5.2 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.3 EHS Incident Reporting • Notify EHS field coordinator. 1. Matt Hogge: 0: 777-8418 C: 907-227-9829 2. Spills: Keegan Fleming: 0:907-777-8477 C:907-350-9439 • Notify Drlg Manager&Drlg Engineer: 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 2. Monty M Myers: 0: 907-777-8341 C: 907-538-1168 • Submit Hilcorp Incident report to contacts above within 24 hrs 5.4 Casing Tally • Send final"As-Run"Casing tally to mmyers@hilcorp.com&cdinger@hilcorp.com 5.5 Casing and Cmt report • Send casing and cement report for each string of casing to mmyers@hilcorp.com & cdinger@hilcorp.com Page 5 Revision 0 March,2017 • 0 11 KU 11-07X Drilling Procedure I hirorp,11a ka,IAA' 6.0 Planned Wellbore Schematic Kenai Gas Field Proposed Well:KU 11-07X PTD: XXX-XXX API: 50-133-XXXXX-XX CASING DETAIL Size Type Wt Grade Conn. ID Top Btm / y 16" 1 ,... Conductor— I 16" Driven to Set 109 X-56 Weld 15" Surf 120' :, Depth < _4 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.95" Surf 1500' ' Z, :'P'`' '" 10-314" '- `y S 0) -5/8' Intermediate 29.7 L-80 BTC6.875" Surf 6,100' 35�" P-5- -F' '' 11.'f 'c TUBING TO =3000' r 4-1/2" Production 12.6 L-80 DWC/C HT 3.958" Surf 9,572' 4it Hole Section Casing MW Workstring 13-1/2" 10-3/4" 8.8—9.3 ppg 4-1/2" \\ 9-7/8" 7-5/8" 9—9.5 ppg 4-1/2" . .may 6-3/4" 4-1/2" 10—11.7 ppg 4-1/2" .pG 5 JEWELRY DETAIL ,,� No. Depth ID OD Item a 1 18' 4.276" 11" Tubing Hanger }M 2 5,600 4.276" 6.875" 10 ft Swell Packer(Water Swell) a'' Lt Is* #0 nli 2 j, i'� 7-5t8" ' y i ( (FT)) FLUID MD TVD(FT) CT 1 iV- if eningA-10gas 3656 3.637 • fSterling A-11 gas 4. 3703 3.684 Sterling 8-1 gas 3791 3.772 Sterling Pool 6 gas 4469 4,442 Upper Beluga gas 4727 4.697 j Lower Beluga gas 6115 6,066 Tyonek 1B gas 7469 7.403 Tyonek D2 gas 8964 8.880 Tyonek D38 gas 92-2 9.184 Z: ti' TyonekD4A gas 9439 9.349 ♦ ,i • 4-114 . PBTD=9,439'MD i 9.349'TVD TD=9,572'MD 19,480'TVD Page 6 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Hilenrp AlaKka,LLC 7.0 Drilling / Completion Summary KU 11-07X is a 9,572' MD/9,480' TVD Beluga/Upper Tyonek development well off the 14-06 pad in the Kenai Gas Field. Reservoir analysis and subsurface mapping has identified an undrained area of the Kenai ' Field that will target reserves in D2,D3B, and D4 sands. Secondary targets include the Lower Beluga-Upper • Tyonek. The base plan is a directional wellbore with a kick off point at 600' MD. Maximum hole angle will be 10 deg. Vertical section will be 1008 ft. Drilling operations are expected to commence approximately April 17th' 2017. The Saxon Rig# 169 will be used to drill and complete the wellbore. The well will be perforated after the rig has departed. There are two water wells permitted for use on Pad 14-06.One is for water supply to the electrical shop,which was drilled in 2003, and is on the southeast corner of the pad by the access road. This well was drilled to 141 feet and is cased to 139 feet. This well is currently operational. The other water well is referred to as well 309 ,.. and is located near KU 21-7. This well was drilled to a depth of 325' and has been capped and the pump was pulled. Surface casing will be run to 1500' MD and cemented to surface to ensure protection of these resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed,a Temp log will be run between 6— 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed • with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal/beneficial reuse depending on test results. This facility is on the same pad as the drill well. General sequence of operations: 1. MOB Saxon Rig# 169 to well site. 2. N/U 16" diverter riser (No diverter, diverter waiver requested) 3. Drill 13-1/2"hole to 1500' MD. Run and cmt 10-3/4" surface casing. f 4. N/D conductor riser,N/U &test 11"x 5M Townsend BOP. 12.E,t 5. Drill (and LWD log) 9-7/8"hole section to 6,100' MD. Run and cmt 7-5/8"intermediate casing. 6. Drill (and LWD log) 6-3/4"prod hole section to well TD. Run and cmt 4-1/2"prod. casing. 7. N/D BOP,N/U tree, RDMO. Reservoir Data Acquisition Program: 13-1/2" Surface hole: GR/Res only • 9-7/8"Intermediate Hole: Mud logging + GR/Res/Den/Neu LWD • 6-3/4"Production Hole: Mud logging+ GR/Res/Den/Neu LWD Page 7 Revision 0 March,2017 • KU 11-07X Drilling Procedure }{ilenrl,.Aln.kn, 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of KU 11-07X. 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 5/10 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 AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • Diverter waiver request requested due to the recent drilling of KBU 32-06 and KBU 43-07Y on a nearby pad. No issues were experienced on either well drilling the surface hole. Surface casing will ' be set at the same depth on KU 11-07X. Page 8 Revision 0 March, 2017 i i KU 11-07X Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 13-1/2" • No diverter Installed N/A • 11"x 5M Townsend Annular BOP • 11"x 5M Townsend Double Ram Initial Test:250/3500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 9-7/8"&6-3/4" • 11"x 5M Townsend 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. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.reggc alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartzaalaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: victoria.loepp(a,alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors(aialaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Revision 0 March,2017 s • KU 11-07X Drilling Procedure Hilror1,Alaska,lfd.0 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at a minimum of 120' below ground level. This is required to isolate a problematic gravel bed that occurs from 90— 105'. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4" 3M"A" section& 20" adapter bushing. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Saxon Rig# 169, spot service company shacks, spot&R/U company man&toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 13-1/2"hole section. 9.9 Set test plug in wellhead prior to N/U conductor riser to ensure nothing is accidentally dropped into the wellbore. 9.10 R/U mud loggers for surface hole section. • 9.11 Install 5-1/2" liners in mud pumps. • HHF 1000 mud pumps are rated at 3063 psi (85%)/339 gpm(100%) with 5-1/2"liners. Page 10 Revision 0 March, 2017 0 • KU 11-07X Drilling Procedure 14 Hilcnrp.Alnwka.1.LC 10.0 N/U 16-3/4" Conductor Riser 10.1 N/U 16-3/4" Conductor Riser • Ensure line does not direct flow from trip tank straight down the flowline. Fill u.p line and flowline should be oriented 90 degrees to each other at approx. the same height. • Ensure flowline outlet installed so that enough slope exists to carry cuttings to the shakers. • Consider adding additional drainage points at the bottom of the conductor riser if deemed necessary. • R/U fill up line to conductor riser. 10.2 Set 15.375" ID wear bushing in wellhead. 10.3 Rig Orientation on 14-06 Pad: $KK 9• '1 S lir i .011, !'� irY)A KBU 1 1 07X SLS . • ' - . ‘,":::,....::: 4. :1,7:: ..L. ..:3 !,, .i.,; 40.- '-', 4: .1; ii 1 STA11 "/ ,34, /x' , .+ r •. 1R Page 11 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure II actor!)Alaska.LLC 11.0 Drill 13-1/2" Hole Section 11.1 P/U below 13-1/2" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Bit TFA should be-0.7 in2. We need to pump at 500 to 510 gpm to clean the hole effectively. • Workstring will be 4.5" 16.6# S-135 CDS40. COMPONENT DATA Item Description Serial Number OD ID Gauge Weight Top Length Cumulative e (In) (In) (In) (Ibpf) Connection (ft) length (ft) Ell 13.1/2"Triton 8.000 3.500 13.500 138.52 P 6.58"REG 1.10 1.10 © 8"SperryDntl lobe 415-5.3 stg 8.000 5.000 121.08 B 6-518-REG 32.00 33.10 - Stabilizer -_ 13.250 _ -- I © 8"DM Collar(Directional) 8.040 3.500 147.40 B 6-5/8"REG 9.20 42.30 1 0 8"DGR Collar • 8.000 1.920 142.70 B 6-5/8"REG IIIIICEM 46.85 © 8"EWR-P4 Collar • 8.000 2.000 151.00 B 6.518"REG 12.19 59.04 0 8"HCIM Collar 8.000 1.920 149.90 B 6.518"REG 4.97 64.01 Q 8"TM Collar(Telemetry) 8.110 4.000 145.20 B 6.518"REG 9.90 73.91 0 8"NM Flex Collar 7.720 2.875 137.40 B 6-518"REG 30.00 103.91 9 8"NM Flex Collar 7.590 2.875 132.07 B 6.5'8"REG 30.00 133.91 10 Bottleneck X-Over Sub 7.563 2.813 131.92 B 4-1/2-IF 3.00 136.91 Inn 6.75"NM Flex Collar 6.450 2.875 89.23 B 4.1/2"IF 30.00 166.91 ® 6.75"NM Flex Collar 6.720 3.000 96.78 B 4-112"IF 30.00 196.91 ® X-Over 4.5"IF P x 4.5'CDS 40 B 6.450 2.625 92.91 B 4 40 CDS 3.00 199.91 KO 2 its 4-112'HWDP 4.500 2.813 36.86 62.00 261.91 ® X-Over 4.5"CDS 40 P x 4.5"IF B 6.300 2.625 87.79 B 4-1/2"IF 3.00 264.91 111131 6-114" Weatherford Jars 6.270 2.250 91.68 B 4-1/2"IF 30.00 294.91 EN X-Over 4.5"IF P x CDS 40 B 6.230 2.625 _ 85.44 B 4.5"CDS40 3.00 297.91 ICI 15 jts 4.1/2"HWDP 4.500 2.813 36.86 460.00 757.91 Total: 757.91 11.2 Hydraulics Summary: Depth- Hole Size Pump Rate Standpipe Est Openhole MW ECD TFA MD (ft) (in) (gpm) Pressure (psi) AV(fpm) (ppg) (ppg) (in2) BHA MM + MWD+25 0- 1500 13-1/2" 500 1848 76 9.0 . 9.2 0.70 HWDP 11.3 Primary bit will be the Security 13-1/2" QHC1GRC Milled Tooth Bit. These are available from Halliburton. Page 12 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Ilileorlr Alnwka,I LC 13-1/2" (343mm) C1HC 1 G RC PRODUCT SPECIFICATIONS IADC Code 117v4' ,y Total Tooth Count 64 .,°" Gage Rnw�'Ninth Count 36 Journal Angle 33,E Offset(1116") 6 Jet Nozzle Types Standard a3244 Extended 311306 Center Jet (If Center Jetted)501 B13 T.J.Connection 6-yr(API Reg.) Recommended wlake-Up Torgue* 2SO0012000 Ft inn, Bit Weight(Boxed) 260 Lbs.(I1S Kg.) Bk Breaker (Ma1.riebegacprt) 1143?Th64491i PRODUCT FEATURES • New patented Diarnnndrm Claw tooth bit design_ ,. • Proprietary 13iamonit TECH2000IM full tooth bard acing on cutting " structure and gage. +� • Tungsten carbide'surf'inserts in gage teeth for added gage protection. • Premium bearing and seal configuration suitable for both rotary and re motor applications, • Innovative mechanical pressure compensating system providesmpg reliable presses equalization and relief for mtximunt bearing and xeal life • Raised tungsten carbide inserts and proprietary hardfasing provides maximum arm protection in,abrnsive and directional applications while minimizing drill string torque. • QuadPack' Plus Series incorporates its successful longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. • Center jet feature to present bit bulling problems Material#€540030 •Calrulutiuncs bused tin atcummennatiuns hum API Ind l.uul-4iinil rnnnufuciursrr. 0 2014 Halliburton.All rights reserved.Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the ens-turner that is applicable to the sale. www.halliburtomeom 11.4 4-1/2" Workstring & HWDP will come from Saxon. Jars will come from Weatherford. 11.5 No LWD tools will be run on the 13-1/2" hole section. • Page 13 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Hileorp Alaska,LLC 11.6 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. 11.7 Drill 13-1/2"hole section to 1500' MD/ 1495' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 510 gpm. This gives us an annular velocity of 77 fpm, which is borderline for effective hole cleaning. Ensure shaker screens are set up to handle this flowrate. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections.. • Adjust MW as necessary to maintain hole stability. Keep API fluid loss < 10. • TD the hole section in a good shale btwn 1450' & 1550' MD. • • Take MWD surveys every stand drilled(60' intervals) - Page 14 Revision 0 March,2017 • KU 11-07X Drilling Procedure Hilcorp Alaska, 11.8 13-1/2"hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1)ppg above highest anticipated MW. We will start • with a simple gel + FW spud mud at 8.8 ppg. 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: 8.8—9.3 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL LGS 120-1500' 8.8—9.3' 85-250 20-40 25-45 <10 <15% System Formulation: AQUAGEL/freshwater Spud Mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 -20 ppb caustic soda 0.1 ppb(8.5—9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8—9.3 ppg PAC-L/DEXTRID LT if required for<10 FL ALDACIDE G 0.1 ppb 11.9 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.10 TOH with the drilling assy, handle BHA as appropriate. Page 15 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Flilrnrp Aln kn.TIC 12.0 Run 10-3/4" Surface Casing 12.1 R/U and pull 15.375"wear bushing. 12.2 R/U Weatherford 10-3/4" casing running equipment. • Ensure 10-3/4" BTC x CDS 40 XO on rig floor and M/U to FOSV. • R/U fill-up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U&thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). • (1)Joint with coupling thread locked. • (1) Joint with float collar bucked on pin end &thread locked. • Install (2) centralizers on shoe joint over a stop collar. 10' from each end. • Install (1) centralizer, mid tube on thread locked joint and on FC joint. • Ensure proper operation of float equipment. 12.5 Continue running 10-3/4" surface casing • Fill casing while running using fill up line on rig floor. • Use"API Modified"thread compound. Dope pin end only w/paint brush. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 10,750 ft-lbs. • After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. • Install (1) centralizer every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 10-3/4" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 10-3/4" 10,750 ft-lbs Page 16 Revision 0 March,2017 i KU 11-07X Drilling Procedure Hilror1,Alaska,LLC Tenaris Casing and Tubing Performance Data Choose pipe size.‘vall thickness and steel grade to view API connection options and performance data. Size Wall ' Grade Connection Q Unit _0 Pipe Body Data GEOMETRY • Nominal OD 10.750 in Wall Thickness 0.400 in API Drift Diameter 9.794 in Nominal Weight 45.50 tbsift Nominal ID 9.950 in Alternate Drift Diameter 9.875 in Plain End Weight 44.26lbstft Nominal Cross Section 13.006 sq in PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Body Yield Strength 1,040,000 lbs Internal Yield Pressure 5,210 psi Collapse Pressure 2,470 psi Connection Data GEOMETRY Regular OD 11.750 in Threads Per Inch 5 Make-Up Thread Tums 1 PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Joint Strength 1,063,000 lbs Internal Pressure 5,210 psi Resistance TenarisHydril Premium Connections Print Contact Us Ver 8.6 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 17 Revision 0 March, 2017 11111 14KU 11-07X Drilling Procedure Hilcorp Alaska,Id.0 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 18 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Hilrnrp Alaska.Td.0 13.0 Cement 10-3/4" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud&water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface,regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 13.2 R/U cmt head(if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.3 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.4 Pump remaining 35 bbls 10 ppg spacer. 13.5 Drop bottom plug. Mix and pump cmt per below recipe. 13.6 Cement volume based on annular volume+ 50% open hole excess. Job will consist of lead& tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: Cs 120' x .106 bpf 12.7 71 16" Conductor x 10-3/4" .4`` 4,, �' casing annulus: LEAD: (1000' — 120') x .065 bpf x 1.5 = 85.8 482 13-1/2" OH x 10-3/4" Casing annulus: Total LEAD: 98.5 553 ..12 5 TAIL: (1500'-1000') x .065 bpf x 1.5 = 48.8 274 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 1-1'` 90 x .096 bpf = 8.7 48.8 10-3/4" Shoe track: Total TAIL: 57.5 322.8 t Page 19 Revision 0 March,2017 • KU 11-07X Drilling Procedure Hilenrp Alnwka.1,11 Cement Slurry Design: Lead Slurry (1000' MD to surface) Tail Slurry (1500' to 1000' MD) System Blend Conventional Density 12 lb/gal 15.2 lb/gal Yield 2.44ft3/sk ✓ 1.26 ft3/sk ✓ Mixed Water 14.437 gal/sk 5.76 gal/sk Mixed Fluid 14.417 gal/sk 5.76 gal/sk Expected Thickening 5 HR 3 HR Code Description Concentration Code Description Concentration D901 Cement 94 lb/sk D901 Cement 94 lb/sk D046 Antifoam 0.2%BWOC D046 Antifoam 0.2%BWOC D020 Extender 2.6% BWOC D065 Dispersant 0.4% BWOC Additives D079 Extender 2% BWOC D167 Fluid Loss 0.2% BWOC D110 Retarder 0.02 gal/sk cmt 5002 Accelerator 0.25% BWOC 13.7 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.8 After pumping cement, drop top plug and displace cement with mud. 13.9 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. Be lined up to displace with rig pumps as well, in the event there is an issue during the displacement with the rig pumps. 13.10 Displacement calculation: 1411' x .0962 bpf= 135.7 bbls civ 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not over displace by more than '/2 shoe track volume. Total volume in shoe track is 8.7 bbls. Page 20 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Hilrorp Alaska,LLC 13.13 Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 6— 18 hours after CIP. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.15 R/D cement equipment. Flush out wellhead with FW. 13.16 Back out and L/D landing joint. Flush out wellhead with FW. 13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.18 Lay down landing joint and pack-off running tool. Ensure to report the following on wellez: • Pre flush type,volume(bbls) &weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to mmyers@hilcorp.com & cdinger(d,hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Revision 0 March, 2017 • KU 11-07X Drilling Procedure HiIrnrp Alipika.Li t 14.0 BOP N/U and Test 14.1 N/D the conductor riser. 14.2 N/U Seaboard multibowl wellhead assy. Install packoff 10-3/4"P-seals. Test to 3000 psi. 14.3 N/U 11"x 5M Townsend BOP as follows: • BOP configuration from Top down: 11"x 5M Townsend annular BOP/11"x 5M Townsend double ram/11"x 5M mud cross/11"x 5M Townsend single ram • Double ram should be dressed with 2-7/8 x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8 x 5" VBRs • N/U bell nipple, install flowline. • Install (1)manual valves & (1) HCR on kill side of mud cross. Manual valve used as inside or"master valve". • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 4-1/2" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3500 psi for 5/10 min. Test annular to 250/2500 psi for 5/10 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9 ppg 6%KC1 drilling fluid for 9-7/8"hole section. 14.8 Set 10"ID wear bushing in wellhead. 14.9 Ensure mud loggers are R/U for the intermediate hole section. • 14.10 Rack back as much 4-1/2"DP in derrick as possible to be used while drilling the hole section. 14.11 Install 5" liners in mud pumps. • HHF 1000 mud pumps are rated at 3673 psi (85%) /280 gpm (100%) with 5" liners. Page 22 Revision 0 March, 2017 • II KU 11-07X Drilling Procedure H Irorp,11ad.n.LLC 15.0 Drill 9-7/8" Hole Section 15.1 Prior to P/U 9-7/8" directional BHA-test casing against blind rams to 2600 psi/30 min. 15.2 P/U below 9-7/8" directional drilling assembly. COMPONENT DATA II Item OD ID Gauge Weight Top Length Cumulative Description Serial Number Connection (In) (in) (in) (Ibpf) (ft) Length (ft) 1 PDC 8.000 3.000 9.875 147.22 P 6.518"REG 0.80 0.80 2 7'SperryDrill Lobe 7/8-6.0 stg 7.000 4.952 93.13 B 4.112'IF 27.38 28.18 Stabilizer 9.625 - 3 6 34'Integral Blade Stabilizer 6.750 2.000 9.625 111.25 B 4-1/2'IF 3.00 31.18 4 6 3'4"DM Collar(Directional) 6.720 3.125 103.40 B 4-112'IF 9.20 40.38 5 6 3 4'DGR Collar(Gamma) • 6.710 1.920 97.80 B 4-1/2'IF 6.50 46.88 6 6 3`4'EWR-P4 Collar(Resistivity)• 6.710 2.000 104.30 B 4.1/2'IF 12.00 58.88 7 6 34'Smart Stab 6.750 2.000 9.625 111.25 B 4.1/2'IF 3.00 61.88 8 6 3 4'PWD Collar(Pressure) 6.720 1.905 96.30 B 4-1 2'IF 4.44 66.32 9 6 34"HCIM Collar(Processor) 6.750 1.920 101.70 B 4-1,2'IF 6.50 72.82 10 6 34'ALD Collar 6.750 1.920 9.375 104.30 PNC 50 14.54 87.36 Stabilizer 9.375 - 11 6 34'CTN Collar 6.750 1.905 102.30 8 NC 50 11.84 99.20 12 6 314'TM Collar(Telemetry) 6.550 3.250 103.60 B 4-1i 2"IF 9.90 109.10 13 6 3`4'Integral Blade Stabilizer 6.750 2.000 9.625 111.25 3.00 112.10 14 6.75'NM Flex Collar 6.750 2.875 99.83 B 4-12"IF 30.00 142.10 15 6.75'NM Flex Collar 6.750 2.875 99.83 30.00 172.10 16 X-Over Sub 4-1,2 IF x CDS 40 6.450 2.625 92.91 B 4.4�DS 3.00 175.10 17 2 115 4-1,2'HWDP 4.500 2.813 36.86 63.00 238.10 18 X-Over Sub CDS 40 x 4.1'2 IF 6.300 2.625 87.79 B 4.1/2'IF 3.00 241.10 19 6.1 4'Weatherford Jar 6.270 2.250 91.68 B 4.1x2'IF 30.00 271.10 20 X-Over Sub 4-1/2 IF x CDS 40 6.230 2.625 85.44 B 4.5'CDS40 3.00 274.10 21 15 Its 4-1/2'HWDP 4.500 2.813 36.86 472.50 746.60 it ,,,,,, 746.6 15.3 Ensure BHA components have been inspected previously. 15.4 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.5 Bit TFA should be-0.75 -0.80 in2. We need to pump at-450 - 500 gpm to clean the hole effectively. Have the directional driller run hydraulics calculations to confirm optimum TFA. V 15.6 Primary bit will be the Security 9-7/8" MM65. Page 23 Revision 0 March, 2017 • 11 KU 11-07X Drilling Procedure Hilcnrp Alankn,LI.(. 9-7/8" (251mm) MM65 PRODUCT SPECIFICATIONS Cutter Type ScleetCutter • 'ADC Code M323 Body Type MATRIX Tidal('utter(oum e Cutter Distribution 13mrn Ir i Face (I 28 Gauge 12 0 16. Up Drill 6 0 l Number of Large Nozzles 6 J Number of Medium Nozzles 0 Number of Small Nozzles (I Number of Micro Nozzles 0 *. Number of Poets(Sive) 0 w Number of Replaceable Ports(Size) 0 Junk Slot Area(sq in) 16.71 Norrnalried Face Volume 45.40 API Connection 1-1;2 REG.PIN Recommended Make-Up Torque* 12,461—1'7,766 Ft*lbs. 'r Nominal Dimensions** , Make-Up Face to Nose 10.81 in-275 nen (iatigc length 2.3 in•64 men .... .... Sleeve Length 0 in-0 nun Shank Diameter 6 in-152 nun Itreak Out Plate(Mat.thtegacy01 IH9541444140 Approximate Shipping Weight 250ILbs.-113Kg. SPECIAL FEATURES Up-Drill Cutlers on Gage Pads,1116"Relieved Gage Material#771827 *Bit specific ine nunended makeup torque is a function of the bit ID.and actual bit sub 0.0.oilfired as specified in API RInG Section A.8.2. **Design dimensions are uarniaed and nuy nary slightly on nunutuctured product Hallihorton Drill Bits and Seryias models are onnnnuuusly reviewed and refined. Product specifications may change u ithuut notice. 0 2013 Halliburton.All rights reserved_Saks 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. www,halliburton_com Page 24 Revision 0 March, 2017 0 II KU 11-07X Drilling Procedure 11i[enrp;kIa.La,LLC 15.7 9-7/8"hole section hydraulic summary: Security DBS BIT HYDRAULIC PROGRAM 0 Prepared For Hilcorp KEW 32412 By-Mark BroulNat Dete prepared:-119114 Operator:-,Hlleorp Well Nanre,No-150032-08 Bit Type:- PDC Contractor:- County;-ttenat Bit Diameter:- 9.675 in. SurveyiAbstract: SlateiiCountry_-AFUUSA MD Out: 1400 It _ - Mud Weigle; 5.5 ppg 1 COMPONENTS 10(In.)- To(th 1 13 PV 22 CpCCartno 9.95 1500 2 13 VP 2515,10015 Open Hole 9,875'. 6400 3 13 Fluid Model ". ...r. .x,a e1._ e 4 13 Flow Rate gpm i 5 13 Max.Pump Press. _Psi - 6 '1 Surface equip.'?: 7 i Motor bypass'? i 1 e TY07 5453 R 9 0 at Nozzle f•101' ''`two,"c.4 o, .1 10 IA In.TFA 0.3634 Int DriN String 1268.30 psi 47.62% Total TFA 0.7777 Int Annulus 70.10 psi 2.88% Jet Velocity 206.37 Rts Surface 7746 psi 2.88% Press.Drop 361.82 psi Specie' 900.00 psi 33.27% Bit Hyd.Power 105,49 hp Sit 361.62 psi 13.31% H.S.1. Impact Force 507.37 161 ECU 9.76 ppg TaiaEESPP 2705.46 pN 100.00% OD ID Tod Joint Length Cap. Pressure Loss DRILL STRING COMPONENTS In In. OD ID n bble psi Drill Pipe(S)(CDS 40 Connections 4.9 3.826 6.375 3.5 S55sl 70,65 593.35 HWOPICDS 40 connectlonC.13 Jtal 4.5 2.66 6.26 255' 403 2.60 109.60 Weatherford HO Jar[CDS40) i 6 2.25 6 225 31 0.15 32.50 HWDP(CDS 40 connections,6 JD) 4.5 2.65 6.25 2.55 106 1.20 92.12 0-0 Sub(CDS 40 Dox X 4-112"IF Pin) 5.5 2.75 6.5 235 4 0.03 1 76 4 Joints 6.314"NM Flex Drill Casters 6.75 2.913 6.75 2.613 120 0.92 47.63 integral 9ladeStabitiaer(9.70'Gauge) 6.75 2.75 6.75 2.75 5 0.04 2.20 l4WD TM HOC(Pulsed 6.75 ••••"••"" 6.75 ••"•"•"•" 16 454.00 MWD HCIM Collar 1 0.75 1.42 6.75 1.42 5 0.01 38,46 /4WD-PWD Caller 9.75 1.42 675 1.42 5 0,01 38.45 MWD EWRP41Gamma Collar 6.75 1.42 6.75 1.42 22 0.04 169.24 MWD Directional Collar 6.75 1.42 6.75 1.42 9 0.02 69.23 Integral RladeStabilizer(0.75-Gauge) 6.75 2.75 6.75 275 5 0.04 2.20 Float Sub 6.75 2.75 0.75 275 3 0.02 1.32 7 Sperty0nll Lobe 778-6.0 51g. I 7 "•'•'^••^ 7 ^""'•'""' 25 450.00 ANNULAR Hole ID Pare OD Length Cum. C . Annular CrIlod Type of Pressure Lone SECTIONS in. M. ft Depth bbte Rre[n ft/min Plow PO Casing 9.95 4.5, 1500 1500 114.75 155_81,, 303.43 L 16.62 Open Hale 9.875 4.5 4058 5558 304.59 150.81 306.06 L 46,43 Open Hole 9.875 4.3 403 5961 30.25 150.61 305.06 L 4.61 Open Hole 9.875 6.25 31 5992 1.76 209.641 364.73 L 0.77 Open Hobe 9.875 4.5. 185 6176 13.96 150.01 305.05 L 2.13 Open Hole 9.875 6.3 4 6192 0.21 22113 364.58 L 0.11 Open Hole 9.875 5,75 120 6302 6.06 235.89 375.48 L 4.00 Open Hole 3.870 6.75 5 6307 0.25 235.89 37549 L 0.17 Open Hole 9.875 5,75 16 6323 0.81 235.89 375.49 1 0.53 Open Hole 9.875 6,75 5 6326 0.25 235.09 37549 L 0.17 Open Hole 9.875 6.75 5 6333 0.25 235.89 37549 L 0.17 Open Hole 9.875 6.75 22 6355 1.11 235.89 375.49 L 0 73 Open Hole 9.875 6.75 9 6364 0.45 235.891 375.49 L 0 30 Open Hole 9.875 6.75 5 6369 0.25 235.091 375.49 L 0.17 Open Mole 9.875 6.75 3 6372 0.15 235-891 375.49 L 0.10 Open Hole 9.875, 7 26 6400 1.32 252.60' 367.67 L 1.10 I I I Page 25 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Hilrnrp Alaska,LLC 15.8 9-7/8"hole section mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1)ppg above highest anticipated MW. 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: 9.0—9.5 ppg 6%KCl/PHPA fresh water based drilling fluid. Properties: MD Mud ; Viscosity Plastic yield Point pH HPHT Weight' Viscosity 1,500'- 6,100' 9.0—9.5• 40-53 15-25 15-25 8.5-9.5 < 11.0 System Formulation: 6% KCL/PHPA Product Concentration Water 0.905 bbl KCl 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-499 4 ppb EZ MUD DP 0.75 ppb(initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC-L 1 ppb BARACARB 5/25/50 5—10 ppb(3.3 ppb of each) BAROTROL PLUS 2—4 ppb SOLTEX 2—4 ppb BAROID 41 as required for a 9.0—9.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) Page 26 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure nilrnrp.41n4n,LLC 15.9 Close blinds and test 10-3/4 casing to 2500 psi. for 30 minutes. 15.10 PU BHA and TIH, Conduct shallow hole test of MWD and confirm Gamma Ray LWD functioning properly. 15.11 Continue in hole and tag TOC. Note depth tagged on AM report. 15.12 Drill out plugs and shoe track. Clean out rat hole and drill an additional 20' of new formation. 15.13 CBU and condition mud for FIT. ) i~ _ '7 S 15.14 Conduct FIT to 12.5 ppg EMW. JC"4- C 4- C 15.15 Drill 9-7/8"hole section to 6,100' MD/6,051' TVD. • • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 500 gpm. Ensure shaker screens are set up to handle this flowrate. • 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. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. If tight hole is encountered, screw in and begin backreaming connections until hole conditions improve. Shales in the Beluga formations are notorious for swelling and causing • tight hole. Most of the time, backreaming them on a short trip is the only solution. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss< 11. • Take MWD surveys every other stand drilled. Surveys can be taken more frequently if deemed necessary. • Ensure to pre-treat the active system with 10 ppg Calcium carbonate. Have additional fibrous and other bridging material on location in the event lost returns are encountered. There are many stacked sands that are severely depleted that will be penetrated in the 9-7/8" hole section. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4" shoe. 15.17 TOH with the drilling assy, handle BHA as appropriate. Page 27 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Hilcor1.Alocka, 16.0 Run 7-5/8" Intermediate Casing 16.1 R/U and pull 10" ID wear bushing. Install and test 7-5/8" casing ram in top ram cavity. Test to 250/3500 psi. 16.2 R/U Weatherford 7-5/8" casing running equipment. • Ensure 7-5/8" BTC x CDS-40 XO on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 16.3 P/U 7-5/8"29.7# L-80 BTC shoe joint, visually verify no debris inside joint. 16.4 Continue M/U&thread locking the shoe track assy consisting of: • (1) Float shoe joint w/float shoe bucked on. Install (2)bow spring centralizers at 10' from each end over a stop collar. • (1) Baker locked joint. Install (1) centralizer mid tube over a stop collar. • (1) Float collar joint w/float collar bucked on pin end. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float shoe and float collar. 16.5 Run 7-5/8"29.7#L-80 BTC casing. • Fill casing while running using fill up line on rig floor. • Use "API Modified"thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install centralizers over couplings on every other joint to 1500' MD. 16.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.7 Slow in and out of slips. 16.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe approximately 10—20' above TD. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. Page 28 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Hilrnrh Aln ka,Li t. Casing and Tubing Performance Data PIPE BODY DATA GEOMETRY Outside Diameter 7.625 in Wall Thickness 0.375 in API Drift Diameter 6.750 in Nominal Weight 29.70 lbs/ft Nominal ID 6.875 in Alternative Drift Diameter n.a. Plain End Weight 29.06 lbs/ft Nominal cross section 8.541 in PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Tension Yield 683,000 in Internal Pressure Yield 6,890 psi Collapse Pressure 4,790 psi Available Seamless Yes Available Welded No CONNECTION DATA TYPE:BTC GEOMETRY Coupling Reg OD 8.500 in Threads per in 5 Thread turns make up 1 PERFORMANCE Steel Grade L80 Coupling Min Yield 80,000 psi Coupling Min Ultimate 95,000 psi Joint Strength 721,000 lbs Internal Pressure Resistance 6,890 psi 7-5/8" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 7-5/8" 7,630 ft-lbs 16.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 16.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat (slightly) to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 16.11 Continue circulating until required properties achieved for cmt operations. 16.12 After circulating, lower string and land hanger in wellhead again. Page 29 Revision 0 March, 2017 • KU 11-07X Drilling Procedure lbIcorh.Alnwkn.i.Lr 17.0 Cement 7-5/8" Cement Procedure 17.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. • Pump minimum of 15 bbls thru SLB lines to clear any debris • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 17.2 R/U cmt head (if not already done so). Ensure top and bottom plugs are loaded correctly. 17.3 Pump 5 bbls 10 ppg spacer. Close low torque valve on plug dropping head, test surface cmt lines to 4000 psi. Pit o�7J 17.4 Pump remaining 35 bbls 10 ppg spacer and drop bottom plug. 6.9 17.5 Mix and pump slurry per below calculations: Section: Calculation: Vol(BBLS) Vol(ft3) LEAD: (5,600'- 3,000') x .038 bpf x 1.25 = 124 696 9-7/8" OH x 7-5/8" csg: Total Lead: 1.1. .t Z 124 bbls 696 ft3 36'f s" TAIL: 500' x .038 bpf x 1.25 = 24 135 9-7/8" OH x 7-5/8" csg: TAIL: 90' x .046 bpf= 4.1 23 7-5/8" Shoe Track: Total Tail: l L' 28.1 bbls 158 ft3 /z.; � Page 30 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Hilrnrp AlaAn.1.1.1. Slurry Information Lead Tail System Conventional Extended Conventional Density 12.5 lb/gal 15.2 lb/gal Yield 1.92 ft3/sk • 1.26 ft3/sk • Mixed Water 6.794 gal/sk 5.76 gal/sk Mixed Fluid 6.834 gal/sk 5.76 gal/sk Expected 5:02 HR:MIN 3 HR Thickening Code Description Concentration Code Description Concentration D-046 Antifoam 0.2% BWOB D901 Cement 94 lb/sk D-065 Dispersant 0.35% BWOB D046 Bonding Agent 10% BWOC Additives D167 Fluid Loss 0.25% BWOB D065 Anti-Static 0.005 lbs/sk D177 Retarder 0.04%gal/sk D167 Anti Foam 1 gal/100 sks S002 Retarder 0.4% BWOC 17.7 After pumping cement, drop flexible shut-off plug and displace cement with mud. Use the cement unit to displace with as volumes can be tracked much more accurately. Displacement calcs: • 6,020' x .0459 bpf=276 bbls. et` • Displace with 10 ppg 6% KC1 drilling fluid out of mud pits. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not over displace by more than '/2 shoe track volume. Total volume in shoe track is 4.1 bbls 17.10 There should be no cmt returns to surface. TOC is planned to be at 3000' MD. 17.11 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. • If this is the case, monitor the pressure on the casing and do not let it exceed 500 psi over the final pump pressure. Page 31 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Hilrnri..Aln,wkn,LLC Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing,bpm,note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to mmyers@hilcorp.com & cdinger(ai,hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 17.1 R/D cement equipment. Flush out wellhead with FW. 17.2 Back out and L/D landing joint, flush out wellhead with FW. 17.3 M/U pack-off running tool and pack-off to bottom of landing joint. Set casing hanger pack-off. Run in lock downs and inject plastic packing element. Test void to 250/3000 psi for 10 min. 17.4 Lay down landing joint and pack-off running tool. 17.5 Run CBL on 7-5/8" casing prior to drilling out float equipment. And minimum of 24 hours after cement is in place. Page 32 Revision 0 March,2017 • • KU 11-07X Drilling Procedure Hileorp Alaska,TIC 18.0 Drill 6-3/4" Hole Section 18.1 Remove 7-5/8" casing rams from BOP. Install 2-7/8" x 5" VBRs in top cavity. BOP configuration should be (from top down): Annular/VBR/Bllnd/Mud cross/VBR. 18.2 Test BOPs on 4-1/2"test joint. 18.3 R/U Mud loggers for the 6-3/4"production hole section. They need to be set up to generate mud - log, pixler plots, and collect (3) sets of samples every 20 ft. 18.4 Pull test plug, run and set wear bushing. 18.5 Ensure BHA Components have been inspected previously. Rack enough 4-1/2"DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 18.6 Drift& caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 18.7 Ensure TF offset is measured accurately and entered correctly into the MWD software. 18.8 Confirm that the bit is dressed with a TFA of 0.46 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 270 gpm. Page 33 Revision 0 March,2017 • • II KU 11-07X Drilling Procedure Hi!cnrp Alaska,IIIc 18.9 P/U below 6-3/4" directional drilling assy: COMPONENT DATA Item OD ID Gauge Weight Top Length Cumulative 4 Description ltserial Number (in) tin) (tbpt) Connection (ft) Length (ft) 1 6.3/4"PDC 5.000 1.500 6.750 60.89 P 3-112'REG 0.80 0.80 2 5"SperryDrill Lobe 67-6.0 stg 5.000 3.120 48.00 B 3-1/2"IF 24.00 24,80 Stabilrzer 6.500 3 4-3/4"Float Sub 4,680 2.250 45.07 B 3-1 2"IF 3.00 27 80 4 Integral Blade 4.750 2.250 6.500 46.84 B 3-1 2"IF 3.00 30.80 5 4 3/4"DM Collar(Directional) • 4.740 2.610 47.00 B 3.1:'2"IF 9.20 40.00 6 4 3`4"Slim Phase 4 Collar . 4750 1.250 48.20 B NC 38 22.00 62.00 7 Inline Stabilizer(ILS) 4.750 2.250 6.500 46.84 B 3-1.2•'IF 3.00 65.00 8 4 3'4"ALD Collar ' 4.750 1.250 6.375 45.50 B NC 38 14.35 79.35 Stabilizer 6.375 9 4 3'4"CTN Collar • 4.750 1.250 50.50 B NC 38 11.14 90.49 10 inline Stabilizer(ILS) 4.750 2.250 6.500 46.84 B 3-1,'2"IF 3.00 93.49 11 4 3'4"PWD?Pressure 4.730 1.250 47.90 B 3-1 2"IF 9.20 102.69 12 4 34"TM Collar(Telemetry) 4.700 2,812 46.10 B 3.1;2"IF 11.60 114.29 13 4-3'4"NM Flex Collar 4.640 2.250 44.08 B 3-12"IF 30.00 144.29 14 4-314"NM Flex Collar 4.770 2.250 47.35 B 3-1/2"IF 30.00 174.29 15 X-Over 3 1'2'•IF Pin x CDS-40 Box 5.250 2.683 54,44 B 4.5" 1,58 175.87 CDS-40 16 6 Its 4.112"HW DP CDS-40 4,500 2.813 36.86 184.00 359.87 17 X-Over CDS-40 Pin x HT-38 Box 5.260 2.125 61.97 B 4"HT 38 2.00 361.87 18 4-3/4"Weatherford Jar 4.890 1.875 54.59 29.00 390.87 19 X-Over HT-38 Pin x CDS-40 Box 5.260 2.000 63.35 B 4.5 2.00 392.87 CDS-40 20 13 jts 4.1/2"I-4WDP CDS-40 4.500 2.813 36.86 409.50 802.37 „;i 802.37 Page 34 Revision 0 March, 2017 s • 1 DrillingKU 1Proce-07Xdure Hileorp Alaska,11.14: 18.10 Hydraulics Summary: Security DBS BIT HYDRAULIC PROGRAM Prepared For-Hilcorp KDt1 32.18 By Mark Oroulllat Oate prepared:-179114 Operator,-I911oarp Well Namei No:-NOLs 32-05 Bit Type:- POC Contractor:- County:-Kenai Bit Diameter:- 6.75 in. SurreyfAbetrate- StalefCourthy:•AIUGSA MO Gar:- 9350't HOLE 1 NOZZLE Manual I Auto Mud WerghO 14,.5 ppg COMPONENTS 10(In.) 10;r1. P/' 13 cp asieg 6.875 0400 2 , YP 19 Ito°cifr,.•n Hale 6 75. 9350 3 10 Fluid Model .. '..,',5, Rae :J 4 10 flow Ram Wm 5 10 Mau,Pump Press.. _psi 6 10 Surface equip.? 7 Motor bypass"? 8 Tvo9 _._ 7853 ft 6 9alNozzle MO)6 .+M4r„4C4Wuean .1 10 Min.TF*, 0.1974 Iles Drill String 875-90 psi 35.40% Total TFA n m0?in' Anthill-ft 369.97 psi 14.99% Jet Velocity 191.62 fb's Surface 29.19 psi 1.19% Press.Drop 345.21 psi Specie.' 850.00 psi 34.44%. Bit Hyd.Power 55.40 hp al 345.31 psi 13.99% H,5.1. Maga' Impact Force 286.69 NO ECD 11.41 ppg TotaIISPP 2468.37 psi 100.00% OD ID Tool Joint Length Cap. Pressure Loss DRILL STRING COMPONENTS in in OD IDI ft bbls psi Drill Pipe(S;I(GDS 40 Conneciians 4.5 3.026 6.375 3.5 5517.5 120.53 319.99 I'WDP(GDS 40 connections,13 As) 4.5 2.66 6.25 2.55 403 2.80 68.47 4-3d4-Weatherford Hyd Jar wl 0-O'r 5 2.25 5 2..25 35 0.17 12.43 IIWDP(GDS 40 connections,6 Jtc) 4.5 2.66 6.25 2.551 186 1.29 31.60 0-0 Sub 1005 40 Boo 0 3-112"IF Pin) 4,7 2,5 5 2.3 1 4 0.02 0.92 2 Joints NM Flax Drill Collars 4,75 2.5 4.75 2.5 60 0.36 13.61 !MD./taxi Sonic 4.75 1.25 4.75 'L25 26 0.04 112.82 MWDITM HOC(Pulser) 4.75 41.1"1.•••"""' 4.75 •""`"•"*". 11 "•••. 400.00 MWD IPWD 4.75 1.25 4.75 1.25 0 0.01 39.05 MWD.rALD-GTN[Nukes! 4,75 1.25 4.75 1.25 25 0.04 118,46 Inline Stabilizer(ILS 0"Gauge 4.75 1.25 4.75 1..25 3,5 0.01 15.15 MWI37 DlractionallSlim Phase 4 4.75 1.25 4.75 1.25 34 0.05 147.54 NM Siring Stabilizer(6.625Gauge) 4.75 2 4.75 2 5.5 0.02 3.23 Float Sub I 4.75 2.5 4.75 2.5 2.5 0.02 0.57 5"Sperry0rill tone 68-6.0 61g1W1ABII I 5 ..••.'•... 5 281 450.00 IIMh': ANNULAR Hole ID 1 Pipe OD Length Cum. Cap. Annular i Cri0WN Type of Pressure Loss SECTIONS in._...............In. ...___ft Depth bbls Main, hfnlfn Flow P11 Casing,. 6.875 4.5 6400 6400 167.96 246.49; 310.59 L 242.12 Open Hole6.75 4.5 2117.5 8517.5 52.07 266.28. 316.12 L 89.68 Open Hole 6.75 4.5 401 8920.5 6.51 266.28' 310.12 L 17,07 Open Hole; 6.75 4.7 35 8955.5 0.80 287.16 325.86 L 1.77 Open Hole' 6.75 4.5 186 9141.5 4.57 266.28. 310.12 L 7.68 Open Hale 6.75 4.7 4 9145.5 0.09 267.16: 325.86 L 0.20 Open Hole 6.75 4.75 60 9205.5 1.34 293 115 326.50 L 3.18 Open Hole 6.75 4.75 26 9731,5 0.56 293 05 326 50 L 1.38 Open Hole 6.75 4.75 11 9242.5 0.25 293 05 379 50 L 0.58 Open Hole 6.75 4.75 9 9251.5 0.20 293 05 328 50 L 0.48 Open Hole 6.75 4.75 25 9276.5 0.56 293 05 328 50 L 1.32 Open Hale 6.75 4.75 1.5 9280 a.06 293.05 328.50 L 0.19 Open Hole 6.75 4.75 34 9314 0.76 293.05'. 328.50 L 1 80 Open Hole 6.75 4.75 5.5 9319.5 0.12 293.05 328.50 L 0.29 Open hale 6.75 4.75 2.5 9322 0.06 293.05 328.50 L 0.13 Open Hole 6.75 5, 26 9350 0.56 327..79. 343.12 L 1.91 k Page 35 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Hileorp Ala.ka.lit'. 18.11 Primary bit will be the Security EM65D. 6-3I4' (171mm) EM65D PRODUCT SPECIFICATIONS Cutter Type X3-Extreme Driltitsg i.ADC Code M323 +r " Body Type MATRIX Fatal(utter('aunt 3:i Cutler Distribution 1311111 i lL1111 Puce 4 13 Gauge 11 0 1 4 )111 Up Drill 5 0 . Number of Large Nozzles 0 e Number of Medium Nozzks 0 i Number of Small Nozzles 6 e " Number of Micro Nozzles 0 v4/. y Number of Poets(Sim) tt ,er Number of Replaceable Ports{Size) Junk Slot Arca{sq in) 8.6K ' Nnnnaltxed Face Wrlome 34.60•. API Connection 3-1.2 REG.PIN Recommended Make-Up Torque' 5.173—7,665 Ft'lbs. Nominal Dimensions'" Make-Up Face to Nose 0.42 in-234 nun Gauge length 2 in-51 nun Sleeve Length 0 in-R min Shank Diantet i 4s in-114 nun Break Out Plate lMat,tMegacy#t I1MI053444130 Approximate Shipping Weight %Lbs.-41 Kg. SPECIAL FEATURES Up-Drill Cutters on Gage Pads,1 I6"Stepped Gage..Oplim ized Dual Row-"D"Feature Material 4761302 'Bit specific recommended mnkrup torque it.a function elate bit I.D.and actual bit sub U.D.atitize l m ifinl in API Rl'7G Section A.;3 2. "'Design dimensions are nominal and rosy ver!.,slightly cm manufactured product.tioltitauir n Drill Sits and.Services models arc continuously reviewed and refired. Product epvctOratbsm may&baileeAtm ndice, 2013 Halliburton.All rights reserved_Sales of Holliburton 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. www.halliburton.com Page 36 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Hilcorp Alaska,LLC 18.12 TIH to TOC. Shallow test MWD on trip in. Note depth TOC tagged at on AM report. 18.13 Conduct casing test to 3500 psi/30 min. 18.14 Drill out shoe track and additional 20' new formation. CBU and prep for FIT. -a 18.15 Perform FIT to 12.5 ppg equivalent. (12h1) —� 18.16 Drill 6-3/4"hole to 9,572' MD/9,480' TVD • Kr • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • 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 adequate LCM is available on location in the event returns are lost. • 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 HTHP fluid loss < 10. • Take MWD surveys every other stand drilled. • Pull wiper trips every 500– 1000 ft drilled. If tight hole is encountered, screw in and begin backreaming connections until hole conditions improve. Page 37 Revision 0 March, 2017 KU 11-07X Drilling Procedure Hilcorp.Alaska,LLC 18.17 6-3/4"hole section mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on • location to weight up the active system(1)ppg above highest anticipated MW. 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: 10— 11.5 ppg 6%KC1/PHPA fresh water based drilling fluid. Properties: MD Mud Viscosity Plastic Yield Point pH HPHT Weight , Viscosity 6,100'- 9,572' 10-11.7 �" 40-53 15-25 15-25 8.5-9.5 < 10.0 PPg System Formulation: 6% KCL/PHPA Product Concentration Water 0.905 bbl KC1 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-499 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 1-2 ppb PAC-L 1 ppb BARACARB 5/25/50 15-20 ppb(5 ppb of each) BAROID 41 as required for a 10.0—11.0 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate) 18.18 Hilcorp Geologists will follow LWD log closely to determine exact TD. 18.19 At TD; pump sweeps, CBU,and pull a wiper trip back to the 7-5/8" shoe. 18.20 TOH with drilling assy and handle BHA as appropriate. Page 38 Revision 0 March, 2017 • 14KU 11-07X Drilling Procedure Mem!,:1111.1.4.LLE. 19.0 Run 4-1/2" Production Long String 19.1 R/U Weatherford 4-1/2" casing running equipment. • Ensure 4-1/2"DWC/C HT x 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 on the deck prior to running. • Be sure to count the total#of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 19.2 P/U shoe joint, visually verify no debris inside joint. 19.3 Continue M/U&thread locking shoe track assy consisting of: • (1) Shoe joint w/shoe bucked on&threadlocked(coupling also thread locked). • (1) Joint with float collar bucked on pin end &threadlocked (coupling also thread locked). • (1) Joint with landing collar installed INSIDE pin end. • Solid body centralizers will be pre-installed on shoe joint& FC joint. • Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe. 19.4 Continue running 4-1/2"prod 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 long solid body centralizers (longer than 6-3/4") on every joint to 6,100' MD. Leave the centralizers free floating. • Ensure to install swell packer joint so that it is 500' inside the 7-5/8" shoe when landed out. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 4-1/2" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2" 5,800 ft-lbs 6,500 ft-lbs 7,200 ft-lbs Page 39 Revision 0 March, 2017 i KU 11-07X Drilling Procedure Hilcorp.Alawka,T.r.l. Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: DWC/C Tubing 4-1r2 in 12.60 Ib/ft (0.271 in) L-80 standard Material L-80 Grade 80.000 Minimum Yield Strength (psi) V U SA 95,000 Minimum Ultimate Strength (psi) VAM USA 4424 W.Sam Houston Pkwy. Suite 150 Pipe Dimensions Houston.Tx 77041 Phone:713-479-3200 4.500 Nominal Pipe Body O.D. (in) Fax:713-479-3234 3.958 Nominal Pipe Body I.D.(in) E-raid:VAAWUSAsales+ +am-usa.com 0.271 Nominal Wall Thickness (in) 12.60 Nominal Weight (Ibslft) 12.25 Plain End Weight(Ibstft) 3.600 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength (lbs) 7,500 Minimum Collapse Pressure(psi) 8,430 Minimum Internal Yield Pressure (psi) 7,700 Hydrostatic Test Pressure (psi) 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(%) Connection Performance Properties 288,000 Joint Strength (lbs) 14,290 Reference String Length (ft) 1.6 Design Factor 314,000 API Joint Strength (lbs) , 288,000 Compression Rating (lbs) 7500 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-lbs) 6,500 Maximum Final Torque (ft-lbs) 7,200 Connection Yield Torque (ft-lbs) Page 40 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Hilcorp Alaska,TIC 19.5 M/U casing hanger joint to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe approximately 10—20' above TD. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 19.6 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 19.7 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat(slightly)to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 19.8 After circulating, lower string and land hanger in wellhead again. Page 41 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Hilenrp Aln kn, 20.0 Cement 4-1/2" Production Long String 20.1 Hold a pre job safety meeting over the upcoming cmt operations. Ensure the below is covered during the meeting: • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 20.2 Attempt to reciprocate the long string during cmt operations. 20.3 Pump 5 bbls 12 ppg MUDPUSH II spacer. 20.4 Test surface cmt lines to 4500 psi. Cu 20.5 Pump remaining 15 bbls 12 ppg MUDPUSH II spacer. ry 20.6 Mix and pump 15.3 ppg class "G" cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 100% OH excess. Section: Calculation: BLS) Vol (ft3) (B7-5/8" x 4-1/2" long string Overlap: 500' x 0.02624 = 13.12 74 6-3/4" OH x 4-1/2" Longstring: (9,572—6,100') x 0.0246 x 1.5 = 128 719 Shoe Track: 90' x 0.01522 = 1.37 7.7 Total Volume: 143 bbls 801 ft3 5133,1-k Page 42 Revision 0 March,2017 • • KU 11-07X Drilling Procedure !Henri)Alaska,UT Slurry Information: Tail System Blend Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.889 gal/sk Mixed Fluid 5.929 gal/sk Expected Thickening Blend Code Description Concentration D046 Antifoam 0.2%BWOC D202 Dispersant 1.5% BWOC D400 Gas 0.8% BWOC Additives Migration D154 Extender 8.0% BWOC D174 Expanding 1.0% BWOC agent D177 Retarder 0.04 gps 20.7 Drop top plug and displace with filtered 6% KC1. 9,439 ft x .01522 = 143.6 bbls. 20.8 Do not overdisplace by more than I/2 shoe track. Shoe track volume is 1.37 bbls. 20.9 Bleed pressure to zero to check float equipment. 20.10 Pressure up again to 3500 psi and hold for 30 min to test production bore. Page 43 Revision 0 March, 2017 • 11 KU 11-07X Drilling Procedure Hileorp Alaska,LLC Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing, bpm,note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job.Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Send final "As-Run" casing tally & casing and cement report to mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 21.0 RDMO 21.1 Install back pressure valve in hanger neck. N/D BOP. cot„,Li 21.2 N/U tree and pressure test tree/casing to 3500 psi for 5 minutes. 21.3 RDMO Saxon Rig#169. 21.4 After rig has departed, pull BPV &run CBL to determine TOC behind 4-1/2"production casing. M 2500 I 5.4 - - � h 1/2- x. 7 ") Page 44 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure !Henri..tla.ka,1JA 22.0 BOP Schematic l� r 11_ °n, IMI lil lil lel lie • Saxon#169 11"x5M all rill fill 111111 Townsend BOP LemiT3-Energy Mode r ' —1�I11 Manual Manual Manual Valve Valle Valye Line '441 +AV ' . [rY {.ill.. . T3-Energy Model 60111 } 5 144)441 14.0 u 411 11 5M X 11 5N.' fi fffi l2` uf1 fi I O..- Serahnard-14413S aysle 1 a +1 1 11 el. 1.4 163MX115M i 1I —(ir~ 1 I a.1 lizeb• (1 111.- r. !.I I,. I, i IJ r; .4411• 1. I I Page 45 Revision 0 March, 2017 • • 1 KU 11-07X Drilling Procedure 23.0 Wellhead Schematic BHTA,Otis,4 1/16 SM FE X 6.5"Otis Quick Union ,,,,`4 •6• to Valve,Swab,WKM-M, ."( . g5 e; �'? 4 1/16 SM FE,HWO,DD trim — ` �" $1, .N°' `$h, ,,,s'- r..... 7111410, Valve,Upper Master " .. "" WKM M,4 1/16 5M FE, • o• HWO,DD trim .--." ...1., .....I Valve,Master,WKM-M, .. 4 1/16 SM FE,HWO,DD trim _7_- `; ..=SO'"_'-'llr Multibowl Wellhead,SMB-22, i !ii.11: - 4. 2 1/16 SM SSO �i i P 'I _momI{_ o. .}I, j' Starting head,Seaboard, c 16%3MX16"SOW,w/ 2-2 1/16 SM EFO :' .1111T.(1 . 1" kiltlo•r :i j 11 I 16" is,a" 7 S/8" 4'7" Page 46 Revision 0 March, 2017 l • KU 11-07X Drilling Procedure !Warp Ala.,kn,1iA 24.0 Days Vs Depth Days Vs Depth 0 _— —KBU 22-06Y \ —KBU 42-06Y 11-07X • 2000 \\4000 t a v v 6000 10 C4/ 8000 10000 12000 0 5 10 15 20 25 30 35 Days Page 47 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Ilileorp.16.1.a,1.11: 25.0 Geoprog GEOLOGICAL PROGNOSIS WELL NAME: KU 11-07X FIELD: Kenai Gas Field SURFACE LOCATION X=271,914.47' X=271,923.15AFE: BHL: As-Built: y=2,362,253.42 Y=2,361,240.03: PAD: KGF 14-06 PROPOSED TD: 9,572'MD 9,480'TVD EST.KB. 81.63 AP/: TBD i Rig RKB: 18.00 Saxon 169 EST.GL: 63.63 Objective: Drill a grass roots well at Kenai Field thatwill target reserves in D2,D3B,and D4 sands.Secondary targets include the Lower Beluga-Upper Tyonek and Sterling A-11 sands. ANTICIPATED FORMATION TOPS&GEOHAZARDS EXPECTED FLU D MD TVD(Fr) I SUBSEA DEPTH i Est.Pressure EMW Grad `---- �,{_ Sterling A-10 gas 3656 3,637 (3555.00) 187 0.99 0.05 ,10 ,. gas 3703 3,684 (3602.00) 270 1.41 0.07 SterlingA-11 Sterling B-1 gas 37911 3,772 (3690.00) 119 0.61 0.03 SterlBeluga ga 47271 _ 4,697 (4615.00)ingPool 6 gas 47271 4,442 (5984.00) 560 Beluga 2.29 0.12 Lower 8.68 0.45 Tyonek1Bgas 7469 7,403 (7321.00) 2 26 6.82 0.35 /�� +.. /�`� Tyonek D2 gas 8964 8,880 (8798.00) 500 1.08 0.06 Tyonek D3B gas 9272 9,184 (9102.00) 1000 2.09 0.11 1 Tyonek D4A gas 9439 9,349 (9267.00) 500 1.03 0.05 4 =Reservoir Objectives =Possible Geo Hazards DATA COLLECTION REQUIREMENTS: Mud Logging: Surface Csg.To TD,samples collected at 20'intervals • LWD Data: LWD Triple Combo Other Log Data: COMPLETION TYPE Chance of Success&Anticipated Rate ..% ARTIFICIAL LIFTEOUIPMENTOD r, 16" P' 136' _ . PROSED PIPE SET DEPTHS 10-3/4 1500' 7-5/8" 6100' !4-1/2"....-..-.-.. TD TUBING SIZE This well is to be driled from the 14-06 pad and will initially be drilled to the south.Please provide drilling and myself with the final surface location when the best location has been identified and staked.We would like to set intermediate casing OTHER COMMENTS above the Lower Beluga at 6100'MD. , NO INFORMATION CONCERNING THIS WELL IS TO BE RELEASED TO ANYONE EXCEPT THE EMPLOYEES OF HILCORP OR THEIR PARTNERS. Page 48 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Hilrnrp Alaska,LLC 26.0 Anticipated Drilling Hazards 13-1/2" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. BARACARB 5, 25, 50, 150, 400, and 1200. Ensure STEELSEAL, WAL-NUT, and BARAFIBRE are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of BARACARB 5 and 25 to the active system at 1 —2 ppb. Hole Cleaning: Maintain rheology w/gel and gel extender. Sweep hole with gel or BARAZAN sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25 —45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with . intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of—50 - —60 lbs/100ft2 to combat this issue. Maintain low flow rates for the intial 200' of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 20—30 prior to cement operations. Do not lower the YP beyond 20 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheology can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 49 Revision 0 March,2017 • • KU 11-07X Drilling Procedure Hilaorp Alaska,LLC 9-7/8" Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous 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/gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25 —45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of—50 -—60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200' of drilling to reduce the likelihood of washing out the conductor shoe. 2 To help insure good cement to surface after running the casing, condition the mud to a YP of 25 —30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 50 Revision 0 March,2017 • • KU 11-07X Drilling Procedure HHrorp Alaska,LLC 6-3/4" Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix • LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/viscosifier as necessary. Sweep hole w/20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KC1 in system for shale inhibition. 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. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 51 Revision 0 March,2017 • i KU 11-07X 11 Drilling Procedure IIii orp: l:1,1,1.11A' 27.0 Saxon Rig 169 Layout I 0 rail . , ..„ awn r , Si11 I "4 pi r ;; ate. Mil•, F, i rP:I r ' • i . , 1 %Thr _OR , : : !N �1,. �iwarna,�� I JI I.1 ils. .moi:lli ..erg.. E mm s 111111 = •ISI.>i1 �I =G I-' I_ IViuit. _ liti It* I �_ I 7.4_1f. I.Iilll CIII! ;7: 11 ;� 111111 =C u3 � �1� i= I�'"'illi I ( I I I I' - • ',- I ;:I i•ill ,, , :_•....; i I!. II:.111Ua I ,. ilgl IIIII I r "1 W . 1 �-! Y �-� I I IT 1 .� .I . 4 r r*—v unnu. U rr I Il – -- dilli . . a`l iII lI — I III'IIII of III .. -....... 1° ; ; y 1111 i____(-t____, i Page 52 Revision 0 March,2017 4 S KU 11-07X Drilling Procedure Iiilrorp Alaska,LLC 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure.Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 53 Revision 0 March,2017 • KU 11-07X IIDrilling Procedure Hilrnrp.Aln«hn.I.11 29.0 Choke Manifold Schematic 1 c. A E �S 1 \N - :: --. t., .tifi,: c.1) b b b <• ` .i I IILIIIIIpl i rktrAgli, e ; —8i+-14 el \ .+o i i ep o 1. P • f e e0 L t\., w 0 2 Ia ,Alit aii r~ imor �� 1 I$ ..M. pa}.`,'1�.. e o O � I + /`_ �� I I 4 Y�\11�iQr A,l{ a ii7 f,,,,,,,„,,, i 0. 0.1 p. I • 8 �=1� `ior 0• Irl— 1 «« o o ,��1 � , K,r a �_ L 1• P b •l�y 10 b �`3'� b 1tt'' S1f.`s. N —T— .. f 143 2 I oiieja A I{Itt �I I D e e . e`` NA 'b m l0ilt Itl p N I 1 H 1111'10N NN tl t,', IH •1111 181 al ""Ai I 49 I'1$1*Ilg t 71: ?FA N ,.l ' � e ,4001.,1.,,•, .ice e I !� i N-- N e mu° e oK) 11 U ii /Iliketi oz..414. Iiii : :1,7riiii.„ i �c 8 14 §al, 1 'mom �s. is A �I Z o P 2 b 11 I ! L _ t_L . L- 1Fr ,41 � i' —4— ; -, 1Y i g a C11 " 01`41."11 Ile. I li Page 54 Revision 0 March, 2017 • KU 11-07X Drilling Procedure Hilrnrp.Alaska,11.0 30.0 Casing Design Information Calculation & Casing Design Factors DATE: 3-17-2017 WELL: KU 11-07X FIELD: Kenai Gas Field DESIGN BY:Monty M Myers Design Criteria: Hole Size 9-7/8" Mud Density: 9.5 ppg Hole Size 6-3/4" Mud Density: 11.5 ppg 9 Hole Size Mud Density: Drilling Mode MASP(sec 1): 2290 psi (see attached MASP determination & calculation) MASP(sec 2): 1043 psi (see attached MASP determination & calculation) Production Mode MASP: 1991 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2, 3 Max MW gradient external stress and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 Casing OD 10-3/4" 7-5/8" 4-1/2" Top(MD) 0 0 0 Top(TVD) 0 0 0 Bottom (MD) 1,500 6,100 9,572 Bottom (TVD) 1,495 6,051 9,480 Length 1,500 6,100 9,572 Weight(ppf) 45.5 29.7 12.6 Grade L-80 L-80 L-80 Connection BTC BTC DWC/C HT Weight w/o Bouyancy Factor(lbs) 68,250 181,170 120,607 Tension at Top of Section (lbs) 68,250 181,170 120,607 Min strength Tension (1000 lbs) 1040 721568 Worst Case Safety Factor(Tension) 15.24 3.98 4.71 Collapse Pressure at bottom (Psi) 739 2,989 4,930 Collapse Resistance w/o tension (Psi) 2,480 4,790 6,601 Worst Case Safety Factor(Collapse) 3.36 1.60 1.34 MASP (psi) 480 2,230 1,064 Minimum Yield(psi) 5,210 6,890 8,430 Worst case safety factor(Burst) 10.85 3.09 , 7.92 Page 55 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Hilcorp Aln,kn,LLC 31.0 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 9-7/8"Hole Section KU 11-07X ,1:,.1:,.I MD ND Planned Top: 1500 1495 Planned TD: 6100 6051 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad Sterling A-10 3,637 187 gas 1.0 0.051 Sterling A-11 3,684 270 gas 1.4 0.073 Sterling 8-1 3,772 119 gas 0.6 0.032 Sterling Pool 6 4,442 220 gas 1.0 0.050 Upper Beluga 4,697 560 gas 2.3 0.119 Lower Beluga 6,066 2739 gas 8.7• 0.452 Offset Well Mud Densities Well MW range Top(ND) Bottom(ND) Date KBU 11-17X 9-9.2 ' 1,587 5,464 2009 KBU 14-08 9-9.2 ' 1,510 5,432 2008 KBU 41-18X 9-9.2 - 1,500 5,391 2008 KBU 24-7X 9-9.7 1,502 5,326 2006 KBU 32-08 9.3-9.8 1,446 5,401 2014 KBU 43-07Y 9.5-9.7 1,540 5,738 2014 Assumptions: 1. Fracture gradient at 1,500'MD/1,495'ND is estimated at 0.936 psi/ft based on field test data. 2. Maximum planned mud density for the 9-7/8"hole section is 9.5 ppg. 3. Calculations assume"Unknown"reservoir contains 100%gas(worst case). 4. Calculations assume worst case event is complete evacuation of wellbore to gas. Fracture Pressure at 10-3/4"shoe considering a full column of gas from shoe to surface: 1495(ft)x 0.936(psi/ft)= 1399 psi 1399(psi)-[0.1(psi/ft)*1495(ft)]= 1250 psi MASP from pore pressure(unknown gas sand at TD,at 9.2 ppg(0.4784 psi/ft) 6,051(ft)x 0.4784(psi/ft)= 2895 psi Downhole • 2895(psi)-[0.1(psi/ft)*6051(ft)]= 2290 psi Surface • Summary: 1. MASP while drilling 9-7/8"intermediate hole is governed by fracture gradient at the 10-3/4"casing shoe Page 56 Revision 0 March,2017 • KU 11-07X Drilling Procedure Hikor1,,tb,.ka.I.LC 32.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 6-3/4"Hole Section KU 11-07X Iik,..p vnas:,.I MD TVD Planned Top: 6100 6051 Planned TD: 9572 9480 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad Tyonek 1B 7,403 2626 gas 6.8 0.35 Tyonek D2 8,880 500 gas 1.1 0.06 Tyonek D3B 9,184 1000 gas 2.1 Oil Tyonek D4A 9,349 500 gas 1.0 0.05 TD 9,480 2000 gas 4.1 0.21 Offset Well Mud Densities Well Max DrIg MW Top(ND) Bottom(ND) Date KBU 11-17X 10.7 5,464 7,919 2009 r KBU 14-08 10.3 5,432 7,746 2008 r KBU 41-18X 11.6 5,391 8,651 2008 KBU 24-7X r 9.7 5,326 7,550 2006 KBU 32-08 10.70 5,401 8,183 2014 KBU 43-07Y 12.10 5,738 9,280 2014 Assumptions: 1. Fracture gradient at shoe is estimated at 0.936 psi/ft based on field test data. 2. Maximum planned mud density for the 9-7/8"hole section is 11.5 ppg. 3. Calculations assume"D4"Sand contains 100%gas(worst case). 4. Calculations assume worst case event is 2/3 evacuation of wellbore to gas. Fracture Pressure at 7-5/8"shoe considering a full column of gas from shoe to surface: 6051(ft)x 0.936(psi/ft)= 5664 psi 5,664(psi)-[0.1(psi/ft)*6,051(ft)]= 5059 psi Drilling Mode MASP MASP from pore pressure(2/3 wellbore evacuated to gas from"D"at.21 psi/ft) 9,480(ft)x 0.21(psi/ft)= 1991 psi 1,991(psi)-[[0.1(psi/ft)*9,480(ft)*2/3]+[0.21(psi/ft)*9,480(ft)*1/3]]= 695 psi Production Mode MASP MASP from pore pressure(entire wellbore evacuated to gas from TD): 9,480(ft)x 0.21(psi/ft)= 1991 psi Downhole 1,991(psi)-[0.1(psi/ft)*9,480(ft)]= 1043 psi Surface Summary: 1 MASP during production mode is governed by SI BHP minus entire wellbore evacuated to gas from TD. Page 57 Revision 0 March, 2017 • • KU 11-07X Drilling Procedure Ilileorp.AlnKka.TIC 33.0 Spider Plot (NAD 27) KBU 22-06Y BHL KBU 22-06 BHL , I • p I KBU 42-06Y BHL 1/ 1 , ' 1 KBU 32-06 BHL I KBU 42-06X BHI! FEE AA093836 '� ' r• I / / I / I I /' I KBU 42-06 BML KU 1306 BHL I / / KTU 43-06XRC`BHA I / • / I/KUI43-06BHL / `\ I KBU 23X-06/�HL 1 •/ KU 43-06RD BHL � // / • / .K111)43-06X L \ I 1 / / \ • %L-.-4KT(III 143-041XRD2 Shit\\ I / / // KBU 33-06 BHL\' 'II I `\ II I // ' ~ U 33-06,X BHL\� / II I KU 41-06A BHL \ 1 / / / el ` 1\ ! I f I / t 1\ / k 1 I S004NO1�2W \\` !r / / \ , 1 \I w I 1, 9 //KTU 24-06H BHL 1 i I SOO N011 W/; \ / I / / `, \\ t\\ I I I / I ,r ADL392670 \\ ; KIK/24-06RD BHL \ '` r i ' i ' ' ,'' \ ! / 4;01 BHl \ 1 \ ! 1 , / 1 / / \\ I / i.//1t ,S004N019 9. \`,,)' 0 i/' 1 ,/ ', \\I 1•4/1-:1 /_ 1 _ KBU 24068HL �. /1%``1 ti'1 /I ,1I, ,- KDU 08(KU 14X-6)BHL f'-�J KU 14-06 Y<! N. )I‘I\ t A I I 1,!! K /1,, --g 'r / KBU II-07X SILL\ \ 1 \t \II / 1 /j ,,,,,� ..,,,,\ yKU 21-Q• BHL 1 y. \j' �+ it, ' �� ,,, ` \ KBU 34-06 ti.HL 1 .,i{/ ! ,,, • • `,..// ' % �. 21-O7BHL \ 1 1I/L,s Vi4w--• � -- \I. `\ KBU 41-07X BHS/ ;• a 4 g1'-07:kik, KIIU I I-07X TPII v x' •l KG,i:1s �,, KENAI UNIT / , �\ - l `„( ,��, / —� . �4 (w�toeHL I 'KBL' I I-n-XBIIL. \ , � ,`\ \ 1 1 \ / TI 11 \ ll09BH\ I I _l,1 ` \ / 1 KBU 111 7 BHL \� ell ` KU -07X��L \\`�"\ 1. `° FEEA028142 ti ' I ' / , �\ KBU 31-07RD BHL I 1\ I yy�,/ /' �\ KTU 32-07H BHL\\ KBU 31-07 /I : KBU 444 BHL / \ ------ /-'7---J— ,ou42- 07RDBHL / 1 i / I •- A028143 ' \ ' / I \ KBt1 (KU 13-7)BHL / I / \ e / I / l / I / \ KTU 32-97 8HL I S004N012W,' \, • I I 9C3 / \t ;S004N019CJ \ x§,13 / / I / ' I / 1 ' t KBU 33-07 BHL I I / •D KDU 04 PB1 BHL 1\ S004N0107 I / U 43-12 BHL \@t3 U \ I • - - KBU 23-078HL t ADL392670 • Legend KBU 11-07X SHL Other Surface Hole Location KBU 11-07X_TPH • Other Bottom Hole Location ' ''4'- KBU 11-07X_BHL Well Paths Oil and Gas Unit Boundary I I . A II 0 500 1.000 1,500 2.000 Kenai Unit Feet KU11-07X Alaska State Plane Zone 4.NAD27 A Ililrorp AI•sL.,LIA. Map Date:3/14/2017 Page 58 Revision 0 March, 2017 S KU 11-07X Drilling Procedure 11iIcor1,Aln.4.a.MI: ill 34.0 Surface Plat (As Built) (NAD 27) - A.,:___......._6.,.. r 7 1..BASIS OF HORIZONTAL COORDINATES ME ALASKA STATE PLANE NAD27 ��0 F q�4 �� ZONE 4 DETERMINED EY A DIRECT TIE TO USCAGS TRI STA AUDRY HAVING A .�P.'. :5:1- Fj PUDUSHED POSITION OF LAT.80'30'50559'N LONG.151'16.37.445'W 1. N 2382045.42 E'.269e66 75 *:4911-1 ,��•/",/�''/ * NORTH 2ISA.%GFVERTICAL DATUM ISMEAN SEA LEVEL / W' /i C-(eraL9.,. / 3)SOUTHWEST CORNER SEC.6 COORDINATE DETERMINED FROM DIRECT ...--.44111...-f /"".'"" ''"' SURVEY TIE TO ME TO EXISTING 8Lh1 WG FORE NW CORNER SEC.7 ANO 0 FZ,.SEAR A.4<u AE / 4637-5 —C� SCTICORNER RNSR VALUS88TRECOVEREOAND NOT THE PROTRACTED //°jJ''. bq+N..-1� SECTION CORNER VALUES. '`,,1 „ D SCALE xa \ J I • I I 1I FEET �_ ____ EDGEPAD EGO NT_ C0N"tt0. P. PE C ) r- .�-Tqoce k. -- -- x‘.221 EV DS ( \Ev.6221' \ / %•IU 22te , \ otf+itu. \ s. • I NN ..AN ,,...,, \ r-- 3 ADD G.?- .1..«616® ® 0%_ru 22• >-I,at>XH %6V to 6Y KIIl IA>N QO 'ry l ..2.N]MTIY ®"In'SOIK C. F^ G. wklUAkk 31 Alb. ' K.G.F.PAD 1641 ' K.Tu A. g '�/ EIEVATiDN•65.8 M,S.I. au uxs a o • IAC•N 6 •S11 x.Jnaeaa K8u»terDi I , %Dx..t,r+ r.,Inu1s Q KIN 31-7 D x.l>kIT« 0 10.1.011.4300* CY X\ %V 214 vi I N. KBU 11-07X 0 ASBUILT SURFACE LOCATION ~ /- " NAD 27 ASP ZONE 4 Z / N:2362258.420' z '41\ O::',';',':;-•• E:271914.47' - �� LAT:60°27'36.11569"N 0 Z LON: 151"15'48.96304"W —../\/ 1003'FWL(NTS) 203'FSL - %U AT.12 62 I 0 V,,, 1003'FWL- n fn . EDGE PAD M001kw1NI US GLO .1 O ELEV: •63.63 MSL CCNTROk P7 CP-2 T4N W.C. 1 «I` + 1 KsktlW 16 Y-2 WO 21275 St S6 • 203'FSL - Etty 6r I 5121 S7 R12W R11W ❑ r� �l1', I 4, 1921 \ a� K r. !I1 U '',Z, vu . e 013 ' % ❑aru" •.... ONIA I SW COR IMO_ N 2362069.27 R 1\ 1 1. 6 E 270908.10 1" 12J7 / f, -1g.„......„.., , , �J / ii , / � t 11\ 0100 ail PRO.E.. 0EVV15C110 0 HILCORP ALASKA LLC AIC 10...6 CoNuLYnQ IncKBU 11-07X AS-BUILT SURFACE LOCATION rnAw'DY .C• '�+ 1�% KENAI GAS FIELD PAD 14-6 sake -Ia NAD27 PNDIECT NO '61019 EN ISEEI O 16WNNa 1+.•1641'+40/IM+TNO DOCK+O 1603 0, PO.10 K9DOTNA AK MMM111[ vace L amc+2N .AA-O+acao (lilcorp Alanka.LLC S6 T4N R11W SEWARD MERIDIAN,ALASKA slxrr 1 a 1 Et( l4C.M..• E fIDGCOY Page 59 Revision 0 March, 2017 0 • 11 KU 11-07X Drilling Procedure Hilrorp.kln.kn.UK 35.0 Offset MW vs TVD Chart MW vs TVD Offsets —KBU 32-08 1c4x, .,b.. _KBY 43-07Y 2000 1 I —KBU 11-O8Z _ -Y,BI..123 C5 301}0 11111M1 -KDU 10 . IIIKBU 42-06Y 4000 i 'I 0,41 Kms.. /lv 7X5000 / 1,��1-(7 Fi i i 5000 1 r o 1101111;k14 144.,, -rDX) Ilk Nk 8000 ` 9000 II 1. 11000 12000 { ISI 13000 6 7 8 9 10 11 12 13 14 Mud Weight(PPG) Page 60 Revision 0 March, 2017 • • 11:1KU 11-07X Drilling Procedure Hileorp Ala l.a,LLC 36.0 Directional Plan (wp09) Page 61 Revision 0 March, 2017 Hilcorp Alaska, LLC Kenai Gas Field KGF 14-6 Pad Plan KU 11-07X KU 11-07X Plan: KU 11-07X WP09 Standard Proposal Report 13 March, 2017 HALLIBURTON Sperry Drilling Services • HALLIBURTON Ig arHilcorpAlaska,LLC REFERENCE INFORMATION Calculation Method: Minimum Curvature Co-ordinate(N/E)Reference:Well Plan KU 11-07X,True North Sperry Grilling Error System:ISCWSA Vertical(ND)Reference: KBU 11-07XAs-Built @ 81.63usft(Saxon 169) Scan Method: Closest Approach 3D Measured Depth Reference: KBU 11-07XAs-Built @ 81.63usft(Saxon 169) Error Surface: Elliptical Conic Warning Method: Error Ratio Calculation Method: Minimum Curvature Project: Kenai Gas Field SECTION DETAILS Site: KGF 14-6 Pad Plan KU 11-07X Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Well: 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 Wellbore: KU 11-07X 2 600.00 0.00 0.00 600.00 0.00 0.00 0.00 0.00 0.00 Design: KU 11-07X WP09 3 813.33 6.40 240.00 812.89 -5.95 -10.31 3.00 240.00 6.05 4 3738.33 6.40 240.00 3719.66 -168.97 -292.67 0.00 0.00 171.68 5 3990.33 9.35 186.42 3969.56 -196.39 -307.15 3.00 -96.15 199.22 6 4226.22 9.50 157.33 4202.39 -233.43 -301.78 2.00 -102.61 236.21 7 5941.03 9.50 157.33 5893.67 -494.68 -192.65 0.00 0.00 496.44 8 5966.25 9.00 157.12 5918.56 -498.42 -191.08 2.00 -176.29 500.16 DDI = 4.906 i 9 8966.25 9.00 157.12 8881.63 -930.79 -8.61 0.00 0.00 930.83 KBU 11-07X TY D2 10 9421.86 9.00 157.12 9331.63 -996.46 19.10 0.00 0.00 996.24 KBU11-07X TY D4 11 9571.86 9.00 157.12 9479.78 -1018.08 28.22 0.00 0.00 1017.77 CASING DETAILS WELL DETAILS: Plan KU 11-07X TVD TVDSS MD Size Ground Level: 63.63 1495.28 1413.65 1500.00 9 5/8"x 12 1/4" +N/-5 +E/-W Northing Easting Latittude Longitude I 6050.67 5969.04 6100.00 7"x 8 3/4" 0.00 0.00 2362258.42 271914.47 60°27'36.116 N 151°15 48.963 VA 1 -750 9479.78 9398.15 9571.86 41/2"x61/8" SURVEY PROGRAM Date:2016-05-13T00:00:00 Validated:Yes Version: a Depth From Depth To Survey/Plan Tool 0 18.00 1500.00 KU 11-07X WP09 MWD+SC+sag 1500.00 6100.00 KU 11-07X WP09 MWD+SC+sag 6100.00 9571.86 KU 11-07X WP09 MWD+SC+sag 500_Start Dir 3°/100':600'MD,600'TVD FORMATION TOP DETAILS 750 --- End Dir :813.33'MD,812.89'ND 1000 TVDPath TVDssPath MDPath Formation 9 5/8"x 12 1/4" 3636.63 3555.00 3654.78 Sterling A-10 3683.63 3602.00 3702.08 Sterling A-11 3771.63 3690.00 3790.63 Sterling B-1 1500 ' ' 500 4441.63 4360.00 4468.79 Sterling Pool 6 4696.63 4615.00 4727.33 Upper Beluga 6065.63 5984.00 6115.15 Lower Beluga 2000 7402.63 7321.00 7468.82 Tyonek 1B 8879.63 8798.00 8964.23 Tyonek D2 2250 9183.63 9102.00 9272.02 Tyonek D3B • 9348.63 9267.00 9439.07 Tyonek D4A 2500 3000 3000 Start Dir 3°/100':3738.33'MD,3719.66'TVD - Sterling A-10 ,- c Sterling A-11 ST All 3500 ,-Start Dir2°/100':4738.33'MD,4671.7'ND 3750-- -Sterling B-1 -4000 End Dir :6062.18'MD,5928.48'ND o - Lo - Sterling Pool 6 4500 4500 Q. o - Upper Beluga 5000 5250- Start Dir 2°/100':8847.51'MD,8708.74'TVD C - 5600 " Lower Beluga 7"x 8 3/4" - End Dir :9020.51'MD,8881.63'TVD F-6000-. --A 6006 - -6500 6750- 7000 _ Tyonek 1B 7500- 7500 8000 8250- - 8500 - - Tyonek D2 KBU 11-07X TY '2 ` •000 Total Depth:9571.86'MD,9479.78'TVD 9000- Tyonek D36 _ _ _KBU11-07X TY •�• ----- - Tyonek D4A -IL,9572 9750- 4 1/2"x 6 1/8" KU 11-07X WP09 I I I I i I I I I i I I I 111111 H---1 I I I I I I I I I I i I I I I I I I 1 i I I I I r I I I I j I i i I I I I I i I i i I l l i l i i -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 Vertical Section at 180.53°(1500 usft/in) • i S HALLIBURTON Project: Kenai Gas Field WELL DETAILS: Plan KU 11-07X Site: KGF 14-6 Pad Ground Level: 63.63 Sperry Drilling Well: Plan KU 11-07X +N/-S +E/-W Northing Easting Latittude Longitude Wellbore: KU 11-07X 0.00 0.00 2362258.42 271914.47 60°2736.116N 151°15'48.963W I Plan: KU 11-07X WP09 REFERENCE INFORMATION Iii I eo rf) Co-ordinate(N/E)Reference:Well Plan KU 11-07X,True North Vertical(TVD)Reference:KBU 11-07XAs-Built(8181.63usft(Saxon 169) Measured Depth Reference:KBU 11-07XAs-Buil @ 81.63usft(Saxon 169) Calculation Method:Minimum Curvature 225— _ CASING DETAILS TVD TVDSS MD Size Name 1495.28 1413.65 1500.00 9-5/8 9 5/8"x 12 1/4" 150— 6050.67 5969.04 6100.00 7 7"x 8 3/4" 9479.78 9398.15 9571.86 4-1/2 4 1/2"x 6 1/8"• 75— 1r5i </3 0— u• 0 -75 q o ` Start Dir 3°/100':600'MD,600TVD 'ti 46' ' End Dir:813.33'MD,812.89'TVD ST Allea -150— - - _ Start Dir 3°/100':3738.33'MD,3719.66TVD 4000 -225— Start Dir 2°/100':4738.33'MD,4671.7TVD 4154 - - End Dir:6062.18'MD,5928.48'TVD - g500 -300- - 8150 = 5000 o -375— 5750 5500 - Start Dir 2°/100';8847.51'MD,8708.74TVD -450- 919 C - _ End Dir:9020.51'MD,8881.63'TVD -525— 7"x 83/4"--- .606 - 6y50 _ 65� -600— _ 6150 1000 -675— _ 11,50 15p0 -750-- 115° gpp0 -825— 8500 -900— 0 KBU 11-07X TY D215 Total Depth:9571.86'MD,9479.78TVD gp00 - KBUI I-07X TY D4 / 975— \ g150 41/2"x61/8 _4gg0 -1050— '6v‘`A1'141°9 T � � � � � � li � i � H 11.11I [ 1H II 1 ; 11111111H ' F [ 11 ilil111111111Iii ] i � liilii -525 -450 -375 -300 -225 -150 -75 0 75 150 225 300 375 450 525 West(-)/East(+)(150 us8/in) • • Halliburton HALLIBURTON Standard Proposal Report Database: x Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan KU 11-07X Company: 'Hilcorp Alaska,LLCTVD Reference: r KBU 11-07X As-Built @ 81.63usft(Saxon 169) • Project: Kenai Gas Field MD Reference: ` KBU 11-07X As-Built @ 81.63usft(Saxon 169) 1 Site: KGF 14-6 Pad North Reference: True Well: Plan KU 11-07X Survey Calculation Method: Minimum Curvature " Wellbore:j KU 11-07X Design: KU 11-07X WP09 - - ".,r;...._..�,.�. ...�. - �... .: »,` » .r . ,m n y„..... ...�. _ .. .' 'a,,.,.. .. x,x�` tea.w.zu. as•:�a Project Kenai Gas 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 Using geodetic scale factor Site :»r :YAMKGF 14-6 Pad Site Position: Northing: 2,362,394.10 usft Latitude: 60°27'37.354 N From: Map Easting: 271,396.69usft Longitude: 151°15'59.339 W Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.10 ° Well Plan KU 11-07X li Well Position +N/-S 0.00 usft Northing: 2,362,258.42 usft . Latitude: 60°27'36.116 N +E/-W 0.00 usft Easting: 271,914.47 usft• Longitude: 151°15'48.963 W- Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: • 63.63 usft yrs._ Wellbore -./..-•:'-':',:4", KU 11-07X «, ,,,,;:gin �,+»"{v:» cr»_,«:v. .»w.w»,,.t n"d 5rs5'u5'uud» -.aen.. i,.::*,ayst ar: {rY.., s2*9xw wvsunm rs. �, «, _. x yrs", ". T----, Magnetics 4 ' Model Name Sample Date Declination o .',,� • r : Field Strength i, L .xp (°) ' nT r .cam . BGGM2016 5/1/2017 15.92 73.46 55,348 • Design KU 11-07X WP09 Audit Notes: Version: Phase: PLAN Tie On Depth: 18.00 Vertical Section: Depth From(TVD) a +N/-Snr"'44E/-W 1 Direction- u ,_ , .'w . _ f _ (usft) (usft) (usft) (°) r 18.00 0.00 0.00 180.53 Plan Sections , t t Measured Vertical TVD Dogleg Build Turn ' k Depth Inclination Azimuth Depth System +N/-S +El-W» »Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°1100usft) (°/100usft) (°) 18.00 0.00 0.00 18.00 -63.63 0.00 0.00 0.00 0.00 0.00 0.00 600.00 0.00 0.00 600.00 518.37 0.00 0.00 0.00 0.00 0.00 0.00 813.33 6.40 240.00 812.89 731.26 -5.95 -10.31 3.00 3.00 0.00 240.00 3,738.33 6.40 240.00 3,719.66 3,638.03 -168.97 -292.67 0.00 0.00 0.00 0.00 3,990.33 9.35 186.42 3,969.56 3,887.93 -196.39 -307.15 3.00 1.17 -21.26 -96.15 4,226.22 9.50 157.33 4,202.39 4,120.76 -233.43 -301.78 2.00 0.06 -12.33 -102.61 5,941.03 9.50 157.33 5,893.67 5,812.04 -494.68 -192.65 0.00 0.00 0.00 0.00 5,966.25 9.00 157.12 5,918.56 5,836.93 -498.42 -191.08 2.00 -2.00 -0.83 -176.29 8,966.25 9.00 157.12 8,881.63 8,800.00 -930.79 -8.61 0.00 0.00 0.00 0.00 9,421.86 9.00 157.12 9,331.63 9,250.00 -996.46 19.10 0.00 0.00 0.00 0.00 9,571.86 9.00 157.12 9,479.78 9,398.15 -1,018.08 28.22 0.00 0.00 0.00 0.00 3/13/2017 5:10:33PM Page 2 COMPASS 5000.1 Build 81 III Halliburton HALLI B U RTO N Standard Proposal Report __ .: �.�.sa„,. .,, rsw*f....�r �*..: aw,..,ks� €€� .��.r.u:,s _ .- A "� a t*^s��»mss,... ^�s�U�# Database: _ Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: 4-4 ,41.1 Well Plan KU 11-07X Company: Hilcorp Alaska,LLC TVD Reference: 4 "a KBU 11-07X As-Built @ 81.63usft(Saxon 169) Project: Kenai Gas Field MD Reference: '1'''' ''.1'. KBU 11-07X As-Built @ 81.63usft(Saxon 169) Site: 'i KGF 14-6 Pad North Reference: '. True Well: ,+ Plan KU 11-07X Survey Calculation Method: Minimum Curvature Wellbore: KU 11-07X Design: KU 11-07X WP09 .44:4! ' 4E44 4 AIWA-4 44:4444-74-::44-44-W4-1441SFMW44,tkAM44-44'444444Tdl.S4AWIMMZ'MgV44,'*4,44144, Planned Survey ,` x Measured 4' Vertical lVfM' 4 i Map Map Depth Inclination Azimuth Depth TVDss .F` +N/-S +E/-W Northing , i, Easting DLS Vert Section (usft) (°) (*) (usft) usft (usft) (usft) (usft) (usft) -63.63 18.00 0.00 0.00 18.00 -63.63 0.00 0.00 2,362,258.42 271,914.47 0.00 0.00 100.00 0.00 0.00 100.00 18.37 0.00 0.00 2,362258.42 271,914.47 0.00 0.00 ' 200.00 0.00 0.00 200.00 118.37 0.00 0.00 2,362,258.42 271,914.47 0.00 0.00 300.00 0.00 0.00 300.00 218.37 0.00 0.00 2,362,258.42 271,914.47 0.00 0.00 ' 400.00 0.00 0.00 400.00 318.37 0.00 0.00 2,362,258.42 271,914.47 0.00 0.00 500.00 0.00 0.00 500.00 418.37 0.00 0.00 2,362,258.42 271,914.47 0.00 0.00 I 600.00 0.00 0.00 600.00 518.37 0.00 0.00 2,362,258.42 271,914.47 0.00 0.00 Start Dir 3°/100':600'MD,600'TVD 700.00 3.00 240.00 699.95 618.32 -1.31 -2.27 2,362,257.16 271,912.18 3.00 1.33 800.00 6.00 240.00 799.63 718.00 -5.23 -9.06 2,362,253.36 271,905.31 3.00 5.31 813.33 6.40 240.00 812.89 731.26 -5.95 -10.31 2,362,252.67 271,904.05 3.00 6.05 End Dir :813.33'MD,812.89'TVD 900.00 6.40 240.00 899.02 817.39 -10.78 -18.67 2,362,248.00 271,895.59 0.00 10.95 1,000.00 6.40 240.00 998.39 916.76 -16.35 -28.33 2,362,242.61 271,885.83 0.00 16.62 1,100.00 6.40 240.00 1,097.77 1,016.14 -21.93 -37.98 2,362,237.23 271,876.08 0.00 22.28 1,200.00 6.40 240.00 1,197.15 1,115.52 -27.50 -47.63 2,362,231.84 271,866.32 0.00 27.94 1,300.00 6.40 240.00 1,296.52 1,214.89 -33.08 -57.29 2,362,226.45 271,856.56 0.00 33.60 1,400.00 6.40 240.00 1,395.90 1,314.27 -38.65 -66.94 2,362,221.06 271,846.80 0.00 39.27 1,500.00 6.40 240.00 1,495.28 1,413.65 -44.22 -76.60 2,362,215.68 271,837.04 0.00 44.93 9 5/8"x 12 1/4" 1,600.00 6.40 240.00 1,594.65 1,513.02 -49.80 -86.25 2,362,210.29 271,827.29 0.00 50.59 1,700.00 6.40 240.00 1,694.03 1,612.40 -55.37 -95.90 2,362,204.90 271,817.53 0.00 56.25 1,800.00 6.40 240.00 1,793.41 1,711.78 -60.94 -105.56 2,362,199.52 271,807.77 0.00 61.92 1,900.00 6.40 240.00 1,892.78 1,811.15 -66.52 -115.21 2,362,194.13 271,798.01 0.00 67.58 2,000.00 6.40 240.00 1,992.16 1,910.53 -72.09 -124.86 2,362,188.74 271,788.25 0.00 73.24 2,100.00 6.40 240.00 2,091.54 2,009.91 -77.66 -134.52 2,362,183.36 271,778.49 0.00 78.90 2,200.00 6.40 240.00 2,190.91 2,109.28 -83.24 -144.17 2,362,177.97 271,768.74 0.00 84.57 2,300.00 6.40 240.00 2,290.29 2,208.66 -88.81 -153.82 2,362,172.58 271,758.98 0.00 90.23 2,400.00 6.40 240.00 2,389.67 2,308.04 -94.38 -163.48 2,362,167.19 271,749.22 0.00 95.89 2,500.00 6.40 240.00 2,489.05 2,407.42 -99.96 -173.13 2,362,161.81 271,739.46 0.00 101.55 2,600.00 6.40 240.00 2,588.42 2,506.79 -105.53 -182.78 2,362,156.42 271,729.70 0.00 107.22 2,700.00 6.40 240.00 2,687.80 2,606.17 -111.10 -192.44 2,362,151.03 271,719.94 0.00 112.88 2,800.00 6.40 240.00 2,787.18 2,705.55 -116.68 -202.09 2,362,145.65 271,710.19 0.00 118.54 2,900.00 6.40 240.00 2,886.55 2,804.92 -122.25 -211.74 2,362,140.26 271,700.43 0.00 124.21 3,000.00 6.40 240.00 2,985.93 2,904.30 -127.82 -221.40 2,362,134.87 271,690.67 0.00 129.87 3,100.00 6.40 240.00 3,085.31 3,003.68 -133.40 -231.05 2,362,129.49 271,680.91 0.00 135.53 3,200.00 6.40 240.00 3,184.68 3,103.05 -138.97 -240.70 2,362,124.10 271,671.15 0.00 141.19 3,300.00 6.40 240.00 3,284.06 3,202.43 -144.54 -250.36 2,362,118.71 271,661.40 0.00 146.86 3,400.00 6.40 240.00 3,383.44 3,301.81 -150.12 -260.01 2,362,113.32 271,651.64 0.00 152.52 3,500.00 6.40 240.00 3,482.81 3,401.18 -155.69 -269.66 2,362,107.94 271,641.88 0.00 158.18 3,600.00 6.40 240.00 3,582.19 3,500.56 -161.26 -279.32 2,362,102.55 271,632.12 0.00 163.84 3,654.78 6.40 240.00 3,636.63 3,555.00 -164.32 -284.61 2,362,099.60 271,626.77 0.00 166.95 Sterling A-10 3,700.00 6.40 240.00 3,681.57 3,599.94 -166.84 -288.97 2,362,097.16 271,622.36 0.00 169.51 3/13/2017 5:10:33PM Page 3 COMPASS 5000.1 Build 81 0 • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan KU 11-07X Company: Hilcorp Alaska,LLC TVD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Project: Kenai Gas Field MD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Site • KGF 14-6 Pad North Reference: ;-1 True . . Well: 'Plan KU 11-07X Survey Calculation Method: :,(-1 Minimum Curvature Wellbore$. - KU 11-07X Design: KU 11-07X WP09 Planned Survey x I Measured Vertical 'P1 ,'- Map Map =- $$$- Depth Inclination Azimuth Depth TVDss +NIS +E/-W Northing ; Easting DLS Vert Section (usft) (°) (°) (usft) usft ., (usft) (usft) (usft) (usft) P 3,602.00 .<- 3,702.08 6.40 240.00 3,683.63 3,602.00 -166.95 -289.17 2,362,097.05 271,622.16 0.00 169.62 Sterling A-11 3,738.33 6.40 240.00 3,719.66 3,638.03 -168.97 -292.67 2,362,095.10 271,618.62 0.00 171.68 Start Dir 3°/100':3738.33'MD,3719.66'TVD 3,790.63 6.42 225.92 3,771.63 3,690.00 -172.47 -297.30 2,362,091.70 271,613.93 3.00 175.21 Sterling B-1 3,800.00 6.47 223.44 3,780.94 3,699.31 -173.22 -298.04 2,362,090.96 271,613.18 3.00 175.97 3,900.00 7.60 200.53 3,880.21 3,798.58 -183.50 -304.23 2,362,080.80 271,606.79 3.00 186.31 3,990.33 9.35 186.42 3,969.56 3,887.93 -196.39 -307.15 2,362,067.97 271,603.63 3.00 199.22 Start Dir 2°/100':4738.33'MD,4671.77VD 4,000.00 9.31 185.25 3,979.10 3,897.47 -197.95 -307.30 2,362,066.41 271,603.44 2.00 200.79 4,100.00 9.13 172.80 4,077.82 3,996.19 -213.88 -307.05 2,362,050.48 271,603.38 2.00 216.71 4,200.00 9.37 160.42 4,176.53 4,094.90 -229.42 -303.33 2,362,034.87 271,606.81 2.00 232.22 4,226.22 9.50 157.33 4,202.39 4,120.76 -233.43 -301.78 2,362,030.83 271,608.28 2.00 236.21 End Dir :6062.18'MD,5928.48'TVD 4,300.00 9.50 157.33 4,275.16 4,193.53 -244.67 -297.08 2,362,019.50 271,612.76 0.00 247.41 4,400.00 9.50 157.33 4,373.79 4,292.16 -259.90 -290.72 2,362,004.15 271,618.83 0.00 262.58 4,468.79 9.50 157.33 4,441.63 4,360.00 -270.38 -286.34 2,361,993.59 271,623.00 0.00 273.02 Sterling Pool 6 4,500.00 9.50 157.33 4,472.42 4,390.79 -275.14 -284.36 2,361,988.80 271,624.90 0.00 277.76 4,600.00 9.50 157.33 4,571.04 4,489.41 -290.37 -277.99 2,361,973.44 271,630.97 0.00 292.93 4,700.00 9.50 157.33 4,669.67 4,588.04 -305.61 -271.63 2,361,958.09 271,637.04 0.00 308.11 4,727.33 9.50 157.33 4,696.63 4,615.00 -309.77 -269.89 2,361,953.89 271,638.70 0.00 312.26 Upper Beluga 4,800.00 9.50 157.33 4,768.30 4,686.67 -320.84 -265.26 2,361,942.74 271,643.11 0.00 323.29 4,900.00 9.50 157.33 4,866.93 4,785.30 -336.08 -258.90 2,361,927.38 271,649.18 0.00 338.46 5,000.00 9.50 157.33 4,965.55 4,883.92 -351.31 -252.54 2,361,912.03 271,655.25 0.00 353.64 5,100.00 9.50 157.33 5,064.18 4,982.55 -366.55 -246.17 2,361,896.68 271,661.32 0.00 368.81 5,200.00 9.50 157.33 5,162.81 5,081.18 -381.78 -239.81 2,361,881.32 271,667.39 0.00 383.99 5,300.00 9.50 157.33 5,261.44 5,179.81 -397.02 -233.44 2,361,865.97 271,673.46 0.00 399.16 5,400.00 9.50 157.33 5,360.06 5,278.43 -412.25 -227.08 2,361,850.62 271,679.53 0.00 414.34 5,500.00 9.50 157.33 5,458.69 5,377.06 -427.49 -220.72 2,361,835.26 271,685.60 0.00 429.51 5,600.00 9.50 157.33 5,557.32 5,475.69 -442.72 -214.35 2,361,819.91 271,691.67 0.00 444.69 5,700.00 9.50 157.33 5,655.95 5,574.32 -457.96 -207.99 2,361,804.56 271,697.74 0.00 459.86 5,800.00 9.50 157.33 5,754.58 5,672.95 -473.19 -201.62 2,361,789.20 271,703.81 0.00 475.04 5,900.00 9.50 157.33 5,853.20 5,771.57 -488.43 -195.26 2,361,773.85 271,709.88 0.00 490.21 5,941.03 9.50 157.33 5,893.67 5,812.04 -494.68 -192.65 2,361,767.55 271,712.37 0.00 496.44 Start Dir 2°/100':8847.51'MD,8708.74'TVD 5,966.25 9.00 157.12 5,918.56 5,836.93 -498.41 -191.08 2,361,763.78 271,713.87 2.00 500.16 End Dir :9020.51'MD,8881.63'TVD 6,000.00 9.00 157.12 5,951.90 5,870.27 -503.28 -189.03 2,361,758.88 271,715.83 0.00 505.01 6,100.00 9.00 157.12 6,050.67 5,969.04 -517.69 -182.94 2,361,744.35 271,721.63 0.00 519.36 7"x 8 3/4" 6,115.15 9.00 157.12 6,065.63 5,984.00 -519.88 -182.02 2,361,742.15 271,722.51 0.00 521.54 Lower Beluga 3/13/2017 5:10:33PM Page 4 COMPASS 5000.1 Build 81 I . Halliburton HALLIBURTON Standard Proposal Report Database: I Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan KU 11-07X Company: Hilcorp Alaska,LLC TVD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Project: :Kenai Gas Field MD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Site: KGF 14-6 Pad North Reference: True Well: Plan KU 11-07X Survey Calculation Method: Minimum Curvature Wellbore: KU 11-07Xa Design: KU 11-07X WP09 .».». .,., - I»,.�.�. iti..t.�.. . .,.454 _gym<.,.<-,,I*Zrf#Z.?:z�,,,, __ >. Planned Survey ,. . l MaM Measured x 1 � an ;'Vertical : gx•Depth Inclination Azimuth Depth TVDss +N/S - +E/-W Northing Easting .., DLS Vert Section (usft) (°) n (usft) usft (usft) (usft) (usft) (usft) 6,067.80 6,200.00 9.00 157.12 6,149.43 6,067.80 -532.10 -176.86 2,361,729.83 271,727.44 0.00 533.72 6,300.00 9.00 157.12 6,248.20 6,166.57 -546.52 -170.78 2,361,715.30 271,733.24 0.00 548.07 6,400.00 9.00 157.12 6,346.97 6,265.34 -560.93 -164.70 2,361,700.78 271,739.05 0.00 562.43 6,500.00 9.00 157.12 6,445.74 6,364.11 -575.34 -158.62 2,361,686.25 271,744.85 0.00 576.79 6,600.00 9.00 157.12 6,544.51 6,462.88 -589.76 -152.53 2,361,671.72 271,750.66 0.00 591.14 6,700.00 9.00 157.12 6,643.28 6,561.65 -604.17 -146.45 2,361,657.20 271,756.46 0.00 605.50 6,800.00 9.00 157.12 6,742.05 6,660.42 -618.58 -140.37 2,361,642.67 271,762.26 0.00 619.85 6,900.00 9.00 157.12 6,840.82 6,759.19 -632.99 -134.29 2,361,628.15 271,768.07 0.00 634.21 7,000.00 9.00 157.12 6,939.58 6,857.95 -647.41 -128.20 2,361,613.62 271,773.87 0.00 648.56 7,100.00 9.00 157.12 7,038.35 6,956.72 -661.82 -122.12 2,361,599.09 271,779.68 0.00 662.92 7,200.00 9.00 157.12 7,137.12 7,055.49 -676.23 -116.04 2,361,584.57 271,785.48 0.00 677.28 7,300.00 9.00 157.12 7,235.89 7,154.26 -690.64 -109.96 2,361,570.04 271,791.29 0.00 691.63 7,400.00 9.00 157.12 7,334.66 7,253.03 -705.06 -103.88 2,361,555.52 271,797.09 0.00 705.99 7,468.82 9.00 157.12 7,402.63 7,321.00 -714.97 -99.69 2,361,545.52 271,801.08 0.00 715.87 Tyonek 1B 7,500.00 9.00 157.12 7,433.43 7,351.80 -719.47 -97.79 2,361,540.99 271,802.89 0.00 720.34 7,600.00 9.00 157.12 7,532.20 7,450.57 -733.88 -91.71 2,361,526.46 271,808.70 0.00 734.70 7,700.00 9.00 157.12 7,630.97 7,549.34 -748.29 -85.63 2,361,511.94 271,814.50 0.00 749.05 7,800.00 9.00 157.12 7,729.74 7,648.11 -762.71 -79.55 2,361,497.41 271,820.31 0.00 763.41 7,900.00 9.00 157.12 7,828.50 7,746.87 -777.12 -73.46 2,361,482.88 271,826.11 0.00 777.77 8,000.00 9.00 157.12 7,927.27 7,845.64 -791.53 -67.38 2,361,468.36 271,831.92 0.00 792.12 8,100.00 9.00 157.12 8,026.04 7,944.41 -805.94 -61.30 2,361,453.83 271,837.72 0.00 806.48 8,200.00 9.00 157.12 8,124.81 8,043.18 -820.36 -55.22 2,361,439.31 271,843.52 0.00 820.83 8,300.00 9.00 157.12 8,223.58 8,141.95 -834.77 -49.14 2,361,424.78 271,849.33 0.00 835.19 8,400.00 9.00 157.12 8,322.35 8,240.72 -849.18 -43.05 2,361,410.25 271,855.13 0.00 849.54 8,500.00 9.00 157.12 8,421.12 8,339.49 -863.60 -36.97 2,361,395.73 271,860.94 0.00 863.90 8,600.00 9.00 157.12 8,519.89 8,438.26 -878.01 -30.89 2,361,381.20 271,866.74 0.00 878.26 8,700.00 9.00 157.12 8,618.65 8,537.02 -892.42 -24.81 2,361,366.68 271,872.55 0.00 892.61 8,800.00 9.00 157.12 8,717.42 8,635.79 -906.83 -18.73 2,361,352.15 271,878.35 0.00 906.97 8,900.00 9.00 157.12 8,816.19 8,734.56 -921.25 -12.64 2,361,337.62 271,884.15 0.00 921.32 8,964.23 9.00 157.12 8,879.63 8,798.00 -930.50 -8.74 2,361,328.29 271,887.88 0.00 930.54 Tyonek D2 8,966.25 9.00 157.12 8,881.63 8,800.00 -930.79 -8.61 2,361,328.00 271,888.00 0.00 930.83 9,000.00 9.00 157.12 8,914.96 8,833.33 -935.66 -6.56 2,361,323.10 271,889.96 0.00 935.68 9,100.00 9.00 157.12 9,013.73 8,932.10 -950.07 -0.48 2,361,308.57 271,895.76 0.00 950.03 9,200.00 9.00 157.12 9,112.50 9,030.87 -964.48 5.60 2,361,294.05 271,901.57 0.00 964.39 9,272.02 9.00 157.12 9,183.63 9,102.00 -974.86 9.98 2,361,283.58 271,905.75 0.00 974.73 Tyonek D3B 9,300.00 9.00 157.12 9,211.27 9,129.64 -978.90 11.69 2,361,279.52 271,907.37 0.00 978.75 9,400.00 9.00 157.12 9,310.04 9,228.41 -993.31 17.77 2,361,264.99 271,913.18 0.00 993.10 9,421.86 9.00 157.12 9,331.63 9,250.00 -996.46 19.10 2,361,261.82 271,914.44 0.00 996.24 9,439.07 9.00 157.12 9,348.63 9,267.00 -998.94 20.14 2,361,259.32 271,915.44 0.00 998.71 Tyonek D4A 9,500.00 9.00 157.12 9,408.81 9,327.18 -1,007.72 23.85 2,361,250.47 271,918.98 0.00 1,007.46 3/13/2017 5:10:33PM Page 5 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTONI Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: .= Well Plan KU 11-07X Company Hilcorp Alaska,LLC TVD Reference: , KBU 11-07X As-Built @ 81.63usft(Saxon 169) Project: ,, Kenai Gas FieldMD Reference KBU 11-07X As-Built @ 81.63usft(Saxon 169) Site: ,n= ` KGF 14-6 Pad North Reference: True Well: Plan KU 11-07X Survey Calculation Method: ; Minimum Curvature Wellbore' KU 11-07X '" ' @ WWII- Design: KU 11-07X WP09 Planned Survey .�� .- , r,,- »t e ». - Measured #ttti-424" , a �),, Vertical r , �)fki I a)' Map Map „ Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing : y,', Easting DLS , iVertSection (usft) (°) (°) (usft) usft (usft) (usft) (usft) _„ (usft) 9,398.15 '" 9,571.86 - 9.00 157.12 9,479.78 • 9,398.15 -1,018.08 28.22 2,361,240.03 • 271,923.15 • 0.00 1,017.77 Total Depth:9571.86'MD,9479.78'TVD-4 1/2"x 6 1/8" Targets I ti- ` ' I-1.44,, 4-,cam s� ) s u • x ' ' ' ; ,04- - Target Name `;'--'7-'-':' -hit/miss target mss.,: Dip Angle Dip Dir. TVD ' +N/-S +E/-W Northing Easting -Shape �E ,x 4 ,-� ..... O it (°) (usft) f. (usft) (usft) (usft) 1 ,$_,' (usft) KBU 11-07X TY D2 0.00 0.00 8,881.63 -930.79 -8.61 2,361,328.00 271,888.00 -plan hits target center -Circle(radius 100.00) STA11 0.00 0.00 3,691.63 -172.08 -293.23 2,362,092.00 271,618.00 -plan misses target center by 5.69usft at 3710.70usft MD(3692.20 TVD,-167.43 N,-290.01 E) -Circle(radius 50.00) KBU11-07X TY D4 0.00 0.00 9,331.63 -930.79 -8.61 2,361,328.00 271,888.00 -plan misses target center by 70.40usft at 9410.71 usft MD(9320.62 TVD,-994.85 N,18.42 E) -Circle(radius 100.00) Casing Points ate si `�?-" ` Measured Vertical ‘ *i e eCasing Hole '- -....$4,-., Depth Depth c,, 4 014„4,,,,,t,• ° Diameter er Diameter ,,,», t r. b.... (usft) (usft) ( 1 .1 �.'N ..a x ( ) »x», (.) A . , 1,500.00 1,495.28 95/8"x121/4" 9-5/8 12-1/4 6,100.00 6,050.67 7”x 8 3/4" 7 8-3/4 9,571.86 9,479.78 4 1/2"x 6 1/8" 4-1/2 6-1/8 Formations mak'.We, r:q , Measured Vertical Vertical 't c'14`" Dip Depth Depth Depth SS 1 ; Dip Direction (usft) (usft) ' ¢ 1N ' a 'e, ,y,, Lithology () () -1r w, , _ ,,. 0,0 „ , ,..,.,,� _, .4 9,272.02 9,183.63 Tyonek D3B 6,115.15 6,065.63 Lower Beluga 7,468.82 7,402.63 Tyonek 1B 3,654.78 3,636.63 Sterling A-10 4,468.79 4,441.63 Sterling Pool 6 4,727.33 4,696.63 Upper Beluga 9,439.07 9,348.63 Tyonek D4A 3,702.08 3,683.63 Sterling A-11 3,790.63 3,771.63 Sterling B-1 8,964.23 8,879.63 Tyonek D2 3/13/2017 5:10:33PM Page 6 COMPASS 5000.1 Build 81 0 ! Halliburton I-IALLIBURTON Standard Proposal Report Database: °;Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: "°Well Plan KU 11-07X Company: . ,Hilcorp Alaska,LLC TVD Reference: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Project: Kenai Gas Field MD Reference: ;:KBU 11-07X As-Built @ 81.63usft(Saxon 169) y Site KGF 14-6 Pad North Reference: #k. True • Well: '-Plan KU 11-07X Survey Calculation Method: t° Minimum Curvature Wellbore: KU 11-07X "' t 5111 Design: KU 11-07X WP09 s.Zus:w?: .a..., —, *We, ,/,'—‘?k,:.,. ;''=',:k...':=,,',;:,, »:.:t, "*a'+ ,,, .:' ;ra... '"^SS:.,": ,..ctt:�„ asr,s-ars,:a �.M...x: x Plan Annotations Measured Vertical Local Coordinates ,1 a, Depth Depth . +N/-S +E/-W G (usft) (usft) I (usft) (usft) E.` Comment It x 600.00 600.00 0.00 0.00 Start Dir 3°/100':600'MD,600'TVD 813.33 812.89 -5.95 -10.31 End Dir :813.33'MD,812.89'TVD 3,738.33 3,719.66 -168.97 -292.67 Start Dir 3°/100':3738.33'MD,3719.66'TVD 3,990.33 3,969.56 -196.39 -307.15 Start Dir 2°/100':4738.33'MD,4671.7'TVD 4,226.22 4,202.39 -233.43 -301.78 End Dir :6062.18'MD,5928.48'ND 5,941.03 5,893.67 -494.68 -192.65 Start Dir 2°/100':8847.51'MD,8708.74'TVD 5,966.25 5,918.56 -498.41 -191.08 End Dir :9020.51'MD,8881.63'ND 9,571.86 9,479.78 -1,018.08 28.22 Total Depth:9571.86'MD,9479.78'TVD 3/13/2017 5.10.33PM Page 7 COMPASS 5000.1 Build 81 I • Hilcorp Alaska, LLC Kenai Gas Field KGF 14-6 Pad Plan KU 11-07X KU 11-07X KU 11-07X WP09 Sperry Drilling Services Clearance Summary Anticollision Report 13 March,2017 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: KGF 14-6 Pad-Plan KU 11-07X-KU 11-07X-KU 11-07X WP09 Well Coordinates: 2,362,258.42 N,271,914.47 E(60°27'36.12"N,151°15'48.96"W) Datum Height: KBU 11-07X As-Built @ 81.63usft(Saxon 169) Scan Range: 0.00 to 9,572.42 usft.Measured Depth. Scan Radius is 1,155.44 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version:5000.1 Build:81 Scan Type: GLOBAL FILTER APPLIED:All welipaths within 200'+100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services • 0 Hilcorp Alaska,LLC HALL I B U RTO N Kenai Gas Field Anticollision Report for Plan KU 11-07X-KU 11-07X WP09 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: KGF 14-6 Pad-Plan KU 11-07X-KU 11-07X-KU 11-07X WP09 Scan Range: 0.00 to 9,572.42 usft.Measured Depth. Scan Radius is 1,155.44 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 KGF 14-6 Pad KBU 11-07-KBU 11-07-KBU 11-07 1,671.44 176.80 1,671.44 166.37 1,728.88 16.952 Centre Distance Pass- KBU 11-07-KBU 11-07-KBU 11-07 1,675.00 176.80 1,675.00 166.34 1,732.24 16.897 Ellipse Separation Pass- KBU 11-07-KBU 11-07-KBU 11-07 7,750.00 560.76 7,750.00 522.42 7,900.00 14.626 Clearance Factor Pass- KBU 14-06Y-KBU 14-06Y-KBU 14-06Y 18.00 306.45 18.00 305.11 23.36 227.637 Centre Distance Pass- KBU 14-06Y-KBU 14-06Y-KBU 14-06Y 500.00 307.86 500.00 304.86 504.00 102.516 Ellipse Separation Pass- KBU 14-06Y-KBU 14-06Y-KBU 14-06Y 7,650.00 755.58 7,650.00 723.27 7,600.00 23.386 Clearance Factor Pass- KBU 23-07-KBU 23-07-KBU 23-07 18.00 154.23 18.00 152.89 23.35 114.557 Centre Distance Pass- KBU 23-07-KBU 23-07-KBU 23-07 50.00 154.27 50.00 152.85 55.04 108.800 Ellipse Separation Pass- KBU 23-07-KBU 23-07-KBU 23-07 2,575.00 396.84 2,575.00 384.85 2,542.81 33.092 Clearance Factor Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 608.85 217.60 608.85 211.25 621.84 34.267 Centre Distance Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 625.00 217.67 625.00 211.17 637.99 33.485 Ellipse Separation Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 1,500.00 310.93 1,500.00 296.68 1,489.49 21.829 Clearance Factor Pass- KBU 24-06-KBU 24-06-KBU 24-06 644.54 273.11 644.54 269.65 656.30 78.926 Centre Distance Pass- KBU 24-06-KBU 24-06-KBU 24-06 650.00 273.11 650.00 269.63 661.82 78.395 Ellipse Separation Pass- KBU 24-06-KBU 24-06-KBU 24-06 1,500.00 344.20 1,500.00 337.10 1,498.50 48.437 Clearance Factor Pass- KBU 24-06-KBU 24-06RD-KBU 24-06RD 644.54 273.11 644.54 270.06 656.30 89.577 Centre Distance Pass- KBU 24-06-KBU 24-06RD-KBU 24-06RD 650.00 273.11 650.00 270.04 661.82 88.893 Ellipse Separation Pass- KBU 24-06-KBU 24-06RD-KBU 24-06RD 1,500.00 344.20 1,500.00 337.51 1,498.50 51.414 Clearance Factor Pass- KDU 1-KDU 1-KDU 1 600.00 218.92 600.00 195.04 608.37 9.170 Centre Distance Pass- KDU 1-KDU 1-KDU 1 1,225.00 234.05 1,225.00 183.80 1,230.36 4.657 Ellipse Separation Pass- KDU 1-KDU 1-KDU 1 3,825.00 436.58 3,825.00 279.03 3,814.15 2.771 Clearance Factor Pass- KDU 1-KDU 1 PB1-KDU 1 PB1 600.00 218.92 600.00 194.78 608.37 9.069 Centre Distance Pass- KDU 1-KDU 1 PB1-KDU 1 PB1 1,200.00 233.02 1,200.00 183.56 1,205.52 4.711 Ellipse Separation Pass- KDU 1-KDU 1 PB1-KDU 1 PB1 3,825.00 436.58 3,825.00 278.92 3,814.15 2.769 Clearance Factor Pass- KU 14-6-KU 14-06RD-KU 14-06RD 797.51 60.62 797.51 34.49 802.54 2.320 Centre Distance Pass- KU 14-6-KU 14-06RD-KU 14-06RD 5,375.00 493.75 5,375.00 27.71 5,340.90 1.059 Clearance Factor Pass- KU 14-6-KU 14-6-KU 14-6 797.51 60.62 797.51 34.49 802.54 2.320 Centre Distance Pass- KU 14-6-KU 14-6-KU 14-6 1,000.00 64.82 1,000.00 32.14 1,004.13 1.984 Ellipse Separation Pass- 13 March,2017-17:30 Page 2 of 6 COMPASS I • Hilcorp Alaska,LLC HALLIBURTON Kenai Gas Field Anticollision Report for Plan KU 11-07X-KU 11-07X WP09 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: KGF 14-6 Pad-Plan KU 11-07X-KU 11-07X-KU 11-07X WP09 Scan Range: 0.00 to 9,572.42 usft.Measured Depth. Scan Radius is 1,155.44 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 KU 14-6-KU 14-6-KU 14-6 1,150.00 72.21 1,150.00 34.70 1,152.85 1.925 Clearance Factor Pass- KU 14X-6-KU 14X-6(KDU 8)-KU 14X-6 605.96 258.83 605.96 252.64 612.06 41.815 Centre Distance Pass- KU 14X-6-KU 14X-6(KDU 8)-KU 14X-6 625.00 258.91 625.00 252.55 631.16 40.676 Ellipse Separation Pass- KU 14X-6-KU 14X-6(KDU 8)-KU 14X-6 7,600.00 964.61 7,600.00 882.58 7,494.23 11.760 Clearance Factor Pass- KU 21-7-KU 21-7-KU 21-7 752.75 150.77 752.75 143.62 763.88 21.112 Centre Distance Pass- KU 21-7-KU 21-7-KU 21-7 775.00 150.89 775.00 143.56 785.77 20.588 Ellipse Separation Pass- KU 21-7-KU 21-7-KU 21-7 1,475.00 227.13 1,475.00 211.56 1,466.44 14.586 Clearance Factor Pass- KU 21-7-KU 21-7 PB1-KU 21-7PB 618.50 137.95 618.50 129.96 627.67 17.276 Centre Distance Pass- KU 21-7-KU 21-7 PB1-KU 21-7PB 650.00 138.32 650.00 129.88 658.47 16.383 Ellipse Separation Pass- KU 21-7-KU 21-7 PB1-KU 21-7PB 875.00 164.65 875.00 152.95 874.66 14.067 Clearance Factor Pass- KU 43-12-KU 43-12-KU 43-12 18.00 44.16 18.00 43.08 26.35 40.745 Centre Distance Pass- KU 43-12-KU 43-12-KU 43-12 50.00 44.28 50.00 42.94 58.08 33.204 Ellipse Separation Pass- KU 43-12-KU 43-12-KU 43-12 500.00 73.43 500.00 67.62 498.31 12.643 Clearance Factor Pass- KGF 41-7 Pad KTU 32-07H-KTU 32-7H-KTU 32-7H 8,875.00 1,080.58 8,875.00 984.15 11,857.00 11.206 Clearance Factor Pass- KTU 32-07H-KTU 32-7H-KTU 32-7H 8,950.00 1,076.45 8,950.00 980.65 11,857.00 11.236 Ellipse Separation Pass- KTU 32-071-1-KTU 32-7H-KTU 32-7H 8,971.80 1,076.23 8,971.80 980.67 11,857.00 11.262 Centre Distance Pass- Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 18.00 1,500.00 KU 11-07X WP09 MWD+SC+sag 1,500.00 6,100.00 KU 11-07X WP09 MWD+SC+sag 6,100.00 9,571.86 KU 11-07X WP09 MWD+SC+sag 13 March,2017- 17:30 Page 3 of 6 COMPASS • • Hilcorp Alaska,LLC HALLIBURTON Kenai Gas Field Anticollision Report for Plan KU 11-07X-KU 11-07X WP09 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. 13 March.2017- 17:30 Page 4 of 6 COMPASS • • HALLIBURTON Project: Kenai Gas Field REFERENCE INFORMATION WELL DETAILS:PImnKU11-07X NAD 1927(NADCONCONUS) Alaska Zone 64 Site: KGF 14-6 Pad Co-ouinete(N/E)Reference Well Pon KU 11-07X True North Ground Level: 63.63 Vertical(ND)Reference'.KBU 11-07X As-Built @ 81.63usrt(Saxon 169) -INAS +E-W Northing _;,,,.,-,-,,�,.;Ih r, Well: Plan KU 11-07X Measured Depth Reference KBU 11-07XAs- Fasting19143 7a�e Longitude pt As-Built a1.63aart(Saxon 1B8) 0.00 0.00 2362258.42 271914.7 60.27 36.116N 151"15'48.963W Wellbore: KU 11-07X Calculation Method:Minimum Curvature Plan: KU 11-07X WP09 SURVEY PROGRAM GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference L7_IC,O�a 18.00 To 9572.42 11 11!1..11 Date:2016-05-13T00:00:00 Validated'.Yes Version: I Ladder/S.F. Plots CASING DETAILS Depth From Depth To Survey/Plan Tool 18.00 1500.00 KU 11-07X WP09 MWD+SC+sag 1500.00 6100.00 KU 11-07X WP09 MWD+SC+sag TVD TVDSS MD Size Names 6100.00 9571.86 KU 11-07X WP09 MWD+00+sag 1495.28 1413.65 1500.00 9-5/8 9 5/8"x 12 1/4" 6050.67 5969.04 6100.00 7 7"x 8 3/4" 9479.78 9398.15 9571.86 4-1/2 4 12"x 6 18" 150.00 r ry -_ .�..-- ling KJ 21-7P6 11'1 !1t 1 00120.00 :, ii�lj' 1 ( } c - KU 146- { I I I _ 90.00 , - -rt---- m i. , 16000 KU 14.6 ti_ .._.__- - _ I... o - KU43-12 't t_,t. KU 14-06RD 2 30.00 c Oil. 0.00 1 1 1 1 1 , 1 1 IIII 1 1 1 , 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 I 1 I , I I I I I I I I , 1 1 1 1 1 1 1 I l 1 1 1 1 1 1 1 1 1 1 1 0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 Measured Depth(1100 usft/in) 6.o0 .. 1 1 I I I I 4.50-_ T.; -- _.__r _ .....____ • 11. 4-„.., 3.00 i .._ _.--- ----- _ _....__._ : --- :co - . - Collision Risk Procedures--q. 1.50 1I I Collision Avoidance Req. i i { No-Go Zone-Stop Drillin, 0.00 IIIIIIIIIillll 11 , 1 111111111 111 , 1111 111111111 111111111 111 , , ill 1 , 11 1111 1111 1111 1111 0 550 1100 1650 2200 2750 3300 3850 4400 4950 5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 Measured Depth • • TRANSMITTAL LETTER CHECKLIST WELL NAME: �� 1, i / /1 -0 /7' K PTD: 2- / 70V( Development Service Exploratory Stratigraphic Test Non-Conventional • ia_ FIELD: KeALL , � POOL: .��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 No. , API No. 50- - - - . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. P g P g g Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 0 • CI 0- , , N , 0 N N 7,,, C N' No O 2 O' N o. E, co 0' x, I. 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U ` a s a a a co Lu 0 KU 11-07X 50-133-20662-00-00 Kenai Gas Field Kenai Peninsula Borough, Alaska April 17, 2017 – May 4, 2017 Provided by: Approved by: Jacob Dunston Compiled by: Ralph Winkelman, Paul Webster Distribution Date: May 18, 2017 KU 11-07x 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 ................................................................................................................... 5 3 GEOLOGICAL DATA ............................................................................................................................. 7 3.1 Lithostratigraphy ............................................................................................................................. 7 3.2 Lithology Details ............................................................................................................................. 8 3.3 Sampling Program ........................................................................................................................ 22 4 DRILLING DATA .................................................................................................................................. 23 4.1 Surveys ......................................................................................................................................... 23 4.2 Bit Record ..................................................................................................................................... 28 4.3 Mud Record .................................................................................................................................. 29 4.4. Drilling Progress ........................................................................................................................... 30 5 SHOW REPORTS ............................................................................................................................... 31 6 DAILY REPORTS ................................................................................................................................ 32 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 KU 11-07x 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 Mud Flow In Calculated value derived from Strokes/Minute and Pump Output 0 Mud Flow Out WITS from Pason “ Pit Volumes, Pit Gain/Loss WITS from Pason “ Pump Pressure WITS from Pason “ Pump Stroke Counters (2) WITS from Pason “ Rate of Penetration Calculated from Pason “ RPM WITS from Pason “ Torque WITS from Pason “ WITS To/ From Pason Rigwatch Remote (HP Compaq) 1.2 Crew Mud Logging Unit Type: Arctic Mud Logging Unit Number: ML038 Logging Geologists Years1 Days2 Sample Catchers/Loggers Years Days2 Ralph Winkelman 27 Dylan Muller 7 Joshua Dubowski 9 10 Garnet Knopp 1 12 Paul Webster 37 18 Ashley Wilderom 4 2 *1 Years’ experience as Mudlogger *2 Days at wellsite between rig up and rig down of logging unit. KU 11-07x 3 2 GENERAL WELL DETAILS 2.1 Well Objectives KU 11-07X is a 9,572’MD/ 9,480’TVD Beluga/ Upper Tyonek development well off the 41-07 pad in the Kenai Gas Field. Reservoir analysis and subsurface mapping has identified an undrai ned area of the Kenai Field that will target reserves in the D2, D3B and D4 sands. Secondary targets include the Lower Beluga – Upper Tyonek. The base plan is a directional wellbore with a kickoff point at 600’ MD. Maximum hole angle will be 10 deg. The vertical section will be 1008’. Operator: HILCORP ALASKA, LLC Well Name: KU 11-07X Field: Kenai Gas Field County: Kenai Peninsula Borough State: Alaska Company Representatives: Rance Pederson, Robert Wall , Clint Montague, Adam Dorr Location: Surface Coordinates 203’ FSL, 1003’ FW L, Sec 6, T4N, R11W, SM, AK Ground ( Pad ) Elevation 63.6’ AMSL Rotary Table Elevation 18.0’ RKB – 84.4’ AMSL Classification: Development – Gas API #: 50-133-20662-00-00 Permit #: 217-041 Rig Name/Type: Saxon 169 / Land / Double Spud Date April 18, 2017 Total Depth Date: May 4, 2017 Total Depth 9799’MD/ 9701.80’TVD Primary Targets Tyonek D2 8964’MD/ 8880’TVD, Tyonek D3B 9272’MD/ 9184’TVD, Tyonek D4A 9439’MD/ 9349’TVD Total Depth Formation: Tyonek 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 Schlumberger RFT, Pollard CBL KU 11-07x 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) 13 1/2” 1522’ 1516.92’ Sterling 8.95 5.50 10.75 1511’ 1506’ 12.5 9 7/8” 6100’ 6050’ Middle Beluga 9.15 8.89 7.625 6090’ 6040.5’ 12.5 6 3/4” 9799’ 9701.8’ Tyonek 11.3 11.51 4.5 KU 11-07x 5 2.3 Daily Activity Summary April 18, 2017: Spud 11-07X well at 01:30 hours. Drill from 86’ to 340’. POOH from 340’ to 52’. Make up BHA. RIH from 172’ to 340’. Drill from 340’ to 1522’. Condition mud and circulate. POOH from 1522’ to 270’, free. RIH from 270’ to 1522’, no fill. Circulate and condition mud. POOH. April 19, 2017: Finish POOH. Lay down BHA. Clean rig floor. Pull wear bushing. Rig up casing bails & elevators stage. Pick up spider tongs. Stage shoe track. Function test equipment. Make up shoe track. Run casing from shoe tract to 1511’. Circulate casing. Cement casing (bump plug @ 15:54 hours). Rig down from running casing. Nipple up BOP. April 20, 2017: Finish nipple BOP. Test BOP. Pick up drill pipe. April 21, 2017: Finish picking up drill pipe. Pressure test casing ti 2600 psi for 30 minutes. Make up BHA from bit to 732’. RIH from 732’ to 1356’. Wash/ream from 1356’ to 1419’ (tagged cement at 1419’). Drill out cement/shoe from 1419’ to 1522’ (tagged float at 1426’/tagged shoe at 1510’). Drill from 1522’ to 1542’.Circulate and displace spud mud with 9.0 ppg KCL. Clean shakers and possum belly. Circulate and condition mud for FIT test. Perform FIT test to 12.5 ppg EQMW. Drill from 1542’ to 1772’. April 22, 2017: Drill from 1772’ to 3033’. Pump sweep and circulate hole clean. Wipe hole from 3033’ to 1476’. Service rig. RIH from 1476’ to 3033’ (no fill). Drill from 3033’ to 3718’. April 23, 2017: Drill from 3718’ to 4027’. Pump sweep and circulate hole clean. Wipe hole from 4027’ to 3030’, no tight spots. Service rig. RIH from 3030’ to 4027’, 8’ fill. Drill from 4027’ to 5023’. Pump sweep and circulate hole clean. Wipe hole to 3967’, free. RIH from 3967’ to 5023’ (safety reamed last stand to bottom) with no issues. April 24, 2017: Drill from 5023’ to 6100’ Casing Point. Pump sweep and circulate hole clean. POOH from 6110’ to 723’. Rack back HWDP and collars in derrick. Remove LWD sources. Download LWD. April 25, 2017: Lay down BHA. Lay down Top Drive for repairs. Rig up wireline equipment. Make Dummy Run (stopped at 5963’). Make XPT tools. Run XPT to 5895’ (first stop). April 26, 2017: Continue to run XPT (35 total stations). Lay down XPT tool. Rig up ECS (Gamma/Neutron) tool. RIH with ECS tool to 5910’ and log up. Rig down ECS. Make SWC logging tools. RIH with SWC tools to 5900’. April 27, 2017: SWC to 4800’ (21 cores). Continue coring (27 out of 35 retrieved). Rig down wireline. Reinstall Top Drive. Make up BHA from bit to 103’. RIH with HW DP/JARS to 661’. RIH from 661’ to 3143’ (filling pipe every 25 stands, no tight spots.). RIH from 3143’ to 5938’, tight spot 5919’ (20K slack off). Ream from 5938’ to 6100’. Pump sweep, circulate hole clean. Mad Pass/POOH from 6100’ to 4421’. April 28, 2017: Continue Mad Pass/POOH from 4421’ to 3087’. POOH from 3087’ to 661’. Rack back HWDP, lay down jars and crossovers from 661’ to 103’. Lay down BHA. Change upper pipe rams to 7 5/8”. Shell test BOP. Pressure test 7 5/8” UPR to 250 psi for 5 minutes / 3500 psi for 5 minutes. Rig up to run 7 5/8” casing. Run 7 5/8” casing to 3250’. Circulate and condition mud (Max Gas = 6u). Run 7 5/8” casing from 3250’ to 5845’. KU 11-07x 6 April 29, 2017: Run 7 5/8” casing from 5845’ to 6058’. Wash down to 6089’. Land hanger. Circulate. Pump 40 bbls 10.0 ppg mud push, follow with 134 bbls 12.5 ppg lead, follow with 15.2 ppg 34 bbls tail, drop top plug. Follow with 10 bbls water, displace with 9.2 ppg mud (total pumped for displacement 278 bbls). CIP @ 0630 Hours. Rig down cementers. Drain stack, pull landing joint, wash out stack, make up packer to landing joint, set packer/run in lockdown screws, pack pack off with packing to 7000 psi. Pressure test pack off to 500 psi for 5 minutes / 5000 psi for 15 minutes. Rig down casing bails/elevators and rig up rig bails/elevators. Service rig. Change out upper pipe rams from 7 5/8” to 4 1/2” rams (function test rams). Continue to service rig (cutting and slipping 155 feet of drill line). Prepare for BOP test. Test BOP. April 30, 2017: Finish testing BOP. Pick up and rack back in derrick 30 stands. Rig up Pollard wireline for CBL. Run CBL (tagged cement @ 5932’). Rig down Pollard wireline. Make up BHA from bit to 121’, attempt shallow-hole LWD/MWD (trouble with communication), troubleshoot, finally get shallow-hole test. Make up BHA from 121’ to 552’. Single in drill pipe from 552’ to 1553’. RIH from derrick from 1553’ to 5909’. Circulate and condition. Test casing to 3500 psi for 30 minutes. May 1, 2017: Drill out cement and shoe track. Drill from 6100’ to 6120’, while beginning displacement to 10.0 ppg mud. Circulate and condition mud. FIT test to 12.5 ppg Equivalent Mud Weight. Drill from 6120’ to 7214’. Pump sweep and circulate hole clean. Wipe hole to shoe, encountering tight spots to 6465’, backream from 6465’ to 6156’. CBU while working pipe and backreaming to 6094’. Pull on elevators to 6030’. Service rig. May 2, 2017: RIH from 6030’ to 7214’, washing last stand to bottom (no issues/no fill). Drill from 7214’ to 8459’. Pump high viscosity sweep, circulate and raise MW to 11.0 ppg. Pump out to 8144’, top drive up and backream from 8133’ to 7771’. Circulate high gas (1586u Max from flow check on bottom, 1778u Max from Coal at 8141’).Continue to backream from 7771’ to 7213’. Pull one stand high on elevators to 7151’. Service rig. May 3, 2017: RIH from 7213’ to 8459’, washing/reaming last stand to bottom (3 feet of fill). Drill from 8459’ to 9643’. May 4, 2017: Drill from 9643’ to TD at 9799', Circulate bottoms up. Flow check well, no flow. Pull out to shoe, service rig. TIH to 9799'. Pump sweep, max gas 2175u. Weight up active system. Flow check, no flow, Circulate bottoms up with 14u gas. May 5, 2017: Flow check: gaining 1 barrel per hour. POOH. Rig up wireline equipment and perform dummy run. RIH to TD at 9700' with XPT tools. POOH recording at desired depths; 35 areas total. Sample catchers are released. May 6, 2017: Continue wireline XPT tools gathering remaining 12 stations. POOH w XPT, rig up and run in with HNGS tool to 9700'. Wireline log from 9700 back to 8350' where tools got hung up. Worked free and POOH. Rigged down radioactive sources and wireline logging equipment. Make up clean-out BHA and begin RIH. Circulated bottoms-up at shoe with 2970u max gas. Cut and slip drill line. Continue RIH to 9700. Circulate bottoms-up with 3360u max gas May 7, 2017: Continue washing and reaming to bottom. Pump high viscosity sweep; 50% increased cuttings. Circulate 2 bottoms-up, and increase weight from 11.5 to 11.6 ppg. Flow check well, then begin TOOH 4 stands, but incurred swabbing. Tripped back in hole to bottom, circulated bottoms up, flow checked again, and pumped out of hole to 9159’. Flow checked well: no flow. Continue pumping out of hole to 8588’ due to swabbing. TOOH to shoe on elevators with no issues. Circulated bottoms up with max gas of 21 units. KU 11-07x 7 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) Primary Tyonek D2 8964 8880 -8798 8,984 8,900 -8,818 Tyonek D3B 9272 9184 -9102 9,271 9,183 -9,101 Tyonek D4A 9439 9349 -9267 9,485 9,394 -9,312 Secondary Upper Beluga 4727 4697 -5615 4,716 4,685 -4,603 Lower Beluga 6115 6066 -5984 6,131 6,081 -5,999 Tyonek 1B 7469 7403 -7321 7,469 7,403 -7,321 KU 11-07x 8 3.2 Lithology Details As per Hilcorp direction, a Canrig/NDS-provided full service mudlogging program, with lithology descriptions of interval-collected rock cuttings samples in the Sterling, Beluga and Tyonek Formations, was initiated at the 9 7/8” intermediate interval at 1509’. 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 form ing 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/NDS 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. Sand (1550' - 1585') = dominant translucent, common clear, black, occasional grayish; upper fine to lower medium, dominant lower medium; well to moderately sorted; dominant angular to subangular, common subround, occasional round; dominant quartz, common mafic-rich, occasional feldspar. Tuffaceous Claystone (1595' - 1635') = medium with slight brownish to olive hues; blocky cuttings; slightly firm; easily crumbly; dull luster; finely grainy texture; no evident structure; non calcareous; commonly grading to tuffaceous siltstone and upward to sandstone; occasional associated carbonaceous material. Sand (1645' - 1690') = dominant translucent, common clear, black, occasional grayish; upper fine to lower medium, dominant lower medium; well to moderately sorted; dominant angular to subangular, common subround, occasional round; dominant quartz, common mafic -rich, occasional feldspar; commonly derived from an argillaceous matrix to grain-supported sandstone. Tuffaceous Siltstone (1720' - 1770') = medium gray with common brownish to olive hues; blocky cuttings; dominant slightly to occasionally moderately firm; dominant easily to occasional moderately crumbly; dull luster; finely grainy to slightly arenaceous texture; no evident structure; occasional associated carbonaceous material; fines downward to tuffaceous claystone and upward to sandstone. Sand (1780' - 1825') = dominant clear to translucent, common black, occasional grays; upper fine to lower coarse, dominant medium; moderate to well sorted; dominant angular to subangular, common subround, occasional round; dominant moderate to low, occasional high sphericity; dominant quartz, common mafic-rich/occasional miscellaneous lithics; note probable coal at 1775'. Sandstone (1835' - 1870') = medium to brownish gray; rounded, hydrated cuttings; soft; mushy; upper fine to lower coarse, dominant medium; grains with abundant argillaceous matrix-support; dominant quartz, common mafic-rich lithics, occasional miscellaneous lithics. Tuffaceous Sandstone (1880' - 1905') = very light gray; rounded cuttings; soft; mushy; lower fine to upper medium; well sorted; bentonic ash matrix support; dominant quartz, common mafic-rich, occasionally other lithics. KU 11-07x 9 Siltstone (1915' - 1950') = dominant medium gray to common (chloritized) greenish gray; blocky cuttings; varies bimodally slightly firm/easily crumbly to hard/tough; more indurate grains with some calcite cementing and tend to coarsen upward to sandstone; occasional greenish gray tuffaceous claystones. Sand (1960' - 2005') = dominant clear to translucent, common black, occasional grays; upper very fine to lower coarse, dominant medium; moderate sorting; dominant angular to subangular, common subround, occasional round; dominant moderate, common low, occasional high sphericity; dominant quartz, common mafic-rich lithics, occasional other lithics, trace micas. Carbonaceous Siltstone (2015' - 2055') = moderate brown to brownish gray; slightly firm; easily crumbly; dull luster; grainy to finely grainy texture; consists of organic-rich argillaceous matrix supporting disseminated arenaceous clasts; mostly coarsening upward to sandstone, some fining downward to claystone. Sand (2065' - 2110') = dominant clear to translucent, occasional to common black, grays; upper fine to lower coarse, dominant medium; dominant subangular to angular, common subround, occasional to trace round; dominant moderate, common low, occasional high sphericity; dominant quartz, occasional to common mafic-rich lithics, occasional miscellaneous lithics. Sand (2065' - 2110') = dominant clear to translucent, occasional to common black, grays; upper fine to lower coarse, dominant medium; dominant subangular to angular, common subround, occasional to trace round; dominant moderate, common low, occasional high sphericity; dominant quartz, occasional to common mafic-rich lithics, occasional miscellaneous lithics. Sand (2175 - 2225') = dominant clear to translucent, occasional to common black, occasional grays, greens, orange; upper fine to upper coarse, dominant medium; moderately sorted; dominant angular to subangular, common subround, occasional round; dominant moderate, common low, occasional high sphericity; dominant quartz, occasional to common miscellaneous lithics (including orange which appear to be pyroclastic). Sand (2235' - 2280') = dominant clear to translucent, occasional common black, gray, occasional green, orange; lower fine to upper coarse, dominant medium; moderately sorted; dominant suban gular to angular, common subround, occasional well rounded; dominant quartz, occasional to common mafic -rich and other miscellaneous lithics, continued good trace orange pyroclastic grains. Tuffaceous Siltstone (2290' - 2345') = brownish to medium gray; amorphous cuttings; dominant slight to occasional moderate firm; dominant mushy to easily crumbly, occasional moderate crumbly; dull luster; grainy to finely grainy texture; top of section was organic -rich with carbonaceous siltstone/claystone, becoming less so with depth thereafter; grades to both light to medium gray sandstone and medium gray tuffaceous claystone. Sandstone (2355' - 2410') = dominant brownish gray, occasional medium to light gray; moderately firm to slightly hard; mushy to slightly friable; upper fine to lower coarse, dominant medium; moderately sorted; dominant subangular to subround, common angular, occasional round; overall grain-packed but with copious amounts argillaceous matrix that is dominant organic-rich (brown) with grays devoid of organics; dominant quartz, common lithic grains. Tuffaceous Siltstone (2420' - 2450') = brownish to medium gray; rounded, hydrated cuttings; overall soft and mushy; dull luster; commonly coarsens upward to argillaceous sandstone, fining downward occasionally to medium gray tuffaceous claystone. KU 11-07x 10 Sand (2460' - 2505') = dominant clear to common translucent, common black, gray; lower fine to upper medium, dominant lower medium; moderate to well sorted; dominant subangular to angular, common subround, occasional well rounded; dominant moderate, common low, occasional high sphericity; dominant quartz, common mafic-rich and other miscellaneous lithics. Tuffaceous Siltstone (2515' - 2550') = overall medium gray with some brownish hues; blocky cuttings; slightly to moderately firm; dull luster; grainy to slight arenaceous texture; coarsens upward to argillaceous sandstone; tuffaceous claystone usually as discrete cuttings, indicating they are thin beds. Tuffaceous Siltstone / Sand (2550' - 2660') = very pale gray to light olive gray to grayish brown; moderate to poor induration; crumbly to brittle to trace semi tough; irregular to blocky fracture; dull to earthy luster; silty to gritty texture; ranges from a sandy siltstone to sandy claystone; deformed carbonaceous banding common; sands are typically unconsolidated with minor easily friable sand heavy clasts of siltstone/claystone; upper medium to upper fine; moderate sorting overall with well to modera te sorting in clean sands as well as good visual porosity and permeability; sub angular to sub rounded to angular; sub spherical to trace sub discoidal; grayish yellow ash clasts observed throughout the interval; overall poor to moderate porosity and poor permeability. Coal (2670' - 2700') = matte black to trace brownish black; semi tough to brittle and crumbly; hackly to planar to conchoidal fracture; platy to flaky cuttings habit; matte to slightly resinou s luster; no visible de- gassing observed. Sand / Tuffaceous Siltstone (2700' - 2840') = medium gray with pale brown hues to light medium gray to olive gray; predominantly unconsolidated with easily friable grain supported silty sandstone and tuffaceous clasts; upper medium to lower fine with minor lower coarse; moderate to well sorted with very good sorting in clean sands; sub angular to sub rounded to angular; sub spherical to trace su b discoidal good visual porosity and permeability in the clean sands with moderate to poor in the clasts with a high matrix content; quartz dominated with carbonaceous sediment and lithics common; the silt/claystones have moderate to poor induration; crum bly to brittle to trace semi tough; irregular to blocky fracture; dull to earthy luster; silty to gritty texture; ranges from a sandy siltstone to sandy claystone; deformed carbonaceous banding common and often fissile; minor sub bituminous coals observed throughout. Sand / Tuffaceous Siltstone (2840' - 2960') = dark medium gray to light medium gray with pale brown hues to olive gray; unconsolidated with easily friable grain suppor ted silty sandstone and tuffaceous clasts; upper coarse to lower fine; moderate sorting; sub rounded to sub angular to angular; sub spherical to trace sub discoidal good visual porosity and permeability in the clean sands with moderate to poor in the clasts with a high matrix content; quartz dominated with carbonaceous sediment and lithics common; the silt/claystones have moderate to poor induration; crumbly to brittle to trace semi tough; irregular to blocky fracture; dull to earthy luster; silty to gritty texture; ranges from a sandy siltstone to sandy claystone; deformed carbonaceous banding common and often fissile; minor sub bituminous coals observed throughout. Tuffaceous Siltstone (2960' - 3020') = light medium gray with pale light blue to light yellow hues; moderate to poor induration; crumbly to brittle to trace semi tough; irregular to blocky fracture; earthy to dull luster; silty to gritty to trace clayey texture; ranges from a sandy siltstone to sandy claystone; deformed carbonaceous banding common and fissile. Tuffaceous Siltstone (3020' - 3100') = light medium gray with pale light blue to light yellow hues; moderate to poor to occasionally good induration; crumbly and b rittle to tough to trace fissile; irregular to blocky to platy fracture; earthy to dull luster; silty to gritty texture; ranges from a sandy siltstone to sandy claystone; deformed carbonaceous banding common on siltstones; minor sand and carbonaceous shal e throughout. KU 11-07x 11 Tuffaceous Siltstone/ Sand (3100' - 3200') = medium dark gray to medium gray with brownish to olive gray hues; moderate to good induration; somewhat tough to minor brittle and crumbly; irregular to blocky to slightly planar fracture; trace fissile; dull to earthy luster; silty to clayey texture; deformed carbonaceous banding common; sands are typically unconsolidated with minor easily friable sand heavy clasts of siltstone and trace tuffaceous matrix; upper medium to upper fine; moderate sorting; sub angular to sub rounded; sub spherical to trace sub discoidal; moderate to poor visual porosity with moderate visual permeability; minor coals grading from sub bituminous to trace lignitic. Tuffaceous Siltstone / Sand (3200' - 3290') = medium dark gray to medium gray with brownish to olive gray hues; moderate induration; somewhat tough to crumbly to trace brittle; irregular to blocky to slightly planar fracture with trace fissile; dull to earthy to trace waxy luster; silty to clayey texture; deformed carbonaceous banding common; sands are typically unconsolidated with minor easily friable sand heavy clasts of siltstone and trace tuffaceous matrix; lower fine to upper medium; moderate sorting; sub rounded to sub angular; sub spherical; moderate to poor visual porosity. Tuffaceous Siltstone (3290' - 3350') = medium dark gray to medium gray with olive to black to brownish hues; moderate to occasionally good induration; somewhat tough to crumbly to trace brittle; amorphous to platy cuttings habit; irregular to blocky to slightly planar fracture with trace fiss ile; dull to earthy to trace waxy luster; silty to clayey texture; moderate unconsolidated to easily friable sands; quartz dominated. Sand (3360' - 3410') = dominant clear, common translucent, black, occasional green, gray; lower very fine to upper medium, dom inate upper fine to lower medium; moderately to well sorted; dominant subangular to subround, common angular, occasional round; dominant moderate, common low, occasional high sphericity; dominant quartz, common mafic-rich lithics, other lithics, occasional micas. Sand (3420' - 3470') = dominant clear to translucent, common black, gray, occasional green, reddish brown to orange; upper fine to rare lower coarse, dominant upper medium; dominant subangular to subround, common angular, occasional rounded; dominant moderate, common low, occasional high sphericity; dominant quartz, common mafic-rich and other lithics, possible good trace feldspar. Coal (3480' - 3505') = black; flaky to blocky cuttings; hard to moderately hard; tough to moderately tough; silky luster; dominant massive but with occasional bedding fissility; occasional grading to carbonaceous shale. Sandstone (3515' - 3580') = medium gray; rounded to slightly angular cuttings; slightly firm to moderately hard; mushy, easily friable to moderately tough; lower very fine to lower medium, dominant lower fine; moderate to well sorted; subangular to subround; moderatel y sphericity; grain to matrix support, softer cuttings with abundant argillaceous matrix with dominant matrix support, harder cuttings grain packed with moderate amounts of argillaceous matrix; dom inate quartz, common mafic-rich lithics, other miscellaneous lithics. Sand (3590' - 3630') = dominant clear to translucent, common multicolored; upper very to upper medium, dominant upper fine; moderate to well sorted; dominant subangular to subround, common angular, occasional rounded; dominant moderate, common low, occasional high sphericity; dominant quartz, common miscellaneous lithics. Sandstone (3640' - 3690') = dominant medium to occasional light gray; blocky, rounded cuttings; dominant slightly firm and easily friable, occasional moderately to very firm and moderately to slightly friable; lower very fine to lower medium, dominant lower fine; moderate to well sorted; dominant argillaceous matrix support (occasional bentonitic) to occasional grain packed; dominant quartz, common lithics. KU 11-07x 12 Tuffaceous Claystone (3720' - 3750') = medium gray; blocky cuttings; slightly to moderately firm; easily to moderately crumbly; slightly waxy luster; very finely grainy to smooth texture; appears to be thinly bedded with no grading to tuffaceous siltstone. Sand (3760' - 3800') = dominant clear to translucent, common multicolored; upper very to upper medium, dominant upper fine; moderate to well sorted; dominant subangular to subround, common angular, occasional rounded; dominant moderate, common low, occasional high sphericity; dominant quartz, common miscellaneous lithics. Sandstone (3810' - 3890') = overall medium gray but with common brownish hues due to organic-rich material; blocky to rounded cuttings; dominant slightly firm and easily friable, occasionally moderate to very firm and moderately to slight friable; lower very fine to lower fine; well sorted; softer matrix supported by argillaceous material, harder grain supported but still with copious amounts argillaceous material; common fining to siltstone; both siltstone and sandstone with organic-rich cuttings, grading to carbonaceous siltstone/sandstone; dominant quartz and common lithics; occasional dense and calcite - cemented. Tuffaceous Siltstone (3900' - 3950') = dominant medium gray to occasional moderate brown; blocky cuttings; slightly to moderately firm; easily to moderately crumbly; dull luster; overall finely grainy texture; appears to be thinly bedded with grading down to tuffaceous claystone and up to sandstone; browns are organic-rich and grade to carbonaceous claystone and siltstone. Tuffaceous Sandstone (3960' - 4010') = very light gray; blocky cuttings; slightly to moderately firm; dominant soft and mushy, occasional moderately firm and easily friable; lower f ine to upper coarse, dominant medium; moderate sorting; angular to subround; overall moderate sphericity; matrix supported with bentonitic matrix; occasionally fines to silt-sized; dominant quartz, common miscellaneous lithics. Tuffaceous Sandstone (4010' - 4100') = light medium gray to medium gray with pale olive hues; unconsolidated to easily friable; upper medium to lower fine; coarse grains common but not abundant; moderate sorting; rounded to sub rounded; moderate to high sphericity; trace sub discoidal; moderate to good visual porosity and permeability; grain supported; translucent to clear quartz dominated; minor dark lithics and carbonaceous sediment; trace plagioclase. Tuffaceous Sandstone (4100' - 4170') = light medium gray to medium gray with pale olive hues; unconsolidated to easily friable; upper fine to lower coarse; moderate to poor sorting; sub rounded to su b angular; sub spherical to slightly sub discoidal; moderate visual porosity and permeability; grain to trace matrix supported clasts; translucent to clear quartz dominated; minor dark lithics and carbonaceous sediment; minor moderately indurated clay and siltstone clasts. Tuffaceous Sandstone (4170'- 4250') = light medium gray to medium gray with pale olive to pale blue hues; unconsolidated to easily friable; upper fine to upper coarse; trace 2 -4mm grains; moderate to poor sorting; sub rounded to sub angular; sub spherical to slightly sub discoidal; moderate to poor visual porosity and permeability; grain to trace matrix supported clasts; trace matrix supported pale yellow sandstone clasts; hard to moderately hard; overall sample is dominated by translucent to clear quartz; minor dark lithics and carbonaceous sediment; minor moderately indurated siltstone. Tuffaceous Sandstone / Sand (4250' - 4330') = medium gray to light medium gray with pale olive hues; typically unconsolidated to easily friable; upper fine to upper coarse; moderate to poor sorting; sub rounded to sub angular; sub spherical to slightly sub discoidal; typically grain supported; pale grayish white ashy matrix; moderate to poor visual porosity and permeability; overall sample is dominated by translucent to clear quartz; minor dark lithics and carbonaceous sediment; minor moderately indurated siltstone clasts. KU 11-07x 13 Tuffaceous Sandstone / Claystone (4330' - 4420') = medium gray to pale grayish brown to dark medium gray with olive hues; easily friable to unconsolidated; lower fine to upper coarse; poor sorting; sub rounded to sub angular; sub spherical to slightly sub discoidal; typically grain supp orted; pale grayish white ashy matrix; poor visual porosity and moderate permeability; dominated by translucent to clear quartz; minor dark lithics; the clay/siltstones are moderately indurated; crumbly to semi tough; blocky to planar fracture; platy cuttings habit; dull to slight waxy luster; silty to clayey texture. Tuffaceous Sandstone / Claystone (4420' - 4520') = pale grayish brown to medium gray to dark medium gray with olive hues; unconsolidated to easily friable; upper fine to upper coarse; poor to moderate sorting; sub rounded to sub angular; sub spherical; grain supported; pale grayish white ashy matrix; moderate to poor visual porosity and moderate permeability; dominated by translucent to clear quartz; minor dark lithics; the clay/siltstones are moderately indurated; mushy to crumbly to semi tough; blocky to planar fracture; platy cuttings habit; dull to slight waxy luster; silty to clayey; trace carbonaceous shale. Tuffaceous Sandstone / Claystone (4520' - 4600') = medium gray to pale grayish brown to dark medium gray with olive hues; unconsolidated to easily friable; lower coarse to upper fine; poor to moderate sorting; sub rounded to sub angular; sub spherical; grain supported; pale grayish white ashy matrix; moderate visual porosity and moderate permeability; dominated by translucent to clear quartz; minor dark lithics; the claystones are poorly indurated; mushy to pasty; pulverulent; amorphous cuttings habit; dull to earthy luster; silty to clayey texture; minor carbonaceous sediment. Tuffaceous Sandstone / Claystone (4610' - 4690') = pale grayish brown to medium gray to dark medium gray with olive hues; easily friable to unconsolidated; upper fine to lower coarse; poor to moderate sorting; sub rounded to sub angular; sub spherical; grain supported; pale grayish white ashy matrix; poor to moderate visual porosity and moderate permeability; dominated by translucent to clear quartz; the clay/siltstones are poorly indurated; mushy to crumbly to semi tough; blocky to planar fracture; platy cuttings habit; dull to slight waxy luster; silty to clayey; trace carbonaceous shale. Tuffaceous Claystone / Siltstone (4700' - 4740') = dark medium gray with to medium gray with pale brown hues; moderate induration; mushy to semi malleable; blocky to planar fracture; platy to tabular to bit stacked cuttings habit; dull to waxy luster; clayey to silty texture. Tuffaceous Sandstone / Claystone (4740' - 4820') = medium gray to dark medium gray with pale brown and blue hues; easily friable to unconsolidated; upper fine to lower coarse; poor to moderate sorting; sub rounded to sub angular; sub spherical; grain supported; pale grayish white ashy matrix; poor visual porosity and permeability; dominated by translucent to clear quartz; the clay/siltstones are poorly indurated; mushy to crumbly to trace semi tough; blocky to planar fracture; platy cuttings habit; dull to slight waxy luster; silty to clayey texture; trace carbonaceous shale. Tuffaceous Claystone / Siltstone (4820' - 4880') = dark medium gray with to medium gray with pale brown hues; moderate induration; mushy to semi malleable; blocky to elongated to nodular cuttings habit; dull to waxy luster; clayey to silty texture; moderately hydrophilic; minor lower fine to upper medium sands; unconsolidated to easily friable; trace carbonaceous sediment. Tuffaceous Claystone / Sandstone (4880' - 4950') = dark medium gray to medium gray with pale brown hues; moderate induration; mushy to semi malleable; blocky to nodular cuttings habit; dull to waxy luster; clayey to silty texture; moderately hydrophilic; minor pale yellowish brown sandstone clasts; very fine grained; well sorted; moderate to good visual porosity; moderate permeability; grain supported; silty matrix. KU 11-07x 14 Sand (4955' - 5000') = dominant clear to translucent, common to abundant black, gray, good trace very light gray; dominant upper medium to lower coarse, common lower fine and u pper coarse, occasional very coarse, good trace grains > 2mm; poorly sorted; angular to subround, dominant subangular; moderate to low sphericity; dominant quartz, common to abundant igneous lithics. Tuffaceous Claystone (5040' - 5065') = medium gray; blocky to rounded cuttings; slightly firm; easily crumbly; dull to very slightly waxy luster; smooth to very finely grainy texture; no evident structure; grades to siltstone. Tuffaceous Siltstone (5075' - 5110') = medium gray; rounded, hydrate cuttings; soft to slightly firm; easily crumbly to mushy; dull luster; finely to very finely grainy texture; no evident structure; grades to tuffaceous claystone; also grades evenly to marginal argillaceous sandstone. Sandstone (5120' - 5165') = dominant medium to occasional medium light gray; rounded, hydrated cuttings; soft; mushy; upper very fine to ultrafine, grading to siltstone; well sorted; consists of grains suspended and disseminated in dominant tuffaceous clay to occasional moderately bentonitic matrices; dominant quartz, common igneous-derived and black lithics. Tuffaceous Claystone (5175' - 5210') = medium gray; blocky cuttings; slightly firm; easily crumbly; dull to very slightly waxy luster; smooth to very finely grainy texture; no evident str ucture; grades to tuffaceous siltstone in part; occasional discrete cuttings of carbonaceous shale in this interval. Sand (5220' -5265') = dominant clear to translucent quartz, common to abundant black mineral grains that have abundant cryptocrystalline pyrite disseminated in quartz matrix with apparent flow structures, occasional volcanically-derived quartz with common mafic-rich inclusions; lower fine to lower coarse, dominant lower medium; moderately sorted; dominant subangular to subround, occasional to common low, occasional high sphericity. Sandstone (5205' - 5330') = overall medium gray; rounded cuttings; soft to slightly firm; mushy to easily friable; ultrafine to upper fine; moderately to well sorted; dominant subangular to subround, occasional well rounded; grains suspended and disseminated in argillaceous matrix (occasionally moderately bentonitic); dominant quartz, common lithic grains. Tuffaceous Claystone (5340' - 5375') = medium gray; blocky cuttings; slightly firm; easily crumbly; dull to very slightly waxy luster; smooth to very finely grainy texture; no evident str ucture; grades to tuffaceous siltstone in part; occasional discrete cuttings of carbonaceous shale in this interval. Tuffaceous Sandstone (5385' - 5435') = very light gray; rounded, hydrated cuttings; soft to slightly firm; mushy to easily friable; upper very fine to lower medium, dominant lower fine; well sorted; dominant subround to subangular, common well rounded, occasional angular; dominant moderate, common high, occasional low sphericity; bentonitic matrix support; dominant quartz, common miscellaneous lithics. Sand (5445' - 5485') = dominant clear to translucent, common black, gray; lower very fine to upper fine, dominant lower fine; well sorted; dominant subround, common subangular, occasional to common angular and rounded; dominant moderate, occasional to common high and low sphericity; dominant quartz, common igneous-derived lithics. Tuffaceous Sandstone (5495' - 5545') = very light gray to light gray; rounded cuttings; soft to slightly firm; mushy to easily friable; lower very fine to lower medium, dominant lower fine; moderate to well sorted; dominant subround to subangular, common angular, occasional rounded; dominant moderate, common low, occasional high sphericity; dominant quartz, common igneous -derived lithics. KU 11-07x 15 Tuffaceous Claystone (5555' - 5585') = medium gray; blocky cuttings; slight to moderate firm; easily to moderate crumbly; dull luster; smooth to very finely grainy texture; no evident structure; scattered carbonaceous shale throughout interval. Tuffaceous Claystone (5590' - 5640') = dark medium gray to medium gray with black to dark brown hues; mushy to clumpy to occasionally pasty; earthy to irregular fracture; amorphous cuttings habit; dull to waxy luster; clayey to slightly silty texture; slightly hydrophilic; massive and interbedded with thin sands and siltstones; minor to trace coals Tuffaceous Claystone (5640' - 5700') = medium gray to dark medium gray with black to dark brown to olive hues; mushy to clumpy to occasionally pasty; earthy to irregular fracture; amorphous cuttings habit; dull to waxy luster; clayey to slightly silty texture; slightly hydrophilic; massive and interbedded with thin sands and siltstones; minor to trace coals and carbonaceous sediment. Tuffaceous Claystone (5700' - 5780') = medium gray to dark medium gray with black to dark brown to olive hues; mushy to clumpy to occasionally pasty; earthy to irregular fracture; amor phous cuttings habit; dull to waxy luster; clayey to slightly silty texture; slightly hydrophilic; massive and interbedded with thin sands and siltstones; trace grain supported sandstone clasts; light brown to tan; upper fine to lower very fine; well sorted; sub angular to sub rounded; predominantly quartz; trace coal and carbonaceous sediment throughout. Tuffaceous Claystone (5780' - 5860') = dark medium gray to medium gray with dark brown to olive hues; mushy to clumpy to pasty; amorphous cuttings habit; earthy to irregular fracture; dull to waxy luster; clayey to smooth texture; slightly hydrophilic; massive and interbedded with thin sands and siltstones; minor matrix supported sandstone clasts; light gray to off white; upper fine to lower coarse; poor to moderate sorting; sub angular to sub rounded; predominantly quartz; minor coal and carbonaceous sediment throughout. Tuffaceous Claystone (5860' - 5930') = dark medium gray to medium gray with olive hues; mushy to clumpy to pasty; earthy to irregular fracture; amorphous cuttings habit; dull to waxy luster; clayey to smooth texture; slightly hydrophilic; massive and interbedded with thin san ds and siltstones; minor unconsolidated sands; upper fine to lower coarse; poor sorting; sub angular to sub rounded; predominantly clear and translucent quartz; carbonaceous shale and coal common but not abundant. Tuffaceous Claystone (5930' - 6010') = dark medium gray with blackish hues to medium gray with olive hues; mushy to clumpy to pasty; earthy to irregular fracture; amorphous cuttings habit; dull to waxy luster; clayey to smooth texture; slightly hydro philic; massive and interbedded with thin sands and siltstones; trace unconsolidated sands; upper fine to lower coarse; poor sorting; sub angular to sub rounded; predominantly clear and translucent quartz; abundant carbonaceous sediment mixed with the clay matrix; minor coals. Tuffaceous Claystone (6010' - 6100') = medium gray with blackish hues to dark gray with olive hues; mushy to clumpy to pasty; clayey to smooth texture; earthy to irregular fracture; amorphous cuttings habit; dull to waxy luster; massive and interbedded with thin sands and siltstones; trace unconsolidated sands and minor coals. Tuffaceous Claystone (6135' - 6165') = medium gray; amorphous to blocky cuttings; soft to very slightly firm; mushy to very easily crumbly; dull luster; very finely grainy to smooth texture; no evident structure; grades to tuffaceous siltstone. Sand (6175' - 6215') = dominant clear to translucent, common black, occasional gray; upper very fine to lower medium, dominant fine; moderately sorted; dominant subangular to subround, common angular, well rounded; dominant moderate, common low and high sphericity; dominant quartz, common miscellaneous lithics. KU 11-07x 16 Tuffaceous Sandstone (6225' - 6275') = medium light gray to light gray; rounded cuttings; soft to very slightly firm; mushy to very easily friable; upper very fine to lower medium, dominant fine; moderately sorted; dominant subangular to subround, common well rounded and angular; dominant moderate, common low and high sphericity; matrix supported with clayey to bentonitic matrix, dominant quartz, common lithics. Tuffaceous Siltstone (6285’ - 6320') = medium gray to medium light gray; amorphous cuttings; soft; mushy to very easily crumbly; dull luster; finely grainy to grainy texture; no evident structure; coarsens upward to tuffaceous sandstone; occasionally grading evenly to tuffaceous claystone. Sandstone (6330' - 6380') = medium gray; rounded, hydrated cuttings; soft; mushy; lower very fine to upper fine, dominant lower fine; moderately to well sorted; dominant subround to subangular, common well rounded, occasional angular; dominant moderate, common high, occasional low sphericity; matrix supported dominantly by gray clay, occasionally bentonitic; dominant quartz, common miscellaneous lithics. Tuffaceous Claystone/ Tuffaceous Siltstone (6380' - 6460') = medium light to light gray with light brownish gray secondary hues; very soft to slightly firm; irregular, wedgelike to shapeless; slimy to mushy; silty to clayey texture; dull to greas y luster; hydrophilic; soluble and expansive; poor cohesiveness; fair adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions in firmer fragments. Sandstone/ Sand (6460' - 6530') = medium to medium dark gray overall; very hard; very fine lower; angular to subangular; well sorted; very calcareous; with individual grains dominantly clear to translucent quartz and volcanic glass, medium to dark gray; very fine lower to fine upper; poor to fair sorting; present in dominantly a claystone formation; trace thin coal beds. Tuffaceous Claystone/ Tuffaceous Siltstone (6530'-6590') = medium light gray to light gray with very light brownish gray secondary hues; very sticky; very soft; shapeless, globular cuttings; silty to clayey texture; dull to greasy luster; slimy to mushy; moderate to very soluble; moderately expansive; hydrophilic; poor cohesiveness; fair to good adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace thin coal beds throughout interval. Tuffaceous Claystone/ Tuffaceous Siltstone (6590' - 6650') = medium light to light gray with light brownish gray secondary hues; very soft to slightly firm; irregular, wedgelike to shapeless; slimy to mushy; silty to clayey texture; dull to greasy luster; hydrophilic; soluble and expansive; poor cohesiveness; fair adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions. Sand (6650' - 6710') = medium light gray to light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray and black; very fine upper to medium lower, dominantly fine; angular to subangular; fair to good sorting; unconsolidated; present as a minor fraction o f dominantly a claystone formation; trace thin coal beds. Tuffaceous Claystone/ Tuffaceous Siltstone (6710' - 6780') = medium light gray to light gray with very light brownish gray secondary hues; very sticky; very soft; shapeless, globular cuttings; silty to clayey texture; dull to greasy luster; slimy to mushy; moderate to very soluble; moderately expansive; hydrophilic; poor cohesiveness; fair to good adhesiveness; non calcareous; trace dark bro wn to black microthin carbonaceous laminations and inclusions; trace thin coal beds throughout interval. Sand (6780' - 6840') = medium light gray to light gray overall with individual grains dominantly cle ar to translucent quartz and volcanic glass, light to dark gray and black; very fine upper to medium lower, dominantly fine; angular to subangular; fair to good sorting; unconsolidated; present as a minor fraction of dominantly a claystone formation; trace thin coal beds throughout interval. KU 11-07x 17 Coal (6840' - 6900') = black with brownish black and grayish black secondary hues; very firm to hard and brittle; massive to flaky; blocky to planar fracture dominant with trace conchoidal and birdeye; smooth to matte texture; resinous to slightly earthy and silty texture; subbituminous to bituminous; poorly developed; commonly grading to a carbonaceous shale; no visible outgassing; present as very thin beds in dominantly claystone formation. Tuffaceous Claystone/ Tuffaceous Siltstone (6900' - 6960') = medium light gray to light gray with very light gray secondary hues; very soft; irregular to shapeless, amorphous cuttings; silty to clayey texture; dull, earthy to greasy luster; slimy to mushy; hydrophilic; very soluble; slight to moderately expansive; poor cohesiveness; fair to good adhesiveness; non calcareous; trace to common thin coal beds throughout. Tuffaceous Claystone/ Tuffaceous Siltstone (6960' - 7030') = medium light gray to light gray with very light brownish gray secondary hues; very sticky; very soft; shapeless, globular cuttings; silty to clayey texture; dull to greasy luster; slimy to mushy; moderate to very soluble; moderately expansive; hydrophilic; poor cohesiveness; fair to good adhesiveness; non calcareous; trace thin coal beds throughout interval; no outgassing observed. Sand (7030' - 7090') = medium light gray to light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray and black; very fine lower to fine upper, dominantly fine lower; angular to subangular; fair to good sorting; unconsolidated; present as a minor fraction of dominantly a claystone formation; trace thin coal beds throughout interval; trace weak outgassing observed. Coal/ Carbonaceous Shale (7090' - 7150') = black with brownish black secondary hues; very firm to hard and brittle; massive to flaky; blocky to planar fracture dominant with trace conchoidal and birdeye; smooth to matte texture; resinous to slightly earthy and silty texture subbituminous to bitumin ous; poorly developed; commonly grading to a carbonaceous shale; trace outgassing bubbles; present as thin beds in dominantly a claystone formation. Tuffaceous Claystone/ Tuffaceous Siltstone (7150' - 7210') = medium light to light gray with light brownish gray secondary hues; very soft to slightly firm; irregular, wedgelike to shapeless; slimy to mushy; silty to clayey texture; dull to greasy luster; hydrophilic; soluble and expansive; poor cohesiveness; fair adhesiveness; non calcareous. Tuffaceous Claystone (7240' - 7275') = medium gray with occasional very slight greenish hue; amorphous cuttings; soft to slightly firm; mushy to easily crumbly; dull luster; mostly as reworked clays but common discrete, integral cuttings; grades in part to tuffaceous siltstone. Sand (7285' - 7320') = dominant clear, common translucent, black, occasional gray; lower very fine to upper fine; well sorted; dominant subround to subangular, common well rounded, occasional angular; dominant moderate, common high, occasional low sphericity; dominant quartz, common lithics. Tuffaceous Sandstone (7330' - 7370') = light gray with common brown hues from disseminated organic material; lower very fine to lower medium, dominant fine; moderately sorted; supported by bentonitic and clay matrix; common very thin coal seams; dominant moderate, common high, occasional low sphericity; dominant quartz, common lithics. Tuffaceous Claystone (7380' - 7420') = medium gray with occasional very slight greenish hue; amorphous to blocky cuttings; slightly firm; easily crumbly; dull luster; smooth to very finely grainy texture; no evident structure; common traces carbonaceous shale throughout; occasionally grading evenly to tuffaceous siltstone. KU 11-07x 18 Tuffaceous Sandstone (7430' - 7485') = very light gray; blocky to rounded cuttings; very slightly firm; easily friable; lower very fine to lower fine; well sorted; dominant subround to subangular, common well rounded, occasional angular; dominant moderate, common high, occasional low sphericity; matrix- supported with bentonitic, ashy matrix material; dominant quartz, common to abundant mafic -rich lithics, other miscellaneous occasionally. Tuffaceous Claystone (7495' - 7530') = overall medium gray; blocky to hydrated, amorphous cuttings; slightly firm to soft; easily crumbly to mushy; dull luster; smooth to very finely grainy texture; overall homogeneous but with occasional coals seams; grades to tuffaceous siltstone in par t. Sand (7540' - 7580') = dominant clear, common translucent, black, occasional gray; upper very fine to upper fine; well sorted; dominant subround to subangular, common well rounded, occasional angular; dominant moderate, common high, occasional low sphericity; dominant quartz, common mafic -rich lithics, occasional other lithics. Coal (7590' - 7615') = black; shardy to angular cuttings; moderately hard and tough but brittle; silky, shiny luster; smooth texture; overall homogeneous but with slight bedding delineation and fissility; hackly irregular fracture. Sand (7625' - 7665') = dominant clear to translucent, common black, gray; upper very fine to upper fine; moderately to well sorted; dominant subround to subangular, common well rounded, occasional angular; dominant moderate, common high, occasional low sphericity; dominant quartz, common mafic -rich lithics, occasional other lithics. Tuffaceous Sandstone (7675' - 7730') = very light gray to light gray; irregular cuttings; soft to slightly firm; mushy to easily friable; lower very fine to lower fine; well sorted; supported by bentonitic, ashy to argillaceous matrix; dominant subround to subangular, common well rounded, occasional angular; dominant moderate, common high, occasional low sphericity; dominant quartz, common mafic -rich lithics, occasional miscellaneous lithics. Tuffaceous Claystone/ Tuffaceous Siltstone (7730' - 7800') = light gray to very light gray with very light brown to brownish gray secondary hues; very soft; irregular, shapeless, globular cuttings; silty to c layey texture; greasy to dull luster; very soluble; hydrophilic; poor cohesiveness; fair to good adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace to common thin coal beds throughout interval. Coal/ Carbonaceous Shale (7800' - 7860') = black with brownish black and grayish black secondary hues; fragile and brittle to very firm and hard; flaky to platy planar fracture dominant with trace con choidal and birdeye fracture; earthy to resinous luster; smooth to slightly silty and gritty texture; sub bituminous to bituminous; commonly grading to a less developed carbonaceous shale; common and vigorous outgassing bubbles observed. Tuffaceous Sandstone/ Sand/ Sandstone (7860' - 7950')= very light gray overall with abundant secondary hues; irregular rounded cuttings; soft; fragile to pulverulent; non calcareous; ashy matrix supports loose sand grains; sand dominantly clear to translucent quartz and volcanic glass, light to medium gray and light green to greenish gray; very fine lower to fine upper, dominantly fine lower; angular to subangular; moderately well sorted; very loosely consolidated in ash matrix; t race salt and pepper sandstone; fine lower to medium lower; well sorted; angular to subangular; grain supported; hard; non calcareous; trace to common thin coal beds throughout interval. KU 11-07x 19 Sand/ Tuffaceous Sandstone (7950' - 8020') = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray and trace darker grains; very fine lower to trace coarse upper, dominantly fine upper to lower; angular to subangular; very well sorted; dominantly unconsolidated with scattered ash supported; very light gray to grayish white matrix; non calcareous; very fragile; trace thin coal beds. Tuffaceous Claystone/ Tuffaceous Siltstone (8020' - 8080') = medium light to light gray with brown to light brown and light brownish gray secondary hues; soft to moderately firm; irregular, shapeless to trace pdc bit action shaped cuttings; silty to clayey texture; dull, earthy to waxy luster; moderately soluble and expansive; hydrophilic; poor to fair cohesiveness and adhesiveness; non calcareous; trace to common thin coal beds throughout interval. Coal/ Carbonaceous Shale (8080' - 8150') = black with brownish black and grayish black secondary hues; hard; brittle at times; platy to flaky; planar fracture with trace splintery and conchoidal; resinous to slightly earthy luster; smooth to slightly silty texture; very well developed; bituminous; occasionally grad ing to a carbonaceous shale; vigorous and long lasting outgassing bubbles observed. Tuffaceous Claystone/ Tuffaceous Siltstone (8150' - 8210') = medium light to light gray to light brown with light brownish gray secondary hues; soft to moderately firm; irregular, shapeless to trace pdc bit action shaped cuttings; silty to clayey texture; dull, earthy to waxy luster; moderately soluble and expansive; hydrophilic; poor to fair cohesiveness; fair to good adhesiveness; non calcareous; common to abundant coal beds throughout interval with abundant outgassing bubbles observed. Coal/ Carbonaceous Shale (8210' - 8270') = black with brownish black and grayish black secondary hues; hard; brittle at times; platy to flaky; planar fracture with trace splintery and conchoidal; resinous to slightly earthy luster; smooth to slightly silty texture; very well developed; bituminous; occasionally grading to a carbonaceous shale; vigorous and long lasting outgassing bubbles observed. Sand/ Tuffaceous Sandstone (8270' - 8330') = light to very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, light to dark gray and trace darker grains; very fine lower to trace coarse lower, dominantly fine upper to lower; angular to subangular; very well sorted; dominantly unconsolidated with scattered ash supported; very light gray to grayish white matrix; non calcareous; very fragile; common to abundant coal beds throughout interval. Tuffaceous Claystone/ Tuffaceous Siltstone (8330'- 8400') = medium light gray to light gray with light brown and light brownish gray secondary hues; shapeless, irregular cuttings; very soft; silty to clayey texture; dull luster; moderately soluble; hydrophilic; poor cohesiveness; fair adhesiveness; non calcareous; trace dark brown to black microthin carbonaceous laminations and inclusions; trace to common coal beds throughout. Coal (8400' - 8460') = black; hard to brittle; platy to flaky; planar fracture dominant; resinous to earthy luster; smooth to matte texture; bituminous; abundant outgassing bubbles present. Sand (8480' - 8520') = dominant clear, common translucent, black, occasional gray; upper very fine to lower coarse, dominant upper fine; moderate sorting; dominant subangular to subround, common angular and rounded; dominant moderate, occasional low and high sphericity; dominant quartz, common mafic - rich and miscellaneous lithics. Tuffaceous Sandstone (8530' - 8585') = very light gray; rounded cuttings; slightly firm to soft; easily friable to mushy; upper very fine to lower coarse, dominant fine; moderately sorted; dominant subround to subangular, common angular and rounded; dominant moderate, common low and high sphericity; grains disseminated in ashy, bentonitic matrix with some grain packing; dominant quartz, common mafic -rich lithics, occasional other lithics. KU 11-07x 20 Tuffaceous Claystone (8595' - 8620') = dominant olive gray to occasional medium gray; irregular cuttings; slightly firm; easily crumbly; dull luster; smooth to very finely grainy texture; grades evenly to tuffaceous siltstone. Coal (8630' - 8650') = black; hard; dense, moderately brittle; silky, shiny luster; smooth texture; no evident structure; associated with pale tan, arenaceous tuff. Tuffaceous Siltstone (8660' - 8700') = medium gray with common strong brownish hues; irregular cuttings; slightly firm; easily crumbly; dull luster; grainy to finely grainy texture; occasionally in direct bedding contact with other lithology types; occasionally grades to tuffaceous claystone but grades evenly and strongly to argillaceous sandstone. Sandstone (8710' - 8760') = dominant olive gray to common medium gray; rounded cuttings; slightly firm to soft; easily friable to mushy; lower very fine to upper fine; moderately sorted; dominant moderate, occasional low and high sphericities; grain to matrix support with abundant argillaceous matrix fill; dominant quartz, common mafic-rich lithics, occasional other miscellaneous lithics. Tuffaceous Claystone (8770' - 8795') = overall olive gray; irregular cuttings; soft to slightly firm; easily crumbly; dull luster; smooth to very slightly grainy texture; no evident structure; grades to tuffaceous siltstone. Tuffaceous Sandstone/ Sand (8800' - 8870') = very light gray overall with very light brown secondary hues, individual grains dominantly clear to translucent quartz and volcanic glass, trace dark liths; ashy matrix is very soft; fragile and pulverulent; supports loose grains; very fine lower to very coarse upper, dominantly fine upper to medium upper; angular to trace subrounded, dominantly subangular; poorly sorted; disaggregated with ashy matrix support common; non calcareous. Tuffaceous Sandstone (8870' - 8920') = very light gray to grayish white with a mottled appearance from abundant secondary hues of light brown, gray and greenish gray; very fr agile and pulverulent; irregular shaped; glass shards visible; non calcareous; ashy matrix supports loose sand grains. Sand (8920' - 8950') = very light gray overall with individual grains dominantly clear to translucent quartz and volcanic glass, trace amounts light to dark gray, black and greenish gray; very fine lower to fine upper; angular to subangular; very well sorted; dominantly unconsolidated; non calcareous. Tuffaceous Sandstone/ Sand (8950' - 9020') = very light gray overall, individual liths dominantly clear to translucent quartz and volcanic glass, trace dark liths; ashy matrix is very soft; fragile and pulverulent; supports loose grains; very fine lower to trace very coarse upper, dominantly fine lower to medium lower; angular to subangular with trace subrounded; poorly sorted; very loosely supported with ashy matrix; non calcareous; trace thin coal beds. Coal/ Carbonaceous Shale (9020' - 9080') = black with brownish black and grayish black secondary hues; hard; brittle at times; platy to flaky; planar fracture dominant with trace conchoidal; resinous to slightly earthy luster; smooth to slightly silty texture; very well developed; bituminous; occasionally grading to a carbonaceous shale; common to abundant outgassing bubbles observed. Tuffaceous Claystone/ Tuffaceous Siltstone (9080' - 9150') = light grayish brown with medium light to light gray secondary hues; very soft; irregular, shapeless cuttings with trace pdc bit action; silty to clayey texture; dull to earthy luster; moderately soluble and expansive; hydrophilic; poor cohes iveness; poor to fair adhesiveness; light yellowish gray siltstone commonly grades between silty sandstone and sandy siltstone; soft; fragile; non calcareous. KU 11-07x 21 Tuffaceous Sandstone/ Sand (9150' - 9200') = very light gray overall, individual liths dominantly clear to translucent quartz and volcanic glass, trace dark liths; ashy matrix is very soft; fragile and pulverulent; supports loose grains; very fine lower to medium upper, dominantly fine; angular to subangular; moderately well sorted; dominantly unconsolidated with ashy supporting matrix abundant; non calcareous. Coal/ Carbonaceous Shale (9200' - 9260') = black with brownish black and grayish black secondary hues; hard; brittle at times; platy to flaky; planar fracture dominant with trace conchoidal; resinous to slightly earthy luster; smooth to slightly silty texture; very well developed; bituminous; occasionally grading to a carbonaceous shale; common to abundant outgassing bubbles o bserved. Tuffaceous Sandstone/ Sand (9260' - 9330') = very light gray overall with light brownish gray secondary hue, individual grains dominantly clear to translucent quartz and volcanic glass, trace dark li ths; ashy matrix is very soft; fragile and pulverulent; supports loose grains; very fine lower to very coarse upper, dominantly fine upper to medium upper; angular to trace subrounded, dominantly subangular; poorly sorted; disaggregated with ashy matrix support common; non calcareous. Tuffaceous Sandstone/ Sand (9330' - 9410') = very light gray to grayish white with a mottled appearance from abundant secondary hues of light brown, gray and greenish gray; very fragile and pulverulent; irregular shaped; glass shards visible; non calcareous; ashy matrix supports loose sand grains; dominantly clear to translucent quartz and volcanic glass, light green to light greenish gray and black; very fine lower to very coarse upper, dominantly fine lower to medium upper; angular to subangular; poorly sorted; loosely consolidated with ashy supporting matrix; non calcareous. Coal/ Carbonaceous Shale (9410' - 9460') = black with brownish black and grayish black secondary hues; hard; brittle at times; platy to flaky; planar fracture dominant with trace conchoidal; resinous to slightly earthy luster; smooth to slightly silty texture; sub bituminous to bituminous; o ccasionally grading to carbonaceous shale; no to trace outgassing bubbles observed. Sand (9470' - 9515') = dominant clear, common black, gray, occasional green, reddish brown; lower fine to upper medium, dominant upper fine to lower medium; moderately sorted; dominant subround to subangular, common to occasional rounded; dominant moderate to occasional high sphericity; dominant quartz, common mafic-rich lithics, other volcanic and plutonic lithics. Tuffaceous Sandstone (9525' - 9575') = very light gray; lower fine to upper medium; moderately to well sorted; dominant subround to subangular, common moderate to well rounded; dominant moderate, common high sphericity; matrix supported with grains evenly distributed in bentonitic tuff matrix (which is in part non-arenaceous tuff); dominant quartz, common mafic-rich and volcanic/plutonic lithics. Tuffaceous Siltstone (9585' - 9625') = olive gray; irregular cuttings; slightly firm to soft; easily crumbly to moderate mushy; dull luster; occasional bedding between variably argillaceous and arenaceous material; grain-sizes right on border between silt and sand size: grades strongly and evenly to an argillaceous sandstone. Tuffaceous Sandstone (9635' - 9680') = very light gray; lower fine to upper medium; moderately to well sorted; dominant subround to subangular, common moderate to well rounded; dominant moderate, common high sphericity; matrix supported with grains evenly distributed in bentonitic tuff matrix; dominant quartz, common mafic-rich and volcanic/plutonic lithics. Sand (9710' - 9750') = dominant clear, common black, translucent, gray; upper very fine to lower medium, dominant fine; moderately sorted; dominant subround to subangular, common well rounded; dominant moderate, common high sphericity; dominant quartz, common mafic-rich lithics; occasional lithics from volcanic and plutonic sources. KU 11-07x 22 Tuffaceous Siltstone (9760' - 9795') = olive gray; irregular cuttings; slightly firm to soft; easily crumbly; dull luster; finely grainy to ultra-finely arenaceous texture; common bedding delineation between more argillaceous and arenaceous beds; grades evenly and strongly to sandstone. 3.3 Sampling Program Set Type and Purpose Interval Frequency Distribution A Washed and Dried Reference 1522’ – 9799’ 30’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 B Washed and Dried Reference 1522’ – 9799’ 30’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 C Washed and Dried Reference 1522’ – 9799’ 30’ Jacob Dunston Hilcorp Alaska LLC 3800 Center Point Drive, Suite 100 Anchorage, AK 99508 KU 11-07x 23 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 0.00 181.74 0.02 192.06 181.74 -0.03 -0.01 0.03 0.38 241.10 0.24 217.56 241.10 -0.14 -0.08 0.14 0.38 302.64 0.26 183.06 302.64 -0.38 -0.17 0.38 0.24 386.78 0.86 233.02 386.78 -0.95 -0.69 0.95 0.86 446.54 0.84 212.48 446.52 -1.58 -1.28 1.60 0.51 505.51 1.17 219.62 505.49 -2.41 -1.89 2.43 0.6 569.32 1.02 211.37 569.29 -3.40 -2.61 3.42 0.34 630.24 2.84 225.50 630.17 -4.92 -3.96 4.96 3.06 691.35 5.13 240.67 691.13 -7.32 -7.43 7.39 4.10 753.78 5.81 237.21 753.28 -10.40 -12.52 10.51 1.20 816.25 6.15 243.90 815.41 -13.58 -18.18 13.75 1.25 877.87 7.30 249.19 876.61 -16.43 -24.81 16.66 2.11 940.93 6.30 238.03 939.22 -19.68 -31.49 19.97 2.82 1003.33 7.13 238.02 1001.19 -23.55 -37.68 23.90 1.32 1065.75 6.05 236.48 1063.19 -27.41 -43.71 27.82 1.76 1128.31 6.46 237.39 1125.38 -31.13 -49.42 -31.59 0.67 1193.12 5.80 236.28 1189.83 -34.91 -55.21 35.42 1.04 1252.62 5.82 236.15 1249.02 -38.17 -60.27 38.73 0.32 1315.12 6.72 237.66 1311.15 -41.80 -66.05 42.41 1.45 1376.88 6.34 240.22 1372.51 -45.43 -72.07 46.09 0.78 1438.86 5.37 242.82 1434.16 -48.45 -77.62 49.17 1.62 1484.37 5.50 238.60 1479.47 -50.56 -81.37 51.31 0.92 1568.95 6.46 233.60 1563.59 -55.49 -88.66 53.01 1.28 1630.22 6.70 232.67 1624.45 -59.70 -94.28 57.06 0.44 1692.57 6.58 233.02 1686.38 -64.05 -100.03 61.25 0.20 1754.18 7.14 231.95 1747.55 -68.54 -105.86 65.57 0.93 1816.61 5.84 235.75 1809.58 -72.72 -111.54 69.59 2.19 1879.62 5.74 236.66 1872.27 -76.25 -116.82 72.98 0.22 1942.12 5.55 237.13 1934.47 -79.61 -121.97 76.19 0.30 2004.81 5.87 236.07 1996.84 -83.04 -127.18 79.48 0.54 2066.80 5.48 244.49 2058.53 -86.09 -132.48 82.38 1.49 2130.29 5.84 244.19 2121.71 -88.80 -138.12 84.93 0.58 2190.91 5.64 244.86 2182.03 -91.41 -143.59 87.39 0.35 KU 11-07x 24 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) 2254.64 6.16 244.26 2245.43 -94.22 -149.51 90.04 0.82 2315.16 6.13 244.51 2305.59 -97.02 -155.35 92.68 0.06 2378.28 6.21 244.26 2368.35 -99.96 -161.46 95.44 0.13 2442.39 6.52 244.08 2432.06 -103.05 -167.86 98.35 0.49 2503.05 6.78 243.45 2492.31 -106.16 -174.16 101.28 0.45 2564.71 7.08 243.41 2553.53 -109.49 -180.82 104.43 0.49 2626.97 7.00 243.53 2615.32 -112.90 -187.65 107.65 0.13 2688.92 6.42 242.32 2676.84 -116.19 -194.09 110.76 0.98 2751.01 6.44 241.59 2738.54 -119.46 -200.23 113.86 0.14 2813.16 6.52 242.99 2800.30 -122.72 -206.44 116.94 0.28 2874.56 6.62 242.78 2861.29 -125.92 -212.69 119.97 0.18 2937.18 7.01 241.84 2923.47 -129.38 -219.27 123.24 0.64 2999.17 6.96 242.89 2985.00 -132.87 -225.95 126.55 0.22 3060.94 6.46 240.25 3046.34 -136.30 -232.30 129.80 0.96 3122.77 6.22 239.32 3107.79 -139.74 -238.20 133.07 0.43 3185.84 5.83 241.12 3170.52 -143.03 -243.94 136.20 0.68 3248.97 5.82 241.90 3233.32 -146.08 -249.57 139.10 0.13 3310.81 5.96 241.93 3294.84 -149.07 -255.17 141.93 0.22 3373.30 6.02 242.28 3356.98 -152.12 -260.93 144.82 0.12 3435.52 5.97 242.00 3418.87 -155.16 -266.67 147.70 0.10 3497.62 6.02 242.64 3480.63 -158.17 -272.41 150.55 0.14 3559.49 6.38 242.89 3542.14 -161.22 -278.35 153.44 0.59 3621.41 6.71 242.36 3603.65 -164.47 -284.62 156.51 0.53 3684.03 6.59 241.68 3665.85 -167.87 -291.02 159.73 0.23 3745.78 6.68 237.86 3727.19 -171.46 -297.18 163.15 0.73 3807.72 7.22 224.01 3788.68 -176.18 -302.93 167.70 2.84 3868.83 8.14 212.63 3849.24 -182.58 -307.94 173.97 2.90 3931.42 8.70 200.61 3911.16 -190.75 -311.99 182.02 2.94 3993.02 9.20 187.72 3972.01 -199.99 -314.30 191.19 3.35 4054.73 9.47 175.30 4032.92 -209.94 -314.54 201.13 3.29 4117.11 9.10 170.12 4094.48 -219.91 -313.28 211.13 1.46 4179.11 9.78 160.97 4155.64 -229.72 -310.72 221.01 2.66 4241.03 9.97 158.37 4216.64 -239.67 -307.03 231.06 0.78 4303.42 9.42 154.62 4278.15 -249.30 -302.85 240.80 1.34 4365.35 9.83 154.33 4339.21 -258.64 -298.39 250.26 0.67 4428.28 9.63 155.67 4401.23 -268.28 -293.89 260.02 0.49 4491.29 9.25 154.96 4463.39 -277.67 -289.58 269.52 0.63 4553.66 9.34 155.30 4524.94 -286.80 -285.34 278.78 0.17 4616.34 9.64 154.84 4586.76 -296.17 -280.99 288.26 0.49 KU 11-07x 25 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) 4678.35 10.00 154.33 4647.87 -305.72 -276.45 297.93 0.60 4740.68 8.53 156.48 4709.38 -314.84 -272.26 307.16 2.43 4802.20 8.23 156.65 4770.24 -323.06 -268.69 315.48 0.49 4864.52 8.62 156.06 4831.88 -331.42 -265.03 323.94 0.63 4926.59 9.05 155.01 4893.22 -340.10 -261.08 332.72 0.75 4988.65 9.15 154.86 4954.50 -348.99 -256.92 341.72 0.17 5051.91 9.56 155.64 5016.92 -358.33 -252.62 351.18 0.68 5113.74 9.72 154.56 5077.88 -367.72 -248.26 360.69 0.40 5175.78 10.23 155.00 5138.98 -377.44 -243.68 370.54 0.82 5237.32 10.41 155.86 5199.53 -387.47 -239.10 380.69 0.39 5300.33 9.65 153.42 5261.57 -397.39 -234.41 390.73 1.38 5363.81 9.33 153.34 5324.18 -406.74 -229.72 400.21 0.50 5426.40 9.77 153.85 5385.90 -416.04 -225.10 409.64 0.72 5488.31 9.66 152.52 5446.92 -425.37 -220.39 419.09 0.41 5552.13 10.09 152.70 5509.80 -435.09 -215.35 428.95 0.68 5614.27 9.67 155.84 5571.02 -444.69 -210.72 438.67 1.10 5674.06 9.22 158.56 5629.99 -453.73 -206.91 447.81 1.07 5735.97 9.71 156.99 5691.07 -463.15 -203.06 457.34 0.89 5798.22 9.65 157.92 5752.43 -472.81 -199.05 467.11 0.27 5860.70 9.80 157.50 5814.01 -482.58 -195.04 476.98 0.27 5922.67 8.84 158.88 5875.16 -491.89 -191.31 486.39 1.60 5988.17 8.81 158.07 5939.89 -501.24 -187.62 495.84 0.19 6064.65 8.89 158.43 6015.46 -512.17 -183.26 506.88 0.12 6120.26 9.11 157.75 6070.39 -520.24 -180.02 515.04 0.45 6183.37 9.36 157.35 6132.68 -529.60 -176.15 524.51 0.41 6245.81 9.86 156.18 6194.24 -539.18 -172.03 534.19 0.86 6308.18 10.26 155.76 6255.65 -549.12 -167.60 544.26 0.65 6370.23 8.66 152.95 6316.85 -558.32 -163.20 553.58 2.68 6430.64 8.33 152.17 6376.60 -566.24 -159.09 561.61 0.58 6493.10 8.37 150.85 6438.40 -574.22 -154.77 569.70 0.32 6555.03 7.91 159.01 6499.70 -582.13 -151.04 577.72 2.01 6617.21 7.94 160.65 6561.29 -590.18 -148.09 585.84 0.37 6679.11 8.32 158.55 6622.57 -598.39 -145.03 594.13 0.78 6740.91 8.51 157.39 6683.70 -606.77 -141.64 602.61 0.41 6803.49 8.86 156.61 6745.56 -615.47 -137.94 611.40 0.59 6865.58 8.95 154.57 6806.91 -624.22 -133.97 620.26 0.53 6928.03 9.05 154.22 6868.59 -633.03 -129.75 629.18 0.19 6989.88 9.29 153.16 6929.65 -641.86 -125.38 638.14 0.47 7052.87 9.44 159.65 6991.80 -651.24 -121.29 647.63 1.69 KU 11-07x 26 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) 7115.77 9.36 159.61 7053.86 -660.88 -117.71 657.35 0.14 7178.40 9.71 158.84 7115.62 -670.57 -114.03 667.15 0.60 7241.10 8.81 163.89 7177.50 -680.12 -110.79 676.79 1.93 7302.83 8.51 164.52 7238.53 -689.07 -108.26 685.80 0.51 7364.51 8.46 163.80 7299.54 -697.83 -105.77 694.62 0.19 7426.64 8.57 161.49 7360.98 -706.61 -103.03 703.48 0.58 7488.28 8.58 161.30 7421.93 -715.32 -100.09 712.27 0.05 7550.62 8.55 160.03 7483.57 -724.08 -97.02 721.11 0.31 7612.75 8.64 159.64 7545.01 -732.79 -93.82 729.91 0.18 7675.37 8.99 157.78 7606.88 -741.73 -90.33 738.94 0.72 7738.10 9.31 156.77 7668.82 -750.93 -86.48 748.25 0.58 7800.03 9.64 155.79 7729.90 -760.27 -82.37 757.69 0.59 7861.93 9.69 154.34 7790.93 -769.70 -77.99 767.24 0.40 7925.31 8.74 158.07 7853.49 -778.97 -73.88 776.62 1.77 7987.46 8.74 156.85 7914.91 -787.69 -70.26 785.44 0.3 8050.72 8.40 154.85 7977.47 -796.29 -66.41 794.14 0.71 8112.31 8.15 154.65 8038.42 -804.31 -62.63 802.26 0.41 8176.09 8.26 150.14 8101.55 -812.37 -58.42 810.43 1.02 8238.04 8.43 157.17 8162.84 -820.41 -54.44 818.58 1.67 8298.39 8.52 158.89 8222.53 -828.65 -51.11 826.92 0.45 8360.44 8.56 159.87 8283.90 -837.28 -47.87 835.63 0.24 8422.73 8.46 160.18 8345.50 -845.93 -44.72 844.37 0.18 8484.81 9.37 162.14 8406.83 -855.04 -41.62 853.55 1.55 8546.93 9.30 160.67 8468.13 -864.59 -38.41 863.19 0.40 8610.28 9.44 159.87 8530.63 -874.30 -34.93 872.99 0.31 8673.00 9.41 156.10 8592.50 -883.82 -31.08 882.62 0.99 8737.64 9.49 155.43 8656.27 -893.50 -26.72 892.42 0.21 8798.26 8.58 158.69 8716.13 -902.26 -23.00 901.28 1.73 8860.73 8.53 154.60 8777.91 -910.79 -19.32 909.90 0.98 8922.73 8.93 153.05 8839.19 -919.23 -15.17 918.45 0.75 8985.59 9.24 149.74 8901.26 -927.93 -10.41 927.29 0.97 9045.99 9.53 147.72 8960.86 -936.35 -5.30 935.84 0.73 9108.96 9.19 143.78 9022.99 -944.81 0.45 944.46 1.16 9170.36 9.48 140.26 9083.58 -952.65 6.58 952.47 1.05 9234.03 9.29 136.51 9146.39 -960.41 13.47 960.42 1.01 9295.56 9.64 133.38 9207.09 -967.55 20.64 967.75 1.02 9359.15 10.02 133.60 9269.74 -975.03 28.51 975.44 0.60 9421.27 10.03 131.21 9330.91 -982.32 36.50 982.96 0.67 9483.47 10.33 128.36 9392.14 -989.35 44.95 990.22 0.94 KU 11-07x 27 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) 9545.33 10.67 125.68 9452.96 -996.14 53.95 997.25 0.96 9607.70 10.87 123.03 9514.23 -1002.71 63.57 1004.09 0.86 9669.36 11.33 121.66 9574.74 -1009.06 73.60 1010.71 0.86 9760.49 11.51 114.76 9664.07 -1017.57 89.48 1019.66 1.51 **9799.00 11.51 114.76 9701.80 -1020.79 96.46 1023.07 0.01 **Projected KU 11-07x 28 4.2 Bit Record BIT NO. SIZE TYPE S/N JETS/ TFA IN OUT Feet Drille d HRS AVE ROP (Ft/HR) CONDITION 1rr 13.5 HDBS QHC1GRC 12369275 3x16, 14 138 1522 1384 7.0 197.7 2-2-WT-A-E-I-BU-TD 2 9.875 Varel VM516P2 4006003 5x14 1522 6100 4578 33.1 139.1 1-3-CT-G-X-1-PN-TD 2rr 9.875 Varel VM516P2 4006003 5x14 6100 6100 0 0 No Grade 3 6.75 HDBS FX55 11554339 5x11 6100 9799 3699 44.0 84.1 3-4-BT-G-X-2-DL-TD 4 6.75 Varel DT1GMRS 1468724 6x18 9799 9799 0 0 0 CLEAN OUT RUN KU 11-07x 29 4.3 Mud Record Contractor: Baroid 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 4/17/17 120 120 8.65 251 36 60 38/82/85 10.5 2/0 2.4 0/97.3 30.0 10.4 800 4/18/17 1522 1518 8.95 80 26 33 17/49/60 9.8 2/0 4.6 0/95.1 0.50 25.0 9.3 600 4/19/17 1522 1518 9.10 62 22 9 5/6/7 8.6 2/0 5.7 0/94.0 0.25 17.5 8.7 600 40 4/20/17 1522 1518 9.10 60 24 11 5/6/7 8.6 2/0 5.7 0/94.0 0.25 17.5 8.6 600 40 6% KCl Polymer 4/21/17 1624 1618 8.95 48 8 20 10/13/16 6.4 1/2 1.8 0/95.4 0.75 n/a 10.0 34000 160 4/22/17 3617 3600 8.95 49 10 18 10/12/15 6.2 1/2 2.0 0/95.3 0.50 1.5 9.5 33000 320 4/23/17 5023 4988 9.00 48 10 20 7/11/13 5.6 1/2 2.3 0/95.0 0.20 2.0 10.4 33000 160 4/24/17 6100 6050 9.15 50 13 20 7/11/13 4.8 1/2 3.3 0/93.8 0.20 2.5 10.8 35000 80 4/25/17 6100 6050 9.15 54 15 21 8/11/14 4.6 1/2 3.3 0/93.8 0.20 2.5 10.5 35000 80 4/26/17 6100 6050 9.20 59 13 21 7/10/13 4.6 1/2 3.7 0/93.5 0.10 2.5 10.2 34000 80 4/27/17 6100 6050 9.20 55 13 18 6/8/12 4.6 1/2 3.5 0/93.5 0.10 3.0 10.3 37000 80 4/28/17 6100 6050 9.25 58 13 20 6/8/12 4.8 1/2 3.8 0/93.3 0.10 3.0 10.2 35000 80 4/29/17 6100 6050 9.25 61 14 21 8/10/14 4.4 1/2 3.9 0/93.3 0.10 3.0 9.6 34000 80 4/30/17 6100 6050 9.25 59 11 19 8/11/15 4.4 1/2 3.9 0/93.3 0.10 3.0 10.3 34000 80 5/01/17 7214 7151 10.30 50 16 21 6/10/13 3.6 1/2 8.4 0/89.0 0.20 3.0 10.0 33000 160 5/02/17 8459 8381 11.05 50 19 21 6/8/10 3.8 1/2 12.0 0/85.5 0.20 4.0 10.0 33000 120 5/03/17 9582 9489 11.30 56 29 21 6/10/14 4.0 1/2 13.3 0/84.2 0.20 5.0 10.4 33500 60 5/04/17 9799 9701 11.50 53 23 22 6/9/13 4.0 1/2 13.9 0/83.7 0.10 5.5 10.8 33000 60 5/05/17 9799 9701 11.55 65 21 20 6/8/13 3.8 1/2 14.1 0/83.5 0.10 5.5 10.5 32500 60 5/06/17 9799 9701 11.55 55 22 22 6/9/13 3.6 1/2 14.1 0/83.5 0.10 5.5 10.4 33500 60 5/07/17 9799 9701 11.6 55 21 22 5/9/13 3.8 1/2 14.4 0/83.2 0.1 5.5 10.5 33000 60 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 KU 11-07x 30 4.4. Drilling Progress 0 2000 4000 6000 8000 10000 4/17/20174/18/20174/19/20174/20/20174/21/20174/22/20174/23/20174/24/20174/25/20174/26/20174/27/20174/28/20174/29/20174/30/20175/1/20175/2/20175/3/20175/4/20175/5/20175/6/20175/7/20175/8/20175/9/20175/10/201713 1/2" 9 7/8" 6 3/4" KU 11-07x 31 5 SHOW REPORTS Hydrocarbon Show Report #1 Operator: Well:API Number: Field:Date: Rig:Time: County:Depth Start End State:20 4939'MD 5009'MD Country:20 4905'TVD 4975'TVD Averages Before During After Maximum ROP (fph)107 ft/hr 124 ft/hr 134 ft/hr 188 ft/hr WOB 7 klbs 7 klbs 8 klbs 10 klbs RPM 74 rpm 74 rpm 74 rpm 77 rpm PP 1808 psi 1736 psi 1732 psi 1830 psi Mud Weight 9.0 lbs/gal 9.0 lbs/gal 9.0 lbs/gal 9.0 lbs/gal Chloride 33,000 33,000 33,000 33,000 Total Gas 111 285 65 887 C1 (ppm)22,672 58,424 13,479 181,830 C2 (ppm)- - - - C3 (ppm)- - - - C4 (ppm)- - - - C5 (ppm)- - - - Lithology Odor Amount Type Amount Amount Distribution Intensity Color Color Intensity Color None Color Intesity Color Color Comments Report by: Residual Cut Sand = dominant clear to translucent, common to abundant black, gray, good trace very light gray; dominant upper medium to lower coarse, common lower fine and upper coarse, occasional very coarse, good trace grains > 2mm; poorly sorted; angular to subround, dominant subangular; moderate to low sphericity; dominant quartz, common to abundant igneous lithics. Hilcorp Alaska, LLC 50-133-20662-00-00KU 11-07X Kenai Gas Field Saxon 169 4/23/2017 8:10 PM Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America Stain Fluorescence Cut Fluorescence Residual Fluorescence Cuttings Analysis Josh Dubowski None Oil Show Rating 1 10 100 1000 10000 1 2 3 4ppmPixler Plot DRY GAS GAS CONDENSATE OIL NON PRODUCTIVE C1/C2 C1/C4 C1/C5C1/C3 Hydrocarbon Show Report #2 Operator: Well:API Number: Field:Date: Rig:Time: County:Depth Start End State:7405 7445'MD 7490'MD Country:7551 7379'TVD 7424'TVD Averages Before During After Maximum ROP (fph)158 ft/hr 138 ft/hr 105 ft/hr 180 ft/hr WOB 5 klbs 5 klbs 6 klbs 6 klbs RPM 41 rpm 74 rpm 11 rpm 79 rpm PP 1536 psi 2495 psi 870 psi 2701 psi Mud Weight 0.0 lbs/gal 0.0 lbs/gal 0.0 lbs/gal 0.0 lbs/gal Chloride 35,000 35,000 35,000 35,000 Total Gas 23 189 22 307 C1 (ppm)8,651 35,569 4,118 57,646 C2 (ppm)(22) - (7) - C3 (ppm)(22) - (7) - C4 (ppm)(45) - (13) - C5 (ppm)(45) - (13) - Lithology Odor n/a Amount n/a Type n/a Amount Amount n/a Distribution n/a Intensity n/a Color Color n/a Intensity n/a Color None Color n/a Intesity Color n/a Color Comments Report by: Residual Fluorescence Cuttings Analysis n/a D. Muller Tyonek 1B. Gas show only. No SFOC No n/a Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America n/a n/a Stain Fluorescence Cut Fluorescence Hilcorp Alaska, LLC 50-133-20662-00-00KU 11-07X Kenai Gas Field Saxon 169 5/7/2017 12:28 AM Residual Cut Tuffaceous sandstone: very light gray; blocky to rounded cuttings; very slightly firm; easily friable; lower very fine to lower fine; well sorted; dominant subround to subangular, common well rounded, occasional angular; dominant moderate, common high, occasional low sphericity; matrix-supported with bentonitic, ashy matrix material; dominant quartz, common to abundant mafic-rich lithics, other miscellaneous occasionally. 1 10 100 1000 10000 1 2 3 4ppmPixler Plot DRY GAS GAS CONDENSATE OIL NON PRODUCTIVE C1/C2 C1/C4 C1/C5C1/C3 Hydrocarbon Show Report #3 Operator: Well:API Number: Field:Date: Rig:Time: County:Depth Start End State:8928 8959'MD 8991'MD Country:9038 8875'TVD 8906'TVD Averages Before During After Maximum ROP (fph)152 ft/hr 107 ft/hr 72 ft/hr 166 ft/hr WOB 5 klbs 5 klbs 7 klbs 8 klbs RPM 43 rpm 60 rpm 0 rpm 61 rpm PP 1744 psi 2916 psi 263 psi 3029 psi Mud Weight 0.0 lbs/gal 0.0 lbs/gal 0.0 lbs/gal 0.0 lbs/gal Chloride 35,000 35,000 35,000 35,000 Total Gas 34 140 3 294 C1 (ppm)10,110 26,243 626 55,264 C2 (ppm)(19) - (6) - C3 (ppm)(19) - (6) - C4 (ppm)(39) - (11) - C5 (ppm)(39) - (11) - Lithology Odor n/a Amount n/a Type n/a Amount Amount n/a Distribution n/a Intensity n/a Color Color n/a Intensity n/a Color None Color n/a Intesity Color n/a Color Comments Report by: Residual Fluorescence Cuttings Analysis n/a D. Muller Tyonek D2. Gas show only. No SFOC No n/a Oil Show Rating Cut Free Oil in Mud Kenai Peninsula Borough Alaska United States of America n/a n/a Stain Fluorescence Cut Fluorescence Hilcorp Alaska, LLC 50-133-20662-00-00KU 11-07X Kenai Gas Field Saxon 169 5/7/2017 12:28 AM Residual Cut Tuffaceous sandstone / sand: very light gray overall, individual liths dominantly clear to translucent quartz and volcanic glass, trace dark liths; ashy matrix is very soft; fragile and pulverulent; supports loose grains; very fine lower to trace very coarse upper, dominantly fine lower to medium lower; angular to subangular with trace subrounded; poorly sorted; very loosely supported with ashy matrix; non calcareous; trace thin coal beds. 1 10 100 1000 10000 1 2 3 4ppmPixler Plot DRY GAS GAS CONDENSATE OIL NON PRODUCTIVE C1/C2 C1/C4 C1/C5C1/C3 KU 11-07x 32 6 DAILY REPORTS Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT KU 11-07X REPORT FOR Clint Montague, Adam Dorr DATE Apr 18, 2017 DEPTH 1522' PRESENT OPERATION POOH TIME 24:00 YESTERDAY 138' 24 HOUR FOOTAGE 1384' CASING INFORMATION 16" Cond @ 138' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 1484.37' 5.50 238.60 1479.47' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED RR 1 13 1/2" HDBS QHC1GRC 12369275 3x16, 1x14 138' 1522' 1384' 7 Casing Point DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 1284.0 @ 354' 3.0 @ 311' 202.2 237.6 FT/HR SURFACE TORQUE 7426 @ 975' 0 @ 1432' 4690.7 6512.6 AMPS WEIGHT ON BIT 18 @ 931' 0 @ 522' 6.2 7.9 KLBS ROTARY RPM 112 @ 544' 33 @ 232' 51.4 73.3 RPM PUMP PRESSURE 1420 @ 1506' 181 @ 140' 1057.5 1328.1 PSI DRILLING MUD REPORT DEPTH 1522' MW 8.95 VIS 80 PV 26 YP 33 FL 9.8 Gels 17/49/60 CL- 600 FC 2/0 SOL 4.6 SD 0.50 OIL 0 MBL 25.0 pH 9.3 Ca+ n/a CCI 0.25 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 75 @ 1310' 0 @ 427' 14.6 TRIP GAS CUTTING GAS @ @ WIPER GAS 17u @ 1522' CHROMATOGRAPHY (ppm) SURVEY N/A METHANE (C-1) 18459 @ 1322' 188 @ 399' 3941.3 CONNECTION GAS HIGH 0 ETHANE (C-2) 0 @ 0 @ 0 AVG 0 PROPANE (C-3) 0 @ 0 @ 0 CURRENT 0 BUTANE (C-4) 0 @ 0 @ 0 CURRENT BACKGROUND/AVG 3-10/5 PENTANE (C-5) 0 @ 0 @ 0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Samples caught at 1500' and 1522'. PRESENT LITHOLOGY @ 1522': 100% Sand DAILY ACTIVITY SUMMARY Spud 11-07X well at 01:30 hours. Drill from 86’ to 340’. POOH from 340’ to 52’. Make up BHA. RIH from 172’ to 340’. Drill from 340’ to 1522’. Condition mud and circulate. POOH from 1522’to 270’, free. RIH from 270’ to 1522’, no fill. Circulate and condition mud. POOH. CANRIG PERSONNEL ON BOARD 2 DAILY COST $1925 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT KU 11-07X REPORT FOR Clint Montague, Adam Dorr DATE Apr 19, 2017 DEPTH 1522' PRESENT OPERATION Nipple up BOP TIME 24:00 YESTERDAY 1522' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" Cond @ 138' 10 3/4" @ 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 1484.37' 5.50 238.60 1479.47' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED RR 1 13 1/2" HDBS QHC1GRC 12369275 3x16, 1x14 138' 1522' 1384' 7 2-2-WT-A-E-I-BU-TD Casing Point DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 1522' MW 9.10 VIS 62 PV 22 YP 9 FL 8.6 Gels 5/6/7 CL- 600 FC 2/0 SOL 5.7 SD 0.25 OIL 0 MBL 17.5 pH 8.7 Ca+ 40 CCI n/a MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 4u Casing TG 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 0-4/Tr PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Samples caught at 1500' and 1522'. PRESENT LITHOLOGY @ 1522': 100% Sand DAILY ACTIVITY SUMMARY Finish POOH. Lay down BHA. Clean rig floor. Pull wear bushing. Rig up casing bails & elev stage h. Pick up spider tongs. Stage shoe track. Function test equipment. Make up shoe track. Run casing from shoe tract to 1511’. Circulate casing. Cement casing (bump plug @ 15:54 hours). Rig down from running casing. Nipple up BOP. CANRIG PERSONNEL ON BOARD 2 DAILY COST $1925 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT KU 11-07X REPORT FOR Clint Montague, Adam Dorr DATE Apr 20, 2017 DEPTH 1522' PRESENT OPERATION Picking up drill pipe TIME 24:00 YESTERDAY 1522' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" Cond @ 138' 10 3/4" @ 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 1484.37' 5.50 238.60 1479.47' 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 @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH 1522' MW 9.10 VIS 60 PV 24 YP 11 FL 8.6 Gels 5/6/7 CL- 600 FC 2/0 SOL 5.7 SD 0.25 OIL 0 MBL 17.5 pH 8.6 Ca+ 40 CCI 0.40 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 0-4/Tr PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Samples caught at 1500' and 1522'. PRESENT LITHOLOGY @ 1522': 100% Sand DAILY ACTIVITY SUMMARY Finish nipple BOP. Test BOP. Pick up drill pipe. CANRIG PERSONNEL ON BOARD 2 DAILY COST $1925 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Clint Montague, Adam Dorr DATE Apr 21, 2017 DEPTH 1772' PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 1522' 24 HOUR FOOTAGE 250' CASING INFORMATION 16" Cond @ 138' 10 3/4" @ 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 1692.57' 6.58 233.02 1686.38' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 2 9 7/8" Varel VM516P2 4006003 5x14 1522' 250' 2.0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 505.5 @ 1730' 3.7 @ 1631' 164.8 179.5 FT/HR SURFACE TORQUE 7056 @ 1727' 1469 @ 1725' 5212.9 5929.7 AMPS WEIGHT ON BIT 7 @ 1651' 0 @ 1542' 2.8 1.9 KLBS ROTARY RPM 94 @ 1712' 25 @ 1565' 62.7 77.7 RPM PUMP PRESSURE 1356 @ 1729' 762 @ 1544' 1043.7 1236.1 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL 1522' TO TOOLS Directional/Triple Combo GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 49 @ 1772' 1 @ 1656' 7.1 TRIP GAS 0 @ 1522' CUTTING GAS @ @ 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) @ @ CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 1-2/1.5 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Sand/Sandstone; Tuffaceous Siltstone/Tuffaceous Claystone; Trace Coal PRESENT LITHOLOGY @ 1760': 10% Sandstone; 40% Tuffaceous Siltstone; 50% Tuffaceous Claystone DAILY ACTIVITY SUMMARY Finish picking up drill pipe. Pressure test casing ti 2600 psi for 30 minutes. Make up BHA from bit to 732’. RIH from 732’ to 1356’. Wash/ream from 1356’ to 1419’ (tagged cement at 1419’). Drill out cement/shoe from 1419’ to 1522’ (tagged float at 1426’/tagged shoe at 1510’). Drill from 1522’ to 1542’.Circulate and displace spud mud with 9.0 ppg KCL. Clean shakers and possum belly. Circulate and condition mud for FIT test. Perform FIT test to 12.5 ppg EQMW. Drill from 1542’to 1772’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Clint Montague, Adam Dorr DATE Apr 22, 2017 DEPTH 3718' PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 1772' 24 HOUR FOOTAGE 1946' CASING INFORMATION 16" Cond @ 138' 10 3/4" @ 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 3684.03' 6.59 241.68 3665.85' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 2 9 7/8" Varel VM516P2 4006003 5x14 1522' 2196' 13.8 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 262.6 @ 3067' 3.5 @ 3214' 171.6 131.2 FT/HR SURFACE TORQUE 8438 @ 3663' 0 @ 2669' 6169.9 6482.0 AMPS WEIGHT ON BIT 9 @ 3587' 0 @ 2354' 2.7 6.3 KLBS ROTARY RPM 132 @ 3589' 2 @ 3048' 70.7 73.9 RPM PUMP PRESSURE 1634 @ 3694' 1087 @ 2992' 1292.3 1445.1 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL 1522' TO 3718' TOOLS Directional/Triple Combo GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 158 @ 3553' 3 @ 2228' 25.0 TRIP GAS CUTTING GAS @ @ WIPER GAS 0u @ 3033' CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 30279 @ 3552' 692 @ 1852' 4975.8 CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 8u-10u/9u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Sand/Sandstone; Tuffaceous Siltstone/Tuffaceous Claystone; Tuff; Carbonaceous Shale; Coal PRESENT LITHOLOGY @ 3710': 30% Sandstone; 50% Sand; 10% Tuffaceous Siltstone; 10% Carbonaceous Shale DAILY ACTIVITY SUMMARY Drill from 1772’ to 3033’. Pump sweep and circulate hole clean. Wipe hole from 3033’ to 1476’. Service rig. RIH from 1476’ to 3033’ (no fill). Drill from 3033’ to 3718’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Clint Montague, Adam Dorr DATE Apr 23, 2017 DEPTH 5023' PRESENT OPERATION Safety ream to bottom after Wiper Trip TIME 24:00 YESTERDAY 3718' 24 HOUR FOOTAGE 1305' CASING INFORMATION 16" Cond @ 138' 10 3/4" @ 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 4988.65' 9.15 154.86 4954.50' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 2 9 7/8" Vrel VM516P2 4006003 5x14 1522' 3501' 23.7 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 267.2 @ 3940' 0.7 @ 4899' 143.1 123.9 FT/HR SURFACE TORQUE 11202 @ 3940' 0 @ 4160' 6268.3 8020.0 AMPS WEIGHT ON BIT 16 @ 3940' 0 @ 4112' 5.5 8.3 KLBS ROTARY RPM 124 @ 4274' 9 @ 4155' 58.5 75.9 RPM PUMP PRESSURE 1874 @ 4922' 1122 @ 4179' 1587.5 1724.2 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL 1522' TO 5023' TOOLS Directional/Triple Combo GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 887 @ 4959' 8 @ 4528' 73.3 TRIP GAS CUTTING GAS @ @ WIPER GAS 17u @ 4027' CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 181830 @ 4959' 1507 @ 4528' 14977.3 CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 15u/12u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Coal; Carbonaceous Shale PRESENT LITHOLOGY 20% Sandstone; 60% Tuffaceous Siltstone; 20% Tuffaceous Claystone DAILY ACTIVITY SUMMARY Drill from 3718’ to 4027’. Pump sweep and circulate hole clean. Wipe hole from 4027’ to 3030’, no tight spots. Service rig. RIH from 3030’ to 4027’, 8’ fill. Drill from 4027’ to 5023’. Pump sweep and circulate hole clean. Wipe hole to 3967’, free. RIH from 3967’ to 5023’ (safety reamed last stand to bottom) with no issues. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Clint Montague, Adam Dorr DATE Apr 24, 2017 DEPTH 6100' PRESENT OPERATION Download LWD TIME 24:00 YESTERDAY 5023' 24 HOUR FOOTAGE 1077' CASING INFORMATION 16" Cond @ 138' 10 3/4" 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6064.65' 8.89 158.43 6015.46' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 2 9 7/8" Varel VM516P2 4006003 5x14 1522' 6100' 4578' 33.1 n/a Casing TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 217.4 @ 5345' 10.6 @ 5961' 126.0 140.8 FT/HR SURFACE TORQUE 10303 @ 5971' 9 @ 5901' 8407.2 9929.3 AMPS WEIGHT ON BIT 12 @ 5591' 0 @ 5588' 7.4 10.7 KLBS ROTARY RPM 212 @ 5892' 1 @ 5902' 71.7 74.1 RPM PUMP PRESSURE 2145 @ 6086' 1557 @ 5024' 1917.4 2111.2 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL 1522' TO 6100' TOOLS Directional/Triple Combo GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 192 @ 5272' 13 @ 5150' 57.6 TRIP GAS CUTTING GAS @ @ WIPER GAS 22u @ 5023' CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 39894 @ 5272' 2793 @ 5648' 11824.4 CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 6/14 PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Carbonaceous Shale; Coal PRESENT LITHOLOGY @ 6100': 10% Sand; 70% Tuffaceous Claystone; 10% Tuffaceous Siltstone; 10% Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Drill from 5023’ to 6100’ Casing Point. Pump sweep and circulate hole clean. POOH from 6110’ to 723’. Rack back HWDP and collars in derrick. Remove LWD sources. Download LWD. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Adam Dorr DATE Apr 25, 2017 DEPTH 6100' PRESENT OPERATION E-Logging TIME 24:00 YESTERDAY 6100' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" Cond @ 138' 10 3/4" 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6064.65' 8.89 158.43 6015.46' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 2 9 7/8" Varel VM516P2 4006003 5x14 1522' 6100' 4578' 33.1 1-3-CT-G-X-1-PN-TD Casing TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS 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 MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS None 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 6 (When stpped circulation to POOH) PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Carbonaceous Shale; Coal PRESENT LITHOLOGY @ 6100': 10% Sand; 70% Tuffaceous Claystone; 10% Tuffaceous Siltstone; 10% Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Lay down BHA. Lay down Top Drive for repairs. Rig up wireline equipment. Make Dummy Run. Make XPT tools. Run XPT. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Adam Dorr DATE Apr 26, 2017 DEPTH 6100' PRESENT OPERATION E-Logging (SWC) TIME 24:00 YESTERDAY 6100' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" Cond @ 138' 10 3/4" 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6064.65' 8.89 158.43 6015.46' 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 @ @ AMPS 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 MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS None 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 6 (When stopped circulation to POOH) PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Carbonaceous Shale; Coal PRESENT LITHOLOGY @ 6100': 10% Sand; 70% Tuffaceous Claystone; 10% Tuffaceous Siltstone; 10% Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Continue to run XPT (35 total stations). Lay down XPT tool. Rig up ECS (Gamma/Neutron) tool. RIH with ECS tool to 5910’ and log up. Rig down ECS. Make SWC logging tools. RIH with SWC tools to 5900’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Adam Dorr DATE Apr 27, 2017 DEPTH 6100' PRESENT OPERATION Mad Pass/POOH TIME 24:00 YESTERDAY 6100' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" Cond @ 138' 10 3/4" 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6064.65' 8.89 158.43 6015.46' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED RR 2 9 7/8" Varel VM516P2 4006003 5x14 6100' 6100' 0' 0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS 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 MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS None GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 55u @ 6100' 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 3 (When stopped circulation to POOH) PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Carbonaceous Shale; Coal PRESENT LITHOLOGY @ 6100': 10% Sand; 70% Tuffaceous Claystone; 10% Tuffaceous Siltstone; 10% Tuffaceous Sandstone DAILY ACTIVITY SUMMARY SWC to 4800’ (21 cores). Continue coring (27 out of 35 retrieved). Rig down wireline. Reinstall Top Drive. Make up BHA from bit to 103’. RIH with HWDP/JARS to 661’. RIH from 661’ to 3143’ (filling pipe every 25 stands, no tight spots.). RIH from 3143’ to 5938’, tight spot 5919’ (20K slack off). Ream from 5938’ to 6100’. Pump sweep, circulate hole clean. Mad Pass/POOH from 6100’ to 4421’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Adam Dorr DATE Apr 28, 2017 DEPTH 6100' PRESENT OPERATION Running 7 5/8" Casing TIME 24:00 YESTERDAY 6100' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" Cond @ 138' 10 3/4" 1511' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6064.65' 8.89 158.43 6015.46' 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 @ @ AMPS 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 MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS None 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 2u when circulating at 3250' PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Carbonaceous Shale; Coal PRESENT LITHOLOGY @ 6100': 10% Sand; 70% Tuffaceous Claystone; 10% Tuffaceous Siltstone; 10% Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Continue Mad Pass/POOH from 4421’ to 3087’. POOH from 3087’ to 661’. Rack back HWDP, lay down jars and crossovers from 661’ to 103’. Lay down BHA. Change upper pipe rams to 7 5/8”. Shell test BOP. Pressure test 7 5/8” UPR to 250 psi for 5 minutes / 3500 psi for 5 minutes. Rig up to run 7 5/8” casing. Run 7 5/8” casing to 3250’. Circulate and condition mud (Max Gas = 6u). Run 7 5/8” casing from 3250’ to 5845’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Adam Dorr DATE Apr 29, 2017 DEPTH 6100' PRESENT OPERATION Testing BOP TIME 24:00 YESTERDAY 6100' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" Cond @ 138' 10 3/4" 1511' 7 5/8" @ 6089' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6064.65' 8.89 158.43 6015.46' 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 @ @ AMPS 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 MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 14u @ 6100' 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 3u-4u/3.5u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Carbonaceous Shale; Coal PRESENT LITHOLOGY @ 6100': 10% Sand; 70% Tuffaceous Claystone; 10% Tuffaceous Siltstone; 10% Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Run 7 5/8” casing from 5845’ to 6058’. Wash down to 6089’. Land hanger. Circulate. Pump 40 bbls 10.0 ppg mud push, follow with 134 bbls 12.5 ppg lead, follow with 15.2 ppg 34 bbls tail, drop top plug. Follow with 10 bbls water, displace with 9.2 ppg mud (total pumped for displacement 278 bbls). CIP @ 0630 Hours. Rig down cementers. Drain stack, pull landing joint, wash out stack, make up packer to landing loint, set packer/run in lockdown screws, pack pack off with packing to 7000 psi. Pressure test pack off to 500 psi for 5 minutes / 5000 psi for 15 minutes. Rig down casing bails/elevators and rig up rig bails/elevators. Service rig. Change out upper pipe rams from 7 5/8” to 4 1/2” rams (function test rams). Continue to service rig (cutting and slipping 155 feet of drill line). Prepare for BOP test. Test BOP. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Adam Dorr DATE Apr 30, 2017 DEPTH 6100' PRESENT OPERATION Fixing to drill out shoe strack TIME 24:00 YESTERDAY 6100' 24 HOUR FOOTAGE 0' CASING INFORMATION 16" Cond @ 138' 10 3/4" 1511' 7 5/8" @ 6089' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 6064.65' 8.89 158.43 6015.46' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 3 6 3/4" HDBS FX55 11554339 5x11 6100' 0 0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS 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 MBL pH Ca+ CCI 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 1u/1u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Carbonaceous Shale; Coal PRESENT LITHOLOGY @ 6100': 10% Sand; 70% Tuffaceous Claystone; 10% Tuffaceous Siltstone; 10% Tuffaceous Sandstone DAILY ACTIVITY SUMMARY Finish testing BOP. Pick up and rack back in derrick 30 stands. Rig up Pollard wireline for CBL. Run CBL (tagged cement @ 5932’). Rig down Pollard wireline. Make up BHA from bit to 121’, attempt shallow-hole LWD/MWD (trouble with communication), troubleshoot, finally get shallow- hole test. Make up BHA from 121’ to 552’. Single in drill pipe from 552’ to 1553’. RIH from derrick from 1553’ to 5909’. Circulate and condition. Test casing to 3500 psi for 30 minutes. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, adam Dorr DATE May 01, 2017 DEPTH 7214' PRESENT OPERATION Wiper Trip TIME 24:00 YESTERDAY 6100' 24 HOUR FOOTAGE 1114' CASING INFORMATION 7 5/8" @ 6090' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 7178.40' 9.71 158.84 7115.62' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 3 6 3/4" HDBS FX55 11554339 5x11 6100' 1114' 10.3 Inc DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 216.2 @ 6481' 9.6 @ 6408' 120.0 97.4 FT/HR SURFACE TORQUE 9073 @ 6559' 0 @ 6348' 7655.1 7902.0 AMPS WEIGHT ON BIT 7 @ 6790' 0 @ 7029' 4.6 3.9 KLBS ROTARY RPM 123 @ 6181' 46 @ 6224' 68.4 58.6 RPM PUMP PRESSURE 2740 @ 7164' 1362 @ 6101' 2355.2 2569.7 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL 6100' TO 7214' TOOLS Directional/Triple Combo GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 221 @ 7110' 10 @ 6159' 83.2 TRIP GAS None CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 32890 @ 7111' 1447 @ 6159' 12496.0 CONNECTION GAS HIGH 0 ETHANE (C-2) @ @ AVG 0 PROPANE (C-3) @ @ CURRENT 0 BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 13u-44u/35u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone; Tuffaceous Claystone; Coal; Carbonaceous Shale PRESENT LITHOLOGY @ 7210': 20% Sand; 20% Tuffaceous Siltstone; 30% Tuffaceous Claystone; 20% Coal; 10% Carbonaceous Shale DAILY ACTIVITY SUMMARY Drill out cement and shoe track. Drill from 6100’ to 6120’, while beginning displacement to 10.0 ppg mud. Circulate and condition mud. FIT test to 12.5 ppg Equivalent Mud Weight. Drill from 6120’to 7214’. Pump sweep and circulate hole clean. Wipe hole to shoe, encounter tight spots to 6465’, backream to 6156’. CBU while working pipe and backreaming to 6094’. Pull on elevators to 6029’. Service rig. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pderson, Robert Wall DATE May 02, 2017 DEPTH 8459' PRESENT OPERATION Wiping Hole TIME 24:00 YESTERDAY 7214' 24 HOUR FOOTAGE 1245' CASING INFORMATION 7 5/8" @ 6090' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 8360.44' 8.56 159.87 8283.90' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 3 6 3/4" HDBS FX55 11554339 5x11 6100' 2359' 21.8 Inc DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 209.9 @ 7416' 2.2 @ 8026' 128.7 105.1' FT/HR SURFACE TORQUE 9912 @ 8251' 0 @ 7903' 8244.7 8959.2 AMPS WEIGHT ON BIT 12 @ 8247' 0 @ 7899' 5.4 5.7 KLBS ROTARY RPM 79 @ 7501' 4 @ 8212' 57.5 59.4 RPM PUMP PRESSURE 3021 @ 8344' 2035 @ 7278' 2689.4 2886.4 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL 6100' TO 8459' TOOLS Directional/Triple Combo GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 528 @ 8143' 15 @ 8010' 96.0 TRIP GAS CUTTING GAS @ @ WIPER GAS 75u @ 7214' CHROMATOGRAPHY (ppm) SURVEY 745u METHANE (C-1) 95805 @ 8144' 2708 @ 8255' 18076.5 CONNECTION GAS HIGH 839u ETHANE (C-2) @ @ AVG 100u PROPANE (C-3) 11 @ 8433' 9 @ 8139' 0.1 CURRENT 839u BUTANE (C-4) @ @ CURRENT BACKGROUND/AVG 15u-50u/27u PENTANE (C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Coal; Carbonaceous Shale; Tuff PRESENT LITHOLOGY @ 8455: 20% Sandstone; 20% Sand; 40% Tuffaceous Siltstone; 20% Tuffaceous Claystone DAILY ACTIVITY SUMMARY RIH from 6030’ to 7214’, washing last stand to bottom (no issues/no fill). Drill from 7214’ to 8459’. Pump high viscosity sweep, circulate and raise MW to 11.0 ppg. Pump out to 8144’, top drive up and backream from 8133’ to 7771’. Circulate high gas (1586u Max from flow check on bottom, 1778u Max from Coal at 8141’).Continue to backream from 7771’ to 7213’. Pull one stand high on elevators to 7151’. Service rig. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC Kenai Gas Field DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Robert Wall DATE May 03, 2017 DEPTH 9643' PRESENT OPERATION Drilling TIME 24:00 YESTERDAY 8459' 24 HOUR FOOTAGE 1184' CASING INFORMATION 7 5/8" @ 6090' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9607.70' 10.87 123.03 9514.23' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 3 6 3/4" HDBS FX55 11554339 5x11 6100' 3543' 38.4 Inc DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 199.3 @ 8678' 6.0 @ 9539' 90.2 69.9 FT/HR SURFACE TORQUE 10991 @ 9563' 15 @ 9507' 9495.4 10589.5 AMPS WEIGHT ON BIT 11 @ 9305' 1 @ 9517' 6.2 9.6 KLBS ROTARY RPM 69 @ 9632' 48 @ 9521' 58.4 68.3 RPM PUMP PRESSURE 3220 @ 9347' 2340 @ 8459' 2922.5 3013.5 PSI DRILLING MUD REPORT DEPTH MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL 6100' TO 9643' TOOLS Directional/Triple Combo GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 348 @ 9224' 9 @ 9540' 55.3 TRIP GAS CUTTING GAS @ @ WIPER GAS 2586u @ 8459' CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 65043 @ 9225' 1787 @ 9540' 10489.0 CONNECTION GAS HIGH 25 ETHANE (C-2) @ @ 0.0 AVG 4 PROPANE (C-3) 14 @ 9225' 9 @ 9232' 0.2 CURRENT 0 BUTANE (C-4) @ @ 0.0 CURRENT BACKGROUND/AVG 13/19 PENTANE (C-5) @ @ 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone/Sandstone/Sand; Tuffaceous Siltstone/Tuffaceous Claystone; Coal; Carbonaceous Shale; Tuff PRESENT LITHOLOGY @ 9620': 10% Tuffaceous Claystone; 20% Sandstone; 10% Sand; 50% Tuffaceous Siltstone; 10% Tuffaceous Claystone DAILY ACTIVITY SUMMARY RIH from 7213’ to 8459’, washing/reaming last stand to bottom (3 feet of fill). Drill from 8459’ to 9643’. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY Paul Webster Hilcorp Alaska, LLC DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Robert Wall DATE May 04, 2017 DEPTH 9799' PRESENT OPERATION POOH TIME 24:00 YESTERDAY 9643' 24 HOUR FOOTAGE 156' CASING INFORMATION 7 5/8" @ 6090' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9799' 11.51 114.76 9701.8' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 3 6 3/4" HDBS FX55 11554339 5x11 6100' 9799' 699' 43:41 N/A TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 90.2 @ 9649' 7.8 @ 9739' 44.0 23.1 FT/HR SURFACE TORQUE 11045 @ 9741' 9882 @ 9666' 10593.5 10391 AMPS WEIGHT ON BIT 13 @ 9798' 6 @ 9675' 9.4 12.9 KLBS ROTARY RPM 76 @ 9789' 55 @ 9646' 70.7 76.3 RPM PUMP PRESSURE 3193 @ 9705' 2850 @ 9769' 3073.9 3083 PSI DRILLING MUD REPORT DEPTH 9799 MW 11.5 VIS 53 PV 23 YP 22 FL 4.0 Gels 6/9/13 CL- 33,000 FC 1/2 SOL 13.9 SD 0.10 OIL 0.0/83.7 MBL 5.5 pH 10.8 Ca+ 30 CCI 1.30 MWD SUMMARY INTERVAL 9643 TO 9799 TOOLS Directional/Triple Combo GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 66u @ 9723' 8 @ 9780' 18 TRIP GAS CUTTING GAS 0 @ 9799' 0 @ 9799' 0.0 WIPER GAS 2175u CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 13135ppm @ 9723' 1627 @ 9780' 3332.9 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 sandstone / sand / tuffaceous claystone / tuffaceous siltstone PRESENT LITHOLOGY 10% carbonaceous shale 10% sandstone 30% tuffaceous claystone 50% tuffaceous siltstone DAILY ACTIVITY SUMMARY Drill to TD at 9799', Circulate bottoms up. Flow check well, no flow. Pull out to shoe, service rig. TIH to 9799'. Pump sweep, max gas 2175u. Weight up active system. Flow check, no flow, Circulate bottoms up with 14u gas. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY D. Muller Hilcorp Alaska, LLC DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Robert Wall DATE May 05, 2017 DEPTH 9799' PRESENT OPERATION Wireline TIME 24:00 YESTERDAY 9799' 24 HOUR FOOTAGE 0 CASING INFORMATION 7 5/8" @ 6090' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9607.70' 10.87 123.03 9514.23' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED NB 3 6 3/4" HDBS FX55 11554339 5x11 6100' 9799' 3543' 38.4 3-4-BT-G-X-2-DL-TD TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH No mud information at report time MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI 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 TD: monitoring gas PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Flow check: gaining 1 barrel per hour. POOH. Rig up wireline equipment and perform dummy run. RIH to TD at 9700' with XPT tools. POOH recording at desired depths; 35 areas total. Sample catchers are released. CANRIG PERSONNEL ON BOARD 4 DAILY COST $2785 REPORT BY D. Muller Hilcorp Alaska, LLC DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Robert Wall DATE May 06, 2017 DEPTH 9799' PRESENT OPERATION ciruclating at bottom of clean-out run TIME 24:00 YESTERDAY 9799' 24 HOUR FOOTAGE 0 CASING INFORMATION 7 5/8" @ 6090' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9799.00' 11.51 114.76 9701.80 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 @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH no mud information at report time MW VIS PV YP FL Gels CL- FC SOL SD OIL MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 3360u @ 9713: 3937 strokes 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 TD. Monitoring gas PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue wireline XPT tools gathering remaining 12 stations. POOH w XPT, rig up and run in with HNGS tool to 9700'. Wireline log from 9700 back to 8350' where tools got hung up. Worked free and POOH. Rigged down radio active sources and wireline logging equipment. Make up clean-out BHA and begin RIH. Circulated bottoms-up at shoe with 2970u max gas. Cut and slip drill line. Continue RIH to 9700. Circulate bottoms-up with 3360u max gas. CANRIG PERSONNEL ON BOARD 2 DAILY COST $1,925 REPORT BY D. Muller Hilcorp Alaska, LLC DAILY WELLSITE REPORT Ku 11-07X REPORT FOR Rance Pederson, Robert Wall DATE May 07, 2017 DEPTH 9799' PRESENT OPERATION TOOH TIME 24:00 YESTERDAY 9799' 24 HOUR FOOTAGE 0 CASING INFORMATION 7 5/8" @ 6090' 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 @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING MUD REPORT DEPTH MD 9799'/9702' MW 11.6 VIS 55 PV 21 YP 22 FL 3.8 Gels 5/9/13 CL- 33,000 FC 1/2 SOL 14.4 SD 0.10 OIL 0.0/83.2 MBL 5.5 pH 10.5 Ca+ 60 CCI 0.80 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS 119u 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 TD. Monitoring gas PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue washing and reaming to bottom. Pump high viscosity sweep; 50% increased cuttings. Circulate 2 bottoms-up, and increase weight from 11.5 to 11.6 ppg. Flow check well, then begin TOOH 4 stands, but incurred swabbing. Tripped back in hole to bottom, circulated bottoms- up, flow checked again, and pumped out of hole to 9159’. Flow checked well: no flow. Continue pumping out of hole to 8588’ due to swabbing. TOOH to shoe on elevators with no issues. Circulated bottoms up with max gas of 21 units. CANRIG PERSONNEL ON BOARD 2 DAILY COST $1,925 REPORT BY D. Muller